Showing papers in "AAPG Bulletin in 1997"
TL;DR: Osborne et al. as discussed by the authors investigated the potential for generating overpressure by hydrocarbon generation and cracking and concluded that these processes may be self-limiting in a sealed system because buildup of pressure could inhibit further organic metamorphism.
Abstract: Overpressure can be produced by the following processes: (1) increase of compressive stress, (2) changes in the volume of the pore fluid or rock matrix, and (3) fluid movement or buoyancy. Loading during burial can generate considerable overpressure due to disequilibrium compaction, particularly during the rapid subsidence of low- permeability sediments. Horizontal stress changes can rapidly generate and dissipate large amounts of overpressure in tectonically active areas. Overpressure mechanisms involving change in volume must be well sealed to be effective. Fluid volume increases associated with aquathermal expansion and clay dehydration are too small to generate significant overpressure unless perfect sealing occurs. Hydrocarbon generation and cracking to gas could possibly produce overpressure, depending upon the kerogen type, abundance of organic matter, temperature history, and rock permeability; however, these processes may be self-limiting in a sealed system because buildup of pressure could inhibit further organic metamorphism. The potential for generating overpressure by hydrocarbon generation and cracking must be regarded as unproven at present. Fluid movement due to a hydraulic head can generate significant overpressure in shallowly buried, "well-plumbed" basins. Calculations indicate that hydrocarbon buoyancy and osmosis can generate only small amounts of localized overpressure. The upward movement of gas in an incompressible fluid also could generate ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received October 17, 1995; revised manuscript received September 4, 1996; final acceptance January 20, 1997. 2Department of Geological Sciences, Durham University, South Road, Durham DH1 3LE, United Kingdom. Osborne e-mail: M.J.Osborne@ durham.ac.uk; GeoPOP web site http://www.dur.ac.uk/~dgl0zz7/ We wish to thank the companies that support the Geosciences Project on Overpressure (GeoPOP) at the universities of Durham, Newcastle, and Heriot-Watt: Agip, Amerada Hess, Amoco, ARCO, Chevron, Conoco, Elf Exploration, Mobil, Norsk Hydro, Phillips Petroleum UK Company Limited, Statoil, and Total. We also thank Neil Goulty (Durham) for commenting on an earlier draft of this paper. Osborne thanks Gordon Macleod (Newcastle) for help with geochemical modeling.
593 citations
TL;DR: In this article, the authors define two types of lithology-dependent attributes: gouge ratio and smear factor, and calibrate them in areas where across-fault pressure differences are explicitly known from wells on both sides of a fault.
Abstract: Fault seal can arise from reservoir/nonreservoir juxtaposition or by development of fault rock having high entry pressure. The methodology for evaluating these possibilities uses detailed seismic mapping and well analysis. A first-order seal analysis involves identifying reservoir juxtaposition areas over the fault surface by using the mapped horizons and a refined reservoir stratigraphy defined by isochores at the fault surface. The second-order phase of the analysis assesses whether the sand/sand contacts are likely to support a pressure difference. We define two types of lithology-dependent attributes: gouge ratio and smear factor. Gouge ratio is an estimate of the proportion of fine-grained material entrained into the fault gouge from the wall rocks. Smear factor methods (including clay smear potential and shale smear factor) estimate the profile thickness of a shale drawn along the fault zone during faulting. All of these parameters vary over the fault surface, implying that faults cannot simply be designated sealing or nonsealing. An important step in using these parameters is to calibrate them in areas where across-fault pressure differences are explicitly known from wells on both sides of a fault. Our calibration for a number of data sets shows remarkably consistent results, despite their diverse settings (e.g., Brent province, Niger Delta, Columbus basin). For example, a shale gouge ratio of about 20% (volume of shale in the slipped interval) is a typical threshold between minimal across-fault pressure difference and significant seal.
548 citations
TL;DR: In this paper, the authors show that the temperature required for in-situ thermochemical sulfate reduction to produce the high H2S concentrations encountered in deep carbonate gas reservoirs is greater than 140°C.
Abstract: Natural gas in the Permian-Triassic Khuff Formation of Abu Dhabi contains variable amounts of H2S. Gas souring occurred through thermochemical sulfate reduction of anhydrite by hydrocarbon gases. Sour gas is observed only in reservoirs hotter than a critical reaction temperature: 140°C. Petrographic examination of core from a wide depth range showed that the anhydrite reactant has been replaced by calcite reaction product only in samples deeper than 4300 m. Gas composition data show that only reservoirs deeper than 4300 m contain large quantities of H2S (i.e., >10%). At present-day geothermal gradients, 4300 m is equivalent to 140°C. Fluid inclusion analysis of calcite reaction product has shown that calcite growth only became significan at temperatures greater than 140°C. Thus, three independent indicators all show that 140°C is the critical temperature above which gas souring by thermochemical sulfate reduction begins. The previously suggested lower temperature thresholds for other sour gas provinces (80-130°C) derive from gas composition data that may not allow adequately either for the reservoir temperature history or for the migration of gas generated at higher temperatures into present traps. Conversely, published proposals for higher threshold temperature (180-200°C) derive from short duration experimental data that are not easily extrapolated to geologically realistic temperatures and time scales. Therefore, the temperature of 140°C derived from our study of the Khuff Formation may be th best estimate of temperature required for in-situ thermochemical sulfate reduction to produce the high H2S concentrations encountered in deep carbonate gas reservoirs.
251 citations
TL;DR: In this paper, the authors illustrate the importance of progradation as a trigger for salt tectonics and formation of allochthonous sheets by showing that prograding wedges above a tabular, buoyant salt layer with a flat base expelled the salt basinward, forming the following structures proximally to distally: (1) sigmoidally distorted initially planar wedges, (2) relict salt pillows and salt welds, (3) basinward-dipping expulsion rollover and crestal graben, (4)
Abstract: Scaled physical models illustrate the importance of progradation as a trigger for salt tectonics and formation of allochthonous sheets. Regional extension and contraction were excluded in the models. In our experiments, prograding wedges above a tabular, buoyant salt layer with a flat base expelled the salt basinward, forming the following structures proximally to distally: (1) sigmoidally distorted initially planar wedges, (2) relict salt pillows and salt welds, (3) basinward-dipping expulsion rollover and crestal graben, (4) rollover syncline, (5) landward-facing salt-cored monocline, and (6) distal inflated salt layer. This deformation zone amplified and advanced basinward during progradation; however, no diapiric salt structures formed. Over a buoyant salt layer whose basement had steps facing landward, progradation initially formed a broad anticline where salt flow was restricted across each basement step. Distal aggradation pinned the anticline and enhanced differential loading. The anticline actively pierced its crest, which ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received October 2, 1995; revised manuscript received May 9, 1996; final acceptance October 16, 1996. 2Bureau of Economic Geology, University of Texas at Austin, and Department of Geological Sciences, University of Texas at Austin, Austin, Texas 78713. 3Bureau of Economic Geology, University of Texas at Austin, Austin, Texas 78713. All modeling was done at the Applied Geodynamics Laboratory of the Bureau of Economic Geology, with financial support by grant number 3658-178 from the Texas Advanced Technology Program and from the following companies: Agip S.p.A, Amoco Production Company, Anadarko Petroleum Corporation, ARCO Exploration and Production Technology, BP Exploration, Chevron Petroleum Technology Company, Conoco and Dupont, Exxon Production Research Company, Louisiana Land and Exploration Company, Marathon Oil Company, Mobil Research and Development Corporation, Petroleo Brasileiro S.A., Phillips Petroleum Company, Societe Nationale Elf Aquitaine Production, Statoil, Texaco, and Total Minatome Corporation. The Department of Geological Sciences and the Geology Foundation at the University of Texas at Austin and Phillips Petroleum Company provided additional financial support for Hongxing Ge. Dan Schultz-Ela helped us depth convert and restore seismic sections. Mark Rowan, Mike Hudec, Lee Fairchild, Sharon Mosher, and Tucker Hentz provided invaluable suggestions for improving the paper. Publication authorized by the Director, Bureau of Economic Geology, University of Texas at Austin.
243 citations
TL;DR: Crowell et al. as discussed by the authors simulated the geometries and progressive evolution of pull-apart basins developed in a weak sedimentary cover above right-stepping (releasing) dextral strike-slip fault systems in rigid basement.
Abstract: Scaled sandbox models have successfully simulated the geometries and progressive evolution of pull-apart basins developed in a weak sedimentary cover above right-stepping (releasing) dextral strike-slip fault systems in rigid basement. Synkinematic basin infill was added progressively as the models were deformed. Vertical and horizontal sectioning of the completed models has allowed the full three-dimensional architecture of the pull-apart system to be analyzed. We present three representative end-member experiments: 30° underlapping releasing sidestep, 90° sharp nonoverlapping releasing sidestep, and 150° overlapping releasing sidestep. The pull-apart basin geometries are typically sigmoidal to rhombic grabens, the geometries of which are dependent upon the architecture of the underlying basement fault systems. Underlapping releasing sidestepping faults (offset angles of 30-75°) typically form elongate rhomboidal grabens; 90° releasing offset sidesteps produce shorter, squat, rhomboid pull-apart basins; and overlapping releasing sidesteps (115-150°) produce box-like grabens with highly kinked basin sidewalls. The pull-apart basins are bounded by terraced oblique-slip extensional sidewall fault systems that link the laterally offset principal displacement zones (PDZ) of the main dextral strike-slip faults. The sidewall faults show changes in kinematics from dominantly dip-slip extension in ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received June 24, 1996; revised manuscript received November 20, 1996; final acceptance June 10, 1997. 2Fault Dynamics Project, Geology Department, Royal Holloway, University of London, Egham, Surrey TW20 OEX, United Kingdom. Supported by the Fault Dynamics Project [sponsored by ARCO British Limited, PETROBRAS U.K. Ltd., BP Exploration, Conoco (U.K.) Limited, Mobil North Sea Limited, and Sun Oil Britain]. We also acknowledge additional funding from Sun Oil Britain. Landsat Thematic Mapper data courtesy of RTZ Mining and Exploration Limited, South American Division. Jurrian Reijs is thanked for field data relating to the Salina del Fraile pull-apart basin. Chris Elders is thanked for reviewing earlier versions of this manuscript, and J. Crowell, C. Morley, and K. Biddle are thanked for constructive reviews of the manuscript. The contents of this paper have been
203 citations
TL;DR: In this paper, a set of fault juxtaposition and sealing diagrams is proposed to analyze the fault displacement magnitude and the fault surface type. But the fault geometry is not considered. The fault displacement is based on the interaction of rock lithology and fault displacement.
Abstract: A new set of diagrams aids in analyzing fault juxtaposition and sealing. The diagrams are based on the interaction of rock lithology and the fault displacement (throw) magnitude to control juxtapositions and fault seal types. The advantages of the diagrams are that they allow an evaluation of a fault seal without the need for detailed three-dimensional mapping of stratigraphic horizons and fault planes, and can be used to contour permeability, sealing capacity, and transmissibility of fault zones. These diagrams may be used to rapidly identify the critical fault throw and juxtapositions that require mapping to identify compartments in hydrocarbon reservoirs.
201 citations
TL;DR: In this paper, the authors describe the benefits of using H/C ratios in source rock evaluations and present new correlations between atomic H/c ratios and thermal maturity, organic matter conversion, and expulsion volumetrics.
Abstract: In recent years, the atomic H/C (hydrogen to carbon) ratio of kerogen as a way to assess the quality of organic matter in source rocks has been overlooked in favor of the more easily determined Rock-Eval hydrogen index. Rock-Eval pyrolysis provides fast, inexpensive, quantitative (mg HC/g rock) data without requiring kerogen isolation from the rock. Because of the general scatter in the data, many source rock interpreters consider Rock-Eval pyrolysis to be a screening analysis. In this paper I describe the benefits of using H/C ratios in source rock evaluations and present new correlations between atomic H/C ratios and thermal maturity, organic matter conversion, and expulsion volumetrics. Atomic H/C ratios of pyrolyzed kerogens have been correlated to the extent of thermal conversion of organic matter for both type I and type II kerogens. The excellent agreement between stoichiometric calculated hydrogen and carbon loss to observed losses from hydrous pyrolysis maturation experiments suggests that kerogen H/C ratios are excellent indicators of thermal maturity for end-member kerogen types. These data also offer a method to estimate percent organic matter conversion, provided that both the initial and present H/C ratios of the kerogen are known. Present H/C ratios can be measured, and initial H/C ratios can be reasonably estimated, from microscopic organic analysis of kerogen. For oil-prone source rocks, typical immature type I kerogens have H/C ratios of 1.35-1.50, whereas type II kerogens have H/C ratios of 1.20-1.35. Correlations of the amount of expelled oil in hydrous pyrolysis experiments to atomic H/C ratio of the spent kerogen offer exploration geologists a quick estimate of oil expulsion volumes. Based on hydrous pyrolysis experiments, measured H/C ratios, and calculated original TOC (total organic carbon) values, first-order volumetric approximations were made on three basins containing mature source rocks. Results compared favorably with published approximate-oil-in-place estimates for the Williston basin (Bakken shale), Los Angeles basin (Nodular shale), and the Illinois basin (New Albany Shale).
181 citations
TL;DR: In this article, the authors used a 3D model to model the three-dimensional distribution of migration pathways within the petroleum system using a program based on the parameters discussed in this paper.
Abstract: Petroleum migration pathways through a basin are determined by the three-dimensional distribution of discontinuous sealing surfaces, which are usually parallel to bedding. The petroleum migrates below the sealing surface, taking the structurally most advantageous route. The three-dimensional distribution of migration pathways within the petroleum system can be modeled on a personal computer using a program based on the parameters discussed in this paper. Application of the model to the Paris and Williston basins demonstrates that a good correlation between predicted pathways and discovered accumulations can be made using simple models. Pathways form a dense network overlying generating areas in the central parts of basins. Toward the basin margins these routes commonly become increasingly focused into discrete pathways by the sealing-surface morphologies. Eventually, these pathways may reach the surface as seepages. It is important to integrate surface outcrops of migration routes (surface seepages) into migration modeling. Deflection of the pathways from the structurally most advantageous route below the sealing surface may be caused by lateral sealing barriers due to facies variation in the carrier rock below the seal, fault juxtaposition, or cross-formational seals such as salt intrusions. Deflection of pathways also occurs where there are hydrodynamic conditions in response to topography-driven groundwater flow. Zones of vertical migration are associated with facies changes along the horizon of the sealing surface into a nonsealing facies, or juxtaposition to nonsealing strata by faults. Vertical migration from either normally or abnormally pressured strata is most likely to occur into normally or lesser pressured strata at intrabasinal highs where hydrocarbons can be stored and transferred at times of temporary seal rupture. Reverse modeling of individual pathways from fields and seepages to potential sources is a powerful exploration tool. It assists in predicting the boundaries of the leaking accumulations or areas of petroleum expulsion.
159 citations
TL;DR: Moos et al. as mentioned in this paper used borehole televiewer (BHTV) data from four wells within the onshore and offshore Santa Maria basin, California, to investigate the relationships among fracture distribution, orientation, and variation with depth and in-situ stress.
Abstract: We used borehole televiewer (BHTV) data from four wells within the onshore and offshore Santa Maria basin, California, to investigate the relationships among fracture distribution, orientation, and variation with depth and in-situ stress. Our analysis of stress-induced well-bore breakouts shows a uniform northeast maximum horizontal stress (SH max) orientation in each well. This direction is consistent with the SH max direction determined from well-bore breakouts in other wells in this region, the northwest trend of active fold axes, and kinematic inversion of nearby earthquake focal plane mechanisms. In contrast to the uniformity of the stress field, fracture orientation, dip, and frequency vary considerably from well to well and within each well. With depth, fractures can be divided into distinct subsets on the basis of fracture frequency and orientation, which correlate with changes of lithology and physical properties. Although factors such as tectonic history, diagenesis, and structural variations obviously have influenced fracture distribution, integration of the in-situ stress and fracture data sets indicates that many of the fractures, faults, and bedding planes are active, small-scale strike-slip and reverse faults in the current northeast-trending transpressive stress field. In fact, we observed local breakout rotations in the wells, providing kinematic evidence for recent shear motion along fracture ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received April 15, 1996; revised manuscript received December 27, 1996; final acceptance July 15, 1997. 2Department of Geophysics, Stanford University, Stanford, California 94305-2215. We wish to thank Tom Zalan of the Chevron U.S.A. Production Company for providing the offshore well data, Unocal Corporation for providing the data on the onshore well, and Marcia McLaren from Pacific Gas and Electric Company for providing the earthquake focal mechanisms used in the stress inversion analysis. The data used as background seismicity in Figure 1 were extracted from the World Wide Web of the Southern California Seismic Network (SCSN) catalog operated jointly by the Seismological Laboratory at Caltech and the U.S. Geological Survey, both in Pasadena, California. We appreciate the comments and helpful discussions from Daniel Moos, Steve Graham, and Lev Vernik.
138 citations
TL;DR: In the Smackover Formation at Black Creek Field, Mississippi, the formation has been buried to a depth of 6 km, has experienced temperatures of over 200 degrees C, and presently contains 78% H 2 S, 20% CO 2, and 2% CH 4 as mentioned in this paper.
Abstract: Organic-inorganic interactions during burial of the Smackover Formation at Black Creek Field, Mississippi, have resulted in nearly complete destruction of hydrocarbons. The formation has been buried to a depth of 6 km, has experienced temperatures of over 200 degrees C, and presently contains 78% H 2 S, 20% CO 2 , and 2% CH 4 . Three distinct stages of burial diagenesis correspond to three phases of organic matter maturation. Pre-oil window diagenesis was dominated by precipitation of prebitumen calcite cement. Diagenesis in the oil window was characterized by precipitation of saddle dolomite and anhydrite in water-filled layers and by formation of solid bitumen in the oil column. Diagenesis in the gas window was dominated by thermochemical sulfate reduction (TSR) resulting in hydrocarbon destruction, anhydrite dissolution, large amounts of H 2 S, CO 2 , and S generation, and postbitumen calcite cementation. During TSR, anhydrite reacted with H 2 S to produce S , which in turn reacted with CH 4 to generate more H 2 S in a self-reinforcing cycle. The lack of metal cations to stabilize H 2 S as metal sulfides, availability of sufficient sulfate to generate H 2 S, and a closed system to prevent H 2 S from escaping resulted in the continuation of the TSR cycle until nearly all hydrocarbons were consumed. In Mississippi, concentration of H 2 S is nearly zero in Smackover hydrocarbon reservoirs that have experienced temperatures of 120 degrees C for more than 50 m.y., suggesting that TSR is not a kinetic (time-dependent) process. High H 2 S concentrations initiate at temperatures above 140 degrees C and increase with temperature, indicating that TSR is a thermodynamic phenomenon. Reported high H 2 S concentrations at low temperatures (80-120 degrees C) from other locations may be explained by the following processes; (1) migration of H 2 S into these reservoirs, (2) high geothermal gradients or local thermal perturbations in the past, (3) a biochemical origin for the H 2 S, or (4) exposure of these reservoirs to temperatures greater than 150 degrees C and a rapid uplift. In Black Creek Field, burial cementation and pressure solution resulted in total destruction of porosity and permeability in limestone reservoirs, but not in dolomite reservoirs, which still possess up to 20% porosity and 100 md permeability. Secondary porosity was not created as a result of hydrocarbon migration. Abundant CO 2 derived during hydrocarbon destruction resulted in calcite cementation rather than carbonate dissolution. Late, secondary porosity development in carbonates may be related to acids generated by metal sulfide precipitation.
137 citations
TL;DR: The Tertiary fold-thrust belt in Oscar II Land, central Spitsbergen, consists of three major structural zones of distinct structural style: (1) a western basement-involved fold-THrust complex, (2) a central zone of thin-skinned foldthrust units above a decollement in Permian evaporites, and (3) an eastern zone characterized by a frontal duplex system in the fold-Thrust belt, bounded eastward by steep, basement-rooted reverse faults (Billefjorden and Lom
Abstract: The Tertiary fold-thrust belt in Oscar II Land, central Spitsbergen, consists of three major zones of distinct structural style: (1) a western basement-involved fold-thrust complex, (2) a central zone of thin-skinned fold-thrust units above a decollement in Permian evaporites, and (3) an eastern zone characterized by a frontal duplex system in the fold-thrust belt, bounded eastward by steep, basement-rooted reverse faults (Billefjorden and Lomfjorden fault zones) beneath subhorizontal platform strata. Offshore seismic data from Isfjorden (Statoil) confirm the threefold zonation and document thick-skinned and thin-skinned structural interactions in both the fold-thrust belt and the foreland section. An admissible cross section yields about 45%, or 20 km, of shortening in Oscar II Land. Deeper parts of the seismic profiles show fault-bounded Devonian (central and east) and Carboniferous (west) basins. The structural grain of the Tertiary fold-thrust belt partly coincides with the margin-bounding normal faults of these basins, suggesting that preexisting structures and stratigraphy controlled the Tertiary fold-thrust belt development. A kinematic evolution of the fold-thrust belt is invoked: (1) north-northeast-directed, bedding-parallel shortening, (2) major west-southwest-east-northeast shortening, with in-sequence foreland fold-thrust propagation, (3) basement-involved, west-southwest-east-northeast uplift in the eastern foreland zone, (4) eastward out-of-sequence propagation of thrusts, and (5) west-east extension in the hinterland. Our regional structural compilation map and synthesis of the central Spitsbergen transect advocates structural variation and linked basement-involved thrusting in the hinterland and thin-skinned/thick-skinned reactivation and out-of-sequence thrusting in the east (foreland), and is new compared with previous work of the region. The synthesis also raises several important new structural play concepts for investigating hydrocarbon prospects in Spitsbergen and adjacent regions; for example, inverted Carboniferous basins, and traps produced by Tertiary thin- and thick-skinned contraction and reactivation structures.
TL;DR: The Pennsylvanian Jackfork Group in the Ouachita Mountains of Arkansas and Oklahoma has been interpreted by many workers, including as mentioned in this paper as a classic flysch sequence dominated by turbidites in a submarine fan setting; however, normal size grading and Bouma sequences are essentially absent in these sandstone beds.
Abstract: The Pennsylvanian Jackfork Group in the Ouachita Mountains of Arkansas and Oklahoma has conventionally been interpreted by many workers, including us, as a classic flysch sequence dominated by turbidites in a submarine fan setting; however, normal size grading and Bouma sequences, indicative of turbidite deposition, are essentially absent in these sandstone beds. They appear massive (i.e., structureless) in outcrop, but when slabbed reveal diagnostic internal features. These beds exhibit sharp and irregular upper bedding contacts, inverse size grading, floating mudstone clasts, a planar clast fabric, lateral pinch-out geometries, moderate to high detrital matrix (up to 25%), sigmoidal deformation (duplex) structures, and contorted layers. All these features indicate sand mplacement by debris flows (mass flows) and slumps. Mud matrix in these sandstones was sufficient to provide cohesive strength to the flow. Discrete units of current ripples and horizontal laminae have been interpreted to represent traction processes associated with bottom-current reworking. The dominance of sandy debris-flow and slump deposits (nearly 70% at DeGray Spillway section) and bottom-current reworked deposits (40% at Kiamichi Mountain section), and the lack of turbidites in the Jackfork Group have led us to propose a slope setting. Our rejection of a submarine fan setting has important implications for predicting sand-body geometry and continuity because deposits of fluidal turbidity currents in fans are laterally more continuous than those of plastic debris flows and slumps on slopes. A turbidite-dominated fan model would predict an outer fan environment with laterally continuous, sheetlike sandstones for the Jackfork Group in southern Oklahoma and western Arkansas, whereas a debris-flow/slump model would predict predominantly a slope environment with disconne ted sandstone bodies for the same area.
TL;DR: In this article, a procedure for identifying and characterizing petrophysical flow units helps resolve some of the key challenges faced in exploration for and production of carbonate reservoirs, and the application of this model reveals that one key to understanding and predicting the performance of Carbonate reservoirs is to represent them as combinations of different flow units, each with uniform porethroat size distribution and similar performance.
Abstract: A procedure for identifying and characterizing petrophysical flow units helps resolve some of the key challenges faced in exploration for and production of carbonate reservoirs. The application of this model reveals that one key to understanding and predicting the performance of carbonate reservoirs is to represent them as combinations of different flow units, each with uniform pore-throat size distribution and similar performance. If a relationship exists between depositional facies and flow units, one can develop a common geological and engineering zonation. Parasequences can then be characterized in terms of petrophysical flow unit types. Combining the water saturation, hydrocarbon column height, and relationships of these flow units with the interpreted sequence stratigraphy of the area provides a useful tool for mapping reservoir performance cells to predict the location of stratigraphic traps. This approach can also be useful in managing producing reservoirs to develop bypassed pay and to establish presimulation performance predictions. To illustrate this method, we use five examples: a Middle East limestone, where the model is used to identify reservoir zones with significantly different performance that are less evident from log porosity alone; the Madison carbonate of the Williston basin, ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received March 23, 1995; revised manuscript received July 7, 1996; final acceptance November 11, 1996. 2Conoco Inc., P.O. Box 2197, Houston, Texas 77252. 3DJH Energy Consulting, P.O. Box 271, Fredericksburg, Texas 78624. Thanks to Conoco Inc. for allowing publication of these examples and to all who have contributed to them. A special thanks goes to the following helpful people: Stanley Bohon, Donna Harwell, and Ginnie Murphy for providing graphics support; Dena Wagner for numerous database logistics; Sheri Gretschel and Chi Chi Coleman for typing help; Rob Pascoe for Middle East sequence stratigraphy; Tom Anderson for his historical perspective on Little Knife's discovery and appraisal; Charles Ways for guidance on the San Andres; Bill Hardie for the opportunity to work on Dagger Draw and for his technical input on the reservoir geology; Andre Bouchard for all of his advice on capillary pressure; Ray Mitchell for allowing us to include the B.F. 12 core description; Randy Mitchell for his talent of combining personnel; and Tim Borbas for championing the assimilation of our model to Tertiary clastics applications in the Gulf of Mexico.
TL;DR: In this article, the migration and filling model presented in this paper suggests that the oil and gas represent two different migration phases and that gas migration and fill predate oil emplacement.
Abstract: Troll Field represents the largest petroleum discovery within the entire North Sea area in oil equivalents, with 74% of the accumulated petroleum present as dry gas and 26% as a heavy biodegraded oil leg. The field is divided into several provinces based on the distribution of gas and oil, and the gas and oil have been suggested to be cogenetic. The migration and filling model presented in this paper suggests that the oil and gas represent two different migration phases and that gas migration and filling predate oil emplacement. Two different oil populations have been characterized and mapped in Troll field applying conventional geochemical techniques. We suggest that the two oil populations migrated into the structure through two different migration systems. Oil and gas were subsequently biodegraded within the reservoir. The two oil populations have been found in neighboring oil and gas discoveries, and an oil-oil correlation with these discoveries has been used to determine the location of field filling points and regional migration routes. When oil biodegradation terminated, fresh oil continued to migrate into the reservoir and mixed with the residue of the biodegraded oil. The field was tilted downward to the west in the Neogene, and oil and gas remigrated within the field with a possible spillage of gas. Tilting resulted in a dominantly upward movement of the oil phase whereas gas migrated laterally. Residual oils in the water zone have been used to reconstruct the paleoconfiguration of the field that controlled the current distribution of oil populations within Troll Field.
TL;DR: In this paper, two fracture sets dominate the Lisburne Group carbonates of the North Slope subsurface and the nearby northeastern Brooks Range fold and thrust belt, and they are overprinted by younger east-northeast-striking fractures related to subsequent contractional deformation.
Abstract: The Carboniferous Lisburne Group of northern Alaska has been deformed into a variety of map-scale structures in both compressional and extensional structural settings, thus providing a series of natural experiments for observing the formation, distribution, and behavior of fractures in this thick carbonate unit. Two fracture sets dominate the Lisburne Group carbonates of the North Slope subsurface and the nearby northeastern Brooks Range fold and thrust belt. North-northwest-striking regional extension fractures probably formed in front of the northeastern Brooks Range fold and thrust belt. In the North Slope subsurface, this fracture set overprints east-northeast-striking fractures related to earlier extensional deformation; in contrast, in the fold and thrust belt, the north-northwest-striking fracture set is overprinted by younger east-northeast-striking fractures related to subsequent contractional deformation. Lithology is the primary control on the fracture density of both sets. In mildly deformed Lisburne ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received February 20, 1996; revised manuscript received November 25, 1996; final acceptance June 5, 1997. 2Geophysical Institute, University of Alaska Fairbanks, Fairbanks, Alaska 99775. 3Sandia National Laboratories, MS 0705, Albuquerque, New Mexico, 87185. 4Department of Petroleum & Natural Gas Engineering, New Mexico Institute of Mining & Technology, Socorro, New Mexico 87801, and Sandla National Laboratories, MS 0705, Albuquerque, New Mexico, 87185. This study was supported by a Department of Energy subcontract administered by Sandia National Laboratories. Additional support was provided by ARCO Alaska, BP Alaska, Chevron, Exxon, Mobil, and Japan National Oil Company. We would like to thank ARCO Alaska and BP Alaska for giving us permission to view selected Lisburne Group cores, W. Wallace for helpful discussions on deformational styles of detachment folds, A. J. Mansure for help in interpreting the interference tests, and W. Wallace, K. Biddle, W. Belfield, N. Hurley, and J. Kelley for helpful reviews of the manuscript.
Journal Article•
TL;DR: In this article, the authors describe how fracture strike can be documented on a bed-by-bed basis even in well bores where few or no visible fractures are directly sampled.
Abstract: In siliciclastic hydrocarbon reservoir rocks, economic gas and oil production may depend on the attributes of natural fractures, and, with the advent of horizontal drilling, fractures are increasingly exploration and development targets; yet reliable information on such key fracture attributes as orientation (strike) is sparse because few fractures intersect vertical well bores. This paper describes how fracture strike can be documented on a bed-by-bed basis even in well bores where few or no visible fractures are directly sampled. Quartz-lined opening-mode microfractures (lengths of microns to millimeters) in quartz-cemented sandstones commonly are not visible using standard petrographic methods, but systematic mapping of these microfractures is possible using photomultiplier-based electron beam-induced luminescence (scanned cathodoluminescence) imaging. As shown by observations, primarily from three natural gas plays and one oil play in the United States, microfracture strike is a good guide to the strike of large fractures (macrofractures) that formed concurrently. Because microfractures are widespread and small specimens can be used to get accurate fracture-strike data, this approach can be applied to samples obtained from wireline-conveyed rotary (drilled) sidewall coring devices, as well as to samples from full-diameter core.
TL;DR: In this paper, the southwestern part of the western Mediterranean Alboran Basin, including the portion of the alboran ridge (Xaouen Bank), was investigated through the analysis of 28 intersecting multichannel seismic lines.
Abstract: The southwestern part of the western Mediterranean Alboran Basin, including part of the Alboran ridge (Xaouen Bank), was investigated through the analysis of 28 intersecting multichannel seismic lines. The seismic stratigraphy is tied to the Amoco well El-Jebha 1. Five seismic units or subunits are described from the Quaternary to the middle (and lower?) Miocene. The acoustic basement is interpreted to be mainly Paleozoic and Triassic metamorphic rocks of the Alboran Domain nappes, and, in places, middle Miocene-Messinian calc-alkalic volcanics. In the depocenters, the thickness of the sedimentary infill (mostly clays and turbidites) exceeds 9 km. Normal faults of middle Miocene-Tortonian age are broadly parallel to the coast, and dip either seaward or landward. They were mostly inverted during pre- and post-Messinian episodes of compression, which formed a set of en echelon, north-verging faulted folds in the Alboran ridge area, in relation with sinistral movement along the offshore projection of the Jebha fault. After Pliocene subsidence, a final episode of compression reactivated the earlier folds and pushed the Alboran ridge onto the Moroccan slope. The complex structural history suggests many structural and stratigraphic potential hydrocarbon traps. A high-resolution seismic survey could lead to the definition of new exploration plays.
TL;DR: In this article, the authors measured the thickness and width of fluvial sandstone and shale bodies from extensive photomosaics of the Upper Jurassic Salt Wash Sandstone Member in the Henry Mountains area of southern Utah.
Abstract: Excellent three-dimensional exposures of the Upper Jurassic Salt Wash Sandstone Member of the Morrison Formation in the Henry Mountains area of southern Utah allow measurement of the thickness and width of fluvial sandstone and shale bodies from extensive photomosaics. The Salt Wash Sandstone Member is composed of fluvial channel fill, abandoned channel fill, and overbank/flood-plain strata that were deposited on a broad alluvial plain of low-sinuosity, sandy, braided streams flowing northeast. A hierarchy of sandstone and shale bodies in the Salt Wash Sandstone Member includes, in ascending order, trough cross-bedding, fining-upward units/mudstone intraclast conglomerates, single-story sandstone bodies/basal conglomerate, abandoned channel fill, multistory sandstone bodies, and overbank/flood-plain heterolithic strata. Trough cross-beds have an average width:thickness ratio (W:T) of 8.5:1 in the lower interval of the Salt Wash Sandstone Member and 10.4:1 in the upper interval. Fining-upward units are 0.5-3.0 m thick and 3-11 m wide. Single-story sandstone bodies in the upper interval are wider and thicker than their counterparts in the lower interval, based on average W:T, linear regression analysis, and cumulative relative frequency graphs. Multistory sandstone bodies are composed of two to eight stories, range up to 30 m thick and over 1500 m wide (W:T > 50:1), and are also larger in the upper interval. Heterolithic units between sandstone bodies include abandoned channel fill (W:T = 33:1) and overbank/flood-plain deposits (W:T = 70:1). Understanding W:T ratios from the component parts of an ancient, sandy, braided stream deposit can be applied in several ways to similar strata in other basins; for example, to (1) determine the width of a unit when only the thickness is known, (2) create correlation guidelines and maximum correlation lengths, (3) aid in interpreting the controls on fluvial architecture, and (4) place additional constraints on input variables to stratigraphic and fluid-flow modeling. The usefulness of these types of data demonstrates the need to develop more data sets from other depositional environments.
TL;DR: In 1989, the American Association of Petroleum Geologists (AOGG) developed a process to allow management to compare a wide variety of global exploration opportunities on a uniform and consistent basis as mentioned in this paper.
Abstract: In 1989, Chevron Overseas Petroleum, Inc., developed a process to allow management to compare a wide variety of global exploration opportunities on a uniform and consistent basis. Over the next five years, the process evolved into an effective method to plan exploration programs on a basis of value incorporating prospect ranking, budget allocation, and technology management. The final product is a continuous process and includes, within a single organizational unit, the integration of geologic risk assessment, probabilistic distribution of prospect hydrocarbon volumes, engineering development planning, and prospect economics. The process is based on the concepts of the play and hydrocarbon system. Other steps of the process (geologic risk assessment, volumetric estimation, engineering support, economic evaluation, and postdrill feedback) are considered extensions of fundamental knowledge and understanding of the underlying geological, engineering, and fiscal constraints imposed by these concepts. A foundation is set, describing the geologic framework and the prospect in terms of the play concept-source, reservoir, trap (including seal), and dynamics (timing/migration). The information and data from this description become the basis for subsquent steps in the process. Risk assessment assigns a probability of success to each of these four elements of the play concept, and multiplication of ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received February 16, 1996; revised manuscript received September 26, 1996; final acceptance February 4, 1997. 2Chevron Overseas Petroleum, Inc., P.O. Box 5046, San Ramon, California 94583-0946. We acknowledge the champion of this process, M. W. Boyce, without whose continuing, senior-management support this process would not have been possible. We acknowledge the pioneering efforts of C. L. Aguilera, G. A. Demaison, E. J. Durrer, F. R. Johnson, W. E. Perkins, J. L. Reich, and R. A. Seltzer, who established the framework for the process in its early stages. We also acknowledge the efforts to refine, document, and teach the process during the later stages by S. D. Adams, A. O. Akinpelu, G. A. Ankenbauer, G. L. Bliss, T. J. Humphrey, E. McLean, and D. B. Wallem. Finally, we acknowledge all the people who, over the past several decades, have championed such a process, but fell victim to deaf ears because of high oil prices or dumb luck. These people provided the well-founded basis for the theoretical and practical application of evaluation principles. We also wish to extend special thanks to Gerard Demaison and Erwin Durrer for their continuous support, guidance, and friendship.
TL;DR: In this paper, the authors integrated 500 km of seismic reflection profiles with surface geologic and drilling data to examine the deformation style and structure of the northern Potwar deformed zone (NPDZ) with particular emphasis on history of deformation of the Dhurnal oil field.
Abstract: The northern Potwar deformed zone (NPDZ) is part of the active foreland fold and thrust belt of the Salt Range and Potwar Plateau in northern Pakistan. About 500 km of seismic reflection profiles are integrated with surface geologic and drilling data to examine the deformation style and structure of the NPDZ with particular emphasis on history of deformation of the Dhurnal oil field. The seismic lines suggest that the overall structure of the eastern NPDZ is a duplex structure developed beneath a passive roof thrust. The roof thrust is generated from a tipline in the Miocene Murree Formation, and the sole thrust is initiated from the same Eocambrian evaporite zone that extends 80 km southward beneath the Soan syncline and Salt Range. The Dhurnal oil field structure is a pop-up at the southern margin of the NPDZ, and developed beneath the passive roof thrust. The passive roof thrust crops out just north of Dhurnal on the steep, northern limb of the Soan syncline. An overstep passive roof thrust (Sakhwal fault) is interpreted west of Dhurnal; this fault developed due to
TL;DR: In this article, the authors determined the MPP history for the Fulmar Formation sandstones (Upper Jurassic) of the Central Graben, North Sea, and compared the predictions to measured core data.
Abstract: The overpressure history of a sandstone can be estimated using a numerical model if the burial curve and geological setting are known. From the resulting effective stress, the maximum potential porosity (MPP) can be calculated. The MPP is the maximum porosity the rock could theoretically hold open at the modeled burial depth and pore pressure. Measured rock porosities should be at or below the MPP. We have determined the MPP history for the Fulmar Formation sandstones (Upper Jurassic) of the Central Graben, North Sea, and have compared the predictions to measured core data. We conclude that for the majority of the Fulmar Formation sandstones, the porosity evolution is a simple pattern of reduction during burial caused by compaction and cementation. However, in wells sited close to regional overpressure leak-off points, the porosity has been significantly increased from an end-of-Oligocene low (mean 21%) to the present-day values (mean 31%). This porosity increase occurred by feldspar dissolution, with the reaction products being removed from the sandstones. Secondary porosity generation and the export of solute occurred while the sandstone was highly overpressured, although still part of an open hydrogeological system. The generation of porosity within deeply buried sandstones is of commercial importance and potentially can be predicted.
TL;DR: In this paper, a map of faults in a 60 km2 area of the southern North Sea has been produced from three-dimensional seismic data, showing that the faults obey power-law cumulative-frequency distributions for throw (power-law exponent, D, 2.7) and length (D ~ 1.1).
Abstract: A map of faults in a 60 km2 area of the southern North Sea has been produced from three-dimensional seismic data. The faults shown on the map obey power-law cumulative-frequency distributions for throw (power-law exponent, D, ~ 2.7) and length (D ~ 1.1). Simulations have been carried out to correct for sampling biases in the data and to make predictions of the throw and length scaling characteristics of the faults. The most important bias is caused by poor resolution of the small displacement tip zones of faults. The raw data show considerable scatter in their length:throw ratios, but they more closely fit a linear relationship if a length of 500 m is added to each fault, thereby making up for the zones near the fault tips with throws (~ 15 m) below seismic resolution. Further variability in the data may be caused by such geological factors as fault interaction. Tip lengths have been extended to simulate the actual fault pattern in the study area. Maps produced by this procedure can be used to estimate the true connectivity of the fault network. Extending the faults results in greater connectivity than shown by the raw data, which may cause greater compartmentalization of the rock mass. This greater compartmentalization has implications for hydrocarbon exploitation if the faults ©Copyright 1996. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received October 2, 1995; revised manuscript received February 15, 1996; final acceptance July 15, 1996. 2Geomechanics Research Group, Department of Geology, University of Southampton, Southampton Oceanographic Centre, Empress Dock, European Way, Southampton, SO14 3ZH, United Kingdom. 3Present address: British Gas, Gas Research Centre, Ashby Road, Loughborough, Leicestershire, LE11 3QU, United Kingdom. 4Department of Geological Sciences, University of Plymouth, Drake Circus, Plymouth, PL4 8AA, United Kingdom. 5Present address: Rock Deformation Research Group, Department of Earth Sciences, University of Leeds, Leeds, LS2 9JT, United Kingdom. Mobil North Sea Ltd. is thanked for funding G. Pickering and for providing seismic data. Funding for field work in Somerset was given by the University of Plymouth. Kevin Biddle, Nancye Dawers, James Handschy, and William Shea are thanked for their careful reviews.
TL;DR: In the Melville Bay area, offshore northwest Greenland, very large structures and sedimentary basins, which were predicted many years ago on the basis of magnetic and gravity data, have been confirmed by a recent reconnaissance seismic survey, with implications that are encouraging for petroleum exploration in the area.
Abstract: In the Melville Bay area, offshore northwest Greenland, very large structures and sedimentary basins, which were predicted many years ago on the basis of magnetic and gravity data, have been confirmed by a recent reconnaissance seismic survey, with implications that are encouraging for petroleum exploration in the area. The Melville Bay area flanks a small ocean basin in Baffin Bay that is thought to have formed by oblique sea-floor spreading in the Eocene. There are two major, coast-parallel basins in the area. The inner basin, the Melville Bay Graben, is essentially a half graben with a maximum thickness of sediments exceeding 13 km. A complex fault- controlled ridge system separates this basin from the outer Kivioq Basin in which up to 7 km of sediments have accumulated. By analogy with onshore geology in the surrounding areas and well data from the continental shelves off southern west Greenland and Labrador to the south, it is expected that the first phase of rifting and sedimentation took place in the Early-middle Cretaceous, while a second phase of rifting took place in the latest Cretaceous and early Paleocene. Later, compression and inversion affected the northern part of the area, leading to the formation of large anticlinal structures. ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received January 30, 1996; revised manuscript received September 9, 1996; final acceptance January 21, 1997. 2GeoArctic Consulting Ltd., 1620 9th Street NW, Calgary, Alberta T2M 3L4, Canada. 3Nunaoil A/S, Pilestraede 52, DK-1112 Copenhagen, Denmark. 4Geological Survey of Denmark and Greenland, Thoravej 8, DK-2400 Copenhagen, Denmark. We wish to acknowledge the companies partaking in the KANUMAS project: BP, Exxon, Japan National Oil Company, Shell, Statoil, and Texaco, for allowing us the opportunity to publish this paper. Our thanks also to Rene Forsberg and Simon Ekholm, National Survey and Cadastre, for processing the gravity data for the paper, and to Alan Menelly (consultant) for discussions on the structural development of the area. Airborne gravity data were made available courtesy of John Brozena of the U.S. Naval Research Laboratory.
TL;DR: Wright et al. as discussed by the authors found that the fabric and composition of a series of Upper Permian high-volatile to lowvolatile bituminous coals of the Sydney basin have a marked effect on stress sensitivity of permeability, and thus on the reservoir characteristics of the coal.
Abstract: Fabric and composition of a series of Upper Permian high-volatile to low-volatile bituminous coals of the Sydney basin have a marked effect on stress sensitivity of permeability, and thus on the reservoir characteristics of the coal. The coals vary in composition from end members of predominantly bright-banded coal comprised mainly of the microlithotype vitrite and the maceral vitrinite, to dull coal composed of significant amounts of ash, inertinite group macerals, and the microlithotype inertite. The brighter coals are more extensively fractured with one or, more commonly, two or three regularly spaced fracture sets (cleats) spaced at 5-20 µm. Fusinite and semifusinite, common macerals in the dull coals, are characterized by phyteral porosity (mainly cell lumens) and fabric- selective intergranular porosity. The permeability of tested samples varies significantly with composition and effective stress. The fabric of the samples is the most important factor in determining permeability and stress sensitivity of permeability. Coals with the highest permeability are those with at least one well-developed, throughgoing fracture set; these samples generally include abundant vitrite bands. The lowest permeability samples are nonbanded, with an attrital fabric and significant authigenic mineralization. At ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received April 1, 1996; revised manuscript received December 4, 1996; final acceptance June 16, 1997. 2Department of Earth and Ocean Sciences, University of British Columbia, Vancouver, BC V6T 1Z4, Canada. This study was financially supported by a grant from CSIRO (Syndal) and by The Earth Resources Foundation, University of Sydney. Samples and some data were provided by Pacific Power Ltd., Sydney. I thank Paul Gamson, formerly of CSIRO, for overseeing the permeability analyses and facilitating some of the study. I thank K. Wright of the Earth Resources Foundation, University of Sydney; J. Enever of CSIRO; J. C. Close of Meridian Oil; and Chris Clarkson of University of British Columbia for their comments on an earlier draft of this paper. Reviewers Andrew Scott, Roger Taylor, and W. Ayers are thanked for their thoughtful comments.
TL;DR: In this article, an order of magnitude variation is found in fracture densities across this fold, and over two orders of magnitude variations occur in mean fracture aperture, suggesting fractal character.
Abstract: Monkshood anticline is a well-exposed surface anticline located in the Foothills in northeastern British Columbia. Extension fractures are well developed in the Prophet Formation (a carbonate-shale-chert sequence) throughout this fold. Virtually all of these fractures are filled with some combination of calcite and quartz cements. The fractures formed and the mineral cements were deposited during the fold development. Most fractures on Monkshood anticline have formed at high angles to bedding, and they commonly fall into two to three distinct orientation sets. The dominant fracture trend is aligned with the fold axis through the backlimb of the fold, but there is considerable variance in the dominant orientation in the forelimb. An order of magnitude variation is found in fracture densities across this fold, and over two orders of magnitude variation occur in mean fracture aperture. These variations in density and aperture do not correlate with particular structural positions. Fracture trace lengths exhibit power-law distribution patterns, suggesting fractal character. Fracture aperture displays a roughly linear correlation to volumetric fracture strain, but shows no consistent association with either density or trace length. Stochastic modeling of the fracture networks on Monkshood anticline suggests density is the primary factor affecting fracture network connectivity, but fracture size also can play an important supporting role. The occurrence of a dominant fracture orientation set can impart a significant directional bias to connectivity. Measurement stations on Monkshood anticline that have both high fracture densities (for connectivity) and substantial fracture apertures (for conductance) occur primarily in midlimb positions.
TL;DR: Shanmugan et al. as discussed by the authors, G., R. E.Shields, G. Mitchell, W. W. Beamish, R. B. Bloch, S. J. Damuth, T. M. Straume, S E. Syvertsen, and K.E. Shields, 1995, AAPG Bulletin v 79, p. 477-512.
Abstract: Original article : Shanmugan, G., R. B. Bloch, S. M. Mitchell, G. W. J. Beamish, R. J. Hodgkinson, J. E. Damuth, T. Straume, S. E. Syvertsen, and K. E. Shields, 1995, AAPG Bulletin, v. 79, p. 477-512.
TL;DR: In this paper, four exhumed hydrocarbon traps crop out in the Traill O region of East Greenland, each at the footwall crest of a fault-block formed during Early Cretaceous rifting.
Abstract: Four exhumed hydrocarbon traps crop out in the Traill O region of East Greenland, each at the footwall crest of a fault-block formed during Early Cretaceous rifting. Former oil accumulations are indicated by a pore fill or pore lining of solid bitumen within the Jurassic sandstone-dominated Vardekloft and Olympen formations. The Vardekloft Formation is divided into an undated fluvial-dominated lower unit (0-520 m) and a Bajocian-Callovian upper unit (65-1020 m) deposited in a shallow-marine environment. The Oxfordian Olympen Formation (0-250 m) contains shallow-marine and fluviodeltaic deposits. The sandstones are dominantly quartzarenites, and petrographic fabrics, such as dissolved feldspar, late quartz cement, and stylolites, are consistent with burial depths in excess of 2.5 km. Porosities ranged from 7 to 27% (generally about 20%, about one-half of which was primary), and permeabilities ranged from 1 to 622 md, prior to the formation of solid bitumen. The distribution of solid bitumen in each trap can be mapped out, allowing sealing elements and original oil-water contacts to be defined. Three of the four exhumed traps (Mols Bjerge, Laplace Bjerg, and Bjornedal) were simple one-seal structural traps. Conformable Upper Jurassic mudstone, unconformable Albian-Cenomanian mudstone, and normal faults are the three top-sealing elements. The fourth (Svinhufvuds Bjerge) was a poly-seal trap with a combined top-seal and a low-side fault closure. Preliminary estimates of the volume of original oil in place within these structures range from 0.2-1.1 billion bbl for the Mols Bjerge trap to 5.3-11.9 billion bbl for the Bjornedal trap. These estimates are prone to large errors, due to uncertainties in estimating original trap geometry, hydrocarbon saturation, and net/gross ratio, and in the understanding of volume changes of hydrocarbon in each trap during thermal degradation of the oil. The Upper Jurassic Bernbjerg Formation is the only known potential source rock in the region, which would require a drainage distance of less than the fault-block spacing to fill the largest of the traps. Secondary hydrocarbon migration into these traps occurred between the Cenomanian (age of the youngest sealing element) and early Eocene to late Oligocene (when widespread volcanism and sill intrusion resulted in thermal degradation of the oil). Each of these structures is relatively well exposed and accessible; we believe that they will provide excellent analogs for studies of enhanced recovery from the mature Lower-Middle Jurassic oil fields of Northwest Europe.
TL;DR: The late Middle to Late Ordovician (late Mohawkian to Cincinnatian) supersequence in Kentucky and Virginia is composed of four large third-order sequences (each 40-150 m thick) that are regionally correlative in outcrops, cores, and gamma-ray logs as discussed by the authors.
Abstract: The late Middle to Late Ordovician (late Mohawkian to Cincinnatian) supersequence in Kentucky and Virginia was deposited in a tectonically active foreland basin during a transition from the "ice-free" Early Ordovician to the glacial Late Ordovician. This sequence was deposited in less than 12 m.y., is 250-500 m thick, and is composed of four large third-order sequences (each 40-150 m thick) that are regionally correlative in outcrops, cores, and gamma-ray logs. Smaller scale third-order parasequence sets (up to 20 m thick) and component parasequences (1-8 m thick) make up the larger sequences, and are only locally correlative. Subtidal-dominated parasequences comprise the basal part of each sequence, whereas shallower subtidal- or peritidal-dominated parasequences compose upper parts of sequences. Each large, third-order sequence is asymmetric and marked by lowstand, transgressive, and highstand systems tracts with unique lithologic and gamma-ray log response characteristics. Ramp margin wedges (RMW) are poorly developed and consist of marine siltstone or grainstone/packstone sheets extending into deep ramp settings; these sheets have high gamma-ray values in their base and lower, blockier gamma-ray responses in their tops. Transgressive systems tracts (TST) are thin; composed of high-energy, locally phosphatic grainstone ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received February 7, 1996; revised manuscript received May 27, 1997; final acceptance June 16, 1997. 2Department of Geology, Virginia Tech, Blacksburg, Virginia 24061-0420. Present address: Department of Earth, Atmospheric and Planetary Sciences, Massachusetts Institute of Technology, Cambridge, Massachusetts 02139. 3Department of Geology, Virginia Tech, Blacksburg, Virginia 24061-0420. This study was supported by NSF Grant EAR-9316057 to J. F. Read, a grant from Mobil Oil Company, and grants-in-aid of research from the Geological Society of America and Appalachian Basin Industrial Associates to Mike Pope. We thank John Haynes, Brian Keith, and Rick Major for thorough and insightful reviews of an earlier version of this manuscript.
TL;DR: In this paper, the authors quantitatively determined sequence grain volume, defined as the volume of sedimentary grains in an individual stratigraphic sequence (total sequence volume minus cement and porosity volume), and calculated rates of total sediment supply to the basin in both time and space were then calculated.
Abstract: Sediment supply comprises a major family of regime variables that influence geomorphic surface grade. Spatial and temporal changes in total sediment supply and sediment texture (gravel:sand:mud ratio) will cause reconfiguration of depositional and erosional profiles, potentially creating or influencing the sequence stratigraphic framework of the basin. Sequence grain volume, which is defined as the volume of sedimentary grains in an individual stratigraphic sequence (total sequence volume minus cement and porosity volume), has been quantitatively determined for each of 16 genetic stratigraphic sequences in the North Sea Basin. Rates of total sediment supply to the basin in both time and space were then calculated. Sand grain volume and sand:mud ratio were also calculated for each sequence. These data define four principal episodes of Tertiary sediment supply. The most significant episode occurred in the late Paleocene and was followed by secondary episodes in the Eocene and Oligocene. A fourth Neogene episode extends through the present. All episodes correlate to source-terrain tectonic pulses related to evolution of the North Atlantic Basin, to intraplate stress changes associated with successive phases of the Alpine orogeny, or to the late Cenozoic epeirogenic uplift of Scandinavia. The major episodes, in turn, contain secondary sequence-to-sequence variations that correspond to changes in spatial or temporal values of one or both of the supply regime variables. Again, most changes closely reflect details within the histories of the principal tectonic phases. The history of changing source-area relief and resulting topographic grades and related changes in sediment yield into the basin was a principal control on North Sea Cenozoic sequence development. Source-basin relief, in turn, was largely determined by regional tectonism.