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Sample records for oil reservoir rock

  1. Dispersivity as an oil reservoir rock characteristic

    SciTech Connect

    Menzie, D.E.; Dutta, S.

    1989-12-01

    The main objective of this research project is to establish dispersivity, {alpha}{sub d}, as an oil reservoir rock characteristic and to use this reservoir rock property to enhance crude oil recovery. A second objective is to compare the dispersion coefficient and the dispersivity of various reservoir rocks with other rock characteristics such as: porosity, permeability, capillary pressure, and relative permeability. The dispersivity of a rock was identified by measuring the physical mixing of two miscible fluids, one displacing the other in a porous medium. 119 refs., 27 figs., 12 tabs.

  2. Characterizing flow in oil reservoir rock using SPH: absolute permeability

    NASA Astrophysics Data System (ADS)

    Holmes, David W.; Williams, John R.; Tilke, Peter; Leonardi, Christopher R.

    2016-04-01

    In this paper, a three-dimensional smooth particle hydrodynamics (SPH) simulator for modeling grain scale fluid flow in porous rock is presented. The versatility of the SPH method has driven its use in increasingly complex areas of flow analysis, including flows related to permeable rock for both groundwater and petroleum reservoir research. While previous approaches to such problems using SPH have involved the use of idealized pore geometries (cylinder/sphere packs etc), in this paper we detail the characterization of flow in models with geometries taken from 3D X-ray microtomographic imaging of actual porous rock; specifically 25.12 % porosity dolomite. This particular rock type has been well characterized experimentally and described in the literature, thus providing a practical `real world' means of verification of SPH that will be key to its acceptance by industry as a viable alternative to traditional reservoir modeling tools. The true advantages of SPH are realized when adding the complexity of multiple fluid phases, however, the accuracy of SPH for single phase flow is, as yet, under developed in the literature and will be the primary focus of this paper. Flow in reservoir rock will typically occur in the range of low Reynolds numbers, making the enforcement of no-slip boundary conditions an important factor in simulation. To this end, we detail the development of a new, robust, and numerically efficient method for implementing no-slip boundary conditions in SPH that can handle the degree of complexity of boundary surfaces, characteristic of an actual permeable rock sample. A study of the effect of particle density is carried out and simulation results for absolute permeability are presented and compared to those from experimentation showing good agreement and validating the method for such applications.

  3. Seismic monitoring of heavy oil reservoirs: Rock physics and finite element modelling

    NASA Astrophysics Data System (ADS)

    Theune, Ulrich

    In the past decades, remote monitoring of subsurface processes has attracted increasing attention in geophysics. With repeated geophysical surveys one attempts to detect changes in the physical properties in the underground without directly accessing the earth. This technique has been proven to be very valuable for monitoring enhanced oil recovery programs. This thesis presents an modelling approach for the feasibility analysis for monitoring of a thermal enhanced oil recovery technique applied to heavy oil reservoirs in the Western Canadian Sedimentary Basin. In order to produce heavy oil from shallow reservoirs thermal oil recovery techniques such as the Steam Assisted Gravity Drainage (SAGD) are often employed. As these techniques are expensive and technically challenging, early detection of operational problems is without doubt of great value. However, the feasibility of geophysical monitoring depends on many factors such as the changes in the rock physical properties of the target reservoir. In order to access the feasibility of seismic monitoring for heavy oil reservoirs, a fluid-substitutional rock physical study has been carried out to simulate the steam injection. The second modelling approach is based on a modified finite element algorithm to simulate the propagation of elastic waves in the earth, which has been developed independently in the framework of this thesis. The work summarized in this thesis shows a possibility to access the feasibility of seismic monitoring for heavy oil reservoirs through an extensive rock-physical study. Seismic monitoring is a useful tool in reservoir management decision process. However, the work reported here suggests that seismic monitoring of SAGD processes in the heavy oil reservoirs of the Western Canadian Sedimentary Basin is only feasible in shallow, unconsolidated deposits. For deeper, but otherwise geological similar reservoirs, the SAGD does not create a sufficient change in the rock physical properties to be

  4. Capillary Trapping of CO2 in Oil Reservoirs: Observations in a Mixed-Wet Carbonate Rock.

    PubMed

    Al-Menhali, Ali S; Krevor, Samuel

    2016-03-01

    Early deployment of carbon dioxide storage is likely to focus on injection into mature oil reservoirs, most of which occur in carbonate rock units. Observations and modeling have shown how capillary trapping leads to the immobilization of CO2 in saline aquifers, enhancing the security and capacity of storage. There are, however, no observations of trapping in rocks with a mixed-wet-state characteristic of hydrocarbon-bearing carbonate reservoirs. Here, we found that residual trapping of supercritical CO2 in a limestone altered to a mixed-wet state with oil was significantly less than trapping in the unaltered rock. In unaltered samples, the trapping of CO2 and N2 were indistinguishable, with a maximum residual saturation of 24%. After the alteration of the wetting state, the trapping of N2 was reduced, with a maximum residual saturation of 19%. The trapping of CO2 was reduced even further, with a maximum residual saturation of 15%. Best-fit Land-model constants shifted from C = 1.73 in the water-wet rock to C = 2.82 for N2 and C = 4.11 for the CO2 in the mixed-wet rock. The results indicate that plume migration will be less constrained by capillary trapping for CO2 storage projects using oil fields compared with those for saline aquifers. PMID:26812184

  5. Diffusion and spatially resolved NMR in Berea and Venezuelan oil reservoir rocks.

    PubMed

    Murgich, J; Corti, M; Pavesi, L; Voltini, F

    1992-01-01

    Conventional and spatially resolved proton NMR and relaxation measurements are used in order to study the molecular motions and the equilibrium and nonequilibrium diffusion of oils in Berea sandstone and Venezuelan reservoir rocks. In the water-saturated Berea a single line with T*2 congruent to 150 microseconds is observed, while the relaxation recovery is multiexponential. In an oil reservoir rock (Ful 13) a single narrow line is present while a distribution of relaxation rates is evidenced from the recovery plots. On the contrary, in the Ful 7 sample (extracted at a deeper depth in a different zone) two NMR components are present, with 3.5 and 30 KHz linewidths, and the recovery plot exhibits biexponential law. No echo signal could be reconstructed in the oil reservoir rocks. These findings can be related to the effects in the micropores, where motions at very low frequency can occur in a thin layer. From a comparison of the diffusion constant in water-saturated Berea, D congruent to 5*10(-6) cm2/sec, with the ones in model systems, the average size of the pores is estimated around 40 A. The density profiles at the equilibrium show uniform distribution of oils or of water, and the relaxation rates appear independent from the selected slice. The nonequilibrium diffusion was studied as a function of time in a Berea cylinder with z axis along H0, starting from a thin layer of oil at the base, and detecting the spin density profiles d(z,t) with slice-selection techniques. Simultaneously, the values of T1's were measured locally, and the distribution of the relaxation rates was observed to be present in any slice.(ABSTRACT TRUNCATED AT 250 WORDS) PMID:1461080

  6. Geochemical character and origin of oils in Ordovician reservoir rock, Illinois and Indiana, USA

    SciTech Connect

    Guthrie, J.M.; Pratt, L.M.

    1995-11-01

    Twenty-three oils produced from reservoirs within the Ordovician Galena Group (Trenton equivalent) and one oil from the Mississippian Ste. Genevieve Limestone in the Illinois and Indiana portions of the Illinois basin are characterized. Two end-member oil groups (1) and (2) and one intermediate group (1A) are identified using conventional carbon isotopic analysis of whole and fractionated oils, gas chromatography (GC) of saturated hydrocarbon fractions, isotope-ratio-monitoring gas chromatography/mass spectrometry (irm-GC/MS) of n-alkanes ranging from C{sub 15} to C{sub 25}, and gas chromatography/mass spectrometry (GC/MS) of the aromatic hydrocarbon fractions. Group 1 is characterized by high odd-carbon predominance in mid-chain n-alkanes (C{sub 15}-C{sub 19}), low abundance Of C{sub 20+}, n-alkanes, and an absence of pristane and phytane. Group IA is characterized by slightly lower odd-carbon predominance of mid-chain n-alkanes, greater abundance of C{sub 20+} n-alkanes compared to group 1, and no pristane and phytane. Conventional correlations of oil to source rock based on carbon isotopic-type curves and hopane (m/z 191) and sterane (m/z 217) distributions are of limited use in distinguishing Ordovician-reservoired oil groups and determining their origin. Oil to source rock correlations using the distribution and carbon isotopic composition of n-alkanes and the m/z 133 chromatograms of n-alkylarenes show that groups 1 and 1A originated from strata of the Upper Ordovician Galena Group. Group 2 either originated solely from the Upper Ordovician Maquoketa Group or from a mixture of oils generated from the Maquoketa Group and the Galena Group. The Mississippian-reservoired oil most likely originated from the Devonian New Albany Group. The use of GC, irm-GC/MS, and GC/MS illustrates the value of integrated molecular and isotopic approaches for correlating oil groups with source rocks.

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

    SciTech Connect

    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 the 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.

  8. The Obtaining of Oil from an Oil Reservoir.

    ERIC Educational Resources Information Center

    Dawe, R. A.

    1979-01-01

    Discusses the mechanics of how an actual oil reservoir works and provides some technical background in physics. An experiment which simulates an oil reservoir and demonstrates quantitatively all the basic concepts of oil reservoir rock properties is also presented. (HM)

  9. Hydrothermal origin of oil and gas reservoirs in basement rock of the South Vietnam continental shelf

    SciTech Connect

    Dmitriyevskiy, A.N.; Kireyev, F.A.; Bochko, R.A.; Fedorova, T.A. )

    1993-07-01

    Oil-saturated granites, with mineral parageneses typical of hydrothermal metasomatism and leaching haloes, have been found near faults in the crystalline basement of the South Vietnam continental shelf. The presence of native silver, barite, zincian copper, and iron chloride indicates a deep origin for the mineralizing fluids. Hydrothermally altered granites are a new possible type of reservoir and considerably broaden the possibilities of oil and gas exploration. 15 refs., 22 figs., 1 tab.

  10. Reservoir rock permeability prediction using support vector regression in an Iranian oil field

    NASA Astrophysics Data System (ADS)

    Saffarzadeh, Sadegh; Shadizadeh, Seyed Reza

    2012-06-01

    Reservoir permeability is a critical parameter for the evaluation of hydrocarbon reservoirs. It is often measured in the laboratory from reservoir core samples or evaluated from well test data. The prediction of reservoir rock permeability utilizing well log data is important because the core analysis and well test data are usually only available from a few wells in a field and have high coring and laboratory analysis costs. Since most wells are logged, the common practice is to estimate permeability from logs using correlation equations developed from limited core data; however, these correlation formulae are not universally applicable. Recently, support vector machines (SVMs) have been proposed as a new intelligence technique for both regression and classification tasks. The theory has a strong mathematical foundation for dependence estimation and predictive learning from finite data sets. The ultimate test for any technique that bears the claim of permeability prediction from well log data is the accurate and verifiable prediction of permeability for wells where only the well log data are available. The main goal of this paper is to develop the SVM method to obtain reservoir rock permeability based on well log data.

  11. Post - sedimentation influence on filtration capacity reservoir rock properties (Pur-Tazov oil\\gas-bearing area)

    NASA Astrophysics Data System (ADS)

    Isaeva, E.; Stolbova, N.; Dolgaya, T.

    2015-11-01

    The processes of the second mineral formation (kaolinite, carbonates and micas) were identified during the post-sedimentation transformation studies in oil⪆s deposits. Besides, quartz regeneration, solid product destructive formation processes and hydrocarbon oxidation processes were -determined. Correlation analysis of the mineralogy and petrophysics data revealed the post-sedimentation influence factors on the reservoir properties of deposits. It should be noted that the second kaolinite composition increase results in water saturation and density decrease, porosity and, especially, permeability increase. Quartz regeneration and second mica formation deteriorate the reservoir properties or poorly influence them. The hydrocarbon decay and oxidation products, as well as secondary carbonate seal the void space, replace the soluble rock debris and sharply deteriorate the reservoir properties of oil andgas deposits.

  12. Chemistry and mineralogy of natural bitumens and heavy oils and their reservoir rocks from the United States, Canada, Trinidad and Tobago, and Venezuela

    USGS Publications Warehouse

    Hosterman, John W.; Meyer, R.F.; Palmer, C.A.; Doughten, M.W.; Anders, D.E.

    1990-01-01

    Twenty-one samples from natural bitumen and heavy oil deposits in seven States of the United States and six samples from outside the United States form the basis of this initial study. This Circular gives the mineral content of the reservoir rock, the trace-element distribution in the reservoir rock and hydrocarbons, and the composition of the heavy oil and natural bitumen. The reservoir rock and sediment residues from California contain more trace-element maximum amounts than any of the other rock samples. These relatively high concentrations of trace elements may be due, in part, to the low quartz content of the rock and to the presence of heulandite, cristobalite, siderite, and pyrite. The reservoir rock and sediment residues from Oklahoma contain more minimum amounts of trace elements than any of the other rock samples. This pattern probably results from the large amount of quartz in four of the samples and a large amount of calcite in the other sample. The maximum and minimum amounts of trace elements in the bitumen and heavy oil do not correlate with those in the reservoir rocks. The bitumen from Utah contains the greatest number of trace-element maxima, whereas there is no trend in the trace-element minima in the bitumen and heavy oil.

  13. Hydrodynamic thickness of petroleum oil adsorbed layers in the pores of reservoir rocks.

    PubMed

    Alkafeef, Saad F; Algharaib, Meshal K; Alajmi, Abdullah F

    2006-06-01

    The hydrodynamic thickness delta of adsorbed petroleum (crude) oil layers into the pores of sandstone rocks, through which the liquid flows, has been studied by Poiseuille's flow law and the evolution of (electrical) streaming current. The adsorption of petroleum oil is accompanied by a numerical reduction in the (negative) surface potential of the pore walls, eventually stabilizing at a small positive potential, attributed to the oil macromolecules themselves. After increasing to around 30% of the pore radius, the adsorbed layer thickness delta stopped growing either with time or with concentrations of asphaltene in the flowing liquid. The adsorption thickness is confirmed with the blockage value of the rock pores' area determined by the combination of streaming current and streaming potential measurements. This behavior is attributed to the effect on the disjoining pressure across the adsorbed layer, as described by Derjaguin and Churaev, of which the polymolecular adsorption films lose their stability long before their thickness has approached the radius of the rock pore. PMID:16414057

  14. Research on anisotropy of shale oil reservoir based on rock physics model

    NASA Astrophysics Data System (ADS)

    Guo, Zhi-Qi; Liu, Cai; Liu, Xi-Wu; Dong, Ning; Liu, Yu-Wei

    2016-06-01

    Rock physics modeling is implemented for shales in the Luojia area of the Zhanhua topographic depression. In the rock physics model, the clay lamination parameter is introduced into the Backus averaging theory for the description of anisotropy related to the preferred alignment of clay particles, and the Chapman multi-scale fracture theory is used to calculate anisotropy relating to the fracture system. In accordance with geological features of shales in the study area, horizontal fractures are regarded as the dominant factor in the prediction of fracture density and anisotropy parameters for the inversion scheme. Results indicate that the horizontal fracture density obtained has good agreement with horizontal permeability measured from cores, and thus confirms the applicability of the proposed rock physics model and inversion method. Fracture density can thus be regarded as an indicator of reservoir permeability. In addition, the anisotropy parameter of the P-wave is higher than that of the S-wave due to the presence of horizontal fractures. Fracture density has an obvious positive correlation with P-wave anisotropy, and the clay content shows a positive correlation with S-wave anisotropy, which fully shows that fracture density has a negative correlation with clay and quartz contents and a positive relation with carbonate contents.

  15. Oil biodegradation by Bacillus strains isolated from the rock of an oil reservoir located in a deep-water production basin in Brazil.

    PubMed

    da Cunha, Claudia Duarte; Rosado, Alexandre S; Sebastián, Gina V; Seldin, Lucy; von der Weid, Irene

    2006-12-01

    Sixteen spore forming Gram-positive bacteria were isolated from the rock of an oil reservoir located in a deep-water production basin in Brazil. These strains were identified as belonging to the genus Bacillus using classical biochemical techniques and API 50CH kits, and their identity was confirmed by sequencing of part of the 16S rRNA gene. All strains were tested for oil degradation ability in microplates using Arabian Light and Marlin oils and only seven strains showed positive results in both kinds of oils. They were also able to grow in the presence of carbazole, n-hexadecane and polyalphaolefin (PAO), but not in toluene, as the only carbon sources. The production of key enzymes involved with aromatic hydrocarbons biodegradation process by Bacillus strains (catechol 1,2-dioxygenase and catechol 2,3-dioxygenase) was verified spectrophotometrically by detection of cis,cis-muconic acid and 2-hydroxymuconic semialdehyde, and results indicated that the ortho ring cleavage pathway is preferential. Furthermore, polymerase chain reaction (PCR) products were obtained when the DNA of seven Bacillus strains were screened for the presence of catabolic genes encoding alkane monooxygenase, catechol 1,2-dioxygenase, and/or catechol 2,3-dioxygenase. This is the first study on Bacillus strains isolated from an oil reservoir in Brazil. PMID:16896598

  16. Actualistic and Geochemical Modeling of Reservoir Rock, CO2 and Formation Fluid Interaction, Citronelle Oil Field, Alabama

    SciTech Connect

    Weislogel, Amy

    2014-01-31

    This report includes description of the Citronelle field study area and the work carried out in the project to characterize the geology and composition of reservoir rock material and to collect an analyze the geochemical composition of produced fluid waters from the Citronelle field. Reservoir rock samples collected from well bore core were made into thin-sections and assessed for textural properties, including pore types and porosity distribution. Compositional framework grain modal data were collected via point-counting, and grain and cement mineralogy was assessed using SEM-EDS. Geochemistry of fluid samples is described and modeled using PHREEQC. Composition of rock and produced fluids were used as inputs for TOUGHREACT reactive transport modeling, which determined the rock-fluid system was in disequilibrium.

  17. The Impacts of Rock Composition and Properties on the Ability to Stimulate Production of Ultra-Low Permeability Oil and Gas Reservoirs Through Hydraulic Fracturing

    NASA Astrophysics Data System (ADS)

    Zoback, M. D.; Sone, H.; Kohli, A. H.; Heller, R. J.

    2014-12-01

    In this talk, we present the results of several research projects investigating how rock properties, natural fractures and the state of stress affect the success of hydraulic fracturing operations during stimulation of shale gas and tight oil reservoirs. First, through laboratory measurements on samples of the Barnett, Eagle Ford, Haynesville and Horn River shales, we discuss pore structure, adsorption and permeability as well as the importance of clay content on the viscoplastic behavior of shale formations. Second, we present several lines of evidence that indicates that the principal way in which hydraulic fracturing stimulates production from shale gas reservoirs is by inducing slow slip on pre-existing fractures and faults, which are not detected by conventional microseismic monitoring, Finally, we discuss how hydraulic fracturing can be optimized in response to variations of rock properties.

  18. Magnetotelluric survey for exploration of a volcanic-rock reservoir in the Yurihara oil and gas field, Japan

    SciTech Connect

    Mitsuhata, Yuji; Matsuo, Koichi; Minegishi, Masato

    1999-03-01

    The Yurihara oil and gas field is located on the southern edge of Akita Prefecture, northeastern Japan. In this area, drilling, surface geological surveys and many seismic surveys have been used to investigate the geological structure. Wells drilled into the Nishikurosawa Basalt Group (NBG) of Miocene age found oil and gas reservoirs at depths of 1.5--2 km. Oil and gas are now being produced commercially and further exploration is required in the surrounding areas. However, since the neighboring areas are covered with young volcanic products from the Chokai volcano, and have a rough topography, the subsurface distribution of the NBG must be investigated using other methods in addition to seismic reflection. According to the well data, the resistivity of the NBG is comparatively higher than that of the overlying sedimentary formations, and therefore the magnetotelluric (MT) method is expected to be useful for the estimation of the distribution of the NBG. An MT survey was conducted along three survey lines in this area. Each line trended east-west, perpendicular to the regional geological strike, and was composed of about 25 measurement sites. Induction vectors evaluated from the magnetic field show that this area has a two-dimensional structure. The evaluated resistivity sections are in agreement with the log data. In conclusion, the authors were able to detect resistive layers (the NBG) below conductive layers. The results indicate that the NBG becomes gradually less resistive from north to south. In the center of the northern line, an uplifted resistive area is interpreted as corresponding to the reservoir. By comparison with a seismic section, the authors prove the effectiveness of the integration of seismic and MT surveys for the investigation of the morphology and internal structure of the NBG. On other survey lines, the resistive uplifted zones are interpreted as possible prospective areas.

  19. Storage capacity in hot dry rock reservoirs

    DOEpatents

    Brown, D.W.

    1997-11-11

    A method is described for extracting thermal energy, in a cyclic manner, from geologic strata which may be termed hot dry rock. A reservoir comprised of hot fractured rock is established and water or other liquid is passed through the reservoir. The water is heated by the hot rock, recovered from the reservoir, cooled by extraction of heat by means of heat exchange apparatus on the surface, and then re-injected into the reservoir to be heated again. Water is added to the reservoir by means of an injection well and recovered from the reservoir by means of a production well. Water is continuously provided to the reservoir and continuously withdrawn from the reservoir at two different flow rates, a base rate and a peak rate. Increasing water flow from the base rate to the peak rate is accomplished by rapidly decreasing backpressure at the outlet of the production well in order to meet periodic needs for amounts of thermal energy greater than a baseload amount, such as to generate additional electric power to meet peak demands. The rate of flow of water provided to the hot dry rock reservoir is maintained at a value effective to prevent depletion of the liquid inventory of the reservoir. 4 figs.

  20. Reservoir management applications to oil reservoirs

    SciTech Connect

    Martin, F.D.; Ouenes, A.; Weiss, W.W.; Chawathe, A.

    1996-02-01

    Winnipegosis and Red River oil production in the Bainville North Field in Roosevelt County, Montana began in 1979. The Red River is at 12,500 ft and one well is completed in the Nisku formation at 10,200 ft. This well produced 125,000 bbl from the Nisku during its first 41 months. Since operating conditions inhibit dual completions and Nisku wells cost $900,000, the need for a Nisku development plan is apparent. The size of the reservoir and optimum well density are the key unknowns. Recognizing the need for additional Nisku data, a 5000 acre 3-D seismic survey was processed and the results used to map the top of the Nisku. The reservoir thickness, porosity, and water saturation were known from the openhole logs at eight well locations on an average of 320 acres spacing. The thickness of the thin pay limited the seismic information to areal extent of reservoir depth. Static reservoir pressure from drillstem test was available at two wells. Additional reservoir pressure data in the form of transient tests were available at two wells. Under Los Alamos National Laboratory Basic Ordering Agreement 9-XU3-0402J-1, the New Mexico Petroleum Recovery Research Center (PRRC) characterized the Nisku to develop a reservoir management plan. Nance Petroleum provided all available field and laboratory data for characterizing the Nisku formation. Due to sparse well coverage, and the lack of producing wells, the PRRC had to develop a new reservoir description approach to reach an acceptable characterization of the entire reservoir. This new approach relies on the simultaneous use of 3-D seismic and reservoir simulation to estimate key reservoir properties.

  1. Characterization of oil and gas reservoir heterogeneity

    SciTech Connect

    Sharma, G.D.

    1992-01-01

    The ultimate objective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task 1 is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization-determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis-source rock identification; and the study of asphaltene precipitation for Alaskan crude oils. Results are discussed.

  2. Characterization of oil and gas reservoir heterogeneity

    SciTech Connect

    Sharma, G.D.

    1992-01-01

    The ultimate objective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task 1 is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization -- determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis -- source rock identification; and the study of asphaltene precipitation for Alaskan crude oils.

  3. Characterization of oil and gas reservoir heterogeneity

    SciTech Connect

    Sharma, G.D.

    1992-01-01

    The ultimate oojective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task 1 is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization--determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis--source rock identification; and the study of asphaltene precipitation for Alaskan crude oils. This report presents a summary of technical progress of the well log analysis of Kuparuk Field, Northslope, Alaska.

  4. Storage capacity in hot dry rock reservoirs

    DOEpatents

    Brown, Donald W.

    1997-01-01

    A method of extracting thermal energy, in a cyclic manner, from geologic strata which may be termed hot dry rock. A reservoir comprised of hot fractured rock is established and water or other liquid is passed through the reservoir. The water is heated by the hot rock, recovered from the reservoir, cooled by extraction of heat by means of heat exchange apparatus on the surface, and then re-injected into the reservoir to be heated again. Water is added to the reservoir by means of an injection well and recovered from the reservoir by means of a production well. Water is continuously provided to the reservoir and continuously withdrawn from the reservoir at two different flow rates, a base rate and a peak rate. Increasing water flow from the base rate to the peak rate is accomplished by rapidly decreasing backpressure at the outlet of the production well in order to meet periodic needs for amounts of thermal energy greater than a baseload amount, such as to generate additional electric power to meet peak demands. The rate of flow of water provided to the hot dry rock reservoir is maintained at a value effective to prevent depletion of the liquid

  5. Geophysical and transport properties of reservoir rocks. Summary annual report

    SciTech Connect

    Cook, N.G.W.

    1990-04-29

    Definition of petrophysical properties, such as porosity, permeability and fluid saturation, on the scale of meters, is the key to planning and control of successful Enhanced Oil Recovery techniques for domestic reservoirs. Macroscopic transport properties in reservoir rocks depend critically upon processes at the pore level involving interactions between the pore topology and the physical and chemical properties of the rock minerals and interstitial fluids. Similar interactions at the pore level determine also the macroscopic electrical and seismic properties of reservoir rocks. The objective of this research is to understand, using analysis and experiment, how fluids in pores affect the geophysical and sport properties of reservoir rocks. The goal is to develop equations-relating seismic and electrical properties of rock to the porosity, permeability and fluid saturations so as to invert geophysical images for improved reservoir management. Results from seismic measurements performed so far in this study suggest that even subtle changes in fluid contacts and the in-situ state of effective stress can be detected using geophysical imaging techniques. The experiments using Wood`s metal and wax are revealing the topology and sport properties of the pore space in clastic sedimentary rocks. A deeper understanding of these properties is considered-to be the key to the recovery of much of the mobile oil left in domestic reservoirs and to the effective management of enhanced oil recovery techniques. The results of Wood`s metal percolation tests indicate that most of the permeability of Berea sandstone resides in the critical percolating paths and these paths occupy only a small fraction of the total porosity. This result may have important implications for flooding in terms of override and efficiency as a function of saturation.

  6. Imaging fluid/solid interactions in hydrocarbon reservoir rocks

    SciTech Connect

    Uwins, P.J.R.; Baker, J.C.; Mackinnon, I.D.R. . Centre for Microscopy and Microanalysis)

    1993-08-01

    The environmental scanning electron microscope (ESEM) has been used to image liquid hydrocarbons in sandstones and oil shales. Additionally, the fluid sensitivity of selected clay minerals in hydrocarbon reservoirs was assessed via three case studies: HCl acid sensitivity of authigenic chlorite in sandstone reservoirs, freshwater sensitivity of authigenic illite/smectite in sandstone reservoir, and bleach sensitivity of a volcanic reservoir containing abundant secondary chlorite/corrensite. The results showed the suitability of using ESEM for imaging liquid hydrocarbon films in hydrocarbon reservoirs and the importance of simulating in situ fluid-rock interactions for hydrocarbon production programs. In each case, results of the ESEM studies greatly enhanced prediction of reservoir/borehole reactions and, in some cases, contradicted conventional wisdom regarding the outcome of potential engineering solutions.

  7. Imaging fluid/solid interactions in hydrocarbon reservoir rocks.

    PubMed

    Uwins, P J; Baker, J C; Mackinnon, I D

    1993-08-01

    The environmental scanning electron microscope (ESEM) has been used to image liquid hydrocarbons in sandstones and oil shales. Additionally, the fluid sensitivity of selected clay minerals in hydrocarbon reservoirs was assessed via three case studies: HCl acid sensitivity of authigenic chlorite in sandstone reservoirs, freshwater sensitivity of authigenic illite/smectite in sandstone reservoirs, and bleach sensitivity of a volcanic reservoir containing abundant secondary chlorite/corrensite. The results showed the suitability of using ESEM for imaging liquid hydrocarbon films in hydrocarbon reservoirs and the importance of simulating in situ fluid-rock interactions for hydrocarbon production programmes. In each case, results of the ESEM studies greatly enhanced prediction of reservoir/borehole reactions and, in some cases, contradicted conventional wisdom regarding the outcome of potential engineering solutions. PMID:8400441

  8. Iron speciation and mineral characterization of upper Jurassic reservoir rocks in the Minhe Basin, NW China

    NASA Astrophysics Data System (ADS)

    Ma, Xiangxian; Zheng, Guodong; Xu, Wang; Liang, Minliang; Fan, Qiaohui; Wu, Yingzhong; Ye, Conglin; Shozugawa, Katsumi; Matsuo, Motoyuki

    2016-12-01

    Six samples from a natural outcrop of reservoir rocks with oil seepage and two control samples from surrounding area in the Minhe Basin, northwestern China were selectively collected and analyzed for mineralogical composition as well as iron speciation using X-ray powder diffraction (XRD) and Mössbauer spectroscopy, respectively. Iron species revealed that: (1) the oil-bearing reservoir rocks were changed by water-rock-oil interactions; (2) even in the same site, there was a different performance between sandstone and mudstone during the oil and gas infusion to the reservoirs; and (3) this was evidence indicating the selective channels of hydrocarbon migration. In addition, these studies showed that the iron speciation by Mössbauer spectroscopy could be useful for the study of oil and gas reservoirs, especially the processes of the water-rock interactions within petroleum reservoirs.

  9. Reservoir, seal, and source rock distribution in Essaouira Rift Basin

    SciTech Connect

    Ait Salem, A. )

    1994-07-01

    The Essaouira onshore basin is an important hydrocarbon generating basin, which is situated in western Morocco. There are seven oil and gas-with-condensate fields; six are from Jurassic reservoirs and one from a Triassic reservoir. As a segment of the Atlantic passive continental margin, the Essaouira basin was subjected to several post-Hercynian basin deformation phases, which resulted in distribution, in space and time, of reservoir, seal, and source rock. These basin deformations are synsedimentary infilling of major half grabens with continental red buds and evaporite associated with the rifting phase, emplacement of a thick postrifting Jurassic and Cretaceous sedimentary wedge during thermal subsidence, salt movements, and structural deformations in relation to the Atlas mergence. The widely extending lower Oxfordian shales are the only Jurassic shale beds penetrated and recognized as potential and mature source rocks. However, facies analysis and mapping suggested the presence of untested source rocks in Dogger marine shales and Triassic to Liassic lacustrine shales. Rocks with adequate reservoir characteristics were encountered in Triassic/Liassic fluvial sands, upper Liassic dolomites, and upper Oxfordian sandy dolomites. The seals are provided by Liassic salt for the lower reservoirs and Middle to Upper Jurassic anhydrite for the upper reservoirs. Recent exploration studies demonstrate that many prospective structure reserves remain untested.

  10. Research on oil recovery mechanisms in heavy oil reservoirs

    SciTech Connect

    Kovscek, Anthony R.; Brigham, William E., Castanier, Louis M.

    2000-03-16

    The research described here was directed toward improved understanding of thermal and heavy-oil production mechanisms and is categorized into: (1) flow and rock properties, (2) in-situ combustion, (3) additives to improve mobility control, (4) reservoir definition, and (5) support services. The scope of activities extended over a three-year period. Significant work was accomplished in the area of flow properties of steam, water, and oil in consolidated and unconsolidated porous media, transport in fractured porous media, foam generation and flow in homogeneous and heterogeneous porous media, the effects of displacement pattern geometry and mobility ratio on oil recovery, and analytical representation of water influx.

  11. A new type of reservoir rock in volcaniclastic sequences

    SciTech Connect

    Vernik, L. )

    1990-06-01

    Development of pronounced secondary porosity and permeability, accompanied by dramatic changes in wave propagation velocity and other physical properties, in laumontite tuffs occurs in the oil fields of eastern Georgia, Soviet Union. These rocks originated during intense hydrothermal alterations of andesite tuffs and comprise local (few meters thick), commonly lens-shaped bodies. Hydrothermal alteration was lithologically and structurally controlled, resulting in the formation of specific reservoir rocks identifiable on geophysical logs and capable of producing oil and gas. The considerable relief of the in-situ stress within these bodies was estimated from differential velocity analysis using sonic-log and laboratory data. This stress relief, as well as borehole enlargements (accompanied by the development of zones of nonelastic deformation around the hole) tends to enhance near-well permeability and, hence, the productive potential of these uncommon and poorly studied reservoirs. 6 figs., 3 tabs.

  12. Adsorption of water vapor on reservoir rocks

    SciTech Connect

    Not Available

    1993-07-01

    Progress is reported on: adsorption of water vapor on reservoir rocks; theoretical investigation of adsorption; estimation of adsorption parameters from transient experiments; transient adsorption experiment -- salinity and noncondensible gas effects; the physics of injection of water into, transport and storage of fluids within, and production of vapor from geothermal reservoirs; injection optimization at the Geysers Geothermal Field; a model to test multiwell data interpretation for heterogeneous reservoirs; earth tide effects on downhole pressure measurements; and a finite-difference model for free surface gravity drainage well test analysis.

  13. Multiscale properties of unconventional reservoir rocks

    NASA Astrophysics Data System (ADS)

    Woodruff, W. F.

    A multidisciplinary study of unconventional reservoir rocks is presented, providing the theory, forward modeling and Bayesian inverse modeling approaches, and laboratory protocols to characterize clay-rich, low porosity and permeability shales and mudstones within an anisotropic framework. Several physical models characterizing oil and gas shales are developed across multiple length scales, ranging from microscale phenomena, e.g. the effect of the cation exchange capacity of reactive clay mineral surfaces on water adsorption isotherms, and the effects of infinitesimal porosity compaction on elastic and electrical properties, to meso-scale phenomena, e.g. the role of mineral foliations, tortuosity of conduction pathways and the effects of organic matter (kerogen and hydrocarbon fractions) on complex conductivity and their connections to intrinsic electrical anisotropy, as well as the macro-scale electrical and elastic properties including formulations for the complex conductivity tensor and undrained stiffness tensor within the context of effective stress and poroelasticity. Detailed laboratory protocols are described for sample preparation and measurement of these properties using spectral induced polarization (SIP) and ultrasonics for the anisotropic characterization of shales for both unjacketed samples under benchtop conditions and jacketed samples under differential loading. An ongoing study of the effects of kerogen maturation through hydrous pyrolysis on the complex conductivity is also provided in review. Experimental results are catalogued and presented for various unconventional formations in North America including the Haynesville, Bakken, and Woodford shales.

  14. Source of oils in Gulf Coast Cenozoic reservoirs

    SciTech Connect

    Curtis, D.M. )

    1989-09-01

    Many Gulf Coast geologists have assumed that shales interbedded with or adjacent to the reservoir sandstones are source rocks for oils in Cenozoic reservoirs, but few source-rock quality shales have been identified in Cenozoic strata. Reservoirs and their associated shales are in thermally immature and organic-poor intervals. Based on geothermal gradient, age, and depth, it can be shown that thermally mature source rocks should be present in older slope shales beneath each producing trend. Assumptions regarding the source rock potential of the interbedded thermally immature shales derive from the fact that hydrocarbons migrated into traps soon after burial of the reservoir (early migration). Early migration from the source rock was therefore also assumed (shallow burial, early migration model). Review of the geochemical requirements for a source rock shows that geochemical constraints demand late migration from the source rock after many thousands of feet of burial (deep burial, late migration model). Geological and geochemical concepts are compatible, however, if migration out of the source rock was late (long after deposition and deep burial of the source rock) but migration into the reservoir was early (soon after shallow burial of the reservoir and trap system).

  15. RESEARCH OIL RECOVERY MECHANISMS IN HEAVY OIL RESERVOIRS

    SciTech Connect

    Anthony R. Kovscek; William E. Brigham

    1999-06-01

    The United States continues to rely heavily on petroleum fossil fuels as a primary energy source, while domestic reserves dwindle. However, so-called heavy oil (10 to 20{sup o}API) remains an underutilized resource of tremendous potential. Heavy oils are much more viscous than conventional oils. As a result, they are difficult to produce with conventional recovery methods such as pressure depletion and water injection. Thermal recovery is especially important for this class of reservoirs because adding heat, usually via steam injection, generally reduces oil viscosity dramatically. This improves displacement efficiency. The research described here was directed toward improved understanding of thermal and heavy-oil production mechanisms and is categorized into: (1) flow and rock properties; (2) in-situ combustion; (3) additives to improve mobility control; (4) reservoir definition; and (5) support services. The scope of activities extended over a three-year period. Significant work was accomplished in the area of flow properties of steam, water, and oil in consolidated and unconsolidated porous media, transport in fractured porous media, foam generation and flow in homogeneous and heterogeneous porous media, the effects of displacement pattern geometry and mobility ratio on oil recovery, and analytical representation of water influx. Significant results are described.

  16. Reconstruction of sedimentary environments of J2-4 reservoir rocks of the Lovin oil field by facial analysis and 3D simulation

    NASA Astrophysics Data System (ADS)

    Iagudin, R.; Minibaev, N.

    2012-04-01

    The reconstruction of accumulations' conditions of sand bodies and determination of paleogeographical conditions is the basis for 3D modeling of lithologically screened oil and gas reservoirs. The reconstruction of accumulations' conditions is implemented by lithologic-and-facies analysis. The facial types are determined during the analysis of deposits of oil reservoir and then mapped within the reservoir's space. The facies type is an integral characteristic. It is determined on the basis of a large number of research methods such as the processing and analysis of core samples, seismic and well log data. Mapping of reservoirs' facies types allow estimating variability of important for exploration of oil deposits parameters such as reservoir properties, productivity, distribution of effective thickness, etc. The facies types can be mapped as an individual geological unit and used in 3D geological modeling. Subject of facial analysis was sediments of J2-4 reservoir of Lovin oil field (Western Lovin structure) which were accumulated in the Jurassic period. Based on lithologic-and-facies analysis of core material from 6 wells (25 samples), including studies on the grain size measurements, analysis of sediment's structure and core description, the metering of magnetic susceptibility of sediments, facies types of the J2-4 reservoir were identified. The lithotype A is characterized by sand and silt structure, small nodules in the halo of pyrite oxidation, indicated the presence of magnetite. This lithotype belongs to conditions of river-bed facies. The lithotype B have a silty structure, interlayer of coal and traces of bioturbation. This lithotype corresponds to the conditions of sand bars of the floodplain. The lithotype C is characterized by silty-clay structure, single siderite nodules and the remnants of the fauna. This is referring to bog part of the floodplain. After analyzing the well log data of 25 wells of Lovin oil field by Muromtsev methodology distribution

  17. Improved characterization of reservoir behavior by integration of reservoir performances data and rock type distributions

    SciTech Connect

    Davies, D.K.; Vessell, R.K.; Doublet, L.E.

    1997-08-01

    An integrated geological/petrophysical and reservoir engineering study was performed for a large, mature waterflood project (>250 wells, {approximately}80% water cut) at the North Robertson (Clear Fork) Unit, Gaines County, Texas. The primary goal of the study was to develop an integrated reservoir description for {open_quotes}targeted{close_quotes} (economic) 10-acre (4-hectare) infill drilling and future recovery operations in a low permeability, carbonate (dolomite) reservoir. Integration of the results from geological/petrophysical studies and reservoir performance analyses provide a rapid and effective method for developing a comprehensive reservoir description. This reservoir description can be used for reservoir flow simulation, performance prediction, infill targeting, waterflood management, and for optimizing well developments (patterns, completions, and stimulations). The following analyses were performed as part of this study: (1) Geological/petrophysical analyses: (core and well log data) - {open_quotes}Rock typing{close_quotes} based on qualitative and quantitative visualization of pore-scale features. Reservoir layering based on {open_quotes}rock typing {close_quotes} and hydraulic flow units. Development of a {open_quotes}core-log{close_quotes} model to estimate permeability using porosity and other properties derived from well logs. The core-log model is based on {open_quotes}rock types.{close_quotes} (2) Engineering analyses: (production and injection history, well tests) Material balance decline type curve analyses to estimate total reservoir volume, formation flow characteristics (flow capacity, skin factor, and fracture half-length), and indications of well/boundary interference. Estimated ultimate recovery analyses to yield movable oil (or injectable water) volumes, as well as indications of well and boundary interference.

  18. Characterizing a Mississippian Carbonate Reservoir for CO2-EOR and Carbon Geosequestration: Applicability of Existing Rock Physics Models and Implications to Feasibility of a Time Lapse Monitoring Program in the Wellington Oil Field, Sumner County, Kansas.

    NASA Astrophysics Data System (ADS)

    Lueck, A. J.; Raef, A. E.

    2015-12-01

    This study will focus on characterizing subsurface rock formations of the Wellington Field, in Sumner County, Kansas, for both geosequestration of carbon dioxide (CO2) in the saline Arbuckle formation and enhanced oil recovery of a depleting Mississippian oil reservoir. Multi-scale data including lithofacies core samples, X-ray diffraction, digital rock physics scans, scanning electron microscope (SEM) imaging, well log data including sonic and dipole sonic, and surface 3D seismic reflection data will be integrated to establish and/or validate a new or existing rock physics model that best represents our reservoir rock types and characteristics. We will acquire compressional wave velocity and shear wave velocity data from Mississippian and Arbuckle cores by running ultrasonic tests using an Ult 100 Ultrasonic System and a 12 ton hydraulic jack located in the geophysics lab in Thompson Hall at Kansas State University. The elastic constants Young's Modulus, Bulk Modulus, Shear (Rigidity) Modulus and Poisson's Ratio will be extracted from these velocity data. Ultrasonic velocities will also be compared to sonic and dipole sonic log data from the Wellington 1-32 well. These data will be integrated to validate a lithofacies classification statistical model, which will be and partially has been applied to the largely unknown saline Arbuckle formation, with hopes for a connection, perhaps via Poisson's ratio, allowing a time-lapse seismic feasibility assessment and potentially developing a transformation of compressional wave sonic velocities to shear wave sonic for all wells, where compressional wave sonic is available. We will also be testing our rock physics model by predicting effects of changing effective (brine + CO2 +hydrocarbon) fluid composition on seismic properties and the implications on feasibility of seismic monitoring. Lessons learned from characterizing the Mississippian are essential to understanding the potential of utilizing similar workflows for the

  19. Next generation oil reservoir simulations

    SciTech Connect

    Joubert, W.

    1996-04-01

    This paper describes a collaborative effort between Amoco Production Company, Los Alamos National Laboratory and Cray Research Inc. to develop a next-generation massively parallel oil reservoir simulation code. The simulator, code-named Falcon, enables highly detailed simulations to be performed on a range of platforms such as the Cray T3D and T3E. The code is currently being used by Amoco to perform a sophisticated field study using multiple geostatistical realizations on a scale of 2-5 million grid blocks and 1000-2000 wells. In this paper we discuss the nature of this collaborative effort, the software design and engineering aspects of the code, parallelization experiences, and performance studies. The code will be marketed to the oil industry by a third-party independent software vendor in mid-1996.

  20. Electromagnetic Heating Methods for Heavy Oil Reservoirs

    SciTech Connect

    Sahni, A.; Kumar, M.; Knapp, R.B.

    2000-05-01

    The most widely used method of thermal oil recovery is by injecting steam into the reservoir. A well-designed steam injection project is very efficient in recovering oil, however its applicability is limited in many situations. Simulation studies and field experience has shown that for low injectivity reservoirs, small thickness of the oil-bearing zone, and reservoir heterogeneity limits the performance of steam injection. This paper discusses alternative methods of transferring heat to heavy oil reservoirs, based on electromagnetic energy. They present a detailed analysis of low frequency electric resistive (ohmic) heating and higher frequency electromagnetic heating (radio and microwave frequency). They show the applicability of electromagnetic heating in two example reservoirs. The first reservoir model has thin sand zones separated by impermeable shale layers, and very viscous oil. They model preheating the reservoir with low frequency current using two horizontal electrodes, before injecting steam. The second reservoir model has very low permeability and moderately viscous oil. In this case they use a high frequency microwave antenna located near the producing well as the heat source. Simulation results presented in this paper show that in some cases, electromagnetic heating may be a good alternative to steam injection or maybe used in combination with steam to improve heavy oil production. They identify the parameters which are critical in electromagnetic heating. They also discuss past field applications of electromagnetic heating including technical challenges and limitations.

  1. Seismic attenuation anisotropy in reservoir sedimentary rocks

    SciTech Connect

    Best, A.I.

    1994-12-31

    Seismic attenuation is a fundamental property of reservoir sedimentary rocks; it is strongly related to reservoir permeability. Knowledge of its variation with lithology, with burial depth, and with wave propagation direction is vital for understanding the attenuation mechanism. Given this information, realistic theoretical models may be constructed for predicting attenuation, and hence permeability, over a wide frequency range. Accurate ultrasonic attenuation measurements were made in the laboratory over a range of effective pressures on sandstone samples with different amounts of humic organic matter. The organic matter formed fine laminations along the bedding planes of the sandstones. The results show that the sandstones are highly attenuating at 5 MPa mainly because of the presence of grain contact microcracks giving rise to squirt flow; at 40 MPa, when most of the microcracks are closed, the clean sandstones are poorly attenuating, but the organic-rich sandstones remain highly attenuating. It is postulated that the compliant organic matter is responsible for causing squirt flow at high and at low pressures. The results also show that the maximum attenuation occurs when the particle motion of the propagating wave is perpendicular to the planes of the organic matter laminations. These results are consistent with the squirt flow theory of Akbar et al (1993) for compressional waves.

  2. Profiles of Reservoir Properties of Oil-Bearing Plays for Selected Petroleum Provinces in the United States

    USGS Publications Warehouse

    Freeman, P.A.; Attanasi, E.D.

    2016-01-01

    Each province profile figure consists of five strip charts and a boxplot. The five strip charts display for individual plays the following reservoir-fluid and reservoir properties: A, oil density (American Petroleum Institute [API] gravity in degrees); B, computed pseudo-Dykstra-Parsons coefficient; C, reservoir porosity (in percent); D, reservoir permeability (in millidarcies); and E, estimates of the original oil in place (OOIP) per unit volume of reservoir rock (in barrels per acre-foot). The OOIP per unit volume of reservoir rock is an indicator of the relative richness of the oil reservoir and is derived from estimates in the CRD of OOIP, reservoir acreage, and net pay. The net pay is the interval of productive reservoir rock. The same data for OOIP per unit volume are graphed as a strip chart (E) and a boxplot (F).

  3. Oil and gas in carbonate rocks of the CIS basins

    SciTech Connect

    Kuznetsov, V. )

    1993-09-01

    In petroleum basins of the Commonwealth of Independent States (CIS), oil and gas fields in carbonate reservoirs have been discovered in rocks ranging from the Riphean to the Eocene. Most fields are found in cratonic carbonate formations deposited under arid climatic conditions. Regional seals are formed by salt, anhydrite, and dolomicrite. Multilayer reservoirs predominate, but massive reservoirs are common also. The distribution of reservoir types and their quality are strongly uneven. Many fields, including giant fields, are controlled by reefs. Depending on the paleoclimatic zone, the seals are composed of salt or, rarely, of shale. Massive reservoirs predominate, but the distribution of porosity and localization of zones of improved reservoir properties are variable and controlled by the morphogenetic types of the reefs. Carbonate formations deposited under humid climatic conditions contain much less hydrocarbon reserves. The seals are generally composed of shale. The reservoirs are stratal, rarely multilayer, and the fields are usually small. A number of fields, some of them highly productive, are present in Upper Cretaceous carbonate rocks of the North Caucasus region. The carbonates consist of the remains of planktonic organisms. Seals for the hydrocarbon pool are composed of shale. The reservoirs are massive and layered-massive. Fractures and stylolites play a leading role in controlling the reservoir properties.

  4. Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. Appendix 1, Volume 2

    SciTech Connect

    Kopaska-Merkel, D.C.; Moore, H.E. Jr.; Mann, S.D.; Hall, D.R.

    1992-06-01

    This volume contains maps, well logging correlated to porosity and permeability, structural cross section, graph of production history, porosity vs. natural log permeability plots, detailed core log, paragenetic sequence, and reservoir characterization sheet for the following fields in southwest Alabama: East Huxford oil field; Fanny Church oil field; Gin Creek oil field; Gulf Crest oil field; Hanberry Church oil field; Hatter`s Pond oil field; Healing Springs gas condensate field; Huxford oil field; Little Escambia Creek oil field; Little River oil field; Little Rock gas condensate field; Lovetts Creek oil field; Melvin oil field; Mill Creek oil field; Mineola oil field; Movico oil field; and North Choctaw Ridge oil field.

  5. Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. [Jurassic Smackover Formation

    SciTech Connect

    Kopaska-Merkel, D.C.; Moore, H.E. Jr.; Mann, S.D.; Hall, D.R.

    1992-06-01

    This volume contains maps, well logging correlated to porosity and permeability, structural cross section, graph of production history, porosity vs. natural log permeability plots, detailed core log, paragenetic sequence, and reservoir characterization sheet for the following fields in southwest Alabama: East Huxford oil field; Fanny Church oil field; Gin Creek oil field; Gulf Crest oil field; Hanberry Church oil field; Hatter's Pond oil field; Healing Springs gas condensate field; Huxford oil field; Little Escambia Creek oil field; Little River oil field; Little Rock gas condensate field; Lovetts Creek oil field; Melvin oil field; Mill Creek oil field; Mineola oil field; Movico oil field; and North Choctaw Ridge oil field.

  6. Biological souring and mitigation in oil reservoirs.

    PubMed

    Gieg, Lisa M; Jack, Tom R; Foght, Julia M

    2011-10-01

    Souring in oil field systems is most commonly due to the action of sulfate-reducing prokaryotes, a diverse group of anaerobic microorganisms that respire sulfate and produce sulfide (the key souring agent) while oxidizing diverse electron donors. Such biological sulfide production is a detrimental, widespread phenomenon in the petroleum industry, occurring within oil reservoirs or in topside processing facilities, under low- and high-temperature conditions, and in onshore or offshore operations. Sulfate reducers can exist either indigenously in deep subsurface reservoirs or can be "inoculated" into a reservoir system during oil field development (e.g., via drilling operations) or during the oil production phase. In the latter, souring most commonly occurs during water flooding, a secondary recovery strategy wherein water is injected to re-pressurize the reservoir and sweep the oil towards production wells to extend the production life of an oil field. The water source and type of production operation can provide multiple components such as sulfate, labile carbon sources, and sulfate-reducing communities that influence whether oil field souring occurs. Souring can be controlled by biocides, which can non-specifically suppress microbial populations, and by the addition of nitrate (and/or nitrite) that directly impacts the sulfate-reducing population by numerous competitive or inhibitory mechanisms. In this review, we report on the diversity of sulfate reducers associated with oil reservoirs, approaches for determining their presence and effects, the factors that control souring, and the approaches (along with the current understanding of their underlying mechanisms) that may be used to successfully mitigate souring in low-temperature and high-temperature oil field operations. PMID:21858492

  7. Paleozoic source and reservoir rocks in unbreached thrust ramp anticlines, Millard County, Utah

    SciTech Connect

    Garrison, P.B.; Larsen, B.R. )

    1991-03-01

    Surface geology, source rock geochemistry, and seismic data indicate that substantial hydrocarbon reserves may occur beneath a regional detachment fault underlying Tule Valley and the Confusion Range in northern Millard County, west-central Utah. Paleozoic hydrocarbon source and reservoir rocks in Millard County are laterally equivalent to highly productive rocks in Railroad Valley, Nevada, oil fields. However, the volume of hydrocarbons trapped in thrust ramp duplex anticlines beneath a regional detachment fault is potentially much greater than that in established Nevada fields. The Devonian Guilmette Formation, which consists of interstratified brown, sucrosic dolomite and gray limestone, and the Mississippian Chainman Shale are exposed in the folded and thrusted Confusion Range. Regional geochemical analysis confirms that the Chainman Shale contains enough total organic carbon (TOC) to serve as an effective hydrocarbon source rock. Some surface samples exceed 3% TOC; average TOC is in excess of 1.5%. Thermal maturity of these source rock surface samples indicates that these rocks were subjected to deep burial during their geologic history and that they have generated the maximum amount of hydrocarbons. In addition, thermal maturity of these samples is consistent with hydrocarbon preservation at the 'floor' of the oil window and within the area of peak wet gas generation. Petrographic examination of potential reservoir facies in the Guilmette Formation confirms that liquid hydrocarbons were contained in porous, permeable dolomite. Petrographic examination of kerogen from these same facies also confirms the presence of solid bitumen (dead oil) in the surface samples.

  8. Use of ``rock-typing`` to characterize carbonate reservoir heterogeneity. Final report

    SciTech Connect

    Ikwuakor, K.C.

    1994-03-01

    The objective of the project was to apply techniques of ``rock-typing`` and quantitative formation evaluation to borehole measurements in order to identify reservoir and non-reservoir rock-types and their properties within the ``C`` zone of the Ordovician Red River carbonates in the northeast Montana and northwest North Dakota areas of the Williston Basin. Rock-typing discriminates rock units according to their pore-size distribution. Formation evaluation estimates porosities and pore fluid saturation. Rock-types were discriminated using crossplots involving three rock-typing criteria: (1) linear relationship between bulk density and porosity, (2) linear relationship between acoustic interval transit-time and porosity, and (3) linear relationship between acoustic interval transit-time and bulk density. Each rock-type was quantitatively characterized by the slopes and intercepts established for different crossplots involving the above variables, as well as porosities and fluid saturations associated with the rock-types. All the existing production was confirmed through quantitative formation evaluation. Highly porous dolomites and anhydritic dolomites contribute most of the production, and constitute the best reservoir rock-types. The results of this study can be applied in field development and in-fill drilling. Potential targets would be areas of porosity pinchouts and those areas where highly porous zones are downdip from non-porous and tight dolomites. Such areas are abundant. In order to model reservoirs for enhanced oil recovery (EOR) operations, a more localized (e.g. field scale) study, expanded to involve other rock-typing criteria, is necessary.

  9. Characterization of oil and gas reservoir heterogeneity

    SciTech Connect

    Tyler, N.; Barton, M.D.; Bebout, D.G.; Fisher, R.S.; Grigsby, J.D.; Guevara, E.; Holtz, M.; Kerans, C.; Nance, H.S.; Levey, R.A.

    1992-10-01

    Research described In this report addresses the internal architecture of two specific reservoir types: restricted-platform carbonates and fluvial-deltaic sandstones. Together, these two reservoir types contain more than two-thirds of the unrecovered mobile oil remaining ill Texas. The approach followed in this study was to develop a strong understanding of the styles of heterogeneity of these reservoir types based on a detailed outcrop description and a translation of these findings into optimized recovery strategies in select subsurface analogs. Research targeted Grayburg Formation restricted-platform carbonate outcrops along the Algerita Escarpment and In Stone Canyon In southeastern New Mexico and Ferron deltaic sandstones in central Utah as analogs for the North Foster (Grayburg) and Lake Creek (Wilcox) units, respectively. In both settings, sequence-stratigraphic style profoundly influenced between-well architectural fabric and permeability structure. It is concluded that reservoirs of different depositional origins can therefore be categorized Into a heterogeneity matrix'' based on varying intensity of vertical and lateral heterogeneity. The utility of the matrix is that it allows prediction of the nature and location of remaining mobile oil. Highly stratified reservoirs such as the Grayburg, for example, will contain a large proportion of vertically bypassed oil; thus, an appropriate recovery strategy will be waterflood optimization and profile modification. Laterally heterogeneous reservoirs such as deltaic distributary systems would benefit from targeted infill drilling (possibly with horizontal wells) and improved areal sweep efficiency. Potential for advanced recovery of remaining mobile oil through heterogeneity-based advanced secondary recovery strategies In Texas is projected to be an Incremental 16 Bbbl. In the Lower 48 States this target may be as much as 45 Bbbl at low to moderate oil prices over the near- to mid-term.

  10. Research on improved and enhanced oil recovery in Illinois through reservoir characterization

    SciTech Connect

    Oltz, D.F.

    1992-01-01

    This project will provide information that can maximize hydrocarbon production minimize formation damage and stimulate new production in Illinois. Such information includes definition of hydrocarbon resources, characterization of hydrocarbon reservoirs, and the implementation of methods that will improve hydrocarbon extractive technology. Increased understanding of reservoir heterogeneities that affect oil recovery can aid in identifying producible resources. The transfer of technology to industry and the general public is a significant component of the program. The project is designed to examine selected subsurface oil reservoirs in Illinois. Scientists use advanced scientific techniques to gain a better understanding of reservoir components and behavior and address ways of potentially increasing the amount of recoverable oil. Initial production rates for wells in the Illinois Basin commonly decline quite rapidly and as much as 60 percent of the oil in place can be unrecoverable using standard operating procedures. Heterogeneities (geological differences in reservoir make-up) affect a reservoir's capability to release fluids. By-passed mobile and immobile oil remain in the reservoir. To learn how to get more of the oil out of reservoirs, the ISGS is studying the nature of reservoir rock heterogeneities and their control on the distribution and production of by-passed, mobile oil.

  11. Reservoir characterization and enhanced oil recovery research

    SciTech Connect

    Lake, L.W.; Pope, G.A.; Schechter, R.S.

    1992-03-01

    The research in this annual report falls into three tasks each dealing with a different aspect of enhanced oil recovery. The first task strives to develop procedures for accurately modeling reservoirs for use as input to numerical simulation flow models. This action describes how we have used a detail characterization of an outcrop to provide insights into what features are important to fluid flow modeling. The second task deals with scaling-up and modeling chemical and solvent EOR processes. In a sense this task is the natural extension of task 1 and, in fact, one of the subtasks uses many of the same statistical procedures for insight into the effects of viscous fingering and heterogeneity. The final task involves surfactants and their interactions with carbon dioxide and reservoir minerals. This research deals primarily with phenomena observed when aqueous surfactant solutions are injected into oil reservoirs.

  12. Hot dry rock fracture propagation and reservoir characterization

    SciTech Connect

    Murphy, H.; Fehler, M.; Robinson, B.; Tester, J.; Potter, R.; Birdsell, S.

    1988-01-01

    North America's largest hydraulic fracturing opeations have been conducted at Fenton hill, New mexico to creae hot dry rock geothermal reservoirs. Microearthquakes induced by these fracturing operations were measured with geophones. The large volume of rock over which the microearthquakes were distributed indicates a mechanism of hydraulic stimulation which is at odds with conventional fracturing theory, which predicts failure along a plane which is perpendicular to the least compressive earth stress. Shear slippage along pre-existing joints in the rock is more easily induced than conventional tensile failure, particularly when the difference between minimum and maximum earth stresses is large and the pre-existing joints are oriented at angles between 30 and 60)degree) to the principal earth stresses, and a low viscosity fluid like water is injected. Shear slippage results in local redistribution of stresses, which allows a branching, or dendritic, stimulation pattern to evolve, in agreement with the patterns of microearthquake locations. Field testing of HDR reservoirs at the Fenton Hill site shows that significant reservoir growth occurred as energy was extracted. Tracer, microseismic, and geochemical measurements provided the primary quantitative evidence for the increases in accessible reservoir volume and fractured rock surface area. These temporal increases indicate that augmentation of reservoir heat production capacity in hot dry rock system occurred. For future reservoir testing, Los Alamos is developing tracer techniques using reactive chemicals to track thermal fronts. Recent studies have focused on the kinetics of hydrolysis of derivatives of bromobenzene, which can be used in reservoirs as hot as 275)degree)C.

  13. Origin of crude oil in eastern Gulf Coast: Upper Jurassic, Upper Cretaceous, and lower Tertiary source rocks

    SciTech Connect

    Sassen, R.

    1988-02-01

    Analysis of rock and crude oil samples suggests that three source rocks have given rise to most crude oil in reservoirs of the eastern Gulf Coast. Carbonate source rocks of the Jurassic Smackover Formation are characterized by algal-derived kerogen preserved in an anoxic and hypersaline environment, resulting in crude oils with distinct compositions. Migration commenced during the Cretaceous, explaining the emplacement of Smackover-derived crude oil in Jurassic and in some Cretaceous reservoirs. Upper Cretaceous clastic and carbonate source rocks are also present. Much crude oil in Upper Cretaceous reservoirs has been derived from organic-rich marine shales of the Tuscaloosa Formation. These shales are characterized by algal and higher plant kerogen, resulting in distinct crude oil compositions. Migration commenced during the Tertiary, but was mostly focused to Upper Cretaceous reservoirs. Lower Tertiary shales, including those of the Wilcox Formation, are quite organic-rich and include downdip marine facies characterized by both algal and higher plant kerogen. Crude oils in lower Tertiary reservoirs are dissimilar to crude oils from deeper and older source rocks. Migration from lower Tertiary shales commenced during the late Tertiary and charged Tertiary reservoirs. Although most crude oil in the eastern Gulf Coast has been emplaced by short-range migration, often with a strong vertical component, some long-range lateral migration (> 100 km) has occurred along lower Tertiary sands. The framework of crude oil generation and migration onshore has important implications with respect to origin of crude oil in the Gulf of Mexico.

  14. Recovery of heavy oils from deep reservoirs

    SciTech Connect

    Stoller, H. M.; Fox, R. L.

    1980-01-01

    The objective of Project DEEP STEAM is to develop the technology required to economically produce heavy oil from deep reservoirs. Two approaches are being pursued: improving the thermal efficiency of injection string components and the development of downhole steam generators to achieve steam injection. The first approach has seen the testing of commercially available components at a high temperature (650/sup 0/F)/high pressure (2100 psi) simulation facility. Promising components will be tested shortly in a field test conducted by Husky Oil at Lloydminster, Canada. The second approach has seen the prototype development and laboratory testing of low-pressure and high-pressure hydrocarbon-fueled downhole steam generators. Concurrently, a modified high pressure steam generator has undergone extensive laboratory combustion studies and is currently being employed in a field test at Chevron's Kern River field. This field test is examining the effects of simultaneous injection of steam and combustion products on the reservoir and oil recovery. 9 figures.

  15. Bacterial community diversity in a low-permeability oil reservoir and its potential for enhancing oil recovery.

    PubMed

    Xiao, Meng; Zhang, Zhong-Zhi; Wang, Jing-Xiu; Zhang, Guang-Qing; Luo, Yi-Jing; Song, Zhao-Zheng; Zhang, Ji-Yuan

    2013-11-01

    The diversity of indigenous bacterial community and the functional species in the water samples from three production wells of a low permeability oil reservoir was investigated by high-throughput sequencing technology. The potential of application of indigenous bacteria for enhancing oil recovery was evaluated by examination of the effect of bacterial stimulation on the formation water-oil-rock surface interactions and micromodel test. The results showed that production well 88-122 had the most diverse bacterial community and functional species. The broth of indigenous bacteria stimulated by an organic nutrient activator at aerobic condition changed the wettability of the rock surface from oil-wet to water-wet. Micromodel test results showed that flooding using stimulated indigenous bacteria following water flooding improved oil recovery by 6.9% and 7.7% in fractured and unfractured micromodels, respectively. Therefore, the zone of low permeability reservoir has a great potential for indigenous microbial enhanced oil recovery. PMID:23994957

  16. Super viscous oil reservoir formations of Ufa unit of Republic of Tatarstan and their properties

    NASA Astrophysics Data System (ADS)

    Osipova, D.; Vafin, R.; Surmashev, R.; Bondareva, O.

    2012-04-01

    Over 450 concentrations of super viscous oils (SVO) were discovered in Tatarstan for the time being. All of them are related to productive deposits of Permian period occurred at depths up to 300-400 metres consisting of terrigenous and carbonate deposits. Described are reservoir formations of the fields where recoverable reserves of SVO are confined by argillo-arenaceous thickness of Ufa terrigenous unit. Studying reservoir properties was based on laboratory analysis of core samples in terms of: Macro- and microscopic description, grain-size analysis, determination of effective porosity, permeability, volumetric and weight oil saturation, carbonate content, mineralogical density. According to macro-analysis data, thickness cross-section presents sandstones with rare interlayer and lenticle of siltstones and clays. The colour of calcareous sandstones varies from grey to black. Incoherent rocks prevail while closely consolidated types are rarely observed. The grain-size analysis revealed that 0.25-0.1 mm size grains are dominated in the sandstone composition, their concentration in rocks amounts to 69% that enables belonging oil rocks to fine-grained sandstones. Reservoir properties of rocks widely vary as follows: Effective porosity varies from 2.4 to 44.5% (average 31.5%), carbonate content from 0.6 to 30.1% (average 6.7%), mineralogical density from 2.3 to 3.3% (average 2.7%), and oil saturation from 0.1 to 14.9 rock weight % (average 7.8%). Reservoir porosities of reservoirs correlate to each other. Correlations between porosities are set in logarithmic values. Good direct correlation dependence (coefficient of correlation 0.5352) was identified between porosity and permeability as well as clear inverse relation between carbonate content and porosity (coefficient of correlation = - 0.7659). More tight positive correlation is observed for Porosity - Mass oil saturation (coefficient of correlation 0. 75087). This correlation indicates that super viscous oils are

  17. Physics of oil entrapment in water-wet rock

    SciTech Connect

    Mohanty, K.K.; Davis, H.T.; Scriven, L.E.

    1987-02-01

    Displacement of oil from an initially oil-filled porous rock by water consists of advancement of menisci and rupture of oil connections. In displacements controlled by capillarity, which are typical of oil reservoir floods, these pore-level events are governed by the local pore geometry, pore topology, and fluid properties, but the pressure field initiates these pore-level events and integrates them with the externally imposed Darcy flow. This paper reports the physics of the pore-level and their integration on a computationally simple model of rock: a square network of pores. The novelty of the approach lies in keeping track of the evolution of the displacement front and in constructing an approximation of the entire pressure field that carries the information essential for predicting the evolution. The result gives insight into the state of the residual oil saturation and its dependence on pore geometry and the capillary number, N/sub ca/, of displacement. As the capillary number increases, the residual oil saturation decreases and the residual oil blobs tend to be smaller. As the pore size distribution becomes wider, the decrease of residual oil saturation with capillary number becomes smoother.

  18. Numerical Calculation of Permeability and Electrical Formation Factor from AN Oil Reservoir Rock Using Geometry Obtained from Synchrotron X-Ray Computed Microtomography

    NASA Astrophysics Data System (ADS)

    Butler, S. L.; Bird, M.; Hawkes, C.; Kotzer, T.

    2013-12-01

    Advanced imaging techniques and computational modeling are being used increasingly to investigate the transport characteristics of porous rocks. In this contribution, we describe modeling of fluid and electrical flow through the interstices of two rock samples from the Weyburn oilfield in Southwestern Saskatchewan, Canada, using commercially available software. Samples of Marley Dolostone and Vuggy Limestone were imaged at resolutions of 0.78 μm and 7.45 μm, respectively, using synchrotron X-ray tomography. The porosity, permeability and electrical formation factor of similar samples were measured in the laboratory. The connected pore space of the rock sample was extracted and converted to a standard CAD file representation using commercial software. This CAD file was then imported into a commercial finite-element modeling software package where the pore space was meshed and the Navier-Stokes equations and Laplace's equation describing fluid and electrical flows were solved with appropriate boundary conditions. An example solution of the fluid flow field is shown in figure 1. Streamlines follow the direction of fluid flow while colors indicate the magnitude of the velocity. Calculation of the fluxes in post-processing allowed us to determine the permeability and electrical formation factors which were similar to those found experimentally and fell on the same porosity-permeability and Archie's Law trends. Fluid flow through a 50 micron per side cubic sub-sample of a Marley Dolostone. The pressure gradient is applied vertically. Streamlines indicate the direction of fluid flow. Colors indicate the magnitude of flow velocity.

  19. Characterization of oil and gas reservoir heterogeneity

    SciTech Connect

    Not Available

    1991-01-01

    The objective of the cooperative research program is to characterize Alaskan reservoirs in terms of their reserves, physical and chemical properties, geologic configuration and structure, and the development potential. The tasks completed during this period include: (1) geologic reservoir description of Endicott Field; (2) petrographic characterization of core samples taken from selected stratigraphic horizons of the West Sak and Ugnu (Brookian) wells; (3) development of a polydispersed thermodynamic model for predicting asphaltene equilibria and asphaltene precipitation from crude oil-solvent mixtures, and (4) preliminary geologic description of the Milne Point Unit.

  20. Geochemical relationships of petroleum in Mesozoic reservoirs to carbonate source rocks of Jurassic Smackover Formation, southwestern Alabama

    SciTech Connect

    Claypool, G.E.; Mancini, E.A.

    1989-07-01

    Algal carbonate mudstones of the Jurassic Smackover Formation are the main source rocks for oil and condensate in Mesozoic reservoir rocks in southwestern Alabama. This interpretation is based on geochemical analyses of oils, condensates, and organic matter in selected samples of shale (Norphlet Formation, Haynesville Formation, Trinity Group, Tuscaloosa Group) and carbonate (Smackover Formation) rocks. Potential and probable oil source rocks are present in the Tuscaloosa Group and Smackover Formation, respectively. Extractable organic matter from Smackover carbonates has molecular and isotopic similarities to Jurassic oil. Although the Jurassic oils and condensates in southwestern Alabama have genetic similarities, they show significant compositional variations due to differences in thermal maturity and organic facies/lithofacies. Organic facies reflect different depositional conditions for source rocks in the various basins. The Mississippi Interior Salt basin was characterized by more continuous marine to hypersaline conditions, whereas the Manila and Conecuh embayments periodically had lower salnity and greater input of clastic debris and terrestrial organic matter. Petroleum and organic matter in Jurassic rocks of southwestern Alabama show a range of thermal transformations. The gas content of hydrocarbons in reservoirs increases with increasing depth and temperature. In some reservoirs where the temperature is above 266/degrees/F(130/degrees/C), gas-condensate is enriched in isotopically heavy sulfur, apparently derived from thermochemical reduction of Jurassic evaporite sulfate. This process also resulted in increase H/sub 2/S and CO in the gas, and depletion of saturated hydrocarbons in the condensate liquids.

  1. Strength measurements of The Geysers reservoir rock

    SciTech Connect

    Lockner, D.A.; Byerlee, J.D.

    1980-09-01

    Rock samples taken from two outcrops and cores from well bores at the Geysers geothermal field were tested at temperatures and pressures similar to those found in the field. Both intact cylinders and cylinders containing 30/sup 0/ sawcuts were deformed at confining pressures of 200 to 1000 bars, pore pressure of 30 bars, and temperatures of 150 to 250/sup 0/C. Constant strain rate tests gave a coefficient of friction of 0.68. Friction was independent of rock type, temperature and strain rate. Most cores taken from the producing zone were highly fractured. For this reason, intact samples were rarely 50% stronger than the frictional strength. At 500 bars confining pressure, P wave velocity of 6.2 km/sec was measured for a sample taken from an outcrop. Porosities and permeabilities were also measured.

  2. Research on Oil Recovery Mechanisms in Heavy Oil Reservoirs

    SciTech Connect

    Louis M. Castanier; William E. Brigham

    1998-03-31

    The goal of this project is to increase recovery of heavy oils. Towards that goal studies are being conducted in how to assess the influence of temperature and pressure on the absolute and relative permeability to oil and water and on capillary pressure; to evaluate the effect of different reservoir parameters on the in site combustion process; to develop and understand mechanisms of surfactants on for the reduction of gravity override and channeling of steam; and to improve techniques of formation evaluation.

  3. Using a hot dry rock geothermal reservoir for load following

    SciTech Connect

    Brown, D.W.; Duteau, R.J.

    1995-01-01

    Field measurements and modeling have shown the potential for using a Hot Dry Rock (HDR) geothermal reservoir for electric load following: either with Power-Peaking from a base-load operating condition, or for Pumped Storage of off-peak electric energy with a very significant thermal augmentation of the stored mechanical energy during periods of power production. For the base-load with power- peaking mode of operation, and HDR reservoir appears capable of producing over twice its nominal power output for short -- 2 to 4 hour -- periods of time. In this mode of operation, the reservoir normally would be produced under a high-backpressure condition with the HDR reservoir region near the production well highly inflated. Upon demand, the production backpressure would be sharply reduced, surging the production flow. The analytical tool used in these investigations has been the transient finite element model of the an HDR reservoir called GEOCRACK, which is being developed by Professor Dan Swenson and his students at Kansas State University. This discrete-element representation of a jointed rock mass has recently been validated for transient operations using the set of cyclic reservoir operating data obtained at the end of the LTFT.

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

    USGS Publications Warehouse

    Pitman, J.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

  5. Patterns of changes in oil properties in complex constructions for carbonate reservoirs

    NASA Astrophysics Data System (ADS)

    Morozov, Vladimir P.; Plotnikova, Irina N.; Nosova, Fidania F.; Pronin, Nikita V.; Nosova, Julia G.

    2014-05-01

    The objects of this research are carbonate reservoirs with non-uniform lithology and filtration-volumetric parameters. The oil under study is heavy ( 0.924 g/cm3). Our research methods include the following: studying of filtration-volumetric parameters in rock samples, performing the thermal and geochemical studies of fluids . Thermal and geochemical studies performed on core samples and on fluids extracted from sediments of Bashkirian sub-panel of a 1985 well in Akansky field showed that oil properties (namely its group composition) are not constant and uniform throughout the deposit but depend on the structure of the pore space, on the porosity, and the size of pore channels. In particular, we found out that oil that saturates large pores and cavities contains less oil fractions and more resins and asphaltenes. The fine pores of the rock matrix are saturated with lighter petroleum hydrocarbons, which predominantly have oils while the percentage of asphaltenes decreases. These patterns can be explained by the process of chromatography (separation) of oil during its migration and filtration through some porous environments while filling up the collector and forming deposits. Assuming that petroleum is a colloidal solution where light hydrocarbons serve as solvents, and resin- asphaltene colloidal particles are the dissolved part, the process of filling the pores can be represented as follows. Under the influence of external forces and as a result of spreading in a porous environment, oil, when entering the collector, is subjected chromatography - the lightest and easily movable hydrocarbons (solvents) penetrate into finer pore channels (including the thinnest pores and micro cracks of the rock matrix), while the resinous asphaltene part dissolved in oil remains in the large pores and cavities. Thus, the distribution of oil in carbonate reservoir of Bashkirian sub-panel is as follows: rock matrix and its low porosity layers are filled with lighter oil, while heavier

  6. Rock characterization in reservoirs targeted for horizontal drilling

    SciTech Connect

    Skopec, R.A. )

    1993-12-01

    Achieving the maximum economic benefit from horizontal drilling requires thorough understanding of reservoir characteristics. The direct measurement of rock properties from oriented core is critical in horizontal-wellbore design. This paper outlines the measures and testing necessary to evaluate naturally fractured reservoirs effectively with field and laboratory technologies. Rock mechanical properties, fracture strike, and principal in-situ stress magnitudes and directions should be known before a horizontal wellbore is drilled. These data can then be used to maximize the intersection of natural fractures and to minimize the potential of borehole failure. In exploration wells, a vertical pilot hole must first be drilled. The zone of interest is cored, field tests are performed, laboratory testing is completed, and the reservoir is evaluated. With this information available, decisions can be made to optimize the borehole azimuth and well placement. The authors have used this approach to formation evaluation in several reservoirs where rock characterization is essential in the exploration and drilling program. 72 refs., 10 figs.

  7. Uncertainty quantification in fractured reservoir by considering geological deformation of reservoir and geomechanical accommodation of rocks

    NASA Astrophysics Data System (ADS)

    Shin, Y.; Jung, A.; Mukerji, T.

    2013-12-01

    Geological interpretations on structural deformation of a reservoir are uncertain. How the reservoir rocks have accommodated the deformational loading is also uncertain. The effects of these two on reservoir property modeling and uncertainty of reservoir responses is rarely investigated and used in reservoir forecasting. In this research, the effect of different scenarios on geological deformation history and modes of accommodation of rock deformation on reservoir flow response is investigated. To do that, we develop a geostatistical reservoir property modeling workflow which allows us to generate petrophysical properties (porosity & permeability) such that the properties are consistent with geological deformation. In this workflow, we restore the values of petrophysical properties from hard data into a restored condition using predefined transfer functions. We conduct geostatistical simulations to populate petrophysical properties using the restored property values in a restored grid. By using the inverse relation used to restore petrophysical values of hard data, we deform the simulated property values into a deformed grid with corresponding deformed values. Fracture sets are populated by considering both the populated petrophysical properties in a restored grid and the geomechanical condition derived from the deformation-restoration constraints. By using this workflow, we can compare and distinguish the effects of different modes of geological deformation on the uncertainty of reservoir flow responses. The uncertainty from different modes of accommodation is considered in the workflow by having different transfer relations when conducting restoration-deformation of the values of petrophysical properties. The proposed workflow is applied on a 3D synthetic fractured sandstone reservoir to see the impact on flow responses. Reservoir models from different scenario of deformation and the modes of accommodation for each deformation produce different characteristics on

  8. Depositional features and source and reservoir rocks of Tertiary age in northern part of South China Sea

    SciTech Connect

    Wang, S.

    1986-07-01

    The northern part of the South China Sea covers an area of about 400,000 km/sup 2/. Tertiary deposits more than 10,000 m in thickness are widely distributed there. The area has sedimentary rocks more than 1000 m thick covers more than 300,000 km/sup 2/. Five sedimentary basins have been established in this area: Beibu Bay, Yinggehai, Southeastern Qiong, Pearl River Mouth, and Southwestern Taiwann basins. The primary source and reservoir rocks for oil and gas prospects are of Tertiary age. Tertiary rocks underwent three stages of development, each forming a specific sedimentation system: (1) a system of fluviolacustrine deposits in rift depressions from the Paleocene to early Oligocene; (2) a system of semiclosed-sea deposits from the late Oligocene to early Miocene; and (3) a system of deltaic open-sea deposits from the middle Miocene to Pliocene. These three sedimentation systems resulted in three suites of source rocks, three suites of reservoir rocks, and three groups of independent oil pools, complete with source, reservoir, and cap rocks. The three suites of source rocks are as follows: (1) the Eocene Liushagang Formation in the Beibu Bay basin, which is believed to be the best source rock discovered in the area; (2) the Oligocene Zhuhai Formation in the Pearl River Mouth basin; and (3) the lower Miocene series in the Pearl River Mouth basin. The Eocene formation is probably the principal source rock of regional scale in the northern part of the South China Sea. The three suites of reservoir rocks are as follows: (1) the fluviolacustrine sandstone bodies in the Liushagang Formation; (2) the fluviolacustrine sand bodies and shallow-sea sandstone bodies in the Zhuhai Formation and Lingshu Formation; (3) the deltaic, littoral, and shallow-sea sand bodies and bioherms of Neogene age, with the middle Miocene sandstone reservoirs having the best physical properties.

  9. Perchlorate reduction by microbes inhabiting oil reservoirs

    NASA Astrophysics Data System (ADS)

    Liebensteiner, Martin; Stams, Alfons; Lomans, Bart

    2014-05-01

    Microbial perchlorate and chlorate reduction is a unique type of anaerobic respiration as during reduction of (per)chlorate chlorite is formed, which is then split into chloride and molecular oxygen. In recent years it was demonstrated that (per)chlorate-reducing bacteria may employ oxygenase-dependent pathways for the degradation of aromatic and aliphatic hydrocarbons. These findings suggested that (per)chlorate may be used as oxygen-releasing compound in anoxic environments that contain hydrocarbons, such as polluted soil sites and oil reservoirs. We started to study perchlorate reduction by microbes possibly inhabiting oil reservoirs. One of the organisms studied was Archaeoglobus fulgidus. This extremely thermophilic archaeon is known as a major contributor to souring in hot oil reservoirs. A. fulgidus turned out to be able to use perchlorate as terminal electron acceptor for growth with lactate (Liebensteiner et al 2013). Genome based physiological experiments indicated that A. fulgidus possesses a novel perchlorate reduction pathway. Perchlorate is first reduced to chlorite, but chlorite is not split into chloride and molecular oxygen as occurs in bacteria. Rather, chlorite reacts chemically with sulfide, forming oxidized sulfur compounds, which are reduced to sulfide in the electron transport chain by the archaeon. The dependence of perchlorate reduction on sulfur compounds could be shown. The implications of our findings as novel strategy for microbiological enhanced oil recovery and for souring mitigation are discussed. Liebensteiner MG, Pinkse MWH, Schaap PJ, Stams AJM and Lomans BP (2013) Archaeal (per)chlorate reduction at high temperature, a matter of abiotic-biotic reactions. Science 340: 85-87

  10. X-ray microtomography application in pore space reservoir rock.

    PubMed

    Oliveira, M F S; Lima, I; Borghi, L; Lopes, R T

    2012-07-01

    Characterization of porosity in carbonate rocks is important in the oil and gas industry since a major hydrocarbons field is formed by this lithology and they have a complex media porous. In this context, this research presents a study of the pore space in limestones rocks by x-ray microtomography. Total porosity, type of porosity and pore size distribution were evaluated from 3D high resolution images. Results show that carbonate rocks has a complex pore space system with different pores types at the same facies. PMID:22264795

  11. SEISMIC AND ROCK PHYSICS DIAGNOSTICS OF MULTISCALE RESERVOIR TEXTURES

    SciTech Connect

    Gary Mavko

    2003-10-01

    As part of our study on ''Relationships between seismic properties and rock microstructure'', we have (1) Studied relationships between velocity and permeability. (2) Used independent experimental methods to measure the elastic moduli of clay minerals as functions of pressure and saturation. (3) Applied different statistical methods for characterizing heterogeneity and textures from scanning acoustic microscope (SAM) images of shale microstructures. (4) Analyzed the directional dependence of velocity and attenuation in different reservoir rocks (5) Compared Vp measured under hydrostatic and non-hydrostatic stress conditions in sands. (6) Studied stratification as a source of intrinsic anisotropy in sediments using Vp and statistical methods for characterizing textures in sands.

  12. Research on improved and enhanced oil recovery in Illinois through reservoir characterization, March 28, 1992--June 28, 1992

    SciTech Connect

    Oltz, D.F.

    1992-09-01

    This project will provide information that can maximize hydrocarbon production, minimize formation damage and stimulate new production in Illinois. Such information includes definition of hydrocarbon resources, characterization of hydrocarbon reservoirs, and the implementation of methods that will improve hydrocarbon extractive technology. Increased understanding of reservoir heterogeneities that affect oil recovery can aid in identifying producible resources. The transfer of technology to industry and the general public is a significant component of the program. The project is designed to examine selected subsurface oil reservoirs in Illinois. Scientists use advanced scientific techniques to gain a better understanding of reservoir components and behavior and address ways of potentially increasing the amount of recoverable oil. Initial production rates for wells in the Illinois Basin commonly decline quite rapidly and as much as 60 percent of the oil in place can be unrecoverable using standard operating procedures. Heterogeneities (geological differences in reservoir make-up) affect a reservoir`s capability to release fluids. By-passed mobile and immobile oil remain in the reservoir. To learn how to get more of the oil out of reservoirs, the ISGS is studying the nature of reservoir rock heterogeneities and their control on the distribution and production of bypassed, mobile oil. Accomplishment for this period are summarized for the following tasks: mapping, cross-sections; subsurface depo-systems; outcrop studies; oil and gas development maps; engineering work; SEM/EDX; and clay minerals.

  13. Foam front propagation in anisotropic oil reservoirs.

    PubMed

    Grassia, P; Torres-Ulloa, C; Berres, S; Mas-Hernández, E; Shokri, N

    2016-04-01

    The pressure-driven growth model is considered, describing the motion of a foam front through an oil reservoir during foam improved oil recovery, foam being formed as gas advances into an initially liquid-filled reservoir. In the model, the foam front is represented by a set of so-called "material points" that track the advance of gas into the liquid-filled region. According to the model, the shape of the foam front is prone to develop concave sharply curved concavities, where the orientation of the front changes rapidly over a small spatial distance: these are referred to as "concave corners". These concave corners need to be propagated differently from the material points on the foam front itself. Typically the corner must move faster than those material points, otherwise spurious numerical artifacts develop in the computed shape of the front. A propagation rule or "speed up" rule is derived for the concave corners, which is shown to be sensitive to the level of anisotropy in the permeability of the reservoir and also sensitive to the orientation of the corners themselves. In particular if a corner in an anisotropic reservoir were to be propagated according to an isotropic speed up rule, this might not be sufficient to suppress spurious numerical artifacts, at least for certain orientations of the corner. On the other hand, systems that are both heterogeneous and anisotropic tend to be well behaved numerically, regardless of whether one uses the isotropic or anisotropic speed up rule for corners. This comes about because, in the heterogeneous and anisotropic case, the orientation of the corner is such that the "correct" anisotropic speed is just very slightly less than the "incorrect" isotropic one. The anisotropic rule does however manage to keep the corner very slightly sharper than the isotropic rule does. PMID:27090239

  14. Research on oil recovery mechanisms in heavy oil reservoirs

    SciTech Connect

    Brigham, W.E.; Aziz, K.; Ramey, H.J. Jr.

    1991-01-01

    The goal of the Stanford University Petroleum Research Institute is to conduct research directed toward increasing the recovery of heavy oils. Presently, SUPRI is working in five main directions: Assess the influence of different reservoir conditions (temperature and pressure) on the absolute and relative permeability to oil and water and on capillary pressure; evaluate the effect of different reservoir parameters on the in-situ combustion process. This project includes the study of the kinetics of the reactions; investigate the mechanisms of the process using commercially available surfactants for reduction of gravity override and channeling of steam; investigate and improve techniques of formation evaluation such as tracer tests and pressure transient tests; and provide technical support for design and monitoring of DOE sponsored or industry initiated field projects.

  15. Genomovar assignment of Pseudomonas stutzeri populations inhabiting produced oil reservoirs

    PubMed Central

    Zhang, Fan; She, Yue-Hui; Banat, Ibrahim M; Chai, Lu-Jun; Huang, Liu-Qin; Yi, Shao-Jin; Wang, Zheng-Liang; Dong, Hai-Liang; Hou, Du-Jie

    2014-01-01

    Oil reservoirs are specific habitats for the survival and growth of microorganisms in general. Pseudomonas stutzeri which is believed to be an exogenous organism inoculated into oil reservoirs during the process of oil production was detected frequently in samples from oil reservoirs. Very little is known, however, about the distribution and genetic structure of P. stutzeri in the special environment of oil reservoirs. In this study, we collected 59 P. stutzeri 16S rRNA gene sequences that were identified in 42 samples from 25 different oil reservoirs and we isolated 11 cultured strains from two representative oil reservoirs aiming to analyze the diversity and genomovar assignment of the species in oil reservoirs. High diversity of P. stutzeri was observed, which was exemplified in the detection of sequences assigned to four known genomovars 1, 2, 3, 20 and eight unknown genomic groups of P. stutzeri. The frequent detection and predominance of strains belonging to genomovar 1 in most of the oil reservoirs under study indicated an association of genomovars of P. stutzeri with the oil field environments. PMID:24890829

  16. SEISMIC AND ROCK PHYSICS DIAGNOSTICS OF MULTISCALE RESERVOIR TEXTURES

    SciTech Connect

    Gary Mavko

    2004-08-01

    As part of our study on ''Relationships between seismic properties and rock microstructure'', we have continued our work on analyzing well logs and microstructural constraints on seismic signatures. We report results of three studies in this report. The first one deals with fractures and faults that provide the primary control on the underground fluid flow through low permeability massive carbonate rocks. Fault cores often represent lower transmissibility whereas the surrounding damaged rocks and main slip surfaces are high transmissibility elements. We determined the physical properties of fault rocks collected in and around the fault cores of large normal faults in central Italy. After studying the P- and S-wave velocity variation during cycles of confining pressure, we conclude that a rigid pore frame characterizes the fault gouge whereas the fractured limestone comprises pores with a larger aspect ratio. The second study was to characterize the seismic properties of brine as its temperature decreases from 25 C to -21 C. The purpose was to understand how the transmitted wave changes with the onset of freezing. The main practical reason for this experiment was to use partially frozen brine as an analogue for a mixture of methane hydrate and water present in the pore space of a gas hydrate reservoir. In the third study we analyzed variations in dynamic moduli in various carbonate reservoirs. The investigations include log and laboratory data from velocity, porosity, permeability, and attenuation measurements.

  17. Mining earth's heat: Development of hot dry rock geothermal reservoirs

    SciTech Connect

    Pettitt, R.A.; Becker, N.A.

    1983-07-01

    Geothermal energy is commonly considered to be available only in areas characterized by hot springs and geysers. However, the rock of the earth is hot at accessible depths everywhere, and this energy source is present beneath the surface in almost any location. The energy-extraction concept of the Hot Dry Rock (HDR) Geothermal Program as initially developed by the Los Alamos National Laboratory, is to ''mine'' this heat by creating a man-made reservoir in low-permeability, hot basement rock. This concept has been successfully proven at Fenton Hill in northern New Mexico by drilling two holes to a depth of approximately 3 km (10,000 ft) and a bottom temperature of 200/sup 0/C (392/sup 0/F), then connecting the boreholes with a large diameter, vertical hydraulic fracture. Water is circulated down one borehole, heated by the hot rock, and rises up the second borehole to the surface where the heat is extracted and the cooled water is reinjected into the underground circulation loop. This system has operated for a cumulative 416 days during engineering and reservoir testing. An energy equivalent of 3 to 5 MW(t) was produced without adverse environmental problems. During one test, a generator was installed in the circulation loop and produced 60 kw of electricity.

  18. Grain-rimming kaolinite in Permian Rotliegend reservoir rocks

    NASA Astrophysics Data System (ADS)

    Waldmann, Svenja; Gaupp, Reinhard

    2016-04-01

    Upper Rotliegend sediments of Permian age from the northeast Netherlands show moderate to good reservoir qualities. The predominant control is by the presence of authigenic grain-rimming kaolinite, which has a negative, but in some parts also a positive, effect on reservoir quality. To better understand the formation and distribution of grain-rimming kaolinite, reservoir rocks were studied in terms of composition and diagenetic processes. Petrographic evidence, summarized as a paragenetic sequence, is integrated with geochemical modeling results to identify early mesodiagenetic water-rock interactions under the participation of gases, i.e., CO2 and H2S, released from underlying Carboniferous source rocks. The sediments investigated were deposited at varying distance from the southern flank of the Southern Permian Basin. Sediments near the basin margin are mainly attributed to a fluvial environment and comprise medium to coarse-grained sandstones and conglomerates. There, vermicular kaolinite occurs with a lath-like structure. Distal to the basin margin, mainly in sandstones intercalated with fine-grained playa sediments, comparatively high amounts of grain-rimming kaolinite occur. There, the presence of this mineral has a significant influence on the rock properties and the reservoir quality. Geochemical modeling suggests that the formation of such kaolinites cannot be explained exclusively by in situ feldspar dissolution. The modeling results support evidence that kaolinite can be formed from precursor clay minerals under the presence of CO2-rich formation waters. Such clay minerals could be corrensite, smectite-chlorite mixed-layer minerals, or chlorite that is potentially present in Rotliegend sediments during early diagenesis. Furthermore, the geochemical modeling can reflect several mineral reactions that were identified from petrographic analysis such as the formation of illite and kaolinite at the expense of feldspar dissolution and consequent silica

  19. A mathematical model of microbial enhanced oil recovery (MEOR) method for mixed type rock

    SciTech Connect

    Sitnikov, A.A.; Eremin, N.A.; Ibattulin, R.R.

    1994-12-31

    This paper deals with the microbial enhanced oil recovery method. It covers: (1) Mechanism of microbial influence on the reservoir was analyzed; (2) The main groups of metabolites affected by the hydrodynamic characteristics of the reservoir were determined; (3) The criterions of use of microbial influence method on the reservoir are defined. The mathematical model of microbial influence on the reservoir was made on this basis. The injection of molasse water solution with Clostridium bacterias into the mixed type of rock was used in this model. And the results of calculations were compared with experimental data.

  20. Anisotropic permeabilities evolution of reservoir rocks under pressure

    NASA Astrophysics Data System (ADS)

    Jeremie, D.; Nicolas, G.; Alexandre, D.; Olga, V.

    2006-12-01

    The aim of our study is to measure, to model and to forecast the evolutions of porosity and permeability under anisotropic stresses representative of hydrocarbon reservoir conditions. Reservoir field exploitation induces a decrease of the pore pressure, hence modifying the effective stress-state at the reservoir scale. To optimize production and recovery rates of the reservoir it is of fundamental interest to understand all the physical and mechanical evolutions of the host-rock and their influence on transport properties. In the case of weakly consolidated reservoirs the variations of stresses are modest, yet they can induce significant porosity and permeability changes due to their high compressibility. In the case of deeply buried and consolidated reservoirs the stress variations might be pronounced enough to influence flow properties as well. Because of reservoir boundaries conditions, the fluid pressure drop influences essentially the vertical stress. The recovery rate is a function of horizontal permeability. In order to understand how the anisotropic stress-states induced during production may influence the transport properties experiments must be designed to measure simultaneously both horizontal and vertical permeabilities under deviatoric stresses. For this purpose we developed a specific triaxial cell operating in conditions representative of the field conditions. Preliminary results obtained with low permeability sandstones allowed a coupled observation of deformation and directional permeability evolution. Because of complex geometrical conditions the results required numerical interpretations. A finite-element inversion of our data allowed the determination of the complete permeability tensor. In addition the study aims on the identification of the microphysical mechanics that induce the pore scale microstructural evolution, which is ultimately responsible of the permeability decrease. For this purpose we used synthetic hot-pressed calcite

  1. Simulating Oil Production from Fractured/Faulted Basement Reservoirs

    NASA Astrophysics Data System (ADS)

    Wang, H.; Forster, C.; Fu, Y.; Huang, C.; Yang, Y.; Deo, M.

    2006-12-01

    A fully-implicit, three-dimensional (3D), three-phase, discrete fault/fracture, black oil simulator provides new insight and understanding of oil production from reservoirs in fractured, low-permeability basement rocks. Results obtained with a controlled volume finite element (CVFE) method compare favorably to those obtained using both single- and dual-porosity finite difference methods (e.g., ECLIPSE). A regularized network of 30 orthogonal faults within a 1000 by 1000 by 200 feet model domain is used to compare the simulator results and to explore the implications of grid sensitivity. In this simple reservoir, cumulative oil recoveries over 900 days of production are similar for CVFE, single-porosity and dual-porosity approaches. CVFE is used to simulate a complex network of intersecting faults that mimic a more realistic basement reservoir with the same fault surface area and fault volume as the regularized network. Cumulative oil production at 900 days is about 3% lower than for the regularized network. The CVFE method provides a much improved ability to represent complex fracture/fault geometries and spatial variations in the internal properties of faults. CVFE simulations of the realistic network illustrate the possible consequences of uncertainty in knowing fracture/fault properties (e.g., porosity, permeability, thickness, dip orientation, connectivity and flow transmissibility). For example, introducing spatial variability in permeability within the fault planes (using spatially randomized patterns of 10, 100 and 1000 md), while retaining a constant geometric mean permeability of 100 md, yields enhanced oil production due to the high-permeability pathways. A 50:50 mix of 10 and 1000 md elements yields 36%OOIP while a 33:33:33 mix of 10, 100 and 1000 md yields 24%OOIP. These results are 26% and 14% greater, respectively, than that obtained for the uniform 100 md case (11%OOIP). This inherent variability, combined with uncertainty in knowing the detailed

  2. Research on improved and enhanced oil recovery in Illinois through reservoir characterization, March 28, 1992--June 28, 1992

    SciTech Connect

    Oltz, D.F.

    1992-01-01

    This project will provide information that can maximize hydrocarbon production, minimize formation damage and stimulate new production in Illinois. Such information includes definition of hydrocarbon resources, characterization of hydrocarbon reservoirs, and the implementation of methods that will improve hydrocarbon extractive technology. Increased understanding of reservoir heterogeneities that affect oil recovery can aid in identifying producible resources. The transfer of technology to industry and the general public is a significant component of the program. The project is designed to examine selected subsurface oil reservoirs in Illinois. Scientists use advanced scientific techniques to gain a better understanding of reservoir components and behavior and address ways of potentially increasing the amount of recoverable oil. Initial production rates for wells in the Illinois Basin commonly decline quite rapidly and as much as 60 percent of the oil in place can be unrecoverable using standard operating procedures. Heterogeneities (geological differences in reservoir make-up) affect a reservoir's capability to release fluids. By-passed mobile and immobile oil remain in the reservoir. To learn how to get more of the oil out of reservoirs, the ISGS is studying the nature of reservoir rock heterogeneities and their control on the distribution and production of bypassed, mobile oil. Accomplishment for this period are summarized for the following tasks: mapping, cross-sections; subsurface depo-systems; outcrop studies; oil and gas development maps; engineering work; SEM/EDX; and clay minerals.

  3. MULTI-ATTRIBUTE SEISMIC/ROCK PHYSICS APPROACH TO CHARACTERIZING FRACTURED RESERVOIRS

    SciTech Connect

    Gary Mavko

    2000-10-01

    This project consists of three key interrelated Phases, each focusing on the central issue of imaging and quantifying fractured reservoirs, through improved integration of the principles of rock physics, geology, and seismic wave propagation. This report summarizes the results of Phase I of the project. The key to successful development of low permeability reservoirs lies in reliably characterizing fractures. Fractures play a crucial role in controlling almost all of the fluid transport in tight reservoirs. Current seismic methods to characterize fractures depend on various anisotropic wave propagation signatures that can arise from aligned fractures. We are pursuing an integrated study that relates to high-resolution seismic images of natural fractures to the rock parameters that control the storage and mobility of fluids. Our goal is to go beyond the current state-of-the art to develop and demonstrate next generation methodologies for detecting and quantitatively characterizing fracture zones using seismic measurements. Our study incorporates 3 key elements: (1) Theoretical rock physics studies of the anisotropic viscoelastic signatures of fractured rocks, including up scaling analysis and rock-fluid interactions to define the factors relating fractures in the lab and in the field. (2) Modeling of optimal seismic attributes, including offset and azimuth dependence of travel time, amplitude, impedance and spectral signatures of anisotropic fractured rocks. We will quantify the information content of combinations of seismic attributes, and the impact of multi-attribute analyses in reducing uncertainty in fracture interpretations. (3) Integration and interpretation of seismic, well log, and laboratory data, incorporating field geologic fracture characterization and the theoretical results of items 1 and 2 above. The focal point for this project is the demonstration of these methodologies in the Marathon Oil Company Yates Field in West Texas.

  4. Geochemical characteristics of crude oil from a tight oil reservoir in the Lucaogou Formation, Jimusar Sag, Junggar Basin

    NASA Astrophysics Data System (ADS)

    Cao, Z.

    2015-12-01

    Jimusar Sag, which lies in the Junggar Basin,is one of the most typical tight oil study areas in China. However, the properties and origin of the crude oil and the geochemical characteristics of the tight oil from the Lucaogou Formation have not yet been studied. In the present study, 23 crude oilsfrom the Lucaogou Formation were collected for analysis, such as physical properties, bulk composition, saturated hydrocarbon gas chromatography-mass spectrometry (GC-MS), and the calculation of various biomarker parameters. In addition,source rock evaluation and porosity permeability analysis were applied to the mudstones and siltstones. Biomarkers of suitable source rocks (TOC>1, S1+S2>6mg/g, 0.7%oil-source correlation. To analyze the hydrocarbon generation history of the Lucaogou source rock, 1D basin modeling was performed. The oil-filling history was also defined by means of basin modeling and microthermometry. The results indicated the presence of low maturity to mature crude oils originating from the burial of terrigenous organic matter beneath a saline lake in the source rocks of mainly type II1kerogen. In addition, a higher proportion of bacteria and algae was shown to contribute to the formation of crude oil in the lower section when compared with the upper section of the Lucaogou Formation. Oil-source correlations demonstrated that not all mudstones within the Lucaogou Formation contributed to oil accumulation.Crude oil from the upper and lower sections originated from thin-bedded mudstones interbedded within sweet spot sand bodies. A good coincidence of filling history and hydrocarbon generation history indicated that the Lucaogou reservoir is a typical in situ reservoir. The mudstones over or beneath the sweet spot bodies consisted of natural caprocks and prevented the vertical movement of oil by capillary forces. Despite being thicker, the thick-bedded mudstone between the upper and lower sweet spots had no obvious contribution to

  5. Water in evolved lunar rocks: Evidence for multiple reservoirs

    NASA Astrophysics Data System (ADS)

    Robinson, Katharine L.; Barnes, Jessica J.; Nagashima, Kazuhide; Thomen, Aurélien; Franchi, Ian A.; Huss, Gary R.; Anand, Mahesh; Taylor, G. Jeffrey

    2016-09-01

    We have measured the abundance and isotopic composition of water in apatites from several lunar rocks representing Potassium (K), Rare Earth Elements (REE), and Phosphorus (P) - KREEP - rich lithologies, including felsites, quartz monzodiorites (QMDs), a troctolite, and an alkali anorthosite. The H-isotope data from apatite provide evidence for multiple reservoirs in the lunar interior. Apatite measurements from some KREEP-rich intrusive rocks display moderately elevated δD signatures, while other samples show δD signatures similar to the range known for the terrestrial upper mantle. Apatite grains in Apollo 15 quartz monzodiorites have the lowest δD values measured from the Moon so far (as low as -749‰), and could potentially represent a D-depleted reservoir in the lunar interior that had not been identified until now. Apatite in all of these intrusive rocks contains <267 ppm H2O, which is relatively low compared to apatites from the majority of studied mare basalts (200 to >6500 ppm H2O). Complexities in partitioning of volatiles into apatite make this comparison uncertain, but measurements of residual glass in KREEP basalt fragments in breccia 15358 independently show that the KREEP basaltic magmas were low in water. The source of 15358 contained ∼10 ppm H2O, about an order of magnitude lower than the source of the Apollo 17 pyroclastic glass beads, suggesting potential variations in the distribution of water in the lunar interior.

  6. 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

  7. Fluid-Rock Interactions at the Interface between Reservoir Rock and Cap Rock: An Experimental Case Study Regarding Mineral Trapping at 54 and 200 C

    NASA Astrophysics Data System (ADS)

    Wigand, M. O.; Carey, J. W.; Kaszuba, J. P.; Hollis, W. K.

    2006-12-01

    Geologic sequestration (underground storage) of carbon dioxide (CO2) is the most feasible approach to mitigating CO2-induced global warming while maintaining the current fossil fuel-based economy. Although simple in principle, effective implementation of geologic sequestration will require significant development of the scientific understanding of interactions among injected CO2 (as a supercritical fluid), brine, and the reservoir rock. This paper presents the results of flow-through experiments that simulated a rising plume of supercritical carbon dioxide (SCCO2) interacting at the interface between reservoir rock and cap rock in a brine- saturated aquifer. We performed two high pressure flow-through experiments using powdered limestone and illite-rich shale separated by a frit with a pore size of 10 μm. One experiment was performed under in-situ pressure (2880 psi) and temperature (54°C) conditions of a typical oil reservoir in the Permian Basin. To increase the kinetic rates of the mineral reactions we also performed an experiment at elevated temperatures (200°C) but using the same boundary conditions for other experimental parameters such as pressure, rock samples, fluids, injection rates, and time span. Both experiments were performed over 3263 hours. After the experiment eight disks of equal size representing different reaction zones were cut to investigate the progressive fluid-rock interaction of the reservoir and cap rock with the mixture of SCCO2 and brine. Additionally, fluid samples were frequently collected and their compositions were analyzed using inductively coupled plasma mass spectrometry. At in-situ temperature conditions we determined an enrichment of B, Ba, Cr, Cu, Fe, K, Li, Mg, Na, Ni, Rb, Si, Sr, Ti, Zn, and sulfate in the collected brines, whereas Mn and chloride concentrations were depleted in comparison with the starting composition. Ca and Al showed uneven behavior with changes in enrichment and depletion during the experiment. At 200

  8. Hot Dry Rock Geothermal Reservoir Model Development at Los Alamos

    SciTech Connect

    Robinson, Bruce A.; Birdsell, Stephen A.

    1989-03-21

    Discrete fracture and continuum models are being developed to simulate Hot Dry Rock (HDR) geothermal reservoirs. The discrete fracture model is a two-dimensional steady state simulator of fluid flow and tracer transport in a fracture network which is generated from assumed statistical properties of the fractures. The model's strength lies in its ability to compute the steady state pressure drop and tracer response in a realistic network of interconnected fractures. The continuum approach models fracture behavior by treating permeability and porosity as functions of temperature and effective stress. With this model it is practical to model transient behavior as well as the coupled processes of fluid flow, heat transfer, and stress effects in a three-dimensional system. The model capabilities being developed will also have applications in conventional geothermal systems undergoing reinjection and in fractured geothermal reservoirs in general.

  9. Hot Dry Rock geothermal reservoir model development at Los Alamos

    SciTech Connect

    Robinson, B.A.; Birdsell, S.A.

    1989-01-01

    Discrete fracture and continuum models are being developed to simulate Hot Dry Rock (HDR) geothermal reservoirs. The discrete fracture model is a two-dimensional steady state simulator of fluid flow and tracer transport in a fracture network which is generated from assumed statistical properties of the fractures. The model's strength lies in its ability to compute the steady state pressure drop and tracer response in a realistic network of interconnected fractures. The continuum approach models fracture behavior by treating permeability and porosity as functions of temperature and effective stress. With this model it is practical to model transient behavior as well as the coupled processes of fluid flow, heat transfer, and stress effects in a three-dimensional system. The model capabilities being developed will also have applications in conventional geothermal systems undergoing reinjection and in fractured geothermal reservoirs in general. 15 refs., 7 figs.

  10. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect

    Unknown

    2001-08-08

    The objective of this project is to increase the recoverable heavy oil reserves within sections of the Wilmington Oil Field, near Long Beach, California, through the testing and application of advanced reservoir characterization and thermal production technologies. The hope is that successful application of these technologies will result in their implementation throughout the Wilmington Field and, through technology transfer, will be extended to increase the recoverable oil reserves in other slope and basin clastic (SBC) reservoirs. The existing steamflood in the Tar zone of Fault Block II-A (Tar II-A) has been relatively inefficient because of several producibility problems which are common in SBC reservoirs: inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil and non-uniform distribution of the remaining oil. This has resulted in poor sweep efficiency, high steam-oil ratios, and early steam breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves. A suite of advanced reservoir characterization and thermal production technologies are being applied during the project to improve oil recovery and reduce operating costs, including: (1) Development of three-dimensional (3-D) deterministic and stochastic reservoir simulation models--thermal or otherwise--to aid in reservoir management of the steamflood and post-steamflood phases and subsequent development work. (2) Development of computerized 3-D visualizations of the geologic and reservoir simulation models to aid reservoir surveillance and operations. (3) Perform detailed studies of the geochemical interactions between the steam and the formation rock and fluids. (4) Testing and proposed application of a

  11. Lower Tertiary and Upper Cretaceous source rocks in Louisiana and Mississippi: Implications to Gulf of Mexico crude oil

    SciTech Connect

    Sassen, R. )

    1990-06-01

    The Lower Tertiary Sparta Formation, Wilcox Group, and the Midway Group in southern Louisiana include organic-rich source facies that generate crude oil at relatively high thermal maturities. The Wilcox Group is an important source of Wilcox crude oil, and regional kerogen variations explain two crude oil subfamilies. Wilcox crude oils in downdip areas of southern Louisiana migrated short distances, but long-range lateral migration (about 150 km) best explains Wilcox crude oils far updip from mature source rocks. Crude oils in Oligocene and younger reservoirs in southern Louisiana migrated vertically from deep lower Tertiary source rocks. Some crude oils in Upper Cretaceous Tuscaloosa reservoirs were emplaced by long-range lateral migration from Tuscaloosa source rocks. Given little evidence of upper Tertiary source rocks and the overmaturity problems of Mesozoic source rocks, most crude oils in upper Tertiary and Pleistocene reservoirs of the Gulf continental shelf are best explained by vertical migration from deep lower Tertiary source rocks. Even so, it is simplistic to assume an exclusive lower Tertiary origin. Many Tertiary and Pleistocene crude oils of this study probably include an overprint of high-maturity hydrocarbons from Mesozoic sources. 12 figs., 7 tabs.

  12. Surface potential and permeability of rock cores under asphaltenic oil flow conditions

    SciTech Connect

    Alkafeef, S.F.; Gochin, R.J.; Smith, A.L.

    1995-12-31

    The surface properties, wetting behaviour and permeability of rock samples are central to understanding recovery behaviour in oil reservoirs. This paper will present a method new to petroleum engineering to show how area/length ratios for porous systems can be obtained by combining streaming potential and streaming current measurements on rock cores. This has allows streaming current measurements (independent of surface conductivity errors) to be made on rock samples using hydrocarbon solvents with increasing concentrations of asphaltene. Negative surface potentials for the rock became steadily more positive as asphaltene coated the pore surfaces, with permeability reduction agreeing well with petrographic analysis.

  13. Mineral-petrographic features of hydrocarbon reservoirs of the Tevlinsko-Russkinskoe oil deposit (Western Siberia)

    NASA Astrophysics Data System (ADS)

    Sitdikova, Elina; Izotov, Victor

    2010-05-01

    The Tevlinsko-Russkinskoe oil field is located in the central part of the West Siberian lowland. It concerns a group of multistory deposits and is one of the perspective deposits in the West Siberian oil and gas province. The young Sortym formation and the Jurassic sediments offer the best prospects. Layers are consisted of sand-clay deposits of Mesozoic-Cainozoic sedimentary cover and rocks of the pre-Jurassic basement. Core material of base drill holes of the Tevlinsko-Russkinskoe oil field was studied in order to obtain detailed lithological and mineralogical characteristics of rocks features. These drill holes found out main productive horizons. Sandstones of productive horizons of Jurassic petroliferous complex are of a homogeneous and monotonous structure. In the studied samples of core material massive structures prevail. Mineral composite of clastic component of sandstones is polymictic and it is represented by quartz, orthoclase, microcline, plagioclases, biotite, strongly changed dark-coloured minerals, fragments of effusive rocks and quartzite of different degrees of recrystallization. Cluster formation - grains accretion into separated quartzite-like parts - is typical for these rocks. Process of cluster formation is accompanied by change of sandstone structure. This results in reservoir quality alteration and extension of porosity and permeability properties. In the studied rocks-reservoirs of Jurassic oil complex processes of cluster formation were lasting during period of diagenesis and were followed by repartition of cement mass. We carried out electron microscopic research of reservoirs structure to analyze void space structure. Electron microscopic studies were spent on the scanning electron microscope of XL-30 system (Phillips company). The conducted research testifies that reservoirs can be considered a mesoporous-nanoporous medium. Its' studying is of a great importance for realization of questions of Tevlinsko-Russkinskoe oil field working out.

  14. The oil and gas potential of southern Bolivia: Contributions from a dual source rock system

    SciTech Connect

    Hartshorn, K.G.

    1996-08-01

    The southern Sub-Andean and Chaco basins of Bolivia produce oil, gas and condensate from reservoirs ranging from Devonian to Tertiary in age. Geochemical evidence points to contributions from two Paleozoic source rocks: the Devonian Los Monos Formation and the Silurian Kirusillas Formation. Rock-Eval pyrolysis, biomarker data, microscopic kerogen analysis, and burial history modeling are used to assess the quality, distribution, and maturity of both source rock systems. The geochemical results are then integrated with the structural model for the area in order to determine the most likely pathways for migration of oil and gas in the thrust belt and its foreland. Geochemical analysis and modeling show that the primary source rock, shales of the Devonian Los Monos Formation, entered the oil window during the initial phase of thrusting in the sub-Andean belt. This provides ideal timing for oil accumulation in younger reservoirs of the thrust belt. The secondary source rock, although richer, consumed most of its oil generating capacity prior to the development of the thrust related structures. Depending on burial depth and location, however, the Silurian source still contributes gas, and some oil, to traps in the region.

  15. Sampling and Nucleic Extraction Procedures from Oil Reservoir Samples

    NASA Astrophysics Data System (ADS)

    van der Kraan, Geert M.; De Ridder, Maarten; Lomans, Bart P.; Muyzer, Gerard

    Today there is a renewed interest towards biological aspects in oil reservoir systems. This interest not only comes from academia, but also from the petroleum industry. Fields of common interest are 'Microbial Enhanced Oil Recovery' (MEOR), efforts to lower H2S production and subsequently microbial corrosion (caused by sulfate reducing microorganisms) and the analysis of microorganisms found in oil wells as additional information source for reservoir conditions.

  16. Opportunities to improve oil productivity in unstructured deltaic reservoirs

    SciTech Connect

    Not Available

    1991-01-01

    This report contains presentations presented at a technical symposium on oil production. Chapter 1 contains summaries of the presentations given at the Department of Energy (DOE)-sponsored symposium and key points of the discussions that followed. Chapter 2 characterizes the light oil resource from fluvial-dominated deltaic reservoirs in the Tertiary Oil Recovery Information System (TORIS). An analysis of enhanced oil recovery (EOR) and advanced secondary recovery (ASR) potential for fluvial-dominated deltaic reservoirs based on recovery performance and economic modeling as well as the potential resource loss due to well abandonments is presented. Chapter 3 provides a summary of the general reservoir characteristics and properties within deltaic deposits. It is not exhaustive treatise, rather it is intended to provide some basic information about geologic, reservoir, and production characteristics of deltaic reservoirs, and the resulting recovery problems.

  17. Characterization of oil and gas reservoir heterogeneity. Technical progress report, April 1, 1992--June 30, 1992

    SciTech Connect

    Sharma, G.D.

    1992-10-01

    The ultimate objective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task 1 is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization-determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis-source rock identification; and the study of asphaltene precipitation for Alaskan crude oils. Results are discussed.

  18. Characterization of oil and gas reservoir heterogeneity. Technical progress report, January 1, 1992--March 31, 1992

    SciTech Connect

    Sharma, G.D.

    1992-08-01

    The ultimate objective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task 1 is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization -- determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis -- source rock identification; and the study of asphaltene precipitation for Alaskan crude oils.

  19. Characterization of oil and gas reservoir heterogeneity. Technical progress report, July 1, 1992--September 30, 1992

    SciTech Connect

    Sharma, G.D.

    1992-12-01

    The ultimate oojective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task 1 is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization--determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis--source rock identification; and the study of asphaltene precipitation for Alaskan crude oils. This report presents a summary of technical progress of the well log analysis of Kuparuk Field, Northslope, Alaska.

  20. Mobilization and Transport of Organic Compounds from Reservoir Rock and Caprock in Geological Carbon Sequestration Sites

    SciTech Connect

    Zhong, Lirong; Cantrell, Kirk J.; Mitroshkov, Alexandre V.; Shewell, Jesse L.

    2014-05-06

    Supercritical CO2 (scCO2) is an excellent solvent for organic compounds, including benzene, toluene, ethyl-benzene, and xylene (BTEX), phenols, and polycyclic aromatic hydrocarbons (PAHs). Monitoring results from geological carbon sequestration (GCS) field tests has shown that organic compounds are mobilized following CO2 injection. Such results have raised concerns regarding the potential for groundwater contamination by toxic organic compounds mobilized during GCS. Knowledge of the mobilization mechanism of organic compounds and their transport and fate in the subsurface is essential for assessing risks associated with GCS. Extraction tests using scCO2 and methylene chloride (CH2Cl2) were conducted to study the mobilization of volatile organic compounds (VOCs, including BTEX), the PAH naphthalene, and n-alkanes (n-C20 – n-C30) by scCO2 from representative reservoir rock and caprock obtained from depleted oil reservoirs and coal from an enhanced coal-bed methane recovery site. More VOCs and naphthalene were extractable by scCO2 compared to the CH2Cl2 extractions, while scCO2 extractable alkane concentrations were much lower than concentrations extractable by CH2Cl2. In addition, dry scCO2 was found to extract more VOCs than water saturated scCO2, but water saturated scCO2 mobilized more naphthalene than dry scCO2. In sand column experiments, moisture content was found to have an important influence on the transport of the organic compounds. In dry sand columns the majority of the compounds were retained in the column except benzene and toluene. In wet sand columns the mobility of the BTEX was much higher than that of naphthalene. Based upon results determined for the reservoir rock, caprock, and coal samples studied here, the risk to aquifers from contamination by organic compounds appears to be relatively low; however, further work is necessary to fully evaluate risks from depleted oil reservoirs.

  1. Increasing Heavy Oil Reserves in the Wilmington Oil Field Through Advanced Reservoir Characterization and Thermal Production Technologies

    SciTech Connect

    Scott Hara

    1998-03-03

    The project involves improving thermal recovery techniques in a slope and basin clastic (SBC) reservoir in the Wilmington field, Los Angeles Co., Calif. using advanced reservoir characterization and thermal production technologies. The existing steamflood in the Tar zone of Fault Block (FB) II-A has been relatively inefficient because of several producibility problems which are common in SBC reservoirs. Inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil, and nonuniform distribution of remaining oil have all contributed to poor sweep efficiency, high steam-oil ratios, and early steam breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated formation sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves. The advanced technologies to be applied include: (1) Develop three-dimensional (3-D) deterministic and stochastic geologic models. (2) Develop 3-D deterministic and stochastic thermal reservoir simulation models to aid in reservoir management and subsequent development work. (3) Develop computerized 3-D visualizations of the geologic and reservoir simulation models to aid in analysis. (4) Perform detailed study on the geochemical interactions between the steam and the formation rock and fluids. (5) Pilot steam injection and production via four new horizontal wells (2 producers and 2 injectors). (6) Hot water alternating steam (WAS) drive pilot in the existing steam drive area to improve thermal efficiency. (7) Installing a 2100 foot insulated, subsurface harbor channel crossing to supply steam to an island location. (8) Test a novel alkaline steam completion technique to control well sanding problems and fluid entry profiles. (9) Advanced reservoir management through computer-aided access to production and

  2. Increasing Heavy Oil Reserves in the Wilmington Oil Field Through Advanced Reservoir Characterization and Thermal Production Technologies

    SciTech Connect

    Scott Hara

    1997-08-08

    The project involves improving thermal recovery techniques in a slope and basin clastic (SBC) reservoir in the Wilmington field, Los Angeles Co., Calif. using advanced reservoir characterization and thermal production technologies. The existing steamflood in the Tar zone of Fault Block (FB) II-A has been relatively inefficient because of several producibility problems which are common in SBC reservoirs. Inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil, and nonuniform distribution of remaining oil have all contributed to poor sweep efficiency, high steam-oil ratios, and early steam breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated formation sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves. The advanced technologies to be applied include: (1) Develop three-dimensional (3-D) deterministic and stochastic geologic models. (2) Develop 3-D deterministic and stochastic thermal reservoir simulation models to aid in reservoir management and subsequent development work. (3) Develop computerized 3-D visualizations of the geologic and reservoir simulation models to aid in analysis. (4) Perform detailed study on the geochemical interactions between the steam and the formation rock and fluids. (5) Pilot steam injection and production via four new horizontal wells (2 producers and 2 injectors). (6) Hot water alternating steam (WAS) drive pilot in the existing steam drive area to improve thermal efficiency. (7) Installing a 2100 foot insulated, subsurface harbor channel crossing to supply steam to an island location. (8) Test a novel alkaline steam completion technique to control well sanding problems and fluid entry profiles. (9) Advanced reservoir management through computer-aided access to production and

  3. Oil-source rock correlation using carbon isotope data and biological marker compounds, Cook Inlet-Alaska Peninsula, Alaska

    SciTech Connect

    Magoon, L.B. ); Anders, D.E. )

    1990-05-01

    Rock and oil samples from the Cook Inlet-Alaska Peninsula area were analyzed to determine the source of the commercial hydrocarbons produced in the Cook Inlet basin from lower Tertiary nonmarine sandstone reservoirs. Rock-Eval (hydrogen index) analysis and organic carbon content were used to identify the most favorable rock samples for solvent extraction and carbon isotope, gas-chromatographic (GC), and gas-chromatrographic/mass-spectrometric (GCMS) analyses. On the basis of organic-matter richness, five nonmarine Tertiary coal and shale samples and 12 marine Mesozoic (Upper Triassic and Middle Jurassic) shale samples were selected. A total of 28 oil and condensate samples from producing wells, oil-stem tests, field separators, and seeps were used for oil-oil and oil-source rock correlation. On the basis of biomarker and carbon isotope data, four of the shallower oils and condensates are from nonmarine source rocks, and 24 of the deeper oils are sourced from marine shales. Geochemical and regional geologic considerations indicate the following conclusions. The upper Tertiary nonmarine oils and condensates associated with commercial microbial gas accumulations are geochemically similar to the immature organic matter in the Tertiary nonmarine rocks. In the upper Cook Inlet, marine oils in lower Tertiary nonmarine reservoirs originated from Middle Jurassic rocks that matured during the Pliocene to Holocene; in the lower Cook Inlet-Alaska Peninsula area, oils migrated from both Upper Triassic and Middle Jurassic source rocks during the Late Cretaceous to early Tertiary. Although three petroleum systems are identified, this study on the petroleum potential in a convergent-margin setting indicates that only one of these three systems was responsible for the 1.2 billion bbl of recoverable oil in the lower Tertiary nonmarine reservoirs.

  4. Tectonic control in source rock maturation and oil migration in Trinidad

    SciTech Connect

    Persad, K.M.; Talukdar, S.C.; Dow, W.G. )

    1993-02-01

    Oil accumulation in Trinidad were sourced by the Upper Cretaceous calcareous shales deposited along the Cretaceous passive margin of northern South America. Maturation of these source rocks, oil generation, migration and re-migration occurred in a foreland basin setting that resulted from interaction between Caribbean and South American plates during Late Oligocene to recent times. During Middle Miocene-Recent times, the foreland basin experienced strong compressional events, which controlled generation, migration, and accumulation of oil in Trinidad. A series of mature source rock kitchens formed in Late Miocene-Recent times in the Southern and Colombus Basins to the east-southeast of the Central Range Thrust. This thrust and associated fratured developed around 12 m.y.b.p. and served as vertical migration paths for the oil generated in Late Miocene time. This oil migrated into submarine fans deposited in the foreland basin axis and older reservoirs deformed into structural traps. Further generation and migration of oil, and re-migration of earlier oil took place during Pliocene-Holocene times, when later thrusting and wrench faulting served as vertical migration paths. Extremely high sedimentation rates in Pliocene-Pleistocene time, concurrent with active faulting, was responsible for very rapid generation of oil and gas. Vertically migrating gas often mixed with earlier migrated oil in overlying reservoirs. This caused depletion of oil in light hydrocarbons with accompanied fractionation among hydrocarbon types resulting in heavier oil in lower reservoirs, enrichment of light hydrocarbons and accumulation of gas-condensates in upper reservoirs. This process led to an oil-gravity stratification within about 10,000 ft of section.

  5. Increasing Waterflooding Reservoirs in the Wilmington Oil Field through Improved Reservoir Characterization and Reservoir Management, Class III

    SciTech Connect

    Koerner, Roy; Clarke, Don; Walker, Scott; Phillips, Chris; Nguyen, John; Moos, Dan; Tagbor, Kwasi

    2001-08-07

    This project was intended to increase recoverable waterflood reserves in slope and basin reservoirs through improved reservoir characterization and reservoir management. The particular application of this project is in portions of Fault Blocks IV and V of the Wilmington Oil Field, in Long Beach, California, but the approach is widely applicable in slope and basin reservoirs, transferring technology so that it can be applied in other sections of the Wilmington field and by operators in other slope and basin reservoirs is a primary component of the project.

  6. Increasing Waterflooding Reservoirs in the Wilmington Oil Field through Improved Reservoir Characterization and Reservoir Management

    SciTech Connect

    Koerner, Roy; Clarke, Don; Walker, Scott

    1999-11-09

    The objectives of this quarterly report was to summarize the work conducted under each task during the reporting period April - June 1998 and to report all technical data and findings as specified in the ''Federal Assistance Reporting Checklist''. The main objective of this project is the transfer of technologies, methodologies, and findings developed and applied in this project to other operators of Slope and Basin Clastic Reservoirs. This project will study methods to identify sands with high remaining oil saturation and to recomplete existing wells using advanced completion technology.

  7. Increasing Waterflooding Reservoirs in the Wilmington Oil Field through Improved Reservoir Characterization and Reservoir Management

    SciTech Connect

    Clarke, Don; Koerner, Roy; Moos, Dan; Nguyen, John; Phillips, Chris; Tagbor, Kwasi; Walker, Scott

    1999-11-09

    The objectives of this quarterly report are to summarize the work conducted under each task during the reporting period July - September 1998 and to report all technical data and findings as specified in the ''Federal Assistance Reporting Checklist''. The main objective of this project is the transfer of technologies, methodologies, and findings developed and applied in this project to other operators of Slope and Basin Clastic Reservoirs. This project will study methods to identify sands with high remaining oil saturation and to recomplete existing wells using advanced completion technology.

  8. WETTABILITY AND PREDICTION OF OIL RECOVERY FROM RESERVOIRS DEVELOPED WITH MODERN DRILLING AND COMPLETION FLUIDS

    SciTech Connect

    Jill S. Buckley; Norman R. Morrow

    2005-04-01

    Exposure to crude oil in the presence of an initial brine saturation can render rocks mixed-wet. Subsequent exposure to components of synthetic oil-based drilling fluids can alter the wetting toward less water-wet or more oil-wet conditions. Mixing of the non-aromatic base oils used in synthetic oil-based muds (SBM) with an asphaltic crude oil can destabilize asphaltenes and make cores less water-wet. Wetting changes can also occur due to contact with the surfactants used in SBM formulations to emulsify water and make the rock cuttings oil-wet. Reservoir cores drilled with SBMs, therefore, show wetting properties much different from the reservoir wetting conditions, invalidating laboratory core analysis using SBM contaminated cores. Core cleaning is required in order to remove all the drilling mud contaminants. In theory, core wettability can then be restored to reservoir wetting conditions by exposure to brine and crude oil. The efficiency of core cleaning of SBM contaminated cores has been explored in this study. A new core cleaning procedure was developed aimed to remove the adsorbed asphaltenes and emulsifiers from the contaminated Berea sandstone cores. Sodium hydroxide was introduced into the cleaning process in order to create a strongly alkaline condition. The high pH environment in the pore spaces changed the electrical charges of both basic and acidic functional groups, reducing the attractive interactions between adsorbing materials and the rock surface. In cores, flow-through and extraction methods were investigated. The effectiveness of the cleaning procedure was assessed by spontaneous imbibition tests and Amott wettability measurements. Test results indicating that introduction of sodium hydroxide played a key role in removing adsorbed materials were confirmed by contact angle measurements on similarly treated mica surfaces. Cleaning of the contaminated cores reversed their wettability from oil-wet to strongly water-wet as demonstrated by spontaneous

  9. 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.

  10. Interpreting isotopic analyses of microbial sulfate reduction in oil reservoirs

    NASA Astrophysics Data System (ADS)

    Hubbard, C. G.; Engelbrektson, A. L.; Druhan, J. L.; Cheng, Y.; Li, L.; Ajo Franklin, J. B.; Coates, J. D.; Conrad, M. E.

    2013-12-01

    Microbial sulfate reduction in oil reservoirs is often associated with secondary production of oil where seawater (28 mM sulfate) is commonly injected to maintain reservoir pressure and displace oil. The hydrogen sulfide produced can cause a suite of operating problems including corrosion of infrastructure, health exposure risks and additional processing costs. We propose that monitoring of the sulfur and oxygen isotopes of sulfate can be used as early indicators that microbial sulfate reduction is occurring, as this process is well known to cause substantial isotopic fractionation. This approach relies on the idea that reactions with reservoir (iron) minerals can remove dissolved sulfide, thereby delaying the transport of the sulfide through the reservoir relative to the sulfate in the injected water. Changes in the sulfate isotopes due to microbial sulfate reduction may therefore be measurable in the produced water before sulfide is detected. However, turning this approach into a predictive tool requires (i) an understanding of appropriate fractionation factors for oil reservoirs, (ii) incorporation of isotopic data into reservoir flow and reactive transport models. We present here the results of preliminary batch experiments aimed at determining fractionation factors using relevant electron donors (e.g. crude oil and volatile fatty acids), reservoir microbial communities and reservoir environmental conditions (pressure, temperature). We further explore modeling options for integrating isotope data and discuss whether single fractionation factors are appropriate to model complex environments with dynamic hydrology, geochemistry, temperature and microbiology gradients.

  11. Oil source rocks in the Romanian area of the Moesian platform

    SciTech Connect

    Baltes, N.; Matracaru, C.; Petrom, R.A.

    1995-08-01

    The Romanian area of the Moesian Platform (north of the Danube-Black Sea and east and South Carpathians Foredeep to north) represents a very important intra-plate with some new real oil prospects. With a thick sedimentary cover, especially in its northern, deepest area, the Moesian Platform offers favorable geological conditions of oil systems in the whole stratigraphic column, from Paleozoic to Upper Cenozoic (Pliocene). Having a few rich oil source rocks both in carbonatic facies (Devonian-Carboniferous, Middle Triassic, Neocomian) and argillitic ones (Silurian, early Carboniferous, Lias-Dogger, Mid-Upper Miocene), the Moesian Platform also contains very good oil reservoirs: Mid-Upper Paleozoic, Triassic, Lower Cretaceous, Upper Miocene and Pliocene. Geochemical studies on kerogen and bitumen have pointed out the most important oil source rocks, as well as the quality and quantity of expelled hydrocarbons and their relationships with oil reservoirs. Geochemical correlations between oils and source rocks have led to a better understanding of the oil pool formation with some interesting goals in the Romanian exploration strategy.

  12. Oxygen isotope geochemistry of The Geysers reservoir rocks, California

    SciTech Connect

    Gunderson, Richard P.; Moore, Joseph N.

    1994-01-20

    Whole-rock oxygen isotopic compositions of Late Mesozoic graywacke, the dominant host rock at The Geysers, record evidence of a large liquid-dominated hydrothermal system that extended beyond the limits of the present steam reservoir. The graywackes show vertical and lateral isotopic variations that resulted from gradients in temperature, permeability, and fluid composition during this early liquid-dominated system. All of these effects are interpreted to have resulted from the emplacement of the granitic "felsite" intrusion 1-2 million years ago. The {delta}{sup 18}O values of the graywacke are strongly zoned around a northwest-southeast trending low located near the center of and similar in shape to the present steam system. Vertical isotopic gradients show a close relationship to the felsite intrusion. The {delta}{sup 18}O values of the graywacke decrease from approximately 15 per mil near the surface to 4-7 per mil 300 to 600 m above the intrusive contact. The {delta}{sup 18}O values then increase downward to 8-10 per mil at the felsite contact, thereafter remaining nearly constant within the intrusion itself. The large downward decrease in {delta}{sup 18}O values are interpreted to be controlled by variations in temperature during the intrusive event, ranging from 150{degree}C near the surface to about 425{degree}C near the intrusive contact. The upswing in {delta}{sup 18}O values near the intrusive contact appears to have been caused by lower rock permeability and/or heavier fluid isotopic composition there. Lateral variations in the isotopic distributions suggests that the effects of temperature were further modified by variations in rock permeability and/or fluid-isotopic composition. Time-integrated water:rock ratios are thought to have been highest within the central isotopic low where the greatest isotopic depletions are observed. We suggest that this region of the field was an area of high permeability within the main upflow zone of the liquid

  13. Neocomian source and reservoir rocks in the western Brooks Range and Arctic Slope, Alaska

    SciTech Connect

    Mull, C.G.; Reifenstuhl, R.R.; Harris, E.E.; Crowder, R.K.

    1995-04-01

    Detailed (1:63,360) mapping of the Tingmerkpuk sandstone and associated rocks in the Misheguk Mountain and DeLong Mountains guadrangles of the western Brooks Range thrust belt documents potential hydrocarbon source and reservoir rocks in the northern foothills of the western Delong Mountains and adjacent Colville basin of northwest Alaska. Neocomian (?) to Albian micaceous shale, litharenite, and graywacke that overlies the Tingmerkpuk represents the onset of deposition of orogenic sediments derived from the Brooks Range to the south, and the merging of northern and southern sediment sources in the Colville basin. Both the proximal and distal Tingmerkpuk facies contain clay shale interbeds and overlie the Upper Jurassic to Neocomian Kingak Shale. Preliminary geochemical data show that in the thrust belt, these shales are thermally overmature (Ro 1.4-1.6), but are good source rocks with total organic content (TOC) that ranges from 1.2 to 1.8 percent. Shale in the overlying Brookian rocks is also thermally overmature (Ro 1.2-1.5 percent), but contains up to 1.8 percent TOC from a dominantly terrigenous source, and has generated gas. In outcrops at Surprise Creek, in the foothills north of the thrust belt, the Kingak (1.9 percent TOC) and underlying Triassic Shublik Formation (4.6 percent TOC) are excellent oil source rocks with thermal maturity close to peak oil generation stage (Ro0.75-0.9 percent). These rocks have lower thermal maturity values than expected for their stratigraphic position within the deeper parts of the Colville basin and indicate anomalous burial and uplift history in parts of the basin. Preliminary apatite fission-track (AFTA) data from the thrust belt indicate a stage of rapid uplift and cooling at about 53.61 Ma.

  14. Increasing Waterflood Reserves in the Wilmington Oil Field Through Reservoir Characterization and Reservoir Management

    SciTech Connect

    Chris Phillips; Dan Moos; Don Clarke; John Nguyen; Kwasi Tagbor; Roy Koerner; Scott Walker

    1997-04-10

    This project is intended to increase recoverable waterflood reserves in slope and basin reservoirs through improved reservoir characterization and reservoir management. The particular application of this project is in portions of Fault Blocks IV and V of the Wilmington Oil Field, in Long Beach, California, but the approach is widely applicable in slope and basin reservoirs. Transferring technology so that it can be applied in other sections of the Wilmington Field and by operators in other slope and basin reservoirs is a primary component of the project.

  15. Characterization of CO2 reservoir rock in Switzerland

    NASA Astrophysics Data System (ADS)

    Fabbri, Stefano; Madonna, Claudio; Zappone, Alba

    2014-05-01

    Anthropogenic emissions of Carbon Dioxide (CO2) are one of the key drivers regarding global climate change (IPCC, 2007). Carbon Dioxide Capture and Storage (CCS) is one valuable technology to mitigate current climate change with an immediate impact. The IPCC special report on CCS predicted a potential capture range of 4.7 to 37.5 Gt of CO2 by 2050. Among several countries, Switzerland has started to investigate its potential for CO2 storage (Chevalier et al., 2010) and is currently performing research on the characterization of the most promising reservoir/seal rocks for CO2 sequestration. For Switzerland, the most feasible option is to store CO2 in saline aquifers, sealed by impermeable formations. One aquifer of regional scale in the Swiss Molasse Basin is a carbonate sequence consisting of reworked shallow marine limestones and accumulations of shell fragments. The upper part of the formation presents the most promising permeability values and storage properties. The storage potential has been estimated of 706 Mt of CO2, based on the specific ranking scheme proposed by Chevalier et al. 2010. In this study, key parameters such as porosity, permeability and acoustic velocities in compressional and shear mode have been measured in laboratory at pressures and temperatures simulating in situ conditions. Reservoir rock samples have been investigated. Permeability has been estimated before and after CO2 injection in supercritical state. The simulation of typical reservoir conditions allows us to go one step further towards a significant evaluation of the reservoir's true capacities for CO2 sequestration. It seems of major importance to notice that the permeability crucially depends on confining pressure, temperature and pore pressure conditions of the sample. Especially at in situ conditions with CO2 being at supercritical state, a substantial loss in permeability have to be taken into consideration when it comes to the calculation of potential injection rates. The

  16. Seismic Characterization of Fractured Reservoirs - Rock Physics Analysis and Modeling of James Limestone Reservoir

    NASA Astrophysics Data System (ADS)

    Sava, D. C.; Florez, J. M.; Mukerji, T.; Mavko, G.

    2002-12-01

    We present the rock physics analysis from well logs of the fractured James Limestone reservoir in the Neuville Field and also the results of our stochastic simulations of various seismic attributes for different models of fractures in the reservoir. Our goal is to determine the optimal combination of seismic attributes, and the uncertainty due to natural variability for delineating the gas filled fractured zones. Geological model based on the logs from horizontal wells suggests that the fractures are controlled by subseismic normal faults. These small faults can generate narrow zones with high fracture density. Between these fracture swarms, the background fracture density may correspond to regularly spaced, vertical joints. Therefore, for fracture modeling we consider both isotropic and anisotropic distributions of fractures. The isotropic distribution corresponds to the fracture swarms in the vicinity of faults, where the cracks are more or less randomly orientated, such as in brecciated zones. The anisotropic distribution corresponds to a single set of vertical joints that generates an azimuthally anisotropic medium with HTI symmetry. For each hypotheses of fracture distribution we stochastically model seismic interval and interface properties such as interval velocities, Poisson's Ratio, impedances, travel time, scattering attenuation, PP reflectivity as a function of angle of incidence and azimuth. The modeling shows that some of these attributes, such as Poisson's Ratio and P Impedance, are more sensitive to the presence of fractures than others. Rock physics analysis of the cross-dipole and FMI logs shows that the fractures are present especially in the clean limestone intervals, characterized by high velocity and small porosity. This observation can be used in fracture delineation from seismic measurements. In summary, rock physics fracture modeling and stochastic simulations for seismic attributes of James Lime reservoir provide a framework for delineating

  17. FUNDAMENTALS OF RESERVOIR SURFACE ENERGY AS RELATED TO SURFACE PROPERTIES, WETTABILITY, CAPILLARY ACTION, AND OIL RECOVERY FROM FRACTURED RESERVOIRS BY SPONTANEOUS IMBIBITION

    SciTech Connect

    Norman R. Morrow; Herbert Fischer; Yu Li; Geoffrey Mason; Douglas Ruth; Siddhartha Seth; Peigui Yin; Shaochang Wo

    2005-04-01

    The objective of this project is to increase oil recovery from fractured reservoirs through improved fundamental understanding of the process of spontaneous imbibition by which oil is displaced from the rock matrix into the fractures. Spontaneous imbibition is fundamentally dependent on the reservoir surface free energy but this has never been investigated for rocks. In this project, the surface free energy of rocks will be determined by using liquids that can be solidified within the rock pore space at selected saturations. Thin sections of the rock then provide a two-dimensional view of the rock minerals and the occupant phases. Saturations and oil/rock, water/rock, and oil/water surface areas will be determined by advanced petrographic analysis and the surface free energy which drives spontaneous imbibition will be determined as a function of increase in wetting phase saturation. The inherent loss in surface free energy resulting from capillary instabilities at the microscopic (pore level) scale will be distinguished from the decrease in surface free energy that drives spontaneous imbibition. A mathematical network/numerical model will be developed and tested against experimental results of recovery versus time over broad variation of key factors such as rock properties, fluid phase viscosities, sample size, shape and boundary conditions. Two fundamentally important, but not previously considered, parameters of spontaneous imbibition, the capillary pressure acting to oppose production of oil at the outflow face and the pressure in the nonwetting phase at the no-flow boundary versus time, will also be measured and modeled. Simulation and network models will also be tested against special case solutions provided by analytic models. In the second stage of the project, application of the fundamental concepts developed in the first stage of the project will be demonstrated. The fundamental ideas, measurements, and analytic/numerical modeling will be applied to mixed

  18. FUNDAMENTALS OF RESERVOIR SURFACE ENERGY AS RELATED TO SURFACE PROPERTIES, WETTABILITY, CAPILLARY ACTION, AND OIL RECOVERY FROM FRACTURED RESERVOIRS BY SPONTANEOUS IMBIBITION

    SciTech Connect

    Norman R. Morrow

    2004-07-01

    The objective of this project is to increase oil recovery from fractured reservoirs through improved fundamental understanding of the process of spontaneous imbibition by which oil is displaced from the rock matrix into the fractures. Spontaneous imbibition is fundamentally dependent on the reservoir surface free energy but this has never been investigated for rocks. In this project, the surface free energy of rocks will be determined by using liquids that can be solidified within the rock pore space at selected saturations. Thin sections of the rock then provide a two-dimensional view of the rock minerals and the occupant phases. Saturations and oil/rock, water/rock, and oil/water surface areas will be determined by advanced petrographic analysis and the surface free energy which drives spontaneous imbibition will be determined as a function of increase in wetting phase saturation. The inherent loss in surface free energy resulting from capillary instabilities at the microscopic (pore level) scale will be distinguished from the decrease in surface free energy that drives spontaneous imbibition. A mathematical network/numerical model will be developed and tested against experimental results of recovery versus time over broad variation of key factors such as rock properties, fluid phase viscosities, sample size, shape and boundary conditions. Two fundamentally important, but not previously considered, parameters of spontaneous imbibition, the capillary pressure acting to oppose production of oil at the outflow face and the pressure in the nonwetting phase at the no-flow boundary versus time, will also be measured and modeled. Simulation and network models will also be tested against special case solutions provided by analytic models. In the second stage of the project, application of the fundamental concepts developed in the first stage of the project will be demonstrated. The fundamental ideas, measurements, and analytic/numerical modeling will be applied to mixed

  19. Fundamentals of reservoir surface energy as related to surface properties, wettability, capillary action, and oil recovery from fractured reservoirs by spontaneous imbibition

    SciTech Connect

    Norman R. Morrow; Herbert Fischer; Yu Li; Geoffrey Mason; Douglas Ruth; Siddhartha Seth; Jason Zhengxin Tong; Peigui Yin; Shaochang Wo

    2006-02-01

    The objective of this project is to increase oil recovery from fractured reservoirs through improved fundamental understanding of the process of spontaneous imbibition by which oil is displaced from the rock matrix into the fractures. Spontaneous imbibition is fundamentally dependent on the reservoir surface free energy but this has never been investigated for rocks. In this project, the surface free energy of rocks will be determined by using liquids that can be solidified within the rock pore space at selected saturations. Thin sections of the rock then provide a two-dimensional view of the rock minerals and the occupant phases. Saturations and oil/rock, water/rock, and oil/water surface areas will be determined by advanced petrographic analysis and the surface free energy which drives spontaneous imbibition will be determined as a function of increase in wetting phase saturation. The inherent loss in surface free energy resulting from capillary instabilities at the microscopic (pore level) scale will be distinguished from the decrease in surface free energy that drives spontaneous imbibition. A mathematical network/numerical model will be developed and tested against experimental results of recovery versus time over broad variation of key factors such as rock properties, fluid phase viscosities, sample size, shape and boundary conditions. Two fundamentally important, but not previously considered, parameters of spontaneous imbibition, the capillary pressure acting to oppose production of oil at the outflow face and the pressure in the nonwetting phase at the no-flow boundary versus time, will also be measured and modeled. Simulation and network models will also be tested against special case solutions provided by analytic models. In the second stage of the project, application of the fundamental concepts developed in the first stage of the project will be demonstrated. The fundamental ideas, measurements, and analytic/numerical modeling will be applied to mixed

  20. Fundamentals of Reservoir Surface Energy as Related to Surface Properties, Wettability, Capillary Action, and Oil Recovery from Fractured Reservoirs by Spontaneous Imbibition

    SciTech Connect

    Norman Morrow; Herbert Fischer; Yu Li; Geoffrey Mason; Douglas Ruth; Siddhartha Seth; Zhengxin Tong; Evren Unsal; Siluni Wickramathilaka; Shaochang Wo; Peigui Yin

    2008-06-30

    The objective of this project is to increase oil recovery from fractured reservoirs through improved fundamental understanding of the process of spontaneous imbibition by which oil is displaced from the rock matrix into the fractures. Spontaneous imbibition is fundamentally dependent on the reservoir surface free energy but this has never been investigated for rocks. In this project, the surface free energy of rocks will be determined by using liquids that can be solidified within the rock pore space at selected saturations. Thin sections of the rock then provide a two-dimensional view of the rock minerals and the occupant phases. Saturations and oil/rock, water/rock, and oil/water surface areas will be determined by advanced petrographic analysis and the surface free energy which drives spontaneous imbibition will be determined as a function of increase in wetting phase saturation. The inherent loss in surface free energy resulting from capillary instabilities at the microscopic (pore level) scale will be distinguished from the decrease in surface free energy that drives spontaneous imbibition. A mathematical network/numerical model will be developed and tested against experimental results of recovery versus time over broad variation of key factors such as rock properties, fluid phase viscosities, sample size, shape and boundary conditions. Two fundamentally important, but not previously considered, parameters of spontaneous imbibition, the capillary pressure acting to oppose production of oil at the outflow face and the pressure in the non-wetting phase at the no-flow boundary versus time, will also be measured and modeled. Simulation and network models will also be tested against special case solutions provided by analytic models. In the second stage of the project, application of the fundamental concepts developed in the first stage of the project will be demonstrated. The fundamental ideas, measurements, and analytic/numerical modeling will be applied to mixed

  1. FUNDAMENTALS OF RESERVOIR SURFACE ENERGY AS RELATED TO SURFACE PROPERTIES, WETTABILITY, CAPILLARY ACTION, AND OIL RECOVERY FROM FRACTURED RESERVOIRS BY SPONTANEOUS IMBIBITION

    SciTech Connect

    Norman R. Morrow

    2004-05-01

    The objective of this project is to increase oil recovery from fractured reservoirs through improved fundamental understanding of the process of spontaneous imbibition by which oil is displaced from the rock matrix into the fractures. Spontaneous imbibition is fundamentally dependent on the reservoir surface free energy but this has never been investigated for rocks. In this project, the surface free energy of rocks will be determined by using liquids that can be solidified within the rock pore space at selected saturations. Thin sections of the rock then provide a two-dimensional view of the rock minerals and the occupant phases. Saturations and oil/rock, water/rock, and oil/water surface areas will be determined by advanced petrographic analysis and the surface free energy which drives spontaneous imbibition will be determined as a function of increase in wetting phase saturation. The inherent loss in surface free energy resulting from capillary instabilities at the microscopic (pore level) scale will be distinguished from the decrease in surface free energy that drives spontaneous imbibition. A mathematical network/numerical model will be developed and tested against experimental results of recovery versus time over broad variation of key factors such as rock properties, fluid phase viscosities, sample size, shape and boundary conditions. Two fundamentally important, but not previously considered, parameters of spontaneous imbibition, the capillary pressure acting to oppose production of oil at the outflow face and the pressure in the nonwetting phase at the no-flow boundary versus time, will also be measured and modeled. Simulation and network models will also be tested against special case solutions provided by analytic models. In the second stage of the project, application of the fundamental concepts developed in the first stage of the project will be demonstrated. The fundamental ideas, measurements, and analytic/numerical modeling will be applied to mixed

  2. Fundamentals of Reservoir Surface Energy as Related to Surface Properties, Wettability, Capillary Action and Oil Recovery from Fractured Reservoirs by Spontaneous Imbibition

    SciTech Connect

    Norman R. Morrow; Herbert Fischer; Yu Li; Geoffrey Mason; Douglas Ruth; Peigui Yin; Shaochang Wo

    2006-12-08

    The objective of this project is to increase oil recovery from fractured reservoirs through improved fundamental understanding of the process of spontaneous imbibition by which oil is displaced from the rock matrix into the fractures. Spontaneous imbibition is fundamentally dependent on the reservoir surface free energy but this has never been investigated for rocks. In this project, the surface free energy of rocks will be determined by using liquids that can be solidified within the rock pore space at selected saturations. Thin sections of the rock then provide a two-dimensional view of the rock minerals and the occupant phases. Saturations and oil/rock, water/rock, and oil/water surface areas will be determined by advanced petrographic analysis and the surface free energy which drives spontaneous imbibition will be determined as a function of increase in wetting phase saturation. The inherent loss in surface free energy resulting from capillary instabilities at the microscopic (pore level) scale will be distinguished from the decrease in surface free energy that drives spontaneous imbibition. A mathematical network/numerical model will be developed and tested against experimental results of recovery versus time over broad variation of key factors such as rock properties, fluid phase viscosities, sample size, shape and boundary conditions. Two fundamentally important, but not previously considered, parameters of spontaneous imbibition, the capillary pressure acting to oppose production of oil at the outflow face and the pressure in the non-wetting phase at the no-flow boundary versus time, will also be measured and modeled. Simulation and network models will also be tested against special case solutions provided by analytic models. In the second stage of the project, application of the fundamental concepts developed in the first stage of the project will be demonstrated. The fundamental ideas, measurements, and analytic/numerical modeling will be applied to mixed

  3. FUNDAMENTALS OF RESERVOIR SURFACE ENERGY AS RELATED TO SURFACE PROPERTIES, WETTABILITY, CAPILLARY ACTION, AND OIL RECOVERY FROM FRACTURED RESERVOIRS BY SPONTANEOUS IMBIBITION

    SciTech Connect

    Norman R. Morrow; Herbert Fischer; Yu Li; Geoffrey Mason; Douglas Ruth; Siddhartha Seth; Peigui Yin; Shaochang Wo

    2005-02-01

    The objective of this project is to increase oil recovery from fractured reservoirs through improved fundamental understanding of the process of spontaneous imbibition by which oil is displaced from the rock matrix into the fractures. Spontaneous imbibition is fundamentally dependent on the reservoir surface free energy but this has never been investigated for rocks. In this project, the surface free energy of rocks will be determined by using liquids that can be solidified within the rock pore space at selected saturations. Thin sections of the rock then provide a two-dimensional view of the rock minerals and the occupant phases. Saturations and oil/rock, water/rock, and oil/water surface areas will be determined by advanced petrographic analysis and the surface free energy which drives spontaneous imbibition will be determined as a function of increase in wetting phase saturation. The inherent loss in surface free energy resulting from capillary instabilities at the microscopic (pore level) scale will be distinguished from the decrease in surface free energy that drives spontaneous imbibition. A mathematical network/numerical model will be developed and tested against experimental results of recovery versus time over broad variation of key factors such as rock properties, fluid phase viscosities, sample size, shape and boundary conditions. Two fundamentally important, but not previously considered, parameters of spontaneous imbibition, the capillary pressure acting to oppose production of oil at the outflow face and the pressure in the nonwetting phase at the no-flow boundary versus time, will also be measured and modeled. Simulation and network models will also be tested against special case solutions provided by analytic models. In the second stage of the project, application of the fundamental concepts developed in the first stage of the project will be demonstrated. The fundamental ideas, measurements, and analytic/numerical modeling will be applied to mixed

  4. Fundamentals of reservoir surface energy as related to surface properties, wettability, capillary action, and oil recovery from fractured reservoirs by spontaneous imbibition

    SciTech Connect

    Norman R. Morrow; Herbert Fischer; Yu Li; Geoffrey Mason; Douglas Ruth; Siddhartha Seth; Jason Zhengxin Tong; Peigui Yin; Shaochang Wo

    2006-06-08

    The objective of this project is to increase oil recovery from fractured reservoirs through improved fundamental understanding of the process of spontaneous imbibition by which oil is displaced from the rock matrix into the fractures. Spontaneous imbibition is fundamentally dependent on the reservoir surface free energy but this has never been investigated for rocks. In this project, the surface free energy of rocks will be determined by using liquids that can be solidified within the rock pore space at selected saturations. Thin sections of the rock then provide a two-dimensional view of the rock minerals and the occupant phases. Saturations and oil/rock, water/rock, and oil/water surface areas will be determined by advanced petrographic analysis and the surface free energy which drives spontaneous imbibition will be determined as a function of increase in wetting phase saturation. The inherent loss in surface free energy resulting from capillary instabilities at the microscopic (pore level) scale will be distinguished from the decrease in surface free energy that drives spontaneous imbibition. A mathematical network/numerical model will be developed and tested against experimental results of recovery versus time over broad variation of key factors such as rock properties, fluid phase viscosities, sample size, shape and boundary conditions. Two fundamentally important, but not previously considered, parameters of spontaneous imbibition, the capillary pressure acting to oppose production of oil at the outflow face and the pressure in the non-wetting phase at the no-flow boundary versus time, will also be measured and modeled. Simulation and network models will also be tested against special case solutions provided by analytic models. In the second stage of the project, application of the fundamental concepts developed in the first stage of the project will be demonstrated. The fundamental ideas, measurements, and analytic/numerical modeling will be applied to mixed

  5. FUNDAMENTALS OF RESERVOIR SURFACE ENERGY AS RELATED TO SURFACE PROPERTIES, WETTABILITY, CAPILLARY ACTION, AND OIL RECOVERY FROM FRACTURED RESERVOIRS BY SPONTANEOUS IMBIBITION

    SciTech Connect

    Norman R. Morrow; Herbert Fischer; Yu Li; Geoffrey Mason; Douglas Ruth; Siddhartha Seth; Peigui Yin; Shaochang Wo

    2004-10-01

    The objective of this project is to increase oil recovery from fractured reservoirs through improved fundamental understanding of the process of spontaneous imbibition by which oil is displaced from the rock matrix into the fractures. Spontaneous imbibition is fundamentally dependent on the reservoir surface free energy but this has never been investigated for rocks. In this project, the surface free energy of rocks will be determined by using liquids that can be solidified within the rock pore space at selected saturations. Thin sections of the rock then provide a two-dimensional view of the rock minerals and the occupant phases. Saturations and oil/rock, water/rock, and oil/water surface areas will be determined by advanced petrographic analysis and the surface free energy which drives spontaneous imbibition will be determined as a function of increase in wetting phase saturation. The inherent loss in surface free energy resulting from capillary instabilities at the microscopic (pore level) scale will be distinguished from the decrease in surface free energy that drives spontaneous imbibition. A mathematical network/numerical model will be developed and tested against experimental results of recovery versus time over broad variation of key factors such as rock properties, fluid phase viscosities, sample size, shape and boundary conditions. Two fundamentally important, but not previously considered, parameters of spontaneous imbibition, the capillary pressure acting to oppose production of oil at the outflow face and the pressure in the nonwetting phase at the no-flow boundary versus time, will also be measured and modeled. Simulation and network models will also be tested against special case solutions provided by analytic models. In the second stage of the project, application of the fundamental concepts developed in the first stage of the project will be demonstrated. The fundamental ideas, measurements, and analytic/numerical modeling will be applied to mixed

  6. A pore-level scenario for the development of mixed-wettability in oil reservoirs

    SciTech Connect

    Kovscek, A.R.; Wong, H.; Radke, C.J.

    1992-09-01

    Understanding the role of thin films in porous media is vital if wettability is to be elucidated at the pore level. The type and thickness of films coating pore walls determines reservoir wettability and whether or not reservoir rock can be altered from its initial state of wettability. Pore shape, especially pore wall curvature, is an important factor in determining wetting-film thicknesses. Yet, pore shape and the physics of thin wetting films are generally neglected in models of flow in porous rocks. This paper incorporates thin-film forces into a collection of star-shaped capillary tubes model to describe the geological development of mixed-wettability in reservoir rock. Here, mixed-wettability refers to continuous and distinct oil and water-wetting surfaces coexisting in the porous medium. The proposed model emphasizes the remarkable role of thin films. New pore-level fluid configurations arise that are quite unexpected. For example, efficient water displacement of oil (i.e, low residual oil saturation) characteristic of mixed-wettability porous media is ascribed to interconnected oil lenses or rivulets which bridge the walls adjacent to a pore corner. Predicted residual oil saturations are approximately 35 % less in mixed-wet rock compared to completely water-wet rock. Calculated capillary pressure curves mimic those of mixed-wet porous media in the primary drainage of water, imbibition of water, and secondary drainage modes. Amott-Harvey indices range from {minus}0.18 to 0.36 also in good agreement with experimental values. (Morrow et al, 1986; Judhunandan and Morrow, 1991).

  7. The Reservoir Rock GeoBioCell: A Microfluidic Flowcell Developed for Controlled Experiments on Subsurface Microbe-Water-Rock Interactions

    NASA Astrophysics Data System (ADS)

    Singh, R.; Sanford, R. A.; Werth, C. J.; Fouke, B. W.

    2014-12-01

    A better understanding of subsurface microbe-water-rock interaction in the Earth's outer crust is of critical importance because it strongly influences the basic petro-physical properties of sedimentary rock. Over the past decade, miniaturized microfluidic flowcell prototypes of subsurface reservoir systems, usually called micromodels and named GeoBioCells herein, have been used to replace traditional column experiments. However, the inert pore structure in these micromodels does not contain the biogeochemical grain surface heterogeneities in actual subsurface rock reservoirs. In this study, we developed a next-generation microfluidic experimental test bed, herein called the Reservoir Rock GeoBioCell (RRGBC), in which an actual piece of subsurface reservoir rock is mounted within a microfluidic flowcell for experimentation. Siliciclastic sandstones core samples of an oil-bearing subsurface reservoir were obtained for construction of the RRGBC. Custom petrographic rock sections (0.5 mm thick) were prepared from these core samples impregnated with Super Glue adhesive. Acetone was then used to remove the Super Glue and physically separate thin sections from the glass slides. A PDMS mold (~3-4 mm thick) was prepared to hold the thin section between a microfluidic inlet and outlet channels. The thin section in PDMS mold was covered with a PDMS-coated glass coverslip to help provide a pressure seal for core thin section (Figure 1, left-top). Multi-photon laser confocal microscopy of the RRGBC showed pore connectivity to an imaging depth of ~400 μm within the thin section. The geochemical reactive sites were characterized using Raman Backscattering Microscopy, confirming the presence of reactive quartz. A fluorescent tracer test was conducted to identify micro-flow paths and solute breakthrough within the thin section (Figure 1). A multiphase flow experiment was performed to trap residual light oil in the thin section. A mixed-culture of oil-degrading biofilm was

  8. Geologic Sequestration of CO2 in a Depleted Oil Reservoir: A Field Demonstration

    NASA Astrophysics Data System (ADS)

    Westrich, H. R.; Zhang, D.; Grigg, R. B.

    2002-12-01

    Carbon dioxide (CO2) sequestration in geologic formations is the most direct carbon management strategy for long-term removal of anthropogenic CO2 from the atmosphere, and is likely to be needed for continuation of the US fossil fuel-based economy and high standard of living. Subsurface injection of CO2 into depleted oil reservoirs is a carbon sequestration strategy that might prove to be both cost effective and environmentally safe. However, there are significant R&D gaps that need to be addressed prior to sequestration of CO2 in depleted oil reservoirs, including the need of coupled physicochemical processes involving CO2, water, oil and reservoir rock, better estimates of the capacity of reservoir for long-term sequestration and ultimate fate of injected CO2, and improved geophysical monitoring technologies for accurately determining the presence and location of injected CO2. Our project is part of the DOE Carbon Sequestration program and it is directed at predicting and monitoring the migration and ultimate fate of CO2 after injection in a depleted oil reservoir. We utilize computer simulations of multiphase oil-brine-CO2 flow in the reservoir, laboratory measurements of geochemical brine-rock reactions, and geophysical surveys to monitor CO2 plume migration after injection. A principal component of this project is characterization and validation of predicted CO2 migration and fate through a field demonstration experiment. The reservoir under investigation is part of the West Pearl Queen field in southeastern New Mexico. Geologic modeling and numerical flow simulations (ECLIPSE code) have been used to study the feasibility of injection, and these techniques were used to help in designing geophysical monitoring studies to track the injected plume. Long-term static brine-rock reactions and short-term brine-CO2-oil flow through tests were performed to better understand the likely geochemical reactions that might be influence CO2 sequestration or injection. Results

  9. Heavy oil reservoirs recoverable by thermal technology. Annual report

    SciTech Connect

    Kujawa, P.

    1981-02-01

    The purpose of this study was to compile data on reservoirs that contain heavy oil in the 8 to 25/sup 0/ API gravity range, contain at least ten million barrels of oil currently in place, and are non-carbonate in lithology. The reservoirs within these constraints were then analyzed in light of applicable recovery technology, either steam-drive or in situ combustion, and then ranked hierarchically as candidate reservoirs. The study is presented in three volumes. Volume I presents the project background and approach, the screening analysis, ranking criteria, and listing of candidate reservoirs. The economic and environmental aspects of heavy oil recovery are included in appendices to this volume. This study provides an extensive basis for heavy oil development, but should be extended to include carbonate reservoirs and tar sands. It is imperative to look at heavy oil reservoirs and projects on an individual basis; it was discovered that operators, and industrial and government analysts will lump heavy oil reservoirs as poor producers, however, it was found that upon detailed analysis, a large number, so categorized, were producing very well. A study also should be conducted on abandoned reservoirs. To utilize heavy oil, refiners will have to add various unit operations to their processes, such as hydrotreaters and hydrodesulfurizers and will require, in most cases, a lighter blending stock. A big problem in producing heavy oil is that of regulation; specifically, it was found that the regulatory constraints are so fluid and changing that one cannot settle on a favorable recovery and production plan with enough confidence in the regulatory requirements to commit capital to the project.

  10. Increasing Waterflood Reserves in the Wilmington Oil Field through Improved Reservoir Characterization and Reservoir Management

    SciTech Connect

    Clarke, D.; Koerner, R.; Moos D.; Nguyen, J.; Phillips, C.; Tagbor, K.; Walker, S.

    1999-04-05

    This project used advanced reservoir characterization tools, including the pulsed acoustic cased-hole logging tool, geologic three-dimensional (3-D) modeling software, and commercially available reservoir management software to identify sands with remaining high oil saturation following waterflood. Production from the identified high oil saturated sands was stimulated by recompleting existing production and injection wells in these sands using conventional means as well as a short radius redrill candidate.

  11. MULTIDISCIPLINARY IMAGING OF ROCK PROPERTIES IN CARBONATE RESERVOIRS FOR FLOW-UNIT TARGETING

    SciTech Connect

    Stephen C. Ruppel

    2005-02-01

    Despite declining production rates, existing reservoirs in the US contain large quantities of remaining oil and gas that constitute a huge target for improved diagnosis and imaging of reservoir properties. The resource target is especially large in carbonate reservoirs, where conventional data and methodologies are normally insufficient to resolve critical scales of reservoir heterogeneity. The objectives of the research described in this report were to develop and test such methodologies for improved imaging, measurement, modeling, and prediction of reservoir properties in carbonate hydrocarbon reservoirs. The focus of the study is the Permian-age Fullerton Clear Fork reservoir of the Permian Basin of West Texas. This reservoir is an especially appropriate choice considering (a) the Permian Basin is the largest oil-bearing basin in the US, and (b) as a play, Clear Fork reservoirs have exhibited the lowest recovery efficiencies of all carbonate reservoirs in the Permian Basin.

  12. Source rock identification and oil generation related to trap formation: Southeast Constantine oil field

    SciTech Connect

    Boudjema, A.; Rahmani, A.; Belhadi, E.M.; Hamel, M.; Bourmouche, R. )

    1990-05-01

    Petroleum exploration began in the Southeast Constantine basin in the late 1940s. Despite the very early discovery of Djebel Onk field (1954), exploration remains very sparse and relatively unsuccessful due mainly to the geological complexity of the region. The Ras-Toumb oil field was discovered only twenty years later. In 1988, a new discovery, the Guerguit-El-Kihal oil field renewed the interest of explorationists in this region. The Southeast Constantine Mesozoic-Cenozoic basin has a sedimentary sequence of shales and carbonates with a thickness exceeding 7,000 m. Structural traps are related to pyrenean and post-Villafranchian phases. Potential reservoirs with good petrophysical characteristics and seals can be found throughout the section and are mainly Cenomanian-Turonian and Coniacian limestones and dolomites. The known source rocks are Cenomanian-Turonian and Campanian carbonate shales. Kerogen is a mixture of type II and type III for the Campanian. The kerogen has a fair petroleum potential and is often immature or low mature. The Cenomanian-Turonian kerogen is type II amorphous, with a variable but important petroleum potential. Total organic carbon values range from 1.5% to 7%. Maturity corresponds to the oil window. This source rock is well known throughout the Mediterranean region and is related to the oceanic anoxic event. Kinetic modeling of this organic matter evolution indicates favorable oil generation timing related to trap formation ages.

  13. Heavy oil reservoirs recoverable by thermal technology. Annual report

    SciTech Connect

    Kujawa, P.

    1981-02-01

    This volume contains reservoir, production, and project data for target reservoirs which contain heavy oil in the 8 to 25/sup 0/ API gravity range and are susceptible to recovery by in situ combustion and steam drive. 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 collectd from three source types: hands-on (A), once-removed (B), and twice-removed (C). 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. This volume also contains a complete listing of operators and projects, as well as a bibliography of source material.

  14. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect

    Scott Hara

    2003-06-04

    The overall objective of this project is to increase heavy oil reserves in slope and basin clastic (SBC) reservoirs through the application of advanced reservoir characterization and thermal production technologies. The project involves improving thermal recovery techniques in the Tar Zone of Fault Blocks II-A and V (Tar II-A and Tar V) of the Wilmington Field in Los Angeles County, near Long Beach, California. A primary objective is to transfer technology which can be applied in other heavy oil formations of the Wilmington Field and other SBC reservoirs, including those under waterflood. The thermal recovery operations in the Tar II-A and Tar V have been relatively inefficient because of several producibility problems which are common in SBC reservoirs. Inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil, and nonuniform distribution of remaining oil have all contributed to poor sweep efficiency, high steam-oil ratios, and early steam breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated formation sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves. The advanced technologies to be applied include: (1) Develop three-dimensional (3-D) deterministic and stochastic geologic models. (2) Develop 3-D deterministic and stochastic thermal reservoir simulation models to aid in reservoir management and subsequent development work. (3) Develop computerized 3-D visualizations of the geologic and reservoir simulation models to aid in analysis. (4) Perform detailed study on the geochemical interactions between the steam and the formation rock and fluids. (5) Pilot steam injection and production via four new horizontal wells (2 producers and 2 injectors). (6) Hot water alternating steam (WAS) drive pilot in the

  15. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect

    Scott Hara

    2004-03-05

    The overall objective of this project is to increase heavy oil reserves in slope and basin clastic (SBC) reservoirs through the application of advanced reservoir characterization and thermal production technologies. The project involves improving thermal recovery techniques in the Tar Zone of Fault Blocks II-A and V (Tar II-A and Tar V) of the Wilmington Field in Los Angeles County, near Long Beach, California. A primary objective is to transfer technology which can be applied in other heavy oil formations of the Wilmington Field and other SBC reservoirs, including those under waterflood. The thermal recovery operations in the Tar II-A and Tar V have been relatively inefficient because of several producibility problems which are common in SBC reservoirs. Inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil, and nonuniform distribution of remaining oil have all contributed to poor sweep efficiency, high steam-oil ratios, and early steam breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated formation sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves. The advanced technologies to be applied include: (1) Develop three-dimensional (3-D) deterministic and stochastic geologic models. (2) Develop 3-D deterministic and stochastic thermal reservoir simulation models to aid in reservoir management and subsequent development work. (3) Develop computerized 3-D visualizations of the geologic and reservoir simulation models to aid in analysis. (4) Perform detailed study on the geochemical interactions between the steam and the formation rock and fluids. (5) Pilot steam injection and production via four new horizontal wells (2 producers and 2 injectors). (6) Hot water alternating steam (WAS) drive pilot in the

  16. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect

    Scott Hara

    2003-09-04

    The overall objective of this project is to increase heavy oil reserves in slope and basin clastic (SBC) reservoirs through the application of advanced reservoir characterization and thermal production technologies. The project involves improving thermal recovery techniques in the Tar Zone of Fault Blocks II-A and V (Tar II-A and Tar V) of the Wilmington Field in Los Angeles County, near Long Beach, California. A primary objective is to transfer technology which can be applied in other heavy oil formations of the Wilmington Field and other SBC reservoirs, including those under waterflood. The thermal recovery operations in the Tar II-A and Tar V have been relatively inefficient because of several producibility problems which are common in SBC reservoirs. Inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil, and nonuniform distribution of remaining oil have all contributed to poor sweep efficiency, high steam-oil ratios, and early steam breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated formation sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves. The advanced technologies to be applied include: (1) Develop three-dimensional (3-D) deterministic and stochastic geologic models. (2) Develop 3-D deterministic and stochastic thermal reservoir simulation models to aid in reservoir management and subsequent development work. (3) Develop computerized 3-D visualizations of the geologic and reservoir simulation models to aid in analysis. (4) Perform detailed study on the geochemical interactions between the steam and the formation rock and fluids. (5) Pilot steam injection and production via four new horizontal wells (2 producers and 2 injectors). (6) Hot water alternating steam (WAS) drive pilot in the

  17. Dynamic reservoir characterization using 4D multicomponent seismic data and rock physics modeling at Delhi Field, Louisiana

    NASA Astrophysics Data System (ADS)

    Carvajal Meneses, Carla C.

    Pore pressure and CO2 saturation changes are important to detect and quantify for maximizing oil recovery in Delhi Field. Delhi Field is a enhanced oil recovery (EOR) project with active monitoring by 4D multicomponent seismic technologies. Dynamic rock physics modeling integrates the rich dataset of core, well logs, petrographic thin sections and facies providing a link between reservoir and elastic properties. The dynamic modeling in this high porosity sandstone reservoir shows that P-wave velocity is more sensitive to CO2 saturation while S-wave velocity is more sensitive to pore pressure changes. I use PP and PS seismic data to jointly invert for Vp=Vs ratio and acoustic impedance. This technique has the advantage of adding more information to the non-unique inversion problem. Combining the inversion results from the monitor surveys of June 2010 and August 2011 provides acoustic impedance and Vp=Vs percentage differences. The time-lapse inverted response enables dynamic characterization of the reservoir by fitting the predicted dynamic models (calibrated at the wells). Dynamic reservoir characterization adds value in this stratigraphic complex reservoir. The results indicate that reservoir heterogeneities and pore pressure gradients control the CO2 flow within the Paluxy reservoir. Injectors 148-2 and 140-1 showed CO2 is moving downdip following a distributary channel induced by differential pressure from an updip injector or a barrier caused by a heterogeneity in the reservoir. CO2 anomalies located above the Paluxy injector 148-2 indicates that CO2 is moving from the Paluxy up into the Tuscaloosa Formation. My work demonstrates that reservoir monitoring is necessary for reservoir management at Delhi Field.

  18. An experimental and theoretical study to relate uncommon rock/fluid properties to oil recovery. Final report

    SciTech Connect

    Watson, R.

    1995-07-01

    Waterflooding is the most commonly used secondary oil recovery technique. One of the requirements for understanding waterflood performance is a good knowledge of the basic properties of the reservoir rocks. This study is aimed at correlating rock-pore characteristics to oil recovery from various reservoir rock types and incorporating these properties into empirical models for Predicting oil recovery. For that reason, this report deals with the analyses and interpretation of experimental data collected from core floods and correlated against measurements of absolute permeability, porosity. wettability index, mercury porosimetry properties and irreducible water saturation. The results of the radial-core the radial-core and linear-core flow investigations and the other associated experimental analyses are presented and incorporated into empirical models to improve the predictions of oil recovery resulting from waterflooding, for sandstone and limestone reservoirs. For the radial-core case, the standardized regression model selected, based on a subset of the variables, predicted oil recovery by waterflooding with a standard deviation of 7%. For the linear-core case, separate models are developed using common, uncommon and combination of both types of rock properties. It was observed that residual oil saturation and oil recovery are better predicted with the inclusion of both common and uncommon rock/fluid properties into the predictive models.

  19. Development of a compositional model fully coupled with geomechanics and its application to tight oil reservoir simulation

    NASA Astrophysics Data System (ADS)

    Xiong, Yi

    Tight oil reservoirs have received great attention in recent years as unconventional and promising petroleum resources; they are reshaping the U.S. crude oil market due to their substantial production. However, fluid flow behaviors in tight oil reservoirs are not well studied or understood due to the complexities in the physics involved. Specific characteristics of tight oil reservoirs, such as nano-pore scale and strong stress-dependency result in complex porous medium fluid flow behaviors. Recent field observations and laboratory experiments indicate that large effects of pore confinement and rock compaction have non-negligible impacts on the production performance of tight oil reservoirs. On the other hand, there are approximations or limitations for modeling tight oil reservoirs under the effects of pore confinement and rock compaction with current reservoir simulation techniques. Thus this dissertation aims to develop a compositional model coupled with geomechanics with capabilities to model and understand the complex fluid flow behaviors of multiphase, multi-component fluids in tight oil reservoirs. MSFLOW_COM (Multiphase Subsurface FLOW COMpositional model) has been developed with the capability to model the effects of pore confinement and rock compaction for multiphase fluid flow in tight oil reservoirs. The pore confinement effect is represented by the effect of capillary pressure on vapor-liquid equilibrium (VLE), and modeled with the VLE calculation method in MSFLOW_COM. The fully coupled geomechanical model is developed from the linear elastic theory for a poro-elastic system and formulated in terms of the mean stress. Rock compaction is then described using stress-dependent rock properties, especially stress-dependent permeability. Thus MSFLOW_COM has the capabilities to model the complex fluid flow behaviors of tight oil reservoirs, fully coupled with geomechanics. In addition, MSFLOW_COM is validated against laboratory experimental data, analytical

  20. Some modern notions on oil and gas reservoir production regulation

    SciTech Connect

    Lohrenz, J.; Monash, E.A.

    1980-05-21

    The historic rhetoric of oil and gas reservoir production regulations has been burdened with misconceptions. One was that most reservoirs are rate insensitive. Another was that a reservoir's decline is primarily a function of reservoir mechaism rather than a choice unconstrained by the laws of physics. Relieved of old notions like these, we introduce some modern notions, the most basic being that production regulation should have the purpose of obtaining the highest value from production per irreversible diminution of thermodynamically available energy. The laws of thermodynamics determine the available energy. What then is value. Value may include contributions other than production per se and purely monetary economic outcomes.

  1. Integration of seismic methods with reservoir simulation, Pikes Peak heavy oil field, Saskatchewan

    NASA Astrophysics Data System (ADS)

    Zou, Ying

    The Pikes Peak heavy oil field has been operated by Husky Energy Ltd since 1981. Steam injection has been successfully employed to increase production. Efforts in geophysics and reservoir engineering have been made to improve interpretations in the mapping of reservoir conditions. This dissertation developed tools and a working flow for integrating the analysis of time-lapse seismic surveys with reservoir simulation, and applied them to the Pikes Peak field. Two time-lapse 2D seismic lines acquired in February 1991 and March 2000 in the eastern part of the field were carefully processed to produce wavelet and structure matched final sections. Reservoir simulation based on the field reservoir production history was carried out. It provided independent complementary information for the time-lapse seismic analysis. A rock physics procedure based on Gassmann's equation and Batzle and Wang's empirical relationship successfully linked the reservoir engineering to the seismic method. Based on the resultant seismic models, synthetic seismic sections were generated as the analogy of field seismic sections. The integrated interpretation for the Pikes Peak reservoir drew the following conclusions: The areas with a gas saturation difference, between two compared time steps, have seismic differences. Thicker gas zones correspond with large reflectivity changes on the top of the reservoir and larger traveltime delays in the seismic section. The thin gas zones only induce large reflectivity changes on the top of the reservoir, and do not have large time delays below the reservoir zone. High temperature regions also correlate with areas having large seismic energy differences. High temperature with thick gas (steam and methane) zones may be evidence for steam existence. The seismic differences at locations far from the production zone are due to the lower pressure that causes solution gas to evolve from the oil. Pressure changes propagate much faster (˜20 m in one month) than

  2. Quantitative evaluation of oil-leg potential in gas reservoirs

    SciTech Connect

    Lisk, M.; Krieger, F.W.; Eadington, P.J.; O`Brien, G.W.

    1996-12-31

    Oil bearing fluid inclusions in sandstone represent hidden oil shows. The frequency of quartz grains containing these inclusions (GOI number) reflects maximum palaeo-oil saturation irrespective of the present fluid phase. In this way fluid inclusion data can be used to both identify palaeo-oil columns and to map original oil water contacts (OWC) in wells where oil has been displaced by later gas charge. Studies conducted on gas fields from the North West Shelf of Australia have shown that substantial oil columns were once present. Moreover, detailed GOI mapping has been used to define the location of the original OWC in these reservoirs allowing the height of the palaeo-column to be determined and an estimate to be made of original oil in place (OOIP). At Oliver-1 in the Timor Sea the reservoir is presently filled to spill with a 164m gas, and 14.5m oil, column. GOI mapping has, however, delineated a 96m thick palaeo-oil column within the gas leg. This is almost seven times thicker than the present oil leg which suggests that perhaps 170-190 million barrels of oil were displaced from this structure. In the Pepper gas field in the Carnarvon Basin GOI mapping has demonstrated the presence of a gross palaeo-oil column between 15 and 30 m thick, suggesting that between about 50 and 70 million barrels of oil has been displaced. This is more oil than that reservoired in any of the surrounding oil discoveries, which emphasizes the importance, from an exploration standpoint, of defining these remigration pathways.

  3. Quantitative evaluation of oil-leg potential in gas reservoirs

    SciTech Connect

    Lisk, M.; Krieger, F.W.; Eadington, P.J. ); O'Brien, G.W. )

    1996-01-01

    Oil bearing fluid inclusions in sandstone represent hidden oil shows. The frequency of quartz grains containing these inclusions (GOI number) reflects maximum palaeo-oil saturation irrespective of the present fluid phase. In this way fluid inclusion data can be used to both identify palaeo-oil columns and to map original oil water contacts (OWC) in wells where oil has been displaced by later gas charge. Studies conducted on gas fields from the North West Shelf of Australia have shown that substantial oil columns were once present. Moreover, detailed GOI mapping has been used to define the location of the original OWC in these reservoirs allowing the height of the palaeo-column to be determined and an estimate to be made of original oil in place (OOIP). At Oliver-1 in the Timor Sea the reservoir is presently filled to spill with a 164m gas, and 14.5m oil, column. GOI mapping has, however, delineated a 96m thick palaeo-oil column within the gas leg. This is almost seven times thicker than the present oil leg which suggests that perhaps 170-190 million barrels of oil were displaced from this structure. In the Pepper gas field in the Carnarvon Basin GOI mapping has demonstrated the presence of a gross palaeo-oil column between 15 and 30 m thick, suggesting that between about 50 and 70 million barrels of oil has been displaced. This is more oil than that reservoired in any of the surrounding oil discoveries, which emphasizes the importance, from an exploration standpoint, of defining these remigration pathways.

  4. Reservoir Space Evolution of Volcanic Rocks in Deep Songliao Basin, China

    NASA Astrophysics Data System (ADS)

    Zheng, M.; Wu, X.; Zheng, M.; HU, J.; Wang, S.

    2015-12-01

    Recent years, large amount of natural gas has been discovered in volcanic rock of Lower Crataceous of Songliao basin. Volcanic reservoirs have become one of the important target reservoir types of eastern basin of China. In order to study the volcanic reservoirs, we need to know the main factors controlling the reservoir space. By careful obsercation on volcanic drilling core, casting thin sections and statistical analysis of petrophysical properties of volcanic reservoir in Songliao basin, it can be suggested that the igneous rock reservoir in Yingcheng formation of Lower Crataceous is composed of different rock types, such ad rohylite, rohylitic crystal tuff, autoclastic brecciation lava and so on. There are different reservoirs storage space in in various lithological igneous rocks, but they are mainly composed of primary stoma, secondary solution pores and fractures.The evolution of storage space can be divided into 3 stage: the pramary reservoir space,exogenic leaching process and burial diagenesis.During the evolution process, the reservoir space is effected by secondary minerals, tectonic movement and volcanic hydrothermal solution. The pore of volcanic reservoirs can be partially filled by secondary minerals, but also may be dissoluted by other chemical volcanic hydrothermal solution. Therefore, the favorable places for better-quality volcanic reservoirs are the near-crater facies of vocanic apparatus and dissolution zones on the high position of paleo-structures.

  5. INCREASING WATERFLOOD RESERVES IN THE WILMINGTON OIL FIELD THROUGH IMPROVED RESERVOIR CHARACTERIZATION AND RESERVOIR MANAGEMENT

    SciTech Connect

    Scott Walker; Chris Phillips; Roy Koerner; Don Clarke; Dan Moos; Kwasi Tagbor

    2002-02-28

    This project increased recoverable waterflood reserves in slope and basin reservoirs through improved reservoir characterization and reservoir management. The particular application of this project is in portions of Fault Blocks IV and V of the Wilmington Oil Field, in Long Beach, California, but the approach is widely applicable in slope and basin reservoirs. Transferring technology so that it can be applied in other sections of the Wilmington Field and by operators in other slope and basin reservoirs is a primary component of the project. This project used advanced reservoir characterization tools, including the pulsed acoustic cased-hole logging tool, geologic three-dimensional (3-D) modeling software, and commercially available reservoir management software to identify sands with remaining high oil saturation following waterflood. Production from the identified high oil saturated sands was stimulated by recompleting existing production and injection wells in these sands using conventional means as well as a short radius redrill candidate. Although these reservoirs have been waterflooded over 40 years, researchers have found areas of remaining oil saturation. Areas such as the top sand in the Upper Terminal Zone Fault Block V, the western fault slivers of Upper Terminal Zone Fault Block V, the bottom sands of the Tar Zone Fault Block V, and the eastern edge of Fault Block IV in both the Upper Terminal and Lower Terminal Zones all show significant remaining oil saturation. Each area of interest was uncovered emphasizing a different type of reservoir characterization technique or practice. This was not the original strategy but was necessitated by the different levels of progress in each of the project activities.

  6. Chip-off-the-old-rock: the study of reservoir-relevant geological processes with real-rock micromodels.

    PubMed

    Song, Wen; de Haas, Thomas W; Fadaei, Hossein; Sinton, David

    2014-11-21

    We present a real-rock micromodel approach whereby microfluidic channels are fabricated in a naturally occurring mineral substrate. The method is applied to quantify calcite dissolution which is relevant to oil/gas recovery, CO2 sequestration, and wastewater disposal in carbonate formations - ubiquitous worldwide. The key advantage of this method is the inclusion of both the relevant substrate chemistry (not possible with conventional microfluidics) and real-time pore-scale resolution (not possible with core samples). Here, microchannels are etched into a natural calcite crystal and sealed with a glass slide. The approach is applied to study acidified brine flow through a single channel and a two-dimensional micromodel. The single-channel case conforms roughly to a 1-D analytical description, with crystal orientation influencing the local dissolution rate an additional 25%. The two-dimensional experiments show highly flow-directed dissolution and associated positive feedback wherein acid preferentially invades high conductivity flow paths, resulting in higher dissolution rates ('wormholing'). These experiments demonstrate and validate the approach of microfabricating fluid structures within natural minerals for transport and geochemical studies. More broadly, real-rock microfluidics open the door to a vast array of lab-on-a-chip opportunities in geology, reservoir engineering, and earth sciences. PMID:25236399

  7. Reservoir condition special core analyses and relative permeability measurements on Almond formation and Fontainebleu sandstone rocks

    SciTech Connect

    Maloney, D.

    1993-11-01

    This report describes the results from special core analyses and relative permeability measurements conducted on Almond formation and Fontainebleu sandstone plugs. Almond formation plug tests were performed to evaluate multiphase, steady-state,reservoir-condition relative permeability measurement techniques and to examine the effect of temperature on relative permeability characteristics. Some conclusions from this project are as follows: An increase in temperature appeared to cause an increase in brine relative permeability results for an Almond formation plug compared to room temperature results. The plug was tested using steady-state oil/brine methods. The oil was a low-viscosity, isoparaffinic refined oil. Fontainebleu sandstone rock and fluid flow characteristics were measured and are reported. Most of the relative permeability versus saturation results could be represented by one of two trends -- either a k{sub rx} versus S{sub x} or k{sub rx} versus Sy trend where x and y are fluid phases (gas, oil, or brine). An oil/surfactant-brine steady-state relative permeability test was performed to examine changes in oil/brine relative permeability characteristics from changes in fluid IFTS. It appeared that, while low interfacial tension increased the aqueous phase relative permeability, it had no effect on the oil relative permeability. The BOAST simulator was modified for coreflood simulation. The simulator was useful for examining effects of variations in relative permeability and capillary pressure functions. Coreflood production monitoring and separator interface level measurement techniques were developed using X-ray absorption, weight methods, and RF admittance technologies. The three types of separators should be useful for routine and specialized core analysis applications.

  8. Biological cleaning of soil and reservoirs from oil products

    SciTech Connect

    Zinberg, M.B.; Ivanovskaya, I.B.; Gafarov, N.A.

    1996-12-31

    The production of oil and gas condensate invariably involves environmental hazards: water and soil contamination due to miscellaneous breakdowns of technological equipment and pipeline damage. Among many existing contamination methods biological cleaning has become more popular lately. It took us some years to make investigations and to carry out a number of field tests in order to develop biological methods of cleaning soil and reservoirs from oil and gas condensate products. Our method is based on the use of special biological agents containing various active hydrocarbon oxidizing bacteria. It has been experimentally proved that biological agents of {open_quotes}Devouroil{close_quotes} possess the greatest oxidizing properties. {open_quotes}Devouroil{close_quotes} contains five kinds of hydrocarbon oxidizing bacteria of Pseudomonas, Rodococcus, Candida genera. These bacteria are extracted from natural ecosystems: underground waters, soils, reservoirs. As the agents are grown on oil distillate, they are very destructive to different oil products. We also proved the described microorganisms ability to oxidize sulfate oil and hydrocarbon condensate, which are the most toxic components. For four years our colleagues have been cleaning soil and reservoirs contaminated with oil, black oil, gas condensate and other products of hydrocarbon origin. This method was used to treat different kinds of soil and ground (grass and arable land, swamp and forest) in actual hazardous situations involving oil and gas condensate spills. Besides it was successfully applied to clean sludge storage which had been filled with oil process sewage for several years.

  9. Oil source rocks in the Adiyaman area, southeast Turkey

    NASA Astrophysics Data System (ADS)

    Soylu, Cengiz

    In the Adiyaman area, southeast Turkey, two carbonate source rock units, the Karababa-A Member and the Karabogaz Formation, are identified. The maturity levels of the source rock units increase towards the north and the west. Both the Karababa-A Member and the Karabogaz Formation are good to excellent oil-source rocks with widespread "kitchen areas".

  10. IMPROVING CO2 EFFICIENCY FOR RECOVERING OIL IN HETEROGENEOUS RESERVOIRS

    SciTech Connect

    Reid B. Grigg; Robert K. Svec

    2002-12-20

    This document is the First Annual Report for the U.S. Department of Energy under contract No., a three-year contract entitled: ''Improving CO{sub 2} Efficiency for Recovering Oil in Heterogeneous Reservoirs.'' The research improved our knowledge and understanding of CO{sub 2} flooding and includes work in the areas of injectivity and mobility control. The bulk of this work has been performed by the New Mexico Petroleum Recovery Research Center, a research division of New Mexico Institute of Mining and Technology. This report covers the reporting period of September 28, 2001 and September 27, 2002. Injectivity continues to be a concern to the industry. During this period we have contacted most of the CO{sub 2} operators in the Permian Basin and talked again about their problems in this area. This report has a summary of what we found. It is a given that carbonate mineral dissolution and deposition occur in a formation in geologic time and are expected to some degree in carbon dioxide (CO{sub 2}) floods. Water-alternating-gas (WAG) core flood experiments conducted on limestone and dolomite core plugs confirm that these processes can occur over relatively short time periods (hours to days) and in close proximity to each other. Results from laboratory CO{sub 2}-brine flow experiments performed in rock core were used to calibrate a reactive transport simulator. The calibrated model is being used to estimate in situ effects of a range of possible sequestration options in depleted oil/gas reservoirs. The code applied in this study is a combination of the well known TOUGH2 simulator, for coupled groundwater/brine and heat flow, with the chemistry code TRANS for chemically reactive transport. Variability in response among rock types suggests that CO{sub 2} injection will induce ranges of transient and spatially dependent changes in intrinsic rock permeability and porosity. Determining the effect of matrix changes on CO{sub 2} mobility is crucial in evaluating the efficacy

  11. Interaction between Fingering and Heterogeneity during Viscous Oil Recovery in Carbonate Rocks (Invited)

    NASA Astrophysics Data System (ADS)

    Mohanty, K. K.; Doorwar, S.

    2013-12-01

    Due to the fast depleting conventional oil reserves, research in the field of petroleum engineering has shifted focus towards unconventional (viscous and heavy) oils. Many of the viscous oil reserves are in carbonate rocks. Thermal methods in carbonate formations are complicated by mineral dissolution and precipitation. Non-thermal methods should be developed for viscous oils in carbonates. In viscous oil reservoirs, oil recovery due to water flood is low due to viscous fingering. Polymer flood is an attractive process, but the timing of the polymer flood start is an important parameter in the optimization of polymer floods. Vuggy Silurian dolomite cores were saturated with formation brine and reservoir oil (150-200 cp). They were then displaced by either a polymeric solution (secondary polymer flood) or brine followed the polymeric solution (tertiary polymer flood). The amount of brine injection was varied as a parameter. Oil recovery and pressure drop was monitored as a function of the starting point of the polymer flood. To visualize the displacement at the pore-scale, two types of micromodels were prepared: one with isolated heterogeneity and the other with connected heterogeneity. The wettability of the micromodels was either water-wet or oil-wet. The micromodels were saturated with formation brine and oil. A series of water flood and polymer flood was conducted to identify the mechanism of fluid flow. Dolomite corefloods show that a tertiary polymer flood following a secondary water flood recovers a substantial amount of oil unlike what is observed in typical sandstone cores with light oil. The tertiary oil recovery plus the secondary waterflood recovery can exceed the oil recovery in a secondary polymer flood in dolomite-viscous oil-brine system. These experiments were repeated in a Berea-oil-brine system which showed that the oil recovered in the secondary polymer flood was similar to the cumulative oil recovery in the tertiary polymer flood. The high

  12. Basement reservoir in Zeit Bay oil field, Gulf of Suez

    SciTech Connect

    Zahran, I.; Askary, S.

    1988-02-01

    Fractured basement, one of the most important reservoirs of Zeit Bay field, contains nearly one-third of oil in place of the field. The flow rates per well vary from 700 to 9,000 BOPD. Due to its well-established production potential, 60% of the wells for the development of the field were drilled down to basement. The Zeit Bay basement consists of granitic rocks of pegmatitic to coarse porphyritic texture and has equal proportions of alkali feldspars. Dykes of various compositions are present, traversing the granite at different intervals. Dykes include aplite, microsyenite, diabase and lamprophyre. The last two pertain to the post-granitic dykes of late Proterozoic age. The main granitic pluton is related to one of the final stages of the tectonic-magmatic cycle of the Arabo-Nubian shield. The Zeit Bay area was a significant paleohigh until the Miocene, hence its structural picture is very complicated due to the impact of different tectonic movements from the late Precambrian to Cenozoic. The resulting structural elements were carefully investigated and statistically analyzed to decipher the influence of various tectonic events. The presence of high porosity in some intervals and low porosity in others could be tied to the presence of new fractures and the nature of cementing minerals. The relation of mineralized fractures and their depths lead to zonation of porous layers in the granitic pluton. Diagenetic processes on the granitic body and the alteration/resedimentation of the diagenetic products controlled the magnitude and amplitude of the porosity layers. A model has been constructed to illustrate the changes in the primary rock texture and structure with sequential diagenetic processes, taking into consideration the fracture distribution and their opening affinities as related to their depths.

  13. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect

    Scott Hara

    2001-05-07

    The project involves using advanced reservoir characterization and thermal production technologies to improve thermal recovery techniques and lower operating and capital costs in a slope and basin clastic (SBC) reservoir in the Wilmington field, Los Angeles Co., CA. Through September 2000, project work has been completed on the following activities: data preparation; basic reservoir engineering; developing a deterministic three dimensional (3-D) geologic model, a 3-D deterministic reservoir simulation model and a rock-log model; well drilling and completions; and surface facilities on the Fault Block II-A Tar Zone (Tar II-A). Work is continuing on improving core analysis techniques, final reservoir tracer work, operational work and research studies to prevent thermal-related formation compaction in the Tar II-A steamflood area, and operational work on the Tar V steamflood pilot and Tar II-A post steamflood projects. Work was discontinued on the stochastic geologic model and developing a 3-D stochastic thermal reservoir simulation model of the Tar II-A Zone so the project team could use the 3-D deterministic reservoir simulation model to provide alternatives for the Tar II-A post steamflood operations and shale compaction studies. The project team spent the fourth quarter 2000 performing well work and reservoir surveillance on the Tar II-A post-steamflood project and the Tar V horizontal well steamflood pilot. Expanding thermal recovery operations to other sections of the Wilmington Oil Field, including the Tar V horizontal well pilot steamflood project, is a critical part of the City of Long Beach and Tidelands Oil Production Company's development strategy for the field. The current steamflood operations in the Tar V pilot are economical, but recent performance is below projections because of wellbore mechanical limitations that are being evaluated.

  14. Potential non-tertiary additional oil recovery from heterogeneous submarine-fan reservoirs, Spraberry-Benedum field, Midland basin, Texas

    SciTech Connect

    Guevara, E.H.; Worrall, J.G.; Walter, T.

    1987-05-01

    The Spraberry-Benedum field is a multipay, solution-gas drive, combined structural-stratigraphic trap. It contains approximately 200 million bbl of original oil in place and has been waterflooded since 1967. Producing intervals are in the Spraberry formation (Permian, Leonardian), which in this area consists of mixed-sediment submarine-fan deposits (upper and lower Spraberry) and basin-plain facies (middle Spraberry). Principal oil reservoirs, with 12% average porosity and permeabilities of less than 1 md, occur in the lower and upper Spraberry. They consist of naturally fractured, very fine-grained sandstones and coarse siltstones of braided and meandering, peripheral channels and associated outer fan facies. Complex facies architecture results in highly heterogeneous reservoirs. Oil accumulations are layered because basin-plain shales vertically separate submarine-fan reservoirs, and they are laterally compartmentalized due to the channelization of reservoir rocks. Production trends locally parallel to facies trends indicate that recovery is influenced by reservoir stratigraphy. Well locations, based only on structural position and fracture orientation, commonly do not conform to the axes of belts of greatest sandstone-siltstone thickness, which contain the best reservoirs. Furthermore, completion intervals do not systematically tap both lower and upper Spraberry reservoirs. Ultimate recovery will be improved by aggressive development programs aimed at producing from poorly drained traps created by reservoir heterogeneities. Recompletion and deepening of wells, strategic infill drilling, and injection patterns in such programs should be based on detailed reservoir stratigraphy, in addition to structure and fracture data.

  15. Diagenesis and reservoir quality of Devonian reservoir rocks of Nevada, Blackburn, and Grant Canyon fields

    SciTech Connect

    Bereskin, S.R.; Little, T.M.; Lord, G.D.

    1989-03-01

    Devonian carbonate rocks of the Basin and Range province are largely responsible for the current enthusiastic search for petroleum in Nevada. Severely dolomitized Givetian and Frasnian rocks, given various formational names, contain numerous marine intertidal to sublittoral facies that are cyclically interbedded. Exploration complications can arise from physical and chemical diagenesis; however, recent advancements in petrology and petrophysics allow evaluation and behavior predictability of fractured reservoirs from the Blackburn 16 and Grant Canyon 4 wells. Complex diagenesis and deformation are common to the hydrocarbon-producing intervals and included numerous cementation, dissolution, and fracturing events. Abundant fractures are dominantly nonpenetrative, partially open types, and such closely spaced fractures resulted from two episodes represented by conjugate sets in each case. Dissolution porosity associated with leached Amphipora is also present. Silica, barite, and kaolinite are the most volumetrically important authigenic fracture-filling minerals. Fluorescence microscopy has revealed shallow burial diagenetic events that are masked by the more severe overprint of solution(.) brecciation of tectonically inspired diagenesis.

  16. Research on improved and enhanced oil recovery in Illinois through reservoir characterization. [Quarterly technical report], December 28, 1991--March 28, 1992

    SciTech Connect

    Oltz, D.F.

    1992-04-01

    This project will provide information that can maximize hydrocarbon production minimize formation damage and stimulate new production in Illinois. Such information includes definition of hydrocarbon resources, characterization of hydrocarbon reservoirs, and the implementation of methods that will improve hydrocarbon extractive technology. Increased understanding of reservoir heterogeneities that affect oil recovery can aid in identifying producible resources. The transfer of technology to industry and the general public is a significant component of the program. The project is designed to examine selected subsurface oil reservoirs in Illinois. Scientists use advanced scientific techniques to gain a better understanding of reservoir components and behavior and address ways of potentially increasing the amount of recoverable oil. Initial production rates for wells in the Illinois Basin commonly decline quite rapidly and as much as 60 percent of the oil in place can be unrecoverable using standard operating procedures. Heterogeneities (geological differences in reservoir make-up) affect a reservoir`s capability to release fluids. By-passed mobile and immobile oil remain in the reservoir. To learn how to get more of the oil out of reservoirs, the ISGS is studying the nature of reservoir rock heterogeneities and their control on the distribution and production of by-passed, mobile oil.

  17. Sediment discharge in Rock Creek and the effect of sedimentation rate on the proposed Rock Creek Reservoir, northwestern Colorado

    USGS Publications Warehouse

    Butler, D.L.

    1987-01-01

    Sediment data collected from 1976 to 1985 and stream discharge data collected from 1952 to 1980 at gaging station 09060500, Rock Creek near Toponas, Colorado, were used to determine total sediment discharge into the proposed Rock Creek Reservoir. Suspended sediment discharge and bedload discharge were related to stream discharge by using logarithmic regression relations. Mean annual suspended sediment discharge was estimated to be 309 tons/yr, and mean annual bedload discharge was estimated to be 428 tons/yr in Rock Creek at the Toponas gaging station for the 1953 through 1980 water years. The mean annual total sediment discharge into the proposed reservoir was estimated to be 768 tons/yr, which includes 10% addition to the suspended sediment discharge calculated for the Toponas gaging station to account for suspended sediment discharge from Horse Creek. This rate of mean annual total sediment discharge would decrease the long-term water storage capacity of the proposed reservoir by < 1% after 100 years. Suspended sediment discharge/unit-drainage-basin area at gaging station 09060550, Rock Creek at Crater, located about 5 mi downstream for the proposed reservoir site, was equivalent to suspended-sediment discharge/unit-drainage-basin area at the Toponas gaging station during 1985. Long-term sediment data collection at the Crater gaging station could be used for detecting changes in suspended sediment discharge in Rock Creek at the proposed reservoir site. (Author 's abstract)

  18. Isotopic insights into microbial sulfur cycling in oil reservoirs

    PubMed Central

    Hubbard, Christopher G.; Cheng, Yiwei; Engelbrekston, Anna; Druhan, Jennifer L.; Li, Li; Ajo-Franklin, Jonathan B.; Coates, John D.; Conrad, Mark E.

    2014-01-01

    Microbial sulfate reduction in oil reservoirs (biosouring) is often associated with secondary oil production where seawater containing high sulfate concentrations (~28 mM) is injected into a reservoir to maintain pressure and displace oil. The sulfide generated from biosouring can cause corrosion of infrastructure, health exposure risks, and higher production costs. Isotope monitoring is a promising approach for understanding microbial sulfur cycling in reservoirs, enabling early detection of biosouring, and understanding the impact of souring. Microbial sulfate reduction is known to result in large shifts in the sulfur and oxygen isotope compositions of the residual sulfate, which can be distinguished from other processes that may be occurring in oil reservoirs, such as precipitation of sulfate and sulfide minerals. Key to the success of this method is using the appropriate isotopic fractionation factors for the conditions and processes being monitored. For a set of batch incubation experiments using a mixed microbial culture with crude oil as the electron donor, we measured a sulfur fractionation factor for sulfate reduction of −30‰. We have incorporated this result into a simplified 1D reservoir reactive transport model to highlight how isotopes can help discriminate between biotic and abiotic processes affecting sulfate and sulfide concentrations. Modeling results suggest that monitoring sulfate isotopes can provide an early indication of souring for reservoirs with reactive iron minerals that can remove the produced sulfide, especially when sulfate reduction occurs in the mixing zone between formation waters (FW) containing elevated concentrations of volatile fatty acids (VFAs) and injection water (IW) containing elevated sulfate. In addition, we examine the role of reservoir thermal, geochemical, hydrological, operational and microbiological conditions in determining microbial souring dynamics and hence the anticipated isotopic signatures. PMID:25285094

  19. A rock-physical modeling method for carbonate reservoirs at seismic scale

    NASA Astrophysics Data System (ADS)

    Li, Jing-Ye; Chen, Xiao-Hong

    2013-03-01

    Strong heterogeneity and complex pore systems of carbonate reservoir rock make its rock physics model building and fluid substitution difficult and complex. However, rock physics models connect reservoir parameters with seismic parameters and fluid substitution is the most effective tool for reservoir prediction and quantitative characterization. On the basis of analyzing complex carbonate reservoir pore structures and heterogeneity at seismic scale, we use the gridding method to divide carbonate rock into homogeneous blocks with independent rock parameters and calculate the elastic moduli of dry rock units step by step using different rock physics models based on pore origin and structural feature. Then, the elastic moduli of rocks saturated with different fluids are obtained using fluid substitution based on different pore connectivity. Based on the calculated elastic moduli of rock units, the Hashin-Shtrikman-Walpole elastic boundary theory is adopted to calculate the carbonate elastic parameters at seismic scale. The calculation and analysis of carbonate models with different combinations of pore types demonstrate the effects of pore type on rock elastic parameters. The simulated result is consistent with our knowledge of real data.

  20. Imaging techniques applied to the study of fluids in porous media. Scaling up in Class 1 reservoir type rock

    SciTech Connect

    Tomutsa, L.; Brinkmeyer, A.; Doughty, D.

    1993-04-01

    A synergistic rock characterization methodology has been developed. It derives reservoir engineering parameters from X-ray tomography (CT) scanning, computer assisted petrographic image analysis, minipermeameter measurements, and nuclear magnetic resonance imaging (NMRI). This rock characterization methodology is used to investigate the effect of small-scale rock heterogeneity on oil distribution and recovery. It is also used to investigate the applicability of imaging technologies to the development of scaleup procedures from core plug to whole core, by comparing the results of detailed simulations with the images ofthe fluid distributions observed by CT scanning. By using the rock and fluid detailed data generated by imaging technology describe, one can verify directly, in the laboratory, various scaling up techniques. Asan example, realizations of rock properties statistically and spatially compatible with the observed values are generated by one of the various stochastic methods available (fuming bands) and are used as simulator input. The simulation results were compared with both the simulation results using the true rock properties and the fluid distributions observed by CT. Conclusions regarding the effect of the various permeability models on waterflood oil recovery were formulated.

  1. Potential CO2 Sequestration in Oil Field Reservoirs: Baseline Mineralogy and Natural Diagenesis, Kern County, California

    NASA Astrophysics Data System (ADS)

    Horton, R. A.; Kaess, A. B.; Nguyen, D. T.; Caffee, S. E.; Olabise, O. E.

    2015-12-01

    Depleted oil fields have been suggested as potential sites for sequestration of CO2 generated from the burning of hydrocarbons. However, to be effective for removing CO2 from the atmosphere, the injected CO2 must remain within the reservoir. The role of atmospheric CO2 in rock weathering is well known and a growing body of experimental work indicates that under reservoir conditions supercritical CO2 also reacts with sedimentary rocks. In order to predict the behavior of injected CO2 in a given reservoir, detailed knowledge of the mineralogy is required. In addition, post-injection monitoring may include analyzing core samples to examine interactions between reservoir rocks and the CO2. Thus, documentation of the natural diagenetic processes within the reservoir is necessary so that changes caused by reactions with CO2 can be recognized. Kern County, California has been a major petroleum producing area for over a century and has three oil fields that have been identified as potential sites for CO2 sequestration. Two of these, Rio Bravo-Greeley and McKittrick, have no previously published mineralogic studies. Samples from these (and nearby Wasco) oil fields were studied using transmitted-light petrography and scanning electron microscopy. At Rio Bravo-Greeley-Wasco, Kreyenhagen (Eocene) and Vedder (Oligocene) sandstones are mainly arkosic arenites with only small amounts of volcanic rock fragments. Detrital feldspars exhibit wide compositional ranges (up to Or75Ab25 & Ab50An50). Diagenesis has greatly altered the rocks. There are significant amounts of relatively pure authigenic K-feldspar and albite. Small amounts of authigenic quartz, calcite, dolomite, ankerite, kaolinite, illite/smectite, chlorite, zeolite, and pyrite are present. Plagioclase has been preferentially dissolved, with andesine more susceptible than oligoclase. Al3+ has been exported from the sandstones. At McKittrick, Temblor sandstones (Oligocene-Miocene) contain up to 33% volcanic rock fragments

  2. Multigrid Methods for Fully Implicit Oil Reservoir Simulation

    NASA Technical Reports Server (NTRS)

    Molenaar, J.

    1996-01-01

    In this paper we consider the simultaneous flow of oil and water in reservoir rock. This displacement process is modeled by two basic equations: the material balance or continuity equations and the equation of motion (Darcy's law). For the numerical solution of this system of nonlinear partial differential equations there are two approaches: the fully implicit or simultaneous solution method and the sequential solution method. In the sequential solution method the system of partial differential equations is manipulated to give an elliptic pressure equation and a hyperbolic (or parabolic) saturation equation. In the IMPES approach the pressure equation is first solved, using values for the saturation from the previous time level. Next the saturations are updated by some explicit time stepping method; this implies that the method is only conditionally stable. For the numerical solution of the linear, elliptic pressure equation multigrid methods have become an accepted technique. On the other hand, the fully implicit method is unconditionally stable, but it has the disadvantage that in every time step a large system of nonlinear algebraic equations has to be solved. The most time-consuming part of any fully implicit reservoir simulator is the solution of this large system of equations. Usually this is done by Newton's method. The resulting systems of linear equations are then either solved by a direct method or by some conjugate gradient type method. In this paper we consider the possibility of applying multigrid methods for the iterative solution of the systems of nonlinear equations. There are two ways of using multigrid for this job: either we use a nonlinear multigrid method or we use a linear multigrid method to deal with the linear systems that arise in Newton's method. So far only a few authors have reported on the use of multigrid methods for fully implicit simulations. Two-level FAS algorithm is presented for the black-oil equations, and linear multigrid for

  3. Relative permeability and trapping of CO2 and water in sandstone rocks at reservoir conditions

    NASA Astrophysics Data System (ADS)

    Krevor, Samuel C. M.; Pini, Ronny; Zuo, Lin; Benson, Sally M.

    2012-02-01

    We report the results of an experimental investigation into the multiphase flow properties of CO2 and water in four distinct sandstone rocks: a Berea sandstone and three reservoir rocks from formations into which CO2 injection is either currently taking place or is planned. Drainage relative permeability and residual gas saturations were measured at 50°C and 9 MPa pore pressure using the steady state method in a horizontal core flooding apparatus with fluid distributions observed using x-ray computed tomography. Absolute permeability, capillary pressure curves, and petrological studies were performed on each sample. Relative permeability in the four samples is consistent with general characteristics of drainage in strongly water-wet rocks. Measurements in the Berea sample are also consistent with past measurements in Berea sandstones using both CO2/brine and oil/water fluid systems. Maximum observed saturations and permeabilities are limited by the capillary pressure that can be achieved in the experiment and do not represent endpoint values. It is likely that maximum saturations observed in other studies are limited in the same way and there is no indication that low endpoint relative permeabilities are a characteristic of the CO2/water system. Residual trapping in three of the rocks is consistent with trapping in strongly water-wet systems, and the results from the Berea sample are again consistent with observations in past studies. This confirms that residual trapping can play a major role in the immobilization of CO2 injected into the subsurface. In the Mt. Simon sandstone, a nonmonotonic relationship between initial and residual CO2 saturations is indicative of a rock that is mixed or intermediate wet, and further investigations should be performed to establish the wetting properties of illite-rich rocks. The combined results suggest that the petrophysical properties of the multiphase flow of CO2/water through siliciclastic rocks is for the most part typical

  4. Hydro-mechanically coupled modelling of deep-seated rock slides in the surroundings of reservoirs

    NASA Astrophysics Data System (ADS)

    Lechner, Heidrun; Preh, Alexander; Zangerl, Christian

    2016-04-01

    In order to enhance the understanding of the behaviour of deep-seated rock slides in the surroundings of large dam reservoirs, this study concentrates on failure mechanisms, deformation processes and the ability of self-stabilisation of rock slides influenced by reservoirs. Particular focus is put on internal rock mass deformations, progressive topographical slope changes due to reservoir impoundment and shear displacements along the basal shear zone in relation to its shear strength properties. In this study, a two-dimensional numerical rock slide model is designed by means of the Universal Distinct Element Code UDEC and investigated concerning different groundwater flow scenarios. These include: (i) a completely drained rock slide model, (ii) a model with fully saturated rock mass below an inclined groundwater table and (iii) a saturated groundwater model with a reservoir at the slope toe. Slope displacements initiate when the shear strength properties of the basal shear zone are at or below the critical parameters for the limit-equilibrium state and continue until a numerical equilibrium is reached due to deformation- and displacement-based geometrical changes. The study focuses on the influence of a reservoir at the toe of a rock slide and tries to evaluate the degree of displacement which is needed for a re-stabilisation in relation to the geometrical characteristics of the rock slide. Besides, challenges and limitations of applied distinct element methods to simulate large strain and displacements of deep-seated rock slides are discussed. The ongoing study will help to understand the deformation behaviour of deep-seated pre-existing rock slides in fractured rock mass during initial impounding and will be part of a hazard assessment for large reservoirs.

  5. Source rock contributions to the Lower Cretaceous heavy oil accumulations in Alberta: a basin modeling study

    USGS Publications Warehouse

    Berbesi, Luiyin Alejandro; di Primio, Rolando; Anka, Zahie; Horsfield, Brian; Higley, Debra K.

    2012-01-01

    The origin of the immense oil sand deposits in Lower Cretaceous reservoirs of the Western Canada sedimentary basin is still a matter of debate, specifically with respect to the original in-place volumes and contributing source rocks. In this study, the contributions from the main source rocks were addressed using a three-dimensional petroleum system model calibrated to well data. A sensitivity analysis of source rock definition was performed in the case of the two main contributors, which are the Lower Jurassic Gordondale Member of the Fernie Group and the Upper Devonian–Lower Mississippian Exshaw Formation. This sensitivity analysis included variations of assigned total organic carbon and hydrogen index for both source intervals, and in the case of the Exshaw Formation, variations of thickness in areas beneath the Rocky Mountains were also considered. All of the modeled source rocks reached the early or main oil generation stages by 60 Ma, before the onset of the Laramide orogeny. Reconstructed oil accumulations were initially modest because of limited trapping efficiency. This was improved by defining lateral stratigraphic seals within the carrier system. An additional sealing effect by biodegraded oil may have hindered the migration of petroleum in the northern areas, but not to the east of Athabasca. In the latter case, the main trapping controls are dominantly stratigraphic and structural. Our model, based on available data, identifies the Gordondale source rock as the contributor of more than 54% of the oil in the Athabasca and Peace River accumulations, followed by minor amounts from Exshaw (15%) and other Devonian to Lower Jurassic source rocks. The proposed strong contribution of petroleum from the Exshaw Formation source rock to the Athabasca oil sands is only reproduced by assuming 25 m (82 ft) of mature Exshaw in the kitchen areas, with original total organic carbon of 9% or more.

  6. Oil reservoirs in grainstone aprons around Bryozoan Mounds, Upper Harrodsburg Limestone, Mississippian, Illinois Basin

    SciTech Connect

    Jobe, H.; Saller, A.

    1995-06-01

    Several oil pools have been discovered recently in the upper Harrodsburg Limestone (middle Mississippian) of the Illinois basin. A depositional model for bryozoan mound complexes has allowed more successful exploration and development in this play. In the Johnsonville area of Wayne County, Illinois, three lithofacies are dominant in the upper Harrodsburg: (1) bryozoan boundstones, (2) bryozoan grainstones, and (3) fossiliferous wackestones. Bryozoan boundstones occur as discontinuous mounds and have low porosity. Although bryozoan boundstones are not the main reservoir lithofacies, they are important because they influenced the distribution of bryozoan grainstones and existing structure. Bryozoan grainstones have intergranular porosity and are the main reservoir rock. Bryozoan fragments derived from bryozoan boundstone mounds were concentrated in grainstones around the mounds. Fossiliferous wackestones are not porous and form vertical and lateral seals for upper Harrodsburg grainstones. Fossiliferous wackestones were deposited in deeper water adjacent to bryozoan grainstone aprons, and above grainstones and boundstones after the mounds were drowned. Upper Harrodsburg oil reservoirs occur where grainstone aprons are structurally high. The Harrodsburg is a good example of a carbonate mound system where boundstone cores are not porous, but adjacent grainstones are porous. Primary recovery in these upper Harrodsburg reservoirs is improved by strong pressure support from an aquifer in the lower Harrodsburg. Unfortunately, oil production is commonly decreased by water encroaching from that underlying aquifer.

  7. Characterization of oil and gas reservoir heterogeneity; Final report, November 1, 1989--June 30, 1993

    SciTech Connect

    Sharma, G.D.

    1993-09-01

    The Alaskan North Slope comprises one of the Nation`s and the world`s most prolific oil province. Original oil in place (OOIP) is estimated at nearly 70 BBL (Kamath and Sharma, 1986). Generalized reservoir descriptions have been completed by the University of Alaska`s Petroleum Development Laboratory over North Slope`s major fields. These fields include West Sak (20 BBL OOIP), Ugnu (15 BBL OOIP), Prudhoe Bay (23 BBL OOIP), Kuparuk (5.5 BBL OOIP), Milne Point (3 BBL OOIP), and Endicott (1 BBL OOIP). Reservoir description has included the acquisition of open hole log data from the Alaska Oil and Gas Conservation Commission (AOGCC), computerized well log analysis using state-of-the-art computers, and integration of geologic and logging data. The studies pertaining to fluid characterization described in this report include: experimental study of asphaltene precipitation for enriched gases, CO{sup 2} and West Sak crude system, modeling of asphaltene equilibria including homogeneous as well as polydispersed thermodynamic models, effect of asphaltene deposition on rock-fluid properties, fluid properties of some Alaskan north slope reservoirs. Finally, the last chapter summarizes the reservoir heterogeneity classification system for TORIS and TORIS database.

  8. Investigation of oil recovery improvement by coupling an interfacial tension agent and a mobility control agent in light oil reservoirs. Final report

    SciTech Connect

    Pitts, M.

    1995-12-01

    This research studied the oil recovery potential of flooding light oil reservoirs by combining interfacial tension reducing agent(s) with a mobility control agent. The specific objectives were: To define the mechanisms and limitations of co-injecting interfacial tension reduction agent(s) and a mobility control agent to recover incremental oil. Specifically, the study focused on the fluid-fluid and fluid-rock interactions. To evaluate the economics of the combination technology and investigate methods to make the process more profitable. Specific areas of study were to evaluate different chemical concentration tapers and the volume of chemical injection required to give optimal oil recovery.

  9. Western Greece unconventional hydrocarbon potential from oil shale and shale gas reservoirs

    NASA Astrophysics Data System (ADS)

    Karakitsios, Vasileios; Agiadi, Konstantina

    2013-04-01

    It is clear that we are gradually running out of new sedimentary basins to explore for conventional oil and gas and that the reserves of conventional oil, which can be produced cheaply, are limited. This is the reason why several major oil companies invest in what are often called unconventional hydrocarbons: mainly oil shales, heavy oil, tar sand and shale gas. In western Greece exist important oil and gas shale reservoirs which must be added to its hydrocarbon potential1,2. Regarding oil shales, Western Greece presents significant underground immature, or close to the early maturation stage, source rocks with black shale composition. These source rock oils may be produced by applying an in-situ conversion process (ICP). A modern technology, yet unproven at a commercial scale, is the thermally conductive in-situ conversion technology, developed by Shell3. Since most of western Greece source rocks are black shales with high organic content, those, which are immature or close to the maturity limit have sufficient thickness and are located below 1500 meters depth, may be converted artificially by in situ pyrolysis. In western Greece, there are several extensive areas with these characteristics, which may be subject of exploitation in the future2. Shale gas reservoirs in Western Greece are quite possibly present in all areas where shales occur below the ground-water level, with significant extent and organic matter content greater than 1%, and during their geological history, were found under conditions corresponding to the gas window (generally at depths over 5,000 to 6,000m). Western Greece contains argillaceous source rocks, found within the gas window, from which shale gas may be produced and consequently these rocks represent exploitable shale gas reservoirs. Considering the inevitable increase in crude oil prices, it is expected that at some point soon Western Greece shales will most probably be targeted. Exploration for conventional petroleum reservoirs

  10. Improving the potential to produce oil from naturally fractured reservoirs

    SciTech Connect

    Perez, J.M.; Nighswander, J.; Berg, R.R.; Friedman, M.; Gangi, A.F.; Poston, S.W.

    1994-12-31

    A multi-phase effort that involved geological, geophysical, and petroleum engineering studies yielded an improved understanding of naturally fractured reservoirs and potential manners to improve the incidence of oil production from such reservoirs. Maps of fracture traces on bedding planes in the Austin Chalk outcrops showed organized trends of the fracture development and a hierarchical nature within the complete fracture system. Vertical Seismic Profile, VSP data has been used to estimate fracture orientation from shear-wave splitting. Well log responses in Austin Chalk wells have shown to be a reliable indicator of organic maturity. Well logs have also been used to calculate average resistivity of producing zones and to correlate resistivity with oil saturation and therefore with producing potential. Additionally, the use of carbonates water imbibition displacement processes has shown encouraging results of accelerating and increasing oil recovery of oil which do not have appreciable asphaltene contents.

  11. 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

  12. Characterization of oil and gas reservoir heterogeneity. Final report

    SciTech Connect

    Tyler, N.; Barton, M.D.; Bebout, D.G.; Fisher, R.S.; Grigsby, J.D.; Guevara, E.; Holtz, M.; Kerans, C.; Nance, H.S.; Levey, R.A.

    1992-10-01

    Research described In this report addresses the internal architecture of two specific reservoir types: restricted-platform carbonates and fluvial-deltaic sandstones. Together, these two reservoir types contain more than two-thirds of the unrecovered mobile oil remaining ill Texas. The approach followed in this study was to develop a strong understanding of the styles of heterogeneity of these reservoir types based on a detailed outcrop description and a translation of these findings into optimized recovery strategies in select subsurface analogs. Research targeted Grayburg Formation restricted-platform carbonate outcrops along the Algerita Escarpment and In Stone Canyon In southeastern New Mexico and Ferron deltaic sandstones in central Utah as analogs for the North Foster (Grayburg) and Lake Creek (Wilcox) units, respectively. In both settings, sequence-stratigraphic style profoundly influenced between-well architectural fabric and permeability structure. It is concluded that reservoirs of different depositional origins can therefore be categorized Into a ``heterogeneity matrix`` based on varying intensity of vertical and lateral heterogeneity. The utility of the matrix is that it allows prediction of the nature and location of remaining mobile oil. Highly stratified reservoirs such as the Grayburg, for example, will contain a large proportion of vertically bypassed oil; thus, an appropriate recovery strategy will be waterflood optimization and profile modification. Laterally heterogeneous reservoirs such as deltaic distributary systems would benefit from targeted infill drilling (possibly with horizontal wells) and improved areal sweep efficiency. Potential for advanced recovery of remaining mobile oil through heterogeneity-based advanced secondary recovery strategies In Texas is projected to be an Incremental 16 Bbbl. In the Lower 48 States this target may be as much as 45 Bbbl at low to moderate oil prices over the near- to mid-term.

  13. Experiences with linear solvers for oil reservoir simulation problems

    SciTech Connect

    Joubert, W.; Janardhan, R.; Biswas, D.; Carey, G.

    1996-12-31

    This talk will focus on practical experiences with iterative linear solver algorithms used in conjunction with Amoco Production Company`s Falcon oil reservoir simulation code. The goal of this study is to determine the best linear solver algorithms for these types of problems. The results of numerical experiments will be presented.

  14. Northeast Kansas well tests oil, gas possibilities in Precambrian rocks

    USGS Publications Warehouse

    Merriam, D.F.; Newell, K.D.; Doveton, J.H.; Magnuson, L.M.; Lollar, B.S.; Waggoner, W.M.

    2007-01-01

    Tests for oil and gas prospects in Precambrian rocks in Northeast Kansas is currently being undertaken by WTW Operating LLC. It drilled in late 2005 the no.1 Wilson well with a depth of 5,772ft, 1,826ft into the Precambrian basement on a venture testing the possibility of oil and gas in the crystalline rocks. The basin extends northeast into Nebraska and Iowa and is a shallow cratonic basin filled with Paleozoic segments. The rocks have been previously though as not a potential for oil and gas due to the rocks' crystalline and nonporous character with the exception of the Midcontinent rift system (MRS). Later, though, small quantities of oil have been produced on the Central Kansas uplift from granite wash while the wells also produced low-Btu with swabbing operations. The recovered gas contained considerable nonflammable components of nitrogen, carbon dioxide and helium which equates to a low btu content of 283.

  15. Laser cleaning of oil spill on coastal rocks

    NASA Astrophysics Data System (ADS)

    Kittiboonanan, Phumipat; Rattanarojpan, Jidapa; Ratanavis, Amarin

    2015-07-01

    In recent years, oil spills have become a significant environmental problem in Thailand. This paper presents a laser treatment for controlled-clean up oil spill from coastal rocks. The cleaning of various types of coastal rocks polluted by the spill was investigated by using a quasi CW diode laser operating at 808 nm. The laser power was attempted from 1 W to 70 W. The result is shown to lead to the laser removal of oil spill, without damaging the underlying rocks. In addition, the cleaning efficiency is evaluated using an optical microscope. This study shows that the laser technology would provide an attractive alternative to current cleaning methods to remove oil spill from coastal rocks.

  16. Investigation of oil recovery improvement by coupling an interfacial tension agent and a mobility control agent in light oil reservoirs. Technical progress report, October--December 1994

    SciTech Connect

    Pitts, M.J.

    1994-01-01

    The study will investigate two major areas concerning co-injecting an interfacial tension reduction agent(s) and a mobility control agent into petroleum reservoirs. The first will consist of defining the mechanisms of interaction of an alkaline agent, a surfactant, and a polymer on a fluid-fluid and a fluid-rock basis. The second is the improvement of the economics of the combined technology. This report examines effect of rock type on oil recovery by an alkaline-surfactant-polymer solutions. This report also begins a series of evaluations to improve the economics of alkaline-surfactant-polymer oil recovery.

  17. Heavy oil reservoirs recoverable by thermal technology. Annual report

    SciTech Connect

    Kujawa, P.

    1981-02-01

    This volume contains reservoir, production, and project data for target reservoirs thermally recoverable by steam drive which are equal to or greater than 2500 feet deep and contain heavy oil in the 8 to 25/sup 0/ API gravity range. Data were collected from three source types: hands-on (A), once-removed (B), and twice-removed (C). 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. This volume also contains a complete listing of operators and projects, as well as a bibliography of source material.

  18. Improved oil recovery using bacteria isolated from North Sea petroleum reservoirs

    SciTech Connect

    Davey, R.A.; Lappin-Scott, H.

    1995-12-31

    During secondary oil recovery, water is injected into the formation to sweep out the residual oil. The injected water, however, follows the path of least resistance through the high-permeability zones, leaving oil in the low-permeability zones. Selective plugging of these their zones would divert the waterflood to the residual oil and thus increase the life of the well. Bacteria have been suggested as an alternative plugging agent to the current method of polymer injection. Starved bacteria can penetrate deeply into rock formations where they attach to the rock surfaces, and given the right nutrients can grow and produce exo-polymer, reducing the permeability of these zones. The application of microbial enhanced oil recovery has only been applied to shallow, cool, onshore fields to date. This study has focused on the ability of bacteria to enhance oil recovery offshore in the North Sea, where the environment can be considered extreme. A screen of produced water from oil reservoirs (and other extreme subterranean environments) was undertaken, and two bacteria were chosen for further work. These two isolates were able to grow and survive in the presence of saline formation waters at a range of temperatures above 50{degrees}C as facultative anaerobes. When a solution of isolates was passed through sandpacks and nutrients were added, significant reductions in permeabilities were achieved. This was confirmed in Clashach sandstone at 255 bar, when a reduction of 88% in permeability was obtained. Both isolates can survive nutrient starvation, which may improve penetration through the reservoir. Thus, the isolates show potential for field trials in the North Sea as plugging agents.

  19. Basement reservoir in Zeit Bay oil field, Gulf of Suez

    SciTech Connect

    Zahran, I.; Askary, S.

    1988-01-01

    Fractured basement, one of the most important reservoirs of Zeit Bay field, contains nearly one-third of oil in place of the field. The flow rates per well vary from 700 to 9,000 BOPD. Due to its well-established production potential, 60% of the wells for the development of the field were drilled down to basement. The Zeit Bay basement consist of granitic rocks of pegmatitic to coarse porphyritic texture and has equal proportions of alkali feldspars. Dykes of various compositions are present, traversing the granite at different intervals. Dykes include aplite, microsyenite, diabase and lamprophyre. The last two pertain to the post-granitic dykes of later Proterozoic age. The main granitic luton is related to one of the final stages of the tectonic-magmatic cycle of the Arabo-Nubian sheild. The Zeit Bay area was a significant paleohigh until the Miocene, hence its structural picture is very complicated due to the impact of different tectonic movements from the late Precambrian to Cenozoic. The resulting structural elements were carefully investigated and statistically analyzed to decipher the influence of various tectonic events. The presence of high porosity in some intervals and low porosity in others could be tied to the presence of new fractures and the nature of cementing minerals. The relation of mineralized fractures and their depths lead to zonation of porous layers in the granitic pluton. Diagenetic processes on the granitic body and the alternation/resedimentation of the diagenetic products controlled the magnitude and amplitude of the porosity layers.

  20. IMPROVING CO2 EFFICIENCY FOR RECOVERING OIL IN HETEROGENEOUS RESERVOIRS

    SciTech Connect

    Reid B. Grigg; Robert K. Svec; Zhengwen Zeng; Baojun Bai; Yi Liu

    2004-09-27

    The third annual report of ''Improving CO{sub 2} Efficiency for Recovery Oil in Heterogeneous Reservoirs'' presents results of laboratory studies with related analytical models for improved oil recovery. All studies were designed to optimize utilization and extend the practice of CO{sub 2} flooding to a wider range of reservoirs. Chapter 1 describes the behavior at low concentrations of the surfactant Chaser International CD1045{trademark} (CD) versus different salinity, pressure and temperature. Results of studies on the effects of pH and polymer (hydrolyzed polyacrylamide?HPAM) and CO{sub 2} foam stability after adsorption in the core are also reported. Calcium lignosulfonate (CLS) transport mechanisms through sandstone, description of the adsorption of CD and CD/CLS onto three porous media (sandstone, limestone and dolomite) and five minerals, and the effect of adsorption on foam stability are also reported. In Chapter 2, the adsorption kinetics of CLS in porous Berea sandstone and non-porous minerals are compared by monitoring adsorption density change with time. Results show that adsorption requires a much longer time for the porous versus non-porous medium. CLS adsorption onto sandstone can be divided into three regions: adsorption controlled by dispersion, adsorption controlled by diffusion and adsorption equilibrium. NaI tracer used to characterize the sandstone had similar trends to earlier results for the CLS desorption process, suggesting a dual porosity model to simulate flow through Berea sandstone. The kinetics and equilibrium test for CD adsorption onto five non-porous minerals and three porous media are reported in Chapter 3. CD adsorption and desorption onto non-porous minerals can be established in less than one hour with adsorption densities ranging from 0.4 to 1.2 mg of CD per g of mineral in decreasing order of montmorillonite, dolomite, kaolinite, silica and calcite. The surfactant adsorption onto three porous media takes much longer than one

  1. Oils and hydrocarbon source rocks of the Baltic syneclise

    SciTech Connect

    Kanev, S.; Margulis, L. ); Bojesen-Koefoed, J.A. ); Weil, W.A.; Merta, H. ); Zdanaviciute, O. )

    1994-07-11

    Prolific source rock horizons of varying thickness, having considerable areal extent, occur over the Baltic syneclise. These source sediments are rich and have excellent petroleum generation potential. Their state of thermal maturity varies form immature in the northeastern part of the syneclise to peak generation maturity in the southwestern part of the region-the main kitchen area. These maturity variations are manifest in petroleum composition in the region. Hence, mature oils occur in the Polish and Kaliningrad areas, immature oils in small accumulations in Latvian and central Lithuanian onshore areas, and intermediate oils in areas between these extremes. The oil accumulations probably result from pooling of petroleum generated from a number of different source rocks at varying levels of thermal maturity. Hence, no single source for petroleum occurrences in the Baltic syneclise may be identified. The paper describes the baltic syneclise, source rocks, thermal maturity and oils and extracts.

  2. 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.

  3. Laboratory techniques for investigating recovery in heavy oil reservoirs

    SciTech Connect

    Maini, B.; Sayegh, S.

    1983-01-01

    Although general guidelines have been published in the literature for selecting the most suitable tertiary recovery technique for a given reservoir, the actual design of a commercial enhanced recovery scheme is a time- consuming and expensive process requiring computer simulations, experimental field pilots, and extensive laboratory tests. The objective of this work is to review laboratory testing procedures related to heavy oil recovery and to provide reservoir and production engineers with an insight into such procedures so that they may better appreciate their potentials and limitations. The topics discussed include characterization of stock tank oils, phase behavior measurements of oil/gas systems, measurements of relative permeability, and its temperature dependence and core tests for evaluation of CO/sub 2/ stimulation. 22 references.

  4. Characterization of oil and gas reservoir heterogeneity. [Quarterly technical progress report], April 1, 1993--June 30, 1993

    SciTech Connect

    Sharma, G.D.

    1993-08-01

    The ultimate objective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task I is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization--determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis--source rock identification; and the study of asphaltene precipitation for Alaskan crude oils.

  5. AFM study of mineral wettability with reservoir oils.

    PubMed

    Kumar, K; Dao, E; Mohanty, K K

    2005-09-01

    Wettability plays a key role in determining fluid distributions and consequently the multiphase flow and transport in petroleum reservoirs. Many crude oils have polar organic components that collect at oil-water interfaces and can adsorb onto the mineral surface if the brine film breaks, rendering the medium oil-wet or mixed-wet. Mica and silica surfaces have been aged with brine and crude oils to induce oil component adsorption. Bulk oil is eventually replaced by water in these experiments by washing with common solvents without ever drying the mineral surface. The organic deposit on the mineral surface is studied by atomic force microscopy in the tapping mode under water. Drying the surface during the removal of bulk oil induces artifacts; it is essential to keep the surface wet at all times before atomic force microscopy or contact angle measurement. As the mean thickness of the organic deposit increases, the oil-water contact angle increases. The organic deposits left behind after extraction of oil by common aromatic solvents used in core studies, such as toluene and decalin, are thinner than those left behind by non-aromatic solvents, such as cyclohexane. The force of adhesion with a probe sphere for minerals aged with just the asphaltene fraction is similar to that of the whole oil. The force of adhesion for the minerals aged with just the resin fraction is the highest of all SARA (saturates, aromatics, resins, and asphaltenes) fractions. PMID:16009229

  6. Core flooding tests to investigate the effects of IFT reduction and wettability alteration on oil recovery during MEOR process in an Iranian oil reservoir.

    PubMed

    Rabiei, Arash; Sharifinik, Milad; Niazi, Ali; Hashemi, Abdolnabi; Ayatollahi, Shahab

    2013-07-01

    Microbial enhanced oil recovery (MEOR) refers to the process of using bacterial activities for more oil recovery from oil reservoirs mainly by interfacial tension reduction and wettability alteration mechanisms. Investigating the impact of these two mechanisms on enhanced oil recovery during MEOR process is the main objective of this work. Different analytical methods such as oil spreading and surface activity measurements were utilized to screen the biosurfactant-producing bacteria isolated from the brine of a specific oil reservoir located in the southwest of Iran. The isolates identified by 16S rDNA and biochemical analysis as Enterobacter cloacae (Persian Type Culture Collection (PTCC) 1798) and Enterobacter hormaechei (PTCC 1799) produce 1.53 g/l of biosurfactant. The produced biosurfactant caused substantial surface tension reduction of the growth medium and interfacial tension reduction between oil and brine to 31 and 3.2 mN/m from the original value of 72 and 29 mN/m, respectively. A novel set of core flooding tests, including in situ and ex situ scenarios, was designed to explore the potential of the isolated consortium as an agent for MEOR process. Besides, the individual effects of wettability alteration and IFT reduction on oil recovery efficiency by this process were investigated. The results show that the wettability alteration of the reservoir rock toward neutrally wet condition in the course of the adsorption of bacteria cells and biofilm formation are the dominant mechanisms on the improvement of oil recovery efficiency. PMID:23553033

  7. Increasing waterflood reserves in the Wilmington oil field through improved reservoir characterization and reservoir management. Quarterly technical progress report, March 21, 1995--June 30, 1995

    SciTech Connect

    Sullivan, D.; Clarke, D.; Walker, S.; Phillips, C.; Nguyen, J.; Moos, D.; Tagbor, K.

    1995-07-26

    The main objective of this project is the transfer of technologies, methodologies, and findings developed and applied in this project to other operators of Slope and Basin Clastic Reservoirs. This project will study methods to identify sands with high remaining oil saturation and to recomplete existing wells using advanced completion technology. The identification of the sands with high remaining oil saturation will be accomplished by developing a deterministic 3-D geologic model and by using a state of the art reservoir management computer software. The wells identified by the geologic and reservoir engineering work as having the best potential will be logged with a pulsed acoustic cased-hole logging tool. The application of the logging tools will be optimized in the lab by developing a rock-log model. The wells that are shown to have the best oil production potential will be recompleted. The recompletions will be optimized by evaluating short radius and ultra-short radius lateral recompletions. Technical progress is reported for the following tasks: Reservoir characterization; reservoir engineering; 3-D geologic modeling; pulsed acoustic logging; and technology transfer.

  8. Evaluation of Reservoir Wettability and its Effect on Oil Recovery

    SciTech Connect

    Jill S. Buckley

    1998-06-12

    This project has three main goals. The first is to achieve improved understanding of the surface and interfacial properties of crude oils and their interactions with mineral surfaces. The second goal is to apply the results of surface studies to improved predictions of oil production in laboratory experiments. Finally, we aim to use the results of this research to recommend ways to improve oil recovery by waterflooding. In order to achieve these goals, the mechanisms of wetting alteration must be explained. We propose a methodology for studying those mechanisms on mineral surfaces, then applying the results to prediction and observation of wetting alteration in porous media. Improved understanding of the underlying mechanisms will show when and how wettability in the reservoir can be altered and under what circumstances that alteration would be beneficial in terms of increased production of oil. In the work reported this quarter, crude oil interactions with Berea sandstone have been used to prepare cores with mixed wettability.

  9. WETTABILITY AND PREDICTION OF OIL RECOVERY FROM RESERVOIRS DEVELOPED WITH MODERN DRILLING AND COMPLETION FLUIDS

    SciTech Connect

    Jill S. Buckley; Norman R. Morrow

    2006-01-01

    The objectives of this project are: (1) to improve understanding of the wettability alteration of mixed-wet rocks that results from contact with the components of synthetic oil-based drilling and completion fluids formulated to meet the needs of arctic drilling; (2) to investigate cleaning methods to reverse the wettability alteration of mixed-wet cores caused by contact with these SBM components; and (3) to develop new approaches to restoration of wetting that will permit the use of cores drilled with SBM formulations for valid studies of reservoir properties.

  10. Mechanical Behaviour of Reservoir Rock Under Brine Saturation

    NASA Astrophysics Data System (ADS)

    Shukla, Richa; Ranjith, P. G.; Choi, S. K.; Haque, A.; Yellishetty, Mohan; Hong, Li

    2013-01-01

    Acoustic emissions (AE) and stress-strain curve analysis are well accepted ways of analysing crack propagation and monitoring the various failure stages (such as crack closure, crack initiation level during rock failure under compression) of rocks and rock-like materials. This paper presents details and results of experimental investigations conducted for characterizing the brittle failure processes induced in a rock due to monocyclic uniaxial compression on loading of two types of sandstone core samples saturated in NaCl brines of varying concentration (0, 2, 5, 10 and 15 % NaCl by weight). The two types of sandstone samples were saturated under vacuum for more than 45 days with the respective pore fluid to allow them to interact with the rocks. It was observed that the uniaxial compressive strength and stress-strain behaviour of the rock specimens changed with increasing NaCl concentration in the saturating fluid. The acoustic emission patterns also varied considerably for increasing ionic strength of the saturating brines. These observations can be attributed to the deposition of NaCl crystals in the rock's pore spaces as well some minor geo-chemical interactions between the rock minerals and the brine. The AE pattern variations could also be partly related to the higher conductivity of the ionic strength of the high-NaCl concentration brine as it is able to transfer more acoustic energy from the cracks to the AE sensors.

  11. SEISMIC AND ROCK PHYSICS DIAGNOSTICS OF MULTISCALE RESERVOIR TEXTURES

    SciTech Connect

    Gary Mavko

    2003-06-30

    As part of our study on ''Relationships between seismic properties and rock microstructure'', we have studied (1) Effects of pore texture on porosity, permeability, and sonic velocity. We show how a relation can be found between porosity, permeability, and velocity by separating the formations of rocks with similar pore textures.

  12. Producing Light Oil from a Frozen Reservoir: Reservoir and Fluid Characterization of Umiat Field, National Petroleum Reserve, Alaska

    SciTech Connect

    Hanks, Catherine

    2012-12-31

    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 be 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 permeability

  13. Fluorescence analysis can identify movable oil in self-sourcing reservoirs

    SciTech Connect

    Calhoun, G.G.

    1995-06-05

    The recent surge of activity involving self-sourcing reservoirs and horizontal drilling recognizes a little tapped niche in the domestic energy mix. Such prolific pays as the Cretaceous Bakken and Austin Chalk have drawn research interest and large amounts of investment capital. Fluorescence analysis can discern movable oil--as opposed to exhausted source rock--in such reservoirs with an inexpensive test. Other potential targets are the Cretaceous Mesaverde in the Piceance basin, Devonian New Albany shale in Kentucky, Devonian Antrim shale in the Michigan basin, and the Cretaceous Niobrara, Mancos, and Pierre formations in Colorado and New Mexico. To insure success in this niche this key question must be answered positively: Is movable oil present in the reservoir? Even if tectonic studies verify a system of open fractures, sonic logs confirm overpressuring in the zone, and resistivity logs document the maturity of the source, the ultimate question remains: Is movable oil in the fractures available to flow to the borehole? The paper explains a technique that will answer these questions.

  14. Xenon NMR measurements of permeability and tortuosity in reservoir rocks.

    PubMed

    Wang, Ruopeng; Pavlin, Tina; Rosen, Matthew Scott; Mair, Ross William; Cory, David G; Walsworth, Ronald Lee

    2005-02-01

    In this work we present measurements of permeability, effective porosity and tortuosity on a variety of rock samples using NMR/MRI of thermal and laser-polarized gas. Permeability and effective porosity are measured simultaneously using MRI to monitor the inflow of laser-polarized xenon into the rock core. Tortuosity is determined from measurements of the time-dependent diffusion coefficient using thermal xenon in sealed samples. The initial results from a limited number of rocks indicate inverse correlations between tortuosity and both effective porosity and permeability. Further studies to widen the number of types of rocks studied may eventually aid in explaining the poorly understood connection between permeability and tortuosity of rock cores. PMID:15833638

  15. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect

    Scott Hara

    2000-02-18

    The project involves using advanced reservoir characterization and thermal production technologies to improve thermal recovery techniques and lower operating and capital costs in a slope and basin clastic (SBC) reservoir in the Wilmington field, Los Angeles Co., CA. Through March 1999, project work has been completed related to data preparation, basic reservoir engineering, developing a deterministic three dimensional (3-D) geologic model, a 3-D deterministic reservoir simulation model, and a rock-log model, well drilling and completions, and surface facilities. Work is continuing on the stochastic geologic model, developing a 3-D stochastic thermal reservoir simulation model of the Fault Block IIA Tar (Tar II-A) Zone, and operational work and research studies to prevent thermal-related formation compaction. Thermal-related formation compaction is a concern of the project team due to observed surface subsidence in the local area above the steamflood project. Last quarter on January 12, the steamflood project lost its inexpensive steam source from the Harbor Cogeneration Plant as a result of the recent deregulation of electrical power rates in California. An operational plan was developed and implemented to mitigate the effects of the two situations. Seven water injection wells were placed in service in November and December 1998 on the flanks of the Phase 1 steamflood area to pressure up the reservoir to fill up the existing steam chest. Intensive reservoir engineering and geomechanics studies are continuing to determine the best ways to shut down the steamflood operations in Fault Block II while minimizing any future surface subsidence. The new 3-D deterministic thermal reservoir simulator model is being used to provide sensitivity cases to optimize production, steam injection, future flank cold water injection and reservoir temperature and pressure. According to the model, reservoir fill up of the steam chest at the current injection rate of 28,000 BPD and gross

  16. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect

    Scott Hara

    2002-04-30

    The project involves using advanced reservoir characterization and thermal production technologies to improve thermal recovery techniques and lower operating and capital costs in a slope and basin clastic (SBC) reservoir in the Wilmington field, Los Angeles Co., Calif. Through December 2001, project work has been completed on the following activities: data preparation; basic reservoir engineering; developing a deterministic three dimensional (3-D) geologic model, a 3-D deterministic reservoir simulation model and a rock-log model; well drilling and completions; and surface facilities on the Fault Block II-A Tar Zone (Tar II-A). Work is continuing on research to understand the geochemistry and process regarding the sand consolidation well completion technique, final reservoir tracer work, operational work and research studies to prevent thermal-related formation compaction in the Tar II-A steamflood area, and operational work on the Tar V steamflood pilot and Tar II-A post-steamflood projects. During the First Quarter 2002, the project team developed an accelerated oil recovery and reservoir cooling plan for the Tar II-A post-steamflood project and began implementing the associated well work in March. The Tar V pilot steamflood project will be converted to post-steamflood cold water injection in April 2002. The Tar II-A post-steamflood operation started in February 1999 and steam chest fillup occurred in September-October 1999. The targeted reservoir pressures in the ''T'' and ''D'' sands are maintained at 90 {+-} 5% hydrostatic levels by controlling water injection and gross fluid production and through the bimonthly pressure monitoring program enacted at the start of the post-steamflood phase. Most of the 2001 well work resulted in maintaining oil and gross fluid production and water injection rates. Reservoir pressures in the ''T'' and ''D'' sands are at 88% and 91% hydrostatic levels, respectively. Well work during the first quarter and plans for 2002 are

  17. Distribution of Thermophilic Marine Sulfate Reducers in North Sea Oil Field Waters and Oil Reservoirs

    PubMed Central

    Nilsen, R. K.; Beeder, J.; Thorstenson, T.; Torsvik, T.

    1996-01-01

    The distribution of thermophilic marine sulfate reducers in produced oil reservoir waters from the Gullfaks oil field in the Norwegian sector of the North Sea was investigated by using enrichment cultures and genus-specific fluorescent antibodies produced against the genera Archaeoglobus, Desulfotomaculum, and Thermodesulforhabdus. The thermophilic marine sulfate reducers in this environment could mainly be classified as species belonging to the genera Archaeoglobus and Thermodesulforhabdus. In addition, some unidentified sulfate reducers were present. Culturable thermophilic Desulfotomaculum strains were not detected. Specific strains of thermophilic sulfate reducers inhabited different parts of the oil reservoir. No correlation between the duration of seawater injection and the numbers of thermophilic sulfate reducers in the produced waters was observed. Neither was there any correlation between the concentration of hydrogen sulfide and the numbers of thermophilic sulfate reducers. The results indicate that thermophilic and hyperthermophilic sulfate reducers are indigenous to North Sea oil field reservoirs and that they belong to a deep subterranean biosphere. PMID:16535321

  18. Chemical water/rock interaction under reservoir condition

    SciTech Connect

    Watanabe, K.; Tanifuji, K.; Takahashi, H.; Wang, Y.; Yamasaki, N.; Nakatsuka, K.

    1995-01-26

    A simple model is proposed for water/rock interaction in rock fractures through which geothermal water flows. Water/rock interaction experiments were carried out at high temperature and pressure (200-350 C, 18 MPa) in order to obtain basic solubility and reaction rate data. Based on the experimental data, changes of idealized fracture apertures with time are calculated numerically. The results of the calculations show that the precipitation from water can lead to plugging of the fractures under certain conditions. Finally, the results are compared with the experimental data.

  19. Reasons for production decline in the diatomite, Belridge oil field: a rock mechanics view

    SciTech Connect

    Strickland, F.G.

    1982-01-01

    This work summarized research conducted on diatomite cores from the Belridge oil field in Kern County. The study was undertaken to try to explain the rapid decline in oil production in diatomite wells. Characterization of the rock showed that the rock was composed principally of amorphous opaline silica diatoms with only a trace of crystoballite quartz or chert quartz. Physical properties tests showed the diatomite to be of low strength and plastic. Finally, it was established that long-term creep of diatomite into a propped fracture proceeds at a rate of approximately 6 x 10-5 in./day, a phenomenon which may be a primary cause of rapid production declines. The testing program also revealed a matrix stength for the formation of calculated 1325 PSI, a value to consider when depleting the reservoir. This also may help to explain the phase transformation of opal ct at calculated 2000 to 2500 ft depth.

  20. Increasing waterflood reserves in the Wilmington oil field through improved reservoir characterization and reservoir management. Quarterly report, July 1, 1996--September 30, 1996

    SciTech Connect

    Walker, S.

    1996-10-28

    The objectives of this quarterly report are to summarize the work conducted under each task during the reporting period July - September 1996, and to report all technical data and findings as specified in the {open_quotes}Federal Assistance Reporting Checklist{close_quotes}. The main objective of this project is the transfer of technologies, methodologies, and findings developed and applied in this project to other operators of Slope and Basin Clastic Reservoirs. This project will study methods to identify sands with high remaining oil saturation and to recomplete existing wells using advanced completion technology. The identification of the sands with high remaining oil saturation will be accomplished by developing a deterministic three dimensional (3-D) geologic model and by using a state of the art reservoir management computer software. The wells identified by the geologic and reservoir engineering work as having the best potential will be logged with a pulsed acoustic cased-hole logging tool. The application of the logging tools will be optimized in the lab by developing a rock-log model. This rock-log model will allow us to convert shear wave velocity measured through casing into effective porosity and hydrocarbon saturation. The wells that are shown to have the best oil production potential will be recompleted. The recompletions will be optimized by evaluating short radius and ultra-short radius lateral recompletions as well as other techniques.

  1. A CUDA based parallel multi-phase oil reservoir simulator

    NASA Astrophysics Data System (ADS)

    Zaza, Ayham; Awotunde, Abeeb A.; Fairag, Faisal A.; Al-Mouhamed, Mayez A.

    2016-09-01

    Forward Reservoir Simulation (FRS) is a challenging process that models fluid flow and mass transfer in porous media to draw conclusions about the behavior of certain flow variables and well responses. Besides the operational cost associated with matrix assembly, FRS repeatedly solves huge and computationally expensive sparse, ill-conditioned and unsymmetrical linear system. Moreover, as the computation for practical reservoir dimensions lasts for long times, speeding up the process by taking advantage of parallel platforms is indispensable. By considering the state of art advances in massively parallel computing and the accompanying parallel architecture, this work aims primarily at developing a CUDA-based parallel simulator for oil reservoir. In addition to the initial reported 33 times speed gain compared to the serial version, running experiments showed that BiCGSTAB is a stable and fast solver which could be incorporated in such simulations instead of the more expensive, storage demanding and usually utilized GMRES.

  2. Evaluation of Reservoir Wettability and its Effect on Oil Recovery

    SciTech Connect

    Jill S. Buckley

    1998-04-13

    This project has three main goals. The first is to achieve improved understanding of the surface and interfacial properties of crude oils and their interactions with mineral surfaces. The second goal is to apply the results of surface studies to improved predictions of oil production in laboratory experiments. Finally, we aim to use the results of this research to recommend ways to improve oil recovery by waterflooding. In order to achieve these goals, the mechanisms of wetting alteration must be explained. We propose a methodology for studying those mechanisms on mineral surfaces, then applying the results to prediction and observation of wetting alteration in porous media. Improved understanding of the underlying mechanisms will show when and how wettability in the reservoir can be altered and under what circumstances that alteration would be beneficial in terms of increased production of oil.

  3. Increasing heavy oil reservers in the Wilmington oil Field through advanced reservoir characterization and thermal production technologies, technical progress report, October 1, 1996--December 31, 1996

    SciTech Connect

    Hara, S. , Casteel, J.

    1997-05-11

    The project involves improving thermal recovery techniques in a slope and basin clastic (SBC) reservoir in the Wilmington field, Los Angeles Co., Calif. using advanced reservoir characterization and thermal production technologies. The existing steamflood in the Tar zone of Fault Block (FB) 11-A has been relatively inefficient because of several producibility problems which are common in SBC reservoirs. Inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil, and nonuniform distribution of remaining oil have all contributed to poor sweep efficiency, high steam-oil ratios, and early steam breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated formation sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves. The advanced technologies to be applied include: (1) Develop three-dimensional (3-D) deterministic and stochastic geologic models. (2) Develop 3-D deterministic and stochastic thermal reservoir simulation models to aid in reservoir management and subsequent development work. (3) Develop computerized 3-D visualizations of the geologic and reservoir simulation models to aid in analysis. (4) Perform detailed study on the geochemical interactions between the steam and the formation rock and fluids. (5) Pilot steam injection and production via four new horizontal wells (2 producers and 2 injectors). (6) Hot water alternating steam (WAS) drive pilot in the existing steam drive area to improve thermal efficiency. (7) Installing a 2100 foot insulated, subsurface harbor channel crossing to supply steam to an island location. (8) Test a novel alkaline steam completion technique to control well sanding problems and fluid entry profiles. (9) Advanced reservoir management through computer-aided access to production and

  4. Oils and source rocks from the Anadarko Basin: Final report, March 1, 1985-March 15, 1995

    SciTech Connect

    Philp, R. P.

    1996-11-01

    The research project investigated various geochemical aspects of oils, suspected source rocks, and tar sands collected from the Anadarko Basin, Oklahoma. The information has been used, in general, to investigate possible sources for the oils in the basin, to study mechanisms of oil generation and migration, and characterization of depositional environments. The major thrust of the recent work involved characterization of potential source formations in the Basin in addition to the Woodford shale. The formations evaluated included the Morrow, Springer, Viola, Arbuckle, Oil Creek, and Sylvan shales. A good distribution of these samples was obtained from throughout the basin and were evaluated in terms of source potential and thermal maturity based on geochemical characteristics. The data were incorporated into a basin modelling program aimed at predicting the quantities of oil that could, potentially, have been generated from each formation. The study of crude oils was extended from our earlier work to cover a much wider area of the basin to determine the distribution of genetically-related oils, and whether or not they were derived from single or multiple sources, as well as attempting to correlate them with their suspected source formations. Recent studies in our laboratory also demonstrated the presence of high molecular weight components(C{sub 4}-C{sub 80}) in oils and waxes from drill pipes of various wells in the region. Results from such a study will have possible ramifications for enhanced oil recovery and reservoir engineering studies.

  5. The overthrusted Zaza Terrane of middle Cretaceous over the North American continental carbonate rocks of upper Jurassic-Lower Cretaceous age - relationships to oil generation

    SciTech Connect

    Echevarria Rodriguez, G.; Castro, J.A.; Amaro, S.V.

    1996-08-01

    The Zaza Terrane is part of the Caribbean plate thrust over the southern edge of the North American basinal and platform carbonate rocks of upper Jurassic-Lower Cretaceous age. Zaza Terrane are volcanic and ophiolitic rocks of Cretaceous age. The ophiolites are mostly serpentines which behave as reservoirs and seals. All Cuban oil fields are either within Zaza Terrane or basinal carbonates underneath, or not far away to the north of the thrust contacts. It appears that the overthrusting of the Zaza Terrane caused the generation of oil in the basinal carbonate source rocks underneath, due to the increase of rock thickness which lowered the oil window to a deeper position and increased the geothermal gradient. Oil generation was after thrusting, during post-orogenic. API gravity of oil is light toward the south and heavy to very heavy to the north. Source rocks to the south are probably of terrigenous origin.

  6. Time lapse seismic observations and effects of reservoir compressibility at Teal South oil field

    NASA Astrophysics Data System (ADS)

    Islam, Nayyer

    corrected for, indicate water encroachment at the base of the producing reservoir. I also identify specific sites of leakage from various unproduced reservoirs, the result of regional pressure blowdown as explained in previous studies; those earlier studies, however, were unable to identify direct evidence of fluid movement. Of particular interest is the identification of one site where oil apparently leaked from one reservoir into a "new" reservoir that did not originally contain oil, but was ideally suited as a trap for fluids leaking from the neighboring spill-point. With continued pressure drop, oil in the new reservoir increased as more oil entered into the reservoir and expanded, liberating gas from solution. Because of the limited volume available for oil and gas in that temporary trap, oil and gas also escaped from it into the surrounding formation. I also note that some of the reservoirs demonstrate time-lapse changes only in the "gas cap" and not in the oil zone, even though gas must be coming out of solution everywhere in the reservoir. This is explained by interplay between pore-fluid modulus reduction by gas saturation decrease and dry-frame modulus increase by frame stiffening. In the second part of this work, I examine various rock-physics models in an attempt to quantitatively account for frame-stiffening that results from reduced pore-fluid pressure in the producing reservoir, searching for a model that would predict the unusual AVO features observed in the time-lapse prestack and stacked data at Teal South. While several rock-physics models are successful at predicting the time-lapse response for initial production, most fail to match the observations for continued production between Phase I and Phase II. Because the reservoir was initially overpressured and unconsolidated, reservoir compaction was likely significant, and is probably accomplished largely by uniaxial strain in the vertical direction; this implies that an anisotropic model may be required

  7. SEISMIC AND ROCK PHYSICS DIAGNOSTICS OF MULTISCALE RESERVOIR TEXTURES

    SciTech Connect

    Gary Mavko

    2003-06-01

    As part of our study on ''Relationships between seismic properties and rock microstructure'', we have studied (1) Elastic properties of clay minerals using Pulse Transmission experiments. We show measurements of elastic moduli and strain in clay minerals.

  8. Eos modeling and reservoir simulation study of bakken gas injection improved oil recovery in the elm coulee field, Montana

    NASA Astrophysics Data System (ADS)

    Pu, Wanli

    The Bakken Formation in the Williston Basin is one of the most productive liquid-rich unconventional plays. The Bakken Formation is divided into three members, and the Middle Bakken Member is the primary target for horizontal wellbore landing and hydraulic fracturing because of its better rock properties. Even with this new technology, the primary recovery factor is believed to be only around 10%. This study is to evaluate various gas injection EOR methods to try to improve on that low recovery factor of 10%. In this study, the Elm Coulee Oil Field in the Williston Basin was selected as the area of interest. Static reservoir models featuring the rock property heterogeneity of the Middle Bakken Member were built, and fluid property models were built based on Bakken reservoir fluid sample PVT data. By employing both compositional model simulation and Todd-Longstaff solvent model simulation methods, miscible gas injections were simulated and the simulations speculated that oil recovery increased by 10% to 20% of OOIP in 30 years. The compositional simulations yielded lower oil recovery compared to the solvent model simulations. Compared to the homogeneous model, the reservoir model featuring rock property heterogeneity in the vertical direction resulted in slightly better oil recovery, but with earlier CO2 break-through and larger CO2 production, suggesting that rock property heterogeneity is an important property for modeling because it has a big effect on the simulation results. Long hydraulic fractures shortened CO2 break-through time greatly and increased CO 2 production. Water-alternating-gas injection schemes and injection-alternating-shut-in schemes can provide more options for gas injection EOR projects, especially for gas production management. Compared to CO2 injection, separator gas injection yielded slightly better oil recovery, meaning separator gas could be a good candidate for gas injection EOR; lean gas generated the worst results. Reservoir

  9. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect

    Scott Hara

    2002-11-08

    The project involves using advanced reservoir characterization and thermal production technologies to improve thermal recovery techniques and lower operating and capital costs in a slope and basin clastic (SBC) reservoir in the Wilmington field, Los Angeles Co., CA. Through June 2002, project work has been completed on the following activities: data preparation; basic reservoir engineering; developing a deterministic three dimensional (3-D) geologic model, a 3-D deterministic reservoir simulation model and a rock-log model; well drilling and completions; and surface facilities on the Fault Block II-A Tar Zone (Tar II-A). Work is continuing on research to understand the geochemistry and process regarding the sand consolidation well completion technique, final reservoir tracer work, operational work and research studies to prevent thermal-related formation compaction in the Tar II-A steamflood area, and operational work on the Tar V post-steamflood pilot and Tar II-A post-steamflood projects. During the Third Quarter 2002, the project team essentially completed implementing the accelerated oil recovery and reservoir cooling plan for the Tar II-A post-steamflood project developed in March 2002 and is proceeding with additional related work. The project team has completed developing laboratory research procedures to analyze the sand consolidation well completion technique and will initiate work in the fourth quarter. The Tar V pilot steamflood project terminated hot water injection and converted to post-steamflood cold water injection on April 19, 2002. Proposals have been approved to repair two sand consolidated horizontal wells that sanded up, Tar II-A well UP-955 and Tar V well J-205, with gravel-packed inner liner jobs to be performed next quarter. Other well work to be performed next quarter is to convert well L-337 to a Tar V water injector and to recomplete vertical well A-194 as a Tar V interior steamflood pattern producer. Plans have been approved to drill and

  10. Characterization of nanometer-scale porosity in reservoir carbonate rock by focused ion beam-scanning electron microscopy.

    PubMed

    Bera, Bijoyendra; Gunda, Naga Siva Kumar; Mitra, Sushanta K; Vick, Douglas

    2012-02-01

    Sedimentary carbonate rocks are one of the principal porous structures in natural reservoirs of hydrocarbons such as crude oil and natural gas. Efficient hydrocarbon recovery requires an understanding of the carbonate pore structure, but the nature of sedimentary carbonate rock formation and the toughness of the material make proper analysis difficult. In this study, a novel preparation method was used on a dolomitic carbonate sample, and selected regions were then serially sectioned and imaged by focused ion beam-scanning electron microscopy. The resulting series of images were used to construct detailed three-dimensional representations of the microscopic pore spaces and analyze them quantitatively. We show for the first time the presence of nanometer-scale pores (50-300 nm) inside the solid dolomite matrix. We also show the degree of connectivity of these pores with micron-scale pores (2-5 μm) that were observed to further link with bulk pores outside the matrix. PMID:22214656

  11. Advanced reservoir management for independent oil and gas producers

    SciTech Connect

    Sgro, A.G.; Kendall, R.P.; Kindel, J.M.; Webster, R.B.; Whitney, E.M.

    1996-11-01

    There are more than fifty-two hundred oil and gas producers operating in the United States today. Many of these companies have instituted improved oil recovery programs in some form, but very few have had access to state-of-the-art modeling technologies routinely used by major producers to manage these projects. Since independent operators are playing an increasingly important role in the production of hydrocarbons in the United States, it is important to promote state-of-the-art management practices, including the planning and monitoring of improved oil recovery projects, within this community. This is one of the goals of the Strategic Technologies Council, a special interest group of independent oil and gas producers. Reservoir management technologies have the potential to increase oil recovery while simultaneously reducing production costs. These technologies were pioneered by major producers and are routinely used by them. Independent producers confront two problems adopting this approach: the high cost of acquiring these technologies and the high cost of using them even if they were available. Effective use of reservoir management tools requires, in general, the services of a professional (geoscientist or engineer) who is already familiar with the details of setting up, running, and interpreting computer models.

  12. Simulation of irreversible rock compaction effects on geopressured reservoir response: Topical report

    SciTech Connect

    Riney, T.D.

    1986-12-01

    A series of calculations are presented which quantitatively demonstrate the effects of nonlinear stress-deformation properties on the behavior of geopressured reservoirs. The range of stress-deformation parameters considered is based on information available from laboratory rock mechanics tests performed at the University of Texas at Austin and at Terra Tek, Inc. on cores recovered from geopressured wells. The effects of irreversible formation rock compaction, associated permeability reduction, and repetitive load/unload cycling are considered. The formation rock and geopressured brine properties are incorporated into an existing reservoir simulator using a bilinear model for the irreversible compaction process. Pressure drawdown and buildup testing of a well producing from the geopressured formation is simulated for a suite of calculations covering the range of formation parameters. The results are presented and discussed in terms of the inference (e.g., permeability and reservoir volume) that would be drawn from the simulated test data by an analyst using conventional methods.

  13. Mechanical rock properties, fracture propagation and permeability development in deep geothermal reservoirs

    NASA Astrophysics Data System (ADS)

    Leonie Philipp, Sonja; Reyer, Dorothea

    2010-05-01

    Deep geothermal reservoirs are rock units at depths greater than 400 m from which the internal heat can be extracted using water as a transport means in an economically efficient manner. In many geothermal reservoirs, fluid flow is largely, and may be almost entirely, controlled by the permeability of the fracture network. No flow, however, takes place along a particular fracture network unless the fractures are interconnected. For fluid flow to occur from one site to another there must be at least one interconnected cluster of fractures that links these sites, that is, the percolation threshold must be reached. In "hydrothermal systems", only the natural fracture system (extension and shear fractures) creates the rock or reservoir permeability that commonly exceeds the matrix permeability by far; in "petrothermal systems", by contrast, interconnected fracture systems are formed by creating hydraulic fractures and massive hydraulic stimulation of the existing fracture system in the host rock. Propagation (or termination, that is, arrest) of both natural extension and shear fractures as well as man-made hydraulic fractures is mainly controlled by the mechanical rock properties, particularly rock toughness, stiffness and strengths, of the host rock. Most reservoir rocks are heterogeneous and anisotropic, in particular they are layered. For many layered rocks, the mechanical properties, particularly their Young's moduli (stiffnesses), change between layers, that is, the rocks are mechanically layered. Mechanical layering may coincide with changes in grain size, mineral content, fracture frequencies, or facies. For example, in sedimentary rocks, stiff limestone or sandstone layers commonly alternate with soft shale layers. In geothermal reservoirs fracture termination is important because non-stratabound fractures, that is, fractures not affected by layering, are more likely to form an interconnected fracture network than stratabound fractures, confined to single rock

  14. Real Time Oil Reservoir Evaluation Using Nanotechnology

    NASA Technical Reports Server (NTRS)

    Li, Jing (Inventor); Meyyappan, Meyya (Inventor)

    2011-01-01

    A method and system for evaluating status and response of a mineral-producing field (e.g., oil and/or gas) by monitoring selected chemical and physical properties in or adjacent to a wellsite headspace. Nanotechnology sensors and other sensors are provided for one or more underground (fluid) mineral-producing wellsites to determine presence/absence of each of two or more target molecules in the fluid, relative humidity, temperature and/or fluid pressure adjacent to the wellsite and flow direction and flow velocity for the fluid. A nanosensor measures an electrical parameter value and estimates a corresponding environmental parameter value, such as water content or hydrocarbon content. The system is small enough to be located down-hole in each mineral-producing horizon for the wellsite.

  15. Determination of heterogeneity by high-resolution seismic reservoir characterization in the heavy oil Temblor reservoir of Coalinga Field, California

    NASA Astrophysics Data System (ADS)

    Mahapatra, Sailendra Nath

    The research focuses on analysis and subsurface imaging of siliciclastics rocks on steam-affected 3D poststack seismic data, merged from different vintages, from the Temblor Formation in the Coalinga heavy oil reservoir in the San Joaquin basin, California. The objective was identification, delineation, and demarcation of reservoir heterogeneities by seismostratigraphic and seismogeomorphic analysis. The proximity of the San Andreas Transforms greatly controlled basin evolution and caused substantial reservoir heterogeneity by changing the depositional environment from shallow marine to near-shore fluvial. Moreover, two unconformities dissect the reservoir interval. The seismic dataset exhibits erratic, distorted reflection strengths and amplitudes caused by steam-injection-aided production. A petrophysical analysis based on Gassmann fluid substitution suggests a 27% P-wave velocity decrease in steam-saturated intervals. Seismic to well log ties were problematic and vexing due to the resulting statics, wavelet changes, and line mismatches. Mapping and flattening on a deeper horizon, however, allowed mapping of the internal unconformities and well ties which were crucial for seismostratigraphic sequence identification. Visualization of seismic attributes brought out stratification patterns and two distinct, laterally and vertically extensive, porous, and interconnected facies tracts interpreted as incised valley fills and tidal-to-subtidal deposits as evidenced by bright, steam related amplitudes. Seismic attribute analysis, Geobody Visualization and Interpretation, and structure and isochron maps brought out two prominent channel-systems, recut and restacked in the central part of the area. These deposits were identified on seismic data and correlated to high-gamma coarsening-upward sands on logs and cores. The deeper one, shifting towards SSE with depth, lies between the Base Temblor and Buttonbed unconformities both in the southwestern and northwestern parts of

  16. Geophysical and transport properties of reservoir rocks. Final report for task 4: Measurements and analysis of seismic properties

    SciTech Connect

    Cook, N.G.W.

    1993-05-01

    The principal objective of research on the seismic properties of reservoir rocks is to develop a basic understanding of the effects of rock microstructure and its contained pore fluids on seismic velocities and attenuation. Ultimately, this knowledge would be used to extract reservoir properties information such as the porosity, permeability, clay content, fluid saturation, and fluid type from borehole, cross-borehole, and surface seismic measurements to improve the planning and control of oil and gas recovery. This thesis presents laboratory ultrasonic measurements for three granular materials and attempts to relate the microstructural properties and the properties of the pore fluids to P- and S-wave velocities and attenuation. These experimental results show that artificial porous materials with sintered grains and a sandstone with partially cemented grains exhibit complexities in P- and S-wave attenuation that cannot be adequately explained by existing micromechanical theories. It is likely that some of the complexity observed in the seismic attenuation is controlled by details of the rock microstructure, such as the grain contact area and grain shape, and by the arrangement of the grain packing. To examine these effects, a numerical method was developed for analyzing wave propagation in a grain packing. The method is based on a dynamic boundary integral equation and incorporates generalized stiffness boundary conditions between individual grains to account for viscous losses and grain contact scattering.

  17. Experimental investigation of reservoir rocks by spontaneous imbibition and mercury intrusion porosimetry

    NASA Astrophysics Data System (ADS)

    Gao, Z.; Hu, Q.

    2013-12-01

    Spontaneous imbibition (SI), one of the important processes affecting hydrocarbon recovery from fractured reservoirs, is a capillary-force controlled process. The properties of displacing and displaced fluids, pore structure of porous media and their interactions are the main factors affecting the SI process. Many studies have been conducted to investigate these factors and among them scaling of SI is a widely used approach to predicting the oil/gas production behavior in the field based on laboratory imbibition tests. We have conducted SI experiments on different reservoir rocks, including Barnett shale (from different depths), dolomite and Indian sandstone. Because of the layered characteristic of Barnett shale, we also conducted imbibition experiments, with upward imbibition direction parallel or transverse to the shale bedding plane, to investigate its directional dependency. Two imbibing fluids, n-decane and water, were used during SI experiments to displace air, which is always treated as the non-wetting phase in the SI process. Mercury intrusion porosimetry (MIP) is a powerful tool of characterizing the pore-throat size distribution of porous media, and many important parameters (e.g. permeability and tortuosity) could be derived from MIP data. The median pore-throat diameter (D50), defined as the pore-throat diameter corresponding to 50% mercury saturation, is an important pore-structural parameter and has been used to predict permeability and tortuosity. Our results showed that Barnett shale (from different depths), dolomite and Indiana sandstone exhibited different SI behaviors. Wettability information was obtained by comparing scaled imbibition curves. Values of D50 obtained from MIP were also used to improve the existing scaling method. Low pore connectivity of Barnett shale was confirmed by both SI and MIP results.

  18. Core acid treatment influence on well reservoir properties in Kazan oil-gas condensate field

    NASA Astrophysics Data System (ADS)

    Janishevskii, A.; Ezhova, A.

    2015-11-01

    The research involves investigation of the influence of hydrochloric acid (HCI-12%) and mud acid (mixture: HCl - 10% and HF - 3%) treatment on the Upper-Jurassic reservoir properties in Kazan oil-gas condensate field wells. The sample collection included three lots of core cylinders from one and the same depth (all in all 42). Two lots of core cylinders were distributed as following: first lot - reservoir properties were determined, and, then thin sections were cut off from cylinder faces; second lot- core cylinders were exposed to hydrochloric acid treatment, then, after flushing the reservoir properties were determined, and thin sections were prepared. Based on the quantitative petrographic rock analysis, involvin 42 thin sections, the following factors were determined: granulometric mineral composition, cement content, intergranular contacts and pore space structure. According to the comparative analysis of initial samples, the following was determined: content decrease of feldspar, clay and mica fragments, mica, clay and carbonate cement; increase of pore spaces while in the investigated samples- on exposure of rocks to acids effective porosity and permeability value range is ambiguous.

  19. Strategies for field application of foams in heavy oil reservoirs

    SciTech Connect

    Isaacs, E.E.; Ivory, J.; Law, D.H.S.

    1995-12-31

    Steam-based processes in heavy oil reservoirs that are not stabilized by gravity have poor vertical and areal conformance. This is because gases are more mobile within the pore space than liquids and steam tends to override or channel through oil in a formation. The steam-foam process which consists of adding surfactant with or without non-condensible gas to the injected steam, was developed to improve the sweep efficiency of steam drive and cyclic steam processes. The foam-forming components injected with the steam stabilize the liquid lamellae and cause some of the steam to exist as a discontinuous phase. The steam mobility (gas relative permeability) is thereby reduced resulting in an increased pressure gradient in the steam-swept region, to divert steam to the unheated interval and displace the heated oil better. The propagation of surfactant in the reservoir is determined by its thermal stability, adsorption, precipitation, and oil partitioning behaviour. The propagation of the foam is determined by the mechanisms that generate and destroyfoam in the reservoir, including gas and liquid velocities, condensation and evaporation, non-condensible gas, and the presence of oil. Strategies were developed to minimize the chemical requirements for generating effective steam-foams. Economic steam-foam processes requires that surfactant losses are minimized, foam propagation and foam stability is maximized at surfactant concentrations lower than has hereto been used in the field. This paper, based on laboratory finding and field experience, discusses the important considerations which affect the efficient application of steam-foam in the field.

  20. Reservoirs III carbonates

    SciTech Connect

    Beaumont, E.A.; Foster, N.H.

    1988-01-01

    This text is part of a three volume set on petroleum and natural gas reservoir rocks. This volume deals with carbonate rocks and their properties as they relate to oil and gas production. Papers deal specifically with depositional environments, diagenesis, and chemical and physical properties of the rock.

  1. Adsorption of water vapor on reservoir rocks. First quarterly report, January--March 1993

    SciTech Connect

    Not Available

    1993-07-01

    Progress is reported on: adsorption of water vapor on reservoir rocks; theoretical investigation of adsorption; estimation of adsorption parameters from transient experiments; transient adsorption experiment -- salinity and noncondensible gas effects; the physics of injection of water into, transport and storage of fluids within, and production of vapor from geothermal reservoirs; injection optimization at the Geysers Geothermal Field; a model to test multiwell data interpretation for heterogeneous reservoirs; earth tide effects on downhole pressure measurements; and a finite-difference model for free surface gravity drainage well test analysis.

  2. IMPROVING CO2 EFFICIENCY FOR RECOVERING OIL IN HETEROGENEOUS RESERVOIRS

    SciTech Connect

    Reid B. Grigg

    2003-10-31

    The second annual report of ''Improving CO{sub 2} Efficiency for Recovery Oil in Heterogeneous Reservoirs'' presents results of laboratory studies with related analytical models for improved oil recovery. All studies have been undertaken with the intention to optimize utilization and extend the practice of CO{sub 2} flooding to a wider range of reservoirs. Many items presented in this report are applicable to other interest areas: e.g. gas injection and production, greenhouse gas sequestration, chemical flooding, reservoir damage, etc. Major areas of studies include reduction of CO{sub 2} mobility to improve conformance, determining and understanding injectivity changes in particular injectivity loses, and modeling process mechanisms determined in the first two areas. Interfacial tension (IFT) between a high-pressure, high-temperature CO{sub 2} and brine/surfactant and foam stability are used to assess and screen surfactant systems. In this work the effects of salinity, pressure, temperature, surfactant concentration, and the presence of oil on IFT and CO{sub 2} foam stability were determined on the surfactant (CD1045{trademark}). Temperature, pressure, and surfactant concentration effected both IFT and foam stability while oil destabilized the foam, but did not destroy it. Calcium lignosulfonate (CLS) can be used as a sacrificial and an enhancing agent. This work indicates that on Berea sandstone CLS concentration, brine salinity, and temperature are dominant affects on both adsorption and desorption and that adsorption is not totally reversible. Additionally, CLS adsorption was tested on five minerals common to oil reservoirs; it was found that CLS concentration, salinity, temperature, and mineral type had significant effects on adsorption. The adsorption density from most to least was: bentonite > kaolinite > dolomite > calcite > silica. This work demonstrates the extent of dissolution and precipitation from co-injection of CO{sub 2} and brine in limestone core

  3. Anisotropic rock physics models for interpreting pore structures in carbonate reservoirs

    NASA Astrophysics Data System (ADS)

    Li, Sheng-Jie; Shao, Yu; Chen, Xu-Qiang

    2016-03-01

    We developed an anisotropic effective theoretical model for modeling the elastic behavior of anisotropic carbonate reservoirs by combining the anisotropic self-consistent approximation and differential effective medium models. By analyzing the measured data from carbonate samples in the TL area, a carbonate pore-structure model for estimating the elastic parameters of carbonate rocks is proposed, which is a prerequisite in the analysis of carbonate reservoirs. A workflow for determining elastic properties of carbonate reservoirs is established in terms of the anisotropic effective theoretical model and the pore-structure model. We performed numerical experiments and compared the theoretical prediction and measured data. The result of the comparison suggests that the proposed anisotropic effective theoretical model can account for the relation between velocity and porosity in carbonate reservoirs. The model forms the basis for developing new tools for predicting and evaluating the properties of carbonate reservoirs.

  4. Rock-physics and seismic-inversion based reservoir characterization of the Haynesville Shale

    NASA Astrophysics Data System (ADS)

    Jiang, Meijuan; Spikes, Kyle T.

    2016-06-01

    Seismic reservoir characterization of unconventional gas shales is challenging due to their heterogeneity and anisotropy. Rock properties of unconventional gas shales such as porosity, pore-shape distribution, and composition are important for interpreting seismic data amplitude variations in order to locate optimal drilling locations. The presented seismic reservoir characterization procedure applied a grid-search algorithm to estimate the composition, pore-shape distribution, and porosity at the seismic scale from the seismically inverted impedances and a rock-physics model, using the Haynesville Shale as a case study. All the proposed rock properties affected the seismic velocities, and the combined effects of these rock properties on the seismic amplitude were investigated simultaneously. The P- and S-impedances correlated negatively with porosity, and the V P/V S correlated positively with clay fraction and negatively with the pore-shape distribution and quartz fraction. The reliability of these estimated rock properties at the seismic scale was verified through comparisons between two sets of elastic properties: one coming from inverted impedances, which were obtained from simultaneous inversion of prestack seismic data, and one derived from these estimated rock properties. The differences between the two sets of elastic properties were less than a few percent, verifying the feasibility of the presented seismic reservoir characterization.

  5. SEISMIC AND ROCK PHYSICS DIAGNOSTICS OF MULTISCALE RESERVOIR TEXTURES

    SciTech Connect

    Gary Mavko

    2003-06-30

    As part of our study on ''Relationships between seismic properties and rock microstructure'', we have studied (1) Methods for detection of stress-induced velocity anisotropy in sands. (2) We have initiated efforts for velocity upscaling to quantify long-wavelength and short-wavelength velocity behavior and the scale-dependent dispersion caused by sediment variability in different depositional environments.

  6. Class III Mid-Term Project, "Increasing Heavy Oil Reserves in the Wilmington Oil Field Through Advanced Reservoir Characterization and Thermal Production Technologies"

    SciTech Connect

    Scott Hara

    2007-03-31

    The overall objective of this project was to increase heavy oil reserves in slope and basin clastic (SBC) reservoirs through the application of advanced reservoir characterization and thermal production technologies. The project involved improving thermal recovery techniques in the Tar Zone of Fault Blocks II-A and V (Tar II-A and Tar V) of the Wilmington Field in Los Angeles County, near Long Beach, California. A primary objective has been to transfer technology that can be applied in other heavy oil formations of the Wilmington Field and other SBC reservoirs, including those under waterflood. The first budget period addressed several producibility problems in the Tar II-A and Tar V thermal recovery operations that are common in SBC reservoirs. A few of the advanced technologies developed include a three-dimensional (3-D) deterministic geologic model, a 3-D deterministic thermal reservoir simulation model to aid in reservoir management and subsequent post-steamflood development work, and a detailed study on the geochemical interactions between the steam and the formation rocks and fluids. State of the art operational work included drilling and performing a pilot steam injection and production project via four new horizontal wells (2 producers and 2 injectors), implementing a hot water alternating steam (WAS) drive pilot in the existing steamflood area to improve thermal efficiency, installing a 2400-foot insulated, subsurface harbor channel crossing to supply steam to an island location, testing a novel alkaline steam completion technique to control well sanding problems, and starting on an advanced reservoir management system through computer-aided access to production and geologic data to integrate reservoir characterization, engineering, monitoring, and evaluation. The second budget period phase (BP2) continued to implement state-of-the-art operational work to optimize thermal recovery processes, improve well drilling and completion practices, and evaluate the

  7. 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

  8. Detailed Study of Seismic Wave Attenuation in Carbonate Rocks: Application on Abu Dhabi Oil Fields

    NASA Astrophysics Data System (ADS)

    Bouchaala, F.; Ali, M. Y.; Matsushima, J.

    2015-12-01

    Seismic wave attenuation is a promising attribute for the petroleum exploration, thanks to its high sensitivity to physical properties of subsurface. It can be used to enhance the seismic imaging and improve the geophysical interpretation which is crucial for reservoir characterization. However getting an accurate attenuation profile is not an easy task, this is due to complex mechanism of this parameter, although that many studies were carried out to understand it. The degree of difficulty increases for the media composed of carbonate rocks, known to be highly heterogeneous and with complex lithology. That is why few attenuation studies were done successfully in carbonate rocks. The main objectives of this study are, Getting an accurate and high resolution attenuation profiles from several oil fields. The resolution is very important target for us, because many reservoirs in Abu Dhabi oil fields are tight.Separation between different modes of wave attenuation (scattering and intrinsic attenuations).Correlation between the attenuation profiles and other logs (Porosity, resistivity, oil saturation…), in order to establish a relationship which can be used to detect the reservoir properties from the attenuation profiles.Comparison of attenuation estimated from VSP and sonic waveforms. Provide spatial distribution of attenuation in Abu Dhabi oil fields.To reach these objectives we implemented a robust processing flow and new methodology to estimate the attenuation from the downgoing waves of the compressional VSP data and waveforms acquired from several wells drilled in Abu Dhabi. The subsurface geology of this area is primarily composed of carbonate rocks and it is known to be highly fractured which complicates more the situation, then we separated successfully the intrinsic attenuation from the scattering. The results show that the scattering is significant and cannot be ignored. We found also a very interesting correlation between the attenuation profiles and the

  9. Hydraulic characterization of aquifers, reservoir rocks, and soils: A history of ideas

    NASA Astrophysics Data System (ADS)

    Narasimhan, T. N.

    1998-01-01

    Estimation of the hydraulic properties of aquifers, petroleum reservoir rocks, and soil systems is a fundamental task in many branches of Earth sciences and engineering. The transient diffusion equation proposed by Fourier early in the 19th century for heat conduction in solids constitutes the basis for inverting hydraulic test data collected in the field to estimate the two basic parameters of interest, namely, hydraulic conductivity and hydraulic capacitance. Combining developments in fluid mechanics, heat conduction, and potential theory, the civil engineers of the 19th century, such as Darcy, Dupuit, and Forchheimer, solved many useful problems of steady state seepage of water. Interest soon shifted towards the understanding of the transient flow process. The turn of the century saw Buckingham establish the role of capillary potential in governing moisture movement in partially water-saturated soils. The 1920s saw remarkable developments in several branches of the Earth sciences; Terzaghi's analysis of deformation of watersaturated earth materials, the invention of the tensiometer by Willard Gardner, Meinzer's work on the compressibility of elastic aquifers, and the study of the mechanics of oil and gas reservoirs by Muskat and others. In the 1930s these led to a systematic analysis of pressure transients from aquifers and petroleum reservoirs through the work of Theis and Hurst. The response of a subsurface flow system to a hydraulic perturbation is governed by its geometric attributes as well as its material properties. In inverting field data to estimate hydraulic parameters, one makes the fundamental assumption that the flow geometry is known a priori. This approach has generally served us well in matters relating to resource development primarily concerned with forecasting fluid pressure declines. Over the past two decades, Earth scientists have become increasingly concerned with environmental contamination problems. The resolution of these problems

  10. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect

    Scott Hara

    2001-05-08

    The project involves using advanced reservoir characterization and thermal production technologies to improve thermal recovery techniques and lower operating and capital costs in a slope and basin clastic (SBC) reservoir in the Wilmington field, Los Angeles Co., CA. Through March 2001, project work has been completed on the following activities: data preparation; basic reservoir engineering; developing a deterministic three dimensional (3-D) geologic model, a 3-D deterministic reservoir simulation model and a rock-log model; well drilling and completions; and surface facilities on the Fault Block II-A Tar Zone (Tar II-A). Work is continuing on research to understand the geochemistry and process regarding the sand consolidation well completion technique, final reservoir tracer work, operational work and research studies to prevent thermal-related formation compaction in the Tar II-A steamflood area, and operational work on the Tar V steamflood pilot and Tar II-A post-steamflood projects. The project team spent the Second Quarter 2001 performing well work and reservoir surveillance on the Tar II-A post-steamflood project. The Tar II-A steamflood reservoirs have been operated over fifteen months at relatively stable pressures, due in large part to the bimonthly pressure monitoring program enacted at the start of the post-steamflood phase in January 1999. Starting in the Fourth Quarter 2000, the project team has ramped up activity to increase production and injection. This work will continue through 2001 as described in the Operational Management section. Expanding thermal recovery operations to other sections of the Wilmington Oil Field, including the Tar V horizontal well pilot steamflood project, is a critical part of the City of Long Beach and Tidelands Oil Production Company's development strategy for the field. The current steamflood operations in the Tar V pilot are economical, but recent performance is below projections because of wellbore mechanical

  11. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect

    Scott Hara

    2001-11-01

    The project involves using advanced reservoir characterization and thermal production technologies to improve thermal recovery techniques and lower operating and capital costs in a slope and basin clastic (SBC) reservoir in the Wilmington field, Los Angeles Co., Calif. Through June 2001, project work has been completed on the following activities: data preparation; basic reservoir engineering; developing a deterministic three dimensional (3-D) geologic model, a 3-D deterministic reservoir simulation model and a rock-log model; well drilling and completions; and surface facilities on the Fault Block II-A Tar Zone (Tar II-A). Work is continuing on research to understand the geochemistry and process regarding the sand consolidation well completion technique, final reservoir tracer work, operational work and research studies to prevent thermal-related formation compaction in the Tar II-A steamflood area, and operational work on the Tar V steamflood pilot and Tar II-A post-steamflood projects. The project team spent the Third Quarter 2001 performing well work and reservoir surveillance on the Tar II-A post-steamflood project. The Tar II-A post-steamflood operation started in February 1999 and steam chest fillup occurred in September-October 1999. The targeted reservoir pressures in the ''T'' and ''D'' sands are maintained at 90 {+-} 5% hydrostatic levels by controlling water injection and gross fluid production and through the bimonthly pressure monitoring program enacted at the start of the post-steamflood phase. The project team ramped up well work activity from October 2000 to September 2001 to increase production and injection. This work will continue through 2001 as described in the Operational Management section. Expanding thermal recovery operations to other sections of the Wilmington Oil Field, including the Tar V horizontal well pilot steamflood project, is a critical part of the City of Long Beach and Tidelands Oil Production Company's development strategy for

  12. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect

    Scott Hara

    2002-01-31

    The project involves using advanced reservoir characterization and thermal production technologies to improve thermal recovery techniques and lower operating and capital costs in a slope and basin clastic (SBC) reservoir in the Wilmington field, Los Angeles Co., Calif. Through September 2001, project work has been completed on the following activities: data preparation; basic reservoir engineering; developing a deterministic three dimensional (3-D) geologic model, a 3-D deterministic reservoir simulation model and a rock-log model; well drilling and completions; and surface facilities on the Fault Block II-A Tar Zone (Tar II-A). Work is continuing on research to understand the geochemistry and process regarding the sand consolidation well completion technique, final reservoir tracer work, operational work and research studies to prevent thermal-related formation compaction in the Tar II-A steamflood area, and operational work on the Tar V steamflood pilot and Tar II-A post-steamflood projects. The project team spent the Fourth Quarter 2001 performing routine well work and reservoir surveillance on the Tar II-A post-steamflood and Tar V pilot steamflood projects. The Tar II-A post-steamflood operation started in February 1999 and steam chest fillup occurred in September-October 1999. The targeted reservoir pressures in the ''T'' and ''D'' sands are maintained at 90 {+-} 5% hydrostatic levels by controlling water injection and gross fluid production and through the bimonthly pressure monitoring program enacted at the start of the post-steamflood phase. The project team ramped up well work activity from October 2000 through November 2001 to increase production and injection. In December, water injection well FW-88 was plug and abandoned and replaced by new well FW-295 into the ''D'' sands to accommodate the Port of Long Beach at their expense. Well workovers are planned for 2002 as described in the Operational Management section. Expanding thermal recovery operations

  13. Chemical hydrofracturing of the Hot Dry Rock reservoir

    SciTech Connect

    Yakovlev, Leonid

    1996-01-24

    The experimental study of the water-rock interaction shows that the secondary mineral assemblage depends on the water composition. For example, granite-pure water interaction produces zeolites (relatively low-dense, Mg-poor minerals), whereas seawater yields chlorites (high-dense, Mg-rich minerals). The reactions have volumetric effects from several % to 20 % in magnitude. Volume deformations in the heterogeneous matrix cause uneven mechanical strains. Reactions with the effect of about 0,1 vol.% may cause strains of the order of 100-1000 bars being enough for destruction of rocks. Signs and magnitudes of local volume changes depend on the mineral composition of the secondary assemblage. Hence, one can provide either healing or cracking of primary fractures, as desired, by changing the composition of water in the water-felsic rock system where some elements (Mg, Fe) are in lack. The techniques of "chemical hydrofracturing" looks promising as applied to a granite HDR massif. One can regulate the permeability of fractured flow paths by changing in concord the composition and pressure of the injected water. This approach should promote efficient extraction of the petrothermal energy.

  14. Controls on CO2 Mineralization in Volcanogenic Sandstone Reservoir Rocks

    NASA Astrophysics Data System (ADS)

    Zhang, S.; DePaolo, D. J.; Xu, T.; Voltolini, M.

    2013-12-01

    We proposed to use volcanogenic sandstones for CO2 sequestration. Such sandstones with a relatively high percentage of volcanic rock fragments (VRF) could be a promising target for CO2 sequestration in that they have a sufficient percentage of reactive minerals to allow substantial mineralization of injected scCO2, which provides the most secure form of CO2 storage, but can also be porous and permeable enough to allow injection at acceptable rates. Modeling results from reactive transport code TOUGHREACT show that as much as 80% CO2 mineralization could occur in 1000 years in rocks with 10-20% volcanic rock fragments and still allow sufficient injectivity so that ca. 1 megaton of CO2 can be injected per year per well. The key to estimating how much CO2 can be injected and mineralized is the relationship between permeability (or injectivity) and reactive mineral content. We have sampled examples of volcanogenic sandstones from Miocene Etchegoin Formation, central California to examine these relationships. Characterizations of these samples by SEM, XRF and XRD show that they are rich in reactive minerals with around 32% plagioclase, 10% clinopyroxene, 2% diopside, and 1% ilmenite. Porosities range from 10% to 20%, and permeabilities range from 10 mD to 1000 mD. Batch experiments are also in progress to obtain realistic reactivity estimates. Figure 1. Outcrop photo and photomicrograph showing volcanic mineralogy and abundant pore space from Miocene Etchegoin Formation, central California

  15. Numerical simulation of the electrical properties of shale gas reservoir rock based on digital core

    NASA Astrophysics Data System (ADS)

    Nie, Xin; Zou, Changchun; Li, Zhenhua; Meng, Xiaohong; Qi, Xinghua

    2016-08-01

    In this paper we study the electrical properties of shale gas reservoir rock by applying the finite element method to digital cores which are built based on an advanced Markov Chain Monte Carlo method and a combination workflow. Study shows that the shale gas reservoir rock has strong anisotropic electrical conductivity because the conductivity is significantly different in both horizontal and vertical directions. The Archie formula is not suitable for application in shale reservoirs. The formation resistivity decreases in two cases; namely (a) with the increase of clay mineral content and the cation exchange capacity of clay, and (b) with the increase of pyrite content. The formation resistivity is not sensitive to the solid organic matter but to the clay and gas in the pores.

  16. High permeability heavy oil reservoir nitrogen injection EOR research

    NASA Astrophysics Data System (ADS)

    Wu, Xiaodong; Wang, Yining; Wang, Ruihe; Han, Guoqing; An, Yongsheng

    2014-05-01

    Nitrogen chemically very unreactive under normal showed great inertia. It is difficult to burn , dry, non-explosive , non-toxic , non-corrosive , and thus the use of safe and reliable. Coefficient of variation of nitrogen increases with increasing pressure , less affected by temperature . Under the same conditions, the ratio of the nitrogen gas formation volume factor carbon dioxide gas is high, about three times the carbon dioxide , the greater the elastic expansion of nitrogen play a beneficial role in flooding . EOR project trends increase the number of oil and gas injection gas injection from the calendar view, carbon dioxide miscible flooding gas injection EOR is the focus of the flue gas project currently has less to carry , nitrogen flooding is still subject to considerable attention. Note the nitrogen requirements of the basic conditions for enhanced oil recovery from major tectonic conditions , reservoir properties of crude nature of the gas injection timing and other aspects to consider , for different reservoir injected in different ways. Oilfield against a thick , high permeability and other characteristics, to improve oil recovery by injecting nitrogen indoor experiments conducted nitrogen injection process factors and supporting technical studies ; and introduced the field of nitrogen injection EOR field test conditions .

  17. Streaming Potential In Rocks Saturated With Water And Oil

    NASA Astrophysics Data System (ADS)

    Tarvin, J. A.; Caston, A.

    2011-12-01

    Fluids flowing through porous media generate electrical currents. These currents cause electric potentials, called "streaming potentials." Streaming potential amplitude depends on the applied pressure gradient, on rock and fluid properties, and on the interaction between rock and fluid. Streaming potential has been measured for rocks saturated with water (1) and with water-gas mixtures. (2) Few measurements (3) have been reported for rocks saturated with water-oil mixtures. We measured streaming potential for sandstone and limestone saturated with a mixture of brine and laboratory oil. Cylindrical samples were initially saturated with brine and submerged in oil. Saturation was changed by pumping oil from one end of a sample to the other and then through the sample in the opposite direction. Saturation was estimated from sample resistivity. The final saturation of each sample was determined by heating the sample in a closed container and measuring the pressure. Measurements were made by modulating the pressure difference (of oil) between the ends of a sample at multiple frequencies below 20 Hz. The observed streaming potential is a weak function of the saturation. Since sample conductivity decreases with increasing oil saturation, the electro-kinetic coupling coefficient (Pride's L (4)) decreases with increasing oil saturation. (1) David B. Pengra and Po-zen Wong, Colloids and Surfaces, vol., p. 159 283-292 (1999). (2) Eve S. Sprunt, Tony B. Mercer, and Nizar F. Djabbarah, Geophysics, vol. 59, p. 707-711 (1994). (3) Vinogradov, J., Jackson, M.D., Geophysical Res. L., Vol. 38, Article L01301 (2011). (4) Steve Pride, Phys. Rev. B, vol. 50, pp. 15678-15696 (1994).

  18. EVALUATION OF RESERVOIR ROCK AND WELL BORE CEMENT ALTERATION WITH SUPERCRITICAL CO2

    SciTech Connect

    William k. O'Connor; Gilbert E Rush

    2009-01-01

    An evaluation of the alteration of reservoir rock and well bore cement at their interface, under supercritical CO{sub 2} (SCCO{sub 2}), was conducted at the laboratory-scale using simulated brine solutions at down-hole conditions. These studies were intended to identify potential leakage pathways for injected CO{sub 2} due to degradation of the well bore. Two distinct test series were conducted on core samples of the Mt. Simon sandstone from the Illinois Basin, IL, and the Grand Ronde basalt from the Pasco Basin, WA. LaFarge Class H well bore cement was used for both series. Reservoir rock/cement cores were immersed within a CO{sub 2}-saturated brine for up to 2000 hours at 35 degrees C and 100 atm CO{sub 2}. Results suggest that the impact of SCCO{sub 2} injection is reservoir-specific, being highly dependent on the reservoir brine and rock type. Brine pH can be significantly altered by CO{sub 2} injection, which in turn can dramatically impact the dissolution characteristics of the reservoir rock. Finally, well bore cement alteration was identified, particularly for fresh cast cement allowed to cure at SCCO{sub 2} conditions. However, this alteration was generally limited to an outer rind of carbonate and Ca-depleted cement which appeared to protect the majority of the cement core from further attack. These studies indicate that at the cement-rock interface, the annular space may be filled by carbonate which could act as an effective barrier against further CO{sub 2} migration along the well bore.

  19. Geochemical simulations on CO2-fluid-rock interactions in EGS reservoirs

    NASA Astrophysics Data System (ADS)

    Pan, F.; McPherson, B. J.; Lichtner, P. C.; Kaszuba, J. P.; Lo Re, C.; Karra, S.; Lu, C.; Xu, T.

    2012-12-01

    Supercritical CO2 has been suggested as a heat transmission fluid in Enhanced Geothermal Systems (EGS) reservoirs to improve energy extraction. Understanding the geochemical processes of CO2-fluid-rock interactions in EGS reservoirs is significant important to investigate the performance of energy extraction with CO2 instead of water as a working fluid, carbon sequestration and risk assessment. The objectives of this study: (1) to calibrate and evaluate the kinetic rate constants and specific reactive surface areas of minerals based on the batch experimental data conducted by other researchers (collaborators Kaszuba and Lo Ré at the University of Wyoming); (2) to investigate the effects of CO2-fluid-rock geochemical interactions on the energy extraction efficiency, carbon sequestration, and risk assessment. A series of laboratory experiments were conducted (Lo Ré et al., 2012) to investigate the geochemical reactions among water, fractured granite rocks, and injected supercritical CO2 at elevated temperatures of 250 oC, and pressures of 250-450 bars. The batch simulations were firstly conducted to mimic the laboratory experiments with the calibration of mineral reactive surface areas using TOUGHREACT model and parameter estimation software (PEST). Then, we performed 2-D geochemical modeling to simulate the chemical interactions among CO2, fluids, and rocks at high temperatures and pressures of EGS reservoirs. We further investigated the effects of fluid-rock interactions on the energy extraction, carbon sequestration, and risk assessment with CO2 as a heat transmission fluid instead of water for EGS reservoirs. Results of carbonate mineral precipitations suggested that the CO2 as a working fluid instead of water was favorable for EGS reservoirs on the CO2 sequestration. Our simulations also suggested that the energy extraction could be enhanced using CO2 as the transmission fluid compared to water.

  20. SEISMIC AND ROCK PHYSICS DIAGNOSTICS OF MULTISCALE RESERVOIR TEXTURES

    SciTech Connect

    Gary Mavko

    2002-05-01

    As part of our study on ''Relationships between seismic properties and rock microstructure'', we have studied (1) How to quantify elastic properties of clay minerals using Atomic Force Acoustic Microscopy. We show how bulk modulus of clay can be measured using atomic force acoustic microscopy (AFAM) (2) We have successfully measured elastic properties of unconsolidated sediments in an effort to quantify attributes for detection of overpressures from seismic (3) We have initiated efforts for velocity upscaling to quantify long-wavelength and short-wavelength velocity behavior and the scale-dependent dispersion caused by sediment variability in different depositional environments.

  1. Potential evaluation of CO2 storage and enhanced oil recovery of tight oil reservoir in the Ordos Basin, China.

    PubMed

    Tian, Xiaofeng; Cheng, Linsong; Cao, Renyi; Zhang, Miaoyi; Guo, Qiang; Wang, Yimin; Zhang, Jian; Cui, Yu

    2015-07-01

    Carbon -di-oxide (CO2) is regarded as the most important greenhouse gas to accelerate climate change and ocean acidification. The Chinese government is seeking methods to reduce anthropogenic CO2 gas emission. CO2 capture and geological storage is one of the main methods. In addition, injecting CO2 is also an effective method to replenish formation energy in developing tight oil reservoirs. However, exiting methods to estimate CO2 storage capacity are all based on the material balance theory. This was absolutely correct for normal reservoirs. However, as natural fractures widely exist in tight oil reservoirs and majority of them are vertical ones, tight oil reservoirs are not close. Therefore, material balance theory is not adaptive. In the present study, a new method to calculate CO2 storage capacity is presented. The CO2 effective storage capacity, in this new method, consisted of free CO2, CO2 dissolved in oil and CO2 dissolved in water. Case studies of tight oil reservoir from Ordos Basin was conducted and it was found that due to far lower viscosity of CO2 and larger solubility in oil, CO2 could flow in tight oil reservoirs more easily. As a result, injecting CO2 in tight oil reservoirs could obviously enhance sweep efficiency by 24.5% and oil recovery efficiency by 7.5%. CO2 effective storage capacity of Chang 7 tight oil reservoir in Longdong area was 1.88 x 10(7) t. The Chang 7 tight oil reservoir in Ordos Basin was estimated to be 6.38 x 10(11) t. As tight oil reservoirs were widely distributed in Songliao Basin, Sichuan Basin and so on, geological storage capacity of CO2 in China is potential. PMID:26387353

  2. Increasing Waterflood Reserves in the Wilmington Oil Field Through Improved Reservoir Characterization and Reservoir Management

    SciTech Connect

    Chris Phillips; Dan Moos; Don Clarke; Dwasi Tagbor; John Nguygen; Roy Koerner; Scott Walker

    1997-04-10

    The objectives of this quarterly report are to summarize the work conducted under each task during the reporting period January - March 1997 and to report all technical data and findings as specified in the "Federal Assistance Reporting Checklist". The main objective of this project is the transfer of technologies, methodologies, and findings developed and applied in this project to other operators of Slope and Basin Clastic Reservoirs. This project will study methods to identify sands with high remaining oil saturation and to recomplete existing wells using advanced completion technology.

  3. Evaluation of Reservoir Wettability and its Effect on Oil Recovery.

    SciTech Connect

    Buckley, J.S.

    1998-01-15

    We report on the first year of the project, `Evaluation of Reservoir Wettability and its Effect on Oil Recovery.` The objectives of this five-year project are (1) to achieve improved understanding of the surface and interfacial properties of crude oils and their interactions with mineral surfaces, (2) to apply the results of surface studies to improve predictions of oil production from laboratory measurements, and (3) to use the results of this research to recommend ways to improve oil recovery by waterflooding. During the first year of this project we have focused on understanding the interactions between crude oils and mineral surfaces that establish wetting in porous media. As background, mixed-wetting and our current understanding of the influence of stable and unstable brine films are reviewed. The components that are likely to adsorb and alter wetting are divided into two groups: those containing polar heteroatoms, especially organic acids and bases; and the asphaltenes, large molecules that aggregate in solution and precipitate upon addition of n-pentane and similar agents. Finally, the test procedures used to assess the extent of wetting alteration-tests of adhesion and adsorption on smooth surfaces and spontaneous imbibition into porous media are introduced. In Part 1, we report on studies aimed at characterizing both the acid/base and asphaltene components. Standard acid and base number procedures were modified and 22 crude oil samples were tested. Our approach to characterizing the asphaltenes is to focus on their solvent environment. We quantify solvent properties by refractive index measurements and report the onset of asphaltene precipitation at ambient conditions for nine oil samples. Four distinct categories of interaction mechanisms have been identified that can be demonstrated to occur when crude oils contact solid surfaces: polar interactions can occur on dry surfaces, surface precipitation is important if the oil is a poor solvent for its

  4. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect

    Scott Hara

    2000-12-06

    Through December 1999, project work has been completed on the following activities: data preparation; basic reservoir engineering; developing a deterministic three dimensional (3-D) geologic model, a 3-D deterministic reservoir simulation model and a rock-log model; well drilling and completions; and surface facilities on the Fault Block II-A Tar (Tar II-A) Zone. Work is continuing on improving core analysis techniques, final reservoir tracer work, operational work and research studies to prevent thermal-related formation compaction in the Tar II-A steamflood area, and operational work on the Tar V steamflood pilot and Tar II-A post steamflood project. Work was discontinued on the stochastic geologic model and developing a 3-D stochastic thermal reservoir simulation model of the Tar II-A Zone in order to focus the remaining time on using the 3-D deterministic reservoir simulation model to provide alternatives for the Tar II-A post steamflood operations and shale compaction studies. Thermal-related formation compaction is a concern of the project team due to observed surface subsidence in the local area above the Tar II-A steamflood project. On January 12, 1999, the steamflood project lost its inexpensive steam source from the Harbor Cogeneration Plant as a result of the recent deregulation of electrical power rates in California. An operational plan was developed and implemented to mitigate the effects of the two situations by injecting cold water into the flanks of the steamflood. The purpose of flank injection has been to increase and subsequently maintain reservoir pressures at a level that would fill-up the steam chests in the ''T'' and ''D'' sands before they can collapse and cause formation compaction and to prevent the steam chests from reoccurring. A new 3-D deterministic thermal reservoir simulation model was used to provide operations with the necessary water injection rates and allowable production rates by well to minimize future surface subsidence and

  5. USE OF POLYMERS TO RECOVER VISCOUS OIL FROM UNCONVENTIONAL RESERVOIRS

    SciTech Connect

    Randall Seright

    2011-09-30

    This final technical progress report summarizes work performed the project, 'Use of Polymers to Recover Viscous Oil from Unconventional Reservoirs.' The objective of this three-year research project was to develop methods using water soluble polymers to recover viscous oil from unconventional reservoirs (i.e., on Alaska's North Slope). The project had three technical tasks. First, limits were re-examined and redefined for where polymer flooding technology can be applied with respect to unfavorable displacements. Second, we tested existing and new polymers for effective polymer flooding of viscous oil, and we tested newly proposed mechanisms for oil displacement by polymer solutions. Third, we examined novel methods of using polymer gels to improve sweep efficiency during recovery of unconventional viscous oil. This report details work performed during the project. First, using fractional flow calculations, we examined the potential of polymer flooding for recovering viscous oils when the polymer is able to reduce the residual oil saturation to a value less than that of a waterflood. Second, we extensively investigated the rheology in porous media for a new hydrophobic associative polymer. Third, using simulation and analytical studies, we compared oil recovery efficiency for polymer flooding versus in-depth profile modification (i.e., 'Bright Water') as a function of (1) permeability contrast, (2) relative zone thickness, (3) oil viscosity, (4) polymer solution viscosity, (5) polymer or blocking-agent bank size, and (6) relative costs for polymer versus blocking agent. Fourth, we experimentally established how much polymer flooding can reduce the residual oil saturation in an oil-wet core that is saturated with viscous North Slope crude. Finally, an experimental study compared mechanical degradation of an associative polymer with that of a partially hydrolyzed polyacrylamide. Detailed results from the first two years of the project may be found in our first and

  6. Velocity dispersion: A tool for characterizing reservoir rocks

    USGS Publications Warehouse

    Brown, R.L.; Seifert, D.

    1997-01-01

    Apparent discrepancies between velocity measurements made with different frequencies in a formation at the Gypsy test site are explained in terms of elastic scattering and intrinsic attenuation. The elastic scattering component of the dispersion (38%) in a marine interval above the Gypsy sandstone is estimated via simple models constructed from well log information. Any dispersion above the predicted value for elastic scattering in this interval is assigned to intrinsic attenuation (62%). Using the vertical measurements in the well, the marine interval directly above the Gypsy sandstone has an estimated intrinsic Q1 = 51 and an effective Q because of the scattering of Qsc = 85. The total Q of the combined mechanisms is 32. The dispersion of the vertical measurements through the heterogeneous sands and shales of the Gypsy formation can be explained using an intrinsic QI = 30 and neglecting the effects of scattering. The horizontal observations require a more detailed modeling effort to unravel the relative roles of path and volume effects, elastic scattering, attenuation, and intrinsic anisotropy. Thin layers barely resolvable on the sonic logs play a significant role in modifying the crosswell response. Potentially, the dispersion can be a key to mapping reservoir properties using crosswell and surface seismic data.

  7. Data requirements and acquisition for reservoir characterization

    SciTech Connect

    Jackson, S.; Chang, Ming Ming; Tham, Min.

    1993-03-01

    This report outlines the types of data, data sources and measurement tools required for effective reservoir characterization, the data required for specific enhanced oil recovery (EOR) processes, and a discussion on the determination of the optimum data density for reservoir characterization and reservoir modeling. The two basic sources of data for reservoir characterization are data from the specific reservoir and data from analog reservoirs, outcrops, and modern environments. Reservoir data can be divided into three broad categories: (1) rock properties (the container) and (2) fluid properties (the contents) and (3)interaction between reservoir rock and fluid. Both static and dynamic measurements are required.

  8. A rock physics model for analysis of anisotropic parameters in a shale reservoir in Southwest China

    NASA Astrophysics Data System (ADS)

    Qian, Keran; Zhang, Feng; Chen, Shuangquan; Li, Xiangyang; Zhang, Hui

    2016-02-01

    A rock physics model is a very effective tool to describe the anisotropy and mechanical properties of rock from a seismology perspective. Compared to a conventional reservoir, modelling a shale reservoir requires us to face two main challenges in modelling: the existence of organic matter and strong anisotropy. We construct an anisotropic rock physics workflow for a typical shale reservoir in Southwest China, in which the organic matter is treated separately from other minerals by using a combination of anisotropic self-consistent approximation and the differential effective medium method. The standard deviation of the distribution function is used to model the degree of lamination of clay and kerogen. A double scan workflow is introduced to invert the probability of pore aspect ratio and lamination simultaneously, which can give us a better understanding of the shale formation. The anisotropic properties of target formation have been analysed based on the proposed model. Inverted Thomsen parameters, especially the sign of delta, are analysed in terms of the physical properties of rock physics modelling.

  9. Combining rock physics and sedimentology for seismic reservoir characterization of North Sea turbidite systems

    NASA Astrophysics Data System (ADS)

    Avseth, Per Age

    The petroleum industry is increasing its focus on the exploration of reservoirs in turbidite systems. However, these sedimentary environments are often characterized by very complex sand distributions. Hence, reservoir description based on conventional seismic and well-log interpretation may be very uncertain. There is a need to employ more quantitative seismic techniques to reveal reservoirs units in these complex systems from seismic amplitude data. In this study we focus on North Sea turbidite systems. Our goal is to improve the ability to use 3D seismic data to map reservoirs in these systems. A cross-disciplinary methodology for seismic reservoir characterization is presented that combines rock physics, sedimentology, and statistical techniques. We apply this methodology to two turbidite systems of Paleocene age located in the South Viking Graben of the North Sea. First, we investigate the relationship between sedimentary petrography and rock physics properties. Next, we define seismic scale sedimentary units, referred to as seismic lithofacies. These facies represent populations of data that have characteristic geologic and seismic properties. We establish a statistically representative training database by identifying seismic lithofacies from thin-sections, cores, and well-log data. This procedure is guided by diagnostic rock physics modeling. Based on the training data, we perform multivariate classification of data from several wells in the area. Next, we assess uncertainties in amplitude versus offset (AVO) response related to the inherent natural variability of each seismic lithofacies. We generate bivariate probability density functions (pdfs) of two AVO parameters for different facies combinations. By combining the bivariate pdfs estimated from well-logs with the AVO parameters estimated from seismic data, we use both quadratic discriminant analysis and Bayesian classification to predict lithofacies and pore fluids from seismic amplitudes. The final

  10. Estimation of Physical Property Changes by Oil Saturation in Carbonates and Sandstone Using Computational Rock Physics Methods

    NASA Astrophysics Data System (ADS)

    Lee, M.; Keehm, Y.

    2010-12-01

    Carbonate Reservoirs are drawing a great attention as global energy demands and consumption increase rapidly, since more than 60% of oil and 40% of gas of world reserves are in carbonate rocks. However, most of them are hard to develop mainly due to their complexity and heterogeneity, especially at the pore scale. In this study, we perform computational rock physics modeling (numerical simulations on pore microstructures of carbonate rocks) and compare the results with those from sandstone. The brief procedure of the method is (1) to obtain high-resolution pore microstructure with a spatial resolution of 1-2 micron by X-ray microtomography technique, (2) to perform two-phase lattice-Boltzmann (LB) flow simulation to obtain various oil and water saturations, then (3) to calculate physical properties, such as P-wave velocity and electrical conductivity through pore-scale property simulation techniques. For the carbonate rock, we identified much more isolated pores than sandstone by investigating pore microstructures. Thus permeability and electrical conductivity were much smaller than those of sandstone. The electrical conductivity versus oil saturation curve of the carbonate rock showed sharper decrease at low oil saturation, but similar slope at higher oil saturation. We think that higher complexity of pore connectivity is responsible for this effect. The P-wave velocity of the carbonate rock was much higher than sandstone and the it did not show any significant changes during the change of oil saturation. Therefore, we think that fluid discrimination by seismic data with P-wave velocity alone would pose a greate challenge in most carbonate reservoirs. In addition, the S-wave velocity seems not to be sensitive either, which suggest that the AVO-type analysis would also be difficult, though requires more researches. On the other hand, our computational rock physics approach can be useful in preliminary analysis of carbonate reservoirs since it can determine the

  11. Advanced Characterization of Fractured Reservoirs in Carbonate Rocks: The Michigan Basin

    SciTech Connect

    Wood, James R.; Harrison, William B.

    2000-10-24

    The main objective of this project is for a university-industry consortium to develop a comprehensive model for fracture carbonate reservoirs based on the ''data cube'' concept using the Michigan Basin as a prototype. This project combined traditional historical data with 2D and 3D seismic data as well as data from modern logging tools in a novel way to produce a new methodology for characterizing fractured reservoirs in carbonate rocks. Advanced visualization software was used to fuse the data and to image it on a variety of scales, ranging from basin-scale to well-scales.

  12. Advanced Characterization of Fractured Reservoirs in Carbonate Rocks: The Michigan Basin

    SciTech Connect

    Wood, J.R.; Harrison, W.B.

    2001-01-22

    The main objective of this project is for a university-industry consortium to develop a comprehensive model for fracture carbonate reservoirs based on the ''data cube'' concept using the Michigan Basin as a prototype. This project combined traditional historical data with 2D and 3D seismic data as well as data from modern logging tools in a novel way to produce a new methodology for characterizing fractured reservoirs in carbonate rocks. Advanced visualization software was used to fuse the data and to image it on a variety of scales, ranging from basin-scale to well-scales.

  13. Multiporosity flow in fractured low-permeability rocks: Extension to shale hydrocarbon reservoirs

    SciTech Connect

    Kuhlman, Kristopher L.; Malama, Bwalya; Heath, Jason E.

    2015-02-05

    We presented a multiporosity extension of classical double and triple-porosity fractured rock flow models for slightly compressible fluids. The multiporosity model is an adaptation of the multirate solute transport model of Haggerty and Gorelick (1995) to viscous flow in fractured rock reservoirs. It is a generalization of both pseudo steady state and transient interporosity flow double-porosity models. The model includes a fracture continuum and an overlapping distribution of multiple rock matrix continua, whose fracture-matrix exchange coefficients are specified through a discrete probability mass function. Semianalytical cylindrically symmetric solutions to the multiporosity mathematical model are developed using the Laplace transform to illustrate its behavior. Furthermore, the multiporosity model presented here is conceptually simple, yet flexible enough to simulate common conceptualizations of double and triple-porosity flow. This combination of generality and simplicity makes the multiporosity model a good choice for flow modelling in low-permeability fractured rocks.

  14. Multiporosity flow in fractured low-permeability rocks: Extension to shale hydrocarbon reservoirs

    DOE PAGESBeta

    Kuhlman, Kristopher L.; Malama, Bwalya; Heath, Jason E.

    2015-02-05

    We presented a multiporosity extension of classical double and triple-porosity fractured rock flow models for slightly compressible fluids. The multiporosity model is an adaptation of the multirate solute transport model of Haggerty and Gorelick (1995) to viscous flow in fractured rock reservoirs. It is a generalization of both pseudo steady state and transient interporosity flow double-porosity models. The model includes a fracture continuum and an overlapping distribution of multiple rock matrix continua, whose fracture-matrix exchange coefficients are specified through a discrete probability mass function. Semianalytical cylindrically symmetric solutions to the multiporosity mathematical model are developed using the Laplace transform tomore » illustrate its behavior. Furthermore, the multiporosity model presented here is conceptually simple, yet flexible enough to simulate common conceptualizations of double and triple-porosity flow. This combination of generality and simplicity makes the multiporosity model a good choice for flow modelling in low-permeability fractured rocks.« less

  15. Evaluating oil quality and monitoring production from heavy oil reservoirs using geochemical methods: Application to the Boscan Field, Venezuela

    SciTech Connect

    Kaufman, R.L.; Noguera, V.H.; Bantz, D.M.; Rodriguez, R.

    1996-08-01

    Many oil fields worldwide contain heavy oil in one or more reservoir units. The low gravity of these oils is most frequently due to biodegradation and/or low maturity. The challenge is to find ways to economically recover this oil. Methods which reduce the operating costs of producing heavy oil add significant value to such projects. Geochemical techniques which use the composition of the reservoir fluids as natural tracers offer cost effective methods to assist with reservoir management. The low viscosity and gravity of heavy oil, combined with frequent high water cuts, low flow rates, and the presence of downhole artificial lift equipment, make many conventional production logging methods difficult to apply. Therefore, monitoring production, especially if the produced oil is commingled from multiple reservoirs, can be difficult. Geochemical methods can be used to identify oil/water contacts, tubing string leaks and to allocate production to individual zones from commingled production. An example of a giant heavy oil field where geochemical methods may be applicable is the Boscan Field in Venezuela. Low maturity oil, averaging 10{degrees} API gravity, is produced from the Eocene Upper and Lower Boscan (Miosa) Sands. Geochemical, stratigraphic and engineering data have helped to better define the controls on oil quality within the field, identified new reservoir compartments and defined unique characteristics of the Upper and Lower Boscan oils. This information can be used to identify existing wells in need of workovers due to mechanical problems and to monitor production from new infill wells.

  16. 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

  17. Organic geochemistry and petrology of oil source rocks, Carpathian Overthrust region, southeastern Poland - Implications for petroleum generation

    USGS Publications Warehouse

    Kruge, M.A.; Mastalerz, Maria; Solecki, A.; Stankiewicz, B.A.

    1996-01-01

    The organic mailer rich Oligocene Menilite black shales and mudstones are widely distributed in the Carpathian Overthrust region of southeastern Poland and have excellent hydrocarbon generation potential, according to TOC, Rock-Eval, and petrographic data. Extractable organic matter was characterized by an equable distribution of steranes by carbon number, by varying amounts of 28,30-dinor-hopane, 18??(H)-oleanane and by a distinctive group of C24 ring-A degraded triterpanes. The Menilite samples ranged in maturity from pre-generative to mid-oil window levels, with the most mature in the southeastern portion of the study area. Carpathian petroleum samples from Campanian Oligocene sandstone reservoirs were similar in biomarker composition to the Menilite rock extracts. Similarities in aliphatic and aromatic hydrocarbon distributions between petroleum asphaltene and source rock pyrolyzates provided further evidence genetically linking Menilite kerogens with Carpathian oils.

  18. Laboratory measurements on reservoir rocks from The Geysers geothermal field

    SciTech Connect

    Boitnott, G.N.

    1995-01-26

    A suite of laboratory measurements have been conducted on Geysers metagraywacke and metashale recovered from a drilled depth of 2599 to 2602 meters in NEGU-17. The tests have been designed to constrain the mechanical and water-storage properties of the matrix material. Various measurements have been made at a variety of pressures and at varying degrees of saturation. Both compressional and shear velocities exhibit relatively little change with effective confining pressure. In all of the samples, water saturation causes an increase in the compressional velocity. In some samples, saturation results in a moderate decrease in shear velocity greater in magnitude than would be expected based on the slight increase in bulk density. It is found that the effect of saturation on the velocities can be quantitatively modeled through a modification of Biot-Gassmann theory to include weakening of the shear modulus with saturation. The decrease is attributed to chemo-mechanical weakening caused by the presence of water. The degree of frame weakening of the shear modulus is variable between samples, and appears correlated with petrographic features of the cores. Two related models are presented through which we can study the importance of saturation effects on field-scale velocity variations. The model results indicate that the saturation effects within the matrix are significant and may contribute to previously observed field anomalies. The results help to define ways in which we may be able to separate the effects of variations in rock properties, caused by phenomena such as degree of fracturing, from similar effects caused by variations in matrix saturation. The need for both compressional and shear velocity data in order to interpret field anomalies is illustrated through comparisons of model results with the field observations.

  19. Permeability estimation from NMR diffusion measurements in reservoir rocks.

    PubMed

    Balzarini, M; Brancolini, A; Gossenberg, P

    1998-01-01

    It is well known that in restricted geometries, such as in porous media, the apparent diffusion coefficient (D) of the fluid depends on the observation time. From the time dependence of D, interesting information can be derived to characterise geometrical features of the porous media that are relevant in oil industry applications. In particular, the permeability can be related to the surface-to-volume ratio (S/V), estimated from the short time behaviour of D(t), and to the connectivity of the pore space, which is probed by the long time behaviour of D(t). The stimulated spin-echo pulse sequence, with pulsed magnetic field gradients, has been used to measure the diffusion coefficients on various homogeneous and heterogeneous sandstone samples. It is shown that the petrophysical parameters obtained by our measurements are in good agreement with those yielded by conventional laboratory techniques (gas permeability and electrical conductivity). Although the diffusing time is limited by T1, eventually preventing an observation of the real asymptotic behaviour, and the surface-to-volume ratio measured by nuclear magnetic resonance is different from the value obtained by BET because of the different length scales probed, the measurement remains reliable and low-time consuming. PMID:9803918

  20. Improved Oil Recovery in Fluvial Dominated Deltaic Reservoirs of Kansas - Near-Term

    SciTech Connect

    A. Walton; D. McCune; D.W. Green; G.P. Willhite; L. Watney; R. Reynolds; m. Michnick

    1998-04-15

    The objective of this study is to study waterflood problems of the type found in Morrow sandstone. The major tasks undertaken are reservoir characterization and the development of a reservoir database; volumetric analysis to evaluate production performance; reservoir modeling; identification of operational problems; identification of unrecovered mobile oil and estimation of recovery factors; and identification of the most efficient and economical recovery process.

  1. The Werkendam natural CO2 accumulation: An analogue for CO2 storage in depleted oil reservoirs

    NASA Astrophysics Data System (ADS)

    Bertier, Pieter; Busch, Andreas; Hangx, Suzanne; Kampman, Niko; Nover, Georg; Stanjek, Helge; Weniger, Philipp

    2015-04-01

    The Werkendam natural CO2 accumulation is hosted in the Röt (Early Triassic) sandstone of the West Netherlands Basin, at a depth of 2.8 km, about 20 km south-east of Rotterdam (NL). This reservoir, in a fault-bound structure, was oil-filled prior to charging with magmatic CO2 in the early Cretaceous. It therefore offers a unique opportunity to study long-term CO2-water-rock interactions in the presence of oil. This contribution will present the results of a detailed mineralogical and geochemical characterisation of core sections from the Werkendam CO2 reservoir and an adjacent, stratigraphically equivalent aquifer. X-ray diffraction combined with X-ray fluorescence spectrometry revealed that the reservoir samples contain substantially more feldspar and more barite and siderite than those from the aquifer, while the latter have higher hematite contents. These differences are attributed to the effects hydrocarbons and related fluids on diagenesis in the closed system of the CO2 reservoir versus the open-system of the aquifer. Petrophysical analyses yielded overall higher and more anisotropic permeability for the reservoir samples, while the porosity is overall not significantly different from that of their aquifer equivalents. The differences are most pronounced in coarse-grained sandstones. These have low anhydrite contents and contain traces of calcite, while all other analyzed samples contain abundant anhydrite, dolomite/ankerite and siderite, but no calcite. Detailed petrography revealed mm-sized zones of excessive primary porosity. These are attributed to CO2-induced dissolution of precompactional, grain-replacive anhydrite cement. Diagenetic dolomite/ankerite crystals are covered by anhedral, epitaxial ankerite, separated from the crystals by bitumen coats. Since these carbonates were oil-wet before CO2-charging, the overgrowths are interpreted to have grown after CO2-charging. Their anhedral habit suggests growth in a 2-phase water-CO2 system. Isotopic

  2. MULTIDISCIPLINARY IMAGING OF ROCK PROPERTIES IN CARBONATE RESERVOIRS FOR FLOW-UNIT TARGETING

    SciTech Connect

    Stephen C. Ruppel

    2004-07-20

    Our analysis and imaging of reservoir properties at the Fullerton Clear Fork field (Figure 1) is in its final stages. Major accomplishments during the past 6 months include: (1) characterization of facies and cyclicity in cores, (2) correlation of cycles and sequences using core-calibrated wireline logs, (3) calculation and modeling of wireline porosity, (4) analysis of new cores for conventional and special core analysis data, (5) construction of full-field reservoir model, and (6) revision of 3D seismic inversion of reservoir porosity and permeability. One activity has been eliminated from the originally proposed tasks. Task 3 (Characterization and Modeling of Rock Mechanics and Fractures) has been deleted because we have determined that fractures are not significant contributing in the reservoir under study. A second project extension has been asked for to extend the project until 7/31/04. Remaining project activities are: (1) interpretation and synthesis of fieldwide data, (2) preparation of 3D virtual reality demonstrations of reservoir model and attributes, (3) transfer of working data sets to the operator for reservoir implementation and decision-making, and (4) preparation and distribution of final reports.

  3. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect

    Scott Hara

    2000-12-06

    Through March 2000, project work has been completed on the following activities: data preparation; basic reservoir engineering; developing a deterministic three dimensional (3-D) geologic model, a 3-D deterministic reservoir simulation model and a rock-log model; well drilling and completions; and surface facilities on the Fault Block II-A Tar (Tar II-A) Zone. Work is continuing on improving core analysis techniques, final reservoir tracer work, operational work and research studies to prevent thermal-related formation compaction in the Tar II-A steamflood area, and operational work on the Tar V steamflood pilot and Tar II-A post steamflood project. Work was discontinued on the stochastic geologic model and developing a 3-D stochastic thermal reservoir simulation model of the Tar II-A Zone so the project team could use the 3-D deterministic reservoir simulation model to provide alternatives for the Tar II-A post steamflood operations and shale compaction studies. The project team spent the second quarter 2000 writing the 1997-2000 Annual Report, completing research for the project on the subjects mentioned above, and operating the Tar II-A post-steamflood project and the Tar V horizontal well steamflood pilot. Thermal-related formation compaction is a concern of the project team due to observed surface subsidence in the local area above the Tar II-A steamflood project. On January 12, 1999, the steamflood project lost its inexpensive steam source from the Harbor Cogeneration Plant as a result of the recent deregulation of electrical power rates in California. An operational plan was developed and implemented to mitigate the effects of the two situations by injecting cold water into the flanks of the steamflood. The purpose of flank injection has been to increase and subsequently maintain reservoir pressures at a level that would fill-up the steam chests in the ''T'' and ''D'' sands before they can collapse and cause formation compaction and to prevent the steam

  4. Increasing Heavy Oil Reserves in the Wilmington Oil Field Through Advanced Reservoir Characterization and Thermal Production Technologies, Class III

    SciTech Connect

    City of Long Beach; Tidelands Oil Production Company; University of Southern California; David K. Davies and Associates

    2002-09-30

    The objective of this project was to increase the recoverable heavy oil reserves within sections of the Wilmington Oil Field, near Long Beach, California through the testing and application of advanced reservoir characterization and thermal production technologies. It was hoped that the successful application of these technologies would result in their implementation throughout the Wilmington Field and, through technology transfer, will be extended to increase the recoverable oil reserves in other slope and basin clastic (SBC) reservoirs.

  5. The model of the oil-gas bearing molasse reservoirs in the Peri-Adriatic depression, Albania

    SciTech Connect

    Hysen, K.N.; Skender, T.G. )

    1996-01-01

    The Peri-Adriatic Depression (PAD) represents the eastern extension of the Cenozoic Adriatic basin into onshore Albania. Several oil, gas condensate, dry gas fields have been discovered in this basin. Dry gas fields occur mainly in the western sector of the basin, whereas the oil fields are found in the eastern one. Reservoir rocks are well sorted to poorly, fine grained to pebbly sandstones and silstones of Miocene (Serravalian) to Pliocene age, deposited in deep water (turbidite), deltaic and littoral environments. Reservoir beds range in thickness from I to 40 in and are generally regionally distributed. The porosity varies from 3 to 37%, the permeability ranges from low values up to 2200-2500 mD. The minimal value of the porosity measured from oil flowing reservoirs varies from 12% to 16% and for the dry gas 12-21%. Geothermal gradient range from 1.4-2 C/100m. The dimensions of the reservoirs are very different and its geometric shape differs from beds to irregular shape. The types of the traps are also different : lithologo-stratigraphic, lithologic, structural-lithologic ones, etc. The upper part of the Pliocene basin belongs to the delta deposits. The deltaic sandstones are coarse grain to conglomeratic ones, of barriers type, saturated with fresh water and have vast distribution.

  6. The model of the oil-gas bearing molasse reservoirs in the Peri-Adriatic depression, Albania

    SciTech Connect

    Hysen, K.N.; Skender, T.G.

    1996-12-31

    The Peri-Adriatic Depression (PAD) represents the eastern extension of the Cenozoic Adriatic basin into onshore Albania. Several oil, gas condensate, dry gas fields have been discovered in this basin. Dry gas fields occur mainly in the western sector of the basin, whereas the oil fields are found in the eastern one. Reservoir rocks are well sorted to poorly, fine grained to pebbly sandstones and silstones of Miocene (Serravalian) to Pliocene age, deposited in deep water (turbidite), deltaic and littoral environments. Reservoir beds range in thickness from I to 40 in and are generally regionally distributed. The porosity varies from 3 to 37%, the permeability ranges from low values up to 2200-2500 mD. The minimal value of the porosity measured from oil flowing reservoirs varies from 12% to 16% and for the dry gas 12-21%. Geothermal gradient range from 1.4-2 C/100m. The dimensions of the reservoirs are very different and its geometric shape differs from beds to irregular shape. The types of the traps are also different : lithologo-stratigraphic, lithologic, structural-lithologic ones, etc. The upper part of the Pliocene basin belongs to the delta deposits. The deltaic sandstones are coarse grain to conglomeratic ones, of barriers type, saturated with fresh water and have vast distribution.

  7. Atlas of Northern Gulf of Mexico Gas and Oil Reservoirs: Procedures and examples of resource distribution

    SciTech Connect

    Seni, S.J.; Finley, R.J.

    1995-06-01

    The objective of the program is to produce a reservoir atlas series of the Gulf of Mexico that (1) classifies and groups offshore oil and gas reservoirs into a series of geologically defined reservoir plays, (2) compiles comprehensive reservoir play information that includes descriptive and quantitative summaries of play characteristics, cumulative production, reserves, original oil and gas in place, and various other engineering and geologic data, (3) provides detailed summaries of representative type reservoirs for each play, and (4) organizes computerized tables of reservoir engineering data into a geographic information system (GIS). The primary product of the program will be an oil and gas atlas series of the offshore Northern Gulf of Mexico and a computerized geographical information system of geologic and engineering data linked to reservoir location.

  8. Investigation of high-temperature, igneous-related hydraulic fracturing as a reservoir control in the Blackburn and Grant Canyon/Bacon Flat oil fields, Nevada

    SciTech Connect

    Hulen, J.B.

    1991-01-01

    Research in progress to evaluate natural, igenous-related hydrothermal fracturing as a reservoir control in two eastern Nevada oil fields has revealed evidence of a far more comprehensive role for moderate- to high-temperature hydrothermal systems in Basin-and-Range oil-reservoir evolution. Fluid-inclusion and petrographic studies have shown that (now) oil-bearing dolomite breccias of the Blackburn field (Pine Valley, Eureka County) were formed when overpressured, magmatically-heated, high-temperature (>350{degrees}C) hydrothermal brines explosively ruptured their host rocks; similar studies of texturally identical breccias of the Grant Canyon/Bacon Flat field (Railroad Valley, Nye County) so far do not support such an explosive origin. At Grant Canyon, however, hydrothermal, breccia-cementing quartz hosts primary oil, aqueous/oil, and aqueous fluid inclusions (homogenization temperature = 120{degrees}C) which document a direct geothermal connection for oil migration and entrapment. Moreover, at both Blackburn and Grant Canyon/Bacon Flat, the oil reservoirs are top- and side-sealed by hydrothermally altered Tertiary ignimbrites and epiclastic rocks. Contemporary geothermal activity is also apparent at grant Canyon/Bacon Flat, where subsurface water temperatures reach 171{degrees}C, and at Blackburn, above which a petroleum-providing hot spring issues at a temperature of 90{degrees}C. We suggest that in the Basin and Range province, hydrothermal systems may have: (1) matured oil from otherwise submature source rocks; (2) transported oil to ultimate entrapment sites by convection in moderate-to high-temperature fluids; and (3) sealed reservoir traps through hydrothermal alteration of overlying Tertiary caprocks. 69 refs., 11 figs., 1 tab.

  9. Rock-physics-based carbonate pore type characterization and reservoir permeability heterogeneity evaluation, Upper San Andres reservoir, Permian Basin, west Texas

    NASA Astrophysics Data System (ADS)

    Dou, Qifeng; Sun, Yuefeng; Sullivan, Charlotte

    2011-05-01

    In addition to mineral composition and pore fluid, pore type variations play an important role in affecting the complexity of velocity-porosity relationship and permeability heterogeneity of carbonate reservoirs. Without consideration of pore type diversity, most rock physics models applicable to clastic rocks for explaining the rock acoustic properties and reservoir parameters relationship may not work well for carbonate reservoirs. A frame flexibility factor ( γ) defined in a new carbonate rock physics model can quantify the effect of pore structure changes on seismic wave velocity and permeability heterogeneity in carbonate reservoirs. Our study of an Upper San Andres carbonate reservoir, Permian Basin, shows that for core samples of given porosity, the lower the frame flexibility factor ( γ), the higher the sonic wave velocity. For the studied reservoir, samples with frame flexibility factor ( γ) < 3.85 represent either visible vuggy pore space in a dolopackstone or intercrystalline pore space in dolowackstone. On the other hand, samples with frame flexibility factor ( γ) > 3.85 indicate either dominant interparticle pore space in dolopackstone or microcrack pore space in dolowackstone or dolomudstone. Using the frame flexibility factor ( γ), different porosity-impedance and porosity-permeability trends can be classified with clear geologic interpretation such as pore type and rock texture variations to improve porosity and permeability prediction accuracy. New porosity-permeability relations with γ classification help delineate permeability heterogeneity in the Upper San Andres reservoir, and could be useful for other similar carbonate reservoir studies. In addition, results from analysis of amplitude variation with offset (AVO) and impedance modeling indicate that by combining rock physics model and pre-stack seismic inversion, simultaneous estimation of porosity and frame flexibility factor ( γ) is quite feasible because of the strong influence of

  10. Experimental Long-term Investigations on Geothermal Reservoir Rock Properties at Simulated In-situ Conditions

    NASA Astrophysics Data System (ADS)

    Milsch, H.; Spangenberg, E.; Kulenkampff, J.; Schuldt, S.; Huenges, E.

    2006-12-01

    Sustainable energy production from geothermal reservoirs requires an exact knowledge of the hydrological aquifer rock properties as well as the processes that could potentially alter its productivity. The latter comprise both mechanical (e. g. fines migration) and chemical (fluid-rock interactions) effects. To perform controlled long-term investigations on the evolution of sedimentary rock transport properties at conditions pertinent to deep geothermal reservoirs two new permeameters have been set up at the GFZ- Potsdam. The apparatuses allow for a variety of continuous petrophysical measurements at a maximum temperature, lithostatic- and pore pressure of 200 ° C, 140 and 50 MPa, respectively. The permeability, ultra-sonic p- and s-wave velocities and the specific electric conductivity of the rock can be determined. In particular, the use of corrosion-resistant parts allows for experiments with highly saline formation pore fluids that can be sampled under pressure for further chemical analysis. The typical duration of an individual test is four to twelve weeks. Experiments are comparatively performed on two types of sandstones: a Lower Permian (Rotliegend) reservoir rock from Eberswalde, Germany and a pure Quartzite from Fontainebleau, France. In addition, two kinds of pore fluids are used: a low salinity brine (0.1 mol NaCl) and a synthetic Ca-Na-Cl formation fluid with a TDS- content of 250 g/l. In a first series the former fluid was used to petrophysically characterize both rocks as a function of temperature and effective pressure within the relevant range of up to 150 ° C and 75 MPa, respectively. I addition, in a continuous flow experiment the permeability and the specific electric conductivity of the reservoir sandstone were monitored as a function of time during six weeks at constant p-T-conditions. In an ongoing series similar continuous flow experiments are performed using the second, highly saline reservoir fluid. These tests are also complemented by p

  11. Seismoelectric response of heavy oil reservoirs: theory and numerical modelling

    NASA Astrophysics Data System (ADS)

    Revil, A.; Jardani, A.

    2010-02-01

    We consider a linear poroelastic material filled with a linear viscoelastic solvent like wet heavy oils (oil as opposed to water or brines is wetting the surfaces of the pores). We extend the electrokinetic theory in the frequency domain accounting for the relaxation effects associated with resonance of the viscoelastic fluid. The fluid is described by a generalized Maxwell rheology with a distribution of relaxation times given by a Cole-Cole distribution. We use the assumption that the charges of the diffuse layer are uniformly distributed in the pore space (Donnan model). The macroscopic constitutive equations of transport for the seepage velocity and the current density have the form of coupled Darcy and Ohm equations with frequency-dependent material properties. These equations are combined with an extended Frenkel-Biot model describing the deformation of the poroelastic material filled with the viscoelastic fluid. In the mechanical constitutive equations, the effective shear modulus is frequency dependent. An amplification of the seismoelectric conversion is expected in the frequency band where resonance of the generalized Maxwell fluid occurs. The seismic and seismoelectric equations are modelled using a finite element code with PML boundary conditions. We found that the DC-value of the streaming potential coupling coefficient is also very high. These results have applications regarding the development of new non-intrusive methods to characterize shallow heavy oil reservoirs in tar sands and DNAPL contaminant plumes in shallow aquifers.

  12. Quantitative model of vapor dominated geothermal reservoirs as heat pipes in fractured porous rock

    SciTech Connect

    Pruess, K.

    1985-03-01

    We present a numerical model of vapor-dominated reservoirs which is based on the well-known conceptual model of White, Muffler, and Truesdell. Computer simulations show that upon heat recharge at the base, a single phase liquid-dominated geothermal reservoir in fractured rock with low matrix permeability will evolve into a two-phase reservoir with B.P.D. (boiling point-for-depth) pressure and temperature profiles. A rather limited discharge event through cracks in the caprock, involving loss of only a few percent of fluids in place, is sufficient to set the system off to evolve a vapor-dominated state. The attributes of this state are discussed, and some features requiring further clarification are identified. 26 refs., 5 figs.

  13. The Relative Permeability of CO2 and Water in Sandstone Rocks at Reservoir Conditions

    NASA Astrophysics Data System (ADS)

    Krevor, S. C.; Pini, R.; Zuo, L.; Benson, S. M.

    2011-12-01

    A firm understanding of the multiphase flow properties of CO2 and water in porous media is essential to predicting the long-term fate of CO2 in geologic storage. Recently, pilot-scale and simulation based studies have highlighted the importance that properties of relative permeability, residual saturation, and rock heterogeneity will play in determining the long-term distribution of CO2 in the subsurface. There is a need for more observations to expand the current dataset of experimental work, as well as a discussion of these results in the context of the theory that is used in reservoir-scale predictions of subsurface flow. In this paper we present the results of an experimental investigation into the flow properties of CO2 and water in 4 distinct rock lithologies: a Berea sandstone and 3 reservoir rocks from formations into which CO2 injection is either currently taking place or is planned. Drainage and imbibition relative permeability and end-point saturations were measured using the steady-state method in a high pressure and temperature core-flooding apparatus with fluid distributions observed using X-ray CT. Absolute permeability, capillary pressure curves, and petrological studies were performed on each sample to fully characterize the rocks. The results are discussed in terms of their potential impact on basin-scale modeling of industrial CO2 injection projects. Theoretical explanations for generally low end-point CO2 relative permeabilities are discussed as well as its relevance for reservoir simulations. It is shown that small-scale heterogeneity plays an important role in both the overall saturations of CO2 in a rock as well as the saturation distribution within the rock. Clear evidence of heterogenous flow-properties are observed even in rocks of homogeneous rock lithology. Observations of residual CO2 saturation are discussed in the context of the long-term stability of CO2 injected in the subsurface. The experiments are compared with results reported

  14. Influences of salt structures on reservoir rocks in block L-2, Dutch continental shelf

    SciTech Connect

    Dronkert, H. ); Remmelts, G. )

    1993-09-01

    In the subsurface of the Netherlands Continental Shelf, thick layers of Zechstein salt have developed into salt domes and ridges that pierce through the overlying formations. To measure the range of lateral influence of the salt in these structures on the sandstone reservoir rocks of the Mesozoic sequence, a cementation model was developed. The target area, Block L-2, was chosen for the presence of salt domes, wells, and reservoir rocks. The L-2 case study has been performed on two Triassic sandstone intervals. The lower, Volpriehausen, sandstone showed halite cementation in one well, located within several 100 m from a salt dome. Four other wells, located more than 1.5 km from a salt structure, did not show any signs of halite cementation. Therefore, the lateral influence of salt domes on the surrounding reservoir rock is, in this case, limited to less than 1.5 km at 3-4 km depth. A slightly shallower Triassic sandstone (Detfurth) shows more frequent halite cementation. This cementation can be attributed to early seepage from overlying Rot salt brines.Triassic Rot salt is present above depletion areas of the Zechstein salt structures, and in such a way the seepage can be seen as an indirect influence of the salt structures.

  15. Real-time oil-saturation monitoring in rock cores with low-field NMR.

    PubMed

    Mitchell, J; Howe, A M; Clarke, A

    2015-07-01

    Nuclear magnetic resonance (NMR) provides a powerful suite of tools for studying oil in reservoir core plugs at the laboratory scale. Low-field magnets are preferred for well-log calibration and to minimize magnetic-susceptibility-induced internal gradients in the porous medium. We demonstrate that careful data processing, combined with prior knowledge of the sample properties, enables real-time acquisition and interpretation of saturation state (relative amount of oil and water in the pores of a rock). Robust discrimination of oil and brine is achieved with diffusion weighting. We use this real-time analysis to monitor the forced displacement of oil from porous materials (sintered glass beads and sandstones) and to generate capillary desaturation curves. The real-time output enables in situ modification of the flood protocol and accurate control of the saturation state prior to the acquisition of standard NMR core analysis data, such as diffusion-relaxation correlations. Although applications to oil recovery and core analysis are demonstrated, the implementation highlights the general practicality of low-field NMR as an inline sensor for real-time industrial process control. PMID:25996514

  16. Black shale source rocks and oil generation in the Cambrian and Ordovician of the central Appalachian Basin, USA

    USGS Publications Warehouse

    Ryder, R.T.; Burruss, R.C.; Hatch, J.R.

    1998-01-01

    Nearly 600 million bbl of oil (MMBO) and 1 to 1.5 trillion ft3 (tcf) of gas have been produced from Cambrian and Ordovician reservoirs (carbonate and sandstone) in the Ohio part of the Appalachian basin and on adjoining arches in Ohio, Indiana, and Ontario, Canada. Most of the oil and gas is concentrated in the giant Lima-Indiana field on the Findlay and Kankakee arches and in small fields distributed along the Knox unconformity. Based on new geochemical analyses of oils, potential source rocks, bitumen extracts, and previously published geochemical data, we conclude that the oils in both groups of fields originated from Middle and Upper Ordovician blcak shale (Utica and Antes shales) in the Appalachian basin. Moroever, we suggest that approximately 300 MMBO and many trillions of cubic feet of gas in the Lower Silurian Clinton sands of eastern Ohio originated in the same source rocks. Oils from the Cambrian and Ordovician reservoirs have similar saturated hydrocarbon compositions, biomarker distributions, and carbon isotope signatures. Regional variations in the oils are attributed to differences in thermal maturation rather than to differences in source. Total organic carbon content, genetic potential, regional extent, and bitument extract geochemistry identify the balck shale of the Utica and Antes shales as the most plausible source of the oils. Other Cambrian and Ordovician shale and carbonate units, such as the Wells Creek formation, which rests on the Knox unconformity, and the Rome Formation and Conasauga Group in the Rome trough, are considered to be only local petroleum sources. Tmax, CAI, and pyrolysis yields from drill-hole cuttings and core indicate that the Utica Shale in eastern and central Ohio is mature with respect to oil generation. Burial, thermal, and hydrocarbon-generation history models suggest that much of the oil was generated from the Utica-Antes source in the late Paleozoic during the Alleghanian orogeny. A pervasive fracture network

  17. Influence of nanomirelal phases on development processes of oil reservoirs in Volga-Ural region

    NASA Astrophysics Data System (ADS)

    Izotov, Victor; Sitdikova, Lyalya

    2010-05-01

    The optimisation of oil-field development by enhancing oil recovery is the most important target in further improvement of oil production processes. The resulting economic benefits often exceed those from discoveries of new fields, especially in hard-to-reach regions. Despite the wide use of enhanced oil recovery methods, their efficiency is in many cases not as high as expected. For instance, in terrigenous reservoirs of the Volga-Ural region oil recovery rarely exceeds 0.4, and in carbonate reservoirs with the complex structure, variability and high oil viscosity it can be as low as 0.15-0.20. In natural bitumen fields, the recovery factor is even lower. Analysis of the conducted EOR optimisation operations indicates that EOR methods mainly aim to change the hydrodynamic conditions in the reservoir under development or the physicochemical properties of oil, - for instance, to decrease its viscosity or to change its lyophilic behaviour. The impact of EOR methods on the reservoir's mineral component remains largely unstudied. It is generally believed that the mineral component of the reservoir, its matrix, is inert and remains unaffected by EOR methods. However, the analysis of oil-field development processes and the available studies allow the conclusion that natural hydrocarbon reservoirs are sensitive to any impact on both the near-wellbore zone and the whole reservoir. The authors' research in the reservoir's mineral phase dynamics has permitted the conclusion that the reservoir's fluid phases (including hydrocarbons) and the reservoir itself form a lithogeochemical system that remains in unstable equilibrium. Any external impact, such as the reservoir penetration or the use of EOR methods, disturbs this equilibrium and changes the filtration characteristics of the reservoir, the fluid chemistry and the reaction of the reservoir's mineral component to the impact. In order to characterise the processes in the reservoir in the course of its development, the

  18. A data mining approach to finding relationships between reservoir properties and oil production for CHOPS

    NASA Astrophysics Data System (ADS)

    Cai, Yongxiang; Wang, Xin; Hu, Kezhen; Dong, Mingzhe

    2014-12-01

    Cold heavy oil production with sand (CHOPS) is a primary oil extraction process for heavy crude oil and reservoir properties are key factors that contribute to the effectiveness of CHOPS. However, identification of the key reservoir properties and quantification of the relationships between the reservoir properties and the oil production are still challenging tasks. In this paper, we propose the use of a data mining approach for finding quantitative relationships between various reservoir properties and oil production for CHOPS. The approach includes four steps: firstly, a set of reservoir properties are identified to describe reservoir characteristics through a petrophysical analysis. In addition to common parameters, such as porosity and permeability, two new parameters - a fluid mobility factor and the maximum inscribed rectangular of net pay (MIRNP) - are proposed. Secondly, three new parameters to describe the production performance of wells are proposed: the peak value, effective life cycle and effective yield. Next, the fuzzy ranking method is used to rank the importance of the identified reservoir properties in terms of oil production. Finally, association rule mining is used to obtain quantitative relationships between reservoir property variables and the production performance of wells. The proposed methods have been applied for 118 wells in the Sparky Formation of the Lloydminster heavy oil field in Alberta. The result shows that the production performance of wells in the area could be described and predicted by using the found quantitative relations.

  19. Calculation of shocks in oil reservoir modeling and porous flow

    SciTech Connect

    Concus, P.

    1982-03-01

    For many enhanced recovery methods propagating fronts arise that may be steep or discontinuous. One example is the waterflooding of a petroleum reservoir, in which there is forced out residual oil that remains after outflow by decompression has declined. In this paper high-resolution numerical methods to solve porous flow problems having propagating discontinuities are discussed. The random choice method can track solution discontinuities sharply and accurately for one space dimension. The first phase of this study adapted this method for solving the Buckley-Leverett equation for immiscible displacement in one space dimension. Extensions to more than one space dimension for the random choice method were carried out subsequently by means of fractional splitting. Because inaccuracies could be introduced for some problems at dicontinuity fronts propagating obliquely to the splitting directions, efforts are currently being directed at investigating alternatives for multidimensional cases.

  20. Material point method modeling in oil and gas reservoirs

    DOEpatents

    Vanderheyden, William Brian; Zhang, Duan

    2016-06-28

    A computer system and method of simulating the behavior of an oil and gas reservoir including changes in the margins of frangible solids. A system of equations including state equations such as momentum, and conservation laws such as mass conservation and volume fraction continuity, are defined and discretized for at least two phases in a modeled volume, one of which corresponds to frangible material. A material point model technique for numerically solving the system of discretized equations, to derive fluid flow at each of a plurality of mesh nodes in the modeled volume, and the velocity of at each of a plurality of particles representing the frangible material in the modeled volume. A time-splitting technique improves the computational efficiency of the simulation while maintaining accuracy on the deformation scale. The method can be applied to derive accurate upscaled model equations for larger volume scale simulations.

  1. Roof-rock contamination of magma along the top of the reservoir for the Bishop Tuff

    NASA Astrophysics Data System (ADS)

    Duffield, Wendell A.; Ruiz, Joaquin; Webster, James D.

    1995-12-01

    The Bishop Tuff, a well known Quaternary high-silica rhyolite in east-central California, is widely considered the type example of a vertically and monotonically zoned pyroclastic deposit that represents zoning in the source magma reservoir, inverted during the process of pyroclastic emplacement. However, the deposit of plinian pumice, which forms the base of the Bishop Tuff and represents the initial 10% or so of all magma erupted during the event that produced the Bishop Tuff, contains features at odds with monotonie zoning for the reservoir. Relative to overlying ignimbrite, the plinian deposit contains a reversal in trace-element zoning. Moreover, the {87Sr }/{86Sr } is significantly higher than that in overlying ignimbrite (about 0.7084 vs 0.7064), and melt inclusions trapped in quartz phenocrysts exhibit notable variability of trace-element concentrations, even within a single host crystal (e.g., U: 10.77 to 8.91 ppm). These data have been previously interpreted as due to processes of chemical fractionation and evolution operating within a magma system closed to chemical interactions with its roof rocks. For example, the reversal in trace-element zoning has been explained by the first-erupted magma being erupted from somewhat below the top of a monotonically zoned reservoir. However, we submit that the reversed zoning and other above-noted features can be explained equally well as consequences of minor assimilation of roof rocks into a magma reservoir that was erupted from the top down. The basal part of the Bishop Tuff exhibits extreme concentrations and depletions of trace elements, relative to the average composition of crustal rocks. For example, the upward decrease of Sr in the Bishop magma reservoir (downward decrease in the ignimbrite) results in concentrations as low as 2-4 ppm. Because of the attendant 'chemical leverage', assimilation of < 1 wt.% of Sierra Nevada batholith rocks typical of the area could readily reverse an 'uncontaminated' Sr (and

  2. Characterization of oil and gas reservoirs and recovery technology deployment on Texas State Lands

    SciTech Connect

    Tyler, R.; Major, R.P.; Holtz, M.H.

    1997-08-01

    Texas State Lands oil and gas resources are estimated at 1.6 BSTB of remaining mobile oil, 2.1 BSTB, or residual oil, and nearly 10 Tcf of remaining gas. An integrated, detailed geologic and engineering characterization of Texas State Lands has created quantitative descriptions of the oil and gas reservoirs, resulting in delineation of untapped, bypassed compartments and zones of remaining oil and gas. On Texas State Lands, the knowledge gained from such interpretative, quantitative reservoir descriptions has been the basis for designing optimized recovery strategies, including well deepening, recompletions, workovers, targeted infill drilling, injection profile modification, and waterflood optimization. The State of Texas Advanced Resource Recovery program is currently evaluating oil and gas fields along the Gulf Coast (South Copano Bay and Umbrella Point fields) and in the Permian Basin (Keystone East, Ozona, Geraldine Ford and Ford West fields). The program is grounded in advanced reservoir characterization techniques that define the residence of unrecovered oil and gas remaining in select State Land reservoirs. Integral to the program is collaboration with operators in order to deploy advanced reservoir exploitation and management plans. These plans are made on the basis of a thorough understanding of internal reservoir architecture and its controls on remaining oil and gas distribution. Continued accurate, detailed Texas State Lands reservoir description and characterization will ensure deployment of the most current and economically viable recovery technologies and strategies available.

  3. ADVANCED CHARACTERIZATION OF FRACTURED RESERVOIRS IN CARBONATE ROCKS: THE MICHIGAN BASIN

    SciTech Connect

    James R. Wood; William B. Harrison

    2002-12-01

    The purpose of the study was to collect and analyze existing data on the Michigan Basin for fracture patterns on scales ranging form thin section to basin. The data acquisition phase has been successfully concluded with the compilation of several large digital databases containing nearly all the existing information on formation tops, lithology and hydrocarbon production over the entire Michigan Basin. These databases represent the cumulative result of over 80 years of drilling and exploration. Plotting and examination of these data show that contrary to most depictions, the Michigan Basin is in fact extensively faulted and fractured, particularly in the central portion of the basin. This is in contrast to most of the existing work on the Michigan Basin, which tends to show relatively simple structure with few or minor faults. It also appears that these fractures and faults control the Paleozoic sediment deposition, the subsequent hydrocarbon traps and very likely the regional dolomitization patterns. Recent work has revealed that a detailed fracture pattern exists in the interior of the Central Michigan Basin, which is related to the mid-continent gravity high. The inference is that early Precambrian, ({approx}1 Ga) rifting events presumed by many to account for the gravity anomaly subsequently controlled Paleozoic sedimentation and later hydrocarbon accumulation. There is a systematic relationship between the faults and a number of gas and oil reservoirs: major hydrocarbon accumulations consistently occur in small anticlines on the upthrown side of the faults. The main tools used in this study to map the fault/fracture patterns are detailed, close-interval (CI = 10 feet) contouring of the formation top picks accompanied by a new way of visualizing the data using a special color spectrum to bring out the third dimension. In addition, recent improvements in visualization and contouring software were instrumental in the study. Dolomitization is common in the

  4. Burial History, Thermal Maturity, and Oil and Gas Generation History of Source Rocks in the Bighorn Basin, Wyoming and Montana

    USGS Publications Warehouse

    Roberts, Laura N.R.; Finn, Thomas M.; Lewan, Michael D.; Kirschbaum, Mark A.

    2008-01-01

    Burial history, thermal maturity, and timing of oil and gas generation were modeled for seven key source-rock units at eight well locations throughout the Bighorn Basin in Wyoming and Montana. Also modeled was the timing of cracking to gas of Phosphoria Formation-sourced oil in the Permian Park City Formation reservoirs at two well locations. Within the basin boundary, the Phosphoria is thin and only locally rich in organic carbon; it is thought that the Phosphoria oil produced from Park City and other reservoirs migrated from the Idaho-Wyoming thrust belt. Other petroleum source rocks include the Cretaceous Thermopolis Shale, Mowry Shale, Frontier Formation, Cody Shale, Mesaverde and Meeteetse Formations, and the Tertiary (Paleocene) Fort Union Formation. Locations (wells) selected for burial history reconstructions include three in the deepest parts of the Bighorn Basin (Emblem Bench, Red Point/Husky, and Sellers Draw), three at intermediate depths (Amoco BN 1, Santa Fe Tatman, and McCulloch Peak), and two at relatively shallow locations (Dobie Creek and Doctor Ditch). The thermal maturity of source rocks is greatest in the deep central part of the basin and decreases to the south, east, and north toward the basin margins. The Thermopolis and Mowry Shales are predominantly gas-prone source rocks, containing a mix of Type-III and Type-II kerogens. The Frontier, Cody, Mesaverde, Meeteetse, and Fort Union Formations are gas-prone source rocks containing Type-III kerogen. Modeling results indicate that in the deepest areas, (1) the onset of petroleum generation from Cretaceous rocks occurred from early Paleocene through early Eocene time, (2) peak petroleum generation from Cretaceous rocks occurred during Eocene time, and (3) onset of gas generation from the Fort Union Formation occurred during early Eocene time and peak generation occurred from late Eocene to early Miocene time. Only in the deepest part of the basin did the oil generated from the Thermopolis and

  5. Methods for estimating petrophysical parameters from well logs in tight oil reservoirs: a case study

    NASA Astrophysics Data System (ADS)

    Zhao, Peiqiang; Zhuang, Wen; Sun, Zhongchun; Wang, Zhenlin; Luo, Xingping; Mao, Zhiqiang; Tong, Zemin

    2016-02-01

    Estimating petrophysical parameters from well logs plays a significant role in the exploration and development of tight oil resources, but faces challenges. What’s more, the methods for petrophysical parameters from well logs are paid little attention at present. In this paper, the typical tight oil reservoirs of Northwest China are used as an example. Based on the characteristics of mineralogy and fluids in the study field, the rock is assumed into five components which are clays, quartz and feldspar, carbonates, kerogen and pore fluids (porosity). The sum of kerogen content and porosity is defined as the apparent porosity. Then, two porosity log response equations are established. Once the clay content is determined by an individual method, the quartz and feldspar content, carbonate content and apparent porosity are calculated through the established equations. The kerogen content is the difference of the apparent porosity and porosity from nuclear magnetic resonance (NMR) logs. This paper also presents a new approach that combines the complex refractive index method (CRIM) and pseudo Archie method to compute saturation from dielectric logs, which avoids selection for the dielectric constants of each of the minerals. The effectiveness and reliability of these methods are verified by the successful application in the study of the target tight oil play in Northwest China.

  6. Cost Effective Surfactant Formulations for Improved Oil Recovery in Carbonate Reservoirs

    SciTech Connect

    William A. Goddard; Yongchun Tang; Patrick Shuler; Mario Blanco; Yongfu Wu

    2007-09-30

    This report summarizes work during the 30 month time period of this project. This was planned originally for 3-years duration, but due to its financial limitations, DOE halted funding after 2 years. The California Institute of Technology continued working on this project for an additional 6 months based on a no-cost extension granted by DOE. The objective of this project is to improve the performance of aqueous phase formulations that are designed to increase oil recovery from fractured, oil-wet carbonate reservoir rock. This process works by increasing the rate and extent of aqueous phase imbibition into the matrix blocks in the reservoir and thereby displacing crude oil normally not recovered in a conventional waterflood operation. The project had three major components: (1) developing methods for the rapid screening of surfactant formulations towards identifying candidates suitable for more detailed evaluation, (2) more fundamental studies to relate the chemical structure of acid components of an oil and surfactants in aqueous solution as relates to their tendency to wet a carbonate surface by oil or water, and (3) a more applied study where aqueous solutions of different commercial surfactants are examined for their ability to recover a West Texas crude oil from a limestone core via an imbibition process. The first item, regarding rapid screening methods for suitable surfactants has been summarized as a Topical Report. One promising surfactant screening protocol is based on the ability of a surfactant solution to remove aged crude oil that coats a clear calcite crystal (Iceland Spar). Good surfactant candidate solutions remove the most oil the quickest from the surface of these chips, plus change the apparent contact angle of the remaining oil droplets on the surface that thereby indicate increased water-wetting. The other fast surfactant screening method is based on the flotation behavior of powdered calcite in water. In this test protocol, first the calcite

  7. Organic geochemical characterization of reservoir rocks, cap rocks and formation fluids from the CO2 storage site at Ketzin, Germany

    NASA Astrophysics Data System (ADS)

    Scherf, A.-K.; Morozova, D.; Wandrey, M.; Mangelsdorf, K.; Würdemann, H.; Vieth, A.

    2009-04-01

    The European project CO2SINK (CO2 Storage by Injection into a natural saline Aquifer at Ketzin) is the first project on the on-shore underground storage of carbon dioxide in Europe. Near the city Ketzin (north-east Germany) a geological formation of the younger Triassic (Stuttgart Formation) was chosen as reservoir for the long-term storage of the carbon dioxide. Within the scope of the Ketzin project we will analyse the organic matter in core rock and fluid samples to investigate the biogeochemical effects and changes on the geological formation caused by the injection of carbon dioxide. These investigations will help to evaluate the efficiency and reliability of the long-term storage of CO2 in such a geological system. Organic geochemical analyses will be performed on core rock samples drilled in 2007 at the Ketzin CO2 storage site in Germany. In total, three bore holes were constructed: one injection well and two observation wells. In addition to the molecular analysis of the microbial community we will investigate rock samples from different depths for total, dissolved and extractable organic carbon including lipid biomarkers, such as organic acids and intact polar lipids as well as the isotopic analysis of individual organic compounds. With the analysis of intact phospholipids (IPL) we will be able to further characterize the indigenous microbial community. Intact phospholipids are found in all living cells as membrane components (Zelles, 1999). Their interpretation is based on the premise that different microorganisms contain different phospholipids with ester- and/or ether-bound fatty acids (White et al., 1979) and thus, the distribution of IPLs and PLFAs (phospholipids fatty acid) can be applied to characterise and compare microbial communities. The data obtained from these analyses will provide valuable information on the active microorganisms as well as shifts in community composition. The characterization of the organic matter in the reservoir rock

  8. DEVELOPMENT PRACTICES FOR OPTIMIZED MEOR IN SHALLOW HEAVY OIL RESERVOIRS

    SciTech Connect

    Shari Dunn-Norman

    2003-09-05

    The objective of this research project is to demonstrate an economically viable and sustainable method of producing shallow heavy oil reserves in western Missouri and southeastern Kansas, using an integrated approach including surface geochemical surveys, conventional MEOR treatments, horizontal fracturing in vertical wells, electrical resistivity tomography (ERT), and reservoir simulation to optimize the recovery process. The objective also includes transferring the knowledge gained from the project to other local landowners, to demonstrate how they may identify and develop their own heavy oil resources with minimal capital investment. Tasks completed in the first six-month period include soil sampling, geochemical analysis, construction of ERT arrays, collection of background ERT surveys, and analysis of core samples to develop a geomechanical model for designing the hydraulic fracturing treatment. Five wells were to be drilled in phase I. However, weather and funding delays resulted in drilling shifting to the second phase of the project. Work performed to date demonstrates that surface geochemical methods can be used to differentiate between productive and non-productive areas of the Warner Sand and that ERT can be used to successfully image through the Warner Sand.

  9. Volume 5: An evaluation of known remaining oil resources in piercement salt dome reservoirs in the Gulf of Mexico

    SciTech Connect

    Mohan, H.; Rogers, M.; Becker, A.; Biglarbigi, K.; Brashear, J.

    1996-08-01

    The US Department of Energy, Office of Fossil Energy (DOE/FE) has among its missions the facilitation of the development of required technologies to maximize the potential economic recovery of domestic oil and gas resources--both offshore and onshore, especially from Federal lands. In planning its activities, the DOE/FE relies on a number of comprehensive analytical systems in order to target and prioritize its research and development (R and D) activities and to estimate the benefits of its programs. DOE/FE`s analytical system, however, lacks the capability to assess the potential of future technology advances on the exploration, development, and production of crude oil resources in the Federal offshore of the Gulf of Mexico. The objective of the present effort is to develop an analytical system to characterize a portion of the Gulf offshore resources--the remaining unrecovered mobile oil resource associated with piercement salt dome reservoirs (hereafter referred to as salt dome reservoirs), and to evaluate additional recovery potential and related economic benefits that could result from the application of improved technologies. As part of the present effort a comprehensive analytical system has been developed for the characterization and evaluation of unrecovered mobile oil associated with the salt dome reservoirs in Federal offshore Gulf of Mexico. The system consists of a comprehensive database containing detailed rock and fluid properties, geologic information, and production and development history for 1,289 major fields and reservoirs representing an estimated 60% of the salt dome resources in the region. In addition, two separate methodologies and related economic and predictive models have been developed for the evaluation of applicable recovery processes. The system is intended for use as part of DOE`s Tertiary Oil Recovery Information System (TORIS).

  10. CO2 gas/oil ratio prediction in a multi-component reservoir bycombined seismic and electromagnetic imaging

    SciTech Connect

    Hoversten, G.M.; Gritto, Roland; Washbourne, John; Daley, Tom

    2002-08-28

    Crosswell seismic and electromagnetic data sets taken before and during CO2 flooding of an oil reservoir are inverted to produce crosswell images of the change in compressional velocity, shear velocity and electrical conductivity during a CO2 injection pilot study. A rock properties model is developed using measured log porosity, fluid saturations, pressure, temperature, bulk density, sonic velocity and electrical conductivity. The parameters of the rock properties model are found by an L1-norm simplex minimization of predicted and observed compressional velocity and density. A separate minimization using Archie's law provides parameters for modeling the relations between water saturation, porosity and the electrical conductivity. The rock properties model is used to generate relationships between changes in geophysical parameters and changes in reservoir parameters. The electrical conductivity changes are directly mapped to changes in water saturation. The estimated changes in water saturation are used with the observed changes in shear wave velocity to predict changes in reservoir pressure. The estimation of the spatial extent and amount of CO2 relies on first removing the effects of the water saturation and pressure changes from the observed compressional velocity changes, producing a residual compressional velocity change. The residual compressional velocity change is then interpreted in terms of increases in the CO2 /oil ratio. Resulting images of CO2/oil ratio show CO2 rich zones that are well correlated with the location of injection perforations with the size of these zones also correlating to the amount of injected CO2. The images produced by this process are better correlated to the location and amount of injected CO2 than are any of the individual images of change in geophysical parameters.

  11. Preliminary evaluation of the second hot dry rock geothermal energy reservoir: results of phase 1, run segment 4

    SciTech Connect

    Murphy, H.D.; Aamodt, R.L.; Albright, J.N.

    1980-05-01

    Results of the preliminary assessment of the second hot dry rock reservoir at the Fenton Hill field site are presented. This second reservoir was created by fracturing a deeper interval of granite rock located at a depth of 2.93 km (9620 ft) in the same wellbore pair used in the creation of the first reservoir; no additional redrilling was required. The new fracture system has a vertical extent of at least 320 m (1050 ft), suggesting that the combined heat-transfer area of the old and new fracture systems is 11 times that of the old system. The virgin rock temperature at the bottom of the deeper interval was 197/sup 0/C (386/sup 0/F). Water at a flow rate of 6 l/s (100 gpm) was circulated through the reservoir for a period of 23 days. Downhole measurements of the water temperature at the reservoir outlet, as well as temperatures inferred from geothermometry, showed that the thermal drawdown of the reservoir was negligible and preliminary estimates indicate that the minimum effective heat-transfer area of the new reservoir is 45,000 m/sup 2/ (480,000 ft/sup 2/), which is six times larger than the first reservoir. The following are presented: operational plan, reservoir geometry and flow paths, flow impedance, geochemistry, heat extraction, dye tracer flow distribution studies, and seismicity. (MHR)

  12. Microbial biodiversity in a Malaysian oil field and a systematic comparison with oil reservoirs worldwide.

    PubMed

    Li, Dongmei; Midgley, David J; Ross, Jason P; Oytam, Yalchin; Abell, Guy C J; Volk, Herbert; Daud, Wan Ata Wan; Hendry, Philip

    2012-06-01

    Microbial diversity within formation water and oil from two compartments in Bokor oil reservoir from a Malaysian petroleum oil field was examined. A total of 1,056 16S rRNA gene clones were screened from each location by amplified ribosomal DNA restriction analysis. All samples were dominated by clones affiliated with Marinobacter, some novel Deferribacteraceae genera and various clones allied to the Methanococci. In addition, either Marinobacterium- or Pseudomonas-like operational taxonomic units were detected from either compartment. A systematic comparison with the existing pertinent studies was undertaken by analysing the microbial amplicons detected and the PCR primers used. The analyses demonstrated that bacterial communities were site specific, while Archaea co-occurred more frequently. Amplicons related to Marinobacter, Marinobacterium and Pseudomonas were detected in a number of the studies examined, suggesting they may be ubiquitous members in oil reservoirs. Further analysis of primers used in those studies suggested that most primer pairs had fairly broad but low matches across the bacterial and archaeal domains, while a minority had selective matches to certain taxa or low matches to all the microbial taxa tested. Thus, it indicated that primers may play an important role in determining which taxa would be detected. PMID:22245906

  13. Water rock interaction during the process of steam stimulation exploitation of viscous crude oil in Liaohe Shuguang Oil Field, Liaoning, China

    NASA Astrophysics Data System (ADS)

    Hui, Qian; Zhenghua, Yang; Yunfeng, Li; Wancai, Xu; Yaqiao, Sun

    2006-05-01

    In the process of steam stimulation exploitation of viscous crude oil, the injected water, at high temperature and under high pressure, reacts intensively with the host rock. This kind of water rock interaction in Liaohe Shuguang Oil Field was studied on the basis of analysis of water composition changes, laboratory experiments, mineral saturation indices analysis, and mass balance calculation. Compared with the injected water, the changes of the composition of discharged water are mainly the distinct decrease of pH, Na+, SiO2 and Cl-, as well as the increase of K+, Ca2+, Mg2+, SO{4/2-} and HCO{3/-}. Laboratory experiments under field conditions showed: the dissolution sequence of minerals quantitatively is quartz>potassium feldspar>albite, and the main change of clay minerals is the conversion of kaolinite to analcime. Mass balance calculation indicated during the process of steam stimulation, large quantities of analcime are precipitated with the dissolution of large amounts of quartz, kaolinite, potassium feldspar, and CO2. These results correlated very well with the experimental results. The calculated results of Liaohe Shuguang Oil Field showed that during the steam stimulation for viscous crude oil, the amounts of minerals dissolved (precipitated) are huge. To control the clogging of pore spaces of oil reservoirs, increased study of water rock interaction is needed.

  14. Well-log signatures of alluvial-lacustrine reservoirs and source rocks, Lagoa-Feia Formations, Lower Cretaceous, Campos Basin, offshore Brazil

    SciTech Connect

    Abrahao, D.; Warme, J.E.

    1988-01-01

    The Campos basin is situated in offshore southeastern Brazil. The Lagoa Feia is the basal formation in the stratigraphic sequence of the basin, and was deposited during rifting in an evolving complex of lakes of different sizes and chemical characteristics, overlying and closely associated with rift volcanism. The stratigraphic sequence is dominated by lacustrine limestones and shales (some of them organic-rich), and volcaniclastic conglomerates deposited on alluvial fans. The sequence is capped by marine evaporites. In the Lagoa Feia Formation, complex lithologies make reservoirs and source rocks unsuitable for conventional well-log interpretation. To solve this problem, cores were studied and the observed characteristics related to log responses. The results have been extended through the entire basin for other wells where those facies were not cored. The reservoir facies in the Lagoa Feia Formation are restricted to levels of pure pelecypod shells (''coquinas''). Resistivity, sonic, neutron, density, and gamma-ray logs were used in this work to show how petrophysical properties are derived for the unconventional reservoirs existing in this formation. The same suite of logs was used to develop methods to define geochemical characteristics where source rock data are sparse in the organic-rich lacustrine shales of the Lagoa Feia Formation. These shales are the main source rocks for all the oil discovered to date in the Campos basin.

  15. Extraction of whole versus ground source rocks: Fundamental petroleum geochemical implications including oil-source rock correlation

    USGS Publications Warehouse

    Price, L.C.; Clayton, J.L.

    1992-01-01

    In petroleum geochemistry, extractable hydrocarbons (HCs) in source rocks have typically been studied by grinding the rock to a fine powder (???100 mesh) and then extracting the HCs from the rock with a solvent. This procedure carries the implicit assumption that the HCs are homogeneously distributed throughout the rock. However, sequential Soxhlet extractions of whole (unpowdered) source rocks have shown that progressive extracts from the same rock can be quite different and may not even correlate with each other. A crude oil-like material clearly has been fractionated from indigenous bitumen in these rocks, has moved to cracks and parting laminae in the rocks, is ready for expulsion from the rocks, and is thus most accessible to the first extracting solvents. This process, which we believe is largely due to HC gases and carbon dioxide generated over all maturation ranks in source rocks, carries petroleum geochemical implications of a fundamental nature for oil-source rock correlations and gives insight into primary migration mechanisms, origin of oil deposits, and use of maturity and organic-facies indices. ?? 1992.

  16. Roof-rock contamination of magma along the top of the reservoir for the Bishop Tuff

    USGS Publications Warehouse

    Duffield, W.A.; Ruiz, J.; Webster, J.D.

    1995-01-01

    The Bishop Tuff, a Quaternary high-silica rhyolite in east-central California, is widely considered the type example of a vertically and monotonically zoned pyroclastic deposit that represents zoning in the source magma reservoir, inverted during the process of pyroclastic emplacement. However, the deposit of plinian pumice, which forms the base of the Bishop Tuff and represents the initial 10% or so of all magma erupted during the event that produced the Bishop Tuff, contains features at odds with monotonic zoning for the reservoir. Relative to overlying ignimbrite, the plinian deposit contains a reversal in trace-element zoning. The data have been previously interpreted as due to processes of chemical fractionation and evolution operating within a magma system closed to chemical interactions with its roof rocks. However, it is suggested here that the reversed zoning and other above-noted features can be explained equally well as consequences of minor assimilation of roof rocks into a magma reservoir that was erupted from the top down. -from Authors

  17. Investigation of oil recovery improvement by coupling an interfacial tension agent and a mobility control agent in light oil reservoirs. Technical progress report, July 1995--September 1995

    SciTech Connect

    Pitts, M.J.

    1995-10-01

    This study will investigate two major areas concerning co-injection and interfacial tension reduction agents and a mobility control agent into petroleum reservoirs. The first will consist of defining the mechanisms of interaction of an alkaline agent, a surfactant, and a polymer on a fluid-fluid and a fluid-rock basis. The second is the improvement of the economics of the combined technology. This report examines altering the concentration of alkali and polymer on the oil recovery economics of alkaline-surfactant-polymer solution.

  18. Using Biosurfactants Produced from Agriculture Process Waste Streams to Improve Oil Recovery in Fractured Carbonate Reservoirs

    SciTech Connect

    Stephen Johnson; Mehdi Salehi; Karl Eisert; Sandra Fox

    2009-01-07

    This report describes the progress of our research during the first 30 months (10/01/2004 to 03/31/2007) of the original three-year project cycle. The project was terminated early due to DOE budget cuts. This was a joint project between the Tertiary Oil Recovery Project (TORP) at the University of Kansas and the Idaho National Laboratory (INL). The objective was to evaluate the use of low-cost biosurfactants produced from agriculture process waste streams to improve oil recovery in fractured carbonate reservoirs through wettability mediation. Biosurfactant for this project was produced using Bacillus subtilis 21332 and purified potato starch as the growth medium. The INL team produced the biosurfactant and characterized it as surfactin. INL supplied surfactin as required for the tests at KU as well as providing other microbiological services. Interfacial tension (IFT) between Soltrol 130 and both potential benchmark chemical surfactants and crude surfactin was measured over a range of concentrations. The performance of the crude surfactin preparation in reducing IFT was greater than any of the synthetic compounds throughout the concentration range studied but at low concentrations, sodium laureth sulfate (SLS) was closest to the surfactin, and was used as the benchmark in subsequent studies. Core characterization was carried out using both traditional flooding techniques to find porosity and permeability; and NMR/MRI to image cores and identify pore architecture and degree of heterogeneity. A cleaning regime was identified and developed to remove organic materials from cores and crushed carbonate rock. This allowed cores to be fully characterized and returned to a reproducible wettability state when coupled with a crude-oil aging regime. Rapid wettability assessments for crushed matrix material were developed, and used to inform slower Amott wettability tests. Initial static absorption experiments exposed limitations in the use of HPLC and TOC to determine

  19. New oil source rocks cut in Greek Ionian basin

    SciTech Connect

    Karakitsios, V.; Rigakis, N.

    1996-02-12

    The Ionian zone of Northwest Greece (Epirus region) constitutes part of the most external zones of the Hellenides (Paxos zone, Ionian zone, Gavrovo Tripolitza zone). The rocks of the Ionian zone range from Triassic evaporites and associated breccias through a varied series of Jurassic through Upper Eocene carbonates and lesser cherts and shales followed by Oligocene flysch. The surface occurrences of petroleum in the Ionian zone are mainly attributed to Toarcian Lower Posidonia beds source rocks and lesser to late Callovian-Tithonian Upper Posidonia beds and to the Albian-Cenomanian Upper Siliceous zone or Vigla shales of the Vigla limestones. Oil that could not be attributed to the above source rocks is believed to have an origin from Triassic formations that contain potential source rocks in Albania and Italy. However, several samples of the shales of Triassic breccias from outcrops and drillholes were analyzed in the past, but the analytical results were not so promising since their hydrocarbon potential was low. In this article, the authors will present their analytical results of the Ioannina-1 well, where for the first time they identified some very rich source beds in the Triassic breccias formation of Northwest Greece.

  20. Mining earth's heat: development of hot-dry-rock geothermal reservoirs

    SciTech Connect

    Pettitt, R.A.; Becker, N.M.

    1983-01-01

    The energy-extraction concept of the Hot Dry Rock (HDR) Geothermal Program, as initially developed by the Los Alamos National Laboratory, is to mine this heat by creating a man-made reservoir in low-permeability, hot basement rock. This concept has been successfully proven at Fenton Hill in northern New Mexico by drilling two holes to a depth of approximately 3 km (10,000 ft) and a bottom temperature of 200/sup 0/C (392/sup 0/F), then connecting the boreholes with a large-diametervertical hydraulic fracture. Water is circulated down one borehole, heated by the hot rock, and rises up the second borehole to the surface where the heat is extracted and the cooled water is reinjected into the underground circulation loop. This system has operated for a cumulative 416 days during engineering and reservoir testing. An energy equivalent of 3 to 5 MW(t) was produced without adverse environmental problems. During one test, a generator was installed in the circulation loop and produced 60 kW of electricity. A second-generation system, recently drilled to 4.5 km (15,000 ft) and temperatures of 320/sup 0/C (608/sup 0/F), entails creating multiple, parallel fractures between a pair of inclined boreholes. This system should produce 5 to 10 MW(e) for 20 years. Significant contributions to underground technology have been made through the development of the program.

  1. Increasing Heavy Oil Reserves in the Wilmington Oil Field Through Advanced Reservoir Characterization and Thermal Production Technologies, Class III

    SciTech Connect

    City of Long Beach; Tidelands Oil Production Company; University of Southern California; David K. Davies and Associates

    2002-09-30

    The objective of this project was to increase the recoverable heavy oil reserves within sections of the Wilmington Oil Field, near Long Beach, California through the testing and application of advanced reservoir characterization and thermal production technologies. The successful application of these technologies would result in expanding their implementation throughout the Wilmington Field and, through technology transfer, to other slope and basin clastic (SBC) reservoirs.

  2. Wettability from Capillarity of CO2-Brine-Rock Systems at Reservoir Conditions

    NASA Astrophysics Data System (ADS)

    Al-Menhali, Ali; Niu, Ben; Krevor, Samuel

    2015-04-01

    The wettability of CO2-brine-rock systems will have a major impact on the management of carbon sequestration in subsurface geological formations. Recent contact angle measurement studies have reported sensitivity in wetting behaviour of this system to pressure, temperature and brine salinity. We report results of an investigation into the impact of reservoir conditions on wetting through direct observations of their impact on the capillary strength of the system. Eight capillary pressure characteristic curves were measured using CO2 and brine in a single fired Berea sandstone at pressures (5 to 20 MPa), temperatures (25 to 50 °C) and ionic strengths (0 to 5 M kg-1 NaCl) representative of subsurface reservoirs. A ninth measurement using an N2-water system provided a benchmark for capillarity with a strongly water wet system. The semi-dynamic capillary pressure core flooding technique was used with in situ saturation monitoring. In all cases, the capillarity of the system, scaled by the interfacial tension, were equivalent to the N2-water system within measurement uncertainty. Thus reservoir conditions did not have a significant impact on the capillary strength of the CO2-brine system through a variation in wetting. Two steady-state relative permeability measurements with CO2 and brine and one with N2 and brine similarly show little variation between conditions, consistent with the observation that the CO2-brine-sandstone system is strongly water wetting and invariant across a wide range of reservoir conditions.

  3. Reasons for production decline in the diatomite, Belridge oil field: a rock mechanics view

    SciTech Connect

    Strickland, F.G.

    1985-03-01

    This paper summarizes research conducted on diatomite cores from the Belridge oil field in Kern County, CA. The study was undertaken to explain the rapid decline in oil production in diatomite wells by investigating three of six possible reasons. Characterization of the rock indicated that the rock was composed of principally amorphous opaline silica diatoms with only a trace of crystoballite quartz or chert quartz. Physical properties tests showed the diatomite to be of very low strength and plastic. It was established that longterm creep of diatomite into a propped fracture proceeds at a rate of approximately 1.5 microns/D (1.5 ..mu..m/d), a phenomenon that may contribute to rapid production declines. Also revealed was a matrix strength for the formation of about 1,325 psi (9136 kPa), a critical value to consider when depleting the reservoir. This also may help to explain the phase transformation to Opal CT around 2,000to 2,500-ft (610- to 762-m) depth.

  4. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect

    Scott Hara

    2001-06-27

    The objective of this project is to increase the recoverable heavy oil reserves within sections of the Wilmington Oil Field, near Long Beach, California through the testing and application of advanced reservoir characterization and thermal production technologies. The successful application of these technologies will result in expanding their implementation throughout the Wilmington Field and, through technology transfer, to other slope and basin clastic (SBC) reservoirs. The existing steamflood in the Tar zone of Fault Block II-A (Tar II-A) has been relatively inefficient because of several producibility problems which are common in SBC reservoirs: inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil and non-uniform distribution of the remaining oil. This has resulted in poor sweep efficiency, high steam-oil ratios, and early steam breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves. A suite of advanced reservoir characterization and thermal production technologies are being applied during the project to improve oil recovery and reduce operating costs.

  5. Theoretical Analysis of the Mechanism of Fracture Network Propagation with Stimulated Reservoir Volume (SRV) Fracturing in Tight Oil Reservoirs.

    PubMed

    Su, Yuliang; Ren, Long; Meng, Fankun; Xu, Chen; Wang, Wendong

    2015-01-01

    Stimulated reservoir volume (SRV) fracturing in tight oil reservoirs often induces complex fracture-network growth, which has a fundamentally different formation mechanism from traditional planar bi-winged fracturing. To reveal the mechanism of fracture network propagation, this paper employs a modified displacement discontinuity method (DDM), mechanical mechanism analysis and initiation and propagation criteria for the theoretical model of fracture network propagation and its derivation. A reasonable solution of the theoretical model for a tight oil reservoir is obtained and verified by a numerical discrete method. Through theoretical calculation and computer programming, the variation rules of formation stress fields, hydraulic fracture propagation patterns (FPP) and branch fracture propagation angles and pressures are analyzed. The results show that during the process of fracture propagation, the initial orientation of the principal stress deflects, and the stress fields at the fracture tips change dramatically in the region surrounding the fracture. Whether the ideal fracture network can be produced depends on the geological conditions and on the engineering treatments. This study has both theoretical significance and practical application value by contributing to a better understanding of fracture network propagation mechanisms in unconventional oil/gas reservoirs and to the improvement of the science and design efficiency of reservoir fracturing. PMID:25966285

  6. Theoretical Analysis of the Mechanism of Fracture Network Propagation with Stimulated Reservoir Volume (SRV) Fracturing in Tight Oil Reservoirs

    PubMed Central

    Su, Yuliang; Ren, Long; Meng, Fankun; Xu, Chen; Wang, Wendong

    2015-01-01

    Stimulated reservoir volume (SRV) fracturing in tight oil reservoirs often induces complex fracture-network growth, which has a fundamentally different formation mechanism from traditional planar bi-winged fracturing. To reveal the mechanism of fracture network propagation, this paper employs a modified displacement discontinuity method (DDM), mechanical mechanism analysis and initiation and propagation criteria for the theoretical model of fracture network propagation and its derivation. A reasonable solution of the theoretical model for a tight oil reservoir is obtained and verified by a numerical discrete method. Through theoretical calculation and computer programming, the variation rules of formation stress fields, hydraulic fracture propagation patterns (FPP) and branch fracture propagation angles and pressures are analyzed. The results show that during the process of fracture propagation, the initial orientation of the principal stress deflects, and the stress fields at the fracture tips change dramatically in the region surrounding the fracture. Whether the ideal fracture network can be produced depends on the geological conditions and on the engineering treatments. This study has both theoretical significance and practical application value by contributing to a better understanding of fracture network propagation mechanisms in unconventional oil/gas reservoirs and to the improvement of the science and design efficiency of reservoir fracturing. PMID:25966285

  7. Influence of shape and skin of matrix-rock blocks on pressure transients in fractured reservoirs

    SciTech Connect

    de Swaan, A.

    1986-01-01

    A formulation of pressure transients in terms of the intrinsic, or core, properties of the two media that compose the fractured reservoir, establishes the influence of these properties, and reciprocally, their corroboration from - the pressure-time relationship observed in well tests and interference tests. The following reservoir characteristics are analyzed: the area of fractures transverse to flow; the dimensions, shape and properties of rectangular parallelepiped matrix-rock blocks; and a permeability reduction in the blocks surface. A restatement of the so-called pseudo-steady state inter-media flow gives to parameters alfa and lambda in the theory of a previous study the physical meaning they lacked, and allows a direct determination of the blocks minimum dimension.

  8. Fracture Surface Area Effects on Fluid Extraction and the Electrical Resistivity of Geothermal Reservoir Rocks

    SciTech Connect

    Roberts, J J; Detwiler, R L; Ralph, W; Bonner, B

    2002-05-09

    Laboratory measurements of the electrical resistivity of fractured analogue geothermal reservoir rocks were performed to investigate the resistivity contrast caused by active boiling and to determine the effects of variable fracture dimensions and surface area on water extraction. Experiments were performed at confining pressures up to 10 h4Pa (100 bars) and temperatures to 170 C. Fractured samples show a larger resistivity change at the onset of boiling than intact samples. Monitoring the resistivity of fractured samples as they equilibrate to imposed pressure and temperature conditions provides an estimate of fluid migration into and out of the matrix. Measurements presented are an important step toward using field electrical methods to quantitatively search for fractures, infer saturation, and track fluid migration in geothermal reservoirs.

  9. Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity

    SciTech Connect

    Mancini, E.A.

    1991-01-01

    The objective of this project is to augment the National Reservoir Database (TORIS database), to increase our understanding of how geologic heterogeneity affects the recovery of oil and gas from carbonate reservoirs in the State of Alabama, and to identify resources that are producible at moderate cost. This objective will be achieved through detailed geological, geostatistical, and engineering characterization of typical Jurassic Smackover Formation hydrocarbon reservoirs in selected productive fields in the State of Alabama. The results of these studies will be used to develop and test mathematical models for prediction of the effects of reservoir heterogeneity on hydrocarbon production. The paper reports on the progress of several subtasks. The subjects discussed are: controls on reservoir heterogeneity in the Smackover; pore facies and Smackover reservoir heterogeneity; geological and petrophysical reservoir characterization; geologic flow modeling; and geostatistical modeling. Accomplishments this quarter are summarized and their significance to EOR research is discussed. 1 ref., 4 figs. (CK)

  10. Integrating sequence stratigraphy and rock-physics to interpret seismic amplitudes and predict reservoir quality

    NASA Astrophysics Data System (ADS)

    Dutta, Tanima

    This dissertation focuses on the link between seismic amplitudes and reservoir properties. Prediction of reservoir properties, such as sorting, sand/shale ratio, and cement-volume from seismic amplitudes improves by integrating knowledge from multiple disciplines. The key contribution of this dissertation is to improve the prediction of reservoir properties by integrating sequence stratigraphy and rock physics. Sequence stratigraphy has been successfully used for qualitative interpretation of seismic amplitudes to predict reservoir properties. Rock physics modeling allows quantitative interpretation of seismic amplitudes. However, often there is uncertainty about selecting geologically appropriate rock physics model and its input parameters, away from the wells. In the present dissertation, we exploit the predictive power of sequence stratigraphy to extract the spatial trends of sedimentological parameters that control seismic amplitudes. These spatial trends of sedimentological parameters can serve as valuable constraints in rock physics modeling, especially away from the wells. Consequently, rock physics modeling, integrated with the trends from sequence stratigraphy, become useful for interpreting observed seismic amplitudes away from the wells in terms of underlying sedimentological parameters. We illustrate this methodology using a comprehensive dataset from channelized turbidite systems, deposited in minibasin settings in the offshore Equatorial Guinea, West Africa. First, we present a practical recipe for using closed-form expressions of effective medium models to predict seismic velocities in unconsolidated sandstones. We use an effective medium model that combines perfectly rough and smooth grains (the extended Walton model), and use that model to derive coordination number, porosity, and pressure relations for P and S wave velocities from experimental data. Our recipe provides reasonable fits to other experimental and borehole data, and specifically

  11. Origin of dolostone reservoir rocks, Smackover Formation (Oxfordian), northeastern Gulf Coast, U. S. A

    SciTech Connect

    Prather, B.E. )

    1992-02-01

    Formation of regionally extensive dolostone reservoir rocks in the Smackover can be understood despite the possible effects of recrystallization. Geochemical and petrographic data suggest that dolomitization took place in (1) seawater-seepage, (2) reflux, (3) near-surface mixed-water, (4) shallow-burial mixed-water, and (5) deeper burial environments, which overlapped in time and space to form a platform-scale' dolostone body composed of a complex mixture of dolomites. Seawater-seepage and reflux dolomitization occurred in the near surface penecontemporaneously with deposition of the Smackover and overlying Haynesville Formations. Dolomitization by seawater seepage occurred within an oolite grainstone sill which separated an intraplatform salt basin from the open sea. Seawater flowed landward through the sill in response to evaporitic drawdown of brines in the isolated intraplatform basin. Isolation of the salt basin occurred during the Oxfordian when the shoreline retreated from the Conecuh embayment. Dolomite located at the top of the Smackover enriched in {sup 18}O suggests additional dolomitization by reflux of hypersaline brines. Reflux occurred as Buckner coastal sabkhas prograded over Smackover oolite grainstone shoreface deposits. Vugs lined with shallow-burial calcite and dolomite cements indicate flushing of the Smackover grainstone aquifer with fresh water. Freshwater intrusion probably occurred following sea level lowstands during the Late Jurassic and Early Cretaceous. Leaching in the proximal portion of the freshwater aquifer produced excellent limestone reservoir rocks in the updip Smackover. Dolomitization in the contemporaneous downdip mixed connate/freshwater zone formed dolostone reservoir rocks with depleted isotopic compositions consistent with a shallow-burial mixed-water origin.

  12. Origin of Dolostone reservoir rocks, smackover formation (Oxfordian), northeastern Gulf Coast, U. S. A

    SciTech Connect

    Prather, B.E. )

    1993-09-01

    Geochemical and petrographic data suggest that, despite the effects of recrystallization, formation of regionally extensive dolostone reservoir rocks in the Smackover Formation can be deciphered. These data indicate that dolomitization took place in (1) seawater seepage, (2) reflux, (3) near-surface mixed-water, (4) shallow-burial mixed-water, and (5) deeper burial environments, which overlapped in time and space to form a platform-scale dolostone body composed of a complex mixture of dolomites. Seawater-seepage and reflux dolomitization occurred in near-surface environments penecontemporaneous with deposition of the Smackover and overlying Haynesville formations. Dolomitization by seawater seepage occurred within an oolite grainstone sill that separated an intraplatform salt basin from the open Late Jurassic sea. Seawater flowed landward through the sill in the response to evaporitic drawdown of brines in the isolated intraplatform basin during a lowstand of Late Jurassic sea level. Dolomite enriched in [sup 18]O located at the top of the Smackover suggests additional dolomitization by reflux of hypersaline brines. Reflux occurred as Buckner coastal sabkhas prograded over Smackover oolite grainstone shoreface deposits. Vugs lined with shallow-burial calcite and dolomite cements indicate flushing of the Smackover grainstone aquifer with fresh water. Freshwater intrusion probably occurred along the Smackover's updip limit and subcrop following sea level lowstands during the Late Jurassic and Early Cretaceous. Leaching in the proximal part of the freshwater aquifer produced excellent-quality limestone reservoir rocks in the updip Smackover. Dolomitization in the contemporaneous downdip mixed connate/freshwater zone formed dolostone reservoir rocks with depleted isotopic compositions consistent with a shallow-burial mixed-water origin.

  13. Lithology and alteration mineralogy of reservoir rocks at Coso Geothermal Area, California

    SciTech Connect

    Lutz, S.J.; Moore, J.N.; Copp, J.F.

    1995-06-01

    Coso is one of several high-temperature geothermal systems associated with recent volcanic activity in the Basin and Range province. Chemical and fluid inclusion data demonstrate that production is from a narrow, asymmetric plume of thermal water that originates from a deep reservoir to the south and then flows laterally to the north. Geologic controls on the geometry of the upwelling plume were investigated using petrographic and analytical analyses of reservoir rock and vein material. The nature of the low-angle outflow zone and the overlying cap that prevents a surface expression of the geothermal system appears to be related to a combination of lithologic, structural and mineralogic factors. The position of the outflow plume is partially controlled by the distribution of fractured crystalline intrusives within foliated metamorphic rocks. Intrusive-metamorphic lithologic contacts are characterized by sericite-pyrite alteration and correlate with fluid entries in the wells. The base of a thick intrusive unit in several wells coincides with the 250{degrees}C isotherm based on fluid inclusion data. A smectite clay zone developed in the overlying metamorphic rock acts as a cap to the productive zone and inhibits vertical movement of the geothermal fluids above the main upwelling zone. The upwelling zone lies within a epidote-quartz veined, coarse-grained granite at depth in the southern portion of the field. The mineralogy of the clays varies systematically with depth and temperature. The distribution of fine-grained clay minerals with depth indicates that the smectite cap thickens dramatically from the north to the south, and overlies a strongly sericitized zone in the upwelling portion of the reservoir. Wairakite-chlorite-epidote-calcite-quartz veins at the contact with the deep granite record deposition from the hottest geothermal fluids (342{degrees}C) in the Coso field.

  14. Geochemical Modeling of CO2, Brine, and Reservoir Rock Interactions in the Knox Group, Western Kentucky

    NASA Astrophysics Data System (ADS)

    Zhu, J.; Parris, T. M.; Bowersox, J.; Harris, D. C.

    2011-12-01

    Regionally extensive dolostones and sandstones in the Cambrian-Ordovician Knox Group could provide commercial-scale CO2 storage capacity in the Illinois Basin of Kentucky, Illinois, and Indiana. This 1200 m thick interval of dolostone and less abundant quartz sandstone is a prospective sequestration target in the southern part of the Illinois Basin, where the Cambrian Mt. Simon Sandstone, a main sequestration target in the central part of the basin, is thin to absent, or deeply buried. The Kentucky Geological Survey (KGS) has successfully injected 690 tons of CO2 into the Knox Group through a 2477 m deep well (KGS #1 Blan well) at a test site in western Kentucky. To understand the long-term fate of CO2 stored in a saline reservoir in the Knox group, this study uses TOUGHREACT to model geochemical reactions among injected CO2, brine, and the reservoir rocks. Data collected in the KGS #1 Blan well, including rock cores, deep brine water samples, temperatures, and pressures, are the main data sources. A kinetic batch model is used first to simulate the impacts of dissolved CO2 on a mineral assemblage representing the Gunter Sandstone, a subgroup of the Knox Formation. The mineral assemblage consists of mainly quartz and dolomite with small amount of k-feldspar. The batch simulation results show precipitation of calcite, magnesite, illite, and quartz and dissolution of dolomite and k-feldspar. A 1-D radial reactive transport model is being constructed to simulate the injection test to evaluate the migration of the injected CO2, mineral dissolution and precipitation, and changes of porosity and permeability of formation rocks. The reactive model will be used to simulate hypothetical commercial scale injection scenarios to evaluate the long-term impacts of large scale CO2 injection on the Knox reservoir.

  15. The elusive Hadean enriched reservoir revealed by 142Nd deficits in Isua Archaean rocks.

    PubMed

    Rizo, Hanika; Boyet, Maud; Blichert-Toft, Janne; O'Neil, Jonathan; Rosing, Minik T; Paquette, Jean-Louis

    2012-11-01

    The first indisputable evidence for very early differentiation of the silicate Earth came from the extinct (146)Sm-(142)Nd chronometer. (142)Nd excesses measured in 3.7-billion-year (Gyr)-old rocks from Isua (southwest Greenland) relative to modern terrestrial samples imply their derivation from a depleted mantle formed in the Hadean eon (about 4,570-4,000 Gyr ago). As dictated by mass balance, the differentiation event responsible for the formation of the Isua early-depleted reservoir must also have formed a complementary enriched component. However, considerable efforts to find early-enriched mantle components in Isua have so far been unsuccessful. Here we show that the signature of the Hadean enriched reservoir, complementary to the depleted reservoir in Isua, is recorded in 3.4-Gyr-old mafic dykes intruding into the Early Archaean rocks. Five out of seven dykes carry (142)Nd deficits compared to the terrestrial Nd standard, with three samples yielding resolvable deficits down to -10.6 parts per million. The enriched component that we report here could have been a mantle reservoir that differentiated owing to the crystallization of a magma ocean, or could represent a mafic proto-crust that separated from the mantle more than 4.47 Gyr ago. Our results testify to the existence of an enriched component in the Hadean, and may suggest that the southwest Greenland mantle preserved early-formed heterogeneities until at least 3.4 Gyr ago. PMID:23128231

  16. Biodegradation reduces magnetization in oil bearing rocks: magnetization results of a combined chemical and magnetic study

    NASA Astrophysics Data System (ADS)

    Emmerton, S.; Muxworthy, A. R.; Sephton, M. A.; Williams, W.

    2012-12-01

    A relationship between hydrocarbons and their magnetic signatures has been alluded to for decades but this is the first study to combine geochemical and magnetic data. We report an extended study that identifies a definitive connection between magnetic mineralogy and biodegradation within oil-bearing rocks. Samples from Colombia, Canada Indonesia and the UK were collected and magnetically characterized. A negative linear regression in log space between magnetic susceptibility and the percentage of extractable organic matter was observed for individual reservoirs. To determine if this relationship is due to the activity of bacteria or migration of the oil, the percentage of oil components; aliphatic, aromatics, polars and resins and the biodegradation state of the samples were compared to the magnetic susceptibility and magnetic mineralogy of the samples. Geochemical biomarker data revealed that all oil samples were derived from mature type-II kerogen, which was deposited in oxygen-poor environments allowing for an investigation into biodegradation variations. Biodegradation is the decrease of oil quality through the conversion of aliphatic hydrocarbons to polar constituents mainly through the activity of bacteria. A distinct decrease in magnetic susceptibility was correlated to decreasing oil quality (loss of aliphatic hydrocarbons, more biodegraded), which cannot be rejected at 99% confidence. Further magnetic characterization revealed that the high quality, low biodegradation oils from Colombia have a higher magnetic susceptibility (10-3-10-4 m3kg-1) and are dominated by pseudo-single domain grains of magnetite. The lower quality oils i.e., the UK, Canadian and Indonesian samples, displayed decreased magnetic susceptibility (10-5-10-6 m3kg-1) and pseudo-single domain to multidomain grains of magnetite and hematite. Magnetite and pyrrhotite framboidal material were found in all but the Canadian samples. Therefore, with decreasing oil quality there is a progressive

  17. Fluid identification in tight sandstone reservoirs based on a new rock physics model

    NASA Astrophysics Data System (ADS)

    Sun, Jianmeng; Wei, Xiaohan; Chen, Xuelian

    2016-08-01

    To identify pore fluids, we establish a new rock physics model named the tight sandstone dual-porosity model based on the Voigt–Reuss–Hill model, approximation for the Xu–White model and Gassmann’s equation to predict elastic wave velocities. The modeling test shows that predicted sonic velocities derived from this rock physics model match well with measured ones from logging data. In this context, elastic moduli can be derived from the model. By numerical study and characteristic analyzation of different elastic properties, a qualitative fluid identification method based on Poisson’s ratio and the S–L dual-factor method based on synthetic moduli is proposed. Case studies of these two new methods show the applicability in distinguishing among different fluids and different layers in tight sandstone reservoirs.

  18. Integrating geology, rock physics, and seismology for reservoir-quality prediction

    NASA Astrophysics Data System (ADS)

    Florez-Nino, Juan-Mauricio

    This research focuses on the prediction of reservoir quality from seismic and well-log data, integrating concepts from geology and geophysics. The purpose has been to understand the geologic processes that control lateral variations in acoustic impedance and porosity. The work concentrates on the effect of rock texture and fractures on the elastic properties of sedimentary rocks. This work improves the understanding of the rock-physics depositional and diagenetic trends. The modified Hashin-Shtrikman lower bound can be used to distinguish between sorting and packing effects. It constitutes an upper bound for the sorting effect and a lower bound for the packing effect. Pressure solution is an alternative mechanism to reproduce the rock-physics diagenetic trend for high-porosity quartzose sands, using the Digby-Rutter model proposed here. The patterns that clastic sedimentary sequences present, in the rock-physics planes, agree with predictions from rock-physics models. Dispersed sand-clay mixtures predominate in fluvial deposits, whereas laminar mixtures predominate in mud-rich deep-water deposits. Scarcity of mixed lithofacies characterizes sand-rich deep-water deposits, whereas abundance of these lithofacies occurs in low-energy shallow marine deposits. The results demonstrate that the elastic properties of clastic mixed lithofacies strongly vary depending on the mixture's proportion and fabric, and rock-physics models can be used to predict these variations. The second part of this research deals with the use of outcrop information and seismic data to predict fracture distribution in the subsurface. This work documents a fundamental link between fracture hierarchies and sequence stratigraphy. Fracture spacing and dimensions of different fracture hierarchies are constrained by the thickness of the confining stratigraphic interval. It also documents examples of hierarchical shearing and progressive deformation, a concept that explains the evolution of faults and

  19. Geologic CO2 Sequestration: Predicting and Confirming Performance in Oil Reservoirs and Saline Aquifers

    NASA Astrophysics Data System (ADS)

    Johnson, J. W.; Nitao, J. J.; Newmark, R. L.; Kirkendall, B. A.; Nimz, G. J.; Knauss, K. G.; Ziagos, J. P.

    2002-05-01

    extending this capability to address CO2-flood EOR/sequestration in oil reservoirs. We have also developed a suite of innovative geophysical and geochemical techniques for monitoring sequestration performance in both settings. These include electromagnetic induction imaging and electrical resistance tomography for tracking migration of immiscible CO2, noble gas isotopes for assessing trace CO2 leakage through the cap rock, and integrated geochemical sampling, analytical, and experimental methods for determining sequestration partitioning among solubility and mineral trapping mechanisms. We have proposed to demonstrate feasibility of the co-optimized EOR/sequestration concept and utility of our modeling and monitoring technologies to design and evaluate its implementation by conducting a demonstration project in the Livermore Oil Field. This small, mature, shallow field, located less than a mile east of Lawrence Livermore National Laboratory, is representative of many potential EOR/sequestration sites in California. In approach, this proposed demonstration is analogous to the Weyburn EOR/CO2 monitoring project, to which it will provide an important complement by virtue of its contrasting depth (immiscible versus Weyburn's miscible CO2 flood) and geologic setting (clay-capped sand versus Weyburn's anhydrite-capped carbonate reservoir).

  20. Fluid sensitivity study of elastic parameters in low-medium porosity and permeability reservoir rocks

    NASA Astrophysics Data System (ADS)

    Pei, Fa-Gen; Zou, Chang-Chun; He, Tao; Shi, Ge; Qiu, Gen-Gen; Ren, Ke-Ying

    2010-03-01

    In this article, based on the acoustic measurements of core samples obtained from the low to medium porosity and permeability reservoirs in the WXS Depression, the densities and P and S wave velocities of these core samples were obtained. Then based on these data, a series of elastic parameters were computed. From the basic theory and previous pore fluid research results, we derived a new fluid identification factor (F). Using the relative variations, Ag/w and Ao/w, of the elastic parameters between gas and water saturated samples and between oil and water saturated samples, λρ, σ HSFIF, Kρ, λρ - 2µ ρ, and F as quantitative indicators, we evaluate the sensitivity of the different fluid identification factors to identify reservoir fluids and validate the effects by crossplots. These confirm that the new fluid identification factor (F) is more sensitive for distinguishing oil and water than the traditional method and is more favorable for fliud identification in low to medium porosity and permeability reservoirs.

  1. Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity

    SciTech Connect

    Mancini, E.A.

    1989-01-01

    The objective of this project is to augment the National Reservoir Database (TORIS database) and to increase our understanding of geologic heterogeneities that affect the recoveries of oil and gas from carbonate reservoirs in the State of Alabama and to identify those resources that are producible at moderate cost. This objective will be achieved through detailed geological, geostatistical, and engineering characterization of typical Jurassic Smackover Formation hydrocarbon reservoirs in selected productive fields in the State of Alabama. These studies will be utilized to develop and test mathematical models for prediction of the effects of reservoirs heterogeneities.

  2. Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity

    SciTech Connect

    Mancini, E.A.

    1990-01-01

    The objective of this project is to augment the National Reservoir Database (TORIS database) and to increase our understanding of geologic heterogeneities that effect the recoveries of oil and gas from carbonate reservoirs in the State of Alabama and to identify those resources that are producible at moderate cost. This objective will be achieved through detailed geological, geostatistical, or engineering characterization of typical Jurassic Smackover Formation hydrocarbon reservoirs in selected productive fields in the State of Alabama. The results of these studies will be used to develop and test mathematical models for prediction of the effects of reservoir heterogeneities in hydrocarbon production.

  3. Total petroleum systems and geologic assessment of undiscovered oil and gas resources in the San Juan Basin Province, exclusive of Paleozoic rocks, New Mexico and Colorado

    USGS Publications Warehouse

    U.S. Geological Survey San Juan Basin Assessment Team

    2013-01-01

    In 2002, the U.S. Geological Survey (USGS) estimated undiscovered oil and gas resources that have the potential for additions to reserves in the San Juan Basin Province, New Mexico and Colorado. Paleozoic rocks were not appraised. The last oil and gas assessment for the province was in 1995. There are several important differences between the 1995 and 2002 assessments. The area assessed is smaller than that in the 1995 assessment. This assessment of undiscovered hydrocarbon resources in the San Juan Basin Province also used a slightly different approach in the assessment, and hence a number of the plays defined in the 1995 assessment are addressed differently in this report. After 1995, the USGS has applied a total petroleum system (TPS) concept to oil and gas basin assessments. The TPS approach incorporates knowledge of the source rocks, reservoir rocks, migration pathways, and time of generation and expulsion of hydrocarbons; thus the assessments are geologically based. Each TPS is subdivided into one or more assessment units, usually defined by a unique set of reservoir rocks, but which have in common the same source rock. Four TPSs and 14 assessment units were geologically evaluated, and for 13 units, the undiscovered oil and gas resources were quantitatively assessed.

  4. Experimental Research on Profile Control for Oil Displacement by Functional Polymer in Low Permeability Fractured Reservoir

    NASA Astrophysics Data System (ADS)

    Li, Li; Xiuting, Han; Lin, Meng

    Utilizing artificial fractured cores with low permeability, a physical simulation experiment on profile control for oil displacement was carried out. The result showed that 23.63% extra oil recovery was realized by functional polymer, and 29.05% extra oil recovery was realized by functional polymer with gas which is higher than water flooding alone. The experiment demonstrates that functional polymer is effective for enhance oil recovery for low permeability fractured reservoir significantly.

  5. An innovative geostatistical approach to oil volumetric calculations: Rock Creek Field, West Virginia

    SciTech Connect

    McDowell, R.R.; Matchen, D.L.; Hohn, M.E.; Vargo, A.G. )

    1994-08-01

    Detailed analysis of production trends in heterogeneous reservoirs requires local estimates of production, original, oil in place (OOIP), and recovery efficiency. In older fields, calculating these values is hampered by incomplete well records, inconsistent reporting of production (well by well vs. lease by lease), unknown effective drainage radius, and poorly constrained completion interval. Accepted methods of estimation rely heavily on the use of average values for reservoir properties. The authors have developed the use of average values for calculating local and field-wide estimates, and have compared their results to published values. The study of the Lower Mississippian Big Injun sandstone reservoir in Rock Creek field, central West Virginia, used production data obtained from operators. Production for the first 10 yr was reconstructed, when necessary, by comparison to decline curves for 70 wells with complete production records. Similarly, curve fitting techniques were used to interpolate data for missing years. Cumulative production values for 667 producing wells were kriged over the extent of the field; the resulting grid was sampled to provide an estimate of cumulative production at each well location. Kriged estimates of pay thickness, porosity, and water saturation were used to calculate OOIP and recovery efficiency (cumulative production + OOIP), but not geographic distribution of these two parameters. An optimal radius of 270 ft gave recovery efficiencies ranging between 18.75% and 21.9%, comparing favorably with a published value of 22.3%. Summing the OOIP value for all producing wells in the field yields a value of 139.6 million bbl, significantly higher than the published value of 37.8 million bbl. The estimate reflects a more complete data set and revised values for reservoir parameters. Discussions with the principal operator in the field suggests that the higher figure is more correct.

  6. Gamma ray spectrometry logs as a hydrocarbon indicator for clastic reservoir rocks in Egypt.

    PubMed

    Al-Alfy, I M; Nabih, M A; Eysa, E A

    2013-03-01

    Petroleum oil is an important source for the energy in the world. The Gulf of Suez, Nile Delta and South Valley are important regions for studying hydrocarbon potential in Egypt. A thorium normalization technique was applied on the sandstone reservoirs in the three regions to determine the hydrocarbon potentialities zones using the three spectrometric radioactive gamma ray-logs (eU, eTh and K% logs). The conventional well logs (gamma-ray, deep resistivity, shallow resistivity, neutron, density and sonic logs) are analyzed to determine the net pay zones in these wells. Indices derived from thorium normalized spectral logs indicate the hydrocarbon zones in petroleum reservoirs. The results of this technique in the three regions (Gulf of Suez, Nile Delta and South Valley) are in agreement with the results of the conventional well log analyses by ratios of 82%, 78% and 71% respectively. PMID:23306160

  7. Bathymetric maps and water-quality profiles of Table Rock and North Saluda Reservoirs, Greenville County, South Carolina

    USGS Publications Warehouse

    Clark, Jimmy M.; Journey, Celeste A.; Nagle, Doug D.; Lanier, Timothy H.

    2014-01-01

    Lakes and reservoirs are the water-supply source for many communities. As such, water-resource managers that oversee these water supplies require monitoring of the quantity and quality of the resource. Monitoring information can be used to assess the basic conditions within the reservoir and to establish a reliable estimate of storage capacity. In April and May 2013, a global navigation satellite system receiver and fathometer were used to collect bathymetric data, and an autonomous underwater vehicle was used to collect water-quality and bathymetric data at Table Rock Reservoir and North Saluda Reservoir in Greenville County, South Carolina. These bathymetric data were used to create a bathymetric contour map and stage-area and stage-volume relation tables for each reservoir. Additionally, statistical summaries of the water-quality data were used to provide a general description of water-quality conditions in the reservoirs.

  8. Impact of rock salt creep law choice on subsidence calculations for hydrocarbon reservoirs overlain by evaporite caprocks

    NASA Astrophysics Data System (ADS)

    Marketos, G.; Spiers, C. J.; Govers, R.

    2016-06-01

    Accurate forward modeling of surface subsidence above producing hydrocarbons reservoirs requires an understanding of the mechanisms determining how ground deformation and subsidence evolve. Here we focus entirely on rock salt, which overlies a large number of reservoirs worldwide, and specifically on the role of creep of rock salt caprocks in response to production-induced differential stresses. We start by discussing available rock salt creep flow laws. We then present the subsidence evolution above an axisymmetric finite element representation of a generic reservoir that extends over a few kilometers and explore the effects of rock salt flow law choice on the subsidence response. We find that if rock salt creep is linear, as appropriate for steady state flow by pressure solution, the subsidence response to any pressure reduction history contains two distinct components, one that leads to the subsidence bowl becoming narrower and deeper and one that leads to subsidence rebound and becomes dominant at later stages. This subsidence rebound becomes inhibited if rock salt deforms purely through steady state power law creep at low stresses. We also show that an approximate representation of transient creep leads to relatively small differences in subsidence predictions. Most importantly, the results confirm that rock salt flow must be modeled accurately if good subsidence predictions are required. However, in practice, large uncertainties exist in the creep behavior of rock salt, especially at low stresses. These are a consequence of the spatial variability of rock salt physical properties, which is practically impossible to constrain. A conclusion therefore is that modelers can only resort to calculating bounds for the subsidence evolution above producing rock salt-capped reservoirs.

  9. Increasing Heavy Oil Reserves in the Wilmington Oil Field through Advanced Reservoir Characterization and Thermal Production Technologies

    SciTech Connect

    City of Long Beach; David K.Davies and Associates; Tidelands Oil Production Company; University of Southern California

    1999-06-25

    The objective of this project is to increase the recoverable heavy oil reserves within sections of the Wilmington Oil Field, near Long Beach, California. This is realized through the testing and application of advanced reservoir characterization and thermal production technologies. It is hoped that the successful application of these technologies will result in their implementation throughout the Wilmington Field and through technology transfer, will be extended to increase the recoverable oil reserves in other slope and basin clastic (SBC) reservoirs. The existing steamflood in the Tar zone of Fault Block (FB) II-A has been relatively insufficient because of several producability problems which are common in SBC reservoir; inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil and non-uniform distribution of the remaining oil. This has resulted in poor sweep efficiency, high steam-oil ratios, and early breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves.

  10. Permeability of intact and fractured rocks in Krafla geothermal reservoir, Iceland

    NASA Astrophysics Data System (ADS)

    Eggertsson, Gudjon; Lavallée, Yan; Markusson, Sigurdur

    2016-04-01

    The magmatic-hydrothermal system at Krafla Volcano, North-East Iceland, has been the source of an important geothermal fluids, exploited by Landsvirkjun National Power since 1977 to generate electricity (~60 MW). In the last decade, the energy was extracted from fluids of moderate temperature (200-300°C), but in order to satisfy the demand for sustainable, environmentally-safe energy, Landsvirkjun is aiming to source fluids in the super high-enthalpy hydrothermal system (400°-600°C and <220 bar). In relation to this, IDDP-1 was drilled in 2009. Drilling was terminated at a depth of 2100m when the drill string penetrated rhyolite magma. The rock around this rhyolite magma body shows great potential for production, as its temperatures are very high and it is located at shallow depth. Here, we present the results of mechanical and permeability tests carried out on the main lithologies forming the geothermal reservoir rock. During a field survey in fall 2015, and through information gathered from previous drilling exercises, five main rock types were identified and sampled to carry out this study: that is, basalts (10% to 60% porosity), hyaloclastites (35% to 45% porosity), obsidians (0,25% to 5% porosity), ignimbrites (13% to 18% porosity), and intrusive felsites and microgabbros (10% to 16% porosity). The only rock type not found in outcrops on the surface is the felsite and microgabbros which are thought to be directly above the rhyolite magma (~80m thick). The reason they can be found on the surface is that during the Mývatns-fires, an explosion creating the Víti crater and scattered these rocks around the area. For all these lithologies, the porosity was determined using helium pycnometry. On-going permeability measurements are made using a classic hydrostatic cell. To simulate the stress conditions extant in the hydrothermal field, we performed permeability measurements at a range of confining pressure (1 to 100 MPa), using a pore pressure differential of 0

  11. A study of relations between physicochemical properties of crude oils and microbiological characteristics of reservoir microflora

    NASA Astrophysics Data System (ADS)

    Yashchenko, I. G.; Polishchuk, Yu. M.; Peremitina, T. O.

    2015-10-01

    The dependence of the population and activity of reservoir microflora upon the chemical composition and viscosity of crude oils has been investigated, since it allows the problem of improvement in the technologies and enhancement of oil recovery as applied to production of difficult types of oils with anomalous properties (viscous, heavy, waxy, high resin) to be solved. The effect of the chemical composition of the oil on the number, distribution, and activity of reservoir microflora has been studied using data on the microbiological properties of reservoir water of 16 different fields in oil and gas basins of Russia, Mongolia, China, and Vietnam. Information on the physicochemical properties of crude oils of these fields has been obtained from the database created at the Institute of Petroleum Chemistry, Siberian Branch on the physicochemical properties of oils throughout the world. It has been found that formation water in viscous oil reservoirs is char acterized by a large population of heterotrophic and sulfate reducing bacteria and the water of oil fields with a high paraffin content, by population of denitrifying bacteria.

  12. Investigation of oil recovery improvement by coupling an interfacial tension agent and a mobility control agent in light oil reservoirs. Second annual report, October 1993--September 1994

    SciTech Connect

    Pitts, M.J.

    1995-04-01

    {open_quotes}Investigation of Oil Recovery Improvement by Coupling an Interfacial Tension Agent and a Mobility Control Agent in Light Oil Reservoirs{close_quotes} is studying two major areas concerning co-injecting an interfacial tension reduction agent(s) and a mobility control agent. The first area defines the interactions of alkaline agents, surfactants, and polymers on a fluid-fluid and a fluid-rock basis. The second area concerns the economic improvement of the combined technology. This report continues the fluid-fluid interaction evaluations and begins the fluid-rock studies. Fluid-fluid interfacial tension work determined that replacing sodium ion with either potassium or ammonium ion in solutions with interfacial tension reduction up to 19,600 fold was detrimental and had little or no effect on alkali-surfactant solutions with interfacial tension reduction of 100 to 200 fold. Reservoir brine increases interfacial tension between crude oil and alkaline-surfactant solutions. Na{sub 2}CO{sub 3}-surfactant solutions maintained ultra low and low interfacial tension values better than NaOH-surfactant solutions. The initial phase of the fluid-rock investigations was adsorption studies. Surfactant adsorption is reduced when co-dissolved with alkali. Na{sub 2}CO{sub 3} and Na{sub 3}PO{sub 4} are more efficient at reducing surfactant adsorption than NaOH. When polymer is added to the surfactant solution, surfactant adsorption is reduced as well. When both polymer and alkali are added, polymer is the dominate component, reducing the Na{sub 2}CO{sub 3} and NaOH effect on adsorption. Substituting sodium ion with potassium or ammonium ion increased or decreased surfactant adsorption depending on surfactant structure with alkali having a less significant effect. No consistent change of surfactant adsorption with increasing salinity was observed in the presence or absence of alkali or polymer.

  13. Wettability modification of rock cores by fluorinated copolymer emulsion for the enhancement of gas and oil recovery

    NASA Astrophysics Data System (ADS)

    Feng, Chunyan; Kong, Ying; Jiang, Guancheng; Yang, Jinrong; Pu, Chunsheng; Zhang, Yuzhong

    2012-07-01

    The fluorine-containing acrylate copolymer emulsion was prepared with butyl acrylate, methacrylic acid and 1H, 1H, 2H, 2H-perfluorooctyl acrylate as monomers. Moreover, the structure of the copolymer was verified by Fourier transform infrared (FTIR), nuclear magnetic resonance (1H NMR and 19F NMR) and X-ray photoelectron spectroscopy (XPS) analyses. The results showed that all the monomers had been copolymerized and the presence of fluorine moieties. The contact angle (CA) analyses, capillary rise and imbibition spontaneous tests were used to estimate the influence of the copolymer emulsion on the wettability of gas reservoirs. It was observed that the rock surface was of large contact angles of water, oilfield sewage, hexadecane and crude oil after treatment with the emulsion. The capillary rise results indicated that the contact angles of water/air and oil/air systems increased from 60° and 32° to 121° and 80°, respectively, due to the emulsion treatment. Similarly, because of wettability alteration by the fluoropolymer, the imbibition of water and oil in rock core decreased significantly. Experimental results demonstrated that the copolymer emulsion can alter the wettability of porous media from strong liquid-wetting to gas-wetting. This work provides a cost-effective method to prepare the fluoropolymer which can increase gas deliverability by altering the wettability of gas-condensate reservoirs and mitigating the water block effect.

  14. Temperature dependence of hydraulic properties of Upper Rhine Graben rocks at conditions modelling deep geothermal reservoirs

    NASA Astrophysics Data System (ADS)

    Hernández Castañeda, Mariela Carolina; Renner, Joerg; Mueller, Thomas

    2016-04-01

    The evolution of reservoir rocks' hydraulic properties critically affects the operation and long term sustainability of geothermal and petroleum reservoirs. Mechanical and chemical effects modify the permeability and the storage capacity of a reservoir, whose time characteristics have remained poorly constrained up to now. The permeability (k) and specific storage capacity (s) of the rocks constituting the geothermal reservoir are important parameters controlling the extent of the space-time characteristics of the pressure drawdown (or buildup at the reinjection site). To study the evolution of permeability and specific storage capacity as a function of pressure, temperature, and time, we performed oscillatory pore pressure tests. Experiments were performed using samples collected at surface outcrops representing the lithological sequence of the Upper Rhine Graben reservoir in southern Germany, i.e. sandstone and limestone, as well as Padang granite, representing a homogeneous, crystalline reservoir rock. Experiments were run at temperatures between 20 and 200 ° C, confining pressures between 20 and 110 MPa, and a fixed fluid pressure of 10 MPa, modeling characteristic conditions of deep geothermal reservoirs. Intact samples of granite, limestone and sandstone yield permeability and specific storage capacity of about 10‑18, 10‑15, and 10‑14 m2, and 10‑10, 10‑11 and 10‑8 Pa‑1, respectively, with modest dependence on temperature and effective pressure. In addition, longitudinally fractured samples were prepared by simple splitting or cutting and grinding. Grinding was performed with sandpaper of different ISO grits designations (P100, P600, and P1200) to systematically vary the surfaces' roughness. Fractures cause an increase in room-temperature permeability up to 3 and 2 orders of magnitudes for samples of granite and limestone, respectively. Their pressure dependence corresponds to a reduction in permeability modulus by about one order of magnitude

  15. Oil Recovery Enhancement from Fractured, Low Permeability Reservoirs. [Carbonated Water

    DOE R&D Accomplishments Database

    Poston, S. W.

    1991-01-01

    The results of the investigative efforts for this jointly funded DOE-State of Texas research project achieved during the 1990-1991 year may be summarized as follows: Geological Characterization - Detailed maps of the development and hierarchical nature the fracture system exhibited by Austin Chalk outcrops were prepared. The results of these efforts were directly applied to the development of production decline type curves applicable to a dual-fracture-matrix flow system. Analysis of production records obtained from Austin Chalk operators illustrated the utility of these type curves to determine relative fracture/matrix contributions and extent. Well-log response in Austin Chalk wells has been shown to be a reliable indicator of organic maturity. Shear-wave splitting concepts were used to estimate fracture orientations from Vertical Seismic Profile, VSP data. Several programs were written to facilitate analysis of the data. The results of these efforts indicated fractures could be detected with VSP seismic methods. Development of the EOR Imbibition Process - Laboratory displacement as well as Magnetic Resonance Imaging, MRI and Computed Tomography, CT imaging studies have shown the carbonated water-imbibition displacement process significantly accelerates and increases recovery from oil saturated, low permeability rocks. Field Tests - Two operators amenable to conducting a carbonated water flood test on an Austin Chalk well have been identified. Feasibility studies are presently underway.

  16. Oil recovery enhancement from fractured, low permeability reservoirs. [Carbonated Water

    SciTech Connect

    Poston, S.W.

    1991-01-01

    The results of the investigative efforts for this jointly funded DOE-State of Texas research project achieved during the 1990-1991 year may be summarized as follows: Geological Characterization - Detailed maps of the development and hierarchical nature the fracture system exhibited by Austin Chalk outcrops were prepared. The results of these efforts were directly applied to the development of production decline type curves applicable to a dual-fracture-matrix flow system. Analysis of production records obtained from Austin Chalk operators illustrated the utility of these type curves to determine relative fracture/matrix contributions and extent. Well-log response in Austin Chalk wells has been shown to be a reliable indicator of organic maturity. Shear-wave splitting concepts were used to estimate fracture orientations from Vertical Seismic Profile, VSP data. Several programs were written to facilitate analysis of the data. The results of these efforts indicated fractures could be detected with VSP seismic methods.Development of the EOR Imbibition Process - Laboratory displacement as well as Magnetic Resonance Imaging, MRI and Computed Tomography, CT imaging studies have shown the carbonated water-imbibition displacement process significantly accelerates and increases recovery from oil saturated, low permeability rocks.Field Tests - Two operators amenable to conducting a carbonated water flood test on an Austin Chalk well have been identified. Feasibility studies are presently underway.

  17. 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.

  18. Orientation of minimum principal stress in the hot dry rock geothermal reservoir at Fenton Hill, New Mexico

    SciTech Connect

    Burns, K.L.

    1991-01-01

    The stress field at the source of microearthquakes in the interior of the hot dry rock geothermal reservoir at Fenton Hill appears to be different to the far field stress outside the reservoir. The stress field seems to be re-oriented prior to failure, during the course of processes that inflate the reservoir. The state of stress, both inside and outside, the hot dry rock (HDR) geothermal reservoir at Fenton Hill, is important in predicting the course of stress-dependent processes, and in transferring HDR technology developed at Fenton Hill, to sites, such as at Clearlake in California, where the stress field is expected to be substantially different. The state of stress at Fenton Hill is not well known because of limitations in stress measuring technology. It is necessary to use a variety of indirect methods and seek an estimate of the stress. 5 refs.

  19. Oil recovery from naturally fractured reservoirs by steam injection methods. Final report

    SciTech Connect

    Reis, J.C.; Miller, M.A.

    1995-05-01

    Oil recovery by steam injection is a proven, successful technology for nonfractured reservoirs, but has received only limited study for fractured reservoirs. Preliminary studies suggest recovery efficiencies in fractured reservoirs may be increased by as much as 50% with the application of steam relative to that of low temperature processes. The key mechanisms enhancing oil production at high temperature are the differential thermal expansion between oil and the pore volume, and the generation of gases within matrix blocks. Other mechanisms may also contribute to increased production. These mechanisms are relatively independent of oil gravity, making steam injection into naturally fractured reservoirs equally attractive to light and heavy oil deposits. The objectives of this research program are to quantify the amount of oil expelled by these recovery mechanisms and to develop a numerical model for predicting oil recovery in naturally fractured reservoirs during steam injection. The experimental study consists of constructing and operating several apparatuses to isolate each of these mechanisms. The first measures thermal expansion and capillary imbibition rates at relatively low temperature, but for various lithologies and matrix block shapes. The second apparatus measures the same parameters, but at high temperatures and for only one shape. A third experimental apparatus measures the maximum gas saturations that could build up within a matrix block. A fourth apparatus measures thermal conductivity and diffusivity of porous media. The numerical study consists of developing transfer functions for oil expulsion from matrix blocks to fractures at high temperatures and incorporating them, along with the energy equation, into a dual porosity thermal reservoir simulator. This simulator can be utilized to make predictions for steam injection processes in naturally-fractured reservoirs. Analytical models for capillary imbibition have also been developed.

  20. Fire flood method for recovering petroleum from oil reservoirs of low permeability and temperature

    DOEpatents

    Kamath, Krishna

    1984-08-14

    The present invention is directed to a method of enhanced oil recovery by fire flooding petroleum reservoirs characterized by a temperature of less than the critical temperature of carbon dioxide, a pore pressure greater than the saturated vapor pressure of carbon dioxide at said temperature (87.7.degree. F. at 1070 psia), and a permeability in the range of about 20 to 100 millidarcies. The in situ combustion of petroleum in the reservoir is provided by injecting into the reservoir a combustion supporting medium consisting essentially of oxygen, ozone, or a combination thereof. The heat of combustion and the products of this combustion which consist essentially of gaseous carbon dioxide and water vapor sufficiently decrease the viscosity of oil adjacent to fire front to form an oil bank which moves through the reservoir towards a recovery well ahead of the fire front. The gaseous carbon dioxide and the water vapor are driven into the reservoir ahead of the fire front by pressure at the injection well. As the gaseous carbon dioxide cools to less than about 88.degree. F. it is converted to liquid which is dissolved in the oil bank for further increasing the mobility thereof. By using essentially pure oxygen, ozone, or a combination thereof as the combustion supporting medium in these reservoirs the permeability requirements of the reservoirs are significantly decreased since the liquid carbon dioxide requires substantially less voidage volume than that required for gaseous combustion products.

  1. Reservoir characterization using oil-production-induced microseismicity, Clinton County, Kentucky

    NASA Astrophysics Data System (ADS)

    Rutledge, James T.; Phillips, W. Scott; Schuessler, Barbra K.

    1998-04-01

    Microseismic monitoring tests were conducted from 1993 to 1995 in the Seventy-Six oil field, Clinton County, Kentucky. Oil is produced from low-porosity, fractured carbonate rocks at <600 m depth. Downhole geophones were deployed in wells located within 120 to 250 m of new production wells. Three tests were conducted sequentially for 9.5-, 20.5-, and 30-week periods during which 110, 180 and 3237 microearthquakes were detected, respectively. Moment-derived magnitudes ranged from -2.5 to 0.9. Volumes extracted ranged from about 1300 to 1800 m 3; no injection operations were conducted. Gross changes in production rate correlate with event rate: event rate lags changes in production rate by 2 to 3 weeks. Hypocenters and first-motion data have revealed previously undetected, low-angle thrust faults above and below the currently drained depth intervals. Production history, well logs and drill tests indicate that the seismically active faults or fractures are previously drained intervals that have subsequently recovered to hydrostatic pressure via brine invasion. Storage capacity computed for one of these drained fractures implies that total oil production represents about 20% of total pore volume. Correlation of older production intervals and well-log porosity anomalies with the seismically active faults indicate that the oil reservoir in the study area is primarily a set of compartmentalized, low-angle thrust faults. Although low-angle fracture sets have not previously been considered in the exploration and development of the area, the mapped thrust faults are consistent with other investigators' interpretations of oil associated with secondary fracture sets occurring along deeper-seated, wrench-fault structures. Stress determined from composite focal mechanisms indicates a near-surface (<550 m) thrust regime. Maximum horizontal stress direction is N15°W±15°, rotated approximately 90° from regional orientation. The seismic behavior is consistent with poroelastic

  2. Integrated geologic and engineering determination of oil-reserve-growth potential in carbonate reservoirs

    SciTech Connect

    Holtz, M.H.; Rupel, S.C.; Hocott, C.R. )

    1992-11-01

    Leonardian restricted-platform carbonate reservoirs in the Permian Basin in West Texas and southeastern New Mexico exhibit abnormally low recovery efficiencies. Cumulative production form these mature reservoirs is only 18% of the original oil in place (OOIP), or about one-half the average recovery efficiency of Permian Basin carbonate reservoirs. Low recovery efficiency is directly related to high degrees of vertical and lateral facies heterogeneity caused by high-frequency, cyclic sedimentation in low-energy, carbonate platform environments and by equally complex postdepositional diagenesis. This paper reports that because of their geologic complexity, these reservoirs have high reserve-growth potential.

  3. Geologic controls on reservoir properties in gas-bearing middle and Upper Devonian rocks, southern Appalachian basin

    SciTech Connect

    Vessell, R.K.; Davies, D.K.

    1988-08-01

    Porosities and permeabilities have been measured for a wide range of nonfractured Devonian lithologies in 23 wells from southeastern Ohio, eastern Kentucky, West Virginia, and Virginia. These reservoir properties can be related directly to the geometry of the pore system. Pore geometry, in turn, is a function of rock lithology and mineralogy. Despite the lithologic complexity of the Devonian sequence, reservoir quality can be related to a small number of differing pore geometries.

  4. Study on Oil-Gas Reservoir Detecting Methods Using Hyperspectral Remote Sensing

    NASA Astrophysics Data System (ADS)

    Tian, Q.

    2012-07-01

    Oil-gas reservoir exploration using hyperspectral remote sensing, which based on the theory of hydrocarbon microseepage information and fine spectral response of target, is a new direction for the application of remote sensing technology. In this paper, Qaidam Basin and Liaodong Bay in China were selected as the study areas. Based on the hydrocarbon microseepage theory, the analysis of crude oil in soil in Qaidam Basin and spectral experiment of crude oil in sea water in Liaodong Bay, Hyperion hyperspectral remote sensing images were used to develop the method of oil-gas exploration. The results indicated that the area of oil-gas reservoir in Qaidam Basin could be delimited in two ways: the oil-gas reservoir can be obtained directly by the absorption bands near 1730nm in Hyperion image; and Linear Spectral Unmixing (LSU) and Spectral Angle Matching (SAM) of alteration mineral (e.g. kaolinite, illite) could be used to indirectly detect the target area in Qaidam Basin. In addition, combined with the optimal bands in the region of visible/near-infrared, SAM was used to extract the thin oil slick of microseepage in Liaodong Bay. Then the target area of oil-gas reservoir in Liaodong Bay can be delineated.

  5. Microbial enhanced oil recovery and compositions therefor

    DOEpatents

    Bryant, Rebecca S.

    1990-01-01

    A method is provided for microbial enhanced oil recovery, wherein a combination of microorganisms is empirically formulated based on survivability under reservoir conditions and oil recovery efficiency, such that injection of the microbial combination may be made, in the presence of essentially only nutrient solution, directly into an injection well of an oil bearing reservoir having oil present at waterflood residual oil saturation concentration. The microbial combination is capable of displacing residual oil from reservoir rock, which oil may be recovered by waterflooding without causing plugging of the reservoir rock. Further, the microorganisms are capable of being transported through the pores of the reservoir rock between said injection well and associated production wells, during waterflooding, which results in a larger area of the reservoir being covered by the oil-mobilizing microorganisms.

  6. Reservoir heterogeneity in Carter Sandstone, North Blowhorn Creek oil unit and vicinity, Black Warrior Basin, Alabama

    SciTech Connect

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

    1992-05-01

    This report presents accomplishments made in completing Task 3 of this project which involves development of criteria for recognizing reservoir heterogeneity in the Black Warrior basin. The report focuses on characterization of the Upper Mississippian Carter sandstone reservoir in North Blowhorn Creek and adjacent oil units in Lamar County, Alabama. This oil unit has produced more than 60 percent of total oil extracted from the Black Warrior basin of Alabama. The Carter sandstone in North Blowhorn Creek oil unit is typical of the most productive Carter oil reservoirs in the Black Warrior basin of Alabama. The first part of the report synthesizes data derived from geophysical well logs and cores from North Blowhorn Creek oil unit to develop a depositional model for the Carter sandstone reservoir. The second part of the report describes the detrital and diagenetic character of Carter sandstone utilizing data from petrographic and scanning electron microscopes and the electron microprobe. The third part synthesizes porosity and pore-throat-size-distribution data determined by high-pressure mercury porosimetry and commercial core analyses with results of the sedimentologic and petrographic studies. The final section of the report discusses reservoir heterogeneity within the context of the five-fold classification of Moore and Kugler (1990).

  7. IMPROVED OIL RECOVERY IN MISSISSIPPIAN CARBONATE RESERVOIRS OF KANSAS - NEAR TERM - CLASS 2

    SciTech Connect

    Timothy R. Carr; Don W. Green; G. Paul Willhite

    2000-04-30

    This annual report describes progress during the final year of the project entitled ''Improved Oil Recovery in Mississippian Carbonate Reservoirs in Kansas''. This project funded under the Department of Energy's Class 2 program targets improving the reservoir performance of mature oil fields located in shallow shelf carbonate reservoirs. The focus of the project was development and demonstration of cost-effective reservoir description and management technologies to extend the economic life of mature reservoirs in Kansas and the mid-continent. As part of the project, tools and techniques for reservoir description and management were developed, modified and demonstrated, including PfEFFER spreadsheet log analysis software. The world-wide-web was used to provide rapid and flexible dissemination of the project results through the Internet. A summary of demonstration phase at the Schaben and Ness City North sites demonstrates the effectiveness of the proposed reservoir management strategies and technologies. At the Schaben Field, a total of 22 additional locations were evaluated based on the reservoir characterization and simulation studies and resulted in a significant incremental production increase. At Ness City North Field, a horizontal infill well (Mull Ummel No.4H) was planned and drilled based on the results of reservoir characterization and simulation studies to optimize the location and length. The well produced excellent and predicted oil rates for the first two months. Unexpected presence of vertical shale intervals in the lateral resulted in loss of the hole. While the horizontal well was not economically successful, the technology was demonstrated to have potential to recover significant additional reserves in Kansas and the Midcontinent. Several low-cost approaches were developed to evaluate candidate reservoirs for potential horizontal well applications at the field scale, lease level, and well level, and enable the small independent producer to identify

  8. Geochemical changes in pore water and reservoir rock due to CO2 injection

    NASA Astrophysics Data System (ADS)

    Huq, Farhana; Blum, Philipp; Nowak, Marcus; Haderlein, Stefan; Grathwohl, Peter

    2010-05-01

    In response to current global warming, carbon capture and storage has been identified as one of the promising option. Thus, it can be an interim solution that is indeed a bridge to the future renewable energy without altering the present mode of energy consumption. Although large natural CO2 sinks are terrestrial eco-system and oceans, geological media or more specifically large sedimentary basins are now the most feasible options for carbon sequestration. At the study site, a former gas field (Altmark), which is located in the South of the Northeast German Basin, CO2 is planned to be injected into the reservoir with high pressure (> 50 bar) and temperature (125°C). Afterwards, CO2 dissolves into the pore water leading to acidification and follow up reactions such as dissolution/precipitation, which potentially change the porosity-permeability of the reservoir and the wetting properties of the mineral surfaces. The Altmark site was chosen due to its large storage capacity, well explored reservoir, high seal integrity due to the presence of massive salt layer (cap rock) and existing infrastructure required for enhanced gas recovery. The main objective of the current study is to quantify the CO2 trapping in aqueous solution under in situ reservoir condition. Therefore, it is necessary to investigate the geochemical changes in fluid composition due to dissolution of minerals under controlled laboratory conditions and to quantify the concentrations of complexing agents that might influence the concentration of total dissolved CO2 in aqueous solution over time. To observe these geochemical and hydraulic changes due to the injection of CO2, a closed system (batch system) technique is developed to study the influence of salinity, temperature, pressure and kinetics on mineral reactions. In addition to the closed system, a flow through (open) autoclave system was constructed. Water saturated sedimentary rock cores (e.g. from the Altmark site; 5cm long, 3cm diameter) are

  9. Physical property characterization of a damage zone in granitic rock - Implications for geothermal reservoir properties

    NASA Astrophysics Data System (ADS)

    Wenning, Quinn; Madonna, Claudio; Amann, Florian; Gischig, Valentin; Burg, Jean-Pierre

    2016-04-01

    Geothermal energy offers a viable alternative to mitigate greenhouse gas emitting energy production. A tradeoff between less expensive drilling costs and increased permeability at shallow depths versus increased heat production at deeper depths stipulates the economic energy potential of a given reservoir. From a geological perspective, successful retrieval of geothermal energy from the subsurface requires sufficient knowledge of the structural and stratigraphic relationship of the target formations, which govern the thermal conditions, physical properties, and fluid flow properties of reservoir rocks. In Switzerland, deep basement rocks (~5 km) with fluid conducting damage zones and enhanced fractured systems stimulated by hydraulic shearing are seen as a potential geothermal reservoir system. Damage zones, both natural and induced, provide permeability enhancement that is especially important for creating fluid conductivity where the matrix permeability is low. This study concentrates on characterizing the elastic and transport properties entering into a natural damage zone penetrated by a borehole at the Grimsel underground research laboratory. The borehole drilled from a cavern at 480 m below ground surface penetrates approximately 20 m of mostly intact Grimsel granodiorite before entering the first phyllosilicate-rich shear zone (~0.2 m thick). The borehole intersects a second shear zone at approximately 23.8m. Between the two shear zones the Grimsel granodiorite is heavily fractured. The minimum principle stress magnitude from in-situ measurements decreases along the borehole into the first shear zone. Two mutually perpendicular core samples of Grimsel granodiorite were taken every 0.1 m from 19.5 to 20.1 m to characterize the physical properties and anisotropy changes as a gradient away from the damage zone. Measurements of ultrasonic compressional (Vp) and shear (Vs) velocities at 1 MHz frequency are conducted at room temperature and hydrostatic pressures

  10. Hydrocarbon charging histories of the Ordovician reservoir in the Tahe oil field, Tarim Basin, China.

    PubMed

    Li, Chun-Quan; Chen, Hong-Han; Li, Si-Tian; Zhang, Xi-Ming; Chen, Han-Lin

    2004-08-01

    The Ordovician reservoir of the Tahe oil field went through many tectonic reconstructions, and was characterized by multiple hydrocarbon chargings. The aim of this study was to unravel the complex charging histories. Systematic analysis of fluid inclusions was employed to complete the investigation. Fluorescence observation of oil inclusions under UV light, and microthermometry of both oil and aqueous inclusions in 105 core samples taken from the Ordovician reservoir indicated that the Ordovician reservoir underwent four oil chargings and a gas charging. The hydrocarbon chargings occurred at the late Hercynian, the Indo-Sinian and Yanshan, the early Himalaya, the middle Himalaya, and the late Himalaya, respectively. The critical hydrocarbon charging time was at the late Hercynian. PMID:15236484

  11. Nonlinear filtering in oil/gas reservoir simulation: filter design

    SciTech Connect

    Arnold, E.M.; Voss, D.A.; Mayer, D.W.

    1980-10-01

    In order to provide an additional mode of utility to the USGS reservoir model VARGOW, a nonlinear filter was designed and incorporated into the system. As a result, optimal (in the least squares sense) estimates of reservoir pressure, liquid mass, and gas cap plus free gas mass are obtained from an input of reservoir initial condition estimates and pressure history. These optimal estimates are provided continuously for each time after the initial time, and the input pressure history is allowed to be corrupted by measurement error. Preliminary testing of the VARGOW filter was begun and the results show promise. Synthetic data which could be readily manipulated during testing was used in tracking tests. The results were positive when the initial estimates of the reservoir initial conditions were reasonably close. Further testing is necessary to investigate the filter performance with real reservoir data.

  12. WETTABILITY AND PREDICTION OF OIL RECOVERY FROM RESERVOIRS DEVELOPED WITH MODERN DRILLING AND COMPLETION FLUIDS

    SciTech Connect

    Jill S. Buckley; Norman r. Morrow

    2002-06-01

    This first semiannual report covers efforts to select the materials that will be used in this project. Discussions of crude oils, rocks, smooth mineral surfaces, and drilling mud additives are included in this report.

  13. Penetration of sulfate reducers through a porous North Sea oil reservoir

    SciTech Connect

    Beeder, J.; Nilsen, R.K.; Thorstenson, T.; Torsvik, T.

    1996-09-01

    During offshore oil production, seawater is often injected into the reservoir to maintain pressure. Sulfate reducers have been reported from water samples in Norwegian oil fields. However in order to demonstrate penetration, a suitable indicator microorganism is required. This paper reports the isolation of one such indicator bacterium from injection water followed by isolation of the same bacterium from water from oil field production system. 28 refs., 1 fig., 2 tabs.

  14. Evaluation of the 3-D channeling flow in a fractured type of oil/gas reservoir

    NASA Astrophysics Data System (ADS)

    Ishibashi, T.; Watanabe, N.; Tsuchiya, N.; Tamagawa, T.

    2013-12-01

    An understanding of the flow and transport characteristics through rock fracture networks is of critical importance in many engineering and scientific applications. These include effective recovery of targeted fluid such as oil/gas, geothermal, or potable waters, and isolation of hazardous materials. Here, the formation of preferential flow path (i.e. channeling flow) is one of the most significant characteristics in considering fluid flow through rock fracture networks; however, the impact of channeling flow remains poorly understood. In order to deepen our understanding of channeling flow, the authors have developed a novel discrete fracture network (DFN) model simulator, GeoFlow. Different from the conventional DFN model simulators, we can characterize each fracture not by a single aperture value but by a heterogeneous aperture distribution in GeoFlow [Ishibashi et al., 2012]. As a result, the formation of 3-D preferential flow paths within fracture network can be considered by using this simulator. Therefore, we would challenge to construct the precise fracture networks whose fractures have heterogeneous aperture distributions in field scale, and to analyze fluid flows through the fracture networks by GeoFlow. In the present study, the Yufutsu oil/gas field in Hokkaido, Japan is selected as the subject area for study. This field is known as the fractured type of reservoir, and reliable DFN models can be constructed for this field based on the 3-D seismic data, well logging, in-situ stress measurement, and acoustic emission data [Tamagawa et al., 2012]. Based on these DFN models, new DFN models for 1,080 (East-West) × 1,080 (North-South) × 1,080 (Depth) m^3, where fractures are represented by squares of 44-346 m on a side, are re-constructed. In these new models, scale-dependent aperture distributions are considered for all fractures constructing the fracture networks. Note that the multi-scale modeling of fracture flow has been developed by the authors

  15. Investigation of oil recovery improvement by coupling an interfacial tension agent and a mobility control agent in light oil reservoirs. Summary annual report, October 1994--September 1995

    SciTech Connect

    Pitts, M.J.

    1995-12-31

    The study will investigate two major areas concerning co-injecting an interfacial tension reduction agent(s) and a mobility control agent into petroleum reservoirs. The first will consist of defining the mechanisms of interaction of an alkaline agent, a surfactant, and a polymer on a fluid-fluid and a fluid-rock basis. The second is the improvement of the economics of the combined technology. The third year of the study finished the oil recovery coreflood studies and evaluated different techniques to improve alkaline-surfactant-polymer solution economics. The final series of corefloods compared the oil recovery efficiency of the alkali gradient in Berea sandstone and J Sand sandstone. Oil recovery efficiency was essentially the same in both types of core, 13 to 15% PV of oil. Cost of chemical per incremental barrel of oil with 30% pore volume of alkaline-surfactant- polymer solution injected were $3.20 for the Na{sub 2}CO{sub 3}- Petrostep B-100-Flopaam 3330S solution in both types of core.

  16. Internal structure of fault zones in geothermal reservoirs: Examples from palaeogeothermal fields and potential host rocks

    NASA Astrophysics Data System (ADS)

    Leonie Philipp, Sonja; Reyer, Dorothea; Meier, Silke; Bauer, Johanna F.; Afşar, Filiz

    2014-05-01

    Fault zones commonly have great effects on fluid transport in geothermal reservoirs. During fault slip all the pores and small fractures that meet with the slip plane become interconnected so that the inner part of the fault, the fault core, consisting of breccia or gouge, may suddenly develop a very high permeability. This is evidenced, for example by networks of mineral veins in deeply eroded fault zones in palaeogeothermal fields. Inactive faults, however, may have low permeabilities and even act as flow barriers. In natural and man-made geothermal reservoirs, the orientation of fault zones in relation to the current stress field and their internal structure needs be known as accurately as possible. One reason is that the activity of the fault zone depends on its angle to the principal stress directions. Another reason is that the outer part of a fault zone, the damage zone, comprises numerous fractures of various sizes. Here we present field examples of faults, and associated joints and mineral veins, in palaeogeothermal fields, and potential host rocks for man-made geothermal reservoirs, respectively. We studied several localities of different stratigraphies, lithologies and tectonic settings: (1) 58 fault zones in 22 outcrops from Upper Carboniferous to Upper Cretaceous in the Northwest German Basin (siliciclastic, carbonate and volcanic rocks); (2) 16 fault zones in 9 outcrops in Lower Permian to Middle Triassic (mainly sandstone, limestone and granite) in the Upper Rhine Graben; and (3) 74 fault zones in two coastal sections of Upper Triassic and Lower Jurassic age (mudstones and limestone-marl alternations) in the Bristol Channel Basin, UK. (1) and (2) are outcrop analogues of geothermal reservoir horizons, (3) represent palaeogeothermal fields with mineral veins. The field studies in the Northwest German Basin (1) show pronounced differences between normal-fault zones in carbonate and clastic rocks. In carbonate rocks clear damage zones occur that are

  17. Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity

    SciTech Connect

    Mancini, E.A.

    1990-01-01

    The objective of this project is to augment the National Reservoir Database (TORIS database) and to increase our understanding of geologic heterogeneities that affect the recoveries of oil and gas from carbonate reservoirs in the State of Alabama and to identify those resources that are producible at moderate cost. This objective will be achieved through detailed geological, geostatistical, and engineering characterization of typical Jurassic Smackover Formation hydrocarbon reservoirs in selected productive fields in the State of Alabama. The results of these studies will be used to develop and test mathematical models for prediction of the effects of reservoir heterogeneities in hydrocarbon production. Geological research this quarter has focused on descriptions of core material and petrographic thin sections from reservoirs producing from the Smackover Formation in southwestern Alabama, computer entry of pertinent data, and generation of maps and cross-sections.

  18. Rock failure during massive hydraulic stimulation of the Baca location geothermal reservoir

    SciTech Connect

    Pearson, C.; Keppler, H.; Albright, J.; Potter, R.

    1982-01-01

    The analyses of microearthquake signals occurring during hydraulic stimulation provide an estimate of the size and location of the fractures thus produced. Studies of microearthquakes occurring during two large (> 10/sup 3/m/sup 3/) hydraulic stimulations of the hydrothermal reservoir at the Baca Location in the Jemez Mountains of northeastern New Mexico are reported. Both stimulations consisted of water, viscosity enhancer, and proppant. The microearthquake event rate was low but variable throughout most of the treatment. Rock failure as indicated by the distribution of the microearthquakes' foci appeared restricted to a nearly vertical NE striking zone. This orientation is in good agreement with the local earth stresses inferred from geological considerations. The second stimulation which occurred in a neighboring well was similar to the first except for a larger injected volume. The lateral extent of the detected fracture system was 600 m in both stimulations.

  19. Evaluation of Management of Water Release for Painted Rocks Reservoir, Bitterroot River, Montana, 1984 Annual Report.

    SciTech Connect

    Lere, Mark E.

    1984-11-01

    Baseline fisheries and habitat data were gathered during 1983 and 1984 to evaluate the effectiveness of supplemental water releases from Painted Rocks Reservoir in improving the fisheries resource in the Bitterroot River. Discharge relationships among main stem gaging stations varied annually and seasonally. Flow relationships in the river were dependent upon rainfall events and the timing and duration of the irrigation season. Daily discharge monitored during the summers of 1983 and 1984 was greater than median values derived at the U.S.G.S. station near Darby. Supplemental water released from Painted Rocks Reservoir totaled 14,476 acre feet in 1983 and 13,958 acre feet in 1984. Approximately 63% of a 5.66 m{sup 3}/sec test release of supplemental water conducted during April, 1984 was lost to irrigation withdrawals and natural phenomena before passing Bell Crossing. A similar loss occurred during a 5.66 m{sup 3}/sec test release conducted in August, 1984. Daily maximum temperature monitored during 1984 in the Bitterroot River averaged 11.0, 12.5, 13.9 and 13.6 C at the Darby, Hamilton, Bell and McClay stations, respectively. Chemical parameters measured in the Bitterroot River were favorable to aquatic life. Population estimates conducted in the Fall, 1983 indicated densities of I+ and older rainbow trout (Salmo gairdneri) were significantly greater in a control section than in a dewatered section (p < 0.20). Numbers of I+ and older brown trout (Salmo trutta) were not significantly different between the control and dewatered sections (p > 0.20). Population and biomass estimates for trout in the control section were 631/km and 154.4 kg/km. In the dewatered section, population and biomass estimates for trout were 253/km and 122.8 kg/km. The growth increments of back-calculated length for rainbow trout averaged 75.6 mm in the control section and 66.9mm in the dewatered section. The growth increments of back-calculated length for brown trout averaged 79.5 mm in the

  20. Velocity measurements in reservoir rock samples from a limestone unit using various pore fluids, and integration with well logs and seismic data

    NASA Astrophysics Data System (ADS)

    Purcell, Christopher C.

    One of the most promising methods proposed to mitigate excess global CO2 is carbon sequestration, a process in which CO2 is pressurized and injected into geologic formations. A technical challenge surrounding the geologic sequestration of CO2 is tracking the movement of the fluids pumped underground. Monitoring, verification and accounting activities related to CO2 storage are important for assuring that sequestered CO2 does not escape to the surface. Tracking this carbon dioxide can be considerably aided by reflection seismic-based detection methods. This thesis employs lab scale velocity measurements of core samples, under in situ reservoir pressure and temperature conditions, combined with multiple 3D reflection seismic surveys, to effectively track the movements of CO2 after injection. The National Energy Technology Laboratory (NETL) of the United States Department of Energy began to participate in research of an enhanced oil recovery project including the injection of CO2 deep into a reservoir structure, repeat reflection seismic surveys, collection of well logs, and rock physics analysis of sample core material. Our study is concentrated on a small area of this field around the injection site. At this site, hydrocarbons were previously moved via water injection. We obtained ultrasonic elastic wave velocity measurements that were conducted under several different saturation scenarios, including CO2 saturated samples, so a quantification of the conditions in different parts of the reservoir could be determined. This approach can help to characterize what is taking place inside the reservoir. Core-scale velocity measurements under in situ conditions allow us to predict changes in future well log or seismic surveys. The large amounts of CO2 accumulated over the past four decades in this reservoir give us a real world example of how an EOR site matures. Combining core scale, well log scale, and seismic scale measurements allows a better understanding of the

  1. An improved technique for modeling initial reservoir hydrocarbon saturation distributions: Applications in Illinois (USA) aux vases oil reservoirs

    USGS Publications Warehouse

    Udegbunam, E.; Amaefule, J.O.

    1998-01-01

    An improved technique for modeling the initial reservoir hydrocarbon saturation distributions is presented. In contrast to the Leverett J-function approach, this methodology (hereby termed flow-unit-derived initial oil saturation or FUSOI) determines the distributions of the initial oil saturations from a measure of the mean hydraulic radius, referred to as the flow zone indicator (FZI). FZI is derived from porosity and permeability data. In the FUSOI approach, capillary pressure parameters, S(wir), P(d), and ??, derived from the Brooks and Corey (1966) model [Brooks, R.H., Corey, A.T., 1966. Hydraulic properties of porous media, Hydrology Papers, Colorado State Univ., Ft. Collins, No. 3, March.], are correlated to the FZI. Subsequent applications of these parameters then permit the computation of improved hydrocarbon saturations as functions of FZI and height above the free water level (FWL). This technique has been successfully applied in the Mississippian Aux Vases Sandstone reservoirs of the Illinois Basin (USA). The Aux Vases Zeigler field (Franklin County, IL, USA) was selected for a field-wide validation of this FUSOI approach because of the availability of published studies. With the initial oil saturations determined on a depth-by-depth basis in cored wells, it was possible to geostatistically determine the three-dimensional (3-D) distributions of initial oil saturations in the Zeigler field. The original oil-in-place (OOIP), computed from the detailed initialization of the 3-D reservoir simulation model of the Zeigler field, was found to be within 5.6% of the result from a rigorous material balance method.An improved technique for modeling the initial reservoir hydrocarbon saturation distributions is presented. In contrast to the Leverett J-function approach, this methodology (hereby termed flow-unit-derived initial oil saturation or FUSOI) determines the distributions of the initial oil saturations from a measure of the mean hydraulic radius, referred to

  2. IMPROVED OIL RECOVERY IN MISSISSIPPIAN CARBONATE RESERVOIRS OF KANSAS--NEAR TERM--CLASS 2

    SciTech Connect

    Timothy R. Carr; Don W. Green; G. Paul Willhite

    1999-06-01

    This annual report describes progress during the third year of the project entitled ''Improved Oil Recovery in Mississippian Carbonate Reservoirs in Kansas''. This project funded under the Department of Energy's Class 2 program targets improving the reservoir performance of mature oil fields located in shallow shelf carbonate reservoirs. The focus of this project is development and demonstration of cost-effective reservoir description and management technologies to extend the economic life of mature reservoirs in Kansas and the mid-continent. The project introduced a number of potentially useful technologies, and demonstrated these technologies in actual oil field operations. Advanced technology was tailored specifically to the scale appropriate to the operations of Kansas producers. An extensive technology transfer effort is ongoing. Traditional technology transfer methods (e.g., publications and workshops) are supplemented with a public domain relational database and an online package of project results that is available through the Internet. The goal is to provide the independent complete access to project data, project results and project technology on their desktop. Included in this report is a summary of significant project results at the demonstration site (Schaben Field, Ness County, Kansas). The value of cost-effective techniques for reservoir characterization and simulation at Schaben Field were demonstrated to independent operators. All major operators at Schaben have used results of the reservoir management strategy to locate and drill additional infill locations. At the Schaben Demonstration Site, the additional locations resulted in incremental production increases of 200 BOPD from a smaller number of wells.

  3. Improved Oil Recovery in Mississippian Carbonate Reservoirs of Kansas -- Near-Term -- Class 2

    SciTech Connect

    Carr, Timothy R.; Green, Don W.; Willhite, G. Paul

    1999-07-08

    This report describes progress during the third year of the project entitled ''Improved Oil Recovery in Mississippian Carbonate Reservoirs in Kansas''. This project funded under the Department of Energy's Class 2 program targets improving the reservoir performance of mature oil fields located in shallow shelf carbonate reservoirs. The focus of this project is development and demonstration of cost-effective reservoir description and management technologies to extend the economic life of mature reservoirs in Kansas and mid-continent. The project introduced a number of potentially useful technologies, and demonstrated these technologies in actual oil field operations. Advanced technology was tailored specifically to the scale appropriate to the operations of Kansas producers. An extensive technology transfer effort is ongoing. Traditional technology transfer methods (e.g., publications and workshops) are supplemented with a public domain relational database and an online package of project results that is available through the Internet. The goal is to provide the independent complete access to project data, project results and project technology on their desktop. Included in this report is a summary of significant project results at the demonstration site (Schaben Field, Ness County, Kansas). The value of cost-effective techniques for reservoir characterization and simulation at Schaben Field were demonstrated to independent operators. All major operators at Schaben have used results of the reservoir management strategy to locate and drill additional infill locations. At the Schaben Demonstration Site, the additional locations resulted in incremental production increases of 200 BOPD from a smaller number of wells.

  4. a Mixed-Fractal Flow Model for Stimulated Fractured Vertical Wells in Tight Oil Reservoirs

    NASA Astrophysics Data System (ADS)

    Su, Yuliang; Sheng, Guanglong; Wang, Wendong; Zhang, Qi; Lu, Mingjing; Ren, Long

    2016-02-01

    Stimulated reservoir volume (SRV) with large fracture networks can be generated near hydraulic fractured vertical wells (HFVWs) in tight oil reservoirs. Statistics show that natural microfractures and fracture networks stimulated by SRV were self-similar in statistical sense. Currently, various analytical models have been presented to study pressure behaviors of HFVWs in tight oil reservoirs. However, most of the existing models did not take the distribution and self-similarity of fractures into consideration. To account for stimulated characteristic and self-similarity of fractures in tight oil reservoirs, a mixed-fractal flow model was presented. In this model, there are two distinct regions, stimulated region and unstimulated region. Dual-porosity model and single porosity model were used to model stimulated and unstimulated regions, respectively. Fractal geometry is employed to describe fractal permeability and porosity relationship (FPPR) in tight oil reservoirs. Solutions for the mixed-fractal flow model were derived in the Laplace domain and were validated among range of the reservoir parameters. The pressure transient behavior and production rate derivative were used to analyze flow regimes. The type curves show that the fluid flow in HFVWs can be divided into six main flow periods. Finally, effect of fractal parameters and SRV size on flow periods were also discussed. The results show that the SRV size and fractal parameters of fracture network have great effect on the former periods and fractal parameters of matrix mainly influence the later flow periods.

  5. Physical properties of rocks and aqueous fluids at conditions simulating near- and supercritical reservoirs

    NASA Astrophysics Data System (ADS)

    Kummerow, Juliane; Raab, Siegfried

    2016-04-01

    The growing interest in exploiting supercritical geothermal reservoirs calls for a thorough identification and understanding of physico-chemical processes occuring in geological settings with a high heat flow. In reservoir engineering, electrical sounding methods are common geophysical exploration and monitoring tools. However, a realistic interpretation of field measurements is based on the knowledge of both, the physical properties of the rock and those of the interacting fluid at defined temperature and pressure conditions. Thus, laboratory studies at simulated in-situ conditions provide a link between the field data and the material properties in the depth. The physico-chemical properties of fluids change dramatically above the critical point, which is for pure water 374.21 °C and 221.2 bar. In supercritical fluids mass transfer and diffusion-controlled chemical reactions are enhanced and cause mineral alterations. Also, ion mobility and ion concentration are affected by the change of physical state. All this cause changes in the electrical resistivity of supercritical fluids and may have considerable effects on the porosity and hydraulic properties of the rocks they are in contact with. While there are some datasets available for physical and chemical properties of water and single component salt solutions above their critical points, there exist nearly no data for electrical properties of mixed brines, representing the composition of natural geothermal fluids. Also, the impact of fluid-rock interactions on the electrical properties of multicomponent fluids in a supercritical region is scarcely investigated. For a better understanding of fluid-driven processes in a near- and supercritical geological environment, in the framework of the EU-funded FP7 program IMAGE we have measured (1) the electrical resistivity of geothermal fluids and (2) physical properties of fluid saturated rock samples at simulated in-situ conditions. The permeability and electrical

  6. Acoustic and reservoir properties of microporous carbonate rocks: Implication of micrite particle size and morphology

    NASA Astrophysics Data System (ADS)

    Regnet, J. B.; Robion, P.; David, C.; Fortin, J.; Brigaud, B.; Yven, B.

    2015-02-01

    This integrated study provides significant insight into parameters controlling the acoustic and reservoir properties of microporous limestones, improving the knowledge of the relationships among petrophysic and microstructural content. Petrophysical properties measured from laboratory and logging tools (porosity, permeability, electrical conductivity, and acoustic properties) have been coupled with thin section and scanning electron microscope observations on the EST205 borehole from the Oxfordian limestone aquifer of the eastern part of the Paris Basin. A major achievement is the establishment of the link between micrite microtexture types (particle morphology and nature of intercrystal contacts) and the physical response, introducing a new effective and interesting rock-typing approach for microporous reservoirs. Fluid-flow properties are enhanced by the progressive augmentation of intercrystalline microporosity and associated pore throat diameter, as the coalescence of micrite particles decreases. Concerning acoustic properties, the slow increase of P wave velocity can be seen as a reflection of crystal size and growing contact cementation leading to a more cohesive and stiffer micrite microtexture. By applying poroelasticity theory on our samples, we show that velocity dispersion can be a very useful tool for data discrimination in carbonates. This dispersion analysis highlights the presence of microcracks in the rocks, and their overall effect on acoustic and transport properties. The presence of microcracks is also confirmed with observations and permeability measurements under high confining pressure. Finally, a possible origin of high porous levels in neritic limestones is a mineralogical transformation of carbonates through freshwater-related diagenesis during subaerial exposure time. Finally, by applying poroelasticity theory on our samples, we show that velocity dispersion can be a very useful tool for data discrimination in carbonates.

  7. Thermal and Hydraulic Coupled Modeling of Hot Fractured Rock Geothermal Reservoir

    NASA Astrophysics Data System (ADS)

    Xu, H.; Xing, H.; Wyborn, D.; Yin, C.; Mora, P.

    2006-12-01

    Geothermal energy manifests itself in spectacular fashion in many places on the earth's surface and has been widely recognized as a renewable green energy in the world. Several countries have started the related projects for developing the Hot Dry Rock (HDR) geothermal system which has been renamed as Hot Fractured Rock (HFR) in Australia. Geodynamics Limited is developing a world-class, high-grade geothermal energy resource beneath the Cooper Basin in NE South Australia, where the measured surface heat flow is over 100mW/m2. It is thought to originate from the Big Lake Suite granites that are enriched in the heat-producing elements. The presence of highly radiogenic intrusive within 3-4 km of the surface generates extraordinarily high geothermal gradient regimes (>60ºC km-1, and the region is recognized as one of the hottest spots in the world outside volcanic centres. To help bringing the vision of HFR geothermal energy to reality, a 3D finite element based computational model and software for simulating such a multi-scale highly coupled thermo- hydro-mechanical geo-mechanical system on the parallel supercomputer are being developed based on our long tern and on-going related outcomes. This presentation will focus on the related outcomes on the thermo- hydro coupling module aiming to investigate thermal and fluid flow coupled process and their impact on the Cooper Basin HFR geothermal reservoir. The microseismicity monitoring data measured during the hydraulic stimulation process was used to estimate the related key input parameters for the further numerical investigation of the coupled thermal and fluid flow behaviours of Cooper Basin HFR geothermal reservoir. The above preliminary simulation results demonstrate the stability and usefulness of the algorithm and software.

  8. Variations of the petrophysical properties of rocks with increasing hydrocarbons content and their implications at larger scale: insights from the Majella reservoir (Italy)

    NASA Astrophysics Data System (ADS)

    Trippetta, Fabio; Ruggieri, Roberta; Lipparini, Lorenzo

    2016-04-01

    Crustal processes such as deformations or faulting are strictly related to the petrophysical properties of involved rocks. These properties depend on mineral composition, fabric, pores and any secondary features such as cracks or infilling material that may have been introduced during the whole diagenetic and tectonic history of the rock. In this work we investigate the role of hydrocarbons (HC) in changing the petrophysical properties of rock by merging laboratory experiments, well data and static models focusing on the carbonate-bearing Majella reservoir. This reservoir represent an interesting analogue for the several oil fields discovered in the subsurface in the region, allowing a comparison of a wide range of geological and geophysical data at different scale. The investigated lithology is made of high porosity ramp calcarenites, structurally slightly affected by a superimposed fracture system and displaced by few major normal faults, with some minor strike-slip movements. Sets of rock specimens were selected in the field and in particular two groups were investigated: 1. clean rocks (without oil) and 2. HC bearing rocks (with different saturations). For both groups, density, porosity, P and S wave velocity, permeability and elastic moduli measurements at increasing confining pressure were conducted on cylindrical specimens at the HP-HT Laboratory of the Istituto Nazionale di Geofisica e Vulcanologia (INGV) in Rome, Italy. For clean samples at ambient pressure, laboratory porosity varies from 10 % up to 26 % and P wave velocity (Vp) spans from 4,1 km/s to 4,9 km/s and a very good correlation between Vp, Vs and porosity is observed. The P wave velocity at 100 MPa of confining pressure, ranges between 4,5 km/s and 5,2 km/s with a pressure independent Vp/Vs ratio of about 1,9. The presence of HC within the samples affects both Vp and Vs. In particular velocities increase with the presence of hydrocarbons proportionally respect to the amount of the filled

  9. Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity

    SciTech Connect

    Mancini, E.A.

    1990-01-01

    The objectives of this project are to augment the National Reservoir Database (TORIS database) and to increase our understanding of geologic heterogeneities that affect the recoveries of oil and gas from carbonate reservoirs in the State of Alabama and to identify those resources that are producible at moderate cost. These objectives will be achieved through detailed geological, engineering, and geostatistical characterization of typical Jurassic Smackover Formation hydrocarbon reservoirs in selected productive fields in the State of Alabama. The results of these studies will be used to develop and test mathematical models for prediction of the effects of reservoir heterogeneities in hydrocarbon production. Work to date has focused on the completion of Subtasks 1, 2, and 3. Subtask 1 included the survey and tabulation of available reservoir engineering and geological data relevant to the Smackover reservoir in southwestern Alabama. Subtask 2 comprises the geological and engineering characterization of Smackover reservoir lithofacies. This has been accomplished through detailed examination and analysis of geophysical well logs, core material, well cuttings, and well-test data from wells penetrating Smackover reservoirs in southwestern Alabama. From these data, reservoir heterogeneities, such as lateral and vertical changes in lithology, porosity, permeability, and diagenetic overprint, have been recognized and used to produce maps, cross sections, graphs, and other graphic representations to aid in interpretation of the geologic parameters that affect these reservoirs. Subtask 3 includes the geologic modeling of reservoir heterogeneities for Smackover reservoirs. This research has been based primarily on the evaluation of key geologic and engineering data from selected Smackover fields. 1 fig.

  10. Executive summary--2002 assessment of undiscovered oil and gas resources in the San Juan Basin Province, exclusive of Paleozoic rocks, New Mexico and Colorado: Chapter 1 in Total petroleum systems and geologic assessment of undiscovered oil and gas resources in the San Juan Basin Province, exclusive of Paleozoic rocks, New Mexico and Colorado

    USGS Publications Warehouse

    U.S. Geological Survey San Juan Basin Assessment Team

    2013-01-01

    In 2002, the U.S. Geological Survey (USGS) estimated undiscovered oil and gas resources that have the potential for additions to reserves in the San Juan Basin Province (5022), New Mexico and Colorado (fig. 1). Paleozoic rocks were not appraised. The last oil and gas assessment for the province was in 1995 (Gautier and others, 1996). There are several important differences between the 1995 and 2002 assessments. The area assessed is smaller than that in the 1995 assessment. This assessment of undiscovered hydrocarbon resources in the San Juan Basin Province also used a slightly different approach in the assessment, and hence a number of the plays defined in the 1995 assessment are addressed differently in this report. After 1995, the USGS has applied a total petroleum system (TPS) concept to oil and gas basin assessments. The TPS approach incorporates knowledge of the source rocks, reservoir rocks, migration pathways, and time of generation and expulsion of hydrocarbons; thus the assessments are geologically based. Each TPS is subdivided into one or more assessment units, usually defined by a unique set of reservoir rocks, but which have in common the same source rock. Four TPSs and 14 assessment units were geologically evaluated, and for 13 units, the undiscovered oil and gas resources were quantitatively assessed.

  11. Lower Cretaceous and Upper Jurassic oil reservoirs of the updip basement structure play: Southwest Alabama

    SciTech Connect

    Mink, R.M.; Mancini, E.A.

    1995-10-01

    Exploration for Lower Cretaceous and Upper Jurassic reservoirs associated with updip basement structures currently is the most active exploratory oil play in Alabama. High initial flow rates, on the order of hundreds to thousands of barrels of oil per day, are commonly encountered at depths between 8,200 and 14,500 feet. Fifty-one fields have been established and 25 million barrels of oil have been produced from these fields developed in Lower Cretaceous Hosston and Upper Jurassic Haynesville, Smackover, and Norphlet reservoirs. Production from Smackover carbonates began at Toxey field in 1967 and from Haynesville sandstones at Frisco City field in 1986. As of September 1994, Smackover wells averaged 88 barrels of oil per day and Haynesville wells averaged 284 barrels of oil per day. In 1994, production was established in the Norphlet at North Excel field and in the Hosston at Pleasant Home field. Reservoirs in the updip basement structure play cluster in three distinct areas; (1) a western area on the Choctaw ridge complex, (2) a central area on the Conecuh ridge complex, and (3) an eastern area in the Conecuh embayment. Reservoir lithologies include Smackover limestones and dolostones and Hosston, Haynesville, Smackover, and Norphlet sandstones. Hydrocarbon traps are structural or combination traps where reservoirs occur on the flanks or over the crests of basement palohighs. An understanding of the complex reservoir properties and trap relationships is the key to successful discovery and development of Lower Cretaceous and Upper Jurassic oil reservoirs of the updip basement structure play of southwest Alabama.

  12. Geochemistry of Eagle Ford group source rocks and oils from the first shot field area, Texas

    USGS Publications Warehouse

    Edman, Janell D.; Pitman, Janet K.

    2010-01-01

    Total organic carbon, Rock-Eval pyrolysis, and vitrinite reflectance analyses performed on Eagle Ford Group core and cuttings samples from the First Shot field area, Texas demonstrate these samples have sufficient quantity, quality, and maturity of organic matter to have generated oil. Furthermore, gas chromatography and biomarker analyses performed on Eagle Ford Group oils and source rock extracts as well as weight percent sulfur analyses on the oils indicate the source rock facies for most of the oils are fairly similar. Specifically, these source rock facies vary in lithology from shales to marls, contain elevated levels of sulfur, and were deposited in a marine environment under anoxic conditions. It is these First Shot Eagle Ford source facies that have generated the oils in the First Shot Field. However, in contrast to the generally similar source rock facies and organic matter, maturity varies from early oil window to late oil window in the study area, and these maturity variations have a pronounced effect on both the source rock and oil characteristics. Finally, most of the oils appear to have been generated locally and have not experienced long distance migration. 

  13. Permeability, electrical impedance, and acoustic velocities on reservoir rocks from the Geysers geothermal field

    SciTech Connect

    Boitnott, G.N.; Boyd, P.J.

    1996-01-24

    Previous measurements of acoustic velocities on NEGU- 17 cores indicate that saturation effects are significant enough to cause Vp/Vs anomalies observed in the field. In this study we report on the results of new measurements on core recently recovered from SB-15-D along with some additional measurements on the NEGU-17 cores. The measurements indicate correlations between mechanical, transport, and water storage properties of the matrix which may prove useful for reservoir assessment and management. The SB-15-D material is found to be similar to the NEGU-17 material in terms of acoustic velocities, being characterized by a notably weak pressure dependence on the velocities and a modest Vp/Vs signature of saturation. The effect of saturation on Vp/Vs appears to result in part from a chemo-mechanical weakening of the shear modulus due to the presence of water. Electrical properties of SB-15-D material are qualitatively similar to those of the NEGU-17 cores, although resistivities of SB-15-D cores are notably lower and dielectric permittivities higher than in their NEGU- 17 counterparts. While some limited correlations of measured properties with depth are noted, no clear change in character is observed within SB-15-D cores which can be associated with the proposed cap-rock/reservoir boundary.

  14. SEISMIC DETERMINATION OF RESERVOIR HETEROGENEITY; APPLICATION TO THE CHARACTERIZATION OF HEAVY OIL RESERVOIRS

    SciTech Connect

    Matthias G. Imhof; James W. Castle

    2003-11-01

    The objective of the project is to examine how seismic and geologic data can be used to improve characterization of small-scale heterogeneity and their parameterization in reservoir models. The study is performed at West Coalinga Field in California. We continued our investigation on the nature of seismic reactions from heterogeneous reservoirs. We began testing our algorithm to infer parameters of object-based reservoir models from seismic data. We began integration of seismic and geologic data to determine the deterministic limits of conventional seismic data interpretation. Lastly, we began integration of seismic and geologic heterogeneity using stochastic models conditioned both on wireline and seismic data.

  15. DEVELOPMENT PRACTICES FOR OPTIMIZED MEOR IN SHALLOW HEAVY OIL RESERVOIRS

    SciTech Connect

    Shari Dunn-Norman

    2004-03-01

    The objective of this research project is to demonstrate an economically viable and sustainable method of producing shallow heavy oil reserves in western Missouri and southeastern Kansas, using an integrated approach including surface geochemical surveys, conventional MEOR treatments, horizontal fracturing in vertical wells, electrical resistivity tomography (ERT), and reservoir simulation to optimize the recovery process. The objective also includes transferring the knowledge gained from the project to other local landowners, to demonstrate how they may identify and develop their own heavy oil resources with little capital investment. The first year period was divided into two phases--Phase I and Phase II. Each phase was 6 months in duration. Tasks completed in first six month period included soil sampling, geochemical analysis, construction of ERT arrays, collection of background ERT surveys, and analysis of core samples to develop a geomechanical model for designing the hydraulic fracturing treatment. Five wells were to be drilled in phase I. However, weather and funding delays resulted in drilling shifting to the second phase of the project. During the second six month period, five vertical wells were drilled through the Bluejacket and Warner Sands. These wells were drilled with air and logged openhole. Drilling locations were selected after reviewing results of background ERT and geochemical surveys. Three ERT wells (2,3,4) were arranged in an equilateral triangle, spaced 70 feet apart and these wells were completed open hole. ERT arrays constructed during Phase I, were installed and background surveys were taken. Two wells (1,5) were drilled, cased, cemented and perforated. These wells were located north and south of the three ERT wells. Each well was stimulated with a linear guar gel and 20/40 mesh Brady sand. Tiltmeters were used with one fracture treatment to verify fracture morphology. Work performed during the first year of this research project

  16. Advanced Reservoir Characterization and Evaluation of CO(2) Gravity Drainage in the Naturally Fractured Spraberry Reservoir

    SciTech Connect

    Schechter, David

    1996-12-01

    Progress has been made in the area of laboratory analysis of Spraberry oil/brine/rock interactions during this quarter. Water imbibition experiments were conducted under ambient conditions, using cleaned Spraberry cores, synthetic Spraberry reservoir brine, and Spraberry oil. It has been concluded that the Spraberry reservoir cores are weakly water-wet. The average Amott wettability index to water is about 0.55. The average oil recovery due to spontaneous water imbibition is about 50% of original oil in place.

  17. Evaluation of Reservoir Wettability and its Effect on Oil Recovery

    SciTech Connect

    Buckley, Jill S.

    2002-01-29

    The objectives of this five-year project were: (1) to achieve improved understanding of the surface and interfacial properties of crude oils and their interactions with mineral surfaces, (2) to apply the results of surface studies to improve predictions of oil production from laboratory measurements, and (3) to use the results of this research to recommend ways to improve oil recovery by waterflooding.

  18. Pore Characterization of Shale Rock and Shale Interaction with Fluids at Reservoir Pressure-Temperature Conditions Using Small-Angle Neutron Scattering

    NASA Astrophysics Data System (ADS)

    Ding, M.; Hjelm, R.; Watkins, E.; Xu, H.; Pawar, R.

    2015-12-01

    Oil/gas produced from unconventional reservoirs has become strategically important for the US domestic energy independence. In unconventional realm, hydrocarbons are generated and stored in nanopores media ranging from a few to hundreds of nanometers. Fundamental knowledge of coupled thermo-hydro-mechanical-chemical (THMC) processes that control fluid flow and propagation within nano-pore confinement is critical for maximizing unconventional oil/gas production. The size and confinement of the nanometer pores creates many complex rock-fluid interface interactions. It is imperative to promote innovative experimental studies to decipher physical and chemical processes at the nanopore scale that govern hydrocarbon generation and mass transport of hydrocarbon mixtures in tight shale and other low permeability formations at reservoir pressure-temperature conditions. We have carried out laboratory investigations exploring quantitative relationship between pore characteristics of the Wolfcamp shale from Western Texas and the shale interaction with fluids at reservoir P-T conditions using small-angle neutron scattering (SANS). We have performed SANS measurements of the shale rock in single fluid (e.g., H2O and D2O) and multifluid (CH4/(30% H2O+70% D2O)) systems at various pressures up to 20000 psi and temperature up to 150 oF. Figure 1 shows our SANS data at different pressures with H2O as the pressure medium. Our data analysis using IRENA software suggests that the principal changes of pore volume in the shale occurred on smaller than 50 nm pores and pressure at 5000 psi (Figure 2). Our results also suggest that with increasing P, more water flows into pores; with decreasing P, water is retained in the pores.

  19. Assessing the role of ancient and active geothermal systems in oil-reservoir evolution in the eastern Basin and Range province, western USA. Annual progress report, June 1, 1992--May 31, 1993

    SciTech Connect

    Hulen, J.B.

    1993-07-01

    Results of our research on the oil fields of the Basin and Range province of the western USA continue to support the following concept: Convecting, moderate-temperature geothermal systems in this region have fostered and in some cases critically influenced the generation, migration, and entrapment of oil. At one Basin-Range field (Grant Canyon), oil-bearing and aqueous fluid inclusions in late-stage hydrothermal quartz were entrapped at temperatures comparable to those now prevailing at reservoir depths (120--130{degrees}C); apparent salinities of the aqueous varieties match closely the actual salinity of the modern, dilute oil-field waters. The inclusion-bearing quartz has the oxygen-isotopic signature for precipitation of the mineral at contemporary temperatures from modern reservoir waters. Measured and fluid-inclusion temperatures define near-coincident isothermal profiles through the oil-reservoir interval, a phenomenon suggesting ongoing heat and mass transfer. These findings are consistent with a model whereby a still-active, convectively circulating, meteoric-hydrothermal system: (1) enhanced porosity in the reservoir rock through dissolution of carbonate; (2) hydrothermally sealed reservoir margins; (3) transported oil to the reservoirs from a deep source of unknown size and configuration; and (4) possibly accelerated source-rock maturation through an increase in the local thermal budget. Grant Canyon and other Basin-Range oil fields are similar to the oil-bearing, Carlin-type, sediment-hosted, disseminated gold deposits of the nearby Alligator Ridge district. The oil fields could represent either weakly mineralized analogues of these deposits, or perhaps an incipient phase in their evolution.

  20. Laboratory measurements of reservoir rock from the Geysers geothermal field, California

    USGS Publications Warehouse

    Lockner, D.A.; Summers, R.; Moore, D.; Byerlee, J.D.

    1982-01-01

    Rock samples taken from two outcrops, as well as rare cores from three well bores at the Geysers geothermal field, California, were tested at temperatures and pressures similar to those found in the geothermal field. Both intact and 30?? sawcut cylinders were deformed at confining pressures of 200-1000 bars, pore pressure of 30 bars and temperatures of 150?? and 240??C. Thin-section and X-ray analysis revealed that some borehole samples had undergone extensive alteration and recrystallization. Constant strain rate tests of 10-4 and 10-6 per sec gave a coefficient of friction of 0.68. Due to the highly fractured nature of the rocks taken from the production zone, intact samples were rarely 50% stronger than the frictional strength. This result suggests that the Geysers reservoir can support shear stresses only as large as its frictional shear strength. Velocity of p-waves (6.2 km/sec) was measured on one sample. Acoustic emission and sliding on a sawcut were related to changes in pore pressure. b-values computed from the acoustic emissions generated during fluid injection were typically about 0.55. An unusually high b-value (approximately 1.3) observed during sudden injection of water into the sample may have been related to thermal cracking. ?? 1982.

  1. Seismic Determination of Reservoir Heterogeneity: Application to the Characterization of Heavy Oil Reservoirs

    SciTech Connect

    Imhof, Matthias G.; Castle, James W.

    2003-03-12

    The objective of the project was to examine how seismic and geologic data could be used to improve characterization of small-scale heterogeneity and their parameterization in reservoir models. The study was performed at West Coalinga Field in California.

  2. Carbonate/clay-mineral relationships and the origin of protodolomite in L-2 and L-3 carbonate reservoir rocks of the Bombay high field, India

    NASA Astrophysics Data System (ADS)

    Gundu Rao, C.

    1981-07-01

    This paper consists of two parts. The first deals with carbonate/clay-mineral relationships and the second with the origin of protodolomite in L-2 and L-3 carbonate reservoir rocks of the Bombay High Oil Field, India. Six carbonate/clay-mineral assemblages, viz. (1) calcite-protodolomite-chlorite-kaolinite, (2) calcite-protodolomite-montmorillonite-kaolinite, (3) calcite-montmorillonite-kaolinite, (4) calcite-protodolomite-montmorillonite, (5) calcite-protodolomite-vermiculite, and (6) calcite-montmorillonite-chlorite-kaolinite are recognized among the L-2 and L-3 carbonate reservoir rocks of the offshore Bombay High Oil Field, India. These form disequilibrium assemblages on a Al 2O 3 (kaolinite), CaO (calcite) and MgO (magnesite) facies diagram. Therefore, the clay minerals are terrigenous in origin and have at least contributed the magnesium needed for the formation of protodolomite. The protodolomite seen in L-2 and L-3 rocks is limpid, water-clear, non-zoned, and inclusion-free with an average grain diameter of 7-10 μm and on the X-ray chart shows a consistent (104) peak between 2.93 Å to 2.90 Å ' d' spacing, reading 30-40 mole% MgCO 3 solid solution in calcite. By comparison with other types of dolomite, viz (1) replacement, (2) evaporite, (3) sabkha, and (4) schizohaline, the present protodolomite seems to be of biogenic origin and in all probability appears to be a new form of dolomite to be reported from an ancient subsurface carbonate formation.

  3. Characterization of reservoir rocks and fluids by surface electromagnetic transient methods

    SciTech Connect

    Hoekstra, P.; Blohm, M.W. ); Stoyer, C.H. ); James, B.A. )

    1992-01-01

    The objectives of this research are to improve the interpretations of transient electromagnetic (TEM) measurements over two-dimensional subsurface structures. TEM is a surface electromagnetic method employed in fossil energy reservoir exploration and characterization. Electrical measurements find application in (i) assisting in fossil energy exploration mainly in areas where seismic methods yield inadequate data quality, such as volcanic covered terrain, permafrost areas, and the Rocky Mountain overthrust; (ii) mapping contacts between hydrocarbon and brines in shallow producing horizons, and (iii) in monitoring enhanced oil recovery processes which cause zones of lower resistivity. Accomplishments for this past year are presented for the following tasks: (1) site selection and acquisition of high density, 3-component TEM data set over test site; (2) finite element forward modeling; and (3) TEM 2-D subsurface imaging.

  4. Characterization of reservoir rocks and fluids by surface electromagnetic transient methods

    SciTech Connect

    Hoekstra, P.; Blohm, M.W.; Stoyer, C.H.; James, B.A.

    1992-07-17

    The objectives of this research were to improve the interpretations of transient electromagnetic (TEM) measurements over two-dimensional subsurface structures. TEM is a surface electromagnetic method employed in fossil energy reservoir exploration and characterization. Electrical measurements find application in (i) assisting in fossil energy exploration mainly in areas where seismic methods yield inadequate data quality, such as volcanic covered terrain, permafrost areas, and the Rocky Mountain Overthrust; (ii) mapping contacts between hydrocarbon and brines in shallow producing horizon, and (iii) in monitoring enhanced oil recovery processes which cause zones of lower resistivity. The work under this contract consisted of three tasks: (1) Selection of a test site and acquisition of a high density, 3-component data set over the test site; (2) development of finite element modeling algorithms for computing 3-D EM fields over 2-D EM fields over 2-D subsurface structures; and development of TEM 2-D subsurface imaging method. Accomplishments for this period are described.

  5. Post Waterflood CO2 Miscible Flood in Light Oil, Fluvial-Dominated Deltaic Reservoir, Class I

    SciTech Connect

    Bou-Mikael, Sami

    2002-02-05

    This report demonstrates the effectiveness of the CO2 miscible process in Fluvial Dominated Deltaic reservoirs. It also evaluated the use of horizontal CO2 injection wells to improve the overall sweep efficiency. A database of FDD reservoirs for the gulf coast region was developed by LSU, using a screening model developed by Texaco Research Center in Houston. The results of the information gained in this project is disseminated throughout the oil industry via a series of SPE papers and industry open forums.

  6. Quantitative Methods for Reservoir Characterization and Improved Recovery: Application to Heavy Oil Sands

    SciTech Connect

    Castle, J.W.; Molz, F.J.; Brame, S.E.; Falta, R.W.

    2003-02-07

    Improved prediction of interwell reservoir heterogeneity was needed to increase productivity and to reduce recovery cost for California's heavy oil sands, which contain approximately 2.3 billion barrels of remaining reserves in the Temblor Formation and in other formations of the San Joaquin Valley. This investigation involved application of advanced analytical property-distribution methods conditioned to continuous outcrop control for improved reservoir characterization and simulation.

  7. Quantitative Methods for Reservoir Characterization and Improved Recovery: Application to Heavy Oil Sands

    SciTech Connect

    Castle, James W.; Molz, Fred J.

    2003-02-07

    Improved prediction of interwell reservoir heterogeneity is needed to increase productivity and to reduce recovery cost for California's heavy oil sands, which contain approximately 2.3 billion barrels of remaining reserves in the Temblor Formation and in other formations of the San Joaquin Valley. This investigation involved application of advanced analytical property-distribution methods conditioned to continuous outcrop control for improved reservoir characterization and simulation.

  8. Fluid-rock interactions in unconventional reservoirs during hydraulic fracturing: a geochemical investigation from the Powder River Basin, WY

    NASA Astrophysics Data System (ADS)

    Herz-Thyhsen, R.; Kaszuba, J. P.

    2014-12-01

    Widespread use of hydraulic fracturing to stimulate resource production from unconventional reservoirs necessitates the development of a fundamental understanding for this process. Our research focuses on a synthesis of three sets of data to better understand geochemical and mineralogic aspects of the process of hydraulic fracturing, including laboratory experiments, field data, and geochemical modeling. Experiments examine fluid-rock interaction using rock samples from the Niobrara and Frontier Formations, two unconventional reservoirs within the Powder River Basin of NE Wyoming. Experiments react reservoir rocks with a representative hydraulic fracturing fluid for 28 days at 115°C and 350 bars. Fresh water and common chemicals, including HCl and petroleum distillates, used in hydraulic fracturing comprise the experimental fluid. Mineral reaction to the acidic fluid (pH ~2.35) causes immediate buffering, bringing fluid pH to near-neutral conditions after ~6 hours. Al initially spikes in the first 6 hours by ~10X, but returns to lower concentrations within 12 hours. Fe, Ba, Co, Mn, Sb, and Cr follow similar trends. Contemporaneously, Sr, Mo, Li, W, V, and Rb increase dramatically and remain at elevated levels. Changes in trace element concentrations correlate with clay alteration, calcite dissolution, and feldspar dissolution observed within reacted rock samples. Fluid samples are compared to produced-water chemistry from active wells in the field, enhancing our understanding of geochemical reactions occurring at depth. Lastly, produced fluid chemistry from both field samples and experiments are tethered together using preliminary geochemical models. These models predict calcite and feldspar reaction as well as new clay formation. This research ties together a limited population of produced water data with reservoir mineralogy to enhance fundamental understanding of fluid-rock interactions in unconventional reservoirs.

  9. Effect of Shear Slip on Fault Permeability in Shale Reservoir Rocks

    NASA Astrophysics Data System (ADS)

    Reece, J. S.; Zoback, M. D.; Kohli, A. H.

    2014-12-01

    Understanding flow along faults and fractures in shales is important for better understanding of hydraulic stimulation in unconventional reservoirs. For example, the re-activation of faults and fractures during hydraulic stimulation appears to be an important process contributing to reservoir permeability. In this study, we examine the effect of shear slip on fault permeability in shale reservoir rocks. We perform shear experiments in a triaxial apparatus on two types of samples: 1) a sample sawcut at 30° to the cylindrical axis and 2) a naturally broken sample. Both samples are from 3481 m (11422 ft) depth within the Haynesville reservoir containing 22 wt.% clay. First, we hydrostatically load the samples to a confining pressure of 15 MPa (2176 psi), followed by triaxial loading in which a constant axial displacement rate of 1 μm/s is applied for increments in axial displacement of initially 0.25 mm and later 1 mm. After each shear increment, we perform measurements of fault permeability at a constant mean pore pressure of 2.1 MPa (300 psi) using the steady state Darcy flow method. Boreholes drilled parallel to the cylindrical axis on either side of the shale sample allow pore fluid to access the fault plane. The coefficient of friction increases with shearing from 0.53 to 0.61 for the sawcut sample and from about 0.60 to 0.74 for the naturally broken sample. The sawcut sample indicates stable sliding behavior whereas small stick-slip events occur in the naturally broken sample. Upon shearing, fault permeability decreases by about 2.5 and 1.5 orders of magnitude within the first mm of shear displacement for the sawcut and naturally broken sample, respectively. Fault permeability of both samples continues to slowly decrease up to a maximum axial displacement of 4 mm and 2 mm, respectively. Laser scanning images before and after shearing show the formation of small striations in the direction of slip for the sawcut sample and the break-off of several grain

  10. Increasing Heavy Oil in the Wilmington Oil Fiel Through Advanced Reservoir Characterization and Thermal Production Technologies. Annual Report, March 30, 1995--March 31, 1996

    SciTech Connect

    Allison, Edith

    1996-12-01

    The objective of this project is to increase heavy oil reserves in a portion of the Wilmington Oil Field, near Long Beach, California, by implementing advanced reservoir characterization and thermal production technologies. Based on the knowledge and experience gained with this project, these technologies are intended to be extended to other sections of the Wilmington Oil Field, and, through technology transfer, will be available to increase heavy oil reserves in other slope and basin clastic (SBC) reservoirs.

  11. Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. [Jurassic Smackover Formation

    SciTech Connect

    Kopasaka-Merkel, D.C.; Moore, H.E. Jr.; Mann, S.D; Hall, D.R.

    1992-06-01

    This volume contains maps, well log correlated to lithology, porosity and permeability, structural cross section, graph of production history, porosity vs. natural log permeability plots; detailed core log, porosity vs. natural permeability plot for one lithofacies, paragenetic sequence and reservoir characterization sheet for the following fields in southwest Alabama: Stave Creek oil field; Sugar Ridge oil field; Toxey oil field, Turkey Creed oil field; Turnerville oil field, Uriah oil field; Vocation oil field; Wallace oil field; Wallers Creek oil field; West Appleton oil field; West Barrytown oil field; West Bend oil field; West Okatuppa Creed oil field; Wild Fork Creek oil field; Wimberly oil field; Womack Hill oil field; and Zion Chapel oil field. (AT)

  12. Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. Appendix 1, Volume 4

    SciTech Connect

    Kopasaka-Merkel, D.C.; Moore, H.E. Jr.; Mann, S.D; Hall, D.R.

    1992-06-01

    This volume contains maps, well log correlated to lithology, porosity and permeability, structural cross section, graph of production history, porosity vs. natural log permeability plots; detailed core log, porosity vs. natural permeability plot for one lithofacies, paragenetic sequence and reservoir characterization sheet for the following fields in southwest Alabama: Stave Creek oil field; Sugar Ridge oil field; Toxey oil field, Turkey Creed oil field; Turnerville oil field, Uriah oil field; Vocation oil field; Wallace oil field; Wallers Creek oil field; West Appleton oil field; West Barrytown oil field; West Bend oil field; West Okatuppa Creed oil field; Wild Fork Creek oil field; Wimberly oil field; Womack Hill oil field; and Zion Chapel oil field. (AT)

  13. The application of petrophysics to resolve fluid flow units and reservoir quality in the Upper Cretaceous Formations: Abu Sennan oil field, Egypt

    NASA Astrophysics Data System (ADS)

    Lala, Amir Maher Sayed; El-sayed, Nahla Abd El-Aziz

    2015-02-01

    Petrophysical flow unit concept can be used to resolve some of the key challenges faced in the characterization of hydrocarbon reservoirs. The present study deals with petrophysical evaluation of some physical properties of the Upper Cretaceous rock samples obtained from the Abu-Roash and the Bahariya Formations at southwest of Sennan oil field in the Western Desert of Egypt. The aim of this study was achieved through carrying out some petrophysical measurements of porosity, bulk density, permeability, mean hydraulic radius (Rh), irreducible water saturation, and radius of pore throat at mercury saturation of 35% in order to determine reservoir characteristics. In this study, the relationships obtained between the measured petrophysical properties such as porosity, permeability and pore throat flow unit types were established for 53 sandstone core samples obtained from two different stratigraphic units. Flow zone indicator (FZI) has been calculated to quantify the flow character of the Abu-Roash and Bahariya reservoir rocks based on empirically derived equations of robust correlation coefficients. The correlations among porosity, permeability, bulk density, mean hydraulic radius and pore throat flow properties reflect the most important reservoir behavior characteristics. The calculated multiple regression models indicate close correlation among petrophysical properties and Rh and R35%. The obtained models are able to predict Rh and R35% by using porosity and permeability, to map reservoir performance and predict the location of stratigraphic traps.

  14. Evaluation of Reservoir Wettability and its Effect on Oil Recovery

    SciTech Connect

    Buckley, Jill S.

    1999-07-01

    The objective of this five-year project are: (1) to achieve improved understanding of the surface and interfacial properties of crude oils and their interactions with mineral surfaces, (2) to apply the results of surface studies to improve predictions of oil production from laboratory measurements, and (3) to use the results of this research to recommend ways to improve oil recovery by waterflooding. During the second year of this project we have tested the generality of the proposed mechanisms by which crude oil components can alter wetting. Using these mechanisms, we have begun a program of characterizing crude oils with respect to their wettability altering potential. Wettability assessment has been improved by replacing glass with mica as a standard surface material and crude oils have been used to alter wetting in simple square glass capillary tubes in which the subsequent imbibition of water can be followed visually.

  15. Electromagnetic oil field mapping for improved process monitoring and reservoir characterization: A poster presentation

    SciTech Connect

    Waggoner, J.R.; Mansure, A.J.

    1992-02-01

    This report is a permanent record of a poster paper presented by the authors at the Third International Reservoir Characterization Technical Conference in Tulsa, Oklahoma on November 3--5, 1991. The subject is electromagnetic (EM) techniques that are being developed to monitor oil recovery processes to improve overall process performance. The potential impact of EM surveys is very significant, primarily in the areas of locating oil, identifying oil inside and outside the pattern, characterizing flow units, and pseudo-real time process control to optimize process performance and efficiency. Since a map of resistivity alone has little direct application to these areas, an essential part of the EM technique is understanding the relationship between the process and the formation resistivity at all scales, and integrating this understanding into reservoir characterization and simulation. First is a discussion of work completed on the core scale petrophysics of resistivity changes in an oil recovery process; a steamflood is used as an example. A system has been developed for coupling the petrophysics of resistivity with reservoir simulation to simulate the formation resistivity structure arising from a recovery process. Preliminary results are given for an investigation into the effect of heterogeneity and anisotropy on the EM technique, as well as the use of the resistivity simulator to interpret EM data in terms of reservoir and process parameters. Examples illustrate the application of the EM technique to improve process monitoring and reservoir characterization.

  16. Penetration of Sulfate Reducers through a Porous North Sea Oil Reservoir

    PubMed Central

    Beeder, J.; Nilsen, R. K.; Thorstenson, T.; Torsvik, T.

    1996-01-01

    The presence of mesophilic benzoate-degrading sulfate-reducing bacteria in the water systems of three Norwegian oil platforms was investigated. Strain 4502 was isolated from the injection water system, and specific antibodies were produced against this isolate. It was present in the injection water system during a period of 3 years, but not in the in situ reservoir water. Later it was found in water samples collected from the oil field production system. This showed that strain 4502 had penetrated the reservoir together with the injection water and eventually reached the production well. PMID:16535415

  17. Factors Governing the Germination of Sulfate-Reducing Desulfotomaculum Endospores Involved in Oil Reservoir Souring.

    NASA Astrophysics Data System (ADS)

    Sherry, A.; Bell, E.; Cueto, G.; Suarez-Suarez, A.; Pilloni, G.; Hubert, C. R.

    2015-12-01

    Reservoir souring is caused by the activity of sulfate-reducing microorganisms (SRM) in subsurface oil reservoirs, and is often induced by seawater injection during secondary oil recovery. Souring can potentially contribute to corrosion of infrastructure, health and safety hazards to the workforce, and reduction in value by increasing refining costs associated with producing the oil resource. Souring causes annual losses in the billions of dollars to the oil industry. Endospore-forming SRM, such as Desulfotomaculum spp., are often suspected culprits in reservoir souring. Endospores can survive unfavourable conditions for long periods, yet remain poised to germinate and become active if conditions become more favourable. Factors governing endospore germination are poorly understood, but are thought to include availability of nutrients, possibly metabolic by products of other anaerobic bioprocesses, and/or variations in temperature. Most research has focused on aerobic Bacillus spp., with very few studies dedicated to spore germination among anaerobes (order Clostridiales) including the sulfate-reducing Desulfotomaculum found in anoxic subsurface petroleum reservoirs. For Desulfotomaculum spores in deep hot oil reservoirs, cold seawater introduction during secondary oil recovery may create thermal viability zones for sulfate reduction near the injection wellbore. To evaluate these processes, sulfate-containing microcosms were prepared with different marine sediments as a source of spores, and amended with organic substrates in the presence or absence of oil. Incubation at 80°C for six days was followed by a down-shift in temperature to 60°C to mimic cold seawater injection into a hot reservoir. Souring did not occur at 80°C, but commenced within hours at 60°C. Microcosms were monitored for sulfate reduction and organic acids in combination with next generation sequencing of 16S rRNA genes (Ion Torrent, Illumina MiSeq). Through a combination of high

  18. Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. Appendix 1, Volume 1

    SciTech Connect

    Kopaska-Merkel, D.C.; Moore, H.E. Jr.; Mann, S.D.; Hall, D.R.

    1992-06-01

    This volume contains maps, well logging correlated to porosity and permeability, structural cross section, graph of production history, porosity vs. natural log permeability plot, detailed core log, paragenetic sequence and reservoir characterization sheet of the following fields in southwest Alabama: Appleton oil field; Barnett oil field; Barrytown oil field; Big Escambia Creek gas and condensate field; Blacksher oil field; Broken Leg Creed oil field; Bucatunna Creed oil field; Chappell Hill oil field; Chatom gas and condensate field; Choctaw Ridge oil field; Chunchula gas and condensate field; Cold Creek oil field; Copeland gas and condensate field; Crosbys Creed gas and condensate field; and East Barnett oil field. (AT)

  19. Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. [Jurassic Smackover Formation

    SciTech Connect

    Kopaska-Merkel, D.C.; Moore, H.E. Jr.; Mann, S.D.; Hall, D.R.

    1992-06-01

    This volume contains maps, well logging correlated to porosity and permeability, structural cross section, graph of production history, porosity vs. natural log permeability plot, detailed core log, paragenetic sequence and reservoir characterization sheet of the following fields in southwest Alabama: Appleton oil field; Barnett oil field; Barrytown oil field; Big Escambia Creek gas and condensate field; Blacksher oil field; Broken Leg Creed oil field; Bucatunna Creed oil field; Chappell Hill oil field; Chatom gas and condensate field; Choctaw Ridge oil field; Chunchula gas and condensate field; Cold Creek oil field; Copeland gas and condensate field; Crosbys Creed gas and condensate field; and East Barnett oil field. (AT)

  20. Wave responses from oil reservoirs in the Arctic shelf zone

    NASA Astrophysics Data System (ADS)

    Favorskaya, A. V.; Petrov, I. B.

    2016-02-01

    We consider the appearance of scattered PP-waves, SS-waves, scattered converted PS-waves, and SP-waves reflected from the reservoirs in the Arctic shelf zone and wave responses from them in the water column when the source and receiver are located near the water surface. We obtained a numerical solution of the direct problems of seismic prospecting in the shelf zone with a reservoir and without it. The solution was obtained using the grid-characteristic method, which makes possible to model the wave processes in detail.

  1. SEISMIC DETERMINATION OF RESERVOIR HETEROGENEITY: APPLICATION TO THE CHARACTERIZATION OF HEAVY OIL RESERVOIRS

    SciTech Connect

    Matthias G. Imhof; James W. Castle

    2005-02-01

    The objective of the project was to examine how seismic and geologic data can be used to improve characterization of small-scale heterogeneity and their parameterization in reservoir models. The study focused on West Coalinga Field in California. The project initially attempted to build reservoir models based on different geologic and geophysical data independently using different tools, then to compare the results, and ultimately to integrate them all. We learned, however, that this strategy was impractical. The different data and tools need to be integrated from the beginning because they are all interrelated. This report describes a new approach to geostatistical modeling and presents an integration of geology and geophysics to explain the formation of the complex Coalinga reservoir.

  2. SEISMIC DETERMINATION OF RESERVOIR HETEROGENEITY: APPLICATION TO THE CHARACTERIZATION OF HEAVY OIL RESERVOIRS

    SciTech Connect

    Matthias G. Imhof; James W. Castle

    2005-02-01

    The objective of the project was to examine how seismic and geologic data can be used to improve characterization of small-scale heterogeneity and their parameterization in reservoir models. The study focused on West Coalinga Field in California. The project initially attempted to build reservoir models based on different geologic and geophysical data independently using different tools, then to compare the results, and ultimately to integrate them all. Throughout the project, however, we learned that this strategy was impractical because the different data and model are complementary instead of competitive. For the complex Coalinga field, we found that a thorough understanding of the reservoir evolution through geologic times provides the necessary framework which ultimately allows integration of the different data and techniques.

  3. Development Practices for Optimized MEOR in Shallow Heavy Oil Reservoirs

    SciTech Connect

    Shari Dunn-Norman

    2006-09-30

    The goal of this project is to demonstrate an economically viable and sustainable method of producing shallow heavy oil reserves in southwest Missouri and southeast Kansas using a combination of microbial enhanced oil recovery (MEOR) and hydraulic fracturing of vertical wells.

  4. Carbonate petroleum reservoirs

    SciTech Connect

    Roehl, P.O.; Choquette, P.W.

    1985-01-01

    This book presents papers on the geology of petroleum deposits. Topics considered include diagenesis, porosity, dolomite reservoirs, deposition, reservoir rock, reefs, morphology, fracture-controlled production, Cenozoic reservoirs, Mesozoic reservoirs, and Paleozoic reservoirs.

  5. Commercial application of steamflooding in an oil field comprised of multiple thin-sand reservoirs

    SciTech Connect

    Powers, M.L.; Dosdon, C.J.; Ghassemi, F.; Moore, J.S.

    1984-09-01

    Steamfloods conducted in thin reservoirs generally provide marginal economics because of relatively high field development costs per barrel of oil-in-place and excessive heat losses from the productive zone. Techniques are being employed which include the utilization of induced horizontal fractures to circumvent these detriments attributed to thin zones, as well as the problems of steam distribution and confinement inherent in any steamflood. This paper documents the successful application of steamflooding in the multiple thin-sand reservoirs of the Loco Unit, Stephens County, Oklahoma. These reservoirs occur at depths from 50 ft (15 m) to 1,200 ft (366 m), and range in thickness up to 40 ft (12 m). Porosities of the productive zones vary from 20 percent to over 30 percent, and permeabilities range from 100 md to over 4,000 md. Oil gravities of the various zones range from 16 degrees to 24 degrees API. Reservoirs that occur at depths above approximately 700 ft (213 m) had little or no natural reservoir energy and generally contain viscous oils, ranging up to 10,000 cp. Consequently, there was no primary production from these reservoirs and potential for waterflooding was marginal. Steamflooding has been the only recovery process successfully applied to these zones, except for one isolated instance. Reservoirs of depths greater than 700 ft (213 m) normally contain lower viscosity oils. Six of these zones were produced by solution gas drive and were later successfully waterflooded. To date two of these six zones have been tested and have proven to support commercial steamflooding operations, after 23 years of waterflooding.

  6. Hot-dry-rock geothermal-reservoir fracturing initial field operations - 1982

    SciTech Connect

    Rowley, J.C.; Pettitt, R.A.; Matsunaga, I.; Dreesen, D.S.; Nicholson, R.W.; Sinclair, A.R.

    1983-01-01

    Initial fracturing operations were conducted during 1982 to create a hot dry rock (HDR) geothermal reservoir at the Los Alamos Fenton Hill site. A preliminary work-over/cleaning operation in November to December 1981 had cleared the injection well, EE-2, and a detailed, comprehensive plan was prepared to accomplish the objectives of hydraulically connecting the injection and production wells. In January 1982, open-hole reservoir sections of both the production and injection wells were pressurized below the 9-5/8 in. casing. The injection well, EE-2, did not take fluid at 2200 psi, but the production well, EE-3, had a lost circulation zone and took water over a 240 ft zone immediately below the production casing. Subsequent field operations from May through December 14, 1982 involved ten major hydraulic injection and/or equipment tests. These ranged from 14,180 ft (4322 m) deep open-hole packer tests to installation of a cemented-in liner/PBR system. Injections of up to 1.3 x 10 gals. were performed in the injection well. Both wells were fractured in zones just below the production casings. Although several large volume injections were accomplished, hydraulic communication between wells was not achieved. Severe hardware problems were encountered due to temperature limitations, the high fracture gradient (breakdown and injection pressures), and the presence of CO/sub 2/ and H/sub 2/S during fracture back-flow and well venting. On-line and post-test analyses of seismic monitoring confirmed that fractures were created in each well that converged on, but did not intersect, the neighboring well.

  7. Geochemical Interaction of Middle Bakken Reservoir Rock and CO2 during CO2-Based Fracturing

    NASA Astrophysics Data System (ADS)

    Nicot, J. P.; Lu, J.; Mickler, P. J.; Ribeiro, L. H.; Darvari, R.

    2015-12-01

    This study was conducted to investigate the effects of geochemical interactions when CO2 is used to create the fractures necessary to produce hydrocarbons from low-permeability Middle Bakken sandstone. The primary objectives are to: (1) identify and understand the geochemical reactions related to CO2-based fracturing, and (2) assess potential changes of reservoir property. Three autoclave experiments were conducted at reservoir conditions exposing middle Bakken core fragments to supercritical CO2 (sc-CO2) only and to CO2-saturated synthetic brine. Ion-milled core samples were examined before and after the reaction experiments using scanning electron microscope, which enabled us to image the reaction surface in extreme details and unambiguously identify mineral dissolution and precipitation. The most significant changes in the reacted rock samples exposed to the CO2-saturated brine is dissolution of the carbonate minerals, particularly calcite which displays severely corrosion. Dolomite grains were corroded to a lesser degree. Quartz and feldspars remained intact and some pyrite framboids underwent slight dissolution. Additionally, small amount of calcite precipitation took place as indicated by numerous small calcite crystals formed at the reaction surface and in the pores. The aqueous solution composition changes confirm these petrographic observations with increase in Ca and Mg and associated minor elements and very slight increase in Fe and sulfate. When exposed to sc-CO2 only, changes observed include etching of calcite grain surface and precipitation of salt crystals (halite and anhydrite) due to evaporation of residual pore water into the sc-CO2 phase. Dolomite and feldspars remained intact and pyrite grains were slightly altered. Mercury intrusion capillary pressure tests on reacted and unreacted samples shows an increase in porosity when an aqueous phase is present but no overall porosity change caused by sc-CO2. It also suggests an increase in permeability

  8. Hydrology of the Valley-fill and carbonate-rock reservoirs, Pahrump Valley, Nevada-California

    USGS Publications Warehouse

    Malmberg, Glenn T.

    1967-01-01

    This is the second appraisal of the water supply of Pahrump Valley, made 15 years after the first cooperative study. In the first report the average recharge was estimated to be 23,000 acre-feet per year, only 1,000 acre-feet more than the estimate made in this report. All this recharge was considered to be available for development. Because of the difficulty in salvaging the subsurface outflow from the deep carbonate-rock reservoir, this report concludes that the perennial yield may be only 25,000 acre-feet. In 1875, Bennetts and Manse Springs reportedly discharged a total of nearly 10,000 acre-feet of water from the valley-fill reservoir. After the construction of several flowing wells in 1910, the spring discharge began to decline. In the mid-1940's many irrigation wells were drilled, and large-capacity pumps were installed. During the 4-year period of this study (1959-62), the net pumping draft averaged about 25,000 acre-feet per year, or about twice the estimated yield. In 1962 Bennetts Spring was dry, and the discharge from Marse Spring was only 1,400 acre-feet. During the period February 1959-February 1962, pumping caused an estimated storage depletion of 45,000 acre-feet, or 15,000 acre-feet per year. If the overdraft is maintained, depletion of stored water will continue and pumping costs will increase. Water levels in the vicinity of the Pahrump, Manse, and Fowler Ranches declined more than ]0 feet in response to the pumping during this period, and they can be expected to continue to decline at ,the projected rate of more than 3 feet per year. The chemical quality of the pumped water has been satisfactory for irrigation and domestic use. Recycling of water pumped or irrigation, however, could result in deterioration of the water quality with time.

  9. Investigation of oil recovery improvement by coupling an interfacial tension agent and a mobility control agent in light oil reservoirs. Technical progress report, April--June 1994

    SciTech Connect

    Pitts, M.J.; Casteel, J.

    1994-09-01

    The study will investigate two major areas concerning co-injecting an interfacial tension reduction agent(s) and a mobility control agent into petroleum reservoirs. The first will consist of defining the mechanisms of interaction of an alkaline agent, a surfactant, and a polymer on a fluid-fluid and a fluid-rock basis. The second is the improvement of the economics of the combined technology. This report examines the changes in the relative permeability characteristics with addition of alkali, surfactant, and polymer to the injected solution, the effect of matrix type on relative permeability characteristics with alkali-surfactant-polymer and the effect of different polymer concentrations on oil recovery by an alkaline-surfactant-polymer solution.

  10. Seismic Determination of Reservoir Heterogeneity: Application to the Characterization of Heavy Oil Reservoirs

    SciTech Connect

    Imhof, Matthias G.; Castle, James W.

    2003-03-12

    The objective of the project was to examine how seismic and geologic data could be used to improve characterization of small-scale heterogeneity and their parameterization in reservoir models. Performed a theoretical and numerical study to examine which subsurface features the surface seismic method actually resolves.

  11. Additive for inclusion in a heavy oil reservoir undergoing steam injection

    SciTech Connect

    Hyne, J. B.; Clark, P. D.

    1985-03-26

    The viscosity of heavy oil may be incrementally reduced over what can be achieved by steam alone, by introducing an aqueous metal salt solution into a reservoir undergoing steam injection. The metal ion is selected from the group consisting of Ti, V, Cr, Mn, Fe, Co, Ni, Cu, Zn, Mo, and Al. In a preferred feature CO is also introduced as a second additive, with a further oil viscosity reduction being observed with certain of the metal ions.

  12. Revitalizing a mature oil play: Strategies for finding and producing unrecovered oil in Frio Fluvial-Deltaic reservoirs of South Texas. Annual report, October 1992--October 1993

    SciTech Connect

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

    1994-05-01

    The Frio Fluvial-Deltaic Sandstone (Vicksburg Fault Zone) oil play of South Texas has produced nearly 1 Bbbl of oil, yet still contains about 1.6 Bbbl of unrecovered mobile oil and nearly the same amount of residual oil resources. More than half of the reservoirs in this depositionally complex play have been abandoned, and large volumes of oil may remain unproduced unless advanced characterization techniques are applied to define untapped, incompletely drained, and new pool reservoirs as suitable targets for near-term recovery. Interwell-scale geological fades models of Frio fluvial-deltaic reservoirs will be combined with engineering assessments and geophysical evaluations in order to characterize Frio fluvial-deltaic reservoir architecture and flow unit boundaries and to determine the controls that these characteristics exert on the location and volume of unrecovered mobile and residual oil. These results will help identify specific opportunities to exploit these heterogeneous reservoirs for incremental recovery by recompletion and strategic infill drilling. Preliminary syntheses of reservoir log, core, and production data were undertaken to identify individual reservoirs with the greatest additional resource potential to target for detailed reservoir characterization studies. Representative logs for each field were selected to characterize overall depositional style and illustrate reservoir zones and associated production. Core analysis data from both fields were tabulated, summarized, and evaluated by reservoir to Identify and assess reservoir variability within the field. Production histories for individual reservoirs were reconstructed using available completion data. On the basis of these preliminary investigations and a general assessment of reserve growth potential of reservoirs within each field area, reservoir Intervals from Rincon and T-C-B fields have been targeted for detailed characterization studies.

  13. Evaluation of Microstructural Parameters of Reservoir Rocks of the Guarani Aquifer by Analysis of Images Obtained by X- Ray Microtomography

    NASA Astrophysics Data System (ADS)

    Fernandes, J. S.; Lima, F. A.; Vieira, S. F.; Reis, P. J.; Appoloni, C. R.

    2015-07-01

    Microstructural parameters evaluation of porous materials, such as, rocks reservoir (water, petroleum, gas...), it is of great importance for several knowledge areas. In this context, the X-ray microtomography (μ-CT) has been showing a technical one quite useful for the analysis of such rocks (sandstone, limestone and carbonate), object of great interest of the petroleum and water industries, because it facilitates the characterization of important parameters, among them, porosity, permeability, grains or pore size distribution. The X-ray microtomography is a non-destructive method, that besides already facilitating the reuse of the samples analyzed, it also supplies images 2-D and 3-D of the sample. In this work samples of reservoir rock of the Guarani aquifer will be analyzed, given by the company of perforation of wells artesian Blue Water, in the municipal district of Videira, Santa Catarina, Brazil. The acquisition of the microtomographys data of the reservoir rocks was accomplished in a Skyscan 1172 μ-CT scanner, installed in Applied Nuclear Physics Laboratory (LFNA) in the State University of Londrina (UEL), Paraná, Brazil. In this context, this work presents the microstructural characterization of reservoir rock sample of the Guarani aquifer, analyzed for two space resolutions, 2.8 μm and 4.8 μm, where determined average porosity was 28.5% and 21.9%, respectively. Besides, we also determined the pore size distribution for both resolutions. Two 3-D images were generated of this sample, one for each space resolution, in which it is possible to visualize the internal structure of the same ones.

  14. Special core analyses and relative permeability measurement on Almond formation reservoir rocks

    SciTech Connect

    Maloney, D.; Doggett, K.; Brinkmeyer, A.

    1993-02-01

    This report describes the results from special core analyses and relative permeability measurements conducted on samples of rock from the Almond Formation in Greater Green River Basin of southwestern Wyoming. The core was from Arch Unit Well 121 of Patrick Draw field. Samples were taken from the 4,950 to 4,965 ft depth interval. Thin section evaluation, X-ray diffraction, routine permeability and porosity, capillary pressure and wettability tests were performed to characterize the samples. Fluid flow capacity characteristics were measured during two-phase unsteady- and steady-state and three-phase steady-state relative permeability tests. Test results are presented in tables and graphs. Relative permeability results are compared with those of a 260-mD, fired Berea sandstone sample which was previously subjected to similar tests. Brine relative permeabilities were similar for the two samples, whereas oil and gas relative permeabilities for the Almond formation rock were higher at equivalent saturation conditions compared to Berea results. Most of the tests described in this report were conducted at 74[degrees]F laboratory temperature. Additional tests are planned at 150[degrees]F temperature. Equipment and procedural modifications to perform the elevated temperature tests are described.

  15. Special core analyses and relative permeability measurement on Almond formation reservoir rocks

    SciTech Connect

    Maloney, D.; Doggett, K.; Brinkmeyer, A.

    1993-02-01

    This report describes the results from special core analyses and relative permeability measurements conducted on samples of rock from the Almond Formation in Greater Green River Basin of southwestern Wyoming. The core was from Arch Unit Well 121 of Patrick Draw field. Samples were taken from the 4,950 to 4,965 ft depth interval. Thin section evaluation, X-ray diffraction, routine permeability and porosity, capillary pressure and wettability tests were performed to characterize the samples. Fluid flow capacity characteristics were measured during two-phase unsteady- and steady-state and three-phase steady-state relative permeability tests. Test results are presented in tables and graphs. Relative permeability results are compared with those of a 260-mD, fired Berea sandstone sample which was previously subjected to similar tests. Brine relative permeabilities were similar for the two samples, whereas oil and gas relative permeabilities for the Almond formation rock were higher at equivalent saturation conditions compared to Berea results. Most of the tests described in this report were conducted at 74{degrees}F laboratory temperature. Additional tests are planned at 150{degrees}F temperature. Equipment and procedural modifications to perform the elevated temperature tests are described.

  16. A combination of streamtube and geostatical simulation methodologies for the study of large oil reservoirs

    SciTech Connect

    Chakravarty, A.; Emanuel, A.S.; Bernath, J.A.

    1997-08-01

    The application of streamtube models for reservoir simulation has an extensive history in the oil industry. Although these models are strictly applicable only to fields under voidage balance, they have proved to be useful in a large number of fields provided that there is no solution gas evolution and production. These models combine the benefit of very fast computational time with the practical ability to model a large reservoir over the course of its history. These models do not, however, directly incorporate the detailed geological information that recent experience has taught is important. This paper presents a technique for mapping the saturation information contained in a history matched streamtube model onto a detailed geostatistically derived finite difference grid. With this technique, the saturation information in a streamtube model, data that is actually statistical in nature, can be identified with actual physical locations in a field and a picture of the remaining oil saturation can be determined. Alternatively, the streamtube model can be used to simulate the early development history of a field and the saturation data then used to initialize detailed late time finite difference models. The proposed method is presented through an example application to the Ninian reservoir. This reservoir, located in the North Sea (UK), is a heterogeneous sandstone characterized by a line drive waterflood, with about 160 wells, and a 16 year history. The reservoir was satisfactorily history matched and mapped for remaining oil saturation. A comparison to 3-D seismic survey and recently drilled wells have provided preliminary verification.

  17. Advanced Oil Recovery Technologies for Improved Recovery from Slope Basin Clastic Reservoirs, Nash Draw Brushy Canyon Pool, Eddy County, NM

    SciTech Connect

    Murphy, M.B.

    1997-10-30

    The overall objective of this project is to demonstrate that a development program-based on advanced reservoir management methods- can significantly improve oil recovery. The plan includes developing a control area using standard reservoir management techniques and comparing its performance to an area developed using advanced reservoir management methods. Specific goals are (1) to demonstrate that an advanced development drilling and pressure maintenance program can significantly improve oil recovery compared to existing technology applications and (2) to transfer these advanced methodologies to oil and gas producers in the Permian Basin and elsewhere throughout the U.S. oil and gas industry.

  18. ADVANCED OIL RECOVERY TECHNOLOGIES FOR IMPROVED RECOVERY FROM SLOPE BASIN CLASTIC RESERVOIRS, NASH DRAW BRUSHY CANYON POOL, EDDY COUNTY, NM

    SciTech Connect

    Mark B. Murphy

    2004-01-31

    The overall objective of this project is to demonstrate that a development program based on advanced reservoir management methods can significantly improve oil recovery at the Nash Draw Pool (NDP). The plan includes developing a control area using standard reservoir management techniques and comparing its performance to an area developed using advanced reservoir management methods. Specific goals are (1) to demonstrate that an advanced development drilling and pressure maintenance program can significantly improve oil recovery compared to existing technology applications and (2) to transfer these advanced methodologies to oil and gas producers in the Permian Basin and elsewhere throughout the U.S. oil and gas industry.

  19. ADVANCED OIL RECOVERY TECHNOLOGIES FOR IMPROVED RECOVERY FROM SLOPE BASIN CLASTIC RESERVOIRS, NASH DRAW BRUSHY CANYON POOL, EDDY COUNTY, NM

    SciTech Connect

    Mark B. Murphy

    2003-10-31

    The overall objective of this project is to demonstrate that a development program based on advanced reservoir management methods can significantly improve oil recovery at the Nash Draw Pool (NDP). The plan includes developing a control area using standard reservoir management techniques and comparing its performance to an area developed using advanced reservoir management methods. Specific goals are (1) to demonstrate that an advanced development drilling and pressure maintenance program can significantly improve oil recovery compared to existing technology applications and (2) to transfer these advanced methodologies to oil and gas producers in the Permian Basin and elsewhere throughout the U.S. oil and gas industry.

  20. ADVANCED OIL RECOVERY TECHNOLOGIES FOR IMPROVED RECOVERY FROM SLOPE BASIN CLASTIC RESERVOIRS, NASH DRAW BRUSHY CANYON POOL, EDDY COUNTY, NM

    SciTech Connect

    Mark B. Murphy

    2002-12-31

    The overall objective of this project is to demonstrate that a development program based on advanced reservoir management methods can significantly improve oil recovery at the Nash Draw Pool (NDP). The plan includes developing a control area using standard reservoir management techniques and comparing its performance to an area developed using advanced reservoir management methods. Specific goals are (1) to demonstrate that an advanced development drilling and pressure maintenance program can significantly improve oil recovery compared to existing technology applications and (2) to transfer these advanced methodologies to oil and gas producers in the Permian Basin and elsewhere throughout the U.S. oil and gas industry.

  1. ADVANCED OIL RECOVERY TECHNOLOGIES FOR IMPROVED RECOVERY FROM SLOPE BASIN CLASTIC RESERVOIRS, NASH DRAW BRUSHY CANYON POOL, EDDY COUNTY, NM

    SciTech Connect

    Mark B. Murphy

    2003-07-30

    The overall objective of this project is to demonstrate that a development program based on advanced reservoir management methods can significantly improve oil recovery at the Nash Draw Pool (NDP). The plan includes developing a control area using standard reservoir management techniques and comparing its performance to an area developed using advanced reservoir management methods. Specific goals are (1) to demonstrate that an advanced development drilling and pressure maintenance program can significantly improve oil recovery compared to existing technology applications and (2) to transfer these advanced methodologies to oil and gas producers in the Permian Basin and elsewhere throughout the U.S. oil and gas industry.

  2. Improving CO2 Efficiency for Recovering Oil in Heterogeneous Reservoirs

    SciTech Connect

    Grigg, Reid B.; Svec, Robert K.

    2003-03-10

    The work strived to improve industry understanding of CO2 flooding mechanisms with the ultimate goal of economically recovering more of the U.S. oil reserves. The principle interests are in the related fields of mobility control and injectivity.

  3. Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. [Jurassic Smackover Formation

    SciTech Connect

    Kopaska-Merkel, D.C.; Moore, H.E. Jr.; Mann, S.D.; Hall, D.R.

    1992-06-01

    This volume contains maps, well logging, structural cross section, graph of production history, porosity vs. natural log permeability plots, detailed core log, paragenetic sequence, and reservoir characterization sheet for the following fields in southwest Alabama: North Smiths Church oil field; North Wallers Creek oil field; Northeast Barnett oil field; Northwest Range oil field; Pace Creek oil field; Palmers Crossroads oil field; Perdido oil field; Puss Cuss Creek oil field; Red Creek gas condensate field; Robinson Creek oil field; Silas oil field; Sizemore Creek gas condensate field; Smiths Church gas condensate field; South Burnt Corn Creek oil field; South Cold Creek oil field; South Vocation oil field; South Wild Fork Creek gas condensate field; South Womack Hill oil field; Southeast Chatom gas condensate field; Southwest Barrytown oil field; and Souwilpa Creek gas condensate field.

  4. Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. Appendix 1, Volume 3

    SciTech Connect

    Kopaska-Merkel, D.C.; Moore, H.E. Jr.; Mann, S.D.; Hall, D.R.

    1992-06-01

    This volume contains maps, well logging, structural cross section, graph of production history, porosity vs. natural log permeability plots, detailed core log, paragenetic sequence, and reservoir characterization sheet for the following fields in southwest Alabama: North Smiths Church oil field; North Wallers Creek oil field; Northeast Barnett oil field; Northwest Range oil field; Pace Creek oil field; Palmers Crossroads oil field; Perdido oil field; Puss Cuss Creek oil field; Red Creek gas condensate field; Robinson Creek oil field; Silas oil field; Sizemore Creek gas condensate field; Smiths Church gas condensate field; South Burnt Corn Creek oil field; South Cold Creek oil field; South Vocation oil field; South Wild Fork Creek gas condensate field; South Womack Hill oil field; Southeast Chatom gas condensate field; Southwest Barrytown oil field; and Souwilpa Creek gas condensate field.

  5. The exhumed ``Carlin-type'' fossil oil reservoir at Yankee Basin

    NASA Astrophysics Data System (ADS)

    Hulen, Jeffrey B.; Collister, James W.; Stout, Bill; Curtiss, David K.; Dahdah, Nicolas F.

    1998-12-01

    The Carlin-type disseminated gold orebodies of Yankee basin in the southern part of the Alligator Ridge mining district in Nevada contain widespread oil as smears, open-space fillings, and fluid inclusions in syn- and pre-mineral calcite veins. These unusual oils are the relicts of an exhumed and deeply oxidized oil reservoir that encom-passes the orebodies at the crest of a dissected, anticlinal trap. Results of fluid-inclusion microthermometry and organic geochemistry demonstrate that the oils experienced peak paleotemperatures of no more than about 150°C, a temperature unusually low for Carlin-type mineralization, but ideal for the transport, entrapment, and preservation of liquid hydrocarbon. Similar geothermal systems are actively circulating at three of Nevada’s producing oil fields—Grant Canyon, Bacon Flat, and Blackburn. Accordingly, concealed Carlin-type fossil hydrothermal systems of this type, even if subeconomic for gold, could contain commercial concentrations of oil.

  6. Advanced Oil Recovery Technologies for Improved Recovery from Slope Basin Clastic Reservoirs, Nash Draw Brushy Canyon Pool, Eddy County, NM

    SciTech Connect

    Murphy, M.B.

    1999-02-01

    Advanced reservoir characterization techniques are being used at the Nash Draw Brushy Canyon Pool project to develop reservoir management strategies for optimizing oil recovery from this Delaware reservoir. The reservoir characterization, geologic modeling, 3-D seismic interpretation, and simulation studies have provided a detailed model of the Brushy Canyon zones. This model was used to predict the success of different reservoir management scenarios and to aid in determining the most favorable combination of targeted drilling, pressure maintenance, well stimulation, and well spacing to improve recovery from this reservoir.

  7. Petroleum source rock potential and crude oil correlation in Great Basin

    SciTech Connect

    Poole, F.G.; Claypool, G.E.

    1985-05-01

    Petroleum source beds in the Great Basin region include marine Paleozoic rocks and nonmarine upper Mesozoic and lower Cenozoic rocks. Potential source beds have been identified in continental-rise deposits of the Ordovician Vinini and Devonian Woodruff formations if the eastern part of the Roberts Mountains allochthon (Antler orogene), in central and north-central Nevada; in flysch-trough and prodelta-basin deposits of the Mississippian Chainman Shale and equivalent rocks of the Antler foreland basin, in Nevada and western Utah; and in lake-basin deposits of the Cretaceous Neward Canyon Formation and the Paleogene Sheep Pass and Elko formations and equivalent rocks, in central and eastern Nevada. Oil fields in the Great Basin are located with Neogene-Quaternary basins that formed during neogene basin-range block faulting. Most of the oil shows and crude oils analyzed can be correlated with Mississippian or paleogene source rocks. The Mississippian Chainman Shale is confirmed as the major petroleum source rock, having generated the oil in the Trap Spring, Bacon Flat, and Grant Canyon fields in Railroad Valley and the Blackburn field in Pine Valley. The Paleogene Sheep Pass Formation is the source of the oil in the Eagle Springs field and probably the Current field in Railroad Valley. Oil occurrences in the northern Great Basin are believed to be derived from two or more other Tertiary lacustrine sequences.

  8. Experimental and Theoretical Determination of Heavy Oil Viscosity Under Reservoir Conditions

    SciTech Connect

    Gabitto, Jorge; Barrufet, Maria

    2002-03-11

    The main objective of this research was to propose a simple procedure to predict heavy oil viscosity at reservoir conditions as a function of easily determined physical properties. This procedure will avoid costly experimental testing and reduce uncertainty in designing thermal recovery processes.

  9. Reservoir characterization and enhanced oil recovery research. Annual report, September 1988--August 1989

    SciTech Connect

    Lake, L.W.; Pope, G.A.; Schechter, R.S.

    1992-03-01

    The research in this annual report falls into three tasks each dealing with a different aspect of enhanced oil recovery. The first task strives to develop procedures for accurately modeling reservoirs for use as input to numerical simulation flow models. This action describes how we have used a detail characterization of an outcrop to provide insights into what features are important to fluid flow modeling. The second task deals with scaling-up and modeling chemical and solvent EOR processes. In a sense this task is the natural extension of task 1 and, in fact, one of the subtasks uses many of the same statistical procedures for insight into the effects of viscous fingering and heterogeneity. The final task involves surfactants and their interactions with carbon dioxide and reservoir minerals. This research deals primarily with phenomena observed when aqueous surfactant solutions are injected into oil reservoirs.

  10. Massive dominance of Epsilonproteobacteria in formation waters from a Canadian oil sands reservoir containing severely biodegraded oil

    PubMed Central

    Hubert, Casey R J; Oldenburg, Thomas B P; Fustic, Milovan; Gray, Neil D; Larter, Stephen R; Penn, Kevin; Rowan, Arlene K; Seshadri, Rekha; Sherry, Angela; Swainsbury, Richard; Voordouw, Gerrit; Voordouw, Johanna K; Head, Ian M

    2012-01-01

    Summary The subsurface microbiology of an Athabasca oil sands reservoir in western Canada containing severely biodegraded oil was investigated by combining 16S rRNA gene- and polar lipid-based analyses of reservoir formation water with geochemical analyses of the crude oil and formation water. Biomass was filtered from formation water, DNA was extracted using two different methods, and 16S rRNA gene fragments were amplified with several different primer pairs prior to cloning and sequencing or community fingerprinting by denaturing gradient gel electrophoresis (DGGE). Similar results were obtained irrespective of the DNA extraction method or primers used. Archaeal libraries were dominated by Methanomicrobiales (410 of 414 total sequences formed a dominant phylotype affiliated with a Methanoregula sp.), consistent with the proposed dominant role of CO2-reducing methanogens in crude oil biodegradation. In two bacterial 16S rRNA clone libraries generated with different primer pairs, > 99% and 100% of the sequences were affiliated with Epsilonproteobacteria (n = 382 and 72 total clones respectively). This massive dominance of Epsilonproteobacteria sequences was again obtained in a third library (99% of sequences; n = 96 clones) using a third universal bacterial primer pair (inosine-341f and 1492r). Sequencing of bands from DGGE profiles and intact polar lipid analyses were in accordance with the bacterial clone library results. Epsilonproteobacterial OTUs were affiliated with Sulfuricurvum, Arcobacter and Sulfurospirillum spp. detected in other oil field habitats. The dominant organism revealed by the bacterial libraries (87% of all sequences) is a close relative of Sulfuricurvum kujiense – an organism capable of oxidizing reduced sulfur compounds in crude oil. Geochemical analysis of organic extracts from bitumen at different reservoir depths down to the oil water transition zone of these oil sands indicated active biodegradation of dibenzothiophenes, and stable

  11. The effect of long-term fluid-rock interactions on the mechanical properties of reservoir rock - a case study of the Werkendam natural CO2 analogue field

    NASA Astrophysics Data System (ADS)

    Hangx, Suzanne; Bertier, Pieter; Bakker, Elisenda; Nover, Georg; Busch, Andreas

    2015-04-01

    Geological storage of CO2 is one of the most promising technologies to rapidly reduce anthropogenic emissions of carbon dioxide. During long-term geological storage of CO2, fluid-rock interactions, induced by the formation of carbonic acid, may affect the mineralogical composition of the reservoir rock. Commonly expected reactions include the dissolution of carbonate and/or sulphate cements, as well as the reaction of primary minerals (feldspars, clays, micas) to form new, secondary phases. In order to ensure storage integrity, it is important to understand the effect of such fluid-rock interactions on the mechanical behaviour of a CO2 storage complex. However, most of these reactions are very slow, which limits the ability to study coupled chemical-mechanical processes in the lab. A possible way to circumvent long reaction times is to investigate natural CO2 analogue fields, which experienced CO2-exposure for thousands of years. In this study, we looked at the Dutch Werkendam natural CO2 field and its unreacted counterpart (Röt Fringe Sandstone, Werkendam, the Netherlands). We focussed on CO2-induced mineralogical and porosity-permeability changes, and their effect on mechanical behaviour of intact rock. Overall, CO2-exposure did not lead to drastic mineralogical changes, though markedly different porosity-permeability relationships were found for the unreacted and exposed material. The limited extent of reaction was in part the result of bitumen coatings protecting specific mineral phases from reaction. In local, mm-sized zones displaying significant anhydrite dissolution, enhanced porosity was observed. For most of the reservoir the long-term mechanical behaviour after CO2-exposure could be described by the behaviour of the unreacted sandstone, while these more 'porous' zones were significantly weaker. Simple stress path calculations predict that reservoir failure due to depletion and injection is unlikely.

  12. Multi-Attribute Seismic/Rock Physics Approach to Characterizing Fractured Reservoirs

    SciTech Connect

    Gary Mavko

    2004-11-30

    Most current seismic methods to seismically characterize fractures in tight reservoirs depend on a few anisotropic wave propagation signatures that can arise from aligned fractures. While seismic anisotropy can be a powerful fracture diagnostic, a number of situations can lessen its usefulness or introduce interpretation ambiguities. Fortunately, laboratory and theoretical work in rock physics indicates that a much broader spectrum of fracture seismic signatures can occur, including a decrease in P- and S-wave velocities, a change in Poisson's ratio, an increase in velocity dispersion and wave attenuation, as well as well as indirect images of structural features that can control fracture occurrence. The goal of this project was to demonstrate a practical interpretation and integration strategy for detecting and characterizing natural fractures in rocks. The approach was to exploit as many sources of information as possible, and to use the principles of rock physics as the link among seismic, geologic, and log data. Since no single seismic attribute is a reliable fracture indicator in all situations, the focus was to develop a quantitative scheme for integrating the diverse sources of information. The integrated study incorporated three key elements: The first element was establishing prior constraints on fracture occurrence, based on laboratory data, previous field observations, and geologic patterns of fracturing. The geologic aspects include analysis of the stratigraphic, structural, and tectonic environments of the field sites. Field observations and geomechanical analysis indicates that fractures tend to occur in the more brittle facies, for example, in tight sands and carbonates. In contrast, strain in shale is more likely to be accommodated by ductile flow. Hence, prior knowledge of bed thickness and facies architecture, calibrated to outcrops, are powerful constraints on the interpreted fracture distribution. Another important constraint is that fracturing

  13. Modelling kinetically controlled water-rock interactions during geothermal stimulation in typical poly-mineralic reservoir rocks from the Upper Rhine Graben, Germany

    NASA Astrophysics Data System (ADS)

    Kuesters, Tim; Mueller, Thomas; Renner, Joerg

    2015-04-01

    A quantitative understanding of geochemically controlled reaction rates and their operating reaction mechanisms is crucial for the efficient exploration and exploitation of geothermal reservoirs. For example, the volume changes associated with dissolution and precipitation reactions potentially may affect the hydraulic properties of a reservoir during the production phase. The reactivity depends on a complex interaction of various parameters such as temperature, fluid flux and chemistry, mineral composition, reactive surface areas, etc. Most shallow geothermal reservoirs are constituted by highly permeable sedimentary rocks saturated by a fluid phase. The abundance of impermeable crystalline basement rocks (magmatic and metamorphic) increases with depth. Typically, hydraulic stimulation is necessary to create fluid pathways, i.e. the permeability of the rock is increased by the generation of new fractures and the reactivation of old fractures (Enhanced Geothermal Systems, EGS). Fresh, high energy surfaces are created by this treatment, constituting potential sites for intensive water-rock interactions. An increasing number of reactive transport models using equilibrium thermodynamic data shed considerable light on water-rock interactions. However, most models simplify the involved rocks to mono-mineralic phases and/or use rate data based on powder experiments with unnatural high reactive surface areas. In this study we present a new numerical model approach to quantify the geochemical evolution and its mechanical feedback during geothermal stimulation of typical poly-mineralic reservoir rocks at elevated temperatures (150-200 °C). Rock samples representative for geothermal energy producing sites (limestone, sandstone, volcanic tuff and granite) were collected at the Upper Rhine Graben (URG) in southern Germany, i.e. one of the high potential locations for geothermal energy production in Germany. Samples have been characterized petrographically with regard to phase

  14. 30 CFR 250.1157 - How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap?

    Code of Federal Regulations, 2013 CFR

    2013-07-01

    ... gas from an oil reservoir with an associated gas cap? 250.1157 Section 250.1157 Mineral Resources... Production § 250.1157 How do I receive approval to produce gas-cap gas from an oil reservoir with an... producing gas-cap gas from each completion in an oil reservoir that is known to have an associated gas...

  15. 30 CFR 250.1157 - How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap?

    Code of Federal Regulations, 2010 CFR

    2010-07-01

    ... gas from an oil reservoir with an associated gas cap? 250.1157 Section 250.1157 Mineral Resources... do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap? (a... from each completion in an oil reservoir that is known to have an associated gas cap. (2) To...

  16. 30 CFR 250.1157 - How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap?

    Code of Federal Regulations, 2012 CFR

    2012-07-01

    ... gas from an oil reservoir with an associated gas cap? 250.1157 Section 250.1157 Mineral Resources... Production § 250.1157 How do I receive approval to produce gas-cap gas from an oil reservoir with an... producing gas-cap gas from each completion in an oil reservoir that is known to have an associated gas...

  17. 30 CFR 250.1157 - How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap?

    Code of Federal Regulations, 2014 CFR

    2014-07-01

    ... gas from an oil reservoir with an associated gas cap? 250.1157 Section 250.1157 Mineral Resources... Production § 250.1157 How do I receive approval to produce gas-cap gas from an oil reservoir with an... producing gas-cap gas from each completion in an oil reservoir that is known to have an associated gas...

  18. Integration of geologic and reservoir data to reevaluate performance of Terminal 8, an upper Miocene reservoir in Long Beach unit, Wilmington oil field, Los Angeles, California

    SciTech Connect

    Berman, B.H.

    1988-03-01

    The Terminal 8 reservoir consists of 615 ft of net oil sand. Vertical closure of the oil-saturated sandstone is 1080 ft. Areal extent is 13,350 ac. The reservoir sandstones are turbidites that have been correlated with the Puente Formation. The environment of deposition is an outer fan (sandstone-to-shale ratio of 1.2) in the lower Terminal sandstones and midfan in the upper Terminal sandstone (sandstone-to-shale ratio of 3.8). The fault block is located on the northeastern flank of the Wilmington anticline and is bounded by two intersecting normal faults and by oil-water contacts. Development started in 1969. Infill drilling after 1980 extended the boundaries and provided new data that led to reevaluation of the reservoir. The nine original sand units were divided into 13 flow units. Volumetrics were calculated for each flow unit using Zycor software. Mapping of electric log-derived water saturation and net oil-sand data revealed discrepancies, the result of varying log quality, different log types, lack of thin sand definition, and changing clay content. Computer-generated maps were constructed for each flow unit, and for weighted averages the units were combined into upper and lower Terminal zones. Individual maps are: structure, net oil sand, original water saturation, current water saturation, original oil in place, current oil in place, original reserves, current reserves, oil produced, pressure, and water cut. Mapping of original oil in place revealed fluid barriers within the reservoir. Mapping of current oil in place indicated moved oil and defined undrained areas. Water cut, fluid entry surveys, and temperature-spinner-tracer survey mapping revealed permeability trends. Pressure data confirmed sealing faults. This detailed study defined suspected, but never analyzed, complexities of the Terminal 8 reservoir.

  19. Interplay of bacteria, bacteriophage, and Berea sandstone rock in relation to enhanced oil recovery

    SciTech Connect

    Chang, P.L.

    1986-01-01

    Much research and development is needed to recovery oil reserves presently unattainable, and biologically enhanced oil recovery is a technology that may be used for this purpose. To address the problem of bacterial contamination in an oil field injection well region, each end of a Teflon-sleeved Berea sandstone rock was connected to a flask containing nutrient medium. By inoculation one flask with Escherichia coli B, observations of the bacterial growth in the uninoculated flask resulting from the transport and establishment of cells across the rock could be made. Differences in bacterial populations occurred depending on whether bacteriophage T4D was first adsorbed to the rock. The results of these experiments indicate that the inhibition of bacterial establishment within a rock matrix is possible via lytic interaction. Some nonlytic effects are also implied by experiments with B/4 cells, which are T4D-resistant mutants of E. coli B. A 10 to 40% retention of T4 by the rock occurred when it was loaded with 10/sup 5/ to 10/sup 6/ PFU. Also proposed is a lysogenic system for possible use in biologically enhanced oil recovery techniques. In addition to the model bacteria and phage system described above, measurements of the passage of Pseudomonas putida. 12633 and a phage-resistant mutant through Berea sandstone rock were also made. When bacteriophage gh-1 was adsorbed within the rock matrix, a reduction in the passage of the susceptible but no the resistant cells through the rock was observed. The use of P. putida and gh-1 represents a more realistic group of experiments since these pseudomonas are ubiquitous soil bacteria commonly found in oil rock regions. Preliminary work on the degradation of certain nitrogen compounds in the context of biologically enhanced oil recovery is also described in this dissertation.

  20. Advanced Oil Recovery Technologies for Improved Recovery From Slope Clastic Reservoirs, Nash Draw Brushy Canyon Pool, Eddy County, New Mexico

    SciTech Connect

    Mark B. Murphy

    1998-01-30

    The overall goal of this project is to demonstrate that an advanced development drilling and pressure maintenance program based on advanced reservoir management methods can significantly improve oil recovery. The plan included developing a control area using standard reservoir management techniques and comparing its performance to an area developed using advanced methods. A key goal is to transfer advanced methodologies to oil and gas producers in the Permian Basin and elsewhere, and throughout the US oil and gas industry.

  1. Assessment of potential oil and gas resources in source rocks of the Alaska North Slope, 2012

    USGS Publications Warehouse

    Houseknecht, David W.; Rouse, William A.; Garrity, Christopher P.; Whidden, Katherine J.; Dumoulin, Julie A.; Schenk, Christopher J.; Charpentier, Ronald R.; Cook, Troy A.; Gaswirth, Stephanie B.; Kirschbaum, Mark A.; Pollastro, Richard M.

    2012-01-01

    The U.S. Geological Survey estimated potential, technically recoverable oil and gas resources for source rocks of the Alaska North Slope. Estimates (95-percent to 5-percent probability) range from zero to 2 billion barrels of oil and from zero to nearly 80 trillion cubic feet of gas.

  2. CO2 Trapping in Reservoirs with Fluvial Architecture: Sensitivity to Heterogeneity and Hysteresis in Characteristic Relationships for Different Rock Types

    NASA Astrophysics Data System (ADS)

    Gershenzon, N. I.; Ritzi, R. W., Jr.; Dominic, D. F.; Mehnert, E.; Okwen, R. T.

    2015-12-01

    Naum I. Gershenzona, Robert W. Ritzi Jr.a, David F. Dominica, Edward Mehnertb, and Roland T. OkwenbaDepartment of Earth and Environmental Sciences, Wright State University, 3640 Col. Glenn Hwy., Dayton, OH 45435, USAbIllinois State Geological Survey, Prairie Research Institute, University of Illinois at Urbana-Champaign, 615 East Peabody Drive, Champaign, IL 61820, USA A number of important candidate CO2 reservoirs exhibit sedimentary architecture reflecting fluvial deposition. Recent studies have led to new conceptual and quantitative models for sedimentary architecture in fluvial deposits over a range of scales that are relevant to CO2 injection and storage, led to new geocellular modelling approaches for representing this architecture, and led to new computational studies of CO2 plume dynamics during and after injection. The processes of CO2 trapping depend upon a complex system of non-linear and hysteretic characteristic relationships including how relative permeability and capillary pressure vary with brine and CO2 saturation. New computational studies of capillary trapping in conglomeratic reservoirs strongly suggest that representing small-scale (decimeter to meter) textural facies among different rock types, including their organization within a hierarchy of larger-scale stratification, representing differences in characteristic relationships between rock types, and representing hysteresis in characteristic curves can all be critical to understanding trapping processes. In this context, CO2trapping was evaluated in conglomeratic reservoirs with fluvial architecture including different rock types with different and hysteretic characteristic curves and with capillary pressure defined for each rock type using two different conventional approaches, i.e. Brooks-Corey and van Genuchten. The results show that in these reservoirs the capillary trapping rates are quite sensitive to differences between the Brooks-Corey and van Genuchten approaches, and that

  3. Geological and geochemical evidence for vertical migration of Upper Cretaceous sourced oils into tertiary reservoirs: Winn and Grant Parishes, Louisiana

    SciTech Connect

    Echols, J.B.; Zimmerman, R.K.; Goddard, D.G.

    1995-10-01

    Analyses of three Wilcox oils taken from the Colgrade Field (Carrizo sand reservoir), Bulger Creek Field (middle Wilcox sand reservoir), both in Winn Parish, and the Blue Lick Field (middle Wilcox sand reservoir) Grant Parish, Louisiana, correlate with other Gulf Coast oils sourced from the Upper Cretaceous (probably Eagle Ford or Tuscaloosa). All three samples are mature and highly biodegraded. The oils from Blue Lick and Bulger Fields contain bisnorhopane (BNH), a Wilcox and younger biomarker in central Louisiana and southwest Mississippi. BNH was identified previously by the authors in chalk oil from Clark Creek Field, Wilkinson Co., Mississippi. Previous studies project northeast-southwest wrench faulting (Boeuf River Fault) into the oil sample area. This faulting, and associated extensional fracture/fault and salt tectonism cause the conduits for vertical migration which emplaced the sampled oils into Wilcox reservoirs. The oils probably migrated from both the Eagle Ford/Tuscaloosa source beds and from fractured Austin chalk reservoirs breached by faulting. The oils provide additional evidence that Wilcox and younger oil reservoirs of central Louisiana and southwest Mississippi were filled by vertical migration from Mesozoic source beds in contrast to long range lateral migration proposed by earlier workers. The Central Louisiana Fracture Zone is described as an extensional fracture zone generated by wrench faulting. The trend of the zone coincides closely with that of the LaSalle Arch and is important in concentrating hydrocarbons along the arch. Exploration targets arise in all traps above Eagle Ford/Tuscaloosa source beds in the area.

  4. A novel recovery mechanism for polymer flooding in gravity-dominated viscous-oil reservoirs

    SciTech Connect

    Goodyear, S.G.; Mead, B.J.; Woods, C.L.

    1995-11-01

    The viscous oil and poor vertical sweep make these reservoirs possible targets for IOR with polymers. This study shows that polymer incremental recoveries can be high, well within the range of potential economic viability. The incremental recovery mechanism is not the usual improved Buckley-Leverett sweep efficiency resulting from correction of an adverse displacement ratio. A novel recovery mechanism is identified in which the polymer increases the ratio of viscous to gravity forces, reducing the water slumping. This leads to improved vertical sweep, recovering oil from regions of high oil saturation at the top of the reservoir. They simulated polymer flooding including temperature effects. Comparison of waterflood simulations including temperature effects with conventional isothermal simulations shows that, counter to normal expectations, isothermal simulations can underpredict recovery by >10%.

  5. Hydrocarbon transfer pathways from Smackover source rocks to younger reservoir traps in the Monroe gas field, NE Louisiana

    SciTech Connect

    Zimmerman, R.K. )

    1993-09-01

    The Monroe gas field contained more than 7 tcf of gas in its virgin state. Much of the original gas reserves have been produced through wells penetrating the Upper Cretaceous Monroe Gas Rock Formation reservoir. Other secondary reservoirs in the field area are Eocene Wilcox, the Upper Cretaceous Arkadelphia, Nacatoch, Ozan, Lower Cretaceous, Hosston, Jurassic Schuler, and Smackover. As producing zones, these secondary producing zones reservoirs have contributed an insignificant amount gas to the field. The source of much of this gas appears to have been in the lower part of the Jurassic Smackover Formation. Maturation and migration of the hydrocarbons from a Smackover source into Upper Cretaceous traps was enhanced and helped by igneous activity, and wrench faults/unconformity conduits, respectively. are present in the pre-Paleocene section. Hydrocarbon transfer pathways appear to be more vertically direct in the Jurassic and Lower Cretaceous section than the complex pattern present in the Upper Cretaceous section.

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

    SciTech Connect

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

    1995-07-01

    The Frio Fluvial-Deltaic Sandstone Play of South Texas is one example of a mature play where reservoirs are being abandoned at high rates, potentially leaving behind significant unrecovered resources in untapped and incompletely drained reservoirs. Nearly 1 billion barrels of oil have been produced from Frio reservoirs since the 1940`s, yet more than 1.6 BSTB of unrecovered mobile oil is estimated to remain in the play. Frio reservoirs of the South Texas Gulf Coast are being studied to better characterize interwell stratigraphic heterogeneity in fluvial-deltaic depositional systems and determine controls on locations and volumes of unrecovered oil. Engineering data from fields throughout the play trend were evaluated to characterize variability exhibited by these heterogeneous reservoirs and were used as the basis for resource calculations to demonstrate a large additional oil potential remaining within the play. Study areas within two separate fields have been selected in which to apply advanced reservoir characterization techniques. Stratigraphic log correlations, reservoir mapping, core analyses, and evaluation of production data from each field study area have been used to characterize reservoir variability present within a single field. Differences in sandstone depositional styles and production behavior were assessed to identify zones with significant stratigraphic heterogeneity and a high potential for containing unproduced oil. Detailed studies of selected reservoir zones within these two fields are currently in progress.

  7. Formation evaluation and reservoir geology. 1995 SPE annual technical conference and exhibition

    SciTech Connect

    1995-12-31

    This document contains the proceedings of the Annual Technical Conference and Exhibition of the Society of Petroleum Engineers which was held on October 22-25, 1995 in Dallas, Texas. This volume contains the presentations regarding Formation Evaluation and Reservoir Geology. The topics covered in these presentations include: resource management and reservoir engineering of oil, natural gas and gas condensate fields, magnetic, electrical, and seismic surveys of reservoir rock, mathematical models and computerized simulation of fluid flow in reservoir rock, geochemistry of reservoir fluids, and enhanced recovery of oil and natural gas using waterflooding and other secondary recovery methods. Team approaches to reservoir characterization using geology, geophysics, and petroleum engineering are also described.

  8. The significance of 24-norcholestanes, triaromatic steroids and dinosteroids in oils and Cambrian-Ordovician source rocks from the cratonic region of the Tarim Basin, NW China

    USGS Publications Warehouse

    Li, Meijun; Wang, T.-G.; Lillis, Paul G.; Wang, Chunjiang; Shi, Shengbao

    2012-01-01

    Two oil families in Ordovician reservoirs from the cratonic region of the Tarim Basin are distinguished by the distribution of regular steranes, triaromatic steroids, norcholestanes and dinosteroids. Oils with relatively lower contents of C28 regular steranes, C26 20S, C26 20R + C27 20S and C27 20R regular triaromatic steroids, dinosteranes, 24-norcholestanes and triaromatic dinosteroids originated from Middle–Upper Ordovician source rocks. In contrast, oils with abnormally high abundances of the above compounds are derived from Cambrian and Lower Ordovician source rocks. Only a few oils have previously been reported to be of Cambrian and Lower Ordovician origin, especially in the east region of the Tarim Basin. This study further reports the discovery of oil accumulations of Cambrian and Lower Ordovician origin in the Tabei and Tazhong Uplifts, which indicates a potential for further discoveries involving Cambrian and Lower Ordovician sourced oils in the Tarim Basin. Dinosteroids in petroleum and ancient sediments are generally thought to be biomarkers for dinoflagellates and 24-norcholestanes for dinoflagellates and diatoms. Therefore, the abnormally high abundance of these compounds in extracts from the organic-rich sediments in the Cambrian and Lower Ordovician and related oils in the cratonic region of the Tarim Basin suggests that phytoplankton algae related to dinoflagellates have appeared and might have flourished in the Tarim Basin during the Cambrian Period. Steroids with less common structural configurations are underutilized and can expand understanding of the early development history of organisms, as well as define petroleum systems.

  9. Prediction of source rock characteristics based on terpane biomarkers in crude oils: a multivariate statistical approach

    SciTech Connect

    Zumberge, J.E.

    1987-06-01

    The distributions of eight tricyclic and eight pentacyclic terpanes were determined for 216 crude oils located worldwide with subsequent simultaneous RQ-mode factor analysis and stepwise discriminate analysis for the purpose of predicting source rock features or depositional environments. Five categories of source rock beds are evident: nearshore marine; deeper-water marine; lacustrine; phosphatic-rich source beds; and Ordovician age source rocks. The first two factors of the RQ-mode factor analysis describe 45 percent of the variation in the data set; the tricyclic terpanes appear to be twice as significant as pentacyclic terpanes in determining the variation among samples. Lacustrine oils are characterized by greater relative abundances of C/sub 21/ diterpane and gammacerane; nearshore marine sources by C/sub 19/ and C/sub 20/ diterpanes and oleanane; deeper-water marine facies by C/sub 24/ and C/sub 25/ tricyclic and C/sub 31/ plus C/sub 32/ extended hopanes; and Ordovician age oils by C/sub 27/ and C/sub 29/ pentacyclic terpanes. Although thermal maturity trends can be observed in factor space, the trends to do necessarily obscure the source rock interpretations. Also, since bacterial degradation of crude oils rarely affects tricyclic terpanes, biodegraded oils can be used in predicting source rock features. The precision to which source rock depositional environments are determined might be increased with the addition of other biomarker and stable isotope data using multivariate statistical techniques.

  10. WETTABILITY AND PREDICTION OF OIL RECOVERY FROM RESERVOIRS DEVELOPED WITH MODERN DRILLING AND COMPLETION FLUIDS

    SciTech Connect

    Jill S. Buckley; Norman R. Morrow

    2004-11-01

    Contamination of crude oils by surface-active agents from drilling fluids or other oil-field chemicals is more difficult to detect and quantify than bulk contamination with, for example, base fluids from oil-based muds. Bulk contamination can be detected by gas chromatography or other common analytical techniques, but surface-active contaminants can be influential at much lower concentrations that are more difficult to detect analytically, especially in the context of a mixture as complex as a crude oil. In this report we present a baseline study of interfacial tensions of 39 well-characterized crude oil samples with aqueous phases that vary in pH and ionic composition. This extensive study will provide the basis for assessing the effects of surface-active contaminant on interfacial tension and other surface properties of crude oil/brine/rock ensembles.

  11. WETTABILITY AND PREDICTION OF OIL RECOVERY FROM RESERVOIRS DEVELOPED WITH MODERN DRILLING AND COMPLETION FLUIDS

    SciTech Connect

    Jill S. Buckley; Norman R. Morrow

    2003-05-01

    This report summarizes the experimental results of some baseline imbibition tests on recovery of mineral oil at very strongly water wet conditions (VSWW) from sandstones with air permeability ranging from 80 to 360 md. Mixed wettability cores were prepared by adsorption from either Minnelusa or Gullfaks crude oil using either synthetic Minnelusa reservoir brine or sea water. Recovery of two synthetic-based mud (SBM) base oils, Petrofree(reg sign)SF and LVT 200 from mixed wettability cores gave results that correlated closely with results for refined oils with viscosities ranging from 3.8 to 84 cp. Two synthetic-based mud emulsifiers (LE SUPERMUL and EZ MUL(reg sign)NT) were added to mineral oil and tested for their effect on the wettability of MXW-F core samples as indicated by spontaneous imbibition. In both cases a significant decrease in water wetness was obtained.

  12. Investigation of biosurfactant-producing indigenous microorganisms that enhance residue oil recovery in an oil reservoir after polymer flooding.

    PubMed

    She, Yue-Hui; Zhang, Fan; Xia, Jing-Jing; Kong, Shu-Qiong; Wang, Zheng-Liang; Shu, Fu-Chang; Hu, Ji-Ming

    2011-01-01

    Three biosurfactant-producing indigenous microorganisms (XDS1, XDS2, XDS3) were isolated from a petroleum reservoir in the Daqing Oilfield (China) after polymer flooding. Their metabolic, biochemical, and oil-degradation characteristics, as well as their oil displacement in the core were studied. These indigenous microorganisms were identified as short rod bacillus bacteria with white color, round shape, a protruding structure, and a rough surface. Strains have peritrichous flagella, are able to produce endospores, are sporangia, and are clearly swollen and terminal. Bacterial cultures show that the oil-spreading values of the fermentation fluid containing all three strains are more than 4.5 cm (diameter) with an approximate 25 mN/m surface tension. The hydrocarbon degradation rates of each of the three strains exceeded 50%, with the highest achieving 84%. Several oil recovery agents were produced following degradation. At the same time, the heavy components of crude oil were degraded into light components, and their flow characteristics were also improved. The surface tension and viscosity of the crude oil decreased after being treated by the three strains of microorganisms. The core-flooding tests showed that the incremental oil recoveries were 4.89-6.96%. Thus, XDS123 treatment may represent a viable method for microbial-enhanced oil recovery. PMID:20652442

  13. Improved Oil Recovery in Fluvial Dominated Deltaic Reservoirs of Kansas - Near-Term

    SciTech Connect

    A. Walton; Don W. Green; G. Paul Whillhite; L. Schoeling; L. Watney; M. Michnick; R. Reynolds

    1997-07-15

    The objective of this project is to address waterflood problems of the type found in Morrow sandstone reservoirs in southwestern Kansas and in Cherokee Group reservoirs in southeastern Kansas. Two demonstration sites operated by different independent oil operators are involved in this project. The Stewart Field is located in Finney County, Kansas and is operated by North American Resources Company. The Nelson Lease is located in Allen County, Kansas, in the N.E. Savonburg Field and is operated by James E. Russell Petroleum, Inc. General topics to be addressed are 1) reservoir management and performance evaluation, 2) waterflood optimization, and 3) the demonstration of recovery processes involving off-the-shelf technologies which can be used to enhance waterflood recovery, increase reserves, and reduce the abandonment rate of these reservoir types. In the Stewart Project, the reservoir management portion of the project conducted during Budget Period 1 involved performance evaluation. This included 1) reservoir characterization and the development of a reservoir database, 2) volumetric analysis to evaluate production performance, 3) reservoir modeling, 4) laboratory work, 5) identification of operational problems, 6) identification of unrecovered mobile oil and estimation of recovery factors, and 7) identification of the most efficient and economical recovery process. To accomplish these objectives the initial budget period was subdivided into three major tasks. The tasks were 1) geological and engineering analysis, 2) laboratory testing, and 3) unitization. Due to the presence of different operators within the field, it was necessary to unitize the field in order to demonstrate a field-wide improved recovery process. This work was completed and the project moved into Budget Period 2. Budget Period 2 objectives consisted of the design, construction, and operation of a field-wide waterflood utilizing state-of-the-art, off-the-shelf technologies in an attempt to

  14. Potential Impacts of Leakage from Black Rock Reservoir on the Hanford Site Unconfined Aquifer: Initial Hypothetical Simulations of Flow and Contaminant Transport - Errata

    SciTech Connect

    Freedman, Vicky L.

    2007-04-30

    Errata for report documenting initial scoping calculations investigating the potential impacts on the Hanford unconfined aquifer resulting from leakage from the proposed Black Rock Reservoir to the west. These calculations were performed for the U.S. Bureau of Reclamation.

  15. The sequential method for the black-oil reservoir simulation on unstructured grids

    NASA Astrophysics Data System (ADS)

    Li, Baoyan; Chen, Zhangxin; Huan, Guanren

    2003-11-01

    This paper presents new results for applying the sequential solution method to the black-oil reservoir simulation with unstructured grids. The fully implicit solution method has been successfully applied to reservoir simulation with unstructured grids. However, the complexity of the fully implicit method and the irregularity of the grids result in a very complicated structure of linear equation systems (LESs) and in high computational cost to solve them. To tackle this problem, the sequential method is applied to reduce the size of the LESs. To deal with instable problems caused by the low implicit degree of this method, some practical techniques are introduced to control convergence of Newton-Raphson's iterations which are exploited in the linearization of the governing equations of the black-oil model. These techniques are tested with the benchmark problem of the ninth comparative solution project (CSP) organized by the society of petroleum engineers (SPE) and applied to field-scale models of both saturated and undersaturated reservoirs. The simulation results show that the sequential method uses as little as 20.01% of the memory for solving the LESs and 23.89% of the total computational time of the fully implicit method to reach the same precision for the undersaturated reservoirs, when the same iteration control parameters are used for both solution methods. However, for the saturated reservoirs, the sequential method must use stricter iteration control parameters to reach the same precision as the fully implicit method.

  16. Characterization of microbial diversity and community in water flooding oil reservoirs in China.

    PubMed

    Zhao, Lingxia; Ma, Ting; Gao, Mengli; Gao, Peike; Cao, Meina; Zhu, Xudong; Li, Guoqiang

    2012-10-01

    The diversity and distribution of bacterial and archaeal communities in four different water flooding oil reservoirs with different geological properties were investigated using 16S rDNA clone library construction method. Canonical correspondence analysis was used to analyze microbial community clustering and the correlation with environmental factors. The results indicated that the diversity and abundance in the bacterial communities were significantly higher than the archaeal communities, while both of them had high similarity within the communities respectively. Phylogenetic analysis showed that of compositions of bacterial communities were distinctly different both at phylum and genus level. Proteobacteria dominated in each bacterial community, ranging from 61.35 to 75.83 %, in which α-proteobacteria and γ-proteobacteria were the main groups. In comparison to bacterial communities, the compositions of archaeal communities were similar at phylum level, while varied at genus level, and the dominant population was Methanomicrobia, ranging from 65.91 to 92.74 % in the single oil reservoir. The factor that most significantly influenced the microbial communities in these reservoirs was found to be temperature. Other environmental factors also influenced the microbial communities but not significantly. It is therefore assumed that microbial communities are formed by an accumulated effect of several factors. These results are essential for understanding ecological environment of the water flooding oil reservoirs and providing scientific guidance to the performance of MEOR technology. PMID:22806743

  17. Transient groundwater observations and modelling at a rockslide in fractured rocks adjacent to a hydropower reservoir (Kaunertal valley, Austria)

    NASA Astrophysics Data System (ADS)

    Strauhal, Thomas; Zangerl, Christian; Loew, Simon; Holzmann, Michael; Perzlmaier, Sebastian

    2015-04-01

    Positive pore water pressure within the fractured network of a rock slope reduces the effective stresses. This makes the knowledge of transient pore pressure magnitudes essential to evaluate time-dependent hydro-mechanically coupled rock slope processes. Slowly moving, deep-seated rockslides are a common type of gravitational mass movements in fractured metamorphic rocks. The hydrogeological conditions in rockslides adjacent to hydropower reservoirs are of major interest given that several case studies document the hydro-mechanical coupling between seasonal variations in the rockslide deformation behaviour and the filling and drawing down of the reservoir and/or seasonal variations of pore water pressure due to rainfall-events and snowmelt. Groundwater flow and pore pressure distributions in deep-seated rockslides, composed of fractured rocks, are usually only described by simplified conceptual models because of a lack of field measurements and difficulties in transient numerical modelling. The heterogeneous degree of disintegration of the sliding mass, soil-like deformation zones and the anisotropic fractured bedrock complicate the hydrogeological measurement, interpretation and analysis. In this study, detailed hydrogeological analyses of the Klasgarten rockslide at the Gepatsch reservoir (Kaunertal valley, Austria) are presented. A focus is set on the impact of reservoir level fluctuations, groundwater recharge along the slope and drainage by an exploring adit. The effect of various hydrogeological properties of the sliding mass, the deformation zone and the fractured bedrock on the groundwater fluctuations is discussed. Information on the groundwater flow regime, hydraulic relevant material properties and pore water pressure data are gained from borehole based investigations, a subhorizontal exploring adit and laboratory tests. Field observations are interpreted and validated on the basis of two dimensional finite element groundwater modelling. The transient

  18. Increasing heavy oil reserves in the Wilmington Oil Field through advanced reservoir characterization and thermal production technologies. Annual report, March 30, 1995--March 31, 1996

    SciTech Connect

    1997-09-01

    The objective of this project is to increase heavy oil reserves in a portion of the Wilmington Oil Field, near Long Beach, California, by implementing advanced reservoir characterization and thermal production technologies. Based on the knowledge and experience gained with this project, these technologies are intended to be extended to other sections of the Wilmington Oil Field, and, through technology transfer, will be available to increase heavy oil reserves in other slope and basin clastic (SBC) reservoirs. The project involves implementing thermal recovery in the southern half of the Fault Block II-A Tar zone. The existing steamflood in Fault Block II-A has been relatively inefficient due to several producibility problems which are common in SBC reservoirs. Inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil, and nonuniform distribution of remaining oil have all contributed to poor sweep efficiency, high steam-oil ratios, and early steam breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated formation sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves. A suite of advanced reservoir characterization and thermal production technologies are being applied during the project to improve oi