Showing papers on "Petroleum reservoir published in 1991"

Applied Petroleum Reservoir Engineering

Abstract: 1. Introduction to Reservoir Engineering. 2. The General Material Balance Equation. 3. Single-Phase Gas Reservoirs. 4. Gas-Condensate Reservoirs. 5. Undersaturated Oil Reservoirs. 6. Saturated Oil Reservoirs. 7. Fluid Flow in Reservoirs. 8. Water Influx. 9. The Displacement of Oil and Gas. 10. History Matching.

Generation and Migration of Petroleum from Abnormally Pressured Fluid Compartments: Reply

Abstract: Much of the world's oil and gas has been generated from source rocks inside deep (> 3,000 m or 9,840 ft) seal-bounded fluid compartments. The quantity and composition of the kerogen and the burial history of the source rocks determine the volumes of petroleum generated; however, the migration from the compartments in an oil and gas phase is a pressure-driven process in which the flow direction is controlled by the configuration and internal pressures of the fluid compartments. Many sedimentary basins contain layers of two or more superimposed hydrogeological systems. The shallow systems are usually basin wide in extent and exhibit normal hydrostatic pressures. The deeper systems, where the oil is generated, are not basin wide and are abnormally over pressured. They usu lly consist of a series of individual fluid compartments that are not in hydraulic pressure communication with each other nor with the overlying hydrodynamic regime. Tops of fluid compartments in currently sinking basins do not always follow a specific stratigraphic horizon. They frequently have planar tops and subsurface temperatures ranging from 90 degrees to 100 degrees C (194 degrees to 212 degrees F). The tops in clastic sediments appear to be caused by carbonate mineralization along a thermocline. In the North Sea, the depth to the top of the deepest seal changes with the geothermal gradient. The seal is deeper where the gradient is lower. The generation of oil and gas within the compartments plus the thermal expansion of pore fluids eventually causes fracturing of the top compartment seal during periods of basin sinking. Hydrocarbons and other pore fluids then move vertically into the overlying lower pressured sediments and accumulate in the nearest structural and stratigraphic traps. Seal fracturing causes a pressure drop with compartment fluids rushing to the breakout point. The compartment then re-seals and pressure builds to another breakout. This episodic process continues with resealing and breakout cycles probably occurring in intervals of thousands of years in rapidly sinking basins such as the United States Gulf Coast. This concept of episodic dewatering of deep-basin fluid compartments needs to be considered n any basin-modeling program where the bulk of the oil generation occurs in the compartmented overpressured section of the basin and the oil moves vertically into the normally pressured rocks above.

Effect of Reservoir Depletion And Pore Pressure Drawdown On In Situ Stress And Deformation In the Ekofisk Field, North Sea

Abstract: Knowledge of in situ stress and how stress changes with reservoir depletion and pore pressure drawdown is important in a multi-disciplinary approach to reservoir characterization, reservoir management, and enhanced oil recovery projects. Over 20 years of petroleum production from the Ekofisk field has resulted in a 21-24 MPa reduction in reservoir pore pressure. The effect of pore pressure drawdown on the minimum horizontal in situ stress in the Ekofisk field has been determined from shut-in pressure data of 32 hydraulic fractures. The effective stresses in the reservoir increase linearly with pore pressure drawdown, but at different rates. The ratio of the change in effective minimum horizontal stress to the change in effective vertical (overburden) stress is approximately 0.20. Laboratory experiments, which simulate the stress path followed by reservoir rock during the production history of the Ekofisk field, clearly indicate that shear failure has occurred during compaction of high porosity chalk as the shear stress increased with pore pressure drawdown. It is suggested that shear failure during primary production has increased fracture density and reduced matrix block dimensions, and has therefore maintained reservoir permeability, which may account for the continued good producibility of the Ekofisk field, in spite of compaction. 9more » refs., 5 figs.« less

Empirical prediction of porosity and permeability in sandstones

Abstract: Current efforts to predict porosity and permeability in sandstones prior to drilling are focused on empirical and process-oriented models. Empirical predictions are based on the correlation between porosity and permeability and a limited number of parameters obtained from calibration data sets or estimated from appropriate geologic models. Of these parameters, the most important are detrital composition, grain size, sorting, and temperature history or pressure history or both. Despite its limitations, the empirical approach provides accurate predrill predictions of reservoir quality in many sandstones containing not only primary but also secondary porosity and permeability. Predictions of the average porosity and permeability of target sandstones are arbitrarily defined h re as accurate if they fall within +/- 2% porosity of the mean measured porosity and within the same order of magnitude as the mean measured permeability in a sample population representing the interval of interest. The effectiveness of the empirical predictive approach is illustrated by case studies from the Taranaki basin (New Zealand) and Yacheng field (People's Republic of China). These studies indicate that empirical predictions are basin specific or even play specific, and require at least some understanding of fundamental processes affecting reservoir quality of a given sandstone target. Process-oriented approaches attempting to model the effect of diagenesis on reservoir quality are hampered by inadequate quantitative understanding of the processes responsible for preserving primary porosity and generating secondary porosity and permeability. Until adequate quantification of the sandstone diagenesis processes is achieved, empirical models have a distinct advantage over process-oriented models in providing reliable predictions of reservoir quality in many sandstone intervals.

Fracture density in the deep subsurface: Techniques with application to Point Arguello oil field

Abstract: Because Monterey Formation reservoirs rely on fractures (joints) for permeability, quantitative information on fracture spacing is important to exploration strategies and for understanding reservoir behavior. Density of joints in cores of four wells from the Point Arguello reservoir has been determined with a new, probability-based method, and these subsurface joint densities are compared with joint densities measured at nearby outcrops. My measure of joint density is the fracture-spacing index, which is the slope of the trend of layer thickness to joint spacing. A single set of extension joints that strike parallel to bedding dip predominates at outcrops. Likewise, the cores contain a single set of extension joints perpendicular to the anticline axis, and parallel to present-day maximum horizontal compressive stress. In core and at outcrop, the only lithologic control on joint density is between nonjointed mudstone and harder (more brittle), jointed rocks. Within each well, the fracture-spacing index is the same for all hard rocks (though it varies between wells). In the reservoir, joint density relates to structural position. The most densely jointed strata (fracture-spacing index = 0.45) are from the hinge of a minor anticline, where its plunge steepens. A less steeply plunging anticlinal nose has lower joint density (fracture-spacing index = 0.30). The lowest joint density (fracture-spacing index = 0.095 and 0.12) is in cores from gently dipping areas. At outcrops in various structural settings, the fracture-spacing index is the same (approximately 1.29) in chert, dolostone, and porcelanite and siliceous shale. These rocks may be "saturated" with joints, so that differences in brittle strain due to local structural variations have been overwhelmed as joints continued to form during unroofing of these strata. Chert looks more fractured than other lithologies because of thin bedding. Fracture-spacing index is used to compute such parameters as fracture porosity and volume of fractures that directly contact the well bore. These parameters may be important when trying to model the behavior of a petroleum reservoir, or when trying to assess the feasibility of strongly deviating wells to improve the performance of a fracture reservoir.

Lithofacies and cyclicity of the Yates Formation, Permian Basin; implications for reservoir heterogeneity

Abstract: Siliciclastics of the Yates Formation (Permian, upper Guadalupian) are significant hydrocarbon reservoirs in the United States Permian basin. Subsurface and outcrop data show that the most porous lithofacies occur in a clastic-dominated middle shelf and that evaporitic inner shelf and carbonate outer shelf equivalents are mostly nonporous. Lithofacies relations and much of the heterogeneity in Yates reservoirs are related to the stacking of depositional sequences (i.e., siliciclastic-carbonate alternations and sandstone-argillaceous siltstone alternations) in response to three orders of orbitally forced, low-amplitude, eustatic variation. In general, siliciclastics dominated the Yates shelf during lowstand parts of asymmetric, 400-k.y. sea level fluctuations, whereas carbonates were deposited during sea level highstands. The character and position of sand depocenters on the Yates shelf during these lowstands were controlled by a longer duration third-order sea level variation. Shorter duration cycles controlled the heterogeneity within the 400-k.y. depositional sequences. The variation in cycle packaging, lithology, and reservoir quality between the Central Basin platform and Northwest shelf may be a response of eustatic variation on parts of the shelf with different slopes or subsidence profiles. The lithofacies described from the Yates Formation and the depositional model proposed to explain the stratigraphy may be valuable as analogs in other basins containing mixed siliciclastic-carbonate settings.

A review of heterogeneity measures used in reservoir characterization

Abstract: This paper examines the properties of petroleum reservoir heterogeneity measures. The authors begin by defining heterogeneity and proposing a structure for the measures. The structure has three categories: static measures without spatial correlation, static measures with correlation, and dynamic measures. The definitions and properties of several measures are then examined and classified according to this structure.

Observed Relation of Soil Magnetic Susceptibility and Soil Gas Hydrocarbon Analyses to Subsurface Hydrocarbon Accumulations

Abstract: Magnetic susceptibility (MS) studies on soils over 19 oil and gas fields showed anomalously large amounts of diagenetic magnetic minerals in shallow-depth samples in about 89% of the cases tested. Soil MS anomalies were compared with soil gas hydrocarbon (GHC) anomalies over 12 oil and gas fields (including several stratigraphic traps) and one gas storage reservoir. Samples were collected along the same profiles. Six examples are presented with detailed data listings. Our goal is to test the utility of soil magnetic susceptibility and soil gas hydrocarbons as petroleum prospecting methods. We emphasize statistical evaluation of anomalies and their empirical correlation with producing areas and leads identified by other geochemical, geological, or geophysical data. For direct comparison of anomaly strengths, data are expressed statistically in terms of the appropriate background mean and standard deviation. Soil MS and soil GHC data complement each other, providing better guidance to productive areas than either data set alone. When used in an integrated exploration program, their combined positive evidence of hydrocarbon presence under prospects could result in fewer dry holes than when drilling with structural information only.

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

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

Liberation of Solution Gas During Pressure Depletion of Virgin and Watered-Out Oil Reservoirs

Abstract: Multipurpose experimental equipment was constructed to investigate the buildup of gas saturation during depressurization of virgin and water-out oil reservoirs at representative conditions. In this paper the measured dependencies of critical gas saturations on gas/oil interfacial tension (IFT), amount of dissolved gas, pressure-decline rate, and structure of the porous medium are discussed. In addition, experimental results indicating significant reductions of waterflood residual oil saturation (ROS) owing to the presence of a gas saturation are presented.

Travis peak core permeability and porosity relationships at reservoir stress

Abstract: In this paper relationships of permeability to porosity are shown from analyses of more than 2,100 core plugs from nine wells in the Travis Peak, a low-permeability, tight-gas sandstone formation in northeast Texas. Effects of reservoir vs. ambient stress are shown for permeability, porosity, and the Klinkenberg factor. The relationship of brine permeability to gas permeability is also shown.

Applied petroleum reservoir engineering. Second edition

Abstract: This book reports on single-phase gas reservoirs; gas-condensate reservoirs; undersaturated oil reservoirs; saturated oil reservoirs; and single-phase oil reservoirs.

Regional paleotopographic trends and production, Muddy Sandstone (Lower Cretaceous), Central and Northern Rocky Mountains

Abstract: The Muddy Sandstone and equivalent strata have produced more than 1.5 billion bbl of oil-equivalent hydrocarbons. Production is controlled principally by unconformities formed during a relative sea level lowstand. Reservoirs are found in paleohills of older marine sandstones, younger valley fills and associated alluvial plain channel sandstones, and transgressive marine deposits. At least ten paleodrainage basins existed at maximum lowstand. A regional drainage divide formed in southern Wyoming and separated southeast-flowing from northwest-flowing alluvial systems. Local tributaries stripped drainage divides of fine-grained detritus derived from the underlying Skull Creek Shale and older marine sandstones. In contrast, trunk streams carried medium- and coarse grained-sands eroded from eastern, southern, and western provenances of Paleozoic and Mesozoic strata. The best fluvial reservoirs are developed within these coarser grained trunk systems. Reservoir data display little or no correlation between depth and porosity due to secondary dissolution porosity developed at all depths. Valley fill and channel reservoirs have produced at least 359 MMBOE, onlap cycles another 315+ MMBOE, and older marine buried-hill reservoirs more than 268 MMBOE. The best per-field reserves are from marine sandstones. Regional production patterns reflect proximity to mature Skull Creek and Mowry shale source beds and favorable trapping conditions within individual paleodrainages. Future hydrocarbon exploration successes will require drilling to the Muddy Sandstone in deeper basin settings and a better understanding of the role of unconformities and diagenesis in controlling hydrocarbon accumulations.

Geology and Hydrocarbon Habitat of the West Siberian Basin

Abstract: The West Siberian oil-gas province comprises the largest flat land area in the world (3.5 million km2, or 1.3 million mi2). Over most of the region, elevations rarely exceed 100 m (330 ft). The basin is bounded on the west by the Uralian and Novaya Zemlya uplifts, on the east by the Siberian craton and Taymyr uplift, on the south by the Kazakh and Altay-Sayan uplifts, and on the north by the North Siberian sill. Structurally, the basm is a broad, relatively gentle downwarp filled with 3-10 km (10,000-33,000 ft) of post-Paleozoic marine, nearshore marine, and continental clastic sedimentary rocks. The basement is composed of Precambrian and Paleozoic fold systems with large areas of partly metamorphosed Paleozoic carbonate and clastic rocks and numerous areas of Paleozoic or older granitic and mafic igneous bodies. In the central part of the basin, the basement is cut by an extensive, northerly oriented Triassic rift system. Paleostructural and stratigraphic trapping are important aspects of West Siberian petroleum geology. Oil source rocks are mainly marine Jurassic and Lower Cretaceous bituminous shales. Gas source rocks are mainly Upper Cretaceous humic and coaly shales. Petroleum production in the basin occurs in four major areas: (1) Middle Ob: primarily oil from Lower Cretaceous deltaic-marine clastic reservoirs on broad regional uplifts; the Samotlor and other supergiant fields are located in this area; (2) Near-Ural: primarily oil in the south and gas in the north from Upper Jurassic and Lower Cretaceous clastic reservoirs in paleo- structural-stratigraphic traps; (3) Southern Basin: oil and oil-gas from Jurassic clastic reservoirs, mainly on anticlines or arches inherited from basement highs; and (4) Northern Basin: gas primarily from Upper Cretaceous (Cenomanian) and gas-condensate from Lower Cretaceous and Jurassic clastic reservoirs on large anticlinal traps sealed by Cretaceous shales or permafrost. Urengoy, the world's largest gas field, and several other supeigiant gas fields are located in this latter area. Large parts of the basin are relatively unexplored, particularly the northern offshore segments. The interrelated paleostructural and depo- sitional character of this enormous basin provides excellent prospects for stratigraphic trap accumulations. An estimated 70 billion bbl of oil and 1000 tcf (trillion cubic feet) of gas have been found in the basin. U.S. Geological Survey estimates (1987) of undiscovered, conventionally recoverable petroleum resources are 30 billion bbl of oil and 350 tcf of gas.

Megacompartment Complex in the Anadarko Basin: A Completely Sealed Overpressured Phenomenon

Abstract: Integrated pore pressure, potentiometric, and geologic data in the Anadarko basin demonstrate the existence of a basinwide, completely sealed overpressured compartment, called the megacompartment complex. All reservoirs within this complex exhibit pressure gradients that exceed the normal gradient of 10.515 kPa/m (0.465 psi/ft). These reservoirs have produced large quantities of natural gas, particularly from the Pennsylvanian Red Fork and Morrowan sandstones. This megacompartment complex is enclosed by top, basal, and lateral seals. The top seal zone, which is located between 2290 m and 3050 m (7500 and 10,000 ft) below the surface, is relatively horizontal, dips slightly to the southwest, and appears to cut across stratigraphy. However, the diagenetically enhanced basal seal is stratigraphically controlled and seems to coincide with the Devonian Woodford Shale. The complex is laterally sealed to the south by a vertical cementation zone associated with the frontal fault zone of the Wichita Mountain uplift and by the convergence of the top and basal seals along the eastern, northern, and western boundaries. The interior of the complex is subdivided into a myriad of smaller compartments with distinct pressure gradients. In addition, local overpressured compartments are present outside the megacompartment complex in normally and near-normally pressured regions.

Diagenetic History and Hydrocarbon Potential of Upper Permian Carbonate Buildups, Wegener Halvo Area, Jameson Land Basin, East Greenland (1)

Abstract: The Upper Permian of Jameson Land includes two carbonate sequences, the Karstryggen and Wegener Halvo formations. The Karstryggen Formation contains hypersaline carbonates and localized evaporites that were heavily weathered and dissected prior to deposition of the overlying strata. The overlying Wegener Halvo Formation represents an abrupt and extensive marine inundation over the underlying karstified Karstryggen surface. Bryozoan-brachiopod-algal-cement buildups of the Wegener Halvo Formation are localized on karstic highs, and show up to 150 m of depositional relief. In-situ mound-core deposits are flanked by allodapic limestones, which pass laterally into intermound calcareous shales. The diagenetic histories of the core and flank facies are very different. Core facies porosity was intially obliterated by marine cements, but repeated meteoric exposure altered unstable core facies constituents. This alteration produced extensive secondary porosity through grain and cement leaching with local collapse brecciation. Flank strata, however, underwent little sea-floor diagenesis, and low permeability and mineralogically stable grain composition protected these strata from meteoric alteration. Early cementation and stabilization of core strata led to minimal burial-diagenetic porosity loss. Uncemented flank beds, however, underwent profound mechanical and chemical compaction during this stage. Thus, at the time of hydrocarbon generation, distal flank beds had less than 2% porosity, coarse upper flank beds had 5-10% remnant primary porosity, and core facies deposits had 8-12% secondary pore space. Hydrocarbons generated from surrounding marine shales charged many of the bioherms with oil. Subsequent fracturing and hydrothermal fluid flow, however, flushed hydrocarbons and filled pores with ferroan calcite, barite, fluorite, galena, and baroque dolomite. This heating and flushing is thought to have been especially intense in the Wegener Halvo region; thus, more basinal areas may still have reservoirs containing significant oil in equivalent Upper Permian limestones. If, as is likely, the sea level changes affecting the Greenland Permian were eustatic, then this study may provide significant clues to porosity development throughout the largely unexplored northern Zechstein basin and the Arctic basin of the Barent Sea. This study also provides some important connections to the probably time-equivalent Guadalupian carbonate reservoir rocks of west Texas-New Mexico and Wyoming.

The Lower Cretaceous Chinkeh Formation: A Frontier-Type Play in the Liard Basin of Western Canada

Abstract: The Lower Cretaceous Liard basin in western Canada covers an area of 9500 sq km (3668 sq mi) but is relatively unexplored despite its size. The present-day expression of the basin, which formed during the latest Cretaceous to early Tertiary, trends north-south and is delineated by the outcrop of the coarse-clastic Upper Cretaceous Dunvegan Formation. The lowermost Cretaceous unit, herein named the Chinkeh Formation, is up to 32 m (105 ft) thick and unconformably overlies older Paleozoic strata. The Chinkeh Formation contains four major lithotypes: (1) conglomeratic breccia interpreted as debris-flow or talus deposits, (2) interbedded coal, carbonaceous shale, rooted sandstone, and conglomerate interpreted as nonmarine valley fill or channel deposits, (3) conglomeratic lag related to marine transgression, and (4) upward-coarsening sandstone interpreted as abandoned shoreline deposits. The lower part of the Chinkeh Formation consists locally of an angular-chert breccia overlain by medium- to coarse-grained sandstone and conglomerate with coal and rooted beds. The uppermost Chinkeh Formation consists of a basal conglomeratic layer overlain by an upward-coarsening, fine- to medium-grained, well-sorted marine sandstone, with bioturbated shale. Sediment was recycled repeatedly with the dominant sediment source being from the east with perhaps some western sources. Cretaceous strata in the Liard basin have good petroleum source-rock and reservoir potential, and hydrocarbons may be present in sandstone of the Chinkeh Formation. Potential play types include stratigraphic traps formed by incised-valley deposits and shallow-marine sandstone pinching out laterally into marine shales of the Garbutt Formation. A potential structural play may occur along the Bovie fault zone where reservoirs may abut against a shale seal on the eastern side of the fault. Most of Lower Cretaceous strata falls within the hydrocarbon generation window, with increasing maturity to the southwest. Pyrobitumen is locally abundant and constitutes 30% of the bulk rock volume in one sandstone. Potential source rocks include the lowermost Garbutt Formation and underlying Triassic oad and Grayling formations. The Chinkeh Formation sandstone has porosity values of 8-18%.

Lopatin Analysis of maturation and petroleum generation in the Illinois basin

Abstract: A modified Lopatin approach was used to evaluate the present-day maturity of Paleozoic source rock units across the Illinois basin, timing of generation, regional porosity trends, and basin paleostructure during major generative events. Ten cases were modeled at 100 locations to test assumed paleogeothermal gradients, post-Pennsylvanian overburden thicknesses, and rates of erosional stripping. Lopatin predicted maturities for the Herrin ({number sign}6) Coal and the New Albany Shale are in good agreement ({plus minus}0.02% R{sub O}) with measured maturities if 500-3,000 ft of post-Middle Pennsylvanian strata and were deposited and subsequently eroded between the Permian and mid-Cretaceous and if paleogeothermal gradients were within a few {degree}C/km of present-day gradients. Predicted mean reflectance levels range from 1.0 to 4.0% R{sub O} at the base of the Potsdam Megagroup, 0.7 to 3.5% at the base of the Know Megagroup, and 0.6 to 1.3% at the base of the Maquoketa Shale, excluding only a small high-maturity area in southeastern Illinois. The Knox and Potsdam section attained oil generation 475-300 Ma, while the Maquoketa and the younger New Albany Shale reached the oil window much later: 300-250 Ma. Because most significant structures in the basin formed after 300 Ma, any pre-Maquoketa source rocks were alreadymore » within the gas zone and may have been largely spent by the time known structures formed. Any Know or deeper traps in the basin will probably contain gas, be restricted to old structures (earlier than 300 Ma) or stratigraphic traps, and will hold pre-300 Ma generated hydrocarbons which subsequently cracked to gas.« less

3D reservoir simulation of Ekofisk compaction drive

Abstract: In late 1984, the seafloor at the Ekofisk oil field in the Norwegian North Sea was discovered to have subsided by more than 10 ft as a result of production-induced reservoir compaction. Subsidence was not expected and its detection suggested that reservoir compaction was perhaps a more important mechanism for hydrocarbon production than previously assumed. This paper describes procedures developed to account for compaction drive in the 3D reservoir simulator that is used for the Ekofisk field. The procedures involve the incorporation of results from a subsidence model into the reservoir chalk as a function of porosity, rock type, reservoir pressure, and position in the reservoir.

Comparison of pressure-transient response in intensely and sparsely fractured reservoirs

Abstract: In this paper a comprehensive analytical model is presented to quantify the pressure-transient behavior of a naturally fractured reservoir with a continuous matrix-block-size distribution and interporosity skin. Geologically realistic probability density functions of matrix block size are used to represent reservoirs of varying fracture intensity and uniformity. Drawdown and interference type curves are developed with rectangular probability density functions. The results obtained extend previous dual-porosity models by incorporating fracture spacing variability. In the absence of interporosity skin, intensely and sparsely fractured reservoirs show distinctions in the pressure response. Uniformity of a fractured reservoir also significantly affects pressure responses, irrespective of the degree of fracture intensity. The pressure response in a nonuniformly fractured reservoir with large block-size variability, for example, can exhibit a nonfractured (homogeneous) reservoir response. The results may be used to estimate matrix-block-size variability and the degree of fracture intensity from drawdown and interference well tests.

Hydrocarbon Generation and Migration Routes in the East Texas Basin

Abstract: The East Texas basin is a prolific, mature hydrocarbon province, producing oil and gas from several reservoirs and a variety of trap types. Many of the liquid hydrocarbons discovered in the basin are trapped in structures related to movement of the underlying Louann Salt. By determining the structural evolution of the basin, we constructed a framework to model the generation of hydrocarbons in the basin. Geochemical data indicate three major oil types: Jurassic oil, Lower Cretaceous oil, and Upper Cretaceous oil. The Jurassic source is mature throughout the basin and began to expel oil at approximately 88 Ma. The distribution of Jurassic oil in Cretaceous reservoirs shows that vertical migration routes predominated. Prospective Lower Cretaceous source rocks are only matur in the deep, central portion of the basin where expulsion began about 47 Ma. Distribution of this oil type suggests that Lower Cretaceous source rocks occur only in localized areas of the East Texas basin. Organic-rich Upper Cretaceous shales are immature in the main part of the basin, but are mature south of the Angelina-Caldwell flexure, where they reached peak generation at approximately 20 Ma. Long-distance, lateral migration routes are necessary to explain the distribution of this oil type. Migration routes to the giant East Texas field may be 100 km or more. Modeling of this basin suggests an exploration approach, in mature basins, of defining migration pathways and seeking traps astride them. Traps in this position have a better probability of being filled; and, all else being equal, are likely to be better fields than traps located away from the major migration routes.

Eocene Submarine Fan Sedimentation in Southwest Java

Abstract: Submarine fan deposits can be important exploration targets but have yet to be widely exploited as potential oil and gas reservoirs in the Indonesian region. Very few have been actively drilled or even recognized in the subsurface, even though they should be relatively frequent given the active tectonic setting of the area. There are many reasons why these deposits have received so little attention, including the lack of a well described ancient example within the region. Well exposed coastal outcrops of the Middle to Late Eocene Ciletuh Formation located in the Ciletuh Area, Southwest Java, have been described on the basis of field study and laboratory analysis, and interpreted as a sand-dominated submarine fan complex. The outcrops consist of laterally continuous, fine to very coarse grained sandstones and sandy conglomerates. A number of classic sediment gravity flow features are present including turbidites with partial Bouma sequences, debris flow deposits and fluidized slump deposits. The sediments are believed to have possibly been deposited in a series of parallel slope grabens oriented perpendicular to slope. Two separate lithofacies are recognized in the Ciletuh Formation; a quartzose lithofacies composed of mostly quartz (58-84%) and a wide variety of lithic rock fragments; and a less pervasive volcanic lithofacies composed almost entirely of volcaniclastic sediments. Mesozoic granitic continental crust and Late Cretaceous subduction complex areas lying to the north are interpreted to have supplied the majority of quartz and lithic fragments, while a possible Eocene local volcanic arc is believed to have sourced the volcanics. The reservoir quality of the quartzose sandstones is poor due to near complete destruction of originally high primary porosity by a combination of compaction and carbonate cementation. Primary intergranular porosity values are estimated to have ranged from 25-40% prior to burial. Tectonic compaction associated with subduction compression is believed responsible for destruction of a large percentage of the porosity. Even though the Ciletuh Formation deposits examined in this study have very low reservoir potential, they present a useful example of a sand-rich submarine fan in the region, and indicate that similar sandstones elsewhere in Indonesia could provide a viable petroleum reservoir under more favorable tectonic or diagenetic conditions.

Transient pressure analysis of horizontal wells in anisotropic naturally fractured reservoirs

Abstract: Analytical solutions are presented for pressure-drawdown and -buildup analyses of horizontal wells in anisotropic reservoirs with tectonic, regional, or contractional natural fractures. (The reservoirs might be limited by parallel sealed boundaries.) These solutions have led to the identification of various flow periods, including radial in a vertical plane, transitional as a result of flow from the matrix into the fractures, linear when the transient pressure reaches the upper and lower boundaries of the reservoir, pseudoradial toward the wellbore in horizontal plane, and linear when the transient reaches the outer parallel boundaries. Recognition of these flow periods leads to the calculation of p{sub i} or P*; permeabilities in the x, y, and z directions; storativity ratio, {omega}; average distance between natural fractures; fracture porosity; and fracture aperture, skin, and pseudoskin caused by vertical and horizontal partial penetration. In this paper calculations are illustrated with an example.

Petroleum geology of the Upper Jurassic and Lower Cretaceous, Baltimore Canyon trough, western North Atlantic Ocean

Abstract: Numerous hydrocarbon shows, including a noncommercial gas and gas-condensate accumulation, occur in the Baltimore Canyon Trough within sandstone units deposited in prograding coastal-plain and transitional-marine environments located updip of an Oxfordian/Kimmeridgian carbonate shelf edge. The coastal-plain and transitional-marine facies are overlain by a fine-grained deltaic complex dominated by delta-plain shales which collectively form a regionally extensive top seal unit. This deltaic complex prograded into a back-reef lagoon during aggradation of lower Kimmeridgian through Berriasian shelf-margin carbonates. Wells drilled seaward of the continental shelf edge (>1500 m water depth) tested large structural/stratigraphic closures along the downdip termination of the Upper Jurassic/Lower Cretaceous carbonate shelf edge but encountered no significant hydrocarbon shows. Reservoir rocks in these wells consist of (1) oolite grainstone, which was deposited within a shoal-water complex located at the Aptian shelf edge, and (2) coral-stromatoporoid grainstone and boundstone, which formed an aggraded shelf-margin complex located at the late Kimmeridgian through Berriasian shelf edge. Structural closures having reservoir and top seals are present in both updip and downdip trends. Hydrocarbon shows in wells along the shelf interior trend indicate the presence of mature source beds, at least locally. The absence of hydrocarbon shows in downdip carbonate reservoirs and around the Schlee Dome, however, suggests charge/migration mechanisms within the fetch areas of these objectives have failed. Failure of charge can be due to (1) absence of mature source rocks, (2) absence of migration pathways from source rocks to reservoirs, and/or (3) absence of top seals at the time of hydrocarbon migration. Continued development of play concepts in the Baltimore Canyon Trough, therefore, requires identification and mapping of potential source-rock intervals and construction of hydr carbon expulsion models to time hydrocarbon generation relative to trap formation.