Showing papers on "Petroleum reservoir published in 1995"

Effect of Faulting on Fluid Flow in Porous Sandstones: Geometry and Spatial Distribution

Abstract: We present a methodology to describe fault geometry at different scales and to characterize the distribution of these scales on the flanks of a salt intrusion in the Colorado Plateau (Arches National Park, United States). This methodology is based on the recognition of the physical processes of faulting and on the quantitative characterization of the structural and petrophysical properties of faults in porous sandstones. The methods used include a variety of mapping techniques (photography, aerial photography, string mapping, theodolite surveys, etc.), as well as techniques for determining fluid flow properties. The resulting study is a prototype for understanding seismic and subseismic scales of heterogeneity related to faulting and fracturing in subsurface reservoirs. > Faulting in porous sandstones on the flanks of the salt intrusion is developed at different stages, from simple deformation bands (1-20 mm shear offset) to slip planes (>1 m shear offset) and complex fault zones. We document that deformation-band outcrop geometry is characterized by a sinuous anastomosing pattern resulting from the linkage of quasitabular segments via ramp or "eye" structures. These connecting structures recur at different scales and provide lateral continuity of the deformation bands; therefore, deformation bands have good geometric sealing characteristics. Slip planes, which are not interconnected, may have poor geometric sealing characteristics. In the hanging wall of a major normal fault, the quantitative spatial distribution of the faults can be correlated with bending of the strata, probably associated with the salt intrusion. The number of deformation bands, the most ubiquitous element, is proportional to the amount of slip on a single major fault. Deformation bands also have a very high density (>100 m-1) in stepovers between slip planes. In these areas we find the largest anomalies in permeability. In zones of high strata curvature, the average layer-parallel permeability can drop one to two orders of magnitude with respect to the host rock; if complex fault zones are present, the average permeability can drop more than four orders of magnitude in the direction normal to the faults. Finally, by using outcrop and laboratory data that describe the effect of distinctive structural units on fluid flow, we quantify the three-dimensional distribution of permeability in a reservoir analog at any scale, and we show that such permeability distribution could be implemented in a geology-based reservoir simulator.

Design and Development of An Artificial Neural Network for Estimation of Formation Permeability

Abstract: Permeability is one of the most important characteristics of hydrocarbon-bearing formations and one of the most important pieces of information in the design and management of enhanced recovery operations. With accurate knowledge of permeability, petroleum engineers can manage the production process of a field efficiently. Although formation permeability is often measured in the laboratory from cores or evaluated from well-test data, core analysis and well-test data are only available from a few wells in a field, while the majority of wells are logged. In this study, the authors have designed an artificial neural network that can accurately predict the permeability of the formations by use of the data provided by geophysical well logs. Artificial neural network, a biologically inspired computing method which has an ability to learn, self-adjust, and be trained, provides a powerful tool in solving pattern recognition problems.

Basin-Floor Fans in the North Sea: Sequence Stratigraphic Models vs. Sedimentary Facies

Abstract: Examination of nearly 12,000 ft (3658 m) of conventional core from Paleogene and Cretaceous deep-water sandstone reservoirs cored in 50 wells in 10 different areas or fields in the North Sea and adjacent regions reveals that these reservoirs are predominantly composed of mass-transport deposits, mainly sandy slumps and sandy debris flows. Classic turbidites are extremely rare and comprise less than 1% of all cores. Sedimentary features indicating slump and debris-flow origin include sand units with sharp upper contacts; slump folds; discordant, steeply dipping layers (up to 60°); glide planes; shear zones; brecciated clasts; clastic injections; floating mudstone clasts; planar clast fabric; inverse grading of clasts; and moderate-to-high matrix content (5-30%). Many f the cored reservoirs either have been previously interpreted as basin-floor fans or exhibit seismic (e.g., mounded forms) and wireline-log signatures (e.g., blocky motif) and stratal relationships (e.g., downlap onto sequence boundary) indicating basin-floor fans within a sequence stratigraphic framework. This model predicts that basin-floor fans are predominantly composed of sand-rich turbidites with laterally extensive, sheetlike geometries. However, calibration of sedimentary facies in our long (400-700 ft) cores with seismic and wireline-log signatures through several of these basin-floor fans (including the Gryphon-Forth, Frigg, and Faeroe areas) shows that these features are actually composed almost exclusively of mass-transport deposits consisting mainly of slumps and debris flo s. Distinguishing deposits of mass-transport processes, such as debris flows, from those of turbidity currents has important implications for predicting reservoir geometry. Debris flows, which have plastic flow rheology, can form discontinuous, disconnected sand bodies that are harder to delineate and less economical to develop than deposits of fluidal turbidity currents, which potentially produce more laterally continuous, interconnected sand bodies. Our core studies thus underscore the complexities of deep-water depositional systems and indicate that model-driven interpretation of remotely sensed data (i.e., seismic and wireline logs) to predict specific sedimentary facies and depositional features should proceed with caution. Process sedimentological interpretation of conventional cor is commonly critical for determining the true origin and distribution of reservoir sands.

Dolomite Reservoirs: Porosity Evolution and Reservoir Characteristics

Abstract: Systematic analyses of the published record of dolomite reservoirs worldwide reveal that the majority of hydrocarbon-producing dolomite reservoirs occurs in (1) peritidal-dominated carbonate, (2) subtidal carbonate associated with evaporitic tidal flat/lagoon, (3) subtidal carbonate associated with basinal evaporite, and (4) nonevaporitic carbonate sequence associated with topographic high/unconformity, platform-margin buildup or fault/fracture. Reservoir characteristics vary greatly from one dolomite type to another depending upon the original sediment fabric, the mechanism by which dolomite was formed, and the extent to which early formed dolomite was modified by postdolomitization diagenetic processes (e.g., karstification, fracturing, and burial corrosion). This paper discusses the origin of dolomite porosity and demonstrates the porosity evolution and reservoir characteristics of different dolomite types.

Facies Variation, Diagenesis, and Exploration Potential of the Cretaceous Rudist-Bearing Carbonates of the Arabian Gulf

Abstract: The Cretaceous rudist-bearing carbonates of the Arabian Gulf region are proven exploration targets for hydrocarbons and form the reservoirs of a number of giant fields, including Bu Hasa, Fateh, Fahud, Idd El Shargi, Rumaila, Shaybah, and Shah. Rudist buildups occur in three principal formations: (1) Aptian Shuaiba, (2) Cenomanian Mishrif, and (3) Maastrichtian Simsima. A regional subaerial unconformity marks the upper boundary of each of these formations. Associated with the rudists that dominate the Shuaiba Formation are calcareous algal crusts, foraminifera, and echinoid plates, which accumulated in mudstone, packstone, and carbonate sands. These rudists are mainly caprinids, with a lesser number of caprotinids, monopleurids, and requienids, deposited in a normal-marine shallow-shelf setting. The Mishrif Formation contains mollusk fragments, bioclastic packstones to grainstones, miliolid and nonrudist bivalves in muddy limestones, and rudist (mainly radiolitids and caprinids) conglomeratic floatstones, with fragmented rudists mixed with wackestone lithoclasts. The Mishrif sediments accumulated as a progradational, low-energy leeward margin formed in marginal slope, shoal-backshoal, and lagoonal settings. The Simsima Formation consists of bioclastic grainstone to packstone, and dolomitic lime mudstones to wackestone. These are rich in bioclastic grains (Loftusia, rudist and rudist debris, coral, and foraminifera) deposited on a restricted to semirestricted shallow-marine shelf that was exposed to moderate energy conditions. The excellent reservoir porosity and permeability of the rudist deposits and their associated sediments are the products of primary and secondary diagenesis. Freshwater leaching during post-Aptian, post-Cenomanian, and post-Maastrichtian erosion enhanced the secondary moldic porosity. Fracturing locally improved porosity and permeability. Other porosity types that occur include interparticle, intraparticle, vuggy, growth framework, shelter, intercrystalline, and karstic. Because of their favorable depositional and postdepositional conditions, the Cretaceous succession of rudists in this region contains many giant oil fields.

Exploration trends of the Halten Terrace

Abstract: The Halten Terrace is a broad fault terrace located between the Trondelag Platform and the More Basin on the mid-Norwegian continental shelf (64°–65°3′N). The terrace contains a normal faulted pre-rift sequence draped by a syn-rift sequence of variable thickness and a thick post-rift sequence. The hydrocarbon plays are due to the occurrence of mature Early Jurassic coal-bearing gas-condensate source rock and the Late Jurassic Spekk Formation oil source rock. Three plays can be recognized. The pre-rift play covers a northeastern fairway which contains a number of commercial fields, and is characterized by a hydrostatic reservoir pressure or low-grade overpressure. To the west the reservoir sequence is deeper buried, greatly overpressured and exploration has so far been unsuccessful. The play is widely explored but there still remain large, high-risk gas prospects in the overpressured Halten West area. The syn-rift play reservoirs are thought to be present in submarine fan systems on the hanging-wall blocks of the Vingleia Fault Zone, which received erosion products from the uplifted Froya High to the south. Shallow marine shoreline and offshore bar sands are present on the major tilted footwall blocks along the edge of the Froya High (Draugen-Rogn Formation) and along the edge of the Sklinna High. The play is in its early exploration phase and the oil potential is considerable. The post-rift play relies on stratigraphic trapping in post-rift, Lange, Lysing and Nise sands on the Sklinna Saddle and in the Grinna Graben, where the sands may have been distributed further southwest from the uplifted and truncated Nordland Ridge. A thin Lysing Formation is oil-bearing in the Smorbukk Sor area. The stratigraphic trap potential of the post-rift play has not yet been tested and the play is thought to have a considerable oil potential. Exploration in the early and mid 1980's was focused on structural traps of the pre-rift play, which has yielded all the commercial fields except Draugen. Recent exploration is directed towards the oil potential of stratigraphic traps of the syn-rift and the post-rift plays and small pre-rift prospects in the vicinity of future production facilities.

Effect of Rock Heterogeneity on Relative Permeability: Implications for Scale-up

Abstract: Relative permeability and capillary pressure are important parameters in reservoir engineering calculations and numerical simulation of reservoir performance. Heterogeneities are often avoided during core-plug screening and selection for relative permeability and capillary pressure measurements. However, sandstone rocks in many depositional environments show significant small-scale laminations that affect the measured relative permeability. This report demonstrates the length-scale dependence of relative permeability data that results from centimeter- to millimeter-scale rock laminations and patterns of initial and final oil-saturation distribution in laminated core. It shows quantitatively the capillary trapping of water in low-permeability laminae during primary drainage and of oil in high-permeability laminae during water imbibition. Steady-state water/oil imbibition relative permeability data and unsteady-state drainage and imbibition data were collected with linear X-ray and X-ray CT scanning for in-situ fluid-saturation measurement. Numerical simulations of the corefloods show that relative permeabilities and capillary pressures that are correlated with small-scale differences in porosity and permeability are necessary to reproduce the observed saturation distributions. Thus, the relative permeability length-scale dependence, combined with anisotropy data, implies that scaled-up effective relative permeability must account properly forheterogeneity. Assignmentof core-plug relative permeability to simulator gridblocks may not capture the correct effective fluid flow performance in rocks that are heterogeneous with correlation length greater than the plug dimensions, leading to erroneous fluid flow performance predictions.

Reservoir Characterization of the Hollin and Napo Formations, Western Oriente Basin, Ecuador

Abstract: The Oriente basin of Ecuador has produced a substantial amount of oil over the past 20 years. Nearly 3 billion bbl of oil have been recovered from the principal reservoirs in the Cretaceous Napo and Hollin formations. Subtle north-south structures, commonly associated with Andean-related faulting, have trapped much of the recoverable hydrocarbons in the thicker sandstones deposited within the Hollin and Napo reservoirs. East to west thinning of these reservoir units also contributes to the formation of stratigraphic traps. Both the Hollin and Napo formations comprise successions of eastward-sourced fluvial and deltaic sedimentary deposits that prograded westward into shoreline and marine shelf parasequences. The Albian Hollin reservoir interval consists of a dominant alluvial plain sandstone sequence (Main Hollin sandstone) that occupies much of the Oriente basin. In the western Oriente, the uppermost Hollin section grades vertically into open marine strata with isolated tidal- and storm-influenced sandstone bodies. The overlying Napo stratigraphy also consists of sand-rich fluvial and deltaic deposits in the eastern Oriente and abruptly changes to marine shales and limestones and lowstand valley-fill sandstones in the western part of the basin. Extensive structural and stratigraphic trap potential remains within the Napo and Hollin strata in the Oriente basin. High-resolution geophysical techniques and detailed geologic reservoir characterization facilitate successful exploitation of these remaining reserves.

Stratigraphic Architecture of the Tonganoxie Paleovalley Fill (Lower Virgilian) in Northeastern Kansas

Abstract: Lower Pennsylvanian paleovalley-confined sandstones are important petroleum reservoirs in the Midwest. In Kansas, such reservoirs have produced approximately 220 million bbl of oil and 1.7 tcf of gas. Valley-fill successions tend to become muddy upward, but there can be considerable local heterogeneity in which reservoir sandstones pass laterally into muddy sandstones or nonreservoir shales. The lack of understanding of this reservoir heterogeneity can lead to low drilling success rates. The Tonganoxie paleovalley (Upper Pennsylvanian, northeastern Kansas) contains facies very similar to Lower Pennsylvanian (Morrowan) valley fills, and can provide an outcrop- and subsurface-based model of sandstone deposition. The Tonganoxie paleovalley was incised during lowered sea level and filled during the subsequent transgression. The main paleovalley is approximately 41 m deep, 11 km wide, and 240 km long, and was fed by 1-km-wide tributary valleys oriented roughly normal to the trunk valley. Sandstones occur in four distinct architectural elements that were deposited during different phases of transgression. Type I sandstone consists of a belt of sandstone and conglomerate 3-18 m thick and confined to the trunk valley and wider portions of tributary valleys. Type I sandstone consists of amalgamated channel fills, has little or no mud, and has the highest porosity and permeability. The type I sandstone is overlain by estuarine deposits of sandstone (type II sandstones), rippled argillaceous sandstone to sandy mudstone, and coal. Most of the paleovalley was filled during this stage. The type II sandstones are narrow (1.5 km wide) arcuate bodies up to 8 km long and were likely deposited in tidal point bars near the fluvial to tidal transition, are either isolated sandstone bodies or are incised into type I sandstone. The higher mud content is expected to reduce porosity and permeability compared to fluvial facies. Type III sandstone bodies occur at the upstream limits of narrow tributaries and are probably bay-head deltas. Well logs indicate a range of mud content. Type IV sandstone is a thin (3 m) discontinuous sheet of marine sandstone deposited after most of the paleovalley had been filled.

Three-Dimensional Distribution of Lithofacies, Bounding Surfaces, Porosity, and Permeability in a Fluvial Sandstone--Gypsy Sandstone of Northern Oklahoma

Abstract: Where it was studied at two sites in north-central Oklahoma, the Gypsy sandstone of the Pennsylvanian Vamoosa Formation provides significant insights into the controls on reservoir quality in a meandering river deposit. At an outcrop site west of Tulsa, a three-dimensional architectural framework, based on erosional surfaces, allowed the recognition of a channel-fill sequence consisting of six channel sand bodies and representing at least three channel belts. Belts are vertically stacked and are incompletely separated by low-permeability flood-plain deposits, which are locally eroded. Porosity and permeability are primarily related to depositional facies. Within channel belts, mudclast lags associated with erosion surfaces at the base of channels have the potential to act as vertical permeability baffles between channel sand bodies, as do mud-draped lateral accretion surfaces within channel sand bodies. At a subsurface site 31 km (19 mi) to the west of the outcrop site, nine wells were drilled and cored through the Gypsy interval. At this site, it was possible to identify and correlate three channel belts comprising amalgamated channel sand bodies. Although lower level architectural elements could be recognized in cores, they could not be correlated with confidence given a 100-m (330-ft) well spacing.

Pore Size and Pore Throat Types in a Heterogeneous Dolostone Reservoir, Devonian Grosmont Formation, Western Canada Sedimentary Basin

Abstract: The Devonian Grosmont Formation in northeastern Alberta, Canada, is a giant heavy-oil reservoir. The main reservoir rocks are dolomitized and karstified platform and ramp carbonates, and the best reservoir facies occur in the upper Grosmont (UGM) units 3 and 2. In these units, reservoir properties are highly heterogeneous. Hand specimen, thin section, UV, and SEM petrography, as well as grading scales, mercury capillary pressure curve analysis, and statistics, have been used to characterize reservoir heterogeneity. Our investigation led to a new pore size classification for carbonate reservoirs; this new classification has four pore sizes: microporosity (pore diameters 256 mm). A combination of microscopic observations and capillary pressure curve characteristics led to the recognition of four pore throat texture types on the microporosity scale, and to five types on the mesoporosity scale. Microporosity pore types include (1) intracrystal dissolution porosity, (2) pervasive intercrystal and intracrystal dissolution porosity, (3) intergranular and/or intercrystal porosity in grainstones, and (4) primary or solution microporosity in mud matrix (only in limestones). Mesoporosity pore types include (1) intercrystal porosity, (2) solution-enhanced intercrystal porosity, (3) oversized porosity, (4) intragranular solution porosity, and (5) intergranular solution porosity. Some of these types are homogeneous (e.g., non-fabric selective dissolution porosity and inte crystal primary porosity), whereas others are heterogeneous. Generally, hydrocarbon recovery efficiency is good in the homogeneous pore throat types, but poor in the heterogeneous types. Reservoir heterogeneity has further been characterized by comparison and statistical analysis of plug and full-diameter core (FDC) data that indicate (1) plug porosities, on average, are higher than FDC porosities; (2) plug permeabilities, on average, are higher than FDC permeabilities; (3) plug porosity and permeability show relatively good linear relationships in certain core intervals, but FDC data do not; and (4) generally, the more homogeneous reservoir rocks have relatively high matrix porosity. Heterogeneity is common in Grosmont dolostone reservoir rocks, and affects overall reservoir quality. At the megascopic scale, the reservoir properties can be classified as homogeneous, dual-porosity, and multilayered. The dual-porosity model has three subcategories: fractured, channeled, and pressure solution derived.

Mapping distribution of fractures in a reservoir with P-S converted waves

Abstract: Where reservoir rock is very impermeable (limestones, cherts, dolomite, etc.), fractures may provide all or most of its porosity and effective permeability. Studies of producing oil wells in fractured limestones have determined a single fracture of width 1 mm, under favorable reservoir conditions, can provide sufficient permeability to yield over 1500 m3 (240 bbl) of oil per day. Consequently, mapping locations of high intensity fractures and determining their orientation/lateral extent could be of great value in reservoir development, especially for locating horizontal well sites.

4-D seismic monitoring of an active steamflood

Abstract: Multiple 3-D seismic surveys have been acquired at time-lapse intervals over a heavy oil reservoir in the Dud Field, Indonesia, to monitor the progress of an active steamflood. Time-lapse 3-D seismic images show dramatic and complex changes in the reservoir zone over a wide area, compared to baseline seismic data recorded prior to steam injection. Careful consideration of steamflood fluid-flow, rock physics measurements, finite-difference seismogram modeling, 3-D seismic imaging and velocity analysis leads to an integrated interpretation of this 4-D data set. Anticipated large decreases in seismic P-wave velocity near the injection well correlate with the presence of a hot steam-saturated zone. Unanticipated large velocity increases and reflectivity changes in an annulus around the steam zone are consistent with a transient high-pressure front, in which initial free gas in pore space is raised above the bubble point pressure and dissolves into liquid oil. Horizontal and vertical anisotropy in flow directions inferred from these seismic observations correlate with two temperature monitor wells, and in situ measurements of upper and lower reservoir permeability. Since the pressure front propagates out from the injector at least one order of magnitude faster than either the thermal or steam fronts, monitoring it may be useful formore » predicting flowpaths of heated oil and steam, months in advance.« less

Geologic Evolution of a Pliocene-Pleistocene Salt-Withdrawal Minibasin: Eugene Island Block 330, Offshore Louisiana

Abstract: The spatial and temporal distributions of reservoir sands are documented within the context of an evolving Pliocene-Pleistocene salt-withdrawal shelf minibasin. The Eugene Island Block 330 field, a giant oil and gas field in offshore Louisiana, is contained within the minibasin. Based on the stratigraphic and structural analyses, we present a sequence-stratigraphic and tectonic-stratigraphic model for reservoir prediction in complex shelf Gulf of Mexico minibasins. The minibasin evolved in three phases: prodelta, proximal deltaic, and fluvial. In the prodelta phase, bathyal and outer neritic shales and turbidites loaded and mobilized an underlying salt sheet. During the proximal deltaic phase, salt continued to withdraw from beneath the minibasin, and lowstand shelf margin deltas remained at a regional fault zone on the northern margin of the minibasin. Sediment accumulation and fault slip rates were high as thick sequences of deltaic sands were deposited adjacent to the fault system. During the final fluvial phase, salt withdrawal waned; consequently, the creation of accommodation space within the minibasin ceased. The basin infilled and, during lowstands, deltaic systems prograded southward. Unconformities developed in the minibasin during the e lowstands. During transgressions, thick packages of shallow-water deltaic and fluvial sands (capped by shales) were deposited on top of the unconformities. One major reservoir, the Lentic, was deposited during the prodelta phase. The hydrocarbons are trapped by deep early faults within this geopressured sand. Most of the major exploited reservoirs of the Block 330 field were deposited in the proximal deltaic phase. Reservoirs deposited in this phase are laterally extensive proximal deltaic sands that have good lateral seals because of the amount of fault activity that occurred in this interval. Only one major reservoir was deposited in the fluvial phase. This reservoir was deposited while the basin-bounding faults were still active, so the reservoir has four-way closure. Sands deposited later in the fluvial phase tend to lack lateral seals and structural closure.

Depositional Setting, Sequence Stratigraphy, Diagenesis, and Reservoir Potential of a Mixed-Lithology, Upwelling Deposit: Upper Triassic Shublik Formation, Prudhoe Bay, Alaska

Abstract: The Upper Triassic Shublik Formation within the Prudhoe Bay field unit, North Slope, Alaska, is a potentially economic hydrocarbon reservoir comprised of mixed lithology and mineralogy. Its composition includes limestone, phosphate, shale, siltstone, and sandstone, as well as accessory amounts of siderite, glauconite, pyrite, kaolinite, and dolomite. Within the Prudhoe Bay field unit, the Shublik has been subdivided into four zones, lettered from base to top, D through A, which become thinner and show evidence of deposition under higher energy conditions toward the northeast. The formation is truncated to the east by the regional Lower Cretaceous unconformity. Zones within the Shublik comprise a basal transgressive systems tract (conglomerate lag at the Shublik Formation/Ivishak Formation contact through basal zone C shales) and two highstand shallowing-upward parasequences (zones C through B, and zone A, respectively). The parasequences are bounded by shales interpreted to represent deposition during periods of marine flooding. The contact between the Shublik and the overlying Sag River Formation juxtaposes comparatively deeper marine Shublik with shallower water glauconitic sandstones of the Sag River Formation. The contact is unconformable and is interpreted to represent a regional sequence boundary. Lithofacies of the Shublik are interpreted to have been coeval depositional facies of an upwelling system. Relative sea level changes durin Shublik deposition are interpreted to have caused the observed vertical and lateral variability in lithofacies via systematic changes between anaerobic, dysaerobic, and aerobic upwelling conditions. Dissolution of carbonate allochems resulted in the creation of moldic porosity that positively affected reservoir quality (i.e., permeability) in the carbonate packstone/grainstone facies. Areas of highest porosity are in the northern and northeastern parts of the field, which correspond to a combination of facies-controlled reservoir quality improvement toward the northeast and carbonate dissolution along the Lower Cretaceous unconformity and the North Prudhoe Bay fault zone. Oil in place for the Shublik within the Prudhoe Bay unit is estimated to be between 250 and 500 million bbl. Although permeabilities are generally low throughout the field area, the Shublik Formation has the potential to add significant reserves to the Prudhoe Bay field unit.

Controls on porosity evolution in Thamama Group carbonate reservoirs in Abu Dhabi, U.A.E.

Abstract: The multiple Lower Cretaceous carbonate reservoirs found throughout Abu Dhabi display pronounced lateral heterogeneities in porosity, permeability, and reservoir thickness. Generally, these variables decrease away from the crests of producing anticlines. Detailed study of the Kharaib Fm. in one of these fields has found that pressure solution along stylolites, with concurrent local reprecipitation of calcite cements, is these major process by which reservoir quality has been degraded. Lateral variations in reservoir quality are largely controlled by stylolite frequency and intensify. No significant variations in depositional facies accompany this change. Marked discontinuities in plots of subsea depth versus porosity and reservoir thickness suggests that differences in pore fluids during burial controlled the degree of chemical compaction, with stylolites preferentially forming in the water leg and inhibited in the oil leg. This discontinuity is more pronounced when subsea sections ar re-datummed on the Halul Fm., and is interpreted to reflect a Santonian-age ``paleo`` oil-water contact (OWC). Stylolite-degraded porosity in the oil leg of the northern part of the field can be explained by later southward tilting of the reservoirs during the Campanian. Migration of hydrocarbons prior to stylolitization is consistent with calculated thermal histories for the field, and suggests the bulk ofmore » stylolitization commenced after 2,000 ft of burial at temperatures of approximately 150 F. Delineating the ``paleo`` OWC allows for improved prediction of porosity and permeability, and accounts for almost all of the observed variation in reservoir quality.« less

Diffusion of Methane and Ethane Through the Reservoir Cap Rock: Implications For the Timing and Duration of Catagenesis

Abstract: To maintain natural gas reserves for even short periods of geologic time, there must be an influx of gas to the reservoir to balance any loss. Because molecular diffusion through the reservoir cap rock is generally regarded as the slowest loss mechanism, the minimum influx rate necessary to maintain the reserves is the same as the diffusive loss rate. Fick's first law of diffusion, modified with the Stokes-Einstein relation and the Archie equation, provides a conservative estimate for the rate of diffusion through a porous medium, such as the reservoir cap rock. As an example, the diffusive flux of methane and ethane through the cap rock of the McClave field in southeastern Colorado was calculated. Assuming a shale cap rock porosity of only 5%, the entire volume of methane would have to be replaced in less than 2.3 m.y., and 5.3 m.y. for ethane, to maintain the reserves. Using 10% porosity, the replacement time falls to less than 500,000 yr for methane and 1.2 m.y. for ethane. Unless natural gas fields are short-lived ephemeral phenomena, there must be ongoing generation and migration of gas to the reservoir to at least balance the diffusional loss. This balance requires that catagenesis be an ongoing and recent phenomenon.

Stratigraphy and sedimentation of the Unayzah reservoir, central Saudi Arabia

Abstract: Significant reserves of Arabian super light oil, condensate, and associated gas occur in the various genetically different sandstone bodies of the upper Permian Unayzah and Khuff Formations in Central Saudi Arabia. The Unayzah Formation which rests unconformably on the older formations is composed of red colored, poorly sorted conglomerate, sandstone, siltstone, mudstone, caliche and nodular anhydrite. Facies changes occur due to the presence of various subenvironments and possible faulting and structural growth in the basin during deposition. However, the entire Unayzah Formation shows an overall fining and thinning-upward sequence. It was deposited as coalescing alluvial fans dominated by braided streams which graded into meandering stream and playa lakes under and to semi-arid conditions. Eolian processes were also inferred. A marked unconformity which is indicated by the occurrence of thick caliche and soil horizons separate the Unayzah and the overlying Khuff Formation. The Khuff Formation consists primarily of marine shale, marl, and fine- to very coarse-grained sandstones in the lower parts; shale, limestone, dolomite, and amhydrite in the upper parts. The sandstones were deposited as incised channel fills and their associated low stand deltaic sediments as a result of fluctuating sea level during the deposition of the Khuff Formation. The basemore » of the incised channels represent a sequence boundary. Red colored and rooted paleosols were formed on the underlying marine sediments. During relative sea level rise, good quality reservoir sands were deposited by aggradation within the incised channels. Sand deposition within the channels terminated at the same time, and the area was covered by shallow marine limestones, shales and marls during maximum sea level highstand. Although the Unayzah reservoir occurs in both the Unayzah and the Khuff Formations because of their different geometry, continuity, and reservoir quality, they have been studied separately.« less

Gas/Oil Capillary Pressure of Chalk at Elevated Pressures

Abstract: Accurate capillary pressure curves are essential for studying the recovery of oil by gas injection in naturally fractured chalk reservoirs. A simple and fast method to determine high-pressure drainage capillary pressure curves has been developed. The effect of gas/oil interfacial tension (IFT) on the capillary pressure of chalk cores has been determined for a methane/n-pentane system. Measurements on a 5-md outcrop chalk core were made at pressures of 70, 105, and 130 bar, with corresponding IFT`s of 6.3, 3.2, and 1.5 mN/m. The results were both accurate and reproducible. The measured capillary pressure curves were not a linear function of IFT when compared with low-pressure centrifuge data. Measured capillary pressures were considerably lower than IFT-scaled centrifuge data. It appears that the deviation starts at an IFT of about 5 mN/m. According to the results of this study, the recovery of oil by gravity drainage in naturally fractured chalk reservoirs may be significantly underestimated if standard laboratory capillary pressure curves are scaled by IFT only. However, general conclusions cannot be made on the basis on only this series of experiments on one chalk core.

Sedimentology, Diagenesis, and Oil Habitat of Lower Cretaceous Qamchuqa Group, Northern Iraq

Abstract: The Zagros basin (Iraq) constitutes a rich petroleum province. The Lower Cretaceous Qamchuqa Group comprises one of its major reservoirs. Data from about 30 wells, drilled in a limited sector corresponding to a northwest-southeast anticlinal structure situated in the Kirkuk region, permit analysis of several sedimentological and diagenetic events that led to the formation of this reservoir. Facies changes took place and divided the structure into three parts: the northwestern part in which neritic facies dominate, the central part in which basinal influence is considerable, and the southeastern part that shows basinal mudstone-type facies. The Lower Cretaceous carbonate platform in the northwestern part of the study area displays good primary porosity. During the course of burial, high secondary porosity related to dolomitization appeared. However, a major part of the porosity was produced when the reservoir was fractured during the Priabonian after the collision between the Arabian and Eurasian plates. Lopatin's method suggests that organic matter maturation started during the Turonian (around 90 Ma), whereas most of the maturation developed during the Miocene due to the rapid accumulation of foreland basin sediments containing evaporite facies (lower Fars Formation) followed by the accumulation of thick upper molasse-type sediments from the erosion of the Zagros Mountains. The accumulation of sediments enhanced the total tectonic subsidence. During this period, the relatively brief time spent by the source rock in a given temperature interval was compensated for by a rapid rise in temperature. This late thermal maturation period controlled most of the transformation of the organic matter into hydrocarbons.

Gas Reservoir Potential of the Lower Ordovician Beekmantown Group, Quebec Lowlands, Canada

Abstract: The Beekmantown Group in the Quebec Lowlands was deposited as part of an extensive Early Ordovician coastal and shallow marine complex on the eastern margin of the North American craton. The Beekmantown is stratigraphically equivalent to the Beekmantown, Knox, Arbuckle, and Ellenburger rocks of the United States, and is subdivided into two formations: the sandstone-rich Theresa Formation and the overlying dolomite-rich Beauharnois. Dolomites of the Beekmantown provide an important exploration target in both the autochthon and the overlying thrust sheets of the Canadian and U.S. Appalachians. The reservoir potential of the autochthonous Beekmantown Group in the Quebec Lowlands can be determined from seismic data, well logs, cuttings, and petrographic analyses of depositional and diagenetic textures. Deposition of the Beekmantown occurred along the western passive margin of the Iapetus Ocean. By the Late Ordovician, the passive margin had been transformed into a foreland basin. Faulting locally positioned Upper Ordovician Utica source rocks against the Beekmantown and contributed to forming hydrocarbon reservoirs. The largest Beekmantown reservoir found to date is the St. Flavien field, with 7.75 bcf of original gas (methane) in place in fractured and possibly karst-influenced allochthonous dolomites within a thrust-fault anticline. The Beekmantown below the thrust sheets forms a northward-thinning wedge of peritidal and subtidal deposits. Seven major depositional units can be distinguished in cuttings and correlated with wireline logs. Most of these units form northward-thinning sediment wedges and were deposited on a gently dipping ramp. Quartz sandstones dominate updip, whereas shallow, subtidal, pelletal to skeletal limestones dominate downdip. A widespread blanket of shaly dolomite is the uppermost unit of the Beekmantown, but is of poor reservoir quality. Dolomites in the Beekmantown contain vuggy, moldic, intercrystalline, and fracture porosity. Early porosity formed at the top of the major depositional units in peritidal dolomites; however, much of this porosity was later filled by late-stage calcite cement after hydrocarbon migration. Thus, a key to finding gas reservoirs in the autochthonous Beekmantown is to define Ordovician paleostructures in which early and continuous entrapment of hydrocarbons prevented later cementation.

Controls on Reservoir Development in Devonian Chert: Permian Basin, Texas

Abstract: Chert reservoirs of the Lower Devonian Thirty-one Formation contain a significant portion of the hydrocarbon resource in the Permian basin. More than 700 million bbl of oil have been produced from these rocks, and an equivalent amount of mobile oil remains. Effective exploitation of this sizable remaining resource, however, demands a comprehensive appreciation of the complex factors that have contributed to reservoir development. Analysis of Thirtyone Formation chert deposits in Three Bar field and elsewhere in the Permian basin indicates that reservoirs display substantial heterogeneity resulting from depositional, diagenetic, and structural processes. Large-scale reservoir geometries and finer scale, intra-reservoir heterogeneity are primarily attributable to original depositional processes. These cherts, which were deposited by relatively deep-water sediment gravity processes along a north-trending depocenter, exhibit relatively continuous stratal geometries in northern, more proximal parts of the depocenter and more discontinuous geometries in the center of the depocenter. Despite facies variations, porosity development in these cherts is principally a result of variations in rates and products of early si ica diagenesis. Because this diagenesis was in part a function of depositional facies architecture, porosity development follows original depositional patterns. In reservoirs such as Three Bar field, where the Thirtyone Formation has been unroofed by Pennsylvanian deformation, meteoric diagenesis has created additional heterogeneity by causing dissolution of chert and carbonate, especially in areas of higher density fracturing and faulting and along truncated reservoir margins. Structural deformation also has exerted direct controls on heterogeneity that are particularly noteworthy in reservoirs under waterflood. High-density fracture zones create preferred flow paths that result in nonuniform sweep through the reservoir. Faulting locally creates compartments by offsetting reservoir flow units. Three Bar field exhibits many of the major styles of heterogeneity that contribute to inefficient recovery in the Thirtyone Formation. As such, the processes and models defined here improve understanding of the causes of heterogeneity in all Thirtyone chert reservoirs in the Permian basin and aid recovery of the sizable hydrocarbon resource remaining in these rocks.

H2S-Related Porosity and Sulfuric Acid Oil-Field Karst

Abstract: "H2S-related porosity" refers to porosity created in a H2S system where dissolution can be produced by the mixing of waters of different H2S content or by the oxidation of H2S. "Sulfuric acid oil-field karst" refers to a specific kind of H2S-related porosity where carbonate reservoirs of cavernous size have been dissolved by a sulfuric acid mechanism. In a H2S system, porosity can be produced entirely in the deep subsurface and does not have to represent a paleokarst surface or dissolution in the shallow-phreatic or vadose zones. H2S-related porosity is characterized by the large volume of hydrocarbons it can host, by extensive fracture permeability interconnected with "spongework" cavities or caves of tens to hundreds of meters in extent, by porosity related to structural and/or stratigraphic traps, and by the presence of high uranium and/or iron. Possible examples of H2S-generated porosity systems are the Lisburne field, Prudhoe Bay, Alaska, and some of the extremely productive fields of the Middle East.

KGEOFLOW: A new reactive transport simulator for sandstone matrix acidizing

Abstract: This paper reports on the first modeling of sandstone matrix acidization using a comprehensive geochemical simulator based on the partial local equilibrium assumption. This new model allows any combination of kinetic and equilibrium reactions involving any number of chemical species, which greatly increases the simulator's predictive abilities compared to existing sandstone acidizing models. The new simulator, KGEOFLOW, which is applicable to a variety of reactive transport processes in petroleum reservoirs, is used to predict optimal acid injection rates based on the amount of mineral dissolution and precipitation.

Upper Triassic-Lower Jurassic reservoir rocks in the Tampen Spur area, Norwegian North Sea

Abstract: Alluvial sandstones of Late Triassic to Early Jurassic age form prominent reservoir rocks in the Statfjord, Snorre, Gullfaks, Gullfaks Sor and Visund fields of the Tampen Spur area. The Rhaetian-Sinemurian Statfjord Formation is a major oil reservoir in all fields. The Lunde Formation is the principal oil reservoir in the Snorre Field and is an important gas reservoir in the Gullfaks Sor and Visund fields. The underlying Lomvi Formation and the sand-rich parts of the Teist Formation are the reservoirs of potential play types. In all fields the hydrocarbons are trapped within crest segments of rotated fault blocks that are eroded to various depths and capped by Lower Jurassic to Cretaceous mudstones and shales. Faults and fractures cut and complicate the reservoirs, especially in the east flank of the Statfjord Field and in the Gullfaks and Gullfaks Sor fields. In the Tampen Spur area, the Triassic to Early Jurassic rocks are up to 2500 m thick. The succession was deposited within a wide alluvial plain during the thermal subsidence phase subsequent to Permian-Early Triassic rifting. Channel and channel belt sandstone bodies interchange with floodplain mudstones and nonchannelized sandstones. Five main types of stream systems are suggested to explain the variation in facies association, geometry and dimension of sandstone bodies. The depositional architecture has been controlled by the interaction of base-level changes and variation in rate of sediment input, besides autocyclic processes. The Triassic-Lower Jurassic reservoir rocks are heterogeneous from a field-wide scale to a microscopic scale. Permeability and porosity reflect sedimentary facies and textural variations modified by diagenesis. A major challenge in the reservoir characterization of these rocks is to model the 3D geometry of the fluvial sandstone bodies and make reliable well-to-well correlations. Stochastic as well as descriptive modelling have been used in the reservoir description. Data obtained from outcrop studies of analogue fluvial formations and modern fluvial systems have been of great value in the modelling procedures and also in the application of sequence stratigraphical and allostratigraphical approaches in correlation within the alluvial successions. In the Statfjord Field, the reservoirs in the Statfjord Formation have been in production since 1979. The production results from this unit verify a predominant sheet geometry of the major sandstone bodies with very good reservoir qualities. Persistent shales of floodplain, lacustrine or lagoonal origin form effective pressure barriers. Experiences from production within the Statfjord Formation on the Snorre Field since August 1992 are generally in accordance with those obtained from the Statfjord Field. The upper member of the Lunde Formation on the Snorre Field has been in production since April 1993 and the results so far confirm the reservoir model. For all of the Triassic-Lower Jurassic reservoirs of continental sandstones in the Tampen Spur area, methods for IOR presuppose detailed reservoir description for 3D modelling of sandstone body geometry and heterogeneity. Integration of high-resolution seismics, sedimentological data and production results within the framework of modern conceptual models on alluvial stratigraphy is recommended. In further exploration on Triassic-Lower Jurassic fluvial play types in the northernmost North Sea area refined models for basin development and facies distribution for this time interval should be evolved.

The Application of ANN for Zone Identification in a Complex Reservoir

Abstract: Reservoir characterization plays a critical role in appraising the economic success of reservoir management and development methods Nearly all reservoirs show some degree of heterogeneity, which invariably impacts production As a result, the production performance of a complex reservoir cannot be realisticall y predicted without accurate reservoir description Characterization of a heterogeneous reservoir is a complex problem The difficulty stems from the fact that sufficient data to accurately predict the distribution of the formation attributes are not usually available Generally the geophysical logs are available from a considerable number of wells in the reservoir Therefore, a methodology for reservoir description and characterization utilizing only well logs data represents a significant technical as well as economic advantage One of the key issues in the description and characterization of heterogeneous formations is the distribution of various zones and their properties In this study, several artificial neural networks (ANN) were successfully designed and developed for zone identification in a heterogeneous formation from geophysical well logs Granny Creek Field in West Virginia has been selected as the study area in this paper This field has produced oil from Big Injun Formation since the early 1900's The water flooding operations were initiated in the 1970's and are currently still in progress Well log data on a substantial number of wells in this reservoir were available and were collected Core analysis results were also available from a few wells The log data from 3 wells along with the various zone definitions were utilized to train the networks for zone recognition The data from 2 other wells with previously determined zones, based on the core and log data, were then utilized to verify the developed networks predictions The results indicated that ANN can be a useful tool for accurately identifying the zones in complex reservoirs

Sequence Stratigraphy of the Hith/Upper Arab Formations Offshore Abu Dhabi, U.A.E.

Abstract: The Kimmeridgian Upper Arab zones A, B, and C, are prolific hydrocarbon bearing reservoirs in central and western Offshore Abu Dhabi, (OAD). They were deposited in an arid climate which dominated the Arabian peninsula during Late Jurassic times. The Berriasian to Titonian Hith Formation which overlies the Arab reservoirs constitutes to cap rock, which just to the east of central OAD gradually pinches out and forms a N-S feather edge. The Hith and Upper Arab zones A, B, and C form 450 to over 660 feet of massive to interbedded anhydrites with varying proportions of limestones and dolomites in central and western OAD. The Arab Formation in OAD is a major regressive unit which was deposited on a broad carbonate platform and prograded eastwards into an open marine self environment. The Upper Arab zones A, B, and C consist of small scale shallowing upward cycles of varying thicknesses (6 to 30 feet) wich typically consist of shoal grainstones (TST) passing upwards into thein bedded lagoonal burrowed mud/wacke-stone (MFS). These are overlain by coarse bioclastic grainstones capped by algal laminites and culminate into supratidal anhydrides, which pinchout eastwards. In the west, cycles are thicker and consist of intertidal pack/grainstones overlain by anhydrites. The parasequences or meter scale cycles have layercake stacking paterns arranged in transgressive, regressive episodes, and are driven by climatic, syndepositional tectonics and their associated low amplitude sea level fluctuations (eustacy). Early evaporative and reflux dolomitization of peloidal end oolitic grainstones has greatly enhanced reservoir characteristics. Meteoric leaching associated with relative drops in sea level resulted in aragonite dissolution and reservoir enhancement. Early marine cementation and late post-burial deagenesis such as anhydritisation resulted in reservoir deterioration. The objectives of this paper are to develop a sequence statigraphic framework, emphasizing cyclicity, facies architecture and diagenesis. Core and well log data geared with various inorganic geochemical analyses from four wells are used to constrain the current uncertainties in age dating and integrate the diagenetic signatures into the patterns of relative sea level change which considerably control the formation of those parasequences. This effort will help in better understanding and possible prediction of porosity in such prospective reservoirs.

Seeking new potential in the early-late Permian Gharif Play, West Central Oman

Abstract: West Central Oman is a relatively underexplored area where the hydrocarbons found to date occur mainly within the Early-Late Permian Gharif Formation. Structural definition of the low relief closures is hampered by seismic velocity variations caused by dune terrain. Recent exploration activity resulted in several Gharif discoveries, but highlighted reservoir distribution problems. The Gharif Formation, which consists of fluvio-marine sediments, conformably overlies the glacio-lacustine sediments of the Early Permian Al Khlata Formation. It is overlain by shallow marine carbonates of the Late Permian Khuff Formation, the main regional seal. The area is located distally from the main sediment sources to the east. Reservoir development and lateral continuity are seen as the main risk. Most reservoirs are beyond seismic resolution, only the stacked sandstones of the incised valley fills could provide sufficient acoustic contrast to be recognized on seismic. Geochemical typing indicates that the hydrocarbons in the Gharif can be grouped in two main families: the Huqf and Q-hydrocarbons, which are believed to originate from Cambrian to Precambrian source rocks. Although the two hydrocarbon families are sometimes found in one well, they have very different spatial distributions. The Q-oils form continuous strings of accumulations below the main regional seal, whereas themore » Huqf hydrocarbons occur scattered throughout the area. Mixed accumulations are found where cross-faults or salt domes intercept a Q-oil fairway. Future exploration activities will be guided by refined sedimentological, stratigraphical and hydrocarbon migration models and by the continued efforts to recognize incised valley fills on seismic.« less

Sand-shale ratio and sandy reservoir properties estimation from seismic attributes: An integrated study

Abstract: Total and Unocal estimated sand-shale ratios in gas reservoirs from the upper Tertiary clastics of Myanmar. They separately used deterministic pre-stack and statistical post-stack seismic attribute analysis calibrated at two wells to objectively extrapolate the lithologies and reservoir properties several kilometers away from the wells. The two approaches were then integrated and lead to a unique distribution of the sands and shales in the reservoir which fit in the known regional geological model. For the sands, the fluid distributions (gas and brine) were also estimated as well as the porosity, water saturation, thickness and clay content of the sands. This was made possible by using precise elastic modeling based on the Biot-Gassmann equation in order to integrate the effects of reservoir properties on seismic signatures.