scispace - formally typeset
Search or ask a question

Showing papers on "Petroleum reservoir published in 1988"


Journal ArticleDOI
TL;DR: In this paper, the authors identify six facies assemblages: (1) lithic arenite, (2) mixed siliciclastic-carbonate packstone-grainstone, (3), ooid-peloid grainstone, mottled mudstone, laminated mudstone and gastropod-intraclast packstonegrainstone.
Abstract: Petroleum production from restricted shelf carbonates of the Lower Ordovician Ellenburger Group is commonly considered to have been a result of a pervasive, relatively homogeneous tectonic fracture system within the reservoir rock. However, regional facies and diagenetic (paleokarst) studies of Ellenburger strata, based on cores and wireline logs, have demonstrated that significant reservoir compartmentalization was caused by karst modification in the upper part of the unit. Ellenburger Group carbonates, which attain a thickness of over 1,700 ft (520 m), record sedimentation on a shallow-water restricted shelf occupying most of west Texas. Logging of over 10,000 ft (3,050 m) of core from 63 wells has allowed recognition of six facies assemblages: (1) lithic arenite, (2) mixed siliciclastic-carbonate packstone-grainstone, (3) ooid-peloid grainstone, (4) mottled mudstone, (5) laminated mudstone, and (6) gastropod-intraclast packstone-grainstone. These facies assemblages record initial transgression and subsequent progradation and aggradation. Paleoslope was generally south and east from the Texas arch toward the Ouachita and Marathon orogenic belts. All facies assemblages, with the local exception of the ooid-peloid grainstone assemblage, are characterized y very low intergranular and intercrystalline porosity. Porosity development in Ellenburger Group carbonates is directly related to a prolonged period of subaerial exposure that coincided with a Middle Ordovician eustatic lowstand prior to transgression of Simpson Group siliciclastics. During this episode, a widespread system of caves, sinkholes, joint-controlled solution features, and collapse breccias developed. Of particular importance to reservoir development was the formation of a regionally extensive cave system between 100 and 300 ft (30 and 90 m) beneath the exposed Ellenburger surface. Infill of this cave system by Simpson Group sand and clay segmented the upper Ellenburger into three karst facies, which are, in descending order, (1) cave-roof dolomites (fracture and mosaic breccias), (2) laterally persistent cave-fill facies (siliciclastic-matrix-supported and carbonate-matrix-supported breccias), and (3) lower collapse facies (chaotic clast-supported breccias) of the cave floor. Pronounced vertical segregation of permeable zones defined by the three karst facies is evident in the Emma, Andector, Martin, Block 13, and several other major Ellenburger reservoirs. Lateral reservoir heterogeneities formed by localized laterally extensive collapse structures, such as in the Shafter Lake reservoir, also contribute to compartmentalization of producing zones within the upper Ellenburger Group. Secondary and tertiary recovery programs in these Ellenburger reservoirs can be optimized by integrating concepts of lateral and vertical heterogeneity predicted by the karst model.

171 citations


Journal ArticleDOI
Gerald E. Smith1
TL;DR: In this article, a field observation of stress modification is discussed, as well as the contributions of the four components discussed previously to the observed phenomena, resulting in a new model of reservoir performance.
Abstract: The production of heavy oil in Canada has led to a number of anomalous results, most of which have been excused as high-permeability channels resulting from sand production. The methods of soil mechanics predict gross formation failure resulting from high fluid compressability, small cohesion, and high viscosity. Gross failure results in excellent productivity but reduced in-situ stress (and fracture stress). Solution-gas drive in these reservoirs involves simultaneous-mixture flow of a gas as very tiny little bubbles entrained in heavy oil. Stress, geometry, and permeability alteration resulting from matrix deformation combined with peculiar pressure-depended multiphase-flow properties result in a new model of reservoir performance. A field observation of stress modification is discussed, as are the contributions of the four components discussed previously to the observed phenomena.

146 citations


Journal ArticleDOI
TL;DR: In this article, the authors focused on the offshore shelf of Tunisia, where two carbonate intervals contain proven hydrocarbon reservoirs: the Metlaoui Formation of earliest Eocene (Ypresian) age and the Zebbag Formation of Late Cretaceous (Turonian) age.
Abstract: The tectonic features of Tunisia are complex and include folds, all types of faults, evaporite diapirs, and the Saharan flexure, which separates a stable Paleozoic province on the south from a subsidence zone of Mesozoic and Cenozoic strata of the offshore Ashtart and Tripolitania basins. The remainder of the offshore region is mostly stable shelf of the Pelagian craton, which also extends onshore. The present study focused on this shelf, where two carbonate intervals contain proven hydrocarbon reservoirs: the Metlaoui Formation of earliest Eocene (Ypresian) age and the Zebbag Formation of Late Cretaceous (Turonian) age. Regionally, well-defined belts of Metlaoui carbonates trend northwest. On the northeast are open-marine deep-water micrites and marls with abundant planktonic foraminifers. Thick bars of nummulitid packstone/grainstone were deposited in shallow water at an angle to the paleoshelf. The reservoir is confined largely to the bars, and visible effective porosity is best developed in those areas among the foraminifers filled with sand-size nummulitid debris, where secondary solution enlargement has occurred. This lithology tested oil in two recent wildcat wells and is a commercial reservoir at Sidi El Itayem and Ashtart fields. Distribution of Zebbag carbonates is more complex. A northwest-trending platform was bounded on three sides by deep water, where shale and micrite with planktonic foraminifers were deposited. Predominately back-reef and lagoonal foraminifer/rudist wackestones and packstones occur in narrow belts, apparently controlled at least locally by block faulting. They tested oil in two recent discoveries. The most significant porosity is interparticle, generally enlarged by solution, in foraminifer packstones, but intraparticle voids in foraminifers and rudists commonly contribute to the porosity. Analyses of surface and subsurface samples identified the Bahloul (basal Turonian) and Bou Dabbous (Ypresian) formations as source rocks. Fluorescence spectra of several oils were compared with extracts from these samples and indicate the Bahloul to be the source of oils in recent Metlaoui and Zebbag discoveries.

103 citations


Patent
29 Jul 1988
TL;DR: In this article, a method for microbial enhanced oil recovery is provided, wherein a combination of microorganisms is empirically formulated based on survivability under reservoir conditions and oil recovery efficiency, such that injection of the microbial combination may be made, in the presence of essentially only nutrient solution, directly into an injection well of an oil bearing reservoir having oil present at waterflood residual oil saturation concentration.
Abstract: A method is provided for microbial enhanced oil recovery, wherein a combination of microorganisms is empirically formulated based on survivability under reservoir conditions and oil recovery efficiency, such that injection of the microbial combination may be made, in the presence of essentially only nutrient solution, directly into an injection well of an oil bearing reservoir having oil present at waterflood residual oil saturation concentration. The microbial combination is capable of displacing residual oil from reservoir rock, which oil may be recovered by waterflooding without causing plugging of the reservoir rock. Further, the microorganisms are capable of being transported through the pores of the reservoir rock between said injection well and associated production wells, during waterflooding, which results in a larger area of the reservoir being covered by the oil-mobilizing microorganisms.

100 citations


Journal ArticleDOI
TL;DR: In this paper, a formal scheme to interpret these facies from wireline logs using quantitative analysis of density and neutron logs and qualitative information from other logs was presented, and the results showed that the facies are widespread in the subsurface.
Abstract: More than 3.5 billion bbl of oil in place have so far been discovered in reservoirs of the Al Khlata Formation of the Permian-Carboniferous lower Haushi Group in south Oman. Glacially striated pavements and boulders in exposures at Al Khlata in east-central Oman confirmed previous interpretations that the formation is, at least partly, of glacial origin. Core and wireline-log data from some 500 wells that penetrate the formation show that glacial facies are widespread in the subsurface. Shales with varvelike laminations and dropstones are present in two main layers, which extend over the larger part of south Oman and are perhaps the most diagnostic facies. Diamictites are also widespread, and some, which can be correlated as sheets over thousands of square kilometers, are interpreted as true tillites. Other diamictites are interbedded with shales with varvelike laminations or unbedded siltstones and are interpreted as subaqueous glacial deposits. Ten sedimentary facies have been described in cores and outcrops. An important result of this study is a formal scheme to interpret these facies from wireline logs using quantitative analysis of density and neutron logs and qualitative information from other logs. Lateral facies relationships are complicated by syndepositional salt withdrawal and dissolution, paleorelief on the basal unconformity, and intraformational unconformities beneath regionally extensive tillites. At least three glacial phases can be recognized: an early phase, represented only by erosional remnants of diamictites, and two later phases, the last of which extended over the whole of Oman south of the Oman Mountains. Deglaciation is represented by a regional shale bed sharply overlying the diamictite sheet of this last glaciation. Oil occurrence can be related to three northwest-southeast-striking facies belts. (1) In the South Oman salt basin, deposits consist of sands, pebbly sands, and diamictites deposited in glaciofluvial environments. This sequence lacks good seals. (2) In the downdip part of the basin's eastern flank, interbedded sands, silts, shales with varvelike laminations, and diamictites represent glaciolacustrine deposition at ice margins and in meltwater deltas. This belt contains interbedded reservoirs and seals, and includes the largest number of oil accumulations. (3) Updip in the eastern flank area, several-hundred-meter thick siltstones and claystones with thin turbiditic sandstones represent a belt of persistent glaciolacustrine deposition, probably in the axis of a salt dissolution synclin . This belt contains few oil accumulations.

89 citations


Journal ArticleDOI
TL;DR: The thermal maturity of the Smackover rend explains the distribution of hydrocarbon discoveries and suggests areas previously overlooked by exploration as discussed by the authors, which is the basis for our work as well.
Abstract: Laminated lime mudstones of the lower member of the Jurassic Smackover Formation are significant source rocks for crude oil across Mississippi, Alabama, and Florida. The source facies was deposited in an anoxic and perhaps hypersaline environment that preserved algal-derived kerogen. The distribution of kerogen along laminations of depositional origin and along stylolites of diagenetic origin resulted in efficient expulsion of crude oil. With increasing thermal maturity, crude oil initially emplaced in reservoirs was cracked to yield gas condensate and then methane rich in nonhydrocarbon gases such as hydrogen sulfide, carbon dioxide, and nitrogen. Early destruction of methane was driven by thermochemical sulfate reduction. The thermal maturity framework of the Smackover rend explains the distribution of hydrocarbon discoveries and suggests areas previously overlooked by exploration.

86 citations


Journal ArticleDOI
TL;DR: In this paper, an oil gas seep was documented by replicate sampling with piston corer, abundant high-resolution and sparse multichannel seismic reflection profiling, and chemical and isotopic analyses.
Abstract: An oil gas seep was documented by replicate sampling with piston corer, abundant high-resolution and sparse multichannel seismic reflection profiling, and chemical and isotopic analyses. The seep occurs on the upper continental slope over a salt ridge interpreted to split and plunge eastward, northeastward, and northward. The relatively shallow diapir over which the seepage occurs is manifested at the surface by a graben in strike section and by a half-graben in dip section. Faulting over the crest is commonly associated with loss of reflected energy or acoustic wipeouts. Most cores taken in wipeouts with prolonged bottom echoes contain oil and gas. The cores also commonly contain secondary carbonate derived from microbial degradation of hydrocarbons. The isotopic lightne s of the carbonate and its negative correlation with porosity may be subtle indicators of seepage at sites where oil and gas are not obvious. The seepage demonstrates the existence of source rocks and maturation at this site.

81 citations


Journal ArticleDOI
TL;DR: The Jurassic eolian Nugget Sandstone of the Utah-Wyoming thrust belt is a texturally heterogeneous formation with anisotropic reservoir inherited primarily from the depositional environment as mentioned in this paper.

64 citations


Journal ArticleDOI
TL;DR: In this article, the authors used the X-ray photoelectron spectroscopic (XPS) method for measuring carbon content of rock surface samples to provide a qualitative measurement of wettability of the rock samples.
Abstract: Previous studies to determine the extent of oil trapping by water during CO/sub 2/ water-alternating-gas (WAG) flooding have shown that rock wettability strongly affects this trapping. A significant trapping occurs in water-wet rock, and less trapping occurs in oil-wet rock. This paper presents laboratory results of Devonian crude oil displacement from watered-out Berea and reservoir cores by use of continuous CO/sub 2/ injection, single-slug CO/sub 2/ injection (followed by water), and CO/sub 2/ WAG injection at miscible reservoir conditions of 120/sup 0/F and 2,500 psig (49/sup 0/C and 17.2 MPa). The reservoir cores used in this study were mixed-wet (Devonian and Muddy formations) and oil-wet (Tensleep formation). The Berea cores used had their wettability artificially altered to simulate these natural wettabilities. The X-ray photoelectron spectroscopic (XPS) method for measuring carbon content of rock surface was used to provide a qualitative measurement of wettability of the rock samples. The results of the study indicated that the experimental wettability-altering technique came close to duplicating reservoir rock wettability. The oil recovery data at the end of 1 PV fluid injection (continuous CO/sub 2/ or WAG CO/sub 2/) indicated that (1) in preferentially water-wet Berea cores, more than 45% of the waterflood residual oilmore » trapped by CO/sub 2/ WAG; (2) in mixed-wettability Berea cores, 15 to 20% of the waterflood residual oil was trapped; and (3) in oil-wet Berea cores, less than 5% residual oil was trapped.« less

62 citations


Journal ArticleDOI
TL;DR: In this article, the authors describe an analytical model for gas flow through a core, and present a method for rapidly and simultaneously determining both the porosity and permeability of a low permeability core.
Abstract: Determining the porosity and permeability of a formation has always been basic to understanding petroleum reservoirs. In low permeability formations, the measurement of permeability from core samples is a difficult task. To complicate the problem, the porosity and permeability can be strongly dependent upon the net stress exerted on the core sample. Net stress, which is the difference between overburden stress and pore pressure, will increase as the reservoir pressure is depleted. A method for determining permeability with precision and reasonable speed can be quite important when one is trying to characterize a low permeability reservoir. The conventional (steady state flow) method for permeability determination is not adequate for low permeability cores. The low flow rates across the core plug are difficult to measure and control. In this paper, the authors describe an analytical model for gas flow through a core, and present a method for rapidly and simultaneously determining both the porosity and permeability of a low permeability core.

54 citations


Journal ArticleDOI
TL;DR: In this paper, the effects of temperature on wave velocities in well-cemented Massillon and Boise sandstones and unconsolidated Ottawa sand saturated with heavy hydrocarbons were investigated.
Abstract: A laboratory investigation was made of the effects of temperature on wave velocities in well cemented Massillon and Boise sandstones and unconsolidated Ottawa sand saturated with heavy hydrocarbons, as well as the dependence of compressional velocities in the hydrocarbons themselves as a function of temperature. The hydrocarbons selected as pore saturants were a commercial paraffin wax, 1-Eicosene, natural heavy crude, and natural tar. The experimental results show that the compressional wave velocities in the hydrocarbons decrease markedly with increasing temperature. In contrast wave velocities in the Massillon and Boise sandstones and unconsolidated Ottawa sand saturated with air or water decrease only little with increasing temperatures. The main reason for the large decreases in rocks with hydrocarbons is the melting of solid hydrocarbons, and high pore pressure. Thermal expansion of the saturants, and possibly thermal cracking of the heavy fractions and vaporization of the light fractions of the hydrocarbons may also contribute. The large decreases of the compressional and shear wave velocities in the hydrocarbon-saturated rocks and sands with temperature, suggest that seismic measurements such as used in seismology or borehole tomography may be very useful in detecting steam fronts in heavy hydrocarbon reservoirs undergoing steam flooding.

Journal ArticleDOI
TL;DR: The Lower Cretaceous Viking Formation in the Crystal field of south-central Alberta contains a linear sandstone body, as much as 30 m thick, that forms a complicated dual-pool hydrocarbon reservoir as mentioned in this paper.
Abstract: The Lower Cretaceous Viking Formation in the Crystal field of south-central Alberta contains a linear sandstone body, as much as 30 m thick, that forms a complicated dual-pool hydrocarbon reservoir. This contrasts sharply with most other Viking reservoirs, which are much thinner, are commonly oriented northwest, and are composed of a single hydrocarbon pool. Thickness, orientation, and pool duality are attributed to the complicated depositional history of the Viking in the Crystal region. The sandstone body is interpreted as a multistage tidal channel-fill deposit within a larger estuarine channel-bay complex, which rests unconformably on inner shelf-lower shoreface facies. A major lowstand of sea level that occurred approximately 97 m.y. ago is believed to be responsible for incisement of the estuarine valley, which was filled during rising sea level. A depositional model of progressive estuarine valley fill under transgressive conditions readily accounts for the occurrence of two hydrodynamically separated oil pools, and also for differences in reservoir continuity and performance trends within the main oil-bearing "A" pool. Highly productive wells in the main pool correspond to specific channel-fill deposits, or are situated in areas where deposits of successive channel stages are highly superimposed. Conversely, marginally productive wells and poor reservoir communication between producing wells occur in areas where the different channel-stage deposits diverge.

Journal ArticleDOI
TL;DR: Cement-stratigraphy studies indicate abundant calcite precipitation from low-temperature fresh water within shelf, shelf-crest, and shelf-edge marine limestones.
Abstract: Cyclic strata of the Holder Formation (Virgilian, New Mexico) were deposited across a Pennsylvanian shelf-to-basin transition during a time when sea level fluctuated over tens of meters. Cement-stratigraphy studies indicate abundant calcite precipitation from low-temperature fresh water within shelf, shelf-crest, and shelf-edge marine limestones. Freshwater cementation occurred during 15 periods of intraformational subaerial exposure. These early cements are least abundant in basin and lagoon limestones. The distribution of the early cement zones suggests that cementation was controlled by paleotopography, stratigraphic position below subaerial exposure surfaces, lithology, and configuration of the paleoaquifer system. Distribution of early calcite cements provides new data for interpretation of cycles, diagenetic systems, and porosity evolution in petroleum reservoirs. Trace-element analyses support a low-temperature, freshwater origin for the early cements. Cement-stratigraphy studies, fluid-inclusion analyses, and trace-element analyses indicate a later cement that occluded remaining limestone porosity precipitated from a sodium- and calcium-rich brine at a temperature of about 100°C. Stratigraphic reconstruction dates this cementation as Cretaceous or later. Fluorescent, oil-filled fluid inclusions were trapped along fractures in the late cement, indicating oil migration during or after late-stage cementation.

Journal ArticleDOI
TL;DR: In this article, the authors show that a more oil-prone source facies is present in marine shales of the deep Wilcox Group in southcentral Louisiana, which is consistent with geologic constraints that suggest an origin of crude oil from within the Wilcox group itself.
Abstract: Geochemical characterization of crude oils from Wilcox reservoirs in central Louisiana and southwest Mississippi suggests that they represent a single crude oil family that is distinct when compared to crude oils in deeper Tuscaloosa and Smackover reservoirs. This observation is consistent with geologic constraints that suggest an origin of crude oil from within the Wilcox Group itself. Although shales of the shallow Wilcox Group in central Louisiana and southwest Mississippi contain gas-prone kerogen and are thermally immature, a more oil-prone source facies is present in marine shales of the deep Wilcox Group in southcentral Louisiana. Thermal maturity measurements based on pyrolysis suggest a broad area of effective Wilcox source rock in southcentral Louisiana. Migration distances from source to reservoir rocks of the downdip Wilcox Trend of southcentral Louisiana appear to be relatively short. However, long-range updip migration (sometimes greater than 100 km) from deeply buried Wilcox source facies provides the best explanation for emplacement of crude oil in the shallow Wilcox Trend of central Louisiana and southwest Mississippi.

Journal ArticleDOI
TL;DR: In this paper, a detailed correlation of well logs, based on field-wide, acoustically soft, lacustrine claystone markers, confirmed a Lacustrine-deltaic reservoir geologic model derived from core analyses.
Abstract: The Sirikit oil field lies in the Phitsanulok basin, one of a series of Tertiary rift-related structures in central and northern Thailand. The tectonic history of the area is complex: the original extensional half graben was deformed during deposition of the upper reservoir sequence by left-lateral strike-slip faulting. Careful interpretation of a three-dimensional seismic data set has resulted in the reliable mapping of seismic markers. Detailed correlation of well logs, based on field-wide, acoustically soft, lacustrine claystone markers, confirmed a lacustrine-deltaic reservoir geologic model derived from core analyses. The Sirikit deltas are of constructive lobate type with sheetlike mouth-bar (bay-mouth bar) reservoir sandstone geometries. Interpretation of seismic horizon seiscrops (amplitude maps) of mapped seismic horizons has refined the understanding of the complex local reservoir structure. Subtle amplitude anomalies, interpreted as small displacement faults, are visible on horizon seiscrop maps. These faults may reduce the drainage area inferred from log correlations. The resolution of small dislocations and flexures by seiscrop analysis may apply to well targeting. Production decline rates are variable in the Sirikit wells, showing no simple relationship to the perforated reservoir thickness. The geologic model explains this behavior in terms of effective drainage area: wells perforated in thin sheet sandstones commonly have lower decline rates than those completed in thicker, better reservoir quality, but isolated, channel sandstones.

Journal ArticleDOI
Paul Enos1
TL;DR: In this article, a diagenetic history of porosity at various stages from original sediment to reservoir rock has been studied in the Poza Rica trend of the Tampico embayment, Mexico, which will ultimately produce 2.3 × 109 barrels of oil from mid-Cretaceous basin-margin deposits.
Abstract: The Poza Rica trend of the Tampico embayment, Mexico, will ultimately produce more than 2.3 × 109 barrels of oil from Mid-Cretaceous (Albian-Cenomanian) basin-margin deposits. Bioclastic grainstone, packstone, and wackestone are interbedded with polymictic lime breccia and dolomitized debris; all were deposited by sediment gravity flow. Indigenous sediment was pelagic lime mud. Typical reservoir porosities are about 10%; permeabilities average 2 md and rarely exceed 100 md. Porosity is largely the result of selective dissolution of rudist fragments, which were originally aragonite. Detailed petrographic study, with emphasis on the diagenetic products, allows quantitative assessment of porosity at various diagenetic stages from original sediment to reservoir rock. A relatively simple diagenetic history is reflected by about 90% of the samples studied: primary porosity was reduced through lithification of matrix mud and initial cementation by clear, equant to bladed, non-ferroan calcite. Later dissolution produced extensive skelmoldic and minor vuggy porosity. Subsequently, non-ferroan calcite cement reduced porosity before the emplacement of hydrocarbons. Reconstructed sediment porosities are comparable to, but lower than, modern counterparts. The initial phase of cementation and presumed lithification of mud greatly reduced porosity in all lithologies, but appreciably more porosity persisted in grainstone and packstone than in wackestone or mudstone. Dissolution produced a porosity resurrection, which exceeded that of the initial sediment in some grainstones. Calcite cementation and local multiphase quartz cementation and dolomitization reduced porosity to present average values of 8–12% in grain-supported rocks and 3% in mud-supported rocks. The greater persistence of primary porosity and, therefore, permeability in grain-supported rocks probably accounts for their greater secondary porosity development and ultimate reservoir quality. Geometrically averaged permeabilities range from only 0.17 md in wackestone to 3.85 md in dolomite, but differ significantly with rock type and grain size. Permeability increases with porosity in all lithologies; the rate of increase is greater at higher porosities and with coarser grain sizes. The agent for both early cementation and development of secondary porosity appears to have been meteoric water. Subaerial exposure appears to be ruled out, however, by a basin-margin depositional environment and continued burial beneath Upper Cretaceous pelagic sediments. Early exposure to meteoric water can be explained by a hydrologic head developed during penecontemporaenous exposure that produced cavernous porosity in the adjacent Golden Lane trend. Descending meteoric water likely emerged as submarine springs along the Tamabra trend. Deposition of pelagic limestone during the Turonian blanketed part of the Golden Lane escarpment to enhance development of a large freshwater lens; gaps in the blanket localized springs and influenced flow patterns within the Poza Rica field. Analogous freshwater circulation exists today in northern Florida.

Journal ArticleDOI
TL;DR: In this paper, a case study of an oil-producing channel sand in the Taber/Turin area, Alta., Canada illustrates the improvement in reservoir characterization achieved with an integrated approach incorporating both well and seismic information.
Abstract: Modern three-dimensional (3D) seismic data assist not only in delineating reservoir geometry, but also in predicting porosity and lithology variations away from well control. This case study of an oil-producing channel sand in the Taber/Turin area, Alta., Canada illustrates the improvement in reservoir characterization achieved with an integrated approach incorporating both well and seismic information.

Proceedings ArticleDOI
01 Jan 1988
TL;DR: In this article, a large number of laboratory tests have been run under simulated reservoir conditions to provide a description of the mechanical properties of this chalk, including porosity and quartz content, and the dependence of compaction on these was determined.
Abstract: The subsidence occurring in the Ekofisk field originates from the compaction of the reservoir rock due to the increasing stress placed upon it as reservoir pressure is reduced with production from the field. The mechanical properties of the reservoir rock determine how much compaction will take place for given conditions in the field and are therefore a key factor in determining the degree to which subsidence will occur. These mechanical properties can be combined with other reservoir information (pressure, overburden load, structure, etc.) in simulators to predict the amount of compaction and surface subsidence that will occur in the life of the field. For this to be done accurately, there must be sufficient information to describe the compaction behaviour of all the rock within the reservoir for all conditions encountered. The Ekofisk reservoir consists largely of chalk, a very fine-grained, high porosity, mechanically weak rock. A large number of laboratory tests have been run under simulated reservoir conditions to provide a description of the mechanical properties of this chalk. Stress states were applied to reservoir chalk samples to duplicate those encountered in the field, and the resulting compaction was measured. At low stress the chalk compacts elastically with moderate compressibility, but at the higher stress levels encountered in the field during production large amounts of plastic deformation occur. Basic mechanisms of chalk compaction were examined to provide better understanding of the chalk behaviour. The chalk properties that primarily influence compaction were identified as porosity and quartz content; the dependence of compaction on these was determined to provide a description of all the chalk within the reservoir. Time dependence of chalk compaction was studied so that laboratory results could be properly applied to the production life of the field. The influence of the waterflooding of the Ekofisk reservoir on the strength of the chalk was studied and found to have no effect.

Journal ArticleDOI
TL;DR: The Tadla basin, Morocco, is the easternmost major structural subdivision of the Meseta south of the Central Massif as discussed by the authors, and the results from computer modeling show that the chief formations of hydrocarbon generation are Carboniferous and Silurian.
Abstract: The Tadla basin, Morocco, is the easternmost major structural subdivision of the Meseta south of the Central Massif. After the basin remained relatively stable through the Paleozoic, movements during the Variscan orogeny divided the basin into two subbasins, a western subbasin where compressional forces formed large anticlines and an eastern subbasin where intense folding and faulting are associated with uplift and erosion. The sedimentary basin fill includes numerous organic shales, which provide the source beds. Also deposited were numerous shallow-water to continental clastics and to a lesser extent carbonates, providing several possible reservoir rocks for hydrocarbons. The results from computer modeling show that the chief formations of hydrocarbon generation are Carboniferous and Silurian. Most of these formations may have generated hydrocarbons before Variscan movements, which probably destroyed preexisting oil and gas traps. The only source rocks in the generation stage from Mesozoic to the present are the upper Visean shales. The western part of the Tadla basin was the most favorable area for the generation and maturation of hydrocarbons of the upper Visean shales.

Book ChapterDOI
01 Jan 1988
TL;DR: In the past decade or so the reservoir engineer's reliance on mathematical models has grown at a remarkable rate, and, in view of the evolution of many other successful branches of engineering, it seems fair to expect this reliance to continue increasing as discussed by the authors.
Abstract: A petroleum reservoir is a complicated mixture of porous rock, brine, and hydrocarbon fluids, usually residing underground at depths that prohibit extensive measurement and characterization. Petroleum reservoir engineers face the difficult task of using their understanding of reservoir mechanics to design schemes for recovering hydrocarbons efficiently. In the past decade or so the reservoir engineer’s reliance on mathematical models has grown at a remarkable rate, and, in view of the evolution of many other successful branches of engineering, it seems fair to expect this reliance to continue increasing. This monograph examines several aspects of the development of mathematical reservoir models. Before embarking on technical discussions, though, we shall give a brief, relatively nontechnical survey of how an oil reservoir works.

Journal ArticleDOI
TL;DR: In this paper, the amplitude response of the Muddy is influenced by Muddy facies and thickness changes, and the lowest Muddy amplitude observed occurs when the Bell Creek sandstone is prevalent.
Abstract: The Muddy Sandstone in the northern Powder River Basin consists of two distinct members (genetic units) that are separated by a widespread subaerial surface of erosion. The older sandstone member, the reservoir rock at the giant Bell Creek field, was deposited in shoreline and associated nearshore marine environments. It is genetically related by intertonguing to the underlying Skull Creek Shale. The younger member is a valley fill deposit of fluvial, estuarine and tidal flat environments. The deposition and distribution of these two genetic units were controlled primarily by relative sea level changes. The Bell Creek sandstone was deposited as a widespread regressive sandstone during a highstand of sea level. A following sea level lowstand caused valley cutting, erosion of all or portions of the Bell Creek sandstone, and paleosoil development causing early diagenesis, especially of kaolinite, siderite and quartz. A rising sea level resulted in valley filling, coastal onlap and a transgressive surface of erosion that is overlain by black marine shale (Nefsy or Shell Creek). Recurrent movement on basement-controlled fault blocks appears to have controlled distribution of the Muddy members, drainage incisement patterns, present structure and heat flow, and possibly petroleum migration. Seismic modeling indicates that it may be possible to recognize seismically the distribution of Muddy reservoir facies that occur in the area. Seismic modeling suggests that the amplitude response of the Muddy is influenced by Muddy facies and thickness changes. The lowest Muddy amplitude observed occurs when the Bell Creek sandstone is prevalent. An increase in the Muddy amplitude is noted when thick valley fill deposits are present. Results from seismic modeling compare well to actual seismic data. Amplitude changes noted in the Muddy reflector in the Bell Creek – Rocky Point area may help explorationists in the future to distinguish between nonprospective and reservoir quality Muddy Sandstone.

Journal ArticleDOI
TL;DR: In this paper, the van Everdingen-Hurst method was used to predict the behavior and the rise of the gas/water contact (GWC) in a water drive gas reservoir.
Abstract: Predicting the advancement of a gas/water contact (GWC) in a waterdrive gas reservoir plays an important role in evaluating, forecasting, and analyzing the reservoir performance. This study was conducted to predict the behavior and the rise of the GWC, assuming that it remains horizontal, and to determine its effect on ultimate gas recovery. Several factors control the rise of the GWC. Some of the most important factors are the size of the aquifer, gas production rate, initial reservoir pressure, and formation permeability. These factors account for the abandonment of a number of gas reservoirs at extraordinarily high pressure. Several methods have been developed for predicting the volume of water influx into a reservoir; the van Everdingen-Hurst method is used in this study. The performance calculated in this study was based on the material-balance equation for gas reservoirs. The gas reservoir pressure was adjusted to the original GWC for the water-influx equation, and the trapped gas in the water-invaded zone was accounted for in the water-invaded region. A constant reservoir permeability of 300 md was used in all calculations. The results showed that when r/sub a//r/sub g/ less than or equal to 2, the effect of the aquifer on gas reservoirmore » performance can be neglected. Also, the rate at which the GWC advances is controlled by the aquifer size when r/sub a//r/sub g/ > 2. Finally, regardless of the size of the reservoir, when r/sub a//r/sub g/ > 2, the pressure in the unsteady-state water-influx equation has to be corrected to the original GWC. Failure to do so may result in an error of more than 100% in the cumulative water influx, which in turn could lead to the wrong conclusions regarding the performance of the gas reservoir.« less

Journal ArticleDOI
TL;DR: In this article, the authors used the Early Ordovician Ellenburger Dolomite (west Texas and New Mexico) and the Late ODE-Early Devonian Hunton Group carbonates (Oklahoma) to calculate or infer petrophysical characteristics, such as median pore-throat size, porethroat distribution, effective porosity, and recovery efficiency.
Abstract: Capillary-pressure data from the Early Ordovician Ellenburger Dolomite (west Texas and New Mexico) and the Late Ordovician-Early Devonian Hunton Group carbonates (Oklahoma) are used to calculate or infer petrophysical characteristics, such as median pore-throat size, pore-throat size distribution, effective porosity, and recovery efficiency (RE). For both data sets, porosity and RE are inversely related. A positive relationship between RE and porosity has been reported by other workers, but the relative importance of these opposed trends is unknown. The ability to accurately predict which relationship will hold in a given reservoir unit would be of great value for predicting reservoir performance.

Journal Article
TL;DR: In the Gulf of Suez, a short-lived salinity crisis resulted in the deposition of massive thick evaporites that formed the ultimate seal in the Gulf as discussed by the authors, and the accompanying rapid burial of the underlying sub-Miocene potential source intervals caused them all to sequentially enter the oil window, within a very short time.
Abstract: Petroleum in the Gulf of Suez is multisourced mainly by restricted marine Cretaceous to Eocene beds. The Campanian carbonates of the Sudr Formation and the Turonian shales of the Abu Qada Formation are high-quality sources. Other proven sources are carbonate and shale intervals within other sub-Miocene formations. Geothermal modeling calibrated by maturation measurements suggests that the organic-rich lower Miocene marls may not be mature enough to expel hydrocarbons north of the Morgan-Amal fields area but are mature to the south. This could be related mainly to a gradual increase in thermal gradient from north to south (20-55{degree}C/km). A few anomalies do exist, however. Thermal gradients are generally higher in areas where oil accumulated. The depth of peak generation ranges between 5,200 m to the north and 3,300 m to the south. The geographic variations in heat flow, maturation depths, and age of source rocks are not reflected in the timing of hydrocarbon migration. During the middle Miocene, a short-lived salinity crisis resulted in the deposition of massive thick evaporites that form the ultimate seal in the Gulf. The accompanying rapid burial of the underlying sub-Miocene potential source intervals caused them all to sequentially enter the oil window, within a verymore » short time, soon after the evaporites accumulated. This timing was perfect for hydrocarbon preservation: after seal deposition and major disturbing regional tectonic events. The almost simultaneous migration from all the source beds resulted in mixed multisourced hydrocarbon accumulations.« less

Book ChapterDOI
TL;DR: In this paper, the authors proposed a wrenching model for the Michigan basin based on lineament (fault) patterns from Landsat imagery and outcrop fracture analyses, and the azimuths of existing linear producing fields, whether from Trenton-Black River or younger rocks, closely fit the shear model.
Abstract: Hydrocarbon production in the Michigan basin occurs primarily from Silurian pinnacle reefs or Middle Ordovician and Middle Devonian linear, faulted, and dolomitized structures. The writer has previously proposed a wrenching model for the basin based on lineament (fault) patterns from Landsat imagery and outcrop fracture analyses (ground truth). The azimuths of existing linear producing fields, whether from Trenton-Black River or younger rocks, closely fit the shear model. Analyses (x-ray diffraction) of numerous well samples from several producing fields show dolomite/calcite ratios of epigenetically formed dolomite (porous reservoir rock) channelways along vertical shear faults, shear folds, cross faults, cross folds, and stratigraphic permeable offshoots from the fault channelways of the wrenching model. The dolomitizing fluids probably entered the fault channelways from artesion waters from below. If so, basin form would be important to reservoir rock development in this system. Geophysical exploration for the strike-slip shear faults in nearly horizontal rocks generally has proved elusive, even for accompanying shear folds where they have small amplitudes. The Trenton-Black River Albion-Scipio giant field is shear faulted but not shear folded. Geophysical search for other similar structures has been far from successful. Thus, model fitting in many instances may be the most effective tool. Itmore » should be recognized that faults sensed by the reflected infrared of Landsat are open systems, at least near the surface. It is the unseen closed system components of the model for which one searches.« less

Journal ArticleDOI
TL;DR: In this paper, the authors present a review of the Statfjord field after 8 years of production, and the reasons behind the reservoir development strategies and field experiences are presented.
Abstract: This paper reviews reservoir performance and management of the Statfjord field after 8 years of production. The reasons behind the reservoir development strategies and field experiences are presented. The field comprises three reservoirs produced simultaneously with designated wells for each reservoir: the Upper and Lower Brent and the Statfjord. The two Brent reservoirs are produced with a waterflood, while the Statfjord reservoir is produced with a high-pressure miscible gasflood. The original development plans have been refined on the basis of field performance through an extensive monitoring program and use of reservoir simulation. The induced gamma ray spectra (IGRS) log is used to monitor water movement in the Brent reservoirs, while the compensated neutron tool (CNT) is the main tool used to monitor the gasflood in the Statfjord reservoir. The acquired data have improved the geologic model and the knowledge of fluid movements in all three reservoirs. This resulted in a large and complex reservoir simulation model with more than 20,000 gridblocks.


01 Jan 1988
TL;DR: In this paper, an improved interpretation leads to the determination of four environments: 1) continental, 2) delta complex, 3) shore-zone, and 4) shelf, based on data from wells, seismic reflection sections and biostratigraphic/paleoenvironmental studies.
Abstract: In the ARII (Atlantic Richfield Indonesia Inc.) Offshore Northwest Java contract area, the Oligocene Talang Akar depositional environments have previously been broadly defined as deltaic and marine. An improved interpretation leads to the determination of four environments: 1) continental, 2) delta complex, 3) shore-zone, and 4) shelf. Data from wells, seismic reflection sections and biostratigraphic/paleoenvironmental studies were used to develop the new interpretation. Each depositional environment is characterized by specific lithofacies and seismic facies which can be related to hydrocarbon potential. The shore-zone, a newly defined environment, was previously identified as either a delta complex or a fully marine setting. The geometry and type of potential reser voir rocks in the shore-zone differ from those of the delta complex. The exploration implications of this interpretation lead to a reevaluation of the hydrocarbon play types which were previously based on the delta model. Both the delta complex and shore-zone environments have good hydrocarbon potential in terms of source and reservoir rocks. Hydrocarbons accumulate either by migrating from source rocks to surrounding channel and bar sands or updip to the structural and stratigraphic traps. The depositional history of the Talang Akar formation has been sub-divided into four stages. Each stage corresponds to a specific geologic time as inferred from biostratigraphic zonation. Sedimentation rates, topography and subsidence rates are the three major factors controlling this continuous marine transgressive sequence. The sedimentation rates were primarily control led by the local topographic relief. The rates varied from zero in the non-depositional plains to more than 20 cm/1000 yr in the depressions. Growth faulting enhanced the rate of sediment deposition.

Proceedings ArticleDOI
01 Jan 1988
TL;DR: In this paper, a computational procedure has been developed to simulate the reservoir compaction and subsidence processes observed at the Ekofisk field in the Norwegian North Sea, where the results of two axially symmetric, 2-D finite element calculations are combined to evaluate alternative reservoir management plans and to assess needs for modifying offshore facilities.
Abstract: To evaluate alternative reservoir management plans and to assess needs for modifying offshore facilities, a computational procedure has been developed to simulate the reservoir compaction and subsidence processes observed at the Ekofisk field in the Norwegian North Sea. The procedure involves combining the results of two axially symmetric, 2-D finite element calculations so that in plan view the Ekofisk reservoir is treated as an elliptically-shaped body. Reservoir compaction is assumed to be driven by reductions in pore pressure, with input information deduced from reservoir simulators used for reservoir management. Porosity distributions and geometrical features of the reservoir are based on porosity logs from some sixty wells drilled prior to the onset of significant compaction. Mechanical properties for the reservoir rock (chalk) are based on laboratory compaction data; for the overburden they are based on data from vertical seismic profiles and compaction tests. The simulation procedure has been applied to several reservoir management scenarios, three of which are considered in the paper. One is a pressure maintenance scenario involving aggressive gas injection to mitigate reservoir compaction and subsidence while the others are depletion scenarios which involve a waterflood that was planned prior to discovery of subsidence to enhance production, but also will serve to maintain reservoir pressure. The good agreement between calculations and recent measurements provides a basis for confidence in future projections. Hence, the prediction of about 6m of subsidence by the year 2011 for depletion reservoir management scenarios suggests that the recently completed operation to elevate the central platforms of the Ekofisk field by 6m represents a long-term solution to the subsidence problem.

Journal ArticleDOI
TL;DR: In this article, Landsat-derived lineament maps were examined for the area between 47°- 48° north latitude and 103°- 104° west longitude (northern Billings and Golden Valley Counties, and western McKenzie County, North Dakota) in an attempt to identify large-scale fracture trends.
Abstract: Fractures play a critical role in oil production from the Bakken Formation (Devonian-Mississippian) in the North Dakota portion of the Williston Basin. The Bakken Formation in the study area is known for its low matrix porosity and permeability, high organic content, thermal maturity, and relative lateral homogeneity. Core analysis has shown the effective porosity and permeability development within the Bakken Formation is primarily related to fracturing. In theory, lineaments mapped on the surface reflect the geometry of basement blocks and the zones of fracturing propagated upward. Fracturing in the Williston Basin is thought to have occurred along reactivated basement-block boundaries in response to varying tectonic stresses and crustal flexure throughout the Phanerozoic. Landsat-derived lineament maps were examined for the area between 47°- 48° north latitude and 103°- 104° west longitude (northern Billings and Golden Valley Counties, and western McKenzie County, North Dakota) in an attempt to identify large-scale fracture trends. In the absence of major tectonic deformation in the craton, a subtle pattern of fracturing has propagated upward through the sedimentary cover and emerged as linear topographic features visible on these large-scale, remote-sensed images. The association of Landsat-derived lineaments and fracture density in the subsurface is demonstrated by a statistically significant relation between proximity of wells to lineament traces and the percentage of drill stem test shut-in pressures indicating fracturing. A statistically significant relation is also identified between Bakken thickness and fracture density.