Reservoir sedimentology of the Big Injun sandstone in Granny Creek field, West Virginia

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

Zou, Xiangdong; Donaldson, K.; Donaldson, A.C.

1992-01-01

Big Injun sandstones of Granny Creek oil field (WV) are interpreted as fluvial-deltaic deposits from core and geophysical log data. The reservoir consists of two distinctive lithologies throughout the field; fine-grained sandstones overlain by pebbly and coarse-grained sandstones. Lower fine-grained sandstones were deposited in westward prograding river-mouth bars, where distal, marine-dominant proximal, and fluvial-dominant proximal bar subfacies are recognized. Principal pay is marine-influenced proximal bar, where porosity ranges from 13 to 23% and permeability, up to 24 md. Thin marine transgressive shales and their laterally equivalent low-permeability sandstones bound time-rock sequences generally less than 10 meters thick. Where field mapped,more » width of prograding bar sequence is approximately 2.7 km (dip trend), measured from truncated eastern edge (pre-coarse-grained member erosional surface) to distal western margin. Dip-trending elongate lobes occur within marine-influenced proximal mouth-bar area, representing thickest part of tidally influenced preserved bar. Upper coarse-grained part of reservoir consists of pebbly sandstones of channel fill from bedload streams. Laterally persistent low permeability cemented interval in lower part commonly caps underlying pay zone and probably serves as seal to vertical oil migration. Southwest paleoflow trends based on thickness maps of unit portent emergence of West Virginia dome, which influences erosion patterns of pre-Greenbrier unconformity for this combination oil trap.« less

Reservoir heterogeneity in Carboniferous sandstone of the Black Warrior basin. Final report

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

Kugler, R.L.; Pashin, J.C.; Carroll, R.E.

1994-04-01

Although oil production in the Black Warrior basin of Alabama is declining, additional oil may be produced through improved recovery strategies, such as waterflooding, chemical injection, strategic well placement, and infill drilling. High-quality characterization of reservoirs in the Black Warrior basin is necessary to utilize advanced technology to recover additional oil and to avoid premature abandonment of fields. This report documents controls on the distribution and producibility of oil from heterogeneous Carboniferous reservoirs in the Black Warrior basin of Alabama. The first part of the report summarizes the structural and depositional evolution of the Black Warrior basin and establishes themore » geochemical characteristics of hydrocarbon source rocks and oil in the basin. This second part characterizes facies heterogeneity and petrologic and petrophysical properties of Carter and Millerella sandstone reservoirs. This is followed by a summary of oil production in the Black Warrior basin and an evaluation of seven improved-recovery projects in Alabama. In the final part, controls on the producibility of oil from sandstone reservoirs are discussed in terms of a scale-dependent heterogeneity classification.« less

Reservoir characterization of Mesaverde (Campanian) bedload fluvial meanderbelt sandstones, northwestern Colorado

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

Jones, J.R. Jr.

1984-04-01

Reservoir characterization of Mesaverde meanderbelt sandstones is used to determined directional continuity of permeable zones. A 500-m (1600 ft) wide fluvial meanderbelt in the Mesaverde Group is exposed as laterally continuous 3-10-m (10-33-ft) high sandstone cliffs north of Rangely, Colorado. Forty-eight detailed measured sections through 3 point bar complexes oriented at right angles to the long axis of deposition and 1 complex oriented parallel to deposition were prepared. Sections were tied together by detailed sketches delineating and tracing major bounding surfaces such as scours and clay drapes. These complexes contain 3 to 8 multilateral sandstone packages separated by 5-20 cmmore » (2-8 in.) interbedded siltstone and shale beds. Component facies are point bars, crevasse splays, chute bars, and floodplain/overbank deposits. Two types of lateral accretion surfaces are recognized in the point bar facies. Gently dipping lateral accretions containing fining-upward sandstone packages. Large scale trough cross-bedding at the base grades upward into ripples and plane beds. Steeply dipping lateral accretion surfaces enclose beds characterized by climbing ripple cross laminations. Bounding surfaces draped by shale lags can seal vertically stacked point bars from reservoir communication. Scoured boundaries allow communication in some stacked point bars. Crevasse splays showing climbing ripples form tongues of very fine-grained sandstone which flank point bars. Chute channels commonly cut upper point bar surfaces at their downstream end. Chute facies are upward-fining with small scale troughs and common dewatering structures. Siltstones and shales underlie the point bar complexes and completely encase the meanderbelt system. Bounding surfaces at the base of the complexes are erosional and contain large shale rip-up clasts.« less

High-temperature quartz cement and the role of stylolites in a deep gas reservoir, Spiro Sandstone, Arkoma Basin, USA

USGS Publications Warehouse

Worden, Richard H.; Morad, Sadoon; Spötl, C.; Houseknecht, D.W.; Riciputi, L.R.

2000-01-01

The Spiro Sandstone, a natural gas play in the central Arkoma Basin and the frontal Ouachita Mountains preserves excellent porosity in chloritic channel-fill sandstones despite thermal maturity levels corresponding to incipient metamorphism. Some wells, however, show variable proportions of a late-stage, non-syntaxial quartz cement, which post-dated thermal cracking of liquid hydrocarbons to pyrobitumen plus methane. Temperatures well in excess of 150°C and possibly exceeding 200°C are also suggested by (i) fluid inclusions in associated minerals; (ii) the fact that quartz post-dated high-temperature chlorite polytype IIb; (iii) vitrinite reflectance values of the Spiro that range laterally from 1.9 to ≥ 4%; and (iii) the occurrence of late dickite in these rocks. Oxygen isotope values of quartz cement range from 17.5 to 22.4‰ VSMOW (total range of individual in situ ion microprobe measurements) which are similar to those of quartz cement formed along high-amplitude stylolites (18.4–24.9‰). We favour a model whereby quartz precipitation was controlled primarily by the availability of silica via deep-burial stylolitization within the Spiro Sandstone. Burial-history modelling showed that the basin went from a geopressured to a normally pressured regime within about 10–15 Myr after it reached maximum burial depth. While geopressure and the presence of chlorite coats stabilized the grain framework and inhibited nucleation of secondary quartz, respectively, stylolites formed during the subsequent high-temperature, normal-pressured regime and gave rise to high-temperature quartz precipitation. Authigenic quartz growing along stylolites underscores their role as a significant deep-burial silica source in this sandstone.

Hydrocarbon Potential in Sandstone Reservoir Isolated inside Low Permeability Shale Rock (Case Study: Beruk Field, Central Sumatra Basin)

NASA Astrophysics Data System (ADS)

Diria, Shidqi A.; Musu, Junita T.; Hasan, Meutia F.; Permono, Widyo; Anwari, Jakson; Purba, Humbang; Rahmi, Shafa; Sadjati, Ory; Sopandi, Iyep; Ruzi, Fadli

2018-03-01

Upper Red Bed, Menggala Formation, Bangko Formation, Bekasap Formation and Duri Formationare considered as the major reservoirs in Central Sumatra Basin (CSB). However, Telisa Formation which is well-known as seal within CSB also has potential as reservoir rock. Field study discovered that lenses and layers which has low to high permeability sandstone enclosed inside low permeability shale of Telisa Formation. This matter is very distinctive and giving a new perspective and information related to the invention of hydrocarbon potential in reservoir sandstone that isolated inside low permeability shale. This study has been conducted by integrating seismic data, well logs, and petrophysical data throughly. Facies and static model are constructed to estimate hydrocarbon potential resource. Facies model shows that Telisa Formation was deposited in deltaic system while the potential reservoir was deposited in distributary mouth bar sandstone but would be discontinued bedding among shale mud-flat. Besides, well log data shows crossover between RHOB and NPHI, indicated that distributary mouth bar sandstone is potentially saturated by hydrocarbon. Target area has permeability ranging from 0.01-1000 mD, whereas porosity varies from 1-30% and water saturation varies from 30-70%. The hydrocarbon resource calculation approximates 36.723 MSTB.

Facies-controlled fluid migration patterns and subsequent reservoir collapse by depressurization - the Entrada Sandstone, Utah

NASA Astrophysics Data System (ADS)

Sundal, A.; Skurtveit, E.; Midtkandal, I.; Hope, I.; Larsen, E.; Kristensen, R. S.; Braathen, A.

2016-12-01

The thick and laterally extensive Middle Jurassic Entrada Sandstone forms a regionally significant reservoir both in the subsurface and as outcrops in Utah. Individual layers of fluvial sandstone within otherwise fine-grained aeolian dunes and silty inter-dune deposits of the Entrada Earthy Member are of particular interest as CO2 reservoir analogs to study injectivity, reservoir-caprock interaction and bypass systems. Detailed mapping of facies and deformation structures, including petrographic studies and core plug tests, show significant rock property contrasts between layers of different sedimentary facies. Beds representing fluvial facies appear as white, medium-grained, well-sorted and cross-stratified sandstone, displaying high porosity, high micro-scale permeability, low tensile strength, and low seismic velocity. Subsequent to deposition, these beds were structurally deformed and contain a dense network of deformation bands, especially in proximity to faults and injectites. Over- and underlying low-permeability layers of inter-dune aeolian facies contain none or few deformation bands, display significantly higher rock strengths and high seismic velocities compared to the fluvial inter-beds. Permeable units between low-permeability layers are prone to become over-pressured during burial, and the establishment of fluid escape routes during regional tectonic events may have caused depressurization and selective collapse of weak layers. Through-cutting, vertical sand pipes display large clasts of stratified sandstone suspended in remobilized sand matrix, and may have served as permeable fluid conduits and pressure vents before becoming preferentially cemented and plugged. Bleached zones around faults and fractures throughout the succession indicate leakage and migration of reducing fluids. The fluvial beds are porous and would appear in wireline logs and seismic profiles as excellent reservoirs; whereas due to dense populations of deformation bands they may in

STRUCTURAL HETEROGENEITIES AND PALEO FLUID FLOW IN AN ANALOG SANDSTONE RESERVOIR 2001-2004

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

Pollard, David; Aydin, Atilla

2005-02-22

Fractures and faults are brittle structural heterogeneities that can act both as conduits and barriers with respect to fluid flow in rock. This range in the hydraulic effects of fractures and faults greatly complicates the challenges faced by geoscientists working on important problems: from groundwater aquifer and hydrocarbon reservoir management, to subsurface contaminant fate and transport, to underground nuclear waste isolation, to the subsurface sequestration of CO2 produced during fossil-fuel combustion. The research performed under DOE grant DE-FG03-94ER14462 aimed to address these challenges by laying a solid foundation, based on detailed geological mapping, laboratory experiments, and physical process modeling, onmore » which to build our interpretive and predictive capabilities regarding the structure, patterns, and fluid flow properties of fractures and faults in sandstone reservoirs. The material in this final technical report focuses on the period of the investigation from July 1, 2001 to October 31, 2004. The Aztec Sandstone at the Valley of Fire, Nevada, provides an unusually rich natural laboratory in which exposures of joints, shear deformation bands, compaction bands and faults at scales ranging from centimeters to kilometers can be studied in an analog for sandstone aquifers and reservoirs. The suite of structures there has been documented and studied in detail using a combination of low-altitude aerial photography, outcrop-scale mapping and advanced computational analysis. In addition, chemical alteration patterns indicative of multiple paleo fluid flow events have been mapped at outcrop, local and regional scales. The Valley of Fire region has experienced multiple episodes of fluid flow and this is readily evident in the vibrant patterns of chemical alteration from which the Valley of Fire derives its name. We have successfully integrated detailed field and petrographic observation and analysis, process-based mechanical modeling, and

Electrofacies vs. lithofacies sandstone reservoir characterization Campanian sequence, Arshad gas/oil field, Central Sirt Basin, Libya

NASA Astrophysics Data System (ADS)

Burki, Milad; Darwish, Mohamed

2017-06-01

The present study focuses on the vertically stacked sandstones of the Arshad Sandstone in Arshad gas/oil field, Central Sirt Basin, Libya, and is based on the conventional cores analysis and wireline log interpretation. Six lithofacies types (F1 to F6) were identified based on the lithology, sedimentary structures and biogenic features, and are supported by wireline log calibration. From which four types (F1-F4) represent the main Campanian sandstone reservoirs in the Arshad gas/oil field. Lithofacies F5 is the basal conglomerates at the lower part of the Arshad sandstones. The Paleozoic Gargaf Formation is represented by lithofacies F6 which is the source provenance for the above lithofacies types. Arshad sediments are interpreted to be deposited in shallow marginal and nearshore marine environment influenced by waves and storms representing interactive shelf to fluvio-marine conditions. The main seal rocks are the Campanian Sirte shale deposited in a major flooding events during sea level rise. It is contended that the syn-depositional tectonics controlled the distribution of the reservoir facies in time and space. In addition, the post-depositional changes controlled the reservoir quality and performance. Petrophysical interpretation from the porosity log values were confirmed by the conventional core measurements of the different sandstone lithofacies types. Porosity ranges from 5 to 20% and permeability is between 0 and 20 mD. Petrophysical cut-off summary of the lower part of the clastic dominated sequence (i. e. Arshad Sandstone) calculated from six wells includes net pay sand ranging from 19.5‧ to 202.05‧, average porosity from 7.7 to 15% and water saturation from 19 to 58%.

Fe-oxide grain coatings support bacterial Fe-reducing metabolisms in 1.7−2.0 km-deep subsurface quartz arenite sandstone reservoirs of the Illinois Basin (USA)

PubMed Central

Dong, Yiran; Sanford, Robert A.; Locke, Randall A.; Cann, Isaac K.; Mackie, Roderick I.; Fouke, Bruce W.

2014-01-01

The Cambrian-age Mt. Simon Sandstone, deeply buried within the Illinois Basin of the midcontinent of North America, contains quartz sand grains ubiquitously encrusted with iron-oxide cements and dissolved ferrous iron in pore-water. Although microbial iron reduction has previously been documented in the deep terrestrial subsurface, the potential for diagenetic mineral cementation to drive microbial activity has not been well studied. In this study, two subsurface formation water samples were collected at 1.72 and 2.02 km, respectively, from the Mt. Simon Sandstone in Decatur, Illinois. Low-diversity microbial communities were detected from both horizons and were dominated by Halanaerobiales of Phylum Firmicutes. Iron-reducing enrichment cultures fed with ferric citrate were successfully established using the formation water. Phylogenetic classification identified the enriched species to be related to Vulcanibacillus from the 1.72 km depth sample, while Orenia dominated the communities at 2.02 km of burial depth. Species-specific quantitative analyses of the enriched organisms in the microbial communities suggest that they are indigenous to the Mt. Simon Sandstone. Optimal iron reduction by the 1.72 km enrichment culture occurred at a temperature of 40°C (range 20–60°C) and a salinity of 25 parts per thousand (range 25–75 ppt). This culture also mediated fermentation and nitrate reduction. In contrast, the 2.02 km enrichment culture exclusively utilized hydrogen and pyruvate as the electron donors for iron reduction, tolerated a wider range of salinities (25–200 ppt), and exhibited only minimal nitrate- and sulfate-reduction. In addition, the 2.02 km depth community actively reduces the more crystalline ferric iron minerals goethite and hematite. The results suggest evolutionary adaptation of the autochthonous microbial communities to the Mt. Simon Sandstone and carries potentially important implications for future utilization of this reservoir for CO2

Reservoir uncertainty, Precambrian topography, and carbon sequestration in the Mt. Simon Sandstone, Illinois Basin

USGS Publications Warehouse

Leetaru, H.E.; McBride, J.H.

2009-01-01

Sequestration sites are evaluated by studying the local geological structure and confirming the presence of both a reservoir facies and an impermeable seal not breached by significant faulting. The Cambrian Mt. Simon Sandstone is a blanket sandstone that underlies large parts of Midwest United States and is this region's most significant carbon sequestration reservoir. An assessment of the geological structure of any Mt. Simon sequestration site must also include knowledge of the paleotopography prior to deposition. Understanding Precambrian paleotopography is critical in estimating reservoir thickness and quality. Regional outcrop and borehole mapping of the Mt. Simon in conjunction with mapping seismic reflection data can facilitate the prediction of basement highs. Any potential site must, at the minimum, have seismic reflection data, calibrated with drill-hole information, to evaluate the presence of Precambrian topography and alleviate some of the uncertainty surrounding the thickness or possible absence of the Mt. Simon at a particular sequestration site. The Mt. Simon is thought to commonly overlie Precambrian basement granitic or rhyolitic rocks. In places, at least about 549 m (1800 ft) of topographic relief on the top of the basement surface prior to Mt. Simon deposition was observed. The Mt. Simon reservoir sandstone is thin or not present where basement is topographically high, whereas the low areas can have thick Mt. Simon. The paleotopography on the basement and its correlation to Mt. Simon thickness have been observed at both outcrops and in the subsurface from the states of Illinois, Ohio, Wisconsin, and Missouri. ?? 2009. The American Association of Petroleum Geologists/Division of Environmental Geosciences. All rights reserved.

Research on the Log Interpretation Method of Tuffaceous Sandstone Reservoirs of X Depression in Hailar-Tamtsag Basin

NASA Astrophysics Data System (ADS)

Liu, S.; Pan, B.

2015-12-01

The logging evaluation of tuffaceous sandstone reservoirs is always a difficult problem. Experiments show that the tuff and shale have different logging responses. Since the tuff content exerts an influence on the computation of shale content and the parameters of the reservoir, and the accuracy of saturation evaluation is reduced. Therefore, the effect of tuff on the calculation of saturation cannot be ignored. This study takes the tuffaceous sandstone reservoirs in the X depression of Hailar-Tamtsag basin as an example to analyze. And the electric conduction model of tuffaceous sandstone reservoirs is established. The method which combines bacterial foraging algorithm and particle swarm optimization algorithm is used to calculate the content of reservoir components in well logging for the first time, and the calculated content of tuff and shale corresponds to the results analysis of thin sections. The experiment on cation exchange capacity (CEC) proves that tuff has conductivity, and the conversion relationship between CEC and resistivity proposed by Toshinobu Iton has been improved. According to the rock electric experiment under simulated reservoir conditions, the rock-electro parameters (a, b, m and n) are determined. The improved relationship between CEC and resistivity and the rock-electro parameters are used in the calculation of saturation. Formula (1) shows the saturation equation of the tuffaceous reservoirs:According to the comparative analysis between irreducible water saturation and the calculated saturation, we find that the saturation equation used CEC data and rock-electro parameters has a better application effect at oil layer than Archie's formulas.

Gas Reservoir Identification Basing on Deep Learning of Seismic-print Characteristics

NASA Astrophysics Data System (ADS)

Cao, J.; Wu, S.; He, X.

2016-12-01

Reservoir identification based on seismic data analysis is the core task in oil and gas geophysical exploration. The essence of reservoir identification is to identify the properties of rock pore fluid. We developed a novel gas reservoir identification method named seismic-print analysis by imitation of the vocal-print analysis techniques in speaker identification. The term "seismic-print" is referred to the characteristics of the seismic waveform which can identify determinedly the property of the geological objectives, for instance, a nature gas reservoir. Seismic-print can be characterized by one or a few parameters named as seismic-print parameters. It has been proven that gas reservoirs are of characteristics of negative 1-order cepstrum coefficient anomaly and Positive 2-order cepstrum coefficient anomaly, concurrently. The method is valid for sandstone gas reservoir, carbonate reservoir and shale gas reservoirs, and the accuracy rate may reach up to 90%. There are two main problems to deal with in the application of seismic-print analysis method. One is to identify the "ripple" of a reservoir on the seismogram, and another is to construct the mapping relationship between the seismic-print and the gas reservoirs. Deep learning developed in recent years is of the ability to reveal the complex non-linear relationship between the attribute and the data, and of ability to extract automatically the features of the objective from the data. Thus, deep learning could been used to deal with these two problems. There are lots of algorithms to carry out deep learning. The algorithms can be roughly divided into two categories: Belief Networks Network (DBNs) and Convolutional Neural Network (CNN). DBNs is a probabilistic generative model, which can establish a joint distribution of the observed data and tags. CNN is a feedforward neural network, which can be used to extract the 2D structure feature of the input data. Both DBNs and CNN can be used to deal with seismic data

Improved reservoir characterization of the Rose Run sandstone on the East Randolph Field, Portage County, Ohio

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

Safley, I.E.; Thomas, J.B.

1996-09-01

The East Randolph Field, located in Randolph Township, Portage County, Ohio, produces oil and gas from the Cambrian Rose Run sandstone unit, a member of the Knox Supergroup. Field development and infill drilling opportunities illustrate the need for improved reservoir characterization of the hydrocarbon productive intervals. This reservoir study is conducted under the Department of Energy`s Reservoir Management Program with professionals from BDM-Oklahoma and Belden & Blake Corporation. Well log and core analyses were conducted to determine the reservoir distribution, the heterogeneity of the hydrocarbon producing intervals, and the effects of faulting and fracturing on well productivity. The Rose Runmore » sandstones and interbedded dolomites were subdivided into three productive intervals. Cross sections were constructed for correlation of individual layers and identification of localized faulting. The geologic data was input into GeoGraphix software for construction of structure, net pay, production, and gas- and water-oil ratio maps.« less

The interplay of fractures and sedimentary architecture: Natural gas from reservoirs in the Molina sandstones, Piceance Basin, Colorado

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

Lorenz, J.C.

1997-03-01

The Molina Member of the Wasatch Formation produces natural gas from several fields along the Colorado River in the Piceance Basin, northwestern Colorado. The Molina Member is a distinctive sandstone that was deposited in a unique fluvial environment of shallow-water floods. This is recorded by the dominance of plane-parallel bedding in many of the sandstones. The Molina sandstones crop out on the western edge of the basin, and have been projected into the subsurface and across the basin to correlate with thinner sandy units of the Wasatch Formation at the eastern side of the basin. Detailed study, however, has shownmore » that the sedimentary characteristics of the type-section Molina sandstones are incompatible with a model in which the eastern sandstones are its distal facies equivalent. Rather, the eastern sandstones represent separate and unrelated sedimentary systems that prograded into the basin from nearby source-area highlands. Therefore, only the subsurface {open_quotes}Molina{close_quotes} reservoirs that are in close proximity to the western edge of the basin are continuous with the type-section sandstones. Reservoirs in the Grand Valley and Rulison gas fields were deposited in separate fluvial systems. These sandstones contain more typical fluvial sedimentary structures such as crossbeds and lateral accretion surfaces. Natural fractures play an important role in enhancing the conductivity and permeability of the Molina and related sandstones of the Wasatch Formation.« less

Evaluation of stratigraphic relations of sandstone-producing reservoirs in upper Council Grove and Chase groups (Permian) in north-central Oklahoma

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

Chaplin, J.R.

1989-08-01

Poor well control and the absence of surface stratigraphic control made previous interpretations of the stratigraphic relations of sandstone-producing reservoirs tenuous. Recent extensive analyses of surface outcrops and well and core data support the contention that the major sandstone-producing reservoirs can be physically correlated with formations in the outcrop section. Sandstone bodies within the upper Council Grove Group include Neva sand and Blackwell sand (Neva Limestone), Hotson-Kisner sand (Eskridge Shale), and the Whitney-Hodges sand. The Whitney-Hodges sand correlates, in part, with the Speiser Shale (Garrison Formation) of the outcrop section. However, previous usage suggested tentative correlations with sandstone bodies stratigraphicallymore » lower in the section. These sands were probably deposited in channels that were, in part, fluvial, tidal, or estuarine. Production from the Chase Group occurs locally within channelform sandstone bodies referred to as the Hoy-Matfield sand. These sands appear to be equivalent, occupying essentially the position of the Kinney Limestone Member (Matfield Shale) of the outcrop section. Detailed core-hole data at and in the vicinity of Kaw Dam, southeastern Kay County, and outcrops along the shoreline of Kaw Lake at Kaw City, Kay County, clearly demonstrate the facies distribution of the Hoy sand. Core-hole data has also delineated additional potential sandstone reservoirs within and near or at the top of the Fort Riley Limestone Member (Barneston Limestone). The Wolfe sand, a producing sandstone locally, occupies a stratigraphic position within the Doyle Shale.« less

Factors controlling reservoir quality in tertiary sandstones and their significance to geopressured geothermal production. Annual report, May 1, 1979-May 31, 1980

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

Loucks, R.G.; Richmann, D.L.; Milliken, K.L.

1980-07-01

Differing extents of diagenetic modification is the factor primarily responsible for contrasting regional reservoir quality of Tertiary sandstones from the Upper and Lower Texas Gulf Coast. Detailed comparison of Frio sandstones from the Chocolate Bayou/Danbury Dome area, Brazoria County, and Vicksburg sandstones from the McAllen Ranch Field area, Hidalgo County, reveals that extent of diagenetic modification is most strongly influenced by (1) detrital mineralogy and (2) regional geothermal gradients. Vicksburg sandstones from the McAllen Ranch Field area are less stable, chemically and mechanically, than Frio sandstones from the Chocolate Bayou/Danbury dome area. Vicksburg sandstones are mineralogically immature and contain greatermore » proportions of feldspars and rock fragments than do Frio sandstones. Thr reactive detrital assemblage of Vicksubrg sandstones is highly susceptible to diagenetic modification. Susceptibility is enhanced by higher than normal geothermal gradients in the McAllen Ranch Field area. Thus, consolidation of Vicksburg sandstones began at shallower depth of burial and precipitation of authigenic phases (especially calcite) was more pervasive than in Frio sandstones. Moreover, the late-stage episode of ferroan calcite precipitation that occluded most secondary porosity in Vicksburg sandstones did not occur significantly in Frio sandstones. Therefore, regional reservoir quality of Frio sandstones from Brazoria County is far better than that characterizing Vicksburg sandstones from Hidalgo County, especially at depths suitable for geopressured geothermal energy production.« less

Reservoir zonation based on statistical analyses: A case study of the Nubian sandstone, Gulf of Suez, Egypt

NASA Astrophysics Data System (ADS)

El Sharawy, Mohamed S.; Gaafar, Gamal R.

2016-12-01

Both reservoir engineers and petrophysicists have been concerned about dividing a reservoir into zones for engineering and petrophysics purposes. Through decades, several techniques and approaches were introduced. Out of them, statistical reservoir zonation, stratigraphic modified Lorenz (SML) plot and the principal component and clustering analyses techniques were chosen to apply on the Nubian sandstone reservoir of Palaeozoic - Lower Cretaceous age, Gulf of Suez, Egypt, by using five adjacent wells. The studied reservoir consists mainly of sandstone with some intercalation of shale layers with varying thickness from one well to another. The permeability ranged from less than 1 md to more than 1000 md. The statistical reservoir zonation technique, depending on core permeability, indicated that the cored interval of the studied reservoir can be divided into two zones. Using reservoir properties such as porosity, bulk density, acoustic impedance and interval transit time indicated also two zones with an obvious variation in separation depth and zones continuity. The stratigraphic modified Lorenz (SML) plot indicated the presence of more than 9 flow units in the cored interval as well as a high degree of microscopic heterogeneity. On the other hand, principal component and cluster analyses, depending on well logging data (gamma ray, sonic, density and neutron), indicated that the whole reservoir can be divided at least into four electrofacies having a noticeable variation in reservoir quality, as correlated with the measured permeability. Furthermore, continuity or discontinuity of the reservoir zones can be determined using this analysis.

Muddy and dolomitic rip-up clasts in Triassic fluvial sandstones: Origin and impact on potential reservoir properties (Argana Basin, Morocco)

NASA Astrophysics Data System (ADS)

Henares, Saturnina; Arribas, Jose; Cultrone, Giuseppe; Viseras, Cesar

2016-06-01

The significance of rip-up clasts as sandstone framework grains is frequently neglected in the literature being considered as accessory components in bulk sandstone composition. However, this study highlights the great value of muddy and dolomitic rip-up clast occurrence as: (a) information source about low preservation potential from floodplain deposits and (b) key element controlling host sandstone diagenetic evolution and thus ultimate reservoir quality. High-resolution petrographic analysis on Triassic fluvial sandstones from Argana Basin (T6 and T7/T8 units) highlights the significance of different types of rip-up clasts as intrabasinal framework components of continental sediments from arid climates. On the basis of their composition and ductility, three main types are distinguished: (a) muddy rip-up clasts, (b) dolomitic muddy rip-up clasts and (c) dolomite crystalline rip-up clasts. Spatial distribution of different types is strongly facies-related according to grain size. Origin of rip-up clasts is related to erosion of coeval phreatic dolocretes, in different development stages, and associated muddy floodplain sediments. Cloudy cores with abundant inclusions and clear outer rims of dolomite crystals suggest a first replacive and a subsequent displacive growth, respectively. Dolomite crystals are almost stoichiometric. This composition is very similar to that of early sandstone dolomite cement, supporting phreatic dolocretes as dolomite origin in both situations. Sandstone diagenesis is dominated by mechanical compaction and dolomite cementation. A direct correlation exists between: (1) muddy rip-up clast abundance and early reduction of primary porosity by compaction with irreversible loss of intergranular volume (IGV); and (2) occurrence of dolomitic rip-up clasts and dolomite cement nucleation in host sandstone, occluding adjacent pores but preserving IGV. Both processes affect reservoir quality by generation of vertical and 3D fluid flow baffles and

The Point Lookout Sandstone: a tale of two cores, or petrology, diagenesis, and reservoir properties of Point Lookout Sandstone, Southern Ute Indian Reservation, San Juan Basin, Colorado

USGS Publications Warehouse

Keighin, C.W.; Zech, R.S.; Dunbar, R.W.

1993-01-01

The Point Lookout sandstones are quartz-rich, fine to very-fine grained, and contain moderately variable quantities of potassium feldspar (2 to 20 modal percent) and lithic fragments (9 to 20 modal percent). Locally, sandstone is tightly cemented by carbonate cement; clays are not important as cementing agents, although they significantly reduce permeability of some samples. Pores are small; many are intergranular micropores between crystals of authigenic clay. Depositional environments are highly variable and range from lower shoreface to coastal plain and include minor deltaic environments. The best reservoir characteristics are generally in the upper shoreface sandstones. -from Authors

Practical characterization of eolian reservoirs for development: Nugget Sandstone, Utah—Wyoming thrust belt

NASA Astrophysics Data System (ADS)

Lindquist, Sandra J.

1988-04-01

The Jurassic eolian Nugget Sandstone of the Utah-Wyoming thrust belt is a texturally heterogeneous formation with anisotropic reservoir inherited primarily from the depositional environment. Original reservoir quality has been reduced somewhat by cementation and slightly enhanced by dissolution. Low-permeability, gouge-filled micro-faults compartmentalize the formation, whereas intermittently open fractures provide effective permeability paths locally. Where productive, the Nugget Sandstone ranges from approximately 800 to 1050 ft (244-320 m) thick at subsurface depths of 7500 to 15,000 ft (2286-4572 m). Porosity ranges from several percent to 25%, and permeability covers five orders of magnitude from hundredths of milliDarcies to Darcies. Some Nugget reservoirs are fully charged with hydrocarbons. Different stratification types have unique depositional textures, primary and diagenetic mineralogies, and deformational fabrics resulting in characteristic porosity, permeability, permeability directionality, and pore geometry attributes. Such characteristics can be determined from core analysis, mercury injection, nuclear magnetic resonance, conventional log, dipmeter and production data. Nugget dune deposits (good reservoir facies) primarily consist of grainflow and wind-ripple cross-strata, the former of which have the better reservoir quality and the lesser heterogeneity in bedding texture. High-permeability facies are commonly affected by local quartz and nodular carbonate cementation, chlorite (and lesser illite) precipitation, and minor framework and cement dissolution. Gouge-filled micro-faults are the predominant deformational overprint. Interdune, sand-sheet, and other water-associated deposits (poor reservoir facies) are characterized by low-angle wind-ripple laminae and more irregular bedding, some of which is associated with damp or wet conditions. Water-associated Nugget stratification generally contains the finest grained depositional textures and has the

Measuring and predicting reservoir heterogeneity in complex deposystems: The fluvial-deltaic Big Injun sandstone in West Virginia

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

Patchen, D.G.; Hohn, M.E.; Aminian, K.

1993-04-01

The purpose of this research is to develop techniques to measure and predict heterogeneities in oil reservoirs that are the products of complex deposystems. The unit chosen for study is the Lower Mississippian Big Injun sandstone, a prolific oil producer (nearly 60 fields) in West Virginia. This research effort has been designed and is being implemented as an integrated effort involving stratigraphy, structural geology, petrology, seismic study, petroleum engineering, modeling and geostatistics. Sandstone bodies are being mapped within their regional depositional systems, and then sandstone bodies are being classified in a scheme of relative heterogeneity to determine heterogeneity across depositionalmore » systems. Facies changes are being mapped within given reservoirs, and the environments of deposition responsible for each facies are being interpreted to predict the inherent relative heterogeneity of each facies. Structural variations will be correlated both with production, where the availability of production data will permit, and with variations in geologic and engineering parameters that affect production. A reliable seismic model of the Big Injun reservoirs in Granny Creek field is being developed to help interpret physical heterogeneity in that field. Pore types are being described and related to permeability, fluid flow and diagenesis, and petrographic data are being integrated with facies and depositional environments to develop a technique to use diagenesis as a predictive tool in future reservoir development. Another objective in the Big Injun study is to determine the effect of heterogeneity on fluid flow and efficient hydrocarbon recovery in order to improve reservoir management. Graphical methods will be applied to Big Injun production data and new geostatistical methods will be developed to detect regional trends in heterogeneity.« less

Controls on the quality of Miocene reservoirs, southern Gulf of Mexico

NASA Astrophysics Data System (ADS)

Gutiérrez Paredes, Hilda Clarisa; Catuneanu, Octavian; Hernández Romano, Ulises

2018-01-01

An investigation was conducted to determine the main controls on the reservoir quality of the middle and upper Miocene sandstones in the southern Gulf of Mexico based on core descriptions, thin section petrography and petrophysical data; as well as to explore the possible link between the sequence stratigraphic framework, depositional facies and diagenetic alterations. The Miocene deep marine sandstones are attributed to the falling-stage, lowstand, and transgressive systems tracts. The middle Miocene falling-stage systems tract includes medium-to very fine-grained, and structureless sandstones deposited in channels and frontal splays, and muddy sandstones, deposited in lobes of debrites. The lowstand and transgressive systems tracts consist of medium-to very fine-grained massive and normally graded sandstones deposited in channel systems within frontal splay complexes. The upper Miocene falling-stage systems tract includes medium-to coarse-grained, structureless sandstones deposited in channel systems and frontal splay, as well as lobes of debrites formed by grain flows and hybrid-flow deposits. The lowstand and transgressive systems tracts include fine-grained sandstones deposited in overbank deposits. The results reveal that the depositional elements with the best reservoir quality are the frontal splays deposited during the falling-stage system tracts. The reservoir quality of the Miocene sandstones was controlled by a combination of depositional facies, sand composition and diagenetic factors (mainly compaction and calcite cementation). Sandstone texture, controlled primarily by depositional facies appears more important than sandstone composition in determining reservoir quality; and compaction was more important than cementation in porosity destruction. Compaction was stopped, when complete calcite cementation occurred.

Diagenesis and reservoir quality of Bhuban sandstones (Neogene), Titas Gas Field, Bengal Basin, Bangladesh

NASA Astrophysics Data System (ADS)

Aminul Islam, M.

2009-06-01

This study deals with the diagenesis and reservoir quality of sandstones of the Bhuban Formation located at the Titas Gas Field of Bengal Basin. Petrographic study including XRD, CL, SEM and BSE image analysis and quantitative determination of reservoir properties were carried out for this study. The sandstones are fine to medium-grained, moderately well to well sorted subfeldspathic arenites with subordinate feldspathic and lithic arenites. The diagenetic processes include clay infiltration, compaction and cementation (quartz overgrowth, chlorite, kaolinite, calcite and minor amount of pyrite, dolomite and K-feldspar overgrowth). Quartz is the dominant pore occluding cement and generally occurred as small euhedral crystals, locally as large pyramidal crystals in the primary pores. Pressure solution derived from grain contact is the main contributor of quartz overgrowths. Chlorite occurs as pore-lining and pore filling cement. In some cases, chlorite helps to retain porosity by preventing quartz overgrowth. In some restricted depth interval, pore-occlusion by calcite cement is very much intense. Kaolinite locally developed as vermiform and accelerated the minor porosity loss due to pore-occlusion. Kaolinite/chlorite enhances ineffective microporosity. Kaolinite is a by-product of feldspar leaching in the presence of acidic fluid produced during the maturation of organic matter in the adjacent Miocene or deeper Oligocene source rocks. The relation between diagenesis and reservoir quality is as follows: the initial porosity was decreased by compaction and cementation and then increased by leaching of the metastable grains and dissolution of cement. Good quality reservoir rocks were deposited in fluvial environment and hence quality of reservoir rocks is also environment selective. Porosity and permeability data exhibit good inverse correlation with cement. However, some data points indicate multiple controls on permeability. Reservoir quality is thus controlled by

Field aided characterization of a sandstone reservoir: Arroyo Grande Oil Field, California, USA

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

Antonellini, M.; Aydin, A.

1995-08-01

The Arroyo Grande Oil Field in Central California has been productive since 1905 from the miopliocene Edna member of the Pismo formation. The Edna member is a massive poorly consolidated sandstone unit with an average porosity of 0.2 and a permeability of 1000-5000 md; the producing levels are shallow, 100 to 500 m from the ground surface. Excellent surface exposures of the same formation along road cuts across the field and above the reservoir provide an opportunity to study reservoir rocks at the surface and to relate fracture and permeability distribution obtained from cores to folds and faults observed inmore » outcrops. We mapped in outcrops the major structures of the oil field and determine the statistical distribution and orientation of small faults (deformation bands) that have been observed both in cores and outcrop. The relation between deformation bands and major structures has also been characterized with detailed mapping. By using synthetic logs it is possible to determine the log signature of structural heterogeneities such as deformation bands in sandstone; these faults cause a neutron porosity drop respect to the host rock in the order of 1-4%. Image analysis has been used to determine the petrophysical properties of the sandstone in outcrop and in cores; permeability is three orders of magnitude lower in faults than in the host rock and capillary pressure is 1-2 orders of magnitude larger in faults than in the host rock. Faults with tens of meters offsets are associated with an high density of deformation bands (10 to 250 m{sup -1}) and with zones of cement precipitation up to 30 m from the fault. By combining well and field data, we propose a structural model for the oil field in which high angle reverse faults with localized deformation bands control the distribution of the hydrocarbons on the limb of a syncline, thereby explaining the seemingly unexpected direction of slope of the top surface of the reservoir which was inferred by well data

Sedimentology and reservoir heterogeneity of a valley-fill deposit-A field guide to the Dakota Sandstone of the San Rafael Swell, Utah

USGS Publications Warehouse

Kirschbaum, Mark A.; Schenk, Christopher J.

2010-01-01

Valley-fill deposits form a significant class of hydrocarbon reservoirs in many basins of the world. Maximizing recovery of fluids from these reservoirs requires an understanding of the scales of fluid-flow heterogeneity present within the valley-fill system. The Upper Cretaceous Dakota Sandstone in the San Rafael Swell, Utah contains well exposed, relatively accessible outcrops that allow a unique view of the external geometry and internal complexity of a set of rocks interpreted to be deposits of an incised valley fill. These units can be traced on outcrop for tens of miles, and individual sandstone bodies are exposed in three dimensions because of modern erosion in side canyons in a semiarid setting and by exhumation of the overlying, easily erodible Mancos Shale. The Dakota consists of two major units: (1) a lower amalgamated sandstone facies dominated by large-scale cross stratification with several individual sandstone bodies ranging in thickness from 8 to 28 feet, ranging in width from 115 to 150 feet, and having lengths as much as 5,000 feet, and (2) an upper facies composed of numerous mud-encased lenticular sandstones, dominated by ripple-scale lamination, in bedsets ranging in thickness from 5 to 12 feet. The lower facies is interpreted to be fluvial, probably of mainly braided stream origin that exhibits multiple incisions amalgamated into a complex sandstone body. The upper facies has lower energy, probably anastomosed channels encased within alluvial and coastal-plain floodplain sediments. The Dakota valley-fill complex has multiple scales of heterogeneity that could affect fluid flow in similar oil and gas subsurface reservoirs. The largest scale heterogeneity is at the formation level, where the valley-fill complex is sealed within overlying and underlying units. Within the valley-fill complex, there are heterogeneities between individual sandstone bodies, and at the smallest scale, internal heterogeneities within the bodies themselves. These

Diagenesis of an 'overmature' gas reservoir: The Spiro sand of the Arkoma Basin, USA

USGS Publications Warehouse

Spotl, C.; Houseknecht, D.W.; Burns, S.J.

1996-01-01

The Spiro sand is a laterally extensive thin sandstone of earliest Atokan (Pennsylvanian) age that forms a major natural gas reservoir in the western Arkoma Basin, Oklahoma. Petrographic analysis reveals a variety of diagenetic alterations, the majority of which occurred during moderate to deep burial. Early diagenetic processes include calcite cementation and the formation of Fe-clay mineral peloids and coatings around quartz framework grains. These clays, which underwent transformation to well-crystallized chamosite [polytype Ib(?? = 90??)] on burial, are particularly abundant in medium-grained channel sandstones, whereas illitic clays are predominant in fine-grained interchannel sandstones. Subsequent to mechanical compaction, saddle ankerite precipitated in the reservoir at temperatures in excess of 70??C. Crude oil collected in favourable structural locations during and after ankeritization. Whereas hydrocarbons apparently halted inorganic diagenesis in oil-saturated zones, cementation continued in the underlying water-saturated zones. As reservoir temperatures increased further, hydrocarbons were cracked and a solid pyrobitumen residue remained in the reservoir. At temperatures exceeding ???140-150??C, non-syntaxial quartz cement, ferroan calcite and traces of dickite(?) locally reduced the reservoir quality. Local secondary porosity was created by carbonate cement dissolution. This alteration post-dated hydrocarbon emplacement and is probably related to late-stage infiltration of freshwater along 'leaky' faults. The study shows that the Spiro sandstone locally retained excellent porosities despite deep burial and thermal conditions that correspond to the zone of incipient very low grade metamorphism.

Effects of reduction in porosity and permeability with depth on storage capacity and injectivity in deep saline aquifers: A case study from the Mount Simon Sandstone aquifer

USGS Publications Warehouse

Medina, C.R.; Rupp, J.A.; Barnes, D.A.

2011-01-01

The Upper Cambrian Mount Simon Sandstone is recognized as a deep saline reservoir that has significant potential for geological sequestration in the Midwestern region of the United States. Porosity and permeability values collected from core analyses in rocks from this formation and its lateral equivalents in Indiana, Kentucky, Michigan, and Ohio indicate a predictable relationship with depth owing to a reduction in the pore structure due to the effects of compaction and/or cementation, primarily as quartz overgrowths. The regional trend of decreasing porosity with depth is described by the equation: ??(d)=16.36??e-0.00039*d, where ?? is the porosity and d is the depth in m. The decrease of porosity with depth generally holds true on a basinwide scale. Bearing in mind local variations in lithologic and petrophysical character within the Mount Simon Sandstone, the source data that were used to predict porosity were utilized to estimate the pore volume available within the reservoir that could potentially serve as storage space for injected CO2. The potential storage capacity estimated for the Mount Simon Sandstone in the study area, using efficiency factors of 1%, 5%, 10%, and 15%, is 23,680, 118,418, 236,832, and 355,242 million metric tons of CO2, respectively. ?? 2010 Elsevier Ltd.

Understanding creep in sandstone reservoirs - theoretical deformation mechanism maps for pressure solution in granular materials

NASA Astrophysics Data System (ADS)

Hangx, Suzanne; Spiers, Christopher

2014-05-01

Subsurface exploitation of the Earth's natural resources removes the natural system from its chemical and physical equilibrium. As such, groundwater extraction and hydrocarbon production from subsurface reservoirs frequently causes surface subsidence and induces (micro)seismicity. These effects are not only a problem in onshore (e.g. Groningen, the Netherlands) and offshore hydrocarbon fields (e.g. Ekofisk, Norway), but also in urban areas with extensive groundwater pumping (e.g. Venice, Italy). It is known that fluid extraction inevitably leads to (poro)elastic compaction of reservoirs, hence subsidence and occasional fault reactivation, and causes significant technical, economic and ecological impact. However, such effects often exceed what is expected from purely elastic reservoir behaviour and may continue long after exploitation has ceased. This is most likely due to time-dependent compaction, or 'creep deformation', of such reservoirs, driven by the reduction in pore fluid pressure compared with the rock overburden. Given the societal and ecological impact of surface subsidence, as well as the current interest in developing geothermal energy and unconventional gas resources in densely populated areas, there is much need for obtaining better quantitative understanding of creep in sediments to improve the predictability of the impact of geo-energy and groundwater production. The key problem in developing a reliable, quantitative description of the creep behaviour of sediments, such as sands and sandstones, is that the operative deformation mechanisms are poorly known and poorly quantified. While grain-scale brittle fracturing plus intergranular sliding play an important role in the early stages of compaction, these time-independent, brittle-frictional processes give way to compaction creep on longer time-scales. Thermally-activated mass transfer processes, like pressure solution, can cause creep via dissolution of material at stressed grain contacts, grain

Stochastic Representation and Uncertainty Assessment of a Deep Geothermal Reservoir Using Cross-Borehole ERT: A 3D Synthetic Case

NASA Astrophysics Data System (ADS)

Brunet, P.; Gloaguen, E.

2014-12-01

Designing and monitoring of geothermal systems is a complex task which requires a multidisciplinary approach. Deep geothermal reservoir models are prone to greater uncertainty, with a lack of direct data and lower resolution of surface geophysical methods. However, recent technical advances have enabled the potential use of permanent downhole vertical resistivity arrays for monitoring fluid injection. As electrical resistivity is sensitive to temperature changes, such data could provide valuable information for deep geothermal reservoir characterization. The objective of this study is to assess the potential of time-lapse cross-borehole ERT to constrain 3D realizations of geothermal reservoir properties. The synthetic case of a permeable geothermal reservoir in a sedimentary basin was set up, as a confined deep and saline sandstone aquifer with intermediate reservoir temperatures (150ºC), depth (1 km) and 30m thickness. The reservoir permeability distribution is heterogeneous, as the result of a fluvial depositional environment. The ERT monitoring system design is a triangular arrangement of 3 wells at 150 m spacing, including 1 injection and 1 extraction well. The optimal number and spacing of electrodes of the ERT array design is site-specific and has been assessed through a sensibility study. Dipole-dipole and pole-pole electrode configurations were used. The study workflow was the following: 1) Generation of a reference reservoir model and 100 stochastic realizations of permeability; 2) Simulation of saturated single-phase flow and heat transport of reinjection of cooled formation fluid (50ºC) with TOUGH2 software; 3) Time-lapse forward ERT modeling on the reference model and all realizations (observed and simulated apparent resistivity change); 4) heuristic optimization on ERT computed and calculated data. Preliminary results show significant reduction of parameter uncertainty, hence realization space, with assimilation of cross-borehole ERT data. Loss in

Description and correlation of reservoir heterogenity within the Big Injun sandstone, Granny Creek field, West Virginia

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

Vargo, A.; McDowell, R.; Matchen, D.

1992-01-01

The Granny Creek field (approximately 6 sq. miles in area), located in Clay and Roane counties, West Virginia, produces oil from the Big Injun sandstone (Lower Mississippian). Analysis of 15 cores, 22 core analyses, and approximately 400 wireline logs (gamma ray and bulk density) show that the Big Injun (approximately 12 to 55 feet thick) can be separated into an upper, coarse-grained sandstone and a lower, fine-grained sandstone. The Big Injun is truncated by an erosional unconformity of Early to Middle Mississippian age which removes the coarse-grain upper unit in the northwest portion of the field. The cores show nodulesmore » and zones (1 inch to 6 feet thick) of calcite and siderite cement. Where the cements occur as zones, porosity and permeability are reduced. Thin shales (1 inch to 1 foot thick) are found in the coarse-grained member of the Big Injun, whereas the bottom of the fine-grained, lower member contains intertongues of dark shale which cause pinchouts in porosity at the bottom of the reservoir. Calcite and siderite cement are recognized on wireline logs as high bulk density zones that form horizontal, inclined, and irregular pods of impermeable sandstone. At a 400 foot well spacing, pods may be confined to a single well or encompass as many as 30 wells creating linear and irregular barriers to flow. These pods increase the length of the fluid flow path and may divide the reservoir into discrete compartments. The combination of sedimentologic and diagenetic features contribute to the heterogeneity observed in the field.« less

Depositional systems and diagenesis of Travis Peak tight gas sandstone reservoirs, Sabine Uplift Area, Texas

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

Fracasso, M.A.; Dutton, S.P.; Finley, R.J.

The Travis Peak formation (lower Cretaceous) in the eastern East Texas basin is a fluvio-deltaic depositional system divided into large-scale facies packages: a middle sandstone-rich fluvial and delta-plain sequence that is gradationally overlain and underlain by a marine-influenced delta-fringe zone with a higher mudstone content. Domes and structural terraces on the west flank of the Sabine Uplift influenced deposition of Travis Peak sediments, and most Travis Peak gas production in this area is from thin sandstones (<25 ft(<7.6 m) thick) in the upper delta-fringe facies. The trapping mechanism is stratigraphic pinch-out of sandstones or porosity zones within sandstone, or both,more » on the flanks of structures. Detailed mapping of producing sandstone sequences in the uppermost upper delta-fringe on the western flank of the Bethany structure has delineated fluvial channelways, distributary or tidal channels, and barrier of distributary-mouth bars. Most Travis Peak gas production in the Bethany West area is from the bases of channel sandstones in a marine-influenced facies belt. Travis Peak sandstones in the eastern East Texas basin have undergone a complex series of diagenetic modifications. Precipitation of authigenic quartz, ankerite, dolomite, illite, and chlorite and the introduction of reservoir bitumen were the most important causes of occlusion of primary porosity and reduction of permeability. Permeability decreases with depth in the Travis Peak, which suggests that the diagenetic processes that caused extensive cementation and resultant low permeability throughout most of the formation operated less completely on sediments deposited near the top of the succession.« less

Experimental Study of Cement - Sandstone/Shale - Brine - CO2 Interactions

PubMed Central

2011-01-01

Background Reactive-transport simulation is a tool that is being used to estimate long-term trapping of CO2, and wellbore and cap rock integrity for geologic CO2 storage. We reacted end member components of a heterolithic sandstone and shale unit that forms the upper section of the In Salah Gas Project carbon storage reservoir in Krechba, Algeria with supercritical CO2, brine, and with/without cement at reservoir conditions to develop experimentally constrained geochemical models for use in reactive transport simulations. Results We observe marked changes in solution composition when CO2 reacted with cement, sandstone, and shale components at reservoir conditions. The geochemical model for the reaction of sandstone and shale with CO2 and brine is a simple one in which albite, chlorite, illite and carbonate minerals partially dissolve and boehmite, smectite, and amorphous silica precipitate. The geochemical model for the wellbore environment is also fairly simple, in which alkaline cements and rock react with CO2-rich brines to form an Fe containing calcite, amorphous silica, smectite and boehmite or amorphous Al(OH)3. Conclusions Our research shows that relatively simple geochemical models can describe the dominant reactions that are likely to occur when CO2 is stored in deep saline aquifers sealed with overlying shale cap rocks, as well as the dominant reactions for cement carbonation at the wellbore interface. PMID:22078161

Provenance, diagenesis, tectonic setting and reservoir quality of the sandstones of the Kareem Formation, Gulf of Suez, Egypt

NASA Astrophysics Data System (ADS)

Zaid, Samir M.

2013-09-01

The Middle Miocene Kareem sandstones are important oil reservoirs in the southwestern part of the Gulf of Suez basin, Egypt. However, their diagenesis and provenance and their impact on reservoir quality, are virtually unknown. Samples from the Zeit Bay Oil Field, and the East Zeit Oil Field represent the Lower Kareem (Rahmi Member) and the Upper Kareem (Shagar Member), were studied using a combination of petrographic, mineralogical and geochemical techniques. The Lower Rahmi sandstones have an average framework composition of Q95F3.4R1.6, and 90% of the quartz grains are monocrystalline. By contrast, the Upper Shagar sandstones are only slightly less quartzose with an average framework composition of Q76F21R3 and 82% of the quartz grains are monocrystalline. The Kareem sandstones are mostly quartzarenite with subordinate subarkose and arkose. Petrographical and geochemical data of sandstones indicate that they were derived from granitic and metamorphic terrains as the main source rock with a subordinate quartzose recycled sedimentary rocks and deposited in a passive continental margin of a syn rift basin. The sandstones of the Kareem Formation show upward decrease in maturity. Petrographic study revealed that dolomite is the dominant cement and generally occurs as fine to medium rhombs pore occluding phase and locally as a grain replacive phase. Authigenic quartz occurs as small euhedral crystals, locally as large pyramidal crystals in the primary pores. Authigenic anhydrites typically occur as poikilotopic rhombs or elongate laths infilling pores but also as vein filling cement. The kaolinite is a by-product of feldspar leaching in the presence of acidic fluid produced during the maturation of organic matter in the adjacent Miocene rocks. Diagenetic features include compaction; dolomite, silica and anhydrite cementation with minor iron-oxide, illite, kaolinite and pyrite cements; dissolution of feldspars, rock fragments. Silica dissolution, grain replacement and

Modeling CO2 distribution in a heterogeneous sandstone reservoir: the Johansen Formation, northern North Sea

NASA Astrophysics Data System (ADS)

Sundal, Anja; Miri, Rohaldin; Petter Nystuen, Johan; Dypvik, Henning; Aagaard, Per

2013-04-01

The last few years there has been broad attention towards finding permanent storage options for CO2. The Norwegian continental margin holds great potential for storage in saline aquifers. Common for many of these reservoir candidates, however, is that geological data are sparse relative to thoroughly mapped hydrocarbon reservoirs in the region. Scenario modeling provides a method for estimating reservoir performances for potential CO2 storage sites and for testing injection strategies. This approach is particularly useful in the evaluation of uncertainties related to reservoir properties and geometry. In this study we have tested the effect of geological heterogeneities in the Johansen Formation, which is a laterally extensive sandstone and saline aquifer at burial depths of 2 - 4 km, proposed as a suitable candidate for CO2 storage by Norwegian authorities. The central parts of the Johansen Formation are underlying the operating hydrocarbon field Troll. In order not to interfere with ongoing gas production, a potential CO2 injection well should be located at a safe distance from the gas reservoir, which consequently implies areas presently without well control. From 3D seismic data, prediction of spatial extent of sandstone is possible to a certain degree, whereas intra-reservoir flow baffles such as draping mudstone beds and calcite cemented layers are below seismic resolution. The number and lateral extent of flow baffles, as well as porosity- and permeability distributions are dependent of sedimentary facies and diagenesis. The interpretation of depositional environment and burial history is thus of crucial importance. A suite of scenario models was established for a potential injection area south of the Troll field. The model grids where made in Petrel based on our interpretations of seismic data, wire line logs, core and cuttings samples. Using Eclipse 300 the distribution of CO2 is modeled for different geological settings; with and without the presence of

Sedimentologic and reservoir characteristics under the tectono-sequence stratigraphic framework: A case study from the Early Cretaceous, upper Abu Gabra sandstones, Sufyan Sub-basin, Muglad Basin, Sudan

NASA Astrophysics Data System (ADS)

Yassin, Mohamed A.; Hariri, Mustafa M.; Abdullatif, Osman M.; Makkawi, M.; Bertotti, G.; Kaminski, Michael A.

2018-06-01

The Sufyan Sub-basin is an east-west trending Sub-basin located in the northwestern part of the Muglad Basin, in the eastern extension of the West and Central Africa Rift System (WCARS). Exploration results showed the occurrence of accumulations of hydrocarbon. The source rock for these hydrocarbons is believed to be the lacustrine shale of the Abu Gabra Formation. Fluvio-deltaic sandstones within the Abu Gabra Formation represent the primary reservoir. Depositional and post-depositional processes influence reservoir heterogeneity, quality, and architecture. This study investigates different scales of reservoir heterogeneities from basin to micro scale and discusses the impact of depositional facies and diagenesis on reservoir quality. Approaches include seismic interpretation, seismic attribute analysis, well log analysis, thin sections and scanning electron microscope (SEM) investigations, and X-ray diffraction (XRD) analysis of the Abu Gabra Formation. Sedimentologic interpretation in this study was performed based on core cuttings, well logs, and seismic data. Subsurface facies analysis was analyzed based on the description of six conventional cores from two wells. Seven lithofacies in Abu Gabra Formation are identified. Four types of depositional systems are identified in the studied succession. These are braided delta, fan delta, sublacustrine fan, and lacustrine systems. The sandstone is medium to coarse-grained, poorly to moderately sorted and sub-angular to sub-rounded, sub-feldspathic arenite to quartz arenite. At the basin scale, the Abu Gabra Formation showed different sandstone bodies thickness, geometry, and architecture and are ascribed to different depositional systems. At macro and meso-scales, reservoir quality varies within the Abu Gabra reservoir where it shows progressive coarsening upward tendencies with different degrees of connectivity. The upper part of the reservoir is well connected with amalgamated sandstone bodies, however, the middle

Development of diagenetic seals in carbonates and sandstones

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

Schmidt, V.; Almon, W.

1983-03-01

Diagenetic seals effectively block the movement of reservoir hydrocarbons in many sandstone and carbonate rock units. Diagenetic seals in sandstones and carbonate rocks encase reservoir rocks with either depositional or diagenetic porosity. Diagenetic reservoir porosity may originate before or after the establishment of an effective diagenetic seal. Hydrocarbon traps with diagenetic seals may conform in their geometry as well to structure or stratigraphy as to diagenetic facies. Therefore, some structural and stratigraphic traps may, in part or entirely, depend on diagenetic seals. Detailed analysis of diagenetic seals in sandstones and carbonate rocks can considerably improve our ability to predict theirmore » occurrence and to recognize their spatial and temporal relationship to reservoir rocks and hydrocarbon migration.« less

ANALYSIS OF OIL-BEARING CRETACEOUS SANDSTONE HYDROCARBON RESERVOIRS, EXCLUSIVE OF THE DAKOTA SANDSTONE, ON THE JICARILLA APACHE INDIAN RESERVATION, NEW MEXICO

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

Jennie Ridgley

2000-01-21

An additional 450 wells were added to the structural database; there are now 2550 wells in the database with corrected tops on the Juana Lopez, base of the Bridge Creek Limestone, and datum. This completes the structural data base compilation. Fifteen oil and five gas fields from the Mancos-ElVado interval were evaluated with respect to the newly defined sequence stratigraphic model for this interval. The five gas fields are located away from the structural margins of the deep part of the San Juan Basin. All the fields have characteristics of basin-centered gas and can be considered as continuous gas accumulationsmore » as recently defined by the U.S. Geological Survey. Oil production occurs in thinly interbedded sandstone and shale or in discrete sandstone bodies. Production is both from transgressive and regressive strata as redefined in this study. Oil production is both stratigraphically and structurally controlled with production occurring along the Chaco slope or in steeply west-dipping rocks along the east margin of the basin. The ElVado Sandstone of subsurface usage is redefined to encompass a narrower interval; it appears to be more time correlative with the Dalton Sandstone. Thus, it was deposited as part of a regressive sequence, in contrast to the underlying rock units which were deposited during transgression.« less

Reservoir characterization of the Mt. Simon Sandstone, Illinois Basin, USA

USGS Publications Warehouse

Frailey, S.M.; Damico, J.; Leetaru, H.E.

2011-01-01

The integration of open hole well log analyses, core analyses and pressure transient analyses was used for reservoir characterization of the Mt. Simon sandstone. Characterization of the injection interval provides the basis for a geologic model to support the baseline MVA model, specify pressure design requirements of surface equipment, develop completion strategies, estimate injection rates, and project the CO2 plume distribution.The Cambrian-age Mt. Simon Sandstone overlies the Precambrian granite basement of the Illinois Basin. The Mt. Simon is relatively thick formation exceeding 800 meters in some areas of the Illinois Basin. In the deeper part of the basin where sequestration is likely to occur at depths exceeding 1000 m, horizontal core permeability ranges from less than 1 ?? 10-12 cm 2 to greater than 1 ?? 10-8 cm2. Well log and core porosity can be up to 30% in the basal Mt. Simon reservoir. For modeling purposes, reservoir characterization includes absolute horizontal and vertical permeability, effective porosity, net and gross thickness, and depth. For horizontal permeability, log porosity was correlated with core. The core porosity-permeability correlation was improved by using grain size as an indication of pore throat size. After numerous attempts to identify an appropriate log signature, the calculated cementation exponent from Archie's porosity and resistivity relationships was used to identify which porosity-permeability correlation to apply and a permeability log was made. Due to the relatively large thickness of the Mt. Simon, vertical permeability is an important attribute to understand the distribution of CO2 when the injection interval is in the lower part of the unit. Only core analyses and specifically designed pressure transient tests can yield vertical permeability. Many reservoir flow models show that 500-800 m from the injection well most of the CO2 migrates upward depending on the magnitude of the vertical permeability and CO2 injection

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.

Petroleum geology of Carter sandstone (upper Mississippian), Black Warrior Basin, Alabama

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

Bearden, B.L.; Mancini, E.A.

1985-03-01

The presence of combination petroleum traps makes the Black Warrior basin of northwestern Alabama an attractive area for continued hydrocarbon exploration. More than 1,500 wells have been drilled, and more than 90 separate petroleum pools have been discovered. The primary hydrocarbon reservoirs are Upper Mississippian sandstones. The Carter sandstone is the most productive petroleum reservoir in the basin. Productivity of the Carter sandstone is directly related to its environment of deposition. The Carter accumulated within a high constructive elongate to lobate delta, which prograded into the basin from the northwest to the southeast. Carter bar-finger and distal-bar lithofacies constitute themore » primary hydrocarbon reservoirs. Primary porosity in the Carter sandstone has been reduced by quartz overgrowths and calcite cementation. Petroleum traps in the Carter sandstone in central Fayette and Lamar Counties, Alabama, are primarily stratigraphic and combination (structural-stratigraphic) traps. The potential is excellent for future development of hydrocarbon reservoirs in the Upper Mississippian Carter sandstone. Frontier regions south and east of the known productive limits of the Black Warrior basin are ideal areas for continued exploration.« less

Performance of Surfactant Methyl Ester Sulphonate solution for Oil Well Stimulation in reservoir sandstone TJ Field

NASA Astrophysics Data System (ADS)

Eris, F. R.; Hambali, E.; Suryani, A.; Permadi, P.

2017-05-01

Asphaltene, paraffin, wax and sludge deposition, emulsion and water blocking are kinds ofprocess that results in a reduction of the fluid flow from the reservoir into formation which causes a decrease of oil wells productivity. Oil well Stimulation can be used as an alternative to solve oil well problems. Oil well stimulation technique requires applying of surfactant. Sodium Methyl Ester Sulphonate (SMES) of palm oil is an anionic surfactant derived from renewable natural resource that environmental friendly is one of potential surfactant types that can be used in oil well stimulation. This study was aimed at formulation SMES as well stimulation agent that can identify phase transitions to phase behavior in a brine-surfactant-oil system and altered the wettability of rock sandstone and limestone. Performance of SMES solution tested by thermal stability test, phase behavioral examination and rocks wettability test. The results showed that SMES solution (SMES 5% + xylene 5% in the diesel with addition of 1% NaCl at TJformation water and SMES 5% + xylene 5% in methyl ester with the addition of NaCl 1% in the TJ formation water) are surfactant that can maintain thermal stability, can mostly altered the wettability toward water-wet in sandstone reservoir, TJ Field.

Digital Rock Physics Aplications: Visualisation Complex Pore and Porosity-Permeability Estimations of the Porous Sandstone Reservoir

NASA Astrophysics Data System (ADS)

Handoyo; Fatkhan; Del, Fourier

2018-03-01

Reservoir rock containing oil and gas generally has high porosity and permeability. High porosity is expected to accommodate hydrocarbon fluid in large quantities and high permeability is associated with the rock’s ability to let hydrocarbon fluid flow optimally. Porosity and permeability measurement of a rock sample is usually performed in the laboratory. We estimate the porosity and permeability of sandstones digitally by using digital images from μCT-Scan. Advantages of the method are non-destructive and can be applied for small rock pieces also easily to construct the model. The porosity values are calculated by comparing the digital image of the pore volume to the total volume of the sandstones; while the permeability values are calculated using the Lattice Boltzmann calculations utilizing the nature of the law of conservation of mass and conservation of momentum of a particle. To determine variations of the porosity and permeability, the main sandstone samples with a dimension of 300 × 300 × 300 pixels are made into eight sub-cubes with a size of 150 × 150 × 150 pixels. Results of digital image modeling fluid flow velocity are visualized as normal velocity (streamline). Variations in value sandstone porosity vary between 0.30 to 0.38 and permeability variations in the range of 4000 mD to 6200 mD. The results of calculations show that the sandstone sample in this research is highly porous and permeable. The method combined with rock physics can be powerful tools for determining rock properties from small rock fragments.

Well logging evaluation of water-flooded layers and distribution rule of remaining oil in marine sandstone reservoirs of the M oilfield in the Pearl River Mouth basin

NASA Astrophysics Data System (ADS)

Li, Xiongyan; Qin, Ruibao; Gao, Yunfeng; Fan, Hongjun

2017-03-01

In the marine sandstone reservoirs of the M oilfield the water cut is up to 98%, while the recovery factor is only 35%. Additionally, the distribution of the remaining oil is very scattered. In order to effectively assess the potential of the remaining oil, the logging evaluation of the water-flooded layers and the distribution rule of the remaining oil are studied. Based on the log response characteristics, the water-flooded layers can be qualitatively identified. On the basis of the mercury injection experimental data of the evaluation wells, the calculation model of the initial oil saturation is built. Based on conventional logging data, the evaluation model of oil saturation is established. The difference between the initial oil saturation and the residual oil saturation can be used to quantitatively evaluate the water-flooded layers. The evaluation result of the water-flooded layers is combined with the ratio of the water-flooded wells in the marine sandstone reservoirs. As a result, the degree of water flooding in the marine sandstone reservoirs can be assessed. On the basis of structural characteristics and sedimentary environments, the horizontal and vertical water-flooding rules of the different types of reservoirs are elaborated upon, and the distribution rule of the remaining oil is disclosed. The remaining oil is mainly distributed in the high parts of the structure. The remaining oil exists in the top of the reservoirs with good physical properties while the thickness of the remaining oil ranges from 2-5 m. However, the thickness of the remaining oil of the reservoirs with poor physical properties ranges from 5-8 m. The high production of some of the drilled horizontal wells shows that the above distribution rule of the remaining oil is accurate. In the marine sandstone reservoirs of the M oilfield, the research on the well logging evaluation of the water-flooded layers and the distribution rule of the remaining oil has great practical significance to

Seismic spectral decomposition and analysis based on Wigner-Ville distribution for sandstone reservoir characterization in West Sichuan depression

NASA Astrophysics Data System (ADS)

Wu, Xiaoyang; Liu, Tianyou

2010-06-01

Reflections from a hydrocarbon-saturated zone are generally expected to have a tendency to be low frequency. Previous work has shown the application of seismic spectral decomposition for low-frequency shadow detection. In this paper, we further analyse the characteristics of spectral amplitude in fractured sandstone reservoirs with different fluid saturations using the Wigner-Ville distribution (WVD)-based method. We give a description of the geometric structure of cross-terms due to the bilinear nature of WVD and eliminate cross-terms using smoothed pseudo-WVD (SPWVD) with time- and frequency-independent Gaussian kernels as smoothing windows. SPWVD is finally applied to seismic data from West Sichuan depression. We focus our study on the comparison of SPWVD spectral amplitudes resulting from different fluid contents. It shows that prolific gas reservoirs feature higher peak spectral amplitude at higher peak frequency, which attenuate faster than low-quality gas reservoirs and dry or wet reservoirs. This can be regarded as a spectral attenuation signature for future exploration in the study area.

Measuring and predicting reservoir heterogeneity in complex deposystems: The fluvial-deltaic Big Injun sandstone in West Virginia. Annual report, September 20, 1991--September 20, 1992

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

Patchen, D.G.; Hohn, M.E.; Aminian, K.

1993-04-01

The purpose of this research is to develop techniques to measure and predict heterogeneities in oil reservoirs that are the products of complex deposystems. The unit chosen for study is the Lower Mississippian Big Injun sandstone, a prolific oil producer (nearly 60 fields) in West Virginia. This research effort has been designed and is being implemented as an integrated effort involving stratigraphy, structural geology, petrology, seismic study, petroleum engineering, modeling and geostatistics. Sandstone bodies are being mapped within their regional depositional systems, and then sandstone bodies are being classified in a scheme of relative heterogeneity to determine heterogeneity across depositionalmore » systems. Facies changes are being mapped within given reservoirs, and the environments of deposition responsible for each facies are being interpreted to predict the inherent relative heterogeneity of each facies. Structural variations will be correlated both with production, where the availability of production data will permit, and with variations in geologic and engineering parameters that affect production. A reliable seismic model of the Big Injun reservoirs in Granny Creek field is being developed to help interpret physical heterogeneity in that field. Pore types are being described and related to permeability, fluid flow and diagenesis, and petrographic data are being integrated with facies and depositional environments to develop a technique to use diagenesis as a predictive tool in future reservoir development. Another objective in the Big Injun study is to determine the effect of heterogeneity on fluid flow and efficient hydrocarbon recovery in order to improve reservoir management. Graphical methods will be applied to Big Injun production data and new geostatistical methods will be developed to detect regional trends in heterogeneity.« less

Sandstone-filled normal faults: A case study from central California

NASA Astrophysics Data System (ADS)

Palladino, Giuseppe; Alsop, G. Ian; Grippa, Antonio; Zvirtes, Gustavo; Phillip, Ruy Paulo; Hurst, Andrew

2018-05-01

Despite the potential of sandstone-filled normal faults to significantly influence fluid transmissivity within reservoirs and the shallow crust, they have to date been largely overlooked. Fluidized sand, forcefully intruded along normal fault zones, markedly enhances the transmissivity of faults and, in general, the connectivity between otherwise unconnected reservoirs. Here, we provide a detailed outcrop description and interpretation of sandstone-filled normal faults from different stratigraphic units in central California. Such faults commonly show limited fault throw, cm to dm wide apertures, poorly-developed fault zones and full or partial sand infill. Based on these features and inferences regarding their origin, we propose a general classification that defines two main types of sandstone-filled normal faults. Type 1 form as a consequence of the hydraulic failure of the host strata above a poorly-consolidated sandstone following a significant, rapid increase of pore fluid over-pressure. Type 2 sandstone-filled normal faults form as a result of regional tectonic deformation. These structures may play a significant role in the connectivity of siliciclastic reservoirs, and may therefore be crucial not just for investigation of basin evolution but also in hydrocarbon exploration.

Oligo-Miocene reservoir sequence characterization and structuring in the Sisseb El Alem-Kalaa Kebira regions (Northeastern Tunisia)

NASA Astrophysics Data System (ADS)

Houatmia, Faten; Khomsi, Sami; Bédir, Mourad

2015-11-01

The Sisseb El Alem-Enfidha basin is located in the northeastern Tunisia, It is borded by Nadhour - Saouaf syncline to the north, Kairouan plain to the south, the Mediterranean Sea to the east and Tunisian Atlassic "dorsale" to the west. Oligocene and Miocene deltaic deposits present the main potential deep aquifers in this basin with high porosity (25%-30%). The interpretation of twenty seismic reflection profiles, calibrated by wire line logging data of twelve oil wells, hydraulic wells and geologic field sections highlighted the impact of tectonics on the structuring geometry of Oligo-Miocene sandstones reservoirs and their distribution in raised structures and subsurface depressions. Miocene seismostratigraphy analysis from Ain Ghrab Formation (Langhian) to the Segui Formation (Quaternary) showed five third-order seismic sequence deposits and nine extended lenticular sandy bodies reservoirs limited by toplap and downlap surfaces unconformities, Oligocene deposits presented also five third- order seismic sequences with five extended lenticular sandy bodies reservoirs. The Depth and the thickness maps of these sequence reservoir packages exhibited the structuring of this basin in sub-basins characterized by important lateral and vertical geometric and thichness variations. Petroleum wells wire line logging correlation with clay volume calculation showed an heterogeneous multilayer reservoirs of Oligocene and Miocene formed by the arrangement of fourteen sandstone bodies being able to be good reservoirs, separated by impermeable clay packages and affected by faults. Reservoirs levels correspond mainly to the lower system tract (LST) of sequences. Intensive fracturing by deep seated faults bounding the different sub-basins play a great role for water surface recharge and inter-layer circulations between affected reservoirs. The total pore volume of the Oligo-Miocene reservoir sandy bodies in the study area, is estimated to about 4 × 1012 m3 and equivalent to 4 �

Long-Term CO2 Exposure Experiments - Geochemical Effects on Brine-Saturated Reservoir Sandstone

NASA Astrophysics Data System (ADS)

Fischer, Sebastian; Zemke, Kornelia; Liebscher, Axel; Wandrey, Maren

2010-05-01

The injection of CO2 into deep saline aquifers is the most promising strategy for the reduction of CO2 emissions to the atmosphere via long-term geological storage. The study is part of the CO2SINK project conducted at Ketzin, situated 40 km west of Berlin. There, food grade CO2 has been pumped into the Upper Triassic Stuttgart Formation since June 2008. The main objective of the experimental program is to investigate the effects of long-term CO2 exposure on the physico-chemical properties of the reservoir rock. To achieve this goal, core samples from observation well Ktzi 202 have been saturated with synthetic brine and exposed to CO2 in high quality steel autoclaves at simulated reservoir P-T-conditions of 5.5 MPa and 40 ° C. The synthetic brine had a composition representative of the formation fluid (Förster et al., 2006) of 172.8 g/l NaCl, 8.0 g/l MgCl2×2H2O, 4.8 g/l CaCl2×2H2O and 0.6 g/l KCl. After 15 months, the first set of CO2-exposed samples was removed from the pressure vessels. Thin sections, XRD, SEM as well as EMP data were used to determine the mineralogical features of the reservoir rocks before and after the experiments. Additionally, NMR relaxation and MP was performed to measure poroperm and pore size distribution values of the twin samples. The analyzed samples are fine- to medium grained, moderately well- to well sorted and weakly consolidated sandstones. Quartz and plagioclase are the major components, while K-feldspar, hematite, white & dark mica, chlorite and illite are present in minor and varying amounts. Cements are composed of analcime, dolomite and anhydrite. Some samples show mm- to cm-scale cross-beddings. The laminae comprise lighter, quartz- and feldspar-dominated layers and dark-brownish layers with notably less quartz and feldspars. The results are consistent with those of Blaschke et al. (2008). The plagioclase composition indicates preferred dissolution of the Ca-component and a trend toward albite-rich phases or even pure

Radon-222 content of natural gas samples from Upper and Middle Devonian sandstone and shale reservoirs in Pennsylvania—preliminary data

USGS Publications Warehouse

Rowan, E.L.; Kraemer, T.F.

2012-01-01

Samples of natural gas were collected as part of a study of formation water chemistry in oil and gas reservoirs in the Appalachian Basin. Nineteen samples (plus two duplicates) were collected from 11 wells producing gas from Upper Devonian sandstones and the Middle Devonian Marcellus Shale in Pennsylvania. The samples were collected from valves located between the wellhead and the gas-water separator. Analyses of the radon content of the gas indicated 222Rn (radon-222) activities ranging from 1 to 79 picocuries per liter (pCi/L) with an overall median of 37 pCi/L. The radon activities of the Upper Devonian sandstone samples overlap to a large degree with the activities of the Marcellus Shale samples.

Effective Wettability Measurements of CO2-Brine-Sandstone System at Different Reservoir Conditions

NASA Astrophysics Data System (ADS)

Al-Menhali, Ali; Krevor, Samuel

2014-05-01

, core-scale effective contact angle can be determined. In addition to providing a quantitative measure of the core-averaged wetting properties, the technique allows for the observation of shifts in contact angle with changing conditions. We examine the wettability changes of the CO2-brine system in Berea sandstone with variations in reservoir conditions including supercritical, gaseous and liquid CO2injection. We evaluate wettability variation within a single rock with temperature, pressure, and salinity across a range of conditions relevant to subsurface CO2 storage. This study will include results of measurements in a Berea sandstone sample across a wide range of conditions representative of subsurface reservoirs suitable for CO2 storage (5-20 MPa, 25-90 oC, 0-5 mol kg-1). The measurement uses X-ray CT imaging in a state of the art core flooding laboratory designed to operate at high temperature, pressure, and concentrated brines.

Flow units classification for geostatisitical three-dimensional modeling of a non-marine sandstone reservoir: A case study from the Paleocene Funing Formation of the Gaoji Oilfield, east China

NASA Astrophysics Data System (ADS)

Zhang, Penghui; Zhang, Jinliang; Wang, Jinkai; Li, Ming; Liang, Jie; Wu, Yingli

2018-05-01

Flow units classification can be used in reservoir characterization. In addition, characterizing the reservoir interval into flow units is an effective way to simulate the reservoir. Paraflow units (PFUs), the second level of flow units, are used to estimate the spatial distribution of continental clastic reservoirs at the detailed reservoir description stage. In this study, we investigate a nonroutine methodology to predict the external and internal distribution of PFUs. The methodology outlined enables the classification of PFUs using sandstone core samples and log data. The relationships obtained between porosity, permeability and pore throat aperture radii (r35) values were established for core and log data obtained from 26 wells from the Funing Formation, Gaoji Oilfield, Subei Basin, China. The present study refines predicted PFUs at logged (0.125-m) intervals, whose scale is much smaller than routine methods. Meanwhile, three-dimensional models are built using sequential indicator simulation to characterize PFUs in wells. Four distinct PFUs are classified and located based on the statistical methodology of cluster analysis, and each PFU has different seepage ability. The results of this study demonstrate the obtained models are able to quantify reservoir heterogeneity. Due to different petrophysical characteristics and seepage ability, PFUs have a significant impact on the distribution of the remaining oil. Considering these allows a more accurate understanding of reservoir quality, especially within non-marine sandstone reservoirs.

Permeability structure of a highly heterogeneous transgressive-marine complex: Tocito Sandstone, New Mexico

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

Lambert, M.L.; Cole, R.D.

1996-01-01

The Tocito Sandstone Member of the Mancos Shale is an Upper Cretaceous shallow-marine sandstone and mudrock complex deposited along the western margin of the Western Interior seaway. The Tocito is a major hydrocarbon producer in the San Juan Basin (approximately 117 million barrels of oil and 79 billion cubic feet of gas). Because of reservoir heterogeneity, ultimate Tocito oil recovery factors are low, generally between 10 and 20 percent. To enhance understanding of permeability heterogeneity in the Tocito, we have undertaken a detailed surface and subsurface investigation. A total of 2,697 permeability measurements have been made using minipermeameters. Permeability variationmore » within the Tocito is controlled by two principal factors: lithofacies and burial/diagenetic history. Coarser grained and better sorted lithofacies have the highest permeability. The permeability values from outcrop and shallow subsurface cores are dramatically higher than those from deep subsurface cores. This is due to dissolution of grains and calcite cement, and decompaction that preferentially affected the outcrop and shallow subsurface. Correlation lengths for permeability values along horizontal transacts are typically less than 3 m, whereas those for vertical transacts are usually less than 0.6 m. These data suggest that small grid block sizes should be used during reservoir simulations if the investigator wishes to accurately capture the reservoir heterogeneity.« less

Permeability structure of a highly heterogeneous transgressive-marine complex: Tocito Sandstone, New Mexico

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

Lambert, M.L.; Cole, R.D.

1996-12-31

The Tocito Sandstone Member of the Mancos Shale is an Upper Cretaceous shallow-marine sandstone and mudrock complex deposited along the western margin of the Western Interior seaway. The Tocito is a major hydrocarbon producer in the San Juan Basin (approximately 117 million barrels of oil and 79 billion cubic feet of gas). Because of reservoir heterogeneity, ultimate Tocito oil recovery factors are low, generally between 10 and 20 percent. To enhance understanding of permeability heterogeneity in the Tocito, we have undertaken a detailed surface and subsurface investigation. A total of 2,697 permeability measurements have been made using minipermeameters. Permeability variationmore » within the Tocito is controlled by two principal factors: lithofacies and burial/diagenetic history. Coarser grained and better sorted lithofacies have the highest permeability. The permeability values from outcrop and shallow subsurface cores are dramatically higher than those from deep subsurface cores. This is due to dissolution of grains and calcite cement, and decompaction that preferentially affected the outcrop and shallow subsurface. Correlation lengths for permeability values along horizontal transacts are typically less than 3 m, whereas those for vertical transacts are usually less than 0.6 m. These data suggest that small grid block sizes should be used during reservoir simulations if the investigator wishes to accurately capture the reservoir heterogeneity.« less

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

Correlative multiple porosimetries for reservoir sandstones with adoption of a new reference-sample-guided computed-tomographic method.

PubMed

Jin, Jae Hwa; Kim, Junho; Lee, Jeong-Yil; Oh, Young Min

2016-07-22

One of the main interests in petroleum geology and reservoir engineering is to quantify the porosity of reservoir beds as accurately as possible. A variety of direct measurements, including methods of mercury intrusion, helium injection and petrographic image analysis, have been developed; however, their application frequently yields equivocal results because these methods are different in theoretical bases, means of measurement, and causes of measurement errors. Here, we present a set of porosities measured in Berea Sandstone samples by the multiple methods, in particular with adoption of a new method using computed tomography and reference samples. The multiple porosimetric data show a marked correlativeness among different methods, suggesting that these methods are compatible with each other. The new method of reference-sample-guided computed tomography is more effective than the previous methods when the accompanied merits such as experimental conveniences are taken into account.

Community dynamics of anaerobic bacteria in deep petroleum reservoirs

NASA Astrophysics Data System (ADS)

Hallmann, Christian; Schwark, Lorenz; Grice, Kliti

2008-09-01

The nature, activity and metabolism of microbes that inhabit the deep subsurface environment are a matter of ongoing debate. Primarily limited by temperature, little is known about secondary factors that restrict or enhance microbial activity or about the extent of a habitable environment deep below the surface. In particular, the degraders of chemically inert organic substrates remain elusive. Petroleum reservoirs can be regarded as natural bioreactors and are ideally suited for the study of microbial metabolism in the deep subsurface. Here we analyse series of oil samples that were biodegraded to different degrees. We find fatty acids after hydrolysis of purified crude oil fractions, indicating the presence of intact phospholipids and suggesting that indigenous bacteria inhabit petroleum reservoirs in sediment depths of up to 2,000m. A major change in bacterial community structure occurs after the removal of n-alkanes, indicating that more than one consortium is responsible for petroleum degradation. Our results suggest that further study of petroleum fluids will help understand bacterial metabolism and diversity in this habitat of the deep subsurface.

Possible continuous-type (unconventional) gas accumulation in the Lower Silurian "Clinton" sands, Medina Group and Tuscarora Sandstone in the Appalachian Basin; a progress report of the 1995 project activities

USGS Publications Warehouse

Ryder, Robert T.; Aggen, Kerry L.; Hettinger, Robert D.; Law, Ben E.; Miller, John J.; Nuccio, Vito F.; Perry, William J.; Prensky, Stephen E.; Filipo, John J.; Wandrey, Craig J.

1996-01-01

INTRODUCTION: In the U.S. Geological Survey's (USGS) 1995 National Assessment of United States oil and gas resources (Gautier and others, 1995), the Appalachian basin was estimated to have, at a mean value, about 61 trillion cubic feet (TCF) of recoverable gas in sandstone and shale reservoirs of Paleozoic age. Approximately one-half of this gas resource is estimated to reside in a regionally extensive, continuous-type gas accumulation whose reservoirs consist of low-permeability sandstone of the Lower Silurian 'Clinton' sands and Medina Group (Gautier and others, 1995; Ryder, 1995). Recognizing the importance of this large regional gas accumulation for future energy considerations, the USGS initiated in January 1995 a multi-year study to evaluate the nature, distribution, and origin of natural gas in the 'Clinton' sands, Medina Group sandstones, and equivalent Tuscarora Sandstone. The project is part of a larger natural gas project, Continuous Gas Accumulations in Sandstones and Carbonates, coordinated in FY1995 by Ben E. Law and Jennie L. Ridgley, USGS, Denver. Approximately 2.6 man years were devoted to the Clinton/Medina project in FY1995. A continuous-type gas accumulation, referred to in the project, is a new term introduced by Schmoker (1995a) to identify those natural gas accumulations whose reservoirs are charged throughout with gas over a large area and whose entrapment does not involve a downdip gas-water contact. Gas in these accumulations is located downdip of the water column and, thus, is the reverse of conventional-type hydrocarbon accumulations. Commonly used industry terms that are more or less synonymous with continuous-type gas accumulations include basin- centered gas accumulation (Rose and others, 1984; Law and Spencer, 1993), tight (low-permeability) gas reservoir (Spencer, 1989; Law and others, 1989; Perry, 1994), and deep basin gas (Masters, 1979, 1984). The realization that undiscovered gas in Lower Silurian sandstone reservoirs of the

Reservoir compartmentalization of deep-water Intra Qua Iboe sand (Pliocene), Edop field, offshore Nigeria

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

Hermance, W.E.; Olaifa, J.O.; Shanmugam, G.

An integration of 3-D seismic and sedimentological information provides a basis for recognizing and mapping individual flow units within the Intra Qua Iboe (IQI) reservoir (Pliocene), Edop Field, offshore Nigeria. Core examination show the following depositional facies: A-Sandy slump/mass flow, B-Muddy slump/mass flow, C. Bottom current reworking. D-Non-channelized turbidity currents, E. Channelized (coalesced) turbidity currents. F-Channelized (isolated) turbidity currents, G-Pelagic/hemipelagic, H-Levee, I-Reworked slope, J-Wave dominated, and K-Tide dominated facies. With the exception of facies J and K, all these facies are of deep-water affinity. The IQI was deposited on an upper slope environment in close proximity to the shelf edge.more » Through time, as the shelf edge migrated scaward, deposition began with a channel dominated deep-water system (IQI 1 and 2) and progressed through a slump/debris flow dominated deep-water system (IQI 3, the principle reservoir) to a tide and wave dominated shallow-water system (IQI 4). Compositional and textural similarities between the deep-water facies result in similar log motifs. Furthermore, these depositional facies are not readily apparent as distinct seismic facies. Deep-water facies A, D, E, and F are reservoir facies, whereas facies B, C, G, H, and I are non-reservoir facies. However, Facies G is useful as a seismically mappable event throughout the study area. Mapping of these non-reservoir events provides the framework for understanding gross reservoir architecture. This study has resulted in seven defined reservoir units within the IQI, which serves as the architectural framework for ongoing reservoir characterization.« less

Correlative multiple porosimetries for reservoir sandstones with adoption of a new reference-sample-guided computed-tomographic method

PubMed Central

Jin, Jae Hwa; Kim, Junho; Lee, Jeong-Yil; Oh, Young Min

2016-01-01

One of the main interests in petroleum geology and reservoir engineering is to quantify the porosity of reservoir beds as accurately as possible. A variety of direct measurements, including methods of mercury intrusion, helium injection and petrographic image analysis, have been developed; however, their application frequently yields equivocal results because these methods are different in theoretical bases, means of measurement, and causes of measurement errors. Here, we present a set of porosities measured in Berea Sandstone samples by the multiple methods, in particular with adoption of a new method using computed tomography and reference samples. The multiple porosimetric data show a marked correlativeness among different methods, suggesting that these methods are compatible with each other. The new method of reference-sample-guided computed tomography is more effective than the previous methods when the accompanied merits such as experimental conveniences are taken into account. PMID:27445105

Lower Cretaceous Avile Sandstone, Neuquen basin, Argentina - Exploration model for a lowstand clastic wedge in a back-arc basin

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

Ryer, T.A.

1991-03-01

The Neuquen basin of western Argentina is a back-arc basin that was occupied by epeiric seas during much of Jurassic and Cretaceous time. The Avile Sandstone Member of the Agrio Formation records a pronounced but short-lived regression of the Agrio sea during middle Hauterivian (Early Cretaceous) time. Abrupt lowering of relative sea level resulted in emergence and erosion of the Agrio sea floor; shoreline and fluvial facies characteristic of the Centenario Formation shifted basinward. The Avile rests erosionally upon lower Agrio shale over a large area; well-sorted, porous sandstones within the member pinch out laterally against the base-Avile erosional surface.more » Avile deposition closed with an abrupt transgression of the shoreline to the approximate position it had occupied prior to the Avile regression. The transgressive deposits are carbonate rich, reflecting starvation of the basin as a consequence of sea-level rise. The Avile lowstand clastic wedge consists predominantly of sandstones deposited in fluvial to shallow-marine paleoenvironments; eolian sandstones probably constitute an important component in the eastern part of the area. The sandstones locally have excellent reservoir characteristics; they constitute the reservoirs in the Puesto Hernandez, Chihuido de la Sierra Negra, and Filo Morado fields. The pinch-out of the Avile lowstand clastic wedge has the potential to form stratigraphic traps in favorable structural positions. The depositional model indicates that there may be a viable stratigraphic play to be made along the Avile pinch-out in the deep, relatively undrilled, northwestern part of the Neuquen basin.« less

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

Gulf of Mexico Oil and Gas Atlas Series: Chronostratigraphically bound reservoir plays in Texas and federal offshore waters

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

Seni, S.J.; Desselle, B.A.; Standen, A.

1994-09-01

The search for additional hydrocarbons in the Gulf of Mexico is directing exploration toward both deep-water frontier trends and historically productive areas on the shelf. The University of Texas at Austin, Bureau of Economic Geology, in cooperation with the Minerals Management Service, the Gas Research Institute, and the U.S. Department of Energy, is responding to this need through a coordinated research effort to develop an oil and gas atlas series for the offshore northern Gulf of Mexico. The atlas series will group regional trends of oil and gas reservoirs into subregional plays and will display graphical location and reservoir datamore » on a computerized information system. Play methodology includes constructing composite type logs with producing zones for all fields, identifying progradational, aggradational, and retrogradational depositional styles, and displaying geologic data for type fields. Deep-water sand-rich depositional systems are identified separately on the basis of faunal ecozones, chronostratigraphic facies position, and log patterns. To date, 4 Oligocene, 19 Lower Miocene, and 5 Upper Miocene plays have been identified in Texas state offshore waters. Texas state offshore plays are gas prone and are preferentially trapped in rollover anticlines. Lower Miocene plays include deep-water sandstones of Lenticulina hanseni and jeffersonensis; progradational sandstones of Marginulina, Discorbis b, Siphonia davisi, and Lenticulina; transgressive sandstones associated with a barrier-bar system in the Matagorda area; and transgressive sandstones below Amphistegina B shale. Particularly productive gas-prone plays are progradational Siphonia davisi, shelf-margin deltas in the High Island area, and progradational Marginulina shelf and deltaic sands in association with large rollover anticlines in the Matagorda Island and Brazos areas.« less

CO{sub 2} Injectivity, Storage Capacity, Plume Size, and Reservoir and Seal Integrity of the Ordovician St. Peter Sandstone and the Cambrian Potosi Formation in the Illnois Basin

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

Leetaru, Hannes; Brown, Alan; Lee, Donald

2012-05-01

The Cambro-Ordovician strata of the Illinois and Michigan Basins underlie most of the states of Illinois, Indiana, Kentucky, and Michigan. This interval also extends through much of the Midwest of the United States and, for some areas, may be the only available target for geological sequestration of CO{sub 2}. We evaluated the Cambro-Ordovician strata above the basal Mt. Simon Sandstone reservoir for sequestration potential. The two targets were the Cambrian carbonate intervals in the Knox and the Ordovician St. Peter Sandstone. The evaluation of these two formations was accomplished using wireline data, core data, pressure data, and seismic data frommore » the USDOE-funded Illinois Basin Decatur Project being conducted by the Midwest Geological Sequestration Consortium in Macon County, Illinois. Interpretations were completed using log analysis software, a reservoir flow simulator, and a finite element solver that determines rock stress and strain changes resulting from the pressure increase associated with CO{sub 2} injection. Results of this research suggest that both the St. Peter Sandstone and the Potosi Dolomite (a formation of the Knox) reservoirs may be capable of storing up to 2 million tonnes of CO{sub 2} per year for a 20-year period. Reservoir simulation results for the St. Peter indicate good injectivity and a relatively small CO{sub 2} plume. While a single St. Peter well is not likely to achieve the targeted injection rate of 2 million tonnes/year, results of this study indicate that development with three or four appropriately spaced wells may be sufficient. Reservoir simulation of the Potosi suggest that much of the CO{sub 2} flows into and through relatively thin, high permeability intervals, resulting in a large plume diameter compared with the St. Peter.« less

Depositional environment of downdip Yegua (Eocene) sandstones, Jackson County, Texas

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

Whitten, C.J.; Berg, R.R.

Yegua sandstones at a depth of 8300-8580 ft (2530-2615 m) were partly cored in the Arco Jansky 1 dry hole. Total thickness of the sandstone section is approximately 240 ft (73 m). The sandstones are enclosed in thick marine shales and are about 20 mi (32 km) downdip from thicker and more abundant sandstones in the Yegua Formation. The section is similar to reservoirs recently discovered in the area at the Toro Grande (1984), Lost Bridge (1984), and El Torito (1985) fields. The sandstones are fine to very fine grained and occur in thin beds that are 0.5-9 ft (0.15-2.7more » m) thick. Sedimentary structures within the beds range from a lower massive division to a laminated or rippled upper division. Grain size within beds fines upward from 0.18 mm at the base to 0.05 mm at the top. The sandstones are interpreted to be turbidites of the AB type that were deposited within channels. The sandstones contain an average of 50% quartz and are classified as volcanic-arenites to feldspathic litharenites. Carbonate cement ranges from 0 to 27%. Average porosity is 29% and permeabilities are in the range of 60-1600 md in the clean sandstones. Much of the porosity is secondary and is the result of the dissolution of cements, volcanic rock fragments, and feldspar grains. Yegua sandstones produce gas and condensate at nearby Toro Grande field on a gentle, faulted anticline. The local trend of reservoir sandstones may be controlled in part by faulting that was contemporaneous with deposition.« less

Diagenetic history of the Surma Group sandstones (Miocene) in the Surma Basin, Bangladesh

NASA Astrophysics Data System (ADS)

Rahman, M. Julleh Jalalur; McCann, Tom

2012-02-01

This study examines the various diagenetic controls of the Miocene Surma Group sandstones encountered in petroleum exploration wells from the Surma Basin, which is situated in the northeastern part of the Bengal Basin, Bangladesh. The principal diagenetic minerals/cements in the Surma Group sandstones are Fe-carbonates (with Fe-calcite dominating), quartz overgrowths and authigenic clays (predominantly chlorite, illite-smectite and minor kaolin). The isotopic composition of the carbonate cement revealed a narrow range of δ 18O values (-10.3‰ to -12.4‰) and a wide range of δ 13C value (+1.4‰ to -23.1‰). The δ 13C VPDB and δ 18O VPDB values of the carbonate cements reveal that carbon was most likely derived from the thermal maturation of organic matter during burial, as well as from the dissolution of isolated carbonate clasts and precipitated from mixed marine-meteoric pore waters. The relationship between the intergranular volume (IGV) versus cement volume indicates that compaction played a more significant role than cementation in destroying the primary porosity. However, cementation also played a major role in drastically reducing porosity and permeability in sandstones with poikilotopic, pore-filling blocky cements formed in early to intermediate and deep burial areas. In addition to Fe-carbonate cements, various clay minerals including illite-smectite and chlorite occur as pore-filling and pore-lining authigenic phases. Significant secondary porosity has been generated at depths from 2500 m to 4728 m. The best reservoir rocks found at depths of 2500-3300 m are well sorted, relatively coarse grained; more loosely packed and better rounded sandstones having good porosities (20-30%) and high permeabilities (12-6000 mD). These good quality reservoir rocks are, however, not uniformly distributed and can be considered to be compartmentalized as a result of interbedding with sandstone layers of low to moderate porosities, low permeabilities owing to poor

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

Micro-mechanics of hydro-mechanical coupled processes during hydraulic fracturing in sandstone

NASA Astrophysics Data System (ADS)

Caulk, R.; Tomac, I.

2017-12-01

This contribution presents micro-mechanical study of hydraulic fracture initiation and propagation in sandstone. The Discrete Element Method (DEM) Yade software is used as a tool to model fully coupled hydro-mechanical behavior of the saturated sandstone under pressures typical for deep geo-reservoirs. Heterogeneity of sandstone strength tensile and shear parameters are introduced using statistical representation of cathodoluminiscence (CL) sandstone rock images. Weibull distribution of statistical parameter values was determined as a best match of the CL scans of sandstone grains and cement between grains. Results of hydraulic fracturing stimulation from the well bore indicate significant difference between models with the bond strengths informed from CL scans and uniform homogeneous representation of sandstone parameters. Micro-mechanical insight reveals formed hydraulic fracture typical for mode I or tensile cracking in both cases. However, the shear micro-cracks are abundant in the CL informed model while they are absent in the standard model with uniform strength distribution. Most of the mode II cracks, or shear micro-cracks, are not part of the main hydraulic fracture and occur in the near-tip and near-fracture areas. The position and occurrence of the shear micro-cracks is characterized as secondary effect which dissipates the hydraulic fracturing energy. Additionally, the shear micro-crack locations qualitatively resemble acoustic emission cloud of shear cracks frequently observed in hydraulic fracturing, and sometimes interpreted as re-activation of existing fractures. Clearly, our model does not contain pre-existing cracks and has continuous nature prior to fracturing. This observation is novel and interesting and is quantified in the paper. The shear particle contact forces field reveals significant relaxation compared to the model with uniform strength distribution.

What's shaking?: Understanding creep and induced seismicity in depleting sandstone reservoirs

NASA Astrophysics Data System (ADS)

Hangx, Suzanne; Spiers, Christopher

2015-04-01

Subsurface exploitation of the Earth's natural resources, such as oil, gas and groundwater, removes the natural system from its chemical and physical equilibrium. With global energy and water demand increasing rapidly, while availability diminishes, densely populated areas are becoming increasingly targeted for exploitation. Indeed, the impact of our geo-resources needs on the environment has already become noticeable. Deep groundwater pumping has led to significant surface subsidence in urban areas such as Venice and Bangkok. Hydrocarbons production has also led to subsidence and seismicity in offshore (e.g. Ekofisk, Norway) and onshore hydrocarbon fields (e.g. Groningen, the Netherlands). Fluid extraction inevitably leads to (poro)elastic compaction of reservoirs, hence subsidence and occasional fault reactivation. However, such effects often exceed what is expected from purely elastic reservoir behaviour and may continue long after exploitation has ceased or show other time-lag effects in relation to changes in production rates. One of the main hypotheses advanced to explain this is time-dependent compaction, or 'creep deformation', of such reservoirs, driven by the reduction in pore fluid pressure compared with the vertical rock overburden pressure. The operative deformation mechanisms may include grain-scale brittle fracturing and thermally-activated mass transfer processes (e.g. pressure solution). Unfortunately, these mechanisms are poorly known and poorly quantified. As a first step to better describe creep in sedimentary granular aggregates, we have derived a universal, simple model for intergranular pressure solution (IPS) within an ordered pack of spherical grains. This universal model is able to predict the conditions under which each of the respective pressure solution serial processes, i.e. diffusion, precipitation or dissolution, is dominant. In essence, this creates a generic deformation mechanism map for IPS in any granular material. We have used

Fractures and stresses in Bone Spring sandstones

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

Warpinski, N.R.; Sattler, A.R.; Lorenz, J.C.

This project was a collaboration between Sandia National Laboratories and the Harvey E. Yates Company (Heyco), Roswell, NM, conducted under the auspices of Department of Energy's Oil Recovery Technology Partnership. The project applied Sandia perspectives on the effects of natural fractures, stress, and sedimentology for the stimulation and production of low permeability gas reservoirs to low permeability oil reservoirs, such as those typified by the Bone Spring sandstones of the Delaware Basin, southeast New Mexico. This report details the results and analyses obtained in 1990 from core, logs, stress, and other data taken from three additional development wells. An overallmore » summary gives results from all five wells studied in this project in 1989--1990. Most of the results presented are believed to be new information for the Bone Spring sandstones.« less

Revitalizing a mature oil play: Strategies for finding and producing oil in Frio Fluvial-Deltaic Sandstone reservoirs of South Texas

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

Knox, P.R.; Holtz, M.H.; McRae, L.E.

Domestic fluvial-dominated deltaic (FDD) reservoirs contain more than 30 Billion barrels (Bbbl) of remaining oil, more than any other type of reservoir, approximately one-third of which is in danger of permanent loss through premature field abandonments. The U.S. Department of Energy has placed its highest priority on increasing near-term recovery from FDD reservoirs in order to prevent abandonment of this important strategic resource. To aid in this effort, the Bureau of Economic Geology, The University of Texas at Austin, began a 46-month project in October, 1992, to develop and demonstrate advanced methods of reservoir characterization that would more accurately locatemore » remaining volumes of mobile oil that could then be recovered by recompleting existing wells or drilling geologically targeted infill. wells. Reservoirs in two fields within the Frio Fluvial-Deltaic Sandstone (Vicksburg Fault Zone) oil play of South Texas, a mature play which still contains 1.6 Bbbl of mobile oil after producing 1 Bbbl over four decades, were selected as laboratories for developing and testing reservoir characterization techniques. Advanced methods in geology, geophysics, petrophysics, and engineering were integrated to (1) identify probable reservoir architecture and heterogeneity, (2) determine past fluid-flow history, (3) integrate fluid-flow history with reservoir architecture to identify untapped, incompletely drained, and new pool compartments, and (4) identify specific opportunities for near-term reserve growth. To facilitate the success of operators in applying these methods in the Frio play, geologic and reservoir engineering characteristics of all major reservoirs in the play were documented and statistically analyzed. A quantitative quick-look methodology was developed to prioritize reservoirs in terms of reserve-growth potential.« less

Influence of depositional environment on diagenesis in St. Peter sandstone, Michigan basin

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

Lundgren, C.E. Jr.; Barnes, D.A.

1989-03-01

The Middle Ordovician St. Peter Sandstone in the Michigan basin was deposited in marine peritidal to storm-dominated, outer shelf depositional environments that evolved in a regionally significant transgressive pattern. The formation is bounded by carbonate and shaly clastic strata of the Prairie du Chien Group below and is transitional to condensed sequence clastics and carbonates of the Glenwood Formation above. Sedimentologic and petrographic analysis of conventional core from 25 wells suggests that reservoir quality in the formation is strongly dependent on a complex diagenetic history, especially the nature and subsequent dissolution of intergranular carbonate in the sandstone. Petrographic evidence indicatesmore » that porosity in the formation formed by dissolution of precursor dolomite of various origins and, locally, the formation of pore-filling authigenic clay (chlorite-illite). Authigenic clay is the incongruent dissolution product of dolomite, detrital K-feldspar, and, possibly, muscovite and results in diminished reservoir quality where abundant in the St. Peter Sandstone. Authigenic clay is volumetrically more significant in the upper portions of the formation and is associated with higher concentrations of detrital K-feldspar. Depositional facies controlled the distribution and types of intergranular carbonate (now dolomite) and detrital K-feldspar in the St. Peter Sandstone and hence reservoir quality; both components were more significant in storm-shelf sandstone facies.« less

Integrated interpretation of C-8 and G-61 sandstones at Badak and Nilam fields in Sanga-Sanga block of east Kalimantan, Indonesia

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

Ade, W.C.; Suwarlan, W.

1989-03-01

Huffco's Badak and Nilam fields are giant gas fields that together currently produce more than 1.0 bcf of gas per day from sandstones within the Miocene Balikpapan beds. The reservoir sandstones were deposited within a thick regressive deltaic sequence that includes coals, shales, and occasional limestones. Wells typically encounter multiple stacked pay sandstones at depths ranging from about 5500 ft to more than 13,000 ft. Individual sandstone thicknesses can vary from several feet to more than 20 ft. Abrupt lateral stratigraphic variations in sandstone thickness are the rule rather than the exception. Sandstone reservoir interpretations are based on an integratedmore » approach by incorporating the study of well logs, cores, seismic sections, normal moveout-corrected gathers, amplitude variations with offset (AVO) graphs, and pressure and reservoir performance data.« less

Outcrop analogue study of Permocarboniferous geothermal sandstone reservoir formations (northern Upper Rhine Graben, Germany): impact of mineral content, depositional environment and diagenesis on petrophysical properties

NASA Astrophysics Data System (ADS)

Aretz, Achim; Bär, Kristian; Götz, Annette E.; Sass, Ingo

2016-07-01

oil and acidic waters led to the dissolution of haematite cements in the lower Permocarboniferous formations. During the Eocene, subsidence of the Upper Rhine Graben porosities and permeabilities of the sandstones of these formations were strongly reduced to 2.5 % and 3.2 × 10-18 m2. The second important influence on reservoir quality is the distinct depositional environment and its influence on early diagenetic processes. In early stage diagenesis, the best influence on reservoir properties exhibits a haematite cementation. It typically occurs in eolian sandstones of the Kreuznach Formation (Upper Permocarboniferous) and is characterized by grain covering haematite coatings, which are interpreted to inhibit cementation, compaction and illitization of pore space during burial. Eolian sandstones taken from outcrops and reservoir depths exhibit the highest porosities (16.4; 12.3 %) and permeabilities (2.0 × 10-15; 8.4 × 10-16 m2). A third important influence on reservoir quality is the general mineral composition and the quartz content which is the highest in the Kreuznach Formation with 73.8 %. Based on the integrated study of depositional environments and diagenetic processes, reservoir properties of the different Permocarboniferous formations within the northern Upper Rhine Graben and their changes with burial depth can be predicted with satisfactory accuracy. This leads to a better understanding of the reservoir quality and enables an appropriate well design for exploration and exploitation of these geothermal resources.

Reservoir performance of Late Eocene incised valley fills, Cusiana Field, Llanos Foothills, Eastern Colombia

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

Pulham, A.; Edward, W.; App, J.

1996-12-31

The Cusiana Field is located in the Llanos Foothills of Eastern Colombia. The principal reservoir is the late Eocene Mirador Formation which comprises >50% of reserves. Currently the Mirador reservoir is providing nearly all of the 150,00bopd of production from the Cusiana Field. The Mirador reservoir comprises a stack of incised valley deposits. The fills of the valleys are dominated by quartz arenite sandstones. The average porosity of the valley sandstones is 8% which reflects abundant quartz cement ({approximately}14%) and significant compaction during deep burial ({approximately}20,000feet). Single valleys are up to 70 feet thick and exhibit a distinctive bipartite fillmore » that reflects changing energy conditions during filling. Bases of valleys have the coarsest grain size and have sedimentological and trace fossil evidence for deposition in highly stressed, brackish water environments. The upper parts of the valleys are typically finer grained and were deposited in more saline settings. Despite the low porosity of the Mirador valleys, drill stem tests and production log data show that they have phenomenal performance characteristics. Rates of {ge}10,000bopd are achieved from single valleys. Bases of the valley fills are the key contributors to flow. Integration of detailed core and pore system analysis with the reservoir performance data shows that the permeability fabric of the Mirador can be explained by original depositional architecture and simple loss of primary porosity. Comparison of Cusiana with other quartz-rich sandstones from around the world suggests that it`s low porosity/high performance is predictable.« less

Assessment of undiscovered oil and gas resources in sandstone reservoirs of the Cotton Valley Group, U.S. Gulf Coast, 2015

USGS Publications Warehouse

Eoff, Jennifer D.; Biewick, Laura R.H.; Brownfield, Michael E.; Burke, Lauri; Charpentier, Ronald R.; Dubiel, Russell F.; Gaswirth, Stephanie B.; Gianoutsos, Nicholas J.; Kinney, Scott A.; Klett, Timothy R.; Leathers, Heidi M.; Mercier, Tracey J.; Paxton, Stanley T.; Pearson, Ofori N.; Pitman, Janet K.; Schenk, Christopher J.; Tennyson, Marilyn E.; Whidden, Katherine J.

2015-08-11

Using a geology-based assessment methodology, the U.S. Geological Survey estimated undiscovered mean volumes of 14 million barrels of conventional oil, 430 billion cubic feet of conventional gas, 34,028 billion cubic feet of continuous gas, and a mean total of 391 million barrels of natural gas liquids in sandstone reservoirs of the Upper Jurassic–Lower Cretaceous Cotton Valley Group in onshore lands and State waters of the U.S. Gulf Coast region.

Middle Micoene sandstone reservoirs of the Penal/Barrackpore field

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

Dyer, B.L.

1991-03-01

The Penal/Barrackpore field was discovered in 1938 and is located in the southern subbasin of onshore Trinidad. The accumulation is one of a series of northeast-southwest trending en echelon middle Miocene anticlinal structures that was later accentuated by late Pliocene transpressional folding. Relative movement of the South American and Caribbean plates climaxed in the middle Miocene compressive tectonic event and produced an imbricate pattern of southward-facing basement-involved thrusts. Further compressive interaction between the plates in the late Pliocene produced a transpressive tectonic episode forming northwest-southeast oriented transcurrent faults, tear faults, basement thrust faults, lystric normal faults, and detached simple foldsmore » with infrequent diapiric cores. The middle Miocene Herrera and Karamat turbiditic sandstones are the primary reservoir rock in the subsurface anticline of the Penal/Barrackpore field. These turbidites were sourced from the north and deposited within the marls and clays of the Cipero Formation. Miocene and Pliocene deltaics and turbidites succeed the Cipero Formation vertically, lapping into preexisting Miocene highs. The late Pliocene transpression also coincides with the onset of oil migration along faults, diapirs, and unconformities from the Cretaceous Naparima Hill source. The Lengua Formation and the upper Forest clays are considered effective seals. Hydrocarbon trapping is structurally and stratigraphically controlled, with structure being the dominant trapping mechanism. Ultimate recoverable reserves for the field are estimated at 127.9 MMBo and 628.8 bcf. The field is presently owned and operated by the Trinidad and Tobago Oil Company Limited (TRINTOC).« less

Deep-water facies and petrography of the Galoc clastic unit, offshore Palawan, Philippines (south China Sea)

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

Link, M.H.; Helmold, K.P.

1988-02-01

The lower Miocene Galoc clastic unit, offshore Palawan, Philippines, is about 500-600 ft thick. The unit overlies the Galoc Limestone and is overlain by the Pelitic Pagasa Formation. The Galoc clastic unit consists of alternating quartzose sandstone, mudstone, and resedimented carbonate deposited at bathyal depths, mainly as turbidites. The deep-water deposits are confined to the axis of a northeast-trending trough in which slope, submarine channel, interchannel, depositional lobe, slump, and basinal facies are recognized. Eroded shallow-marine carbonate lithoclasts are commonly incorporated within the siliciclastic turbidites. The main reservoir sandstones occur in submarine channels and depositional lobes. The sandstones are texturallymore » submature, very fine to medium-grained feldspathic litharenites and subarkoses. The sandstones have detrital modes of Q78:F11:L11 and Qm51:F11:Lt38, with partial modes of the monocrystalline components of Qm82:P13:K5. Lithic fragments include chert, shale, schist, volcanic rock fragments, and minor plutonic rock fragments. Porosity in the better reservoir sandstones ranges from 11 to 25%, and calcite is the dominant cement. Dissolution textures and inhomogeneity of calcite distribution suggest that at least half of the porosity in the sandstones has formed through the leaching of calcite cement and labile framework grains. A source terrain of quartzo-feldspathic sediments and metasediments, chert, volcanics, and acid-intermediate plutonic rocks is visualized.« less

Mineral-microbial interaction in long term experiments with sandstones and reservoir fluids exposed to CO2

NASA Astrophysics Data System (ADS)

Kasina, Monika; Morozova, Daria; Pellizzari, Linda; Würdemann, Hilke

2013-04-01

Microorganisms represent very effective geochemical catalysts, and may influence the process of the CO2 storage significantly. The goal of this study is to characterize the interactions between minerals and microorganisms during their exposure to the CO2 in a long term experiment in high pressure vessels to better understand the influence of biological processes on the composition of the reservoir sandstones and the long term stability of CO2 storage. The natural gas reservoir, proposed for the CO2 storage is characterized by high salinity (up to 420 g/l) and temperatures around 130°C, at depth of approximately 3.5 km. Microbial community of the reservoir fluid samples was dominated by different H2-oxidising, thiosulfate-oxidising and biocorrosive thermophilic bacteria as well as microorganisms similar to representatives from other deep environments, which have not previously been cultivated. The cells were attached to particles and were difficult to detect because of low cell numbers (Morozova et al., 2011). For the long term experiments, the autoclaved rock core samples from the core deposit were grinded, milled to the size of 0.5 mm and incubated with fresh reservoir fluids as inoculum for indigenous microorganisms in a N2/CH4/H2-atmosphere in high pressure vessels at a temperature of 80°C and pressure of 40 bars. Incubation was performed under lower temperature than in situ in order to favor the growth of the dormant microorganisms. After three months of incubation samples were exposed to high CO2 concentrations by insufflating it into the vessels. The sampling of rock and fluid material was executed 10 and 21 months after start of the experiment. Mineralogical analyses performed using XRD and SEM - EDS showed that main mineral components are quartz, feldspars, dolomite, anhydrite and calcite. Chemical fluid analyses using ICP-MS and ICP-OES showed that after CO2 exposure increasing Si4+ content in the fluid was noted after first sampling (ca. 25 relative

Implications of a reservoir model for the evolution of deep carbon

NASA Astrophysics Data System (ADS)

Kellogg, L. H.; Weisfeiler, M.; Turcotte, D. L.

2016-12-01

We consider a reservoir model for the evolution of carbon in Earth's deep interior. We begin with the assumption that the mantle reservoir that interacts with the surface is well mixed. We hypothesize that the loss of carbon from the mantle reservoir occurs primarily at mid-ocean ridges and we take the flux of carbon to be 36 ± 24 GtC yr-1 (Dasgupta and Hirschmann, 2010). We infer that the mass concentration of carbon is 5.3 ± 1.8 × 10-5. Assuming that the mass of the mantle reservoir is 4.043×1024 kg, the mass of carbon in that reservoir is 2.1±0.7×108 GtC. We further hypothesize that the addition of carbon to the mantle reservoir occurs primarily at subduction zones and take the flux of carbon to be 36 ± 12 GtC yr-1 (Dasgupta and Hirschmann, 2010). Thus within estimated uncertainties there is a steady state balance between the fluxes into and out of the mantle reservoir. A basic question is where this carbon came from. The present mass of carbon in the atmosphere of Venus is 1.28 × 108 GtC, which scales to be equivalent to 1.57 × 108 GtC in the Earth's atmosphere. This is much greater than the current mass of cabron in Earth's atmosphere but is close to the mass of carbon in the mantle reservoir given above. One explanation for the loss of carbon from Earth's atmosphere to its mantle has been given by Sleep and Zahnle (2001), who suggest that after the moon-forming giant impact at about 4.4 Ga, the carbon in the Earth's atmosphere was transferred into the mantle reservoir. We further suggest that the volcanic flux of carbon out of the mantle was responsible for the carbon concentrations in the surficial reservoirs today. In this scenario, carbon accumulated in the deep ocean until the carbon flux into the mantle due to subduction balanced the carbon flux out of the mantle due to volcanism.

Petrophysics of Lower Silurian sandstones and integration with the tectonic-stratigraphic framework, Appalachian basin, United States

USGS Publications Warehouse

Castle, J.W.; Byrnes, A.P.

2005-01-01

Petrophysical properties were determined for six facies in Lower Silurian sandstones of the Appalachian basin: fluvial, estuarine, upper shoreface, lower shoreface, tidal channel, and tidal flat. Fluvial sandstones have the highest permeability for a given porosity and exhibit a wide range of porosity (2-18%) and permeability (0.002-450 md). With a transition-zone thickness of only 1-6 m (3-20 ft), fluvial sandstones with permeability greater than 5 md have irreducible water saturation (Siw) less than 20%, typical of many gas reservoirs. Upper shoreface sandstones exhibit good reservoir properties with high porosity (10-21%), high permeability (3-250 md), and low S iw (<20%). Lower shoreface sandstones, which are finer grained, have lower porosity (4-12%), lower permeability (0.0007-4 md), thicker transition zones (6-180 m [20-600 ft]), and higher S iw. In the tidal-channel, tidal-flat, and estuarine facies, low porosity (average < 6%), low permeability (average < 0.02 md), and small pore throats result in large transition zones (30-200 m; 100-650 ft) and high water saturations. The most favorable reservoir petrophysical properties and the best estimated production from the Lower Silurian sandstones are associated with fluvial and upper shoreface facies of incised-valley fills, which we interpret to have formed predominantly in areas of structural recesses that evolved from promontories along a collisional margin during the Taconic orogeny. Although the total thickness of the sandstone may not be as great in these areas, reservoir quality is better than in adjacent structural salients, which is attributed to higher energy depositional processes and shallower maximum burial depth in the recesses than in the salients. Copyright ??2005. The American Association of Petroleum Geologists. All rights reserved.

Deep Geothermal Energy for Lower Saxony (North Germany) - Combined Investigations of Geothermal Reservoir Characteristics

NASA Astrophysics Data System (ADS)

Hahne, Barbara; Thomas, Rüdiger

2014-05-01

In Germany, successful deep geothermal projects are mainly situated in Southern Germany in the Molassebecken, furthermore in the Upper Rhine Graben and, to a minor extend, in the North German Basin. Mostly they are hydrothermal projects with the aim of heat production. In a few cases, they are also constructed for the generation of electricity. In the North German Basin temperature gradients are moderate. Therefore, deep drilling of several thousand meters is necessary to reach temperatures high enough for electricity production. However, the porosity of the sedimentary rocks is not sufficient for hydrothermal projects, so that natural fracture zones have to be used or the rocks must be hydraulically stimulated. In order to make deep geothermal projects in Lower Saxony (Northern Germany) economically more attractive, the interdisciplinary research program "Geothermal Energy and High-Performance Drilling" (gebo) was initiated in 2009. It comprises four focus areas: Geosystem, Drilling Technology, Materials and Technical System and aims at improving exploration of the geothermal reservoir, reducing costs of drilling and optimizing exploitation. Here we want to give an overview of results of the focus area "Geosystem" which investigates geological, geophysical, geochemical and modeling aspects of the geothermal reservoir. Geological and rock mechanical investigations in quarrys and core samples give a comprehensive overview on rock properties and fracture zone characteristics in sandstones and carbonates. We also show that it is possible to transfer results of rock property measurements from quarry samples to core samples or to in situ conditions by use of empirical relations. Geophysical prospecting methods were tested near the surface in a North German Graben system. We aim at transferring the results to the prospection of deep situated fracture zones. The comparison of P- and S-wave measurements shows that we can get hints on a possible fluid content of the

Daily Reservoir Inflow Forecasting using Deep Learning with Downscaled Multi-General Circulation Models (GCMs) Platform

NASA Astrophysics Data System (ADS)

Li, D.; Fang, N. Z.

2017-12-01

Dallas-Fort Worth Metroplex (DFW) has a population of over 7 million depending on many water supply reservoirs. The reservoir inflow plays a vital role in water supply decision making process and long-term strategic planning for the region. This paper demonstrates a method of utilizing deep learning algorithms and multi-general circulation model (GCM) platform to forecast reservoir inflow for three reservoirs within the DFW: Eagle Mountain Lake, Lake Benbrook and Lake Arlington. Ensemble empirical mode decomposition was firstly employed to extract the features, which were then represented by the deep belief networks (DBNs). The first 75 years of the historical data (1940 -2015) were used to train the model, while the last 2 years of the data (2016-2017) were used for the model validation. The weights of each DBN gained from the training process were then applied to establish a neural network (NN) that was able to forecast reservoir inflow. Feature predictors used for the forecasting model were generated from weather forecast results of the downscaled multi-GCM platform for the North Texas region. By comparing root mean square error (RMSE) and mean bias error (MBE) with the observed data, the authors found that the deep learning with downscaled multi-GCM platform is an effective approach in the reservoir inflow forecasting.

Numerical study of the origin and stability of chemically distinct reservoirs deep in Earth's mantle

NASA Astrophysics Data System (ADS)

van Thienen, P.; van Summeren, J.; van der Hilst, R. D.; van den Berg, A. P.; Vlaar, N. J.

Seismic tomography is providing mounting evidence for large scale compositional heterogeneity deep in Earth's mantle; also, the diverse geochemical and isotopic signatures observed in oceanic basalts suggest that the mantle is not chemically homogeneous. Isotopic studies on Archean rocks indicate that mantle inhomogeneity may have existed for most of the Earth's history. One important component may be recycled oceanic crust, residing at the base of the mantle. We investigate, by numerical modeling, if such reservoirs may have been formed in the early Earth, before plate tectonics (and subduction) were possible, and how they have survived—and evolved—since then. During Earth's early evolution, thick basaltic crust may have sunk episodically into the mantle in short but vigorous diapiric resurfacing events. These sections of crust may have resided at the base of the mantle for very long times. Entrainment of material from the enriched reservoirs thus produced may account for enriched mantle and high-μ signatures in oceanic basalts, whereas deep subduction events may have shaped and replenished deep mantle reservoirs. Our modeling shows that (1) convective instabilities and resurfacing may have produced deep enriched mantle reservoirs before the era of plate tectonics; (2) such formation is qualitatively consistent with the geochemical record, which shows multiple distinct ocean island basalt sources; and (3) reservoirs thus produced may be stable for billions of years.

The effects of steam injection in a sandstone reservoir (Etchegoin Formation), Buena Vista field, California

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

Grant, C.W.; Reed, A.A.

1991-03-01

At Buena Vista field, California, 120 ft of post-steamflood core, spanning the middle Pliocene Wilhelm Member of the Etchegoin Formation, was taken to assess the influence of stratigraphy on light-oil steamflood (LOSF) processes and to determine what steam-rock reactions occurred and how these affected reservoir properties. High-quality steam (600F (300C)) had been injected ({approximately}1,700 psi) into mixed tidal flat and estuarine facies in an injector well located 55 ft from the cored well. Over a period of 20 months, steam rapidly channeled through a thin ({approximately}7 ft), relatively permeable (1-1,000 md), flaser-bedded sandstone unit. Conductive heating above this permeable unitmore » produced, in the vicinity of the cored well, a 35-ft steam-swept zone (oil saturation = 0), overlain by a 29-ft steam-affected zone in which oil saturation had been reduced to 13%, far below the presteam saturation of 30%. Steam-induced alteration ('artificial diagenesis') of the clay-rich reservoir rock was recognized using SEM, petrography, and X-ray diffraction. Salient dissolution effects were the complete to partial removal of siliceous microfossils, Fe-dolomite, volcanic rock fragments, and labile heavy minerals. The artificial diagenetic effects are first encountered in the basal 6 ft of the 29-ft steam-affected zone. Based on the distribution of the authigenic phases, the authors conclude that the reactions took place, or were at least initiated, in the steam condensate bank ahead of the advancing steam front. Although these changes presumably reduced permeability, the steamflood process was effective in reducing oil saturation to zero in the steam-contacted portion of the reservoir.« less

Resonant Ultrasound Spectroscopy studies of Berea sandstone at high temperature

DOE PAGES

Davis, Eric S.; Sturtevant, Blake T.; Sinha, Dipen N.; ...

2016-09-04

Resonant Ultrasound Spectroscopy was used in this paper to determine the elastic moduli of Berea sandstone from room temperature to 478 K. Sandstone is a common component of oil reservoirs, and the temperature range was chosen to be representative of typical downhole conditions, down to about 8 km. In agreement with previous works, Berea sandstone was found to be relatively soft with a bulk modulus of approximately 6 GPa as compared to 37.5 GPa for α-quartz at room temperature and pressure. Finally, it was found that Berea sandstone undergoes a ~17% softening in bulk modulus between room temperature and 385more » K, followed by an abnormal behavior of similar stiffening between 385 K and 478 K.« less

Resonant Ultrasound Spectroscopy studies of Berea sandstone at high temperature

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

Davis, Eric S.; Sturtevant, Blake T.; Sinha, Dipen N.

Resonant Ultrasound Spectroscopy was used in this paper to determine the elastic moduli of Berea sandstone from room temperature to 478 K. Sandstone is a common component of oil reservoirs, and the temperature range was chosen to be representative of typical downhole conditions, down to about 8 km. In agreement with previous works, Berea sandstone was found to be relatively soft with a bulk modulus of approximately 6 GPa as compared to 37.5 GPa for α-quartz at room temperature and pressure. Finally, it was found that Berea sandstone undergoes a ~17% softening in bulk modulus between room temperature and 385more » K, followed by an abnormal behavior of similar stiffening between 385 K and 478 K.« less

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

Implications of heterogeneous fracture distribution on reservoir quality; an analogue from the Torridon Group sandstone, Moine Thrust Belt, NW Scotland

NASA Astrophysics Data System (ADS)

Watkins, Hannah; Healy, David; Bond, Clare E.; Butler, Robert W. H.

2018-03-01

Understanding fracture network variation is fundamental in characterising fractured reservoirs. Simple relationships between fractures, stress and strain are commonly assumed in fold-thrust structures, inferring relatively homogeneous fracture patterns. In reality fractures are more complex, commonly appearing as heterogeneous networks at outcrop. We use the Achnashellach Culmination (NW Scotland) as an outcrop analogue to a folded tight sandstone reservoir in a thrust belt. We present fracture data is collected from four fold-thrust structures to determine how fracture connectivity, orientation, permeability anisotropy and fill vary at different structural positions. We use a 3D model of the field area, constructed using field observations and bedding data, and geomechanically restored using Move software, to determine how factors such as fold curvature and strain influence fracture variation. Fracture patterns in the Torridon Group are consistent and predictable in high strain forelimbs, however in low strain backlimbs fracture patterns are inconsistent. Heterogeneities in fracture connectivity and orientation in low strain regions do not correspond to fluctuations in strain or fold curvature. We infer that where strain is low, other factors such as lithology have a greater control on fracture formation. Despite unpredictable fracture attributes in low strain regions, fractured reservoir quality would be highest here because fractures in high strain forelimbs are infilled with quartz. Heterogeneities in fracture attribute data on fold backlimbs mean that fractured reservoir quality and reservoir potential is difficult to predict.

Anomalies of natural gas compositions and carbon isotope ratios caused by gas diffusion - A case from the Donghe Sandstone reservoir in the Hadexun Oilfield, Tarim Basin, northwest China

NASA Astrophysics Data System (ADS)

Wang, Yangyang; Chen, Jianfa; Pang, Xiongqi; Zhang, Baoshou; Wang, Yifan; He, Liwen; Chen, Zeya; Zhang, Guoqiang

2018-05-01

Natural gases in the Carboniferous Donghe Sandstone reservoir within the Block HD4 of the Hadexun Oilfield, Tarim Basin are characterized by abnormally low total hydrocarbon gas contents (<65%), low methane contents (<10%) and low dryness coefficients (<0.5), and a reversal of the normal trend of carbon isotope ratios, showing δ13C methane (C1) > δ13C ethane (C2) < δ13C propane (C3) < δ13C butane (C4). Specifically, methane is enriched in 13C with the variations in δ13C1 values between gases from Block HD4 and gases from its neighboring blocks reaching 10‰. This type of abnormal gas has never been reported previously in the Tarim Basin and such large variations in δ13C have rarely been observed in other basins globally. Based on a comprehensive analysis of gas geochemical data and the geological setting of the Carboniferous reservoirs in the Hadexun Oilfield, we reveal that the anomalies of the gas compositions and carbon isotope ratios in the Donghe Sandstone reservoir are caused by gas diffusion through the poorly-sealed caprock rather than by pathways such as gas mixing, microorganism degradation, different kerogen types or thermal maturity degrees of source rocks. The documentation of an in-reservoir gas diffusion during the post entrapment process as a major cause for gas geochemical anomalies may offer important insight into exploring natural gas resources in deeply buried sedimentary basins.

Fractures and stresses in Bone Spring sandstones. Final report

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

Warpinski, N.R.; Sattler, A.R.; Lorenz, J.C.

This project was a collaboration between Sandia National Laboratories and the Harvey E. Yates Company (Heyco), Roswell, NM, conducted under the auspices of Department of Energy`s Oil Recovery Technology Partnership. The project applied Sandia perspectives on the effects of natural fractures, stress, and sedimentology for the stimulation and production of low permeability gas reservoirs to low permeability oil reservoirs, such as those typified by the Bone Spring sandstones of the Delaware Basin, southeast New Mexico. This report details the results and analyses obtained in 1990 from core, logs, stress, and other data taken from three additional development wells. An overallmore » summary gives results from all five wells studied in this project in 1989--1990. Most of the results presented are believed to be new information for the Bone Spring sandstones.« less

Petrographic and reservoir features of Hauterivian (Lower Cretaceous) Shatlyk horizon in the Malay gas field, Amu-Darya basin, east Turkmenia

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

Naz, H.; Ersan, A.

1996-08-01

Malay gas field in Amu-Darya basin, eastern Turkmenia, is located on the structural high that is on the Malay-Bagadzha arch north of the Repetek-Kelif structure zone. With 500 km{sup 2} areal coverage, 16 producing wells and 200 billion m{sup 3} estimated reserves, the field was discovered in 1978 and production began in 1987 from 2400-m-deep Hauterivian-age (Early Cretaceous) Shatlyk horizon. The Shatlyk elastic sequence shows various thickness up to 100 m in the Malay structural closure and is studied through E-log, core, petrographic data and reservoir characteristics. The Shatlyk consists of poorly indurated, reddish-brown and gray sandstones, and sandy graymore » shales. The overall sand-shale ratio increases up and the shales interleave between the sand packages. The reservoir sandstones are very fine to medium grained, moderately sorted, compositionally immature, subarkosic arenites. The framework grains include quartz, feldspar and volcanic lithic fragments. Quartz grains are monocrystalline in type and most are volcanic in origin. Feldspars consist of K- Feldspar and plagioclase. The orthoclases are affected by preferential alteration. The sandstones show high primary intergranular porosity and variations in permeability. Patch-like evaporate cement and the iron-rich grain coatings are reducing effects in permeability. The coats are pervasive in reddish-brown sandstones but are not observed in the gray sandstones. The evaporate cement is present in all the sandstone samples examined and, in places, follows the oxidation coats. The petrographic evidences and the regional facies studies suggest the deposition in intersection area from continental to marine nearshore deltaic environment.« less

Geologic framework for the assessment of undiscovered oil and gas resources in sandstone reservoirs of the Upper Jurassic-Lower Cretaceous Cotton Valley Group, U.S. Gulf of Mexico region

USGS Publications Warehouse

Eoff, Jennifer D.; Dubiel, Russell F.; Pearson, Ofori N.; Whidden, Katherine J.

2015-01-01

The Cotton Valley Group extends in the subsurface from southern Texas to the Florida Panhandle in an arcuate belt that crosses northern Louisiana, the southern part of Arkansas, and southern Mississippi and Alabama. Three of the AUs are quantitatively assessed for undiscovered volumes of hydrocarbons in conventional accumulations. The Cotton Valley Updip Oil AU includes areas between the maximum updip limit of the Cotton Valley Group and a curved belt of regional faults (included in the Peripheral Fault System AU). Hydrocarbon charge to this AU remains uncertain. The Peripheral Fault System Oil and Gas AU includes the Mexia, Talco, State Line, South Arkansas, Pickens, Gilbertown, and other fault segments, which trapped early oil that migrated from source rocks within the Smackover Formation. Hydrocarbons in the Downdip Oil and Gas AU are primarily associated with low-amplitude salt-related features in the East Texas, North Louisiana, and Mississippi salt basins. The Tight Sandstone Gas AU contains gas-charged sandstones previously referred to collectively as “massive.” Their reservoir properties are consistent with the USGS’s definition of continuous reservoirs, and their resources, therefore, are assessed using a separate methodology. Optimal coincidence of low-permeability sandstone, gas-mature source rocks, and complex structures of the regional Sabine feature encouraged development of a general “sweet spot” area in eastern Texas.

Noble gas as tracers for CO2 deep input in petroleum reservoirs

NASA Astrophysics Data System (ADS)

Pujol, Magali; Stuart, Finlay; Gilfillan, Stuart; Montel, François; Masini, Emmanuel

2016-04-01

The sub-salt hydrocarbon reservoirs in the deep offshore part of the Atlantic Ocean passive margins are a new key target for frontier oil and gas exploration. Type I source rocks locally rich in TOC (Total Organic Carbon) combined with an important secondary connected porosity of carbonate reservoirs overlain by an impermeable salt layer gives rise to reservoirs with high petroleum potential. However, some target structures have been found to be mainly filled with CO2 rich fluids. δ13C of the CO2 is generally between -9 and -4 permil, compatible with a deep source (metamorphic or mantle). Understanding the origin of the CO2 and the relative timing of its input into reservoir layers in regard to the geodynamic context appears to be a key issue for CO2 risk evaluation. The inertness and ubiquity of noble gases in crustal fluids make them powerful tools to trace the origin and migration of mixed fluids (Ballentine and Burnard 2002). The isotopic signature of He, Ne and Ar and the elemental pattern (He to Xe) of reservoir fluid from pressurized bottom hole samples provide an insight into fluid source influences at each reservoir depth. Three main end-members can be mixed into reservoir fluids (e.g. Gilfillan et al., 2008): atmospheric signature due to aquifer recharge, radiogenic component from organic fluid ± metamorphic influence, and mantle input. Their relative fractionation provides insights into the nature of fluid transport (Burnard et al., 2012)and its relative migration timing. In the studied offshore passive margin reservoirs, from both sides of South Atlantic margin, a strong MORB-like magmatic CO2 influence is clear. Hence, CO2 charge must have occurred during or after lithospheric break-up. CO2 charge(s) history appears to be complex, and in some cases requires several inputs to generate the observed noble gas pattern. Combining the knowledge obtained from noble gas (origin, relative timing, number of charges) with organic geochemical and thermodynamic

Structural-Diagenetic Controls on Fracture Opening in Tight Gas Sandstone Reservoirs, Alberta Foothills

NASA Astrophysics Data System (ADS)

Ukar, Estibalitz; Eichhubl, Peter; Fall, Andras; Hooker, John

2013-04-01

progressively decreases from the faulted cores of mesoscopic folds to their forelimbs, with lowest intensities within relatively undeformed backlimb strata. Fracture apertures locally increase adjacent to reverse faults without an overall increase in fracture frequency. Fluid inclusion analyses of crack-seal quartz cement indicate both aqueous and methane-rich inclusions are present. Homogenization temperatures of two-phase inclusions indicate synkinematic fracture cement precipitation and fracture opening under conditions at or near maximum burial of 190-210°C in core samples, and 120-160°C in outcrop samples. In comparison with the fracture evolution in other, less deformed tight-gas sandstone reservoirs such as the Piceance and East Texas basins where fracture opening is primarily controlled by gas generation, gas charge, and pore fluid pressure, these results suggest a strong control of regional tectonic processes on fracture generation. In conjunction with timing and rate of gas charge, rates of fracture cement growth, and stratigraphic-lithological controls, these processes determine the overall distribution of open fractures in these reservoirs.

Structural-Diagenetic Controls on Fracture Opening in Tight Gas Sandstone Reservoirs, Alberta Foothills

NASA Astrophysics Data System (ADS)

Ukar, E.; Eichhubl, P.; Fall, A.; Hooker, J. N.

2012-12-01

progressively decreases from the faulted cores of mesoscopic folds to their forelimbs, with lowest intensities within relatively undeformed backlimb strata. Fracture apertures locally increase adjacent to reverse faults without an overall increase in fracture frequency. Fluid inclusion analyses of crack-seal quartz cement indicate both aqueous and methane-rich inclusions are present. Homogenization temperatures of two-phase inclusions indicate synkinematic fracture cement precipitation and fracture opening under conditions at or near maximum burial of 190-210°C in core samples, and 120-160°C in outcrop samples. In comparison with the fracture evolution in other, less deformed tight-gas sandstone reservoirs such as the Piceance and East Texas basins where fracture opening is primarily controlled by gas generation, gas charge, and pore fluid pressure, these results suggest a strong control of regional tectonic processes on fracture generation. In conjunction with timing and rate of gas charge, rates of fracture cement growth, and stratigraphic-lithological controls, these processes determine the overall distribution of open fractures in these reservoirs.

Shallow, low-permeability reservoirs of northern Great Plains - assessment of their natural gas resources.

USGS Publications Warehouse

Rice, D.D.; Shurr, G.W.

1980-01-01

Major resources of natural gas are entrapped in low-permeability, low-pressure reservoirs at depths less than 1200m in the N.Great Plains. This shallow gas is the product of the immature stage of hydrocarbon generation and is referred to as biogenic gas. Prospective low-permeability, gas-bearing reservoirs range in age from late Early to Late Cretaceous. The following facies were identified and mapped: nonmarine rocks, coastal sandstones, shelf sandstones, siltstones, shales, and chalks. The most promising low-permeability reservoirs are developed in the shelf sandstone, siltstone, and chalk facies. Reservoirs within these facies are particularly attractive because they are enveloped by thick sequences of shale which serve as both a source and a seal for the gas.-from Author

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

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

Assessment of potential shale oil and tight sandstone gas resources of the Assam, Bombay, Cauvery, and Krishna-Godavari Provinces, India, 2013

USGS Publications Warehouse

Klett, Timothy R.; Schenk, Christopher J.; Wandrey, Craig J.; Brownfield, Michael E.; Charpentier, Ronald R.; Tennyson, Marilyn E.; Gautier, Donald L.

2014-01-01

Using a well performance-based geologic assessment methodology, the U.S. Geological Survey estimated a technically recoverable mean volume of 62 million barrels of oil in shale oil reservoirs, and more than 3,700 billion cubic feet of gas in tight sandstone gas reservoirs in the Bombay and Krishna-Godavari Provinces of India. The term “provinces” refer to geologically defined units assessed by the USGS for the purposes of this report and carries no political or diplomatic connotation. Shale oil and tight sandstone gas reservoirs were evaluated in the Assam and Cauvery Provinces, but these reservoirs were not quantitatively assessed.

Improved reservoir characterisation using fuzzy logic platform: an integrated petrophysical, seismic structural and poststack inversion study

NASA Astrophysics Data System (ADS)

Jafri, Muhammad Kamran; Lashin, Aref; Ibrahim, El-Khedr Hassan; Hassanein, Kamal A.; Al Arifi, Nassir; Naeem, Muhammad

2017-06-01

There is a tendency for applying different integrated geophysical approaches for better hydrocarbon reservoir characterisation and interpretation. In this study, petrophysical properties, seismic structural and poststack seismic inversion results are integrated using the fuzzy logic AND operator to characterise the Tensleep Sandstone Formation (TSF) at Powder River Basin (PRB), Wyoming, USA. TSF is deposited in a coastal plain setting during the Pennsylvanian era, and contains cross-bedded sandstone of Aeolian origin as a major lithology with alternative sabkha dolomite/carbonates. Wireline logging datasets from 17 wells are used for the detailed petrophysical evaluation. Three units of the TSF (A-sandstone, B-dolomite and B-sandstone) are targeted and their major rock properties estimated (i.e. shale/clay volume, Vsh; porosity, φEff permeability, K; fluid saturations, Sw and SH; and bulk volume water, BVW). The B-sandstone zone, with its petrophysical properties of 5-20% effective porosity, 0.10-250 mD permeability and hydrocarbon potential up to 72%, is considered the best reservoir zone among the three studied units. Distributions of the most important petrophysical parameters of the B-sandstone reservoir (Vsh, φEff, K, Sw) are generated as GIS thematic layers. The two-dimensional (2D) and three-dimensional (3D) seismic structural interpretations revealed that the hydrocarbons are entrapped in an anticlinal structure bounded with fault closures at the west of the study area. Poststack acoustic impedance (PSAI) inversion is performed on 3D seismic data to extract the inverted acoustic impedance (AI) cube. Two attribute slices (inverted AI and seismic amplitude) were extracted at the top of the B-sandstone unit as GIS thematic layers. The reservoir properties and inverted seismic attributes were then integrated using fuzzy AND operator. Finally, a fuzzy reservoir quality map was produced, and a prospective reservoir area with best reservoir characteristics is

Depositional environments and sand body morphologies of the muddy sandstones at Kitty Field, Powder River Basin, Wyoming

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

Larberg, G.M.B.

1980-01-01

Lower Cretaceous muddy sandstones form a stratigraphic trap at Kitty Field, Campbell County, Wyoming. Porosity and permeability are generally low, but the best reservoir develop maximum effective porosity of 17% and maximum permeability of 442 md. Reservoirs sandstones average less than 15 ft and rarely exceed 30 ft in thickness. Ultimate recovery from the field is estimated at 23 million bbl. Based on electric log character, 4 easily recognizable zones within the muddy interval at Kitty were numbered one through 4 in slabbed cores and petrographic analyses of selected core samples, suggest that sandstones in the second, third, and fourthmore » muddy zones were deposited as part of a sequence associated with the overall transgression of the lower Cretaceous sea. Fourth zone sandstones are fluvial in origin, and were deposited in lows on the unconformable surface of the underlying skull creek shale. 18 references.« less

Comparison of transgressive and regressive clastic reservoirs, late Albian Viking Formation, Alberta basin

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

Reinson, G.E.

1996-06-01

Detailed stratigraphic analysis of hydrocarbon reservoirs from the Basal Colorado upwards through the Viking/Bow Island and Cardium formations indicates that the distributional trends, overall size and geometry, internal heterogeneity, and hydrocarbon productivity of the sand bodies are related directly to a transgressive-regressive (T-R) sequence stratigraphic model. The Viking Formation (equivalent to the Muddy Sandstone of Wyoming) contains examples of both transgressive and regressive reservoirs. Viking reservoirs can be divided into progradational shoreface bars associated with the regressive systems tract, and bar/sheet sands and estuary/channel deposits associated with the transgressive systems tract. Shoreface bars, usually consisting of fine- to medium-grained sandstones,more » are tens of kilometers long, kilometers in width, and in the order of five to ten meters thick. Transgressive bar and sheet sandstones range from coarse-grained to conglomeratic, and occur in deposits that are tens of kilometers long, several kilometers wide, and from less than one to four meters in thickness. Estuary and valley-fill reservoir sandstones vary from fine-grained to conglomeratic, occur as isolated bodies that have channel-like geometries, and are usually greater than 10 meters thick. From an exploration viewpoint the most prospective reservoir trends in the Viking Formation are those associated with transgressive systems tracts. In particular, bounding discontinuities between T-R systems tracts are the principal sites of the most productive hydrocarbon-bearing sandstones.« less

Fluvial-deltaic sedimentation and stratigraphy of the ferron sandstone

USGS Publications Warehouse

Anderson, P.B.; Chidsey, T.C.; Ryer, T.A.

1997-01-01

East-central Utah has world-class outcrops of dominantly fluvial-deltaic Turonian to Coniacian aged strata deposited in the Cretaceous foreland basin. The Ferron Sandstone Member of the Mancos Shale records the influences of both tidal and wave energy on fluvial-dominated deltas on the western margin of the Cretaceous western interior seaway. Revisions of the stratigraphy are proposed for the Ferron Sandstone. Facies representing a variety of environments of deposition are well exposed, including delta-front, strandline, marginal marine, and coastal-plain. Some of these facies are described in detail for use in petroleum reservoir characterization and include permeability structure.

An interpretation of core and wireline logs for the Petrophysical evaluation of Upper Shallow Marine sandstone reservoirs of the Bredasdorp Basin, offshore South Africa

NASA Astrophysics Data System (ADS)

Magoba, Moses; Opuwari, Mimonitu

2017-04-01

This paper embodies a study carried out to assess the Petrophysical evaluation of upper shallow marine sandstone reservoir of 10 selected wells in the Bredasdorp basin, offshore, South Africa. The studied wells were selected randomly across the upper shallow marine formation with the purpose of conducting a regional study to assess the difference in reservoir properties across the formation. The data sets used in this study were geophysical wireline logs, Conventional core analysis and geological well completion report. The physical rock properties, for example, lithology, fluid type, and hydrocarbon bearing zone were qualitatively characterized while different parameters such as volume of clay, porosity, permeability, water saturation ,hydrocarbon saturation, storage and flow capacity were quantitatively estimated. The quantitative results were calibrated with the core data. The upper shallow marine reservoirs were penetrated at different depth ranging from shallow depth of about 2442m to 3715m. The average volume of clay, average effective porosity, average water saturation, hydrocarbon saturation and permeability range from 8.6%- 43%, 9%- 16%, 12%- 68% , 32%- 87.8% and 0.093mD -151.8mD respectively. The estimated rock properties indicate a good reservoir quality. Storage and flow capacity results presented a fair to good distribution of hydrocarbon flow.

Incorporating reservoir heterogeneity with geostatistics to investigate waterflood recoveries

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

Wolcott, D.S.; Chopra, A.K.

1993-03-01

This paper presents an investigation of infill drilling performance and reservoir continuity with geostatistics and a reservoir simulator. The geostatistical technique provides many possible realizations and realistic descriptions of reservoir heterogeneity. Correlation between recovery efficiency and thickness of individual sand subunits is shown. Additional recovery from infill drilling results from thin, discontinuous subunits. The technique may be applied to variations in continuity for other sandstone reservoirs.

Geometrical characteristics of sandstone with different sample sizes

NASA Astrophysics Data System (ADS)

Cheon, D. S.; Takahashi, M., , Dr

2017-12-01

In many rock engineering projects such as CO2 underground storage, engineering geothermal system, it is important things to understand the fluid flow behavior in the deep geological conditions. This fluid flow is generally affected by the geometrical characteristics of rock, especially porous media. Furthermore, physical properties in rock may depend on the existence of voids space in rock. Total porosity and pore size distribution can be measured by Mercury Intrusion Porosimetry and the other geometrical and spatial information of pores can be obtained through micro-focus X-ray CT. Using the micro-focus X-ray CT, we obtained the extracted void space and transparent image from the original CT voxel images of with different sample sizes like 1 mm, 2 mm, 3 mm cubes. The test samples are Berea sandstone and Otway sandstone. The former is well-known sandstone and it is used for the standard sample to compared to the result from the Otway sandstone. Otway sandstone was obtained from the CO2CRC Otway pilot site for the CO2 geosequestraion project. From the X-ray scan and ExFACT software, we get the informations including effective pore radii, coordination number, tortuosity and effective throat/pore radius ratio etc. The geometrical information analysis showed that for Berea sandstone and Otway sandstone, there is rarely differences with different sample sizes and total value of coordination number show high porosity, the tortuosity of Berea sandstone is higher than the Otway sandstone. In the future, these information will be used for the permeability of the samples.

Effects of climate events driven hydrodynamics on dissolved oxygen in a subtropical deep reservoir in Taiwan.

PubMed

Fan, Cheng-Wei; Kao, Shuh-Ji

2008-04-15

The seasonal concentrations of dissolved oxygen in a subtropical deep reservoir were studied over a period of one year. The study site was the Feitsui Reservoir in Taiwan. It is a dam-constructed reservoir with a surface area of 10.24 km(2) and a mean depth of 39.6 m, with a maximum depth of 113.5 m near the dam. It was found that certain weather and climate events, such as typhoons in summer and autumn, as well as cold fronts in winter, can deliver oxygen-rich water, and consequently have strong impacts on the dissolved oxygen level. The typhoon turbidity currents and winter density currents played important roles in supplying oxygen to the middle and bottom water, respectively. The whole process can be understood by the hydrodynamics driven by weather and climate events. This work provides the primary results of dissolved oxygen in a subtropical deep reservoir, and the knowledge is useful in understanding water quality in subtropical regions.

Red Fork and lower Skinner sandstones in northwest Tecumseh field, Pottawatomie County, Oklahoma

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

Dale, T.B.

1987-08-01

The Northwest Tecumseh field, discovered in 1978, produces from the Pennsylvanian Skinner and Red Fork sandstones at 4800 ft. The 50 wells had produced 6.4 million bbl of oil and 20.8 bcf of gas through 1986. The field is 4.5 mi long, 3/4 mi wide, and the vertical section contains up to 132 ft of sandstone with greater than 10% porosity. These stacked, interconnected north-northeast-trending, channel-fill sandstones are part of a much larger fluvial/distributary system. These channels flowed to the north and cut down into underlying, fossiliferous, carbonate-bearing marine shale. A pre-Pennsylvanian structural low, trending north-northeast, existed in the southernmore » half of the field and created a predisposition for the channel trend which continued through Red Fork and Skinner deposition. The north-northeast-trending sandstone complex, parallel with present-day regional structural strike, provides the excellent configuration for this efficient stratigraphic trap. The northern end of the field is marked by bifurcation of the channel complex and by the crosscutting of a younger clay-filled channel. Despite the lenticularity of the sandstone sequence, there appears to be a uniform gas-oil contact and minor southwestward tilt of the oil-water contact in the south part of the pool. The primary reservoir energy is provided by a dissolved gas drive, with some assistance from the 60-ft gas cap. The vertical oil column is 80 ft. These reservoir sandstones are fine-grained quartzarenites, and the dissolution of ferrodolomite has increased porosities up to 21%. Kaolinite is the predominant clay mineral and has a tendency to migrate and reduce permeability during production.« less

Is there a basin-centered gas accumulation in Cotton Valley Group Sandstones, Gulf Coast Basin, U.S.A.?

USGS Publications Warehouse

Bartberger, Charles E.; Dyman, Thaddeus S.; Condon, Steven M.

2002-01-01

The U.S. Geological Survey (USGS), in cooperation with the U.S. Department of Energy, is reevaluating the resource potential of selected domestic basin-centered gas accumulations. Basin-centered gas accumulations are characterized by presence of gas in extensive low-permeability (tight) reservoirs in which conventional seals and trapping mechanisms are absent, abnormally high or low reservoir pressures exist, and gas-water contacts are absent. In 1995, the USGS assessed one basin-centered gas play and two conventional plays within the trend of Jurassic and Cretaceous Cotton Valley Group fl uvial-deltaic and barrierisland/ strandplain sandstones across the onshore northern Gulf of Mexico Basin. Detailed evaluation of geologic and production data provides new insights into these Cotton Valley plays. Two Cotton Valley sandstone trends are identifi ed based on reservoir properties and gas-production characteristics. Transgressive blanket sandstones across northern Louisiana have relatively high porosity and permeability and do not require fracture stimulation to produce gas at commercial rates. South of this trend, and extending westward into eastern Texas, massive sandstones of the Cotton Valley trend exhibit low porosity and permeability and require fracture stimulation. The high permeability of Cotton Valley blanket sandstones is not conducive to the presence of basin-centered gas, but lowpermeability massive sandstones provide the type of reservoir in which basin-centered gas accumulations commonly occur. Data on source rocks, including burial and thermal history, are consistent with the interpretation of potential basincentered gas within Cotton Valley sandstones. However, pressure gradients throughout most of the blanket- and massivesandstone trends are normal or nearly normal, which is not characteristic of basin-centered gas accumulations. The presence of gas-water contacts in at least seven fi elds across the blanket-sandstone trend together with relatively

Architecture and sedimentology of turbidite reservoirs from Miocene Moco T and Webster zones, Midway-Sunset field, California

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

Link, M.H.; Hall, B.R.

1989-03-01

Thirty-five turbidite sandstone bodies from the Moco T and Webster reservoir zones were delineated for enhanced oil recovery projects in Mobil's MOCO FEE property, south Midway-Sunset field. The recognition of these sand bodies is based on mappable geometries determined from wireline log correlations, log character, core facies, reservoir characteristics, and comparison to nearby age-equivalent outcrops. These turbidite sands are composed of unconsolidated arkosic late Miocene sandstones (Stevens equivalent, Monterey Formation). They were deposited normal to paleoslope and trend southwest-northeast in an intraslope basin. Reservoir quality in the sandstone is very good, with average porosities of 33% and permeabilities of 1more » darcy.« less

CO2 Storage Potential of the Eocene Tay Sandstone, Central North Sea, UK

NASA Astrophysics Data System (ADS)

Gent, Christopher; Williams, John

2017-04-01

Carbon Capture and Storage (CCS) is crucial for low-carbon industry, climate mitigation and a sustainable energy future. The offshore capacity of the UK is substantial and has been estimated at 78 Gt of CO2 in saline aquifers and hydrocarbon fields. The early-mid Eocene Tay Sandstone Member of the Central North Sea (CNS) is a submarine-fan system and potential storage reservoir with a theoretical capacity of 123 Mt of CO2. The Tay Sandstone comprises of 4 sequences, amalgamating into a fan complex 125km long and 40 km at a minimum of 1500 m depth striking NW-SE, hosting several hydrocarbon fields including Gannett A, B, D and Pict. In order to better understand the storage potential and characteristics, the Tay Sandstone over Quadrant 21 has been interpreted using log correlation and 3D seismic. Understanding the internal and external geometry of the sandstone as well as the lateral extent of the unit is essential when considering CO2 vertical and horizontal fluid flow pathways and storage security. 3D seismic mapping of a clear mounded feature has revealed the youngest sequence of the Tay complex; a homogenous sand-rich channel 12 km long, 1.5 km wide and on average 100 m thick. The sandstone has porosity >35%, permeability >5 D and a net to gross of 0.8, giving a total pore volume of 927x106 m3. The remaining three sequences are a series of stacked channels and interbedded mudstones which are more quiescent on the seismic, however, well logs indicate each subsequent sequence reduce in net to gross with age as mud has a greater influence in the early fan system. Nevertheless, the sandstone properties remain relatively consistent and are far more laterally extensive than the youngest sequence. The Tay Sandstone spatially overlaps several other potential storage sites including the older Tertiary sandstones of the Cromarty, Forties and Mey Members and deeper Jurassic reservoirs. This favours the Tay Sandstone to be considered in a secondary or multiple stacked

Petroleum produced water disposal: Mobility and transport of barium in sandstone and dolomite rocks.

PubMed

Ebrahimi, Pouyan; Vilcáez, Javier

2018-09-01

To assess the risk of underground sources of drinking water contamination by barium (Ba) present in petroleum produced water disposed into deep saline aquifers, we examined the effect of salinity (NaCl), competition of cations (Ca, Mg), temperature (22 and 60°C), and organic fracturing additives (guar gum) on the sorption and transport of Ba in dolomites and sandstones. We found that at typical concentration levels of NaCl, Ca, and Mg in petroleum produced water, Ba sorption in both dolomites and sandstones is inhibited by the formation of Ba(Cl) + complexes in solution and/or the competition of cations for binding sites of minerals. The inhibition of Ba sorption by both mechanisms is greater in dolomites than in sandstones. This is reflected by a larger decrease in the breakthrough times of Ba through dolomites than through sandstones. We found that the presence of guar gum has little influence on the sorption and thus the transport of Ba in both dolomites and sandstones. Contrary to most heavy metals, Ba sorption in both dolomites and sandstones decreases with increasing temperature, however the reducing effect of temperature on Ba sorption is relevant only at low salinity conditions. Higher inhibition of Ba sorption in dolomites than in sandstones is due to the greater reactivity of dolomite over sandstone. The results of this study which includes the formulation of a reactive transport model and estimation of partition coefficients of Ba in dolomites and sandstones have significant implications in understanding and predicting the mobility and transport of Ba in deep dolomite and sandstone saline aquifers. Copyright © 2018 Elsevier B.V. All rights reserved.

Experimental study on the CO2-flow mechanism in the two different sandstones

NASA Astrophysics Data System (ADS)

Imasato, M.; Honda, H.; Kitamura, K.

2016-12-01

It is important to discuss the flow properties of CO2 in the reservoir for estimations of storage potential and safety of CCS operation. In this study, we conducted the CO2-injection tests into two different types of porous sandstones with extremely low CO2 flow rate (10µl/min) under supercritical CO2 conditions. It was measured CO2 saturation (SCO2) and differential pressure (ΔP) between upstream and downstream of specimen. It was also monitored P-wave velocity (Vp) and electrical impedance (Z) for the monitoring of CO2 behavior in the specimen. We set three Vp measurement lines in different height for monitoring the movement of CO2 front. The results of ΔP measurement indicated that the Berea sandstone showed no obvious change, but the Ainoura sandstone was increasing gradually and peaked in 73 hours. After that, ΔP of the Ainoura sandstone started reducing. Both sandstones showed stepwise Vp-reduction from the bottom Vp-measurement line, which is near CO2 injection end. There are large differences of CO2 arrival time at the bottom line between Berea and Ainoura sandstone. In case of Ainoura sandstone, it took 29 hours to reduce Vp which is the nearest to CO2 injection end, but in case of Berea sandstone, it took 3.3 hours. This is also confirmed the arrival time at the top channel, 2.5 hours in the Berea sandstone and 11 hours in the Ainoura sandstone. The impedances of both sandstones indicted the gradual increment. It took 25 hours to become constant in the Berea sandstone and 148 hours in the Ainoura sandstone. SCO2 of the Berea sandstone was about 6% and Ainoura sandstone reached over 20%. These results suggest that it is due to the difference of the pore structure of Berea sandstone and Ainoura sandstone.

Spatial Persistence of Macropores and Authigenic Clays in a Reservoir Sandstone: Implications for Enhanced Oil Recovery and CO2 Storage

NASA Astrophysics Data System (ADS)

Dewers, T. A.

2015-12-01

Multiphase flow in clay-rich sandstone reservoirs is important to enhanced oil recovery (EOR) and the geologic storage of CO2. Understanding geologic controls on pore structure allows for better identification of lithofacies that can contain, storage, and/or transmit hydrocarbons and CO2, and may result in better designs for EOR-CO2 storage. We examine three-dimensional pore structure and connectivity of sandstone samples from the Farnsworth Unit, Texas, the site of a combined EOR-CO2 storage project by the Southwest Regional Partnership on Carbon Sequestration (SWP). We employ a unique set of methods, including: robotic serial polishing and reflected-light imaging for digital pore-structure reconstruction; electron microscopy; laser scanning confocal microscopy; mercury intrusion-extrusion porosimetry; and relative permeability and capillary pressure measurements using CO2 and synthetic formation fluid. Our results link pore size distributions, topology of porosity and clay-rich phases, and spatial persistence of connected flow paths to multiphase flow behavior. The authors gratefully acknowledge the U.S. Department of Energy's National Energy Technology Laboratory for sponsoring this project through the SWP under Award No. DE-FC26-05NT42591. 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.

Pre-drill predictions versus post-drill results: use of sequence stratigraphic methods in reduction of exploration risk, Sarawak Deep-water Blocks, Malaysia

NASA Astrophysics Data System (ADS)

Mansor, Md Yazid; Snedden, J. W.; Sarg, J. F.; Smith, B. S.; Kolich, T.; Carter, M.

1999-04-01

Limited well control, great distances from age-equivalent producing fields, and a largely unknown stratigraphy necessitated use of sequence stratigraphic methods to assess exploration risk associated with reservoir, source and seal distribution in the Mobil-operated Deep-water Blocks of Sarawak, Malaysia. These methods allowed predictions to be made and reservoir risks to be halved in each of the locations drilled in 1995. Predictions regarding reservoir and stratigraphy proved correct, as the Mulu-1 and Bako-1 wells penetrated numerous high-quality, thick sandstone reservoirs in the Middle to Lower Miocene section. Shallow marine sandstones dominate the vertical succession in both wells, with characteristic aggradational, upward-coarsening log motifs. Cores display classic wave-generated stratification and hummocky cross-bedding. Evidence, such as marginal-marine to neritic microfauna in cuttings of both wells, supports these interpretations. Lack of hydrocarbon charge in the two wells may be due to their position relative to coaly hydrocarbon source beds. These prospects have high trap and seal integrity, being well defined on seismics as high relief horst blocks covered by a very thick shale-prone section. The Mulu-1 well, for example, is located at least 20-30 km down stratigraphic dip from mapped coeval lower coastal-plain deposits. Amplitude anomalies on the flank of the Mulu horst are probably derived from transported organics buried in deep Plio-Pleistocene kitchens in the northwest portion of the Mobil blocks. Remaining potential of mapped prospects is high and efforts continue at characterizing the petroleum system of the Deep-water Blocks. Seismic attribute and interval velocity analyses provide new clues to the location of probable coaly source rocks, especially when viewed in their regional and sequence stratigraphic context. Future work is planned and will serve to reduce risk to acceptable levels and support further drilling in this prospective

Stress-dependent permeability evolution in sandstones with anisotropic physical properties

NASA Astrophysics Data System (ADS)

Metz, V.; David, C.; Louis, L.; Rodriguez Rey, A.; Ruiz de Argandona, V. G.

2003-04-01

Fluid flow in reservoir rocks is strongly dependent on stress path and rock microstructure which may present a significant anisotropy. We present recent experimental data on the evolution of permeability with applied stress for three sandstones tested under triaxial conditions in the low confining pressure range (<10 MPa). Samples with diameter 40 mm and length 80 mm were cored in three orthogonal directions in blocks retrieved from quarries. One coring direction was perpendicular to the bedding plane whereas the other directions were arbitrarily chosen within the bedding plane. The selected rocks are the Bentheim sandstone (BNT), a quartz-rich cretaceous sandstone from Germany with 24% porosity, and two different varieties of a same jurassic formation in Northern Spain, the La Marina sandstone. The Yellow La Marina sandstone (YLM) with porosity 28% has a low cohesion and is the weathered form of the well-consolidated Grey La Marina sandstone (GLM) with porosity 17%. When loaded up to the failure stress, the more porous sandstones (BNT, YLM) exhibited a monotonic decrease of permeability even when the rock was dilating at deviatoric stresses close to the failure stress. On the other hand the permeability of the less porous sandstone (GLM) increased during the dilating phase. These results are in agreement with previous studies. In addition we observed that all three sandstones are anisotropic with respect to several physical properties including permeability. We systematically found a lower permeability in the direction perpendicular to the bedding plane, but the ratio of "vertical" to "horizontal" permeability varies from one sandstone to the other. The permeability anisotropy is compared to the anisotropy of electrical conductivity, acoustic velocity, capillary imbibition and elastic moduli: in general good correlations are found for all the properties. For the Bentheim sandstone, a microstructural study on thin sections revealed that the rock anisotropy is due

Stratigraphic comparison of six oil fields (WV) producing from Big Injun sandstones

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

Zou, X.; Donaldson, A.C.

1993-08-01

Clustered within western West Virginia, six oil fields produce from the lower Mississippian Big Injun sandstones, and three more oil fields also supplement this production either from underlying Squaw or Weir sandstones. Shales separate these sandstones that occur stratigraphically between the Sunbury Shale (maximum flooding surface) and pre-Greenbrier unconformity (maximum regressive erosional surface), and represent highstand regressive deposits associated with the postorogenic phase of foreland basin accumulation. Stratigraphic studies show two Big Injun sandstones. The upper sandstone, called the Maccrady Big Injun, is separated from the lower Price/Pocono Big Injun sandstone by red shales. Both Big Injun sandstones consist ofmore » fine-grained river-mouth bars capped by coarse-grained river-channel deposits. Although the six fields are within three adjacent counties, Maccrady Big Injun sandstones of Blue Creek (Kanawha) and Rock Creek (Roane) fields are younger and were deposited by a different fluvial-deltaic system than the Price/Pocono Big Injun sandstones of Granny Creek (Clay), Tariff (Roane) Clendenin (Clay), and Pond Fork (Kanawha) fields. Upper Weir sandstones are thick, narrow north-trending belts underlying Pond Fork and Blue Creek fields, with properties suggesting wave-dominated shoreline deposits. Allocycles spanning separate drainage systems indicate eustasy. Postorogenic flexural adjustments probably explain stacked sandstone belts with superposed paleovalleys of overlying unconformities (pre-Greenbrier, Pottsville), particularly where aligned along or parallel basement structures of Rome trough or West Virginia dome. Initially, differential subsidence or uplift during sedimentation influenced the position, geometry, trend, and distribution patterns of these reservoir sandstone, then influenced their preserved condition during erosion of pre-Greenbrier unconformity.« less

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

A fast complex domain-matching pursuit algorithm and its application to deep-water gas reservoir detection

NASA Astrophysics Data System (ADS)

Zeng, Jing; Huang, Handong; Li, Huijie; Miao, Yuxin; Wen, Junxiang; Zhou, Fei

2017-12-01

The main emphasis of exploration and development is shifting from simple structural reservoirs to complex reservoirs, which all have the characteristics of complex structure, thin reservoir thickness and large buried depth. Faced with these complex geological features, hydrocarbon detection technology is a direct indication of changes in hydrocarbon reservoirs and a good approach for delimiting the distribution of underground reservoirs. It is common to utilize the time-frequency (TF) features of seismic data in detecting hydrocarbon reservoirs. Therefore, we research the complex domain-matching pursuit (CDMP) method and propose some improvements. First is the introduction of a scale parameter, which corrects the defect that atomic waveforms only change with the frequency parameter. Its introduction not only decomposes seismic signal with high accuracy and high efficiency but also reduces iterations. We also integrate jumping search with ergodic search to improve computational efficiency while maintaining the reasonable accuracy. Then we combine the improved CDMP with the Wigner-Ville distribution to obtain a high-resolution TF spectrum. A one-dimensional modeling experiment has proved the validity of our method. Basing on the low-frequency domain reflection coefficient in fluid-saturated porous media, we finally get an approximation formula for the mobility attributes of reservoir fluid. This approximation formula is used as a hydrocarbon identification factor to predict deep-water gas-bearing sand of the M oil field in the South China Sea. The results are consistent with the actual well test results and our method can help inform the future exploration of deep-water gas reservoirs.

Multinomial Logistic Regression & Bootstrapping for Bayesian Estimation of Vertical Facies Prediction in Heterogeneous Sandstone Reservoirs

NASA Astrophysics Data System (ADS)

Al-Mudhafar, W. J.

2013-12-01

Precisely prediction of rock facies leads to adequate reservoir characterization by improving the porosity-permeability relationships to estimate the properties in non-cored intervals. It also helps to accurately identify the spatial facies distribution to perform an accurate reservoir model for optimal future reservoir performance. In this paper, the facies estimation has been done through Multinomial logistic regression (MLR) with respect to the well logs and core data in a well in upper sandstone formation of South Rumaila oil field. The entire independent variables are gamma rays, formation density, water saturation, shale volume, log porosity, core porosity, and core permeability. Firstly, Robust Sequential Imputation Algorithm has been considered to impute the missing data. This algorithm starts from a complete subset of the dataset and estimates sequentially the missing values in an incomplete observation by minimizing the determinant of the covariance of the augmented data matrix. Then, the observation is added to the complete data matrix and the algorithm continues with the next observation with missing values. The MLR has been chosen to estimate the maximum likelihood and minimize the standard error for the nonlinear relationships between facies & core and log data. The MLR is used to predict the probabilities of the different possible facies given each independent variable by constructing a linear predictor function having a set of weights that are linearly combined with the independent variables by using a dot product. Beta distribution of facies has been considered as prior knowledge and the resulted predicted probability (posterior) has been estimated from MLR based on Baye's theorem that represents the relationship between predicted probability (posterior) with the conditional probability and the prior knowledge. To assess the statistical accuracy of the model, the bootstrap should be carried out to estimate extra-sample prediction error by randomly

Evaluation of input output efficiency of oil field considering undesirable output —A case study of sandstone reservoir in Xinjiang oilfield

NASA Astrophysics Data System (ADS)

Zhang, Shuying; Wu, Xuquan; Li, Deshan; Xu, Yadong; Song, Shulin

2017-06-01

Based on the input and output data of sandstone reservoir in Xinjiang oilfield, the SBM-Undesirable model is used to study the technical efficiency of each block. Results show that: the model of SBM-undesirable to evaluate its efficiency and to avoid defects caused by traditional DEA model radial angle, improve the accuracy of the efficiency evaluation. by analyzing the projection of the oil blocks, we find that each block is in the negative external effects of input redundancy and output deficiency benefit and undesirable output, and there are greater differences in the production efficiency of each block; the way to improve the input-output efficiency of oilfield is to optimize the allocation of resources, reduce the undesirable output and increase the expected output.

Characterization of the Lower Cambrian sandstone aquifer in the Swedish Baltic Sea area - assessment regarding its potential suitability for storage of CO2

NASA Astrophysics Data System (ADS)

Erlström, M.; Sivhed, U.

2012-04-01

In the Baltic region the Cambrian sandstone is considered to have great economic value concerning its aquifer and reservoir properties. Its potential as petroleum reservoir is well known, especially from the Polish, Lithuanian and Russian sectors of the Baltic Sea where oil and gas has been found in anticline traps in the sandstone sequence. Offshore exploration in the Swedish sector has so far not encountered any significant findings of oil and gas. However, the extensive exploration has generated data, which is now being used for assessing the overall properties regarding suitability for storage of CO2. The Swedish primary industry has a great interest in finding potential sites for storage of CO2. A suitable site in the Baltic Sea would be a most favourable alternative in comparison to more remote alternatives such as deep saline aquifers in the North Sea. The Lower Cambrian is in the Swedish sector of the Baltic Sea composed of three main sandstone units varying in thickness between 5 and 50 m occurring within an up to 250 m thick Cambrian sequence dominated by fine-grained terriclastic sediments. The limit of Lower Palaeozoic sequence in the Baltic area is today defined by erosional truncation because of the gently dipping Lower Palaeozoic sequence. To the north and northwest, the limit is found in the Pre-Quaternary, whereas the erosional limit is deeply buried beneath Permian and Mesozoic sediments to the south. Here the Lower Palaeozoic limit is buried to depths reaching more than 2 km. The Cambrian sequence in the distal parts of the Swedish sector occurs at depths of c. 1300 m while it constitutes the bedrock surface in a narrow zone trending from Öland to the north of of Gotland. Sandstone beds constitute 40-60% of the total Cambrian sequence. The main sandstone units have a regional distribution of several thousands of square kilometres. The up to 50 m thick Faludden sandstone member exhibits the best reservoir properties including porosities in the

Textural and mineralogical study of sandstones from the onshore Gulf of Alaska Tertiary Province, southern Alaska

USGS Publications Warehouse

Winkler, Gary R.; McLean, Hugh; Plafker, George

1976-01-01

Petrographic examination of 74 outcrop samples of Paleocene through Pliocene age from the onshore Gulf of Alaska Tertiary Province indicates that sandstones of the province characteristically are texturally immature and mineralogically unstable. Diagenetic alteration of framework grains throughout the stratigraphic sequence has produced widespread zeolite cement or phyllosilicate grain coatings and pseudomatrix. Multiple deformation and deep burial of the older Tertiary sequence--the Orca Group, the shale of Haydon Peak, and the Kulthieth and Tokun Formations--caused extensive alteration and grain interpenetration, resulting in low porosity values. Less intense deformation and intermediate depth of burial of the younger Tertiary sequence--the Katalla, Poul Creek, Redwood, and Yakataga Formations--has resulted in a greater range in textural properties. Most sandstone samples in the younger Tertiary sequence are poorly sorted, tightly packed, and have strongly appressed framework grains, but some are less tightly packed and contain less matrix. Soft and mineralogically unstable framework grains have undergone considerable alteration, reducing pore space even in the youngest rocks. Measurements of porosity, permeability, grain density, and sonic velocity of outcrop samples of the younger Tertiary sequence indicate a modest up-section improvement in sandstone reservoir characteristics. Nonetheless porosity and permeability values typically are below 16 percent and 15 millidarcies respectively and grain densities are consistently high, about 2.7 gm/cc. Low permeability and porosity values, and high grain densities and sonic velocities appear to be typical of most outcrop areas throughout the onshore Gulf of Alaska Tertiary Province.

Origin and diagenesis of clay minerals in relation to sandstone paragenesis: An example in eolian dune reservoirs and associated rocks, Permian upper part of the Minnelusa Formation, Powder River basin, Wyoming

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

Pollastro, R.M.; Schenk, C.J.

Eolian dune sandstones are the principal reservoir rocks in the Permian upper part of the Minnelusa Formation, Powder River basin, Wyoming. These sandstones formed as shorelines retreated and dunes migrated across siliciclastic sabkhas. Sandstones are mainly quartzarenites; on average, clay minerals constitute about 5 wt.% the whole rock. Although present in minor amounts, clay minerals play an important role in the diagenetic evolution of these sandstones. Allogenic clay minerals are present in shaly rock fragments and laminae. Early infiltration of clays into porous sabkha sands commonly form characteristic menisei or bridges between framework grains or, when more extensive, form coatingsmore » or rims on grain surfaces. Authigenic clays include nearly pure smectite, mixed-layer illite/smectite (I/S), and late diagenetic illite and corrensite; these clay minerals are present as pore-lining cements. In addition to the deposition and neoformation of clay minerals throughout sandstone paragenesis, the conversion of smectite to illite occurred as temperatures increased with progressive burial. A temperature of 103C is calculated at a present depth of 3,200 m using a geothermal gradient of 30C/km and a mean annual surface temperature of 7C. After correction for uplift and erosion (250 m), the maximum calculated temperature for the conversion of all random I/S to ordered I/S is 100C. This calculated temperature is in excellent agreement with temperatures of 100-110C implied from I/S geothermometry.« less

Determination techniques of Archie’s parameters: a, m and n in heterogeneous reservoirs

NASA Astrophysics Data System (ADS)

Mohamad, A. M.; Hamada, G. M.

2017-12-01

The determination of water saturation in a heterogeneous reservoir is becoming more challenging, as Archie’s equation is only suitable for clean homogeneous formation and Archie’s parameters are highly dependent on the properties of the rock. This study focuses on the measurement of Archie’s parameters in carbonate and sandstone core samples around Malaysian heterogeneous carbonate and sandstone reservoirs. Three techniques for the determination of Archie’s parameters a, m and n will be implemented: the conventional technique, core Archie parameter estimation (CAPE) and the three-dimensional regression technique (3D). By using the results obtained by the three different techniques, water saturation graphs were produced to observe the symbolic difference of Archie’s parameter and its relevant impact on water saturation values. The difference in water saturation values can be primarily attributed to showing the uncertainty level of Archie’s parameters, mainly in carbonate and sandstone rock samples. It is obvious that the accuracy of Archie’s parameters has a profound impact on the calculated water saturation values in carbonate sandstone reservoirs due to regions of high stress reducing electrical conduction resulting from the raised electrical heterogeneity of the heterogeneous carbonate core samples. Due to the unrealistic assumptions involved in the conventional method, it is better to use either the CAPE or 3D method to accurately determine Archie’s parameters in heterogeneous as well as homogeneous reservoirs.

Preliminary evaluation of the basal sandstone in Tennessee for receiving injected wastes

USGS Publications Warehouse

Mulderink, Dolores; Bradley, M.W.

1986-01-01

The EPA is authorized, under the Safe Drinking Water Act, to administer the Underground Injection Control program. This program allows for the regulation of deep-well disposal of wastes and establishes criteria to protect underground sources of drinking water from contamination. The basal sandstone in Tennessee occurs west of the Valley and Ridge province at depths of 5,000 to 9,000 ft below land surface. The basal sandstone consists of about 30 to 750 ft of Cambrian sandstone overlying the crystalline basement complex. The basal sandstone is overlain and confined by shale and carbonate rocks of the Middle and Upper Cambrian Conasauga Group. Hydrologic data for the basal sandstone, available from only three sites (four wells) in Tennessee, indicate that the basal sandstone generally has low porosity and permeability with a few zones having enough permeability to accept injected fluids. Limited water quality data indicate the basal sandstone contains water with dissolved solids concentrations exceeding 10,000 mg/L. Since the dissolved-solids concentrations exceed 10,000 mg/L, the basal sandstone is not classified as an underground source of drinking water according to EPA regulations. (Author 's abstract)

Fracture characterization in a deep geothermal reservoir

NASA Astrophysics Data System (ADS)

Rühaak, Wolfram; Hehn, Vera; Hassanzadegan, Alireza; Tischner, Torsten

2017-04-01

At the geothermal research drilling Horstberg in North West Germany studies for the characterization of a vertical fracture are performed. The fracture was created by a massive hydraulic stimulation in 2003 in approx. 3700 m depth within rocks of the middle Buntsandstein. The fracture surface is in the order of 100,000 m2, depending on the flow rate at which water is injected. Besides hydraulic characterization, multiple tracer tests are planned. At the depth of interest the reservoir temperature is around 150 °C, pressure is around 600 bar (60 MPa) and due to salinity the water density is around 1200 kg/m3. Knowledge of tracer stability and behavior at these reservoir conditions is limited. Additionally, the planned tracer tests will be performed within one single borehole. In a closed cycle water is injected into the inner pipe of the well (tubing), which is separated by a permanent packer from the outer pipe (annulus). The water is produced back from the annulus approximately 150 m above the injection point. Thus, the circulation of thermal water between two sandstone layers via an artificial fracture can be achieved. Tests will be carried out with different flow rates and accordingly with different pressures, resulting in different fracture areas. Due to this test setup tracer signals will be stacked and will remain for a longer time in the fracture - which is the reason why different tracers are required. For an optimal characterization both conservative and reactive tracers will be used and different injection methods (continuous, instantaneous and pulsed) will be applied. For a proper setup of the tracer test numerical modelling studies are performed in advance. The relevant thermal, hydraulic and chemical processes (mainly adsorption and degredation) are coupled, resulting in a THC model; additionally the dependence of fracture aperture and area on fluid pressure has to be considered. Instead of applying a mechanically coupled model (THMC) a simplified

Use of micro-resistivity imaging tools in developing lower Pennsylvanian Morrow channel sandstone reservoirs, Cheyenne, Kiowa and Lincoln Counties, Colorado

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

Germinario, M.P.

1996-01-01

In southeastern Colorado, Lower Pennsylvanian Morrow channel sandstones are part of complex valley-fill sequences incised into Morrow marine deposits. Morrow valleys are approximately [1/2] to 1 mile wide. Valley-fill consists of floodplain and channel filling shales, very fine-grained estuarine sandstones and fine- to coarse-grained channel sandstones that are up to 50' thick. Channel sandstones represent a sequence of stacked fluvial bars deposited in braided, anastomosing and meandering fluvial environments. Cross-stratification in channel sandstones can be imaged by micro-resistivity wireline logging tools and interpreted interactively on various workstation software packages. Recognition, interpretation and measurement of current, stoss face, and lateral accretionmore » beds in these sandstones can result in an estimated direction of paleocurrent flow of the channel. Determination of the channel's local paleoflow direction can provide significant sand risk reduction in developmental drilling, especially in 80 acre or less spacing patterns. As the distance between offset drilling locations increases, the reliability of paleoflow prediction decreases, and the corresponding sand risk rises. Lateral accretion bedding in Morrow channel sandstones has proven to be a poor indicator of sand thickening direction, due to the complex stacking of multiple channel sandstones within any given valley-fill sequence. Micro-resistivity imaging reduces risk in Morrow channel sandstone development drilling programs. Furthermore, these interpretation techniques could be applicable in other fluvial channel sandstone plays.« less

Use of micro-resistivity imaging tools in developing lower Pennsylvanian Morrow channel sandstone reservoirs, Cheyenne, Kiowa and Lincoln Counties, Colorado

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

Germinario, M.P.

1996-12-31

In southeastern Colorado, Lower Pennsylvanian Morrow channel sandstones are part of complex valley-fill sequences incised into Morrow marine deposits. Morrow valleys are approximately {1/2} to 1 mile wide. Valley-fill consists of floodplain and channel filling shales, very fine-grained estuarine sandstones and fine- to coarse-grained channel sandstones that are up to 50` thick. Channel sandstones represent a sequence of stacked fluvial bars deposited in braided, anastomosing and meandering fluvial environments. Cross-stratification in channel sandstones can be imaged by micro-resistivity wireline logging tools and interpreted interactively on various workstation software packages. Recognition, interpretation and measurement of current, stoss face, and lateral accretionmore » beds in these sandstones can result in an estimated direction of paleocurrent flow of the channel. Determination of the channel`s local paleoflow direction can provide significant sand risk reduction in developmental drilling, especially in 80 acre or less spacing patterns. As the distance between offset drilling locations increases, the reliability of paleoflow prediction decreases, and the corresponding sand risk rises. Lateral accretion bedding in Morrow channel sandstones has proven to be a poor indicator of sand thickening direction, due to the complex stacking of multiple channel sandstones within any given valley-fill sequence. Micro-resistivity imaging reduces risk in Morrow channel sandstone development drilling programs. Furthermore, these interpretation techniques could be applicable in other fluvial channel sandstone plays.« less

Compositional changes of reservoir rocks through the injection of supercritical CO2

NASA Astrophysics Data System (ADS)

Scherf, Ann-Kathrin; Schulz, Hans-Martin; Zetzl, Carsten; Smirnova, Irina; Andersen, Jenica; Vieth, Andrea

2010-05-01

The European project CO2SINK is the first project on the on-shore underground storage of carbon dioxide in Europe. CO2SINK is part of the ongoing efforts to understand the impact, problems, and likelihood of using deep saline aquifers for long term storage of CO2. In Ketzin (north-east Germany, 40 km west of Berlin) a saline sandstone aquifer of the younger Triassic (Stuttgart Formation) has been chosen as a reservoir for the long-term storage of carbon dioxide. Our monitoring focuses on the composition and mobility of the organic carbon pools within the saline aquifer and their changes due to the storage of carbon dioxide. Supercritical carbon dioxide is known as an excellent solvent of non- to moderately polar organic compounds, depending on temperature and pressure (Hawthorne, 1990). The extraction of organic matter (OM) from reservoir rock, using multiple extraction methods, allows insight into the composition of the OM and the biomarker inventory of the deep biosphere. The extraction of reservoir rock using supercritical CO2 may additionally simulate the impact of CO2 storage on the deep biosphere by the possible mobilisation of OM. We will present compound specific results from laboratory CO2 extraction experiments on reservoir rocks from the CO2 storage site in Ketzin, Germany. A total of five rock samples (silt and sandstones) from the injection well and two observation wells were applied to supercritical CO2 extraction. In the experimental setup, a supercritical fluid extractor is used to simulate the conditions within the saline aquifer. The results show distinct quantitative and qualitative differences in extraction yields between the rock samples. This may be due to differences in mineralogy and porosity (12 - 27%; Norden et al., 2007a, b, c), which seem to be extraction-controlling key factors. Furthermore, the results illustrate that the amount of extracted materials depends on the length of the time interval in which CO2 flows through the rock

THM modelling of hydrothermal circulation in deep geothermal reservoirs

NASA Astrophysics Data System (ADS)

Magnenet, Vincent; Fond, Christophe; Schmittbuhl, Jean; Genter, Albert

2014-05-01

Numerous models have been developped for describing deep geothermal reservoirs. Using the opensource finite element software ASTER developped by EDF R&D, we carried out 2D simulations of the hydrothermal circulation in the deep geothermal reservoir of Soultz-sous-Forêts. The model is based on the effective description of Thermo-Hydro-Mechanical (THM) coupling at large scale. Such a model has a fourfold interest: a) the physical integration of laboratory measurements (rock physics), well logging, well head parameters, geological description, and geophysics field measurements; b) the construction of a direct model mechanically based for geophysical inversion: fluid flow, fluid pressure, temperature profile, seismicity monitoring, deformation of the ground surface (INSAR/GPS) related to reservoir modification, gravity or electromagnetic geophysical measurements; c) the sensitivity analysis of the parameters involved in the hydrothermal circulation and identification of the dominant ones; d) the development of a decision tool for drilling planning, stimulation and exploitation. In our model, we introduced extended Thermo-Hydro-Mechanical coupling including not only poro-elastic behavior but also the sensitivity of the fluid density, viscosity, and heat capacity to temperature and pressure. The behavior of solid rock grains is assumed to be thermo-elastic and linear. Hydraulic and thermal phenomena are governed by Darcy and Fourier laws respectively, and most rock properties (like the specific heat at constant stress csσ(T), or the thermal conductivity Λ(T,φ)) are assumed to depend on the temperature T and/or porosity φ. The radioactivity of the rocks is taken into account through a heat source term appearing in the balance equation of enthalpy. To characterize as precisely as possible the convective movement of water and the associated heat flow, water properties (specific mass ρw(T,pw), specific enthalpy hmw(T,pw) dynamic viscosity μw(T), thermal dilation �

Middle Jurassic incised valley fill (eolian/estuarine) and nearshore marine petroleum reservoirs, Powder River Basin

USGS Publications Warehouse

Ahlbrandt, T.S.; Fox, J.E.

1997-01-01

Paleovalleys incised into the Triassic Spearfish Formation (Chugwater equivalent) are filled with a vertical sequence of eolian, estuarine, and marine sandstones of the Middle Jurassic (Bathonian age) Canyon Springs Sandstone Member of the Sundance Formation. An outcrop exemplifying this is located at Red Canyon in the southern Black Hills, Fall River County, South Dakota. These paleovalleys locally have more than 300 ft of relief and are as much as several miles wide. Because they slope in a westerly direction, and Jurassic seas transgressed into the area from the west there was greater marine-influence and more stratigraphic complexity in the subsurface, to the west, as compared to the Black Hills outcrops. In the subsurface two distinctive reservoir sandstone beds within the Canyon Springs Sandstone Member fill the paleovalleys. These are the eolian lower Canyon Springs unit (LCS) and the estuarine upper Canyon Springs unit (UCS), separated by the marine "Limestone Marker" and estuarine "Brown Shale". The LCS and UCS contain significant proven hydrocarbon reservoirs in Wyoming (about 500 MMBO in-place in 9 fields, 188 MMBO produced through 1993) and are prospective in western South Dakota, western Nebraska and northern Colorado. Also prospective is the Callovian-age Hulett Sandstone Member which consists of multiple prograding shoreface to foreshore parasequences, as interpreted from the Red Canyon locality. Petrographic, outcrop and subsurface studies demonstrate the viability of both the Canyon Springs Sandstone and Hulett Sandstone members as superior hydrocarbon reservoirs in both stratigraphic and structural traps. Examples of fields with hydrocarbon production from the Canyon Springs in paleovalleys include Lance Creek field (56 MMBO produced) and the more recently discovered Red Bird field (300 MBO produced), both in Niobrara County, Wyoming. At Red Bird field the primary exploration target was the Pennsylvanian "Leo sands" of the Minnelusa Formation, and

Assessment of Deep Seated Geothermal Reservoirs in Selected European Sedimentary Environments

NASA Astrophysics Data System (ADS)

Ungemach, Pierre; Antics, Miklos

2014-05-01

Europe at large enjoys a variety of sedimentary environments. They most often host dependable geothermal reservoirs thus favouring the farming of hot fluids, within the low to medium enthalpy range, among which geothermal district heating (GDH) and combined heat and power (CHP) undertakings hold a dominant share. Three selected reservoir settings, addressing carbonate and clastic deposits, the Central part of the Paris Basin, the Southern Germany Molasse Basin in the Münich area and the Netherland Basin respectively will be presented and the exploratory, modeling and development strategies discussed accordingly. Whereas 2D (reprocessed) and 3D seismics have become a standard in matching the distinctive (reef facies, an echelon faulting, carbonate platform layering) features of a deep buried karst and a key to drilling success in the Molasse Basin, thus emphasizing a leading exploratory rationale, the Netherland and Paris Basin instead benefit from a mature data base inherited from extensive hydrocarbon exploration campaigns, with concerns focused on reservoir modeling and sustainable management issues. As a result the lessons learned from the foregoing have enabled to build up a nucleus of expertise in the whole chain from resource identification to reservoir assessment and market penetration. The seismic risk, indeed a sensitive though somewhat emotional issue, which is requiring special attention and due microseismic monitoring from the geothermal community will also be commented.

Changes in the composition and properties of Ashalchinskoye bitumen-saturated sandstones when exposed to water vapor

NASA Astrophysics Data System (ADS)

Korolev, E.; Eskin, A.; Kolchugin, A.; Morozov, V.; Khramchenkov, M.; Gabdelvalieva, R.

2018-05-01

Ashalchinskoye bitumen deposit is an experimental platform for testing technology of high-viscosity oil extraction from reservoir rocks. Last time for enhanced of oil recovery in reservoir used pressurization a water vapor with a temperature of ∼ 180 ° C (SAGD technology). However, what happens in sandstone reservoir is little known. We did a study of the effects of water vapor on the structural components of bitumen saturated sandstone. In paper were studied the rock samples at base condition and after one week exposure by water vapour. The thermal analysis showed that steaming helps to removes light and middle oil fractions with a boiling point up to 360 ° C from oil saturated sandstones. Content of heavy oil fractions virtually unchanged. Studying the composition of water extractions of samples showed that the process of aquathermolysis of oil is accompanied by a lowering of the pH of the pore solution from 7.4 to 6.5 and rise content in several times of mobile cations Ca2+, Mg2+ and HCO3 -, SO4 2- anions. Follows from this that the thermal steam effect by bitumen saturated sandstones leads to partial oxidation of hydrocarbons with to form a carbon dioxide. The source of sulfate ions were oxidized pyrite aggregates. Due to the increasing acidity of condensed water, which fills the pore space of samples, pore fluid becomes aggressive to calcite and dolomite cement of bitumen saturated sandstones. As a result of the dissolution of carbonate cement the pore fluid enriched by calcium and magnesium cations. Clearly, that the process is accompanied by reduction of contact strength between fragments of minerals and rocks. Resulting part of compounds is separated from the outer side of samples and falls to bottom of water vapor container. Decreasing the amount of calcite and dolomite anions in samples in a steam-treated influence is confirmed by X-Ray analysis. X-Ray analysis data of study adscititious component of rocks showed that when influenced of water vapor to

Analysis of some seismic expressions of Big Injun sandstone and its adjacent interval

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

Xiangdong, Zou; Wilson, T.A.; Donaldson, A.C.

1991-08-01

The Big Injun sandstone is an important oil and gas reservoir in western West Virginia. The pre-Greenbrier unconformity has complicated correlations, and hydrocarbon explorationists commonly have misidentified the Big Injun in the absence of a regional stratigraphic study. Paleogeologic maps on this unconformity show the West Virginia dome, with the Price/Pocono units truncated resulting in pinch-outs of different sandstones against the overlying Big Lime (Greenbrier Limestone). Drillers have named the first sandstone below the Big Lime as Big Injun, and miscorrelated the real Big Injun with Squaw, upper Weir, and even the Berea sandstone. In this report, an 8-mi (13-km)more » seismic section extending from Kanawha to Clay counties was interpreted. The study area is near the pinch-out of the Big Injun sandstone. A stratigraphic cross section was constructed from gamma-ray logs for comparison with the seismic interpretation. The modeling and interpretation of the seismic section recognized the relief on the unconformity and the ability to determine facies changes, too. Both geophysical wireline and seismic data can be used for detailed stratigraphic analysis within the Granny Creek oil field of Clay and Roane countries.« less

Characterization of petroleum reservoirs in the Eocene Green River Formation, Central Uinta Basin, Utah

USGS Publications Warehouse

Morgan, C.D.; Bereskin, S.R.

2003-01-01

The oil-productive Eocene Green River Formation in the central Uinta Basin of northeastern Utah is divided into five distinct intervals. In stratigraphically ascending order these are: 1) Uteland Butte, 2) Castle Peak, 3) Travis, 4) Monument Butte, and 5) Beluga. The reservoir in the Uteland Butte interval is mainly lacustrine limestone with rare bar sandstone beds, whereas the reservoirs in the other four intervals are mainly channel and lacustrine sandstone beds. The changing depositional environments of Paleocene-Eocene Lake Uinta controlled the characteristics of each interval and the reservoir rock contained within. The Uteland Butte consists of carbonate and rare, thin, shallow-lacustrine sandstone bars deposited during the initial rise of the lake. The Castle Peak interval was deposited during a time of numerous and rapid lake-level fluctuations, which developed a simple drainage pattern across the exposed shallow and gentle shelf with each fall and rise cycle. The Travis interval records a time of active tectonism that created a steeper slope and a pronounced shelf break where thick cut-and-fill valleys developed during lake-level falls and rises. The Monument Butte interval represents a return to a gentle, shallow shelf where channel deposits are stacked in a lowstand delta plain and amalgamated into the most extensive reservoir in the central Uinta Basin. The Beluga interval represents a time of major lake expansion with fewer, less pronounced lake-level falls, resulting in isolated single-storied channel and shallow-bar sandstone deposits.

Integrated geomechanical, petrographical and petrophysical study of the sandstones of the Wajid Group, SW Saudi Arabia

NASA Astrophysics Data System (ADS)

Benaafi, Mohammed; Hariri, Mustafa; Al-Shaibani, Abdulaziz; Abdullatif, Osman; Makkawi, Mohammed

2018-07-01

The Cambro-Permian siliciclastic succession in southwestern Saudi Arabia is represented by the Wajid Group, which consists mainly of fluvial, shallow marine, aeolian, and glacial sandstones. The Wajid Group comprises the Dibsiyah, Sanamah, Qalibah, Khusayyayn, and Juwayl Formations. It is exposed in the Wadi Al-Dawasir area and extends to Najran City. The sandstones of the Wajid Group serve as groundwater aquifers in the Wadi Al-Dawasir and Najran areas and host hydrocarbon (mainly gas) reservoirs in the Rub' Al-Khali Basin. This study aims to characterize the geomechanical properties (rock strength and Young's modulus) of the sandstones of the Wajid Group using field and experimental techniques. A further objective is to investigate the relationships between the geomechanical properties and the petrographical and petrophysical properties of the studied sandstones. The geomechanical properties of the studied sandstones vary from glacial to non-glacial sandstones, as the glacial sandstones display high values of the geomechanical properties with high variability indices. Four geological factors including grain size, cement content, porosity and permeability were observed as the main controls on the geomechanical behaviour of the studied sandstones except for the Khusayyayn sandstone, where the mineral composition was also important. Significant correlations were observed between the petrographical and petrophysical properties and the geomechanical properties of the glacial sandstones. Predictive models of the geomechanical properties (RN, UCS, and E) were generated using regression analysis to account for the glacial sandstones.

Sedimentology and Reservoir Characteristics of Early Cretaceous Fluvio-Deltaic and Lacustrine Deposits, Upper Abu Gabra Formation, Sufyan Sub-basin, Muglad Rift Basin, Sudan

NASA Astrophysics Data System (ADS)

Yassin, Mohamed; Abdullatif, Osman; Hariri, Mustafa

2017-04-01

Sufyan Sub-basin is an East-West trending Sub-basin located in the northwestern part of the Muglad Basin (Sudan), in the eastern extension of the West and Central Africa Rift System (WCARS). The Early Cretaceous Abu Gabra Formation considered as the main source rock in the Muglad Basin. In Sufyan Sub-basin the Early Cretaceous Upper Abu Gabra Formation is the main oil-producing reservoir. It is dominated by sandstone and shales deposited in fluvio-deltaic and lacustrine environment during the first rift cycle in the basin. Depositional and post-depositional processes highly influenced the reservoir quality and architecture. This study investigates different scales of reservoir heterogeneities from macro to micro scale. Subsurface facies analysis was analyzed based on the description of six conventional cores from two wells. Approaches include well log analysis, thin sections and scanning electron microscope (SEM) investigations, grain-size, and X-ray diffraction (XRD) analysis of the Abu Gabra sandstone. The cores and well logs analyses revealed six lithofacies representing fluvio-deltaic and lacustrine depositional environment. The sandstone is medium to coarse-grained, poorly to moderately sorted and sub-angular to subrounded, Sub-feldspathic arenite to quartz arenite. On macro-scale, reservoir quality varies within Abu Gabra reservoir where it shows progressive coarsening upward tendencies with different degrees of connectivity. The upper part of the reservoir showed well connected and amalgamated sandstone bodies, the middle to lower parts, however, have moderate to low sandstone bodies' connectivity and amalgamation. On micro-scale, sandstone reservoir quality is directly affected by textures and diagenesis.The XRD and SEM analyses show that kaolinite and chlorite clay are the common clay minerals in the studied samples. Clay matrix and quartz overgrowth have significantly reduced the reservoir porosity and permeability, while the dissolution of feldspars

Single well productivity prediction of carbonate reservoir

NASA Astrophysics Data System (ADS)

Le, Xu

2018-06-01

It is very important to predict the single-well productivity for the development of oilfields. The fracture structure of carbonate fractured-cavity reservoirs is complex, and the change of single-well productivity is inconsistent with that of sandstone reservoir. Therefore, the establishment of carbonate oil well productivity It is very important. Based on reservoir reality, three different methods for predicting the productivity of carbonate reservoirs have been established based on different types of reservoirs. (1) To qualitatively analyze the single-well capacity relations corresponding to different reservoir types, predict the production capacity according to the different wells encountered by single well; (2) Predict the productivity of carbonate reservoir wells by using numerical simulation technology; (3) According to the historical production data of oil well, fit the relevant capacity formula and make single-well productivity prediction; (4) Predict the production capacity by using oil well productivity formula of carbonate reservoir.

Geometrical and hydrogeological impact on the behaviour of deep-seated rock slides during reservoir impoundment

NASA Astrophysics Data System (ADS)

Lechner, Heidrun; Zangerl, Christian

2015-04-01

Given that there are still uncertainties regarding the deformation and failure mechanisms of deep-seated rock slides this study concentrates on key factors that influence the behaviour of rock slides in the surrounding of reservoirs. The focus is placed on the slope geometry, hydrogeology and kinematics. Based on numerous generic rock slide models the impacts of the (i) rock slide geometry, (ii) reservoir impoundment and level fluctuations, (iii) seepage and buoyancy forces and (iv) hydraulic conductivity of the rock slide mass and the basal shear zone are examined using limit equilibrium approaches. The geometry of many deep-seated rock slides in metamorphic rocks is often influenced by geological structures, e.g. fault zones, joints, foliation, bedding planes and others. With downslope displacement the rock slide undergoes a change in shape. Several observed rock slides in an advanced stage show a convex, bulge-like topography at the foot of the slope and a concave topography in the middle to upper part. Especially, the situation of the slope toe plays an important role for stability. A potentially critical situation can result from a partially submerged flat slope toe because the uplift due to water pressure destabilizes the rock slide. Furthermore, it is essential if the basal shear zone daylights at the foot of the slope or encounters alluvial or glacial deposits at the bottom of the valley, the latter having a buttressing effect. In this study generic rock slide models with a shear zone outcropping at the slope toe are established and systematically analysed using limit equilibrium calculations. Two different kinematic types are modelled: (i) a translational or planar and (ii) a rotational movement behaviour. Questions concerning the impact of buoyancy and pore pressure forces that develop during first time impoundment are of key interest. Given that an adverse effect on the rock slide stability is expected due to reservoir impoundment the extent of

Integrated reservoir characterization and flow simulation for well targeting and reservoir management, Iagifu-Hedinia field, Southern Highlands Province, Papua New Guinea

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

Franklin, S.P.; Livingston, J.E.; Fitzmorris, R.E.

Infill drilling based on integrated reservoir characterization and flow simulation is increasing recoverable reserves by 20 MMBO, in lagifu-Hedinia Field (IHF). Stratigraphically-zoned models are input to window and full-field flow simulations, and results of the flow simulations target deviated and horizontal wells. Logging and pressure surveys facilitate detailed reservoir management. Flooding surfaces are the dominant control on differential depletion within and between reservoirs. The primary reservoir is the basal Cretaceous Toro Sandstone. Within the IHF, Toro is a 100 m quartz sandstone composed of stacked, coarsening-upward parasequences within a wave-dominated deltaic complex. Flooding surfaces are used to form a hydraulicmore » zonation. The zonation is refined using discontinuities in RIFT pressure gradients and logs from development wells. For flow simulation, models use 3D geostatistical techniques. First, variograms defining spatial correlation are developed. The variograms are used to construct 3D porosity and permeability models which reflect the stratigraphic facies models. Structure models are built using dipmeter, biostratigraphic, and surface data. Deviated wells often cross axial surfaces and geometry is predicted from dip domain and SCAT. Faults are identified using pressure transient data and dipmeter. The Toro reservoir is subnormally pressured and fluid contacts are hydrodynamically tilted. The hydrodynamic flow and tilted contacts are modeled by flow simulation and constrained by maps of the potentiometric surface.« less

Cyclicity and reservoir properties of Lower-Middle Miocene sediments of South Kirinsk oil and gas field

NASA Astrophysics Data System (ADS)

Kurdina, Nadezhda

2017-04-01

Exploration and additional exploration of oil and gas fields, connected with lithological traps, include the spreading forecast of sedimentary bodies with reservoir and seal properties. Genetic identification and forecast of geological bodies are possible in case of large-scale studies, based on the study of cyclicity, structural and textural features of rocks, their composition, lithofacies and depositional environments. Porosity and permeability evaluation of different reservoir groups is also an important part. Such studies have been successfully completed for productive terrigenous Dagi sediments (Lower-Middle Miocene) of the north-eastern shelf of Sakhalin. In order to identify distribution of Dagi reservoirs with different properties in section, core material of the one well of South Kirinsk field has been studied (depth interval from 2902,4 to 2810,5 m). Productive Dagi deposits are represented by gray-colored sandstones with subordinate siltstones and claystones (total thickness 90,5 m). Analysis of cyclicity is based on the concepts of Vassoevich (1977), who considered cycles as geological body, which is the physical result of processes that took place during the sedimentation cycle. Well section was divided into I-X units with different composition and set of genetic features due to layered core description and elementary cyclites identification. According to description of thin sections and results of cylindrical samples porosity and permeability studies five groups of reservoirs were determined. There are coarse-grained and fine-coarse-grained sandstones, fine-grained sandstones, fine-grained silty sandstones, sandy siltstones and siltstones. It was found, in Dagi section there is interval of fine-coarse-grained and coarse-grained sandstones with high petrophysical properties: permeability 3000 mD, porosity more than 25%, but rocks with such properties spread locally and their total thickness is 6 meters only. This interval was described in the IV unit

The Researches on Reasonable Well Spacing of Gas Wells in Deep and low Permeability Gas Reservoirs

NASA Astrophysics Data System (ADS)

Bei, Yu Bei; Hui, Li; Lin, Li Dong

2018-06-01

This Gs64 gas reservoir is a condensate gas reservoir which is relatively integrated with low porosity and low permeability found in Dagang Oilfield in recent years. The condensate content is as high as 610g/m3. At present, there are few reports about the well spacing of similar gas reservoirs at home and abroad. Therefore, determining the reasonable well spacing of the gas reservoir is important for ensuring the optimal development effect and economic benefit of the gas field development. This paper discusses the reasonable well spacing of the deep and low permeability gas reservoir from the aspects of percolation mechanics, gas reservoir engineering and numerical simulation. considering there exist the start-up pressure gradient in percolation process of low permeability gas reservoir, this paper combined with productivity equation under starting pressure gradient, established the formula of gas well spacing with the formation pressure and start-up pressure gradient. The calculation formula of starting pressure gradient and well spacing of gas wells. Adopting various methods to calculate values of gas reservoir spacing are close to well testing' radius, so the calculation method is reliable, which is very important for the determination of reasonable well spacing in low permeability gas reservoirs.

Supercritical CO2 Migration under Cross-Bedded Structures: Outcrop Analog from the Jurassic Navajo Sandstone

NASA Astrophysics Data System (ADS)

Lee, S.; Allen, J.; Han, W.; Lu, C.; McPherson, B. J.

2011-12-01

Jurassic aeolian sandstones (e.g. Navajo and White Rim Sandstones) on the Colorado Plateau of Utah have been considered potential sinks for geologic CO2 sequestration due to their regional lateral continuity, thickness, high porosity and permeability, presence of seal strata and proximity to large point sources of anthropogenic CO2. However, aeolian deposits usually exhibit inherent internal complexities induced by migrating bedforms of different sizes and their resulting bounding surfaces. Therefore, CO2 plume migration in such complex media should be well defined and successively linked in models for better characterization of the plume behavior. Based on an outcrop analog of the upper Navajo Sandstone in the western flank of the San Rafael Swell, Utah, we identified five different bedform types with dune and interdune facies to represent the spatial continuity of lithofacies units. Using generated 3D geometrical facies patterns of cross-bedded structures in the Navajo Sandstone, we performed numerical simulations to understand the detailed behavior of CO2 plume migration under the different cross-bedded bedforms. Our numerical simulation results indicate that cross-bedded structures (bedform types) play an important role on governing the rate and directionality of CO2 migration, resulting in changes of imbibition processes of CO2. CO2 migration tends to follow wind ripple laminations and reactivation surfaces updip. Our results suggest that geologically-based upscaling of CO2 migration is crucial in cross-bedded formations as part of reservoir or basin scale models. Furthermore, comparative modeling studies between 3D models and 2D cross-sections extracted from 3D models showed the significant three-dimensional interplay in a cross-bedded structure and the need to correctly capture the geologic heterogeneity to predict realistic CO2 plume behavior. Our outcrop analog approach presented in this study also demonstrates an alternative method for assessing geologic

Sequence stratigraphy of the Aux Vases Sandstone: A major oil producer in the Illinois basin

USGS Publications Warehouse

Leetaru, H.E.

2000-01-01

The Aux Vases Sandstone (Mississippian) has contributed between 10 and 25% of all the oil produced in Illinois. The Aux Vases is not only an important oil reservoir but is also an important source of groundwater, quarrying stone, and fluorspar. Using sequence stratigraphy, a more accurate stratigraphic interpretation of this economically important formation can be discerned and thereby enable more effective exploration for the resources contained therein. Previous studies have assumed that the underlying Spar Mountain, Karnak, and Joppa formations interfingered with the Aux Vases, as did the overlying Renault Limestone. This study demonstrates that these formations instead are separated by sequence boundaries; therefore, they are not genetically related to each other. A result of this sequence stratigraphic approach is the identification of incised valleys, paleotopography, and potential new hydrocarbon reservoirs in the Spar Mountain and Aux Vases. In eastern Illinois, the Aux Vases is bounded by sequence boundaries with 20 ft (6 m) of relief. The Aux Vases oil reservoir facies was deposited as a tidally influenced siliciclastic wedge that prograded over underlying carbonate-rich sediments. The Aux Vases sedimentary succession consists of offshore sediment overlain by intertidal and supratidal sediments. Low-permeability shales and carbonates typically surround the Aux Vases reservoir sandstone and thereby form numerous bypassed compartments from which additional oil can be recovered. The potential for new significant oil fields within the Aux Vases is great, as is the potential for undrained reservoir compartments within existing Aux Vases fields.

Deep Subseafloor Fungi as an Untapped Reservoir of Amphipathic Antimicrobial Compounds.

PubMed

Navarri, Marion; Jégou, Camille; Meslet-Cladière, Laurence; Brillet, Benjamin; Barbier, Georges; Burgaud, Gaëtan; Fleury, Yannick

2016-03-10

The evolving global threat of antimicrobial resistance requires a deep renewal of the antibiotic arsenal including the isolation and characterization of new drugs. Underexplored marine ecosystems may represent an untapped reservoir of novel bioactive molecules. Deep-sea fungi isolated from a record-depth sediment core of almost 2000 m below the seafloor were investigated for antimicrobial activities. This antimicrobial screening, using 16 microbial targets, revealed 33% of filamentous fungi synthesizing bioactive compounds with activities against pathogenic bacteria and fungi. Interestingly, occurrence of antimicrobial producing isolates was well correlated with the complexity of the habitat (in term of microbial richness), as higher antimicrobial activities were obtained at specific layers of the sediment core. It clearly highlights complex deep-sea habitats as chemical battlefields where synthesis of numerous bioactive compounds appears critical for microbial competition. The six most promising deep subseafloor fungal isolates were selected for the production and extraction of bioactive compounds. Depending on the fungal isolates, antimicrobial compounds were only biosynthesized in semi-liquid or solid-state conditions as no antimicrobial activities were ever detected using liquid fermentation. An exception was made for one fungal isolate, and the extraction procedure designed to extract amphipathic compounds was successful and highlighted the amphiphilic profile of the bioactive metabolites.

Simulated Last Glacial Maximum Δ14CATM and the Deep Glacial Ocean Reservoir

NASA Astrophysics Data System (ADS)

Mariotti, V.; Paillard, D.; Roche, D. M.; Bouttes, N.; Bopp, L.

2012-12-01

Δ14Catm has been estimated at 420 ± 80‰ (INTCAL09) during the Last Glacial Maximum (LGM) compared to preindustrial times (0‰), but mechanisms explaining this difference are not yet resolved. Δ14Catm is a function of cosmogenic production in high atmosphere and of carbon cycling in the Earth system (through carbon exchange with the superficial reservoirs, ocean and continental biosphere). 10Be-based reconstructions show a contribution of the cosmogenic production term of only 200 ± 200‰ at the LGM. The remaining 220‰ of Δ14Catm variation between the LGM and preindustrial times have thus to be explained by changes in the carbon cycle. Recently, Bouttes et al. (2010) proposed to explain most of the difference in atmospheric pCO2 between glacial and interglacial times by brine-induced ocean stratification in the Southern Ocean. This mechanism involves the formation of very saline water masses that can store Dissolved Inorganic Carbon (DIC) in the deep ocean. During glacial times, the sinking of brines is enhanced and more DIC is stored in the deep ocean, lowering atmospheric pCO2. Such an isolated ocean reservoir would be characterized by a low Δ14C signature. Evidence of such 14C-depleted deep waters during the LGM has recently been found in the Southern Ocean (Skinner et al., 2010). The degassing of this carbon with low Δ14C would then reduce Δ14Catm throughout the deglaciation. We have further developed the CLIMBER-2 model to include a cosmogenic production of 14C as well as an interactive atmospheric 14C reservoir. We investigate the role of both sinking of brines and cosmogenic production, alongside iron and vertical diffusion mechanisms to explain changes in Δ14Catm during the last deglaciation. In our simulations, not only the sinking of brine mechanism is consistent with past Δ14C data but also it explains most of the differences in atmospheric pCO2 and Δ14C between LGM and preindustrial times.

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

Micro- and macro-scale petrophysical characterization of potential reservoir units from the Northern Israel

NASA Astrophysics Data System (ADS)

Haruzi, Peleg; Halisch, Matthias; Katsman, Regina; Waldmann, Nicolas

2016-04-01

Lower Cretaceous sandstone serves as hydrocarbon reservoir in some places over the world, and potentially in Hatira formation in the Golan Heights, northern Israel. The purpose of the current research is to characterize the petrophysical properties of these sandstone units. The study is carried out by two alternative methods: using conventional macroscopic lab measurements, and using CT-scanning, image processing and subsequent fluid mechanics simulations at a microscale, followed by upscaling to the conventional macroscopic rock parameters (porosity and permeability). Comparison between the upscaled and measured in the lab properties will be conducted. The best way to upscale the microscopic rock characteristics will be analyzed based the models suggested in the literature. Proper characterization of the potential reservoir will provide necessary analytical parameters for the future experimenting and modeling of the macroscopic fluid flow behavior in the Lower Cretaceous sandstone.

Depositional and diagenetic variability within the Cambrian Mount Simon Sandstone: Implications for carbon dioxide sequestration

USGS Publications Warehouse

Bowen, B.B.; Ochoa, R.I.; Wilkens, N.D.; Brophy, J.; Lovell, T.R.; Fischietto, N.; Medina, C.R.; Rupp, J.A.

2011-01-01

The Cambrian Mount Simon Sandstone is the major target reservoir for ongoing geologic carbon dioxide (CO2) sequestration demonstrations throughout the midwest United States. The potential CO2 reservoir capacity, reactivity, and ultimate fate of injected CO2 depend on textural and compositional properties determined by depositional and diagenetic histories that vary vertically and laterally across the formation. Effective and efficient prediction and use of the available pore space requires detailed knowledge of the depositional and diagenetic textures and mineralogy, how these variables control the petrophysical character of the reservoir, and how they vary spatially. Here, we summarize the reservoir characteristics of the Mount Simon Sandstone based on examination of geophysical logs, cores, cuttings, and analysis of more than 150 thin sections. These samples represent different parts of the formation and depth ranges of more than 9000 ft (>2743 m) across the Illinois Basin and surrounding areas. This work demonstrates that overall reservoir quality and, specifically, porosity do not exhibit a simple relationship with depth, but vary both laterally and with depth because of changes in the primary depositional facies, framework composition (i.e., feldspar concentration), and diverse diagenetic modifications. Diagenetic processes that have been significant in modifying the reservoir include formation of iron oxide grain coatings, chemical compaction, feldspar precipitation and dissolution, multiple generations of quartz overgrowth cementation, clay mineral precipitation, and iron oxide cementation. These variables provide important inputs for calculating CO2 capacity potential, modeling reactivity, and are also an important baseline for comparisons after CO2 injection. Copyright ??2011. The American Association of Petroleum Geologists/Division of Environmental Geosciences. All rights reserved.

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

Characterization of the deep microbial life in the Altmark natural gas reservoir

NASA Astrophysics Data System (ADS)

Morozova, D.; Alawi, M.; Vieth-Hillebrand, A.; Kock, D.; Krüger, M.; Wuerdemann, H.; Shaheed, M.

2010-12-01

Within the framework of the CLEAN project (CO2 Largescale Enhanced gas recovery in the Altmark Natural gas field) technical basics with special emphasis on process monitoring are explored by injecting CO2 into a gas reservoir. Our study focuses on the investigation of the in-situ microbial community of the Rotliegend natural gas reservoir in the Altmark, located south of the city Salzwedel, Germany. In order to characterize the microbial life in the extreme habitat we aim to localize and identify microbes including their metabolism influencing the creation and dissolution of minerals. The ability of microorganisms to speed up dissolution and formation of minerals might result in changes of the local permeability and the long-term safety of CO2 storage. However, geology, structure and chemistry of the reservoir rock and the cap rock as well as interaction with saline formation water and natural gases and the injected CO2 affect the microbial community composition and activity. The reservoir located at the depth of approximately 3500 m, is characterised by high salinity (420 g/l) and temperatures up to 127°C. It represents an extreme environment for microbial life and therefore the main focus is on hyperthermophilic, halophilic anaerobic microorganisms. In consequence of the injection of large amounts of CO2 in the course of a commercial EGR (Enhanced Gas Recovery), the environmental conditions (e.g. pH, temperature, pressure and solubility of minerals) for the autochthonous microorganisms will change. Genetic profiling of amplified 16S rRNA genes are applied for detecting structural changes in the community by using PCR- SSCP (PCR-Single-Strand-Conformation Polymorphism), DGGE (Denaturing Gradient Gel Electrophoresis) and 16S rRNA cloning. First results of the baseline survey indicate the presence of microorganisms similar to representatives from other deep environments. The sequence analyses revealed the presence of several H2-oxidising bacteria (Hydrogenophaga sp

Diagenesis and porosity evolution of tight sand reservoirs in Carboniferous Benxi Formation, Southeast Ordos Basin

NASA Astrophysics Data System (ADS)

Hu, Peng; Yu, Xinghe; Shan, Xin; Su, Dongxu; Wang, Jiao; Li, Yalong; Shi, Xin; Xu, Liqiang

2016-04-01

The Ordos Basin, situated in west-central China, is one of the oldest and most important fossil-fuel energy base, which contains large reserves of coal, oil and natural gas. The Upper Palaeozoic strata are widely distributed with rich gas-bearing and large natural gas resources, whose potential is tremendous. Recent years have witnessed a great tight gas exploration improvement of the Upper Paleozoic in Southeastern Ordos basin. The Carboniferous Benxi Formation, mainly buried more than 2,500m, is the key target strata for hydrocarbon exploration, which was deposited in a barrier island and tidal flat environment. The sandy bars and flats are the favorable sedimentary microfacies. With an integrated approach of thin-section petrophysics, constant velocity mercury injection test, scanning electron microscopy and X-ray diffractometry, diagenesis and porosity evolution of tight sand reservoirs of Benxi Formation were analyzed in detail. The result shows that the main lithology of sandstone in this area is dominated by moderately to well sorted quartz sandstone. The average porosity and permeability is 4.72% and 1.22mD. The reservoirs of Benxi Formation holds a variety of pore types and the pore throats, with obvious heterogeneity and poor connection. Based on the capillary pressure curve morphological characteristics and parameters, combined with thin section and phycical property data, the reservoir pore structure of Benxi Formation can be divided into 4 types, including mid pore mid throat type(I), mid pore fine throat type(II), small pore fine throat type(III) and micro pro micro throat type(Ⅳ). The reservoirs primarily fall in B-subsate of middle diagenesis and late diagenesis, which mainly undergo compaction, cmentation, dissolution and fracturing process. Employing the empirical formula of different sorting for unconsolideated sandstone porosity, the initial sandstone porosity is 38.32% on average. Quantitative evaluation of the increase and decrease of

Hydropressure tongues within regionally geopressured lower Tuscaloosa sandstone, Tuscaloosa trend, Louisiana

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

McCulloh, R.P.; Purcell, M.D.

1983-09-01

A regional study of the Tuscaloosa Formation in Louisiana, undertaken to assess geopressured-geothermal potential, revealed lobate, downdip extensions of the hydropressured zone in lower Tuscaloosa massive sandstone facies below the regional top of geopressure. Normal pressure zones within geopressured section were identified by drilling-mud weights less than 13 lb/gal on electric logs of massive lower Tuscaloosa sandstone; cross section demonstrated updip continuity of these zones with the regional hydropressured zone. These hydropressure tongues are permitted by the anomalously high permeabilities reported from the deep Tuscaloosa trend, and they are attributed to both primary and secondary porosity by investigators of Tuscaloosamore » sandstone petrography. The hydropressure tongues correspond with lobes of thick net sandstone, principally in Pointe Coupee, East Felinicana, East Baton Rouge, and Livingston Parishes in the central Tuscaloosa trend. Limited control suggests at least one hydropressure tongue in the Chandeleur Sound area to the east. Dimensions of hydropressure tongues range up to 27 km (17 mi) parallel to srike and 17 km (11 mi) oblique to strike. In many places, tongues are terminated downdip by faults, which, by acting as pressure seals, prevent the tongues from extending to the downdip edge of the massive sandstone in the expanded sections of the downthrown blocks. The areal extent of geopressured Tuscaloosa sandstone is controlled updip by these fault zones, and downdip by pinch-out of the sandstone units basinward. Local hydropressure tongues diminish the geopressured-geothermal potential of the Tuscaloosa trend, but show no discernible relation to gas-productive areas.« less

Experimental investigation of geochemical and mineralogical effects of CO2 sequestration on flow characteristics of reservoir rock in deep saline aquifers

PubMed Central

Rathnaweera, T. D.; Ranjith, P. G.; Perera, M. S. A.

2016-01-01

Interactions between injected CO2, brine, and rock during CO2 sequestration in deep saline aquifers alter their natural hydro-mechanical properties, affecting the safety, and efficiency of the sequestration process. This study aims to identify such interaction-induced mineralogical changes in aquifers, and in particular their impact on the reservoir rock’s flow characteristics. Sandstone samples were first exposed for 1.5 years to a mixture of brine and super-critical CO2 (scCO2), then tested to determine their altered geochemical and mineralogical properties. Changes caused uniquely by CO2 were identified by comparison with samples exposed over a similar period to either plain brine or brine saturated with N2. The results show that long-term reaction with CO2 causes a significant pH drop in the saline pore fluid, clearly due to carbonic acid (as dissolved CO2) in the brine. Free H+ ions released into the pore fluid alter the mineralogical structure of the rock formation, through the dissolution of minerals such as calcite, siderite, barite, and quartz. Long-term CO2 injection also creates a significant CO2 drying-out effect and crystals of salt (NaCl) precipitate in the system, further changing the pore structure. Such mineralogical alterations significantly affect the saline aquifer’s permeability, with important practical consequences for the sequestration process. PMID:26785912

Facies heterogeneity, pay continuity, and infill potential in barrier-island, fluvial, and submarine fan reservoirs: examples from the Texas Gulf Coast and Midland basins

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

Ambrose, W.A.; Tyler, N.

1989-03-01

Three reservoirs representing different depositional environments - barrier island (West Ranch field, south-central Texas), fluvial (La Gloria field, south Texas), and submarine fan (Spraberry trend, Midland basin) - illustrate variations in reservoir continuity. Pay continuity methods based on facies geometry and variations in permeability and thickness between wells can quantify reservoir heterogeneity in each of these examples. Although barrier-island reservoirs are relatively homogeneous, West Ranch field contains wide (1000-5000 ft or 300-1500 m) dip-parallel belts of lenticular inlet-fill facies that disrupt reservoir continuity in the main barrier-core facies. Other reservoir compartments in West Ranch field are in flood-tidal delta depositsmore » partly encased in lagoonal mudstones updip of the barrier core. Fluvial reservoirs have a higher degree of internal complexity than barrier-island reservoirs. In La Gloria field, reservoirs exhibit significant heterogeneity in the form of numerous sandstone stringers bounded vertically and laterally by thin mudstone layers. Successful infill wells in La Gloria field contact partly drained reservoir compartments in splay deposits that pinch out laterally into flood-plain mudstones. Recompletions in vertically isolated sandstone stringers in La Gloria field contact other reservoir compartments. Submarine fan deposits are extremely heterogeneous and may have the greatest potential for infill drilling to tap isolated compartments in clastic reservoirs. The Spraberry trend contains thin discontinuous reservoir sandstones deposited in complex mid-fan channels. Although facies relationships in Spraberry reservoirs are similar to those in fluvial reservoirs in La Gloria field, individual pay stringers are thinner and more completely encased in low-permeability mudstone facies.« less

Effect of chemical environment and rock composition on fracture mechanics properties of reservoir lithologies in context of CO2 sequestration

NASA Astrophysics Data System (ADS)

Major, J. R.; Eichhubl, P.; Callahan, O. A.

2015-12-01

The coupled chemical and mechanical response of reservoir and seal rocks to injection of CO2 have major implications on the short and long term security of sequestered carbon. Many current numerical models evaluating behavior of reservoirs and seals during and after CO2 injection in the subsurface consider chemistry and mechanics separately and use only simple mechanical stability criteria while ignoring time-dependent failure parameters. CO2 injection irreversibly alters the subsurface chemical environment which can then affect geomechanical properties on a range of time scales by altering rock mineralogy and cements through dissolution, remobilization, and precipitation. It has also been documented that geomechanical parameters such as fracture toughness (KIC) and subcritical index (SCI) are sensitive to chemical environment. Double torsion fracture mechanics testing of reservoir lithologies under controlled environmental conditions relevant to CO2 sequestration show that chemical environment can measurably affect KIC and SCI. This coupled chemical-mechanical behavior is also influenced by rock composition, grains, amount and types of cement, and fabric. Fracture mechanics testing of the Aztec Sandstone, a largely silica-cemented, subarkose sandstone demonstrate it is less sensitive to chemical environment than Entrada Sandstone, a silty, clay-rich sandstone. The presence of de-ionized water lowers KIC by approximately 20% and SCI 30% in the Aztec Sandstone relative to tests performed in air, whereas the Entrada Sandstone shows reductions on the order of 70% and 90%, respectively. These results indicate that rock composition influences the chemical-mechanical response to deformation, and that the relative chemical reactivity of target reservoirs should be recognized in context of CO2 sequestration. In general, inert grains and cements such as quartz will be less sensitive to the changing subsurface environment than carbonates and clays.

Geohydrology of the Navajo sandstone in western Kane, southwestern Garfield, and southeastern Iron counties, Utah

USGS Publications Warehouse

Freethey, G.W.

1988-01-01

The upper Navajo and Lamb Point aquifers in the Navajo Sandstone are the principal source of water for the city of Kanab, irrigation, stock, and for rural homes in the study area. Well logs and outcrop descriptions indicate the Navajo Sandstone consists of the Lamb Point Tongue and an unnamed upper member that are separated by the Tenney Canyon Tongue of the Kayenta Formation. The main Kayenta Formation underlies the Lamb Point Tongue. The Lamb Point Tongue and the upper member of the Navajo Sandstone are saturated and hydraulically connected through the Tenney Canyon Tongue. Available data indicate that precipitation percolates to the groundwater reservoir where the Navajo Sandstone crops out. Estimates of the rate of recharge at the outcrop range from 0.1 to as much as 2.8 in/yr. Water level data indicate that water moves from the upper member of the Navajo Sandstone, through the Tenney Canyon Tongue, and into the Lamb Point Tongue. Lateral flow is generally from the outcrop areas toward the incised canyons formed by tributaries of Kanab Creek and Johnson Wash. Direction and rate of groundwater movement and the location and character of the natural hydrologic boundaries in the northern part of the area where the Navajo Sandstone is buried cannot be determined conclusively without additional water level data. (Author 's abstract)

Permeability in fractured rocks from deep geothermal boreholes in the Upper Rhine Graben

NASA Astrophysics Data System (ADS)

Vidal, Jeanne; Whitechurch, Hubert; Genter, Albert; Schmittbuhl, Jean; Baujard, Clément

2015-04-01

Permeability in fractured rocks from deep geothermal boreholes in the Upper Rhine Graben Vidal J.1, Whitechurch H.1, Genter A.2, Schmittbuhl J.1, Baujard C.2 1 EOST, Université de Strasbourg 2 ES-Géothermie, Strasbourg The thermal regime of the Upper Rhine Graben (URG) is characterized by a series of geothermal anomalies on its French part near Soultz-sous-Forêts, Rittershoffen and in the surrounding area of Strasbourg. Sedimentary formations of these areas host oil field widely exploited in the past which exhibit exceptionally high temperature gradients. Thus, geothermal anomalies are superimposed to the oil fields which are interpreted as natural brine advection occurring inside a nearly vertical multi-scale fracture system cross-cutting both deep-seated Triassic sediments and Paleozoic crystalline basement. The sediments-basement interface is therefore very challenging for geothermal industry because most of the geothermal resource is trapped there within natural fractures. Several deep geothermal projects exploit local geothermal energy to use the heat or produce electricity and thus target permeable fractured rocks at this interface. In 1980, a geothermal exploration well was drilled close to Strasbourg down to the Permian sediments at 3220 m depth. Bottom hole temperature was estimated to 148°C but the natural flow rate was too low for an economic profitability (<7 L/s). Petrophysics and reservoir investigations based on core analysis revealed a low matrix porosity with fracture zones spatially isolated and sealed in the sandstone formations. Any stimulation operation was planned and the project was abandoned. The Soultz-sous-Forêts project, initiated in 1986, explored during more than 30 years the experimental geothermal site by drilling five boreholes, three of which extend to 5 km depth. They identified a temperature of 200° C at 5 km depth in the granitic basement but with a variable flow rate. Hydraulic and chemical stimulation operations were

Sequence stratigraphic re-interpretation of [open quotes]stray[close quotes] sandstones in the Cretaceous Mancos Shale, Book Cliffs, Utah: Implications for exploration models

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

Hampson, G.J.; Howell, J.A.; Flint, S.S.

1996-01-01

The Mancos Shale, Book Cliffs, eastern Utah, represents the open marine mudstones of the Cretaceous Western Interior Seaway and contains a number of detached sandstone bodies ([open quotes]Mancos B[close quotes]) which are located 30-150 km down depositional dip from contemporaneous highstand shoreline deposits in the Blackhawk Formation. Examination of these [open quotes]stray[close quotes] sandstones reveals that they do not represent deep water deposition, as previously supposed, but instead comprise three shallow marine facies associations; (1) tidally-influenced fluvial channel fills, (2) fluvially-dominated delta front successions and (3) low-energy shorelines. Tidally-influenced fluvial channel fills are commonly stacked into multistorey bodies at discretemore » stratigraphic levels, thereby defining incised valley fill (IVF) networks. Fluvially-dominated deltas are eroded into by, and lie at the down-dip terminations of, IVFs and are therefore interpreted as falling stage and lowstand shorelines. Low-energy shorelines are inferred to lie along strike from these deltas. The above shallow marine deposits have been mapped at five discrete stratigraphic horizons, which can be either traced or projected up-dip to previously-documented IVFs in the Blackhawk Formation. Their paleocurrents imply that falling stage and lowstand shoreline trends were sub-parallel to mapped highstand shorelines, although there is evidence for a perpendicular lowstand shoreline trend in the east of the study area. This facies and sequence stratigraphic re-interpretation enables predictive exploration modelling of subsurface [open quotes]Mancos B[close quotes] gas reservoir sandstones.« less

Sequence stratigraphic re-interpretation of {open_quotes}stray{close_quotes} sandstones in the Cretaceous Mancos Shale, Book Cliffs, Utah: Implications for exploration models

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

Hampson, G.J.; Howell, J.A.; Flint, S.S.

1996-12-31

The Mancos Shale, Book Cliffs, eastern Utah, represents the open marine mudstones of the Cretaceous Western Interior Seaway and contains a number of detached sandstone bodies ({open_quotes}Mancos B{close_quotes}) which are located 30-150 km down depositional dip from contemporaneous highstand shoreline deposits in the Blackhawk Formation. Examination of these {open_quotes}stray{close_quotes} sandstones reveals that they do not represent deep water deposition, as previously supposed, but instead comprise three shallow marine facies associations; (1) tidally-influenced fluvial channel fills, (2) fluvially-dominated delta front successions and (3) low-energy shorelines. Tidally-influenced fluvial channel fills are commonly stacked into multistorey bodies at discrete stratigraphic levels, thereby definingmore » incised valley fill (IVF) networks. Fluvially-dominated deltas are eroded into by, and lie at the down-dip terminations of, IVFs and are therefore interpreted as falling stage and lowstand shorelines. Low-energy shorelines are inferred to lie along strike from these deltas. The above shallow marine deposits have been mapped at five discrete stratigraphic horizons, which can be either traced or projected up-dip to previously-documented IVFs in the Blackhawk Formation. Their paleocurrents imply that falling stage and lowstand shoreline trends were sub-parallel to mapped highstand shorelines, although there is evidence for a perpendicular lowstand shoreline trend in the east of the study area. This facies and sequence stratigraphic re-interpretation enables predictive exploration modelling of subsurface {open_quotes}Mancos B{close_quotes} gas reservoir sandstones.« less

Hydropressure tongues within regionally geopressured lower Tuscaloosa sandstone, Tuscaloosa trend, Louisiana

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

McCulloh, R.P.; Purcell, M.D.

1983-01-01

A regional study of the Tuscaloosa Formation in Louisiana, undertaken to assess geopressured-geothermal potential, revealed lobate, downdip extensions of the hydropressured zone in lower Tuscaloosa massive sandstone facies below the regional top of geopressure. Normal pressure zones within geopressured section were identified by drilling mud weights less than 13 pounds per gallon on electric logs of massive lower Tuscaloosa sandstone, and cross sections demonstrated updip continuity of these zones with the regional hydropressured zone. These hydropressure tongues are permitted by the anomalously high permeabilities reportd from the deep Tuscaloosa trend which have been attributed to both primary and secondary porosity.more » The hydropressure tongues correspond with lobes of thick net sandstone, principally in Pointe Coupee, East Feliciana, East Baton Rouge, and Livingston Parishes in the central Tuscaloosa trend. Limited control suggests at least one hydropressure tongue in the Chandeleur Sound area to the east.« less

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

An Intensive Survey of Archaeological Resources in the Proposed Long Branch Reservoir. Volume 2B

DTIC Science & Technology

1977-01-01

GcGb - Gneissic Gabbro Hematite TGn - Talc Gneiss c - chipped ShGb - Schistic Gabbro a - scratched ShD - Schistic Dolerite f - flake FH/SS - Flint...Hill Sandstone g - ground Mss - Micaceous Sandstone fss - Ferruginous Sandstone A - Argillite c - chert Qtz - Quartz FGQtt - Fine-grained Quartzite Qtt...ARTIFACTS - LONG BRANCI RESERVOIR 41 0 Points Contracti~ng-@ taed, square-based points l a 23MC55 4-4 50 25 9 9.6g b 23MCSS 2-1 74 39 9 22.8g c

Sedimentological and geophysical studies of clastic reservoir analogs: Methods, applications and developments of ground-penetrating radar for determination of reservoir geometries in near-surface settings. Final report

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

McMechan, G.A.; Soegaard, K.

1998-05-25

An integrated sedimentologic and GPR investigation has been carried out on a fluvial channel sandstone in the mid-Cretaceous Ferron Sandstone at Coyote Basin along the southwestern flank of the San Rafael Uplift in east-central Utah. This near-surface study, which covers a area of 40 {times} 16.5 meters to a depth of 15 meters, integrates detailed stratigraphic data from outcrop sections and facies maps with multi-frequency 3-D GPR surveys. The objectives of this investigation are two-fold: (1) to develop new ground-penetrating radar (GPR) technology for imaging shallow subsurface sandstone bodies, and (2) to construct an empirical three-dimensional sandstone reservoir model suitablemore » for hydrocarbon flow-simulation by imaging near-surface sandstone reservoir analogs with the use of GPR. The sedimentological data base consists of a geologic map of the survey area and a detailed facies map of the cliff face immediately adjacent to the survey area. Five vertical sections were measured along the cliff face adjacent to the survey area. In addition, four wells were cored within the survey area from which logs were recorded. In the sections and well logs primary sedimentary structures were documented along with textural information and permeability data. Gamma-ray profiles were also obtained for all sections and core logs. The sedimentologic and stratigraphic information serves as the basis from which much of the processing and interpretation of the GPR data was made. Three 3-D GPR data sets were collected over the survey area at frequencies of 50 MHZ, 100 MHZ, and 200 MHZ.« less

Geothermometry Mapping of Deep Hydrothermal Reservoirs in Southeastern Idaho: Final Report

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

Mattson, Earl D.; Conrad, Mark; Neupane, Ghanashayam

The Eastern Snake River Plain (ESRP) in southern Idaho is a region of high heat flow. Sustained volcanic activities in the wake of the passage of Yellowstone Hotspot have turned this region into an area with great potential for geothermal resources. Numerous hot springs with temperatures up to 75 ºC are scattered along the margins of the plain. Similarly, several hot-water producing wells and few hot springs are also present within the plain. The geothermal reservoirs in the area are likely to be hosted at depth in the felsic volcanic rocks underneath the thick sequences of basalts within the plainmore » and the Paleozoic rocks underneath both basalts and felsic volcanic rocks along the margins. The heat source to these geothermal resources is thought to be the mid-crustal sill complex which sustains high heat flow in the ESRP. Several thermal anomaly areas are believed to be associated with the local thermal perturbation because of the presence of favorable structural settings. However, it is hypothesized that the pervasive presence of an overlying groundwater aquifer in the region effectively masks thermal signatures of deep-seated geothermal resources. The dilution of deeper thermal water and re-equilibration at lower temperatures are significant challenges for the evaluation of potential resource areas in the ESRP. To address this issue, this project, led by the Idaho National Laboratory (INL), aimed at applying advanced geothermometry tools including temperature-dependent mineral and isotopic equilibria with mixing models that account for processes such as boiling and dilution with shallow groundwater that could affect calculated temperatures of underlying deep thermal waters. Over the past several years, we collected approximately 100 water samples from springs/wells for chemical analysis as well as assembled existing water chemistry data from literature. We applied several geothermometric and geochemical modeling tools to the compositions of ESRP water

Rock Physics and Petrographic Parameters Relationship Within Siliciclastic Rocks: Quartz Sandstone Outcrop Study Case

NASA Astrophysics Data System (ADS)

Syafriyono, S.; Caesario, D.; Swastika, A.; Adlan, Q.; Syafri, I.; Abdurrokhim, A.; Mardiana, U.; Mohamad, F.; Alfadli, M. K.; Sari, V. M.

2018-03-01

Rock physical parameters value (Vp and Vs) is one of fundamental aspects in reservoir characterization as a tool to detect rock heterogenity. Its response is depend on several reservoir conditions such as lithology, pressure and reservoir fluids. The value of Vp and Vs is controlled by grain contact and contact stiffness, a function of clay mineral content and porosity also affected by mineral composition. The study about Vp and Vs response within sandstone and its relationship with petrographic parameters has become important to define anisotrophy of reservoir characteristics distribution and could give a better understanding about local diagenesis that influence clastic reservoir properties. Petrographic analysis and Vp-Vs calculation was carried out to 12 core sample which is obtained by hand-drilling of the outcrop in Sukabumi area, West Java as a part of Bayah Formation. Data processing and interpretation of sedimentary vertical succession showing that this outcrop comprises of 3 major sandstone layers indicating fluvial depositional environment. As stated before, there are 4 petrographic parameters (sorting, roundness, clay mineral content, and grain contact) which are responsible to the differences of shear wave and compressional wave value in this outcrop. Lithology with poor-sorted and well- roundness has Vp value lower than well-sorted and poor-roundness (sub-angular) grain. For the sample with high clay content, Vp value is ranging from 1681 to 2000 m/s and could be getting high until 2190 to 2714 m/s in low clay content sample even though the presence of clay minerals cannot be defined neither as matrix nor cement. The whole sample have suture grain contact indicating telogenesis regime whereas facies has no relationship with Vp and Vs value because of the different type of facies show similar petrographic parameters after diagenesis.

Fluvial reservoir architecture in the Malay Basin: Opportunities and challenges

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

Elias, M.R.; Dharmarajan, K.

1994-07-01

Miocene fluvial sandstones are significant hydrocarbon-bearing reservoirs in the Malay Basin. These include high energy, braided stream deposits of group K, associated with late development of extensional half grabens and relatively lower energy, meandering, and anastomosing channel deposits of group I formed during the subsequent basin sag phase. Group K reservoirs are typically massive, commonly tens of meters thick, and cover an extensive part of the Malay Basin. These reservoirs have good porosity and permeability at shallow burial depths. However, reservoir quality deteriorates rapidly with increasing depth. Lateral and vertical reservoir continuity is generally good within a field, commonly formingmore » a single system. Good water drive enhances recovery. Seismic modeling to determine fluid type and the extent of interfluvial shales is possible due to reservoir homogeneity.« less

Submarine fans: Characteristics, models, classification, and reservoir potential

NASA Astrophysics Data System (ADS)

Shanmugam, G.; Moiola, R. J.

1988-02-01

Submarine-fan sequences are important hydrocarbon reservoirs throughout the world. Submarine-fan sequences may be interpreted from bed-thickness trends, turbidite facies associations, log motifs, and seismic-reflection profiles. Turbidites occurring predominantly in channels and lobes (or sheet sands) constitute the major portion of submarine-fan sequences. Thinning- and thickening-upward trends are suggestive of channel and lobe deposition, respectively. Mounded seismic reflections are commonly indicative of lower-fan depositional lobes. Fan models are discussed in terms of modern and ancient fans, attached and detached lobes, highly efficient and poorly efficient systems, and transverse and longitudinal fans. In general, depositional lobes are considered to be attached to feeder channels. Submarine fans can be classified into four types based on their tectonic settings: (1) immature passive-margin fans (North Sea type); (2) mature passive-margin fans (Atlantic type); (3) active-margin fans (Pacific type); and (4) mixed-setting fans. Immature passive-margin fans (e.g., Balder, North Sea), and active-margin fans (e.g., Navy, Pacific Ocean) are usually small, sand-rich, and possess well developed lobes. Mature passive-margin fans (e.g., Amazon, Atlantic Ocean) are large, mud-rich, and do not develop typical lobes. However, sheet sands are common in the lower-fan regions of mature passive-margin fans. Mixed-setting fans display characteristics of either Atlantic type (e.g., Bengal, Bay of Bengal), or Pacific type (Orinoco, Caribbean), or both. Conventional channel-lobe models may not be applicable to fans associated with mature passive margins. Submarine fans develop primarily during periods of low sea level on both active- and passive-margin settings. Consequently, hydrocarbon-bearing fan sequences are associated generally with global lowstands of sea level. Channel-fill sandstones in most tectonic settings are potential reservoirs. Lobes exhibit the most favorable

Importance of Low Permeability Natural Gas Reservoirs (released in AEO2010)

EIA Publications

2010-01-01

Production from low-permeability reservoirs, including shale gas and tight gas, has become a major source of domestic natural gas supply. In 2008, low-permeability reservoirs accounted for about 40% of natural gas production and about 35% of natural gas consumption in the United States. Permeability is a measure of the rate at which liquids and gases can move through rock. Low-permeability natural gas reservoirs encompass the shale, sandstone, and carbonate formations whose natural permeability is roughly 0.1 millidarcies or below. (Permeability is measured in darcies.)

Sequence stratigraphic controls on reservoir characterization and architecture: case study of the Messinian Abu Madi incised-valley fill, Egypt

NASA Astrophysics Data System (ADS)

Abdel-Fattah, Mohamed I.; Slatt, Roger M.

2013-12-01

Understanding sequence stratigraphy architecture in the incised-valley is a crucial step to understanding the effect of relative sea level changes on reservoir characterization and architecture. This paper presents a sequence stratigraphic framework of the incised-valley strata within the late Messinian Abu Madi Formation based on seismic and borehole data. Analysis of sand-body distribution reveals that fluvial channel sandstones in the Abu Madi Formation in the Baltim Fields, offshore Nile Delta, Egypt, are not randomly distributed but are predictable in their spatial and stratigraphic position. Elucidation of the distribution of sandstones in the Abu Madi incised-valley fill within a sequence stratigraphic framework allows a better understanding of their characterization and architecture during burial. Strata of the Abu Madi Formation are interpreted to comprise two sequences, which are the most complex stratigraphically; their deposits comprise a complex incised valley fill. The lower sequence (SQ1) consists of a thick incised valley-fill of a Lowstand Systems Tract (LST1)) overlain by a Transgressive Systems Tract (TST1) and Highstand Systems Tract (HST1). The upper sequence (SQ2) contains channel-fill and is interpreted as a LST2 which has a thin sandstone channel deposits. Above this, channel-fill sandstone and related strata with tidal influence delineates the base of TST2, which is overlain by a HST2. Gas reservoirs of the Abu Madi Formation (present-day depth ˜3552 m), the Baltim Fields, Egypt, consist of fluvial lowstand systems tract (LST) sandstones deposited in an incised valley. LST sandstones have a wide range of porosity (15 to 28%) and permeability (1 to 5080mD), which reflect both depositional facies and diagenetic controls. This work demonstrates the value of constraining and evaluating the impact of sequence stratigraphic distribution on reservoir characterization and architecture in incised-valley deposits, and thus has an important impact on

Sequence stratigraphic and sedimentologic significance of biogenic structures from a late Paleozoic marginal- to open-marine reservoir, Morrow Sandstone, subsurface of southwest Kansas, USA

USGS Publications Warehouse

Buatois, L.A.; Mangano, M.G.; Alissa, A.; Carr, T.R.

2002-01-01

Integrated ichnologic, sedimentologic, and stratigraphic studies of cores and well logs from Lower Pennsylvanian oil and gas reservoirs (lower Morrow Sandstone, southwest Kansas) allow distinction between fluvio-estuarine and open marine deposits in the Gentzler and Arroyo fields. The fluvio-estuarine facies assemblage is composed of both interfluve and valley-fill deposits, encompassing a variety of depositional environments such as fluvial channel, interfluve paleosol, bay head delta, estuary bay, restricted tidal flat, intertidal channel, and estuary mouth. Deposition in a brackish-water estuarine valley is supported by the presence of a low diversity, opportunistic, impoverished marine ichnofaunal assemblage dominated by infaunal structures, representing an example of a mixed, depauperate Cruziana and Skolithos ichnofacies. Overall distribution of ichnofossils along the estuarine valley was mainly controlled by the salinity gradient, with other parameters, such as oxygenation, substrate and energy, acting at a more local scale. The lower Morrow estuarine system displays the classical tripartite division of wave-dominated estuaries (i.e. seaward-marine sand plug, fine-grained central bay, and sandy landward zone), but tidal action is also recorded. The estuarine valley displays a northwest-southeast trend, draining to the open sea in the southeast. Recognition of valley-fill sandstones in the lower Morrow has implications for reservoir characterization. While the open marine model predicts a "layer-cake" style of facies distribution as a consequence of strandline shoreline progradation, identification of valley-fill sequences points to more compartmentalized reservoirs, due to the heterogeneity created by valley incision and subsequent infill. The open-marine facies assemblage comprises upper, middle, and lower shoreface; offshore transition; offshore; and shelf deposits. In contrast to the estuarine assemblage, open marine ichnofaunas are characterized by a

An assessment on CO2 geosequestration in deep saline formations in the Taihsi Basin, central Taiwan

NASA Astrophysics Data System (ADS)

Cai, Mo-Si; Lin, Andrew T.; Fan, Jhen-Huei

2015-04-01

Geological storage of carbon dioxide (CO2) is to inject and store a large amount of anthropogenic CO2 in deep and sealed porous rocks in order to mitigate the aggravated threat of global climate changes. Borehole and reflection seismic data are used to understand the spatial distribution of suitable CO2 reservoirs and cap rocks in the Taihsi Basin, central Taiwan, where the level of seismicity is low. The Taihsi Basin was a rift basin during the Paleocene to Eocene, followed by a phase of post-rift subsidence during late Oligocene to late Miocene. The loading of the Taiwan mountain belt since late Miocene has turned the Taihsi Basin into a peripheral foreland basin, with strata gently dipping toward the mountain belts in the east. The coastal plain in central Taiwan (Changhua and Yunlin Counties) and its adjacent offshore areas are close to major CO2 emission sources and no active geological structures are found in these areas, making the study area a favorable CO2 storage site. Spatial distribution of formation thickness and depth for CO2 reservoirs and cap rocks indicates three CO2 storage systems existed in the study area. They are: (1) late Miocene to Pliocene Nanchuang Formation and Kueichulin Formation (reservoirs)-Chinshui Shale (seals) system (hereafter abbreviated as NK-C system), (2) early to middle Miocene Shihti Formation and Peiliao Formation (reservoirs)-Talu Shale (seals) system (SP-T system), (3) early Miocene Mushan Formation (reservoirs)-Piling Shale (seals) system (M-P system). The NK-C system contains multiple layers of porous sandstones from Nanchuang and Kueichulin formations, with total thickness around 210-280 m. In the vicinity of the northern bank of the Jhuoshuei River, reservoir top reaches a depth around 1850 m, with 60 m thick seal formation, the Chinshui Shale. However, the Chinshui Shale becomes sand-prone in the Changhua coastal and nearshore areas due to facies changes. The SP-T system consists of two porous sandstone layers from

Development of Discrete Compaction Bands in Two Porous Sandstones

NASA Astrophysics Data System (ADS)

Tembe, S.; Baud, P.; Wong, T.

2003-12-01

Compaction band formation has been documented by recent field and laboratory studies as a localized failure mode occurring in porous sandstones. The coupling of compaction and localization may significantly alter the stress field and strain partitioning, and act as barriers within reservoirs. Two end-members of this failure mode that develop subperpendicular to the maximum principal stress have been identified: numerous discrete compaction bands with a thickness of only several grains, or a few diffuse bands that are significantly thicker. Much of what is known about discrete compaction bands derives from laboratory experiments performed on the relatively homogeneous Bentheim sandstone with 23% porosity. In this study we observe similar compaction localization behavior in the Diemelstadt sandstone, that has an initial porosity of 24.4% and a modal composition of 68% quartz, 26% feldspar, 4% oxides, and 2% micas. CT scans of the Diemelstadt sandstone indicate bedding corresponding to low porosity laminae. Saturated samples cored perpendicular to bedding were deformed at room temperature under drained conditions at a constant pore pressure of 10 MPa and a confining pressure range of 20-175 MPa. Acoustic emission activity and pore volume change were recorded continuously. Samples were deformed to axial strains of 1-4% and recovered from the triaxial cell for microstructural analysis. The mechanical data map the transition in failure mode from brittle faulting to compactive cataclastic flow. The brittle regime occurred at effective pressures up to 40 MPa, associated with failure by conjugate shear bands. At an effective pressure range of 60-175 MPa strain hardening and shear-enhanced compaction were accompanied by the development of discrete compaction bands, that was manifested by episodic surges of acoustic emission. Preliminary microstructural observations of the failed samples suggest that bedding influenced the band orientations which varies between 75-90\\deg

Tyler sandstones (Pennsylvanian), Dickinson area, North Dakota: a 24-million barrel soil-zone stratigraphic trap

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

Land, C.B.

Approximately 24 million bbl of recoverable oil has been found in stratigraphic traps in the lower Pennsylvanian Tyler formation at the Dickinson, South Heart, and E. Green River Fields, Stark County, North Dakota. Production is from a multiple sequence of quartzose sandstones 5 to 18 ft (1.5 to 5 m) thick deposited as barrier islands along regressive shorelines. A typical vertical sequence is given. Throughout much of the subject area, porosity and permeability in the sandstones have been greatly reduced or completely destroyed by development of caliche paleosols. In the western part, the caliche consists of gray to brown limestonemore » nodules or nodular layers of limestone in the sandstones and contains abundant pyrite. It is estimated that the caliche destroys as much as 50% of the potential reservoir rock in the area and is an essential factor in the stratigraphic entrapment of the petroleum accumulations by providing an eastern (updip) barrier to migration.« less

Potential for deep basin-centered gas accumulation in Travis Peak (Hosston) Formation, Gulf Coastal Basin

USGS Publications Warehouse

Bartberger, Charles E.; Dyman, Thaddeus S.; Condon, Steven M.

2003-01-01

The potential of Lower Cretaceous sandstones of the Travis Peak Formation in the northern Gulf Coast Basin to harbor a basin-centered gas accumulation was evaluated by examining (1) the depositional and diagenetic history and reservoir properties of Travis Peak sandstones, (2) the presence and quality of source rocks for generating gas, (3) the burial and thermal history of source rocks and time of gas generation and migration relative to tectonic development of Travis Peak traps, (4) gas and water recoveries from drill-stem and formation tests, (5) the distribution of abnormal pressures based on shut-in-pressure data, and (6) the presence or absence of gas-water contacts associated with gas accumulations in Travis Peak sandstones. The Travis Peak Formation (and correlative Hosston Formation) is a basinward-thickening wedge of terrigenous clastic sedimentary rocks that underlies the northern Gulf Coast Basin from eastern Texas across northern Louisiana to southern Mississippi. Clastic infl ux was focused in two main fl uvial-deltaic depocenters?one located in northeastern Texas and the other in southeastern Mississippi and northeastern Louisiana. Across the main hydrocarbon-productive trend in eastern Texas and northern Louisiana, the Travis Peak Formation is about 2,000 ft thick. Most Travis Peak hydrocarbon production in eastern Texas comes from drilling depths between 6,000 and 10,000 ft. Signifi cant decrease in porosity and permeability occurs through that depth interval. Above 8,000-ft drilling depth in eastern Texas, Travis Peak sandstone matrix permeabilities often are signifi cantly higher than the 0.1-millidarcy (mD) cutoff that characterizes tight-gas reservoirs. Below 8,000 ft, matrix permeability of Travis Peak sandstones is low because of pervasive quartz cementation, but abundant natural fractures impart signifi cant fracture permeability. Although pressure data within the middle and lower Travis Peak Formation are limited in eastern Texas

Structural control on the deep hydrogeological and geothermal aquifers related to the fractured Campanian-Miocene reservoirs of north-eastern Tunisia foreland constrained by subsurface data

NASA Astrophysics Data System (ADS)

Khomsi, Sami; Echihi, Oussema; Slimani, Naji

2012-03-01

A set of different data including high resolution seismic sections, petroleum wire-logging well data, borehole piezometry, structural cross-sections and outcrop analysis allowed us to characterise the tectonic framework, and its relationships with the deep aquifers seated in Cretaceous-Miocene deep reservoirs. The structural framework, based on major structures, controls the occurrence of deep aquifers and sub-basin aquifer distributions. Five structural domains can be defined, having different morphostructural characteristics. The northernmost domain lying on the north-south axis and Zaghouan thrust system is a domain of recharge by underflow of the different subsurface reservoirs and aquifers from outcrops of highly fractured reservoirs. On the other hand, the morphostructural configuration controls the piezometry of underground flows in the Plio-Quaternary unconfined aquifer. In the subsurface the Late Cretaceous-Miocene reservoirs are widespread with high thicknesses in many places and high porosities and connectivities especially along major fault corridors and on the crestal parts of major anticlines. Among all reservoirs, the Oligo-Miocene, detritic series are widespread and present high cumulative thicknesses. Subsurface and fieldwork outline the occurrence of 10 fractured sandy reservoirs for these series with packages having high hydrodynamic and petrophysical characteristics. These series show low salinities (maximum 5 g/l) in the northern part of the study area and will constitute an important source of drinkable water for the next generations. A regional structural cross-section is presented, compiled from all the different data sets, allowing us to define the major characteristics of the hydrogeological-hydrogeothermal sub-basins. Eight hydrogeological provinces are defined from north-west to south-east. A major thermal anomaly is clearly identified in the south-eastern part of the study area in Sfax-Sidi Il Itayem. This anomaly is possibly related to

Geological Carbon Sequestration Storage Resource Estimates for the Ordovician St. Peter Sandstone, Illinois and Michigan Basins, USA

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

Barnes, David; Ellett, Kevin; Leetaru, Hannes

The Cambro-Ordovician strata of the Midwest of the United States is a primary target for potential geological storage of CO2 in deep saline formations. The objective of this project is to develop a comprehensive evaluation of the Cambro-Ordovician strata in the Illinois and Michigan Basins above the basal Mount Simon Sandstone since the Mount Simon is the subject of other investigations including a demonstration-scale injection at the Illinois Basin Decatur Project. The primary reservoir targets investigated in this study are the middle Ordovician St Peter Sandstone and the late Cambrian to early Ordovician Knox Group carbonates. The topic of thismore » report is a regional-scale evaluation of the geologic storage resource potential of the St Peter Sandstone in both the Illinois and Michigan Basins. Multiple deterministic-based approaches were used in conjunction with the probabilistic-based storage efficiency factors published in the DOE methodology to estimate the carbon storage resource of the formation. Extensive data sets of core analyses and wireline logs were compiled to develop the necessary inputs for volumetric calculations. Results demonstrate how the range in uncertainty of storage resource estimates varies as a function of data availability and quality, and the underlying assumptions used in the different approaches. In the simplest approach, storage resource estimates were calculated from mapping the gross thickness of the formation and applying a single estimate of the effective mean porosity of the formation. Results from this approach led to storage resource estimates ranging from 3.3 to 35.1 Gt in the Michigan Basin, and 1.0 to 11.0 Gt in the Illinois Basin at the P10 and P90 probability level, respectively. The second approach involved consideration of the diagenetic history of the formation throughout the two basins and used depth-dependent functions of porosity to derive a more realistic spatially variable model of porosity rather than

Multiphase Flow Characteristics of Heterogeneous Rocks From CO2 Storage Reservoirs in the United Kingdom

NASA Astrophysics Data System (ADS)

Reynolds, Catriona A.; Blunt, Martin J.; Krevor, Samuel

2018-02-01

We have studied the impact of heterogeneity on relative permeability and residual trapping for rock samples from the Bunter sandstone of the UK Southern North Sea, the Ormskirk sandstone of the East Irish Sea, and the Captain sandstone of the UK Northern North Sea. Reservoir condition CO2-brine relative permeability measurements were made while systematically varying the ratio of viscous to capillary flow potential, across a range of flow rates, fractional flow, and during drainage and imbibition displacement. This variation resulted in observations obtained across a range of core-scale capillary number 0.2

Lattice Boltzmann Simulation of Seismic Mobilization of Residual Oil in Sandstone

NASA Astrophysics Data System (ADS)

Guo, R.; Jiang, F.; Deng, W.

2017-12-01

Seismic stimulation is a promising technology for enhanced oil recovery. However, current mechanism studies are mainly in the single constricted tubes or idealized porous media, and no study has been conducted in real reservoir porous media. We have developed a numerical simulation which uses the lattice Boltzmann method to directly calculate the characteristics of residual oil clusters to quantify seismic mobilization of residual oil in real Berea sandstone in a scale of 400μm x 400μm x 400μm. The residual oil clusters will be firstly obtained by applying the water flooding scheme to the oil-saturated sandstone. Then, we will apply the seismic stimulation to the sandstone by converting the seismic effect to oscillatory inertial force and add to the pore fluids. This oscillatory inertial force causes the mobilization of residual oil by overcoming the capillary force. The response of water and oil to the seismic stimulation will be observed in our simulations. Two seismic oil mobilization mechanisms will be investigated: (1) the passive response of residual oil clusters to the seismic stimulation, and (2) the resonance of oil clusters subject to low frequency seismic stimulation. We will then discuss which mechanism should be the dominant mechanism for the seismic stimulation oil recovery for practical applications.

Thermal regime of the deep carbonate reservoir of the Po Plain (Italy)

NASA Astrophysics Data System (ADS)

Pasquale, V.; Chiozzi, P.; Verdoya, M.

2012-04-01

Italy is one of the most important countries in the world with regard to high-medium enthalpy geothermal resources, a large part of which is already extracted at relatively low cost. High temperatures at shallow to medium depth occur within a wide belt, several hundred kilometre long, west of the Apennines mountain chain. This belt, affected by recent lithosphere extension, includes several geothermal fields, which are largely exploited for electricity generation. Between the Alps and Apennines ranges, the deeper aquifer, occurring in carbonate rocks of the Po Plain, can host medium enthalpy fluids, which are exploited for district heating. Such a general picture of the available geothermal resources has been well established through several geophysical investigations and drillings. Nevertheless, additional studies are necessary to evaluate future developments, especially with reference to the deep carbonate aquifer of the Po Plain. In this paper, we focus on the eastern sector of the plain and try to gain a better understanding of the thermal regime by using synergically geothermal methodologies and geological information. The analysis of the temperatures recorded to about 6 km depth in hydrocarbon wells supplies basic constraints to outline the thermal regime of the sedimentary basin and to investigate the occurrence and importance of hydrothermal processes in the carbonate layer. After correction for drilling disturbance, temperatures were analysed, together with geological information, through an inversion technique based on a laterally constant thermal gradient model. The inferred thermal gradient changes with depth; it is quite low within the carbonate layer, while is larger in the overlying, practically impermeable formations. As the thermal conductivity variation does not justify such a thermal gradient difference, the vertical change can be interpreted as due to convective processes occurring in the carbonate layer, acting as thermal reservoir. The

Novel Geothermal Development of Deep Sedimentary Systems in the United States

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

Moore, Joseph; Allis, Rick

Economic and reservoir engineering models show that stratigraphic reservoirs have the potential to contribute significant geothermal power in the U.S. If the reservoir temperature exceeds about 150 – 200 °C at 2 – 4 km depth, respectively, and there is good permeability, then these resources can generate power with a levelized cost of electricity (LCOE) of close to 10 ¢/kWh (without subsidies) on a 100 MW power plant scale. There is considerable evidence from both groundwater geology and petroleum reservoir geology that relatively clean carbonates and sandstones have, and can sustain, the required high permeability to depths of at leastmore » 5 km. This paper identifies four attractive stratigraphic reservoir prospects which are all located in the eastern Great Basin, and have temperatures of 160 – 230 °C at 3 – 3.5 km depth. They are the Elko basins (Nevada), North Steptoe Valley (Nevada), Pavant Butte (Utah), and the Idaho Thrust Belt. The reservoir lithologies are Paleozoic carbonates in the first three, and Jurassic sandstone and carbonate in the Idaho Thrust Belt. All reservoir lithologies are known to have high permeability characteristics. At North Steptoe Valley and Pavant Butte, nearby transmission line options allow interconnection to the California power market. Modern techniques for drilling and developing tight oil and gas reservoirs are expected to have application to geothermal development of these reservoirs.« less

Valley-fill sequences and onlap geometries, Lower Cretaceous Muddy Sandstone, Kitty Field, Powder River basin, Wyoming

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

Gardner, M.H.; Gustason, E.R.

1987-05-01

The Muddy Sandstone at Kitty field is a valley-fill sequence that records a late Albian sea level rise and accompanying transgression. The valley was cut during a preceding sea level lowstand. Stratal geometries and facies successions within the valley fill demonstrate the history of transgression was not gradual and progressive. Rather, the valley fill comprises a series of discrete, time-bounded, depositional units which onlap the erosional surface. Five time-bounded depositional units were defined by facies successions and were used to define onlap geometries. Facies successions within individual units record progressive shoaling. Capping each succession, there may be a planar disconformity,more » a thin bioturbated interval, or the deepest water facies of the next depositional event. Thus, the termination of each depositional event is marked by an episode of rapid deepening. At a single geographic location, stratal successions within older depositional units represent more landward facies than those within younger units. Therefore, the onlap geometry of the valley-fill sequence consists of a landward-stepping arrangement of depositional units. The primary reservoirs within the valley-fill sequence, at Kitty field, are laterally coalesced, channel-belt sandstones at the base and barrier island sandstones at the top. Reservoir sandstones of lesser quality occur within the intermediate estuarine facies. The stacking pattern, developed by onlap of the units, results in multiple pay zones within mid-valley reaches. The boundaries of each depositional unit define a high-resolution, chronostratigraphic correlation of valley-fill strata, a correlation corroborated by bentonites. This correlation method gives an accurate description of the internal geometry of valley-fill strata and, therefore, provides a basis for understanding the process of transgressive onlap.« less

Diagenetic contrast of sandstones in hydrocarbon prospective Mesozoic rift basins (Ethiopia, UK, USA)

NASA Astrophysics Data System (ADS)

Wolela, A.

2014-11-01

Diagenetic studied in hydrocarbon-prospective Mesozoic rift basins were carried out in the Blue Nile Basin (Ethiopia), Ulster Basin (United Kingdom) and Hartford Basin (United States of America). Alluvial fan, single and amalgamated multistorey meandering and braided river, deep and shallow perennial lake, shallow ephemeral lake, aeolian and playa mud-flat are the prominent depositional environments. The studied sandstones exhibit red bed diagenesis. Source area geology, depositional environments, pore-water chemistry and circulation, tectonic setting and burial history controlled the diagenetic evolution. The diagenetic minerals include: facies-related minerals (calcrete and dolocrete), grain-coating clay minerals and/or hematite, quartz and feldspar overgrowths, carbonate cements, hematite, kaolinite, illite-smectite, smectite, illite, chlorite, actinolite, laumontite, pyrite and apatite. Diversity of diagenetic minerals and sequence of diagenetic alteration can be directly related to depositional environment and burial history of the basins. Variation in infiltrated clays, carbonate cements and clay minerals observed in the studied sandstones. The alluvial fan and fluviatile sandstones are dominated by kaolinite, illite calcite and ferroan calcite, whereas the playa and lacustrine sandstones are dominated by illite-smectite, smectite-chlorite, smectite, chlorite, dolomite ferroan dolomite and ankerite. Albite, pyrite and apatite are predominantly precipitated in lacustrine sandstones. Basaltic eruption in the basins modified mechanically infiltrated clays to authigenic clays. In all the studied sandstones, secondary porosity predominates over primary porosity. The oil emplacement inhabited clay authigenesis and generation of secondary porosity, whereas authigenesis of quartz, pyrite and apatite continued after oil emplacement.

Fluid Pressure Variation in a Sedimentary Geothermal Reservoir in the North German Basin: Case Study Groß Schönebeck

NASA Astrophysics Data System (ADS)

Huenges, Ernst; Trautwein, Ute; Legarth, Björn; Zimmermann, Günter

2006-10-01

The Rotliegend of the North German basin is the target reservoir of an interdisciplinary investigation program to develop a technology for the generation of geothermal electricity from low-enthalpy reservoirs. An in situ downhole laboratory was established in the 4.3 km deep well Groβ Schönebeck with the purpose of developing appropriate stimulation methods to increase permeability of deep aquifers by enhancing or creating secondary porosity and flow paths. The goal is to learn how to enhance the inflow performance of a well from a variety of rock types in low permeable geothermal reservoirs. A change in effective stress due to fluid pressure was observed to be one of the key parameters influencing flow properties both downhole and in laboratory experiments on reservoir rocks. Fluid pressure variation was induced using proppant-gel-frac techniques as well as waterfrac techniques in several different new experiments in the borehole. A pressure step test indicates generation and extension of multiple fractures with closure pressures between 6 and 8.4 MPa above formation pressure. In a 24-hour production test 859 m3 water was produced from depth indicating an increase of productivity in comparison with former tests. Different depth sections and transmissibility values were observed in the borehole depending on fluid pressure. In addition, laboratory experiments were performed on core samples from the sandstone reservoir under uniaxial strain conditions, i.e., no lateral strain, constant axial load. The experiments on the borehole and the laboratory scale were realized on the same rock types under comparable stress conditions with similar pore pressure variations. Nevertheless, stress dependences of permeability are not easy to compare from scale to scale. Laboratory investigations reflect permeability variations due to microstructural heterogeneities and the behavior in the borehole is dominated by the generation of connections to large-scale structural patterns.

Numerical simulation of multi-dimensional NMR response in tight sandstone

NASA Astrophysics Data System (ADS)

Guo, Jiangfeng; Xie, Ranhong; Zou, Youlong; Ding, Yejiao

2016-06-01

Conventional logging methods have limitations in the evaluation of tight sandstone reservoirs. The multi-dimensional nuclear magnetic resonance (NMR) logging method has the advantage that it can simultaneously measure transverse relaxation time (T 2), longitudinal relaxation time (T 1) and diffusion coefficient (D). In this paper, we simulate NMR measurements of tight sandstone with different wettability and saturations by the random walk method and obtain the magnetization decays of Carr-Purcell-Meiboom-Gill pulse sequences with different wait times (TW) and echo spacings (TE) under a magnetic field gradient, resulting in D-T 2-T 1 maps by the multiple echo trains joint inversion method. We also study the effects of wettability, saturation, signal-to-noise ratio (SNR) of data and restricted diffusion on the D-T 2-T 1 maps in tight sandstone. The results show that with decreasing wetting fluid saturation, the surface relaxation rate of the wetting fluid gradually increases and the restricted diffusion phenomenon becomes more and more obvious, which leads to the wetting fluid signal moving along the direction of short relaxation and the direction of the diffusion coefficient decreasing in D-T 2-T 1 maps. Meanwhile, the non-wetting fluid position in D-T 2-T 1 maps does not change with saturation variation. With decreasing SNR, the ability to identify water and oil signals based on NMR maps gradually decreases. The wetting fluid D-T 1 and D-T 2 correlations in NMR diffusion-relaxation maps of tight sandstone are obtained through expanding the wetting fluid restricted diffusion models, and are further applied to recognize the wetting fluid in simulated D-T 2 maps and D-T 1 maps.

Origin and heterogeneity of pore sizes in the Mount Simon Sandstone and Eau Claire Formation: Implications for multiphase fluid flow

DOE PAGES

Mozley, Peter S.; Heath, Jason E.; Dewers, Thomas A.; ...

2016-01-01

The Mount Simon Sandstone and Eau Claire Formation represent a principal reservoir - caprock system for wastewater disposal, geologic CO 2 storage, and compressed air energy storage (CAES) in the Midwestern United States. Of primary concern to site performance is heterogeneity in flow properties that could lead to non-ideal injectivity and distribution of injected fluids (e.g., poor sweep efficiency). Using core samples from the Dallas Center Structure, Iowa, we investigate pore structure that governs flow properties of major lithofacies of these formations. Methods include gas porosimetry and permeametry, mercury intrusion porosimetry, thin section petrography, and X-ray diffraction. The lithofacies exhibitmore » highly variable intra- and inter-informational distributions of pore throat and body sizes. Based on pore-throat size, samples fall into four distinct groups. Micropore-throat dominated samples are from the Eau Claire Formation, whereas the macropore-, mesopore-, and uniform-dominated samples are from the Mount Simon Sandstone. Complex paragenesis governs the high degree of pore and pore-throat size heterogeneity, due to an interplay of precipitation, non-uniform compaction, and later dissolution of cements. Furthermore, the cement dissolution event probably accounts for much of the current porosity in the unit. The unusually heterogeneous nature of the pore networks in the Mount Simon Sandstone indicates that there is a greater-than-normal opportunity for reservoir capillary trapping of non-wetting fluids — as quantified by CO 2 and air column heights — which should be taken into account when assessing the potential of the reservoir-caprock system for CO 2 storage and CAES.« less

Flow unit modeling and fine-scale predicted permeability validation in Atokan sandstones: Norcan East Kansas

USGS Publications Warehouse

Bhattacharya, S.; Byrnes, A.P.; Watney, W.L.; Doveton, J.H.

2008-01-01

Characterizing the reservoir interval into flow units is an effective way to subdivide the net-pay zone into layers for reservoir simulation. Commonly used flow unit identification techniques require a reliable estimate of permeability in the net pay on a foot-by-foot basis. Most of the wells do not have cores, and the literature is replete with different kinds of correlations, transforms, and prediction methods for profiling permeability in pay. However, for robust flow unit determination, predicted permeability at noncored wells requires validation and, if necessary, refinement. This study outlines the use o f a spreadsheet-based permeability validation technique to characterize flow units in wells from the Norcan East field, Clark County, Kansas, that produce from Atokan aged fine- to very fine-grained quartzarenite sandstones interpreted to have been deposited in brackish-water, tidally dominated restricted tidal-flat, tidal-channel, tidal-bar, and estuary bay environments within a small incised-valley-fill system. The methodology outlined enables the identification of fieldwide free-water level and validates and refines predicted permeability at 0.5-ft (0.15-m) intervals by iteratively reconciling differences in water saturation calculated from wire-line log and a capillary-pressure formulation that models fine- to very fine-grained sandstone with diagenetic clay and silt or shale laminae. The effectiveness of this methodology was confirmed by successfully matching primary and secondary production histories using a flow unit-based reservoir model of the Norcan East field without permeability modifications. The methodologies discussed should prove useful for robust flow unit characterization of different kinds of reservoirs. Copyright ?? 2008. The American Association of Petroleum Geologists. All rights reserved.

A subtle diagenetic trap in the Cretaceous Glauconite Sandstone of Southwest Alberta

USGS Publications Warehouse

Meshri, I.D.; Comer, J.B.

1990-01-01

Despite the long history of research which documents many studies involving extensive diagenesis, there are a few examples of a fully documented diagenetic trap. In the context of this paper, a trap is a hydrocarbon-bearing reservoir with a seal; because a reservoir without a seal acts as a carrier bed. The difficulty in the proper documentation of diagenetic traps is often due to the lack of: (a) extensive field records on the perforation and production histories, which assist in providing the depth of separation between hydrocarbon production and non-hydrocarbon or water production; and (b) the simultaneous availability of core data from these intervals, which could be studied for the extent and nature of diagenesis. This paper provides documentation for the existence of a diagenetic trap, based on perforation depths, production histories and petrologic data from the cored intervals, in the context of the geologic and stratigraphic setting. Cores from 15 wells and SP logs from 45 wells were carefully correlated and the data on perforated intervals was also acquired. Extensive petrographic work on the collected cores led to the elucidation of a diagenetic trap that separates water overlying and updip from gas downdip. Amoco's Berrymore-Lobstick-Bigoray fields, located near the northeastern edge of the Alberta Basin, are prolific gas producers. The gas is produced from reservoir rock consisting of delta platform deposits formed by coalescing distributary mouth bars. The overlying rock unit is composed of younger distributary channels; although it has a good reservoir quality, it contains and produces water only. The total thickness of the upper, water-bearing and lower gas-bearing sandstone is about 40 ft. The diagenetic seal is composed of a zone 2 to 6 ft thick, located at the base of distributary channels. This zone is cemented with 20-30% ankerite cement, which formed the gas migration and is also relatively early compared to other cements formed in the water

Effect of hydrocarbon to nuclear magnetic resonance (NMR) logging in tight sandstone reservoirs and method for hydrocarbon correction

NASA Astrophysics Data System (ADS)

Xiao, Liang; Mao, Zhi-qiang; Xie, Xiu-hong

2017-04-01

It is crucial to understand the behavior of the T2 distribution in the presence of hydrocarbon to properly interpret pore size distribution from NMR logging. The NMR T2 spectrum is associated with pore throat radius distribution under fully brine saturated. However, when the pore space occupied by hydrocarbon, the shape of NMR spectrum is changed due to the bulk relaxation of hydrocarbon. In this study, to understand the effect of hydrocarbon to NMR logging, the kerosene and transformer oil are used to simulate borehole crude oils with different viscosity. 20 core samples, which were separately drilled from conventional, medium porosity and permeability and tight sands are saturated with four conditions of irreducible water saturation, fully saturated with brine, hydrocarbon-bearing condition and residual oil saturation, and the corresponding NMR experiments are applied to acquire NMR measurements. The residual oil saturation is used to simulate field NMR logging due to the shallow investigation depth of NMR logging. The NMR spectra with these conditions are compared, the results illustrate that for core samples drilled from tight sandstone reservoirs, the shape of NMR spectra have much change once they pore space occupied by hydrocarbon. The T2 distributions are wide, and they are bimodal due to the effect of bulk relaxation of hydrocarbon, even though the NMR spectra are unimodal under fully brine saturated. The location of the first peaks are similar with those of the irreducible water, and the second peaks are close to the bulk relaxation of viscosity oils. While for core samples drilled from conventional formations, the shape of T2 spectra have little changes. The T2 distributions overlap with each other under these three conditions of fully brine saturated, hydrocarbon-bearing and residual oil. Hence, in tight sandstone reservoirs, the shape of NMR logging should be corrected. In this study, based on the lab experiments, seven T2 times of 1ms, 3ms, 10ms, 33ms

Reservoir characterization combining elastic velocities and electrical resistivity measurements

NASA Astrophysics Data System (ADS)

Gomez, Carmen Teresa

2009-12-01

The elastic and electric parameters of rocks that can be obtained from seismic and electromagnetic data depend on porosity, texture, mineralogy, and fluid. However, seismic data seldom allow us to accurately quantify hydrocarbon saturation. On the other hand, in the case of common reservoir rocks (i.e., sandstones and carbonates), resistivity strongly depends on porosity and saturation. Therefore, the recent progress of controlled-source-electromagnetic (CSEM) methods opens new possibilities in identifying and quantifying potential hydrocarbon reservoirs, although its resolution is much lower than that of seismic data. Hence, a combination of seismic and CSEM data arguably offers a powerful means of finally resolving the problem of remote sensing of saturation. The question is how to combine the two data sources (elastic data and electrical resistivity data) to better characterize a reservoir. To address this question, we introduce the concept of P-wave impedance and resistivity templates as a tool to estimate porosity and saturation from well log data. Adequate elastic and resistivity models, according to the lithology, cementation, fluid properties must be chosen to construct these templates. These templates can be upscaled to seismic and CSEM scale using Backus average for seismic data, and total resistance for CSEM data. We also measured velocity and resistivity in Fontainebleau samples in the laboratory. Fontainebleau formation corresponds to clean sandstones (i.e., low clay content). We derived an empirical relation between these P-wave velocity and resistivity at 40MPa effective pressure, which is around 3 km depth at normal pressure gradients. We were not able to test if this relation could be used at well or field data scales (once appropriate upscaling was applied), since we did not have a field dataset over a stiff sandstone reservoir. A relationship between velocity and resistivity laboratory data was also found for a set of carbonates. This expression

Investigations related to scientific deep drilling to study reservoir-triggered earthquakes at Koyna, India

NASA Astrophysics Data System (ADS)

Gupta, Harsh; Purnachandra Rao, N.; Roy, Sukanta; Arora, Kusumita; Tiwari, V. M.; Patro, Prasanta K.; Satyanarayana, H. V. S.; Shashidhar, D.; Mallika, K.; Akkiraju, Vyasulu V.; Goswami, Deepjyoti; Vyas, Digant; Ravi, G.; Srinivas, K. N. S. S. S.; Srihari, M.; Mishra, S.; Dubey, C. P.; Raju, D. Ch. V.; Borah, Ujjal; Chinna Reddy, K.; Babu, Narendra; Rohilla, Sunil; Dhar, Upasana; Sen, Mrinal; Bhaskar Rao, Y. J.; Bansal, B. K.; Nayak, Shailesh

2015-09-01

Artificial water reservoir-triggered earthquakes have continued at Koyna in the Deccan Traps province, India, since the impoundment of the Shivaji Sagar reservoir in 1962. Existing models, to comprehend the genesis of triggered earthquakes, suffer from lack of observations in the near field. To investigate further, scientific deep drilling and setting up a fault zone observatory at depth of 5-7 km is planned in the Koyna area. Prior to undertaking deep drilling, an exploratory phase of investigations has been launched to constrain subsurface geology, structure and heat flow regime in the area that provide critical inputs for the design of the deep borehole observatory. Two core boreholes drilled to depths of 1,522 and 1,196 m have penetrated the Deccan Traps and sampled the granitic basement in the region for the first time. Studies on cores provide new and direct information regarding the thickness of the Deccan Traps, the absence of infra-Trappean sediments and the nature of the underlying basement rocks. Temperatures estimated at a depth of 6 km in the area, made on the basis of heat flow and thermal properties data sets, do not exceed 150 °C. Low-elevation airborne gravity gradient and magnetic data sets covering 5,012 line km, together with high-quality magnetotelluric data at 100 stations, provide both regional information about the thickness of the Deccan Traps and the occurrence of localized density heterogeneities and anomalous conductive zones in the vicinity of the hypocentral zone. Acquisition of airborne LiDAR data to obtain a high-resolution topographic model of the region has been completed over an area of 1,064 km2 centred on the Koyna seismic zone. Seismometers have been deployed in the granitic basement inside two boreholes and are planned in another set of six boreholes to obtain accurate hypocentral locations and constrain the disposition of fault zones.

Provenance and depositional conditions of Cretaceous-Paleogene boundary sandstones from northeastern Mexico

NASA Astrophysics Data System (ADS)

Rehrmann, Stephanie; Augustsson, Carita; Izaguirre Valdez, Rocio Nereyda; Jenchen, Uwe; Schulte, Peter

2012-12-01

We compare Late Maastrichtian siliciclastic sandstone in northeastern Mexico with those representing the Cretaceous-Paleogene (K-Pg) boundary to reveal differences in provenance and depositional conditions between background sedimentation and K-Pg sand. Lithology and compositional variations are presented for the deep-water Burgos Basin and the shallow-water La Popa Basin. The Late Maastrichtian sandstones in the Burgos Basin have sharp lower contacts, contain abundant trace fossils and are separated by meter-thick marl layers. They represent sporadic mass flows from coastal areas separated by long phases of hemipelagic sedimentation. The K-Pg sandstone layers are amalgamated, contain thin marl intercalations only in the uppermost part and trace fossils are present in the top sandstone layer only. Also this succession represents mass-flow deposits, but the sand may have been deposited during a very short period. The La Popa Basin sandstones represent deltaic sedimentation interrupted by submarine channel deposition during the K-Pg boundary transition with abundant rip-up clasts and bioclasts at the base. The sandstones of the Burgos Basin are quartz to akosic wacke dominated by quartz (> 90%) and some feldspar (< 10%) in calcite cement and matrix. Lithic fragments are rare and dominated by chert and bioclasts. Ultra-stable heavy minerals (ZTR = 50-80) and plutonic quartz grains (ca. 40% of the total quartz population) are particularly common in the K-Pg sandstones. In the Maastrichtian sandstones, metamorphic heavy minerals, particularly chlorite, clinozoisite, and tourmaline (20-50% of the heavy mineral population), and metamorphic quartz (80% of the quartz population) have higher abundances. The La Popa sandstones are subarkose to arkose and arkosic wacke and have a high abundance of feldspar (15-30%) and lithic fragments (5-20%), mainly of siltstone and carbonate. The sandstones from both basins have chemical compositions typical for recycling (Zr/Sc = 12-27 and

Genome Sequence of Aeribacillus pallidus Strain GS3372, an Endospore-Forming Bacterium Isolated in a Deep Geothermal Reservoir

PubMed Central

Filippidou, Sevasti; Jaussi, Marion; Junier, Thomas; Wunderlin, Tina; Jeanneret, Nicole; Regenspurg, Simona; Li, Po-E; Lo, Chien-Chi; McMurry, Kim; Gleasner, Cheryl D.; Vuyisich, Momchilo; Chain, Patrick S.

2015-01-01

The genome of strain GS3372 is the first publicly available strain of Aeribacillus pallidus. This endospore-forming thermophilic strain was isolated from a deep geothermal reservoir. The availability of this genome can contribute to the clarification of the taxonomy of the closely related Anoxybacillus, Geobacillus, and Aeribacillus genera. PMID:26316637

Microbial potential for carbon and nutrient cycling in a geogenic supercritical carbon dioxide reservoir: Microbial life in the deep carbonated biosphere

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

Freedman, Adam J. E.; Tan, BoonFei; Thompson, Janelle R.

Microorganisms catalyze carbon cycling and biogeochemical reactions in the deep subsurface and thus may be expected to influence the fate of injected super-critical (sc) CO 2 following geological carbon sequestration (GCS). We hypothesized that natural subsurface scCO 2 reservoirs, which serve as analogs for the long-term fate of sequestered scCO 2 harbor a ‘deep carbonated biosphere’ with carbon cycling potential. We sampled subsurface fluids from scCO 2- water separators at a natural scCO 2 reservoir at McElmo Dome, Colorado for analysis of 16S rRNA gene diversity and metagenome content. Sequence annotations indicated dominance of Sulfurospirillum, Rhizobium, Desulfovibrio and four membersmore » of the Clostridiales family. Genomes extracted from metagenomes using homology and compositional approaches revealed diverse mechanisms for growth and nutrient cycling, including pathways for CO 2 and N 2 fixation, anaerobic respiration, sulfur oxidation, fermentation and potential for metabolic syntrophy. Differences in biogeochemical potential between two production well communities were consistent with differences in fluid chemical profiles, suggesting a potential link between microbial activity and geochemistry. In conclusion, the existence of a microbial ecosystem associated with the McElmo Dome scCO 2 reservoir indicates that potential impacts of the deep biosphere on CO 2 fate and transport should be taken into consideration as a component of GCS planning and modelling.« less

Microbial potential for carbon and nutrient cycling in a geogenic supercritical carbon dioxide reservoir: Microbial life in the deep carbonated biosphere

DOE PAGES

Freedman, Adam J. E.; Tan, BoonFei; Thompson, Janelle R.

2017-05-02

Microorganisms catalyze carbon cycling and biogeochemical reactions in the deep subsurface and thus may be expected to influence the fate of injected super-critical (sc) CO 2 following geological carbon sequestration (GCS). We hypothesized that natural subsurface scCO 2 reservoirs, which serve as analogs for the long-term fate of sequestered scCO 2 harbor a ‘deep carbonated biosphere’ with carbon cycling potential. We sampled subsurface fluids from scCO 2- water separators at a natural scCO 2 reservoir at McElmo Dome, Colorado for analysis of 16S rRNA gene diversity and metagenome content. Sequence annotations indicated dominance of Sulfurospirillum, Rhizobium, Desulfovibrio and four membersmore » of the Clostridiales family. Genomes extracted from metagenomes using homology and compositional approaches revealed diverse mechanisms for growth and nutrient cycling, including pathways for CO 2 and N 2 fixation, anaerobic respiration, sulfur oxidation, fermentation and potential for metabolic syntrophy. Differences in biogeochemical potential between two production well communities were consistent with differences in fluid chemical profiles, suggesting a potential link between microbial activity and geochemistry. In conclusion, the existence of a microbial ecosystem associated with the McElmo Dome scCO 2 reservoir indicates that potential impacts of the deep biosphere on CO 2 fate and transport should be taken into consideration as a component of GCS planning and modelling.« 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

Unraveling the stratigraphy of the Oriskany Sandstone: A necessity in assessing its site-specific carbon sequestration potential

USGS Publications Warehouse

Kostelnik, J.; Carter, K.M.

2009-01-01

The widespread distribution, favorable reservoir characteristics, and depth make the Lower Devonian Oriskany Sandstone a viable sequestration target in the Appalachian Basin. The Oriskany Sandstone is thickest in the structurally complex Ridge and Valley Province, thins toward the northern and western basin margins, and is even absent in other parts of the basin (i.e., the no-sand area of northwestern Pennsylvania). We evaluated four regions using petrographic data, core analyses, and geophysical log analyses. Throughout the entire study area, average porosities range from 1.35 to 14%. The most notable porosity types are primary intergranular, secondary dissolution, and fracture porosity. Intergranular primary porosity dominates at stratigraphic pinch-out zones near the Oriskany no-sand area and at the western limit of the Oriskany Sandstone. Secondary porosity occurs from dissolution of carbonate constituents primarily in the combination-traps natural gas play extending through western Pennsylvania, western West Virginia, and eastern Ohio. Fracture porosity dominates in the central Appalachian Plateau Province and Valley and Ridge Province. Based on average porosity, the most likely regions for successful sequestration in the Oriskany interval are (1) updip from Oriskany Sandstone pinch-outs in eastern Ohio, and (2) western Pennsylvania, western West Virginia, and eastern Ohio where production occurs from a combination of stratigraphic and structural traps. Permeability data, where available, were used to further evaluate the potential of these regions. Permeability ranges from 0.2 to 42.7 md. Stratigraphic pinch-outs at the northern and western limits of the basin have the highest permeabilities. We recommend detailed site assessments when evaluating the sequestration potential of a given injection site based on the variability observed in the Oriskany structure, lithology, and reservoir characteristics. ?? 2009. The American Association of Petroleum Geologists

Depostional systems, provenance, and sequence stratigraphy, Carter and [open quotes]Millerella[close quotes] sandstones of northeast Mississippi

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

Cleaves, A.W. II

1993-09-01

The subsurface [open quotes]Millerella[close quotes] and Carter sandstones (middle Chesterian) of the Black Warrior basin represent the highest units of the thick Muldon clastics deltaic facies tract. Lowstand marine conditions during Carter deposition allowed for southeastwardly progradation of five distinct deltaic lobe complexes onto the stable northern shelf of the basin. With each of these lobes, both an [open quotes]A[close quotes] (upper) and a [open quotes]B[close quotes] (lower) reservoir unit can be identified. The [open quotes]B[close quotes] sandstone produces from delta-front sheet sands, channel-mouth bars, and possible bar fingers of river-dominated deltas. The more prolific [open quotes]A[close quotes] subdivision containsmore » reservoirs in upper delta-plain point bars, crevasse splays, and distributary channel fills. The most easterly of the lobes, preserved in the Bean's Ferry field of Itawamba County, comprises an amalgamated valley-fill facies that removed a maximum of 250 ft (76 m) of lower Bangor platform carbonates. In contrast, the [open quotes]Millerella[close quotes] sandstone is a series of unconnected pods that formed as marine-reworked sand bodies during a eustatic rise in sea level. The average detrital sand grain composition for four cores taken in Monroe County is 94.7% monocrystalline quartz, 2.9% polycrystalline quartz, 1.6% albite feldspar, 0.1% low-rank metamorphic rock fragments, 0.5 chert, and 0.2% muscovite. These data indicate that neither the Ozark uplift nor the Ouachita orogen could have acted as the principal source area for the Carter and [open quotes]Millerella[close quotes] sandstones. More likely, the sedimentary-igneous terrains along the northern margin of the Illinois basin served this function. A major eustatic lowstand brought this mineralogically mature sediment across the Illinois basin through incised valleys to the northern self of the Black Warrior basin.« less

CarbonSAFE Rocky Mountain Phase I : Seismic Characterization of the Navajo Reservoir, Buzzard Bench, Utah

NASA Astrophysics Data System (ADS)

Haar, K. K.; Balch, R. S.; Lee, S. Y.

2017-12-01

The CarbonSAFE Rocky Mountain project team is in the initial phase of investigating the regulatory, financial and technical feasibility of commercial-scale CO2 capture and storage from two coal-fired power plants in the northwest region of the San Rafael Swell, Utah. The reservoir interval is the Jurassic Navajo Sandstone, an eolian dune deposit that at present serves as the salt water disposal reservoir for Ferron Sandstone coal-bed methane production in the Drunkards Wash field and Buzzard Bench area of central Utah. In the study area the Navajo sandstone is approximately 525 feet thick and is at an average depth of about 7000 feet below the surface. If sufficient porosity and permeability exist, reservoir depth and thickness would provide storage for up to 100,000 metric tonnes of CO2 per square mile, based on preliminary estimates. This reservoir has the potential to meet the DOE's requirement of having the ability to store at least 50 million metric tons of CO2 and fulfills the DOE's initiative to develop protocols for commercially sequestering carbon sourced from coal-fired power plants. A successful carbon storage project requires thorough structural and stratigraphic characterization of the reservoir, seal and faults, thereby allowing the creation of a comprehensive geologic model with subsequent simulations to evaluate CO2/brine migration and long-term effects. Target formation lithofacies and subfacies data gathered from outcrop mapping and laboratory analysis of core samples were developed into a geologic model. Synthetic seismic was modeled from this, allowing us to seismically characterize the lithofacies of the target formation. This seismic characterization data was then employed in the interpretation of 2D legacy lines which provided stratigraphic and structural control for more accurate model development of the northwest region of the San Rafael Swell. Developing baseline interpretations such as this are crucial toward long-term carbon storage

Pore-throat radius and tortuosity estimation from formation resistivity data for tight-gas sandstone reservoirs

NASA Astrophysics Data System (ADS)

Ziarani, Ali S.; Aguilera, Roberto

2012-08-01

A new model is proposed for estimation of pore-throat aperture size from formation resistivity factor and permeability data. The model is validated with data from the Mesaverde sandstone using brine salinities ranging from 20,000 to 200,000 ppm. The data analyzed includes various basins such as Green River, Piceance, Sand Wash, Powder River, Uinta, Washakie and Wind River, available in the literature. For pore-throat radii analysis the methodology involves the use of log-log plots of pore-throat radius versus the product of formation resistivity factor and permeability (rT = a(FK)b + c). The model fits over 280 samples from the Mesaverde formation with coefficients of determination varying between 0.95 and 0.99 depending primarily on the type of model used for pore throat radius calculation. The brine salinity has some minor effects on the results. The model can provide better estimates of pore-throat radii if it is calibrated with experimental techniques such as mercury porosimetry. The results show pore-throat radii varying between 0.001 and 5 μm for the Mesaverde tight sandstone; however, most of the samples fall in a range between 0.01 and 1 μm. For tortuosity analysis, the calculation involves the use of product of formation factor and porosity data. Results indicate that the estimated tortuosity values range mainly between 1 and 5. For samples with lower porosities (< 5%), tortuosity values show a wider scatter (between 1 and 8); whereas for samples with larger porosities (> 15%), the scattering in tortuosity decreases significantly. In general, for tortuosity calculation in tight gas sandstone formations, a square root model with a parameter (bf) representing various types of connecting pores, i.e., sheet-like and tubular pores, is recommended.

Karstification at Beskonak dam site and reservoir area, southern Turkey

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

Degirmenci, M.

1993-10-01

Beskonak dam and hydroelectric power plant are planned to be constructed on the Koepruecay river, 40 km east of the Antalya city. In the dam site and reservoir area, Koepruecay Conglomerates of Miocene age and the Beskonak Formation (sandstone-claystone) alternating with each other crop out vertically. Koepruecay conglomerates, with the components of limestone fragments and carbonate texture, are karstic and permeable, whereas the Beskonak Formation is impermeable. At the northern edge of the reservoir area, the Olukkoeprue karst springs discharge at a minimum of 30 m{sup 3}/s. These springs discharge mainly through vertical and subvertical joint systems. Intensive superficial karstificationmore » developed along the joint systems and the terrane reveals columns of rocks, called {open_quotes}fairy chimneys.{close_quotes} Olukkoeprue springs represent the discharge point for a large and continuous system of underground solution cavities. In the Koepruecay basin, there are numerous karstic features within the conglomerates. Within the reservoir area, Kurukoeprue cave, with a length of 530 m, is an example of these caves developed within the conglomerates. In some parts of the reservoir area, where the groundwater level is lower than the surface-river elevation, a highly developed karstification zone is present within the fluctuation range of groundwater between depths of 40 and 50 m. The above-mentioned Kurukoeprue cave is an active cave developed in the dam site and its vicinity. The solution conduits developed along the system of mostly vertical fractures and joints are interconnected, thus giving rise to a three-dimensional conduit network. On the other hand, a majority of these conduits have clay and calcite filling materials. Karstification in the dam site varies with depths exponentially. Data suggest that karstification has a vertical extention as deep as -220 m. 4 refs., 9 figs.« less

Numerical simulation of groundwater movement and managed aquifer recharge from Sand Hollow Reservoir, Hurricane Bench area, Washington County, Utah

USGS Publications Warehouse

Marston, Thomas M.; Heilweil, Victor M.

2012-01-01

The Hurricane Bench area of Washington County, Utah, is a 70 square-mile area extending south from the Virgin River and encompassing Sand Hollow basin. Sand Hollow Reservoir, located on Hurricane Bench, was completed in March 2002 and is operated primarily as a managed aquifer recharge project by the Washington County Water Conservancy District. The reservoir is situated on a thick sequence of the Navajo Sandstone and Kayenta Formation. Total recharge to the underlying Navajo aquifer from the reservoir was about 86,000 acre-feet from 2002 to 2009. Natural recharge as infiltration of precipitation was approximately 2,100 acre-feet per year for the same period. Discharge occurs as seepage to the Virgin River, municipal and irrigation well withdrawals, and seepage to drains at the base of reservoir dams. Within the Hurricane Bench area, unconfined groundwater-flow conditions generally exist throughout the Navajo Sandstone. Navajo Sandstone hydraulic-conductivity values from regional aquifer testing range from 0.8 to 32 feet per day. The large variability in hydraulic conductivity is attributed to bedrock fractures that trend north-northeast across the study area.A numerical groundwater-flow model was developed to simulate groundwater movement in the Hurricane Bench area and to simulate the movement of managed aquifer recharge from Sand Hollow Reservoir through the groundwater system. The model was calibrated to combined steady- and transient-state conditions. The steady-state portion of the simulation was developed and calibrated by using hydrologic data that represented average conditions for 1975. The transient-state portion of the simulation was developed and calibrated by using hydrologic data collected from 1976 to 2009. Areally, the model grid was 98 rows by 76 columns with a variable cell size ranging from about 1.5 to 25 acres. Smaller cells were used to represent the reservoir to accurately simulate the reservoir bathymetry and nearby monitoring wells; larger

Hydrogeology of the Potsdam Sandstone in northern New York

USGS Publications Warehouse

Williams, John H.; Reynolds, Richard J.; Franzi, David A.; Romanowicz, Edwin A.; Paillet, Frederick L.

2010-01-01

The Potsdam Sandstone of Cambrian age forms a transboundary aquifer that extends across northern New York and into southern Quebec. The Potsdam Sandstone is a gently dipping sequence of arkose, subarkose, and orthoquartzite that unconformably overlies Precambrian metamorphic bedrock. The Potsdam irregularly grades upward over a thickness of 450 m from a heterogeneous feldspathic and argillaceous rock to a homogeneous, quartz-rich and matrix-poor rock. The hydrogeological framework of the Potsdam Sandstone was investigated through an analysis of records from 1,500 wells and geophysical logs from 40 wells, and through compilation of GIS coverages of bedrock and surficial geology, examination of bedrock cores, and construction of hydrogeological sections. The upper several metres of the sandstone typically is weathered and fractured and, where saturated, readily transmits groundwater. Bedding-related fractures in the sandstone commonly form sub-horizontal flow zones of relatively high transmissivity. The vertical distribution of sub-horizontal flow zones is variable; spacings of less than 10 m are common. Transmissivity of individual flow zones may be more than 100 m2/d but typically is less than 10 m2/d. High angle fractures, including joints and faults, locally provide vertical hydraulic connection between flow zones. Hydraulic head gradients in the aquifer commonly are downward; a laterally extensive series of sub-horizontal flow zones serve as drains for the groundwater flow system. Vertical hydraulic head differences between shallow and deep flow zones range from 1 m to more than 20 m. The maximum head differences are in recharge areas upgradient from the area where the Chateauguay and Chazy Rivers, and their tributaries, have cut into till and bedrock. Till overlies the sandstone in much of the study area; its thickness is generally greatest in the western part, where it may exceed 50 m. A discontinuous belt of bedrock pavements stripped of glacial drift extends

Pore structure characterization of Chang-7 tight sandstone using MICP combined with N2GA techniques and its geological control factors

NASA Astrophysics Data System (ADS)

Cao, Zhe; Liu, Guangdi; Zhan, Hongbin; Li, Chaozheng; You, Yuan; Yang, Chengyu; Jiang, Hang

2016-11-01

Understanding the pore networks of unconventional tight reservoirs such as tight sandstones and shales is crucial for extracting oil/gas from such reservoirs. Mercury injection capillary pressure (MICP) and N2 gas adsorption (N2GA) are performed to evaluate pore structure of Chang-7 tight sandstone. Thin section observation, scanning electron microscope, grain size analysis, mineral composition analysis, and porosity measurement are applied to investigate geological control factors of pore structure. Grain size is positively correlated with detrital mineral content and grain size standard deviation while negatively related to clay content. Detrital mineral content and grain size are positively correlated with porosity, pore throat radius and withdrawal efficiency and negatively related to capillary pressure and pore-to-throat size ratio; while interstitial material is negatively correlated with above mentioned factors. Well sorted sediments with high debris usually possess strong compaction resistance to preserve original pores. Although many inter-crystalline pores are produced in clay minerals, this type of pores is not the most important contributor to porosity. Besides this, pore shape determined by N2GA hysteresis loop is consistent with SEM observation on clay inter-crystalline pores while BJH pore volume is positively related with clay content, suggesting N2GA is suitable for describing clay inter-crystalline pores in tight sandstones.

Genome Sequence of Aeribacillus pallidus Strain GS3372, an Endospore-Forming Bacterium Isolated in a Deep Geothermal Reservoir.

PubMed

Filippidou, Sevasti; Jaussi, Marion; Junier, Thomas; Wunderlin, Tina; Jeanneret, Nicole; Regenspurg, Simona; Li, Po-E; Lo, Chien-Chi; Johnson, Shannon; McMurry, Kim; Gleasner, Cheryl D; Vuyisich, Momchilo; Chain, Patrick S; Junier, Pilar

2015-08-27

The genome of strain GS3372 is the first publicly available strain of Aeribacillus pallidus. This endospore-forming thermophilic strain was isolated from a deep geothermal reservoir. The availability of this genome can contribute to the clarification of the taxonomy of the closely related Anoxybacillus, Geobacillus, and Aeribacillus genera. Copyright © 2015 Filippidou et al.

The effect of organic acids on wettability of sandstone and carbonate rocks

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

Mwangi, Paulina; Brady, Patrick V.; Radonjic, Mileva

This paper examines the role of crude oil’s organic acid surface active compounds (SAC) in determining the reservoir wettability over a range of salinities and temperatures. To isolate the effects of individual SACs, this project used model oil mixtures of pure decane and single SACs to represent the oleic phase. Due to the large number of experiments in this study, we used wettability measurement method by the modified flotation technique (MFT) to produce fast, reliable, and quantitative results. The results showed that oil wetting by decane increased with temperature for carbonate rocks. Sandstones oil wetting showed little temperature dependency. Themore » presence of long-chained acids in decane increased oil wetting in sandstone and carbonate rocks as salinity was lowered, while the short-chained acid increased water wetting under the same conditions. The effect of organic acids on wettability was slightly enhanced with increasing temperature for all rock types.« less

The effect of organic acids on wettability of sandstone and carbonate rocks

DOE PAGES

Mwangi, Paulina; Brady, Patrick V.; Radonjic, Mileva; ...

2018-02-21

This paper examines the role of crude oil’s organic acid surface active compounds (SAC) in determining the reservoir wettability over a range of salinities and temperatures. To isolate the effects of individual SACs, this project used model oil mixtures of pure decane and single SACs to represent the oleic phase. Due to the large number of experiments in this study, we used wettability measurement method by the modified flotation technique (MFT) to produce fast, reliable, and quantitative results. The results showed that oil wetting by decane increased with temperature for carbonate rocks. Sandstones oil wetting showed little temperature dependency. Themore » presence of long-chained acids in decane increased oil wetting in sandstone and carbonate rocks as salinity was lowered, while the short-chained acid increased water wetting under the same conditions. The effect of organic acids on wettability was slightly enhanced with increasing temperature for all rock types.« less

Reducing production of taste and odor by deep-living cyanobacteria in drinking water reservoirs by regulation of water level.

PubMed

Su, Ming; Jia, Dongmin; Yu, Jianwei; Vogt, Rolf D; Wang, Jingshi; An, Wei; Yang, Min

2017-01-01

Abatement and control of algae, producing toxins and creating taste & odor (T&O) in drinking water sources, is a major challenge for water supply. In this study we proposed a strategy based on water level regulation for the control of odor-producing cyanobacteria in source water. Miyun Reservoir, the main surface water source for Beijing, has been suffering from 2-methylisoborneol (2-MIB) induced T&O problems caused by deep-living Planktothrix sp. since 2002. The biomass of deep-living Planktothrix in Miyun Reservoir was found to be mainly governed by the water depth above its sediment habitat. An algorithm for water level regulation aiming to minimize the risk for T&O in different types of reservoirs is proposed. The study demonstrates that risk for T&O can be minimized by increasing the water level in Miyun Reservoir. The high-risk area can be reduced by about 2.91% (0.61% to 5.76%) of surface area for each meter increase in the water level, when the water level is lower than 145m. More specifically, the water level needs to be raised to higher than 147.7ma.s.l. from 131.0m in order to obtain an acceptable risk level (ARL) of 10%. This management strategy to abate T&O problems is simpler and cheaper to implement compared to traditional physical, chemical and biological techniques. Moreover, it has no apparent negative impact on water quality and aquatic organisms. Copyright © 2016. Published by Elsevier B.V.

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

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

Reservoir studies with geostatistics to forecast performance

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

Tang, R.W.; Behrens, R.A.; Emanuel, A.S.

1991-05-01

In this paper example geostatistics and streamtube applications are presented for waterflood and CO{sub 2} flood in two low-permeability sandstone reservoirs. Thy hybrid approach of combining fine vertical resolution in cross-sectional models with streamtubes resulted in models that showed water channeling and provided realistic performance estimates. Results indicate that the combination of detailed geostatistical cross sections and fine-grid streamtube models offers a systematic approach for realistic performance forecasts.

THERMAL-ENERGY STORAGE IN A DEEP SANDSTONE AQUIFER IN MINNESOTA: FIELD OBSERVATIONS AND THERMAL ENERGY-TRANSPORT MODELING.

USGS Publications Warehouse

Miller, R.T.

1986-01-01

A study of the feasibility of storing heated water in a deep sandstone aquifer in Minnesota is described. The aquifer consists of four hydraulic zones that are areally anisotropic and have average hydraulic conductivities that range from 0. 03 to 1. 2 meters per day. A preliminary axially symmetric, nonisothermal, isotropic, single-phase, radial-flow, thermal-energy-transport model was constructed to investigate the sensitivity of model simulation to various hydraulic and thermal properties of the aquifer. A three-dimensional flow and thermal-energy transport model was constructed to incorporate the areal anisotropy of the aquifer. Analytical solutions of equations describing areally anisotropic groundwater flow around a doublet-well system were used to specify model boundary conditions for simulation of heat injection. The entire heat-injection-testing period of approximately 400 days was simulated. Model-computed temperatures compared favorably with field-recorded temperatures, with differences of no more than plus or minus 8 degree C. For each test cycle, model-computed aquifer thermal efficiency, defined as total heat withdrawn divided by total heat injected, was within plus or minus 2% of the field-calculated values.

The Fault Block Model: A novel approach for faulted gas reservoirs

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

Ursin, J.R.; Moerkeseth, P.O.

1994-12-31

The Fault Block Model was designed for the development of gas production from Sleipner Vest. The reservoir consists of marginal marine sandstone of Hugine Formation. Modeling of highly faulted and compartmentalized reservoirs is severely impeded by the nature and extent of known and undetected faults and, in particular, their effectiveness as flow barrier. The model presented is efficient and superior to other models, for highly faulted reservoir, i.e. grid based simulators, because it minimizes the effect of major undetected faults and geological uncertainties. In this article the authors present the Fault Block Model as a new tool to better understandmore » the implications of geological uncertainty in faulted gas reservoirs with good productivity, with respect to uncertainty in well coverage and optimum gas recovery.« less

Reservoir Identification: Parameter Characterization or Feature Classification

NASA Astrophysics Data System (ADS)

Cao, J.

2017-12-01

The ultimate goal of oil and gas exploration is to find the oil or gas reservoirs with industrial mining value. Therefore, the core task of modern oil and gas exploration is to identify oil or gas reservoirs on the seismic profiles. Traditionally, the reservoir is identify by seismic inversion of a series of physical parameters such as porosity, saturation, permeability, formation pressure, and so on. Due to the heterogeneity of the geological medium, the approximation of the inversion model and the incompleteness and noisy of the data, the inversion results are highly uncertain and must be calibrated or corrected with well data. In areas where there are few wells or no well, reservoir identification based on seismic inversion is high-risk. Reservoir identification is essentially a classification issue. In the identification process, the underground rocks are divided into reservoirs with industrial mining value and host rocks with non-industrial mining value. In addition to the traditional physical parameters classification, the classification may be achieved using one or a few comprehensive features. By introducing the concept of seismic-print, we have developed a new reservoir identification method based on seismic-print analysis. Furthermore, we explore the possibility to use deep leaning to discover the seismic-print characteristics of oil and gas reservoirs. Preliminary experiments have shown that the deep learning of seismic data could distinguish gas reservoirs from host rocks. The combination of both seismic-print analysis and seismic deep learning is expected to be a more robust reservoir identification method. The work was supported by NSFC under grant No. 41430323 and No. U1562219, and the National Key Research and Development Program under Grant No. 2016YFC0601

Denitrifier Community in the Oxygen Minimum Zone of a Subtropical Deep Reservoir

PubMed Central

Yu, Zheng; Yang, Jun; Liu, Lemian

2014-01-01

Denitrification is an important pathway for nitrogen removal from aquatic systems and this could benefit water quality. However, little is known about the denitrifier community composition and key steps of denitrification in the freshwater environments, and whether different bacteria have a role in multiple processes of denitrification reduction. In this study, quantitative PCR, quantitative RT-PCR, clone library and 454 pyrosequencing were used together to investigate the bacterial and denitrifier community in a subtropical deep reservoir during the strongly stratified period. Our results indicated that the narG gene recorded the highest abundance among the denitrifying genes (2.76×109 copies L−1 for DNA and 4.19×108 copies L−1 for RNA), and the lowest value was nosZ gene (7.56×105 copies L−1 for DNA and undetected for RNA). The RNA: DNA ratios indicated that narG gene was the most active denitrifying gene in the oxygen minimum zone of Dongzhen Reservoir. Further, α-, β- and γ- Proteobacteria were the overwhelmingly dominant classes of denitrifier communities. Each functional gene had its own dominant groups which were different at the genus level: the narG gene was dominated by Albidiferax, while nirS gene was dominated by Dechloromonas. The main OTU of nirK gene was Rhodopseudomonas palustris, but for norB and nosZ genes, they were Bacillus and Bradyrhizobium, respectively. These results contribute to the understanding of linkages between denitrifier community, function and how they work together to complete the denitrification process. Studies on denitrifier community and activity may be useful in managing stratified reservoirs for the ecosystem services and aiding in constructing nitrogen budgets. PMID:24664112

Denitrifier community in the oxygen minimum zone of a subtropical deep reservoir.

PubMed

Yu, Zheng; Yang, Jun; Liu, Lemian

2014-01-01

Denitrification is an important pathway for nitrogen removal from aquatic systems and this could benefit water quality. However, little is known about the denitrifier community composition and key steps of denitrification in the freshwater environments, and whether different bacteria have a role in multiple processes of denitrification reduction. In this study, quantitative PCR, quantitative RT-PCR, clone library and 454 pyrosequencing were used together to investigate the bacterial and denitrifier community in a subtropical deep reservoir during the strongly stratified period. Our results indicated that the narG gene recorded the highest abundance among the denitrifying genes (2.76×109 copies L-1 for DNA and 4.19×108 copies L-1 for RNA), and the lowest value was nosZ gene (7.56×105 copies L-1 for DNA and undetected for RNA). The RNA: DNA ratios indicated that narG gene was the most active denitrifying gene in the oxygen minimum zone of Dongzhen Reservoir. Further, α-, β- and γ- Proteobacteria were the overwhelmingly dominant classes of denitrifier communities. Each functional gene had its own dominant groups which were different at the genus level: the narG gene was dominated by Albidiferax, while nirS gene was dominated by Dechloromonas. The main OTU of nirK gene was Rhodopseudomonas palustris, but for norB and nosZ genes, they were Bacillus and Bradyrhizobium, respectively. These results contribute to the understanding of linkages between denitrifier community, function and how they work together to complete the denitrification process. Studies on denitrifier community and activity may be useful in managing stratified reservoirs for the ecosystem services and aiding in constructing nitrogen budgets.

Mineralogy and diagenesis of low-permeability sandstones of Late Cretaceous age, Piceance Creek Basin, northwestern Colorado

USGS Publications Warehouse

Hansley, Paula L.; Johnson, Ronald C.

1980-01-01

This report presents preliminary results of a mineralogic and diagenetic study of some low-permeability sandstones from measured surface sections and cores obtained from drill holes in the Piceance Creek Basin of northwestern Colorado. A documentation of the mineralogy and diagenetic history will aid in the exploration for natural gas and in the development of recovery technology in these low-permability sandstones. These sandstones are in the nonmarine upper part of the Mesaverde Formation (or Group) of Late Cretaceous age and are separated from overlying lower Tertiary rocks by a major regional unconformity. Attention is focused on the sandstone units of the Ohio Creek Member, which directly underlies the unconformity; however, comparisons between the mineralogy of the Ohio Creek strata and that of the underlying sandstone units are made whenever possible. The Ohio Creek is a member of the Hunter Canyon Formation (Mesaverde Group) in the southwestern part of the basin, and the Mesaverde Formation in the southern and central parts of the basin. The detrital mineralogy is fairly constant throughout all of these nonrnarine Cretaceous sandstone units; however, in the southeastern part of the basin, there is an increase in percentage of feldspar, quartzite, and igneous rock fragments in sandstones of the Ohio Creek Member directly underlying the unconformity. In the southwestern part of the basin, sandstones of the Ohio Creek Member are very weathered and are almost-entirely comprised of quartz, chert, and kaolinite. A complex diagenetic history, partly related to the overlying unconformity, appears to be responsible for transforming these sandstones into potential gas reservoirs. The general diagenetic sequence for the entire Upper Cretaceous interval studied is interpreted to be (early to late): early(?) calcite cement, chlorite, quartz overgrowths, calcite cement, secondary porosity, analcime (surface only), kaolinite and illite, and late carbonate cements

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

A multiscale fixed stress split iterative scheme for coupled flow and poromechanics in deep subsurface reservoirs

NASA Astrophysics Data System (ADS)

Dana, Saumik; Ganis, Benjamin; Wheeler, Mary F.

2018-01-01

In coupled flow and poromechanics phenomena representing hydrocarbon production or CO2 sequestration in deep subsurface reservoirs, the spatial domain in which fluid flow occurs is usually much smaller than the spatial domain over which significant deformation occurs. The typical approach is to either impose an overburden pressure directly on the reservoir thus treating it as a coupled problem domain or to model flow on a huge domain with zero permeability cells to mimic the no flow boundary condition on the interface of the reservoir and the surrounding rock. The former approach precludes a study of land subsidence or uplift and further does not mimic the true effect of the overburden on stress sensitive reservoirs whereas the latter approach has huge computational costs. In order to address these challenges, we augment the fixed-stress split iterative scheme with upscaling and downscaling operators to enable modeling flow and mechanics on overlapping nonmatching hexahedral grids. Flow is solved on a finer mesh using a multipoint flux mixed finite element method and mechanics is solved on a coarse mesh using a conforming Galerkin method. The multiscale operators are constructed using a procedure that involves singular value decompositions, a surface intersections algorithm and Delaunay triangulations. We numerically demonstrate the convergence of the augmented scheme using the classical Mandel's problem solution.

The seismo-hydromechanical behavior during deep geothermal reservoir stimulations: open questions tackled in a decameter-scale in situ stimulation experiment

NASA Astrophysics Data System (ADS)

Amann, Florian; Gischig, Valentin; Evans, Keith; Doetsch, Joseph; Jalali, Reza; Valley, Benoît; Krietsch, Hannes; Dutler, Nathan; Villiger, Linus; Brixel, Bernard; Klepikova, Maria; Kittilä, Anniina; Madonna, Claudio; Wiemer, Stefan; Saar, Martin O.; Loew, Simon; Driesner, Thomas; Maurer, Hansruedi; Giardini, Domenico

2018-02-01

In this contribution, we present a review of scientific research results that address seismo-hydromechanically coupled processes relevant for the development of a sustainable heat exchanger in low-permeability crystalline rock and introduce the design of the In situ Stimulation and Circulation (ISC) experiment at the Grimsel Test Site dedicated to studying such processes under controlled conditions. The review shows that research on reservoir stimulation for deep geothermal energy exploitation has been largely based on laboratory observations, large-scale projects and numerical models. Observations of full-scale reservoir stimulations have yielded important results. However, the limited access to the reservoir and limitations in the control on the experimental conditions during deep reservoir stimulations is insufficient to resolve the details of the hydromechanical processes that would enhance process understanding in a way that aids future stimulation design. Small-scale laboratory experiments provide fundamental insights into various processes relevant for enhanced geothermal energy, but suffer from (1) difficulties and uncertainties in upscaling the results to the field scale and (2) relatively homogeneous material and stress conditions that lead to an oversimplistic fracture flow and/or hydraulic fracture propagation behavior that is not representative of a heterogeneous reservoir. Thus, there is a need for intermediate-scale hydraulic stimulation experiments with high experimental control that bridge the various scales and for which access to the target rock mass with a comprehensive monitoring system is possible. The ISC experiment is designed to address open research questions in a naturally fractured and faulted crystalline rock mass at the Grimsel Test Site (Switzerland). Two hydraulic injection phases were executed to enhance the permeability of the rock mass. During the injection phases the rock mass deformation across fractures and within intact rock

Petroleum system and production characteristics of the Muddy (J) Sandstone (Lower Cretaceous) Wattenberg continuous gas field, Denver basin, Colorado

USGS Publications Warehouse

Higley, D.K.; Cox, D.O.; Weimer, R.J.

2003-01-01

Wattenberg field is a continuous-type gas accumulation. Estimated ultimate recovery from current wells is 1.27 tcf of gas from the Lower Cretaceous Muddy (J) Sandstone. Mean gas resources that have the potential to be added to these reserves in the next 30 yr are 1.09 tcf; this will be primarily through infill drilling to recover a greater percentage of gas in place and to drain areas that are isolated because of geologic compartmentalization. Greatest gas production from the Muddy (J) Sandstone in Wattenberg field occurs (1) from within the most permeable and thickest intervals of Fort Collins Member delta-front and nearshore-marine sandstones, (2) to a lesser extent from the Horsetooth Member valley-fill channel sandstones, (3) in association with a large thermal anomaly that is delineated by measured temperatures in wells and by vitrinite reflectance contours of 0.9% and greater, (4) in proximity to the bounding Mowry, Graneros, and Skull Creek shales that are the hydrocarbon source rocks and reservoir seals, and (5) between the Lafayette and Longmont right-lateral wrench fault zones (WFZs) with secondary faults that act as conduits in areas of the field. The axis of greatest gas production is north 25 to 35?? northeast, which parallels the basin axis. Recurrent movement along five right-lateral WFZs that crosscut Wattenberg field shifted the Denver basin axis to the northeast and influenced depositional and erosional patterns of the reservoir and seal intervals. Levels of thermal maturity within the Wattenberg field are anomalously high compared to other areas of the Denver basin. The Wattenberg field thermal anomaly may be due to upward movement of fluids along faults associated with probable igneous intrusions. Areas of anomalous high heat flow within the field correlate with an increased and variable gas-oil ratio.

A multi-tracer study in the Hutton Sandstone aquifer, Australia: How "wrong ages" give us deeper insights into aquifer structure and effective deep recharge to a double porosity system

NASA Astrophysics Data System (ADS)

Suckow, Axel; Taylor, Andrew; Davies, Phil; Leaney, Fred

2017-04-01

assumed to be rejected recharge which discharges through spring complexes in the Surat Basin and contributes to base flow of the Dawson River. This interpretation also suggests: 1) that the Hutton Sandstone aquifer is potentially more vulnerable to impacts from groundwater abstraction, including from stock and domestic water supply and coal seam gas production, than previously anticipated; 2) that other "groundwater age records" around the world likely observe similar double porosity effects and their apparent ages may be similarly distorted; and 3) that the multi-tracer approach used here is a suitable method for identifying other previously unknown double porosity aquifer systems and can potentially quantify deep effective recharge where important water resources are subject of economic development.

Pore structure characterization of Chang-7 tight sandstone using MICP combined with N2GA techniques and its geological control factors

PubMed Central

Cao, Zhe; Liu, Guangdi; Zhan, Hongbin; Li, Chaozheng; You, Yuan; Yang, Chengyu; Jiang, Hang

2016-01-01

Understanding the pore networks of unconventional tight reservoirs such as tight sandstones and shales is crucial for extracting oil/gas from such reservoirs. Mercury injection capillary pressure (MICP) and N2 gas adsorption (N2GA) are performed to evaluate pore structure of Chang-7 tight sandstone. Thin section observation, scanning electron microscope, grain size analysis, mineral composition analysis, and porosity measurement are applied to investigate geological control factors of pore structure. Grain size is positively correlated with detrital mineral content and grain size standard deviation while negatively related to clay content. Detrital mineral content and grain size are positively correlated with porosity, pore throat radius and withdrawal efficiency and negatively related to capillary pressure and pore-to-throat size ratio; while interstitial material is negatively correlated with above mentioned factors. Well sorted sediments with high debris usually possess strong compaction resistance to preserve original pores. Although many inter-crystalline pores are produced in clay minerals, this type of pores is not the most important contributor to porosity. Besides this, pore shape determined by N2GA hysteresis loop is consistent with SEM observation on clay inter-crystalline pores while BJH pore volume is positively related with clay content, suggesting N2GA is suitable for describing clay inter-crystalline pores in tight sandstones. PMID:27830731

Implications of magma transfer between multiple reservoirs on eruption cycling.

PubMed

Elsworth, Derek; Mattioli, Glen; Taron, Joshua; Voight, Barry; Herd, Richard

2008-10-10

Volcanic eruptions are episodic despite being supplied by melt at a nearly constant rate. We used histories of magma efflux and surface deformation to geodetically image magma transfer within the deep crustal plumbing of the Soufrière Hills volcano on Montserrat, West Indies. For three cycles of effusion followed by discrete pauses, supply of the system from the deep crust and mantle was continuous. During periods of reinitiated high surface efflux, magma rose quickly and synchronously from a deflating mid-crustal reservoir (at about 12 kilometers) augmented from depth. During repose, the lower reservoir refilled from the deep supply, with only minor discharge transiting the upper chamber to surface. These observations are consistent with a model involving the continuous supply of magma from the deep crust and mantle into a voluminous and compliant mid-crustal reservoir, episodically valved below a shallow reservoir (at about 6 kilometers).

Effective pressure law for permeability of E-bei sandstones

NASA Astrophysics Data System (ADS)

Li, M.; Bernabé, Y.; Xiao, W.-I.; Chen, Z.-Y.; Liu, Z.-Q.

2009-07-01

Laboratory experiments were conducted to determine the effective pressure law for permeability of tight sandstone rocks from the E-bei gas reservoir, China. The permeability k of five core samples was measured while cycling the confining pressure pc and fluid pressure pf. The permeability data were analyzed using the response-surface method, a statistical model-building approach yielding a representation of k in (pc, pf) space that can be used to determine the effective pressure law, i.e., peff = pc - κpf. The results show that the coefficient κ of the effective pressure law for permeability varies with confining pressure and fluid pressure as well as with the loading or unloading cycles (i.e., hysteresis effect). Moreover, κ took very small values in some of the samples, even possibly lower than the value of porosity, in contradiction with a well-accepted theoretical model. We also reanalyzed a previously published permeability data set on fissured crystalline rocks and found again that the κ varies with pc but did not observe κ values lower than 0.4, a value much larger than porosity. Analysis of the dependence of permeability on effective pressure suggests that the occurrence of low κ values may be linked to the high-pressure sensitivity of E-bei sandstones.

The Collyhurst Sandstone as a secondary storage unit for CCS in the East Irish Sea Basin (UK)

NASA Astrophysics Data System (ADS)

Gamboa, D.; Williams, J. D. O.; Kirk, K.; Gent, C. M. A.; Bentham, M.; Schofield, D. I.

2016-12-01

Carbon Capture and Storage (CCS) is key technology for low-carbon energy and industry. The UK hosts a large CO2 storage potential offshore with an estimated capacity of 78 Gt. The East Irish Sea Basin (EISB) is the key area for CCS in the western UK, with a CO2 storage potential of 1.7 Gt in hydrocarbon fields and in saline aquifers within the Triassic Sherwood Sandstone Formation. However, this theoretical storage capacity does not consider the secondary storage potential in the lower Permian Collyhurst Sandstone Formation. 3D seismic data were used to characterise the Collyhurst Sandstone Formation in the EISB. On the southern basin domain, numerous fault-bound blocks limit the lateral continuity of the sandstone strata, while on the northern domain the sandstones are intersected by less faults. The caprock for the Collyhurst sandstones is variable. The Manchester Marls predominate in the south, transitioning to the St. Bees evaporites towards the north. The evaporites in the EISB cause overburden faults to terminate or detach along Upper Permian strata, limiting the deformation of the underlying reservoir units. Five main storage closures have been identified in the Permian strata. In the southern and central area these are predominantly fault bounded, occurring at depths over 1000m. Despite the higher Collyhurst sandstone thickness in the southern IESB, the dolomitic nature of the caprock constitutes a storage risk in this area. Closures in the northern area are deeper (around 2000-2500m) and wider, reaching areas of 34Km2, and are overlain by evaporitic caprocks. The larger Collyhurst closures to the north underlie large Triassic fields with high storage potential. The spatial overlap favours storage plans including secondary storage units in the EISB. The results of this work also expand the understanding of prospective areas for CO2 sequestration in the East Irish Sea Basin in locations where the primary Sherwood Sandstone Formation is either too shallow

Advanced Reservoir Characterization and Development through High-Resolution 3C3D Seismic and Horizontal Drilling: Eva South Marrow Sand Unit, Texas County, Oklahoma

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

Wheeler,David M.; Miller, William A.; Wilson, Travis C.

2002-03-11

The Eva South Morrow Sand Unit is located in western Texas County, Oklahoma. The field produces from an upper Morrow sandstone, termed the Eva sandstone, deposited in a transgressive valley-fill sequence. The field is defined as a combination structural stratigraphic trap; the reservoir lies in a convex up -dip bend in the valley and is truncated on the west side by the Teepee Creek fault. Although the field has been a successful waterflood since 1993, reservoir heterogeneity and compartmentalization has impeded overall sweep efficiency. A 4.25 square mile high-resolution, three component three-dimensional (3C3D) seismic survey was acquired in order tomore » improve reservoir characterization and pinpoint the optimal location of a new horizontal producing well, the ESU 13-H.« less

Ranking of Texas reservoirs for application of carbon dioxide miscible displacement

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

Ham, J

Of the 431 reservoirs screened, 211 projected revenue that exceeded cost, ie, were profitable. Only the top 154 reservoirs, however, showed a profit greater than 30%. The top 10 reservoirs predicted a profit of at least 80%. Six of the top ten were Gulf Coast sandstones. The reservoirs are representative of the most productive discoveries in Texas; they account for about 72% of the recorded 52 billion barrels oil production in the State. Preliminary evaluation in this study implied that potential production from CO{sub 2}-EOR could be as much as 4 billion barrels. In order to enhance the chances ofmore » achieving this, DOE should consider a targeted outreach program to the specific independent operators controlling the leases. Development of ownership/technical potential maps and an outreach program should be initiated to aid this identification.« less

Seismic sequence stratigraphy and platform to basin reservoir structuring of Lower Cretaceous deposits in the Sidi Aïch-Majoura region (Central Tunisia)

NASA Astrophysics Data System (ADS)

Azaïez, Hajer; Bédir, Mourad; Tanfous, Dorra; Soussi, Mohamed

2007-05-01

In central Tunisia, Lower Cretaceous deposits represent carbonate and sandstone reservoir series that correspond to proven oil fields. The main problems for hydrocarbon exploration of these levels are their basin tectonic configuration and their sequence distribution in addition to the source rock availability. The Central Atlas of Tunisia is characterized by deep seated faults directed northeast-southwest, northwest-southeast and north-south. These faults limit inherited tectonic blocks and show intruded Triassic salt domes. Lower Cretaceous series outcropping in the region along the anticline flanks present platform deposits. The seismic interpretation has followed the Exxon methodologies in the 26th A.A.P.G. Memoir. The defined Lower Cretaceous seismic units were calibrated with petroleum well data and tied to stratigraphic sequences established by outcrop studies. This allows the subsurface identification of subsiding zones and thus sequence deposit distribution. Seismic mapping of these units boundary shows a structuring from a platform to basin blocks zones and helps to understand the hydrocarbon reservoir systems-tract and horizon distribution around these domains.

Anisotropy of permeability of reservoir rocks over Miaoli area, NW Taiwan.

NASA Astrophysics Data System (ADS)

Bo-Siang, Xiong; Loung-Yie, Tsai

2013-04-01

The amount of the CO2 has risen since the Industrial Evolution. In order to reduce the amount of CO2 in atmosphere, CO2 sequestration is considered to be the most effective way. In recent years, research about subsurface storage of CO2 into geological formations has increased rapidly. Assessment of storage capability is needed before selecting a site for sequestration. Porosity and permeability are important assessment factors for CO2 sequestration in reservoir rocks. In order to improve the assessment, reservoir rock properties are important and need to be evaluated in advance. Porosity of sandstone is controlled by texture and degree of cementation, whereas permeability is controlled by pore-throat size, pore types and connectivity of pore throat. Sandstones of Miocene to Pleistocene in Miaoli area, NW Taiwan, were collected in this study. YOKO2 porosity/permeability detector is used to measure their permeability perpendicular and parallel to bedding planes under 3 to 60MPa confining pressure with Helium as media. Optical microscope and scanning electron microscope (SEM) were then used to observe the mineral composition, lithology, texture and pore type of sandstones, so as to explore the influence of rock properties on porosity and anisotropy of permeability, as well as the storage potential for CO2 sequestration in the future. The experimental results show that most of the horizontal permeability exceeds the vertical permeability and the anisotropy increases with increasing confining pressure. Mineral composition of sandstones studied were mainly quartz and lithic with little feldspar content. The pore types were mainly primary pores and micropores in this study. The correlation between quantity of macropores and permeability were higher than total porosity and permeability, mainly due to total porosity contains micropores which contribute little to permeability.

Formation factor in Bentheimer and Fontainebleau sandstones: Theory compared with pore-scale numerical simulations

NASA Astrophysics Data System (ADS)

Ghanbarian, Behzad; Berg, Carl F.

2017-09-01

Accurate quantification of formation resistivity factor F (also called formation factor) provides useful insight into connectivity and pore space topology in fully saturated porous media. In particular the formation factor has been extensively used to estimate permeability in reservoir rocks. One of the widely applied models to estimate F is Archie's law (F = ϕ- m in which ϕ is total porosity and m is cementation exponent) that is known to be valid in rocks with negligible clay content, such as clean sandstones. In this study we compare formation factors determined by percolation and effective-medium theories as well as Archie's law with numerical simulations of electrical resistivity on digital rock models. These digital models represent Bentheimer and Fontainebleau sandstones and are derived either by reconstruction or directly from micro-tomographic images. Results show that the universal quadratic power law from percolation theory accurately estimates the calculated formation factor values in network models over the entire range of porosity. However, it crosses over to the linear scaling from the effective-medium approximation at the porosity of 0.75 in grid models. We also show that the effect of critical porosity, disregarded in Archie's law, is nontrivial, and the Archie model inaccurately estimates the formation factor in low-porosity homogeneous sandstones.

Composition of natural gas and crude oil produced from 10 wells in the Lower Silurian "Clinton" Sandstone, Trumbull County, Ohio: Chapter G.7 in Coal and petroleum resources in the Appalachian basin: distribution, geologic framework, and geochemical character

USGS Publications Warehouse

Burruss, Robert A.; Ryder, Robert T.; Ruppert, Leslie F.; Ryder, Robert T.

2014-01-01

Natural gases and associated crude oils in the “Clinton” sandstone, Medina Group sandstones, and equivalent Tuscarora Sandstone in the northern Appalachian basin are part of a regional, continuous-type or basin-centered accumulation. The origin of the hydrocarbon charge to regional continuoustype accumulations is poorly understood. We have analyzed the molecular and stable isotopic composition of gases and oils produced from 10 wells in the “Clinton” sandstone in Trumbull County, Ohio, in an initial attempt to identify the characteristics of the accumulated fluids. The analyses show that the fluids have remarkably uniform compositions that are similar to previously published analyses of oils (Cole and others, 1987) and gases (Laughrey and Baldasarre, 1998) in Early Silurian reservoirs elsewhere in Ohio; however, geochemical parameters in the oils and gases suggest that the fluids have experienced higher levels of thermal stress than the present-day burial conditions of the reservoir rocks. The crude oils have an unusual geochemical characteristic: they do not contain detectable levels of sterane and triterpane biomarkers. The origin of these absences is unknown.

Heterogeneities of mechanical properties in potential geothermal reservoir rocks of the North German Basin

NASA Astrophysics Data System (ADS)

Reyer, D.; Philipp, S. L.

2012-04-01

Heterogeneous rock properties in terms of layering and complex infrastructure of fault zones are typical phenomena in sedimentary basins such as the North German Basin. To be able to model reservoir stimulation in layered stratifications and to better adapt the drilling strategy to the rock mechanical conditions it is important to have knowledge about the effects of heterogeneous rock properties on fracture propagation and fault zone infrastructure for typical sedimentary reservoir rocks in the North German Basin. Therefore we aim at quantifying these properties by performing structural geological field studies in outcrop analogues combined with laboratory analyses. The field studies in Rotliegend sandstones (Lower Permian), the sandstones of the Middle Bunter (Lower Triassic) and the sandstones of the Upper Keuper (Upper Triassic) focus on 1) host rock fracture systems and 2) fault zone infrastructure. We analyse quantitatively the dimension, geometry, persistence and connectivity of fracture systems separately for host rocks and fault damage zones. The results show that in rocks with distinctive layering (sandstones and shales) natural fractures are often restricted to individual layers, that is, they are stratabound. The probability of fracture arrest seems to depend on the stiffness contrast between the two layers and on the thickness of the softer layer. The field studies are complemented by systematic sampling to obtain mechanical property variations caused by the layering. For the samples we measure the parameters Young's modulus, compressive and tensile strengths, elastic strain energy, density and porosity. The results show that the mechanical properties vary considerably and many samples are clearly anisotropic. That is, samples taken perpendicular to layering commonly have higher strengths but lower stiffnesses than those taken parallel to layering. We combine the results of laboratory analyses and field measurements to specify the mechanical

Delta 37Cl and Characterisation of Petroleum-gas Reservoirs

NASA Astrophysics Data System (ADS)

Woulé Ebongué, V.; Jendrzejewski, N.; Walgenwitz, F.; Pineau, F.; Javoy, M.

2003-04-01

The geochemical characterisation of formation waters from oil/gas fields is used to detect fluid-flow barriers in reservoirs and to reconstruct the system dynamic. During the progression of the reservoir filling, the aquifer waters are pushed by hydrocarbons toward the reservoir bottom and their compositions evolve due to several parameters such as water-rock interactions, mixing with oil-associated waters, physical processes etc. The chemical and isotopic evolution of these waters is recorded in irreducible waters that have been progressively "fossilised" in the oil/gas column. Residual salts precipitated from these waters were recovered. Chloride being the most important dissolved anion in these waters and not involved in diagenetic reactions, its investigation should give insights into the different transport or mixing processes taking place in the sedimentary basin and point out to the formation waters origins. The first aim of our study was to test the Cl-RSA technique (Chlorine Residual Salts Analysis) based on the well-established Sr-RSA technique. The main studied area is a turbiditic sandstone reservoir located in the Lower Congo basin in Angola. Present-day aquifer waters, irreducible waters from sandstone and shale layers as well as drilling mud and salt dome samples were analysed. Formation waters (aquifer and irreducible trapped in shale) show an overall increase of chlorinity with depth. Their δ37Cl values range from -1.11 ppm to +2.30 ppm ± 0.05 ppm/ SMOC. Most Cl-RSA data as well as the δ37Cl obtained on a set of water samples (from different aquifers in the same area) are lower than -0.13 ppm with lower δ37Cl values at shallower depths. In a δ37Cl versus chlorinity diagram, they are distributed along a large range of chlorinity: 21 to 139 g/l, in two distinct groups. (1) Irreducible waters from one of the wells display a positive correlation between chlorinity and the δ37Cl values. (2) In contrary, the majority of δ37Cl measured on aquifers

Conversion of crude oil to methane by a microbial consortium enriched from oil reservoir production waters

PubMed Central

Berdugo-Clavijo, Carolina; Gieg, Lisa M.

2014-01-01

The methanogenic biodegradation of crude oil is an important process occurring in petroleum reservoirs and other oil-containing environments such as contaminated aquifers. In this process, syntrophic bacteria degrade hydrocarbon substrates to products such as acetate, and/or H2 and CO2 that are then used by methanogens to produce methane in a thermodynamically dependent manner. We enriched a methanogenic crude oil-degrading consortium from production waters sampled from a low temperature heavy oil reservoir. Alkylsuccinates indicative of fumarate addition to C5 and C6 n-alkanes were identified in the culture (above levels found in controls), corresponding to the detection of an alkyl succinate synthase encoding gene (assA/masA) in the culture. In addition, the enrichment culture was tested for its ability to produce methane from residual oil in a sandstone-packed column system simulating a mature field. Methane production rates of up to 5.8 μmol CH4/g of oil/day were measured in the column system. Amounts of produced methane were in relatively good agreement with hydrocarbon loss showing depletion of more than 50% of saturate and aromatic hydrocarbons. Microbial community analysis revealed that the enrichment culture was dominated by members of the genus Smithella, Methanosaeta, and Methanoculleus. However, a shift in microbial community occurred following incubation of the enrichment in the sandstone columns. Here, Methanobacterium sp. were most abundant, as were bacterial members of the genus Pseudomonas and other known biofilm forming organisms. Our findings show that microorganisms enriched from petroleum reservoir waters can bioconvert crude oil components to methane both planktonically and in sandstone-packed columns as test systems. Further, the results suggest that different organisms may contribute to oil biodegradation within different phases (e.g., planktonic vs. sessile) within a subsurface crude oil reservoir. PMID:24829563

Characteristics and origin of the relatively high-quality tight reservoir in the Silurian Xiaoheba Formation in the southeastern Sichuan Basin

PubMed Central

Gong, Xiaoxing; Shi, Zejin; Wang, Yong; Tian, Yaming; Li, Wenjie; Liu, Lei

2017-01-01

A mature understanding of the sandstone gas reservoir in the Xiaoheba Formation in the southeastern Sichuan Basin remains lacking. To assess the reservoir characteristics and the origin of the high-quality reservoir in the Xiaoheba Formation, this paper uses systematic field investigations, physical property analysis, thin section identification, scanning electron microscopy and electron microprobe methods. The results indicate that the Xiaoheba sandstone is an ultra-tight and ultra-low permeability reservoir, with an average porosity of 2.97% and an average permeability of 0.56×10−3 μm2. This promising reservoir is mainly distributed in the Lengshuixi and Shuangliuba regions and the latter has a relatively high-quality reservoir with an average porosity of 5.28% and average permeability of 0.53×10−3 μm2. The reservoir space comprises secondary intergranular dissolved pores, moldic pores and fractures. Microfacies, feldspar dissolution and fracture connectivity control the quality of this reservoir. The relatively weak compaction and cementation in the interbedded delta front distal bar and interdistributary bay microfacies indirectly protected the primary intergranular pores and enhanced late-stage dissolution. Late-stage potassium feldspar dissolution was controlled by the early-stage organic acid dissolution intensity and the distance from the hydrocarbon generation center. Early-stage fractures acted as pathways for organic acid migration and were therefore important factors in the formation of the reservoir. Based on these observations, the area to the west of the Shuangliuba and Lengshuixi regions has potential for gas exploration. PMID:28686735

Reservoir management in a hydrodynamic environment, Iagifu-Hedinia area, Southern Highlands, Papua New Guinea

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

Eisenberg, L.I.; Langston, M.V.; Fitzmorris, R.E.

Northwest to southeast regional scale flow in the Toro Sandstone parallels the Papuan Fold and Thrust Belt for a distance of 115 km, passing through Iagifu/Hedinia oil field along the way. This has had a profound effect on oil distribution in the Toro there, having swept the northwest side free of movable oil. A structurally controlled flow restriction causes a local, rapid drop in hydraulic potential, tilting local oil/water contacts up to six degrees and causing the three sandstone members of the Toro to locally behave as separate reservoirs, each with its own hydrocarbon/water contact. Reservoir simulations of Iagifu/Hedinia whichmore » include a flowing aquifer are able to match observed production history. Without a flowing aquifer, simulation predicts greater and earlier water production, and a greater pressure drop in the oil leg than has been observed. Reservoir modeling using a flowing aquifer has allowed downhole, structural targeting of later infill wells to be much closer to the OWC than would otherwise have been thought prudent, and has raised questions as to the potential effectiveness of a downdip water injection scheme. Production results from a small satellite field upstream of the main Iagifu/Hedinia field have shown a sudden increase in water production and reservoir pressure after a long period of pressure decline and no water production. This behavior appears to be due to an influx of higher hydraulic potential from a separate reservoir sand, the influx being brought about by pressure draw down during production and consequent breakdown of fault seal.« less

Redefining fluids relative permeability for reservoir sands. (Osland oil and gas field, offshore Niger Delta, Nigeria)

NASA Astrophysics Data System (ADS)

Richardson, M. A.-A.; Taioli, F.

2018-06-01

Redefining oil and water relative permeability for the evaluation of reservoir sands, a case study of Osland oil and gas field, Offshore Niger Delta, Nigeria has been carried out. The aim of this study is to modify water relative permeability (Kwr) and oil relative permeability (Kor) equations in sandstone units. The objectives are to provide alternative expressions for Kwr and Kor in sandstone units, use the equations as inputs in a simplified water cut (Cw) equation to predict the volume of water that will be associated with the recoverable volume of oil (VRo) in penetrated reservoirs. The relationship between porosity (Φ) and water saturation (Sw) , with the relationship between porosity and hydrocarbon saturation ( Sh), were used to evaluate KWr and Kor in order to predict Cw in the selected reservoirs. Reservoir X in Well D1 shows about 2.0 ×106bbl for VRo and 18.78% for Cw but in D2 it shows about 7.4 ×106bbl and 1.73% for VRo and Cw respectively. Similarly, in Reservoir Y, D1 has about 6.8 ×106bbl of VRo and 0.034% of Cw , but in D2 it has about 9.3 ×106 bbl of VRo and 0.015% of Cw . The results suggest that high Φ with corresponding high Sw resulted in high associated Cw in Reservoir X. The evaluation also confirmed that the decrease in the ratio of oil relative permeability to water relative permeability (Kor /Kwr) corresponds to the increase in Cw . The total recoverable volumes of hydrocarbons from the two wells are estimated at 7.7 ×109cu .ft for gas and at 2.54 ×107bbl for oil. With the present conditions of the two reservoirs, the values of Cw in Reservoir X are low and are extremely low and negligible in Reservoir Y. Reservoir X in Well D1 has a smaller volume of VRo but the Cw is higher than others. Nonetheless, the Cw in Reservoir X is still within acceptable range.

Cross-bedding Related Anisotropy and its Role in the Orientation of Joints in an Aeolian Sandstone

NASA Astrophysics Data System (ADS)

Deng, S.; Cilona, A.; Mapeli, C.; Panfilau, A.; Aydin, A.; Prasad, M.

2014-12-01

Previous research revealed that the cross-bedding related anisotropy in aeolian sandstones affects the orientation of compaction bands, also known as anticracks. We hypothesize that cross-bedding should a have similar influence on the orientation of the joints within the same rock at the same location. To test this hypothesis, we investigated the relationship between the cross-beds and the cross-bed package confined joints in the Jurassic aeolian Aztec Sandstone cropping out in the Valley of Fire State Park, Nevada. The field data demonstrates that the cross-bed package confined joints occur at high-angle to bedding and trend roughly parallel to the dip direction of the cross-beds. This shows that the cross-bed orientation and the associated anisotropy also exert a strong control on the formation and orientation of the joints. In order to characterize the anisotropy due to cross-bedding in the Aztec Sandstone, we measured the P-wave velocities parallel and perpendicular to bedding from 11 samples in the laboratory using a bench-top ultrasonic assembly. The measured P-wave anisotropy is about 13% on average. Based on these results, a numerical model based on the generalized Hooke's law for anisotropic materials is analyzed assuming the cross-bedded sandstone to be transversely isotropic. Using this model, we tested various cross-bed orientations as well as different strain boundary conditions (uniaxial, axisymmetric and triaxial). It is possible to define a boundary condition under which the modeled results roughly match with the observed relationship between cross-bed package confined joints and cross-beds. These results have important implications for fluid flow through aeolian sandstones in reservoirs and aquifers.

Sandstone dykes in siwalik sandstone-sedimentology and basin analysis-subansiri district (NEFA), Eastern Himalaya

NASA Astrophysics Data System (ADS)

Kumar, Surendar; Singh, Trilochan

1982-11-01

Sandstone dykes (including sills) of varied thickness and with tapering ends are present either transecting or (sills) parallel to bedding in the Siwalik sandstone of Arunachal Pradesh (NEFA), Eastern Himalaya. The different sedimentary and microstructural analyses show varied conditions of deposition with changing facies from fluvial channel, to alluvial fan, to coastal plain-fan delta. The non-marine and shallow marine environments are indicated by the presence of organised and disorganised gradation and the presence of sandstone dykes in the interface regions. The orientations of the longer axes of the conglomerate along with the sand bedding indicate palaeoflow.

Time-lapse seismic waveform modelling and attribute analysis using hydromechanical models for a deep reservoir undergoing depletion

NASA Astrophysics Data System (ADS)

He, Y.-X.; Angus, D. A.; Blanchard, T. D.; Wang, G.-L.; Yuan, S.-Y.; Garcia, A.

2016-04-01

Extraction of fluids from subsurface reservoirs induces changes in pore pressure, leading not only to geomechanical changes, but also perturbations in seismic velocities and hence observable seismic attributes. Time-lapse seismic analysis can be used to estimate changes in subsurface hydromechanical properties and thus act as a monitoring tool for geological reservoirs. The ability to observe and quantify changes in fluid, stress and strain using seismic techniques has important implications for monitoring risk not only for petroleum applications but also for geological storage of CO2 and nuclear waste scenarios. In this paper, we integrate hydromechanical simulation results with rock physics models and full-waveform seismic modelling to assess time-lapse seismic attribute resolution for dynamic reservoir characterization and hydromechanical model calibration. The time-lapse seismic simulations use a dynamic elastic reservoir model based on a North Sea deep reservoir undergoing large pressure changes. The time-lapse seismic traveltime shifts and time strains calculated from the modelled and processed synthetic data sets (i.e. pre-stack and post-stack data) are in a reasonable agreement with the true earth models, indicating the feasibility of using 1-D strain rock physics transform and time-lapse seismic processing methodology. Estimated vertical traveltime shifts for the overburden and the majority of the reservoir are within ±1 ms of the true earth model values, indicating that the time-lapse technique is sufficiently accurate for predicting overburden velocity changes and hence geomechanical effects. Characterization of deeper structure below the overburden becomes less accurate, where more advanced time-lapse seismic processing and migration is needed to handle the complex geometry and strong lateral induced velocity changes. Nevertheless, both migrated full-offset pre-stack and near-offset post-stack data image the general features of both the overburden and

Potential seal bypass and caprock storage produced by deformation-band-to-opening-mode-fracture transition at the reservoir/caprock interface

DOE PAGES

Raduha, S.; Butler, D.; Mozley, P. S.; ...

2016-06-18

Here, we examined the potential impact on CO 2 transport of zones of deformation bands in reservoir rock that transition to opening-mode fractures within overlying caprock. Sedimentological and petrophysical measurements were collected along an approximately 5 m × 5 m outcrop of the Slick Rock and Earthy Members of the Entrada Sandstone on the eastern flank of the San Rafael Swell, Utah, USA. Measured deformation band permeability (2 mD) within the reservoir facies is about three orders of magnitude lower than the host sandstone. Average permeability of the caprock facies (0.0005 mD) is about seven orders of magnitude lower thanmore » the host sandstone. Aperture-based permeability estimates of the opening-mode caprock fractures are high (3.3 × 10 7 mD). High-resolution CO 2–H 2O transport models incorporate these permeability data at the millimeter scale. We then varied fault properties at the reservoir/caprock interface between open fractures and deformation bands as part of a sensitivity study. Numerical modeling results suggest that zones of deformation bands within the reservoir strongly compartmentalize reservoir pressures largely blocking lateral, cross-fault flow of supercritical CO 2. Significant vertical CO 2 transport into the caprock occurred in some scenarios along opening-mode fractures. The magnitude of this vertical CO 2 transport depends on the small-scale geometry of the contact between the opening-mode fracture and the zone of deformation bands, as well as the degree to which fractures penetrate caprock. Finally, the presence of relatively permeable units within the caprock allows storage of significant volumes of CO 2, particularly when the fracture network does not extend all the way through the caprock.« less

"Sydney sandstone": Heritage Stone from Australia

NASA Astrophysics Data System (ADS)

Cooper, Barry; Kramar, Sabina

2014-05-01

Sydney is Australia's oldest city being founded in 1788. The city was fortunate to be established on an extensive and a relatively undeformed layer of lithified quartz sandstone of Triassic age that has proved to be an ideal building stone. The stone has been long identified by geologists as the Hawkesbury Sandstone. On the other hand the term "Sydney sandstone" has also been widely used over a long period, even to the extent of being utilised as the title of published books, so its formal designation as a heritage stone will immediately formalise this term. The oldest international usage is believed to be its use in the construction of the Stone Store at Kerikeri, New Zealand (1832-1836). In the late 19th century, public buildings such as hospitals, court houses as well as the prominent Sydney Town Hall, Sydney General Post Office, Art Gallery of New South Wales, State Library of New South Wales as well as numerous schools, churches, office building buildings, University, hotels, houses, retaining walls were all constructed using Sydney sandstone. Innumerable sculptures utilising the gold-coloured stone also embellished the city ranging from decorative friezes and capitals on building to significant monuments. Also in the late 19th and early 20th century, Sydney sandstone was used for major construction in most other major Australian cities especially Melbourne, Adelaide and Brisbane to the extent that complaints were expressed that suitable local stone materials were being neglected. Quarrying of Sydney sandstone continues today. In 2000 it was recorded noted that there were 33 significant operating Sydney sandstone quarries including aggregate and dimension stone operations. In addition sandstone continues to be sourced today from construction sites across the city area. Today major dimension stone producers (eg Gosford Quarries) sell Sydney sandstone not only into the Sydney market but also on national and international markets as cladding and paving products

Sedimentology of the Sbaa oil reservoir in the Timimoun basin (S. Algeria)

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

Mehadi, Z.

1990-05-01

In 1980 oil was discovered in the Timimoun portion of the Sbaa depression in Southern Algeria. Until that time this basin had produced only dry gas. Since the 1980 oil discovery, several wells have been drilled. Data acquired from these wells were analyzed and are presented in this study. The oil reservoir is located within a sandstone interval of the Sbaa formation which has an average thickness of 75 m. The Sbaa lies between the Tournaisian (Lower Carboniferous) silts and the Strunian (uppermost Devonian) shales and sandstones. The sedimentological study reveals that the Sbaa formation contains bimodal facies consisting ofmore » coarse siltstones and fine sandstones. The sequence has been attributed to a deltaic environment developed in the central part of the Ahnet basin. The sources of the associated fluvial system are from the surrounding In-Semmen, Tinessourine, and Arak-Foum-Belrem paleohighs. Thermoluminescence indicates the provenance for the Sbaa sands was the crystalline basement Cambrian and Ordovician sections.« less

Development of deformation band clusters in porous quartz sandstones - Contribution from microstructural analysis and numerical modeling

NASA Astrophysics Data System (ADS)

Philit, S.; Soliva, R.; Chemenda, A. I.

2017-12-01

Because sandstones form good reservoirs for hydrocarbon, water or C02 storage, the understanding of the deformation processes in sandstones is major. The deformation band clusters result from the localization of the deformation in porous sandstones under the form of gathered low-permeability cataclastic deformation bands. It has recently been shown that this localization is favored in extensional tectonics. The clusters measure tens to hundreds of meters in extent and propagate vertically as long as the sandstone is clean. Because the clusters can form several kilometers long networks, they are likely to hamper fluid flow during reservoir exploitation. Yet, the processes of band accumulation linked to the evolution of the clusters to a potential faulting are poorly understood. An integrated study coupling a microscopic analysis of the deformed granular material in clusters from 7 sites in the world and distinct element numerical modeling permits to propose a model for cluster growth. Our microscopic analysis reveals that the clusters display varying degree of cataclasis, with the most important degrees in the bands. This cataclasis is accompanied by porosity reduction (more reduced in thrust Andersonian regime), and increased Particle Size Distribution. This testifies of an important packing and implies an increased number of particle coordination. During deformation, the grain shape is both smoothened and roughened; the averaged values of the roundness and circularity indicate a rapid roughening of the clasts at the first stages of deformation followed by a slight smoothening. The roughening of the clasts in densely packed material induces high friction and strengthens the material. High residual porosity at some band edges suggests a local dilatant behavior of sheared material. Our distinct element numerical models and other particle models in the literature confirm this observation. The development of force chains with low particle coordination at these

Use of seasonal trend decomposition to understand groundwater behaviour in the Permo-Triassic Sandstone aquifer, Eden Valley, UK

NASA Astrophysics Data System (ADS)

Lafare, Antoine E. A.; Peach, Denis W.; Hughes, Andrew G.

2016-02-01

The daily groundwater level (GWL) response in the Permo-Triassic Sandstone aquifers in the Eden Valley, England (UK), has been studied using the seasonal trend decomposition by LOESS (STL) technique. The hydrographs from 18 boreholes in the Permo-Triassic Sandstone were decomposed into three components: seasonality, general trend and remainder. The decomposition was analysed first visually, then using tools involving a variance ratio, time-series hierarchical clustering and correlation analysis. Differences and similarities in decomposition pattern were explained using the physical and hydrogeological information associated with each borehole. The Penrith Sandstone exhibits vertical and horizontal heterogeneity, whereas the more homogeneous St Bees Sandstone groundwater hydrographs characterize a well-identified seasonality; however, exceptions can be identified. A stronger trend component is obtained in the silicified parts of the northern Penrith Sandstone, while the southern Penrith, containing Brockram (breccias) Formation, shows a greater relative variability of the seasonal component. Other boreholes drilled as shallow/deep pairs show differences in responses, revealing the potential vertical heterogeneities within the Penrith Sandstone. The differences in bedrock characteristics between and within the Penrith and St Bees Sandstone formations appear to influence the GWL response. The de-seasonalized and de-trended GWL time series were then used to characterize the response, for example in terms of memory effect (autocorrelation analysis). By applying the STL method, it is possible to analyse GWL hydrographs leading to better conceptual understanding of the groundwater flow. Thus, variation in groundwater response can be used to gain insight into the aquifer physical properties and understand differences in groundwater behaviour.

Tidal dunes versus tidal bars: The sedimentological and architectural characteristics of compound dunes in a tidal seaway, the lower Baronia Sandstone (Lower Eocene), Ager Basin, Spain

NASA Astrophysics Data System (ADS)

Olariu, Cornel; Steel, Ronald J.; Dalrymple, Robert W.; Gingras, Murray K.

2012-11-01

dunes, separated by 10-30 cm of bioturbated muddy sandstone, which migrated over each other in an offlapping, progradational fashion. Each compound-dune complex (the best reservoir rock) thins as it downlaps, at average rates of 3-4 m/km in a dip direction. These reservoir units can be comprised of discrete compartments, each formed by a single compound dune, that extend for 500-1000 m in the direction of the current, and are at least 350-600 m wide in a flow-transverse direction. Distinguishing between tidal bars and tidal dunes in an ancient tidal succession can be difficult because both can contain similar cross-bedded facies and have overlapping thicknesses; however, the internal architecture and sandbody orientations are different. Tidal bars have their long axis almost parallel both to the tidal current direction and to the strike of the lateral-accretion master surfaces. In inshore areas, they are bounded by channels and fine upward. Large compound tidal dunes, in contrast, have their crest oriented approximately normal to the tidal currents and contain a forward-accretion architecture. Coeval channels are uncommon within large, sub-tidal dune fields. The above distinctions are very important to reservoir description and modeling, because the long axis of the intra-reservoir compartments in the two cases will be 90° apart.

Preservation of primary porosity in the Neogene clastic reservoirs of the Surma Basin, Bangladesh

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

Ferdous, H.S.; Renaut, R.W.

1996-01-01

The Surma Basin is a Tertiary sub-basin within the greater Bengal Basin, in N.E. Bangladesh. The Neogene sequence ([approximately]17 km thick) contains the producing hydrocarbon reservoirs with proven gas reserves. These sediments are alternating coarse and fine clastics, representing a complex interfingering of deltaic and marine subenvironments, with the former dominating. The principal reservoir facies are distributary channel-fill sandstones in a lower delta-plain setting. Kailashtila, Beanibazar and Rashidpur, located in anticlinal structures, are major hydrocarbon-producing fields in the E. Surma Basin. Petrographic analysis shows that primary intergranular porosity mainly controls the reservoir quality of these Neogene sands, which occur atmore » a depth of [approximately]3000 m. Most samples show primary pores with about 20% porosity and permeabilities of about 200 mD. The preservation of a higher proportion of primary pores in fine to medium grained sandstones is a result of (1) moderate compaction resulting from overpressuring caused by a higher rate of subsidence and sedimentation, (2) weak cementation, and (3) a general lack of deleterious clays and the presence of some grain-rimming chlorites. The general absence of long and sutured grain contacts also supports these observations. Some of the existing literature suggests that secondary pores are dominant in the Neogene sandy reservoirs of the Bengal Basin; however, they contribute little ([approximately]2%) to the total porosity in the Surma Basin.« less

Preservation of primary porosity in the Neogene clastic reservoirs of the Surma Basin, Bangladesh

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

Ferdous, H.S.; Renaut, R.W.

1996-12-31

The Surma Basin is a Tertiary sub-basin within the greater Bengal Basin, in N.E. Bangladesh. The Neogene sequence ({approximately}17 km thick) contains the producing hydrocarbon reservoirs with proven gas reserves. These sediments are alternating coarse and fine clastics, representing a complex interfingering of deltaic and marine subenvironments, with the former dominating. The principal reservoir facies are distributary channel-fill sandstones in a lower delta-plain setting. Kailashtila, Beanibazar and Rashidpur, located in anticlinal structures, are major hydrocarbon-producing fields in the E. Surma Basin. Petrographic analysis shows that primary intergranular porosity mainly controls the reservoir quality of these Neogene sands, which occur atmore » a depth of {approximately}3000 m. Most samples show primary pores with about 20% porosity and permeabilities of about 200 mD. The preservation of a higher proportion of primary pores in fine to medium grained sandstones is a result of (1) moderate compaction resulting from overpressuring caused by a higher rate of subsidence and sedimentation, (2) weak cementation, and (3) a general lack of deleterious clays and the presence of some grain-rimming chlorites. The general absence of long and sutured grain contacts also supports these observations. Some of the existing literature suggests that secondary pores are dominant in the Neogene sandy reservoirs of the Bengal Basin; however, they contribute little ({approximately}2%) to the total porosity in the Surma Basin.« less

Area of Interest 1, CO 2 at the Interface. Nature and Dynamics of the Reservoir/Caprock Contact and Implications for Carbon Storage Performance

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

Mozley, Peter; Evans, James; Dewers, Thomas

2014-10-31

We examined the influence of geologic features present at the reservoir/caprock interface on the transmission of supercritical CO 2 into and through caprock. We focused on the case of deformation-band faults in reservoir lithologies that intersect the interface and transition to opening-mode fractures in caprock lithologies. Deformation-band faults are exceeding common in potential CO 2 injection units and our fieldwork in Utah indicates that this sort of transition is common. To quantify the impact of these interface features on flow and transport we first described the sedimentology and permeability characteristics of selected sites along the Navajo Sandstone (reservoir lithology) andmore » Carmel Formation (caprock lithology) interface, and along the Slickrock Member (reservoir lithology) and Earthy Member (caprock lithology) of the Entrada Sandstone interface, and used this information to construct conceptual permeability models for numerical analysis. We then examined the impact of these structures on flow using single-phase and multiphase numerical flow models for these study sites. Key findings include: (1) Deformation-band faults strongly compartmentalize the reservoir and largely block cross-fault flow of supercritical CO 2. (2) Significant flow of CO 2 through the fractures is possible, however, the magnitude is dependent on the small-scale geometry of the contact between the opening-mode fracture and the deformation band fault. (3) Due to the presence of permeable units in the caprock, caprock units are capable of storing significant volumes of CO 2, particularly when the fracture network does not extend all the way through the caprock. The large-scale distribution of these deformation-bandfault-to-opening-mode-fractures is related to the curvature of the beds, with greater densities of fractures in high curvature regions. We also examined core and outcrops from the Mount Simon Sandstone and Eau Claire Formation reservoir/caprock interface in order to

Post-depositional alteration of titanomagnetite in a Miocene sandstone, south Texas (U.S.A.)

USGS Publications Warehouse

Reynolds, R.L.

1982-01-01

Petrographic and geochemical studies have yielded information on the time-space relationships of the post-depositional alteration of detrital titanomagnetite (Ti-mt) in fine- to medium-grained sandstone from unoriented core samples (taken below the water table at depths of 30-45 m) of the Miocene Catahoula Sandstone, south Texas. Aqueous sulfide introduced from sour gas reservoirs along a growth fault into part of the Catahoula shortly after deposition resulted in the replacement at the periphery of Ti-mt grains by iron disulfide (FeS2) minerals. Remnants of Ti-mt in cores of the partly sulfidized grains show no evidence of earlier hematitic oxidation. After sulfidization, part of the sandstone body was invaded by oxygenated groundwaters flowing down a shallowly inclined (1??) hydrologic gradient. The boundary between oxidized and reduced facies is clearly defined by the distribution of ferric and ferrous iron minerals, and the concentrations of Mo, U, and Se. In oxidized (light-red) strata that had not been previously subjected to sulfidic-reducing conditions but that are correlative with strata containing FeS2 minerals, Ti-mt has been partly to entirely replaced pseudomorphously by hematite to form martite. The absence of hematitic alteration of Ti-mt in the reduced facies is strong evidence that martite in the oxidized facies formed after deposition. ?? 1982.

Compaction and Permeability Reduction of Castlegate Sandstone under Pore Pressure Cycling

NASA Astrophysics Data System (ADS)

Bauer, S. J.

2014-12-01

We investigate time-dependent compaction and permeability changes by cycling pore pressure with application to compressed air energy storage (CAES) in a reservoir. Preliminary experiments capture the impacts of hydrostatic stress, pore water pressure, pore pressure cycling, chemical, and time-dependent considerations near a borehole in a CAES reservoir analog. CAES involves creating an air bubble in a reservoir. The high pressure bubble serves as a mechanical battery to store potential energy. When there is excess grid energy, bubble pressure is increased by air compression, and when there is energy needed on the grid, stored air pressure is released through turbines to generate electricity. The analog conditions considered are depth ~1 km, overburden stress ~20 MPa and a pore pressure ~10MPa. Pore pressure is cycled daily or more frequently between ~10 MPa and 6 MPa, consistent with operations of a CAES facility at this depth and may continue for operational lifetime (25 years). The rock can vary from initially fully-to-partially saturated. Pore pressure cycling changes the effective stress.Jacketed, room temperature tap water-saturated samples of Castlegate Sandstone are hydrostatically confined (20 MPa) and subjected to a pore pressure resulting in an effective pressure of ~10 MPa. Pore pressure is cycled between 6 to 10 MPa. Sample displacement measurements yielded determinations of volumetric strain and from water flow measurements permeability was determined. Experiments ran for two to four weeks, with 2 to 3 pore pressure cycles per day. The Castlegate is a fluvial high porosity (>20%) primarily quartz sandstone, loosely calcite cemented, containing a small amount of clay.Pore pressure cycling induces compaction (~.1%) and permeability decreases (~20%). The results imply that time-dependent compactive processes are operative. The load path, of increasing and decreasing pore pressure, may facilitate local loosening and grain readjustments that results in the

Reservoir characterization and preliminary modeling of deltaic facies, lower Wilcox, Concordia Parish, Louisiana

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

Schenewerk, P.; Goddard, D.; Echols, J.

The decline in production in several fields in Concordia Parish, Louisiana, has created interest in the economic feasibility of producing the remaining bypassed oil in the lower Wilcox Group. One of these fields, Bee Brake, has been one of the more prolific oil-producing fields in east-central Louisiana. The producing interval, the Minter sandstones, at a depth of about 6,775 ft typically consists of an upper Bee Brake sandstone and a lower Angelina sandstone. A detailed study of a conventional core in the center of the field reveals a 15-ft-thick Minter interval bounded above and below by sealing shales and lignitesmore » of lower delta plain marsh facies. The upper 4-ft-thick Bee Brake is a very fine silty sandstone with characteristics of a small overbank or crevasse splay deposit. The lower 3-ft-thick oil-producing Angelina sandstone consists of very fine and fine sandstone of probable overbank or crevasse facies. Cumulative production from the Angelina is about 1.8 million stock-tank barrels of oil. Special core analysis data (capillary pressure, relative permeability, and waterflood recovery) have been used to develop a simulation model of the two reservoirs in the Minter. This model incorporates the geologic and engineering complexities noted during evaluation of the field area. Operators can use the model results in this field to design an optimal development plan for enhanced recovery.« less

Depositional setting and diagenetic evolution of some Tertiary unconventional reservoir rocks, Uinta Basin, Utah.

USGS Publications Warehouse

Pitman, Janet K.; Fouch, T.D.; Goldhaber, M.B.

1982-01-01

The Douglas Creek Member of the Tertiary Green River Formation underlies much of the Uinta basin, Utah, and contains large volumes of oil and gas trapped in a complex of fractured low-permeability sandstone reservoirs. In the SE part of the basin at Pariette Bench, the Eocene Douglas Creek Member is a thick sequence of fine- grained alluvial sandstone complexly intercalated with lacustrine claystone and carbonate rock. Sediments were deposited in a subsiding intermontane basin along the shallow fluctuating margin of ancient Lake Uinta. Although the Uinta basin has undergone postdepositional uplift and erosion, the deepest cored rocks at Pariette Bench have never been buried more than 3000m.-from Authors

The Effects of Storm Runoff on Water Quality and the Coping Strategy of a Deep Canyon-Shaped Source Water Reservoir in China

PubMed Central

Ma, Weixing; Huang, Tinglin; Li, Xuan; Zhou, Zizhen; Li, Yang; Zeng, Kang

2015-01-01

Storm runoff events in the flooding season affect the water quality of reservoirs and increase risks to the water supply, but coping strategies have seldom been reported. The phenomenon of turbid current intrusion resulting in water turbidity and anoxic conditions reappearing after storm runoff, resulting in the deterioration of water quality, was observed in the flooding season in the deep canyon-shaped Heihe Reservoir. The objective of this work was to elucidate the effects of storm runoff on the Heihe Reservoir water quality and find a coping strategy. In this study, an intensive sampling campaign measuring water temperature, dissolved oxygen, turbidity, nutrients, and metals were conducted in the reservoir over a period of two years, and the water-lifting aerators were improved to achieve single aeration and a full layer of mixing and oxygenation functions using different volumes of gas. The operation of the improved water-lifting aerators mixed the reservoir three months ahead of the natural mixing time, and good water quality was maintained during the induced mixing period, thereby extending the good water quality period. The results can provide an effective coping strategy to improve the water quality of a source water reservoir and ensure the safety of drinking water. PMID:26184258

Quartz cement in sandstones: a review

NASA Astrophysics Data System (ADS)

McBride, Earle F.

Quartz cement as syntaxial overgrowths is one of the two most abundant cements in sandstones. The main factors that control the amount of quartz cement in sandstones are: framework composition; residence time in the "silica mobility window"; and fluid composition, flow volume and pathways. Thus, the type of sedimentary basin in which a sand was deposited strongly controls the cementation process. Sandstones of rift basins (arkoses) and collision-margin basins (litharenites) generally have only a few percent quartz cement; quartzarenites and other quartzose sandstones of intracratonic, foreland and passive-margin basins have the most quartz cement. Clay and other mineral coatings on detrital quartz grains and entrapment of hydrocarbons in pores retard or prevent cementation by quartz, whereas extremely permeable sands that serve as major fluid conduits tend to sequester the greatest amounts of quartz cement. In rapidly subsiding basins, like the Gulf Coast and North Sea basins, most quartz cement is precipitated by cooling, ascending formation water at burial depths of several kilometers where temperatures range from 60° to 100° C. Cementation proceeds over millions of years, often under changing fluid compositions and temperatures. Sandstones with more than 10% imported quartz cement pose special problems of fluid flux and silica transport. If silica is transported entirely as H 4SiO 4, convective recycling of formation water seems to be essential to explain the volume of cement present in most sandstones. Precipitation from single-cycle, upward-migrating formation water is adequate to provide the volume of cement only if significant volumes of silica are transported in unidentified complexes. Modeling suggests that quartz cementation of sandstones in intracratonic basins is effected by advecting meteoric water, although independent petrographic, isotopic or fluid inclusion data are lacking. Silica for quartz cement comes from both shale and sandstone beds within

Artificial Water Reservoir Triggered Earthquakes at Koyna, India: Completion of the 3 km deep Pilot Borehole

NASA Astrophysics Data System (ADS)

Gupta, H. K.; Tiwari, V. M.; Satyanarayana, H.; Roy, S.; Arora, K.; Patro, P. K.; Shashidhar, D.; Mallika, K.; Akkiraju, V.; Misra, S.; Goswami, D.; Podugu, N.; Mishra, S.

2017-12-01

Koyna, near the west coast of India is the most prominent site of artificial water reservoir triggered seismicity (RTS). Soon after the impoundment of the Koyna Dam in 1962, RTS was observed. It has continued till now. It includes the largest RTS earthquake M 6.3 on December 10, 1967; 22 M≥5.0, and thousands of smaller earthquakes. The entire earthquake activity is limited to an area of about 30 km x 20 km, with most focal depths being within 6 km. There is no other earthquake source within 50 km of the Koyna Dam. An ICDP Workshop held in March 2011 found Koyna to be the most suitable site to investigate reservoir- triggered seismicity (RTS) through deep drilling. Studies carried out in the preparatory phase since 2011 include airborne magnetic and gravity-gradient surveys, MT surveys, drilling of 9 boreholes going to depths of 1500 m and logging, heat flow measurements, seismological investigations including the deployment of six borehole seismometers, and LiDAR. The Second ICDP Workshop held during 16- 18 May 2014, reviewed the progress made and detailed planning of putting the borehole observatory was discussed. The site of a 3 km deep pilot borehole was debated and among the 5 possible location. Based on the seismic activity and logistics the location of the first Pilot Borehole has been finalized and the drilling started on the 21st December 2016. The 3000 m deep borehole was completed on 11th June 2017. The basement was touched at 1247 m depth and there were no sediments below basalt. Several zones with immense fluid losses were encountered. Geophysical Logging has been completed. Cores were recovered from 1269, 1892 and 2091 depths. The cores are 9 m long and with 4 inches diameter. The core recovery is almost 100%. In-situ stress measurements have been conducted at depths of 1600 m onwards.

Magma-sponge hypothesis and stratovolcanoes: Case for a compressible reservoir and quasi-steady deep influx at Soufrière Hills Volcano, Montserrat

NASA Astrophysics Data System (ADS)

Voight, Barry; Widiwijayanti, Christina; Mattioli, Glen; Elsworth, Derek; Hidayat, Dannie; Strutt, M.

2010-02-01

We use well-documented time histories of episodic GPS surface deformation and efflux of compressible magma to resolve apparent magma budget anomalies at Soufrière Hills volcano (SHV) on Montserrat, WI. We focus on data from 2003 to 2007, for an inflation succeeded by an episode of eruption-plus-deflation. We examine Mogi-type and vertical prolate ellipsoidal chamber geometries to accommodate both mineralogical constraints indicating a relatively shallow pre-eruption storage, and geodetic constraints inferring a deeper mean-pressure source. An exsolved phase involving several gas species greatly increases andesite magma compressibility to depths >10 km (i.e., for water content >4 wt%, crystallinity ˜40%), and this property supports the concept that much of the magma transferred into or out of the crustal reservoir could be accommodated by compression or decompression of stored reservoir magma (i.e., the “magma-sponge”). Our results suggest quasi-steady deep, mainly mafic magma influx of the order of 2 m3s-1, and we conclude that magma released in eruptive episodes is approximately balanced by cumulative deep influx during the eruptive episode and the preceding inflation. Our magma-sponge model predicts that between 2003 and 2007 there was no evident depletion of magma reservoir volume at SHV, which comprises tens of km3 with radial dimensions of order ˜1-2 km, in turn implying a long-lived eruption.

Experimental Investigation on Dilation Mechanisms of Land-Facies Karamay Oil Sand Reservoirs under Water Injection

NASA Astrophysics Data System (ADS)

Lin, Botao; Jin, Yan; Pang, Huiwen; Cerato, Amy B.

2016-04-01

The success of steam-assisted gravity drainage (SAGD) is strongly dependent on the formation of a homogeneous and highly permeable zone in the land-facies Karamay oil sand reservoirs. To accomplish this, hydraulic fracturing is applied through controlled water injection to a pair of horizontal wells to create a dilation zone between the dual wells. The mechanical response of the reservoirs during this injection process, however, has remained unclear for the land-facies oil sand that has a loosely packed structure. This research conducted triaxial, permeability and scanning electron microscopy (SEM) tests on the field-collected oil sand samples. The tests evaluated the influences of the field temperature, confining stress and injection pressure on the dilation mechanisms as shear dilation and tensile parting during injection. To account for petrophysical heterogeneity, five reservoir rocks including regular oil sand, mud-rich oil sand, bitumen-rich oil sand, mudstone and sandstone were investigated. It was found that the permeability evolution in the oil sand samples subjected to shear dilation closely followed the porosity and microcrack evolutions in the shear bands. In contrast, the mudstone and sandstone samples developed distinct shear planes, which formed preferred permeation paths. Tensile parting expanded the pore space and increased the permeability of all the samples in various degrees. Based on this analysis, it is concluded that the range of injection propagation in the pay zone determines the overall quality of hydraulic fracturing, while the injection pressure must be carefully controlled. A region in a reservoir has little dilation upon injection if it remains unsaturated. Moreover, a cooling of the injected water can strengthen the dilation potential of a reservoir. Finally, it is suggested that the numerical modeling of water injection in the Karamay oil sand reservoirs must take into account the volumetric plastic strain in hydrostatic loading.

Deformation Bands in an Exhumed Oil Reservoir, Corona del Mar, California, USA

NASA Astrophysics Data System (ADS)

Sample, J.; Woods, S.; Bender, E.; Loveall, M.

2002-12-01

Deformation bands in coarse-grained sandstones are commonly narrow zones of reduced porosity that restrict migration of fluids. Deformation bands are known from core observations and outcrop studies, but we present for the first time results from an exhumed oil reservoir. The deformation bands occur in a poorly consolidated, oil-bearing sandstone of the Miocene Monterey Formation, within the active, right-slip Newport-Inglewood fault zone (NIFZ). The deformation bands crop out as resistant ribs and fins in a very coarse-grained sandstone comprising mainly quartz and feldspar detritus. Deformation bands strike 323°, similar to the NIFZ, and dip variably (N = 113). There are three clusters of dips within the main set: 88NE, 60NE, and 47SW. A fourth cluster has an orientation of 353 °, 70W. Although the kinematic history is complex, steep bands generally are youngest. Deformation bands exhibit both normal and right-slip separations, but net slip was rarely possible to determine. The deformation bands are closely spaced. They formed by porosity reduction and locally cataclasis. Most deformation bands are oil-free, indicating formation before oil migration, and that they were barriers to flow. There are at least two modes of oil-bearing bands: 1) bands with oil in pore spaces; and 2) bands containing oil in small open pockets, especially lining the edges of bands. Case 1 suggests that porosity reduction did not completely preclude oil penetration or that at least some band formation occurred after oil migration. Case 2 is consistent with reactivation of bands as tensional features, perhaps late in the evolution of the reservoir. Other evidence for late-stage tensional deformation during oil migration includes the presence of young sandstone dikes and bitumen veins up to 7 cm in width lined with euhedral quartz. The relationships observed at Corona del Mar are generally consistent with deformation bands acting as barriers to flow, but clearly deformation bands can be

Effects of microstructure on water imbibition in sandstones using X-ray computed tomography and neutron radiography

NASA Astrophysics Data System (ADS)

Zhao, Yixin; Xue, Shanbin; Han, Songbai; Chen, Zhongwei; Liu, Shimin; Elsworth, Derek; He, Linfeng; Cai, Jianchao; Liu, Yuntao; Chen, Dongfeng

2017-07-01

Capillary imbibition in variably saturated porous media is important in defining displacement processes and transport in the vadose zone and in low-permeability barriers and reservoirs. Nonintrusive imaging in real time offers the potential to examine critical impacts of heterogeneity and surface properties on imbibition dynamics. Neutron radiography is applied as a powerful imaging tool to observe temporal changes in the spatial distribution of water in porous materials. We analyze water imbibition in both homogeneous and heterogeneous low-permeability sandstones. Dynamic observations of the advance of the imbibition front with time are compared with characterizations of microstructure (via high-resolution X-ray computed tomography (CT)), pore size distribution (Mercury Intrusion Porosimetry), and permeability of the contrasting samples. We use an automated method to detect the progress of wetting front with time and link this to square-root-of-time progress. These data are used to estimate the effect of microstructure on water sorptivity from a modified Lucas-Washburn equation. Moreover, a model is established to calculate the maximum capillary diameter by modifying the Hagen-Poiseuille and Young-Laplace equations based on fractal theory. Comparing the calculated maximum capillary diameter with the maximum pore diameter (from high-resolution CT) shows congruence between the two independent methods for the homogeneous silty sandstone but less effectively for the heterogeneous sandstone. Finally, we use these data to link observed response with the physical characteristics of the contrasting media—homogeneous versus heterogeneous—and to demonstrate the sensitivity of sorptivity expressly to tortuosity rather than porosity in low-permeability sandstones.

Consolidation of geologic studies of geopressured-geothermal resources in Texas: Barrier-bar tidal-channel reservoir facies architecture, Jackson Group, Prado Field, South Texas

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

Seni, S.J.; Choh, S.J.

1993-09-01

Sandstone reservoirs in the Jackson barrier/strandplain play are characterized by low recovery efficiencies and thus contain a large hydrocarbon resource target potentially amenable to advanced recovery techniques. Prado field, Jim Hogg County, South Texas, has produced over 23 million bbl of oil and over 32 million mcf gas from combination structural-stratigraphic traps in the Eocene lower Jackson Group. Hydrocarbon entrapment at Prado field is a result of anticlinal nosing by differential compaction and updip pinch-out of barrier bar sandstone. Relative base-level lowering resulted in forced regression that established lower Jackson shoreline sandstones in a relatively distal location in central Jimmore » Hogg County. Reservoir sand bodies at Prado field comprise complex assemblages of barrier-bar, tidal-inlet fill, back-barrier bar, and shoreface environments. Subsequent progradation built the barrier-bar system seaward 1 to 2 mi. With the barrier-bar system, favorable targets for hydrocarbon reexploration are concentrated in tidal-inlet facies because they possess the greatest degree of depositional heterogeneity.« 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

Burial, thermal, and petroleum generation history of the Upper Cretaceous Steele Member of the Cody Shale (Shannon Sandstone Bed Horizon), Powder River Basin, Wyoming (Chapter A). Bulletin

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

Nuccio, V.F.

The purposes of the study are to (1) present burial histories representative of the northwestern and southwestern parts of the Powder River Basin (south of lat 45 N.), (2) show the maximum level of thermal maturity for the Steele Member and its Shannon Sandstone Bed, and (3) show the source-rock potential and timing of petroleum generation for the Steele. It is hoped that data presented in the study will also lead to a better understanding of the burial and temperature history of the Shannon Sandstone Bed, an understanding crucial for diagenetic studies, fluid-flow modeling, and reservoir-rock characterization.

Experimental measurements of the SP response to concentration and temperature gradients in sandstones with application to subsurface geophysical monitoring

NASA Astrophysics Data System (ADS)

Leinov, E.; Jackson, M. D.

2014-09-01

Exclusion-diffusion potentials arising from temperature gradients are widely neglected in self-potential (SP) surveys, despite the ubiquitous presence of temperature gradients in subsurface settings such as volcanoes and hot springs, geothermal fields, and oil reservoirs during production via water or steam injection. Likewise, with the exception of borehole SP logging, exclusion-diffusion potentials arising from concentration gradients are also neglected or, at best, it is assumed that the diffusion potential dominates. To better interpret these SP sources requires well-constrained measurements of the various coupling terms. We report measurements of thermoelectric and electrochemical exclusion-diffusion potentials across sandstones saturated with NaCl brine and find that electrode effects can dominate the measured voltage. After correcting for these, we find that Hittorf transport numbers are the same within experimental error regardless of whether ion transport occurs in response to temperature or concentration gradients over the range of NaCl concentration investigated that is typical of natural systems. Diffusion potentials dominate only if the pore throat radius is more than approximately 4000 times larger than the diffuse layer thickness. In fine-grained sandstones with small pore throat diameter, this condition is likely to be met only if the saturating brine is of relatively high salinity; thus, in many cases of interest to earth scientists, exclusion-diffusion potentials will comprise significant contributions from both ionic diffusion through, and ionic exclusion from, the pore space of the rock. However, in coarse-grained sandstones, or sandstones saturated with high-salinity brine, exclusion-diffusion potentials can be described using end-member models in which ionic exclusion is neglected. Exclusion-diffusion potentials in sandstones depend upon pore size and salinity in a complex way: they may be positive, negative, or zero depending upon sandstone

Measuring and predicting reservoir heterogeneity in complex deposystems

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

Donaldson, A.; Shumaker, R.; Laughrey, C.

1992-08-01

The Lower Mississippian Big Injun sandstone, a major oil producer in the western half of West Virginia, consists of several sandstones that overstep each west. Examination of cores and thin sections has led to preliminary interpretations of depositional environments for the Big Injun. These include distributary-mouth bars with associated distal, bar crest and back bar environments in a marine-deltaic system; and channel, point bar and chute environments in a fluvial system. Overall, the Big Injun is a medium-grained sublitharenite in which initially high porosity has been modified by compaction and diagenesis. Chlorite grain coatings helped to preserve original porosity, whereasmore » illite promoted pressure solution during compaction, resulting in a loss of porosity. Diagenetic effects within specific environments are being evaluated to determine if environmental interpretations can be used to predict porosity preservation. Core plugs taken from cores in Granny Creek field were analyzed for porosity and horizontal and vertical permeability. Directional permeability was negligible, but permeability does correlate with depth. Changes in permeability with depth can be related to subdivisions of the Big Injun determined from density logs. Permeability also correlated with porosity, but porosity values derived from both cores and logs show no significant correlation trend at present. A layered reservoir model is being developed to evaluate the effect of these vertical heterogeneities. Initial attempts to characterize the heterogeneity of the Big Injun reservoir in Granny Creek field used a number of direct and indirect methods.« less

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

Hydrocarbons related to early Cretaceous source rocks, reservoirs and seals, trapped in northeastern Neuqun basin, Argentina

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

Gulisano, C.; Minniti, S.; Rossi, G.

1996-08-01

The Jurassic-Cretaceous backarc Neuqun Basin, located in the west central part of Argentina, is currently the most prolific oil basin of the country. The primary objective of this study is to evaluate an Early Cretaceous to Tertiary petroleum system in the northeastern portion of the basin, where oil and gas occurrences (e.g., Puesto Hernandez, Chihuido de la Sierra Negra, El Trapial and Filo Morado oil fields, among others) provide 82 MMBO/yr comprising 67% of the basin oil production and 31% of Argentina. The source rocks are represented by two thick sections of basinal kerogen type I and II organic-rich shales,more » deposited during transgressive peaks (Agrio Formation), with TOC content up to 5.1%. Lowstand sandstones bodies, 10 to 100 m thick, are composed of eolian and fluvial facies with good reservoir conditions (Avil and Troncoso Sandstones). The seals are provided by the organic-rich shales resting sharply upon the Avil Sandstone and a widespread Aptian-Albian evaporitic event (Huitrin Formation) on top of the Troncoso reservoir. Tertiary structural traps (duplex anticlines) are developed in the outer foothills, whereas structural, combined and stratigraphic traps are present in the adjacent stable structural platform. Oil-to-source rock and oil-to-oil correlation by chromatographic and biomarker fingerprints, carbon isotopic composition and the geological evidences support the proposed oil system.« less

Anatomy of a lower Mississippian oil reservoir, West Virginia, United States

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

Patchen, D.; Hohn, M.E.; McDowell, R.

1993-09-01

Several lines of evidence indicate that the oil reservoir in Granny Creek field is compartmentalized due to internal heterogeneities: an analysis of initial open flows vs. year completed and well location; mapping of initial open flows and cumulative production; and the nonuniform behavior of injection pressures and rates in waterflood patterns. The Big Injun sandstones includes an upper, coarse-grained, fluvial channel facies, and a lower, fine-grained, distributary mouthbar facies. The bar facies is the main reservoir, and can be subdivided into crest, distal, and proximal subfacies. Low original porosity and permeability in the poorly sorted channel facies was reduced furthermore » by quartz cementation. In contrast, chlorite coatings restricted quartz cementation and preserved porosity and permeability in the proximal bar subfacies. Small, low-amplitude folds plunge northeastward on the flank of the main syncline in which the fields is located. These minor structural highs seem to match areas of high initial open flows and cumulative production. High production also occurs where the distal and marine-influenced, proximal mouth-bar subfacies pinch out against at least a few feet of the relatively impremeable channel facies. Lower production is associated with (1) thin areas of proximal mouth-bar subfacies; (2) a change from marine to fluvial dominance of the bar facies, which is accompanied by a reduction in porosity and permeability; and (3) loss of the less permeable channel facies above the porous reservoir sandstone, due to downcutting by regional erosion that produced a post-Big Injun unconformity.« less

Sandstone-body and shale-body dimensions in a braided fluvial system: Salt wash sandstone member (Morrison formation), Garfield County, Utah

USGS Publications Warehouse

Robinson, J.W.; McCabea, P.J.

1997-01-01

Excellent three-dimensional exposures of the Upper Jurassic Salt Wash Sandstone Member of the Morrison Formation in the Henry Mountains area of southern Utah allow measurement of the thickness and width of fluvial sandstone and shale bodies from extensive photomosaics. The Salt Wash Sandstone Member is composed of fluvial channel fill, abandoned channel fill, and overbank/flood-plain strata that were deposited on a broad alluvial plain of low-sinuosity, sandy, braided streams flowing northeast. A hierarchy of sandstone and shale bodies in the Salt Wash Sandstone Member includes, in ascending order, trough cross-bedding, fining-upward units/mudstone intraclast conglomerates, singlestory sandstone bodies/basal conglomerate, abandoned channel fill, multistory sandstone bodies, and overbank/flood-plain heterolithic strata. Trough cross-beds have an average width:thickness ratio (W:T) of 8.5:1 in the lower interval of the Salt Wash Sandstone Member and 10.4:1 in the upper interval. Fining-upward units are 0.5-3.0 m thick and 3-11 m wide. Single-story sandstone bodies in the upper interval are wider and thicker than their counterparts in the lower interval, based on average W:T, linear regression analysis, and cumulative relative frequency graphs. Multistory sandstone bodies are composed of two to eight stories, range up to 30 m thick and over 1500 m wide (W:T > 50:1), and are also larger in the upper interval. Heterolithic units between sandstone bodies include abandoned channel fill (W:T = 33:1) and overbank/flood-plain deposits (W:T = 70:1). Understanding W:T ratios from the component parts of an ancient, sandy, braided stream deposit can be applied in several ways to similar strata in other basins; for example, to (1) determine the width of a unit when only the thickness is known, (2) create correlation guidelines and maximum correlation lengths, (3) aid in interpreting the controls on fluvial architecture, and (4) place additional constraints on input variables to

An Experimental Study of the Fracture Coalescence Behaviour of Brittle Sandstone Specimens Containing Three Fissures

NASA Astrophysics Data System (ADS)

Yang, S. Q.; Yang, D. S.; Jing, H. W.; Li, Y. H.; Wang, S. Y.

2012-07-01

To analyse the fracture coalescence behaviour of rock, rectangular prismatic sandstone specimens (80 × 160 × 30 mm in size) containing three fissures were tested under uniaxial compression. The strength and deformation behaviours of the specimens are first analysed by investigating the effects of the ligament angle β2 on the peak strength, peak strain and crack initiation stress of the specimens. To confirm the sequence of crack coalescence, a photographic monitoring technique is used throughout the entire period of deformation. Based on the results, the relationship between the real-time crack coalescence process and the axial stress-strain curve of brittle sandstone specimens is also developed, and this relationship can be used to evaluate the macroscopic deformation characteristics of pre-cracked rock. The equivalent strain evolution fields of the specimen, with α = β1 = 45° and β2 = 90°, are obtained using the digital image correlation technique and show good agreement with the experimental results of pre-cracked brittle sandstone. These experimental results are expected to improve the understanding of fracture mechanisms and be used in rock engineering with intermittent structures, such as deep underground excavated tunnels.

A review of the multiwell experiment in tight gas sandstones of the Mesaverde Group, Piceance Basin, Colorado

USGS Publications Warehouse

Nelson, P.H.

2002-01-01

The Cretaceous Iles and Williams Fork Formations of the Mesaverde Group contain important reservoir and source rocks for basin-centered gas accumulations in the Piceance Basin of northwestern Colorado. The sandstones in these formations have very low permeability, so low that successful production of gas requires the presence of fractures. To increase gas production, the natural fracture system of these "tight gas sandstones" must be augmented by inducing artificial fractures, while minimizing the amount of formation damage due to introduced fluids. The Multiwell Experiment was undertaken to provide geological characterization, obtain physical property data, and perform stimulation experiments in the Iles and Williams Fork Formations. Three vertical wells and one follow-up slant well were drilled, logged, partially cored, tested for gas production, stimulated in various manners, and tested again. Drawing from published reports and papers, this review paper presents well log, core, and test data from the Multiwell Experiment while emphasizing the geological controls on gas production at the site. Gas production is controlled primarily by a set of regional fractures trending west-northwest. The fractures are vertical, terminating at lithologic boundaries within and at the upper and lower boundaries of sandstone beds. Fractures formed preferentially in sandstones where in situ stress and fracture gradients are lower than in shales and mudstones. The fractures cannot be identified adequately in vertical wellbores; horizontal wells are required. Because present-day maximum horizontal stress is aligned with the regional fractures, artificial fractures induced by pressuring the wellbore form parallel to the regional fractures rather than linking them, with consequent limitations upon enhancement of gas production.

1D Thermal-Hydraulic-Chemical (THC) Reactive transport modeling for deep geothermal systems: A case study of Groß Schönebeck reservoir, Germany

NASA Astrophysics Data System (ADS)

Driba, D. L.; De Lucia, M.; Peiffer, S.

2014-12-01

Fluid-rock interactions in geothermal reservoirs are driven by the state of disequilibrium that persists among solid and solutes due to changing temperature and pressure. During operation of enhanced geothermal systems, injection of cooled water back into the reservoir disturbs the initial thermodynamic equilibrium between the reservoir and its geothermal fluid, which may induce modifications in permeability through changes in porosity and pore space geometry, consequently bringing about several impairments to the overall system.Modeling of fluid-rock interactions induced by injection of cold brine into Groß Schönebeck geothermal reservoir system situated in the Rotliegend sandstone at 4200m depth have been done by coupling geochemical modeling Code Phreeqc with OpenGeoSys. Through batch modeling the re-evaluation of the measured hydrochemical composition of the brine has been done using Quintessa databases, the results from the calculation indicate that a mineral phases comprising of K-feldspar, hematite, Barite, Calcite and Dolomite was found to match the hypothesis of equilibrium with the formation fluid, Reducing conditions are presumed in the model (pe = -3.5) in order to match the amount of observed dissolved Fe and thus considered as initial state for the reactive transport modeling. based on a measured composition of formation fluids and the predominant mineralogical assemblage of the host rock, a preliminary 1D Reactive transport modeling (RTM) was run with total time set to 30 years; results obtained for the initial simulation revealed that during this period, no significant change is evident for K-feldspar. Furthermore, the precipitation of calcite along the flow path in the brine results in a drop of pH from 6.2 to a value of 5.2 noticed over the simulated period. The circulation of cooled fluid in the reservoir is predicted to affect the temperature of the reservoir within the first 100 -150m from the injection well. Examination of porosity change in

Deep microbial life in the Altmark natural gas reservoir: baseline characterization prior CO2 injection

NASA Astrophysics Data System (ADS)

Morozova, Daria; Shaheed, Mina; Vieth, Andrea; Krüger, Martin; Kock, Dagmar; Würdemann, Hilke

2010-05-01

Within the framework of the CLEAN project (CO2 Largescale Enhanced gas recovery in the Altmark Natural gas field) technical basics with special emphasis on process monitoring are explored by injecting CO2 into a gas reservoir. Our study focuses on the investigation of the in-situ microbial community of the Rotliegend natural gas reservoir in the Altmark, located south of the city Salzwedel, Germany. In order to characterize the microbial life in the extreme habitat we aim to localize and identify microbes including their metabolism influencing the creation and dissolution of minerals. The ability of microorganisms to speed up dissolution and formation of minerals might result in changes of the local permeability and the long-term safety of CO2 storage. However, geology, structure and chemistry of the reservoir rock and the cap rock as well as interaction with saline formation water and natural gases and the injected CO2 affect the microbial community composition and activity. The reservoir located at the depth of about 3500m, is characterised by high salinity fluid and temperatures up to 127° C. It represents an extreme environment for microbial life and therefore the main focus is on hyperthermophilic, halophilic anaerobic microorganisms. In consequence of the injection of large amounts of CO2 in the course of a commercial EGR (Enhanced Gas Recovery) the environmental conditions (e.g. pH, temperature, pressure and solubility of minerals) for the autochthonous microorganisms will change. Genetic profiling of amplified 16S rRNA genes are applied for detecting structural changes in the community by using PCR- SSCP (PCR-Single-Strand-Conformation Polymorphism) and DGGE (Denaturing Gradient Gel Electrophoresis). First results of the baseline survey indicate the presence of microorganisms similar to representatives from other saline, hot, anoxic, deep environments. However, due to the hypersaline and hyperthermophilic reservoir conditions, cell numbers are low, so that

Pore Structure and Limit Pressure of Gas Slippage Effect in Tight Sandstone

PubMed Central

You, Lijun; Xue, Kunlin; Kang, Yili; Liao, Yi

2013-01-01

Gas slip effect is an important mechanism that the gas flow is different from liquid flow in porous media. It is generally considered that the lower the permeability in porous media is, the more severe slip effect of gas flow will be. We design and then carry out experiments with the increase of backpressure at the outlet of the core samples based on the definition of gas slip effect and in view of different levels of permeability of tight sandstone reservoir. This study inspects a limit pressure of the gas slip effect in tight sandstones and analyzes the characteristic parameter of capillary pressure curves. The experimental results indicate that gas slip effect can be eliminated when the backpressure reaches a limit pressure. When the backpressure exceeds the limit pressure, the measured gas permeability is a relatively stable value whose range is less than 3% for a given core sample. It is also found that the limit pressure increases with the decreasing in permeability and has close relation with pore structure of the core samples. The results have an important influence on correlation study on gas flow in porous medium, and are beneficial to reduce the workload of laboratory experiment. PMID:24379747

Sensitivity Studies of 3D Reservoir Simulation at the I-Lan Geothermal Area in Taiwan Using TOUGH2

NASA Astrophysics Data System (ADS)

Kuo, C. W.; Song, S. R.

2014-12-01

A large scale geothermal project conducted by National Science Council is initiated recently in I-Lan south area, northeastern Taiwan. The goal of this national project is to generate at least 5 MW electricity from geothermal energy. To achieve this goal, an integrated team which consists of various specialties are held together to investigate I-Lan area comprehensively. For example, I-Lan geological data, petrophysical analysis, seismicity, temperature distribution, hydrology, geochemistry, heat source study etc. were performed to build a large scale 3D conceptual model of the geothermal potential sites. In addition, not only a well of 3000m deep but also several shallow wells are currently drilling to give us accurate information about the deep underground. According to the current conceptual model, the target area is bounded by two main faults, Jiaosi and Choshui faults. The geothermal gradient measured at one drilling well (1200m) is about 49.1˚C/km. The geothermal reservoir is expected to occur at a fractured geological formation, Siling sandstone layer. The preliminary results of this area from all the investigations are used as input parameters to create a realistic numerical reservoir model. This work is using numerical simulator TOUGH2/EOS1 to study the geothermal energy potential in I-Lan area. Once we can successfully predict the geothermal energy potential in this area and generate 5 MW electricity, we can apply the similar methodology to the other potential sites in Taiwan, and therefore increase the percentage of renewable energy in the generation of electricity. A large scale of three-dimensional subsurface geological model is built mainly based on the seismic exploration of the subsurface structure and well log data. The dimensions of the reservoir model in x, y, and z coordinates are 20x10x5 km, respectively. Once the conceptual model and the well locations are set up appropriately based on the field data, sensitivity studies on production and

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

(Capillary trapping) capacity. There is a positive possibility to conduct CCS in the low-quality reservoir (low permeable sandstone).

Fast evolving conduits in clay-bonded sandstone: Characterization, erosion processes and significance for the origin of sandstone landforms

NASA Astrophysics Data System (ADS)

Bruthans, Jiri; Svetlik, Daniel; Soukup, Jan; Schweigstillova, Jana; Valek, Jan; Sedlackova, Marketa; Mayo, Alan L.

2012-12-01

In Strelec Quarry, the Czech Republic, an underground conduit network > 300 m long with a volume of ~ 104 m3 and a catchment of 7 km2 developed over 5 years by groundwater flow in Cretaceous marine quartz sandstone. Similar landforms at natural exposures (conduits, slot canyons, undercuts) are stabilized by case hardening and have stopped evolving. The quarry offers a unique opportunity to study conduit evolution in sandstone at local to regional scales, from the initial stage to maturity, and to characterize the erosion processes which may form natural landforms prior to stabilization. A new technique was developed to distinguish erodible and non-erodible sandstone surfaces. Based on measurements of relative erodibility, drilling resistance, ambient and water-saturated tensile strength (TS) at natural and quarry exposures three distinct kinds of surfaces were found. 1) Erodible sandstone exposed at ~ 60% of surfaces in quarry. This sandstone loses as much as 99% of TS when saturated. 2) Sub-vertical fracture surfaces that are non-erodible already prior to exposure at ground surface and which keep considerable TS if saturated. 3) Case hardened surfaces that start to form after exposure. In favorable conditions they became non-erodible and reach the full TS in just 6 years. An increase in the hydraulic gradient from ~ 0.005 to > 0.02 triggered conduit evolution, based on long-term monitoring of water table in 18 wells and inflows to the quarry. Rapidly evolving major conduits are characterized by a channel gradient of ~ 0.01, a flow velocity ~ 40 cm/s and sediment concentration ~ 10 g/l. Flow in openings with a discharge 1 ml/s and hydraulic gradient > 0.05 exceeds the erosion threshold and initiates piping. In the first phase of conduit evolution, fast concentrated flow mobilizes erodible sandstone between sets of parallel fractures in the shallow phreatic zone. In the second phase the conduit opening mainly expands vertically upward into the vadose zone by mass

Effect of lithological heterogeneity of bitumen sandstones on SAGD reservoir development

NASA Astrophysics Data System (ADS)

Korolev, E. A.; Usmanov, S. A.; Nikolaev, D. S.; Gabdelvaliyeva, R. R.

2018-05-01

The article describes the heavy oil field developed by the SAGD method. While development planning all the heterogeneity of the reservoir is must be taken into account. The objective of this work is to identify the distribution of lithological heterogeneities and their influence on oil production. For this reason, the studies of core samples were conducted and the heterogeneity was identified. Then properties and approximate geometry of lithological objects were studied. Also the effect of the heterogeneity on the heat propagation and production of fluid were analyzed. In the end, recommendations were made for the study of such heterogeneities on other deposits with similar geology

Supercritical sedimentary structures and bedforms and criteria for recognition in the field: insights from the Middle Eocene deep-marine Morillo and Guaso systems, Ainsa Basin, Spanish Pyrenees

NASA Astrophysics Data System (ADS)

Torley, John; Pickering, Kevin

2017-04-01

It has long been acknowledged that for most submarine slopes with gradients > 0.5, common to many deep-water environments, they should contain abundant evidence of supercritical flows and their deposits. However, it is common for deep-marine sands/sandstones to be routinely modelled using the Bouma (1962) sequence for turbidites. Recently, the importance of supercritical flows has been highlighted from seafloor observations, with numerical and physical experiments. Such experiments have produced previously unrecognised bedforms which fail to be interpreted adequately by Bouma's model, including antidunes, chutes-and-pools, and cyclic steps. Fieldwork in the Middle Eocene Ainsa Basin, Spanish Pyrenees, has been undertaken in the Morillo and Guaso systems of the Upper Hecho Group. Approximately 5,000 beds were measured and documented in detail, e.g., grain size, sedimentary structures, bedforms and facies. Collectively, this data can be used to understand supercritical versus subcritical flow. The relative importance of supercritical flow can then be compared and contrasted within individual ancient deep-marine systems. The Morillo System is relatively coarse-grained, compared with the Guaso System. The results of this research contribute to an improved understanding of the processes in deep-marine systems, and directly benefit the hydrocarbon industry by providing better constraints to predict deep-water reservoir composition and architecture.

Simulation of the mulltizones clastic reservoir: A case study of Upper Qishn Clastic Member, Masila Basin-Yemen

NASA Astrophysics Data System (ADS)

Khamis, Mohamed; Marta, Ebrahim Bin; Al Natifi, Ali; Fattah, Khaled Abdel; Lashin, Aref

2017-06-01

The Upper Qishn Clastic Member is one of the main oil-bearing reservoirs that are located at Masila Basin-Yemen. It produces oil from many zones with different reservoir properties. The aim of this study is to simulate and model the Qishn sandstone reservoir to provide more understanding of its properties. The available, core plugs, petrophysical, PVT, pressure and production datasets, as well as the seismic structural and geologic information, are all integrated and used in the simulation process. Eclipse simulator was used as a powerful tool for reservoir modeling. A simplified approach based on a pseudo steady-state productivity index and a material balance relationship between the aquifer pressure and the cumulative influx, is applied. The petrophysical properties of the Qishn sandstone reservoir are mainly investigated based on the well logging and core plug analyses. Three reservoir zones of good hydrocarbon potentiality are indicated and named from above to below as S1A, S1C and S2. Among of these zones, the S1A zone attains the best petrophysical and reservoir quality properties. It has an average hydrocarbon saturation of more than 65%, high effective porosity up to 20% and good permeability record (66 mD). The reservoir structure is represented by faulted anticline at the middle of the study with a down going decrease in geometry from S1A zone to S2 zone. It is limited by NE-SW and E-W bounding faults, with a weak aquifer connection from the east. The analysis of pressure and PVT data has revealed that the reservoir fluid type is dead oil with very low gas liquid ratio (GLR). The simulation results indicate heterogeneous reservoir associated with weak aquifer, supported by high initial water saturation and high water cut. Initial oil in place is estimated to be around 628 MM BBL, however, the oil recovery during the period of production is very low (<10%) because of the high water cut due to the fractures associated with many faults. Hence, secondary and

Constitutive Modelling and Deformation Band Angle Predictions for High Porosity Sandstones

NASA Astrophysics Data System (ADS)

Richards, M. C.; Issen, K. A.; Ingraham, M. D.

2017-12-01

The development of a field-scale deformation model requires a constitutive framework that is capable of representing known material behavior and able to be calibrated using available mechanical response data. This work employs the principle of hyperplasticity (e.g., Houlsby and Puzrin, 2006) to develop such a constitutive framework for high porosity sandstone. Adapting the works of Zimmerman et al. (1986) and Collins and Houlsby (1997), the mechanical data set of Ingraham et al. (2013 a, b) was used to develop a specific constitutive framework for Castlegate sandstone, a high porosity fluvial-deposited reservoir analog rock. Using the mechanical data set of Ingraham et al. (2013 a, b), explicit expressions and material parameters of the elastic moduli and strain tensors were obtained. With these expressions, analytical and numerical techniques were then employed to partition the total mechanical strain into elastic, coupled, and plastic strain components. With the partitioned strain data, yield surfaces in true-stress space, coefficients of internal friction, dilatancy factors, along with the theorectical predictions of the deformation band angles were obtained. These results were also evaluated against band angle values obtained from a) measurements on specimen jackets (Ingraham et al., 2013a), b) plane fits through located acoustic emissions (AE) events (Ingraham et al. 2013b), and c) X-ray micro-computed tomography (micro-CT) calculations.

3-D reservoir characterization of the House Creek oil field, Powder River Basin, Wyoming

USGS Publications Warehouse

Higley, Debra K.; Pantea, Michael P.; Slatt, Roger M.

1997-01-01

This CD-ROM is intended to serve a broad audience. An important purpose is to explain geologic and geochemical factors that control petroleum production from the House Creek Field. This information may serve as an analog for other marine-ridge sandstone reservoirs. The 3-D slide and movie images are tied to explanations and 2-D geologic and geochemical images to visualize geologic structures in three dimensions, explain the geologic significance of porosity/permeability distribution across the sandstone bodies, and tie this to petroleum production characteristics in the oil field. Movies, text, images including scanning electron photomicrographs (SEM), thin-section photomicrographs, and data files can be copied from the CD-ROM for use in external mapping, statistical, and other applications.

Origin of the Nubian and similar sandstones

USGS Publications Warehouse

McKee, E.D.

1963-01-01

The Nubian Sandstone and similar sandstone bodies exposed across much of northern Africa and adjoining parts of Asia are characteristically formed of clean sand that is conspicuously cross stratified throughout. Such sandstone, here called Nubian-type sandstone, ranges from Cambrian through Cretaceous in age and its genesis has been interpreted in many ways. Studies of its primary structures, and of the direction of sand transport, based on statistical measurements of foreset dip directions, have contributed new data on its genesis. By far the most common structure in Nubian-type sandstone is a medium-scale planar-type cross stratification in which sets of evenly dipping cross beds are bounded by essentially flat-lying top and bottom surfaces to form tabular bodies. Other less numerous but typical structures are large-scale, truncated-wedge cross strata, trough-type cross strata, intraformational recumbent folds, small-scale ripple laminae, and dipping sets of tabular-planar cross beds. An analysis of these structures suggests that in the typical Nubian Sandstone of Cretaceous age eolian deposits are not represented and normal marine types probably also are lacking; flood plain, pond or lagoon, and other continental and marginal environments are indicated. In the Carboniferous rocks of Sinai Peninsula some beach sandstone and possibly some eolian, in addition to the types described, form part of the sequence. Direction of sand transport, as determined from cross-bed dips, was northerly in the Cretaceous Nubian of Libya, Sudan, and Egypt; easterly in the Jurassic Adigrat of Ethiopia; westerly in the Carboniferous of Sinai; northwesterly in the early Paleozoic of Jordan. ?? 1963 Ferdinand Enke Verlag Stuttgart.

Sedimentary petrology and reservoir quality of the Middle Jurassic Red Glacier Formation, Cook Inlet forearc basin: Initial impressions

USGS Publications Warehouse

Helmold, K.P.; LePain, D.L.; Stanley, Richard G.

2016-01-01

The Division of Geological & Geophysical Surveys and Division of Oil & Gas are currently conducting a study of the hydrocarbon potential of Cook Inlet forearc basin (Gillis, 2013, 2014; LePain and others, 2013; Wartes, 2015; Herriott, 2016 [this volume]). The Middle Jurassic Tuxedni Group is recognized as a major source of oil in Tertiary reservoirs (Magoon, 1994), although the potential for Tuxedni reservoirs remains largely unknown. As part of this program, five days of the 2015 field season were spent examining outcrops, largely sandstones, of the Middle Jurassic Red Glacier Formation (Tuxedni Group) approximately 6.4 km northeast of Johnson Glacier on the western side of Cook Inlet (fig. 4-1). Three stratigraphic sections (fig. 4-2) totaling approximately 307 m in thickness were measured and described in detail (LePain and others, 2016 [this volume]). Samples were collected for a variety of analyses including palynology, Rock-Eval pyrolysis, vitrinite reflectance, detrital zircon geochronology, and petrology. This report summarizes our initial impressions of the petrology and reservoir quality of sandstones encountered in these measured sections. Interpretations are based largely on hand-lens observations of hand specimens and are augmented by stereomicroscope observations. Detailed petrographic (point-count) analyses and measurement of petrophysical properties (porosity, permeability, and grain density) are currently in progress.

Unconformity-related oil entrapment in Muddy Sandstone: comparison of Kitty and Amos Draw fields, Powder River basin, Wyoming

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

Odland, S.K.; Gardner, M.H.; Gustason, E.R.

1986-08-01

It has long been known that an unconformity plays a critical role in trapping oil in the Muddy Sandstone in the Powder River basin, but opinions have varied as to exactly where in the section that unconformity is located. Their work indicates that there are, in fact, two unconformities associated with the Muddy in the northern part of the basin. The older of these occurs on top of the Skull Creek Shale, whereas the younger is largely intraformational. In places, the younger unconformity has truncated the older one. It is the younger unconformity that is responsible for creating favorable settingsmore » for stratigraphic entrapment of oil. Two types of unconformity-related oil traps result from fluvial downcutting into and through the strand-plain sandstones of the oldest member of the Muddy during a major sea level drop. In cases where the unconformity cuts through the Muddy into the underlying Skull Creek Shale, permeable valley-fill sediments, deposited during the Muddy transgression, are juxtaposed against the impermeable Skull Creek Shale along the valley walls. Where valleys are oriented roughly perpendicular to regional structure, as at Kitty field, the updip portion of the valley wall can form a permeability barrier to the fluvial reservoir sandstones of the adjacent valley fill. In cases where the unconformity is intraformational, such as at Amos Draw field, early diagenetic clay, associated with the weathered horizon directly beneath the unconformity, can create a seal on top of the strand-plain sandstones of the oldest member of the Muddy.« less

Dynamic fluid connectivity during steady-state multiphase flow in a sandstone.

PubMed

Reynolds, Catriona A; Menke, Hannah; Andrew, Matthew; Blunt, Martin J; Krevor, Samuel

2017-08-01

The current conceptual picture of steady-state multiphase Darcy flow in porous media is that the fluid phases organize into separate flow pathways with stable interfaces. Here we demonstrate a previously unobserved type of steady-state flow behavior, which we term "dynamic connectivity," using fast pore-scale X-ray imaging. We image the flow of N 2 and brine through a permeable sandstone at subsurface reservoir conditions, and low capillary numbers, and at constant fluid saturation. At any instant, the network of pores filled with the nonwetting phase is not necessarily connected. Flow occurs along pathways that periodically reconnect, like cars controlled by traffic lights. This behavior is consistent with an energy balance, where some of the energy of the injected fluids is sporadically converted to create new interfaces.

Architecture and reservoir quality of low-permeable Eocene lacustrine turbidite sandstone from the Dongying Depression, East China

NASA Astrophysics Data System (ADS)

Munawar, Muhammad Jawad; Lin, Chengyan; Chunmei, Dong; Zhang, Xianguo; Zhao, Haiyan; Xiao, Shuming; Azeem, Tahir; Zahid, Muhammad Aleem; Ma, Cunfei

2018-05-01

The architecture and quality of lacustrine turbidites that act as petroleum reservoirs are less well documented. Reservoir architecture and multiscale heterogeneity in turbidites represent serious challenges to production performance. Additionally, establishing a hierarchy profile to delineate heterogeneity is a challenging task in lacustrine turbidite deposits. Here, we report on the turbidites in the middle third member of the Eocene Shahejie Formation (Es3), which was deposited during extensive Middle to Late Eocene rifting in the Dongying Depression. Seismic records, wireline log responses, and core observations were integrated to describe the reservoir heterogeneity by delineating the architectural elements, sequence stratigraphic framework and lithofacies assemblage. A petrographic approach was adopted to constrain microscopic heterogeneity using an optical microscope, routine core analyses and X-ray diffraction (XRD) analyses. The Es3m member is interpreted as a sequence set composed of four composite sequences: CS1, CS2, CS3 and CS4. A total of forty-five sequences were identified within these four composite sequences. Sand bodies were mainly deposited as channels, levees, overbank splays, lobes and lobe fringes. The combination of fining-upward and coarsening-upward lithofacies patterns in the architectural elements produces highly complex composite flow units. Microscopic heterogeneity is produced by diagenetic alteration processes (i.e., feldspar dissolution, authigenic clay formation and quartz cementation). The widespread kaolinization of feldspar and mobilization of materials enhanced the quality of the reservoir by producing secondary enlarged pores. In contrast, the formation of pore-filling authigenic illite and illite/smectite clays reduced its permeability. Recovery rates are higher in the axial areas and smaller in the marginal areas of architectural elements. This study represents a significant insight into the reservoir architecture and

Heavy oil reservoirs recoverable by thermal technology

NASA Astrophysics Data System (ADS)

Kujawa, P.

1981-02-01

Reservoir, production, and project data for target reservoirs which contain heavy oil in the 8 to 25(0) API gravity range and are susceptible to recovery by in situ combustion and steam drive are presented. The reservoirs for steam recovery are less than 2500 feet deep to comply with state of the art technology. In cases where one reservoir would be a target for in situ combustion or steam drive, that reservoir is reported in both sections. Data were collected from three source types: hands-on, once removed, and twice removed. In all cases, data were sought depicting and characterizing individual reservoirs as opposed to data covering an entire field with more than one producing interval or reservoir. The data sources are listed at the end of each case. A complete listing of operators and projects is included as well as a bibliography of source material.

Dakota sandstone facies, western Oklahoma panhandle

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

Atalik, E.; Mansfield, C.F.

The Cretaceous Dakota Sandstone in Cimarron County comprised three sandstone units and intervening mudrocks; it overlies the Kiowa Shale Member of the Purgatoire Formation. Deposits include shoreface, beach (foreshore) and dune, estuarine and tidal channel, marine marginal bay and swamp/marsh in a generally progradational sequences associated with marine regression in the Western Interior. The shoreface sand, characterized by ripple lamination, bioturbation and the trace fossils Teichichnus and Thalassinoides, is fine-grained, 5-10 m (15-30 ft) thick and grades into the underlying Kiowa Shale. Beach and associated dune deposits are 2-5 m (6-16 ft) thick, medium to fine-grained, medium to thick-bedded, tabular-planarmore » cross-bedded, and lenticular; cross-bed paleocurrent headings are northeasterly and northwesterly. Estuarine channel deposits are 3-5 m (10 to 16 ft) thick, trough to tabular-planar cross-bedded, and medium to coarse-grained with local conglomerate overlying the scoured base which commonly cuts into the Kiowa Shale or overlying shoreface sandstone; rip-up clasts and wood pieces are common but trace fossils are rare; southeasterly and southwesterly paleocurrents predominate. Tidal channel deposits are thinner (up to 2 m of 6 ft) and finer grained (medium to fine-grained) that the estuarine channel deposits; they occur within fine-grained sandstone and mudrock sequences, are trough cross-bedded, and commonly contain trace fossils (e.g., Skolithos) and wood fragments. Marine marginal (tidal flat or bay.) deposits comprise fine-grained sandstone, siltstone and interbedded shale, that are 1-3m (3-10 ft) thick with abundant burrows, small ripple marks, and parallel lamination. These grade into the fine to very fine-grained sandstones, siltstones, shales, and coals of the swamp/marsh deposits that are 1-5m (3-16 ft) thick and contain ripple marks, burrows, other trace fossils, and parallel lamination.« less

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

Sedimentation, zoning of reservoir rocks in W. Siberian basin oil fields

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

Kliger, J.A.

1994-02-07

A line pattern of well cluster spacing was chosen in western Siberia because of taiga, marshes, etc., on the surface. The zoning of the oil pools within productive Upper Jurassic J[sub 3] intervals is complicated. This is why until the early 1990s almost each third well drilled in the Shaimsky region on the western edge of the West Siberian basin came up dry. The results of development drilling would be much better if one used some sedimentological relationships of zoning of the reservoir rocks within the oil fields. These natural phenomena are: Paleobasin bathymetry; Distances from the sources of themore » clastic material; and Proximity of the area of deposition. Using the diagram in this article, one can avoid drilling toward areas where the sandstone pinch out, area of argillization of sand-stones, or where the probability of their absence is high.« less

Real-time detection of dielectric anisotropy or isotropy in unconventional oil-gas reservoir rocks supported by the oblique-incidence reflectivity difference technique

NASA Astrophysics Data System (ADS)

Zhan, Honglei; Wang, Jin; Zhao, Kun; Lű, Huibin; Jin, Kuijuan; He, Liping; Yang, Guozhen; Xiao, Lizhi

2016-12-01

Current geological extraction theory and techniques are very limited to adequately characterize the unconventional oil-gas reservoirs because of the considerable complexity of the geological structures. Optical measurement has the advantages of non-interference with the earth magnetic fields, and is often useful in detecting various physical properties. One key parameter that can be detected using optical methods is the dielectric permittivity, which reflects the mineral and organic properties. Here we reported an oblique-incidence reflectivity difference (OIRD) technique that is sensitive to the dielectric and surface properties and can be applied to characterization of reservoir rocks, such as shale and sandstone core samples extracted from subsurface. The layered distribution of the dielectric properties in shales and the uniform distribution in sandstones are clearly identified using the OIRD signals. In shales, the micro-cracks and particle orientation result in directional changes of the dielectric and surface properties, and thus, the isotropy and anisotropy of the rock can be characterized by OIRD. As the dielectric and surface properties are closely related to the hydrocarbon-bearing features in oil-gas reservoirs, we believe that the precise measurement carried with OIRD can help in improving the recovery efficiency in well-drilling process.

Depositional Architecture of Late Cambrian-Early Ordovician Siliciclastic Barik Formation; Al Huqf Area, Oman

NASA Astrophysics Data System (ADS)

Abbasi, Iftikhar Ahmed

2017-04-01

Early Paleozoic siliciclastics sediments of the Haima Supergroup are subdivided into a number of formations and members based on lithological characteristics of various rock sequences. One of the distinct sandstone sequence, the Barik Formation (Late Cambrian-Early Ordovician) of the Andam Group is a major deep gas reservoir in central Oman. The sandstone bodies are prospective reservoir rocks while thick shale and clay interbeds act as effective seal. Part of the Barik Formation (lower and middle part) is exposed in isolated outcrops in Al Huqf area as interbedded multistoried sandstone, and green and red shale. The sandstone bodies are up to 2 meters thick and can be traced laterally for 300 m to over 1 km. Most of sandstone bodies show both lateral and vertical stacking. Two types of sandstone lithofacies are identified on the basis of field characteristics; a plane-bedded sandstone lithofacies capping thick red and green color shale beds, and a cross-bedded sandstone lithofacies overlying the plane-bedded sandstone defining coarsening upward sequences. The plane-bedded sandstone at places contains Cruziana ichnofacies and bivalve fragments indicating deposition by shoreface processes. Thick cross-bedded sandstone is interpreted to be deposited by the fluvial dominated deltaic processes. Load-casts, climbing ripples and flaser-bedding in siltstone and red shale indicate influence of tidal processes at times during the deposition of the formation. This paper summarizes results of a study carried out in Al Huqf area outcrops to analyze the characteristics of the sandstone-body geometry, internal architecture, provenance and diagenetic changes in the lower and middle part of the formation. The study shows build-up of a delta complex and its progradation over a broad, low-angle shelf where fluvial processes operate beside shoreface processes in a vegetation free setting. Keywords: Andam Group, Barik Formation, Ordovician sandstone, Al Huqf, Central Oman,

Consolidation of geologic studies of geopressured-geothermal resources in Texas: Barrier-bar tidal-channel reservoir facies architecture, Jackson Group, Prado field, South Texas; Final report

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

Seni, S.J.; Choh, S.J.

1994-01-01

Sandstone reservoirs in the Jackson barrier/strandplain play are characterized by low recovery efficiencies and thus contain a large hydrocarbon resource target potentially amenable to advanced recovery techniques. Prado field, Jim Hogg County, South Texas, has produced over 23 million bbl of oil and over 32 million mcf gas from combination structural-stratigraphic traps in the Eocene lower Jackson Group. Hydrocarbon entrapment at Prado field is a result of anticlinal nosing by differential compaction and updip pinch-out of barrier bar sandstone. Relative base-level lowering resulted in forced regression that established lower Jackson shoreline sandstones in a relatively distal location in central Jimmore » Hogg County. Reservoir sand bodies at Prado field comprise complex assemblages of barrier-bar, tidal-inlet fill, back-barrier bar, and shoreface environments. Subsequent progradation built the barrier-bar system seaward 1 to 2 mi. Within the barrier-bar system, favorable targets for hydrocarbon reexploration are concentrated in tidal-inlet facies because they possess the greatest degree of depositional heterogeneity. The purpose of this report is (1) to describe and analyze the sand-body architecture, depositional facies variations, and structure of Prado field, (2) to determine controls on distribution of hydrocarbons pertinent to reexploration for bypassed hydrocarbons, (3) to describe reservoir models at Prado field, and (4) to develop new data affecting the suitability of Jackson oil fields as possible candidates for thermally enhanced recovery of medium to heavy oil.« less

Provenance of sandstones in the Golconda terrane, north central Nevada

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

Jones, E.A.

1991-02-01

The upper Paleozoic Golconda terrane of north-central Nevada is a composite of several structurally bounded subterranes made of clastic, volcanic, and carbonate rocks. The clastic rocks provide important clues for the interpretation of the provenance and paleogeographic settings of the different lithologic assemblages found in these subterranes. Two petrographically distinct sandstones are identified in the Golconda terrane in the Osgood Mountains and the Hot springs Range of north-central Nevada. The sandstone of the Mississippian Farrel Canyon Formation, part of the Dry Hills subterrane, is characterized by quartzose and sedimentary and lithic-rich clasts with a small feldspar component. in contrast, themore » sandstone of the Permian Poverty Peak (II) subterrane is a silty quartzarenite with no lithic component, and a very limited feldspar component. The sandstone of the Farrel Canyon Formation is similar to nonvolcanic sandstones reported from elsewhere in the Golconda terrane. Modal data reflect a provenance of a recycled orogen and permit the interpretation that it could have been derived from the antler orogen as has been proposed for other sandstones of the golconda terrane. The sandstone of the Poverty Peak (II) subterrane is more mature than any of the other sandstones in either the Golconda terrane, the Antler overlap sequence, or the Antler foreland basin sequence. Modal data put the Poverty Peak (II) sandstone in the continental block provenance category. The distinct extrabasinal provenances represented in these different sandstones support the idea that the Golconda basin was made up of complex paleogeographic settings, which included multiple sources of extrabasinal sediment.« less

Failure warning of hydrous sandstone based on electroencephalogram technique

NASA Astrophysics Data System (ADS)

Tao, Kai; Zheng, Wei

2018-06-01

Sandstone is a type of rock mass that widely exists in nature. Moisture is an important factor that leads to sandstone structural failure. The major failure assessment methods of hydrous sandstone at present cannot satisfy real-time and portability requirements, especially lacks of warning function. In this study, acoustic emission (AE) and computed tomography (CT) techniques are combined for real-time failure assessment of hydrous sandstone. Eight visual colors for warning are screened according to different failure states, and an electroencephalogram (EEG) experiment is conducted to demonstrate their diverse excitations of the human brain's concentration.

Role of reservoir simulation in development and management of complexly-faulted, multiple-reservoir Dulang field, offshore Malaysia: Holistic strategies

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

Sonrexa, K.; Aziz, A.; Solomon, G.J.

1995-10-01

The Dulang field, discovered in 1981, is a major oil filed located offshore Malaysia in the Malay Basin. The Dulang Unit Area constitutes the central part of this exceedingly heterogeneous field. The Unit Area consists of 19 stacked shaly sandstone reservoirs which are divided into about 90 compartments with multiple fluid contacts owing to severe faulting. Current estimated put the Original-Oil-In-Place (OOIP) in the neighborhood of 700 million stock tank barrels (MMSTB). Production commenced in March 1991 and the current production is more than 50,000 barrels of oil per day (BOPD). In addition to other more conventional means, reservoir simulationmore » has been employed form the very start as a vital component of the overall strategy to develop and manage this challenging field. More than 10 modeling studies have been completed by Petronas Carigali Sdn. Bhd. (Carigali) at various times during the short life of this field thus far. To add to that, Esso Production Malaysia Inc. (EPMI) has simultaneously conducted a number of independent studies. These studies have dealt with undersaturated compartments as well as those with small and large gas caps. They have paved the way for improved reservoir characterization, optimum development planning and prudent production practices. This paper discusses the modeling approaches and highlights the crucial role these studies have played on an ongoing basis in the development and management of the complexly-faulted, multi-reservoir Dulang Unit Area.« less

Effects of storm runoff on the thermal regime and water quality of a deep, stratified reservoir in a temperate monsoon zone, in Northwest China.

PubMed

Huang, Tinglin; Li, Xuan; Rijnaarts, Huub; Grotenhuis, Tim; Ma, Weixing; Sun, Xin; Xu, Jinlan

2014-07-01

Jinpen Reservoir is a deep, stratified reservoir in Shaanxi province, located in a warm temperate zone of Northwest China. Influenced by a temperate monsoon climate, more than 60% of the annual precipitation is concentrated from late summer to autumn (July-September). In recent years, extreme rainfall events occurred more frequently and strongly affected the thermal structure, mixing layer depth and evolution of stratification of Jinpen Reservoir. The reservoir's inflow volume increased sharply after heavy rainfall during the flooding season. Large volumes of inflow induced mixing of stratified water zones in early autumn and disturbed the stratification significantly. A temporary positive effect of such disturbance was the oxygenation of the water close to the bottom of the reservoir, leading to inhibition of the release of nutrients from sediments, especially phosphate. However, the massive inflow induced by storm runoff with increased oxygen-consuming substances led to an increase of the oxygen consumption rate. After the bottom water became anaerobic again, the bottom water quality would deteriorate due to the release of pollutants from sediments. Heavy rainfall events could lead to very high nutrient input into the reservoir due to massive erosion from the surrounding uninhabited steep mountains, and the particulate matter contributed to most nutrient inputs. Reasonably releasing density flow is an effective way to reduce the amounts of particulate associated pollutants entering the reservoir. Significant turbid density flow always followed high rainfall events in Jinpen Reservoir, which not only affected the reservoir water quality but also increased costs of the drinking water treatment plant. Understanding the effects of the storm runoff on the vertical distributions of water quality indicators could help water managers to select the proper position of the intake for the water plant in order to avoid high turbidity outflow. Copyright © 2014 Elsevier B

Numerical simulations of highly buoyant flows in the Castel Giorgio - Torre Alfina deep geothermal reservoir

NASA Astrophysics Data System (ADS)

Volpi, Giorgio; Crosta, Giovanni B.; Colucci, Francesca; Fischer, Thomas; Magri, Fabien

2017-04-01

Geothermal heat is a viable source of energy and its environmental impact in terms of CO2 emissions is significantly lower than conventional fossil fuels. However, nowadays its utilization is inconsistent with the enormous amount of energy available underneath the surface of the earth. This is mainly due to the uncertainties associated with it, as for example the lack of appropriate computational tools, necessary to perform effective analyses. The aim of the present study is to build an accurate 3D numerical model, to simulate the exploitation process of the deep geothermal reservoir of Castel Giorgio - Torre Alfina (central Italy), and to compare results and performances of parallel simulations performed with TOUGH2 (Pruess et al. 1999), FEFLOW (Diersch 2014) and the open source software OpenGeoSys (Kolditz et al. 2012). Detailed geological, structural and hydrogeological data, available for the selected area since early 70s, show that Castel Giorgio - Torre Alfina is a potential geothermal reservoir with high thermal characteristics (120 ° C - 150 ° C) and fluids such as pressurized water and gas, mainly CO2, hosted in a carbonate formation. Our two steps simulations firstly recreate the undisturbed natural state of the considered system and then perform the predictive analysis of the industrial exploitation process. The three adopted software showed a strong numerical simulations accuracy, which has been verified by comparing the simulated and measured temperature and pressure values of the geothermal wells in the area. The results of our simulations have demonstrated the sustainability of the investigated geothermal field for the development of a 5 MW pilot plant with total fluids reinjection in the same original formation. From the thermal point of view, a very efficient buoyant circulation inside the geothermal system has been observed, thus allowing the reservoir to support the hypothesis of a 50 years production time with a flow rate of 1050 t

Sequence-stratigraphic controls on sandstone diagenesis: An example from the Williams Fork formation, Piceance Basin, Colorado

NASA Astrophysics Data System (ADS)

Aboktef, Adel

reasons that are unknown. High total clay content (infiltrated, grain coatings, pseudomatrix) does inhibit quartz overgrowths in all systems tracts. Williams Fork sandstones form low-permeability tight-gas reservoirs. Primary porosity was almost entirely destroyed by compaction and cementation. Reservoir rock resulted from one of two pathways. Eogenetic authigenic chlorite and/or calcite inhibited quartz cementation, minimized compaction and protected some primary porosity. Alternately, dissolution of framework grains or cements created secondary porosity. The later pathway tends to be the more dominant.

Capillary trapping quantification in sandstones using NMR relaxometry

NASA Astrophysics Data System (ADS)

Connolly, Paul R. J.; Vogt, Sarah J.; Iglauer, Stefan; May, Eric F.; Johns, Michael L.

2017-09-01

Capillary trapping of a non-wetting phase arising from two-phase immiscible flow in sedimentary rocks is critical to many geoscience scenarios, including oil and gas recovery, aquifer recharge and, with increasing interest, carbon sequestration. Here we demonstrate the successful use of low field 1H Nuclear Magnetic Resonance [NMR] to quantify capillary trapping; specifically we use transverse relaxation time [T2] time measurements to measure both residual water [wetting phase] content and the surface-to-volume ratio distribution (which is proportional to pore size] of the void space occupied by this residual water. Critically we systematically confirm this relationship between T2 and pore size by quantifying inter-pore magnetic field gradients due to magnetic susceptibility contrast, and demonstrate that our measurements at all water saturations are unaffected. Diffusion in such field gradients can potentially severely distort the T2-pore size relationship, rendering it unusable. Measurements are performed for nitrogen injection into a range of water-saturated sandstone plugs at reservoir conditions. Consistent with a water-wet system, water was preferentially displaced from larger pores while relatively little change was observed in the water occupying smaller pore spaces. The impact of cyclic wetting/non-wetting fluid injection was explored and indicated that such a regime increased non-wetting trapping efficiency by the sequential occupation of the most available larger pores by nitrogen. Finally the replacement of nitrogen by CO2 was considered; this revealed that dissolution of paramagnetic minerals from the sandstone caused by its exposure to carbonic acid reduced the in situ bulk fluid T2 relaxation time on a timescale comparable to our core flooding experiments. The implications of this for the T2-pore size relationship are discussed.

Search for hydraulic connectivity between surface reservoirs and surrounding aquifers in the reservoir-triggered seismic environment (Koyna region, India) using hydrochemical and isotopic signatures

NASA Astrophysics Data System (ADS)

Reddy, D. V.; Nagabhushanam, P.

2016-01-01

Triggered seismicity is an accepted hypothesis in the present days. However, detailed hydrogeological investigations are lacking in the well-known reservoir-triggered seismic (RTS) zones. Here, we made an attempt to understand the direct linkage between the well-known Koyna-Warna reservoirs believed to be under the RTS zone (situated in the Deccan volcanic province (DVP), India) and the surrounding groundwater system up to 250 m deep from the ground surface. Seismic activity in the region started soon after the impoundment of water in the Koyna reservoir and being continued over the last four and a half decades. Though researchers have carried out numerous studies on the Koyna seismicity, no hydrogeological investigations were attempted. Hence, hydrogeological, hydrochemical, and isotopic investigations were carried out for 7 years on groundwaters from 15 deep bore wells (up to 250 m) and two surface reservoir waters to elucidate the direct hydraulic connectivity between them. No appreciable seasonal change was observed in piezometric heads of the artesian wells, but the semi-artesian wells did show fluctuation of ~2 to 12 m during different years, which did not have any relation with the reservoir water levels. No considerable seasonal change in hydrochemistry was observed in individual wells due to the confined nature of the aquifers. The hydrochemical and δ18O data of the studied deep groundwaters and reservoir waters, being different from each other, rule out the possibility of direct hydraulic connectivity between them and surrounding groundwater (up to 250 m), even though favorable topographic conditions exist for linkage. The radiocarbon ages, being incomparable between different well waters, support the inference drawn from hydrochemistry and stable isotope data.

Petrofacies Analysis - A Petrophysical Tool for Geologic/Engineering Reservoir Characterization

USGS Publications Warehouse

Watney, W.L.; Guy, W.J.; Doveton, J.H.; Bhattacharya, S.; Gerlach, P.M.; Bohling, Geoffrey C.; Carr, T.R.

1998-01-01

Petrofacies analysis is defined as the characterization and classification of pore types and fluid saturations as revealed by petrophysical measurements of a reservoir. The word "petrofacies" makes an explicit link between petroleum engineers' concerns with pore characteristics as arbiters of production performance and the facies paradigm of geologists as a methodology for genetic understanding and prediction. In petrofacies analysis, the porosity and resistivity axes of the classical Pickett plot are used to map water saturation, bulk volume water, and estimated permeability, as well as capillary pressure information where it is available. When data points are connected in order of depth within a reservoir, the characteristic patterns reflect reservoir rock character and its interplay with the hydrocarbon column. A third variable can be presented at each point on the crossplot by assigning a color scale that is based on other well logs, often gamma ray or photoelectric effect, or other derived variables. Contrasts between reservoir pore types and fluid saturations are reflected in changing patterns on the crossplot and can help discriminate and characterize reservoir heterogeneity. Many hundreds of analyses of well logs facilitated by spreadsheet and object-oriented programming have provided the means to distinguish patterns typical of certain complex pore types (size and connectedness) for sandstones and carbonate reservoirs, occurrences of irreducible water saturation, and presence of transition zones. The result has been an improved means to evaluate potential production, such as bypassed pay behind pipe and in old exploration wells, or to assess zonation and continuity of the reservoir. Petrofacies analysis in this study was applied to distinguishing flow units and including discriminating pore type as an assessment of reservoir conformance and continuity. The analysis is facilitated through the use of colorimage cross sections depicting depositional sequences

A rock physics and seismic reservoir characterization study of the Rock Springs Uplift, a carbon dioxide sequestration site in Southwestern Wyoming

DOE PAGES

Grana, Dario; Verma, Sumit; Pafeng, Josiane; ...

2017-06-20

We present a reservoir geophysics study, including rock physics modeling and seismic inversion, of a carbon dioxide sequestration site in Southwestern Wyoming, namely the Rock Springs Uplift, and build a petrophysical model for the potential injection reservoirs for carbon dioxide sequestration. Our objectives include the facies classification and the estimation of the spatial model of porosity and permeability for two sequestration targets of interest, the Madison Limestone and the Weber Sandstone. The available dataset includes a complete set of well logs at the location of the borehole available in the area, a set of 110 core samples, and a seismicmore » survey acquired in the area around the well. The proposed study includes a formation evaluation analysis and facies classification at the well location, the calibration of a rock physics model to link petrophysical properties and elastic attributes using well log data and core samples, the elastic inversion of the pre-stack seismic data, and the estimation of the reservoir model of facies, porosity and permeability conditioned by seismic inverted elastic attributes and well log data. In particular, the rock physics relations are facies-dependent and include granular media equations for clean and shaley sandstone, and inclusion models for the dolomitized limestone. The permeability model has been computed by applying a facies-dependent porosity-permeability relation calibrated using core sample measurements. Finally, the study shows that both formations show good storage capabilities. The Madison Limestone includes a homogeneous layer of high-porosity high-permeability dolomite; the Weber Sandstone is characterized by a lower average porosity but the layer is thicker than the Madison Limestone.« less

A rock physics and seismic reservoir characterization study of the Rock Springs Uplift, a carbon dioxide sequestration site in Southwestern Wyoming

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

Grana, Dario; Verma, Sumit; Pafeng, Josiane

We present a reservoir geophysics study, including rock physics modeling and seismic inversion, of a carbon dioxide sequestration site in Southwestern Wyoming, namely the Rock Springs Uplift, and build a petrophysical model for the potential injection reservoirs for carbon dioxide sequestration. Our objectives include the facies classification and the estimation of the spatial model of porosity and permeability for two sequestration targets of interest, the Madison Limestone and the Weber Sandstone. The available dataset includes a complete set of well logs at the location of the borehole available in the area, a set of 110 core samples, and a seismicmore » survey acquired in the area around the well. The proposed study includes a formation evaluation analysis and facies classification at the well location, the calibration of a rock physics model to link petrophysical properties and elastic attributes using well log data and core samples, the elastic inversion of the pre-stack seismic data, and the estimation of the reservoir model of facies, porosity and permeability conditioned by seismic inverted elastic attributes and well log data. In particular, the rock physics relations are facies-dependent and include granular media equations for clean and shaley sandstone, and inclusion models for the dolomitized limestone. The permeability model has been computed by applying a facies-dependent porosity-permeability relation calibrated using core sample measurements. Finally, the study shows that both formations show good storage capabilities. The Madison Limestone includes a homogeneous layer of high-porosity high-permeability dolomite; the Weber Sandstone is characterized by a lower average porosity but the layer is thicker than the Madison Limestone.« less

Sequence Stratigraphy of the Dakota Sandstone, Eastern San Juan Basin, New Mexico, and its Relationship to Reservoir Compartmentalization

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

Varney, Peter J.

2002-04-23

This research established the Dakota-outcrop sequence stratigraphy in part of the eastern San Juan Basin, New Mexico, and relates reservoir quality lithologies in depositional sequences to structure and reservoir compartmentalization in the South Lindrith Field area. The result was a predictive tool that will help guide further exploration and development.

Optimization of Well Configuration for a Sedimentary Enhanced Geothermal Reservoir

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

Zhou, Mengnan; Cho, JaeKyoung; Zerpa, Luis E.

The extraction of geothermal energy in the form of hot water from sedimentary rock formations could expand the current geothermal energy resources toward new regions. From previous work, we observed that sedimentary geothermal reservoirs with relatively low permeability would require the application of enhancement techniques (e.g., well hydraulic stimulation) to achieve commercial production/injection rates. In this paper we extend our previous work to develop a methodology to determine the optimum well configuration that maximizes the hydraulic performance of the geothermal system. The geothermal systems considered consist of one vertical well doublet system with hydraulic fractures, and three horizontal well configurationsmore » with open-hole completion, longitudinal fractures and transverse fractures, respectively. A commercial thermal reservoir simulation is used to evaluate the geothermal reservoir performance using as design parameters the well spacing and the length of the horizontal wells. The results obtained from the numerical simulations are used to build a response surface model based on the multiple linear regression method. The optimum configuration of the sedimentary geothermal systems is obtained from the analysis of the response surface model. The proposed methodology is applied to a case study based on a reservoir model of the Lyons sandstone formation, located in the Wattenberg field, Denver-Julesburg basin, Colorado.« less

Quantitative petrographic analysis of Desmoinesian sandstones from Oklahoma

USGS Publications Warehouse

Dyman, Thaddeus S.

1989-01-01

Desmoinesian sandstones from the northern Oklahoma platform and the Anadarko, Arkoma, and Ardmore basins record a complex interaction between mid-Pennsylvanian source-area tectonism and cyclic sedimentation patterns associated with numerous transgressions and regressions. Framework-grain summaries for 50 thin sections from sandstones of the Krebs, Cabaniss, and Marmaton Groups and their surface and subsurface equivalents were subjected to multivariate statistical analyses to establish regional compositional trends for provenance analysis. R-mode cluster and correspondence analyses were used to determine the contributing effect (total variance) of key framework grains. Fragments of monocrystalline and polycrystalline quartz; potassium and plagioclase feldspar; chert; and metamorphic, limestone, and mudstone-sandstone rock fragments contribute most to the variation in the grain population. Q-mode cluster and correspondence analyses were used to identify four petrofacies and establish the range of compositional variation in Desmoinesian sandstones. Petrofacies I is rich in monocrystalline quartz (78-98%); mica and rock fragments are rare. Petrofacies II is also rich in monocrystalline quartz (60-84%) and averages 12% total rock fragments. Petrofacies III and IV are compositionally heterogeneous and contain variable percentages of monocrystalline and polycrystalline quartz, potassium feldspar, mica, chert, and metamorphic and sedimentary rock fragments. Quantitative analyses indicate that Desmoinesian sandstones were derived from sedimentary, igneous, and metamorphic source areas. Sandstones of petrofacies I and II occur mostly in the lower Desmoinesian and are widely distributed, although they are most abundant in eastern and central Oklahoma; sandstones of petrofacies III and IV are widely distributed and occur primarily in the middle and upper Desmoinesian. The range of compositional variation and the distribution of petrofacies are related to paleotectonics and

High-resolution mapping of yield curve shape and evolution for high porosity sandstones

NASA Astrophysics Data System (ADS)

Bedford, J. D.; Faulkner, D.; Wheeler, J.; Leclere, H.

2017-12-01

The onset of permanent inelastic deformation for porous rock is typically defined by a yield curve plotted in P-Q space, where P is the effective mean stress and Q is the differential stress. Sandstones usually have broadly elliptical shaped yield curves, with the low pressure side of the ellipse associated with localized brittle faulting (dilation) and the high pressure side with distributed ductile deformation (compaction). However recent works have shown that these curves might not be perfectly elliptical and that significant evolution in shape occurs with continued deformation. We therefore use a novel stress-probing methodology to map in high-resolution the yield curve shape for Boise and Idaho Gray sandstones (36-38% porosity) and also investigate curve evolution with increasing deformation. The data reveal yield curves with a much flatter geometry than previously recorded for porous sandstone and that the compactive side of the curve is partly comprised of a near vertical limb. The yield curve evolution is found to be strongly dependent on the nature of inelastic strain. Samples that were compacted under a deviatoric load, with a component of inelastic shear strain, were found to have yield curves with peaks that are approximately 50% higher than similar porosity samples that were hydrostatically compacted (i.e. purely volumetric strain). The difference in yield curve evolution along the different loading paths is attributed to mechanical anisotropy that develops during deviatoric loading by the closure of preferentially orientated fractures. Increased shear strain also leads to the formation of a plateau at the peak of the yield curve as samples deform along the deviatoric loading path. These results have important implications for understanding how the strength of porous rock evolves along different stress paths, including during fluid extraction from hydrocarbon reservoirs where the stress state is rarely isotropic.

Geology of the Gladys McCall geopressured-geothermal prospect, Cameron Parish, Louisiana

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

John, C.J.

The Gladys McCall prospect lies at the western edge of the Rockefeller Wildlife Refuge about 88 km (55 mi) southeast of Lake Charles in Cameron Parish, Louisiana. The test well is 4825 m (15,831 ft) deep and was drilled in 1981 under the U.S. Department of Energy geopressured-geothermal research program. The well was shut in at the end of October 1987 after it had produced over 27 million barrels of brine and 676 MMscf gas, without any significant pressure decline. The stratigraphic section seen in this test well consists of alternating sandstones and shales with about 350 m (1150 ft)more » of net sand between 4393 m (14,412 ft) and 4974 m (16,320 ft). The producing reservoir is bounded on the north and south by faults. The east-west dimension is poorly defined due to lack of deep well control. Eleven prospective production zones have been identified. The pressure maintenance and the continuous high brine yield from the reservoir may be due to laterally overlapping and connected sandstones, communication between overlying and/or underlying reservoirs, growth faults acting as passageways for brine, shale dewatering, or possible communication of zones behind the casing.« less

Secondary oil recovery from selected Carter sandstone oilfields--Black Warrior Basin, Alabama. Final report

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

Anderson, J.C.

1995-02-01

Producibility problems, such as low reservoir pressure and reservoir heterogeneity, have severely limited oil production from the Central Bluff and North Fairview fields. Specific objectives for this project were: To successfully apply detailed geologic and engineering studies with conventional waterflood technologies to these fields in an effort to increase the ultimate economic recovery of oil from Carter sandstone fields; To extensively model, test and evaluate these technologies; thereby, developing a sound methodology for their use and optimization; and To team with Advanced Resources International and the US DOE to assimilate and transfer the information and results gathered from this studymore » to other oil companies to encourage the widespread use of these technologies. At Central Bluff, water injection facilities were constructed and water injection into one well began in January 1993. Oil response from the waterflood has been observed at both producing wells. One of the producing wells has experienced early water breakthrough and a concomitant drop in secondary oil rate. A reservoir modeling study was initiated to help develop an appropriate operating strategy for Central Bluff. For the North Fairview unit waterflood, a previously abandoned well was converted for water injection which began in late June 1993. The reservoir is being re-pressurized, and unit water production has remained nil since flood start indicating the possible formation of an oil bank. A reservoir simulation to characterize the Carter sand at North Fairview was undertaken and the modeling results were used to forecast field performance. The project was terminated due to unfavorable economics. The factors contributing to this decision were premature water breakthrough at Central Bluff, delayed flood response at North Fairview and stalled negotiations at the South Bluff site.« less

Results of the multiwell experiment in situ stresses, natural fractures, and other geological controls on reservoirs

NASA Astrophysics Data System (ADS)

Lorenz, John C.; Warpinski, Norman R.; Teufel, Lawrence W.; Branagan, Paul T.; Sattler, Allan R.; Northrop, David A.

Hundreds of millions of cubic meters of natural gas are locked up in low-permeability, natural gas reservoirs. The Multiwell Experiment (MWX) was designed to characterize such reservoirs, typical of much of the western United States, and to assess and develop a technology for the production of this unconventional resource. Flow-rate tests of the MWX reservoirs indicate a system permeability that is several orders of magnitude higher than laboratory permeability measurements made on matrix-rock sandstones. This enhanced permeability is caused by natural fractures. The single set of fractures present in the reservoirs provides a significant permeability anisotropy that is aligned with the maximum in situ horizontal stress. Hydraulic fractures therefore form parallel to the natural fractures and are consequently an inefficient mechanism for stimulation. Successful stimulation may be possible by perturbing the local stress field with a large hydraulic fracture in one well so that a second hydraulic fracture in an offset well propagates transverse to the natural fracture permeability trend.

Infrastructure and mechanical properties of a fault zone in sandstone as an outcrop analogue of a potential geothermal reservoir

NASA Astrophysics Data System (ADS)

Bauer, J. F.; Meier, S.; Philipp, S. L.

2013-12-01

Due to high drilling costs of geothermal projects, it is economically sensible to assess the potential suitability of a reservoir prior to drilling. Fault zones are of particular importance, because they may enhance fluid flow, or be flow barriers, respectively, depending on their particular infrastructure. Outcrop analogue studies are useful to analyze the fault zone infrastructure and thereby increase the predictability of fluid flow behavior across fault zones in the corresponding deep reservoir. The main aims of the present study are to 1) analyze the infrastructure and the differences of fracture system parameters in fault zones and 2) determine the mechanical properties of the faulted rocks. We measure fracture frequencies as well as orientations, lengths and apertures and take representative rock samples for each facies to obtain Young's modulus, compressive and tensile strengths in the laboratory. Since fractures reduce the stiffnesses of in situ rock masses we use an inverse correlation of the number of discontinuities to calculate effective (in situ) Young's moduli to investigate the variation of mechanical properties in fault zones. In addition we determine the rebound hardness, which correlates with the compressive strength measured in the laboratory, with a 'Schmidt-Hammer' in the field because this allows detailed maps of mechanical property variations within fault zones. Here we present the first results for a fault zone in the Triassic Lower Bunter of the Upper Rhine Graben in France. The outcrop at Cleebourg exposes the damage zone of the footwall and a clear developed fault core of a NNW-SSE-striking normal fault. The approximately 15 m wide fault core consists of fault gouge, slip zones, deformation bands and host rock lenses. Intensive deformation close to the core led to the formation of a distal fault core, a 5 m wide zone with disturbed layering and high fracture frequency. The damage zone also contains more fractures than the host rock

Lacustrine Environment Reservoir Properties on Sandstone Minerals and Hydrocarbon Content: A Case Study on Doba Basin, Southern Chad

NASA Astrophysics Data System (ADS)

Sumery, N. F. Mohd; Lo, S. Z.; Salim, A. M. A.

2017-10-01

The contribution of lacustrine environment as the hydrocarbon reservoir has been widely known. However, despite its growing importance, the lacustrine petroleum geology has received far less attention than marine due to its sedimentological complexity. This study therefore aims in developing an understanding of the unique aspects of lacustrine reservoirs which eventually impacts the future exploration decisions. Hydrocarbon production in Doba Basin, particularly the northern boundary, for instance, has not yet succeeded due to the unawareness of its depositional environment. The drilling results show that the problems were due to the: radioactive sand and waxy oil/formation damage, which all are related to the lacustrine depositional environment. Detailed study of geological and petrophysical integration on wireline logs and petrographic thin sections analysis of this environment helps in distinguishing reservoir and non-reservoir areas and determining the possible mechanism causing the failed DST results. The interpretations show that the correlation of all types> of logs and rho matrix analysis are capable in identifying sand and shale bed despite of the radioactive sand present. The failure of DST results were due to the presence of arkose in sand and waxy oil in reservoir bed. This had been confirmed by the petrographic thin section analysis where the arkose has mineral twinning effect indicate feldspar and waxy oil showing bright colour under fluorescent light. Understanding these special lacustrine environment characteristics and features will lead to a better interpretation of hydrocarbon prospectivity for future exploration.

Testing the Injectivity of CO2 in a Sub-surface Heterogeneous Reservoir

NASA Astrophysics Data System (ADS)

Sundal, A.; Nystuen, J.; Dypvik, H.; Aagaard, P.

2011-12-01

This case study on subsurface reservoir characterization, considers the effect of geological heterogeneities on the storage capacity and injectivity of the Johansen Formation, which is a deep, saline aquifer underlying the Troll Gas Field off the Norwegian coast. The Johansen Formation has been interpreted as a sandy, prograding unit, deposited in a shallow marine environment during Early Jurassic time, and is overlain by a shaly unit; the Amundsen Formation. It appears as a wedge shaped sandstone body, up to 140m thick, with an areal extent in the order of 10 000 km2. The Johansen Formation is currently being considered for large scale CO2 storage from two gas power plants situated on the west coast of Norway, both of which will operate with full scale CO2 handling, as proposed by Norwegian authorities. The storage capacity needed is in the order of 3 Mt CO2/year. With access to a new 3D seismic survey (Gassnova, 2010), and based on existing well log data from 25 penetrating wells, we have studied large scale geometries and intra-formational features, and built a geo-conceptual model of the Johansen Formation. The reservoir is heterogeneous, with distinct permeability zonation within clinothems separated by less permeable layers. In order to obtain better understanding of crucial reservoir parameters and supplement limited data, comparison of data from easily accessible analogue rock units is useful. For this purpose the unit should be well exposed and thoroughly documented, such as the Panther Tongue Member (Star Point Formation, Mesa Verde Group) in Book Cliffs, from which we have collected some comparable permeability estimates for the model. On a micro scale, mineralogy, grain size/shape and pore geometry constitue major controls on reservoir porosity and permeability. Direct geological information is at this point in time limited to a few meters of core, from which detailed mineralogical information has been derived (optical microscopy, SEM, XRD), and some

Producing Light Oil from a Frozen Reservoir: Reservoir and Fluid Characterization of Umiat Field, National Petroleum Reserve, Alaska

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

Hanks, Catherine

Umiat oil field is a light oil in a shallow, frozen reservoir in the Brooks Range foothills of northern Alaska with estimated oil-in-place of over 1 billion barrels. Umiat field was discovered in the 1940’s but was never considered viable because it is shallow, in the permafrost, and far from any transportation infrastructure. The advent of modern drilling and production techniques has made Umiat and similar fields in northern Alaska attractive exploration and production targets. Since 2008 UAF has been working with Renaissance Alaska Inc. and, more recently, Linc Energy, to develop a more robust reservoir model that can bemore » combined with rock and fluid property data to simulate potential production techniques. This work will be used to by Linc Energy as they prepare to drill up to 5 horizontal wells during the 2012-2013 drilling season. This new work identified three potential reservoir horizons within the Cretaceous Nanushuk Formation: the Upper and Lower Grandstand sands, and the overlying Ninuluk sand, with the Lower Grandstand considered the primary target. Seals are provided by thick interlayered shales. Reserve estimates for the Lower Grandstand alone range from 739 million barrels to 2437 million barrels, with an average of 1527 million bbls. Reservoir simulations predict that cold gas injection from a wagon-wheel pattern of multilateral injectors and producers located on 5 drill sites on the crest of the structure will yield 12-15% recovery, with actual recovery depending upon the injection pressure used, the actual Kv/Kh encountered, and other geologic factors. Key to understanding the flow behavior of the Umiat reservoir is determining the permeability structure of the sands. Sandstones of the Cretaceous Nanushuk Formation consist of mixed shoreface and deltaic sandstones and mudstones. A core-based study of the sedimentary facies of these sands combined with outcrop observations identified six distinct facies associations with distinctive

Major hydrogeochemical processes in the two reservoirs of the Yangbajing geothermal field, Tibet, China

NASA Astrophysics Data System (ADS)

Guo, Qinghai; Wang, Yanxin; Liu, Wei

2007-10-01

The Yangbajing geothermal field with the highest reservoir temperature in China is located about 90 km northwest to Lhasa City, capital of Tibet, where high temperature geothermal fluids occur both in shallow and deep reservoirs. The geophysical survey by the INDEPTH (International Deep Profiling of Tibet and the Himalayas) project group proved the existence of magmatic heat source at Yangbajing. In the study area, the hydrochemistry of cold surface waters and groundwaters and that of thermal groundwaters from both reservoirs are distinctively different. However, analysis of the relationship between enthalpy values and Cl concentrations of cold groundwaters and geothermal fluids indicates that the geothermal fluids from the shallow reservoir were formed as a result of mixing of cold groundwaters with geothermal fluids from the deep reservoir. In other words, the geothermal fluids from the deep reservoir flowed upwards into the shallow reservoir where it was diluted by the shallow cold groundwaters to form the shallow geothermal fluids with much lower temperature. A binary mixing model with two endmembers (the cold groundwaters and the deep geothermal fluids) was proposed and the mixing ratios for the geothermal fluid from each shallow well were estimated. Using the mixing ratios, the concentrations of some constituents in shallow geothermal fluids, such as As, B, SiO 2, SO 42- and F, were calculated and their differences with the actual concentrations were estimated. The results show that the differences between estimated and actual concentrations of As and B are small (the average absolute values being only 1.9% and 7.9%, respectively), whereas those of SiO 2, SO 42- and F are much bigger, indicating that other hydrogeochemical processes are responsible for the concentrations of these constituents. It is postulated that SiO 2 precipitation due to water temperature decrease, H 2S oxidation and ion exchange between OH - in geothermal waters and exchangeable F - in

Post waterflood CO{sub 2} miscible flood in light oil, fluvial-dominated deltaic reservoir. FY 1993 annual report

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

Davis, D.W.

1995-03-01

The project is a Class 1 DOE-sponsored field demonstration project of a CO{sub 2} miscible flood project at the Port Neches Field in Orange County, Texas. The project will determine the recovery efficiency of CO{sub 2} flooding a waterflooded and a partial waterdrive sandstone reservoir at a depth of 5,800. The project will also evaluate the use of a horizontal CO{sub 2} injection well placed at the original oil-water contact of the waterflooded reservoir. A PC-based reservoir screening model will be developed by Texaco`s research lab in Houston and Louisiana State University will assist in the development of a databasemore » of fluvial-dominated deltaic reservoirs where CO{sub 2} flooding may be applicable. This technology will be transferred throughout the oil industry through a series of technical papers and industry open forums.« less

A relationship between porosity and permeability of carbonate rock reservoirs

NASA Astrophysics Data System (ADS)

Lee, J.; Park, Y.; Jo, Y.; Jeong, J.; Eom, S.

2009-12-01

Most of oil reservoirs in the world occur in carbonate rocks. Thus, characterization of the carbonate reservoirs, including understanding the correlation between porosity and permeability is essentially required to enhance oil recovery. Compared with the other sedimentary rocks such as sandstone and shale, the carbonate rocks would exhibit a wide variety of vertical and horizontal heterogeneities. In general, pores of the carbonate rocks can be affected by mineral dissolution, replacement by other minerals and re-crystallization, which are the post-depositional processes. Permeability has been estimated at a wide scale by thin section image analysis, rock core experiments, geophysical well logging data and large scale aquifer tests. For the same porosity, the permeability might show a wide variation. In this study, a large number of the porosity and the permeability data pairs for world wide carbonate rocks (reservoirs) were collected from many literatures. The porosity and permeability data were grouped according to test scale, the reservoir location and the rock types. As is already known, the relation showed a rather scattered distribution also in this study, not monotonous, which indicates that higher porosity does not mean higher permeability of the rock formation. This study provides the analysis results and implications for oil production of the carbonate reservoirs. This research was funded by Energy Efficiency and Resources Program of KETEP (Korea Institute of Energy Technology Evaluation and Planning), Grant No. 2009T100200058.

Sensing, Measuring and Modelling the Mechanical Properties of Sandstone

NASA Astrophysics Data System (ADS)

Antony, S. J.; Olugbenga, A.; Ozerkan, N. G.

2018-02-01

We present a hybrid framework for simulating the strength and dilation characteristics of sandstone. Where possible, the grain-scale properties of sandstone are evaluated experimentally in detail. Also, using photo-stress analysis, we sense the deviator stress (/strain) distribution at the micro-scale and its components along the orthogonal directions on the surface of a V-notch sandstone sample under mechanical loading. Based on this measurement and applying a grain-scale model, the optical anisotropy index K 0 is inferred at the grain scale. This correlated well with the grain contact stiffness ratio K evaluated using ultrasound sensors independently. Thereafter, in addition to other experimentally characterised structural and grain-scale properties of sandstone, K is fed as an input into the discrete element modelling of fracture strength and dilation of the sandstone samples. Physical bulk-scale experiments are also conducted to evaluate the load-displacement relation, dilation and bulk fracture strength characteristics of sandstone samples under compression and shear. A good level of agreement is obtained between the results of the simulations and experiments. The current generic framework could be applied to understand the internal and bulk mechanical properties of such complex opaque and heterogeneous materials more realistically in future.

Rupture propagation behavior and the largest possible earthquake induced by fluid injection into deep reservoirs

NASA Astrophysics Data System (ADS)

Gischig, Valentin S.

2015-09-01

Earthquakes caused by fluid injection into deep underground reservoirs constitute an increasingly recognized risk to populations and infrastructure. Quantitative assessment of induced seismic hazard, however, requires estimating the maximum possible magnitude earthquake that may be induced during fluid injection. Here I seek constraints on an upper limit for the largest possible earthquake using source-physics simulations that consider rate-and-state friction and hydromechanical interaction along a straight homogeneous fault. Depending on the orientation of the pressurized fault in the ambient stress field, different rupture behaviors can occur: (1) uncontrolled rupture-front propagation beyond the pressure front or (2) rupture-front propagation arresting at the pressure front. In the first case, fault properties determine the earthquake magnitude, and the upper magnitude limit may be similar to natural earthquakes. In the second case, the maximum magnitude can be controlled by carefully designing and monitoring injection and thus restricting the pressurized fault area.

Elevated Uranium in Aquifers of the Jacobsville Sandstone

NASA Astrophysics Data System (ADS)

Sherman, H.; Gierke, J.

2003-12-01

The EPA has announced a new standard for uranium in drinking water of 30 parts per billion (ppb). This maximum contaminant level (MCL) takes effect for community water supplies December 2003. The EPA's ruling has heightened awareness among residential well owners that uranium in drinking water may increase the risk of kidney disease and cancer and has created a need for a quantified, scientific understanding of the occurrence and distribution of uranium isotopes in aquifers. The authors are investigating the occurrence of elevated uranium in northern Michigan aquifers of the Middle Proterozoic Jacobsville sandstone, a red to mottled sequence of sandstones, conglomerates, siltstones and shales deposited as basin fill in the 1.1 Ga Midcontinent rift. Approximately 25% of 300 well water samples tested for isotopic uranium have concentrations above the MCL. Elevated uranium occurrences are distributed throughout the Jacobsville sandstone aquifers stretching across Michigan's Upper Peninsula. However, there is significant variation in well water uranium concentrations (from 0.01 to 190 ppb) and neighboring wells do not necessarily have similar concentrations. The authors are investigating hydrogeologic controls on ground water uranium concentrations in the Jacobsville sandstone, e.g. variations in lithology, mineralogy, groundwater residence time and geochemistry. Approximately 2000' of Jacobsville core from the Amoco St. Amour well was examined in conjunction with the spectral gamma ray log run in the borehole. Spikes in equivalent uranium (eU) concentration from the log are frequently associated with clay and heavy mineral layers in the sandstone core. The lithology and mineralogy of these layers will be determined by analysis of thin sections and x-ray diffraction. A portable spectrometer, model GRS-2000/BL, will be used on the sandstone cliffs along Lake Superior to characterize depositional and lithologic facies of the Jacobsville sandstone in terms of

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.

Real-time detection of dielectric anisotropy or isotropy in unconventional oil-gas reservoir rocks supported by the oblique-incidence reflectivity difference technique

PubMed Central

Zhan, Honglei; Wang, Jin; Zhao, Kun; Lű, Huibin; Jin, Kuijuan; He, Liping; Yang, Guozhen; Xiao, Lizhi

2016-01-01

Current geological extraction theory and techniques are very limited to adequately characterize the unconventional oil-gas reservoirs because of the considerable complexity of the geological structures. Optical measurement has the advantages of non-interference with the earth magnetic fields, and is often useful in detecting various physical properties. One key parameter that can be detected using optical methods is the dielectric permittivity, which reflects the mineral and organic properties. Here we reported an oblique-incidence reflectivity difference (OIRD) technique that is sensitive to the dielectric and surface properties and can be applied to characterization of reservoir rocks, such as shale and sandstone core samples extracted from subsurface. The layered distribution of the dielectric properties in shales and the uniform distribution in sandstones are clearly identified using the OIRD signals. In shales, the micro-cracks and particle orientation result in directional changes of the dielectric and surface properties, and thus, the isotropy and anisotropy of the rock can be characterized by OIRD. As the dielectric and surface properties are closely related to the hydrocarbon-bearing features in oil-gas reservoirs, we believe that the precise measurement carried with OIRD can help in improving the recovery efficiency in well-drilling process. PMID:27976746

Giant calcite concretions in aeolian dune sandstones; sedimentological and architectural controls on diagenetic heterogeneity, mid-Cretaceous Iberian Desert System, Spain

NASA Astrophysics Data System (ADS)

Arribas, Maria Eugenia; Rodríguez-López, Juan Pedro; Meléndez, Nieves; Soria, Ana Rosa; de Boer, Poppe L.

2012-01-01

Aeolian dune sandstones of the Iberian erg system (Cretaceous, Spain) host giant calcite concretions that constitute heterogeneities of diagenetic origin within a potential aeolian reservoir. The giant calcite concretions developed in large-scale aeolian dune foresets, at the transition between aeolian dune toeset and damp interdune elements, and in medium-scale superimposed aeolian dune sets. The chemical composition of the giant concretions is very homogeneous. They formed during early burial by low Mg-calcite precipitation from meteoric pore waters. Carbonate components with yellow/orange luminescence form the nuclei of the poikilotopic calcite cement. These cements postdate earlier diagenetic features, characterized by early mechanical compaction, Fe-oxide cements and clay rims around windblown quartz grains resulting from the redistribution of aeolian dust over the grain surfaces. The intergranular volume (IGV) in friable aeolian sandstone ranges from 7.3 to 15.3%, whereas in cemented aeolian sandstone it is 18.6 to 25.3%. The giant-calcite concretions developed during early diagenesis under the influence of meteoric waters associated with the groundwater flow of the desert basin, although local (e.g. activity of fluid flow through extensional faults) and/or other regional controls (e.g. variations of the phreatic level associated with a variable water influx to the erg system and varying sea level) could have favoured the local development of giant-calcite concretions. The spatial distribution pattern of carbonate grains and the main bounding surfaces determined the spatial distribution of the concretions. In particular, the geometry of the giant calcite concretions is closely associated with main bounding aeolian surfaces. Thus, interdune, superimposition and reactivation surfaces exerted a control on the concretion geometries ranging from flat and tabular ones (e.g. bounded by interdunes) to wedge-shaped concretions at the dune foresets (e.g. bounded by

Transport of silver nanoparticles in single fractured sandstone

NASA Astrophysics Data System (ADS)

Neukum, Christoph

2018-02-01

Silver nanoparticles (Ag-NP) are used in various consumer products and are one of the most prevalent metallic nanoparticle in commodities and are released into the environment. Transport behavior of Ag-NP in groundwater is one important aspect for the assessment of environmental impact and protection of drinking water resources in particular. Ag-NP transport processes in saturated single-fractured sandstones using triaxial flow cell experiments with different kind of sandstones is investigated. Ag-NP concentration and size are analyzed using flow field-flow fractionation and coupled SEM-EDX analysis. Results indicate that Ag-NP are more mobile and show generally lower attachment on rock surface compared to experiments in undisturbed sandstone matrix and partially fractured sandstones. Ag-NP transport is controlled by the characteristics of matrix porosity, time depending blocking of attachment sites and solute chemistry. Where Ag-NP attachment occur, it is heterogeneously distributed on the fracture surface.

Stress-Induced Fracturing of Reservoir Rocks: Acoustic Monitoring and μCT Image Analysis

NASA Astrophysics Data System (ADS)

Pradhan, Srutarshi; Stroisz, Anna M.; Fjær, Erling; Stenebråten, Jørn F.; Lund, Hans K.; Sønstebø, Eyvind F.

2015-11-01

Stress-induced fracturing in reservoir rocks is an important issue for the petroleum industry. While productivity can be enhanced by a controlled fracturing operation, it can trigger borehole instability problems by reactivating existing fractures/faults in a reservoir. However, safe fracturing can improve the quality of operations during CO2 storage, geothermal installation and gas production at and from the reservoir rocks. Therefore, understanding the fracturing behavior of different types of reservoir rocks is a basic need for planning field operations toward these activities. In our study, stress-induced fracturing of rock samples has been monitored by acoustic emission (AE) and post-experiment computer tomography (CT) scans. We have used hollow cylinder cores of sandstones and chalks, which are representatives of reservoir rocks. The fracture-triggering stress has been measured for different rocks and compared with theoretical estimates. The population of AE events shows the location of main fracture arms which is in a good agreement with post-test CT image analysis, and the fracture patterns inside the samples are visualized through 3D image reconstructions. The amplitudes and energies of acoustic events clearly indicate initiation and propagation of the main fractures. Time evolution of the radial strain measured in the fracturing tests will later be compared to model predictions of fracture size.

Sediment pollution characteristics and in situ control in a deep drinking water reservoir.

PubMed

Zhou, Zizhen; Huang, Tinglin; Li, Yang; Ma, Weixing; Zhou, Shilei; Long, Shenghai

2017-02-01

Sediment pollution characteristics, in situ sediment release potential, and in situ inhibition of sediment release were investigated in a drinking water reservoir. Results showed that organic carbon (OC), total nitrogen (TN), and total phosphorus (TP) in sediments increased from the reservoir mouth to the main reservoir. Fraction analysis indicated that nitrogen in ion exchangeable form and NaOH-extractable P (Fe/Al-P) accounted for 43% and 26% of TN and TP in sediments of the main reservoir. The Risk Assessment Code for metal elements showed that Fe and Mn posed high to very high risk. The results of the in situ reactor experiment in the main reservoir showed the same trends as those observed in the natural state of the reservoir in 2011 and 2012; the maximum concentrations of total OC, TN, TP, Fe, and Mn reached 4.42mg/L, 3.33mg/L, 0.22mg/L, 2.56mg/L, and 0.61mg/L, respectively. An in situ sediment release inhibition technology, the water-lifting aerator, was utilized in the reservoir. The results of operating the water-lifting aerator indicated that sediment release was successfully inhibited and that OC, TN, TP, Fe, and Mn in surface sediment could be reduced by 13.25%, 15.23%, 14.10%, 5.32%, and 3.94%, respectively. Copyright © 2016. Published by Elsevier B.V.

Anatomy of anomalously thick sandstone units in the Brent Delta of the northern North Sea

NASA Astrophysics Data System (ADS)

Wei, Xiaojie; Steel, Ronald J.; Ravnås, Rodmar; Jiang, Zaixing; Olariu, Cornel; Ma, Yinsheng

2018-05-01

Some potentially attractive reservoirs, containing anomalously thick (10s to a few 100 m), cross-stratified sandstone, have been locally encountered within both the classic regressive (lower Brent) and the transgressive (upper Brent) segments of the Brent Delta. Three documented cases of these sandstone bodies are re-examined. They are internally dominated by simple or compound dunes, and typified by two types of deepening-upward succession, recording a retrogradational or transgressive shoreline history. Type I is expressed as a single estuarine succession changing upwards from erosive, coarse-grained channelized deposits into outer estuary tidal bar deposits. The estuary is underlain and overlain by deltaic deposits. Type II lacks significant basal river deposits but is composed by stacked mixed-energy and tide-dominated estuarine deposits. It is underlain by deltaic deposits and overlain by open marine sediments. Considering the structural evolution in the northern North Sea basin, we suggest (as did some earlier researchers) that these sandstone bodies were local, but sometimes broad transgressive estuaries, formed at any time during large-scale Brent Delta growth and decay. The estuary generation was likely triggered by fluvial incision coupled with active faulting, producing variable accommodation embayments, where tidal currents became focused and deposition became transgressive. The spatial variations of the interpreted estuary deposits were linked with variable, fault-generated accommodation. The relatively simple, lower Brent estuarine units were created by short-lived, fault activity in places, whereas the complex, stacked upper-Brent estuarine units were likely a result of more long-lived, punctuated fault-induced subsidence leading into the northern North Sea main rifting stage. The thick cross-stratified units potentially accumulated in the hangingwall of large bounding faults.

Jonah field, sublette county, Wyoming: Gas production from overpressured Upper Cretaceous Lance sandstones of the Green River basin

USGS Publications Warehouse

Montgomery, S.L.; Robinson, J.W.

1997-01-01

Jonah field, located in the northwestern Green River basin, Wyoming, produces gas from overpressured fluvial channel sandstones of the Upper Cretaceous Lance Formation. Reservoirs exist in isolated and amalgamated channel facies 10-100 ft (3-30 m) thick and 150-4000 ft (45-1210 m) wide, deposited by meandering and braided streams. Compositional and paleocurrent studies indicate these streams flowed eastward and had their source area in highlands associated with the Wyoming-Idaho thrust belt to the west. Productive sandstones at Jonah have been divided into five pay intervals, only one of which (Jonah interval) displays continuity across most of the field. Porosities in clean, productive sandstones range from 8 to 12%, with core permeabilities of .01-0.9 md (millidarcys) and in-situ permeabilities as low as 3-20 ??d (microdarcys), as determined by pressure buildup analyses. Structurally, the field is bounded by faults that have partly controlled the level of overpressuring. This level is 2500 ft (758 m) higher at Jonah field than in surrounding parts of the basin, extending to the top part of the Lance Formation. The field was discovered in 1975, but only in the 1990s did the area become fully commercial, due to improvements in fracture stimulation techniques. Recent advances in this area have further increased recoverable reserves and serve as a potential example for future development of tight gas sands elsewhere in the Rocky Mountain region.

Paleozoic fluid history of the Michigan Basin: Evidence from dolomite geochemistry in the Middle Ordovician St. Peter Sandstone

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

Winter, B.L.; Johnson, C.M.; Simo, J.A.

1995-04-03

The isotope (Sr and O) and elemental (Mg, Ca, Mn, Fe, and Sr) compositions of the various dolomites in the Middle Ordovician St. Peter Sandstone in the Michigan Basin are determined and the variations are modeled in terms of fluid-rock interaction or as mixing relations. These geochemical models, combined with the paragenetic sequence of the dolomites and late anhydrite cement, suggest the existence of at least four distinct diagenetic fluids in the St. Peter Sandstone during the paleozoic. Fluid 1 has a composition consistent with a modified older (pre-Middle Ordovician) seawater origin, which indicates that the flow path for thismore » fluid had a major upward component. This fluid resulted in the first and volumetrically most important burial dolomitization event, producing dolomite in both carbonate and quartz sandstone lithofacies in the St. Peter Sandstone. Fluid 2 has a composition consistent with a modified Middle to early Late Ordovician seawater origin, suggesting a major downward component for fluid flow. Fluid 2 produced dolomite cement in the carbonate lithofacies that postdates Fluid 1 dolomite. The composition of Fluid 3 is best interpreted to reflect a heated, deep basinal brine that had previously interacted with the K-feldspar-rich rocks near the Cambrian-Precambrian unconformity in the Michigan Basin, indicating a major upward component for fluid flow. Fluid 3 produced dolomite cement in quartz sandstone lithofacies that postdates Fluid 1 dolomite. Fluid 4 resulted in precipitation of late anhydrite in fractures. The {sup 87}Sr/{sup 86}Sr ratio of the anhydrite is consistent with Fluid 4 originating as a dilute fluid that interacted extensively with Silurian gypsum in the Michigan Basin; this indicates that the flow path of Fluid 4 had a major downward component.« less

Kinetics of carbonate dissolution in CO2-saturated aqueous system at reservoir conditions

NASA Astrophysics Data System (ADS)

Peng, Cheng; Crawshaw, John P.; Maitland, Geoffrey; Trusler, J. P. Martin

2014-05-01

In recent years, carbon capture and storage (CCS) has emerged as a key technology for limiting anthropogenic CO2 emissions while allowing the continued utilisation of fossil fuels. The most promising geological storage sites are deep saline aquifers because the capacity, integrity and injection economics are most favourable, and the environmental impact can be minimal. Many rock-fluid chemical reactions are known to occur both during and after CO2 injection in saline aquifers. The importance of rock-fluid reactions in the (CO2 + H2O) system can be understood in terms of their impact on the integrity and stability of both the formation rocks and cap rocks. The chemical interactions between CO2-acidified brines and the reservoir minerals can influence the porosity and permeability of the formations, resulting in changes in the transport processes occurring during CO2 storage. Since carbonate minerals are abundant in sedimentary rocks, one of the requirements to safely implement CO2 storage in saline aquifers is to characterise the reactivity of carbonate minerals in aqueous solutions at reservoir conditions. In this work, we reported measurements of the intrinsic rate of carbonate dissolution in CO2-saturated water under high-temperature high-pressure reservoir conditions extending up to 373 K and 14 MPa. The rate of carbonate dissolution in CO2-free HCl(aq) was also measured at ambient pressure at temperatures up to 353 K. Various pure minerals and reservoir rocks were investigated in this study, including single-crystals of calcite and magnesite, and samples of dolomite, chalks and sandstones. A specially-designed batch reactor system, implementing the rotating disc technique, was used to obtain the intrinsic reaction rate at the solid/liquid interface, free of mass transfer effects. The effective area and mineralogy of the exposed surface was determined by a combination of surface characterisation techniques including XRD, SEM, EDX and optical microscopy. The

Andrew integrated reservoir description

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

Todd, S.P.

1996-12-31

The Andrew field is an oil and gas accumulation in Palaeocene deep marine sands in the Central North Sea. It is currently being developed with mainly horizontal oil producers. Because of the field`s relatively small reserves (mean 118 mmbbls), the performance of each of the 10 or so horizontal wells is highly important. Reservoir description work at sanction time concentrated on supporting the case that the field could be developed commercially with the minimum number of wells. The present Integrated Reservoir Description (IRD) is focussed on delivering the next level of detail that will impact the understanding of the localmore » reservoir architecture and dynamic performance of each well. Highlights of Andrew IRD Include: (1) Use of a Reservoir Uncertainty Statement (RUS) developed at sanction time to focus the descriptive effort of both asset, support and contract petrotechnical staff, (2) High resolution biostratigraphic correlation to support confident zonation of the reservoir, (3) Detailed sedimentological analysis of the core including the use of dipmeter to interpret channel/sheet architecture to provide new insights into reservoir heterogeneity; (4) Integrated petrographical and petrophysical investigation of the controls on Sw-Height and relative permeability of water; (5) Fluids description using oil geochemistry and Residual Salt Analysis Sr isotope studies. Andrew IRD has highlighted several important risks to well performance, including the influence of more heterolithic intervals on gas breakthrough and the controls on water coning exerted by suppressed water relative permeability in the transition zone.« less

Andrew integrated reservoir description

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

Todd, S.P.

1996-01-01

The Andrew field is an oil and gas accumulation in Palaeocene deep marine sands in the Central North Sea. It is currently being developed with mainly horizontal oil producers. Because of the field's relatively small reserves (mean 118 mmbbls), the performance of each of the 10 or so horizontal wells is highly important. Reservoir description work at sanction time concentrated on supporting the case that the field could be developed commercially with the minimum number of wells. The present Integrated Reservoir Description (IRD) is focussed on delivering the next level of detail that will impact the understanding of the localmore » reservoir architecture and dynamic performance of each well. Highlights of Andrew IRD Include: (1) Use of a Reservoir Uncertainty Statement (RUS) developed at sanction time to focus the descriptive effort of both asset, support and contract petrotechnical staff, (2) High resolution biostratigraphic correlation to support confident zonation of the reservoir, (3) Detailed sedimentological analysis of the core including the use of dipmeter to interpret channel/sheet architecture to provide new insights into reservoir heterogeneity; (4) Integrated petrographical and petrophysical investigation of the controls on Sw-Height and relative permeability of water; (5) Fluids description using oil geochemistry and Residual Salt Analysis Sr isotope studies. Andrew IRD has highlighted several important risks to well performance, including the influence of more heterolithic intervals on gas breakthrough and the controls on water coning exerted by suppressed water relative permeability in the transition zone.« less

Production of superheated steam from vapor-dominated geothermal reservoirs

USGS Publications Warehouse

Truesdell, A.H.; White, D.E.

1973-01-01

Vapor-dominated geothermal systems such as Larderello, Italy, The Geysers, California, and Matsukawa, Japan yield dry or superheated steam when exploited. Models for these systems are examined along with production data and the thermodynamic properties of water, steam and rock. It is concluded that these systems initially consist of a water and steam filled reservoir, a water-saturated cap rock, and a water or brine-saturated deep reservoir below a water table. Most liquid water in all parts of the system is relatively immobilized in small pores and crevices; steam dominates the large fractures and voids of the reservoir and is the continuous, pressure-controlling phase. With production, the pressure is lowered and the liquid water boils, causing massive transfer of heat from the rock and its eventual drying. Passage of steam through already dried rock produces superheating. After an initial vaporization of liquid water in the reservoir, the decrease in pressure produces increased boiling below the deep water table. With heavy exploitation, boiling extends deeper into hotter rock and the temperature of the steam increases. This model explains most features of the published production behavior of these systems and can be used to guide exploitation policies. ?? 1973.

The Research and Application of Microbial Degradation Technology on Heavy Oil Reservoir in Huabei Oilfield

NASA Astrophysics Data System (ADS)

Wang, Guan; Wang, Rui; Fu, Yaxiu; Duan, Lisha; Yuan, Xizhi; Zheng, Ya; Wang, Ai; Huo, Ran; Su, Na

2018-06-01

Mengulin sandstone reservoir in Huabei oilfield is low- temperature heavy oil reservoir. Recently, it is at later stage of waterflooding development. The producing degree of water flooding is poor, and it is difficult to keep yield stable. To improve oilfield development effect, according to the characteristics of reservoir geology, microbial enhanced oil recovery to improve oil displacement efficiency is researched. 2 microbial strains suitable for the reservoir conditions were screened indoor. The growth characteristics of strains, compatibility and function mechanism with crude oil were studied. Results show that the screened strains have very strong ability to utilize petroleum hydrocarbon to grow and metabolize, can achieve the purpose of reducing oil viscosity, and can also produce biological molecules with high surface activity to reduce the oil-water interfacial tension. 9 oil wells had been chosen to carry on the pilot test of microbial stimulation, of which 7 wells became effective with better experiment results. The measures effective rate is 77.8%, the increased oil is 1,093.5 tons and the valid is up to 190 days.

Assessing the effects of microbial metabolism and metabolities on reservoir pore structure

USGS Publications Warehouse

Udegbunam, E.O.; Adkins, J.P.; Knapp, R.M.; McInerney, M.J.; Tanner, R.S.

1991-01-01

The effect of microbial treatment on pore structure of sandstone and carbonatereservoirs was determined. Understanding how different bacterial strains and their metabolic bioproducts affect reservoir pore structure will permit the prudent application of microorganisms for enhanced oil recovery. The microbial strains tested included Clostridium acetobutylicum, a polymer-producing Bacillus strain, and an unidentified halophilic anaerobe that mainly produced acids and gases. Electrical conductivity, absolute permeability, porosity and centrifuge capillary pressure were used to examine rock pore structures. Modifications of the pore structure observed in the laboratory cores included pore enlargement due to acid dissolution of carbonates and poare throat reduction due to biomass plugging. This paper shows that careful selection of microbes based on proper understanding of the reservoir petrophysical characteristics is necessary for applications of microbially enhanced oil recovery. These methods and results can be useful to field operators and laboratory researchers involved in design and screening of reservoirs for MEOR. The methods are also applicable in evaluation of formation damage caused by drilling, injection or completion fluids or stimulation caused by acids.

4D inversion of time-lapse magnetotelluric data sets for monitoring geothermal reservoir

NASA Astrophysics Data System (ADS)

Nam, Myung Jin; Song, Yoonho; Jang, Hannuree; Kim, Bitnarae

2017-06-01

The productivity of a geothermal reservoir, which is a function of the pore-space and fluid-flow path of the reservoir, varies since the properties of the reservoir changes with geothermal reservoir production. Because the variation in the reservoir properties causes changes in electrical resistivity, time-lapse (TL) three-dimensional (3D) magnetotelluric (MT) methods can be applied to monitor the productivity variation of a geothermal reservoir thanks to not only its sensitivity to the electrical resistivity but also its deep depth of survey penetration. For an accurate interpretation of TL MT-data sets, a four-dimensional (4D) MT inversion algorithm has been developed to simultaneously invert all vintage data considering time-coupling between vintages. However, the changes in electrical resistivity of deep geothermal reservoirs are usually small generating minimum variation in TL MT responses. Maximizing the sensitivity of inversion to the changes in resistivity is critical in the success of 4D MT inversion. Thus, we further developed a focused 4D MT inversion method by considering not only the location of a reservoir but also the distribution of newly-generated fractures during the production. For the evaluation of the 4D MT algorithm, we tested our 4D inversion algorithms using synthetic TL MT-data sets.

Assessment of managed aquifer recharge from Sand Hollow Reservoir, Washington County, Utah, updated to conditions in 2010

USGS Publications Warehouse

Heilweil, Victor M.; Marston, Thomas M.

2011-01-01

Sand Hollow Reservoir in Washington County, Utah, was completed in March 2002 and is operated primarily for managed aquifer recharge by the Washington County Water Conservancy District. From 2002 through 2009, total surface-water diversions of about 154,000 acre-feet to Sand Hollow Reservoir have allowed it to remain nearly full since 2006. Groundwater levels in monitoring wells near the reservoir rose through 2006 and have fluctuated more recently because of variations in reservoir water-level altitude and nearby pumping from production wells. Between 2004 and 2009, a total of about 13,000 acre-feet of groundwater has been withdrawn by these wells for municipal supply. In addition, a total of about 14,000 acre-feet of shallow seepage was captured by French drains adjacent to the North and West Dams and used for municipal supply, irrigation, or returned to the reservoir.From 2002 through 2009, about 86,000 acre-feet of water seeped beneath the reservoir to recharge the underlying Navajo Sandstone aquifer. Water-quality sampling was conducted at various monitoring wells in Sand Hollow to evaluate the timing and location of reservoir recharge moving through the aquifer. Tracers of reservoir recharge include major and minor dissolved inorganic ions, tritium, dissolved organic carbon, chlorofluorocarbons, sulfur hexafluoride, and noble gases. By 2010, this recharge arrived at monitoring wells within about 1,000 feet of the reservoir.

Assessment of managed aquifer recharge at Sand Hollow Reservoir, Washington County, Utah, updated to conditions through 2014

USGS Publications Warehouse

Marston, Thomas M.; Heilweil, Victor M.

2016-09-08

Sand Hollow Reservoir in Washington County, Utah, was completed in March 2002 and is operated primarily for managed aquifer recharge by the Washington County Water Conservancy District. From 2002 through 2014, diversions of about 216,000 acre-feet from the Virgin River to Sand Hollow Reservoir have allowed the reservoir to remain nearly full since 2006. Groundwater levels in monitoring wells near the reservoir rose through 2006 and have fluctuated more recently because of variations in reservoir stage and nearby pumping from production wells. Between 2004 and 2014, about 29,000 acre-feet of groundwater was withdrawn by these wells for municipal supply. In addition, about 31,000 acre-feet of shallow seepage was captured by French drains adjacent to the North and West Dams and used for municipal supply, irrigation, or returned to the reservoir. From 2002 through 2014, about 127,000 acre-feet of water seeped beneath the reservoir to recharge the underlying Navajo Sandstone aquifer.Water quality continued to be monitored at various wells in Sand Hollow during 2013–14 to evaluate the timing and location of reservoir recharge as it moved through the aquifer. Changing geochemical conditions at monitoring wells WD 4 and WD 12 indicate rising groundwater levels and mobilization of vadose-zone salts, which could be a precursor to the arrival of reservoir recharge.

Paleohydrologic controls on soft-sediment deformation in the Navajo Sandstone

NASA Astrophysics Data System (ADS)

Bryant, Gerald; Cushman, Robert; Nick, Kevin; Miall, Andrew

2016-10-01

Many workers have noted the presence of contorted cross-strata in the Navajo Sandstone and other ancient eolianites, and have recognized their significance as indicators of sediment saturation during the accumulation history. Horowitz (1982) proposed a general model for the production of such features in ancient ergs by episodic, seismically induced liquefaction of accumulated sand. A key feature of that popular model is the prevalence of a flat water table, characteristic of a hyper-arid climatic regime, during deformation. Under arid climatic conditions, the water table is established by regional flow and liquefaction is limited to the saturated regions below the level of interdune troughs. However, various paleohydrological indicators from Navajo Sandstone outcrops point toward a broader range of water table configurations during the deformation history of that eolianite. Some outcrops reveal extensive deformation complexes that do not appear to have extended to the contemporary depositional surface. These km-scale zones of deformation, affecting multiple sets of cross-strata, and grading upward into undeformed crossbeds may represent deep water table conditions, coupled with high intensity triggers, which produced exclusively intrastratal deformation. Such occurrences contrast with smaller-scale complexes formed within the zone of interaction between the products of soft-sediment deformation and surface processes of deposition and erosion. The Horowitz model targets the smaller-scale deformation morphologies produced in this near-surface environment. This study examines the implications of a wet climatic regime for the Horowitz deformation model. It demonstrates how a contoured water table, characteristic of humid climates, may have facilitated deformation within active bedforms, as well as in the accumulation. Intra-dune deformation would enable deflation of deformation features during the normal course of dune migration, more parsimoniously accounting for

Fracture properties from tight reservoir outcrop analogues with application to geothermal exploration

NASA Astrophysics Data System (ADS)

Philipp, Sonja L.; Reyer, Dorothea; Afsar, Filiz; Bauer, Johanna F.; Meier, Silke; Reinecker, John

2015-04-01

In geothermal reservoirs, similar to other tight reservoirs, fluid flow may be intensely affected by fracture systems, in particular those associated with fault zones. When active (slipping) the fault core, that is, the inner part of a fault zone, which commonly consists of breccia or gouge, can suddenly develop high permeability. Fault cores of inactive fault zones, however, may have low permeabilities and even act as flow barriers. In the outer part of a fault zone, the damage zone, permeability depends mainly on the fracture properties, that is, the geometry (orientation, aperture, density, connectivity, etc.) of the fault-associated fracture system. Mineral vein networks in damage zones of deeply eroded fault zones in palaeogeothermal fields demonstrate their permeability. In geothermal exploration, particularly for hydrothermal reservoirs, the orientation of fault zones in relation to the current stress field as well as their internal structure, in particular the properties of the associated fracture system, must be known as accurately as possible for wellpath planning and reservoir engineering. Here we present results of detailed field studies and numerical models of fault zones and associated fracture systems in palaeogeo¬thermal fields and host rocks for geothermal reservoirs from various stratigraphies, lithologies and tectonic settings: (1) 74 fault zones in three coastal sections of Upper Triassic and Lower Jurassic age (mudstones and limestone-marl alternations) in the Bristol Channel Basin, UK. (2) 58 fault zones in 22 outcrops from Upper Carboniferous to Upper Cretaceous in the Northwest German Basin (siliciclastic, carbonate and volcanic rocks); and (3) 16 fault zones in 9 outcrops in Lower Permian to Middle Triassic (mainly sandstone and limestone) in the Upper Rhine Graben shoulders. Whereas (1) represent palaeogeothermal fields with mineral veins, (2) and (3) are outcrop analogues of reservoir horizons from geothermal exploration. In the study

Reservoir controls on the occurrence and production of gas hydrates in nature

USGS Publications Warehouse

Collett, Timothy Scott

2014-01-01

modeling has shown that concentrated gas hydrate occurrences in sand reservoirs are conducive to existing well-based production technologies. The resource potential of gas hydrate accumulations in sand-dominated reservoirs have been assessed for several polar terrestrial basins. In 1995, the U.S. Geological Survey (USGS) assigned an in-place resource of 16.7 trillion cubic meters of gas for hydrates in sand-dominated reservoirs on the Alaska North Slope. In a more recent assessment, the USGS indicated that there are about 2.42 trillion cubic meters of technically recoverable gas resources within concentrated, sand-dominated, gas hydrate accumulations in northern Alaska. Estimates of the amount of in-place gas in the sand dominated gas hydrate accumulations of the Mackenzie Delta Beaufort Sea region of the Canadian arctic range from 1.0 to 10 trillion cubic meters of gas. Another prospective gas hydrate resources are those of moderate-to-high concentrations within sandstone reservoirs in marine environments. In 2008, the Bureau of Ocean Energy Management estimated that the Gulf of Mexico contains about 190 trillion cubic meters of gas in highly concentrated hydrate accumulations within sand reservoirs. In 2008, the Japan Oil, Gas and Metals National Corporation reported on a resource assessment of gas hydrates in which they estimated that the volume of gas within the hydrates of the eastern Nankai Trough at about 1.1 trillion cubic meters, with about half concentrated in sand reservoirs. Because conventional production technologies favor sand-dominated gas hydrate reservoirs, sand reservoirs are considered to be the most viable economic target for gas hydrate production and will be the prime focus of most future gas hydrate exploration and development projects.

Bluebell Field, Uinta Basin: reservoir characterization for improved well completion and oil recovery

USGS Publications Warehouse

Montgomery, S.L.; Morgan, C.D.

1998-01-01

Bluefield Field is the largest oil-producing area in the Unita basin of northern Utah. The field inclucdes over 300 wells and has produced 137 Mbbl oil and 177 bcf gas from fractured Paleocene-Eocene lacustrine and fluvial deposits of the Green River and Wasatch (Colton) formations. Oil and gas are produced at depths of 10 500-13 000 ft (3330-3940 m), with the most prolific reservoirs existing in over-pressured sandstones of the Colton Formation and the underlying Flagstaff Member of the lower Green River Formation. Despite a number of high-recovery wells (1-3 MMbbl), overall field recovery remains low, less than 10% original oil in place. This low recovery rate is interpreted to be at least partly a result of completion practices. Typically, 40-120 beds are perforated and stimulated with acid (no proppant) over intervals of up to 3000 ft (900 m). Little or no evaluation of individual beds is performed, preventing identification of good-quality reservoir zones, water-producing zones, and thief zones. As a result, detailed understanding of Bluebell reservoirs historically has been poor, inhibiting any improvements in recovery strategies. A recent project undertaken in Bluebell field as part of the U.S. Department of Energy's Class 1 (fluvial-deltaic reservoir) Oil Demonstration program has focused considerable effort on reservoir characterization. This effort has involved interdisciplinary analysis of core, log, fracture, geostatistical, production, and other data. Much valuable new information on reservoir character has resulted, with important implications for completion techniques and recovery expectations. Such data should have excellent applicability to other producing areas in the Uinta Basin withi reservoirs in similar lacustrine and related deposits.Bluebell field is the largest oil-producing area in the Uinta basin of northern Utah. The field includes over 300 wells and has produced 137 MMbbl oil and 177 bcf gas from fractured Paleocene-Eocene lacustrine

Hydraulic stimulation or low water injection in fractured reservoir of the geothermal well GRT-1 at Rittershoffen (France)?

NASA Astrophysics Data System (ADS)

Vidal, J.; Genter, A.; Schmittbuhl, J.; Baujard, C.

2016-12-01

In the Upper Rhine Graben, several deep geothermal projects, such as at Soultz-sous-Forêts (France) or Basel (Switzerland), were based on the Enhanced Geothermal System technology. The principle underlying this technology consists of increasing the low initial natural hydraulic performance of pre-existing natural fractures in the geothermal granitic reservoir via hydraulic and/or chemical stimulations. Hydraulic stimulation consists of injection of a large amount of water at a high flow rate to promote hydroshearing of pre-existing fractures. At Soultz-sous-Forêts and Basel, the maximum wellhead pressures were 16 MPa and 30 MPa respectively which induced larger magnitude seismic events of 2.9 and 3.4 respectively. Those specific induced seismicity events were felt by local population. At Rittershoffen (France), the geothermal well GRT-1 was drilled in 2012 down to a depth of 2.6 km and penetrates fractured sandstones and granite. The reservoir temperature reaches more than 160°C but the production flowrate was too low for an industrial project economically viable. Thus, the well was subjected to Thermal, Chemical and Hydraulic stimulations, which improved the injectivity index five-fold. During the hydraulic operation, a moderate volume of water was injected from the wellhead with a low pressure of 3 MPa. Approximately 300 microseismic events were detected during the hydraulic stimulations. Due to the low wellhead pressure during injection, no events were felt by nearby residents. The goal of the study was to assess the impact of the stimulation by comparing pre- and post-stimulation acoustic image logs. This comparison revealed minor modifications of almost all the natural fractures. However, not all of these fractures are associated with permeability enhancement. The most important permeability enhancement was observed on the originally permeable fault zone affecting the top of the granitic basement. In the Upper Rhine Graben, several deep geothermal projects

Physical properties of sidewall cores from Decatur, Illinois

USGS Publications Warehouse

Morrow, Carolyn A.; Kaven, Joern; Moore, Diane E.; Lockner, David A.

2017-10-18

To better assess the reservoir conditions influencing the induced seismicity hazard near a carbon dioxide sequestration demonstration site in Decatur, Ill., core samples from three deep drill holes were tested to determine a suite of physical properties including bulk density, porosity, permeability, Young’s modulus, Poisson’s ratio, and failure strength. Representative samples of the shale cap rock, the sandstone reservoir, and the Precambrian basement were selected for comparison. Physical properties were strongly dependent on lithology. Bulk density was inversely related to porosity, with the cap rock and basement samples being both least porous (

Polygonal deformation bands in sandstone

NASA Astrophysics Data System (ADS)

Antonellini, Marco; Nella Mollema, Pauline

2017-04-01

We report for the first time the occurrence of polygonal faults in sandstone, which is compelling given that layer-bound polygonal fault systems have been observed so far only in fine-grained sediments such as clay and chalk. The polygonal faults are dm-wide zones of shear deformation bands that developed under shallow burial conditions in the lower portion of the Jurassic Entrada Fm (Utah, USA). The edges of the polygons are 1 to 5 meters long. The shear deformation bands are organized as conjugate faults along each edge of the polygon and form characteristic horst-like structures. The individual deformation bands have slip magnitudes ranging from a few mm to 1.5 cm; the cumulative average slip magnitude in a zone is up to 10 cm. The deformation bands heaves, in aggregate form, accommodate a small isotropic horizontal extension (strain < 0.005). The individual shear deformation bands show abutting T-junctions, veering, curving, and merging where they mechanically interact. Crosscutting relationships are rare. The interactions of the deformation bands are similar to those of mode I opening fractures. Density inversion, that takes place where under-compacted and over-pressurized layers (Carmel Fm) lay below normally compacted sediments (Entrada Sandstone), may be an important process for polygonal deformation bands formation. The gravitational sliding and soft sediment structures typically observed within the Carmel Fm support this hypothesis. Soft sediment deformation may induce polygonal faulting in the section of the Entrada Sandstone just above the Carmel Fm. The permeability of the polygonal deformation bands is approximately 10-14 to 10-13 m2, which is less than the permeability of the host, Entrada Sandstone (range 10-12 to 10-11 m2). The documented fault networks have important implications for evaluating the geometry of km-scale polygonal fault systems in the subsurface, top seal integrity, as well as constraining paleo-tectonic stress regimes.

Mobilization of aluminum by the acid percolates within unsaturated zone of sandstones.

PubMed

Navrátil, Tomáš; Vařilová, Zuzana; Rohovec, Jan

2013-09-01

The area of the Black Triangle has been exposed to extreme levels of acid deposition in the twentieth century. The chemical weathering of sandstones found within the Black Triangle became well-known phenomenon. Infiltration of acid rain solutions into the sandstone represents the main input of salt components into the sandstone. The infiltrated solutions--sandstone percolates--react with sandstone matrix and previously deposited materials such as salt efflorescence. Acidic sandstone percolates pH 3.2-4.8 found at ten sites within the National Park Bohemian Switzerland contained high Al-tot (0.8-10 mg L(-1)) concentrations and high concentrations of anions SO4 (5-66 mg L(-1)) and NO3 (2-42 mg L(-1)). A high proportion (50-98 %) of Al-tot concentration in acid percolates was represented by toxic reactive Al(n+). Chemical equilibrium modeling indicated as the most abundant Al species Al(3+), AlSO4 (+), and AlF(2+). The remaining 2-50 % of Al-tot concentration was present in the form of complexes with dissolved organic matter Al-org. Mobilization and transport of Al from the upper zones of sandstone causes chemical weathering and sandstone structure deterioration. The most acidic percolates contained the highest concentrations of dissolved organic material (estimated up to 42 mg L(-1)) suggesting the contribution of vegetation on sandstone weathering processes. Very low concentrations of Al-tot in springs at BSNP suggest that Al mobilized in unsaturated zone is transported deeper into the sandstone. This process of mobilization could represent a threat for the water quality small-perched aquifers.

Contractional deformation of porous sandstone: Insights from the Aztec Sandstone, SE Nevada, USA

NASA Astrophysics Data System (ADS)

Fossen, Haakon; Zuluaga, Luisa F.; Ballas, Gregory; Soliva, Roger; Rotevatn, Atle

2015-05-01

Contractional deformation of highly porous sandstones is poorly explored, as compared to extensional deformation of such sedimentary rocks. In this work we explore the highly porous Aztec Sandstone in the footwall to the Muddy Mountain thrust in SE Nevada, which contains several types of deformation bands in the Buffington tectonic window: 1) Distributed centimeter-thick shear-enhanced compaction bands (SECBs) and 2) rare pure compaction bands (PCBs) in the most porous parts of the sandstone, cut by 3) thin cataclastic shear-dominated bands (CSBs) with local slip surfaces. Geometric and kinematic analysis of the SECBs, the PCBs and most of the CSBs shows that they formed during ∼E-W (∼100) shortening, consistent with thrusting related to the Cretaceous to early Paleogene Sevier orogeny of the North American Cordilleran thrust system. Based on stress path modeling, we suggest that the compactional bands (PCBs and SECBs) formed during contraction at relatively shallow burial depths, before or at early stages of emplacement of the Muddy Mountains thrust sheet. The younger cataclastic shear bands (CSBs, category 3), also related to E-W Sevier thrusting, are thinner and show larger shear offsets and thus more intense cataclasis, consistent with the initiation of cataclastic shear bands in somewhat less porous materials. Observations made in this work support earlier suggestions that contraction lead to more distributed band populations than what is commonly found in the extensional regime, and that shear-enhanced compaction bands are widespread only where porosity (and permeability) is high.

The Middle Jurassic Entrada Sandstone near Gallup, New Mexico

USGS Publications Warehouse

Robertson, J.F.; O'Sullivan, R. B.

2001-01-01

Near Gallup, New Mexico, the Middle Jurassic Entrada Sandstone consists of, in ascending order, the Iyanbito Member, the Rehoboth Member, and an upper sandstone member. The Rehoboth Member is named herein to replace the middle siltstone member, with a type section located 26 km east of Gallup. The Iyanbito Member has been erroneously equated with the Wingate Sandstone of northeast Arizona, and the Rehoboth Member has been miscorrelated with the Dewey Bridge Member of the Entrada in Utah. The Dewey Bridge is an older unit that does not extend into New Mexico. The Iyanbito Member, east of Gallup, overlies the J-2 unconformity and the eroded tops of the Owl Rock and Petrified Forest Members of the Chinle Formation. The Wingate Sandstone of the Lower Jurassic Glen Canyon Group overlies the J-0 unconformity and the underlying Rock Point Member (topmost unit) of the Chinle Formation in northeast Arizona. Both the Wingate Sandstone and the Rock Point Member are missing east of Gallup below the J-2 unconformity. Similarly, the Wingate is missing southwest of Gallup, near Lupton, Arizona, but the Rock Point Member is present and underlies the Iyanbito from Zuni northward to Toadlena, New Mexico. The Wingate and other formations of the Glen Canyon Group thin and wedge out southward and eastward in northeast Arizona. The J-2 unconformity truncates the Wingate Sandstone and the underlying J-0 unconformity, 5 km north of Toadlena.

Calibration of NMR well logs from carbonate reservoirs with laboratory NMR measurements and μXRCT

DOE PAGES

Mason, Harris E.; Smith, Megan M.; Hao, Yue; ...

2014-12-31

The use of nuclear magnetic resonance (NMR) well log data has the potential to provide in-situ porosity, pore size distributions, and permeability of target carbonate CO₂ storage reservoirs. However, these methods which have been successfully applied to sandstones have yet to be completely validated for carbonate reservoirs. Here, we have taken an approach to validate NMR measurements of carbonate rock cores with independent measurements of permeability and pore surface area to volume (S/V) distributions using differential pressure measurements and micro X-ray computed tomography (μXRCT) imaging methods, respectively. We observe that using standard methods for determining permeability from NMR data incorrectlymore » predicts these values by orders of magnitude. However, we do observe promise that NMR measurements provide reasonable estimates of pore S/V distributions, and with further independent measurements of the carbonate rock properties that universally applicable relationships between NMR measured properties may be developed for in-situ well logging applications of carbonate reservoirs.« less

Calibration of NMR well logs from carbonate reservoirs with laboratory NMR measurements and μXRCT

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

Mason, Harris E.; Smith, Megan M.; Hao, Yue

The use of nuclear magnetic resonance (NMR) well log data has the potential to provide in-situ porosity, pore size distributions, and permeability of target carbonate CO₂ storage reservoirs. However, these methods which have been successfully applied to sandstones have yet to be completely validated for carbonate reservoirs. Here, we have taken an approach to validate NMR measurements of carbonate rock cores with independent measurements of permeability and pore surface area to volume (S/V) distributions using differential pressure measurements and micro X-ray computed tomography (μXRCT) imaging methods, respectively. We observe that using standard methods for determining permeability from NMR data incorrectlymore » predicts these values by orders of magnitude. However, we do observe promise that NMR measurements provide reasonable estimates of pore S/V distributions, and with further independent measurements of the carbonate rock properties that universally applicable relationships between NMR measured properties may be developed for in-situ well logging applications of carbonate reservoirs.« less

Porosity and grain size controls on compaction band formation in Jurassic Navajo Sandstone

USGS Publications Warehouse

Schultz, Richard A.; Okubo, Chris H.; Fossen, Haakon

2010-01-01

Determining the rock properties that permit or impede the growth of compaction bands in sedimentary sequences is a critical problem of importance to studies of strain localization and characterization of subsurface geologic reservoirs. We determine the porosity and average grain size of a sequence of stratigraphic layers of Navajo Sandstone that are then used in a critical state model to infer plastic yield envelopes for the layers. Pure compaction bands are formed in layers having the largest average grain sizes (0.42–0.45 mm) and porosities (28%), and correspondingly the smallest values of critical pressure (-22 MPa) in the sequence. The results suggest that compaction bands formed in these layers after burial to -1.5 km depth in association with thrust faulting beneath the nearby East Kaibab monocline, and that hardening of the yield caps accompanied compactional deformation of the layers.

The Noble Gas Record of Gas-Water Phase Interaction in the Tight-Gas-Sand Reservoirs of the Rocky Mountains

NASA Astrophysics Data System (ADS)

Ballentine, C. J.; Zhou, Z.; Harris, N. B.

2015-12-01

The mass of hydrocarbons that have migrated through tight-gas-sandstone systems before the permeability reduces to trap the hydrocarbon gases provides critical information in the hydrocarbon potential analysis of a basin. The noble gas content (Ne, Ar, Kr, Xe) of the groundwater has a unique isotopic and elemental composition. As gas migrates through the water column, the groundwater-derived noble gases partition into the hydrocarbon phase. Determination of the noble gases in the produced hydrocarbon phase then provides a record of the type of interaction (simple phase equilibrium or open system Rayleigh fractionation). The tight-gas-sand reservoirs of the Rocky Mountains represent one of the most significant gas resources in the United States. The producing reservoirs are generally developed in low permeability (averaging <0.1mD) Upper Cretaceous fluvial to marginal marine sandstones and commonly form isolated overpressured reservoir bodies encased in even lower permeability muddy sediments. We present noble gas data from producing fields in the Greater Green River Basin, Wyoming; the the Piceance Basin, Colorado; and in the Uinta Basin, Utah. The data is consistent from all three basins. We show how in each basin the noble gases record open system gas migration through a water column at maximum basin burial. The data within an open system model indicates that the gas now in-place represents the last ~10% of hydrocarbon gas to have passed through the water column, most likely prior to permeability closedown.

Advances in coalbed methane reservoirs using integrated reservoir characterization and hydraulic fracturing in Karaganda coal basin, Kazakhstan

NASA Astrophysics Data System (ADS)

Ivakhnenko, Aleksandr; Aimukhan, Adina; Kenshimova, Aida; Mullagaliyev, Fandus; Akbarov, Erlan; Mullagaliyeva, Lylia; Kabirova, Svetlana; Almukhametov, Azamat

2017-04-01

Coalbed methane from Karaganda coal basin is considered to be an unconventional source of energy for the Central and Eastern parts of Kazakhstan. These regions are situated far away from the main traditional sources of oil and gas related to Precaspian petroleum basin. Coalbed methane fields in Karaganda coal basin are characterized by geological and structural complexity. Majority of production zones were characterized by high methane content and extremely low coal permeability. The coal reservoirs also contained a considerable natural system of primary, secondary, and tertiary fractures that were usually capable to accommodate passing fluid during hydraulic fracturing process. However, after closing was often observed coal formation damage including the loss of fluids, migration of fines and higher pressures required to treat formation than were expected. Unusual or less expected reservoir characteristics and values of properties of the coal reservoir might be the cause of the unusual occurred patterns in obtained fracturing, such as lithological peculiarities, rock mechanical properties and previous natural fracture systems in the coals. Based on these properties we found that during the drilling and fracturing of the coal-induced fractures have great sensitivity to complex reservoir lithology and stress profiles, as well as changes of those stresses. In order to have a successful program of hydraulic fracturing and avoid unnecessary fracturing anomalies we applied integrated reservoir characterization to monitor key parameters. In addition to logging data, core sample analysis was applied for coalbed methane reservoirs to observe dependence tiny lithological variations through the magnetic susceptibility values and their relation to permeability together with expected principal stress. The values of magnetic susceptibility were measured by the core logging sensor, which is equipped with the probe that provides volume magnetic susceptibility parameters

Temperature and oxygen in Missouri reservoirs

USGS Publications Warehouse

Jones, John R.; Knowlton, Matthew F.; Obrecht, Daniel V.; Graham, Jennifer L.

2011-01-01

Vertical profiles of water temperature (n = 7193) and dissolved oxygen (n = 6516) were collected from 235 Missouri reservoirs during 1989–2007; most data were collected during May–August and provide a regional summary of summer conditions. Collectively, surface water temperature ranged from a mean of ~22 C in May to 28 C in July, and individual summer maxima typically were 28–32 C. Most (~95%) reservoirs stably stratify by mid-May, but few are deep enough to have hypolimnia with near-uniform temperatures. Among stratified reservoirs, maximum effective length and maximum depth accounted for 75% of the variation in mixed depth and thermocline depth. Ephemeral, near-surface thermoclines occurred in 39% of summer profiles and were most frequent in small, turbid reservoirs. Isotherms below the mixed layer deepen during stratification, and the water column is >20 C by August in all but the deepest reservoirs. Most reservoirs showed incipient dissolved oxygen (DO) depletion by mid-May, and by August, 80% of profiles had DO minima of 50% of variation in DO below the mixed layer during summer. Warm summer temperatures and widespread low DO often limit available fish habitat in Missouri reservoirs and compress warm-water fish communities into subsurface layers that exceed their thermal preferences. This study provides a regional baseline of reservoir temperature and oxygen conditions useful for future evaluations of eutrophication and the effects of a warming climate.

Diazotrophic bacterial community variability in a subtropical deep reservoir is correlated with seasonal changes in nitrogen.

PubMed

Wang, Lina; Yu, Zheng; Yang, Jun; Zhou, Jing

2015-12-01

Nitrogen-fixing microorganisms (diazotrophs) play important roles in aquatic biogeochemistry and ecosystem functioning. However, little is known about the spatiotemporal variation of diazotrophic microbial communities in deep subtropical reservoirs. In this study, denaturing gradient gel electrophoresis (DGGE), clone libraries, quantitative PCR, and quantitative reverse transcription (RT)-PCR were used together to examine the vertical and seasonal patterns of diazotrophic microbial communities based on nitrogenase (nifH) gene sequences in the Dongzhen Reservoir, China, across time (every 3 months for 1 year) and space (five different water depths). In general, the numbers of DGGE bands increased with water depth during the stratification seasons (spring, summer, and autumn), with the clone-library-based operational taxonomic unit (OTU) number and nifH gene diversity being highest in autumn (6 OTUs at depth 0 m; 15 OTUs at 33 m) and winter (12 OTUs at 0 m, 13 OTUs at 33 m) but decreasing drastically in spring (2 OTUs at 0 m, 3 OTUs at 33 m) and summer (3 OTUs at 0 m, 2 OTUs at 33 m). The nifH gene abundance was lowest in the water mixing season (winter average, 5.17 × 10(7) copies/L) but increased in the three other seasons (9.03 × 10(9) copies/L). Cyanobacteria (dominated by filamentous thermophilic cyanobacteria and Cylindrospermopsis raciborskii) were the most dominant diazotrophic group at all depths and seasons, while both alphaproteobacteria and gammaproteobacteria were co-dominant in the bottom waters in autumn and winter. The distinct seasonal and spatial patterns in diazotrophic communities were significantly related to total nitrogen (TN) and ammonium nitrogen (NH4-N) in the reservoir (P < 0.01). Further, TN showed a significant positive correlation with nifH RNA copy number (P < 0.05) and DGGE band number (P < 0.01), whereas the NH4-N was negatively correlated with nifH DNA copy number (P < 0.01) and positively with both RNA

High submuscular placement of urologic prosthetic balloons and reservoirs via transscrotal approach.

PubMed

Morey, Allen F; Cefalu, Christopher A; Hudak, Steven J

2013-02-01

Traditional placement of inflatable penile prosthesis (IPP) reservoirs and/or artificial urinary sphincter (AUS) balloons into the space of Retzius may be challenging following major pelvic surgery. The aim of this study is to report our 1-year experience using a novel technique for high balloon/reservoir placement beneath the rectus abdominus muscle, thus completely obviating deep pelvic dissection during prosthetic urologic surgery. A retrospective review of all patients who underwent IPP and/or AUS placement between June 2011 and June 2012 was performed. All had AUS balloons and/or IPP reservoirs placed in a submuscular location by bluntly tunneling through the external inguinal ring into a potential space between the transversalis fascia and the rectus abdominus muscle using a long, angled, lung grasping clamp. Patient demographics, perioperative outcomes, and initial follow-up patient-reported outcomes were reviewed. During the study period, 120 submuscular balloons/reservoirs were inserted in 107 consecutive patients who underwent placement of an IPP (61 patients), AUS (33 patients), or both (13 patients). Among our 48 most recent patients, 41 (85%) reported they were totally unable to feel their balloon/reservoir, and all but two patients reported no bother from the submuscular balloon/reservoir placement. Of the 120 total submuscular balloons and reservoirs, surgical time and outcomes of the prosthetic procedures appeared similar to those placed using traditional methods; two reservoirs required revision surgery for repositioning. High submuscular placement of genitourinary prosthetic balloons and reservoirs via a transscrotal approach is both safely and effective, while avoiding deep retropubic dissection. © 2012 International Society for Sexual Medicine.

South Sumatra Basin Province, Indonesia; the Lahat/Talang Akar-Cenozoic total petroleum system

USGS Publications Warehouse

Bishop, Michele G.

2000-01-01

Oil and gas are produced from the onshore South Sumatra Basin Province. The province consists of Tertiary half-graben basins infilled with carbonate and clastic sedimentary rocks unconformably overlying pre-Tertiary metamorphic and igneous rocks. Eocene through lower Oligocene lacustrine shales and Oligocene through lower Miocene lacustrine and deltaic coaly shales are the mature source rocks. Reserves of 4.3 billion barrels of oil equivalent have been discovered in reservoirs that range from pre-Tertiary basement through upper Miocene sandstones and carbonates deposited as synrift strata and as marine shoreline, deltaic-fluvial, and deep-water strata. Carbonate and sandstone reservoirs produce oil and gas primarily from anticlinal traps of Plio-Pleistocene age. Stratigraphic trapping and faulting are important locally. Production is compartmentalized due to numerous intraformational seals. The regional marine shale seal, deposited by a maximum sea level highstand in early middle Miocene time, was faulted during post-depositional folding allowing migration of hydrocarbons to reservoirs above the seal. The province contains the Lahat/Talang Akar-Cenozoic total petroleum system with one assessment unit, South Sumatra.

Geochemistry of surface and subsurface waters in quartz-sandstones: significance for the geomorphic evolution of tepui table mountains (Gran Sabana, Venezuela)

NASA Astrophysics Data System (ADS)

Mecchia, Marco; Sauro, Francesco; Piccini, Leonardo; De Waele, Jo; Sanna, Laura; Tisato, Nicola; Lira, Jesus; Vergara, Freddy

2014-04-01

In situ measurements of discharge, pH, electric conductivity (EC), temperature, and SiO2 content have been carried out during five expeditions in the last 20 years on the summit plateaus, inside caves and along the rivers of the surrounding lowlands of three tepui massifs in Venezuela (Auyan, Roraima, and Chimanta). Additionally, detailed chemical analyses were performed on waters sampled in a newly discovered extensive quartz-sandstone cave system on the Auyan Tepui. Rock samples of the quartz-sandstone bedrock from different locations have been analysed to obtain their chemical composition with a wavelength dispersive X-ray fluorescence spectrometer. These data show that the majority of silica present in surface and subsurface water comes from dissolution of quartz and only in minor amount from hydrolysis of other silicate minerals. Probably the presence of a hardened crust of iron hydroxides limits the dissolution of silica on the top surface of tepuis. Dissolution in the subsurface, instead, is more significant and causes, in the long term, the “arenisation” of the quartz-sandstone and its subsequent removal by mechanical erosion. On the other hand, waters flowing on the arkosic rock outcropping on the lowland below the tepuis obtain their high dissolved silica content mainly from hydrolysis of silicates. The morphological evolution of these table mountains appears thus to be controlled mainly by the underground weathering of the quartz-sandstone, with the opening of deep fractures (grietas) and the collapse of large underground horizontal cave systems. Scarp retreat, instead, seems to be related to the higher weathering rate of the more arkosic formations underlying the quartz-sandstones.

Bacterial communities in pigmented biofilms formed on the sandstone bas-relief walls of the Bayon Temple, Angkor Thom, Cambodia.

PubMed

Kusumi, Asako; Li, Xianshu; Osuga, Yu; Kawashima, Arata; Gu, Ji-Dong; Nasu, Masao; Katayama, Yoko

2013-01-01

The Bayon temple in Angkor Thom, Cambodia has shown serious deterioration and is subject to the formation of various pigmented biofilms. Because biofilms are damaging the bas-reliefs, low reliefs engraved on the surface of sandstone, information about the microbial community within them is indispensable to control biofilm colonization. PCR-denaturing gradient gel electrophoresis (DGGE) analysis of biofilm samples from the pigmented sandstone surfaces showed that the bacterial community members in the biofilms differed clearly from those in the air and had low sequence similarity to database sequences. Non-destructive sampling of biofilm revealed novel bacterial groups of predominantly Rubrobacter in salmon pink biofilm, Cyanobacteria in chrome green biofilm, Cyanobacteria and Chloroflexi in signal violet biofilm, Chloroflexi in black gray biofilm, and Deinococcus-Thermus, Cyanobacteria, and Rubrobacter in blue green biofilm. Serial peeling-off of a thick biofilm by layers with adhesive sheets revealed a stratified structure: the blue-green biofilm, around which there was serious deterioration, was very rich in Cyanobacteria near the surface and Chloroflexi in deep layer below. Nitrate ion concentrations were high in the blue-green biofilm. The characteristic distribution of bacteria at different biofilm depths provides valuable information on not only the biofilm formation process but also the sandstone weathering process in the tropics.

Assessment of managed aquifer recharge at Sand Hollow Reservoir, Washington County, Utah, updated to conditions in 2012

USGS Publications Warehouse

Marston, Thomas M.; Heilweil, Victor M.

2013-01-01

Sand Hollow Reservoir in Washington County, Utah, was completed in March 2002 and is operated primarily for managed aquifer recharge by the Washington County Water Conservancy District. From 2002 through 2011, surface-water diversions of about 199,000 acre-feet to Sand Hollow Reservoir have allowed the reservoir to remain nearly full since 2006. Groundwater levels in monitoring wells near the reservoir rose through 2006 and have fluctuated more recently because of variations in reservoir altitude and nearby pumping from production wells. Between 2004 and 2011, a total of about 19,000 acre-feet of groundwater was withdrawn by these wells for municipal supply. In addition, a total of about 21,000 acre-feet of shallow seepage was captured by French drains adjacent to the North and West Dams and used for municipal supply, irrigation, or returned to the reservoir. From 2002 through 2011, about 106,000 acre-feet of water seeped beneath the reservoir to recharge the underlying Navajo Sandstone aquifer. Water quality was sampled at various monitoring wells in Sand Hollow to evaluate the timing and location of reservoir recharge as it moved through the aquifer. Tracers of reservoir recharge include major and minor dissolved inorganic ions, tritium, dissolved organic carbon, chlorofluorocarbons, sulfur hexafluoride, and noble gases. By 2012, this recharge arrived at four monitoring wells located within about 1,000 feet of the reservoir. Changing geochemical conditions at five other monitoring wells could indicate other processes, such as changing groundwater levels and mobilization of vadose-zone salts, rather than arrival of reservoir recharge.

3D Sedimentological and geophysical studies of clastic reservoir analogs: Facies architecture, reservoir properties, and flow behavior within delta front facies elements of the Cretaceous Wall Creek Member, Frontier Formation, Wyoming

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

Christopher D. White

2009-12-21

Significant volumes of oil and gas occur in reservoirs formed by ancient river deltas. This has implications for the spatial distribution of rock types and the variation of transport properties. A between mudstones and sandstones may form baffles that influence productivity and recovery efficiency. Diagenetic processes such as compaction, dissolution, and cementation can also alter flow properties. A better understanding of these properties and improved methods will allow improved reservoir development planning and increased recovery of oil and gas from deltaic reservoirs. Surface exposures of ancient deltaic rocks provide a high-resolution view of variability. Insights gleaned from these exposures canmore » be used to model analogous reservoirs, for which data is sparser. The Frontier Formation in central Wyoming provides an opportunity for high-resolution models. The same rocks exposed in the Tisdale anticline are productive in nearby oil fields. Kilometers of exposure are accessible, and bedding-plane exposures allow use of high-resolution ground-penetrating radar. This study combined geologic interpretations, maps, vertical sections, core data, and ground-penetrating radar to construct geostatistical and flow models. Strata-conforming grids were use to reproduce the observed geometries. A new Bayesian method integrates outcrop, core, and radar amplitude and phase data. The proposed method propagates measurement uncertainty and yields an ensemble of plausible models for calcite concretions. These concretions affect flow significantly. Models which integrate more have different flow responses from simpler models, as demonstrated an exhaustive two-dimensional reference image and in three dimensions. This method is simple to implement within widely available geostatistics packages. Significant volumes of oil and gas occur in reservoirs that are inferred to have been formed by ancient river deltas. This geologic setting has implications for the spatial

Diagenesis Along Fractures in an Eolian Sandstone, Gale Crater, Mars

NASA Technical Reports Server (NTRS)

Ming, D. W.; Yen, A. S.; Rampe, E. B.; Grotzinger, J. P.; Blake, D. F.; Bristow, T. F.; Chipera, S. J.; Downs, R.; Morris, R. V.; Morrison, S. M.;

Erosion processes, fluvial sediment transport, and reservoir sedimentation in a part of the Newell and Zayante Creek basins, Santa Cruz County, California

USGS Publications Warehouse

Brown, W. M.

1973-01-01

The drainage basins upstream from Loch Lomond, a water-supply reservoir on Newell Creek, and a proposed reservoir site on Zayante Creek were investigated for their characteristics with respect to the erosion, transportation, and deposition of sediment. The study area is underlain predominantly by sandstone, siltstone, and shale of Tertiary age that decompose readily into moderately deep soils, friable colluvium, and easily transported sediment particles. The Rices Mudstone and Twobar, Shale Members of the San Lorenzo Formation of Brabb (1964) underlie steep dip slopes in the study area, and probably are the most highly erodible of the several geologic units present there. However, nearly all of the geologic units have shown a propensity for accelerated erosion accompanying the disturbance of the land surface by the roadbuilding practices that predominate over other types of sediment-producing land-use activities in the study area. Sediment transport in the study area was estimated from (1) a reservoir survey of Loch Lomond in 1971 that was compared with a preconstruction survey of 1960, and (2) sampling of sediment transported in suspension by Zayante Creek during the 1970 and 1971 water years. At least 46 acre-feet of sediment accumulated in Loch Lomond in a 10-year period, and an unmeasured quantity of very fine sediment in the form of a thin layer over much of the reservoir bottom was observed. The measured quantity of deposited sediment in a 10-year period represented a sediment yield of about 1,100 tons annually per square mile of drainage basin upstream from the reservoir arms where the major deposition occurred. This sediment occupied less than i percent of the original capacity of Loch Lomond, but the volume of measured sediment deposition is probably conservative in view of the unmeasured deposits observed and a reservoir trap efficiency of about 95 percent. Sediment sampling on Zayante Creek indicated suspended-sediment yields of about 4,570 and 570 tons

Drilling history and stratigraphic correlation of Rose Run sandstone of northeastern Ohio

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

Moyer, C.C.

1988-08-01

To date, 40 known tests have penetrated the Knox unconformity in Ashtabula, Lake, Trumbull, Geauga, and Portage Counties, Ohio. Prior to 1980, there were only 22 tests. Of these, only 10 penetrated and logged rocks older than the Rose Run sandstone. In the period 1980-1986, two Rose Run discoveries were drilled, one in New Lyme Township of Ashtabula County and one in Burton Township of Geauga County. Both discovery wells have been offset. Attempts have been made to correlate these two areas with older tests in northeastern Ohio and with the Rose Run sandstones of Coshocton County. In northeastern Ohio,more » preliminary studies indicate a Rose Run sandstone and/or dolomite interval approximately 100 ft thick. The upper 50 ft is predominantly sandstone and the lower 50 ft changes locally from sandstone to dolomite. The upper sandy member can be correlated to the A, B, and C sandstone units of Coshocton County.« less

Sedimentological characterization of flood-tidal delta deposits in the Sego Sandstone, subsidence analysis in the Piceance Creek Basin, and uranium-lead geochronology (NW Colorado, USA)

NASA Astrophysics Data System (ADS)

York, Carly C.

The Sego Sandstone located in western Colorado is a member of the Upper Cretaceous Mesaverde Group and is considered an analogue of the Canadian heavy oil sands. Deposition of the Sego Sandstone occurred during the Upper Campanian (~78 Ma) at the end of the Sevier Orogeny and the beginning of the Laramide Orogeny on the western edge of the Cretaceous Interior Seaway. Although regional studies have detailed time equivalent deposits in the Book Cliffs, UT, the tidally influenced and marginal marine lithofacies observed north of Rangely, CO are distinctly different from the dominately fluvial and tidally-influenced delta facies of Book Cliff outcrops to the southwest. This study characterized flood-tidal delta deposits within the Sego Sandstone, the subsidence history of the Upper Cretaceous sedimentary rocks within the present day Piceance Creek Basin in NW Colorado, and the detrital zircon signal and oldest depositional age of the Sego Sandstone. The goals of this study are to (i) identify relative controls on reservoir characteristics of marginal marine deposits, specifically in flood-tidal delta deposits; (ii) identify the possible mechanisms responsible for subsidence within the present day Piceance Creek Basin during the Late Cretaceous; and (iii) better constrain the provenance and maximum depositional age of the Sego Sandstone. In this study I compared grain size diameter, grain and cement composition, and the ratio of pore space/cement from thin sections collected in tidal, shoreface, and flood-tidal delta facies recognized along detailed measured stratigraphic sections. This analysis provides a detailed comparison between different depositional environments and resultant data showed that grain size diameter is different between tidal, shoreface, and flood-tidal delta facies. Identifying the subsidence mechanisms affecting the Piceance Creek Basin and sediment source of the Late Cretaceous sediments, on the other hand, is important for evaluation of controls

Volcanic settings and their reservoir potential: An outcrop analog study on the Miocene Tepoztlán Formation, Central Mexico

NASA Astrophysics Data System (ADS)

Lenhardt, Nils; Götz, Annette E.

2011-07-01

The reservoir potential of volcanic and associated sedimentary rocks is less documented in regard to groundwater resources, and oil and gas storage compared to siliciclastic and carbonate systems. Outcrop analog studies within a volcanic setting enable to identify spatio-temporal architectural elements and geometric features of different rock units and their petrophysical properties such as porosity and permeability, which are important information for reservoir characterization. Despite the wide distribution of volcanic rocks in Mexico, their reservoir potential has been little studied in the past. In the Valley of Mexico, situated 4000 m above the Neogene volcanic rocks, groundwater is a matter of major importance as more than 20 million people and 42% of the industrial capacity of the Mexican nation depend on it for most of their water supply. Here, we present porosity and permeability data of 108 rock samples representing five different lithofacies types of the Miocene Tepoztlán Formation. This 800 m thick formation mainly consists of pyroclastic rocks, mass flow and fluvial deposits and is part of the southern Transmexican Volcanic Belt, cropping out south of the Valley of Mexico and within the two states of Morelos and Mexico State. Porosities range from 1.4% to 56.7%; average porosity is 24.8%. Generally, permeabilities are low to median (0.2-933.3 mD) with an average permeability of 88.5 mD. The lavas are characterized by the highest porosity values followed by tuffs, conglomerates, sandstones and tuffaceous breccias. On the contrary, the highest permeabilities can be found in the conglomerates, followed by tuffs, tuffaceous breccias, sandstones and lavas. The knowledge of these petrophysical rock properties provides important information on the reservoir potential of volcanic settings to be integrated to 3D subsurface models.

The effects of burial diagenesis on multiscale porosity in the St. Peter Sandstone: An imaging, small-angle, and ultra-small-angle neutron scattering analysis

DOE PAGES

Anovitz, Lawrence M.; Freiburg, Jared T.; Wasbrough, Matthew; ...

2017-11-06

To examine the effects of burial diagenesis on heirarchical pore structures in sandstone and compare those with the effects of overgrowth formation, we obtained samples of St. Peter Sandstone from drill cores obtained in the Illinois and Michigan Basins. The multiscale pore structure of rocks in sedimentary reservoirs and the mineralogy associated with those pores are critical factors for estimating reservoir properties, including fluid mass in place, permeability, and capillary pressures, as well as geochemical interactions between the rock and the fluid. The combination of small- and ultra-small-angle neutron scattering with backscattered electron or X ray-computed tomographic imaging, or both,more » provided a means by which pore structures were quantified at scales ranging from aproximately 1 nm to 1 cm—seven orders of magnitude. Larger scale (>10 µm) porosity showed the expected logarithmic decrease in porosity with depth, although there was significant variation in each sample group. However, small- and ultra-small-angle neutron scattering data showed that the proportion of small-scale porosity increased with depth. Porosity distributions were not continuous, but consisted of a series of log normal-like distributions at several distinct scales within these rocks. Fractal dimensions at larger scales decreased (surfaces smoothed) with increasing depth, and those at smaller scales increased (surfaces roughened) and pores become more isolated (higher lacunarity). Furthermore, data suggest that changes in pore-size distributions are controlled by both physical (compaction) and chemical effects (precipitation, cementation, dissolution).« less

The effects of burial diagenesis on multiscale porosity in the St. Peter Sandstone: An imaging, small-angle, and ultra-small-angle neutron scattering analysis

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

Anovitz, Lawrence M.; Freiburg, Jared T.; Wasbrough, Matthew

To examine the effects of burial diagenesis on heirarchical pore structures in sandstone and compare those with the effects of overgrowth formation, we obtained samples of St. Peter Sandstone from drill cores obtained in the Illinois and Michigan Basins. The multiscale pore structure of rocks in sedimentary reservoirs and the mineralogy associated with those pores are critical factors for estimating reservoir properties, including fluid mass in place, permeability, and capillary pressures, as well as geochemical interactions between the rock and the fluid. The combination of small- and ultra-small-angle neutron scattering with backscattered electron or X ray-computed tomographic imaging, or both,more » provided a means by which pore structures were quantified at scales ranging from aproximately 1 nm to 1 cm—seven orders of magnitude. Larger scale (>10 µm) porosity showed the expected logarithmic decrease in porosity with depth, although there was significant variation in each sample group. However, small- and ultra-small-angle neutron scattering data showed that the proportion of small-scale porosity increased with depth. Porosity distributions were not continuous, but consisted of a series of log normal-like distributions at several distinct scales within these rocks. Fractal dimensions at larger scales decreased (surfaces smoothed) with increasing depth, and those at smaller scales increased (surfaces roughened) and pores become more isolated (higher lacunarity). Furthermore, data suggest that changes in pore-size distributions are controlled by both physical (compaction) and chemical effects (precipitation, cementation, dissolution).« less

A chemical EOR benchmark study of different reservoir simulators

NASA Astrophysics Data System (ADS)

Goudarzi, Ali; Delshad, Mojdeh; Sepehrnoori, Kamy

2016-09-01

Interest in chemical EOR processes has intensified in recent years due to the advancements in chemical formulations and injection techniques. Injecting Polymer (P), surfactant/polymer (SP), and alkaline/surfactant/polymer (ASP) are techniques for improving sweep and displacement efficiencies with the aim of improving oil production in both secondary and tertiary floods. There has been great interest in chemical flooding recently for different challenging situations. These include high temperature reservoirs, formations with extreme salinity and hardness, naturally fractured carbonates, and sandstone reservoirs with heavy and viscous crude oils. More oil reservoirs are reaching maturity where secondary polymer floods and tertiary surfactant methods have become increasingly important. This significance has added to the industry's interest in using reservoir simulators as tools for reservoir evaluation and management to minimize costs and increase the process efficiency. Reservoir simulators with special features are needed to represent coupled chemical and physical processes present in chemical EOR processes. The simulators need to be first validated against well controlled lab and pilot scale experiments to reliably predict the full field implementations. The available data from laboratory scale include 1) phase behavior and rheological data; and 2) results of secondary and tertiary coreflood experiments for P, SP, and ASP floods under reservoir conditions, i.e. chemical retentions, pressure drop, and oil recovery. Data collected from corefloods are used as benchmark tests comparing numerical reservoir simulators with chemical EOR modeling capabilities such as STARS of CMG, ECLIPSE-100 of Schlumberger, REVEAL of Petroleum Experts. The research UTCHEM simulator from The University of Texas at Austin is also included since it has been the benchmark for chemical flooding simulation for over 25 years. The results of this benchmark comparison will be utilized to improve

Terrestrial tight oil reservoir characteristics and Graded Resource Assessment in China

NASA Astrophysics Data System (ADS)

Wang, Shejiao; Wu, Xiaozhi; Guo, Giulin

2016-04-01

The success of shale/tight plays and the advanced exploitation technology applied in North America have triggered interest in exploring and exploiting tight oil in China. Due to the increased support of exploration and exploitation，great progress has been made in Erdos basin, Songliao basin, Junggar basin, Santanghu basin, Bohai Bay basin, Qaidam Basin, and Sichuan basin currently. China's first tight oil field has been found in Erdos basin in 2015, called xinanbian oil field, with over one hundred million tons oil reserves and one million tons of production scale. Several hundred million tons of tight oil reserve has been found in other basins, showing a great potential in China. Tight oil in China mainly developed in terrestrial sedimentary environment. According to the relations of source rock and reservoir, the source-reservoir combination of tight oil can be divided into three types, which are bottom generating and top storing tight oil,self- generating and self-storing tight oil，top generating and bottom storing tight oil. The self- generating and self-storing tight oil is the main type discovered at present. This type of tight oil has following characteristics:(1) The formation and distribution of tight oil are controlled by high quality source rocks. Terrestrial tight oil source rocks in China are mainly formed in the deep to half deep lacustrine facies. The lithology includes dark mudstone, shale, argillaceous limestone and dolomite. These source rocks with thickness between 20m-150m, kerogen type mostly I-II, and peak oil generation thermal maturity(Ro 0.6-1.4%), have great hydrocarbon generating potential. Most discovered tight oil is distributed in the area of TOC greater than 2 %.( 2) the reservoir with strong heterogeneity is very tight. In these low porosity and permeability reservoir,the resources distribution is controlled by the physical property. Tight sandstone, carbonate and hybrid sedimentary rocks are three main tight reservoir types in

Marine petroleum source rocks and reservoir rocks of the Miocene Monterey Formation, California, U.S.A

USGS Publications Warehouse

Isaacs, C.M.

1988-01-01

The Miocene Monterey Formation of California, a biogenous deposit derived mainly from diatom debris, is important both as a petroleum source and petroleum reservoir. As a source, the formation is thought to have generated much of the petroleum in California coastal basins, which are among the most prolific oil provinces in the United States. Oil generated from the Monterey tends to be sulfur-rich and heavy (<20° API), and has chemical characteristics that more closely resemble immature source extracts than "normal" oil. Thermal-maturity indicators in Monterey kerogens appear to behave anomalously, and several lines of evidence indicate that the oil is generated at lower than expected levels of organic metamorphism. As a reservoir, the Monterey is important due both to conventional production from permeable sandstone beds and to fracture production from fine-grained rocks with low matrix permeability. Fractured reservoirs are difficult to identify, and conventional well-log analysis has not proven to be very useful in exploring for and evaluating these reservoirs. Lithologically similar rocks are broadly distributed throughout the Circum-Pacific region, but their petroleum potential is unlikely to be realized without recognition of the distinctive source and reservoir characteristics of diatomaceous strata and their diagenetic equivalents.

Quantification of the effects of secondary matrix on the analysis of sandstone composition, and a petrographic-chemical technique for retrieving original framework grain modes of altered sandstones.

PubMed

Cox, R; Lowe, D R

1996-05-01

Most studies of sandstone provenance involve modal analysis of framework grains using techniques that exclude the fine-grained breakdown products of labile mineral grains and rock fragments, usually termed secondary matrix or pseudomatrix. However, the data presented here demonstrate that, when the proportion of pseudomatrix in a sandstone exceeds 10%, standard petrographic analysis can lead to incorrect provenance interpretation. Petrographic schemes for provenance analysis such as QFL and QFR should not therefore be applied to sandstones containing more than 10% secondary matrix. Pseudomatrix is commonly abundant in sandstones, and this is therefore a problem for provenance analysis. The difficulty can be alleviated by the use of whole-rock chemistry in addition to petrographic analysis. Combination of chemical and point-count data permits the construction of normative compositions that approximate original framework grain compositions. Provenance analysis is also complicated in many cases by fundamental compositional alteration during weathering and transport. Many sandstones, particularly shallow marine deposits, have undergone vigorous reworking, which may destroy unstable mineral grains and rock fragments. In such cases it may not be possible to retrieve provenance information by either petrographic or chemical means. Because of this, pseudomatrix-rich sandstones should be routinely included in chemical-petrological provenance analysis. Because of the many factors, both pre- and post-depositional, that operate to increase the compositional maturity of sandstones, petrologic studies must include a complete inventory of matrix proportions, grain size and sorting parameters, and an assessment of depositional setting.

Hydraulic properties of siliciclastic geothermal reservoir rocks under triaxial stress conditions, a multidisciplinary approach.

NASA Astrophysics Data System (ADS)

Bakker, Richard; Gholizadeh Doonechaly, Nima; Bruhn, David

2017-04-01

Cretaceous Sandstone bodies in the subsurface of western Netherlands are already used for heating some of the greenhouses in that area. The reservoirs used are typically at depths between 1500 and 3000m, with temperatures generally <100 ˚C. For higher temperature applications deeper reservoirs are required. However, deeper reservoirs are subjected to higher effective pressures due to more overburden, which can lead to more compacted rocks, and thereby reduced permeability. We assess the effects of effective pressure on Triassic Buntsandstein, a formation targeted to act as a deep geothermal reservoir in the western Netherlands. Rock samples are acquired from laterally equivalent quarries and prepared for permeability measurements within a tri-axial apparatus. To determine anisotropy, cores are drilled both perpendicular and parallel to bedding. Experiments are conducted by maintaining hydrostatic confining pressure, stepwise increasing up to 700 bar (if still permeable enough for accurate measurements) and a pore pressure of 25 bar. At each step the permeability is assessed by imposing a number of constant flow rates and continuous measurement of the pore pressure difference between up and downstream reservoirs. Throughout the experiment the sample strain is measured in radial and axial directions, such that elastic constants can be determined and micromechanical mechanisms may be observed. In addition to measurements on in-tact rock samples, we also assess the effect of induced fracturing on permeability by similar measurements. First, rock samples are fractured within the tri-axial cell with normal jacketing to evaluate the stress conditions of failure. Secondly, the experiment is repeated using relatively strong jackets which remain sealing after sample failure, allowing for permeability measurements. Preliminary results show that an increase of confining pressure leads to a decrease of permeability by three orders of magnitude, from 1e-13 to 1e-16 m2

Paragenesis and reservoir quality within a shallow combination trap: Central West Virginia

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

Bell, D.A.; Siegrist, H.G. Jr.; Buurman, J.D.

1993-12-01

Sandstone character and reservoir quality of the Lower Mississippian Pocono Big Injun sandstone were examined in Granny Creek-Stockly field, Clay County, West Virginia. Sixty-three samples from 6 wells were analyzed using transmitted light, x-ray diffraction, and scanning electron microscopy techniques. The Pocono Big Injun formation is divided into four [open quotes]sands[close quotes] (Injun 1 through 4) based on composition and hydrocarbon productivity. The Injun 1 sand is a fine-grained, carbonate-cemented litharenite below the oil-producing zone. The oil-productive Injun 2 and 3 sands are well sorted, fine-grained litharenites which contain more authigenic and allogenic clay minerals than adjacent sands. These sandsmore » have produced more than 3.4 million bbl of oil from the Granny Creek part of the field since 1925. The Injun 4 sand is generally a coarse-grained sublitharenite with marginal gas production limited to the uppermost section of the sand. The paragenetic sequence consists of (1) minor quartz overgrowths, (2) illite and chlorite grain coatings, (3) quartz overgrowths, (4) early carbonate, (5) kaolinite, (6) calcite, (7) dolomite, and (8) pyrite. Porosity and permeability were not preserved once paragenesis progressed past the kaolinite stage. Porosity and permeability are variably preserved when steps in the paragenetic sequence are absent within the Pocono Group. Where any porosity is identified within the Pocono sandstones, primary porosity is dominant. However, secondary porosity and microporosity in clay-rich intervals are also important.« less

In-situ formation compaction monitoring in deep reservoirs by use of fiber optics

NASA Astrophysics Data System (ADS)

Murai, Daisuke; Kunisue, Shoji; Higuchi, Tomoyuki; Kokubo, Tatsuo

2013-04-01

depth of about 800m, and have been measuring the formation compaction of the natural gas reservoir now. 3. Conclusions (1) We succeeded in installing the monitoring system into the observation well and measure the each of 6 formation compactions in the gas reservoir. (2) As a result of the preliminary test we confirmed that the monitoring system run without big problems even in the field. The formation compacted/expanded with the groundwater level fallen/risen according to the pump rate. (3) We improved the monitoring system based on the knowledge acquired by the demonstration test and installed it into the deep observation well. We are carrying out the long term observation now. 4. Acknowledgements This research was carried out by the support for application of new technologies and technical studies program which Japan Oil, Gas and Metals National Corporation (JOGMEC) undertook.

Sulfur Isotope Analysis of Minerals and Fluids in a Natural CO2 Reservoir, Green River, Utah

NASA Astrophysics Data System (ADS)

Chen, F.; Kampman, N.; Bickle, M. J.; Busch, A.; Turchyn, A. V.

2013-12-01

Predicting the security of geological CO2 storage sites requires an understanding of the geochemical behavior of the stored CO2, especially of fluid-rock reactions in reservoirs, caprocks and fault zones. Factors that may influence geochemical behavior include co-injection of sulfur gases along with the CO2, either in acid-gas disposal or as contaminants in CO2 storage sites, and microbial activity, such as bacterial sulfate reduction. The latter may play an important role in buffering the redox chemistry of subsurface fluids, which could affect toxic trace metal mobilization and transport in acidic CO2-rich fluids. These processes involving sulfur are poorly understood. Natural CO2-reservoirs provide natural laboratories, where the flow and reactions of the CO2-charged fluids and the activity of microbial communities are integrated over sufficient time-scales to aid prediction of long-term CO2 storage. This study reports on sulfur isotope analyses of sulfate and sulfide minerals in rock core and in CO2-charged fluids collected from a stacked sequence of natural CO2 reservoirs at Green River, Utah. Scientific drilling adjacent to a CO2-degassing normal fault to a depth of 325m retrieved core and fluid samples from two CO2 reservoirs in the Entrada and Navajo Sandstones and from the intervening Carmel Formation caprock. Fluid samples were collected from CO2-charged springs that discharge through the faults. Sulfur exists as sulfate in the fluids, as sedimentary gypsum beds in the Carmel Formation, as remobilized gypsum veins within a fault damage zone in the Carmel Fm. and in the Entrada Sandstone, and as disseminated pyrite and pyrite-mineralized open fractures throughout the cored interval. We use the stable sulfur (δ34S) and oxygen (δ18OSO4) isotopes of the sulfate, gypsum, and pyrite to understand the source of sulfur in the reservoir as well as the timing of gypsum vein and pyrite formation. The hydration water of the gypsum is also reported to explore the

Stress heterogeneity above and within a deep geothermal reservoir: From borehole observations to geomechanical modelling

NASA Astrophysics Data System (ADS)

Seithel, Robin; Peters, Max; Lesueur, Martin; Kohl, Thomas

2017-04-01

Overpressured reservoir conditions, local stress concentrations or a locally rotated stress field can initiate substantial problems during drilling or reservoir exploitation. Increasing geothermal utilization in the Molasse basin area in S-Germany is faced with such problems of deeply seated reservoir sections. In several wells, radial fluid flow systems are interpreted as highly porous layers. However, in nearby wells a combination of linear fluid flow, local stress heterogeneities and structural geology hint to a rather fault dominated reservoir (Seithel et al. 2015). Due to missing knowledge of the stress magnitude, stress orientation and their coupling to reservoir response, we will present a THMC model of critical formations and the geothermal reservoir targeting nearby faults. In an area south of Munich, where several geothermal wells are constructed, such wells are interpreted and integrated into a 30 x 30 km simulated model area. One of the main objectives here is to create a geomechanical reservoir model in a thermo-mechanical manner in order to understand the coupling between reservoir heterogeneities and stress distributions. To this end, stress analyses of wellbore data and laboratory tests will help to calibrate a reliable model. In order to implement the complex geological structure of the studied wedge-shaped foreland basin, an automatic export of lithology, fault and borehole data (e.g. from Petrel) into a FE mesh is used. We will present a reservoir-scale model that considers thermo-mechanic effects and analyze their influence on reservoir deformation, fluid flow and stress concentration. We use the currently developed finite element application REDBACK (https://github.com/pou036/redback), inside the MOOSE framework (Poulet et al. 2016). We show that mechanical heterogeneities nearby fault zones and their orientation within the stress field correlate to fracture pattern, interpreted stress heterogeneities or variegated flow systems within the

Selection of reservoirs amenable to micellar flooding. First annual report, October 1978-December 1979

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

Goldburg, A.; Price, H.

The overall project objective is to build a solid engineering base upon which the Department of Energy (DOE) can improve and accelerate the application of micellar-polymer recovery technology to Mid-Continent and California sandstone reservoirs. The purpose of the work carried out under these two contracts is to significantly aid, both DOE and the private sector, in gaining the following Project Objectives: to select the better micellar-polymer prospects in the Mid-Continent and California regions; to assess all of the available field and laboratory data which has a bearing on recovering oil by micellar-polymer projects in order to help identify and resolvemore » both the technical and economic constraints relating thereto; and to design and analyze improved field pilots and tests and to develop a micellar-polymer applications matrix for use by the potential technology users; i.e., owner/operators. The report includes the following: executive summary and project objectives; development of a predictive model for economic evaluation of reservoirs; reservoir data bank for micellar-polymer recovery evaluation; PECON program for preliminary economic evaluation; ordering of candidate reservoirs for additional data acquisition; validation of predictive model by numerical simulation; and work forecast. Tables, figures and references are included.« less

Petro-elastic modelling and characterization of solid-filled reservoirs: Comparative analysis on a Triassic North Sea reservoir

NASA Astrophysics Data System (ADS)

Auduson, Aaron E.

2018-07-01

One of the most common problems in the North Sea is the occurrence of salt (solid) in the pores of Triassic sandstones. Many wells have failed due to interpretation errors based conventional substitution as described by the Gassmann equation. A way forward is to device a means to model and characterize the salt-plugging scenarios. Modelling the effects of fluid and solids on rock velocity and density will ascertain the influence of pore material types on seismic data. In this study, two different rock physics modelling approaches are adopted in solid-fluid substitution, namely the extended Gassmann theory and multi-mineral mixing modelling. Using the modified new Gassmann equation, solid-and-fluid substitutions were performed from gas or water filling in the hydrocarbon reservoirs to salt materials being the pore-filling. Inverse substitutions were also performed from salt-filled case to gas- and water-filled scenarios. The modelling results show very consistent results - Salt-plugged wells clearly showing different elastic parameters when compared with gas- and water-bearing wells. While the Gassmann equation-based modelling was used to discretely compute effective bulk and shear moduli of the salt plugs, the algorithm based on the mineral-mixing (Hashin-Shtrikman) can only predict elastic moduli in a narrow range. Thus, inasmuch as both of these methods can be used to model elastic parameters and characterize pore-fill scenarios, the New Gassmann-based algorithm, which is capable of precisely predicting the elastic parameters, is recommended for use in forward seismic modelling and characterization of this reservoir and other reservoir types. This will significantly help in reducing seismic interpretation errors.

Paving the road for hydraulic fracturing in Paleozoic tight gas reservoirs in Abu Dhabi

NASA Astrophysics Data System (ADS)

Alzarouni, Asim

This study contributes to the ongoing efforts of Abu Dhabi National Oil Company (ADNOC) to improve gas production and supply in view of increasing demand and diminishing conventional gas reservoirs in the region. The conditions of most gas reservoirs with potentially economical volumes of gas in Abu Dhabi are tight abrasive deep sand reservoirs at high temperature and pressures. Thus it inevitably tests the limit of both conventional thinking and technology. Accurate prediction of well performance is a major challenge that arises during planning phase. The primary aim is to determine technical feasibility for the implementation of the hydraulic fracture technology in a new area. The ultimate goal is to make economical production curves possible and pave the road to tap new resource of clean hydrocarbon energy source. The formation targeted in this study is characterized by quartzitic sandstone layers and variably colored shale and siltstones with thin layers of anhydrites. It dates back from late Permian to Carboniferous age. It forms rocks at the lower reservoir permeability ranging from 0.2 to less than 1 millidarcy (mD). When fractured, the expected well flow in Abu Dhabi offshore deep gas wells will be close to similar tight gas reservoir in the region. In other words, gas production can be described as transient initially with high rates and rapidly declining towards a pseudo-steady sustainable flow. The study results estimated fracturing gradient range from 0.85 psi/ft to 0.91 psi/ft. In other words, the technology can be implemented successfully to the expected rating without highly weighted brine. Hence, it would be a remarkable step to conduct the first hydraulic fracturing successfully in Abu Dhabi which can pave the road to tapping on a clean energy resource. The models predicted a remarkable conductivity enhancement and an increase of production between 3 to 4 times after fracturing. Moreover, a sustainable rate above 25 MMSCFD between 6 to 10 years is

Analyzing the Sand-fixing Effect of Feldspathic Sandstone from the Texture Characteristics

NASA Astrophysics Data System (ADS)

Zhang, lu; Ban, Jichang

2018-01-01

The purpose of this research was aimed to study the sand fixing effect of feldspathic sandstone in Mu Us Sandy Land, to provide a scienticic basis for desertification control, soil and water conservation and development of farming there. Methods of mixing feldspathic sandstone and aeolian sandy soil according to 1: 0, 1: 1, 1: 2, 1: 5, and 0: 1 mass ratioes, the graded composition and characteristics were studied with laser particle size analyzer. The result showed that these features of sand-based, loosely structured, easy to wind erosion of aeolian sandy soil were changed before feldspathic sandstone and aeolian sandy soil compounding. The <0.05 mm particle mass increased with feldspathic sandstone mass increasing. The texture presented this kind of change from sand to sandy loam to loam to silt loam. The small particle size distribution, good homogeneity and other features of aeolian sandy soil were improved to a certain degree, and the particle size distribution became broad before feldspathic sandstone and aeolian sandy soil compounding. The particle grading was continuous, and the grading characteristic was good when m(F): m(S) was 1: 5(Cu was 54.71 and Cc was 2.54) or when m(F): m(S) was 1: 2(Cu was 76.21, Cc was 1.12). The conclusion is that feldspathic sandstone has sand-fixing effect in texture characteristics, which heightens with feldspathic sandstone mass increasing, and when the mass ratio of feldspathic sandstone: aeolian sandy soil is 1: 2 or 1: 5 which compound better.

Mineral displacement and -dissolution processes and their relevance to rock porosity and permeability in Rotliegend sandstones of the Altmark natural gas field (central Germany) - results from CO2 laboratory batch experiments

NASA Astrophysics Data System (ADS)

Pudlo, Dieter; Enzmann, Frieder; Heister, Katja; Werner, Lars; Ganzer, Leonhard; Reitenbach, Viktor; Henkel, Steven; Albrecht, Daniel; Gaupp, Reinhard

2014-05-01

The Rotliegend reservoir sandstones of the Altmark area (central Germany) comprise the second largest natural gas field of Europe. These sandstones were deposited on a playa-like continental platform with braided river systems, ephemeral lakes and aeolian dunes under semi-arid conditions. Some of the pristine, red coloured deposits suffered intensive late diagenetic alteration and are now preserved as bleached, high porous and permeable sandstones. To evaluate the relevance of distinct fluids and their fluid-rock alteration reactions on such bleaching processes we performed laboratory static batch experiments on the Altmark sandstones. These 4-6 week lasting runs were conducted with CO2 saturated synthetic brines under typical Altmark reservoir conditions (p= 20 MPa, T= 125°C). Thereby mineralogical, petrophysical and (hydro- and geo-) chemical rock features were maintained prior and after the experiments. Chemical data proved the dissolution of carbonate and sulphate minerals during the runs, whereas the variation in abundance of further elements was within the detection limit of analytical accuracy. However, FE-SEM investigations on used, evaporated brines reveal the presence of illite and chlorite minerals within a matrix of Ca-, Si-, Fe, Al-, Na- and S components (carbonate, anhydrite, albite and Fe-(hydr-) oxides ?). By porosity and relative permeability measurements an increase in both rock features was observed after the runs, indicating that mineral dissolution and/or (clay) fine migration/detachment occurred during the experiments. Mineral dissolution, especially of pore-filling cements (e.g. carbonate-, sulphate minerals) is also deduced by BET analysis, in determining the specific surface of the sandstones. The size of these reactive surfaces increased after the experiments, suggesting that after the dissolution of pore-filling cements, formerly armoured grain rimming clay cutans were exposed to potential migrating fluids. These findings are also

Comparative petrology of arkosic sandstone lithofacies of Cowlitz, Spencer, and Yamhill Formations, northwest Oregon

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

Van Atta, R.O.

Recent discovery (1979) and commercial production of natural gas in arkosic sandstone (Clark and Wilson sand, informal) of the Cowlitz Formation near Mist, Oregon, has stimulated interest in the sedimentology and stratigraphy of Narizian sandstones of northwestern Oregon and the Willamette lowlands. Petrographic study of arkosic sandstone in the lower part of the Cowlitz Formation in surface outcrops in Clatsop, Tillamook, and Columbia Counties, Oregon, and in the Texaco 1 Clatskanie well reveals that the composition is more lithic than that of arkosic sandstone (Clark and Wilson sand) in the upper part of the Cowlitz Formation. The petrography of highlymore » permeable, arkosic sandstone in the Spencer Formation in the western Tualatin Valley south of the Mist gas field is identical in framework grain composition, texture, matrix composition, and heavy mineral content to that of the gas producing Clark and Wilson sand. The petrography of sandstone in the Yamhill Formation in the western Tualatin Valley is very like that of sandstone in the lower part of the Cowlitz Formation of northern northwest Oregon. Diagenetic alteration is more pronounced in arkosic sandstone in the lower part of the Cowlitz Formation and in the Yamhill Formation compared to diagenesis, which is almost nil in arkosic sandstone in the upper part of the cowlitz and in the Spencer Formations. Natural gas exploration will be aided by a clearer and more certain understanding of these petrologic differences between Eocene sandstones in northwestern Oregon.« less

The identification of multi-cave combinations in carbonate reservoirs based on sparsity constraint inverse spectral decomposition

NASA Astrophysics Data System (ADS)

Li, Qian; Di, Bangrang; Wei, Jianxin; Yuan, Sanyi; Si, Wenpeng

2016-12-01

Sparsity constraint inverse spectral decomposition (SCISD) is a time-frequency analysis method based on the convolution model, in which minimizing the l1 norm of the time-frequency spectrum of the seismic signal is adopted as a sparsity constraint term. The SCISD method has higher time-frequency resolution and more concentrated time-frequency distribution than the conventional spectral decomposition methods, such as short-time Fourier transformation (STFT), continuous-wavelet transform (CWT) and S-transform. Due to these good features, the SCISD method has gradually been used in low-frequency anomaly detection, horizon identification and random noise reduction for sandstone and shale reservoirs. However, it has not yet been used in carbonate reservoir prediction. The carbonate fractured-vuggy reservoir is the major hydrocarbon reservoir in the Halahatang area of the Tarim Basin, north-west China. If reasonable predictions for the type of multi-cave combinations are not made, it may lead to an incorrect explanation for seismic responses of the multi-cave combinations. Furthermore, it will result in large errors in reserves estimation of the carbonate reservoir. In this paper, the energy and phase spectra of the SCISD are applied to identify the multi-cave combinations in carbonate reservoirs. The examples of physical model data and real seismic data illustrate that the SCISD method can detect the combination types and the number of caves of multi-cave combinations and can provide a favourable basis for the subsequent reservoir prediction and quantitative estimation of the cave-type carbonate reservoir volume.

Material properties of Godula sandstones and forms and reasons of their deterioration in constructions in industrial environment of the Ostrava region

NASA Astrophysics Data System (ADS)

Vavro, Martin; Souček, Kamil; Martinec, Petr; Vavro, Leona; Handzelová, Barbora

2015-04-01

by presence of authigenic carbonates (dolomite and calcite) in the matrix and presence of very fine-grained framboidal pyrite localized especially in upper and more lutitic parts of sedimentary bodies. Using the method of 57Fe Mössbauer spectrometry, the Fe2+/Fe3+ ratio close to 1:1 in the crystal structure of glauconite separated from the Godula sandstones was estimated. In glauconite in the Godula sandstone, there is a sufficient quantity of Fe2+ which can be transformed to the Fe3+ form by the weathering process, which causes glauconite instability in the contact with the atmosphere. Structural features of rock are other risk factors influencing weathering. The Godula sandstones represent deep-marine turbiditic sediments with typical graded bedding. Problematic parts represent thin laminas rich in clay matter with dominant illite and/or illite/smectite mixed-layers in upper parts of mined sedimentary bodies. Due to significant structural anisotropy of the Godula sandstones, the final form of stone element degradation is also affected by the relationship between cutting plane during stone block processing and bedding planes. Ignorance of these aspects which influence durability of the Godula sandstones in exterior is the reason of often inappropriate use of stone in building industry in the environment affected by temperature and moisture changes which may result in early rehabilitation or reconstruction of constructions.

Understanding and Mitigating Reservoir Compaction: an Experimental Study on Sand Aggregates

NASA Astrophysics Data System (ADS)

Schimmel, M.; Hangx, S.; Spiers, C. J.

2016-12-01

Fossil fuels continue to provide a source for energy, fuels for transport and chemicals for everyday items. However, adverse effects of decades of hydrocarbons production are increasingly impacting society and the environment. Production-driven reduction in reservoir pore pressure leads to a poro-elastic response of the reservoir, and in many occasions to time-dependent compaction (creep) of the reservoir. In turn, reservoir compaction may lead to surface subsidence and could potentially result in induced (micro)seismicity. To predict and mitigate the impact of fluid extraction, we need to understand production-driven reservoir compaction in highly porous siliciclastic rocks and explore potential mitigation strategies, for example, by using compaction-inhibiting injection fluids. As a first step, we investigate the effect of chemical environment on the compaction behaviour of sand aggregates, comparable to poorly consolidated, highly porous sandstones. The sand samples consist of loose aggregates of Beaujean quartz sand, sieved into a grainsize fraction of 180-212 µm. Uniaxial compaction experiments are performed at an axial stress of 35 MPa and temperature of 80°C, mimicking conditions of reservoirs buried at three kilometres depth. The chemical environment during creep is either vacuum-dry or CO2-dry, or fluid-saturated, with fluids consisting of distilled water, acid solution (CO2-saturated water), alkaline solution (pH 9), aluminium solution (pH 3) and solution with surfactants (i.e., AMP). Preliminary results show that compaction of quartz sand aggregates is promoted in a wet environment compared to a dry environment. It is inferred that deformation is controlled by subcritical crack growth when dry and stress corrosion cracking when wet, both resulting in grain failure and subsequent grain rearrangement. Fluids inhibiting these processes, have the potential to inhibit aggregate compaction.

Preliminary study of a potential CO2 reservoir area in Hungary

NASA Astrophysics Data System (ADS)

Sendula, Eszter; Király, Csilla; Szabó, Zsuzsanna; Falus, György; Szabó, Csaba; Kovács, István; Füri, Judit; Kónya, Péter; Páles, Mariann; Forray, Viktória

2014-05-01

Since the first international agreement in 1997 (the Kyoto Protocol) the reduction of greenhouse gas emission has a key role in the European Union's energy and climate change policy. Following the Directive 2009/31/EC we are experiencing a significant change in the Hungarian national activity. Since the harmonization procedure, which was completed in May 2012, the national regulation obligates the competent authority to collect and regularly update all geological complexes that are potential for CO2 geological storage. In Hungary the most abundant potential storage formations are mostly saline aquifers of the Great Hungarian Plain (SE-Hungary), with sandstone reservoir and clayey caprock. The Neogene basin of the Great Hungarian Plain was subsided and then filled by a prograding delta system from NW and NE during the Late Miocene, mostly in the Pannonian time. The most potential storage rock was formed as a fine-grained sandy turbidite interlayered by thin argillaceous beds in the deepest part of the basin. It has relatively high porosity, depth and more than 1000 m thickness. Providing a regional coverage for the sandy turbidite, a 400-500 m thick argillaceous succession was formed in the slope environment. The composition, thickness and low permeability is expected to make it a suitable, leakage-safe caprock of the storage system. This succession is underlain by argillaceous rocks that were formed in the basin, far from sediment input and overlain by interfingering siltstone, sandstone and claystone succession formed in delta and shoreline environments and in the alluvial plain. Core samples have been collected from the potential reservoir rock and its cap rock in the Great Hungarian Plain's succession. The water compositions of the studied depth were known from well-log database. Using the information, acquired from these archive documents, we have constructed input data for geochemical modeling in order to to study the effect of pCO2 injection in the potential

Cense Explosion Test Program. Report 1. Cense 1. Explosions in Sandstone

DTIC Science & Technology

1977-09-01

series, "Analysis and Summary of CENSE Data." 10 * _ CHAPTER 2 APPROACH 2.1 DESCRIPTION OF TEST SITE An exposed outcrop of Kayenta sandstone with 180...ft/s seismic velocity previously determined (References 12-14) for the unweathered upper zone of the Kayenta sandstone. 16 I The P-wave propagation...Propagation along the horizontal radial was 8400 ft/s. The seismic velocity pre- viously determined for Kayenta sandstone in this area was 7500 ft/s

Mechanical Weakening during Fluid Injection in Critically Stressed Sandstones with Acoustic Monitoring

NASA Astrophysics Data System (ADS)

David, C.; Dautriat, J. D.; Sarout, J.; Macault, R.; Bertauld, D.

2014-12-01

Water weakening is a well-known phenomenon which can lead to subsidence during the production of hydrocarbon reservoirs. The example of the Ekofisk oil field in the North Sea has been well documented for years. In order to assess water weakening effects in reservoir rocks, previous studies have focused on changes in the failure envelopes derived from mechanical tests conducted on rocks saturated either with water or with inert fluids. However, little attention has been paid so far on the mechanical behaviour during the fluid injection stage, like in enhanced oil recovery operations. We studied the effect of fluid injection on the mechanical behaviour of Sherwood sandstone, a weakly-consolidated sandstone sampled at Ladram Bay in UK. In order to highlight possible weakening effects, water and inert oil have been injected into critically-loaded samples to assess their effect on strength and elastic properties and to derive the acoustic signature of the saturation front for each fluid. The specimens were instrumented with 16 ultrasonic P-wave transducers for both passive and active acoustic monitoring during fluid injection and loading. After conducting standard triaxial tests on three samples saturated with air, water and oil respectively, mechanical creep tests were conducted on dry samples loaded at 80% of the compressive strength of the dry rock. While these conditions are kept constant, a fluid is injected at the bottom end of the sample with a low back pressure (0.5 MPa) to minimize effective stress variations during injection. Both water and oil were used as the injected pore fluid in two experiments. As soon as the fluids start to flow into the samples, creep is taking place with a much higher strain rate for water injection compared to oil injection. A transition from secondary creep to tertiary creep is observed in the water injection test whereas in the oil injection test no significant creep acceleration is observed after one pore volume of oil was

Using sequence stratigraphic approaches in a highly tectonic area: Case study - Nubia (A) sandstone in southwestern Gulf of Suez, Egypt

NASA Astrophysics Data System (ADS)

Attia, Ibrahem; Helal, Iman; El Dakhakhny, Alaa; Aly, Said A.

2017-12-01

West Esh El Mallaha area is located west of the Hurghada shoreline. It pertains to the southwestern province of the Gulf of Suez. Nubia (A) sandstone is one of the prolific reservoirs in the western side along the Gulf of Suez area. To enhance further oil production and to develop this reservoir, it is important to gain a clear understanding of the reservoir in terms of its depositional origin. In west Esh El Mallaha area, the understanding of the depositional setting of Nubia (A) is relatively hard due to the limited number of cores. A comprehensive workflow which integrates all geological datasets (electrical logs pattern, the high resolution biostratigraphic analysis, and previous studies) which has been performed for the Nubia (A), enables to recognize different patterns of electrical logs, which are used to define the sequence stratigraphy and systems tracts for Nubia (A). The Lower Nubia (A) is characterized by fining-upward profile and well-developed coarsening-straight profile interpreted as a braided - fluvial facies (lowstand system tract). On the other hand, the upper Nubia (A) is characterized by fining-upward, coarsening-upward, and bell profile interpreted as meandering fluvial to fluvio-dominated delta (transgressive system tract). This study is an approach to build a reliable geological model, and give wide view to evaluate and develop the reservoir in the drilled areas and predict sand distribution in the undrilled areas despite the limited number of cores.

Metal release from sandstones under experimentally and numerically simulated CO2 leakage conditions.

PubMed

Kirsch, Katie; Navarre-Sitchler, Alexis K; Wunsch, Assaf; McCray, John E

2014-01-01

Leakage of CO2 from a deep storage formation into an overlying potable aquifer may adversely impact water quality and human health. Understanding CO2-water-rock interactions is therefore an important step toward the safe implementation of geologic carbon sequestration. This study targeted the geochemical response of siliclastic rock, specifically three sandstones of the Mesaverde Group in northwestern Colorado. To test the hypothesis that carbonate minerals, even when present in very low levels, would be the primary source of metals released into a CO2-impacted aquifer, two batch experiments were conducted. Samples were reacted for 27 days with water and CO2 at partial pressures of 0.01 and 1 bar, representing natural background levels and levels expected in an aquifer impacted by a small leakage, respectively. Concentrations of major (e.g., Ca, Mg) and trace (e.g., As, Ba, Cd, Fe, Mn, Pb, Sr, U) elements increased rapidly after CO2 was introduced into the system, but did not exceed primary Maximum Contaminant Levels set by the U.S. Environmental Protection Agency. Results of sequential extraction suggest that carbonate minerals, although volumetrically insignificant in the sandstone samples, are the dominant source of mobile metals. This interpretation is supported by a simple geochemical model, which could simulate observed changes in fluid composition through CO2-induced calcite and dolomite dissolution.

Integrated Analysis of Flow, Temperature, and Specific-Conductance Logs and Depth-Dependent Water-Quality Samples from Three Deep Wells in a Fractured-Sandstone Aquifer, Ventura County, California

USGS Publications Warehouse

Williams, John H.; Knutson, Kevin D.

2009-01-01

Analysis of flow, temperature, and specific-conductance logs and depth-dependent water-quality samples collected under ambient and pumped conditions provided a preliminary delineation of flow zones and water quality in three deep abandoned water-supply wells. The integrated analysis was completed as part of the characterization of a fractured-sandstone aquifer in the mountainous setting of the Santa Susana Field Laboratory in southern Ventura County, California. In the deepest well, which was 1,768 feet deep and had the highest specific capacity (120 gallons per minute per foot), flow zones were detected at 380 feet (base of casing) and at 440, 595, and 770 feet in the open hole. Under ambient conditions, measured flow was downward from the 380- and 440-foot zones to the 595- and 770-foot zones. Under pumped conditions, most of flow was contributed by the 595-foot zone. Flow from the 380- and 440-foot zones appeared to have lower specific conductance and higher trichloroethylene concentrations than that from the 595-foot zone. In the shallowest well, which was reportedly 940 feet deep but only logged to 915 feet due to blockage, flow zones were detected behind the perforated casing and at 867 feet in the open hole. Under ambient conditions, downward and upward flows appeared to exit at a zone behind the perforated casing at 708 feet. Most of the pumped flow was contributed from zones behind the perforated casing between 565 and 708 feet. Pumped flow also was contributed by zones at 867 feet and below the logged depth. Volatile organic compounds were not detected in the ambient and pumped flows. In the third well, which was 1,272 feet deep and had the lowest specific capacity (3.6 gallons per minute per foot), flow zones were detected in the open hole above and just below the water level near 337 feet and at 615, 785, 995, and 1,070 feet. Under ambient conditions, measured flow in well was downward from the shallowmost zones to the 995-foot zone. Fracture zones at

The Ogden Valley artesian reservoir

USGS Publications Warehouse

Thomas, H.E.

1945-01-01

Ogden Valley, in Weber County, Utah, contains an artesian reservoir from which the city of Ogden obtains all except a small part of its municipal water supply. A detailed investigation of the ground-water resources of Ogden Valley, and particularly of this artesian reservoir, was made by the Geological Survey, United States Department of the Interior, in cooperation with the city of Ogden between 1932 and 1934, and the results of this investigation have been reported by Leggette and Taylor.1 The present paper, which might be termed a sequel to that report, is based on data collected during those years, augmented by records that have been obtained (1935-1940) by the Geological Survey as part of a State-wide project in cooperation with the Utah State Engineer. The conclusions drawn from the study of these records and presented in detail in the following pages are as follows: (1) The artesian reservoir is filled to capacity nearly every year during the spring run-off from melting snow; (2) after the annual freshet, the recharge to the reservoir is insufficient to balance the discharge from artesian wells, which ordinarily is at a maximum during the summer; the reservoir is depleted and is not filled again until the following spring; (3) during the periods when the artesian reservoir is not full the rate of recharge is more or less proportional to the inflow to the valley by streams, except that rain on the recharge area may be of sufficient intensity to contribute some water by infiltration and deep penetration; and (4) the artesian reservoir thus serves to store water that would otherwise be lost to Great Salt Lake in the excess spring overflow, and available records indicate that water used by increased draft from wells would be replenished in normal years by increased recharge during the spring freshet.

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

Hamlin, H.S.; Dutton, S.P.; Tyler, N.

The Tirrawarra Sandstone contains 146 million bbl of oil in Tirrawarra field in the Cooper basin of South Australia. We used core, well logs, and petro-physical data to construct a depositional-facies-based flow-unit model of the reservoir, which describes rock properties and hydrocarbon saturations in three dimensions. Using the model to calculate volumes and residency of original and remaining oil in place, we identified an additional 36 million bbl of oil in place and improved understanding of past production patterns. The Tirrawarra Sandstone reservoir was deposited in a Carboniferous-Permian proglacial intracratonic setting and is composed of lacustrine and fluvial facies assemblages.more » The stratigraphic framework of these nonmarine facies is defined by distinctive stacking patterns and erosional unconformities. Mudstone dominated zones that are analogous to marine maximum flooding surfaces bound the reservoir. At its base a progradational lacustrine-delta system, composed of lenticular mud-clast-rich sandstones enclosed in mudstone, is truncated by an unconformity. Sandstones in these lower deltaic facies lost most of their porosity by mechanical compaction of ductile grains. Sediment reworking by channel migration and locally shore-zone processes created by quartz-rich, multilateral sandstones, which retained the highest porosity and permeability of all the reservoir facies and contained most of the original oil in place. Braided-channel sandstones, however, are overlain by lenticular meandering-channel sandstones, which in turn grade upward into widespread mudstones and coals. Thus, this uppermost part of the reservoir displays a retrogradational stacking pattern and upward-decreasing reservoir quality. Our results demonstrate that depositional variables are the primary controls on reservoir quality and productivity in the Tirrawarra Sandstone.« less

Evolution of permeability and Biot coefficient at high mean stresses in high porosity sandstone

DOE PAGES

Ingraham, Mathew D.; Bauer, Stephen J.; Issen, Kathleen A.; ...

2017-05-01

A series of constant mean stress (CMS) and constant shear stress (CSS) tests were performed to investigate the evolution of permeability and Biot coefficient at high mean stresses in a high porosity reservoir analog (Castlegate sandstone). Permeability decreases as expected with increasing mean stress, from about 20 Darcy at the beginning of the tests to between 1.5 and 0.3 Darcy at the end of the tests (mean stresses up to 275 MPa). The application of shear stress causes permeability to drop below that of a hydrostatic test at the same mean stress. Results show a nearly constant rate decrease inmore » the Biot coefficient as the mean stress increases during hydrostatic loading, and as the shear stress increases during CMS loading. In conclusion, CSS tests show a stabilization of the Biot coefficient after the application of shear stress.« less

Evolution of permeability and Biot coefficient at high mean stresses in high porosity sandstone