Field experiment on CO2 back-production at the Ketzin pilot site

NASA Astrophysics Data System (ADS)

Martens, Sonja; Möller, Fabian; Schmidt-Hattenberger, Cornelia; Streibel, Martin; Szizybalski, Alexandra; Liebscher, Axel

2015-04-01

The operational phase of the Ketzin pilot site for geological CO2 storage in Germany started in June 2008 and ended in August 2013. Over the period of approximately five years, a total amount of 67 kt of CO2 was successfully injected into a saline aquifer (Upper Triassic sandstone) at a depth of 630 m - 650 m. The CO2 used was mainly of food grade quality. In addition, 1.5 kt of CO2 from the pilot capture facility "Schwarze Pumpe" (lignite power plant CO2) was used in 2011. At the end of the injection period, 32 t N2 and 613 t CO2 were co-injected during a four-week field test in July and August 2013. In October 2014, a field experiment was carried out at Ketzin with the aim to back-produce parts of the injected CO2 during a two-week period. This experiment addressed two main questions: (i) How do reservoir and wellbore behave during back-production of CO2? and (ii) What is the composition of the CO2 and the co-produced formation fluid? The back-production was carried out through the former injection well. It was conducted continuously over the first week and with an alternating regime including production during day-time and shut-ins during night-time in the second week. During the test, a total amount of 240 t of CO2 and 57 m3 of brine were safely back-produced from the reservoir. Production rates up to 3,200 kg/h - which corresponds to the former highest injection rate - could be tested. Vital monitoring parameters included production rates of CO2 and brine, wellhead and bottomhole pressure and temperature at the production and observation wells and distributed temperature sensing (DTS) along the production well. A permanently installed geoelectrical array was used for crosshole electrical resistivity tomography (ERT) monitoring of the reservoir. Formation fluid and gas samples were collected and analysed. The measured compositions allow studying the geochemical interactions between CO2, formation fluid and rocks under in-situ conditions The field experiment indicates that a safe back-production of CO2 is generally feasible and can be performed at both, stable reservoir and wellbore conditions. ERT monitoring shows that the geoelectrical array at the production well was capable of tracking the back-production process, e.g. the back-flow of brine into the parts formerly filled with CO2. Preliminary results also show that the back-produced CO2 at Ketzin has a purity > 97 per cent. Secondary component in the CO2 stream is N2 with < 3 per cent which probably results from former injection operation and field tests. The results will help to verify geochemical laboratory experiments which are typically performed in simplified synthetic systems. The results gained at the Ketzin site refer to the pilot scale. Upscaling of the results to industrial scale is possible but must first be tested and validated at demo projects.

Monitoring CO2 invasion processes at the pore scale using geological labs on chip.

PubMed

Morais, S; Liu, N; Diouf, A; Bernard, D; Lecoutre, C; Garrabos, Y; Marre, S

2016-09-21

In order to investigate at the pore scale the mechanisms involved during CO2 injection in a water saturated pore network, a series of displacement experiments is reported using high pressure micromodels (geological labs on chip - GLoCs) working under real geological conditions (25 < T (°C) < 75 and 4.5 < p (MPa) < 8). The experiments were focused on the influence of three experimental parameters: (i) the p, T conditions, (ii) the injection flow rates and (iii) the pore network characteristics. By using on-chip optical characterization and imaging approaches, the CO2 saturation curves as a function of either time or the number of pore volume injected were determined. Three main mechanisms were observed during CO2 injection, namely, invasion, percolation and drying, which are discussed in this paper. Interestingly, besides conventional mechanisms, two counterintuitive situations were observed during the invasion and drying processes.

CO2 Capture by Injection of Flue Gas or CO2-N2 Mixtures into Hydrate Reservoirs: Dependence of CO2 Capture Efficiency on Gas Hydrate Reservoir Conditions.

PubMed

Hassanpouryouzband, Aliakbar; Yang, Jinhai; Tohidi, Bahman; Chuvilin, Evgeny; Istomin, Vladimir; Bukhanov, Boris; Cheremisin, Alexey

2018-04-03

Injection of flue gas or CO 2 -N 2 mixtures into gas hydrate reservoirs has been considered as a promising option for geological storage of CO 2 . However, the thermodynamic process in which the CO 2 present in flue gas or a CO 2 -N 2 mixture is captured as hydrate has not been well understood. In this work, a series of experiments were conducted to investigate the dependence of CO 2 capture efficiency on reservoir conditions. The CO 2 capture efficiency was investigated at different injection pressures from 2.6 to 23.8 MPa and hydrate reservoir temperatures from 273.2 to 283.2 K in the presence of two different saturations of methane hydrate. The results showed that more than 60% of the CO 2 in the flue gas was captured and stored as CO 2 hydrate or CO 2 -mixed hydrates, while methane-rich gas was produced. The efficiency of CO 2 capture depends on the reservoir conditions including temperature, pressure, and hydrate saturation. For a certain reservoir temperature, there is an optimum reservoir pressure at which the maximum amount of CO 2 can be captured from the injected flue gas or CO 2 -N 2 mixtures. This finding suggests that it is essential to control the injection pressure to enhance CO 2 capture efficiency by flue gas or CO 2 -N 2 mixtures injection.

The U.S. Gas Flooding Experience: CO2 Injection Strategies and Impact on Ultimate Recovery

DOE Office of Scientific and Technical Information (OSTI.GOV)

Nunez-Lopez, Vanessa; Hosseini, Seyyed; Gil-Egui, Ramon

The Permian Basin in West Texas and southwestern New Mexico has seen 45 years of oil reserve growth through CO2 enhanced oil recovery (CO2 EOR). More than 60 CO2 EOR projects are currently active in the region’s limestone, sandstone and dolomite reservoirs. Water alternating gas (WAG) has been the development strategy of choice in the Permian for several technical and economic reasons. More recently, the technology started to get implemented in the much more porous and permeable clastic depositional systems of the onshore U.S. Gulf Coast. Continued CO2 injection (CGI), as opposed to WAG, was selected as the injection strategymore » to develop Gulf Coast oil fields, where CO2 injection volumes are significantly larger (up to 6 times larger) than those of the Permian. We conducted a compositional simulation based study with the objective of comparing the CO2 utilization ratios (volume of CO2 injected to produce a barrel of oil) of 4 conventional and novel CO2 injection strategies: (1) continuous gas injection (CGI), (2) water alternating gas (WAG), (3) water curtain injection (WCI), and (4) WAG and WCI combination. These injection scenarios were simulated using the GEM module from the Computer Modeling Group (CMG). GEM is an advanced general equation-of-state compositional simulator, which includes equation of state, CO2 miscible flood, CO2/brine interactions, and complex phase behavior. The simulator is set up to model three fluid phases including water, oil, and gas. Our study demonstrates how the selected field development strategy has a significant impact on the ultimate recovery of CO2-EOR projects, with GCI injection providing maximum oil recovery in absolute volume terms, but with WAG offering a more balanced technical-economical approach.« less

The Monitoring of Sallow CO2 Leakage From the CO2 Release Experiment in South Korea

NASA Astrophysics Data System (ADS)

Kim, H. J.; Han, S. H.; Kim, S.; Son, Y.

2017-12-01

This study was conducted to analyze the in-soil CO2 gas diffusion from the K-COSEM shallow CO2 release experiment. The study site consisting of five zones was built in Eumseong, South Korea, and approximately 1.8 t CO2 were injected from the perforated release well at Zones 1 to 4 from June 1 to 30, 2016. In-soil CO2 concentrations were measured once a day at 15 cm and 60 cm depths at 0 m, 2.5 m, 5.0 m, and 10.0 m away from the CO2 releasing well using a portable gas analyzer (GA5000) from May 11 to July 27, 2016. On June 4, CO2 leakage was simultaneously detected at 15 cm (8.8 %) and 60 cm (44.0 %) depths at 0 m from the well at Zone 3, and were increased up to about 30 % and 70 %, respectively. During the CO2 injection period, CO2 concentrations measured at 15 cm depth were significantly lower than those measured at 60 cm depth because of the atmospheric pressure effect. After stopping the CO2 injection, CO2 concentrations gradually decreased until July 27, but were still higher than the natural background concentration. This result suggested the possibility of long-term CO2 leakage. In addition, low levels of CO2 leakage were determined using CO2 regression analysis and CO2:O2 ratio. CO2 concentrations measured at 60 cm depth at 0 m from the well at Zones 1 to 4 consistently showed sigmoid increasing patterns with the injection time (R2=0.60-0.99). O2 concentrations at 15 cm and 60 cm depths from the CO2 release experiment were reached 0 % at about 76 % and 84 % of CO2 concentrations, respectively, whereas, those from biological reaction approached 0 % when CO2 increased to about 21 %. Therefore, deep underground monitoring would be able to detect CO2 leakage faster than near-surface monitoring, and CO2 regression and CO2:O2 ratio analyses seemed to be useful as clear indicators of CO2 leakage.

Monitoring a pilot CO2 injection experiment in a shallow aquifer using 3D cross-well electrical resistance tomography

NASA Astrophysics Data System (ADS)

Yang, X.; Lassen, R. N.; Looms, M. C.; Jensen, K. H.

2014-12-01

Three dimensional electrical resistance tomography (ERT) was used to monitor a pilot CO2 injection experiment at Vrøgum, Denmark. The purpose was to evaluate the effectiveness of the ERT method for monitoring the two opposing effects from gas-phase and dissolved CO2 in a shallow unconfined siliciclastic aquifer. Dissolved CO2 increases water electrical conductivity (EC) while gas phase CO2 reduce EC. We injected 45kg of CO2 into a shallow aquifer for 48 hours. ERT data were collected for 50 hours following CO2 injection. Four ERT monitoring boreholes were installed on a 5m by 5m square grid and each borehole had 24 electrodes at 0.5 m electrode spacing at depths from 1.5 m to 13 m. ERT data were inverted using a difference inversion algorithm for bulk EC. 3D ERT successfully detected the CO2 plume distribution and growth in the shallow aquifer. We found that the changes of bulk EC were dominantly positive following CO2 injection, indicating that the effect of dissolved CO2 overwhelmed that of gas phase CO2. The pre-injection baseline resistivity model clearly showed a three-layer structure of the site. The electrically more conductive glacial sand layer in the northeast region are likely more permeable than the overburden and underburden and CO2 plumes were actually confined in this layer. Temporal bulk EC increase from ERT agreed well with water EC and cross-borehole ground penetrating radar data. ERT monitoring offers a competitive advantage over water sampling and GPR methods because it provides 3D high-resolution temporal tomographic images of CO2 distribution and it can also be automated for unattended operation. This work was performed under the auspices of the U.S. Department of Energy by Lawrence Livermore National Laboratory under contract DE-AC52-07NA27344. Lawrence Livermore National Security, LLC. LLNL IM release#: LLNL-PROC-657944.

The planning of a passive seismic experiment: the Ketzin case

NASA Astrophysics Data System (ADS)

Rossi, G.; Petronio, L.

2009-04-01

In the last years, it has been recognized the importance of using microseismic activity data to gain information on the state and dynamics of a reservoir, notwithstanding the difficulties of recording, localizing the events, interpret them correctly, in terms of developing fractures, or thermal effects. The increasing number of CO2 storage experiments, with the necessity of providing efficient, economic, and long-term monitoring methods, both in the injection and post-injection phases, further encourage the development and improvement of recording and processing techniques. Microseismic signals are typically recorded with downhole sensors. Monitoring with surface sensors is problematic due to increased noise levels and signal attenuation particularly in the near surface. The actual detection distance depends on background noise conditions, seismic attenuation and the microseismic source strength. In the frame of the European project Co2ReMoVe and of the European Network of Excellence Co2GeoNet, a passive seismic experiment was planned in the Ketzin site for geological storage of CO2, a former gas store near Potsdam, object of the CO2SINK European project and inserted also in the European project Co2ReMoVe. Aim of the survey is to complement the CO2-SINK active seismic downhole experiments, adding precious information on the microseismicity induced by stress field changes at the reservoir level and in the overburden, due to the CO2 injection. The baseline survey was done in May 2008 by the Istituto Nazionale di Oceanografia e di Geofisica Sperimentale-OGS (Italy), with the support of the Deutsches GeoForschungsZentrum-GFZ (Germany) and the collaboration of the Institut für Geowissenschaftliche Gemeinschaftsaufgaben-GGA (Germany), shortly before the starting of the CO2 injection (June 30th 2008). A continuous monitoring (about 5 days) was performed by 2 downhole 3C geophones, and 3 surface 3C geophones located around the wells. This paper, based on the analysis of the baseline data, is focused on the design and planning of the next seismic passive surveys, optimizing the recording geometry and instrumentation, to record the microseismic events that could be induced by the redistribution of the stresses following the injection, and help the understanding of the injected CO2 behaviour.

Impact of CO2 injection protocol on fluid-solid reactivity: high-pressure and temperature microfluidic experiments in limestone

NASA Astrophysics Data System (ADS)

Jimenez-Martinez, Joaquin; Porter, Mark; Carey, James; Guthrie, George; Viswanathan, Hari

2017-04-01

Geological sequestration of CO2 has been proposed in the last decades as a technology to reduce greenhouse gas emissions to the atmosphere and mitigate the global climate change. However, some questions such as the impact of the protocol of CO2 injection on the fluid-solid reactivity remain open. In our experiments, two different protocols of injection are compared at the same conditions (8.4 MPa and 45 C, and constant flow rate 0.06 ml/min): i) single phase injection, i.e., CO2-saturated brine; and ii) simultaneous injection of CO2-saturated brine and scCO2. For that purpose, we combine a unique high-pressure/temperature microfluidics experimental system, which allows reproducing geological reservoir conditions in geo-material substrates (i.e., limestone, Cisco Formation, Texas, US) and high resolution optical profilometry. Single and multiphase flow through etched fracture networks were optically recorded with a microscope, while processes of dissolution-precipitation in the etched channels were quantified by comparison of the initial and final topology of the limestone micromodels. Changes in hydraulic conductivity were quantified from pressure difference along the micromodel. The simultaneous injection of CO2-saturated brine and scCO2, reduced the brine-limestone contact area and also created a highly heterogeneous velocity field (i.e., low velocities regions or stagnation zones, and high velocity regions or preferential paths), reducing rock dissolution and enhancing calcite precipitation. The results illustrate the contrasting effects of single and multiphase flow on chemical reactivity and suggest that multiphase flow by isolating parts of the flow system can enhance CO2 mineralization.

Experimental insights into the geochemistry and mineralogy of a granite-hosted geothermal system injected with supercritical CO2

NASA Astrophysics Data System (ADS)

Lo Re, C.; Kaszuba, J. P.; Moore, J.; McPherson, B. J.

2011-12-01

Supercritical CO2 may be a viable working fluid in enhanced geothermal systems (EGS) due to its large expansivity, low viscosity, and reduced reactivity with rock as compared to water. Hydrothermal experiments are underway to evaluate the geochemical impact of using supercritical CO2 as a working fluid in granite-hosted geothermal systems. Synthetic aqueous fluid and a model granite are reacted at 250 °C and 250 bars in a rocking autoclave and Au-Ti reaction cell for a minimum of 28 days (water:rock ratio of approximately 20:1). Subsequent injection of supercritical CO2 increases pressure, which decays over time as the CO2 dissolves into the aqueous fluid. Initial experiments decreased to a steady state pressure of 450 bars approximately 14 hours after injection of supercritical CO2. Post-injection reaction is allowed to continue for at least an additional 28 days. Excess CO2 is injected to produce a separate supercritical fluid phase (between 1.7 and 3.1 molal), ensuring aqueous CO2 saturation for the duration of each experiment. The granite was created using mineral separates and consists of ground (75 wt%, <45 microns) and chipped (25 wt%, 0.5-1.0 cm), sub-equal portions of quartz, perthitic potassium feldspar (~ 25 wt% albite and 75 wt% potassium feldspar), oligoclase, and a minor (4 wt%) component of Fe-rich biotite. The synthetic saline water (I = 0.12 m) contains molal quantities of Na, Cl, and HCO3 and millimolal quantities of K, SiO2, SO4, Ca, Al, and Mg, in order of decreasing molality. Aqueous fluids are sampled approximately 10 times over the course of each experiment and analyzed for total dissolved carbon and sulfide by coulometric titration, anions by ion chromatography, and major, minor, and trace cations by ICP-OES and -MS. Bench pH measurements are paired with aqueous analyses to calculate in-situ pH. Solid reactants are evaluated by SEM-EDS, XRD, and/or bulk chemical analysis before and after each experiment. Analytical data are reviewed alongside geochemical models to evaluate fluid-rock interactions and the capacity of theoretical models to predict the observed outcome. Data derived from this study will inform our understanding of how a real world geothermal system may respond geochemically and mineralogically given 'spontaneous' injection of CO2, whether by an anthropogenic or natural source. Companion modeling work is also underway, which will use these experiments to calibrate EGS models for field application.

Performance of CO2 enrich CNG in direct injection engine

NASA Astrophysics Data System (ADS)

Firmansyah, W. B.; Ayandotun, E. Z.; Zainal, A.; Aziz, A. R. A.; Heika, M. R.

2015-12-01

This paper investigates the potential of utilizing the undeveloped natural gas fields in Malaysia with high carbon dioxide (CO2) content ranging from 28% to 87%. For this experiment, various CO2 proportions by volume were added to pure natural gas as a way of simulating raw natural gas compositions in these fields. The experimental tests were carried out using a 4-stroke single cylinder spark ignition (SI) direct injection (DI) compressed natural gas (CNG) engine. The tests were carried out at 180° and 300° before top dead centre (BTDC) injection timing at 3000 rpm, to establish the effects on the engine performance. The results show that CO2 is suppressing the combustion of CNG while on the other hand CNG combustion is causing CO2 dissociation shown by decreasing CO2 emission with the increase in CO2 content. Results for 180° BTDC injection timing shows higher performance compared to 300° BTDC because of two possible reasons, higher volumetric efficiency and higher stratification level. The results also showed the possibility of increasing the CO2 content by injection strategy.

A Field Study on Simulation of CO 2 Injection and ECBM Production and Prediction of CO 2 Storage Capacity in Unmineable Coal Seam

DOE PAGES

He, Qin; Mohaghegh, Shahab D.; Gholami, Vida

2013-01-01

CO 2 sequestration into a coal seam project was studied and a numerical model was developed in this paper to simulate the primary and secondary coal bed methane production (CBM/ECBM) and carbon dioxide (CO 2 ) injection. The key geological and reservoir parameters, which are germane to driving enhanced coal bed methane (ECBM) and CO 2 sequestration processes, including cleat permeability, cleat porosity, CH 4 adsorption time, CO 2 adsorption time, CH 4 Langmuir isotherm, CO 2 Langmuir isotherm, and Palmer and Mansoori parameters, have been analyzed within a reasonable range. The model simulation results showed good matches for bothmore » CBM/ECBM production and CO 2 injection compared with the field data. The history-matched model was used to estimate the total CO 2 sequestration capacity in the field. The model forecast showed that the total CO 2 injection capacity in the coal seam could be 22,817 tons, which is in agreement with the initial estimations based on the Langmuir isotherm experiment. Total CO 2 injected in the first three years was 2,600 tons, which according to the model has increased methane recovery (due to ECBM) by 6,700 scf/d.« less

Influence of Capillary Force and Buoyancy on CO2 Migration During CO2 Injection in a Sandstone Reservoir

NASA Astrophysics Data System (ADS)

Wu, H.; Pollyea, R.

2017-12-01

Carbon capture and sequestration (CCS) is one component of a broad carbon management portfolio designed to mitigate adverse effects of anthropogenic CO2 emissions. During CCS, capillary trapping is an important mechanism for CO2 isolation in the disposal reservoir, and, as a result, the distribution of capillary force is an important factor affecting CO2 migration. Moreover, the movement of CO2 being injected to the reservoir is also affected by buoyancy, which results from the density difference between CO2 and brine. In order to understand interactions between capillary force and buoyancy, we implement a parametric modeling experiment of CO2 injections in a sandstone reservoir for combinations of the van Genuchten capillary pressure model that bound the range of capillary pressure-saturation curves measured in laboratory experiments. We simulate ten years supercritical CO2 (scCO2) injections within a 2-D radially symmetric sandstone reservoir for five combinations of the van Genuchten model parameters λ and entry pressure (P0). Results are analyzed on the basis of a modified dimensionless ratio, ω, which is similar to the Bond number and defines the relationship between buoyancy pressure and capillary pressure. We show how parametric variability affects the relationship between buoyancy and capillary force, and thus controls CO2 plume geometry. These results indicate that when ω >1, then buoyancy governs the system and CO2 plume geometry is governed by upward flow. In contrast, when ω <1, then buoyancy is smaller than capillary force and lateral flow governs CO2 plume geometry. As a result, we show that the ω ratio is an easily implemented screening tool for qualitative assessment of reservoir performance.

Reactivity of Iron Bearing Minerals and CO 2 Sequestration: A Multi-­Disciplinary and Experimental Approach

DOE Office of Scientific and Technical Information (OSTI.GOV)

Schoonen, Martin A.

2014-12-22

The reactivity of sandstones was studied under conditions relevant to the injection of supercritical carbon dioxide in the context of carbon geosequestration. The emphasis of the study was on the reactivity of iron-­bearing minerals when exposed to supercritical CO 2 (scCO 2) and scCO 2 with commingled aqueous solutions containing H 2S and/or SO 2. Flow through and batch experiments were conducted. Results indicate that sandstones, irrespective of their mineralogy, are not reactive when exposed to pure scCO2 or scCO 2 with commingled aqueous solutions containing H 2S and/or SO 2 under conditions simulating the environment near the injection pointmore » (flow through experiments). However, sandstones are reactive under conditions simulating the edge of the injected CO 2 plume or ahead of the plume (batch experiments). Sandstones containing hematite (red sandstone) are particularly reactive. The composition of the reaction products is strongly dependent on the composition of the aqueous phase. The presence of dissolved sulfide leads to the conversion of hematite into pyrite and siderite. The relative amount of the pyrite and siderite is influenced by the ionic strength of the solution. Little reactivity is observed when sulfite is present in the aqueous phase. Sandstones without hematite (grey sandstones) show little reactivity regardless of the solution composition.« less

Artificial Weathering as a Function of CO2 Injection in Pahang Sandstone Malaysia: Investigation of Dissolution Rate in Surficial Condition

PubMed Central

Jalilavi, Madjid; Zoveidavianpoor, Mansoor; Attarhamed, Farshid; Junin, Radzuan; Mohsin, Rahmat

2014-01-01

Formation of carbonate minerals by CO2 sequestration is a potential means to reduce atmospheric CO2 emissions. Vast amount of alkaline and alkali earth metals exist in silicate minerals that may be carbonated. Laboratory experiments carried out to study the dissolution rate in Pahang Sandstone, Malaysia, by CO2 injection at different flow rate in surficial condition. X-ray Powder Diffraction (XRD), Scanning Electron Microscope (SEM) with Energy Dispersive X-ray Spectroscopy (EDX), Atomic Absorption Spectroscopy (AAS) and weight losses measurement were performed to analyze the solid and liquid phase before and after the reaction process. The weight changes and mineral dissolution caused by CO2 injection for two hours CO2 bubbling and one week' aging were 0.28% and 18.74%, respectively. The average variation of concentrations of alkaline earth metals in solution varied from 22.62% for Ca2+ to 17.42% for Mg2+, with in between 16.18% observed for the alkali earth metal, potassium. Analysis of variance (ANOVA) test is performed to determine significant differences of the element concentration, including Ca, Mg, and K, before and after the reaction experiment. Such changes show that the deposition of alkali and alkaline earth metals and the dissolution of required elements in sandstone samples are enhanced by CO2 injection. PMID:24413195

Artificial weathering as a function of CO2 injection in Pahang Sandstone Malaysia: investigation of dissolution rate in surficial condition.

PubMed

Jalilavi, Madjid; Zoveidavianpoor, Mansoor; Attarhamed, Farshid; Junin, Radzuan; Mohsin, Rahmat

2014-01-13

Formation of carbonate minerals by CO2 sequestration is a potential means to reduce atmospheric CO2 emissions. Vast amount of alkaline and alkali earth metals exist in silicate minerals that may be carbonated. Laboratory experiments carried out to study the dissolution rate in Pahang Sandstone, Malaysia, by CO2 injection at different flow rate in surficial condition. X-ray Powder Diffraction (XRD), Scanning Electron Microscope (SEM) with Energy Dispersive X-ray Spectroscopy (EDX), Atomic Absorption Spectroscopy (AAS) and weight losses measurement were performed to analyze the solid and liquid phase before and after the reaction process. The weight changes and mineral dissolution caused by CO2 injection for two hours CO2 bubbling and one week' aging were 0.28% and 18.74%, respectively. The average variation of concentrations of alkaline earth metals in solution varied from 22.62% for Ca(2+) to 17.42% for Mg(2+), with in between 16.18% observed for the alkali earth metal, potassium. Analysis of variance (ANOVA) test is performed to determine significant differences of the element concentration, including Ca, Mg, and K, before and after the reaction experiment. Such changes show that the deposition of alkali and alkaline earth metals and the dissolution of required elements in sandstone samples are enhanced by CO2 injection.

Artificial Weathering as a Function of CO2 Injection in Pahang Sandstone Malaysia: Investigation of Dissolution Rate in Surficial Condition

NASA Astrophysics Data System (ADS)

Jalilavi, Madjid; Zoveidavianpoor, Mansoor; Attarhamed, Farshid; Junin, Radzuan; Mohsin, Rahmat

2014-01-01

Formation of carbonate minerals by CO2 sequestration is a potential means to reduce atmospheric CO2 emissions. Vast amount of alkaline and alkali earth metals exist in silicate minerals that may be carbonated. Laboratory experiments carried out to study the dissolution rate in Pahang Sandstone, Malaysia, by CO2 injection at different flow rate in surficial condition. X-ray Powder Diffraction (XRD), Scanning Electron Microscope (SEM) with Energy Dispersive X-ray Spectroscopy (EDX), Atomic Absorption Spectroscopy (AAS) and weight losses measurement were performed to analyze the solid and liquid phase before and after the reaction process. The weight changes and mineral dissolution caused by CO2 injection for two hours CO2 bubbling and one week' aging were 0.28% and 18.74%, respectively. The average variation of concentrations of alkaline earth metals in solution varied from 22.62% for Ca2+ to 17.42% for Mg2+, with in between 16.18% observed for the alkali earth metal, potassium. Analysis of variance (ANOVA) test is performed to determine significant differences of the element concentration, including Ca, Mg, and K, before and after the reaction experiment. Such changes show that the deposition of alkali and alkaline earth metals and the dissolution of required elements in sandstone samples are enhanced by CO2 injection.

The Field-Laboratory for CO2 Storage 'CO2SINK

NASA Astrophysics Data System (ADS)

Würdemann, Hilke; Möller, Fabian; Kühn, Michael; Borm, Günter; Schilling, Frank R.

2010-05-01

The first European onshore geological CO2 storage project in a saline aquifer CO2SINK is designed as a field size experiment to better understand in situ storage processes and to test various monitoring techniques. This EU project is run by 18 partners from universities, research institutes and industry out of 9 European countries (www.co2sink.org). The CO2 is injected into Upper Triassic sandstones (Stuttgart Formation) of a double-anticline at a depth of 650 m. The Stuttgart Formation represents a flu vial environment comprised of sandstone channels and silty to muddy deposits. The anticline forms a classical multibarrier system: The first caprock is a playa type mudstone of the Weser and Arnstadt formations directly overlying the Stuttgart formation. Laboratory tests revealed permeabilities in a µDarcy-range. The second main caprock is a tertiary clay, the so-called Rupelton. To determine the maximum injection pressure modified leak-off tests (without fracturing the caprock) were performed resulting in values around 120 bar. Due to safety standards the pressure threshold is set to 82 bar until more experience on the reservoir behaviour is available. The sealing property of the secondary cap rock is well known from decades of natural gas storage operations at the testing site and was the basis for the permission to operate the CO2 storage by the mining authority. Undisturbed, initial reservoir conditions are 35 °C and 62 bar. The initial reservoir fluid is highly saline with about 235 g/l total dissolved solids primarily composed of sodium chloride with notable amounts of calcium chloride. The initial pH value is 6.6. Hydraulic tests as well as laboratory tests revealed a permeability between 50 and 100 mDarcy for the sand channels of the storage formation. Within twenty months of storage operation, about 30,000 t of CO2 have been injected. Spreading of the CO2 plume is monitored by a broad range of geophysical techniques. The injection well and the two observation wells are equipped with 'smart casing technology' containing a Distributed Temperature Sensing (DTS) and electrodes for Electrical Resistivity Tomography (ERT) behind casing, facing the rocks. The geophysical monitoring includes crosshole seismic experiments, Vertical Seismic Profiling (VSP) and Moving Source Profiling (MSP), star seismic experiments and 4-D seismics. Gas membrane sensors (GMS) monitored the arrival of CO2 at the observation wells: CO2 arrived after injection of about 500 t of CO2.at the first well. Arrival in the second well was 9 months after start of injection, having injected an amount of about 11,000 t. Prior to CO2, the arrival of the gas tracers nitrogen and krypton was observed. Pressure and temperature logs showed a supercritical state of the CO2 in all three wells at depth of the storage formation after arrival of CO2. Downhole samples of the brine showed changes in the fluid composition and the activity of biocenosis due CO2 exposure (Morozova et al., EGU General Assembly 2010). Numerical models are benchmarked via the monitoring results indicating a sufficient match for the arrival at the first observation well. First results of ERT measurements indicate an anisotopic flow of CO2 coinciding with the 'on-time' arrival of CO2 at the first well and the late arrival at the second well. Time lapse crosshole seismics showed no considerable change in seismic velocity between the two observation wells within the first two repeats after injection of 660 t and 1,700 t of CO2, respectively. However, after injection of 18,000 t CO2 all time-lapse surveys showed a clearly observable signature of the CO2 propagating in the Stuttgart formation. In May 2010 results from twenty months of operation and monitoring the storage operation will be presented. Morozova, D., Zettlitzer, M.., Vieth A., Würdemann, H., (2010). Microbial community response to the CO2 injection and storage in the saline aquifer, Ketzin, Germany. European Geosciences Union (EGU) General Assembly. Vienna.

Interactions and exchange of CO2 and H2O in coals: an investigation by low-field NMR relaxation

NASA Astrophysics Data System (ADS)

Sun, Xiaoxiao; Yao, Yanbin; Liu, Dameng; Elsworth, Derek; Pan, Zhejun

2016-01-01

The mechanisms by which CO2 and water interact in coal remain unclear and these are key questions for understanding ECBM processes and defining the long-term behaviour of injected CO2. In our experiments, we injected helium/CO2 to displace water in eight water-saturated samples. We used low-field NMR relaxation to investigate CO2 and water interactions in these coals across a variety of time-scales. The injection of helium did not change the T2 spectra of the coals. In contrast, the T2 spectra peaks of micro-capillary water gradually decreased and those of macro-capillary and bulk water increased with time after the injection of CO2. We assume that the CO2 diffuses through and/or dissolves into the capillary water to access the coal matrix interior, which promotes desorption of water molecules from the surfaces of coal micropores and mesopores. The replaced water mass is mainly related to the Langmuir adsorption volume of CO2 and increases as the CO2 adsorption capacity increases. Other factors, such as mineral composition, temperature and pressure, also influence the effective exchange between water and CO2. Finally, we built a quantified model to evaluate the efficiency of water replacement by CO2 injection with respect to temperature and pressure.

Interactions and exchange of CO2 and H2O in coals: an investigation by low-field NMR relaxation.

PubMed

Sun, Xiaoxiao; Yao, Yanbin; Liu, Dameng; Elsworth, Derek; Pan, Zhejun

2016-01-28

The mechanisms by which CO2 and water interact in coal remain unclear and these are key questions for understanding ECBM processes and defining the long-term behaviour of injected CO2. In our experiments, we injected helium/CO2 to displace water in eight water-saturated samples. We used low-field NMR relaxation to investigate CO2 and water interactions in these coals across a variety of time-scales. The injection of helium did not change the T2 spectra of the coals. In contrast, the T2 spectra peaks of micro-capillary water gradually decreased and those of macro-capillary and bulk water increased with time after the injection of CO2. We assume that the CO2 diffuses through and/or dissolves into the capillary water to access the coal matrix interior, which promotes desorption of water molecules from the surfaces of coal micropores and mesopores. The replaced water mass is mainly related to the Langmuir adsorption volume of CO2 and increases as the CO2 adsorption capacity increases. Other factors, such as mineral composition, temperature and pressure, also influence the effective exchange between water and CO2. Finally, we built a quantified model to evaluate the efficiency of water replacement by CO2 injection with respect to temperature and pressure.

Interactions and exchange of CO2 and H2O in coals: an investigation by low-field NMR relaxation

PubMed Central

Sun, Xiaoxiao; Yao, Yanbin; Liu, Dameng; Elsworth, Derek; Pan, Zhejun

2016-01-01

The mechanisms by which CO2 and water interact in coal remain unclear and these are key questions for understanding ECBM processes and defining the long-term behaviour of injected CO2. In our experiments, we injected helium/CO2 to displace water in eight water-saturated samples. We used low-field NMR relaxation to investigate CO2 and water interactions in these coals across a variety of time-scales. The injection of helium did not change the T2 spectra of the coals. In contrast, the T2 spectra peaks of micro-capillary water gradually decreased and those of macro-capillary and bulk water increased with time after the injection of CO2. We assume that the CO2 diffuses through and/or dissolves into the capillary water to access the coal matrix interior, which promotes desorption of water molecules from the surfaces of coal micropores and mesopores. The replaced water mass is mainly related to the Langmuir adsorption volume of CO2 and increases as the CO2 adsorption capacity increases. Other factors, such as mineral composition, temperature and pressure, also influence the effective exchange between water and CO2. Finally, we built a quantified model to evaluate the efficiency of water replacement by CO2 injection with respect to temperature and pressure. PMID:26817784

Microfluidic study for investigating migration and residual phenomena of supercritical CO2 in porous media

NASA Astrophysics Data System (ADS)

Park, Gyuryeong; Wang, Sookyun; Lee, Minhee; Um, Jeong-Gi; Kim, Seon-Ok

2017-04-01

The storage of CO2 in underground geological formation such as deep saline aquifers or depleted oil and gas reservoirs is one of the most promising technologies for reducing the atmospheric CO2 release. The processes in geological CO2 storage involves injection of supercritical CO2 (scCO2) into porous formations saturated with brine and initiates CO2 flooding with immiscible displacement. The CO2 migration and porewater displacement within geological formations, and , consequentially, the storage efficiency are governed by the interaction of fluid and rock properties and are affected by the interfacial tension, capillarity, and wettability in supercritical CO2-brine-mineral systems. This study aims to observe the displacement pattern and estimate storage efficiency by using micromodels. This study aims to conduct scCO2 injection experiments for visualization of distribution of injected scCO2 and residual porewater in transparent pore networks on microfluidic chips under high pressure and high temperature conditions. In order to quantitatively analyze the porewater displacement by scCO2 injection under geological CO2 storage conditions, the images of invasion patterns and distribution of CO2 in the pore network are acquired through a imaging system with a microscope. The results from image analysis were applied in quantitatively investigating the effects of major environmental factors and scCO2 injection methods on porewater displacement process by scCO2 and storage efficiency. The experimental observation results could provide important fundamental information on capillary characteristics of reservoirs and improve our understanding of CO2 sequestration progress.

Microbial succession and stimulation following a test well injection simulating CO2 leakage into shallow Newark Basin aquifers

NASA Astrophysics Data System (ADS)

Dueker, M.; Clauson, K.; Yang, Q.; Umemoto, K.; Seltzer, A. M.; Zakharova, N. V.; Matter, J. M.; Stute, M.; Takahashi, T.; Goldberg, D.; O'Mullan, G. D.

2012-12-01

Despite growing appreciation for the importance of microbes in altering geochemical reactions in the subsurface, the microbial response to geological carbon sequestration injections and the role of microbes in altering metal mobilization following leakage scenarios in shallow aquifers remain poorly constrained. A Newark Basin test well was utilized in field experiments to investigate patterns of microbial succession following injection of CO2 saturated water into isolated aquifer intervals. Additionally, laboratory mesocosm experiments, including microbially-active and inactive (autoclave sterilized) treatments, were used to constrain the microbial role in mineral dissolution, trace metal release, and gas production (e.g. hydrogen and methane). Hydrogen production was detected in both sterilized and unsterilized laboratory mesocosm treatments, indicating abiotic hydrogen production may occur following CO2 leakage, and methane production was detected in unsterilized, microbially active mesocosms. In field experiments, a decrease in pH following injection of CO2 saturated aquifer water was accompanied by mobilization of trace elements (e.g. Fe and Mn), the production of hydrogen gas, and increased bacterial cell concentrations. 16S ribosomal RNA clone libraries, from samples collected before and after the test well injection, were compared in an attempt to link variability in geochemistry to changes in aquifer microbiology. Significant changes in microbial composition, compared to background conditions, were found following the test well injection, including a decrease in Proteobacteria, and an increased presence of Firmicutes, Verrucomicrobia, Acidobacteria and other microbes associated with iron reducing and syntrophic metabolism. The concurrence of increased microbial cell concentration, and rapid microbial community succession, with increased concentrations of hydrogen gas suggests that abiotically produced hydrogen may serve as an ecologically-relevant energy source stimulating changes in aquifer microbial communities immediately following CO2 leakage.

Mineral Dissolution and Precipitation due to Carbon Dioxide-Water-Rock Interactions: The Significance of Accessory Minerals in Carbonate Reservoirs (Invited)

NASA Astrophysics Data System (ADS)

Kaszuba, J. P.; Marcon, V.; Chopping, C.

2013-12-01

Accessory minerals in carbonate reservoirs, and in the caprocks that seal these reservoirs, can provide insight into multiphase fluid (CO2 + H2O)-rock interactions and the behavior of CO2 that resides in these water-rock systems. Our program integrates field data, hydrothermal experiments, and geochemical modeling to evaluate CO2-water-rock reactions and processes in a variety of carbonate reservoirs in the Rocky Mountain region of the US. These studies provide insights into a wide range of geologic environments, including natural CO2 reservoirs, geologic carbon sequestration, engineered geothermal systems, enhanced oil and gas recovery, and unconventional hydrocarbon resources. One suite of experiments evaluates the Madison Limestone on the Moxa Arch, Southwest Wyoming, a sulfur-rich natural CO2 reservoir. Mineral textures and geochemical features developed in the experiments suggest that carbonate minerals which constitute the natural reservoir will initially dissolve in response to emplacement of CO2. Euhedral, bladed anhydrite concomitantly precipitates in response to injected CO2. Analogous anhydrite is observed in drill core, suggesting that secondary anhydrite in the natural reservoir may be related to emplacement of CO2 into the Madison Limestone. Carbonate minerals ultimately re-precipitate, and anhydrite dissolves, as the rock buffers the acidity and reasserts geochemical control. Another suite of experiments emulates injection of CO2 for enhanced oil recovery in the Desert Creek Limestone (Paradox Formation), Paradox Basin, Southeast Utah. Euhedral iron oxyhydroxides (hematite) precipitate at pH 4.5 to 5 and low Eh (approximately -0.1 V) as a consequence of water-rock reaction. Injection of CO2 decreases pH to approximately 3.5 and increases Eh by approximately 0.1 V, yielding secondary mineralization of euhedral pyrite instead of iron oxyhydroxides. Carbonate minerals also dissolve and ultimately re-precipitate, as determined by experiments in the Madison Limestone, but pyrite will persist and iron oxyhydroxides will not recrystallize.

Measurement of electrical impedance of a Berea sandstone core during the displacement of saturated brine by oil and CO2 injections

NASA Astrophysics Data System (ADS)

Liu, Yu; Xue, Ziqiu; Park, Hyuck; Kiyama, Tamotsu; Zhang, Yi; Nishizawa, Osamu; Chae, Kwang-seok

2015-12-01

Complex electrical impedance measurements were performed on a brine-saturated Berea sandstone core while oil and CO2 were injected at different pressures and temperatures. The saturations of brine, oil, and CO2 in the core were simultaneously estimated using an X-ray computed tomography scanner. The formation factor of this Berea core and the resistivity indexes versus the brine saturations were calculated using Archie's law. The experimental results found different flow patterns of oil under different pressures and temperatures. Fingers were observed for the first experiment at 10 MPa and 40 °C. The fingers were restrained as the viscosity ratio of oil and water changed in the second (10 MPa and 25 °C) and third (5 MPa and 25 °C) experiments. The resistivity index showed an exponential increase with a decrease in brine saturation. The saturation exponent varied from 1.4 to 4.0 at different pressure and temperature conditions. During the oil injection procedure, the electrical impedance increased with oil saturation and was significantly affected by different oil distributions; therefore, the impedance varied whether the finger was remarkable or not, even if the oil saturation remained constant. During the CO2 injection steps, the impedance showed almost no change with CO2 saturation because the brine in the pores became immobile after the oil injection.

Biological CO2 conversion to acetate in subsurface coal-sand formation using a high-pressure reactor system.

PubMed

Ohtomo, Yoko; Ijiri, Akira; Ikegawa, Yojiro; Tsutsumi, Masazumi; Imachi, Hiroyuki; Uramoto, Go-Ichiro; Hoshino, Tatsuhiko; Morono, Yuki; Sakai, Sanae; Saito, Yumi; Tanikawa, Wataru; Hirose, Takehiro; Inagaki, Fumio

2013-01-01

Geological CO2 sequestration in unmineable subsurface oil/gas fields and coal formations has been proposed as a means of reducing anthropogenic greenhouse gasses in the atmosphere. However, the feasibility of injecting CO2 into subsurface depends upon a variety of geological and economic conditions, and the ecological consequences are largely unpredictable. In this study, we developed a new flow-through-type reactor system to examine potential geophysical, geochemical and microbiological impacts associated with CO2 injection by simulating in-situ pressure (0-100 MPa) and temperature (0-70°C) conditions. Using the reactor system, anaerobic artificial fluid and CO2 (flow rate: 0.002 and 0.00001 ml/min, respectively) were continuously supplemented into a column comprised of bituminous coal and sand under a pore pressure of 40 MPa (confined pressure: 41 MPa) at 40°C for 56 days. 16S rRNA gene analysis of the bacterial components showed distinct spatial separation of the predominant taxa in the coal and sand over the course of the experiment. Cultivation experiments using sub-sampled fluids revealed that some microbes survived, or were metabolically active, under CO2-rich conditions. However, no methanogens were activated during the experiment, even though hydrogenotrophic and methylotrophic methanogens were obtained from conventional batch-type cultivation at 20°C. During the reactor experiment, the acetate and methanol concentration in the fluids increased while the δ(13)Cacetate, H2 and CO2 concentrations decreased, indicating the occurrence of homo-acetogenesis. 16S rRNA genes of homo-acetogenic spore-forming bacteria related to the genus Sporomusa were consistently detected from the sandstone after the reactor experiment. Our results suggest that the injection of CO2 into a natural coal-sand formation preferentially stimulates homo-acetogenesis rather than methanogenesis, and that this process is accompanied by biogenic CO2 conversion to acetate.

Biological CO2 conversion to acetate in subsurface coal-sand formation using a high-pressure reactor system

PubMed Central

Ohtomo, Yoko; Ijiri, Akira; Ikegawa, Yojiro; Tsutsumi, Masazumi; Imachi, Hiroyuki; Uramoto, Go-Ichiro; Hoshino, Tatsuhiko; Morono, Yuki; Sakai, Sanae; Saito, Yumi; Tanikawa, Wataru; Hirose, Takehiro; Inagaki, Fumio

2013-01-01

Geological CO2 sequestration in unmineable subsurface oil/gas fields and coal formations has been proposed as a means of reducing anthropogenic greenhouse gasses in the atmosphere. However, the feasibility of injecting CO2 into subsurface depends upon a variety of geological and economic conditions, and the ecological consequences are largely unpredictable. In this study, we developed a new flow-through-type reactor system to examine potential geophysical, geochemical and microbiological impacts associated with CO2 injection by simulating in-situ pressure (0–100 MPa) and temperature (0–70°C) conditions. Using the reactor system, anaerobic artificial fluid and CO2 (flow rate: 0.002 and 0.00001 ml/min, respectively) were continuously supplemented into a column comprised of bituminous coal and sand under a pore pressure of 40 MPa (confined pressure: 41 MPa) at 40°C for 56 days. 16S rRNA gene analysis of the bacterial components showed distinct spatial separation of the predominant taxa in the coal and sand over the course of the experiment. Cultivation experiments using sub-sampled fluids revealed that some microbes survived, or were metabolically active, under CO2-rich conditions. However, no methanogens were activated during the experiment, even though hydrogenotrophic and methylotrophic methanogens were obtained from conventional batch-type cultivation at 20°C. During the reactor experiment, the acetate and methanol concentration in the fluids increased while the δ13Cacetate, H2 and CO2 concentrations decreased, indicating the occurrence of homo-acetogenesis. 16S rRNA genes of homo-acetogenic spore-forming bacteria related to the genus Sporomusa were consistently detected from the sandstone after the reactor experiment. Our results suggest that the injection of CO2 into a natural coal-sand formation preferentially stimulates homo-acetogenesis rather than methanogenesis, and that this process is accompanied by biogenic CO2 conversion to acetate. PMID:24348470

Short-core acoustic resonant bar test and x-ray CT imaging on sandstone samples during super-critical CO2 flooding and dissolution

NASA Astrophysics Data System (ADS)

Nakagawa, S.; Kneafsey, T. J.; Daley, T. M.; Freifeld, B. M.

2010-12-01

Geological sequestration of CO2 requires accurate monitoring of the spatial distribution and pore-level saturation of super-critical (sc-) CO2 for both optimizing reservoir performance and satisfying regulatory requirements. Fortunately, thanks to the high compliance of sc-CO2 compared to brine under in-situ temperatures and pressures, injection of sc-CO2 into initially brine-saturated rock will lead to significant reductions in seismic velocity and increased attenuation of seismic waves. Because of the frequency-dependent nature of this relationship, its determination requires testing at low frequencies (10 Hz-10 kHz) that are not usually employed in the laboratory. In this paper, we present the changes in seismic wave velocities and attenuation in sandstone cores during sc-CO2 core flooding and during subsequent brine re-injection and CO2 removal via convection and dissolution. The experiments were conducted at frequencies near 1 kHz using a variation of the acoustic resonant bar technique, called the Split Hopkinson Resonant Bar (SHRB) method, which allows measurements under elevated temperatures and pressures (up to 120°C, 35 MPa), using a short (several cm long) core. Concurrent x-ray CT scanning reveals sc-CO2 saturation and distribution within the cores. The injection experiments revealed different CO2 patch size distributions within the cores between the injection phase and the convection/dissolution phase of the tests. The difference was reflected particularly in the P-wave velocities and attenuation. Also, compared to seismic responses, which were separately measured during a gas CO2 injection/drainage test, the seismic responses from the sc-CO2 test showed measurable changes over a wider range of brine saturation. Considering the proximity of the frequency band employed by our measurement to the field seismic measurements, this result implies that seismic monitoring of sc-CO2, if constrained by laboratory data and interpreted using a proper petrophysical model, can be conducted with greater accuracy for determining the sc-CO2 saturation and distribution within reservoir rock, than typically predicted by the Gassmann model and/or by a natural gas reservoir analogue.

Surface-downhole and crosshole geoelectrics for monitoring of brine injection at the Ketzin CO2 storage site

NASA Astrophysics Data System (ADS)

Rippe, Dennis; Bergmann, Peter; Labitzke, Tim; Wagner, Florian; Schmidt-Hattenberger, Cornelia

2016-04-01

The Ketzin pilot site in Germany is the longest operating on-shore CO2 storage site in Europe. From June 2008 till August 2013, a total of ˜67,000 tonnes of CO2 were safely stored in a saline aquifer at depths of 630 m to 650 m. The storage site has now entered the abandonment phase, and continuation of the multi-disciplinary monitoring as part of the national project "CO2 post-injection monitoring and post-closure phase at the Ketzin pilot site" (COMPLETE) provides the unique chance to participate in the conclusion of the complete life cycle of a CO2 storage site. As part of the continuous evaluation of the functionality and integrity of the CO2 storage in Ketzin, from October 12, 2015 till January 6, 2015 a total of ˜2,900 tonnes of brine were successfully injected into the CO2 reservoir, hereby simulating in time-lapse the natural backflow of brine and the associated displacement of CO2. The main objectives of this brine injection experiment include investigation of how much of the CO2 in the pore space can be displaced by brine and if this displacement of CO2 during the brine injection differs from the displacement of formation fluid during the initial CO2 injection. Geophysical monitoring of the brine injection included continuous geoelectric measurements accompanied by monitoring of pressure and temperature conditions in the injection well and two adjacent observation wells. During the previous CO2 injection, the geoelectrical monitoring concept at the Ketzin pilot site consisted of permanent crosshole measurements and non-permanent large-scale surveys (Kiessling et al., 2010). Time-lapse geoelectrical tomographies derived from the weekly crosshole data at near-wellbore scale complemented by six surface-downhole surveys at a scale of 1.5 km showed a noticeable resistivity signature within the target storage zone, which was attributed to the CO2 plume (Schmidt-Hattenberger et al., 2011) and interpreted in terms of relative CO2 and brine saturations (Bergmann et al., 2012). During the brine injection, usage of a new data acquisition unit allowed the daily collection of an extended crosshole data set. This data set was complemented by an alternative surface-downhole acquisition geometry, which for the first time allowed for regular current injections from three permanent surface electrodes into the existing electrical resistivity downhole array without the demand of an extensive field survey. This alternative surface-downhole acquisition geometry is expected to be characterized by good data quality and well confined sensitivity to the target storage zone. Time-lapse geoelectrical tomographies have been derived from both surface-downhole and crosshole data and show a conductive signature around the injection well associated with the displacement of CO2 by the injected brine. In addition to the above mentioned objectives of this brine injection experiment, comparative analysis of the surface-downhole and crosshole data provides the opportunity to evaluate the alternative surface-downhole acquisition geometry with respect to its resolution within the target storage zone and its ability to quantitatively constrain the displacement of CO2 during the brine injection. These results will allow for further improvement of the deployed alternative surface-downhole acquisition geometries. References Bergmann, P., Schmidt-Hattenberger, C., Kiessling, D., Rücker, C., Labitzke, T., Henninges, J., Baumann, G., Schütt, H. (2012). Surface-Downhole Electrical Resistivity Tomography applied to Monitoring of the CO2 Storage Ketzin (Germany). Geophysics, 77, B253-B267. Kiessling, D., Schmidt-Hattenberger, C., Schuett, H., Schilling, F., Krueger, K., Schoebel, B., Danckwardt, E., Kummerow, J., CO2SINK Group (2010). Geoelectrical methods for monitoring geological CO2 storage: First results from cross-hole and surface-downhole measurements from the CO2SINK test site at Ketzin (Germany). International Journal of Greenhouse Gas Control, 4(5), 816-826. Schmidt-Hattenberger, C., Bergmann, P., Kießling, D., Krüger, K., Rücker, C., Schütt, H., Ketzin Group (2011). Application of a Vertical Electrical Resistivity Array (VERA) for monitoring CO2 migration at the Ketzin site: First performance evaluation. Energy Procedia, 4, 3363-3370.

Experimental observation and numerical simulation of permeability changes in dolomite at CO2 sequestration conditions

NASA Astrophysics Data System (ADS)

Tutolo, B. M.; Luhmann, A. J.; Kong, X.; Saar, M. O.; Seyfried, W. E.

2013-12-01

Injecting surface temperature CO2 into geothermally warm reservoirs for geologic storage or energy production may result in depressed temperature near the injection well and thermal gradients and mass transfer along flow paths leading away from the well. Thermal gradients are particularly important to consider in reservoirs containing carbonate minerals, which are more soluble at lower temperatures, as well as in CO2-based geothermal energy reservoirs where lowering heat exchanger rejection temperatures increases efficiency. Additionally, equilibrating a fluid with cation-donating silicates near a low-temperature injection well and transporting the fluid to higher temperature may enhance the kinetics of mineral precipitation in such a way as to overcome the activation energy required for mineral trapping of CO2. We have investigated this process by subjecting a dolomite core to a 650-hour temperature series experiment in which the fluid was saturated with CO2 at high pressure (110-126 bars) and 21°C. This fluid was recirculated through the dolomite core, increasing permeability from 10-16 to 10-15.2 m2. Subsequently, the core temperature was raised to 50° C, and permeability decreased to 10-16.2 m2 after 289 hours, due to thermally-driven CO2 exsolution. Increasing core temperature to 100°C for the final 145 hours of the experiment caused dolomite to precipitate, which, together with further CO2 exsolution, decreased permeability to 10-16.4 m2. Post-experiment x-ray computed tomography and scanning electron microscope imagery of the dolomite core reveals abundant matrix dissolution and enlargement of flow paths at low temperatures, and subsequent filling-in of the passages at elevated temperature by dolomite. To place this experiment within the broader context of geologic CO2 sequestration, we designed and utilized a reactive transport simulator that enables dynamic calculation of CO2 equilibrium constants and fugacity and activity coefficients by incorporating mineral, fluid, and aqueous species equations of state into its structure. Phase equilibria calculations indicate that fluids traveling away from the depressed temperature zone near the injection well may exsolve and precipitate up to 200 cc CO2, 1.45 cc dolomite, and 2.3 cc calcite, per kg, but we use the reactive transport simulator to place more realistic limits on these calculations. The simulations show that thermally-induced CO2 exsolution creates velocity gradients within the modeled domain, leading to increased velocities at lower pressure due to the increasingly gas-like density of CO2. Because dolomite precipitation kinetics strongly depend on temperature, modeled dolomite precipitation effectively concentrates within high temperature regions, while calcite precipitation is predicted to occur over a broader range. Additionally, because the molar volume of dolomite is almost double that of calcite, transporting a low temperature, dolomite-saturated fluid across a thermal gradient can lead to more substantial pore space clogging. We conclude that injecting cool CO2 into geothermally warm reservoirs may substantially alter formation porosity, permeability, and injectivity, and can result in favorable conditions for permanent storage of CO2 as a solid carbonate phase.

Monitoring CO2 penetration and storage in the brine-saturated low permeable sandstone by the geophysical exploration technologies

NASA Astrophysics Data System (ADS)

Honda, H.; Mitani, Y.; Kitamura, K.; Ikemi, H.; Imasato, M.

2017-12-01

Carbon dioxide (CO2) capture and storage (CCS) plays a vital role in reducing greenhouse gas emissions. In the northern part of Kyushu region of Japan, complex geological structure (Coalfield) is existed near the CO2 emission source and has 1.06 Gt of CO2 storage capacity. The geological survey shows that these layers are formed by low permeable sandstone. It is necessary to monitor the CO2 behavior and clear the mechanisms of CO2 penetration and storage in the low permeable sandstone. In this study, measurements of complex electrical impedance (Z) and elastic wave velocity (P-wave velocity: Vp) were conducted during the supercritical CO2 injection experiment into the brine-saturated low permeable sandstone. The experiment conditions were as follows; Confining pressure: 20 MPa, Initial pore pressure: 10 MPa, 40 °, CO2 injection rate: 0.01 to 0.5 mL/min. Z was measured in the center of the specimen and Vp were measured at three different heights of the specimen at constant intervals. In addition, we measured the longitudinal and lateral strain at the center of the specimen, the pore pressure and CO2 injection volume (CO2 saturation). During the CO2 injection, the change of Z and Vp were confirmed. In the drainage terms, Vp decreased drastically once CO2 reached the measurement cross section.Vp showed the little change even if the flow rate increased (CO2 saturation increased). On the other hand, before the CO2 front reached, Z decreased with CO2-dissolved brine. After that, Z showed continuously increased as the CO2 saturation increased. From the multi-parameter (Hydraulic and Rock-physics parameters), we revealed the detail CO2 behavior in the specimen. In the brine-saturated low permeable sandstone, the slow penetration of CO2 was observed. However, once CO2 has passed, the penetration of CO2 became easy in even for brine-remainded low permeable sandstone. We conclude low permeable sandstone has not only structural storage capacity but also residual tapping (Capillary trapping) capacity. There is a positive possibility to conduct CCS in the low-quality reservoir (low permeable sandstone).

Petrophysical laboratory invertigations of carbon dioxide storage in a subsurface saline aquifer in Ketzin/Germany within the scope of CO2SINK

NASA Astrophysics Data System (ADS)

Zemke, K.; Kummmerow, J.; Wandrey, M.; Co2SINK Group

2009-04-01

Since June of 2008 carbon dioxide has been injected into a saline aquifer at the Ketzin test site [Würdemann et al., this volume]. The food grade CO2 is injected into a sandstone zone of the Stuttgart formation at ca. 650 m depth at 35°C reservoir temperature and 62 bar reservoir pressure. With the injection of CO2 into the geological formation, chemical and physical reservoir characteristics are changed depending on pressure, temperature, fluid chemistry and rock composition. Fluid-rock interaction could comprise dissolution of non-resistant minerals in CO2-bearing pore fluids, cementing of the pore space by precipitating substances from the pore fluid, drying and disintegration of clay minerals and thus influence of the composition and activities of the deep biosphere. To testing the injection behaviour of CO2 in water saturated rock and to evaluate the geophysical signature depending on the thermodynamic conditions, flow experiments with water and CO2 have been performed on cores of the Stuttgart formation from different locations including new wells of ketzin test site. The studied core material is an unconsolidated fine-grained sandstone with porosity values from 15 to 32 %. Permeability, electrical resistivity, and sonic wave velocities and their changes with pressure, saturation and time have been studied under simulated in situ conditions. The flow experiments conducted over several weeks with brine and CO2 showed no significant changes of resistivity and velocity and a slightly decreasing permeability. Pore fluid analysis showed mobilization of clay and some other components. A main objective of the CO2Sink laboratory program is the assessment of the effect of long-term CO2 exposure on reservoir rocks to predict the long-term behaviour of geological CO2 storage. For this CO2 exposure experiments reservoir rock samples were exposed to CO2 saturated reservoir fluid in corrosion-resistant high pressure vessels under in situ temperature and pressure conditions over a period of several months. Before and after the CO2 exposure experiment cyclic measurements of physical properties were carried out on these cores in a mechanical testing system. After experimental runs of up to 3 months no significant changes in flow and petrophysical data were observed. [For the microbilogical studies see Wandrey et al., this volume.] To study the impact of fluid-rock interactions on petrophysical parameters, porosity and pore radii distribution have been investigated before and after the experiment by NMR relaxation and mercury-injection. NMR measurements on rock core plugs saturated with brine may return valuable information on the porous structure of the rock core. The distribution of NMR-T2 values (CPMG) reflects the pore sizes within the rock core. NMR pore size is a derivative of the ratio pore surface/volume. The mercury injection pore size is an area-equivalent diameter of the throats connecting the pore system. Most of the tested samples show in the NMR measurements a slightly increasing porosity and a higher part of large pores. The mercury measurements and thin- section for microstructural characterisation after the CO2 exposure will be done at a later date.

CO2 injection into submarine, CH4-hydrate bearing sediments: Parameter studies towards the development of a hydrate conversion technology

NASA Astrophysics Data System (ADS)

Deusner, Christian; Bigalke, Nikolaus; Kossel, Elke; Haeckel, Matthias

2013-04-01

In the recent past, international research efforts towards exploitation of submarine and permafrost hydrate reservoirs have increased substantially. Until now, findings indicate that a combination of different technical means such as depressurization, thermal stimulation and chemical activation is the most promising approach for producing gas from natural hydrates. Moreover, emission neutral exploitation of CH4-hydrates could potentially be achieved in a combined process with CO2 injection and storage as CO2-hydrate. In the German gas hydrate initiative SUGAR, a combination of experimental and numerical studies is used to elucidate the process mechanisms and technical parameters on different scales. Experiments were carried out in the novel high-pressure flow-through system NESSI (Natural Environment Simulator for sub-Seafloor Interactions). Recent findings suggest that the injection of heated, supercritical CO2 is beneficial for both CH4 production and CO2 retention. Among the parameters tested so far are the CO2 injection regime (alternating vs. continuous injection) and the reservoir pressure / temperature conditions. Currently, the influence of CO2 injection temperature is investigated. It was shown that CH4 production is optimal at intermediate reservoir temperatures (8 ° C) compared to lower (2 ° C) and higher temperatures (10 ° C). The reservoir pressure, however, was of minor importance for the production efficiency. At 8 ° C, where CH4- and CO2-hydrates are thermodynamically stable, CO2-hydrate formation appears to be slow. Eventual clogging of fluid conduits due to CO2-rich hydrate formation force open new conduits, thereby tapping different regions inside the CH4-hydrate sample volume for CH4gas. In contrast, at 2 ° C immediate formation of CO2-hydrate results in rapid and irreversible obstruction of the entire pore space. At 10 ° C pure CO2-hydrates can no longer be formed. Consequently the injected CO2 flows through quickly and interaction with the reservoir is minimized. Our results clearly indicate that the formation of mixed CH4-CO2-hydrates is an important aspect in the conversion process. The experimental studies have shown that the injection of heated CO2 into the hydrate reservoir induces a variety of spatial and temporal processes which result in substantial bulk heterogeneity. Current numerical simulators are not able to predict these process dynamics and it is important to improve available transport-reaction models (e.g. to include the effect of bulk sediment permeability on the conversion dynamics). Our results confirm that experimental studies are important to better understand the mechanisms of hydrate dissociation and conversion at CO2-injection conditions as a basis towards the development of a suitable hydrate conversion technology. The application of non-invasive analytical methods such as Magnetic Resonance Imaging (MRI) and Raman microscopy are important tools, which were applied to resolve process dynamics on the pore scale. Additionally, the NESSI system is being modified to allow high-pressure flow-through experiments under triaxial loading to better simulate hydrate-sediment mechanics. This aspect is important for overall process development and evaluation of process safety issues.

CO2-brine-mineral Reactions in Geological Carbon Storage: Results from an EOR Experiment

NASA Astrophysics Data System (ADS)

Chapman, H.; Wigley, M.; Bickle, M.; Kampman, N.; Dubacq, B.; Galy, A.; Ballentine, C.; Zhou, Z.

2012-04-01

Dissolution of CO2 in brines and reactions of the acid brines ultimately dissolving silicate minerals and precipitating carbonate minerals are the prime long-term mechanisms for stabilising the light supercritical CO2 in geological carbon storage. However the rates of dissolution are very uncertain as they are likely to depend on the heterogeneity of the flow of CO2, the possibility of convective instability of the denser CO2-saturated brines and on fluid-mineral reactions which buffer brine acidity. We report the results of sampling brines and gases during a phase of CO2 injection for enhanced oil recovery in a small oil field. Brines and gases were sampled at production wells daily for 3 months after initiation of CO2 injection and again for two weeks after 5 months. Noble gas isotopic spikes were detected at producing wells within days of initial CO2 injection but signals continued for weeks, and at some producers for the duration of the sampling period, attesting to the complexity of gas-species pathways. Interpretations are complicated by the previous history of the oil field and re-injection of produced water prior to injection of CO2. However water sampled from some producing wells during the phase of CO2 injection showed monotonic increases in alkalinity and in concentrations of major cations to levels in excess of those in the injected water. The marked increase in Na, and smaller increases in Ca, Mg, Si, K and Sr are interpreted primarily to result from silicate dissolution as the lack of increase in S and Cl concentrations preclude additions of more saline waters. Early calcite dissolution was followed by re-precipitation. 87Sr/86Sr ratios in the waters apparently exceed the 87Sr/86Sr ratios of acetic and hydrochloric acid leaches of carbonate fractions of the reservoir rocks and the silicate residues from the leaching. This may indicate incongruent dissolution of Sr or larger scale isotopic heterogeneity of the reservoir. This is being investigated further by analyses of rock and mineral clasts from core. A surprising result of this study is the extent to which CO2 has dissolved in brines to drive fluid-rock reactions during the short duration of this experiment. However, simple one-dimensional flow modelling with lateral diffusion of CO2 into brines demonstrates that the natural heterogeneities in permeability in the reservoir on the scale of ~ 1 m are sufficient to cause extensive fingering of the CO2 along the highest permeability horizons. Because flow of brines is fastest in the relatively high permeability layers adjacent to the CO2-bearing layers, production of this more CO2-rich water dominates the output from production wells.

Poromechanical response of naturally fractured sorbing media

NASA Astrophysics Data System (ADS)

Kumar, Hemant

The injection of CO2 in coal seams has been utilized for enhanced gas recovery and potential CO2 sequestration in unmineable coal seams. It is advantageous because as it enhances the production and significant volumes of CO2 may be stored simultaneously. The key issues for enhanced gas recovery and geologic sequestration of CO2 include (1) Injectivity prediction: The chemical and physical processes initiated by the injection of CO2 in the coal seam leads to permeability/porosity changes (2) Up scaling: Development of full scale coupled reservoir model which may predict the enhanced production, associated permeability changes and quantity of sequestered CO2. (3) Reservoir Stimulation: The coalbeds are often fractured and proppants are placed into the fractures to prevent the permeability reduction but the permeability evolution in such cases is poorly understood. These issues are largely governed by dynamic coupling of adsorption, fluid exchange, transport, water content, stress regime, fracture geometry and physiomechanical changes in coals which are triggered by CO 2 injection. The understanding of complex interactions in coal has been investigated through laboratory experiments and full reservoir scale models are developed to answer key issues. (Abstract shortened by ProQuest.).

Injection of Super-Critical CO2 in Brine Saturated Sandstone:

NASA Astrophysics Data System (ADS)

Ott, Holger; de Kloe, Kees; Taberner, Conxita; Marcelis, Fons; Makurat, Axel

2010-05-01

Presently, large-scale geological sequestration of CO2, originating from sources like fossil-fueled power plants and contaminated gas production, is seen as an option to reduce anthropogenic emission of greenhouse gases to the atmosphere. Deep saline aquifers and depleted oil and gas fields are potential subsurface deposits for CO2. Injected CO2, however, interacts physically and chemically with the formation leading to uncertainties for CCS projects. One of these uncertainties is related to a dry-out zone that is likely to form around the well bore owing to the injection of dry CO2. Precipitation of salt (mainly halite) that is associated with that drying out of a saline formation has the potential to impair injectivity, and could even lead to the loss of a well. If dry (or under-saturated), super-critical (SC) CO2 is injected into water-bearing geological formations like saline aquifers, water is removed by either advection of the aqueous phase or by evaporation of water and subsequent advection in the injected CO2-rich phase. Both mechanisms act in parallel, however while advection of the aqueous phase decreases with increasing CO2 saturation (diminished mobility), evaporation becomes increasingly important as the aqueous phase becomes immobile. Below residual water saturation, only evaporation takes place and the formation dries out if no additional source of water is available. If water evaporates, the salts originally present in the water are left behind. In case of highly saline formations, the amount of salt that potentially precipitates per unit volume can be quite substantial. It depends on salinity, the solubility limit of water in the CO2 rich phase, and on the ratio of advection and evaporation rates. Since saturations and flow rates cover a large range as functions of space and time close to the well bore, there is no easy answer to the questions whether, where and how salt precipitation impacts injectivity. The present paper presents results of core-flood experiments that were performed to investigate the spatial and temporal precipitation of salt due to the injection of dry CO2 and to understand the underlying mechanisms; super-critical CO2 was injected into brine-saturated sandstone (Berea) samples under realistic pressure and temperature conditions and at high injection rate. To match flow rates that are realistic for the near well-bore area, the experiments were performed on small-scale samples with a cross section of less than 1 cm2. Density profiles were measured by mCT (micro computer tomography) scanning during injection. Reference scans and brine doping with a contrast agent allow the distinction between the CO2-rich phase, the aqueous phase and precipitated solid salt even on pore scale. By means of mCT scanning, spatial and time evolution of halite precipitation in rock samples have been observed under sequestration conditions. Pattern formation of solid salt along the main flow direction as well as a cross-sectional pattern formation has been found. However, while there are areas of high local solid salt accumulation, permeability remained unaffected, which might be a result of the precipitation pattern. The results were complemented by (ex-situ) eSEM/EDAX measurements to study where and how salt precipitates on the microscopic scale. The SEM results cannot be directly translated to in-situ conditions, as salt migrates post-experiment at ambient conditions, but give valuable insight into microscopic processes controlling deposition. Numerical simulations have been performed for a qualitative understanding of principle mechanisms and show a dependency of the observed profile on injection rate and capillary pressure.

The CarbFix Pilot Project in Iceland - CO2 capture and mineral storage in basaltic rocks

NASA Astrophysics Data System (ADS)

Sigurdardottir, H.; Sigfusson, B.; Aradottir, E. S.; Gunnlaugsson, E.; Gislason, S. R.; Alfredsson, H. A.; Broecker, W. S.; Matter, J. M.; Stute, M.; Oelkers, E.

2010-12-01

The overall objective of the CarbFix project is to develop and optimize a practical and cost-effective technology for capturing CO2 and storing it via in situ mineral carbonation in basaltic rocks, as well as to train young scientist to carry the corresponding knowledge into the future. The project consists of a field injection of CO2 charged water at the Hellisheidi geothermal power plant in SW Iceland, laboratory experiments, numerical reactive transport modeling, tracer tests, natural analogue and cost analysis. The CO2 injection site is situated about 3 km south of the Hellisheidi geothermal power plant. Reykjavik Energy operates the power plant, which currently produces 60,000 tons/year CO2 of magmatic origin. The produced geothermal gas mainly consists of CO2 and H2S. The two gases will be separated in a pilot gas treatment plant, and CO2 will be transported in a pipeline to the injection site. There, CO2 will be fully dissolved in 20 - 25°C water during injection at 25 - 30 bar pressure, resulting in a single fluid phase entering the storage formation, which consists of relatively fresh basaltic lavas. The CO2 charged water is reactive and will dissolve divalent cations from the rock, which will combine with the dissolved carbon to form solid thermodynamically stable carbonate minerals. The injection test is designed to inject 2200 tons of CO2 per year. In the past three years the CarbFix project has been addressing background fluid chemistries at the injection site and characterizing the target reservoir for the planned CO2 injection. Numerous groundwater samples have been collected and analysed. A monitoring and accounting plan has been developed, which integrates surface, subsurface and atmospheric monitoring. A weather station is operating at the injection site for continuous monitoring of atmospheric CO2 and to track all key parameters for the injection. Environmental authorities have granted licenses for the CO2 injection and the use of tracers, based on the monitoring plan. Pipelines, injection and monitoring wells have been installed and equipment test runs are in the final phase. A bailer has been constructed to be used to retrieve samples at reservoir conditions. Hydrological parameters of a three dimensional field model have been calibrated and reactive transport simulations are ongoing. The key risks that the project is currently facing are technical and financial. Until now the project has been facing incidences that have already impacted the time schedule in the CarbFix project. Furthermore the project is facing world-wide exchange rate uncertainty plus the inherited uncertainty that innovative research projects contain. However, the CarbFix group remains optimistic that injection will start in near future.

Joint Cross Well and Single Well Seismic Studies at Lost Hills, California

DOE Office of Scientific and Technical Information (OSTI.GOV)

Gritto, Roland; Daley, Thomas M.; Myer, Larry R.

2002-06-25

A series of time-lapse seismic cross well and single well experiments were conducted in a diatomite reservoir to monitor the injection of CO{sub 2} into a hydrofracture zone, based on P- and S-wave data. A high-frequency piezo-electric P-wave source and an orbital-vibrator S-wave source were used to generate waves that were recorded by hydrophones as well as three-component geophones. The injection well was located about 12 m from the source well. During the pre-injection phase water was injected into the hydrofrac-zone. The set of seismic experiments was repeated after a time interval of 7 months during which CO{sub 2} wasmore » injected into the hydrofractured zone. The questions to be answered ranged from the detectability of the geologic structure in the diatomic reservoir to the detectability of CO{sub 2} within the hydrofracture. Furthermore it was intended to determine which experiment (cross well or single well) is best suited to resolve these features. During the pre-injection experiment, the P-wave velocities exhibited relatively low values between 1700-1900 m/s, which decreased to 1600-1800 m/s during the post-injection phase (-5%). The analysis of the pre-injection S-wave data revealed slow S-wave velocities between 600-800 m/s, while the post-injection data revealed velocities between 500-700 m/s (-6%). These velocity estimates produced high Poisson ratios between 0.36 and 0.46 for this highly porous ({approx} 50%) material. Differencing post- and pre-injection data revealed an increase in Poisson ratio of up to 5%. Both, velocity and Poisson estimates indicate the dissolution of CO{sub 2} in the liquid phase of the reservoir accompanied by a pore-pressure increase. The single well data supported the findings of the cross well experiments. P- and S-wave velocities as well as Poisson ratios were comparable to the estimates of the cross well data. The cross well experiment did not detect the presence of the hydrofracture but appeared to be sensitive to overall changes in the reservoir and possibly the presence of a fault. In contrast, the single well reflection data revealed an arrival that could indicate the presence of the hydrofracture between the source and receiver wells, while it did not detect the presence of the fault, possibly due to out of plane reflections.« less

System Assessment of Carbon Dioxide Used as Gas Oxidant and Coolant in Vanadium-Extraction Converter

NASA Astrophysics Data System (ADS)

Du, Wei Tong; Wang, Yu; Liang, Xiao Ping

2017-10-01

With the aim of reducing carbon dioxide (CO2) emissions and of using waste resources in steel plants, the use of CO2 as a gas oxidant and coolant in the converter to increase productivity and energy efficiency was investigated in this study. Experiments were performed in combination with thermodynamic theory on vanadium-extraction with CO2 and oxygen (O2) mixed injections. The results indicate that the temperature of the hot metal bath decreased as the amount of CO2 introduced into O2 increased. At an injection of 85 vol.% O2 and 15 vol.% CO2, approximately 12% of additional carbon was retained in the hot metal. Moreover, the content of vanadium trioxide in the slag was higher. In addition, the O2 consumption per ton of hot metal was reduced by 8.5% and additional chemical energy was recovered by the controlled injection of CO2 into the converter. Therefore, using CO2 as a gas coolant was conducive to vanadium extraction, and O2 consumption was reduced.

West Pearl Queen CO2 sequestration pilot test and modeling project 2006-2008.

DOE Office of Scientific and Technical Information (OSTI.GOV)

Engler, Bruce Phillip; Cooper, Scott Patrick; Symons, Neill Phillip

2008-08-01

The West Pearl Queen is a depleted oil reservoir that has produced approximately 250,000 bbl of oil since 1984. Production had slowed prior to CO{sub 2} injection, but no previous secondary or tertiary recovery methods had been applied. The initial project involved reservoir characterization and field response to injection of CO{sub 2}; the field experiment consisted of injection, soak, and venting. For fifty days (December 20, 2002, to February 11, 2003) 2090 tons of CO{sub 2} were injected into the Shattuck Sandstone Member of the Queen Formation at the West Pearl Queen site. This technical report highlights the test resultsmore » of the numerous research participants and technical areas from 2006-2008. This work included determination of lateral extents of the permeability units using outcrop observations, core results, and well logs. Pre- and post-injection 3D seismic data were acquired. To aid in interpreting seismic data, we performed numerical simulations of the effects of CO{sub 2} replacement of brine where the reservoir model was based upon correlation lengths established by the permeability studies. These numerical simulations are not intended to replicate field data, but to provide insight of the effects of CO{sub 2}.« less

Microbial monitoring during CO2 storage in deep subsurface saline aquifers in Ketzin, Germany

NASA Astrophysics Data System (ADS)

Wuerdemann, H.; Wandrey, M.; Fischer, S.; Zemke, K.; Let, D.; Zettlitzer, M.; Morozova, D.

2010-12-01

Investigations on subsurface saline aquifers have shown an active biosphere composed of diverse groups of microorganisms in the subsurface. Since microorganisms represent very effective geochemical catalysts, they may influence the process of CO2 storage significantly. In the frames of the EU Project CO2SINK a field laboratory to study CO2 storage into saline aquifer was operated. Our studies aim at monitoring of biological and biogeochemical processes and their impact on the technical effectiveness of CO2 storage technique. The interactions between microorganisms and the minerals of both the reservoir and the cap rock may cause changes to the structure and chemical composition of the rock formations, which may influence the reservoir permeability locally. In addition, precipitation and corrosion may be induced around the well affecting the casing and the casing cement. Therefore, analyses of the composition of microbial communities and its changes should contribute to an evaluation of the effectiveness and reliability of the long-term CO2 storage technique. In order to investigate processes in the deep biosphere caused by the injection of supercritical CO2, genetic fingerprinting (PCR SSCP Single-Strand-Conformation Polymorphism) and FISH (Fluorescence in situ Hybridisation) were used for identification and quantification of microorganisms. Although saline aquifers could be characterised as an extreme habitat for microorganisms due to reduced conditions, high pressure and salinity, a high number of diverse groups of microorganisms were detected with downhole sampling in the injection and observation wells at a depth of about 650m depth. Of great importance was the identification of the sulphate reducing bacteria, which are known to be involved in corrosion processes. Microbial monitoring during CO2 injection has shown that both quantity and diversity of microbial communities were strongly influenced by the CO2 injection. In addition, the indigenous microbial communities revealed a high adaptability to the changed environments after CO2 injection. In order to investigate processes in the rock substrate, long term CO2 exposure experiments on freshly drilled, pristine Ketzin reservoir core samples were accomplished for 24 months using sterile synthetic brine under in situ pressure and temperature conditions. The composition of the microbial community dominated by chemoorganotrophic bacteria and hydrogen oxidizing bacteria changed slightly under CO2 exposure. In addition, changes in porosities were observed with time. During the experiments porosity first increased due to mineral dissolution but then tend to decrease due to mineral precipitation. These mineralogical changes are consistent with changes in fluid composition during the course of the experiments that indicate notably increased K+, Ca2+, Mg2+, and SO4 2- concentrations. K+, Ca2+, Mg2+ concentrations exceeded the reservoir brine composition significantly and can be attributed to the CO2 exposure.

Intermediate-Scale Investigation of Capillary and Dissolution Trapping during CO2 Injection and Post-Injection in Heterogeneous Geological Formations

NASA Astrophysics Data System (ADS)

Cihan, A.; Illangasekare, T. H.; Zhou, Q.; Birkholzer, J. T.; Rodriguez, D.

2010-12-01

The capillary and dissolution trapping processes are believed to be major trapping mechanisms during CO2 injection and post-injection in heterogeneous subsurface environments. These processes are important at relatively shorter time periods compared to mineralization and have a strong impact on storage capacity and leakage risks, and they are suitable to investigate at reasonable times in the laboratory. The objectives of the research presented is to investigate the effect of the texture transitions and variability in heterogeneous field formations on the effective capillary and dissolution trapping at the field scale through multistage analysis comprising of experimental and modeling studies. A series of controlled experiments in intermediate-scale test tanks are proposed to investigate the key processes involving (1) viscous fingering of free-phase CO2 along high-permeability (or high-K) fast flow pathways, (2) dynamic intrusion of CO2 from high-K zones into low-K zones by capillarity (as well as buoyancy), (3) diffusive transport of dissolved CO2 into low-K zones across large interface areas, and (4) density-driven convective mass transfer into CO2-free regions. The test tanks contain liquid sampling ports to measure spatial and temporal changes in concentration of dissolved fluid as the injected fluid migrates. In addition to visualization and capturing images through digital photography, X-ray and gamma attenuation methods are used to measure phase saturations. Heterogeneous packing configurations are created with tightly packed sands ranging from very fine to medium fine to mimic sedimentary rocks at potential storage formations. Effect of formation type, injection pressure and injection rate on trapped fluid fraction are quantified. Macroscopic variables such as saturation, pressure and concentration that are measured will be used for testing the existing macroscopic models. The applicability of multiphase flow theories will be evaluated by comparing with the experimental data. Existing upscaling methodologies will be tested using experimental data for accurately estimating parameters of the large-scale heterogeneous porous media. This paper presents preliminary results from the initial-stage experiments and the modeling analysis. In the future, we will design and conduct a comprehensive set of experiments for improving the fundamental understanding of the processes, and refine and calibrate the models simulating the effective capillary and dissolution trapping with an ultimate goal to design efficient and safe storage schemes.

Numerical Modeling of the Pumping Tests at the Ketzin Pilot Site for CO2 Injection: Model Calibration and Heterogeneity Effects

NASA Astrophysics Data System (ADS)

Chen, F.; Wiese, B.; Zhou, Q.; Birkholzer, J. T.; Kowalsky, M. B.

2013-12-01

The Stuttgart formation used for ongoing CO2 injection at the Ketzin pilot test site in Germany is highly heterogeneous in nature. The site characterization data, including 3D seismic amplitude images, the regional geology data, and the core measurements and geophysical logs of the wells show the formation is composed of permeable sandstone channels of varying thickness and length embedded in less permeable mudstones. Most of the sandstone channels are located in the upper 10-15 m of the formation, with only a few sparsely distributed sandstone channels in the bottom 70-m layer. Three-dimensional seismic data help to identify the large-scale facies distribution patterns in the Stuttgart formation, but are unable to resolve internal structures at a smaller scale (e.g. ~100 m). Heterogeneity has a large effect on the pressure propagation measured during a suite of pumping tests conducted in 2007-2008 and also impacts strongly the CO2 arrival times observed during the ongoing CO2 injection experiment. The arrival time of the CO2 plume at the observation well Ktzi 202was 12.5 times greater than at the other observation well Ktzi 200, even though the distance to the injection well is only 2.2 times farther than that of Ktzi 200. To characterize subsurface properties and help predict the behavior of injected CO2 in subsequent experiments, we develop a TOUGH2/EOS9 model for modeling the hydraulic pumping tests and use the inverse modeling tool iTOUGH2 for automatic model calibration. The model domain is parameterized using multiple zones, with each zone assumed to have uniform rock properties. The calibrated model produces system responses that are in good agreement with the measured pressure drawdown data, indicating that it captures the essential flow processes occurring during the pumping tests. The estimated permeability distribution shows that the heterogeneity is significant and that the study site is situated a semi-closed system with one or two sides open to permeable regions and the others effectively blocked by low-permeability regions. A low-permeability zone appears at the northern boundary of the model. Of the three wells that are analyzed, permeable channels are found to connect Ktzi 202 with Ktzi 200/Ktzi 201, while a low-permeability zone is observed between Ktzi 201 and Ktzi 200. The calibrated results are consistent with the crosshole ERT data and can help explain the position of a CO2 plume, inferred from 3D seismic surveys in a subsequent CO2 injection experiment. Because the CO2 transport that occurs during a CO2 injection and the pressure propagation that occurs during pumping tests are sensitive to different scales of subsurface heterogeneity, direct application of a model calibrated from pumping test data is inappropriate for predicting CO2 arrival. However, by including a thin layer of highly permeable sandstone, we present a proof-of-concept model that produces CO2 arrival times comparable to those observed at the site.

Investigation of the relationship between CO2 reservoir rock property change and the surface roughness change originating from the supercritical CO2-sandstone-groundwater geochemical reaction at CO2 sequestration condition

NASA Astrophysics Data System (ADS)

Lee, Minhee; Wang, Sookyun; Kim, Seyoon; Park, Jinyoung

2015-04-01

Lab scale experiments were performed to investigate the property changes of sandstone slabs and cores, resulting from the scCO2-rock-groundwater reaction for 180 days under CO2 sequestration conditions (100 bar and 50 °C). The geochemical reactions, including the surface roughness change of minerals in the slab, resulted from the dissolution and the secondary mineral precipitation for the sandstone reservoir of the Gyeongsang basin, Korea were reproduced in laboratory scale experiments and the relationship between the geochemical reaction and the physical rock property change was derived, for the consideration of successful subsurface CO2 sequestration. The use of the surface roughness value (SRrms) change rate and the physical property change rate to quantify scCO2-rock-groundwater reaction is the novel approach on the study area for CO2 sequestration in the subsurface. From the results of SPM (Scanning Probe Microscope) analyses, the SRrms for each sandstone slab was calculated at different reaction time. The average SRrms increased more than 3.5 times during early 90 days reaction and it continued to be steady after 90 days, suggesting that the surface weathering process of sandstone occurred in the early reaction time after CO2 injection into the subsurface reservoir. The average porosity of sandstone cores increased by 8.8 % and the average density decreased by 0.5 % during 90 days reaction and these values slightly changed after 90 days. The average P and S wave velocities of sandstone cores also decreased by 10 % during 90 days reaction. The trend of physical rock property change during the geochemical reaction showed in a logarithmic manner and it was also correlated to the logarithmic increase in SRrms, suggesting that the physical property change of reservoir rocks originated from scCO2 injection directly comes from the geochemical reaction process. Results suggested that the long-term estimation of the physical property change for reservoir rocks in CO2 injection site could be possible from the extrapolation process of SRrms and rocks property change rates, acquired from laboratory scale experiments. It will be aslo useful to determine the favorite CO2 injection site from the viewpoint of the safety.

Qualitative and quantitative changes in detrital reservoir rocks caused by CO2-brine-rock interactions during first injection phases (Utrillas sandstones, Northern Spain)

NASA Astrophysics Data System (ADS)

Berrezueta, E.; Ordóñez-Casado, B.; Quintana, L.

2015-08-01

The aim of this article is to describe and interpret qualitative and quantitative changes at rock matrix scale of Lower-Upper Cretaceous sandstones exposed to supercritical (SC) CO2 and brine. The effects of experimental injection of SC CO2 during the first injection phases were studied at rock matrix scale, in a potential deep sedimentary reservoir in Northern Spain (Utrillas unit, at the base of the Cenozoic Duero Basin). Experimental wet CO2 injection was performed in a reactor chamber under realistic conditions of deep saline formations (P ≈ 78 bar, T ≈ 38 °C and 24 h exposure time). After the experiment, exposed and non-exposed equivalent sample sets were compared with the aim of assessing possible changes due to the effect of the CO2-brine exposure. Optical microscopy (OpM) and scanning electron microscopy (SEM) aided by optical image analysis (OIA) were used to compare the rock samples and get qualitative and quantitative information about mineralogy, texture and porous network distribution. Chemical analyses were performed to refine the mineralogical information and to obtain whole rock geochemical data. Brine composition was also analysed before and after the experiment. The results indicate an evolution of the pore network (porosity increase ≈ 2 %). Intergranular quartz matrix detachment and partial removal from the rock sample (due to CO2 input/release dragging) are the main processes that may explain the porosity increase. Primary mineralogy (≈ 95 % quartz) and rock texture (heterogeneous sand with interconnected framework of micro-channels) are important factors that seem to enhance textural/mineralogical changes in this heterogeneous system. The whole rock and brine chemical analyses after interaction with SC CO2-brine do not present important changes in the mineralogical, porosity and chemical configuration of the rock with respect to initial conditions, ruling out relevant precipitation or dissolution at these early stages. These results, simulating the CO2 injection near the injection well during the first phases (24 h) indicate that, in this environment where CO2 displaces the brine, the mixture principally generates local mineralogical/textural re-adjustments due to physical detachment of quartz grains. Consequences deriving from these changes are variable. Possible porosity and permeability increases could facilitate further CO2 injection but textural re-adjustment could also affect the rock physically. However, it is not clear yet what effect the quartz (solid suspension) could provoke in more distant areas of the rock. Quartz could be transported in the fluid flow path and probably accumulated at pore throats.

Transient Changes in Shallow Groundwater Chemistry During the MSU-ZERT CO2 Injection Experiment

NASA Astrophysics Data System (ADS)

Zheng, L.; Apps, J. A.; Spycher, N.; Birkholzer, J. T.; Kharaka, Y. K.; Thordsen, J. J.; Kakouros, E.; Trautz, R. C.

2009-12-01

The Montana State University Zero Emission Research and Technology (MSU-ZERT) field experiment at Bozeman, Montana, is designed to evaluate atmospheric and near-surface monitoring and detection techniques applicable to the potential leakage of CO2 from deep storage reservoirs. However, the experiment also affords an excellent opportunity to investigate the transient changes in groundwater chemical composition in response to increasing CO2 partial pressures. Between July 9 and August 7, 2008, 300 kg/day of food-grade CO2 was injected into shallow groundwater through a horizontal perforated pipe about 2-2.3 m below the ground surface. Changes in groundwater quality were investigated through comprehensive chemical analyses of 80 water samples taken before, during and following CO2 injection from 10 shallow observation wells located 1-6 m from the injection pipe, and from two distant monitoring wells. Field and laboratory analyses suggest rapid and systematic changes in pH, alkalinity, and conductance, as well as increases in the aqueous concentrations of both major and trace element species. A principal component analysis and independent thermodynamic interpretation of the water quality analyses were conducted. Results were interpreted in conjunction with a mineralogical characterization of the shallow sediments and a review of historical records of the chemical composition of rainfall at neighboring monitoring sites. The interpretation permitted tentative identification of a complex array of adsorption/desorption, ion exchange, precipitation/dissolution, oxidation/reduction and infiltration processes that were operative during the test. Geochemical modeling was conducted using TOUGHREACT to test whether the observed water quality changes were consistent with the hypothesized processes, and very good agreement was obtained with respect to the behavior of both major and trace elements.

Comparison of water-based foam and carbon dioxide gas mass emergency depopulation of White Pekin ducks.

PubMed

Caputo, M P; Benson, E R; Pritchett, E M; Hougentogler, D P; Jain, P; Patil, C; Johnson, A L; Alphin, R L

2012-12-01

The mass depopulation of production birds remains an effective means of controlling fast-moving, highly infectious diseases such as avian influenza and virulent Newcastle disease. Two experiments were performed to compare the physiological responses of White Pekin commercial ducks during foam depopulation and CO(2) gas depopulation. Both experiment 1 (5 to 9 wk of age) and 2 (8 to 14 wk of age) used electroencephalogram, electrocardiogram, and accelerometer to monitor and evaluate the difference in time to unconsciousness, motion cessation, brain death, altered terminal cardiac activity, duration of bradycardia, and elapsed time from onset of bradycardia to onset of unconsciousness between foam and CO(2) gas. Experiment 2 also added a third treatment, foam + atropine injection, to evaluate the effect of suppressing bradycardia. Experiment 1 resulted in significantly shorter times for all 6 physiological points for CO(2) gas compared with foam, whereas experiment 2 found that there were no significant differences between foam and CO(2) gas for these physiological points except brain death, in which CO(2) was significantly faster than foam and duration of bradycardia, which was shorter for CO(2). Experiment 2 also determined there was a significant positive correlation between duration of bradycardia and time to unconsciousness, motion cessation, brain death, and altered terminal cardiac activity. The time to unconsciousness, motion cessation, brain death, and altered terminal cardiac activity was significantly faster for the treatment foam + atropine injection compared with foam. Both experiments showed that bradycardia can occur as a result of either submersion in foam or exposure to CO(2) gas. The duration of bradycardia has a significant impact on the time it takes White Pekin ducks to reach unconsciousness and death during depopulation.

Hydro-geochemical impact of CO2 leakage from geological storage on shallow potable aquifers: A field scale pilot experiment.

NASA Astrophysics Data System (ADS)

Cahill, A.; Jakobsen, R.

2012-04-01

In order to assess the environmental implications of leakage of CO2 from a geological sequestration site into overlying shallow potable aquifers, a 3 month field release experiment is planned to commence in spring 2012 at Vrøgum plantation, Western Denmark. To test the injection and sampling methodologies and as a study of short term effects, a pilot experiment was conducted at the field site: 45 kg of food grade CO2 was injected at 10 m depth over 48 hours into an unconfined, aeolian/glacial sand aquifer and the effects on water chemistry studied. The CO2 was injected through an inclined well installed with a 1 m length of porous polyethylene well screen (20 µm pore size) initially at a rate of 5 litres per minute increasing to 10 litres per minute after 24 hours. Water samples were taken from a network of multi-level sample points (8, 4 and 2.4m depth) before, during and after the injection and measured for physico-chemical parameters and major/trace element composition. Although the site possesses a relatively high hydraulic conductivity (12-16 m/day), due to the small hydraulic gradient (0.0039) 6 days elapsed before effects of CO2 on the ground water were detected in the first sampling point located 0.5 m down flow from the injection well. The dissolved plume of CO2 was observed only in the 8 m depth sample points and moved with flow (approximately 0.10 - 0.12 m/day). The plume spread laterally to 2m width as little as 1 m from the injection screen after 26 days, indicating that CO2 bubbles change the hydraulics of the medium. Dissolved CO2 was not detected in sample points at 4 or 2.4 m depth at any time during the experiment, suggesting gas could not move into the slightly finer grained upper sand. Effects of CO2 dissolution at 8 m depth were manifest as a clear and stable increase in electrical conductivity (approximately 160 to 300 µS/cm), a relatively small increase in total dissolved ions (approximately 30 to 50 mg/l) and an unstable depression of pH (approximately 5.8 to 4.73). The dissolved CO2 plume evolved with a distinct maximal front observed to pass through sample points followed by a slowly dissipating tail. After 56 days the CO2 plume reached the end of the monitoring network and was at its greatest extent (5 m length by 1 m width) however still appeared to be increasing in size suggesting residual gas phase CO2 trapped within the pore space continuously dissolving. Water quality did not significantly deteriorate and only small increases in major and trace elements were observed. Overall, groundwater chemistry results indicate that for an aquifer composed primarily of slowly reacting silicate sediments, such as Vrøgum, the risks to water resources from a short term leak from CCS into shallow overlying aquifers are minimal. However, a potential accumulation effect within the plume front as it moves through the formation was observed inferring a large scale leak may develop a CO2 charged plume exceeding guideline values for major and trace elements.

Micro-CT in situ study of carbonate rock microstructural evolution for geologic CO2 storage

NASA Astrophysics Data System (ADS)

Zheng, Y.; Yang, Y.; Rogowska, M.; Gundlach, C.

2017-09-01

To achieve the 2°C target made in the 2016 Paris Agreement, it is essential to reduce the emission of CO2 into the atmosphere. Carbon Capture and Storage (CCS) has been given increasing importance over the last decade. One of the suggested methods for CCS is to inject CO2 into geologic settings such as the carbonate reservoirs in the North Sea. The final aim of our project is to find out how to control the evolution of petrophysical parameters during CO2 injection using an optimal combination of flow rate, injection pressure and chemical composition of the influent. The first step to achieve this is to find a suitable condition to create a stable 3D space in carbonate rock by injecting liquid to prepare space for the later CO2 injection. Micro-CT imaging is a non-destructive 3D method that can be used to study the property changes of carbonate rocks during and after CO2 injection. The advance in lab source based micro-CT has made it capable of in situ experiments. We used a commercial bench top micro-CT (Zeiss Versa XRM410) to study the microstructure changes of chalk during liquid injection. Flexible temporal CT resolution is essential in this study because that the time scales of coupled physical and chemical processes can be very different. The results validated the feasibility of using a bench top CT system with a pressure cell to monitor the mesoscale multiphase interactions in chalk.

Biological CO2 conversion to acetate in subsurface coal-sand formation using a high-pressure reactor system

NASA Astrophysics Data System (ADS)

Ohtomo, Y.; Ijiri, A.; Ikegawa, Y.; Tsutsumi, M.; Imachi, H.; Uramoto, G.; Hoshino, T.; Morono, Y.; Tanikawa, W.; Hirose, T.; Inagaki, F.

2013-12-01

The geological CO2 sequestration into subsurface unmineable oil/gas fields and coal formations has been considered as one of the possible ways to reduce dispersal of anthropogenic greenhouse gasses into the atmosphere. However, feasibility of CO2 injection largely depends on a variety of geological and economical settings, and its ecological consequences have remained largely unpredictable. To address these issues, we developed a new flow-through-type CO2 injection system designated as the 'geobio-reactor system' to examine possible geophysical, geochemical and microbiological impact caused by CO2 injection under in-situ pressure (0-100 MPa) and temperature (0-70°C) conditions. In this study, we investigated Eocene bituminous coal-sandstones in the northwestern Pacific coast, Hokkaido, Japan, using the geobio-reactor system. Anaerobic artificial fluid and CO2 (flow rate: 0.002 and 0.00001 mL/min, respectively) were continuously supplemented into the coal-sand column under the pore pressure of 40 MPa (confined pressure: 41 MPa) at 40°C for 56 days. Molecular analysis of bacterial 16S rRNA genes showed that predominant bacterial components were physically dispersed from coal to sand as the intact form during experiment. Cultivation experiments from sub-sampling fluids indicated that some terrestrial microbes could preserve their survival in subsurface condition. Molecular analysis of archaeal 16S rRNA genes also showed that no methanogens were activated during experiment. We also anaerobically incubated the coal sample using conventional batch-type cultivation technique with a medium for methanogens. After one year of the batch incubation at 20°C, methane could be detected from the cultures except for the acetate-fed culture. The sequence of archaeal 16S rRNA genes via PCR amplification obtained from the H2 plus formate-fed culture was affiliated with a hydrogenotrophic methanogen within the genus Methanobacterium, whereas the methanol plus trimethylamine culture belonged to a methylotrophic methanogen within the genus Methanosarcina. For the acetate-fed culture, no cell proliferation and methane-production were observed after two-years incubation. During the injection of CO2 and fluid, increase of dissolved CH4 concentration was observed, of which δ13CCH4 were constantly similar to those of the absorbed coal-bed methane (δ13CCBM, ~70‰), suggesting the enhanced gas recovery with fluid flow. The output volume of CO2 (ΣCO2out, 22.1 to 125.6 mM) was smaller than initial concentration (ΣCO2in, 138.38 mM), which can be explained by either adsorption on coal, formation of carbonate minerals, or microbial consumption. Increase of acetate concentration in the fluids was also observed, whereas δ13Cacetate depleted during experiment. Considering with the decrease of additive H2, it is most likely that homo-acetogenesis would occur during experiments, which is consistent with detection of Sporomusa-related 16S rRNA genes, homo-acetogenic bacterium, in cloning analysis of sandstone after experiment. Decrease of formate concentrations and increase of δ13Cformate indicate bacterial consumption of formate and isotopic fractionation. Our results suggest that CO2 injection to natural coal-sand formation stimulates homo-acetogenesis rather than methanogenesis, accompanied by biogenic CO2 conversion to acetate.

Microbial Stimulation and Succession following a Test Well Injection Simulating CO₂ Leakage into a Shallow Newark Basin Aquifer

PubMed Central

O’Mullan, Gregory; Dueker, M. Elias; Clauson, Kale; Yang, Qiang; Umemoto, Kelsey; Zakharova, Natalia; Matter, Juerg; Stute, Martin; Takahashi, Taro; Goldberg, David

2015-01-01

In addition to efforts aimed at reducing anthropogenic production of greenhouse gases, geological storage of CO2 is being explored as a strategy to reduce atmospheric greenhouse gas emission and mitigate climate change. Previous studies of the deep subsurface in North America have not fully considered the potential negative effects of CO2 leakage into shallow drinking water aquifers, especially from a microbiological perspective. A test well in the Newark Rift Basin was utilized in two field experiments to investigate patterns of microbial succession following injection of CO2-saturated water into an isolated aquifer interval, simulating a CO2 leakage scenario. A decrease in pH following injection of CO2 saturated aquifer water was accompanied by mobilization of trace elements (e.g. Fe and Mn), and increased bacterial cell concentrations in the recovered water. 16S ribosomal RNA gene sequence libraries from samples collected before and after the test well injection were compared to link variability in geochemistry to changes in aquifer microbiology. Significant changes in microbial composition, compared to background conditions, were found following the test well injections, including a decrease in Proteobacteria, and an increased presence of Firmicutes, Verrucomicrobia and microbial taxa often noted to be associated with iron and sulfate reduction. The concurrence of increased microbial cell concentrations and rapid microbial community succession indicate significant changes in aquifer microbial communities immediately following the experimental CO2 leakage event. Samples collected one year post-injection were similar in cell number to the original background condition and community composition, although not identical, began to revert toward the pre-injection condition, indicating microbial resilience following a leakage disturbance. This study provides a first glimpse into the in situ successional response of microbial communities to CO2 leakage after subsurface injection in the Newark Basin and the potential microbiological impact of CO2 leakage on drinking water resources. PMID:25635675

Stable isotope monitoring of ionic trapping of CO2 in deep brines

NASA Astrophysics Data System (ADS)

Myrttinen, A.; Barth, J. A. C.; Becker, V.; Blum, P.; Grathwohl, P.

2009-04-01

CO2 injection into a depleted gas-reservoir is used as a combined method for Enhanced Gas Recovery (EGR) and CO2 storage. In order to safeguard this process, monitoring the degree of dissolution and potential further precipitation and mineral interactions are a necessity. Here a method is introduced, in which stable isotope and geochemical data can be used as a monitoring technique to quantify ionic trapping of injected CO2. Isotope and geochemical data of dissolved inorganic carbon (DIC) can be used to distinguish between already present and to be injected inorganic carbon. Injected CO2, for instance, is formed during combustion of former plant material and is expected to have a different isotope ratio (δ13C value) than the baseline data of the aquifer. This is because combusted CO2 originates from organic material, such as coal and oil with a predominant C3 plant signature. Mixing the injected CO2 with groundwater is therefore expected to change the isotope, as well as the geochemical composition of the groundwater. Mass balance calculations with stable isotope ratios can serve to quantify ionic trapping of CO2 as DIC in groundwater. However, depending on the composition of the aquifer, weathering of carbonate or silicates may occur. Enhanced weathering processes due to CO2 injection can also further influence the isotopic composition. Such interactions between dissolved CO2 and minerals depend on the temperature and pressure regimes applied. Field data, as well as laboratory experiments are planned to quantify isotope ratios of dissolved inorganic carbon as well as oxygen isotope ratios of the water. These are indicative of geochemical processes before, during and after EGR. The isotope method should therefore provide a new tool to quantify the efficiency of ionic trapping under various temperatures and pressures. Keywords: Enhanced Gas Recovery, monitoring of CO2 dissolution, stable isotopes

Assessing Induced Seismicity Risk at CO 2 Storage Projects: Recent Progress and Remaining Challenges

DOE PAGES

White, Joshua A.; Foxall, William

2016-04-13

It is well established that fluid injection has the potential to induce earthquakes—from microseismicity to magnitude 5+ events—by altering state-of-stress conditions in the subsurface. This paper reviews recent lessons learned regarding induced seismicity at carbon storage sites. While similar to other subsurface injection practices, CO 2 injection has distinctive features that should be included in a discussion of its seismic hazard. Induced events have been observed at CO 2 injection projects, though to date it has not been a major operational issue. Nevertheless, the hazard exists and experience with this issue will likely grow as new storage operations come online.more » This review paper focuses on specific technical difficulties that can limit the effectiveness of current risk assessment and risk management approaches, and highlights recent research aimed at overcoming them. Finally, these challenges form the heart of the induced seismicity problem, and novel solutions to them will advance our ability to responsibly deploy large-scale CO 2 storage.« less

Pore-scale supercritical CO2 dissolution and mass transfer under imbibition conditions

DOE Office of Scientific and Technical Information (OSTI.GOV)

Chang, Chun; Zhou, Quanlin; Kneafsey, Timothy J.

2016-06-01

In modeling of geological carbon storage, dissolution of supercritical CO2 (scCO2) is often assumed to be instantaneous with equilibrium phase partitioning. In contrast, recent core-scale imbibition experiments have shown a prolonged depletion of residual scCO2 by dissolution, implying a non-equilibrium mechanism. In this study, eight pore-scale scCO2 dissolution experiments in a 2D heterogeneous, sandstone-analogue micromodel were conducted at supercritical conditions (9 MPa and 40 °C). The micromodel was first saturated with deionized (DI) water and drained by injecting scCO2 to establish a stable scCO2 saturation. DI water was then injected at constant flow rates after scCO2 drainage was completed. Highmore » resolution time-lapse images of scCO2 and water distributions were obtained during imbibition and dissolution, aided by a scCO2-soluble fluorescent dye introduced with scCO2 during drainage. These images were used to estimate scCO2 saturations and scCO2 depletion rates. Experimental results show that (1) a time-independent, varying number of water-flow channels are created during imbibition and later dominant dissolution by the random nature of water flow at the micromodel inlet, and (2) a time-dependent number of water-flow channels are created by coupled imbibition and dissolution following completion of dominant imbibition. The number of water-flow paths, constant or transient in nature, greatly affects the overall depletion rate of scCO2 by dissolution. The average mass fraction of dissolved CO2 (dsCO2) in water effluent varies from 0.38% to 2.72% of CO2 solubility, indicating non-equilibrium scCO2 dissolution in the millimeter-scale pore network. In general, the transient depletion rate decreases as trapped, discontinuous scCO2 bubbles and clusters within water-flow paths dissolve, then remains low with dissolution of large bypassed scCO2 clusters at their interfaces with longitudinal water flow, and finally increases with coupled transverse water flow and enhanced dissolution of large scCO2 clusters. The three stages of scCO2 depletion, common to experiments with time-independent water-flow paths, are revealed by zoom-in image analysis of individual scCO2 bubbles and clusters. The measured relative permeability of water, affected by scCO2 dissolution and bi-modal permeability, shows a non-monotonic dependence on saturation. The results for experiments with different injection rates imply that the non-equilibrium nature of scCO2 dissolution becomes less important when water flow is relatively low and the time scale for dissolution is large, and more pronounced when heterogeneity is strong.« less

Revisiting ocean carbon sequestration by direct injection: a global carbon budget perspective

NASA Astrophysics Data System (ADS)

Reith, Fabian; Keller, David P.; Oschlies, Andreas

2016-11-01

In this study we look beyond the previously studied effects of oceanic CO2 injections on atmospheric and oceanic reservoirs and also account for carbon cycle and climate feedbacks between the atmosphere and the terrestrial biosphere. Considering these additional feedbacks is important since backfluxes from the terrestrial biosphere to the atmosphere in response to reducing atmospheric CO2 can further offset the targeted reduction. To quantify these dynamics we use an Earth system model of intermediate complexity to simulate direct injection of CO2 into the deep ocean as a means of emissions mitigation during a high CO2 emission scenario. In three sets of experiments with different injection depths, we simulate a 100-year injection period of a total of 70 GtC and follow global carbon cycle dynamics over another 900 years. In additional parameter perturbation runs, we varied the default terrestrial photosynthesis CO2 fertilization parameterization by ±50 % in order to test the sensitivity of this uncertain carbon cycle feedback to the targeted atmospheric carbon reduction through direct CO2 injections. Simulated seawater chemistry changes and marine carbon storage effectiveness are similar to previous studies. As expected, by the end of the injection period avoided emissions fall short of the targeted 70 GtC by 16-30 % as a result of carbon cycle feedbacks and backfluxes in both land and ocean reservoirs. The target emissions reduction in the parameter perturbation simulations is about 0.2 and 2 % more at the end of the injection period and about 9 % less to 1 % more at the end of the simulations when compared to the unperturbed injection runs. An unexpected feature is the effect of the model's internal variability of deep-water formation in the Southern Ocean, which, in some model runs, causes additional oceanic carbon uptake after injection termination relative to a control run without injection and therefore with slightly different atmospheric CO2 and climate. These results of a model that has very low internal climate variability illustrate that the attribution of carbon fluxes and accounting for injected CO2 may be very challenging in the real climate system with its much larger internal variability.

CO2–rock–brine interactions in Lower Tuscaloosa Formation at Cranfield CO2 sequestration site, Mississippi, U.S.A.

USGS Publications Warehouse

Lu, Jiemin; Kharaka, Yousif K.; Thordsen, James J.; Horita, Juske; Karamalidis, Athanasios; Griffith, Craig; Hakala, J. Alexandra; Ambats, Gil; Cole, David R.; Phelps, Tommy J.; Manning, Michael A.; Cook, Paul J.; Hovorka, Susan D.

2012-01-01

A highly integrated geochemical program was conducted at the Cranfield CO2-enhanced oil recovery (EOR) and sequestration site, Mississippi, U.S.A.. The program included extensive field geochemical monitoring, a detailed petrographic study, and an autoclave experiment under in situ reservoir conditions. Results show that mineral reactions in the Lower Tuscaloosa reservoir were minor during CO2 injection. Brine chemistry remained largely unchanged, which contrasts with significant changes observed in other field tests. Field fluid sampling and laboratory experiments show consistently slow reactions. Carbon isotopic composition and CO2 content in the gas phase reveal simple two-end-member mixing between injected and original formation gas. We conclude that the reservoir rock, which is composed mainly of minerals with low reactivity (average quartz 79.4%, chlorite 11.8%, kaolinite 3.1%, illite 1.3%, concretionary calcite and dolomite 1.5%, and feldspar 0.2%), is relatively unreactive to CO2. The significance of low reactivity is both positive, in that the reservoir is not impacted, and negative, in that mineral trapping is insignificant.

Qualitative and quantitative changes in detrital reservoir rocks caused by CO2-brine-rock interactions during first injection phases (Utrillas sandstones, northern Spain)

NASA Astrophysics Data System (ADS)

Berrezueta, E.; Ordóñez-Casado, B.; Quintana, L.

2016-01-01

The aim of this article is to describe and interpret qualitative and quantitative changes at rock matrix scale of lower-upper Cretaceous sandstones exposed to supercritical (SC) CO2 and brine. The effects of experimental injection of CO2-rich brine during the first injection phases were studied at rock matrix scale, in a potential deep sedimentary reservoir in northern Spain (Utrillas unit, at the base of the Cenozoic Duero Basin).

Experimental CO2-rich brine was exposed to sandstone in a reactor chamber under realistic conditions of deep saline formations (P ≈ 7.8 MPa, T ≈ 38 °C and 24 h exposure time). After the experiment, exposed and non-exposed equivalent sample sets were compared with the aim of assessing possible changes due to the effect of the CO2-rich brine exposure. Optical microscopy (OpM) and scanning electron microscopy (SEM) aided by optical image analysis (OIA) were used to compare the rock samples and get qualitative and quantitative information about mineralogy, texture and pore network distribution. Complementary chemical analyses were performed to refine the mineralogical information and to obtain whole rock geochemical data. Brine composition was also analyzed before and after the experiment.

The petrographic study of contiguous sandstone samples (more external area of sample blocks) before and after CO2-rich brine injection indicates an evolution of the pore network (porosity increase ≈ 2 %). It is probable that these measured pore changes could be due to intergranular quartz matrix detachment and partial removal from the rock sample, considering them as the early features produced by the CO2-rich brine. Nevertheless, the whole rock and brine chemical analyses after interaction with CO2-rich brine do not present important changes in the mineralogical and chemical configuration of the rock with respect to initial conditions, ruling out relevant precipitation or dissolution at these early stages to rock-block scale. These results, simulating the CO2 injection near the injection well during the first phases (24 h) indicate that, in this environment where CO2 enriches the brine, the mixture principally generates local mineralogical/textural re-adjustments on the external area of the samples studied.

The application of OpM, SEM and optical image analysis have allowed an exhaustive characterization of the sandstones studied. The procedure followed, the porosity characterization and the chemical analysis allowed a preliminary approximation of the CO2-brine-rock interactions and could be applied to similar experimental injection tests.

On-farm euthanasia of broiler chickens: effects of different gas mixtures on behavior and brain activity.

PubMed

Gerritzen, M A; Lambooij, B; Reimert, H; Stegeman, A; Spruijt, B

2004-08-01

The purpose of this study was to investigate the suitability of gas mixtures for euthanasia of groups of broilers in their housing by increasing the percentage of CO2. The suitability was assessed by the level of discomfort before loss of consciousness, and the killing rate. The gas mixtures injected into the housing were 1) 100% CO2, 2) 50% N2 + 50% CO2, and 3) 30% O2 + 40% CO2 + 30% N2, followed by 100% CO2. At 2 and 6 wk of age, groups of 20 broiler chickens per trial were exposed to increasing CO2 percentages due to the injection of these gas mixtures. Behavior and killing rate were examined. At the same time, 2 broilers per trial equipped with brain electrodes were observed for behavior and brain activity. Ten percent of the 2-wk-old broilers survived the increasing CO2 percentage due to the injection of 30% O2 + 40% CO2 + 30% N2 mixture, therefore this mixture was excluded for further testing at 6 wk of age. At 6 wk of age, 30% of the broilers survived in the 50% N2 + 50% CO2 group. The highest level of CO2 in the breathing air (42%) was reached by the injection of the 100% CO2 mixture, vs. 25% for the other 2 mixtures. In all 3 gas mixtures, head shaking, gasping, and convulsions were observed before loss of posture. Loss of posture and suppression of electrical activity of the brain (n = 7) occurred almost simultaneously. The results of this experiment indicate that euthanasia of groups of 2- and 6-wk-old broilers by gradually increasing the percentage of CO2 in the breathing air up to 40% is possible.

Predicting injection related changes in seismic properties at Kevin Dome, north central Montana, using well logs and laboratory measurements

NASA Astrophysics Data System (ADS)

Saltiel, S.; Bonner, B. P.; Ajo Franklin, J. B.

2014-12-01

Time-lapse seismic monitoring (4D) is currently the primary technique available for tracking sequestered CO2 in a geologic storage reservoir away from monitoring wells. The main seismic responses to injection are those due to direct fluid substitution, changes in differential pressure, and chemical interactions with reservoir rocks; the importance of each depends on reservoir/injection properties and temporal/spatial scales of interest. As part of the Big Sky Carbon Sequestration Partnership, we are monitoring the upcoming large scale (1 million ton+) CO2 injection in Kevin Dome, north central Montana. As part of this research, we predict the relative significance of these three effects, as an aid in design of field surveys. Analysis is undertaken using existing open-hole well log data and cores from wells drilled at producer and injector pads as well as core experiments. For this demonstration site, CO2 will be produced from a natural reservoir and re-injected down dip, where the formation is saturated with brine. Effective medium models based on borehole seismic velocity measurements predict relatively small effects (less than 40 m/s change in V¬p) due to the injection of more compressible supercritical CO2. This is due to the stiff dolomite reservoir rock, with high seismic velocities (Vp~6000 m/s, Vs~3000 m/s) and fairly low porosity (<10%). Assuming pure dolomite mineralogy, these models predict a slight increase in Vp during CO2 injection. This velocity increase is due to the lower density of CO2 relative to brine; which outweighs the small change in modulus compared to the stiff reservoir rock. We present both room pressure and in-situ P/T ultrasonic experiments using core samples obtained from the reservoir; such measurements are undertaken to access the expected seismic velocities under pressurized injection. The reservoir appears to have fairly low permeability. Large-volume injection is expected to produce large local pore pressure increases, which may have the largest immediate effect on seismic velocities. Increasing pore pressure lowers the differential pressure due to confining stress, which decreases seismic velocities by opening cracks. The magnitude of this effect depends both on rock microstructure and fracture at the field scale; core scale measurements will help separate these effects.

Experimental investigation of CO2-brine-rock interactions at elevated temperature and pressure: Implications for CO2 sequestration in deep-saline aquifers

USGS Publications Warehouse

Rosenbauer, R.J.; Koksalan, T.; Palandri, J.L.

2005-01-01

Deep-saline aquifers are potential repositories for excess CO2, currently being emitted to the atmosphere from anthropogenic activities, but the reactivity of supercritical CO2 with host aquifer fluids and formation minerals needs to be understood. Experiments reacting supercritical CO2 with natural and synthetic brines in the presence and absence of limestone and plagioclase-rich arkosic sandstone showed that the reaction of CO2-saturated brine with limestone results in compositional, mineralogical, and porosity changes in the aquifer fluid and rock that are dependent on initial brine composition, especially dissolved calcium and sulfate. Experiments reacting CO2-saturated, low-sulfate brine with limestone dissolved 10% of the original calcite and increased rock porosity by 2.6%. Experiments reacting high-sulfate brine with limestone, both in the presence and absence of supercritical CO2, were characterized by the precipitation of anhydrite, dolomitization of the limestone, and a final decrease in porosity of 4.5%. However, based on favorable initial porosity changes of about 15% due to the dissolution of calcite, the combination of CO2 co-injection with other mitigation strategies might help alleviate some of the well-bore scale and formation-plugging problems near the injection zone of a brine disposal well in Paradox Valley, Colorado, as well as provide a repository for CO2. Experiments showed that the solubility of CO2 is enhanced in brine in the presence of limestone by 9% at 25 ??C and 6% at 120 ??C and 200 bar relative to the brine itself. The solubility of CO2 is enhanced also in brine in the presence of arkosic sandstone by 5% at 120 ??C and 300 bar. The storage of CO 2 in limestone aquifers is limited to only ionic and hydraulic trapping. However, brine reacted with supercritical CO2 and arkose yielded fixation and sequestration of CO2 in carbonate mineral phases. Brine desiccation was observed in all experiments containing a discrete CO2 phase, promoting porosity-reducing precipitation reactions in aquifers near saturation with mineral phases. Published by Elsevier B.V.

Application of Geochemical Parameters for the Early Detection of CO2 Leakage from Sequestration Sites into Groundwater

NASA Astrophysics Data System (ADS)

Kharaka, Y. K.; Beers, S.; Thordsen, J.; Thomas, B.; Campbell, P.; Herkelrath, W. N.; Abedini, A. A.

2011-12-01

Geologically sequestered CO2 is buoyant, has a low viscosity and, when dissolved in brine, becomes reactive to minerals and well pipes. These properties of CO2 may cause it to leak upward, possibly contaminating underground sources of drinking water. We have participated in several multi-laboratory field experiments to investigate the chemical and isotopic parameters that are applicable to monitoring the flow of injected CO2 into deep saline aquifers and into potable shallow groundwater. Geochemical results from the deep SECARB Phase III tests at Cranfield oil field, Mississippi, and from the Frio Brine I and II pilots located in the S. Liberty oil field, Dayton, Texas, proved powerful tools in: 1- Tracking the successful injection and flow of CO2 into the injection sandstones; 2- showing major changes in the chemical (pH, alkalinity, and major divalent cations) and isotopic (δ13C values of CO2, and δ18O values of CO2 and brine) compositions of formation water; 3-. showing mobilization of metals, including Fe Mn and Pb, and organic compounds , including DOC, BTEX, PAHs, and phenols following CO2 injection; and 4- showing that some of the CO2 injected into the Frio "C" sandstone was detected in the overlying "B" sandstone that is separated from it by 15 m of shale and siltstone. Rapid, significant and systematic changes were also observed in the isotopic and chemical compositions of shallow groundwater at the Zero Emissions Research and Technology (ZERT) site located in Bozeman, Montana, in response to four yearly injections of variable amounts of CO2 gas through a slotted pipe placed horizontally at a depth of ~2 m below ground level. The observed changes, included the lowering of groundwater pH from ~7.0 to values as low as 5.6, increases in the alkalinity from about 400 mg/L as HCO3 to values of up to 1330 mg/L, increases in the electrical conductance from ~600 μS/cm to up to 1800 μS/cm, as well as increases in the concentrations of cations and metals following CO2 injection. Geochemical modeling, sequential extractions of cations from the ZERT-aquifer sediments, and controlled laboratory CO2-groundwater-sediment interactions demonstrated that calcite dissolution and ion exchange on organic material and inorganic mineral surfaces are responsible for the observed chemical changes. Results from both the deep and shallow field tests show that geochemical methods have highly sensitive chemical and isotopic tracers that are needed at CO2 injection sites to monitor injection performance and for early detection of any CO2 and brine leakages.

Reactivity of rock and well in a geological storage of CO2 : role of co-injected gases

NASA Astrophysics Data System (ADS)

Renard, S.; Sterpenich, J.; Pironon, J.

2009-04-01

The CO2 capture and geological storage from high emitting sources (coal and gas power plants) is one of a panel of solutions proposed to reduce the global greenhouse gas emissions. Different pre- , post- or oxy-combustion capture processes are now available to separate associated gases (SOx, NOx, etc…) and the CO2. However, complete purification of CO2 is unachievable for cost reasons as well as for CO2 surplus of emissions due to the separation processes. By consequence, a non-negligible part (more or less 5%) of these gases, called "annex gases", could be co-injected with the CO2. Their impact on the chemical stability of reservoir rocks, caprocks and wells has to be evaluated before any large scale injection procedure. Physico-chemical transformations could modify mechanical and injectivity properties of the site and possibly alter storage safety. One of the aims of the CCS pilot project leaded by TOTAL at Lacq (France) is to develop, through a real case study, a methodology for a long-term safe storage qualification. Greenhouse gases are captured from an oxy-combustion power plant, transported along 30 km to the carbonate reservoir of Rousse at around 4500 m in depth. The study presented here is focused on laboratory simulations of geochemical interactions between the reservoir rock (fractured dolomite), the caprock (marl) and the injected CO2 with some potential annex gases. In the same time, experiments are performed on the reactivity of reference minerals such as calcite, dolomite, muscovite, quartz and pyrite to better understand the implication of each phase on bulk rock reactivity. Moreover, well reactivity is observed through specific steel and cement used by petroleum industry. Two annex gases (SO2 and NO) have been selected.. Their reactivity is compared to that of N2 considered as an inert annex gas from a chemical point of view. Solid samples are placed in 1cm3 gold capsules in presence or not of water with a salinity of 25 NaCl g/l. Gases are hermetically transferred by cold trap into the gold reactors that are sealed by electrical welding and placed in an autoclave during one month at 150˚ C and 100 bar, which represent the geological conditions in the Rousse reservoir after two years of injection. After experiments, solid samples (rock, cement, steel) are observed and analysed with different techniques (SEM, TEM, Raman and XRD). Gases are also collected and analysed by Raman spectrometry whereas the aqueous solution is analysed with ICP-MS, ICP-AES and ionic chromatography. As sampling methods cannot be used during experiment the synthetic fluid inclusions technique has been developed to trap and analyse the fluids in experimental conditions. It allows to characterise the number of phase and the nature of dissolved species. Mass balances are established in order to quantify the reaction rates. This study shows the first results concerning the mineralogical transformation of rocks and well materials that have undergone CO2and co-injected annex gases. The results are used to better constrain thermodynamical approaches leading to a predictive geochemical modelling. The results are interpreted in terms of petrophysical and chemical impacts of the injected gases on the mineral assemblages of a storage site. This work is supported by TOTAL and ADEME (national agency for energy control and development, France).

Field-based stable isotope analysis of carbon dioxide by mid-infrared laser spectroscopy for carbon capture and storage monitoring.

PubMed

van Geldern, Robert; Nowak, Martin E; Zimmer, Martin; Szizybalski, Alexandra; Myrttinen, Anssi; Barth, Johannes A C; Jost, Hans-Jürg

2014-12-16

A newly developed isotope ratio laser spectrometer for CO2 analyses has been tested during a tracer experiment at the Ketzin pilot site (northern Germany) for CO2 storage. For the experiment, 500 tons of CO2 from a natural CO2 reservoir was injected in supercritical state into the reservoir. The carbon stable isotope value (δ(13)C) of injected CO2 was significantly different from background values. In order to observe the breakthrough of the isotope tracer continuously, the new instruments were connected to a stainless steel riser tube that was installed in an observation well. The laser instrument is based on tunable laser direct absorption in the mid-infrared. The instrument recorded a continuous 10 day carbon stable isotope data set with 30 min resolution directly on-site in a field-based laboratory container during a tracer experiment. To test the instruments performance and accuracy the monitoring campaign was accompanied by daily CO2 sampling for laboratory analyses with isotope ratio mass spectrometry (IRMS). The carbon stable isotope ratios measured by conventional IRMS technique and by the new mid-infrared laser spectrometer agree remarkably well within analytical precision. This proves the capability of the new mid-infrared direct absorption technique to measure high precision and accurate real-time stable isotope data directly in the field. The laser spectroscopy data revealed for the first time a prior to this experiment unknown, intensive dynamic with fast changing δ(13)C values. The arrival pattern of the tracer suggest that the observed fluctuations were probably caused by migration along separate and distinct preferential flow paths between injection well and observation well. The short-term variances as observed in this study might have been missed during previous works that applied laboratory-based IRMS analysis. The new technique could contribute to a better tracing of the migration of the underground CO2 plume and help to ensure the long-term integrity of the reservoir.

Injection and Monitoring at the Wallula Basalt Pilot Project

DOE PAGES

McGrail, B. Peter; Spane, Frank A.; Amonette, James E.; ...

2014-01-01

Continental flood basalts represent one of the largest geologic structures on earth but have received comparatively little attention for geologic storage of CO2. Flood basalt lava flows have flow tops that are porous, permeable, and have large potential capacity for storage of CO2. In appropriate geologic settings, interbedded sediment layers and dense low-permeability basalt rock flow interior sections may act as effective seals allowing time for mineralization reactions to occur. Previous laboratory experiments showed the relatively rapid chemical reaction of CO2-saturated pore water with basalts to form stable carbonate minerals. However, recent laboratory tests with water-saturated supercritical CO2 show thatmore » mineralization reactions occur in this phase as well, providing a second and potentially more important mineralization pathway than was previously understood. Field testing of these concepts is proceeding with drilling of the world’s first supercritical CO2 injection well in flood basalt being completed in May 2009 near the township of Wallula in Washington State and corresponding CO2 injection permit granted by the State of Washington in March 2011. Injection of a nominal 1000 MT of CO2 was completed in August 2013 and site monitoring is in progress. Well logging conducted immediately after injection termination confirmed the presence of CO2 predominantly within the upper flow top region, and showed no evidence of vertical CO2 migration outside the well casing. Shallow soil gas samples collected around the injection well show no evidence of leakage and fluid and gas samples collected from the injection zone show strongly elevated concentrations of Ca, Mg, Mn, and Fe and 13C/18O isotopic shifts that are consistent with basalt-water chemical reactions. If proven viable by this field test and others that are in progress or being planned, major flood basalts in the U.S., India, and perhaps Australia would provide significant additional CO2 storage capacity and additional geologic sequestration options in regions of these countries where conventional storage options are limited.« less

Boundary-Layer Transition on a Slender Cone in Hypervelocity Flow with Real Gas Effects

NASA Astrophysics Data System (ADS)

Jewell, Joseph Stephen

The laminar to turbulent transition process in boundary layer flows in thermochemical nonequilibrium at high enthalpy is measured and characterized. Experiments are performed in the T5 Hypervelocity Reflected Shock Tunnel at Caltech, using a 1 m length 5-degree half angle axisymmetric cone instrumented with 80 fast-response annular thermocouples, complemented by boundary layer stability computations using the STABL software suite. A new mixing tank is added to the shock tube fill apparatus for premixed freestream gas experiments, and a new cleaning procedure results in more consistent transition measurements. Transition location is nondimensionalized using a scaling with the boundary layer thickness, which is correlated with the acoustic properties of the boundary layer, and compared with parabolized stability equation (PSE) analysis. In these nondimensionalized terms, transition delay with increasing CO2 concentration is observed: tests in 100% and 50% CO2, by mass, transition up to 25% and 15% later, respectively, than air experiments. These results are consistent with previous work indicating that CO2 molecules at elevated temperatures absorb acoustic instabilities in the MHz range, which is the expected frequency of the Mack second-mode instability at these conditions, and also consistent with predictions from PSE analysis. A strong unit Reynolds number effect is observed, which is believed to arise from tunnel noise. NTr for air from 5.4 to 13.2 is computed, substantially higher than previously reported for noisy facilities. Time- and spatially-resolved heat transfer traces are used to track the propagation of turbulent spots, and convection rates at 90%, 76%, and 63% of the boundary layer edge velocity, respectively, are observed for the leading edge, centroid, and trailing edge of the spots. A model constructed with these spot propagation parameters is used to infer spot generation rates from measured transition onset to completion distance. Finally, a novel method to control transition location with boundary layer gas injection is investigated. An appropriate porous-metal injector section for the cone is designed and fabricated, and the efficacy of injected CO2 for delaying transition is gauged at various mass flow rates, and compared with both no injection and chemically inert argon injection cases. While CO2 injection seems to delay transition, and argon injection seems to promote it, the experimental results are inconclusive and matching computations do not predict a reduction in N factor from any CO2 injection condition computed.

Area 2. Use Of Engineered Nanoparticle-Stabilized CO 2 Foams To Improve Volumetric Sweep Of CO 2 EOR Processes

DOE Office of Scientific and Technical Information (OSTI.GOV)

DiCarlo, David; Huh, Chun; Johnston, Keith P.

2015-01-31

The goal of this project was to develop a new CO 2 injection enhanced oil recovery (CO 2-EOR) process using engineered nanoparticles with optimized surface coatings that has better volumetric sweep efficiency and a wider application range than conventional CO 2-EOR processes. The main objectives of this project were to (1) identify the characteristics of the optimal nanoparticles that generate extremely stable CO 2 foams in situ in reservoir regions without oil; (2) develop a novel method of mobility control using “self-guiding” foams with smart nanoparticles; and (3) extend the applicability of the new method to reservoirs having a widemore » range of salinity, temperatures, and heterogeneity. Concurrent with our experimental effort to understand the foam generation and transport processes and foam-induced mobility reduction, we also developed mathematical models to explain the underlying processes and mechanisms that govern the fate of nanoparticle-stabilized CO 2 foams in porous media and applied these models to (1) simulate the results of foam generation and transport experiments conducted in beadpack and sandstone core systems, (2) analyze CO 2 injection data received from a field operator, and (3) aid with the design of a foam injection pilot test. Our simulator is applicable to near-injection well field-scale foam injection problems and accounts for the effects due to layered heterogeneity in permeability field, foam stabilizing agents effects, oil presence, and shear-thinning on the generation and transport of nanoparticle-stabilized C/W foams. This report presents the details of our experimental and numerical modeling work and outlines the highlights of our findings.« less

Fluid Dynamics of Carbon Dioxide Disposal into Saline Aquifers

DOE Office of Scientific and Technical Information (OSTI.GOV)

Garcia, Julio Enrique

2003-01-01

Injection of carbon dioxide (CO 2) into saline aquifers has been proposed as a means to reduce greenhouse gas emissions (geological carbon sequestration). Large-scale injection of CO 2 will induce a variety of coupled physical and chemical processes, including multiphase fluid flow, fluid pressurization and changes in effective stress, solute transport, and chemical reactions between fluids and formation minerals. This work addresses some of these issues with special emphasis given to the physics of fluid flow in brine formations. An investigation of the thermophysical properties of pure carbon dioxide, water and aqueous solutions of CO 2 and NaCl has beenmore » conducted. As a result, accurate representations and models for predicting the overall thermophysical behavior of the system CO 2-H 2O-NaCl are proposed and incorporated into the numerical simulator TOUGH2/ECO2. The basic problem of CO 2 injection into a radially symmetric brine aquifer is used to validate the results of TOUGH2/ECO2. The numerical simulator has been applied to more complex flow problem including the CO 2 injection project at the Sleipner Vest Field in the Norwegian sector of the North Sea and the evaluation of fluid flow dynamics effects of CO 2 injection into aquifers. Numerical simulation results show that the transport at Sleipner is dominated by buoyancy effects and that shale layers control vertical migration of CO 2. These results are in good qualitative agreement with time lapse surveys performed at the site. High-resolution numerical simulation experiments have been conducted to study the onset of instabilities (viscous fingering) during injection of CO 2 into saline aquifers. The injection process can be classified as immiscible displacement of an aqueous phase by a less dense and less viscous gas phase. Under disposal conditions (supercritical CO 2) the viscosity of carbon dioxide can be less than the viscosity of the aqueous phase by a factor of 15. Because of the lower viscosity, the CO 2 displacement front will have a tendency towards instability. Preliminary simulation results show good agreement between classical instability solutions and numerical predictions of finger growth and spacing obtained using different gas/liquid viscosity ratios, relative permeability and capillary pressure models. Further studies are recommended to validate these results over a broader range of conditions.« less

How Do Deep Saline Aquifer Microbial Communities Respond to Supercritical CO2 Injection?

NASA Astrophysics Data System (ADS)

Mu, A.; Billman-Jacobe, H.; Boreham, C.; Schacht, U.; Moreau, J. W.

2011-12-01

Carbon Capture and Storage (CCS) is currently seen as a viable strategy for mitigating anthropogenic carbon dioxide pollution. The Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) is currently conducting a field experiment in the Otway Basin (Australia) studying residual gas saturation in the water-saturated reservoir of the Paaratte Formation. As part of this study, a suite of pre-CO2 injection water samples were collected from approximately 1400 meters depth (60°C, 13.8 MPa) via an in situ sampling system. The in situ sampling system isolates aquifer water from sources of contamination while maintaining the formation pressure. Whole community DNA was extracted from these samples to investigate the prokaryotic biodiversity of the saline Paaratte aquifer (EC = 1509.6 uS/cm). Bioinformatic analysis of preliminary 16S ribosomal gene data revealed Thermincola, Acinetobacter, Sphingobium, and Dechloromonas amongst the closest related genera to environmental clone sequences obtained from a subset of pre-CO2 injection groundwater samples. Epifluorescent microscopy with 4',6-diamidino-2-phenylindole (DAPI) highlighted an abundance of filamentous cells ranging from 5 to 45 μM. Efforts are currently directed towards utilising a high throughput sequencing approach to capture an exhaustive profile of the microbial diversity of the Paaratte aquifer CO2 injection site, and to understand better the response of in situ microbial populations to the injection of large volumes (e.g. many kilotonnes) of supercritical CO2 (sc-CO2). Sequencing results will be used to direct cultivation efforts towards enrichment of a CO2-tolerant microorganism. Understanding the microbial response to sc-CO2 is an integral aspect of carbon dioxide storage, for which very little information exists in the literature. This study aims to elucidate molecular mechanisms, through genomic and cultivation-based methods, for CO2 tolerance with the prospect of engineering biofilms to enhance trapping of CO2 in saline aquifers.

CO2 exsolution - challenges and opportunities in subsurface flow management

NASA Astrophysics Data System (ADS)

Zuo, Lin; Benson, Sally

2014-05-01

In geological carbon sequestration, a large amount of injected CO2 will dissolve in brine over time. Exsolution occurs when pore pressures decline and CO2 solubility in brine decreases, resulting in the formation of a separate CO2 phase. This scenario occurs in storage reservoirs by upward migration of carbonated brine, through faults, leaking boreholes or even seals, driven by a reverse pressure gradient from CO2 injection or ground water extraction. In this way, dissolved CO2 could migrate out of storage reservoirs and form a gas phase at shallower depths. This paper summarizes the results of a 4-year study regarding the implications of exsolution on storage security, including core-flood experiments, micromodel studies, and numerical simulation. Micromodel studies have shown that, different from an injected CO2 phase, where the gas remains interconnected, exsolved CO2 nucleates in various locations of a porous medium, forms disconnected bubbles and propagates by a repeated process of bubble expansion and snap-off [Zuo et al., 2013]. A good correlation between bubble size distribution and pore size distribution is observed, indicating that geometry of the pore space plays an important role in controlling the mobility of brine and exsolved CO2. Core-scale experiments demonstrate that as the exsolved gas saturation increases, the water relative permeability drops significantly and is disproportionately reduced compared to drainage relative permeability [Zuo et al., 2012]. The CO2 relative permeability remains very low, 10-5~10-3, even when the exsolved CO2 saturation increases to over 40%. Furthermore, during imbibition with CO2 saturated brines, CO2 remains trapped even under relatively high capillary numbers (uv/σ~10-6) [Zuo et al., submitted]. The water relative permeability at the imbibition endpoint is 1/3~1/2 of that with carbonated water displacing injected CO2. Based on the experimental evidence, CO2 exsolution does not appear to create significant risks for storage security. Falta et al. [2013] show that if carbonated brine migrates upwards and exsolution occurs, brine migration would be greatly reduced and limited by the presence of exsolved CO2 and the consequent low relatively permeability to brine. Similarly, if an exsolved CO2 phase were to evolve in seals, for example, after CO2 injection stops, the effect would be to reduce the permeability to brine and the CO2 would have very low mobility. This flow blocking effect is also studied with water/oil/CO2 [Zuo et al., 2013]. Experiments show that exsolved CO2 performs as a secondary residual phase in porous media that effectively blocks established water flow paths and deviates water to residual oil zones, thereby increasing recovery. Overall, our studies suggest that CO2 exsolution provides an opportunity for mobility control in subsurface processes. However, the lack of simulation capability that accounts for differences between gas injection and gas exsolution creates challenges for modeling and hence, designing studies to exploit the mobility reduction capabilities of CO2 exsolution. Using traditional drainage multiphase flow parameterization in simulations involving exsolution will lead to large errors in transport rates. Development of process dependent parameterizations of multiphase flow properties will be a key next step and will help to unlock the benefits from gas exsolution. ACKNOWLEDGEMENT This work is funded by the Global Climate and Energy Project (GCEP) at Stanford University. This work was also supported by U.S. EPA, Science To Achieve Results (STAR) Program, Grant #: 834383, 2010-2012. REFERENCES Falta, R., L. Zuo and S.M. Benson (2013). Migration of exsolved CO2 following depressurization of saturated brines. Journal of Greenhouse Gas Science and Technology, 3(6), 503-515. Zuo, L., S.C.M. Krevor, R.W. Falta, and S.M. Benson (2012). An experimental study of CO2 exsolution and relative permeability measurements during CO2 saturated water depressurization. Transp. Porous Media, 91(2), 459-478. Zuo, L., C. Zhang, R.W. Falta, and S.M. Benson (2013). Micromodel investigations of CO2 exsolution from carbonated water in sedimentary rocks. Adv. Water Res., 53, 188-197. Zuo, L., and S.M. Benson (2013). Exsolution enhanced oil recovery with concurrent CO2 sequestration. Energy Procedia, 37, 6957-6963. Zuo, L., and S.M. Benson. Different Effects of Imbibed and Exsolved Residually Trapped CO2 in Sandstone. Submitted to Geophysical Research Letters.

Experimental Insights into Multiphase (H2O-CO2) Fluid-Rock Interactions in Geothermal Systems

NASA Astrophysics Data System (ADS)

Kaszuba, J. P.; Lo Re, C.; Martin, J.; McPherson, B. J.; Moore, J. N.

2012-12-01

Integrated hydrothermal experiments and geochemical modeling elucidate fluid-rock interactions and reaction pathways in both natural and anthropogenic systems, including enhanced geothermal systems (EGS) in which CO2 is introduced as a working fluid. Experiments are conducted in rocker bombs and flexible Au-Ti reaction cells. Individual experiments require one to three months to complete; intensive in-situ fluid/gas sampling gauges reaction progress. Investigation of granitic reservoirs and associated vein minerals are broadly based on the Roosevelt Hot Springs thermal area, Utah, USA. The granite consists of subequal amounts of quartz, perthitic K-feldspar (~25% wt% albite and 75% wt% K-feldspar), and oligoclase (An23), and 4 wt% Fe-rich biotite. Vein minerals include epidote and chlorite (clinochlore). Experiments are conducted at 250°C and 25 to 45 MPa. Each experiment uses mineral powders (75 wt% of rock mass, ground to <45 um) to increase reactivity and also mineral pieces (0.1-0.7 cm in size) to promote petrologic evaluation of mineral reactions. The water (I ≈ 0.1 molal) initially contains millimolal quantities of SiO2, Al, Ca, Mg, K, SO4, and HCO3 and is designed to be saturated with all of the minerals present at the start of each experiment. Excess CO2 is injected to saturate the water and maintain an immiscible supercritical fluid phase. The entire evolutionary path of the natural system is not replicated at laboratory scales. Instead, experiments define a segment of the reaction path and, in combination with geochemical modeling, provide clear trajectories towards equilibrium. Reaction of granite+water yields illite+zeolite; smectite subsequently precipitates in response to CO2 injection. Reaction of granite+epidote+water yields illite+zeolite+smectite; zeolite does not precipitate after CO2 is injected. Water in all experiments become saturated with chalcedony. Carbonate minerals do not precipitate but are predicted as final equilbrium products. Enhanced Geothermal Systems are expected to follow similar reaction pathways and produce metastable minerals during initial development.

CO2 breakthrough pressure and permeability for unsaturated low-permeability sandstone of the Ordos Basin

NASA Astrophysics Data System (ADS)

Zhao, Yan; Yu, Qingchun

2017-07-01

With rising threats from greenhouse gases, capture and injection of CO2 into suitable underground formations is being considered as a method to reduce anthropogenic emissions of CO2 to the atmosphere. As the injected CO2 will remain in storage for hundreds of years, the safety of CO2 geologic sequestration is a major concern. The low-permeability sandstone of the Ordos Basin in China is regarded as both caprock and reservoir rock, so understanding the breakthrough pressure and permeability of the rock is necessary. Because part of the pore volume experiences a non-wetting phase during the CO2 injection and migration process, the rock may be in an unsaturated condition. And if accidental leakage occurs, CO2 will migrate up into the unsaturated zone. In this study, breakthrough experiments were performed at various degrees of water saturation with five core samples of low-permeability sandstone obtained from the Ordos Basin. The experiments were conducted at 40 °C and pressures of >8 MPa to simulate the geological conditions for CO2 sequestration. The results indicate that the degree of water saturation and the pore structure are the main factors affecting the rock breakthrough pressure and permeability, since the influence of calcite dissolution and clay mineral swelling during the saturation process is excluded. Increasing the average pore radius or most probable pore radius leads to a reduction in the breakthrough pressure and an increase by several orders of magnitude in scCO2 effective permeability. In addition, the breakthrough pressure rises and the scCO2 effective permeability decreases when the water saturation increases. However, when the average pore radius is greater than 0.151 μm, the degree of water saturation will has a little effect on the breakthrough pressure. On this foundation, if the most probable pore radius of the core sample reaches 1.760 μm, the breakthrough pressure will not be impacted by the increasing water saturation. We establish correlations between (1) the breakthrough pressure and average pore radius or most probable pore radius, (2) the breakthrough pressure and scCO2 effective permeability, (3) the breakthrough pressure and water saturation, and (4) the scCO2 effective permeability and water saturation. This study provides practical information for further studies of CO2 sequestration as well as the caprock evaluation.

A connectivity-based modeling approach for representing hysteresis in macroscopic two-phase flow properties

DOE PAGES

Cihan, Abdullah; Birkholzer, Jens; Trevisan, Luca; ...

2014-12-31

During CO 2 injection and storage in deep reservoirs, the injected CO 2 enters into an initially brine saturated porous medium, and after the injection stops, natural groundwater flow eventually displaces the injected mobile-phase CO 2, leaving behind residual non-wetting fluid. Accurate modeling of two-phase flow processes are needed for predicting fate and transport of injected CO 2, evaluating environmental risks and designing more effective storage schemes. The entrapped non-wetting fluid saturation is typically a function of the spatially varying maximum saturation at the end of injection. At the pore-scale, distribution of void sizes and connectivity of void space playmore » a major role for the macroscopic hysteresis behavior and capillary entrapment of wetting and non-wetting fluids. This paper presents development of an approach based on the connectivity of void space for modeling hysteretic capillary pressure-saturation-relative permeability relationships. The new approach uses void-size distribution and a measure of void space connectivity to compute the hysteretic constitutive functions and to predict entrapped fluid phase saturations. Two functions, the drainage connectivity function and the wetting connectivity function, are introduced to characterize connectivity of fluids in void space during drainage and wetting processes. These functions can be estimated through pore-scale simulations in computer-generated porous media or from traditional experimental measurements of primary drainage and main wetting curves. The hysteresis model for saturation-capillary pressure is tested successfully by comparing the model-predicted residual saturation and scanning curves with actual data sets obtained from column experiments found in the literature. A numerical two-phase model simulator with the new hysteresis functions is tested against laboratory experiments conducted in a quasi-two-dimensional flow cell (91.4cm×5.6cm×61cm), packed with homogeneous and heterogeneous sands. Initial results show that the model can predict spatial and temporal distribution of injected fluid during the experiments reasonably well. However, further analyses are needed for comprehensively testing the ability of the model to predict transient two-phase flow processes and capillary entrapment in geological reservoirs during geological carbon sequestration.« less

Hydrogeological characterization of shallow-depth zone for CO2 injection and leak test at a CO2 environmental monitoring site in Korea

NASA Astrophysics Data System (ADS)

Lee, S. S.; Kim, T. W.; Kim, H. H.; Ha, S. W.; Jeon, W. T.; Lee, K. K.

2015-12-01

The main goal of the this study is to evaluate the importance of heterogeneities in controlling the field-scale transport of CO2 are originated from the CO2 injected at saturated zone below the water table for monitoring and prediction of CO2 leakage from a reservoir. Hydrogeological and geophysical data are collected to characterize the site, prior to conducting CO2 injection experiment at the CO2 environmental monitoring site at Eumseong, Korea. The geophysical data were acquired from borehole electromagnetic flowmeter tests, while the hydraulic data were obtained from pumping tests, slug tests, and falling head permeability tests. Total of 13 wells to perform hydraulic and geophysical test are established along groundwater flow direction in regular sequence, revealed by the results of borehole electromagnetic flowmeter test. The results of geophysical tests indicated that hydraulic gradient is not identical with the topographic gradient. Groundwater flows toward the uphill direction in the study area. Then, the hydraulic tests were conducted to identify the hydraulic properties of the study site. According to the results of pumping and slug tests at the study site, the hydraulic conductivity values show ranges between 4.75 x 10-5 cm/day and 9.74 x 10-5 cm/day. In addition, a portable multi-level sampling and monitoring packer device which remains inflated condition for a long period developed and used to isolate designated depths to identify vertical distribution of hydrogeological characteristics. Hydrogeological information obtained from this study will be used to decide the injection test interval of CO2-infused water and gaseous CO2. Acknowledgement: Financial support was provided by "R&D Project on Environmental Mangement of Geologic CO2 Storage" from the KEITI (Project Number: 2014001810003).

An investigation of reaction parameters on geochemical storage of non-pure CO2 streams in iron oxides-bearing formations

DOE Office of Scientific and Technical Information (OSTI.GOV)

Garcia, Susana; Liu, Q.; Bacon, Diana H.

2014-08-26

Hematite deposit that is the main FeIII-bearing mineral in sedimentary red beds was proposed as a potential host repository for converting CO2 into carbonate minerals such as siderite (FeCO3), when CO2–SO2 gas mixtures are co-injected. This work investigated CO2 mineral trapping using hematite and sensitivity of the reactive systems to different parameters, including particle size, gas composition, temperature, pressure, and solid-to-liquid ratio. Experimental and modelling studies of hydrothermal experiments were conducted, which emulated a CO2 sequestration scenario by injecting CO2-SO2 gas streams into a NaCl-NaOH brine hosted in iron oxide-containing aquifer. This study provides novel information on the mineralogical changesmore » and fluid chemistry derived from the co-injection of CO2-SO2 gas mixtures in hematite deposit. It can be concluded that the amount of siderite precipitate depends primarily on the SO2 content of the gas stream. Increasing SO2 content in the system could promote the reduction of Fe3+ from the hematite sample to Fe2+, which will be further available for its precipitation as siderite. Moreover, siderite precipitation is enhanced at low temperatures and high pressures. The influence of the solid to liquid ratio on the overall carbonation reaction suggests that the conversion increases if the system becomes more diluted.« less

DOE Office of Scientific and Technical Information (OSTI.GOV)

Soltanian, Mohamad Reza; Amooie, Mohammad Amin; Cole, David R.

In this study, a field-scale carbon dioxide (CO 2) injection pilot project was conducted as part of the Southeast Regional Sequestration Partnership (SECARB) at Cranfield, Mississippi. We present higher-order finite element simulations of the compositional two-phase CO 2-brine flow and transport during the experiment. High- resolution static models of the formation geology in the Detailed Area Study (DAS) located below the oil- water contact (brine saturated) are used to capture the impact of connected flow paths on breakthrough times in two observation wells. Phase behavior is described by the cubic-plus-association (CPA) equation of state, which takes into account the polarmore » nature of water molecules. Parameter studies are performed to investigate the importance of Fickian diffusion, permeability heterogeneity, relative permeabilities, and capillarity. Simulation results for the pressure response in the injection well and the CO 2 breakthrough times at the observation wells show good agreement with the field data. For the high injection rates and short duration of the experiment, diffusion is relatively unimportant (high P clet numbers), while relative permeabilities have a profound impact on the pressure response. High-permeability pathways, created by fluvial deposits, strongly affect the CO 2 transport and highlight the importance of properly characterizing the formation heterogeneity in future carbon sequestration projects.« less

The movement of sequestrated CO2 revealed by seismic attenuation spatial and temporal changes in Frio-II site, USA

NASA Astrophysics Data System (ADS)

Zhu, T.; Ajo Franklin, J. B.; Daley, T. M.

2015-12-01

Continuous active source seismic measurements (CASSM) were collected in the crosswell geometry during scCO2 injection at the Frio-II brine pilot (Liberty, TX). Previous studies (Daley et.al. 2007, 2011) have demonstrated that spatial-temporal changes in the picked first arrival time after CO2 injection constrain the movement of the CO2 plume in the storage interval. To improve the quantitative constraints on plume saturation using this dataset, we investigate spatial-temporal changes in the seismic attenuation of the first arrivals. The attenuation changes over the injection period (~60 h) are estimated by the amount of the centroid frequency shift computed by the local time-frequency analysis. Our observations include: at receivers above the packer seismic attenuation does not change in a physical trend; at receivers below the packer attenuation sharply increases as the amount of CO2 plume increase at the first few hours and peaks at specific points varying with distributed receivers, which are consistent with observations from time delays of first arrivals. Then, attenuation decreases over the injection time with increased amount of CO2 plume. This bell-shaped attenuation response as a function of time in the experiment is consistent with White's patchy saturation model which predicts an attenuation peak at intermediate CO2 saturations. Our analysis suggests that spatial-temporal attenuation change is an indicator of the movement/saturation of CO2 plume at high saturations, a system state for which seismic measurements are typically only weakly sensitive to.

An experimental study of relative permeability hysteresis, capillary trapping characteristics, and capillary pressure of CO2/brine systems at reservoir conditions

NASA Astrophysics Data System (ADS)

Akbarabadi, Morteza

We present the results of an extensive experimental study on the effects of hysteresis on permanent capillary trapping and relative permeability of CO2/brine and supercritical (sc)CO2+SO2/brine systems. We performed numerous unsteady- and steady-state drainage and imbibition full-recirculation flow experiments in three different sandstone rock samples, i.e., low and high-permeability Berea, Nugget sandstones, and Madison limestone carbonate rock sample. A state-of-the-art reservoir conditions core-flooding system was used to perform the tests. The core-flooding apparatus included a medical CT scanner to measure in-situ saturations. The scanner was rotated to the horizontal orientation allowing flow tests through vertically-placed core samples with about 3.8 cm diameter and 15 cm length. Both scCO2 /brine and gaseous CO2 (gCO2)/brine fluid systems were studied. The gaseous and supercritical CO2/brine experiments were carried out at 3.46 and 11 MPa back pressures and 20 and 55°C temperatures, respectively. Under the above-mentioned conditions, the gCO2 and scCO2 have 0.081 and 0.393 gr/cm3 densities, respectively. During unsteady-state tests, the samples were first saturated with brine and then flooded with CO2 (drainage) at different maximum flow rates. The drainage process was then followed by a low flow rate (0.375 cm 3/min) imbibition until residual CO2 saturation was achieved. Wide flow rate ranges of 0.25 to 20 cm3/min for scCO2 and 0.125 to 120 cm3min for gCO2 were used to investigate the variation of initial brine saturation (Swi) with maximum CO2 flow rate and variation of trapped CO2 saturation (SCO2r) with Swi. For a given Swi, the trapped scCO2 saturation was less than that of gCO2 in the same sample. This was attributed to brine being less wetting in the presence of scCO2 than in the presence of gCO 2. During the steady-state experiments, after providing of fully-brine saturated core, scCO2 was injected along with brine to find the drainage curve and as a consequence the Swi, then it was followed by the imbibition process to measure SCO2r. We performed different cycles of relative permeability experiments to investigate the effect of hysteresis. The Swi and SCO2r varied from 0.525 to 0.90 and 0.34 to 0.081, respectively. Maximum CO2 and brine relative permeabilities at the end of drainage and imbibition and also variation of brine relative permeability due to post-imbibition CO2 dissolution during unsteady-state experiment were also studied. We co-injected SO2 with CO2 and brine into the Madison limestone core sample. The sample was acquired from the Rock Springs Uplift in southwest Wyoming. The temperature and pressure of the experiments were 60°C and 19.16 MPa, respectively. Each drainage-imbibition cycle was followed by a dissolution process to establish Sw=1. The results showed that about 76% of the initial CO2 was trapped by capillary trapping mechanism at the end of imbibition test. We also investigated the scCO2+SO2/brine capillary pressure versus saturation relationship through performing primary drainage, imbibition, and secondary drainage experiments. The results indicated that the wettability of the core sample might have been altered owing to being in contact with the scCO 2+SO2/brine system. During primary drainage CO2 displaced 52.5% of brine, i.e., Swi = 0.475. The subsequent imbibition led to 0.329 CO2 saturation. For all series of experiments, the ratio of SCO2r to initial CO2 saturation (1- S wi) was found to be much higher for low initial CO2 saturations. This means that greater fractions of injected CO2 can be permanently trapped at higher initial brine saturations. The results illustrated that very promising fractions (about 49 to 83 %) of the initial CO2 saturation can be trapped permanently. (Abstract shortened by UMI.).

Fines migration during CO 2 injection: Experimental results interpreted using surface forces

DOE Office of Scientific and Technical Information (OSTI.GOV)

Xie, Quan; Saeedi, Ali; Delle Piane, Claudio

The South West Hub project is one of the Australian Flagship Carbon Capture and Storage projects located in the south-west of Western Australia. To evaluate the injectivity potential during the forthcoming full-scale CO 2 injection, we conducted three core-flooding experiments using reservoir core plugs from the well Harvey-1. We aimed to investigate in this paper whether the injection of CO 2 leads to fines migration and permeability reduction due to the relatively high kaolinite content (up to 13%) in the injection interval of the target formation (i.e. the Wonnerup Member of the Lesueur Formation). We imaged the core samples beforemore » flooding to verify the presence of kaolinite at the pore-scale using scanning electron microscopy (SEM). We also examined the pore network of the core plugs before and after the core-flooding experiments using Nuclear Magnetic Resonance (NMR). Moreover, to gain a better understanding of any kaolinite fines migration, we delineated surface force using two models based on Derjaguin-Landau-Verwey-Overbeek (denoted by DLVO) theory coupled hydrodynamic force: (1) sphere/flat model representing interaction between kaolinite/quartz, and (2) flat/flat model representing interaction between kaolinite/kaolinite. Our core-flooding experimental results showed that CO 2/brine injection triggered moderate to significant reduction in the permeability of the core samples with a negligible porosity change. NMR measurements supported the core-flooding results, suggesting that the relatively large pores disappeared in favour of a higher proportion of the medium to small pores after flooding. The DLVO calculations showed that some kaolinite particles probably lifted off and detached from neighbouring kaolinite particles rather than quartz grains. Moreover, the modelling results showed that the kaolinite fines migration would not occur under normal reservoir multiphase flow conditions. This is not because of the low hydrodynamic force. It is rather because the geometries of the particles dominate their interplay. Finally and overall, both of the experimental and analytical modelling results point to the fines migration to be the most likely cause of the permeability impairment observed during core-flooding experiments.« less

Fines migration during CO 2 injection: Experimental results interpreted using surface forces

DOE PAGES

Xie, Quan; Saeedi, Ali; Delle Piane, Claudio; ...

2017-09-04

The South West Hub project is one of the Australian Flagship Carbon Capture and Storage projects located in the south-west of Western Australia. To evaluate the injectivity potential during the forthcoming full-scale CO 2 injection, we conducted three core-flooding experiments using reservoir core plugs from the well Harvey-1. We aimed to investigate in this paper whether the injection of CO 2 leads to fines migration and permeability reduction due to the relatively high kaolinite content (up to 13%) in the injection interval of the target formation (i.e. the Wonnerup Member of the Lesueur Formation). We imaged the core samples beforemore » flooding to verify the presence of kaolinite at the pore-scale using scanning electron microscopy (SEM). We also examined the pore network of the core plugs before and after the core-flooding experiments using Nuclear Magnetic Resonance (NMR). Moreover, to gain a better understanding of any kaolinite fines migration, we delineated surface force using two models based on Derjaguin-Landau-Verwey-Overbeek (denoted by DLVO) theory coupled hydrodynamic force: (1) sphere/flat model representing interaction between kaolinite/quartz, and (2) flat/flat model representing interaction between kaolinite/kaolinite. Our core-flooding experimental results showed that CO 2/brine injection triggered moderate to significant reduction in the permeability of the core samples with a negligible porosity change. NMR measurements supported the core-flooding results, suggesting that the relatively large pores disappeared in favour of a higher proportion of the medium to small pores after flooding. The DLVO calculations showed that some kaolinite particles probably lifted off and detached from neighbouring kaolinite particles rather than quartz grains. Moreover, the modelling results showed that the kaolinite fines migration would not occur under normal reservoir multiphase flow conditions. This is not because of the low hydrodynamic force. It is rather because the geometries of the particles dominate their interplay. Finally and overall, both of the experimental and analytical modelling results point to the fines migration to be the most likely cause of the permeability impairment observed during core-flooding experiments.« less

Reducing Risk in CO2 Sequestration: A Framework for Integrated Monitoring of Basin Scale Injection

NASA Astrophysics Data System (ADS)

Seto, C. J.; Haidari, A. S.; McRae, G. J.

2009-12-01

Geological sequestration of CO2 is an option for stabilization of atmospheric CO2 concentrations. Technical ability to safely store CO2 in the subsurface has been demonstrated through pilot projects and a long history of enhanced oil recovery and acid gas disposal operations. To address climate change, current injection operations must be scaled up by a factor of 100, raising issues of safety and security. Monitoring and verification is an essential component in ensuring safe operations and managing risk. Monitoring provides assurance that CO2 is securely stored in the subsurface, and the mechanisms governing transport and storage are well understood. It also provides an early warning mechanism for identification of anomalies in performance, and a means for intervention and remediation through the ability to locate the CO2. Through theoretical studies, bench scale experiments and pilot tests, a number of technologies have demonstrated their ability to monitor CO2 in the surface and subsurface. Because the focus of these studies has been to demonstrate feasibility, individual techniques have not been integrated to provide a more robust method for monitoring. Considering the large volumes required for injection, size of the potential footprint, length of time a project must be monitored and uncertainty, operational considerations of cost and risk must balance safety and security. Integration of multiple monitoring techniques will reduce uncertainty in monitoring injected CO2, thereby reducing risk. We present a framework for risk management of large scale injection through model based monitoring network design. This framework is applied to monitoring CO2 in a synthetic reservoir where there is uncertainty in the underlying permeability field controlling fluid migration. Deformation and seismic data are used to track plume migration. A modified Ensemble Kalman filter approach is used to estimate flow properties by jointly assimilating flow and geomechanical observations. Issues of risk, cost and uncertainty are considered.

Wellbore Completion Systems Containment Breach Solution Experiments at a Large Scale Underground Research Laboratory : Sealant placement & scale-up from Lab to Field

NASA Astrophysics Data System (ADS)

Goodman, H.

2017-12-01

This investigation seeks to develop sealant technology that can restore containment to completed wells that suffer CO2 gas leakages currently untreatable using conventional technologies. Experimentation is performed at the Mont Terri Underground Research Laboratory (MT-URL) located in NW Switzerland. The laboratory affords investigators an intermediate-scale test site that bridges the gap between the laboratory bench and full field-scale conditions. Project focus is the development of CO2 leakage remediation capability using sealant technology. The experimental concept includes design and installation of a field scale completion package designed to mimic well systems heating-cooling conditions that may result in the development of micro-annuli detachments between the casing-cement-formation boundaries (Figure 1). Of particular interest is to test novel sealants that can be injected in to relatively narrow micro-annuli flow-paths of less than 120 microns aperture. Per a special report on CO2 storage submitted to the IPCC[1], active injection wells, along with inactive wells that have been abandoned, are identified as one of the most probable sources of leakage pathways for CO2 escape to the surface. Origins of pressure leakage common to injection well and completions architecture often occur due to tensile cracking from temperature cycles, micro-annulus by casing contraction (differential casing to cement sheath movement) and cement sheath channel development. This discussion summarizes the experiment capability and sealant testing results. The experiment concludes with overcoring of the entire mock-completion test site to assess sealant performance in 2018. [1] IPCC Special Report on Carbon Dioxide Capture and Storage (September 2005), section 5.7.2 Processes and pathways for release of CO2 from geological storage sites, page 244

Multiphase, multicomponent simulations and experiments of reactive flow, relevant for combining geologic CO2 sequestration with geothermal energy capture

NASA Astrophysics Data System (ADS)

Saar, Martin O.

2011-11-01

Understanding the fluid dynamics of supercritical carbon dioxide (CO2) in brine- filled porous media is important for predictions of CO2 flow and brine displacement during geologic CO2 sequestration and during geothermal energy capture using sequestered CO2 as the subsurface heat extraction fluid. We investigate multiphase fluid flow in porous media employing particle image velocimetry experiments and lattice-Boltzmann fluid flow simulations at the pore scale. In particular, we are interested in the motion of a drop (representing a CO2 bubble) through an orifice in a plate, representing a simplified porous medium. In addition, we study single-phase/multicomponent reactive transport experimentally by injecting water with dissolved CO2 into rocks/sediments typically considered for CO2 sequestration to investigate how resultant fluid-mineral reactions modify permeability fields. Finally, we investigate numerically subsurface CO2 and heat transport at the geologic formation scale.

Muon borehole detector development for use in four-dimensional tomographic density monitoring

NASA Astrophysics Data System (ADS)

Flygare, Joshua

The increase of CO2 concentrations in the atmosphere and the correlated temperature rise has initiated research into methods of carbon sequestration. One promising possibility is to store CO2 in subsurface reservoirs of porous rock. After injection, the monitoring of the injected CO2 is of paramount importance because the CO2 plume, if escaped, poses health and environmental risks. Traditionally, seismic reflection methods are the chosen method of determining changes in the reservoir density due to CO2 injection, but this is expensive and not continuous. A potential and promising alternative is to use cosmic muon tomography to determine density changes in the reservoir over a period of time. The work I have completed was the development of a muon detector that will be capable of being deployed in boreholes and perform long-term tomography of the reservoir of interest. The detector has the required dimensions, an angular resolution of approximately 2 degrees, and is robust enough to survive the caustic nature of the fluids in boreholes, as well as temperature and pressure fluctuations. The detector design is based on polystyrene scintillating rods arrayed in alternating layers. The layers, as arranged, can provide four-dimensional (4D) tomographic data to detect small changes in density at depths up to approximately 2 kilometers. Geant4, a Monte Carlo simulation code, was used to develop and optimize the detector design. Additionally, I developed a method of determining the muon flux at depth, including CO2 saturation changes in subsurface reservoirs. Preliminary experiments were performed at Pacific Northwest National Laboratory. This thesis will show the simulations I performed to determine the angular resolution and background discrimination required of the detector, the experiments to determine light transport through the polystyrene scintillating rods and fibers, and the method developed to predict muon flux changes at depth expected after injection.

Using hyperspectral plant signatures for CO2 leak detection during the 2008 ZERT CO2 sequestration field experiment in Bozeman, Montana

DOE Office of Scientific and Technical Information (OSTI.GOV)

Male, E.J.; Pickles, W.L.; Silver, E.A.

2009-11-01

Hyperspectral plant signatures can be used as a short-term, as well as long-term (100-yr timescale) monitoring technique to verify that CO2 sequestration fields have not been compromised. An influx of CO2 gas into the soil can stress vegetation, which causes changes in the visible to nearinfrared reflectance spectral signature of the vegetation. For 29 days, beginning on July 9th, 2008, pure carbon dioxide gas was released through a 100-meter long horizontal injection well, at a flow rate of 300 kg/day. Spectral signatures were recorded almost daily from an unmown patch of plants over the injection with a ''FieldSpec Pro'' spectrometermore » by Analytical Spectral Devices, Inc. Measurements were taken both inside and outside of the CO2 leak zone to normalize observations for other environmental factors affecting the plants.« less

Role of Geomechanics in Assessing the Feasibility of CO2 Sequestration in Depleted Hydrocarbon Sandstone Reservoirs

NASA Astrophysics Data System (ADS)

Fang, Zhi; Khaksar, Abbas

2013-05-01

Carbon dioxide (CO2) sequestration in depleted sandstone hydrocarbon reservoirs could be complicated by a number of geomechanical problems associated with well drilling, completions, and CO2 injection. The initial production of hydrocarbons (gas or oil) and the resulting pressure depletion as well as associated reduction in horizontal stresses (e.g., fracture gradient) narrow the operational drilling mud weight window, which could exacerbate wellbore instabilities while infill drilling. Well completions (casing, liners, etc.) may experience solids flowback to the injector wells when injection is interrupted due to CO2 supply or during required system maintenance. CO2 injection alters the pressure and temperature in the near wellbore region, which could cause fault reactivation or thermal fracturing. In addition, the injection pressure may exceed the maximum sustainable storage pressure, and cause fracturing and fault reactivation within the reservoirs or bounding formations. A systematic approach has been developed for geomechanical assessments for CO2 storage in depleted reservoirs. The approach requires a robust field geomechanical model with its components derived from drilling and production data as well as from wireline logs of historical wells. This approach is described in detail in this paper together with a recent study on a depleted gas field in the North Sea considered for CO2 sequestration. The particular case study shows that there is a limitation on maximum allowable well inclinations, 45° if aligning with the maximum horizontal stress direction and 65° if aligning with the minimum horizontal stress direction, beyond which wellbore failure would become critical while drilling. Evaluation of sanding risks indicates no sand control installations would be needed for injector wells. Fracturing and faulting assessments confirm that the fracturing pressure of caprock is significantly higher than the planned CO2 injection and storage pressures for an ideal case, in which the total field horizontal stresses increase with the reservoir re-pressurization in a manner opposite to their reduction with the reservoir depletion. However, as the most pessimistic case of assuming the total horizontal stresses staying the same over the CO2 injection, faulting could be reactivated on a fault with the least favorable geometry once the reservoir pressure reaches approximately 7.7 MPa. In addition, the initial CO2 injection could lead to a high risk that a fault with a cohesion of less than 5.1 MPa could be activated due to the significant effect of reduced temperature on the field stresses around the injection site.

Effects of Impurities in CO2 Spreading Model Development for Field Experiments in the Framework of the CO2QUEST Project

NASA Astrophysics Data System (ADS)

Rebscher, D.; Wolf, J. L.; Jung, B.; Bensabat, J.; Segev, R.; Niemi, A. P.

2014-12-01

The aim of the CO2QUEST project (Impact of the Quality of CO2 on Storage and Transport) is to investigate the effect of typical impurities in the CO2 stream captured from fossil fuel power plants on its safe and economic transportation and deep geologic storage. An important part of this EU funded project is to enhance the understanding of typical impurity effects in a CO2 stream regarding the performance of the storage. Based on the experimental site Heletz in Israel, where injection tests of water as well as of super-critical pure and impure CO2 will be conducted, numerical simulations are performed. These studies illustrate flow and transport of CO2 and brine as well as impurities induced chemical reactions in relation to changes in the reservoir, e.g. porosity, permeability, pH-value, and mineral composition. Using different THC codes (TOUGH2-ECO2N, TOUGHREACT, PFLOTRAN), the spatial distribution of CO2 and impurities, both in the supercritical and aqueous phases, are calculated. The equation of state (EOS) of above numerical codes are properly modified to deal with binary/tertiary gas mixtures (e.g. CO2-N2 or CO2-SO2). In addition, simulations for a push-pull test of about 10 days duration are performed, which will be validated against experimental field data. Preliminary results are as follows: (a) As expected, the injection of SO2 leads to a strong decrease in pH-value, hence, the total dissolution of carbonate minerals could be observed. (b) Due to the acidic attack on clay minerals , which is enhanced compared to a pure CO2 dissolution, a higher amount of metal ions are released, in particular Fe2+ and Mg2+ by a factor of 25 and 10, respectively. Whereas secondary precipitation occurs only for sulphur minerals, namely anhydrite and pyrite. (c) The co-injection of CO2 with N2 changes physical properties of the gas mixture. Increasing N2 contents induces density decrease of the gas mixture, resulting in faster and wider plume migration compared to the pure CO2 injection case.

Hydrogeochemical alteration of groundwater due to a CO2 injection test into a shallow aquifer in Northeast Germany

NASA Astrophysics Data System (ADS)

Dethlefsen, Frank; Peter, Anita; Hornbruch, Götz; Lamert, Hendrik; Garbe-Schönberg, Dieter; Beyer, Matthias; Dietrich, Peter; Dahmke, Andreas

2014-05-01

The accidental release of CO2 into potable aquifers, for instance as a consequence of a leakage out of a CO2 store site, can endanger drinking water resources due to the induced geochemical processes. A 10-day CO2 injection experiment into a shallow aquifer was carried out in Wittstock (Northeast Germany) in order to investigate the geochemical impact of a CO2 influx into such an aquifer and to test different monitoring methods. Information regarding the site investigation, the injection procedure monitoring setup, and first geochemical monitoring results are described in [1]. Apart from the utilization of the test results to evaluate monitoring approaches [2], further findings are presented on the evaluation of the geophysical monitoring [3], and the monitoring of stable carbon isotopes [4]. This part of the study focuses of the hydrogeochemical alteration of groundwater due to the CO2 injection test. As a consequence of the CO2 injection, major cations were released, i.e. concentrations increased, whereas major anion concentrations - beside bicarbonate - decreased, probably due to increased anion sorption capacity at variably charged exchange sites of minerals. Trace element concentrations increased as well significantly, whereas the relative concentration increase was far larger than the relative concentration increase of major cations. Furthermore, geochemical reactions show significant spatial heterogeneity, i.e. some elements such as Cr, Cu, Pb either increased in concentration or remained at stable concentrations with increasing TIC at different wells. Statistical analyses of regression coefficients confirm the different spatial reaction patterns at different wells. Concentration time series at single wells give evidence, that the trace element release is pH dependent, i.e. trace elements such as Zn, Ni, Co are released at pH of around 6.2-6.6, whereas other trace elements like As, Cd, Cu are released at pH of 5.6-6.4. [1] Peter, A., et al., Investigation of the geochemical impact of CO2; on shallow groundwater: design and implementation of a CO2; injection test in Northeast Germany. Environmental Earth Sciences, 2012. 67(2): p. 335-349. [2] Dethlefsen, F., et al., Monitoring approaches for detecting and evaluating CO2 and formation water leakages into near-surface aquifers. Energy Procedia, 2013. 37(0): p. 4886-4893. [3] Lamert, H., et al., Feasibility of geoelectrical monitoring and multiphase modeling for process understanding of gaseous CO2; injection into a shallow aquifer. Environmental Earth Sciences, 2012. 67(2): p. 447-462. [4] Schulz, A., et al., Monitoring of a simulated CO2 leakage in a shallow aquifer using stable carbon isotopes. Environmental Science & Technology, 2012. 46(20): p. 11243-11250.

The relative roles of external and internal CO(2) versus H(+) in eliciting the cardiorespiratory responses of Salmo salar and Squalus acanthias to hypercarbia.

PubMed

Perry, S F; McKendry, J E

2001-11-01

Fish breathing hypercarbic water encounter externally elevated P(CO(2)) and proton levels ([H(+)]) and experience an associated internal respiratory acidosis, an elevation of blood P(CO(2)) and [H(+)]. The objective of the present study was to assess the potential relative contributions of CO(2) versus H(+) in promoting the cardiorespiratory responses of dogfish (Squalus acanthias) and Atlantic salmon (Salmo salar) to hypercarbia and to evaluate the relative contributions of externally versus internally oriented receptors in dogfish. In dogfish, the preferential stimulation of externally oriented branchial chemoreceptors using bolus injections (50 ml kg(-1)) of CO(2)-enriched (4 % CO(2)) sea water into the buccal cavity caused marked cardiorespiratory responses including bradycardia (-4.1+/-0.9 min(-1)), a reduction in cardiac output (-3.2+/-0.6 ml min(-1) kg(-1)), an increase in systemic vascular resistance (+0.3+/-0.2 mmHg ml min(-1) kg(-1)), arterial hypotension (-1.6+/-0.2 mmHg) and an increase in breathing amplitude (+0.3+/-0.09 mmHg) (means +/- S.E.M., N=9-11). Similar injections of CO(2)-free sea water acidified to the corresponding pH of the hypercarbic water (pH 6.3) did not significantly affect any of the measured cardiorespiratory variables (when compared with control injections). To preferentially stimulate putative internal CO(2)/H(+) chemoreceptors, hypercarbic saline (4 % CO(2)) was injected (2 ml kg(-1)) into the caudal vein. Apart from an increase in arterial blood pressure caused by volume loading, internally injected CO(2) was without effect on any measured variable. In salmon, injection of hypercarbic water into the buccal cavity caused a bradycardia (-13.9+/-3.8 min(-1)), a decrease in cardiac output (-5.3+/-1.2 ml min(-1) kg(-1)), an increase in systemic resistance (0.33+/-0.08 mmHg ml min(-1) kg(-1)) and increases in breathing frequency (9.7+/-2.2 min(-1)) and amplitude (1.2+/-0.2 mmHg) (means +/- S.E.M., N=8-12). Apart from a small increase in breathing amplitude (0.4+/-0.1 mmHg), these cardiorespiratory responses were not observed after injection of acidified water. These results demonstrate that, in dogfish and salmon, the external chemoreceptors linked to the initiation of cardiorespiratory responses during hypercarbia are predominantly stimulated by the increase in water P(CO(2)) rather than by the accompanying decrease in water pH. Furthermore, in dogfish, the cardiorespiratory responses to hypercarbia are probably exclusively derived from the stimulation of external CO(2) chemoreceptors, with no apparent contribution from internally oriented receptors.

Method of controlling injection of oxygen into hydrogen-rich fuel cell feed stream

DOEpatents

Meltser, Mark Alexander; Gutowski, Stanley; Weisbrod, Kirk

2001-01-01

A method of operating a H.sub.2 --O.sub.2 fuel cell fueled by hydrogen-rich fuel stream containing CO. The CO content is reduced to acceptable levels by injecting oxygen into the fuel gas stream. The amount of oxygen injected is controlled in relation to the CO content of the fuel gas, by a control strategy that involves (a) determining the CO content of the fuel stream at a first injection rate, (b) increasing the O.sub.2 injection rate, (c) determining the CO content of the stream at the higher injection rate, (d) further increasing the O.sub.2 injection rate if the second measured CO content is lower than the first measured CO content or reducing the O.sub.2 injection rate if the second measured CO content is greater than the first measured CO content, and (e) repeating steps a-d as needed to optimize CO consumption and minimize H.sub.2 consumption.

EGS rock reactions with Supercritical CO2 saturated with water and water saturated with Supercritical CO2

DOE Office of Scientific and Technical Information (OSTI.GOV)

Earl D. Mattson; Travis L. McLing; William Smith

2013-02-01

EGS using CO2 as a working fluid will likely involve hydro-shearing low-permeability hot rock reservoirs with a water solution. After that process, the fractures will be flushed with CO2 that is maintained under supercritical conditions (> 70 bars). Much of the injected water in the main fracture will be flushed out with the initial CO2 injection; however side fractures, micro fractures, and the lower portion of the fracture will contain connate water that will interact with the rock and the injected CO2. Dissolution/precipitation reactions in the resulting scCO2/brine/rock systems have the potential to significantly alter reservoir permeability, so it ismore » important to understand where these precipitates form and how are they related to the evolving ‘free’ connate water in the system. To examine dissolution / precipitation behavior in such systems over time, we have conducted non-stirred batch experiments in the laboratory with pure minerals, sandstone, and basalt coupons with brine solution spiked with MnCl2 and scCO2. The coupons are exposed to liquid water saturated with scCO2 and extend above the water surface allowing the upper portion of the coupons to be exposed to scCO2 saturated with water. The coupons were subsequently analyzed using SEM to determine the location of reactions in both in and out of the liquid water. Results of these will be summarized with regard to significance for EGS with CO2 as a working fluid.« less

Micro-Ct Imaging of Multi-Phase Flow in Carbonates and Sandstones

NASA Astrophysics Data System (ADS)

Andrew, M. G.; Bijeljic, B.; Blunt, M. J.

2013-12-01

One of the most important mechanisms that limits the escape of CO2 when injected into the subsurface for the purposes of carbon storage is capillary trapping, where CO2 is stranded as pore-scale droplets (ganglia). Prospective storage sites are aquifers or reservoirs that tend to be at conditions where CO2 will reside as a super-critical phase. In order to fully describe physical mechanisms characterising multi-phase flow during and post CO2 injection, experiments need to be conducted at these elevated aquifer/reservoir conditions - this poses a considerable experimental challenge. A novel experimental apparatus has been developed which uses μCT scanning for the non-invasive imaging of the distribution of CO2 in the pore space of rock with resolutions of 7μm at temperatures and pressures representative of the conditions present in prospective saline aquifer CO2 storage sites. The fluids are kept in chemical equilibrium with one-another and with the rock into which they are injected. This is done to prevent the dissolution of the CO2 in the brine to form carbonic acid, which can then react with the rock, particularly carbonates. By eliminating reaction we study the fundamental mechanisms of capillary trapping for an unchanging pore structure. In this study we present a suite of results from three carbonate and two sandstone rock types, showing that, for both cases the CO2 acts as the non-wetting phase and significant quantities of CO2 is trapped. The carbonate examined represent a wide variety of pore topologies with one rock with a very well connected, high porosity pore space (Mt Gambier), one with a lower porosity, poorly connected pore space (Estaillades) and one with a cemented bead pack type pore space (Ketton). Both sandstones (Doddington and Bentheimer) were high permeability granular quartzites. CO2 was injected into each rock, followed by brine injection. After brine injection the entire length of the rock core was scanned, processed and segmented into grain, brine and CO2. Experiments were repeated five times for each rock type, allowing for statistical errors to be estimated. The images from each experiment were approximately 900x900x3200 voxels, representing a sample size of approximately 6.4mm x 6.4mm x 22.4mm. Higher residual saturations were found in the sandstones (Bentheimer: 0.299×0.009, Doddington: 0.27×0.03) than in the carbonates (Mt Gambier: 0.187×0.007, Estaillades: 0.190×0.005, Ketton: 0.193×0.012). The size frequency distribution of ganglia was also examined. The largest ganglia contributed negligibly to the total residual saturation in all cases apart from Mt Gambier, where the increased connectivity of the pore-space inhibits non-wetting phase snap-off. The snap-off of ganglia is understood theoretically as a percolation process, and ganglia size distributions show approximately power-law distributions with exponents agreeing with predictions from percolation theory apart from in Mt Gambier limestone, where the extreme connectivity of the pore space may cause snap-off to be a non-percolation like process. We also present the first dynamic real time multiphase fluid displacements at reservoir conditions. These images were taken using the same reservoir-condition flow rig at Diamond Light Source synchrotron. This advanced facility allows for scanning intervals of 30 seconds, enabling the imaging of discrete pore-filling events (Haines jumps).

Coupled Reactive Transport Modeling of CO2 Injection in Mt. Simon Sandstone Formation, Midwest USA

NASA Astrophysics Data System (ADS)

Liu, F.; Lu, P.; Zhu, C.; Xiao, Y.

2009-12-01

CO2 sequestration in deep geological formations is one of the promising options for CO2 emission reduction. While several large scale CO2 injections in saline aquifers have shown to be successful for the short-term, there is still a lack of fundamental understanding on key issues such as CO2 storage capacity, injectivity, and security over multiple spatial and temporal scales that need to be addressed. To advance these understandings, we applied multi-phase coupled reactive mass transport modeling to investigate the fate of injected CO2 and reservoir responses to the injection into Mt. Simon Formation. We developed both 1-D and 2-D reactive transport models in a radial region of 10,000 m surrounding a CO2 injection well to represent the Mt. Simon sandstone formation, which is a major regional deep saline reservoir in the Midwest, USA. Supercritical CO2 is injected into the formation for 100 years, and the modeling continues till 10,000 years to monitor both short-term and long-term behavior of injected CO2 and the associated rock-fluid interactions. CO2 co-injection with H2S and SO2 is also simulated to represent the flue gases from coal gasification and combustion in the Illinois Basin. The injection of CO2 results in acidified zones (pH ~3 and 5) adjacent to the wellbore, causing progressive water-rock interactions in the surrounding region. In accordance with the extensive dissolution of authigenic K-feldspar, sequential precipitations of secondary carbonates and clay minerals are predicted in this zone. The vertical profiles of CO2 show fingering pattern from the top of the reservoir to the bottom due to the density variation of CO2-impregnated brine, which facilitate convection induced mixing and solubility trapping. Most of the injected CO2 remains within a radial distance of 2500 m at the end of 10,000 years and is sequestered and immobilized by solubility and residual trapping. Mineral trapping via secondary carbonates, including calcite, magnesite, ankerite and dawsonite, is predicted, but only constituting a minor component as compared to other trapping mechanisms. The mineral alteration induced by CO2 injection results in changes in porosity/permeability due to these complex mineral dissolution and precipitation reactions. Increases in porosity (from 15% to 16.2%) occur in the low-pH zones due to the acidic dissolution of minerals. However, within the carbonate mineral trapping zone, porosity reduction occurs. Co-injection of H2S causes relatively limited modification from the CO2 alone case while significantly higher water-rock reactivity is associated with the SO2 co-injection. Although co-injection of CO2 with H2S and SO2 could potentially reduce separation and injection cost, it may lead to some uncertainty and risks and therefore require further investigation.

The Effect of Hydrous Supercritical Carbon Dioxide on the Mohr Coulomb Failure Envelope in Boise Sandstone

NASA Astrophysics Data System (ADS)

Choens, R. C., II; Dewers, T. A.; Ilgen, A.; Espinoza, N.; Aman, M.

2016-12-01

Experimental rock deformation was used to quantify the relationship between supercritical carbon dioxide (scCO2), water vapor, and failure strength in an analog for Tertiary sandstone saline formation reservoirs. Storing large volumes of carbon dioxide in depleted petroleum reservoirs and deep saline aquifers over geologic time is an important tool in mitigating effects of climate change. Carbon dioxide is injected as a supercritical phase, where it forms a buoyant plume. At brine-plume interfaces, scCO2 dissolves over time into the brine, lowering pH and perturbing the local chemical environment. Previous work has shown that the resulting geochemical changes at mineral-fluid interfaces can alter rock mechanical properties, generally causing a decrease in strength. Additionally, water from the native brine can dissolve into the scCO2 plume where it is present as humidity. This study investigates the effect of hydrous scCO2 and CO2-saturated brine on shear failure of Boise sandstone. Samples are held in a hydrostatic pressure vessel at 2250 PSI confining pressure (PC) and 70 C, and scCO2 at specific humidity is circulated through the core for 24 hours at 2000 PSI and 70 C. Experiments are conducted at relative humidity levels of 0, 14, 28, 42, 56, 70, 84, 98, and 100% relative humidity. After the scCO2 core flood is finished, triaxial compression experiments are conducted on the samples at room temperature and an axial strain rate of 10-5 sec-1. Experiments are conducted at 500, 1000, and 1500 PSI PC. The results demonstrate that water present as humidity in scCO2 can reduce failure strength and lower slopes of the Mohr-Coulomb failure envelope. These effects increase with increasing humidity, as dry scCO2 does not affect rock strength, and may be influenced by capillary condensation of water films from humid scCO2. The reductions in failure strength seen in this study could be important in predicting reservoir response to injection, reservoir caprock integrity, and borehole stability of injection wells. Sandia National Laboratories is a multi-program laboratory managed and operated by Sandia Corporation, a wholly owned subsidiary of Lockheed Martin Corporation, for the U.S. Department of Energy's National Security Administration under contract DE-AC04-94AL85000. SAND2016-7552A

Involvement of histaminergic and noradrenergic receptors in the oxytocin-induced food intake in neonatal meat-type chicks.

PubMed

Mirnaghizadeh, Seyed Vahid; Zendehdel, Morteza; Babapour, Vahab

2017-03-01

Oxytocin neurons have a physiological role in food intake and energy balance. Several studies have shown that central histaminergic and adrenergic systems synapse on oxytocin neurons but there is no information for their interaction on food intake regulation in birds. The purpose of this study was to examine the effects of intracerebroventricular (ICV) injection of α-fluoromethylhistidine (α-FMH, histidine decarboxylase inhibitor), chlorpheniramine (histamine H1 receptors antagonist), famotidine (histamine H2 receptors antagonist), thioperamide (histamine H3 receptors antagonist), prazosin (α1 receptor antagonist), yohimbine (α2 receptor antagonist), metoprolol (β1 adrenergic receptor antagonist), ICI 118,551 (β2 adrenergic receptor antagonist) and SR59230R (β3 adrenergic receptor antagonist) on oxytocin-induced hypophagia in 3-h food-deprived (FD 3 ) neonatal broiler chicken. In Experiment 1, 3 h-fasted chicks were given an ICV injection of saline, α-FMH (250 nmol), oxytocin (10 μg) and co-injection of α-FMH + oxytocin. Experiments 2-9 were similar to experiment 1 except birds were injected with chlorpheniramine (300 nmol), famotidine (82 nmol), thioperamide (300 nmol), prazosin (10 nmol), yohimbine (13 nmol), metoprolol (24 nmol), ICI 118,551(5 nmol) and SR59230R (20 nmol) instead of α-FMH, respectively. After injection cumulative food intake was measured until 120 min post injection. According to the results, ICV injection of oxytocin significantly decreased food intake in broiler chickens (P < 0.001). ICV injection of α-FMH significantly attenuated hypophagic effect of oxytocin (P < 0.001). Also, co-injection of chlorpheniramine plus oxytocin significantly decreased the effect of oxytocin on food intake (P < 0.001). Co-administration of thioperamide and oxytocin significantly amplified hypophagic effect of oxytocin in chickens (P < 0.001). In addition, ICI 118,551 attenuated hypophagic effect of oxytocin (P < 0.001); while famotidine, prazosin, yohimbine, metoprolol and SR59230R had no effect on oxytocin- induced food intake in FD3 broiler chickens. These results suggest that the effect of oxytocin on food intake is probably mediated by histaminergic (via H1 and H3 receptors) and noradrenergic (via β2 receptors) systems in broiler chickens.

Determining Carbon and Oxygen Stable Isotope Systematics in Brines at Elevated p/T Conditions to Enhance Monitoring of CO2 Induced Processes in Carbon Storage Reservoirs

NASA Astrophysics Data System (ADS)

Becker, V.; Myrttinen, A.; Mayer, B.; Barth, J. A.

2012-12-01

Stable carbon isotope ratios (δ13C) are a powerful tool for inferring carbon sources and mixing ratios of injected and baseline CO2 in storage reservoirs. Furthermore, CO2 releasing and consuming processes can be deduced if the isotopic compositions of end-members are known. At low CO2 pressures (pCO2), oxygen isotope ratios (δ18O) of CO2 usually assume the δ18O of the water plus a temperature-dependent isotope fractionation factor. However, at very high CO2 pressures as they occur in CO2 storage reservoirs, the δ18O of the injected CO2 may in fact change the δ18O of the reservoir brine. Hence, changing δ18O of brine constitutes an additional tracer for reservoir-internal carbon dynamics and allows the determination of the amount of free phase CO2 present in the reservoir (Johnson et al. 2011). Further systematic research to quantify carbon and oxygen isotope fractionation between the involved inorganic carbon species (CO2, H2CO3, HCO3-, CO32-, carbonate minerals) and kinetic and equilibrium isotope effects during gas-water-rock interactions is necessary because p/T conditions and salinities in CO2 storage reservoirs may exceed the boundary conditions of typical environmental isotope applications, thereby limiting the accuracy of stable isotope monitoring approaches in deep saline formations (Becker et al. 2011). In doing so, it is crucial to compare isotopic patterns observed in laboratory experiments with artificial brines to similar experiments with original fluids from representative field sites to account for reactions of dissolved inorganic carbon (DIC) with minor brine components. In the CO2ISO-LABEL project, funded by the German Ministry for Education and Research, multiple series of laboratory experiments are conducted to determine the influence of pressure, temperature and brine composition on the δ13C of DIC and the δ18O of brines in water-CO2-rock reactions with special focus placed on kinetics and stable oxygen and carbon isotope fractionation factors. Laboratory experiments with original reservoir fluids from CO2 storage reservoirs in Canada using supercritical fluid extraction reactors are being conducted at temperatures of up to 200 °C and CO2 pressures of up to 20 MPa. Preliminary results show that equilibration times for δ18O in high saline waters increase by an order of magnitude compared to fresh water, with exact times depending on CO2 partial pressure, stirring and the contact area between the phases. References Becker, V. et al., 2011. Predicting δ13CDIC dynamics in CCS: A scheme based on a review of inorganic carbon chemistry under elevated pressures and temperatures. International Journal of Greenhouse Gas Control, 5, pp.1250-1258. Johnson, G. et al., 2011. Using oxygen isotope ratios to quantitatively assess trapping mechanisms during CO2 injection into geological reservoirs: The Pembina case study. Chemical Geology, 283(3-4), pp.185-193.

New stable isotope results for reservoir and above zone monitoring in CCS from the Ketzin pilot site, Germany

NASA Astrophysics Data System (ADS)

Nowak, Martin; van Geldern, Robert; Myrttinen, Anssi; Veith, Becker; Zimmer, Martin; Barth, Johannes

2013-04-01

With rising atmospheric greenhouse gas concentrations, CCS technologies are a feasible option to diminish consequences of uncontrolled anthropogenic CO2 emissions and related climate change. However, application of CCS technologies requires appropriate and routine monitoring tools in order to ensure a safe and effective CO2 injection. Stable isotope techniques have proven as a useful geochemical monitoring tool at several CCS pilot projects worldwide. They can provide important information about gas - water - rock interactions, mass balances and CO2 migration in the reservoir and may serve as a tool to detect CO2 leakage in the subsurface and surface. Since the beginning of injection in 2008 at the Ketzin pilot site in Germany, more than 450 samples of fluids and gases have been analysed for their carbon and oxygen isotopic composition. Analytical advancements were achieved by modifying a conventional isotope ratio mass-spectrometer with a He dilution system. This allowed analyses of a larger number of CO2 gas samples from the injection well and observation wells. With this, a high-resolution monitoring program was established over a time period of one year. Results revealed that two isotopical distinct kinds of CO2 are injected at the Ketzin pilot site. The most commonly injected CO2 is so-called 'technical' CO2 with an average carbon isotopic value of about -31 ‰. Sporadically, natural source CO2 with an average δ13C value of -3 ‰ was injected. The injection of natural source CO2 generated a distinct isotope signal at the injection well that can be used as an ideal tracer. CO2 isotope values analysed at the observation wells indicate a highly dispersive migration of the supercritical CO2 that results in mixing of the two kinds of CO2 within the reservoir. Above-reservoir monitoring includes the first overlying aquifer above the cap rock. An observation well within this zone comprises an U-tube sampling device that allows frequent sampling of unaltered brine. The fluids were analysed among others for their carbon isotopic compositions of dissolved inorganic carbon (DIC). δ13CDIC values allowed to assess impacts of the carbonate-based drilling fluid during well development and helped to monitor successive geochemical re-equilibration processes of the brine. Based on the determined δ13C baseline values of the aquifer fluid, first concepts indicate the scale of change of the δ13CDIC values that would be necessary to detect CO2 leakage from the underlying storage reservoir. Recent efforts aim at applications of new laser-based isotope sensors that allow online measurements in the field. These devices are applied for CO2 gas tracer experiments as well as for monitoring of isotope composition of soil gases in the vicinity of the pilot site. This new development will allow much better temporal and spatial resolution of measurements at a lower price. Therefore, stable isotope analyses can become a strong and promising tool for subsurface as well as surface monitoring at future CCS sites.

Simulating the Cranfield geological carbon sequestration project with high-resolution static models and an accurate equation of state

DOE PAGES

Soltanian, Mohamad Reza; Amooie, Mohammad Amin; Cole, David R.; ...

2016-10-11

In this study, a field-scale carbon dioxide (CO 2) injection pilot project was conducted as part of the Southeast Regional Sequestration Partnership (SECARB) at Cranfield, Mississippi. We present higher-order finite element simulations of the compositional two-phase CO 2-brine flow and transport during the experiment. High- resolution static models of the formation geology in the Detailed Area Study (DAS) located below the oil- water contact (brine saturated) are used to capture the impact of connected flow paths on breakthrough times in two observation wells. Phase behavior is described by the cubic-plus-association (CPA) equation of state, which takes into account the polarmore » nature of water molecules. Parameter studies are performed to investigate the importance of Fickian diffusion, permeability heterogeneity, relative permeabilities, and capillarity. Simulation results for the pressure response in the injection well and the CO 2 breakthrough times at the observation wells show good agreement with the field data. For the high injection rates and short duration of the experiment, diffusion is relatively unimportant (high P clet numbers), while relative permeabilities have a profound impact on the pressure response. High-permeability pathways, created by fluvial deposits, strongly affect the CO 2 transport and highlight the importance of properly characterizing the formation heterogeneity in future carbon sequestration projects.« less

Ultrasonic laboratory measurements of the seismic velocity changes due to CO2 injection

NASA Astrophysics Data System (ADS)

Park, K. G.; Choi, H.; Park, Y. C.; Hwang, S.

2009-04-01

Monitoring the behavior and movement of carbon dioxide (CO2) in the subsurface is a quite important in sequestration of CO2 in geological formation because such information provides a basis for demonstrating the safety of CO2 sequestration. Recent several applications in many commercial and pilot scale projects and researches show that 4D surface or borehole seismic methods are among the most promising techniques for this purpose. However, such information interpreted from the seismic velocity changes can be quite subjective and qualitative without petrophysical characterization for the effect of CO2 saturation on the seismic changes since seismic wave velocity depends on various factors and parameters like mineralogical composition, hydrogeological factors, in-situ conditions. In this respect, we have developed an ultrasonic laboratory measurement system and have carried out measurements for a porous sandstone sample to characterize the effects of CO2 injection to seismic velocity and amplitude. Measurements are done by ultrasonic piezoelectric transducer mounted on both ends of cylindrical core sample under various pressure, temperature, and saturation conditions. According to our fundamental experiments, injected CO2 introduces the decrease of seismic velocity and amplitude. We identified that the velocity decreases about 6% or more until fully saturated by CO2, but the attenuation of seismic amplitude is more drastically than the velocity decrease. We also identified that Vs/Vp or elastic modulus is more sensitive to CO2 saturation. We note that this means seismic amplitude and elastic modulus change can be an alternative target anomaly of seismic techniques in CO2 sequestration monitoring. Thus, we expect that we can estimate more quantitative petrophysical relationships between the changes of seismic attributes and CO2 concentration, which can provide basic relation for the quantitative assessment of CO2 sequestration by further researches.

Integrated CO 2 Storage and Brine Extraction

DOE Office of Scientific and Technical Information (OSTI.GOV)

Hunter, Kelsey; Bielicki, Jeffrey M.; Middleton, Richard

Carbon dioxide (CO 2) capture, utilization, and storage (CCUS) can reduce CO 2 emissions from fossil fuel power plants by injecting CO 2 into deep saline aquifers for storage. CCUS typically increases reservoir pressure which increases costs, because less CO 2 can be injected, and risks such as induced seismicity. Extracting brine with enhanced water recovery (EWR) from the CO 2 storage reservoir can manage and reduce pressure in the formation, decrease the risks linked to reservoir overpressure (e.g., induced seismicity), increase CO 2 storage capacity, and enable CO 2 plume management. We modeled scenarios of CO 2 injection withmore » EWR into the Rock Springs Uplift (RSU) formation in southwest Wyoming. The Finite Element Heat and Mass Transfer Code (FEHM) was used to model CO 2 injection with brine extraction and the corresponding increase in pressure within the RSU. We analyzed the model for pressure management, CO 2 storage, CO 2 saturation, and brine extraction due to the quantity and location of brine extraction wells. The model limited CO 2 injection to a constant pressure increase of two MPa at the injection well with and without extracting brine at hydrostatic pressure. Finally, we found that brine extraction can be used as a technical and cost-effective pressure management strategy to limit reservoir pressure buildup and increase CO 2 storage associated with a single injection well.« less

Integrated CO 2 Storage and Brine Extraction

DOE PAGES

Hunter, Kelsey; Bielicki, Jeffrey M.; Middleton, Richard; ...

2017-08-18

Carbon dioxide (CO 2) capture, utilization, and storage (CCUS) can reduce CO 2 emissions from fossil fuel power plants by injecting CO 2 into deep saline aquifers for storage. CCUS typically increases reservoir pressure which increases costs, because less CO 2 can be injected, and risks such as induced seismicity. Extracting brine with enhanced water recovery (EWR) from the CO 2 storage reservoir can manage and reduce pressure in the formation, decrease the risks linked to reservoir overpressure (e.g., induced seismicity), increase CO 2 storage capacity, and enable CO 2 plume management. We modeled scenarios of CO 2 injection withmore » EWR into the Rock Springs Uplift (RSU) formation in southwest Wyoming. The Finite Element Heat and Mass Transfer Code (FEHM) was used to model CO 2 injection with brine extraction and the corresponding increase in pressure within the RSU. We analyzed the model for pressure management, CO 2 storage, CO 2 saturation, and brine extraction due to the quantity and location of brine extraction wells. The model limited CO 2 injection to a constant pressure increase of two MPa at the injection well with and without extracting brine at hydrostatic pressure. Finally, we found that brine extraction can be used as a technical and cost-effective pressure management strategy to limit reservoir pressure buildup and increase CO 2 storage associated with a single injection well.« less

An Experimental Study of Effects in Soils by Potential CO2 Seepage

NASA Astrophysics Data System (ADS)

Wei, Y.; Caramanna, G.; Nathanail, P.; Steven, M.; Maroto-Valer, M.

2011-12-01

Potential CO2 seepage during a CCS project will not only reduce its performing efficiency, but can also impact the local environment. Though scientists announce with confidence that CCS is a safe technology to store CO2 deep underground, it is essential to study the effects of CO2 seepage, to avoid any possible influences on soils. As a simplified environment, laboratory experiments can easily be controlled and vital to be studied to be compared with more complex natural analogues and modelling works. Recent research focuses on the effects on ecosystems of CO2 leakage. However, the impacts of long-term, low level exposure for both surface and subsurface ecosystems, as well as soil geochemistry changes are currently not clear. Moreover, previous work has focussed on pure CO2 leakage only and its impacts on the ecosystem. However, in a more realistic scenario the gas coming from a capture process may contain impurities, such as SO2, which are more dangerous than pure CO2 and could cause more severe consequences. Therefore, it is critical to assess the potential additional risks caused by CO2 leakage with impurities. Accordingly, both a batch and a continuous flow reactor were designed and used to study potential impacts caused by the CO2 seepage, focusing on soil geochemistry changes, due to different concentrations of CO2/SO2 mixtures. Stage 1- Batch experiments. In this stage, a soil sample was collected from the field and exposed to a controlled CO2/SO2 gas mixtures (100% CO2 and CO2:SO2=99:1). The water soluble fractions were measured before and after incubation. With 100% CO2 incubation it was found that: 1) the pH in the soil sample did not change significantly; 2) for soils with different moisture levels, greater moisture in the soil results in higher CO2 uptake during incubation; and 3) for sandy soils, small changes in CaCl2-exchangeable metal concentration, were observed after CO2 incubation. However, the increased concentration of toxic elements is still below plant tolerance limits. With a gas mixture of 99% CO2 and 1% SO2, it was found that: 1) pH changed significantly from 5.54 to ~3.00; 2) consistent but minor changes were found in some of the nutrients; and 3) high concentrations of the toxic element, Al, were found, at approximately ~200 mg/l compared to an initial value of <0.1 mg/l. Stage 2- A continuous flow reactor. At this stage, a continuous vertical flow reactor was designed and used to assess the impact in soil caused by different mixtures of CO2/SO2. With limestone sand and 100% CO2, it was found that: 1) pH dropped quickly at the first hour and stabilised around 6.10 until CO2 injecting was stopped; 2) limestone had strong buffering capacity but only after stopping CO2 injection; 3) a change was found for soil permeability and porosity during the gas injecting process; 4) with saturated soil, a dome was always formed at the top of the soil column at the end of each experiment. More experiments are planned in the near future.

Steam and air co-injection in removing residual TCE in unsaturated layered sandy porous media.

PubMed

Peng, Sheng; Wang, Ning; Chen, Jiajun

2013-10-01

Steam and air co-injection is a promising technique for volatile and semi-volatile organic contaminant remediation in heterogeneous porous media. In this study, removal of trichloroethene (TCE) with steam-air co-injection was investigated through a series of 2D sandbox experiments with different layered sand structures, and through numerical simulations. The results show that a layered structure with coarse sand, in which steam and air convection are relatively rapid, resulted in a higher removal rate and a larger removal ratio than those observed in an experiment using finer sand; however, the difference was not significant, and the removal ratios from three experiments ranged from 85% to 94%. Slight downward movement of TCE was observed for Experiment 1 (TCE initially in a fine sand zone encased in a coarse sand), while no such movement was observed for Experiment 2 (TCE initially in two fine sand layers encased in a coarse sand) or 3 (TCE initially in a silty sand zone encased in a coarse sand). Simulations show accumulation of TCE at the interface of the layered sands, which indicates a capillary barrier effect in restraining the downward movement of TCE. This effect is illustrated further by a numerical experiment with homogeneous coarse sand, in which continuous downward TCE movement to the bottom of the sandbox was simulated. Another numerical experiment with higher water saturation was also conducted. The results illustrate a complicated influence of water saturation on TCE removal in a layered sand structure. Published by Elsevier B.V.

Effects on the mobility of metals from acidification caused by possible CO₂ leakage from sub-seabed geological formations.

PubMed

de Orte, Manoela Romanó; Sarmiento, Aguasanta M; Basallote, Maria Dolores; Rodríguez-Romero, Araceli; Riba, Inmaculada; Delvalls, Angel

2014-02-01

Carbon dioxide capture and storage (CCS) in submarine geological formations has been proposed as a mitigation measure for the prevention of global warming. However, leakage of CO2 to overlying sediments may occur over time, leading to various effects on ecosystems. Laboratory-scale experiments were performed, involving direct release of carbon dioxide into sediment, inside non-pressurized chambers, in order to provide data on the possible effects of CO2 leakage from geological storage sites on the fate of several metals. Marine sediments from three sites with different levels of contamination were sampled and submitted to acidification by means of CO2 injection. The experiment lasted 10 days and sediment samples were collected at the beginning and end of the experiment and pore water was extracted for metal analysis. The results revealed that mobility of metals from sediment to pore water depends on the site, metal and length of time exposed. Mobilization of the metals Al, Fe, Zn, Co, Pb and Cu increases with acidification, and this response generally increases with time of exposure to CO2 injection. The geochemical model applied suggests that acidification also influences the speciation of metals, transforming metals and metalloids, like As, into species much more toxic to biota. The data obtained from this study will be useful for calculating the potential risk of CCS activities to the marine environment. © 2013.

Geoelectric Monitoring of geological CO2 storage at Ketzin, Germany (CO2SINK project): Downhole and Surface-Downhole measurements

NASA Astrophysics Data System (ADS)

Kiessling, D.; Schuett, H.; Schoebel, B.; Krueger, K.; Schmidt-Hattenberger, C.; Schilling, F.

2009-04-01

Numerical models of the CO2 storage experiment CO2SINK (CO2 Storage by Injection into a Natural Saline Aquifer at Ketzin), where CO2 is injected into a deep saline aquifer at roughly 650 m depth, yield a CO2 saturation of approximately 50% for large parts of the plume. Archie's equation predicts an increase of the resistivity by a factor of approximately 3 to 4 for the reservoir sandstone, and laboratory tests on Ketzin reservoir samples support this prediction. Modeling results show that tracking the CO2 plume may be doable with crosshole resistivity surveys under these conditions. One injection well and two observation wells were drilled in 2007 to a depth of about 800 m and were completed with "smart" casings, arranged L-shaped with distances of 50 m and 100 m. 45 permanent ring-shaped steel electrodes were attached to the electrically insulated casings of the three Ketzin wells at 590 m to 735 m depth with a spacing of about 10 m. It is to our knowledge the deepest permanent vertical electrical resistivity array (VERA) worldwide. The electrodes are connected to the current power supply and data registration units at the surface through custom-made cables. This deep electrode array allows for the registration of electrical resistivity tomography (ERT) data sets at basically any desired repetition rate and at very low cost, without interrupting the injection operations. The installation of all 45 electrodes succeeded. The electrodes are connected to the electrical cable, and the insulated casing stood undamaged. Even after 2-odd years under underground conditions only 6 electrodes are in a critical state now, caused by corrosion effects. In the framework of the COSMOS project (CO2-Storage, Monitoring and Safety Technology), supported by the German "Geotechnologien" program, the geoelectric monitoring has been performed. The 3D crosshole time-laps measurements are taken using dipole-dipole configurations. The data was inverted using AGI EarthImager 3D to obtain 3D images of the true resistivity distribution in the reservoir, which reflects the extent of the CO2 plume. The resistivity data provide information about the saturation state of the reservoir independently of seismic methods. Base data sets have been measured prior to the CO2 injection; monitoring data sets are registered while CO2 is being injected. Using combined 3D surface-downhole measurements (realized in cooperation with University of Leipzig) we got in addition an indication for effects of anisotropy in CO2 migration. We present an overview of the electrode installation, first examples for baseline and monitoring datasets and the corresponding tomograms that show indications of the CO2 migration.

Effects of CO 2 on mechanical variability and constitutive behavior of the Lower Tuscaloosa formation, Cranfield Injection Site, USA

DOE PAGES

Rinehart, Alex J.; Dewers, Thomas A.; Broome, Scott T.; ...

2016-08-25

We characterize geomechanical constitutive behavior of reservoir sandstones at conditions simulating the “Cranfield” Southeast Regional Carbon Sequestration Partnership injection program. From two cores of Lower Tuscaloosa Formation, three sandstone lithofacies were identified for mechanical testing based on permeability and lithology. These include: chlorite-cemented conglomeratic sandstone (Facies A); quartz-cemented fine sandstone (Facies B); and quartz- and calcite-cemented very fine sandstone (Facies C). We performed a suite of compression tests for each lithofacies at 100 °C and pore pressure of 30 MPa, including hydrostatic compression and triaxial tests at several confining pressures. Plugs were saturated with supercritical CO 2-saturated brine. Chemical environmentmore » affected the mechanical response of all three lithofacies, which experience initial plastic yielding at stresses far below estimated in situ stress. Measured elastic moduli degradation defines a secondary yield surface coinciding with in situ stress for Facies B and C. Facies A shows measurable volumetric creep strain and a failure envelope below estimates of in situ stress, linked to damage of chlorite cements by acidic pore solutions. Furthermore, the substantial weakening of a particular lithofacies by CO 2 demonstrates a possible chemical-mechanical coupling during injection at Cranfield with implications for CO 2 injection, reservoir permeability stimulation, and enhanced oil recovery.« less

Micromechanical Tests and Geochemical Modeling to Evaluate Evolution of Rock Alteration by CO2-Water Mixtures

NASA Astrophysics Data System (ADS)

Aman, M.; Sun, Y.; Ilgen, A.; Espinoza, N.

2015-12-01

Injection of large volumes of CO2 into geologic formations can help reduce the atmospheric CO2 concentration and lower the impact of burning fossil fuels. However, the injection of CO2 into the subsurface shifts the chemical equilibrium between the mineral assemblage and the pore fluid. This shift will situationally facilitate dissolution and reprecipitation of mineral phases, in particular intergranular cements, and can potentially affect the long term mechanical stability of the host formation. The study of these coupled chemical-mechanical reservoir rock responses can help identify and control unexpected emergent behavior associated with geological CO2 storage.Experiments show that micro-mechanical methods are useful in capturing a variety of mechanical parameters, including Young's modulus, hardness and fracture toughness. In particular, micro-mechanical measurements are well-suited for examining thin altered layers on the surfaces of rock specimens, as well as capturing variability on the scale of lithofacies. We performed indentation and scratching tests on sandstone and siltstone rocks altered in natural CO2-brine environments, as well as on analogous samples altered under high pressure, temperature, and dissolved CO2 conditions in a controlled laboratory experiment. We performed geochemical modeling to support the experimental observations, in particular to gain the insight into mineral dissolution/precipitation as a result of the rock-water-CO2reactions. The comparison of scratch measurements performed on specimens both unaltered and altered by CO2 over geologic time scales results in statistically different values for fracture toughness and scratch hardness, indicating that long term exposure to CO2 caused mechanical degradation of the reservoir rock. Geochemical modeling indicates that major geochemical change caused by CO2 invasion of Entrada sandstone is dissolution of hematite cement, and its replacement with siderite and dolomite during the alteration process.

Hydrologic Responses to CO2 Injection in Basalts Based on Flow-through Experiments

NASA Astrophysics Data System (ADS)

Thomas, D.; Hingerl, F.; Garing, C.; Bird, D. K.; Benson, S. M.; Maher, K.

2015-12-01

Experimental studies of basalt-CO2 interactions have increased our ability to predict geochemical responses within a mafic reservoir during geologic CO2 sequestration. However, the lack of flow-through experiments prevents the use of coupled hydrologic-geochemical models to predict evolution of permeability and porosity, critical parameters for assessing storage feasibility. We present here results of three flow-through experiments on an intact basalt core during which we employed X-ray Computed Tomography (CT) to quantify porosity evolution and fluid flow. Using a single core of glassy basaltic tuff from the Snake River Plain (Menan Buttes complex), we performed tracer tests using a solution of NaI (~100,000 ppm) before and after injection of CO2-saturated water at reservoir conditions (90 bar, 50°C) to image porosity and flow path distribution. During the tracer tests, CT scans were taken at 2.5-minute intervals, and outlet fluid was discretely sampled at the same intervals and subsequently measured via ICP-MS, enabling interpretation of the tracer breakthrough curve through both imaging and geochemical analyses. Comparison of the porosity distribution from before and after injection of CO2 shows an overall decrease in core-averaged porosity from 34% to 31.1%. Permeability decreased exponentially from ~4.9x10-12 m2 to 1.18 x10-12 m2. The decrease in porosity and permeability suggests geochemical transformations in the mineral assemblage of the core, which we observe through petrographic analysis of an unaltered sample of the same lithology in contrast with the altered core. There is a significant increase in grain coatings, as well as reduction in the grain size, suggesting dissolution re-precipitation mechanisms. Finally, to develop a framework for the coupled geochemical and hydrologic responses observed experimentally, we have calibrated a reactive transport model at the core scale using the TOUGHREACT simulator [1]. [1] Xu et al. (2011) Comput. Geosci.

Hydrochemical Impacts of CO2 Leakage on Fresh Groundwater: a Field Scale Experiment

NASA Astrophysics Data System (ADS)

Lions, J.; Gal, F.; Gombert, P.; Lafortune, S.; Darmoul, Y.; Prevot, F.; Grellier, S.; Squarcioni, P.

2013-12-01

One of the questions related to the emerging technology for Carbon Geological Storage concerns the risk of CO2 migration beyond the geological storage formation. In the event of leakage toward the surface, the CO2 might affect resources in neighbouring formations (geothermal or mineral resources, groundwater) or even represent a hazard for human activities at the surface or in the subsurface. In view of the preservation of the groundwater resources mainly for human consumption, this project studies the potential hydrogeochemical impacts of CO2 leakage on fresh groundwater quality. One of the objectives is to characterize the bio-geochemical mechanisms that may impair the quality of fresh groundwater resources in case of CO2 leakage. To reach the above mentioned objectives, this project proposes a field experiment to characterize in situ the mechanisms that could impact the water quality, the CO2-water-rock interactions and also to improve the monitoring methodology by controlled CO2 leakage in shallow aquifer. The tests were carried out in an experimental site in the chalk formation of the Paris Basin. The site is equipped with an appropriate instrumentation and was previously characterized (8 piezometers, 25 m deep and 4 piezairs 11 m deep). The injection test was preceded by 6 months of monitoring in order to characterize hydrodynamics and geochemical baselines of the site (groundwater, vadose and soil). Leakage into groundwater is simulated via the injection of a small quantity of food-grade CO2 (~20 kg dissolved in 10 m3 of water) in the injection well at a depth of about 20 m. A plume of dissolved CO2 is formed and moves downward according to the direction of groundwater flow and probably by degassing in part to the surface. During the injection test, hydrochemical monitoring of the aquifer is done in situ and by sampling. The parameters monitored in the groundwater are the piezometric head, temperature, pH and electrical conductivity. Analysis on water samples provide chemical elements (major, minor and trace metals), dissolved gases, microbiological diversity and isotopes (13C). The evolution of the composition of the groundwater in terms of major elements, trace elements and isotope signatures is interpreted in terms of geochemical mechanisms, and the water-rock-CO2 interactions are characterized. Modification of the chemical composition of water in the aquifer due to CO2 injection is assessed in term of groundwater quality i.e. metal element release and the possibility of exceeding references and quality of water for human consumption. One outcome of the CIPRES project will be to highlight mechanisms that can impact groundwater quality when a CO2 leakage occurs and to propose recommendations to prevent or/and eliminate negative effects and any risks to the environment and human health. This project is partially funded by the French Research Agency (ANR).

Detection of CO2 leakage by the surface-soil CO2-concentration monitoring (SCM) system in a small scale CO2 release test

NASA Astrophysics Data System (ADS)

Chae, Gitak; Yu, Soonyoung; Sung, Ki-Sung; Choi, Byoung-Young; Park, Jinyoung; Han, Raehee; Kim, Jeong-Chan; Park, Kwon Gyu

2015-04-01

Monitoring of CO2 release through the ground surface is essential to testify the safety of CO2 storage projects. We conducted a feasibility study of the multi-channel surface-soil CO2-concentration monitoring (SCM) system as a soil CO2 monitoring tool with a small scale injection. In the system, chambers are attached onto the ground surface, and NDIR sensors installed in each chamber detect CO2 in soil gas released through the soil surface. Before injection, the background CO2 concentrations were measured. They showed the distinct diurnal variation, and were positively related with relative humidity, but negatively with temperature. The negative relation of CO2 measurements with temperature and the low CO2 concentrations during the day imply that CO2 depends on respiration. The daily variation of CO2 concentrations was damped with precipitation, which can be explained by dissolution of CO2 and gas release out of pores through the ground surface with recharge. For the injection test, 4.2 kg of CO2 was injected 1 m below the ground for about 30 minutes. In result, CO2 concentrations increased in all five chambers, which were located less than 2.5 m of distance from an injection point. The Chamber 1, which is closest to the injection point, showed the largest increase of CO2 concentrations; while Chamber 2, 3, and 4 showed the peak which is 2 times higher than the average of background CO2. The CO2 concentrations increased back after decreasing from the peak around 4 hours after the injection ended in Chamber 2, 4, and 5, which indicated that CO2 concentrations seem to be recovered to the background around 4 hours after the injection ended. To determine the leakage, the data in Chamber 2 and 5, which had low increase rates in the CO2 injection test, were used for statistical analysis. The result shows that the coefficient of variation (CV) of CO2 measurements for 30 minutes is efficient to determine a leakage signal, with reflecting the abnormal change in CO2 concentrations. The CV of CO2 measurements for 30 minutes exceeded 5% about 5 minutes before the maximum CO2 concentration was detected. The contributions of this work are as follows: (1) SCM is an efficient monitoring tool to detect the CO2 release through the ground surface. (2) The statistical analysis method to determine the leakage and a monitoring frequency are provided, with analyzing background concentrations and CO2 increases in a small-scale injection test. (3) The 5% CV of CO2 measurements for 30 minutes can be used for the early warning in CO2 storage sites.

Modeling of CO 2 sequestration in coal seams: Role of CO 2 -induced coal softening on injectivity, storage efficiency and caprock deformation: Original Research Article: Modeling of CO 2 sequestration in coal seams

DOE PAGES

Ma, Tianran; Rutqvist, Jonny; Liu, Weiqun; ...

2017-01-30

An effective and safe operation for sequestration of CO 2 in coal seams requires a clear understanding of injection-induced coupled hydromechanical processes such as the evolution of pore pressure, permeability, and induced caprock deformation. In this study, CO 2 injection into coal seams was studied using a coupled flow-deformation model with a new stress-dependent porosity and permeability model that considers CO 2 -induced coal softening. Based on triaxial compression tests of coal samples extracted from the site of the first series of enhanced coalbed methane field tests in China, a softening phenomenon that a substantial (one-order-of-magnitude) decrease of Young's modulusmore » and an increase of Poisson's ratio with adsorbed CO 2 content was observed. Such softening was considered in the numerical simulation through an exponential relation between elastic properties (Young's modulus and Poisson's ratio) and CO 2 pressure considering that CO 2 content is proportional to the CO 2 pressure. Our results of the numerical simulation show that the softening of the coal strongly affects the CO 2 sequestration performance, first by impeding injectivity and stored volume (cumulative injection) during the first week of injection, and thereafter by softening mediated rebound in permeability that tends to increase injectivity and storage over the longer term. A sensitivity study shows that stronger CO 2 -induced coal softening and higher CO 2 injection pressure contribute synergistically to increase a significant increase of CO 2 injectivity and adsorption, but also result in larger caprock deformations and uplift. This study demonstrates the importance of considering the CO 2 -induced softening when analyzing the performance and environmental impact of CO 2 -sequestration operations in unminable coal seams.« less

Modeling of CO 2 sequestration in coal seams: Role of CO 2 -induced coal softening on injectivity, storage efficiency and caprock deformation: Original Research Article: Modeling of CO 2 sequestration in coal seams

DOE Office of Scientific and Technical Information (OSTI.GOV)

Ma, Tianran; Rutqvist, Jonny; Liu, Weiqun

An effective and safe operation for sequestration of CO 2 in coal seams requires a clear understanding of injection-induced coupled hydromechanical processes such as the evolution of pore pressure, permeability, and induced caprock deformation. In this study, CO 2 injection into coal seams was studied using a coupled flow-deformation model with a new stress-dependent porosity and permeability model that considers CO 2 -induced coal softening. Based on triaxial compression tests of coal samples extracted from the site of the first series of enhanced coalbed methane field tests in China, a softening phenomenon that a substantial (one-order-of-magnitude) decrease of Young's modulusmore » and an increase of Poisson's ratio with adsorbed CO 2 content was observed. Such softening was considered in the numerical simulation through an exponential relation between elastic properties (Young's modulus and Poisson's ratio) and CO 2 pressure considering that CO 2 content is proportional to the CO 2 pressure. Our results of the numerical simulation show that the softening of the coal strongly affects the CO 2 sequestration performance, first by impeding injectivity and stored volume (cumulative injection) during the first week of injection, and thereafter by softening mediated rebound in permeability that tends to increase injectivity and storage over the longer term. A sensitivity study shows that stronger CO 2 -induced coal softening and higher CO 2 injection pressure contribute synergistically to increase a significant increase of CO 2 injectivity and adsorption, but also result in larger caprock deformations and uplift. This study demonstrates the importance of considering the CO 2 -induced softening when analyzing the performance and environmental impact of CO 2 -sequestration operations in unminable coal seams.« less

Subsurface capture of carbon dioxide

DOEpatents

Blount, Gerald; Siddal, Alvin A.; Falta, Ronald W.

2014-07-22

A process and apparatus of separating CO.sub.2 gas from industrial off-gas source in which the CO.sub.2 containing off-gas is introduced deep within an injection well. The CO.sub.2 gases are dissolved in the, liquid within the injection well while non-CO.sub.2 gases, typically being insoluble in water or brine, are returned to the surface. Once the CO.sub.2 saturated liquid is present within the injection well, the injection well may be used for long-term geologic storage of CO.sub.2 or the CO.sub.2 saturated liquid can be returned to the surface for capturing a purified CO.sub.2 gas.

Mass spectrometric gas composition measurements associated with jet interaction tests in a high-enthalpy wind tunnel

NASA Technical Reports Server (NTRS)

Lewis, B. W.; Brown, K. G.; Wood, G. M., Jr.; Puster, R. L.; Paulin, P. A.; Fishel, C. E.; Ellerbe, D. A.

1986-01-01

Knowledge of test gas composition is important in wind-tunnel experiments measuring aerothermodynamic interactions. This paper describes measurements made by sampling the top of the test section during runs of the Langley 7-Inch High-Temperature Tunnel. The tests were conducted to determine the mixing of gas injected from a flat-plate model into a combustion-heated hypervelocity test stream and to monitor the CO2 produced in the combustion. The Mass Spectrometric (MS) measurements yield the mole fraction of N2 or He and CO2 reaching the sample inlets. The data obtained for several tunnel run conditions are related to the pressures measured in the tunnel test section and at the MS ionizer inlet. The apparent distributions of injected gas species and tunnel gas (CO2) are discussed relative to the sampling techniques. The measurements provided significant real-time data for the distribution of injected gases in the test section. The jet N2 diffused readily from the test stream, but the jet He was mostly entrained. The amounts of CO2 and Ar diffusing upward in the test section for several run conditions indicated the variability of the combustion-gas test-stream composition.

Applying monitoring, verification, and accounting techniques to a real-world, enhanced oil recovery operational CO2 leak

USGS Publications Warehouse

Wimmer, B.T.; Krapac, I.G.; Locke, R.; Iranmanesh, A.

2011-01-01

The use of carbon dioxide (CO2) for enhanced oil recovery (EOR) is being tested for oil fields in the Illinois Basin, USA. While this technology has shown promise for improving oil production, it has raised some issues about the safety of CO2 injection and storage. The Midwest Geological Sequestration Consortium (MGSC) organized a Monitoring, Verification, and Accounting (MVA) team to develop and deploy monitoring programs at three EOR sites in Illinois, Indiana, and Kentucky, USA. MVA goals include establishing baseline conditions to evaluate potential impacts from CO2 injection, demonstrating that project activities are protective of human health and the environment, and providing an accurate accounting of stored CO2. This paper focuses on the use of MVA techniques in monitoring a small CO2 leak from a supply line at an EOR facility under real-world conditions. The ability of shallow monitoring techniques to detect and quantify a CO2 leak under real-world conditions has been largely unproven. In July of 2009, a leak in the pipe supplying pressurized CO2 to an injection well was observed at an MGSC EOR site located in west-central Kentucky. Carbon dioxide was escaping from the supply pipe located approximately 1 m underground. The leak was discovered visually by site personnel and injection was halted immediately. At its largest extent, the hole created by the leak was approximately 1.9 m long by 1.7 m wide and 0.7 m deep in the land surface. This circumstance provided an excellent opportunity to evaluate the performance of several monitoring techniques including soil CO2 flux measurements, portable infrared gas analysis, thermal infrared imagery, and aerial hyperspectral imagery. Valuable experience was gained during this effort. Lessons learned included determining 1) hyperspectral imagery was not effective in detecting this relatively small, short-term CO2 leak, 2) even though injection was halted, the leak remained dynamic and presented a safety risk concern during monitoring activities and, 3) the atmospheric and soil monitoring techniques used were relatively cost-effective, easily and rapidly deployable, and required minimal manpower to set up and maintain for short-term assessments. However, characterization of CO2 distribution near the land surface resulting from a dynamic leak with widely variable concentrations and fluxes was challenging. ?? 2011 Published by Elsevier Ltd.

Quantification of CO2-FLUID-ROCK Reactions Using Reactive and Non-Reactive Tracers

NASA Astrophysics Data System (ADS)

Matter, J.; Stute, M.; Hall, J. L.; Mesfin, K. G.; Gislason, S. R.; Oelkers, E. H.; Sigfússon, B.; Gunnarsson, I.; Aradottir, E. S.; Alfredsson, H. A.; Gunnlaugsson, E.; Broecker, W. S.

2013-12-01

Carbon dioxide mineralization via fluid-rock reactions provides the most effective and long-term storage option for geologic carbon storage. Injection of CO2 in geologic formations induces CO2 -fluid-rock reactions that may enhance or decrease the storage permanence and thus the long-term safety of geologic carbon storage. Hence, quantitative characterization of critical CO2 -fluid-rock interactions is essential to assess the storage efficiency and safety of geologic carbon storage. In an attempt to quantify in-situ fluid-rock reactions and CO2 transport relevant for geologic carbon storage, we are testing reactive (14C, 13C) and non-reactive (sodium fluorescein, amidorhodamine G, SF5CF3, and SF6) tracers in an ongoing CO2 injection in a basaltic storage reservoir at the CARBFIX pilot injection site in Iceland. At the injection site, CO2 is dissolved in groundwater and injected into a permeable basalt formation located 500-800 m below the surface [1]. The injected CO2 is labeled with 14C by dynamically adding calibrated amounts of H14CO3-solution into the injection stream in addition to the non-reactive tracers. Chemical and isotopic analyses of fluid samples collected in a monitoring well, reveal fast fluid-rock reactions. Maximum SF6 concentration in the monitoring well indicates the bulk arrival of the injected CO2 solution but dissolved inorganic carbon (DIC) concentration and pH values close to background, and a potentially lower 14C to SF6 ratio than the injection ratio suggest that most of the injected CO2 has reacted with the basaltic rocks. This is supported by δ13CDIC, which shows a drop from values close to the δ 13C of the injected CO2 gas (-3‰ VPDB) during breakthrough of the CO2 plume to subsequent more depleted values (-11.25‰ VPDB), indicating precipitation of carbonate minerals. Preliminary mass balance calculations using mixing relationships between the background water in the storage formation and the injected solution, suggest that approximately 85% of the injected CO2 must have reacted along the flow path from the injection well to the monitoring well within less than one year. Monitoring is still going on and we will extend the time series and the mass balance accordingly. Our study demonstrates that by combining reactive and non-reactive tracers, we are able to quantify CO2-fluid-rock interactions on a reservoir scale. [1] Gislason et al. (2010), Int. J. Greenh. Gas Con. 4, 537-545.

Peculiarities of CO2 sequestration in the Permafrost area

NASA Astrophysics Data System (ADS)

Guryeva, Olga; Chuvilin, Evgeny; Moudrakovski, Igor; Lu, Hailong; Ripmeester, John; Istomin, Vladimir

2010-05-01

Natural gas and gas-condensate accumulations in North of Western Siberia contain an admixture of CO2 (about 0.5-1.0 mol.%). Recently, the development and transportation of natural gas in the Yamal peninsula has become of interest to Russian scientists. They suggest liquifaction of natural gas followed by delivery to consumers using icebreaking tankers. The technique of gas liquefaction requires CO2 to be absent from natural gas, and therefore the liquefaction technology includes the amine treatment of gas. This then leads to a problem with utilization of recovered CO2. It is important to note, that gas reservoirs in the northern part of Russia are situated within the Permafrost zone. The thickness of frozen sediment reaches 500 meters. That is why one of the promising places for CO2 storage can be gas-permeable collectors in under-permafrost horizons. The favorable factors for preserving CO2 in these places are as follows: low permeability of overlying frozen sediments, low temperatures, the existence of a CO2 hydrate stability zone, and the possibility of sequestration at shallow depths (less then 800-1000 meters). When CO2 (in liquid or gas phase) is pumped into the under-permafrost collectors it is possible that some CO2 migrates towards the hydrate stability zone and hydrate-saturated horizons can be formed. This can result on the one hand in the increase of effective capacity of the collector, and on the other hand, in the increase of isolating properties of cap rock. Therefore, CO2 injection sometimes can be performed without a good cap rock. In connection with the abovementioned, to elaborate an effective technology for CO2 injection it is necessary to perform a comprehensive experimental investigation with computer simulation of different utilization schemes, including the process of CO2 hydrate formation in porous media. There are two possible schemes of hydrate formation in pore medium of sediments: from liquid CO2 or the gas. The pore water in the sediment may be either in frozen or liquid states. To study these processes, an experimental investigation of hydrate formation kinetics from liquid and gaseous CO2 has been performed using the method of NMR imaging*. Experiments were made with samples of quartz sand (particles' diameter 0,21-0,297mm) with different water saturation in the range of temperatures between -3 and +8oC and pressures between 3 and 6 MPa. The experiments performed revealed the main regularities of hydrate accumulation from liquid CO2 in sediment. The influence of temperature on the rate of pore hydrate growth was analyzed. For example, the rate of hydrate growth at +7.2oC was 6 times smaller then at -3 оС. Fast hydrate formation from liquid CO2 was observed in sand samples with water saturation below 20-30%. With an increase in water saturation to 50%, the rate of hydrate formation decreased significantly, and when water saturation was 60% or more, nucleation was not observed during the time of the experiment (1-3 days). Experimental results revealed that pressure variation in the range between 4 and 6 MPa does not have any influence on the kinetics of hydrate formation from liquid CO2. Comparison of kinetics of hydrate formation from liquid and gas CO2 showed that hydrate accumulation is faster from gas CO2 then from liquid CO2. Thus, 50% of pore water that reacted with liquid CO2 transformed into hydrate in 0.8 hours after nucleation, and when reacted with CO2-gas, it transformed in 0.3 hours. The completed experiments allowed us to consider the peculiarities of hydrate formation and filtration of liquid and gaseous CO2 towards the hydrate stability zone, which is important to take into account during the elaboration of industrial techniques of CO2 injection in under-permafrost collectors. * Experiments have been made in the laboratory of NRC of Canada.

Estimation of seismically detectable portion of a gas plume: CO2CRC Otway project case study

NASA Astrophysics Data System (ADS)

Pevzner, Roman; Caspari, Eva; Bona, Andrej; Galvin, Robert; Gurevich, Boris

2013-04-01

CO2CRC Otway project comprises of several experiments involving CO2/CH4 or pure CO2 gas injection into different geological formations at the Otway test site (Victoria, Australia). During the first stage of the project, which was finished in 2010, more than 64,000 t of gas were injected into the depleted gas reservoir at ~2 km depth. At the moment, preparations for the next stage of the project aiming to examine capabilities of seismic monitoring of small scale injection (up to 15,000 t) into saline formation are ongoing. Time-lapse seismic is one of the most typical methods for CO2 geosequestration monitoring. Significant experience was gained during the first stage of the project through acquisition and analysis of the 4D surface seismic and numerous time-lapse VSP surveys. In order to justify the second stage of the project and optimise parameters of the experiment, several modelling studies were conducted. In order to predict seismic signal we populate realistic geological model with elastic properties, model their changes using fluid substitution technique applied to the fluid flow simulation results and compute synthetic seismic baseline and monitor volumes. To assess detectability of the time-lapse signal caused by the injection, we assume that the time-lapse noise level will be equivalent to the level of difference between the last two Otway 3D surveys acquired in 2009 and 2010 using conventional surface technique (15,000 lbs vibroseis sources and single geophones as the receivers). In order to quantify the uncertainties in plume imaging/visualisation due to the time-lapse noise realisation we propose to use multiple noise realisations with the same F-Kx-Ky amplitude spectra as the field noise for each synthetic signal volume. Having signal detection criterion defined in the terms of signal/time- lapse noise level on a single trace we estimate visible portion of the plume as a function of this criterion. This approach also gives an opportunity to attempt to evaluate probability of the signal detection. The authors acknowledge the funding provided by the Australian government through its CRC program to support this CO2CRC research project. We also acknowledge the CO2CRC's corporate sponsors and the financial assistance provided through Australian National Low Emissions Coal Research and Development (ANLEC R&D). ANLEC R&D is supported by Australian Coal Association Low Emissions Technology Limited and the Australian Government through the Clean Energy Initiative.

Effects of CO2 injection and Kerogen Maturation on Low-Field Nuclear Magnetic Resonance Response

NASA Astrophysics Data System (ADS)

Prasad, M.; Livo, K.

2017-12-01

Low-field Nuclear Magnetic Resonance (NMR) is commonly used in petrophysical analysis of petroleum reservoir rocks. NMR experiments record the relaxation and polarization of in-situ hydrogen protons present in gaseous phases such as free-gas intervals and solution gas fluids, bulk fluid phases such as oil and aquifer intervals, and immovable fractions of kerogen and bitumen. Analysis of NMR relaxation spectra is performed to record how fluid composition, maturity, and viscosity change NMR experimental results. We present T1-T2 maps as thermal maturity of a water-saturated, sub-mature Woodford shale is increased at temperatures from 125 to 400 degrees Celsius. Experiments with applied fluid pressure in paraffinic mineral oil and DI water with varying fluid pH have been performed to mimic reservoir conditions in analysis of the relaxation of bulk fluid phases. We have recorded NMR spectra, T1-T2 maps, and fluid diffusion coefficients using a low-field (2 MHz) MagritekTM NMR. CO2 was injected at a pressure of 900 psi in an in house developed NMR pressure vessel made of torlon plastic. Observable 2D NMR shifts in immature kerogen formations as thermal maturity is increased show generation of lighter oils with increased maturity. CO2 injection leads to a decrease in bulk fluid relaxation time that is attributed to viscosity modification with gas presence. pH variation with increased CO2 presence were shown to not effect NMR spectra. From this, fluid properties have been shown to greatly affect NMR readings and must be taken into account for more accurate NMR reservoir characterization.

Understanding the interaction of injected CO2 and reservoir fluids in the Cranfield enhanced oil recovery (EOR) field (MS, USA) by non-radiogenic noble gas isotopes

NASA Astrophysics Data System (ADS)

Gyore, Domokos; Stuart, Finlay; Gilfillan, Stuart

2016-04-01

Identifying the mechanism by which the injected CO2 is stored in underground reservoirs is a key challenge for carbon sequestration. Developing tracing tools that are universally deployable will increase confidence that CO2 remains safely stored. CO2 has been injected into the Cranfield enhanced oil recovery (EOR) field (MS, USA) since 2008 and significant amount of CO2 has remained (stored) in the reservoir. Noble gases (He, Ne, Ar, Kr, Xe) are present as minor natural components in the injected CO2. He, Ne and Ar previously have been shown to be powerful tracers of the CO2 injected in the field (Györe et al., 2015). It also has been implied that interaction with the formation water might have been responsible for the observed CO2 loss. Here we will present work, which examines the role of reservoir fluids as a CO2 sink by examining non-radiogenic noble gas isotopes (20Ne, 36Ar, 84Kr, 132Xe). Gas samples from injection and production wells were taken 18 and 45 months after the start of injection. We will show that the fractionation of noble gases relative to Ar is consistent with the different degrees of CO2 - fluid interaction in the individual samples. The early injection samples indicate that the CO2 injected is in contact with the formation water. The spatial distribution of the data reveal significant heterogeneity in the reservoir with some wells exhibiting a relatively free flow path, where little formation water is contacted. Significantly, in the samples, where CO2 loss has been previously identified show active and ongoing contact. Data from the later stage of the injection shows that the CO2 - oil interaction has became more important than the CO2 - formation water interaction in controlling the noble gas fingerprint. This potentially provides a means to estimate the oil displacement efficiency. This dataset is a demonstration that noble gases can resolve CO2 storage mechanisms and its interaction with the reservoir fluids with high resolution. References: Györe, D., Stuart, F.M., Gilfillan, S.M.V., Waldron, S., 2015. Tracing injected CO2 in the Cranfield enhanced oil recovery field (MS, USA) using He, Ne and Ar isotopes. Int. J. Greenh. Gas Con. 42, 554-561.

Mechanical changes caused by CO2-driven cement dissolution in the Morrow B Sandstone at reservoir conditions: Experimental observations

NASA Astrophysics Data System (ADS)

Wu, Z.; Luhmann, A. J.; Rinehart, A. J.; Mozley, P.; Dewers, T. A.

2017-12-01

Carbon Capture, Utilization and Storage (CCUS) in transmissive reservoirs is a proposed mechanism in reducing CO2 emissions. Injection of CO2 perturbs reservoir chemistry, and can modify porosity and permeability and alter mineralogy. However, little work has been done on the coupling of rock alteration by CO2 injection and the mechanical integrity of the reservoir. In this study, we perform flow-through experiments on calcite- and dolomite-cemented Pennsylvanian Morrow B Sandstone (West Texas, USA) cores. We hypothesize that poikilotopic calcite cement has a larger impact on chemo-mechanical alteration than disseminated dolomite cement given similar CO2 exposure. With one control brine flow-through experiment and two CO2-plus-brine flow-through experiments for each cement composition, flow rates of 0.1 and 0.01 ml/min were applied under 4200 psi pore fluid pressure and 5000 psi confining pressure at 71 °C. Fluid chemistry and permeability data enable monitoring of mineral dissolution. Ultrasonic velocities were measured pre-test using 1.2 MHz source-receiver pairs at 0.5 MPa axial load and show calcite-cemented samples with higher dynamic elastic moduli than dolomite-cemented samples. Velocities measured post-experiment will identify changes from fluid-rock interaction. We plan to conduct cylinder-splitting destructive mechanical test (Brazil test) to measure the pristine and altered tensile strength of different cemented sandstones. The experiments will identify extents to which cement composition and texture control chemo-mechanical degradation of CCUS reservoirs. Funding for this project is provided by the U.S. Department of Energy's (DOE) National Energy Technology Laboratory (NETL) through the Southwest Regional Partnership on Carbon Sequestration (SWP) under Award No. DE-FC26-05NT42591. Sandia National Laboratories is a multimission laboratory managed and operated by National Technology and Engineering Solutions of Sandia LLC, a wholly owned subsidiary of Honeywell International Inc. for the U.S. Department of Energy's National Nuclear Security Administration under contract DE-NA0003525.

Laboratory Mid-frequency (Kilohertz) Range Seismic Property Measurements and X-ray CT Imaging of Fractured Sandstone Cores During Supercritical CO2 Injection

NASA Astrophysics Data System (ADS)

Nakagawa, S.; Kneafsey, T. J.; Chang, C.; Harper, E.

2014-12-01

During geological sequestration of CO2, fractures are expected to play a critical role in controlling the migration of the injected fluid in reservoir rock. To detect the invasion of supercritical (sc-) CO2 and to determine its saturation, velocity and attenuation of seismic waves can be monitored. When both fractures and matrix porosity connected to the fractures are present, wave-induced dynamic poroelastic interactions between these two different types of rock porosity—high-permeability, high-compliance fractures and low-permeability, low-compliance matrix porosity—result in complex velocity and attenuation changes of compressional waves as scCO2 invades the rock. We conducted core-scale laboratory scCO2 injection experiments on small (diameter 1.5 inches, length 3.5-4 inches), medium-porosity/permeability (porosity 15%, matrix permeability 35 md) sandstone cores. During the injection, the compressional and shear (torsion) wave velocities and attenuations of the entire core were determined using our Split Hopkinson Resonant Bar (short-core resonant bar) technique in the frequency range of 1-2 kHz, and the distribution and saturation of the scCO2 determined via X-ray CT imaging using a medical CT scanner. A series of tests were conducted on (1) intact rock cores, (2) a core containing a mated, core-parallel fracture, (3) a core containing a sheared core-parallel fracture, and (4) a core containing a sheared, core-normal fracture. For intact cores and a core containing a mated sheared fracture, injections of scCO2 into an initially water-saturated sample resulted in large and continuous decreases in the compressional velocity as well as temporary increases in the attenuation. For a sheared core-parallel fracture, large attenuation was also observed, but almost no changes in the velocity occurred. In contrast, a sample containing a core-normal fracture exhibited complex behavior of compressional wave attenuation: the attenuation peaked as the leading edge of the scCO2 approached the fracture; followed by an immediate drop as scCO2 invaded the fracture; and by another, gradual increase as the scCO2 infiltrated into the other side of the fracture. The compressional wave velocity declined monotonically, but the rate of velocity decrease changed with the changes in attenuation.

Hyperspectral detection of a subsurface CO2 leak in the presence of water stressed vegetation.

PubMed

Bellante, Gabriel J; Powell, Scott L; Lawrence, Rick L; Repasky, Kevin S; Dougher, Tracy

2014-01-01

Remote sensing of vegetation stress has been posed as a possible large area monitoring tool for surface CO2 leakage from geologic carbon sequestration (GCS) sites since vegetation is adversely affected by elevated CO2 levels in soil. However, the extent to which remote sensing could be used for CO2 leak detection depends on the spectral separability of the plant stress signal caused by various factors, including elevated soil CO2 and water stress. This distinction is crucial to determining the seasonality and appropriateness of remote GCS site monitoring. A greenhouse experiment tested the degree to which plants stressed by elevated soil CO2 could be distinguished from plants that were water stressed. A randomized block design assigned Alfalfa plants (Medicago sativa) to one of four possible treatment groups: 1) a CO2 injection group; 2) a water stress group; 3) an interaction group that was subjected to both water stress and CO2 injection; or 4) a group that received adequate water and no CO2 injection. Single date classification trees were developed to identify individual spectral bands that were significant in distinguishing between CO2 and water stress agents, in addition to a random forest classifier that was used to further understand and validate predictive accuracies. Overall peak classification accuracy was 90% (Kappa of 0.87) for the classification tree analysis and 83% (Kappa of 0.77) for the random forest classifier, demonstrating that vegetation stressed from an underground CO2 leak could be accurately discerned from healthy vegetation and areas of co-occurring water stressed vegetation at certain times. Plants appear to hit a stress threshold, however, that would render detection of a CO2 leak unlikely during severe drought conditions. Our findings suggest that early detection of a CO2 leak with an aerial or ground-based hyperspectral imaging system is possible and could be an important GCS monitoring tool.

Hyperspectral Detection of a Subsurface CO2 Leak in the Presence of Water Stressed Vegetation

PubMed Central

Bellante, Gabriel J.; Powell, Scott L.; Lawrence, Rick L.; Repasky, Kevin S.; Dougher, Tracy

2014-01-01

Remote sensing of vegetation stress has been posed as a possible large area monitoring tool for surface CO2 leakage from geologic carbon sequestration (GCS) sites since vegetation is adversely affected by elevated CO2 levels in soil. However, the extent to which remote sensing could be used for CO2 leak detection depends on the spectral separability of the plant stress signal caused by various factors, including elevated soil CO2 and water stress. This distinction is crucial to determining the seasonality and appropriateness of remote GCS site monitoring. A greenhouse experiment tested the degree to which plants stressed by elevated soil CO2 could be distinguished from plants that were water stressed. A randomized block design assigned Alfalfa plants (Medicago sativa) to one of four possible treatment groups: 1) a CO2 injection group; 2) a water stress group; 3) an interaction group that was subjected to both water stress and CO2 injection; or 4) a group that received adequate water and no CO2 injection. Single date classification trees were developed to identify individual spectral bands that were significant in distinguishing between CO2 and water stress agents, in addition to a random forest classifier that was used to further understand and validate predictive accuracies. Overall peak classification accuracy was 90% (Kappa of 0.87) for the classification tree analysis and 83% (Kappa of 0.77) for the random forest classifier, demonstrating that vegetation stressed from an underground CO2 leak could be accurately discerned from healthy vegetation and areas of co-occurring water stressed vegetation at certain times. Plants appear to hit a stress threshold, however, that would render detection of a CO2 leak unlikely during severe drought conditions. Our findings suggest that early detection of a CO2 leak with an aerial or ground-based hyperspectral imaging system is possible and could be an important GCS monitoring tool. PMID:25330232

Controlled CO2 injection into a shallow aquifer and leakage detection monitoring practices at the K-COSEM site, Korea

NASA Astrophysics Data System (ADS)

Lee, S. S.; Joun, W.; Ju, Y. J.; Ha, S. W.; Jun, S. C.; Lee, K. K.

2017-12-01

Artificial carbon dioxide injection into a shallow aquifer system was performed with two injection types imitating short- and long-term CO2 leakage events into a shallow aquifer. One is pulse type leakage of CO2 (6 hours) under a natural hydraulic gradient (0.02) and the other is long-term continuous injection (30 days) under a forced hydraulic gradient (0.2). Injection and monitoring tests were performed at the K-COSEM site in Eumseong, Korea where a specially designed well field had been installed for artificial CO2 release tests. CO2-infused and tracer gases dissolved groundwater was injected through a well below groundwater table and monitoring were conducted in both saturated and unsaturated zones. Real-time monitoring data on CO2 concentration and hydrochemical parameters, and periodical measurements of several gas tracers (He, Ar, Kr, SF6) were obtained. The pulse type short-term injection test was carried out prior to the long-term injection test. Results of the short-term injection test, under natural hydraulic gradient, showed that CO2 plume migrated along the preferential pathway identified through hydraulic interference tests. On the other hand, results of the long-term injection test indicated the CO2 plume migration path was aligned to the forced hydraulic gradient. Compared to the short-term test, the long-term injection formed detectable CO2 concentration change in unsaturated wellbores. Recovery data of tracer gases made breakthrough curves compatible to numerical simulation results. The monitoring results indicated that detection of CO2 leakage into groundwater was more effectively performed by using a pumping and monitoring method in order to capture by-passing plume. With this concept, an effective real-time monitoring method was proposed. Acknowledgement: Financial support was provided by the "R&D Project on Environmental Management of Geologic CO2storage" from the KEITI (Project number : 2014001810003)

Transient changes in shallow groundwater chemistry during the MSU ZERT CO2 injection experiment

USGS Publications Warehouse

Apps, J.A.; Zheng, Lingyun; Spycher, N.; Birkholzer, J.T.; Kharaka, Y.; Thordsen, J.; Kakouros, E.; Trautz, R.

2011-01-01

Food-grade CO2 was injected into a shallow aquifer through a perforated pipe placed horizontally 1-2 m below the water table at the Montana State University Zero Emission Research and Technology (MSU-ZERT) field site at Bozeman, Montana. The possible impact of elevated CO2 levels on groundwater quality was investigated by analyzing 80 water samples taken before, during, and following CO2 injection. Field determinations and laboratory analyses showed rapid and systematic changes in pH, alkalinity, and conductance, as well as increases in the aqueous concentrations of trace element species. The geochemical data were first evaluated using principal component analysis (PCA) in order to identify correlations between aqueous species. The PCA findings were then used in formulating a geochemical model to simulate the processes likely to be responsible for the observed increases in the concentrations of dissolved constituents. Modeling was conducted taking into account aqueous and surface complexation, cation exchange, and mineral precipitation and dissolution. Reasonable matches between measured data and model results suggest that: (1) CO2 dissolution in the groundwater causes calcite to dissolve. (2) Observed increases in the concentration of dissolved trace metals result likely from Ca+2-driven ion exchange with clays (smectites) and sorption/desorption reactions likely involving Fe (hydr)oxides. (3) Bicarbonate from CO2 dissolution appears to compete for sorption with anionic species such as HAsO4-2, potentially increasing dissolved As levels in groundwater. ?? 2011 Published by Elsevier Ltd.

ADVANCED RESERVOIR CHARACTERIZATION IN THE ANTELOPE SHALE TO ESTABLISH THE VIABILITY OF CO2 ENHANCED OIL RECOVERY IN CALIFORNIA'S MONTEREY FORMATION SILICEOUS SHALES

DOE Office of Scientific and Technical Information (OSTI.GOV)

Pasquale R. Perri

2003-05-15

This report describes the evaluation, design, and implementation of a DOE funded CO{sub 2} pilot project in the Lost Hills Field, Kern County, California. The pilot consists of four inverted (injector-centered) 5-spot patterns covering approximately 10 acres, and is located in a portion of the field, which has been under waterflood since early 1992. The target reservoir for the CO{sub 2} pilot is the Belridge Diatomite. The pilot location was selected based on geologic considerations, reservoir quality and reservoir performance during the waterflood. A CO{sub 2} pilot was chosen, rather than full-field implementation, to investigate uncertainties associated with CO{sub 2}more » utilization rate and premature CO{sub 2} breakthrough, and overall uncertainty in the unproven CO{sub 2} flood process in the San Joaquin Valley. A summary of the design and objectives of the CO{sub 2} pilot are included along with an overview of the Lost Hills geology, discussion of pilot injection and production facilities, and discussion of new wells drilled and remedial work completed prior to commencing injection. Actual CO{sub 2} injection began on August 31, 2000 and a comprehensive pilot monitoring and surveillance program has been implemented. Since the initiation of CO{sub 2} injection, the pilot has been hampered by excessive sand production in the pilot producers due to casing damage related to subsidence and exacerbated by the injected CO{sub 2}. Therefore CO{sub 2} injection was very sporadic in 2001 and 2002 and we experienced long periods of time with no CO{sub 2} injection. As a result of the continued mechanical problems, the pilot project was terminated on January 30, 2003. This report summarizes the injection and production performance and the monitoring results through December 31, 2002 including oil geochemistry, CO{sub 2} injection tracers, crosswell electromagnetic surveys, crosswell seismic, CO{sub 2} injection profiling, cased hole resistivity, tiltmetering results, and corrosion monitoring results. Although the Lost Hills CO{sub 2} pilot was not successful, the results and lessons learned presented in this report may be applicable to evaluate and design other potential San Joaquin Valley CO{sub 2} floods.« less

Investigation of uncertainty in CO 2 reservoir models: A sensitivity analysis of relative permeability parameter values

DOE PAGES

Yoshida, Nozomu; Levine, Jonathan S.; Stauffer, Philip H.

2016-03-22

Numerical reservoir models of CO 2 injection in saline formations rely on parameterization of laboratory-measured pore-scale processes. Here, we have performed a parameter sensitivity study and Monte Carlo simulations to determine the normalized change in total CO 2 injected using the finite element heat and mass-transfer code (FEHM) numerical reservoir simulator. Experimentally measured relative permeability parameter values were used to generate distribution functions for parameter sampling. The parameter sensitivity study analyzed five different levels for each of the relative permeability model parameters. All but one of the parameters changed the CO 2 injectivity by <10%, less than the geostatistical uncertainty that applies to all large subsurface systems due to natural geophysical variability and inherently small sample sizes. The exception was the end-point CO 2 relative permeability, kmore » $$0\\atop{r}$$ CO2, the maximum attainable effective CO 2 permeability during CO 2 invasion, which changed CO2 injectivity by as much as 80%. Similarly, Monte Carlo simulation using 1000 realizations of relative permeability parameters showed no relationship between CO 2 injectivity and any of the parameters but k$$0\\atop{r}$$ CO2, which had a very strong (R 2 = 0.9685) power law relationship with total CO 2 injected. Model sensitivity to k$$0\\atop{r}$$ CO2 points to the importance of accurate core flood and wettability measurements.« less

Investigation of uncertainty in CO 2 reservoir models: A sensitivity analysis of relative permeability parameter values

DOE Office of Scientific and Technical Information (OSTI.GOV)

Yoshida, Nozomu; Levine, Jonathan S.; Stauffer, Philip H.

Numerical reservoir models of CO 2 injection in saline formations rely on parameterization of laboratory-measured pore-scale processes. Here, we have performed a parameter sensitivity study and Monte Carlo simulations to determine the normalized change in total CO 2 injected using the finite element heat and mass-transfer code (FEHM) numerical reservoir simulator. Experimentally measured relative permeability parameter values were used to generate distribution functions for parameter sampling. The parameter sensitivity study analyzed five different levels for each of the relative permeability model parameters. All but one of the parameters changed the CO 2 injectivity by <10%, less than the geostatistical uncertainty that applies to all large subsurface systems due to natural geophysical variability and inherently small sample sizes. The exception was the end-point CO 2 relative permeability, kmore » $$0\\atop{r}$$ CO2, the maximum attainable effective CO 2 permeability during CO 2 invasion, which changed CO2 injectivity by as much as 80%. Similarly, Monte Carlo simulation using 1000 realizations of relative permeability parameters showed no relationship between CO 2 injectivity and any of the parameters but k$$0\\atop{r}$$ CO2, which had a very strong (R 2 = 0.9685) power law relationship with total CO 2 injected. Model sensitivity to k$$0\\atop{r}$$ CO2 points to the importance of accurate core flood and wettability measurements.« less

An experimental study of basaltic glass-H2O-CO2 interaction at 22 and 50 °C: Implications for subsurface storage of CO2

NASA Astrophysics Data System (ADS)

Galeczka, Iwona; Wolff-Boenisch, Domenik; Oelkers, Eric H.; Gislason, Sigurdur R.

2014-02-01

A novel high pressure column flow reactor was used to investigate the evolution of solute chemistry along a 2.3 m flow path during pure water- and CO2-charged water-basaltic glass interaction experiments at 22 and 50 °C and 10-5.7 to 22 bars partial pressure of CO2. Experimental results and geochemical modelling showed the pH of injected pure water evolved rapidly from 6.7 to 9-9.5 and most of the iron released to the fluid phase was subsequently consumed by secondary minerals, similar to natural meteoric water-basalt systems. In contrast to natural systems, however, the aqueous aluminium concentration remained relatively high along the entire flow path. The aqueous fluid was undersaturated with respect to basaltic glass and carbonate minerals, but supersaturated with respect to zeolites, clays, and Fe hydroxides. As CO2-charged water replaced the alkaline fluid within the column, the fluid briefly became supersaturated with respect to siderite. Basaltic glass dissolution in the column reactor, however, was insufficient to overcome the pH buffer capacity of CO2-charged water. The pH of this CO2-charged water rose from an initial 3.4 to only 4.5 in the column reactor. This acidic reactive fluid was undersaturated with respect to carbonate minerals but supersaturated with respect to clays and Fe hydroxides at 22 °C, and with respect to clays and Al hydroxides at 50 °C. Basaltic glass dissolution in the CO2-charged water was closer to stoichiometry than in pure water. The mobility and aqueous concentration of several metals increased significantly with the addition of CO2 to the inlet fluid, and some metals, including Mn, Cr, Al, and As exceeded the allowable drinking water limits. Iron became mobile and the aqueous Fe2+/Fe3+ ratio increased along the flow path. Although carbonate minerals did not precipitate in the column reactor in response to CO2-charged water-basaltic glass interaction, once this fluid exited the reactor, carbonates precipitated as the fluid degassed at the outlet. Substantial differences were found between the results of geochemical modelling calculations and the observed chemical evolution of the fluids during the experiments. These differences underscore the need to improve the models before they can be used to predict with confidence the fate and consequences of carbon dioxide injected into the subsurface. The pH increase from 3.4 to 4.5 of the CO2-rich inlet fluid does not immobilize toxic elements at ambient temperature but immobilizes Al and Cr at 50 °C. This indicates that further neutralization of CO2-charged water is required for decreased toxic element mobility. The CO2-charged water injection enhances the mobility of redox sensitive Fe2+ significantly making it available for the storage of injected carbon as iron carbonate minerals. The precipitation of aluminosilicates likely occurred at a pH of 4.2-4.5 in CO2-charged waters. These secondary phases can (1) fill the available pore space and therefore clog the host rock in the vicinity of the injection well, and (2) incorporate some divalent cations limiting their availability for carbon storage. The inability of simple reactive transport models to describe accurately the fluid evolution in this well constrained one dimensional flow system suggests that significant improvements need to be made to such models before we can predict with confidence the fate and consequences of injecting carbon dioxide into the subsurface. Column reactors such as that used in this study could be used to facilitate ex situ carbon mineral storage. Carbonate precipitation at the outlet of the reactor suggests that the harvesting of divalent metals from rocks using CO2-charged waters could potentially be upscaled to an industrial carbonation process.

Reactive alteration of Mt. Simon sandstone during CO2-rich brine injection: A coupled experimental and modeling study

NASA Astrophysics Data System (ADS)

Dávila Ordoñez, M. G.; Zahasky, C.; Crandall, D.; Druhan, J. L.

2017-12-01

Thus far, one million metric tons of CO2 have been injected into the lower Mt. Simon formation as part of the Decatur CO2 Capture and Storage Project. Micro-seismic events were observed within the CO2 plume both during and after pressurization associated with the primary injection. The Mt. Simon reservoir rock consists of 76.5 wt.% quartz, 2.1 wt.% calcite, 17.3 wt.% K-feldspar, 1.1 wt.% chlorite, 0.7 wt.% illite and lesser extents of siderite, kaolinite, dolomite and marcasite, and is thus anticipated to become geochemically altered by exposure to acidified CO2-rich brine. However, the extent to which the geochemical reactivity contributes to structural weakening is unknown. To explore relationships between the principle geochemical reactions, evolution of fluid transport properties and physical alteration, we performed a series of flow-through experiments using Mt. Simon core (5 cm diameter, ranging from 4.3 - 8.6 cm length) and fluids representative of acidified reservoir brine. Experiments were operated under P = 1450 bar, Pconfining = 1900 - 3000 bar and T = 53 ºC conditions, and flow rates varied from 0.08 to 5.00 mL h-1 over a period of 166 h. A 2D reactive transport code (Crunch-Tope) was used to simulate these experiments, constrained by measured time series aqueous concentrations of Ca, Mg, S, Si, K and Fe and pH during the CO2-rich brine interaction. The model domain was divided into 30 nodes in x at a spacing of 0.12 cm, and 40 nodes in y at a spacing of 0.22 cm, and initial permeability measured for the core was specified and allowed to evolve over the course of the simulation using measured flow rate as a constraint. All relevant kinetic and thermodynamic reaction parameters were obtained from the literature. Solute time series from both experiments and simulations indicated that the acidified brine introduced continuously into the column promoted dissolution of K-feldspar, chloride, illite, pyrite and calcite, and the precipitation of Ca-, Fe- and Si -bearing secondary phases, resulting in a net porosity increase at the inlet. Despite this opening of the inlet pore space, permeability decreased over the length of the column (kfinal/kinitial = 0.76), thus altering local resistance to fluid phase pressure gradients.

Geological Sequestration of CO2 A Brief Overview and Potential for Application for Oklahoma

EPA Science Inventory

Geologic sequestration of CO2 is a component of C capture and storage (CCS), an emerging technology for reducing CO2 emissions to the atmosphere, and involves injection of captured CO2 into deep subsurface formations. Similar to the injection of hazardous wastes, before injection...

Intermediate Scale Laboratory Testing to Understand Mechanisms of Capillary and Dissolution Trapping during Injection and Post-Injection of CO 2 in Heterogeneous Geological Formations

DOE Office of Scientific and Technical Information (OSTI.GOV)

Illangasekare, Tissa; Trevisan, Luca; Agartan, Elif

2015-03-31

Carbon Capture and Storage (CCS) represents a technology aimed to reduce atmospheric loading of CO 2 from power plants and heavy industries by injecting it into deep geological formations, such as saline aquifers. A number of trapping mechanisms contribute to effective and secure storage of the injected CO 2 in supercritical fluid phase (scCO 2) in the formation over the long term. The primary trapping mechanisms are structural, residual, dissolution and mineralization. Knowledge gaps exist on how the heterogeneity of the formation manifested at all scales from the pore to the site scales affects trapping and parameterization of contributing mechanismsmore » in models. An experimental and modeling study was conducted to fill these knowledge gaps. Experimental investigation of fundamental processes and mechanisms in field settings is not possible as it is not feasible to fully characterize the geologic heterogeneity at all relevant scales and gathering data on migration, trapping and dissolution of scCO 2. Laboratory experiments using scCO 2 under ambient conditions are also not feasible as it is technically challenging and cost prohibitive to develop large, two- or three-dimensional test systems with controlled high pressures to keep the scCO 2 as a liquid. Hence, an innovative approach that used surrogate fluids in place of scCO 2 and formation brine in multi-scale, synthetic aquifers test systems ranging in scales from centimeter to meter scale developed used. New modeling algorithms were developed to capture the processes controlled by the formation heterogeneity, and they were tested using the data from the laboratory test systems. The results and findings are expected to contribute toward better conceptual models, future improvements to DOE numerical codes, more accurate assessment of storage capacities, and optimized placement strategies. This report presents the experimental and modeling methods and research results.« less

Experimental methods for the simulation of supercritical CO2 injection at laboratory scale aimed to investigate capillary trapping

NASA Astrophysics Data System (ADS)

Trevisan, L.; Illangasekare, T. H.; Rodriguez, D.; Sakaki, T.; Cihan, A.; Birkholzer, J. T.; Zhou, Q.

2011-12-01

Geological storage of carbon dioxide in deep geologic formations is being considered as a technical option to reduce greenhouse gas loading to the atmosphere. The processes associated with the movement and stable trapping are complex in deep naturally heterogeneous formations. Three primary mechanisms contribute to trapping; capillary entrapment due to immobilization of the supercritical fluid CO2 within soil pores, liquid CO2 dissolving in the formation water and mineralization. Natural heterogeneity in the formation is expected to affect all three mechanisms. A research project is in progress with the primary goal to improve our understanding of capillary and dissolution trapping during injection and post-injection process, focusing on formation heterogeneity. It is expected that this improved knowledge will help to develop site characterization methods targeting on obtaining the most critical parameters that capture the heterogeneity to design strategies and schemes to maximize trapping. This research combines experiments at the laboratory scale with multiphase modeling to upscale relevant trapping processes to the field scale. This paper presents the results from a set of experiments that were conducted in an intermediate scale test tanks. Intermediate scale testing provides an attractive alternative to investigate these processes under controlled conditions in the laboratory. Conducting these types of experiments is highly challenging as methods have to be developed to extrapolate the data from experiments that are conducted under ambient laboratory conditions to high temperatures and pressures settings in deep geologic formations. We explored the use of a combination of surrogate fluids that have similar density, viscosity contrasts and analogous solubility and interfacial tension as supercritical CO2-brine in deep formations. The extrapolation approach involves the use of dimensionless numbers such as Capillary number (Ca) and the Bond number (Bo). A set of experiments that captures some of the complexities of the geologic heterogeneity and injection scenarios are planned in a 4.8 m long tank. To test the experimental methods and instrumentation, a set of preliminary experiments were conducted in a smaller tank with dimensions 90 cm x 60 cm. The tank was packed to represent both homogeneous and heterogeneous conditions. Using the surrogate fluids, different injection scenarios were tested. Images of the migration plume showed the critical role that heterogeneity plays in stable entrapment. Destructive sampling done at the end of the experiments provided data on the final saturation distributions. Preliminary analysis suggests the entrapment configuration is controlled by the large-scale heterogeneities as well as the pore-scale entrapment mechanisms. The data was used in modeling analysis that is presented in a companion abstract.

Reactive Tracer Techniques to Quantitatively Monitor Carbon Dioxide Storage in Geologic Formations

NASA Astrophysics Data System (ADS)

Matter, J. M.; Carson, C.; Stute, M.; Broecker, W. S.

2012-12-01

Injection of CO2 into geologic storage reservoirs induces fluid-rock reactions that may lead to the mineralization of the injected CO2. The long-term safety of geologic CO2 storage is, therefore, determined by in situ CO2-fluid-rock reactions. Currently existing monitoring and verification techniques for CO2 storage are insufficient to characterize the solubility and reactivity of the injected CO2, and to establish a mass balance of the stored CO2. Dissolved and chemically transformed CO2 thus avoid detection. We developed and are testing a new reactive tracer technique for quantitative monitoring and detection of dissolved and chemically transformed CO2 in geologic storage reservoirs. The technique involves tagging the injected carbon with radiocarbon (14C). Carbon-14 is a naturally occurring radioisotope produced by cosmic radiation and made artificially by 14N neutron capture. The ambient concentration is very low with a 14C/12C ratio of 10-12. The concentration of 14C in deep geologic formations and fossil fuels is at least two orders of magnitude lower. This makes 14C an ideal quantitative tracer for tagging underground injections of anthropogenic CO2. We are testing the feasibility of this tracer technique at the CarbFix pilot injection site in Iceland, where approximately 2,000 tons of CO2 dissolved in water are currently injected into a deep basalt aquifer. The injected CO2 is tagged with 14C by dynamically adding calibrated amounts of H14CO3 solution to the injection stream. The target concentration is 12 Bq/kg of injected water, which results in a 14C activity that is 5 times enriched compared to the 1850 background. In addition to 14C as a reactive tracer, trifluormethylsulphur pentafluoride (SF5CF3) and sulfurhexafluoride (SF6) are used as conservative tracers to monitor the transport of the injected CO2 in the subsurface. Fluid samples are collected for tracer analysis from the injection and monitoring wells on a regular basis. Results show a fast reaction of the injected CO2 with the ambient reservoir fluid and rocks. Mixing and in situ CO2-water-rock reactions are detected by changes in the different tracer ratios. The feasibility of 14C as a reactive tracer for geologic CO2 storage also depends on the analytical technique used to measure 14C activities. Currently, 14C is analyzed using Accelerator Mass Spectrometery (AMS), which is expensive and requires centralized facilities. To enable real time online monitoring and verification, we are developing an alternative detection method for radiocarbon. The IntraCavity OptoGalvanic Spectroscopy (ICOGS) system is using a CO2 laser to detect carbon isotope ratios at environmental levels. Results from our prototype of this bench-top technology demonstrate that an ICOGS system can be used in a continuous mode with analysis times of the order of minutes, and can deliver data of similar quality as AMS.

The Iġnik Sikumi Field Experiment, Alaska North Slope: Design, operations, and implications for CO2−CH4 exchange in gas hydrate reservoirs

USGS Publications Warehouse

Boswell, Ray; Schoderbek, David; Collett, Timothy S.; Ohtsuki, Satoshi; White, Mark; Anderson, Brian J.

2017-01-01

The Iġnik Sikumi Gas Hydrate Exchange Field Experiment was conducted by ConocoPhillips in partnership with the U.S. Department of Energy, the Japan Oil, Gas and Metals National Corporation, and the U.S. Geological Survey within the Prudhoe Bay Unit on the Alaska North Slope during 2011 and 2012. The primary goals of the program were to (1) determine the feasibility of gas injection into hydrate-bearing sand reservoirs and (2) observe reservoir response upon subsequent flowback in order to assess the potential for CO2 exchange for CH4 in naturally occurring gas hydrate reservoirs. Initial modeling determined that no feasible means of injection of pure CO2 was likely, given the presence of free water in the reservoir. Laboratory and numerical modeling studies indicated that the injection of a mixture of CO2 and N2 offered the best potential for gas injection and exchange. The test featured the following primary operational phases: (1) injection of a gaseous phase mixture of CO2, N2, and chemical tracers; (2) flowback conducted at downhole pressures above the stability threshold for native CH4 hydrate; and (3) an extended (30-days) flowback at pressures near, and then below, the stability threshold of native CH4 hydrate. The test findings indicate that the formation of a range of mixed-gas hydrates resulted in a net exchange of CO2 for CH4 in the reservoir, although the complexity of the subsurface environment renders the nature, extent, and efficiency of the exchange reaction uncertain. The next steps in the evaluation of exchange technology should feature multiple well applications; however, such field test programs will require extensive preparatory experimental and numerical modeling studies and will likely be a secondary priority to further field testing of production through depressurization. Additional insights gained from the field program include the following: (1) gas hydrate destabilization is self-limiting, dispelling any notion of the potential for uncontrolled destabilization; (2) gas hydrate test wells must be carefully designed to enable rapid remediation of wellbore blockages that will occur during any cessation in operations; (3) sand production during hydrate production likely can be managed through standard engineering controls; and (4) reservoir heat exchange during depressurization was more favorable than expected—mitigating concerns for near-wellbore freezing and enabling consideration of more aggressive pressure reduction.

Strength and Deformation Behaviour of Cap Rocks Above the CO2SINK-Reservoir

NASA Astrophysics Data System (ADS)

Mutschler, T.; Triantafyllidis, T.; Balthasar, K.; Norden, B.

2009-04-01

The cap-rock of the CO2SINK storage site close to Ketzin consists of clay rich rocks which are typical for cap rock formations above CO2 storage reservoirs. The strength and deformation behaviour of such claystone samples are therefore of fundamental importance for the characterization of secure geological storage of CO2. The elastic and anelastic deformation behaviour limits the maximum injection pressure during CO2-injection and is part of the security measures for the long term storage of CO2. The laboratory experiments where performed on samples gathered from the injection well of the Ketzin pilot test site in Germany and are compared with the elastic and anelastic behaviour of samples from the same Keuper formation in a near-surface outcrop in the Southwest of Germany showing a similar lithology. The samples from the outcrop allowed drilling of samples with a standard size of 100 mm diameter and 200 mm height as well as large samples with a diameter of 550 mm and a height of 1200 mm. The investigations have a special emphasis on the viscous behaviour of the clay stones and its scaling behaviour. A special triaxial testing procedure is applied both on standard and large size samples allowing the determination of the strength, stiffness and viscosity behaviour of the rock in one experimental run. Multi-stage technique (stepwise variation of the confining pressure) gives the strength behaviour of each single sample while applying a constant deformation rate. Stepwise varied deformation rates on the other hand lead to steps in the stress-strain-curve from which the viscosity index is determined. The viscosity index is directly used in the Norton's constitutive relations for viscoplastic simulations. The combination of tests allows for the determination of a broad range of elastic and anelastic properties. The comparison of results - both for elastic and anelastic behaviour - from standard and large samples shows that for the examined rocks a scale effect is negligible. Transition from cataclastic to non-cataclastic behaviour - the transition limit - occurs in a similar range of applied levels of pressure and deformation rates even at room temperature. The obtained transition limit is very important for the judgment of the sealing capacity and integrity of the cap rock. The deformation rates predicted for the pressure and temperature conditions of the caprock at Ketzin test site are far beneath the determined transition limit during the injection and after stop of injection. As a 0° friction angle is used for pressure and deformation limit at Ketzin, the measured elastic and anelastic behaviour of the real caprock act as additional safety margin during injection and in the post injection phase. As the examined rocks are typical for many possible storage sites, the discussed results are of importance beyond the Ketzin Pilot Experiment CO2SINK.

Estimation of CO2 saturation during both CO2 drainage and imbibition processes based on both seismic velocity and electrical resistivity measurements

NASA Astrophysics Data System (ADS)

Kim, Jongwook; Nam, Myung Jin; Matsuoka, Toshifumi

2013-10-01

In order to monitor injected carbon dioxide (CO2), simultaneous measurements of seismic velocity and electrical resistivity are employed during the drainage (CO2 injection) and imbibition (water injection) processes of a Berea sandstone. Supercritical CO2 (10 MPa at 40 ºC) was injected into a water-saturated Berea sandstone in the drainage stage and monitored via simultaneous measurements. After the injection of supercritical CO2, fresh distilled water was injected into the CO2-injected sandstone during the imbibition stage. Electrical resistivity and P-wave velocity measurements acquired during the drainage and imbibition stages were employed to evaluate CO2 saturations (SCO2) based on the resistivity index and the Gassmann fluid-substitution equations, respectively. Comparing estimated values for SCO2 saturation against those from volume-derived SCO2, based on analysis on injected and drained fluid volumes in the drainage process, we conclude that Gassmann-Brie and resistivity index are suitable for the evaluation based on P-wave velocity and electrical resistivity, respectively. Rt-based estimation properly tracks the variation in SCO2 even when SCO2 is large (>0.15), while Vp-based estimation is sensitive to the variation in SCO2 when SCO2 is small (<0.1). Employing the Gassmann-Brie and resistivity index, estimation of variation in SCO2 based on the simultaneous measurements provides the upper and lower bounds of SCO2 even when SCO2 is large (>0.1), while properly estimating SCO2 when SCO2 is small (<0.1). Monitoring the CO2 imbibition process confirms residual CO2 saturation within the sample.

An Experimental Approach to CO2 Sequestration in Saline Aquifers: Application to Paradox Valley, CO

NASA Astrophysics Data System (ADS)

Rosenbauer, R. J.; Bischoff, J. L.; Koksalan, T.

2001-12-01

As part of a Bureau of Reclamation program to decrease the salt load of the lower Colorado River Paradox, Valley Brine (PVB) is being disposed of into the Leadville Formation via a deep-injection well, situated in southwest Colorado. A complex pre-injection process uses nano-filtration to minimize well-plugging scaling caused by elevated downhole temperatures and pressures. We address here the possibility of liquid carbon dioxide as an additive to the injection fluid in an attempt to increase formation porosity. We report here the CO2 solubility results of preliminary experiments on pure water and PVB. We used fixed-volume titanium and flexible gold-cell technology to (1) measure the solubility of CO2 in PVB from surface to downhole conditions and (2) investigate the geochemical interactions between CO2 - charged PVB and rocks from the Leadville Limestone. The apparatus is applicable to the general study of CO2 sequestration in deep-saline aquifers where the understanding of the interaction of CO2 - charged fluids and potential host rocks is important. The experimental procedure is an adaptation of the technology designed to study hydrothermal systems where seawater was reacted with basaltic rocks at high temperature and pressure. This procedure has been used extensively for the investigation of rock-water interactions and the determination of the solubilities of Na-K-Ca-Cl solutions over a wide range of temperature, pressure, and composition, along the vapor pressure curve and from beyond the critical point to the triple point. To validate the experimental design we calibrated the system with published data on the binary CO2 - pure water system. We obtained new data on the solubility of CO2 in pure water and PVB ( ~21% TDS) at 21° C and 50° C from 100 to 600 bars. At 21° C the solubility of CO2 (as wt% CO2/g fluid) in PVB is 2.2, 2.3, and 2.6 at 100, 300 and 600 bars pressure respectively contrasted with 6.5, 7.4 and 8.5 in pure water at similar pressures. At 50° C and the same pressures the solubility of CO2 in PVB is 1.9, 2.1, and 2.5 respectively. Pressure/solubility relations suggest that differences between the solubility of CO2 in pure water and PVB are not due to simple salting out effects. Experiments are underway to test a pure NaCl solution as an analog for PVB.

An Advanced Reservoir Simulator for Tracer Transport in Multicomponent Multiphase Compositional Flow and Applications to the Cranfield CO2 Sequestration Site

NASA Astrophysics Data System (ADS)

Moortgat, J.

2015-12-01

Reservoir simulators are widely used to constrain uncertainty in the petrophysical properties of subsurface formations by matching the history of injection and production data. However, such measurements may be insufficient to uniquely characterize a reservoir's properties. Monitoring of natural (isotopic) and introduced tracers is a developing technology to further interrogate the subsurface for applications such as enhanced oil recovery from conventional and unconventional resources, and CO2 sequestration. Oak Ridge National Laboratory has been piloting this tracer technology during and following CO2 injection at the Cranfield, Mississippi, CO2 sequestration test site. Two campaigns of multiple perfluorocarbon tracers were injected together with CO2 and monitored at two wells at 68 m and 112 m from the injection site. The tracer data suggest that multiple CO2 flow paths developed towards the monitoring wells, indicative of either channeling through high permeability pathways or of fingering. The results demonstrate that tracers provide an important complement to transient pressure data. Numerical modeling is essential to further explain and interpret the observations. To aid the development of tracer technology, we enhanced a compositional multiphase reservoir simulator to account for tracer transport. Our research simulator uses higher-order finite element (FE) methods that can capture the small-scale onset of fingering on the coarse grids required for field-scale modeling, and allows for unstructured grids and anisotropic heterogeneous permeability fields. Mass transfer between fluid phases and phase behavior are modeled with rigorous equation-of-state based phase-split calculations. We present our tracer simulator and preliminary results related to the Cranfield experiments. Applications to noble gas tracers in unconventional resources are presented by Darrah et al.

CO2 injection into fractured peridotites: a reactive percolation experiment

NASA Astrophysics Data System (ADS)

Escario, S.; Godard, M.; Gouze, P.; Leprovost, R.; Luquot, L.; Garcia-Rios, M.

2017-12-01

Mantle peridotites have the potential to trap CO2 as carbonates. This process observed in ophiolites and in oceanic environments provides a long term and safe storage for CO2. It occurs as a part of a complex suite of fluid-rock reactions involving silicate dissolution and precipitation of hydrous phases, carbonates and minor phases that may in turn modify the hydrodynamic properties and the reactivity of the reacted rocks. The efficiency and lastingness of the process require the renewal of fluids at the mineral-fluid interface. Fractures are dominant flow paths in exhumed mantle sections. This study aims at better understanding the effect of CO2-enriched saline fluids on hydrodynamic and chemical processes through fractured peridotites. Experiments were performed using the reactive percolation bench ICARE Lab 3 - Géosciences Montpellier. It allows monitoring the permeability changes during experiments. Effluents are recurrently sampled for analysing cation concentration, pH and alkalinity. Reacted rock samples were characterized by high resolution X-ray microtomography (ESRF ID19, Grenoble, France) and SEM. Experiments consisted in injecting CO2-enriched brines (NaCl 0.5 M) at a rate of 6 mL.h-1 into artificially fractured cores (9 mm diameter × 20 mm length) of Oman harzburgites at T=170°C and Ptotal = 25 MPa for up to 2 weeks. Fractures are of few µm apertures with rough walls. Three sets of experiments were performed at increasing value of [CO2] (0, 0.1 and 1 mol/kg). All experiments showed a decrease in permeability followed by steady state regime that can be caused by a decrease in the roughness of fracture walls (dissolution dominated process), thus favouring fracture closing, or by the precipitation of secondary phases. Maximum enrichments in Mg, Fe and Ca of the effluent fluids occur during the first 2 hours of the experiments whereas Si displays a maximum enrichment at t = 20 h, suggesting extensive dissolution. Maximum enrichments are observed with the highest values of the [CO2]. After one day, effluent fluid concentrations decrease and become constant. By analysing both the permeability and the outlet fluid concentration one can investigate the coupling processes controlling the transport and the reaction mechanisms that in turn act at maintaining the circulation in the fractures.

Single hole multi-parameter downhole monitoring of shallow CO2 injection at Maguelone experimental site (Languedoc, France)

NASA Astrophysics Data System (ADS)

Denchik, N.; Pezard, P. A.; Abdoulghafour, H.; Lofi, J.; Neyens, D.; Perroud, H.; Henry, G.; Rolland, B.

2015-12-01

The Maguelone experimental site for shallow subsurface hydrogeophysical monitoring, located along the Mediterranean Lido near Montpellier (Languedoc, France) has proven over the years to provide a unique setup to test gas storage monitoring methods at shallow depth. The presence of two small reservoirs (R1: 13-16 m and R2: 8-9 m) with impermeable boundaries provides an opportunity to study a saline formation for geological storage both in the field and in a laboratory context. This integrated monitoring concept was first applied at Maguelone for characterization of the reservoir state before and during N2 and CO2 injections as part of the MUSTANG FP7 project. Multimethod monitoring was shown to be sensitive to gas storage within a saline reservoir with clear data changes immediately after the beginning of injection. Pressure remains the first indicator of gas storage at ~8-9 m depth in a small permeable unit (gravels/shells) under the Holocene lagoonal sediments. A good correlation is also obtained between the resistivity response and geochemical parameters from pore fluid sampling (pH, minor and major cation concentrations) at this depth. On the basis of previous gas injection experiments, new holes were drilled as part of PANACEA (EC project) in 2014, including an injection hole targeted for injection at 8-9 m depth in the R2 reservoir in order to have gas injection and gas storage at the same depth, a single hole multi-parameter observatory, and a seismic source hole. A total volume of ~48 m3 of CO2 was injected over ~2 hours on December 4, 2014. The injection rate varied from 24 to 30 m3/h, with a well head pressure of 1.8 bars. All downhole monitoring technologies (resistivity, temperature, pressure, SP and seismic measurements) were combined in the single hole observatory. Such device allows monitoring the downhole system before and after injection and the gas migration from the injection hole, helping to characterize the transport mechanism. Decreasing the number of monitoring-measurements and verification (MMV) holes enables a significant decrease of gas leakage risk. This specific monitoring approach is expected to give information about the safety and reliability of CO2 storage operation that guarantees public acceptance.

Numerical modeling of experimental observations on gas formation and multi-phase flow of carbon dioxide in subsurface formations

NASA Astrophysics Data System (ADS)

Pawar, R.; Dash, Z.; Sakaki, T.; Plampin, M. R.; Lassen, R. N.; Illangasekare, T. H.; Zyvoloski, G.

2011-12-01

One of the concerns related to geologic CO2 sequestration is potential leakage of CO2 and its subsequent migration to shallow groundwater resources leading to geochemical impacts. Developing approaches to monitor CO2 migration in shallow aquifer and mitigate leakage impacts will require improving our understanding of gas phase formation and multi-phase flow subsequent to CO2 leakage in shallow aquifers. We are utilizing an integrated approach combining laboratory experiments and numerical simulations to characterize the multi-phase flow of CO2 in shallow aquifers. The laboratory experiments involve a series of highly controlled experiments in which CO2 dissolved water is injected in homogeneous and heterogeneous soil columns and tanks. The experimental results are used to study the effects of soil properties, temperature, pressure gradients and heterogeneities on gas formation and migration. We utilize the Finite Element Heat and Mass (FEHM) simulator (Zyvoloski et al, 2010) to numerically model the experimental results. The numerical models capture the physics of CO2 exsolution, multi-phase fluid flow as well as sand heterogeneity. Experimental observations of pressure, temperature and gas saturations are used to develop and constrain conceptual models for CO2 gas-phase formation and multi-phase CO2 flow in porous media. This talk will provide details of development of conceptual models based on experimental observation, development of numerical models for laboratory experiments and modelling results.

CO2 plume management in saline reservoir sequestration

USGS Publications Warehouse

Frailey, S.M.; Finley, R.J.

2011-01-01

A significant difference between injecting CO2 into saline aquifers for sequestration and injecting fluids into oil reservoirs or natural gas into aquifer storage reservoirs is the availability and use of other production and injection wells surrounding the primary injection well(s). Of major concern for CO2 sequestration using a single well is the distribution of pressure and CO2 saturation within the injection zone. Pressure is of concern with regards to caprock integrity and potential migration of brine or CO2 outside of the injection zone, while CO2 saturation is of interest for storage rights and displacement efficiency. For oil reservoirs, the presence of additional wells is intended to maximize oil recovery by injecting CO2 into the same hydraulic flow units from which the producing wells are withdrawing fluids. Completing injectors and producers in the same flow unit increases CO2 throughput, maximizes oil displacement efficiency, and controls pressure buildup. Additional injectors may surround the CO2 injection well and oil production wells in order to provide external pressure to these wells to prevent the injected CO2 from migrating from the pattern between two of the producing wells. Natural gas storage practices are similar in that to reduce the amount of "cushion" gas and increase the amount of cycled or working gas, edge wells may be used for withdrawal of gas and center wells used for gas injection. This reduces loss of gas to the formation via residual trapping far from the injection well. Moreover, this maximizes the natural gas storage efficiency between the injection and production wells and reduces the areal extent of the natural gas plume. Proposed U.S. EPA regulations include monitoring pressure and suggest the "plume" may be defined by pressure in addition to the CO2 saturated area. For pressure monitoring, it seems that this can only be accomplished by injection zone monitoring wells. For pressure, these wells would not need to be very close to the injection well, compared to monitoring wells intended to measure CO2 saturation via fluid sampling or cased-hole well logs. If pressure monitoring wells become mandated, these wells could be used for managing the CO2 saturation and aquifer pressure distribution. To understand the relevance and effectiveness of producing and injecting brine to improve storage efficiency, direct the plume to specific pore space, and redistribute the pressure, numerical models of CO2 injection into aquifers are used. Simulated cases include various aquifer properties at a single well site and varying the number and location of surrounding wells for plume management. Strategies in terms of completion intervals can be developed to effectively contact more vertical pore space in relatively thicker geologic formations. Inter-site plume management (or cooperative) wells for the purpose of pressure monitoring and plume management may become the responsibility of a consortium of operators or a government entity, not individual sequestration site operators. ?? 2011 Published by Elsevier Ltd.

Modelling gas transport in the shallow subsurface in the Maguelone field experiment

NASA Astrophysics Data System (ADS)

Basirat, Farzad; Niemi, Auli; Perroud, Hervé; Lofi, Johanna; Denchik, Nataliya; Lods, Gérard; Pezard, Philippe; Sharma, Prabhakar; Fagerlund, Fritjof

2013-04-01

Developing reliable monitoring techniques to detect and characterize CO2 leakage in shallow subsurface is necessary for the safety of any GCS project. To test different monitoring techniques, shallow injection-monitoring experiment have and are being carried out at the Maguelone, along the Mediterranean lido of the Gulf of Lions, near Montpellier, France. This experimental site was developed in the context of EU FP7 project MUSTANG and is documented in Lofi et al. (2012). Gas injection experiments are being carried out and three techniques of pressure, electrical resistivity and seismic monitoring have been used to detect the nitrogen and CO2 release in the near surface environment. In the present work we use the multiphase and multicomponent TOUGH2/EOS7CA model to simulate the gaseous nitrogen and CO2 transport of the experiments carried out so far. The objective is both to gain understanding of the system performance based on the model analysis as well as to further develop and validate modelling approaches for gas transport in the shallow subsurface, against the well-controlled data sets. Numerical simulation can also be used for the prediction of experimental setup limitations. We expect the simulations to represent the breakthrough time for the different tested injection rates. Based on the hydrogeological formation data beneath the lido, we also expect the vertical heterogeneities in grain size distribution create an effective capillary barrier against upward gas transport in numerical simulations. Lofi J., Pezard P.A., Bouchette F., Raynal O., Sabatier P., Denchik N., Levannier A., Dezileau L., and Certain R. Integrated onshore-offshore geophysical investigation of a layered coastal aquifer, NW Mediterranean. Ground Water, (2012).

Injection of CO2-saturated water through a siliceous sandstone plug from the Hontomin test site (Spain): experiment and modeling.

PubMed

Canal, J; Delgado, J; Falcón, I; Yang, Q; Juncosa, R; Barrientos, V

2013-01-02

Massive chemical reactions are not expected when injecting CO(2) in siliceous sandstone reservoirs, but their performance can be challenged by small-scale reactions and other processes affecting their transport properties. We have conducted a core flooding test with a quartzarenite plug of Lower Cretaceous age representative of the secondary reservoir of the Hontomín test site. The sample, confined at high pressure, was successively injected with DIW and CO(2)-saturated DIW for 49 days while monitoring geophysical, chemical, and hydrodynamic parameters. The plug experienced little change, without evidence of secondary carbonation. However, permeability increased by a factor of 4 (0.022-0.085 mD), and the V(P)/V(S) ratio, whose change is related with microcracking, rose from ~1.68 to ~1.8. Porosity also increased (7.33-8.1%) from the beginning to the end of the experiment. Fluid/rock reactions were modeled with PHREEQC-2, and they are dominated by the dissolution of Mg-calcite. Mass balances show that ~4% of the initial carbonate was consumed. The results suggest that mineral dissolution and microcracking may have acted in a synergistic way at the beginning of the acidic flooding. However, dissolution processes concentrated in pore throats can better explain the permeability enhancement observed over longer periods of time.

Review: Role of chemistry, mechanics, and transport on well integrity in CO 2 storage environments

DOE PAGES

Carroll, Susan A.; Carey, William J.; Dzombak, David; ...

2016-03-22

Among the various risks associated with CO 2 storage in deep geologic formations, wells are important potential pathways for fluid leaks and groundwater contamination. Injection of CO 2 will perturb the storage reservoir and any wells that penetrate the CO 2 or pressure footprints are potential pathways for leakage of CO 2 and/or reservoir brine. Well leakage is of particular concern for regions with a long history of oil and gas exploration because they are top candidates for geologic CO 2storage sites. This review explores in detail the ability of wells to retain their integrity against leakage with careful examinationmore » of the coupled physical and chemical processes involved. Understanding time-dependent leakage is complicated by the changes in fluid flow, solute transport, chemical reactions, and mechanical stresses over decade or longer time frames for site operations and monitoring. Almost all studies of the potential for well leakage have been laboratory based, as there are limited data on field-scale leakage. When leakage occurs by diffusion only, laboratory experiments show that while CO 2 and CO 2-saturated brine react with cement and casing, the rate of degradation is transport-limited and alteration of cement and casing properties is low. When a leakage path is already present due to cement shrinkage or fracturing, gaps along interfaces (e.g. casing/cement or cement/rock), or casing failures, chemical and mechanical alteration have the potential to decrease or increase leakage risks. Laboratory experiments and numerical simulations have shown that mineral precipitation or closure of strain-induced fractures can seal a leak pathway over time or conversely open pathways depending on flow-rate, chemistry, and the stress state. Experiments with steel/cement and cement/rock interfaces have indicated that protective mechanisms such as metal passivation, chemical alteration, mechanical deformation, and pore clogging can also help mitigate leakage. The specific rate and nature of alteration depends on the cement, brine, and injected fluid compositions. For example, the presence of co-injected gases (e.g. O 2, H 2S, and SO 2) and pozzolan amendments (fly ash) to cement influences the rate and the nature of cement reactions. A more complete understanding of the coupled physical-chemical mechanisms involved with sealing and opening of leakage pathways is needed. An important challenge is to take empirically based chemical, mechanical, and transport models reviewed here and assess leakage risk for carbon storage at the field scale. Furthermore, field observations to accompany laboratory and modeling studies are critical to validating understanding of leakage risk. Long-term risk at the field scale is an area of active research made difficult by the large variability of material types (cement, geologic material, casing), field conditions (pressure, temperature, gradient in potential, residence time), and leaking fluid composition (CO 2, co-injected gases, brine). Of particular interest are the circumstances when sealing and other protective mechanisms are likely to be effective, when they are likely to fail, and the zone of uncertainty between these two extremes.« less

Radiocarbon as a Reactive Tracer for Tracking Permanent CO 2 Storage in Basaltic Rocks

DOE Office of Scientific and Technical Information (OSTI.GOV)

Matter, Juerg; Stute, Martin; Schlosser, Peter

In view of concerns about the long-term integrity and containment of CO 2 storage in geologic reservoirs, many efforts have been made to improve the monitoring, verification and accounting methods for geologically stored CO 2. Our project aimed to demonstrate that carbon-14 ( 14C) could be used as a reactive tracer to monitor geochemical reactions and evaluate the extent of mineral trapping of CO 2 in basaltic rocks. The capacity of a storage reservoir for mineral trapping of CO 2 is largely a function of host rock composition. Mineral carbonation involves combining CO 2 with divalent cations including Ca 2+,more » Mg 2+ and Fe 2+. The most abundant geological sources for these cations are basaltic rocks. Based on initial storage capacity estimates, we know that basalts have the necessary capacity to store million to billion tons of CO 2 via in situ mineral carbonation. However, little is known about CO2-fluid-rock reactions occurring in a basaltic storage reservoir during and post-CO 2 injection. None of the common monitoring and verification techniques have been able to provide a surveying tool for mineral trapping. The most direct method for quantitative monitoring and accounting involves the tagging of the injected CO 2 with 14C because 14C is not present in deep geologic reservoirs prior to injection. Accordingly, we conducted two CO 2 injection tests at the CarbFix pilot injection site in Iceland to study the feasibility of 14C as a reactive tracer for monitoring CO 2-fluid-rock reactions and CO 2 mineralization. Our newly developed monitoring techniques, using 14C as a reactive tracer, have been successfully demonstrated. For the first time, permanent and safe disposal of CO 2 as environmentally benign carbonate minerals in basaltic rocks could be shown. Over 95% of the injected CO 2 at the CarbFix pilot injection site was mineralized to carbonate minerals in less than two years after injection. Our monitoring results confirm that CO 2 mineralization in basaltic rocks is far faster than previously postulated.« less

Multiwell CO2 injectivity: impact of boundary conditions and brine extraction on geologic CO2 storage efficiency and pressure buildup.

PubMed

Heath, Jason E; McKenna, Sean A; Dewers, Thomas A; Roach, Jesse D; Kobos, Peter H

2014-01-21

CO2 storage efficiency is a metric that expresses the portion of the pore space of a subsurface geologic formation that is available to store CO2. Estimates of storage efficiency for large-scale geologic CO2 storage depend on a variety of factors including geologic properties and operational design. These factors govern estimates on CO2 storage resources, the longevity of storage sites, and potential pressure buildup in storage reservoirs. This study employs numerical modeling to quantify CO2 injection well numbers, well spacing, and storage efficiency as a function of geologic formation properties, open-versus-closed boundary conditions, and injection with or without brine extraction. The set of modeling runs is important as it allows the comparison of controlling factors on CO2 storage efficiency. Brine extraction in closed domains can result in storage efficiencies that are similar to those of injection in open-boundary domains. Geomechanical constraints on downhole pressure at both injection and extraction wells lower CO2 storage efficiency as compared to the idealized scenario in which the same volumes of CO2 and brine are injected and extracted, respectively. Geomechanical constraints should be taken into account to avoid potential damage to the storage site.

A Multi-scale Approach for CO2 Accounting and Risk Analysis in CO2 Enhanced Oil Recovery Sites

NASA Astrophysics Data System (ADS)

Dai, Z.; Viswanathan, H. S.; Middleton, R. S.; Pan, F.; Ampomah, W.; Yang, C.; Jia, W.; Lee, S. Y.; McPherson, B. J. O. L.; Grigg, R.; White, M. D.

2015-12-01

Using carbon dioxide in enhanced oil recovery (CO2-EOR) is a promising technology for emissions management because CO2-EOR can dramatically reduce carbon sequestration costs in the absence of greenhouse gas emissions policies that include incentives for carbon capture and storage. This study develops a multi-scale approach to perform CO2 accounting and risk analysis for understanding CO2 storage potential within an EOR environment at the Farnsworth Unit of the Anadarko Basin in northern Texas. A set of geostatistical-based Monte Carlo simulations of CO2-oil-water flow and transport in the Marrow formation are conducted for global sensitivity and statistical analysis of the major risk metrics: CO2 injection rate, CO2 first breakthrough time, CO2 production rate, cumulative net CO2 storage, cumulative oil and CH4 production, and water injection and production rates. A global sensitivity analysis indicates that reservoir permeability, porosity, and thickness are the major intrinsic reservoir parameters that control net CO2 injection/storage and oil/CH4 recovery rates. The well spacing (the distance between the injection and production wells) and the sequence of alternating CO2 and water injection are the major operational parameters for designing an effective five-spot CO2-EOR pattern. The response surface analysis shows that net CO2 injection rate increases with the increasing reservoir thickness, permeability, and porosity. The oil/CH4 production rates are positively correlated to reservoir permeability, porosity and thickness, but negatively correlated to the initial water saturation. The mean and confidence intervals are estimated for quantifying the uncertainty ranges of the risk metrics. The results from this study provide useful insights for understanding the CO2 storage potential and the corresponding risks of commercial-scale CO2-EOR fields.

Reactive Transport Models with Geomechanics to Mitigate Risks of CO2 Utilization and Storage

DOE Office of Scientific and Technical Information (OSTI.GOV)

Deo, Milind; Huang, Hai; Kweon, Hyukmin

2016-03-28

Reactivity of carbon dioxide (CO 2), rocks and brine is important in a number of practical situations in carbon dioxide sequestration. Injectivity of CO 2 will be affected by near wellbore dissolution or precipitation. Natural fractures or faults containing specific minerals may reactivate leading to induced seismicity. In this project, we first examined if the reactions between CO 2, brine and rocks affect the nature of the porous medium and properties including petrophysical properties in the timeframe of the injection operations. This was done by carrying out experiments at sequestration conditions (2000 psi for corefloods and 2400 psi for batchmore » experiments, and 600°C) with three different types of rocks – sandstone, limestone and dolomite. Experiments were performed in batch mode and corefloods were conducted over a two-week period. Batch experiments were performed with samples of differing surface area to understand the impact of surface area on overall reaction rates. Toughreact, a reactive transport model was used to interpret and understand the experimental results. The role of iron in dissolution and precipitation reactions was observed to be significant. Iron containing minerals – siderite and ankerite dissolved resulting in changes in porosity and permeability. Corefloods and batch experiments revealed similar patterns. With the right cationic balance, there is a possibility of precipitation of iron bearing carbonates. The results indicate that during injection operations mineralogical changes may lead to injectivity enhancements near the wellbore and petrophysical changes elsewhere in the system. Limestone and dolomite cores showed consistent dissolution at the entrance of the core. The dissolution led to formation of wormholes and interconnected dissolution zones. Results indicate that near wellbore dissolution in these rock-types may lead to rock failure. Micro-CT images of the cores before and after the experiments revealed that an initial high-permeability pathway facilitated the formation of wormholes. The peak cation concentrations and general trends were matched using Toughreact. Batch reactor modeling showed that the geometric factors obtained using powder data that related effective surface area to the BET surface area had to be reduced for fractured samples and cores. This indicates that the available surface area in consolidated samples is lower than that deduced from powder experiments. Field-scale modeling of reactive transport and geomechanics was developed in parallel at Idaho National Laboratory. The model is able to take into account complex chemistry, and consider interactions of natural fractures and faults. Poroelastic geomechanical considerations are also included in the model.« less

CarbFix I: Rapid CO2 mineralization in basalt for permanent carbon storage

NASA Astrophysics Data System (ADS)

Matter, J. M.; Stute, M.; Snæbjörnsdóttir, S.; Gíslason, S. R.; Oelkers, E. H.; Sigfússon, B.; Gunnarsson, I.; Aradottir, E. S.; Gunnlaugsson, E.; Broecker, W. S.

2015-12-01

Carbon dioxide mineralization via CO2-fluid-rock reactions provides the most permanent solution for geologic CO2 storage. Basalts, onshore or offshore, have the potential to store million metric tons of CO2 as (Ca, Mg, Fe) carbonates [1, 2]. However, as of today it was unclear how fast CO2 is converted to carbonate minerals in-situ in a basalt storage reservoir. The CarbFix I project in Iceland was designed to verify in-situ CO2 mineralization in basaltic rocks. Two injection tests were performed at the CarbFix I pilot injection site near the Hellisheidi geothermal power plant in 2012. 175 tons of pure CO2 and 73 tons of a CO2+H2S mixture were injection from January to March 2012 and in June 2013, respectively. The gases were injected fully dissolved in groundwater into a permeable basalt formation between 400 and 800 m depth using a novel CO2 injection system. Using conservative (SF6, SF5CF3) and reactive (14C) tracers, we quantitatively monitor and detect dissolved and chemically transformed CO2. Tracer breakthrough curves obtained from the first monitoring well indicate that the injected solution arrived in a fast short pulse and a late broad peak. Ratios of 14C/SF6, 14C/SF5CF3 or DIC/SF6 and DIC/SF5CF3 are significantly lower in the monitoring well compared to the injection well, indicating that the injected dissolved CO2 reacted. Mass balance calculations using the tracer data reveal that >95% of the injected CO2 has been mineralized over a period of two years. Evidence of carbonate precipitation has been found in core samples that were collected from the storage reservoir using wireline core drilling as well as in and on the submersible pump in the monitoring well. Results from the core analysis will be presented with emphasis on the CO2 mineralization. [1] McGrail et al. (2006) JGR 111, B12201; [2] Goldberg et al. (2008) PNAS 105(29), 9920-9925.

Our trial to develop a risk assessment tool for CO2 geological storage (GERAS-CO2GS)

NASA Astrophysics Data System (ADS)

Tanaka, A.; Sakamoto, Y.; Komai, T.

2012-12-01

We will introduce our researches about to develop a risk assessment tool named 'GERAS-CO2GS' (Geo-environmental Risk Assessment System, CO2 Geological Storage Risk Assessment System) for 'Carbon Dioxide Geological Storage (Geological CCS)'. It aims to facilitate understanding of size of impact of risks related with upper migration of injected CO2. For gaining public recognition about feasibility of Geological CCS, quantitative estimation of risks is essential, to let public knows the level of the risk: whether it is negligible or not. Generally, in preliminary hazard analysis procedure, potential hazards could be identified within Geological CCS's various facilities such as: reservoir, cap rock, upper layers, CO2 injection well, CO2 injection plant and CO2 transport facilities. Among them, hazard of leakage of injected C02 is crucial, because it is the clue to estimate risks around a specific injection plan in terms of safety, environmental protection effect and economy. Our risk assessment tool named GERAS-CO2GS evaluates volume and rate of retention and leakage of injected CO2 in relation with fractures and/or faults, and then it estimates impact of seepages on the surface of the earth. GERAS-CO2GS has four major processing segments: (a) calculation of CO2 retention and leakage volume and rate, (b) data processing of CO2 dispersion on the surface and ambient air, (c) risk data definition and (d) evaluation of risk. Concerning to the injection site, we defined a model, which is consisted from an injection well and a geological strata model: which involves a reservoir, a cap rock, an upper layer, faults, seabed, sea, the surface of the earth and the surface of the sea. For retention rate of each element of CO2 injection site model, we use results of our experimental and numerical studies on CO2 migration within reservoirs and faults with specific lithological conditions. For given CO2 injection rate, GERAS-CO2GS calculates CO2 retention and leakage of each segment of injection site model. It also evaluates dispersion of CO2 on the surface of the earth and ambient air, and displays evaluated risk level on Goole earth contour of risk levels with color classification. As regard with numerical estimation of CO2's surface dispersion, we use ADMER 2.5 (Atmospheric Dispersion Model for Exposure and Risk Assessment, AIST), which assesses ambient dispersion of materials using real observed atmospheric data such as wind direction and temperatures by meteorological observatory. As far as our simulations, it is obvious that cause of Lake Nyos type accident is owes its maar topography of the lake and the volume and duration of the CO2 outburst (about 1 km3). It's unlikely to cause similar happenings in geological CCS site, because there are significant difference amount of CO2 and topography. At this moment, GERAS-CO2GS is prototype system. We are going to extend GERAS-CO2GS functions and evaluate risks of further risk scenarios. Concerning to the route of seabed to sea and the surface of the sea, we hope to implement outer research findings into our logics. In the course of further research, we are going to develop GERAS-CO2GS will be able to estimate broader risks, and to contribute to the efforts for legislations and standards of CO2 Geological storage.

Metal mobility and toxicity to microalgae associated with acidification of sediments: CO2 and acid comparison.

PubMed

De Orte, M R; Lombardi, A T; Sarmiento, A M; Basallote, M D; Rodriguez-Romero, A; Riba, I; Del Valls, A

2014-05-01

The injection and storage of CO2 into marine geological formations has been suggested as a mitigation measure to prevent global warming. However, storage leaks are possible resulting in several effects in the ecosystem. Laboratory-scale experiments were performed to evaluate the effects of CO2 leakage on the fate of metals and on the growth of the microalgae Phaeodactylum tricornutum. Metal contaminated sediments were collected and submitted to acidification by means of CO2 injection or by adding HCl. Sediments elutriate were prepared to perform toxicity tests. The results showed that sediment acidification enhanced the release of metals to elutriates. Iron and zinc were the metals most influenced by this process and their concentration increased greatly with pH decreases. Diatom growth was inhibited by both processes: acidification and the presence of metals. Data obtained is this study is useful to calculate the potential risk of CCS activities to the marine environment. Copyright © 2013 Elsevier Ltd. All rights reserved.

Influence of local capillary trapping on containment system effectiveness

DOE Office of Scientific and Technical Information (OSTI.GOV)

Bryant, Steven

2014-03-31

Immobilization of CO 2 injected into deep subsurface storage reservoirs is a critical component of risk assessment for geologic CO 2 storage (GCS). Local capillary trapping (LCT) is a recently established mode of immobilization that arises when CO 2 migrates due to buoyancy through heterogeneous storage reservoirs. This project sought to assess the amount and extent of LCT expected in storage formations under a range of injection conditions, and to confirm the persistence of LCT if the seal overlying the reservoir were to lose its integrity. Numerical simulation using commercial reservoir simulation software was conducted to assess the influence ofmore » injection. Laboratory experiments, modeling and numerical simulation were conducted to assess the effect of compromised seal integrity. Bench-scale (0.6 m by 0.6 m by 0.03 m) experiments with surrogate fluids provided the first empirical confirmation of the key concepts underlying LCT: accumulation of buoyant nonwetting phase at above residual saturations beneath capillary barriers in a variety of structures, which remains immobile under normal capillary pressure gradients. Immobilization of above-residual saturations is a critical distinction between LCT and the more familiar “residual saturation trapping.” To estimate the possible extent of LCT in a storage reservoir an algorithm was developed to identify all potential local traps, given the spatial distribution of capillary entry pressure in the reservoir. The algorithm assumes that the driving force for CO 2 migration can be represented as a single value of “critical capillary entry pressure” P c,entry crit, such that cells with capillary entry pressure greater/less than P c,entry crit act as barriers/potential traps during CO 2 migration. At intermediate values of P c,entry crit, the barrier regions become more laterally extensive in the reservoir, approaching a percolation threshold while non-barrier regions remain numerous. The maximum possible extent of LCT thus occurs at P c,entry crit near this threshold. Testing predictions of this simple algorithm against full-physics simulations of buoyancy-driven CO 2 migration support the concept of critical capillary entry pressure. However, further research is needed to determine whether a single value of critical capillary entry pressure always applies and how that value can be determined a priori. Simulations of injection into high-resolution (cells 0.3 m on a side) 2D and 3D heterogeneous domains show two characteristic behaviors. At small gravity numbers (vertical flow velocity much less than horizontal flow velocity) the CO 2 fills local traps as well as regions that would act as local barriers if CO 2 were moving only due to buoyancy. When injection ceases, the CO 2 migrates vertically to establish large saturations within local traps and residual saturation elsewhere. At large gravity numbers, the CO 2 invades a smaller portion of the perforated interval. Within this smaller swept zone the local barriers are not invaded, but local traps are filled to large saturation during injection and remain during post-injection gravity-driven migration. The small gravity number behavior is expected in the region within 100 m of a vertical injection well at anticipated rates of injection for commercial GCS. Simulations of leakage scenarios (through-going region of large permeability imposed in overlying seal) indicate that LCT persists (i.e. CO 2 remains held in a large fraction of the local iv traps) and the persistence is independent of injection rate during storage. Simulations of leakage for the limiting case of CO 2 migrating vertically from an areally extensive emplacement in the lower portion of a reservoir showed similar strong persistence of LCT. This research has two broad implications for GCS. The first is that LCT can retain a significant fraction of the CO 2 stored in a reservoir – above and beyond the residual saturation -- if the overlying seal were to fail. Thus frameworks for risk assessment should be extended to account for LCT. The second implication is that compared to pressure driven flow in reservoirs, CO 2 migration and trapping behave in a qualitatively different manner in heterogeneous reservoirs when buoyancy is the dominant driving force for flow. Thus simulations of GCS that neglect capillary heterogeneity will fail to capture important features of the CO 2 plume. While commercial reservoir simulation software can account for fine scale capillary heterogeneity, it has not been designed to work efficiently with such domains, and no simulators can handle fine-scale resolution throughout the reservoir. A possible way to upscale the migration and trapping is to apply an “effective residual saturation” to coarse-scale grids. While the extent of overall immobilization can be correlated in this way, all coarser grids failed to capture the distance traveled by the migrating CO 2 for large gravity number. Thus it remains unclear how best to account for LCT in the routine simulation work-flow that will be needed for large-scale GCS. Alternatives meriting investigation include streamline methods, reduced-physics proxies (e.g. particle tracking), and biased invasion percolation algorithms, which are based on precisely the capillary heterogeneity essential for LCT.« less

CO 2 water-alternating-gas injection for enhanced oil recovery: Optimal well controls and half-cycle lengths

DOE PAGES

Chen, Bailian; Reynolds, Albert C.

2018-03-11

We report that CO 2 water-alternating-gas (WAG) injection is an enhanced oil recovery method designed to improve sweep efficiency during CO 2 injection with the injected water to control the mobility of CO 2 and to stabilize the gas front. Optimization of CO 2 -WAG injection is widely regarded as a viable technique for controlling the CO 2 and oil miscible process. Poor recovery from CO 2 -WAG injection can be caused by inappropriately designed WAG parameters. In previous study (Chen and Reynolds, 2016), we proposed an algorithm to optimize the well controls which maximize the life-cycle net-present-value (NPV). However,more » the effect of injection half-cycle lengths for each injector on oil recovery or NPV has not been well investigated. In this paper, an optimization framework based on augmented Lagrangian method and the newly developed stochastic-simplex-approximate-gradient (StoSAG) algorithm is proposed to explore the possibility of simultaneous optimization of the WAG half-cycle lengths together with the well controls. Finally, the proposed framework is demonstrated with three reservoir examples.« less

CO 2 water-alternating-gas injection for enhanced oil recovery: Optimal well controls and half-cycle lengths

DOE Office of Scientific and Technical Information (OSTI.GOV)

Chen, Bailian; Reynolds, Albert C.

We report that CO 2 water-alternating-gas (WAG) injection is an enhanced oil recovery method designed to improve sweep efficiency during CO 2 injection with the injected water to control the mobility of CO 2 and to stabilize the gas front. Optimization of CO 2 -WAG injection is widely regarded as a viable technique for controlling the CO 2 and oil miscible process. Poor recovery from CO 2 -WAG injection can be caused by inappropriately designed WAG parameters. In previous study (Chen and Reynolds, 2016), we proposed an algorithm to optimize the well controls which maximize the life-cycle net-present-value (NPV). However,more » the effect of injection half-cycle lengths for each injector on oil recovery or NPV has not been well investigated. In this paper, an optimization framework based on augmented Lagrangian method and the newly developed stochastic-simplex-approximate-gradient (StoSAG) algorithm is proposed to explore the possibility of simultaneous optimization of the WAG half-cycle lengths together with the well controls. Finally, the proposed framework is demonstrated with three reservoir examples.« less

CO2 migration in the vadose zone: experimental and numerical modelling of controlled gas injection

NASA Astrophysics Data System (ADS)

gasparini, andrea; credoz, anthony; grandia, fidel; garcia, david angel; bruno, jordi

2014-05-01

The mobility of CO2 in the vadose zone and its subsequent transfer to the atmosphere is a matter of concern in the risk assessment of the geological storage of CO2. In this study the experimental and modelling results of controlled CO2 injection are reported to better understanding of the physical processes affecting CO2 and transport in the vadose zone. CO2 was injected through 16 micro-injectors during 49 days of experiments in a 35 m3 experimental unit filled with sandy material, in the PISCO2 facilities at the ES.CO2 centre in Ponferrada (North Spain). Surface CO2 flux were monitored and mapped periodically to assess the evolution of CO2 migration through the soil and to the atmosphere. Numerical simulations were run to reproduce the experimental results, using TOUGH2 code with EOS7CA research module considering two phases (gas and liquid) and three components (H2O, CO2, air). Five numerical models were developed following step by step the injection procedure done at PISCO2. The reference case (Model A) simulates the injection into a homogeneous soil(homogeneous distribution of permeability and porosity in the near-surface area, 0.8 to 0.3 m deep from the atmosphere). In another model (Model B), four additional soil layers with four specific permeabilities and porosities were included to predict the effect of differential compaction on soil. To account for the effect of higher soil temperature, an isothermal simulation called Model C was also performed. Finally, the assessment of the rainfall effects (soil water saturation) on CO2 emission on surface was performed in models called Model D and E. The combined experimental and modelling approach shows that CO2 leakage in the vadose zone quickly comes out through preferential migration pathways and spots with the ranges of fluxes in the ground/surface interface from 2.5 to 600 g·m-2·day-1. This gas channelling is mainly related to soil compaction and climatic perturbation. This has significant implications to design adapted detection and monitoring strategies of early leakage in commercial CO2 storage. The presence of soils with different compactions at surface influences the CO2 dispersion. The inclusion of soils with different permeability, porosity and liquid saturation results in preferential pathways. The formation of preferential pathways in the soil and hot spots on the surface has commonly been observed in natural systems where deep CO2 fluxes interact with shallow aquifers. Increase of ambient temperature increases CO2 fluxes intensity whereas rainfall decreases CO2 emission in gas phase and trap it as aqueous species in the porous media of the soil. A good accuracy has been obtained for surface CO2 fluxes location and intensity between experimental and modelling results taking into account the selected equation of state, the soil characteristics and the operational conditions. Phenomena of compaction and preferential pathways located only in the first centimetres of the soil can explain the heterogeneity of CO2 fluxes in the 16 m2 surface area of PISCO2 experimental platform.

FTIR study of CO2 and H2O/CO2 nanoparticles and their temporal evolution at 80 K.

PubMed

Taraschewski, M; Cammenga, H K; Tuckermann, R; Bauerecker, S

2005-04-21

Fourier transform infrared (FTIR) spectroscopy combined with a long-path collisional cooling cell was used to investigate the temporal evolution of CO2 nanoparticles and binary H2O/CO2 nanocomposites in the aerosol phase at 80 K. The experimental conditions for the formation of different CO2 particle shapes as slab, shell, sphere, cube, and needle have been studied by comparison with calculated data from the literature. The H2O/CO2 nanoparticles were generated with a newly developed multiple-pulse injection technique and with the simpler flow-in technique. The carbon dioxide nu3-vibration band at 2360 cm(-1) and the water ice OH-dangling band at 3700 cm(-1) were used to study the evolution of structure, shape, and contact area of the nanocomposites over 150 s. Different stages of binary nanocomposites with primary water ice cores were identified dependent on the injected CO2 portion: (a) disordered (amorphous) CO2 slabs on water particle surfaces, (b) globular crystalline CO2 humps sticking on the water cores, and (c) water cores being completely enclosed in bigger predominantly crystalline CO2 nanoparticles. However, regular CO2 shell structures on primary water particles showing both longitudinal (LO) and transverse (TO) optical mode features of the nu3-vibration band could not be observed. Experiments with reversed nucleation order indicate that H2O/CO2 composite particles with different initial structures evolve toward similar molecular nanocomposites with separated CO2 and H2O regions.

The Effect of fluid buoyancy and fracture orientation on CaCO3 Formation in a Fracture

NASA Astrophysics Data System (ADS)

Xu, Z.; Li, Q.; Sheets, J.; Kneafsey, T. J.; Jun, Y. S.; Cole, D. R.; Pyrak-Nolte, L. J.

2016-12-01

Sealing fractures through mineral precipitation is a potential way for improving caprock integrity in subsurface reservoirs. We investigated the effect of buoyancy and fracture orientation on the amount and spatial distribution of calcium carbonate (CaCO3) precipitates in a fracture. To monitor mineral precipitation during reactive flow, transparent acrylic casts of an induced fracture in Austin chalk were used. To trigger CaCO3 precipitates, 1M CaCl2 with either 0.6M NaHCO3 solution (for surface adhering precipitation), or 0.3M Na2CO3 solution (for pore filling precipitation) were injected simultaneously into a saturated fracture. Experiments were performed with the fracture plane oriented either parallel or perpendicular to gravity. Acoustic wave transmission (compressional wave, 1 MHz) and optical imaging were used to monitor the sample prior to, during and after fluid injection. Complementary X-ray computed tomography was performed throughout the experiments on vertical fractures and post injection for the horizontal fractures. For the vertical fractures, the denser CaCl2 almost completely displaced the carbonate solution in the fracture and caused strong localization of the precipitates. The width of the precipitated region grew slowly over time. The horizontal fracture caused the less dense carbonate to flow over the CaCl2 solution thus resulting in more mixing and a more even distribution of precipitates throughout the fracture. The acoustic signatures depended on the type of precipitation that occurred. For pore filling experiments, the compressional wave amplitude increased by 5-20% and the velocity increased for both the vertical and horizontal fractures. However, the acoustic responses differed between the vertical and horizontal fractures for surface adhering experiments. Based on the acoustic response, surface adhering precipitation increased fracture specific stiffness more in the horizontal fracture than in the vertical fracture. The horizontal fracture enabled more mixing of the two solutions within the fracture than the vertical fracture. This work was supported by the Center for Nanoscale Controls on Geologic CO (NCGC), an Energy Frontier Research Center funded by the U.S. Department of Energy, Office of Science, Basic Energy Sciences under Award # DE-AC02-05CH11231

Downhole monitoring of biogenic gas production at the Maguelone shallow injection experimental site (Languedoc coastline, France).

NASA Astrophysics Data System (ADS)

Abdelghafour, H.; Brondolo, F.; Denchik, N.; Pezard, P. A.

2014-12-01

The controllability of CO2 geological storage can ensure the integrity of storage operations, requiring a precise monitoring of reservoir fluids and properties during injection and over time. In this context, deep saline aquifers offer a large capacity of storing CO2, but the accessibility to long term behavior studies remains limited until now. The Maguelone shallow experimental site located near Montpellier (Languedoc, France) provides such an opportunity for the understanding and accuracy of hydrogeophysical monitoring methods. The geology, petrophysic and hydrology of this site have been studied in details in previous studies, revealing the presence of a thin saline aquifer at 13-16 m depth surrounded by clay-rich materials. The site as a whole provides a natural laboratory to study CO2 injection at field scale, shallow depth, hence reasonable costs. The monitoring setup is composed of a series of hydrogeophysical and geochemical methods offering measurements of fluid pore pressure, electrical resistivity, acoustic velocities as well as pH and fluid properties and chemistry. To assess the response of the reservoir during CO2 injection, all measurements need to be compared to a representative baseline. Long after a series of gas injection experiments at Maguelone, fluctuations overtime of reservoir fluids and properties (such as pore fluid pH) were discovered at steady state, demonstrating the natural variability of the site in terms of biogenic gas (H2S, CH4, CO2) production and transfer. For this, a new resistivity baseline had to be constructed for all observatories. From this, the downhole gas saturation was determined versus depth and time from time-lapse resistivity logs analysed on the basis of other logs and laboratory measurements. The Waxman and Smits model (1968) for electrical properties of sand-clay formations was modified to estimate the gas saturation in 4D, to account for surface conductivity and pore connectivity. High frequency logging and monitoring of electrical properties both, with several measurements per hour and a dm-scale resolution, provide and insight into subsurface dynamics in terms of gas flow and storage, with biogenic gas saturations ranging from 0.1 to 5.0 %. This natural contribution has to be taken into account for upcoming experiments.

Uncertainty Quantification for CO2-Enhanced Oil Recovery

NASA Astrophysics Data System (ADS)

Dai, Z.; Middleton, R.; Bauman, J.; Viswanathan, H.; Fessenden-Rahn, J.; Pawar, R.; Lee, S.

2013-12-01

CO2-Enhanced Oil Recovery (EOR) is currently an option for permanently sequestering CO2 in oil reservoirs while increasing oil/gas productions economically. In this study we have developed a framework for understanding CO2 storage potential within an EOR-sequestration environment at the Farnsworth Unit of the Anadarko Basin in northern Texas. By coupling a EOR tool--SENSOR (CEI, 2011) with a uncertainty quantification tool PSUADE (Tong, 2011), we conduct an integrated Monte Carlo simulation of water, oil/gas components and CO2 flow and reactive transport in the heterogeneous Morrow formation to identify the key controlling processes and optimal parameters for CO2 sequestration and EOR. A global sensitivity and response surface analysis are conducted with PSUADE to build numerically the relationship among CO2 injectivity, oil/gas production, reservoir parameters and distance between injection and production wells. The results indicate that the reservoir permeability and porosity are the key parameters to control the CO2 injection, oil and gas (CH4) recovery rates. The distance between the injection and production wells has large impact on oil and gas recovery and net CO2 injection rates. The CO2 injectivity increases with the increasing reservoir permeability and porosity. The distance between injection and production wells is the key parameter for designing an EOR pattern (such as a five (or nine)-spot pattern). The optimal distance for a five-spot-pattern EOR in this site is estimated from the response surface analysis to be around 400 meters. Next, we are building the machinery into our risk assessment framework CO2-PENS to utilize these response surfaces and evaluate the operation risk for CO2 sequestration and EOR at this site.

Time-lapse processing of 2D seismic profiles with testing of static correction methods at the CO2 injection site Ketzin (Germany)

NASA Astrophysics Data System (ADS)

Bergmann, Peter; Yang, Can; Lüth, Stefan; Juhlin, Christopher; Cosma, Calin

2011-09-01

The Ketzin project provides an experimental pilot test site for the geological storage of CO2. Seismic monitoring of the Ketzin site comprises 2D and 3D time-lapse experiments with baseline experiments in 2005. The first repeat 2D survey was acquired in 2009 after 22 kt of CO2 had been injected into the Stuttgart Formation at approximately 630 m depth. Main objectives of the 2D seismic surveys were the imaging of geological structures, detection of injected CO2, and comparison with the 3D surveys. Time-lapse processing highlighted the importance of detailed static corrections to account for travel time delays, which are attributed to different near-surface velocities during the survey periods. Compensation for these delays has been performed using both pre-stack static corrections and post-stack static corrections. The pre-stack method decomposes the travel time delays of baseline and repeat datasets in a surface consistent manner, while the latter cross-aligns baseline and repeat stacked sections along a reference horizon. Application of the static corrections improves the S/N ratio of the time-lapse sections significantly. Based on our results, it is recommended to apply a combination of both corrections when time-lapse processing faces considerable near-surface velocity changes. Processing of the datasets demonstrates that the decomposed solution of the pre-stack static corrections can be used for interpretation of changes in near-surface velocities. In particular, the long-wavelength part of the solution indicates an increase in soil moisture or a shallower groundwater table in the repeat survey. Comparison with the processing results of 2D and 3D surveys shows that both image the subsurface, but with local variations which are mainly associated to differences in the acquisition geometry and source types used. Interpretation of baseline and repeat stacks shows that no CO2 related time-lapse signature is observable where the 2D lines allow monitoring of the reservoir. This finding is consistent with the time-lapse results of the 3D surveys, which show an increase in reflection amplitude centered around the injection well. To further investigate any potential CO2 signature, an amplitude versus offset (AVO) analysis was performed. The time-lapse analysis of the AVO does not indicate the presence of CO2, as expected, but shows signs of a pressure response in the repeat data.

The stability of chalk during flooding of carbonated sea water at reservoir in-situ conditions

NASA Astrophysics Data System (ADS)

Nermoen, Anders; Korsnes, Reidar I.; Madland, Merete V.

2014-05-01

Injection of CO2 into carbonate oil reservoirs has been proposed as a possible utilization of the captured CO2 due to its capability to enhance the oil recovery. For offshore reservoirs such as Ekofisk and Valhall it has been discussed to alternate the CO2 and sea water injection (WAG) to reduce costs and keep the beneficial effects of both sea water (SSW) and gas injection. Water and CO2 mix to form carbonic acids that enhance the solubility of carbonates, thus a serious concern has been raised upon the potential de-stabilization of the reservoirs during CO2 injection. In this study we focus on how carbonated sea water alters the mechanical integrity of carbonate rocks both to evaluate safety of carbon storage sites and in the planning of production strategies in producing oil fields since enhanced compaction may have both detrimental and beneficial effects. Here we will present results from long term experiments (approx. half year each) performed on Kansas outcrop chalk (38-41% porosity), which serves as model material to understand the physical and chemical interplaying processes taking place in chalk reservoirs. All tests are performed at uni-axial strain conditions, meaning that the confining radial stresses are automatically adjusted to ensure zero radial strain. The tests are performed at in-situ conditions and run through a series of stages that mimic the reservoir history at both Ekofisk and Valhall fields. We observe the strain response caused by the injected brine. The experimental stages are: (a) axial stress build-up by pore pressure depletion to stresses above yield with NaCl-brine which is inert to the chalk; (b) uni-axial creep at constant axial stresses with NaCl-brine; (c) sea water injection; and (d) injection of carbonated water (SSW+CO2) at various mixture concentrations. Two test series were performed in which the pore pressure was increased (re-pressurized) before stage (c) to explore the stress dependency of the fluid induced strain triggering. The main findings of our investigations are: 1. The creep rate in the plastic phase is pore fluid dependent. The injection of sea water induces a period of accelerating creep. 2. The injection of CO2 and sea water reduces the deformation rate, a result which is in contrast to what has previously been shown. 3. The solid weight of the plugs is maintained during flooding which indicates that the observed carbonate dissolution at the inlet side is counteracted with secondary precipitation, possibly calcium sulphate, within the plug. These recent obtained results show that chalk cores maintain their mechanical integrity during flooding of carbonated water. This experimental study, however, separates from earlier studies by the low injection rate which allows secondary precipitation processes to equilibrate within the plugs, chalk type, test temperature, and stress conditions, which all are factors that will affect the reported dynamics.

Method for carbon dioxide sequestration

DOEpatents

Wang, Yifeng; Bryan, Charles R.; Dewers, Thomas; Heath, Jason E.

2015-09-22

A method for geo-sequestration of a carbon dioxide includes selection of a target water-laden geological formation with low-permeability interbeds, providing an injection well into the formation and injecting supercritical carbon dioxide (SC--CO.sub.2) into the injection well under conditions of temperature, pressure and density selected to cause the fluid to enter the formation and splinter and/or form immobilized ganglia within the formation. This process allows for the immobilization of the injected SC--CO.sub.2 for very long times. The dispersal of scCO2 into small ganglia is accomplished by alternating injection of SC--CO.sub.2 and water. The injection rate is required to be high enough to ensure the SC--CO.sub.2 at the advancing front to be broken into pieces and small enough for immobilization through viscous instability.

FY12 ARRA-NRAP Report – Studies to Support Risk Assessment of Geologic Carbon Sequestration

DOE Office of Scientific and Technical Information (OSTI.GOV)

Cantrell, Kirk J.; Shao, Hongbo; Thompson, C. J.

2011-09-27

This report summarizes results of research conducted during FY2012 to support the assessment of environmental risks associated with geologic carbon dioxide (CO2) sequestration and storage. Several research focus areas are ongoing as part of this project. This includes the quantification of the leachability of metals and organic compounds from representative CO2 storage reservoir and caprock materials, the fate of metals and organic compounds after release, and the development of a method to measure pH in situ under supercritical CO2 (scCO2) conditions. Metal leachability experiments were completed on 6 different rock samples in brine in equilibrium with scCO2 at representative geologicmore » reservoir conditions. In general, the leaching of RCRA metals and other metals of concern was found to be limited and not likely to be a significant issue (at least, for the rocks tested). Metals leaching experiments were also completed on 1 rock sample with scCO2 containing oxygen at concentrations of 0, 1, 5, and 10% to simulate injection of CO2 originating from the oxy-fuel combustion process. Significant differences in the leaching behavior of certain metals were observed when oxygen is present in the CO2. These differences resulted from oxidation of sulfides, release of sulfate, ferric iron and other metals, and subsequent precipitation of iron oxides and some sulfates such as barite. Experiments to evaluate the potential for mobilization of organic compounds from representative reservoir materials and cap rock and their fate in porous media (quartz sand) have been conducted. Results with Fruitland coal and Gothic shale indicate that lighter organic compounds were more susceptible to mobilization by scCO2 compared to heavier compounds. Alkanes demonstrated very low extractability by scCO2. No significant differences were observed between the extractability of organic compounds by dry or water saturated scCO2. Reaction equilibrium appears to have been reached by 96 hours. When the scCO2 was released from the reactor, less than 60% of the injected lighter compounds (benzene, toluene) were transported through dry sand column by the CO2, while more than 90% of the heavier organics were trapped in the sand column. For wet sand columns, most (80% to 100%) of the organic compounds injected into the sand column passed through, except for naphthalene which was substantial removed from the CO2 within the column. A spectrophotometric method was developed to measure pH in brines in contact with scCO2. This method provides an alternative to fragile glass pH electrodes and thermodynamic modeling approaches for estimating pH. The method was tested in simulated reservoir fluids (CO2–NaCl–H2O) at different temperatures, pressures, and ionic strength, and the results were compared with other experimental studies and geochemical models. Measured pH values were generally in agreement with the models, but inconsistencies were present between some of the models.« less

Characterization of the CO2 fluid adsorption in coal as a function of pressure using neutron scattering techniques (SANS and USANS)

USGS Publications Warehouse

Melnichenko, Y.B.; Radlinski, A.P.; Mastalerz, Maria; Cheng, G.; Rupp, J.

2009-01-01

Small angle neutron scattering techniques have been applied to investigate the phase behavior of CO2 injected into coal and possible changes in the coal pore structure that may result from this injection. Three coals were selected for this study: the Seelyville coal from the Illinois Basin (Ro = 0.53%), Baralaba coal from the Bowen Basin (Ro = 0.67%), and Bulli 4 coal from the Sydney Basin (Ro = 1.42%). The coals were selected from different depths to represent the range of the underground CO2 conditions (from subcritical to supercritical) which may be realized in the deep subsurface environment. The experiments were conducted in a high pressure cell and CO2 was injected under a range of pressure conditions, including those corresponding to in-situ hydrostatic subsurface conditions for each coal. Our experiments indicate that the porous matrix of all coals remains essentially unchanged after exposure to CO2 at pressures up to 200??bar (1??bar = 105??Pa). Each coal responds differently to the CO2 exposure and this response appears to be different in pores of various sizes within the same coal. For the Seelyville coal at reservoir conditions (16????C, 50??bar), CO2 condenses from a gas into liquid, which leads to increased average fluid density in the pores (??pore) with sizes (r) 1 ?? 105 ??? r ??? 1 ?? 104???? (??pore ??? 0.489??g/cm3) as well as in small pores with size between 30 and 300???? (??pore ??? 0.671??g/cm3). These values are by a factor of three to four higher than the density of bulk CO2 (??CO2) under similar thermodynamic conditions (??CO2 ??? 0.15??g/cm3). At the same time, in the intermediate size pores with r ??? 1000???? the average fluid density is similar to the density of bulk fluid, which indicates that adsorption does not occur in these pores. At in situ conditions for the Baralaba coal (35 OC, 100??bar), the average fluid density of CO2 in all pores is lower than that of the bulk fluid (??pore / ??CO2 ??? 0.6). Neutron scattering from the Bulli 4 coal did not show any significant variation with pressure, a phenomenon which we assign to the extremely small amount of porosity of this coal in the pore size range between 35 and 100,000????. ?? 2008 Elsevier B.V.

Identification and determination of trapping parameters as key site parameters for CO2 storage for the active CO2 storage site in Ketzin (Germany) - Comparison of different experimental approaches and analysis of field data

NASA Astrophysics Data System (ADS)

Zemke, Kornelia; Liebscher, Axel

2015-04-01

Petrophysical properties like porosity and permeability are key parameters for a safe long-term storage of CO2 but also for the injection operation itself. The accurate quantification of residual trapping is difficult, but very important for both storage containment security and storage capacity; it is also an important parameter for dynamic simulation. The German CO2 pilot storage in Ketzin is a Triassic saline aquifer with initial conditions of the target sandstone horizon of 33.5 ° C/6.1 MPa at 630 m. One injection and two observation wells were drilled in 2007 and nearly 200 m of core material was recovered for site characterization. From June 2008 to September 2013, slightly more than 67 kt food-grade CO2 has been injected and continuously monitored. A fourth observation well has been drilled after 61 kt injected CO2 in summer 2012 at only 25 m distance to the injection well and new core material was recovered that allow study CO2 induced changes in petrophysical properties. The observed only minor differences between pre-injection and post-injection petrophysical parameters of the heterogeneous formation have no severe consequences on reservoir and cap rock integrity or on the injection behavior. Residual brine saturation for the Ketzin reservoir core material was estimated by different methods. Brine-CO2 flooding experiments for two reservoir samples resulted in 36% and 55% residual brine saturation (Kiessling, 2011). Centrifuge capillary pressure measurements (pc = 0.22 MPa) yielded the smallest residual brine saturation values with ~20% for the lower part of the reservoir sandstone and ~28% for the upper part (Fleury, 2010). The method by Cerepi (2002), which calculates the residual mercury saturation after pressure release on the imbibition path as trapped porosity and the retracted mercury volume as free porosity, yielded unrealistic low free porosity values of only a few percent, because over 80% of the penetrated mercury remained in the samples after pressure release to atmospheric pressure. The results from the centrifuge capillary pressure measurements were then used for calibrating the cutoff time of NMR T2 relaxation (average value 8 ms) to differentiate between the mobile and immobile water fraction (standard for clean sandstone 33 ms). Following Norden (2010) a cutoff time of 10 ms was applied to estimate the residual saturation as Bound Fluid Volume for the Ketzin core materials and to estimate NMR permeability after Timur-Coates. This adapted cutoff value is also consistent with results from RST logging after injection. The maximum measured CO2 saturation corresponds to the effective porosity for the upper most CO2 filled sandstone horizon. The directly measured values and the estimated residual brine saturations from NMR measurements with the adapted cutoff time of 10 ms are within the expected range compared to the literature data with a mean residual brine saturation of 53%. A. Cerepi et al., 2002, Journal of Petroleum Science and Engineering 35. M. Fleury et al., 2011, SCA2010-06. D. Kiessling et al., 2010, International Journal of Greenhouse Gas Control 4. B. Norden et al. 2010, SPE Reservoir Evaluation & Engineering 13. .

Effects of dissolved CO2 on Shallow Freshwater Microbial Communities simulating a CO2 Leakage Scenario

NASA Astrophysics Data System (ADS)

Gulliver, D. M.; Lowry, G. V.; Gregory, K.

2013-12-01

Geological carbon sequestration is likely to be part of a comprehensive strategy to minimize the atmospheric release of greenhouse gasses, establishing a concern of sequestered CO2 leakage into overlying potable aquifers. Leaking CO2 may affect existing biogeochemical processes and therefore water quality. There is a critical need to understand the evolution of CO2 exposed microbial communities that influence the biogeochemistry in these freshwater aquifers. The evolution of microbial ecology for different CO2 exposure concentrations was investigated using fluid-slurry samples obtained from a shallow freshwater aquifer (55 m depth, 0.5 MPa, 22 °C, Escatawpa, MS). The microbial community of well samples upstream and downstream of CO2 injection was characterized. In addition, batch vessel experiments were conducted with the upstream aquifer samples exposed to varying pCO2 from 0% to 100% under reservoir temperature and pressure for up to 56 days. The microbial community of the in situ experiment and the batch reactor experiment were analyzed with 16S rRNA clone libraries and qPCR. In both the in situ experiment and the batch reactor experiment, DNA concentration did not correlate with CO2 exposure. Both the in situ experiment and the batch reactors displayed a changing microbial community with increased CO2 exposure. The well water isolate, Curvibacter, appeared to be the most tolerant genus to high CO2 concentrations in the in situ experiments and to mid-CO2 concentrations in the batch reactors. In batch reactors with pCO2 concentrations higher than experienced in situ (pCO2 = 0.5 MPa), Pseudomonas appeared to be the most tolerant genus. Findings provide insight into a dynamic biogeochemical system that will alter with CO2 exposure. Adapted microbial populations will eventually give rise to the community that will impact the metal mobility and water quality. Knowledge of the surviving microbial populations will enable improved models for predicting the fate of CO2 following leakage and lead to better strategies for ensuring the quality of potable aquifer water.

Mathematical models as tools for probing long-term safety of CO2 storage

DOE Office of Scientific and Technical Information (OSTI.GOV)

Pruess, Karsten; Birkholzer, Jens; Zhou, Quanlin

Subsurface reservoirs being considered for storing CO{sub 2} include saline aquifers, oil and gas reservoirs, and unmineable coal seams (Baines and Worden, 2004; IPCC, 2005). By far the greatest storage capacity is in saline aquifers (Dooley et al., 2004), and our discussion will focus primarily on CO{sub 2} storage in saline formations. Most issues for safety and security of CO{sub 2} storage arise from the fact that, at typical temperature and pressure conditions encountered in terrestrial crust, CO{sub 2} is less dense than aqueous fluids. Accordingly, CO{sub 2} will experience an upward buoyancy force in most subsurface environments, and willmore » tend to migrate upwards whenever (sub-)vertical permeable pathways are available, such as fracture zones, faults, or improperly abandoned wells (Bachu, 2008; Pruess, 2008a, b; Tsang et al., 2008). CO{sub 2} injection will increase fluid pressures in the target formation, thereby altering effective stress distributions, and potentially triggering movement along fractures and faults that could increase their permeability and reduce the effectiveness of a caprock in containing CO{sub 2} (Rutqvist et al., 2008; Chiaramonte et al., 2008). Induced seismicity as a consequence of fluid injection is also a concern (Healy et al., 1968; Raleigh et al., 1976; Majer et al., 2007). Dissolution of CO{sub 2} in the aqueous phase generates carbonic acid, which may induce chemical corrosion (dissolution) of minerals with associated increase in formation porosity and permeability, and may also mediate sequestration of CO{sub 2} as solid carbonate (Gaus et al., 2008). Chemical dissolution of caprock minerals could promote leakage of CO{sub 2} from a storage reservoir (Gherardi et al., 2007). Chemical dissolution and geomechanical effects could reinforce one another in compromising CO{sub 2} containment. Additional issues arise from the potential of CO{sub 2} to mobilize hazardous chemical species (Kharaka et al., 2006), and from migration of the large amounts of brine that would be mobilized by industrial-scale CO{sub 2} injection (Nicot et al., 2008; Birkholzer et al., 2008a, b).« less

Post-injection Multiphase Flow Modeling and Risk Assessments for Subsurface CO2 Storage in Naturally Fractured Reservoirs

NASA Astrophysics Data System (ADS)

Jin, G.

2015-12-01

Subsurface storage of carbon dioxide in geological formations is widely regarded as a promising tool for reducing global atmospheric CO2 emissions. Successful geologic storage for sequestrated carbon dioxides must prove to be safe by means of risk assessments including post-injection analysis of injected CO2 plumes. Because fractured reservoirs exhibit a higher degree of heterogeneity, it is imperative to conduct such simulation studies in order to reliably predict the geometric evolution of plumes and risk assessment of post CO2injection. The research has addressed the pressure footprint of CO2 plumes through the development of new techniques which combine discrete fracture network and stochastic continuum modeling of multiphase flow in fractured geologic formations. A subsequent permeability tensor map in 3-D, derived from our preciously developed method, can accurately describe the heterogeneity of fracture reservoirs. A comprehensive workflow integrating the fracture permeability characterization and multiphase flow modeling has been developed to simulate the CO2plume migration and risk assessments. A simulated fractured reservoir model based on high-priority geological carbon sinks in central Alabama has been employed for preliminary study. Discrete fracture networks were generated with an NE-oriented regional fracture set and orthogonal NW-fractures. Fracture permeability characterization revealed high permeability heterogeneity with an order of magnitude of up to three. A multiphase flow model composed of supercritical CO2 and saline water was then applied to predict CO2 plume volume, geometry, pressure footprint, and containment during and post injection. Injection simulation reveals significant permeability anisotropy that favors development of northeast-elongate CO2 plumes, which are aligned with systematic fractures. The diffusive spreading front of the CO2 plume shows strong viscous fingering effects. Post-injection simulation indicates significant upward lateral spreading of CO2 resulting in accumulation of CO2 directly under the seal unit because of its buoyancy and strata-bound vertical fractures. Risk assessment shows that lateral movement of CO2 along interconnected fractures requires widespread seals with high integrity to confine the injected CO2.

Development of Carbon Sequestration Options by Studying Carbon Dioxide-Methane Exchange in Hydrates

NASA Astrophysics Data System (ADS)

Horvat, Kristine Nicole

Gas hydrates form naturally at high pressures (>4 MPa) and low temperatures (<4 °C) when a set number of water molecules form a cage in which small gas molecules can be entrapped as guests. It is estimated that about 700,000 trillion cubic feet (tcf) of methane (CH4) exist naturally as hydrates in marine and permafrost environments, which is more than any other natural sources combined as CH4 hydrates contain about 14 wt% CH4. However, a vast amount of gas hydrates exist in marine environments, which makes gas extraction an environmental challenge, both for potential gas losses during extraction and the potential impact of CH4 extraction on seafloor stability. From the climate change point of view, a 100 ppm increase in atmospheric carbon dioxide (CO2) levels over the past century is of urgent concern. A potential solution to both of these issues is to simultaneously exchange CH4 with CO 2 in natural hydrate reserves by forming more stable CO2 hydrates. This approach would minimize disturbances to the host sediment matrix of the seafloor while sequestering CO2. Understanding hydrate growth over time is imperative to prepare for large scale CH4 extraction coupled with CO2 sequestration. In this study, we performed macroscale experiments in a 200 mL high-pressure Jerguson cell that mimicked the pressure-temperature conditions of the seafloor. A total of 13 runs were performed under varying conditions. These included the formation of CH4 hydrates, followed by a CO2 gas injection and CO2 hydrate formation followed by a CH4 gas injection. Results demonstrated that once gas hydrates formed, they show "memory effect" in subsequent charges, irrespective of the two gases injected. This was borne out by the induction time data for hydrate formation that reduced from 96 hours for CH4 and 24 hours for CO2 to instant hydrate formation in both cases upon injection of a secondary gas. During the study of CH4-CO2 exchange where CH4 hydrates were first formed and CO2 gas was injected into the system, gas chromatographic (GC) analysis of the cell indicated a pure CH4 gas phase, i.e., all injected CO2 gas entered the hydrate phase and remained trapped in hydrate cages for several hours, though over time some CO2 did enter the gas phase. Alternatively, during the CH 4-CO2 exchange study where CO2 hydrates were first formed, the injected CH4 initially entered the hydrate phase, but quickly gaseous CO2 exchanged with CH4 in hydrates to form more stable CO2 hydrates. These results are consistent with the better thermodynamic stability of CO2 hydrates, and this appears to be a promising method to sequester CO2 in natural CH4 hydrate matrices. The macroscale study described above was complemented by a microscale study to visualize hydrate growth. This first-of-its-kind in-situ study utilized the x-ray computed microtomography (CMT) technique to visualize microscale CO2, CH4, and mixed CH 4-CO2 hydrate growth phenomenon in salt solutions in the presence or absence of porous media. The data showed that under the experimental conditions used, pure CH4 formed CH4 hydrates as mostly spheres, while pure CO2 hydrates were more dendritic branches. Additionally, varying ratios of mixed CH4-CO2 hydrates were also formed that had needle-like growth. In porous media, CO2 hydrates grew, consistent with known growth models in which the solution was the sediment wetting phase. When glass beads and Ottawa sand were used as a host, the system exhibited pore-filling hydrate growth, while the presence of liquid CO2 and possible CO2 hydrates in Ottawa sand initially were pore-filling that over time transformed into a grain-displacing morphology. The data appears promising to develop a method that would supplant our energy supply by extracting CH4 from naturally occurring hydrates while CO2 is sequestered in the same formations.

Permanent downhole fiber optic pressure and temperature monitoring during CO2 injection

NASA Astrophysics Data System (ADS)

Schmidt-Hattenberger, C.; Moeller, F.; Liebscher, A.; Koehler, S.

2009-04-01

Permanent downhole monitoring of pressure and temperature, ideally over the entire length of the injection string, is essential for any smooth and safe CO2 injection within the framework of geological CO2 storage: i) To avoid fracturing of the cap-rock, a certain, site dependent pressure threshold within the reservoir should not be exceeded; ii) Any CO2 phase transition within the injection string, i.e. either condensation or evaporation, should be avoided. Such phase transitions cause uncontrolled and undetermined P-T regimes within the injection string that may ultimately result in a shut-in of the injection facility; and iii) Precise knowledge of the P and T response of the reservoir to the CO2 injection is a prerequisite to any reservoir modeling. The talk will present first results from our permanent downhole P-T monitoring program from the Ketzin CO2 storage test site (CO2SINK). At Ketzin, a fiber Bragg grating pressure sensor has been installed at the end of the injection string in combination with distributed temperature profiling over the entire length (about 550 m) of the string for continuous P-T monitoring during operation. Such fiber optic monitoring technique is used by default in the oil and gas industry but has not yet been applied as standard on a long-term routine mode for CO2 injection. Pressure is measured every 5 seconds with a resolution of < 1 bar. The data are later processed by user-defined program. The temperature logs along the injection string are measured every 3 minutes with a spatial resolution of one meter and with a temperature resolution of about 0.1°C. The long-term stability under full operational conditions is currently under investigation. The main computer of the P-T system operates as a stand-alone data-acquisition unit, and is connected with a secure intranet in order to ensure remote data access and system maintenance. The on-line measurements are displayed on the operator panel of the injection facility for direct control. The monitoring program started already prior to CO2 injection and runs since 6 months without any fatal errors. The recorded data cover the pre-injection well-testing phase, the initial injection phase as well as several shut-in and re-start phases during routine injection. Especially during the initial and re-start phases the monitoring results significantly optimized and improved the operation of the injection facility in terms of injection rate and injection temperature. Due to the high qualitative and also quantitative resolution of this technique even shortest-term transient disturbances of the reservoir and injection regime could be monitored as they may occur due to fluid sampling or logging in neighboring wells. Such short-term transient effects are normally overlooked using non-permanent monitoring techniques. On the long-term perspective, this monitoring technique will also support the control of CO2 injection tubing integrity, which is a prerequisite for any secure long-lasting CO2 injection and storage.

Computational Modeling of the Geologic Sequestration of Carbon Dioxide

EPA Science Inventory

Geologic sequestration of CO2 is a component of C capture and storage (CCS), an emerging technology for reducing CO2 emissions to the atmosphere, and involves injection of captured CO2 into deep subsurface formations. Similar to the injection of hazardous wastes, before injection...

Field Validation of Supercritical CO 2 Reactivity with Basalts

DOE Office of Scientific and Technical Information (OSTI.GOV)

McGrail, B. Peter; Schaef, Herbert T.; Spane, Frank A.

2017-01-10

Continued global use of fossil fuels places a premium on developing technology solutions to minimize increases in atmospheric CO 2 levels. CO 2 storage in reactive basalts might be one of these solutions by permanently converting injected gaseous CO 2 into solid carbonates. Herein we report results from a field demonstration where ~1000 MT of CO 2 was injected into a natural basalt formation in Eastern Washington State. Following two years of post-injection monitoring, cores were obtained from within the injection zone and subjected to detailed physical and chemical analysis. Nodules found in vesicles throughout the cores were identified asmore » the carbonate mineral, ankerite Ca[Fe, Mg, Mn](CO 3) 2. Carbon isotope analysis showed the nodules are chemically distinct as compared with natural carbonates present in the basalt and clear correlation with the isotopic signature of the injected CO 2. These findings provide field validation of rapid mineralization rates observed from years of laboratory testing with basalts.« less

Development of new measuring technique using sound velocity for CO2 concentration in Cameroonian volcanic lakes

NASA Astrophysics Data System (ADS)

Sanemasa, M.; Saiki, K.; Kaneko, K.; Ohba, T.; Kusakabe, M.; Tanyileke, G.; Hell, J.

2012-12-01

1. Introduction Limnic eruptions at Lakes Monoun and Nyos in Cameroon, which are sudden degassing of magmatic CO2 dissolved in the lake water, occurred in 1984 and 1986, respectively. The disasters killed about 1800 people around the lakes. Because of ongoing CO2 accumulation in the bottom water of the lakes, tragedy of limnic eruptions will possibly occur again. To prevent from further disasters, artificial degassing of CO2 from the lake waters has been undergoing. Additionally, CO2 monitoring of the lake waters is needed. Nevertheless, CO2 measurement is done only once or twice a year because current methods of CO2 measurement, which require chemical analysis of water samples, are not suitable for frequent measurement. In engineering field, on the other hand, a method to measure salt concentration using sound velocity has been proposed (Kleis and Sanchez, 1990). This method allows us to evaluate solute concentration fast. We applied the method to dissolved CO2 and examined the correlation between sound velocity and CO2 concentration in laboratory experiment. Furthermore, using the obtained correlation, we tried to estimate the CO2 concentration of waters in the Cameroonian lakes. 2. Laboratory experiment We examined the correlation between sound velocity and CO2 concentration. A profiler (Minos X, made by AML oceanography) and pure water were packed in cylindrical stainless vessel and high-pressure CO2 gas was injected to produce carbonated water. The profiler recorded temperature, pressure and sound velocity. Change of sound velocity was defined as difference of sound velocity between carbonated water and pure water under the same temperature and pressure conditions. CO2 concentration was calculated by Henry's law. The result indicated that the change of sound velocity [m s-1] is proportional to CO2 concentration [mmol kg-1], and the coefficient is 0.021 [m kg s-1 mmol-1]. 3. Field application Depth profiles of sound velocity, pressure, and temperature of Lakes Nyos and Monoun were measured in March 2012, and CO2 concentration was calculated using the results of laboratory experiment. The CO2 concentration profiles by Sound Velocity Method were compared to estimated profile of 2012 by chemical analysis with correction using results of Kusakabe et al., 2008. The CO2 concentration profile estimated by Sound Velocity Method looks overestimated. This may be the effect of bicarbonate salt little existed in laboratory experiment. The change of sound velocity was evaluated as a linear function of CO2 and bicarbonate ion concentration by multiple regression analysis. Coefficient for the change of sound velocity of CO2 concentration in Lake Nyos agrees with the laboratory experiment within the precision of 10%. On the other hand, in Lake Monoun, the difference of coefficient is larger than 50%. In Lake Monoun, CO2 concentration may be estimated incorrectly because CO2/bicarbonate ratio seems to have changed. From these results, we concluded that Sound Velocity Method is useful to measure CO2 concentration quantitatively as far as the CO2/bicarbonate ratio does not change. The method is also applicable as an early diagnosis when the CO2 profile changes by a sudden CO2 injection to the lakes.

Simulation of CO2 Sequestration at Rock Spring Uplift, Wyoming: Heterogeneity and Uncertainties in Storage Capacity, Injectivity and Leakage

DOE Office of Scientific and Technical Information (OSTI.GOV)

Deng, Hailin; Dai, Zhenxue; Jiao, Zunsheng

2011-01-01

Many geological, geochemical, geomechanical and hydrogeological factors control CO{sub 2} storage in subsurface. Among them heterogeneity in saline aquifer can seriously influence design of injection wells, CO{sub 2} injection rate, CO{sub 2} plume migration, storage capacity, and potential leakage and risk assessment. This study applies indicator geostatistics, transition probability and Markov chain model at the Rock Springs Uplift, Wyoming generating facies-based heterogeneous fields for porosity and permeability in target saline aquifer (Pennsylvanian Weber sandstone) and surrounding rocks (Phosphoria, Madison and cap-rock Chugwater). A multiphase flow simulator FEHM is then used to model injection of CO{sub 2} into the target salinemore » aquifer involving field-scale heterogeneity. The results reveal that (1) CO{sub 2} injection rates in different injection wells significantly change with local permeability distributions; (2) brine production rates in different pumping wells are also significantly impacted by the spatial heterogeneity in permeability; (3) liquid pressure evolution during and after CO{sub 2} injection in saline aquifer varies greatly for different realizations of random permeability fields, and this has potential important effects on hydraulic fracturing of the reservoir rock, reactivation of pre-existing faults and the integrity of the cap-rock; (4) CO{sub 2} storage capacity estimate for Rock Springs Uplift is 6614 {+-} 256 Mt at 95% confidence interval, which is about 36% of previous estimate based on homogeneous and isotropic storage formation; (5) density profiles show that the density of injected CO{sub 2} below 3 km is close to that of the ambient brine with given geothermal gradient and brine concentration, which indicates CO{sub 2} plume can sink to the deep before reaching thermal equilibrium with brine. Finally, we present uncertainty analysis of CO{sub 2} leakage into overlying formations due to heterogeneity in both the target saline aquifer and surrounding formations. This uncertainty in leakage will be used to feed into risk assessment modeling.« less

Analogue modelling of caprock failure and sediment mobilisation due to pore fluid overpressure in shallow reservoirs

NASA Astrophysics Data System (ADS)

Warsitzka, Michael; Kukowski, Nina; May, Franz

2017-04-01

Injection of CO2 in geological formations may cause excess pore fluid pressure by enhancing the fluid volume in the reservoir rock and by buoyancy-driven flow. If sediments in the reservoir and the caprock are undercompacted, pore fluid overpressure can lead to hydro-fractures in the caprock and fluidisation of sediments. Eventually, these processes trigger the formation of pipe structures, gas chimneys, gas domes or sand injections. Generally, such structures serve as high permeable pathways for fluid migration through a low-permeable seal layer and have to be considered in risk assessment or modelling of caprock integrity of CO2 storage sites. We applied scaled analogue experiments to characterise and quantify mechanisms determining the onset and migration of hydro-fractures in a low-permeable, cohesive caprock and fluidisation of unconsolidated sediments of the reservoir layer. The caprock is simulated by different types of cohesive powder. The reservoir layer consists of granulates with small particle density. Air injected through the base of the experiment and additionally through a single needle valve reaching into the analogue material is applied to generate fluid pressure within the materials. With this procedure, regional fluid pressure increase or a point-like local fluid pressure increase (e.g. injection well), respectively, can be simulated. The deformation in the analogue materials is analysed with a particle tracking imaging velocimetry technique. Pressure sensors at the base of the experiment and in the needle valve record the air pressure during an experimental run. The structural evolution observed in the experiments reveal that the cohesive cap rock first forms a dome-like anticline. Extensional fractures occur at the hinges of the anticline. A further increase of fluid pressure causes a migration of this fractures towards the surface, which is followed by intrusion of reservoir material into the fractures and the collapse of the anticline. The breakthrough of the fractures at the surface is accompanied by a significant drop of air pressure at the base of the analogue materials. The width of the dome shaped uplift is narrower and the initiating fluid pressure in the needle valve is lower, if the fluid pressure at the base of the experiment is larger. The experimental outcomes help to evaluate if the injection of CO2 into a reservoir potentially provokes initiation or reactivation of fractures and sediment mobilisation structures.

DOE Office of Scientific and Technical Information (OSTI.GOV)

James P. Barry; Peter G. Brewer

OAK-B135 This report summarizes activities and results of investigations of the potential environmental consequences of direct injection of carbon dioxide into the deep-sea as a carbon sequestration method. Results of field experiments using small scale in situ releases of liquid CO2 are described in detail. The major conclusions of these experiments are that mortality rates of deep sea biota will vary depending on the concentrations of CO2 in deep ocean waters that result from a carbon sequestration project. Large changes in seawater acidity and carbon dioxide content near CO2 release sites will likely cause significant harm to deep-sea marine life.more » Smaller changes in seawater chemistry at greater distances from release sites will be less harmful, but may result in significant ecosystem changes.« less

Dependence of injection locking of a TEA CO2 laser on intensity of injected radiation

NASA Technical Reports Server (NTRS)

Oppenheim, U. P.; Menzies, R. T.; Kavaya, M. J.

1982-01-01

The results of an experimental study to determine the minimum required injected power to control the output frequency of a TEA CO2 laser are reported. A CW CO2 waveguide laser was used as the injection oscillator. Both the power and the frequency of the injected radiation were varied, while the TEA resonator cavity length was adjusted to match the frequency of the injected signal. Single-longitudinal mode (SLM) TEA laser radiation was produced for injected power levels which are several orders of magnitude below those previously reported. The ratio of SLM output power to injection power exceeded 10 to the 12th at the lowest levels of injected intensity.

Oxygen isotopes as a tool to quantify reservoir-scale CO2 pore-space saturation

NASA Astrophysics Data System (ADS)

Serno, Sascha; Flude, Stephanie; Johnson, Gareth; Mayer, Bernard; Boyce, Adrian; Karolyte, Ruta; Haszeldine, Stuart; Gilfillan, Stuart

2017-04-01

Structural and residual trapping of carbon dioxide (CO2) are two key mechanisms of secure CO2 storage, an essential component of Carbon Capture and Storage technology [1]. Estimating the amount of CO2 that is trapped by these two mechanisms is a vital requirement for accurately assessing the secure CO2 storage capacity of a formation, but remains a key challenge. Recent field [2,3] and laboratory experiment studies [4] have shown that simple and relatively inexpensive measurements of oxygen isotope ratios in both the injected CO2 and produced water can provide an assessment of the amount of CO2 that is stored by these processes. These oxygen isotope assessments on samples obtained from observation wells provide results which are comparable to other geophysical techniques. In this presentation, based on the first comprehensive review of oxygen isotope ratios measured in reservoir waters and CO2 from global CO2 injection projects, we will outline the advantages and potential limitations of using oxygen isotopes to quantify CO2 pore-space saturation. We will further summarise the currently available information on the oxygen isotope composition of captured CO2. Finally, we identify the potential issues in the use of the oxygen isotope shifts in the reservoir water from baseline conditions to estimate accurate saturations of the pore space with CO2, and suggest how these issues can be reduced or avoided to provide reliable CO2 pore-space saturations on a reservoir scale in future field experiments. References [1] Scott et al., (2013) Nature Climate Change, Vol. 3, 105-111 doi:10.1038/nclimate1695 [2] Johnson et al., (2011) Chemical Geology, Vol. 283, 185-193 http://dx.doi.org/10.1016/j.ijggc.2016.06.019 [3] Serno et al., (2016) IJGGC, Vol. 52, 73-83 http://dx.doi.org/10.1016/j.ijggc.2016.06.019 [4] Johnson et al., (2011) Applied Geochemistry, Vol. 26 (7) 1184-1191 http://dx.doi.org/10.1016/j.apgeochem.2011.04.007

Post-injection feasibility study with the reflectivity method for the Ketzin pilot site, Germany (CO2 storage in a saline aquifer)

NASA Astrophysics Data System (ADS)

Ivanova, Alexandra; Kempka, Thomas; Huang, Fei; Diersch [Gil], Magdalena; Lüth, Stefan

2016-04-01

3D time-lapse seismic surveys (4D seismic) have proven to be a suitable technique for monitoring of injected CO2, because when CO2 replaces brine as a free gas it considerably affects elastic properties of porous media. Forward modeling of a 4D seismic response to the CO2-fluid substitution in a storage reservoir is an inevitable step in such studies. At the Ketzin pilot site (CO2 storage) 67 kilotons of CO2 were injected into a saline aquifer between 2008 and 2013. In order to track migration of CO2 at Ketzin, 3D time-lapse seismic data were acquired by means of a baseline pre-injection survey in 2005 and 3 monitor surveys: in 2009, 2012 and in 2015 (the 1st post-injection survey). Results of the 4D seismic forward modeling with the reflectivity method suggest that effects of the injected CO2 on the 4D seismic data at Ketzin are significant regarding both seismic amplitudes and time delays. These results prove the corresponding observations in the real 4D seismic data at the Ketzin pilot site. But reservoir heterogeneity and seismic resolution, as well as random and coherent seismic noise are negative factors to be considered in this interpretation. Results of the 4D seismic forward modeling with the reflectivity method support the conclusion that even small amounts of injected CO2 can be monitored in such post-injected saline aquifer as the CO2 storage reservoir at the Ketzin pilot site both qualitatively and quantitatively with considerable uncertainties (Lüth et al., 2015). Reference: Lueth, S., Ivanova, A., Kempka, T. (2015): Conformity assessment of monitoring and simulation of CO2 storage: A case study from the Ketzin pilot site. - International Journal of Greenhouse Gas Control, 42, p. 329-339.

Shock-induced CO2 loss from CaCO3: Implications for early planetary atmospheres

NASA Technical Reports Server (NTRS)

Lange, M. A.; Ahrens, T. J.

1984-01-01

Recovered samples from shock recovery experiments on single crystal calcite were subjected to thermogravimetric analysis to determine the amount of post-shock CO2, the decarbonization interval and the activation energy, for the removal of remaining CO2 in shock-loaded calcite. Comparison of post-shock CO2 with that initially present determines shock-induced CO2 loss as a function of shock pressure. Incipient to complete CO2 loss occurs over a pressure range of approximately 10 to approximately 70 GPa. Optical and scanning electron microscopy reveal structural changes, which are related to the shock-loading. The occurrence of dark, diffuse areas, which can be resolved as highly vesicular areas as observed with a scanning electron microscope are interpreted as representing quenched partial melts, into which shock-released CO2 was injected. The experimental results are used to constrain models of shock-produced, primary CO2 atmospheres on the accreting terrestrial planets.

The Inherent Tracer Fingerprint of Captured CO2

NASA Astrophysics Data System (ADS)

Flude, Stephanie; Gyore, Domokos; Stuart, Finlay; Boyce, Adrian; Haszeldine, Stuart; Chalaturnyk, Rick; Gilfillan, Stuart

2017-04-01

Inherent tracers, the isotopic and trace gas composition of captured CO2 streams, are potentially powerful tracers for use in CCS technology [1,2]. Despite this potential, the inherent tracer fingerprint in captured CO2 streams has yet to be robustly investigated and documented [3]. Here, we will present the first high quality systematic measurements of the carbon and oxygen isotopic and noble gas fingerprints measured in anthropogenic CO2 captured from combustion power stations and fertiliser plants, using amine capture, oxyfuel and gasification processes, and derived from coal, biomass and natural gas feedstocks. We will show that δ13C values are mostly controlled by the feedstock composition, as expected. The majority of the CO2 samples exhibit δ18O values similar to atmospheric O2 although captured CO2 samples from biomass and gas feedstocks at one location in the UK are significantly higher. Our measured noble gas concentrations in captured CO2 are generally as expected [2], typically being two orders of magnitude lower in concentration than in atmospheric air. Relative noble gas elemental abundances are variable and often show an opposite trend to that of a water in contact with the atmosphere. Expected enrichments in radiogenic noble gases (4He and 40Ar) for fossil fuel derived CO2 were not always observed due to dilution with atmospheric noble gases during the CO2 generation and capture process. Many noble gas isotope ratios indicate that isotopic fractionation takes place during the CO2 generation and capture processes, resulting in isotope ratios similar to fractionated air. We conclude that phase changes associated with CO2 transport and sampling may induce noble gas elemental and isotopic fractionation, due to different noble gas solubilities between high (liquid or supercritical) and low (gaseous) density CO2. Data from the Australian CO2CRC Otway test site show that δ13C of CO2 will change once injected into the storage reservoir, but that this change is small and can be quantitatively modelled in order to determine the proportion of CO2 that has dissolved into the formation waters. Furthermore, noble gas data from the Otway storage reservoir post-injection, shows evidence of noble gas stripping of formation water and contamination with Kr and Xe related to an earlier injection experiment. Importantly, He data from SaskPower's Aquistore illustrates that injected CO2 will inherit distinctive crustal radiogenic noble gas fingerprints from the subsurface once injected into an undisturbed geological storage reservoir, meaning this could be used to identify unplanned migration of the CO2 to the surface and shallow subsurface [4]. References [1] Mayer et al., (2015) IJGGC, Vol. 37, 46-60 http://dx.doi.org/10.1016/j.ijggc.2015.02.021 [2] Gilfillan et al., (2014) Energy Procedia, Vol. 63, 4123-4133 http://dx.doi.org/10.1016/j.egypro.2014.11.443 [3] Flude et al., (2016) Environ. Sci. Technol., 50 (15), pp 7939-7955 DOI: 10.1021/acs.est.6b01548 [4] Gilfillan et al., (2011) IJGGC, Vol. 5 (6) 1507-1516 http://dx.doi.org/10.1016/j.ijggc.2011.08.008

Element mobilization and immobilization from carbonate rocks between CO2 storage reservoirs and the overlying aquifers during a potential CO2 leakage.

PubMed

Lawter, Amanda R; Qafoku, Nikolla P; Asmussen, R Matthew; Kukkadapu, Ravi K; Qafoku, Odeta; Bacon, Diana H; Brown, Christopher F

2018-04-01

Despite the numerous studies on changes within the reservoir following CO 2 injection and the effects of CO 2 release into overlying aquifers, little or no literature is available on the effect of CO 2 release on rock between the storage reservoirs and subsurface. This is important, because the interactions that occur in this zone between the CO 2 storage reservoir and the subsurface may have a significant impact on risk analysis for CO 2 storage projects. To address this knowledge gap, relevant rock materials, temperatures and pressures were used to study mineralogical and elemental changes in this intermediate zone. After rocks reacted with CO 2 -acidified 0.01 M NaCl, liquid analysis showed an increase of major elements (e.g., Ca and Mg) and variable concentrations of potential contaminants (e.g., Sr and Ba); lower aqueous concentrations of these elements were observed in N 2 control experiments, likely due to differences in pH between the CO 2 and N 2 experiments. In experiments with As/Cd and/or organic spikes, representing potential contaminants in the CO 2 plume originating in the storage reservoir, most or all of these contaminants were removed from the aqueous phase. SEM and Mössbauer spectroscopy results showed the formation of new minerals and Fe oxides in some CO 2 -reacted samples, indicating potential for contaminant removal through mineral incorporation or adsorption onto Fe oxides. These experiments show the interactions between the CO 2 -laden plume and the rock between storage reservoirs and overlying aquifers have the potential to affect the level of risk to overlying groundwater, and should be considered during site selection and risk evaluation. Copyright © 2018 Elsevier Ltd. All rights reserved.

Element mobilization and immobilization from carbonate rocks between CO 2 storage reservoirs and the overlying aquifers during a potential CO 2 leakage

DOE PAGES

Lawter, Amanda R.; Qafoku, Nikolla P.; Asmussen, R. Matthew; ...

2018-01-04

In spite of the numerous studies on changes within the reservoir following CO 2 injection and the effects of CO 2 release into overlying aquifers, little or no literature is available on the effect of CO 2 release on rock between the storage reservoirs and subsurface. This is important, because the interactions that occur in this zone between the CO 2 storage reservoir and the subsurface may have a significant impact on risk analysis for CO 2 storage projects. To address this knowledge gap, relevant rock materials, temperatures and pressures were used to study mineralogical and elemental changes in thismore » intermediate zone. Furthermore, after rocks reacted with CO 2-acidified 0.01 M NaCl, liquid analysis showed an increase of major elements (e.g., Ca and Mg) and variable concentrations of potential contaminants (e.g., Sr and Ba); lower aqueous concentrations of these elements were observed in N 2 control experiments, likely due to differences in pH between the CO 2 and N 2 experiments. In experiments with As/Cd and/or organic spikes, representing potential contaminants in the CO 2 plume originating in the storage reservoir, most or all of these contaminants were removed from the aqueous phase. SEM and Mössbauer spectroscopy results showed the formation of new minerals and Fe oxides in some CO 2-reacted samples, indicating potential for contaminant removal through mineral incorporation or adsorption onto Fe oxides. These experiments show the interactions between the CO 2-laden plume and the rock between storage reservoirs and overlying aquifers have the potential to affect the level of risk to overlying groundwater, and should be considered during site selection and risk evaluation.« less

Element mobilization and immobilization from carbonate rocks between CO 2 storage reservoirs and the overlying aquifers during a potential CO 2 leakage

DOE Office of Scientific and Technical Information (OSTI.GOV)

Lawter, Amanda R.; Qafoku, Nikolla P.; Asmussen, R. Matthew

In spite of the numerous studies on changes within the reservoir following CO 2 injection and the effects of CO 2 release into overlying aquifers, little or no literature is available on the effect of CO 2 release on rock between the storage reservoirs and subsurface. This is important, because the interactions that occur in this zone between the CO 2 storage reservoir and the subsurface may have a significant impact on risk analysis for CO 2 storage projects. To address this knowledge gap, relevant rock materials, temperatures and pressures were used to study mineralogical and elemental changes in thismore » intermediate zone. Furthermore, after rocks reacted with CO 2-acidified 0.01 M NaCl, liquid analysis showed an increase of major elements (e.g., Ca and Mg) and variable concentrations of potential contaminants (e.g., Sr and Ba); lower aqueous concentrations of these elements were observed in N 2 control experiments, likely due to differences in pH between the CO 2 and N 2 experiments. In experiments with As/Cd and/or organic spikes, representing potential contaminants in the CO 2 plume originating in the storage reservoir, most or all of these contaminants were removed from the aqueous phase. SEM and Mössbauer spectroscopy results showed the formation of new minerals and Fe oxides in some CO 2-reacted samples, indicating potential for contaminant removal through mineral incorporation or adsorption onto Fe oxides. These experiments show the interactions between the CO 2-laden plume and the rock between storage reservoirs and overlying aquifers have the potential to affect the level of risk to overlying groundwater, and should be considered during site selection and risk evaluation.« less

Experimental Study of Porosity Changes in Shale Caprocks Exposed to Carbon Dioxide-Saturated Brine II: Insights from Aqueous Geochemistry

DOE PAGES

Miller, Quin R. S.; Wang, Xiuyu; Kaszuba, John P.; ...

2016-07-18

Laboratory experiments evaluated two shale caprock formations, the Gothic Shale and Marine Tuscaloosa Formation, at conditions relevant to carbon dioxide (CO 2) sequestration. Both rocks were exposed to CO 2-saturated brines at 160°C and 15 MPa for ~45 days. Baseline experiments for both rocks were pressurized with argon to 15 MPa for ~35 days. Varying concentrations of iron, aqueous silica, sulfate, and initial pH decreases coincide with enhanced carbonate and silicate dissolution due to reaction between CO 2-saturated brine and shale. Saturation indices were calculated and activity diagrams were constructed to gain insights into sulfate, silicate, and carbonate mineral stabilities.more » We found that upon exposure to CO 2-saturated brines, the Marine Tuscaloosa Formation appeared to be more reactive than the Gothic Shale. Evolution of aqueous geochemistry in the experiments is consistent with mineral precipitation and dissolution reactions that affect porosity. Finally, this study highlights the importance of tracking fluid chemistry to clarify downhole physicochemical responses to CO 2 injection and subsequent changes in sealing capacity in CO 2 storage and utilization projects.« less

Sleipner vest CO{sub 2} disposal, CO{sub 2} injection into a shallow underground aquifer

DOE Office of Scientific and Technical Information (OSTI.GOV)

Baklid, A.; Korbol, R.; Owren, G.

1996-12-31

This paper describes the problem of disposing large amounts of CO{sub 2} into a shallow underground aquifer from an offshore location in the North Sea. The solutions presented is an alternative for CO{sub 2} emitting industries in addressing the growing concern for the environmental impact from such activities. The topside injection facilities, the well and reservoir aspects are discussed as well as the considerations made during establishing the design basis and the solutions chosen. The CO{sub 2} injection issues in this project differs from industry practice in that the CO{sub 2} is wet and contaminated with methane, and further, becausemore » of the shallow depth, the total pressure resistance in the system is not sufficient for the CO{sub 2} to naturally stay in the dense phase region. To allow for safe and cost effective handling of the CO{sub 2}, it was necessary to develop an injection system that gave a constant back pressure from the well corresponding to the output pressure from the compressor, and being independent of the injection rate. This is accomplished by selecting a high injectivity sand formation, completing the well with a large bore, and regulating the dense phase CO{sub 2} temperature and thus the density of the fluid in order to account for the variations in back pressure from the well.« less

Strontium Co-precipitation During Biomineralization of Calcite in Porous Media Using Differing Treatment Strategies

NASA Astrophysics Data System (ADS)

Lauchnor, E. G.; Schultz, L.; Mitchell, A.; Cunningham, A. B.; Gerlach, R.

2013-12-01

The process of ureolytically-induced calcium carbonate mineralization has been shown in laboratory studies to be effective in co-precipitation of heavy metals and radionuclides. During this process, the microbially catalyzed hydrolysis of urea increases alkalinity and pH, thus promoting CaCO3 precipitation in the presence of dissolved calcium. One proposed application of biomineralization includes the remediation of radionuclides such as strontium, which can be co-precipitated in situ within calcite. Strontium is of concern at several US DOE sites where it is a radioactive product of uranium fission and groundwater contaminant. Our research focuses on promoting attached bacteria, or biofilms, in subsurface environments where they serve as immobilized catalysts in biomineralization and can aide in co-precipitation of some contaminants. In this work, flat plate reactors with 1 mm etched flow channels designed to mimic a porous medium environment were used. Reactors were inoculated with the model ureolytic bacterium Sporosarcina pasteurii and addition of urea, calcium and strontium containing fluid was performed to induce biomineralization. Continuous flow and stopped-flow injection strategies were investigated to evaluate differences in strontium co-precipitation efficiency. During stopped-flow experiments, injection of cementation fluid containing urea, Ca2+ and Sr2+ was alternated with growth nutrients for stimulation of microbial activity. Control parameters such as urea and calcium concentration and injection flow rate are currently being varied to optimize rate and efficiency of strontium co-precipitation. Ureolytically induced calcite precipitation and strontium incorporation in the calcite was verified by chemical and mineralogical analyses, including X-ray diffraction and ICP-MS. Strontium co-precipitation efficiency was similar under different injection strategies. Alternating calcium-containing fluid with growth nutrients allowed for continued viability of the ureolytic biofilms and also insured that bacterially-induced mineralization was still occurring after 60 days of operation. Batch rate experiments demonstrated the effective use of alternative sources of substrates for biomineralization, which are economical for use in field-scale remediation. Fertilizer has been shown to be an effective urea source and several economical carbon and nutrient sources such as molasses and whey are being evaluated for stimulating ureolytic microorganisms. This research demonstrates on a bench scale the use of different injection strategies to control precipitation of calcium carbonate, as well as the feasibility of strontium co-precipitation in porous media. The ongoing optimization of strontium co-precipitation will lead to additional work on potential remediation of other heavy metal groundwater contaminants.

Variation in Biofilm Stability with Decreasing pH Affects Porous Medium Hydraulic Properties

NASA Astrophysics Data System (ADS)

Kirk, M. F.; Santillan, E. F.; McGrath, L. K.; Altman, S. J.

2010-12-01

Changes to microbial communities caused by subsurface CO2 injection may have many consequences, including possible impacts to CO2 transport. We used column experiments to examine how decreasing pH, a geochemical change associated with CO2 injection, will affect biofilm stability and ultimately the hydraulic properties of porous media. Columns consisted of 1 mm2 square capillary tubes filled with 105-150 µm diameter glass beads. Artificial groundwater medium containing 1 mM glucose was pumped through the columns at a rate of 0.01 mL/min (q = 14.4 m/day; Re = 0.03). Columns were inoculated with 3 × 10^8 CFU (avg.) of Pseudomonas fluorescens, a model biofilm former, transformed with a green fluorescent protein. Biomass distribution and transport was examined using scanning laser confocal microscopy and effluent plating. Variation in the bulk hydraulic properties of the columns was measured using manometers. In an initial experiment, biofilm growth was allowed to occur for seven days in medium with pH 7.3. Within this period, cells uniformly coated bead surfaces, effluent cell numbers stabilized at 1 × 10^9 CFU/mL, and hydraulic conductivity (K) decreased 77%. Next, medium with pH 4 was introduced. As a result, biomass within the reactor redistributed from bead surfaces to pores, effluent cell numbers decreased to 3 × 10^5 CFU/mL, and K decreased even further (>94% reduction). This decreased K was maintained until the experiment was terminated, seven days after introducing low pH medium. These results suggest that changes in biomass distribution as a result of decreased pH may initially limit transport of solubility-trapped CO2 following CO2 injection. Experiments in progress and planned will test this result in more detail and over longer periods of time. This material is based upon work supported as part of the Center for Frontiers of Subsurface Energy Security, an Energy Frontier Research Center funded by the U.S. Department of Energy, Office of Science, Office of Basic Energy Sciences under Award Number DE-SC0001114. Sandia National Laboratories is a multi-program laboratory managed and operated by Sandia Corporation, a wholly owned subsidiary of Lockheed Martin Corporation, for the U.S. Department of Energy’s National Nuclear Security Administration under contract DE-AC04-94AL85000.

Constraining Path-Dependent Processes During Basalt-CO2 Interactions with Observations From Flow-Through and Batch Experiments

NASA Astrophysics Data System (ADS)

Thomas, D.; Garing, C.; Zahasky, C.; Harrison, A. L.; Bird, D. K.; Benson, S. M.; Oelkers, E. H.; Maher, K.

2017-12-01

Predicting the timing and magnitude of CO2 storage in basaltic rocks relies partly on quantifying the dependence of reactivity on flow path and mineral distribution. Flow-through experiments that use intact cores are advantageous because the spatial heterogeneity of pore space and reactive phases is preserved. Combining aqueous geochemical analyses and petrologic characterization with non-destructive imaging techniques (e.g. micro-computed tomography) constrains the relationship between irreversible reactions, pore connectivity and accessible surface area. Our work enhances these capabilities by dynamically imaging flow through vesicular basalts with Positron Emission Tomography (PET) scanning. PET highlights the path a fluid takes by detecting photons produced during radioactive decay of an injected radiotracer (FDG). We have performed single-phase, CO2-saturated flow-through experiments with basaltic core from Iceland at CO2 sequestration conditions (50 °C; 76-90 bar Ptot). Constant flow rate and continuous pressure measurements at the inlet and outlet of the core constrain permeability. We monitor geochemical evolution through cation and anion analysis of outlet fluid sampled periodically. Before and after reaction, we perform PET scans and characterize the core using micro-CT. The PET scans indicate a discrete, localized flow path that appears to be a micro-crack connecting vesicles, suggesting that vesicle-lining minerals are immediately accessible and important reactants. Rapid increases in aqueous cation concentration, pH and HCO3- indicate that the rock reacts nearly immediately after CO2 injection. After 24 hours the solute release decreases, which may reflect a transition to reaction with phases with slower kinetic dissolution rates (e.g. zeolites and glasses to feldspar), a decrease in available reactive surface area or precipitation. We have performed batch experiments using crushed material of the same rock to elucidate the effect of flow path geometry and mineral accessibility on geochemical evolution. Interestingly, surface area-normalized dissolution rates as evinced by SiO2 release in all experiments approach similar values ( 10-15 mol/cm2/s). Our experiments show how imaging techniques are helpful in interpreting path-dependent processes in open systems.

Spatiotemporal changes of seismic attenuation caused by injected CO2 at the Frio-II pilot site, Dayton, TX, USA

NASA Astrophysics Data System (ADS)

Zhu, Tieyuan; Ajo-Franklin, Jonathan B.; Daley, Thomas M.

2017-09-01

A continuous active source seismic monitoring data set was collected with crosswell geometry during CO2 injection at the Frio-II brine pilot, near Liberty, TX. Previous studies have shown that spatiotemporal changes in the P wave first arrival time reveal the movement of the injected CO2 plume in the storage zone. To further constrain the CO2 saturation, particularly at higher saturation levels, we investigate spatial-temporal changes in the seismic attenuation of the first arrivals. The attenuation changes over the injection period are estimated by the amount of the centroid frequency shift computed by local time-frequency analysis. We observe that (1) at receivers above the injection zone seismic attenuation does not change in a physical trend; (2) at receivers in the injection zone attenuation sharply increases following injection and peaks at specific points varying with distributed receivers, which is consistent with observations from time delays of first arrivals; then, (3) attenuation decreases over the injection time. The attenuation change exhibits a bell-shaped pattern during CO2 injection. Under Frio-II field reservoir conditions, White's patchy saturation model can quantitatively explain both the P wave velocity and attenuation response observed. We have combined the velocity and attenuation change data in a crossplot format that is useful for model-data comparison and determining patch size. Our analysis suggests that spatial-temporal attenuation change is not only an indicator of the movement and saturation of CO2 plumes, even at large saturations, but also can quantitatively constrain CO2 plume saturation when used jointly with seismic velocity.

Leakage of CO2 from sub-seafloor CO2 storage sites to the seabed; Impacts on sediment microorganisms and geochemical parameters during in situ and laboratory leakage experiments

NASA Astrophysics Data System (ADS)

Reigstad, L. J.; Hannisdal, B.; Hoffmann, F. U.; Sweetman, A. K.; Baumberger, T.; Eickmann, B.; Røy, H.; Thorseth, I. H.; Pedersen, R. B.

2013-12-01

Since 1996, 14 million tons of CO2 extracted from natural gas have been injected into the Utsira Formation, a saline aquifer at ~1000 m depth in the North Sea. The injected CO2 covers today an area of 4 x 2 km2. At present, there are three international treaties protecting the oceans, and all three allow CO2 storage in sub-seabed geological formations. One of these, the EU Directive 2009/31, states that monitoring must take place before, during and after CO2 storage in order to detect leakage of CO2 and significant adverse effects on the surrounding environment. However, few environmental studies have investigated the potential impacts of a CO2 leakage on the microbial life and geochemical conditions in seafloor sediment. To remedy this, we performed two experiments with abrupt CO2 acidification on the top 10 cm of the seafloor close to the North Sea storage site: 1) One laboratory CO2 acidification experiment on undisturbed sediment cores from the seafloor overlying the CO2 storage site (80 m water depth). The continuous flow of CO2 acidified seawater (pH 6.4) with 20 000 μatm pCO2 over the cores lasted for 1.5 months with sediment core terminations at regular intervals. 2) In situ CO2 acidification experiments carried out on the seafloor at 350 m water depth, with life span of 40 hours and exposure to 20 000 μatm pCO2. Both experiments showed increased O2 consumption in the water overlying the CO2 acidified sediment relative to the control sediment, indicating a rise in metabolic activity due to the treatment. After about 12 hours of acidification and throughout the laboratory experimental period, an increase in macrofauna burial activity could be seen, with dead/dying macrofauna appearing on the sediment surface. The pyrosequencing amplicon dataset obtained after bacterial and archaeal 16S rRNA amplification (RNA level) was subjected to multivariate analyses (PCA, NMDS), revealing changes in the active community on phylum, class and OTU levels. Changes were detected on all three levels in all depths investigated, but the response to acidification appeared among less-abundant prokaryotic groups in the sediment, rather than the numerically dominant groups. Quantification of the 16S rRNA genes (DNA level) indicated no increase in cell numbers in response to the treatment. However, an increase in the in situ microbial sulfate reduction rates and/or expression of marker genes for sulfate reduction (RNA level) was discovered. Analyses of marker gene expression for other prokaryotic metabolisms will be presented as well as correlations between specific organisms and geochemical parameters. Within the limitations of the experimental set up, our studies indicate that a leakage of CO2 from a sub-seafloor storage site may not dramatically change the composition of the active microbial community in the seabed sediment though we did register activity changes in some metabolisms.

Experimental and Numerical Investigation of Guest Molecule Exchange Kinetics based on the 2012 Ignik Sikumi Gas Hydrate Field Trial

NASA Astrophysics Data System (ADS)

Ruprecht Yonkofski, C. M.; Horner, J.; White, M. D.

2015-12-01

In 2012 the U.S. DOE/NETL, ConocoPhillips Company, and Japan Oil, Gas and Metals National Corporation jointly sponsored the first field trial of injecting a mixture of N2-CO2 into a CH4-hydrate bearing formation beneath the permafrost on the Alaska North Slope. Known as the Ignik Sikumi #1 Gas Hydrate Field Trial, this experiment involved three stages: 1) the injection of a N2-CO2 mixture into a targeted hydrate-bearing layer, 2) a 4-day pressurized soaking period, and 3) a sustained depressurization and fluid production period. Data collected during the three stages of the field trial were made available after a thorough quality check. The Ignik Sikumi #1 data set is extensive, but contains no direct evidence of the guest-molecule exchange process. This study uses numerical simulation to provide an interpretation of the CH4/CO2/N2 guest molecule exchange process that occurred at Ignik Sikumi #1. Simulations were further informed by experimental observations. The goal of the scoping experiments was to understand kinetic exchange rates and develop parameters for use in Iġnik Sikumi history match simulations. The experimental procedure involves two main stages: 1) the formation of CH4 hydrate in a consolidated sand column at 750 psi and 2°C and 2) flow-through of a 77.5/22.5 N2/CO2 molar ratio gas mixture across the column. Experiments were run both above and below the hydrate stability zone in order to observe exchange behavior across varying conditions. The numerical simulator, STOMP-HYDT-KE, was then used to match experimental results, specifically fitting kinetic behavior. Once this behavior is understood, it can be applied to field scale models based on Ignik Sikumi #1.

Wallula Basalt Pilot Demonstration Project: Post-injection Results and Conclusions

DOE Office of Scientific and Technical Information (OSTI.GOV)

McGrail, Bernard Pete; Schaef, Herbert T.; Spane, Frank A.

Deep underground geologic formations are emerging as a reasonable option for long-term storage of CO 2, including large continental flood basalt formations. At the GHGT-11 and GHGT-12 conferences, progress was reported on the initial phases for Wallula Basalt Pilot demonstration test (located in Eastern Washington state), where nearly 1,000 metric tons of CO 2 were injected over a 3-week period during July/August 2013. The target CO 2 injection intervals were two permeable basalt interflow reservoir zones with a combined thickness of ~20 m that occur within a layered basalt sequence between a depth of 830-890 m below ground surface. Duringmore » the two-year post-injection period, downhole fluid samples were periodically collected during this post-injection monitoring phase, coupled with limited wireline borehole logging surveys that provided indirect evidence of on-going chemical geochemical reactions/alterations and CO 2 disposition. A final detailed post-closure field characterization program that included downhole fluid sampling, and performance of hydrologic tests and wireline geophysical surveys. Included as part of the final wireline characterization activities was the retrieval of side-wall cores from within the targeted injection zones. These cores were examined for evidence of in-situ mineral carbonization. Visual observations of the core material identified small globular nodules, translucent to yellow in color, residing within vugs and small cavities of the recovered basalt side-wall cores, which were not evident in pre-injection side-wall cores obtained from the native basalt formation. Characterization by x-ray diffraction identified these nodular precipitates as ankerite, a commonly occurring iron and calcium rich carbonate. Isotopic characterization (δ 13C, δ 18O) conducted on the ankerite nodules indicate a distinct isotopic signature that is closely aligned with that of the injected CO 2. Both the secondary mineral nodules and injected CO 2 are measurably different from the isotopic content of basalt, injection zone groundwater and for naturally occurring calcite. Final post-injection wireline geophysical logging results also indicate the presence of free-phase CO 2 at the top of the two injection interflow zones, with no vertical migration of CO 2 above the injection horizons. Furthermore, these findings are significant and demonstrate the feasibility of sequestering CO 2 in a basalt formation.« less

Wallula Basalt Pilot Demonstration Project: Post-injection Results and Conclusions

DOE PAGES

McGrail, Bernard Pete; Schaef, Herbert T.; Spane, Frank A.; ...

2017-08-18

Deep underground geologic formations are emerging as a reasonable option for long-term storage of CO 2, including large continental flood basalt formations. At the GHGT-11 and GHGT-12 conferences, progress was reported on the initial phases for Wallula Basalt Pilot demonstration test (located in Eastern Washington state), where nearly 1,000 metric tons of CO 2 were injected over a 3-week period during July/August 2013. The target CO 2 injection intervals were two permeable basalt interflow reservoir zones with a combined thickness of ~20 m that occur within a layered basalt sequence between a depth of 830-890 m below ground surface. Duringmore » the two-year post-injection period, downhole fluid samples were periodically collected during this post-injection monitoring phase, coupled with limited wireline borehole logging surveys that provided indirect evidence of on-going chemical geochemical reactions/alterations and CO 2 disposition. A final detailed post-closure field characterization program that included downhole fluid sampling, and performance of hydrologic tests and wireline geophysical surveys. Included as part of the final wireline characterization activities was the retrieval of side-wall cores from within the targeted injection zones. These cores were examined for evidence of in-situ mineral carbonization. Visual observations of the core material identified small globular nodules, translucent to yellow in color, residing within vugs and small cavities of the recovered basalt side-wall cores, which were not evident in pre-injection side-wall cores obtained from the native basalt formation. Characterization by x-ray diffraction identified these nodular precipitates as ankerite, a commonly occurring iron and calcium rich carbonate. Isotopic characterization (δ 13C, δ 18O) conducted on the ankerite nodules indicate a distinct isotopic signature that is closely aligned with that of the injected CO 2. Both the secondary mineral nodules and injected CO 2 are measurably different from the isotopic content of basalt, injection zone groundwater and for naturally occurring calcite. Final post-injection wireline geophysical logging results also indicate the presence of free-phase CO 2 at the top of the two injection interflow zones, with no vertical migration of CO 2 above the injection horizons. Furthermore, these findings are significant and demonstrate the feasibility of sequestering CO 2 in a basalt formation.« less

Sedimentary reservoir oxidation during geologic CO2 sequestration

NASA Astrophysics Data System (ADS)

Lammers, Laura N.; Brown, Gordon E.; Bird, Dennis K.; Thomas, Randal B.; Johnson, Natalie C.; Rosenbauer, Robert J.; Maher, Katharine

2015-04-01

Injection of carbon dioxide into subsurface geologic reservoirs during geologic carbon sequestration (GCS) introduces an oxidizing supercritical CO2 phase into a subsurface geologic environment that is typically reducing. The resulting redox disequilibrium provides the chemical potential for the reduction of CO2 to lower free energy organic species. However, redox reactions involving carbon typically require the presence of a catalyst. Iron oxide minerals, including magnetite, are known to catalyze oxidation and reduction reactions of C-bearing species. If the redox conditions in the reservoir are modified by redox transformations involving CO2, such changes could also affect mineral stability, leading to dissolution and precipitation reactions and alteration of the long-term fate of CO2 in GCS reservoirs. We present experimental evidence that reservoirs with reducing redox conditions are favorable environments for the relatively rapid abiotic reduction of CO2 to organic molecules. In these experiments, an aqueous suspension of magnetite nanoparticles was reacted with supercritical CO2 under pressure and temperature conditions relevant to GCS in sedimentary reservoirs (95-210 °C and ∼100 bars of CO2). Hydrogen production was observed in several experiments, likely caused by Fe(II) oxidation either at the surface of magnetite or in the aqueous phase. Heating of the Fe(II)-rich system resulted in elevated PH2 and conditions favorable for the reduction of CO2 to acetic acid. Implications of these results for the long-term fate of CO2 in field-scale systems were explored using reaction path modeling of CO2 injection into reservoirs containing Fe(II)-bearing primary silicate minerals, with kinetic parameters for CO2 reduction obtained experimentally. The results of these calculations suggest that the reaction of CO2 with reservoir constituents will occur in two primary stages (1) equilibration of CO2 with organic acids resulting in mineral-fluid disequilibrium, and (2) gradual dissolution of primary minerals promoting significant CO2 reduction through the release of Fe(II). The reduction of CO2 is identified as a new trapping mechanism that could significantly enhance the long-term stability of GCS reservoirs. Identification of reservoir characteristics that promote CO2 redox transformations could be used as an additional factor in screening geologic reservoirs for GCS.

Aquifer disposal of carbon dioxide for greenhouse effect mitigation

DOE Office of Scientific and Technical Information (OSTI.GOV)

Gupta, N.; Naymik, T.G.; Bergman, P.

1998-07-01

Deep aquifer sequestration of carbon dioxide (CO{sup 2}), generated from power plant and other industrial emissions, is being evaluated as one of the potential options for the reduction of atmospheric greenhouse gas emissions. The major advantages of using deep aquifers are that the disposal facilities may be located close to the sources, thus reducing the CO{sub 2} transport costs. The potential capacity is much larger than the projected CO{sub 2} emissions over the next century, and it is a long-term/permanent sequestration option, because a large portion of the injected CO{sub 2} may be fixed into the aquifer by dissolution ormore » mineralization. The major limitations include the potentially high cost, the risk of upward migration, and the public perception of risk. Most of the cost is due to the need to separate CO{sub 2} from other flue gases, rather than the actual cost of disposal. Hazardous liquid waste and acid gas disposal in deep sedimentary formations is a well-established practice. There are also numerous facilities for storage of natural gases in depleted oil and gas reservoirs. The only current facility for aquifer disposal of CO{sub 2} is the offshore injection well at Sleipner Vest in the North Sea in Norway operated by Statoil. Exxon and Pertamina are planning an offshore aquifer disposal facility at Natuna gas field in Indonesia. A major evaluation of the feasibility of CO{sub 2} disposal in the European Union and Norway has been conducted under project Joule II. The data and experience obtained from the existing deep-waste disposal facilities and from the Sleipner Vest site form a strong foundation for further research and development on CO{sub 2} sequestration. Federal Energy Technology Center (FETC) is currently leading a project that uses data from an existing hazardous waste disposal facility injecting in the Mt. Simon Sandstone aquifer in Ohio to evaluate hydrogeologic, geochemical, and social issues related to CO{sub 2} disposal.« less

Aquifer disposal of carbon dioxide for greenhouse effect mitigation

DOE Office of Scientific and Technical Information (OSTI.GOV)

Gupta, N.; Naymik, T.G.; Bergman, P.

1998-04-01

Deep aquifer sequestration of carbon dioxide (CO{sub 2}) generated from power plant and other industrial emissions, is being evaluated as one of the potential options for the reduction of atmospheric greenhouse gas emissions. The major advantages of using deep aquifers are that the disposal facilities may be located close to the sources, thus reducing the CO{sub 2} transport costs. The potential capacity is much larger than the projected CO{sub 2} emissions over the next century, and it is a long-term/permanent sequestration option, because a large portion of the injected CO{sub 2} may be fixed into the aquifer by dissolution ormore » mineralization. The major limitations include the potentially high cost, the risk of upward migration, and the public perception of risk. Most of the cost is due to the need to separate CO{sub 2} from other flue gases, rather than the actual cost of disposal. Hazardous liquid waste and acid gas disposal in deep sedimentary formations is a well-established practice. There are also numerous facilities for storage of natural gases in depleted oil and gas reservoirs. The only current facility for aquifer disposal of CO{sub 2} is the offshore injection well at Sleipner Vest in the North Sea in Norway operated by Statoil. Exxon and Pertamina are planning an offshore aquifer disposal facility at Natuna gas field in Indonesia. A major evaluation of the feasibility of CO{sub 2} disposal in the European Union and Norway has been conducted under project Joule II. The data and experience obtained from the existing deep-waste disposal facilities and from the Sleipner Vest site form a strong foundation for further research and development on CO{sub 2} sequestration. Federal Energy Technology Center (FETC) is currently leading a project that uses data from an existing hazardous waste disposal facility injecting in the Mt. Simon Sandstone aquifer in Ohio to evaluate hydrogeologic, geochemical, and social issues related to CO{sub 2} disposal.« less

Potential Environmental Impacts of CO2 Storage in Sedimentary Basins: Results From the Frio Brine Test, Texas, USA

NASA Astrophysics Data System (ADS)

Kharaka, Y. K.; Cole, D. R.; Hovorka, S. D.; Phelps, T. J.; Nance, S.

2006-12-01

Deep saline aquifers in sedimentary basins, including depleted petroleum reservoirs, provide advantageous locations close to major anthropogenic sources of CO2 and potential capacity for the storage of huge volumes of this greenhouse gas. To investigate the potential for the long-term storage of CO2 in such aquifers, 1600 t of CO2 were injected at 1500 m depth into a 24-m-thick "C" sandstone section of the Frio Formation, a regional saline aquifer in the U.S. Gulf Coast. Fluid samples obtained before CO2 injection from the injection well and an observation well 30 m updip showed a Na-Ca-Cl type brine with 93,000 mg/L TDS at near saturation with CH4 at reservoir conditions; gas analyses show CH4 comprised ~95% of dissolved gas, but CO2 was low at 0.3%. Following CO2 breakthrough, 51 h after injection, samples showed sharp drops in pH (6.5 to 5.7), pronounced increases in alkalinity (100 to 3000 mg/L as HCO3) and in Fe (30 to 1100 mg/L), and significant shifts in the isotopic compositions of H2O, Sr, DIC, and CH4. These data coupled with geochemical modeling indicate rapid dissolution of minerals, especially calcite and iron oxyhydroxides caused by lowered pH (~3.0 initially) of the brine in contact with the injected supercritical CO2. These geochemical parameters, together with perfluorocarbon tracer gases (PFTs) proved effective in mapping the distribution and interactions of the injected CO2 in the Frio "C". They are being used to track the migration of the injected CO2 into the local shallow groundwater and into the overlying Frio "B", comprised of a 4-m-thick sandstone bed and separated from the "C" by ~15 m of shale, muddy sandstone and siltstone beds. Results obtained to date from the four monitoring groundwater wells perforated (26-29 m) in the Beaumont aquifer show some temporal chemical changes. These changes, however, are tentatively attributed to natural variations and recharge events caused by the construction of a mud pit at the site, and not to leakage through the Anahuac Formation, the regional cap rock comprised of thick (~80 m) and impermeable marine shale and mudstone beds. Data on brine and gas compositions of samples obtained from the Frio "B" 6 mo after injection show significant CO2 (2.9% compared with 0.3% CO2 in dissolved gas) migration into the "B" sandstone. Except for two PFT tracer gases explained by desorption, results of samples collected 15 mo after injection show no other indications of injected CO2 in the "B" sandstone. The initial presence of injected CO2 near the observation well shows migration through the intervening beds or more likely a leakage through the remedial cement around the casing of a 50- year old well. These results highlight the importance of investigating the integrity of cement seals, especially in nearby abandoned wells, prior to the injection of large quantities of reactive and buoyant CO2.

Modeling of CBM production, CO2 injection, and tracer movement at a field CO2 sequestration site

DOE Office of Scientific and Technical Information (OSTI.GOV)

Siriwardane, Hema J.; Bowes, Benjamin D.; Bromhal, Grant S.

2012-07-01

Sequestration of carbon dioxide in unmineable coal seams is a potential technology mainly because of the potential for simultaneous enhanced coalbed methane production (ECBM). Several pilot tests have been performed around the globe leading to mixed results. Numerous modeling efforts have been carried out successfully to model methane production and carbon dioxide (CO{sub 2}) injection. Sensitivity analyses and history matching along with several optimization tools were used to estimate reservoir properties and to investigate reservoir performance. Geological and geophysical techniques have also been used to characterize field sequestration sites and to inspect reservoir heterogeneity. The fate and movement of injectedmore » CO{sub 2} can be determined by using several monitoring techniques. Monitoring of perfluorocarbon (PFC) tracers is one of these monitoring technologies. As a part of this monitoring technique, a small fraction of a traceable fluid is added to the injection wellhead along with the CO{sub 2} stream at different times to monitor the timing and location of the breakthrough in nearby monitoring wells or offset production wells. A reservoir modeling study was performed to simulate a pilot sequestration site located in the San Juan coal basin of northern New Mexico. Several unknown reservoir properties at the field site were estimated by modeling the coal seam as a dual porosity formation and by history matching the methane production and CO{sub 2} injection. In addition to reservoir modeling of methane production and CO{sub 2} injection, tracer injection was modeled. Tracers serve as a surrogate for determining potential leakage of CO{sub 2}. The tracer was modeled as a non-reactive gas and was injected into the reservoir as a mixture along with CO{sub 2}. Geologic and geometric details of the field site, numerical modeling details of methane production, CO{sub 2} injection, and tracer injection are presented in this paper. Moreover, the numerical predictions of the tracer arrival times were compared with the measured field data. Results show that tracer modeling is useful in investigating movement of injected CO{sub 2} into the coal seam at the field site. Also, such new modeling techniques can be utilized to determine potential leakage pathways, and to investigate reservoir anisotropy and heterogeneity.« less

Numerical modeling of time-lapse monitoring of CO2 sequestration in a layered basalt reservoir

USGS Publications Warehouse

Khatiwada, M.; Van Wijk, K.; Clement, W.P.; Haney, M.

2008-01-01

As part of preparations in plans by The Big Sky Carbon Sequestration Partnership (BSCSP) to inject CO2 in layered basalt, we numerically investigate seismic methods as a noninvasive monitoring technique. Basalt seems to have geochemical advantages as a reservoir for CO2 storage (CO2 mineralizes quite rapidly while exposed to basalt), but poses a considerable challenge in term of seismic monitoring: strong scattering from the layering of the basalt complicates surface seismic imaging. We perform numerical tests using the Spectral Element Method (SEM) to identify possibilities and limitations of seismic monitoring of CO2 sequestration in a basalt reservoir. While surface seismic is unlikely to detect small physical changes in the reservoir due to the injection of CO2, the results from Vertical Seismic Profiling (VSP) simulations are encouraging. As a perturbation, we make a 5%; change in wave velocity, which produces significant changes in VSP images of pre-injection and post-injection conditions. Finally, we perform an analysis using Coda Wave Interferometry (CWI), to quantify these changes in the reservoir properties due to CO2 injection.

Mobilization of Trace Metals in an Experimental Carbon Sequestration Scenario

NASA Astrophysics Data System (ADS)

Marcon, V.; Kaszuba, J. P.

2012-12-01

Mobilizing trace metals with injection of supercritical CO2 into deep saline aquifers is a concern for geologic carbon sequestration. The potential for leakage from these systems requires an understanding of how injection reservoirs interact with the overlying potable aquifers. Hydrothermal experiments were performed to evaluate metal mobilization and mechanisms of release in a carbonate storage reservoir and at the caprock-reservoir boundary. Experiments react synthetic Desert Creek limestone and/or Gothic Shale, formations in the Paradox Basin, Utah, with brine that is close to equilibrium with these rocks. A reaction temperature of 1600C accelerates the reaction kinetics without changing in-situ water-rock reactions. The experiments were allowed to reach steady state before injecting CO2. Changes in major and trace element water chemistry, dissolved carbon and sulfide, and pH were tracked throughout the experiments. CO2 injection decreases the pH by 1 to 2 units; concomitant mineral dissolution produces elevated Ba, Cu, Fe, Pb, and Zn concentrations in the brine. Concentrations subsequently decrease to approximately steady state values after 120-330 hours, likely due to mineral precipitation as seen in SEM images and predicted by geochemical modeling. In experiments that emulate the caprock-reservoir boundary, final Fe (0.7ppb), an element of secondary concern for the EPA, and Pb (0.05ppb) concentrations exceed EPA limits, whereas Ba (0.140ppb), Cu (48ppb), and Zn (433ppb) values remain below EPA limits. In experiments that simulate deeper reservoir conditions, away from the caprock boundary, final Fe (3.5ppb) and Pb (0.017ppb) values indicate less mobilization than seen at the caprock-reservoir boundary, but values still exceed EPA limits. Barium concentrations always remain below the EPA limit of 2ppb, but are more readily mobilized in experiments replicating deeper reservoir conditions. In both systems, transition elements Cd, Cr, Cu, Pb and Zn behave in a similar manner, increasing in concentration with injection but continually decreasing after about 830 hours until termination of the experiment. SEM images and geochemical models indicate initial dissolution of all rocks and minerals, re-precipitation of Ca-Mg-Fe carbonates and Fe-sulfides, and precipitation of anhydrite in both systems. Calcite dissolves more readily than dolomite in these experiments, but re-precipitates in veins on dolomite. If brines leak from a storage reservoir and mix with a potable aquifer, the experimental results suggest that Ba, Cu, and Zn will not be contaminants of concern. Pb, Fe and As (still under consideration) initially exceed the EPA threshold and may require careful attention in a sequestration scenario. However, experimentally observed trends of decreasing trace metal concentration suggest that these metals could become less of a concern during the life of a carbon repository. Finally, the caprock plays an active role in trace metal mobilization in the system. The caprock provides a source of metals, although subsequent precipitation may remove metals from solution.

Measurement and modeling of CO2 mass transfer in brine at reservoir conditions

NASA Astrophysics Data System (ADS)

Shi, Z.; Wen, B.; Hesse, M. A.; Tsotsis, T. T.; Jessen, K.

2018-03-01

In this work, we combine measurements and modeling to investigate the application of pressure-decay experiments towards delineation and interpretation of CO2 solubility, uptake and mass transfer in water/brine systems at elevated pressures of relevance to CO2 storage operations in saline aquifers. Accurate measurements and modeling of mass transfer in this context are crucial to an improved understanding of the longer-term fate of CO2 that is injected into the subsurface for storage purposes. Pressure-decay experiments are presented for CO2/water and CO2/brine systems with and without the presence of unconsolidated porous media. We demonstrate, via high-resolution numerical calculations in 2-D, that natural convection will complicate the interpretation of the experimental observations if the particle size is not sufficiently small. In such settings, we demonstrate that simple 1-D interpretations can result in an overestimation of the uptake (diffusivity) by two orders of magnitude. Furthermore, we demonstrate that high-resolution numerical calculations agree well with the experimental observations for settings where natural convection contributes substantially to the overall mass transfer process.

Sensitivity of CO2 storage performance to varying rates and dynamic injectivity in the Bunter Sandstone, UK

NASA Astrophysics Data System (ADS)

Kolster, C.; Mac Dowell, N.; Krevor, S. C.; Agada, S.

2016-12-01

Carbon capture and storage (CCS) is needed for meeting legally binding greenhouse gas emissions targets in the UK (ECCC 2016). Energy systems models have been key to identifying the importance of CCS but they tend to impose few constraints on the availability and use of geologic CO2 storage reservoirs. Our aim is to develop simple models that use dynamic representations of limits on CO2 storage resources. This will allow for a first order representation of the storage reservoir for use in systems models with CCS. We use the ECLIPSE reservoir simulator and a model of the Southern North Sea Bunter Sandstone saline aquifer. We analyse reservoir performance sensitivities to scenarios of varying CO2 injection demand for a future UK low carbon energy market. With 12 injection sites, we compare the impact of injecting at a constant 2MtCO2/year per site and varying this rate by a factor of 1.8 and 0.2 cyclically every 5 and 2.5 years over 50 years of injection. The results show a maximum difference in average reservoir pressure of 3% amongst each case and a similar variation in plume migration extent. This suggests that simplified models can maintain accuracy by using average rates of injection over similar time periods. Meanwhile, by initiating injection at rates limited by pressurization at the wellhead we find that injectivity steadily increases. As a result, dynamic capacity increases. We find that instead of injecting into sites on a need basis, we can strategically inject the CO2 into 6 of the deepest sites increasing injectivity for the first 15 years by 13%. Our results show injectivity as highly dependent on reservoir heterogeneity near the injection site. Injecting 1MTCO2/year into a shallow, low permeability and porosity site instead of into a deep injection site with high permeability and porosity reduces injectivity in the first 5 years by 52%. ECCC. 2016. Future of Carbon Capture and Storage in the UK. UK Parliament House of Commons, Energy and Climate Change Committee, London: The Stationary Office Limited.

75 FR 77229 - Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO2

Federal Register 2010, 2011, 2012, 2013, 2014

2010-12-10

...This action finalizes minimum Federal requirements under the Safe Drinking Water Act (SDWA) for underground injection of carbon dioxide (CO2) for the purpose of geologic sequestration (GS). GS is one of a portfolio of options that could be deployed to reduce CO2 emissions to the atmosphere and help to mitigate climate change. This final rule applies to owners or operators of wells that will be used to inject CO2 into the subsurface for the purpose of long-term storage. It establishes a new class of well, Class VI, and sets minimum technical criteria for the permitting, geologic site characterization, area of review (AoR) and corrective action, financial responsibility, well construction, operation, mechanical integrity testing (MIT), monitoring, well plugging, post-injection site care (PISC), and site closure of Class VI wells for the purposes of protecting underground sources of drinking water (USDWs). The elements of this rulemaking are based on the existing Underground Injection Control (UIC) regulatory framework, with modifications to address the unique nature of CO2 injection for GS. This rule will help ensure consistency in permitting underground injection of CO2 at GS operations across the United States and provide requirements to prevent endangerment of USDWs in anticipation of the eventual use of GS to reduce CO2 emissions to the atmosphere and to mitigate climate change.

Quantification of a maximum injection volume of CO2 to avert geomechanical perturbations using a compositional fluid flow reservoir simulator

NASA Astrophysics Data System (ADS)

Jung, Hojung; Singh, Gurpreet; Espinoza, D. Nicolas; Wheeler, Mary F.

2018-02-01

Subsurface CO2 injection and storage alters formation pressure. Changes of pore pressure may result in fault reactivation and hydraulic fracturing if the pressure exceeds the corresponding thresholds. Most simulation models predict such thresholds utilizing relatively homogeneous reservoir rock models and do not account for CO2 dissolution in the brine phase to calculate pore pressure evolution. This study presents an estimation of reservoir capacity in terms of allowable injection volume and rate utilizing the Frio CO2 injection site in the coast of the Gulf of Mexico as a case study. The work includes laboratory core testing, well-logging data analyses, and reservoir numerical simulation. We built a fine-scale reservoir model of the Frio pilot test in our in-house reservoir simulator IPARS (Integrated Parallel Accurate Reservoir Simulator). We first performed history matching of the pressure transient data of the Frio pilot test, and then used this history-matched reservoir model to investigate the effect of the CO2 dissolution into brine and predict the implications of larger CO2 injection volumes. Our simulation results -including CO2 dissolution- exhibited 33% lower pressure build-up relative to the simulation excluding dissolution. Capillary heterogeneity helps spread the CO2 plume and facilitate early breakthrough. Formation expansivity helps alleviate pore pressure build-up. Simulation results suggest that the injection schedule adopted during the actual pilot test very likely did not affect the mechanical integrity of the storage complex. Fault reactivation requires injection volumes of at least about sixty times larger than the actual injected volume at the same injection rate. Hydraulic fracturing necessitates much larger injection rates than the ones used in the Frio pilot test. Tested rock samples exhibit ductile deformation at in-situ effective stresses. Hence, we do not expect an increase of fault permeability in the Frio sand even in the presence of fault reactivation.

Measurement and Visualization of Tight Rock Exposed to CO2 Using NMR Relaxometry and MRI

PubMed Central

Wang, Haitao; Lun, Zengmin; Lv, Chengyuan; Lang, Dongjiang; Ji, Bingyu; Luo, Ming; Pan, Weiyi; Wang, Rui; Gong, Kai

2017-01-01

Understanding mechanisms of oil mobilization of tight matrix during CO2 injection is crucial for CO2 enhanced oil recovery (EOR) and sequestration engineering design. In this study exposure behavior between CO2 and tight rock of the Ordos Basin has been studied experimentally by using nuclear magnetic resonance transverse relaxation time (NMR T2) spectrum and magnetic resonance imaging (MRI) under the reservoir pressure and temperature. Quantitative analysis of recovery at the pore scale and visualization of oil mobilization are achieved. Effects of CO2 injection, exposure times and pressure on recovery performance have been investigated. The experimental results indicate that oil in all pores can be gradually mobilized to the surface of rock by CO2 injection. Oil mobilization in tight rock is time-consuming while oil on the surface of tight rock can be mobilized easily. CO2 injection can effectively mobilize oil in all pores of tight rock, especially big size pores. This understanding of process of matrix exposed to CO2 could support the CO2 EOR in tight reservoirs. PMID:28281697

40 CFR 98.440 - Definition of the source category.

Code of Federal Regulations, 2011 CFR

2011-07-01

... comprises any well or group of wells that inject a CO2 stream for long-term containment in subsurface... where a CO2 stream is being injected in subsurface geologic formations to enhance the recovery of oil or natural gas unless one of the following applies: (1) The owner or operator injects the CO2 stream for long...

40 CFR 98.440 - Definition of the source category.

Code of Federal Regulations, 2013 CFR

2013-07-01

... comprises any well or group of wells that inject a CO2 stream for long-term containment in subsurface... where a CO2 stream is being injected in subsurface geologic formations to enhance the recovery of oil or natural gas unless one of the following applies: (1) The owner or operator injects the CO2 stream for long...

40 CFR 98.440 - Definition of the source category.

Code of Federal Regulations, 2014 CFR

2014-07-01

... comprises any well or group of wells that inject a CO2 stream for long-term containment in subsurface... where a CO2 stream is being injected in subsurface geologic formations to enhance the recovery of oil or natural gas unless one of the following applies: (1) The owner or operator injects the CO2 stream for long...

40 CFR 98.440 - Definition of the source category.

Code of Federal Regulations, 2012 CFR

2012-07-01

... comprises any well or group of wells that inject a CO2 stream for long-term containment in subsurface... where a CO2 stream is being injected in subsurface geologic formations to enhance the recovery of oil or natural gas unless one of the following applies: (1) The owner or operator injects the CO2 stream for long...

The response of abyssal organisms to low pH conditions during a series of CO2-release experiments simulating deep-sea carbon sequestration

NASA Astrophysics Data System (ADS)

Barry, J. P.; Buck, K. R.; Lovera, C.; Brewer, P. G.; Seibel, B. A.; Drazen, J. C.; Tamburri, M. N.; Whaling, P. J.; Kuhnz, L.; Pane, E. F.

2013-08-01

The effects of low-pH, high-pCO2 conditions on deep-sea organisms were examined during four deep-sea CO2 release experiments simulating deep-ocean C sequestration by the direct injection of CO2 into the deep sea. We examined the survival of common deep-sea, benthic organisms (microbes; macrofauna, dominated by Polychaeta, Nematoda, Crustacea, Mollusca; megafauna, Echinodermata, Mollusca, Pisces) exposed to low-pH waters emanating as a dissolution plume from pools of liquid carbon dioxide released on the seabed during four abyssal CO2-release experiments. Microbial abundance in deep-sea sediments was unchanged in one experiment, but increased under environmental hypercapnia during another, where the microbial assemblage may have benefited indirectly from the negative impact of low-pH conditions on other taxa. Lower abyssal metazoans exhibited low survival rates near CO2 pools. No urchins or holothurians survived during 30-42 days of exposure to episodic, but severe environmental hypercapnia during one experiment (E1; pH reduced by as much as ca. 1.4 units). These large pH reductions also caused 75% mortality for the deep-sea amphipod, Haploops lodo, near CO2 pools. Survival under smaller pH reductions (ΔpH<0.4 units) in other experiments (E2, E3, E5) was higher for all taxa, including echinoderms. Gastropods, cephalopods, and fish were more tolerant than most other taxa. The gastropod Retimohnia sp. and octopus Benthoctopus sp. survived exposure to pH reductions that episodically reached -0.3 pH units. Ninety percent of abyssal zoarcids (Pachycara bulbiceps) survived exposure to pH changes reaching ca. -0.3 pH units during 30-42 day-long experiments.

Monitoring field scale CO2 injection from time-lapse seismic and well log, integrating with advanced rock physics model at Cranfield EOR site

NASA Astrophysics Data System (ADS)

Ghosh, Ranjana

2017-12-01

Causes and effects of global warming have been highly debated in recent years. Nonetheless, injection and storage of CO2 (CO2 sequestration) in the subsurface is becoming increasingly accepted as a viable tool to reduce the amount of CO2 from the atmosphere, which is a primary contributor to global warming. Monitoring of CO2 movement with time is essential to ascertain that sequestration is not hazardous. A method is proposed here to appraise CO2 saturation from seismic attributes using differential effective medium theory modified for pressure (PDEM). The PDEM theory accounts pressure-induced fluid flow between cavities, which is a very important investigation in the CO2-sequestered regime of heterogeneous microstructure. The study area is the lower Tuscaloosa formation at Cranfield in Mississippi, USA, which is one of the active enhanced oil recovery (EOR), and CO2 capture and storage (CCS) fields. Injection well (F1) and two observation wells (F2 and F3) are present close (within 112 m) to the detailed area of study for this region. Since the three wells are closely situated, two wells, namely injection well F1 and the furthest observation well F3, have been focused on to monitor CO2 movement. Time-lapse (pre- and post-injection) log, core and surface seismic data are used in the quantitative assessment of CO2 saturation from the PDEM theory. It has been found that after approximately 9 months of injection, average CO2 saturations in F1 and F3 are estimated as 50% in a zone of thickness 25 m at a depth of 3 km.

Guest Molecule Exchange Kinetics for the 2012 Ignik Sikumi Gas Hydrate Field Trial

DOE Office of Scientific and Technical Information (OSTI.GOV)

White, Mark D.; Lee, Won Suk

A commercially viable technology for producing methane from natural gas hydrate reservoirs remains elusive. Short-term depressurization field tests have demonstrated the potential for producing natural gas via dissociation of the clathrate structure, but the long-term performance of the depressurization technology ultimately requires a heat source to sustain the dissociation. A decade of laboratory experiments and theoretical studies have demonstrated the exchange of pure CO2 and N2-CO2 mixtures with CH4 in sI gas hydrates, yielding critical information about molecular mechanisms, recoveries, and exchange kinetics. Findings indicated the potential for producing natural gas with little to no production of water and rapidmore » exchange kinetics, generating sufficient interest in the guest-molecule exchange technology for a field test. In 2012 the U.S. DOE/NETL, ConocoPhillips Company, and Japan Oil, Gas and Metals National Corporation jointly sponsored the first field trial of injecting a mixture of N2-CO2 into a CH4-hydrate bearing formation beneath the permafrost on the Alaska North Slope. Known as the Ignik Sikumi #1 Gas Hydrate Field Trial, this experiment involved three stages: 1) the injection of a N2-CO2 mixture into a targeted hydrate-bearing layer, 2) a 4-day pressurized soaking period, and 3) a sustained depressurization and fluid production period. Data collected during the three stages of the field trial were made available after an extensive quality check. These data included continuous temperature and pressure logs, injected and recovered fluid compositions and volumes. The Ignik Sikumi #1 data set is extensive, but contains no direct evidence of the guest-molecule exchange process. This investigation is directed at using numerical simulation to provide an interpretation of the collected data. A numerical simulator, STOMP-HYDT-KE, was recently completed that solves conservation equations for energy, water, mobile fluid guest molecules, and hydrate guest molecules, for up to three gas hydrate guest molecules: CH4, CO2, and N2. The independent tracking of mobile fluid and hydrate guest molecules allows for the kinetic exchange of guest molecules between the mobile fluids and hydrate. The particular interest of this numerical investigation is to determine whether kinetic exchange parameters, determined from laboratory-scale experiments, are directly applicable to interpreting the Ignik Sikumi #1 data.« less

Development of tunable high pressure CO2 laser for lidar measurements of pollutants and wind velocities

NASA Technical Reports Server (NTRS)

Levine, J. S.; Guerra, M.; Javan, A.

1980-01-01

The problem of laser energy extraction at a tunable monochromatic frequency from an energetic high pressure CO2 pulsed laser plasma, for application to remote sensing of atmospheric pollutants by Differential Absorption Lidar (DIAL) and of wind velocities by Doppler Lidar, was investigated. The energy extraction principle analyzed is based on transient injection locking (TIL) at a tunable frequency. Several critical experiments for high gain power amplification by TIL are presented.

DE-SC0004118 (Wong & Lindquist). Final Report: Changes of Porosity, Permeability and Mechanical Strength Induced by Carbon Dioxide Sequestration.

DOE Office of Scientific and Technical Information (OSTI.GOV)

WONG, TENG-FONG; Lindquist, Brent

In the context of CO{sub 2} sequestration, the overall objective of this project is to conduct a systematic investigation of how the flow of the acidic, CO{sub 2} saturated, single phase component of the injected/sequestered fluid changes the microstructure, permeability and strength of sedimentary rocks, specifically limestone and sandstone samples. Hydromechanical experiments, microstructural observations and theoretical modeling on multiple scales were conducted.

Using noble gas tracers to estimate residual CO2 saturation in the field: results from the CO2CRC Otway residual saturation and dissolution test

NASA Astrophysics Data System (ADS)

LaForce, T.; Ennis-King, J.; Paterson, L.

2013-12-01

Residual CO2 saturation is a critically important parameter in CO2 storage as it can have a large impact on the available secure storage volume and post-injection CO2 migration. A suite of single-well tests to measure residual trapping was conducted at the Otway test site in Victoria, Australia during 2011. One or more of these tests could be conducted at a prospective CO2 storage site before large-scale injection. The test involved injection of 150 tonnes of pure carbon dioxide followed by 454 tonnes of CO2-saturated formation water to drive the carbon dioxide to residual saturation. This work presents a brief overview of the full test sequence, followed by the analysis and interpretation of the tests using noble gas tracers. Prior to CO2 injection krypton (Kr) and xenon (Xe) tracers were injected and back-produced to characterise the aquifer under single-phase conditions. After CO2 had been driven to residual the two tracers were injected and produced again. The noble gases act as non-partitioning aqueous-phase tracers in the undisturbed aquifer and as partitioning tracers in the presence of residual CO2. To estimate residual saturation from the tracer test data a one-dimensional radial model of the near-well region is used. In the model there are only two independent parameters: the apparent dispersivity of each tracer and the residual CO2 saturation. Independent analysis of the Kr and Xe tracer production curves gives the same estimate of residual saturation to within the accuracy of the method. Furthermore the residual from the noble gas tracer tests is consistent with other measurements in the sequence of tests.

Thermal effects on geologic carbon storage

DOE Office of Scientific and Technical Information (OSTI.GOV)

Vilarrasa, Victor; Rutqvist, Jonny

One of the most promising ways to significantly reduce greenhouse gases emissions, while carbon-free energy sources are developed, is Carbon Capture and Storage (CCS). Non-isothermal effects play a major role in all stages of CCS. In this paper, we review the literature on thermal effects related to CCS, which is receiving an increasing interest as a result of the awareness that the comprehension of non-isothermal processes is crucial for a successful deployment of CCS projects. We start by reviewing CO 2 transport, which connects the regions where CO 2 is captured with suitable geostorage sites. The optimal conditions for COmore » 2 transport, both onshore (through pipelines) and offshore (through pipelines or ships), are such that CO 2 stays in liquid state. To minimize costs, CO 2 should ideally be injected at the wellhead in similar pressure and temperature conditions as it is delivered by transport. To optimize the injection conditions, coupled wellbore and reservoir simulators that solve the strongly non-linear problem of CO 2 pressure, temperature and density within the wellbore and non-isothermal two-phase flow within the storage formation have been developed. CO 2 in its way down the injection well heats up due to compression and friction at a lower rate than the geothermal gradient, and thus, reaches the storage formation at a lower temperature than that of the rock. Inside the storage formation, CO 2 injection induces temperature changes due to the advection of the cool injected CO 2, the Joule-Thomson cooling effect, endothermic water vaporization and exothermic CO 2 dissolution. These thermal effects lead to thermo-hydro-mechanical-chemical coupled processes with non-trivial interpretations. These coupled processes also play a relevant role in “Utilization” options that may provide an added value to the injected CO 2 , such as Enhanced Oil Recovery (EOR), Enhanced Coal Bed Methane (ECBM) and geothermal energy extraction combined with CO 2 storage. If the injected CO 2 leaks through faults, the caprock or wellbores, strong cooling will occur due to the expansion of CO 2 as pressure decreases with depth. Finally, we conclude by identifying research gaps and challenges of thermal effects related to CCS.« less

Thermal effects on geologic carbon storage

DOE PAGES

Vilarrasa, Victor; Rutqvist, Jonny

2016-12-27

One of the most promising ways to significantly reduce greenhouse gases emissions, while carbon-free energy sources are developed, is Carbon Capture and Storage (CCS). Non-isothermal effects play a major role in all stages of CCS. In this paper, we review the literature on thermal effects related to CCS, which is receiving an increasing interest as a result of the awareness that the comprehension of non-isothermal processes is crucial for a successful deployment of CCS projects. We start by reviewing CO 2 transport, which connects the regions where CO 2 is captured with suitable geostorage sites. The optimal conditions for COmore » 2 transport, both onshore (through pipelines) and offshore (through pipelines or ships), are such that CO 2 stays in liquid state. To minimize costs, CO 2 should ideally be injected at the wellhead in similar pressure and temperature conditions as it is delivered by transport. To optimize the injection conditions, coupled wellbore and reservoir simulators that solve the strongly non-linear problem of CO 2 pressure, temperature and density within the wellbore and non-isothermal two-phase flow within the storage formation have been developed. CO 2 in its way down the injection well heats up due to compression and friction at a lower rate than the geothermal gradient, and thus, reaches the storage formation at a lower temperature than that of the rock. Inside the storage formation, CO 2 injection induces temperature changes due to the advection of the cool injected CO 2, the Joule-Thomson cooling effect, endothermic water vaporization and exothermic CO 2 dissolution. These thermal effects lead to thermo-hydro-mechanical-chemical coupled processes with non-trivial interpretations. These coupled processes also play a relevant role in “Utilization” options that may provide an added value to the injected CO 2 , such as Enhanced Oil Recovery (EOR), Enhanced Coal Bed Methane (ECBM) and geothermal energy extraction combined with CO 2 storage. If the injected CO 2 leaks through faults, the caprock or wellbores, strong cooling will occur due to the expansion of CO 2 as pressure decreases with depth. Finally, we conclude by identifying research gaps and challenges of thermal effects related to CCS.« less

Technological Innovations of Carbon Dioxide Injection in EAF-LF Steelmaking

NASA Astrophysics Data System (ADS)

Wei, Guangsheng; Zhu, Rong; Wu, Xuetao; Dong, Kai; Yang, Lingzhi; Liu, Runzao

2018-06-01

In this study, the recent innovations and improvements in carbon dioxide (CO2) injection technologies for electric arc furnace (EAF)-ladle furnace (LF) steelmaking processes have been reviewed. The utilization of CO2 in the EAF-LF steelmaking process resulted in improved efficiency, purity and environmental impact. For example, coherent jets with CO2 and O2 mixed injection can reduce the amount of iron loss and dust generation, and submerged O2 and powder injection with CO2 in an EAF can increase the production efficiency and improve the dephosphorization and denitrification characteristics. Additionally, bottom-blowing CO2 in an EAF can strengthen molten bath stirring and improve nitrogen removal, while bottom-blowing CO2 in a LF can increase the rate of desulfurization and improve the removal of inclusions. Based on these innovations, a prospective process for the cyclic utilization of CO2 in the EAF-LF steelmaking process is introduced that is effective in mitigating greenhouse gas emissions from the steelmaking shop.

Technological Innovations of Carbon Dioxide Injection in EAF-LF Steelmaking

NASA Astrophysics Data System (ADS)

Wei, Guangsheng; Zhu, Rong; Wu, Xuetao; Dong, Kai; Yang, Lingzhi; Liu, Runzao

2018-03-01

In this study, the recent innovations and improvements in carbon dioxide (CO2) injection technologies for electric arc furnace (EAF)-ladle furnace (LF) steelmaking processes have been reviewed. The utilization of CO2 in the EAF-LF steelmaking process resulted in improved efficiency, purity and environmental impact. For example, coherent jets with CO2 and O2 mixed injection can reduce the amount of iron loss and dust generation, and submerged O2 and powder injection with CO2 in an EAF can increase the production efficiency and improve the dephosphorization and denitrification characteristics. Additionally, bottom-blowing CO2 in an EAF can strengthen molten bath stirring and improve nitrogen removal, while bottom-blowing CO2 in a LF can increase the rate of desulfurization and improve the removal of inclusions. Based on these innovations, a prospective process for the cyclic utilization of CO2 in the EAF-LF steelmaking process is introduced that is effective in mitigating greenhouse gas emissions from the steelmaking shop.

Application of intracytoplasmic sperm injection (ICSI) for fertilization and development in birds.

PubMed

Shimada, Kiyoshi; Ono, Tamao; Mizushima, Shusei

2014-01-15

Intracytoplasmic sperm injection (ICSI) technology in birds has been hampered due to opacity of oocyte. We developed ICSI-assisted fertilization and gene transfer in quail. This paper reviews recent advances of our ICSI experiments. The oocyte retrieved from the oviduct and a quail sperm was injected into the oocyte under a stereomicroscope. The oocyte was cultured for 24h at 41°C under 5% CO2 in air. The fertilization and development was assessed by microscopic observation. The fertility rate ranged 12-18% and development varied from stage II to V in trials. To improve the fertility rate, phospholipase C (PLC) zeta was injected with a sperm. It was increased to 37-50%. Furthermore, injection of inositol trisphosphate increased to over 85%. Quail oocyte can be fertilized with chicken sperm and so can testicular elongated spermatid. To extend embryonic development, chicken eggshell was used as a surrogate culture at 37°C after the 24h incubation at 41°C under 5% CO2 in air. It survived up to 2days thereafter. Finally, gene transfer was attempted in quail egg. The sperm membrane was disrupted with Triton X-100 (TX-100) and was injected with PLCzeta cRNA and enhanced green fluorescent protein (EGFP) gene in oocyte. The GFP expression was evaluated at 24h incubation at 41°C under 5% CO2 in air in the embryos. While the expression was not detected in the control oocytes, the experimental treatment induced blastoderm development (44%) of the oocytes and 86% of blastoderm showed fluorescent emission. In addition, PCR analysis detected EGFP fragments in 50% of GFP-expressing blastoderm. Our ICSI method may be the first step toward the production of transgenic birds. Copyright © 2013 Elsevier Inc. All rights reserved.

Release of Dissolved CO2 from Water in Laboratory Porous Media Following Rapid Depressurization

NASA Astrophysics Data System (ADS)

Crews, J. B.; Cooper, C. A.

2011-12-01

A bench-top laboratory study is undertaken to investigate the effects of seismic shocks on brine aquifers into which carbon dioxide has been injected for permanent storage. Long-term storage in deep saline aquifers has been proposed and studied as one of the most viable near-term options for sequestering fossil fuel-derived carbon dioxide from the atmosphere to curb anthropogenic climate change. Upon injection into the subsurface, it is expected that CO2, as either a gas or supercritical fluid, will mix convectively with the formation water. The possibility exists, however, that dissolved CO2 will come out of solution as a result of an earthquake. The effect is similar to that of slamming an unsealed container of carbonated beverage on a table; previously dissolved CO2 precipitates, forms bubbles, and rises due to buoyancy. In this study, we measure the change in gas-phase CO2 concentration as a function of the magnitude of the shock and the initial concentration of CO2. In addition, we investigate and seek to characterize the nucleation and transport of CO2 bubbles in a porous medium after a seismic shock. Experiments are conducted using a Hele-Shaw cell and a CCD camera to quantify the fraction of dissolved CO2 that comes out of solution as a result of a sharp mechanical impulse. The data are used to identify and constrain the conditions under which CO2 comes out of solution and, further, to understand the end-behavior of the precipitated gas-phase CO2 as it moves through or is immobilized in a porous medium.

The European FP7 ULTimateCO2 project: A comprehensive approach to study the long term fate of CO2 geological storage sites

NASA Astrophysics Data System (ADS)

Audigane, P.; Brown, S.; Dimier, A.; Pearce, J.; Frykman, P.; Maurand, N.; Le Gallo, Y.; Spiers, C. J.; Cremer, H.; Rutters, H.; Yalamas, T.

2013-12-01

The European FP7 ULTimateCO2 project aims at significantly advance our knowledge of specific processes that could influence the long-term fate of geologically stored CO2: i) trapping mechanisms, ii) fluid-rock interactions and effects on mechanical integrity of fractured caprock and faulted systems and iii) leakage due to mechanical and chemical damage in the well vicinity, iv) brine displacement and fluid mixing at regional scale. A realistic framework is ensured through collaboration with two demonstration sites in deep saline sandstone formations: the onshore former NER300 West Lorraine candidate in France (ArcelorMittal GeoLorraine) and the offshore EEPR Don Valley (former Hatfield) site in UK operated by National Grid. Static earth models have been generated at reservoir and basin scale to evaluate both trapping mechanisms and fluid displacement at short (injection) and long (post injection) time scales. Geochemical trapping and reservoir behaviour is addressed through experimental approaches using sandstone core materials in batch reactive mode with CO2 and impurities at reservoir pressure and temperature conditions and through geochemical simulations. Collection of data has been generated from natural and industrial (oil industry) analogues on the fluid flow and mechanical properties, structure, and mineralogy of faults and fractures that could affect the long-term storage capacity of underground CO2 storage sites. Three inter-related lines of laboratory experiments investigate the long-term evolution of the mechanical properties and sealing integrity of fractured and faulted caprocks using Opalinus clay of Mont Terri Gallery (Switzerland) (OPA), an analogue for caprock well investigated in the past for nuclear waste disposal purpose: - Characterization of elastic parameters in intact samples by measuring strain during an axial experiment, - A recording of hydraulic fracture flow properties by loading and shearing samples in order to create a 'realistic' fracture, followed by a gas injection in the fracture plan, - An assessment of temperature influences on carbonate and water content which affect carbonate bearing fault gouge using shear experiments at 20C and 120C on simulated fault gouges prepared by crushed OPA samples. To evaluate the interactions between CO2 (and formation fluids) and the well environment (formation, cement, casing) and to assess the consequences of these interactions on the transport properties of well materials, a 1:1 scale experiment has been set in the OPA to reproduce classical well objects (cemented annulus, casing and cement plug) perforating caprock formations (OPA). Innovative probabilistic modelling tools are also under development in order to build robust calibration methods for uncertainty management of the simulated long term scenarios.

Reservoir fluid and gas chemistry during CO2 injection at the Cranfield field, Mississippi, USA

NASA Astrophysics Data System (ADS)

Lu, J.; Kharaka, Y. K.; Cole, D. R.; Horita, J.; Hovorka, S.

2009-12-01

At Cranfield field, Mississippi, USA, a monitored CO2-EOR project provides a unique opportunity to understand geochemical interactions of injected CO2 within the reservoir. Cranfield field, discovered in 1943, is a simple anticlinal four-way closure and had a large gas cap surrounded by an oil ring (Mississippi Oil and Gas Board, 1966). The field was abandoned in 1966. The reservoir returned to original reservoir pressure (hydrostatic pressure) by a strong aquifer drive by 2008. The reservoir is in the lower Tuscaloosa Formation at depths of more than 3000 m. It is composed of stacked and incised channel fills and is highly heterogeneous vertically and horizontally. A variable thickness (5 to 15 m) of terrestrial mudstone directly overlies the basal sandstone providing the primary seal, isolating the injection interval from a series of fluvial sand bodies occurring in the overlying 30 m of section. Above these fluvial channels, the marine mudstone of the Middle Tuscaloosa forms a continuous secondary confining system of approximately 75 m. The sandstones of the injection interval are rich in iron, containing abundant diagenetic chamosite (ferroan chlorite), hematite and pyrite. Geochemical modeling suggests that the iron-bearing minerals will be dissolved in the face of high CO2 and provide iron for siderite precipitation. CO2 injection by Denbury Resources Inc. begun in mid-July 2008 on the north side of the field with rates at ~500,000 tones per year. Water and gas samples were taken from seven production wells after eight months of CO2 injection. Gas analyses from three wells show high CO2 concentrations (up to 90 %) and heavy carbon isotopic signatures similar to injected CO2, whereas the other wells show original gas composition and isotope. The mixing ratio between original and injected CO2 is calculated based on its concentration and carbon isotope. However, there is little variation in fluid samples between the wells which have seen various levels of CO2. Comparison between preinjection and postinjection fluid analyses also shows little difference. It suggests that CO2 injection has not induced significant mineral-water reactions to change water chemistry. In October 2009, CO2 will be injected into the down-dip, non-productive Tuscaloosa Formation on the east side of the same field. In-situ fluid and gas samples will be collected using downhole U-tube. Fluid chemistry data through time will reveal mineral reactions during and after injection and confine timescales of the interactions. This project was funded thought the National Energy Technology Laboratory Regional Carbon Sequestration Partnership Program as part of the Southeast Regional Carbon Sequestration Partnership.

Status of Geological Storage of CO2 as Part of Negative Emissions Strategy

NASA Astrophysics Data System (ADS)

Benson, S. M.

2014-12-01

Recent analyses show that many GHG stabilization scenarios require technologies that permanently extract CO2 from the atmosphere -so-called "net negative emissions." Among the most promising negative emissions approaches is bioenergy with carbon capture and storage (BECCS). The most mature options for CO2 storage are in sedimentary rocks located in thick sedimentary basins. Within those basins, CO2 can be stored either in depleted or depleting hydrocarbon formations or in so-called saline aquifers. In addition to the economic costs of bioenergy with CO2 capture, key to the success of and scale at which BECCS can contribute to negative emissions is the ability to store quantities on the order of 1 Gt per year of CO2. Today, about 65 Mt of CO2 per year are injected underground for the purposes of enhancing oil recovery (CO2-EOR) or for CO2 storage, the vast majority being for CO2-EOR. Achieving 1 Gt per year of negative emissions will require a 15-fold scale up of the current injection operations. This paper will review the conditions necessary for storage at this scale, identify what has been learned from nearly 2 decades of experience with CO2 storage that provides insight into the feasibility of CO2 storage on this scale, and identify critical issues that remain to be resolved to meet these ambitious negative emissions targets. Critical technological issues include but are not limited to: the amount of CO2 storage capacity that is available and where it is located in relation to biomass energy resources; identification of sustainable injection rates and how this depends on the properties of the geological formation; the extent to which water extraction will be required to manage the magnitude of pressure buildup; identification of regions at high risk for induced seismicity that could damage structures and infrastructure; and selection of sites with a adequate seals to permanently contain CO2. Social, economic and political issues are also important: including the support for and confidence in the projects by the local population; scale at which these projects are financially feasible; resolution of issues such as who pays and who benefits from these projects; and development of regulatory frameworks that are at the same time, environmentally protective and not overly burdensome.

The Ketzin Project, Germany - Status and Future of the First European on-shore CO2 Storage Site

NASA Astrophysics Data System (ADS)

Kuehn, M.; Martens, S.; Moeller, F.; Lueth, S.; Liebscher, A.; Kempka, T.; Ketzin Group

2010-12-01

At the Ketzin site close to Berlin, the German Research Centre for Geosciences operates Europe’s first on-shore CO2 storage site with the aim of increasing the understanding of geological storage of CO2 in saline aquifers. Following site characterization and drilling of three wells, the in-situ field laboratory is fully in use since the CO2 injection started in June 2008. Our presentation summarizes key results from the first (Schilling et al. 2009) and second year (Martens et al. 2010) of injection and outlines future activities. Focus of the research is on interdisciplinary monitoring and modeling approaches. Since start of the CO2 injection on June 30, 2008, the injection facility has been reliably and safely operated. By the end of August 2010, about 37,700 tons of food grade CO2 have been injected into a sandstone aquifer of the Triassic Stuttgart Formation at a depth of about 630 to 700 m. The new project CO2MAN (CO2 Reservoir Management) is planned to succeed the EU-funded CO2SINK project which ended in March 2010 and further nationally funded projects. Our interdisciplinary monitoring concept for the Ketzin site integrates geophysical, geochemical and microbial investigations. Following baseline measurements prior to the injection, repeat measurements have been carried out for a comprehensive characterization of the reservoir and the developing CO2 plume. CO2MAN aims at continuing the injection up to a maximum of 100,000 tons of CO2, advancing the monitoring concept and further integrating numerical modeling. Planned activities include the installation of a third and a fourth observation well and the testing of well abandonment procedures. All data available from the Ketzin wells and the different monitoring techniques are going to be compiled into an integral geological model of the site. Such a geological model is the prerequisite for any holistic approach and understanding of CO2 storage not only at Ketzin. A variety of seismic methods, including cross-hole measurement between both observation wells, surface-downhole observations, and 2D and 3D surface surveys have been used in order to cover the near-injection to regional scale. In addition, geoelectric methods including cross-hole measurements between the wells and additional surface and surface-downhole electrical resistivity tomography have been applied to monitor the CO2 migration process. Geological modeling and dynamic flow modeling is conducted in different phases, including pre-existing data, information obtained from drilling and subsequent CO2 injection. On-going modeling also integrates recent geophysical monitoring data in order to improve the understanding of geological heterogeneities at the Ketzin site and their impact on the CO2 plume distribution. Martens S., Liebscher A., Möller F., Würdemann H, Schilling F., Kühn M., and Ketzin Group (2010) Progress Report on the First European on-shore CO2 Storage Site at Ketzin (Germany) - Second Year of Injection, GHGT 10, subm. Schilling F., Borm G., Würdemann H., Möller F., Kühn M., CO2SINK Group (2009) Status Report on the First European on-shore CO2 Storage Site at Ketzin (Germany). GHGT 9, Energy Procedia 1(1) 2029-2035, doi: 10.1016/j.egypro.2009.01.264

Gas-water-rock interactions in sedimentary basins: CO2 sequestration in the Frio Formation, Texas, USA

USGS Publications Warehouse

Kharaka, Y.K.; Cole, D.R.; Thordsen, J.J.; Kakouros, E.; Nance, H.S.

2006-01-01

To investigate the potential for the geologic storage of CO2 in saline sedimentary aquifers, 1600??ton of CO2 were injected at ???1500 m depth into a 24-m sandstone section of the Frio Formation - a regional reservoir in the US Gulf Coast. Fluid samples obtained from the injection and observation wells before, during and after CO2 injection show a Na-Ca-Cl type brine with 93,000??mg/L TDS and near saturation of CH4 at reservoir conditions. As injected CO2 gas reached the observation well, results showed sharp drops in pH (6.5 to 5.7), pronounced increases in alkalinity (100 to 3000??mg/L as HCO3) and Fe (30 to 1100??mg/L), and significant shifts in the isotopic compositions of H2O and DIC. Geochemical modeling indicates that brine pH would have dropped lower, but for buffering by dissolution of calcite and Fe oxyhydroxides. Post-injection results show the brine gradually returning to its pre-injection composition. ?? 2006 Elsevier B.V. All rights reserved.

PNIPAAm-based biohybrid injectable hydrogel for cardiac tissue engineering.

PubMed

Navaei, Ali; Truong, Danh; Heffernan, John; Cutts, Josh; Brafman, David; Sirianni, Rachael W; Vernon, Brent; Nikkhah, Mehdi

2016-03-01

Injectable biomaterials offer a non-invasive approach to deliver cells into the myocardial infarct region to maintain a high level of cell retention and viability and initiate the regeneration process. However, previously developed injectable matrices often suffer from low bioactivity or poor mechanical properties. To address this need, we introduced a biohybrid temperature-responsive poly(N-isopropylacrylamide) PNIPAAm-Gelatin-based injectable hydrogel with excellent bioactivity as well as mechanical robustness for cardiac tissue engineering. A unique feature of our work was that we performed extensive in vitro biological analyses to assess the functionalities of cardiomyocytes (CMs) alone and in co-culture with cardiac fibroblasts (CFs) (2:1 ratio) within the hydrogel matrix. The synthesized hydrogel exhibited viscoelastic behavior (storage modulus: 1260 Pa) and necessary water content (75%) to properly accommodate the cardiac cells. The encapsulated cells demonstrated a high level of cell survival (90% for co-culture condition, day 7) and spreading throughout the hydrogel matrix in both culture conditions. A dense network of stained F-actin fibers (∼ 6 × 10(4) μm(2) area coverage, co-culture condition) illustrated the formation of an intact and three dimensional (3D) cell-embedded matrix. Furthermore, immunostaining and gene expression analyses revealed mature phenotypic characteristics of cardiac cells. Notably, the co-culture group exhibited superior structural organization and cell-cell coupling, as well as beating behavior (average ∼ 45 beats per min, co-culture condition, day 7). The outcome of this study is envisioned to open a new avenue for extensive in vitro characterization of injectable matrices embedded with 3D mono- and co-culture of cardiac cells prior to in vivo experiments. In this work, we synthesized a new class of biohybrid temperature-responsive poly(N-isopropylacrylamide) PNIPAAm-Gelatin-based injectable hydrogel with suitable bioactivity and mechanical properties for cardiac tissue engineering. A significant aspect of our work was that we performed extensive in vitro biological analyses to assess the functionality of cardiomyocytes alone and in co-culture with cardiac fibroblasts encapsulated within the 3D hydrogel matrix. Copyright © 2015 Acta Materialia Inc. Published by Elsevier Ltd. All rights reserved.

Potential environmental issues of CO2 storage in deep saline aquifers: Geochemical results from the Frio-I Brine Pilot test, Texas, USA

USGS Publications Warehouse

Kharaka, Yousif K.; Thordsen, James J.; Hovorka, Susan D.; Nance, H. Seay; Cole, David R.; Phelps, Tommy J.; Knauss, Kevin G.

2009-01-01

Sedimentary basins in general, and deep saline aquifers in particular, are being investigated as possible repositories for large volumes of anthropogenic CO2 that must be sequestered to mitigate global warming and related climate changes. To investigate the potential for the long-term storage of CO2 in such aquifers, 1600 t of CO2 were injected at 1500 m depth into a 24-m-thick "C" sandstone unit of the Frio Formation, a regional aquifer in the US Gulf Coast. Fluid samples obtained before CO2 injection from the injection well and an observation well 30 m updip showed a Na–Ca–Cl type brine with ∼93,000 mg/L TDS at saturation with CH4 at reservoir conditions; gas analyses showed that CH4 comprised ∼95% of dissolved gas, but CO2 was low at 0.3%. Following CO2 breakthrough, 51 h after injection, samples showed sharp drops in pH (6.5–5.7), pronounced increases in alkalinity (100–3000 mg/L as HCO3) and in Fe (30–1100 mg/L), a slug of very high DOC values, and significant shifts in the isotopic compositions of H2O, DIC, and CH4. These data, coupled with geochemical modeling, indicate corrosion of pipe and well casing as well as rapid dissolution of minerals, especially calcite and iron oxyhydroxides, both caused by lowered pH (initially ∼3.0 at subsurface conditions) of the brine in contact with supercritical CO2.These geochemical parameters, together with perfluorocarbon tracer gases (PFTs), were used to monitor migration of the injected CO2 into the overlying Frio “B”, composed of a 4-m-thick sandstone and separated from the “C” by ∼15 m of shale and siltstone beds. Results obtained from the Frio “B” 6 months after injection gave chemical and isotopic markers that show significant CO2 (2.9% compared with 0.3% CO2 in dissolved gas) migration into the “B” sandstone. Results of samples collected 15 months after injection, however, are ambiguous, and can be interpreted to show no additional injected CO2 in the “B” sandstone. The presence of injected CO2 may indicate migration from “C” to “B” through the intervening beds or, more likely, a short-term leakage through the remedial cement around the casing of a 50-year old well. Results obtained to date from four shallow monitoring groundwater wells show no brine or CO2 leakage through the Anahuac Formation, the regional cap rock.

Geologic Storage of CO2: Leakage Pathways and Environmental Risks

NASA Astrophysics Data System (ADS)

Celia, M. A.; Peters, C. A.; Bachu, S.

2002-05-01

Geologic storage of CO2 appears to be an attractive option for carbon mitigation because it offers sufficient capacity to solve the problem, and it can be implemented with existing technology. Among the list of options for storage sites, depleted hydrocarbon reservoirs and deep saline aquifers are two major categories. While injection into hydrocarbon reservoirs offers immediate possibilities, especially in the context of enhanced oil recovery, it appears that deep saline aquifers provide the extensive capacity necessary to solve the problem over the decade to century time scale. Capacity and technology argue favorably for this option, but remaining obstacles to implementation include capture technologies, overall economic considerations, and potential environmental consequences of the injection. Of these, the environmental questions may be most difficult to solve. Experience from CO2 floods for enhanced oil recovery and from CO2 and acid gas disposal operations indicates that geological storage of CO2 is safe over the short term for comparatively small amounts of CO2. However, there is no experience to date regarding the long-term fate and safety of the large volumes of CO2 that must be injected to significantly reduce atmospheric emissions. In order to make proper evaluation of environmental risks, the full range of possible environmental consequences must be considered. Most of these environmental concerns involve migration and leakage of CO2 into shallow portions of the subsurface and eventually into the atmosphere. In shallow subsurface zones, elevated levels of carbon dioxide can cause pH changes, leading to possible mobilization of ground-water contaminants including metals. In the unsaturated zone, vegetation can be adversely affected, as can other ecosystem components. At the land surface, elevated levels of CO2 can lead to asphyxiation in humans and other animals. And finally, in the atmosphere, CO2 that leaks from underground diminishes the effectiveness of the overall storage scheme and contributes to possible climate change. To characterize these environmental consequences, reliable models of leakage characteristics and rates are needed. While leakage through natural flowpaths in the subsurface may occur, a more likely pathway is leakage through abandoned wells. This may be especially troublesome in mature sedimentary basins, which are often "punctured" by a very large number of exploration and production wells. For example, in the Alberta Basin there are more than 100,000 abandoned wells, the oldest from 1883. The cement used in the completion and abandonment of these wells, historically of variable quality and quantity, most probably has degraded with age and under the effect of formation brines. The cement may degrade even more rapidly when contacted by CO2 and possibly other components in the injection mixture (such as H2S). Cement properties and their modification through time must be understood in order to provide reliable estimates of leakage rates. Those leakage rates must then be linked to models of environmental consequences, and ultimately the entire analysis must be embedded in a probabilistic framework. Such an approach will allow leakage to be addressed rationally in terms of safety and long-term environmental impacts.

Stochastic Modeling of CO2 Migrations and Chemical Reactions in Deep Saline Formations

NASA Astrophysics Data System (ADS)

Ni, C.; Lee, I.; Lin, C.

2013-12-01

Carbon capture and storage (CCS) has been recognized the feasible technology that can significant reduce the anthropogenic CO2 emissions from large point sources. The CO2 injection in geological formations is one of the options to permanently store the captured CO2. Based on this concept a large number of target formations have been identified and intensively investigated with different types of techniques such as the hydrogeophysical experiments or numerical simulations. The numerical simulations of CO2 migrations in saline formations recently gather much attention because a number of models are available for this purpose and there are potential sites existing in many countries. The lower part of Cholan Formation (CF) near Changhua Coastal Industrial Park (CCIP) in west central Taiwan was identified the largest potential site for CO2 sequestration. The top elevations of the KF in this area varies from 1300 to 1700m below the sea level. Laboratory experiment showed that the permeability of CF is 10-14 to 10-12 m2. Over the years the offshore seismic survey and limited onshore borehole logs have provided information for the simulation of CO2 migration in the CF although the original investigations might not focus on the purpose of CO2 sequestration. In this study we modify the TOUGHREACT model to consider the small-scale heterogeneity in target formation and the cap rock of upper CF. A Monte Carlo Simulation (MCS) approach based on the TOUGHREACT model is employed to quantify the effect of small-scale heterogeneity on the CO2 migrations and hydrochemical reactions in the CF. We assume that the small-scale variability of permeability in KF can be described with a known Gaussian distribution. Therefore, the Gaussian type random field generator such as Sequential Gaussian Simulation (SGSIM) in Geostatistical Software Library (GSLIB) can be used to provide the random permeability realizations for the MCS. A variety of statistical parameters such as the variances and correlation lengths in a Gaussian covariance model are varied in the MCS and the uncertainty of the CO2 and other chemical concentrations are evaluated based on 144 random realizations. In this study a constant injection rate of100Mt/year supercritical CO2 is applied in the bottom of CF. The continuous injection time is 20 years and the uncertainty results are evaluated at 100 years. By comparing with the case without small-scale variability simulation results show that the CO2 plume sizes in the horizontal direction increase from tens of meters to hundreds of meters when the variances of small-scale variability are varied from 1.0 to 4.0. The changes of correlation lengths (i.e., from 100m, 200m, to 400m) show small contribution on the size increases of CO2 plumes. Other uncertainties of chemical concentrations show behaviors similar to the CO2 plume patterns.

CO2-Water-Rock Wettability: Variability, Influencing Factors, and Implications for CO2 Geostorage.

PubMed

Iglauer, Stefan

2017-05-16

Carbon geosequestration (CGS) has been identified as a key technology to reduce anthropogenic greenhouse gas emissions and thus significantly mitigate climate change. In CGS, CO 2 is captured from large point-source emitters (e.g., coal fired power stations), purified, and injected deep underground into geological formations for disposal. However, the CO 2 has a lower density than the resident formation brine and thus migrates upward due to buoyancy forces. To prevent the CO 2 from leaking back to the surface, four trapping mechanisms are used: (1) structural trapping (where a tight caprock acts as a seal barrier through which the CO 2 cannot percolate), (2) residual trapping (where the CO 2 plume is split into many micrometer-sized bubbles, which are immobilized by capillary forces in the pore network of the rock), (3) dissolution trapping (where CO 2 dissolves in the formation brine and sinks deep into the reservoir due to a slight increase in brine density), and (4) mineral trapping (where the CO 2 introduced into the subsurface chemically reacts with the formation brine or reservoir rock or both to form solid precipitates). The efficiency of these trapping mechanisms and the movement of CO 2 through the rock are strongly influenced by the CO 2 -brine-rock wettability (mainly due to the small capillary-like pores in the rock which form a complex network), and it is thus of key importance to rigorously understand CO 2 -wettability. In this context, a substantial number of experiments have been conducted from which several conclusions can be drawn: of prime importance is the rock surface chemistry, and hydrophilic surfaces are water-wet while hydrophobic surfaces are CO 2 -wet. Note that CO 2 -wet surfaces dramatically reduce CO 2 storage capacities. Furthermore, increasing pressure, salinity, or dissolved ion valency increases CO 2 -wettability, while the effect of temperature is not well understood. Indeed theoretical understanding of CO 2 -wettability and the ability to quantitatively predict it are currently limited although recent advances have been made. Moreover, data for real storage rock and real injection gas (which contains impurities) is scarce and it is an open question how realistic subsurface conditions can be reproduced in laboratory experiments. In conclusion, however, it is clear that in principal CO 2 -wettability can vary drastically from completely water-wet to almost completely CO 2 -wet, and this possible variation introduces a large uncertainty into trapping capacity and containment security predictions.

Impact of fluid injection velocity on CO2 saturation and pore pressure in porous sandstone

NASA Astrophysics Data System (ADS)

Kitamura, Keigo; Honda, Hiroyuki; Takaki, Shinnosuke; Imasato, Mitsunori; Mitani, Yasuhiro

2017-04-01

The elucidation of CO2 behavior in sandstone is an essential issue to understand the fate of injecting CO2 in reservoirs. Injected CO2 invades pore spaces and replaces with resident brine and forms complex two-phase flow with brine. It is considered that this complex CO2 flow arises CO2 saturation (SCO_2)and pore fluid pressure(Pp) and makes various types of CO2 distribution pattern in pore space. The estimation of SCO_2 in the reservoir is one of important task in CCS projects. Fluid pressure (Pp) is also important to estimate the integrity of CO2 reservoir and overlying cap rocks. Generally, elastic waves are used to monitor the changes of SCO_2. Previous experimental and theoretical studies indicated that SCO_2 and Pp are controlled by the fluid velocity (flow rate) of invaded phase. In this study, we conducted the CO2 injection test for Berea sandstone (φ=18.1{%}) under deep CO2 reservoir conditions (confining pressure: 20MPa; temperature: 40 rC). We try to estimate the changes of SCO_2 and Pp with changing CO2 injection rate (FR) from 10 to 5000 μ l/min for Berea sandstone. P-wave velocities (Vp) are also measured during CO2 injection test and used to investigate the relationships between SCO2 and these geophysical parameters. We set three Vp-measurement channels (ch.1, ch2 and ch.3 from the bottom) monitor the CO2 behavior. The result shows step-wise SCO_2 changes with increasing FR from 9 to 25 {%} in low-FR condition (10-500 μ l/min). Vp also shows step wise change from ch1 to ch.3. The lowermost channel (ch.1) indicates that Vp-reduction stops around 4{%} at 10μ m/min condition. However, ch.3 changes slightly from 4{%} at 10 μ l/min to 5{%} at 100 μ l/min. On the other hand, differential Pp (Δ P) dose not shows obvious changes from 10kPa to 30kPa. Over 1000 μ l/min, SCO_2 increases from 35 to 47 {%}. Vp of all channels show slight reductions and Vp-reductions reach constant values as 8{%}, 6{%} and 8{%}, respectively at 5000{}μ l/min. On the other hand, Δ P shows rapid increasing from 50kPa to 500 kPa. It suggests a drastic change of CO2 behavior with injection rate. CO2 flows gently and enlarges SCO_2up to 25 {%} under low FR conditions without arisen Δ P (

Coupled Hydro-Mechanical Modeling of Fluid Geological Storage

NASA Astrophysics Data System (ADS)

Castelletto, N.; Garipov, T.; Tchelepi, H. A.

2013-12-01

The accurate modeling of the complex coupled physical processes occurring during the injection and the post-injection period is a key factor for assessing the safety and the feasibility of anthropogenic carbon dioxide (CO2) sequestration in subsurface formations. In recent years, it has become widely accepted the importance of the coupling between fluid flow and geomechanical response in constraining the sustainable pressure buildup caused by fluid injection relative to the caprock sealing capacity, induced seismicity effects and ground surface stability [e.g., Rutqvist, 2012; Castelletto et al., 2013]. Here, we present a modeling approach based on a suitable combination of Finite Volumes (FVs) and Finite Elements (FEs) to solve the coupled system of partial differential equations governing the multiphase flow in a deformable porous medium. Specifically, a FV method is used for the flow problem while the FE method is adopted to address the poro-elasto-plasticity equations. The aim of the present work is to compare the performance and the robustness of unconditionally stable sequential-implicit schemes [Kim et al., 2011] and the fully-implicit method in solving the algebraic systems arising from the discretization of the governing equations, for both normally conditioned and severely ill-conditioned problems. The two approaches are tested against well-known analytical solutions and experimented with in a realistic application of CO2 injection in a synthetic aquifer. References: - Castelletto N., G. Gambolati, and P. Teatini (2013), Geological CO2 sequestration in multi-compartment reservoirs: Geomechanical challenges, J. Geophys. Res. Solid Earth, 118, 2417-2428, doi:10.1002/jgrb.50180. - Kim J., H. A. Tchelepi, and R. Juanes (2011), Stability, accuracy and efficiency of sequential methods for coupled flow and geomechanics, SPE J., 16(2), 249-262. - Rutqvist J. (2012), The geomechanics of CO2 storage in deep sedimentary formations, Geotech. Geol. Eng., 30, 525-551.

Performance Enhancement of Organic Light-Emitting Diodes Using Electron-Injection Materials of Metal Carbonates

NASA Astrophysics Data System (ADS)

Shin, Jong-Yeol; Kim, Tae Wan; Kim, Gwi-Yeol; Lee, Su-Min; Shrestha, Bhanu; Hong, Jin-Woong

2016-05-01

Performance of organic light-emitting diodes was investigated depending on the electron-injection materials of metal carbonates (Li2CO3 and Cs2CO3 ); and number of layers. In order to improve the device efficiency, two types of devices were manufactured by using the hole-injection material (Teflon-amorphous fluoropolymer -AF) and electron-injection materials; one is a two-layer reference device ( ITO/Teflon-AF/Alq3/Al ) and the other is a three-layer device (ITO/Teflon-AF/Alq3/metal carbonate/Al). From the results of the efficiency for the devices with hole-injection layer and electron-injection layer, it was found that the electron-injection layer affects the electrical properties of the device more than the hole-injection layer. The external-quantum efficiency for the three-layer device with Li2CO3 and Cs2CO3 layer is improved by approximately six and eight times, respectively, compared with that of the two-layer reference device. It is thought that a use of electron-injection layer increases recombination rate of charge carriers by the active injection of electrons and the blocking of holes.

Optimization of enhanced coal-bed methane recovery using numerical simulation

NASA Astrophysics Data System (ADS)

Perera, M. S. A.; Ranjith, P. G.; Ranathunga, A. S.; Koay, A. Y. J.; Zhao, J.; Choi, S. K.

2015-02-01

Although the enhanced coal-bed methane (ECBM) recovery process is one of the potential coal bed methane production enhancement techniques, the effectiveness of the process is greatly dependent on the seam and the injecting gas properties. This study has therefore aimed to obtain a comprehensive knowledge of all possible major ECBM process-enhancing techniques by developing a novel 3D numerical model by considering a typical coal seam using the COMET 3 reservoir simulator. Interestingly, according to the results of the model, the generally accepted concept that there is greater CBM (coal-bed methane) production enhancement from CO2 injection, compared to the traditional water removal technique, is true only for high CO2 injection pressures. Generally, the ECBM process can be accelerated by using increased CO2 injection pressures and reduced temperatures, which are mainly related to the coal seam pore space expansion and reduced CO2 adsorption capacity, respectively. The model shows the negative influences of increased coal seam depth and moisture content on ECBM process optimization due to the reduced pore space under these conditions. However, the injection pressure plays a dominant role in the process optimization. Although the addition of a small amount of N2 into the injecting CO2 can greatly enhance the methane production process, the safe N2 percentage in the injection gas should be carefully predetermined as it causes early breakthroughs in CO2 and N2 in the methane production well. An increased number of production wells may not have a significant influence on long-term CH4 production (50 years for the selected coal seam), although it significantly enhances short-term CH4 production (10 years for the selected coal seam). Interestingly, increasing the number of injection and production wells may have a negative influence on CBM production due to the coincidence of pressure contours created by each well and the mixing of injected CO2 with CH4.

Long-term thermal effects on injectivity evolution during CO 2 storage

DOE Office of Scientific and Technical Information (OSTI.GOV)

Vilarrasa, Victor; Rinaldi, Antonio P.; Rutqvist, Jonny

Carbon dioxide (CO 2 ) is likely to reach the bottom of injection wells at a colder temperature than that of the storage formation, causing cooling of the rock. This cooling, together with overpressure, tends to open up fractures, which may enhance injectivity. Here, we investigate cooling effects on injectivity enhancement by modeling the In Salah CO 2 storage site and a theoretical, long-term injection case. We use stress-dependent permeability functions that predict an increase in permeability as the effective stress acting normal to fractures decreases. Normal effective stress can decrease either due to overpressure or cooling. We calibrate ourmore » In Salah model, which includes a fracture zone perpendicular to the well, obtaining a good fitting with the injection pressure measured at KB-502 and the rapid CO 2 breakthrough that occurred at the observation well KB-5 located 2 km away from the injection well. CO 2 preferentially advances through the fracture zone, which becomes two orders of magnitude more permeable than the rest of the reservoir. Nevertheless, the effect of cooling on the long-term injectivity enhancement is limited in pressure dominated storage sites, like at In Salah, because most of the permeability enhancement is due to overpressure. But, thermal effects enhance injectivity in cooling dominated storage sites, which may decrease the injection pressure by 20%, saving a significant amount of compression energy all over the duration of storage projects. Overall, our simulation results show that cooling has the potential to enhance injectivity in fractured reservoirs.« less

Long-term thermal effects on injectivity evolution during CO 2 storage

DOE PAGES

Vilarrasa, Victor; Rinaldi, Antonio P.; Rutqvist, Jonny

2017-08-22

Carbon dioxide (CO 2 ) is likely to reach the bottom of injection wells at a colder temperature than that of the storage formation, causing cooling of the rock. This cooling, together with overpressure, tends to open up fractures, which may enhance injectivity. Here, we investigate cooling effects on injectivity enhancement by modeling the In Salah CO 2 storage site and a theoretical, long-term injection case. We use stress-dependent permeability functions that predict an increase in permeability as the effective stress acting normal to fractures decreases. Normal effective stress can decrease either due to overpressure or cooling. We calibrate ourmore » In Salah model, which includes a fracture zone perpendicular to the well, obtaining a good fitting with the injection pressure measured at KB-502 and the rapid CO 2 breakthrough that occurred at the observation well KB-5 located 2 km away from the injection well. CO 2 preferentially advances through the fracture zone, which becomes two orders of magnitude more permeable than the rest of the reservoir. Nevertheless, the effect of cooling on the long-term injectivity enhancement is limited in pressure dominated storage sites, like at In Salah, because most of the permeability enhancement is due to overpressure. But, thermal effects enhance injectivity in cooling dominated storage sites, which may decrease the injection pressure by 20%, saving a significant amount of compression energy all over the duration of storage projects. Overall, our simulation results show that cooling has the potential to enhance injectivity in fractured reservoirs.« less

Fundamental Studies of Clay and Clay-rich Mineral Reactions with H2O-CO2 Fluids: Application to Geological Carbon Dioxide Sequestration

NASA Astrophysics Data System (ADS)

Chizmeshya, A. V.

2016-12-01

Geological sequestration is currently being actively developed as a near-term, large-scale carbon sequestration technology in which supercritical carbon dioxide (scCO2) is injected below-ground into saline aquifers, depleted and existing oil and gas reservoir. Implementation strongly depends on the specific geological profile of each candidate injection site. Caprock formations that contain swellable clay minerals are of particular concern, since interaction with injected CO2 may produce complex local structural effects related to shrinkage, desiccation, and plastic response leading to CO2 escape. The current knowledge-base on rock-brine-CO2 interactions often relies on semi-empirical geochemical modeling and autoclave experiments, which necessitate quenching (de-gassing) to ambient conditions for characterization. To avoid these effects we used a moissanite-based microreaction system (Diefenbacher, J et al Rev. Mod. Inst., 76 15103 (2005)) which enables in situ synchrotron characterization of interactions under constant CO2 activity. Synchrotron studies were performed at the GSECARS sector of the Argonne National Lab APS to systematically determine the response of representative Ca- and Na-montmorillonites (STx-1, SWy-1) clays to dry/wet scCO2 (H2O-rich) fluids at T and P encountered in typical aquifers. Our main findings for hydrated STx-1 are that desiccation occurs spontaneously on the scale of minutes-hours over a wide range of conditions in dry scCO2 via release of H2O with volume changes as large as 19% in relation to the initial volume. Desiccation was not observed in wet scCO2, or in corresponding saline solutions containing 1-3 M NaCl, but quenching to ambient conditions from low-pressures leads to re-hydration in STx-1 suggesting a pressure-dependent diffusion barrier for H2O from the clay into bulk scCO2. Similar desiccation transitions with smaller volume changes of 5-9% were also observed in SWy-1 at P 140 atm and T 40 C. At high pressures ( 200 atm) minor lamellar expansion was sometimes found in STx-1 suggesting the possible intercalation of CO2. Our diffraction studies reveal an intriguing relationship between the critical dehydration temperatures and pressures, with bounds defined by critical properties of CO2.

Impact on the deep biosphere of CO2 geological sequestration in (ultra)mafic rocks and retroactive consequences on its fate

NASA Astrophysics Data System (ADS)

Ménez, Bénédicte; Gérard, Emmanuelle; Rommevaux-Jestin, Céline; Dupraz, Sébastien; Guyot, François; Arnar Alfreősson, Helgi; Reynir Gíslason, Sigurőur; Sigurőardóttir, Hólmfríiur

2010-05-01

Due to their reactivity and high potential of carbonation, mafic and ultramafic rocks constitute targets of great interest to safely and permanently sequestrate anthropogenic CO2 and thus, limit the potential major environmental consequences of its increasing atmospheric level. In addition, subsurface (ultra)mafic environments are recognized to harbor diverse and active microbial populations that may be stimulated or decimated following CO2 injection (± impurities) and subsequent acidification. However, the nature and amplitude of the involved biogeochemical pathways are still unknown. To avoid unforeseen consequences at all time scales (e.g. reservoir souring and clogging, bioproduction of H2S and CH4), the impact of CO2 injection on deep biota with unknown ecology, and their retroactive effects on the capacity and long-term stability of CO2 storage sites, have to be determined. We present here combined field and experimental investigations focused on the Icelandic pilot site, implemented in the Hengill area (SW Iceland) at the Hellisheidi geothermal power plant (thanks to the CarbFix program, a consortium between the University of Iceland, Reykjavik Energy, the French CNRS of Toulouse and Columbia University in N.Y., U.S.A. and to the companion French ANR-CO2FIX project). This field scale injection of CO2 charged water is here designed to study the feasibility of storing permanently CO2 in basaltic rocks and to optimize industrial methods. Prior to the injection, the microbiological initial state was characterized through regular sampling at various seasons (i.e., October '08, July '09, February '10). DNA was extracted and amplified from the deep and shallow observatory wells, after filtration of 20 to 30 liters of groundwater collected in the depth interval 400-980 m using a specifically developed sampling protocol aiming at reducing contamination risks. An inventory of living indigenous bacteria and archaea was then done using molecular methods based on the amplification of small subunit ribosomal RNA genes (SSU rDNAs). The stratigraphic levels targeted to store the injected CO2 as aqueous phase harbor numerous new species close to cultivable species belonging to the genus Thermus or Proteobacteria species known to be linked in particular with the hydrogen and iron cycles. After injection, the evolution of these microbial communities will be monitored using the Denaturing Gradient Gel Electrophoresis technique. Beyond the ecological impact of storing high levels of CO2 in deep environments, particularly important is the ability of intraterrestrial microbes to potentially interact with the injected fluids. For example, carbonation has been shown to be strongly influenced by microbiological activities that can locally modify pH and induce nucleation of solid carbonates. To improve the understanding of these processes and to better constrain the influence of deep biota on the evolving chemical and petrophysical properties of the reservoir, an experimental and numerical modeling is carried out in parallel, using model strains representative of the subsurface (including acetogens, sulphate and iron reducing bacteria), as single-species or consortia. A set of batch experiments in presence of crushed olivine or basalts was especially designed to evaluate how microbial activity could overcome the slow kinetics of mineral-fluid reactions and reduce the energy needed to hasten the carbonation process.

Ambient Seismic Noise Monitoring of Time-lapse Velocity Changes During CO2 Injection at Otway, South Australia

NASA Astrophysics Data System (ADS)

Saygin, E.; Lumley, D. E.

2017-12-01

We use continuous seismic data recorded with an array of 909 buried geophones at Otway, South Australia, to investigate the potential of using ambient seismic noise for time-lapse monitoring of the subsurface. The array was installed prior to a 15,000 ton CO2 injection in 2016-17, in order to detect and monitor the evolution of the injected CO2 plume, and any associated microseismic activity. Continuously recorded data from the vertical components of the geophone array were cross-correlated to retrieve the inter-station Green's functions. The dense collection of Green's functions contains diving body waves and surface Rayleigh waves. Green's Functions were then compared with each other at different time frames including the pre-injection period to track subtle changes in the travel times due to the CO2 injection. Our results show a clear change in the velocities of Green's functions at the start of injection for both body waves and surface waves for wave paths traversing the injection area, whereas the observed changes are much smaller for areas which are far from the injection well.

Your View or Mine: Spatially Quantifying CO2 Storage Risk from Various Stakeholder Perspectives

NASA Astrophysics Data System (ADS)

Bielicki, J. M.; Pollak, M.; Wilson, E.; Elliot, T. R.; Guo, B.; Nogues, J. P.; Peters, C. A.

2011-12-01

CO2 capture and storage involves injecting captured CO2 into geologic formations, such as deep saline aquifers. This injected CO2 is to be "stored" within the rock matrix for hundreds to thousands of years, but injected CO2, or the brine it displaces, may leak from the target reservoir. Such leakage could interfere with other subsurface activities-water production, energy production, energy storage, and waste disposal-or migrate to the surface. Each of these interferences will incur multiple costs to a variety of stakeholders. Even if injected or displaced fluids do not interfere with other subsurface activities or make their way to the surface, costs will be incurred to find and fix the leak. Consequently, the suitability of a site for CO2 storage must therefore include an assessment of the risk of leakage and interference with various other activities within a three-dimensional proximity of where CO2 is being injected. We present a spatial analysis of leakage and interference risk associated with injecting CO2 into a portion of the Mount Simon sandstone in the Michigan Basin. Risk is the probability of an outcome multiplied by the impact of that outcome (Ro=po*Io). An outcome is the result of the leakage (e.g., interference with oil production), and the impact is the cost associated with the outcome. Each outcome has costs that will vary by stakeholder. Our analysis presents CO2 storage risk for multiple outcomes in a spatially explicit manner that varies by stakeholder. We use the ELSA semi-analytical model for estimating CO2 and brine leakage from aquifers to determine plume and pressure front radii, and CO2 and brine leakage probabilities for the Mount Simon sandstone and multiple units above it. Results of ELSA simulations are incorporated into RISCS: the Risk Interference Subsurface CO2 Storage model. RISCS uses three-dimensional data on subsurface geology and the locations of wells and boreholes to spatially estimate risks associated with CO2 leakage from injection reservoirs. Where plumes probabilistically intersect subsurface activities, reach groundwater, or reach the surface, RISCS uses cost estimates from the Leakage Impact Valuation framework to estimate CO2 storage leakage and interference risk in monetary terms. This framework estimates costs that might be incurred if CO2 leaks from an injection reservoir. Such leakage could beget a variety of costs, depending on the nature and extent of the impacts. The framework identifies multiple costs under headings of: (a) finding and fixing the leak, (b) business disruption, and (c) cleaning up and paying for damages. The framework also enumerates the distribution of costs between ten different stakeholders, and allocates these costs along four leakage scenarios: 1) No interference, 2) interference with a subsurface activity, 3) interference with groundwater, and 4) migration to the surface. Our methodology facilitates research along two lines. First, it allows a probabilistic assessment of leakage costs to an injection operator, and thus what the effect of leakage might be on CCS market effectiveness. Second, it allows a broader inquiry about injection site prioritization from the point of view of various stakeholders.

Impacts of CO2 Leakage on a Shallow Aquifer System: Laboratory Column Experiments and Reactive Transport Modeling

NASA Astrophysics Data System (ADS)

Ha, Jong Heon; Jeen, Sung-Wook

2017-04-01

Groundwater quality change due to the leakage of CO2 in a shallow aquifer system is an important aspect of environmental impact assessment in a carbon dioxide capture and storage (CCS) site. This study evaluated geochemical changes in a shallow aquifer system resulting from leakage of CO2 through laboratory column experiments and reactive transport modeling. In the column experiments, two columns were set up and filled with the sediment from the Environmental Impact Test (EIT) facility of the Korea CO2 Storage Environmental Management (K-COSEM) Research Center. Groundwater, also collected form the EIT site, was purged with CO2 or Ar gases, and was pumped into the columns with the pumping rates of 200-1000 mL day-1 (0.124-0.62 m day-1). Profile and time-series effluent samplings were conducted to evaluate the spatial and temporal geochemical changes in the aquifer materials upon contact with CO2. The experimental results showed that after injecting CO2-purged groundwater, the pH was decreased, and alkalinity, electrical conductivity (EC) and concentrations of major cations were increased. The spatial and temporal geochemical changes from the column experiments indicate that dissolution of aquifer materials in contact with dissolved CO2 is the major contributor to the changes in groundwater geochemistry. The reactive transport modeling has been conducted to reproduce these geochemical changes in the aquifer system by incorporating dissolution of the dominant aluminosilicate minerals in the aquifer such as microcline, anorthite, albite, and biotite. This study suggests that pH, alkalinity, EC and concentrations of major cations are important monitoring parameters for detecting CO2 leakage in a shallow groundwater aquifer system.

Gas-water-rock interactions in Frio Formation following CO2 injection: Implications for the storage of greenhouse gases in sedimentary basins

USGS Publications Warehouse

Kharaka, Yousif K.; Cole, David R.; Hovorka, Susan D.; Gunter, W.D.; Knauss, Kevin G.; Freifeild, Barry M.

2006-01-01

To investigate the potential for the geologic storage of CO2 in saline sedimentary aquifers, 1600 t of CO2 were injected at 1500 m depth into a 24-m-thick sandstone section of the Frio Formation, a regional brine and oil reservoir in the U.S. Gulf Coast. Fluid samples obtained from the injection and observation wells before CO2 injection showed a Na-Ca-Cl–type brine with 93,000 mg/L total dissolved solids (TDS) at near saturation with CH4 at reservoir conditions. Following CO2 breakthrough, samples showed sharp drops in pH (6.5–5.7), pronounced increases in alkalinity (100–3000 mg/L as HCO3) and Fe (30–1100 mg/L), and significant shifts in the isotopic compositions of H2O, dissolved inorganic carbon (DIC), and CH4. Geochemical modeling indicates that brine pH would have dropped lower but for the buffering by dissolution of carbonate and iron oxyhydroxides. This rapid dissolution of carbonate and other minerals could ultimately create pathways in the rock seals or well cements for CO2 and brine leakage. Dissolution of minerals, especially iron oxyhydroxides, could mobilize toxic trace metals and, where residual oil or suitable organics are present, the injected CO2 could also mobilize toxic organic compounds. Environmental impacts could be major if large brine volumes with mobilized toxic metals and organics migrated into potable groundwater. The δ18O values for brine and CO2 samples indicate that supercritical CO2 comprises ∼50% of pore-fluid volume ∼6 mo after the end of injection. Postinjection sampling, coupled with geochemical modeling, indicates that the brine gradually will return to its preinjection composition.

CO 2 Mineral Sequestration in Naturally Porous Basalt

DOE Office of Scientific and Technical Information (OSTI.GOV)

Xiong, Wei; Wells, Rachel K.; Horner, Jake A.

2018-02-27

Continental flood basalts are extensive geologic features currently being evaluated as reservoirs that are suitable for long-term storage of carbon emissions. Favorable attributes of these formations for containment of injected carbon dioxide (CO2) include high mineral trapping capacity, unique structural features, and enormous volumes. We experimentally investigated mineral carbonation in whole core samples retrieved from the Grand Ronde basalt, the same formation into which ~1000 t of CO2 was recently injected in an eastern Washington pilot-scale demonstration. The rate and extent of carbonate mineral formation at 100 °C and 100 bar were tracked via time-resolved sampling of bench-scale experiments. Basaltmore » cores were recovered from the reactor after 6, 20, and 40 weeks, and three-dimensional X-ray tomographic imaging of these cores detected carbonate mineral formation in the fracture network within 20 weeks. Under these conditions, a carbon mineral trapping rate of 1.24 ± 0.52 kg of CO2/m3 of basalt per year was estimated, which is orders of magnitude faster than rates for deep sandstone reservoirs. On the basis of these calculations and under certain assumptions, available pore space within the Grand Ronde basalt formation would completely carbonate in ~40 years, resulting in solid mineral trapping of ~47 kg of CO2/m3 of basalt.« less

Enhanced convective dissolution of CO2 in reactive systems

NASA Astrophysics Data System (ADS)

de Wit, Anne; Thomas, Carelle; Loodts, Vanessa; Knaepen, Bernard; Rongy, Laurence

2017-11-01

To decrease the atmospheric concentration of CO2, sequestration techniques whereby this greenhouse gas is injected in saline aquifers present in soils are considered. Upon contact with the aquifer, the CO2 can dissolve in it and subsequently be mineralized via reactions with minerals like carbonates for instance. We investigate both experimentally and theoretically the influence of such reactions on the convective dissolution of CO2. Experiments analyze convective patterns developing when gaseous CO2 is put in contact with aqueous solutions of reactants in a confined vertical Hele-Shaw geometry. We show that the reactions can enhance convection and modify the nonlinear dynamics of density fingering. Numerical simulations further show that reactions can increase the flux of dissolving CO2, inducing a more efficient sequestration. Emphasis will be put on the control of the convective pattern properties by varying the very nature of the chemicals. Implications on the choice of optimal sequestration sites will be discussed.

Method and apparatus for efficient injection of CO2 in oceans

DOEpatents

West, Olivia R.; Tsouris, Constantinos; Liang, Liyuan

2003-07-29

A liquid CO.sub.2 injection system produces a negatively buoyant consolidated stream of liquid CO.sub.2, CO.sub.2 hydrate, and water that sinks upon release at ocean depths in the range of 700-1500 m. In this approach, seawater at a predetermined ocean depth is mixed with the liquid CO.sub.2 stream before release into the ocean. Because mixing is conducted at depths where pressures and temperatures are suitable for CO.sub.2 hydrate formation, the consolidated stream issuing from the injector is negatively buoyant, and comprises mixed CO.sub.2 -hydrate/CO.sub.2 -liquid/water phases. The "sinking" characteristic of the produced stream will prolong the metastability of CO.sub.2 ocean sequestration by reducing the CO.sub.2 dissolution rate into water. Furthermore, the deeper the CO.sub.2 hydrate stream sinks after injection, the more stable it becomes internally, the deeper it is dissolved, and the more dispersed is the resulting CO.sub.2 plume. These factors increase efficiency, increase the residence time of CO2 in the ocean, and decrease the cost of CO.sub.2 sequestration while reducing deleterious impacts of free CO.sub.2 gas in ocean water.

The use of tracers to assess leakage from the sequestration of CO2 in a depleted oil reservoir, New Mexico, USA

DOE Office of Scientific and Technical Information (OSTI.GOV)

Wells, A.W.; Diehl, J.R.; Bromhal, G.S.

Geological sequestration of CO2 in depleted oil reservoirs is a potentially useful strategy for greenhouse gas management and can be combined with enhanced oil recovery. Development of methods to estimate CO2 leakage rates is essential to assure that storage objectives are being met at sequestration facilities. Perfluorocarbon tracers (PFTs) were added as three 12 h slugs at about one week intervals during the injection of 2090 tons of CO2 into the West Pearl Queen (WPQ) depleted oil formation, sequestration pilot study site located in SE New Mexico. The CO2 was injected into the Permian Queen Formation. Leakage was monitored inmore » soil–gas using a matrix of 40 capillary adsorbent tubes (CATs) left in the soil for periods ranging from days to months. The tracers, perfluoro-1,2-dimethylcyclohexane (PDCH), perfluorotrimethylcyclohexane (PTCH) and perfluorodimethylcyclobutane (PDCB), were analyzed using thermal desorption, and gas chromatography with electron capture detection. Monitoring was designed to look for immediate leakage, such as at the injection well bore and at nearby wells, and to develop the technology to estimate overall CO2 leak rates based on the use of PFTs. Tracers were detected in soil–gas at the monitoring sites 50 m from the injection well within days of injection. Tracers continued to escape over the following years. Leakage appears to have emanated from the vicinity of the injection well in a radial pattern to about 100 m and in directional patterns to 300 m. Leakage rates were estimated for the 3 tracers from each of the 4 sets of CATs in place following the start of CO2 injection. Leakage was fairly uniform during this period. As a first approximation, the CO2 leak rate was estimated at about 0.0085% of the total CO2 sequestered per annum.« less

Comparison of geomechanical deformation induced by megatonne-scale CO2 storage at Sleipner, Weyburn, and In Salah

PubMed Central

Verdon, James P.; Kendall, J.-Michael; Stork, Anna L.; Chadwick, R. Andy; White, Don J.; Bissell, Rob C.

2013-01-01

Geological storage of CO2 that has been captured at large, point source emitters represents a key potential method for reduction of anthropogenic greenhouse gas emissions. However, this technology will only be viable if it can be guaranteed that injected CO2 will remain trapped in the subsurface for thousands of years or more. A significant issue for storage security is the geomechanical response of the reservoir. Concerns have been raised that geomechanical deformation induced by CO2 injection will create or reactivate fracture networks in the sealing caprocks, providing a pathway for CO2 leakage. In this paper, we examine three large-scale sites where CO2 is injected at rates of ∼1 megatonne/y or more: Sleipner, Weyburn, and In Salah. We compare and contrast the observed geomechanical behavior of each site, with particular focus on the risks to storage security posed by geomechanical deformation. At Sleipner, the large, high-permeability storage aquifer has experienced little pore pressure increase over 15 y of injection, implying little possibility of geomechanical deformation. At Weyburn, 45 y of oil production has depleted pore pressures before increases associated with CO2 injection. The long history of the field has led to complicated, sometimes nonintuitive geomechanical deformation. At In Salah, injection into the water leg of a gas reservoir has increased pore pressures, leading to uplift and substantial microseismic activity. The differences in the geomechanical responses of these sites emphasize the need for systematic geomechanical appraisal before injection in any potential storage site. PMID:23836635

Comparison of geomechanical deformation induced by megatonne-scale CO2 storage at Sleipner, Weyburn, and In Salah.

PubMed

Verdon, James P; Kendall, J-Michael; Stork, Anna L; Chadwick, R Andy; White, Don J; Bissell, Rob C

2013-07-23

Geological storage of CO2 that has been captured at large, point source emitters represents a key potential method for reduction of anthropogenic greenhouse gas emissions. However, this technology will only be viable if it can be guaranteed that injected CO2 will remain trapped in the subsurface for thousands of years or more. A significant issue for storage security is the geomechanical response of the reservoir. Concerns have been raised that geomechanical deformation induced by CO2 injection will create or reactivate fracture networks in the sealing caprocks, providing a pathway for CO2 leakage. In this paper, we examine three large-scale sites where CO2 is injected at rates of ~1 megatonne/y or more: Sleipner, Weyburn, and In Salah. We compare and contrast the observed geomechanical behavior of each site, with particular focus on the risks to storage security posed by geomechanical deformation. At Sleipner, the large, high-permeability storage aquifer has experienced little pore pressure increase over 15 y of injection, implying little possibility of geomechanical deformation. At Weyburn, 45 y of oil production has depleted pore pressures before increases associated with CO2 injection. The long history of the field has led to complicated, sometimes nonintuitive geomechanical deformation. At In Salah, injection into the water leg of a gas reservoir has increased pore pressures, leading to uplift and substantial microseismic activity. The differences in the geomechanical responses of these sites emphasize the need for systematic geomechanical appraisal before injection in any potential storage site.

Implications of Sub-Hydrostatic Pressures in the Bravo Dome Natural CO2 Reservoir for the Long-Term Security of Geological Carbon Dioxide Storage

NASA Astrophysics Data System (ADS)

Akhbari, D.; Hesse, M. A.; Larson, T.

2014-12-01

The Bravo Dome field in northeast New Mexico is one of the largest gas accumulations worldwide and the largest natural CO2 accumulation in North America. The field is only 580-900 m deep and located in the Permian Tubb sandstone that unconformably overlies the granitic basement. Sathaye et al. (2014) estimated that 1.3 Gt of CO2 is stored at the reservoir. A major increase in the pore pressure relative to the hydrostatic pressure is expected due to the large amount of CO2 injected into the reservoir. However, the pre-production gas pressures indicate that most parts of the reservoir are approximately 5 MPa below hydrostatic pressure. Three processes could explain the under pressure in the Bravo Dome reservoir; 1) erosional unloading, 2) CO2 dissolution into the ambient brine, 3) cooling of CO2after injection. Analytical solutions suggest that an erosion rate of 180 m/Ma is required to reduce the pore pressures to the values observed at Bravo Dome. Given that the current erosion rate is only 5 m/Ma (Nereson et al. 2013); the sub-hydrostatic pressures at Bravo Dome are likely due to CO2dissolution and cooling. To investigate the impact of CO2 dissolution on the pore pressure we have developed new analytical solutions and conducted laboratory experiments. We assume that gaseous CO2 was confined to sandstones during emplacement due to the high entry pressure of the siltstones. After emplacement the CO2 dissolves in to the brine contained in the siltstones and the pressure in the sandstones declines. Assuming the sandstone-siltstone system is closed, the pressure decline due to CO2 dissolution is controlled by a single dimensionless number, η = KHRTVw /Vg. Herein, KH is Henry's constant, R is ideal gas constant, T is temperature, Vw is water volume, and Vg is CO2 volume. The pressure drop is controlled by the ratio of water volume to CO2 volume and η varies between 0.1 to 8 at Bravo Dome. This corresponds to pressure drops between 0.8-7.5 MPa and can therefore account for the observed 5 MPa drop in pore pressures at Bravo Dome. This is consistent with geochemical observation suggesting significant dissolution of CO2 at Bravo Dome (Gilfillan 2009). The observation of sub-hydrostatic pressures in CO2 reservoirs is important because they illustrate that CO2 dissolution may mitigate problems due to injection induced overpressure in the long-term.

Use of Anticlines for Geologic Sequestration of Carbon Dioxide in a Saline Aquifer in Northwestern Taiwan

NASA Astrophysics Data System (ADS)

Lin, Shin-Hsun; Liou, Tai-Sheng

2013-04-01

In this study, migration of CO2 in a deep saline aquifer with anticlines under various injection schemes was numerically simulated using the ECO2N simulator. The hypothetical study site was selected at the Taoyuan Plateau near the second largest coal-fired power plant, Datan power plant (annual CO2 emission of 1.5 Mt/yr), in Northwestern Taiwan. A 15x15 km2 simulation domain, containing two sub-parallel east-northeast Hukou and Pingzhen anticlines, was discretized into unstructured grid with spatial refinement at the injection borehole. Kueichulin sandstone and Chinshui shale in the simulation domain were considered as the storage formation and the cap rock, respectively. It was assumed that no CO2 exists in the aquifer prior to injection, and that the aquifer has a hydrostatic pressure distribution and a constant salinity of 3%. All boundaries were assumed to be "open". Isothermal simulations with 1 Mt/yr injection rate and 20 years of injection period were considered. van Genuchten capillary pressure and Corey relative permeability were assumed for all rock formations. Simulation results indicated that pressure buildup characterized the CO2 migration into three different phases: drainage of brine, formation dry-out, and dissolution and gravity take-over . It was found that the worst leakage scenario occurs if a single injection borehole is placed along the anticline axis. In this case, rock formations near the anticline axis provide a leakage path such that CO2 ultimately leaks out of the upper boundary. On the other hand, CO2 can be safely sequestrated in the storage formation if the injection borehole was placed away from the anticline axis. This is because gas phase CO2 migrates along the counter dipping direction of the anticline as a result of buoyancy. More favorable scenarios were found if a multiple-borehole injection scheme was used. In such cases, not only pressure buildup was significantly mitigated but the amount of precipitated salt was reduced. If a five-borehole scheme was used, for example, pressure buildup and the amount of precipitated salt can be reduced by 20% and 90%, respectively. More interestingly, if injection borehole was placed midway between the two anticlines, buoyancy dominates the migration of CO2 such that most CO2 is accumulated under the apex of anticline. Therefore, it is suggested that a multiple-borehole injection scheme would be a preferable scenario because of the reduced risks of pressure buildup and salt precipitation. Moreover, it would be better to place the injection boreholes away from the anticline axis in order to make good use of all possible trapping mechanisms to permanently sequestrate CO2 in deep rock formations.

DOE Office of Scientific and Technical Information (OSTI.GOV)

Mouzakis, Katherine M.; Navarre-Sitchler, Alexis K.; Rother, Gernot

Carbon capture, utilization, and storage, one proposed method of reducing anthropogenic emissions of CO 2, relies on low permeability formations, such as shales, above injection formations to prevent upward migration of the injected CO 2. Porosity in caprocks evaluated for sealing capacity before injection can be altered by geochemical reactions induced by dissolution of injected CO 2 into pore fluids, impacting long-term sealing capacity. Therefore, long-term performance of CO 2 sequestration sites may be dependent on both initial distribution and connectivity of pores in caprocks, and on changes induced by geochemical reaction after injection of CO 2, which are currentlymore » poorly understood. This paper presents results from an experimental study of changes to caprock porosity and pore network geometry in two caprock formations under conditions relevant to CO 2 sequestration. Pore connectivity and total porosity increased in the Gothic Shale; while total porosity increased but pore connectivity decreased in the Marine Tuscaloosa. Gothic Shale is a carbonate mudstone that contains volumetrically more carbonate minerals than Marine Tuscaloosa. Carbonate minerals dissolved to a greater extent than silicate minerals in Gothic Shale under high CO 2 conditions, leading to increased porosity at length scales <~200 nm that contributed to increased pore connectivity. In contrast, silicate minerals dissolved to a greater extent than carbonate minerals in Marine Tuscaloosa leading to increased porosity at all length scales, and specifically an increase in the number of pores >~1 μm. Mineral reactions also contributed to a decrease in pore connectivity, possibly as a result of precipitation in pore throats or hydration of the high percentage of clays. Finally, this study highlights the role that mineralogy of the caprock can play in geochemical response to CO 2 injection and resulting changes in sealing capacity in long-term CO 2 storage projects.« less

VSP Monitoring of CO2 Injection at the Aneth Oil Field in Utah

NASA Astrophysics Data System (ADS)

Huang, L.; Rutledge, J.; Zhou, R.; Denli, H.; Cheng, A.; Zhao, M.; Peron, J.

2008-12-01

Remotely tracking the movement of injected CO2 within a geological formation is critically important for ensuring safe and long-term geologic carbon sequestration. To study the capability of vertical seismic profiling (VSP) for remote monitoring of CO2 injection, a geophone string with 60 levels and 96 channels was cemented into a monitoring well at the Aneth oil field in Utah operated by Resolute Natural Resources and Navajo National Oil and Gas Company. The oil field is located in the Paradox Basin of southeastern Utah, and was selected by the Southwest Regional Partnership on Carbon Sequestration, supported by the U.S. Department of Energy, to demonstrate combined enhanced oil recovery (EOR) and CO2 sequestration. The geophones are placed at depths from 805 m to 1704 m, and the oil reservoir is located approximately from 1731 m to 1786 m in depth. A baseline VSP dataset with one zero-offset and seven offset source locations was acquired in October, 2007 before CO2 injection. The offsets/source locations are approximately 1 km away from the monitoring well with buried geophone string. A time-lapse VSP dataset with the same source locations was collected in July, 2008 after five months of CO2/water injection into a horizontal well adjacent to the monitoring well. The total amount of CO2 injected during the time interval between the two VSP surveys was 181,000 MCF (million cubic feet), or 10,500 tons. The time-lapse VSP data are pre-processed to balance the phase and amplitude of seismic events above the oil reservoir. We conduct wave-equation migration imaging and interferometry analysis using the pre-processed time-lapse VSP data. The results demonstrate that time-lapse VSP surveys with high-resolution migration imaging and scattering analysis can provide reliable information about CO2 migration. Both the repeatability of VSP surveys and sophisticated time-lapse data pre-processing are essential to make VSP as an effective tool for monitoring CO2 injection.

Displacement front behavior of near miscible CO2 flooding in decane saturated synthetic sandstone cores revealed by magnetic resonance imaging.

PubMed

Liu, Yu; Teng, Ying; Jiang, Lanlan; Zhao, Jiafei; Zhang, Yi; Wang, Dayong; Song, Yongchen

2017-04-01

It is of great importance to study the CO 2 -oil two-phase flow characteristic and displacement front behavior in porous media, for understanding the mechanisms of CO 2 enhanced oil recovery. In this work, we carried out near miscible CO 2 flooding experiments in decane saturated synthetic sandstone cores to investigate the displacement front characteristic by using magnetic resonance imaging technique. Experiments were done in three consolidated sandstone cores with the permeabilities ranging from 80 to 450mD. The oil saturation maps and the overall oil saturation during CO 2 injections were obtained from the intensity of magnetic resonance imaging. Finally the parameters of the piston-like displacement fronts, including the front velocity and the front geometry factor (the length to width ratio) were analyzed. Experimental results showed that the near miscible vertical upward displacement is instable above the minimum miscible pressure in the synthetic sandstone cores. However, low permeability can restrain the instability to some extent. Copyright © 2016 Elsevier Inc. All rights reserved.

Laboratory study of the effects of combustion gases on retorting of Green River oil shale with superheated steam

DOE Office of Scientific and Technical Information (OSTI.GOV)

Tyler, A.L.; Bullen, E.A.; Jacobs, H.R.

The leached zone of the Parachute Creek member of the Piceance Basin in the Green River Formation has a unique natural porosity that makes it a likely source for in-situ production of oil from oil shale by injection of superheated steam. The Equity Oil Co. of Salt Lake City, in cooperation with the U. S. Department of Energy, carried out field tests using surface generated steam. Difficulties in delivering steam of sufficiently high temperature to the formation resulted in an experiment which was only marginally successful yielding less than 1 percent of the estimated 300,000 barrels of oil in place.more » In 1981, personnel at Sandia National Laboratory suggested that a downhole steam generator which could produce steam at temperatures in excess of 1000/sup 0/F (538/sup 0/C) at depth could well solve the temperature problem. In order to evaluate the effects of combustion gases which would be injected along with steam, should a downhole steam generator be used, laboratory studies have been completed using steam diluted with CO/sub 2/ and with CO/sub 2/ and N/sub 2/ as the heating medium. Results of experiments in an autoclave reactor and in a laboratory retort are reported. The temperature, residence time, and partial pressure of steam are the parameters which effect oil yield and oil quality. Oil properties are reported for several experimental conditions and include oil yield, boiling point distributions, pour points, gravity, and elemental and hydrocarbon-type analyses. Both the autoclave and laboratory retort experiments indicate that CO/sub 2/ and N/sub 2/ do not take a reactive part in the formation of oils except as they dilute the steam. However, the presence of CO/sub 2/ in the gaseous atmosphere during retorting does promote a low-temperature transformation of dolomite to calcite in the inorganic matrix of the oil shale.« less

Hydrogeochemical and mineralogical effects of sustained CO2 contamination in a shallow sandy aquifer: A field-scale controlled release experiment

NASA Astrophysics Data System (ADS)

Cahill, Aaron G.; Marker, Pernille; Jakobsen, Rasmus

2014-02-01

A shallow aquifer CO2 contamination experiment was performed to investigate evolution of water chemistry and sediment alteration following leakage from geological storage by physically simulating a leak from a hypothetical storage site. In a carbonate-free aquifer, in western Denmark, a total of 1600 kg of gas phase CO2 was injected at 5 and 10 m depth over 72 days through four inclined injection wells into aeolian and glacial sands. Water chemistry was monitored for pH, EC, and dissolved element evolution through an extensive network of multilevel sampling points over 305 days. Sediment cores were taken pre and postinjection and analyzed to search for effects on mineralogy and sediment properties. Results showed the simulated leak to evolve in two distinct phases; an advective elevated ion pulse followed by increasing persistent acidification. Spatial and temporal differences in evolution of phases suggest separate chemical mechanisms and geochemical signatures. Dissolved element concentrations developed exhibiting four behaviors: (1) advective pulse (Ca, Mg, Na, Si, Ba, and Sr), (2) pH sensitive abundance dependent (Al and Zn), (3) decreasing (Mn and Fe), and (4) unaffected (K). Concentration behaviors were characterized by: (1) a maximal front moving with advective flow, (2) continual increase in close proximity to the injection plane, (3) removal from solution, and (4) no significant change. Only Al was observed to exceed WHO guidelines, however significantly so (10-fold excess). The data indicate that pH is controlled by equilibrium with gibbsite which is again coupled to cation exchange processes. Pre and postinjection sediment analysis indicated alteration of sediment composition and properties including depletion of reactive mineral species.

On the Role of Multi-Scale Processes in CO2 Storage Security and Integrity

NASA Astrophysics Data System (ADS)

Pruess, K.; Kneafsey, T. J.

2008-12-01

Consideration of multiple scales in subsurface processes is usually referred to the spatial domain, where we may attempt to relate process descriptions and parameters from pore and bench (Darcy) scale to much larger field and regional scales. However, multiple scales occur also in the time domain, and processes extending over a broad range of time scales may be very relevant to CO2 storage and containment. In some cases, such as in the convective instability induced by CO2 dissolution in saline waters, space and time scales are coupled in the sense that perturbations induced by CO2 injection will grow concurrently over many orders of magnitude in both space and time. In other cases, CO2 injection may induce processes that occur on short time scales, yet may affect large regions. Possible examples include seismicity that may be triggered by CO2 injection, or hypothetical release events such as "pneumatic eruptions" that may discharge substantial amounts of CO2 over a short time period. This paper will present recent advances in our experimental and modeling studies of multi-scale processes. Specific examples that will be discussed include (1) the process of CO2 dissolution-diffusion-convection (DDC), that can greatly accelerate the rate at which free-phase CO2 is stored as aqueous solute; (2) self- enhancing and self-limiting processes during CO2 leakage through faults, fractures, or improperly abandoned wells; and (3) porosity and permeability reduction from salt precipitation near CO2 injection wells, and mitigation of corresponding injectivity loss. This work was supported by the Office of Basic Energy Sciences and by the Zero Emission Research and Technology project (ZERT) under Contract No. DE-AC02-05CH11231 with the U.S. Department of Energy.

Exploring the effects of data quality, data worth, and redundancy of CO2 gas pressure and saturation data on reservoir characterization through PEST Inversion

DOE Office of Scientific and Technical Information (OSTI.GOV)

Fang, Zhufeng; Hou, Zhangshuan; Lin, Guang

2014-04-01

This study examined the impacts of reservoir properties on CO2 migration after subsurface injection and evaluated the possibility of characterizing reservoir properties using CO2 monitoring data such as saturation distribution. The injection reservoir was assumed to be located 1400-1500 m below the ground surface such that CO2 remained in the supercritical state. The reservoir was assumed to contain layers with alternating conductive and resistive properties, which is analogous to actual geological formations such as the Mount Simon Sandstone unit. The CO2 injection simulation used a cylindrical grid setting in which the injection well was situated at the center of themore » domain, which extended up to 8000 m from the injection well. The CO2 migration was simulated using the PNNL-developed simulator STOMP-CO2e (the water-salt-CO2 module). We adopted a nonlinear parameter estimation and optimization modeling software package, PEST, for automated reservoir parameter estimation. We explored the effects of data quality, data worth, and data redundancy on the detectability of reservoir parameters using CO2 saturation monitoring data, by comparing PEST inversion results using data with different levels of noises, various numbers of monitoring wells and locations, and different data collection spacing and temporal sampling intervals. This study yielded insight into the use of CO2 saturation monitoring data for reservoir characterization and how to design the monitoring system to optimize data worth and reduce data redundancy.« less

Advanced buffer materials for indoor air CO2 control in commercial buildings.

PubMed

Rajan, P E; Krishnamurthy, A; Morrison, G; Rezaei, F

2017-11-01

In this study, we evaluated solid sorbents for their ability to passively control indoor CO 2 concentration in buildings or rooms with cyclic occupancy (eg, offices, bedrooms). Silica supported amines were identified as suitable candidates and systematically evaluated in the removal of CO 2 from indoor air by equilibrium and dynamic techniques. In particular, sorbents with various amine loadings were synthesized using tetraethylenepentamine (TEPA), poly(ethyleneimine) (PEI) and a silane coupling agent 3-aminopropyltriethoxysilane (APS). TGA analysis indicates that TEPA impregnated silica not only displays a relatively high adsorption capacity when exposed to ppm level CO 2 concentrations, but also is capable of desorbing the majority of CO 2 by air flow (eg, by concentration gradient). In 10 L flow-through chamber experiments, TEPA-based sorbents reduced outlet CO 2 by up to 5% at 50% RH and up to 93% of CO 2 adsorbed over 8 hours was desorbed within 16 hours. In 8 m 3 flow-through chamber experiments, 18 g of the sorbent powder spread over a 2 m 2 area removed approximately 8% of CO 2 injected. By extrapolating these results to real buildings, we estimate that meaningful reductions in the CO 2 can be achieved, which may help reduce energy requirements for ventilation and/or improve air quality. © 2017 John Wiley & Sons A/S. Published by John Wiley & Sons Ltd.

Parameters affecting acetate concentrations during in-situ biological hydrogen methanation.

PubMed

Agneessens, Laura Mia; Ottosen, Lars Ditlev Mørck; Andersen, Martin; Berg Olesen, Christina; Feilberg, Anders; Kofoed, Michael Vedel Wegener

2018-06-01

Surplus electricity may be supplied to anaerobic digesters as H 2 gas to upgrade the CH 4 content of biogas. Acetate accumulation has been observed following H 2 injections, but the parameters determining the degree of acetate accumulation are not well understood. The pathways involved during H 2 consumption and acetate kinetics were evaluated in continuous lab reactors and parallel batch 13 C experiments. Acetate accumulation increased during initial H 2 injections as organic loading rate increased and CO 2 levels decreased below 7%. The share of CH 4 in H 2 and 13 C mass balances increased after repeated H 2 injections, which corresponded with the increase of Methanomicrobiales observed via qPCR. The organic loading rate, the inorganic carbon level and level of methanogen adaption hence determine acetate kinetics during biomethanation of H 2 . The three identified parameters may form the base of a decision tool to assess acetate accumulation during H 2 injections to an anaerobic digester. Copyright © 2018 Elsevier Ltd. All rights reserved.

Fate of injected CO2 in the Wilcox Group, Louisiana, Gulf Coast Basin: Chemical and isotopic tracers of microbial–brine–rock–CO2 interactions

USGS Publications Warehouse

Shelton, Jenna L.; McIntosh, Jennifer C.; Warwick, Peter D.; Lee Zhi Yi, Amelia

2014-01-01

The “2800’ sandstone” of the Olla oil field is an oil and gas-producing reservoir in a coal-bearing interval of the Paleocene–Eocene Wilcox Group in north-central Louisiana, USA. In the 1980s, this producing unit was flooded with CO2 in an enhanced oil recovery (EOR) project, leaving ∼30% of the injected CO2 in the 2800’ sandstone post-injection. This study utilizes isotopic and geochemical tracers from co-produced natural gas, oil and brine to determine the fate of the injected CO2, including the possibility of enhanced microbial conversion of CO2 to CH4 via methanogenesis. Stable carbon isotopes of CO2, CH4 and DIC, together with mol% CO2 show that 4 out of 17 wells sampled in the 2800’ sandstone are still producing injected CO2. The dominant fate of the injected CO2appears to be dissolution in formation fluids and gas-phase trapping. There is some isotopic and geochemical evidence for enhanced microbial methanogenesis in 2 samples; however, the CO2 spread unevenly throughout the reservoir, and thus cannot explain the elevated indicators for methanogenesis observed across the entire field. Vertical migration out of the target 2800’ sandstone reservoir is also apparent in 3 samples located stratigraphically above the target sand. Reservoirs comparable to the 2800’ sandstone, located along a 90-km transect, were also sampled to investigate regional trends in gas composition, brine chemistry and microbial activity. Microbial methane, likely sourced from biodegradation of organic substrates within the formation, was found in all oil fields sampled, while indicators of methanogenesis (e.g. high alkalinity, δ13C-CO2 and δ13C-DIC values) and oxidation of propane were greatest in the Olla Field, likely due to its more ideal environmental conditions (i.e. suitable range of pH, temperature, salinity, sulfate and iron concentrations).

Geophysical and Geochemical Aspects of Pressure and CO2 Saturation Modeling due to Migration of Fluids into the Above Zone Monitoring Interval of a Geologic Carbon Storage Site

NASA Astrophysics Data System (ADS)

Zhang, L.; Namhata, A.; Dilmore, R. M.; Bromhal, G. S.

2016-12-01

An increasing emphasis on the industrial scale implementation of CO2 storage into geological formations has led to the development of whole-system models to evaluate performance of candidate geologic storage sites, and the environmental risk associated with them. The components of that engineered geologic system include the storage reservoir, primary and secondary seals, and the overlying formations above primary and secondary seals (above-zone monitoring interval, AZMI). Leakage of CO2 and brine through the seal to the AZMI may occur due to the presence of natural or induced fractures in the seal. In this work, an AZMI model that simulates pressure and CO2 saturation responses through time to migration of fluids (here, CO2 and brine) from the primary seal to the AZMI is developed. A hypothetical case is examined wherein CO2 is injected into a storage reservoir for 30 years and a heterogeneous primary seal exists above the reservoir with some permeable zones. The total simulation period is 200 years (30 years of CO2 injection period and 170 years of post CO2 injection period). Key geophysical parameters such as permeability of the AZMI, thickness of the AZMI and porosity of the AZMI have significant impact on pressure evolution in the AZMI. arbitrary Polynomial Chaos (aPC) Expansion analysis shows that permeability of the AZMI has the most significant impact on pressure build up in the AZMI above the injection well at t=200 years, followed by thickness of the AZMI and porosity of the AZMI. Geochemical reactions have no impact on pressure and CO2 saturation evolution in the AZMI during the CO2 injection period. After the CO2 injection stops, precipitation of secondary minerals (e.g., amorphous silica and kaolinite) at the CO2 plume/brine interface in the AZMI formation may cause permeability reduction of the AZMI, which restrains horizontal migration of CO2 in the AZMI.

Understanding of the carbon dioxide sequestration in extremely low-permeability saline aquifers in the Ordos Basin

NASA Astrophysics Data System (ADS)

Zhang, K.; Xie, J.; Hu, L.; Wang, Y.; Chen, M.

2014-12-01

A full-chain CCS demonstration project was started in 2010 by capturing and injecting around 100,000 tons of CO2 per annum into extremely low-permeability sandstone formations in the northeastern Ordos basin, Inner Mongonia, China. It is the first demonstration project in China for the purpose of public interests by sequestrating in the deep saline aquifers massive amount of CO2 captured from a coal liquefaction company. The injection takes place in overall five brine-bearing geological units that are composed of four sandstones and one carbonate, which are interbedded with various mudstone caprocks. A single vertical well was drilled to the depth of 2826m. Injection screens are opened to more than 20 thin aquifers distributed between the depth 1690m-2453m with a total of 88 m injecting thickness. The permeability for all the storage formations is less 10 md and porosity is in the range of 1-12%. Hydraulic fracturing and formation acidizing were conducted at 10 layers for reservoir improvement. Up to present, total injection of CO2 is about 280,000 tons. Injection pressure drops from around 8.5 MP at the beginning to less than 5MP at present and most CO2 goes to shallowest injection formation at the depth interval 1690-1699 m, which has not been conducted any reservoir improvement. We intend to understand the improving injectivity of such low permeability reservoirs with numerical simulations. The modeling results reasonably describe the spreading of the CO2 plume. After 3 years of injection of CO2, the maximum migrating distance of CO2 plume is about 500 m and the pore pressure build-up is slightly less than 15 MPa. The major storage reservoir at the depth interval 1690-1699 m contributes over 80% of the storage capacity of the entire reservoir system.

Laboratory flow experiments for visualizing carbon dioxide-induced, density-driven brine convection

DOE Office of Scientific and Technical Information (OSTI.GOV)

Kneafsey, T.; Pruess, K.

2009-09-01

Injection of carbon dioxide (CO{sub 2}) into saline aquifers confined by low-permeability cap rock will result in a layer of CO{sub 2} overlying the brine. Dissolution of CO{sub 2} into the brine increases the brine density, resulting in an unstable situation in which more-dense brine overlies less-dense brine. This gravitational instability could give rise to density-driven convection of the fluid, which is a favorable process of practical interest for CO{sub 2} storage security because it accelerates the transfer of buoyant CO{sub 2} into the aqueous phase, where it is no longer subject to an upward buoyant drive. Laboratory flow visualizationmore » tests in transparent Hele-Shaw cells have been performed to elucidate the processes and rates of this CO{sub 2} solute-driven convection (CSC). Upon introduction of CO{sub 2} into the system, a layer of CO{sub 2}-laden brine forms at the CO{sub 2}-water interface. Subsequently, small convective fingers form, which coalesce, broaden, and penetrate into the test cell. Images and time-series data of finger lengths and wavelengths are presented. Observed CO{sub 2} uptake of the convection system indicates that the CO{sub 2} dissolution rate is approximately constant for each test and is far greater than expected for a diffusion-only scenario. Numerical simulations of our system show good agreement with the experiments for onset time of convection and advancement of convective fingers. There are differences as well, the most prominent being the absence of cell-scale convection in the numerical simulations. This cell-scale convection observed in the experiments is probably initiated by a small temperature gradient induced by the cell illumination.« less

Laboratory Investigation of Coal Deformation Behavior and Its Influence on Permeability Evolution During Methane Displacement by CO2

NASA Astrophysics Data System (ADS)

Fan, Jingjing; Feng, Ruimin; Wang, Jin; Wang, Yanbin

2017-07-01

Geological sequestration of CO2 in coal seams is of significant interest to both academia and industry. A thorough laboratory investigation of mechanical and flow behaviors is crucial for understanding the complex response of coalbeds to CO2 injection-enhanced coalbed methane recovery (CO2-ECBM) operation. In this work, systematic experiments were carried out on cylindrical coal core specimens under different uniform confining stresses. The coal deformation caused by variations in effective stress as well as the sorption-induced matrix swelling/shrinkage was monitored. The competitive gas sorption characteristics and permeability evolution during the process of methane displacement by CO2 were also investigated. The measured volumetric strain results indicate that sorption-induced strain is the dominant factor in the coal deformation. The relationship between the volumetric strain and the adsorbed gas volume has been revealed to be a linear function. Experimental results obtained under different stress conditions suggest that higher confining stress suppresses the increase in both volumetric strain and the adsorbed gas volume. Furthermore, both methane displacement and CO2 injection are reduced when applying higher confining stresses. In addition, the permeability enhancement is heavily suppressed at higher confining stress. At a certain confining stress, a characteristic "U-shaped" trend of permeability is presented as a function of decreasing pore pressure. This study contributes to the understanding of coal deformation and its impact on permeability evolution under uniformly stressed condition, which has practical significance for CO2 sequestration and CO2-ECBM operation in the Qinshui basin.

Experimental investigation of supercritical CO 2 trapping mechanisms at the Intermediate Laboratory Scale in well-defined heterogeneous porous media

DOE PAGES

Trevisan, Luca; Pini, Ronny; Cihan, Abdullah; ...

2014-12-31

The heterogeneous nature of typical sedimentary formations can play a major role in the propagation of the CO 2 plume, eventually dampening the accumulation of mobile phase underneath the caprock. From core flooding experiments, it is also known that contrasts in capillary threshold pressure due to different pore size can affect the flow paths of the invading and displaced fluids and consequently influence the build- up of non-wetting phase (NWP) at interfaces between geological facies. The full characterization of the geologic variability at all relevant scales and the ability to make observations on the spatial and temporal distribution of themore » migration and trapping of supercritical CO 2 is not feasible from a practical perspective. To provide insight into the impact of well-defined heterogeneous systems on the flow dynamics and trapping efficiency of supercritical CO 2 under drainage and imbibition conditions, we present an experimental investigation at the meter scale conducted in synthetic sand reservoirs packed in a quasi-two-dimensional flow-cell. Two immiscible displacement experiments have been performed to observe the preferential entrapment of NWP in simple heterogeneous porous media. The experiments consisted of an injection, a fluid redistribution, and a forced imbibition stages conducted in an uncorrelated permeability field and a homogeneous base case scenario. We adopted x-ray attenuation analysis as a non-destructive technique that allows a precise measurement of phase saturations throughout the entire flow domain. By comparing a homogeneous and a heterogeneous scenario we have identified some important effects that can be attributed to capillary barriers, such as dampened plume advancement, higher non-wetting phase saturations, larger contact area between the injected and displaced phases, and a larger range of non-wetting phase saturations.« less

SUBTASK 2.19 – OPERATIONAL FLEXIBILITY OF CO2 TRANSPORT AND STORAGE

DOE Office of Scientific and Technical Information (OSTI.GOV)

Jensen, Melanie; Schlasner, Steven; Sorensen, James

2014-12-31

Carbon dioxide (CO2) is produced in large quantities during electricity generation and by industrial processes. These CO2 streams vary in terms of both composition and mass flow rate, sometimes substantially. The impact of a varying CO2 stream on pipeline and storage operation is not fully understood in terms of either operability or infrastructure robustness. This study was performed to summarize basic background from the literature on the topic of operational flexibility of CO2 transport and storage, but the primary focus was on compiling real-world lessons learned about flexible operation of CO2 pipelines and storage from both large-scale field demonstrations andmore » commercial operating experience. Modeling and pilot-scale results of research in this area were included to illustrate some of the questions that exist relative to operation of carbon capture and storage (CCS) projects with variable CO2 streams. It is hoped that this report’s real-world findings provide readers with useful information on the topic of transport and storage of variable CO2 streams. The real-world results were obtained from two sources. The first source consisted of five full-scale, commercial transport–storage projects: Sleipner, Snøhvit, In Salah, Weyburn, and Illinois Basin–Decatur. These scenarios were reviewed to determine the information that is available about CO2 stream variability/intermittency on these demonstration-scale projects. The five projects all experienced mass flow variability or an interruption in flow. In each case, pipeline and/or injection engineers were able to accommodate any issues that arose. Significant variability in composition has not been an issue at these five sites. The second source of real- world results was telephone interviews conducted with experts in CO2 pipeline transport, injection, and storage during which commercial anecdotal information was acquired to augment that found during the literature search of the five full-scale projects. The experts represented a range of disciplines and hailed from North America and Europe. Major findings of the study are that compression and transport of CO2 for enhanced oil recovery (EOR) purposes in the United States has shown that impurities are not likely to cause transport problems if CO2 stream composition standards are maintained and pressures are kept at 10.3 MPa or higher. Cyclic, or otherwise intermittent, CO2 supplies historically have not impacted in-field distribution pipeline networks, wellbore integrity, or reservoir conditions. The U.S. EOR industry has demonstrated that it is possible to adapt to variability and intermittency in CO2 supply through flexible operation of the pipeline and geologic storage facility. This CO2 transport and injection experience represents knowledge that can be applied in future CCS projects. A number of gaps in knowledge were identified that may benefit from future research and development, further enhancing the possibility for widespread application of CCS. This project was funded through the Energy & Environmental Research Center–U.S. Department of Energy Joint Program on Research and Development for Fossil Energy-Related Resources Cooperative Agreement No. DE-FC26-08NT43291. Nonfederal funding was provided by the IEA Greenhouse Gas R&D Programme.« less

Geologic Sequestration of CO2: Potential Permeability Changes in Host Formations of the San Juan Basin, New Mexico

NASA Astrophysics Data System (ADS)

Abel, A. P.; McPherson, B.; Lichtner, P.; Bond, G.; Stringer, J.; Grigg, R.

2002-12-01

Terrestrial sequestration through injection into geologic formations is one proposed method for the isolation of anthropogenic CO2 from the atmosphere. A variety of physical and chemical processes are known to occur both during and after geologic CO2 injection, including diagenetic chemical reactions and associated permeability changes. Although it is commonly assumed that CO2 sequestered in this way will ultimately become mineralized, the rates of these changes, including CO2 hydration in brines, are known to be relatively slow. Bond and others (this volume) have developed a biomimetic approach to CO2 sequestration, in which the rate of CO2 hydration is accelerated by the use of a biological catalyst. Together with the hydrated CO2, cations from produced brines may be used to form solid-state carbonate minerals at the earth's surface, or this bicarbonate solution may be reinjected for geologic sequestration. Chemical composition of produced brines will affect both the diagenetic reactions that occur within the host formation, and the precipitation reactions that will occur above ground. In a specific case study of the San Juan Basin, New Mexico, we are cataloging different brines present in that basin. We are using this information to facilitate evaluation of potential applications of the biomimetic process and geologic sequestration. In a separate collaborative study by Grigg and others (this volume), laboratory experiments have been conducted on multiphase CO2 and brine injection and flow through saturated rock cores. We are extending from that study to our specific case study of the San Juan basin, to examine and characterize potential permeability changes associated with accelerated diagenesis due to the presence of high concentrations of CO2 or bicarbonate solutions in situ. We are developing and conducting new laboratory experiments to evaluate relative permeability (to CO2 and brine) of selected strata from the Fruitland Formation and Pictured Cliffs Sandstone. In addition to relative permeability, we are conducting longer-term flow tests reflecting marked permeability changes, and documenting the changes by comparing detailed pre-test measurements of porosity and permeability to post-test measurements. We are using these experimental results to parameterize coupled-flow and reactive-chemistry models of a selected cross-section of the San Juan basin. Our flow and chemistry model is based on the Los Alamos National Laboratory reactive chemistry simulator, TRANS, coupled to the Lawrence Berkeley Laboratory flow simulator, TOUGH2. The purpose of these simulation models is to evaluate potential CO2- and bicarbonate-induced diagenetic changes in permeability and flow at the basin-scale. In addition they will provide useful information in relation to brine extraction. We are also using these calibrated basin models to examine natural diagenesis and permeability evolution associated with changing brine properties and flow conditions over geologic time.

Southwestern Regional Partnership For Carbon Sequestration (Phase 2) Pump Canyon CO2- ECBM/Sequestration Demonstration, San Juan Basin, New Mexico

DOE Office of Scientific and Technical Information (OSTI.GOV)

Advanced Resources International

2010-01-31

Within the Southwest Regional Partnership on Carbon Sequestration (SWP), three demonstrations of geologic CO{sub 2} sequestration are being performed -- one in an oilfield (the SACROC Unit in the Permian basin of west Texas), one in a deep, unmineable coalbed (the Pump Canyon site in the San Juan basin of northern New Mexico), and one in a deep, saline reservoir (underlying the Aneth oilfield in the Paradox basin of southeast Utah). The Pump Canyon CO{sub 2}-enhanced coalbed methane (CO{sub 2}/ECBM) sequestration demonstration project plans to demonstrate the effectiveness of CO{sub 2} sequestration in deep, unmineable coal seams via a small-scalemore » geologic sequestration project. The site is located in San Juan County, northern New Mexico, just within the limits of the high-permeability fairway of prolific coalbed methane production. The study area for the SWP project consists of 31 coalbed methane production wells located in a nine section area. CO{sub 2} was injected continuously for a year and different monitoring, verification and accounting (MVA) techniques were implemented to track the CO{sub 2} movement inside and outside the reservoir. Some of the MVA methods include continuous measurement of injection volumes, pressures and temperatures within the injection well, coalbed methane production rates, pressures and gas compositions collected at the offset production wells, and tracers in the injected CO{sub 2}. In addition, time-lapse vertical seismic profiling (VSP), surface tiltmeter arrays, a series of shallow monitoring wells with a regular fluid sampling program, surface measurements of soil composition, CO{sub 2} fluxes, and tracers were used to help in tracking the injected CO{sub 2}. Finally, a detailed reservoir model was constructed to help reproduce and understand the behavior of the reservoir under production and injection operation. This report summarizes the different phases of the project, from permitting through site closure, and gives the results of the different MVA techniques.« less

Reactive transport modeling to study changes in water chemistry induced by CO2 injection at the Frio-I Brine Pilot

USGS Publications Warehouse

Xu, T.; Kharaka, Y.K.; Doughty, C.; Freifeld, B.M.; Daley, T.M.

2010-01-01

To demonstrate the potential for geologic storage of CO2 in saline aquifers, the Frio-I Brine Pilot was conducted, during which 1600 tons of CO2 were injected into a high-permeability sandstone and the resulting subsurface plume of CO2 was monitored using a variety of hydrogeological, geophysical, and geochemical techniques. Fluid samples were obtained before CO2 injection for baseline geochemical characterization, during the CO2 injection to track its breakthrough at a nearby observation well, and after injection to investigate changes in fluid composition and potential leakage into an overlying zone. Following CO2 breakthrough at the observation well, brine samples showed sharp drops in pH, pronounced increases in HCO3- and aqueous Fe, and significant shifts in the isotopic compositions of H2O and dissolved inorganic carbon. Based on a calibrated 1-D radial flow model, reactive transport modeling was performed for the Frio-I Brine Pilot. A simple kinetic model of Fe release from the solid to aqueous phase was developed, which can reproduce the observed increases in aqueous Fe concentration. Brine samples collected after half a year had lower Fe concentrations due to carbonate precipitation, and this trend can be also captured by our modeling. The paper provides a method for estimating potential mobile Fe inventory, and its bounding concentration in the storage formation from limited observation data. Long-term simulations show that the CO2 plume gradually spreads outward due to capillary forces, and the gas saturation gradually decreases due to its dissolution and precipitation of carbonates. The gas phase is predicted to disappear after 500 years. Elevated aqueous CO2 concentrations remain for a longer time, but eventually decrease due to carbonate precipitation. For the Frio-I Brine Pilot, all injected CO2 could ultimately be sequestered as carbonate minerals. ?? 2010 Elsevier B.V.

Assessment of Factors Influencing Effective CO 2 Storage Capacity and Injectivity in Eastern Gas Shales

DOE Office of Scientific and Technical Information (OSTI.GOV)

Godec, Michael

Building upon advances in technology, production of natural gas from organic-rich shales is rapidly developing as a major hydrocarbon supply option in North America and around the world. The same technology advances that have facilitated this revolution - dense well spacing, horizontal drilling, and hydraulic fracturing - may help to facilitate enhanced gas recovery (EGR) and carbon dioxide (CO 2) storage in these formations. The potential storage of CO 2 in shales is attracting increasing interest, especially in Appalachian Basin states that have extensive shale deposits, but limited CO 2 storage capacity in conventional reservoirs. The goal of this cooperativemore » research project was to build upon previous and on-going work to assess key factors that could influence effective EGR, CO 2 storage capacity, and injectivity in selected Eastern gas shales, including the Devonian Marcellus Shale, the Devonian Ohio Shale, the Ordovician Utica and Point Pleasant shale and equivalent formations, and the late Devonian-age Antrim Shale. The project had the following objectives: (1) Analyze and synthesize geologic information and reservoir data through collaboration with selected State geological surveys, universities, and oil and gas operators; (2) improve reservoir models to perform reservoir simulations to better understand the shale characteristics that impact EGR, storage capacity and CO 2 injectivity in the targeted shales; (3) Analyze results of a targeted, highly monitored, small-scale CO 2 injection test and incorporate into ongoing characterization and simulation work; (4) Test and model a smart particle early warning concept that can potentially be used to inject water with uniquely labeled particles before the start of CO 2 injection; (5) Identify and evaluate potential constraints to economic CO 2 storage in gas shales, and propose development approaches that overcome these constraints; and (6) Complete new basin-level characterizations for the CO 2 storage capacity and injectivity potential of the targeted eastern shales. In total, these Eastern gas shales cover an area of over 116 million acres, may contain an estimated 6,000 trillion cubic feet (Tcf) of gas in place, and have a maximum theoretical storage capacity of over 600 million metric tons. Not all of this gas in-place will be recoverable, and economics will further limit how much will be economic to produce using EGR techniques with CO 2 injection. Reservoir models were developed and simulations were conducted to characterize the potential for both CO 2 storage and EGR for the target gas shale formations. Based on that, engineering costing and cash flow analyses were used to estimate economic potential based on future natural gas prices and possible financial incentives. The objective was to assume that EGR and CO 2 storage activities would commence consistent with the historical development practices. Alternative CO 2 injection/EGR scenarios were considered and compared to well production without CO 2 injection. These simulations were conducted for specific, defined model areas in each shale gas play. The resulting outputs were estimated recovery per typical well (per 80 acres), and the estimated CO 2 that would be injected and remain in the reservoir (i.e., not produced), and thus ultimately assumed to be stored. The application of this approach aggregated to the entire area of the four shale gas plays concluded that they contain nearly 1,300 Tcf of both primary production and EGR potential, of which an estimated 460 Tcf could be economic to produce with reasonable gas prices and/or modest incentives. This could facilitate the storage of nearly 50 Gt of CO 2 in the Marcellus, Utica, Antrim, and Devonian Ohio shales.« less

Experimental observation of permeability changes in dolomite at CO2 sequestration conditions.

PubMed

Tutolo, Benjamin M; Luhmann, Andrew J; Kong, Xiang-Zhao; Saar, Martin O; Seyfried, William E

2014-02-18

Injection of cool CO2 into geothermally warm carbonate reservoirs for storage or geothermal energy production may lower near-well temperature and lead to mass transfer along flow paths leading away from the well. To investigate this process, a dolomite core was subjected to a 650 h, high pressure, CO2 saturated, flow-through experiment. Permeability increased from 10(-15.9) to 10(-15.2) m(2) over the initial 216 h at 21 °C, decreased to 10(-16.2) m(2) over 289 h at 50 °C, largely due to thermally driven CO2 exsolution, and reached a final value of 10(-16.4) m(2) after 145 h at 100 °C due to continued exsolution and the onset of dolomite precipitation. Theoretical calculations show that CO2 exsolution results in a maximum pore space CO2 saturation of 0.5, and steady state relative permeabilities of CO2 and water on the order of 0.0065 and 0.1, respectively. Post-experiment imagery reveals matrix dissolution at low temperatures, and subsequent filling-in of flow passages at elevated temperature. Geochemical calculations indicate that reservoir fluids subjected to a thermal gradient may exsolve and precipitate up to 200 cm(3) CO2 and 1.5 cm(3) dolomite per kg of water, respectively, resulting in substantial porosity and permeability redistribution.

Silurian "Clinton" Sandstone Reservoir Characterization for Evaluation of CO2-EOR Potential in the East Canton Oil Field, Ohio

DOE Office of Scientific and Technical Information (OSTI.GOV)

Ronald Riley; John Wicks; Christopher Perry

The purpose of this study was to evaluate the efficacy of using CO2-enhanced oil recovery (EOR) in the East Canton oil field (ECOF). Discovered in 1947, the ECOF in northeastern Ohio has produced approximately 95 million barrels (MMbbl) of oil from the Silurian 'Clinton' sandstone. The original oil-in-place (OOIP) for this field was approximately 1.5 billion bbl and this study estimates by modeling known reservoir parameters, that between 76 and 279 MMbbl of additional oil could be produced through secondary recovery in this field, depending on the fluid and formation response to CO2 injection. A CO2 cyclic test ('Huff-n-Puff') wasmore » conducted on a well in Stark County to test the injectivity in a 'Clinton'-producing oil well in the ECOF and estimate the dispersion or potential breakthrough of the CO2 to surrounding wells. Eighty-one tons of CO2 (1.39 MMCF) were injected over a 20-hour period, after which the well was shut in for a 32-day 'soak' period before production was resumed. Results demonstrated injection rates of 1.67 MMCF of gas per day, which was much higher than anticipated and no CO2 was detected in gas samples taken from eight immediately offsetting observation wells. All data collected during this test was analyzed, interpreted, and incorporated into the reservoir characterization study and used to develop the geologic model. The geologic model was used as input into a reservoir simulation performed by Fekete Associates, Inc., to estimate the behavior of reservoir fluids when large quantities of CO2 are injected into the 'Clinton' sandstone. Results strongly suggest that the majority of the injected CO2 entered the matrix porosity of the reservoir pay zones, where it diffused into the oil. Evidence includes: (A) the volume of injected CO2 greatly exceeded the estimated capacity of the hydraulic fracture and natural fractures; (B) there was a gradual injection and pressure rate build-up during the test; (C) there was a subsequent, gradual flashout of the CO2 within the reservoir during the ensuing monitored production period; and (D) a large amount of CO2 continually off-gassed from wellhead oil samples collected as late as 3 1/2 months after injection. After the test well was returned to production, it produced 174 bbl of oil during a 60-day period (September 22 to November 21, 2008), which represents an estimated 58 percent increase in incremental oil production over preinjection estimates of production under normal, conditions. The geologic model was used in a reservoir simulation model for a 700-acre model area and to design a pilot to test the model. The model was designed to achieve a 1-year response time and a five-year simulation period. The reservoir simulation modeling indicated that the injection wells could enhance oil production and lead to an additional 20 percent recovery in the pilot area over a five-year period. The base case estimated that by injecting 500 MCF per day of CO2 into each of the four corner wells, 26,000 STBO would be produced by the central producer over the five-year period. This would compare to 3,000 STBO if a new well were drilled without the benefit of CO2 injection. This study has added significant knowledge to the reservoir characterization of the 'Clinton' in the ECOF and succeeded in identifying a range on CO2-EOR potential. However, additional data on fluid properties (PVT and swelling test), fractures (oriented core and microseis), and reservoir characteristics (relative permeability, capillary pressure, and wet ability) are needed to further narrow the uncertainties and refine the reservoir model and simulation. After collection of this data and refinement of the model and simulation, it is recommended that a larger scale cyclic-CO2 injection test be conducted to better determine the efficacy of CO2-EOR in the 'Clinton' reservoir in the ECOF.« less

Detecting potential impacts of deep subsurface CO2 injection on shallow drinking water

NASA Astrophysics Data System (ADS)

Smyth, R. C.; Yang, C.; Romanak, K.; Mickler, P. J.; Lu, J.; Hovorka, S. D.

2012-12-01

Presented here are results from one aspect of collective research conducted at Gulf Coast Carbon Center, BEG, Jackson School at UT Austin. The biggest hurdle to public acceptance of CCS is to show that drinking water resources will not be impacted. Since late 1990s our group has been supported by US DOE NETL and private industry to research how best to detect potential impacts to shallow (0 to ~0.25 km) subsurface drinking water from deep (~1 to 3.5 km) injection of CO2. Work has and continues to include (1) field sampling and testing, (2) laboratory batch experiments, (3) geochemical modeling. The objective has been to identify the most sensitive geochemical indicators using data from research-level investigations, which can be economically applied on an industrial-scale. The worst-case scenario would be introduction of CO2 directly into drinking water from a leaking wellbore at a brownfield site. This is unlikely for a properly screened and/or maintained site, but needs to be considered. Our results show aquifer matrix (carbonate vs. clastic) to be critical to interpretation of pH and carbonate (DIC, Alkalinity, and δ13C of DIC) parameters because of the influence of water-rock reaction (buffering vs. non-buffering) on aqueous geochemistry. Field groundwater sampling sites to date are Cranfield, MS and SACROC, TX CO2-EOR oilfields. Two major aquifer types are represented, one dominated by silicate (Cranfield) and the other by carbonate (SACROC) water-rock reactions. We tested sensitivity of geochemical indicators (pH, DIC, Alkalinity, and δ13C of DIC) by modeling the effects of increasing pCO2 on aqueous geochemistry, and laboratory batch experiments, both with partial pressure of CO2 gas (pCO2) at 1x105 Pa (1 atm). Aquifer matrix and groundwater data provided constraints for the geochemical models. We used results from modeling and batch experiments to rank geochemical parameter sensitivity to increased pCO2 into weakly, mildly and strongly sensitive categories for both aquifer systems. DIC concentration is strongly sensitive to increased pCO2 for both aquifers; however, CO2 outgassing during sampling complicates direct field measurement of DIC. Interpretation of data from in-situ push-pull aquifer tests is ongoing and will be used to augment results summarized here. We are currently designing groundwater monitoring plans for two additional industrial-scale sites where we will further test the sensitivity and utility of our sampling approach.

Sequestration and Enhanced Coal Bed Methane: Tanquary Farms Test Site, Wabash County, Illinois

DOE Office of Scientific and Technical Information (OSTI.GOV)

Frailey, Scott; Parris, Thomas; Damico, James

The Midwest Geological Sequestration Consortium (MGSC) carried out a pilot project to test storage of carbon dioxide (CO{sub 2}) in the Springfield Coal Member of the Carbondale Formation (Pennsylvanian System), in order to gauge the potential for large-scale CO{sub 2} sequestration and/or enhanced coal bed methane recovery from Illinois Basin coal beds. The pilot was conducted at the Tanquary Farms site in Wabash County, southeastern Illinois. A four-well design an injection well and three monitoring wells was developed and implemented, based on numerical modeling and permeability estimates from literature and field data. Coal cores were taken during the drilling processmore » and were characterized in detail in the lab. Adsorption isotherms indicated that at least three molecules of CO{sub 2} can be stored for each displaced methane (CH{sub 4}) molecule. Microporosity contributes significantly to total porosity. Coal characteristics that affect sequestration potential vary laterally between wells at the site and vertically within a given seam, highlighting the importance of thorough characterization of injection site coals to best predict CO{sub 2} storage capacity. Injection of CO{sub 2} gas took place from June 25, 2008, to January 13, 2009. A continuous injection period ran from July 21, 2008, to December 23, 2008, but injection was suspended several times during this period due to equipment failures and other interruptions. Injection equipment and procedures were adjusted in response to these problems. Approximately 92.3 tonnes (101.7 tons) of CO{sub 2} were injected over the duration of the project, at an average rate of 0.93 tonne (1.02 tons) per day, and a mode injection rate of 0.6-0.7 tonne/day (0.66-0.77 ton/day). A Monitoring, Verification, and Accounting (MVA) program was set up to detect CO{sub 2 leakage. Atmospheric CO{sub 2} levels were monitored as were indirect indicators of CO{sub 2} leakage such as plant stress, changes in gas composition at wellheads, and changes in several shallow groundwater characteristics (e.g., alkalinity, pH, oxygen content, dissolved solids, mineral saturation indices, and isotopic distribution). Results showed that there was no CO{sub 2} leakage into groundwater or CO{sub 2} escape at the surface. Post-injection cased hole well log analyses supported this conclusion. Numerical and analytical modeling achieved a relatively good match with observed field data. Based on the model results the plume was estimated to extend 152 m (500 ft) in the face cleat direction and 54.9 m (180 ft) in the butt cleat direction. Using the calibrated model, additional injection scenarios-injection and production with an inverted five-spot pattern and a line drive pattern could yield CH{sub 4} recovery of up to 70%.« less

Subtask – CO 2 storage and enhanced bakken recovery research program

DOE Office of Scientific and Technical Information (OSTI.GOV)

Sorensen, James; Hawthorne, Steven; Smith, Steven

Small improvements in productivity could increase technically recoverable oil in the Bakken Petroleum System by billions of barrels. The use of CO 2 for enhanced oil recovery (EOR) in tight oil reservoirs is a relatively new concept. The large-scale injection of CO 2 into the Bakken would also result in the geological storage of significant amounts of CO 2. The Energy & Environmental Research Center (EERC) has conducted laboratory and modeling activities to examine the potential for CO 2 storage and EOR in the Bakken. Specific activities included the characterization and subsequent modeling of North Dakota study areas as wellmore » as dynamic predictive simulations of possible CO 2 injection schemes to predict the potential CO 2 storage and EOR in those areas. Laboratory studies to evaluate the ability of CO 2 to remove hydrocarbons from Bakken rocks and determine minimum miscibility pressures for Bakken oil samples were conducted. Data from a CO 2 injection test conducted in the Elm Coulee area of Montana in 2009 were evaluated with an eye toward the possible application of knowledge gained to future injection tests in other areas. A first-order estimation of potential CO 2 storage capacity in the Bakken Formation in North Dakota was also conducted. Key findings of the program are as follows. The results of the research activities suggest that CO 2 may be effective in enhancing the productivity of oil from the Bakken and that the Bakken may hold the ability to geologically store between 120 Mt and 3.2 Gt of CO 2. However, there are no clear-cut answers regarding the most effective approach for using CO 2 to improve oil productivity or the storage capacity of the Bakken. The results underscore the notion that an unconventional resource will likely require unconventional methods of both assessment and implementation when it comes to the injection of CO 2. In particular, a better understanding of the fundamental mechanisms controlling the interactions between CO 2, oil, and other reservoir fluids in these unique formations is necessary to develop accurate assessments of potential CO 2 storage and EOR in the Bakken. In addition, existing modeling and simulation software packages do not adequately address or incorporate the unique properties of these tight, unconventional reservoirs in terms of their impact on CO 2 behavior. These knowledge gaps can be filled by conducting scaled-up laboratory activities integrated with improved modeling and simulation techniques, the results of which will provide a robust foundation for pilot-scale field injection tests. Finally, field-based data on injection, fluid production, and long-term monitoring from pilot-scale CO 2 injection tests in the Bakken are necessary to verify and validate the findings of the laboratory- and modeling-based research efforts. This subtask was funded through the EERC–U.S. Department of Energy (DOE) Joint Program on Research and Development for Fossil Energy-Related Resources Cooperative Agreement No. DE-FC26-08NT43291. Nonfederal funding was provided by the North Dakota Industrial Commission, Marathon Oil Corporation, Continental Resources Inc., and TAQA North, Ltd.« less

A Novel Approach to Experimental Studies of Mineral Dissolution Kinetics

DOE Office of Scientific and Technical Information (OSTI.GOV)

Chen Zhu

2006-08-31

Currently, DOE is conducting pilot CO{sub 2} injection tests to evaluate the concept of geological sequestration. One strategy that potentially enhances CO{sub 2} solubility and reduces the risk of CO{sub 2} leak back to the surface is dissolution of indigenous minerals in the geological formation and precipitation of secondary carbonate phases, which increases the brine pH and immobilizes CO{sub 2}. Clearly, the rates at which these dissolution and precipitation reactions occur directly determine the efficiency of this strategy. However, one of the fundamental problems in modern geochemistry is the persistent two to five orders of magnitude discrepancy between laboratory measuredmore » and field derived feldspar dissolution rates. To date, there is no real guidance as to how to predict silicate reaction rates for use in quantitative models. Current models for assessment of geological carbon sequestration have generally opted to use laboratory rates, in spite of the dearth of such data for compositionally complex systems, and the persistent disconnect between laboratory and field applications. Therefore, a firm scientific basis for predicting silicate reaction kinetics in CO2 injected geological formations is urgently needed to assure the reliability of the geochemical models used for the assessments of carbon sequestration strategies. The funded experimental and theoretical study attempts to resolve this outstanding scientific issue by novel experimental design and theoretical interpretation to measure silicate dissolution rates and iron carbonate precipitation rates at conditions pertinent to geological carbon sequestration. In the second year of the project, we completed CO{sub 2}-Navajo sandstone interaction batch and flow-through experiments and a Navajo sandstone dissolution experiment without the presence of CO{sub 2} at 200 C and 250-300 bars, and initiated dawsonite dissolution and solubility experiments. We also performed additional 5-day experiments at the same conditions as alkali-feldspar dissolution experiments with and without the presence of CO{sub 2} performed in the first year to check the validation of the experiments and analysis. The changes of solution chemistry as dissolution experiments progressed were monitored with on-line sampling of the aqueous phase at the constant temperature and pressure. These data allow calculating overall apparent mineral (feldspars and sandstones) dissolution rates and secondary mineral precipitation rates as a function of saturation states. State-of-the-art atomic resolution transmission electron microscopy (TEM), scanning electron microscopy (SEM), and electron microprobe was used to characterize the products and reactants. Reaction-path geochemical modeling was used to interpret the experimental results of alkali-feldspar dissolution experiments without the presence of CO{sub 2}. Two manuscripts are near completion. Also during the second year, our education goal of graduate student training has been advanced. A Ph. D. student at Indiana University is progressing well in the degree program and has taken geochemical modeling, SEM, and TEM courses, which will facilitate research in the third year. A Ph. D. student at University of Minnesota had graduated. With the success of training of graduate students and excellent experimental data in the second year, we anticipate a more fruitful year in the third year.« less

Constraints on the magnitude and rate of CO2 dissolution at Bravo Dome natural gas field

PubMed Central

Sathaye, Kiran J.; Hesse, Marc A.; Cassidy, Martin; Stockli, Daniel F.

2014-01-01

The injection of carbon dioxide (CO2) captured at large point sources into deep saline aquifers can significantly reduce anthropogenic CO2 emissions from fossil fuels. Dissolution of the injected CO2 into the formation brine is a trapping mechanism that helps to ensure the long-term security of geological CO2 storage. We use thermochronology to estimate the timing of CO2 emplacement at Bravo Dome, a large natural CO2 field at a depth of 700 m in New Mexico. Together with estimates of the total mass loss from the field we present, to our knowledge, the first constraints on the magnitude, mechanisms, and rates of CO2 dissolution on millennial timescales. Apatite (U-Th)/He thermochronology records heating of the Bravo Dome reservoir due to the emplacement of hot volcanic gases 1.2–1.5 Ma. The CO2 accumulation is therefore significantly older than previous estimates of 10 ka, which demonstrates that safe long-term geological CO2 storage is possible. Integrating geophysical and geochemical data, we estimate that 1.3 Gt CO2 are currently stored at Bravo Dome, but that only 22% of the emplaced CO2 has dissolved into the brine over 1.2 My. Roughly 40% of the dissolution occurred during the emplacement. The CO2 dissolved after emplacement exceeds the amount expected from diffusion and provides field evidence for convective dissolution with a rate of 0.1 g/(m2y). The similarity between Bravo Dome and major US saline aquifers suggests that significant amounts of CO2 are likely to dissolve during injection at US storage sites, but that convective dissolution is unlikely to trap all injected CO2 on the 10-ky timescale typically considered for storage projects. PMID:25313084

CCS Site Optimization by Applying a Multi-objective Evolutionary Algorithm to Semi-Analytical Leakage Models

NASA Astrophysics Data System (ADS)

Cody, B. M.; Gonzalez-Nicolas, A.; Bau, D. A.

2011-12-01

Carbon capture and storage (CCS) has been proposed as a method of reducing global carbon dioxide (CO2) emissions. Although CCS has the potential to greatly retard greenhouse gas loading to the atmosphere while cleaner, more sustainable energy solutions are developed, there is a possibility that sequestered CO2 may leak and intrude into and adversely affect groundwater resources. It has been reported [1] that, while CO2 intrusion typically does not directly threaten underground drinking water resources, it may cause secondary effects, such as the mobilization of hazardous inorganic constituents present in aquifer minerals and changes in pH values. These risks must be fully understood and minimized before CCS project implementation. Combined management of project resources and leakage risk is crucial for the implementation of CCS. In this work, we present a method of: (a) minimizing the total CCS cost, the summation of major project costs with the cost associated with CO2 leakage; and (b) maximizing the mass of injected CO2, for a given proposed sequestration site. Optimization decision variables include the number of CO2 injection wells, injection rates, and injection well locations. The capital and operational costs of injection wells are directly related to injection well depth, location, injection flow rate, and injection duration. The cost of leakage is directly related to the mass of CO2 leaked through weak areas, such as abandoned oil wells, in the cap rock layers overlying the injected formation. Additional constraints on fluid overpressure caused by CO2 injection are imposed to maintain predefined effective stress levels that prevent cap rock fracturing. Here, both mass leakage and fluid overpressure are estimated using two semi-analytical models based upon work by [2,3]. A multi-objective evolutionary algorithm coupled with these semi-analytical leakage flow models is used to determine Pareto-optimal trade-off sets giving minimum total cost vs. maximum mass of CO2 sequestered. This heuristic optimization method is chosen because of its robustness in optimizing large-scale, highly non-linear problems. Trade-off curves are developed for multiple fictional sites with the intent of clarifying how variations in domain characteristics (aquifer thickness, aquifer and weak cap rock permeability, the number of weak cap rock areas, and the number of aquifer-cap rock layers) affect Pareto-optimal fronts. Computational benefits of using semi-analytical leakage models are explored and discussed. [1] Birkholzer, J. (2008) "Research Project on CO2 Geological Storage and Groundwater Resources: Water Quality Effects Caused by CO2 Intrusion into Shallow Groundwater" Berkeley (CA): Lawrence Berkeley National Laboratory (US); 2008 Oct. 473 p. Report No.: 510-486-7134. [2] Celia, M.A. and Nordbotten, J.M. (2011) "Field-scale application of a semi-analytical model for estimation of CO2 and brine leakage along old wells" International Journal of Greenhouse Gas Control, 5 (2011), 257-269. [3] Nordbotten, J.M. and Celia, M.A. (2009) "Model for CO2 leakage including multiple geological layers and multiple leaky wells" Environ. Sci. Technol., 43, 743-749.

Silurian "Clinton" Sandstone Reservoir Characterization for Evaluation of CO2-EOR Potential in the East Canton Oil Field, Ohio

DOE Office of Scientific and Technical Information (OSTI.GOV)

Riley, Ronald; Wicks, John; Perry, Christopher

The purpose of this study was to evaluate the efficacy of using CO2-enhanced oil recovery (EOR) in the East Canton oil field (ECOF). Discovered in 1947, the ECOF in northeastern Ohio has produced approximately 95 million barrels (MMbbl) of oil from the Silurian “Clinton” sandstone. The original oil-in-place (OOIP) for this field was approximately 1.5 billion bbl and this study estimates by modeling known reservoir parameters, that between 76 and 279 MMbbl of additional oil could be produced through secondary recovery in this field, depending on the fluid and formation response to CO2 injection. A CO2 cyclic test (“Huff-n-Puff”) wasmore » conducted on a well in Stark County to test the injectivity in a “Clinton”-producing oil well in the ECOF and estimate the dispersion or potential breakthrough of the CO2 to surrounding wells. Eighty-one tons of CO2 (1.39 MMCF) were injected over a 20-hour period, after which the well was shut in for a 32-day “soak” period before production was resumed. Results demonstrated injection rates of 1.67 MMCF of gas per day, which was much higher than anticipated and no CO2 was detected in gas samples taken from eight immediately offsetting observation wells. All data collected during this test was analyzed, interpreted, and incorporated into the reservoir characterization study and used to develop the geologic model. The geologic model was used as input into a reservoir simulation performed by Fekete Associates, Inc., to estimate the behavior of reservoir fluids when large quantities of CO2 are injected into the “Clinton” sandstone. Results strongly suggest that the majority of the injected CO2 entered the matrix porosity of the reservoir pay zones, where it diffused into the oil. Evidence includes: (A) the volume of injected CO2 greatly exceeded the estimated capacity of the hydraulic fracture and natural fractures; (B) there was a gradual injection and pressure rate build-up during the test; (C) there was a subsequent, gradual flashout of the CO2 within the reservoir during the ensuing monitored production period; and (D) a large amount of CO2 continually off-gassed from wellhead oil samples collected as late as 3½ months after injection. After the test well was returned to production, it produced 174 bbl of oil during a 60-day period (September 22 to November 21, 2008), which represents an estimated 58 percent increase in incremental oil production over preinjection estimates of production under normal, conditions. The geologic model was used in a reservoir simulation model for a 700-acre model area and to design a pilot to test the model. The model was designed to achieve a 1-year response time and a five-year simulation period. The reservoir simulation modeling indicated that the injection wells could enhance oil production and lead to an additional 20 percent recovery in the pilot area over a five-year period. The base case estimated that by injecting 500 MCF per day of CO2 into each of the four corner wells, 26,000 STBO would be produced by the central producer over the five-year period. This would compare to 3,000 STBO if a new well were drilled without the benefit of CO2 injection. This study has added significant knowledge to the reservoir characterization of the “Clinton” in the ECOF and succeeded in identifying a range on CO2-EOR potential. However, additional data on fluid properties (PVT and swelling test), fractures (oriented core and microseis), and reservoir characteristics (relative permeability, capillary pressure, and wet ability) are needed to further narrow the uncertainties and refine the reservoir model and simulation. After collection of this data and refinement of the model and simulation, it is recommended that a larger scale cyclic- CO2 injection test be conducted to better determine the efficacy of CO2-EOR in the “Clinton” reservoir in the ECOF.« less

Geological factors affecting CO2 plume distribution

USGS Publications Warehouse

Frailey, S.M.; Leetaru, H.

2009-01-01

Understanding the lateral extent of a CO2 plume has important implications with regards to buying/leasing pore volume rights, defining the area of review for an injection permit, determining the extent of an MMV plan, and managing basin-scale sequestration from multiple injection sites. The vertical and lateral distribution of CO2 has implications with regards to estimating CO2 storage volume at a specific site and the pore pressure below the caprock. Geologic and flow characteristics such as effective permeability and porosity, capillary pressure, lateral and vertical permeability anisotropy, geologic structure, and thickness all influence and affect the plume distribution to varying degrees. Depending on the variations in these parameters one may dominate the shape and size of the plume. Additionally, these parameters do not necessarily act independently. A comparison of viscous and gravity forces will determine the degree of vertical and lateral flow. However, this is dependent on formation thickness. For example in a thick zone with injection near the base, the CO2 moves radially from the well but will slow at greater radii and vertical movement will dominate. Generally the CO2 plume will not appreciably move laterally until the caprock or a relatively low permeability interval is contacted by the CO2. Conversely, in a relatively thin zone with the injection interval over nearly the entire zone, near the wellbore the CO2 will be distributed over the entire vertical component and will move laterally much further with minimal vertical movement. Assuming no geologic structure, injecting into a thin zone or into a thick zone immediately under a caprock will result in a larger plume size. With a geologic structure such as an anticline, CO2 plume size may be restricted and injection immediately below the caprock may have less lateral plume growth because the structure will induce downward vertical movement of the CO2 until the outer edge of the plume reaches a spill point within the structure. ?? 2009 Elsevier Ltd. All rights reserved.

Experimental Study of Porosity Changes in Shale Caprocks Exposed to CO 2-Saturated Brines I: Evolution of Mineralogy, Pore Connectivity, Pore Size Distribution, and Surface Area

DOE PAGES

Mouzakis, Katherine M.; Navarre-Sitchler, Alexis K.; Rother, Gernot; ...

2016-07-18

Carbon capture, utilization, and storage, one proposed method of reducing anthropogenic emissions of CO 2, relies on low permeability formations, such as shales, above injection formations to prevent upward migration of the injected CO 2. Porosity in caprocks evaluated for sealing capacity before injection can be altered by geochemical reactions induced by dissolution of injected CO 2 into pore fluids, impacting long-term sealing capacity. Therefore, long-term performance of CO 2 sequestration sites may be dependent on both initial distribution and connectivity of pores in caprocks, and on changes induced by geochemical reaction after injection of CO 2, which are currentlymore » poorly understood. This paper presents results from an experimental study of changes to caprock porosity and pore network geometry in two caprock formations under conditions relevant to CO 2 sequestration. Pore connectivity and total porosity increased in the Gothic Shale; while total porosity increased but pore connectivity decreased in the Marine Tuscaloosa. Gothic Shale is a carbonate mudstone that contains volumetrically more carbonate minerals than Marine Tuscaloosa. Carbonate minerals dissolved to a greater extent than silicate minerals in Gothic Shale under high CO 2 conditions, leading to increased porosity at length scales <~200 nm that contributed to increased pore connectivity. In contrast, silicate minerals dissolved to a greater extent than carbonate minerals in Marine Tuscaloosa leading to increased porosity at all length scales, and specifically an increase in the number of pores >~1 μm. Mineral reactions also contributed to a decrease in pore connectivity, possibly as a result of precipitation in pore throats or hydration of the high percentage of clays. Finally, this study highlights the role that mineralogy of the caprock can play in geochemical response to CO 2 injection and resulting changes in sealing capacity in long-term CO 2 storage projects.« less

CO 2-induced chemo-mechanical alteration in reservoir rocks assessed via batch reaction experiments and scratch testing

DOE Office of Scientific and Technical Information (OSTI.GOV)

Aman, Michael; Espinoza, D. Nicolas; Ilgen, Anastasia G.

Here, the injection of carbon dioxide (CO 2) into geological formations results in a chemical re-equilibration between the mineral assemblage and the pore fluid, with ensuing mineral dissolution and re-precipitation. Hence, target rock formations may exhibit changes of mechanical and petrophysical properties due to CO 2 exposure. We conducted batch reaction experiments with Entrada Sandstone and Summerville Siltstone exposed to de-ionized water and synthetic brine under reservoir pressure (9–10 MPa) and temperature (80°C) for up to four weeks. Samples originate from the Crystal Geyser field site, where a naturally occurring CO 2 seepage alters portions of these geologic formations. Wemore » conducted micro-scratch tests on rock samples without alteration, altered under laboratory conditions, and naturally altered over geologic time. Scratch toughness and hardness decrease as a function of exposure time and water salinity up to 52% in the case of Entrada and 87% in the case of Summerville after CO 2-induced alteration in the laboratory. Imaging of altered cores with SEM-EDS and X-ray microCT methods show dissolution of carbonate and silica cements and matrix accompanied by minor dissolution of Fe-oxides, clays, and other silicates. Parallel experiments using powdered samples confirm that dissolution of carbonate and silica are the primary reactions. The batch reaction experiments in the autoclave utilize a high fluid to rock volume ratio and represent an end member of possible alteration associated with CO 2 storage systems. These types of tests serve as a pre-screening tool to identify the susceptibility of rock facies to CO 2-related chemical-mechanical alteration during long-term CO 2 storage.« less

CO 2-induced chemo-mechanical alteration in reservoir rocks assessed via batch reaction experiments and scratch testing

DOE PAGES

Aman, Michael; Espinoza, D. Nicolas; Ilgen, Anastasia G.; ...

2017-09-22

Here, the injection of carbon dioxide (CO 2) into geological formations results in a chemical re-equilibration between the mineral assemblage and the pore fluid, with ensuing mineral dissolution and re-precipitation. Hence, target rock formations may exhibit changes of mechanical and petrophysical properties due to CO 2 exposure. We conducted batch reaction experiments with Entrada Sandstone and Summerville Siltstone exposed to de-ionized water and synthetic brine under reservoir pressure (9–10 MPa) and temperature (80°C) for up to four weeks. Samples originate from the Crystal Geyser field site, where a naturally occurring CO 2 seepage alters portions of these geologic formations. Wemore » conducted micro-scratch tests on rock samples without alteration, altered under laboratory conditions, and naturally altered over geologic time. Scratch toughness and hardness decrease as a function of exposure time and water salinity up to 52% in the case of Entrada and 87% in the case of Summerville after CO 2-induced alteration in the laboratory. Imaging of altered cores with SEM-EDS and X-ray microCT methods show dissolution of carbonate and silica cements and matrix accompanied by minor dissolution of Fe-oxides, clays, and other silicates. Parallel experiments using powdered samples confirm that dissolution of carbonate and silica are the primary reactions. The batch reaction experiments in the autoclave utilize a high fluid to rock volume ratio and represent an end member of possible alteration associated with CO 2 storage systems. These types of tests serve as a pre-screening tool to identify the susceptibility of rock facies to CO 2-related chemical-mechanical alteration during long-term CO 2 storage.« less

Laboratory batch experiments and geochemical modelling of water-rock-supercritical CO2 reactions in Southern San Joaquin Valley, California oil field sediments: Implications for future carbon capture and sequestration projects.

NASA Astrophysics Data System (ADS)

Mickler, P. J.; Rivas, C.; Freeman, S.; Tan, T. W.; Baron, D.; Horton, R. A.

2015-12-01

Storage of CO2 as supercritical liquid in oil reservoirs has been proposed for enhanced oil recovery and a way to lower atmospheric CO2 levels. The fate of CO2 after injection requires an understanding of mineral dissolution/precipitation reactions occurring between the formation minerals and the existing formation brines at formation temperatures and pressures in the presence of supercritical CO2. In this study, core samples from three potential storage formations, the Vedder Fm. (Rio Bravo oil field), Stevens Fm. (Elk Hills oil field) and Temblor Fm. (McKittrick oil field) were reacted with a synthetic brine and CO2(sc) at reservoir temperature (110°C) and pressure (245-250 bar). A combination of petrographic, SEM-EDS and XRD analyses, brine chemistry, and PHREEQ-C modelling were used to identify geochemical reactions altering aquifer mineralogy. XRD and petrographic analyses identified potentially reactive minerals including calcite and dolomite (~2%), pyrite (~1%), and feldspars (~25-60%). Despite the low abundance, calcite dissolution and pyrite oxidation were dominant geochemical reactions. Feldspar weathering produced release rates ~1-2 orders of magnitude slower than calcite dissolution. Calcite dissolution increased the aqueous concentrations of Ca, HCO3, Mg, Mn and Sr. Silicate weathering increased the aqueous concentrations of Si and K. Plagioclase weathering likely increased aqueous Ca concentrations. Pyrite oxidation, despite attempts to remove O2 from the experiment, increased the aqueous concentration of Fe and SO4. SEM-EDS analysis of post-reaction samples identified mixed-layered illite-smectites associated with feldspar grains suggesting clay mineral precipitation in addition to calcite, pyrite and feldspar dissolution. The Vedder Fm. sample underwent complete disaggregation during the reaction due to cement dissolution. This may adversely affect Vedder Formation CCS projects by impacting injection well integrity.

APPLICATION OF CYCLIC CO2 METHODS IN AN OVER-MATURE MISICBLE CO2 PILOT PROJECT-WEST MALLALIEU FIELD, LINCOLN COUNTY, MS

DOE Office of Scientific and Technical Information (OSTI.GOV)

Boyd Stevens Getz

2001-09-01

This progress report summarizes the results of a miscible cyclic CO{sub 2} project conducted at West Mallalieu Field Unit (WMU) Lincoln County, MS by J.P. Oil Company, Inc. Lafayette, LA. Information is presented regarding the verification of the mechanical integrity of the present candidate well, WMU 17-2B, to the exclusion of nearby more desirable wells from a reservoir standpoint. Engineering summaries of both the injection and flow back phases of the cyclic process are presented. The results indicate that the target volume of 63 MMCF of CO{sub 2} was injected into the candidate well during the month of August 2000more » and a combined 73 MMCF of CO{sub 2} and formation gas were recovered during September, October, and November 2000. The fact that all of the injected CO{sub 2} was recovered is encouraging; however, only negligible volumes of liquid were produced with the gas. A number of different factors are explored in this report to explain the lack of economic success. These are divided into several groupings and include: Reservoir Factors, Process Factors, Mechanical Factors, and Special Circumstances Factors. It is impossible to understand precisely the one or combination of interrelated factors responsible for the failure of the experiment but I feel that the original reservoir quality concerns for the subject well WMU 17-2B were not surmountable. Based on the inferences made as to possible failure mechanisms, two future test candidates were selected, WMU 17-10 and 17-14. These lie a significant distance south of the WMU Pilot area and each have a much thicker and higher quality reservoir section than does WMU 17-2B. Both of these wells were productive on pumping units in the not too distant past. This was primary production not influenced by the distant CO{sub 2} injection. These wells are currently completed within somewhat isolated reservoir channels in the Lower Tuscaloosa ''A'' and ''B-2'' Sands that overlie the much more continuous and much larger Lower Tuscaloosa ''C'' Sand reservoir. The current proposal is to not only cycle the Lower Tuscaloosa ''C'' Sand in these wells but to also test the process on these discontinuous ''A'' and ''B-2'' reservoir pools to determine if miscible cyclic processes are applicable where continuous CO{sub 2} operations are not feasible.« less

CO2 Storage related Groundwater Impacts and Protection

NASA Astrophysics Data System (ADS)

Fischer, Sebastian; Knopf, Stefan; May, Franz; Rebscher, Dorothee

2016-03-01

Injection of CO2 into the deep subsurface will affect physical and chemical conditions in the storage environment. Hence, geological CO2 storage can have potential impacts on groundwater resources. Shallow freshwater can only be affected if leakage pathways facilitate the ascent of CO2 or saline formation water. Leakage associated with CO2 storage cannot be excluded, but potential environmental impacts could be reduced by selecting suitable storage locations. In the framework of risk assessment, testing of models and scenarios against operational data has to be performed repeatedly in order to predict the long-term fate of CO2. Monitoring of a storage site should reveal any deviations from expected storage performance, so that corrective measures can be taken. Comprehensive R & D activities and experience from several storage projects will enhance the state of knowledge on geological CO2 storage, thus enabling safe storage operations at well-characterised and carefully selected storage sites while meeting the requirements of groundwater protection.

The U-tube: A novel system for acquiring borehole fluid samples from a deep geologic CO2 sequestration experiment

USGS Publications Warehouse

Freifeild, Barry M.; Trautz, Robert C.; Kharaka, Yousif K.; Phelps, Tommy J.; Myer, Larry R.; Hovorka, Susan D.; Collins, Daniel J.

2005-01-01

A novel system has been deployed to obtain geochemical samples of water and gas, at in situ pressure, during a geologic CO2 sequestration experiment conducted in the Frio brine aquifer in Liberty County, Texas. Project goals required high-frequency recovery of representative and uncontaminated aliquots of a rapidly changing two-phase fluid (supercritical CO2 and brine) fluid from 1.5 km depth. The data sets collected, using both the liquid and gas portions of the downhole samples, provide insights into the coupled hydrogeochemical issues affecting CO2sequestration in brine-filled formations. While the basic premise underlying the U-tube sampler is not new, the system is unique because careful consideration was given to the processing of the recovered two-phase fluids. In particular, strain gauges mounted beneath the high-pressure surface sample cylinders measured the ratio of recovered brine to supercritical CO2. A quadrupole mass spectrometer provided real-time gas analysis for perfluorocarbon and noble gas tracers that were injected along with the CO2. The U-tube successfully acquired frequent samples, facilitating accurate delineation of the arrival of the CO2 plume, and on-site analysis revealed rapid changes in geochemical conditions.

The U-tube: A novel system for acquiring borehole fluid samples from a deep geologic CO2 sequestration experiment

USGS Publications Warehouse

Freifeild, Barry M.; Trautz, Robert C.; Kharaka, Yousif K.; Phelps, Tommy J.; Myer, Larry R.; Hovorka, Susan D.; Collins, Daniel J.

2005-01-01

A novel system has been deployed to obtain geochemical samples of water and gas, at in situ pressure, during a geologic CO2 sequestration experiment conducted in the Frio brine aquifer in Liberty County, Texas. Project goals required high-frequency recovery of representative and uncontaminated aliquots of a rapidly changing two-phase fluid (supercritical CO2 and brine) fluid from 1.5 km depth. The data sets collected, using both the liquid and gas portions of the downhole samples, provide insights into the coupled hydrogeochemical issues affecting CO2 sequestration in brine-filled formations. While the basic premise underlying the U-tube sampler is not new, the system is unique because careful consideration was given to the processing of the recovered two-phase fluids. In particular, strain gauges mounted beneath the high-pressure surface sample cylinders measured the ratio of recovered brine to supercritical CO2. A quadrupole mass spectrometer provided real-time gas analysis for perfluorocarbon and noble gas tracers that were injected along with the CO2. The U-tube successfully acquired frequent samples, facilitating accurate delineation of the arrival of the CO2 plume, and on-site analysis revealed rapid changes in geochemical conditions.

The U-tube: A novel system for acquiring borehole fluid samples from a deep geologic CO2 sequestration experiment

NASA Astrophysics Data System (ADS)

Freifeld, Barry M.; Trautz, Robert C.; Kharaka, Yousif K.; Phelps, Tommy J.; Myer, Larry R.; Hovorka, Susan D.; Collins, Daniel J.

2005-10-01

A novel system has been deployed to obtain geochemical samples of water and gas, at in situ pressure, during a geologic CO2 sequestration experiment conducted in the Frio brine aquifer in Liberty County, Texas. Project goals required high-frequency recovery of representative and uncontaminated aliquots of a rapidly changing two-phase fluid (supercritical CO2 and brine) fluid from 1.5 km depth. The data sets collected, using both the liquid and gas portions of the downhole samples, provide insights into the coupled hydrogeochemical issues affecting CO2 sequestration in brine-filled formations. While the basic premise underlying the U-tube sampler is not new, the system is unique because careful consideration was given to the processing of the recovered two-phase fluids. In particular, strain gauges mounted beneath the high-pressure surface sample cylinders measured the ratio of recovered brine to supercritical CO2. A quadrupole mass spectrometer provided real-time gas analysis for perfluorocarbon and noble gas tracers that were injected along with the CO2. The U-tube successfully acquired frequent samples, facilitating accurate delineation of the arrival of the CO2 plume, and on-site analysis revealed rapid changes in geochemical conditions.

Assessment of basin-scale hydrologic impacts of CO2 sequestration, Illinois basin

USGS Publications Warehouse

Person, M.; Banerjee, A.; Rupp, J.; Medina, C.; Lichtner, P.; Gable, C.; Pawar, R.; Celia, M.; McIntosh, J.; Bense, V.

2010-01-01

Idealized, basin-scale sharp-interface models of CO2 injection were constructed for the Illinois basin. Porosity and permeability were decreased with depth within the Mount Simon Formation. Eau Claire confining unit porosity and permeability were kept fixed. We used 726 injection wells located near 42 power plants to deliver 80 million metric tons of CO2/year. After 100 years of continuous injection, deviatoric fluid pressures varied between 5.6 and 18 MPa across central and southern part of the Illinois basin. Maximum deviatoric pressure reached about 50% of lithostatic levels to the south. The pressure disturbance (>0.03 MPa) propagated 10-25 km away from the injection wells resulting in significant well-well pressure interference. These findings are consistent with single-phase analytical solutions of injection. The radial footprint of the CO2 plume at each well was only 0.5-2 km after 100 years of injection. Net lateral brine displacement was insignificant due to increasing radial distance from injection well and leakage across the Eau Claire confining unit. On geologic time scales CO2 would migrate northward at a rate of about 6 m/1000 years. Because of paleo-seismic events in this region (M5.5-M7.5), care should be taken to avoid high pore pressures in the southern Illinois basin. ?? 2010 Elsevier Ltd.

System-level modeling for geological storage of CO2

DOE Office of Scientific and Technical Information (OSTI.GOV)

Zhang, Yingqi; Oldenburg, Curtis M.; Finsterle, Stefan

2006-04-24

One way to reduce the effects of anthropogenic greenhousegases on climate is to inject carbon dioxide (CO2) from industrialsources into deep geological formations such as brine formations ordepleted oil or gas reservoirs. Research has and is being conducted toimprove understanding of factors affecting particular aspects ofgeological CO2 storage, such as performance, capacity, and health, safetyand environmental (HSE) issues, as well as to lower the cost of CO2capture and related processes. However, there has been less emphasis todate on system-level analyses of geological CO2 storage that considergeological, economic, and environmental issues by linking detailedrepresentations of engineering components and associated economic models.Themore » objective of this study is to develop a system-level model forgeological CO2 storage, including CO2 capture and separation,compression, pipeline transportation to the storage site, and CO2injection. Within our system model we are incorporating detailedreservoir simulations of CO2 injection and potential leakage withassociated HSE effects. The platform of the system-level modelingisGoldSim [GoldSim, 2006]. The application of the system model is focusedon evaluating the feasibility of carbon sequestration with enhanced gasrecovery (CSEGR) in the Rio Vista region of California. The reservoirsimulations are performed using a special module of the TOUGH2 simulator,EOS7C, for multicomponent gas mixtures of methane and CO2 or methane andnitrogen. Using this approach, the economic benefits of enhanced gasrecovery can be directly weighed against the costs, risks, and benefitsof CO2 injection.« less

Evaluation of the Effect of the CO2 Ocean Sequestration on Marine Life in the Sea near Japan Using a Numerical Model

NASA Astrophysics Data System (ADS)

Nakamura, Tomoaki; Wada, Akira; Hasegawa, Kazuyuki; Ochiai, Minoru

CO2 oceanic sequestration is one of the technologies for reducing the discharge of CO2 into the atmosphere, which is considered to cause the global warming, and consists in isolating industry-made CO2 gas within the depths of the ocean. This method is expected to enable industry-made CO2 to be separated from the atmosphere for a considerably long period of time. On the other hand, it is also feared that the CO2 injected in the ocean may lower pH of seawater surrounding the sequestration site, thus may adversely affect marine organisms. For evaluating the biological influences, we have studied to precisely predict the CO2 distribution around the CO2 injection site by a numerical simulation method. In previous studies, in which a 2 degree by 2 degree mesh was employed in the simulation, CO2 concentrations tended to be evenly dispersed within the grid, giving lower concentration values. Thus, the calculation accuracy within the area several hundred kilometers from the CO2 injection site was not satisfactory for the biological effect assessment. In the present study, we improved the accuracy of concentration distribution by changing the computational mesh resolution for a 0.2 by 0.2 degree. By the renewed method we could obtain detailed CO2 distribution in waters within several hundred kilometers of the injection site, and clarified that the Moving-ship procedure may have less effects of lowered pH on marine organisms than the fixed-point release procedure of CO2 sequestration.

Extended probit mortality model for zooplankton against transient change of PCO(2).

PubMed

Sato, Toru; Watanabe, Yuji; Toyota, Koji; Ishizaka, Joji

2005-09-01

The direct injection of CO(2) in the deep ocean is a promising way to mitigate global warming. One of the uncertainties in this method, however, is its impact on marine organisms in the near field. Since the concentration of CO(2), which organisms experience in the ocean, changes with time, it is required to develop a biological impact model for the organisms against the unsteady change of CO(2) concentration. In general, the LC(50) concept is widely applied for testing a toxic agent for the acute mortality. Here, we regard the probit-transformed mortality as a linear function not only of the concentration of CO(2) but also of exposure time. A simple mathematical transform of the function gives a damage-accumulation mortality model for zooplankton. In this article, this model was validated by the mortality test of Metamphiascopsis hirsutus against the transient change of CO(2) concentration.

Simulation of reactive transport of injected CO2 on the Colorado Plateau, Utah, USA

USGS Publications Warehouse

White, S.P.; Allis, R.G.; Moore, J.; Chidsey, T.; Morgan, C.; Gwynn, W.; Adams, M.

2005-01-01

This paper investigates injection of CO2 into non-dome-shaped geological structures that do not provide the traps traditionally deemed necessary for the development of artificial CO2 reservoirs. We have developed a conceptual and two numerical models of the geology and groundwater along a cross-section lying approximately NW-SE and in the vicinity of the Hunter power station on the Colorado Plateau, Central Utah and identified a number of potential sequestration sites on this cross-section. Preliminary modeling identified the White Rim Sandstone as appearing to offer the properties required of a successful sequestration site. Detailed modeling of injection of CO2 into the White Rim Sandstone using the reactive chemical simulator ChemTOUGH found that 1000 years after the 30 year injection period began approximately 21% of the injected CO2 was permanently sequestered as a mineral, 52% was beneath the ground surface as a gas or dissolved in the groundwater and 17% had leaked to the surface and leakage to the surface was continuing. ?? 2005 Elsevier B.V. All rights reserved.

3-D simulation of gases transport under condition of inert gas injection into goaf

NASA Astrophysics Data System (ADS)

Liu, Mao-Xi; Shi, Guo-Qing; Guo, Zhixiong; Wang, Yan-Ming; Ma, Li-Yang

2016-12-01

To prevent coal spontaneous combustion in mines, it is paramount to understand O2 gas distribution under condition of inert gas injection into goaf. In this study, the goaf was modeled as a 3-D porous medium based on stress distribution. The variation of O2 distribution influenced by CO2 or N2 injection was simulated based on the multi-component gases transport and the Navier-Stokes equations using Fluent. The numerical results without inert gas injection were compared with field measurements to validate the simulation model. Simulations with inert gas injection show that CO2 gas mainly accumulates at the goaf floor level; however, a notable portion of N2 gas moves upward. The evolution of the spontaneous combustion risky zone with continuous inert gas injection can be classified into three phases: slow inerting phase, rapid accelerating inerting phase, and stable inerting phase. The asphyxia zone with CO2 injection is about 1.25-2.4 times larger than that with N2 injection. The efficacy of preventing and putting out mine fires is strongly related with the inert gas injecting position. Ideal injections are located in the oxidation zone or the transitional zone between oxidation zone and heat dissipation zone.

Modeling basin- and plume-scale processes of CO2 storage for full-scale deployment

DOE Office of Scientific and Technical Information (OSTI.GOV)

Zhou, Q.; Birkholzer, J.T.; Mehnert, E.

Integrated modeling of basin- and plume-scale processes induced by full-scale deployment of CO{sub 2} storage was applied to the Mt. Simon Aquifer in the Illinois Basin. A three-dimensional mesh was generated with local refinement around 20 injection sites, with approximately 30 km spacing. A total annual injection rate of 100 Mt CO{sub 2} over 50 years was used. The CO{sub 2}-brine flow at the plume scale and the single-phase flow at the basin scale were simulated. Simulation results show the overall shape of a CO{sub 2} plume consisting of a typical gravity-override subplume in the bottom injection zone of highmore » injectivity and a pyramid-shaped subplume in the overlying multilayered Mt. Simon, indicating the important role of a secondary seal with relatively low-permeability and high-entry capillary pressure. The secondary-seal effect is manifested by retarded upward CO{sub 2} migration as a result of multiple secondary seals, coupled with lateral preferential CO{sub 2} viscous fingering through high-permeability layers. The plume width varies from 9.0 to 13.5 km at 200 years, indicating the slow CO{sub 2} migration and no plume interference between storage sites. On the basin scale, pressure perturbations propagate quickly away from injection centers, interfere after less than 1 year, and eventually reach basin margins. The simulated pressure buildup of 35 bar in the injection area is not expected to affect caprock geomechanical integrity. Moderate pressure buildup is observed in Mt. Simon in northern Illinois. However, its impact on groundwater resources is less than the hydraulic drawdown induced by long-term extensive pumping from overlying freshwater aquifers.« less

Geochemical effects of CO2 injection on produced water chemistry at an enhanced oil recovery site in the Permian Basin of northwest Texas, USA: Preliminary geochemical and Li isotope results

NASA Astrophysics Data System (ADS)

Pfister, S.; Gardiner, J.; Phan, T. T.; Macpherson, G. L.; Diehl, J. R.; Lopano, C. L.; Stewart, B. W.; Capo, R. C.

2014-12-01

Injection of supercritical CO2 for enhanced oil recovery (EOR) presents an opportunity to evaluate the effects of CO2 on reservoir properties and formation waters during geologic carbon sequestration. Produced water from oil wells tapping a carbonate-hosted reservoir at an active EOR site in the Permian Basin of Texas both before and after injection were sampled to evaluate geochemical and isotopic changes associated with water-rock-CO2 interaction. Produced waters from the carbonate reservoir rock are Na-Cl brines with TDS levels of 16.5-34 g/L and detectable H2S. These brines are potentially diluted with shallow groundwater from earlier EOR water flooding. Initial lithium isotope data (δ7Li) from pre-injection produced water in the EOR field fall within the range of Gulf of Mexico Coastal sedimentary basin and Appalachian basin values (Macpherson et al., 2014, Geofluids, doi: 10.1111/gfl.12084). Pre-injection produced water 87Sr/86Sr ratios (0.70788-0.70795) are consistent with mid-late Permian seawater/carbonate. CO2 injection took place in October 2013, and four of the wells sampled in May 2014 showed CO2 breakthrough. Preliminary comparison of pre- and post-injection produced waters indicates no significant changes in the major inorganic constituents following breakthrough, other than a possible drop in K concentration. Trace element and isotope data from pre- and post-breakthrough wells are currently being evaluated and will be presented.

X-Ray microtomography analysis of the impact of pCO2 on serpentinization reactions: A reactive percolation experimental approach

NASA Astrophysics Data System (ADS)

Escario, Sofia; Godard, Marguerite; Gouze, Philippe; Smal, Pavel; Rodriguez, Olivier; Leprovost, Richard

2017-04-01

Serpentinization is the main hydrothermal process driving the alteration of the mantle lithosphere by seawater at ridges. It consists in the alteration of olivine to serpentine and is associated to processes such as oxidation as well as carbonation when CO2 is present. The sustainability and efficiency of the reaction requires penetration and renewal of fluids at the mineral-fluid interface. Yet the secondary low density minerals can fill the porous network, clogging flow paths efficiently. This study aims at better understanding the coupled hydrodynamic and chemical processes driving the earliest stages of alteration of the ultramafic basement, when seawater-derived hydrothermal fluids penetrate and interact with exposed mantle rocks at slow spreading ridges. We investigate the structural changes of the rock in relation to dissolution-precipitation reactions triggered by the injection CO2-rich seawater using an experimental approach. The experiments simulate open conditions and were performed using the reactive percolation bench ICARE Lab 3 - Géosciences Montpellier. ICARE 3 allows to continuously measuring permeability changes during experiments and sampling the outlet fluids passing through the sample. We analysed the reacted samples before and after the experiments using a combination of geochemical (TGA-MS) and high resolution X-Ray microtomography (ESRF ID19 synchrotron beamline, Grenoble) approaches. A series of experiments was carried out at 190°C and 25 MPa. CO2 enriched natural seawater (XCO2 5.24 mmol/kg) was injected into Titanium capsules (2 mm diameter, 6 mm length) filled by pressed powdered San Carlos olivine (Fo90; grains 150-200 µm). The outlet section of the samples were analysed at 0.65 µm resolution using microtomography before and after the experiments. The reacted powdered sample was analysed by TGA-MS. Comparison of microtomography images of reacted and unreacted samples shows evidences of olivine dissolution and secondary minerals precipitation during the 14 days long experiments. A new method based on image registration enables to identify the dissolution mainly localized at grain borders and the precipitation localizes in fractures and at grain borders. Dissolution appears to be dominant in the outlet section of the sample. The equilibrium of the reaction will be determined by the comparison of thermogravimetry (TGA-MS) analysis of the reacted sample after the experiment and thermodynamic modelling of the experiment in equilibrium.

Downhole fluid injection systems, CO₂ sequestration methods, and hydrocarbon material recovery methods

DOEpatents

Schaef, Herbert T.; McGrail, B. Peter

2015-07-28

Downhole fluid injection systems are provided that can include a first well extending into a geological formation, and a fluid injector assembly located within the well. The fluid injector assembly can be configured to inject a liquid CO₂/H₂O-emulsion into the surrounding geological formation. CO₂ sequestration methods are provided that can include exposing a geological formation to a liquid CO₂/H₂O-emulsion to sequester at least a portion of the CO₂ from the emulsion within the formation. Hydrocarbon material recovery methods are provided that can include exposing a liquid CO₂/H₂O-emulsion to a geological formation having the hydrocarbon material therein. The methods can include recovering at least a portion of the hydrocarbon material from the formation.

Optimization of CO2 Storage in Saline Aquifers Using Water-Alternating Gas (WAG) Scheme - Case Study for Utsira Formation

NASA Astrophysics Data System (ADS)

Agarwal, R. K.; Zhang, Z.; Zhu, C.

2013-12-01

For optimization of CO2 storage and reduced CO2 plume migration in saline aquifers, a genetic algorithm (GA) based optimizer has been developed which is combined with the DOE multi-phase flow and heat transfer numerical simulation code TOUGH2. Designated as GA-TOUGH2, this combined solver/optimizer has been verified by performing optimization studies on a number of model problems and comparing the results with brute-force optimization which requires a large number of simulations. Using GA-TOUGH2, an innovative reservoir engineering technique known as water-alternating-gas (WAG) injection has been investigated to determine the optimal WAG operation for enhanced CO2 storage capacity. The topmost layer (layer # 9) of Utsira formation at Sleipner Project, Norway is considered as a case study. A cylindrical domain, which possesses identical characteristics of the detailed 3D Utsira Layer #9 model except for the absence of 3D topography, was used. Topographical details are known to be important in determining the CO2 migration at Sleipner, and are considered in our companion model for history match of the CO2 plume migration at Sleipner. However, simplification on topography here, without compromising accuracy, is necessary to analyze the effectiveness of WAG operation on CO2 migration without incurring excessive computational cost. Selected WAG operation then can be simulated with full topography details later. We consider a cylindrical domain with thickness of 35 m with horizontal flat caprock. All hydrogeological properties are retained from the detailed 3D Utsira Layer #9 model, the most important being the horizontal-to-vertical permeability ratio of 10. Constant Gas Injection (CGI) operation with nine-year average CO2 injection rate of 2.7 kg/s is considered as the baseline case for comparison. The 30-day, 15-day, and 5-day WAG cycle durations are considered for the WAG optimization design. Our computations show that for the simplified Utsira Layer #9 model, the WAG operation with 5-day cycle leads to most noticeable reduction in plume migration. For 5-day WAG cycle, the values of design variables corresponding to optimal WAG operation are found as optimal CO2 injection ICO2,optimal = 11.56 kg/s, and optimal water injection Iwater,optimal = 7.62 kg/s. The durations of CO2 and water injection in one WAG cycle are 11 and 19 days, respectively. Identical WAG cycles are repeated 20 times to complete a two-year operation. Significant reduction (22%) in CO2 migration is achieved compared to CGI operation after only two years of WAG operation. In addition, CO2 dissolution is also significantly enhanced from about 9% to 22% of the total injected CO2 . The results obtained from this and other optimization studies suggest that over 50% reduction of in situ CO2 footprint, greatly enhanced CO2 dissolution, and significantly improved well injectivity can be achieved by employing GA-TOUGH2. The optimization code has also been employed to determine the optimal well placement in a multi-well injection operation. GA-TOUGH2 appears to hold great promise for studying a host of other optimization problems related to Carbon Storage.

Pressure Monitoring to Detect Fault Rupture Due to CO 2 Injection

DOE Office of Scientific and Technical Information (OSTI.GOV)

Keating, Elizabeth; Dempsey, David; Pawar, Rajesh

The capacity for fault systems to be reactivated by fluid injection is well-known. In the context of CO 2 sequestration, however, the consequence of reactivated faults with respect to leakage and monitoring is poorly understood. Using multi-phase fluid flow simulations, this study addresses key questions concerning the likelihood of ruptures, the timing of consequent upward leakage of CO 2, and the effectiveness of pressure monitoring in the reservoir and overlying zones for rupture detection. A range of injection scenarios was simulated using random sampling of uncertain parameters. These include the assumed distance between the injector and the vulnerable fault zone,more » the critical overpressure required for the fault to rupture, reservoir permeability, and the CO 2 injection rate. We assumed a conservative scenario, in which if at any time during the five-year simulations the critical fault overpressure is exceeded, the fault permeability is assumed to instantaneously increase. For the purposes of conservatism we assume that CO 2 injection continues ‘blindly’ after fault rupture. We show that, despite this assumption, in most cases the CO 2 plume does not reach the base of the ruptured fault after 5 years. As a result, one possible implication of this result is that leak mitigation strategies such as pressure management have a reasonable chance of preventing a CO 2 leak.« less

Pressure Monitoring to Detect Fault Rupture Due to CO 2 Injection

DOE PAGES

Keating, Elizabeth; Dempsey, David; Pawar, Rajesh

2017-08-18

The capacity for fault systems to be reactivated by fluid injection is well-known. In the context of CO 2 sequestration, however, the consequence of reactivated faults with respect to leakage and monitoring is poorly understood. Using multi-phase fluid flow simulations, this study addresses key questions concerning the likelihood of ruptures, the timing of consequent upward leakage of CO 2, and the effectiveness of pressure monitoring in the reservoir and overlying zones for rupture detection. A range of injection scenarios was simulated using random sampling of uncertain parameters. These include the assumed distance between the injector and the vulnerable fault zone,more » the critical overpressure required for the fault to rupture, reservoir permeability, and the CO 2 injection rate. We assumed a conservative scenario, in which if at any time during the five-year simulations the critical fault overpressure is exceeded, the fault permeability is assumed to instantaneously increase. For the purposes of conservatism we assume that CO 2 injection continues ‘blindly’ after fault rupture. We show that, despite this assumption, in most cases the CO 2 plume does not reach the base of the ruptured fault after 5 years. As a result, one possible implication of this result is that leak mitigation strategies such as pressure management have a reasonable chance of preventing a CO 2 leak.« less

Model complexity in carbon sequestration:A design of experiment and response surface uncertainty analysis

NASA Astrophysics Data System (ADS)

Zhang, Y.; Li, S.

2014-12-01

Geologic carbon sequestration (GCS) is proposed for the Nugget Sandstone in Moxa Arch, a regional saline aquifer with a large storage potential. For a proposed storage site, this study builds a suite of increasingly complex conceptual "geologic" model families, using subsets of the site characterization data: a homogeneous model family, a stationary petrophysical model family, a stationary facies model family with sub-facies petrophysical variability, and a non-stationary facies model family (with sub-facies variability) conditioned to soft data. These families, representing alternative conceptual site models built with increasing data, were simulated with the same CO2 injection test (50 years at 1/10 Mt per year), followed by 2950 years of monitoring. Using the Design of Experiment, an efficient sensitivity analysis (SA) is conducted for all families, systematically varying uncertain input parameters. Results are compared among the families to identify parameters that have 1st order impact on predicting the CO2 storage ratio (SR) at both end of injection and end of monitoring. At this site, geologic modeling factors do not significantly influence the short-term prediction of the storage ratio, although they become important over monitoring time, but only for those families where such factors are accounted for. Based on the SA, a response surface analysis is conducted to generate prediction envelopes of the storage ratio, which are compared among the families at both times. Results suggest a large uncertainty in the predicted storage ratio given the uncertainties in model parameters and modeling choices: SR varies from 5-60% (end of injection) to 18-100% (end of monitoring), although its variation among the model families is relatively minor. Moreover, long-term leakage risk is considered small at the proposed site. In the lowest-SR scenarios, all families predict gravity-stable supercritical CO2 migrating toward the bottom of the aquifer. In the highest-SR scenarios, supercritical CO2 footprints are relatively insignificant by the end of monitoring.

Determining CO2 storage potential during miscible CO2 enhanced oil recovery: Noble gas and stable isotope tracers

USGS Publications Warehouse

Shelton, Jenna L.; McIntosh, Jennifer C.; Hunt, Andrew; Beebe, Thomas L; Parker, Andrew D; Warwick, Peter D.; Drake, Ronald; McCray, John E.

2016-01-01

Rising atmospheric carbon dioxide (CO2) concentrations are fueling anthropogenic climate change. Geologic sequestration of anthropogenic CO2 in depleted oil reservoirs is one option for reducing CO2 emissions to the atmosphere while enhancing oil recovery. In order to evaluate the feasibility of using enhanced oil recovery (EOR) sites in the United States for permanent CO2 storage, an active multi-stage miscible CO2flooding project in the Permian Basin (North Ward Estes Field, near Wickett, Texas) was investigated. In addition, two major natural CO2 reservoirs in the southeastern Paradox Basin (McElmo Dome and Doe Canyon) were also investigated as they provide CO2 for EOR operations in the Permian Basin. Produced gas and water were collected from three different CO2 flooding phases (with different start dates) within the North Ward Estes Field to evaluate possible CO2 storage mechanisms and amounts of total CO2retention. McElmo Dome and Doe Canyon were sampled for produced gas to determine the noble gas and stable isotope signature of the original injected EOR gas and to confirm the source of this naturally-occurring CO2. As expected, the natural CO2produced from McElmo Dome and Doe Canyon is a mix of mantle and crustal sources. When comparing CO2 injection and production rates for the CO2 floods in the North Ward Estes Field, it appears that CO2 retention in the reservoir decreased over the course of the three injections, retaining 39%, 49% and 61% of the injected CO2 for the 2008, 2010, and 2013 projects, respectively, characteristic of maturing CO2 miscible flood projects. Noble gas isotopic composition of the injected and produced gas for the flood projects suggest no active fractionation, while δ13CCO2 values suggest no active CO2dissolution into formation water, or mineralization. CO2 volumes capable of dissolving in residual formation fluids were also estimated along with the potential to store pure-phase supercritical CO2. Using a combination of dissolution trapping and residual trapping, both volumes of CO2 currently retained in the 2008 and 2013 projects could be justified, suggesting no major leakage is occurring. These subsurface reservoirs, jointly considered, have the capacity to store up to 9 years of CO2 emissions from an average US powerplant.

Coupled reservoir-geomechanical analysis of CO2 injection and ground deformations at In Salah, Algeria

DOE Office of Scientific and Technical Information (OSTI.GOV)

Rutqvist, J.; Vasco, D.W.; Myer, L.

2009-11-01

In Salah Gas Project in Algeria has been injecting 0.5-1 million tonnes CO{sub 2} per year over the past five years into a water-filled strata at a depth of about 1,800 to 1,900 m. Unlike most CO{sub 2} storage sites, the permeability of the storage formation is relatively low and comparatively thin with a thickness of about 20 m. To ensure adequate CO{sub 2} flow-rates across the low-permeability sand-face, the In Salah Gas Project decided to use long-reach (about 1 to 1.5 km) horizontal injection wells. In an ongoing research project we use field data and coupled reservoir-geomechanical numerical modelingmore » to assess the effectiveness of this approach and to investigate monitoring techniques to evaluate the performance of a CO{sub 2}-injection operation in relatively low permeability formations. Among the field data used are ground surface deformations evaluated from recently acquired satellite-based inferrometry (InSAR). The InSAR data shows a surface uplift on the order of 5 mm per year above active CO{sub 2} injection wells and the uplift pattern extends several km from the injection wells. In this paper we use the observed surface uplift to constrain our coupled reservoir-geomechanical model and conduct sensitivity studies to investigate potential causes and mechanisms of the observed uplift. The results of our analysis indicates that most of the observed uplift magnitude can be explained by pressure-induced, poro-elastic expansion of the 20 m thick injection zone, but there could also be a significant contribution from pressure-induced deformations within a 100 m thick zone of shaly sands immediately above the injection zone.« less

Modeling and Evaluation of Geophysical Methods for Monitoring and Tracking CO2 Migration

DOE Office of Scientific and Technical Information (OSTI.GOV)

Daniels, Jeff

2012-11-30

Geological sequestration has been proposed as a viable option for mitigating the vast amount of CO{sub 2} being released into the atmosphere daily. Test sites for CO{sub 2} injection have been appearing across the world to ascertain the feasibility of capturing and sequestering carbon dioxide. A major concern with full scale implementation is monitoring and verifying the permanence of injected CO{sub 2}. Geophysical methods, an exploration industry standard, are non-invasive imaging techniques that can be implemented to address that concern. Geophysical methods, seismic and electromagnetic, play a crucial role in monitoring the subsurface pre- and post-injection. Seismic techniques have beenmore » the most popular but electromagnetic methods are gaining interest. The primary goal of this project was to develop a new geophysical tool, a software program called GphyzCO2, to investigate the implementation of geophysical monitoring for detecting injected CO{sub 2} at test sites. The GphyzCO2 software consists of interconnected programs that encompass well logging, seismic, and electromagnetic methods. The software enables users to design and execute 3D surface-to-surface (conventional surface seismic) and borehole-to-borehole (cross-hole seismic and electromagnetic methods) numerical modeling surveys. The generalized flow of the program begins with building a complex 3D subsurface geological model, assigning properties to the models that mimic a potential CO{sub 2} injection site, numerically forward model a geophysical survey, and analyze the results. A test site located in Warren County, Ohio was selected as the test site for the full implementation of GphyzCO2. Specific interest was placed on a potential reservoir target, the Mount Simon Sandstone, and cap rock, the Eau Claire Formation. Analysis of the test site included well log data, physical property measurements (porosity), core sample resistivity measurements, calculating electrical permittivity values, seismic data collection, and seismic interpretation. The data was input into GphyzCO2 to demonstrate a full implementation of the software capabilities. Part of the implementation investigated the limits of using geophysical methods to monitor CO{sub 2} injection sites. The results show that cross-hole EM numerical surveys are limited to under 100 meter borehole separation. Those results were utilized in executing numerical EM surveys that contain hypothetical CO{sub 2} injections. The outcome of the forward modeling shows that EM methods can detect the presence of CO{sub 2}.« less

Characterizing near-surface CO2 conditions before injection - Perspectives from a CCS project in the Illinois Basin, USA

USGS Publications Warehouse

Locke, R.A.; Krapac, I.G.; Lewicki, J.L.; Curtis-Robinson, E.

2011-01-01

The Midwest Geological Sequestration Consortium is conducting a large-scale carbon capture and storage (CCS) project in Decatur, Illinois, USA to demonstrate the ability of a deep saline formation to store one million tonnes of carbon dioxide (CO2) from an ethanol facility. Beginning in early 2011, CO2 will be injected at a rate of 1,000 tonnes/day for three years into the Mount Simon Sandstone at a depth of approximately 2,100 meters. An extensive Monitoring, Verification, and Accounting (MVA) program has been undertaken for the Illinois Basin Decatur Project (IBDP) and is focused on the 0.65 km2 project site. Goals include establishing baseline conditions to evaluate potential impacts from CO2 injection, demonstrating that project activities are protective of human health and the environment, and providing an accurate accounting of stored CO2. MVA efforts are being conducted pre-, during, and post- CO2 injection. Soil and net CO2 flux monitoring has been conducted for more than one year to characterize near-surface CO2 conditions. More than 2,200 soil CO2 flux measurements have been manually collected from a network of 118 soil rings since June 2009. Three ring types have been evaluated to determine which type may be the most effective in detecting potential CO 2 leakage. Bare soil, shallow-depth rings were driven 8 cm into the ground and were prepared to minimize surface vegetation in and near the rings. Bare soil, deep-depth rings were prepared similarly, but were driven 46 cm. Natural-vegetation, shallow-depth rings were driven 8 cm and are most representative of typical vegetation conditions. Bare-soil, shallow-depth rings had the smallest observed mean flux (1.78 ??mol m-2 s-1) versus natural-vegetation, shallow-depth rings (3.38 ??mol m-2 s-1). Current data suggest bare ring types would be more sensitive to small CO2 leak signatures than natural ring types because of higher signal to noise ratios. An eddy covariance (EC) system has been in use since June 2009. Baseline data from EC monitoring is being used to characterize pre-injection conditions, and may then be used to detect changes in net exchange CO2 fluxes (Fc) that could be the result of CO2 leakage into the near-surface environment during or following injection. When injection at IBDP begins, soil and net CO2 monitoring efforts will have established a baseline of near-surface conditions that will be important to help demonstrate the effectiveness of storage activities. ?? 2011 Published by Elsevier Ltd.

The impacts of effective stress and CO 2 sorption on the matrix permeability of shale reservoir rocks [The impacts of CO 2 sorption and effective stress on the matrix permeability of shale reservoir rocks

DOE PAGES

Wu, Wei; Zoback, Mark D.; Kohli, Arjun H.

2017-05-02

We assess the impacts of effective stress and CO 2 sorption on the bedding-parallel matrix permeability of the Utica shale through pressure pulse-decay experiments. We first measure permeability using argon at relatively high (14.6 MPa) and low (2.8 MPa) effective stresses to assess both pressure dependence and recoverability. We subsequently measure permeability using supercritical CO 2 and again using argon to assess changes due to CO 2 sorption. We find that injection of both argon and supercritical CO 2 reduces matrix permeability in distinct fashion. Samples with permeability higher than 10 –20 m 2 experience a large permeability reduction aftermore » treatment with argon, but a minor change after treatment with supercritical CO 2. However, samples with permeability lower than this threshold undergo a slight change after treatment with argon, but a dramatic reduction after treatment with supercritical CO 2. These results indicate that effective stress plays an important role in the evolution of relatively permeable facies, while CO 2 sorption dominates the change of ultra-low permeability facies. The permeability reduction due to CO 2 sorption varies inversely with initial permeability, which suggests that increased surface area from hydraulic stimulation with CO 2 may be counteracted by sorption effects in ultra-low permeability facies. As a result, we develop a conceptual model to explain how CO 2 sorption induces porosity reduction and volumetric expansion to constrict fluid flow pathways in shale reservoir rocks.« less

The impacts of effective stress and CO 2 sorption on the matrix permeability of shale reservoir rocks [The impacts of CO 2 sorption and effective stress on the matrix permeability of shale reservoir rocks

DOE Office of Scientific and Technical Information (OSTI.GOV)

Wu, Wei; Zoback, Mark D.; Kohli, Arjun H.

We assess the impacts of effective stress and CO 2 sorption on the bedding-parallel matrix permeability of the Utica shale through pressure pulse-decay experiments. We first measure permeability using argon at relatively high (14.6 MPa) and low (2.8 MPa) effective stresses to assess both pressure dependence and recoverability. We subsequently measure permeability using supercritical CO 2 and again using argon to assess changes due to CO 2 sorption. We find that injection of both argon and supercritical CO 2 reduces matrix permeability in distinct fashion. Samples with permeability higher than 10 –20 m 2 experience a large permeability reduction aftermore » treatment with argon, but a minor change after treatment with supercritical CO 2. However, samples with permeability lower than this threshold undergo a slight change after treatment with argon, but a dramatic reduction after treatment with supercritical CO 2. These results indicate that effective stress plays an important role in the evolution of relatively permeable facies, while CO 2 sorption dominates the change of ultra-low permeability facies. The permeability reduction due to CO 2 sorption varies inversely with initial permeability, which suggests that increased surface area from hydraulic stimulation with CO 2 may be counteracted by sorption effects in ultra-low permeability facies. As a result, we develop a conceptual model to explain how CO 2 sorption induces porosity reduction and volumetric expansion to constrict fluid flow pathways in shale reservoir rocks.« less

A SEA FLOOR GRAVITY SURVEY OF THE SLEIPNER FIELD TO MONITOR CO2 MIGATION

DOE Office of Scientific and Technical Information (OSTI.GOV)

Mark Zumberge

2003-06-13

At the Sleipner gas field, excess CO{sub 2} is sequestered and injected underground into a porous saline aquifer 1000 m below the seafloor. A high precision micro-gravity survey was carried out on the seafloor to monitor the injected CO{sub 2}. A repeatability of 5 {micro}Gal in the station averages was observed. This is considerably better than pre-survey expectations. These data will serve as the baseline for time-lapse gravity monitoring of the Sleipner CO{sub 2} injection site. Simple modeling of the first year data give inconclusive results, thus a more detailed approach is needed. Work towards this is underway.

Effect of Jet Injection Angle and Number of Jets on Mixing and Emissions From a Reacting Crossflow at Atmospheric Pressure

NASA Technical Reports Server (NTRS)

St.John, D.; Samuelsen, G. S.

2000-01-01

The mixing of air jets into hot, fuel-rich products of a gas turbine primary zone is an important step in staged combustion. Often referred to as "quick quench," the mixing occurs with chemical conversion and substantial heat release. An experiment has been designed to simulate and study this process, and the effect of varying the entry angle (0 deg, 22.5 deg and 45 deg from normal) and number of the air jets (7, 9, and 11) into the main flow, while holding the jet-to-crossflow mass-low ratio, MR, and momentum-flux ratio, J, constant (MR = 2.5;J = 25). The geometry is a crossflow confined in a cylindrical duct with side-wall injection of jets issuing from orifices equally spaced around the perimeter. A specially designed reactor, operating on propane, presents a uniform mixture to a module containing air jet injection tubes that can be changed to vary orifice geometry. Species concentrations of O2, CO, CO2, NO(x) and HC were obtained one duct diameter upstream (in the rich zone), and primarily one duct radius downstream. From this information, penetration of the jet, the spatial extent of chemical reaction, mixing, and the optimum jet injection angle and number of jets can be deduced.

Modeling of time-lapse multi-scale seismic monitoring of CO2 injected into a fault zone to enhance the characterization of permeability in enhanced geothermal systems

NASA Astrophysics Data System (ADS)

Zhang, R.; Borgia, A.; Daley, T. M.; Oldenburg, C. M.; Jung, Y.; Lee, K. J.; Doughty, C.; Altundas, B.; Chugunov, N.; Ramakrishnan, T. S.

2017-12-01

Subsurface permeable faults and fracture networks play a critical role for enhanced geothermal systems (EGS) by providing conduits for fluid flow. Characterization of the permeable flow paths before and after stimulation is necessary to evaluate and optimize energy extraction. To provide insight into the feasibility of using CO2 as a contrast agent to enhance fault characterization by seismic methods, we model seismic monitoring of supercritical CO2 (scCO2) injected into a fault. During the CO2 injection, the original brine is replaced by scCO2, which leads to variations in geophysical properties of the formation. To explore the technical feasibility of the approach, we present modeling results for different time-lapse seismic methods including surface seismic, vertical seismic profiling (VSP), and a cross-well survey. We simulate the injection and production of CO2 into a normal fault in a system based on the Brady's geothermal field and model pressure and saturation variations in the fault zone using TOUGH2-ECO2N. The simulation results provide changing fluid properties during the injection, such as saturation and salinity changes, which allow us to estimate corresponding changes in seismic properties of the fault and the formation. We model the response of the system to active seismic monitoring in time-lapse mode using an anisotropic finite difference method with modifications for fracture compliance. Results to date show that even narrow fault and fracture zones filled with CO2 can be better detected using the VSP and cross-well survey geometry, while it would be difficult to image the CO2 plume by using surface seismic methods.

Assessment of mechanical rock alteration caused by CO 2 -water mixtures using indentation and scratch experiments

DOE Office of Scientific and Technical Information (OSTI.GOV)

Sun, Yuhao; Aman, Michael; Espinoza, D. Nicolas

CO2 injection into geological formations disturbs the geochemical equilibrium between water and minerals. Thus, some mineral phases are prone to dissolution and precipitation with ensuing changes of petrophysical and geomechanical properties of the host formations. Chemically-assisted degradation of mechanical properties can endanger the structural integrity of the storage formation and must be carefully studied and considered to guarantee safe long-term trapping. Few experimental data sets involving CO2 alteration and mechanical testing of rock samples are available since these experiments are length, expensive, and require specialized equipment and personnel. Autoclave experiments are easier to perform and control but result in amore » limited 'skin depth' of chemically-altered zone near the surface of the sample. This article presents the validation of micro-indentation and micro-scratch tests as efficient tools to assess the alteration of mechanical properties of rocks geochemically altered by CO2-water mixtures. Results from tests on sandstone and siltstone from Crystal Geyser, Utah naturally altered by CO2-acidified water show that mechanical parameters measured with indentation (indentation hardness, Young's modulus and contact creep compliance rate) and scratching (scratch hardness and fracture toughness) consistently indicated weakening of the rock after CO2-induced alteration. Decreases of measured parameters vary from 14% to 87%. Experimental results and analyses show that micromechanical tests are potentially quick and reliable tools to determine the change of mechanical properties of rocks subject to exposure to CO2-acidified water, particularly in well-controlled autoclave experiments. Measured parameters are not intended to provide inputs for coupled reservoir simulation with geomechanics but rather to inform the execution of larger scale tests investigating the susceptibility of rock facies to chemical alteration by CO2-water mixtures. Recognizing this susceptibility of rock facies of CO2 geological storage target formations is critical to controlling undesired emergent behavior associated with CO2 sequestration.« less

CO2 storage capacity estimates from fluid dynamics (Invited)

NASA Astrophysics Data System (ADS)

Juanes, R.; MacMinn, C. W.; Szulczewski, M.

2009-12-01

We study a sharp-interface mathematical model for the post-injection migration of a plume of CO2 in a deep saline aquifer under the influence of natural groundwater flow, aquifer slope, gravity override, and capillary trapping. The model leads to a nonlinear advection-diffusion equation, where the diffusive term describes the upward spreading of the CO2 against the caprock. We find that the advective terms dominate the flow dynamics even for moderate gravity override. We solve the model analytically in the hyperbolic limit, accounting rigorously for the injection period—using the true end-of-injection plume shape as an initial condition. We extend the model by incorporating the effect of CO2 dissolution into the brine, which—we find—is dominated by convective mixing. This mechanism enters the model as a nonlinear sink term. From a linear stability analysis, we propose a simple estimate of the convective dissolution flux. We then obtain semi-analytic estimates of the maximum plume migration distance and migration time for complete trapping. Our analytical model can be used to estimate the storage capacity (from capillary and dissolution trapping) at the geologic basin scale, and we apply the model to various target formations in the United States. Schematic of the migration of a CO2 plume at the geologic basin scale. During injection, the CO2 forms a plume that is subject to gravity override. At the end of the injection, all the CO2 is mobile. During the post-injection period, the CO2 migrates updip and also driven by regional groundwater flow. At the back end of the plume, where water displaces CO2, the plume leaves a wake or residual CO2 due to capillary trapping. At the bottom of the moving plume, CO2 dissolves into the brine—a process dominated by convective mixing. These two mechanisms—capillary trapping and convective dissolution—reduce the size of the mobile plume as it migrates. In this communication, we present an analytical model that predicts the migration distance and time for complete trapping. This is used to estimate storage capacity of geologic formations at the basin scale.

Carbon dioxide sequestration monitoring and verification via laser based detection system in the 2 mum band

NASA Astrophysics Data System (ADS)

Humphries, Seth David

Carbon Dioxide (CO2) is a known contributor to the green house gas effect. Emissions of CO2 are rising as the global demand for inexpensive energy is placated through the consumption and combustion of fossil fuels. Carbon capture and sequestration (CCS) may provide a method to prevent CO2 from being exhausted to the atmosphere. The carbon may be captured after fossil fuel combustion in a power plant and then stored in a long term facility such as a deep geologic feature. The ability to verify the integrity of carbon storage at a location is key to the success of all CCS projects. A laser-based instrument has been built and tested at Montana State University (MSU) to measure CO2 concentrations above a carbon storage location. The CO2 Detection by Differential Absorption (CODDA) Instrument uses a temperature-tunable distributed feedback (DFB) laser diode that is capable of accessing a spectral region, 2.0027 to 2.0042 mum, that contains three CO2 absorption lines and a water vapor absorption line. This instrument laser is aimed over an open-air, two-way path of about 100 m, allowing measurements of CO2 concentrations to be made directly above a carbon dioxide release test site. The performance of the instrument for carbon sequestration site monitoring is studied using a newly developed CO2 controlled release facility. The field and CO2 releases are managed by the Zero Emissions Research Technology (ZERT) group at MSU. Two test injections were carried out through vertical wells simulating seepage up well paths. Three test injections were done as CO2 escaped up through a slotted horizontal pipe simulating seepage up through geologic fault zones. The results from these 5 separate controlled release experiments over the course of three summers show that the CODDA Instrument is clearly capable of verifying the integrity of full-scale CO2 storage operations.

Laboratory estimates of trace gas emissions following surface application and injection of cattle slurry

DOE Office of Scientific and Technical Information (OSTI.GOV)

Flessa, H.; Beese, F.

2000-02-01

Applying cattle slurry to soil may induce emissions of the greenhouse gases N{sub 2}O and CH{sub 4}. Their objective was to determine the effects of different application techniques (surface application and slit injection) of cattle (Bostaurus) slurry on the decomposition of slurry organic matter and the emissions of N{sub 2}O and CH{sub 4}. The effects of slurry application (43.6 m{sup 3} ha{sup {minus}1}) were studied for 9 wk under controlled laboratory conditions using a soil microcosm system with automated monitoring of the CO{sub 2}, N{sub 2}O, and CH{sub 4} fluxes. The soil used was a silty loam (Ap horizon ofmore » a cambisol) with a constant water-filled pore space of 67% during the experiment. About 38% of the organic matter applied with the slurry was decomposed within 9 wk. Production of CO{sub 2} was not affected by the application technique. Emissions of N{sub 2}O and CH{sub 4} from the injected slurry were significantly higher than from the surface-applied slurry, probably because of restricted aeration at the injected-slurry treatment. Total N{sub 2}O-N emissions were 0.2% (surface application) and 3.3% (slit injection) of the slurry N added. Methane emission occurred only during the first few days following application. The total net flux of CH{sub 4}-C for 2 wk was {minus}12 g ha{sup {minus}1} for the control (CH{sub 4} uptake), 2 g ha{sup {minus}1} for the surface-applied slurry, and 39 g ha{sup {minus}1} for the injected slurry. Slurry injection, which is recommended to reduce NH{sub 3} volatilization, appears to increase emissions of the greenhouse gases N{sub 2}O and CH{sub 4} from the fertilized fields.« less

Investigation of Reactions between Glauconite and Carbon Dioxide, with Implications for Carbon Sequestration

NASA Astrophysics Data System (ADS)

Nguyen, A. V.; Gabitov, R. I.; Beckingham, L. E.; Toghiani, H.; Fei, Y.; Kirkland, B. L.

2017-12-01

Mineral trapping is one potentially effective technology for long-term storage of carbon dioxide in a subsurface environment that has high temperature and pressure. Conceptually, upon injection of CO2 as a supercritical fluid into geological formations, the CO2 will react with the host rock to form a secondary carbonate mineral that is stable, thus creating a long-term carbon sink under thermodynamic condition of the reaction. Previous studies have demonstrated crystallization of magnesite by reactivity of CO2 and olivine-bearing basalt. Glauconite, a Fe/Ca/Mg bearing aluminosilicate mineral, a potential candidate for reaction with CO2 is common in sedimentary rock formations. The objectives of this study are to 1) develop a protocol for testing mineral trapping in the subsurface and 2) use that protocol to test the reactivity and effectiveness of the mineral glauconite in carbon sequestration. A sample from the Cambrian Riley Formation of Central Texas was selected for this study because it is extremely rich in glauconite. Mineral composition of the powdered sample was investigated by X-ray diffraction (XRD), which revealed that the glauconitic sandstone contains glauconite 20.4%, quartz 71%, and celadonite 8.6%. In the first experiment, 1.5 g of 0.01- 0.5 cm diameter grains reacted with a supercritical CO2 fluid in 30 g of sea water. The laboratory experiment was conducted in a stainless steel vessel in situ reservoir conditions at 120 degrees Celsius and 100 bars. After CO2 injection, pH of the brine decreased from 8.23 to 7. Scanning electron microscopy (SEM) and X-ray diffraction method showed no carbonate formed after 10 days of reaction. However, further experimental modifications facilitated formation of calcite at higher pH. In the second experiment, 0.7 g of 10-75 μm grains presumably reacted with CO2 formed by ammonium carbonate decomposition in a brine of NaCl 0.5 and CaCl2 0.25M; pH after the end of experiment was 7.74. The autoclave was set at 120 degrees Celsius and pressure of saturated water vapour for 14 days. XRD and EDS confirmed the presence of calcite in the sample after the treatment. This material is based upon work supported by the Department of Energy National Energy Technology Laboratory under the Southern States Energy Board's Cooperative Agreement Award Number DE-FE0029465.

Analysis of Geologic Parameters on the Performance of CO2-Plume Geothermal (CPG) Systems in a Multi-Layered Reservoirs

NASA Astrophysics Data System (ADS)

Garapati, N.; Randolph, J.; Saar, M. O.

2013-12-01

CO2-Plume Geothermal (CPG) involves injection of CO2 as a working fluid to extract heat from naturally high permeable sedimentary basins. The injected CO2 forms a large subsurface CO2 plume that absorbs heat from the geothermal reservoir and eventually buoyantly rises to the surface. The heat density of sedimentary basins is typically relatively low.However, this drawback is likely counteracted by the large accessible volume of natural reservoirs compared to artificial, hydrofractured, and thus small-scale, reservoirs. Furthermore, supercritical CO2has a large mobility (inverse kinematic viscosity) and expansibility compared to water resulting in the formation of a strong thermosiphon which eliminates the need for parasitic pumping power requirements and significantly increasing electricity production efficiency. Simultaneously, the life span of the geothermal power plant can be increased by operating the CPG system such that it depletes the geothermal reservoir heat slowly. Because the produced CO2 is reinjected into the ground with the main CO2 sequestration stream coming from a CO2 emitter, all of the CO2 is ultimately geologically sequestered resulting in a CO2 sequestering geothermal power plant with a negative carbon footprint. Conventional geothermal process requires pumping of huge amount of water for the propagation of the fractures in the reservoir, but CPG process eliminates this requirement and conserves water resources. Here, we present results for performance of a CPG system as a function of various geologic properties of multilayered systemsincludingpermeability anisotropy, rock thermal conductivity, geothermal gradient, reservoir depth and initial native brine salinity as well as spacing between the injection and production wells. The model consists of a 50 m thick, radially symmetric grid with a semi-analytic heat exchange and no fluid flow at the top and bottom boundaries and no fluid and heat flow at the lateral boundaries. We design Plackett-Burman experiments resulting in 16 simulations for the seven parameters investigated. The reservoir is divided into 3-, 4-, or 5- layer systems with log-normal permeability distributions. We consider 10 sets of values for each case resulting in a total of 16x3x10 =480 simulations.We analyze the performance of the system to maximize the amount of heat energy extracted, minimize reservoir temperature depletion and maximize the CO2concentration in the produced fluid. Achieving the latter objective reduces power system problems as Welch and Boyle (GRC Trans. 2009) found that CO2 concentration should be >94% in the systems they investigated.

Predicting CO2-H2O Interfacial Tension Using COSMO-RS.

PubMed

Silvestri, A; Stipp, S L S; Andersson, M P

2017-02-14

Knowledge about the interaction between fluids and solids and the interfacial tension (IFT) that results is important for predicting behavior and properties in industrial systems and in nature, such as in rock formations before, during, and after CO 2 injection for long-term storage. Many authors have studied the effect of the environmental variables on the IFT in the CO 2 -H 2 O system. However, experimental measurements above CO 2 supercritical conditions are scarce and sometimes contradictory. Molecular modeling is a valuable tool for complementing experimental IFT determination, and it can help us interpret results and gain insight under conditions where experiments are difficult or impossible. Here, we report predictions for CO 2 -water interfacial tension performed using density functional theory (DFT) combined with the COSMO-RS implicit solvent model. We predicted the IFT dependence as a function of pressure (0-50 MPa), temperature (273-383 K), and salinity (0-5 M NaCl). The results agree well with literature data, within the estimated uncertainty for experiments and for molecular dynamics (MD) simulations, suggesting that the model can be used as a fast alternative to time-consuming computational approaches for predicting the CO 2 -water IFT over a range of pressures, temperatures, and salinities.

Cortical and subcortical connections of V1 and V2 in early postnatal macaque monkeys.

PubMed

Baldwin, Mary K L; Kaskan, Peter M; Zhang, Bin; Chino, Yuzo M; Kaas, Jon H

2012-02-15

Connections of primary (V1) and secondary (V2) visual areas were revealed in macaque monkeys ranging in age from 2 to 16 weeks by injecting small amounts of cholera toxin subunit B (CTB). Cortex was flattened and cut parallel to the surface to reveal injection sites, patterns of labeled cells, and patterns of cytochrome oxidase (CO) staining. Projections from the lateral geniculate nucleus and pulvinar to V1 were present at 4 weeks of age, as were pulvinar projections to thin and thick CO stripes in V2. Injections into V1 in 4- and 8-week-old monkeys labeled neurons in V2, V3, middle temporal area (MT), and dorsolateral area (DL)/V4. Within V1 and V2, labeled neurons were densely distributed around the injection sites, but formed patches at distances away from injection sites. Injections into V2 labeled neurons in V1, V3, DL/V4, and MT of monkeys 2-, 4-, and 8-weeks of age. Injections in thin stripes of V2 preferentially labeled neurons in other V2 thin stripes and neurons in the CO blob regions of V1. A likely thick stripe injection in V2 at 4 weeks of age labeled neurons around blobs. Most labeled neurons in V1 were in superficial cortical layers after V2 injections, and in deep layers of other areas. Although these features of adult V1 and V2 connectivity were in place as early as 2 postnatal weeks, labeled cells in V1 and V2 became more restricted to preferred CO compartments after 2 weeks of age. Copyright © 2011 Wiley-Liss, Inc.

Subsurface injection of combustion power plant effluent as a solid-phase carbon dioxide storage strategy

NASA Astrophysics Data System (ADS)

Darnell, K. N.; Flemings, P. B.; DiCarlo, D.

2017-06-01

Long-term geological storage of CO2 may be essential for greenhouse gas mitigation, so a number of storage strategies have been developed that utilize a variety of physical processes. Recent work shows that injection of combustion power plant effluent, a mixture of CO2 and N2, into CH4 hydrate-bearing reservoirs blends CO2 storage with simultaneous CH4 production where the CO2 is stored in hydrate, an immobile, solid compound. This strategy creates economic value from the CH4 production, reduces the preinjection complexity since costly CO2 distillation is circumvented, and limits leakage since hydrate is immobile. Here we explore the phase behavior of these types of injections and describe the individual roles of H2O, CO2, CH4, and N2 as these components partition into aqueous, vapor, hydrate, and liquid CO2 phases. Our results show that CO2 storage in subpermafrost or submarine hydrate-forming reservoirs requires coinjection of N2 to maintain two-phase flow and limit plugging.

Leakage risk assessment of the In Salah CO2 storage project: Applying the Certification Framework in a dynamic context.

DOE Office of Scientific and Technical Information (OSTI.GOV)

Oldenburg, C.M.; Jordan, P.D.; Nicot, J.-P.

2010-08-01

The Certification Framework (CF) is a simple risk assessment approach for evaluating CO{sub 2} and brine leakage risk at geologic carbon sequestration (GCS) sites. In the In Salah CO{sub 2} storage project assessed here, five wells at Krechba produce natural gas from the Carboniferous C10.2 reservoir with 1.7-2% CO{sub 2} that is delivered to the Krechba gas processing plant, which also receives high-CO{sub 2} natural gas ({approx}10% by mole fraction) from additional deeper gas reservoirs and fields to the south. The gas processing plant strips CO{sub 2} from the natural gas that is then injected through three long horizontal wellsmore » into the water leg of the Carboniferous gas reservoir at a depth of approximately 1,800 m. This injection process has been going on successfully since 2004. The stored CO{sub 2} has been monitored over the last five years by a Joint Industry Project (JIP) - a collaboration of BP, Sonatrach, and Statoil with co-funding from US DOE and EU DG Research. Over the years the JIP has carried out extensive analyses of the Krechba system including two risk assessment efforts, one before injection started, and one carried out by URS Corporation in September 2008. The long history of injection at Krechba, and the accompanying characterization, modeling, and performance data provide a unique opportunity to test and evaluate risk assessment approaches. We apply the CF to the In Salah CO{sub 2} storage project at two different stages in the state of knowledge of the project: (1) at the pre-injection stage, using data available just prior to injection around mid-2004; and (2) after four years of injection (September 2008) to be comparable to the other risk assessments. The main risk drivers for the project are CO{sub 2} leakage into potable groundwater and into the natural gas cap. Both well leakage and fault/fracture leakage are likely under some conditions, but overall the risk is low due to ongoing mitigation and monitoring activities. Results of the application of the CF during these different state-of-knowledge periods show that the assessment of likelihood of various leakage scenarios increased as more information became available, while assessment of impact stayed the same. Ongoing mitigation, modeling, and monitoring of the injection process is recommended.« less

Reservoir Architecture Control on the Geometry of a CO2 Plume Using 4D Seismic, Sleipner Field.

NASA Astrophysics Data System (ADS)

Bitrus, Roy; Iacopini, David; Bond, Clare

2017-04-01

Time lapse seismic from the Sleipner field, Norwegian North Sea represents a unique database to understand the geometry of a saline aquifer, the Utsira Sand Formation, and its role in containing sequestered CO2. The heterogeneous high permeability Utsira Sand formation bounded by an overlying seal is surrounded by impermeable to semi-permeable intra-reservoir thin shale units that influence the migration of injected CO2. It is important to understand and verify the dynamics of injected CO2 plume migration as this ensures close to accurate predictions of the evolving and stable state of CO2 in storage projects. Previous detailed interpretation results of the thin shale units and permeability flow path chimneys within the Utsira Formation have been used in this research. The Utsira Cap rock, IUTS1 and IUTS1 (Intra-Utsira Shale Units) are the top three units that affect the containment and upward migration path of injected CO2. They are combined with seismic geobodies of the CO2 plume across time lapse data. Here, these seismic geobodies are created using 2 methods to delineate the 3D shape and the cubic volume occupancy of the CO2 plume within the reservoir. Method 1 employs the use of an envelope attribute volume, where samples are extracted from voxels that contain seismic trace amplitude values of injected CO2 across the 3D data. These extracted samples are then tracked throughout the target area and then classed and quantified as a CO2 geobodies. Method 2 applies the same concept; the only difference is the samples extracted from voxels are classed based on the proximity and connectivity of pre-defined amplitude values. Both methods employ the use of a Bayesian classifier which defines the probability density function used to categorise the extracted threshold values. Our result of the 3D geobody shapes are compared against the internal geometry of the reservoir which shows the influence of the cap rock and intra-reservoir thin shales on the CO2 plume acting as baffles and flow paths. The amount of injected CO2 is compared against the occupied volume of CO2 within the reservoir rock. Result values are plotted in graphs and they give an indication of the upper and lower end of reservoir volume occupied by injected supercritical CO2. These values are based on the porosity, permeability, density and temperature values of the rock volume, formation fluid and supercritical CO2. The results also show a decrease in effective rock volume occupied by CO2 reaching the Utsira top cap rock with increase in injected amounts of CO2. Our results indicate that the methods proposed can be applied to storage reservoirs in their early to mid-stages to help predict and understand the internal geometries of the reservoir unit and how they can affect the containment or upward migration flow of CO2. The CO2 volumetric measurement can also be used as a well-grounded assessment for future saline aquifer storage projects.

Potential for the Use of Wireless Sensor Networks for Monitoring of CO2 Leakage Risks

NASA Astrophysics Data System (ADS)

Pawar, R.; Illangasekare, T. H.; Han, Q.; Jayasumana, A.

2015-12-01

Storage of supercritical CO2 in deep saline geologic formation is under study as a means to mitigate potential global climate change from green house gas loading to the atmosphere. Leakage of CO2 from these formations poses risk to the storage permanence goal of 99% of injected CO2 remaining sequestered from the atmosphere,. Leaked CO2 that migrates into overlying groundwater aquifers may cause changes in groundwater quality that pose risks to environmental and human health. For these reasons, technologies for monitoring, measuring and accounting of injected CO2 are necessary for permitting of CO2 sequestration projects under EPA's class VI CO2 injection well regulations. While the probability of leakage related to CO2 injection is thought to be small at characterized and permitted sites, it is still very important to protect the groundwater resources and develop methods that can efficiently and accurately detect CO2 leakage. Methods that have been proposed for leakage detection include remote sensing, soil gas monitoring, geophysical techniques, pressure monitoring, vegetation stress and eddy covariance measurements. We have demonstrated the use of wireless sensor networks (WSN) for monitoring of subsurface contaminant plumes. The adaptability of this technology for leakage monitoring of CO2 through geochemical changes in the shallow subsurface is explored. For this technology to be viable, it is necessary to identify geochemical indicators such as pH or electrical conductivity that have high potential for significant change in groundwater in the event of CO2 leakage. This talk presents a conceptual approach to use WSNs for CO2 leakage monitoring. Based on our past work on the use of WSN for subsurface monitoring, some of the challenges that need to be over come for this technology to be viable for leakage detection will be discussed.

Analysis of Geologic CO2 Sequestration at Farnham Dome, Utah, USA

NASA Astrophysics Data System (ADS)

Lee, S.; Han, W.; Morgan, C.; Lu, C.; Esser, R.; Thorne, D.; McPherson, B.

2008-12-01

The Farnham Dome in east-central Utah is an elongated, Laramide-age anticline along the northern plunge of the San Rafael uplift and the western edge of the Uinta Basin. We are helping design a proposed field demonstration of commercial-scale geologic CO2 sequestration, including injection of 2.9 million tons of CO2 over four years time. The Farnham Dome pilot site stratigraphy includes a stacked system of saline formations alternating with low-permeability units. Facilitating the potential sequestration demonstration is a natural CO2 reservoir at depth, the Jurassic-age Navajo formation, which contains an estimated 50 million tons of natural CO2. The sequestration test design includes two deep formations suitable for supercritical CO2 injection, the Jurassic-age Wingate sandstone and the Permian-age White Rim sandstone. We developed a site-specific geologic model based on available geophysical well logs and formation tops data for use with numerical simulation. The current geologic model is limited to an area of approximately 6.5x4.5 km2 and 2.5 km thick, which contains 12 stacked formations starting with the White Rim formation at the bottom (>5000 feet bgl) and extending to the Jurassic Curtis formation at the top of the model grid. With the detail of the geologic model, we are able to estimate the Farnham Dome CO2 capacity at approximately 36.5 million tones within a 5 mile radius of a single injection well. Numerical simulation of multiphase, non- isothermal CO2 injection and flow suggest that the injected CO2 plume will not intersect nearby fault zones mapped in previous geologic studies. Our simulations also examine and compare competing roles of different trapping mechanisms, including hydrostratigraphic, residual gas, solubility, and mineralization trapping. Previous studies of soil gas flux at the surface of the fault zones yield no significant evidence of CO2 leakage from the natural reservoir at Farnham Dome, and thus we use these simulations to evaluate what factors make this natural reservoir so effective for CO2 storage. Our characterization and simulation efforts are producing a CO2 sequestration framework that incorporates production and capacity estimation, area-of-review, injectivity, and trapping mechanisms. Likewise, mitigation and monitoring strategies have been formulated from the site characterization and modeling results.

Stokes injected Raman capillary waveguide amplifier

DOEpatents

Kurnit, Norman A.

1980-01-01

A device for producing stimulated Raman scattering of CO.sub.2 laser radiation by rotational states in a diatomic molecular gas utilizing a Stokes injection signal. The system utilizes a cryogenically cooled waveguide for extending focal interaction length. The waveguide, in conjunction with the Stokes injection signal, reduces required power density of the CO.sub.2 radiation below the breakdown threshold for the diatomic molecular gas. A Fresnel rhomb is employed to circularly polarize the Stokes injection signal and CO.sub.2 laser radiation in opposite circular directions. The device can be employed either as a regenerative oscillator utilizing optical cavity mirrors or as a single pass amplifier. Additionally, a plurality of Raman gain cells can be staged to increase output power magnitude. Also, in the regenerative oscillator embodiment, the Raman gain cell cavity length and CO.sub.2 cavity length can be matched to provide synchronism between mode locked CO.sub.2 pulses and pulses produced within the Raman gain cell.

Response of Heterogeneous and Fractured Carbonate Samples to CO2-Brine Exposure

NASA Astrophysics Data System (ADS)

Smith, M. M.; Mason, H. E.; Hao, Y.; Carroll, S.

2014-12-01

Carbonate rock units are often considered as candidate sites for storage of carbon dioxide (CO2), whether as stand-alone reservoirs or coupled with enhanced oil recovery efforts. In order to accept injected carbon dioxide, carbonate reservoirs must either possess sufficient preexisting connected void space, or react with CO2-acidified fluids to produce more pore space and improve permeability. However, upward migration of CO2 through barrier zones or seal layers must be minimized for effective safe storage. Therefore, prediction of the changes to porosity and permeability in these systems over time is a key component of reservoir management. Towards this goal, we present the results of several experiments on carbonate core samples from the Wellington, Kansas 1-32 well, conducted under reservoir temperature, pressure, and CO2 conditions. These samples were imaged by X-ray computed tomography (XRCT) and analyzed with nuclear magnetic resonance (NMR) spectroscopy both prior to and after reaction with CO2-enriched brines. The carbonate samples each displayed distinct responses to CO2 exposure in terms of permeability change with time and relative abundance of calcite versus dolomite dissolution. The measured permeability of each sample was also much lower than that estimated by downhole NMR logging, with samples with larger fractured regions possessing higher permeability values. We present also our modeling approach and preliminary simulation results for a specific sample from the targeted injection zone. The heterogeneous composition as well as the presence of large fractured zones within the rock necessitated the use of a nested three-region approach to represent the range of void space observed via tomography. Currently, the physical response to CO2-brine flow (i.e., pressure declines with time) is reproduced well but the extent of chemical reaction is overestimated by the model.

Deep aquifer prokaryotic community responses to CO2 geosequestration

NASA Astrophysics Data System (ADS)

Mu, A.; Moreau, J. W.

2015-12-01

Little is known about potential microbial responses to supercritical CO2 (scCO2) injection into deep subsurface aquifers, a currently experimental means for mitigating atmospheric CO2 pollution being trialed at several locations around the world. One such site is the Paaratte Formation of the Otway Basin (~1400 m below surface; 60°C; 2010 psi), Australia. Microbial responses to scCO2 are important to understand as species selection may result in changes to carbon and electron flow. A key aim is to determine if biofilm may form in aquifer pore spaces and reduce aquifer permeability and storage. This study aimed to determine in situ, using 16S rRNA gene, and functional metagenomic analyses, how the microbial community in the Otway Basin geosequestration site responded to experimental injection of 150 tons of scCO2. We demonstrate an in situ sampling approach for detecting deep subsurface microbial community changes associated with geosequestration. First-order level analyses revealed a distinct shift in microbial community structure following the scCO2 injection event, with proliferation of genera Comamonas and Sphingobium. Similarly, functional profiling of the formation revealed a marked increase in biofilm-associated genes (encoding for poly-β-1,6-N-acetyl-D-glucosamine). Global analysis of the functional gene profile highlights that scCO2 injection potentially degraded the metabolism of CH4 and lipids. A significant decline in carboxydotrophic gene abundance (cooS) and an anaerobic carboxydotroph OTU (Carboxydocella), was observed in post-injection samples. The potential impacts on the flow networks of carbon and electrons to heterotrophs are discussed. Our findings yield insights for other subsurface systems, such as hydrocarbon-rich reservoirs and high-CO2 natural analogue sites.

Plants as Indicators of Past and Present Zones of Upwelling Soil CO2 at the ZERT Facility

NASA Astrophysics Data System (ADS)

Apple, M. E.; Sharma, B.; Zhou, X.; Shaw, J. A.; Dobeck, L.; Cunnningham, A.; Spangler, L.; ZERT Team

2011-12-01

By their very nature, photosynthetic plants are sensitive and responsive to CO2, which they fix during the Calvin-Benson cycle. Responses of plants to CO2 are valuable tools in the surface detection of upwelling and leaking CO2 from carbon sequestration fields. Plants exposed to upwelling CO2 rapidly exhibit signs of stress such as changes in stomatal conductance, hyperspectral signatures, pigmentation, and viability (Lakkaraju et al. 2010; Male et al. 2010). The Zero Emission Research and Technology (ZERT) site in Bozeman, MT is an experimental facility for surface detection of CO2 where 0.15 ton/day of CO2 was released (7/19- 8/15/2010, and 7/18 - 8/15/2011) from a 100m horizontal injection well, (HIW), 1.5 m underground with deliberate leaks of CO2 at intervals, and from a vertical injector, (VIW), (6/3-6/24/2010). Soil CO2 concentrations reached 16%. Plants at ZERT include Taraxacum officinale (Dandelion), Dactylis glomerata (Orchard Grass), Poa pratensis, (Kentucky Bluegrass), Phleum pratense (Timothy), Bromus japonicus (Japanese Brome), Medicago sativa (Alfalfa) and Cirsium arvense (Canadian Thistle). Dandelion leaves above the zones of upwelling CO2 at the HIW and the VIW changed color from green to reddish-purple (indicative of an increase in anthocyanins) to brown as they senesced within two weeks of CO2 injection. Their increased stomatal conductance along with their extensive surface area combined to make water loss occur quickly following injection of CO2. Xeromorphic grass leaves were not as profoundly affected, although they did exhibit changes in stomatal conductance, accelerated loss of chlorophyll beyond what would normally occur with seasonal senescence, and altered hyperspectral signatures. Within two weeks of CO2 injection at the HIW and the VIW, hot spots formed, which are circular zones of visible leaf senescence that appear at zones of upwelling CO2. The hot spots became more pronounced as the CO2 injection continued, and were detectable until obscured by snow in the fall and winter. Residual hot spots were visible in the spring after a summer CO2 injection. At both the HIW and the VIW, dandelions were less abundant, if not scarce, in the hot spots when quantified the next year. We mounted a Star-Dot web camera on a scaffold, from which the camera photographs the area each day at noon. The camera remains in place year round and obtains images of the current and residual hot spots, and the growth, color changes, and senescence of the plants. We also quantified percent coverage of plant species along the HIW and the VIW. At the VIW, which received CO2 in 2010 but not in 2011, the site of the 2010 hot spot was detectable in 2011 as a scarcity of dandelion leaves. Therefore, previous, or antecedent, conditions influenced the distribution of species at the VIW and do not depend on continuous injection of CO2. Sudden and long-term shifts in species composition have important ecological implications and may serve as a means of surface detection of upwelling CO2.

Stability of Buoyancy-Driven Gas Flow: Visualization of Coherent and Incoherent Gas Flow Patterns and Capillary Trapping

NASA Astrophysics Data System (ADS)

Geistlinger, H. W.; Samani, S.; Pohlert, M.; Jia, R.; Lazik, D.

2009-12-01

There are several mechanisms by which the CO2 can be stored: (1) In hydrodynamic trapping, the buoyant CO2 remains as a mobile fluid but is prevented from flowing back to the surface by an impermeable cap rock. (2) In solution trapping, CO2 dissolves into the brine, possibly enhanced by gravity instabilities due to the larger density of the brine-CO2 liquid mixture. (3) In mineral trapping, geochemical binding to the rock due to mineral precipitation. (4) In capillary trapping, the CO2 phase is disconnected into a coherent, mobile phase and an incoherent, immobile (trapped) phase. Recent analytical and numerical investigations [Juanes et al., 2006, 2009; Hesse et al., 2007 ] of buoyant-driven CO2-plume along a sloped aquifer are based on the following conceptual process model: (1) During the injection period, the less wetting CO2 displaces the more wetting brine in a drainage-like process. It is assumed that no capillary trapping occurs and that the CO2-network is coherent and driven both by the injection pressure and the buoyant pressure. Because of this coherence assumption a generalized Darcy-law can be used for the dynamics of the mobile, gaseous CO2-phase. (2) After injection the buoyant CO2 migrates laterally and upward, and water displaces CO2 at the trailing edge of the plume in an imbibition-like process. During this process, there are several physical mechanisms by which the water can displace the CO2 [Lenormand et al., 1983]. In addition to piston-type displacement, core-annular flow (also called: cooperative pore-body filling) may occur, i.e. the wetting phase moves along the walls and under certain conditions the CO2-core flow becomes unstable (snap-off). For water wet rocks, snap-off is the dominant mechanism [Al-Futaisi and Patzek, 2003; Valvatne and Blunt, 2004]. There seems to be consensus that the capillary trapping mechanism has a huge impact on the migration and distribution of CO2 which, in turn, affects the effectiveness of the other sequestration mechanisms. In order to investigate the stability of buoyancy-driven gas flow and the transition between coherent flow, incoherent flow, and their correlation to capillary trapping, we conducted high-resolution optical bench scale experiments. We observed a grain-size (dk) - and flow-rate (Q) dependent transition from incoherent to coherent flow. Based on core-annular flow (= cooperative pore-body filling), we propose a dynamic stability criterion that could describe our experimental results. Our experimental results for vertical gas flow support the experimental results by Lenormand et al. [1983] obtained for horizontal flow, if one takes into account that gravity leads to more unstable flow conditions. Our main results, which are in strong contradiction to the accepted conceptual model of the sloped aquifer, are: (1) Capillary Trapping can already occur during injection and at the front of the plume [Lazik et al., 2008] (2) Gas clusters or bubbles can be mobile (incoherent gas flow) and immobile (capillary trapping), and (3) Incoherent gas flow can not be described by a generalized Darcy law [Geistlinger et al., 2006, 2009].

Geomechanical Evaluation of Thermal Impact of Injected CO 2 Temperature on a Geological Reservoir: Application to the FutureGen 2.0 Site

DOE PAGES

Bonneville, Alain; USA, Richland Washington; Nguyen, Ba Nghiep; ...

2014-12-31

The impact of temperature variations of injected CO 2 on the mechanical integrity of a reservoir is a problem rarely addressed in the design of a CO 2 storage site. The geomechanical simulation of the FutureGen 2.0 storage site presented here takes into account the complete modeling of heat exchange between the environment and CO 2 during its transport in the pipeline and injection well before reaching the reservoir, as well as its interaction with the reservoir host rock. An ad-hoc program was developed to model CO 2 transport from the power plant to the reservoir and an approach couplingmore » PNNL STOMP-CO 2 multiphase flow simulator and ABAQUS® has been developed for the reservoir model which is fully three-dimensional with four horizontal wells and variable layer thickness. The Mohr-Coulomb fracture criterion has been employed, where hydraulic fracture was predicted to occur at an integration point if the fluid pressure at the point exceeded the least compressive principal stress. Evaluation of the results shows that the fracture criterion has not been verified at any node and time step for the CO 2 temperature range predicted at the top of the injection zone.« less

Understanding CO2 Plume Behavior and Basin-Scale Pressure Changes during Sequestration Projects through the use of Reservoir Fluid Modeling

USGS Publications Warehouse

Leetaru, H.E.; Frailey, S.M.; Damico, J.; Mehnert, E.; Birkholzer, J.; Zhou, Q.; Jordan, P.D.

2009-01-01

Large scale geologic sequestration tests are in the planning stages around the world. The liability and safety issues of the migration of CO2 away from the primary injection site and/or reservoir are of significant concerns for these sequestration tests. Reservoir models for simulating single or multi-phase fluid flow are used to understand the migration of CO2 in the subsurface. These models can also help evaluate concerns related to brine migration and basin-scale pressure increases that occur due to the injection of additional fluid volumes into the subsurface. The current paper presents different modeling examples addressing these issues, ranging from simple geometric models to more complex reservoir fluid models with single-site and basin-scale applications. Simple geometric models assuming a homogeneous geologic reservoir and piston-like displacement have been used for understanding pressure changes and fluid migration around each CO2 storage site. These geometric models are useful only as broad approximations because they do not account for the variation in porosity, permeability, asymmetry of the reservoir, and dip of the beds. In addition, these simple models are not capable of predicting the interference between different injection sites within the same reservoir. A more realistic model of CO2 plume behavior can be produced using reservoir fluid models. Reservoir simulation of natural gas storage reservoirs in the Illinois Basin Cambrian-age Mt. Simon Sandstone suggest that reservoir heterogeneity will be an important factor for evaluating storage capacity. The Mt. Simon Sandstone is a thick sandstone that underlies many significant coal fired power plants (emitting at least 1 million tonnes per year) in the midwestern United States including the states of Illinois, Indiana, Kentucky, Michigan, and Ohio. The initial commercial sequestration sites are expected to inject 1 to 2 million tonnes of CO2 per year. Depending on the geologic structure and permeability anisotropy, the CO2 injected into the Mt. Simon are expected to migrate less than 3 km. After 30 years of continuous injection followed by 100 years of shut-in, the plume from a 1 million tonnes a year injection rate is expected to migrate 1.6 km for a 0 degree dip reservoir and over 3 km for a 5 degree dip reservoir. The region where reservoir pressure increases in response to CO2 injection is typically much larger than the CO2 plume. It can thus be anticipated that there will be basin wide interactions between different CO2 injection sources if multiple, large volume sites are developed. This interaction will result in asymmetric plume migration that may be contrary to reservoir dip. A basin- scale simulation model is being developed to predict CO2 plume migration, brine displacement, and pressure buildup for a possible future sequestration scenario featuring multiple CO2 storage sites within the Illinois Basin Mt. Simon Sandstone. Interactions between different sites will be evaluated with respect to impacts on pressure and CO2 plume migration patterns. ?? 2009 Elsevier Ltd. All rights reserved.

Abiotic CO2 reduction during geologic carbon sequestration facilitated by Fe(II)-bearing minerals

NASA Astrophysics Data System (ADS)

Nielsen, L. C.; Maher, K.; Bird, D. K.; Brown, G. E.; Thomas, B.; Johnson, N. C.; Rosenbauer, R. J.

2012-12-01

Redox reactions involving subsurface minerals and fluids and can lead to the abiotic generation of hydrocarbons from CO2 under certain conditions. Depleted oil reservoirs and saline aquifers targeted for geologic carbon sequestration (GCS) can contain significant quantities of minerals such as ferrous chlorite, which could facilitate the abiotic reduction of carbon dioxide to n-carboxylic acids, hydrocarbons, and amorphous carbon (C0). If such reactions occur, the injection of supercritical CO2 (scCO2) could significantly alter the oxidation state of the reservoir and cause extensive reorganization of the stable mineral assemblage via dissolution and reprecipitation reactions. Naturally occurring iron oxide minerals such as magnetite are known to catalyze CO2 reduction, resulting in the synthesis of organic compounds. Magnetite is thermodynamically stable in Fe(II) chlorite-bearing mineral assemblages typical of some reservoir formations. Thermodynamic calculations demonstrate that GCS reservoirs buffered by the chlorite-kaolinite-carbonate(siderite/magnesite)-quartz assemblage favor the reduction of CO2 to n-carboxylic acids, hydrocarbons, and C0, although the extent of abiotic CO2 reduction may be kinetically limited. To investigate the rates of abiotic CO2 reduction in the presence of magnetite, we performed batch abiotic CO2 reduction experiments using a Dickson-type rocking hydrothermal apparatus at temperatures (373 K) and pressures (100 bar) within the range of conditions relevant to GCS. Blank experiments containing CO2 and H2 were used to rule out the possibility of catalytic activity of the experimental apparatus. Reaction of brine-suspended magnetite nanoparticles with scCO2 at H2 partial pressures typical of reservoir rocks - up to 100 and 0.1 bars respectively - was used to investigate the kinetics of magnetite-catalyzed abiotic CO2 reduction. Later experiments introducing ferrous chlorite (ripidolite) were carried out to determine the potential for heterogeneous catalysis in GCS systems.

MUFITS Code for Modeling Geological Storage of Carbon Dioxide at Sub- and Supercritical Conditions

NASA Astrophysics Data System (ADS)

Afanasyev, A.

2012-12-01

Two-phase models are widely used for simulation of CO2 storage in saline aquifers. These models support gaseous phase mainly saturated with CO2 and liquid phase mainly saturated with H2O (e.g. TOUGH2 code). The models can be applied to analysis of CO2 storage only in relatively deeply-buried reservoirs where pressure exceeds CO2 critical pressure. At these supercritical reservoir conditions only one supercritical CO2-rich phase appears in aquifer due to CO2 injection. In shallow aquifers where reservoir pressure is less than the critical pressure CO2 can split in two different liquid-like and gas-like phases (e.g. Spycher et al., 2003). Thus a region of three-phase flow of water, liquid and gaseous CO2 can appear near the CO2 injection point. Today there is no widely used and generally accepted numerical model capable of the three-phase flows with two CO2-rich phases. In this work we propose a new hydrodynamic simulator MUFITS (Multiphase Filtration Transport Simulator) for multiphase compositional modeling of CO2-H2O mixture flows in porous media at conditions of interest for carbon sequestration. The simulator is effective both for supercritical flows in a wide range of pressure and temperature and for subcritical three-phase flows of water, liquid CO2 and gaseous CO2 in shallow reservoirs. The distinctive feature of the proposed code lies in the methodology for mixture properties determination. Transport equations and Darcy correlation are solved together with calculation of the entropy maximum that is reached in thermodynamic equilibrium and determines the mixture composition. To define and solve the problem only one function - mixture thermodynamic potential - is required. The potential is determined using a three-parametric generalization of Peng-Robinson equation of state fitted to experimental data (Todheide, Takenouchi, Altunin etc.). We apply MUFITS to simple 1D and 2D test problems of CO2 injection in shallow reservoirs subjected to phase changes between liquid and gaseous CO2. We consider CO2 injection into highly heterogeneous the 10th SPE reservoir. We provide analysis of physical phenomena that have control temperature distribution in the reservoir. The distribution is non-monotonic with regions of high and low temperature. The main phenomena responsible for considerable temperature decline around CO2 injection point is the liquid CO2 evaporation process. We also apply the code to real-scale 3D simulations of CO2 geological storage at supercritical conditions in Sleipner field and Johansen formation (Fig). The work is supported financially by the Russian Foundation for Basic Research (12-01-31117) and grant for leading scientific schools (NSh 1303.2012.1). CO2 phase saturation in Johansen formation after 50 years of injection and 1000 years of rest period

Multiple isotopes (O, C, Li, Sr) as tracers of CO2 and brine leakage from CO2-enhanced oil recovery activities in Permian Basin, Texas, USA

NASA Astrophysics Data System (ADS)

Phan, T. T.; Sharma, S.; Gardiner, J. B.; Thomas, R. B.; Stuckman, M.; Spaulding, R.; Lopano, C. L.; Hakala, A.

2017-12-01

Potential CO2 and brine migration or leakage into shallow groundwater is a critical issue associated with CO2 injection at both enhanced oil recovery (EOR) and carbon sequestration sites. The effectiveness of multiple isotope systems (δ18OH2O, δ13C, δ7Li, 87Sr/86Sr) in monitoring CO2 and brine leakage at a CO2-EOR site located within the Permian basin (Seminole, Texas, USA) was studied. Water samples collected from an oil producing formation (San Andres), a deep groundwater formation (Santa Rosa), and a shallow groundwater aquifer (Ogallala) over a four-year period were analyzed for elemental and isotopic compositions. The absence of any change in δ18OH2O or δ13CDIC values of water in the overlying Ogallala aquifer after CO2 injection indicates that injected CO2 did not leak into this aquifer. The range of Ogallala water δ7Li (13-17‰) overlaps the San Andres water δ7Li (13-15‰) whereas 87Sr/86Sr of Ogallala (0.70792±0.00005) significantly differs from San Andres water (0.70865±0.00003). This observation demonstrates that Sr isotopes are much more sensitive than Li isotopes in tracking brine leakage into shallow groundwater at the studied site. In contrast, deep groundwater δ7Li (21-25‰) is isotopically distinct from San Andres produced water; thus, monitoring this intermitted formation water can provide an early indication of CO2 injection-induced brine migration from the underlying oil producing formation. During water alternating with gas (WAG) operations, a significant shift towards more positive δ13CDIC values was observed in the produced water from several of the San Andres formation wells. The carbon isotope trend suggests that the 13C enriched injected CO2 and formation carbonates became the primary sources of dissolved inorganic carbon in the area surrounding the injection wells. Moreover, one-way ANOVA statistical analysis shows that the differences in δ7Li (F(1,16) = 2.09, p = 0.17) and 87Sr/86Sr (F(1,18) = 4.47, p = 0.05) values of shallow groundwater collected before and during the WAG period are not statistically significant. The results to date suggest that the water chemistry of shallow groundwater has not been influenced by the CO2 injection activities. The efficacy of each isotope system as a monitoring tool will be evaluated and discussed using a Bayesian mixing model.

Flow in a discrete slotted nozzle with massive injection. [water table tests

NASA Technical Reports Server (NTRS)

Perkins, H. C.

1974-01-01

An experimental investigation has been conducted to determine the effect of massive wall injection on the flow characteristics in a slotted nozzle. Some of the experiments were performed on a water table with a slotted-nozzle test section. This has 45 deg and 15 deg half angles of convergence and divergence, respectively, throat radius of 2.5 inches, and throat width of 3 inches. The hydraulic analogy was employed to qualitatively extend the results to a compressible gas flow through the nozzle. Experimental results from the water table include contours of constant Froude and Mach number with and without injection. Photographic results are also presented for the injection through slots of CO2 and Freon-12 into a main-stream air flow in a convergent-divergent nozzle in a wind tunnel. Schlieren photographs were used to visualize the flow, and qualititative agreement between the results from the gas tunnel and water table is good.

Interplay between microorganisms and geochemistry in geological carbon storage

DOE Office of Scientific and Technical Information (OSTI.GOV)

Altman, Susan J.; Kirk, Matthew Fletcher; Santillan, Eugenio-Felipe U.

Researchers at the Center for Frontiers of Subsurface Energy Security (CFSES) have conducted laboratory and modeling studies to better understand the interplay between microorganisms and geochemistry for geological carbon storage (GCS). We provide evidence of microorganisms adapting to high pressure CO 2 conditions and identify factors that may influence survival of cells to CO 2 stress. Factors that influenced the ability of cells to survive exposure to high-pressure CO 2 in our experiments include mineralogy, the permeability of cell walls and/or membranes, intracellular buffering capacity, and whether cells live planktonically or within biofilm. Column experiments show that, following exposure tomore » acidic water, biomass can remain intact in porous media and continue to alter hydraulic conductivity. Our research also shows that geochemical changes triggered by CO 2 injection can alter energy available to populations of subsurface anaerobes and that microbial feedbacks on this effect can influence carbon storage. Our research documents the impact of CO 2 on microorganisms and in turn, how subsurface microorganisms can influence GCS. Furthermore, we conclude that microbial presence and activities can have important implications for carbon storage and that microorganisms should not be overlooked in further GCS research.« less

Inorganic Carbon Source for Photosynthesis in the Seagrass Thalassia hemprichii (Ehrenb.) Aschers.

PubMed

Abel, K M

1984-11-01

Photosynthetic carbon uptake of the tropical seagrass Thalassia hemprichii (Ehrenb.) Aschers was studied by several methods. Photosynthesis in buffered seawater in media in the range of pH 6 to pH 9 showed an exponentially increasing rate with decreasing pH, thus indicating that free CO(2) was a photosynthetic substrate. However, these experiments were unable to determine whether photosynthesis at alkaline pH also contained some component due to HCO(3) (-) uptake. This aspect was further investigated by studying photosynthetic rates in a number of media of varying pH (7.8-8.61) and total inorganic carbon (0.75-13.17 millimolar). In these media, photosynthetic rate was correlated with free CO(2) concentration and was independent of the HCO(3) (-) concentration in the medium. Short time-course experiments were conducted during equilibration of free CO(2) and HCO(3) (-) after injection of (14)C labeled solution at acid or alkaline pH. High initial photosynthetic rates were observed when acidic solutions (largely free CO(2)) were used but not with alkaline solutions. The concentration of free CO(2) was found to be a limiting factor for photosynthesis in this plant.

Interplay between microorganisms and geochemistry in geological carbon storage

DOE PAGES

Altman, Susan J.; Kirk, Matthew Fletcher; Santillan, Eugenio-Felipe U.; ...

2016-02-28

Researchers at the Center for Frontiers of Subsurface Energy Security (CFSES) have conducted laboratory and modeling studies to better understand the interplay between microorganisms and geochemistry for geological carbon storage (GCS). We provide evidence of microorganisms adapting to high pressure CO 2 conditions and identify factors that may influence survival of cells to CO 2 stress. Factors that influenced the ability of cells to survive exposure to high-pressure CO 2 in our experiments include mineralogy, the permeability of cell walls and/or membranes, intracellular buffering capacity, and whether cells live planktonically or within biofilm. Column experiments show that, following exposure tomore » acidic water, biomass can remain intact in porous media and continue to alter hydraulic conductivity. Our research also shows that geochemical changes triggered by CO 2 injection can alter energy available to populations of subsurface anaerobes and that microbial feedbacks on this effect can influence carbon storage. Our research documents the impact of CO 2 on microorganisms and in turn, how subsurface microorganisms can influence GCS. Furthermore, we conclude that microbial presence and activities can have important implications for carbon storage and that microorganisms should not be overlooked in further GCS research.« less

Microbial community response to the CO2 injection and storage in the saline aquifer, Ketzin, Germany

NASA Astrophysics Data System (ADS)

Morozova, Daria; Zettlitzer, Michael; Vieth, Andrea; Würdemann, Hilke

2010-05-01

The concept of CO2 capture and storage in the deep underground is currently receiving great attention as a consequence of the effects of global warming due to the accumulation of carbon dioxide gas in the atmosphere. The EU funded CO2SINK project is aimed as a pilot storage of CO2 in a saline aquifer located near Ketzin, Germany. One of the main aims of the project is to develop efficient monitoring procedures for assessing the processes that are triggered in the reservoir by CO2 injection. This study reveals analyses of the composition and activity of the microbial community of a saline CO2 storage aquifer and its response to CO2 injection. The availability of CO2 has an influence on the metabolism of both heterotrophic microorganisms, which are involved in carbon cycle, and lithoautotrophic microorganisms, which are able to use CO2 as the sole carbon source and electron acceptor. Injection of CO2 in the supercritical state (temperature above 31.1 °C, pressure above 72.9 atm) may induce metabolic shifts in the microbial communities. Furthermore, bacterial population and activity can be strongly influenced by changes in pH value, pressure, temperature, salinity and other abiotic factors, which will be all influenced by CO2 injection into the deep subsurface. Analyses of the composition of microbial communities and its changes should contribute to an evaluation of the effectiveness and reliability of the long-term CO2 storage technique. The interactions between microorganisms and the minerals of both the reservoir and the cap rock may cause major changes to the structure and chemical composition of the rock formations, which would influence the permeability within the reservoir. In addition, precipitation and corrosion may occur around the well affecting the casing and the casing cement. By using Fluorescence in situ Hybridisation (FISH) and molecular fingerprinting such as Polymerase-Chain-Reaction Single-Strand-Conformation Polymorphism (PCR-SSCP) and Denaturing Gradient Gel Electrophoresis (PCR-DGGE), we have shown that the microbial community was strongly influenced by CO2 injection. Before CO2 arrival, up to 6x106 cells ml-1 were detected by DAPI-staining at a depth of 647 m below the surface. The microbial community was dominated by the domain Bacteria, with Proteobacteria and Firmicutes as the most abundant phyla. Representatives of the sulphate-reducing bacteria, extremophilic and fermenting bacteria were identified. After CO2 injection, our study revealed temporal outcompetition of sulphate-reducing bacteria by methanogenic archaea. In addition, an enhanced activity of the microbial population after five months CO2 storage indicated that the bacterial community was able to adapt to the extreme conditions of the deep biosphere and to the extreme changes of these conditions. In order to draw broader conclusions about the microbial community in the deep biosphere, more intensive sampling and methodologies are necessary. The limiting factors such as high expenses of the downhole sampling and time-consuming analyses should be taken into consideration. This study can thus provide only an early insight into the community structure and its changes due to the CO2 injection. Further studies on the activity, quantity and physiology of these microbial communities using molecular cloning and real-time PCR are in progress.

Constraints on the magnitude and rate of CO 2 dissolution at Bravo Dome natural gas field

DOE PAGES

Sathaye, Kiran J.; Hesse, Marc A.; Cassidy, M.; ...

2014-10-13

The injection of carbon dioxide (CO 2) captured at large point sources into deep saline aquifers can significantly reduce anthropogenic CO 2 emissions from fossil fuels. Dissolution of the injected CO 2 into the formation brine is a trapping mechanism that helps to ensure the long-term security of geological CO 2 storage. We use thermochronology to estimate the timing of CO 2 emplacement at Bravo Dome, a large natural CO 2 field at a depth of 700 m in New Mexico. Together with estimates of the total mass loss from the field we present, to our knowledge, the first constraintsmore » on the magnitude, mechanisms, and rates of CO 2 dissolution on millennial timescales. Apatite (U-Th)/He thermochronology records heating of the Bravo Dome reservoir due to the emplacement of hot volcanic gases 1.2–1.5 Ma. The CO 2 accumulation is therefore significantly older than previous estimates of 10 ka, which demonstrates that safe long-term geological CO 2 storage is possible. Here, integrating geophysical and geochemical data, we estimate that 1.3 Gt CO 2 are currently stored at Bravo Dome, but that only 22% of the emplaced CO 2 has dissolved into the brine over 1.2 My. Roughly 40% of the dissolution occurred during the emplacement. The CO 2 dissolved after emplacement exceeds the amount expected from diffusion and provides field evidence for convective dissolution with a rate of 0.1 g/(m 2y). Finally, the similarity between Bravo Dome and major US saline aquifers suggests that significant amounts of CO 2 are likely to dissolve during injection at US storage sites, but that convective dissolution is unlikely to trap all injected CO 2 on the 10-ky timescale typically considered for storage projects.« less

Study on the Fluid Flow Characteristics of Coherent Jets with CO2 and O2 Mixed Injection in Electric Arc Furnace Steelmaking Processes

NASA Astrophysics Data System (ADS)

Wei, Guangsheng; Zhu, Rong; Wu, Xuetao; Yang, Lingzhi; Dong, Kai; Cheng, Ting; Tang, Tianping

2018-06-01

As an efficient oxygen supplying technology, coherent jets are widely applied in electric arc furnace (EAF) steelmaking processes to strengthen chemical energy input, speed up smelting rhythm, and promote the uniformity of molten bath temperature and compositions. Recently, the coherent jet with CO2 and O2 mixed injection (COMI) was proposed and demonstrated great application potentiality in reducing the dust production in EAF steelmaking. In the present study, based on the eddy dissipation concept model, a computational fluid dynamics model of coherent jets with COMI was built with the overall and detailed chemical kinetic mechanisms (GRI-Mech 3.0). Compared with one-step combustion reaction, GRI-Mech 3.0 consists of 325 elementary reactions with 53 components and can predict more accurate results. The numerical simulation results were validated by the combustion experiment data. The jet behavior and the fluid flow characteristics of coherent jets with COMI under 298 K and 1700 K (25 °C and 1427 °C) were studied and the results showed that for coherent jets with COMI, the chemical effect of CO2 significantly weakened the shrouding combustion reactions of CH4 and the relative importance of the chemical effect of CO2 increases with CO2 concentration increasing. The potential core length of coherent jet decreases with the volume fraction of CO2 increasing. Moreover, it also can be found that the potential core length of coherent jets was prolonged with higher ambient temperature.

Study on the Fluid Flow Characteristics of Coherent Jets with CO2 and O2 Mixed Injection in Electric Arc Furnace Steelmaking Processes

NASA Astrophysics Data System (ADS)

Wei, Guangsheng; Zhu, Rong; Wu, Xuetao; Yang, Lingzhi; Dong, Kai; Cheng, Ting; Tang, Tianping

2018-03-01

As an efficient oxygen supplying technology, coherent jets are widely applied in electric arc furnace (EAF) steelmaking processes to strengthen chemical energy input, speed up smelting rhythm, and promote the uniformity of molten bath temperature and compositions. Recently, the coherent jet with CO2 and O2 mixed injection (COMI) was proposed and demonstrated great application potentiality in reducing the dust production in EAF steelmaking. In the present study, based on the eddy dissipation concept model, a computational fluid dynamics model of coherent jets with COMI was built with the overall and detailed chemical kinetic mechanisms (GRI-Mech 3.0). Compared with one-step combustion reaction, GRI-Mech 3.0 consists of 325 elementary reactions with 53 components and can predict more accurate results. The numerical simulation results were validated by the combustion experiment data. The jet behavior and the fluid flow characteristics of coherent jets with COMI under 298 K and 1700 K (25 °C and 1427 °C) were studied and the results showed that for coherent jets with COMI, the chemical effect of CO2 significantly weakened the shrouding combustion reactions of CH4 and the relative importance of the chemical effect of CO2 increases with CO2 concentration increasing. The potential core length of coherent jet decreases with the volume fraction of CO2 increasing. Moreover, it also can be found that the potential core length of coherent jets was prolonged with higher ambient temperature.

Thermal and capillary effects on the caprock mechanical stability at In Salah, Algeria

DOE PAGES

Vilarrasa, Víctor; Rutqvist, Jonny; Rinaldi, Antonio Pio

2015-04-20

Thermo-mechanical effects are important in geologic carbon storage because CO 2 will generally reach the storage formation colder than the rock, inducing thermal stresses. Capillary functions, i.e., retention and relative permeability curves, control the CO 2 plume shape, which may affect overpressure and thus, caprock stability. To analyze these thermal and capillary effects, we numerically solve non-isothermal injection of CO 2 in deformable porous media considering the In Salah, Algeria, CO 2 storage site. Here, we find that changes in the capillary functions have a negligible effect on overpressure and thus, caprock stability is not affected by capillary effects. But,more » we show that for the strike slip stress regime prevalent at In Salah, stability decreases in the lowest parts of the caprock during injection due to cooling-induced thermal stresses. Simulations show that shear slip along pre-existing fractures may take place in the cooled region, whereas tensile failure is less likely to occur. Indeed, only the injection zone and the lowest tens of meters of the 900-m-thick caprock at In Salah might be affected by cooling effects, which would thus not jeopardize the overall sealing capacity of the caprock. Furthermore, faults are likely to remain stable far away from the injection well because outside the cooled region the injection-induced stress changes are not sufficient to exceed the anticipated shear strength of minor faults. Nonetheless, we recommend that thermal effects should be considered in the site characterization and injection design of future CO 2 injection sites to assess caprock stability and guarantee a permanent CO 2 storage.« less

Preliminary Reactive Geochemical Transport Modeling Study on Changes in Water Chemistry Induced by CO2 Injection at Frio Pilot Test Site

NASA Astrophysics Data System (ADS)

Xu, T.; Kharaka, Y.; Benson, S.

2006-12-01

A total of 1600 tons of CO2 were injected into the Frio ~{!0~}C~{!1~} sandstone layer at a depth of 1500 m over a period of 10 days. The pilot, located near Dayton, Texas, employed one injection well and one observation well, separated laterally by about 30 m. Each well was perforated over 6 m in the upper portion of the 23-m thick sandstone. Fluid samples were taken from both wells before, during, and after the injection. Following CO2 breakthrough, observations indicate drops in pH (6.5 to 5.7), pronounced increases in concentrations of HCO3- (100 to 3000 mg/L), in Fe (30 to 1100), and dissolved organic carbon. Numerical modeling was used in this study to understand changes of aqueous HCO3- and Fe caused by CO2 injection. The general multiphase reactive geochemical transport simulator TOUGHREACT was used, which includes new fluid property module ECO2N with an accurate description of the thermophysical properties of mixtures of water, brine, and CO2 at conditions of interest for CO2 storage. A calibrated 1-D radial well flow model was employed for the present reactive geochemical transport simulations. Mineral composition used was taken from literatures relevant to Frio sandstone. Increases in HCO3- concentration were well reproduced by an initial simulation. Several scenarios were used to capture increases in Fe concentration including (1) dissolution of carbonate minerals, (2) dissolution of iron oxyhydroxides, (3) de-sorption of previously coated Fe. Future modeling, laboratory and field investigations are proposed to better understand the CO2-brine-mineral interactions at the Frio site. Results from this study could have broad implication for subsurface storage of CO2 and potential water quality impacts.

Distribution of Particles, Small Molecules and Polymeric Formulation Excipients in the Suprachoroidal Space after Microneedle Injection

PubMed Central

Chiang, Bryce; Venugopal, Nitin; Edelhauser, Henry F.; Prausnitz, Mark R.

2016-01-01

The purpose of this work was to determine the effect of injection volume, formulation composition, and time on circumferential spread of particles, small molecules and polymeric formulation excipients in the suprachoroidal space (SCS) after microneedle injection into New Zealand White rabbit eyes ex vivo and in vivo. Microneedle injections of 25–150 μL Hank’s Balanced Salt Solution (HBSS) containing 0.2 μm red-fluorescent particles and a model small molecule (fluorescein) were performed in rabbit eyes ex vivo, and visualized via flat mount. Particles with diameters of 0.02 – 2 μm were co-injected into SCS in vivo with fluorescein or a polymeric formulation excipient: fluorescein isothiocyanate (FITC)-labeled Discovisc or FITC-labeled carboxymethyl cellulose (CMC). Fluorescent fundus images were acquired over time to determine area of particle, fluorescein and polymeric formulation excipient spread, as well as their co-localization. We found that fluorescein covered a significantly larger area than co-injected particles when suspended in HBSS, and that this difference was present from 3 min post-injection onwards. We further showed that there was no difference in initial area covered by FITC-Discovisc and particles; the transport time (i.e., the time until the FITC-Discovisc and particle area began dissociating) was 2 d. There was also no difference in initial area covered by FITC-CMC and particles; the transport time in FITC-CMC was 4 d. We also found that particle size (20 nm – 2 μm) had no effect on spreading area when delivered in HBSS or Discovisc. We conclude that (i) the area of particle spread in SCS during injection generally increased with increasing injection volume, was unaffected by particle size and was significantly less than the area of fluorescein spread, (ii) particles suspended in low-viscosity HBSS formulation were entrapped in the SCS after injection, whereas fluorescein was not and (iii) particles co-injected with viscous polymeric formulation excipients co-localized near the site of injection in the SCS, continued to co-localize while spreading over larger areas for 2 – 4 days, and then no longer co-localized as the polymeric formulation excipients were cleared within 1 – 3 weeks and the particles remained largely in place. These data suggest that particles encounter greater barriers to flow in SCS compared to molecules and that co-localization of particles and polymeric formulation excipients allow spreading over larger areas of the SCS until the particles and excipients dissociate. PMID:27742547

Distribution of particles, small molecules and polymeric formulation excipients in the suprachoroidal space after microneedle injection.

PubMed

Chiang, Bryce; Venugopal, Nitin; Edelhauser, Henry F; Prausnitz, Mark R

2016-12-01

The purpose of this work was to determine the effect of injection volume, formulation composition, and time on circumferential spread of particles, small molecules, and polymeric formulation excipients in the suprachoroidal space (SCS) after microneedle injection into New Zealand White rabbit eyes ex vivo and in vivo. Microneedle injections of 25-150 μL Hank's Balanced Salt Solution (HBSS) containing 0.2 μm red-fluorescent particles and a model small molecule (fluorescein) were performed in rabbit eyes ex vivo, and visualized via flat mount. Particles with diameters of 0.02-2 μm were co-injected into SCS in vivo with fluorescein or a polymeric formulation excipient: fluorescein isothiocyanate (FITC)-labeled Discovisc or FITC-labeled carboxymethyl cellulose (CMC). Fluorescent fundus images were acquired over time to determine area of particle, fluorescein, and polymeric formulation excipient spread, as well as their co-localization. We found that fluorescein covered a significantly larger area than co-injected particles when suspended in HBSS, and that this difference was present from 3 min post-injection onwards. We further showed that there was no difference in initial area covered by FITC-Discovisc and particles; the transport time (i.e., the time until the FITC-Discovisc and particle area began dissociating) was 2 d. There was also no difference in initial area covered by FITC-CMC and particles; the transport time in FITC-CMC was 4 d. We also found that particle size (20 nm-2 μm) had no effect on spreading area when delivered in HBSS or Discovisc. We conclude that (i) the area of particle spread in SCS during injection generally increased with increasing injection volume, was unaffected by particle size, and was significantly less than the area of fluorescein spread, (ii) particles suspended in low-viscosity HBSS formulation were entrapped in the SCS after injection, whereas fluorescein was not and (iii) particles co-injected with viscous polymeric formulation excipients co-localized near the site of injection in the SCS, continued to co-localize while spreading over larger areas for 2-4 days, and then no longer co-localized as the polymeric formulation excipients were cleared within 1-3 weeks and the particles remained largely in place. These data suggest that particles encounter greater barriers to flow in SCS compared to molecules and that co-localization of particles and polymeric formulation excipients allows spreading over larger areas of the SCS until the particles and excipients dissociate. Copyright © 2016 Elsevier Ltd. All rights reserved.

Lattice Boltzmann simulations of supercritical CO2-water drainage displacement in porous media: CO2 saturation and displacement mechanism.

PubMed

Yamabe, Hirotatsu; Tsuji, Takeshi; Liang, Yunfeng; Matsuoka, Toshifumi

2015-01-06

CO2 geosequestration in deep aquifers requires the displacement of water (wetting phase) from the porous media by supercritical CO2 (nonwetting phase). However, the interfacial instabilities, such as viscous and capillary fingerings, develop during the drainage displacement. Moreover, the burstlike Haines jump often occurs under conditions of low capillary number. To study these interfacial instabilities, we performed lattice Boltzmann simulations of CO2-water drainage displacement in a 3D synthetic granular rock model at a fixed viscosity ratio and at various capillary numbers. The capillary numbers are varied by changing injection pressure, which induces changes in flow velocity. It was observed that the viscous fingering was dominant at high injection pressures, whereas the crossover of viscous and capillary fingerings was observed, accompanied by Haines jumps, at low injection pressures. The Haines jumps flowing forward caused a significant drop of CO2 saturation, whereas Haines jumps flowing backward caused an increase of CO2 saturation (per injection depth). We demonstrated that the pore-scale Haines jumps remarkably influenced the flow path and therefore equilibrium CO2 saturation in crossover domain, which is in turn related to the storage efficiency in the field-scale geosequestration. The results can improve our understandings of the storage efficiency by the effects of pore-scale displacement phenomena.

On the verge of a respiratory-type panic attack: Selective activations of rostrolateral and caudoventrolateral periaqueductal gray matter following short-lasting escape to a low dose of potassium cyanide.

PubMed

Müller, Cláudia Janaina Torres; Quintino-Dos-Santos, Jeyce Willig; Schimitel, Fagna Giacomin; Tufik, Sérgio; Beijamini, Vanessa; Canteras, Newton Sabino; Schenberg, Luiz Carlos

2017-04-21

Intravenous injections of potassium cyanide (KCN) both elicit escape by its own and facilitate escape to electrical stimulation of the periaqueductal gray matter (PAG). Moreover, whereas the KCN-evoked escape is potentiated by CO 2 , it is suppressed by both lesions of PAG and clinically effective treatments with panicolytics. These and other data suggest that the PAG harbors a hypoxia-sensitive alarm system the activation of which could both precipitate panic and render the subject hypersensitive to CO 2 . Although prior c-Fos immunohistochemistry studies reported widespread activations of PAG following KCN injections, the employment of repeated injections of high doses of KCN (>60µg) in anesthetized rats compromised both the localization of KCN-responsive areas and their correlation with escape behavior. Accordingly, here we compared the brainstem activations of saline-injected controls (air/saline) with those produced by a single intravenous injection of 40-µg KCN (air/KCN), a 2-min exposure to 13% CO 2 (CO 2 /saline), or a combined stimulus (CO 2 /KCN). Behavioral effects of KCN microinjections into the PAG were assessed as well. Data showed that whereas the KCN microinjections were ineffective, KCN intravenous injections elicited escape in all tested rats. Moreover, whereas the CO 2 alone was ineffective, it potentiated the KCN-evoked escape. Compared to controls, the nucleus tractus solitarius was significantly activated in both CO 2 /saline and CO 2 /KCN groups. Additionally, whereas the laterodorsal tegmental nucleus was activated by all treatments, the rostrolateral and caudoventrolateral PAG were activated by air/KCN only. Data suggest that the latter structures are key components of a hypoxia-sensitive suffocation alarm which activation may trigger a panic attack. Copyright © 2017 IBRO. Published by Elsevier Ltd. All rights reserved.

Field-Scale Modeling of Local Capillary Trapping During CO2 Injection into a Saline Aquifer

NASA Astrophysics Data System (ADS)

Ren, B.; Lake, L. W.; Bryant, S. L.

2015-12-01

Local capillary trapping is the small-scale (10-2 to 10+1 m) CO2 trapping that is caused by the capillary pressure heterogeneity. The benefit of LCT, applied specially to CO2 sequestration, is that saturation of stored CO2 is larger than the residual gas, yet these CO2 are not susceptible to leakage through failed seals. Thus quantifying the extent of local capillary trapping is valuable in design and risk assessment of geologic storage projects. Modeling local capillary trapping is computationally expensive and may even be intractable using a conventional reservoir simulator. In this paper, we propose a novel method to model local capillary trapping by combining geologic criteria and connectivity analysis. The connectivity analysis originally developed for characterizing well-to-reservoir connectivity is adapted to this problem by means of a newly defined edge weight property between neighboring grid blocks, which accounts for the multiphase flow properties, injection rate, and gravity effect. Then the connectivity is estimated from shortest path algorithm to predict the CO2 migration behavior and plume shape during injection. A geologic criteria algorithm is developed to estimate the potential local capillary traps based only on the entry capillary pressure field. The latter is correlated to a geostatistical realization of permeability field. The extended connectivity analysis shows a good match of CO2 plume computed by the full-physics simulation. We then incorporate it into the geologic algorithm to quantify the amount of LCT structures identified within the entry capillary pressure field that can be filled during CO2 injection. Several simulations are conducted in the reservoirs with different level of heterogeneity (measured by the Dykstra-Parsons coefficient) under various injection scenarios. We find that there exists a threshold Dykstra-Parsons coefficient, below which low injection rate gives rise to more LCT; whereas higher injection rate increases LCT in heterogeneous reservoirs. Both the geologic algorithm and connectivity analysis are very fast; therefore, the integrated methodology can be used as a quick tool to estimate local capillary trapping. It can also be used as a potential complement to the full-physics simulation to evaluate safe storage capacity.

Using Carbon Dioxide to Enhance Recovery of Methane from Gas Hydrate Reservoirs: Final Summary Report

DOE Office of Scientific and Technical Information (OSTI.GOV)

McGrail, B. Peter; Schaef, Herbert T.; White, Mark D.

2007-09-01

Carbon dioxide sequestration coupled with hydrocarbon resource recovery is often economically attractive. Use of CO2 for enhanced recovery of oil, conventional natural gas, and coal-bed methane are in various stages of common practice. In this report, we discuss a new technique utilizing CO2 for enhanced recovery of an unconventional but potentially very important source of natural gas, gas hydrate. We have focused our attention on the Alaska North Slope where approximately 640 Tcf of natural gas reserves in the form of gas hydrate have been identified. Alaska is also unique in that potential future CO2 sources are nearby, and petroleummore » infrastructure exists or is being planned that could bring the produced gas to market or for use locally. The EGHR (Enhanced Gas Hydrate Recovery) concept takes advantage of the physical and thermodynamic properties of mixtures in the H2O-CO2 system combined with controlled multiphase flow, heat, and mass transport processes in hydrate-bearing porous media. A chemical-free method is used to deliver a LCO2-Lw microemulsion into the gas hydrate bearing porous medium. The microemulsion is injected at a temperature higher than the stability point of methane hydrate, which upon contacting the methane hydrate decomposes its crystalline lattice and releases the enclathrated gas. Small scale column experiments show injection of the emulsion into a CH4 hydrate rich sand results in the release of CH4 gas and the formation of CO2 hydrate« less

Radioisotope tracer studies of inorganic carbon and Ca in microbially derived CaCO3

USGS Publications Warehouse

Yates, Kimberly K.; Robbins, Lisa L.

1999-01-01

Microbial calcification significantly impacts the cycling and deposition of inorganic carbon. This research employs 45Ca and 14C techniques as radioisotopic tracers to examine the role of cellular cycling of Ca2+ and inorganic carbon in CaCO3 precipitation by the unicellular green alga Nannochloris atomus. Implications of the effects of these physiological aspects on CaCO3 precipitation and the effects of microbial calcification on CaCO3 δ13C ratios are discussed. Results from pulse/chase experiments indicate that intracellular Ca2+ is incorporated into extracellular CaCO3. Intracellular inorganic carbon leaks from cells within 10 to 12 s after injection of unlabelled NaHCO3, providing a source of inorganic carbon for extracellular CaCO3. Cellular expulsion of calcium plays a key role in increasing the CaCO3 saturation state at the site of calcification. The δ13C ratios of microbial carbonates may vary depending on the amount of photorespiratory CO2 incorporated.

Pore-scale supercritical CO 2 dissolution and mass transfer under drainage conditions

DOE PAGES

Chang, Chun; Zhou, Quanlin; Oostrom, Mart; ...

2016-12-05

Recently, both core- and pore-scale imbibition experiments have shown non-equilibrium dissolution of supercritical CO 2 (scCO 2) and a prolonged depletion of residual scCO 2. In this paper, pore-scale scCO 2 dissolution and mass transfer under drainage conditions were investigated using a two-dimensional heterogeneous micromodel and a novel fluorescent water dye with a sensitive pH range between 3.7 and 6.5. Drainage experiments were conducted at 9 MPa and 40 °C by injecting scCO 2 into the sandstone-analogue pore network initially saturated by water without dissolved CO 2 (dsCO 2). During the experiments, time-lapse images of dye intensity, reflecting water pH,more » were obtained. These images show non-uniform pH in individual pores and pore clusters, with average pH levels gradually decreasing with time. Further analysis on selected pores and pore clusters shows that (1) rate-limited mass transfer prevails with slowly decreasing pH over time when the scCO 2-water interface area is low with respect to the volume of water-filled pores and pore clusters, (2) fast scCO 2 dissolution and phase equilibrium occurs when scCO 2 bubbles invade into water-filled pores, significantly enhancing the area-to-volume ratio, and (3) a transition from rate-limited to diffusion-limited mass transfer occurs in a single pore when a medium area-to-volume ratio is prevalent. The analysis also shows that two fundamental processes – scCO 2 dissolution at phase interfaces and diffusion of dsCO 2 at the pore scale (10–100 µm) observed after scCO 2 bubble invasion into water-filled pores without pore throat constraints – are relatively fast. The overall slow dissolution of scCO 2 in the millimeter-scale micromodel can be attributed to the small area-to-volume ratios that represent pore-throat configurations and characteristics of phase interfaces. Finally, this finding is applicable for the behavior of dissolution at pore, core, and field scales when water-filled pores and pore clusters of varying size are surrounded by scCO 2 at narrow pore throats.« less

Pore-scale supercritical CO 2 dissolution and mass transfer under drainage conditions

DOE Office of Scientific and Technical Information (OSTI.GOV)

Chang, Chun; Zhou, Quanlin; Oostrom, Mart

Recently, both core- and pore-scale imbibition experiments have shown non-equilibrium dissolution of supercritical CO 2 (scCO 2) and a prolonged depletion of residual scCO 2. In this paper, pore-scale scCO 2 dissolution and mass transfer under drainage conditions were investigated using a two-dimensional heterogeneous micromodel and a novel fluorescent water dye with a sensitive pH range between 3.7 and 6.5. Drainage experiments were conducted at 9 MPa and 40 °C by injecting scCO 2 into the sandstone-analogue pore network initially saturated by water without dissolved CO 2 (dsCO 2). During the experiments, time-lapse images of dye intensity, reflecting water pH,more » were obtained. These images show non-uniform pH in individual pores and pore clusters, with average pH levels gradually decreasing with time. Further analysis on selected pores and pore clusters shows that (1) rate-limited mass transfer prevails with slowly decreasing pH over time when the scCO 2-water interface area is low with respect to the volume of water-filled pores and pore clusters, (2) fast scCO 2 dissolution and phase equilibrium occurs when scCO 2 bubbles invade into water-filled pores, significantly enhancing the area-to-volume ratio, and (3) a transition from rate-limited to diffusion-limited mass transfer occurs in a single pore when a medium area-to-volume ratio is prevalent. The analysis also shows that two fundamental processes – scCO 2 dissolution at phase interfaces and diffusion of dsCO 2 at the pore scale (10–100 µm) observed after scCO 2 bubble invasion into water-filled pores without pore throat constraints – are relatively fast. The overall slow dissolution of scCO 2 in the millimeter-scale micromodel can be attributed to the small area-to-volume ratios that represent pore-throat configurations and characteristics of phase interfaces. Finally, this finding is applicable for the behavior of dissolution at pore, core, and field scales when water-filled pores and pore clusters of varying size are surrounded by scCO 2 at narrow pore throats.« less

Pore-scale supercritical CO 2 dissolution and mass transfer under drainage conditions

DOE Office of Scientific and Technical Information (OSTI.GOV)

Chang, Chun; Zhou, Quanlin; Oostrom, Mart

Abstract: Recently, both core- and pore-scale imbibition experiments have shown non-equilibrium dissolution of supercritical CO 2 (scCO 2) and a prolonged depletion of residual scCO 2. In this study, pore-scale scCO 2 dissolution and mass transfer under drainage conditions were investigated using a two-dimensional heterogeneous micromodel and a novel fluorescent water dye with a sensitive pH range between 3.7 and 6.5. Drainage experiments were conducted at 9 MPa and 40 °C by injecting scCO 2 into the sandstone-analogue pore network initially saturated by water without dissolved CO 2 (dsCO 2). During the experiments, time-lapse images of dye intensity, reflecting watermore » pH, were obtained. These images show non-uniform pH in individual pores and pore clusters, with average pH levels gradually decreasing with time. Further analysis on selected pores and pore clusters shows that (1) rate-limited mass transfer prevails with slowly decreasing pH over time when the scCO 2-water interface area is low with respect to the volume of water-filled pores and pore clusters, (2) fast scCO 2 dissolution and phase equilibrium occurs when scCO 2 bubbles invade into water-filled pores, significantly enhancing the area-to-volume ratio, and (3) a transition from rate-limited to diffusion-limited mass transfer occurs in a single pore when a medium area-to-volume ratio is prevalent. The analysis also shows that two fundamental processes – scCO 2 dissolution at phase interfaces and diffusion of dsCO 2 at the pore scale (10-100 µm) observed after scCO 2 bubble invasion into water-filled pores without pore throat constraints – are relatively fast. The overall slow dissolution of scCO 2 in the millimeter-scale micromodel can be attributed to the small area-to-volume ratios that represent pore-throat configurations and characteristics of phase interfaces. This finding is applicable for the behavior of dissolution at pore, core, and field scales when water-filled pores and pore clusters of varying size are surrounded by scCO 2 at narrow pore throats.« less

Experimental Studies on the Interaction of scCO2 and scCO2-SO2 With Rock Forming Minerals at Conditions of Geologic Carbon Storages - First Results

NASA Astrophysics Data System (ADS)

Erzinger, J.; Wilke, F.; Wiersberg, T.; Vasquez Parra, M.

2010-12-01

Co-injection of SO2 (plus possibly NOx and O2) during CO2 storage in deep saline aquifers may cause stronger brine acidification than CO2 alone. Because of that, we investigate chemical corrosion of rocks and rock-forming minerals with impure supercritical CO2 (scCO2) at possible storage conditions of >73.7 bar and >31°C. Contaminates were chosen with respect to the composition of CO2 captured industrially from coal-fired power plants using the oxyfuel technology. The resulting data should build a base for the long-term prediction of the behavior of CO2 in geologic storage reservoirs. Experiments of up to 1000 hrs duration have been performed with 10 natural mineral concentrates (calcite, dolomite, siderite, anhydrite, hematite, albite, microcline, kaolinite, muscovite, biotite) in 3n NaCl solution and pure scCO2 or scCO2+SO2 (99.5+0.5 vol%). The NaCl reaction fluid resembles the average salinity of deep formation waters of the North German Basin and is not free of oxygen. To increase reaction rates all minerals were ground and the reagents agitated either by stirring or shaking in autoclaves of about one liter in volume. The autoclaves consist of Hastelloy™ or ferromagnetic stainless steel fully coated with PTFE. We used in average 15 g of solids, 700 ml liquid, and the vessels were pressurized up to 100 bars with CO2 or CO2-SO2 mixture. Experiments were run at temperatures up to 90°C. Before, during and after the experiments small amounts fluids were sampled and analyzed for dissolved constituents and pH. Solid phases were characterized by XRF, XRD, and EMPA before and after the experiments. Pure scCO2 corrodes all carbonates, reacts only slightly with anhydrite, albite, and microcline at a minimum pH of 4, and does not recognizably interact with the others. After the experiment, albite has gained in a, not yet fully identified, carbonate phase which might be dawsonite. Reaction fluids of the experiments with scCO2+SO2 have mostly lower pH than using scCO2 alone, at which those with silicate phases have a lower pH (between 2 and 3) than experiments with carbonates. Fluid-mineral-interactions using scCO2-SO2 are thus much stronger and the concentrations of SO4 and cations in the reacting fluids are generally much higher, especially for Fe, Si and Al of silicates. However, intensity and rate of reactions are controlled by the availability of SO2 and apparently buffered by dissolution and precipitation processes. EMPA and Raman spectroscopy analyses are in progress to identify possible precipitated secondary products on mineral surfaces.

Corrosion of Pipeline and Wellbore Steel by Liquid CO2 Containing Trace Amounts of Water and SO2

NASA Astrophysics Data System (ADS)

McGrail, P.; Schaef, H. T.; Owen, A. T.

2009-12-01

Carbon dioxide capture and storage in deep saline formations is currently considered the most attractive option to reduce greenhouse gas emissions with continued use of fossil fuels for energy production. Transporting captured CO2 and injection into suitable formations for storage will necessarily involve pipeline systems and wellbores constructed of carbon steels. Industry standards currently require nearly complete dehydration of liquid CO2 to reduce corrosion in the pipeline transport system. However, it may be possible to establish a corrosion threshold based on H2O content in the CO2 that could allow for minor amounts of H2O to remain in the liquid CO2 and thereby eliminate a costly dehydration step. Similarly, trace amounts of sulfur and nitrogen compounds common in flue gas streams are currently removed through expensive desulfurization and catalytic reduction processes. Provided these contaminants could be safely and permanently transported and stored in the geologic reservoir, retrofits of existing fossil-fuel plants could address comprehensive emissions reductions, including CO2 at perhaps nearly the same capital and operating cost. Because CO2-SO2 mixtures have never been commercially transported or injected, both experimental and theoretical work is needed to understand corrosion mechanisms of various steels in these gas mixtures containing varying amounts of water. Experiments were conducted with common tool steel (AISI-01) and pipeline steel (X65) immersed in liquid CO2 at room temperature containing ~1% SO2 and varying amounts of H2O (0 to 2500 ppmw). A threshold concentration of H2O in the liquid CO2-SO2 mixture was established based on the absence of visible surface corrosion. For example, experiments exposing steel to liquid CO2-SO2 containing ~300 ppmw H2O showed a delay in onset of visible corrosion products and minimal surface corrosion was visible after five days of testing. However increasing the water content to 760 ppmw produced extensive surface corrosion after 48 hours at room temperature. Surface characterization by SEM showed one type of morphology that included large circular features radiating outward from a central structure. Chemical analyses obtained by SEM-EDX indicate the phases contained mostly Fe and S with minor amounts of Mn. Corrosion products completely covering the metal coupon surface were identified by XRD as iron sulfite hydrate (FeSO3●3H2O), with lesser amounts of gravegliaite (MnSO3●3H2O), and rozenite (Fe(SO4)●(H2O)4).

Preferential flow pathways revealed by field based stable isotope analysis of CO2 by mid-infrared laser spectroscopy

NASA Astrophysics Data System (ADS)

van Geldern, Robert; Nowak, Martin; Zimmer, Martin; Szizybalski, Alexandra; Myrttinen, Anssi; Barth, Johannes A. C.; Jost, Hj

2016-04-01

A newly developed and commercially available isotope ratio laser spectrometer for CO2 analyses has been tested during a 10-day field monitoring campaign at the Ketzin pilot site for CO2 storage in northern Germany. The laser instrument is based on tunable laser direct absorption in the mid-infrared. The instrument recorded a continuous 10-day carbon stable isotope data set with 30 minutes resolution directly on-site in a field-based laboratory container during a tracer experiment. To test the instruments performance and accuracy the monitoring campaign was accompanied by daily CO2 sampling for laboratory analyses with isotope ratio mass spectrometry (IRMS). The carbon stable isotope ratios measured by conventional IRMS technique and by the new mid-infrared laser spectrometer agree remarkably well within 2σ analytical precision (<0.3 ‰). This proves the capability of the new mid-infrared direct absorption technique to measure high precision and accurate real-time table isotope data directly in the field. The injected CO2 tracer had a distinct δ13C value that was largely different from the reservoir background value. The laser spectroscopy data revealed a prior to this study unknown, intensive dynamic with fast changing δ13C values. The arrival pattern of the tracer suggest that the observed fluctuations were probably caused by migration along separate and distinct preferential flow paths between injection well and observation well. The new technique might contribute to a better tracing of the migration of the underground CO2 plume and help to ensure the long-term integrity of the reservoir.

Effective CO2 sequestration monitoring using joint inversion result of seismic and electromagnetic data

NASA Astrophysics Data System (ADS)

Noh, K.; Jeong, S.; Seol, S. J.; Byun, J.; Kwon, T.

2015-12-01

Man-made carbon dioxide (CO2) released into the atmosphere is a significant contributor to the greenhouse gas effect and related global warming. Sequestration of CO2 into saline aquifers has been proposed as one of the most practical options of all geological sequestration possibilities. During CO2 geological sequestration, monitoring is indispensable to delineate the change of CO2 saturation and migration of CO2 in the subsurface. Especially, monitoring of CO2 saturation in aquifers provides useful information for determining amount of injected CO2. Seismic inversion can provide the migration of CO2 plume with high resolution because velocity is reduced when CO2 replaces the pore fluid during CO2 injection. However, the estimation of CO2 saturation using the seismic method is difficult due to the lower sensitivity of the velocity to the saturation when the CO2 saturation up to 20%. On the other hand, marine controlled-source EM (mCSEM) inversion is sensitive to the resistivity changes resulting from variations in CO2 saturation, even though it has poor resolution than seismic method. In this study, we proposed an effective CO2 sequestration monitoring method using joint inversion of seismic and mCSEM data based on a cross-gradient constraint. The method was tested with realistic CO2 injection models in a deep brine aquifer beneath a shallow sea which is selected with consideration for the access convenience for the installation of source and receiver and an environmental safety. Resistivity images of CO2 plume by the proposed method for different CO2 injection stages have been significantly improved over those obtained from individual EM inversion. In addition, we could estimate a reliable CO2 saturation by rock physics model (RPM) using the P-wave velocity and the improved resistivity. The proposed method is a basis of three-dimensional estimation of reservoir parameters such as porosity and fluid saturation, and the method can be also applied for detecting a reservoir and calculating the accurate oil and gas reserves.

Stimuli Responsive/Rheoreversible Hydraulic Fracturing Fluids for Enhanced Geothermal Energy Production (Part II)

DOE Office of Scientific and Technical Information (OSTI.GOV)

Bonneville, Alain; Jung, Hun Bok; Shao, Hongbo

We have used an environmentally friendly and recyclable hydraulic fracturing fluid - diluted aqueous solutions of polyallylamine or PAA – for reservoir stimulation in Enhanced Geothermal System (EGS). This fluid undergoes a controlled and large volume expansion with a simultaneous increase in viscosity triggered by CO2 at EGS temperatures. We are presenting here the results of laboratory-scale hydraulic fracturing experiment using the fluid on small cylindrical rock cores (1.59 cm in diameter and 5.08 cm in length) from the Coso geothermal field in California. Rock samples consisted of Mesozoic diorite metamorphosed to greenschist facies. The experiments were conducted on 5more » samples for realistic ranges of pressures (up to 275 bar) and temperatures (up to 210 °C) for both the rock samples and the injected fluid. After fracturing, cores were subjected to a CO2 leakage test, injection of KI solution, and X-ray microtomography (XMT) scanning to examine the formation and distribution of fractures. The design and conduct of these experiments will be presented and discussed in details. Based on the obtained XMT images, Computational Fluid Dynamics (CFD) simulations were then performed to visualize hydraulic fractures and compute the bulk permeability. OpenFOAM (OpenCFD Ltd., Reading, UK), was used to solve the steady state simulation. The flow predictions, based upon the laminar, 3-D, incompressible Navier-Stokes equations for fluid mass and momentum, show the remarkable stimulation of the permeability in the core samples and demonstrate the efficiency of such a CO2 triggered fluid in EGS.« less

Interpretaion of synthetic seismic time-lapse monitoring data for Korea CCS project based on the acoustic-elastic coupled inversion

NASA Astrophysics Data System (ADS)

Oh, J.; Min, D.; Kim, W.; Huh, C.; Kang, S.

2012-12-01

Recently, the CCS (Carbon Capture and Storage) is one of the promising methods to reduce the CO2 emission. To evaluate the success of the CCS project, various geophysical monitoring techniques have been applied. Among them, the time-lapse seismic monitoring is one of the effective methods to investigate the migration of CO2 plume. To monitor the injected CO2 plume accurately, it is needed to interpret seismic monitoring data using not only the imaging technique but also the full waveform inversion, because subsurface material properties can be estimated through the inversion. However, previous works for interpreting seismic monitoring data are mainly based on the imaging technique. In this study, we perform the frequency-domain full waveform inversion for synthetic data obtained by the acoustic-elastic coupled modeling for the geological model made after Ulleung Basin, which is one of the CO2 storage prospects in Korea. We suppose the injection layer is located in fault-related anticlines in the Dolgorae Deformed Belt and, for more realistic situation, we contaminate the synthetic monitoring data with random noise and outliers. We perform the time-lapse full waveform inversion in two scenarios. One scenario is that the injected CO2 plume migrates within the injection layer and is stably captured. The other scenario is that the injected CO2 plume leaks through the weak part of the cap rock. Using the inverted P- and S-wave velocities and Poisson's ratio, we were able to detect the migration of the injected CO2 plume. Acknowledgment This work was financially supported by the Brain Korea 21 project of Energy Systems Engineering, the "Development of Technology for CO2 Marine Geological Storage" program funded by the Ministry of Land, Transport and Maritime Affairs (MLTM) of Korea and the Korea CCS R&D Center (KCRC) grant funded by the Korea government (Ministry of Education, Science and Technology) (No. 2012-0008926).

System-level modeling for economic evaluation of geological CO2storage in gas reservoirs

DOE Office of Scientific and Technical Information (OSTI.GOV)

Zhang, Yingqi; Oldenburg, Curtis M.; Finsterle, Stefan

2006-03-02

One way to reduce the effects of anthropogenic greenhousegases on climate is to inject carbon dioxide (CO2) from industrialsources into deep geological formations such as brine aquifers ordepleted oil or gas reservoirs. Research is being conducted to improveunderstanding of factors affecting particular aspects of geological CO2storage (such as storage performance, storage capacity, and health,safety and environmental (HSE) issues) as well as to lower the cost ofCO2 capture and related processes. However, there has been less emphasisto date on system-level analyses of geological CO2 storage that considergeological, economic, and environmental issues by linking detailedprocess models to representations of engineering components andassociatedmore » economic models. The objective of this study is to develop asystem-level model for geological CO2 storage, including CO2 capture andseparation, compression, pipeline transportation to the storage site, andCO2 injection. Within our system model we are incorporating detailedreservoir simulations of CO2 injection into a gas reservoir and relatedenhanced production of methane. Potential leakage and associatedenvironmental impacts are also considered. The platform for thesystem-level model is GoldSim [GoldSim User's Guide. GoldSim TechnologyGroup; 2006, http://www.goldsim.com]. The application of the system modelfocuses on evaluating the feasibility of carbon sequestration withenhanced gas recovery (CSEGR) in the Rio Vista region of California. Thereservoir simulations are performed using a special module of the TOUGH2simulator, EOS7C, for multicomponent gas mixtures of methane and CO2.Using a system-level modeling approach, the economic benefits of enhancedgas recovery can be directly weighed against the costs and benefits ofCO2 injection.« less

Monitoring CO 2 sequestration into deep saline aquifer and associated salt intrusion using coupled multiphase flow modeling and time lapse electrical resistivity tomography

DOE Office of Scientific and Technical Information (OSTI.GOV)

Chuan Lu; CHI Zhang; Hai Hanag

2014-04-01

Successful geological storage and sequestration of carbon dioxide (CO2) require efficient monitoring of the migration of CO2 plume during and after large-scale injection in order to verify the containment of the injected CO2 within the target formation and to evaluate potential leakage risk. Field studies have shown that surface and cross-borehole electrical resistivity tomography (ERT) can be a useful tool in imaging and characterizing solute transport in heterogeneous subsurface. In this synthetic study, we have coupled a 3-D multiphase flow model with a parallel 3-D time-lapse ERT inversion code to explore the feasibility of using time-lapse ERT for simultaneously monitoringmore » the migration of CO2 plume in deep saline formation and potential brine intrusion into shallow fresh water aquifer. Direct comparisons of the inverted CO2 plumes resulting from ERT with multiphase flow simulation results indicate the ERT could be used to delineate the migration of CO2 plume. Detailed comparisons on the locations, sizes and shapes of CO2 plume and intruded brine plumes suggest that ERT inversion tends to underestimate the area review of the CO2 plume, but overestimate the thickness and total volume of the CO2 plume. The total volume of intruded brine plumes is overestimated as well. However, all discrepancies remain within reasonable ranges. Our study suggests that time-lapse ERT is a useful monitoring tool in characterizing the movement of injected CO2 into deep saline aquifer and detecting potential brine intrusion under large-scale field injection conditions.« less

Experimental Investigations into CO2 Interactions with Injection Well Infrastructure for CO2 Storage

NASA Astrophysics Data System (ADS)

Syed, Amer; Shi, Ji-Quan; Durucan, Sevket; Nash, Graham; Korre, Anna

2013-04-01

Wellbore integrity is an essential requirement to ensure the success of a CO2 Storage project as leakage of CO2 from the injection or any other abandoned well in the storage complex, could not only severely impede the efficiency of CO2 injection and storage but also may result in potential adverse impact on the surrounding environment. Early research has revealed that in case of improper well completions and/or significant changes in operating bottomhole pressure and temperature could lead to the creation of microannulus at cement-casing interface which may constitute a preferential pathway for potential CO2 leakage during and post injection period. As a part of a European Commission funded CO2CARE project, the current research investigates the sealing behaviour of such microannulus at the cement-casing interface under simulated subsurface reservoir pressure and temperature conditions and uses the findings to develop a methodology to assess the overall integrity of CO2 storage. A full scale wellbore experimental test set up was constructed for use under elevated pressure and temperature conditions as encountered in typical CO2 storage sites. The wellbore cell consists of an assembly of concentric elements of full scale casing (Diameter= 0.1524m), cement sheath and an outer casing. The stainless steel outer ring is intended to simulate the stiffness offered by the reservoir rock to the displacement applied at the wellbore. The Central Loading Mechanism (CLM) consists of four case hardened shoes that can impart radial load onto the well casing. The radial movement of the shoes is powered through the synchronised movement of four precision jacks controlled hydraulically which could impart radial pressures up to 15 MPa. The cell body is a gas tight enclosure that houses the wellbore and the central loading mechanism. The setup is enclosed in a laboratory oven which acts both as temperature and safety enclosure. Prior to a test, cement mix is set between the casing and outer steel ring. A radial pressure is maintained on the wellbore casing during cement setting, i.e., the casing is in a state of tension, so that a microannulus can be created by subsequent contraction of CLM when the radial pressure is relieved. The aperture (permeability) of the microannulus can be controlled by varying the CLM pressure on the casing, which is maintained throughout a flow test. During a test, pure CO2/brine saturated CO2 is flown through the microannulus over a period of time to study its permeability behaviour under simulated downhole conditions. Evolution in permeability is monitored and the effluent is collected and analysed regularly. These experimental results will be used as an input to implement a time-dependent microannulus permeability in the numerical model to assess the impact of such behaviour on the storage performance of a CO2 storage reservoir. The results of the first set of experiments, where the permeability behaviour of pure CO2 was monitored over a 3 months period, are presented and discussed in this paper.

Carbon biofixation and lipid composition of an acidophilic microalga cultivated on treated wastewater supplied with different CO2 levels.

PubMed

Neves, Fábio de Farias; Hoinaski, Leonardo; Rörig, Leonardo Rubi; Derner, Roberto Bianchini; de Melo Lisboa, Henrique

2018-05-15

This study evaluated productivity, CO 2 biofixation, and lipid content in biomass of the acidophilic microalga Chlamydomonas acidophila LAFIC-004 cultivated with five different carbon dioxide concentrations. The influence of carbon dioxide concentration on nutrient removal and pH was also investigated. Treated wastewater (secondary effluent) was used as culture medium. Five experimental setups were tested: T-0% - injection of atmospheric air (0.038% CO 2 ), T-5% (5% CO 2 ), T-10% (10% CO 2 ), T-15% (15% CO 2 ) and T-20% (20% CO 2 ). The T-5% and T-10% experiments showed the highest values of productivity and CO 2 biofixation, and maximum biomass dry weight was 0.48 ± 0.02 and 0.51 ± 0.03 g L -1 , respectively. This acidophilic microalga proved to be suitable for carbon biofixation and removal of nutrients from secondary effluent of wastewater treatment plants with high CO 2 concentration. All assays were performed without pH control. This microalga species presented high lipid content. However, fatty acid methyl esters (FAME) are not suitable for biodiesel use.

Opportunities for increasing CO 2 storage in deep, saline formations by active reservoir management and treatment of extracted formation water: Case study at the GreenGen IGCC facility, Tianjin, PR China

DOE PAGES

Ziemkiewicz, Paul; Stauffer, Philip H.; Sullivan-Graham, Jeri; ...

2016-08-04

Carbon capture, utilization and storage (CCUS) seeks beneficial applications for CO 2 recovered from fossil fuel combustion. This study evaluated the potential for removing formation water to create additional storage capacity for CO 2, while simultaneously treating the produced water for beneficial use. Furthermore, the process would control pressures within the target formation, lessen the risk of caprock failure, and better control the movement of CO 2 within that formation. The project plans to highlight the method of using individual wells to produce formation water prior to injecting CO 2 as an efficient means of managing reservoir pressure. Because themore » pressure drawdown resulting from pre-injection formation water production will inversely correlate with pressure buildup resulting from CO 2 injection, it can be proactively used to estimate CO 2 storage capacity and to plan well-field operations. The project studied the GreenGen site in Tianjin, China where Huaneng Corporation is capturing CO 2 at a coal fired IGCC power plant. Known as the Tianjin Enhanced Water Recovery (EWR) project, local rock units were evaluated for CO 2 storage potential and produced water treatment options were then developed. Average treatment cost for produced water with a cooling water treatment goal ranged from 2.27 to 2.96 US$/m 3 (recovery 95.25%), and for a boiler water treatment goal ranged from 2.37 to 3.18 US$/m 3 (recovery 92.78%). Importance analysis indicated that water quality parameters and transportation are significant cost factors as the injection-extraction system is managed over time. Our study found that in a broad sense, active reservoir management in the context of CCUS/EWR is technically feasible. In addition, criteria for evaluating suitable vs. unsuitable reservoir properties, reservoir storage (caprock) integrity, a recommended injection/withdrawal strategy and cost estimates for water treatment and reservoir management are proposed.« less

Opportunities for increasing CO 2 storage in deep, saline formations by active reservoir management and treatment of extracted formation water: Case study at the GreenGen IGCC facility, Tianjin, PR China

DOE Office of Scientific and Technical Information (OSTI.GOV)

Ziemkiewicz, Paul; Stauffer, Philip H.; Sullivan-Graham, Jeri

Carbon capture, utilization and storage (CCUS) seeks beneficial applications for CO 2 recovered from fossil fuel combustion. This study evaluated the potential for removing formation water to create additional storage capacity for CO 2, while simultaneously treating the produced water for beneficial use. Furthermore, the process would control pressures within the target formation, lessen the risk of caprock failure, and better control the movement of CO 2 within that formation. The project plans to highlight the method of using individual wells to produce formation water prior to injecting CO 2 as an efficient means of managing reservoir pressure. Because themore » pressure drawdown resulting from pre-injection formation water production will inversely correlate with pressure buildup resulting from CO 2 injection, it can be proactively used to estimate CO 2 storage capacity and to plan well-field operations. The project studied the GreenGen site in Tianjin, China where Huaneng Corporation is capturing CO 2 at a coal fired IGCC power plant. Known as the Tianjin Enhanced Water Recovery (EWR) project, local rock units were evaluated for CO 2 storage potential and produced water treatment options were then developed. Average treatment cost for produced water with a cooling water treatment goal ranged from 2.27 to 2.96 US$/m 3 (recovery 95.25%), and for a boiler water treatment goal ranged from 2.37 to 3.18 US$/m 3 (recovery 92.78%). Importance analysis indicated that water quality parameters and transportation are significant cost factors as the injection-extraction system is managed over time. Our study found that in a broad sense, active reservoir management in the context of CCUS/EWR is technically feasible. In addition, criteria for evaluating suitable vs. unsuitable reservoir properties, reservoir storage (caprock) integrity, a recommended injection/withdrawal strategy and cost estimates for water treatment and reservoir management are proposed.« less

Potential for iron oxides to control metal releases in CO2 sequestration scenarios

USGS Publications Warehouse

Berger, P.M.; Roy, W.R.

2011-01-01

The potential for the release of metals into groundwater following the injection of carbon dioxide (CO2) into the subsurface during carbon sequestration projects remains an open research question. Changing the chemical composition of even the relatively deep formation brines during CO2 injection and storage may be of concern because of the recognized risks associated with the limited potential for leakage of CO2-impacted brine to the surface. Geochemical modeling allows for proactive evaluation of site geochemistry before CO2 injection takes place to predict whether the release of metals from iron oxides may occur in the reservoir. Geochemical modeling can also help evaluate potential changes in shallow aquifers were CO2 leakage to occur near the surface. In this study, we created three batch-reaction models that simulate chemical changes in groundwater resulting from the introduction of CO2 at two carbon sequestration sites operated by the Midwest Geological Sequestration Consortium (MGSC). In each of these models, we input the chemical composition of groundwater samples into React??, and equilibrated them with selected mineral phases and CO 2 at reservoir pressure and temperature. The model then simulated the kinetic reactions with other mineral phases over a period of up to 100 years. For two of the simulations, the water was also at equilibrium with iron oxide surface complexes. The first model simulated a recently completed enhanced oil recovery (EOR) project in south-central Illinois in which the MGSC injected into, and then produced CO2, from a sandstone oil reservoir. The MGSC afterwards periodically measured the brine chemistry from several wells in the reservoir for approximately two years. The sandstone contains a relatively small amount of iron oxide, and the batch simulation for the injection process showed detectable changes in several aqueous species that were attributable to changes in surface complexation sites. After using the batch reaction configuration to match measured geochemical changes due to CO2 injection, we modeled potential changes in groundwater chemistry at the Illinois Basin - Decatur Project (IBDP) site in Decatur, Illinois, USA. At the IBDP, the MGSC will inject 1 million tonnes of CO2 over the course of three years at a depth of about 2 km below the surface into the Mt. Simon Formation. Sections of the Mt. Simon Formation contain up to 10 percent iron oxide, and therefore surface complexes on iron oxides should play a major role in controlling brine chemistry. The batch simulation of this system showed a significant decrease in pH after the injection of CO2 with corresponding changes in brine chemistry resulting from both mineral precipitation/dissolution reactions and changes in the chemistry on iron oxide surfaces. To ensure the safety of shallow drinking water sources, there are several shallow monitoring wells at the IBDP that the MGSC samples regularly to determine baseline chemical concentrations. Knowing what geochemical parameters are most sensitive to CO2 disturbances allows us to focus monitoring efforts. Modeling a major influx of CO2 into the shallow groundwater allowed us to determine that were an introduction of CO2 to occur, the only immediate effect will be dolomite dissolution and calcite precipitation. ?? 2011 Published by Elsevier Ltd.

Fayalite Dissolution and Siderite Formation in Water-Saturated Supercritical CO2

DOE Office of Scientific and Technical Information (OSTI.GOV)

Qafoku, Odeta; Kovarik, Libor; Kukkadapu, Ravi K.

2012-11-25

Olivines, a significant constituent of basaltic rocks, have the potential to immobilize permanently CO2 after it is injected in the deep subsurface, due to carbonation reactions occurring between CO2 and the host rock. To investigate the reactions of fayalitic olivine with supercritical CO2 (scCO2) and formation of mineral carbonates, experiments were conducted at temperatures of 35 °C to 80 °C, 90 atm pressure and anoxic conditions. For every temperature, the dissolution of fayalite was examined both in the presence of liquid water and H2O-saturated scCO2. The experiments were conducted in a high pressure batch reactor at reaction time extending upmore » to 85 days. The newly formed products were characterized using a comprehensive suite of bulk and surface characterization techniques X-ray diffraction, Transmission/Emission Mössbauer Spectroscopy, Scanning Electron Microscopy coupled with Focused Ion Beam, and High Resolution Transmission Electron Microscopy. Siderite with rhombohedral morphology was formed at 35 °C, 50 °C, and 80 °C in the presence of liquid water and scCO2. In H2O-saturated scCO2, the formation of siderite was confirmed only at high temperature (80 °C). Characterization of reacted samples in H2O-saturated scCO2 with high resolution TEM indicated that siderite formation initiated inside voids created during the initial steps of fayalite dissolution. Later stages of fayalite dissolution result in the formation of siderite in layered vertical structures, columns or pyramids with a rhombus base morphology.« less

Control of spontaneous combustion of coal in goaf at high geotemperatureby injecting liquid carbon dioxide: inertand cooling characteristics of coal

NASA Astrophysics Data System (ADS)

Liu, Zhenling; Wen, Hu; Yu, Zhijin; Wang, Chao; Ma, Li

2018-02-01

The spontaneous combustion of coal in goaf at high geo temperatures is threatening safety production in coalmine. The TG-DSC is employed to study the variation of mass and energy at 4 atmospheres (mixed gases of N2, O2 and CO2) and heating rates (10°C/min) during oxidation of coal samples. The apparent activation energy and pre-exponential factor of coal oxidation decrease rapidly with increasing theCO2 concentration. Furthermore, its reaction rate is slow, its heat released reduces. Based on the conditions of 1301 face in the Longgucoalmine, a three-dimensional geometry model is developed to simulate the distributions stream field and temperature field and the variation characteristics ofCO2 concentration field after injecting liquidCO2. The results indicate that oxygen reached to depths of˜120m in goaf, 100m in the side of inlet air, and 10m in the side of outlet air before injecting liquidCO2. After injecting liquidCO2for 28.8min, the width of oxidation and heat accumulation zone is shortened by 20m, and the distance is 80m in the side of working face and 40˜60m in goafin the direction of dip affected by temperature.

Application of open-path Fourier transform infrared spectroscopy for atmospheric monitoring of a CO2 back-production experiment at the Ketzin pilot site (Germany).

PubMed

Sauer, Uta; Borsdorf, H; Dietrich, P; Liebscher, A; Möller, I; Martens, S; Möller, F; Schlömer, S; Schütze, C

2018-02-03

During a controlled "back-production experiment" in October 2014 at the Ketzin pilot site, formerly injected CO 2 was retrieved from the storage formation and directly released to the atmosphere via a vent-off stack. Open-path Fourier transform infrared (OP FTIR) spectrometers, on-site meteorological parameter acquisition systems, and distributed CO 2 point sensors monitored gas dispersion processes in the near-surface part of the atmospheric boundary layer. The test site provides a complex and challenging mosaic-like surface setting for atmospheric monitoring which can also be found at other storage sites. The main aims of the atmospheric monitoring of this experiment were (1) to quantify temporal and spatial variations in atmospheric CO 2 concentrations around the emitting vent-off stack and (2) to test if and how atmospheric monitoring can cope with typical environmental and operational challenges. A low environmental risk was encountered during the whole CO 2 back-production experiment. The study confirms that turbulent wind conditions favor atmospheric mixing processes and are responsible for rapid dilution of the released CO 2 leading to decreased detectability at all sensors. In contrast, calm and extremely stable wind conditions (especially occurring during the night) caused an accumulation of gases in the near-ground atmospheric layer with the highest amplitudes in measured gas concentration. As an important benefit of OP FTIR spectroscopic measurements and their ability to detect multiple gas species simultaneously, emission sources could be identified to a much higher certainty. Moreover, even simulation models using simplified assumptions help to find suitable monitoring network designs and support data analysis for certain wind conditions in such a complex environment.

Field demonstration of CO2 leakage detection and potential impacts on groundwater quality at Brackenridge Field Laboratory

NASA Astrophysics Data System (ADS)

Zou, Y.; Yang, C.; Guzman, N.; Delgado, J.; Mickler, P. J.; Horvoka, S.; Trevino, R.

2015-12-01

One concern related to GCS is possible risk of unintended CO2 leakage from the storage formations into overlying potable aquifers on underground sources of drinking water (USDW). Here we present a series of field tests conducted in an alluvial aquifer which is on a river terrace at The University of Texas Brackenridge Field Laboratory. Several shallow groundwater wells were completed to the limestone bedrock at a depth of 6 m and screened in the lower 3 m. Core sediments recovered from the shallow aquifer show that the sediments vary in grain size from clay-rich layers to coarse sandy gravels. Two main types of field tests were conducted at the BFL: single- (or double-) well push-pull test and pulse-like CO2 release test. A single- (or double-) well push-pull test includes three phases: the injection phase, the resting phase and pulling phase. During the injection phase, groundwater pumped from the shallow aquifer was stored in a tank, equilibrated with CO2 gasand then injected into the shallow aquifer to mimic CO2 leakage. During the resting phase, the groundwater charged with CO2 reacted with minerals in the aquifer sediments. During the pulling phase, groundwater was pumped from the injection well and groundwater samples were collected continuously for groundwater chemistry analysis. In such tests, large volume of groundwater which was charged with CO2 can be injected into the shallow aquifer and thus maximize contact of groundwater charged with CO2. Different than a single- (or double-) well push-pull test, a pulse-like CO2 release test for validating chemical sensors for CO2 leakage detection involves a CO2 release phase that CO2 gas was directly bubbled into the testing well and a post monitoring phase that groundwater chemistry was continuously monitored through sensors and/or grounder sampling. Results of the single- (or double-) well push-pull tests conducted in the shallow aquifer shows that the unintended CO2 leakage could lead to dissolution of carbonates and some silicates and mobilization of heavy metals from the aquifer sediments to groundwater, however, such mobilization posed no risks on groundwater quality at this site. The pulse-like tests have demonstrated it is plausible to use chemical sensors for CO2 leakage detection in groundwater.

Hydraulic and Mechanical Effects from Gas Hydrate Conversion and Secondary Gas Hydrate Formation during Injection of CO2 into CH4-Hydrate-Bearing Sediments

NASA Astrophysics Data System (ADS)

Bigalke, N.; Deusner, C.; Kossel, E.; Schicks, J. M.; Spangenberg, E.; Priegnitz, M.; Heeschen, K. U.; Abendroth, S.; Thaler, J.; Haeckel, M.

2014-12-01

The injection of CO2 into CH4-hydrate-bearing sediments has the potential to drive natural gas production and simultaneously sequester CO2 by hydrate conversion. The process aims at maintaining the in situ hydrate saturation and structure and causing limited impact on soil hydraulic properties and geomechanical stability. However, to increase hydrate conversion yields and rates it must potentially be assisted by thermal stimulation or depressurization. Further, secondary formation of CO2-rich hydrates from pore water and injected CO2 enhances hydrate conversion and CH4 production yields [1]. Technical stimulation and secondary hydrate formation add significant complexity to the bulk conversion process resulting in spatial and temporal effects on hydraulic and geomechanical properties that cannot be predicted by current reservoir simulation codes. In a combined experimental and numerical approach, it is our objective to elucidate both hydraulic and mechanical effects of CO2 injection and CH4-CO2-hydrate conversion in CH4-hydrate bearing soils. For the experimental approach we used various high-pressure flow-through systems equipped with different online and in situ monitoring tools (e.g. Raman microscopy, MRI and ERT). One particular focus was the design of triaxial cell experimental systems, which enable us to study sample behavior even during large deformations and particle flow. We present results from various flow-through high-pressure experimental studies on different scales, which indicate that hydraulic and geomechanical properties of hydrate-bearing sediments are drastically altered during and after injection of CO2. We discuss the results in light of the competing processes of hydrate dissociation, hydrate conversion and secondary hydrate formation. Our results will also contribute to the understanding of effects of temperature and pressure changes leading to dissociation of gas hydrates in ocean and permafrost systems. [1] Deusner C, Bigalke N, Kossel E, Haeckel M. Methane Production from Gas Hydrate Deposits through Injection of Supercritical CO2. Energies 2012:5(7): 2112-2140.

Impact of methanol-gasoline fuel blend on the fuel consumption and exhaust emission of a SI engine

NASA Astrophysics Data System (ADS)

Rifal, Mohamad; Sinaga, Nazaruddin

2016-04-01

In this study, the effect of methanol-gasoline fuel blend (M15, M30 and M50) on the fuel consumption and exhaust emission of a spark ignition engine (SI) were investigated. In the experiment, an engine four-cylinder, four stroke injection system (engine of Toyota Kijang Innova 1TR-FE) was used. Test were did to know the relation of fuel consumption and exhaust emission (CO, CO2, HC) were analyzed under the idle throttle operating condition and variable engine speed ranging from 1000 to 4000 rpm. The experimental result showed that the fuel consumption decrease with the use of methanol. It was also shown that the CO and HC emission were reduced with the increase methanol content while CO2 were increased.

[Experimental study of brain lesions after combined coaxial exposure to high-peaked pulse wave form CO2 and Nd: YAG lasers on the brain].

PubMed

Tsuyumu, M; Verasques, G; Yamazaki, S; Kuroiwa, T; Suzuki, R; Takei, H; Suzuki, K; Inaba, Y

1985-04-01

The CO2 laser is useful for cutting and vaporization but not for coagulation and hemostasis. On the contrary, YAG laser is effective for coagulation and hemostasis but not for cutting. The purpose of this study is to examine the effect of the exposure of combined, coaxial CO2 and YAG laser on the animal brain to supplement the advantages and draw-backs of each other. To compare these results, each of non-combined pulse wave form CO2 and YAG lasers was employed separately. The lasers in this study were pulse wave form CO2 and YAG lasers, employed separately or simultaneously using 130 YZ of Nihon Infrared Industries Company. Japanese white rabbits were anesthetized with pentobarbital. Fronto-parietal burr holes were made, the dura was removed and then Evans blue solution was injected intravenously. The lasers were employed to the cerebral cortex without great vessels using a micromanipulator attached to the operative microscope with a distance of 30 cm. The spot size was 700 mu for CO2 laser and 1200 mu for YAG laser. The first experiment was to see the effect of nine combinations of simultaneous coaxial CO2 of 2, 4 and 8 watts and YAG lasers of 10, 20 and 40 watts, 1 sec on the brain. In the second experiment, also combining two lasers, the exposure time of YAG laser was elongated from 1 or 2 seconds into 2 or 4 seconds and the arrangement of powers was the same as that of the first experiment. The lesions were thus made in 18 different conditions.(ABSTRACT TRUNCATED AT 250 WORDS)

Impact of hydrogeological and geomechanical properties on surface uplift at a CO2 injection site: Parameter estimation and uncertainty quantification

NASA Astrophysics Data System (ADS)

Newell, P.; Yoon, H.; Martinez, M. J.; Bishop, J. E.; Arnold, B. W.; Bryant, S.

2013-12-01

It is essential to couple multiphase flow and geomechanical response in order to predict a consequence of geological storage of CO2. In this study, we estimate key hydrogeologic features to govern the geomechanical response (i.e., surface uplift) at a large-scale CO2 injection project at In Salah, Algeria using the Sierra Toolkit - a multi-physics simulation code developed at Sandia National Laboratories. Importantly, a jointed rock model is used to study the effect of postulated fractures in the injection zone on the surface uplift. The In Salah Gas Project includes an industrial-scale demonstration of CO2 storage in an active gas field where CO2 from natural gas production is being re-injected into a brine-filled portion of the structure downdip of the gas accumulation. The observed data include millimeter scale surface deformations (e.g., uplift) reported in the literature and injection well locations and rate histories provided by the operators. Our preliminary results show that the intrinsic permeability and Biot coefficient of the injection zone are important. Moreover pre-existing fractures within the injection zone affect the uplift significantly. Estimation of additional (i.e., anisotropy ratio) and coupled parameters will help us to develop models, which account for the complex relationship between mechanical integrity and CO2 injection-induced pressure changes. Uncertainty quantification of model predictions will be also performed using various algorithms including null-space Monte Carlo and polynomial-chaos expansion methods. This work will highlight that our coupled reservoir and geomechanical simulations associated with parameter estimation can provide a practical solution for designing operating conditions and understanding subsurface processes associated with the CO2 injection. This work is supported as part of the Center for Frontiers of Subsurface Energy Security, an Energy Frontier Research Center funded by the U.S. Department of Energy, Office of Science, Office of Basic Energy Sciences under Award Number DE-SC0001114. Sandia National Laboratories is a multi-program laboratory managed and operated by Sandia Corporation, a wholly owned subsidiary of Lockheed Martin Corporation, for the U.S. Department of Energy's National Nuclear Security Administration under contract DE-AC04-94AL85000.

Experimental study of two-phase fluid flow in two different porosity types of sandstone by P-wave velocity and electrical Impedance measurement

NASA Astrophysics Data System (ADS)

Honda, H.; Mitani, Y.; Kitamura, K.; Ikemi, H.; Takaki, S.

2015-12-01

Carbon dioxide (CO2) capture and storage (CCS) is recently expected as the promising method to reduce greenhouse gas emissions. It is important to investigate CO2 behavior in the reservoir, to evaluate the safety and to account the stored CO2 volume. In this study, experimental investigation is conducted to discuss the relationships between injected fluid speed (Flow rate: FR) or capillary number (Ca) and non-wetting fluid flow by compressional wave velocity (Vp) and electrical impedance (Z). In the experiment, N2 and supercritical CO2 were injected into the two sandstones with different porosity (φ), Berea sandstone (φ: 18 %), and Ainoura sandstone (φ: 11.9 %). The dimension of the rock specimens is cored cylinder with a 35 mm diameter and 70 mm height. Experimental conditions are nearly same as the reservoir of deep underground (Confining pressure:15MPa, 40℃). Initial conditions of the specimen are brine (0.1wt%-KCl) saturated. Four piezo-electrical transducers (PZTs) are set on the each surface of the top, middle, lower of the specimen to monitor the CO2 bahavior by Vp. To measuring Z, we use for electrodes method with Ag-AgCl electrodes. Four electrodes are wounded around specimen on the both sides of PZTs. We measured the changes of these parameters with injecting N2, injected fluid speed (FR), the differential pore pressure (DP), N2 saturation (SN2), P-wave velocity (Vp) and electrical impedance (Z), respectively. We also estimated the Ca from measured FR. From these experimental results, there are no obvious Vp changes with increasing Ca, while Z measurement indicates clear and continuous increment. In regards to Vp, Vp reduced at the small FR (0.1 to 0.2 ml/min). As the Ca increases, Vp doesn't indicate large reduction. On the other hand, Z is more sensitive to change the fluid saturation than Vp. It is well-known that both of Vp and Z are the function of fluid saturation. Though, these experimental results are not consistent with previous studies. In this study, we will discuss this mismatch by using fluid mechanical theory and numerical simulation of two-phase fluid flow in porous geological medium based on experimental results of two different types of sandstone.

Advanced wastewater treatment using microalgae: effect of temperature on removal of nutrients and organic carbon

NASA Astrophysics Data System (ADS)

Mohamad, Shurair; Fares, Almomani; Judd, Simon; Bhosale, Rahul; Kumar, Anand; Gosh, Ujjal; Khreisheh, Majeda

2017-05-01

This study evaluated the use of mixed indigenous microalgae (MIMA) as a treatment process for wastewaters and CO2 capturing technology at different temperatures. The study follows the growth rate of MIMA, CO2 Capturing from flue gas, removals of organic matter and nutrients from three types of wastewater (primary effluent, secondary effluent and septic effluent). A noticeable difference between the growth patterns of MIMA was observed at different CO2 and different operational temperatures. MIMA showed the highest growth grate when injected with CO2 dosage of 10% compared to the growth for the systems injected with 5% and 15 % of CO2. Ammonia and phosphorus removals for Spirulina were 69%, 75%, and 83%, and 20%, 45% and 75 % for the media injected with 0, 5 and 10% CO2. The results of this study show that simple and cost-effective microalgae-based wastewater treatment systems can be successfully employed at different temperatures as a successful CO2 capturing technology even with the small probability of inhibition at high temperatures.

Multistaged stokes injected Raman capillary waveguide amplifier

DOEpatents

Kurnit, Norman A.

1980-01-01

A multistaged Stokes injected Raman capillary waveguide amplifier for providing a high gain Stokes output signal. The amplifier uses a plurality of optically coupled capillary waveguide amplifiers and one or more regenerative amplifiers to increase Stokes gain to a level sufficient for power amplification. Power amplification is provided by a multifocused Raman gain cell or a large diameter capillary waveguide. An external source of CO.sub.2 laser radiation can be injected into each of the capillary waveguide amplifier stages to increase Raman gain. Devices for injecting external sources of CO.sub.2 radiation include: dichroic mirrors, prisms, gratings and Ge Brewster plates. Alternatively, the CO.sub.2 input radiation to the first stage can be coupled and amplified between successive stages.

Olivine dissolution in the presence of heterotrophic bacteria (Pseudomonas reactants) extracted from Icelandic groundwater of the CO2 injection pilot site

NASA Astrophysics Data System (ADS)

Shirokova, Liudmila; Pokrovsky, Oleg; Benezeth, Pascale; Gerard, Emmanuelle; Menez, Benedicte; Alfredsson, Helgi

2010-05-01

This work is aimed at experimental modeling of the effect of heterotrophic bacteria on dissolution of important rock-forming mineral, olivine, at the conditions of CO2 storage and sequestration. Heterotrophic aerobic gram-negative bacteria were extracted from deep underground water (HK31, 1700 m deep and, t = 25-30°C) of basaltic aquifer located within the Hellisheidi CO2 injection pilot site (Iceland). Following this sampling, we separated, using culture on nutrient agar plates, four different groups of gram-negative aerobic bacteria. The enzymatic activity of studied species has been evaluated using Biolog Ecoplates and their genetic identification was performed using 18-S RNA analysis. The optimal growth conditions of bacteria on Brain Hearth Broth nutrient have been determined as 5 to 37°C and growth media pH varied from 7.0-8.2. Culturing experiments allowed determining the optimal physico-chemical conditions for bacteria experiments in the presence of basic Ca, Mg-containing silicates. Olivine (Fo92) was chosen as typical mineral of basalt, widely considered in carbon dioxide sequestration mechanisms. Dissolution experiments were performed in constant-pH (7 to 9), bicarbonate-buffered (0.001 to 0.05 M) nutrient-diluted media in batch reactors at 0-30 bars of CO2 in the presence of various biomass of Pseudomonas reactants. The release rate of magnesium, silica and iron was measured as a function of time in the presence of live, actively growing, dead (autoclaved or glutaraldehyde-treated) cells and bacteria exometabolites. Both nutrient media diluted 10 times (to 100 mg DOC/L) and inert electrolyte (NaCl, no DOC) were used. Our preliminary results indicate that the pH and dissolved organic matter are the first-order parameters that control the element release from olivine at far from equilibrium conditions. The SEM investigation of reacted surfaces reveal formation of surface roughness with much stronger mineral alteration in the presence of live bacteria compared to experiments with dead biomass. Overall, this work allows better understanding of microbially-affected silicate dissolution in basaltic aquifers and provides a firm methodological basis for constructing the mixed-flow reactors for studying the interaction of heterotrophic bacteria with rock-forming silicates at the environmental conditions of CO2-storage.

Modelling of Seismic and Resistivity Responses during the Injection of CO2 in Sandstone Reservoir

NASA Astrophysics Data System (ADS)

Omar, Muhamad Nizarul Idhafi Bin; Almanna Lubis, Luluan; Nur Arif Zanuri, Muhammad; Ghosh, Deva P.; Irawan, Sonny; Regassa Jufar, Shiferaw

2016-07-01

Enhanced oil recovery plays vital role in production phase in a producing oil field. Initially, in many cases hydrocarbon will naturally flow to the well as respect to the reservoir pressure. But over time, hydrocarbon flow to the well will decrease as the pressure decrease and require recovery method so called enhanced oil recovery (EOR) to recover the hydrocarbon flow. Generally, EOR works by injecting substances, such as carbon dioxide (CO2) to form a pressure difference to establish a constant productive flow of hydrocarbon to production well. Monitoring CO2 performance is crucial in ensuring the right trajectory and pressure differences are established to make sure the technique works in recovering hydrocarbon flow. In this paper, we work on computer simulation method in monitoring CO2 performance by seismic and resistivity model, enabling geoscientists and reservoir engineers to monitor production behaviour as respect to CO2 injection.

Consequence of dopamine D2 receptor blockade on the hyperphagic effect induced by cannabinoid CB1 and CB2 receptors in layers.

PubMed

Khodadadi, M; Zendehdel, M; Baghbanzadeh, A; Babapour, V

2017-10-01

1. Endocannabinoids (ECBs) and their receptors play a regulatory function on several physiological processes such as feed-intake behaviour, mainly in the brain. This study was carried out in order to investigate the effects of the dopaminergic D1 and D2 receptors on CB1/CB2 ECB receptor-induced hyperphagia in 3-h feed-deprived neonatal layer chickens. 2. A total of 8 experiments were designed to explore the interplay of these two modulatory systems on feed intake in neonatal chickens. In Experiment 1, chickens were intracerebroventricular (ICV) injected with control solution, l-DOPA (levo-dihydroxyphenylalanine as precursor of dopamine; 125 nmol), 2-AG (2-arachidonoylglycerol as CB 1 receptor agonist; 2 µg) and co-administration of l-DOPA (125 nmol) plus 2-AG (2 µg). Experiments 2-4 were similar to Experiment 1 except birds were injected with either 6-OHDA (6-hydroxydopamine as dopamine synthesis inhibitor; 150 nmol), SCH23390 (D1 receptor antagonist; 5 nmol) and AMI-193 (D2 receptor antagonist; 5 nmol) instead of l-DOPA, respectively. Additionally, Experiments 5-8 followed the previous ones using the same dose of l-DOPA, 6-OHDA and dopamine antagonists except that birds were injected with CB65 (CB2 receptor agonist; 5 µg) instead of 2-AG. Coadministrations were at the same dose for each experiment. Cumulative feed intakes were measured until 120 min after each injection. 3. ICV administration of 6-OHDA and AMI-193 significantly attenuated 2-AG-induced hyperphagia. Interestingly, the hyperphagic effect of CB65 was significantly attenuated by administration of l-DOPA, whereas the administration of 6-OHDA and AMI-193 together amplified the hyperphagic effect of CB65. 4. It was concluded that cannabinoid-induced feeding behaviour is probably modulated by dopamine receptors in neonatal layer-type chickens. It seems that their interaction may be mediated by the D2-dopamine receptor.

Fexapotide triflutate: results of long-term safety and efficacy trials of a novel injectable therapy for symptomatic prostate enlargement.

PubMed

Shore, Neal; Tutrone, Ronald; Efros, Mitchell; Bidair, Mohamed; Wachs, Barton; Kalota, Susan; Freedman, Sheldon; Bailen, James; Levin, Richard; Richardson, Stephen; Kaminetsky, Jed; Snyder, Jeffrey; Shepard, Barry; Goldberg, Kenneth; Hay, Alan; Gange, Steven; Grunberger, Ivan

2018-05-01

These studies were undertaken to determine if fexapotide triflutate 2.5 mg transrectal injectable (FT) has significant long-term (LT) safety and efficacy for the treatment of benign prostatic hyperplasia (BPH). Two placebo controlled double-blind randomized parallel group trials with 995 BPH patients at 72 sites treated 3:2 FT:placebo, with open-label FT crossover (CO) re-injection in 2 trials n = 344 and long-term follow-up (LF) 2-6.75 years (mean 3.58 years, median 3.67 years; FT re-injection CO mean 4.27 years, median 4.42 years) were evaluated. 12 months post-treatment patients elected no further treatment, approved oral medications, FT, or interventional treatment. Primary endpoint variable was change in Symptom Score (IPSS) at 12 months and at LF. CO primary co-endpoints were 3-year incidence of (1) surgery for BPH in FT treated CO patients versus patients crossed over to oral BPH medications and (2) surgery or acute urinary retention in FT-treated CO placebo patients versus placebo patients crossed over to oral BPH medications. 28 CO secondary endpoints assessed surgical and symptomatic outcomes in FT reinjected patients versus conventional BPH medication CO and control subgroups at 2 and 3 years. FT injection had no significant safety differences from placebo. LF IPSS change from baseline was higher in FT treated patients compared to placebo (median FT group improvement - 5.2 versus placebo - 3.0, p < 0.0001). LF incidence of AUR (1.08% p = 0.0058) and prostate cancer (PCa) (1.1% p = 0.0116) were both reduced in FT treated patients. LF incidence of intervention for BPH was reduced in the FT group versus oral BPH medications (8.08% versus 27.85% at 3 years, p < 0.0001). LF incidence of intervention or AUR in placebo CO group with FT versus placebo CO group with oral medications was reduced (6.07% versus 33.3% at 3 years, p < 0.0001). 28/28 secondary efficacy endpoints were reached in LF CO re-injection studies. FT 2.5 mg is a safe and effective transrectal injectable for LT treatment of BPH. FT treated patients also had reduced need for BPH intervention, and reduced incidence of PCa and AUR.

A Novel Method for Determining the Gas Transfer Velocity of Carbon Dioxide in Streams

NASA Astrophysics Data System (ADS)

McDowell, M. J.; Johnson, M. S.

2016-12-01

Characterization of the global carbon cycle relies on the accurate quantification of carbon fluxes into and out of natural and human-dominated ecosystems. Among these fluxes, carbon dioxide (CO2) evasion from surface water has received increasing attention in recent years. However, limitations of current methods, including determination of the gas transfer velocity (k), compromise our ability to evaluate the significance of CO2 fluxes between freshwater systems and the atmosphere. We developed an automated method to determine gas transfer velocities of CO2 (kCO2), and tested it under a range of flow conditions for a first-order stream of a headwater catchment in southwestern British Columbia, Canada. Our method uses continuous in situ measurements of CO2 concentrations using two non-dispersive infrared (NDIR) sensors enclosed in water impermeable, gas permeable membranes (Johnson et al., 2010) downstream from a gas diffuser. CO2 was injected into the stream at regular intervals via a compressed gas tank connected to the diffuser. CO2 injections were controlled by a datalogger at fixed time intervals and in response to storm-induced changes in streamflow. Following the injection, differences in CO2 concentrations at known distances downstream from the diffuser relative to pre-injection baseline levels allowed us to calculate kCO2. Here we present relationships between kCO2 and hydro-geomorphologic (flow velocity, streambed slope, stream width, stream depth), atmospheric (wind speed and direction), and water quality (stream temperature, pH, electrical conductivity) variables. This method has advantages of being automatable and field-deployable, and it does not require supplemental gas chromatography, as is the case for propane injections typically used to determine k. The dataset presented suggests the potential role of this method to further elucidate the role that CO2 fluxes from headwater streams play in the global carbon cycle. Johnson, M. S., Billett, M. F., Dinsmore, K. J., Wallin, M., Dyson, K. E., & Jassal, R. S. (2010). Direct and continuous measurement of dissolved carbon dioxide in freshwater aquatic systems—method and applications. Ecohydrology, 3(1), 68-78. http://doi.org/10.1002/eco.95

Fluid Substitution Modeling to Determine Sensitivity of 3D Vertical Seismic Profile Data to Injected CO­2­ at an active Carbon Capture, Utilization and Storage Project, Farnsworth field, TX.

NASA Astrophysics Data System (ADS)

Haar, K. K.; Balch, R. S.

2015-12-01

The Southwest Regional Partnership on Carbon Sequestration monitors a CO2 capture, utilization and storage project at Farnsworth field, TX. The reservoir interval is a Morrowan age fluvial sand deposited in an incised valley. The sands are between 10 to 25m thick and located about 2800m below the surface. Primary oil recovery began in 1958 and by the late 1960's secondary recovery through waterflooding was underway. In 2009, Chaparral Energy began tertiary recovery using 100% anthropogenic CO2 sourced from an ethanol and a fertilizer plant. This constitutes carbon sequestration and fulfills the DOE's initiative to determine the best approach to permanent carbon storage. One purpose of the study is to understand CO­2 migration from injection wells. CO2­ plume spatial distribution for this project is analyzed with the use of time-lapse 3D vertical seismic profiles centered on CO2 injection wells. They monitor raypaths traveling in a single direction compared to surface seismic surveys with raypaths traveling in both directions. 3D VSP surveys can image up to 1.5km away from the well of interest, exceeding regulatory requirements for maximum plume extent by a factor of two. To optimize the timing of repeat VSP acquisition, the sensitivity of the 3D VSP surveys to CO2 injection was analyzed to determine at what injection volumes a seismic response to the injected CO­2 will be observable. Static geologic models were generated for pre-CO2 and post-CO2 reservoir states through construction of fine scale seismic based geologic models, which were then history matched via flow simulations. These generated static states of the model, where CO2­ replaces oil and brine in pore spaces, allow for generation of impedance volumes which when convolved with a representative wavelet generate synthetic seismic volumes used in the sensitivity analysis. Funding for the project is provided by DOE's National Energy Technology Laboratory (NETL) under Award No. DE-FC26-05NT42591.

Offsetting Water Requirements and Stress with Enhanced Water Recovery from CO 2 Storage

DOE Office of Scientific and Technical Information (OSTI.GOV)

Hunter, Kelsey Anne

2016-08-04

Carbon dioxide (CO 2) capture, utilization, and storage (CCUS) operations ultimately require injecting and storing CO 2 into deep saline aquifers. Reservoir pressure typically rises as CO 2 is injected increasing the cost and risk of CCUS and decreasing viable storage within the formation. Active management of the reservoir pressure through the extraction of brine can reduce the pressurization while providing a number of benefits including increased storage capacity for CO 2, reduced risks linked to reservoir overpressure, and CO 2 plume management. Through enhanced water recovery (EWR), brine within the saline aquifer can be extracted and treated through desalinationmore » technologies which could be used to offset the water requirements for thermoelectric power plants or local water needs such as agriculture, or produce a marketable such as lithium through mineral extraction. This paper discusses modeled scenarios of CO 2 injection into the Rock Springs Uplift (RSU) formation in Wyoming with EWR. The Finite Element Heat and Mass Transfer Code (FEHM), developed by Los Alamos National Laboratory (LANL), was used to model CO 2 injection with brine extraction and the corresponding pressure tradeoffs. Scenarios were compared in order to analyze how pressure management through the quantity and location of brine extraction wells can increase CO 2 storage capacity and brine extraction while reducing risks associated with over pressurization. Future research will couple a cost-benefit analysis to these simulations in order to determine if the benefit of subsurface pressure management and increase CO 2 storage capacity can outweigh multiple extraction wells with increased cost of installation and maintenance as well as treatment and/or disposal of the extracted brine.« less

Initial results from seismic monitoring at the Aquistore CO 2 storage site, Saskatchewan, Canada

DOE PAGES

White, D. J.; Roach, L. A.N.; Roberts, B.; ...

2014-12-31

The Aquistore Project, located near Estevan, Saskatchewan, is one of the first integrated commercial-scale CO 2 storage projects in the world that is designed to demonstrate CO 2 storage in a deep saline aquifer. Starting in 2014, CO 2 captured from the nearby Boundary Dam coal-fired power plant will be transported via pipeline to the storage site and to nearby oil fields for enhanced oil recovery. At the Aquistore site, the CO 2 will be injected into a brine-filled sandstone formation at ~3200 m depth using the deepest well in Saskatchewan. The suitability of the geological formations that will hostmore » the injected CO 2 has been predetermined through 3D characterization using high-resolution 3D seismic images and deep well information. These data show that 1) there are no significant faults in the immediate area of the storage site, 2) the regional sealing formation is continuous in the area, and 3) the reservoir is not adversely affected by knolls on the surface of the underlying Precambrian basement. Furthermore, the Aquistore site is located within an intracratonic region characterized by extremely low levels of seismicity. This is in spite of oil-field related water injection in the nearby Weyburn-Midale field where a total of 656 million m 3 of water have been injected since the 1960`s with no demonstrable related induced seismicity. A key element of the Aquistore research program is the further development of methods to monitor the security and subsurface distribution of the injected CO 2. Toward this end, a permanent areal seismic monitoring array was deployed in 2012, comprising 630 vertical-component geophones installed at 20 m depth on a 2.5x2.5 km regular grid. This permanent array is designed to provide improved 3D time-lapse seismic imaging for monitoring subsurface CO 2. Prior to the onset of CO 2 injection, calibration 3D surveys were acquired in May and November of 2013. Comparison of the data from these surveys relative to the baseline 3D survey data from 2012 shows excellent repeatability (NRMS less than 10%) which will provide enhanced monitoring sensitivity to smaller amounts of CO 2. The permanent array also provides continuous passive monitoring for injection-related microseismicity. Passive monitoring has been ongoing since the summer of 2012 in order to establish levels of background seismicity before CO 2 injection starts in 2014. Microseismic monitoring was augmented in 2013 by the installation of 3 broadband seismograph stations surrounding the Aquistore site. These surface installations should provide a detection capability of seismic events with magnitudes as low as ~0. Downhole seismic methods are also being utilized for CO 2 monitoring at the Aquistore site. Baseline crosswell tomographic images depict details (meters-scale) of the reservoir in the 150-m interval between the observation and injection wells. This level of resolution is designed to track the CO 2 migration between the wells during the initial injection period. A baseline 3D vertical seismic profile (VSP) was acquired in the fall of 2013 to provide seismic images with resolution on a scale between that provided by the surface seismic array and the downhole tomography. The 3D VSP was recorded simultaneously using both a conventional array of downhole geophones (60-levels) and an optical fibre system. The latter utilized an optical fiber cable deployed on the outside of the monitor well casing and cemented in place. A direct comparison of these two methodologies will determine the suitability of using the fiber cable for ongoing time-lapse VSP monitoring.« less

Time-lapse 3-D electrical resistance tomography inversion for crosswell monitoring of dissolved and supercritical CO 2 flow at two field sites: Escatawpa and Cranfield, Mississippi, USA

DOE PAGES

Commer, Michael; Doetsch, Joseph; Dafflon, Baptiste; ...

2016-06-01

In this study, we advance the understanding of three-dimensional (3-D) electrical resistivity tomography (ERT) for monitoring long-term CO 2 storage by analyzing two previously published field time-lapse data sets. We address two important aspects of ERT inversion-the issue of resolution decay, a general impediment to the ERT method, and the issue of potentially misleading imaging artifacts due to 2-D model assumptions. The first study analyzes data from a shallow dissolved-CO 2 injection experiment near Escatawpa (Mississippi), where ERT data were collected in a 3-D crosswell configuration. Here, we apply a focusing approach designed for crosswell configurations to counteract resolution lossmore » in the inter-wellbore area, with synthetic studies demonstrating its effectiveness. The 3-D field data analysis reveals an initially southwards-trending flow path development and a dispersing plume development in the downgradient inter-well region. The second data set was collected during a deep (over 3 km) injection of supercritical CO 2 near Cranfield (Mississippi). Comparative 2-D and 3-D inversions reveal the projection of off-planar anomalies onto the cross-section, a typical artifact introduced by 2-D model assumptions. Conforming 3-D images from two different algorithms support earlier hydrological investigations, indicating a conduit system where flow velocity variations lead to a circumvention of a close observation well and an onset of increased CO 2 saturation downgradient from this well. We relate lateral permeability variations indicated by an independently obtained hydrological analysis to this consistently observed pattern in the CO 2 spatial plume evolution.« less

Feasibility Study for The Setting Up of a Safety System for Monitoring CO2 Storage at Prinos Field, Greece

NASA Astrophysics Data System (ADS)

Koukouzas, Nikolaos; Lymperopoulos, Panagiotis; Tasianas, Alexandros; Shariatipour, Seyed

2016-10-01

Geological storage of CO2 in subsurface geological structures can mitigate global warming. A comprehensive safety and monitoring system for CO2 storage has been undertaken for the Prinos hydrocarbon field, offshore northern Greece; a system which can prevent any possible leakage of CO2. This paper presents various monitoring strategies of CO2 subsurface movement in the Prinos reservoir, the results of a simulation of a CO2 leak through a well, an environmental risk assessment study related to the potential leakage of CO2 from the seafloor and an overall economic insight of the system. The results of the simulation of the CO2 leak have shown that CO2 reaches the seabed in the form of gas approximately 13.7 years, from the beginning of injection. From that point onwards the amount of CO2 reaching the seabed increases until it reaches a peak at around 32.9 years. During the injection period, the CO2 plume develops only within the reservoir. During the post-injection period, the CO2 reaches the seabed and develops side branches. These correspond to preferential lateral flow pathways of the CO2 and are more extensive for the dissolved CO2 than for the saturated CO2 gas. For the environmental risk assessment, we set up a model, using ArcGIS software, based on the use of data regarding the speeds of the winds and currents encountered in the region. We also made assumptions related to the flow rate of CO2. Results show that after a period of 10 days from the start of CO2 leakage the CO2 has reached halfway to the continental shores where the “Natura” protected areas are located. CO2 leakage modelling results show CO2 to be initially flowing along a preferential flow direction, which is towards the NE. However, 5 days after the start of leakage of CO2, the CO2 is also flowing towards the ENE. The consequences of a potential CO2 leak are considered spatially limited and the ecosystem is itself capable of recovering. We have tried to determine the costs necessary for the creation of such an integrated CO2 monitoring program both during the CO2 injection phase as well as during permanent storage. The most prevalent solution consists of purchasing both seismic equipment and Echosounder systems as well as privileging a monitoring system, which uses selected boreholes. The necessary period required for monitoring the study area is at least 20 years after the end of the CO2 storage period at Prinos. To the overall monitoring time, we should also add a further 20 years that are required for the injection phase as well as 12 years for the storage phase. The operating costs for monitoring the CO2 amount to 0,38 /ton CO2 and the total cost for EOR at Prinos amounts to 0,45 /ton CO2.

Turbulent structure and emissions of strongly-pulsed jet diffusion flames

NASA Astrophysics Data System (ADS)

Fregeau, Mathieu

This current research project studied the turbulent flame structure, the fuel/air mixing, the combustion characteristics of a nonpremixed pulsed (unsteady) and unpulsed (steady) flame configuration for both normal- and microgravity conditions, as well as the flame emissions in normal gravity. The unsteady flames were fully-modulated, with the fuel flow completely shut off between injection pulses using an externally controlled valve, resulting in the generation of compact puff-like flame structures. Conducting experiments in normal and microgravity environments enabled separate control over the relevant Richardson and Reynolds numbers to clarify the influence of buoyancy on the flame behavior, mixing, and structure. Experiments were performed in normal gravity in the laboratory at the University of Washington and in microgravity using the NASA GRC 2.2-second Drop Tower facility. High-speed imaging, as well as temperature and emissions probes were used to determine the large-scale structure dynamics, the details of the flame structure and oxidizer entrainment, the combustion temperatures, and the exhaust emissions of the pulsed and steady flames. Of particular interest was the impact of changes in flame structure due to pulsing on the combustion characteristics of this system. The turbulent flame puff celerity (i.e., the bulk velocity of the puffs) was strongly impacted by the jet-off time, increasing markedly as the time between pulses was decreased, which caused the degree of puff interaction to increase and the strongly-pulsed flame to more closely resemble a steady flame. This increase occurred for all values of injection time as well as for constant fuelling rate and in both the presence and absence of buoyancy. The removal of positive buoyancy in microgravity resulted in a decrease in the flame puff celerity in all cases, amounting to as much as 40%, for both constant jet injection velocity and constant fuelling rate. The mean flame length of the strongly-pulsed flames was not strongly impacted by buoyancy. This lack of sensitivity to buoyancy was consistent with offsetting changes in flame puff celerity and time to burnout for the microgravity versus normal-gravity cases. The emissions of CO and NO were examined in the vicinity of the visible flame tip and at the combustor exit for strongly-pulsed flames. The highest exhaust-point emission indices of CO for compact, isolated puffs were as much as a factor of six higher than those of elongated flames with longer injection times. The amount of CO decreased substantially with a decreased amount of flame puff interaction. The higher CO levels for pulsed flames with the shortest injection times were consistent with quenching due to the very rapid mixing and dilution with excess air for the most compact flame puffs. The injection time for which steady-flame emission levels were attained was comparable to the injection time for which the visible flame length approached the flame length of steady flames. The CO emissions, for a given fuelling rate, were strongly dependent on both the injection time and jet-off time for a jet-on fraction less than approximately 50%. The NO levels were generally proportional to the fuelling rate. This work indicates that there are specific combinations of injection time and jet-off time that considerably change the fuel/air mixing, resulting in emissions comparable to those of the steady flame while the flame length is significantly shorter. This points the potential utility of the strongly-pulsed injection technique in the development of compact, low emissions combustors involving turbulent diffusion flames. (Abstract shortened by UMI.)

Influence of CO2 on the long-term chemomechanical behavior of an oolitic limestone

NASA Astrophysics Data System (ADS)

Grgic, D.

2011-07-01

In order to study the long-term mechanical and petrographical evolutions of a carbonate rock (oolitic limestone) during storage of CO2, CO2 injection tests were performed in triaxial cells at temperature and mechanical stresses (isotropic and deviatoric) corresponding to the depth of the Dogger carbonate reservoirs of the Paris basin (˜800 m). We used a specific "flow-through" triaxial cell which allowed us to measure very low strain rates in both axial and lateral directions, while ensuring the sealing of the samples during the injection of CO2. Under isotropic loading, neither the dynamic percolation (i.e., flow-through tests) of dry supercritical/gaseous CO2, nor the diffusion of CO2, into initially saturated samples was shown to produce significant axial compaction and calcite dissolution. Indeed, even though the interstitial aqueous fluid becomes acidic, the progressive increase in dissolved species induces the H2O-CO2-calcite re-equilibrium. The dynamic injection of CO2-saturated solution induced significant axial compaction due to the dissolution of calcite at the sample/piston interface only under open flow conditions (i.e., the injected acidic solution is continuously renewed). Under closed flow conditions (i.e., acidic solution recirculation or no-flow conditions) which reproduce the physicochemical conditions of CO2 storage at the field scale better, the rapid H2O-CO2-calcite re-equilibrium inhibits calcite dissolution. Under deviatoric loading and closed conditions, the diffusion of CO2 induced a very small increase in the PSC (pressure solution creep) process which was stopped by the H2O-CO2-calcite re-equilibrium inside the sample. Therefore, a significant compaction of limestone samples was obtained only under open conditions and is mainly due to a purely chemical mechanism (calcite dissolution), while the contribution of the chemo-mechanical mechanism (PSC) was found to not be of any great importance. In the context of massive injection of CO2 at the field scale, if the reservoir can be considered as a closed system from a hydrodynamic point of view (i.e., the brine circulates in the aquifer but is not renewed by any groundwater), CO2 will not play a significant role in the chemistry of carbonate reservoirs due to the H2O-CO2-calcite re-equilibrium and will not induce reservoir compaction and affect its long-term storage capacity, whatever the stress state (isotropic or deviatoric).

In-situ biogas upgrading with pulse H2 additions: The relevance of methanogen adaption and inorganic carbon level.

PubMed

Agneessens, Laura Mia; Ottosen, Lars Ditlev Mørck; Voigt, Niels Vinther; Nielsen, Jeppe Lund; de Jonge, Nadieh; Fischer, Christian Holst; Kofoed, Michael Vedel Wegener

2017-06-01

Surplus electricity from fluctuating renewable power sources may be converted to CH 4 via biomethanisation in anaerobic digesters. The reactor performance and response of methanogen population of mixed-culture reactors was assessed during pulsed H 2 injections. Initial H 2 uptake rates increased immediately and linearly during consecutive pulse H 2 injections for all tested injection rates (0.3 to 1.7L H2 /L sludge /d), while novel high throughput mcrA sequencing revealed an increased abundance of specific hydrogenotrophic methanogens. These findings illustrate the adaptability of the methanogen population to H 2 injections and positively affects the implementation of biomethanisation. Acetate accumulated by a 10-fold following injections exceeding a 4:1 H 2 :CO 2 ratio and may act as temporary storage prior to biomethanisation. Daily methane production decreased for headspace CO 2 concentrations below 12% and may indicate a high sensitivity of hydrogenotrophic methanogens to CO 2 limitation. This may ultimately decide the biogas upgrading potential which can be achieved by biomethanisation. Copyright © 2017 Elsevier Ltd. All rights reserved.

Active Management of Integrated Geothermal-CO2 Storage Reservoirs in Sedimentary Formations

DOE Data Explorer

Buscheck, Thomas A.

2012-01-01

Active Management of Integrated Geothermal–CO2 Storage Reservoirs in Sedimentary Formations: An Approach to Improve Energy Recovery and Mitigate Risk: FY1 Final Report The purpose of phase 1 is to determine the feasibility of integrating geologic CO2 storage (GCS) with geothermal energy production. Phase 1 includes reservoir analyses to determine injector/producer well schemes that balance the generation of economically useful flow rates at the producers with the need to manage reservoir overpressure to reduce the risks associated with overpressure, such as induced seismicity and CO2 leakage to overlying aquifers. Based on a range of well schemes, techno-economic analyses of the levelized cost of electricity (LCOE) are conducted to determine the economic benefits of integrating GCS with geothermal energy production. In addition to considering CO2 injection, reservoir analyses are conducted for nitrogen (N2) injection to investigate the potential benefits of incorporating N2 injection with integrated geothermal-GCS, as well as the use of N2 injection as a potential pressure-support and working-fluid option. Phase 1 includes preliminary environmental risk assessments of integrated geothermal-GCS, with the focus on managing reservoir overpressure. Phase 1 also includes an economic survey of pipeline costs, which will be applied in Phase 2 to the analysis of CO2 conveyance costs for techno-economics analyses of integrated geothermal-GCS reservoir sites. Phase 1 also includes a geospatial GIS survey of potential integrated geothermal-GCS reservoir sites, which will be used in Phase 2 to conduct sweet-spot analyses that determine where promising geothermal resources are co-located in sedimentary settings conducive to safe CO2 storage, as well as being in adequate proximity to large stationary CO2 sources.

Long-term exposure to elevated carbon dioxide does not alter activity levels of a coral reef fish in response to predator chemical cues.

PubMed

Sundin, Josefin; Amcoff, Mirjam; Mateos-González, Fernando; Raby, Graham D; Jutfelt, Fredrik; Clark, Timothy D

2017-01-01

Levels of dissolved carbon dioxide (CO 2 ) projected to occur in the world's oceans in the near future have been reported to increase swimming activity and impair predator recognition in coral reef fishes. These behavioral alterations would be expected to have dramatic effects on survival and community dynamics in marine ecosystems in the future. To investigate the universality and replicability of these observations, we used juvenile spiny chromis damselfish ( Acanthochromis polyacanthus ) to examine the effects of long-term CO 2 exposure on routine activity and the behavioral response to the chemical cues of a predator ( Cephalopholis urodeta ). Commencing at ~3-20 days post-hatch, juvenile damselfish were exposed to present-day CO 2 levels (~420 μatm) or to levels forecasted for the year 2100 (~1000 μatm) for 3 months of their development. Thereafter, we assessed routine activity before and after injections of seawater (sham injection, control) or seawater-containing predator chemical cues. There was no effect of CO 2 treatment on routine activity levels before or after the injections. All fish decreased their swimming activity following the predator cue injection but not following the sham injection, regardless of CO 2 treatment. Our results corroborate findings from a growing number of studies reporting limited or no behavioral responses of fishes to elevated CO 2 . Alarmingly, it has been reported that levels of dissolved carbon dioxide (CO 2 ) forecasted for the year 2100 cause coral reef fishes to be attracted to the chemical cues of predators. However, most studies have exposed the fish to CO 2 for very short periods before behavioral testing. Using long-term acclimation to elevated CO 2 and automated tracking software, we found that fish exposed to elevated CO 2 showed the same behavioral patterns as control fish exposed to present-day CO 2 levels. Specifically, activity levels were the same between groups, and fish acclimated to elevated CO 2 decreased their swimming activity to the same degree as control fish when presented with cues from a predator. These findings indicate that behavioral impacts of elevated CO 2 levels are not universal in coral reef fishes.

Upward flow of supercritical CO2 with transition to gaseous conditions: Simulations for design of large-scale CO2 flow experiments at LUCI

NASA Astrophysics Data System (ADS)

Oldenburg, C. M.; Peters, C. A.; Dobson, P. F.; Doughty, C.

2010-12-01

Understanding the processes involved in large-scale upward flow of CO2 related to Geologic Carbon Sequestration (GCS) is critical to evaluating trapping mechanisms and potential impacts of CO2 leakage over long distances. The Laboratory for Underground CO2 Investigations (LUCI) is being planned to be built at DUSEL to host large-scale vertical CO2 and brine flow experiments. As conceived, LUCI would consist of a 500 m-long vertical raisebore approximately 3 m in diameter which will contain three suspended long-column pressure vessels. The long-column pressure vessels are planned to be 1 m in diameter with thermal control on the outer walls with a centralized inner fiberglass well for accommodating monitoring tools for determining phase saturation, porosity, temperature, and other properties of the flow region. The outer wall of the inner fiberglass well and the inner wall of the main vessel comprise the lateral boundaries of the long vertical annular regions that will be filled with porous media in which experiments investigating flow and transport, geochemical alterations of well cement, and biological processes involving injected CO2 will be performed. The large vertical extent of the column is needed to span the full range of CO2 conditions from supercritical (scCO2, P > 7.4 MPa, T > 31 °C) to gaseous CO2 that is believed to be significant as CO2 flows upwards. Here we consider the CO2-brine flow experiments in which the annular region will be pressurized at the top and bottom and contain brine-filled porous media through which scCO2 introduced at the bottom will flow upward. We are carrying out two-phase flow simulations of the buoyancy- and pressure-driven flow of CO2 and brine upward in the annular porous media region to further design the flow columns, e.g., to determine critical length and diameter requirements, as well as to plan the experiments to be performed. The simulations are carried out using TOUGH2/ECO2N, which models two-phase non-isothermal flow and transport of water, CO2, and NaCl in porous media. To treat important issues of drainage and imbibition at the leading and trailing edges of the CO2 slug, we employ hysteretic relative permeability functions. Simulation results will be presented showing flow rate, saturation, and temperature dependence on permeability, relative permeability parameters, size of initial CO2 slug, imposed upward flow rate, and different side boundary conditions (e.g., fully insulated and temperature equal to a constant geothermal gradient).

Applications of Satellite Geodesy in Environmental and Climate Change

NASA Astrophysics Data System (ADS)

Yang, Qian

Satellite geodesy plays an important role in earth observation. This dissertation presents three applications of satellite geodesy in environmental and climate change. Three satellite geodesy techniques are used: high-precision Global Positioning System (GPS), the Gravity Recovery and Climate Experiment (GRACE) and Interferometric Synthetic Aperture Radar (InSAR). In the first study, I use coastal uplift observed by GPS to study the annual changes in mass loss of the Greenland ice sheet. The data show both spatial and temporal variations of coastal ice mass loss and suggest that a combination of warm atmospheric and oceanic condition drove these variations. In the second study, I use GRACE monthly gravity change estimates to constrain recent freshwater flux from Greenland. The data show that Arctic freshwater flux started to increase rapidly in the mid-late 1990s, coincident with a decrease in the formation of dense Labrador Sea Water, a key component of the deep southward return flow od the Atlantic Meridional Overturning Circulation (AMOC). Recent freshening of the polar oceans may be reducing formation of Labrador Sea Water and hence may be weakening the AMOC. In the third study, I use InSAR to monitor ground deformation caused by CO2 injection at an enhanced oil recovery site in west Texas. Carbon capture and storage can reduce CO 2 emitted from power plants, and is a promising way to mitigate anthropogenic warming. From 2007 to 2011, ~24 million tons of CO2 were sequestered in this field, causing up to 10 MPa pressure buildup in a reservoir at depth, and surface uplift up to 10 cm. This study suggests that surface displacement observed by InSAR is a cost-effective way to estimate reservoir pressure change and monitor the fate of injected fluids at waste disposal and CO2 injection sites.

Interpretation of Tracer Experiments on Inverted Five-spot Well-patterns within the Western Half of the Farnsworth Unit Oil Field

DOE PAGES

White, Mark D.; Esser, R. P.; McPherson, B. P.; ...

2017-07-01

The Southwest Carbon Partnership (SWP), one of the U.S. Department of Energy (U.S. DOE) seven Regional Carbon Sequestration Partnerships, is currently working to demonstrate the utilization and storage of CO 2 in the Farnsworth Unit (FWU) Enhanced Oil Recovery (EOR) site under the final development phase of this U.S. DOE initiative. A component of the research is to use fluid tracers to understand the multifluid flow patterns that develop between injection and production wells via collected field data and supporting numerical reservoir models. The FWU, located in the Anadarko Basin, Ochiltree County, Texas, and being operated by Chaparral Energy, ismore » a mature EOR water-flood field, which is currently being converted to a CO 2 flow, with inverted 5-spot patterns transitioning from pure water to alternating CO 2 and water floods (i.e., water alternating gas (WAG)) at an approximate rate of one every 6 to 10 months. The SWP tracer program is conducting a suite of tracer injections into the active 5-spot patterns at the FWU. Tracers have been selected to be nonreactive and either principally soluble in CO 2 (gas soluble) or water (aqueous soluble). In addition to characterizing the multifluid flow behaviour within reservoir, the gas and aqueous tracers have roles in detecting any leakage from the reservoir. A total of seven unique perfluorocarbon tracer (PFT) compounds make up the suite of gas soluble tracers and eight unique naphthalene sulfonate tracer (NPT) compounds comprise the aqueous soluble tracers. Lastly, all selected tracers are significantly detectable below the parts per billion concentrations, allowing for high resolution for the inter-well tests at relatively low injection volumes.« less

Interpretation of Tracer Experiments on Inverted Five-spot Well-patterns within the Western Half of the Farnsworth Unit Oil Field

DOE Office of Scientific and Technical Information (OSTI.GOV)

White, Mark D.; Esser, R. P.; McPherson, B. P.

The Southwest Carbon Partnership (SWP), one of the U.S. Department of Energy (U.S. DOE) seven Regional Carbon Sequestration Partnerships, is currently working to demonstrate the utilization and storage of CO 2 in the Farnsworth Unit (FWU) Enhanced Oil Recovery (EOR) site under the final development phase of this U.S. DOE initiative. A component of the research is to use fluid tracers to understand the multifluid flow patterns that develop between injection and production wells via collected field data and supporting numerical reservoir models. The FWU, located in the Anadarko Basin, Ochiltree County, Texas, and being operated by Chaparral Energy, ismore » a mature EOR water-flood field, which is currently being converted to a CO 2 flow, with inverted 5-spot patterns transitioning from pure water to alternating CO 2 and water floods (i.e., water alternating gas (WAG)) at an approximate rate of one every 6 to 10 months. The SWP tracer program is conducting a suite of tracer injections into the active 5-spot patterns at the FWU. Tracers have been selected to be nonreactive and either principally soluble in CO 2 (gas soluble) or water (aqueous soluble). In addition to characterizing the multifluid flow behaviour within reservoir, the gas and aqueous tracers have roles in detecting any leakage from the reservoir. A total of seven unique perfluorocarbon tracer (PFT) compounds make up the suite of gas soluble tracers and eight unique naphthalene sulfonate tracer (NPT) compounds comprise the aqueous soluble tracers. Lastly, all selected tracers are significantly detectable below the parts per billion concentrations, allowing for high resolution for the inter-well tests at relatively low injection volumes.« less

A Model To Estimate Carbon Dioxide Injectivity and Storage Capacity for Geological Sequestration in Shale Gas Wells.

PubMed

Edwards, Ryan W J; Celia, Michael A; Bandilla, Karl W; Doster, Florian; Kanno, Cynthia M

2015-08-04

Recent studies suggest the possibility of CO2 sequestration in depleted shale gas formations, motivated by large storage capacity estimates in these formations. Questions remain regarding the dynamic response and practicality of injection of large amounts of CO2 into shale gas wells. A two-component (CO2 and CH4) model of gas flow in a shale gas formation including adsorption effects provides the basis to investigate the dynamics of CO2 injection. History-matching of gas production data allows for formation parameter estimation. Application to three shale gas-producing regions shows that CO2 can only be injected at low rates into individual wells and that individual well capacity is relatively small, despite significant capacity variation between shale plays. The estimated total capacity of an average Marcellus Shale well in Pennsylvania is 0.5 million metric tonnes (Mt) of CO2, compared with 0.15 Mt in an average Barnett Shale well. Applying the individual well estimates to the total number of existing and permitted planned wells (as of March, 2015) in each play yields a current estimated capacity of 7200-9600 Mt in the Marcellus Shale in Pennsylvania and 2100-3100 Mt in the Barnett Shale.

Reduction of toroidal rotation by fast wave power in DIII-D

DOE Office of Scientific and Technical Information (OSTI.GOV)

Grassie, J.S. de; Baker, D.R.; Burrell, K.H.

1997-04-01

The application of fast wave power in DIII-D has proven effective for both electron heating and current drive. Since the last RIF Conference FW power has been applied to advanced confinement regimes in DIII-D; negative central shear (NCS), VH- and H-modes, high {beta}{sub p}, and high-{ell}i. Typically these regimes show enhanced confinement of toroidal momentum exhibited by increased toroidal rotation velocity. Indeed, layers of large shear in toroidal velocity are associated with transport barriers. A rather common occurrence in these experiments is that the toroidal rotation velocity is decreased when the FW power is turned on, to lowest order independentmore » of whether the antennas are phased for co or counter current drive. At present all the data is for co-injected beams. The central toroidal rotation can be reduced to 1/2 of the non-FW level. Here the authors describe the effect in NCS discharges with co-beam injection.« less

CO{sub 2} Digital Subtraction Splenoportography with the 'Skinny' Needle: Experimental Study in a Swine Model

DOE Office of Scientific and Technical Information (OSTI.GOV)

Cho, Kyung J.; Cho, David R.

Purpose: To evaluate the safety and the effectiveness of CO{sub 2} splenoportography with the 'skinny' needle. Methods: A flexible, 22 gauge needle ('skinny' needle) was introduced into the exteriorized spleens of five pigs. After checking the intrasplenic positioning withCO{sub 2} injection, increasing doses of CO{sub 2} (10-60cm{sup 3}) were injected using a dedicated CO{sub 2}injector with digital imaging. The puncture sites were observed during and after CO{sub 2} injections, and after removal of the needle.The spleens were then removed for gross and microscopic examination. Results: In all animals digital subtractionCO{sub 2} splenoportograms showed the splenic, extra- and intrahepatic portal veins,more » and the most distal portion of the superiormesenteric vein. No CO{sub 2} extravasation occurred in the spleen. There was no significant bleeding from the puncture site after removal of the needle. Gross and microscopic examination revealed no evidence of splenic rupture or intrasplenic hematoma. Conclusion: CO{sub 2} splenoportography with the 'skinny' needle is a safe and simple method of visualizing the portal vein and its branches. Careful appraisals of the clinical usefulness of the method will be needed in various clinical settings.« less

Laboratory simulation system, using Carcinus maenas as the model organism, for assessing the impact of CO2 leakage from sub-seabed injection and storage.

PubMed

Rodríguez-Romero, Araceli; Jiménez-Tenorio, Natalia; Riba, Inmaculada; Blasco, Julián

2016-01-01

The capture and storage of CO2 in sub-seabed geological formations has been proposed as one of the potential options to decrease atmospheric CO2 concentrations in order to mitigate the abrupt and irreversible consequences of climate change. However, it is possible that CO2 leakages could occur during the injection and sequestration procedure, with significant repercussions for the marine environment. We investigate the effects of acidification derived from possible CO2 leakage events on the European green crab, Carcinus maenas. To this end, a lab-scale experiment involving direct release of CO2 was conducted at pH values between 7.7 and 6.15. Female crabs were exposed for 10 days to sediment collected from two different coastal areas, one with relatively uncontaminated sediment (RSP) and the other with known contaminated sediment (MZ and ML), under the pre-established seawater pH conditions. Survival rate, histopathological damage and metal (Fe, Mn, Cu, Zn, Cr, Cd and Pb) and As accumulation in gills and hepatopancreas tissue were employed as endpoints. In addition, the obtained results were compared with the results of the physico-chemical characterization of the sediments, which included the determination of the metals Fe, Mn, Cu, Zn, Cr, Pb and Cd, the metalloid As, certain polycyclic aromatic hydrocarbons (PAHs) and polychlorinated biphenyls (PCBs), as well as nonchemical sediment properties (grain size, organic carbon and total organic matter). Significant associations were observed between pH and the histological damage. Concentrations of Fe, Mn, Cr, Pb, Cd and PAHs in sediment, presented significant negative correlations with the damage to gills and hepatopancreas, and positive correlations with metal accumulation in both tissues. The results obtained in this study reveal the importance of sediment properties in the biological effects caused by possible CO2 leakage. However, a clear pattern was not observed between metal accumulation in tissues and pH reduction. Animals' avoidance behavior and degree of tolerance to acidification are confounding factors for assessing metal bioaccumulation. Further research is required to find a suitable assay that would allow us to predict the risk to environmental health of possible negative side effects of metal mobility derived from CO2 leakage during its injection and storage in sub-seabed formations. Copyright © 2015 Elsevier Inc. All rights reserved.

Modeling techniques for cross-hole seismic monitoring of CO2 injection in a deep saline aquifer

NASA Astrophysics Data System (ADS)

Da, Federico, ,, Col; Gei, Davide

2017-04-01

In this work, we present a modelling technique for a synthetic, yet realistic, 2D cross-hole seismic monitoring experiment for CO2 injection in a deep saline aquifer. We implement a synthetic (2D) geological formation consisting of a sandstone aquifer, with shaly mudstone intrusions, embedded in very low permeability shales. The aquifer has its top at about 800 m b.s.l., is approximately 200 m thick and it extends about 800 m in the horizontal direction.The formation is very heterogenous with respect to all petrophysical and hydrological properties; furthermore, we consider the grains to be a mixture of quartz and clay. Injection of the CO2 and the propagation of the plume is modelled using STOMP commercial software. The algorithm solves the mass balance equation for wetting and non-wetting phase fluids, as well as for the dissolved salt. It considers advection via Darcy's equation extended to two phase flow and molecular diffusion. Furthermore, dissolution of the CO2 in the brine is considered. We assume the aquifer to be initially in hydrostatic equilibrium and we inject pure CO2 for 2 years. We then compute phase p-wave velocities and quality factor by means of White's mesoscopic theory, which assumes that the partially saturated pore consists of two concentrical spheres; the inner saturated with gas, the outer saturated with brine. Using this p-wave velocity and quality factor map, we compute synthetic cross-hole seismograms by means of a visco-acoustic modelling code. We perform 80 shots along the left borehole, with a source spacing of 5 metres. We then pick the first arrivals (direct wave) on the seismograms and we perform a tomographic inversion using cat3d software. We invert for straight rays, updating the velocity model with a SIRT algorithm at each iteration. Due to the mainly horizontal orientation of the velocity anomalies, we select to invert only for rays having an angle lower than 30° with the horizontal direction. The algorithm converged well after 200 iterations; furthermore, the picked and computed velocities fit rather well, with residuals showing a gaussian distribution around 0. The method looks promising, since the main velocity anomalies are well detected.

Increased N2O emission by inhibited plant growth in the CO2 leaked soil environment: Simulation of CO2 leakage from carbon capture and storage (CCS) site.

PubMed

Kim, You Jin; He, Wenmei; Ko, Daegeun; Chung, Haegeun; Yoo, Gayoung

2017-12-31

Atmospheric carbon dioxide (CO 2 ) concentrations is continuing to increase due to anthropogenic activity, and geological CO 2 storage via carbon capture and storage (CCS) technology can be an effective way to mitigate global warming due to CO 2 emission. However, the possibility of CO 2 leakage from reservoirs and pipelines exists, and such leakage could negatively affect organisms in the soil environment. Therefore, to determine the impacts of geological CO 2 leakage on plant and soil processes, we conducted a greenhouse study in which plants and soils were exposed to high levels of soil CO 2 . Cabbage, which has been reported to be vulnerable to high soil CO 2 , was grown under BI (no injection), NI (99.99% N 2 injection), and CI (99.99% CO 2 injection). Mean soil CO 2 concentration for CI was 66.8-76.9% and the mean O 2 concentrations in NI and CI were 6.6-12.7%, which could be observed in the CO 2 leaked soil from the pipelines connected to the CCS sites. The soil N 2 O emission was increased by 286% in the CI, where NO 3 - -N concentration was 160% higher compared to that in the control. This indicates that higher N 2 O emission from CO 2 leakage could be due to enhanced nitrification process. Higher NO 3 - -N content in soil was related to inhibited plant metabolism. In the CI treatment, chlorophyll content decreased and chlorosis appeared after 8th day of injection. Due to the inhibited root growth, leaf water and nitrogen contents were consistently lowered by 15% under CI treatment. Our results imply that N 2 O emission could be increased by the secondary effects of CO 2 leakage on plant metabolism. Hence, monitoring the environmental changes in rhizosphere would be very useful for impact assessment of CCS technology. Copyright © 2017 Elsevier B.V. All rights reserved.

Carbon dioxide enhanced oil recovery performance according to the literature

USGS Publications Warehouse

Olea, Ricardo A.

2017-07-17

IntroductionThe need to increase the efficiency of oil recovery and environmental concerns are bringing to prominence the use of carbon dioxide (CO2) as a tertiary recovery agent. Assessment of the impact of flooding with CO2 all eligible reservoirs in the United States not yet undergoing enhanced oil recovery (EOR) requires making the best possible use of the experience gained in 40 years of applications. Review of the publicly available literature has located relevant CO2-EOR information for 53 units (fields, reservoirs, pilot areas) in the United States and 17 abroad.As the world simultaneously faces an increasing concentration of CO2 in the atmosphere and a higher demand for fossil fuels, the CO2-EOR process continues to gain popularity for its efficiency as a tertiary recovery agent and for the potential for having some CO2 trapped in the subsurface as an unintended consequence of the enhanced production (Advanced Resources International and Melzer Consulting, 2009). More extensive application of CO2-EOR worldwide, however, is not making it significantly easier to predict the exact outcome of the CO2 flooding in new reservoirs. The standard approach to examine and manage risks is to analyze the intended target by conducting laboratory work, running simulation models, and, finally, gaining field experience with a pilot test. This approach, though, is not always possible. For example, assessment of the potential of CO2-EOR at the national level in a vast country such as the United States requires making forecasts based on information already available.Although many studies are proprietary, the published literature has provided reviews of CO2-EOR projects. Yet, there is always interest in updating reports and analyzing the information under new perspectives. Brock and Bryan (1989) described results obtained during the earlier days of CO2-EOR from 1972 to 1987. Most of the recovery predictions, however, were based on intended injections of 30 percent the size of the reservoir’s hydrocarbon pore volume (HCPV), and the predictions in most cases badly missed the actual recoveries because of the embryonic state of tertiary recovery in general and CO2 flooding in particular at the time. Brock and Bryan (1989), for example, reported for the Weber Sandstone in the Rangely oil field in Colorado, an expected recovery of 7.5 percent of the original oil in place (OOIP) after injecting a volume of CO2 equivalent to 30 percent of the HCPV, but Clark (2012) reported that after injecting a volume of CO2 equivalent to 46 percent of the HCPV, the actual recovery was 4.8 percent of the OOIP. Decades later, the numbers by Brock and Bryan (1989) continue to be cited as part of expanded reviews, such as the one by Kuuskraa and Koperna (2006). Other comprehensive reviews including recovery factors are those of Christensen and others (2001) and Lake and Walsh (2008). The Oil and Gas Journal (O&GJ) periodically reports on active CO2-EOR operations worldwide, but those releases do not include recovery factors. The monograph by Jarrell and others (2002) remains the most technically comprehensive publication on CO2 flooding, but it does not cover recovery factors either.This chapter is a review of the literature found in a search for information about CO2-EOR. It has been prepared as part of a project by the U.S. Geological Survey (USGS) to assess the incremental oil production that would be technically feasible by CO2 flooding of all suitable oil reservoirs in the country not yet undergoing tertiary recovery.

Experimental and simulation studies of iron oxides for geochemical fixation of CO2-SO2 gas mixtures

USGS Publications Warehouse

Garcia, Susana; Rosenbauer, Robert J.; Palandri, James; Maroto-Valer, M. Mercedes

2011-01-01

Iron-bearing minerals are reactive phases of the subsurface environment and could potentially trap CO2–SO2gas mixtures derived from fossil fuel combustion processes by their conversion to siderite (FeCO3) and dissolved sulfate. Changes in fluid and mineral compositions resulting from reactions, involving the co-injection of SO2 with CO2 were observed both theoretically and experimentally. Experiments were conducted with a natural hematite (α-Fe2O3) sample. A high pressure-high temperature apparatus was used to simulate conditions in geologic formations deeper than 800 m, where CO2 is in the supercritical state. Solid samples were allowed to react with a NaCl–NaOH brine and SO2-bearing CO2-dominated gas mixtures. The predicted equilibrium mineral assemblage at 100 °C and 250 bar became hematite, dawsonite (NaAl(OH)2CO3), siderite (FeCO3) and quartz (SiO2). Experimentally, siderite and dawsonite, derived from the presence of kaolinite (Al2Si2O5(OH)4) in the parent material, were present in residual solids at longer reaction time intervals, which agreed well with results from the modelling work.

CO2 Exsolution from CO2 Saturated Water: Core-Scale Experiments and Focus on Impacts of Pressure Variations.

PubMed

Xu, Ruina; Li, Rong; Ma, Jin; Jiang, Peixue

2015-12-15

For CO2 sequestration and utilization in the shallow reservoirs, reservoir pressure changes are due to the injection rate changing, a leakage event, and brine withdrawal for reservoir pressure balance. The amounts of exsolved CO2 which are influenced by the pressure reduction and the subsequent secondary imbibition process have a significant effect on the stability and capacity of CO2 sequestration and utilization. In this study, exsolution behavior of the CO2 has been studied experimentally using a core flooding system in combination with NMR/MRI equipment. Three series of pressure variation profiles, including depletion followed by imbibitions without or with repressurization and repetitive depletion and repressurization/imbibition cycles, were designed to investigate the exsolution responses for these complex pressure variation profiles. We found that the exsolved CO2 phase preferentially occupies the larger pores and exhibits a uniform spatial distribution. The mobility of CO2 is low during the imbibition process, and the residual trapping ratio is extraordinarily high. During the cyclic pressure variation process, the first cycle has the largest contribution to the amount of exsolved CO2. The low CO2 mobility implies a certain degree of self-sealing during a possible reservoir depletion.

Assessment of fluid distribution and flow properties in two phase fluid flow using X-ray CT technology

NASA Astrophysics Data System (ADS)

Jiang, Lanlan; Wu, Bohao; Li, Xingbo; Wang, Sijia; Wang, Dayong; Zhou, Xinhuan; Zhang, Yi

2018-04-01

To study on microscale distribution of CO2 and brine during two-phase flow is crucial for understanding the trapping mechanisms of CO2 storage. In this study, CO2-brine flow experiments in porous media were conducted using X-ray computed tomography. The porous media were packed with glass beads. The pore structure (porosity/tortuosity) and flow properties at different flow rates and flow fractions were investigated. The results showed that porosity of the packed beads differed at different position as a result of heterogeneity. The CO2 saturation is higher at low injection flow rates and high CO2 fractions. CO2 distribution at the pore scale was also visualized. ∅ Porosity of porous media CT brine_ sat grey value of sample saturated with brine CT dry grey value of sample saturated with air CT brine grey value of pure brine CT air grey value of pure air CT flow grey values of sample with two fluids occupying the pore space {CT}_{CO_2_ sat} grey value of sample saturated with CO2 {f}_{CO_2}({S}_{CO_2}) CO2 fraction {q}_{CO_2} the volume flow rate for CO2 q brine the volume flow rate for brine L Thickness of the porous media, mm L e a bundle of capillaries of equal length, mm τ Tortuosity, calculated from L e / L.

[Clinical effect of ultrasound-guided injection of biodegradable poly(lactic-co-glycolic acid)-Fe3O4 in situ implant for magnetic thermal ablation in treatment of nude mice with human liver cancer SMMC-7721 cells].

PubMed

Liang, B; Zuo, G Q; Zheng, Y Y; He, S; Zuo, D Y

2016-12-20

Objective: To prepare the Fe 3 O 4 -loaded biodegradable liquid-solid phase inversion poly(lactic-co-glycolic acid) (PLGA) in situ implant for ultrasound-guided injection into nude mouse tumor model, and to investigate its clinical effect in thermomagnetic treatment of nude mice with human liver cancer SMMC-7721 cells in an alternating magnetic field. Methods: An in situ implant containing 10% Fe 3 O 4 was prepared, and 50 μl Fe 3 O 4 -PLGA-NMP gel was injected into the subcutaneous tissue of Kunming mice. The degradation of this material was observed for 2 consecutive months, and the changes in body weight were recorded. HE staining and Prussian blue staining were performed for the heart, liver, spleen, lung, and kidney of Kunming mice. Fresh ex vivo bovine liver was taken and cut into cubes with a dimension of 2 cm×2 cm×2 cm and then 50 μl Fe 3 O 4 -PLGA-NMP gel was injected; after phase inversion, the cubes of ex vivo bovine liver were heated for 1, 2, 3, 4, and 5 minutes, respectively, and then cut open for observing the range of ablation; HE staining was also performed. Micro-CT scan was performed after ultrasound-guided injection of 50 μl Fe 3 O 4 -PLGA gel into the tumors of the nude mice, and then the nude mice were divided into treatment group and control group. The mice in the treatment group were given thermomagnetic treatment for 3 minutes, and tumor growth was observed daily. Results: The biodegradation of Fe 3 O 4 -PLGA-NMP implant showed that the subcutaneously injected material was gradually metabolized at 2 weeks after injection and that the nude mice were in good condition. The bovine liver ablation experiment showed that the range of ablation of 50 μl Fe 3 O 4 -PLGA implant reached 1.46 ± 0.11 cm. HE staining showed that part of bovine liver had coagulative necrosis. The phase inversion experiment of Fe 3 O 4 -PLGA gel showed quick liquid-solid phase inversion of the material after injection into the tumor, and the process of liquid-solid phase inversion could be monitored by ultrasound and CT. The detachment and incrustation of the tumor started at 2 days after treatment, the wound started to heal 15 days later, and the tumor tissue disappeared completely. Conclusion: Ultrasound-guided injection of biodegradable Fe 3 O 4 -PLGA in situ implant combined with magnetic thermal ablation can effectively treat human liver cancer SMMC-7721 cells in nude mice.

Effect of Mineral Dissolution/Precipitation and CO2 Exsolution on CO2 transport in Geological Carbon Storage.

PubMed

Xu, Ruina; Li, Rong; Ma, Jin; He, Di; Jiang, Peixue

2017-09-19

Geological carbon sequestration (GCS) in deep saline aquifers is an effective means for storing carbon dioxide to address global climate change. As the time after injection increases, the safety of storage increases as the CO 2 transforms from a separate phase to CO 2 (aq) and HCO 3 - by dissolution and then to carbonates by mineral dissolution. However, subsequent depressurization could lead to dissolved CO 2 (aq) escaping from the formation water and creating a new separate phase which may reduce the GCS system safety. The mineral dissolution and the CO 2 exsolution and mineral precipitation during depressurization change the morphology, porosity, and permeability of the porous rock medium, which then affects the two-phase flow of the CO 2 and formation water. A better understanding of these effects on the CO 2 -water two-phase flow will improve predictions of the long-term CO 2 storage reliability, especially the impact of depressurization on the long-term stability. In this Account, we summarize our recent work on the effect of CO 2 exsolution and mineral dissolution/precipitation on CO 2 transport in GCS reservoirs. We place emphasis on understanding the behavior and transformation of the carbon components in the reservoir, including CO 2 (sc/g), CO 2 (aq), HCO 3 - , and carbonate minerals (calcite and dolomite), highlight their transport and mobility by coupled geochemical and two-phase flow processes, and consider the implications of these transport mechanisms on estimates of the long-term safety of GCS. We describe experimental and numerical pore- and core-scale methods used in our lab in conjunction with industrial and international partners to investigate these effects. Experimental results show how mineral dissolution affects permeability, capillary pressure, and relative permeability, which are important phenomena affecting the input parameters for reservoir flow modeling. The porosity and the absolute permeability increase when CO 2 dissolved water is continuously injected through the core. The MRI results indicate dissolution of the carbonates during the experiments since the porosity has been increased after the core-flooding experiments. The mineral dissolution changes the pore structure by enlarging the throat diameters and decreasing the pore specific surface areas, resulting in lower CO 2 /water capillary pressures and changes in the relative permeability. When the reservoir pressure decreases, the CO 2 exsolution occurs due to the reduction of solubility. The CO 2 bubbles preferentially grow toward the larger pores instead of toward the throats or the finer pores during the depressurization. After exsolution, the exsolved CO 2 phase shows low mobility due to the highly dispersed pore-scale morphology, and the well dispersed small bubbles tend to merge without interface contact driven by the Ostwald ripening mechanism. During depressurization, the dissolved carbonate could also precipitate as a result of increasing pH. There is increasing formation water flow resistance and low mobility of the CO 2 in the presence of CO 2 exsolution and carbonate precipitation. These effects produce a self-sealing mechanism that may reduce unfavorable CO 2 migration even in the presence of sudden reservoir depressurization.

Hydro-geomechanical behaviour of gas-hydrate bearing soils during gas production through depressurization and CO2 injection

NASA Astrophysics Data System (ADS)

Deusner, C.; Gupta, S.; Kossel, E.; Bigalke, N.; Haeckel, M.

2015-12-01

Results from recent field trials suggest that natural gas could be produced from marine gas hydrate reservoirs at compatible yields and rates. It appears, from a current perspective, that gas production would essentially be based on depressurization and, when facing suitable conditions, be assisted by local thermal stimulation or gas hydrate conversion after injection of CO2-rich fluids. Both field trials, onshore in the Alaska permafrost and in the Nankai Trough offshore Japan, were accompanied by different technical issues, the most striking problems resulting from un-predicted geomechanical behaviour, sediment destabilization and catastrophic sand production. So far, there is a lack of experimental data which could help to understand relevant mechanisms and triggers for potential soil failure in gas hydrate production, to guide model development for simulation of soil behaviour in large-scale production, and to identify processes which drive or, further, mitigate sand production. We use high-pressure flow-through systems in combination with different online and in situ monitoring tools (e.g. Raman microscopy, MRI) to simulate relevant gas hydrate production scenarios. Key components for soil mechanical studies are triaxial systems with ERT (Electric resistivity tomography) and high-resolution local strain analysis. Sand production control and management is studied in a novel hollow-cylinder-type triaxial setup with a miniaturized borehole which allows fluid and particle transport at different fluid injection and flow conditions. Further, the development of a large-scale high-pressure flow-through triaxial test system equipped with μ-CT is ongoing. We will present results from high-pressure flow-through experiments on gas production through depressurization and injection of CO2-rich fluids. Experimental data are used to develop and parametrize numerical models which can simulate coupled process dynamics during gas-hydrate formation and gas production.

Atmospheric and soil-gas monitoring for surface leakage at the San Juan Basin CO{sub 2} pilot test site at Pump Canyon New Mexico, using perfluorocarbon tracers, CO{sub 2} soil-gas flux and soil-gas hydrocarbons

DOE Office of Scientific and Technical Information (OSTI.GOV)

Wells, Arthur W; Diehl, J Rodney; Strazisar, Brian R

2012-05-01

Near-surface monitoring and subsurface characterization activities were undertaken in collaboration with the Southwest Regional Carbon Sequestration Partnership on their San Juan Basin coal-bed methane pilot test site near Navajo City, New Mexico. Nearly 18,407 short tons (1.670 × 107 kg) of CO{sub 2} were injected into 3 seams of the Fruitland coal between July 2008 and April 2009. Between September 18 and October 30, 2008, two additions of approximately 20 L each of perfluorocarbon (PFC) tracers were mixed with the CO{sub 2} at the injection wellhead. PFC tracers in soil-gas and in the atmosphere were monitored over a period ofmore » 2 years using a rectangular array of permanent installations. Additional monitors were placed near existing well bores and at other locations of potential leakage identified during the pre-injection site survey. Monitoring was conducted using sorbent containing tubes to collect any released PFC tracer from soil-gas or the atmosphere. Near-surface monitoring activities also included CO{sub 2} surface flux and carbon isotopes, soil-gas hydrocarbon levels, and electrical conductivity in the soil. The value of the PFC tracers was demonstrated when a significant leakage event was detected near an offset production well. Subsurface characterization activities, including 3D seismic interpretation and attribute analysis, were conducted to evaluate reservoir integrity and the potential that leakage of injected CO{sub 2} might occur. Leakage from the injection reservoir was not detected. PFC tracers made breakthroughs at 2 of 3 offset wells which were not otherwise directly observable in produced gases containing 20–30% CO{sub 2}. These results have aided reservoir geophysical and simulation investigations to track the underground movement of CO{sub 2}. 3D seismic analysis provided a possible interpretation for the order of appearance of tracers at production wells.« less

3D Geological Modeling of CoalBed Methane (CBM) Resources in the Taldykuduk Block Karaganda Coal Basin, Kazakhstan

NASA Astrophysics Data System (ADS)

Sadykov, Raman; Kiponievich Ogay, Evgeniy; Royer, Jean-Jacques; Zhapbasbayev, Uzak; Panfilova, Irina

2015-04-01

Coal Bed Methane (CBM) is gas stored in coal layers. It can be extracted from wells after hydraulic fracturing and/or solvent injection, and secondary recovery techniques such as CO2 injection. Karaganda Basin is a very favorable candidate region to develop CBM production for the following reasons: (i) Huge gas potential; (ii) Available technologies for extracting and commercializing the gas produced by CBM methods; (iii) Experience in degassing during underground mining operations for safety reasons; (iv) Local needs in energy for producing electricity for the industrial and domestic market. The objectives of this work are to model the Taldykuduk block coal layers and their properties focusing on Coal Bed Methane production. It is motivated by the availability of large coal bed methane resources in Karaganda coal basin which includes 4 300 Bm3 equivalent 2 billion tons of coal (B = billion = 109) with gas content 15-25 m3/t of coal (for comparison San Juan basin (USA) has < 20 m3/t). The CBM reserves estimations are about: Saransk block, 26.3 Bm3 and Taldykuduk block, 23.5 Bm3. Methane (CH4) can be considered as an environmentally-friendly fuel compared to coal. Actually, the methane extracted during mining is released in the atmosphere, collecting it for recovering energy will reduce CO2 equivalent emissions by 36 Mt, good news regarding climate warming issues. The exploitation method will be based on a EOR technology consisting in injecting CO2 which replaces methane in pores because it has a higher adsorption capacity than CH4; exploiting CBM by CO2 injection provides thus a safe way to sequestrate CO2 in adsorbed form. The 3D geological model was built on Gocad/Skua using the following available data set: 926 wells and large area (7 x 12 km). No seismic data; coal type and chemical components (S, ash, …); unreliable available cross-section & maps due to old acquisition; quality mature coal; complex heterogeneous fractures network reported on geological cross sections; and utilization issues of the water extracted in the early stages of exploitation. The resulting 3D faulted model which includes more than 100 of faults will be further used to simulate the secondary recovery of methane by injecting CO2. The simulation will be carried out on a flow simulator assuming a two phase dimensionless formulation of CBM production in a double porosity model considering two domains: the matrix (m) and the fracture (f) for which the initial and boundary conditions are different. The resulting comprehensive 3D models had helped in better understanding the tectonic structures of the region, especially the relationships between the fault systems.

Air Sparging Versus Gas Saturated Water Injection for Remediation of Volatile LNAPL in the Borden Aquifer

NASA Astrophysics Data System (ADS)

Barker, J.; Nelson, L.; Doughty, C.; Thomson, N.; Lambert, J.

2009-05-01

In the shallow, rather homogeneous, unconfined Borden sand aquifer, field trials of air sparging (Tomlinson et al., 2003) and pulsed air sparging (Lambert et al., 2009) have been conducted, the latter to remediate a residual gasoline source emplaced below the water table. As well, a supersaturated (with CO2) water injection (SWI) technology, using the inVentures inFusion system, has been trialed in two phases: 1. in the uncontaminated sand aquifer to evaluate the radius of influence, extent of lateral gas movement and gas saturation below the water table, and 2. in a sheet pile cell in the Borden aquifer to evaluate the recovery of volatile hydrocarbon components (pentane and hexane) of an LNAPL emplaced below the water table (Nelson et al., 2008). The SWI injects water supersaturated with CO2. The supersaturated injected water moves laterally away from the sparge point, releasing CO2 over a wider area than does gas sparging from a single well screen. This presentation compares these two techniques in terms of their potential for remediating volatile NAPL components occurring below the water table in a rather homogeneous sand aquifer. Air sparging created a significantly greater air saturation in the vicinity of the sparge well than did the CO2 system (60 percent versus 16 percent) in the uncontaminated Borden aquifer. However, SWI pushed water, still supersaturated with CO2, up to about 2.5 m from the injection well. This would seem to provide a considerable advantage over air sparging from a point, in that gas bubbles are generated at a much larger radius from the point of injection with SWI and so should involve additional gas pathways through a residual NAPL. Overall, air sparging created a greater area of influence, defined by measurable air saturation in the aquifer, but air sparging also injected about 12 times more gas than was injected in the SWI trials. The pulsed air sparging at Borden (Lambert et al.) removed about 20 percent (4.6 kg) of gasoline hydrocarbons, mainly pentane and hexane, from the residual gasoline via sparging. A similar mass was estimated to have been removed by aerobic biodegradation. The extent of volatile recovery needs to be better defined and so post-sparging coring and analysis of residual LNAPL is underway. Impressively, the second SWI trial recovered more than 60 percent of the pentane-hexane from the NAPL. In both field experiments there was potential for minor additional recovery if the system had been operated longer. Comparison of efficiency of the pulsed air sparging and SWI systems is difficult in that the initial LNAPL residuals have different chemistry, but similar distribution, different volumes of gas were used, and biodegradation accounted for a significant removal of hydrocarbons only in the air sparging system. The SWI trial recovered an impressive portion of the volatile LNAPL, while using considerably less gas than the air sparging system, but the SWI delivery system was both more complex and more expensive than the air sparging system. Additional trials are underway in more complex aquifers to further assess the performance of the SWI technology, including costs and practical limitations.

Investigation of representing hysteresis in macroscopic models of two-phase flow in porous media using intermediate scale experimental data

NASA Astrophysics Data System (ADS)

Cihan, Abdullah; Birkholzer, Jens; Trevisan, Luca; Gonzalez-Nicolas, Ana; Illangasekare, Tissa

2017-01-01

Incorporating hysteresis into models is important to accurately capture the two phase flow behavior when porous media systems undergo cycles of drainage and imbibition such as in the cases of injection and post-injection redistribution of CO2 during geological CO2 storage (GCS). In the traditional model of two-phase flow, existing constitutive models that parameterize the hysteresis associated with these processes are generally based on the empirical relationships. This manuscript presents development and testing of mathematical hysteretic capillary pressure—saturation—relative permeability models with the objective of more accurately representing the redistribution of the fluids after injection. The constitutive models are developed by relating macroscopic variables to basic physics of two-phase capillary displacements at pore-scale and void space distribution properties. The modeling approach with the developed constitutive models with and without hysteresis as input is tested against some intermediate-scale flow cell experiments to test the ability of the models to represent movement and capillary trapping of immiscible fluids under macroscopically homogeneous and heterogeneous conditions. The hysteretic two-phase flow model predicted the overall plume migration and distribution during and post injection reasonably well and represented the postinjection behavior of the plume more accurately than the nonhysteretic models. Based on the results in this study, neglecting hysteresis in the constitutive models of the traditional two-phase flow theory can seriously overpredict or underpredict the injected fluid distribution during post-injection under both homogeneous and heterogeneous conditions, depending on the selected value of the residual saturation in the nonhysteretic models.

Targeted Control of Permeability Using Carbonate Dissolution/Precipitation Reactions

NASA Astrophysics Data System (ADS)

Clarens, A. F.; Tao, Z.; Plattenberger, D.

2016-12-01

Targeted mineral precipitation reactions are a promising approach for controlling fluid flow in the deep subsurface. Here we studied the potential to use calcium and magnesium bearing silicates as cation donors that would react with aqueous phase CO2 under reservoir conditions to form solid carbonate precipitates. Preliminary experiments in high pressure and temperature columns suggest that these reactions can effectively lower the permeability of a porous media. Wollastonite (CaSiO3) was used as the model silicate, injected as solid particles into the pore space of a packed column, which was then subsequently flooded with CO2(aq). The reactions occur spontaneously, leveraging the favorable kinetics that occur at the high temperature and pressure conditions characteristic of the deep subsurface, to form solid phase calcium carbonate (CaCO3) and amorphous silica (SiO2) within the pore space. Both x-ray tomography imaging of reacted columns and electron microscopy imaging of thin sections were used to characterize where dissolution/precipitation occurred within the porous media. The spatial distribution of the products was closely tied to the flow rate and the duration of the experiment. The SiO2 product precipitated in close spatial proximity to the CaSiO3 reactant. The CaCO3 product, which is sensitive to the low pH and high pCO2 brine, precipitated out of solution further down the column as Ca2+ ions moved with the brine. The permeability of the columns decreased by several orders of magnitude after injecting the CaSiO3 particles. Following carbonation, the permeability decreased even further as precipitates filled flow paths within the pore network. A pore network model was developed to help understand the interplay between precipitation kinetics and flow in altering the permeability of the porous media. The effect of particle concentration and size, pore size, reaction time, and pCO2, are explored on pore/fracture aperture and reaction extent. To provide better control of these dynamics and ultimately devise a mechanism to deliver carbonation seed particles into leakage pathways, we are exploring the potential to functionalize the silicate particles using temperature sensitive polymer coatings.

Pulse evolution and mode selection characteristics in a TEA-CO2 laser perturbed by injection of external radiation

NASA Technical Reports Server (NTRS)

Flamant, P. H.; Menzies, R. T.; Kavaya, M. J.; Oppenheim, U. P.

1983-01-01

A grating-tunable TEA-CO2 laser with an unstable resonator cavity, modified to allow injection of CW CO2 laser radiation at the resonant transition line by means of an intracavity NaCl window, has been used to study the coupling requirements for generation of single frequency pulses. The width and shape of the mode selection region, and the dependence of the gain-switched spike buildup time and the pulse shapes on the intensity and detuning frequency of the injected radiation are reported. Comparisons of the experimental results with previously reported mode selection behavior are discussed.

Intermediate-Scale Experimental Study to Improve Fundamental Understanding of Attenuation Capacity for Leaking CO2 in Heterogeneous Shallow Aquifers

NASA Astrophysics Data System (ADS)

Plampin, Michael R.; Porter, Mark L.; Pawar, Rajesh J.; Illangasekare, Tissa H.

2017-12-01

To assess the risks of Geologic Carbon Sequestration (GCS), it is crucial to understand the fundamental physicochemical processes that may occur if and when stored CO2 leaks upward from a deep storage reservoir into the shallow subsurface. Intermediate-scale experiments allow for improved understanding of the multiphase evolution processes that control CO2 migration behavior in the subsurface, because the boundary conditions, initial conditions, and porous media parameters can be better controlled and monitored in the laboratory than in field settings. For this study, a large experimental test bed was designed to mimic a cross section of a shallow aquifer with layered geologic heterogeneity. As water with aqueous CO2 was injected into the system to mimic a CO2-charged water leakage scenario, the spatiotemporal evolution of the multiphase CO2 plume was monitored. Similar experiments were performed with two different sand combinations to assess the relative effects of different types of geologic facies transitions on the CO2 evolution processes. Significant CO2 attenuation was observed in both scenarios, but by fundamentally different mechanisms. When the porous media layers had very different permeabilities, attenuation was caused by local accumulation (structural trapping) and slow redissolution of gas phase CO2. When the permeability difference between the layers was relatively small, on the other hand, gas phase continually evolved over widespread areas near the leading edge of the aqueous plume, which also attenuated CO2 migration. This improved process understanding will aid in the development of models that could be used for effective risk assessment and monitoring programs for GCS projects.

Intermediate-Scale Experimental Study to Improve Fundamental Understanding of Attenuation Capacity for Leaking CO 2 in Heterogeneous Shallow Aquifers

DOE PAGES

Plampin, Michael R.; Porter, Mark L.; Pawar, Rajesh J.; ...

2017-11-15

In order to assess the risks of Geologic Carbon Sequestration (GCS), it is crucial to understand the fundamental physicochemical processes that may occur if and when stored CO 2 leaks upward from a deep storage reservoir into the shallow subsurface. Intermediate-scale experiments allow for improved understanding of the multiphase evolution processes that control CO 2 migration behaviour in the subsurface, because the boundary conditions, initial conditions, and porous media parameters can be better controlled and monitored in the laboratory than in field settings. For this study, a large experimental test bed was designed to mimic a cross-section of a shallowmore » aquifer with layered geologic heterogeneity. As water with aqueous CO 2 was injected into the system to mimic a CO 2-charged water leakage scenario, the spatiotemporal evolution of the multiphase CO 2 plume was monitored. Similar experiments were performed with two different sand combinations to assess the relative effects of different types of geologic facies transitions on the CO 2 evolution processes. Significant CO 2 attenuation was observed in both scenarios, but by fundamentally different mechanisms. When the porous media layers had very different permeabilities, attenuation was caused by local accumulation (structural trapping) and slow re-dissolution of gas phase CO 2. When the permeability difference between the layers was relatively small, on the other hand, gas phase continually evolved over widespread areas near the leading edge of the aqueous plume, which also attenuated CO 2 migration. In conclusion, this improved process understanding will aid in the development of models that could be used for effective risk assessment and monitoring programs for GCS projects.« less

Intermediate-Scale Experimental Study to Improve Fundamental Understanding of Attenuation Capacity for Leaking CO 2 in Heterogeneous Shallow Aquifers

DOE Office of Scientific and Technical Information (OSTI.GOV)

Plampin, Michael R.; Porter, Mark L.; Pawar, Rajesh J.

In order to assess the risks of Geologic Carbon Sequestration (GCS), it is crucial to understand the fundamental physicochemical processes that may occur if and when stored CO 2 leaks upward from a deep storage reservoir into the shallow subsurface. Intermediate-scale experiments allow for improved understanding of the multiphase evolution processes that control CO 2 migration behaviour in the subsurface, because the boundary conditions, initial conditions, and porous media parameters can be better controlled and monitored in the laboratory than in field settings. For this study, a large experimental test bed was designed to mimic a cross-section of a shallowmore » aquifer with layered geologic heterogeneity. As water with aqueous CO 2 was injected into the system to mimic a CO 2-charged water leakage scenario, the spatiotemporal evolution of the multiphase CO 2 plume was monitored. Similar experiments were performed with two different sand combinations to assess the relative effects of different types of geologic facies transitions on the CO 2 evolution processes. Significant CO 2 attenuation was observed in both scenarios, but by fundamentally different mechanisms. When the porous media layers had very different permeabilities, attenuation was caused by local accumulation (structural trapping) and slow re-dissolution of gas phase CO 2. When the permeability difference between the layers was relatively small, on the other hand, gas phase continually evolved over widespread areas near the leading edge of the aqueous plume, which also attenuated CO 2 migration. In conclusion, this improved process understanding will aid in the development of models that could be used for effective risk assessment and monitoring programs for GCS projects.« less

Local Sensitivity of Predicted CO 2 Injectivity and Plume Extent to Model Inputs for the FutureGen 2.0 site

DOE PAGES

Zhang, Z. Fred; White, Signe K.; Bonneville, Alain; ...

2014-12-31

Numerical simulations have been used for estimating CO2 injectivity, CO2 plume extent, pressure distribution, and Area of Review (AoR), and for the design of CO2 injection operations and monitoring network for the FutureGen project. The simulation results are affected by uncertainties associated with numerous input parameters, the conceptual model, initial and boundary conditions, and factors related to injection operations. Furthermore, the uncertainties in the simulation results also vary in space and time. The key need is to identify those uncertainties that critically impact the simulation results and quantify their impacts. We introduce an approach to determine the local sensitivity coefficientmore » (LSC), defined as the response of the output in percent, to rank the importance of model inputs on outputs. The uncertainty of an input with higher sensitivity has larger impacts on the output. The LSC is scalable by the error of an input parameter. The composite sensitivity of an output to a subset of inputs can be calculated by summing the individual LSC values. We propose a local sensitivity coefficient method and applied it to the FutureGen 2.0 Site in Morgan County, Illinois, USA, to investigate the sensitivity of input parameters and initial conditions. The conceptual model for the site consists of 31 layers, each of which has a unique set of input parameters. The sensitivity of 11 parameters for each layer and 7 inputs as initial conditions is then investigated. For CO2 injectivity and plume size, about half of the uncertainty is due to only 4 or 5 of the 348 inputs and 3/4 of the uncertainty is due to about 15 of the inputs. The initial conditions and the properties of the injection layer and its neighbour layers contribute to most of the sensitivity. Overall, the simulation outputs are very sensitive to only a small fraction of the inputs. However, the parameters that are important for controlling CO2 injectivity are not the same as those controlling the plume size. The three most sensitive inputs for injectivity were the horizontal permeability of Mt Simon 11 (the injection layer), the initial fracture-pressure gradient, and the residual aqueous saturation of Mt Simon 11, while those for the plume area were the initial salt concentration, the initial pressure, and the initial fracture-pressure gradient. The advantages of requiring only a single set of simulation results, scalability to the proper parameter errors, and easy calculation of the composite sensitivities make this approach very cost-effective for estimating AoR uncertainty and guiding cost-effective site characterization, injection well design, and monitoring network design for CO2 storage projects.« less

CO 2 Storage by Sorption on Organic Matter and Clay in Gas Shale

DOE Office of Scientific and Technical Information (OSTI.GOV)

Bacon, Diana H.; Yonkofski, Catherine MR; Schaef, Herbert T.

2015-10-10

Simulations of methane production and supercritical carbon dioxide injection were developed that consider competitive adsorption of CH 4 and CO 2 on both organic matter and montmorillonite. The results were used to assess the potential for storage of CO 2 in a hydraulically fractured shale gas reservoir and for enhanced recovery of CH 4. Assuming equal volume fractions of organic matter and montmorillonite, amounts of CO 2 adsorbed on both materials were comparable, while methane desorption was from clays was two times greater than desorption from organic material. The most successful strategy considered CO 2 injection from a separate wellmore » and enhanced methane recovery by 73%, while storing 240 kmt of CO 2.« less

Cost Implications of Uncertainty in CO{sub 2} Storage Resource Estimates: A Review

DOE Office of Scientific and Technical Information (OSTI.GOV)

Anderson, Steven T., E-mail: sanderson@usgs.gov

Carbon capture from stationary sources and geologic storage of carbon dioxide (CO{sub 2}) is an important option to include in strategies to mitigate greenhouse gas emissions. However, the potential costs of commercial-scale CO{sub 2} storage are not well constrained, stemming from the inherent uncertainty in storage resource estimates coupled with a lack of detailed estimates of the infrastructure needed to access those resources. Storage resource estimates are highly dependent on storage efficiency values or storage coefficients, which are calculated based on ranges of uncertain geological and physical reservoir parameters. If dynamic factors (such as variability in storage efficiencies, pressure interference,more » and acceptable injection rates over time), reservoir pressure limitations, boundaries on migration of CO{sub 2}, consideration of closed or semi-closed saline reservoir systems, and other possible constraints on the technically accessible CO{sub 2} storage resource (TASR) are accounted for, it is likely that only a fraction of the TASR could be available without incurring significant additional costs. Although storage resource estimates typically assume that any issues with pressure buildup due to CO{sub 2} injection will be mitigated by reservoir pressure management, estimates of the costs of CO{sub 2} storage generally do not include the costs of active pressure management. Production of saline waters (brines) could be essential to increasing the dynamic storage capacity of most reservoirs, but including the costs of this critical method of reservoir pressure management could increase current estimates of the costs of CO{sub 2} storage by two times, or more. Even without considering the implications for reservoir pressure management, geologic uncertainty can significantly impact CO{sub 2} storage capacities and costs, and contribute to uncertainty in carbon capture and storage (CCS) systems. Given the current state of available information and the scarcity of (data from) long-term commercial-scale CO{sub 2} storage projects, decision makers may experience considerable difficulty in ascertaining the realistic potential, the likely costs, and the most beneficial pattern of deployment of CCS as an option to reduce CO{sub 2} concentrations in the atmosphere.« less

Cost implications of uncertainty in CO2 storage resource estimates: A review

USGS Publications Warehouse

Anderson, Steven T.

2017-01-01

Carbon capture from stationary sources and geologic storage of carbon dioxide (CO2) is an important option to include in strategies to mitigate greenhouse gas emissions. However, the potential costs of commercial-scale CO2 storage are not well constrained, stemming from the inherent uncertainty in storage resource estimates coupled with a lack of detailed estimates of the infrastructure needed to access those resources. Storage resource estimates are highly dependent on storage efficiency values or storage coefficients, which are calculated based on ranges of uncertain geological and physical reservoir parameters. If dynamic factors (such as variability in storage efficiencies, pressure interference, and acceptable injection rates over time), reservoir pressure limitations, boundaries on migration of CO2, consideration of closed or semi-closed saline reservoir systems, and other possible constraints on the technically accessible CO2 storage resource (TASR) are accounted for, it is likely that only a fraction of the TASR could be available without incurring significant additional costs. Although storage resource estimates typically assume that any issues with pressure buildup due to CO2 injection will be mitigated by reservoir pressure management, estimates of the costs of CO2 storage generally do not include the costs of active pressure management. Production of saline waters (brines) could be essential to increasing the dynamic storage capacity of most reservoirs, but including the costs of this critical method of reservoir pressure management could increase current estimates of the costs of CO2 storage by two times, or more. Even without considering the implications for reservoir pressure management, geologic uncertainty can significantly impact CO2 storage capacities and costs, and contribute to uncertainty in carbon capture and storage (CCS) systems. Given the current state of available information and the scarcity of (data from) long-term commercial-scale CO2 storage projects, decision makers may experience considerable difficulty in ascertaining the realistic potential, the likely costs, and the most beneficial pattern of deployment of CCS as an option to reduce CO2 concentrations in the atmosphere.

Spectral-element simulations of carbon dioxide (CO2) sequestration time-lapse monitoring

NASA Astrophysics Data System (ADS)

Morency, C.; Luo, Y.; Tromp, J.

2009-12-01

Geologic sequestration of CO2, a green house gas, represents an effort to reduce the large amount of CO2 generated as a by-product of fossil fuels combustion and emitted into the atmosphere. This process of sequestration involves CO2 storage deep underground. There are three main storage options: injection into hydrocarbon reservoirs, injection into methane-bearing coal beds, or injection into deep saline aquifers, that is, highly permeable porous media. The key issues involve accurate monitoring of the CO2, from the injection stage to the prediction & verification of CO2 movement over time for environmental considerations. A natural non-intrusive monitoring technique is referred to as ``4D seismics'', which involves 3D time-lapse seismic surveys. The success of monitoring the CO2 movement is subject to a proper description of the physics of the problem. We propose to realize time-lapse migrations comparing acoustic, elastic, and poroelastic simulations of 4D seismic imaging to characterize the storage zone. This approach highlights the influence of using different physical theories on interpreting seismic data, and, more importantly, on extracting the CO2 signature from the seismic wave field. Our simulations are performed using a spectral-element method, which allows for highly accurate results. Biot's equations are implemented to account for poroelastic effects. Attenuation associated with the anelasticity of the rock frame and frequency-dependent viscous resistance of the pore fluid are accommodated based upon a memory variable approach. The sensitivity of observables to the model parameters is quantified based upon finite-frequency sensitivity kernels calculated using an adjoint method.

Selective mucosal ablation using CO2 laser for the development of novel endoscopic submucosal dissection: comparison of continuous wave and nanosecond pulsed wave

NASA Astrophysics Data System (ADS)

Ishii, K.; Watanabe, S.; Obata, D.; Hazama, H.; Morita, Y.; Matsuoka, Y.; Kutsumi, H.; Azuma, T.; Awazu, K.

2010-02-01

Endoscopic submucosal dissection (ESD) is accepted as a minimally invasive treatment technique for small early gastric cancers. Procedures are carried out using some specialized electrosurgical knifes with a submucosal injection solution. However it is not widely used because its procedure is difficult. The objective of this study is to develop a novel ESD method which is safe in principle and widely used by using laser techniques. In this study, we used CO2 lasers with a wavelength of 10.6 μm for mucosal ablation. Two types of pulse, continuous wave and pulsed wave with a pulse width of 110 ns, were studied to compare their values. Porcine stomach tissues were used as a sample. Aqueous solution of sodium hyaluronate (MucoUpR) with 50 mg/ml sodium dihydrogenphosphate is injected to a submucosal layer. As a result, ablation effect by CO2 laser irradiation was stopped because submucosal injection solution completely absorbed CO2 laser energy in the invasive energy condition which perforates a muscle layer without submucosal injection solution. Mucosal ablation by the combination of CO2 Laser and a submucosal injection solution is a feasible technique for treating early gastric cancers safely because it provides a selective mucosal resection and less-invasive interaction to muscle layer.

Experimental Investigation of the Influence of Small Scale Geological Heterogeneity on Capillary Trapping of CO2 Using Engineered Beadpacks

NASA Astrophysics Data System (ADS)

Ganesan Krishnamurthy, P.; Trevisan, L.; Meckel, T. A.

2017-12-01

During geologic CO2 sequestration, most of the storage domain far from the injection sites is likely to be dominated by buoyancy and capillary forces. Under such flow regimes, small scale geological heterogeneities have been shown to dampen plume migration rates and cause trapping beneath capillary barriers. To understand the impact of such heterogeneities on CO2 trapping processes experimentally, many core-scale and lab scale flow studies have been conducted. Reservoir cores are limited by the scale of investigation possible and most lab experiments are conducted in macroheterogeneous media constructed by arranging homogeneous units to represent heterogeneity. However, most natural sedimentary facies display heterogeneity at a hierarchy of scales, and heterogeneity at the mesoscale (mm to decimeters) goes unrepresented in laboratory experiments due to the difficulty in reproducibility. This work presents results from buoyancy driven migration experiments conducted at the meter scale using glass beads packed in a quasi 2D glass cell and complementary reduced physics simulations. We demonstrate a novel automated technique to build beadpacks with 2D heterogeneous sedimentary features in a reproducible manner. A fluid pair that mimics the phase density and viscosity contrasts, and interfacial tension of CO2-Brine at reservoir pressures and temperatures is employed for the flow experiments. Light transmission technique is used for visualization, and to calibrate and quantify saturation of the trapped non-wetting fluid during the experiments. Invasion Percolation is used to simulate the buoyancy driven flow. With the ability to generate different types of heterogeneous structures in a reproducible manner, and by comparing experiments and simulations, a systematic investigation of the effect of heterogeneity on capillary trapping becomes possible.

Overestimation of low cardiac output measured by thermodilution.

PubMed

Tournadre, J P; Chassard, D; Muchada, R

1997-10-01

We have investigated the influence of a cold water bolus (CWB) injection on overestimation of cardiac output (CO) in low CO states in anaesthetized dogs. CO was measured using three methods: (1) thermodilution (TD), (2) electromagnetic (EM) flow meter placed on the pulmonary artery and (3) transoesophageal echo-Doppler (OD) placed on the descending aorta. Measurements of CO were obtained before (steady state) and after induction of a low CO state with thiopentone 5 mg kg-1 i.v. After CWB injection, mean CO measured by EM and OD increased by 26% and 27%, respectively (P < 0.05) during steady state, and by 85% and 75% (P < 0.05) during the low CO state. This transient increase was produced by an increase in stroke volume, while heart rate did not change. Frank Starling's law may explain this variation by a sudden increase in preload produced by CWB injection. These results indicate that thermodilution overestimated CO during low CO states when CWB injection was used.

Enhanced characterization of faults and fractures at EGS sites by CO2 injection coupled with active seismic monitoring, pressure-transient testing, and well logging

NASA Astrophysics Data System (ADS)

Oldenburg, C. M.; Daley, T. M.; Borgia, A.; Zhang, R.; Doughty, C.; Jung, Y.; Altundas, B.; Chugunov, N.; Ramakrishnan, T. S.

2016-12-01

Faults and fractures in geothermal systems are difficult to image and characterize because they are nearly indistinguishable from host rock using traditional seismic and well-logging tools. We are investigating the use of CO2 injection and production (push-pull) in faults and fractures for contrast enhancement for better characterization by active seismic, well logging, and push-pull pressure transient analysis. Our approach consists of numerical simulation and feasibility assessment using conceptual models of potential enhanced geothermal system (EGS) sites such as Brady's Hot Spring and others. Faults in the deep subsurface typically have associated damage and gouge zones that provide a larger volume for uptake of CO2 than the slip plane alone. CO2 injected for push-pull well testing has a preference for flowing in the fault and fractures because CO2 is non-wetting relative to water and the permeability of open fractures and fault gouge is much higher than matrix. We are carrying out numerical simulations of injection and withdrawal of CO2 using TOUGH2/ECO2N. Simulations show that CO2 flows into the slip plane and gouge and damage zones and is driven upward by buoyancy during the push cycle over day-long time scales. Recovery of CO2 during the pull cycle is limited because of buoyancy effects. We then use the CO2 saturation field simulated by TOUGH2 in our anisotropic finite difference code from SPICE-with modifications for fracture compliance-that we use to model elastic wave propagation. Results show time-lapse differences in seismic response using a surface source. Results suggest that CO2 can be best imaged using time-lapse differencing of the P-wave and P-to-S-wave scattering in a vertical seismic profile (VSP) configuration. Wireline well-logging tools that measure electrical conductivity show promise as another means to detect and image the CO2-filled fracture near the injection well and potential monitoring well(s), especially if a saline-water pre-flush is carried out to enhance conductivity contrast. Pressure-transient analysis is also carried out to further constrain fault zone characteristics. These multiple complementary characterization approaches are being used to develop working models of fault and fracture zone characteristics relevant to EGS energy recovery.

Analysis of microbial communities in the oil reservoir subjected to CO2-flooding by using functional genes as molecular biomarkers for microbial CO2 sequestration

PubMed Central

Liu, Jin-Feng; Sun, Xiao-Bo; Yang, Guang-Chao; Mbadinga, Serge M.; Gu, Ji-Dong; Mu, Bo-Zhong

2015-01-01

Sequestration of CO2 in oil reservoirs is considered to be one of the feasible options for mitigating atmospheric CO2 building up and also for the in situ potential bioconversion of stored CO2 to methane. However, the information on these functional microbial communities and the impact of CO2 storage on them is hardly available. In this paper a comprehensive molecular survey was performed on microbial communities in production water samples from oil reservoirs experienced CO2-flooding by analysis of functional genes involved in the process, including cbbM, cbbL, fthfs, [FeFe]-hydrogenase, and mcrA. As a comparison, these functional genes in the production water samples from oil reservoir only experienced water-flooding in areas of the same oil bearing bed were also analyzed. It showed that these functional genes were all of rich diversity in these samples, and the functional microbial communities and their diversity were strongly affected by a long-term exposure to injected CO2. More interestingly, microorganisms affiliated with members of the genera Methanothemobacter, Acetobacterium, and Halothiobacillus as well as hydrogen producers in CO2 injected area either increased or remained unchanged in relative abundance compared to that in water-flooded area, which implied that these microorganisms could adapt to CO2 injection and, if so, demonstrated the potential for microbial fixation and conversion of CO2 into methane in subsurface oil reservoirs. PMID:25873911

The cost of getting CCS wrong: Uncertainty, infrastructure design, and stranded CO 2

DOE PAGES

Middleton, Richard Stephen; Yaw, Sean Patrick

2018-01-11

Carbon capture, and storage (CCS) infrastructure will require industry—such as fossil-fuel power, ethanol production, and oil and gas extraction—to make massive investment in infrastructure. The cost of getting these investments wrong will be substantial and will impact the success of CCS technology. Multiple factors can and will impact the success of commercial-scale CCS, including significant uncertainties regarding capture, transport, and injection-storage decisions. Uncertainties throughout the CCS supply chain include policy, technology, engineering performance, economics, and market forces. In particular, large uncertainties exist for the injection and storage of CO 2. Even taking into account upfront investment in site characterization, themore » final performance of the storage phase is largely unknown until commercial-scale injection has started. We explore and quantify the impact of getting CCS infrastructure decisions wrong based on uncertain injection rates and uncertain CO 2 storage capacities using a case study managing CO 2 emissions from the Canadian oil sands industry in Alberta. We use SimCCS, a widely used CCS infrastructure design framework, to develop multiple CCS infrastructure scenarios. Each scenario consists of a CCS infrastructure network that connects CO 2 sources (oil sands extraction and processing) with CO 2 storage reservoirs (acid gas storage reservoirs) using a dedicated CO 2 pipeline network. Each scenario is analyzed under a range of uncertain storage estimates and infrastructure performance is assessed and quantified in terms of cost to build additional infrastructure to store all CO 2. We also include the role of stranded CO 2, CO 2 that a source was expecting to but cannot capture due substandard performance in the transport and storage infrastructure. Results show that the cost of getting the original infrastructure design wrong are significant and that comprehensive planning will be required to ensure that CCS becomes a successful climate mitigation technology. Here, we show that the concept of stranded CO 2 can transform a seemingly high-performing infrastructure design into the worst case scenario.« less

The cost of getting CCS wrong: Uncertainty, infrastructure design, and stranded CO 2

DOE Office of Scientific and Technical Information (OSTI.GOV)

Middleton, Richard Stephen; Yaw, Sean Patrick

Carbon capture, and storage (CCS) infrastructure will require industry—such as fossil-fuel power, ethanol production, and oil and gas extraction—to make massive investment in infrastructure. The cost of getting these investments wrong will be substantial and will impact the success of CCS technology. Multiple factors can and will impact the success of commercial-scale CCS, including significant uncertainties regarding capture, transport, and injection-storage decisions. Uncertainties throughout the CCS supply chain include policy, technology, engineering performance, economics, and market forces. In particular, large uncertainties exist for the injection and storage of CO 2. Even taking into account upfront investment in site characterization, themore » final performance of the storage phase is largely unknown until commercial-scale injection has started. We explore and quantify the impact of getting CCS infrastructure decisions wrong based on uncertain injection rates and uncertain CO 2 storage capacities using a case study managing CO 2 emissions from the Canadian oil sands industry in Alberta. We use SimCCS, a widely used CCS infrastructure design framework, to develop multiple CCS infrastructure scenarios. Each scenario consists of a CCS infrastructure network that connects CO 2 sources (oil sands extraction and processing) with CO 2 storage reservoirs (acid gas storage reservoirs) using a dedicated CO 2 pipeline network. Each scenario is analyzed under a range of uncertain storage estimates and infrastructure performance is assessed and quantified in terms of cost to build additional infrastructure to store all CO 2. We also include the role of stranded CO 2, CO 2 that a source was expecting to but cannot capture due substandard performance in the transport and storage infrastructure. Results show that the cost of getting the original infrastructure design wrong are significant and that comprehensive planning will be required to ensure that CCS becomes a successful climate mitigation technology. Here, we show that the concept of stranded CO 2 can transform a seemingly high-performing infrastructure design into the worst case scenario.« less

Carbon dioxide coronary angiography: A mechanical feasibility study with a cardiovascular simulator

NASA Astrophysics Data System (ADS)

Corazza, Ivan; Taglieri, Nevio; Pirazzini, Edoardo; Rossi, Pier Luca; Lombi, Alessandro; Scalise, Filippo; Caridi, James G.; Zannoli, Romano

2018-01-01

The aim of this study was to carry out a bench evaluation of the biomechanical feasibility of carbon dioxide (CO2) coronary arteriography. Many patients among the aging population of individuals requiring cardiac intervention have underlying renal insufficiency making them susceptible to contrast-induced nephropathy. To include those patients, it is imperative to find an alternative and safe technique to perform coronary imaging on cardiac ischemic patients. As CO2 angiography has no renal toxicity, it may be a possible solution offering good imaging with negligible collateral effects. Theoretically, by carefully controlling the gas injection process, new automatic injectors may avoid gas reflux into the aorta and possible cerebral damage. A feasibility study is mandatory. A mechanical mock of the coronary circulation was developed and employed. CO2 was injected into the coronary ostium with 2 catheters (2F and 6F) and optical images of bubbles flowing inside the vessels at different injection pressures were recorded. The gas behavior was then carefully studied for quantitative and qualitative analysis. Video recordings showed that CO2 injection at a precise pressure in the interval between the arterial dicrotic notch and the minimum diastolic value does not result in gas reflow into the aorta. Gas reflow was easier to control with the smaller catheter, but the gas bubbles were smaller with different vascular filling. Our simulation demonstrates that carefully selected injection parameters allow CO2 coronary imaging without any risk of gas reflux into the aorta.

The Coal-Seq III Consortium. Advancing the Science of CO 2 Sequestration in Coal Seam and Gas Shale Reservoirs

DOE Office of Scientific and Technical Information (OSTI.GOV)

Koperna, George

The Coal-Seq consortium is a government-industry collaborative that was initially launched in 2000 as a U.S. Department of Energy sponsored investigation into CO2 sequestration in deep, unmineable coal seams. The consortium’s objective aimed to advancing industry’s understanding of complex coalbed methane and gas shale reservoir behavior in the presence of multi-component gases via laboratory experiments, theoretical model development and field validation studies. Research from this collaborative effort was utilized to produce modules to enhance reservoir simulation and modeling capabilities to assess the technical and economic potential for CO2 storage and enhanced coalbed methane recovery in coal basins. Coal-Seq Phase 3more » expands upon the learnings garnered from Phase 1 & 2, which has led to further investigation into refined model development related to multicomponent equations-of-state, sorption and diffusion behavior, geomechanical and permeability studies, technical and economic feasibility studies for major international coal basins the extension of the work to gas shale reservoirs, and continued global technology exchange. The first research objective assesses changes in coal and shale properties with exposure to CO2 under field replicated conditions. Results indicate that no significant weakening occurs when coal and shale were exposed to CO2, therefore, there was no need to account for mechanical weakening of coal due to the injection of CO2 for modeling. The second major research objective evaluates cleat, Cp, and matrix, Cm, swelling/shrinkage compressibility under field replicated conditions. The experimental studies found that both Cp and Cm vary due to changes in reservoir pressure during injection and depletion under field replicated conditions. Using laboratory data from this study, a compressibility model was developed to predict the pore-volume compressibility, Cp, and the matrix compressibility, Cm, of coal and shale, which was applied to modeling software to enhance model robustness. Research was also conducted to improve algorithms and generalized adsorption models to facilitate realistic simulation of CO2 sequestration in coal seams and shale gas reservoirs. The interaction among water and the adsorbed gases, carbon dioxide (CO2), methane (CH4), and nitrogen (N2) in coalbeds is examined using experimental in situ laboratory techniques to comprehensively model CBM production and CO2 sequestration in coals. An equation of state (EOS) module was developed which is capable of predicting the density of pure components and mixtures involving the wet CBM gases CH4, CO2, and N2 at typical reservoir condition, and is used to inform CO2 injection models. The final research objective examined the effects adsorbed CO2 has on coal strength and permeability. This research studied the weakening or failure of coal by the adsorption of CO2 from empirically derived gas production data to develop models for advanced modeling of permeability changes during CO2 sequestration. The results of this research effort have been used to construct a new and improved model for assessing changes in permeability of coal reservoirs due CO2 injection. The modules developed from these studies and knowledge learned are applied to field validation and basin assessment studies. These data were used to assess the flow and storage of CO2 in a shale reservoir, test newly developed code against large-scale projects, and conduct a basin-oriented review of coal storage potential in the San Juan Basin. The storage potential and flow of CO2 was modeled for shale sequestration of a proprietary Marcellus Shale horizontal gas production well using COMET3 simulation software. Simulation results from five model runs indicate that stored CO2 quantities are linked to the duration of primary production preceding injection. Matrix CO2 saturation is observed to increase in each shale zone after injection with an increase in primary production, and the size of the CO2 plume is also observed to increase in size the longer initial production is sustained. The simulation modules developed around the Coal-Seq experimental work are also incorporated into a pre-existing large-scale numerical simulation model of the Pump Canyon CO2-ECBM pilot in the San Juan Basin. The new model was applied to re-history match the data set to explore the improvements made in permeability prediction against previously published data sets and to validate this module. The assessment of the new data, however, indicates that the impact of the variable Cp is negligible on the overall behavior of the coal for CO2 storage purposes. Applying these new modules, the San Juan Basin and the Marcellus Shale are assessed for their technical ECBM/AGR and CO2 storage potential and the economic potential of these operations. The San Juan Basin was divided into 4 unique geographic zones based on production history, and the Marcellus was divided into nine. Each was assessed based upon each zone’s properties, and simulations were run to assess the potential of full Basin development. Models of a fully developed San Juan Basin suggest the potential for up to 104 Tcf of CO2 storage, and 12.3 Tcf of methane recovery. The Marcellus models suggest 1,248 Tcf of CO2 storage and 924 Tcf of AGR. The economics are deemed favorable where credits cover the cost of CO2 in the San Juan Basin, and in many cases in the Marcellus, but to maximize storage potential, credits need to extend to pay the operator to store CO2.« less

Pore network quantification of sandstones under experimental CO2 injection using image analysis

NASA Astrophysics Data System (ADS)

Berrezueta, Edgar; González-Menéndez, Luís; Ordóñez-Casado, Berta; Olaya, Peter

2015-04-01

Automated-image identification and quantification of minerals, pores and textures together with petrographic analysis can be applied to improve pore system characterization in sedimentary rocks. Our case study is focused on the application of these techniques to study the evolution of rock pore network subjected to super critical CO2-injection. We have proposed a Digital Image Analysis (DIA) protocol that guarantees measurement reproducibility and reliability. This can be summarized in the following stages: (i) detailed description of mineralogy and texture (before and after CO2-injection) by optical and scanning electron microscopy (SEM) techniques using thin sections; (ii) adjustment and calibration of DIA tools; (iii) data acquisition protocol based on image capture with different polarization conditions (synchronized movement of polarizers); (iv) study and quantification by DIA that allow (a) identification and isolation of pixels that belong to the same category: minerals vs. pores in each sample and (b) measurement of changes in pore network, after the samples have been exposed to new conditions (in our case: SC-CO2-injection). Finally, interpretation of the petrography and the measured data by an automated approach were done. In our applied study, the DIA results highlight the changes observed by SEM and microscopic techniques, which consisted in a porosity increase when CO2 treatment occurs. Other additional changes were minor: variations in the roughness and roundness of pore edges, and pore aspect ratio, shown in the bigger pore population. Additionally, statistic tests of pore parameters measured were applied to verify that the differences observed between samples before and after CO2-injection were significant.

Stable large-scale CO2 storage in defiance of an energy system based on renewable energy - Modelling the impact of varying CO2 injection rates on reservoir behavior

NASA Astrophysics Data System (ADS)

Bannach, Andreas; Hauer, Rene; Martin, Streibel; Stienstra, Gerard; Kühn, Michael

2015-04-01

The IPCC Report 2014 strengthens the need for CO2 storage as part of CCS or BECCS to reach ambitious climate goals despite growing energy demand in the future. The further expansion of renewable energy sources is a second major pillar. As it is today in Germany the weather becomes the controlling factor for electricity production by fossil fuelled power plants which lead to significant fluctuations of CO2-emissions which can be traced in injection rates if the CO2 were captured and stored. To analyse the impact of such changing injection rates on a CO2 storage reservoir. two reservoir simulation models are applied: a. An (smaller) reservoir model approved by gas storage activities for decades, to investigate the dynamic effects in the early stage of storage filling (initial aquifer displacement). b. An anticline structure big enough to accommodate a total amount of ≥ 100 Mega tons CO2 to investigate the dynamic effects for the entire operational life time of the storage under particular consideration of very high filling levels (highest aquifer compression). Therefore a reservoir model was generated. The defined yearly injection rate schedule is based on a study performed on behalf of IZ Klima (DNV GL, 2014). According to this study the exclusive consideration of a pool of coal-fired power plants causes the most intensive dynamically changing CO2 emissions and hence accounts for variations of a system which includes industry driven CO2 production. Besides short-term changes (daily & weekly cycles) seasonal influences are also taken into account. Simulation runs cover a variation of injection points (well locations at the top vs. locations at the flank of the structure) and some other largely unknown reservoir parameters as aquifer size and aquifer mobility. Simulation of a 20 year storage operation is followed by a post-operational shut-in phase which covers approximately 500 years to assess possible effects of changing injection rates on the long-term reservoir behaviour. The cyclic injection operation has an impact on the requirements of the facility design. To define the design basis for the aboveground installations only wellhead pressures are to be considered. For this reason the calculated bottom hole pressures need to be transferred into wellhead pressures. This is done by the application of thermodynamic models which include all relevant processes associated with the fluid flow through production or injection strings. Finally, a commercial analysis is carried out which is based on a total cost estimate (CAPEX & OPEX). The outcome of this analysis demonstrates required certificate prices to reach the common return targets of an industrial project. References DNV GL, " CO2 Transport Infrastructure in Germany - Necessity and Boundary Conditions up to 2050", IZ Klima, Berlin, 2014, http://www.iz-klima.de/.

Geospatial Analysis of Near-Term Technical Potential of BECCS in the U.S.

NASA Astrophysics Data System (ADS)

Baik, E.; Sanchez, D.; Turner, P. A.; Mach, K. J.; Field, C. B.; Benson, S. M.

2017-12-01

Atmospheric carbon dioxide (CO2) removal using bioenergy with carbon capture and storage (BECCS) is crucial for achieving stringent climate change mitigation targets. To date, previous work discussing the feasibility of BECCS has largely focused on land availability and bioenergy potential, while CCS components - including capacity, injectivity, and location of potential storage sites - have not been thoroughly considered in the context of BECCS. A high-resolution geospatial analysis of both biomass production and potential geologic storage sites is conducted to consider the near-term deployment potential of BECCS in the U.S. The analysis quantifies the overlap between the biomass resource and CO2 storage locations within the context of storage capacity and injectivity. This analysis leverages county-level biomass production data from the U.S. Department of Energy's Billion Ton Report alongside potential CO2 geologic storage sites as provided by the USGS Assessment of Geologic Carbon Dioxide Storage Resources. Various types of lignocellulosic biomass (agricultural residues, dedicated energy crops, and woody biomass) result in a potential 370-400 Mt CO2 /yr of negative emissions in 2020. Of that CO2, only 30-31% of the produced biomass (110-120 Mt CO2 /yr) is co-located with a potential storage site. While large potential exists, there would need to be more than 250 50-MW biomass power plants fitted with CCS to capture all the co-located CO2 capacity in 2020. Neither absolute injectivity nor absolute storage capacity is likely to limit BECCS, but the results show regional capacity and injectivity constraints in the U.S. that had not been identified in previous BECCS analysis studies. The state of Illinois, the Gulf region, and western North Dakota emerge as the best locations for near-term deployment of BECCS with abundant biomass, sufficient storage capacity and injectivity, and the co-location of the two resources. Future studies assessing BECCS potential should employ higher-resolution spatial datasets to identify near-term deployment opportunities, explicitly including the availability of co-located storage, regional capacity limitations, and integration of electricity produced with BECCS into local electricity grids.

Mode selection and frequency tuning by injection in pulsed TEA-CO2 lasers

NASA Technical Reports Server (NTRS)

Flamant, P. H.; Menzies, R. T.

1983-01-01

An analytical model characterizing pulsed-TEA-CO2-laser injection locking by tunable CW-laser radiation is presented and used to explore the requirements for SLM pulse generation. Photon-density-rate equations describing the laser mechanism are analyzed in terms of the mode competition between photon densities emitted at two frequencies. The expression derived for pulsed dye lasers is extended to homogeneously broadened CO2 lasers, and locking time is defined as a function of laser parameters. The extent to which injected radiation can be detuned from the CO2 line center and continue to produce SLM pulses is investigated experimentally in terms of the analytical framework. The dependence of locking time on the detuning/pressure-broadened-halfwidth ratio is seen as important for spectroscopic applications requiring tuning within the TEA-laser line-gain bandwidth.

CO2 adsorption-assisted CH4 desorption on carbon models of coal surface: A DFT study

NASA Astrophysics Data System (ADS)

Xu, He; Chu, Wei; Huang, Xia; Sun, Wenjing; Jiang, Chengfa; Liu, Zhongqing

2016-07-01

Injection of CO2 into coal is known to improve the yields of coal-bed methane gas. However, the technology of CO2 injection-enhanced coal-bed methane (CO2-ECBM) recovery is still in its infancy with an unclear mechanism. Density functional theory (DFT) calculations were performed to elucidate the mechanism of CO2 adsorption-assisted CH4 desorption (AAD). To simulate coal surfaces, different six-ring aromatic clusters (2 × 2, 3 × 3, 4 × 4, 5 × 5, 6 × 6, and 7 × 7) were used as simplified graphene (Gr) carbon models. The adsorption and desorption of CH4 and/or CO2 on these carbon models were assessed. The results showed that a six-ring aromatic cluster model (4 × 4) can simulate the coal surface with limited approximation. The adsorption of CO2 onto these carbon models was more stable than that in the case of CH4. Further, the adsorption energies of single CH4 and CO2 in the more stable site were -15.58 and -18.16 kJ/mol, respectively. When two molecules (CO2 and CH4) interact with the surface, CO2 compels CH4 to adsorb onto the less stable site, with a resulting significant decrease in the adsorption energy of CH4 onto the surface of the carbon model with pre-adsorbed CO2. The Mulliken charges and electrostatic potentials of CH4 and CO2 adsorbed onto the surface of the carbon model were compared to determine their respective adsorption activities and changes. At the molecular level, our results showed that the adsorption of the injected CO2 promoted the desorption of CH4, the underlying mechanism of CO2-ECBM.

Experimental observation of direct particle acceleration by stimulated emission of radiation.

PubMed

Banna, Samer; Berezovsky, Valery; Schächter, Levi

2006-09-29

We report the first experimental evidence for direct particle acceleration by stimulated emission of radiation. In the framework of this proof-of-principle experiment, a 45 MeV electron macrobunch was modulated by a high-power CO2 laser and then injected into an excited CO2 gas mixture. The emerging microbunches experienced a 0.15% relative change in the kinetic energy, in a less than 40 cm long interaction region. According to our experimental results, a fraction of these electrons have gained more than 200 keV each, implying that such an electron has undergone an order of magnitude of 2 x 10(6) collisions of the second kind.

Effects of raised CO2 concentration on the egg production rate and early development of two marine copepods (Acartia steueri and Acartia erythraea).

PubMed

Kurihara, Haruko; Shimode, Shinji; Shirayama, Yoshihisa

2004-11-01

Direct injection of CO(2) into the deep ocean is receiving increasing attention as a way to mitigate increasing atmospheric CO(2) concentration. To assess the potential impact of the environmental change associated with CO(2) sequestration in the ocean, we studied the lethal and sub-lethal effects of raised CO(2) concentration in seawater on adult and early stage embryos of marine planktonic copepods. We found that the reproduction rate and larval development of copepods are very sensitive to increased CO(2) concentration. The hatching rate tended to decrease, and nauplius mortality rate to increase, with increased CO(2) concentration. These results suggest that the marine copepod community will be negatively affected by the disposal of CO(2). This could decrease on the carbon export flux to the deep ocean and change the biological pump. Clearly, further studies are needed to determine whether ocean CO(2) injection is an acceptable strategy to reduce anthropogenic CO(2).

Potential impacts of CO2 leakage from the CCS sites on seed germination and soil microbial enzyme activities

NASA Astrophysics Data System (ADS)

Wenmei, H.; Yoo, G.; Kim, Y.; Moonis, M.

2015-12-01

To ensure the safety of carbon capture and storage (CCS) technology, it is essential to assess the impacts of potential CO2 leakage on the soil and ecosystem. The changes in soil environment due to the CO2 leakage might have an enormous effect on the plant growth. As a preliminary study, we conducted a research focusing on the germination process because it is known to be especially sensitive to the environmental change. The objective of this study is to investigate the impacts of high soil CO2 concentration on the germination of different species. A laboratory experiment was designed to investigate the effect of high soil CO2 concentration on germination rate and soil physicochemical/microbial parameters. Cabbage, corn, bean, and wheat were selected for this study. The concentrations of the injected CO2 treatments were 10%, 30%, 60% and 100%, and the actual soil CO2 concentration ranged from 3.6% to 53.2%. Two types of controls were employed: the one connected with ambient air tank and the other connected with nothing. The final germination rates of four crops were not different between the controls and 10% treatment, but the delay of germination was observed in cabbage, corn, and bean. At 30% treatment, the germination rates of cabbage, corn and bean were 38%, while that of wheat was 78%. No seed was germinated at 60% and 100% treatments. After the incubation, soil pH decreased from 6.0 in the controls to 5.6 in the 100% treatment. The contents of soil total C and total N were not different among treatments. Activities of microbial fluorescein diacetate hydrolysis were not different among treatments for all plants. Five kinds of soil extracellular enzyme activities were not affected by the CO2 treatments. Our results suggest that: 1) Soil CO2 concentration at 3-4% did not inhibit germination of four crops. 2) Wheat is most resistant to high soil CO2 concentration in this study. 3) Soil microbial parameters were more tolerant during the short term injection.

Enhancement of low power CO2 laser cutting process for injection molded polycarbonate

NASA Astrophysics Data System (ADS)

Moradi, Mahmoud; Mehrabi, Omid; Azdast, Taher; Benyounis, Khaled Y.

2017-11-01

Laser cutting technology is a non-contact process that typically is used for industrial manufacturing applications. Laser cut quality is strongly influenced by the cutting processing parameters. In this research, CO2 laser cutting specifications have been investigated by using design of experiments (DOE) with considering laser cutting speed, laser power and focal plane position as process input parameters and kerf geometry dimensions (i.e. top and bottom kerf width, ratio of the upper kerf to lower kerf, upper heat affected zone (HAZ)) and surface roughness of the kerf wall as process output responses. A 60 Watts CO2 laser cutting machine is used for cutting the injection molded samples of polycarbonate sheet with the thickness of 3.2 mm. Results reveal that by decreasing the laser focal plane position and laser power, the bottom kerf width will be decreased. Also the bottom kerf width decreases by increasing the cutting speed. As a general result, locating the laser spot point in the depth of the workpiece the laser cutting quality increases. Minimum value of the responses (top kerf, heat affected zone, ratio of the upper kerf to lower kerf, and surface roughness) are considered as optimization criteria. Validating the theoretical results using the experimental tests is carried out in order to analyze the results obtained via software.

Influence of methane in CO2 transport and storage for CCS technology.

PubMed

Blanco, Sofía T; Rivas, Clara; Fernández, Javier; Artal, Manuela; Velasco, Inmaculada

2012-12-04

CO(2) Capture and Storage (CCS) is a good strategy to mitigate levels of atmospheric greenhouse gases. The type and quantity of impurities influence the properties and behavior of the anthropogenic CO(2), and so must be considered in the design and operation of CCS technology facilities. Their study is necessary for CO(2) transport and storage, and to develop theoretical models for specific engineering applications to CCS technology. In this work we determined the influence of CH(4), an important impurity of anthropogenic CO(2), within different steps of CCS technology: transport, injection, and geological storage. For this, we obtained new pressure-density-temperature (PρT) and vapor-liquid equilibrium (VLE) experimental data for six CO(2) + CH(4) mixtures at compositions which represent emissions from the main sources in the European Union and United States. The P and T ranges studied are within those estimated for CO(2) pipelines and geological storage sites. From these data we evaluated the minimal pressures for transport, regarding the density and pipeline's capacity requirements, and values for the solubility parameter of the mixtures, a factor which governs the solubility of substances present in the reservoir before injection. We concluded that the presence of CH(4) reduces the storage capacity and increases the buoyancy of the CO(2) plume, which diminishes the efficiency of solubility and residual trapping of CO(2), and reduces the injectivity into geological formations.

Regional-scale brine migration along vertical pathways due to CO2 injection - Part 1: The participatory modeling approach

NASA Astrophysics Data System (ADS)

Scheer, Dirk; Konrad, Wilfried; Class, Holger; Kissinger, Alexander; Knopf, Stefan; Noack, Vera

2017-06-01

Saltwater intrusion into potential drinking water aquifers due to the injection of CO2 into deep saline aquifers is one of the potential hazards associated with the geological storage of CO2. Thus, in a site selection process, models for predicting the fate of the displaced brine are required, for example, for a risk assessment or the optimization of pressure management concepts. From the very beginning, this research on brine migration aimed at involving expert and stakeholder knowledge and assessment in simulating the impacts of injecting CO2 into deep saline aquifers by means of a participatory modeling process. The involvement exercise made use of two approaches. First, guideline-based interviews were carried out, aiming at eliciting expert and stakeholder knowledge and assessments of geological structures and mechanisms affecting CO2-induced brine migration. Second, a stakeholder workshop including the World Café format yielded evaluations and judgments of the numerical modeling approach, scenario selection, and preliminary simulation results. The participatory modeling approach gained several results covering brine migration in general, the geological model sketch, scenario development, and the review of the preliminary simulation results. These results were included in revised versions of both the geological model and the numerical model, helping to improve the analysis of regional-scale brine migration along vertical pathways due to CO2 injection.

Damage evaluation for crops exposed to a simulated leakage of geologically stored CO2 using hyperspectral imaging technology

NASA Astrophysics Data System (ADS)

Burud, Ingunn; Moni, Christophe; Flø, Andreas; Rolstad Denby, Cecilie; Rasse, Daniel

2013-04-01

Facilities for the geological storage of carbon dioxide (CO2) as part of carbon capture and storage (CCS) schemes will be designed to prevent any leakage from the defined 'storage complex'. However, even though the risk is of low probability, the precautionary principle requires that near surface environments that might be at risk be thoroughly monitored to detect a leak, were it to happen. Among all currently proposed monitoring methods, only hyperspectral imaging of vegetation stress response allows one to scan large areas rapidly and in detail. Until now, however, only a handful of studies have been carried out on using this novel technology. The aim of the present communication was to characterize the impacts that a simulated CO2 leak might have on the hyperspectral signature of a Norwegian oats crop. In order to test the effects of different intensity of leakage, a CO2 exposure field experiment was designed to create a longitudinal CO2 gradient. For this purpose a gas supply pipe was inserted at one end of a 6m by 3m experimental plot at the base of a 45 cm thick layer of sand buried 40 cm below the surface under a silt loam plough layer. CO2 was then injected at a rate of 2l.min-1 just after the oats had germinated at the end of June, and Facilities for the geological storage of carbon dioxide (CO2) as part of carbon capture and storage (CCS) schemes will be designed to prevent any leakage from the defined 'storage complex'. However, even though the risk is of low probability, the precautionary principle requires that near surface environments that might be at risk be thoroughly monitored to detect a leak, were it to happen. Among all currently proposed monitoring methods, only hyperspectral imaging of vegetation stress response allows one to scan large areas rapidly and in detail. Until now, however, only a handful of studies have been carried out on using this novel technology. The aim of the present communication was to characterize the impacts that a simulated CO2 leak might have on the hyperspectral signature of a Norwegian oats crop. In order to test the effects of different intensity of leakage, a CO2 exposure field experiment was designed to create a longitudinal CO2 gradient. For this purpose a gas supply pipe was inserted at one end of a 6m by 3m experimental plot at the base of a 45 cm thick layer of sand buried 40 cm below the surface under a silt loam plough layer. CO2 was then injected at a rate of 2l.min-1 just after the oats had germinated at the end of June, and continued until it was harvested at the end of August. Then soil CO2 fluxes were recorded at the surface using a (60 x 60 cm) grid sampling pattern. Hyperspectral images of the experimental plot were taken at different dates during the gassing period using a SPECIM camera with 800 spectral bands, covering the wavelength range 400 - 1000 nm. The change in the reflectance spectra were characterized over time within the plot by the computation of various hyperspectral vegetation indices for small discretized spatial units (i.e. 10 cm by 10 cm square). The results showed that one month after injection, reduced plant growth, yellowing of the leaves and purple discoloration of the stems were observed just above the injection points were high CO2 fluxes had been identified. These high CO2 flux zones were further associated with an increase of the reflectance that occurred in the red region of the spectra indicating a decrease of the chlorophyll content in the plants. To conclude, plant health, as indicated by the hyperspectral signature, was closely related to the leakage pattern, indicating that hyperspectral imaging could be used to identify a CO2 seepage in an agricultural field. Acknowledgments This work is part of the RISCS project (Research into Impacts and Safety in CO2 Storage), funded by the EC 7th Framework Programme and by industry partners ENEL I&I, Statoil, Vattenfall AB, E.ON and RWE. R&D partners are BGS, CERTH, IMARES, OGS, PML, SINTEF, University of Nottingham, Sapienza Università di Roma, Quintessa, CO2 GeoNet, Bioforsk, BGR and ZERO. For more information please go to the website (www.riscs-co2.eu) or contact the project coordinator David Jones (e-mail: dgj@bgs.ac.uk tel. +44(0)115-936-3576).

Experimental investigation of CO2-brine-rock interactions at simulated in-situ conditions

NASA Astrophysics Data System (ADS)

Słomski, Piotr; Lutyński, Marcin; Mastalerz, Maria; Szczepański, Jacek; Derkowski, Arkadiusz; Topór, Tomasz

2017-04-01

Geological sequestration of carbon dioxide (CO2) in deep formations (e.g. saline aquifers, oil and gas reservoirs and coalbeds) is one of the most promising options for reducing concentration of this anthropogenic greenhouse gas in the atmosphere. CO2 injected into the rock formations can be trapped by several mechanisms including structural and stratigraphic trapping, capillary CO2 trapping, dissolution trapping and mineral trapping. During dissolution trapping, CO2 dissolves in the formation brine and sinks in the reservoir as the CO2-enriched brine has an increased density. In comparison, in mineral trapping, CO2 is bound by precipitating new carbonate minerals. The latter two mechanisms depend on the temperature, pressure, and the mineralogy of the reservoir rock and the chemical composition of the brine. This study discusses laboratory scale alterations of Ordovician and Silurian shale rocks from potential CO2 sequestration site B1 in the Baltic Basin. In the reported experiment, rocks submerged in brine in specially constructed reactors were subjected to CO2 pressure of 30-35 MPa for 30-45 days at temperature of 80 oC. Shale samples were analyzed in terms of mineral composition and mesopore surface area and volume, before and after experiments, by means of X-ray diffraction and N2 low-pressure adsorption, respectively, for possible CO2 induced changes. Comparison of mineral composition before and after experiments demonstrated subtle mineral changes. The most conspicuous was a release of Fe in the form of Fe-oxyhydroxides, most probably related to the decomposition of Fe-bearing minerals like pyrite, chlorite and, less frequently, ankerite. With regard to porosity, interestingly, the most significant increase in mesopore surface area and mesopore volume was observed in samples with the largest drop of chlorite amount. The less significant mineral changes were associated with formation of kaolinite related to breakdown of feldspars and dissolution of carbonate minerals represented by calcite, dolomite, and ankerite. In the analyzed samples, no new carbonate minerals were formed during the experiments. An increase of carbonates was recorded only in three out of 13 samples. However, concentration of carbonates in these three samples is too low to conclude CO2 mineral trapping in new carbonate phases. Acknowledgments: the study was supported from grant SHALESEQ (No PL12-0109) funded by the National Centre for Research and Development.

Experimental study of CO2 dissolution a convection phenomenon at high pressure

NASA Astrophysics Data System (ADS)

Ben Salem, Imen; Chevalier, Sylvie; Faisal, Titly Farhana; Abderrahmane, Hamid; Sassi, Mohamed

2016-05-01

The density driven convection phenomenon has a significant role in enhancing the CO2 geological storage capacity. Deep saline aquifers are targeted for large scale geological sequestration. Once the CO2 is injected in saline aquifer, the supercritical CO2 rises up, forms a thin layer of free phase CO2, and the dissolution and molecular diffusion of the dissolved CO2 in brine begins. The CO2 saturated brine is denser than the original brine leading to gravitational convection of CO2 saturated brine. Convection accelerates the dissolution process and thus improves the safety and the efficiency of the sequestration. Laboratory experiments have been previously performed with experimental set-ups allowing the visualization of the phenomenon (1) eventually combined to the measurements of the dissolved CO2 mass transfer (2) as a function of the permeability of the medium. The visualization of the process was possible as Hele-Shaw cells at atmospheric pressure were used. Pressurized cylindrical vessel containing porous media allows measuring mass transfer of CO2 using the pressure decay concept (3) but visualization of the convection/dissolution was not possible for these setups. In this work, we performed experiments in a pressurized transparent cell similar to a Hele-Shaw cell but with bigger aperture. Permeability was varied by changing the size of the glass beads filling the cell. Bromocrysol green was used as a dye to track the pH change due to the presence of dissolved CO2 (1). The phenomenon is captured by a high resolution camera. We studied the effect of the pressure and of the permeability on the fingering pattern, the onset and the timescale of the phenomenon and the quantitative mass transfer of dissolved CO2. Experiments were validated on numerical simulations performed using STOMP (Subsurface Transport Over Multiple Phases) developed by the PNNL (Pacific Northwest National Laboratory) Hydrology group of the Department of Energy, USA. (1) Kneafsey, T.J., Pruess, K., 2010. Laboratory flow experiments for visualizing carbon dioxide-induced density-driven brine convection, Transport in Porous Media 82, 123-139. (2) Faisal, T. F., Chevalier, S., Bernabé, Y., Juanes, R. and M. Sassi. 2015. Quantitative and qualitative study of density driven CO2 mass transfer in a vertical Hele-Shaw cell. International Journal of Heat and Mass Transfer. Vol. 81, 901-914. (3) Farajzadeh, R.; Barati, A.; Delil, H. A.; Bruining, J.; Zitha, P. L. J., Mass transfer of CO2 into water and surfactant solutions, Petroleum Science and Technology 25 (12) (2007) 1493-1511.

Numerical simulations of CO2 -assisted gas production from hydrate reservoirs

NASA Astrophysics Data System (ADS)

Sridhara, P.; Anderson, B. J.; Myshakin, E. M.

2015-12-01

A series of experimental studies over the last decade have reviewed the feasibility of using CO2 or CO2+N2 gas mixtures to recover CH4 gas from hydrates deposits. That technique would serve the dual purpose of CO2 sequestration and production of CH4 while maintaining the geo-mechanical stability of the reservoir. In order to analyze CH4 production process by means of CO2 or CO2+N2 injection into gas hydrate reservoirs, a new simulation tool, Mix3HydrateResSim (Mix3HRS)[1], was previously developed to account for the complex thermodynamics of multi-component hydrate phase and to predict the process of CH4 substitution by CO2 (and N2) in the hydrate lattice. In this work, Mix3HRS is used to simulate the CO2 injection into a Class 2 hydrate accumulation characterized by a mobile aqueous phase underneath a hydrate bearing sediment. That type of hydrate reservoir is broadly confirmed in permafrost and along seashore. The production technique implies a two-stage approach using a two-well design, one for an injector and one for a producer. First, the CO2 is injected into the mobile aqueous phase to convert it into immobile CO2 hydrate and to initiate CH4 release from gas hydrate across the hydrate-water boundary (generally designating the onset of a hydrate stability zone). Second, CH4 hydrate decomposition is induced by the depressurization method at a producer to estimate gas production potential over 30 years. The conversion of the free water phase into the CO2 hydrate significantly reduces competitive water production in the second stage, thereby improving the methane gas production. A base case using only the depressurization stage is conducted to compare with enhanced gas production predicted by the CO2-assisted technique. The approach also offers a possibility to permanently store carbon dioxide in the underground formation to greater extent comparing to a direct injection of CO2 into gas hydrate sediment. Numerical models are based on the hydrate formations at the Prudhoe Bay L-Pad region on the Alaska North Slope. References [1] N.Garapati, "Reservoir Simulation for Production of CH4 from Gas Hydrate Reservoirs Using CO2/CO2+N2 by HydrateResSim", Ph.D. thesis, West Virginia University, 2013.

The reactivity of plant-derived organic matter in the Amazon River and implications on aquatic carbon fluxes to the atmosphere and ocean

NASA Astrophysics Data System (ADS)

Ward, N. D.; Sawakuchi, H. O.; Keil, R. G.; da Silva, R.; Brito, D. C.; Cunha, A. C.; Gagne-Maynard, W.; de Matos, A.; Neu, V.; Bianchi, T. S.; Krusche, A. V.; Richey, J. E.

2014-12-01

The remineralization of terrestrially-derived organic carbon (OC), along with direct CO2 inputs from autochthonous plant respiration in floodplains, results in an evasive CO2 gas flux from inland waters that is an order of magnitude greater than the flux of OC to the ocean. This phenomenon is enhanced in tropical systems as a result of elevated temperatures and productivity relative to temperate and high-latitude counterparts. Likewise, this balance is suspected to be influenced by increasing global temperatures and alterations to hydrologic and land use regimes. Here, we assess the reactivity of terrestrial and aquatic plant-derived OM near the mouth of the Amazon River. The stable isotopic signature of CO2 (δ13CO2) was monitored in real-time during incubation experiments performed in a closed system gas phase equilibration chamber connected to a Picarro Cavity Ring-Down Spectrometer. Incubations were performed under natural conditions and with the injection of isotopically labeled terrestrial macromolecules (e.g. lignin) and algal fatty acids. Under natural conditions, δ13CO2 became more depleted, shifting from roughly -23‰ to -27‰ on average, suggesting that C3 terrestrial vegetation was the primary fuel for CO2 production. Upon separate injections of 13C-labeled lignin and algal fatty acids, δ13CO2 increased near instantaneously and peaked in under 12 hours. Roughly 75% of the labeled lignin was converted to CO2 at the peak in δ13CO2, whereas less than 20% of the algal fatty acids were converted to CO2 (preliminary data subject to change). The rate of labeled-OC remineralization was enhanced by the addition of a highly labile substrate (e.g. ethyl acetate). Likewise, constant measurements of O2/pCO2 along the lower river revealed anomalously high CO2 and low O2 levels near the confluence of the mainstem and large tributaries with high algal productivity. These collective results suggest that the remineralization of complex terrestrial macromolecules is a significant source of CO2 to tropical rivers, whereas algal-derived OC is primarily incorporated into the microbial loop/higher trophic levels and enhances the breakdown of more complex terrestrially-derived molecules (e.g. the "priming effect").

An experimental study of basaltic glass-H2O-CO2 interaction at 22 and 50 ° C: Implications for subsurface storage of CO2

NASA Astrophysics Data System (ADS)

Galeczka, Iwona; Wolff-Boenisch, Domenik; Oelkers, Eric H.; Gislason, Sigurdur R.

2014-05-01

A novel high pressure column flow reactor (HPCFR) was used to investigate the evolution of fluid chemistry along a 2.3 meter flow path during 37-104 days of pure water- and CO2-charged water- (0.3 M CO2(aq)) basaltic glass interaction experiments at 22 and 50 ° C. The scale of the HPCFR, the ability to sample a reactive fluid at discrete spatial intervals under pressure and the possibility to measure the dissolved inorganic carbon and pH in situ all render the HPCFR unique in comparison with other reactors constructed for studies of CO2-charged water-rock interaction. During the pure water-basaltic glass interaction experiment, the pH of the injected water evolved rapidly from 6.7 to 9-9.5 and most of the dissolved iron was consumed by secondary mineral formation, similar to natural basaltic groundwater systems. In contrast to natural systems, however, the dissolved aluminium concentration remained relatively high along the entire flow path. The reactive fluid was undersaturated with respect to basaltic glass and carbonate minerals, but supersaturated with respect to zeolites, clays, and Fe hydroxides. Basaltic glass dissolution in the CO2-charged water was closer to stoichiometry than in pure water. The mobility of metals increased significantly in the reactive fluid and the concentration of some metals, including Mn, Fe, Cr, Al, and As exceeded the WHO (World Health Organisation) allowable drinking water limits. Iron was mobile and the aqueous Fe2+/Fe3+ ratio increased along the flow path. Basaltic glass dissolution in the CO2-charged water did not overcome the pH buffer capacity of the fluid. The pH rose only from an initial pH of 3.4 to 4.5 along the first 18.5 cm of the column, then remained constant during the remaining 2.1 meters of the flow path. Increasing the temperature of the CO2-charged fluid from 22 to 50 ° C increased the relative amount of dissolved divalent iron along the flow path. After a significant initial increase along the first metre of the column, the dissolved aluminium concentration decreased consistent with its incorporation into secondary minerals. The dissolved chromium concentration evolution mimicked that of Al at 50 ° C, suggesting substitution of trivalent Cr for Al in secondary phases. According to PHREEQC calculations, the CO2-charged fluid was always undersaturated with respect to carbonate minerals within the column, but supersaturated with respect to clays and Fe hydroxides at 22 ° C and with respect to clays and Al hydroxides at 50 ° C. Substantial differences were found between modelled and measured dissolved element concentrations in the fluids during the experiments. These differences underscore the need to improve computational models before they can be used to predict with confidence the fate and consequences of carbon dioxide injected into the subsurface.

Manufacture of modified milk protein concentrate utilizing injection of carbon dioxide.

PubMed

Marella, Chenchaiah; Salunke, P; Biswas, A C; Kommineni, A; Metzger, L E

2015-06-01

Dried milk protein concentrate is produced from skim milk using a combination of processes such as ultrafiltration (UF), evaporation or nanofiltration, and spray drying. It is well established that dried milk protein concentrate (MPC) that contains 80% (MPC80) and greater protein content (relative to dry matter) can lose solubility during storage as a result of protein-protein interactions and formation of insoluble complexes. Previous studies have shown that partial replacement of calcium with sodium improves MPC80 functionality and prevents the loss in solubility during storage. Those studies have used pH adjustment with the addition of acids, addition of monovalent salts, or ion exchange treatment of UF retentate. The objective of this study was to use carbon dioxide to produce MPC80 with improved functionality. In this study, reduced-calcium MPC80 (RCMPC) was produced from skim milk that was subjected to injection of 2,200 ppm of CO2 before UF, along with additional CO2 injection at a flow rate of 1.5 to 2 L/min during UF. A control MPC80 (CtrlMPC) was also produced from the same lot of skim milk without injection of CO2. The above processes were replicated 3 times, using different lots of skim milk for each replication. All the UF retentates were spray dried using a pilot-scale dryer. Skim milk and UF retentates were tested for ζ-potential (net negative charge), particle size, and viscosity. All the MPC were stored at room (22±1°C) and elevated (40°C) temperatures for 6 mo. Solubility was measured by dissolving the dried MPC in water at 22°C and at 10°C (cold solubility). Injection of CO2 and the resultant solubilization of calcium phosphate had a significant effect on UF performance, resulting in 10 and 20% loss in initial and average flux, respectively. Processing of skim milk with injection of CO2 also resulted in higher irreversible fouling resistances. Compared with control, the reduced-calcium MPC had 28 and 34% less ash and calcium, respectively. Injection of CO2 resulted in a significant decrease in ζ-potential and a significant increase in the size of the casein micelle. Moreover, RCMPC had a significantly higher solubility after storage at room temperature and at elevated temperature. This study demonstrates that MPC80 with a reduced calcium and mineral content can be produced with injection of CO2 before and during UF of skim milk. Copyright © 2015 American Dairy Science Association. Published by Elsevier Inc. All rights reserved.

Subsurface Characterization and Seismic Monitoring for the Southwest Partnerships Phase III Demonstration Project at Farnsworth Field, TX

NASA Astrophysics Data System (ADS)

Will, R. A.; Balch, R. S.

2015-12-01

The Southwest Partnership on Carbon Sequestration is performing seismic based characterization and monitoring activities at an active CO2 EOR project at Farnsworth Field, Texas. CO2 is anthropogenically sourced from a fertilizer and an ethanol plant. The field has 13 CO2 injectors and has sequestered 302,982 metric tonnes of CO2 since October 2013. The field site provides an excellent laboratory for testing a range of monitoring technologies in an operating CO2 flood since planned development is sequential and allows for multiple opportunities to record zero CO2 baseline data, mid-flood data, and fully flooded data. The project is comparing and contrasting several scales of seismic technologies in order to determine best practices for large scale commercial sequestration projects. Characterization efforts include an 85 km2 3D surface seismic survey, baseline and repeat 3D VSP surveys centered on injection wells, cross-well tomography baseline and repeat surveys between injector/producer pairs, and a borehole passive seismic array to monitor induced seismicity. All surveys have contributed to detailed geologic models which were then used for fluid flow and risk assessment simulations. 3D VSP and cross-well data with repeat surveys have allowed for direct comparisons of the reservoir prior to CO2 injection and at eight months into injection, with a goal of imaging the CO2 plume as it moves away from injection wells. Additional repeat surveys at regular intervals will continue to refine the plume. The goal of this work is to demonstrate seismic based technologies to monitor CO2 sequestration projects, and to contribute to best practices manuals for commercial scale CO2 sequestration projects. In this talk the seismic plan will be outlined, progress towards goals enumerated, and preliminary results from baseline and repeat seismic data will be discussed. Funding for this project is provided by the U.S. Department of Energy under Award No. DE-FC26-05NT42591.

Monotoring of CO2 Sequestration at Sleipner Using Full Waveform Inversion in Time-lapse Mode.

NASA Astrophysics Data System (ADS)

Gosselet, A.; Singh, S. C.

2007-12-01

It is now widely admitted that recent increase of CO2 in the atmosphere is due to human activities. The consecutive greenhouse effect is a major ecological concern. Geological storage is one proposed way to reduce atmosphere CO2 emissions. The Sleipner methane field, North Sea, is the very first site where CO2 has been injected back into a deep saline aquifer. In 1996, the Norwegian company Statoil and its partners began the production of the methane. The extracted methane contains a relatively high ratio of CO2, between 4% and 9%, that has to be reduced below 2.5% before delivering into the pipeline. An environmental tax introduced in Norway as early as 1991 prompted the company to store the separated CO2 instead of releasing it into the atmosphere as usually done. The CO2 is injected at the base of the Utsira sands. This water bearing formation lies at a depth between 800 and 1000m and is sealed by a thick shale layer. Seismic monitoring is a key tool in this strategy from a security standpoint and for sequestration optimization itself. Consequently, 3D seismic data were acquired before injection in 1994 and after injection in 1999, 2001, 2002, 2004 and 2006. Well-log revealed that the reservoir is crossed by thin shale layers that are 1 to 10m thick. CO2 rises up and is confined vertically by the shale layers, favouring horizontal gas migration and creating gas bearing thin beds. Seismic imaging of the gas pockets is therefore a challenging problem because large velocity variations occur on very short distance. Classical processing of time-lapse data consists in subtracting repeated survey seismic traces from the pre- injection baseline traces to exhibit changes within the reservoir. This approach remains qualitative, providing only the shape and extent of the gas cloud. Instead, we propose to compare elastic models of the subsurface computed through 2D full wave form inversion, an advanced seismic imaging technique. This method is based on the wave equation numerical simulation and can account for complex propagation effects as encountered in the Sleipner time-lapse data. This makes possible quantitative estimation of P and S-wave velocities on the meter scale. We applied the technique to 2D lines from the 1994, 1999 and 2006 vintages. The resulting post- injection models were subtracted to the pre-injection model to determine both the geometry and the velocity structure of the gas bearing areas which will be used to quantify the amount of CO2 in different forms (free versus dissolved).

The role of mineral heterogeneity on the hydrogeochemical response of two fractured reservoir rocks in contact with dissolved CO2

NASA Astrophysics Data System (ADS)

Garcia Rios, Maria; Luquot, Linda; Soler, Josep M.; Cama, Jordi

2017-04-01

In this study we compare the hydrogeochemical response of two fractured reservoir rocks (limestone composed of 100 wt.% calcite and sandstone composed of 66 wt.% calcite, 28 wt.% quartz and 6 wt.% microcline) in contact with CO2-rich sulfate solutions. Flow-through percolation experiments were performed using artificially fractured limestone and sandstone cores and injecting a CO2-rich sulfate solution under a constant volumetric flow rate (from 0.2 to 60 mL/h) at P = 150 bar and T = 60 °C. Measurements of the pressure difference between the inlet and the outlet of the samples and of the aqueous chemistry enabled the determination of fracture permeability changes and net reaction rates. Additionally, X-ray computed microtomography (XCMT) was used to characterize and localized changes in fracture volume induced by dissolution and precipitation reactions. In all reacted cores an increase in fracture permeability and in fracture volume was always produced even when gypsum precipitation happened. The presence of inert silicate grains in sandstone samples favored the occurrence of largely distributed dissolution structures in contrast to localized dissolution in limestone samples. This phenomenon promoted greater dissolution and smaller precipitation in sandstone than in limestone experiments. As a result, in sandstone reservoirs, the larger increase in fracture volume as well as the more extended distribution of the created volume would favor the CO2 storage capacity. The different distribution of created volume between limestone and sandstone experiments led to a different variation in fracture permeability. The progressive stepped permeability increase for sandstone would be preferred to the sharp permeability increase for limestone to minimize risks related to CO2 injection, favor capillary trapping and reduce energetic storage costs. 2D reactive transport simulations that reproduce the variation in aqueous chemistry and the fracture geometry (dissolution pattern) were performed using CrunchFlow. The calcite reactive surface area had to be diminished with respect to the geometric surface area in order to account for the transport control of the calcite dissolution reaction at pH < 5. The fitted reactive surface area was higher under faster flow conditions, reflecting a decrease in transport control and a more distributed reaction in sandstone compared to limestone.

Maintained LTP and Memory Are Lost by Zn2+ Influx into Dentate Granule Cells, but Not Ca2+ Influx.

PubMed

Takeda, Atsushi; Tamano, Haruna; Hisatsune, Marie; Murakami, Taku; Nakada, Hiroyuki; Fujii, Hiroaki

2018-02-01

The idea that maintained LTP and memory are lost by either increase in intracellular Zn 2+ in dentate granule cells or increase in intracellular Ca 2+ was examined to clarify significance of the increases induced by excess synapse excitation. Both maintained LTP and space memory were impaired by injection of high K + into the dentate gyrus, but rescued by co-injection of CaEDTA, which blocked high K + -induced increase in intracellular Zn 2+ but not high K + -induced increase in intracellular Ca 2+ . High K + -induced disturbances of LTP and intracellular Zn 2+ are rescued by co-injection of 6-cyano-7-nitroquinoxakine-2,3-dione, an α-amino-3-hydroxy-5-methyl-4-isoxazolepropionate (AMPA) receptor antagonist, but not by co-injection of blockers of NMDA receptors, metabotropic glutamate receptors, and voltage-dependent calcium channels. Furthermore, AMPA impaired maintained LTP and the impairment was also rescued by co-injection of CaEDTA, which blocked increase in intracellular Zn 2+ , but not increase in intracellular Ca 2+ . NMDA and glucocorticoid, which induced Zn 2+ release from the internal stores, did not impair maintained LTP. The present study indicates that increase in Zn 2+ influx into dentate granule cells through AMPA receptors loses maintained LTP and memory. Regulation of Zn 2+ influx into dentate granule cells is more critical for not only memory acquisition but also memory retention than that of Ca 2+ influx.

Effect of injection matrix concentration on peak shape and separation efficiency in ion chromatography.

PubMed

Zhang, Ya; Lucy, Charles A

2014-12-05

In HPLC, injection of solvents that differ from the eluent can result in peak broadening due to solvent strength mismatch or viscous fingering. Broadened, distorted or even split analyte peaks may result. Past studies of this injection-induced peak distortion in reversed phase (RPLC) and hydrophilic interaction (HILIC) liquid chromatography have led to the conclusion that the sample should be injected in the eluent or a weaker solvent. However, there have been no studies of injection-induced peak distortion in ion chromatography (IC). To address this, injection-induced effects were studied for six inorganic anions (F-, Cl-, NO2-, Br-, NO3- and SO4(2-)) on a Dionex AS23 IC column using a HCO3-/CO3(2-) eluent. The VanMiddlesworth-Dorsey injection sensitivity parameter (s) showed that IC of anions has much greater tolerance to the injection matrix (HCO3-/CO3(2-) herein) mismatch than RPLC or HILIC. Even when the injection contained a ten-fold greater concentration of HCO3-/CO3(2-) than the eluent, the peak shapes and separation efficiencies of six analyte ions did not change significantly. At more than ten-fold greater matrix concentrations, analyte anions that elute near the system peak of the matrix were distorted, and in the extreme cases exhibited a small secondary peak on the analyte peak front. These studies better guide the degree of dilution needed prior to IC analysis of anions. Copyright © 2014 Elsevier B.V. All rights reserved.

CO 2 Sequestration and Enhanced Oil Recovery at Depleted Oil/Gas Reservoirs

DOE PAGES

Dai, Zhenxue; Viswanathan, Hari; Xiao, Ting; ...

2017-08-18

This study presents a quantitative evaluation of the operational and technical risks of an active CO 2-EOR project. A set of risk factor metrics is defined to post-process the Monte Carlo (MC) simulations for statistical analysis. The risk factors are expressed as measurable quantities that can be used to gain insight into project risk (e.g. environmental and economic risks) without the need to generate a rigorous consequence structure, which include (a) CO 2 injection rate, (b) net CO 2 injection rate, (c) cumulative CO 2 storage, (d) cumulative water injection, (e) oil production rate, (f) cumulative oil production, (g) cumulativemore » CH 4 production, and (h) CO 2 breakthrough time. The Morrow reservoir at the Farnsworth Unit (FWU) site, Texas, is used as an example for studying the multi-scale statistical approach for CO 2 accounting and risk analysis. A set of geostatistical-based MC simulations of CO 2-oil/gas-water flow and transport in the Morrow formation are conducted for evaluating the risk metrics. A response-surface-based economic model has been derived to calculate the CO 2-EOR profitability for the FWU site with a current oil price, which suggests that approximately 31% of the 1000 realizations can be profitable. If government carbon-tax credits are available, or the oil price goes up or CO 2 capture and operating expenses reduce, more realizations would be profitable.« less

CO 2 Sequestration and Enhanced Oil Recovery at Depleted Oil/Gas Reservoirs

DOE Office of Scientific and Technical Information (OSTI.GOV)

Dai, Zhenxue; Viswanathan, Hari; Xiao, Ting

This study presents a quantitative evaluation of the operational and technical risks of an active CO 2-EOR project. A set of risk factor metrics is defined to post-process the Monte Carlo (MC) simulations for statistical analysis. The risk factors are expressed as measurable quantities that can be used to gain insight into project risk (e.g. environmental and economic risks) without the need to generate a rigorous consequence structure, which include (a) CO 2 injection rate, (b) net CO 2 injection rate, (c) cumulative CO 2 storage, (d) cumulative water injection, (e) oil production rate, (f) cumulative oil production, (g) cumulativemore » CH 4 production, and (h) CO 2 breakthrough time. The Morrow reservoir at the Farnsworth Unit (FWU) site, Texas, is used as an example for studying the multi-scale statistical approach for CO 2 accounting and risk analysis. A set of geostatistical-based MC simulations of CO 2-oil/gas-water flow and transport in the Morrow formation are conducted for evaluating the risk metrics. A response-surface-based economic model has been derived to calculate the CO 2-EOR profitability for the FWU site with a current oil price, which suggests that approximately 31% of the 1000 realizations can be profitable. If government carbon-tax credits are available, or the oil price goes up or CO 2 capture and operating expenses reduce, more realizations would be profitable.« less

The Effects of CO2 Injection and Barrel Temperatures on the Physiochemical and Antioxidant Properties of Extruded Cereals

PubMed Central

Thin, Thazin; Myat, Lin; Ryu, Gi-Hyung

2016-01-01

The effects of CO2 injection and barrel temperatures on the physiochemical and antioxidant properties of extruded cereals (sorghum, barley, oats, and millet) were studied. Extrusion was carried out using a twin-screw extruder at different barrel temperatures (80, 110, and 140°C), CO2 injection (0 and 500 mL/min), screw speed of 200 rpm, and moisture content of 25%. Extrusion significantly increased the total flavonoid content (TFC) of extruded oats, and β-glucan and protein digestibility (PD) of extruded barley and oats. In contrast, there were significant reductions in 1,1-diphenyl-2-picrylhydrazyl (DPPH) radical scavenging activity, PD of extruded sorghum and millet, as well as resistant starch (RS) of extruded sorghum and barley, and total phenolic content (TPC) of all extrudates, except extruded millet. At a barrel temperature of 140°C, TPC in extruded barley was significantly increased, and there was also an increase in DPPH and PD in extruded millet with or without CO2 injection. In contrast, at a barrel temperature of 140°C, the TPC of extruded sorghum decreased, TFC of extruded oats decreased, and at a barrel temperature of 110°C, PD of extruded sorghum without CO2 decreased. Some physical properties [expansion ratio (ER), specific length, piece density, color, and water absorption index] of the extrudates were significantly affected by the increase in barrel temperature. The CO2 injection significantly affected some physical properties (ER, specific length, piece density, water solubility index, and water absorption index), TPC, DPPH, β-glucan, and PD. In conclusion, extruded barley and millet had higher potential for making value added cereal-based foods than the other cereals. PMID:27752504

DOE Office of Scientific and Technical Information (OSTI.GOV)

Friedmann, S J

Carbon capture and sequestration (CCS) has emerged as a key technology for dramatic short-term reduction in greenhouse gas emissions in particular from large stationary. A key challenge in this arena is the monitoring and verification (M&V) of CO2 plumes in the deep subsurface. Towards that end, we have developed a tool that can simultaneously invert multiple sub-surface data sets to constrain the location, geometry, and saturation of subsurface CO2 plumes. We have focused on a suite of unconventional geophysical approaches that measure changes in electrical properties (electrical resistance tomography, electromagnetic induction tomography) and bulk crustal deformation (til-meters). We had alsomore » used constraints of the geology as rendered in a shared earth model (ShEM) and of the injection (e.g., total injected CO{sub 2}). We describe a stochastic inversion method for mapping subsurface regions where CO{sub 2} saturation is changing. The technique combines prior information with measurements of injected CO{sub 2} volume, reservoir deformation and electrical resistivity. Bayesian inference and a Metropolis simulation algorithm form the basis for this approach. The method can (a) jointly reconstruct disparate data types such as surface or subsurface tilt, electrical resistivity, and injected CO{sub 2} volume measurements, (b) provide quantitative measures of the result uncertainty, (c) identify competing models when the available data are insufficient to definitively identify a single optimal model and (d) rank the alternative models based on how well they fit available data. We present results from general simulations of a hypothetical case derived from a real site. We also apply the technique to a field in Wyoming, where measurements collected during CO{sub 2} injection for enhanced oil recovery serve to illustrate the method's performance. The stochastic inversions provide estimates of the most probable location, shape, volume of the plume and most likely CO{sub 2} saturation. The results suggest that the method can reconstruct data with poor signal to noise ratio and use hard constraints available from many sites and applications. External interest in the approach and method is high, and already commercial and DOE entities have requested technical work using the newly developed methodology for CO{sub 2} monitoring.« less

Mineral storage of CO2/H2S gas mixture injection in basaltic rocks

NASA Astrophysics Data System (ADS)

Clark, D. E.; Gunnarsson, I.; Aradottir, E. S.; Oelkers, E. H.; Sigfússon, B.; Snæbjörnsdottír, S. Ó.; Matter, J. M.; Stute, M.; Júlíusson, B. M.; Gíslason, S. R.

2017-12-01

Carbon capture and storage is one solution to reducing CO2 emissions in the atmosphere. The long-term geological storage of buoyant supercritical CO2 requires high integrity cap rock. Some of the risk associated with CO2 buoyancy can be overcome by dissolving CO2 into water during its injection, thus eliminating its buoyancy. This enables injection into fractured rocks, such as basaltic rocks along oceanic ridges and on continents. Basaltic rocks are rich in divalent cations, Ca2+, Mg2+ and Fe2+, which react with CO2 dissolved in water to form stable carbonate minerals. This possibility has been successfully tested as a part of the CarbFix CO2storage pilot project at the Hellisheiði geothermal power plant in Iceland, where they have shown mineralization occurs in less than two years [1, 2]. Reykjavik Energy and the CarbFix group has been injecting a mixture of CO2 and H2S at 750 m depth and 240-250°C since June 2014; by 1 January 2016, 6290 tons of CO2 and 3530 tons of H2S had been injected. Once in the geothermal reservoir, the heat exchange and sufficient dissolution of the host rock neutralizes the gas-charged water and saturates the formation water respecting carbonate and sulfur minerals. A thermally stable inert tracer was also mixed into the stream to monitor the subsurface transport and to assess the degree of subsurface carbonation and sulfide precipitation [3]. Water and gas samples have been continuously collected from three monitoring wells and geochemically analyzed. Based on the results, mineral saturation stages have been defined. These results and tracer mass balance calculations are used to evaluate the rate and magnitude of CO2 and H2S mineralization in the subsurface, with indications that mineralization of carbon and sulfur occurs within months. [1] Gunnsarsson, I., et al. (2017). Rapid and cost-effective capture and subsurface mineral storage of carbon and sulfur. Manuscript submitted for publication. [2] Matter, J., et al. (2016). Rapid carbon mineralization for permanent disposal of anthropogenic carbon dioxide emissions. Science 352 (6291), 1312-1314. [3] Snæbjörnsdottír, S.O., et al. (2017). The chemistry and saturation states of subsurface fluids during the in-situ mineralisation of CO2 and H2S at the CarbFix site in SW-Iceland. International Journal of Greenhouse Gas Control 58, 87-102.

Optimal distribution of borehole geophones for monitoring CO2-injection-induced seismicity

NASA Astrophysics Data System (ADS)

Huang, L.; Chen, T.; Foxall, W.; Wagoner, J. L.

2016-12-01

The U.S. DOE initiative, National Risk Assessment Partnership (NRAP), aims to develop quantitative risk assessment methodologies for carbon capture, utilization and storage (CCUS). As part of tasks of the Strategic Monitoring Group of NRAP, we develop a tool for optimal design of a borehole geophones distribution for monitoring CO2-injection-induced seismicity. The tool consists of a number of steps, including building a geophysical model for a given CO2 injection site, defining target monitoring regions within CO2-injection/migration zones, generating synthetic seismic data, giving acceptable uncertainties in input data, and determining the optimal distribution of borehole geophones. We use a synthetic geophysical model as an example to demonstrate the capability our new tool to design an optimal/cost-effective passive seismic monitoring network using borehole geophones. The model is built based on the geologic features found at the Kimberlina CCUS pilot site located in southern San Joaquin Valley, California. This tool can provide CCUS operators with a guideline for cost-effective microseismic monitoring of geologic carbon storage and utilization.

Environmental Assessment for Potential Impacts of Ocean CO2 Storage on Marine Biogeochemical Cycles

NASA Astrophysics Data System (ADS)

Yamada, N.; Tsurushima, N.; Suzumura, M.; Shibamoto, Y.; Harada, K.

2008-12-01

Ocean CO2 storage that actively utilizes the ocean potential to dissolve extremely large amounts of CO2 is a useful option with the intent of diminishing atmospheric CO2 concentration. CO2 storage into sub-seabed geological formations is also considered as the option which has been already put to practical reconnaissance in some projects. Direct release of CO2 in the ocean storage and potential CO2 leakage from geological formations into the bottom water can alter carbonate system as well as pH of seawater. It is essential to examine to what direction and extent chemistry change of seawater induced by CO2 can affect the marine environments. Previous studies have shown direct and acute effects by increasing CO2 concentrations on physiology of marine organisms. It is also a serious concern that chemistry change can affect the rates of chemical, biochemical and microbial processes in seawater resulting in significant influences on marine biogeochemical cycles of the bioelements including carbon, nutrients and trace metals. We, AIST, have conducted a series of basic researches to assess the potential impacts of ocean CO2 storage on marine biogeochemical processes including CaCO3 dissolution, and bacterial and enzymatic decomposition of organic matter. By laboratory experiments using a special high pressure apparatus, the improved empirical equation was obtained for CaCO3 dissolution rate in the high CO2 concentrations. Based on the experimentally obtained kinetics with a numerical simulation for a practical scenario of oceanic CO2 sequestration where 50 Mton CO2 per year is continuously injected to 1,000-2,500 m depth within 100 x 333 km area for 30 years, we could illustrate precise 3-D maps for the predicted distributions of the saturation depth of CaCO3, in situ Ω value and CaCO3 dissolution rate in the western North Pacific. The result showed no significant change in the bathypelagic CaCO3 flux due to chemistry change induced by ocean CO2 sequestration. Both bacteria and hydrolytic enzymes are known as the essential promoters for organic matter decomposition in marine ecosystems. Bacterial activity and metabolisms under various CO2 concentrations and pH were examined on total cell abundance, 3H-leucine incorporation rate, and viable cell abundance. Our in vitro experiments demonstrated that acute effect by high CO2 conditions was negligible on the activities of bathypelagic bacteria at pH 7 or higher. However, our results suggested that bacterial assemblage in some organic-rich "microbial hot-spots" in seawater such as organic aggregates sinking particles, exhibited high sensitivity to acidification. Furthermore, it was indicated that CO2 injection seems to be the trigger to alter the microbial community structure between Eubacteria and Archaea. The activities of five types of hydrolytic enzymes showed no significant change with acidification as those observed in the bacterial activity. As to acute effects on microbial and biochemical processes examined by our laboratory studies, no significant influence was exhibited in the simulated ocean CO2 storage on marine biogeochemical cycling. Uncertainties in chronic and large-scale impacts, however, remain and should be addressed for more understanding the potential benefits and risks of the ocean storage.

Matrix effect of sodium compounds on the determination of metal ions in aqueous solutions by underwater laser-induced breakdown spectroscopy

DOE PAGES

Goueguel, Christian; McIntyre, Dustin L.; Jain, Jinesh; ...

2015-06-30

A significant portion of the carbon sequestration research being performed in the United States involves the risk assessment of injecting large quantities of carbon dioxide into deep saline aquifers. Leakage of CO 2 has the potential to affect the quality of groundwater supplies in case contaminants migrate through underlying conduits. New remote sensing and near-surface monitoring technologies are needed to ensure that injection, abandoned, and monitoring wells are structurally sound, and that CO 2 remains within the geologic storage reservoir. In this paper, we propose underwater laser-induced breakdown spectroscopy (underwater LIBS) as an analytical method for monitoring naturally occurring elementsmore » that can act as tracers to detect a CO 2 leak from storage sites. Laboratory-scale experiments were conducted to measure Sr 2+, Ca 2+, K +, and Li + in bulk solutions to ascertain the analytical performance of underwater LIBS. We compared the effect of NaCl, Na 2CO 3, and Na 2SO 4 on the analytes calibration curves to determine underwater LIBS’ ability to analyze samples of sodium compounds. In all cases, the calibration curves showed a good linearity within 2 orders of magnitude. The limit of detections (LODs) obtained for K + (30±1 ppb) and Li + (60±2 ppb) were in ppb range, while higher LODs were observed for Ca 2+ (0.94±0.14 ppm) and Sr 2+ (2.89±0.11 ppm). Evaluation of the calibration curves for the analytes in mixed solutions showed dependence of the lines’ intensity with the sodium compounds. The intensities increased respectively in the presence of dissolved NaCl and Na 2SO 4, whereas the intensities slightly decreased in the presence of Na 2CO 3. Lastly, the capabilities of underwater LIBS to detect certain elements in the ppb or in the low ppm range make it particularly appealing for in situ monitoring of a CO 2 leak.« less

Matrix effect of sodium compounds on the determination of metal ions in aqueous solutions by underwater laser-induced breakdown spectroscopy

DOE Office of Scientific and Technical Information (OSTI.GOV)

Goueguel, Christian; McIntyre, Dustin L.; Jain, Jinesh

A significant portion of the carbon sequestration research being performed in the United States involves the risk assessment of injecting large quantities of carbon dioxide into deep saline aquifers. Leakage of CO 2 has the potential to affect the quality of groundwater supplies in case contaminants migrate through underlying conduits. New remote sensing and near-surface monitoring technologies are needed to ensure that injection, abandoned, and monitoring wells are structurally sound, and that CO 2 remains within the geologic storage reservoir. In this paper, we propose underwater laser-induced breakdown spectroscopy (underwater LIBS) as an analytical method for monitoring naturally occurring elementsmore » that can act as tracers to detect a CO 2 leak from storage sites. Laboratory-scale experiments were conducted to measure Sr 2+, Ca 2+, K +, and Li + in bulk solutions to ascertain the analytical performance of underwater LIBS. We compared the effect of NaCl, Na 2CO 3, and Na 2SO 4 on the analytes calibration curves to determine underwater LIBS’ ability to analyze samples of sodium compounds. In all cases, the calibration curves showed a good linearity within 2 orders of magnitude. The limit of detections (LODs) obtained for K + (30±1 ppb) and Li + (60±2 ppb) were in ppb range, while higher LODs were observed for Ca 2+ (0.94±0.14 ppm) and Sr 2+ (2.89±0.11 ppm). Evaluation of the calibration curves for the analytes in mixed solutions showed dependence of the lines’ intensity with the sodium compounds. The intensities increased respectively in the presence of dissolved NaCl and Na 2SO 4, whereas the intensities slightly decreased in the presence of Na 2CO 3. Lastly, the capabilities of underwater LIBS to detect certain elements in the ppb or in the low ppm range make it particularly appealing for in situ monitoring of a CO 2 leak.« less

Active CO2 Reservoir Management for Carbon Capture, Utilization, and Sequestration: Impact on Permitting, Monitoring, and Public Acceptance

NASA Astrophysics Data System (ADS)

Buscheck, T. A.; Chen, M.; Sun, Y.; Hao, Y.; Court, B.; Celia, M. A.; Wolery, T.; Aines, R. D.

2011-12-01

CO2 capture and sequestration (CCS) integrated with geothermal energy production in deep geological formations can play an important role in reducing CO2 emissions to the atmosphere and thereby mitigate global climate change. For industrial-scale CO2 injection in saline formations, pressure buildup can limit storage capacity and security. Active CO2 Reservoir Management (ACRM) combines brine production with CO2 injection to relieve pressure buildup, increase injectivity, manipulate CO2 migration, constrain brine leakage, and enable beneficial utilization of produced brine. Therefore, ACRM can be an enabler of carbon capture, utilization, and sequestration (CCUS). Useful products may include freshwater, cooling water, make-up water for pressure support in oil, gas, and geothermal reservoir operations, and geothermal energy production. Implementation barriers to industrial-scale CCS include concerns about (1) CO2 sequestration security and assurance, (2) pore-space competition with neighboring subsurface activities, (3) CO2 capture costs, and (4) water-use demands imposed by CCS operations, which is particularly important where water resources are already scarce. CCUS, enabled by ACRM, has the potential of addressing these barriers. Pressure relief from brine production can substantially reduce the driving force for potential CO2 and brine migration, as well as minimize interference with neighboring subsurface activities. Electricity generated from geothermal energy can offset a portion of the parasitic energy and financial costs of CCS. Produced brine can be used to generate freshwater by desalination technologies, such as RO, provide a source for saltwater cooling systems or be used as make-up water for oil, gas, or geothermal reservoir operations, reducing the consumption of valuable freshwater resources. We examine the impact of brine production on reducing CO2 and brine leakage. A volumetric balance between injected and produced fluids minimizes the spatial extent of the pressure perturbation, substantially reducing both the Area of Review (AoR) and interactions with neighboring subsurface activities. This will reduce pore-space competition between neighboring subsurface activities, allowing for independent planning, assessment, and permitting. Because post-injection pressure buildup is virtually eliminated, this could have a major impact on post-injection monitoring requirements. Reducing the volume of rock over which brine can migrate may significantly affect site characterization requirements, as well as the impact of parametric and conceptual model uncertainties, such as those related to abandoned wells. ACRM-CCUS has the potential of playing a beneficial role in site-characterization, permitting, and monitoring activities, and in gaining public acceptance. This work performed under the auspices of the U.S. Department of Energy by Lawrence Livermore National Laboratory under Contract DE-AC52-07NA27344.

Geologic Carbon Sequestration: Mitigating Climate Change by Injecting CO2 Underground (LBNL Summer Lecture Series)

ScienceCinema

Oldenburg, Curtis M. [Lawrence Berkeley National Lab. (LBNL), Berkeley, CA (United States). Earth Sciences Division

2018-05-07

Summer Lecture Series 2009: Climate change provides strong motivation to reduce CO2 emissions from the burning of fossil fuels. Carbon dioxide capture and storage involves the capture, compression, and transport of CO2 to geologically favorable areas, where its injected into porous rock more than one kilometer underground for permanent storage. Oldenburg, who heads Berkeley Labs Geologic Carbon Sequestration Program, will focus on the challenges, opportunities, and research needs of this innovative technology.

Sequestration of non-pure carbon dioxide streams in iron oxyhydroxide-containing saline repositories

USGS Publications Warehouse

Garcia, S.; Rosenbauer, Robert J.; Palandri, James L.; Maroto-Valer, M. Mercedes

2012-01-01

Iron oxyhydroxide, goethite (α-FeOOH), was evaluated as a potential formation mineral reactant for trapping CO2 in a mineral phase such as siderite (FeCO3), when a mixture of CO2-SO 2 flue gas is injected into a saline aquifer. Two thermodynamic simulations were conducted, equilibrating a CO2-SO2 fluid mixture with a NaCl-brine and Fe-rich rocks at 150 °C and 300 bar. The modeling studies evaluated mineral and fluid composition at equilibrium and the influence of pH buffering in the system. Results show siderite precipitates both in the buffered and unbuffered system; however, the presence of an alkaline pH buffer enhances the stability of the carbonate. Based on the model, an experiment was designed to compare with thermodynamic predictions. A CO2-SO2 gas mixture was reacted in 150 ml of NaCl-NaOH brine containing 10 g of goethite at 150 °C and 300 bar for 24 days. Mineralogical and brine chemistry confirmed siderite as the predominant reaction product in the system. Seventy-six mg of CO2 are sequestered in siderite per 10 g of goethite.

Tunable mode and line selection by injection in a TEA CO2 laser

NASA Technical Reports Server (NTRS)

Menzies, R. T.; Flamant, P. H.; Kavaya, M. J.; Kuiper, E. N.

1984-01-01

Tunable mode selection by injection in pulsed CO2 lasers is examined, and both analytical and numerical models are used to compute the required injection power for a variety of experimental cases. These are treated in two categories: mode selection at a desired frequency displacement from the center frequency of a transition line in a dispersive cavity and mode (and line) selection at the center frequency of a selected transition line in a nondispersive cavity. The results point out the potential flexibility of pulsed injection in providing wavelength tunable high-energy single-frequency pulses.

Final Scientific/Technical Report for project “Geomechanical Monitoring for CO 2 Hub Storage: Production and Injection at Kevin Dome

DOE Office of Scientific and Technical Information (OSTI.GOV)

Daley, Thomas M.; Vasco, Don; Ajo-Franklin, Jonathan

After learning that the TDS value in the target injection formation at the Kevin Dome site is too low to qualify for an EPA Class VI CO2 injection permit, the BSCSP project was re-scoped such that injection of CO2 is no longer planned. With no injection planned, the Geomechanics project was closed. In this final report, we describe the objective and approach of the project as proposed, and the limited results obtained before stopping work. The objective of the proposed research was the development & validation of an integrated monitoring approach for quantifying the interactions between large-scale geological carbon storagemore » (GCS) and subsurface geomechanical state, particularly perturbations relevant to reservoir integrity such as fault reactivation and induced fracturing. In the short period of work before knowing the fate of the Kevin Dome project, we (1) researched designs for both the proposed InSAR corner reflectors as well as the near-surface 3C seismic stations; (2) developed preliminary elastic geomechanical models; (3) developed a second generation deformation prediction for the BSCSP Kevin Dome injection site; and (4) completed a preliminary map of InSAR monuments and shallow MEQ wells in the vicinity of the BSCSP injection pad.« less

Intramuscular injection of malignant hyperthermia trigger agents induces hypermetabolism in susceptible and nonsusceptible individuals.

PubMed

Metterlein, Thomas; Schuster, Frank; Kranke, Peter; Roewer, Norbert; Anetseder, Martin

2010-01-01

A new minimally invasive metabolic test for the diagnosis of susceptibility for malignant hyperthermia measuring intramuscular p(CO(2)) and lactate following local application of caffeine and halothane in humans was recently proposed. The present study tested the hypothesis that a more simplified test protocol allows a differentiation between malignant hyperthermia susceptible (MHS) and malignant hyperthermia nonsusceptible (MHN) and control individuals. With approval of the local ethics committee and informed consent, microdialysis and p(CO(2)) probes with attached microtubing were placed into the lateral vastus muscle of six MHS, seven MHN and seven control individuals. Following equilibration, boluses of 500 microl caffeine 80 mmol l(-1) and halothane 10 vol% dissolved in soybean oil were injected locally. p(CO(2)) and lactate were measured spectrophotometrically. The maximal rate of p(CO(2)) increase was significantly higher in MHS than in MHN and control individuals following application of halothane and caffeine, respectively. Intramuscular caffeine injection leads to a significantly higher increase of local lactate levels in MHS than in MHN and control individuals, whereas halothane increased local lactate levels in all investigated groups. Haemodynamic and systemic metabolic parameters did not differ between the investigated groups. Local caffeine and halothane injection increased intramuscular metabolism in MHS individuals significantly more than in the two other groups. In contrast to previous investigations, direct injection of the concentrations of halothane described here increased lactate and p(CO(2)) even in MHN skeletal muscle.

Interaction of Rock Minerals with Carbon Dioxide and Brine: A Hydrothermal Investigation

DOE Office of Scientific and Technical Information (OSTI.GOV)

Sass, Bruce M.; Gupta, Neeraj; Ickes, Jennifer A.

2002-02-02

This paper presents interim results of a feasibility study on carbon dioxide (CO{sub 2}) sequestration in deep saline formations. The focus of the investigation is to examine factors that may affect chemical sequestration of CO{sub 2} in deep saline formations. Findings of the first phase of this investigation were presented in a topical report (Sass et al., 1999a). Preliminary results of the second phase, now underway, have been reported elsewhere (Sass et al., 1999b; 2001). Evaluations of the suitability of Mt. Simon formation for sequestering CO{sub 2} and economic issues are reported by Gupta et al., 1999; 2001; Smith etmore » al., 2001. This study is sponsored by the U.S. Department of Energy's (DOE) National Energy Technology Laboratory (NETL) under a Novel Concepts project grant. The overall objectives of Phase II experiments were to determine: (1) the potential for long-term sequestration of CO{sub 2} in deep, regional host rock formations; and (2) the effectiveness of overlying caprock as a barrier against upward migration of the injected CO{sub 2}. To meet these goals, experiments were conducted using rock samples from different potential host reservoirs and overlying rocks. In addition, pure mineral samples were used in some experimental runs to investigate specific mineralogical reactions. Due to space limitations, the scope of this paper will be limited to two types of equilibration experiments using pure minerals. Implications for more complex natural systems will be discussed in the report for Phase II being finalized at this time.« less

CO2 geosequestration at the laboratory scale: Combined geophysical and hydromechanical assessment of weakly-cemented shallow Sleipner-like reservoirs

NASA Astrophysics Data System (ADS)

Falcon-Suarez, I.; North, L. J.; Best, A. I.

2017-12-01

To date, the most promising mitigation strategy for reducing global carbon emissions is Carbon Capture and Storage (CCS). The storage technology (i.e., CO2 geosequestration, CGS) consists of injecting CO2 into deep geological formations, specifically selected for such massive-scale storage. To guarantee the mechanical stability of the reservoir during and after injection, it is crucial to improve existing monitoring techniques for controlling CGS activities. We developed a comprehensive experimental program to investigate the integrity of the Sleipner CO2 storage site in the North Sea - the first commercial CCS project in history where 1 Mtn/y of CO2 has been injected since 1996. We assessed hydro-mechanical effects and the related geophysical signatures of three synthetic sandstones and samples from the Utsira Sand formation (main reservoir at Sleipner), at realistic pressure-temperature (PT) conditions and fluid compositions. Our experimental approach consists of brine-CO2 flow-through tests simulating variable inflation/depletion scenarios, performed in the CGS-rig (Fig. 1; Falcon-Suarez et al., 2017) at the National Oceanography Centre (NOC) in Southampton. The rig is designed for simultaneous monitoring of ultrasonic P- and S-wave velocities and attenuations, electrical resistivity, axial and radial strains, pore pressure and flow, during the co-injection of up to two fluids under controlled PT conditions. Our results show velocity-resistivity and seismic-geomechanical relations of practical importance for the distinction between pore pressure and pore fluid distribution during CGS activities. By combining geophysical and thermo-hydro-mechano-chemical coupled information, we can provide laboratory datasets that complement in situ seismic, geomechanical and electrical survey information, useful for the CO2 plume monitoring in Sleipner site and other shallow weakly-cemented sand CCS reservoirs. Falcon-Suarez, I., Marín-Moreno, H., Browning, F., Lichtschlag, A., Robert, K., North, L.J., Best, A.I., 2017. Experimental assessment of pore fluid distribution and geomechanical changes in saline sandstone reservoirs during and after CO2 injection. International Journal of Greenhouse Gas Control 63, 356-369.

Interaction Between CO2-Rich Sulfate Solutions and Carbonate Reservoir Rocks from Atmospheric to Supercritical CO2 Conditions: Experiments and Modeling

NASA Astrophysics Data System (ADS)

Cama, J.; Garcia-Rios, M.; Luquot, L.; Soler Matamala, J. M.

2014-12-01

A test site for CO2 geological storage is situated in Hontomín (Spain) with a reservoir rock that is mainly composed of limestone. During and after CO2 injection, the resulting CO2-rich acid brine gives rise to the dissolution of carbonate minerals (calcite and dolomite) and gypsum (or anhydrite at depth) may precipitate since the reservoir brine contains sulfate. Experiments using columns filled with crushed limestone or dolostone were conducted under different P-pCO2 conditions (atmospheric: 1-10-3.5 bar; subcritical: 10-10 bar; and supercritical: 150-34 bar), T (25, 40 and 60 ºC) and input solution compositions (gypsum-undersaturated and gypsum-equilibrated solutions). We evaluated the effect of these parameters on the coupled reactions of calcite/dolomite dissolution and gypsum/anhydrite precipitation. The CrunchFlow and PhreeqC (v.3) numerical codes were used to perform reactive transport simulations of the experiments. Under the P-pCO2-T conditions, the volume of precipitated gypsum was smaller than the volume of dissolved carbonate minerals, yielding an increase in porosity (Δporosity up to ≈ 4%). A decrease in T favored limestone dissolution regardless of pCO2 owing to increasing undersaturation with decreasing temperature. However, gypsum precipitation was favored at high T and under atmospheric pCO2 conditions but not at high T and under 10 bar of pCO2 conditions. The increase in limestone dissolution with pCO2 was directly attributed to pH, which was more acidic at higher pCO2. Increasing pCO2, carbonate dissolution occurred along the column whereas it was localized in the very inlet under atmospheric conditions. This was due to the buffer capacity of the carbonic acid, which maintains pH at around 5 and keeps the solution undersaturated with respect to calcite and dolomite along the column. 1D reactive transport simulations reproduced the experimental data (carbonate dissolution and gypsum precipitation for different P-pCO2-T conditions). Drawing on reaction rate laws in the literature, we used the reactive surface area to fit the models to the experimental data. The values of the reactive surface area were much smaller than those calculated of the geometric areas.

Experimental investigation of biofilm formation within a glass porous medium in the presence of carbon dioxide

NASA Astrophysics Data System (ADS)

Sygouni, Varvara; Manariotis, Ioannis D.; Chrysikopoulos, Constantinos V.

2013-04-01

Capturing CO2 emissions and storing them in properly selected deep geologic formations is considered a promising solution for the reduction of CO2 in the atmosphere. However, if CO2 leakage occurs from geologic storage formations due to permeability increases caused by rock-brine-supercritical CO2 geochemical reactions or reactivation of existing fractures, the impact to groundwater quality could be significant. Dissolved CO2 in groundwater can decrease the pH, which in turn can solubilize undesired heavy metals from the solid matrix with profound and severe implications to public health. Consequently, it is essential to fully understand the potential impact of CO2 to shallow groundwater systems. In this study, a series of visualization experiments in a glass-etched micromodel were performed in order to estimate the effect of CO2 on biofilm formation. All biofilms were developed using Pseudomonas (P.) Putida. Synthetic water saturated with CO2 was injected through the micromodel through an inlet port, and CO2 was measured at the outlet port. The transient growth of the biofilm was monitored by taking high-resolution digital photographs at various times, and the effect of CO2 on biofilm growth was estimated. Furthermore, transient changes of effective permeability and porosity were measured and the effect of solution chemistry (e.g. pH, ionic strength, redox potential) on the rate of biofilm growth was evaluated.

IMPLEMENTING A NOVEL CYCLIC CO2 FLOOD IN PALEOZOIC REEFS

DOE Office of Scientific and Technical Information (OSTI.GOV)

James R. Wood; W. quinlan; A. Wylie

Recycled CO2 is being used in this demonstration project to produce bypassed oil from the Silurian Dover 35 Niagaran pinnacle reef located in Otsego County, Michigan. CO2 injection in the Dover 35 field into the Salling-Hansen 4-35A well began on May 6, 2004. A second injection well, the Salling-Hansen 1-35, commenced injection in August 2004. Oil production in the Pomerzynski 5-35 producing well increased from 9 BOPD prior to operations to an average of 165 BOPD in December, 2004 and has produced at an average rate of 61 BOPD (Jan-Dec, 2005). The Salling-Hansen 4-35A also produced during this reporting periodmore » an average of 29 BOPD. These increases have occurred as a result of CO2 injection and the production rate appears to be stabilizing. CO2 injection volume has reached approximately 2.18 BCF. The CO2 injection phase of this project has been fully operational since December 2004 and most downhole mechanical issues have been solved and surface facility modifications have been completed. It is anticipated that filling operations will run for another 6-12 months from July 1, 2005. In most other aspects, the demonstration is going well and hydrocarbon production has been stabilized at an average rate of 57 BOPD (July-Dec, 2005). Our industry partners continue to experiment with injection rates and pressures, various downhole and surface facility mechanical configurations, and the huff-n-puff technique to develop best practices for these types of enhanced recovery projects. Subsurface characterization was completed using well log tomography and 3D visualizations to map facies distributions and reservoir properties in the Belle River Mills, Chester 18, Dover 35, and Dover 36 Fields. The Belle River Mills and Chester 18 fields are being used as type-fields because they have excellent log and/or core data coverage. Amplitude slicing of the log porosity, normalized gamma ray, core permeability, and core porosity curves are showing trends that indicate significant heterogeneity and compartmentalization in these reservoirs associated with the original depositional fabric and pore types of the carbonate reservoir rocks. Accumulated pressure data supports the hypothesis of extreme heterogeneity in the Dover 35. Some intervals now have pressure readings over 2345 psig (April 29, 2005) in the A-1 Carbonate while nearby Niagaran Brown intervals only show 1030 psig (March 7, 2005). This is a pressure differential over 1300 psig and suggests significant vertical barriers in the reef, consistent with the GR tomography modeling. Digital and hard copy data have been compiled for the Niagaran reefs in the Michigan Basin, including a detailed summary of 20 fields in the vicinity of the demonstration well. Technology transfer took place through technical presentations regarding visualization of the reservoir heterogeneity in these Niagaran reefs. Oral presentations were given at two Petroleum Technology Transfer Council workshops, a Michigan Oil and Gas Association Conference, a Michigan Basin Geological Society meeting, and the Eastern American Association of Petroleum Geologist's Annual meeting. In addition, we met with our industry partners several times during the first half of 2005 to communicate and discuss the reservoir characterization and field site aspects of the demonstration project. A technical paper was published in the April 2005 issue of the AAPG Bulletin on the characterization of the Belle River Mills Field.« less