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Sample records for hydrocarbon sandstone reservoirs

  1. Aux Vases Sandstone diagenesis: Implications for hydrocarbon recovery from southern Illinois reservoirs

    SciTech Connect

    Seyler, B.D.; Beaty, D.S.; Huff, B.G. )

    1991-03-01

    The Aux Vases Sandstone (Mississippian) is a problematic yet productive reservoir in the Illinois basin. The Aux Vases Formation was deposited in a mixed siliciclastic-carbonate offshore environment. Hydrocarbon reservoirs are dominantly elongate sandstone bodies interpreted as subtidal facies within a prograding tidally influenced deposystem. Oil saturated zones, in most cases, are composed of fine-grained, cross-bedded, friable, feldspathic quartz sandstone. Resistivity logs, even from productive wells, are typically characterized by unusually low resistivities (2-4 ohms) that lead to high calculated water saturations. X-ray diffraction, SEM/EDS, and thin section studies were used to analyze diagenetic processes that may affect hydrocarbon production in several Aux Vases reservoirs. Diagenetic processes common to the field studied include: (1) early calcite cementation occluding primary porosity and inhibiting compaction, (2) dissolution of feldspar grains to form authigenic clay, (3) dissolution of early calcite cement, (4) diagenesis of detrital clay minerals into new authigenic clay minerals, and (5) multiple stages of quartz overgrowths that reduce porosity. Commonly used drilling and completion practices may adversely affect reservoir quality by reacting with diagenetic products. Loosening of the fine mineral fraction that causes migration of fines and swelling of expandable clay minerals are examples of this type of damage. Knowledge of reservoir mineralogy and diagenesis may influence drilling and completion practices and affect selection of secondary and tertiary recovery methods.

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

    NASA Astrophysics Data System (ADS)

    Fang, Zhi; Khaksar, Abbas

    2013-05-01

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

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

    SciTech Connect

    Jennie Ridgley

    2000-05-21

    A goal of the Mesaverde project was to better define the depositional system of the Mesaverde in hopes that it would provide insight to new or by-passed targets for oil exploration. The new, detailed studies of the Mesaverde give us a better understanding of the lateral variability in depositional environments and facies. Recognition of this lateral variability and establishment of the criteria for separating deltaic, strandplain-barrier, and estuarine deposits from each other permit development of better hydrocarbon exploration models, because the sandstone geometry differs in each depositional system. Although these insights will provide better exploration models for gas exploration, it does not appear that they will be instrumental in finding more oil. Oil in the Mesaverde Group is produced from isolated fields on the Chaco slope; only a few wells define each field. Production is from sandstone beds in the upper part of the Point Lookout Sandstone or from individual fluvial channel sandstones in the Menefee. Stratigraphic traps rather than structural traps are more important. Source of the oil in the Menefee and Point Lookout may be from interbedded organic-rich mudstones or coals rather than from the Lewis Shale. The Lewis Shale appears to contain more type III organic matter and, hence, should produce mainly gas. Outcrop studies have not documented oil staining that might point to past oil migration through the sandstones of the Mesaverde. The lack of oil production may be related to the following: (1) lack of abundant organic matter of the type I or II variety in the Lewis Shale needed to produce oil, (2) ineffective migration pathways due to discontinuities in sandstone reservoir geometries, (3) cementation or early formation of gas prior to oil generation that reduced effective permeabilities and served as barriers to updip migration of oil, or (4) erosion of oilbearing reservoirs from the southern part of the basin. Any new production should mimic that of

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

    SciTech Connect

    Jennie Ridgley

    2000-01-21

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

  5. Timing of Hydrocarbon Fluid Emplacement in Sandstone Reservoirs in Neogene in Huizhou Sag, Southern China Sea, by Authigenic Illite 40Ar- 39Ar Laser Stepwise Heating

    NASA Astrophysics Data System (ADS)

    Hesheng, Shi; Junzhang, Zhu; Huaning, Qiu; yu, Shu; Jianyao, Wu; Zulie, Long

    Timing of oil or gas emplacements is a new subject in isotopic geochronology and petroleum geology. Hamilton et al. expounded the principle of the illite K-Ar age: Illite is often the last or one of the latest mineral cements to form prior to hydrocarbon accumulation. Since the displacement of formation water by hydrocarbons will cause silicate diagenesis to cease, K-Ar ages for illite will constrain the timing of this event, and also constrain the maximum age of formation of the trap structure. In this study, the possibility of authigenic illites 40Ar- 39Ar dating has been investigated. The illite samples were separated from the Tertiary sandstones in three rich oil reservoir belts within the Huizhou sag by cleaning, fracturing by cycled cooling-heating, soxhlet-extraction with solvents of benzene and methanol and separating with centrifugal machine. If oil is present in the separated samples, ionized organic fragments with m/e ratios of 36 to 40 covering the argon isotopes will be yielded by the ion source of a mass spectrometer, resulting in wrong argon isotopic analyses and wrong 40Ar- 39Ar ages. The preliminary experiments of illite by heating did show the presence of ionized organic fragments with m/e ratios of 36 to 44. In order to clean up the organic gases completely and obtain reliable analysis results, a special purification apparatus has been established by Qiu et al. and proved valid by the sequent illite analyses. All the illite samples by 40Ar- 39Ar IR-laser stepwise heating yield stair-up age spectra in lower laser steps and plateaux in higher laser steps. The youngest apparent ages corresponding to the beginning steps are reasonable to be interpreted for the hydrocarbon accumulation ages. The weighted mean ages of the illites from the Zhuhai and Zhujiang Formations are (12.1 ± 1.1) Ma and (9.9 ± 1.2) Ma, respectively. Therefore, the critical emplacement of petroleum accumulation in Zhujiang Formation in Huizhou sag took place in ca 10 Ma. Late

  6. Imaging fluid/solid interactions in hydrocarbon reservoir rocks

    SciTech Connect

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

    1993-08-01

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

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

    PubMed

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

    1993-08-01

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

  8. Reservoir characterization of Pennsylvanian sandstone reservoirs. Final report

    SciTech Connect

    Kelkar, M.

    1995-02-01

    This final report summarizes the progress during the three years of a project on Reservoir Characterization of Pennsylvanian Sandstone Reservoirs. The report is divided into three sections: (i) reservoir description; (ii) scale-up procedures; (iii) outcrop investigation. The first section describes the methods by which a reservoir can be described in three dimensions. The next step in reservoir description is to scale up reservoir properties for flow simulation. The second section addresses the issue of scale-up of reservoir properties once the spatial descriptions of properties are created. The last section describes the investigation of an outcrop.

  9. Ourcrop characterization of sandstone heterogeneity in Carboniferous reservoirs, Black Warrior basin, Alabama

    SciTech Connect

    Pashin, J.C.; Osborne, E.W.; Rindsberg, A.K.

    1991-08-01

    Where production is currently declining, improved recovery strategies, such as waterflooding, injection, strategic well placement, and infill drilling may be used to increase production of liquid hydrocarbons from reservoir sandstone in the Black Warrior basin. Characterizing reservoir heterogeneity provides information regarding how those strategies can best be applied, and exceptional exposures of asphaltic sandstone in north Alabama enable first-hand observation of such heterogeneity. This report identifies heterogeneity in Carboniferous strata of the Black Warrior basin on the basis of vertical variations, lithofacies analysis. Results of lithofacies analysis and depositional modeling were synthesized with existing models of sandstone heterogeneity to propose methods which may improve hydrocarbon recovery in Carboniferous sandstone reservoirs of the Black Warrior basin. 238 refs., 89 figs. 2 tabs.

  10. Basin-wide architecture of sandstone reservoirs in the Fort Union Formation, Wind River basin, Wyoming

    SciTech Connect

    Flores, R.M.; Keighin, C.W.; Keefer, W.R. )

    1991-06-01

    Architecture of hydrocarbon-bearing sandstone reservoirs of the Paleocene Fort Union Formation in the Wind River basin, Wyoming, was studied using lithofacies, grain size, bounding surfaces, sedimentary structures, internal organization, and geometry. Two principal groups of reservoirs, both erosionally based and fining upward, consist of either conglomeratic sandstone or sandstone lithofacies. Two types of architecture were recognized in conglomeratic sandstone reservoirs: (1) heterogeneous, multistacked, lenticular and (2) homogeneous, multiscoured, wedge-sheet bodies. Three types of architecture were recognized in sandstone reservoirs: (3) heterogeneous, multistacked, elongate; (4) homogeneous, multilateral, lenticular; and (5) homogeneous, ribbon-lensoid bodies. Conglomeratic sandstone reservoirs in the southern and southwestern parts of the basin suggest deposition in gravel-bedload fluvial systems influenced by provenance uplift of the Granite and southern Wind River mountains. Type 2 reservoirs represent deposits of eastward-flowing braided streams aggrading an alluvial valley in response to base level rise. Thus, to determine basin-wide architecture of reservoirs requires understanding the interplay between base level conditions, basin subsidence, and provenance uplift. These interrelated factors, in turn, control differences in hierarchies of fluvial systems throughout the basin.

  11. Reservoir characterization of Pennsylvanian Sandstone Reservoirs. Annual report

    SciTech Connect

    Kelkar, M.

    1992-09-01

    This annual report describes the progress during the second year of a project on Reservoir Characterization of Pennsylvanian Sandstone Reservoirs. The report is divided into three sections: (i) reservoir description and scale-up procedures; (ii) outcrop investigation; (iii) in-fill drilling potential. The first section describes the methods by which a reservoir can be characterized, can be described in three dimensions, and can be scaled up with respect to its properties, appropriate for simulation purposes. The second section describes the progress on investigation of an outcrop. The outcrop is an analog of Bartlesville Sandstone. We have drilled ten wells behind the outcrop and collected extensive log and core data. The cores have been slabbed, photographed and the several plugs have been taken. In addition, minipermeameter is used to measure permeabilities on the core surface at six inch intervals. The plugs have been analyzed for the permeability and porosity values. The variations in property values will be tied to the geological descriptions as well as the subsurface data collected from the Glen Pool field. The third section discusses the application of geostatistical techniques to infer in-fill well locations. The geostatistical technique used is the simulated annealing technique because of its flexibility. One of the important reservoir data is the production data. Use of production data will allow us to define the reservoir continuities, which may in turn, determine the in-fill well locations. The proposed technique allows us to incorporate some of the production data as constraints in the reservoir descriptions. The technique has been validated by comparing the results with numerical simulations.

  12. Haynesville sandstone reservoirs in the Updip Jurassic trend of Alabama

    SciTech Connect

    Kugler, R.L.; Mink, R.M.

    1994-09-01

    Subsequent to the 1986 drilling of the 1 Carolyn McCollough Unit 1-13 well, which initiated production from the Frisco City sand of the Haynesville Formation in Monroe County, Alabama, seven Haynesville fields have been established in Covington, Escambia, and Monroe counties. Initial flow rates of several hundred BOPD are typical for wells in these fields, and maximum rates exceed 2000 BOPD in North Frisco City field. As of August 1993, these fields produced more than 3,400,000 bbl of oil and 4,000,000 mcf of gas from depths of 12,000 to 13,000 ft. Haynesville sandstone reservoirs are concentrated in two distinct areas: (1) an eastern area (Hickory Branch, North Rome, and West Falco fields; API oil gravity = 40{degrees}) in the Conecuh embayment and (2) a western area (Frisco City, North Frisco City, southeast Frisco City, and Megargel fields; API oil gravity = 58-59{degrees}) on the Conecuh ridge complex. Eastern fields are productive from Haynesville sandstone, which is not continuous with the two distinct, productive sandstone bodies in western fields, the Frisco City sand and the Megargel sand. Hydrocarbon traps are structural or combination traps associated with basement paleohighs. Reservoir bodies generally consist of conglomerate (igneous clasts in western fields; limestone clasts in eastern fields), sandstone (subarkose-arkose), and shale (some of which is red) in stacked fining-upward sequences. Shale at the tops of these sequences is bioturbated. These marine strata were deposited in shoal-water braid-delta fronts. Petrophysical properties differ between the two areas. Maximum and average permeability in western fields (k{sub max} = 2000 md; k{sub ave} = 850-1800 md) is an order of magnitude higher than in eastern fields. The distribution of diagenetic components, including a variety of carbonate minerals, evaporate minerals (anhydrite and halite in western fields), and carbonate-replaced pseudomatrix, commonly is related to depositional architecture.

  13. Digital characterization and preliminary computer modeling of hydrocarbon bearing sandstone

    NASA Astrophysics Data System (ADS)

    Latief, Fourier Dzar Eljabbar; Haq, Tedy Muslim

    2014-03-01

    With the advancement of three dimensional imaging technologies, especially the μCT scanning systems, we have been able to obtain three-dimensional digital representation of porous rocks in the scale of micrometers. Characterization was then also possible to conduct using computational approach. Hydrocarbon bearing sandstone has become one of interesting objects to analyze in the last decade. In this research, we performed digital characterization of hydrocarbon bearing sandstone reservoir from Sumatra. The sample was digitized using a μCT scanner (Skyscan 1173) which produced series of reconstructed images with the spatial resolution of 15 μm. Using computational approaches, i.e., image processing, image analysis, and simulation of fluid flow inside the rock using Lattice Boltzmann Method, we have been able to obtain the porosity of the sandstone, which is 23.89%, and the permeability, which is 9382 mD. Based on visual inspection, the porosity value, along with the calculated specific surface area, we produce a preliminary computer model of the rock using grain based method. This method employs a reconstruction of grains using the non-spherical model, and a purely random deposition of the grains in a virtual three dimensional cube with the size of 300 × 300 × 300. The model has porosity of 23.96%, and the permeability is 7215 mD. While the error of the porosity is very small (which is only 0.3%), the permeability has error of around 23% from the real sample which is considered very significant. This suggests that the modeling based on porosity and specific surface area is not satisfactory to produce a representative model. However, this work has been a good example of how characterization and modeling of porous rock can be conducted using a non-destructive computational approach.

  14. Sulfidization and magnetization above hydrocarbon reservoirs

    SciTech Connect

    Reynolds, R.L.; Goldhaber, M.B.; Tuttle, M.L. )

    1991-03-01

    Geochemical and rock magnetic studies of strata over Cement oil field (Anadarko basin, Oklahoma), Simpson oil field (North Slope basin, Alaska), and the Edwards deep gas trend, south Texas coastal plain, document changes in original magnetizations caused by postdepositional iron sulfide minerals that are, or may be, related to hydrocarbon seepage. At Cement, ferrimagnetic pyrrhotite (Fe{sub 7}S{sub 8}) formed with pyrite and marcasite in Permian red beds. The Fe-S minerals contain isotopically heavy, abiogenic sulfur derived from thermal degradation of petroleum and (or) isotopically light sulfur derived from sulfate-reducing bacteria fed by leaking hydrocarbons. At Simpson, ferrimagnetic greigite (Fe{sub 3}S{sub 4}) dominates magnetizations in Upper Cretaceous nonmarine beds that contain biodegraded oil. Sulfur isotopic data are consistent with, but do not prove, a genetic link between the greigite ({delta}{sup 34}S {gt} +20 per mil) and seepage. In middle Tertiary sandstones of southeast Texas, pyrite and marcasite formed when abiogenic H{sub 2}S migrated upward from deep reservoirs, or when H{sub 2}S was produced at shallow depths by bacteria that utilized organic material dissolved in migrating water from depth. The sulfide minerals replaced detrital magnetite to result in a systematic decrease in magnetic susceptibility toward faults that connect deep petroleum reservoirs to shallow sandstone. The authors results show that abiologic and biologic mechanisms can generate magnetic sulfide minerals in some sulfidic zones of hydrocarbon seepage. The magnetizations in such zones are diminished most commonly by replacement of detrital magnetic minerals with nonmagnetic sulfide minerals or are unchanged if such detrital minerals were originally absent.

  15. Middle Micoene sandstone reservoirs of the Penal/Barrackpore field

    SciTech Connect

    Dyer, B.L. )

    1991-03-01

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

  16. Diagenesis and reservoir quality of Paleocoene sandstones in the Kupe South field, Taranaki Basin, New Zealand

    SciTech Connect

    Martin, K.R. ); Baker, J.C. ); Hamilton, P.J. ); Thrasher, G.P. )

    1994-04-01

    The Kupe South field, Taranaki basin, New Zealand is a gas condensate and oil field offshore in the southern Taranaki basin. Its Paleocene reservoir sandstones contain a diagenetic mineral assemblage that records major shifts in pore-water composition during the burial history of the basin. Early calcite formed a shallow burial largely from meteoric depositional pore waters, whereas later chlorite/smectic records the downward passage of marine pore waters into the sandstones from overlying, marine mudrocks prior to significant sandstone compaction during the late Miocene. Late calcite and ferroan carbonates may record the presence of connate meteoric water expelled upward from nonmarine sedimentary rocks of the underyling Cretaceous sequence, whereas later kaolinite and secondary porosity formation are related to localized meteoric influx resulting from late Miocene to early Pliocene uplift and erosion of the reservoir section. Hydrocarbon entrapment occurred during further Pliocene to Holocene sediment accumulation. Labile-grain alteration has been less severe in the lower part of the hydrocarbon-bearing section than in the upper sands with the result that the lower sands contain mainly chlorite/smectite and the upper sands contain mainly ferroan carbonates and kaolinite formed by extensive alteration of labile grains and earlier formed chlorite/smectite. Reservoir quality in the lower sands is controlled mostly by grain size and the presence of chlorite/smectite, but in the upper sands, the presence of kaolinite is the single most important cause of poor reservoir quality. 36 refs., 13 figs., 3 tabs.

  17. Ferron sandstone - stratigraphy and reservoir analogs, East-Central Utah

    SciTech Connect

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

    1996-06-01

    The Ferron Sandstone (Upper Cretaceous) crops out along the west flank of the San Rafael Swell of east-central Utah. Exposures were described on photomosaics to better define the stratigraphy, to enhance facies prediction, and establish rules for reservoir modeling within fluvial-deltaic rocks. Major regressive cycles are recognized as parasequence sets composed of several to many parasequences. Each of the seaward-stepping parasequence sets recognized in the Ferron begins with a rapidly thickening and stratigraphically climbing, wave-modified shoreface. In later stages of progradation, deposition is dominated by river influences. Continued regression of the seaway is recorded in outcrop and shows a complex history of delta lobe progradation, switching, and abandonment. Onlapping and stacking of parasequences creates a collage of potential reservoir sweet spots, baffles, and barriers within a parasequence set. Shoreface and delta-front deposits of the older parasequences are commonly eroded by younger distributary and meanderbelt systems that fed younger parasequences of the parasequence sets. The result is numerous and locally thick channel sandstone bodies incised into shoreface and delta-front deposits. Published studies and recently completed work show that upper shoreface, stream mouth-bar, and channel sandstones constitute the best potential reservoir rocks within the Ferron Sandstone.

  18. Diagenesis and reservoir quality of the Lower Cretaceous Quantou Formation tight sandstones in the southern Songliao Basin, China

    NASA Astrophysics Data System (ADS)

    Xi, Kelai; Cao, Yingchang; Jahren, Jens; Zhu, Rukai; Bjørlykke, Knut; Haile, Beyene Girma; Zheng, Lijing; Hellevang, Helge

    2015-12-01

    later than the tight rock formation (with the porosity close to 10%). However, thicker sandstone bodies (more than 2 m) constitute potential hydrocarbon reservoirs.

  19. Diagenetic influences on reservoir characteristics of Terry sandstone, Spindle field, Colorado

    SciTech Connect

    Hays, P.D.; Tieh, T.T.

    1989-03-01

    The Upper Cretaceous Terry sandstones of Spindle field, Weld County, Colorado, were deposited as offshore bars in a shallow-marine environment. The Terry Sandstone Member of the Pierre Shale is presently buried at depths of 4500-5000 ft (1375-1525 m). The Terry sandstone reservoir was diagenetically created by selective dissolution of calcite cement and detrital material in downdip sands. Hydrocarbon entrapment occurred as a diagenetic/stratigraphic trap through preservation of cement updip and by shale boundaries laterally and vertically. The arkosic litharenites of the Terry sandstone have experienced four major stages of diagenesis: (1) early compaction and calcite cementation, (2) cement and grain dissolution and renewed compaction, (3) chlorite authigenesis, and (4) late illite and smectite authigenesis. In the study area, samples which have experienced dissolution of calcite exhibit porosities of up to 20%. However, permeabilities are low (0.1-11.0 md) due to the presence of pore-lining chlorite and the development of a pseudomatrix related to postdissolution compaction of glauconite pellets. The authigenic chlorite and glauconite pseudomatrix reduced porosity and blocked pore throats. Semilogarithmic plots indicate a logarithmic decrease in permeability with increased chlorite and glauconite content. Terry sandstone reservoir quality has been strongly modified by the diagenetic processes of cementation and compaction. These diagenetic processes resulted in the destruction of primary porosity, the formation of secondary porosity, and the subsequent partial occlusion of secondary porosity. Variations in reservoir properties and production potential within the sandstones can be ascribed to both primary lithologic contrasts and subsequent diagenetic modifications.

  20. Haynesville sandstone reservoirs in the updip-Jurassic trend of Alabama

    SciTech Connect

    Kugler, R.L.; Mink, R.M.

    1994-12-31

    Since the 1986 drilling of the 1 Carolyn McCollough Unit 1-13 well, which initiated production from the Frisco City sandstone of the Haynesville Formation in Monroe County, Alabama, seven Haynesville fields have been established in Covington, Escambia, and Monroe Counties. Initial flow rates of several hundred BOPD are typical in wells in these fields, and maximum rates exceed 2,000 BOPD in North Frisco City field. As of August 1993, these fields had produced more than 3,400,000 bbl of oil and 4,000,000 Mcf of gas from depths of 12,000 to 13,000 ft. Haynesville sandstone reservoirs are concentrated in two distinct areas: (1) an eastern area (Hickory Branch, North Rome, and West Falco fields; API oil gravity = 40{degrees}) in the Conecuh embayment and (2) a western area (Frisco City, North Frisco City, southeast Frisco City, and Megargel fields, API oil gravity = 58-59{degrees}) on the Conecuh ridge complex. Eastern fields are productive from Haynesville sandstone, which is not continuous with the two distinct, productive sandstone bodies in western fields, the Frisco City sandstone and the Megargel sandstone. Hydrocarbon traps are structural or combination traps associated with basement paleohighs. Reservoir bodies generally consist of conglomerate (igneous clasts in western fields; limestone clasts in eastern fields), sandstone (subarkose-arkose), and shale (some of which is red) in stacked upward-fining sequences. Shale at the tops of these sequences is bioturbated. These marine strata were deposited in shoal-water braid-delta fronts. Maximum and average permeability in western fields (k{sub max} = 2,000 md; k{sub ave} = 850-1,800 md) is an order of magnitude higher than that in eastern fields. The distribution of diagenetic components, including a variety of carbonate minerals, evaporite minerals (anhydrite and halite in western fields), and carbonate-replaced pseudomatrix, commonly is related to depositional architecture.

  1. Appalachian Basin Low-Permeability Sandstone Reservoir Characterizations

    SciTech Connect

    Ray Boswell; Susan Pool; Skip Pratt; David Matchen

    1993-04-30

    A preliminary assessment of Appalachian basin natural gas reservoirs designated as 'tight sands' by the Federal Energy Regulatory Commission (FERC) suggests that greater than 90% of the 'tight sand' resource occurs within two groups of genetically-related units; (1) the Lower Silurian Medina interval, and (2) the Upper Devonian-Lower Mississippian Acadian clastic wedge. These intervals were targeted for detailed study with the goal of producing geologic reservoir characterization data sets compatible with the Tight Gas Analysis System (TGAS: ICF Resources, Inc.) reservoir simulator. The first phase of the study, completed in September, 1991, addressed the Medina reservoirs. The second phase, concerned with the Acadian clastic wedge, was completed in October, 1992. This report is a combined and updated version of the reports submitted in association with those efforts. The Medina interval consists of numerous interfingering fluvial/deltaic sandstones that produce oil and natural gas along an arcuate belt that stretches from eastern Kentucky to western New York. Geophysical well logs from 433 wells were examined in order to determine the geologic characteristics of six separate reservoir-bearing intervals. The Acadian clastic wedge is a thick, highly-lenticular package of interfingering fluvial-deltaic sandstones, siltstones, and shales. Geologic analyses of more than 800 wells resulted in a geologic/engineering characterization of seven separate stratigraphic intervals. For both study areas, well log and other data were analyzed to determine regional reservoir distribution, reservoir thickness, lithology, porosity, water saturation, pressure and temperature. These data were mapped, evaluated, and compiled into various TGAS data sets that reflect estimates of original gas-in-place, remaining reserves, and 'tight' reserves. The maps and data produced represent the first basin-wide geologic characterization for either interval. This report outlines the methods and

  2. Consistent small-scale porosity contrasts in reservoir sandstones and their relevance to reservoir characterization

    SciTech Connect

    Etris, E.L.; Ehrlich, R.

    1988-01-01

    Although grain size may gradually increase or decrease vertically through a sandstone reservoir, porosity need not change appreciably. Yet porosity does vary greatly at all scales. Large-scale changes, commonly measured by wireline logs, are used in assessing not only reservoir capacity, but also (not always correctly) reservoir efficiency. Systematic porosity variation at smaller scales, however, is usually not considered in reservoir modeling or assessment because it is thought to be difficult to measure, insignificant compared to variation at larger scales, and difficult to simulate in numerical models. The authors' data indicate there there is a common mode of small-scale porosity contrast in reservoir sandstones and that this contrast is important in understanding the behavior of multiphase flow in such rocks. Using image analysis procedures, they measured porosity between adjacent laminate in 50 thin sections taken from four contrasting reservoir sandstones (Kekiktuk, Rotliegendes, Wilcox, and Satun), and have found consistent small-scale contrasts in porosity between laminae. In all but a few samples, porosity alternates, with contrasts of a factor of three or more. The bimodal distribution of porosity in laminated sandstones means theat few if any laminate contain the porosity measured form wireline logs. The authors' data indicate that permeability, pore sizes, and throat sizes also alternate - a fact that can affect the localization of residual oil. Although this phenomenon increases the complexity of the sandstone system, the simple alternation of porosity allows ease in modeling.

  3. Micromechanics of compaction in an analogue reservoir sandstone

    SciTech Connect

    DIGIOVANNI,ANTHONY A.; FREDRICH,JOANNE T.; HOLCOMB,DAVID J.; OLSSON,WILLIAM A.

    2000-02-28

    Energy production, deformation, and fluid transport in reservoirs are linked closely. Recent field, laboratory, and theoretical studies suggest that, under certain stress conditions, compaction of porous rocks may be accommodated by narrow zones of localized compressive deformation oriented perpendicular to the maximum compressive stress. Triaxial compression experiments were performed on Castlegate, an analogue reservoir sandstone, that included acoustic emission detection and location. Initially, acoustic emissions were focused in horizontal bands that initiated at the sample ends (perpendicular to the maximum compressive stress), but with continued loading progressed axially towards the center. This paper describes microscopy studies that were performed to elucidate the micromechanics of compaction during the experiments. The microscopy revealed that compaction of this weakly-cemented sandstone proceeded in two phases: an initial stage of porosity decrease accomplished by breakage of grain contacts and grain rotation, and a second stage of further reduction accommodated by intense grain breakage and rotation.

  4. Application of the BISQ model to clay squirt flow in reservoir sandstones

    NASA Astrophysics Data System (ADS)

    Marketos, G.; Best, A. I.

    2010-06-01

    An understanding of the variations of compressional wave velocity and attenuation in sandstones as a function of pore-fluid properties is important for the identification and monitoring of hydrocarbon reservoirs. In order for seismic inversion to be well constrained a rock physics model that describes accurately the observed behavior is required; a number of such models have been proposed but have not been extensively tested against laboratory data. The unified Biot and squirt flow model was applied to data obtained from ultrasonic experiments conducted on a wide range of sandstone types when saturated with different pore fluids with viscosities ranging from 0.3 to 1000 cP. This model was seen to match well all the observed velocity and attenuation values as opposed to the Biot model, which was only successful for clean sandstones saturated with low viscosity fluids. This has led to the conclusion that a squirt flow mechanism is important at the grain scale. In addition, an increase in the dynamic uniaxial strain modulus of the dry frame with increasing pore-fluid viscosity was observed. In the absence of free gas or grain contact microcracks (the laboratory data were collected at 60 MPa effective pressure), this can be linked to decreasing local flow and decreasing relaxation in the soft pore space of the sandstone, the extent of which is in turn connected to the clay content and pore structure of the sandstone. These results imply that at ultrasonic frequencies the squirt-flow is due to the presence of clay.

  5. Basin Dynamics and Sedimentary Infilling of Miocene Sandstone Reservoir Systems In Eastern Tunisian African Margin

    NASA Astrophysics Data System (ADS)

    Bédir, Mourad; Khomsi, Sami

    2015-04-01

    Most of hydrocarbon accumulations and aquifers within the Cap Bon, Gulf of Hammamet and Sahel basins in eastern tunisian foreland are reservoired within the Upper Miocene Birsa and Saouaf sandstones and shales Formations. In the gulf of Hammamet, these sandstones constitutes oil and gas fields and are exploited on anticline highs and described as varying from shoreface to shallow marine and typically exhibit excellent reservoir quality of 30% to 35% porosity and good permeability from 500 to 1100 md. In addition, the fracturing of faults enhanced the reservoir quality potential. In contrary, the same hydrocarbon reservoirs are important hydrogeologic ones in the Cap Bon and Sahel basins with huge amount of hundred millions of cubic meters of water only partially exploited. Integrated wire line logging correlations, seismic sequence stratigraphic, tectonics and outcrop geologic analogue studies had permitted to highlight the basin structuring and sedimentary environments of sequence deposits infilling of the reservoir distribution between high platforms to subsiding graben and syncline basins bounded by deep-seated transtensive and transpressive flower faults. Seven third order sequence deposits limited by downlap prograding and onlap/toplap aggrading/retrograding system tracts extend along the eastern margin around the three basins by facies and thickness variances. System tracts exhibit around high horst and graben a channelized and levee infillings extending from 100 meters to more than a kilometer of width. They present a stacked single story and multistory channels types showing space lateral and vertical migrations along NE-SW, E-W and N-S directions. Paleogeographic depositional reservoir fair maps distribution highlight deltaic horst domain with floodplain and incised valley of fluvial amalgamed and braided sandstones distributary channels that occupy the high folded horsts. Whereas folded horst-graben and syncline borders domain of Shelf prodelta are

  6. Effects of primary sedimentary processes on reservoir quality of Deep Wilcox (Eocene) sandstones in Fordoche field, Louisiana

    SciTech Connect

    Lemoine, R.C.; Moslow, T.F.; Lowry, P.

    1987-05-01

    The initial discovery and subsequent development of Fordoche field established a Deep Wilcox production trend in south-central Louisiana. Production in the field occurs within five intervals: the W4, W5, W8, W12, and W15 sandstones. The W8 and W12 sandstones are the most prolific. They represent shoreface sequences which formed at or near the shelf margin. Cumulative hydrocarbon production from these sandstones is in excess of 22 million bbl of oil and 151 bcf of gas. Over 1100 ft (335 m) of conventional core from the W8 and W12 sandstones in six wells were analyzed and compared to petrophysical data to effectively characterize reservoir quality. Primary sedimentation patterns (i.e., physical and biogenic sedimentary structures and sequences) are the dominant control on reservoir quality throughout the field. Burrowed to bioturbated (> 75% burrowed) lower shoreface sandstones possess relatively high average porosity values (16.7%); however, permeability values are extremely low (< 0.2 md). Clay-lined burrow walls create numerous permeability barriers which significantly alter fluid flow patterns within this facies. In contrast, massive to burrowed middle shoreface sandstones, although possessing similar average porosity values (19.8%), have substantially higher average permeability values (8.6 md). Within the middle shoreface facies, higher wave energies winnow the fine-grained silts and clays, resulting in the deposition of a clean, well-sorted sandstone. The entire sequence coarsens upward in both grain size and percent sand and is overlain by a thin (3.5 ft; 1.0 m), tightly cemented calcareous sandstone. Average thickness of the middle shoreface facies in Fordoche field is 23 ft (7.0 m) with stacked sequences within the W12 sandstone as thick as 57 ft (17.4 m) of high reservoir quality sandstones.

  7. Low permeability Neogene lithofacies in Northern Croatia as potential unconventional hydrocarbon reservoirs

    NASA Astrophysics Data System (ADS)

    Malvić, Tomislav; Sučić, Antonija; Cvetković, Marko; Resanović, Filip; Velić, Josipa

    2014-06-01

    We present two examples of describing low permeability Neogene clastic lithofacies to outline unconventional hydrocarbon lithofacies. Both examples were selected from the Drava Depression, the largest macrostructure of the Pannonian Basin System located in Croatia. The first example is the Beničanci Field, the largest Croatian hydrocarbon reservoir discovered in Badenian coarse-grained clastics that consists mostly of breccia. The definition of low permeability lithofacies is related to the margins of the existing reservoir, where the reservoir lithology changed into a transitional one, which is mainly depicted by the marlitic sandstones. However, calculation of the POS (probability of success of new hydrocarbons) shows critical geological categories where probabilities are lower than those in the viable reservoir with proven reserves. Potential new hydrocarbon volumes are located in the structural margins, along the oil-water contact, with a POS of 9.375%. These potential reserves in those areas can be classified as probable. A second example was the Cremušina Structure, where a hydrocarbon reservoir was not proven, but where the entire structure has been transferred onto regional migration pathways. The Lower Pontian lithology is described from well logs as fine-grained sandstones with large sections of silty or marly clastics. As a result, the average porosity is low for conventional reservoir classification (10.57%). However, it is still an interesting case for consideration as a potentially unconventional reservoir, such as the "tight" sandstones.

  8. Geometry and reservoir heterogeneity of tertiary sandstones: a guide to reservoir continuity and geothermal resource development

    SciTech Connect

    Morton, R.A.; Ewing, T.E.

    1981-01-01

    External and internal continuity of Tertiary sandstones are controlled by various factors including structural trends, sand body geometry, and the distribution of mineral framework, matrix, and intersticies within the sand body. Except for the limits imposed by faults, these factors are largely inherited from the depositional environment and modified during sandstone compaction and cementation. Sandstone continuity affects energy exploration and production strategies. The strategies range in scope from regional to site-specific and closely parallel a sandstone hierarchy. The hierarchy includes subdivisions ranking from genetically related aquifer systems down to individual reservoirs within a fault-bounded sandstone. Volumes of individual reservoirs are 50% less to 200% more than estimated from conventional geologic mapping. In general, mapped volumes under-estimate actual volumes where faults are nonsealing and overestimate actual volumes where laterally continuous shale breaks cause reductions in porosity and permeability. Gross variations in these pore properties can be predicted on the basis of internal stratification and sandstone facies. Preliminary analyses indicate that large aquifers are found where barrier and strandplain sandstones parallel regional faults or where fluvial (meandering) channels trend normal to regional faults. Within these sand bodies, porosity and permeability are highest in large-scale crossbedded intervals and lowest in contorted, bioturbated, and small-scale ripple cross-laminated intervals.

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

    SciTech Connect

    Kugler, R.L.; Pashin, J.C.; Carroll, R.E.; Irvin, G.D.; Moore, H.E.

    1994-04-01

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

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

    SciTech Connect

    Kugler, R.L.; Pashin, J.C.; Carroll, R.E.; Irvin, G.D.; Moore, H.E.

    1994-06-01

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

  11. Petroacoustic Modelling of Heterolithic Sandstone Reservoirs: A Novel Approach to Gassmann Modelling Incorporating Sedimentological Constraints and NMR Porosity data

    NASA Astrophysics Data System (ADS)

    Matthews, S.; Lovell, M.; Davies, S. J.; Pritchard, T.; Sirju, C.; Abdelkarim, A.

    2012-12-01

    Heterolithic or 'shaly' sandstone reservoirs constitute a significant proportion of hydrocarbon resources. Petroacoustic models (a combination of petrophysics and rock physics) enhance the ability to extract reservoir properties from seismic data, providing a connection between seismic and fine-scale rock properties. By incorporating sedimentological observations these models can be better constrained and improved. Petroacoustic modelling is complicated by the unpredictable effects of clay minerals and clay-sized particles on geophysical properties. Such effects are responsible for erroneous results when models developed for "clean" reservoirs - such as Gassmann's equation (Gassmann, 1951) - are applied to heterolithic sandstone reservoirs. Gassmann's equation is arguably the most popular petroacoustic modelling technique in the hydrocarbon industry and is used to model elastic effects of changing reservoir fluid saturations. Successful implementation of Gassmann's equation requires well-constrained drained rock frame properties, which in heterolithic sandstones are heavily influenced by reservoir sedimentology, particularly clay distribution. The prevalent approach to categorising clay distribution is based on the Thomas - Stieber model (Thomas & Stieber, 1975), this approach is inconsistent with current understanding of 'shaly sand' sedimentology and omits properties such as sorting and grain size. The novel approach presented here demonstrates that characterising reservoir sedimentology constitutes an important modelling phase. As well as incorporating sedimentological constraints, this novel approach also aims to improve drained frame moduli estimates through more careful consideration of Gassmann's model assumptions and limitations. A key assumption of Gassmann's equation is a pore space in total communication with movable fluids. This assumption is often violated by conventional applications in heterolithic sandstone reservoirs where effective porosity, which

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

    NASA Astrophysics Data System (ADS)

    Hangx, Suzanne; Spiers, Christopher

    2014-05-01

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

  13. Sandstone geometry, porosity and permeability distribution, and fluid migration in eolian system reservoirs

    USGS Publications Warehouse

    Lupe, Robert; Ahlbrandt, Thomas S.

    1975-01-01

    Upper Paleozoic to Mesozoic eolian blanket sandstones of the Colorado Plateau and the Rocky Mountains of Colorado and southern Wyoming are texturally complex. As petroleum reservoirs they commonly have poor performance histories. They contain the sediments of a depositional system comprised of three closely associated depositional subenvironments: dune, interdune, and extradune. Sediments of each subenvironment have different textural properties which resulted from different depositional processes. Dune sediments are usually more porous and permeable than interdune or extradune sediments and may be better quality reservoirs than interdune or extradune sediments. Interdune sediments are here restricted to those nondune sediments deposited in the relatively flat areas between dunes. Extradune sediments (a new term) include all deposits adjacent to a dune field and are mainly subaqueous deposits. Dune sediments may be enveloped by extradune sediments as the depositional system evolves resulting in a texturally inhomogeneous reservoir having poor fluid migration properties. This model of textural inhomogeneity in eolian blanket sandstones. was applied to the Weber (Tensleep) Sandstone in Brady, Wertz, and Lost Soldier fields, Sweetwater County, Wyoming. Data were obtained from both outcrop and subsurface and included environmental interpretation, textural analysis, and plotting of the distribution of depositional subenvironments. As predicted from the model, the texture of dune sediments in Brady field differed markedly from interdune and extradune sediments. The predicted geometric distribution of subenvironments was confirmed in Lost Soldier and Wertz fields. However, secondary cementation and fracturing there has obscured the original porosity and permeability contrasts. The porosity and permeability distribution, a characteristic depending partly on depositional processes, could impede fluid migration in the reservoir and significantly reduce recovery of

  14. Geology and diagenetic history of overpressured sandstone reservoirs, Venture Gas field, offshore Nova Scotia, Canada

    SciTech Connect

    Jansa, L.F. Dalhousie Univ., Halifax, Nova Scotia ); Urrea V.H.N. )

    1990-10-01

    Deep exploratory wells in the Scotian Basin, offshore Nova Scotia, Canada, have encountered overpressured formations with pressures 1.9 {times} the normal hydrostatic gradient. The overpressures occur over an area of approximately 10,000 km{sup 2}. In the Venture field, the abnormal pressures are confined below a depth of 4,500 m and are associated with Upper Jurassic-Lower Cretaceous gas- and condensate-bearing sandstone reservoirs. The overpressures occur within normally compacted shales containing numerous overpressured sandstone reservoir beds. The development of overpressures, seals, and secondary reservoirs are all diagenetically driven. Three secondary porosity depth levels, which top at 2,500 m (65C), 3,700 m (95C), and 4,600 m (130C), correlate with major steps in the organic matter maturation in the basin. Secondary porosity is initially achieved by aluminosilicate dissolution, with ferroan sparry calcite cement dissolution dominating below 4,000 m. Porosity enhancement and preservation is not the result of a single diagenetic event but instead the result of a series of diagenetic events that overlapped in time. Formation of dynamic diagenetic barriers within the zone of peak gas generation helps retard the diffusive migration of hydrocarbons and other fluids expelled during shale diagenesis resulting in pressure build up. The preservation of up to 32% porosity under 500-1,000 atm of pressure could not be achieved without simultaneous pressuring of developing voids. Significant for hydrocarbon exploration is that Venture-type diagenetic overpressures are not associated with undercompacted sediments and, hence, they cannot be predicted from compaction trends during drilling. Petrographic diagenetic, and lithofacies studies can be instrumental in predicting potential areas of deep subsurface secondary reservoirs dependent.

  15. Characterization of the Qishn sandstone reservoir, Masila Basin-Yemen, using an integrated petrophysical and seismic structural approach

    NASA Astrophysics Data System (ADS)

    Lashin, Aref; Marta, Ebrahim Bin; Khamis, Mohamed

    2016-03-01

    This study presents an integrated petrophysical and seismic structural analysis that is carried out to evaluate the reservoir properties of Qishn sandstone as well as the entrapment style of the hydrocarbons at Sharyoof field, Sayun-Masila Basin that is located at the east central of Yemen. The reservoir rocks are dominated by clean porous and permeable sandstones zones usually intercalated with some clay stone interbeds. As identified from well logs, Qishn sandstone is classified into subunits (S1A, S1B, S1C and S2) with different reservoir characteristics and hydrocarbon potentiality. A number of qualitative and quantitative well logging analyses are used to characterize the different subunits of the Qishn reservoir and identify its hydrocarbon potentiality. Dia-porosity, M-N, Pickett, Buckles plots, petrophysical analogs and lateral distribution maps are used in the analysis. Shale volume, lithology, porosity, and fluid saturation are among the most important deduced parameters. The analysis revealed that S1A and S1C are the main hydrocarbon-bearing units. More specifically, S1A unit is the best, as it attains the most prolific hydrocarbon saturations (oil saturation "SH″ up to 65) and reservoir characteristics. An average petrophysical ranges of 4-21%, 16-23%, 11-19%, 0-65%, are detected for S1A unit, regarding shale volume, total and effective porosity, and hydrocarbon saturation, respectively. Meanwhile, S1B unit exhibits less reservoir characteristics (Vsh>30%, ϕEff<15% and SH< 15%). The lateral distribution maps revealed that most of the hydrocarbons (for S1A and S1C units) are indicated at the middle of the study area as NE-SW oriented closures. The analysis and interpretation of seismic data had clarified that the structure of study area is represented by a big middle horst bounded by a group of step-like normal faults at the extreme boundaries (faulted anticlinal-structure). In conclusion, the entrapment of the encountered hydrocarbon at Sharyoof oil

  16. The Stimulation of Hydrocarbon Reservoirs with Subsurface Nuclear Explosions

    SciTech Connect

    LORENZ,JOHN C.

    2000-12-08

    Between 1965 and 1979 there were five documented and one or more inferred attempts to stimulate the production from hydrocarbon reservoirs by detonating nuclear devices in reservoir strata. Of the five documented tests, three were carried out by the US in low-permeability, natural-gas bearing, sandstone-shale formations, and two were done in the USSR within oil-bearing carbonates. The objectives of the US stimulation efforts were to increase porosity and permeability in a reservoir around a specific well by creating a chimney of rock rubble with fractures extending beyond it, and to connect superimposed reservoir layers. In the USSR, the intent was to extensively fracture an existing reservoir in the more general vicinity of producing wells, again increasing overall permeability and porosity. In both countries, the ultimate goals were to increase production rates and ultimate recovery from the reservoirs. Subsurface explosive devices ranging from 2.3 to about 100 kilotons were used at depths ranging from 1208 m (3963 ft) to 2568 m (8427 ft). Post-shot problems were encountered, including smaller-than-calculated fracture zones, formation damage, radioactivity of the product, and dilution of the BTU value of tie natural gas with inflammable gases created by the explosion. Reports also suggest that production-enhancement factors from these tests fell short of expectations. Ultimately, the enhanced-production benefits of the tests were insufficient to support continuation of the pro-grams within increasingly adversarial political, economic, and social climates, and attempts to stimulate hydrocarbon reservoirs with nuclear devices have been terminated in both countries.

  17. Chlorites in reservoir sandstones of the Guadalupian Delaware Mountain Group

    SciTech Connect

    Walling, S.D. )

    1992-04-01

    Late-stage authigenic clay minerals are pervasive in the very fine-grained, subarkosic sandstones of the Guadalupian Delaware Mountain Group, comprising up to 10% of the bulk rock. Thus, reservoir rock properties are influenced by these minerals. Samples selected from cored intervals, ranging from 600 to 2500 m, were studied using optical and electron microscopy and x-ray diffraction methods to determine the distribution and nature of occurrence of the authigenic clay minerals. In thin sections, the clay minerals are recognizable as grain coatings, with thickness varying from a few micrometers to tens of micrometers. A correlation between the morphology and the amount of interstratification has been observed, with more interstratification corresponding to the formless chlorite variety. The structural and morphological evidence suggests that the chlorites represent different stages of development, possibly evolving from a smectite component through an interstratified intermediate, to a more well-ordered form. There appears to be no systematic trends vertically or laterally in clay mineralogy. The importance of understanding the clay mineralogy and chemistry in these sandstones is evident when considering enhanced recovery procedures. Different clay structures and chemistries may respond differently to production and stimulation techniques. The proposed chlorite diagenetic sequence suggests that drastic changes in borehole fluid chemistry may cause retrogression of chlorite to some expansive forms, which may be water sensitive or inclined to migration.

  18. Geophysical monitoring in a hydrocarbon reservoir

    NASA Astrophysics Data System (ADS)

    Caffagni, Enrico; Bokelmann, Goetz

    2016-04-01

    Extraction of hydrocarbons from reservoirs demands ever-increasing technological effort, and there is need for geophysical monitoring to better understand phenomena occurring within the reservoir. Significant deformation processes happen when man-made stimulation is performed, in combination with effects deriving from the existing natural conditions such as stress regime in situ or pre-existing fracturing. Keeping track of such changes in the reservoir is important, on one hand for improving recovery of hydrocarbons, and on the other hand to assure a safe and proper mode of operation. Monitoring becomes particularly important when hydraulic-fracturing (HF) is used, especially in the form of the much-discussed "fracking". HF is a sophisticated technique that is widely applied in low-porosity geological formations to enhance the production of natural hydrocarbons. In principle, similar HF techniques have been applied in Europe for a long time in conventional reservoirs, and they will probably be intensified in the near future; this suggests an increasing demand in technological development, also for updating and adapting the existing monitoring techniques in applied geophysics. We review currently available geophysical techniques for reservoir monitoring, which appear in the different fields of analysis in reservoirs. First, the properties of the hydrocarbon reservoir are identified; here we consider geophysical monitoring exclusively. The second step is to define the quantities that can be monitored, associated to the properties. We then describe the geophysical monitoring techniques including the oldest ones, namely those in practical usage from 40-50 years ago, and the most recent developments in technology, within distinct groups, according to the application field of analysis in reservoir. This work is performed as part of the FracRisk consortium (www.fracrisk.eu); this project, funded by the Horizon2020 research programme, aims at helping minimize the

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

    NASA Astrophysics Data System (ADS)

    Lindquist, Sandra J.

    1988-04-01

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

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

    SciTech Connect

    Pollard, David; Aydin, Atilla

    2005-02-22

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

  1. Diagenetic Evolution and Reservoir Quality of Sandstones in the North Alpine Foreland Basin: A Microscale Approach.

    PubMed

    Gross, Doris; Grundtner, Marie-Louise; Misch, David; Riedl, Martin; Sachsenhofer, Reinhard F; Scheucher, Lorenz

    2015-10-01

    Siliciclastic reservoir rocks of the North Alpine Foreland Basin were studied focusing on investigations of pore fillings. Conventional oil and gas production requires certain thresholds of porosity and permeability. These parameters are controlled by the size and shape of grains and diagenetic processes like compaction, dissolution, and precipitation of mineral phases. In an attempt to estimate the impact of these factors, conventional microscopy, high resolution scanning electron microscopy, and wavelength dispersive element mapping were applied. Rock types were established accordingly, considering Poro/Perm data. Reservoir properties in shallow marine Cenomanian sandstones are mainly controlled by the degree of diagenetic calcite precipitation, Turonian rocks are characterized by reduced permeability, even for weakly cemented layers, due to higher matrix content as a result of lower depositional energy. Eocene subarkoses tend to be coarse-grained with minor matrix content as a result of their fluvio-deltaic and coastal deposition. Reservoir quality is therefore controlled by diagenetic clay and minor calcite cementation.Although Eocene rocks are often matrix free, occasionally a clay mineral matrix may be present and influence cementation of pores during early diagenesis. Oligo-/Miocene deep marine rocks exhibit excellent quality in cases when early cement is dissolved and not replaced by secondary calcite, mainly bound to the gas-water contact within hydrocarbon reservoirs. PMID:26365327

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

    NASA Astrophysics Data System (ADS)

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

    2013-04-01

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

  3. Solid hydrocarbon: a migration-of-fines problem in carbonate reservoirs

    SciTech Connect

    Lomando, A.J.

    1986-05-01

    The most familiar example of a migration-of-fines problem is authigenic kaolinite, which can detach, migrate through a pore system, and bridge pore throats, thus reducing permeability. under certain conditions, a similar problem is caused by solid hydrocarbon, independent of a mode of origin, which has precipitated in carbonate pore systems. Cores from several reservoirs in the Lower Cretaceous of east Texas were used as the data base in this study. Three morphotypes of solid hydrocarbon have been identified from thin-section and scanning electron microscope observations: droplets, peanut brittle, and carpets. Droplets are small, individual, rounded particles scattered on pore walls. Peanut brittle ranges from a continuous to discontinuous thin coating with random rounded lumps that probably have droplet precursors. Carpets are thick, continuous coatings and, at the extreme, can effectively occlude whole pores. Initially, solid hydrocarbon reduces permeability without necessarily decreasing porosity significantly. Likewise, solid hydrocarbon cannot be detected directly from wireline logs. Acidizing to enhance communication to the well bore is a common completion procedure in limestone and calcareous sandstone reservoirs. In reservoirs containing solid hydrocarbon, acid etches the substrate and releases solid hydrocarbon, which migrates in the pore system and bridges pore throats. Differential well-bore pressure also may cause solid hydrocarbon to migrate. Therefore, wettability, which controls hydrocarbon adhesion to the pore walls, and the dominant morphotype are important factors in the extent of reservoir damage.

  4. Sedimentary facies and reservoir characteristics of Cretaceous J Sandstone at Torrington field (North), Goshen County, Wyoming, exploration and development implications

    SciTech Connect

    Mikesh, D.L.; Lafollette, R.F.

    1983-08-01

    Torrington field (North) is productive from the Lower Cretaceous J sandstone in the Wyoming portion of the Denver basin. The trapping mechanism is stratigraphic, with reservoir sandstones enveloped laterally and updip by shale-dominated lithofacies. The field has produced 13,000 bbl of oil from two wells since its discovery in late 1981. Three major sedimentary environments and their associated facies, characteristic of a meandered fluvial system, occur within the J interval in the area: abandoned channel, point bar(s), and interfluvial plain. Production at both Torrington (North) and Torrington is from reservoir development within point bar deposits. Cores of the J point bar at Torrington (North) show that it is comprised primarily of very fine to fine-grained quartzarenites and sublitharenites. Sedimentary structures observed in the cores include burrowing and bioturbation, high-angle plane-parallel cross-bedding, discontinuous wavy shale laminae, climbing ripples, and truncated laminae. Although excellent hydrocarbon shows occur from the base to the top of the point bar, production appears to be confined to thin intervals of medium-grained quartzarenite found near the middle of the vertical sequence. Petrophysical reservoir characteristics of the J sandstone were established through examination of X-ray diffraction, scanning electron microscopy, thin-section petrography, and conventional core analysis data. Microporosity development and geometry also affect production. Field extension locations and an exploratory drill site have been established as a result of this study.

  5. Water saturations in a Wilcox shaly reservoir sandstone, Fordoche field, Point Coupee Parish, Louisiana

    SciTech Connect

    Berg, C.R.; Berg, R.R.

    1996-09-01

    A new equation has been derived for calculation of water saturations in shaly reservoir sandstones. The equation is based on effective medium theory (EMT) and has been used successfully on a wide range of clayey, low-resistivity reservoirs. A further, independent test of saturations calculated by the equation was made for a deep Wilcox shaly reservoir at a depth of 13,176 ft (4016 m) in Fordoche field. The reservoir (W8) has a low, average resistivity of about 2.5 ohm-m and an estimated 18% clay as compared to an average resistivity of 1.5 ohm-m in an underlying water-saturated sandstone (W-10) of similar clay content. For the reservoir, calculated water saturations are in the range of 35 to 50%, increasing downward, and suggest that the shaly sandstone should produce water-free oil. For the underlying wet sandstone, the calculated water saturations range from 55 to 75% and confirm that only water should be produced. Other shaly sand equations generally give water saturations in excess of 50% for the reservoir. Water saturations calculated by the EMT equation agree well with other parameters for sandstones: reported production, core, analysis, and synthetic capillary pressures. The reservoir (W8) had an initial potential of 213 bbl of oil per day, confirming water-free oil production which could have been predicted by the EMT equation.

  6. Factors controlling reservoir quality in tertiary sandstones and their significance to geopressured geothermal production

    SciTech Connect

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

    1981-01-01

    Variable intensity of diagenesis is the factor primarily responsible for contrasting regional reservoir quality of Tertiary sandstones from the upper and lower Texas coast. Detailed comparison of Frio sandstone from the Chocolate Bayou/Danbury Dome area, Brazoria County, and Vicksburg sandstones from the McAllen Ranch Field area, Hidalgo County, reveals that extent of diagenetic modification is most strongly influenced by (1) detrital mineralogy and (2) regional geothermal gradients. The regional reservoir quality of Frio sandstones from Brazoria County is far better than that characterizing Vicksburg sandstones from Hidalgo County, especially at depths suitable for geopressured geothermal energy production. However, in predicting reservoir quality on a site-specific basis, locally variable factors such as relative proportions for porosity types, pore geometry as related to permeability, and local depositional environment must also be considered. Even in an area of regionally favorable reservoir quality, such local factors can significantly affect reservoir quality and, hence, the geothermal production potential of a specific sandstone unit.

  7. Regional diagenetic variation in Norphlet sandstone: Implications for reservoir quality and the origin of porosity

    SciTech Connect

    Kugler, R.L.; McHugh, A. )

    1990-09-01

    Although deeply buried (18,000->20,000 ft) eolian and reworked marine Norphlet arkose and subarkose in Mississippi, Alabama, and Florida have been intensely studied by several workers, fundamental questions remain regarding diagenetic controls on reservoir quality and the origin of porosity. In spite of a regionally uniform framework composition of quartz, albite, and potassium feldspar, the diagenetic character of the unit is variable on a scale ranging from individual laminations to single hydrocarbon-producing fields to areas encompassing several fields or offshore blocks. The presence or absence of clay minerals in various forms clearly is a dominant control on porosity-permeability trends. In deep reservoirs in Mobile Bay and offshore Alabama and Florida, petrographic evidence for dissolution of pervasive authigenic carbonate and/or evaporite minerals to produce high secondary porosity values is equivocal or absent. Although evidence exists for some secondary porosity, much porosity appears to be relict primary porosity. On a regional scale, including both onshore and offshore areas, sandstones with radial, authigenic chlorite coats consistently have high porosity and permeability. In Mobile Bay and offshore Alabama, the distribution of this form of chlorite may be controlled by the presence of precursor clay/iron-oxide grain coats. The occurrence of these coats likely is related to environment of deposition.

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

    SciTech Connect

    Patchen, D.G.; Hohn, M.E.; Aminian, K.; Donaldson, A.; Shumaker, R.; Wilson, T.

    1993-04-01

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

  9. Halomonas sulfidaeris-dominated microbial community inhabits a 1.8 km-deep subsurface Cambrian Sandstone reservoir.

    PubMed

    Dong, Yiran; Kumar, Charu Gupta; Chia, Nicholas; Kim, Pan-Jun; Miller, Philip A; Price, Nathan D; Cann, Isaac K O; Flynn, Theodore M; Sanford, Robert A; Krapac, Ivan G; Locke, Randall A; Hong, Pei-Ying; Tamaki, Hideyuki; Liu, Wen-Tso; Mackie, Roderick I; Hernandez, Alvaro G; Wright, Chris L; Mikel, Mark A; Walker, Jared L; Sivaguru, Mayandi; Fried, Glenn; Yannarell, Anthony C; Fouke, Bruce W

    2014-06-01

    A low-diversity microbial community, dominated by the γ-proteobacterium Halomonas sulfidaeris, was detected in samples of warm saline formation porewater collected from the Cambrian Mt. Simon Sandstone in the Illinois Basin of the North American Midcontinent (1.8 km/5872 ft burial depth, 50°C, pH 8, 181 bars pressure). These highly porous and permeable quartz arenite sandstones are directly analogous to reservoirs around the world targeted for large-scale hydrocarbon extraction, as well as subsurface gas and carbon storage. A new downhole low-contamination subsurface sampling probe was used to collect in situ formation water samples for microbial environmental metagenomic analyses. Multiple lines of evidence suggest that this H. sulfidaeris-dominated subsurface microbial community is indigenous and not derived from drilling mud microbial contamination. Data to support this includes V1-V3 pyrosequencing of formation water and drilling mud, as well as comparison with previously published microbial analyses of drilling muds in other sites. Metabolic pathway reconstruction, constrained by the geology, geochemistry and present-day environmental conditions of the Mt. Simon Sandstone, implies that H. sulfidaeris-dominated subsurface microbial community may utilize iron and nitrogen metabolisms and extensively recycle indigenous nutrients and substrates. The presence of aromatic compound metabolic pathways suggests this microbial community can readily adapt to and survive subsurface hydrocarbon migration. PMID:24238218

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

    PubMed

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

    2013-03-01

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

  11. Reservoir heterogeneity in middle Frio fluvial sandstones: Case studies in Seeligson field, Jim Wells County, Texas

    SciTech Connect

    Jirik, L.A. )

    1990-09-01

    Detailed evaluation of middle Frio (Oligocene) fluvial sandstones reveals a complex architectural style potentially suited to the addition of gas reserves through recognition of poorly drained reservoir compartments and bypassed gas zones. Seeligson field is being studied as part of a Gas Research Institute/US Department of Energy/State of Texas-sponsored program, with the cooperation of Oryx Energy Company and Mobil Exploration and Producing US, Inc. Four reservoirs, Zones 15, 16D, 16E, and 19C, were studied in a 20 mi{sup 2} area within Seeligson field. Collectively, these reservoirs have produced more than 240 bcf of gas from wells within the study area. Detailed electric log correlation of individual reservoirs enabled subdivision of aggregate producing zones into component genetic units. Cross sections, net-sandstone maps, and log-facies maps were prepared to illustrate depositional style, sand-body geometry, and reservoir heterogeneity. Zones 15 and 19C are examples of laterally stacked fluvial architecture. Individual channel-fill sandstones range from 10 to 50 ft thick, and channel widths are approximately 2,500 ft. Crevasse-splay sandstones may extend a few thousand feet from the main channel system. Multiple, overlapping channel and splay deposits commonly form sand-rich belts that result in leaky reservoir compartments that may be incompletely drained. Zones 16D and 16E are examples of vertically stacked fluvial architecture, with discrete, relatively thin and narrow channel and splay sandstones generally encased within floodplain muds. This architectural style is likely to form more isolated reservoir compartments. Although all of these reservoirs are currently considered nearly depleted, low-pressure producers, recent well completions and bottomhole pressure data indicate that untapped or poorly drained compartments are being encountered.

  12. 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).

  13. Variations of chlorites and illites and porosity in Mississippian sandstone reservoirs in the Illinois basin

    SciTech Connect

    Moore, D.M.; Hughes, R.E. )

    1991-03-01

    Shallow marine, Mississippian, siliclastics in the Illinois basin, although predominantly quartz, contain other minerals that directly influence the porosity and permeability of these reservoir rocks. These sandstones contain more chlorite and kaolinite, relative to illite, than the authors have observed for shales from other Chesterian and Valmeyeran strata. Clay mineral suites in reservoirs appear to be diagenetic. The Aux Vases Sandstone contains illite, illite/smectite, and chlorite; kaolinite is absent. The Cypress Sandstone contains illite, illite/smectite, chlorite, and kaolinite. Chlorite in the Aux Vases Sandstone varies from moderately Fe-rich to Mg-rich, whereas the chlorite in the Cypress Sandstone is uniformly Fe-rich. As the percentage of clay minerals in these rocks decreases, the proportion of chlorite to other clay minerals increases. In some chlorites, the width of the 003 and 005 peaks at half-height is greater than that of the 002 and 004 peaks. This suggests an interlayering of a 7{angstrom} mineral, probably berthierine- or serpentine-like. SEM photos show chlorite coating quartz grains. In some samples there are quartz overgrowths in spite of the presence of a coating of chlorite; in others, chlorite interlayered with the 7{angstrom} phase seems to have interfered with or suppressed overgrowths. Correspondingly, there is a correlation between the 7{angstrom} phase/chlorite and porosity. Therefore, identification of the type of chlorite in a potential reservoir may be an indicator of porosity, as well as a guide for selecting completion and stimulation treatments.

  14. Controls on CO2 Mineralization in Volcanogenic Sandstone Reservoir Rocks

    NASA Astrophysics Data System (ADS)

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

    2013-12-01

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

  15. Predicting cement distribution in geothermal sandstone reservoirs based on estimates of precipitation temperatures

    NASA Astrophysics Data System (ADS)

    Olivarius, Mette; Weibel, Rikke; Whitehouse, Martin; Kristensen, Lars; Hjuler, Morten L.; Mathiesen, Anders; Boyce, Adrian J.; Nielsen, Lars H.

    2016-04-01

    Exploitation of geothermal sandstone reservoirs is challenged by pore-cementing minerals since they reduce the fluid flow through the sandstones. Geothermal exploration aims at finding sandstone bodies located at depths that are adequate for sufficiently warm water to be extracted, but without being too cemented for warm water production. The amount of cement is highly variable in the Danish geothermal reservoirs which mainly comprise the Bunter Sandstone, Skagerrak and Gassum formations. The present study involves bulk and in situ stable isotope analyses of calcite, dolomite, ankerite, siderite and quartz in order to estimate at what depth they were formed and enable prediction of where they can be found. The δ18O values measured in the carbonate minerals and quartz overgrowths are related to depth since they are a result of the temperatures of the pore fluid. Thus the values indicate the precipitation temperatures and they fit the relative diagenetic timing identified by petrographical observations. The sandstones deposited during arid climatic conditions contain calcite and dolomite cement that formed during early diagenesis. These carbonate minerals precipitated as a response to different processes, and precipitation of macro-quartz took over at deeper burial. Siderite was the first carbonate mineral that formed in the sandstones that were deposited in a humid climate. Calcite began precipitating at increased burial depth and ankerite formed during deep burial and replaced some of the other phases. Ankerite and quartz formed in the same temperature interval so constrains on the isotopic composition of the pore fluid can be achieved. Differences in δ13C values exist between the sandstones that were deposited in arid versus humid environments, which suggest that different kinds of processes were active. The estimated precipitation temperatures of the different cement types are used to predict which of them are present in geothermal sandstone reservoirs in

  16. Reservoir characteristics of Lower Wilcox Sandstones, Lobo Trend, Webb and Zapata Counties, Texas

    SciTech Connect

    Henke, K.A.

    1985-02-01

    To date, over 340 bcf of gas have been produced from the Lobo sandstones in the Laredo field area at depths of less than 10,000 ft (3050 m). Gas accumulation is controlled by faulting and erosional truncation. The resulting structural complexity has made accurate prediction of reservoir sandstones difficult. Cored sections display repetitive ordered sequences of sedimentary structures and textural and compositional gradations indicative of turbidity-current deposits. The reservoir sandstones were deposited as constructional channels having vertical and lateral variation from channel-fill to channel-margin to overbank deposits. Channel-fill units are 2-10 ft (0.61-3.05 m) thick and composed of AB, AE, and ABE bedsets. Channel-margin units are 1-3 ft (0.31-0.92 m) thick and contain thinner, more complete ABC, ABE and ABCE sequences. Overbank deposits consist of highly bioturbated, thinly interbedded sandstones and shales. Sandstones are feldspathic litharenites that have 15% matrix and 15% calcite cement. Porosities average 16% and permeabilities range from 0.54 to 12 md, decreasing with increased matrix, cement, and bioturbation. The channel-fill sandstones are linear, dip-trending bodies less than 3000 ft (915 m) wide, which bifurcate downdip into distributary channels. High-intensity, small-scale, soft-sediment deformation indicates the sandstones were deposited in an unstable outer-shelf to upper-slope environment. A slumped, dip-trending channel-fill interpretation for the Lobo sandstones provides a mechanism for sediment transport beyond the present downdip limits of the trend.

  17. Microfractures in Quartz Grains as a Measurement of Maximum Effective Stress in Sandstone Reservoirs

    NASA Astrophysics Data System (ADS)

    Mehrkian, K.; Aubourg, C.; Girard, J. P.; Teinturier, S.; Hoareau, G.

    2015-12-01

    Effective stress, defined as the load transmitted from particle to particle in the solid framework of a rock, plays a significant role in controlling mechanical compaction and thus reservoir quality in sandstones. Mechanical compaction in sandstones takes place through rearrangement and ductile/ brittle deformation of framework grains during progressive burial. It is primarily dependent on the magnitude and evolution of effective stress during burial, and on the nature and textural properties of framework grains (mineralogy, grain size/shape, sorting…) and pore-filing solid cements when present. Here, we propose a method to directly evaluate maximum effective stress in sandstone reservoirs by quantifying the brittle deformation of quartz grains evidenced through the development of microfractures. Quartz microfracturing is documented and quantified by examining thin sections of core samples under SEM CL microscopy. Previous published experimental studies and observations made on natural samples indicate that quartz burial-induced microfracturing in sandstones is mainly affected by effective stress, but also reflects other factors such as grain size, sorting and proportion of ductile grains (clays, micas…). In order to investigate the quantitative impact of such factors altogether, we have conducted compaction experiments (>30 tests) on 10 types of sands at 25°C, under dry conditions and pressures up to 55 Mpa. The resulting compressed sands were studied by optical microscopy to quantify fractured quartz grains. Results were processed using R statistical computing language via a multi input model to define a simple equation that provides correction constants for each influencing factor. The resulting equation will then be used to calculate the maximum effective stress recorded by a sandstone reservoir during its burial history, based on the petrographic/mineralogical characteristics (thin section point-counting) and the fractured-grain ratio (obtained by SEM CL

  18. Anomalous dispersion due to hydrocarbons: The secret of reservoir geophysics?

    USGS Publications Warehouse

    Brown, R.L.

    2009-01-01

    When P- and S-waves travel through porous sandstone saturated with hydrocarbons, a bit of magic happens to make the velocities of these waves more frequency-dependent (dispersive) than when the formation is saturated with brine. This article explores the utility of the anomalous dispersion in finding more oil and gas, as well as giving a possible explanation about the effect of hydrocarbons upon the capillary forces in the formation. ?? 2009 Society of Exploration Geophysicists.

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

    NASA Astrophysics Data System (ADS)

    Wolela, A.

    2014-11-01

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

  20. Estimation of permeability of a sandstone reservoir by a fractal and Monte Carlo simulation approach: a case study

    NASA Astrophysics Data System (ADS)

    Vadapalli, U.; Srivastava, R. P.; Vedanti, N.; Dimri, V. P.

    2014-01-01

    Permeability of a hydrocarbon reservoir is usually estimated from core samples in the laboratory or from well test data provided by the industry. However, such data is very sparse and as such it takes longer to generate that. Thus, estimation of permeability directly from available porosity logs could be an alternative and far easier approach. In this paper, a method of permeability estimation is proposed for a sandstone reservoir, which considers fractal behavior of pore size distribution and tortuosity of capillary pathways to perform Monte Carlo simulations. In this method, we consider a reservoir to be a mono-dispersed medium to avoid effects of micro-porosity. The method is applied to porosity logs obtained from Ankleshwar oil field, situated in the Cambay basin, India, to calculate permeability distribution in a well. Computed permeability values are in good agreement with the observed permeability obtained from well test data. We also studied variation of permeability with different parameters such as tortuosity fractal dimension (Dt), grain size (r) and minimum particle size (d0), and found that permeability is highly dependent upon the grain size. This method will be extremely useful for permeability estimation, if the average grain size of the reservoir rock is known.

  1. Effects of clay minerals on Triassic sandstone reservoir in Shan Can Ning basin and their significance

    SciTech Connect

    Zhu Guo Hua; Qian Kai

    1989-03-01

    Mesozoic sandstone reservoirs in the Shan Can Ning basin contain various clay minerals with different genesis and occurrences, which give rise to different effects on reservoir characteristics. The results of this study suggest that the effects of illite on permeability, electrical resistivity, and oil and water saturation of the Yan 10 sandstone are much more obvious than those due to kaolinite. Authigenic chlorite film covering the peripheral edges of sand grains restrained the coaxial secondary overgrowths of quartz, feldspar, and other grains. This restraint played an effective role in preserving the pores and texture of the Yanchang reservoir rocks. The authigenic chlorite film contains abundant micropores which can adsorb considerable pore water, which is kept in an irreducible state. Thus, given the same water saturation conditions, the water production of Yanchang reservoir rocks rich in authigenic chlorite is significantly lower than that of the rocks poor in chlorite film. Because the occurrence of the pore-lining clay (film type) reduces the size of pore throats, acidization may show notable effects on this type of sandstone reservoir.

  2. Core analysis in a low permeability sandstone reservoir: Results from the Multiwell Experiment

    SciTech Connect

    Sattler, A.R.

    1989-04-01

    Over 4100 ft (1100 ft oriented) of Mesaverde core was taken during the drilling of the three Multiwell Experiment (MWX) wells, for study in a comprehensive core analysis program. This core traversed five separate depositional environments (shoreline/marine, coastal, paludal, fluvial, and paralic), and almost every major sand in the Mesaverde at the site was sampled. This paper summarizes MWX core analysis and describes the petrophysical properties at the MWX site; reservoir parameters, including permeabilities of naturally fractured core; and mechanical rock properties including stress-related measurements. Some correlations are made between reservoir properties and mineralogy/petrology data. Comparisons are made between the properties of lenticular and blanket sandstone morphologies existing at the site. This paper provides an overview of a complete core analysis in a low-permeability sandstone reservoir. 66 refs., 17 figs. , 9 tabs.

  3. Sedimentology and reservoir characteristics of tight gas sandstones, Frontier formation, southwestern Wyoming

    SciTech Connect

    Moslow, T.F.; Tillman, R.W.

    1984-04-01

    The lower Frontier Formation, Moxa arch area, southwestern Wyoming, is one of the most prolific gas-producing formations in the Rocky Mountain region. Lower Frontier sediments were deposited as strandplains and coalescing wave-dominated deltas that prograding into the western margin of the Cretaceous interior seaway during the Cenomanian. In this study, sedimentologic, petrologic, and stratigraphic analyses were conducted on cores and logs of Frontier wells from the Whiskey Buttes and Moxa fields. Twelve sedimentary facies have been identified. The most common sequence consists of burrowed to cross-bedded near shore marine (delta-front and inner-shelf) sandstones disconformably overlain by cross-bedded (active) to deformed (abandoned) distributary-channel sandstones and conglomerates. The sequence is capped by delta-plain mudstones and silty sandstones. Tight-gas sandstone reservoir facies are non-homogenous and include crevasse splay, abandoned and active distributary channel, shoreface, foreshore, and inner shelf sandstones. Distributary-channel facies represent 80% of perforated intervals in wells in the southern part of the Moxa area, but only 50% to the north. Channel sandstone bodies are occasionally stacked, occur on the same stratigraphic horizon, and are laterally discontinuous with numerous permeability barriers. Percentage of perforated intervals in upper shoreface and foreshore facies increases from 20% in the south to 50% in the north.

  4. Sedimentology and reservoir characteristics of tight gas sandstones, Frontier formation, southwestern Wyoming

    SciTech Connect

    Moslow, T.F.; Tillman, R.W.

    1984-04-01

    The lower Frontier Formation, Moxa arch area, southwestern Wyoming, is one of the most prolific gas-producing formations in the Rocky Mountain region. Lowr Frontier sediments were deposited as strandplains and coalescing wave-dominated deltas that prograding into the western margin of the Cretaceous interior seaway during the Cenomanian. In this study, sedimentologic, petrologic, and stratigraphic analyses were conducted on cores and logs of Frontier wells from the Whiskey Buttes and Moxa fields. Twelve sedimentary facies have been identified. The most common sequence consists of burrowed to cross-bedded near shore marine (delta-front and inner-shelf) sandstones disconformably overlain by crossbedded (active) to deformed (abandoned) distributary-channel sandstones and conglomerates. The sequence is capped by delta-plain mudstones and silty sandstones. Tight-gas sandstone reservoir facies are nonhomogenous and include crevasse splay, abandoned and active distributary channel, shoreface, foreshore, and inner shelf sandstones. Distributary-channel facies represent 80% of perforated intervals in wells in the southern part of the Moxa area, but only 50% to the north. Channel sandstone bodies are occasionally stacked, occur on the same stratigraphic horizon, and are laterally discontinuous with numerous permeability barriers. Percentage of perforated intervals in upper shoreface and foreshore facies increases from 20% in the south to 50% in the north.

  5. Influence of depositional environment and diagenesis on gas reservoir properties in St. Peter Sandstone, Michigan basin

    SciTech Connect

    Harrison, W.B. III; Turmelle, T.M.; Barnes, D.A.

    1987-05-01

    The St. Peter Sandstone in the Michigan basin subsurface is rapidly becoming a major exploration target for natural gas. This reservoir was first proven with the successful completion of the Dart-Edwards 7-36 (Falmouth field, Missaukee County, Michigan) in 1981. Fifteen fields now are known, with a maximum of three producing wells in any one field. The production from these wells ranges from 1 to more than 10 MMCFGD on choke, with light-gravity condensate production of up to 450 b/d. Depth to the producing intervals ranges from about 7000 ft to more than 11,000 ft. The St. Peter Sandstone is an amalgamated stack of shoreface and shelf sequences more than 1100 ft in thickness in the basin center and thinning to zero at the basin margins. Sandstone composition varies from quartzarenite in the coarser sizes to subarkose and arkose in the finer sizes. Thin salty/shaly lithologies and dolomite-cemented sandstone intervals separate the porous sandstone packages. Two major lithofacies are recognized in the basin: a coarse-grained, well-sorted quartzarenite with various current laminations and a fine-grained, more poorly sorted subarkose and arkose with abundant bioturbation and distinct vertical and horizontal burrows. Reservoir quality is influenced by original depositional and diagenetic fabrics, but there is inversion of permeability and porosity with respect to primary textures in the major lithofacies. The initially highly porous and permeable, well-sorted, coarser facies is now tightly cemented with syntaxial quartz cement, resulting in a low-permeability, poor quality reservoir. The more poorly sorted, finer facies with initially lower permeabilities did not receive significant fluid flux until it passed below the zone of quartz cementation. This facies was cemented with carbonate which has subsequently dissolved to form a major secondary porosity reservoir.

  6. Timing and Duration of Gas Charge-Driven Fracturing in Tight-Gas Sandstone Reservoirs Based on Fluid Inclusion Observations: Piceance Basin, Colorado

    NASA Astrophysics Data System (ADS)

    Fall, A.; Eichhubl, P.; Laubach, S.; Bodnar, R. J.

    2012-12-01

    Natural fractures are universally present in tight-gas sandstone reservoirs. Fractures are recognized to enhance permeability of the reservoir, provide gas-migration pathways during charge, and boost connectivity with well bore during production of natural gas. "Sweet spots", or higher than average permeability and production regions, have been attributed to the presence of open fractures in the reservoir. Thus it is essential to understand the opening history of natural fractures, such as the timing with respect to hydrocarbon generation and migration in the reservoirs. The natural opening-mode fractures in the tight-gas sandstone of the Mesaverde Group in the Piceance Basin, Colorado, are partially or completely cemented by quartz and/or calcite that precipitated syn- or postkinematically relative to fracture opening. Fluid inclusions trapped in the cements record pressure, temperature, and fluid composition during subsequent fracture opening and cementation. SEM-CL imaging of cements combined with fluid inclusion microthermometry and Raman spectroscopy constrain fluid evolution trends during fracturing, and timing of fracture opening in the tight-gas sandstone reservoirs. Fluid inclusions indicate a thermal history varying from ~150°C to ~188°C to ~140°C in sandstones of the Piceance Basin. Based on microthermometry, Raman spectroscopy, and equation of state modeling calculated pore-fluid pressures varied from ~40 to 100 MPa suggesting fracture opening under significant pore-fluid overpressures. Observed variability in pore-fluid pressure over time is interpreted to reflect dynamic conditions of episodic gas charge. Models of gas and oil generation in the Piceance Basin suggest that fracture opening and elevated pore-fluid pressures coincided with maximum gas generation within the Mesaverde Group. These observations demonstrate that protracted growth of the pervasive fracture system was the consequence of gas maturation and reservoir charge, and that fracture

  7. Petrography and diagenesis of reservoir and non-reservoir sandstones in Shattuck Member of Queen Formation, northwest shelf of Permian basin

    SciTech Connect

    Malicse, A.; Siegel, J.; Mazzullo, J.

    1988-02-01

    The Shattuck Member is a thick (6-20 m) sandstone that defines the top of the Queen Formation (Permian, Guadalupian) and is a major hydrocarbon reservoir on the Northwestern shelf of the Permian basin. The Shattuck was deposited in desert dune and interdune, dry and wet sand sheet, and sandy sabkha environments during a lowstand of sea level. The desert dune, interdune, and dry sand sheet deposits constitute the producing horizons in the Shattuck, whereas the wet sand sheet and sabkha deposits are generally non-productive. The purposes of this study are to examine the petrographic characteristics of the producing and non-producing horizons with petrographic and scanning electron microscopes, and to determine their provenance and diagenetic history.

  8. Continuity and internal properties of Gulf Coast sandstones and their implications for geopressured fluid production

    SciTech Connect

    Morton, R.A.; Ewing, T.E.; Tyler, N.

    1983-01-01

    The intrinsic properties of the genetic sandstone units that typify many geopressured geothermal aquifers and hydrocarbon reservoirs in the Gulf Coast region were systematically investigated classified, and differentiated. The following topics are coverd: structural and stratigraphic limits of sandstone reservoirs, characteristics and dimensions of Gulf Coast sandstones; fault-compartment areas; comparison of production and geologic estimates of aquifer fluid volume; geologic setting and reservoir characteristics, Wells of Opportunity; internal properties of sandstones; and implications for geopressured fluid production. (MHR)

  9. CHARACTERIZATION OF SANDSTONE RESERVOIRS FOR ENHANCED OIL RECOVERY: THE PERMIAN UPPER MINNELUSA FORMATION, POWDER RIVER BASIN, WYOMING.

    USGS Publications Warehouse

    Schenk, C.J.; Schmoker, J.W.; Scheffler, J.M.

    1986-01-01

    Upper Minnelusa sandstones form a complex group of reservoirs because of variations in regional setting, sedimentology, and diagenetic alteration. Structural lineaments separate the reservoirs into northern and southern zones. Production in the north is from a single pay sand, and in the south from multi-pay sands due to differential erosion on top of the Upper Minnelusa. The intercalation of eolian dune, interdune, and sabkha sandstones with marine sandstones, carbonates, and anhydrites results in significant reservoir heterogeneity. Diagenetic alterations further enhance heterogeneity, because the degree of cementation and dissolution is partly facies-related.

  10. Capillarity and wetting of carbon dioxide and brine during drainage in Berea sandstone at reservoir conditions

    NASA Astrophysics Data System (ADS)

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

    2015-10-01

    The wettability of CO2-brine-rock systems will have a major impact on the management of carbon sequestration in subsurface geological formations. Recent contact angle measurement studies have reported sensitivity in wetting behavior of this system to pressure, temperature, and brine salinity. We report observations of the impact of reservoir conditions on the capillary pressure characteristic curve and relative permeability of a single Berea sandstone during drainage—CO2 displacing brine—through effects on the wetting state. Eight reservoir condition drainage capillary pressure characteristic curves were measured using CO2 and brine in a single fired Berea sandstone at pressures (5-20 MPa), temperatures (25-50°C), and ionic strengths (0-5 mol kg-1 NaCl). A ninth measurement using a N2-water system provided a benchmark for capillarity with a strongly water wet system. The capillary pressure curves from each of the tests were found to be similar to the N2-water curve when scaled by the interfacial tension. Reservoir conditions were not found to have a significant impact on the capillary strength of the CO2-brine system during drainage through a variation in the wetting state. Two steady-state relative permeability measurements with CO2 and brine and one with N2 and brine similarly show little variation between conditions, consistent with the observation that the CO2-brine-sandstone system is water wetting and multiphase flow properties invariant across a wide range of reservoir conditions.

  11. Depositional environment and reservoir characteristics of lower Cretaceous Paluxy sandstones, Bolton Field, Hinds County, Mississippi

    SciTech Connect

    Coyle, R.D.

    1981-05-01

    Bolton Field produces oil from numerous lenticular, lower Cretaceous sandstones at depths ranging from 8350 to 11,800 ft (2545 to 3596 m). The field is on an elongated, faulted anticline in the northwest part of the Mississippi salt basin. It was discovered in 1954 as a result of seismic mapping. Two years after its discovery it had produced 1,475,179 bbl of oil. A core of the lower Cretaceous Paluxy sandstone, and electric logs from the field area, were studied to determine the environment of deposition and reservoir morphology. The Paluxy sandstones were deposited within a fluvial system. Primary rock properties observed in the core indicate a braided stream deposit. Bedsets are thin, ranging from 0.5 to 9 ft (0.15 to 2.74 m) in thickness. Sedimentary structures within bedsets consist of inclined laminae in the lower part to parallel laminae and ripples in the upper part, indicating deposition from decreasing flow regime.

  12. Fines migration, blocking, and clay swelling of potential geothermal sandstone reservoirs, Denmark

    SciTech Connect

    Priisholm, S.; Nielson, B.L.; Haslund, O.

    1987-06-01

    Medium-grained, moderately well-sorted sandstones of fluvio-deltaic to shallow marine origin have been investigated for fines production and for variations in porosity/permeability. Porosity and permeability change within small horizontal and vertical changes in sampling points. Also, air permeability depends on flow direction, Klinkenberg correction, and cleaning procedure. Klinkenberg-corrected permeability and brine permeability were found not to be comparable. Brine flow cause flines of kaolinite and quartz to be produced from the compacted sandstones, while uncompacted sandstones produced kaolinite, illite, and detrital minerals. Chlorites and mixed-layer clays were not produced as fines, although they were present in some samples. Reservoir damage occurred when formation brine was replaced by KCl-brine, at increase in flow velocity, and at pauses in flow. Changes in flow direction caused severe fines production, renewed bridging, and blocking by fines.

  13. 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

  14. The effects of impure CO2 on reservoir sandstones: results from mineralogical and geomechanical experiments

    NASA Astrophysics Data System (ADS)

    Marbler, H.; Erickson, K. P.; Schmidt, M.; Lempp, Ch.; Pöllmann, H.

    2012-04-01

    An experimental study of the behaviour of reservoir sandstones from deep saline aquifers during the injection and geological storage of CO2 with the inherent impurities SOX and NOX is part of the German national project COORAL*. Sample materials were taken from outcrops of possible reservoir formations of Rotliegend and Bunter Sandstones from the North German Basin. A combination of mineralogical alteration experiments and geomechanical tests was carried out on these rocks to study the potential effects of the impurities within the CO2 pore fluid. Altered rock samples after the treatment with CO2 + SOX/NOX in an autoclave system were loaded in a triaxial cell under in-situ pressure and temperature conditions in order to estimate the modifications of the geomechanical rock properties. Mineralogical alterations were observed within the sandstones after the exposure to impure supercritical (sc)CO2 and brine, mainly of the carbonatic, but also of the silicatic cements, as well as of single minerals. Besides the partial solution effects also secondary carbonate and minor silicate mineral precipitates were observed within the pore space of the treated sandstones. These alterations affect the grain structure of the reservoir rock. Results of geomechanical experiments with unaltered sandstones show that the rock strength is influenced by the degree of rock saturation before the experiment and the chemical composition of the pore fluid (scCO2 + SOX + NOX). After long-term autoclave treatment with impure scCO2, the sandstone samples exhibit modified strength parameters and elastic deformation behaviour as well as changes in porosity compared to untreated samples. Furthermore, the injected fluid volume into the pore space of sandstones from the same lithotype varies during triaxial loading depending on the chemistry of the pore fluid. CO2 with NOX and SOX bearing fluid fills a significantly larger proportion of the sandstone pore space than brine with pure scCO2. * The

  15. Modelling of Seismic and Resistivity Responses during the Injection of CO2 in Sandstone Reservoir

    NASA Astrophysics Data System (ADS)

    Omar, Muhamad Nizarul Idhafi Bin; Almanna Lubis, Luluan; Nur Arif Zanuri, Muhammad; Ghosh, Deva P.; Irawan, Sonny; Regassa Jufar, Shiferaw

    2016-07-01

    Enhanced oil recovery plays vital role in production phase in a producing oil field. Initially, in many cases hydrocarbon will naturally flow to the well as respect to the reservoir pressure. But over time, hydrocarbon flow to the well will decrease as the pressure decrease and require recovery method so called enhanced oil recovery (EOR) to recover the hydrocarbon flow. Generally, EOR works by injecting substances, such as carbon dioxide (CO2) to form a pressure difference to establish a constant productive flow of hydrocarbon to production well. Monitoring CO2 performance is crucial in ensuring the right trajectory and pressure differences are established to make sure the technique works in recovering hydrocarbon flow. In this paper, we work on computer simulation method in monitoring CO2 performance by seismic and resistivity model, enabling geoscientists and reservoir engineers to monitor production behaviour as respect to CO2 injection.

  16. Oxfordian-Kimmeridgian (Late Jurassic) reservoir sandstones in the Witch Ground Graben, U. K. North Sea

    SciTech Connect

    Harker, S.D. Ltd., Aberdeen ); Mantel, K.A. ); Morton, D.J. ); Riley, L.A. )

    1991-03-01

    Oil-bearing Late Jurassic Oxfordian-Kimmeridgian sandstones of the Sgiath and Piper formations are of major economic importance in the Witch Ground Graben. They form the reservoirs in Scott, which in 1993 will be the largest producing North Sea oil field to come on stream for more than a decade. Together with Scott, the Piper, Saltire, Tartan, Highlander, Petronella, Rob Roy, and Ivanhoe fields contained almost 2 Bbbl of recoverable reserves in these formations. The Sgiath and Piper represent two phases of Late Jurassic transgression and regression, initially represented by paralic deposited sand culminating in a wave-dominated delta sequence. The history of the Sgiath and Piper formations is reviewed and lithostratigraphic and biostratigraphic correlations presented to illustrate the distribution of the reservoir sandstones.

  17. Relationships among low frequency (2 Hz) electrical resistivity, porosity, clay content and permeability in reservoir sandstones

    NASA Astrophysics Data System (ADS)

    Han, Tongcheng; Best, Angus I.; Sothcott, Jeremy; North, Laurence J.; MacGregor, Lucy M.

    2015-01-01

    The improved interpretation of marine controlled source electromagnetic (CSEM) data requires knowledge of the inter-relationships between reservoir parameters and low frequency electrical resistivity. Hence, the electrical resistivities of 67 brine (35 g/l) saturated sandstone samples with a range of petrophysical properties (porosity from 2% to 29%, permeability from 0.0001 mD to 997.49 mD and volumetric clay content from 0 to 28%) were measured in the laboratory at a frequency of 2 Hz using a four-electrode circumferential resistivity method with an accuracy of ± 2%. The results show that sandstones with porosity higher than 9% and volumetric clay content up to 22% behave like clean sandstones and follow Archie's law for a brine concentration of 35 g/l. By contrast, at this brine salinity, sandstones with porosity less than 9% and volumetric clay content above 10% behave like shaly sandstones with non-negligible grain surface conductivity. A negative, linear correlation was found between electrical resistivity and hydraulic permeability on a logarithmic scale. We also found good agreement between our experimental results and a clay pore blocking model based on pore-filling and load-bearing clay in a sand/clay mixture, variable (non-clay) cement fraction and a shaly sandstone resistivity model. The model results indicate a general transition in shaly sandstones from clay-controlled resistivity to sand-controlled resistivity at about 9% porosity. At such high brine concentrations, no discernible clay conduction effect was observed above 9% porosity.

  18. Comparative study of models for predicting permeability from nuclear magnetic resonance (NMR) logs in two Chinese tight sandstone reservoirs

    NASA Astrophysics Data System (ADS)

    Xiao, Liang; Liu, Xiao-Peng; Zou, Chang-Chun; Hu, Xiao-Xin; Mao, Zhi-Qiang; Shi, Yu-Jiang; Guo, Hao-Peng; Li, Gao-Ren

    2014-02-01

    Based on the analysis of mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR) experimental data for core plugs, which were drilled from two Chinese tight sandstone reservoirs, permeability prediction models, such as the classical SDR, Timur-Coates, the Swanson parameter, the Capillary Parachor, the R10 and R35 models, are calibrated to estimating permeabilities from field NMR logs, and the applicabilities of these permeability prediction models are compared. The processing results of several field examples show that the SDR model is unavailable in tight sandstone reservoirs. The Timur-Coates model is effective once the optimal T 2cutoff can be acquired to accurately calculate FFI and BVI from field NMR logs. The Swanson parameter model and the Capillary Parachor model are not always available in tight sandstone reservoirs. The R35 based model cannot effectively work in tight sandstone reservoirs, while the R10 based model is optimal in permeability prediction.

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

    NASA Astrophysics Data System (ADS)

    Dewers, T. A.

    2015-12-01

    Multiphase flow in clay-rich sandstone reservoirs is important to enhanced oil recovery (EOR) and the geologic storage of CO2. Understanding geologic controls on pore structure allows for better identification of lithofacies that can contain, storage, and/or transmit hydrocarbons and CO2, and may result in better designs for EOR-CO2 storage. We examine three-dimensional pore structure and connectivity of sandstone samples from the Farnsworth Unit, Texas, the site of a combined EOR-CO2 storage project by the Southwest Regional Partnership on Carbon Sequestration (SWP). We employ a unique set of methods, including: robotic serial polishing and reflected-light imaging for digital pore-structure reconstruction; electron microscopy; laser scanning confocal microscopy; mercury intrusion-extrusion porosimetry; and relative permeability and capillary pressure measurements using CO2 and synthetic formation fluid. Our results link pore size distributions, topology of porosity and clay-rich phases, and spatial persistence of connected flow paths to multiphase flow behavior. The authors gratefully acknowledge the U.S. Department of Energy's National Energy Technology Laboratory for sponsoring this project through the SWP under Award No. DE-FC26-05NT42591. Sandia National Laboratories is a multi-program laboratory managed and operated by Sandia Corporation, a wholly owned subsidiary of Lockheed Martin Corporation, for the U.S. Department of Energy's National Nuclear Security Administration under contract DE-AC04-94AL85000.

  20. Amplitude map analysis using forward modeling in sandstone and carbonate reservoirs

    SciTech Connect

    Neff, D.B. )

    1993-10-01

    The extent to which seismic amplitude maps can contribute to the analysis of hydrocarbon reservoirs was investigated for clastic and carbonate reservoirs worldwide. By using a petrophysical-based, forward modeling process called incremental pay thickness (IPT) modeling, five lithology types were quantitatively analyzed for the interplay of seismic amplitude versus lithology, porosity, hydrocarbon pore fluid saturation, bedding geometries, and reservoir thickness. The studies identified three common tuning curve shapes (concave, convex, and bilinear) that were primarily dependent upon the lithology model type and the average net porosity therein. While the reliability of pay and porosity predictions from amplitude maps varied for each model type, all analyses showed a limited thickness range for which amplitude data could successfully predict net porosity thickness or hydrocarbon pore volume. The investigation showed that systematic forward modeling is required before amplitude maps can be properly interpreted.

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

    SciTech Connect

    Jones, J.R. Jr.

    1984-04-01

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

  2. Genesis analysis of high-gamma ray sandstone reservoir and its log evaluation techniques: a case study from the Junggar basin, northwest China.

    PubMed

    Wang, Liang; Mao, Zhiqiang; Sun, Zhongchun; Luo, Xingping; Song, Yong; Liu, Zhen

    2013-01-01

    In the Junggar basin, northwest China, many high gamma-ray (GR) sandstone reservoirs are found and routinely interpreted as mudstone non-reservoirs, with negative implications for the exploration and exploitation of oil and gas. Then, the high GR sandstone reservoirs' recognition principles, genesis, and log evaluation techniques are systematically studied. Studies show that the sandstone reservoirs with apparent shale content greater than 50% and GR value higher than 110API can be regarded as high GR sandstone reservoir. The high GR sandstone reservoir is mainly and directly caused by abnormally high uranium enrichment, but not the tuff, feldspar or clay mineral. Affected by formation's high water sensitivity and poor borehole quality, the conventional logs can not recognize reservoir and evaluate the physical property of reservoirs. Then, the nuclear magnetic resonance (NMR) logs is proposed and proved to be useful in reservoir recognition and physical property evaluation. PMID:24078797

  3. Genesis Analysis of High-Gamma Ray Sandstone Reservoir and Its Log Evaluation Techniques: A Case Study from the Junggar Basin, Northwest China

    PubMed Central

    Wang, Liang; Mao, Zhiqiang; Sun, Zhongchun; Luo, Xingping; Song, Yong; Liu, Zhen

    2013-01-01

    In the Junggar basin, northwest China, many high gamma-ray (GR) sandstone reservoirs are found and routinely interpreted as mudstone non-reservoirs, with negative implications for the exploration and exploitation of oil and gas. Then, the high GR sandstone reservoirs' recognition principles, genesis, and log evaluation techniques are systematically studied. Studies show that the sandstone reservoirs with apparent shale content greater than 50% and GR value higher than 110API can be regarded as high GR sandstone reservoir. The high GR sandstone reservoir is mainly and directly caused by abnormally high uranium enrichment, but not the tuff, feldspar or clay mineral. Affected by formation's high water sensitivity and poor borehole quality, the conventional logs can not recognize reservoir and evaluate the physical property of reservoirs. Then, the nuclear magnetic resonance (NMR) logs is proposed and proved to be useful in reservoir recognition and physical property evaluation. PMID:24078797

  4. Analysis of Texas Gulf Coast Tertiary sandstones to delineate areas of high-quality geopressured geothermal reservoirs

    SciTech Connect

    Loucks, R.G.; Dodge, M.M.

    1980-06-01

    In Lower and in parts of Middle and Upper Texas Gulf Coast the Wilcox sandstones are relatively well consolidated, but in other parts of Middle and Upper Texas Gulf Coast they show a reversal toward increased porosity at depth. The Wilcox Group has good reservoir potential for geopressured geothermal energy in the Middle Texas Gulf Coast and possibly in adjacent areas, but other Wilcox areas are marginal. Vicksburg sandstones have the poorest reservoir quality of sandstones of any formation and are not prospective for geothermal energy. Reservoir quality in the Frio Formation increases from very poor to lowermost Texas, to marginal into the Middle Texas Gulf Coast, and to good through the Upper Texas Gulf Coast. This increase in reservoir quality correlates to changes in rock composition and cementation. The Frio Formation in the Upper Texas Gulf Coast has the best deep-reservoir quality of any unit along the Texas Gulf Coast. 18 references.

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

    NASA Astrophysics Data System (ADS)

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

    2016-06-01

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

  6. Diagenesis and reservoir potential of volcanogenic sandstones - Cretaceous of the Surat Basin, Queensland, Australia

    SciTech Connect

    Hawlader, H.M. )

    1990-06-01

    The sandstones of the Lower Cretaceous succession of the Surat basin are characterized by abundant volcanogenic detritus in the form of rock-fragments and feldspars derived from an andesitic magmatic arc coincident with the present Great Barrier Reef in offshore Queensland. These compositionally immature sandstones are not regarded as favorable exploration targets because of their labile nature, their shallow burial depths, and hence the low thermal maturity of the intercalated mudrocks that might have constituted hydrocarbon source rocks. However, petrographic and petrophysical examinations show that significant primary and early diagenetic secondary dissolution porosity and permeability exist in some of these stratigraphic units that under certain circumstances could be the host for hydrocarbons and may become the future exploration targets. Flushing by CO{sub 2}-charged meteoric water after the inception of the Great Artesian basin (of which the Surat basin is a component) in the Tertiary is likely to have been the principal agent of secondary porosity development in these sandstones. Additionally, products of microbial degradation of organic matter (in the intercalated mudstones) and/or maturation products from the deeply buried part of the basin might have assisted in the dissolution of framework grains and previously deposited cement.

  7. Transport of Organic Contaminants Mobilized from Coal through Sandstone Overlying a Geological Carbon Sequestration Reservoir

    SciTech Connect

    Zhong, Lirong; Cantrell, Kirk J.; Bacon, Diana H.; Shewell, Jesse L.

    2014-02-01

    Column experiments were conducted using a wetted sandstone rock installed in a tri-axial core holder to study the flow and transport of organic compounds mobilized by scCO2 under simulated geologic carbon storage (GCS) conditions. The sandstone rock was collected from a formation overlying a deep saline reservoir at a GCS demonstration site. Rock core effluent pressures were set at 0, 500, or 1000 psig and the core temperature was set at 20 or 50°C to simulate the transport to different subsurface depths. The concentrations of the organic compounds in the column effluent and their distribution within the sandstone core were monitored. Results indicate that the mobility though the core sample was much higher for BTEX compounds than for naphthalene. Retention of organic compounds from the vapor phase to the core appeared to be primarily controlled by partitioning from the vapor phase to the aqueous phase. Adsorption to the surfaces of the wetted sandstone was also significant for naphthalene. Reduced temperature and elevated pressure resulted in greater partitioning of the mobilized organic contaminants into the water phase.

  8. The relationship between mineral content and acoustic velocity of sandstone reservoirs in Junggar basin

    NASA Astrophysics Data System (ADS)

    Li, Yan; Gu, Hanming

    2015-08-01

    Sandstone reservoirs have generally high porosity in the Shawan formation of the Chunguang oil field, Junggar basin, because they developed in geological conditions of shallow and weak compaction. High porosity always links lower acoustic velocities in sandstone. However, when it is more than a certain value (approximately 27.5%), the porosity is not in accordance with acoustic velocities. In addition, cast thin sections illustrated incoherence between pore types and porosity. Fluids and mineral content are the two main factors changing acoustic velocities. This means that acoustic velocities of the high-porosity sandstone are mainly affected by the mineral content and fluid properties. Hence, data from litho-electric analysis are used to measure velocities of the compression shear waves, and thin sections are used to identify the mineral content. By the application of cross-plot maps, relations of acoustic velocities and mineral contents are proposed. Mineral contents include mainly quartz, feldspar, and tuff. In normal rock physical models, the shale content is calculated from well logs. The mineral grain is often regarded as pure quartz grain or average mineral composition. However, the application of the normal rock physics model will be inaccurate for high-porosity sandstone. Experience regression functions of the velocity model are established to estimate acoustic velocities. Also, mineral content logs could be predicted by using the P-wave acoustic log, and the rock physics model would be enhanced by using these logs of dynamic mineral contents. Shear wave velocity could also be estimated more accurately.

  9. Factors controlling permeability of cataclastic deformation bands and faults in porous sandstone reservoirs

    NASA Astrophysics Data System (ADS)

    Ballas, Gregory; Fossen, Haakon; Soliva, Roger

    2015-07-01

    Improving the prediction of sub-seismic structures and their petrophysical properties is essential for realistic characterization of deformed sandstone reservoirs. In the present paper, we describe permeability contrasts induced by cataclastic deformation bands and faults in porous sandstones (766 data synthesized from field examples and the literature). We also discuss the influence of several factors, including tectonic regime, presence of a fault, burial depth, host sandstone porosity, and grain size and sorting for their initiation and permeability. This analysis confirms that permeability decrease is as a function of grain-crushing intensity in bands. Permeability reduction ranges from very limited in crush-microbreccia of compaction bands to high permeability reduction in cataclasites and ultracataclasites of shear-dominated bands, band clusters and faults. Tectonic regime, and especially normal-fault regime, with its tendency to localize strain and generate faults, is identified as the most important factor, leading to the formation of cataclastic bands with high permeability contrasts. Moreover, moderate burial depth (1-3 km) favors cataclastic bands with high permeability contrasts with respect to the host sandstone. High porosity, coarse-grain size and good grain sorting can slightly amplify the permeability reductions recorded in bands.

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

    USGS Publications Warehouse

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

    2009-01-01

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

  11. Diagenetic history and porosity development of Triassic arkosic sandstones: implications for hydrocarbon exploration

    SciTech Connect

    Ziegler, D.G.; Kasza, S.E.

    1987-05-01

    The Richmond basin of Virginia is one of several frontier Triassic basins of the Newark rift system of eastern North America currently being explored for hydrocarbons. There are numerous penetrations but limited core samples available for examination. In one well, however, 33 rotary sidewall cores have been collected and used for this study. Examination of these cores using thin section, X-ray diffraction (XRD) and scanning electron microscopy/energy dispersive spectroscopy (SEM/EDS) techniques has revealed a complex diagenetic history for arkosic sandstones near potential hydrocarbon source beds. An atypical mineral assemblage has developed as a result of dissolution of feldspar, quartz, mafic silicate, and other minerals and subsequent precipitation of laumontite (a zeolite), quartz, and trace amounts of clay. In thin section and with the SEM, these rocks have impressive intragranular and grainmoldic porosity and virtually no porosity-inhibiting clay. Consequently, a mechanism for creating significant secondary porosity in arkosic sandstones has been documented. This mechanism is probably related to the migration of hydrocarbons and associated fluids from source lithologies.

  12. Fluvial architecture and reservoir heterogeneity of middle Frio sandstones, Seeligson field, Jim Wells and Kleberg Counties, south Texas

    SciTech Connect

    Jirik, L.A.; Kerr, D.R.; Zinke, S.G.; Finley, R.J. )

    1990-05-01

    Evaluation of fluvial Frio reservoirs in south Texas reveals a complex architectural style potentially suited to the addition of incremental gas reserves through recognition of untapped compartments or bypassed gas zones. Seeligson field is being studied as part of a GRI/DOE/Texas-sponsored program, in cooperation with Oryx Energy Company and Mobil Exploration and Production U.S., Inc., and is designed to develop technologies and methodologies for increasing gas reserves from conventional reservoirs in mature fields. Seeligson field, discovered in 1937, has produced 2.2 tcf of gas from more than 50 middle Frio reservoirs. Cross sections as well as net sand and log facies maps illustrate depositional style, sandstone geometry, and reservoir heterogeneities. Far-offset vertical seismic profiles show laterally discontinuous reflections corresponding to the reservoirs. Lenticular lateral-bar sandstones dominate channel-fill deposits that together are commonly less than 50 ft thick, forming belts of sandstone approximately 2,500 ft wide. Crevasse-splay deposits commonly extend a few thousand feet beyond the channel system. Sand-rich channel-fill deposits are flanked by levee and overbank mudstones, isolating the reservoirs in narrow, dip-elongate trends. Deposition on an aggrading coastal plain resulted in a pattern of laterally stacked sandstone bodies that are widespread across the study area. Alternating periods of more rapid aggradation resulted in deposition of vertically stacked sandstones with limited areal distribution. Facies architecture of both depositional styles has implications for reservoir compartmentalization. Reservoir compartments within a laterally stacked system may be leaky, resulting from sandstone contact from producing wells along depositional axes. This effect is a major factor controlling incremental recovery. Reservoirs in vertically stacked systems should be better isolated.

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

    NASA Astrophysics Data System (ADS)

    Sun, Jianmeng; Wei, Xiaohan; Chen, Xuelian

    2016-08-01

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

  14. Analyzing a hydrocarbon reservoir by determining the response of that reservoir to tidal forces

    SciTech Connect

    Graebner, P.

    1991-08-20

    This patent describes a method for determining a component of the response of a hydrocarbons reservoir to tidal forces. It comprises measuring a variable responsive to tidal forces within the reservoir over a measurement time period; determining a theoretical earth-tide for the reservoir over the measurement time period; and determining the component of the response to tidal forces by comparing the variable measurements and the theoretical earth-tide determinations.

  15. Petrography, diagenesis and reservoir characteristics of the Pre-Cenomanian sandstone, Sheikh Attia area, East Central Sinai, Egypt

    NASA Astrophysics Data System (ADS)

    Kassab, Mohamed A.; Hassanain, Ibrahim M.; Salem, Alaa M.

    2014-08-01

    The diagenetic influence on reservoir characteristics was investigated for the Pre-Cenomanian (Early Paleozoic and Early Cretaceous) sandstone sequence in the Sheikh Attia area, East Central Sinai. This sequence can be distinguished into four formations: Sarabit El-Khadim Formation (Cambrian) at the base, Abu Hamata Formation (Cambro-Ordovician), Adedia Formation (Ordovician-Silurian) and Malha Formation (Early Cretaceous) on the top. The sandstones of Pre-Cenomanian sequence in the Sheikh Attia area are dominantly quartz arenites and subarkoses, where the quartz grains constitute about 82.3-98.4% of the framework composition with an average value of approximately 94% of the framework composition. Feldspars range in abundance from 0% to14.2%, with an average value of about 3% of the framework composition. The rock fragments constitute up to 9.8% of volume percent of framework grains, with an average of about 2.7%. Diagenetic events identified in these sandstones include compaction, cementation by calcite, quartz, clay minerals and iron oxides, dissolution and alteration of unstable clastic grains, and tectonically induced grain fracturing. Unstable clastic grains like feldspars suffered considerable alteration to kaolinite. The Pre-Cenomanian (Early Paleozoic and Early Cretaceous) sandstones possess good reservoir characteristics because they retain sufficient porosity and permeability in some intervals. These sandstones are characterized by porosity ranges between 3.80% and 27.60%, and have a permeability range from k ⩽ 0.03 mD, for tight sandstones to k ⩾ 50 mD, for the more permeable parts. The Pre-Cenomanian sandstones can be classified into four petrophysical flow units (megaport, macroport, mesoport and microport) with varying reservoir performances and are distinguished by comparable ranges of R35. Petrographic observations showed that the Early Paleozoic sandstones are texturally immature owing to the abundance of angular grains, non-uniformity of grain

  16. Facies architecture of the Bluejacket Sandstone in the Eufaula Lake area, Oklahoma: Implications for the reservoir characterization of the Bartlesville Sandstone

    SciTech Connect

    Ye, Liangmiao; Yang, Kexian

    1997-08-01

    Outcrop studies of the Bluejacket Sandstone (Middle Pennsylvanian) provide significant insights to reservoir architecture of the subsurface equivalent Bartlesville Sandstone. Quarry walls and road cuts in the Lake Eufaula area offer excellent exposures for detailed facies architectural investigations using high-precision surveying, photo mosaics. Directional minipermeameter measurements are being conducted. Subsurface studies include conventional logs, borehole image log, and core data. Reservoir architectures are reconstructed in four hierarchical levels: multi-storey sandstone, i.e. discrete genetic intervals; individual discrete genetic interval; facies within a discrete genetic interval; and lateral accretion bar deposits. In both outcrop and subsurface, the Bluejacket (Bartlesville) Sandstone comprises two distinctive architectures: a lower braided fluvial and an upper meandering fluvial. Braided fluvial deposits are typically 30 to 80 ft thick, and are laterally persistent filling an incised valley wider than the largest producing fields. The lower contact is irregular with local relief of 50 ft. The braided-fluvial deposits consist of 100-400-ft wide, 5-15-ft thick channel-fill elements. Each channel-fill interval is limited laterally by an erosional contact or overbank deposits, and is separated vertically by discontinuous mudstones or highly concentrated mudstone interclast lag conglomerates. Low-angle parallel-stratified or trough cross-stratified medium- to coarse-grained sandstones volumetrically dominate. This section has a blocky well log profile. Meandering fluvial deposits are typically 100 to 150 ft thick and comprise multiple discrete genetic intervals.

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

    SciTech Connect

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

    1992-01-01

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

  18. RESERVOIR HETEROGENEITY IN THE CAMBRIAN MOUNT SIMON SANDSTONE: IMPLICATIONS FOR CO2 SEQUESTRATION

    NASA Astrophysics Data System (ADS)

    Wilkens, N. D.; Bowen, B.; Fischietto, N.; Ochoa, R.; Soong, Y.; Rupp, J.

    2009-12-01

    The Cambrian Mount Simon Sandstone is a deep saline aquifer that is a primary reservoir target for large scale carbon dioxide injection tests due to its proximity to CO2 sources, permeability, porosity, and the overlying Eau Claire Formation as a seal. While the Mount Simon Sandstone has ideal reservoir characteristics in some areas, there are extreme variations in porosity and permeability that cannot be explained by burial related compaction alone. It is critical to understand the behavior of previous diagenetic fluids, prior to injection, as they have formed the authigenic minerals that line pore spaces and will be in contact with the CO2 saturated fluids and may serve as predictors of future injected fluid behavior. This study focuses on the diagenetic history of the Mount Simon Sandstone, utilizing evidence of diagenetic fluid movement as well as experiments performed to assess mineralization and dissolution associated with carbon dioxide injection. This ongoing research uses a combination of techniques to provide a clearer picture of the diagenetic history and potential results of injection. These analyses range in scale from basin-wide down to nanometers, to explore both depth variations within wells to individual grain coatings deposited by diagenetic fluids. Techniques include gamma and neutron log interpretation, VNIR spectroscopy of well cuttings, detailed petrographic studies, X-Ray Diffraction, Fluid Inclusion Analysis, Cathodeluminescence studies, and SEM/EDX analysis. Previous studies of diagenetic minerals have shown a dichotomy between P/T conditions modeled and those found within fluid inclusions, suggesting a source of deeper diagenetic fluids had altered the Mount Simon Sandstone. Our approach expands on these earlier studies both in scale and methods, to discern both regional scale and microscale evidence of diagenetic fluids. To assess the impact of injected CO2, through collaboration with Indiana Geological Survey and the National Energy

  19. Laboratory study of fluid viscosity induced ultrasonic velocity dispersion in reservoir sandstones

    NASA Astrophysics Data System (ADS)

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

    2010-06-01

    Ultrasonic velocities of a set of saturated sandstone samples were measured at simulated in-situ pressures in the laboratory. The samples were obtained from the W formation of the WXS Depression and covered low to nearly high porosity and permeability ranges. The brine and four different density oils were used as pore fluids, which provided a good chance to investigate fluid viscosity-induced velocity dispersion. The analysis of experimental observations of velocity dispersion indicates that (1) the Biot model can explain most of the small discrepancy (about 2-3%) between ultrasonic measurements and zero frequency Gassmann predictions for high porosity and permeability samples saturated by all the fluids used in this experiment and is also valid for medium porosity and permeability samples saturated with low viscosity fluids (less than approximately 3 mP·S) and (2) the squirt flow mechanism dominates the low to medium porosity and permeability samples when fluid viscosity increases and produces large velocity dispersions as high as about 8%. The microfracture aspect ratios were also estimated for the reservoir sandstones and applied to calculate the characteristic frequency of the squirt flow model, above which the Gassmann’ s assumptions are violated and the measured high frequency velocities cannot be directly used for Gassmann’s fluid replacement at the exploration seismic frequency band for W formation sandstones.

  20. Diagenetic characteristics and reservoir quality of the Lower Cretaceous Biyadh sandstones at Kharir oilfield in the western central Masila Basin, Yemen

    NASA Astrophysics Data System (ADS)

    Hakimi, Mohammed Hail; Shalaby, Mohamed Ragab; Abdullah, Wan Hasiah

    2012-06-01

    The Lower Cretaceous Biyadh Formation in the Masila Basin is an important hydrocarbon reservoir. However, in spite of its importance as a reservoir, published studies on the Biyadh Formation more specifically on the diagenesis and relate with reservoir quality, are limited. Based on core samples from one well in the Kharir oilfield, western central Masila Basin, this study reports the lithologic and diagenetic characteristics of this reservoir. The Biyadh sandstones are very fine to very coarse-grained, moderate to well sorted quartzarenite and quartzwacke. The diagenetic processes recognized include mechanical compaction, cementation (carbonate, clay minerals, quartz overgrowths, and a minor amount of pyrite), and dissolution of the calcite cement and feldspar grains. The widespread occurrences of early calcite cement suggest that the Biyadh sandstones lost a significant amount of primary porosity at a very early stage of its diagenetic history. Based on the framework grain-cement relationships, precipitation of the early calcite cement was either accompanied or followed by the development of part of the pore-lining and pore-filling clay cements. Secondary porosity development occurred due to partial to complete dissolution of early calcite cement and feldspar grains. In addition to calcite, several different clay minerals including kaolinite and chlorite occur as pore-filling and pore-lining cements. Kaolinite largely occurs as vermiform and accelerated the minor porosity loss due to pore-occlusion. Chlorite coating grains helps to retain primary porosity a by retarding the envelopment of quartz overgrowths. Porosity and permeability data exhibit good inverse correlation with cement. Thus, reservoir quality is controlled by pore occluding cement. Diagenetic history of the Biyadh sandstones as established here is expected to help better understanding and exploitation of this reservoir. The relation between diagenesis and reservoir quality is as follows: the

  1. An improved technique for modeling initial reservoir hydrocarbon saturation distributions: Applications in Illinois (USA) aux vases oil reservoirs

    USGS Publications Warehouse

    Udegbunam, E.; Amaefule, J.O.

    1998-01-01

    An improved technique for modeling the initial reservoir hydrocarbon saturation distributions is presented. In contrast to the Leverett J-function approach, this methodology (hereby termed flow-unit-derived initial oil saturation or FUSOI) determines the distributions of the initial oil saturations from a measure of the mean hydraulic radius, referred to as the flow zone indicator (FZI). FZI is derived from porosity and permeability data. In the FUSOI approach, capillary pressure parameters, S(wir), P(d), and ??, derived from the Brooks and Corey (1966) model [Brooks, R.H., Corey, A.T., 1966. Hydraulic properties of porous media, Hydrology Papers, Colorado State Univ., Ft. Collins, No. 3, March.], are correlated to the FZI. Subsequent applications of these parameters then permit the computation of improved hydrocarbon saturations as functions of FZI and height above the free water level (FWL). This technique has been successfully applied in the Mississippian Aux Vases Sandstone reservoirs of the Illinois Basin (USA). The Aux Vases Zeigler field (Franklin County, IL, USA) was selected for a field-wide validation of this FUSOI approach because of the availability of published studies. With the initial oil saturations determined on a depth-by-depth basis in cored wells, it was possible to geostatistically determine the three-dimensional (3-D) distributions of initial oil saturations in the Zeigler field. The original oil-in-place (OOIP), computed from the detailed initialization of the 3-D reservoir simulation model of the Zeigler field, was found to be within 5.6% of the result from a rigorous material balance method.An improved technique for modeling the initial reservoir hydrocarbon saturation distributions is presented. In contrast to the Leverett J-function approach, this methodology (hereby termed flow-unit-derived initial oil saturation or FUSOI) determines the distributions of the initial oil saturations from a measure of the mean hydraulic radius, referred to

  2. Study on fine geological modelling of the fluvial sandstone reservoir in Daqing oilfield

    SciTech Connect

    Zhoa Han-Qing

    1997-08-01

    These paper aims at developing a method for fine reservoir description in maturing oilfields by using close spaced well logging data. The main productive reservoirs in Daqing oilfield is a set of large fluvial-deltaic deposits in the Songliao Lake Basin, characterized by multi-layers and serious heterogeneities. Various fluvial channel sandstone reservoirs cover a fairly important proportion of reserves. After a long period of water flooding, most of them have turned into high water cut layers, but there are considerable residual reserves within them, which are difficult to find and tap. Making fine reservoir description and developing sound a geological model is essential for tapping residual oil and enhancing oil recovery. The principal reason for relative lower precision of predicting model developed by using geostatistics is incomplete recognition of complex distribution of fluvial reservoirs and their internal architecture`s. Tasking advantage of limited outcrop data from other regions (suppose no outcrop data available in oilfield) can only provide the knowledge of subtle changing of reservoir parameters and internal architecture. For the specific geometry distribution and internal architecture of subsurface reservoirs (such as in produced regions) can be gained only from continuous infilling logging well data available from studied areas. For developing a geological model, we think the first important thing is to characterize sandbodies geometries and their general architecture`s, which are the framework of models, and then the slight changing of interwell parameters and internal architecture`s, which are the contents and cells of the model. An excellent model should possess both of them, but the geometry is the key to model, because it controls the contents and cells distribution within a model.

  3. Geometric and sedimentologic characteristic of Mid-Miocene lowstand reservoir sandstones, offshore northwest Java, Indonesia

    SciTech Connect

    Lowry, P.; Kusumanegara, Y.; Warman, S.

    1996-12-31

    Numerous reservoirs in the Upper Cibulakan Formation (Mid-Miocene) of the Offshore Northwest Java shelf occur in sharp-based sandbodies that range from less than 1 m up to 10 m in thickness. Well-log derived net-sand isopach and seismic amplitude maps of these sandbodies depict elongate features, that are 1-2 km wide and 5-8 km long. The orientation of the longest axis of these sandbodies is predominantly north-south. Conventional cores reveal that these sandbodies are burrowed to completely bioturbated sandstones. Common trace fossils associated with these sandbodies include Ophiomorpha, Teichichnus and Thalassinoides. The lower contact of these sands is typically sharp and is commonly associated with a Glossifungites surface and siderite mud clasts. Overlying and underlying mudstones are relatively devoid of burrowing. Benthonic foraminifera assemblages within these mudstones indicate inner to outer neritic conditions in a relatively restricted marine setting. The upper contact of these sandstones is gradational over a 0.5 to 1m interval. Sandbodies of the same age and similar facies were observed in outcrops in onshore west Java. Here, they can be observed to pinch out over a distance of 500 m. The lower bounding contact appears discordant with underlying interbedded sandstones and mudstones. Several of the sandstones contain abundant accumulations of the large, open marine, benthonic foraminifera Cycloclypeus and Lepidocyclina. Occasionally the concentration of these large foraminifera form limestones within the sharp-based sandbodies. These bioclastic deposits commonly exhibit planar-tabular and trough cross-stratification. The sandbodies are interpreted as having been emplaced during relative falls in sea-level within a large Mid-Miocene embayment. Our understanding of their geometry and sedimentologic characteristics is leading to a more effective exploitation strategy for these sandbodies in the Offshore Northwest Java area.

  4. New exploration targets in Malaysia: Deep sandstone reservoirs in Malay basin and turbidites in Sabah basin

    SciTech Connect

    Ngah, K.B. )

    1996-01-01

    Much of the production in Malaysia is from middle to upper Miocene sandstones and carbonates in three main basins: Malay, Sarawak (Its three subbasins-Central Luconia, Balingian and Baram), and Sabah. Fifteen fields produce an average of 630,000 bopd and 3.0 bcfgpd. More than 4.0 billion barrels of oil and 20 tcf of gas have been produced, and reserves are 4.2 billion barrels of oil and 90 tcf. Oil production will decline within the next 1 0 years unless new discoveries are made and/or improved oil recovery methods introduced, but gas production of 5 tcf, expected after the turn of the century, can be sustained for several decades. Successful exploratory wells continue to be drilled in the Malaysian Tertiary basins, and others are anticipated with application of new ideas and technology. In the Malay basin, Miocene sandstone reservoirs in Groups L and M have been considered as very [open quote]high risk[close quotes] targets, the quality of the reservoirs has generally been thought to be poor, especially toward the basinal center, where they occur at greater depth. The cause of porosity loss is primarily burial-related. Because of this factor and overpressuring, drilling of many exploration wells has been suspended at or near the top of Group L. In a recent prospect drilled near the basinal axis on the basis of advanced seismic technology, Groups L and M sandstones show fair porosity (8-15%) and contain gas. In the Sabah basin, turbidite play has received little attention, partly because of generally poor seismic resolution in a very complex structural setting. Only one field is known to produce oil from middle Miocene turbidities. However, using recently acquired 3-D seismic data over this field, new oil pools have been discovered, and they are currently being developed. These finds have created new interest, as has Shell's recent major gas discovery from a turbidite play in this basin.

  5. New exploration targets in Malaysia: Deep sandstone reservoirs in Malay basin and turbidites in Sabah basin

    SciTech Connect

    Ngah, K.B.

    1996-12-31

    Much of the production in Malaysia is from middle to upper Miocene sandstones and carbonates in three main basins: Malay, Sarawak (Its three subbasins-Central Luconia, Balingian and Baram), and Sabah. Fifteen fields produce an average of 630,000 bopd and 3.0 bcfgpd. More than 4.0 billion barrels of oil and 20 tcf of gas have been produced, and reserves are 4.2 billion barrels of oil and 90 tcf. Oil production will decline within the next 1 0 years unless new discoveries are made and/or improved oil recovery methods introduced, but gas production of 5 tcf, expected after the turn of the century, can be sustained for several decades. Successful exploratory wells continue to be drilled in the Malaysian Tertiary basins, and others are anticipated with application of new ideas and technology. In the Malay basin, Miocene sandstone reservoirs in Groups L and M have been considered as very {open_quote}high risk{close_quotes} targets, the quality of the reservoirs has generally been thought to be poor, especially toward the basinal center, where they occur at greater depth. The cause of porosity loss is primarily burial-related. Because of this factor and overpressuring, drilling of many exploration wells has been suspended at or near the top of Group L. In a recent prospect drilled near the basinal axis on the basis of advanced seismic technology, Groups L and M sandstones show fair porosity (8-15%) and contain gas. In the Sabah basin, turbidite play has received little attention, partly because of generally poor seismic resolution in a very complex structural setting. Only one field is known to produce oil from middle Miocene turbidities. However, using recently acquired 3-D seismic data over this field, new oil pools have been discovered, and they are currently being developed. These finds have created new interest, as has Shell`s recent major gas discovery from a turbidite play in this basin.

  6. Geology and Petrophysical Characterization of the Ferron Sandstone for 3-D Simulation of a Fluvial-Deltaic Reservoir

    SciTech Connect

    Ann Mattson; Craig B. Forster; Paul B. Anderson; Steve H. Snelgrove; Thomas C. Chidsey, Jr.

    1997-05-20

    The objective of this project is to develop a comprehensive, interdisciplinary, and quantitative characterization of a fluvial-deltaic reservoir which will allow realistic inter-well and reservoir-scale modeling to be constructed for improved oil-field development in similar reservoirs world-wide. The geological and petrophysical properties of the Cretaceous Ferron Sandstone in east-central Utah will be quantitatively determined. Both new and existing data will be integrated into a three-dimensional representation of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for inter-well to regional-scale reservoir simulation. Four activities continued this quarter as part of the geological and petrophysical characterization of the fluvial-deltaic Ferron Sandstone in the Ivie Creek case-study area: (1) regional stratigraphic interpretation, (2) case-study evaluation, (3) reservoir modeling, and (4) technology transfer.

  7. Continuity and internal properties of Gulf Coast sandstones and their implications for geopressured energy development. Annual report, November 1, 1980-October 31, 1981

    SciTech Connect

    Morton, R.A.; Ewing, T.E.; Tyler, N.

    1982-06-01

    Systematic investigation, classification, and differentiation of the intrinsic properties of genetic sandstone units that typify many geopressured geothermal aquifers and hydrocarbon reservoirs of the Gulf Coast region are provided. The following are included: structural and stratigraphic limits of sandstone reservoirs; characteristics and dimensions of Gulf Coast Sandstones; fault compartment areas; comparison of production and geologic estimates of aquifer volume; geologic setting and reservoir characteristics, wells of opportunity; internal properties of sandstones and implications for geopressured energy development. (MHR)

  8. Impact of depositional facies on the distribution of diagenetic alterations in the Devonian shoreface sandstone reservoirs, Southern Ghadamis Basin, Libya

    NASA Astrophysics Data System (ADS)

    Khalifa, Muftah Ahmid; Morad, Sadoon

    2015-11-01

    The middle Devonian, shoreface quartz arenites (present-day burial depths 2833-2786 m) are important oil and gas reservoirs in the Ghadamis Basin, western Libya. This integrated petrographic and geochemical study aims to unravel the impact of depositional facies on distribution of diagenetic alterations and, consequently, related reservoir quality and heterogeneity of the sandstones. Eogenetic alterations include the formation of kaolinite, pseudomatrix, and pyrite. The mesogenetic alterations include cementation by quartz overgrowths, Fe-dolomite/ankerite, and illite, transformation of kaolinite to dickite, illitization of smectite, intergranular quartz dissolution, and stylolitization, and albitization of feldspar. The higher energy of deposition of the coarser-grained upper shoreface sandstones combined with less extensive chemical compaction and smaller amounts of quartz overgrowths account for their better primary reservoir quality compared to the finer-grained, middle-lower shoreface sandstones. The formation of kaolin in the upper and middle shoreface sandstones is attributed to a greater flux of meteoric water. More abundant quartz overgrowths in the middle and lower shoreface is attributed to a greater extent of stylolitization, which was promoted by more abundant illitic clays. This study demonstrated that linking the distribution of diagenetic alterations to depositional facies of shoreface sandstones leads to a better understanding of the impact of these alterations on the spatial and temporal variation in quality and heterogeneity of the reservoirs.

  9. Active geophysical monitoring of hydrocarbon reservoirs using EM methods

    NASA Astrophysics Data System (ADS)

    Gribenko, A.; Black, N.; Zhdanov, M. S.

    2008-12-01

    Marine controlled-source electromagnetic (MCSEM) technology has been successfully established as an effective tool for offshore hydrocarbon (HC) exploration. In this paper we consider another application of the MCSEM method for HC reservoir monitoring. We demonstrate that EM methods can be successfully used for the monitoring of producing wells in connection with the enhanced recovery of hydrocarbons. We have developed a new powerful EM modeling technique based on the integral equation method with an inhomogeneous background conductivity (IE IBC). This new method and the corresponding computer software make it possible to model the EM response over a realistic complex model of a sea-bottom HC reservoir. The numerical modeling results demonstrate that the MCSEM method has the ability to map changes in resistivity caused by the production of hydrocarbons over time. In addition, the EM data help to visualize the changes in the location of the oil-water contact within the reservoir. This result opens the possibility for practical application of the EM method in HC reservoir monitoring.

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

    SciTech Connect

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

    1980-07-01

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

  11. Petrology and reservoir paragenesis in the Sussex 'B' sandstone of the upper Cretaceous Cody Shale, House Creek and Porcupine Fields, Powder River Basin, Wyoming

    SciTech Connect

    Higley, D.K.

    1991-05-03

    Using petrologic and sedimentologic studies, the paper characterizes the influence of sedimentologic and petrologic variations on reservoir heterogeneity in the Sussex 'B' sandstone in the House Creek and Porcupine fields, Powder River Basin, Wyoming. Effects of authigenic minerals on reservoir properties are described in detail for selected inter-ridge and ridge facies sandstones.

  12. Petrophysical properties and 3D block model of Buntsandstein Sandstones reservoir (Upper Rhine Graben)

    NASA Astrophysics Data System (ADS)

    Sébastien, Haffen; Yves, Géraud; Marc, Diraison; Chrystel, Dezayes

    2013-04-01

    Buntsandstein sandstones (upper Permian to middle Triassic), located in the Upper Rhine Graben, appear as an easy target for geothermal exploitation: this reservoir links more or less permeable argillaceous sandstones, intersected by many major faults, to the regional thermal anomaly. In this context, we propose a conceptual geological 3-D block model of the Buntsandstein reservoir which could be used as a guide for future regional geothermal exploration or exploitation. This block presents the Buntsandstein sandstones reservoir at depth with different sedimentary facies (braided rivers, playa lake and fluvio-aeolian), above the Palaeozoic Granit and below the Muschelkalk limestones, intersecting by faults oriented according regional major azimuths: (1) ≈N020°E, corresponding to Rhenish faults and (2) ≈N060°E (or ≈N130°E) corresponding to Hercynian reactivated faults. Petrophysical properties of the reservoir are both controlled by matrix and faults/fractures characteristics. (1) Matrix properties (porosity, permeability, thermal conductivity, Pwaves velocity) have been determined from petrophysical measurements performed on cores of 15 borehole, mainly on borehole EPS1 (Soultz-sous-Forêts, France), continuously cored through Buntsandstein; (2) from thermal gradient analyses based on thermal conductivity measurements on core samples and also from borehole temperature logs run in the same borehole. This last approach allows locating fluid flow and thus permeability at reservoir scale. The flow paths appear as a composite network controlled by 'sedimentary' permeability on one hand and by 'fracture' permeability on the other. Fracturing associated with major fault zones provide pathways for the upward flowing fluids to connect with stratigraphic levels characterized by high matrix permeability and no impermeable macroscopic layers. This is why the Playa Lake and Fluvio-aeolian marginal erg facies provide a reservoir connected to a deep hot fluid source

  13. Numerical modeling of temperature and species distributions in hydrocarbon reservoirs

    NASA Astrophysics Data System (ADS)

    Bolton, Edward W.; Firoozabadi, Abbas

    2014-01-01

    We examine bulk fluid motion and diffusion of multicomponent hydrocarbon species in porous media in the context of nonequilibrium thermodynamics, with particular focus on the phenomenology induced by horizontal thermal gradients at the upper and lower horizontal boundaries. The problem is formulated with respect to the barycentric (mass-averaged) frame of reference. Thermally induced convection, with fully time-dependent temperature distributions, can lead to nearly constant hydrocarbon composition, with minor unmixing due to thermal gradients near the horizontal boundaries. Alternately, the composition can be vertically segregated due to gravitational effects. Independent and essentially steady solutions have been found to depend on how the compositions are initialized in space and may have implications for reservoir history. We also examine injection (to represent filling) and extraction (to represent leakage) of hydrocarbons at independent points and find a large distortion of the gas-oil contact for low permeability.

  14. Reservoir Characterization and Tectonic Settings of Ahwaz Sandstone Member of the Asmari Formation in the Zagros Mountain, SW of Iran

    NASA Astrophysics Data System (ADS)

    Adabi, M. H.; Sadeghi, A. D.; Hosseini, M.; Moalemi, A.; Lotfpour, A.; Khatibi Mehr, M.; Salehi, M.; Zohdi, A.; Jafarzadeh, M.

    2009-04-01

    The Ahwaz Sandstone Member of the Asmari Formation, the major oil reservoir in Zagros mountain, have been studied to understand the distribution, provenance, tectonic setting and reservoir characteristic of Ahwaz Sandstone intervals as an exploration target. This study was based on petrographic and geochemical analysis of 16 core samples from 13 oilfields in the Dezful Embayment zone, and 2 surface sections (Katula and Khami) in Izeh zone. Petrographic studies of 400 thin sections and geochemical analysis indicated that sandstones consist of quartzarenite (Khami surface section), sublitharenite ( Katula surface section) and subarkose (subsurface sections). The modal analysis of medium size and well sorted samples show a recycled orogen (Katula outcrop) and craton (Khami and subsurface sections) tectonic setting. The parent rocks for Ahwaz Sandstone, based on petrographic point counting suggest a low to medium grade metamorphic and plutonic source. Petrographic and grain size analysis indicate a shallow shoreline to barrier bar environments. Heavy minerals in sandstones have mostly plutonic source and abundance of stable heavy mineral, along with well rounded and high sphericity, support stable cratonic source for subsurface sections and Khami surface section. However, in Katula section, heavy minerals have metamorphic source. Facies map illustrated that siliciclastic sediments in Asmari Formation during Rupelian time comes from south-west and north west of the study area. During Chattian, sand distribution reaches to the maximum level and sediments arrived from south-west, north-west and also north-east of the study area. In Aquitanian, sandstones sourced from two areas of south-west and north-west. In Burdigalian stage, sandstone sourced only from south and south-west. These sandstones have limited distributions. Tectonic settings based on geochemical analysis, plotted on discrimination diagrams, suggest that passive continental margin. These sandstones were

  15. Seismic Evaluation of Hydrocarbon Saturation in Deep-Water Reservoirs

    SciTech Connect

    Michael Batzle

    2006-04-30

    During this last period of the ''Seismic Evaluation of Hydrocarbon Saturation in Deep-Water Reservoirs'' project (Grant/Cooperative Agreement DE-FC26-02NT15342), we finalized integration of rock physics, well log analysis, seismic processing, and forward modeling techniques. Most of the last quarter was spent combining the results from the principal investigators and come to some final conclusions about the project. Also much of the effort was directed towards technology transfer through the Direct Hydrocarbon Indicators mini-symposium at UH and through publications. As a result we have: (1) Tested a new method to directly invert reservoir properties, water saturation, Sw, and porosity from seismic AVO attributes; (2) Constrained the seismic response based on fluid and rock property correlations; (3) Reprocessed seismic data from Ursa field; (4) Compared thin layer property distributions and averaging on AVO response; (5) Related pressures and sorting effects on porosity and their influence on DHI's; (6) Examined and compared gas saturation effects for deep and shallow reservoirs; (7) Performed forward modeling using geobodies from deepwater outcrops; (8) Documented velocities for deepwater sediments; (9) Continued incorporating outcrop descriptive models in seismic forward models; (10) Held an open DHI symposium to present the final results of the project; (11) Relations between Sw, porosity, and AVO attributes; (12) Models of Complex, Layered Reservoirs; and (14) Technology transfer Several factors can contribute to limit our ability to extract accurate hydrocarbon saturations in deep water environments. Rock and fluid properties are one factor, since, for example, hydrocarbon properties will be considerably different with great depths (high pressure) when compared to shallow properties. Significant over pressure, on the other hand will make the rocks behave as if they were shallower. In addition to the physical properties, the scale and tuning will alter our

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

    NASA Astrophysics Data System (ADS)

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

    2012-02-01

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

  17. Secondary natural gas recovery in mature fluvial sandstone reservoirs, Frio Formation, Agua Dulce Field, South Texas

    SciTech Connect

    Ambrose, W.A.; Levey, R.A. ); Vidal, J.M. ); Sippel, M.A. ); Ballard, J.R. ); Coover, D.M. Jr. ); Bloxsom, W.E. )

    1993-09-01

    An approach that integrates detailed geologic, engineering, and petrophysical analyses combined with improved well-log analytical techniques can be used by independent oil and gas companies of successful infield exploration in mature Gulf Coast fields that larger companies may consider uneconomic. In a secondary gas recovery project conducted by the Bureau of Economic Geology and funded by the Gas Research Institute and the U.S. Department of Energy, a potential incremental natural gas resource of 7.7 bcf, of which 4.0 bcf may be technically recoverable, was identified in a 490-ac lease in Agua Dulce field. Five wells in this lease had previously produced 13.7 bcf from Frio reservoirs at depths of 4600-6200 ft. The pay zones occur in heterogeneous fluvial sandstones offset by faults associated with the Vicksburg fault zone. The compartments may each contain up to 1.0 bcf of gas resources with estimates based on previous completions and the recent infield drilling experience of Pintas Creek Oil Company. Uncontacted gas resources occur in thin (typically less than 10 ft) bypassed zones that can be identified through a computed log evaluation that integrates open-hole logs, wireline pressure tests, fluid samples, and cores. At Agua Dulce field, such analysis identified at 4-ft bypassed zone uphole from previously produced reservoirs. This reservoir contained original reservoir pressure and flowed at rates exceeding 1 mmcf/d. The expected ultimate recovery is 0.4 bcf. Methodologies developed in the evaluation of Agua Dulce field can be successfully applied to other mature gas fields in the south Texas Gulf Coast. For example, Stratton and McFaddin are two fields in which the secondary gas recovery project has demonstrated the existence of thin, potentially bypassed zones that can yield significant incremental gas resources, extending the economic life of these fields.

  18. The impact of reservoir conditions on the residual trapping of carbon dioxide in Berea sandstone

    NASA Astrophysics Data System (ADS)

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

    2015-04-01

    The storage of carbon dioxide in deep brine-filled permeable rocks is an important tool for CO2 emissions mitigation on industrial scales. Residual trapping of CO2 through capillary forces within the pore space of the reservoir is one of the most significant mechanisms for storage security and is also a factor determining the ultimate extent of CO2 migration within the reservoir. In this study we have evaluated the impact of reservoir conditions of pressure, temperature, and brine salinity on the residual trapping characteristic curve of a fired Berea sandstone rock. The observations demonstrate that the initial-residual characteristic trapping curve is invariant across a wide range of pressure, temperature, and brine salinities and is also the same for CO2-brine systems as a N2-water system. The observations were made using a reservoir condition core-flooding laboratory that included high-precision pumps, temperature control, the ability to recirculate fluids for weeks at a time, and an X-ray CT scanner. Experimental conditions covered pressures of 5-20 MPa, temperatures of 25-50°C, and 0-5 mol/kg NaCl brine salinity. A novel coreflooding approach was developed, making use of the capillary end effect to create a large range in initial CO2 saturation (0.15-0.6) in a single coreflood. Upon subsequent flooding with CO2-equilibriated brine, the observation of residual saturation corresponded to the wide range of initial saturations before flooding resulting in a rapid construction of the initial-residual curve. For each condition we report the initial-residual curve and the resulting parameterization of the Land hysteresis models.

  19. Deformation microstructures and diagenesis in sandstone adjacent to an extensional fault: Implications for the flow and entrapment of hydrocarbons

    SciTech Connect

    Hippler, S.J. )

    1993-04-01

    Microstructural and diagenetic analyses of the North Scapa Sandstone in the hanging wall of the North Scapa fault, Orkney, Scotland, provide insight into the relationship between faulting and fluid flow during basin development. The results demonstrate the influence of this relationship on fault sealing processes and hydrocarbon migration. During development of the Orcadian basin in the Middle Devonian, the fault moved in an extensional sense. Dilatancy associated with cataclastic deformation caused localization of fluid flow and resulted in the precipitation of quartz and illite cement in the North Scapa Sandstone up to 1 m from the fault plane. This diagenetic event, coupled with cataclastic grain-size reduction, significantly reduced the porosity and permeability of the sandstone directly adjacent to the fault. These processes are effective sealing mechanisms within the sandstone. Lacustrine source rocks in the Orcadian basin reached maturation during the latest Devonian to middle Carboniferous. At the end of this time, the basin was uplifted, and the North Scapa fault was reactivated in a normal, but dominantly oblique-slip sense. This later deformation was accommodated directly outside the sealed zone and resulted in the development of broad (10-20 cm) breccia zones and narrow (<10 cm) cataclastic bands. Further dilatancy associated with the cataclastic deformation channelized hydrocarbon flow through the high-strain breccia zones and cataclastic bands. These observations indicate that fault activity that is broadly coincident with maturation and expulsion of hydrocarbons within a basin can directly influence the location of migration pathways. 81 refs., 14 figs., 1 tab.

  20. SEISMIC EVALUATION OF HYDROCARBON SATURATION IN DEEP-WATER RESERVOIRS

    SciTech Connect

    Michael Batzle; D-h Han; R. Gibson; Huw James

    2005-01-22

    During this last quarter of the ''Seismic Evaluation of Hydrocarbon Saturation in Deep-Water Reservoirs'' project (Grant/Cooperative Agreement DE-FC26-02NT15342), we have moved forward on several fronts, including data acquisition as well as analysis and application. During this quarter we have: (1) Completed our site selection (finally); (2) Measured fluid effects in Troika deep water sand sample; (3) Applied the result to Ursa ''fizz gas'' zone; (4) Compared thin layer property averaging on AVO response; (5) Developed target oriented NMO stretch correction; (6) Examined thin bed effects on A-B crossplots; and (7) Begun incorporating outcrop descriptive models in seismic forward models. Several factors can contribute to limit our ability to extract accurate hydrocarbon saturations in deep water environments. Rock and fluid properties are one factor, since, for example, hydrocarbon properties will be considerably different with great depths (high pressure) when compared to shallow properties. Significant over pressure, on the other hand will make the rocks behave as if they were shallower. In addition to the physical properties, the scale and tuning will alter our hydrocarbon indicators. Reservoirs composed of thin bed effects will broaden the reflection amplitude distribution with incident angle. Normal move out (NMO) stretch corrections based on frequency shifts can be applied to offset this effect. Tuning will also disturb the location of extracted amplitudes on AVO intercept and gradient (A-B) plots. Many deep water reservoirs fall this tuning thickness range. Our goal for the remaining project period is to systematically combine and document these various effects for use in deep water exploration.

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

    NASA Astrophysics Data System (ADS)

    Zaid, Samir M.

    2013-09-01

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

  2. Seismic Evaluation of Hydrocarbon Saturation in Deep-Water Reservoirs

    SciTech Connect

    Michael Batzle; D-h Han; R. Gibson; Huw James

    2006-01-30

    During this last quarter of the ''Seismic Evaluation of Hydrocarbon Saturation in Deep-Water Reservoirs'' project (Grant/Cooperative Agreement DE-FC26-02NT15342), our efforts have become focused on technology transfer. To this end, we completing our theoretical developments, generating recommended processing flows, and perfecting our rock and fluid properties interpretation techniques. Some minor additional data analysis and modeling will complete our case studies. During this quarter we have: Presented findings for the year at the DHI/FLUIDS meeting at UH in Houston; Presented and published eight papers to promote technology transfer; Shown how Rock and fluid properties are systematic and can be predicted; Shown Correct values must be used to properly calibrate deep-water seismic data; Quantified and examined the influence of deep water geometries in outcrop; Compared and evaluated hydrocarbon indicators for fluid sensitivity; Identified and documented inappropriate processing procedures; Developed inversion techniques to better distinguish hydrocarbons; Developed new processing work flows for frequency-dependent anomalies; and Evaluated and applied the effects of attenuation as an indicator. We have demonstrated that with careful calibration, direct hydrocarbon indicators can better distinguish between uneconomic ''Fizz'' gas and economic hydrocarbon reservoirs. Some of this progress comes from better characterization of fluid and rock properties. Other aspects include alternative techniques to invert surface seismic data for fluid types and saturations. We have also developed improved work flows for accurately measuring frequency dependent changes in seismic data that are predicted by seismic models, procedures that will help to more reliably identify anomalies associated with hydrocarbons. We have been prolific in publishing expanded abstracts and presenting results, particularly at the SEG. This year, we had eight such papers to promote technology transfer

  3. Frio sandstone reservoirs in the deep subsurface along the Texas Gulf Coast: their potential for production of geopressured geothermal energy

    SciTech Connect

    Bebout, D.G.; Loucks, R.G.; Gregory, A.R.

    1983-01-01

    Detailed geological, geophysical, and engineering studies conducted on the Frio Formation have delineated a geothermal test well site in the Austin Bayou Prospect which extends over an area of 60 square miles. A total of 800 to 900 feet of sandstone will occur between the depths of 13,500 and 16,500 feet. At leat 30 percent of the sand will have core permeabilities of 20 to 60 millidarcys. Temperature at the top of the sandstone section will be 300/sup 0/F. Water, produced at a rate of 20,000 to 40,000 barrels per day, will probably have to be disposed of by injection into shallower sandstone reservoirs. More than 10 billion barrels of water are in place in these sandstone reservoirs of the Austin Bayou Prospect; there should be approximately 400 billion cubic feet of methane in solution in this water. Only 10 percent of the water and methane (1 billion barrels of water and 40 billion cubic feet of methane) will be produced without reinjection of the waste water into the producing formation. Reservoir simulation studies indicate that 90 percent of the methane can be produced with reinjection. 106 figures.

  4. SEISMIC EVALUATION OF HYDROCARBON SATURATION IN DEEP-WATER RESERVOIRS

    SciTech Connect

    Michael Batzle; D-h Han; R. Gibson; Huw James

    2005-08-12

    We are now entering the final stages of our ''Seismic Evaluation of Hydrocarbon Saturation in Deep-Water Reservoirs'' project (Grant/Cooperative Agreement DE-FC26-02NT15342). We have now developed several techniques to help distinguish economic hydrocarbon deposits from false ''Fizz'' gas signatures. These methods include using the proper in situ rock and fluid properties, evaluating interference effects on data, and doing better constrained inversions for saturations. We are testing these techniques now on seismic data from several locations in the Gulf of Mexico. In addition, we are examining the use of seismic attenuation as indicated by frequency shifts below potential reservoirs. During this quarter we have: Began our evaluation of our latest data set over the Neptune Field; Developed software for computing composite reflection coefficients; Designed and implemented stochastic turbidite reservoir models; Produced software & work flow to improve frequency-dependent AVO analysis; Developed improved AVO analysis for data with low signal-to-noise ratio; and Examined feasibility of detecting fizz gas using frequency attenuation. Our focus on technology transfer continues, both by generating numerous presentations for the upcoming SEG annual meeting, and by beginning our planning for our next DHI minisymposium next spring.

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

    NASA Astrophysics Data System (ADS)

    Hangx, Suzanne; Spiers, Christopher

    2015-04-01

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

  6. Research on the methods of splitting and prediction point by point in tight sandstone gas reservoir productivity

    NASA Astrophysics Data System (ADS)

    Sheng-fu, Wen; Bao-zhi, Pan; Bi-ci, Jiang; Li-hua, Zhang; Dan, Liu; Wen-bin, Liu; Yu-hang, Guo

    2015-06-01

    Single-point productivity evaluation and prediction are of important significance for the exploration and development in a tight sandstone gas field. The method of production splitting, multiple linear regression (MLR), and support vector machine regression (SVR) was used to establish the relationship between logging data and the gas production split point-to-point in tight sandstone gas reservoirs. In this study, the western region of the Sulige area in the Ordos Basin was the object of our research. Compared with the traditional KH splitting, the KHK splitting method was better.

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

    NASA Astrophysics Data System (ADS)

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

    2015-11-01

    The Permocarboniferous siliciclastic formations represent the largest hydrothermal reservoir in the northern Upper Rhine Graben in SW Germany and have so far been investigated in large-scale studies only. The Cenozoic Upper Rhine Graben crosses the Permocarboniferous Saar-Nahe Basin, a Variscan intramontane molasse basin. Due to the subsidence in this graben structure, the top of the up to 2-km-thick Permocarboniferous is located at a depth of 600-2900 m and is overlain by Tertiary and Quaternary sediments. At this depth, the reservoir temperatures exceed 150 °C, which are sufficient for geothermal electricity generation with binary power plants. To further assess the potential of this geothermal reservoir, detailed information on thermophysical and hydraulic properties of the different lithostratigraphical units and their depositional environment is essential. Here, we present an integrated study of outcrop analogues and drill core material. In total, 850 outcrop samples were analyzed, measuring porosity, permeability, thermal conductivity and thermal diffusivity. Furthermore, 62 plugs were taken from drillings that encountered or intersected the Permocarboniferous at depths between 1800 and 2900 m. Petrographic analysis of 155 thin sections of outcrop samples and samples taken from reservoir depth was conducted to quantify the mineral composition, sorting and rounding of grains and the kind of cementation. Its influence on porosity, permeability, the degree of compaction and illitization was quantified. Three parameters influencing the reservoir properties of the Permocarboniferous were detected. The strongest and most destructive influence on reservoir quality is related to late diagenetic processes. An illitic and kaolinitic cementation and impregnation of bitumina document CO2- and CH4-rich acidic pore water conditions, which are interpreted as fluids that migrated along a hydraulic contact from an underlying Carboniferous hydrocarbon source rock. Migrating

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

    NASA Astrophysics Data System (ADS)

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

    2016-07-01

    The Permocarboniferous siliciclastic formations represent the largest hydrothermal reservoir in the northern Upper Rhine Graben in SW Germany and have so far been investigated in large-scale studies only. The Cenozoic Upper Rhine Graben crosses the Permocarboniferous Saar-Nahe Basin, a Variscan intramontane molasse basin. Due to the subsidence in this graben structure, the top of the up to 2-km-thick Permocarboniferous is located at a depth of 600-2900 m and is overlain by Tertiary and Quaternary sediments. At this depth, the reservoir temperatures exceed 150 °C, which are sufficient for geothermal electricity generation with binary power plants. To further assess the potential of this geothermal reservoir, detailed information on thermophysical and hydraulic properties of the different lithostratigraphical units and their depositional environment is essential. Here, we present an integrated study of outcrop analogues and drill core material. In total, 850 outcrop samples were analyzed, measuring porosity, permeability, thermal conductivity and thermal diffusivity. Furthermore, 62 plugs were taken from drillings that encountered or intersected the Permocarboniferous at depths between 1800 and 2900 m. Petrographic analysis of 155 thin sections of outcrop samples and samples taken from reservoir depth was conducted to quantify the mineral composition, sorting and rounding of grains and the kind of cementation. Its influence on porosity, permeability, the degree of compaction and illitization was quantified. Three parameters influencing the reservoir properties of the Permocarboniferous were detected. The strongest and most destructive influence on reservoir quality is related to late diagenetic processes. An illitic and kaolinitic cementation and impregnation of bitumina document CO2- and CH4-rich acidic pore water conditions, which are interpreted as fluids that migrated along a hydraulic contact from an underlying Carboniferous hydrocarbon source rock. Migrating

  9. Noble gas and hydrocarbon tracers in multiphase unconventional hydrocarbon systems: Toward integrated advanced reservoir simulators

    NASA Astrophysics Data System (ADS)

    Darrah, T.; Moortgat, J.; Poreda, R. J.; Muehlenbachs, K.; Whyte, C. J.

    2015-12-01

    Although hydrocarbon production from unconventional energy resources has increased dramatically in the last decade, total unconventional oil and gas recovery from black shales is still less than 25% and 9% of the totals in place, respectively. Further, the majority of increased hydrocarbon production results from increasing the lengths of laterals, the number of hydraulic fracturing stages, and the volume of consumptive water usage. These strategies all reduce the economic efficiency of hydrocarbon extraction. The poor recovery statistics result from an insufficient understanding of some of the key physical processes in complex, organic-rich, low porosity formations (e.g., phase behavior, fluid-rock interactions, and flow mechanisms at nano-scale confinement and the role of natural fractures and faults as conduits for flow). Noble gases and other hydrocarbon tracers are capably of recording subsurface fluid-rock interactions on a variety of geological scales (micro-, meso-, to macro-scale) and provide analogs for the movement of hydrocarbons in the subsurface. As such geochemical data enrich the input for the numerical modeling of multi-phase (e.g., oil, gas, and brine) fluid flow in highly heterogeneous, low permeability formations Herein we will present a combination of noble gas (He, Ne, Ar, Kr, and Xe abundances and isotope ratios) and molecular and isotopic hydrocarbon data from a geographically and geologically diverse set of unconventional hydrocarbon reservoirs in North America. Specifically, we will include data from the Marcellus, Utica, Barnett, Eagle Ford, formations and the Illinois basin. Our presentation will include geochemical and geological interpretation and our perspective on the first steps toward building an advanced reservoir simulator for tracer transport in multicomponent multiphase compositional flow (presented separately, in Moortgat et al., 2015).

  10. 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.

  11. Advances in our knowledge of biodegradation of hydrocarbons in reservoirs

    SciTech Connect

    Connan, J. )

    1993-09-01

    Biodegradation of hydrocarbons in reservoirs is a widespread phenomenon that is currently observed by petroleum organic geochemists in most sedimentary basins. This basic phenomenon is responsible for the occurrence of large, heavy oil deposits referred to as tar mats or tar belts. Biodegradation of crude oils takes place in reservoirs in which oil-eating bacteria may thrive. For this reason, effective and present biodegradation effects are not observed at subsurface temperatures higher than 70-80[degrees]C. Significant compositional changes, especially at a molecular level, still remain linked to the aerobic biodegradation of crude oils. Under favorable circumstances, both alkanes and aromatics are degraded, but when nutrients (N, P, O[sup 2]) are impoverished, aromatics seem to be preferentially removed. Biodegradation extends also to sulfur-bearing aromatics with a preferential removal of alkylated structures. Changes in molecular patterns are used to assess degrees of biodegradation in crude oils. The most bacterially resistant structures are polycyclic alkanes and aromatics. The in-reservoir biodegradation of hydrocarbons does not generate new hydrocarbons, e.g., 25-norhopanes as proposed by several authors. In fact, the selective removal of less resistant structures concentrates preexisting minor families that were not detected on the unaltered crude due to their low absolute concentration. Consequently, the molecular spectrum found in severely biodegraded oils may be considered as highly diagnostic of a part of the primary genetic spectrum of each oil. In outcrop samples, biodegradation is associated with other complementary phenomena such as photooxidation, oxidation, inspissation, evaporation, water washing, etc. Of particular importance are weathering effects linked to oxidation, which entail drastic compositional changes, with neogenesis of resins, asphaltenes, and even insoluble residue.

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

    NASA Astrophysics Data System (ADS)

    Al-Menhali, Ali; Krevor, Samuel

    2014-05-01

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

  13. Evaluating Nitrogen Isotope Measurements in Unconventional Hydrocarbon Reservoirs

    NASA Astrophysics Data System (ADS)

    Quan, T. M.; Rivera, K.; Adigwe, E.; Riedinger, N.; Puckette, J.

    2014-12-01

    Nitrogen isotope (δ15N) measurements from core samples taken from unconventional hydrocarbon reservoirs may provide important information on depositional environment, reservoir characterization, and post-depositional processes. In order to evaluate the potential of nitrogen isotopes as geochemical proxies for resource evaluation, we measured δ15Nbulk values for six Woodford Shale (Late Devonian-Early Mississippian) cores and three Caney Shale (Early Mississippian) cores and compared the profiles with other geochemical, lithological, maturation, and well-log data. The strongest correlation is between δ15Nbulk and redox-sensitive trace metals and other redox proxies, as predicted by previous research into δ15Nbulk values. This indicates that δ15Nbulk can be used in unconventional reservoirs as a proxy for depositional redox conditions. Unlike other redox proxies, δ15Nbulk reflects the redox state of the deep-water column, rather than that of the deposited sediment, providing a representation of water column processes during deposition. The δ15Nbulk proxy also appears not to be overprinted by catagenic processes. Associations of δ15Nbulk with thermal maturity, gamma ray response, and catagenesis and diagenesis proxies were found to be minimal. The δ15Nbulk profiles do not appear to be overprinted during catagenesis and therefore are not a reliable record of post-depositional processes. Including nitrogen isotope analyses in a geochemical assessment can provide valuable information about the original redox state of the reservoir unit, and assist in characterizing depositional environment.

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

    NASA Astrophysics Data System (ADS)

    Liu, S.; Pan, B.

    2015-12-01

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

  15. Deformation bands evolving from dilation to cementation bands in a hydrocarbon reservoir (Vienna Basin, Austria)

    PubMed Central

    Exner, Ulrike; Kaiser, Jasmin; Gier, Susanne

    2013-01-01

    In this study we analyzed five core samples from a hydrocarbon reservoir, the Matzen Field in the Vienna Basin (Austria). Deformation bands occur as single bands or as strands of several bands. In contrast to most published examples of deformation bands in terrigeneous sandstones, the reduction of porosity is predominantly caused by the precipitation of Fe-rich dolomite cement within the bands, and only subordinately by cataclasis of detrital grains. The chemical composition of this dolomite cement (10–12 wt% FeO) differs from detrital dolomite grains in the host rock (<2 wt% FeO). This observation in combination with stable isotope data suggests that the cement is not derived from the detrital grains, but precipitated from a fluid from an external, non-meteoric source. After an initial increase of porosity by dilation, disaggregation and fragmentation of detrital grains, a Fe-rich carbonate fluid crystallized within the bands, thereby reducing the porosity relative to the host sediment. The retention of pyrite cement by these cementation bands as well as the different degree of oil staining on either side of the bands demonstrate that these cementation bands act as effective barriers to the migration of fluids and should be considered in reservoir models. PMID:26321782

  16. Mechanical and mineralogical modifications of petrophysical parameters by deformation bands in a hydrocarbon reservoir (Matzen, Austria)

    NASA Astrophysics Data System (ADS)

    Kaiser, Jasmin; Exner, Ulrike; Gier, Susanne; Hujer, Wolfgang

    2010-05-01

    In porous sedimentary rocks, fault zones are frequently accompanied by deformation bands. These structures are tabular zones of displacement, where grain rotation and in some cases grain fracturing result in a significant reduction in porosity. Core samples were analyzed close to large normal faults from the most productive hydrocarbon reservoir in the Vienna Basin (Austria), the Matzen oil field. The Badenian terrigeneous sandstones contain predominately quartz, feldspar and dolomite as sub-rounded, detrial grains and are weakly cemented by chlorite and kaolinite. Deformation bands occur as single bands of ca. 1-3 mm thickness and negligible displacement, as well as strands of several bands with up to 2 cm thickness and displacement of 1-2 cm. A dramatic porosity reduction can already be recognized macroscopically. In some samples, the corresponding reduction in permeability is highlighted by different degree of oil staining on either side of the bands. The mineralogical composition of the deformation bands compared to the host rock does not indicate any preferential cementation or diagenetic growth of clay minerals or calcite. Instead, clay minerals are slightly enriched in the host sediment. These observations suggest that the formation of deformation bands predates the cementation in the Matzen sands. Thus, we speculate that the porosity reduction is predominately caused by cataclastic grain size reduction. Identification of the grain scale processes of porosity and permeability reduction, in combination with the analysis of the spatial distribution and orientation of the deformation bands may provide valuable information on the reservoir properties and fluid migration paths.

  17. The stratigraphy of Oxfordian-Kimmeridgian (Late Jurassic) reservoir sandstones in the Witch Ground Graben, United Kingdom North Sea

    SciTech Connect

    Harker, S.D. ); Mantel, K.A. ); Morton, D.J. ); Riley, L.A. )

    1993-10-01

    Oil-bearing Upper Jurassic Oxfordian-Kimmeridgian sandstones of the Sgiath and Piper formations are of major economic importance in the Witch Ground Gaben, United Kingdom North Sea. They form the reservoirs in 14 fields that originally contained 2 billion bbl of oil reserves, including Scott Field, which in 1993 will be the largest producing United Kingdom North Sea oil field to come on stream in more than a decade. The Sgiath and Piper formations represent Late Jurassic transgressive and regressive phases that began with paralic deposition and culminated in a wave-dominated delta system. These phases preceded the major grabel rifting episode (late Kimmeridgian to early Ryazanian) and deposition of the Kimmeridge Clay Formation, the principal source rock of the Witch Ground Graben oil fields. A threefold subdivision of the middle to upper Oxfordian Sgiath Formation is formally proposed, with Scott field well 15/21a-15 as the designated reference well. The basal Skene Member consists of thinly interbedded paralic carbonaceous shales, coals, and sandstones. This is overlain by transgressive marine shales of the Saltire Member. The upper-most Oxfordian Scott Member consists of shallow marine sandstones that prograded to the southwest. The contact of the Sgiath and Piper formations is a basinwide transgressive marine shale (I shale), which can act as an effective barrier to fluid communication between the Sgiath and Piper reservoir sandstones.

  18. Effect of temperature on ultrasonic velocities of unconsolidated sandstones reservoirs during the SAGD recovery process

    NASA Astrophysics Data System (ADS)

    Doan, D.-H.; Nauroy, J.-F.; Delage, P.; Mainguy, M.

    2010-06-01

    The steam assisted gravity drainage (SAGD) is a thermal in-situ technology that has been successfully used to enhance the recovery of heavy oil and bitumen in the Western Canada and in the Eastern Venezuela basins. Pressure and temperature variations during SAGD operations induce complex changes in the mechanical and acoustic properties of the reservoir rocks as well as of the caprock. To study these changes, measurements of ultrasonic wave velocities Vp, Vs were performed on both reconstituted samples and natural samples from oil sands reservoir. Reconstituted samples were made of Fontainebleau sands with a slight cementation formed by a silicate solution. They have a high porosity (about 30 % to 40 %) and a high permeability (up to 10 D). Natural oil sands samples are unconsolidated sandstones extracted from the fluvio-estuarine McMurray Formation in Alberta (Canada). The saturating fluids were bitumen and glycerol with a strongly temperature dependent viscosity. The tests were carried out at different temperatures (in the range 40° and +86°C) and at different effective pressures (from 12 bars up to 120 bars). Experimental results firstly showed that the elastic wave propagation velocities measured are strongly dependent on temperature and pore fluid viscosity whereas little effect of effective pressure was observed. Velocities decreased with increasing temperature and increased with increasing effective pressure. These effects are mainly due to the variations of the saturating fluids properties. Finally, the tests were modelled by using Ciz and Shapiro (2007) approach and satisfactory velocities values were obtained with highly viscous fluids, a case that cannot be easily explained by using the poro-elastic theory of Biot-Gassmann.

  19. SATI algorithm — the calculation of stress aligned HTI stiffness tensor for sandstone reservoir from wireline data

    NASA Astrophysics Data System (ADS)

    Brajanovski, Miroslav

    2011-11-01

    I present an algorithm that uses cross-dipole wireline data only in order to estimate the HTI stiffness tensor for sandstone formations under in-situ asymmetric lateral (azimuthal) stress conditions. The algorithm is based on the generalization of terms "excess compliance" and "fracture weakness" developed within the linear slip interface theory for fractured rocks and is applied here to describe the effect of grain contacts in loose sandstones. I introduce the term "plane of weakness" being oriented (aligned) orthogonal to the minimal horizontal principal stress direction in order to describe the overall effective weakness of sandstone caused by the different principal stresses. For the quantification of this phenomenon I use the anisotropic Gassmann model. As a result I am able to calculate a HTI stiffness tensor for the interval length of a saturated sandstone formation and the respective Thomsen's parameters. The input data required for these calculations have to be provided by wireline logging and will consist of porosity, density, P-wave velocity, fast and slow shear wave velocities and oil-water saturation ratio. The algorithm in its current form is applicable to sandstone reservoirs only. Its limitation is based on two assumptions, which state that all the measured anisotropy is induced by the present stress in sandstone and that the unstressed sandstone would be nearly isotropic. From a technical viewpoint this algorithm can be implemented fairly easily in data acquisition and interpretation software relying on correct estimation of anisotropy parameters. It is also cheap because it does not require any additional measurements apart from the cross-dipole logging.

  20. Petrology and reservoir paragenesis in the Sussex B sandstone of the Upper Cretaceous Cody Shale, House Creek and Porcupine fields, Powder River basin, Wyoming

    SciTech Connect

    Not Available

    1992-01-01

    This book of reservoir paragenesis includes detailed descriptions of the petrology of depositional facies of the Sussex B sandstone of the Sussex Sandstone Member of the Upper Cretaceous Cody Shale in the House Creek and Porcupine fields, Powder River basin, Wyoming.

  1. Geological and Petrophysical Characterization of the Ferron Sandstone for 3-D Simulation of a Fluvial-Deltaic Reservoir.

    SciTech Connect

    Allison, M.L.

    1997-07-01

    The objective of this project is to develop a comprehensive, interdisciplinary, and quantitative characterization of a fluvial- deltaic reservoir which will allow realistic inter-well and reservoir-scale modeling to be constructed for improved oil-field development in similar reservoirs world-wide. The geological and petrophysical properties of the Cretaceous Ferron Sandstone in east-central Utah will be quantitatively determined. Both new and existing data will be integrated into a three-dimensional representation of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for inter-well to regional-scale reservoir simulation. Results could improve reservoir management through proper infill and extension drilling strategies, reduction of economic risks, increased recovery from existing oil fields, and more reliable reserve calculations. Transfer of the project results to the petroleum industry is an integral component of the project. Two activities continued this quarter as part of the geological and petrophysical characterization of the fluvial-deltaic Ferron Sandstone: (1) evaluation of the Ivie Creek case-study area and (2) technology transfer. The Ivie Creek case-study evaluation work during the quarter focused on the two parasequence sets, the Kf-1 and Kf-2, in the lower Ferron Sandstone. This work included: (1) clinoform characterization, (2) parasequence characterization from elevation and isopach maps, and (3) three-dimensional facies modeling. Scaled photomosaic panels from the Ivie Creek amphitheater (south-facing outcrop belt) and Quitchupah Canyon (Fig. 1) provide a deterministic framework for two apparent-dip cross sections. These panels along with other photomosaic coverage and data from five drill holes, ten stratigraphic sections, and 22 permeability transacts (Fig. 1), acquired during two field seasons, provided the necessary information for this geologic evaluation and creation of the models to be used

  2. 3-D solid modeling of sandstone reservoirs using NURBS: A case study of Noonen Ranch Field, Denver Basin, Colorado

    SciTech Connect

    Fisher, T.R. ); Wales, R.Q. )

    1990-02-01

    In this paper, the authors describe an experimental attempt to represent sandstone petroleum reservoirs as 3-D solids using Intergraphs object-oriented NURBS (non-uniform rational B-splines) based engineering modeling system. Initial data interpretation, well log correlation, map preparation and combination were done using GIPSE geological interpretation software. The modeling efforts were concentrated on Noonen Ranch, a small producing field in the Denver Basin of Colorado.

  3. SEISMIC EVALUATION OF HYDROCARBON SATURATION IN DEEP-WATER RESERVOIRS

    SciTech Connect

    M. Batzle; D-h Han; R. Gibson; O. Djordjevic

    2003-03-20

    The ''Seismic Evaluation of Hydrocarbon Saturation in Deep-Water Reservoirs'' (Grant/Cooperative Agreement DE-FC26-02NT15342) began September 1, 2002. During this second quarter: A Direct Hydrocarbon Indicator (DHI) symposium was held at UH; Current DHI methods were presented and forecasts made on future techniques; Dr. Han moved his laboratory from HARC to the University of Houston; Subcontracts were re-initiated with UH and TAMU; Theoretical and numerical modeling work began at TAMU; Geophysical Development Corp. agreed to provide petrophysical data; Negotiations were begun with Veritas GDC to obtain limited seismic data; Software licensing and training schedules were arranged with Paradigm; and Data selection and acquisition continues. The broad industry symposium on Direct Hydrocarbon Indicators was held at the University of Houston as part of this project. This meeting was well attended and well received. A large amount of information was presented, not only on application of the current state of the art, but also on expected future trends. Although acquisition of appropriate seismic data was expected to be a significant problem, progress has been made. A 3-D seismic data set from the shelf has been installed at Texas A&M University and analysis begun. Veritas GDC has expressed a willingness to provide data in the deep Gulf of Mexico. Data may also be available from TGS.

  4. Flow and transport effects of compaction bands in sandstone at scales relevant to aquifer and reservoir management

    NASA Astrophysics Data System (ADS)

    Sternlof, K. R.; Karimi-Fard, M.; Pollard, D. D.; Durlofsky, L. J.

    2006-07-01

    Thin, tabular, low-porosity, low-permeability compaction bands form pervasive, subparallel, anastomosing arrays that extend over square kilometers of exposure in the Aztec Sandstone of southeastern Nevada, an exhumed analog for active aquifers and reservoirs. In order to examine the potential flow and transport effects of these band arrays at scales relevant to production and management, we performed a suite of simulations using an innovative discrete-feature modeling technique to capture the exact pattern of compaction bands mapped over some 150,000 m2 of contiguous outcrop. Significant impacts related to the presence of the bands and their dominant trend are apparent: the average pressure drop required to drive flow between wells exceeds that for band-free sandstone by a factor of three and is 10% to 50% higher across the bands versus along them; reservoir production efficiency varies up to 56% for a typical five-spot well array, depending on its orientation relative to the dominant band trend; and contaminant transport away from a point source within an aquifer tends to channel along the bands, regardless of the regional gradient direction. We conclude that accounting for the flow effects of similar compaction-band arrays would prove essential for optimal management of those sandstone aquifers and reservoirs in which they occur.

  5. Geological and Petrophysical Characterization of the Ferron Sandstone for 3-D Simulation of a Fluvial-Deltaic Reservoir

    SciTech Connect

    M. Lee Allison

    1997-03-01

    The objective of this project is to develop a comprehensive, interdisciplinary, and quantitative characterization of a fluvial-deltaic reser v oir which will allow realistic inter-well and reservoir-scale modeling to be constructed for improved oil-field development in similiar reservoirs world-wide. The geological and petrophysical properties of the Cretaceous Ferron Sandstone in east-central Utah will be quantitatively determined . Both new and existing data will be integrated into a three-dimensional representation of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for inter-well to regional-scale reservoir simulation. Results could improve reservoir management through proper infill and extension drilling strategies, reduction of economic risks, increased recovery from existing oil fields, and more reliable reserve calculations . Transfer of the project results to the petroleum industry is an integral component of the project. Four activities continued this quarter as part of the geological and petrophysical characterization of the fluvial-deltaic Ferron Sandstone in the Ivie Creek case-study area: (1) geostatistics, (2) field description of clinoform bounding surfaces, (3) reservoir modeling, and (4) technology transfer.

  6. Reservoir characterization and diagenesis of the oligocene 64-zone sandstone, North Belridge Field, Kern County, California

    SciTech Connect

    Taylor, T.R. ); Soule, C.H. )

    1993-09-01

    The Oligocene (Zemorrian) 64-Zone sandstone is an important oil and gas reservoir in North Belridge field, Kern County, California. The 64-Zone is a submarine-fan deposit that ranges from 83 to 137 m in thickness. The overall variations in reservoir quality reflect an upward increase in grain size associated with depositional processes. Three diagenetic events have had a significant impact on reservoir quality: (1) compaction, which reduced intergranular volume to an average of 20%, (2) quartz cement, which reduced porosity by an average of 6.2%, and (3) feldspar dissolution. Although an average of 2.7% porosity is directly associated with leached feldspar grains, mass balance calculations indicate secondary porosity is roughly balanced by formation of authigenic kaolinite, resulting in little or no net gain in porosity. Three episodes of calcite cementation reflect various stages of burial history. Petrographic and isotopic data demonstrate that calcite I formed at shallow depths in the zone of bacterial sulfate reduction. Fluid inclusion data indicate that calcite II precipitated at temperatures of 92 to 167[degrees]C from fluids less saline than seawater. Fracture-filing calcite III post-dates calcite II, but formed at lower temperatures (85 to 125[degrees]C). The results of isotopic modeling indicate that calcite II precipitated in equilibrium with waters expelled by shales during I/S diagenesis ([delta][sup 18]O[sub SMOW] = + 2 to +8%) and that calcite III precipitated during tectonic uplift from a mixture of shale-derived and meteoric waters ([delta][sup 18]O[sub SMOW] = 0 to +4%). Most fluid inclusions in calcite II yield temperatures greater than present bottom-hole values ([approximately]110[degrees]C). Assuming that fluid inclusions in calcite II record maximum burial and geothermal gradient of 33[degrees]C/km, tectonic uplift of 0.6 to 1.7 km ([approximately]2000-5700 ft) would be required to explain the fluid inclusion data. 48 refs., 18 figs., 1 tab.

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

    NASA Astrophysics Data System (ADS)

    Al-Mudhafar, W. J.

    2013-12-01

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

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

    NASA Astrophysics Data System (ADS)

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

    2011-12-01

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

  9. Hydrocarbon-Induced Diagenetic Aureoles (HIDA): Indicators of deeper leaky reservoirs

    SciTech Connect

    Al-Shaieb, Z.; Cairns, J.; Puckette, J.

    1995-06-01

    The Permian redbeds that overlie some giant oil fields in southwestern and south-central Oklahoma have undergone extensive mineralogical and chemical diagenesis. The diagenetic minerals occur within a distinctly zoned aureole that delineates the position of the oil field. The geometries of the aureoles strongly reflect the major structural elements that controlled emplacement of hydrocarbons in the underlying rocks . Calcite, ferroan calcite, manganese-rich calcite, dolomite, ankerite, pyrite and native sulfur are the major diagenetic minerals. The innermost zone of the aureole (zone 1) is characterized by abundant carbonate cementation and generally coincides with a major fault system. Zone 2 is composed of altered (bleached) redbeds with minimal calcite cement. Pyrite cement (zone 3) is commonly associated with the carbonate-cemented zones and is disseminated in some bleached sandstones. Zone 4 represents the unaltered red beds. {delta}C{sup 13} values of carbonate cements indicate 3 major sources of carbon: (1) an organic source with {delta}C{sup 13} values approximately -32 {per_thousand} vs. PDB, (2) a freshwater source with an average {delta}C{sup 13} value of -8.0 {+-} 3 {per_thousand}, and (3) a hybrid source (freshwater and organic). {delta}S{sup 34} values of pyrite average 6.1{per_thousand} and range from -9 {per_thousand} to +16 {per_thousand}. Leakage from deeper hydrocarbon-bearing reservoirs formed shallow petroleum accumulations and contributed to the alteration of the redbeds. Faults were the likely conduits that carried leaked hydrocarbons to the shallow rocks. The development of the oil fields with alteration halos indicate that the HIDA can be used to identify potential shallow oil and deep gas accumulations. Therefore, the HIDA concept can be used in the exploration for oil and gas, especially in faulted structural settings.

  10. Multiscale characterization of porous media properties for hydrocarbon reservoir simulation

    NASA Astrophysics Data System (ADS)

    Neeman, Henry; Lao, Hio-Wai; Simpson, Dale; Papavassiliou, Dimitrios V.

    2001-07-01

    Fluid flow through porous materials is critical for understanding and predicting the behavior of systems as diverse in function and scale as hydrocarbon reservoirs, aquifers, filters, membrane separators and even catalytic converters. Recently, there have been calls to incorporate more physics in oil reservoir simulations, as well as to enhance computational capability through the use of High Performance Computing (HPC), in order to improve reservoir management. Accurate prediction of reservoir behavior depends on the physical properties of not only the fluid but also the underlying rock formation. Contemporary approaches to solving these flows involve simulation of only a single physical scale. We are currently developing HiMuST (Hierarchical Multiscale Simulator Technology), an integrated multiscale simulation system for flow through heterogeneous porous materials. HiMuST uses a hierarchy of simulation codes to address the issue of rock property characterization at the pore scale and can self-adjust according to available input data. At the microscopic scale, HiMuST employs the Lattice Boltzmann Method, based on magnetic resonance digitizations of actual rock samples. At the mesoscopic scale, a stochastic model represents a pore network as a randomly generated skeleton of cylindrical pipes, based on physical characteristics determined by the microscopic simulation. We present computational and computer science issues involved in the HPC implementation of the codes and in integrating them into a seamless simulation system. Issues such as portability, scalability, efficiency and extensibility of the final product are also discussed, as well as the numerical methods implemented at each scale. Example simulation results are presented.

  11. Reservoir heterogeneity and hydrocarbon production in mixed dolomitic-clastic sequence: Escandalosa Formation, Barinas-Apure basin, southwestern Venezuela

    SciTech Connect

    Escalona, N.; Abud, J.

    1989-03-01

    Widespread dedolomitization and differential leaching occur in the Turonian O Member of the Escandalosa Formation, Barinas-Apure basin. Within this dolostone-dominated succession, calcite was developed through a dedolomitization process occurring in deeply buried dolomitized lime sediments previously deposited on a carbonate platform as well as dedolomitization on the associated glauconitic-quartzose sandstones of small-scale channels that scoured the platform. The dolomitized intervals have a strata-bound nature, and their original fabric is totally obliterated. The dolomitization process generated a sucrose-textured mosaic of saddle dolomite. Initial dolomite was of the scattered type, but progressive replacement of the host produced a mosaic dolostone with both idiotopic and xenotopic textures. A general increase occurred in the iron and manganese content, and goethite was exsolved from the curved rhombs of saddle dolomite. Calcite usually postdates dolomitization, except in the highly fossiliferous packstones; calcite veins develop in both dolostones and limestones. Leaching is restricted essentially to glauconitic sandstones where calcite and some clay have been leached. This has produced very low intercrystalline porosity within the dolostones and partially dissolved, corroded and floating grains with oversized pores in the sandstones. These sandy intervals exhibit maximum potential for hydrocarbon storage, due to contrasting diagenetic influence associated with reservoir heterogeneity.

  12. Depositional environments, diagenesis, and porosity of upper cretaceous volcanic-rich Tokio sandstone reservoirs, Haynesville Field, Clairborne Parish, Louisiana

    SciTech Connect

    Clark, W.J.

    1995-10-01

    Tokio Formation sandstones produce oil from volcanic-rich to quartzose lithic sandstones in the Haynesville Field. The Tokio interval is approximately 210 feet thick and has been divided into four sandstone zones separated by shales or scoured contacts. In ascending order, the four zones are the RA, S3, S2, and S1. The RA is composed of quartzose sublitharenites inferred to have been deposited in delta front bars and distributary channels. The upper three zones are composed of sublitharenite and feldspathic litharenite to quartzose litharenite. The upper sands are interpreted to have been deposited in littoral environments including storm influenced shelf, tidal flats and channels, and barrier island/strand plain. The diagenesis of these sands is strongly related to composition: greater percentages of cements and secondary porosity occur in lithic-rich sandstones. Diagenetic cements in quartzose sandstones are mainly quartz overgrowths with minor early K-spar overgrowths on plagioclase, early chlorite-rims, and late patchy calcite, pyrite, and rare dolomite and siderite. Diagenesis in lithic-rich sands includes greater amounts of chlorite rim and pore-filling kaolinite cements and less quartz-overgrowth and other cements. The effect of the original mineralogy and diagenetic minerals on wireline logs includes: (1) reduction of SP due to cements, (2) increase in GR response due to K-spar and volcanic detritus, (3) higher resistivity due to carbonate minerals, and (4) increase in irreducible water saturation due to pore-lining and pore-filling clay. Thus, potential reservoir zones with lithic-rich sandstones like the Tokio could be overlooked in many areas around the world.

  13. USGS investigations of water produced during hydrocarbon reservoir development

    USGS Publications Warehouse

    Engle, Mark A.; Cozzarelli, Isabelle M.; Smith, Bruce D.

    2014-01-01

    Significant quantities of water are present in hydrocarbon reservoirs. When brought to the land surface during oil, gas, and coalbed methane production, the water—either naturally occurring or injected as a method to enhance production—is termed produced water. Produced water is currently managed through processes such as recycling, treatment and discharge, spreading on roads, evaporation or infiltration, and deep well injection. U.S. Geological Survey (USGS) scientists conduct research and publish data related to produced water, thus providing information and insight to scientists, decisionmakers, the energy industry, and the public. The information advances scientific knowledge, informs resource management decisions, and facilitates environmental protection. This fact sheet discusses integrated research being conducted by USGS scientists supported by programs in the Energy and Minerals and Environmental Health Mission Areas. The research products help inform decisions pertaining to understanding the nature and management of produced water in the United States.

  14. Sedimentation of shelf sandstones in Queen Formation, McFarland and Means fields, central basin platform of Permian basin

    SciTech Connect

    Malicse, A.; Mazzullo, J.; Holley, C.; Mazzullo, S.J.

    1988-01-01

    The Queen Formation is a sequence of carbonates, evaporites, and sandstones of Permian (Guadalupian) age that is found across the subsurface of the Central Basin platform of the Permian basin. The formation is a major hydrocarbon reservoir in this region, and its primary reservoir facies are porous shelf sandstones and dolomites. Cores and well logs from McFarland and Means fields (on the northwest margin of the Central Basin platform) were examined to determine the sedimentary history of the shelf sandstones.

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

    NASA Astrophysics Data System (ADS)

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

    2010-05-01

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

  16. Depositional systems and structural controls of Hackberry sandstone reservoirs in southeast Texas

    SciTech Connect

    Ewing, T.E.; Reed, R.S.

    1984-01-01

    Deep-water sandstones of the Oligocene-age Hackberry unit of the Frio Formation contain significant quantities of oil and gas remain potentially one of the most productive exploration targets in southeast Texas. The Hackberry is a wedge of sandstone and shale containing bathyal fauna that separates upper Frio barrier-bar-strandplain sandstones from lower Frio neritic shale and sand. Major Hackberry sandstones lie atop a channeled unconformity that forms the base of the unit. Sandstones in a typical sand-rich channel at Port Arthur field grade upward from a basal, confined channel-fill sandstone to more widespread, broad, fan-channel deposits. Topmost are proximal to medial fan deposits and overbank turbidite deposits. The sequence suggests that Hackberry sandstones were laid down by an onlapping submarine canyon-fan complex deposited in canyons that eroded headward into the contemporaneous Frio barrier system. Regional maps and seismic interpretations outline a network of sand-filled channels extending from the barrier toward the southeast.

  17. The filling time sequence of mantle CO2 and hydrocarbon in Southern Songliao Basin: dawsonite-bearing sandstone evidence

    NASA Astrophysics Data System (ADS)

    Liu, Li; Liu, Na; Zhou, Bing; Yu, Miao; Hu, Chunyan

    2014-05-01

    The filling time of mantle CO2 in sedimentary basin is the basement of carrying out the research on interaction of CO2-sandstone, as well as CO2-crude oil. In general, the age of the volcanic rocks eruption occurred in the vicinity of the CO2 pool is supposed to be the filling time of mantle CO2. But this approach is obviously not suitable to the case of possessing multi volcanic activities. Two stages of hydrocarbon filling and single stage CO2 filling have been interpreted in Southern Songliao basin, through the systematic observation/analysis of diagenetic sequence and fluid inclusions in the dawsonite-bearing sandstone. The two stages of hydrocarbon fillings were presented by the different occurrence of the liquid hydrocarbon inclusion and gas-liquid hydrocarbon inclusion founded in the authigenic minerals and fractures developed in detrital minerals. The filling records of mantle CO2 were preserved in the form of dawsonite and CO2-bearing inclusion developed in the fractures of detrital minerals. The filling time of mantle CO2 is slightly later than that of second stage of hydrocarbon, or they are almost synchronously. As the injection of mantle CO2 lead to the formation of authigenic carbonate minerals like dawsonite and ankerite, the injecting time of mantle CO2 into Songliao basin has been proved to be probably the end of Cretaceous (end of Mingshui period) -Tertiary, according to the analysis of diagenetic sequence and liquid inclusions in dawsonite-bearing sandstone. Also the conclusion is consistent with the time of hydrocarbon filling and structural fractures developing that are obtained by other workers. Results of this work will be useful for understanding the sequence between volcanic activity, mantle CO2 injection and mineral carbonation in Songliao basin, and be the implication for manual CO2 injection. This work was supported by Key Development Plan of Science and Technology Project of Jilin Province in China (No. 20110426) and National Natural

  18. Hydrocarbon-bearing sandstone in the Upper Jurassic Naknek Formation on the south shore of Kamishak Bay

    USGS Publications Warehouse

    Stanley, Richard G.; Herriott, Trystan M.; Helmold, Kenneth P.; Gillis, Robert J.; Lillis, Paul G.

    2013-01-01

    The presence of an active petroleum system in Kamishak Bay is demonstrated by an outcrop of hydrocarbon-bearing sandstone in the Upper Jurassic Naknek Formation near the south shore of the bay (fig. 1). The outcrop is about 140 km southwest of Homer on a small, unnamed island near the mouth of the Douglas River (fig. 17). The existence of this outcrop was kindly reported to us by Les Magoon (U.S. Geological Survey, emeritus), who also provided a topographic map showing its exact position. The outcrop was mentioned very briefly in publications by Magoon and others (1975, p. 19) and by Lyle and Morehouse (1977, p. E-1), but to our knowledge there are no detailed descriptions of this outcrop or its hydrocarbons in the published scientific literature.

  19. Porosity prediction in sandstones using erosional unconformities

    SciTech Connect

    Shanmugam, G.

    1989-03-01

    Erosional unconformities of subaerial origin are created by tectonic uplifts and eustatic sea level fall. Most erosional unconformities developed on sandstones are planes of increased porosity because uplifted sandstones are exposed to undersaturated CO/sub 2/-charged meteoric waters that result in dissolution of unstable framework grains and cements. The chemical weathering of sandstones is intensified in humid regions by the heavy rainfall, soil zones, lush vegetation, and accompanying voluminous production of organic and inorganic acids. Erosional unconformities are considered hydrologically open systems because of abundant supply of fresh meteoric water and relatively unrestricted transport of dissolved constituents away from the site of dissolution, causing a net gain in porosity near unconformities. Thus, porosity in sandstones tends to increase toward overlying unconformities. Such porosity trends have been observed in hydrocarbon-bearing sandstone reservoirs in Alaska, Algeria, Australia, China, Libya, Netherlands, Norwegian North Sea, Norwegian Sea, and Texas. A common attribute of these reservoirs is that they were all subaerially exposed under heavy rainfall conditions. An empirical model has been developed for the Triassic and Jurassic sandstone reservoirs in the Norwegian North Sea on the basis of the observed relationship that shows an increase in porosity in these reservoirs with increasing proximity to the overlying base of Cretaceous unconformity. An important practical attribute of this model is that it allows for the prediction of porosity in the neighboring undrilled areas by recognizing the base of Cretaceous unconformity in seismic reflection profiles and by constructing subcrop maps.

  20. Long term effects of CO2 on 3-D pore structure and 3-D phase distribution in reservoir sandstones from the Green River well (Utah, USA)

    NASA Astrophysics Data System (ADS)

    Barnhoorn, Auke; Kisoensingh, Shailesh

    2014-05-01

    Reservoir sandstones and cap rocks from the Green River area in Utah (USA) have been naturally exposed to CO2 fluids for hundreds of thousands of years, leading to compositional and microstructural alterations of the rocks. A 300m long section of this section of these Green river reservoir and cap rocks has been cored in 2012. Here, results of a high-resolution micro X-ray tomography study of a suite of samples from the well are reported detailing the 3D pore structure and phase distribution changes due to long term CO2 exposure. The reservoir sandstones from the Green River well (Utah) reveal the presence of various degrees of carbonate precipitation in the pores. Both reservoir sandstones (the shallower Entrada Formation and the deeper Navajo Formation) show variations in carbonate content and porosity structure. The Entrada sandstone exhibits widespread carbonate precipitation (up to 60% of infill of the original porosity), with the largest amount of carbonates at the boundary with the underlying Carmel cap rock. In an interval of a meter from the contact, carbonate precipitation decreases sharply till ~20%. The porosity is significantly reduced in the lowest 1 meter. The reduction in porosity lead to a reduction in pore connectivity and thereby permeability by the long-term CO2 exposure. On the other hand the Navajo sandstone shows predominantly only isolated spots of carbonate precipitation (up to 20% of the original porosity). Widespread carbonate precipitation is absent in the Navajo reservoir sandstone samples. Because carbonate precipitation is not present throughout, the large-scale permeability of the formation is likely not significantly affected by the CO2 exposure. The results show how the 3D distribution of the phases and the 3D shapes of the pores are affected by long term CO2 exposure and can be used as an example for potential changes to be expected in reservoir sandstones due to CO2 storage in future CO2 sequestration endeavours.

  1. Polyhalogenated aromatic hydrocarbons in surface sediments from Three Gorges Reservoir.

    PubMed

    Zhao, Gaofeng; Li, Kun; Zhou, Huaidong; Liu, Xiaoru; Zhang, Panwei; Wen, Wu; Yu, Yang; Yuan, Hao

    2013-01-01

    This study was conducted to investigate the current contamination status of polyhalogenated aromatic hydrocarbons (PHAHs) in sediments from the mainstream and 22 primary tributaries of the Yangtze River in the Three Gorges Reservoir region. To accomplish this, the concentrations of 22 polybrominated biphenyl (PBB) congeners, 27 polybrominated diphenyl ether (PBDE) congeners, and 27 polychlorinated biphenyl (PCB) congeners in sediment samples were measured by GC-MS/MS. The result showed that the observed values of PBBs and PBDEs were 22.41 and 35.24 pg g(-1) dw, respectively. PBB1, 31 and 103 were the predominant PBB congeners, while PBDE28, 47, 77 and 99 were the predominant PBDE congeners. PBB209 and BDE209 were detected in >39% of the samples, with geometric means 2.43 and 11.92 pg g(-1) dw, respectively. PCBs were found to be the predominant compounds in sediment samples among the three PHAH subfamilies, with a geometric mean of 1,231.11 pg g(-1) dw, and PCB8, 18, 28, 52 and 66 were the primary PCB congeners. The measured levels of PHAHs were compared with results recently reported in the literature and their respective sediment quality guidelines recommended by the USEPA. The levels of PHAHs in the present study were generally lower than their respective threshold-effect levels, or were comparable to those reported in relatively uncontaminated freshwater samples from other regions. Taken together, these results suggest that, in the reservoir, toxic biological effects on aquatic biota in response to PHAHs contamination of sediments can be expected to be negligible. PMID:23043334

  2. Neogene sandstone reservoirs of the East Slovakian basin: Zeolites and clay minerals from the alteration of volcanics

    SciTech Connect

    Reed, J.K.; Gipson, M. Jr. )

    1991-03-01

    Petrographic analyses of core samples from wells in the East Slovakian basin indicate that alteration products of volcanic materials cause porosity loss in sandstone reservoirs. The reservoirs, which produce natural gas, are part of a shallow marine to continental basin fill with interbedded volcaniclastics, tuffs, and volcanites. Abnormally high heat-flow values have been recorded in the basin fill, which reaches up to 7 km in thickness. Both clay minerals and zeolites are found to restrict porosity. Kaolinite, smectite, illite, chlorite, and mixed-layer clay minerals are all identified in various combinations. Zeolites identified include phillipsite, erionite, clinoptilolite, and analcime. These minerals are related to the occurrence of volcanic rock fragments in the reservoir sand and interbedded volcanics, and they occur as diagenetic replacement minerals and cements. The effects of these minerals are compounded by the initial poor reservoir quality caused by immature sediments and calcite cement. Reservoir productivity would probably be increased if drilling and completion practices in the basin reflected the potential effects of the clay minerals and zeolites.

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

    PubMed Central

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

    2016-01-01

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

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

    NASA Astrophysics Data System (ADS)

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

    2016-07-01

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

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

    PubMed

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

    2016-01-01

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

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

    USGS Publications Warehouse

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

    2000-01-01

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

  7. Hydrocarbon accumulations of Mississippian Berea sandstone in west-central West Virginia

    SciTech Connect

    Cox, D.L. )

    1988-08-01

    The Berea Sandstone is a widely recognized producer of oil and gas in the Appalachian basin. Subsurface mapping, core analysis, and production data from producing wells have been evaluated in west-central West Virginia, where the Berea Sandstone represents a wide range of nearshore and coastal environments. Fluvial system deposits are found in southern Jackson County as channel sands (Gay-Fink) and adjacent deltaic facies. Coastal sediments were deposited to the north as intertidal shoals, tidal flats, and coarse-grained tidal-creek point bars. Marine shelf sands are found to the west.

  8. Measuring and predicting reservoir heterogeneity in complex deposystems. The fluvial-deltaic Big Injun Sandstone in West Virginia. Final report, September 20, 1991--October 31, 1993

    SciTech Connect

    Hohn, M.E.; Patchen, D.G.; Heald, M.; Aminian, K.; Donaldson, A.; Shumaker, R.; Wilson, T.

    1994-05-01

    Non-uniform composition and permeability of a reservoir, commonly referred to as reservoir heterogeneity, is recognized as a major factor in the efficient recovery of oil during primary production and enhanced recovery operations. Heterogeneities are present at various scales and are caused by various factors, including folding and faulting, fractures, diagenesis and depositional environments. Thus, a reservoir consists of a complex flow system, or series of flow systems, dependent on lithology, sandstone genesis, and structural and thermal history. Ultimately, however, fundamental flow units are controlled by the distribution and type of depositional environments. Reservoir heterogeneity is difficult to measure and predict, especially in more complex reservoirs such as fluvial-deltaic sandstones. The Appalachian Oil and Natural Gas Research Consortium (AONGRC), a partnership of Appalachian basin state geological surveys in Kentucky, Ohio, Pennsylvania, and West Virginia, and West Virginia University, studied the Lower Mississippian Big Injun sandstone in West Virginia. The Big Injun research was multidisciplinary and designed to measure and map heterogeneity in existing fields and undrilled areas. The main goal was to develop an understanding of the reservoir sufficient to predict, in a given reservoir, optimum drilling locations versus high-risk locations for infill, outpost, or deeper-pool tests.

  9. Geology and hydrocarbon reservoir potential of the Pituil and Barreal Formations, Calingasta Valley, western Argentina

    SciTech Connect

    Janks, J.S. ); Lopez-Gamundi, O.R.; Siegele, P.K. )

    1990-05-01

    The Calingasta basin is one of the north-south-trending intermontane basins informally known as the Bolsones. The stratigraphy consists of lower Paleozoic metamorphic basement overlain by sediments and volcanics of upper Paleozoic through Cenozoic age. Three distinct geological provinces are recognized within the Bolsones region: Sierras Pampeanas, Precordillera, and Cordillera Frontal. Outcrop samples from the Permian Pituil and Triassic Barreal formations from the Tamberias region of the Sierras Pampeanas province were analyzed to determine the composition, porosity type, and diagenetic modification. The Pituil formation is a shallow marine sequence overlying Carboniferous glaciomarine sediments. They grade eastward into nonmarine lacustrine, deltaic, and fluvial sandstones. The rocks are fine- to medium-grained litharenites with porosities of 6-10 %. Diagenetic modifications include quartz overgrowths, unstable grain dissolution, carbonate cements, pyrite, and kaolinite. Triassic deposits occur on the western flank of the Precordillera, overlying a basement of volcanics and metasedimentary rocks. The Triassic sediments can be several hundreds of meters thick; deposition occurred in fluvial to lacustrine environments. These clastic sediments are considered to be northern extensions of the hydrocarbon-productive sediments in the Cuyo basin. The Barreal formation ranges from clay-rich lithic wackes and shales to conglomeratic, volcaniclastic litharenites and sublitharenites. Framework grains consist of quartz, feldspars, rock fragments, and, rarely, glass shards. Cements include zeolites, carbonates, chalcedony, pyrite, and clays. Tuffs are found at certain intervals within the section; alteration to iron-rich smectite is common. Reservoir potential is highly variable. Porosities range from as low as 5% to greater than 25%.

  10. Calculation of hydrocarbon-in-place in gas and gas-condensate reservoirs - Carbon dioxide sequestration

    USGS Publications Warehouse

    Verma, Mahendra K.

    2012-01-01

    The Energy Independence and Security Act of 2007 (Public Law 110-140) authorized the U.S. Geological Survey (USGS) to conduct a national assessment of geologic storage resources for carbon dioxide (CO2), requiring estimation of hydrocarbon-in-place volumes and formation volume factors for all the oil, gas, and gas-condensate reservoirs within the U.S. sedimentary basins. The procedures to calculate in-place volumes for oil and gas reservoirs have already been presented by Verma and Bird (2005) to help with the USGS assessment of the undiscovered resources in the National Petroleum Reserve, Alaska, but there is no straightforward procedure available for calculating in-place volumes for gas-condensate reservoirs for the carbon sequestration project. The objective of the present study is to propose a simple procedure for calculating the hydrocarbon-in-place volume of a condensate reservoir to help estimate the hydrocarbon pore volume for potential CO2 sequestration.

  11. NMR response of non-reservoir fluids in sandstone and chalk.

    PubMed

    van der Zwaag, C H; Stallmach, F; Skjetne, T; Veliyulin, E

    2001-01-01

    Transverse (T2) NMR relaxation time at 2 MHz proton resonance frequency was measured on core plug samples from two different lithologies, sandstone and chalk, before and after exposure to selected drilling fluids. The results show that NMR signal response was significantly altered after displacing 50% of the original pore fluids, crude oil and water, by drilling fluid filtrate. Relaxation spectra of the rock samples invaded by water-based filtrate shift to significantly shorter T2-values. This shift yields an underestimation of the free-fluid volumes when selecting cut-off values of 33 ms and 100 ms for sandstone and chalk, respectively. In opposite, rock samples affected by oil-based filtrate respond with a signal indicating significantly larger free-fluid volumes than present before exposure. NMR-permeability calculated based on the Timur-Coates Free Fluid model altered in some cases by one order of magnitude. PMID:11445352

  12. Clay microporosity in reservoir sandstones: An application of quantitative electron microscopy in petrophysical evaluation

    SciTech Connect

    Hurst, A.; Nadeau, P.H.

    1995-04-01

    Clay mineral microporosity in sandstones is measured using computer-assisted image analysis of back-scattered electron micrographs of petrographic sections. Diagenetic kaolinite has a variety of textures with microporosity values ranging from 15 to 61%. Diagenetic chlorite has a generally uniform grain-coating texture and microporosity of about 50%. Fibrous illitic clays are difficult to characterize by the same method (an average value of 63% microporosity was recorded), but analysis of stereo-pair micrographs from scanning-electron microscopy analyses reveals that illite commonly has microporosity of approximately 90%. Clay microporosity data are used to calculate effective pore volumes and volumes of clay-bound water for clay minerals in sandstones. Converting from weight percent clay to volume percent clay is important. Microporosity data are valuable input to V{sub shale} evaluation where water saturation is associated with clay mineral type, texture, and volume.

  13. Reservoir Characterization of Upper Devonian Gordon Sandstone, Jacksonburg, Stringtown Oil Field, Northwestern West Virginia

    SciTech Connect

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

    2002-05-21

    This report gives results of efforts to determine electrofacies from logs; measure permeability in outcrop to study very fine-scale trends; find the correlation between permeability measured by the minipermeameter and in core plugs, define porosity-permeability flow units; and run the BOAST III reservoir simulator using the flow units defined for the Gordon reservoir.

  14. Abiogenic formation of alkanes in the Earth's crust as a minor source for global hydrocarbon reservoirs.

    PubMed

    Sherwood Lollar, B; Westgate, T D; Ward, J A; Slater, G F; Lacrampe-Couloume, G

    2002-04-01

    Natural hydrocarbons are largely formed by the thermal decomposition of organic matter (thermogenesis) or by microbial processes (bacteriogenesis). But the discovery of methane at an East Pacific Rise hydrothermal vent and in other crustal fluids supports the occurrence of an abiogenic source of hydrocarbons. These abiogenic hydrocarbons are generally formed by the reduction of carbon dioxide, a process which is thought to occur during magma cooling and-more commonly-in hydrothermal systems during water-rock interactions, for example involving Fischer-Tropsch reactions and the serpentinization of ultramafic rocks. Suggestions that abiogenic hydrocarbons make a significant contribution to economic hydrocarbon reservoirs have been difficult to resolve, in part owing to uncertainty in the carbon isotopic signatures for abiogenic versus thermogenic hydrocarbons. Here, using carbon and hydrogen isotope analyses of abiogenic methane and higher hydrocarbons in crystalline rocks of the Canadian shield, we show a clear distinction between abiogenic and thermogenic hydrocarbons. The progressive isotopic trends for the series of C1-C4 alkanes indicate that hydrocarbon formation occurs by way of polymerization of methane precursors. Given that these trends are not observed in the isotopic signatures of economic gas reservoirs, we can now rule out the presence of a globally significant abiogenic source of hydrocarbons. PMID:11932741

  15. Abiogenic formation of alkanes in the Earth's crust as a minor source for global hydrocarbon reservoirs

    NASA Astrophysics Data System (ADS)

    Sherwood Lollar, B.; Westgate, T. D.; Ward, J. A.; Slater, G. F.; Lacrampe-Couloume, G.

    2002-04-01

    Natural hydrocarbons are largely formed by the thermal decomposition of organic matter (thermogenesis) or by microbial processes (bacteriogenesis). But the discovery of methane at an East Pacific Rise hydrothermal vent and in other crustal fluids supports the occurrence of an abiogenic source of hydrocarbons. These abiogenic hydrocarbons are generally formed by the reduction of carbon dioxide, a process which is thought to occur during magma cooling and-more commonly-in hydrothermal systems during water-rock interactions, for example involving Fischer-Tropsch reactions and the serpentinization of ultramafic rocks. Suggestions that abiogenic hydrocarbons make a significant contribution to economic hydrocarbon reservoirs have been difficult to resolve, in part owing to uncertainty in the carbon isotopic signatures for abiogenic versus thermogenic hydrocarbons. Here, using carbon and hydrogen isotope analyses of abiogenic methane and higher hydrocarbons in crystalline rocks of the Canadian shield, we show a clear distinction between abiogenic and thermogenic hydrocarbons. The progressive isotopic trends for the series of C1-C4 alkanes indicate that hydrocarbon formation occurs by way of polymerization of methane precursors. Given that these trends are not observed in the isotopic signatures of economic gas reservoirs, we can now rule out the presence of a globally significant abiogenic source of hydrocarbons.

  16. Reconstruction and geochemical modelling of the diagenetic history of the middle Jurassic Oseberg sandstone reservoir, Oseberg Field, Norwegian North Sea

    SciTech Connect

    Girard, J.P.; Sanjuan, B.; Fouillac, C.

    1995-08-01

    A detailed multidisciplinary integrated study of the Middle Jurassic Oseberg reservoir in 13 wells of the Oseberg field, Norwegian North Sea, was carried out in order to (1) reconstruct precisely the timing, conditions and spatial variation of diagenetic transformations (2) characterize the nature and origin of the diagenetic fluids, and (3) develop a geochemical model of the observed diagenesis. The 20-60 in thick Oseberg Formation occurs at depths of 2.5 to 3.2 km, and at present temperatures ranging from 100 to 125{degrees}C. The detrital assemblage is mainly composed of quartz, K-feldspar, albrite, muscovite and lithic clay clasts, and is very homogeneous throughout the study area. The chronological sequence of diagenetic phases established from petrographic observations includes: minor siderite and pyrite, K-feldspar overgrowths, ankerite, feldspar dissolution, vermiform, kaolinite, quartz overgrowths, poikilotopic Fe-rich calcite, dickite. Diagenetic temperatures were determined from fluid inclusions in ankerite, quarts and calcite. Combination with modelled burial/thermal history permitted to constrain approximate ages and duration of major diagenetic events. Isotopic compositions of diagenetic cements indicate that meteoric water was (and still is) a major constituant of diagenetic fluids. Present formation waters are fairly similar chemically and isotopically at reservoir scale and represent mixing of three endmembers: seawater, meteoric water and primary evaporative brine. Stability diagrams and chemical geothermometers suggest that formation fluids are close to equilibrium with the host sandstone at present reservoir temperatures. Geochemical modelling of the diagenetic evolution of water-reservoir interactions was carried out using the EQ3/6 code and the Allan{sup TM}/Neptunix integrated simulator system. Results emphasize the importance of circulations of large volumes of fluid within the reservoir throughout the diagenetic history.

  17. Diagenesis of the Oseberg Sandstone Reservoir (North Sea): An example of integration of core, formation fluid and geochemical modelling studies

    SciTech Connect

    Girard, J.P.; Sanjuan, B.; Czernichowski-Lauriol, I.; Fouillac, C.

    1996-12-31

    A detailed multidisciplinary integrated study of the Middle Jurassic Oseberg reservoir in 20 wells of the Oseberg field, Norwegian North Sea, was carried out in collaboration with Norsk Hydro and Oseberg partners. The objectives were to reconstruct the tinting, conditions and spatial variation of diagenetic transformations; to characterize the nature and origin of diagenetic fluids; and to develop a geochemical model of the observed diagenesis. The 20-60 m thick Oseberg Formation occurs at depths of 2.5 to 3.2 km, and at present temperatures of 100 to 125{degrees}C. The detrital assemblage is mainly composed of quartz, K-feldspar, albite, muscovite and lithic clay clasts, and is very homogeneous throughout the field. The diagenetic sequence includes: minor siderite and pyrite, K-feldspar rims, ankerite, pervasive feldspar dissolution, abundant vermiform kaolinite, quartz overgrowths, poikilotopic ferroan calcite, and dickite. Diagenetic temperatures were derived from fluid inclusions in ankerite, quartz and calcite, and combined with the modelled burial/thermal history to constrain approximate ages and duration of diagenetic events. Isotopic compositions of carbonates and kaolinite indicate that meteoric water and seawater were two major constituents of diagenetic fluids. Present formation waters are fairly similar chemically and isotopically at reservoir scale and represent mixing of three end members: seawater ({approximately}54%), meteoric water ({approximately}40%) and primary evaporative brine ({approximately}6%). Stability diagrams and chemical geothermometers indicate that formation fluids are close to equilibrium with the host sandstone at present reservoir temperatures.

  18. Predictive modeling of CO{sub 2} sequestration in deep saline sandstone reservoirs: Impacts of geochemical kinetics

    SciTech Connect

    Balashov, Victor N; Guthrie, George D; Hakala, J Alexandra; Lopano, Christina L. J.; Rimstidt, Donald; Brantley, Susan L

    2013-03-01

    One idea for mitigating the increase in fossil-fuel generated CO{sub 2} in the atmosphere is to inject CO{sub 2} into subsurface saline sandstone reservoirs. To decide whether to try such sequestration at a globally significant scale will require the ability to predict the fate of injected CO{sub 2}. Thus, models are needed to predict the rates and extents of subsurface rock-water-gas interactions. Several reactive transport models for CO{sub 2} sequestration created in the last decade predicted sequestration in sandstone reservoirs of ~17 to ~90 kg CO{sub 2} m{sup -3|. To build confidence in such models, a baseline problem including rock + water chemistry is proposed as the basis for future modeling so that both the models and the parameterizations can be compared systematically. In addition, a reactive diffusion model is used to investigate the fate of injected supercritical CO{sub 2} fluid in the proposed baseline reservoir + brine system. In the baseline problem, injected CO{sub 2} is redistributed from the supercritical (SC) free phase by dissolution into pore brine and by formation of carbonates in the sandstone. The numerical transport model incorporates a full kinetic description of mineral-water reactions under the assumption that transport is by diffusion only. Sensitivity tests were also run to understand which mineral kinetics reactions are important for CO{sub 2} trapping. The diffusion transport model shows that for the first ~20 years after CO{sub 2} diffusion initiates, CO{sub 2} is mostly consumed by dissolution into the brine to form CO{sub 2,aq} (solubility trapping). From 20-200 years, both solubility and mineral trapping are important as calcite precipitation is driven by dissolution of oligoclase. From 200 to 1000 years, mineral trapping is the most important sequestration mechanism, as smectite dissolves and calcite precipitates. Beyond 2000 years, most trapping is due to formation of aqueous HCO{sub 3}{sup -}. Ninety-seven percent of the

  19. 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.

  20. Reservoir Characterization of Upper Devonian Gordon Sandstone, Jacksonburg, Stringtown Oil Field, Northwestern West Virginia

    SciTech Connect

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

    2002-05-21

    The purpose of this work was 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.

  1. Geological and petrophysical characterization of the Ferron Sandstone for 3-D simulation of a fluvial-deltaic reservoir. Deliverable 2.5.4, Ferron Sandstone lithologic strip logs, Emergy & Sevier Counties, Utah: Volume I

    SciTech Connect

    Allison, M.L.

    1995-12-08

    Strip logs for 491 wells were produced from a digital subsurface database of lithologic descriptions of the Ferron Sandstone Member of the Mancos Shale. This subsurface database covers wells from the parts of Emery and Sevier Counties in central Utah that occur between Ferron Creek on the north and Last Chance Creek on the south. The lithologic descriptions were imported into a logging software application designed for the display of stratigraphic data. Strip logs were produced at a scale of one inch equals 20 feet. The strip logs were created as part of a study by the Utah Geological Survey to develop a comprehensive, interdisciplinary, and qualitative characterization of a fluvial-deltaic reservoir using the Ferron Sandstone as a surface analogue. The study was funded by the U.S. Department of Energy (DOE) under the Geoscience/Engineering Reservoir Characterization Program.

  2. Geological and petrophysical characterization of the Ferron Sandstone for 3-D simulation of a fluvial-deltaic reservoir. Annual report, October 1, 1995--September 30, 1996

    SciTech Connect

    Chidsey, T.C. Jr.

    1997-05-01

    The objective of the Ferron Sandstone project is to develop a comprehensive, interdisciplinary, quantitative characterization of a fluvial-deltaic reservoir to allow realistic inter-well and reservoir-scale models to be developed for improved oil-field development in similar reservoirs world-wide. Quantitative geological and petrophysical information on the Cretaceous Ferron Sandstone in east-central Utah was collected. Both new and existing data is being integrated into a three-dimensional model of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for inter-well to regional-scale reservoir simulation. Simulation results could improve reservoir management through proper infill and extension drilling strategies, reduction of economic risks, increased recovery from existing oil fields, and more reliable reserve calculations. Transfer of the project results to the petroleum industry is an integral component of the project. This report covers research activities for fiscal year 1995-96, the third year of the project. Most work consisted of interpreting the large quantity of data collected over two field seasons. The project is divided into four tasks: (1) regional stratigraphic analysis, (2) case studies, (3) reservoirs models, and (4) field-scale evaluation of exploration strategies. The primary objective of the regional stratigraphic analysis is to provide a more detailed interpretation of the stratigraphy and gross reservoir characteristics of the Ferron Sandstone as exposed in outcrop. The primary objective of the case-studies work is to develop a detailed geological and petrophysical characterization, at well-sweep scale or smaller, of the primary reservoir lithofacies typically found in a fluvial-dominated deltaic reservoir.

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

    PubMed

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

    2004-08-01

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

  4. Diagenesis and secondary porosity enhancement from dissolution of analcime cement in reservoir sandstones: The Upper Permian Pingdiquan Formation, Junggar basin, northwest China

    SciTech Connect

    Zhaohui, T.; Longstaffe, F.J.; Parnell, J.

    1996-12-31

    The Junggar Basin is one of the largest and most important oil-producing basins in China, in which Upper Permian lacustrine oil shales are among the thickest and richest petroleum source rocks in the world. The Upper Permian Pingdiquan Formation was deposited predominantly in fan-delta sequences within a lacustrine setting. The Pingdiquan Formation sandstones constitute the principal oil reservoirs, whereas the interbedded black shales are the predominant oil source rocks. The early diagenetic mineral assemblage in the sandstones comprises siderite, pyrite, analcime, albite, calcite and authigenic quartz as well as trace amount of halite; By contrast, the late diagenetic minerals are characterized by authigenic K-feldspar, ankerite, and minor amounts of mixed-layer clay minerals. Petrographic, mineralogical and available paleoecological data suggest that early authigenic minerals in the sandstones were controlled by alternating periodic fresh water and saline/alkaline water episodes in a lacustrine environment. The cementation of siderite, analcime, calcite and albite occluded the substantial porosity in the sandstones at an early diagenetic stage. However, extensive dissolution of analcime cement and labile detrital feldspars occurred during burial diagenesis, resulting in a significant secondary porosity enhancement in the sandstones and making them very good quality oil reservoirs. The origin of secondary porosity is related to the generation of various organic acids due to organic maturation of the interbedded exceptionally organic-rich oil shales.

  5. Diagenesis and secondary porosity enhancement from dissolution of analcime cement in reservoir sandstones: The Upper Permian Pingdiquan Formation, Junggar basin, northwest China

    SciTech Connect

    Zhaohui, T.; Longstaffe, F.J. ); Parnell, J. )

    1996-01-01

    The Junggar Basin is one of the largest and most important oil-producing basins in China, in which Upper Permian lacustrine oil shales are among the thickest and richest petroleum source rocks in the world. The Upper Permian Pingdiquan Formation was deposited predominantly in fan-delta sequences within a lacustrine setting. The Pingdiquan Formation sandstones constitute the principal oil reservoirs, whereas the interbedded black shales are the predominant oil source rocks. The early diagenetic mineral assemblage in the sandstones comprises siderite, pyrite, analcime, albite, calcite and authigenic quartz as well as trace amount of halite; By contrast, the late diagenetic minerals are characterized by authigenic K-feldspar, ankerite, and minor amounts of mixed-layer clay minerals. Petrographic, mineralogical and available paleoecological data suggest that early authigenic minerals in the sandstones were controlled by alternating periodic fresh water and saline/alkaline water episodes in a lacustrine environment. The cementation of siderite, analcime, calcite and albite occluded the substantial porosity in the sandstones at an early diagenetic stage. However, extensive dissolution of analcime cement and labile detrital feldspars occurred during burial diagenesis, resulting in a significant secondary porosity enhancement in the sandstones and making them very good quality oil reservoirs. The origin of secondary porosity is related to the generation of various organic acids due to organic maturation of the interbedded exceptionally organic-rich oil shales.

  6. 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.

  7. EMD and Teager-Kaiser energy applied to hydrocarbon detection in a carbonate reservoir

    NASA Astrophysics Data System (ADS)

    Xue, Ya-juan; Cao, Jun-xing; Tian, Ren-fei

    2014-04-01

    Oil and gas reservoirs can cause anomalies in the energy and frequency of seismic signals. We can take advantage of these anomalies for hydrocarbon detection. Based on the Teager-Kaiser (TK) energy characteristics, a method that uses this energy in association with the Empirical Mode Decomposition (EMD) method is proposed for hydrocarbon detection in carbonate reservoirs. The EMD method, which can decompose the original seismic signals into a finite number of monocomponent intrinsic mode functions (IMFs) in the temporal domain, is used for multiband filtering. A TK energy separation algorithm is used to estimate the instantaneous frequency and amplitude of the selected IMFs from the EMD method. The proposed method can generate a joint time-frequency representation that can reflect the energy tracking of the seismic signals. The instantaneous spectrums produced by the EMD/TK method have the capability to detect hydrocarbon. The model results to the gas field, which located in the eastern Ordos Basin, China, show that the EMD/TK method can be adopted and they detect the gas-bearing reservoir efficiently. Application of the EMD/TK method in hydrocarbon detection in a gas field located in the Eastern Ordos Basin shows its effectiveness. The EMD/TK method can be used as a new analysis tool to determine the instantaneous spectral properties of a reservoir to detect hydrocarbon.

  8. Analysis and evaluation of interwell seismic logging techniques for hydrocarbon reservoir characterization. Final report

    SciTech Connect

    Parra, J.O.; Zook, B.J.; Sturdivant, V.R.

    1994-06-01

    The work reported herein represents the third year work in evaluating high-resolution interwell seismic logging techniques for hydrocarbon reservoir characterization. The objective of this project is to investigate interwell seismic logging techniques for indirectly interpreting oil and gas reservoir geology and rock physical properties. The work involves a balanced study of theoretical and numerical modeling of seismic waves transmitted between pairs of wells combined with experimental data acquisition and processing at controlled field conditions. The field applications of this reservoir probing concept are aimed at demonstrating high resolution measurements and detailed interpretation of heterogeneous hydrocarbon-bearing formations. The first part of this third year project efforts was devoted to thoroughly evaluating interwell seismic logging and reverse VSP in a hydrocarbon-bearing formation at the Buckhorn test site in Illinois. Specifically, the data from the experiments conducted in the second year of this project were analyzed to delineate geological structures and to extract rock physical parameters. The second part of this project is devoted to the evaluation of continuity logging techniques for hydrocarbon reservoir continuity. Specifically, this part of the project includes the evaluation of methods of measurements, modeling and data processing to delineate the reservoir architecture and relate dispersion and attenuation measurements to rock physical properties.

  9. Study on detailed geological modelling for fluvial sandstone reservoir in Daqing oil field

    SciTech Connect

    Zhao Hanqing; Fu Zhiguo; Lu Xiaoguang

    1997-08-01

    Guided by the sedimentation theory and knowledge of modern and ancient fluvial deposition and utilizing the abundant information of sedimentary series, microfacies type and petrophysical parameters from well logging curves of close spaced thousands of wells located in a large area. A new method for establishing detailed sedimentation and permeability distribution models for fluvial reservoirs have been developed successfully. This study aimed at the geometry and internal architecture of sandbodies, in accordance to their hierarchical levels of heterogeneity and building up sedimentation and permeability distribution models of fluvial reservoirs, describing the reservoir heterogeneity on the light of the river sedimentary rules. The results and methods obtained in outcrop and modem sedimentation studies have successfully supported the study. Taking advantage of this method, the major producing layers (PI{sub 1-2}), which have been considered as heterogeneous and thick fluvial reservoirs extending widely in lateral are researched in detail. These layers are subdivided into single sedimentary units vertically and the microfacies are identified horizontally. Furthermore, a complex system is recognized according to their hierarchical levels from large to small, meander belt, single channel sandbody, meander scroll, point bar, and lateral accretion bodies of point bar. The achieved results improved the description of areal distribution of point bar sandbodies, provide an accurate and detailed framework model for establishing high resolution predicting model. By using geostatistic technique, it also plays an important role in searching for enriched zone of residual oil distribution.

  10. Geological and petrophysical characterization of the Ferron Sandstone for 3-D simulation of a fluvial-deltaic reservoir. Technical progress report, April 1--June 30, 1995

    SciTech Connect

    Allison, M.L.

    1995-07-28

    The objective of this project is to develop a comprehensive, interdisciplinary, and quantitative characterization of a fluvial-deltaic reservoir which will allow realistic inter-well and reservoir-scale modeling to be constructed for improved oil-field development in similar reservoirs world-wide. The geological and petrophysical properties of the Cretaceous Ferron Sandstone in east-central Utah will be quantitatively determined. Both new and existing data will be integrated into a three-dimensional representation of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for inter-well to regional-scale reservoir simulation. Results could improve reservoir management through proper infill and extension drilling strategies, reduction of economic risks, increased recovery from existing oil fields, and more reliable reserve calculations. Technical progress this quarter is divided into regional stratigraphy, case studies, stochastic modeling and fluid-flow simulation, and technology transfer activities. The regional stratigraphy of the Ferron Sandstone outcrop belt from Last Chance Creek to Ferron Creek is being described and interpreted. Photomosaics and a database of existing surface and subsurface data are being used to determine the extent and depositional environment of each parasequence, and the nature of the contacts with adjacent rocks or flow units. For the second field season, detailed geological and petrophysical characterization of the primary reservoir lithofacies typically found in a fluvial-dominated deltaic reservoir, is continuing at selected case-study areas.

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

    SciTech Connect

    Riley, Ronald; Wicks, John; Perry, Christopher

    2009-12-30

    The purpose of this study was to evaluate the efficacy of using CO2-enhanced oil recovery (EOR) in the East Canton oil field (ECOF). Discovered in 1947, the ECOF in northeastern Ohio has produced approximately 95 million barrels (MMbbl) of oil from the Silurian “Clinton” sandstone. The original oil-in-place (OOIP) for this field was approximately 1.5 billion bbl and this study estimates by modeling known reservoir parameters, that between 76 and 279 MMbbl of additional oil could be produced through secondary recovery in this field, depending on the fluid and formation response to CO2 injection. A CO2 cyclic test (“Huff-n-Puff”) was conducted on a well in Stark County to test the injectivity in a “Clinton”-producing oil well in the ECOF and estimate the dispersion or potential breakthrough of the CO2 to surrounding wells. Eighty-one tons of CO2 (1.39 MMCF) were injected over a 20-hour period, after which the well was shut in for a 32-day “soak” period before production was resumed. Results demonstrated injection rates of 1.67 MMCF of gas per day, which was much higher than anticipated and no CO2 was detected in gas samples taken from eight immediately offsetting observation wells. All data collected during this test was analyzed, interpreted, and incorporated into the reservoir characterization study and used to develop the geologic model. The geologic model was used as input into a reservoir simulation performed by Fekete Associates, Inc., to estimate the behavior of reservoir fluids when large quantities of CO2 are injected into the “Clinton” sandstone. Results strongly suggest that the majority of the injected CO2 entered the matrix porosity of the reservoir pay zones, where it diffused into the oil. Evidence includes: (A) the volume of injected CO2 greatly exceeded the estimated capacity of the hydraulic fracture and natural fractures; (B) there was a gradual injection and pressure rate build-up during the test; (C) there was a subsequent

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

    SciTech Connect

    Ronald Riley; John Wicks; Christopher Perry

    2009-12-30

    The purpose of this study was to evaluate the efficacy of using CO2-enhanced oil recovery (EOR) in the East Canton oil field (ECOF). Discovered in 1947, the ECOF in northeastern Ohio has produced approximately 95 million barrels (MMbbl) of oil from the Silurian 'Clinton' sandstone. The original oil-in-place (OOIP) for this field was approximately 1.5 billion bbl and this study estimates by modeling known reservoir parameters, that between 76 and 279 MMbbl of additional oil could be produced through secondary recovery in this field, depending on the fluid and formation response to CO2 injection. A CO2 cyclic test ('Huff-n-Puff') was conducted on a well in Stark County to test the injectivity in a 'Clinton'-producing oil well in the ECOF and estimate the dispersion or potential breakthrough of the CO2 to surrounding wells. Eighty-one tons of CO2 (1.39 MMCF) were injected over a 20-hour period, after which the well was shut in for a 32-day 'soak' period before production was resumed. Results demonstrated injection rates of 1.67 MMCF of gas per day, which was much higher than anticipated and no CO2 was detected in gas samples taken from eight immediately offsetting observation wells. All data collected during this test was analyzed, interpreted, and incorporated into the reservoir characterization study and used to develop the geologic model. The geologic model was used as input into a reservoir simulation performed by Fekete Associates, Inc., to estimate the behavior of reservoir fluids when large quantities of CO2 are injected into the 'Clinton' sandstone. Results strongly suggest that the majority of the injected CO2 entered the matrix porosity of the reservoir pay zones, where it diffused into the oil. Evidence includes: (A) the volume of injected CO2 greatly exceeded the estimated capacity of the hydraulic fracture and natural fractures; (B) there was a gradual injection and pressure rate build-up during the test; (C) there was a subsequent, gradual flashout of

  13. Porosity evolution in reservoir sandstones in the West-Central San Joaquin basin, California

    SciTech Connect

    Horton, R.A. Jr.; McCullough, P.T.; Houghton, B.D.; Pennell, D.A.; Dunwoody, J.A. III; Menzie, R.J. Jr.

    1995-04-01

    Miocene reservoir sands (feldspathic and lithic arenites) in central San Joaquin basin oil fields show similar trends in porosity development despite differences in depositional environment, pore-fluid chemistry, and burial history. Burial and tectonic compaction caused grain rotation, deformation of altered lithics, and extensive fracturing of brittle grains, thereby eliminating most primary porosity. Diagenetic fluids, infiltrating along fractures in grains, reacted with freshly exposed mineral surfaces causing extensive leaching of framework components. All major grain types were affected but preferential removal of feldspars and lithics resulted in changes in QFL ratios. With continued compaction angular remnants of partially disolved grains were rotated and rearranged while secondary intergranular and moldic porosity collapsed to form secondary intergranular porosity. This resulted in reservoir sands that are less well sorted, more angular, and mineralogically more mature than they were at deposition. Such changes appear to widespread in the San Joaquin basin and may be more important than is generally acknowledged.

  14. Geological and petrophysical characterization of the Ferron Sandstone for 3-D simulation of a fluvial-deltaic reservoir. Quarterly technical progress report, January 1--March 31, 1997

    SciTech Connect

    Allison, M.L.

    1997-04-01

    The objective of this project is to develop a comprehensive, interdisciplinary, and quantitative characterization of a fluvial-deltaic reservoir which will allow realistic inter-well and reservoir-scale modeling to be constructed for improved oil-field development in similar reservoirs world-wide. The geological and petrophysical properties of the Cretaceous Ferron Sandstone in east-central Utah will be quantitatively determined. Both new and existing data will be integrated into a three-dimensional representation of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for inter-well to regional-scale reservoir simulation. Results could improve reservoir management through proper infill and extension drilling strategies, reduction of economic risks, increased recovery from existing oil fields, and more reliable reserve calculations. Transfer of the project results to the petroleum industry is an integral component of the project.

  15. Geological and petrophysical characterization of the Ferron Sandstone for 3-D simulation of a fluvial-deltaic reservoir. Quarterly progress report, January 1, 1997--March 31, 1997

    SciTech Connect

    Allison, M.L.

    1997-05-01

    The objective of this project is to develop a comprehensive, interdisciplinary, and quantitative characterization of a fluvial-deltaic reservoir which will allow realistic inter-well and reservoir-scale modeling to be constructed for improved oil-field development in similar reservoirs world-wide. The geological and petrophysical properties of the Cretaceous Ferron Sandstone in east-central Utah will be quantitatively determined. Both new and existing data will be integrated into a three-dimensional representation of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for inter-well to regional-scale reservoir simulation. Results could improve reservoir management through proper infill and extension drilling strategies, reduction of economic risks, increased recovery from existing oil fields, and more reliable reserve calculations. Transfer of the project results to the petroleum industry is an integral component of the project.

  16. Geological and petrophysical characterization of the Ferron Sandstone for 3-D simulation of a fluvial-deltaic reservoir. Technical progress report, January 1, 1995--March 31, 1995

    SciTech Connect

    Allison, M.L.

    1995-05-02

    The objective of this project is to develop a comprehensive, interdisciplinary, and quantitative characterization of a fluvial-deltaic reservoir which will allow realistic inter-well and reservoir-scale modeling to be developed for improved oil-field development in similar reservoirs world-wide. The geological and petrophysical properties of the Cretaceous Ferron Sandstone in east-central Utah will be quantitatively determined. Both new and existing data will be integrated into a three-dimensional representation of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for inter-well to regional-scale reservoir simulation. Results could improve reservoir management through proper infill and extension drilling strategies, reduction of economic risks, increased recovery from existing oil fields, and more reliable reserve calculations. Transfer of the project results to the petroleum industry is an integral component of the project.

  17. Geological and petrophysical characterization of the Ferron Sandstone for 3-D simulation of a fluvial-deltaic reservoir. Quarterly report, July 1--September 30, 1994

    SciTech Connect

    Allison, M.L.

    1994-10-30

    The objective of this project is to develop a comprehensive, interdisciplinary, and quantitative characterization of a fluvial-deltaic reservoir which will allow realistic inter-well and reservoir-scale modeling to be developed for improved oil-field development in similar reservoirs world-wide. The geological and petrophysical properties of the Cretaceous Ferron Sandstone in east-central Utah will be quantitatively determined. Both new and existing data will be integrated into a 3-D representation of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for inter-well to regional-scale reservoir simulation. Results could improve reservoir management through proper infill and extension drilling strategies, reduction of economic risks, increased recovery from existing oil fields, and more reliable reserve calculations. Transfer of the project results to the petroleum industry is an integral component of the project.

  18. Geological and petrophysical characterization of the Ferron Sandstone for 3-D simulation of a fluvial-deltaic reservoir. Technical progress report, July 1, 1996--September 30, 1996

    SciTech Connect

    Allison, M.L.

    1996-10-01

    The objective of this project is to develop a comprehensive, interdisciplinary, and quantitative characterization of a fluvial-deltaic reservoir which will allow realistic inter-well and reservoir-scale modeling to be constructed for improved oil-field development in similar reservoirs world-wide. The geological and petrophysical properties of the Cretaceous Ferron Sandstone in east-central Utah will be quantitatively determined. Both new and existing data will be integrated into a three-dimensional representation of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for inter-well to regional-scale reservoir simulation. Results could improve reservoir management through proper infill and extension drilling strategies, reduction of economic risks, increased recovery from existing oil fields, and more reliable reserve calculations. Transfer of the project results to the petroleum industry is an integral component of the project.

  19. Geological and petrophysical characterization of the Ferron Sandstone for 3-D simulation of a fluvial-deltaic reservoir. Quarterly progress report, October 1, 1997--December 31, 1997

    SciTech Connect

    Allison, M.L.

    1998-01-01

    The objective of this project is to develop a comprehensive, interdisciplinary, and quantitative characterization of a fluvial-deltaic reservoir which will allow realistic inter-well and reservoir-scale modeling to be constructed for improved oil-field development in similar reservoirs world-wide. The geological and petrophysical properties of the Cretaceous Ferron Sandstone in east-central Utah will be quantitatively determined. Both new and existing data will be integrated into a three-dimensional representation of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for inter-well to regional-scale reservoir simulation. Results could improve reservoir management through proper infill and extension drilling strategies, reduction of economic risks, increased recovery from existing oil fields, and more reliable reserve calculations. Transfer of the project results to the petroleum industry is an integral component of the project.

  20. 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.

  1. Geology and petrophysical characterization of the Ferron Sandstone for 3-D simulation of a fluvial-deltaic reservoir. Annual report, October 1, 1996--September 30, 1997

    SciTech Connect

    Chidsey, T.C. Jr.; Anderson, P.B.; Morris, T.H.; Dewey, J.A. Jr.; Mattson, A.; Foster, C.B.; Snelgrove, S.H.; Ryer, T.A.

    1998-05-01

    The objective of the Ferron Sandstone (Utah) project is to develop a comprehensive, interdisciplinary, quantitative characterization of a fluvial-deltaic reservoir to allow realistic interwell and reservoir-scale models to be developed for improved oil-field development in similar reservoirs world-wide. Both new and existing data is being integrated into a 3-D model of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for inter-well to regional-scale reservoir simulation. Simulation results could improve reservoir management through proper infill and extension drilling strategies, reduction of economic risks, increased recovery from existing oil fields, and more reliable reserve calculations. The project is divided into four tasks: (1) regional stratigraphic analysis, (2) case studies, (3) reservoirs models, and (4) field-scale evaluation of exploration strategies. The primary objective of the regional stratigraphic analysis is to provide a more detailed interpretation of the stratigraphy and gross reservoir characteristics of the Ferron Sandstone as exposed in outcrop. The primary objective of the case-studies work is to develop a detailed geological and petrophysical characterization, at well-sweep scale or smaller, of the primary reservoir lithofacies typically found in a fluvial-dominated deltaic reservoir. Work on tasks 3 and 4 consisted of developing two- and three-dimensional reservoir models at various scales. The bulk of the work on these tasks is being completed primarily during the last year of the project, and is incorporating the data and results of the regional stratigraphic analysis and case-studies tasks.

  2. Diagenesis of the Almond sandstone in the Washakie Basin

    SciTech Connect

    Yin, Peigui; Liu, Jie; Surdam, C.R. . Dept. of Geology and Geophysics)

    1992-01-01

    The marginal marine and nonmarine Almond sandstones are mostly sublitharenite, litharenite, and lithic arkose. The sandstones are fine-to very-fine-grained, and are well-sorted. The framework composition, authigenic minerals, and porosity and permeability distributions in the Almond sandstones are different below and above 8,000 feet, resulting in a variation in hydrocarbon reservoir types. The shallow conventional reservoirs are permeable, producing both liquid oil and gas, whereas the deep gas-bearing sandstones are very tight and overpressured. Porosity of the shallow Almond sandstones have been significantly enhanced by dissolution of the feldspar grains and lithic fragments. Quartz overgrowth cement and authigenic clay rims have occluded most of the intergranular pores, as well as the previously leached pores. The Almond sandstones have been buried deeper than their present depths. The sandstones in each part of the Washakie Basin have experienced different uplift and subsidence. Reconstruction of the burial history and diagenetic modeling are essential steps for understanding the diagenetic evolution of the Almond sandstones.

  3. Geological and petrophysical characterization of the Ferron Sandstone for 3-D simulation of a fluvial-deltaic reservoir. Annual report, September 29, 1993--September 29, 1994

    SciTech Connect

    Allison, M.

    1995-07-01

    The objective of the Ferron Sandstone project is to develop a comprehensive, interdisciplinary, quantitative characterization of a fluvial-deltaic reservoir to allow realistic inter-well and reservoir-scale models to be developed for improved oil-field development in similar reservoirs world-wide. Quantitative geological and petrophysical information on the Cretaceous Ferron Sandstone in east-central Utah will be collected. Both new and existing data will be integrated into a three-dimensional model of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for inter-well to regional-scale reservoir simulation. Simulation results could improve reservoir management through proper infill and extension drilling strategies, reduction of economic risks, increased recovery from existing oil fields, and more reliable reserve calculations. Transfer of the project results to the petroleum industry is an integral component of the project. This report covers research activities for fiscal year 1993-94, the first year of the project. Most work consisted of developing field methods and collecting large quantities of existing and new data. We also developed preliminary regional and case-study area interpretations. The project is divided into four tasks: (1) regional stratigraphic analysis, (2) case studies, (3) development of reservoirs models, and (4) field-scale evaluation of exploration strategies.

  4. Geological and petrophysical characterization of the ferron sandstone for 3-D simulation of a fluvial-deltaic reservoir. Annual report, October 1, 1994--September 30, 1995

    SciTech Connect

    Chidsey, T.C. Jr.; Allison, M.L.

    1996-05-01

    The objective of the Ferron Sandstone project is to develop a comprehensive, interdisciplinary, quantitative characterization of a fluvial-deltaic reservoir to allow realistic interwell and reservoir-scale models to be developed for improved oil-field development in similar reservoirs world-wide. Quantitative geological and petrophysical information on the Cretaceous Ferron Sandstone in east-central Utah was collected. Both new and existing data is being integrated into a three-dimensional model of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for inter-well to regional-scale reservoir simulation. Simulation results could improve reservoir management through proper infill and extension drilling strategies, reduction of economic risks, increased recovery from existing oil fields, and more reliable reserve calculations. Transfer of the project results to the petroleum industry is an integral component of the project. This report covers research activities for fiscal year 1994-95, the second year of the project. Most work consisted of developing field methods and collecting large quantities of existing and new data. We also continued to develop preliminary regional and case-study area interpretations. The project is divided into four tasks: (1) regional stratigraphic analysis, (2) case studies, (3) reservoirs models, and (4) field-scale evaluation of exploration strategies.

  5. Equation of state density models for hydrocarbons in ultradeep reservoirs at extreme temperature and pressure conditions

    NASA Astrophysics Data System (ADS)

    Wu, Yue; Bamgbade, Babatunde A.; Burgess, Ward A.; Tapriyal, Deepak; Baled, Hseen O.; Enick, Robert M.; McHugh, Mark A.

    2013-10-01

    The necessity of exploring ultradeep reservoirs requires the accurate prediction of hydrocarbon density data at extreme temperatures and pressures. In this study, three equations of state (EoS) models, Peng-Robinson (PR), high-temperature high-pressure volume-translated PR (HTHP VT-PR), and perturbed-chain statistical associating fluid theory (PC-SAFT) EoS are used to predict the density data for hydrocarbons in ultradeep reservoirs at temperatures to 523 K and pressures to 275 MPa. The calculated values are compared with experimental data. The results show that the HTHP VT-PR EoS and PC-SAFT EoS always perform better than the regular PR EoS for all the investigated hydrocarbons.

  6. Geological and petrophysical characterization of the Ferron Sandstone for 3-D simulation of a fluvial-deltaic reservoir. [Quarterly] report, January 1--March 31, 1994

    SciTech Connect

    Allison, M.L.

    1994-04-22

    The objective of this project is to develop a comprehensive, interdisciplinary, quantitative characterization of a fluvial-deltaic reservoir which will allow realistic interwell and reservoir-scale modeling to be used for improved oil-field development in similar reservoirs world wide. The geological and petrophysical properties of the Cretaceous Ferron Sandstone in east-central Utah will be quantitatively determined. Both new and existing data will be integrated into a 3-D representation of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for interwell to regional-scale reservoir simulation. Results could improve reservoir management through proper infill and extension drilling strategies, reduce economic risks, increase recovery from existing oil fields, and provide more reliable reserve calculations. Transfer of the project results to the petroleum industry will be an integral component of the project. The technical progress is divided into several sections corresponding to subtasks outlined in the Regional Stratigraphy Task and the Case Studies Task of the original proposal. The primary objective of the Regional Stratigraphy Task is to provide a more detailed interpretation of the stratigraphy of the Ferron Sandstone outcrop belt from Last Chance Creek to Ferron Creek. The morphological framework established from the case studies will be used to generate subsequent flow models for the reservoir types. The primary objective of the Case Study Task is to develop a detailed geological and petrophysical characterization, at well-sweep scale or smaller, of the primary reservoir lithofacies typically found in a fluvial-dominated deltaic reservoir. Sedimentary structures, lithofacies, bounding surfaces, and permeabilities measured along closely spaced traverses (both vertical and horizontal) will be combined with data from core drilling to develop a 3-D morphology of the reservoirs within each case study area.

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

    NASA Astrophysics Data System (ADS)

    Schmitt, Mayka; Halisch, Matthias; Müller, Cornelia; Peres Fernandes, Celso

    2016-02-01

    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 behavior of rock-fluid systems. With the availability of 3-D high-resolution imaging, such as x-ray micro-computed tomography (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 (length, width, and thickness) and a shape classification that involves the similarity of artificial objects, which is based on main pore network detachments and 3-D sample sizes. Two main pore components were identified from the analyzed volumes: pore networks and residual pore ganglia. A watershed algorithm was applied to preserve the pore morphology after separating the main pore networks, which is essential for the pore shape characterization. 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, ranging from 39.49 to 50.94 % and from 58.80 to 45.18 % when the Feret caliper descriptor was investigated in a 10003 voxel volume. 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.

  8. Prediction of reservoir quality and porosity basement in sandstones of the Pakawau and Kapuni groups, Taranaki basin, New Zealand - Preliminary results

    SciTech Connect

    Bloch, S.; Helmold, K.P. )

    1990-05-01

    Vitrinite reflectance porosity and porosity permeability relationships were established in 12 wells during a preliminary investigation of arkosic sandstones of the Pakawau and Kapuni groups (Late Cretaceous through Eocene) in the Taranaki basin of New Zealand. These relationships were used in conjunction with geohistory analysis to determine the economic basement and to predict porosity and permeability in the sandstones prior to drilling. Medium- to coarse-grained Kapuni and Pakawau sandstones, at vitrinite reflectance values of 0.65-0.70% R{sub 0} and higher, are not expected to have porosities and permeabilities greater than 10% and 1 md, respectively. Results obtained from a subsequently drilled well confirmed the validity of this approach. Meaningful reservoir quality predictions can be obtained only if (1) the lithological characteristics of the sandstones are accurately predicted from facies analysis, (2) the realistic input parameters, based on seismic stratigraphy and regional geologic interpretations, are used in basin modeling, and (3) the sandstones were not affected by hydrothermal activity associated with regional volcanism.

  9. Reservoir Characterization of Bridgeport and Cypress Sandstones in Lawrence Field Illinois to Improve Petroleum Recovery by Alkaline-Surfactant-Polymer Flood

    SciTech Connect

    Seyler, Beverly; Grube, John; Huff, Bryan; Webb, Nathan; Damico, James; Blakley, Curt; Madhavan, Vineeth; Johanek, Philip; Frailey, Scott

    2012-12-21

    Within the Illinois Basin, most of the oilfields are mature and have been extensively waterflooded with water cuts that range up to 99% in many of the larger fields. In order to maximize production of significant remaining mobile oil from these fields, new recovery techniques need to be researched and applied. The purpose of this project was to conduct reservoir characterization studies supporting Alkaline-Surfactant-Polymer Floods in two distinct sandstone reservoirs in Lawrence Field, Lawrence County, Illinois. A project using alkaline-surfactantpolymer (ASP) has been established in the century old Lawrence Field in southeastern Illinois where original oil in place (OOIP) is estimated at over a billion barrels and 400 million barrels have been recovered leaving more than 600 million barrels as an EOR target. Radial core flood analysis using core from the field demonstrated recoveries greater than 20% of OOIP. While the lab results are likely optimistic to actual field performance, the ASP tests indicate that substantial reserves could be recovered even if the field results are 5 to 10% of OOIP. Reservoir characterization is a key factor in the success of any EOR application. Reservoirs within the Illinois Basin are frequently characterized as being highly compartmentalized resulting in multiple flow unit configurations. The research conducted on Lawrence Field focused on characteristics that define reservoir compartmentalization in order to delineate preferred target areas so that the chemical flood can be designed and implemented for the greatest recovery potential. Along with traditional facies mapping, core analyses and petrographic analyses, conceptual geological models were constructed and used to develop 3D geocellular models, a valuable tool for visualizing reservoir architecture and also a prerequisite for reservoir simulation modeling. Cores were described and potential permeability barriers were correlated using geophysical logs. Petrographic analyses

  10. Sediment supply systems of the Champion "Delta" of NW Borneo: Implications for deepwater reservoir sandstones

    NASA Astrophysics Data System (ADS)

    Lambiase, Joseph J.; Cullen, Andrew B.

    2013-10-01

    Middle Miocene to Pliocene sedimentation on the NW Borneo margin has been interpreted as the product of one relatively large deltaic system, the Champion Delta. However, several lines of evidence indicate that the Champion system was not a simple, large delta; its drainage basin was too small, fluvial outcrops indicate multiple, relatively small rivers and outcrop studies indicate the same facies associations as the diverse, modern depositional systems. The number and location of rivers reaching the shoreline changed as rapidly subsiding footwall synclines, episodically active inversion anticlines and growth faults created an evolving structurally-generated topography that not only controlled drainage pathways, but also segregated Champion strata into thick, wave-dominant and tide-dominant successions. Although the principal rivers within the Champion system, the Limbang, Padas and Trusan Rivers, transport significant loads of coarse sediment, the intermittent proximal ponding of sand in local basins, as is currently occurring in Brunei Bay, resulted in a variable delivery of sand to the shelf edge. The number and distribution of shelf edge canyons also changed with time. Consequently, the spatial and temporal distribution of deepwater sand accumulations sourced from the Champion system are not solely related to relative sea level fluctuations; such accumulations should be smaller and more scattered than those sourced from a large shelf edge delta. Because the catchments of the Champion system's principal rivers represent different provenances, the system's deepwater sands may carry the signal of specific rivers. For example, mineralogical contrasts between in the main reservoir sands of the deepwater Gumusut and Kikeh fields suggest that the relative contributions of the principal rivers shifted with time with the Trusan and Limbang Rivers dominating sand supply for the youngest reservoirs at Gumusut.

  11. Geological and petrophysical characterization of the Ferron Sandstone for 3-D simulation of a fluvial-deltaic reservoir. Quarterly report, April 1--June 30, 1998

    SciTech Connect

    Chidsey, T.C. Jr.

    1998-07-01

    The objective of this project is to develop a comprehensive, interdisciplinary, and quantitative characterization of a fluvial-deltaic reservoir which will allow realistic inter-well and reservoir-scale modeling to be constructed for improved oil-field development in similar reservoirs world-wide. The geological and petrophysical properties of the Cretaceous Ferron Sandstone in east-central Utah will be quantitatively determined. Both new and existing data will be integrated into a three-dimensional representation of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for inter-well to regional-scale reservoir simulation. Results could improve reservoir management through proper infill and extension drilling strategies, reduction of economic risks, increased recovery from existing oil fields, and more reliable reserve calculations. Transfer of the project results to the petroleum industry is an integral component of the project. Two activities continued this quarter as part of the geological and petrophysical characterization of the fluvial-deltaic Ferron Sandstone: (1) preparation of the project final report and (2) technology transfer.

  12. Geological and petrophysical characterization of the Ferron Sandstone for 3-D simulation of a fluvial-deltaic reservoir. Quarterly report, July 1--September 30, 1997

    SciTech Connect

    Allison, M.L.

    1997-11-01

    The objective of this project is to develop a comprehensive, interdisciplinary, and quantitative characterization of a fluvial-deltaic reservoir which will allow realistic inter-well and reservoir-scale modeling to be constructed for improved oil-field development in similar reservoirs world-wide. The geological and petrophysical properties of the Cretaceous Ferron Sandstone in east-central Utah will be quantitatively determined. Both new and existing data will be integrated into a three-dimensional representation of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for inter-well to regional-scale reservoir simulation. Results could improve reservoir management through proper infill and extension drilling strategies, reduction of economic risks, increased recovery from existing oil fields, and more reliable reserve calculations. Two activities continued this quarter as part of the geological and petrophysical characterization of the fluvial-deltaic Ferron Sandstone: (1) evaluation of the Ivie Creek and Willow Springs Wash case-study areas and (2) technology transfer.

  13. Geological and petrophysical characterization of the Ferron Sandstone for 3-D simulation of a fluvial-deltaic reservoir. Technical progress report, October 1--December 1997

    SciTech Connect

    Allison, M.L.

    1998-01-01

    The objective of this project is to develop a comprehensive, interdisciplinary, and quantitative characterization of a fluvial-deltaic reservoir which will allow realistic inter-well and reservoir-scale modeling to be constructed for improved oil-field development in similar reservoirs world-wide. The geological and petrophysical properties of the Cretaceous Ferron Sandstone in east-central Utah will be quantitatively determined. Both new and existing data will be integrated into a three-dimensional representation of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for inter-well to regional-scale reservoir simulation. Results could improve reservoir management through proper infill and extension drilling strategies, reduction of economic risks, increased recovery from existing oil fields, and more reliable reserve calculations. Transfer of the project results to the petroleum industry is an integral component of the project. Two activities continued this quarter as part of the geological and petrophysical characterization of the fluvial-deltaic Ferron Sandstone and are described within: (1) regional stratigraphic interpretation and (2) technology transfer.

  14. Hydrocarbon Reservoir Prediction Using Bi-Gaussian S Transform Based Time-Frequency Analysis Approach

    NASA Astrophysics Data System (ADS)

    Cheng, Z.; Chen, Y.; Liu, Y.; Liu, W.; Zhang, G.

    2015-12-01

    Among those hydrocarbon reservoir detection techniques, the time-frequency analysis based approach is one of the most widely used approaches because of its straightforward indication of low-frequency anomalies from the time-frequency maps, that is to say, the low-frequency bright spots usually indicate the potential hydrocarbon reservoirs. The time-frequency analysis based approach is easy to implement, and more importantly, is usually of high fidelity in reservoir prediction, compared with the state-of-the-art approaches, and thus is of great interest to petroleum geologists, geophysicists, and reservoir engineers. The S transform has been frequently used in obtaining the time-frequency maps because of its better performance in controlling the compromise between the time and frequency resolutions than the alternatives, such as the short-time Fourier transform, Gabor transform, and continuous wavelet transform. The window function used in the majority of previous S transform applications is the symmetric Gaussian window. However, one problem with the symmetric Gaussian window is the degradation of time resolution in the time-frequency map due to the long front taper. In our study, a bi-Gaussian S transform that substitutes the symmetric Gaussian window with an asymmetry bi-Gaussian window is proposed to analyze the multi-channel seismic data in order to predict hydrocarbon reservoirs. The bi-Gaussian window introduces asymmetry in the resultant time-frequency spectrum, with time resolution better in the front direction, as compared with the back direction. It is the first time that the bi-Gaussian S transform is used for analyzing multi-channel post-stack seismic data in order to predict hydrocarbon reservoirs since its invention in 2003. The superiority of the bi-Gaussian S transform over traditional S transform is tested on a real land seismic data example. The performance shows that the enhanced temporal resolution can help us depict more clearly the edge of the

  15. Geological and petrophysical characterization of the Ferron Sandstone for 3-D simulation of a fluvial-deltaic reservoir. Quarterly progress report, July 1--September 30, 1995

    SciTech Connect

    Allison, M.L.

    1995-10-30

    The objective of this project is to develop a comprehensive, interdisciplinary, and quantitative characterization of a fluvial-deltaic reservoir which will allow realistic inter-well and reservoir-scale modeling to be constructed for improved oil-field development in similar reservoirs world-wide. The geological and petrophysical properties of the Cretaceous Ferron Sandstone in east-central Utah will be quantitatively determined. Both new and existing data will be integrated into a three-dimensional representation of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for inter-well to regional-scale reservoir simulation. Results could improve reservoir management through proper infill and extension drilling strategies, reduction of economic risks, increased recovery from existing oil fields, and more reliable reserve calculations. Transfer of the project results to the petroleum industry is an integral component of the project. Technical progress this quarter is divided into regional stratigraphy, case studies, stochastic modeling and fluid-flow simulation, and technology transfer activities. The regional stratigraphy of the Ferron Sandstone outcrop belt is being described and interpreted. Detailed geological and petrophysical characterization of the primary reservoir lithofacies typically found in a fluvial-dominated deltaic reservoir, is continuing at selected case-study areas. Interpretations of lithofacies, bounding surfaces, and other geologic information are being combined with permeability measurements from closely spaced traverses and from drill-hole cores (existing and two drilled during the quarter). Petrophysical and statistical analyses are being incorporated with the geological characterization to develop a three-dimensional model of the reservoirs through fluid-flow simulation.

  16. Imaging Sand Bars using 3D GPR in an Outcrop Reservoir Analog: Cretaceous Ferron Sandstone, South-East Utah

    NASA Astrophysics Data System (ADS)

    Aziz, A. S.; Stewart, R. R.; Ullah, M. S.; Bhattacharya, J.

    2015-12-01

    Outcrop analog studies provide crucial information on geometry and facies patterns to improve the understanding of the complex subsurface reservoir architecture for enhanced oil recovery (EOR) planning during field development. Ground-penetrating radar (GPR) has greatly facilitated analog outcrop study progress by bridging the gap in image resolution between seismic and well data. A 3D GPR survey was conducted to visualize architectural elements of friction-dominated distributary mouth bars within proximal delta front deposits in Cretaceous Ferron Sandstone at the top of the Notom Delta in south-east Utah. Sensors and Software's Noggin 250 MHz system was used over a 25 m x 15 m grid. We employed a spatial sampling of 0.5 m for the inline (dip direction) and 1.5 m for the crossline (strike direction). Standard processing flows including time-zero correction, dewow, gain, background subtraction and 2D migration were used to increase the signal-to-noise ratio. Formation velocity estimates from the hyperbola matching yielded 0.131 m/ns which is comparable to the literature velocity of about 0.125 m/ns. The calculated average dielectric constant (directly related to volumetric water content) is 5.2 matches unsaturated sandstone. The depth of GPR penetration is limited to approximately 3 m - likely due to the compaction/carbonate cementation in the rock and interbedded layers of finer-grained material contributing to higher attenuation of the GPR signal. The vertical resolution is about 0.125 m, enabling the imaging of the dune-scale cross sets (15-20 cm thickness). Calculation of the medium porosity via an adapted Wyllie Time Average equation yields 7.8 % which is consistent with the average porosity (5-10%) obtained from the literature. Bedding diagrams from local cliff exposures in the previous studies show gently NE dipping accretion of single large foresets that were interpreted as small-scale unit bars, the amalgamation of which resulted in the progradation of

  17. New Hydrocarbon Degradation Pathways in the Microbial Metagenome from Brazilian Petroleum Reservoirs

    PubMed Central

    Sierra-García, Isabel Natalia; Correa Alvarez, Javier; Pantaroto de Vasconcellos, Suzan; Pereira de Souza, Anete; dos Santos Neto, Eugenio Vaz; de Oliveira, Valéria Maia

    2014-01-01

    Current knowledge of the microbial diversity and metabolic pathways involved in hydrocarbon degradation in petroleum reservoirs is still limited, mostly due to the difficulty in recovering the complex community from such an extreme environment. Metagenomics is a valuable tool to investigate the genetic and functional diversity of previously uncultured microorganisms in natural environments. Using a function-driven metagenomic approach, we investigated the metabolic abilities of microbial communities in oil reservoirs. Here, we describe novel functional metabolic pathways involved in the biodegradation of aromatic compounds in a metagenomic library obtained from an oil reservoir. Although many of the deduced proteins shared homology with known enzymes of different well-described aerobic and anaerobic catabolic pathways, the metagenomic fragments did not contain the complete clusters known to be involved in hydrocarbon degradation. Instead, the metagenomic fragments comprised genes belonging to different pathways, showing novel gene arrangements. These results reinforce the potential of the metagenomic approach for the identification and elucidation of new genes and pathways in poorly studied environments and contribute to a broader perspective on the hydrocarbon degradation processes in petroleum reservoirs. PMID:24587220

  18. New hydrocarbon degradation pathways in the microbial metagenome from Brazilian petroleum reservoirs.

    PubMed

    Sierra-García, Isabel Natalia; Correa Alvarez, Javier; de Vasconcellos, Suzan Pantaroto; Pereira de Souza, Anete; dos Santos Neto, Eugenio Vaz; de Oliveira, Valéria Maia

    2014-01-01

    Current knowledge of the microbial diversity and metabolic pathways involved in hydrocarbon degradation in petroleum reservoirs is still limited, mostly due to the difficulty in recovering the complex community from such an extreme environment. Metagenomics is a valuable tool to investigate the genetic and functional diversity of previously uncultured microorganisms in natural environments. Using a function-driven metagenomic approach, we investigated the metabolic abilities of microbial communities in oil reservoirs. Here, we describe novel functional metabolic pathways involved in the biodegradation of aromatic compounds in a metagenomic library obtained from an oil reservoir. Although many of the deduced proteins shared homology with known enzymes of different well-described aerobic and anaerobic catabolic pathways, the metagenomic fragments did not contain the complete clusters known to be involved in hydrocarbon degradation. Instead, the metagenomic fragments comprised genes belonging to different pathways, showing novel gene arrangements. These results reinforce the potential of the metagenomic approach for the identification and elucidation of new genes and pathways in poorly studied environments and contribute to a broader perspective on the hydrocarbon degradation processes in petroleum reservoirs. PMID:24587220

  19. Petrophysical characteristics and fluid flow zones in the Buntsandstein sandstones reservoir according well cores and outcrop analysis (Upper Rhine Graben, France)

    NASA Astrophysics Data System (ADS)

    Sébastien, H.; Géraud, Y.; Diraison, M.; Dezayes, C.

    2012-04-01

    Buntsandstein Sandstones (Lower Triassic), located in the Upper Rhine Graben, appears as an easy target for geothermal exploitation. This sedimentary reservoir links more or less permeable argillaceous sandstones intersected by many major faults to the regional thermal anomaly. Petrophysical analysis (permeability, porosity, thermal conductivity, P-wave velocity), performed on cores from several boreholes and samples from several outcrops in the Vosgian Mountain, drive us to characterise fluid and heat transfer capability of the different sedimentary facies present in the Buntsandstein sandstones. First data from well cores analysis indicate that the more permeable and porous (respectively >100mD & >15%) facies are the Playa Lake and fluvial and aeolian sand-sheet, and the fluvial-aeolian marginal erg, whereas the more common facies, the braided rivers within arid alluvial plain, presents permeability <10mD and porosity <10%. Thermal conductivities present high heterogeneities and values range between 1 and 5 W/m/K and their detailed analysis according a new proposed method, drive us to determine fluid flow at formation scale: major fault drive hot fluid flow and feed permeable levels. Second, outcrop analysis allows us to analysis fracturation dispersion and petrophysical modifications induced by fracture and fault in the sandstone series. Barite and quartz precipitation in fracture indicate us fracture orientation and position, compare to major fault position, in which fluid flow has occurs. All data acquired allow us to build a schematic geological block model: this block represent the Buntsandstein sandstone reservoir at depth with the different facies, above the Palaeozoic Granit and below the Muschelkalk limestones, intersecting by faults according the regional major azimuth. According each particular direction the particular fracturation is raised according outcrop data. This bloc points the major zones in which fluid circulation occurs.

  20. 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.

  1. Geological and petrophysical characterization of the Ferron sandstone for 3-D simulation of a fluvial-deltaic reservoir. [Quarterly progress report], October 1--December 31, 1995

    SciTech Connect

    Allison, M.L.

    1995-12-31

    The objective of this project is to develop a comprehensive, interdisciplinary, and quantitative characterization of a fluvial-deltaic reservoir which will allow realistic inter-well and reservoir-scale modeling to be constructed for improved oil-field development in similar reservoirs world-wide. The geological and petrophysical properties of the Cretaceous Ferron Sandstone in east-central Utah will be quantitatively determined. Both new and existing data will be integrated into a three-dimensional representation of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for inter-well to regional-scale reservoir simulation. Results could improve reservoir management through proper infill and extension drilling strategies, reduction of economic risks, increased recovery from existing oil fields, and more reliable reserve calculations. Technical progress this quarter is divided into regional stratigraphy, case studies, and technology transfer activities. The Kf-2 contains more and cleaner sand, indicating a more wave-modified environment of deposition. The regional stratigraphy of the Ferron Sandstone outcrop belt from Last Chance Creek to Ferron Creek was described and interpreted. Photomosaics and a database of existing surface and subsurface data are being used to determine the extent and depositional environment of each parasequence, and the nature of the contacts with adjacent rocks or flow units. Detailed geological and petrophysical characterization of the primary reservoir lithofacies typically found in a fluvial-dominated deltaic reservoir, is continuing at selected case-study areas. Interpretations of lithofacies, bounding surfaces, and other geologic information are being combined with permeability measurements from closely spaced traverses and from drill-hole cores (described this quarter).

  2. Characteristics of sedimentary polycyclic aromatic hydrocarbons (PAHs) in the subtropical Feitsui Reservoir, Taiwan

    NASA Astrophysics Data System (ADS)

    Fan, Cheng-Wei; Yang, Tien-Nan; Kao, Shuh-Ji

    2010-09-01

    SummaryPolycyclic aromatic hydrocarbons (PAHs) are usually loaded through atmospheric deposition into a water body and eventually into sediments. We study the PAHs from a 22-cm sediment core collected from the subtropical Feitsui Reservoir in Taiwan, and find the PAHs deposition characteristics in the reservoir, the man-made water body, is different from those in natural water bodies. The surficial sedimentary PAH fluxes are significantly higher than those in the European high altitude mountain lakes and those in the northeastern USA urban/industrial lakes. However, the catchment-corrected PAH fluxes normalized by the ratios of the catchment area to the water surface area are comparable to those of remote lakes in Europe and USA, suggesting the sedimentary PAHs in the reservoir is fluvial dominated, i.e., the reservoir system concentrated the atmospheric PAHs from the catchment area into the sediments. PAHs distribution found in the Feitsui Reservoir indicates both biogenic and anthropogenic origins. We also find the vehicular transport upstream of the reservoir is likely one of the PAHs sources to this reservoir.

  3. Influence of composition and temperature on hydrocarbon migration through Morrow fluvial reservoirs, Las Animas Arch, Colorado

    SciTech Connect

    Bolyard, D.W.

    1995-06-01

    Precipitation of wax in pores may impair permeability and prohibit the flow of oil. Crude oil composition and temperature are the most important controlling factors. Oils are chemically complex, may contain up to 45 wax compounds and may vary significantly even in the same pool. High-wax oils are common in the Morrow of eastern Colorado. Narrow fluvial sandstones provide migration paths toward the Las Animas Arch from adjacent basins. Temperatures range from less than 110{degrees}F. on the top of the arch to 180{degrees}F at a structural position only 1,400 feet lower. A range of 30{degrees}F has been observed in individual pools. Wax has precipitated in the 120-140{degrees}F range, creating relative permeability barriers which cut across the sandstones. Wax barriers are impermeable to oil, but may be permeable to gas and water. They account for certain dry holes with high porosity, permeability and oil saturation (and low water saturation) in both core and electrical log analysis. They explain why some oil wells with impaired permeability are adjacent to structurally lower gas wells with good permeability. A network of wax barriers around the Las Animas Arch accounts for approximately 300 feet of variation in the structural position of a line separating oil from gas fields. Since the low temperature bands may be short and discontinuous, wax barriers are more effective in narrow fluvial reservoirs than in blanket reservoirs.

  4. Frisco City sandstone: Upper Jurassic play in southern Alabama

    SciTech Connect

    Montgomery, S.L.; Baria, L.R.; Handford, C.R.

    1997-10-01

    The Frisco City sandstone play in southern Alabama is an example of hydrocarbon entrapment on the flanks of basement erosional features, with principal reservoirs occurring in proximal alluvial-fan to marine shoreface facies. Productive fields are developed on four-way closures of complex geometry, with reservoir sandstones showing maximum thickness along the margins of basement highs that are roughly 1.3-5.18 km{sup 2} in size and have 136-151 m of relief. Detailed analysis of sandstone facies indicates a downdip progression from alluvial-fan through wadi, eolian, beach, tidal-flat, and shoreface deposits. A sequence stratigraphic model based on identification of backstepping strata representing successive transgressive events is useful in predicting maximum reservoir occurrence in the vicinity of inselbergs. Reservoir quality in productive sandstones is high, with porosities ranging from 13 to 27% and permeabilities of 50 md to 5 d. Hydrocarbon occurrence is related to the distribution of high-quality source rock in the Smackover Formation and to maturation history.

  5. Temperature and injection water source influence microbial community structure in four Alaskan North Slope hydrocarbon reservoirs

    PubMed Central

    Piceno, Yvette M.; Reid, Francine C.; Tom, Lauren M.; Conrad, Mark E.; Bill, Markus; Hubbard, Christopher G.; Fouke, Bruce W.; Graff, Craig J.; Han, Jiabin; Stringfellow, William T.; Hanlon, Jeremy S.; Hu, Ping; Hazen, Terry C.; Andersen, Gary L.

    2014-01-01

    A fundamental knowledge of microbial community structure in petroleum reservoirs can improve predictive modeling of these environments. We used hydrocarbon profiles, stable isotopes, and high-density DNA microarray analysis to characterize microbial communities in produced water from four Alaskan North Slope hydrocarbon reservoirs. Produced fluids from Schrader Bluff (24–27°C), Kuparuk (47–70°C), Sag River (80°C), and Ivishak (80–83°C) reservoirs were collected, with paired soured/non-soured wells sampled from Kuparuk and Ivishak. Chemical and stable isotope data suggested Schrader Bluff had substantial biogenic methane, whereas methane was mostly thermogenic in deeper reservoirs. Acetoclastic methanogens (Methanosaeta) were most prominent in Schrader Bluff samples, and the combined δD and δ13C values of methane also indicated acetoclastic methanogenesis could be a primary route for biogenic methane. Conversely, hydrogenotrophic methanogens (e.g., Methanobacteriaceae) and sulfide-producing Archaeoglobus and Thermococcus were more prominent in Kuparuk samples. Sulfide-producing microbes were detected in all reservoirs, uncoupled from souring status (e.g., the non-soured Kuparuk samples had higher relative abundances of many sulfate-reducers compared to the soured sample, suggesting sulfate-reducers may be living fermentatively/syntrophically when sulfate is limited). Sulfate abundance via long-term seawater injection resulted in greater relative abundances of Desulfonauticus, Desulfomicrobium, and Desulfuromonas in the soured Ivishak well compared to the non-soured well. In the non-soured Ivishak sample, several taxa affiliated with Thermoanaerobacter and Halomonas predominated. Archaea were not detected in the deepest reservoirs. Functional group taxa differed in relative abundance among reservoirs, likely reflecting differing thermal and/or geochemical influences. PMID:25147549

  6. Temperature and injection water source influence microbial community structure in four Alaskan North Slope hydrocarbon reservoirs.

    PubMed

    Piceno, Yvette M; Reid, Francine C; Tom, Lauren M; Conrad, Mark E; Bill, Markus; Hubbard, Christopher G; Fouke, Bruce W; Graff, Craig J; Han, Jiabin; Stringfellow, William T; Hanlon, Jeremy S; Hu, Ping; Hazen, Terry C; Andersen, Gary L

    2014-01-01

    A fundamental knowledge of microbial community structure in petroleum reservoirs can improve predictive modeling of these environments. We used hydrocarbon profiles, stable isotopes, and high-density DNA microarray analysis to characterize microbial communities in produced water from four Alaskan North Slope hydrocarbon reservoirs. Produced fluids from Schrader Bluff (24-27°C), Kuparuk (47-70°C), Sag River (80°C), and Ivishak (80-83°C) reservoirs were collected, with paired soured/non-soured wells sampled from Kuparuk and Ivishak. Chemical and stable isotope data suggested Schrader Bluff had substantial biogenic methane, whereas methane was mostly thermogenic in deeper reservoirs. Acetoclastic methanogens (Methanosaeta) were most prominent in Schrader Bluff samples, and the combined δD and δ(13)C values of methane also indicated acetoclastic methanogenesis could be a primary route for biogenic methane. Conversely, hydrogenotrophic methanogens (e.g., Methanobacteriaceae) and sulfide-producing Archaeoglobus and Thermococcus were more prominent in Kuparuk samples. Sulfide-producing microbes were detected in all reservoirs, uncoupled from souring status (e.g., the non-soured Kuparuk samples had higher relative abundances of many sulfate-reducers compared to the soured sample, suggesting sulfate-reducers may be living fermentatively/syntrophically when sulfate is limited). Sulfate abundance via long-term seawater injection resulted in greater relative abundances of Desulfonauticus, Desulfomicrobium, and Desulfuromonas in the soured Ivishak well compared to the non-soured well. In the non-soured Ivishak sample, several taxa affiliated with Thermoanaerobacter and Halomonas predominated. Archaea were not detected in the deepest reservoirs. Functional group taxa differed in relative abundance among reservoirs, likely reflecting differing thermal and/or geochemical influences. PMID:25147549

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

    USGS Publications Warehouse

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

    2012-01-01

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

  8. Time-Lapse inversion of EM Tomography data for polymer-injected hydrocarbon reservoirs

    NASA Astrophysics Data System (ADS)

    Cheon, Seiwook; Park, Chanho; Nam, Myung Jin; Son, Jeong-Sul

    2015-04-01

    Polymer flooding is a method to increase the production of hydrocarbon reservoir by injecting polymer solution into the reservoir. For a study on the monitoring fluid variation within the reservoir, we first make analysis on seismic- and electromagnetic (EM)- tomography responses for seismic and electrical-resistivity rock physics models (RPMs) of the reservoir considering polymer fluid. Constructing RPMs are dependent on not only geologic characteristics of reservoir but also reservoir parameters such as fluid-type, fluid saturation, pressure and temperature. When making RPM for monitoring analysis, we assume the geology does not changes while reservoir parameters change to affect responses of seismic and EM tomography data. Specifically when constructing electrical-resistivity RPM, we consider three different types of hydrocarbon reservoirs, which are clean sand, shaly sand, sand-shale lamination, while considering two different types of waters (fresh water and salt water) to make 2wt% polymer solution. To compute time lapse EM and seismic tomography responses for corresponding RPMs of polymer-injected reservoirs, we used 2.5D finite element EM modeling algorithm and staggered-grid finite difference elastic modeling algorithm, respectively. Comparison between sensitivities of seismic and EM tomography to polymer injection confirms that EM tomography is more sensitivity to the polymer injection. For the evaluation of the potential of EM tomography to monitor polymer flooding, this study subsequently develops an efficient time-lapse EM tomography inversion algorithm based on the 2.5D EM tomography modeling. Using the inversion algorithm, we inverted the time-lapse EM tomography data to construct true resistivity models of polymer-injected reservoirs and analyze differences between them. From the time-lapse inversion results, we can observe the differences in time lapse responses between using fresh water and salt water have been decreased in the inverted time

  9. Determining between-well reservoir architecture in deltaic sandstones using only well data: Oligocene Frio formation, Tijerina-Canales-Blucher field, South Texas

    SciTech Connect

    Knox, P.R.

    1996-09-01

    Accurate prediction of compartment architecture and intra-compartment heterogeneity is necessary to locate and recover the estimated 15 billion barrels of mobile oil remaining in U.S. fluvial-dominated deltaic reservoirs. Complex architecture and rapid lateral variability in such reservoirs complicate subsurface prediction, particularly in mature fields where well logs are the only available subsurface data. A genetic-stratigraphy-based methodology has been developed that improves between-well prediction of deltaic reservoir architecture and, thus, reduces risks associated with infill-drilling. In the area of Tijerina-Canales-Blucher (T-C-B) field, the productive 3rd-order Lower Frio unit was subdivided into eight 4th-order genetic units. Delta-front positions were identified on the basis of regional and subregional cross sections. The 4th-order units (30 to 80 ft thick) were subdivided into two five 5th-order units (10 to 30 ft thick). Log patterns and n sandstone maps were used to identify facies, which include (1) distributary channels (up to 25 ft thick, <1,000 to >8,000 ft wide, and commonly narrower than 40-acre well spacing), (2) mouth bars (up to 15 ft thick, ranging in size from 40 to 640 acres in area, commonly <320 acres), (3) bayfill splays (up to 10 ft thick, 20 to 700 acres in area, and commonly <160 acres), (4) wave-reworked delta fronts (up to 35 ft thick, and >5,000 ft wide), and (5) washover fans (up to 10 ft thick, and 7,000 ft wide). Many reservoir compartments, including the prolific 21-B interval, contain a significant degree of stratigraphic trapping caused by updip pinchout of delta front or washover sandstones or convex-updip segments of meandering distributary channel sandstones. The methodology and results of this study are directly applicable to other Gulf Coast fluvial-deltaic reservoirs in the Frio Formation and Wilcox Group, as well as to deltaic reservoirs throughout the U.S.

  10. Revitalizing a mature oil play: Strategies for finding and producing unrecovered oil in frio fluvial-deltaic sandstone reservoirs at South Texas. Annual report, October 1994--October 1995

    SciTech Connect

    Holtz, M.; Knox, P.; McRae, L.

    1996-02-01

    The Frio Fluvial-Deltaic Sandstone oil play of South Texas has produced nearly 1 billion barrels of oil, yet it still contains about 1.6 billion barrels of unrecovered mobile oil and nearly the same amount of residual oil resources. Interwell-scale geologic facise models of Frio Fluvial-deltaic reservoirs are being combined with engineering assessments and geophysical evaluations in order to determine the controls that these characteristics exert on the location and volume or unrecovered mobile and residual oil. Progress in the third year centered on technology transfer. An overview of project tasks is presented.

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

    USGS Publications Warehouse

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

    2015-01-01

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

  12. Anisotropy and spatial variation of relative permeability and lithologic character of Tensleep Sandstone reservoirs in the Bighorn and Wind River basins, Wyoming. Final technical report, September 15, 1993--October 31, 1996

    SciTech Connect

    Dunn, T.L.

    1996-10-01

    This multidisciplinary study was designed to provide improvements in advanced reservoir characterization techniques. This goal was accomplished through: (1) an examination of the spatial variation and anisotropy of relative permeability in the Tensleep Sandstone reservoirs of Wyoming; (2) the placement of that variation and anisotropy into paleogeographic, and depositional regional frameworks; (3) the development of pore-system imagery techniques for the calculation of relative permeability; and (4) reservoir simulations testing the impact of relative permeability anisotropy and spatial variation on Tensleep Sandstone reservoir enhanced oil recovery. Concurrent efforts were aimed at understanding the spatial and dynamic alteration in sandstone reservoirs that is caused by rock-fluid interaction during CO{sub 2} enhanced oil recovery processes. The work focused on quantifying the interrelationship of fluid-rock interaction with lithologic characterization and with fluid characterization in terms of changes in chemical composition and fluid properties. This work establishes new criteria for the susceptibility of Tensleep Sandstone reservoirs to formation alteration that results in wellbore scale damage. This task was accomplished by flow experiments using core material; examination of regional trends in water chemistry; examination of local water chemistry trends the at field scale; and chemical modeling of both the experimental and reservoir systems.

  13. Anisotropy and spatial variation of relative permeability and lithologic character of Tensleep Sandstone reservoirs in the Bighorn and Wind River basins, Wyoming. Annual report, September 15, 1993--September 30, 1994

    SciTech Connect

    Dunn, T.L.

    1995-07-01

    The principal focus of this project is to evaluate the importance of relative permeability anisotropy with respect to other known geologic and engineering production concepts. This research is to provide improved strategies for enhanced oil recovery from the Tensleep Sandstone oil reservoirs in the Bighorn and Wind River basins, Wyoming. The Tensleep Sandstone contains the largest potential reserves within reservoirs which are candidates for EOR processes in the State of Wyoming. Although this formation has produced billions of barrels of oil, in some fields, as little as one in seven barrels of discovered oil is recoverable by current primary and secondary techniques. Because of the great range of {degree}API gravities of the oils produced from the Tensleep Sandstone reservoirs, the proposed study concentrates on establishing an understanding of the spatial variation and anisotropy of relative permeability within the Tensleep Sandstone. This research is to associate those spatial distributions and anisotropies with the depositional subfacies and zones of diagenetic alteration found within the Tensleep Sandstone. In addition, these studies are being coupled with geochemical modeling and coreflood experiments to investigate the potential for wellbore scaling and formation damage anticipated during EOR processes (e.g., C0{sub 2} flooding). This multidisciplinary project will provide a regional basis for EOR strategies which can be clearly mapped and efficiently applied to the largest potential target reservoir in the State of Wyoming. Additionally, the results of this study have application to all eolian reservoirs through the correlations of relative permeability variation and anisotropy with eolian depositional lithofacies.

  14. Results from probability-based, simplified, off-shore Louisiana CSEM hydrocarbon reservoir modeling

    NASA Astrophysics Data System (ADS)

    Stalnaker, J. L.; Tinley, M.; Gueho, B.

    2009-12-01

    Perhaps the biggest impediment to the commercial application of controlled-source electromagnetic (CSEM) geophysics marine hydrocarbon exploration is the inefficiency of modeling and data inversion. If an understanding of the typical (in a statistical sense) geometrical and electrical nature of a reservoir can be attained, then it is possible to derive therefrom a simplified yet accurate model of the electromagnetic interactions that produce a measured marine CSEM signal, leading ultimately to efficient modeling and inversion. We have compiled geometric and resistivity measurements from roughly 100 known, producing off-shore Louisiana Gulf of Mexico reservoirs. Recognizing that most reservoirs could be recreated roughly from a sectioned hemi-ellipsoid, we devised a unified, compact reservoir geometry description. Each reservoir was initially fit to the ellipsoid by eye, though we plan in the future to perform a more rigorous least-squares fit. We created, using kernel density estimation, initial probabilistic descriptions of reservoir parameter distributions, with the understanding that additional information would not fundamentally alter our results, but rather increase accuracy. From the probabilistic description, we designed an approximate model consisting of orthogonally oriented current segments distributed across the ellipsoid--enough to define the shape, yet few enough to be resolved during inversion. The moment and length of the currents are mapped to geometry and resistivity of the ellipsoid. The probability density functions (pdfs) derived from reservoir statistics serve as a workbench. We first use the pdfs in a Monte Carlo simulation designed to assess the detectability off-shore Louisiana reservoirs using magnitude versus offset (MVO) anomalies. From the pdfs, many reservoir instances are generated (using rejection sampling) and each normalized MVO response is calculated. The response strength is summarized by numerically computing MVO power, and that

  15. Geostatistics from Digital Outcrop Models of Outcrop Analogues for Hydrocarbon Reservoir Characterisation.

    NASA Astrophysics Data System (ADS)

    Hodgetts, David; Burnham, Brian; Head, William; Jonathan, Atunima; Rarity, Franklin; Seers, Thomas; Spence, Guy

    2013-04-01

    In the hydrocarbon industry stochastic approaches are the main method by which reservoirs are modelled. These stochastic modelling approaches require geostatistical information on the geometry and distribution of the geological elements of the reservoir. As the reservoir itself cannot be viewed directly (only indirectly via seismic and/or well log data) this leads to a great deal of uncertainty in the geostatistics used, therefore outcrop analogues are characterised to help obtain the geostatistical information required to model the reservoir. Lidar derived Digital Outcrop Model's (DOM's) provide the ability to collect large quantities of statistical information on the geological architecture of the outcrop, far more than is possible by field work alone as the DOM allows accurate measurements to be made in normally inaccessible parts of the exposure. This increases the size of the measured statistical dataset, which in turn results in an increase in statistical significance. There are, however, many problems and biases in the data which cannot be overcome by sample size alone. These biases, for example, may relate to the orientation, size and quality of exposure, as well as the resolution of the DOM itself. Stochastic modelling used in the hydrocarbon industry fall mainly into 4 generic approaches: 1) Object Modelling where the geology is defined by a set of simplistic shapes (such as channels), where parameters such as width, height and orientation, among others, can be defined. 2) Sequential Indicator Simulations where geological shapes are less well defined and the size and distribution are defined using variograms. 3) Multipoint statistics where training images are used to define shapes and relationships between geological elements and 4) Discrete Fracture Networks for fractures reservoirs where information on fracture size and distribution are required. Examples of using DOM's to assist with each of these modelling approaches are presented, highlighting the

  16. Temperatures of quartz cementation in Jurassic sandstones from the Norwegian continental shelf -- evidence from fluid inclusions

    SciTech Connect

    Walderhaug, O. )

    1994-04-01

    Recent studies of fluid inclusions in quartz overgrowths have shown quartz cementation to have taken place at temperatures within the range 60--145 C in several sandstones from the North Sea and offshore mid-Norway (Malley et al. 1986; Konnerup-Madsen and Dypvik 1988; Burley et al. 1989; Walderhaug 1990; Ehrenberg 1990; Saigal et al. 1992; Nedkvitne et al. 1993). This study aims at determining whether these results are typical for quartz cementation of sandstones by presenting homogenization temperatures for 274 aqueous and 366 hydrocarbon inclusions in quartz overgrowths from Jurassic reservoir sandstones on the Norwegian continental shelf, and by reviewing previously published fluid-inclusion data. Possible explanations for different ranges of homogenization temperatures in different sandstones are also discussed, and possible sources of quartz cement and the effect of hydrocarbon emplacement on quartz cementation are considered.

  17. Quantifying the Texture, Composition, and Coupled Chemical-Mechanical Diagenesis of Deformation Bands within Sandstone Reservoir Outcrop Analogs of Assorted Detrital Compositions, Southwestern USA

    NASA Astrophysics Data System (ADS)

    Elliott, S. J.; Eichhubl, P.

    2015-12-01

    In porous sandstones many factors including grain size, sorting, stress-state, and composition influence deformation mechanisms and resulting deformation band properties, especially those related to fluid flow. Using high resolution SEM-CL, EDS, and BSE images we quantitatively point counted various band types and their associated host rocks at the sub-micron scale, performed comprehensive grain size analyses on the undeformed host rocks, and calculated the total porosity lost through coupled chemical-mechanical means for each host rock and band. Our goals were to 1) determine the influence of detrital composition and texture [Cedar Mesa, Navajo, and Entrada sandstones] both on bands formed by different mechanisms and on bands formed by the same deformation mechanism at various stages of development, and to 2) assess the effects of coupled chemical-mechanical processes leading to deformation localization within these sandstone reservoir outcrop analogs. Analyzed samples include a non-cataclastic disaggregation band, a non-cataclastic pressure solution band, and single, multistrand, and clustered cataclastic bands, all of which formed through combinations of grain reorganization, brittle processes, pressure solution, and cementation. The textural, compositional, and diagenetic properties of the older burial-related bands (pressure solution and disaggregation) are more comparable to the detrital host rocks than the later, faulting-related cataclastic bands, regardless of the host rock characteristics. Furthermore, the relative influence of the detrital sandstone properties varies throughout the evolutionary stages of cataclastic band development. For example, multistrand bands across formations have undergone similar chemical-mechanical deformation, yet their remnant porosities and compositions vary drastically. Cluster bands, on the other hand, represent a later developmental stage than multistrand bands, and yet their porosities and compositions are similar across

  18. Depositional environment, diagenetic history, and reservoir geology of the Santiago member sandstones of the Pojuca Formation (Lower Cretaceous) in the Aracas oil field, Reconcavo basin, Brazil

    SciTech Connect

    Couto dos Anjos, S.M.

    1987-01-01

    Core analysis, sand isolith maps, shape of SP curves, and comparison with recent depositional models defined crevasse mouth bar, distal bar, bay fill, and transitional (distal bar/bay) environments. The best potential reservoirs occur in crevasse mouth bar deposits. Ten microfacies were defined, namely, two wackes, six arenites which are the most frequent in all sandstone bodies (S-1 to S-5), and two carbonates. The diagenetic evolution of the various microfacies of the Santiago sandstone is very similar and comprises: destruction of primary porosity by compaction and burial cementation; development of secondary porosity by leaching of cements; decrease in secondary porosity by late cementation and compaction; and preservation of secondary porosity due to oil migration which halted further diagenetic evolution. Framework grains, cements, and porosity in the S-2, S-3, and S-4 reservoirs display different distribution patterns. Framework grains display patterns similar to those of depositional environment whereas cements and porosity patterns reflect predominantly diagenetic processes. They show closed geometry indicating the effect of a dome-like structure of compaction origin which probably controlled the circulation of pore fluids. Highest values of porosity occur in the least cemented areas with exception of the matrix-rich interval (S-4) where the reverse values of porosity and cement are not observed. The distribution pattern of permeability is complex, and does not follow that of porosity. It does not seem to be directly related to any observable variation in framework grains or cements.

  19. Strategies for reservoir characterization and identification of incremental recovery opportunities in mature reservoirs in Frio Fluvial-Deltaic sandstones, south Texas: An example from Rincon Field, Starr County. Topical report

    SciTech Connect

    McRae, L.; Holtz, M.; Hentz, T.

    1995-11-01

    Fluvial-deltaic sandstone reservoirs in the United States are being abandoned at high rates, yet they still contain more than 34 billion barrels of unrecovered oil. The mature Oligocene-age fluvial-deltaic reservoirs of the Frio Formation along the Vicksburg Fault Zone in South Texas are typical of this class in that, after more than three decades of production, they still contain 61 percent of the original mobile oil in place, or 1.6 billion barrels. This resource represents a tremendous target for advanced reservoir characterization studies that integrate geological and engineering analysis to locate untapped and incompletely drained reservoir compartments isolated by stratigraphic heterogeneities. The D and E reservoir intervals of Rincon field, Starr County, South Texas, were selected for detailed study to demonstrate the ability of advanced characterization techniques to identify reservoir compartmentalization and locate specific infield reserve-growth opportunities. Reservoir architecture, determined through high-frequency genetic stratigraphy and facies analysis, was integrated with production history and facies-based petrophysical analysis of individual flow units to identify recompletion and geologically targeted infill drilling opportunities. Estimates of original oil in place versus cumulative production in D and E reservoirs suggest that potential reserve growth exceeds 4.5 million barrels. Comparison of reservoir architecture and the distribution of completions in each flow unit indicates a large number of reserve-growth opportunities. Potential reserves can be assigned to each opportunity by constructing an Sooh map of remaining mobile oil, which is the difference between original oil in place and the volumes drained by past completions.

  20. Caprock Integrity during Hydrocarbon Production and CO2 Injection in the Goldeneye Reservoir

    NASA Astrophysics Data System (ADS)

    Salimzadeh, Saeed; Paluszny, Adriana; Zimmerman, Robert

    2016-04-01

    Carbon Capture and Storage (CCS) is a key technology for addressing climate change and maintaining security of energy supplies, while potentially offering important economic benefits. UK offshore, depleted hydrocarbon reservoirs have the potential capacity to store significant quantities of carbon dioxide, produced during power generation from fossil fuels. The Goldeneye depleted gas condensate field, located offshore in the UK North Sea at a depth of ~ 2600 m, is a candidate for the storage of at least 10 million tons of CO2. In this research, a fully coupled, full-scale model (50×20×8 km), based on the Goldeneye reservoir, is built and used for hydro-carbon production and CO2 injection simulations. The model accounts for fluid flow, heat transfer, and deformation of the fractured reservoir. Flow through fractures is defined as two-dimensional laminar flow within the three-dimensional poroelastic medium. The local thermal non-equilibrium between injected CO2 and host reservoir has been considered with convective (conduction and advection) heat transfer. The numerical model has been developed using standard finite element method with Galerkin spatial discretisation, and finite difference temporal discretisation. The geomechanical model has been implemented into the object-oriented Imperial College Geomechanics Toolkit, in close interaction with the Complex Systems Modelling Platform (CSMP), and validated with several benchmark examples. Fifteen major faults are mapped from the Goldeneye field into the model. Modal stress intensity factors, for the three modes of fracture opening during hydrocarbon production and CO2 injection phases, are computed at the tips of the faults by computing the I-Integral over a virtual disk. Contact stresses -normal and shear- on the fault surfaces are iteratively computed using a gap-based augmented Lagrangian-Uzawa method. Results show fault activation during the production phase that may affect the fault's hydraulic conductivity

  1. Permian Bone Spring formation: Sandstone play in the Delaware basin. Part I - slope

    SciTech Connect

    Montgomery, S.L.

    1997-08-01

    New exploration in the Permian (Leonardian) Bone Spring formation has indicated regional potential in several sandstone sections across portions of the northern Delaware basin. Significant production has been established in the first, second, and third Bone Spring sandstones, as well as in a new reservoir interval, the Avalon sandstone, above the first Bone Spring sandstone. These sandstones were deposited as submarine-fan systems within the northern Delaware basin during periods of lowered sea level. The Bone Spring as a whole consists of alternating carbonate and siliciclastic intervals representing the downdip equivalents to thick Abo-Yeso/Wichita-Clear Fork carbonate buildups along the Leonardian shelf margin. Hydrocarbon exploration in the Bone Spring has traditionally focused on debris-flow carbonate deposits restricted to the paleoslope. Submarine-fan systems, in contrast, extend a considerable distance basinward of these deposits and have been recently proven productive as much as 40-48 km south of the carbonate trend.

  2. Effects of Coupled Structural and Diagenetic Processes on Deformation Localization and Fluid Flow Properties in Sandstone Reservoirs of the Southwestern United States

    NASA Astrophysics Data System (ADS)

    Elliott, S. J.; Eichhubl, P.; Landry, C. J.

    2014-12-01

    Fluid flow tends to be restricted perpendicular to deformation bands through the combined effects of mechanical grain size reduction, porosity loss, and preferred cementation relative to the adjacent host rock. Deformation bands that occur in association with reservoir scale faults can impact reservoir-scale fluid flow and fault seal behavior, potentially imparting a permeability anisotropy to reservoir rocks. We use a combination of Hg-intrusion porosimetry, high-resolution 2D-image analysis of pore size distributions, and detailed compositional analyses obtained from integrating petrographic and SEM-based imaging techniques, including SEM-cathodoluminescence, backscattered electron imaging, and energy-dispersive X-ray spectroscopy, to (1) assess the effects of coupled chemical and mechanical processes leading to deformation localization within various detrital compositions [Cedar Mesa, Navajo, and Entrada sandstones] and (2) to quantify the effect of these processes on single and multiphase fluid flow as a function of host rock properties, structural position, and deformation band textural and diagenetic properties. Within each sample, bands of differing kinematic properties and structural style, i.e. shear bands, shear enhanced compaction bands etc., were identified and pre-kinematic pore-filling cements, as well as syn- and post-kinematic cements including various clay minerals, were distinguished for both the host rock and associated deformation bands. Although the deformation bands display a variety of textures and diagenetic attributes, initial petrophysical results suggest that the flow properties - permeability and capillary pressure curves - of the bands in the formations studied are very similar. However, both individual and clustered deformation bands of the Navajo Sandstone contain open or partially cemented cross-cutting fractures that could act as flow pathways across the deformation bands.

  3. Porosity development in deep sandstones, Taranaki Basin, New Zealand

    NASA Astrophysics Data System (ADS)

    Collen, J. D.; Newman, R. H.

    Reservoir quality in the Taranaki Basin is controlled by both depositional facies and diagenesis. High initial porosities and permeabilities in manyfluvial and littoral sandstones directed fluid flow such that these facies underwater widespread cementation by silica, carbonate and authigenic clays, and later dissolution of carbonates. Current commercial production of hydrocarbons in mainly from secondary, dissolution porosity in sandstones at depths of 1750-3600 m. Recent studies suggest that oil may not be released from terrestrial source rocks in western New Zealand until depths of 5.5 km or more. Knowledge of porosity development at such depths is therefore essential for understanding migration pathways and the controls on hydrocarbon accumulation. Organic species and/or carbon dioxide evolved from kerogen before liquid hydrocarbons are important to the formation of secondary porosity in sandstones by carbonate dissolution. Further, hydrocarbon migration should follow soon after the evolution of these, in order that re-cementation does not occur. High resolution nuclear magnetic resonance (NMR) spectroscopy shows that in western New Zealand basins, the evolution of solvents continues to at least 4 km and may persist almost until the expulsion of liquid hydrocarbons.

  4. Is there any impact of CO2 injection on sandstone reservoir rocks? - Insights from a field experiment at the CO2-storage site of Ketzin (Germany)

    NASA Astrophysics Data System (ADS)

    Bock, Susanne; Pudlo, Dieter; Meier, Angela; Förster, Hans-Jürgen; Förster, Andrea; Gaupp, Reinhard

    2013-04-01

    The importance and viability of Carbon Capture and Storage (CCS) is an issue of intense discussion both in the science community and the public society. The effects of CO2 on formation fluids, minerals, and perspective reservoir rocks have been investigated by several laboratory experiments, but studies on the long-term CO2-impregnation of rocks are sparse. With the installation of a pilot CO2-injection site at Ketzin, near to the German capital of Berlin, the impact of CO2 on reservoir sandstones is investigated at field scale. Ketzin is located on the top of an anticline structure, which belongs to a double anticline formed during several episodes of halokinetic uprise of Permian salt. The storage reservoir belongs to the Stuttgart Formation (Keuper, Upper Triassic) and consists of two main sedimentary facies types. Channel sandstones (CH) formed by meandering river systems are considered as most perspective reservoir rocks for CO2 storage. For storage considerations the second type of facies, characterized by overbank fine (OF) siltstones, is less important. These sediments exhibit only low porosity and permeability. During field operation of four years about 61,000 tons of almost pure CO2 were injected. This contribution presents preliminary results of an ongoing study of petrographic-mineralogical and geochemical features of rocks which suffered CO2 attack during this period of time. Due to the high porosity and permeability, which promote gas-brine-rock interactions, analytical investigations were focused on the reservoir sandstones of the CH facies. In general such reactions will strongly affect reservoir quality. These processes are mainly controlled by fluid and rock chemistry and associated pH- and Eh-conditions. On one side, the precipitation of mineral phases (esp. pore-filling cements) can induce porosity and permeability deterioration, which will retard further fluid flow and an expansion of the CO2 plume. On the other side, due to the dissolution of

  5. Sequence Stratigraphy of the Dakota Sandstone, Eastern San Juan Basin, New Mexico, and its Relationship to Reservoir Compartmentalization

    SciTech Connect

    Varney, Peter J.

    2002-04-23

    This research established the Dakota-outcrop sequence stratigraphy in part of the eastern San Juan Basin, New Mexico, and relates reservoir quality lithologies in depositional sequences to structure and reservoir compartmentalization in the South Lindrith Field area. The result was a predictive tool that will help guide further exploration and development.

  6. Field-wide Pressure Response of Three Mid-Cenozoic Sandstone Reservoirs to Fluid Production: a Reverse Analog to Carbon Storage

    NASA Astrophysics Data System (ADS)

    Gillespie, J.; Jordan, P. D.; Chehal, S.; Gonzales, G.; goodell, J. A.; Wilson, J.

    2013-12-01

    Potential carbon storage reservoirs exist in mature oilfields of the southern San Joaquin Valley, California. Data regarding fluid extraction and injection and reservoir pressure exist for the three main oil reservoirs with carbon storage potential: the Monterey (Stevens sandstone member), Vedder and Temblor formations. The pressure response of these reservoirs to fluid volume changes over time provides information regarding how carbon storage may affect the pressure gradients in the adjacent saline aquifers outside the fields where less data exist. This project may provide a template for analysis of other potential carbon storage reservoirs that are contiguous with oilfields. A field-scale version of the productivity index (PI, defined as the average net fluid production rate divided by the average pressure drop over the time period) was calculated for fields with substantial production from depths suitable for carbon storage. The PI determines the reservoir's pressure response to fluid production and is related to the effective CO2 storage capacity. The variance of the 2005 pressure values within each reservoir provides a measure of reservoir continuity. The highest PI values (113,000 and 88,410 m3/yr/MPa) are in the Vedder Formation. The lowest PI values occur in the Temblor Formation and range from 3734 to 16,460 m3/yr/MPa. This indicates the Vedder reservoirs have more pressure support from the aquifer beyond the field than do the Temblor reservoirs. The pressure variance of 3.2 MPa within the Vedder Formation in the Greeley Field is the lowest. The greatest variance (8.5 MPa) occurs within the Temblor Formation in the Carneros unit of the Railroad Gap field. This indicates greater uniformity in the Vedder and more compartmentalization of the Temblor. Pressure response in the Stevens is more varied within the two fields examined in this study: North and South Coles Levee. In North Coles Levee, water injection was employed throughout the field resulting in a

  7. Assessment of in-place solution methane in tertiary sandstones: Texas Gulf Coast

    SciTech Connect

    Gregory, A.R.; Dodge, M.M.; Posey, J.S.; Morton, R.A.

    1981-01-01

    The higher prices obtained for commercial natural gas in recent years have stimulated interest in methane-saturated formation waters of sandstone reservoirs in the Texas Gulf Coast as a potential alternative source of energy. The objective of this project was to appraise the total volume of in-place methane dissolved in formation waters of deep sandstone reservoirs of the onshore Texas Gulf Coast within the stratigraphic section extending from the base of significant hydrocarbon production (8000 ft) to the deepest significant sandstone occurrence. Factors that must be evaluated to determine the total methane resource are reservoir bulk volume, porosity, and methane solubility. The latter is controlled by the temperature, pressure, and salinity of formation waters. Regional assessment of the volume and distribution of potential sandstone reservoirs was made from a data base of 880 electrical well logs, from which a grid of 24 structural dip cross sections and 4 strike cross sections was constructed. These cross sections extend from near the Wilcox outcrop to the coastline. Reservoir bulk volume was determined by mapping the structural and stratigraphic framework of Tertiary sandstone units. Structural and stratigraphic boundaries were used to divide the Texas Gulf Coast into 24 subdivisions. Methane content in each of nine formations or divisions of formations was determined for each subdivision. The total in-place methane for Tertiary sandstones below 8000 ft in the Texas Gulf Coast was found to be 690 TCF./sup 2/ The total in-place methane for effective Tertiary sandstones (sandstone units greater than 30 ft thick) below 8000 ft was 325 TCF.

  8. Effective Thermal Conductivity Modeling of Sandstones: SVM Framework Analysis

    NASA Astrophysics Data System (ADS)

    Rostami, Alireza; Masoudi, Mohammad; Ghaderi-Ardakani, Alireza; Arabloo, Milad; Amani, Mahmood

    2016-06-01

    Among the most significant physical characteristics of porous media, the effective thermal conductivity (ETC) is used for estimating the thermal enhanced oil recovery process efficiency, hydrocarbon reservoir thermal design, and numerical simulation. This paper reports the implementation of an innovative least square support vector machine (LS-SVM) algorithm for the development of enhanced model capable of predicting the ETCs of dry sandstones. By means of several statistical parameters, the validity of the presented model was evaluated. The prediction of the developed model for determining the ETCs of dry sandstones was in excellent agreement with the reported data with a coefficient of determination value ({R}2) of 0.983 and an average absolute relative deviation of 0.35 %. Results from present research show that the proposed LS-SVM model is robust, reliable, and efficient in calculating the ETCs of sandstones.

  9. Water-rock interaction processes in the Triassic sandstone and the granitic basement of the Rhine Graben: Geochemical investigation of a geothermal reservoir

    NASA Astrophysics Data System (ADS)

    Aquilina, L.; Pauwels, H.; Genter, A.; Fouillac, C.

    1997-10-01

    Saline fluids have been collected in the Rhine Graben over the last two decades, both from the Triassic sandstone aquifer and the granitic basement down to a depth of 3500m. Their salinities and location are compared in order to distinguish the respective influences of temperature and host-rock mineralogy in the water-rock interaction processes. The comparison shows that sulphates in the sedimentary formations were dissolved by the fluids, which also led to Br enrichment. Mica dissolution has strongly increased the Rb and Cs contents, which then provide an indication of the degree of water-rock interaction. The Sr isotopic ratios are used to compare the fluids with the granite minerals. Two relationships are revealed for the fluids in the sandstone and the granite, one related to widespread mica dissolution, which could have affected both the Buntsandstein and the granite, and the other to subsequent plagioclase dissolution, which is observed only in the granite. Computations showed that 12.5g of mica and 1.658 of plagioclase per liter of fluid have been dissolved. The nature of these two relationships suggests two different evolutions for the fluids and the individualization of the two reservoirs during the graben's history. The cation concentrations are mainly controlled by temperature, and are independent of the type of host rock. Equilibrium with the rock mainly caused Ca and K concentration variations, which has induced clear CaK and Ca-δ 18O, K-δ 18O correlations. Geothermometric computations indicate that with increasing depth, the cations, the silica and the δ 18O(SO 4) geothermometers evolve towards a value close to 230δC. This demonstrates the existence of a hot reservoir in the granite of the graben, at a depth estimated at 4.5-5 km.

  10. Water-rock interaction processes in the Triassic sandstone and the granitic basement of the Rhine Graben: Geochemical investigation of a geothermal reservoir

    SciTech Connect

    Aquilina, L.; Pauwels, H.; Genter, A.; Fouillac, C.

    1997-10-01

    Saline fluids have been collected in the Rhine Graben over the last two decades, both from the Triassic sandstone aquifer and the granitic basement down to a depth of 3500m. Their salinities and location are compared in order to distinguish the respective influences of temperature and host-rock mineralogy in the water-rock interaction processes. The comparison shows that sulphates in the sedimentary formations were dissolved by the fluids, which also led to Br enrichment. Mica dissolution has strongly increased the Rb and Cs contents, which then provide an indication of the degree of water-rock interaction. The Sr isotopic ratios are used to compare the fluids with the granite minerals. Two relationships are revealed for the fluids in the sandstone and the granite, one related to widespread mica dissolution, which could have affected both the Buntsandstein and the granite, and the other to subsequent plagioclase dissolution, which is observed only in the granite. Computations showed that 12.5g of mica and 1.65g of plagioclase per liter of fluid have been dissolved. The nature of these two relationships suggests two different evolutions for the fluids and the individualization of the two reservoirs during the graben`s history. The cation concentrations are mainly controlled by temperature, and are independent of the type of host rock. Equilibrium with the rock mainly caused Ca and K concentration variations, which has induced clear Ca-K and Ca-{delta}{sup 18}O, K-{delta}{sup 18}O correlations. Geothermometric computations indicate that with increasing depth, the cations, the silica and the {delta}{sup 18}O (SO{sub 4}) geothermometers evolve towards a value close to 230{degrees}C. This demonstrates the existence of a hot reservoir in the granite of the graben, at a depth estimated at 4.5-5 km. 59 refs., 11 figs., 6 tabs.