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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. Brittleness index and seismic rock physics model for anisotropic tight-oil sandstone reservoirs

    NASA Astrophysics Data System (ADS)

    Huang, Xin-Rui; Huang, Jian-Ping; Li, Zhen-Chun; Yang, Qin-Yong; Sun, Qi-Xing; Cui, Wei

    2015-03-01

    Brittleness analysis becomes important when looking for sweet spots in tight-oil sandstone reservoirs. Hence, appropriate indices are required as accurate brittleness evaluation criteria. We construct a seismic rock physics model for tight-oil sandstone reservoirs with vertical fractures. Because of the complexities in lithology and pore structure and the anisotropic characteristics of tight-oil sandstone reservoirs, the proposed model is based on the solid components, pore connectivity, pore type, and fractures to better describe the sandstone reservoir microstructure. Using the model, we analyze the brittleness sensitivity of the elastic parameters in an anisotropic medium and establish a new brittleness index. We show the applicability of the proposed brittleness index for tight-oil sandstone reservoirs by considering the brittleness sensitivity, the rock physics response characteristics, and cross-plots. Compared with conventional brittleness indexes, the new brittleness index has high brittleness sensitivity and it is the highest in oil-bearing brittle zones with relatively high porosity. The results also suggest that the new brittleness index is much more sensitive to elastic properties variations, and thus can presumably better predict the brittleness characteristics of sweet spots in tight-oil sandstone reservoirs.

  5. 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.

  6. 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)

  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. 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.

  9. 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.

  10. 4D reservoir characterization using well log data for feasible CO2-enhanced oil recovery at Ankleshwar, Cambay Basin - A rock physics diagnostic and modeling approach

    NASA Astrophysics Data System (ADS)

    Ganguli, Shib Sankar; Vedanti, Nimisha; Dimri, V. P.

    2016-12-01

    In recent years, rock physics modeling has become an integral part of reservoir characterization as it provides the fundamental relationship between geophysical measurements and reservoir rock properties. These models are also used to quantify the effect of fluid saturation and stress on reservoir rocks by tracking the changes in elastic properties during production. Additionally, various rock physics models can be applied to obtain the information of rock properties away from existing drilled wells, which can play a crucial role in the feasibility assessment of CO2-enhanced oil recovery (EOR) operation at field. Thus, the objective of this study is to develop a rock-physics model of the Ankleshwar reservoir to predict the reservoir response under CO2-EOR. The Ankleshwar oil field is a mature field situated in Cambay Basin (Western India) that witnessed massive peripheral water flooding for around 40 years. Since the field was under water flooding for a long term, reasonable changes in reservoir elastic properties might have occurred. To identify potential reservoir zone with significant bypassed (or residual) oil saturation, we applied the diagnostic rock physics models to two available wells from the Ankleshwar oil field. The results clearly indicate transitions from clean sands to shaly sands at the base, and from sandy shale to pure shale at the top of the reservoir pay zone, suggesting a different seismic response at the top when compared to the base of the reservoir in both the wells. We also found that clay content and sorting affects the elastic properties of these sands, indicating different depositional scenario for the oil sands encountered in the Ankleshwar formation. Nevertheless, the rock physics template (RPT) analysis of the well data provides valuable information about the residual oil zone, a potential target for CO2-EOR. Further, a 4D reservoir characterization study has been conducted to assess the seismic detectability of CO2-EOR, and we

  11. 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.

  12. 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.

  13. 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.

  14. Reservoir microseismicity at the Ekofisk Oil Field

    SciTech Connect

    Rutledge, J.T.; Fairbanks, T.D.; Albright, J.N.; Boade, R.R.; Dangerfield, J.; Landa, G.H.

    1994-07-01

    A triaxial, downhole geophone was deployed within the Ekofisk oil reservoir for monitoring ambient microseismicity as a test to determine if microearthquake signals generated from discrete shear failure of the reservoir rock could be detected. The results of the test were positive. During 104 hours of monitoring, 572 discrete events were recorded which have been identified as shear-failure microearthquakes. Reservoir microseismicity was detected at large distances (1000 m) from the monitor borehole and at rates (> 5 events per hour) which may allow practical characterization of the reservoir rock and overburden deformation induced by reservoir pressure changes.

  15. Carboniferous and older carbonate rocks: Lithofacies, extent, and reservoir quality: Chapter CC in The oil and gas resource potential of the Arctic National Wildlife Refuge 1002 area, Alaska

    USGS Publications Warehouse

    Dumoulin, Julie A.

    1999-01-01

    -stem tests found locally reasonable flow rates (4,220-4,800 bpd) and, in the Flaxman Island area, recovered gas and condensate from these rocks. The Lisburne Group has produced up to 50,000 bbl of oil/ day from the Lisburne field at Prudhoe Bay. Reservoir parameters of the Lisburne in northeastern Alaska range from low (porosities ≤ 5% in most limestones) to good (porosities average 6.5-10% in some dolostones). Reservoir quality in Carboniferous and older carbonate strata in the 1002 area should be greatest where these rocks are highly fractured and (or) truncated by the Lower Cretaceous Unconformity.

  16. 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.

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

    NASA Astrophysics Data System (ADS)

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

    2016-12-01

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

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

    PubMed

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

    2016-12-15

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

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

    PubMed Central

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

    2016-01-01

    Current geological extraction theory and techniques are very limited to adequately characterize the unconventional oil-gas reservoirs because of the considerable complexity of the geological structures. Optical measurement has the advantages of non-interference with the earth magnetic fields, and is often useful in detecting various physical properties. One key parameter that can be detected using optical methods is the dielectric permittivity, which reflects the mineral and organic properties. Here we reported an oblique-incidence reflectivity difference (OIRD) technique that is sensitive to the dielectric and surface properties and can be applied to characterization of reservoir rocks, such as shale and sandstone core samples extracted from subsurface. The layered distribution of the dielectric properties in shales and the uniform distribution in sandstones are clearly identified using the OIRD signals. In shales, the micro-cracks and particle orientation result in directional changes of the dielectric and surface properties, and thus, the isotropy and anisotropy of the rock can be characterized by OIRD. As the dielectric and surface properties are closely related to the hydrocarbon-bearing features in oil-gas reservoirs, we believe that the precise measurement carried with OIRD can help in improving the recovery efficiency in well-drilling process. PMID:27976746

  20. 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.

  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. 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.

  6. 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.

  7. 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.

  8. 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.

  9. 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.

  10. 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.

  11. 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.

  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. Identification of clay minerals in reservoir rocks by FTIR spectroscopy

    NASA Astrophysics Data System (ADS)

    Cong Khang, Vu; Korovkin, Mikhail V.; Ananyeva, Ludmila G.

    2016-09-01

    Clay minerals including kaolinite, montmorillonite and bentonite in oil and gas reservoir rocks are identified by absorption spectra obtained via Fourier Transform Infrared (FTIR) spectroscopy. Bands around 3695, 3666, 3650 and 3630 cm-1 and bands around 3620 and 3400 cm-1 are the most diagnostically reliable for kaolinite and montmorillonite, respectively; also absorption bands in the region of 1200...955 cm-1 are equally diagnostic for all the clay minerals studied.

  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. 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.

  17. 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

  18. 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.

  19. 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.

  20. Compositional and black oil reservoir simulation

    SciTech Connect

    Coats, K.H.; Thomas, L.K.; Pierson, R.G.

    1995-12-31

    This paper describes a three-dimensional, three-phase reservoir simulation model for black oil and compositional applications. Both IMPES and fully implicit formulations are included. The model`s use of a relaxed volume balance concept effectively conserves both mass and volume and reduces Newton iterations. A new implicit well rate calculation method improves IMPES stability. It approximates wellbore crossflow effects with high efficiency and relative simplicity in both IMPES and fully implicit formulations. Multiphase flow in the tubing and near-well turbulent gas flow effects are treated implicitly. Initial saturations are calculated as a function of water-oil and gas-oil capillary pressures which are optimally dependent upon the Leverett J function or initial saturations may be entered as data arrays. A normalization of the relative permeability and capillary pressure curves is used to calculate these terms as a function of rock type and grid block residual saturations. Example problems are presented, including several of the SPE Comparative Solution problems and field simulations. 48 refs.

  1. 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.

    2015-11-05

    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).

  2. Visual display of reservoir parameters affecting enhanced oil recovery

    SciTech Connect

    Wood, J.R.

    1996-04-30

    This project consists of two parts. In Part 1, well logs, other well data, drilling, and production data for the Pioneer Field in the southern San Joaquin Valley of California were obtained, assembled, and input to a commercial relational database manager. These data are being used in PC-based geologic mapping, evaluation, and visualization software programs to produce 2-D and 3-D representations of the reservoir geometry, facies and subfacies, stratigraphy, porosity, oil saturation, and other measured and model parameters. Petrographic and petrophysical measurements made on samples from Pioneer Field, including core, cuttings and liquids, are being used to calibrate the log suite. In Part 2, these data sets are being used to develop algorithms to correlate log response to geologic and engineering measurements. Rock alteration due to interactions with hot fluids are being quantitatively modeled and used to predict the reservoir response if the rock were subjected to thermally enhanced oil recovery (TEOR).

  3. Development of heavy-oil reservoirs

    SciTech Connect

    Briggs, P.J.; Baron, R.P.; Fulleylove, R.J.; Wright, M.S.

    1988-02-01

    Although complex categorizations are in vogue, ''heavy oils'' can be defined simply in terms of their flow properties in the reservoir-e.g., a 100-cp (100-mPa.s) or greater viscosity. Such heavy oils are major world hydrocarbon resource that is exploited where indigenous demand exists. Efficient methods of production require enthalpy input to the reservoir by hot-fluid injection or by creation of heat in the reservoir. Heat losses must be minimized to achieve maximum production efficiency. The widely used cyclic-steam-injection process is examined analytically to indicate which parameters govern successful exploitation. Steamflood and in-situ combustion techniques are discussed with reference to recent developments. Heavy-oil recovery from the more difficult carbonate reservoirs, such as those of the Middle East, is reviewed and potential production mechanism are examined. Production techniques are described together with export handling schemes.

  4. 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.

  5. Hydrocarbon-water-rock interaction: Redox reaction as a mechanism for sandstone reservoir porosity enhancement

    SciTech Connect

    Shebl, M.A.; Surdam, R.C.

    1995-06-01

    Experiments evaluated the potential for and extent of oil-water-rock reactions in hydrocarbon reservoirs. Results indicate not only that significant potential exists for redox reactions between oxidized mineral phases and crude oil, but that such reactions can significantly alter porosity and permeability characteristics of an elastic hydrocarbon reservoir. The red (oxidized) sandstones used in the redox experiment initially contained 10 to 25% carbonate, anhydrite, and intergranular clay cements. Porosity ranged from 6 to 15%. The sandstones were gray or white after experimentation, and porosity increased 12 to 20% over original values, primarily due to carbonate dissolution. It is suggested that during the redox experiments, the iron oxides ({+-} sulphate) were reduced and hydrocarbon was oxidized to produce oxygenated organic compounds (e.g., organic acid anions, CO{sub 2}). These redox reaction products destabilized the carbonate cements and enhanced sandstone porosity. It is concluded that redox reactions involving crude oil and the mineral matrix of these reservoir rocks in the presence of H{sub 2}O do occur and may result in significantly enhanced porosity. Hydrocarbon emplacement and the resultant redox reactions can cause bleaching and changes in porosity and permeability. This relationship is well documented in the Wingate, White Rim, and Tensleep sandstones. The hydrocarbon reservoir units are white to gray and have good porosity and permeability. The adjacent non-reservoir units are red (due to hematite staining), and have good carbonate cementation and poor porosity and permeability, confining hydrocarbon flow to the nearby reservoir units or associated fractures.

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

    SciTech Connect

    Oltz, D.F.

    1991-04-10

    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.

  7. 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.

  8. Experimental Investigation on Oil Enhancement Mechanism of Hot Water Injection in tight reservoirs

    NASA Astrophysics Data System (ADS)

    Yongmao, Hao; Mingjing, Lu; Chengshun, Dong; Jianpeng, Jia; Yuliang, Su; Guanglong, Sheng

    2016-01-01

    Aimed at enhancing the oil recovery of tight reservoirs, the mechanism of hot water flooding was studied in this paper. Experiments were conducted to investigate the influence of hot water injection on oil properties, and the interaction between rock and fluid, petrophysical property of the reservoirs. Results show that with the injected water temperature increasing, the oil/water viscosity ratio falls slightly in a tight reservoir which has little effect on oil recovery. Further it shows that the volume factor of oil increases significantly which can increase the formation energy and thus raise the formation pressure. At the same time, oil/water interfacial tension decreases slightly which has a positive effect on production though the reduction is not obvious. Meanwhile, the irreducible water saturation and the residual oil saturation are both reduced, the common percolation area of two phases is widened and the general shape of the curve improves. The threshold pressure gradient that crude oil starts to flow also decreases. It relates the power function to the temperature, which means it will be easier for oil production and water injection. Further the pore characteristics of reservoir rocks improves which leads to better water displacement. Based on the experimental results and influence of temperature on different aspects of hot water injection, the flow velocity expression of two-phase of oil and water after hot water injection in tight reservoirs is obtained.

  9. Application of oil gas-chromatography in reservoir compartmentalization in a mature Venezuelan oil field

    SciTech Connect

    Munoz, N.G.; Mompart, L.; Talukdar, S.C.

    1996-08-01

    Gas chromatographic oil {open_quotes}fingerprinting{close_quotes} was successfully applied in a multidisciplinary production geology project by Maraven, S.A. to define the extent of vertical and lateral continuity of Eocene and Miocene sandstone reservoirs in the highly faulted Bloque I field, Maracaibo Basin, Venezuela. Seventy-five non-biodegraded oils (20{degrees}-37.4{degrees} API) were analyzed with gas chromatography. Fifty were produced from the Eocene Misoa C-4, C-5, C-6 or C-7 horizons, fifteen from the Miocene basal La Rosa and ten from multizone completions. Gas chromatographic and terpane and sterane biomarker data show that all of the oils are genetically related. They were expelled from a type II, Upper Cretaceous marine La Luna source rock at about 0.80-0.90% R{sub o} maturity. Alteration in the reservoir by gas stripping with or without subsequent light hydrocarbons mixing was observed in some oils. Detailed chromatographic comparisons among the oils shown by star plots and cluster analysis utilizing several naphthenic and aromatic peak height ratios, resulted in oil pool groupings. This led to finding previously unknown lateral and vertical reservoir communication and also helped in checking and updating the scaling character of faults. In the commingled oils, percentages of each contributing zone in the mixture were also determined giving Maraven engineers a proven, rapid and inexpensive tool for production allocation and reservoir management The oil pool compartmentalization defined by the geochemical fingerprinting is in very good agreement with the sequence stratigraphic interpretation of the reservoirs and helped evaluate the influence of structure in oil migration and trapping.

  10. 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.

  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. 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.

  13. 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

  14. IMPROVING CO2 EFFICIENCY FOR RECOVERING OIL IN HETEROGENEOUS RESERVOIRS

    SciTech Connect

    Reid B. Grigg; Robert K. Svec; Zheng-Wen Zeng; Liu Yi; Baojun Bai

    2004-03-27

    A three-year contract for the project, DOE Contract No. DE-FG26-01BC15364, ''Improving CO{sub 2} Efficiency for Recovering Oil in Heterogeneous Reservoirs'', was started on September 28, 2001. This project examines three major areas in which CO{sub 2} flooding can be improved: fluid and matrix interactions, conformance control/sweep efficiency, and reservoir simulation for improved oil recovery. The project has received a one-year, no-cost extension to September 27, 2005. During this extra time additional deliverables will be (1) the version of MASTER that has been debugged and a foam option added for CO{sub 2} mobility control and (2) adsorption/desorption data on pure component minerals common in reservoir rock that will be used to improve predictions of chemical loss to adsorption in reservoirs. This report discusses the activity during the six-month period covering October 1, 2003 through March 31, 2004 that comprises the first and second fiscal quarters of the project's third year. During this period of the project several areas have advanced: reservoir fluid/rock interactions and their relationships to changing injectivity, and surfactant adsorption on quarried core and pure component granules, foam stability, and high flow rate effects. Presentations and papers included: a papers covered in a previous report was presented at the fall SPE ATCE in Denver in October 2003, a presentation at the Southwest ACS meeting in Oklahoma City, presentation on CO{sub 2} flood basic behavior at the Midland Annual CO{sub 2} Conference December 2003; two papers prepared for the biannual SPE/DOE Symposium on IOR, Tulsa, April 2004; one paper accepted for the fall 2004 SPE ATCE in Houston; and a paper submitted to an international journal Journal of Colloid and Interface Science which is being revised after peer review.

  15. 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.

  16. 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.

  17. 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.

  18. 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.

  19. 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.

  20. Reservoir modeling of the Phase II Hot Dry Rock System

    SciTech Connect

    Zyvoloski, G.

    1984-01-01

    The Phase II system has been created with a series of hydraulic fracturing experiments at the Fenton Hill Hot Dry Rock site. Experiment 2032, the largest of the fracturing operations, involved injecting 5.6 million gallons (21,200m/sup 3/) of water into wellbore EE-2 over the period December 6-9, 1983. The experiment has been modeled using geothermal simulator FEHM developed at Los Alamos National Laboratory. The modeling effort has produced strong evidence of a large highly fractured reservoir. Two long term heat extraction schemes for the reservoir are studied with the model.

  1. 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

  2. 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.

  3. 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.

  4. 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.

  5. CO2 wettability of seal and reservoir rocks and the implications for carbon geo-sequestration

    NASA Astrophysics Data System (ADS)

    Iglauer, Stefan; Pentland, C. H.; Busch, A.

    2015-01-01

    We review the literature data published on the topic of CO2 wettability of storage and seal rocks. We first introduce the concept of wettability and explain why it is important in the context of carbon geo-sequestration (CGS) projects, and review how it is measured. This is done to raise awareness of this parameter in the CGS community, which, as we show later on in this text, may have a dramatic impact on structural and residual trapping of CO2. These two trapping mechanisms would be severely and negatively affected in case of CO2-wet storage and/or seal rock. Overall, at the current state of the art, a substantial amount of work has been completed, and we find that: Sandstone and limestone, plus pure minerals such as quartz, calcite, feldspar, and mica are strongly water wet in a CO2-water system. Oil-wet limestone, oil-wet quartz, or coal is intermediate wet or CO2 wet in a CO2-water system. The contact angle alone is insufficient for predicting capillary pressures in reservoir or seal rocks. The current contact angle data have a large uncertainty. Solid theoretical understanding on a molecular level of rock-CO2-brine interactions is currently limited. In an ideal scenario, all seal and storage rocks in CGS formations are tested for their CO2 wettability. Achieving representative subsurface conditions (especially in terms of the rock surface) in the laboratory is of key importance but also very challenging.

  6. Petroleum potentialities of central Tunisia as deduced from identification and characterization of oil source rocks

    SciTech Connect

    Saidi, M.; Acheche, M.H.; Inoubli, H. ); Belayouni, H. )

    1991-08-01

    Many potential oil source rocks occur within the Tunisian stratigraphic column, including Silurian-Devonian shales, Albian and upper Albian-Vraconian carbonates, Cenomanian-Turonian black shales and lower Eocene carbonates. This focuses on the inventory of potential oil source rocks in central Tunisia ranging from middle Jurassic to Turonian. The emphasis is on determining their genetic potential and whether they could have generated oil and gas. Geochemical data obtained from the analysis of at least 2,147 samples show this region to be of significant interest as a petroleum prospective area. The main source rocks identified are Toarcian shales, upper Albian-Vraconian carbonates and Cenomanian-Turonian black shales. They contain predominantly type 2 organic matter (oil and gas prone) and are at the low maturity limit of the oil window. The occurrence of those source rocks close to numerous potential reservoir facies supports the conclusion that central Tunisia is a very interesting area for petroleum exploration.

  7. 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.

  8. Pyritization effect on well logging parameters in Jurassic reservoirs within S-E Western Siberian oil fields

    NASA Astrophysics Data System (ADS)

    Janishevskii, A.; Ten, T.; Ezhova, A.

    2016-09-01

    Authigenic sulfide mineralization in hydrocarbon-saturated reservoirs distorts the electrical and density properties of rocks. The correlation between volumetric density, electro-conductive minerals and open porosity in 300 samples were determined. This fact made it possible to develop a nomograph in evaluating oil saturated reservoirs and could be applied in well geophysical survey data interpretation.

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

    SciTech Connect

    Stephen C. Ruppel

    2003-01-01

    Excellent progress has been made on all project objectives and goals. All tasks have been completed in the Phase 1 study area, the initial area of project focus. Primary elements of this work include the following: The stratigraphic architecture has been established through correlation of wireline logs guided by core and outcrop studies of facies and cyclicity. A porosity model has been developed that creates a basis for calculation of porosity for wells in the study area. Rock fabrics have been defined by sampling, analysis, and description of cores and used to create transforms for calculating permeability and oil saturation from porosity data. Finally, a preliminary 3-D model has been constructed that incorporates stratigraphic architecture, rock-fabric data, and petrophysical data. Reservoir volumetrics calculated from the model show that a very large fraction of the original oil in place remains.

  10. 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

  11. 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.

  12. 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

  13. 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.

  14. 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

  15. 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.

  16. 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

  17. 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

  18. 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.

  19. 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.

  20. Reservoir monitoring of enhanced oil recovery using marine CSEM methods

    NASA Astrophysics Data System (ADS)

    Black, N.; Wilson, G. A.; Zhdanov, M. S.

    2009-12-01

    Effective reservoir management requires time-lapse reservoir information throughout the interwell volume. The use of seismic data for monitoring is very challenging because of the small variation of seismic velocities over time, and of the difficulty of survey repeatability. At the same time, significant differences in the resistivities of oil and the water filling the reservoir during production allows for the possibility to monitor the flooding front by electromagnetic (EM) methods. In this paper, we perform a recoverability analysis of reservoir properties using marine controlled-source electromagnetic (MCSEM) methods. We compute the EM fields for models of partially depleted reservoirs representing different positions of the oil-water contact over time. The oil-water contact can be clearly seen in several field components, even with the presence of bathymetry. Our analysis demonstrates that MCSEM data can provide an accurate position of the oil-water contact inside the reservoir over time.

  1. Oil-source correlation for the paleo-reservoir in the Majiang area and remnant reservoir in the Kaili area, South China

    NASA Astrophysics Data System (ADS)

    Fang, Yunxin; Liao, Yuhong; Wu, Liangliang; Geng, Ansong

    2011-05-01

    There are different viewpoints on the oil-source correlation of the Majiang paleo-reservoir and the neighbouring Kaili remnant reservoir in the Southern Guizhou Depression of China. Three potential source rocks in this depression could be inferred: the Lower-Cambrian marine mudstone, Lower-Silurian shale and Lower-Permian mudstone. Most of the potential source rocks are of high maturity. The solid bitumens and oil seepages in the Southern Guizhou Depression suffered severe secondary alterations, such as thermal degradation and biodegradation. The solid bitumens of the Majiang paleo-reservoir are also of high maturity. The oil seepages and soft bitumen of the Kaili remnant reservoir were severely biodegraded. All these secondary alterations may obscure oil-source correlations by routine biomarkers. Thus, it is very important to select appropriate biomarker parameters for the oil-source correlation. In this work, biomarkers resistant to thermal degradation and biodegradation and the data of organic carbon isotopic compositions were used for the correlation. The δ 13C values of n-alkanes in asphaltene pyrolysates were also used to make oil-oil and oil-source correlations between severely biodegraded oils. The results indicate that the Lower-Cambrian marine mudstones are the main source for the Ordovician-Silurian (O-S) solid bitumens of the Majiang area and the Ordovician-Silurian oil seepages and soft bitumens of the Kaili area. Remnant reservoir in the eastern Kaili area might have been charged at least twice by the oil generated from the Lower-Cambrian marine source rocks.

  2. 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

  3. 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.

  4. 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.

  5. 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.

  6. Development of Porosity Measurement Method in Shale Gas Reservoir Rock

    NASA Astrophysics Data System (ADS)

    Siswandani, Alita; Nurhandoko, BagusEndar B.

    2016-08-01

    The pore scales have impacts on transport mechanisms in shale gas reservoirs. In this research, digital helium porosity meter is used for porosity measurement by considering real condition. Accordingly it is necessary to obtain a good approximation for gas filled porosity. Shale has the typical effective porosity that is changing as a function of time. Effective porosity values for three different shale rocks are analyzed by this proposed measurement. We develop the new measurement method for characterizing porosity phenomena in shale gas as a time function by measuring porosity in a range of minutes using digital helium porosity meter. The porosity of shale rock measured in this experiment are free gas and adsorbed gas porosoty. The pressure change in time shows that porosity of shale contains at least two type porosities: macro scale porosity (fracture porosity) and fine scale porosity (nano scale porosity). We present the estimation of effective porosity values by considering Boyle-Gay Lussaac approximation and Van der Waals approximation.

  7. 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.

  8. 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.

  9. 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.

  10. 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.

  11. 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.

  12. 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.

  13. 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.

  14. Characterization of oil and gas reservoir heterogeneity. [Quarterly report], January 1, 1993--March 31, 1993

    SciTech Connect

    Sharma, G.D.

    1993-04-01

    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.

  15. 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

  16. 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

  17. 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

  18. Microbial enhancement of oil production from carbonate reservoirs

    SciTech Connect

    Tanner, R.S.; Knapp, R.M.; McInerney, M.J.; Udegbunam, E.O.

    1991-01-01

    The goal of this work is to evaluate the potential for Microbial Enhanced Oil Recovery (MEOR) in carbonate reservoirs. Specific objectives include: review of the literature pertinent to MEOR in carbonate reservoirs, a study of the microbial ecology of carbonate reservoirs, isolation of microorganisms and their end-products of metabolism on carbonate pore structure, the recovery of residual oil from carbonates in model core systems, and development of models to examine and predict MEOR processes in carbonate reservoirs. 1 ref., 3 figs., 1 tab.

  19. 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.

  20. 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.

  1. 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.

  2. 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

  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; 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

  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; 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

  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 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

  6. Pore Type Classification on Carbonate Reservoir in Offshore Sarawak using Rock Physics Model and Rock Digital Images

    NASA Astrophysics Data System (ADS)

    Lubis, L. A.; Harith, Z. Z. T.

    2014-03-01

    It has been recognized that carbonate reservoirs are one of the biggest sources of hydrocarbon. Clearly, the evaluation of these reservoirs is important and critical. For rigorous reservoir characterization and performance prediction from geophysical measurements, the exact interpretation of geophysical response of different carbonate pore types is crucial. Yet, the characterization of carbonate reservoir rocks is difficult due to their complex pore systems. The significant diagenesis process and complex depositional environment makes pore systems in carbonates far more complicated than in clastics. Therefore, it is difficult to establish rock physics model for carbonate rock type. In this paper, we evaluate the possible rock physics model of 20 core plugs of a Miocene carbonate platform in Central Luconia, Sarawak. The published laboratory data of this area were used as an input to create the carbonate rock physics models. The elastic properties were analyzed to examine the validity of an existing analytical carbonate rock physics model. We integrate the Xu-Payne Differential Effective Medium (DEM) Model and the elastic modulus which was simulated from a digital carbonate rock image using Finite Element Modeling. The results of this integration matched well for the separation of carbonate pore types and sonic P-wave velocity obtained from laboratory measurement. Thus, the results of this study show that the integration of rock digital image and theoretical rock physics might improve the elastic properties prediction and useful for more advance geophysical techniques (e.g. Seismic Inversion) of carbonate reservoir in Sarawak.

  7. 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).

  8. 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

  9. Crude-oil biodegradation via methanogenesis in subsurface petroleum reservoirs.

    PubMed

    Jones, D M; Head, I M; Gray, N D; Adams, J J; Rowan, A K; Aitken, C M; Bennett, B; Huang, H; Brown, A; Bowler, B F J; Oldenburg, T; Erdmann, M; Larter, S R

    2008-01-10

    Biodegradation of crude oil in subsurface petroleum reservoirs has adversely affected the majority of the world's oil, making recovery and refining of that oil more costly. The prevalent occurrence of biodegradation in shallow subsurface petroleum reservoirs has been attributed to aerobic bacterial hydrocarbon degradation stimulated by surface recharge of oxygen-bearing meteoric waters. This hypothesis is empirically supported by the likelihood of encountering biodegraded oils at higher levels of degradation in reservoirs near the surface. More recent findings, however, suggest that anaerobic degradation processes dominate subsurface sedimentary environments, despite slow reaction kinetics and uncertainty as to the actual degradation pathways occurring in oil reservoirs. Here we use laboratory experiments in microcosms monitoring the hydrocarbon composition of degraded oils and generated gases, together with the carbon isotopic compositions of gas and oil samples taken at wellheads and a Rayleigh isotope fractionation box model, to elucidate the probable mechanisms of hydrocarbon degradation in reservoirs. We find that crude-oil hydrocarbon degradation under methanogenic conditions in the laboratory mimics the characteristic sequential removal of compound classes seen in reservoir-degraded petroleum. The initial preferential removal of n-alkanes generates close to stoichiometric amounts of methane, principally by hydrogenotrophic methanogenesis. Our data imply a common methanogenic biodegradation mechanism in subsurface degraded oil reservoirs, resulting in consistent patterns of hydrocarbon alteration, and the common association of dry gas with severely degraded oils observed worldwide. Energy recovery from oilfields in the form of methane, based on accelerating natural methanogenic biodegradation, may offer a route to economic production of difficult-to-recover energy from oilfields.

  10. Characterization of thermophilic consortia from two souring oil reservoirs

    SciTech Connect

    Mueller, R.F.; Nielsen P.H.

    1996-09-01

    Contamination of crude oil and fuel gas with hydrogen sulfide decreases the value of the product and increases refining costs. Injection of seawater into oil field reservoirs for secondary oil recovery is a common practice. However, seawater contains sulfate and other substances essential for bacterial growth, eventually growth requirements of sulfate-reducing bacteria; are met, resulting in the production of hydrogen sulfide. This paper presents results on substrate characterization for microbial consortia from two oil field reservoirs at a temperature range of 35 to 75 C. The competition of sulfate-reducing bacteria and other groups of microorganisms is discussed. 38 refs., 3 figs., 3 tabs.

  11. 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.

  12. 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.

  13. 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.

  14. 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.

  15. 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

  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. 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

  18. Dynamic rock fragmentation: oil shale applications

    SciTech Connect

    Boade, R. R.; Grady, D. E.; Kipp, M. E.

    1980-01-01

    Explosive rock fragmentation techniques used in many resource recovery operations have in the past relied heavily upon traditions of field experience for their design. As these resources, notably energy resources, become less accessible, it becomes increasingly important that fragmentation techniques be optimized and that methods be developed to effectively evaluate new or modified explosive deployment schemes. Computational procedures have significant potential in these areas, but practical applications must be preceded by a thorough understanding of the rock fracture phenomenon and the development of physically sound computational models. This paper presents some of the important features of a rock fragmentation model that was developed as part of a program directed at the preparation of subterranean beds for in situ processing of oil shale. The model, which has been implemented in a two-dimensional Lagrangian wavecode, employs a continuum damage concept to quantify the degree of fracturing and takes into account experimental observations that fracture strength and fragment dimensions depend on tensile strain rates. The basic premises of the model are considered in the paper as well as some comparisons between calculated results and observations from blasting experiments.

  19. 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.

  20. 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

  1. 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.

  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. 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.

  4. Vertical distribution of the subsurface microorganisms in Sagara oil reservoir

    NASA Astrophysics Data System (ADS)

    Nunoura, T.; Oida, H.; Masui, N.; Ingaki, F.; Takai, K.; Nealson, K. H.; Horikoshi, K.

    2002-12-01

    The recent microbiological studies reported that active microbial habitat for methanogen, sulfate reducers (Archaeoglobus, d-Proteobacteria, gram positives), fermenters (Thermococcus, Thermotogales, gram positives etc.) and other heterotrophs (g-Proteobacteria etc.) are in subsurface petroleum oil reservoirs. However, microbial distribution at vertical distances in depth has not been demonstrated since the samples in previous studies are only to use oil and the formation water. Here, we show the vertical profile of microbial community structure in Japanese terrestrial oil reservoir by a combination of molecular ecological analyses and culture dependent studies. The sequential WRC (Whole Round Core) samples (200 mbsf) were recovered from a drilling project for Sagara oil reservoir, Shizuoka Prefecture, Japan, conducted in Jar. -Mar. 2002. The lithology of the core samples was composed of siltstone, sandstone, or partially oil containing sand. The major oil components were gasoline, kerosene and light oil, that is a unique feature observed in the Sagara oil reservoir. The direct count of DAPI-stained cells suggested that the biomass was relatively constant, 1.0x104cells/g through the core of the non-oil layers, whereas the oil-bearing layers had quite higher population density at a range of 1.0x105 ? 3.7x107cells/g. The vertical profile of microbial community structures was analyzed by the sequence similarity analysis, phylogenetic analysis and T-RFLP fingerprinting of PCR-amplified 16S rDNA. From bacterial rDNA clone libraries, most of the examined rDNA were similar with the sequence of genera Pseudomanas, Stenotrophomonas and Sphingomonas within g-Proteobacteria. Especially, Pseudomonas stutzeri was predominantly present in all oil-bearing layers. From archaeal rDNA clone libraries, all rDNA clone sequences were phylogenetically associated with uncultured soil group in Crenarchaeota. We detected none of the sequences of sulfate reducers, sulfur dependent fermenters

  5. 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.

  6. 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.

  7. China onshore heavy oil reservoir features and new recovery measures

    SciTech Connect

    Naiju Wang

    1995-12-31

    China is known as being rich in onshore heavy oil resources, with a variety of reservoir characteristics, and complex conditions for thermal recoveries. Over the past decade, with improvement in technology, the scale of heavy oil production has continually expanded, and China has now become one of the major heavy oil producing countries in the world. To date, a complete set of techniques associated with huff and puff processes has been developed with some unique features. This paper analyzes several problems inherent in heavy oil development, and presents technical measures for the future development of heavy oil.

  8. 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

  9. 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.

  10. 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.

  11. 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.

  12. Oil reservoir properties estimation using neural networks

    SciTech Connect

    Toomarian, N.B.; Barhen, J.; Glover, C.W.; Aminzadeh, F.

    1997-02-01

    This paper investigates the applicability as well as the accuracy of artificial neural networks for estimating specific parameters that describe reservoir properties based on seismic data. This approach relies on JPL`s adjoint operators general purpose neural network code to determine the best suited architecture. The authors believe that results presented in this work demonstrate that artificial neural networks produce surprisingly accurate estimates of the reservoir parameters.

  13. 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

  14. Isotopic insights into microbial sulfur cycling in oil reservoirs.

    PubMed

    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.

  15. 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

  16. 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

  17. 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.

  18. 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.

  19. 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.

  20. 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.

  1. 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.

  2. 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

  3. Acid Fluid-Rock Interactions with Shales Comprising Unconventional Hydrocarbon Reservoirs and with Shale Capping Carbon Storage Reservoirs: Experimental Insights

    NASA Astrophysics Data System (ADS)

    Kaszuba, J. P.; Bratcher, J.; Marcon, V.; Herz-Thyhsen, R.

    2015-12-01

    Injection of HCl is often a first stage in the hydraulic fracturing process. These acidic fluids react with marls or shales in unconventional reservoirs, reactions generally comparable to reaction between shale caprocks and acidic, carbonated formation waters in a carbon storage reservoir. Hydrothermal experiments examine acid fluid-rock interaction with 1) an unconventional shale reservoir and 2) a model shale capping a carbon storage reservoir. In the former, unconventional reservoir rock and hydraulic fracturing fluid possessing a range of ionic strengths (I = 0.01, 0.15) and initial pH values (2.5 and 7.3) reacted at 115°C and 35 MPa for 28 days. In the latter, a model carbon storage reservoir (Fe-rich dolomite), shale caprock (illite), and shale-reservoir mixture each reacted with formation water (I = 0.1 and pH 6.3) at 160°C and 25 MPa for ~15 days. These three experiments were subsequently injected with sufficient CO2 to maintain CO2 saturation in the water and allowed to react for ~40 additional days. Acidic frac fluid was rapidly buffered (from pH 2.5 to 6.2 after 38 hrs) by reaction with reservoir rock whereas the pH of near-neutral frac fluid decreased (from 7.3 to 6.9) after 47 hrs. Carbonate dissolution released Ca and Sr into solution and feldspar dissolution released SiO2 and Li; the extent of reaction was greater in the experiment containing acidic frac fluid. All three carbon storage experiments displayed a similar pH decrease of 1.5 units after the addition of CO2. The pH remained low for the duration of the experiments because the immiscible supercritical CO2 phase provided an infinite reservoir of carbonic acid that could not be consumed by reaction with the rock. In all three experiments, Ca, Fe, Mg, Mn and SO4 increase with injection, but slowly decline through termination of the experiments. This trend suggests initial dissolution followed by re-precipitation of carbonates, which can be seen in modeling and SEM results. New clay minerals

  4. 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.

  5. 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.

  6. 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.

  7. 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.

  8. Carbon dioxide concentration dictates alternative methanogenic pathways in oil reservoirs.

    PubMed

    Mayumi, Daisuke; Dolfing, Jan; Sakata, Susumu; Maeda, Haruo; Miyagawa, Yoshihiro; Ikarashi, Masayuki; Tamaki, Hideyuki; Takeuchi, Mio; Nakatsu, Cindy H; Kamagata, Yoichi

    2013-01-01

    Deep subsurface formations (for example, high-temperature oil reservoirs) are candidate sites for carbon capture and storage technology. However, very little is known about how the subsurface microbial community would respond to an increase in CO2 pressure resulting from carbon capture and storage. Here we construct microcosms mimicking reservoir conditions (55 °C, 5 MPa) using high-temperature oil reservoir samples. Methanogenesis occurs under both high and low CO2 conditions in the microcosms. However, the increase in CO2 pressure accelerates the rate of methanogenesis to more than twice than that under low CO2 conditions. Isotope tracer and molecular analyses show that high CO2 conditions invoke acetoclastic methanogenesis in place of syntrophic acetate oxidation coupled with hydrogenotrophic methanogenesis that typically occurs in this environment (low CO2 conditions). Our results present a possibility of carbon capture and storage for enhanced microbial energy production in deep subsurface environments that can mitigate global warming and energy depletion.

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

    NASA Astrophysics Data System (ADS)

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

    2013-12-01

    Accessory minerals in carbonate reservoirs, and in the caprocks that seal these reservoirs, can provide insight into multiphase fluid (CO2 + H2O)-rock interactions and the behavior of CO2 that resides in these water-rock systems. Our program integrates field data, hydrothermal experiments, and geochemical modeling to evaluate CO2-water-rock reactions and processes in a variety of carbonate reservoirs in the Rocky Mountain region of the US. These studies provide insights into a wide range of geologic environments, including natural CO2 reservoirs, geologic carbon sequestration, engineered geothermal systems, enhanced oil and gas recovery, and unconventional hydrocarbon resources. One suite of experiments evaluates the Madison Limestone on the Moxa Arch, Southwest Wyoming, a sulfur-rich natural CO2 reservoir. Mineral textures and geochemical features developed in the experiments suggest that carbonate minerals which constitute the natural reservoir will initially dissolve in response to emplacement of CO2. Euhedral, bladed anhydrite concomitantly precipitates in response to injected CO2. Analogous anhydrite is observed in drill core, suggesting that secondary anhydrite in the natural reservoir may be related to emplacement of CO2 into the Madison Limestone. Carbonate minerals ultimately re-precipitate, and anhydrite dissolves, as the rock buffers the acidity and reasserts geochemical control. Another suite of experiments emulates injection of CO2 for enhanced oil recovery in the Desert Creek Limestone (Paradox Formation), Paradox Basin, Southeast Utah. Euhedral iron oxyhydroxides (hematite) precipitate at pH 4.5 to 5 and low Eh (approximately -0.1 V) as a consequence of water-rock reaction. Injection of CO2 decreases pH to approximately 3.5 and increases Eh by approximately 0.1 V, yielding secondary mineralization of euhedral pyrite instead of iron oxyhydroxides. Carbonate minerals also dissolve and ultimately re-precipitate, as determined by experiments in the

  10. 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.

  11. 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.

  12. 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

  13. 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.

  14. 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.

  15. 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.

  16. Visco-plastic properties of organic-rich shale gas reservoir rocks and its implication for stress variations within reservoirs

    NASA Astrophysics Data System (ADS)

    Sone, H.; Zoback, M. D.

    2011-12-01

    We are studying the time-dependent deformational properties of shale gas reservoir rocks through laboratory creep experiments in a triaxial deformation apparatus under room temperature and room humidity conditions. Samples come from the Barnett shale (TX), Eagle Ford shale (TX), Haynesville shale (LA), and Fort St. John shale (Canada). The clay and carbonate content of these shales vary markedly, as well as the total organic content. To cover effective pressures both below and above in-situ conditions, confining pressures were between 10-60 MPa. In order to examine creep processes unrelated to pre-failure crack growth, differential stresses during creep were kept below 50% of the ultimate rock strength. Time dependent creep at constant differential stress increases with clay content (regardless of the carbonate content) and there is a pronounced increase in amount of creep at around 35-40% clay content. The amount of creep strain is relatively insensitive to both the confining pressure and differential pressure. More creep occurs in the bedding-perpendicular direction than the bedding-parallel direction, which correlates with the sample's elastic anisotropy. The constitutive law governing the time-dependent deformation of these rocks is visco-plastic, and creep strain is well-approximated by a power-law function of time within the time scales of the experiment (maximum of 2 weeks). Also an oven-dried sample exhibited much less creep, which suggests that the physical mechanism of the creep is likely a hydrolytically-assisted plastic deformation process. Interpretation of the results through visco-elastic theory shows that the power law exponents of these rocks, which reflects how rapid a rock creeps or relaxes stress, vary between 0.01-0.07. Based on these numbers, we can roughly calculate the visco-elastic accumulation of differential stresses within these reservoirs, by assuming a constant intraplate tectonic strain rate (10^-19 - 10^-17) and by considering the

  17. 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.

  18. 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

  19. 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.

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

    NASA Astrophysics Data System (ADS)

    Reyer, D.; Philipp, S. L.

    2012-04-01

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

  1. Modeling naturally fractured reservoirs: From experimental rock mechanics to flow simulation

    NASA Astrophysics Data System (ADS)

    Rijken, Margaretha Catharina Maria

    Fractures have a big impact on reservoir production but are inherently difficult to quantify. This study gives a robust and practical workflow to obtain a mechanically consistent naturally fractured reservoir model without direct sampling of the fracture network. The three tiers of the workflow are: (1) subcritical testing, (2) geomechanical modeling, and (3) flow modeling. Subcritical fracture index, a rock property, has been shown to influence fracture attributes such as length, spacing and connectivity. Subcritical tests show that the average subcritical index for sandstones in ambient air is around 62, whereas the average value for microstructurally comparable carbonates samples is 120. Thin-section analysis shows that an increase in cement content increases the subcritical index. Furthermore, sandstone samples containing more than 15% carbonate cement, sandstone samples containing more than 40% clay, and pure carbonate samples exhibit a large drop in subcritical index when the environment is changed from ambient air or oil to fresh water or brine. Geomechanical modeling has shown that the mechanical bed thickness has a large influence on fracture pattern characteristics and has the potential to overshadow fracture pattern changes due to strain level, strain anisotropy and subcritical index. Furthermore, an increase in strain anisotropy reduces the number of dominant through-going fracture sets and decreases the fracture spacing between the through-going fractures. This spacing variation not only influences the preferential drainage direction, it can also enhance the drainage efficiency, because more rock is exposed to the through-going fractures which are more likely to be intersected by a borehole. The level of detail provided by the geomechanical model greatly exceeds the level of detail normally used in reservoir simulation. Therefore, upscaling of the geomechanically generated fracture patterns is necessary for practical flow modeling. This study shows

  2. 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

  3. 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.

  4. 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

  5. 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.

  6. Laboratory investigation of steam adsorption in geothermal reservoir rocks

    SciTech Connect

    Luetkehans, J.

    1988-02-01

    Some vapor-dominated geothermal reservoirs and low-permeability gas reservoirs exhibit anomalous behavior that may be caused by surface adsorption. For example, geothermal reservoirs in the Larderello are of Italy and reservoirs in the Geysers Geothermal Field, California produce little, if any, liquid. Yet to satisfy material balance constraints, another phase besides steam must be present. If steam adsorption occurring in significant amounts is not accounted for, the reserves will be grossly under-estimated. In addition, well tests may be misinterpreted because the pressure response is delayed owing to be adsorbed material leaving or entering the gaseous phase. In the present research the role of adsorption in geothermal reservoirs in investigated. Two sets of laboratory equipment were constructed to measure adsorption isotherms of cores from Berea sandstone, Larderello, and The Geysers. Seven experimental runs were completed using nitrogen on the low temperature apparatus at -196/sup 0/C. Eight runs were conducted using steam on the high temperature apparatus at temperatures ranging from 150 C to 207/sup 0/C. The largest specific surface area and the greatest nitrogen adsorption isotherm were measured on the Berea sandstone, followed by a core from Larderello and then The Geysers. Difficulties in determining whether a system had reached equilibrium at the end of each step lead to questions regarding the magnitude of adsorption measured by the steam runs. Nevertheless, adsorption was observed and the difficulties themselves were useful indicators of needed future research.

  7. 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

  8. 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.

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

    SciTech Connect

    Buckley, Jill S.

    1999-11-09

    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.

  10. 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

  11. 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.

  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. 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.

  14. 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.

  15. Petroleum geochemistry of oil and gas from Barbados: Implications for distribution of Cretaceous source rocks and regional petroleum prospectivity

    USGS Publications Warehouse

    Hill, R.J.; Schenk, C.J.

    2005-01-01

    Petroleum produced from the Barbados accretionary prism (at Woodbourne Field on Barbados) is interpreted as generated from Cretaceous marine shale deposited under normal salinity and dysoxic conditions rather than from a Tertiary source rock as previously proposed. Barbados oils correlate with some oils from eastern Venezuela and Trinidad that are positively correlated to extracts from Upper Cretaceous La Luna-like source rocks. Three distinct groups of Barbados oils are recognized based on thermal maturity, suggesting petroleum generation occurred at multiple levels within the Barbados accretionary prism. Biodegradation is the most significant process affecting Barbados oils resulting in increased sulfur content and decreased API gravity. Barbados gases are interpreted as thermogenic, having been co-generated with oil, and show mixing with biogenic gas is limited. Gas biodegradation occurred in two samples collected from shallow reservoirs at the Woodbourne Field. The presence of Cretaceous source rocks within the Barbados accretionary prism suggests that greater petroleum potential exists regionally, and perhaps further southeast along the passive margin of South America. Likewise, confirmation of a Cretaceous source rock indicates petroleum potential exists within the Barbados accretionary prism in reservoirs that are deeper than those from Woodbourne Field.

  16. 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.

  17. Multimodal reservoir porosity simulation: An application to a tight oil reservoir

    NASA Astrophysics Data System (ADS)

    Sauvageau, Mathieu; Gloaguen, Erwan; Claprood, Maxime; Lefebvre, René; Bêche, Martin

    2014-08-01

    At appraisal stage of a reservoir characterization, a key step is the inference of the reservoir static properties, such as porosity. In this study, we present a new nested workflow that optimally integrates 3D acoustic impedance and geophysical log data for the estimation of the spatial distribution of reservoir porosity, which is applied to a tight sandstone oil reservoir located in Quebec, Canada. In this workflow, 3D seismic is the main source of spatial information. First, the statistical petrophysical relationship between acoustic impedance and reservoir porosity is established using collocated geophysical log data. Second, a conventional least-squares post-stack inversion of the impedance is computed on the seismic grid. The fit between well log data and numerically computed traces was found to be inaccurate. This leads to the third step, involving a post-stack stochastic impedance inversion using the same seismic traces not only to improve well and trace fit but also to estimate the uncertainty on the inverted impedances. Finally, a Bayesian simulation algorithm adapted to the estimation of a multi-modal porosity distribution is used to simulate realizations of porosity over the entire seismic grid. Results show that the over-smoothing effect of least-squares inversion has a major impact on resource evaluation, especially by not reproducing the high-valued tail of the porosity distribution. The adapted Bayesian algorithm combined with stochastic impedance inversion thus allows a better reproduction of the porosity distribution and improves estimation of the geophysical and geological uncertainty.

  18. Inert and Reacting Tracers for Reservoir Sizing in Fractured, Hot Dry Rock Systems

    SciTech Connect

    Tester, J.W.; Robinson, B.A.; Ferguson, J.H.

    1986-01-21

    Flow characterization and volumetric sizing techniques using tracers in fractured hot dry rock reservoirs are discussed. Statistical methods for analyzing the residence time distribution (RTD) are presented. Tracer modal volumes and RTD shape are correlated with reservoir performance parameters such as active heat transfer area and dispersion levels. Chemically reactive tracers are proposed for mapping advance rates of cooled regions in HDR reservoirs, providing early warning of thermal drawdown. Important reaction rate parameters are identified for screening potential tracers. Current laboratory research and field work is reviewed.

  19. 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.

  20. 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

  1. Increasing heavy oil reserves in the Wilmington Oil field through advanced reservoir characterization and thermal production technologies. Quarterly report, April 1, 1996--June 30, 1996

    SciTech Connect

    Hara, S.

    1996-08-05

    The project involves improving thermal recovery techniques in a slope and basin clastic (SBC) reservoir in the Wilmington field, Los Angeles Co., California using advanced reservoir characterization and thermal production technologies. 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 technologies 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 an 2400 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 geologic data to integrate reservoir characterization, engineering, monitoring, and evaluation.

  2. 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

  3. Pressure-velocity relations in reservoir rocks: Modified MacBeth's equation

    NASA Astrophysics Data System (ADS)

    Grana, Dario

    2016-09-01

    The knowledge of the saturation and pressure effects on elastic properties is a key factor in reservoir monitoring. The relation between saturation changes and velocity variations is well known in rock physics and at seismic frequency it can be satisfactorily described by Gassmann's equations. The pressure effect still requires deeper investigations in order to be included in rock physics models for 4D studies. Theoretical models of velocity-pressure relations often do not match lab measurements, or contain empirical constants or theoretical parameters that are difficult to calibrate or do not have a precise physical meaning. In this work, I present a new model to describe the pressure sensitivity of elastic moduli for clastic rocks. The proposed model is an extension of MacBeth's relations. These equations are then integrated within a complete rock physics model to describe the relation between rock properties (porosity and clay content), dynamic attributes (saturation and pressure) and elastic properties. The proposed model is calibrated with laboratory measurements of dry samples over a wide range of pressure variations and then applied to well data to simulate different production scenarios. The complete rock physics model can then be used in time-lapse inversion to predict the distribution of dynamic property changes in the reservoir within an inversion workflow for reservoir monitoring.

  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. 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

  6. 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

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

    PubMed

    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.

  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. Quantification of rock stress heterogeneity: Application to hydraulic fracturing of hydrocarbon reservoirs

    NASA Astrophysics Data System (ADS)

    Langenbruch, Cornelius; Shapiro, Serge A.

    2015-04-01

    Fluid injection-induced earthquakes occur due to opening of new and re-activation of pre-existing fractures contained in the rock volume stress-perturbed by the fluid injection. We compare elastic rock heterogeneity measured by borehole logging to the occurrence of seismic events caused by hydraulic fracturing of the corresponding rock sections. Our observations made from two hydraulic fracturing case studies suggest that elastic rock heterogeneity controls the occurrence of fluid injection-induced earthquakes. The seismic events occur preferentially in rock sections characterized by low Poisson's ratio and high Young's modulus. Fracture opening and re-activation probability and the occurrence of associated seismic events should be strongly related to the initial state of stress in the unperturbed reservoir rock. We describe the sedimentary reservoir rock by a perfectly layered linear elastic medium in equilibrium to an externally applied homogeneous far field stress and quantify the relation between stress changes leading to fracture opening and re-activation and elastic rock heterogeneity. We extend existing analytic solutions of stress fluctuations in heterogeneous linear elastic media consisting of elastically isotropic layers to the case of vertical transverse isotropic layers. This allows application to unconventional shale gas reservoirs, which are usually characterized by a high intrinsic anisotropy. We find that magnitudes of rock stress fluctuations originating from elastic rock heterogeneity are significant. Moreover, we show that stress changes leading to fracture opening and re-activation in rocks undergo scale invariance spatial fluctuations. The scale invariant nature of rock stress fluctuations is caused by scale invariant fluctuations of elastic rock properties measured along the borehole. This gives a physical explanation for scale invariance of seismogenic processes. Based on our model, we analyze the physical meaning of a heterogeneity index of

  10. Predicting oil quality from sidewall cores using PFID, TEC, and NIR analytical techniques in sandstone reservoirs, Offshore Cameroon

    SciTech Connect

    Bement, W.O.; McNeil, R.I.; Lippincott, R.G.

    1996-08-01

    Cameroon reservoirs contain oil and gas that have migrated vertically from deeper buried thermally mature marine shales. Several shallow reservoirs also contain biogenic gas. Generally, lower gravity oils found in the shallow reservoirs have undergone various degrees of biodegradation. Deeper accumulations are higher gravity {open_quote}primary{close_quote} oils. The biodegraded oils are characterized by lower gravities, higher acid numbers, higher sulfur contents, and higher viscosities than their non-biodegraded counterparts. Oil quality (API gravity and acid number) has a significant impact on the development economics. It is important to obtain as much geochemical information as possible from the limited volume of oil contained in conventional sidewall samples because borehole conditions often preclude the possibility of running a wireline test tool (the MDT) to obtain a fluid sample. An analytical program of PFID (Pyrolysis Flame Ionization Detection), TEC (Thermal Extraction Chromatography) and NIR (Near Infra-Red spectroscopy) was conducted on a set of {open_quote}calibration{close_quote} oils and the data were used to develop both empirical and quantitative predictive criteria for estimating crude oil properties of gravity, acid number, sulfur content, and viscosity. Sidewall samples provide sufficient material for these micro-analytical techniques. The individual sidewalls were split for geochemical analysis with the remaining material available for petrographic analysis. The PFID and TEC techniques were run on the {open_quote}rock{close_quote} sample containing the oil. For the NIR technique, the oil was extracted from the sample with an organic solvent and the extract evaluated. Results will be presented for sidewall core samples obtained from four oil sands encountered during a two well exploratory program.

  11. Classification of mechanical heterogeneity of petroleum reservoir rocks optimal for radial drilling technology

    NASA Astrophysics Data System (ADS)

    Ivakhnenko, Aleksandr; Seitova, Nargiza; Dzhafarov, Tarlan

    2013-04-01

    The radial drilling technology involves drilling lateral horizontal boreholes of small diameter and up to one hundred meters long with the possibility of placing several wells within productive petroleum reservoirs. The usage of the radial drilling involves making small diameter horizontal perforations in the rock formation by using water jet and the jet propulsion which facilitate the penetration along the rock formation. In this study was reviewed the effectiveness of water jet propulsion for different mechanical heterogeneity of rocks. Experiments were carried out to investigate the variation in water jet penetration in different rock types, such as sandstones, carbonates, conglomerates, dolomites, limestone, etc., and their mechanical variations including unconsolidated and cemented members. There were also addressed cases when the pores of the rocks were filled with different minerals including clays and quartz. It was found that the method of penetration differ for mechanical heterogeneity of rocks. The results are shown for the different types of rocks and degree of their porosity variations. The efficiency of the rock penetration obtained by dividing the energy of the jet by the volume of hole created is discussed in relation to rock types and the method of rock failure.

  12. 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

  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. 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).

  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. Probe imaging studies of magnetic susceptibility and permeability for sensitive characterisation of carbonate reservoir rocks

    NASA Astrophysics Data System (ADS)

    Ivakhnenko, Aleksandr; Bigaliyeva, Akmaral; Dubinin, Vladislav

    2016-04-01

    In this study were disclosed the main principals of identifying petrophysical properties of carbonate reservoirs such as porosity, permeability and magnetic susceptibility. While exploring and developing reservoir there are significant diversity of tasks that can be solved by appropriate knowledge of properties which are listed above. Behavior of fluid flow, distribution of hydrocarbons and other various industrial applications can be solved by measuring areal distribution of these petrophysical parameters. The results demonstrate how magnetic probe and hysteresis measurements correlate with petrophysical parameters in carbonate reservoirs. We made experimental measurements and theoretical calculations of how much magnetic susceptibility depends on the porosity of the rocks and analyzed data with graphics. In theoretical model of the carbonate rocks we considered calcite, dolomite, quartz and combinations of calcite and dolomite, calcite and Fe-dolomite, calcite and quartz, calcite and aragonite with increasing concentrations of the dolomite, Fe-dolomite, quartz and aragonite up to 50% with step of 5%. Here we defined dependence of magnetic susceptibility from the porosity: the higher porosity measurements, the less slope of magnetic susceptibility, consequently mass magnetization is higher for diamagnetic and lower for paramagnetic carbonate rocks, but in the both cases magnetic susceptibility tries to reach zero with increasing of the total porosity. Rock measurements demonstrate that reservoir zones of the low diamagnetic magnetic susceptibility are generally correlated with higher permeability and also porosity distribution. However for different carbonate reservoirs we establish different relationships depending on the complexity of their mineralogy and texture. Application of integral understanding in distribution of permeability, porosity and mineral content in heterogeneous carbonates represented by this approach can be useful tool for carbonate reservoir

  17. 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.

  18. Elastic waves push organic fluids from reservoir rock

    NASA Astrophysics Data System (ADS)

    Beresnev, Igor A.; Vigil, R. Dennis; Li, Wenqing; Pennington, Wayne D.; Turpening, Roger M.; Iassonov, Pavel P.; Ewing, Robert P.

    2005-07-01

    Elastic waves have been observed to increase productivity of oil wells, although the reason for the vibratory mobilization of the residual organic fluids has remained unclear. Residual oil is entrapped as ganglia in pore constrictions because of resisting capillary forces. An external pressure gradient exceeding an ``unplugging'' threshold is needed to carry the ganglia through. The vibrations help overcome this resistance by adding an oscillatory inertial forcing to the external gradient; when the vibratory forcing acts along the gradient and the threshold is exceeded, instant ``unplugging'' occurs. The mobilization effect is proportional to the amplitude and inversely proportional to the frequency of vibrations. We observe this dependence in a laboratory experiment, in which residual saturation is created in a glass micromodel, and mobilization of the dyed organic ganglia is monitored using digital photography. We also directly demonstrate the release of an entrapped ganglion by vibrations in a computational fluid-dynamics simulation.

  19. 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.

  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. 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

  2. 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

  3. 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

  4. 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.

  5. 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

  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. 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.

  8. Visual display of reservoir parameters affecting enhanced oil recovery

    SciTech Connect

    Wood, J.R.

    1996-01-27

    This project will provide a detailed example, based on a field trial, of how to evaluate a field for EOR operations utilizing data typically available in an older field which has under gone primary development. The approach will utilize readily available, affordable PC-based computer software and analytical services. This study will illustrate the steps involved in: (1) setting up a relational database to store geologic, well-log, engineering, and production data, (2) integration of data typically available for oil and gas fields with predictive models for reservoir alteration, and (3) linking these data and models with modern computer software to provide 2-D and 3-D visualizations of the reservoir and its attributes. The techniques are being demonstrated through a field trial on a reservoir, Pioneer Field, a field that produces from the Monterey Formation, which is a candidate for thermal EOR. Technical progress is summarized for the following tasks: (1) project administration and management; (2) data collection; (3) data analysis and measurement; (4) modeling; and (5) technology transfer.

  9. 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.

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

    DOE PAGES

    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

  11. 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.

  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. 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.

  14. Correlating biodegradation to magnetization in oil bearing sedimentary rocks

    NASA Astrophysics Data System (ADS)

    Emmerton, Stacey; Muxworthy, Adrian R.; Sephton, Mark A.; Aldana, Milagrosa; Costanzo-Alvarez, Vincenzo; Bayona, German; Williams, Wyn

    2013-07-01

    A relationship between hydrocarbons and their magnetic signatures has previously been alluded to but this is the first study to combine extensive geochemical and magnetic data of hydrocarbon-associated samples. We report a detailed study that identifies a connection between magnetic mineralogy and oil biodegradation within oil-bearing sedimentary units from Colombia, Canada Indonesia and the UK. Geochemical data reveal that all the oil samples are derived from mature type-II kerogens deposited in oxygen-poor environments. Biodegradation is evident to some extent in all samples and leads to a decrease in oil quality through the bacterially mediated conversion of aliphatic hydrocarbons to polar constituents. The percentage of oil components and the biodegradation state of the samples were compared to the magnetic susceptibility and magnetic mineralogy. A distinct decrease in magnetic susceptibility is correlated to decreasing oil quality and the amount of extractable organic matter present. Further magnetic characterization revealed that the high quality oils are dominated by pseudo-single domain grains of magnetite and the lower quality oils by larger pseudo-single domain to multidomain grains of magnetite and hematite. Hence, with decreasing oil quality there is a progressive dominance of multidomain magnetite as well as the appearance of hematite. It is concluded that biodegradation is a dual process, firstly, aliphatic hydrocarbons are removed thereby reducing oil quality and secondly, magnetic signatures are both created and destroyed. This complex relationship may explain why controversy has plagued previous attempts to resolve the connection between magnetics and hydrocarbon deposits. These findings reinforce the importance of bacteria within petroleum systems as well as providing a platform for the use of magnetization as a possible exploration tool to identify subsurface reservoirs and a novel proxy of hydrocarbon migration.

  15. 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

  16. 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.

  17. 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.

  18. 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.

  19. 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

  20. Changes in composition and pore space of sand rocks in the oil water contact zone (section YU1 3-4, Klyuchevskaya area, Tomsk region)

    NASA Astrophysics Data System (ADS)

    Nedolivko, N.; Perevertailo, T.; Pavlovec, T.

    2016-09-01

    The article provides an analysis of specific features in changes of rocks in the oil water contact zone. The object of study is the formation YU1 3-4 (J3o1) of Klyuchevskaya oil deposit (West Siberian oil-gas province, Tomsk region). The research data allow the authors to determine vertical zoning of the surface structure and identify the following zones: oil saturation (weak alteration), bitumen-content dissolution, non-bitumen-content dissolution, cementation, including rocks not affected by hydrocarbon deposit. The rocks under investigation are characterized by different changes in composition, pore space, as well as reservoir filtration and volumetric parameters. Detection of irregularity in distribution of void- pore space in oil-water contact zones is of great practical importance. It helps to avoid the errors in differential pressure drawdown and explain the origin of low-resistivity collectors.

  1. 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

  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. 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.

  4. 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

  5. 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.

  6. Porosity, permeability and 3D fracture network characterisation of dolomite reservoir rock samples.

    PubMed

    Voorn, Maarten; Exner, Ulrike; Barnhoorn, Auke; Baud, Patrick; Reuschlé, Thierry

    2015-03-01

    With fractured rocks making up an important part of hydrocarbon reservoirs worldwide, detailed analysis of fractures and fracture networks is essential. However, common analyses on drill core and plug samples taken from such reservoirs (including hand specimen analysis, thin section analysis and laboratory porosity and permeability determination) however suffer from various problems, such as having a limited resolution, providing only 2D and no internal structure information, being destructive on the samples and/or not being representative for full fracture networks. In this paper, we therefore explore the use of an additional method - non-destructive 3D X-ray micro-Computed Tomography (μCT) - to obtain more information on such fractured samples. Seven plug-sized samples were selected from narrowly fractured rocks of the Hauptdolomit formation, taken from wellbores in the Vienna basin, Austria. These samples span a range of different fault rocks in a fault zone interpretation, from damage zone to fault core. We process the 3D μCT data in this study by a Hessian-based fracture filtering routine and can successfully extract porosity, fracture aperture, fracture density and fracture orientations - in bulk as well as locally. Additionally, thin sections made from selected plug samples provide 2D information with a much higher detail than the μCT data. Finally, gas- and water permeability measurements under confining pressure provide an important link (at least in order of magnitude) towards more realistic reservoir conditions. This study shows that 3D μCT can be applied efficiently on plug-sized samples of naturally fractured rocks, and that although there are limitations, several important parameters can be extracted. μCT can therefore be a useful addition to studies on such reservoir rocks, and provide valuable input for modelling and simulations. Also permeability experiments under confining pressure provide important additional insights. Combining these and

  7. Porosity, permeability and 3D fracture network characterisation of dolomite reservoir rock samples

    PubMed Central

    Voorn, Maarten; Exner, Ulrike; Barnhoorn, Auke; Baud, Patrick; Reuschlé, Thierry

    2015-01-01

    With fractured rocks making up an important part of hydrocarbon reservoirs worldwide, detailed analysis of fractures and fracture networks is essential. However, common analyses on drill core and plug samples taken from such reservoirs (including hand specimen analysis, thin section analysis and laboratory porosity and permeability determination) however suffer from various problems, such as having a limited resolution, providing only 2D and no internal structure information, being destructive on the samples and/or not being representative for full fracture networks. In this paper, we therefore explore the use of an additional method – non-destructive 3D X-ray micro-Computed Tomography (μCT) – to obtain more information on such fractured samples. Seven plug-sized samples were selected from narrowly fractured rocks of the Hauptdolomit formation, taken from wellbores in the Vienna basin, Austria. These samples span a range of different fault rocks in a fault zone interpretation, from damage zone to fault core. We process the 3D μCT data in this study by a Hessian-based fracture filtering routine and can successfully extract porosity, fracture aperture, fracture density and fracture orientations – in bulk as well as locally. Additionally, thin sections made from selected plug samples provide 2D information with a much higher detail than the μCT data. Finally, gas- and water permeability measurements under confining pressure provide an important link (at least in order of magnitude) towards more realistic reservoir conditions. This study shows that 3D μCT can be applied efficiently on plug-sized samples of naturally fractured rocks, and that although there are limitations, several important parameters can be extracted. μCT can therefore be a useful addition to studies on such reservoir rocks, and provide valuable input for modelling and simulations. Also permeability experiments under confining pressure provide important additional insights. Combining these

  8. 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

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

    SciTech Connect

    Shari Dunn-Norman

    2005-06-01

    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 minimal capital investment. In the twelve to eighteen-month project period, three wells were equipped with ERT arrays. Electrical resistivity tomography (ERT) background measurements were taken in the three ERT equipped wells. Pumping equipment was installed on the two fracture stimulated wells and pumping tests were conducted following the hydraulic fracture treatments. All wells were treated monthly with microbes, by adding a commercially available microbial mixture to wellbore fluids. ERT surveys were taken on a monthly basis, following microbial treatments. Worked performed to date demonstrates that resistivity changes are occurring in the subsurface, with resistivity increasing slightly. Pumping results for the hydraulically fractured wells were disappointing, with only a show of oil recovered and an increase in well shut-in pressure.

  10. 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.

  11. 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.

  12. 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.

  13. 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.

  14. 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

  15. 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

  16. 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.

  17. 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.

  18. 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

  19. 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.

  20. Reservoirs of Selenium in Coal Waste Rock: Elk Valley, British Columbia, Canada.

    PubMed

    Hendry, M Jim; Biswas, Ashis; Essilfie-Dughan, Joseph; Chen, Ning; Day, Stephen J; Barbour, S Lee

    2015-07-07

    Selenium (Se) reservoirs in coal waste rock from the Elk Valley, southeastern British Columbia, the location of Canada's major steelmaking coal mines, were characterized and quantified by analyzing samples collected from the parent rock, freshly blasted waste rock (less than 10 days old), and aged waste rock (deposited between 1982 and 2012). Se is present throughout the waste rock dumps at a mean digestible (SeD) concentration of 3.12 mg/kg. Microprobe analyses show that Se is associated with the primary minerals sphalerite, pyrite, barite, and chalcopyrite and secondary Fe oxyhydroxides. Selenium K-edge X-ray absorption near-edge spectroscopy analyses indicate that, on average, 21% of Se is present as selenide (Se(2-)) in pyrite and sphalerite, 19% of Se is present as selenite (Se(4+)) in barite, 21% of Se is present as exchangeable Fe oxyhydroxide and clay-adsorbed Se(4+), and 39% of Se is present as organoselenium associated with coaly matter. The dominant source minerals for aqueous-phase Se are pyrite and sphalerite. Secondary Fe oxyhydroxide sequesters, on average, 37% of Se released by pyrite oxidation. Measured long-term Se fluxes from a rock drain at the base of a waste dump suggest that at least 20% of Se(2-)-bearing sulfides were oxidized and released from that dump over the past 30 year period; however, the Se mass lost was not evident in SeD analyses.

  1. 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).

  2. 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.

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

    SciTech Connect

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

    1992-03-01

    In petroleum geochemistry, extractable hydrocarbons (HCs) in source rocks have typically been studied by grinding the rock to a fine powder ({le}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 the authors 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.

  4. 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.

  5. 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.

  6. 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

  7. 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

  8. 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.

  9. 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

  10. 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.

  11. Storage of Residual Fuel Oil in Underground Unlined Rock Caverns.

    DTIC Science & Technology

    1980-12-01

    Francaise des Petroles BP, Elf Union, Shell Francaise, and Compagnie Francaise de Raffinage (Total). The company and its subsidiaries were formed with...DEC 80 D C BANKS UNCLASSIFIED WES/NP/S4.-8O-19 ti. LE VEL MISCELLANEOUS PAPER GL-80-19 31 STORAGE OF RESIDUAL FUEL OIL IN UNDERGROUND UNLINED ROCK...Ruimaia.~ indl a riiirI( le ol Air in1 wi r’ hve en coIit’Icted to enc1ouraige muiliriershnpl I[I the i 5kRM. 1) By Innf t-Ii .fi’ I ’I.]%- I "W

  12. 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.

  13. Stimulation of a hot dry rock geothermal reservoir in the Cornubian Granite, England

    SciTech Connect

    Batchelor, A.S.

    1982-01-01

    A hot dry rock geothermal reservoir has been created at a depth of 2000 m in granite. The stimulation was carried out using 40,000 m/sup 3/ (10 million US gal) from a 350 m open hole section that had been treated with a purpose-designed explosive tool. On-line seismic mapping has shown that the reservoir has developed in the direction of the maximum principal stress despite the fact tht the joint directions are not orientated in that direction. Photographic and television inspection has been used to correlate acoustic seisviewer and conventional wire logging results including observations of fracture width at the wellbore during pressurization. Downward growth of the reservoir has been observed despite the fact that the stimulation fluid was fresh water. This has been explained tentatively as predominantly shear growth because the shear stress gradient is sub-hydrostatic due to the highly anisotropic stress field. Preliminary calculations have shown that the reservoir structure has a volume of 100 to 200 million m/sup 3/ but there is no direct, low resistance flow path between the wells and the residence time is in excess of 5 days.

  14. 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

  15. 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.

  16. 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.

  17. 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.

  18. 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.

  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. 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

    ,

    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.

  1. Development of a layered treatment technique for multiple heavy oil reservoirs

    SciTech Connect

    Hu Zhimian; Wu Dehua

    1995-12-31

    Liaohe Oilfield abounds in heavy oil. It has 10 hydrocarbon-bearing formation series. Most reservoirs lie 600-700 m deep. Sandstone heavy oil reservoirs can be generally divided into three types, which are massive oil pool, medium-thick interbedding reservoir, and medium-thin interbedding reservoir. In the huff and puff process, lots of downhole measurement information indicates that due to inhomogeneity between layers, steam absorption differs in different layers. This results in low steam absorbing percentage of perforated interval (that is the percentage of the steam absorbing thickness to the perforated interval`s length), and the lower layers at the perforated interval take in no steam. The main steam absorbing layers are at the layer upper of the perforated interval and they are thicker with high permeability. In order to improve the multilayer heavy oil reservoir`s vertical steam soaking profile, and to increase the steam absorbing percentage of perforated interval and steam soaking production effect, we have studied and developed the selective and separate layer steam injection technology for multilayer heavy oil reservoir. This essay gives a particular expounding on the method of selective and separate zone steam injection, its application on site, and its working results.

  2. 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.

  3. 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.

  4. 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; 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.

  5. Pore Scale Observations of Trapped CO2 in Mixed-Wet Carbonate Rock: Applications to Storage in Oil Fields.

    PubMed

    Al-Menhali, Ali S; Menke, Hannah P; Blunt, Martin J; Krevor, Samuel C

    2016-09-20

    Geologic CO2 storage has been identified as a key to avoiding dangerous climate change. Storage in oil reservoirs dominates the portfolio of existing projects due to favorable economics. However, in an earlier related work ( Al-Menhali and Krevor Environ. Sci. Technol. 2016 , 50 , 2727 - 2734 ) , it was identified that an important trapping mechanism, residual trapping, is weakened in rocks with a mixed wetting state typical of oil reservoirs. We investigated the physical basis of this weakened trapping using pore scale observations of supercritical CO2 in mixed-wet carbonates. The wetting alteration induced by oil provided CO2-wet surfaces that served as conduits to flow. In situ measurements of contact angles showed that CO2 varied from nonwetting to wetting throughout the pore space, with contact angles ranging 25° < θ < 127°; in contrast, an inert gas, N2, was nonwetting with a smaller range of contact angle 24° < θ < 68°. Observations of trapped ganglia morphology showed that this wettability allowed CO2 to create large, connected, ganglia by inhabiting small pores in mixed-wet rocks. The connected ganglia persisted after three pore volumes of brine injection, facilitating the desaturation that leads to decreased trapping relative to water-wet systems.

  6. Electrical Resistivity as an Indicator of Saturation in Fractured Geothermal Reservoir Rocks: Experimental Data and Modeling

    SciTech Connect

    Detwiler, R L; Roberts, J J

    2003-06-23

    The electrical resistivity of rock cores under conditions representative of geothermal reservoirs is strongly influenced by the state and phase (liquid/vapor) of the pore fluid. In fractured samples, phase change (vaporization/condensation) can result in resistivity changes that are more than an order of magnitude greater than those measured in intact samples. These results suggest that electrical resistivity monitoring of geothermal reservoirs may provide a useful tool for remotely detecting the movement of water and steam within fractures, the development and evolution of fracture systems and the formation of steam caps. We measured the electrical resistivity of cores of welded tuff containing fractures of various geometries to investigate the resistivity contrast caused by active boiling and to determine the effects of variable fracture dimensions and surface area on water extraction from the matrix. We then used the Nonisothermal Unsaturated Flow and Transport model (NUFT) (Nitao, 1998) to simulate the propagation of boiling fronts through the samples. The simulated saturation profiles combined with previously reported measurements of resistivity-saturation curves allow us to estimate the evolution of the sample resistivity as the boiling front propagates into the rock matrix. These simulations provide qualitative agreement with experimental measurements suggesting that our modeling approach may be used to estimate resistivity changes induced by boiling in more complex systems.

  7. Modeling Fluid Flow and Electrical Resistivity in Fractured Geothermal Reservoir Rocks

    SciTech Connect

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

    2003-01-14

    Phase change of pore fluid (boiling/condensing) in rock cores under conditions representative of geothermal reservoirs results in alterations of the electrical resistivity of the samples. In fractured samples, phase change can result in resistivity changes that are more than an order of magnitude greater than those measured in intact samples. These results suggest that electrical resistivity monitoring may provide a useful tool for monitoring the movement of water and steam within fractured geothermal reservoirs. We measured the electrical resistivity of cores of welded tuff containing fractures of various geometries to investigate the resistivity contrast caused by active boiling and to determine the effects of variable fracture dimensions and surface area on water extraction. We then used the Nonisothermal Unsaturated Flow and Transport model (NUFT) (Nitao, 1998) to simulate the propagation of boiling fronts through the samples. The simulated saturation profiles combined with previously reported measurements of resistivity-saturation curves allow us to estimate the evolution of the sample resistivity as the boiling front propagates into the rock matrix. These simulations provide qualitative agreement with experimental measurements suggesting that our modeling approach may be used to estimate resistivity changes induced by boiling in more complex systems.

  8. A hybrid waveguide cell for the dielectric properties of reservoir rocks

    NASA Astrophysics Data System (ADS)

    Siggins, A. F.; Gunning, J.; Josh, M.

    2011-02-01

    A hybrid waveguide cell is described for broad-band measurements of the dielectric properties of hydrocarbon reservoir rocks. The cell is designed to operate in the radio frequency range of 1 MHz to 1 GHz. The waveguide consists of 50 Ω coaxial lines feeding into a central cylindrical section which contains the sample under test. The central portion of the waveguide acts as a circular waveguide and can accept solid core plugs of 38 mm diameter and lengths from 2 to 150 mm. The central section can also be used as a conventional coaxial waveguide when a central electrode with spring-loaded end collets is installed. In the latter mode the test samples are required to be in the form of hollow cylinders. An additional feature of the cell is that the central section is designed to telescope over a limited range of 1-2 mm with the application of an axial load. Effective pressures up to 35 MPa can be applied to the sample under the condition of uniaxial strain. The theoretical basis of the hybrid waveguide cell is discussed together with calibration results. Two reservoir rocks, a Donnybrook sandstone and a kaolin rich clay, are then tested in the cell, both as hollow cylinders in coaxial mode and in the form of solid core plugs. The complex dielectric properties of the two materials over the bandwidth of 1 MHz to 1 GHz are compared with the results of the two testing methods.

  9. 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

  10. Experimental verification of the load-following potential of a Hot Dry Rock geothermal reservoir

    SciTech Connect

    Brown, Donald

    1996-01-24

    A recent 6-day flow experiment conducted at the Los Alamos National Laboratory's Fenton Hill Hot Dry Rock (HDR) test site in north-central New Mexico has verified that an HDR reservoir has the capability for a significant, and very rapid, increase in power output upon demand. The objective of this cyclic load-following experiment was to investigate the performance of the reservoir in a nominal high-backpressure (2200 psi) baseload operating condition upon which was superimposed greatly increased power production for a 4-hour period each day. In practice, this enhanced production was accomplished by dropping the production well backpressure from the preexisting level of 2200 psi down to about 500 psi to rapidly drain the fluid stored in the pressure-dilated joints surrounding the production well. During the last cycle of this six-cycle test, the mean production conditions were 146.6 gpm for 4 hours at a temperature of 189°C followed by 92.4 gpm for 20 hours at a temperature of 183°C. These flow and temperature values indicate a flow enhancement of 59%, and a power enhancement of 65% during the high-production period. The time required to increase the reservoir power output from the baseload to the peaking rate was about 2 minutes.

  11. Experimental verification of the load-following potential of a hot dry rock geothermal reservoir

    SciTech Connect

    Brown, D.

    1996-12-31

    A recent 6-day flow experiment conducted at the Los Alamos National Laboratory`s Fenton Hill Hot Dry Rock (HDR) test site in north-central New Mexico has verified that an HDR reservoir has the capability for a significant, and very rapid, increase in power output upon demand. The objective of this cyclic load-following experiment was to investigate the performance of the reservoir in a nominal high-backpressure (2200 psi) baseload operating condition upon which was superimposed greatly increased power production for a 4-hour period each day. In practice, this enhanced production was accomplished by dropping the production well backpressure from the preexisting level of 2200 psi down to about 500 psi to rapidly drain the fluid stored in the pressure-dilated joints surrounding the production well. During the last cycle of this six-cycle test, the mean production conditions were 146.6 gpm for 4 hours at a temperature of 189{degrees}C, followed by 92.4 gpm for 20 hours at a temperature of 183{degrees}C. These flow and temperature values indicate a flow enhancement of 59%, and a power enhancement of 65% during the high-production period. The time required to increase the reservoir power output from the baseload to the peaking rate was about 2 minutes.

  12. 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.

  13. 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.

  14. 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.

  15. 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.

  16. 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.

  17. 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.

  18. Wetting behavior of selected crude oil/brine/rock systems. Topical report, March 1, 1995--March 31, 1996

    SciTech Connect

    Zhou, X.; Morrow, N.R.; Ma, S.

    1996-12-31

    Previous studies of crude oil/brine/rock (COBR) and related ensembles showed that wettability and its effect on oil recovery depend on numerous complex interactions. In the present work, the wettability of COBR ensembles prepared using Prudhoe Bay crude oil, a synthetic formation brine, and Berea Sandstone was varied by systematic change in initial water saturation and length of aging time at reservoir temperature (88 C). All displacement tests were run at ambient temperature. Various degrees of water wetness were achieved and quantified by a modified Amott wettability index to water, the relative pseudo work of imbibition, and a newly defined apparent advancing dynamic contact angle. Pairs of spontaneous imbibition (oil recovery by spontaneous imbibition of water) and waterflood (oil recovery vs. pore volumes of water injected) curves were measured for each of the induced wetting states. Several trends were observed. Imbibition rate, and hence water wetness, decreased with increase in aging time and with decrease in initial water saturation. Breakthrough recoveries and final oil recovery by waterflooding increased with decrease in water wetness. Correlations between water wetness and oil recovery by waterflooding and spontaneous imbibition are presented.

  19. Oil flow to a slit-like well in a reservoir containing other fluids

    NASA Astrophysics Data System (ADS)

    Emikh, V. N.

    2014-03-01

    An exact solution is obtained for the boundary-value problem of oil flow to a slit-like well in a reservoir containing other fluids adjacent to its top and base. This solution is used to compare the maximum possible oil production from slit-like and tubular wells in the double critical regime.

  20. Simulation Study of CO2-EOR in Tight Oil Reservoirs with Complex Fracture Geometries

    NASA Astrophysics Data System (ADS)

    Zuloaga-Molero, Pavel; Yu, Wei; Xu, Yifei; Sepehrnoori, Kamy; Li, Baozhen

    2016-09-01

    The recent development of tight oil reservoirs has led to an increase in oil production in the past several years due to the progress in horizontal drilling and hydraulic fracturing. However, the expected oil recovery factor from these reservoirs is still very low. CO2-based enhanced oil recovery is a suitable solution to improve the recovery. One challenge of the estimation of the recovery is to properly model complex hydraulic fracture geometries which are often assumed to be planar due to the limitation of local grid refinement approach. More flexible methods like the use of unstructured grids can significantly increase the computational demand. In this study, we introduce an efficient methodology of the embedded discrete fracture model to explicitly model complex fracture geometries. We build a compositional reservoir model to investigate the effects of complex fracture geometries on performance of CO2 Huff-n-Puff and CO2 continuous injection. The results confirm that the appropriate modelling of the fracture geometry plays a critical role in the estimation of the incremental oil recovery. This study also provides new insights into the understanding of the impacts of CO2 molecular diffusion, reservoir permeability, and natural fractures on the performance of CO2-EOR processes in tight oil reservoirs.

  1. Simulation Study of CO2-EOR in Tight Oil Reservoirs with Complex Fracture Geometries

    PubMed Central

    Zuloaga-Molero, Pavel; Yu, Wei; Xu, Yifei; Sepehrnoori, Kamy; Li, Baozhen

    2016-01-01

    The recent development of tight oil reservoirs has led to an increase in oil production in the past several years due to the progress in horizontal drilling and hydraulic fracturing. However, the expected oil recovery factor from these reservoirs is still very low. CO2-based enhanced oil recovery is a suitable solution to improve the recovery. One challenge of the estimation of the recovery is to properly model complex hydraulic fracture geometries which are often assumed to be planar due to the limitation of local grid refinement approach. More flexible methods like the use of unstructured grids can significantly increase the computational demand. In this study, we introduce an efficient methodology of the embedded discrete fracture model to explicitly model complex fracture geometries. We build a compositional reservoir model to investigate the effects of complex fracture geometries on performance of CO2 Huff-n-Puff and CO2 continuous injection. The results confirm that the appropriate modelling of the fracture geometry plays a critical role in the estimation of the incremental oil recovery. This study also provides new insights into the understanding of the impacts of CO2 molecular diffusion, reservoir permeability, and natural fractures on the performance of CO2-EOR processes in tight oil reservoirs. PMID:27628131

  2. 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).

  3. Simulation Study of CO2-EOR in Tight Oil Reservoirs with Complex Fracture Geometries.

    PubMed

    Zuloaga-Molero, Pavel; Yu, Wei; Xu, Yifei; Sepehrnoori, Kamy; Li, Baozhen

    2016-09-15

    The recent development of tight oil reservoirs has led to an increase in oil production in the past several years due to the progress in horizontal drilling and hydraulic fracturing. However, the expected oil recovery factor from these reservoirs is still very low. CO2-based enhanced oil recovery is a suitable solution to improve the recovery. One challenge of the estimation of the recovery is to properly model complex hydraulic fracture geometries which are often assumed to be planar due to the limitation of local grid refinement approach. More flexible methods like the use of unstructured grids can significantly increase the computational demand. In this study, we introduce an efficient methodology of the embedded discrete fracture model to explicitly model complex fracture geometries. We build a compositional reservoir model to investigate the effects of complex fracture geometries on performance of CO2 Huff-n-Puff and CO2 continuous injection. The results confirm that the appropriate modelling of the fracture geometry plays a critical role in the estimation of the incremental oil recovery. This study also provides new insights into the understanding of the impacts of CO2 molecular diffusion, reservoir permeability, and natural fractures on the performance of CO2-EOR processes in tight oil reservoirs.

  4. Microbial analysis of backflowed injection water from a nitrate-treated North Sea oil reservoir.

    PubMed

    Bødtker, Gunhild; Lysnes, Kristine; Torsvik, Terje; Bjørnestad, Eva Ø; Sunde, Egil

    2009-03-01

    Reservoir souring in offshore oil fields is caused by hydrogen sulphide (H(2)S) produced by sulphate-reducing bacteria (SRB), most often as a consequence of sea water injection. Biocide treatment is commonly used to inhibit SRB, but has now been replaced by nitrate treatment on several North Sea oil fields. At the Statfjord field, injection wells from one nitrate-treated reservoir and one biocide-treated reservoir were reversed (backflowed) and sampled for microbial analysis. The two reservoirs have similar properties and share the same pre-nitrate treatment history. A 16S rRNA gene-based community analysis (PCR-DGGE) combined with enrichment culture studies showed that, after 6 months of nitrate injection (0.25 mM NO(3) (-)), heterotrophic and chemolithotrophic nitrate-reducing bacteria (NRB) formed major populations in the nitrate-treated reservoir. The NRB community was able to utilize the same substrates as the SRB community. Compared to the biocide-treated reservoir, the microbial community in the nitrate-treated reservoir was more phylogenetically diverse and able to grow on a wider range of substrates. Enrichment culture studies showed that SRB were present in both reservoirs, but the nitrate-treated reservoir had the least diverse SRB community. Isolation and characterisation of one of the dominant populations observed during nitrate treatment (strain STF-07) showed that heterotrophic denitrifying bacteria affiliated to Terasakiella probably contributed significantly to the inhibition of SRB.

  5. 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.

  6. 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

  7. 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

  8. 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

  9. Redistribution of filtration flows by thermogel at boundary water flooding of oil reservoirs

    NASA Astrophysics Data System (ADS)

    Korsakova, N. K.; Penkovsky, V. I.; Altunina, L. K.; Kuvshinov, V. A.

    2016-11-01

    The results of physical simulation by a two-dimensional reservoir model and numerical calculation by a finite element method for the GALKA-NT thermogel influence on the redistribution of filtration flows of injected water in the oil production by boundary water flooding are presented. The reserve development by this method, especially in the case of viscose oil pools, occurs with an unstable displacement front that causes growing water fingers, which finally transform into the network of water-conducting channels in the direction of the least filtration resistance between well rows. Here the most amount of oil remains in the nonmobile capillary-locked state, which is in dynamic equilibrium with the flow of displacing water. The injection of thermogel into the reservoir area between the wells is shown to widen the displacement front and to increase the reservoir coverage by water flooding at a later stage in order to enhance oil recovery.

  10. Petroleum, oil field waters, and authigenic mineral assemblages - Are they in metastable equilibrium in hydrocarbon reservoirs?

    NASA Astrophysics Data System (ADS)

    Helgeson, Harold C.; Knox, Annette M.; Owens, Christine E.; Shock, Everett L.

    1993-07-01

    The hypothesis that although the presence of carboxylic acids and carboxylate anions in oil field waters is commonly attributed to the thermal maturation of kerogen or bacterial degradation of hydrocarbons during water-washing of petroleum in relatively shallow reservoirs, they may have also been produced in deeper reservoirs by the hydrolysis of hydrocarbons in petroleum at the oil-water interface is tested. Calculations were carried out to determine the distribution of species with the minimum Gibbs free energy in overpressured oil field waters in the Texas Gulf Coast assuming metastable equilibrium among calcite, albite, and a representative spectrum of organic and inorganic aqueous species at reservoir temperatures and pressures. The hypothesis that homogeneous equilibrium obtains among carboxylate and carbonate species in oil field waters is confirmed.

  11. 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.

  12. 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.

  13. 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

    ,

    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.

  14. 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

  15. 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.; Hammes, Ursula

    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. 

  16. 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

  17. 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.

  18. Wetting behavior of selected crude oil/brine/rock systems

    SciTech Connect

    1997-04-01

    Of the many methods of characterizing wettability of a porous medium, the most commonly used are the Amott test and the USBM test. The Amott test does not discriminate adequately between systems that give high values of wettability index to water and are collectively described as very strongly water-wet. The USBM test does not recognize systems that achieve residual oil saturation by spontaneous imbibition. For such systems, and for any systems that exhibit significant spontaneous imbibition, measurements of imbibition rate provide a useful characterization of wettability. Methods of interpreting spontaneous imbibition data are reviewed and a new method of quantifying wettability from rate of imbibition is proposed. Capillary pressure is the driving force in spontaneous imbibition. The area under an imbibition curve is closely related to the work of displacement that results from decrease in surface free energy. Imbibition rate data can be correlated to allow for differences in interracial tension, viscosities, pore structure, and sample size. Wettability, the remaining key factor in determining the capillary driving force and the related imbibition rate, then largely determines the differences in saturation vs. scaled time curves. These curves are used to obtain pseudo imbibition capillary pressure curves; a wettability index based on relative areas under these curves is defined as the relative pseudo work of imbibition. The method is applied for two crude oil/brine/rock systems. Comparison of the method with the Amott wettability index is made for different wettability states given by differences in aging of cores with crude oil. Correlations of wettability indices with waterflood recoveries are presented.

  19. 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

  20. 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

  1. 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.

  2. 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.

  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. 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.

  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. 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.

  7. 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.

  8. 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.

  9. Exploration for fractured reservoirs in Precambrian basement rocks of Texas panhandle: an integrated approach

    SciTech Connect

    Manwaring, M.S.; Weimer, B.A.

    1986-05-01

    This paper describes a detailed integrated study of the buried basement rocks of the Gray County, Texas, area. The study area comprises parts of Gray, Carson, and Wheeler Counties in the Texas Panhandle. The authors mapped faults and basement structure by integrating aerial photographs and enhanced Landsat structural interpretations with various data, including magnetics, gravity, geomorphic, paleogeologic, well-log, fracture core, well-top, subsurface structural, and isopach mapping data. The present structural configuration of the basement is a complex system of faults, bounding horst, graben, and tilted fault blocks. Most deformation resulted from left-lateral, oblique-slip faulting during the Pennsylvanian through Early Permian. Fractures in several orientations have experienced multiple episodes of opening and fluid circulation. The local relief of the basement results from a combination of structural deformation and paleoweathering. Basement production ranges from 1 to 700 BOPD. This variable rate primarily results from the fractured nature of the basement rocks. Depth to production averages 3500 ft. Oil probably migrated from the Woodford Shale in the Anadarko basin into the basement along ubiquitous fractures, and accumulated in open fracture zones associated with faults. However, drilling within a fault zone does not assure basement production. Other geologic factors that are equally important to basement oil accumulations and production are fault orientation, fracture type, fracture mineralization, degree of weathering, basement subcrop elevation, lithology, fault intensity, proximity to fault-associated fracture zone, and treatment procedures.

  10. 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.

  11. 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

  12. Evolution of overpressured and underpressured oil and gas reservoirs, Anadarko Basin of Oklahoma, Texas, and Kansas

    USGS Publications Warehouse

    Nelson, Phillip H.; Gianoutsos, Nicholas J.

    2011-01-01

    Departures of resistivity logs from a normal compaction gradient indicate that overpressure previously extended north of the present-day overpressured zone. These indicators of paleopressure, which are strongest in the deep basin, are mapped to the Kansas-Oklahoma border in shales of Desmoinesian age. The broad area of paleopressure has contracted to the deep basin, and today the overpressured deep basin, as determined from drillstem tests, is bounded on the north by strata with near normal pressures (hydrostatic), grading to the northwest to pressures that are less than hydrostatic (underpressured). Thus the pressure regime in the northwest portion of the Anadarko Basin has evolved from paleo-overpressure to present-day underpressure. Using pressure data from drillstem tests, we constructed cross sections and potentiometric maps that illustrate the extent and nature of present-day underpressuring. Downcutting and exposure of Lower Permian and Pennsylvanian strata along, and east of, the Nemaha fault zone in central Oklahoma form the discharge locus where pressure reaches near atmospheric. From east to west, hydraulic head increases by several hundred feet in each rock formation, whereas elevation increases by thousands of feet. The resulting underpressuring of the aquifer-supported oil and gas fields, which also increases from east to west, is a consequence of the vertical separation between surface elevation and hydraulic head. A 1,000-ft thick cap of Permian evaporites and shales isolates the underlying strata from the surface, preventing re-establishment of a normal hydrostatic gradient. Thus, the present-day pressure regime of oil and gas reservoirs, overpressured in the deep basin and underpressured on the northwest flank of the basin, is the result of two distinct geologic events-rapid burial and uplift/erosion-widely separated in time.

  13. 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.

  14. 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.

  15. 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.

  16. CO/sub 2/ injection as an immiscible application for enhanced recovery in heavy oil reservoirs

    SciTech Connect

    Khatib, A.K.; Earlougher, R.C.; Kantar, K.

    1981-01-01

    Two techniques have been field-tested. These are ''huff-and-puff'' CO/sub 2/ injection for stimulation of the producing wells and either alternate or simultaneous injection of CO/sub 2/ and water. Both process mechanisms are discussed and are illustrated, where possible, by the results of field tests in the United States. These have been in sandstone reservoirs containing light oils and heavy oils. Several other pilot or field projects are in the planning stage. A planned field demonstration project of both processes, in different test areas of a fractured limestone reservoir (oil 9/degree/-15/degree/) in Turkey, is summarized. The possible range of candidate reservoirs is discussed, and general economic comparison with steam injection is given. 27 refs.

  17. 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.

  18. 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.

  19. 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

  20. 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)

  1. 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)

  2. 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.

  3. 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.

  4. Study on distribution of reservoir endogenous microbe and oil displacement mechanism.

    PubMed

    Yue, Ming; Zhu, Weiyao; Song, Zhiyong; Long, Yunqian; Song, Hongqing

    2017-02-01

    In order to research oil displacement mechanism by indigenous microbial communities under reservoir conditions, indigenous microbial flooding experiments using the endogenous mixed bacterium from Shengli Oilfield were carried out. Through microscopic simulation visual model, observation and analysis of distribution and flow of the remaining oil in the process of water flooding and microbial oil displacement were conducted under high temperature and high pressure conditions. Research has shown that compared with atmospheric conditions, the growth of the microorganism metabolism and attenuation is slowly under high pressure conditions, and the existence of the porous medium for microbial provides good adhesion, also makes its growth cycle extension. The microbial activities can effectively launch all kinds of residual oil, and can together with metabolites, enter the blind holes off which water flooding, polymer flooding and gas flooding can't sweep, then swap out remaining oil, increase liquidity of the crude oil and remarkably improve oil displacement effect.

  5. Rhamnolipids Produced by Indigenous Acinetobacter junii from Petroleum Reservoir and its Potential in Enhanced Oil Recovery

    PubMed Central

    Dong, Hao; Xia, Wenjie; Dong, Honghong; She, Yuehui; Zhu, Panfeng; Liang, Kang; Zhang, Zhongzhi; Liang, Chuanfu; Song, Zhaozheng; Sun, Shanshan; Zhang, Guangqing

    2016-01-01

    Biosurfactant producers are crucial for incremental oil production in microbial enhanced oil recovery (MEOR) processes. The isolation of biosurfactant-producing bacteria from oil reservoirs is important because they are considered suitable for the extreme conditions of the reservoir. In this work, a novel biosurfactant-producing strain Acinetobacter junii BD was isolated from a reservoir to reduce surface tension and emulsify crude oil. The biosurfactants produced by the strain were purified and then identified via electrospray ionization-Fourier transform ion cyclotron resonance mass spectrometry (ESI FT-ICR-MS). The biosurfactants generated by the strain were concluded to be rhamnolipids, the dominant rhamnolipids were C26H48O9, C28H52O9, and C32H58O13. The optimal carbon source and nitrogen source for biomass and biosurfactant production were NaNO3 and soybean oil. The results showed that the content of acid components increased with the progress of crude oil biodegradation. A glass micromodel test demonstrated that the strain significantly increased oil recovery through interfacial tension reduction, wettability alteration and the mobility of microorganisms. In summary, the findings of this study indicate that the newly developed BD strain and its metabolites have great potential in MEOR. PMID:27872613

  6. Rhamnolipids Produced by Indigenous Acinetobacter junii from Petroleum Reservoir and its Potential in Enhanced Oil Recovery.

    PubMed

    Dong, Hao; Xia, Wenjie; Dong, Honghong; She, Yuehui; Zhu, Panfeng; Liang, Kang; Zhang, Zhongzhi; Liang, Chuanfu; Song, Zhaozheng; Sun, Shanshan; Zhang, Guangqing

    2016-01-01

    Biosurfactant producers are crucial for incremental oil production in microbial enhanced oil recovery (MEOR) processes. The isolation of biosurfactant-producing bacteria from oil reservoirs is important because they are considered suitable for the extreme conditions of the reservoir. In this work, a novel biosurfactant-producing strain Acinetobacter junii BD was isolated from a reservoir to reduce surface tension and emulsify crude oil. The biosurfactants produced by the strain were purified and then identified via electrospray ionization-Fourier transform ion cyclotron resonance mass spectrometry (ESI FT-ICR-MS). The biosurfactants generated by the strain were concluded to be rhamnolipids, the dominant rhamnolipids were C26H48O9, C28H52O9, and C32H58O13. The optimal carbon source and nitrogen source for biomass and biosurfactant production were NaNO3 and soybean oil. The results showed that the content of acid components increased with the progress of crude oil biodegradation. A glass micromodel test demonstrated that the strain significantly increased oil recovery through interfacial tension reduction, wettability alteration and the mobility of microorganisms. In summary, the findings of this study indicate that the newly developed BD strain and its metabolites have great potential in MEOR.

  7. Analysis of methane production by microorganisms indigenous to a depleted oil reservoir for application in Microbial Enhanced Oil Recovery.

    PubMed

    Kobayashi, Hajime; Kawaguchi, Hideo; Endo, Keita; Mayumi, Daisuke; Sakata, Susumu; Ikarashi, Masayuki; Miyagawa, Yoshihiro; Maeda, Haruo; Sato, Kozo

    2012-01-01

    We examined methane production by microorganisms collected from a depleted oilfield. Our results indicated that microorganisms indigenous to the petroleum reservoir could effectively utilize yeast extract, suggesting that the indigenous microorganisms and proteinaceous nutrients could be recruitable for Microbially Enhanced Oil Recovery.

  8. 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

  9. 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

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

    NASA Astrophysics Data System (ADS)

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

    2009-04-01

    The cap-rock of the CO2SINK storage site close to Ketzin consists of clay rich rocks which are typical for cap rock formations above CO2 storage reservoirs. The strength and deformation behaviour of such claystone samples are therefore of fundamental importance for the characterization of secure geological storage of CO2. The elastic and anelastic deformation behaviour limits the maximum injection pressure during CO2-injection and is part of the security measures for the long term storage of CO2. The laboratory experiments where performed on samples gathered from the injection well of the Ketzin pilot test site in Germany and are compared with the elastic and anelastic behaviour of samples from the same Keuper formation in a near-surface outcrop in the Southwest of Germany showing a similar lithology. The samples from the outcrop allowed drilling of samples with a standard size of 100 mm diameter and 200 mm height as well as large samples with a diameter of 550 mm and a height of 1200 mm. The investigations have a special emphasis on the viscous behaviour of the clay stones and its scaling behaviour. A special triaxial testing procedure is applied both on standard and large size samples allowing the determination of the strength, stiffness and viscosity behaviour of the rock in one experimental run. Multi-stage technique (stepwise variation of the confining pressure) gives the strength behaviour of each single sample while applying a constant deformation rate. Stepwise varied deformation rates on the other hand lead to steps in the stress-strain-curve from which the viscosity index is determined. The viscosity index is directly used in the Norton's constitutive relations for viscoplastic simulations. The combination of tests allows for the determination of a broad range of elastic and anelastic properties. The comparison of results - both for elastic and anelastic behaviour - from standard and large samples shows that for the examined rocks a scale effect is

  11. 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.

  12. 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.

  13. 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.

  14. 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.

  15. 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

  16. 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.

  17. 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.

  18. Distribution and Physiological Characteristics of Hyperthermophiles in the Kubiki Oil Reservoir in Niigata, Japan

    PubMed Central

    Takahata, Yoh; Nishijima, Miyuki; Hoaki, Toshihiro; Maruyama, Tadashi

    2000-01-01

    The distribution of culturable hyperthermophiles was studied in relation to environmental conditions in the Kubiki oil reservoir in Japan, where the temperature was between 50 and 58°C. Dominant hyperthermophilic cocci and rods were isolated and shown to belong to the genera Thermococcus and Thermotoga, respectively, by 16S rDNA analyses. Using the most-probable-number method, we found that hyperthermophilic cocci were widely distributed in several unconnected fault blocks in the Kubiki oil reservoir. In 1996 to 1997, their populations in the production waters from oil wells were 9.2 × 103 to 4.6 × 104 cells/ml, or 10 to 42% of total cocci. On the other hand, hyperthermophilic rods were found in only one fault block of the reservoir with populations less than 10 cells/ml. Dominant Thermococcus and Thermotoga spp. grew at reservoir temperatures and utilized amino acids and sugars, respectively, as sole carbon sources. While organic carbon was plentiful in the environment, these hyperthermophiles were unable to grow in the formation water due to lack of essential nutrients. Concentrations of some organic and inorganic substances differed among fault blocks, indicating that the movement of formation water between fault blocks was restricted. This finding suggests that the supply of nutrients via fluid current is limited in this subterranean environment and that the organisms are starved in the oil reservoir. Under starved conditions at 50°C, culturable cells of Thermococcus sp. remained around the initial cell density for about 200 days, while those of Thermotoga sp. decreased exponentially to 0.01% of the initial cell density after incubation for the same period. The difference in survivability between these two hyperthermophiles seems to reflect their populations in the fault blocks. These results indicate that hyperthermophilic cocci and rods adapt to the subterranean environment of the Kubiki oil reservoir by developing an ability to survive under starved

  19. Distribution and physiological characteristics of hyperthermophiles in the Kubiki oil reservoir in Niigata, Japan.

    PubMed

    Takahata, Y; Nishijima, M; Hoaki, T; Maruyama, T

    2000-01-01

    The distribution of culturable hyperthermophiles was studied in relation to environmental conditions in the Kubiki oil reservoir in Japan, where the temperature was between 50 and 58 degrees C. Dominant hyperthermophilic cocci and rods were isolated and shown to belong to the genera Thermococcus and Thermotoga, respectively, by 16S rDNA analyses. Using the most-probable-number method, we found that hyperthermophilic cocci were widely distributed in several unconnected fault blocks in the Kubiki oil reservoir. In 1996 to 1997, their populations in the production waters from oil wells were 9.2 x 10(3) to 4.6 x 10(4) cells/ml, or 10 to 42% of total cocci. On the other hand, hyperthermophilic rods were found in only one fault block of the reservoir with populations less than 10 cells/ml. Dominant Thermococcus and Thermotoga spp. grew at reservoir temperatures and utilized amino acids and sugars, respectively, as sole carbon sources. While organic carbon was plentiful in the environment, these hyperthermophiles were unable to grow in the formation water due to lack of essential nutrients. Concentrations of some organic and inorganic substances differed among fault blocks, indicating that the movement of formation water between fault blocks was restricted. This finding suggests that the supply of nutrients via fluid current is limited in this subterranean environment and that the organisms are starved in the oil reservoir. Under starved conditions at 50 degrees C, culturable cells of Thermococcus sp. remained around the initial cell density for about 200 days, while those of Thermotoga sp. decreased exponentially to 0. 01% of the initial cell density after incubation for the same period. The difference in survivability between these two hyperthermophiles seems to reflect their populations in the fault blocks. These results indicate that hyperthermophilic cocci and rods adapt to the subterranean environment of the Kubiki oil reservoir by developing an ability to survive

  20. 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.

  1. 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.

  2. 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.

  3. 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.

  4. 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.

  5. 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.

  6. 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.

  7. 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.

  8. 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.

  9. 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.

  10. 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.

  11. Evaluation of linear solvers for oil reservoir simulation problems. Part 2: The fully implicit case

    SciTech Connect

    Joubert, W.; Janardhan, R.

    1997-12-01

    A previous paper [Joubert/Biswas 1997] contained investigations of linear solver performance for matrices arising from Amoco`s Falcon parallel oil reservoir simulation code using the IMPES formulation (implicit pressure, explicit saturation). In this companion paper, similar issues are explored for linear solvers applied to matrices arising from more difficult fully implicit problems. The results of numerical experiments are given.

  12. 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.

  13. 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

  14. 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.

  15. Optimized polymer enhanced foam flooding for ordinary heavy oil reservoir after cross-linked polymer flooding.

    PubMed

    Sun, Chen; Hou, Jian; Pan, Guangming; Xia, Zhizeng

    2016-01-01

    A successful cross-linked polymer flooding has been implemented in JD reservoir, an ordinary heavy oil reservoir with high permeability zones. For all that, there are still significant volumes of continuous oil remaining in place, which can not be easily extracted due to stronger vertical heterogeneity. Considering selective plugging feature, polymer enhanced foam (PEF) flooding was taken as following EOR technology for JD reservoir. For low cost and rich source, natural gas was used as foaming gas in our work. In the former work, the surfactant systems CEA/FSA1 was recommended as foam agent for natural gas foam flooding after series of compatibility studies. Foam performance evaluation experiments showed that foaming volume reached 110 mL, half-life time reached 40 min, and dimensionless filter coefficient reached 1.180 when CEA/FSA1 reacted with oil produced by JD reservoir. To compare the recovery efficiency by different EOR technologies, series of oil displacement experiments were carried out in a parallel core system which contained cores with relatively high and low permeability. EOR technologies concerned in our work include further cross-linked polymer (C-P) flooding, surfactant-polymer (S-P) flooding, and PEF flooding. Results showed that PEF flooding had the highest enhanced oil recovery of 19.2 % original oil in place (OOIP), followed by S-P flooding (9.6 % OOIP) and C-P flooding (6.1 % OOIP). Also, produced liquid percentage results indicated PEF flooding can efficiently promote the oil recovery in the lower permeability core by modifying the injection profile.

  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, 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...

  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, 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...

  18. 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...

  19. 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...

  20. Environmental Drivers of Differences in Microbial Community Structure in Crude Oil Reservoirs across a Methanogenic Gradient

    PubMed Central

    Shelton, Jenna L.; Akob, Denise M.; McIntosh, Jennifer C.; Fierer, Noah; Spear, John R.; Warwick, Peter D.; McCray, John E.

    2016-01-01

    Stimulating in situ microbial communities in oil reservoirs to produce natural gas is a potentially viable strategy for recovering additional fossil fuel resources following traditional recovery operations. Little is known about what geochemical parameters drive microbial population dynamics in biodegraded, methanogenic oil reservoirs. We investigated if microbial community structure was significantly impacted by the extent of crude oil biodegradation, extent of biogenic methane production, and formation water chemistry. Twenty-two oil production wells from north central Louisiana, USA, were sampled for analysis of microbial community structure and fluid geochemistry. Archaea were the dominant microbial community in the majority of the wells sampled. Methanogens, including hydrogenotrophic and methylotrophic organisms, were numerically dominant in every well, accounting for, on average, over 98% of the total Archaea present. The dominant Bacteria groups were Pseudomonas, Acinetobacter, Enterobacteriaceae, and Clostridiales, which have also been identified in other microbially-altered oil reservoirs. Comparing microbial community structure to fluid (gas, water, and oil) geochemistry revealed that the relative extent of biodegradation, salinity, and spatial location were the major drivers of microbial diversity. Archaeal relative abundance was independent of the extent of methanogenesis, but closely correlated to the extent of crude oil biodegradation; therefore, microbial community structure is likely not a good sole predictor of methanogenic activity, but may predict the extent of crude oil biodegradation. However, when the shallow, highly biodegraded, low salinity wells were excluded from the statistical analysis, no environmental parameters could explain the differences in microbial community structure. This suggests that the microbial community structure of the 5 shallow, up-dip wells was different than the 17 deeper, down-dip wells. Also, the 17 down-dip wells

  1. Environmental drivers of differences in microbial community structure in crude oil reservoirs across a methanogenic gradient

    USGS Publications Warehouse

    Shelton, Jenna L.; Akob, Denise M.; McIntosh, Jennifer C.; Fierer, Noah; Spear, John R.; Warwick, Peter D.; McCray, John E.

    2016-01-01

    Stimulating in situ microbial communities in oil reservoirs to produce natural gas is a potentially viable strategy for recovering additional fossil fuel resources following traditional recovery operations. Little is known about what geochemical parameters drive microbial population dynamics in biodegraded, methanogenic oil reservoirs. We investigated if microbial community structure was significantly impacted by the extent of crude oil biodegradation, extent of biogenic methane production, and formation water chemistry. Twenty-two oil production wells from north central Louisiana, USA, were sampled for analysis of microbial community structure and fluid geochemistry. Archaea were the dominant microbial community in the majority of the wells sampled. Methanogens, including hydrogenotrophic and methylotrophic organisms, were numerically dominant in every well, accounting for, on average, over 98% of the total Archaea present. The dominant Bacteria groups were Pseudomonas, Acinetobacter, Enterobacteriaceae, and Clostridiales, which have also been identified in other microbially-altered oil reservoirs. Comparing microbial community structure to fluid (gas, water, and oil) geochemistry revealed that the relative extent of biodegradation, salinity, and spatial location were the major drivers of microbial diversity. Archaeal relative abundance was independent of the extent of methanogenesis, but closely correlated to the extent of crude oil biodegradation; therefore, microbial community structure is likely not a good sole predictor of methanogenic activity, but may predict the extent of crude oil biodegradation. However, when the shallow, highly biodegraded, low salinity wells were excluded from the statistical analysis, no environmental parameters could explain the differences in microbial community structure. This suggests that the microbial community structure of the 5 shallow, up-dip wells was different than the 17 deeper, down-dip wells. Also, the 17 down-dip wells

  2. Environmental Drivers of Differences in Microbial Community Structure in Crude Oil Reservoirs across a Methanogenic Gradient.

    PubMed

    Shelton, Jenna L; Akob, Denise M; McIntosh, Jennifer C; Fierer, Noah; Spear, John R; Warwick, Peter D; McCray, John E

    2016-01-01

    Stimulating in situ microbial communities in oil reservoirs to produce natural gas is a potentially viable strategy for recovering additional fossil fuel resources following traditional recovery operations. Little is known about what geochemical parameters drive microbial population dynamics in biodegraded, methanogenic oil reservoirs. We investigated if microbial community structure was significantly impacted by the extent of crude oil biodegradation, extent of biogenic methane production, and formation water chemistry. Twenty-two oil production wells from north central Louisiana, USA, were sampled for analysis of microbial community structure and fluid geochemistry. Archaea were the dominant microbial community in the majority of the wells sampled. Methanogens, including hydrogenotrophic and methylotrophic organisms, were numerically dominant in every well, accounting for, on average, over 98% of the total Archaea present. The dominant Bacteria groups were Pseudomonas, Acinetobacter, Enterobacteriaceae, and Clostridiales, which have also been identified in other microbially-altered oil reservoirs. Comparing microbial community structure to fluid (gas, water, and oil) geochemistry revealed that the relative extent of biodegradation, salinity, and spatial location were the major drivers of microbial diversity. Archaeal relative abundance was independent of the extent of methanogenesis, but closely correlated to the extent of crude oil biodegradation; therefore, microbial community structure is likely not a good sole predictor of methanogenic activity, but may predict the extent of crude oil biodegradation. However, when the shallow, highly biodegraded, low salinity wells were excluded from the statistical analysis, no environmental parameters could explain the differences in microbial community structure. This suggests that the microbial community structure of the 5 shallow, up-dip wells was different than the 17 deeper, down-dip wells. Also, the 17 down-dip wells

  3. 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

  4. 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.

  5. 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.

  6. 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.

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

    NASA Astrophysics Data System (ADS)

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

    2015-12-01

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

  8. 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

  9. Microbial diversity in degraded and non-degraded petroleum samples and comparison across oil reservoirs at local and global scales.

    PubMed

    Sierra-Garcia, Isabel Natalia; Dellagnezze, Bruna M; Santos, Viviane P; Chaves B, Michel R; Capilla, Ramsés; Santos Neto, Eugenio V; Gray, Neil; Oliveira, Valeria M

    2017-01-01

    Microorganisms have shown their ability to colonize extreme environments including deep subsurface petroleum reservoirs. Physicochemical parameters may vary greatly among petroleum reservoirs worldwide and so do the microbial communities inhabiting these different environments. The present work aimed at the characterization of the microbiota in biodegraded and non-degraded petroleum samples from three Brazilian reservoirs and the comparison of microbial community diversity across oil reservoirs at local and global scales using 16S rRNA clone libraries. The analysis of 620 16S rRNA bacterial and archaeal sequences obtained from Brazilian oil samples revealed 42 bacterial OTUs and 21 archaeal OTUs. The bacterial community from the degraded oil was more diverse than the non-degraded samples. Non-degraded oil samples were overwhelmingly dominated by gammaproteobacterial sequences with a predominance of the genera Marinobacter and Marinobacterium. Comparisons of microbial diversity among oil reservoirs worldwide suggested an apparent correlation of prokaryotic communities with reservoir temperature and depth and no influence of geographic distance among reservoirs. The detailed analysis of the phylogenetic diversity across reservoirs allowed us to define a core microbiome encompassing three bacterial classes (Gammaproteobacteria, Clostridia, and Bacteroidia) and one archaeal class (Methanomicrobia) ubiquitous in petroleum reservoirs and presumably owning the abilities to sustain life in these environments.

  10. 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.

  11. 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.

  12. 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.

  13. 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.

  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. Terahertz-dependent identification of simulated hole shapes in oil-gas reservoirs

    NASA Astrophysics Data System (ADS)

    Bao, Ri-Ma; Zhan, Hong-Lei; Miao, Xin-Yang; Zhao, Kun; Feng, Cheng-Jing; Dong, Chen; Li, Yi-Zhang; Xiao, Li-Zhi

    2016-10-01

    Detecting holes in oil-gas reservoirs is vital to the evaluation of reservoir potential. The main objective of this study is to demonstrate the feasibility of identifying general micro-hole shapes, including triangular, circular, and square shapes, in oil-gas reservoirs by adopting terahertz time-domain spectroscopy (THz-TDS). We evaluate the THz absorption responses of punched silicon (Si) wafers having micro-holes with sizes of 20 μm-500 μm. Principal component analysis (PCA) is used to establish a model between THz absorbance and hole shapes. The positions of samples in three-dimensional spaces for three principal components are used to determine the differences among diverse hole shapes and the homogeneity of similar shapes. In addition, a new Si wafer with the unknown hole shapes, including triangular, circular, and square, can be qualitatively identified by combining THz-TDS and PCA. Therefore, the combination of THz-TDS with mathematical statistical methods can serve as an effective approach to the rapid identification of micro-hole shapes in oil-gas reservoirs. Project supported by the National Natural Science Foundation of China (Grant No. 61405259), the National Basic Research Program of China (Grant No. 2014CB744302), and the Specially Founded Program on National Key Scientific Instruments and Equipment Development, China (Grant No. 2012YQ140005).

  16. 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 oil recovery efficiency and reduce operating costs.

  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. Camorim Field, Brazil: facies and oil qualities controlling reservoir behavior and well performances

    SciTech Connect

    Nascimento, O.S.; Menezes, S.X.; Bandeira, A. Jr.; Pimental, A.M.; Oliveira, C.M.P.

    1982-05-01

    Camorim Field is located offshore Sergipe State, Brazil. The producing section includes 150 M of Cretaceous conglomerates and coarse to very fine-grained sandstones, interbedded with siltstones and shales. Within this interval, 6 pools are recognized based on log correlation and facies analysis. The field has an area of 25 sq km and the reservoir average depth is 1900 m. Twenty-eight development wells were drilled. Reservoir geology and performance were analyzed by a multidisciplinary group. The reservoirs were fully cored in 5 wells and the correlation between rock and log responses allowed facies mapping throughout the field. The depositional model is interpreted as an alluvial-fan complex prograding toward a lacustrine environment.

  19. Simulation study to determine the feasibility of injecting hydrogen sulfide, carbon dioxide and nitrogen gas injection to improve gas and oil recovery oil-rim reservoir

    NASA Astrophysics Data System (ADS)

    Eid, Mohamed El Gohary

    This study is combining two important and complicated processes; Enhanced Oil Recovery, EOR, from the oil rim and Enhanced Gas Recovery, EGR from the gas cap using nonhydrocarbon injection gases. EOR is proven technology that is continuously evolving to meet increased demand and oil production and desire to augment oil reserves. On the other hand, the rapid growth of the industrial and urban development has generated an unprecedented power demand, particularly during summer months. The required gas supplies to meet this demand are being stretched. To free up gas supply, alternative injectants to hydrocarbon gas are being reviewed to support reservoir pressure and maximize oil and gas recovery in oil rim reservoirs. In this study, a multi layered heterogeneous gas reservoir with an oil rim was selected to identify the most optimized development plan for maximum oil and gas recovery. The integrated reservoir characterization model and the pertinent transformed reservoir simulation history matched model were quality assured and quality checked. The development scheme is identified, in which the pattern and completion of the wells are optimized to best adapt to the heterogeneity of the reservoir. Lateral and maximum block contact holes will be investigated. The non-hydrocarbon gases considered for this study are hydrogen sulphide, carbon dioxide and nitrogen, utilized to investigate miscible and immiscible EOR processes. In November 2010, re-vaporization study, was completed successfully, the first in the UAE, with an ultimate objective is to examine the gas and condensate production in gas reservoir using non hydrocarbon gases. Field development options and proces schemes as well as reservoir management and long term business plans including phases of implementation will be identified and assured. The development option that maximizes the ultimate recovery factor will be evaluated and selected. The study achieved satisfactory results in integrating gas and oil

  20. Quantitative Methods for Reservoir Characterization and Improved Recovery: Application to Heavy Oil Sands

    SciTech Connect

    Castle, James W.; Molz, Fred W.; Bridges, Robert A.; Dinwiddie, Cynthia L.; Lorinovich, Caitlin J.; Lu, Silong

    2003-02-07

    This project involved application of advanced analytical property-distribution methods conditioned to continuous outcrop control for improved reservoir characterization and simulation. The investigation was performed in collaboration with Chevron Production Company U.S.A. as an industrial partner, and incorporates data from the Temblor Formation in Chevron's West Coalinga Field, California. Improved prediction of interwell reservoir heterogeneity was needed to increase productivity and to reduce recovery cost for California's heavy oil sands, which contained approximately 2.3 billion barrels of remaining reserves in the Temblor Formation and in other formations of the San Joaquin Valley.

  1. C02 Huff-n-Puff Process in a Light Oil Shallow Shelf Carbonate Reservoir

    SciTech Connect

    Mark Kovar; Scott Wehner

    1998-01-31

    The principal objective of this CO2 Huf-n-Puff (H-n-P) project is to determine the feasibility and practicality of the technology in a waterflooded shallow shelf carbonate environment. The results of parametric simulation of the CO2 H-n-P process, coupled with reservoir characterization components are to be used to determine if this process is technically and economically feasible for field implementation. The technology transfer objective of the project is to disseminate the knowledge gained through an innovative plan of increasing oil production and deferring abandonment of shallow shelf carbonate reservoirs.

  2. Characterization of oil and gas reservoir heterogeneity. Annual report, November 1, 1990--October 31, 1991

    SciTech Connect

    Not Available

    1991-12-31

    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.

  3. Reservoir quality in relation to facies, burial history, and oil migration: A review

    SciTech Connect

    Ghosh, S.K. )

    1993-02-01

    The diagenetic make-up and, in consequence, the ultimate reservoir quality of a sand body depends on depositional facies, as well as on burial history, diagenetic fluid chemistry and timing of oil migration. A regional subsurface study in the Maracaibo Basin, Venezuela along a northwest-southeast transect in the Urdaneta, Lagunillas and Barua-Motatan fields reveal that depositional facies of the reservoir sandstones range from mainly fluvial (Urdaneta) to deltaic-coastal marine in Lagunillas, and typically sublittoral in the Barua-Motatan area. Factors such as granulometry, development of early pore-lining chlorite (in marginal marine facies), infiltrated grain-coating clays (fluvial B-6 sands), and proximity of reservoirs to the post-Eocene unconformity, have preserved, enhanced or otherwise influenced reservoir quality. Data on authigenic mineralogy, vitrinite reflectance and burial history indicate a progressively greater subsidence from northwest to southeast. As a result, diagenetic grade is immature in Urdaneta where porosity/permeability values are the highest. In contrast, the Barua-Motatan field in the southeast is typified by a higher grade of diagenesis, varied authigenic mineralogy, and severe deterioration of reservoir quality. Similarly, degree of compaction progressively increases from northwest to southeast. Timing of oil migration have parallelly contributed to systematic regional variation in reservoir quality. An early migration in Urdaneta has been favorable to preservation of original porosity. In contrast, late migration during Upper Miocene, in the Barua-Motatan field, indirectly permitted abundant silicification and consequent destruction of virtually all primary porosity. Thus both pre- and post-depositional parameters are important constraints which should be considered while evaluating quality of siliciclastic reservoirs.

  4. Improved Oil Recovery In Fluvial Dominated Deltaic Reservoirs of Kansas - Near Term

    SciTech Connect

    Green, Don W.; McCune, D.; Michnick, M.; Reynolds, R.; Walton, A.; Watney, L.; Willhite, G. Paul

    1999-01-14

    Common oil field problems exist in fluvial dominated deltaic reservoirs in Kansas. The problems are poor waterflood sweep efficiency and lack of reservoir management. The poor waterflood sweep efficiency is due to (1) reservoir heterogeneity, (2) channeling of injected water through high permeability zones or fractures, and (3) clogging of injection wells due to solids in the injection water. In many instances the lack of reservoir management results from (1) poor data collection and organization, (2) little or no integrated analysis of existing data by geological and engineering personnel, (3) the presence of multiple operators within the field, and (4) not identifying optimum recovery techniques. 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 PetroSantander, Inc. This field was in the latter stage of primary production at the beginning of this project and is currently being waterflooded as a result of this project. The Nelson Lease (an existing waterflood) is located in Allen County, Kansas, in the N.E. Savonburg Field and is operated by James E. Russell Petroleum, Inc. The objective is to increase recovery efficiency and economics in these types of reservoirs. The technologies being applied to increase waterflood sweep efficiency are (1) in situ permeability modification treatments, (2) infill drilling, (3) pattern changes, and (4) air flotation to improve water quality. The technologies being applied to improve reservoir management are (1) database development, (2) reservoir simulation, (3) transient testing, (4) database management, and (5) integrated geological and engineering analysis.

  5. Improved oil recovery in fluvial dominated reservoirs of Kansas--near-term. Annual report

    SciTech Connect

    Green, D.W.; Willhite, G.P.; Walton, A.; Schoeling, L.; Reynolds, R.; Michnick, M.; Watney, L.

    1996-11-01

    Common oil field problems exist in fluvial dominated deltaic reservoirs in Kansas. The problems are poor waterflood sweep efficiency and lack of reservoir management. The poor waterflood sweep efficiency is due to (1) reservoir heterogeneity, (2) channeling of injected water through high permeability zones or fractures, and (3) clogging of injection wells due to solids in the injection water. In many instances the lack of reservoir management results from (1) poor data collection and organization, (2) little or no integrated analysis of existing data by geological and engineering personnel, (3) the presence of multiple operators within the field, and (4) not identifying optimum recovery techniques. 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. This field was in the latter stage of primary production at the beginning of this project and is currently being waterflooded as a result of this project. The Nelson Lease (an existing waterflood) is located in Allen County, Kansas, in the N.E. Savonburg Field and is operated by James E. Russell Petroleum, Inc. The objective is to increase recovery efficiency and economics in these type of reservoirs. The technologies being applied to increase waterflood sweep efficiency are (1) in situ permeability modification treatments, (2) infill drilling, (3) pattern changes, and (4) air flotation to improve water quality. The technologies being applied to improve reservoir management are (1) database development, (2) reservoir simulation, (3) transient testing, (4) database management and (5) integrated geological and engineering analysis. Results of these two field projects are discussed.

  6. [Assessment of effects of surfactants in a heavy oil reservoir

    SciTech Connect

    Kostura, J.A.

    1991-04-08

    During the past three months we have carefully negotiated a joint venture to implement a pilot for testing the two enhanced oil recovery processes developed at CLD Technology, Inc. The technical staff at CLD Technology, Inc. has decided to model the heavy oil reserve on the Cantleberry Lease, the Jasmin oil field in Kern County, California. Staff members have designed a new sand pack to represent one-eighth (1/8) of a one, ten-acre, five-spot well pattern that will represent the sands of the Cantleberry lease. All calculated parameters are listed in Table 1. The 3-dimensional scaled physical model design represents a typical Cantleberry steamflood pattern. The design of the model will allow the creation of zones identical to those in the Cantleberry lease which will represent the shale break between the Cantleberry A'' and B'' sands. The last 3-dimensional scaled physical model experiment, needed to design the pilot, is ready to go awaiting continuous funding from the DOE.

  7. Estimation of reservoir properties of the Haynesville Shale by using rock-physics modelling and grid searching

    NASA Astrophysics Data System (ADS)

    Jiang, Meijuan; Spikes, Kyle T.

    2013-10-01

    This study presents a workflow that combines an isotropic and an anisotropic effective medium model with a grid-search method to invert for the reservoir properties (porosity, composition and pore shape) of the Haynesville Shale. The reservoir properties inverted from this workflow closely matched the observed data, and they provide very useful information in determining locations with relatively high porosities and relatively large fractions of brittle components favourable for hydraulic fracturing. The isotropic effective medium model represents a complex medium as a single homogeneous medium by including grains and pores of different shapes and sizes. The anisotropic effective medium model introduces vertical transversely isotropic media through aligned fractures. After building the relationships between the reservoir properties and P- and S-wave velocities, we used grid searching to obtain porosity, composition and pore shape distributions conditioned by the rock-physics models. The modelled seismic velocities that satisfied criteria from objective functions provided estimated reservoir properties. The porosity and composition estimations at the well location matched the observations from log and core data quite well. The pore shape estimation suggested that the pores, cracks and fractures within the Haynesville Shale have elongated shapes. Future application of this workflow at the seismic scale will provide continuous spatial distributions of these reservoir properties.

  8. Rock bolting techniques for forming an in situ oil shale retort

    SciTech Connect

    Sass, A.

    1981-08-04

    A subterranean formation containing oil shale is prepared for in situ retorting by forming a fragmented permeable mass of formation particles containing oil shale in an in situ oil shale retort site. Formation is initially excavated from the retort site for forming one or more voids extending horizontally across the retort site, leaving a zone of unfragmented formation adjacent such a void. In one ambodiment, an array of rocks bolts are anchored in at least a portion of the roof adjacent such a void for providing reinforcement of unfragmented formation above the void. Vertical blasting holes are drilled in the zone of unfragmented formation adjacent the void. Explosive is placed in the blasting holes and detonated for explosively expanding the zone of unfragmented formation toward the void, including the rock bolted portion of the roof, for forming at least a portion of a fragmented permeable mass of formation particles containing oil shale in an in situ oil shale retort. Surprisingly, the rock bolting does not interfere with, and in some instances can improve, fragmentation compared with comparable blasts without such rock bolts. The reinforcement provided by the rock bolts can reduce or eliminate the need for roof support pillars in horizontal voids at intermediate levels of the retort site.

  9. Feasibility of steam injection process in a thin, low-permeability heavy oil reservoir of Arkansas -- a numerical simulation study

    SciTech Connect

    Sarkar, A.K.; Sarathi, P.S.

    1993-12-01

    This report details the findings of an in-depth study undertaken to assess the viability of the steam injection process in the heavy oil bearing Nacatoch sands of Arkansas. Published screening criteria and DOE`s steamflood predictive models were utilized to screen and select reservoirs for further scrutiny. Although, several prospects satisfied the steam injection screening criteria, only a single candidate was selected for detailed simulation studies. The selection was based on the availability of needed data for simulation and the uniqueness of the reservoir. The reservoir investigated is a shallow, thin, low-permeability reservoir with low initial oil saturation and has an underlying water sand. The study showed that the reservoir will respond favorably to steamdrive, but not to cyclic steaming. Steam stimulation, however, is necessary to improve steam injectivity during subsequent steamdrive. Further, in such marginal heavy oil reservoirs (i.e., reservoir characterized by thin pay zone and low initial oil saturation) conventional steamdrive (i.e., steam injection using vertical wells) is unlikely to be economical, and nonconventional methods must be utilized. It was found that the use of horizontal injectors and horizontal producers significantly improved the recovery and oil-steam ratio and improved the economics. It is recommended that the applicability of horizontal steam injection technology in this reservoir be further investigated.

  10. Simonette Beaverhill Lake oil pool: Discovery history, reservoir characterization and depletion strategy

    SciTech Connect

    Ollenberger, L.R. ); Cortis, T.L. )

    1996-01-01

    A significant light oil discovery was made in reefal carbonates of the Middle-Upper Devonian Swan Hills Formation of the Beaverhill Lake Group in west-central Alberta in September, 1993. The discovery well, Chevron Simonette 7-20-64-26W5, encountered a dolomitized Swan Hills reef margin with 28 meters of net oil pay and was capable of producing 750 ml (4700 barrels) of oil per day. A total of eighteen wells have been drilled into the pool to date. The accumulation at Simonette is divided into two pools (Beaverhill Lake A and B) by a north-south trending fault. The pools are the twelfth and fourteenth largest Swan Hills oil pools discovered to date and the largest Swan Hills oil pools discovered since 1962. The pools have an average net pay of 13.5 meters, with average porosity of approximately 9% and average water saturation of 7%. Porosity is present within both dolomite and limestone and the distribution of the reservoir is controlled by depositional facies. The density of the oil is 808 kg/m[sup 3] (43[degrees] API) and the gas/oil ratio is 325 m[sup 3]/m[sup 3]. The solution gas has an H[sub 2]S content of 1.5%. Initial reservoir studies indicate that 48% of the oil in place in the A Pool can be recovered with a hydrocarbon miscible flood, which was initiated in March, 1995. A water flood, with anticipated recovery of 41% of the oil in place, will be initiated in the B Pool in early 1996.

  11. Simonette Beaverhill Lake oil pool: Discovery history, reservoir characterization and depletion strategy

    SciTech Connect

    Ollenberger, L.R.; Cortis, T.L.

    1996-12-31

    A significant light oil discovery was made in reefal carbonates of the Middle-Upper Devonian Swan Hills Formation of the Beaverhill Lake Group in west-central Alberta in September, 1993. The discovery well, Chevron Simonette 7-20-64-26W5, encountered a dolomitized Swan Hills reef margin with 28 meters of net oil pay and was capable of producing 750 ml (4700 barrels) of oil per day. A total of eighteen wells have been drilled into the pool to date. The accumulation at Simonette is divided into two pools (Beaverhill Lake A and B) by a north-south trending fault. The pools are the twelfth and fourteenth largest Swan Hills oil pools discovered to date and the largest Swan Hills oil pools discovered since 1962. The pools have an average net pay of 13.5 meters, with average porosity of approximately 9% and average water saturation of 7%. Porosity is present within both dolomite and limestone and the distribution of the reservoir is controlled by depositional facies. The density of the oil is 808 kg/m{sup 3} (43{degrees} API) and the gas/oil ratio is 325 m{sup 3}/m{sup 3}. The solution gas has an H{sub 2}S content of 1.5%. Initial reservoir studies indicate that 48% of the oil in place in the A Pool can be recovered with a hydrocarbon miscible flood, which was initiated in March, 1995. A water flood, with anticipated recovery of 41% of the oil in place, will be initiated in the B Pool in early 1996.

  12. Exploration, Drilling and Development Operations in the Bottle Rock Area of the Geysers Steam Field, With New Geologic Insights and Models Defining Reservoir Parameters

    SciTech Connect

    Hebein, Jeffrey J.

    1983-12-15

    MCR Geothermal Corporation pioneered successful exploratiory drilling the Bottle Rock area of the Geysers Steam Field in 1976. The wellfield is characterized by a deep reservoir with varied flowrates, temperatures, pressures, and stem chemistries being quite acceptable. More detailed reservoir engineering tests will follow as production commences.

  13. Increased oil production and reserves utilizing secondary/tertiary recovery techniques on small reservoirs in the Paradox Basin, Utah. Annual report, February 9, 1997--February 8, 1998

    SciTech Connect

    Chidsey, T.C. Jr.

    1998-03-01

    The Paradox basin of Utah, Colorado, and Arizona contains nearly 100 small oil fields producing from carbonate buildups or mounds within the Pennsylvanian (Desmoinesian) Paradox Formation. These fields typically have one to four wells with primary production ranging from 700,000 to 2,000,000 barrels (111,300-318,000 m{sup 3}) of oil per field at a 15 to 20 percent recovery rate. At least 200 million barrels (31,800,000 m{sup 3}) of oil are at risk of being unrecovered in these small fields because of inefficient recovery practices and undrained heterogeneous reservoirs. Five fields (Anasazi, Mule, Blue Hogan, Heron North, and Runway) within the Navajo Nation of southeastern Utah are being evaluated for waterflood or carbon-dioxide (CO{sub 2})-miscible flood projects based upon geological characterization and reservoir modeling. The results can be applied to other fields in the Paradox basin and the Rocky Mountain region, the Michigan and Illinois basins, and the Midcontinent. Geological characterization on a local scale focused on reservoir heterogeneity, quality, and lateral continuity as well as possible compartmentalization within each of the five project fields. This study utilized representative core and modern geophysical logs to characterize and grade each of the five fields for suitability of enhanced recovery projects. The typical vertical sequence or cycle of lithofacies from each field, as determined from conventional core, was tied to its corresponding log response. The diagenetic fabrics and porosity types found in the various hydrocarbon-bearing rocks of each field can be an indicator of reservoir flow capacity, storage capacity, and potential for water- and/or CO{sub 2}-flooding. Diagenetic histories of the various Desert Creek reservoirs were determined from 50 representative samples selected from the conventional cores of each field. Thin sections were also made of each sample for petrographic description.

  14. Geochemistry and origin of oil from Cambrian and Ordovician reservoirs in eastern and central Ohio

    SciTech Connect

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

    1991-08-01

    Oil from stratigraphic traps along the Middle Ordovician Knox unconformity in Ohio was analyzed to determine its geochemical characteristics, source, and migration history. The following stratigraphic units were samples: Upper Cambrian( ) Rose Run Sandstone, sample number (n) = 7; Upper Cambrian Knox Dolomite, n = 6; Upper Cambrian Krysik sandstone, n = 1; and Middle Ordovician Black River Limestone, n = 1. These Ohio oils are geochemically similar to oils in North America that are correlated with Ordovician source rocks. Seventy-one core samples from Ohio and West Virginia were analyzed by Rock-Eval for total organic carbon (TOC) and pyrolysis products and by solvent extraction to evaluate the source of the Ohio oils. Three potential source-rock intervals were tested: (1) Middle and Upper Cambrian strata in the Rome trough, (2) the Middle Ordovician Wells Creek Formation and the equivalent part of the Beekmantown Group, and (3) the Middle and Upper Ordovician Antes Shale. The thermal maturity of many samples was too high to give T{sub max} values and to yield adequate solvent extracts for detailed characterization. The Antes Shale samples have moderate TOC values ({bar x} = 1.2, n = 12) and Rock-Eval production indices between 0.3 and 0.5 ({bar x} = 0.4) calculated from nine samples with TOC greater than 0.5. These geochemical characteristics, a stratigraphic position about 1,000 ft above the Knox unconformity, and a maximum burial depth of about 10,000 ft along the Ohio-West Virginia border suggests that the Antes Shale is the probable source rock for the Ohio oils.

  15. Co-Optimization of CO2-EOR and Storage Processes in Mature Oil Reservoirs

    DOE PAGES

    Ampomah, William; Balch, Robert S.; Grigg, Reid B.; ...

    2016-08-02

    This article presents an optimization methodology for CO2 enhanced oil recovery in partially depleted reservoirs. A field-scale compositional reservoir flow model was developed for assessing the performance history of an active CO2 flood and for optimizing both oil production and CO2 storage in the Farnsworth Unit (FWU), Ochiltree County, Texas. A geological framework model constructed from geophysical, geological, and engineering data acquired from the FWU was the basis for all reservoir simulations and the optimization method. An equation of state was calibrated with laboratory fluid analyses and subsequently used to predict the thermodynamic minimum miscible pressure (MMP). Initial history calibrationsmore » of primary, secondary and tertiary recovery were conducted as the basis for the study. After a good match was achieved, an optimization approach consisting of a proxy or surrogate model was constructed with a polynomial response surface method (PRSM). The PRSM utilized an objective function that maximized both oil recovery and CO2 storage. Experimental design was used to link uncertain parameters to the objective function. Control variables considered in this study included: water alternating gas cycle and ratio, production rates and bottom-hole pressure of injectors and producers. Other key parameters considered in the modeling process were CO2 purchase, gas recycle and addition of infill wells and/or patterns. The PRSM proxy model was ‘trained’ or calibrated with a series of training simulations. This involved an iterative process until the surrogate model reached a specific validation criterion. A sensitivity analysis was first conducted to ascertain which of these control variables to retain in the surrogate model. A genetic algorithm with a mixed-integer capability optimization approach was employed to determine the optimum developmental strategy to maximize both oil recovery and CO2 storage. The proxy model reduced the computational cost

  16. Log evaluation of oil-bearing igneous rocks

    SciTech Connect

    Khatchikian, A.

    1983-12-01

    The evaluation of porosity, water saturation and clay content of oilbearing igneous rocks with well logs is difficult due to the mineralogical complexity of this type of rocks. The log responses to rhyolite and rhyolite tuff; andesite, dacite and zeolite tuff; diabase and basalt have been studied from examples in western Argentina and compared with values observed in other countries. Several field examples show how these log responses can be used in a complex lithology program to make a complete evaluation.

  17. Investigation of oil recovery improvement by coupling an interfacial tension agent and a mobility control agent in light oil reservoirs. Annual report, October 1992--September 1993

    SciTech Connect

    Pitts, M.J.

    1994-06-01

    Investigation of Oil Recovery Improvement by Coupling and Interfacial Tension Agent and a Mobility Control Agent in Light Oil Reservoirs will study 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 agent, surfactants, and polymers on a fluid-fluid and fluid-rock basis. The second area concerns the economic improvement of the combined technology. This report examines the interactions of different alkaline agents, surfactants, and polymer combinations on a fluid-fluid basis. Alkali and surfactant combine to reduce the interfacial tension between a low acid number, 42 API gravity crude oil and the aqueous solution to values lower than either agent alone. Surfactant structure can vary from linear chain sulfonates to alkyl aryl sulfonates to produce low interfacial tension values when combined with alkali. However as a class, the alkyl aryl sulfonates were the most effective surfactants. Surfactant olefinic character appears to be critical in developing low interfacial tensions. For the 42 API gravity crude oil, surfactants with molecular weights ranging from 370 to 450 amu are more effective in lowering interfacial tension. Ultra low interfacial tensions were achieved with all of the alkaline agents evaluated when combined with appropriate surfactants. Different interfacial tension reduction characteristics with the various alkali types indicates alkali interacts synergistically with the surfactants to develop interfacial tension reduction. The solution pH is not a determining factor in lowering interfacial tension. Surfactant is the dominant agent for interfacial tension reduction.

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

    SciTech Connect

    Jill S. Buckley; Norman R. Morrow

    2002-12-01

    We report on a preliminary study of wetting effects of synthetic oil-based mud components on the wetting of mica surfaces using drilling mud fractions obtained from two wells drilled with synthetic oil-based muds (SBM). We have used these SBM fractions, one a filtrate and the other a centrifugate, to develop testing protocols for studies on smooth mica surfaces. Both SBM fractions changed the wetting of clean, dry mica surfaces, making them preferentially oil-wet. Solvents were tested to clean the mica with varying degrees of success. In tests designed to simulate contact between SBM fractions and reservoir pore surface, changes of wetting of mica that had previously been exposed to brine and crude oil were examined using six different crude oils in combination with several different brine formulations. Four of the six oils produced preferentially water-wet surfaces whereas two produced fairly oil-wet conditions on mica. Exposure to the SBM fractions tended to increase decane/water advancing contact angles on the more water-wet surfaces and to decrease those on the more oil-wet surfaces. Cleaning solvents were compared for their efficacy and the possibility of wettability restoration was examined for some of the cleaned surfaces.

  19. Oil recovery enhancement from fractured, low permeability reservoirs. Annual report 1990--1991, Part 1

    SciTech Connect

    Poston, S.W.

    1991-12-31

    Joint funding by the Department of Energy and the State of Texas has Permitted a three year, multi-disciplinary investigation to enhance oil recovery from a dual porosity, fractured, low matrix permeability oil reservoir to be initiated. The Austin Chalk producing horizon trending thru the median of Texas has been identified as the candidate for analysis. Ultimate primary recovery of oil from the Austin Chalk is very low because of two major technological problems. The commercial oil producing rate is based on the wellbore encountering a significant number of natural fractures. The prediction of the location and frequency of natural fractures at any particular region in the subsurface is problematical at this time, unless extensive and expensive seismic work is conducted. A major portion of the oil remains in the low permeability matrix blocks after depletion because there are no methods currently available to the industry to mobilize this bypassed oil. The following multi-faceted study is aimed to develop new methods to increase oil and gas recovery from the Austin Chalk producing trend. These methods may involve new geological and geophysical interpretation methods, improved ways to study production decline curves or the application of a new enhanced oil recovery technique. The efforts for the second year may be summarized as one of coalescing the initial concepts developed during the initial phase to more in depth analyses. Accomplishments are predicting natural fractures; relating recovery to well-log signatures; development of the EOR imbibition process; mathematical modeling; and field test.

  20. Characterization of thermophilic consortia from two souring oil reservoirs.

    PubMed

    Mueller, R F; Nielsen, P H

    1996-09-01

    The microbial consortia from produced water at two different oil fields in Alaska (Kuparuk) and the North Sea (Ninian) were investigated for sulfate-reducing and methanogenic activity over a range of temperatures and for a variety of substrates. The consortia were sampled on site, and samples were either incubated on site at 60(deg)C with various substrates or frozen for later incubation and analyses. Temperature influenced the rates of sulfate reduction, hydrogen sulfide production, and substrate oxidation, as well as the cell morphology. The highest rates of sulfate reduction and substrate oxidation were found between 50 and 60(deg)C. Formate and n-butyrate were the most favorable electron donors at any tested temperature. Acetate was utilized at 35(deg)C but not at 50 or 70(deg)C and was produced at 60(deg)C. This indicates that the high levels of acetate found in produced water from souring oil formations are due mainly to an incomplete oxidation of volatile fatty acids to acetate. The cell size distribution of the microbial consortium indicated a nonuniform microbial composition in the original sample from the Kuparuk field. At different temperatures, different microbial morphologies and physiologies were observed. Methane-producing activity at thermophilic temperatures (60(deg)C) was found only for the Kuparuk consortium when hydrogen and carbon dioxide were present. No methane production from acetate was observed. Suppression of methanogenic activity in the presence of sulfate indicated a competition with sulfate-reducing bacteria for hydrogen.

  1. Combining water-rock interaction experiments with reaction path and reactive transport modelling to predict reservoir rock evolution in an enhanced geothermal system

    NASA Astrophysics Data System (ADS)

    Kuesters, Tim; Mueller, Thomas; Renner, Joerg

    2016-04-01

    Reliably predicting the evolution of mechanical and chemical properties of reservoir rocks is crucial for efficient exploitation of enhanced geothermal systems (EGS). For example, dissolution and precipitation of individual rock forming minerals often result in significant volume changes, affecting the hydraulic rock properties and chemical composition of fluid and solid phases. Reactive transport models are typically used to evaluate and predict the effect of the internal feedback of these processes. However, a quantitative evaluation of chemo-mechanical interaction in polycrystalline environments is elusive due to poorly constrained kinetic data of complex mineral reactions. In addition, experimentally derived reaction rates are generally faster than reaction rates determined from natural systems, likely a consequence of the experimental design: a) determining the rate of a single process only, e.g. the dissolution of a mineral, and b) using powdered sample materials and thus providing an unrealistically high reaction surface and at the same time eliminating the restrictions on element transport faced in-situ for fairly dense rocks. In reality, multiple reactions are coupled during the alteration of a polymineralic rocks in the presence of a fluid and the rate determining process of the overall reactions is often difficult to identify. We present results of bulk rock-water interaction experiments quantifying alteration reactions between pure water and a granodiorite sample. The rock sample was chosen for its homogenous texture, small and uniform grain size (˜0.5 mm in diameter), and absence of pre-existing alteration features. The primary minerals are plagioclase (plg - 58 vol.%), quartz (qtz - 21 vol.%), K-feldspar (Kfs - 17 vol.%), biotite (bio - 3 vol.%) and white mica (wm - 1 vol.%). Three sets of batch experiments were conducted at 200 ° C to evaluate the effect of reactive surface area and different fluid path ways using (I) powders of the bulk rock with

  2. The impact of reservoir conditions and rock heterogeneity on multiphase flow in CO2-brine-sandstone systems

    NASA Astrophysics Data System (ADS)

    Krevor, S. C.; Reynolds, C. A.; Al-Menhali, A.; Niu, B.

    2015-12-01

    Capillary strength and multiphase flow are key for modeling CO2 injection for CO2 storage. Past observations of multiphase flow in this system have raised important questions about the impact of reservoir conditions on flow through effects on wettability, interfacial tension and fluid-fluid mass transfer. In this work we report the results of an investigation aimed at resolving many of these outstanding questions for flow in sandstone rocks. The drainage capillary pressure, drainage and imbibition relative permeability, and residual trapping [1] characteristic curves have been characterized in Bentheimer and Berea sandstone rocks across a pressure range 5 - 20 MPa, temperatures 25 - 90 C and brine salinities 0-5M NaCl. Over 30 reservoir condition core flood tests were performed using techniques including the steady state relative permeability test, the semi-dynamic capillary pressure test, and a new test for the construction of the residual trapping initial-residual curve. Test conditions were designed to isolate effects of interfacial tension, viscosity ratio, density ratio, and salinity. The results of the tests show that, in the absence of rock heterogeneity, reservoir conditions have little impact on flow properties, consistent with continuum scale multiphase flow theory for water wet systems. The invariance of the properties is observed, including transitions of the CO2 from a gas to a liquid to a supercritical fluid, and in comparison with N2-brine systems. Variations in capillary pressure curves are well explained by corresponding changes in IFT although some variation may reflect small changes in wetting properties. The low viscosity of CO2at certain conditions results in sensitivity to rock heterogeneity. We show that (1) heterogeneity is the likely source of uncertainty around past relative permeability observations and (2) that appropriate scaling of the flow potential by a quantification of capillary heterogeneity allows for the selection of core flood

  3. The effect of thermotropic oil-displacing compound thickened Ninka on reservoir microflora and the composition of oil in Usinskoe oil field

    NASA Astrophysics Data System (ADS)

    Ovsyannikova, V. S.; Shcherbakova, A. G.; Guseva, Y. Z.; Altunina, L. K.; Chuykina, D. I.

    2016-11-01

    The work presents results of the study of the impact of thermotropic sol-forming compound thickened NINKA on enhanced oil recovery, stimulation of oil production, on the composition of crude oil, and on oil reservoir microflora sampled from reservoir fluids in the testing and reference areas of Usinskoe field. In vitro, the compound in the concentrations of 0.1-0.5% has a stimulating effect on the microflora, which is more pronounced in a low-mineralized environment. In reservoir conditions, after the injection of the compound, along with the appearance of nitrogen-containing components of the compound and products of its hydrolysis in the wellstream, some wells showed a significant increase in the number of heterotrophic and denitrifying microflora, which is indicative of a stimulating effect of the compound. The change in the composition of oil from these producing wells is due to the desorption of polar and high-molecular components and, to a lesser extent, to the redistribution of filtration flows.

  4. Significance of oil-like hydrocarbons in metamorphic and ore-deposit rocks

    SciTech Connect

    Price, L.C.

    1996-10-01

    Carbonaceous rocks (0.7-45.0% carbon content) from both greenschist metamorphism and hydrothermal-ore deposition were solvent-extracted and the resulting extracts characterized by standard analyses. Blank runs showed no contamination from laboratory procedures. The recovered HCS are in low, but significant, concentrations (0.5-50 ppm, rock weight). Moreover, the composition of these HCS (including biomarkers) resemble that of mature crude oils and do not have the ultra-mature characteristics expected from their high temperature environs. This strongly suggests that HCS will survive in even higher-rank rocks. These data contradict petroleum-geochemical paradigm regarding an inferred thermal instability of HCS and also bear on natural gas origins (e.g. - the hypothesized cracking of oil to gas), rock-water-HC interactions, petroleum-geochemical models, and other related topics.

  5. [Isolation and identification of a methanogen from the high temperature oil reservoir water].

    PubMed

    Liu, Haichang; Lan, Guihong; Liu, Quanquan; Zhang, Wenjing; Cao, Yi; Deng, Yu; Zhang, Hui

    2010-07-01

    To explore new microbial resources in deep subsurface oil reservoirs, strain DL-7 was isolated with Hungate technology from oil reservoir water sampled from Dagang oilfield, China. Physiological and biochemical examinations showed that H2/CO2 is the unique substrate of the strain, which cannot metabolize formate, methanol, trimethylamine, acetate and other secondary alcohols. The optimum growth conditions were further identified to be 60 degrees C, pH 7.0-7.5 and 0.25% NaCl. Moreover, the strain cannot grow without yeast extract. Analysis of its 16S rRNA sequence indicated that a similarity of 99.7% presents between the strain and the model species M. marburgensis DSM2133T (X15364).

  6. Feasibility Study of Non-Radioactive Tracers for Monitoring Injected Water in Oil Reservoirs

    NASA Astrophysics Data System (ADS)

    Sawamura, H.; Nishimura, K.; Mituishi, H.; Muta, T.; Schweitzer, J. S.

    This paper discusses the results of analyses conducted on non-radioactive tracers that can be used in combination with the sea water injected into a well for monitoring the water permeating through the oil reservoir by a nuclear logging tool utilizing a pulsed neutron generator. The model of the pulsed neutron tool is constructed to permit Monte Carlo Simulations to be performed of the tool response to the presence of non-radioactive tracers to achieve a desirable level of the neutron absorbing cross sections in the sea water injected into and permeating through the oil reservoirs. Sensitivity analyses of the tool response of the nuclear logging tool were performed for two types of non-radioactive tracers, ammonium tetraborate and gadolinium chloride.

  7. Recognition of an infracambrian source rock based on biomarkers in the Baghewala-1 oil, India

    SciTech Connect

    Peters, K.E.; Clark, M.E.; Lee, C.Y.

    1995-10-01

    Heavy, sulfur-rich oil produced from the Infra-cambrian (540-640 Ma) Jodhpur Formation in the Baghewala-1 well represents a new exploration play in the Bikaner-Nagaur basin in India and the punjab basin in Pakistan. The Baghewala-1 oil is nonbiodegraded, and thermal-maturation-dependent biomarker ratios indicate generation from the source rock within the early oil window. Age-diagnostic and source-dependent biomarkers indicate that the oil originated from algal and bacterial organic matter with no higher plant input in an Infracambrian, carbonate-rich source rock deposited under anoxic marine conditions. These characteristics support a local origin of the Baghewala-1 oil from organic-rich laminated dolomites in the Infracambrian Bilara Formation. Significant amounts of petroleum could originate from equivalents of the proposed Bilara source rock in the Punjab basin, Pakistan, where the Precambrian to lower Paleozoic section is thicker and more deeply buried than in India. Deeper burial of the source rock in the Punjab basin than in the Bikaner-Nagaur basin could generate more mature equivalents of the Baghewala-1 oil. The Baghewala-1 oil is geochemically similar to another heavy oil from the Infracambrian Salt Range Series in the nearby Karampur-1 well in Pakistan and to oils derived from carbonate-evaporite facies of the Infracambrian Huqf Group about 2000 km (1243 mi) to the southwest in the Eastern Flank province of southern Oman. These findings are consistent with published evidence that subsiding rift basins in northwest India, Pakistan, and southern Oman were in close proximity during the Infracambrian along the Middle Eastern edge of Gondwanaland.

  8. Reliability of Low-Salinity Waterflooding in Oil Recovery: Effects of Reservoir Conditions and Fractures

    NASA Astrophysics Data System (ADS)

    Namnoum, Ali; Abdelaziz, Ramadan

    2016-04-01

    ​Low-salinity waterflooding is a relatively new technique for enhanced oil recovery. The paper aims at understanding the thermal, physical and chemical processes in the fractured reservoirs. The effects of water injection in the fractured formations are simulated by TOUGH2 and TOUGHREACT analyses with a case study. Using TOUGHREACT as a geochemical model provides an inclusive insight into possible changes in the mineral composition.

  9. Development of a reservoir-type transdermal delivery system containing eucalyptus oil for tetramethylpyrazine.

    PubMed

    Shen, Teng; Xu, Huinan; Weng, Weiyu; Zhang, Jianfeng

    2013-01-01

    The purpose of this study was to formulate a reservoir-type transdermal delivery system (TDS) for 2,3,5,6-tetramethylpyrazine (TMP) to enable the delivery of a sufficient dose through human skin to achieve an effective therapeutic plasma concentration. To improve the penetration of TMP in the reservoir-type TDS, several chemical penetration enhancers were investigated using in vitro rat dorsal skin permeation studies. Eucalyptus oil was found to enhance the permeation of TMP to the greatest extent, with the optimal concentration being 5% and the flux being 542.6 ± 49.7 μg/cm(2)/h, which was 4.5-fold greater than control with no enhancer (p < 0.01). The flux of the optimized reservoir-type TDS permeated through the human epidermis was 346.0 ± 27.7 μg/cm(2)/h. Based on the in vitro human skin permeation flux and the pharmacokinetics parameters observed, the clinical surface area of the TDS patch was predicted to be 20 cm(2). The in vivo study conducted in rabbits showed that the TMP TDS patch containing 5% eucalyptus oil had a more favorable pharmacokinetic profile, with a lower C(max) and prolonged T(max) and mean residence time than that observed with the oral administration of TMP. The TMP reservoir-type TDS was shown to be a promising alternative route to oral administration or intravenous infusion of TMP.

  10. Improved oil recovery in fluvial dominated deltaic reservoirs of Kansas - Near-term, Class I

    SciTech Connect

    Green, D.W.; Willhite, G.P.; Reynolds, Rodney R.; McCune, A. Dwayne; Michnick, Michael J.; Walton, Anthony W.; Watney, W. Lynn

    2000-06-08

    This project involved two demonstration projects, one in a Marrow reservoir located in the southwestern part of the state and the second in the Cherokee Group in eastern Kansas. Morrow reservoirs of western Kansas are still actively being explored and constitute an important resource in Kansas. Cumulative oil production from the Morrow in Kansas is over 400,000,000 bbls. Much of the production from the Morrow is still in the primary stage and has not reached the mature declining state of that in the Cherokee. The Cherokee Group has produced about 1 billion bbls of oil since the first commercial production began over a century ago. It is a billion-barrel plus resource that is distributed over a large number of fields and small production units. Many of the reservoirs are operated close to the economic limit, although the small units and low production per well are offset by low costs associated with the shallow nature of the reservoirs (less than 1000 ft. deep).

  11. Characterization of Thermophilic Consortia from Two Souring Oil Reservoirs

    PubMed Central

    Mueller, R. F.; Nielsen, P. H.

    1996-01-01

    The microbial consortia from produced water at two different oil fields in Alaska (Kuparuk) and the North Sea (Ninian) were investigated for sulfate-reducing and methanogenic activity over a range of temperatures and for a variety of substrates. The consortia were sampled on site, and samples were either incubated on site at 60(deg)C with various substrates or frozen for later incubation and analyses. Temperature influenced the rates of sulfate reduction, hydrogen sulfide production, and substrate oxidation, as well as the cell morphology. The highest rates of sulfate reduction and substrate oxidation were found between 50 and 60(deg)C. Formate and n-butyrate were the most favorable electron donors at any tested temperature. Acetate was utilized at 35(deg)C but not at 50 or 70(deg)C and was produced at 60(deg)C. This indicates that the high levels of acetate found in produced water from souring oil formations are due mainly to an incomplete oxidation of volatile fatty acids to acetate. The cell size distribution of the microbial consortium indicated a nonuniform microbial composition in the original sample from the Kuparuk field. At different temperatures, different microbial morphologies and physiologies were observed. Methane-producing activity at thermophilic temperatures (60(deg)C) was found only for the Kuparuk consortium when hydrogen and carbon dioxide were present. No methane production from acetate was observed. Suppression of methanogenic activity in the presence of sulfate indicated a competition with sulfate-reducing bacteria for hydrogen. PMID:16535394

  12. Classification and quantification of pore shapes in sandstone reservoir rocks with 3-D X-ray micro-computed tomography

    NASA Astrophysics Data System (ADS)

    Schmitt, M.; Halisch, M.; Müller, C.; Fernandes, C. P.

    2015-12-01

    Recent years have seen a growing interest in the characterization of the pore morphologies of reservoir rocks and how the spatial organization of pore traits affects the macro behaviour of rock-fluid systems. With the availability of 3-D high-resolution imaging (e.g. μ-CT), the detailed quantification of particle shapes has been facilitated by progress in computer science. Here, we show how the shapes of irregular rock particles (pores) can be classified and quantified based on binary 3-D images. The methodology requires the measurement of basic 3-D particle descriptors and a shape classification that involves the similarity of artificial objects, which is based on main pore network detachments and 3-D sample sizes. The results were validated for three sandstones (S1, S2 and S3) from distinct reservoirs, and most of the pore shapes were found to be plate- and cube-like. Furthermore, this study generalizes a practical way to correlate specific particle shapes, such as rods, blades, cuboids, plates and cubes, to characterize asymmetric particles of any material type with 3-D image analysis.

  13. An integrated petrophysical and rock physics analysis to improve reservoir characterization of Cretaceous sand intervals in Middle Indus Basin, Pakistan

    NASA Astrophysics Data System (ADS)

    Azeem, Tahir; Chun, Wang Yan; MonaLisa; Khalid, Perveiz; Xue Qing, Liu; Ehsan, Muhammad Irfan; Jawad Munawar, Muhammad; Wei, Xie

    2017-03-01

    The sand intervals of the Lower Goru Formation of the Cretaceous age, widely distributed in the Middle and Lower Indus Basin of Pakistan, are proven reservoirs. However, in the Sawan gas field of the Middle Indus Basin, these sandstone intervals are very deep and extremely heterogeneous in character, which makes it difficult to discriminate lithologies and fluid saturation. Based on petrophysical analysis and rock physics modeling, an integrated approach is adopted to discriminate between lithologies and fluid saturation in the above-mentioned sand intervals. The seismic velocities are modeled using the Xu–White clay–sand mixing rock physics model. The calibrated rock physics model shows good consistency between measured and modeled velocities. The correlation between measured and modeled P and S wave velocities is 92.76% and 84.99%, respectively. This calibrated model has been successfully used to estimate other elastic parameters, even in those wells where both shear and sonic logs were missing. These estimated elastic parameters were cross-plotted to discriminate between the lithology and fluid content in the target zone. Cross plots clearly separate the shale, shaly sand, and gas-bearing sand clusters, which was not possible through conventional petrophysical analysis. These data clusters have been exported to the corresponding well for the purpose of interpolation between wells and to analyze the lateral and vertical variations in lithology and fluid content in the reservoir zone.

  14. Mineral content prediction for unconventional oil and gas reservoirs based on logging data

    NASA Astrophysics Data System (ADS)

    Maojin, Tan; Youlong, Zou; Guoyue

    2012-09-01

    Coal bed methane and shale oil &gas are both important unconventional oil and gas resources, whose reservoirs are typical non-linear with complex and various mineral components, and the logging data interpretation model are difficult to establish for calculate the mineral contents, and the empirical formula cannot be constructed due to various mineral. The radial basis function (RBF) network analysis is a new method developed in recent years; the technique can generate smooth continuous function of several variables to approximate the unknown forward model. Firstly, the basic principles of the RBF is discussed including net construct and base function, and the network training is given in detail the adjacent clustering algorithm specific process. Multi-mineral content for coal bed methane and shale oil &gas, using the RBF interpolation method to achieve a number of well logging data to predict the mineral component contents; then, for coal-bed methane reservoir parameters prediction, the RBF method is used to realized some mineral contents calculation such as ash, volatile matter, carbon content, which achieves a mapping from various logging data to multimineral. To shale gas reservoirs, the RBF method can be used to predict the clay content, quartz content, feldspar content, carbonate content and pyrite content. Various tests in coalbed and gas shale show the method is effective and applicable for mineral component contents prediction

  15. Extended application of radon as a natural tracer in oil reservoirs

    NASA Astrophysics Data System (ADS)

    Pinto, A. M. F.; Barreto, A. A.; Moreira, R. M.; Tambourgi, E. B.

    2013-05-01

    In the 80's it was a common practice in the study of contamination by NAPL to incorporate a tracer to the medium to be studied. At that time the first applications focused on the use of 222Rn, a naturally occurring radioactive isotope as a natural tracer, appropriate for thermodynamics studies, geology and transport properties in thermal reservoirs. In 1993 the deficit of radon was used to spot and quantify the contamination by DNAPL under the surface. For the first time these studies showed that radon could be used as a partitioning tracer. A methodology that provides alternatives to quantify the oil volume stored in the porous space of oil reservoirs is under development at CDTN. The methodology here applied, widens up and adapts the knowledge acquired from the use of radon as a tracer to the studies aimed at assessing SOR. It is a postulation of this work that once the radon partition coefficient between oil and water is known, SOR will be determined considering the increased amount of radon in the water phase as compared to the amount initially existent as the reservoir is flooded with water. This paper will present a description of the apparatus used and some preliminary results of the experiments.

  16. Oil/source rock correlations in the Polish Flysch Carpathians and Mesozoic basement and organic facies of the Oligocene Menilite Shales: Insights from hydrous pyrolysis experiments

    USGS Publications Warehouse

    Curtis, John B.; Kotarba, M.J.; Lewan, M.D.; Wieclaw, D.

    2004-01-01

    The Oligocene Menilite Shales in the study area in the Polish Flysch Carpathians are organic-rich and contain varying mixtures of Type-II, Type-IIS and Type-III kerogen. The kerogens are thermally immature to marginally mature based on atomic H/C ratios and Rock-Eval data. This study defined three organic facies, i.e., sedimentary strata with differing hydrocarbon-generation potentials due to varying types and concentrations of organic matter. These facies correspond to the Silesian Unit and the eastern and western portions of the Skole Unit. Analysis of oils generated by hydrous pyrolysis of outcrop samples of Menilite Shales demonstrates that natural crude oils reservoired in the flysch sediments appear to have been generated from the Menilite Shales. Natural oils reservoired in the Mesozoic basement of the Carpathian Foredeep appear to be predominantly derived and migrated from Menilite Shales, with a minor contribution from at least one other source rock most probably within Middle Jurassic strata. Definition of organic facies may have been influenced by the heterogeneous distribution of suitable Menilite Shales outcrops and producing wells, and subsequent sample selection during the analytical phases of the study. ?? 2004 Elsevier Ltd. All rights reserved.

  17. RESERVOIR CHARACTERIZATION OF UPPER DEVONIAN GORDON SANDSTONE, JACKSONBURG STRINGTOWN OIL FIELD, NORTHWESTERN WEST VIRGINIA

    SciTech Connect

    S. Ameri; K. Aminian; K.L. Avary; H.I. Bilgesu; M.E. Hohn; R.R. McDowell; D.L. Matchen

    2001-07-01

    The Jacksonburg-Stringtown oil field contained an estimated 88,500,000 barrels of oil in place, of which approximately 20,000,000 barrels were produced during primary recovery operations. A gas injection project, initiated in 1934, and a pilot waterflood, begun in 1981, yielded additional production from limited portions of the field. The pilot was successful enough to warrant development of a full-scale waterflood in 1990, involving approximately 8,900 acres in three units, with a target of 1,500 barrels of oil per acre recovery. Historical patterns of drilling and development within the field suggests that the Gordon reservoir is heterogeneous, and that detailed reservoir characterization is necessary for understanding well performance and addressing problems observed by the operators. The purpose of this work is to establish relationships among permeability, geophysical and other data by integrating geologic, geophysical and engineering data into an interdisciplinary quantification of reservoir heterogeneity as it relates to production. Conventional stratigraphic correlation and core description shows that the Gordon sandstone is composed of three parasequences, formed along the Late Devonian shoreline of the Appalachian Basin. The parasequences comprise five lithofacies, of which one includes reservoir sandstones. Pay sandstones were found to have permeabilities in core ranging from 10 to 200 mD, whereas non-pay sandstones have permeabilities ranging from below the level of instrumental detection to 5 mD; Conglomeratic zones could take on the permeability characteristics of enclosing materials, or could exhibit extremely low values in pay sandstone and high values in non-pay or low permeability pay sandstone. Four electrofacies based on a linear combination of density and scaled gamma ray best matched correlations made independently based on visual comparison of geophysical logs. Electrofacies 4 with relatively high permeability (mean value > 45 mD) was

  18. 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, 2011 CFR

    2011-07-01

    ... gas from an oil reservoir with an associated gas cap? 250.1157 Section 250.1157 Mineral Resources... reservoir with an associated gas cap? (a) You must request and receive approval from the Regional Supervisor: (1) Before producing gas-cap gas from each completion in an oil reservoir that is known to have...

  19. EXPERIMENTAL AND THEORETICAL DETERMINATION OF HEAVY OIL VISCOSITY UNDER RESERVOIR CONDITIONS

    SciTech Connect

    Dr. Jorge Gabitto; Maria Barrufet

    2003-05-01

    The USA deposits of heavy oils and tar sands contain significant energy reserves. Thermal methods, particularly steam drive and steam soak, are used to recover heavy oils and bitumen. Thermal methods rely on several displacement mechanisms to recover oil, but the most important is the reduction of crude viscosity with increasing temperature. The main objective of this research is 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. First, we reviewed critically the existing literature choosing the most promising models for viscosity determination. Then, we modified an existing viscosity correlation, based on the corresponding states principle in order to fit more than two thousand commercial viscosity data. We collected data for compositional and black oil samples (absence of compositional data). The data were screened for inconsistencies resulting from experimental error. A procedure based on the monotonic increase or decrease of key variables was implemented to carry out the screening process. The modified equation was used to calculate the viscosity of several oil samples where compositional data were available. Finally, a simple procedure was proposed to calculate black oil viscosity from common experimental information such as, boiling point, API gravity and molecular weight.

  20. Inverse modelling of the reversely magnetized, shallow plumbing system hosting oil reservoirs of the Auca Mahuida volcano (Payeina retroarc, Neuquén Basin, Argentina)

    NASA Astrophysics Data System (ADS)

    Paine, John; De Ritis, Riccardo; Ventura, Guido; Longo, Mariana; Ravat, Dhananjay; Speranza, Fabio; Chiappini, Massimo

    2016-02-01

    The Auca Mahuida volcano (2.03-0.88 Ma) located east of the Andean thrust front in the Neuquén basin (Argentina) hosts an oil system of thermogenic origin and is affected by the NW-SE striking-faults. Intrusive bodies and the underlying Jurassic sediments constitute the reservoir rocks. Aeromagnetic data collected in the Auca Mahuida area detected multiple dipolar magnetic anomalies, many of which have reverse polarity. Palaeomagnetic measurements on rock samples collected in the field together with available age determinations indicate that the reversely magnetized sources were mainly emplaced during the Matuyama reverse polarity chron while the normal polarity sources were emplaced during the Olduvai and/or Jaramillo subchrons. The location and geometry of the intrusive bodies is poorly known and the customary magnetic inversion is rendered difficult because of multiple natural remanent magnetization directions. To address these difficulties, a voxel inversion was applied to model the vector residual magnetic intensity (VRMI) transformation of the observed total magnetic intensity data. The modelling showed a 1.5 km deep, subcircular ring-shaped intrusion below the summit of the volcano and a series of NW-SE elongated, fault-controlled intrusive bodies to depths up to 3-4 km. Our results show that magnetic data and VRMI modelling help resolve the geometry of the shallow plumbing system of volcanoes with remanently magnetized sources, and estimate the depth and geometry of potential oil reservoirs in volcanic areas.

  1. CO2 Huff-n-Puff Process in a Light Oil Shallow Shelf Carbonate Reservoir

    SciTech Connect

    John Prieditis; Mark Kovar; Roger Cole; Scott Wehner

    1998-02-02

    The principal objective of the Sundown Slaughter Unit (SSU) CO2 Huff- n- Puff (H- n- P) project is to determine the feasibility and practicality of the technology in a waterflooded shallow shelf carbonate environment. Sundown Slaughter Unit is the second demonstration site associated with this project, following the unsuccessful test at Central Vacuum Unit. The ultimate goal will be to develop guidelines based on commonly available data that other operators in the industry can use to investigate the applicability of the process within other fields. The technology transfer objective of the project is to disseminate the knowledge gained through an innovative plan in support of the Department of Energy's (DOE) objective of increasing domestic oil production and deferring the abandonment of shallow shelf carbonate (SSC) reservoirs. Tasks associated with this objective are carried out in what is a timely effort for near- term goals. The goal of this Sundown Slaughter Unit Project is to demonstrate the CO2 Huff- n- Puff process in a waterflooded, light oil, shallow shelf carbonate reservoir within the Permian Basin. The CO2 Huff- n- Puff process is a proven enhanced oil recovery technology for Louisiana- Texas gulf coast sandstone reservoirs. The reader is referred to three Society of Petroleum Engineer (SPE) papers, No. 15502, No. 16720 & No. 20208 for a review of the theory, mechanics of the process, and several case histories. The process has even been shown to be moderately effective in conjunction with steam on heavy California crude oils. Although the technology is proven in gulf coast sandstones, it continues to be a very underutilized enhanced recovery option for carbonates. The goal of this technology demonstration is to gain an overall understanding of the reservoir qualities that influence CO2 Huff- n- Puff production responses within a heterogeneous reservoir such as the shallow shelf carbonate environment of the Sundown Slaughter Unit. A generalized

  2. Integrated electromagnetic data investigation of a Mesozoic CO2 storage target reservoir-cap-rock succession, Svalbard

    NASA Astrophysics Data System (ADS)

    Beka, Thomas I.; Senger, Kim; Autio, Uula A.; Smirnov, Maxim; Birkelund, Yngve

    2017-01-01

    Recently acquired time-domain electromagnetic (TEM) and magnetotelluric (MT) data sets are utilized in the first electromagnetic (EM) characterization of a geological CO2 storage target site in Adventdalen, Arctic Norway. Combining the two EM data sets enabled to resolve the electrical resistivity structure of the target site better than either of the methods alone. 2D inverting the MT data in the audio period interval (0.003-1 s) with supporting input derived from the TEM data (0.01-10 ms) provided a geologically meaningful resistivity model that included information not previously evident from existing seismic and borehole data. The ca. 1.8 × 1 km 2D resistivity model displays a laterally constrained highly conductive anomaly (ca. 10 Ω m) at about 400-500 m depth, where reflectors of a parallel seismic section are concealed and core samples indicate a highly fractured décollement zone formed during Paleogene compression. The base of the permafrost is imaged at ca. 200 m depth. Synthetic inversion tests, however, suggest that this may be exaggerated by tens of meters, due to a thin conductive layer present approximately between 10 and 25 m depth. The resistivity model does not give indication for a fluid pathway we can connect to leakage, in line with water injection and leak-off tests in the reservoir and cap-rock, both of which indicate a sealing shale-dominated cap-rock separating an over-pressured compartment above the sealing shale from a severely under-pressured reservoir interval. The results we present indicate the advantage of integrating EM exploration techniques in a CO2 reservoir-cap-rock study to obtain a more complete picture.

  3. A Cultural Resources Site Inventory at Painted Rock Reservoir, Maricopa County, Arizona.

    DTIC Science & Technology

    1988-02-01

    basalt . The toolstone is actually a metamorphosed form of basalt more aptly termed metabasalt or greenstone. Greenstone is a generic term used . for...altered basic (as opposed to acid rocks such as granite or rhyolite) "’ igneous rocks, and includes felsites, basalts , and other rock types. To provide...continuity with the earlier work we have listed the black raw .. , materials as basalt and then qualified them to greenstone parenthetically. The

  4. Evaluation of Management of Water Releases for Painted Rocks Reservoir, Bitterroot River, Montana, 1983-1986, Final Report.

    SciTech Connect

    Spoon, Ronald L.

    1987-06-01

    This study was initiated in July, 1983 to develop a water management plan for the release of water purchased from Painted Rocks Reservoir. Releases were designed to provide optimum benefits to the Bitterroot River fishery. Fisheries, habitat, and stream flow information was gathered to evaluate the effectiveness of these supplemental releases in improving trout populations in the Bitterroot River. The study was part of the Northwest Power Planning Council's Fish and Wildlife Program and was funded by the Bonneville Power Administration. This report presents data collected from 1983 through 1986.

  5. A chemical and thermodynamic model of oil generation in hydrocarbon source rocks

    NASA Astrophysics Data System (ADS)

    Helgeson, Harold C.; Richard, Laurent; McKenzie, William F.; Norton, Denis L.; Schmitt, Alexandra

    2009-02-01

    Thermodynamic calculations and Gibbs free energy minimization computer experiments strongly support the hypothesis that kerogen maturation and oil generation are inevitable consequences of oxidation/reduction disproportionation reactions caused by prograde metamorphism of hydrocarbon source rocks with increasing depth of burial.These experiments indicate that oxygen and hydrogen are conserved in the process.Accordingly, if water is stable and present in the source rock at temperatures ≳25 but ≲100 °C along a typical US Gulf Coast geotherm, immature (reduced) kerogen with a given atomic hydrogen to carbon ratio (H/C) melts incongruently with increasing temperature and depth of burial to produce a metastable equilibrium phase assemblage consisting of naphthenic/biomarker-rich crude oil, a type-II/III kerogen with an atomic hydrogen/carbon ratio (H/C) of ˜1, and water. Hence, this incongruent melting process promotes diagenetic reaction of detritus in the source rock to form authigenic mineral assemblages.However, in the water-absent region of the system CHO (which is extensive), any water initially present or subsequently entering the source rock is consumed by reaction with the most mature kerogen with the lowest H/C it encounters to form CO 2 gas and a new kerogen with higher H/C and O/C, both of which are in metastable equilibrium with one another.This hydrolytic disproportionation process progressively increases both the concentration of the solute in the aqueous phase, and the oil generation potential of the source rock; i.e., the new kerogen can then produce more crude oil.Petroleum is generated with increasing temperature and depth of burial of hydrocarbon source rocks in which water is not stable in the system CHO by a series of irreversible disproportionation reactions in which kerogens with higher (H/C)s melt incongruently to produce metastable equilibrium assemblages consisting of crude oil, CO 2 gas, and a more mature (oxidized) kerogen with a lower

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

    SciTech Connect

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

    1996-09-01

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

  7. Coupling geostatistics to detailed reservoir description allows better visualization and more accurate characterization/simulation of turbidite reservoirs: Elk Hills oil field, California

    SciTech Connect

    Allan, M.E.; Wilson, M.L.; Wightman, J. )

    1996-01-01

    The Elk Hills giant oilfield, located in the southern San Joaquin Valley of California, has produced 1.1 billion barrels of oil from Miocene and shallow Pliocene reservoirs. 65% of the current 64,000 BOPD production is from the pressure-supported, deeper Miocene turbidite sands. In the turbidite sands of the 31 S structure, large porosity permeability variations in the Main Body B and Western 31 S sands cause problems with the efficiency of the waterflooding. These variations have now been quantified and visualized using geostatistics. The end result is a more detailed reservoir characterization for simulation. Traditional reservoir descriptions based on marker correlations, cross-sections and mapping do not provide enough detail to capture the short-scale stratigraphic heterogeneity needed for adequate reservoir simulation. These deterministic descriptions are inadequate to tie with production data as the thinly bedded sand/shale sequences blur into a falsely homogenous picture. By studying the variability of the geologic petrophysical data vertically within each wellbore and spatially from well to well, a geostatistical reservoir description has been developed. It captures the natural variability of the sands and shales that was lacking from earlier work. These geostatistical studies allow the geologic and petrophysical characteristics to be considered in a probabilistic model. The end-product is a reservoir description that captures the variability of the reservoir sequences and can be used as a more realistic starting point for history matching and reservoir simulation.

  8. Coupling geostatistics to detailed reservoir description allows better visualization and more accurate characterization/simulation of turbidite reservoirs: Elk Hills oil field, California

    SciTech Connect

    Allan, M.E.; Wilson, M.L.; Wightman, J.

    1996-12-31

    The Elk Hills giant oilfield, located in the southern San Joaquin Valley of California, has produced 1.1 billion barrels of oil from Miocene and shallow Pliocene reservoirs. 65% of the current 64,000 BOPD production is from the pressure-supported, deeper Miocene turbidite sands. In the turbidite sands of the 31 S structure, large porosity & permeability variations in the Main Body B and Western 31 S sands cause problems with the efficiency of the waterflooding. These variations have now been quantified and visualized using geostatistics. The end result is a more detailed reservoir characterization for simulation. Traditional reservoir descriptions based on marker correlations, cross-sections and mapping do not provide enough detail to capture the short-scale stratigraphic heterogeneity needed for adequate reservoir simulation. These deterministic descriptions are inadequate to tie with production data as the thinly bedded sand/shale sequences blur into a falsely homogenous picture. By studying the variability of the geologic & petrophysical data vertically within each wellbore and spatially from well to well, a geostatistical reservoir description has been developed. It captures the natural variability of the sands and shales that was lacking from earlier work. These geostatistical studies allow the geologic and petrophysical characteristics to be considered in a probabilistic model. The end-product is a reservoir description that captures the variability of the reservoir sequences and can be used as a more realistic starting point for history matching and reservoir simulation.

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

    SciTech Connect

    James R. Wood; William B. Harrison

    2001-04-01

    Among the accomplishments of this past reporting period are obtaining a complete landgrid for the State of Michigan and the digital processing of the high and medium resolution DEM files. We can now extract lineations from the DEMs automatically using machine algorithms. One tentative result that may be very significant is that we may be seeing manifestations of buried structures in the DEM data. We are looking at a set of extracted lineations in the northern lower peninsula that appear to follow the trend of the pinnacle reefs (Silurian) which had relief approaching 300 feet but are now buried to greater than 3000 feet. We have also extracted the dolomite alteration data from all fields and can show that this is mainly confined to the basin center. It may be related to the paleo-rift suggested by the paleomagnetic and gravity data. As reported last time, the acquisition of a 3D seismic dataset over Stoney Point Field from Marathon Oil Company, is complete and attention is being devoted to incorporating the data into the project database and utilizing it. The surface lineation study is focusing on Stoney Point Field using the high-resolution DEM data and plotting of subsurface formation top data for the main reservoir, the Trenton (Ordovician) Formation. The fault pattern at Stoney Point is well documented by Marathon and we are looking for any manifestations on the surface. The main project database is now about as complete as it will be for this project. The main goals have been met, although the scanning of the paper records will have to continue beyond the scheduled end of the project due to the sheer number of records and the increased donations of data from companies as word spread of the project. One of the unanticipated benefits of the project has been the cooperation of gas and oil companies that are or were active in the Michigan Basin in donating material to the project. Both Michigan Tech and Western Michigan continue to receive donations at an

  10. Miscibility study of carbon dioxide injection to enhance oil recovery from Abu-Dhabi oil field Thani reservoire

    NASA Astrophysics Data System (ADS)

    Aljarwan, Abdulla Humaid Saif Saeed

    The subject field in this study has been recognized among the largest offshore oil fields in the world, located in the Arabian Gulf 63 kilometers to the Northwest of Abu Dhabi, producing large quantities of crude oil and associated gas from three different carbonate reservoirs, Thani-I, II and IIII since 1963. In the early 1970's peripheral water injection scheme was adopted to maintain the reservoir pressure and sustain production. Simultaneously, partial waterflooding was applied to one sector of the field, but stopped soon after implementation shadowed by poor sweep efficiency and dramatic escalation of water-cut. Furthermore, hydrocarbon miscible gas injection was implemented in the year 2000 but stopped seven years later, due to high gas oil ratio and aspheltene deposition. In light of such recovery complications, management is considering serious recovery measures to extend plateau production and meet long-term production from this field. Post initial screening phase, it became evident that CO 2 miscible injection is the most suitable way forward. Characteristics of the Thani-III reservoir are within the favorable range for both immiscible and miscible CO2 injection criteria set by Taber, Martine and Serigh. Thani-III reservoir is considered more homogenous, less fractured and with higher production potential than Thani-I and II, hence promoted to be the target of CO2 miscible gas injection. This thesis aims to study the miscibility features of CO2 miscible injecton to enhanced oil recovery from Thani-III reservoir. Comprehensive simulation model is used to determine multi contact miscibility and suitable equation of state with CO2 as a separate pseudo component using one of the industry standard simulation software. Experimental PVT data for bottom hole and separator samples including compositional analysis, differential liberation test, separator tests, constant composition expansion, viscosity measurements and swelling tests for pure CO2 were used to

  11. Detection of brine plumes in an oil reservoir using the geoelectric method

    NASA Astrophysics Data System (ADS)

    Bongiovanni, María Victoria; Osella, Ana; de la Vega, Matías; Tichno, Adrián

    2013-08-01

    During water injection in a reservoir at the secondary recovery phase, oil is replaced by salt water, producing different saturation zones in the formation containing this reservoir. This process could be optimized if the direction of the fluids is monitored. Since there are large contrasts in the electric conductivity between salt water and oil, geoelectrical methods could provide a water saturation map at any given moment of the production. The case we study here corresponds to a rather shallow reservoir (between 500 and 600 m in depth). As the wells are in production, electrodes for borehole measurements cannot be introduced. Hence, our objectives are to determine the possibilities of detecting the channelling direction of saline water between injection and producing wells, and applying the method of placing electrodes on the surface or even burying them, but at depths corresponding to shallow layers. We design an electrical model of the reservoir and then numerically simulate the geoelectrical response in order to determine the conditions under which the anomaly, i.e. the accumulation of brine in a reduced area, can be detected. We find that the channelling of the brine can be detected for the reservoir studied here if the electrodes are placed at 180 m depth. The Wenner configuration using 16 electrodes provides the best resolution. Therefore, monitoring the voltage at a number of electrodes embedded at rather shallow depths (from a technical-logistic point of view) could give information about the direction of the saline channelling even if a quantitative image of the subsoil cannot be obtained due to the reduced number of electrodes used in the study.

  12. Advanced reservoir characterization and evaluation of CO{sub 2} gravity drainage in the naturally fractured Spraberry reservoir. Quarterly technical report, April 1, 1996--June 30, 1996

    SciTech Connect

    Schechter, D.

    1996-11-01

    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.

  13. Stress, seismicity and structure of shallow oil reservoirs of Clinton County, Kentucky. Final report

    SciTech Connect

    Hamilton-Smith, T.

    1995-12-12

    Between 1993 and 1995 geophysicists of the Los Alamos National Laboratory, in a project funded by the US Department of Energy, conducted extensive microseismic monitoring of oil production in the recently discovered High Bridge pools of Clinton County and were able to acquire abundant, high-quality data in the northern of the two pools. This investigation provided both three-dimensional spatial and kinetic data relating to the High Bridge fracture system that previously had not been available. Funded in part by the Los Alamos National Laboratory, the Kentucky Geological Survey committed to develop a geological interpretation of these geophysical results, that would be of practical benefit to future oils exploration. This publication is a summary of the results of that project. Contents include the following: introduction; discovery and development; regional geology; fractured reservoir geology; oil migration and entrapment; subsurface stress; induced seismicity; structural geology; references; and appendices.

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

    SciTech Connect

    Mehadi, Z. )

    1990-05-01

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

  15. Laboratory evaluation of the CO2 huff-n-puff process for heavy oil reservoirs

    SciTech Connect

    Sayegh, S.G.; Maini, B.B.

    1983-01-01

    Laboratory tests were conducted to evaluate a CO2 huff-n-puff well stimulation process in a Lloydminster heavy oil reservoir. Two series of phase behavior measurements were done on the reconstituted oil, each in a pressurization-then-liberation cycle. The first series was performed using CO2 as the carbonating gas. Some oil swelling occurred, and a large viscosity reduction was observed. CO2 was retained preferentially to CH4 during liberation and, consequently reduced viscosities were maintained down to low pressures. The second series was performed using a 1:3 mole ratio CH4:CO2, simulating the use of recycled gas in the huff-n-puff process. The results revealed that CH4 reduces the efficiency of CO2. 12 references.

  16. Characterization of phosphorus leaching from phosphate waste rock in the Xiangxi River watershed, Three Gorges Reservoir, China.

    PubMed

    Jiang, Li-guo; Liang, Bing; Xue, Qiang; Yin, Cheng-wei

    2016-05-01

    Phosphate mining waste rocks dumped in the Xiangxi River (XXR) bay, which is the largest backwater zone of the Three Gorges Reservoir (TGR), are treated as Type I industry solid wastes by the Chinese government. To evaluate the potential pollution risk of phosphorus leaching from phosphate waste rocks, the phosphorus leaching behaviors of six phosphate waste rock samples with different weathering degrees under both neutral and acidic conditions were investigated using a series of column leaching experiments, following the Method 1314 standard of the US EPA. The results indicate that the phosphorus release mechanism is solubility-controlled. Phosphorus release from waste rocks increases as pH decreases. The phosphorus leaching concentration and cumulative phosphorus released in acidic leaching conditions were found to be one order of magnitude greater than that in neutral leaching conditions. In addition, the phosphorus was released faster during the period when environmental pH turned from weak alkalinity to slight acidity, with this accelerated release period appearing when L/S was in the range of 0.5-2.0 mL/g. In both neutral and acidic conditions, the average values of Total Phosphorus (TP), including orthophosphates, polyphosphates and organic phosphate, leaching concentration exceed the availability by regulatory (0.5 mg/L) in the whole L/S range, suggesting that the phosphate waste rocks stacked within the XXR watershed should be considered as Type II industry solid wastes. Therefore, the phosphate waste rocks deposited within the study area should be considered as phosphorus point pollution sources, which could threaten the adjacent surface-water environment.

  17. 3-D Reservoir and Stochastic Fracture Network Modeling for Enhanced Oil Recovery, Circle Ridge Phosphoria/Tensleep Reservoir, and River Reservation, Arapaho and Shoshone Tribes, Wyoming

    SciTech Connect

    La Pointe, Paul R.; Hermanson, Jan

    2002-09-09

    The goal of this project is to improve the recovery of oil from the Circle Ridge Oilfield, located on the Wind River Reservation in Wyoming, through an innovative integration of matrix characterization, structural reconstruction, and the characterization of the fracturing in the reservoir through the use of discrete fracture network models.

  18. Increasing waterflood reserves in the Wilmington Oil Field through improved reservoir characterization and reservoir management. Annual report, March 21, 1995--March 20, 1996

    SciTech Connect

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

    1997-08-01

    This project uses 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 saturation sands will be stimulated by recompleting existing production and injection wells in these sands using conventional means as well as short radius and ultra-short radius laterals. 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.

  19. Computer simulation of reservoir depletion and oil flow from the Macondo well following the Deepwater Horizon blowout

    USGS Publications Warehouse

    Hsieh, Paul

    2010-01-01

    This report describes the application of a computer model to simulate reservoir depletion and oil flow from the Macondo well following the Deepwater Horizon blowout. Reservoir and fluid data used for model development are based on (1) information released in BP's investigation report of the incident, (2) information provided by BP personnel during meetings in Houston, Texas, and (3) calibration by history matching to shut-in pressures measured in the capping stack during the Well Integrity Test. The model is able to closely match the measured shut-in pressures. In the simulation of the 86-day period from the blowout to shut in, the simulated reservoir pressure at the well face declines from the initial reservoir pressure of 11,850 pounds per square inch (psi) to 9,400 psi. After shut in, the simulated reservoir pressure recovers to a final value of 10,300 psi. The pressure does not recover back to the initial pressure owing to reservoir depletion caused by 86 days of oil discharge. The simulated oil flow rate declines from 63,600 stock tank barrels per day just after the Deepwater Horizon blowout to 52,600 stock tank barrels per day just prior to shut in. The simulated total volume of oil discharged is 4.92 million stock tank barrels. The overall uncertainty in the simulated flow rates and total volume of oil discharged is estimated to be + or - 10 percent.

  20. Effects of mineral composition and pore structure in HC potential of reservoir rocks in the Western Foothill Belt, Taiwan

    NASA Astrophysics Data System (ADS)

    Lin, J. M.; Tsai, L. Y.

    2014-12-01

    The exploration of unconventional gas resource achieved a successful breakthrough in USA due to the innovation of hydraulic fracturing and horizontal drilling since 1995. The production of shale gas dramatically changed the energy structure and released the demand of fossil fuel in USA. Many studies about the unconventional oil-gas resource were performed worldwide especially in China, which provide very useful characterization for unconventional gas reservoirs. Since Taiwan has a strong energy demand and still highly relied on imported fossil fuel, the development of unconventional gas resource needs to be concerned. Therefore, the objective of this study is to evaluate the potential of unconventional oil-gas in Taiwan. In this study, we examine mineral composition and pore structure of Miocene oil-gas bearing strata from the Western Foothill Belt in Taiwan. Sandstone samples were collected from Cholan Fm, Yutengpin ss, Kuantaoshan ss, Shangfuchi ss, Tungkeng Fm, Guanyinshang ss and Peiliao Fm; whereas shale samples were collected from Chinshui sh and Talu sh, as well as outcropped coal sample from Nanchung Fm. The porosity, permeability, TOC, thermal maturity, and mineral composition of samples are examined after a series of geochemical experiments. Finally, after comparing the data with their gas sorption capacity, the reservoir with the strongest potential in unconventional gas resource can be identified.