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Sample records for hydrocarbon sandstone reservoirs

  1. Controls on hydrocarbon production from Lower Silurian Clinton sandstone reservoir in Portage County, Ohio

    SciTech Connect

    Wilson, J.T.; Coogan, A.H. )

    1989-08-01

    The Lower Silurian Clinton section (Ordovician Queenston Shale to Packer Shell/Brassfield Limestone) represents a deltaic sequence in Portage County where it occurs approximately 25 mi east of the delta edge and 50 mi east of the sandstone depositional limit. In Portage County, the Clinton section is approximately 190 ft thick. The mean sandstone thickness is 53 ft (range from > 100 to < 10 ft). The mean sandstone thickness is much greater than it is for the Clinton sandstone reservoir closer to the delta edge, where hydrocarbon production is comparable to, or surpasses that in Portage County. It is now evident that the occurrence of thick, clean Clinton sandstone is not the only primary geologic factor for high production from the reservoir. Two productive areas were studied to isolate controls on hydrocarbon occurrence and production. One area is structurally low, the other is structurally high, but both have about the same mean Clinton sandstone thickness.

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

    SciTech Connect

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

    1995-06-01

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

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

    NASA Astrophysics Data System (ADS)

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

    2017-04-01

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

  4. Fluvioglacial sandstone reservoirs and deposystem analysis in hydrocarbon exploration of Permian Gidgealpa group, southern Cooper basin, south Australia

    SciTech Connect

    Wild, E.K.; Williams, B.P.J.

    1984-04-01

    The sedimentology of the Permian Gidgealpa Group of the southern Cooper basin currently is being evaluated to ascertain the tectono-sedimentologic evolution of the basin and to determine the architecture of the clastic suite in order to generate exploration plays. The Merrimelia Formation of the Gidgealpa Group was examined regionally in 29 cored wells. The formation attains a maximum thickness of 300 m (1000 ft), and representative facies include glaciofluvial outwash, terrestrial and subaqueous diamictites, and glaciolacustrine, wave-affected, and ripple-laminated sandstones, with thick, monotonous mudrock sequences containing clay-dominant rhythmite horizons. The Tirrawarra Sandstone, analyzed in 32 cored wells, comprises four major facies associations throughout its maximum 75 m (250 ft) thickness. These associations indicate a temporal and spatial evolution of a fluvioglacial to predominantly fluvial system. Initial deposition on low slope, outwash fans, where braided processes operated is indicated. This sedimentation style evolved into a low sinuosity, bedload-dominant, sandy braided system, with high width-to-depth ratio channels. Allocyclic control mechanisms are invoke for late Tirrawarra sedimentation as the facies reveal proximal-distal patterns and the fluvial style changes to a mixed-load channel system. The interfacing and evolutionary pattern of the deposystem indicates that additional reserves potential exists for reservoirs developed locally within the Merrimelia Formation.

  5. 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.

  6. Reservoir assessment of the Nubian sandstone reservoir in South Central Gulf of Suez, Egypt

    NASA Astrophysics Data System (ADS)

    El-Gendy, Nader; Barakat, Moataz; Abdallah, Hamed

    2017-05-01

    The Gulf of Suez is considered as one of the most important petroleum provinces in Egypt and contains the Saqqara and Edfu oil fields located in the South Central portion of the Gulf of Suez. The Nubian sandstone reservoir in the Gulf of Suez basin is well known for its great capability to store and produce large volumes of hydrocarbons. The Nubian sandstone overlies basement rocks throughout most of the Gulf of Suez region. It consists of a sequence of sandstones and shales of Paleozoic to Cretaceous age. The Nubian sandstone intersected in most wells has excellent reservoir characteristics. Its porosity is controlled by sedimentation style and diagenesis. The cementation materials are mainly kaolinite and quartz overgrowths. The permeability of the Nubian sandstone is mainly controlled by grain size, sorting, porosity and clay content especially kaolinite and decreases with increase of kaolinite. The permeability of the Nubian Sandstone is evaluated using the Nuclear Magnetic Resonance (NMR technology) and formation pressure data in addition to the conventional logs and the results were calibrated using core data. In this work, the Nubian sandstone was investigated and evaluated using complete suites of conventional and advanced logging techniques to understand its reservoir characteristics which have impact on economics of oil recovery. The Nubian reservoir has a complicated wettability nature which affects the petrophysical evaluation and reservoir productivity. So, understanding the reservoir wettability is very important for managing well performance, productivity and oil recovery.

  7. 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

  8. 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.

  9. 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.

  10. 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.

  11. The influence of diagenesis on the heterogeneity of sandstone reservoir

    NASA Astrophysics Data System (ADS)

    Yan, Ming

    2017-06-01

    Diagenesis plays an important role in controlling the quality and heterogeneity of clastic reservoirs. The variation of diagenesis is usually reflected in the variation of sedimentary porosity and permeability. The effects of the types and distribution of sedimentary rocks and clastic sedimentary evolution and sequence stratigraphic framework provide a powerful tool to predict the prediction effect on the distribution of rock mass and the heterogeneity of the control effect. The heterogeneity of sandstone reservoir, it determines the volume, velocity and hydrocarbon recovery, the sand body geometry and internal structure, grain size, sorting, bioturbation degree, origin, and diagenesis types, volume and distribution.

  12. Petrology and reservoir quality of the Gaikema Sandstone: Initial impressions

    USGS Publications Warehouse

    Helmold, Kenneth P.; Stanley, Richard G.

    2015-01-01

    The Division of Geological & Geophysical Surveys (DGGS) and Division of Oil & Gas (DOG) are currently conducting a study of the hydrocarbon potential of Cook Inlet basin (LePain and others, 2011). The Tertiary stratigraphic section of the basin includes coal-bearing units that are prolific gas reservoirs, particularly the Neogene sandstones. The Paleogene sandstones are locally prolific oil reservoirs that are sourced largely from the underlying Middle Jurassic Tuxedni Group. Several large structures act as hydrocarbon traps and the possibility exists for stratigraphic traps although this potential has not been fully exploited. As part of this study a significant number of Tertiary sandstones from the basin have been already collected and analyzed (Helmold and others, 2013). Recent field programs have shifted attention to the Mesozoic stratigraphic section to ascertain whether it contains potential hydrocarbon reservoirs. During the 2013 Cook Inlet field season, two days were spent on the Iniskin Peninsula examining outcrops of the Middle Jurassic Gaikema Sandstone along the south shore of Chinitna Bay (fig. 7-1). A stratigraphic section approximately 34 m in thickness was measured and a detailed description was initiated (Stanley and others, 2015), but due to deteriorating weather it was not possible to complete the description. During the 2014 field season two additional days were spent completing work on the Gaikema section. Analyses of thin sections from six of the samples collected in 2013 are available for incorporation in this report (table 7-1). Data from samples collected during the 2014 field season will be included in future reports.

  13. Deformation of Reservoir Sandstones by Elastic versus Inelastic Deformation Mechanisms

    NASA Astrophysics Data System (ADS)

    Pijnenburg, R.; Verberne, B. A.; Hangx, S.; Spiers, C. J.

    2016-12-01

    Hydrocarbon or groundwater production from sandstone reservoirs can result in surface subsidence and induced seismicity. Subsidence results from combined elastic and inelastic compaction of the reservoir due to a change in the effective stress state upon fluid extraction. The magnitude of elastic compaction can be accurately described using poroelasticity theory. However inelastic or time-dependent compaction is poorly constrained. Specifically, the underlying microphysical processes controlling sandstone compaction remain poorly understood. We use sandstones recovered by the field operator (NAM) from the Slochteren gas reservoir (Groningen, NE Netherlands) to study the importance of elastic versus inelastic deformation processes upon simulated pore pressure depletion. We conducted conventional triaxial tests under true in-situ conditions of pressure and temperature. To investigate the effect of applied differential stress (σ1 - σ3 = 0 - 50 MPa) and initial sample porosity (φi = 12 - 24%) on instantaneous and time-dependent inelastic deformation, we imposed multiple stages of axial loading and relaxation. The results show that inelastic strain develops at all stages of loading, and that its magnitude increases with increasing value of differential stress and initial porosity. The stress sensitivity of the axial creep strain rate and microstructural evidence suggest that inelastic compaction is controlled by a combination of intergranular slip and intragranular cracking. Intragranular cracking is shown to be more pervasive with increasing values of initial porosity. The results are consistent with a conceptual microphysical model, involving deformation by poro-elasticity combined with intergranular sliding and grain contact failure. This model aims to predict sandstone deformation behavior for a wide range of stress conditions.

  14. 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.

  15. 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.

  16. Reservoir sandstone bodies in lower Silurian Clinton sandstone interval, eastern Ohio

    SciTech Connect

    Coogan, A.H.

    1987-09-01

    The stratigraphic relationships of the sandstones, shales, limestones, dolomites, and related beds of the Lower Silurian Clinton sandstone interval in Ohio have been examined using several thousand well logs from Medina County to Coshocton County in eastern Ohio. This north-south band of counties lies semiparallel to the north-northeast-trending depositional edge of the Clinton lower deltaic and coastal plain. Continuous and discontinuous bar sandstones with patterns similar to barrier island deposits are found at the edge of the deltaic plain. The thicker sandstone reservoirs in these deposits have been prolific oil and gas pools. The discontinuous bar sands are more common, however, and where drilling is sparse or where only the cleaner sandstones are mapped, these bar sands appear as isolated, thick, porous sandstone bodies. Examples exist in Holmes and Wayne Counties, Ohio. Elongate, nearly straight, narrow sandstone bodies occur on the lower deltaic plain, and were deposited in channels that were fluvial or partly estuarine. The channel sandstones are less than 1000 ft wide, extend for distances up to 10 mi and can be seen in Coshocton, Summit, and Medina Counties. The reservoirs in these sandstones are prolific oil and gas producers, but they are not easy to locate. At the seaward end of the elongate channel, sandstones are thick, localized sand bodies that fit in the sedimentological picture as river mouth bars. An example from Medina County illustrates this reservoir geometry at the site of excellent oil production from the Clinton interval.

  17. Bleaching of Jurassic Navajo Sandstone on Colorado Plateau Laramide highs: Evidence of exhumed hydrocarbon supergiants?

    NASA Astrophysics Data System (ADS)

    Beitler, Brenda; Chan, Marjorie A.; Parry, William T.

    2003-12-01

    Spectacular color variations in the Lower Jurassic Navajo Sandstone reflect stratigraphic and structural control on the spatial distribution of fluid-driven alteration. Field observations and supervised classification of Landsat 7 Enhanced Thematic Mapper (ETM+) satellite imagery show that the most extensive regional bleaching of the Navajo Sandstone occurs on eroded crests of Laramide uplifts on the Colorado Plateau in southern Utah. Alteration patterns suggest that the blind reverse faults that core the eastern monoclines associated with these uplifts were carriers for hydrocarbons and brought the buoyant fluids to the crests of monoclines and anticlines, where they bleached the sandstone in both structural and stratigraphic traps. The extent of bleaching indicates that the Navajo Sandstone (Navajo Sandstone, Aztec Sandstone, and Nugget Sandstone) may have been one of the largest hydrocarbon reservoirs known. Rapid incision and breaching of this reservoir during Tertiary uplift and erosion of the Colorado Plateau could have released enough carbon into the atmosphere to significantly contribute to global carbon fluxes and possibly influence climate.

  18. The influence of diagenesis on the reservoir quality of Cambrian and Carboniferous sandstones, southwest Sinai, Egypt

    NASA Astrophysics Data System (ADS)

    McBride, Earle F.; Abdel-Wahab, Antar; Salem, Alaa M. K.

    1996-04-01

    The diagenetic influence on hydrocarbon reservoir quality was investigated for the Cambrian and Lower Carboniferous sandstones of southwestern Sinai. These quartzose and feldspathic Palaeozoic sandstones were not buried more than 1 to 1.5 km until Late Cretaceous and more recent times, when the most deeply buried rocks may have reached 25 km. Porosity was reduced by compaction from an assumed original 45% to about 26%. In general, both Cambrian and Carboniferous sandstones lost more porosity by compaction (average of 19% for each) than by cementation (average of 17% and 13%, respectively). There is no significant difference in the degree of compaction shown by Cambrian (older, deeper buried) rather than Carboniferous sandstones. Cementation by iron oxide, quartz, calcite and kaolinite reduced porosity to 12-15%, except in silcretes and some ferricretes where porosity was reduced to <5%. Significant secondary porosity was created (5.8 and 5.1 % for Cambrian and Carboniferous sandstones, respectively ) chiefly by dissolution of feldspar. Kaolinite (maximum of 20%) is the most deleterious cement because it has high microporosity, which causes high residual water saturation, and occurs as tiny crystals that have the potential to break loose during rapid fluid flow and block the pore throats. The present-day porosity in these sandstones averages 19% and ranges from 1.5 to 32%. Many sandstone samples (47% of a total of 178 samples) have permeability values higher than 1000 md. The plot of porosity versus the log of permeability has a good correlation indicating that microporosity, even though locally important, does not significantly influence reservoir quality. In spite of their age and the large volumes of groundwater that probably passed through them, these Palaeozoic sandstones retain sufficient porosity and permeability to possess excellent reservoir quality.

  19. 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).

  20. 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.

  1. Genetic stratigraphy and reservoir characterization of the Spiro sandstone, Red Oak Field, Arkoma Basin, southeastern Oklahoma

    SciTech Connect

    Horn, B.W. )

    1996-01-01

    The Lower Atokan Spiro sandstone is a mixed carbonate-silicilastic reservoir that produces hydrocarbons from three discrete stratigraphic intervals at the Red Oak Field. Reservoir-quality sandstones develop in the seaward stepping sub-Spiro sequence (highstand system tract), landward stepping Foster [open quote]channel,[close quotes] and upper Spiro depositional sequences (transgressive and highstand system tract). The sub-Spiro and Foster [open quote]channel[close quote] sequences are separated by regional unconformity interpreted as a sequence boundary. Regressive marine shoreface cycles, genetically related to the sub-Spiro shale, comprise the lowermost producing interval. Fluvial/estuarine valley-fill (Foster channel) sandstones progressively onlap the sequence boundary overlying the regressive shoreface cycles and juxtapose reservoir-quality sandstones of different sequences, creating a complex reservoir architecture. Upper Spiro reservoir sandstones are developed within marine shoreface cycles that are deposited in a landward-stepping succession (highstand systems tract) following the drowning of incised paleovalleys. These aggradational / retrogradational successions downlap onto the valley-fill and sub-Spiro sequences representing the final stages of Spiro deposition prior to the high stand of sea level during Middle Atokan time. Regional stratigraphic correlations demonstrate progressive basinward truncation of the sub-Spiro regressive shoreface cycles by an erosional surface, creating a network of incised paleovalleys across the Pennsylvanian shelf. Based on core, well log, and outcrop interpretations, the magnitude of the facies offset across this sequence boundary indicates that a significant volume of reservoir-quality sediment has been partitioned basinward of the current producing areas.

  2. Multiscale Fractal Characterization of Hierarchical Heterogeneity in Sandstone Reservoirs

    NASA Astrophysics Data System (ADS)

    Liu, Yanfeng; Liu, Yuetian; Sun, Lu; Liu, Jian

    2016-07-01

    Heterogeneities affecting reservoirs often develop at different scales. Previous studies have described these heterogeneities using different parameters depending on their size, and there is no one comprehensive method of reservoir evaluation that considers every scale. This paper introduces a multiscale fractal approach to quantify consistently the hierarchical heterogeneities of sandstone reservoirs. Materials taken from typical depositional pattern and aerial photography are used to represent three main types of sandstone reservoir: turbidite, braided, and meandering river system. Subsequent multiscale fractal dimension analysis using the Bouligand-Minkowski method characterizes well the hierarchical heterogeneity of the sandstone reservoirs. The multiscale fractal dimension provides a curve function that describes the heterogeneity at different scales. The heterogeneity of a reservoir’s internal structure decreases as the observational scale increases. The shape of a deposit’s facies is vital for quantitative determination of the sedimentation type, and thus enhanced oil recovery. Characterization of hierarchical heterogeneity by multiscale fractal dimension can assist reservoir evaluation, geological modeling, and even the design of well patterns.

  3. 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.

  4. 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.

  5. 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.

  6. An integrated workflow to characterize and evaluate low resistivity pay and its phenomenon in a sandstone reservoir

    NASA Astrophysics Data System (ADS)

    Pratama, Edo; Suhaili Ismail, Mohd; Ridha, Syahrir

    2017-06-01

    The identification, characterization and evaluation of low resistivity pay is very challenging and important for the development of oil and gas fields. Proper identification and characterization of these reservoirs is essential for recovering their reserves. There are many reasons for low resistivity pay zones. It is crucial to identify the origin of this phenomenon. This paper deals with the identification, characterization and evaluation of low resistivity hydrocarbon-bearing sand reservoirs in order to understand the low resistivity phenomenon in a sandstone reservoir, the characterization of the rock types and how to conduct petrophysical analysis to accurately obtain petrophysical properties. An integrated workflow based on petrographical, rock typing and petrophysical methods is conducted and applied. From the integrated analysis that was performed, the presence of illite and a mixed layer of illite-smectite clay minerals in sandstone formation and pyrite-siderite conductive minerals was identified as one of the main reasons for low resistivity occurence in sandstone reservoirs. These clay minerals are distributed as a laminated-dispersed shale distribution model in sandstone reservoirs. The dual water method is recommended to calculate water saturation in low resistivity hydrocarbon-bearing sand reservoirs as this method is more accurate and does not result in an over estimation in water saturation calculation.

  7. 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

  8. 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.

  9. 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.

  10. Phenomenology of tremor-like signals observed over hydrocarbon reservoirs

    NASA Astrophysics Data System (ADS)

    Dangel, S.; Schaepman, M. E.; Stoll, E. P.; Carniel, R.; Barzandji, O.; Rode, E.-D.; Singer, J. M.

    2003-11-01

    We have observed narrow-band, low-frequency (1.5-4 Hz, amplitude 0.01-10 μm/s) tremor signals on the surface over hydrocarbon reservoirs (oil, gas and water multiphase fluid systems in porous media) at currently 15 sites worldwide. These 'hydrocarbon tremors' possess remarkably similar spectral and signal structure characteristics, pointing to a common source mechanism, even though the depth (some hundreds to several thousands of meters), specific fluid content (oil, gas, gas condensate of different compositions and combinations) and reservoir rock type (such as sandstone, carbonates, etc.) for each of those sites are quite different. About half of the sites are fully explored or even developed and producing fields, and hard quantitative data on the reservoirs are available (well data, reservoir monitoring data, seismic surveys, etc.). The other areas are essentially either explored prospect areas where we did not have access to hard reservoir data or (in only one case) areas where no exploration wells have been drilled at all. The tremor signal itself was observed over ALL locations investigated so far. The signals weaken at the rim of the reservoirs and are not observed outside the reservoir area. There is a strong correlation of the tremor power with the thickness of the hydrocarbon-bearing layers ('pay zone thickness') determined by borehole log measurements. The overall correlation between surface tremor measurements and accessible subsurface well data is higher than 90%. The phenomenological comparison of hydrocarbon tremor signals with volcanic tremor signals from Stromboli and Arenal volcanoes using both conventional spectral analysis tools and non-linear dynamics methods reveals fundamental similarities between those two phenomena as well as their close relation to bandpass filtered noise. Nevertheless, the specific signal sources are expected to be different for volcanoes and hydrocarbon reservoirs. Using the currently available data we present possible

  11. 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.

  12. 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.

  13. 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.

  14. 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

  15. 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

  16. Hydrocarbon accumulation in basal Pennsylvanian fluvial sandstone near Hardinville, Crawford County, Illinois: a model paleogeomorphic trap

    SciTech Connect

    Howard, R.H.; Whitaker, S.T.

    1987-09-01

    The surface of the Mississippian-Pennsylvanian unconformity in the Illinois basin is characterized by an anastomosing pattern of paleovalleys eroded by the ancient Michigan River system. Fluvial sandstones deposited within these valleys commonly were buried by transgressive Pennsylvanian marine shales, creating the potential for stratigraphic entrapment of hydrocarbons. One such trap was discovered accidentally on the northeast flank of the Hardinville dome in 1955. The exploration significance of a linear sand body within a paleovalley was not recognized at that time and only four producing wells resulted. Not until 1974 was this reservoir again encountered, 1.5 mi to the southwest, on the dome's southwest flank. Correct log correlations led to its identification in 1976 as a 3-mi-long, 5-45-ft-thick conglomeratic sand body along one side of the paleovalley floor. Sixteen producing wells in the southwestern portion of the reservoir will recover an estimated 1.2 million bbl of 36/sup 0/ oil. This reservoir illustrates the difficulties and rewards in developing exploration models for stratigraphic traps. Traps associated with paleovalleys at the Mississippian-Pennsylvanian unconformity in particular could prove to be important targets for future exploration. Maps showing (1) paleogeology and paleotopography of the sub-Pennsylvanian surface, and (2) structure of overlying Pennsylvanian coals can be used to delineate paleovalleys on the unconformity surface and potential hydrocarbon reservoir strata associated with sedimentary fill. Seismic data may also be useful, but models will require careful computer modeling and field testings.

  17. Synsedimentary tectonics, distribution, and reservoir quality of Rotliegende sandstones: Emsland Province, northwest Germany

    SciTech Connect

    Kuehn, M. )

    1993-09-01

    The exploration for gas in the Rotliegende of the Emsland province, northwest Germany, has had very limited success so far. This fact is contrasted by less than 30 km distance to the giant Groningen gas field. Risks concerning Rotliegende hydrocarbon reservoirs in this area are (a) severe deterioration of permeability by widespread growth of illite in pore space and (b) absence of upper Rotliegende strata in certain areas. The Rotliegende of the Emsland was deposited in an embayment of the main west-northwest-east-southeast Rotliegende basin. Intensive growth of illite area. A southern part, about 50 km southward, with only limited well control in between, displays an erratic spatial distribution of clay- and sandstones. A total of 450-m conventional cores of 22 wells in the rotliegende were evaluated as to their sedimentary facies and petrography. A plateau basalt represents the lower Rotliegende, with a maximum thickness of 135 m. It was covered by a red-laminated claystone of up to 65 m thickness. After deposition of this claystone, a half-garben structure was formed, filled up with clean mature medium-grained sandstones up to 150 m thick, and deposited in a desert environment. Subsidence in the southern part ended after deposition of the so-called Haren sandstone, which is of good reservoir quality. The northern part continued to subside, and sandstones of a regressive lakeshore environment alternate with transgressive claystones. Erosion of the southern area is documented (a) in the distinct amount of detrital basalt fragments in the sands shedded to the north and (b) the absence of upper Rotliegende strata. We assume the composition of detritus, together with depth, to be the main factors creating illite growth in this northern area.

  18. 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

  19. Depositional facies of hydrocarbon reservoirs of upper Cherokee Group, Anadarko basin

    SciTech Connect

    Puckette, J.O.; Al-Shaieb, Z. )

    1989-08-01

    The Desmoinesian upper Cherokee Group sequence in the Anadarko basin is the subsurface equivalent of the Cabaniss Group of eastern Oklahoma. This sequence includes the Pink limestone, Skinner sandstone, Verdigris limestone, and Prue sandstone intervals. The upper Skinner sandstone, which has not been well documented, is an important hydrocarbon-producing reservoir in the Anadarko basin. The Skinner sandstone is represented by channel, delta-front-prodelta, and shallow marine facies. Channel facies consist of a primary elongate trend extending 40 mi southeast-northwest across Custer and Roger Mills Counties, Oklahoma. Several small secondary channels trending northeast-southwest were also observed. Active channel-fill sequences in the primary trend exceed 100 ft in thickness and represent the major producing reservoir of the upper Skinner sandstone. Delta-front-prodelta sequences are dominated by shale and interbedded sandstone-shale units. Shallow marine facies consist of massive coarsening-upward units that reach 300 ft in thickness. This facies belt is broad and slightly elongated, approximately 12 mi wide by 20 mi long, and trends northeast-southwest somewhat normal to channel facies orientation. Lithologically, the upper Skinner channel sandstone is feldspathic litharenite with abundant feldspar and quartz overgrowth. Both primary and secondary porosity were observed in the upper Skinner sandstone. Secondary porosity evolved mainly from dissolution of feldspar and lithic fragments. However, extensive cementation in the shallow marine facies has reduced porosity to negligible amounts and consequently reduced reservoir quality.

  20. 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.

  1. 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

  2. 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.

  3. 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

  4. 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.

  5. 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

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

    USGS Publications Warehouse

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

    2011-01-01

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

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

    NASA Astrophysics Data System (ADS)

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

    2015-03-01

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

  8. 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.

  9. Sedimentology, petrology, and reservoir characteristics of lower Strawn sandstone, Bent Tree field, Hardeman County, Texas

    SciTech Connect

    Moore, T.R.; Bridges, K.F.

    1987-08-01

    Reservoir sandstones of the lower Strawn Formation (early Middle Pennsylvanian) in the Bent Tree field of Hardeman County, Texas, are coarse to fine-grained, texturally submature arkoses. Cores show the sandstones to have been deposited in 1.5-4.5 m thick fining-upward successions of aggraded or prograded bar units. Each bar unit has a sharp erosional base overlain by cross-bedded, coarse-grained, conglomeratic sandstone, which, in turn, is overlain by medium to fine-grained, horizontally bedded or ripple-bedded sandstone. The coarse conglomeratic sandstones are interpreted to represent deposition in main channels of a braided fluvial system that were progressively filled by aggrading and prograding bars. The interbedded, finer grained, more immature sandstones appear to have been deposited in auxiliary channels or swales, or in proximal overbank settings. The detrital framework grain suite of the reservoir sandstones averages 47% quartz, 30% feldspars, 19% igneous rock fragments, and 4% sedimentary rock fragments. The source of these sands was a plutonic/cratonic igneous massif with minor exposures of older sedimentary strata, and was probably the ancestral Wichita Mountains. Diagenesis has significantly affected the petrographic and reservoir properties of the lower Strawn sandstones, primarily through the in-situ alteration of detrital feldspathic grains and by the precipitation of authigenic quartz overgrowths, chlorite clay, and carbonate cements.

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

    SciTech Connect

    Antonellini, M.; Aydin, A.

    1995-08-01

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

  11. Sedimentological reservoir characteristics of the Paleocene fluvial/lacustrine Yabus Sandstone, Melut Basin, Sudan

    NASA Astrophysics Data System (ADS)

    Mahgoub, M. I.; Padmanabhan, E.; Abdullatif, O. M.

    2016-11-01

    Melut Basin in Sudan is regionally linked to the Mesozoic-Cenozoic Central and Western African Rift System (CWARS). The Paleocene Yabus Formation is the main oil producing reservoir in the basin. It is dominated by channel sandstone and shales deposited in fluvial/lacustrine environment during the third phase of rifting in the basin. Different scales of sedimentological heterogeneities influenced reservoir quality and architecture. The cores and well logs analyses revealed seven lithofacies representing fluvial, deltaic and lacustrine depositional environments. The sandstone is medium to coarse-grained, poorly to moderately-sorted and sub-angular to sub-rounded, arkosic-subarkosic to sublitharenite. On the basin scale, the Yabus Formation showed variation in sandstone bodies, thickness, geometry and architecture. On macro-scale, reservoir quality varies vertically and laterally within Yabus Sandstone where it shows progressive fining upward tendencies with different degrees of connectivity. The lower part of the reservoir showed well-connected and amalgamated sandstone bodies, the middle to the upper parts, however, have moderate to low sandstone bodies' connectivity and amalgamation. On micro-scale, sandstone reservoir quality is directly affected by textures and diagenetic changes such as compaction, cementation, alteration, dissolution and kaolinite clays pore fill and coat all have significantly reduced the reservoir porosity and permeability. The estimated porosity in Yabus Formation ranges from 2 to 20% with an average of 12%; while permeability varies from 200 to 500 mD and up to 1 Darcy. The understanding of different scales of sedimentological reservoir heterogeneities might contribute to better reservoir quality prediction, architecture, consequently enhancing development and productivity.

  12. 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.

  13. 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.

  14. 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.

  15. 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.

  16. Enhancement of seismic monitoring in hydrocarbon reservoirs

    NASA Astrophysics Data System (ADS)

    Caffagni, Enrico; Bokelmann, Götz

    2017-04-01

    Hydraulic Fracturing (HF) is widely considered as one of the most significant enablers of the successful exploitation of hydrocarbons in North America. Massive usage of HF is currently adopted to increase the permeability in shale and tight-sand deep reservoirs, despite the economical downturn. The exploitation success is less due to the subsurface geology, but in technology that improves exploration, production, and decision-making. This includes monitoring of the reservoir, which is vital. Indeed, the general mindset in the industry is to keep enhancing seismic monitoring. It allows understanding and tracking processes in hydrocarbon reservoirs, which serves two purposes, a) to optimize recovery, and b) to help minimize environmental impact. This raises the question of how monitoring, and especially seismic techniques could be more efficient. There is a pressing demand from seismic service industry to evolve quickly and to meet the oil-gas industry's changing needs. Nonetheless, the innovative monitoring techniques, to achieve the purpose, must enhance the characterization or the visualization of a superior-quality images of the reservoir. We discuss recent applications of seismic monitoring in hydrocarbon reservoirs, detailing potential enhancement and eventual limitations. The aim is to test the validity of these seismic monitoring techniques, qualitatively discuss their potential application to energy fields that are not only limited to HF. Outcomes from our investigation may benefit operators and regulators in case of future massive HF applications in Europe, as well. This work is part of the FracRisk consortium (www.fracrisk.eu), funded by the Horizon2020 research programme, whose aims is to help minimize the environmental footprint of the shale-gas exploration and exploitation.

  17. Upper Cretaceous Shannon Sandstone reservoirs, Powder River Basin, Wyoming: evidence for organic acid diagenesis?

    USGS Publications Warehouse

    Hansley, P.L.; Nuccio, V.F.

    1992-01-01

    Comparison of the petrology of shallow and deep oil reservoirs in the Upper Cretaceous Shannon Sandstone Beds of the Steele Member of the Cody Shale strongly suggests that organic acids have had a more significant impact on the diagenetic alteration of aluminosilicate grains and carbonate cements in the deep reservoirs than in the shallow reservoirs. Vitrinite reflectance and Rock-Eval measurements, as well as the time-temperature index and kinetic modeling, indicate that deep reservoirs have been subjected to maximum temperatures of approximately 110-120??C, whereas shallow reservoirs have reached only 75??C. -from Authors

  18. Reservoir heterogeneity within Bartlesville sandstone, Glenn Pool oil field, Creek County, Oklahoma

    SciTech Connect

    Kuykendall, M.D. )

    1989-08-01

    The extent of reservoir heterogeneity within the Middle Pennsylvanian (Desmoinesian) Bartlesville Glenn sandstone in the 160-ac William Berryhill unit was established using more than 70 modern well log suites and 18 cores. Reservoir characterization of genetic sandstone units within the Bartlesville is based on differences in lithologic characteristics, sedimentologic features, porosity, permeability, and log-response characteristics. The upper delta-plain depositional setting of the Bartlesville was such that short-distance changes in facies created many small-scale heterogeneities. Recognition of laterally continuous distinct units in the Bartlesville sandstone requires integration of well log signatures and rock properties. Although thin intervals of interbedded sandstone and shale, and calcite-cemented sandstone are discontinuous laterally, they tend to compartmentalize portions of the reservoir. The Bartlesville sandstone is presently a sublitharenite-litharenite, even after its composition has been influenced strongly by diagenetic processes. Porosity is mostly secondary owing to the dissolution of unstable framework grains. Distribution and general trends of porosity are affected by changes in composition and pore geometry in particular rock units as well as local changes in depositional trend.

  19. 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.

  20. Temporal and spatial variation in diagenesis and reservoir quality: Brent sandstone, Heather field, North Sea

    SciTech Connect

    Lundegard, P.D.; Glasmann, J.R.; Penny, B.K.

    1989-03-01

    Brent Group sandstones in the Heather field show extreme inter- and intrafacies heterogeneity in reservoir quality as a result of diagenetic variation. Diagenetic patterns varied spatially and temporally as a result of variations in paleofluid chemistry, the time of hydrocarbon accumulation, and detrital grain composition. Important diagenetic cements are poikilotopic calcite, kaolinite, quartz, and illite. Geochemical, petrographic, and structural evidence indicate that calcite precipitated in the Late Jurassic (approximately 150 Ma) at a low temperature (40/degrees/-50/degrees/C), from reducing water of partial meteoric derivation (/delta//sup 18/O water = /minus/4 to /minus/6 /per thousand/ SMOW) that contained highly radiogenic strontium (/sup 87/Sr//sup 86/Sr > 0.71). Calcite distribution was partially controlled by local erosion of the Brent immediately following its deposition. Subsequently, a major period of kaolinite precipitation and feldspar dissolution occurred. Isotopic and tectonic/thermal history data suggest that these events were caused by thorough meteoric flushing (/delta//sup 18/O water = /minus/6 to /minus 8/ /per thousand/ SMOW) during the mid-Cimmerian sea level low (ca. 140 Ma), but not via recharge at the mid-Cimmerian unconformity immediately above the structure. Quartz precipitated as a result of feldspar dissolution, pressure solution, and fluid movement up fault zones over a long period of geologic time. In the vicinity of major faults, quartz fluid inclusions indicate invasion of hot, saline brines.

  1. 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).

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

    PubMed

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

    2013-03-01

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

  3. 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

  4. 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

  5. Relationship between sandstone-type uranium deposits and hydrocarbon in the northern ordos basin

    NASA Astrophysics Data System (ADS)

    Wang, Feifei; Wang, Jianqiang; Guo, Pei; Cheng, Xianghu; Li, Bei; Song, Zisheng; Wei, Anjun

    2017-05-01

    The Ordos Basin is one of the largest proliferous basins and also one of the most important uranium-bearing basins in China. It is characterized by the coexistence of petroleum and uranium in the northern part of the basin. To understand the coexistence mechanism, more studies are called for on the genesis of sandstone-type uranium deposits in the northern part of the basin, especially on the role of hydrocarbon in uranium mineralization. In this study, we investigated the relationship between uranium and hydrocarbon in the northern Ordos Basin using the methods of petrology, mineralogy and geochemistry. Our results show that the hydrocarbon seepage plays an important role in the mineralization of sandstone-type uranium deposits. It greatly affects the reduction in mineralization and the environmental rehabilitation to protect the ore body from being destroyed by the groundwater after mineralization.

  6. 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.

  7. 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.

  8. 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.

  9. Relevance of trapping mechanisms in certain Michigan formation stray sandstone gas reservoirs to gas storage operations

    SciTech Connect

    Nowaczewski, S.F. )

    1994-08-01

    The Stray sandstones of the Michigan Formation were early exploration targets in the Michigan basin. Subsequent to primary production, some of these reservoirs were converted to gas storage. Many of the Stray fields were discovered in an underpressured state, whereas peak storage pressures often exceed native brine gradients. It can be demonstrated that the Stray sandstones exist in sheets and lenses throughout the central basin area, and that gas/water contacts exist in the gas reservoirs but behave volumetrically. Various indirect and direct evidence indicates that gas is trapped structurally by the antiformal geometry of the sandstone bodies, by probable fracture-controlled porosity, stratigraphically by the isolation of parts of the sand bodies due to depositional and diagenetic influences, and by structurally controlled stratigraphic relationships. The understanding of the trapping mechanisms allows successful high pressure-gradient gas storage and leads to understanding reservoir behavior, which should result in efficient storage development and operation. Additional direct and secondary benefits of understanding Stray sandstone structure and stratigraphy are demonstrated for gas storage operation nuisances such as water production, and for use of the Stray as a window to or a type for deeper formations.

  10. 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.

  11. 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.

  12. Seismic attenuation and pore-fluid viscosity in clay-rich reservoir sandstones

    SciTech Connect

    Best, A.I.; McCann, C.

    1995-09-01

    The frequency dependence of seismic attenuation in a suite of clay-rich reservoir sandstones was investigated in the laboratory. Compressional- and shear-wave velocities (V{sub P} and V{sub S}) and quality factors (Q{sub P} and Q{sub S}) were measured as functions of pore-fluid viscosity at an effective pressure of 50 MPa and at an experimental frequency of about 0.8 MHz using the pulse-echo technique. The experimental viscosity ranged from 0.3 to 1,000 centipoise, which gives equivalent frequencies for a water-saturated sandstone of 2.6 MHz to 780 Hz, assuming a global-flow loss mechanism. Two types of behavior were observed: high permeability (greater than 100 millidarcies) sandstones tend to show variable Q{sub P} and Q{sub S} which are similar in magnitude to those predicted by the Biot theory over the viscosity range 0.3 to about 20 centipoise; low permeability sandstones tend to show almost constant Q{sub P} and Q{sub S} over the experimental viscosity range that are not predicted by the Biot theory. High permeability sandstones show small velocity dispersions with changing pore-fluid viscosity that are consistent with the Biot theory. Low permeability sandstones show relatively large increases in velocity with increasing viscosity not explained by the Biot theory, which are consistent with a local flow loss mechanism. The results indicate the presence of two dominant loss mechanisms: global flow (at least down to about 39 kHz in water-saturated rocks) in high permeability sandstones with only small amounts of intrapore clay, and local flow at ultrasonic frequencies in low permeability, clay-rich sandstones.

  13. 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.

  14. 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.

  15. 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.

  16. 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.

  17. 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)

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

    NASA Astrophysics Data System (ADS)

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

    2016-12-01

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

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

    USGS Publications Warehouse

    Kirschbaum, Mark A.; Schenk, Christopher J.

    2010-01-01

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

  20. 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

  1. 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

  2. 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.

  3. Petrology, diagnosis, and sedimentology of oil reservoirs in Upper Cretaceous Shannon Sandstone Beds, Powder River basin, Wyoming

    SciTech Connect

    Hansley, P.L.; Whitney, C.G.

    1990-01-01

    This paper reports on a study of the petrology of the Shannon Sandstone Member that indicates diagenetic alterations of outcrop and near-surface sandstones cannot be used to predict the diagenesis of deeply buried sandstones. Textural relations show that oil migrated to reservoirs late in the postdepositional history of the Shannon. Petrologic and sedimentologic data suggest that an alternative depositional model (for example, a nearshore rather than mid-shelf setting) should be considered for the Shannon.

  4. 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.

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

    NASA Astrophysics Data System (ADS)

    Magoba, Moses; Opuwari, Mimonitu

    2017-04-01

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

  6. 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.

  7. Fan-delta hydrocarbon reservoirs: example from Utikuma-Nipisi Fields, Alberta

    SciTech Connect

    Horne, J.C.; Reel, C.L.; Campbell, C.V.

    1985-02-01

    Because large amounts of hydrocarbons have been found in reservoirs of deltaic origin, deltas have been extensively studied in both the modern and rock record. Internal morphologies and geometries of reservoir-potential deposits within most types of deltas are today reasonably well understood. Fan deltas and the geometries of their sandstone reservoir bodies are exceptions. To provide a better understanding of fan-delta reservoirs, 700 wells and 365 cores from the Utikuma-Nipisi fields of north-central Alberta were studied in detail. The Utikuma-Nipisi fields, which contain 751.4 million bbl of oil reserves in fan deltas, produce from structural-stratigraphic traps in Middle Devonian Gilwood sandstones of the Watt Mountain Formation. These sediments are part of the clastic apron that surrounded the Peace River arch, a positive granitic terrane that had relief of more than 2300 ft during Middle Devonian time. In the Utikuma-Nipisi area, arkosic sediments were transported from the Peace River arch by ephemeral braided streams and deposited as a fan delta at the margin of the Elk Point Sea. In upper reaches of the delta, porosities and permeabilities in the course alluvial fan-braided stream portions have been occluded by fine-grained sieve deposits. Seaward of the delta front, prodelta sediments act as fine-grained permeability barriers. Only in the delta front have significant reservoir-potential porous deposits accumulated. These primary intergranular porosities and permeabilities are attributable to sorting and reworking by fluvial processes as well as wave and tidal energies in the depositional basin. Discontinuities in these delta-front reservoirs were the result of delta-lobe switches. Results of this analysis suggest hydrocarbon exploration in fan deltas should target delta-front depositional settings.

  8. 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.

  9. 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.

  10. 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.

  11. 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.

  12. 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

  13. 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

  14. 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.

  15. 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.

  16. Grain-scale deformation in granular materials: time-lapse XCT-imaging of a deforming reservoir sandstone

    NASA Astrophysics Data System (ADS)

    Hangx, Suzanne; Cordonnier, Benoît; Pijnenburg, Ronald; Renard, François; Spiers, Christopher

    2017-04-01

    Relating macroscopic deformation of granular media to grain-scale processes, such as grain fracturing, has been a focus of many studies. Understanding these processes is key for predicting surface subsidence and induced seismicity caused by hydrocarbon depletion, the hydraulic fracturing response of geothermal reservoirs, and post-seismic crustal deformation. With the development of state-of-the-art techniques, such as time-lapse X-ray tomography imaging during triaxial deformation, new avenues to investigate the operating mechanisms have opened up. As a first step to understanding grain-scale deformation processes, we performed a deformation experiment on highly porous sandstone, obtained from a depleting gas reservoir, using a novel small-scale triaxial deformation apparatus coupled to high-resolution 4D X-ray tomography, available at the European Synchrotron Radiation Facility (ESRF, Grenoble) and Université Grenoble Alpes. This state-of-the-art apparatus allows for 3D time-lapse imaging of samples, while deforming at pressure, temperature and fluid flow conditions relevant for geological reservoirs. We performed our experiment at relevant in-situ reservoir conditions (T = 100˚ C, 10 MPa pore pressure, 40 MPa effective confining pressure). Axial stress was increased step-wise until failure occurred, while continuously imaging deformation. This enables us to monitor progressive grain failure, and strain localisation, during deformation in real-time. Though the vast amount of data obtained from even a single test poses challenges for data analysis, this presentation will address the first results obtained from this experiment.

  17. Controls on diagenesis of Lower Cretaceous reservoir sandstones in the western Sable Subbasin, offshore Nova Scotia

    NASA Astrophysics Data System (ADS)

    Karim, Atika; Pe-Piper, Georgia; Piper, David J. W.

    2010-03-01

    Lower Cretaceous deltaic sandstones of the Scotian Basin, offshore eastern Canada, are important gas reservoirs. The influence of several factors on diagenesis has been investigated: depositional lithofacies, sea level changes, chemistry of basinal sediments and basinal fluid flux during burial. The distribution and chemistry of diagenetic minerals was determined from nine wells located along a dip section of the Sable Subbasin. Mineral type and paragenesis were characterized using a combination of optical petrography, back-scattered electron images, and electron microprobe analyses. Siderite is unusually abundant in marine sediments of the Scotian Basin and has thus been studied in detail. Siderite occurs in several generations. Early and late siderites are similar in chemical composition, suggesting buffering by pre-existing siderite, but rare low-Mg siderite is related to a greater contribution of meteoric water. Siderite has locally dissolved to create microporosity and has suppressed quartz overgrowths. Siderite is most common in those muddy prodeltaic lithofacies where there is the highest availability of detrital ilmenite. Reactive Fe released by breakdown of this ilmenite is responsible for the unusual presence of early siderite in marine sediments, with the Ca and Mg content of the siderite indicating fully marine waters. Lithofacies have a strong influence on early diagenetic mineral assemblages. Lithofacies deposited in the transgressive system tract have abundant early Fe-calcite and siderite. Early kaolinite occurs principally in proximal (fluvial and river mouth) lithofacies, where meteoric water was most likely available during the deposition. Contrary to other studies, we find little impact of sequence stratigraphy on diagenetic minerals except in the transgressive system tract. Mesogenetic minerals are related to flux of formation water and maturing hydrocarbon products, resulting first in pyrite and siderite and later in ankerite and ferroan

  18. 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.

  19. 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.

  20. 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

  1. 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.

  2. The point lookout sandstone: A tale of two cores, or petrology, diagenesis, and reservoir properties of point lookout sandstone, southern Ute Indian reservation, San Juan Basin, Colorado

    SciTech Connect

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

    1993-01-01

    Petrographic analysis of two cores of the Point Lookout Sandstone, in conjunction with an interpretation of depositional environments and electric logs, adds new information to our knowledge of this significant gas reservoir. Thin section analyses show the Point Lookout sandstone are quartz-rich, fine to very-fine grained, and contain moderately variable quantities of potassium feldspar (2 to 20 modal percent) and lithic fragments (9 to 30 modal percent). Locally, sandstone is tightly cemented by carbonate cement; clays are not important as cementing agents, although they significantly reduce permeability of some samples. Thin section and scanning electron microscope (SEM) analyses indicate that pores are small; many are intergranular micropores between crystals of authigenic clay. Mercury-injection capillary pressure measurements show that pore throats range between approximately 0.4 and 40 micrometers in diameter during initial entry of mercury. Measured porosities range from 4 to 20 percent; reduction of porosity by increasing confining stress is variable, but is typically small. Ambient permeabilities range from 0.03 to 82 millidarcies. Permeability in some samples is sensitive to increasing confining stress, especially in samples in which initial permeability is low. Under confining stress approximating reservoir conditions, in situ permeability may be less that 5 percent of the ambient permeability for those samples that display small pore-throats. Depositional environments are highly variable and range from lower shoreface to coastal plain and include minor deltaic environments. The best reservoir characteristics are generally in the upper shoreface sandstones. 21 refs., 11 figs., 1 tab.

  3. Abnormal pressure, natural fractures, and prolific hydrocarbon production in Fall river Sandstone, deep Powder River basin, Wyoming

    SciTech Connect

    Sonnenberg, S.A.; Meissner, F.F.

    1986-08-01

    Prolific hydrocarbon production from the Lower Cretaceous Fall River (Dakota) sandstone occurs in several fields in the deep overpressured portion of the Powder River basin. Most of the production to date comes from Buck Draw field at depths greater than 12,000 ft (3657 m). Individual wells in the field are capable of producing more than 2000 BOPD and have cumulatively produced in excess of 1 million bbl. Production comes mainly from stratigraphic traps. The Fall River Formation consists of fluvial, deltaic, and marine sandstones. Most of the productive sandstones in the Buck Draw area are interpreted to be fluvial (point bar) in origin. This interpretation is based upon log-curve shape, mapped subsurface trends, and the vertical sequence of sedimentary structures, lithologic textures, and mineralogic composition that was observed in cores. The fluvial sandstones were deposited by a meandering river that incised through previously deposited delta-front and marine sandstones. The delta-front and marine sandstones are in transitional contact with the underlying Fuson Shale, whereas the fluvial sandstones are in erosional contact with the Fuson. The updip traps to the fluvial sandstones are clay plugs in abandoned meander loops and the less-permeable delta-front and marine sandstones.

  4. 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.

  5. Use of nanoparticles to improve the performance of sodium dodecyl sulfate flooding in a sandstone reservoir

    NASA Astrophysics Data System (ADS)

    Ahmadi, Mohammad Ali

    2016-12-01

    One of the prominent enhanced oil recovery (EOR) methods in oil reservoirs is surfactant flooding. The purpose of this research is to study the effect of nanoparticles on the surfactant adsorption. Real reservoir sandstone rock samples were implemented in adsorption tests. The ranges of the initial surfactant and nano silica concentrations were from 500 to 5000 ppm and 500 ppm to 2000 ppm, respectively. The commercial surfactant used is sodium dodecyl sulfate (SDS) as an ionic surfactant and two different types of nano silica were employed. The rate of surfactant losses extremely depends on the concentration of surfactant in the system, and it was found that the adsorption of surfactant decreased with increasing the concentration of nano silica. Also, it was found that hydrophobic nano silica is more effective than hydrophilic nanoparticles.

  6. 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

  7. 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.

  8. Influence of high-frequency strandline cycles on internal reservoir geometry: Point Lookout sandstone, New Mexico and Colorado

    SciTech Connect

    Wright, R.

    1989-03-01

    High-frequency (< 100,000 years) transgressive-regressive strandline couplets that form basic building blocks of individual marine shoreface sandstones strongly influence strandline migration pattern and internal reservoir geometry. At reservoir scale, couplets average 7-10 m thick and are characterized by repetitive stacking of genetically related sandstone-mud rock packages. Individual cycles, or architectural elements, correlate in 3-D outcrop for at least 30 km, are locally bundled into larger discrete packages of five to eight constituent cycles, and are distinguishable in well logs. Contrary to long-held opinion, many of these cycles are not asymmetric. Rather, they contain thin (< 3 m) transgressive systems tracts that are overlain by thicker (< 7 m) regressive systems tracts and which are separated from one another by a pronounced downdip surface. Transgressive mud rocks fine upward from siltstone to clay-shale and coarsen landward less than 10 km into thinly interbedded sandstones with abundant siderite lags. Regressive mud rocks coarsen upward and landward into prograding shoreface sandstones that may overlie transgressive sandstones in proximal positions. Landward facies transitions within transgressive and regressive components of a single cycle vary, resulting in complex lithofacies interlayering. The significance for reservoir studies is that repeated transgressive systems tracts form predictable intraformational stratigraphic markers which may influence both horizontal and vertical fluid migration pathways. Importantly, the standard vertical profile fails to properly interpret transgressive deposits (especially sandstones) in the absence of a well-constrained lateral model.

  9. 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.

  10. Reservoir characteristics of low-permeability sandstones in the Rocky Mountains

    SciTech Connect

    Byrnes, A.P.

    1997-01-01

    Understanding gas production from low-permeability sandstones requires an understanding of the in situ porosity, brine saturation, and effective gas permeability at reservoir brine saturation. Diagenesis in these sandstones commonly resulted in the destruction of much of the original intergranular porosity and left dissolved grains, clay-filled pores, and sheet-like connecting intergranular pore throats. Pore throats or channels that connect larger pores typically range in size from 1 to 0.1 micron and represent only a small portion of the total porosity. In most low-permeability sandstones, porosity is not significantly changed by confining stress changes, but in situ effective gas permeabilities range from 10 to 1,000 times less than routine air permeability. The influence of confining stress on permeability can be attributed primarily to the decrease in size of the thin, tabular pore throats that connect the larger pores. Under stress, pore throats decrease in diameter by up to 50% to 70% resulting in permeability decreases of 10 to 40 times. Gas effective permeabilities also decrease rapidly to less than 1% of absolute values at water saturations above approximately 40% to 50%. {open_quotes}Irreducible{close_quotes} water saturations increase with decreasing porosity and permeability, and, in sandstones with less than 0.01 md permeability, {open_quotes}irreducible{close_quotes} water saturations increase dramatically. Cumulative flow and storage capacity plots indicate that very thin higher permeability intervals typically yield a large percentage of the cumulative flow capacity. Increased water saturations due to drilling or stimulation result in lower effective gas permeabilities and can unknowingly be stabilized by capillary pressure forces if pore pressures are decreased. This type of formation damage can be remedied by increasing the gas pore pressure to displace mobile water.

  11. 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.

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

    NASA Astrophysics Data System (ADS)

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

    2017-05-01

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

  13. Imaging pore space in tight gas sandstone reservoir: insights from broad ion beam cross-sectioning

    NASA Astrophysics Data System (ADS)

    Desbois, G.; Enzmann, F.; Urai, J. L.; Baerle, C.; Kukla, P. A.; Konstanty, J.

    2010-06-01

    Monetization of tight gas reservoirs, which contain significant gas reserves world-wide, represents a challenge for the entire oil and gas industry. The development of new technologies to enhance tight gas reservoir productivity is strongly dependent on an improved understanding of the rock properties and especially the pore framework. Numerous methods are now available to characterize sandstone cores. However, the pore space characterization at pore scale remains difficult due to the fine pore size and delicate sample preparation, and has thus been mostly indirectly inferred until now. Here we propose a new method of ultra high-resolution petrography combining high resolution SEM and argon ion beam cross sectioning (BIB, Broad Ion Beam) which prepares smooth and damage free surfaces. We demonstrate this method using the example of Permian (Rotliegend) age tight gas sandstone core samples. The combination of Ar-beam cross-sectioning facility and high-resolution SEM imaging has the potential to result in a step change in the understanding of pore geometries, in terms of its morphology, spatial distribution and evolution based on the generation of unprecedented image quality and resolution enhancing the predictive reliability of image analysis.

  14. 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.

  15. 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.

  16. Detection of new hydrocarbon reservoir using hydrocarbon microtremor combined attribute analysis

    NASA Astrophysics Data System (ADS)

    Ramadhan, Dimmas; Nugraha, Andri Dian; Afnimar, Akbar, Muhammad Fadhillah; Mulyanagara, Guntur

    2013-09-01

    An increasing demand for oil and gas production undoubtedly triggered innovation in exploration studies to find new hydrocarbon reservoir. Low-frequency passive seismic method named Hy MAS (Hydrocarbon Microtremor Analysis) is a new method invented and developed recently by Spectraseis which provide a quick look to find new hydrocarbon reservoir prospect area. This method based on empirical study which investigated an increasing of spectra anomaly between 2 - 4 Hz above reservoir but missing from the measurement distant from the reservoir. This method is quite promising because it has been used as another DHI (Direct Hydrocarbon Indicator) instead of active seismic survey which has some problem when applied in sensitive biomes. Another advantage is this method is completely passive and does not require seismic artificial excitation sources. In this study, by utilizing many attributes mentioned in the latest publication of this method, we try to localize new hydrocarbon prospect area outside from the proven production field. We deployed 63 stations of measurement with two of them are located above the known reservoir production site. We measured every single attribute for each data acquired from all station and mapped it spatially for better understanding and interpretation. The analysis has been made by considering noise identification from the measurement location and controlled by the attribute values from the data acquired by two stations above the reservoir. As the result, we combined each attribute analysis and mapped it in weighted-scoring map which provide the level of consistency for every single attribute calculated in each station. Finally, the new reservoir location can be suggested by the station which has a weighted-score around the values from the two production reservoir stations. We successfully identified 5 new stations which expected to have good prospect of hydrocarbon reservoir.

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

    SciTech Connect

    Chidsey, Jr, Thomas C.

    2001-10-31

    The objective of the Ferron Sandstone project was to develop a comprehensive, interdisciplinary, quantitative characterization f 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 was 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.

  18. 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.

  19. Dawsonite occurrences related to the age and origin of CO2 influx in sandstone reservoirs: A case study in the Songliao Basin, NE China

    NASA Astrophysics Data System (ADS)

    Li, Fulai; Li, Wenshuai; Yu, Zhichao; Liu, Na; Yang, Huidong; Liu, Li

    2017-01-01

    Dawsonite is often associated with CO2-rich gas reservoirs, and it is regarded as a "trace mineral" for recording migration and accumulation of CO2. Following accepted petrological, mineralogical, and geochemical principles, we used several methods (described herein) to study the Cretaceous dawsonite-bearing sandstone reservoirs in the Songliao Basin, China. We used the ideas of "sequencing" and "timing" to verify the influx stages of CO2 and hydrocarbons, dividing their influx sequence pattern and building a CO2-influx timeframe. First, we determined the stable isotopic ratios of dawsonite and CO2 in gas and oil reservoirs, and found that the CO2 in? dawsonite is of a mantle-derived magma origin. Second, we differentiated an early/late-stage oil and gas influx and a midmantle source influx through the study of diagenetic paragenetic sequences, formation water, and fluid inclusions in the dawsonite-bearing sandstones. Combining burial/thermal-history curves and illite K-Ar dates from the study area, we determined that the early-stage oil and gas influx, late oil and gas influx, and medium CO2 influx occurred at 85-58.8 Ma, 41-20 Ma, and 58.8-41 Ma (Paleocene and Eocene), respectively. Finally, we observed a coupling relationship between CO2 influx and Shuangliao volcanic activities and material compositions, as constrained by volcanic activity history in the basin since the Late Cretaceous.

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

    NASA Astrophysics Data System (ADS)

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

    2016-12-01

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

  1. 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)

  2. Factors controlling porosity and permeability in geopressured Frio sandstone reservoirs, general crude oil/Department of Energy Pleasant Bayou test wells, Brazoria County, Texas

    SciTech Connect

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

    1980-06-01

    Reservoir characteristics of Frio sandstones in the GCO/DOE Pleasant Bayou No. 1 and No. 2 wells are influenced by depositional environment, sandstone composition, and diagenetic history. The sandstones and shales were deposited in deltaic and continental slope environments. Fluvial channel and distributary-mouth bar sandstones are most favorable for development and preservation of the porosity needed for a geothermal reservoir. Sandstones in the geopressured zone are lithic arkoses and feldspathic litharenites. Depositional matric (detrital material less than 20 micrometers in size) occluded most or all of the potential primary porosity between grains in many of the fine-grained sandstones at the time of deposition. Even if cements are present, dissolution of grains and development of secondary porosity do take place. Permeable geopressured sandstone reservoirs are characterized by porosity that is dominantly secondary. 12 references.

  3. 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.

  4. Seismic modeling, rock physics, avo and seismic attribute analysis for illuminating sandstone facies of the Late Ordovic Ian Mamuniyat Reservoir, R-Field, Murzuq Basin-Libya

    NASA Astrophysics Data System (ADS)

    Abushalah, Yousf Milad

    The Late Ordovician Mamuniyat Formation is the main hydrocarbon reservoir in the R-Field in Murzuq Basin, SW Libya. The Lower Mamuniyat, which is the only unit that was encountered in the study area, is composed of sandstone facies called Clean Mamuniyat and shaly sandstone facies called Dirty Mamuniyat. One major problem with the development of the R-Field is the difficulty of distinguishing the two units so this project was aimed to develop better methods for distinguishing between the two units of the Lower Mamuniyat. The other problem is to distinguish the transgressive shaly facies of the Bir Tlacsin, which has an impact on the hydrocarbon accumulation. Those issues manifested in limit of seismic resolution and interference that resulted from the converted shear mode waves. The dissertation was divided into three chapters. In the first chapter, seismic modeling using a deterministic and a Ricker wavelet were used to investigate the interference effects on the poststack seismic data and a bandpass filter was used to remove those effects. Instantaneous frequency, spectral-based colored inversion and rock physics were, then applied to determine the distributions of the sandstone facies of the Lower Mamuniyat Formation and to interpret the depositional setting of it. In the second chapter, spectral decomposition and inverted density were utilized to determine the distribution of the shaly facies of Bir Tlacsin, and its temporal thickness and to remap the top reservoir. In the last chapter, amplitude variation with offset (AVO) modeling, ray tracing, and spectral analysis were used to investigate the mode conversion and its effect on AVO signature, the amplitude of the near-mid and far offsets and frequency contents. Data enhancement then was performed using partial stacks and a bandpass filter.

  5. 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

  6. Predictive modeling of CO2 sequestration in deep saline sandstone reservoirs: Impacts of geochemical kinetics

    SciTech Connect

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

  7. Sea level and paleotectonic controls on distribution of reservoir sandstone of Lower Cretaceous Muddy Sandstone, Hilight Field, Powder River basin, Wyoming

    SciTech Connect

    Wheeler, D.M.; Gustason, E.R.

    1987-05-01

    To date, over 74 million bbl of oil have been produced from stratigraphic traps at Hilight field. Production is primarily from thin but stratigraphically complex fluvial and shallow marine sandstone of the Lower Cretaceous Muddy Sandstone. The deposition and preservation of these reservoirs were controlled by the interplay between sea level and tectonics. The Muddy Sandstone in Hilight field was deposited during a late Albian sea level rise. It onlaps an erosional surface, developed during the preceding sea level drop, including a dendritic valley system cut deeply into the underlying Skull Creek Shale. In this area, the Muddy consists of four members that are bounded by transgressive disconformities. These members were deposited during stillstands in the overall rise of sea level. The lower two members consist of fluvial and fluvial-estuarine deposits which fill the valley system; the upper two members consist of fluvial-deltaic and barrier island deposits. Three northeast-trending lineaments transect Hilight field. These lineaments are interpreted to represent basement faults that experienced recurrent movement during Muddy deposition. Relative structural downdrop controlled the orientation of drainages that cut the Hilight valley system. Recurrent movement provided structural and topographic lows within which relatively thick fluvial-deltaic and barrier island sandstones were deposited and preserved. Thinner sequences were deposited and subsequently eroded on adjacent structural and topographic highs.

  8. Geologic parameters of reservoir sandstones as applied to enhanced oil recovery

    SciTech Connect

    Gaida, K.H.; Kessel, D.G.; Volz, H.; Zimmerie, W.

    1987-03-01

    This paper discusses the importance of geological parameters of reservoir sandstones and their fieldwide distribution for proper planning and operation of EOR projects. Such parameters are gross and net pay thickness, permeability, porosity, grain size distribution, composition of detrital minerals, amount and type of mineral cements, and amount and type of clay minerals. Fieldwide distribution of these parameters is shown for the case history of the Hankensbuttel-Sud oil field in the Federal Republic of Germany. Overlaying the distribution maps made it possible to distinguish areas with excellent to good potential for chemical flooding from areas of fair to poor potential. On the basis of these results, a surfactant/polymer flood pilot has been initiated in this field.

  9. 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.

  10. 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.

  11. Sedimentology and reservoir potential of Matilija sandstone: an Eocene sand-rich deep-sea fan and shallow-marine complex, California

    SciTech Connect

    Link, M.H.; Welton, J.E.

    1982-10-01

    A deep-sea fan facies model for the Matilija Sandstone (southern California) regression from turbidite to shallow-marine to brackish deposits are documented. In addition, reservoir characteristics and the diagenetic history of the deep-sea fan complex is discussed. Despite thick, favorable source beds and generally good initial reservoir characteristics, the Matilija Sandstone is not a productive unit of the Ventura basin because of low reservoir permeability and porosity.

  12. 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.

  13. 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

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

    NASA Astrophysics Data System (ADS)

    Burki, Milad; Darwish, Mohamed

    2017-06-01

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

  15. 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.

  16. 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.

  17. Geothermal energy from the Main Karoo Basin (South Africa): An outcrop analogue study of Permian sandstone reservoir formations

    NASA Astrophysics Data System (ADS)

    Campbell, Stuart A.; Lenhardt, Nils; Dippenaar, Matthys A.; Götz, Annette E.

    2016-04-01

    The geothermal potential of the South African Main Karoo Basin has not been addressed in the past, although thick siliciclastic successions in geothermal prone depths are promising target reservoir formations. A first assessment of the geothermal potential of the Karoo Basin is based on petro- and thermophysical data gained from an outcrop analogue study of Permian sandstones in the Eastern Cape Province, and evaluation of groundwater temperature and heat flow values from literature. A volumetric approach of the sandstones' reservoir potential leads to a first estimation of 2240 TWh (8.0 EJ) of power generation within the central and southern part of the basin. Comparison with data from other sedimentary basins where deep geothermal reservoirs are identified shows the high potential of the Karoo for future geothermal resource exploration, development and production. The mainly low permeability lithotypes may be operated as stimulated systems, depending on the fracture porosity in the deeper subsurface. In some areas auto-convective thermal water circulation might be expected and direct heat use becomes reasonable. The data presented here serve to identify exploration areas and are valuable attributes for reservoir modeling, contributing to (1) a reliable reservoir prognosis, (2) the decision of potential reservoir stimulation, and (3) the planning of long-term efficient reservoir utilization.

  18. 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

  19. Structural and stratigraphic compartmentalization of the Terry Sandstone and effects on reservoir fluid distributions: Latham Bar Trend, Denver Basin: Colorado

    SciTech Connect

    Al-Raisi, M.H.; Slatt, R.M.; Decker, M.K.

    1996-01-01

    The Latham Bar Trend, located in the Denver Basin of Colorado, is an elongate sandstone which extends in a northwest direction for more than 6 mi and is up to 1-2 mi wide. It is now under infill drilling on 40-acre spacing, with more than 65 wells producing from the Upper Cretaceous Terry Sandstone. Detailed analysis of four cores and 210 wells suggests that the Terry Sandstone within the Lantham Bar Trend was deposited in an open marine environment. Reservoir quality, particularly permeability, is primarily facies controlled, and secondarily controlled by diagenetic products. Estimated ultimate recovery (EUR) values in wells are related to thickness of this facies. Structural analysis indicates the Trend is dissected by a series of northeast-trending, northwest-dipping faults with vertical displacements of 30-100 ft. (9-30 m). The faults are interpreted to be sealing, separating the Terry Sandstone into isolated fault blocks, on the basis of the following criteria: (1) normalized GOR values exhibit a non-systematic areal distribution across the trend, but show systematic up-structure increases in GOR within individual fault blocks; (2) initial API gravity values from different wells also are non-systematically distributed areally across the Trend, but show similar groupings within fault blocks; (3) EUR values within each fault block exhibit a positive correlation with thickness of cross-bedded sandstone facies; (4) individual wells with specific normalized GOR values occur at lower structural elevations than wells in adjacent fault blocks with lower GORs, giving rise to structural reversal of fluid distributions. Recognition of the facies control on reservoir quality, reservoir facies thickness, sealing capacity of normal faults, and resultant compartmentalization can help explain complex stratigraphic and areas distribution patterns of gas and oil in these and other strata in the Denver Basin and to maximize reservoir producibility and exploration success.

  20. 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.

  1. 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.

  2. 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

  3. 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.

  4. 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

  5. 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.

  6. 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.

  7. 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.

  8. 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.

  9. Geologic reservoir characterization of Humphreys sandstone (Pennsylvanian), east Velma field, Oklahoma

    SciTech Connect

    McGowen, M.K.

    1988-02-01

    East Velma field is located in the Ardmore basin, Stephens County, Oklahoma, on the north flank of a truncated anticline with dips that range from 30/degrees/-60/degrees/. The discovery well of the Humphreys sand unit was drilled in April 1951 and an original oil in place of 32.7 million bbl was calculated. Primary depletion was by solution gas drive with gas reinjection and gravity drainage which was enhanced by the steep structural dip of the field. A waterflood that was initiated in 1983 and a proposed CO/sub 2/ miscible displacement program to further enhance field recovery prompted the need to develop a detailed geologic description of the reservoir. Core studies indicate that the Humphreys sandstone was deposited in a shallow marine, tidally dominated environment. Subfacies include sand-rich tidal flat and tidal channel deposits. The unit is primarily composed of very fine to fine-grained, moderately to well-sorted quartzarenites. Dominant sedimentary structures include bidirectional and unidirectional current ripples, cross-laminations, common slump structures, and zones abundant and scattered burrows.

  10. 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.

  11. 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.

  12. Evaluation of Geologic CO2 Sequestration Potential of the Morrow B Sandstone in the Farnsworth, Texas Hydrocarbon Field using Reactive Transport Modeling

    NASA Astrophysics Data System (ADS)

    Khan, R. H.; Appold, M. S.; McPherson, B. J. O. L.; Balch, R. S.; White, M. D.

    2016-12-01

    The objective of the present study is to evaluate the effects of injection of CO2 into the Morrow B Sandstone reservoir in the Farnsworth, Texas hydrocarbon field in order to predict the reservoir's potential for long term CO2 sequestration. Three-dimensional reactive transport simulations were conducted using the TOUGHREACT software and the ECO2N equation of state on a grid representing the Morrow B Sandstone and parts of the adjacent Morrow Shale layers. Supercritical CO2 was injected in the simulation through nine wells for ten years at rates on the order of several kg/s at a constant enthalpy of 3.01 x 105 J/kg. The simulations showed most of the injected CO2 to dissolve into the formation water and to migrate westward. An immiscible fraction of the injected CO2 accumulated near the wells during the injection period, reaching a peak saturation of 0.98. After injection ceased, the immiscible CO2 gradually dissolved into the formation water over the next several decades. The simulations predicted minor dissolution of albite, chlorite, and illite, minerals that are present in the reservoir matrix. The simulations also predicted minor precipitation of dolomite, kaolinite, smectite, and quartz within the aqueous CO2 plume. However, the amounts of mineral precipitation and dissolution were not great enough to cause significant changes in the porosity and permeability of the reservoir, most likely because of its quartz-rich nature (about 85% by volume), which together with the low salinity of the formation water offer little reaction potential for the injected CO2. These results suggest that for the century-scale time scales simulated, CO2 should be sequestered mainly by hydrodynamic trapping in the Morrow B Sandstone within the boundaries of the Farnsworth field. Funding for this project is provided by the U.S. Department of Energy's National Energy Technology Laboratory through the Southwest Partnership on Carbon Sequestration under Award No. DE-FC26-05NT42591.

  13. 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.

  14. 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).

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

    PubMed

    Exner, Ulrike; Kaiser, Jasmin; Gier, Susanne

    2013-05-01

    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.

  16. 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

  17. 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.

  18. 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.

  19. Multilayer stress field interference in sandstone and mudstone thin interbed reservoir

    NASA Astrophysics Data System (ADS)

    Guo, Jian-Chun; Luo, Bo; Zhu, Hai-Yan; Yuan, Shu-Hang; Deng, Yan; Duan, You-Jing; Duan, Wei-Gang; Chen, Li

    2016-10-01

    General fracturing and separate layer fracturing play an important role in sandstone and mudstone thin interbed (SMTI) reservoirs, where one of the main issues is to control the excessive height growth of fracturing. The fracture propagation at the interface depends on the induced stress produced by the hydraulic fracturing construction. This paper employed a poroelastic coupled damage element with the cohesive zone method (CZM) to establish a 2D fracture quasi-static propagation model. A parametric study was performed under different fracture height, fracture width, pumping rate, fluid viscosity, in situ stress, elastic modulus and tensile strength with this model. General fracturing and separate layer fracturing are compared with each other through fracture morphology and induced stress. The simulation results show that the absolute value of induced stress increases with the decrease in matrix stress near the fracture tip. As a result, the propagation of the fractures is much easier due to the weakened degree of compression. The growth of fracture height and width, the increase in pumping rate and the excessively large or small value of fluid viscosity lead to larger induced stress on the interface. Higher in situ stress, lower elastic modulus, and higher tensile strength of the interlayers can control the excessive height growth of fracturing. The simulated results also show that the fractures are more likely to be overlapped with each other in general fracturing compared to that in separate-layer fracturing. Results of the simulations suggest that lower pumping rates, the proper value of fluid viscosity, separate layer fracturing and interlayers with higher in situ stress, lower elastic modulus and higher tensile strength tend to limit fracture height. Finally, the proposed model was applied to a practical oil field case to verify its effectiveness.

  20. 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

  1. 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.

  2. 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.

  3. 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.

  4. 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.

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

    SciTech Connect

    Chaplin, J.R. )

    1989-08-01

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

  6. 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.

  7. 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.

  8. 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.

  9. Depositional facies, diagenesis, and reservoir quality of Ivishak sandstone (Sadlerochit Group), Prudhoe Bay field

    SciTech Connect

    McGowen, J.H.; Bloch, S.

    1985-02-01

    The Sadlerochit Group is a large fan-delta system comparable in size to the modern Kosi River wet alluvial fan of Nepal and India. Braided-stream processes distributed chert gravel and quartz and chert sand in radial fashion to construct the subaerial part of the fan delta. Fluvial energy, slope of the fan surface, and grain size decrease in a north to south basinward direction. There is also a decrease in scale of sedimentation units from source area seaward. Facies of the subaerial fan delta can be broadly categorized as midfan delta (alternating conglomerate and sandstone), distal fan-delta (chiefly sandstone), and abandoned channel-fill, overbank, and pond facies (mudstone, siltstone, fine-grained sandstone). Seaward of the subaerial fan delta are the delta-front and prodelta facies. Subaerial fan-delta and delta-front facies compose the Ivishak sandstone, which grades basinward into the Kavik shale, a prodelta facies. Diagenetic effects were gradually superimposed on the sediments deposited in the Sadlerochit fan-delta system. The sedimentary facies, and in particular their textural characteristics, seem to control the side and degree of diagenesis, including enhancement of porosity and permeability. Comparison of permeability trends among the facies of the Ivishak sandstone with permeability patterns displayed by unconsolidated sands with analogous grain size and texture, indicates that the general trends that existed in the Ivishak sediments are still recognizable in spite of the diagenetic overprint.

  10. 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

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

    NASA Astrophysics Data System (ADS)

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

    2015-12-01

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

  12. 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.

  13. 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.

  14. 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.

  15. 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.

  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. Investigations of illite and small scale fluid-rock interaction in Upper Carboniferous reservoir sandstones from the Lower Saxony Basin, Northwest Germany

    NASA Astrophysics Data System (ADS)

    Bock, Susanne; Zwingmann, Horst; Aehnelt, Michaela; Gaupp, Reinhard

    2013-04-01

    Illite is one of the most important minerals concerning the exploration of hydrocarbons. It is known, that illite reduces significantly porosity and permeability and deteriorates reservoir quality. Therefore the formation conditions are an issue of special interest. The Upper Carboniferous sandstones from the Lower Saxony Basin (LSB) show intense mechanical compaction and thus low porosity values (3-12 Vol.-%) and very low permeability values (0.001-0.1 mD). Petrographic observations indicate that fluid pathways must be hampered, but illite occurs in variable amounts. This study was intended to get a better understanding of the controlling factors of the illite formation in the LSB. This investigation, funded by the RWE Dea Germany, compares 18 samples of Upper Carboniferous sandstones (Westphalian C & D). These samples originate from three different study areas with varying burial histories within the Lower Saxony Basin (LSB), Northwest Germany. The southern margin offers a deep burial during Cretaceous with subsequent uplift/inversion. The center of the deepest burial is situated north of the southern margin and shows also a post-Cretaceous, but more intense uplift. Also the northern part with shallower burial depths was investigated. The locations have different initial thermal histories and resulting conditions for illite formation. Petrographic analyses revealed a consistent modal composition, which describes sublitharenitic sandstones. Most common authigenic phases are quartz, carbonate cements, and phyllosilicates like illite, kaolinite and locally chlorite. Several investigation methods were applied to detect differences between the illites from the locations. The age of last illite precipitation was determined by conventional K-Ar dating of clay fractions (< 2 µm). Using the burial history (known from literature) the illite age can be linked to the burial depth and related p-T conditions at this time. Additional vitrinite reflectance measurements provide

  18. 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.

  19. Geologic controls on reservoir properties of low-permeability sandstone, Frontier Formation, Moxa Arch, southwest Wyoming. Topical report, April 1989-April 1992

    SciTech Connect

    Dutton, S.P.; Scott, H.; Laubach, S.E.

    1992-06-01

    The report examines the influence of stratigraphy, diagenesis, natural fractures, and in situ stress on low-permeability, gas-bearing sandstone reservoirs of the Upper Cretaceous Frontier Formation along the Moxa Arch in the Green River Basin, southwestern Wyoming. The main stratigraphic controls on distribution and quality of Frontier reservoirs are sandstone continuity and detrital clay content. The Frontier was deposited in a fluvial-deltaic system, in which most reservoirs lie in marine upper shoreface and fluvial channel-fill sandstone facies. The major causes of porosity loss in Frontier sandstones during burial diagenesis were mechanical and chemical compaction and cementation by calcite, quartz, and authigenic clays. Despite extensive diagenetic modification, reservoir quality is best in facies that had the highest porosity and permeability at the time of deposition. Natural fractures are sparse in Frontier core, but outcrop studies show that fractures commonly are in discrete, irregularly spaced swarms separated by domains having few fractures. Natural fracture swarms are potential high-permeability 'sweet spots.' Stress-direction indicators give highly scattered estimates of maximum horizontal compression direction ranging from north to east or northeast. The scatter may reflect interference of natural fractures with measurements of stress directions, as well as spatially variable stress directions and low horizontal stress anisotropy.

  20. Reservoir sedimentology

    SciTech Connect

    Tillman, R.W.; Weber, K.J.

    1987-01-01

    Collection of papers focuses on sedimentology of siliclastic sandstone and carbonate reservoirs. Shows how detailed sedimentologic descriptions, when combined with engineering and other subsurface geologic techniques, yield reservoir models useful for reservoir management during field development and secondary and tertiary EOR. Sections cover marine sandstone and carbonate reservoirs; shoreline, deltaic, and fluvial reservoirs; and eolian reservoirs. References follow each paper.

  1. 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.

  2. 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.

  3. Application of Model Based Uncertainty Analysis to Hydrocarbon Reservoirs

    NASA Astrophysics Data System (ADS)

    Lyons, S. L.; Lee, L. W.

    2007-12-01

    Model-Based Uncertainty Analysis (MBUA) is a method to evaluate reservoir performance uncertainty using multiple 3D models. Experimental Design techniques are used to determine what 3D models are built (unique geologic models which are then simulated) based on the number of identified uncertain factors. This method captures main effects and factor interactions and results in a multivariable response surface for each desired outcome (e.g. expected ultimate recovery, original hydrocarbon in place) which can be used for Monte Carlo simulations. The entire MBUA process results in tornado plots, exceedence curves, and a method to build representative models. A key strength of the MBUA process is the ability to capture dynamic responses such as water rate, production at early times, and plateau length. These responses provide project teams a greater understanding of how their subsurface uncertainties impact field performance and can help guide additional technical work, development planning decisions and representative model building. We have applied either a full or partial MBUA process to several fields for the purposes of identifying key technical uncertainties and improving the development plan across likely outcomes. Once an initial base case model has been built, subsequent models (totaling 16-54 models) can be rapidly built and simulated using normal geologic and flow simulation model workflows. While the analysis is quick, all model results are required to complete the analysis, thus simulation time is the biggest bottleneck in the process. Production data have been incorporated through either history-matching the initial base case or examining Monte Carlo simulation results for potential trends. The uncertainty analysis provides a streamlined process to examine potential uncertainty factors and allows a project to make informed decisions regarding future technical work or potential mitigation plans. A process overview will be presented along with sample results

  4. 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%.

  5. 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.

  6. 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.

  7. 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.

  8. 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.

  9. 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.

  10. 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

    2002-04-04

    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.

  11. 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.

  12. 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.

  13. 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.

  14. Stratigraphy and hydrocarbon potential of Muddy sandstone, Wind River basin, Wyoming

    SciTech Connect

    Gustason, E.R.; Geesaman, R.C.; Sturm, S.D.; Wheeler, D.M. )

    1989-09-01

    The Lower Cretaceous (late Albian) Muddy Sandstone in the Wind River basin and adjacent areas rests unconformably upon the Thermopolis Shale and is disconformably overlain by and interfingers with the lower part of the Shell Creek Shale. The Muddy Sandstone is divided into five informal members: the Lazy B, Rozet, lower Recluse, upper Recluse, and Cyclone members. These members, defined as chronostratigraphic units bounded by bentonite beds, transgressive disconformities, and/or unconformities, consist of asymmetrical, coarsening and thickening-upward progradational deltaic/strand-plain and bay-fill deposits and/or asymmetrical, fining and thinning-upward aggradational valley-fill deposits. The Lazy B and Rozet members are marine progradational strand-plain deposits bounded by unconformities. They occur as discontinuous, erosional remnants in the western and northwestern parts of the study area. Following Rozet deposition, a major sea level fall resulted in the development of a headward-eroding valley system. During a subsequent sea level rise these valleys aggraded with fluvial/estuarine deposits of the Grieve member. Eventually the study area was blanketed by landward-stepping, progradational bay-fill, nearshore, and offshore marine deposits of the lower Recluse, upper Recluse, and Cyclone members. In addition to localized production from anticlinal or fault-bounded structural closure, the most significant oil and gas production is from updip pinch-outs of sand-rich valley fill of the Grieve member in the southeastern Wind River basin. Extensive outcrop and core analysis reveals these sand-rich paleovalleys, which range up to 10 mi wide and 100 ft thick, contain numerous scour-and-fill sequences composed of either fluvial bed load, fluvial suspended load, or abandoned channel deposits. Individual scour-and-fill sequences range up to 300 ft wide and up to 50 ft thick.

  15. 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

  16. 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

  17. 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.

  18. Seismic amplitude variation with offset: Its effects on weighted stacking, and its uses in characterization of sandstone and carbonate reservoirs

    NASA Astrophysics Data System (ADS)

    Madiba, Gislain Bolouvi

    An algorithm for weighted stacking, which is not particularly expensive in terms of computer time or memory and can be easily incorporated into routine processing is proposed. A comprehensive comparison of the proposed weighted stacking algorithm and the conventional stacking algorithm is conducted through testing on synthetics and a real data set from New Mexico, USA. This weighted stacking algorithm achieves the primary goal of signal-to-noise ratio improvement while at the same time providing better resolution, wider bandwidth, and a higher signal-to-noise ratio than the conventional stack. A novel hydrocarbon indicator [the water-filled porosity (S wv)], which is estimated from the ratio of P-velocity to S-velocity (Vp/Vs), is proposed and applied to characterize clastic hydrocarbon reservoirs in the North Sea. The separation between pore fluids and lithologies is enhanced by mapping from V p/Vs to Swv using an empirical crossplot-derived relationship. The Swv-V p/Vs plane still does not produce unique interpretations in many situations. However, the critical distinction, which is between hydrocarbon-bearing sands and all other geologic/reservoir configurations, is defined. Porosity is the dominant factor controlling reservoir signature for carbonate rocks. Acoustic impedance and seismic amplitudes are porosity and lithology indicators. Angle-dependent reflectivity effects are introduced for determination of fluid charactersitics by simultaneous elastic impedance inversion of three non-overlapping migrated common-angle stacked sections for P- and S-impedance (Ip and Is). Deviations of points from a water-filled baseline in the Ip-I s plane define a gas potential section that is used for direct identification of gas zones in the dolomitized limestone reservoirs of the Turner Valley Formation in southern Alberta, Canada. There is consistency with the known gas production at a well and agreement with gas index sections obtained through the use of Lame parameter

  19. 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.

  20. 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.

  1. Reservoir structures detection and hydrocarbons exploration using wavelet transform method in 2 oil fields in southwestern of Iran

    NASA Astrophysics Data System (ADS)

    Hassani, H.; Saadatinejad, M. R.

    2012-04-01

    reservoirs and differ for limestone and sandstone. In this way, CWT applied on vertical sections and in 4 different iso-frequency displaying. By comparing these figures at 10, 16, 24 and 32 Hz, the presence of low frequency shadows under reservoir could be seen. These shadows have distinctly different dynamic frequency responses rather than the background, probably because the hydrocarbons have changed the reflectivity of the reservoir as the anomalies at 10 Hz are bright. In the 16 Hz section, anomalies almost stand out, and the difference between them becomes relatively weak; yet, some of them are still brighter than other anomalies at higher frequencies. Consequently, these variations of anomalies at different frequencies can consider as indicator from presence of hydrocarbons in the target reservoir. Finally, selecting a suitable wavelet is important step of CWT method and in all mentioned usages, Morlet wavelet has beneficial properties to applying in our investigation. In fact, Morlet wavelet demonstrates velocity dispersion and energy absorption to identify fault and gas respectively.

  2. 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.

  3. 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.

  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. Depositional environments and hydrocarbon occurrence of upper Jurassic Cotton Valley sandstones, Mississippi, Louisiana, and Texas

    SciTech Connect

    Kornfeld, I.

    1985-02-01

    The sandstones of the Kimmeridgian (Jurassic) upper Cotton Valley Formation of Mississippi, northern Louisiana, and eastern Texas were deposited on a stable subsiding shelf. These sands are regressive and are part of a complex of deltaic and marine systems. They are quartz-rich and exhibit a variety of sedimentary structures. Cotton Valley fluvial-deltaic systems drained Paleozoic and younger highlands to the north and northwest, depositing sands on the shelf where they were subsequently reworked. Three depositional environments have been interpreted for these sands in Mississippi: (1) a constructive delta in the west-central part of the state, (2) a destructive delta in the east-central part of the state, and (3) an interdeltaic system in central Mississippi between the other systems. In northern Louisiana and northeastern Texas, the following environments have been interpreted: a proximal destructive delta system in northwest Louisiana and northeast Texas and another delta system in northeastern Louisiana with an interdeltaic system consisting of barrier beaches and barrier bars located centrally between them. Production is controlled by porosity and permeability barriers, fault traps, and salt- and basement-induced structures.

  6. 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.

  7. Chemistry of a low temperature geothermal reservoir: The Triassic sandstone aquifer at Melleray, FR

    SciTech Connect

    Vuataz, Francois-David; Fouillac, Christian; Detoc, Aylvie; Brach, Michel

    1988-01-01

    The Triassic sandstone aquifer offers on a regional scale, a large potential for low-temperature geothermal exploitation in the Paris Basin. The Na-Cl water n the aquifer has highly variable mineralization (TDS = 4 to 110 g/l) and a wide range of temperature (50º to >100ºC). Chemical studies have been carried out on the Melleray site near Orléans, where a single wel was producing a Na-Cl geothermal water (TDS = 35 g/l) at a wellhead temperature of 72ºC to provide heat for greenhouses. The purpose of these studies is to understand the chemical phenomena occurring in the geothermal loop and to determine the treatment of the fluid and the exploitation procedures necessary for proper reinjection conditions to be achieved. During the tests performed after the drilling operations, chemical variations in the fluid were noticed between several producing zones in the aquifer. Daily geochemical monitoring of the fluid was carried out during two periods of differing exploitation conditions, respectively pumping at 148 m{sup 3}/h and artesian flow at 36 m{sup 3}/h. Vertical heterogeneities of the aquifer can explain the variations observed for the high flowrate. Filtration experiments revealed that the particle load varies with the discharge rate and that over 95 weight % of the particles are smaller than 1 micrometer. The chemistry of the particles varies greatly, according to their origin as corrosion products from the well casing, particles drawn out of the rock or minerals newly formed through water-rock reactions. Finally, small-scale oxidation experiments were carried out on the geothermal fluid to observe the behavior of Fe and SiO{sub 2} and to favour particle aggregates for easier filtration or decantation processes.

  8. A parametric analysis of capillary pressure effects during the carbon sequestration injection process in a sandstone reservoir

    NASA Astrophysics Data System (ADS)

    Wu, H.; Pollyea, R.

    2016-12-01

    Geological Carbon Sequestration (GCS) is considered as a key method for mitigating the adverse effects of steadily increasing atmospheric CO2 concentrations. Numerical simulation is one technique for better understanding the injection, migration and leakage of supercritical CO2 (scCO2) during GCS. At the field scale, capillary pressure (Pcap) is an important factor governing the subsurface movement of scCO2. Constitutive models of Pcap as a function of wetting phase saturation (Sw) are essential to field-scale GCS simulations; however, such Pcap models are based on core-scale laboratory measurements. As a result, there exists uncertainty in the application of laboratory-measured Pcap models to field-scale GCS simulations. In this study, a parametric analysis of commonly used van Genucthen Pcap model is undertaken to quantify the effects of variability in the model parameter space. The study focuses on two parameters: the non-wetting phase entry pressure (P0) and the pore-size distribution index (λ), the latter of which controls curvature of the Pcap model. A two-dimensional parameter space is selected that covers a wide range of laboratory-scale Pcap measurements in the scCO2-brine system, and scCO2 injection processes are modeled within a homogeneous sandstone reservoir over the complete parameter space. Simulation results demonstrate how changes in the Pcap model parameters influence scCO2 migration within the storage reservoir. Maximum injection pressure is largely insensitive to variability of Pcap model parameters; however, vertical scCO2 migration is strongly controlled by Pcap model parameter selection. Since vertical scCO2 migration is the key point to estimate scCO2 leakage risk through caprock sealing, these results illustrate the importance of Pcap model parameter selection in field-scale numerical models of GCS.

  9. 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.

  10. The microbiology of hydrocarbon degradation in subsurface petroleum reservoirs: perspectives and prospects.

    PubMed

    Röling, Wilfred F M; Head, Ian M; Larter, Steve R

    2003-06-01

    The majority of the Earth's petroleum resource is partly biodegraded. This is of considerable practical significance and can limit economic exploitation of petroleum reserves and lead to problems during petroleum production. Knowledge of the microorganisms present in petroleum reservoirs, their physiological properties and the biochemical potential for hydrocarbon degradation benefits successful petroleum exploration. Anaerobic conditions prevail in petroleum reservoirs and biological hydrocarbon degradation is apparently inhibited at temperatures above 80-90 degrees C. We summarise available knowledge and conjecture on the dominant biological processes active during subsurface petroleum biodegradation.

  11. 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.

  12. 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

  13. Production data as an indicator of gas reservoir heterogenesity in the Vicksburg S sandstones (Oligocene), McAllen Ranch field, Hidalgo County, Texas

    SciTech Connect

    Wermund, E.G.; Langford, R.P. )

    1990-09-01

    To assess reservoir heterogeneity in low-permeability Vicksburg S sandstone reservoirs in McAllen Ranch gas field, production and pressure histories of 49 wells were analyzed; predominant well spacing is 80 acres. These histories were compared both fieldwide and in local areas defined by faults or facies. Production is through casing perforations, which commonly extend over 600 ft gross intervals within vertically stacked potential reservoir sandstones. The S reservoir comprises five sand-rich intervals that together have produced 249 bcf of gas since 1965. Cumulative production per well ranges from 39 bcf for 24 years to 0.8 bcf in 11 years. Average cumulative production is 6.3 bcf per well. To date, the largest average monthly production for a well is over 360 Mmcf; the mean for average monthly production (based on publicly available data) for all wells is 30.5 Mmcf. There is poor correlation among gross thicknesses of perforated intervals and cumulative production (R = 0.024). Wellhead shut-in pressures range from 12,500 psi on completion to 1,300 psi at abandonment. Maps of cumulative production and normalized BHP/Z show good production/pressure correlations. The slopes of regression curves for (1) monthly production decline histories and (2) periodic tests of daily production of adjacent well pairs show little influence from adjacent well completions or refracturing, even at relatively close well spacing. Monthly production in a newly completed or refractured adjacent well commonly exceeds the last production rate of a nearby older well. Production and pressure histories in adjacent well pairs suggest that limited communication occurs between S sandstone reservoirs of paired wells. This limited communication may be a consequence of limited drainage radius due to low permeability and of stratigraphic/diagenetic heterogeneity within the reservoir.

  14. 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.

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

    NASA Astrophysics Data System (ADS)

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

    2013-04-01

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

  16. 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.

  17. 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.

  18. 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.

  19. 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.

  20. Hydrocarbon exploration in Western Oregon and Washington

    SciTech Connect

    Armentrout, J.M.; Suek, D.H.

    1985-04-01

    Continuing development of the Mist gas field and stepout discovery wells affirm the hydrocarbon prospectivity of western Oregon and Washington. Reservoir sandstones in the Mist area are in the Cowlitz Formation of middle to late Eocene age. Reservoir-quality sandstones have average porosities of 25% and average permeabilities of 200 md. The reservoir sands are wellsorted feldspathic-quartzose sandstones and are less susceptible to diagenetically formed pore-filling authigenic minerals than are the more lithic sandstones of other horizons and less well-sorted depositional environments. Potential hydrocarbon source rocks consist of marine shale to coaly facies. Organic matter is predominately terrestrially derived. Mist gas field pools are small and have variable gas types, suggesting to some workers that the gas is generated from rocks immediately adjacent to the reservoir. Gas wetness and delta/sup 13/C values indicate that gas from the Bruer, Flora, and Newton pools is probably thermally generated. Shales encasing the Mist gas field sandstone reservoirs are thermally immature, having vitrinite reflectance values less than 0.4%. Thermal gas most likely would have been generated downdip within nearby depocenters and migrated into the reservoir. The integration of paleogeographic models for mineralogic provenance, well-sorted sand accumulation, and thermal maturation within Cenozoic depocenters provides an exploration strategy for defining areas of highest hydrocarbon potential in western Oregon and Washington.

  1. 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

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

    NASA Astrophysics Data System (ADS)

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

    2017-03-01

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

  3. 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.

  4. 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.

  5. Pore-throat sizes in sandstones, tight sandstones, and shales

    USGS Publications Warehouse

    Nelson, Philip H.

    2009-01-01

    Pore-throat sizes in silidclastic rocks form a continuum from the submillimeter to the nanometer scale. That continuum is documented in this article using previously published data on the pore and pore-throat sizes of conventional reservoir rocks, tight-gas sandstones, and shales. For measures of central tendency (mean, mode, median), pore-throat sizes (diameters) are generally greater than 2 μm in conventional reservoir rocks, range from about 2 to 0.03 μm in tight-gas sandstones, and range from 0.1 to 0.005 μm in shales. Hydrocarbon molecules, asphaltenes, ring structures, paraffins, and methane, form another continuum, ranging from 100 Å (0.01 μm for asphaltenes to 3.8 A (0.00038 μm) for methane. The pore-throat size continuum provides a useful perspective for considering (1) the emplacement of petroleum in consolidated siliciclastics and (2) fluid flow through fine-grained source rocks now being exploited as reservoirs.

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

    NASA Astrophysics Data System (ADS)

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

    1993-07-01

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

  7. Sulphur stable isotope systematics in diagenetic pyrite from the North Sea hydrocarbon reservoirs revealed by laser combustion analysis.

    PubMed

    Fallick, Anthony E; Boyce, Adrian J; McConville, Paul

    2012-01-01

    Our study focuses on pyrite nodules developed in the Brent Group sandstones, which host the Brent Oilfield, one of the North Sea's greatest oil and gas producers. Timing of nodule formation is equivocal, but due to the forceful, penetrative textures that abound, it is considered late. This pyrite offers a research opportunity because it records the development of the supply of H(2)S in a hydrocarbon reservoir and its sulphur isotopic composition. Laser-based analysis of δ(34)S reveals an extraordinary diversity in values and patterns. The values range from-27 to+72‰, covering half the terrestrial range, with large variations at the submillimetre scale. Isotopically heavy (δ(34)S ∼+30‰ or higher) sulphide is endemic, but low δ(34)S pyrite is also present and appears to represent a temporally though not spatially (on the ∼cm scale) distinct pyritisation event. The distribution of δ(34)S values within individual concretions can be normal (Gaussian), but in some cases may reflect progressive isotope fractionation process(es), conceivably of Rayleigh type. The source of the sulphur and the identity of the isotope fractionation process(es) remain enigmatic.

  8. 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.

  9. Discrete fracture modeling of multiphase flow and hydrocarbon production in fractured shale or low permeability reservoirs

    NASA Astrophysics Data System (ADS)

    Hao, Y.; Settgast, R. R.; Fu, P.; Tompson, A. F. B.; Morris, J.; Ryerson, F. J.

    2016-12-01

    It has long been recognized that multiphase flow and transport in fractured porous media is very important for various subsurface applications. Hydrocarbon fluid flow and production from hydraulically fractured shale reservoirs is an important and complicated example of multiphase flow in fractured formations. The combination of horizontal drilling and hydraulic fracturing is able to create extensive fracture networks in low permeability shale rocks, leading to increased formation permeability and enhanced hydrocarbon production. However, unconventional wells experience a much faster production decline than conventional hydrocarbon recovery. Maintaining sustainable and economically viable shale gas/oil production requires additional wells and re-fracturing. Excessive fracturing fluid loss during hydraulic fracturing operations may also drive up operation costs and raise potential environmental concerns. Understanding and modeling processes that contribute to decreasing productivity and fracturing fluid loss represent a critical component for unconventional hydrocarbon recovery analysis. Towards this effort we develop a discrete fracture model (DFM) in GEOS (LLNL multi-physics computational code) to simulate multiphase flow and transfer in hydraulically fractured reservoirs. The DFM model is able to explicitly account for both individual fractures and their surrounding rocks, therefore allowing for an accurate prediction of impacts of fracture-matrix interactions on hydrocarbon production. We apply the DFM model to simulate three-phase (water, oil, and gas) flow behaviors in fractured shale rocks as a result of different hydraulic stimulation scenarios. Numerical results show that multiphase flow behaviors at the fracture-matrix interface play a major role in controlling both hydrocarbon production and fracturing fluid recovery rates. The DFM model developed in this study will be coupled with the existing hydro-fracture model to provide a fully integrated

  10. Geologic aspects of reservoir souring - Brent Group sandstones, North Sea: The use of conventional and laser extraction techniques in sulfur isotope studies of authigenic pyrite

    SciTech Connect

    Brint, J.F. ); Fallick, A.E. )

    1991-03-01

    The Middle Jurassic Brent Group sandstones are prolific oil reservoirs in the North Sea. Recently, a number of Brent wells have experienced increased levels of hydrogen sulfide contamination during production. A study involving the characterization of all iron-bearing minerals to understand the controls of mineralogy on the nature and timing of souring has been undertaken. The potential of iron minerals to scavenge hydrogen sulfide and hence delay/inhibit souring by precipitation of pyrite has been investigated by determining its distribution, quantity, and origin. Authigenic pyrite occurs as disseminated (framboidal, cubic, and octahedral) crystals and as a pore-filling cement. The pyrite has formed throughout the diagenetic history of the sandstones. however, most of the pyrite is considered to be a late cement formed during burial diagenesis. Conventional separation and sulfur isotope analysis of the authigenic pyrite was conducted on samples from oil- and water-bearing sequences to give a bulk signature for all pyrite present. Subsequently, laser sulfur isotope analysis was used to characterize the signature and origin of the different pyrite morphologies present. The enhanced level of sulfur isotope signature characterization can be used to improve the knowledge of the origin and timing of the different pyrite morphologies. This allows closer reconciliation of the isotopic data to the diagenetic history of the Brent sandstones. Calculations have been made using the known quantities of iron in these minerals and the hydrogen sulfide concentrations present. This indicates the effect of sulfide precipitation on the hydrogen sulfide levels remaining in the reservoir.

  11. 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

  12. 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.

  13. 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

  14. 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.

  15. Anisotropy and spatial variation of relative permeability and lithologic character of Tensleep Sandstone reservoirs in the Bighorn and Wind River basins, Wyoming. First quarterly technical progress report, September 15, 1993--December 14, 1993

    SciTech Connect

    Dunn, T.L.

    1993-12-14

    This multidisciplinary study is designed to provide improvements in advanced reservoir characterization techniques. This goal is to be 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, depositional, and diagenetic 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 are 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 focuses on quantifying the interrelationship of fluid-rock interaction with lithologic characterization in terms of changes in relative permeability, wettability, and pore structure, and with fluid characterization in terms of changes in chemical composition and fluid properties. This work will establish new criteria for the susceptibility of Tensleep Sandstone reservoirs to formation alteration that results in a change in relative permeability and wellbore scale damage. This task will be accomplished by flow experiments using core material; examination of regional trends in water chemistry; examination of local water chemistry trends on the scale of a field; and chemical modeling of the reservoir and experimental systems in order to scale-up the experiments to reservoir conditions.

  16. Regional hydrocarbon generation, migration, and accumulation pattern of Cretaceous strata, Powder River Basin

    SciTech Connect

    Meissner, F.F.

    1985-05-01

    A cell of abnormally high fluid pressure in the deep part of the Powder River basin is centered in an area where oil-generation-prone source rocks in the Skull Creek (oldest), Mowry, and Niobrara (youngest) formations are presently at their maximum hydrocarbon-volume generation rate. The overpressures are believed to be caused by the high conversion rate of solid kerogen in the source rocks to an increased volume of potentially expellable fluid hydrocarbons. In this area, hydrocarbons appear to be the principal mobile fluid species present in reservoirs within or proximal to the actively generating source rocks. Maximum generation pressures within the source rocks have caused vertical expulsion through a pressure-induced microfracture system and have charged the first available underlying and/or overlying sandstone carrier-reservoir bed. Hydrocarbons generated in the Skull Creek have been expelled downward into the Dakota Sandstone and upward into the Muddy Sandstone. Hydrocarbons generated in the Mowry have been expelled downward into the Muddy or upward into lower Frontier sandstones. Hydrocarbons generated in the Niobrara have been expelled downward into upper Frontier sandstones or upward into the first available overlying sandstone in the Upper Cretaceous. The first chargeable sandstone overlying the Niobrara, in ascending order, may be the (1) Shannon, (2) Sussex, (3) Parkman, (4) Teapot, or (5) Tekla, depending on the east limit of each sandstone with respect to vertical fracture migration through the Cody Shale from the underlying area of mature overpressured Niobrara source rocks.

  17. 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.

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

    USGS Publications Warehouse

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

    2015-08-11

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

  19. Imaging and characterization of a carbonate hydrocarbon reservoir analogue using GPR attributes

    NASA Astrophysics Data System (ADS)

    Forte, E.; Pipan, M.; Casabianca, D.; Di Cuia, R.; Riva, A.

    2012-06-01

    We adapt and test seismic attributes techniques on a 2-D and 3-D multi-frequency GPR dataset recorded in an abandoned limestone quarry, analogous to a specific set of hydrocarbon reservoirs. Our main objective was to image the vertical and lateral lithological variations, the network of stratigraphic joints and fractures and to characterize the rock mass based on the radar response. We apply semi-automatic horizon mapping techniques using manually picked seeds (control points) on selected attributes, and automatic extrapolation both on in-line and cross-line, starting from seed positions. We also apply Principal Component Analysis (PCA) and cluster analysis on group data with similar multi-attribute response to reduce the total number of calculated attributes by minimizing the interpreter's bias. We compare and validate the results with direct outcrop measures, imaging a hydrocarbon reservoir analogue in 3-D to over 10 m beneath the topographic surface.

  20. 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.

  1. 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

  2. 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.

  3. Geological and petrophysical characterization of the ferron sandstone for 3-D simulation of a fluvial-deltaic reservoir. Quarterly report, January 1 - March 31, 1996

    SciTech Connect

    Allison, M.L.

    1996-04-01

    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. Technical progress this quarter is divided into case-study evaluation, geostatistics, and technology transfer activities. The work focused on one parasequence set, referred to as the Kf-1, in the Willow Springs Wash and Ivie Creek case-study areas. In the Ivie Creek case-study area the Kf-1 represents a river-dominated delta deposit which changes from proximal to distal from east to west. In the Willow Springs Wash case-study area the Kf-1 contains parasequences which represent river-dominated and wave-modified environments of deposition. Interpretations of lithofacies, bounding surfaces, and other geologic information are being used to determine reservoir architecture. Graphical interpretations of important flow boundaries in the case-study areas, identified on photomosaics, are being used to construct cross sections, paleogeographic, maps, and reservoir models. Geostatistical analyses are being incorporated with the geological characterization to develop a three-dimensional model of the reservoirs for fluid-flow simulation.

  4. 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.

  5. Mercury-free PVT apparatus for thermophysical property analyses of hydrocarbon reservoir fluids

    SciTech Connect

    Lansangan, R.M.; Lievois, J.S.

    1992-08-31

    Typical reservoir fluid analyses of complex, multicomponent hydrocarbon mixtures include the volumetric properties, isothermal compressibility, thermal expansivity, equilibrium ratios, saturation pressure, viscosities, etc. These parameters are collectively referred to as PVT properties, an acronym for the primary state variables; pressure, volume, and temperature. The reservoir engineer incorporates this information together with the porous media description in performing material balance calculations. These calculations lead to the determination (estimation) of the initial hydrocarbon in-place, the future reservoir performance, the optimal production scheme, and the ultimate hydrocarbon recovery. About four years ago, Ruska Instrument Corporation embarked on a project to develop an apparatus designed to measure PVT properties that operates free of mercury. The result of this endeavor is the 2370 Hg-Free PVT system which has been in the market for the last three years. The 2370 has evolved from the prototype unit to its present configuration which is described briefly in this report. The 2370 system, although developed as a system-engineered apparatus based on existing technology, has not been exempt from this burden-of-proof Namely, the performance of the apparatus under routine test conditions with real reservoir fluids. This report summarizes the results of the performance and applications testing of the 2370 Hg-Free PVT system. Density measurements were conducted on a pure fluid. The results were compared against literature values and the prediction of an equation of state. Routine reservoir fluid analyses were conducted with a black oil and a retrograde condensate gas mixtures. Limited comparison of the results were performed based on the same tests performed on a conventional mercury-based PVT apparatus. The results of these tests are included in this report.

  6. Controls upon hydrocarbon reservoir evolution within the Rotliegende group: A fully integrated regional study

    SciTech Connect

    Howell, J.A.; Becker, A.; Turner, P.; Searl, A. ); Edwards, H.E.; Williams, G. )

    1993-09-01

    The collection of a large database, in conjunction with new understandings of sedimentology and structural controls upon diagenesis, has enabled the detailed mapping of the factors that control the distribution of hydrocarbon reservoirs within the Rotliegende Group of the United Kingdom southern North Sea. The results of this regional study incorporate detail previously confined to field scale studies. High resolution sedimentological and stratigraphic studies (4 km of core) have resulted in a twelve-fold subdivision of the Rotliegende Group based upon the recognition of climatically driven depositional cycles. These illustrate a progressive basin expansion controlled by the distribution of buried lower Paleozoic granites and post-Vanscan topography. This model incorporated with mapping of facies distribution has been used to document the distribution of potential reservoir rocks. Detailed diagenetic work has documented the distribution of all the principal mineral phases within the basin. Integration with structural studies has revealed the role of the fractures for introducing fluids to, and compartmentalizing reservoirs has led to significant understanding of the source and transport mechanism for the pore-occluding diagenetic phases. Regionally, an understanding of burial and inversion events has demonstrated that the distribution of clays, particularly permeability destroying illite, is controlled by both burial depth and source of reactants. Combination of sedimentological and diagenetic aspects has enabled the production predictive maps for the area. This, combined with the structural work, has highlighted the importance of timing of hydrocarbon migration in relation to reservoir structuration, particularly in areas away from the main Sole Pit source kitchen.

  7. 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

  8. 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.

  9. 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.

  10. 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.

  11. Depositional environments, reservoir trends, and diagenesis of Red Fork sandstones in parts of Blaine, Caddo, and Custer counties, Oklahoma

    SciTech Connect

    Johnson, C.L.

    1984-04-01

    The Red Fork sandstone was divided into the upper and lower Red Fork which are separated by a consistent marker bed. The Red Fork interval thickens markedly across the study area from 250 ft (75 m) in the northeast to over 1300 ft (400 m) in the southwest. Most of the thickening is within the lower Red Fork. The lower Red Fork is believed to have been deposited in shelf-to-basin transitional terrain. Sands were located in delta-front, submarine-channel-fill, and possible submarine-fan terrain. The upper Red Fork is believed to represent the maximum progradation of a deltaic complex. Sandstones of the lower Red Fork are sublithic to lithic arenites; the upper Red Fork is sublithic arenite. The dominant lithic fraction is mudstone fragments. The main diagenetic alterations of both the upper and lower Red Fork sandstones were destruction of primary porosity by compaction and cementation. Dissolution chiefly of mud fragments has produced well-developed secondary porosity. Clays of the lower Red Fork mainly are authigenic chlorite; clays of the upper Red Fork primarily are authigenic kaolinite. Present oil and gas production from Red Fork sandstones is most abundant from localities on the paleoshelf.

  12. 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.

  13. 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

  14. CO sub 2 Huff 'n' Puff recovery feasibility as function of the effect of CO sub 2 on mineral stability in a Dakota Sandstone Reservoir, central Wyoming

    SciTech Connect

    Smith, L.K.; MacGowan, D.B.; Surdam, R.C. )

    1990-05-01

    The high pressures required for CO{sub 2} injection in Huff n' Puff treatment have the potential to destabilize carbonate minerals in the formation. Scaling problems caused by precipitating cements may occur after production resumes. However, the presence of sufficient organic acid anion buffers may stabilize carbonate minerals at high P{sub CO2} causing them to precipitate from the formation waters and block pore throats, Modeling these conditions for individual reservoirs is important in the design of the Huff n' Puff treatment in order to avoid formation damage or production-line clogging. Based on the authors modeling, they predict that in the Huff n' Puff treatment on this Dakota sandstone reservoir, scale buildup in the production line will not be a significant problem. The CO{sub 2} injection Pressures expected (1,100-2,000 psi) are sufficiently high to keep carbonates in solution. No formation damage is expected because there is little carbonate cement in this Dakota sandstone reservoir to dissolve and reprecipitate in the pore throats after pressures decline. Also, organic acid anions are in sufficiently low concentration (3.56 meq/L) that they cannot buffer the pH; thus carbonates will not precipitate with increased {Sigma}CO{sub 2}, especially since calcium concentrations are also low (26 ppm). These predictions will be tested when this Huff n' Puff treatment is initiated. Test results will provide refined input data (especially pressure data) for modeling future treatments. The predictions and test results presented will then be used to improve the predictive capability of the modeling process.

  15. 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.

  16. Influence of reservoir conditions on multiphase flow in natural sandstone using lattice Boltzmann simulation: Investigation of suitable conditions in CCS and EOR

    NASA Astrophysics Data System (ADS)

    Tsuji, T.; Jiang, F.; Christensen, K. T.

    2015-12-01

    Microscopic two-phase fluid behavior in porous media is influenced by reservoir temperature, interfacial tension, pore structure, and porous medium characteristics (e.g., wettability), which vary significantly from one reservoir to the next. Pore-scale interfacial instabilities, such as snap-off and fingering phenomena, influence the stability, injectivity, mobility, and saturation within the reservoir. Therefore, understanding microscopic multiphase flow in porous media is crucial to estimating critical reservoir-scale characteristics, including storage capacity, leakage risk, and storage efficiency. Here we calculated fluid displacements within 3D pore spaces of natural sandstone using two-phase lattice Boltzmann (LB) simulation and characterized the influence of reservoir conditions upon multiphase flow. We classified the two-phase flow behavior that occurred under various conditions into three typical fluid displacement patterns on the diagram of capillary number (Ca) and viscosity ratio of the two fluids (M). Then the saturation of the nonwetting phase was calculated and mapped on the Ca-M diagram. The saturation map is useful to investigate suitable conditions in CCS and EOR. We further characterized dynamic pore-filling events (i.e., Haines jumps) from the fluid pressure variation. The results revealed the onset of capillary fingering in natural rock at a higher Ca than previously reported for homogeneous porous media, with the crossover region between typical displacement patterns much broader than in a homogeneous granular model. These differences between two-phase flow in natural rock and in a homogeneous porous structure could be the result of the heterogeneity of the natural rock.

  17. Electromagnetic Analysis in Time Domain in Various Configurations for Identification of Hydrocarbon Reservoirs: Numerical Modeling

    NASA Astrophysics Data System (ADS)

    Salazar Rodriguez, J. M.; Vargas Jiménez, C. A.

    2015-12-01

    In this research, various configurations of reservoirs were simulated using finite elements in 3D, in order to analyze the subsoil electromagnetic responses in the time domain. Apparent resistivity curves both early and late time and their respective sensitivities in detecting hydrocarbon reservoirs are found. The maximum sensitivity obtained in the early and late times was 55.72% and 49.32% respectively. The separation of 1km between the transmitter and receiver was used in the simulations, because at shorter distances problems were encountered in in determining the resistivity curves. In addition, it was determined that the current dipole transmitter must be over 800A • m to overcome the level of noise instrumental of the receptor coil.

  18. Subsurface petroleum geology of Santa Rosa sandstone (Triassic), northeast New Mexico

    NASA Astrophysics Data System (ADS)

    Broadhead, R. F.

    The Santa Rose Sandstone (Triassic) occurs at depths of less than 2,000 ft over most of northeast New Mexico. Two major petroleum accumulations are known to exist in it. These outcrops of oil impregnated sandstone are known as the Santa Rosa tar sands. The oil in the tar sands is viscous and heavy. The other known petroleum accumulation is a pool of heavy oil that occurs at depths of 400 ft to 800 ft in northeast Guadalupe County. Attempts are being made to recover the heavy oil with steamflooding in two small pilot fields. The lower and upper sandstone units are blanket deposits composed mostly of fine to medium grained porous sandstones and minor red siliciclastic mudstones. The middle mudstone unit is a blanket deposit composed chiefly of red siliciclastic mudstones and minor lenticular sandstones. Stratigraphic and petrographic studies indicate that good reservoirs are widespread in the lower and upper sandstone unit. The blanket geometry of the lower and upper sandstone units indicates that structure probably plays an important or even dominant role in the trapping of any undiscovered hydrocarbons in the Santa Rosa. Oil proximal to the outcrop belt of the Santa Rosa Sandstone has probably been flushed by recently recharged fresh ground water. Although the source of the oil in Santa Rosa Sandstone is not definitely known, geochemical studies point to the San Andres Formation (Permian) or possibly Pennsylanian rocks.

  19. Modification of Gaussian elimination to identify hydrocarbon reservoir (the thin- bed model reconstruction)

    NASA Astrophysics Data System (ADS)

    Sayankina, M. K.; Smaglichenko, A. V.; Lukianitsa, A. A.

    2012-04-01

    Passive seismic tomography can be not expensive and effective tool for hydrocarbon exploration as well for challenging task of environment protection. In this paper we focus our attention on the thin-bed model (20 m thick) that has been defined by Haitao Ren and Gennady Golobushin (2007). Their 2-D model includes both water- and gas- saturated reservoirs cases. We supplemented this model by synthetic sources assuming that they imitate possible micro seismicity. Positions of sources were selected in order to resolve the dipping thin model from point of view ray's theory. Stations of the surface network were located to be able register seismic waves that transmitted via thin-bed. The medium parameters were found so that to approximate the layer by means of blocks. Two large zones with significant velocity contrast between them correspond to the water-saturated and the gas-saturated reservoirs. Properties of rocks define anomalies in zones that surround reservoirs. It is known that such kind of tomographic structures are normally poorly resolved because of over- or under- determined systems of arising linear equations. Therefore synthetic data were processed applying new differentiated approach, which is stable at least with respect to parameterization errors. The base of the approach is the modification of Gaussian elimination that has been developed by Tatyana A. Smaglichenko (2011) with purpose to decrease level of any error by means of division of initial system into sub-systems. In this study we demonstrate stages of the thin-bed model reconstruction and ability of inversion technique to adequately detect the complicated parts of this model. With help of this example, we conclude that under defined physical conditions passive tomography identifies details of hydrocarbon reservoir.

  20. An analysis on three-dimensional electromagnetic responses of offshore hydrocarbon reservoir

    NASA Astrophysics Data System (ADS)

    Jang, H.; Kim, H.

    2013-12-01

    The marine controlled-source electromagnetic (CSEM) method has been applied successfully to detect hydrocarbon (HC) reservoirs. However, the sensitivity to subseafloor geology can be significantly smaller in shallow water and at higher frequencies, where the air layer exerts a stronger influence on the data. This airwave effect may be comparable or larger than the signal through the subseafloor. This study presents a three-dimensional (3D) marine CSEM modeling algorithm using primary fields for a homogeneous half-space model to account for airwave effects. This algorithm is validated with analytic solutions for a 2-layer model and numerical results from another 3D model. Using this code, we investigate 3D EM responses of a 100 m thick, 5 km disk-shaped hydrocarbon reservoir buried at a depth of 1 km in 1 km seawater. From numerical results, we can recognize that a 3D effect of the reservoir typically produces a transition zone in comparison with 1D model responses. The transition zone decreases with the airwave effect as the water becomes shallow. As the source frequency increases, the sensitivity to the reservoir increases whereas the amplitude decreases, and falls at more than 1 Hz below the current system noise floor, 1E-15 V/Am2. Broadside electric fields for a 10-km diameter disk model are only about 5 % of in-line electric fields for the 5-km disk model. T-equivalence is observed at such a low frequency of 1 Hz for the thin resistive tabular target, whose response varies almost linearly with the target thickness and resistivity even in the transition zone.

  1. 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

  2. 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.

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

    NASA Astrophysics Data System (ADS)

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

    2017-06-01

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

  4. 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.

  5. 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.

  6. High-resolution reservoir characterization of midcontinent sandstones using wireline resistivity imaging, Boonsville (Bend Conglomerate) Gas Field, Fort Worth Basin, TX

    SciTech Connect

    Carr, D.L.; Elphick, R.Y.; Foulk, L.S.

    1996-12-31

    In the absence of abundant core data, Formation MicroScanner* (FMS) and Fullbore Formation Microlmager* (FMI) wireline logs from 3 wells in Boonsville Field provided continuous geologic information in a 1000-foot thick, Pennsylvanian (Atoka) interval. Cores provided the most detailed sequence-stratigraphic information, but only 358 ft of core from 4 wells was available to evaluate the 30 mi{sup 2} project area. The FMS and FMI logs thus served as continuous, oriented {open_quote}virtual cores{close_quote} that expanded our stratigraphic database and improved our interpretations, which included the identification of key chronostratigraphic surfaces, lithofacies, sedimentary structures, faults, and fractures. Paleocurrents inferred from the FMS and FMI images suggest that most Bend Conglomerate sandstones are lowstand valley-fill deposits derived from the Muenster and Red River Uplifts, rather than Ouachita-derived deltas. Combined analysis of cores and wireline resistivity imaging technology enabled the development of a fine-scale, sequence-stratigraphic framework which formed the basis for correlation and mapping of the major Bend Conglomerate reservoir zones, and helped us to identify compartmentalization mechanisms within these complex reservoirs.

  7. High-resolution reservoir characterization of midcontinent sandstones using wireline resistivity imaging, Boonsville (Bend Conglomerate) Gas Field, Fort Worth Basin, TX

    SciTech Connect

    Carr, D.L. ); Elphick, R.Y. ); Foulk, L.S. )

    1996-01-01

    In the absence of abundant core data, Formation MicroScanner* (FMS) and Fullbore Formation Microlmager* (FMI) wireline logs from 3 wells in Boonsville Field provided continuous geologic information in a 1000-foot thick, Pennsylvanian (Atoka) interval. Cores provided the most detailed sequence-stratigraphic information, but only 358 ft of core from 4 wells was available to evaluate the 30 mi[sup 2] project area. The FMS and FMI logs thus served as continuous, oriented [open quote]virtual cores[close quote] that expanded our stratigraphic database and improved our interpretations, which included the identification of key chronostratigraphic surfaces, lithofacies, sedimentary structures, faults, and fractures. Paleocurrents inferred from the FMS and FMI images suggest that most Bend Conglomerate sandstones are lowstand valley-fill deposits derived from the Muenster and Red River Uplifts, rather than Ouachita-derived deltas. Combined analysis of cores and wireline resistivity imaging technology enabled the development of a fine-scale, sequence-stratigraphic framework which formed the basis for correlation and mapping of the major Bend Conglomerate reservoir zones, and helped us to identify compartmentalization mechanisms within these complex reservoirs.

  8. A reservoir model for the Lower Cretaceous deep marine sandstones in the Maloy Fault Block area, Norwegian North Sea

    SciTech Connect

    Kloster, A.; Areklett, E.K.; Milton, N.

    1995-08-01

    The Maloy Fault Block area of the North Viking Graben forms a platform to the east of the Sogn Graben next to the coast of Norway. This area is characterized by an unusual and thick Lower Cretaceous section containing a number of discrete sandstone packages. Wells drilled elsewhere in the Norwegian North Sea are in contrast dominated by a relatively thin mud and marl dominated section in the Lower Cretaceous. Two wells in block 35/3 (the Agat field) encountered gas bearing sandstones of Albian age interpreted to represent deposition in a deep marine environment. An integrated sequence stratigraphic approach to the Lower Cretaceous stratigraphy in the Maloy Fault Block area has led to a new and more detailed understanding of controls on deposition in this area. This is based both on a regional dataset and good quality 3D seismic data. A Valanginian-Hauterivian relict slope/shelf system is present along the eastern basin margin. It formed a long-lasting topographic feature and in some areas was not onlapped until the Campanian time. A dramatic change in the basin configuration took place most likely in the Aptian time. This was initiated by erosion of the slope/shelf system which cut multiple huge canyons along the basin-margin. The canyons focused sediment input to the basin along discrete and mappable transport routes, some of which are controlled by erosion features inherited from the Late Jurassic. A complex history of deposition and filling followed. This was controlled by a constantly changing basin floor topography and left a complex pattern of partly constrained fan deposition.

  9. Effect of Salinity on Effective CO2 Permeability in Reservoir Rock Determined by Pressure Transient Methods: an Experimental Study on Hawkesbury Sandstone

    NASA Astrophysics Data System (ADS)

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

    2015-09-01

    The determination of effective carbon dioxide (CO2) permeability in reservoir rock and its variation is of great interest in the process of CO2 sequestration in deep saline aquifers, as CO2 sequestration-induced permeability alternations appear to create major problems during the CO2 injection process. The main objective of this study is to investigate the effect of salinity on the effective CO2 permeability of reservoir rock under different injection pressures. A series of high-pressure tri-axial experiments was, therefore, performed to investigate the effect of salinity on effective CO2 permeability in Hawkesbury sandstone under various brine concentrations. The selected brine concentrations were 0, 10, 20, and 30 % sodium chloride (NaCl) by weight and the experiments were conducted for a range of CO2 injection pressures (2, 4, 6, 8, 10, and 12 MPa) at a constant confinement of 20 MPa and a temperature of 35 °C, respectively. According to the results, the degree of salinity of the aquifer's pore fluid plays a vital role in the effective CO2 permeability variation which occurs with CO2 injection, and the effective permeability decreases with increasing salinity in the range of 0-30 % of NaCl. Interestingly, in dry reservoir rock samples, the phase transition of the injection of CO2 from gas to super-critical condition caused a sudden reduction of CO2 permeability, related to the slip flow effect which occurs in gas CO2. Transfer into vapor or super-critical CO2 causes this slip flow to be largely reduced, reducing the reservoir permeability for CO2 movement in dry reservoir rock samples. However, this behavior was not observed for water- and brine-saturated samples, and an increasing trend of effective CO2 permeability was observed with increasing injection pressure. A detailed chemical analysis was then conducted to understand the physical phenomenon causing the salinity effect on effective CO2 permeability using scanning electron microscopy analyses. Such

  10. Investigation of gas hydrate-bearing sandstone reservoirs at the "Mount Elbert" stratigraphic test well, Milne Point, Alaska

    SciTech Connect

    Boswell, R.M.; Hunter, R.; Collett, T.; Digert, S. Inc., Anchorage, AK); Hancock, S.; Weeks, M. Inc., Anchorage, AK); Mt. Elbert Science Team

    2008-01-01

    In February 2007, the U.S. Department of Energy, BP Exploration (Alaska), Inc., and the U.S. Geological Survey conducted an extensive data collection effort at the "Mount Elbert #1" gas hydrates stratigraphic test well on the Alaska North Slope (ANS). The 22-day field program acquired significant gas hydrate-bearing reservoir data, including a full suite of open-hole well logs, over 500 feet of continuous core, and open-hole formation pressure response tests. Hole conditions, and therefore log data quality, were excellent due largely to the use of chilled oil-based drilling fluids. The logging program confirmed the existence of approximately 30 m of gashydrate saturated, fine-grained sand reservoir. Gas hydrate saturations were observed to range from 60% to 75% largely as a function of reservoir quality. Continuous wire-line coring operations (the first conducted on the ANS) achieved 85% recovery through 153 meters of section, providing more than 250 subsamples for analysis. The "Mount Elbert" data collection program culminated with open-hole tests of reservoir flow and pressure responses, as well as gas and water sample collection, using Schlumberger's Modular Formation Dynamics Tester (MDT) wireline tool. Four such tests, ranging from six to twelve hours duration, were conducted. This field program demonstrated the ability to safely and efficiently conduct a research-level openhole data acquisition program in shallow, sub-permafrost sediments. The program also demonstrated the soundness of the program's pre-drill gas hydrate characterization methods and increased confidence in gas hydrate resource assessment methodologies for the ANS.

  11. Sedimentary record of polycyclic aromatic hydrocarbons in a reservoir in Northeast China.

    PubMed

    Lin, Tian; Qin, Yanwen; Zheng, Binghui; Li, Yuanyuan; Zhang, Lei; Guo, Zhigang

    2012-04-01

    A sediment core from the Dahuofang Reservoir in Northeast China was (210)Pb and (137)Cs dated and analyzed for polycyclic aromatic hydrocarbons (PAHs) to track the regional PAH pollution in the past 50 years. The 2-4 ring PAHs peaked in the early 1990s, reflecting the historical role of coal usage in the energy structure in this area. More recently, vehicle emissions caused the continuous increase of the 5+6 ring PAHs. However, the sixteen US EPA priority PAHs showed a significant decline since the early 1990s. This PAH temporal trend is different from the U.S., the European countries and Japan, and is also different from the other areas of China, which could be attributed to the switch from coal to oil or natural gas as the main energy, and the large-scale elimination of outdated combustion facilities and techniques in Northeast China.

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

    USGS Publications Warehouse

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

    2002-01-01

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

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

    NASA Astrophysics Data System (ADS)

    Buatois, Luis A.; Mángano, M. Gabriela; Alissa, Abdulrahman; Carr, Timothy R.

    2002-09-01

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

  14. Anisotropy and spatial variation of relative permeability and lithologic character of Tensleep Sandstone reservoirs in the Bighorn and Wind River Basins, Wyoming. Annual report, October 1, 1994-- September 30, 1995

    SciTech Connect

    Dunn, T.L.

    1996-03-01

    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. Because of the great range of API gravities of the oils produced from these reservoirs, the proposed study concentrates on understanding the spatial variation and anisotropy of relative permeability within the Tensleep Sandstone. This research will associate those spatial distributions and anisotropies with the depositional subfacies and zones of diagenetic alteration found within the sandstone. The associations of the above with pore geometry will link relative permeability with the dimensions of lithofacies and authigenic mineral facies. Hence, the study is to provide criteria for scaling this parameter on a range of scales, from the laboratory to the basin-wide scale of subfacies distribution. Effects of depositional processes and burial diagenesis will be investigated. Image analysis of pore systems will be done to produce algorithms for estimating relative permeability from petrographic analyses of core and well cuttings. 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, eg., CO{sub 2} flooding. This will provide a regional basis for EOR strategies for the largest potential target reservoir in Wyoming; results will have application to all eolian reservoirs through correlations of relative permeability variation and anisotropy with eolian depositional lithofacies.

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

    NASA Astrophysics Data System (ADS)

    Karakitsios, Vasileios; Agiadi, Konstantina

    2013-04-01

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

  16. Hydrocarbon transfer pathways from Smackover source rocks to younger reservoir traps in the Monroe gas field, NE Louisiana

    SciTech Connect

    Zimmerman, R.K. )

    1993-09-01

    The Monroe gas field contained more than 7 tcf of gas in its virgin state. Much of the original gas reserves have been produced through wells penetrating the Upper Cretaceous Monroe Gas Rock Formation reservoir. Other secondary reservoirs in the field area are Eocene Wilcox, the Upper Cretaceous Arkadelphia, Nacatoch, Ozan, Lower Cretaceous, Hosston, Jurassic Schuler, and Smackover. As producing zones, these secondary producing zones reservoirs have contributed an insignificant amount gas to the field. The source of much of this gas appears to have been in the lower part of the Jurassic Smackover Formation. Maturation and migration of the hydrocarbons from a Smackover source into Upper Cretaceous traps was enhanced and helped by igneous activity, and wrench faults/unconformity conduits, respectively. are present in the pre-Paleocene section. Hydrocarbon transfer pathways appear to be more vertically direct in the Jurassic and Lower Cretaceous section than the complex pattern present in the Upper Cretaceous section.

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

    SciTech Connect

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

    1996-08-01

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

  18. Microbial water diversion technique-designed for near well treatment in low temperature sandstone reservoirs in the North Sea

    SciTech Connect

    Paulsen, J.E.; Vatland, A.; Sorheim, R.

    1995-12-31

    A Norwegian Research Program on Improved Oil Recovery (IOR) in North Sea reservoirs was launched in 1992. Microbial methods, applied in this context, is a part of this program. The scope, the methodological approach, and results from the three first years are presented. Water profile control, using biomass to block high permeable zones of a reservoir, has been investigated using nitrate-reducing bacteria in the injected sea water as plugging agents. Emphasis has been put on developing a process that does not have disadvantages secondary to the process itself, such as souring and impairment of the overall injectivity of the field. Data from continuous culture studies indicate that souring may successfully be mitigated by adding nitrite to the injected seawater. The morphology and size of generic-nitrate-reducing seawater bacteria have been investigated. Screening of growth-promoting nutrients has been carried out, and some sources were detected as favorable. Transport and penetration of bacteria in porous media have been given special attention. Investigations with sand packs, core models, and pore micromodels have been carried out. The inherent problems connected with permeability contrasts and flow patterns, versus bacterial behavior, are believed to be critical for the success of this technology. Data from the transport and blocking experiments with the porous matrices confirm this concern. The technology is primarily being developed for temperatures less than 40{degrees}C.

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

    SciTech Connect

    Reinson, G.E.

    1996-06-01

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

  20. Chemical effects of carbon dioxide sequestration in the Upper Morrow Sandstone in the Farnsworth, Texas, hydrocarbon unit

    SciTech Connect

    Ahmmed, Bulbul; Appold, Martin S.; Fan, Tianguang; McPherson, Brian J. O. L.; Grigg, Reid B.; White, Mark D.

    2016-03-01

    Numerical geochemical modeling was used to study the effects on pore-water composition and mineralogy from carbon dioxide (CO2) injection into the Pennsylvanian Morrow B Sandstone in the Farnsworth Unit in northern Texas to evaluate its potential for long-term CO2 sequestration. Speciation modeling showed the present Morrow B formation water to be supersaturated with respect to an assemblage of zeolite, clay, carbonate, mica, and aluminum hydroxide minerals and quartz. The principal accessory minerals in the Morrow B, feldspars and chlorite, were predicted to dissolve. A reaction-path model in which CO2 was progressively added up to its solubility limit into the Morrow B formation water showed a decrease in pH from its initial value of 7 to approximately 4.1 to 4.2, accompanied by the precipitation of small amounts of quartz, diaspore, and witherite. As the resultant CO2-charged fluid reacted with more of the Morrow B mineral matrix, the model predicted a rise in pH, reaching a maximum of 5.1 to 5.2 at a water–rock ratio of 10:1. At a higher water–rock ratio of 100:1, the pH rose to only 4.6 to 4.7. Diaspore, quartz, and nontronite precipitated consistently regardless of the water–rock ratio, but the carbonate minerals siderite, witherite, dolomite, and calcite precipitated at higher pH values only. As a result, CO2 sequestration by mineral trapping was predicted to be important only at low water–rock ratios, accounting for a maximum of 2% of the added CO2 at the lowest water–rock ratio investigated of 10:1, which corresponds to a small porosity increase of approximately 0.14% to 0.15%.

  1. Infrastructure and mechanical properties of a fault zone in sandstone as an outcrop analogue of a potential geothermal reservoir

    NASA Astrophysics Data System (ADS)

    Bauer, J. F.; Meier, S.; Philipp, S. L.

    2013-12-01

    Due to high drilling costs of geothermal projects, it is economically sensible to assess the potential suitability of a reservoir prior to drilling. Fault zones are of particular importance, because they may enhance fluid flow, or be flow barriers, respectively, depending on their particular infrastructure. Outcrop analogue studies are useful to analyze the fault zone infrastructure and thereby increase the predictability of fluid flow behavior across fault zones in the corresponding deep reservoir. The main aims of the present study are to 1) analyze the infrastructure and the differences of fracture system parameters in fault zones and 2) determine the mechanical properties of the faulted rocks. We measure fracture frequencies as well as orientations, lengths and apertures and take representative rock samples for each facies to obtain Young's modulus, compressive and tensile strengths in the laboratory. Since fractures reduce the stiffnesses of in situ rock masses we use an inverse correlation of the number of discontinuities to calculate effective (in situ) Young's moduli to investigate the variation of mechanical properties in fault zones. In addition we determine the rebound hardness, which correlates with the compressive strength measured in the laboratory, with a 'Schmidt-Hammer' in the field because this allows detailed maps of mechanical property variations within fault zones. Here we present the first results for a fault zone in the Triassic Lower Bunter of the Upper Rhine Graben in France. The outcrop at Cleebourg exposes the damage zone of the footwall and a clear developed fault core of a NNW-SSE-striking normal fault. The approximately 15 m wide fault core consists of fault gouge, slip zones, deformation bands and host rock lenses. Intensive deformation close to the core led to the formation of a distal fault core, a 5 m wide zone with disturbed layering and high fracture frequency. The damage zone also contains more fractures than the host rock

  2. Ground motions induced by a producing hydrocarbon reservoir that is overlain by a viscoelastic rocksalt layer: a numerical model

    NASA Astrophysics Data System (ADS)

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

    2015-10-01

    Hydrocarbon reservoir pressure depletion leads to stress changes inside the reservoir and ground deformation which is registered at the surface as subsidence. As reservoirs are often overlain by layers of rocksalt (or other evaporites), which are materials that flow so as to relax stresses inside them, there is the potential for time-varying surface subsidence. This work focuses on understanding the macroscopic mechanisms that lead to rocksalt flow-induced ground displacements. A Finite Element Model is used for this purpose in which the rocksalt layer is represented by a viscoelastic Maxwell material. Two distinct mechanisms that lead to displacement are observed. These are active during different stages of the deformation and have different timescales associated with them. An important observation is that the timescale for deformation that is measured at the ground surface is not equal to the timescale for deformation of a viscoelastic material element, but can be many times larger than that. The sensitivity of the response to the thickness and location of the rocksalt layer is also presented. Conclusions are drawn which allow for the relative importance of the presence of the rocksalt layer to be assessed and for a framework for understanding time-dependent subsidence above producing hydrocarbon reservoirs to be developed. Finally the changes in stress distribution around a producing reservoir are also briefly discussed.

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

    SciTech Connect

    Leetaru, Hannes; Brown, Alan; Lee, Donald; Senel, Ozgur; Coueslan, Marcia

    2012-05-01

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

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

    NASA Astrophysics Data System (ADS)

    Gent, Christopher; Williams, John

    2017-04-01

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

  5. Remagnetization of the Rush Springs Formation, Cement, Oklahoma: Implications for dating hydrocarbon migration and aeromagnetic exploration

    SciTech Connect

    Elmore, R.D.; Leach, M.C. )

    1990-02-01

    The Permian Rush Springs Formation above the Cement anticline in Oklahoma contains a Late Permian-Early Triassic chemical remanent magnetization (CRM) that is interpreted to reside in authigenic magnetite. The CRM is found in bleached, carbonate-cemented sandstones that were altered by hydrocarbons and contain authigenic magnetite. The magnetite presumably precipitated in the Late Permian-Early Triassic as a result of chemical conditions created by hydrocarbons or associated fluids that migrated from underlying reservoir units. Red sandstones around Cement that were not altered by hydrocarbons contain a Permian CRM that resides in hematite. The red and bleached sandstones have similar magnetization intensities and susceptibilities; this raises questions about the use of aeromagnetic surveys in hydrocarbon exploration.

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

    NASA Astrophysics Data System (ADS)

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

    2015-12-01

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

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

    USGS Publications Warehouse

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

    1980-01-01

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

  8. Subcontinuum mass transport of hydrocarbons in nanoporous media and long-time kinetics of recovery from unconventional reservoirs

    NASA Astrophysics Data System (ADS)

    Bocquet, Lyderic

    2015-11-01

    In this talk I will discuss the transport of hydrocarbons across nanoporous media and analyze how this transport impacts at larger scales the long-time kinetics of hydrocarbon recovery from unconventional reservoirs (the so-called shale gas). First I will establish, using molecular simulation and statistical mechanics, that the continuum description - the so-called Darcy law - fails to predict transport within a nanoscale organic matrix. The non-Darcy behavior arises from the strong adsorption of the alkanes in the nanoporous material and the breakdown of hydrodynamics at the nanoscale, which contradicts the assumption of viscous flow. Despite this complexity, all permeances collapse on a master curve with an unexpected dependence on alkane length, which can be described theoretically by a scaling law for the permeance. Then I will show that alkane recovery from such nanoporous reservoirs is dynamically retarded due to interfacial effects occuring at the material's interface. This occurs especially in the hydraulic fracking situation in which water is used to open fractures to reach the hydrocarbon reservoirs. Despite the pressure gradient used to trigger desorption, the alkanes remain trapped for long times until water desorbs from the external surface. The free energy barrier can be predicted in terms of an effective contact angle on the composite nanoporous surface. Using a statistical description of the alkane recovery, I will then demonstrate that this retarded dynamics leads to an overall slow - algebraic - decay of the hydrocarbon flux. Such a behavior is consistent with algebraic decays of shale gas flux from various wells reported in the literature. This work was performed in collaboration with B. Coasne, K. Falk, T. Lee, R. Pellenq and F. Ulm, at the UMI CNRS-MIT, Massachusetts Institute of Technology, Cambridge, USA.

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

    USGS Publications Warehouse

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

    1996-01-01

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

  10. Compound-specific radiocarbon analysis of polycyclic aromatic hydrocarbons (PAHs) in sediments from an urban reservoir

    NASA Astrophysics Data System (ADS)

    Kanke, Hirohide; Uchida, Masao; Okuda, Tomoaki; Yoneda, Minoru; Takada, Hideshige; Shibata, Yasuyuki; Morita, Masatoshi

    2004-08-01

    A quantitative apportionment of polycyclic aromatic hydrocarbons (PAHs) derived from fossil fuel combustion (14C-free) and biomass burning (contemporary 14C) was carried out using a recently developed compound-specific radiocarbon analysis (CSRA) method for a sediment core from an urban reservoir located in the central Tokyo metropolitan area, Japan. The 14C abundance of PAHs in the sediments was measured by accelerator mass spectrometry (AMS) after extraction and purification by three types of column chromatography, by high performance liquid chromatography (HPLC), and, subsequently, by a preparative capillary gas chromatography (PCGC) system. This method yielded a sufficient quantity of pure compounds and allowed a high degree of confidence in the determination of 14C. The fraction modern values (fM) of individual PAHs (phenanthrene, alkylphenanthrenes, fluoranthene, pyrene and benz[a]anthracene) in the sediments ranged from 0.06 to 0.21. These results suggest that sedimentary PAHs (those compounds mentioned above) were derived mostly from fossil fuel combustion. Three sectioned-downcore profiles (∼40 cm) of the 14C abundance in phenanthrene and alkylphenanthrenes showed a decreasing trend with depth, that was anti-correlated with the trend of ∑PAHs concentration. The fM values of phenanthrene were also larger than those of alkylphenanthrenes in each section of the core. This result indicates that phenanthrene received a greater contribution from biomass burning than alkylphenanthrenes throughout the core. This finding highlights the method used here as an useful approach to elucidate the source and origin of PAHs in the environment.

  11. Reservoir characteristics and 3D static modelling of the Late Miocene Abu Madi Formation, onshore Nile Delta, Egypt

    NASA Astrophysics Data System (ADS)

    El Khadragy, A. A.; Eysa, E. A.; Hashim, A.; Abd El Kader, A.

    2017-08-01

    West Al Khilala Field is considered as gas producing from Abu Madi Miocene sandstone Formation. It lies at the central onshore Nile Delta and covers about 47.6 km2. The petrophysical parameters (porosity, permeability, water saturation and net-to-gross ratio) as well as static modelling of the Abu Madi reservoir from well logs are carried out. The porosity model reflected good porosity in the study area especially in the massive sandstone unit with values range from 18% to 27%, while low porosity value are recorded in the layered and basal sandstone units with values range from 1% to 24%. The permeability model displayed values range from 50 md to 2000 md in the massive sandstone unit that increases towards the southeast direction reflected a high promising for hydrocarbon prospecting. The permeability values of the layered and basal sandstone units range from 0.5 md to 700 md with mean value of 40 md reflected a tight permeability due to the presence of shale streaks. The water saturation (Sw) model of the layered and massive sandstone units indicated hydrocarbon-bearing intervals with values from 10% to 64.7%, while the basal sandstone unit is highly saturated with water from 65% up to 100%. The volumetric calculation of the reservoir showed that the reservoir contained about 246 BSCF as a recoverable gas.

  12. The potential for hydrocarbon biodegradation and production of extracellular polymeric substances by aerobic bacteria isolated from a Brazilian petroleum reservoir.

    PubMed

    Vasconcellos, S P; Dellagnezze, B M; Wieland, A; Klock, J-H; Santos Neto, E V; Marsaioli, A J; Oliveira, V M; Michaelis, W

    2011-06-01

    Extracellular polymeric substances (EPS) can contribute to the cellular degradation of hydrocarbons and have a huge potential for application in biotechnological processes, such as bioremediation and microbial enhanced oil recovery (MEOR). Four bacterial strains from a Brazilian petroleum reservoir were investigated for EPS production, emulsification ability and biodegradation activity when hydrocarbons were supplied as substrates for microbial growth. Two strains of Bacillus species had the highest EPS production when phenanthrene and n-octadecane were offered as carbon sources, either individually or in a mixture. While Pseudomonas sp. and Dietzia sp., the other two evaluated strains, had the highest hydrocarbon biodegradation indices, EPS production was not detected. Low EPS production may not necessarily be indicative of an absence of emulsifier activity, as indicated by the results of a surface tension reduction assay and emulsification indices for the strain of Dietzia sp. The combined results gathered in this work suggest that a microbial consortium consisting of bacteria with interdependent metabolisms could thrive in petroleum reservoirs, thus overcoming the limitations imposed on each individual species by the harsh conditions found in such environments.

  13. Modeling the (Sub)surface Deformation Field Evolution Due to Production from a Hydrocarbon Reservoir Overlain by Rocksalt

    NASA Astrophysics Data System (ADS)

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

    2014-12-01

    Rocksalt is an important caprock for sealing or trapping hydrocarbons. Given its relatively low viscosity, it may flow during and after production and result in time-dependent surface deformation. To predict the consequences of alternative production strategies, we seek to understand the primary controls on stress-driven flow and surface deformation of hydrocarbon extraction from a reservoir topped by rocksalt. The mechanical properties of rock salt are a key influence, but complicated. Depending on grain size, temperature, and stress, salt can deform mainly elastically, by power law viscous creep, and/or by linear viscous diffusion creep. In this study, we evaluate the evolution of production induced deformation using generic geo-mechanical models. Our strategy is to start with simplified geometries, rheologies, and forcing, and to increase model complexity slowly. Our results show that there are two distinctly different time scales that dominate the evolution of the models: short term subsidence and longer term partial rebound. The shortest time scale corresponds to stress-driven flow in the vicinity of the reservoir. The longest time scale is controlled by resistance to viscous flow and stress relaxation within a wider region of the rocksalt layer. We discuss the sensitivity to the thickness of the rocksalt seal, the geometry of the reservoir, and the distance between the source and the seal.

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

    NASA Astrophysics Data System (ADS)

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

    2015-08-01

    The aim of this article is to describe and interpret qualitative and quantitative changes at rock matrix scale of Lower-Upper Cretaceous sandstones exposed to supercritical (SC) CO2 and brine. The effects of experimental injection of SC CO2 during the first injection phases were studied at rock matrix scale, in a potential deep sedimentary reservoir in Northern Spain (Utrillas unit, at the base of the Cenozoic Duero Basin). Experimental wet CO2 injection was performed in a reactor chamber under realistic conditions of deep saline formations (P ≈ 78 bar, T ≈ 38 °C and 24 h exposure time). After the experiment, exposed and non-exposed equivalent sample sets were compared with the aim of assessing possible changes due to the effect of the CO2-brine exposure. Optical microscopy (OpM) and scanning electron microscopy (SEM) aided by optical image analysis (OIA) were used to compare the rock samples and get qualitative and quantitative information about mineralogy, texture and porous network distribution. Chemical analyses were performed to refine the mineralogical information and to obtain whole rock geochemical data. Brine composition was also analysed before and after the experiment. The results indicate an evolution of the pore network (porosity increase ≈ 2 %). Intergranular quartz matrix detachment and partial removal from the rock sample (due to CO2 input/release dragging) are the main processes that may explain the porosity increase. Primary mineralogy (≈ 95 % quartz) and rock texture (heterogeneous sand with interconnected framework of micro-channels) are important factors that seem to enhance textural/mineralogical changes in this heterogeneous system. The whole rock and brine chemical analyses after interaction with SC CO2-brine do not present important changes in the mineralogical, porosity and chemical configuration of the rock with respect to initial conditions, ruling out relevant precipitation or dissolution at these early stages. These results

  15. Sandstones of unexpectedly high diffusibility.

    PubMed

    Bashar, Khairul; Tellam, John H

    2011-03-25

    Measurements have been made of diffusion coefficients (D(i)=-mass flux/concentration gradient) using a double reservoir, steady-state method with two tracers, CaBr(2) and amino-G-acid, on intact samples of Triassic red-bed sandstone from northwest England. Diffusibility (D'=D(i)/diffusion coefficient in water) averages 0.124, ranging between 0.075 and 0.215 (porosity 0.1 to 0.24), very similar for the two tracers. Implied tortuosities (actual path length/straight line length) average 1.21 (range 1.06 to 1.47), with constrictivities close to 1. In comparison with limited red-bed sandstone data from elsewhere, these D' values are up to 4 times greater, and tortuosity correspondingly lower. Re-interpretation of formation factor data from previous studies on shallow sandstone samples also from northwest England confirms that diffusibility is significantly higher in these sandstones than others from similar palaeoenvironment/stratigraphic units. The lower tortuosities appear to result from the relatively high permeability, open fabric of the rock, properties likely to be present in shallow sandstone systems used for water supply. It is concluded that diffusion rates may, in some shallow freshwater-containing continental sandstone systems, be significantly greater than is implied by estimates of sandstone diffusibility current in the literature. Copyright © 2010 Elsevier B.V. All rights reserved.

  16. Hydrocarbon reservoirs with rocksalt caprocks: time dependence of subsidence effects and the influence of the rocksalt creep model

    NASA Astrophysics Data System (ADS)

    Marketos, George; Govers, Rob; Spiers, Chris

    2015-04-01

    Rocksalt is the caprock for a large number of hydrocarbon reservoirs. Understanding its response to extraction-induced stress perturbations can therefore be very important when calculating the resulting deformation and associated subsidence above such fields. We investigate how flow in the rocksalt leads to time-dependent deformation of the ground surface using numerical models that simulate the mechanical response of the subsurface. Rock mechanical experiments have demonstrated that rocksalt can flow by linear creep or power-law creep, depending on stress and grain size among others. Given that we often do not have data from cores that constrain these quantities, we investigate the two rocksalt flow laws as alternatives. Here, we focus specifically on differences in the surface imprints of these two types of flow. Mechanical models for linear creep show that the rocksalt exhibits two time scales in response to the reservoir pumping. The first, and shortest, time scale reflects flow that is driven by relaxation of stresses in the vicinity of the reservoir. At the surface, this results in maximum subsidence that is increasing with time. The second time scale reflects closed-conduit flow within the rocksalt layer that is driven by mean stresses equilibration. Interestingly, this results in a decrease in the maximum subsidence above the reservoir.

  17. Spatial distribution of Hydrocarbon Reservoirs in the West Korea Bay Basin in the northern part of the Yellow Sea, estimated by 3D gravity forward modeling

    NASA Astrophysics Data System (ADS)

    Choi, Sungchan; Ryu, In-Chang; Götze, H.-J.; Chae, Y.

    2016-10-01

    Although an amount of hydrocarbon has been discovered in the West Korea Bay Basin (WKBB), located in the North Korean offshore area, geophysical investigations associated with these hydrocarbon reservoirs are not permitted because of the current geopolitical situation. Interpretation of satellite- derived potential field data can be alternatively used to image the three-dimensional (3D) density distribution in the sedimentary basin associated with hydrocarbon deposits. We interpreted the TRIDENT satellite-derived gravity field data to provide detailed insights into the spatial distribution of sedimentary density structures in the WKBB. We used 3D forward density modeling for the interpretation that incorporated constraints from existing geological and geophysical information. The gravity data interpretation and the 3D forward modeling showed that there are two modeled areas in the central subbasin that are characterized by very low density structures, with a maximum density of about 2000 kg/m3, indicating some type of hydrocarbon reservoir. One of the anticipated hydrocarbon reservoirs is located in the southern part of the central subbasin with a volume of about 250 km3 at a depth of about 3000 m in the Cretaceous/Jurassic layer. The other hydrocarbon reservoir should exist in the northern part of the central subbasin, with an average volume of about 300 km3 at a depth of about 2500 m.

  18. Spatial distribution of hydrocarbon reservoirs in the West Korea Bay Basin in the northern part of the Yellow Sea, estimated by 3-D gravity forward modelling

    NASA Astrophysics Data System (ADS)

    Choi, Sungchan; Ryu, In-Chang; Götze, H.-J.; Chae, Y.

    2017-01-01

    Although an amount of hydrocarbon has been discovered in the West Korea Bay Basin (WKBB), located in the North Korean offshore area, geophysical investigations associated with these hydrocarbon reservoirs are not permitted because of the current geopolitical situation. Interpretation of satellite-derived potential field data can be alternatively used to image the 3-D density distribution in the sedimentary basin associated with hydrocarbon deposits. We interpreted the TRIDENT satellite-derived gravity field data to provide detailed insights into the spatial distribution of sedimentary density structures in the WKBB. We used 3-D forward density modelling for the interpretation that incorporated constraints from existing geological and geophysical information. The gravity data interpretation and the 3-D forward modelling showed that there are two modelled areas in the central subbasin that are characterized by very low density structures, with a maximum density of about 2000 kg m-3, indicating some type of hydrocarbon reservoir. One of the anticipated hydrocarbon reservoirs is located in the southern part of the central subbasin with a volume of about 250 km3 at a depth of about 3000 m in the Cretaceous/Jurassic layer. The other hydrocarbon reservoir should exist in the northern part of the central subbasin, with an average volume of about 300 km3 at a depth of about 2500 m.

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

    PubMed

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

    2014-01-01

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

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

    PubMed Central

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

    2014-01-01

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

  1. New Acid Combination for a Successful Sandstone Acidizing

    NASA Astrophysics Data System (ADS)

    Shafiq, M. U.; Mahmud, H. K. B.; Rezaee, R.

    2017-05-01

    With the development of new enhanced oil recovery techniques, sandstone acidizing has been introduced and played a pivotal role in the petroleum industry. Different acid combinations have been applied, which react with the formation, dissolve the soluble particles; thus increase the production of hydrocarbons. To solve the problems which occurred using current preflush sandstone acidizing technology (hydrochloric acid); a new acid combination has been developed. Core flooding experiments on sandstone core samples with dimensions 1.5 in. × 3 in. were conducted at a flow rate of 2 cm3/min. A series of hydrochloric-acetic acid mixtures with different ratios were tested under 150°F temperature. The core flooding experiments performed are aimed to dissolve carbonate, sodium, potassium and calcium particles from the core samples. These experiments are followed by few important tests which include, porosity-permeability, pH value, Inductively Coupled Plasma (ICP) analysis and Nuclear Magnetic Resonance (NMR measurements). All the results are compared with the results of conventional hydrochloric acid technology. NMR and porosity analysis concluded that the new acid combination is more effective in creating fresh pore spaces and thus increasing the reservoir permeability. It can be seen from the pore distribution before and after the acidizing. Prior applying acid; the large size of pores appears most frequently in the pore distribution while with the applied acid, it was found that the small pore size is most the predominant of the pore distribution. These results are validated using ICP analysis which shows the effective removal of calcium and other positive ions from the core sample. This study concludes that the combination of acetic-hydrochloric acid can be a potential candidate for the preflush stage of sandstone acidizing at high temperature reservoirs.

  2. Wilcox sandstone reservoirs in the deep subsurface along the Texas Gulf Coast: their potential for production of geopressured geothermal energy. Report of Investigations No. 117

    SciTech Connect

    Debout, D.G.; Weise, B.R.; Gregory, A.R.; Edwards, M.B.

    1982-01-01

    Regional studies of the lower Eocene Wilcox Group in Texas were conducted to assess the potential for producing heat energy and solution methane from geopressured fluids in the deep-subsurface growth-faulted zone. However, in addition to assembling the necessary data for the geopressured geothermal project, this study has provided regional information of significance to exploration for other resources such as lignite, uranium, oil, and gas. Because the focus of this study was on the geopressured section, emphasis was placed on correlating and mapping those sandstones and shales occurring deeper than about 10,000 ft. The Wilcox and Midway Groups comprise the oldest thick sandstone/shale sequence of the Tertiary of the Gulf Coast. The Wilcox crops out in a band 10 to 20 mi wide located 100 to 200 mi inland from the present-day coastline. The Wilcox sandstones and shales in the outcrop and updip shallow subsurface were deposited primarily in fluvial environments; downdip in the deep subsurface, on the other hand, the Wilcox sediments were deposited in large deltaic systems, some of which were reworked into barrier-bar and strandplain systems. Growth faults developed within the deltaic systems, where they prograded basinward beyond the older, stable Lower Cretaceous shelf margin onto the less stable basinal muds. Continued displacement along these faults during burial resulted in: (1) entrapment of pore fluids within isolated sandstone and shale sequences, and (2) buildup of pore pressure greater than hydrostatic pressure and development of geopressure.

  3. Reservoir evaluation of thin-bedded turbidites and hydrocarbon pore thickness estimation for an accurate quantification of resource

    NASA Astrophysics Data System (ADS)

    Omoniyi, Bayonle; Stow, Dorrik

    2016-04-01

    One of the major challenges in the assessment of and production from turbidite reservoirs is to take full account of thin and medium-bedded turbidites (<10cm and <30cm respectively). Although such thinner, low-pay sands may comprise a significant proportion of the reservoir succession, they can go unnoticed by conventional analysis and so negatively impact on reserve estimation, particularly in fields producing from prolific thick-bedded turbidite reservoirs. Field development plans often take little note of such thin beds, which are therefore bypassed by mainstream production. In fact, the trapped and bypassed fluids can be vital where maximising field value and optimising production are key business drivers. We have studied in detail, a succession of thin-bedded turbidites associated with thicker-bedded reservoir facies in the North Brae Field, UKCS, using a combination of conventional logs and cores to assess the significance of thin-bedded turbidites in computing hydrocarbon pore thickness (HPT). This quantity, being an indirect measure of thickness, is critical for an accurate estimation of original-oil-in-place (OOIP). By using a combination of conventional and unconventional logging analysis techniques, we obtain three different results for the reservoir intervals studied. These results include estimated net sand thickness, average sand thickness, and their distribution trend within a 3D structural grid. The net sand thickness varies from 205 to 380 ft, and HPT ranges from 21.53 to 39.90 ft. We observe that an integrated approach (neutron-density cross plots conditioned to cores) to HPT quantification reduces the associated uncertainties significantly, resulting in estimation of 96% of actual HPT. Further work will focus on assessing the 3D dynamic connectivity of the low-pay sands with the surrounding thick-bedded turbidite facies.

  4. Fluvial reservoir architecture in the Malay Basin: Opportunities and challenges

    SciTech Connect

    Elias, M.R.; Dharmarajan, K. )

    1994-07-01

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

  5. 3D modelling of a dolomitized syn-sedimentary structure: an exhumed potential analogue of hydrocarbon reservoir.

    NASA Astrophysics Data System (ADS)

    Martinelli, Mattia; Franceschi, Marco; Massironi, Matteo; Bistacchi, Andrea; Di Cuia, Raffaele; Rizzi, Alessandro

    2016-04-01

    The decrease in discoveries of new hydrocarbon reservoirs has twofold implications: i) the need to improve our knowledge of classic reservoirs, such as traps within extensional syn-sedimentary structures, and ii) enhanced efforts aimed at better understanding complex type of reservoirs. In particular, in the last few years, fault related dolomitized bodies, often associated to extensional faults, received worldwide attention thanks to the capability of dolomitizing fluids to improve the pore network. However, the shape and geometries of the dolomitized bodies within complex fault network as well as the related porosity distribution and evolution is difficult to predict. The study of outcrop analogues can help to solve these issues. In this work, we focused our attention on the Early Jurassic carbonate sediments of the Calcari Grigi Group deposited on the Trento Platform (Italian Southern Alps). The stratigraphic succession encompasses (from bottom to top): the peritidal limestones of the Monte Zugna Formation, the initially highly porous Loppio Oolitic Limestone and the nearly tight marls and marly limestones of the lower Rotzo Formation. During Early Jurassic, after the deposition of the Loppio Oolitic Limestone, the Trento Platform underwent syn-sedimentary extensional tectonics, which caused the formation of numerous tilted blocks. Differential subsidence of these blocks is testified by abrupt thickness changes in Rotzo Formation. This created a structural framework favourable to the formation of syn-sedimentary extensional traps (with the Loppio Oolitic Limestone as reservoir and Rotzo Formation as seal). In the Tertiary, Alpine compressional tectonics caused the reactivation of the Jurassic faults with a strike slip kinematics and was associated with the circulation of dolomitizing fluids. The combination of these events led to the formation of secondary fault-related dolomitized bodies. The enhanced pore network in correspondence of the dolomitized dykes

  6. Model for sandstone-carbonate cyclothems based on upper member of Morgan Formation (Middle Pennsylvanian) of Northern Utah and Colorado

    SciTech Connect

    Driese, S.G.; Dott, R.H. Jr.

    1984-05-01

    The upper member of the 200 m (660 ft) thick Morgan Formation (Middle Pennsylvanian) consists of 5-25 m (16-82 ft) thick, very fine-grained quartz sandstone units that are interbedded repetitively with 0.5-11 m (1.6-36 ft) thick, oolitic, bioclastic, peloidal, and micritic carbonate units. Similar repetitive sequences occur widely in western North America. The quartz sandstone-carbonate cyclothems defined by this study have potential as targets for hydrocarbon exploration. Both eolian dune sandstones and dolomitized shelf carbonate strata are locally important reservoir rocks in the subsurface in parts of the western Overthrust belt in Utah and Wyoming. 84 references, 22 figures, 4 tables.

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

    SciTech Connect

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

    1997-07-01

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

  8. Reservoir characterization through facies analysis of core and outcrop of the Lower Green River Formation: Hydrocarbon production enhancement in the Altamont-Bluebell Field, Uinta Basin, Utah

    SciTech Connect

    Wegner, M.; Garner, A.; Morris, T.H.

    1995-06-01

    The Altamont-Bluebell Field has produced over 125 million barrels of oil from lacustrine rocks of the Green River Formation, yet operators have not been able to accurately distinguish productive zones from non-productive, thief, and water-bearing zones. Low recoverability is largely due to the lack of understanding of the relationship between heterolithic facies, reservoir fracture systems and clay migration. These areas were investigated by analyzing over 457 meters of core from the Bluebell area and 843 meters of outcrop from the Willow Creek area. Approximately 60% of the core consists of carbonates and 40% consists of clastics (predominantly sandstones). The carbonate rocks in general have good porosity and randomly oriented, interconnected fractures, whereas the fractures in the sandstones are more vertical and isolated. The sandstones, however, do have the best reservoir capacity due to inherent interparticle porosity. Preliminary analysis of clay types indicates swelling illite-smectite mixed layer clays as well as kaolinite in both the elastic and carbonate rocks. These swelling clay types combine with the high pour point waxy oils to reduce production efficiency and total recovery. Outcrop studies conducted in the Willow Creek Canyon area help establish facies heterogeneity and reservoir storage capacity of lithology within the facies belts that have been defined in the Altamont-Bluebell field. Although production primarily occurs from fractured lithology, core plug analyses of more than 10 lithology indicate that arenites have the greatest potential for reservoir capacity, with porosities as high as 27%. This suggests that an association of arenites with fractured lithology would provide the best scenario for long-term production.

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

    NASA Astrophysics Data System (ADS)

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

    2016-06-01

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

  10. Subglacial geomorphology reveals connections between glacial dynamics and deeper hydrocarbon reservoir leakages at the Polar north Atlantic continental margin

    NASA Astrophysics Data System (ADS)

    Andreassen, Karin; Deryabin, Alexey; Rafaelsen, Bjarne; Richarsen, Morten

    2014-05-01

    Three-dimensional (3D) seismic data from the Barents Sea continental shelf and margin reveal spatial links between subsurface distributions of inferred glacitectonic geomorphic landforms and seismic indications of fluid flow from deeper hydrocarbon reservoirs. Particularly 3D seismic techniques allow detailed mapping and visualization of buried glacial geomorphology and geophysical indications of fluid flow and gas accumulations. Several subsurface glacitectonic landforms show pronounced depressions up to 200 m deep and several km wide. These appear in many locations just upstream from hills of similar sizes and volumes, and are inferred to be hill-hole pairs. The hills are interpreted as thrusted and compressed slabs of sediments and bedrock which have been removed from their original location by moving glaciers during the last glacial, leaving the holes as depressions. The mapped depressions seem often to appear in sediments of different lithology and age. The appearance of mega-scale glacial lineations indicates that fast-flowing ice streams, draining the former Barents Sea and Fennoscandian ice sheets were the main agents of these glacitectonic landforms. Mapped fluid flow migration pathways from deeper reservoirs and shallow gas accumulations show evidence of active fluid migration systems over longer time periods, and their spatial relationship with the glacitectonic landforms is documented for several areas of the Barents Sea continental shelf. A conceptual model is proposed for the depressions, where brittle glacitectonic deformation takes place along a weak layer at the base of gas-hydrate cemented sediments. Fluid flow from deeper hydrocarbon reservoirs is inferred to be associated with cycles of glaciations and unloading due to glacial erosion and ice retreat, causing gas to expand, which in turn potentially breaks the traps, reactivates faults and creates new faults. Gas hydrate stability modeling indicates that the south-western Barents Sea is today

  11. Depth and density variations of hydrocarbon and mud reservoirs from Bouguer anomaly inversion at the Nirano Mud Volcanic Field, Italy.

    NASA Astrophysics Data System (ADS)

    Carrier, Aurore; Lupi, Matteo; Haddad, Antoine; Baron, Ludovic; Linde, Niklas

    2017-04-01

    Mud volcanoes are dynamic and stress-sensitive geological systems. They are often found in hydrocarbon provinces and could sample underlying reservoir. However those systems are still geophysically poorly investigated and their plumbing structure and flow dynamics is still not very well understood. Because of its accessibility, the Nirano Mud Volcanic Field (NMVF) was targeted as an experimental field to improve our understanding about the plumbing system of mud volcanic structures. Two gravity surveys were performed along dipole-dipole geoelectric profiles. We used the gravimeter Scintrex CG5 and the GPS Leica 1200 to conduct two profiles striking N45 and N135. Wavelength filtering of Bouguer anomalies indicate a 2000 m deep reservoir, two mid-depth reservoirs (i.e., 600 m deep) and three shallow ones (i.e., 100 m deep). Using these observations and previous studies (geology, ERT) as prior information, the Bouguer anomalies were inverted using a gradient-based least-squares method that uses the LSQR algorithm and accounts for data and model covariances. Depth weighting is taken into account by introducing a weighting matrix based on kernel decrease. Unconstrained inversion results suggest at least three subsurface bodies and one deeper one (1000 m deep). Constrained inversion results are in accordance with a model of two sub-spheroidal reservoirs located at about 1500 m depth that are tilted by 30° overlaid by two reservoirs at intermediate depths (i.e. 600 m deep). This is in agreement with the inferred tilting of the Ligurian Units occurring at such depths. Density variations range from 0 to 800 kg/m3. Due to the difficulty to constrain both geometry and density of the investigated reservoirs, complementary information (i.e. seismic and electrical resistivity tomography) will later be used to further improve the results. Despite the degree of nonuniqueness in our investigations, this study represents the first attempt to provide a gravity-based geophysical

  12. Fault Permeability Estimated From Rate of Sea Water Recharge Into an Underpressured Hydrocarbon Reservoir

    NASA Astrophysics Data System (ADS)

    Boles, J. R.; Horner, S.

    2003-12-01

    Methane has leaked from the offshore South Ellwood fault at least since discovery of the South Ellwood field at Platform Holly. The fault bounds the north side of the field and has 600 meters of normal offset. The reservoir, which is fractured Monterey shale at one kilometer depth, was initially 5% over hydrostatic pressure, but is currently at 25% below hydrostatic pressure. Production fluid in well tubing that connects the platform and reservoir is isolated from the ocean. New data indicate that the ocean is in direct hydraulic communication with the reservoir in the vicinity of the fault. Quartz pressure sensors were installed at about one km depth in five wells during a 15 day production shut down. A well that intersects the fault at reservoir depth (about one km subsea), shows a pressure variation that matches the frequency of the ocean tide. Within +/- 1 minute, there is no lag between the predicted tide signal and the pressure variation in the well. The pressure change is less than predicted from sea heights, which we attribute to compressibility of the gas in the fault zone. The other wells (160m-1 km from the fault) do not show the tidal signal, indicating that pressure change is not a general effect of the tide on the earth's crust. During testing, fluid pressures increased at a rate of 55 Pa/hr (0.008 psi/hr) in the well adjacent to the fault. We conclude that the pressure recovery from sub-hydrostatic conditions is due to sea water flowing down the fault into the under pressured reservoir. From this data we calculate the permeability of the South Ellwood Fault to be about 20 md, a value similar to the overall field permeability in the fractured Monterey reservoir.

  13. Microorganisms Associated with Hydrocarbon Contaminated Sites and Reservoirs for Microbially Enhanced Oil Recovery (MEOR)

    SciTech Connect

    Negri, M. Cristina

    2013-10-21

    Russian partner Institutes tested a number of strains from their collection and/or selected at oilfield contamination/ extraction sites to determine their ability to create aggregates that could plug oil well reservoirs to enhance oil recovey. Among these tested, five facultative anaerobic organisms that performed the best in the Russian Institutes' trials were shipped to Argonne and evaluated at Argonne for their ability to produce aggregates that plug pores in oil reservoirs formations. Results were provided to the Industrial Partner who is interested in receiving the strains for further testing.

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

    USGS Publications Warehouse

    Leetaru, H.E.

    2000-01-01

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

  15. Dunlin group sequence stratigraphy in the northern North Sea: A model for Cook sandstone deposition

    SciTech Connect

    Marjanac, T.; Steel, R.J.

    1997-02-01

    The Dunlin Group in the northern North Sea, consisting of the Johansen, Amundsen, Burton, Cook, and Drake formations of late Sinemurian-Toarcian age, hosts important hydrocarbon reservoirs in the Cook Formation sandstones. The Johansen Formation is associated with a relative fall of sea level and is interpreted to be a large sandstone delta confined within a broad incised valley at the base of the group. During a later stage of relative sea level rise, the finer grained Amundsen and Burton formations were deposited. The overlying Cook Formation consists of four sandstone tongues, each of which is characterized by a lower zone of sharp-based, upward-coarsening, thinly bedded shoreface sandstones and siltstones (reflecting forced regression during falling relative sea level) and an erosively based upper zone of thin tidal flat and thick deltaic/estuarine sandstones (reflecting lowstand incision, as well as initial progradation and subsequent transgressive backfill of estuaries during relative sea level rise). The Drake Formation shales were deposited during continued relative sea level rise. Several types of erosional surfaces are recognized within the studied succession: (1) sequence boundaries occur at the base of the Johansen Formation and within the Cook Formation, and represent the bottoms of incised valleys that truncate the underlying shoreface deposits; (2) regressive surfaces of marine erosion occur at the base of Cook Formation units and truncate the underlying Burton and Drake shales, siltstones, and mudstones; (3) transgressive tidal channel (tidal ravinement) surfaces within the Cook Formation underlie the estuarine sandstones of the incised valley fills; (4) wave ravinement surfaces truncate the tops of estuarine sandstones and are overlain by thin transgressive lags that grade upward into the overlying black shales.

  16. Joint Stochastic Inversion of Pre-Stack 3D Seismic Data and Well Logs for High Resolution Hydrocarbon Reservoir Characterization

    NASA Astrophysics Data System (ADS)

    Torres-Verdin, C.

    2007-05-01

    This paper describes the successful implementation of a new 3D AVA stochastic inversion algorithm to quantitatively integrate pre-stack seismic amplitude data and well logs. The stochastic inversion algorithm is used to characterize flow units of a deepwater reservoir located in the central Gulf of Mexico. Conventional fluid/lithology sensitivity analysis indicates that the shale/sand interface represented by the top of the hydrocarbon-bearing turbidite deposits generates typical Class III AVA responses. On the other hand, layer- dependent Biot-Gassmann analysis shows significant sensitivity of the P-wave velocity and density to fluid substitution. Accordingly, AVA stochastic inversion, which combines the advantages of AVA analysis with those of geostatistical inversion, provided quantitative information about the lateral continuity of the turbidite reservoirs based on the interpretation of inverted acoustic properties (P-velocity, S-velocity, density), and lithotype (sand- shale) distributions. The quantitative use of rock/fluid information through AVA seismic amplitude data, coupled with the implementation of co-simulation via lithotype-dependent multidimensional joint probability distributions of acoustic/petrophysical properties, yields accurate 3D models of petrophysical properties such as porosity and permeability. Finally, by fully integrating pre-stack seismic amplitude data and well logs, the vertical resolution of inverted products is higher than that of deterministic inversions methods.

  17. Mapping Exploitation-Unduced Velocity Changes in the Shallow Overburden of an Hydrocarbon Reservoir Using Correlation of Seismic Noise

    NASA Astrophysics Data System (ADS)

    Mordret, A.; Shapiro, N.; Singh, S. C.

    2014-12-01

    We used two "vintages" of ambient seismic noise recorded at the Valhall Life of the Field Seismic network in 2004 and 2005 to perform a passive time-lapse imaging of the subsurface. First, the cross-correlations between each pair of stations were computed for both vintages to extract Scholte waves. Second, the relative velocity variations between the 2004 and 2005 cross-correlations were measured on the ballistic waves using the Moving-Window Cross-Spectral technique. Finally, the best-quality relative velocity variation measurements were regionalized using a modified eikonal tomography technique. The results, albeit noisy because of the short duration of the available records, show a large patch of increased seismic velocity in the southern part of the network and a weaker anomaly in the northern part. The increase of velocity can be attributed to the subsidence caused by the exploitation of the flanks of the Valhall reservoir with new wells. Our results are in good agreement with other time-lapse results using Scholte waves from active or passive datasets. The proposed technique could be used for continuous monitoring of the hydrocarbon reservoir under exploitation and of the CO2 sequestration sites.

  18. [Distribution of various polycyclic aromatic hydrocarbons in reservoir water of Estonia].

    PubMed

    Veldre, I A; Itra, A R; Paal'me, L P; Urbas, E R

    1985-01-01

    The paper presents experimental data on different polycyclic aromatic hydrocarbons (PAH) in water, bottom sediments and algae as well as evidence available in literature on their content in exhausts of automobiles, oil shale industry and power station. Attempts are made to reveal differences in sources of the environment pollution with allowance for different PAH/benzo(a)pyrene percentage ratio, but as the PAH ratios are relatively similar in different pollution sources this attempt was a failure.

  19. Distribution of polycyclic aromatic hydrocarbons in surface water and sediment near a drinking water reservoir in Northeastern China.

    PubMed

    Liu, Yu; Shen, Jimin; Chen, Zhonglin; Ren, Nanqi; Li, Yifan

    2013-04-01

    The levels of polycyclic aromatic hydrocarbons (PAHs) in the water and the sediment samples collected near the Mopanshan Reservoir-the most important drinking water resource of Harbin City in Northeast China-were examined. A total of 16 PAHs were concurrently identified and quantified in the three water bodies tested (Lalin River, Mangniu River, and Mopanshan Reservoir) and in the Mopanshan drinking water treatment plant during the high- and low water periods. The total PAH concentrations in the water and sediment samples ranged from 122.7 to 639.8 ng/L and from 89.1 to 749.0 ng/g dry weight, respectively. Similar spatial and temporal trends were also found for both samples. The lowest Σ16PAH concentration of the Mopanshan Reservoir was obtained during the high water period; by contrast, the Lalin River had the highest concentration during the low water period. The PAH profiles resembling the three water bodies, with high percentages of low-molecular weight PAHs and dominated by two- to three-ring PAHs (78.4 to 89.0%). Two of the molecular indices used reflected the possible PAH sources, indicating the main input from coal combustion, especially during the low water period. The conventional drinking water treatment operations resulted in a 20.7 to 67.0% decrease in the different-ringed PAHs in the Mopanshan-treated drinking water. These findings indicate that human activities negatively affect the drinking water resource. Without the obvious removal of the PAHs in the waterworks, drinking water poses certain potential health risks to people.

  20. Integrated reservoir description and analysis of the Lance formation at Jonah Field, Sublette County, Wyoming

    SciTech Connect

    Robinson, J.W.; Delozier, D.L.; Flinch, R.

    1996-06-01

    Log, core, and production data from the 16 wells in Jonah field have been used to characterize sandstone reservoirs in the Lance Formation (Cretaceous) in the northern Green River basin. The Lance Fm. is composed of 2500 feet of heterolithic fluvial strata that were deposited on a broad alluvial plain. Sandstones were deposited in east- flowing channels 10-20 feet deep and 150-4000 feet wide; some amalgamated sandstone intervals are >100 feet thick and over a mile wide. Fluvial architecture varies from isolated meandering river deposits to amalgamated braided river deposits. Sandstones are dominantly composed of detrital chert and quartz grains. The Lance Fm. has been divided into several informal pay intervals that have different reservoir character and performance. Wardell interval sandstones produce gas in eight wells and are poor reservoirs due to fine grain size, high clay and cement content, and greater depth. Yellow Point interval sandstones have shown average performance in five wells. The Jonah interval produces in 10 wells and is the most prolific pay zone with up to 150 net feet of sandstone having core porosity of 8-12% and permeability of .01-0.9 mD. Upper and middle Lance sandstones have better than average performance from five wells. All pay intervals require greater than 8% porosity and less than 35% water saturation. Pre-frac pressure build-up analysis indicates in situ permeabilities of 3-20 microdarcys and suggests that fractures are a significant contributor to deliverability. Estimated reserves of 0.4-4.0 BCFG/well are based on decline curve analysis. Liquid yields vary from 6-86 BO/MMCFG and increase with depth. Pressure gradients range from .55 to .59 psi/ft. Reservoir overpressure is a result of continuous migration of hydrocarbons into available pore space via microfracture seepage.

  1. Petrophysics Features of the Hydrocarbon Reservoirs in the Precambrian Crystalline Basement

    NASA Astrophysics Data System (ADS)

    Plotnikova, Irina

    2014-05-01

    A prerequisite for determining the distribution patterns of reservoir zones on the section of crystalline basement (CB) is the solution of a number of problems connected with the study of the nature and structure of empty spaces of reservoirs with crystalline basement (CB) and the impact of petrological, and tectonic factors and the intensity of the secondary transformation of rocks. We decided to choose the Novoelhovskaya well # 20009 as an object of our research because of the following factors. Firstly, the depth of the drilling of the Precambrian crystalline rocks was 4077 m ( advance heading - 5881 m) and it is a maximum for the Volga-Urals region. Secondly, petrographic cut of the well is made on core and waste water, and the latter was sampled regularly and studied macroscopically. Thirdly, a wide range of geophysical studies were performed for this well, which allowed to identify promising areas of collector with high probability. Fourth, along with geological and technical studies that were carried out continuously (including washing and bore hole redressing periods), the studies of the gaseous component of deep samples of clay wash were also carried out, which indirectly helped us estimate reservoir properties and fluid saturation permeable zones. As a result of comprehensive analysis of the stone material and the results of the geophysical studies we could confidently distinguish 5 with strata different composition and structure in the cut of the well. The dominating role in each of them is performed by rocks belonging to one of the structural-material complexes of Archean, and local variations in composition and properties are caused by later processes of granitization on different stages and high temperature diaphthoresis imposed on them. Total capacity of reservoir zones identified according to geophysical studies reached 1034.2 m, which corresponds to 25.8% of the total capacity of 5 rock masses. However, the distribution of reservoirs within the cut

  2. Hydrocarbon composition of authigenic inclusions: Application to elucidation of petroleum reservoir filling history

    NASA Astrophysics Data System (ADS)

    Karlsen, Dag A.; Nedkvitne, Tor; Larter, Steve R.; Bjørlykke, Knut

    1993-08-01

    Geochemical analysis of petroleum inclusions trapped in authigenic feldspar and quartz in the Ula Formation in the North Sea Ula oil field revealed a petroleum of markedly different composition than the oil presently in the reservoir. Using microthermometry and the burial history as a dating tools, it is concluded that the petroleum in the K-feldspar inclusions was present in the more porous and permeable parts of the Ula Formation as early as 45-75 My Bp when the field was at a depth of about 1.0-1.5 km, as compared with the current depth of 3.4 km. This early petroleum, which was trapped as inclusions in authigenic K-feldspar, shows a distinctly different distribution of tricyclic terpanes and pentacyclic triterpanes from that of the current petroleum charge in the Ula Formation, which was derived from the Mandal Formation source rock in late Neogene time. Molecular parameters show that the oil in the K-feldspar inclusions is significantly less mature than the crude oil in the present reservoir. The approximate 90°C temperature increase occurring after entrapment of the early petroleum in Kfeldspar (the field is currently at 143°C) appears not to have reset the low maturity signature of the oil in the K-feldspar inclusions. This could suggest that the temperature in the inclusions is too low for isomerization/selective thermal degradation to occur (lack of catalysts?), or that there are other controls on the ratio of some of these parameters. Still, parameters like the ratio of C 21 to C 28 triaromatic steroids, and those based on dimethyl- and trimethyl-naphthalenes, are comparatively similar in both the inclusions and in the reservoir crude. The oil inclusions in authigenic quartz and albite, formed from about 10 My BP (burial depth ≈ 2.5 km) until the present (burial depth = 3.4 km), are interpreted as representing a palaeo-petroleum charge having a composition intermediate between the oil found in K-feldspar inclusions and the oil charge in the present

  3. Effects of sequence stratigraphy on distribution of Cambro-Ordovician siliciclastic hydrocarbon reservoirs in Michigan basin

    SciTech Connect

    Horne, J.C.; Reel, C.L.; Cummins, G.D. )

    1989-08-01

    The lateral and vertical distribution of Cambrian-Ordovician siliciclastic reservoir-potential rock types in the Michigan basin is governed by the sequence stratigraphy. The sequence stratigraphy is controlled primarily by the interaction of four variables: subsidence, eustasy, volume of sediments, and climate. Seven sequential stratigraphic intervals can be defined in the pre-Utica, Cambrian-Ordovician deposits of the Michigan basin. Each of these unconformity-bounded sequences begins with a siliciclastic unit deposited over a lowstand surface of erosion. These lowstand surfaces developed during periods when eustatic sea level decline exceeded the rate of subsidence in the basin, and much or all of the basin became exposed. Where the sedimentation rate was less than the sum of the rate of subsidence and sea level change, a transgressive sequence developed with more open-marine carbonates overlying shallower water and/or non-marine facies. Reservoir-potential siliciclastics accumulated in incised valley-fill and transgressive reworked deposits.

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

    NASA Astrophysics Data System (ADS)

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

    2016-12-01

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

  5. A methodology to evaluate regional hydraulic controls on flow from hydrocarbon reservoirs into overlying aquifers

    SciTech Connect

    Fryar, A.E.; Kreitler, C.W.; Akhter, M.C.

    1994-09-01

    Because drilling, completion, and abandonment practices for oil and gas wells have improved over the past century, some older abandoned wells may be mechanically deficient or inadequately plugged, thus posing a risk of contamination to underground sources of drinking water. The risk of saltwater contamination of freshwater aquifers through inadequately plugged, abandoned wells increases if the hydraulic potential of the oil- and-gas-bearing brine formations is higher than that in the overlying freshwater aquifers. First, average regional potentiometric surfaces of aquifers and reservoirs are generated from aquifer water-level measurements and the conversion of bottom-hole pressure measurements from oil and gas reservoirs to hydraulic heads. Next, differences in hydraulic heads between aquifers and reservoirs are calculated to delineate regional residual areas of upward (positive) or downward (negative) hydraulic gradients. Third, locations of abandoned wells and class II injection wells are plotted relative to residuals to examine where water flooding, pressure maintenance, and saltwater disposal may cause or exacerbate the potential for upward flow. Three areas were used as case studies for testing the method. Positive residuals in the South Texas basin (informally defined to include the Val Verde basin, Maverick basin, part of the Rio Grande Salt basin, and the Austin Chalk trend) result from natural geopressuring in formations deeper than 6000 ft, which are negligibly affected by class II injection wells. Positive residuals in the greater Permian basin (including the northwestern shelf, Delaware basin, part of the Palo Duro basin, Central Basin platform, Midland basin, southern shelf, and Fort Worth basin) may reflect injection for enhanced recovery in the west and natural hydrologic processes in the eastern shelf region. Residual surfaces for the San Juan basin indicate several areas with a natural potential for upward migration of brine.

  6. GREYBULL SANDSTONE PETROLEUM POTENTIAL ON THE CROW INDIAN RESERVATION, SOUTH-CENTRAL MONTANA

    SciTech Connect

    David A. Lopez

    2000-12-14

    . With continued transgression, the Greybull fluvial sand graded upward into marginal marine (probably estuarine) sand (upper Greybull) and finally was capped by marine shale and the Fall River Sandstone. Subsurface mapping, incorporated with surface data, has revealed five major Greybull channels crossing the Crow Reservation. The Greybull Sandstone is a proven petroleum reservoir in the Crow Reservation region. Greybull combination traps require the presence of channel sandstone as well as structural closure. With sparse reservation well control, subsurface structural and isopach maps are highly interpretive. Three potential Greybull exploration leads were identified where possible structural closures are coincident with mapped Greybull channels: the Little Woody, Woody Dome, and Crow Agency prospects. Of these, the Crow Agency prospect was confirmed by a significant soil-gas anomaly and appears to have the greatest probability of having trapped a hydrocarbon accumulation.

  7. Depositional architecture of Springer Old Woman sandstone, central Anadarko basin, Oklahoma

    SciTech Connect

    O'Donnell, M.R.; Haiduk, J.P.

    1987-08-01

    The fluvial meander belt containing the Old Woman sandstone served as a conduit for clastics transported into the Anadarko basin. Mappable for a distance of more than 30 mi (48 km), sand bodies characterizing this system average 0.5 mi (0.8 km) in width and attain maximum thicknesses of 50-70 ft (15-20 m). Channel and point-bar sandstone facies display a fining-upward sequence and sharp basal contact, as inferred from gamma-ray and resistivity logs. Sandstones of the Old Woman fluvial complex overlie the laminated shales and silts of the penecontemporaneous flood-plain environment. These flood-plain deposits are underlain by crinoidal wackestones and packstones deposited in the subtidal regime. Encroachment of the fluvial complex into a marine setting is interpreted from this sequence. Thin flood-plain deposits and lack of shallow marine clastic sediments suggest rapid advancement. Quartzitic and petrologically mature, the Old Woman sandstone is fine grained, with small-scale troughs and laminations, and a few mudstone rip-up clasts. Diagenesis has altered the mineralogic composition mainly by siliceous and carbonate cementation. Porosity is secondary, resulting from dissolution of various metastable constituents. The Old Woman sandstone was established as a hydrocarbon reservoir in the early 1960s, and sporadic development continued for years. The present-day petroleum market has prompted a resurgence in drilling activity owing to the economic viability of this reservoir. Successful wells are concentrated in newly discovered meander-belt bends; however, the elusiveness of this fluvial system challenges today's exploration geologists as it has for the past quarter century.

  8. Shale hydrocarbon reservoirs: some influences of tectonics and paleogeography during deposition: Chapter 2

    USGS Publications Warehouse

    Eoff, Jennifer D

    2014-01-01

    Fundamental to any of the processes that acted during deposition, however, was active tectonism. Basin type can often distinguish self-sourced shale plays from other types of hydrocarbon source rocks. The deposition of North American self-sourced shale was associated with the assembly and subsequent fragmentation of Pangea. Flooded foreland basins along collisional margins were the predominant depositional settings during the Paleozoic, whereas deposition in semirestricted basins was responsible along the rifted passive margin of the U.S. Gulf Coast during the Mesozoic. Tectonism during deposition of self-sourced shale, such as the Upper Jurassic Haynesville Formation, confined (re)cycling of organic materials to relatively closed systems, which promoted uncommonly thick accumulations of organic matter.

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

    SciTech Connect

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

    2015-02-05

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

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

    DOE PAGES

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

    2015-02-05

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

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

    NASA Astrophysics Data System (ADS)

    Langenbruch, Cornelius; Shapiro, Serge A.

    2015-04-01

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

  12. Permian tectonism in Rocky Mountain foreland and its importance in Exploration for Minnelusa and Lyons sandstones

    SciTech Connect

    Moore, W.R.

    1985-05-01

    Permian sandstones are important producers of oil in the Powder River and Denver basins of the Rocky Mountain foreland region. In the Powder River basin, Wolfcampian Minnelusa Sandstone produces oil from structural and stratigraphic traps on both sides of the basin axis, whereas in Denver basin, the Leonardian Lyons Sandstone produces oil mainly from structural traps on the west flank of the basin. Two fields, North Fork-Cellars Ranch in the Powder River basin, and Black Hollow in the Denver basin, are examples of Permian growth of structural features. At North Fork-Cellars Ranch, a period of Permian structural growth and resultant differential sedimentation is documented by structure and isopach maps of the Minnelusa and overlying Goose Egg Formation. Structural growth began at the end of Minnelusa deposition and resulted in deposition of a much thicker Goose Egg section on the west flank of the field. At Black Hollow, mapping indicates structural growth was initiated before deposition of the Lyons Sandstone and continued throughout Leonardian time. In both fields growth abruptly ceased in the Late Permian. Both North Fork-Cellars Ranch and Black Hollow are located on structural highs, or arches, which trend east-west across the Powder River and Denver basins. These arches were present during the pre-Laramide migration of Paleozoic-sourced hydrocarbons into the basins and acted as pathways for migration. Exploration for Permian reservoirs in the two basins should be concentrated on the arches, as the early formed traps were present when migration began.

  13. Micro- and Macro-Scale Petrophysical Characterization of a Lower Cretaceous sandstone unit simulated in a real geometry obtained with µ-CT Imaging

    NASA Astrophysics Data System (ADS)

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

    2017-04-01

    Lower Cretaceous sandstone serves as hydrocarbon reservoir in some places over the world, and potentially in Hatira formation,Northern Israel. The purpose of the current research is to conduct a petrophysical characterization of these sandstone units. The study was carried out by two alternative methods: using conventional macroscopic lab measurements; and using a 3D microscopic imaging a modeling. The latter included µ-CT scanning, segmentation of the pore-network, image processing, image analysis of pore network, followed by fluid flow simulations at a microscale. Upscaling the results of these micro-scale flow simulations allowed obtaining macroscopic rock parameters that are conventionally measured in the lab. Comparison of the upscaled and the measured properties was conducted, showing a good agreement. Results of this study will provide necessary parameters for the future macroscopic fluid flow modeling in the Lower Cretaceous sandstone, applicable for the fields of petroleum production and CO2 sequestration.

  14. Global prediction of continuous hydrocarbon accumulations in self-sourced reservoirs

    USGS Publications Warehouse

    Eoff, Jennifer D.

    2012-01-01

    This report was first presented as an abstract in poster format at the American Association of Petroleum Geologists (AAPG) 2012 Annual Convention and Exhibition, April 22-25, Long Beach, Calif., as Search and Discovery Article no. 90142. Shale resource plays occur in predictable tectonic settings within similar orders of magnitude of eustatic events. A conceptual model for predicting the presence of resource-quality shales is essential for evaluating components of continuous petroleum systems. Basin geometry often distinguishes self-sourced resource plays from conventional plays. Intracratonic or intrashelf foreland basins at active margins are the predominant depositional settings among those explored for the development of self-sourced continuous accumulations, whereas source rocks associated with conventional accumulations typically were deposited in rifted passive margin settings (or other cratonic environments). Generally, the former are associated with the assembly of supercontinents, and the latter often resulted during or subsequent to the breakup of landmasses. Spreading rates, climate, and eustasy are influenced by these global tectonic events, such that deposition of self-sourced reservoirs occurred during periods characterized by rapid plate reconfiguration, predominantly greenhouse climate conditions, and in areas adjacent to extensive carbonate sedimentation. Combined tectonic histories, eustatic curves, and paleogeographic reconstructions may be useful in global predictions of organic-rich shale accumulations suitable for continuous resource development. Accumulation of marine organic material is attributed to upwellings that enhance productivity and oxygen-minimum bottom waters that prevent destruction of organic matter. The accumulation of potential self-sourced resources can be attributed to slow sedimentation rates in rapidly subsiding (incipient, flexural) foreland basins, while flooding of adjacent carbonate platforms and other cratonic highs

  15. Subtask 1.17 - Measurement of Hydrocarbon Evolution from Coal and Petroleum Reservoirs Under Carbon Dioxide Floods

    SciTech Connect

    Steven B. Hawthorne

    2006-12-31

    The project developed, built, and tested three apparatuses for studying different interactions of carbon dioxide with geologic materials. In Year 1, an online instrument was constructed by coupling a high-pressure carbon dioxide extraction system with a flame ionization detector that can yield a real-time profile and quantitative measurements of hydrocarbons removed from materials such as coal and petroleum reservoir rock. In Years 2 and 3, one instrument was built to measure the excess sorption of carbon dioxide in geologic materials such as coal and showed that measurable uptake of carbon dioxide into the coal matrix is rapid. The final apparatus was built to expose geologic materials to carbon dioxide for long periods of time (weeks to months) under the range of pressures and temperatures relevant to carbon dioxide sequestration. The apparatus allows as many as twenty gram-sized samples of geologic materials to be exposed simultaneously and can also include exposures with geologic brines. The system was used to demonstrate complete conversion of magnesium silicate to magnesium carbonate in less than 4 weeks when exposed to clean water or brine, compared to no measurable conversion of dry magnesium carbonate.

  16. Breakdown of doublet recirculation and direct line drives by far-field flow in reservoirs: implications for geothermal and hydrocarbon well placement

    NASA Astrophysics Data System (ADS)

    Weijermars, R.; van Harmelen, A.

    2016-07-01

    An important real world application of doublet flow occurs in well design of both geothermal and hydrocarbon reservoirs. A guiding principle for fluid management of injection and extraction wells is that mass balance is commonly assumed between the injected and produced fluid. Because the doublets are considered closed loops, the injection fluid is assumed to eventually reach the producer well and all the produced fluid ideally comes from stream tubes connected to the injector of the well pair making up the doublet. We show that when an aquifer background flow occurs, doublets will rarely retain closed loops of fluid recirculation. When the far-field flow rate increases relative to the doublet's strength, the area occupied by the doublet will diminish and eventually vanishes. Alternatively, rather than using a single injector (source) and single producer (sink), a linear array of multiple injectors separated by some distance from a parallel array of producers can be used in geothermal energy projects as well as in waterflooding of hydrocarbon reservoirs. Fluid flow in such an arrangement of parallel source-sink arrays is shown to be macroscopically equivalent to that of a line doublet. Again, any far-field flow that is strong enough will breach through the line doublet, which then splits into two vortices. Apart from fundamental insight into elementary flow dynamics, our new results provide practical clues that may contribute to improve the planning and design of doublets and direct line drives commonly used for flow management of groundwater, geothermal and hydrocarbon reservoirs.

  17. Mercury-free PVT apparatus for thermophysical property analyses of hydrocarbon reservoir fluids. Final report, August 16, 1990--July 31, 1992

    SciTech Connect

    Lansangan, R.M.; Lievois, J.S.

    1992-08-31

    Typical reservoir fluid analyses of complex, multicomponent hydrocarbon mixtures include the volumetric properties, isothermal compressibility, thermal expansivity, equilibrium ratios, saturation pressure, viscosities, etc. These parameters are collectively referred to as PVT properties, an acronym for the primary state variables; pressure, volume, and temperature. The reservoir engineer incorporates this information together with the porous media description in performing material balance calculations. These calculations lead to the determination (estimation) of the initial hydrocarbon in-place, the future reservoir performance, the optimal production scheme, and the ultimate hydrocarbon recovery. About four years ago, Ruska Instrument Corporation embarked on a project to develop an apparatus designed to measure PVT properties that operates free of mercury. The result of this endeavor is the 2370 Hg-Free PVT system which has been in the market for the last three years. The 2370 has evolved from the prototype unit to its present configuration which is described briefly in this report. The 2370 system, although developed as a system-engineered apparatus based on existing technology, has not been exempt from this burden-of-proof Namely, the performance of the apparatus under routine test conditions with real reservoir fluids. This report summarizes the results of the performance and applications testing of the 2370 Hg-Free PVT system. Density measurements were conducted on a pure fluid. The results were compared against literature values and the prediction of an equation of state. Routine reservoir fluid analyses were conducted with a black oil and a retrograde condensate gas mixtures. Limited comparison of the results were performed based on the same tests performed on a conventional mercury-based PVT apparatus. The results of these tests are included in this report.

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

    SciTech Connect

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

    1994-01-01

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

  19. Novel CO2 Foam Concepts and Injection Schemes for Improving CO2 Sweep Efficiency in Sandstone and Carbonate Hydrocarbon Formations

    SciTech Connect

    Nguyen, Quoc; Hirasaki, George; Johnston, Keith

    2015-02-05

    We explored cationic, nonionic and zwitterionic surfactants to identify candidates that have the potential to satisfy all the key requirements for CO2 foams in EOR. We have examined the formation, texture, rheology and stability of CO2 foams as a function of the surfactant structure and formulation variables including temperature, pressure, water/CO2 ratio, surfactant concentration, salinity and concentration of oil. Furthermore, the partitioning of surfactants between oil and water as well as CO2 and water was examined in conjunction with adsorption measurements on limestone by the Hirasaki lab to develop strategies to optimize the transport of surfactants in reservoirs.

  20. Frisco City sand: New Jurassic reservoir in southwest Alabama

    SciTech Connect

    Mann, S.D.; Mink, R.M.; Bearden, B.L. ); Schneeflock, R.D. Jr. )

    1989-09-01

    The first commercial production of hydrocarbons from the Jurassic Haynesville Formation in southwestern Alabama was from the Frisco City field. The field currently produces 57.8{degree} API gravity oil on 160-ac well spacing from a depth of approximately 12,000 ft. Perforations are in the Frisco City sand interval, in the lower part of the Haynesville Formation. Average porosity is 15% and average permeability is 45 md. Currently, the field has two producing wells with cumulative production of over 138,876 bbl of oil and 213,144 mcf of gas. The hydrocarbon trap in the Frisco City field is a combination structural-stratigraphic trap. The Frisco City sand reservoir is located on a faulted anticline. The stratigraphic trap is produced by a permeability barrier near the crest of the structure and termination against a basement high. The lower part of the Haynesville Formation in this area is comprised of (in ascending order) the Buckner Anhydrite Member, the Frisco City sand, and interbedded shale and anhydrite. Sandstones of the Frisco City sand interval were deposited in a shallow marine setting and have a sheetlike morphology. The sandstones are poorly to moderately sorted, angular to rounded arkose, and contain angular to rounded pebbles. The sandstones are interbedded with thin, sandy, mudstones that contribute, along with patchy carbonate and anhydrite cement, to considerable reservoir heterogeneity. Porosity is predominantly primary intergranular with a small amount of framework grain dissolution and decementation.

  1. Poncho field - Cretaceous J sandstone stratigraphic traps - Denver basin, Colorado

    SciTech Connect

    Ethridge, F.G.; Ziegler, J.R.

    1983-08-01

    Distributary channel and delta destructional sandstones of Early Cretaceous age are important reservoirs for stratigraphic traps in the J sandstone at Poncho field, Adams and Arapahoe Counties, Colorado. Cores and logs from the field area reveal a lowermost, nonproductive, northeast-trending delta front sandstoe (J-3); a middle complex of southeast- and east-trending, productive distributary channel sandstones (J-2) that grade into tightly cemented delta fringe marine sediments to the southeast and northeast; and an upper, northeast trending, productive delta destructional sandstone (J-1). Vertical and lateral sequences of sedimentary structures, textures, trace fossil assemblages, and geometry and trend of sandstone bodies suggest that these units were part of a wave-dominated delta complex that prograded to the east and southeast from the area of Lonetree field. Thin section and SEM analyses reveal that the principal cements in both reservoir sandstones are quartz overgrowths, kaolinite, and chlorite, and that the bulk of the porosity is secondary and related to dissolution of carbonate cement and feldspar grains. Porosities and permeabilities are most variable and lowest in the nonproductive delta front sandstones, averaging 15% and 7 md; variable and intermediate in the productive distributary channel sandstones, averaging 16% and 28 md; and most uniform and highest in the overlying delta destructional sandstones, averaging 21% and 88 md.

  2. Spatial distribution and sources of polycyclic aromatic hydrocarbons (PAHs) in the reservoir sediments after impoundment of Manwan Dam in the middle of Lancang River, China.

    PubMed

    An, NanNan; Liu, Shiliang; Yin, Yijie; Cheng, Fangyan; Dong, Shikui; Wu, Xiaoyu

    2016-08-01

    Polycyclic aromatic hydrocarbons (PAHs) have received increasing attentions owing to their carcinogenicity, teratogenicity and environmental toxicity. The studies on the spatial variations, sources identification and potential ecological risk assessment of PAHs in the reservoir sediments after dam construction are becoming new hotpots. Sixteen PAHs contamination levels were investigated from 15 sample sections in the sediments of Manwan Reservoir in the middle of Lancang River, China. Total concentrations of 16 PAHs ranged from 14.4 to 137.7 ng g(-1) dw with a mean concentration of 70.68 ng g(-1) dw. The areas with residential settlement at large tributaries and near dam had higher PAHs concentrations. In the sight of classification of PAHs pollution levels, the sediments of Manwan Reservoir could be considered as low to moderate PAHs polluted levels. One-way analysis of variance for spatial analysis revealed that there were no significant differences (P < 0.05) for 16 PAHs at the reservoir head, centre and tail. Moreover, no significant differences (P < 0.05) were found for most individual PAH at the mainstream and tributaries except that BaP showed significant differences (P < 0.05) in the mainstream and tributaries. According to the diagnostic ratios, the possible pollution sources of PAHs in Manwan Reservoir might be mixed, primarily including the petroleum source and coal combustion. As compared with sediment quality guidelines, the observed concentrations of PAHs in all sample sections did not exceed the effects range low (ERL) and the threshold effect level (TEL) values, suggesting that there were little harmful biological toxic effects on the aquatic organisms in Manwan Reservoir. The study provided a comprehensive overview on the PAHs contaminations on the reservoir sediments in the middle Lancang River, which may have an important significances on the international river management.

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

    USGS Publications Warehouse

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

    1990-01-01

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

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

    NASA Astrophysics Data System (ADS)

    Meshri, Indu D.; Comer, John B.

    1990-10-01

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

  5. Fractures and stresses in Bone Spring sandstones

    SciTech Connect

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

    1990-09-01

    This project is a collaboration between Sandia National Laboratories and Harvey E. Yates Company being conducted under the auspices of the Oil Recovery Technology Partnership. The project seeks to apply perspectives related to the effects of natural fractures, stress, and sedimentology to the simulation and production of low-permeability gas reservoirs to low-permeability oil reservoirs as typified by the Bone Spring sandstones of the Permian Basin, southeast New Mexico. This report presents the results and analysis obtained in 1989 from 233 ft of oriented core, comprehensive suite of logs, various in situ stress measurements, and detailed well tests conducted in conjunction with the drilling of two development wells. Natural fractures were observed in core and logs in the interbed carbonates, but there was no direct evidence of fractures in the sandstones. However, production tests of the sandstones indicated permeabilities and behavior typical of a dual porosity reservoir. A general northeast trend for the maximum principal horizontal stress was observed in an elastic strain recovery measurements and in strikes of drilling-induced fractures; this direction is subparallel to the principal fracture trend observed in the interbed carbonates. Many of the results presented are believed to be new information for the Bone Spring sandstones. 57 figs., 18 tabs.

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

    NASA Astrophysics Data System (ADS)

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

    2016-12-01

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

  7. Reservoir quality and diagenetic evolution of Upper Mississippian rocks in the Illinois Basin; influence of a regional hydrothermal fluid-flow event during late diagenesis

    USGS Publications Warehouse

    Pitman, Janet K.; Henry, Mitchell E.; Seyler, Beverly

    1998-01-01

    Conventional reservoir quality data for more than 300 wells provided by the Illinois and Indiana State Geological Surveys were analyzed to determine the factors governing porosity and permeability in the Upper Mississippian Bethel Sandstone and Cypress Sandstone, two of the principal producing units in the Illinois Basin. In addition, approximately 150 samples of the Bethel Sandstone-Cypress Sandstone interval from about 80 wells in the Illinois Basin were collected for mineralogical and geochemical analysis to reconstruct the burial and diagenetic history and to establish the timing of diagenesis relative to the entrapment of hydrocarbons. One aspect of the study involved linking inorganic and organic diagenesis to late Paleozoic tectonism and hydrothermal fluid-flow events in the region.

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

    USGS Publications Warehouse

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

    1997-01-01

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

  9. The Noble Gas Record of Gas-Water Phase Interaction in the Tight-Gas-Sand Reservoirs of the Rocky Mountains

    NASA Astrophysics Data System (ADS)

    Ballentine, C. J.; Zhou, Z.; Harris, N. B.

    2015-12-01

    The mass of hydrocarbons that have migrated through tight-gas-sandstone systems before the permeability reduces to trap the hydrocarbon gases provides critical information in the hydrocarbon potential analysis of a basin. The noble gas content (Ne, Ar, Kr, Xe) of the groundwater has a unique isotopic and elemental composition. As gas migrates through the water column, the groundwater-derived noble gases partition into the hydrocarbon phase. Determination of the noble gases in the produced hydrocarbon phase then provides a record of the type of interaction (simple phase equilibrium or open system Rayleigh fractionation). The tight-gas-sand reservoirs of the Rocky Mountains represent one of the most significant gas resources in the United States. The producing reservoirs are generally developed in low permeability (averaging <0.1mD) Upper Cretaceous fluvial to marginal marine sandstones and commonly form isolated overpressured reservoir bodies encased in even lower permeability muddy sediments. We present noble gas data from producing fields in the Greater Green River Basin, Wyoming; the the Piceance Basin, Colorado; and in the Uinta Basin, Utah. The data is consistent from all three basins. We show how in each basin the noble gases record open system gas migration through a water column at maximum basin burial. The data within an open system model indicates that the gas now in-place represents the last ~10% of hydrocarbon gas to have passed through the water column, most likely prior to permeability closedown.

  10. Nitrogen isotope geochemistry of organic matter and minerals during diagenesis and hydrocarbon migration

    NASA Astrophysics Data System (ADS)

    Williams, Lynda B.; Ferrell, Ray E., Jr.; Hutcheon, Ian; Bakel, Allen J.; Walsh, Maud M.; Krouse, H. Roy

    1995-02-01

    The magnitude of isotopic variations between organic and inorganic nitrogen was examined in samples from three stacked hydrocarbon reservoirs in the Fordoche Field (Louisiana Gulf Coast Basin, USA). Measurements were made of δ 15N in kerogen, bitumen, oil, formation water, and fixed-NH 4 extracted from mudstones, nonproductive sandstones, and productive sandstones. Nitrogen isotope fractionation occurs because 14N is released preferentially to 15N from organic molecules during thermal maturation. Released 14N goes into solution, or may be adsorbed by minerals, leaving crude oil enriched in 15N. Diagenetic clay minerals (e.g., illite) commonly form in the temperature range of hydrocarbon generation, and NH 4+ may be fixed in clay interlayers with an isotopic ratio similar to that of the migrating fluids. Results indicate that the influence of organic matter on mineral δ 15N depends on the timing of authigenic mineral formation relative to fluid migration. The average δ 15N of kerogen (3.2 ± 0.3‰) and fixed-NH 4 from mudstones (3.0 ± 1.4) is similar, while bitumen increases from +3.5 to +5.1‰ with depth. In deep reservoir sandstones (>100°C), the δ 15N of crude oil averages +5.2 ± 0.4‰, similar to the δ 15N of bitumen in the proposed source rocks. Formation waters are 14N-enriched with an average δ 15N of -2.2 ± 2.6‰. Fixed-NH 4 δ 15N values lie between that of the oil and water. The average δ 15N of fixed-NH 4 is 3.0 ± 1.2‰ in productive sandstones, and 0.2 ± 2.4‰ innonproductive sandstones. In the shallower reservoir sandstones (<90°C) fixed-NH 4 is apparently not influenced by the presently associated fluids. Productive and nonproductive sandstones have distinctly low average δ 15N values (-1.2 ± 0.8‰), yet crude oil (+11.1 ± 0.3‰) and water (+3.8 ± 0.1‰) have been 15N-enriched by ˜6‰ relative to the deeper reservoirs. This suggests that the present fluids migrated into the reservoir after authigenic illite had formed

  11. The influence of hydrocarbons in changing the mechanical and acoustic properties of a carbonate reservoir: implications of laboratory results on larger scale processes

    NASA Astrophysics Data System (ADS)

    Trippetta, Fabio; Ruggieri, Roberta; Geremia, Davide; Brandano, Marco

    2017-04-01

    Understanding hydraulic and mechanical processes that acted in reservoir rocks and their effect on the rock properties is of a great interest for both scientific and industry fields. In this work we investigate the role of hydrocarbons in changing the petrophysical properties of rock by merging laboratory, outcrops, and subsurface data focusing on the carbonate-bearing Majella reservoir (Bolognano formation). This reservoir represents an interesting analogue for subsurface carbonate reservoirs and is made of high porosity (8 to 28%) ramp calcarenites saturated by hydrocarbon in the state of bitumen at the surface. Within this lithology clean and bitumen bearing samples were investigated. For both groups, density, porosity, P and S wave velocity, at increasing confining pressure and deformation tests were conducted on cylindrical specimens with BRAVA apparatus at the HP-HT Laboratory of the Istituto Nazionale di Geofisica e Vulcanologia (INGV) in Rome, Italy. The performed petrophysical characterization, shows a very good correlation between Vp, Vs and porosity and a pressure independent Vp/Vs ratio while the presence of bitumen within samples increases both Vp and Vs. P-wave velocity hysteresis measured at ambient pressure after 100 MPa of applied confining pressure, suggests an almost pure elastic behaviour for bitumen-bearing samples and a more inelastic behaviour for cleaner samples. Calculated dynamic Young's modulus is larger for bitumen-bearing samples and these data are confirmed by cyclic deformation tests where the same samples generally record larger strength, larger Young's modulus and smaller permanent strain respect to clean samples. Starting from laboratory data, we also derived a synthetic acoustic model highlighting an increase in acoustic impedance for bitumen-bearing samples. Models have been also performed simulating a saturation with decreasing API° hydrocarbons, showing opposite effects on the seismic properties of the reservoir respect to

  12. Stratigraphy, sedimentology and diagenetic evolution of the Lapur Sandstone in northern Kenya: Implications for oil exploration of the Meso-Cenozoic Turkana depression

    NASA Astrophysics Data System (ADS)

    Tiercelin, Jean-Jacques; Potdevin, Jean-Luc; Thuo, Peter Kinyua; Abdelfettah, Yassine; Schuster, Mathieu; Bourquin, Sylvie; Bellon, Hervé; Clément, Jean-Philippe; Guillou, Hervé; Nalpas, Thierry; Ruffet, Gilles

    2012-08-01

    disappearance of the Lapur upper fan system relates to the deposition of the "Turkana Volcanics" from Late Eocene, possibly as a consequence of the emplacement of the Afar Plume at 45-35 Ma. In terms of diagenesis, the main cement material at the base of the Lapur Sandstone is calcite, whereas at the middle of the formation, hematite becomes the dominant cement, and at the topmost section, kaolin cement dominates. The diagenetic evolution of the sandstones has been favourable to the retention of adequate primary intergranular porosity and the creation of secondary intragranular dissolution porosity, mainly through feldspar dissolution, and thus preserving the reservoir potential of the Lapur Sandstone. The reservoir characteristics, such as the porosity and cementation style, of the Lapur Sandstone are comparable to those of the fluvial sandstone reservoirs of the southern Sudan oil fields and this should positively contribute to the overall petroleum potential of the northern Turkana region. Though the northern Turkana area has remained largely unexplored, it is hoped that the demonstration of the presence of reasonably good reservoir quality sandstones in the Lapur Sandstone will serve to encourage further interest in hydrocarbon exploration in the Turkana area.

  13. Hydrocarbon systems in the southwest Maracaibo Basin, Colombia

    SciTech Connect

    Yurewicz, D.A.; Advocate, D.M.; Sequeira, J.J.; McDermott, V.J.; Young, R.H.; Wellman, P.C.

    1996-08-01

    Multiple hydrocarbon systems are recognized in the Colombian portion of the Maracaibo Basin (Catatumbo subbasin). Hydrocarbons, trapped in wrench controlled, faulted anticlines, were generated from two different source horizons, in two distinct source kitchens, and migrated along different pathways into Cretaceous and Tertiary reservoirs. Cretaceous reservoirs are shallow-marine sandstones and limestones characterized by low matrix porosity and permeability. They are separated from Tertiary reservoirs by a thick shale seal that limited cross-stratal migration. Tertiary reservoirs are fluvial-deltaic sandstones with good to excellent porosities and permeabilities. Geochemical data suggest the presence of two oil families. Family 1 oils were sourced locally from Cretaceous marine shales and limestones and account for most of the oil in Tertiary and Cretaceous reservoirs. Family 2 oils are only present in Tertiary reservoirs in the southern part of the subbasin, and are interpreted to be sourced from Paleocene terrestrial shales and coals. Two distinct migration systems operated to fill Catatumbo traps. Family 1 oils migrated from local Cretaceous source beds along fractures and faults that developed concurrently with trap formation. Family 2 oils were sourced from outside the Catatumbo subbasin. Maturation data and burial history modelling indicate that Paleocene rocks are immature in the Catatumbo subbasin. Maturation levels increase westward into the Maracaibo Basin and along the axis of the North Andean foredeep. The proximity of Rio Zulia Field to the North Andean foredeep, and lack of Tertiary-sourced oils in other Catatumbo fields suggest that the North Andean foredeep is the primary source for these oils.

  14. Fractures and stresses in Bone Spring sandstones

    SciTech Connect

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

    1992-06-01

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

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

    NASA Astrophysics Data System (ADS)

    Abdel-Fattah, Mohamed; Slatt, Roger

    2013-12-01

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

  16. Greybull Sandstone Petroleum Potential on the Crow Indian Reservation, South-Central Montana

    SciTech Connect

    Lopez, David A.

    2002-05-13

    The focus of this project was to explore for stratigraphic traps that may be present in valley-fill sandstone at the top of the Lower Cretaceous Kootenai Formation. This sandstone interval, generally known as the Greybull Sandstone, has been identified along the western edge of the reservation and is a known oil and gas reservoir in the surrounding region. The Greybull Sandstone was chosen as the focus of this research because it is an excellent, well-documented, productive reservoir in adjacent areas, such as Elk Basin; Mosser Dome field, a few miles northwest of the reservation; and several other oil and gas fields in the northern portion of the Bighorn Basin.

  17. Volume and accessibility of entrained (solution) methane in deep geopressured reservoirs - tertiary formations of the Texas Gulf Coast. Final report

    SciTech Connect

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

    1980-10-01

    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. The area of investigation is about 50,000 mi/sup 2/. Factors that 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 the distribution of potential sandstone reservoirs was made from a data base of 880 electrical well logs, from which a grid of 24 dip cross sections and 4 strike cross sections was constructed. Solution methane content in each of nine formations or divisions of formations was determined for each subdivision. The distribution of solution methane in the Gulf Coast was described on the basis of five reservoir models. Each model was characterized by depositional environment, reservoir continuity, porosity, permeability, and methane solubility.

  18. Microbial diversity in methanogenic hydrocarbon-degrading enrichment cultures isolated from a water-flooded oil reservoir (Dagang oil field, China)

    NASA Astrophysics Data System (ADS)

    Jiménez, Núria; Cai, Minmin; Straaten, Nontje; Yao, Jun; Richnow, Hans H.; Krüger, Martin

    2015-04-01

    Microbial transformation of oil to methane is one of the main degradation processes taking place in oil reservoirs, and it has important consequences as it negatively affects the quality and economic value of the oil. Nevertheless, methane could constitute a recovery method of carbon from exhausted reservoirs. Previous studies combining geochemical and isotopic analysis with molecular methods showed evidence for in situ methanogenic oil degradation in the Dagang oil field, China (Jiménez et al., 2012). However, the main key microbial players and the underlying mechanisms are still relatively unknown. In order to better characterize these processes and identify the main microorganisms involved, laboratory biodegradation experiments under methanogenic conditions were performed. Microcosms were inoculated with production and injection waters from the reservoir, and oil or 13C-labelled single hydrocarbons (e.g. n-hexadecane or 2-methylnaphthalene) were added as sole substrates. Indigenous microbiota were able to extensively degrade oil within months, depleting most of the n-alkanes in 200 days, and producing methane at a rate of 76 ± 6 µmol day-1 g-1 oil added. They could also produce heavy methane from 13C-labeled 2-methylnaphthalene, suggesting that further methanogenesis may occur from the aromatic and polyaromatic fractions of Dagang reservoir fluids. Microbial communities from oil and 2-methyl-naphthalene enrichment cultures were slightly different. Although, in both cases Deltaproteobacteria, mainly belonging to Syntrophobacterales (e.g. Syntrophobacter, Smithella or Syntrophus) and Clostridia, mostly Clostridiales, were among the most represented taxa, Gammaproteobacteria could be only identified in oil-degrading cultures. The proportion of Chloroflexi, exclusively belonging to Anaerolineales (e.g. Leptolinea, Bellilinea) was considerably higher in 2-methyl-naphthalene degrading cultures. Archaeal communities consisted almost exclusively of representatives of

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

    PubMed Central

    Berdugo-Clavijo, Carolina; Gieg, Lisa M.

    2014-01-01

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

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

    PubMed

    Berdugo-Clavijo, Carolina; Gieg, Lisa M

    2014-01-01

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

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

    USGS Publications Warehouse

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

    2003-01-01

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

  2. Sedimentation of the Triassic Jurassic Adigrat Sandstone Formation, Blue Nile (Abay) Basin, Ethiopia

    NASA Astrophysics Data System (ADS)

    Wolela, A.

    2008-09-01

    Exploration of oil and gas deposits in the Blue Nile Basin targeted the Adigrat Sandstone Formation as a reservoir objective. Conglomerates, gravely sandstones, coarse to medium-grained sandstones, very fine-grained cross-bedded sandstones, siltstones and mudstones of the Adigrat Sandstone Formation were deposited in semi-arid to arid climates. The North-western highlands are the main source for the sedimentation. The poorly-sorted, crudely-bedded conglomerates and gravely sandstones are interpreted as alluvial fan deposits. The basal polymictic orthoconglomerate passes up vertically into gravely sandstone, possibly indicating proximal to mid-fan sedimentation. The alluvial fan sedimentation passes up vertically into channel, point bars and flood-plain fines. The meandering river sedimentation is characterized by single and amalgamated multi-storey sandstone bodies. In places, the uppermost part of the Adigrat Sandstone Formation is represented by coal-bearing sediments possibly reflect lacustrine depositional environment. The medium-coarse-grained sandstone is a possible oil and gas reservoir, whilst the fine-grained sediments are a possible gas reservoir.

  3. Functional and genetic characterization of hydrocarbon biodegrader and exopolymer-producing clones from a petroleum reservoir metagenomic library.

    PubMed

    Vasconcellos, Suzan P; Sierra-Garcia, Isabel N; Dellagnezze, Bruna M; Vicentini, Renato; Midgley, David; Silva, Cynthia C; Santos Neto, Eugenio V; Volk, Herbert; Hendry, Philip; Oliveira, Valéria M

    2017-05-01

    Microbial degradation of petroleum is a worldwide issue, which causes physico-chemical changes in its compounds, diminishing its commercial value. Biosurfactants are chemically diverse molecules that can be produced by several microorganisms and can enable microbial access to hydrocarbons. In order to investigate both microbial activities, function-driven screening assays for biosurfactant production and hydrocarbon biodegradation were carried out from a metagenomic fosmid library. It was constructed from the total DNA extracted from aerobic and anaerobic enrichments from a Brazilian biodegraded petroleum sample. A sum of 10 clones were selected in order to evaluate their ability to produce exopolymers (EPS) with emulsifying activity, as well as to characterize the gene sequences, harbored by the fosmid clones, through 454 pyrosequencing. Functional analyses confirmed the ability of some clones to produce surfactant compounds. Regarding hydrocarbon as microbial carbon sources, n-alkane (in mixture or not) and naphthalene were preferentially consumed as substrates. Analysis of sequence data set revealed the presence of genes related to xenobiotics biodegradation and carbohydrate metabolism. These data were corroborated by the results of hydrocarbon biodegradation and biosurfactant production detected in the evaluated clones.

  4. Sequence stratigraphic framework of the Cretaceous Gallup and Tocito sandstones, San Juan basin, New Mexico

    SciTech Connect

    Valasek, D.W. )

    1991-03-01

    The Gallup (Turonian) and Tocito (Coniacian) sandstones are hydrocarbon reservoirs in the San Juan basin, northwestern New Mexico. The Gallup is a regressive shoreface system capped by Dilco Member coastal plain deposits. The Tocito is a transgressive system of valley-fill, estuary, and shelf deposits. All of the units were deposited in a ramp setting. The Gallup is comprised of seaward-stepping (10-20 km) genetic units. Each genetic unit is also comprised of smaller scale (1.5-3 km) parasequences. Both scales are separated by flooding surfaces. Each genetic unit has an independent fluvial feeder system. The most well-developed, widespread, and amalgamated fluvial system correlates to the downward shift of facies basinward at the top of the shoreface. The base of the amalgamated fluvial, downward shifted facies and the valley fills is interpreted to be a sequence boundary. The Tocito fills the incised valleys, lies on the shoreface deposits, and is capped by the maximum flooding surface. Near the shoreface pinch out, the transgressive surface is amalgamated to the sequence boundary surface. These estuary/shelf deposits are the primary hydrocarbon reservoir. Landward, the transgressive surface lies on coastal plain deposits and stratigraphically climbs. The transgression was interrupted by a progradational event consisting of ebb and flood tidal delta deposits of the Borrego Pass Member. These genetic units form a landward-stepping geometry. Availability of outcrop exposures, well logs, and seismic data makes the Gallup/Tocito sequence an excellent example of the development of new exploration scenarios in well-exploited hydrocarbon reservoirs using sequence stratigraphy.

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

    NASA Astrophysics Data System (ADS)

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

    2016-12-01

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

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

    USGS Publications Warehouse

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

    2014-01-01

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

  7. Human Health and Ecological Risk Assessment of 16 Polycyclic Aromatic Hydrocarbons in Drinking Source Water from a Large Mixed-Use Reservoir

    PubMed Central

    Sun, Caiyun; Zhang, Jiquan; Ma, Qiyun; Chen, Yanan

    2015-01-01

    Reservoirs play an important role in living water supply and irrigation of farmlands, thus the water quality is closely related to public health. However, studies regarding human health and ecological risk assessment of polycyclic aromatic hydrocarbons (PAHs) in the waters of reservoirs are very few. In this study, Shitou Koumen Reservoir which supplies drinking water to 8 million people was investigated. Sixteen priority PAHs were analyzed in a total of 12 water samples. In terms of the individual PAHs, the average concentration of Fla, which was 5.66 × 10−1 μg/L, was the highest, while dibenz(a,h)anthracene which was undetected in any of the water samples was the lowest. Among three PAH compositional patterns, the concentration of low-molecular-weight and 4-ring PAHs was dominant, accounting for 94%, and the concentration of the total of 16 PAHs was elevated in constructed-wetland and fish-farming areas. According to the calculated risk quotients, little or no adverse effects were posed by individual and complex PAHs in the water on the aquatic ecosystem. In addition, the results of hazard quotients for non-carcinogenic risk also showed little or no negative impacts on the health of local residents. However, it could be concluded from the carcinogenic risk results that chrysene and complex PAHs in water might pose a potential carcinogenic risk to local residents. Moreover, the possible sources of PAHs were identified as oil spills and vehicular emissions, as well as the burning of biomass and coal. PMID:26529001

  8. Human Health and Ecological Risk Assessment of 16 Polycyclic Aromatic Hydrocarbons in Drinking Source Water from a Large Mixed-Use Reservoir.

    PubMed

    Sun, Caiyun; Zhang, Jiquan; Ma, Qiyun; Chen, Yanan

    2015-10-30

    Reservoirs play an important role in living water supply and irrigation of farmlands, thus the water quality is closely related to public health. However, studies regarding human health and ecological risk assessment of polycyclic aromatic hydrocarbons (PAHs) in the waters of reservoirs are very few. In this study, Shitou Koumen Reservoir which supplies drinking water to 8 million people was investigated. Sixteen priority PAHs were analyzed in a total of 12 water samples. In terms of the individual PAHs, the average concentration of Fla, which was 5.66 × 10(-1) μg/L, was the highest, while dibenz(a,h)anthracene which was undetected in any of the water samples was the lowest. Among three PAH compositional patterns, the concentration of low-molecular-weight and 4-ring PAHs was dominant, accounting for 94%, and the concentration of the total of 16 PAHs was elevated in constructed-wetland and fish-farming areas. According to the calculated risk quotients, little or no adverse effects were posed by individual and complex PAHs in the water on the aquatic ecosystem. In addition, the results of hazard quotients for non-carcinogenic risk also showed little or no negative impacts on the health of local residents. However, it could be concluded from the carcinogenic risk results that chrysene and complex PAHs in water might pose a potential carcinogenic risk to local residents. Moreover, the possible sources of PAHs were identified as oil spills and vehicular emissions, as well as the burning of biomass and coal.

  9. Libyan Paleozoic: A review of the factors limiting hydrocarbon potential

    SciTech Connect

    Kanes, W.H.; Mairn, A.E.M.; Aburawi, R.M.

    1988-08-01

    Of the three main Paleozoic basins - Ghadames, Murquz, and Kufra - only the Ghadames and its continuation into Algeria, the Illizi (or Fort Polignac) basin, has yielded hydrocarbons in significant quantity. The Paleozoic on the Cyrenaica platform and basement of the Sirte basin has a potential not fully considered. The paleogeography of the Paleozoic system is reviewed to illustrate the extent to which inherited and reactivated basement-controlled structures have influenced later Paleozoic sedimentation and hence the distribution of source rocks, reservoirs, and seals. In all instances, the source rocks are restricted to shales of the Tanezufft Formation or occur in the Upper Devonian Aouinet Oeunine Formation. Multiple fine-grained sequences serve as seals in all the fields. The reservoirs range from the well-cemented but highly fractured Cambrian-Ordovician Gargaf sandstones to the Acacus-Tadrart clastics to the fine-grained Lower Carboniferous Tahara Sandstone. The principal plays are associated with minor structures, and stratigraphic trapping mechanisms play a minor role. The average field size (excluding the Sirte basin) is approximately 80 million bbl of recoverable oil. Paleozoic structural plays in the Sirte basin and the Cyrenaica platform include reactivated infra-Cambrian faults. The lower Paleozoic accumulations of the Murzuq basin are tied to large structures. With the exception of local areas in the Ghadames basin, the Paleozoic succession remains a stratigraphic frontier province - still incompletely explored but with several interesting possibilities for large amounts of stratigraphically trapped hydrocarbons.

  10. Illite and hydrocarbon exploration

    PubMed Central

    Pevear, David R.

    1999-01-01

    Illite is a general term for the dioctahedral mica-like clay mineral common in sedimentary rocks, especially shales. Illite is of interest to the petroleum industry because it can provide a K-Ar isotope date that constrains the timing of basin heating events. It is critical to establish that hydrocarbon formation and migration occurred after the formation of the trap (anticline, etc.) that is to hold the oil. Illite also may precipitate in the pores of sandstone reservoirs, impeding fluid flow. Illite in shales is a mixture of detrital mica and its weathering products with diagenetic illite formed by reaction with pore fluids during burial. K-Ar ages are apparent ages of mixtures of detrital and diagenetic end members, and what we need are the ages of the end members themselves. This paper describes a methodology, based on mineralogy and crystallography, for interpreting the K-Ar ages from illites in sedimentary rocks and for estimating the ages of the end members. PMID:10097055

  11. Tectonic significance of lithicwacke-polymictic conglomerate petrofacies association within Upper Cretaceous torchlight sandstone, Big Horn basin, Wyoming

    SciTech Connect

    Khandaker, N.I.; Vondra, C.F.

    1987-05-01

    The Torchlight Sandstone belonging to the Upper Cretaceous Frontier Formation in the Big Horn basin, Wyoming, shows a distinctive lithicwacke-polymictic conglomerate is composed of granule-cobble-sized clasts of quartzite, chert, andesite, and argillite, and phyllite. The survival of phyllite, argillite, and neovolcanic andesite clasts indicate that the detritus underwent very little subaerial transport before it was deposited along the proximal margin of the foreland basin. A petrologically heterogeneous upland source of high to moderate relief is indicated by the clast size and composition. Hydrodynamic structures, in conjunction with textural attributes, and compositional data indicate that detritus moved southeast from its source terrane and was deposited by a high-energy distributary complex. The lithicwacke petrofacies is dominated by higher chert and quartz content with a subordinate amount of labile components including paleovolcanic clasts and fine-grained matrix. The development of phyllosilicate matrix around quartz and chert grains preserved the primary porosity and permeability of the sandstone. Absence of any noticeable quartz overgrowth apparently contributed to the preservation of good reservoir quality in this petrofacies. Considering its (Torchlight Sandstone) close proximity to the thrust belt and to the locus of andesite volcanism in the northwest and west, it is suggested that the extrabasinal detritus within the foreland basin can provide significant clues as to the timing of the thrust events and volcanicity in the adjacent region. New perspectives for hydrocarbon exploration and regional correlation may be gained by employing this petrofacies association.

  12. Application of sequence stratigraphy to reservoir and hydrocarbon source rock prediction in the Cretaceous carbonate platforms of Maracaibo Basin, Venezuela

    SciTech Connect

    Murat, B.; Azpiritxaga, I. )

    1993-02-01

    Prediction of reservoir and source rocks is enhanced by an understanding of the sequential organization of the sedimentary units. In the Maracaibo Basin, the carbonate Cogollo Group and the basal part of the Shaly La Luna Formation (Upper Barremian to Lower Cenomanian) have been subdivided into a hierarchy of cycles ranging from parasequences (4th and 5th order) up to Regressive-Transgressive cycles (2nd order). Sedimentation during this period on a passive platform under the influence of eustatic sea level fluctuations, led to a succession of about twenty 3rd order sequences (depending on their location on the platform) composed of Transgressive Systems Tracts (TST) and Highstand Systems Tracts (HST). Their boundaries and maximum flooding surfaces can be traced on wireline logs and on cored material. These sequences belong to three Regressive-Transgressive 2nd order cycles showing a 3-stage evolution of infill, aggradation and backstepping. Sedimentary facies vary laterally within systems tracts and vertically from one cycle to another. Most basal TST units display high energy sediments prone to porosity development, whereas the basal HST units are generally characterized by muddier sediments. The best reservoirs are at the top of HST units, with development of both early dolomite and grainy packstones with moderate reservoir quality. Maximum oil productivity occurs where matrix porosity is associated with fractures, which are always best developed within the aggrading stage. Finally, source-rock intervals coincide with the maximum flooding surfaces which limit second order cycles.

  13. Experimental research on seismoelectric effects in sandstone

    NASA Astrophysics Data System (ADS)

    Peng, Rong; Wei, Jian-Xing; Di, Bang-Rang; Ding, Pin-Bo; Liu, Zi-Chun

    2016-09-01

    The seismoelectric effects induced from the coupling of the seismic wave field and the electromagnetic field depend on the physical properties of the reservoir rocks. We built an experimental apparatus to measure the seismoelectric effects in saturated sandstone samples. We recorded the seismoelectric signals induced by P-waves and studied the attenuation of the seismoelectric signals induced at the sandstone interface. The analysis of the seismoelectric effects suggests that the minimization of the potential difference between the reference potential and the baseline potential of the seismoelectric disturbance area is critical to the accuracy of the seismoelectric measurements and greatly improves the detectability of the seismoelectric signals. The experimental results confirmed that the seismoelectric coupling of the seismic wave field and the electromagnetic field is induced when seismic wave propagating in a fluid-saturated porous medium. The amplitudes of the seismoelectric signals decrease linearly with increasing distance between the source and the interface, and decay exponentially with increasing distance between the receiver and the interface. The seismoelectric response of sandstone samples with different permeabilities suggests that the seismoelectric response is directly related to permeability, which should help obtaining the permeability of reservoirs in the future.

  14. Source, reservoir promise seen in Marathon-Ouachita overthrust

    SciTech Connect

    Trabelsi, A.S. )

    1994-09-26

    The Permian Basin of West Texas is a prolific oil and gas province that has been extensively explored, but the Marathon-Ouachita overthrust area of Pecos County, Tex., is not fully explored. Rocks of the Ouachita fold belt have been generally regarded by most petroleum geologists as metamorphosed and unsuitable for oil and gas accumulation. Indications of the presence of hydrocarbons in Ouachita rocks have been reported from the earliest days of Permian Basin exploration. Goldstein and Flawn indicated that in the subsurface Ouachita fold belt in Texas asphaltic materials are fairly common in sandstones and cherts. The Ouachita overthrust area in Texas has all the required elements for hydro-carbon accumulation and should be fully explored. This article gives a brief assessment of these elements (traps, source rocks, and reservoirs) in this area.

  15. Upper Jurassic Norphlet formation: new frontier for hydrocarbon prospecting in the central and eastern Gulf of Mexico regions

    SciTech Connect

    Mancini, E.A.; Mink, R.M.; Bearden, B.L.

    1984-04-01

    Since the discovery of oil in 1967 from the Smackover Formation at Toxey field, Choctaw County, Alabama, and of condensate in 1968 from the Norphlet Formation at Flomaton field, Escambia County, Alabama, the Upper Jurassic has become the primary exploration target in southwestern Alabama. Norphlet petroleum traps in the region are principally combination traps involving favorable stratigraphy and salt anticlines (Copeland field), extensional fault traps associated with salt movement (Flomaton field), and faulted salt anticlines (Hatter's Pond and Lower Mobile Bay-Mary Ann fields). Reservoir rocks include marine, dune, and fluvial sandstone lithofacies. Sandstone porosity involves both primary intergranular and secondary dissolution and fracture. Smackover algal carbonate mudstone is probably the source for much of the Norphlet hydrocarbon, but downdip Norphlet marine shales may also be source rocks. The central and eastern Gulf of Mexico regions should continue to be excellent areas to explore for hydrocarbons in the years ahead. Successful Norphlet petroleum prospecting in the area has involved the identification of favorable sandstone lithofacies and structural hydrocarbon traps by using geologic and geophysical methods. Future Norphlet discoveries will require the delineation of stratigraphic and structural/stratigraphic combination hydrocarbon traps using seismic-stratigraphic techniques.

  16. Upper Jurassic Norphlet formation: new frontier for hydrocarbon prospecting in the central and eastern Gulf of Mexico regions

    SciTech Connect

    Mancini, E.A.; Mink, R.M.; Bearden, B.L.

    1984-04-01

    Since the discovery of oil in 1967 from the Smackover Formation at Toxey field, Choctaw County, Alabama, and of condensate in 1968 from the Norphlet Formation at Flomaton field, Escambia County, Alabama, the Upper Jurassic has become the primary exploration target in southwestern Alabama. Norphlet petroleum traps in the region are principally combination traps involving favorable stratigraphy and salt anticlines (Copeland field), exensional fault traps associated with salt movement (Flomaton field), and faulted salt anticlines (Hatter's Pond and Lower Mobile Bay-Mary Ann fields). Reservoir rocks include marine, dune, and fluvial sandstone lithofacies. Sandstone porosity involves both primary intergranular and secondary dissolution and fracture. Smackover algal carbonate mudstone is probably the source for much of the Norphlet hydrocarbon, but downdip Norphlet marine shales may also be source rocks. The central and eastern Gulf of Mexico regions should continue to be excellent areas to explore for hydrocarbons in the years ahead. Successful Norphlet petroleum prospecting in the area has involved the identification of favorable sandstone lithofacies and structural hydrocarbon traps by using geologic and geophysical methods. Future Norphlet discoveries will require the delineation of stratigraphic and structural/stratigraphic combination hydrocarbon traps using seismic-stratigraphic techniques.

  17. Mechanical stratigraphy of deep-water sandstones: insights from a multisciplinary field and laboratory study

    NASA Astrophysics Data System (ADS)

    Agosta, Fabrizio; di Celma, Claudio; Tondi, Emanuele; Corradetti, Amerigo; Cantalamessa, Gino

    2010-05-01

    Turbidite sandstones found in deep-water fold-and-thrust belts are increasingly exploited as hydrocarbon reservoirs. Within these rocks, the fluid flow is profoundly affected by the complex interaction between primary sedimentological and stratigraphic attributes (i.e, facies, layering, reservoir quality, stacking patterns, bed connectivity and lateral extent) and fracture characteristics (i.e., length, spacing, distribution, orientation, connectivity). Unfortunately, most of these features are at, or below, the resolution of conventional seismic datasets and, for this reason, their identification and localization represent one of the fundamental challenges facing exploration, appraisal and production of the sandstone reservoirs. In this respect, whereas considerable effort has been afforded to a characterization of the sedimentological and stratigraphic aspects of sandstones, detailed analysis of fractures in this type of successions has received significantly less attention. In this work, we combine field and laboratory analyses to assess the possible mechanical control exerted by the rock properties (grain size, intergranualr porosity, and Young modulus), as well as the influence of bed thickness, on joint density in turbidite sandstones. Joints are mode-I fractures occurring parallel to the greatest principle stress axis, which solve opening displacement and do not show evidence of shearing and enhance the values of total porosity forming preferential hydraulic conduits for fluid flow. Within layered rocks, commonly, joints form perpendicular to bedding due to overburden or exhumation. The empirical relation between joint spacing and bed thickness, documented in the field by many authors, has been mechanically related to the stress perturbation taking place around joints during their formation. Furthermore, close correlations between joint density and rock properties have been already established. In this present contribution, we focus on the bed

  18. Source of oils in Gulf Coast Cenozoic reservoirs

    SciTech Connect

    Curtis, D.M. )

    1989-09-01

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

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

    NASA Astrophysics Data System (ADS)

    Yassin, Mohamed; Abdullatif, Osman; Hariri, Mustafa

    2017-04-01

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

  20. Geological model of shallow marine clastic reservoirs in a Wrench-Faulted Province

    SciTech Connect

    Johnson, H.D.; Chapman, J.W.; Ranggon, J.

    1988-01-01

    The St. Joseph field is situated along a major wrench-fault zone in offshore Sabah (The Bunbury-St. Joseph-Bambazon ''ridge'') that divides the field into several structural areas. The most prospective of these is the structurally simple northwest flank (about 6 km long and 1 km wide) that dips uniformly to the northwest (about 15/sup 0/-20/sup 0/) in a basinward direction away from the crestal wrench-fault zone. The main hydrocarbon-bearing interval comprises a 1,350-ft long oil column, which is contained within a highly heterogeneous sequence of late Miocene shallow marine sandstone and shales. The main geologic uncertainties of the northwest flank concern lateral variations in sand development, shale-layer continuity, and reservoir quality. They have a major impact on reservoir recovery mechanisms, pressure-maintenance schemes, and on field development strategy. Therefore, a reservoir geologic model was developed that incorporates sedimentologic studies, well-log facies analysis, reservoir mapping, and detailed structural interpretation (using a full reservoir core and three-dimensional seismic data). These studies demonstrate that depositional processes and tectonic setting had a major impact in controlling the thickness, quality and distribution of the sandstone reservoirs. Features that had a particularly significant impact on hydrocarbon distribution, reservoir modeling and field development are: (1) a storm-dominated shelf-sand depositional system, (2) rapid vertical and lateral switches in sand supply, (3) a tectonically unstable, narrow (about 5-15 km wide) shelf, and (4) shelf-edge slumping (slump scars).

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

    USGS Publications Warehouse

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

    1996-01-01

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

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

    NASA Astrophysics Data System (ADS)

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

    2016-04-01

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

  3. The hydrocarbon potential of the Ene Basin (Peru)

    SciTech Connect

    Fabre, A.D.; Alvarez, D.U.

    1993-02-01

    The Ene basin is located between 10[degrees]30' and 12[degrees] latitude south in the foothills of the Eastern Cordillera. Geochemical analysis indicate the presence of mature organic-rich source rocks in the Upper Paleozoic. In particular the Ene formation includes mature (Ro = 0.7 to 0.9%) oil-prone shale with mixed type I/II kerogen. Geohistory models show that the Ene formation entered into the oil window some 5 to 3 m.y. ago in the deep part of the basin and could generate hydrocarbons until the present time. Good reservoir sandstones (Oriente gr., Vivian Fm.) were deposited during the Cretaceous sandstones. The Ene basin extends in a northwest-southeast direction between the Eastern Cordillera to the west and the Shiro-Vilcabamba uplift to the east. The Late Miocene-Pliocene Quechua phase III deformed the sedimentary series producing east verging imbricated thrust sheets and large anticlines which could trap the hydrocarbons generated by the Upper Paleozoic source rocks. Several anticlines are still sealed by the Tertiary cover and represent attractive prospects for hydrocarbon exploration. With a prospective area close to 8000 km[sup 2] the unexplored Ene basin is awaiting imaginative geologists and geophysicists to demonstrate its potential.

  4. Structure, stratigraphy, and depositional environment of the heterostegina limestone and overlying sandstones in the Lake Pontchartrain area of southeast Louisiana

    SciTech Connect

    Street, S.B. III; Lock, B.E.

    1994-12-31

    The Heterostegina zone of the Oligocene Anahuac Formation in southwestern Louisiana occurs in the subsurface as an extensive shelf reef complex. The Heterostegina limestone is overlain by strata associated with the Oligocene Discorbis and lower Miocene Robulus (43) biostratigraphic zones. Examination of electric logs and drill cuttings from wells in the Lake Pontchartrain area of southeastern Louisiana reveals the importance of the Heterostegina reef as a paleoenvironmental punctuation marking a significant shift in regional depositional patterns that occurred between the generally transgressive Oligocene seas and the generally regressive Miocene seas. Fauna identified in thin section from the Heterostegina reef interval suggest deposition in a warm, shallow-marine environment relatively free of significant clastic influx. An eastward migration of late Oligocene-early Miocene stream systems introduced an influx of clastic sediments onto the ancient shelf of the Lake Pontchartrain area, which influenced the termination of favorable conditions for Heterostegina reef growth. Lithofacies I is characterized by thick, shore-parallel sandstone deposits and is interpreted to have been deposited in association with a barrier-beach/tidal-inlet channel environment. Lithofacies II is characterized by shale-prone sandstone intervals, which are immediately overlain by calcareous mudstones and limestones deposited in the offshore inner-middle neritic environment. Five oil and gas fields in the study area have produced hydrocarbons from the interval of interest. The occurrence of hydrocarbons at these locations with respect to mechanisms of entrapment and areal extent of the reservoirs was characterized through detailed subsurface mapping.

  5. Extensional tectonic influence on lower and upper cretaceous stratigraphy and reservoirs, southern Powder River basin, Wyoming

    SciTech Connect

    Mitchell, G.C.; Rogers, M.H.

    1993-04-01

    The southern Powder River basin has been influenced significantly by an extensional system affecting Lower Cretaceous, Upper Cretaceous and Tertiary units. The system is composed of small throw, nearly vertical normal faults which are identified in the Cretaceous marine shales and that we believe are basement derived. Resultant fractures were present at erosional/depositional surfaces, both marine and nonmarine, that, in part, controlled erosion and subsequent deposition of Lower and Upper Cretaceous rocks. The normal faults also affected coal deposition in the Tertiary, now exposed at the surface. The erosion and resultant deposition formed extensive stratigraphic traps in Cretaceous units in both conventional and unconventional reservoirs. These reservoirs are interbedded with mature source rocks that have generated and expelled large amounts of hydrocarbons. Resulting overpressuring in the Fall River through the Niobrara formations has kept fractures open and has preserved primary porosity in the reservoirs. The normal faults offset thin sandstone reservoirs forming permeability barriers. Associated fractures may have provided vertical pathways for organic acids that assisted development of secondary porosity in Upper Cretaceous sandstones. These normal...faults and fractures provide significant potential for the use of horizontal drilling techniques to evaluate fractured, overpressured conventional and unconventional reservoirs.

  6. Hydrocarbon Accumulation and Distribution Characteristics of the Silurian in the Tazhong Uplift of Tarim Basin

    NASA Astrophysics Data System (ADS)

    LÜ, Xiuxiang; BAI, Zhongkai; ZHAO, Fengyun

    Hydrocarbon accumulation of the Silurian in the Tazhong uplift of Tarim basin is characterized by "two sources and three stages". "Two sources" means that the hydrocarbons are derived from two source rocks of the Cambrian and Middle-Upper Ordovician. "Three stages" means that asphalt and movable oil undergoes three hydrocarbon accumulation stages, i.e., Late Caledonian, Late Hercynian, and Yanshanian-Himalayan. The formation of asphalt resulted from the destruction of the hydrocarbons accumulated and migrated in the early stages. The present movable oil, mostly derived from Middle-Upper Ordovician source rock, resulted from the hydrocarbons accumulated in the late stage. There are three types of reservoirs, i.e., anticline structural, stratigraphic lithological, and lava shield reservoirs in the Tazhong uplift. Hydrocarbon accumulation of the Silurian in the Tazhong uplift is controlled by the three factors. (1) The background of uplift structure. Around the ancient uplift, the compounding of many types makes up the composite hydrocarbon accumulation areas. (2) Effective cover. The show of oil gas including asphalt, heavy crude oil, and normal oil is quite active in the Silurian. Asphalt and heavy crude oil are distributed under the red mudstone member and movable oil is distributed under the gray mudstone member. (3) High quality reservoir bed. Sandstone is distributed widely in the Tazhong area. Reservoir pore space can be divided into three types: a) secondary origin-primary origin pore space; b) primary origin-secondary origin pore space, and c) micropore space. Porosity is 3.3-17.4%, and permeability is (0.1-667.97) × 10 -3 μm 2.

  7. Resonant Ultrasound Spectroscopy studies of Berea sandstone at high temperature

    SciTech Connect

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

    2016-09-04

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

  8. Resonant Ultrasound Spectroscopy studies of Berea sandstone at high temperature

    DOE PAGES

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

    2016-09-04

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

  9. Sand and sandstone

    SciTech Connect

    Pettijohn, F.J.; Potter, P.E.; Siever, R.

    1987-01-01

    Here is a new, second edition of a classical textbook in sedimentology, petrology, and petrography of sand and sandstones. It has been extensively revised and updated, including: new techniques and their utility; new literature; new illustrations; new, explicitly stated problems for the student; and a wider scope.

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

    SciTech Connect

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

    1993-09-01

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

  11. Geology of the reservoirs from interval I of the Oficina formation, Greater Oficina area, eastern Venezuela Basin

    SciTech Connect

    Rivero, C.A.; Scherer, W.

    1996-08-01

    In order to determine the geologic features of the reservoirs and their areal statistical distribution and geometry, a study was made of a selected interval where the sands present less coalescence and the reservoirs are clearly defined. The study area comprises 1900 km{sup 2} of the Greater Oficina area; core samples, logs and reservoir maps were used. It was found that interval I consists of interbedded sandstones, shales, some siltstone, and occasionally lignites. Based upon lithologic mesoscopic features, eight (8) characteristic lithofacies could be defined. Rocks classified as sub-litharenites, sub-arkoses, arkoses lithic sandstones and graywackes could be inferred as belonging to a fluvio-deltaic system sourced on the Pre-Cambrian Guayana shield. The diagenetic level reached by the sequence corresponds to the intermediate stage, where significant processes of cementation by oxides, carbonates and silica are of equal intensity and magnitude to the lixiviation of feldspars and other detritic particles, giving these rooks good potential reservoir qualities. Descriptive statistical evaluation was performed on 140 reservoirs representing all lithofacies populations in this interval. Based on this analysis reservoirs were statistically grouped in classes which are a function of their geometry, spatial location and type of hydrocarbon content.

  12. Jurassic sequence stratigraphy of the eastern Gulf Coastal Plain: Applications to hydrocarbon exploration

    SciTech Connect

    Tew, B.H.; Mancini, E.A.; Mink, R.M. )

    1991-03-01

    Based on regional stratigraphic and sedimentologic data, three unconformity-bounded depositional sequences associated with cycles of relative sea-level change and coastal onlap are recognized for Jurassic strata in the eastern Gulf Coastal Plain area. These sequences are designated, in ascending order, the LZAGC (Lower Zuni A Gulf Coast)-3.1, the LZAGC-4.1, and the LZAGC-4.2 sequences and include Callovian through Kimmeridgian Stage strata. An understanding of the relationship of Jurassic reservoirs to sequence stratigraphy can serve as an aid to hydrocarbon exploration in the eastern gulf area. The most extensive and productive Jurassic hydrocarbon reservoirs in the study area occur within the progradational, regressive highstand deposits of the LZAGC-3.1 and LZAGC-4.1 depositional sequences. For example, the majority of Norphlet sandstone reservoirs in the onshore and offshore Alabama area are interpreted to have accumulated in eolian dune, interdune, and wadi (fluvial) depositional environments, which occurred in association with the highstand regressive system of the LZAGC-3.1 sequence. The most important Smackover reservoirs generally consist of partially to completely dolomitized ooid and peloid packstones and grainstones in the upper portion of the unit. These reservoirs occur in subtidal to supratidal, shoaling-upward carbonate mudstone to grainstone cycles in the highstand regressive system of the LZAGC-4.1 sequence. In addition, minor reservoirs that are discontinuous and not well developed are associated with the shelf margin and transgressive systems of the LZAGC-4.1.

  13. Tectonic evolution and hydrocarbon potential of the southern Moesian platform and Balkan-Forebalken regions of northern Bulgaria

    SciTech Connect

    Emery, M. ); Georgiev, G. )

    1993-09-01

    The major tectonic elements of northern Bulgaria are the east-west-trending Balkan-Forebalkan fold belt and the Moesian platform. Moderate hydrocarbon exploration potential exists in trapping geometries generated during the tectonic evolution of the region coupled with reservoir/seal pairs and source rocks within Mesozoic strata. The tectonic evolution of the region includes Early Triassic to Early Jurassic intracratonic rifting followed by multiphase compression that contracted the rift basin and produced a north vergent fold and thrust belt along the southern margin of the stable Moesian platform. Compression began during the Early Cretaceous, continued during the Paleocene, and concluded during the middle Eocene. Trap types generated during the tectonic evolution include normal fault-bounded rotated blocks in the autochthonous section and elongate, asymmetric anticlines in the allochthonous section. Triassic to Upper Jurassic Marine facies were deposited in an east-west-trending rift. Sediments deposited in a shallow foredeep, which evolved during Lower cretaceous compression, overlay the rift sequence. The Early Mesozoic rift sequence provides the depositional settings for Middle Triassic and lower Middle Jurassic source rock shales and sandstone/carbonate reservoirs ranging from Middle Triassic to Lower Cretaceous. Carbonate reservoirs generally are porous dolomites with intercrystalline, moldic, and vugular pore types interbedded with nonporous limestones. Clastic reservoirs are quartz-rich sandstones with pore types that are reduced intergranular, dissolution, and microporosity. These heterogeneous reservoir targets exhibit poor to good reservoir characteristics and are overlain with sealing lithologies of variable thicknesses.

  14. Stratigraphy, depositional history and environments of deposition of Cretaceous through Tertiary strata in the Lamu Basin, southeast Kenya and implications for reservoirs for hydrocarbon exploration

    NASA Astrophysics Data System (ADS)

    Nyagah, Kivuti

    1995-04-01

    . Determination and description of these lithostratigraphic units, their distribution and palaeohistory have been imperative for predicting reservoirs for hydrocarbon exploration.

  15. Discrimination between induced, triggered, and natural earthquakes close to hydrocarbon reservoirs: A probabilistic approach based on the modeling of depletion-induced stress changes and seismological source parameters

    NASA Astrophysics Data System (ADS)

    Dahm, Torsten; Cesca, Simone; Hainzl, Sebastian; Braun, Thomas; Krüger, Frank

    2015-04-01

    Earthquakes occurring close to hydrocarbon fields under production are often under critical view of being induced or triggered. However, clear and testable rules to discriminate the different events have rarely been developed and tested. The unresolved scientific problem may lead to lengthy public disputes with unpredictable impact on the local acceptance of the exploitation and field operations. We propose a quantitative approach to discriminate induced, triggered, and natural earthquakes, which is based on testable input parameters. Maxima of occurrence probabilities are compared for the cases under question, and a single probability of being triggered or induced is reported. The uncertainties of earthquake location and other input parameters are considered in terms of the integration over probability density functions. The probability that events have been human triggered/induced is derived from the modeling of Coulomb stress changes and a rate and state-dependent seismicity model. In our case a 3-D boundary element method has been adapted for the nuclei of strain approach to estimate the stress changes outside the reservoir, which are related to pore pressure changes in the field formation. The predicted rate of natural earthquakes is either derived from the background seismicity or, in case of rare events, from an estimate of the tectonic stress rate. Instrumentally derived seismological information on the event location, source mechanism, and the size of the rupture plane is of advantage for the method. If the rupture plane has been estimated, the discrimination between induced or only triggered events is theoretically possible if probability functions are convolved with a rupture fault filter. We apply the approach to three recent main shock events: (1) the Mw 4.3 Ekofisk 2001, North Sea, earthquake close to the Ekofisk oil field; (2) the Mw 4.4 Rotenburg 2004, Northern Germany, earthquake in the vicinity of the Söhlingen gas field; and (3) the Mw 6

  16. Magnetic resonance imaging study of complex fluid flow in porous media: flow patterns and quantitative saturation profiling of amphiphilic fracturing fluid displacement in sandstone cores.

    PubMed

    Sheppard, S; Mantle, M D; Sederman, A J; Johns, M L; Gladden, L F

    2003-01-01

    Magnetic resonance imaging is used to follow the removal process of a visco-elastic surfactant (VES) fracturing fluid in Bentheimer sandstone cores at typical reservoir temperatures (T=333 K). Two displacing fluids were investigated, a Gadolinium doped water phase (1M NaCl solution), and a Gadolinium doped hydrocarbon phase (Mineral Spirits). In addition to flow characteristics obtained by conventional core-flooding, i.e., the macroscopically averaged volumetric flow rates and differential pressures, we have also measured the saturation profiles and characteristic displacement patterns during all stages of the removal process. To acquire these data we have used quantitative one-dimensional chemically specific profiling along with fast two-dimensional imaging experiments while flooding Bentheimer sandstone cores in situ in the spectrometer. Our results show that both displacement processes (complex fluid displaced by water or hydrocarbon phase) are dominated by the large viscosity contrasts present. However, distinct differences were found between the displacement characteristics of water and hydrocarbon, which confirmed the sensitivity of the complex fracturing fluid to the displacing fluid.

  17. Parameters controlling hydrocarbon distribution at Tatums Camp Field, Lamar County, Mississippi

    SciTech Connect

    Jackson, P. )

    1990-09-01

    Structural setting, stratigraphy, diagenesis, and hydraulic pathways all have played an important role in the development of reservoir at Tatums Camp field in Lamar County, Mississippi. The field is a domal anticline located on the southern flank of Midway Salt Dome within the confines of the Mississippi Salt basin. Production is from the Booth Sandstone of the Lower Cretaceous Hosston Formation. The Booth Sandstone contains productive mouth bar sands that pinch out across the northeast half of the dome, and nonproductive channel sands on the west. The mouth bars appear to have been deposited in a marginal marine, perhaps, estuarine environment. Porosity is secondary in origin, the result of leaching of framework constituents. Diagenetic studies indicate that hydrocarbons migrated into the sands when they were at or close to their present depth of 15,700 15,800 ft (4,785-4,815 m). Hydraulic head estimates within the upper Hosston Formation decrease from north to south. This pattern suggests that fluid movement is to the south away from Midway Salt Dome. It is probable that these hydraulic pathways were established at the time of hydrocarbon migration. The reservoir at Tatums Camp field appears to be the result of hydrocarbon migration from the north into a stratigraphic pinchout lying across a structurally positive feature.

  18. Hidden oil leg: Case study of lower D1 Miocene sandstone, Dulang field, offshore Peninsular Malaysia

    SciTech Connect

    Solomon, G.J.; Chandramohan, S.; Karra, S.; Sonrexa, K.

    1995-10-01

    The Dulang Field is located offshore east coast of Peninsular Malaysia in water depths of approximately 75 m. The field, discovered in 1981, is about 24 km by 3.5 km. After drilling 14 exploration/appraisal wells by both Carigali and its partner Esso Production Malaysia Inc., the central part of the field was developed as a unitized area in November 1990. Three 32-slot platforms have been installed in the unitized area, and development drilling is ongoing. Production commenced in March 1991 and is currently maintained at approximately 50,000 BOPD. The estimated OIIP (oil-initially-in-place) for the unitized area is in the order of 700 million barrels. There are 19 reservoir sands in Groups D and E which are of Middle-Late Miocene age. During the exploration/appraisal phase, oil and gas were encountered in the Group E and only gas in the Lower D1 reservoirs. Wireline formation pressure test data taken in the Lower D1 reservoir in these wells plotted along a common trend with a gradient of 0.06 psi/ft. The lowermost gas pressure point was only 6 m above the normal hydrostatic gradient. It was therefore concluded that an oil column, even if present, would be thin. At the time, it was understandable that the gas pressures plotted along the same trend because the hydrocarbon column of the Lower D1 reservoir was large and extended beyond the limits of the major faults, suggesting a common pool. However, during the development drilling phase, it was discovered that the Lower D1 sandstone was a major oil reservoir, with estimated oil-in-place of about 100 million barrels. Oil columns of 75 m and 40 m have been proven up in the northern and southern flanks of the field, respectively, in the Lower D1. In addition, development plans were flexible enough to be able to effectively exploit the discovery.

  19. Application of ultrasonic as a novel technology for removal of inorganic scales (KCl) in hydrocarbon reservoirs: An experimental approach.

    PubMed

    Taheri-Shakib, Jaber; Naderi, Hassan; Salimidelshad, Yaser; Kazemzadeh, Ezzatollah; Shekarifard, Ali

    2018-01-01

    Inorganic scales are one of the most important causes of formation damage, which causes pressure drops near wellbores; these in turn impair permeability and severely reduce production in oil and gas reservoirs. This paper examines the effectiveness of ultrasonic waves in removing potassium chloride (KCl) scales. Twenty core samples with different permeabilities were exposed to KCl precipitation. After measuring the permeabilities of the saturated core samples, the samples were first subjected to water injection, and then to water injection with ultrasonic wave radiation. At each stage, sample permeabilities were measured and recorded. The results showed that water injection with two pore volumes did not significantly improve permeability, especially in low-permeability core samples. Ultrasonic wave radiation with water could efficiently improve permeability; this result is more obvious for samples with lower permeabilities. SEM images taken from thin sections of the core samples under water injection and water with ultrasonic waves showed that ultrasonic waves distorted the crystal lattice of the KCl scales, causing cracking and delamination. Creation of wormholes in KCl deposits within fractures also resulted from the application of ultrasonic waves. Analysis of chlorine in the output water from core samples in the core-flooding process showed that ultrasonic waves increased the solubility of scales in water, improving the recovery of permeability in the samples. Results of this study show that using ultrasonic waves can be considered a novel and practical method in the removal of inorganic scales in the near-wellbore region of oil and gas reservoirs. Copyright © 2017 Elsevier B.V. All rights reserved.

  20. Depositional environments of Upper Triassic sandstones, El Borma oil field, southwestern Tunisia

    SciTech Connect

    Bentahar, H.; Ethridge, F.G. )

    1991-03-01

    El Borma oil field in southwestern Tunisia is located on the Algerian border and produces from five Upper Triassic sandstone reservoirs at depths ranging from 2,300 to 2,400 m. The 250 km{sup 2} field has recoverable reserves of 770 mm bbl of equivalent oil. Reservoir sandstones rest unconformably on south-dipping Lower Devonian clastic deposits. Silurian shale represents the major oil source rock and the field is capped by 550 m of shale, carbonate, and evaporite. Hercynian, topography below the reservoir sandstones comprises an 18 km wide, northeast-oriented paleovalley. Each of the four lower reservoir sandstones, bounded by a lower scour surface and a basal lag deposit, is commonly discontinuous and separated by lenticular shale beds. These 5 to 15 m thick sandstones display in channels flowing to the northeast. The overlying 12 m thick transgressive marine dolomitic shale contains carbonized bivalves and is capped by a paleosoil with root structures and siderite cement indicating subaerial exposure. The clay-rich and locally bioturbated uppermost reservoir sandstone was probably deposited in a tidally influenced estuary. Overall, the Upper Triassic reservoirs at El Borma consists of valley-fill estuary deposits that were formed during transgression of the sea from the northeast.

  1. Mapping 3D thin shale and permeability pathway within a reservoir system: Case study from the Sleipner Field

    NASA Astrophysics Data System (ADS)

    Ponfa Bitrus, Roy; Iacopini, David; Bond, Clare

    2016-04-01

    Reservoir architecture plays an integral part of seismic reservoir characterization. The characteristics of a reservoir which includes its external and internal geometry are important as they influence the production and development strategy employed in the oil and gas sector. Reservoir architecture is defined by the interpretation of seismic data, thus identifying the basic structural and stratigraphic geometrical framework of a trapping and flow system for hydrocarbon and fluids. One major issue though is the interpretation of thin shales and identification of permeability pathways within the reservoir system. This paper employs a method using attributes to map thin shales and identify permeability pathways or transmissitives that exist within a reservoir taking into consideration the seismic resolution and available data. Case study is the Utsira Formation in the Sleipner field, Norwegian North sea. The Utsira formation presents a classic case of thin beds within a sandstone formation and transmissitives that exist as chimneys within the formation. A total of 10 intra reservoir horizon units of shales where interpreted using complex trace seismic attributes. These interpreted horizons where further analysed through spectral decomposition to reveal possible facies distribution and unit thickness within the horizon. Reservoir transmissitives identified as vertical curvilinear structures were also analysed using unique seismic attributes in other to delineate their extent and characterise their occurrence These interpreted shales and pathway transmissitives illuminate the geometry of the formation, the reservoir heterogeneities on a finer-scale and, in the long term, constrain the migration prediction of reservoir fluids, hydrocarbons and injected CO2 when matched across a 4D seismic data survey. As such, useful insights into the key elements operating within the reservoir can be provided, giving a good indication of the long and short term reservoir performance.

  2. Geologic characteristics of hydrocarbon-bearing marine, transitional and lacustrine shales in China

    NASA Astrophysics Data System (ADS)

    Jiang, Shu; Xu, Zhengyu; Feng, Youliang; Zhang, Jinchuan; Cai, Dongsheng; Chen, Lei; Wu, Yue; Zhou, Dongsheng; Bao, Shujing; Long, Shengxiang

    2016-01-01

    Organic-rich shales spanning in age from Pre-Cambrian to Quaternary were widely deposited in China. This paper elaborates the geology and unique characteristics of emerging and potential hydrocarbon-bearing shales in China. The Pre-Cambrian Sinian Doushantuo to Silurian black marine shales in the intra-shelf low to slope environments were accumulated in South China and Tarim Platform in Northwest China. These marine shales with maturity (Ro) of 1.3-5% are in dry gas window. During Carboniferous to Permian, the shales associated with coal and sandstones were mainly deposited in coastal swamp transitional setting in north China, NE China, NW China and Yangtze platform in South China. These transitional shales are generally clay rich and are potential gas-bearing reservoirs. Since Middle Permian, the lacustrine shales with total carbon content (TOC) up to 30% and Ro mainly in oil window are widely distributed in all the producing basins in China. The lacustrine shales usually have more clay mineral content than marine shales and are characterized by rapid facies change and are interbedded with carbonates and sandstone. The high quality shale reservoir with high TOC, hydrocarbon content and brittle minerals content is usually located at transgressive systems tract (TST) to early highstand systems tract (EHST) interval deposited in anoxic depositional setting. Recent commercial shale gas production from the Silurian Longmaxi marine shale in the southeastern Sichuan Basin, preliminary tight oil production associated with lacustrine hydrocarbon-bearing shale intervals and hydrocarbon shows from many other shales have proven the hydrocarbon-bearing shales in China are emerging and potential shale gas and tight (shale) oil plays. Tectonic movements could have breached the early hydrocarbon accumulation in shales and tectonically stable areas are suggested to be favorable prospects for China shale plays exploration and production.

  3. Diagenetic control of reservoir quality of Araba and Naqua diagenetic quartzarenites (Cambrian), Gebel Araba-Qabeliat, Southwest Sinai, Egypt

    SciTech Connect

    Abdel-Wahab, A. ); Mcbride, E.F. )

    1991-03-01

    Sandstones of the marine Lower Cambrian Araba Formation and the overlying fluvial Upper Cambrian( ) Naqus Formation in Gebel Araba-Qabeliat, southwest Sinai (the eastern side of the Gulf of Suez) were studied to evaluate the major factors controlling potential hydrocarbon reservoir quality. The formations have a composite thickness of 873 m and overlie Precambrian granite and metamorphic rocks and underlie Cretaceous marine strata. The framework composition of both sandstones is almost entirely quartz with trace amounts of muscovite, K-feldspar, and heavy minerals. Up to 21.5% oversize pores, some filled with younger cements, attest to extensive dissolution loss of detrital grains, chiefly feldspar. Because the final mineralogical maturation of these quartzarenites was through diagenesis, they are diagenetic quartzarenites. Following deposition, the introduction of thin coatings of infiltered clay was followed by the precipitation of 6.3% unhomogeneously distributed quartz cement. Some outcrop samples contain pore-occluding gypsum cement or mixtures of gypsum and halite cement. Sr{sup 87}/Sr{sup 86} ratios of seven samples of gypsum cement have values (0.7077 to 0.7083) that are equal to Miocene and slightly younger seawater. These Cambrian sandstones have excellent reservoir potential (mean thin section porosity = 25.7%) because they contained few ductile grains to enhance compaction, and they developed significant amounts of secondary pores by both dissolution of calcite cement and unstable detrital grains. Kaolinite and dickite are potential problems for hydrocarbon production in some beds.

  4. The Petrology and Diagenetic History of the Phacoides Sandstone, Temblor Formation at the McKittrick Oil Field, California

    NASA Astrophysics Data System (ADS)

    Kaess, A. B.; Horton, R. A.

    2015-12-01

    The McKittrick oil field is located near the western edge of the San Joaquin Basin, California. The oil field is currently in production with 480 wells producing from the Tulare, San Joaquin, Reef Ridge, Monterey, Temblor, Tumey, and Kreyenhagen formations. Within the Temblor Formation production is mainly from the Miocene Carneros and the Phacoides sandstones. Eighty-two samples from the Phacoides sandstone (2403 - 3045 m below surface) were obtained from the California Well Sample Repository to characterize and understand the diagenetic history and its influence on its reservoir properties. Petrographic thin sections were analyzed by quantitative optical petrography, energy dispersive X-ray spectrometry, and imaging with back-scatter electron and cathodoluminescence. The Phacoides sandstone consists of fine to very coarse, poorly to well-sorted, arkosic arenites, and wackes with detrital framework grains including sub-angular quartz, K-feldspar (microcline and orthoclase), plagioclase, and lithic fragments. Ba-free, Ba-rich, and perthitic K-feldspars are present. Accessory minerals include glauconite, biotite, muscovite, magnetite, titanomagnetite, sphene, zircon, apatite, corundum, and rutile. Diagenetic alteration includes: (1) compaction, (2) mineral dissolution, (3) albitization of feldspars, alteration of biotite to pyrite and chlorite, replacement of framework grains by calcite, (4) alteration of volcanic rock fragments, (5) cementation by kaolinite, calcite and dolomite, and (6) precipitation of K-feldspar and quartz overgrowths. Early-formed fractures were healed by authigenic quartz, albite, and K-feldspars. Precipitation of carbonates and clays, rearranging of broken grains, and formation of pseudomatrix reduced primary porosity. Secondary porosity is common and formed initially by the dissolution of plagioclase (excluding albite) and volcanic fragments, and later by dissolution of calcite, dolomite, and detrital K-feldspars. Hydrocarbon emplacement was

  5. [Identification of Hydrocarbon-Oxidizing Dietzia Bacteria from Petroleum Reservoirs Based on Phenotypic Properties and Analysis of the 16S rRNA and gyrB Genes].

    PubMed

    Nazina, T N; Shumkova, E S; Sokolova, D Sh; Babich, T L; Zhurina, M V; Xue, Yan-Fen; Osipov, G A; Poltaraus, A B; Tourova, T P

    2015-01-01

    The taxonomic position of hydrocarbon-oxidizing bacterial strains 263 and 32d isolated from formation water of the Daqing petroleum reservoir (PRC) was determined by polyphasic taxonomy techniques, including analysis of the 16S rRNA and the gyrB genes. The major chemotaxonomic characteristics of both strains, including the IV type cell wall, composition of cell wall fatty acids, mycolic acids, and menaquinones, agreed with those typical of Dietzia strains. The DNA G+C content of strains 263 and 32d were 67.8 and 67.6 mol%, respectively. Phylogenetic analysis of the 16S rRNA gene of strain 32d revealed 99.7% similarity to the gene of D. maris, making it possible to identify strain 32d as belonging to this species. The 16S rRNA gene sequence of strain 263 exhibited 99.7 and 99.9% similarity to those of D. natronolimnaea and D. cercidiphylli YIM65002(T), respectively. Analysis of the gyrB genes of the subterranean isolates and of a number of Dietzia type strains confirmed classiffication of strain 32d as a D. maris strain and of strain 263, as a D. natronolimnaea strain. A conclusion was made concerning higher resolving power of phylogenetic analysis of the gyrB gene compared to the 16S rRNA gene analysis in the case of determination of the species position of Dietzia isolates.

  6. Pingos, craters and methane-leaking seafloor in the central Barents Sea: signals of decomposing gas hydrate releasing gas from deeper hydrocarbon reservoirs?

    NASA Astrophysics Data System (ADS)

    Andreassen, K.; Plaza-Faverola, A. A.; Winsborrow, M.; Deryabin, A.; Mattingsdal, R.; Vadakkepuliyambatta, S.; Serov, P.; Mienert, J.; Bünz, S.

    2015-12-01

    A cluster of large craters and mounds appear on the gas-leaking sea floor in the central Barents Sea around the upper limit for methane hydrate stability, covering over 360 km2. We use multibeam bathymetry, single-beam echo sounder and high-resolution seismic data to reveal the detailed geomorphology and internal structure of craters and mounds, map the distribution gas in the water and to unravel the subsurface plumbing system and sources of gas leakage. Distinct morphologies and geophysical signatures of mounds and craters are inferred to reflect different development stages of shallow gas hydrate formation and dissociation. Over 600 gas flares extending from the sea floor into the water are mapped, many of these from the seafloor mounds and craters, but most from their flanks and surroundings. Analysis of geophysical data link gas flares in the water, craters and mounds to seismic indications of gas advection from deeper hydrocarbon reservoirs along faults and fractures. We present a conceptual model for formation of mounds, craters and gas leakage of the area.

  7. Depositional systems and hydrocarbon resource potential of the Pennsylvanian system, Palo Duro and Dalhart Basins, Testas Panhandle. Geological Circular 80-8

    SciTech Connect

    Dutton, S.P.

    1980-01-01

    Pennsylvanian clastic and carbonate strata were deposited in a variety of environments within the Palo Duro Basin. Maximum accumulation (totalling 750 m or 2400 ft) occurred along a northwest-southeast axis. Major facies include fan-delta sandstone and conglomerate, shelf and shelf-margin carbonate, deltaic sandstone and shale, and basinal shale and fine-grained sandstone. Erosion of Precambrian basement in the adjacent Amarillo and Sierra Grande Uplifts supplied arkosic sand (granite wash) to fan deltas along the northern margin of the basin. Distal fan-delta sandstones grade laterally and basinward into shallow-shelf limestone. Deep basinal shales were deposited only in a small area immediately north of the Matador Arch. Increased subsidence deepened and enlarged the basin throughout late Pennsylvanian time. Ultimately, the basin axis trended east-west with a narrow northwest extension. A carbonate shelf-margin complex having 60 to 120 m (200 to 400 ft) of depositional relief developed around the basin margin. The eastern shelf margin remained stationary, but the western shelf margin retreated landward throughout late Pennsylvanian time. Porous, dolomitized limestone occurs in a belt 16 to 32 km (10 to 20 mi) wide along the shelf margin. High-constructive elongate deltas prograded into the Palo Duro Basin from the east during late Pennsylvanian time. Prodelta mud and thin turbidite sands entered the basin through breaks in the eastern carbonate shelf margin. Potential hydrocarbon reservoirs re shelf-margin dolomite, fan-delta sandstone, and high-constructive delta sandstone. Basinal shales are fair to good hydrocarbon source rocks on the basis of total organic carbon content. Kerogen color and vitrinite reflectance data indicate that source beds may have reached the early stages of hydrocarbon maturation.

  8. Preservation of anomalously high porosity in deeply buried sandstones by grain-coating chlorite: Examples from the Norwegian Continental Shelf

    SciTech Connect

    Ehrenberg, S.N. )

    1993-07-01

    Five Lower to Middle Jurassic sandstone reservoirs from the Norwegian sector provide examples of deep porosity preservation caused by grain-coating, authigenic chlorite. Wide porosity variations in clean sandstones correlate with an abundance of grain-coating chlorite and consequent inhibition of quarts cementation. Maximum porosities tend to decrease with increasing depth but generally are 10-15% higher than would be predicted from regional trends of mean porosity vs. depth. It is proposed in this paper that the high chlorite content of the porous zones reflects syndepositional concentration of Fe-rich marine clays analogous to minerals of the modern verdine facies. Fe-clay mineralization would have been localized where Fe-rich river water was discharged into the sea. The syndepositional clays were transformed during burial diagenesis into grain coatings of radially oriented chlorite crystals. Petrographic relationships indicate that these coatings grew mainly before the beginning of quartz cementation and feldspar grain dissolution (probably within the first 2 km of burial) but after grain contacts had become adjusted by mechanical compaction. The Norwegian examples demonstrate that a wide range of nearshore marine sand-body types is susceptible to chlorite mineralization. The distribution of anomalous porosity and the proportion of the net sand affected depend upon sedimentary facies architecture and the pattern of discharge of Fe-rich river water during sand deposition. This phenomenon can be critically important for hydrocarbon exploration because it can provide good reservoir quality at depths far below the [open quotes]economic basement[close quotes] originally defined on the basis of sandstones lacking chlorite coatings. 58 refs., 25 figs., 1 tab.

  9. The dolomitized{open_quotes}O{close_quotes} Limestone in the Barinas basin: A hydrocarbon reservoir in carbonate rocks

    SciTech Connect

    Aquino, R.; Boujana, M.

    1996-08-01

    The {open_quotes}O{close_quotes} Limestone Member, top of Escandalosa Formation of a Lower to Upper Cretaceous age, is an interval of about 70 feet thick. It represents a coastal facies of caitonate platform; dominated by carbonates of calcarenitic lithologies intercalated with some sandy, glauconitic, calcareous bodies and thin bioturbated shaly intervals. Detailed studies carried out in five cores yield to a new approach and subdivision within this interval based on diagnostic erosive surfaces that may be interpreted as sequence boundaries. Based on sedimentology, trace fossil assemblages and diagenetic events, the milieu of sedimentation varies from foreshore to offshore. Porous dolomite levels occur within the {open_quotes}O{close_quotes} Limestone. This porosity is of intergranular, moldic and vuggy types. Some microfractures are also observed. Subaerial karstification is an alternative hypothesis that can explain the origin of the localized dolomitized vuggy reservoirs. The following sequence of events is suggested: (1) Sedimentation followed by bioturbation, then lithification with a probable replacement of aragonite by calcite, (2) Early dolomitization undergoing the {open_quotes}mixing{close_quote} or {open_quotes}Dorag {close_quotes} Model, (3) Dedolomitization and dissolution generating a moldic porosity enhanced the vuggy forms. This stage may have been influenced by karst processes, (4) Burial diagenesis accompanied by stylolitization and fracturation with pressure-solution effects, and (5) Some levels increase their porosity because of partial dolomitization; in others the vuggy porosity is totally infilled with sparry calcite.

  10. Method for inverting reflection trace data from 3-D and 4-D seismic surveys and identifying subsurface fluid and pathways in and among hydrocarbon reservoirs based on impedance models

    DOEpatents

    He, Wei; Anderson, Roger N.

    1998-01-01

    A method is disclosed for inverting 3-D seismic reflection data obtained from seismic surveys to derive impedance models for a subsurface region, and for inversion of multiple 3-D seismic surveys (i.e., 4-D seismic surveys) of the same subsurface volume, separated in time to allow for dynamic fluid migration, such that small scale structure and regions of fluid and dynamic fluid flow within the subsurface volume being studied can be identified. The method allows for the mapping and quantification of available hydrocarbons within a reservoir and is thus useful for hydrocarbon prospecting and reservoir management. An iterative seismic inversion scheme constrained by actual well log data which uses a time/depth dependent seismic source function is employed to derive impedance models from 3-D and 4-D seismic datasets. The impedance values can be region grown to better isolate the low impedance hydrocarbon bearing regions. Impedance data derived from multiple 3-D seismic surveys of the same volume can be compared to identify regions of dynamic evolution and bypassed pay. Effective Oil Saturation or net oil thickness can also be derived from the impedance data and used for quantitative assessment of prospective drilling targets and reservoir management.

  11. Method for inverting reflection trace data from 3-D and 4-D seismic surveys and identifying subsurface fluid and pathways in and among hydrocarbon reservoirs based on impedance models

    DOEpatents

    He, W.; Anderson, R.N.

    1998-08-25

    A method is disclosed for inverting 3-D seismic reflection data obtained from seismic surveys to derive impedance models for a subsurface region, and for inversion of multiple 3-D seismic surveys (i.e., 4-D seismic surveys) of the same subsurface volume, separated in time to allow for dynamic fluid migration, such that small scale structure and regions of fluid and dynamic fluid flow within the subsurface volume being studied can be identified. The method allows for the mapping and quantification of available hydrocarbons within a reservoir and is thus useful for hydrocarbon prospecting and reservoir management. An iterative seismic inversion scheme constrained by actual well log data which uses a time/depth dependent seismic source function is employed to derive impedance models from 3-D and 4-D seismic datasets. The impedance values can be region grown to better isolate the low impedance hydrocarbon bearing regions. Impedance data derived from multiple 3-D seismic surveys of the same volume can be compared to identify regions of dynamic evolution and bypassed pay. Effective Oil Saturation or net oil thickness can also be derived from the impedance data and used for quantitative assessment of prospective drilling targets and reservoir management. 20 figs.

  12. An Evaluation of the Carbon Sequestration Potential of the Cambro-Ordovician Strata of the Illinois and Michigan Basins. Part 1. Evaluation of Phase 2 CO2 Injection Testing in the Deep Saline Gunter Sandstone Reservoir (Cambro-Ordovician Knox Group), Marvin Blan No. 1 Hancock County, Kentucky Part 2. Time-lapse Three-Dimensional Vertical Seismic Profile (3D-VSP) of Sequestration Target Interval with Injected Fluids

    SciTech Connect

    Bowersox, Richard; Hickman, John; Leetaru, Hannes

    2012-12-20

    Part 1 of this report focuses on results of the western Kentucky carbon storage test, and provides a basis for evaluating injection and storage of supercritical CO2 in Cambro-Ordovician carbonate reservoirs throughout the U.S. Midcontinent. This test demonstrated that the Cambro- Ordovician Knox Group, including the Beekmantown Dolomite, Gunter Sandstone, and Copper Ridge Dolomite in stratigraphic succession from shallowest to deepest, had reservoir properties suitable for supercritical CO2 storage in a deep saline reservoir hosted in carbonate rocks, and that strata with properties sufficient for long-term confinement of supercritical CO2 were present in the deep subsurface. Injection testing with brine and CO2 was completed in two phases. The first phase, a joint project by the Kentucky Geological Survey and the Western Kentucky Carbon Storage Foundation, drilled the Marvin Blan No. 1 carbon storage research well and tested the entire Knox Group section in the open borehole – including the Beekmantown Dolomite, Gunter Sandstone, and Copper Ridge Dolomite – at 1152–2255 m, below casing cemented at 1116 m. During Phase 1 injection testing, most of the 297 tonnes of supercritical CO2 was displaced into porous and permeable sections of the lowermost Beekmantown below 1463 m and Gunter. The wellbore was then temporarily abandoned with a retrievable bridge plug in casing at 1105 m and two downhole pressure-temperature monitoring gauges below the bridge plug pending subsequent testing. Pressure and temperature data were recorded every minute for slightly more than a year, providing a unique record of subsurface reservoir conditions in the Knox. In contrast, Phase 2 testing, this study, tested a mechanically-isolated dolomitic-sandstone interval in the Gunter.

  13. Hydrocarbon entrapment in Trenton of southern Ontario

    SciTech Connect

    Trevail, R.A.

    1984-12-01

    Middle Ordovician Trenton strata in southern Ontario are represented by a generally transgressive sequence that reflects a wide spectrum of carbonate environments from tidal flat, through lagoon and shoal, into deeper shelf carbonates. Virtually all Ordovician production in Ontario is associated with structural deformation related to rejuvenation of a Precambrian fracture framework triggered by orogenic events in the nearby Appalachian orogene. The reservoirs are characterized by the replacement of original bioclastic limestone beds by more or less discontinuous lenses of fine to medium-grained, light to medium-brown crystalline dolostone. Pools generally are linear, following the trend of the associated fracture. Six of the 18 known Ordovician pools in Ontario are located in Essex County. A detailed study of the geology and reservoirs confirmed the close association of fracturing, dolomitization, and hydrocarbon entrapment. Representative samples of well cuttings from 20 wells were analyzed by XRD (x-ray defraction) to determine calcite-dolomite ratios. As expected, low ratios were present in the producing reservoirs. Partially dolomitized zones were revealed in wells in close proximity to fractures. Formation water originating in the underlying Cambrian sandstones was probably the main dolomitizing agent as it migrated up through the fracture. Dolomitization enhanced already existing porosity within the bioclastic zones.

  14. Stratigraphy and reservoir potential of glacial deposits of the Itarare Group (Carboniferous-Permian), Parana basin, Brazil

    SciTech Connect

    Franca, A.B. ); Potter, P.E. )

    1991-01-01

    Drilling in the Parana basin of Brazil in the mid-1980s discovered gas and condensate in the Itarare Group, and showed that glacial deposits in Brazil can contain hydrocarbons. The reservoir potential of the Carboniferous-Permian Itarare Group of the basin is analyzed using new subsurface data from 20 deep wells drilled in the early to middle 1980s. Central to the analysis was the construction of over 3000 km of cross sections based on more than 100 wells, the description of more than 400 m of core, and study of 95 thin sections. Subsurface exploration and mapping of the Itarare are greatly aided by the recognition of three recently defined and described formations and four members, which are traceable for hundreds of kilometers. These units belong to three major glacial cycles in which the pebbly mudstones and shales are seals and glacially related sandstones are reservoirs. The best sandstone reservoirs in the deep subsurface belong to the Rio Segredo Member, the upper-most sandy unit of the Itarare. The Rio Segredo Member is the best petroleum target because it is overlain by thick seals and massive pebbly mudstones and shales, and because it is shallower and less compacted than underlying, more deeply buried sandstones. This member has little detrital matrix and much of its porosity is secondary, developed by carboxylic acid and CO{sub 2} generated when Jurassic-Cretaceous basalts, sills, and dikes were intruded into the Parana basin as Gondwana broke up.

  15. Effective Stress Approximation using Geomechanical Formulation of Fracturing Technology (GFFT) in Petroleum Reservoirs

    NASA Astrophysics Data System (ADS)

    Haghi, A.; Asef, M.; Kharrat, R.

    2010-12-01

    Recently, rock mechanics and geophysics contribution in petroleum industry has been significantly increased. Wellbore stability analysis in horizontal wells, sand production problem while extracting hydrocarbon from sandstone reservoirs, land subsidence due to production induced reservoir compaction, reservoir management, casing shearing are samples of these contributions. In this context, determination of the magnitude and orientation of the in-situ stresses is an essential parameter. This paper is presenting new method to estimate the magnitude of in-situ stresses based on fracturing technology data. Accordingly, kirsch equations for the circular cavities and fracturing technology models in permeable formations have been used to develop an innovative Geomechanical Formulation (GFFT). GFFT introduces a direct reasonable relation between the reservoir stresses and the breakdown pressure of fracture, while the concept of effective stress was employed. Thus, this complex formula contains functions of some rock mechanic parameters such as poison ratio, Biot’s coefficient, Young’s modulus, rock tensile strength, depth of reservoir and breakdown/reservoir pressure difference. Hence, this approach yields a direct method to estimate maximum and minimum effective/insitu stresses in an oil field and improves minimum in-situ stress estimation compared to previous studies. In case of hydraulic fracturing; a new stress analysis method is developed based on well known Darcy equations for fluid flow in porous media which improves in-situ stress estimation using reservoir parameters such as permeability, and injection flow rate. The accuracy of the method would be verified using reservoir data of a case history. The concepts discussed in this research would eventually suggest an alternative methodology with sufficient accuracy to derive in-situ stresses in hydrocarbon reservoirs, while no extra experimental work is accomplished for this purpose.

  16. 3D seismic analysis of the Collyhurst Sandstone: implications for CO2 sequestration in the East Irish Sea Basin

    NASA Astrophysics Data System (ADS)

    Gamboa, Davide; Williams, John; Kirk, Karen; Gent, Christopher; Bentham, Michelle; Fellgett, Mark; Schofield, David

    2016-04-01

    Carbon Capture and Storage (CCS) is a vital technology towards low-carbon energy resources and the mitigation of global warming trends induced by rising CO2 levels in the atmosphere. The East Irish Sea Basin (EISB) is a key area for CCS in the western UK, having high CO2 storage potentials in explored hydrocarbon fields and in saline aquifers within the Permo-Triassic Sherwood Sandstone Formation. However, the theoretical storage potential of the EISB could be poorly estimated as the reservoir-prone Lower Permian formations are not considered in detail by current estimations. This work aims to fill this gap, focusing on the characterisation of the Lower Permian Collyhurst Sandstone Formation as a viable storage unit. The potential for CO2 storage is estimated as the total volume/area of suitable closures that are isolated by structural traps, occurring at depths suitable for CO2 injection and containment (>800m). Detailed structural and stratigraphic interpretations were made using 3D seismic data to assess the storage potential of the Collyhurst Sandstone Formation in the southern EISB. The basin strata is compartmentalised by numerous N-S trending faults. A higher degree of compartmentalisation occurs within regional anticlines where elongated tilted blocks are observed, bound by predominantly west-dipping faults that induce a variable offset of the Collyhurst Sandstone strata. Contrastingly, higher lateral continuity of this formation is observed within graben basins were faults are less frequent and with minor offset, thus potentially creating larger storage closures. Fault dip orientation in the grabens is variable, with west and east dipping faults occurring as a function of large east-dipping listric faults. This study was complemented by the stress modelling of the interpreted faults in order to assess the risk of CO2 leakage. Analysis of borehole breakouts observed in four approximately vertical wells in the EISB suggest a maximum horizontal stress

  17. Fluvial-deltaic sedimentation and stratigraphy of the ferron sandstone

    USGS Publications Warehouse

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

    1997-01-01

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

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

    SciTech Connect

    Hu Zhimian; Wu Dehua

    1995-12-31

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

  19. Geology of deep-water sandstones in the Mississippi Stanley Shale at Cossatot Falls, Arkansas

    SciTech Connect

    Coleman, J.L. Jr. )

    1993-09-01

    The Mississippian Stanley Shale crops out along the Cossatot River in the Ouachita Mountains of western Arkansas. Here, exposures of deep-water sandstones and shales, on recently established public lands, present a rare, three-dimensional look at sandstones of the usually obscured Stanley. Cossatot Falls, within the Cossatot River State Park Natural Area, is a series of class IV and V rapids developed on massive- to medium-bedded quartz sandstones on the northern flank of an asymmetric, thrust-faulted anticline. In western Arkansas, the Stanley Shale is a 10,000-ft (3200-m) succession of deep-water sandstone and shale. At Cossatot Falls, approximately 50 ft (155 m) of submarine-fan-channel sedimentary rocks are exposed during low-river stages. This section is composed primarily of sets of thinning-upward sandstone beds. With rare exceptions, the sandstones are turbidites, grading from massive, homogeneous, basal beds upward through festoon-cross-bedded thick beds, into rippled medium and thin beds. Sandstone sets are capped by thin shales and siltstones. Regional, north-northwestward paleocurrent indicators are substantiated by abundant, generally east-west ripple crests asymmetric to the north-northwest. Flute casts at the top of the sandstone sequence indicate an additional east-ward flow component. Based on regional, lithologic characteristics, the sandstones at Cossatot Falls appear to be within the Moyers Formation. The Moyers is the upper sandstone unit of the Stanley and is an oil and gas reservoir in the eastern Oklahoma Ouachita Mountains.

  20. Origin of quartz cement in the Tirrawarra Sandstone, Southern Cooper Basin, South Australia

    SciTech Connect

    Rezaee, M.R.; Tingate, P.R.

    1997-01-01

    Quartz cement in siliciclastic sequences is commonly a major diagenetic phase that affects hydrocarbon reservoir quality. Quartz cement is the most abundant authigenic mineral in the fluvio-deltaic Tirrawarra Sandstone and plays an important role in controlling reservoir quality. Petrographic, fluid inclusion, electron microprobe and cathodoluminescence (CL) data from the quartz cement indicate multiple stages of cementation at different temperatures and suggest more than one silica source. CL observations indicate up to six stages of quartz cement in some samples. The stages of quartz cement can be classified into three zones: an innermost zone of brown-luminescing cement (Z1), a middle zone of bright blue-luminescing cement (Z2) and an outer zone of brown-luminescing cement (Z3). Dead oil or bitumen is trapped between Z2 and Z3, indicating that Z3 formed after oil migration commenced. Measurements of homogenization temperatures from fluid inclusions in quartz overgrowths indicate that quartz cement precipitated over a temperature range of 65 to 130 C. Microprobe analysis shows a consistent variation in aluminum between each quartz cement zone. Fluid-inclusion precipitation temperatures and aluminum content have been used to help identify the silica sources for different zones of cement. Considering the temperature of precipitation, very low aluminum content, and the presence of Z3 cement in facies prone to stylolitization, the silica source for the cement is likely to have been pressure solution of detrital quartz at stylolites and grain contacts.

  1. Variations of the petrophysical properties of rocks with increasing hydrocarbons content and their implications at larger scale: insights from the Majella reservoir (Italy)

    NASA Astrophysics Data System (ADS)

    Trippetta, Fabio; Ruggieri, Roberta; Lipparini, Lorenzo

    2016-04-01

    Crustal processes such as deformations or faulting are strictly related to the petrophysical properties of involved rocks. These properties depend on mineral composition, fabric, pores and any secondary features such as cracks or infilling material that may have been introduced during the whole diagenetic and tectonic history of the rock. In this work we investigate the role of hydrocarbons (HC) in changing the petrophysical properties of rock by merging laboratory experiments, well data and static models focusing on the carbonate-bearing Majella reservoir. This reservoir represent an interesting analogue for the several oil fields discovered in the subsurface in the region, allowing a comparison of a wide range of geological and geophysical data at different scale. The investigated lithology is made of high porosity ramp calcarenites, structurally slightly affected by a superimposed fracture system and displaced by few major normal faults, with some minor strike-slip movements. Sets of rock specimens were selected in the field and in particular two groups were investigated: 1. clean rocks (without oil) and 2. HC bearing rocks (with different saturations). For both groups, density, porosity, P and S wave velocity, permeability and elastic moduli measurements at increasing