ALBERT

Description: Determination of multiphase flow properties considering the variation of fracture patterns (i.e., number of fracture sets, their orientation, length distribution, spacing, and in-situ aperture) remains a key challenge in reservoirs. In reservoir engineering, one way is by studying outcrop analogs with comparable petrophysical properties and a similar geological history, and incorporating these data into model building, discretization, and numerical simulation. The limitation of directly incorporating attributes measured on outcrops is that this method is error prone because of postburial processes. Mineralized fracture (vein) attributes are good candidates to use as analogs for open fractures formed under in-situ conditions, to establish the relationship between fracture length and aperture and help to reveal the conditions at the time of their formation, and to quantify fracture-induced porosity in rock masses. Vein attributes determined from scan lines and window samples were combined to condition the stochastic generation of fractures using the discrete fracture network code FracMan. Comparison of water breakthrough time and oil saturation at breakthrough was then determined by applying a constant pressure gradient for each realization to simulate water-flooding numerical simulation using the combined finite element–finite volume method. The different stochastic realizations were compared with discrete fracture and matrix models, and we show how the uncertainty in these fracture attributes affects multiphase flow behavior in naturally fractured rocks. Uncertainty in quantifying these attributes has a profound impact for predicting the oil recovery and water breakthrough time based on limited information from boreholes. Mandefro W. Belayneh is a research fellow at the Department of Earth Science and Engineering, Imperial College London, where he obtained his M.Sc. degree and his Ph.D. in structural geology. Prior to joining Imperial, he had industrial experience in Ethiopia. His research interests are studying the links between geological stresses, brittle failure, and fluid flow in the Earth's crust and their applications to fractured and faulted reservoirs. Stephan K. Matthai is the chair of reservoir engineering at Montan University of Leoben, School of Petroleum Engineering, Austria. He received a Ph.D. from the Australian National University. He was a governor's lecturer in earth science and engineering, Imperial College London. He has postdoctoral experience from Cornell University, the Swiss Federal Institute of Technology (ETH), and at the Department of Geological and Environmental Science, Stanford, California. His research interests are investigating complex geological processes by means of numerical simulations. Martin J. Blunt is a professor of petroleum engineering and head of the Department of Earth Science and Engineering at Imperial College London. He holds a B.A. degree and Ph.D. from Cambridge University. Before joining Imperial College, he was a research physicist with BP at Sunbury-on-Thames and a faculty member in the Department of Petroleum Engineering at Stanford University. His research interests are flow in porous media, reservoir engineering, flow in fractured systems, streamline-based simulation, carbon dioxide storage, and pore-scale modeling. Stephen F. Rogers received a B.A. degree in geology and management science from Keele University and a Ph.D. in rock mechanics from Nottingham University. He works for Golder Associates in Vancouver, British Columbia, as a senior geoscientist specializing in the characterization and modeling of fractured reservoirs. He is particularly interested in the integration of static and dynamic fracture data and the simulation of pressure transients through discrete fracture models for model calibration and validation.

Description: Average porosity values for the producing zones of oil and gas fields worldwide are examined as a function of the present depth for sandstone and carbonate lithologies divided into 10 groupings by reservoir depositional age (Precambrian–Silurian to Pliocene–Pleistocene). The wide variations in average reservoir porosity within each depth range reflect the extreme ranges in porosity-controlling factors such as depositional facies, early diagenetic histories, geothermal gradients, and degrees of uplift from previous maximum burial that exist in the Earth's petroleum reservoirs. Median porosity for a given depth nevertheless decreases with both increasing depth and age in most age and lithology categories examined. Maps of reservoir geographic distributions corresponding with each porosity-depth plot show the Earth's petroleum provinces in terms of reservoir ages and lithologies. The results demonstrate quantitatively and empirically the degree to which porosity is related to depth, lithology, and geological age on the global scale of observation. Steve has a Ph.D. from the University of California at Los Angeles. He works on sandstone and carbonate reservoir studies for exploration and production projects. Paul first joined Statoil in 1986, and now serves as a specialist in global exploration working on basin evaluation and petroleum systems analysis. Originating from Maine, Paul received his B.S. degree from Boston College and his Ph.D. from Dartmouth College. He received the Schlumberger Medal from the Mineralogical Society and the Brindley Award from the Clay Minerals Society. Presently, Paul is preparing a popular petroleum geology book outlining the diagenetic controls on hydrocarbon discovery and production efficiency, focusing on the strong relationships between recoverable reserves and reservoir temperature, as well as implications for future energy resource management. Øyvind received his M.Sc. degree in 1994 and his Ph.D. in 1997 in structural geology from the University of Oslo. He joined Statoil in 1997 and has been working as a production geologist and in exploration. His current research concerns the reconstruction of sedimentary basins and thermal-history modeling.

Description: Oil and gas reservoirs in the Cowley Formation (upper Osagean to lower Meramecian) are within a thick (up to 400 ft [122 m]) section of spiculite-dominated rocks, derived from demosponges, deposited in a low-latitude setting. These rocks are present in the subsurface for 325 mi (523 km) along paleostrike in southern Kansas and some adjoining states. They represent a stratigraphically significant lithosome that markedly contrasts thin and areally restricted spiculitic rocks present in some Mississippian reservoirs elsewhere in the mid-continent. Cowley lithologies represent a low-gradient ramp, whereon (1) bedded spiculites were deposited in moderate-energy, shallow-water, inner-ramp settings; (2) lenticular-, nodular-, or flaser (L/N/F)-bedded spiculite and shale were moderate- to low-energy, progressively deeper-water medial-ramp deposits; and (3) dark shales are deepest-water, outer-ramp facies. The internal stratigraphic architecture of the unconformity-bounded Cowley identifies it as a depositional sequence with component deepening-upward basal strata (transgressive systems tract) overlain by shallowing-upward, progradational clinoforms (highstand systems tract). Sequence deposition was punctuated by several unconformities attending short periods of subaerial exposure. Suppression of otherwise warm, shallow-water carbonate production, and instead spiculite deposition, in this low-latitude setting was likely a consequence of elevated concentrations of dissolved silica and nutrients in the ambient marine environment. Three successive generations of silicification are recognized in the rocks. Early partial silicification is presumed to have begun in the marine environment, and ensuing silicification and attendant porosity formation were likely coincident with falling sea level as pore fluids evolved from being of mixed marine-meteoric to meteoric composition. Petroleum reservoirs mainly with vuggy porosity are present in relatively high-porosity bedded spiculites and less porous L/N/F-bedded rocks. Traps commonly are developed in structurally modified, subunconformity buried-hills and truncated, gently dipping strata. Reservoirs in the L/N/F-bedded rocks locally extend considerable distances downdip within individual clinoformal parasequences in the section, thereby locally creating thick gas-saturated reservoir columns. Because of its great subsurface extent, the Cowley section, commonly bypassed during drilling, offers considerable potential for as-yet discovered fields in the mid-continent. Sal Mazzullo is a professor of geology, and his research has focused on the sedimentology and diagenesis of carbonate petroleum reservoirs. He therefore seeks absolution from the carbonate deities for this diversion to “the dark side.” He received his B.S. and M.S. degrees in geology from Brooklyn College, and his Ph.D. in geology in 1974 from Rensselaer Polytechnic Institute. His petroleum industry experience includes Texaco Research Laboratory, Houston, Texas (1975); manager of Stratigraphic Exploration, Union Texas Petroleum Corp., Midland, Texas (1978–1981), and an independent oil operator and consultant since 1981. Brian Wilhite received his B.S. degree in geology from Kansas State University (1996) and his M.S. degree in geology, with emphasis in carbonate sedimentology and sequence stratigraphy, from Wichita State University (2001). He joined Woolsey Operating Company, LLC (WOC) in late 2000 as an exploration geologist. His exploration focuses on mid-continent Paleozoic reservoirs, with special emphasis on Mississippian rocks. He has implemented a core and research division at WOC to further its exploration and production efforts. Wayne Woolsey received a B.S. degree in business administration from the University of North Texas (1951) and an M.S. degree in geology from Texas A&M (1958). He was the district geologist for Texaco, and during his 10 years there, he explored over a large area of the continental United States. During the last 38 years, through privately held Woolsey Companies, he has worked on the mid-continent basins of Kansas, Oklahoma, and Texas with a primary focus on the gas-prone Mississippian in south-central Kansas. He is the president and CEO of Woolsey Energy Corporation, the parent company that owns 100% of Woolsey Operating Company, LLC; American Pipeline Company, LLC; and Bluestem Gas Marketing, LLC.

Description: Accurate predictions of natural fracture flow attributes in sandstones require an understanding of the underlying mechanisms responsible for fracture growth and aperture preservation. Poroelastic stress calculations combined with fracture mechanics criteria show that it is possible to sustain opening-mode fracture growth with sublithostatic pore pressure without associated or preemptive shear failure. Crack-seal textures and fracture aperture to length ratios suggest that preserved fracture apertures reflect the loading state that caused propagation. This implies that, for quartz-rich sandstones, the synkinematic cement in the fractures and in the rock mass props fracture apertures open and reduces the possibility of aperture loss on unloading and relaxation. Fracture pattern development caused by subcritical fracture growth for a limited range of strain histories is demonstrated to result in widely disparate fracture pattern geometries. Substantial opening-mode growth can be generated by very small extensional strains (on the order of 10−4); consequently, fracture arrays are likely to form in the absence of larger scale structures. The effective permeabilities calculated for these low-strain fracture patterns are considerable. To replicate the lower permeabilities that typify tight gas sandstones requires the superimposition of systematic cement filling that preferentially plugs fracture tips and other narrower parts of the fracture pattern. Jon Olson is an associate professor in the Department of Petroleum and Geosystems Engineering. He joined the faculty in 1995. He has six years of industrial experience. He specializes in the applications of rock fracture and continuum mechanics to fractured reservoir characterization, hydraulic fracturing, and reservoir geomechanics. He was a distinguished lecturer for AAPG in 2007–2008. Steve Laubach is a senior research scientist at the Bureau Economic Geology where he conducts research on unconventional and fractured reservoirs. His interests include fluid inclusion and cathodoluminescence studies and application of borehole-imaging geophysical logs to stress and fracture evaluation. He was a distinguished lecturer for the Society of Petroleum Engineers in 2003–2004. Rob Lander develops diagenetic models for Geocosm LLC. He obtained his Ph.D. in geology from the University of Illinois in 1991, was a research geologist at Exxon Production Research from 1991 to 1993, and worked for Rogaland Research and Geologica AS from 1993 to 2000. He is also a research fellow at the Bureau of Economic Geology.

Description: In promoting the Ross Formation (Carboniferous Shannon Basin)2 as an excellent outcrop analog for Gulf of Mexico, oil-rich, Pliocene–Pleistocene, salt-withdrawal minibasins, Pyles (2008) reaffirmed the popular deep-sea-turbidite model for the Ross Formation (Collinson et al., 1991; Chapin et al., 1994; Elliott, 2000; Martinsen et al., 2000; Lien et al., 2003) without mentioning a detailed published reinterpretation of the Ross Formation as lacustrine, river-fed turbidites (hyperpycnites) and wave-modified turbidites (Higgs, 2004). Oil field development in technologically challenging deep-water settings can have costly economic consequences if based on predictions emanating from inappropriate outcrop analogs. Such consequences include, in order of increasing costliness, (1) selection of nonoptimum perforation intervals, causing lower production flow rates and lower ultimate recovery; (2) nonoptimum placement, spacing, and number of development wells, with the same effects; and (3) inaccurate predictions of reserves volume and production rates, leading to unwarranted declaration of field economic viability (hence major expenditures such as platforms, development drilling programs, and pipelines) or nonviability (Higgs, 2004). For an outcrop to be considered analogous to any given subsurface example, the two facies associations should be essentially indistinguishable, insofar as this can be judged from the existing core control; in other words, the interpreted depositional processes should be the same, resulting in near-identical sand-body (reservoir) architecture. Given the passive margin context and present deep-water (below storm wavebase) slope setting of the Gulf of Mexico minibasins (e.g., Pyles, 2008), a similar deep-marine setting can be inferred for the Pliocene–Pleistocene. In contrast, the Ross Formation may be neither marine nor of deep-water origin. Sedimentological evidence summarized below suggests (1) lowered salinity, amenable to much greater frequency and duration of hyperpycnal flows than in …

Description: Peter Hennings received his B.S. and M.S. degrees in geology from Texas A&M University and his Ph.D. in geology from the University of Texas. He has held various technical and supervisory positions in Mobil Research Company, Phillips Petroleum Company, and ConocoPhillips. His research and application focus in these positions includes structure and tectonics, seismic interpretation, reservoir description, geomechanics, and fracture characterization. He is the manager of the Structure and Geomechanics Group in ConocoPhillips Subsurface Technology. He is an AAPG Distinguished lecturer, a Geological Society of America Honorary Fellow, and an adjunct professor at the University of Wyoming. In July 2008, a Hedberg research conference entitled “The Geologic Occurrence and Hydraulic Significance of Fractures in Reservoirs” was hosted jointly by the AAPG, Society of Petroleum Engineers (SPE), and Society of Exploration Geophysicists (SEG), and organized by AAPG in Casper, Wyoming. The original endorsement for the conference was by recommendation from the author and the AAPG Reservoir Deformation Research Group, a standing subcommittee of the AAPG Research Committee. The scientific justification for conducting the conference was the rapidly growing recognition by the industry and academia that natural fractures and their geomechanical framework commonly control the hydraulic behavior of reservoirs. The sciences of fracture detection, characterization, and hydraulic modeling must advance if we are to maximize recovery from fractured reservoirs and optimize our exploitation of emerging resources, especially in the nonconventional realm. Success in these areas requires interdisciplinary integration from geophysical acquisition, processing, and analysis, to petrophysics, geological interpretation, geomechanics, and reservoir engineering at scales from pores to fields. The last research conference in North America dedicated to the topic was conducted in 1997. Therefore, the agenda was designed to address fractured reservoirs at a fundamental level to assess progress in the last decade. The participants addressed the following questions.

Description: Conventional reservoir modeling approaches are developed to account for uncertainty associated with sparse subsurface data but are not equipped for detailed reconstruction of high-resolution geologic data sets. We present a surface-based modeling procedure that enables explicit representation of heterogeneity across a hierarchy of length scales. Numerous surfaces are used to construct complex facies-body geometries and distributions prior to generating a grid, allowing sampled and conceptual data to be fully incorporated within field-scale models. Our approach is driven by the improved efficiency that surfaces introduce to reservoir modeling through their geologically intuitive design, rapid construction, and ease of manipulation. Cornerpoint gridding of the architecture defined by the surfaces reduces the number of cells required to represent complex geometries, thus preserving geologic detail and rendering upscaling unnecessary for fluid-flow simulations. The application of surface-based modeling is demonstrated by reconstructing the detailed three-dimensional facies architecture of a wave-dominated shoreface-shelf parasequence from a rich outcrop data set. The studied outcrop data set describes reservoir architecture in a generic analog for many shallow-marine reservoirs. The process of model construction has demonstrated the function of (1) shoreface-shelf clinoforms, (2) paleogeographic changes in shoreline orientation, and (3) storm-event-bed amalgamation in controlling facies architecture. These subtle geometric features cannot be accurately represented using conventional stochastic reservoir modeling algorithms, which results in poor estimation of facies proportions and associated hydrocarbon volumes in place. In contrast, the surface-based modeling approach honors all data and captures subtle geometric facies relationships, thus allowing detailed and robust reservoir characterization. Richard Sech is a research scientist at ExxonMobil Upstream Research Company, Houston. He holds a B.S. degree in exploration geology from Cardiff University, an M.S. degree in reservoir evaluation and management from Heriot-Watt University, and a Ph.D. in petroleum engineering from Imperial College, London. His research interests are in reservoir modeling and quantifying the influence of geologic heterogeneity on fluid flow behavior. Matthew Jackson is a senior lecturer in reservoir engineering in the Department of Earth Science and Engineering, Imperial College, London. He holds a B.S. degree in physics from Imperial College and a Ph.D. in geological fluid mechanics from the University of Liverpool. His research interests include simulation of multiphase flow through porous media, representation of geologic heterogeneity in simulation models, and downhole monitoring and control in instrumented wells. Gary Hampson is a senior lecturer in sedimentary geology in the Department of Earth Science and Engineering, Imperial College, London. He holds a B.A. degree in natural sciences from the University of Cambridge and a Ph.D. in sedimentology and sequence stratigraphy from the University of Liverpool. His research interests lie in the understanding of siliciclastic depositional systems and their preserved stratigraphy, and in applying this knowledge to reservoir characterization.

Description: This article evaluates the impact of a submarine channel sand in the western Wilmington oil field, California, on hydrocarbon accumulation and leakage across boundary faults. The Wilmington field is in a broad anticline broken into 10 fault blocks by normal faults. The coarse-grained channel deposit, named T4, is identified in fault blocks I through III within the Tar zone, a lower Pliocene turbidite deposit and the shallowest productive zone in the area. The channel deposit incised into three sand units: T2, T5, and T7. Evidences of tilted oil-water contacts (OWC), OWC cutting structure depth contours, scattered oil traces, and fault seal analysis all indicate that the channel deposit is responsible for hydrocarbon leakage across the boundary faults. The leakage occurs in the three channel-incised sand units: T2, T5, and T7. In fault block I, hydrocarbons in the three sands charge the channel sand at the structural culmination, and then leak across the eastern boundary Wilmington fault into the wet S sand directly above the Tar zone on the hanging-wall block. In fault block IIA, hydrocarbons from the T5 and T7 sands pool in the channel sand on the north flank and leak across the eastern boundary Ford fault into the S sand on the hanging-wall block. This leakage across faults caused depletion of almost all hydrocarbon accumulations in the three channel-incised sands in fault block I. The leakage also raised OWCs on the north flank in fault block IIA, resulting in tilted OWCs in the two channel-incised sand intervals. Linji Y. An is a geologist with Aera Energy LLC. After receiving his Ph.D. degree in earth sciences from the University of Southern California in 1996, he worked for System Technology Associates, Atlantic Richfield Company (ARCO) Exploration and Production Technology, and Sterling Commerce. His interests include fault and fracture network analysis, fault seal analysis, geologic modeling, and software development. Currently, he focuses on characterization of diatomite reservoirs.

Description: The geochemistry of formation fluids (water and hydrocarbon gases) in the Uinta Basin, Utah, is evaluated at the regional scale based on fluid sampling and compilation of past records. The deep formation water is dominated by Na-Cl type where halite dissolution has the greatest effects on water chemistry. Its distribution and composition is controlled by both the lithology of geological formations and regional hydrodynamics. The origin of the saline waters in the southeastern basin is interpreted to be a mix of ancient evaporatively concentrated seawater with meteoric water recharged in the geological past, which has experienced water-rock interactions. At the basin scale, three-dimensional mapping of the dissolved solid contents further reveals that (1) in the northern Uinta Basin bordering the Uinta Mountains, significant flushing of the deep basinal brines up to 6-km (3.7-mi) depth by meteoric water has occurred, and (2) in the central basin groundwater discharge areas along the Green River Valley, regional upwelling of saline waters from 2- to 3-km (1.2- to 1.8-mi) depth is occurring. Moreover, gas composition and water-gas stable isotope characteristics in the central to southeastern basin indicate the presence of a deep, thermogenic, and regionally continuous gas deposit. In particular, gases sampled in this region from the Wasatch Formation and Mesaverde Group indicate a similar source rock (type III kerogen of the deeply buried, thermally mature Mesaverde Group in the central to northern basin) as well as migration from the Natural Buttes gas field toward the southeastern basin. Evidence for biogenic methane formation is observed only in the upper Green River Formation in the central to northern Uinta Basin. Here, the organic-rich, immature Green River shales experience meteoric water invasions and formation fluid chemistry, and stable isotope compositions are diagnostic of microbial methanogenesis. Ye Zhang received her B.S. degree in hydrogeology and engineering geology from Nanjing University, P.R. China (1998); her M.S. degree in hydrogeology from the University of Minnesota (2004); and her Ph.D. in hydrogeology from Indiana University (2005). She is currently an assistant professor of geology at the University of Wyoming. Her research interests include geological modeling and fluid-flow simulation, scientific computing, and aqueous and hydrocarbon gas geochemistry. Carl Gable received his A.B. degree in geophysics from the University of California, Berkeley, and his M.S. degree in applied physics and Ph.D. in geophysics from Harvard University. Since 1990 he has been a staff scientist at Los Alamos National Laboratory working in various areas of computational fluid dynamics and continuum mechanics applied to geologic systems. His main focus is in research and application of finite element mesh generation, computational geometry, and flow and transport in porous media. George A. Zyvoloski received his B.S. (1971) and M.S. (1972) degrees and Ph.D. (1975) in mechanical engineering from the University of California, Santa Barbara. He has been at Los Alamos since 1979, where he has developed numerical methods and software to solve subsurface flow and transport problems related to geothermal energy extraction and radionuclide transport as well as conventional and unconventional oil and gas production. Lynn M. Walter received her M.S. degree from Louisiana State University (1978) and her Ph.D. from the University of Miami (1983). She was an assistant professor at Washington University in St. Louis until 1988. She then joined the University of Michigan, where she is now a professor of geological sciences and director of the Experimental and Analytical Geochemistry Laboratory. Her research interests focus on the hydrogeochemistry of near-surface and deeper basin environments, with emphasis on carbon transformations and mineral mass transport.

Description: The Mackenzie Basin in northwest arctic Canada has many characteristics of a typical terrestrial, gas-rich sedimentary basin, but the origins of this important hydrocarbon province are still not well known. The three-dimensional basin modeling approach employed here illustrates not only improved capabilities but also potential pitfalls in reproducing flow in complex stratal and structural basin architectures of present-day models. Listric fault structures especially are still inadequately reproduced in most migration models. By integrating individual styles of deformation and introducing a sequence-stratigraphic approach to reproduce the stratal architecture, we are able to identify temporal and spatial relationships between sources and reservoirs. Based on these considerations, three genetic groups of oils in the basin are proposed: a first group mainly related to a Paleocene source rock, a second group related almost exclusively to an early mature source in the Eocene Taglu formation, and a third group related to the Upper Cretaceous Smoking Hills and Boundary Creek formations. In contrast to oil accumulations, gas accumulations resulted mainly from a filling event in the late Miocene, which is interpreted to be related to a decrease in pressure during a late Miocene uplift and erosional event. The Mackenzie Basin is therefore an excellent example to show that the gas proneness of a mature petroleum system, especially if the organic matter is predominantly of terrestrial origin, is mainly a function of expulsion efficiency and timing and thus is directly linked to the structural history of the basin. Karsten Kroeger joined GNS Science in 2008 as a basin modeler after his time as a postdoctoral fellow at GFZ German Research Center for Geosciences. He holds a diploma in geology from the Technical University in Karlsruhe and a Ph.D. from the Johannes Gutenberg University of Mainz on Tertiary isotope systems, paleoecology, and carbonate sedimentology. His research focuses on sedimentary systems, stratigraphy, and their application in integrated basin and earth systems modeling. Rolando di Primio joined the German Research Center for Geosciences as a senior research scientist in 2001 after having worked as an exploration geologist in the Norwegian petroleum industry for several years. He holds a diploma in geology from the Rheinisch-Westfälische Technische Hochschule Aachen, Germany, and a Ph.D. from the University of Cologne. His research interests are hydrocarbon phase behavior, basin modeling, and organic geochemistry. Brian Horsfield is a professor of organic geochemistry and hydrocarbon systems at the Technical University of Berlin, Germany, and leads the Department of Chemistry of the Earth at the German Research Center for Geosciences. He has 28 years of experience working with and for the industry in upstream research and development. His research interests include predicting fluid compositions ahead of drilling in petroleum systems and unraveling the workings of the deep biosphere.

Description: In the current context of continuous supply of energy, the discovery and development of new prospects will rely on our ability to detect reserves in deeper and structurally more complex formations. These exploration areas stretch the capabilities of currently available three-dimensional (3-D) exploration software, which cannot accommodate a realistic geometrical description of present-day geological structures and the tectonic deformation steps. Correctly handling the kinematics of structural deformation and evaluating the pressure regime and temperature history at the scale of exploration will remain as challenges for several years to come. In this article, we focus on geometric aspects using a reversible kinematic approach to deform and restore faulted and folded structures. Kinematic modeling is a good alternative to the complexity of a mechanical approach and is sufficiently representative of the natural processes involved (sedimentation, erosion, and compaction). Its reversibility ensures that the basin parameters need to be defined only once for both the restoration and the deformation steps. The model describes the incremental development of the basin in space and time. It is based on a hexahedral discretization process that is fully adapted and appropriate for thermal and fluid transfer. Different deformation modes (flexural slip and vertical shear) are mixed to integrate natural deformation more effectively. The algorithm is validated using different geological examples of growing complexity up to curved normal and thrust faults. The approach offers various prospects for improvement, integrating both kinematic and mechanical constraints. Considering the challenges that the industry needs to overcome in future exploration, the results of this approach are very encouraging and can be considered as a solution for solving the structural part of 3-D basin modeling in complex areas. Natacha Gibergues has a Ph.D. from Joseph Fourier University, Grenoble (2007). She has worked for the ALTRAN company from 2007 to 2009. Muriel Thibaut has worked with the Institut Français du Pétrole since 2001. In 2006, she was the project leader responsible for defining the strategy for basin software. Her recent work includes defining the methodology for coupling complex tectonics with fluids. She received her Ph.D. in geometry and solid mechanics from the University of Grenoble in 1994. Jean-Pierre Gratier is professor, physicist of observatory, at the Joseph Fourier University, Grenoble. He received his Ph.D. in geology in 1973. He works on the mechanisms of creep and sealing in the upper crust both from experimental approaches and from analysis of natural processes. His recent work is focused on fault permeability and strength evolution related to earthquakes and fluid transfers.

Description: Simulation grid blocks of naturally fractured reservoirs contain thousands of fractures with variable flow properties, dimensions, and orientations. This complexity precludes direct incorporation into field-scale models. Macroscopic laws capturing their integral effects on multiphase flow are required. Numerical discrete fracture and matrix simulations show that ensemble relative permeability as a function of water saturation ( k ri[ S w]), water breakthrough, and cut depend on the fraction of the cross-sectional flux that occurs through the fractures. This fracture-matrix flux ratio ( q f/ q m) can be quantified by steady-state computation. Here we present a new semianalytical model that uses q f/ q m and the fracture-related porosity ( ϕ f) to predict k ri( S w) capturing that, shortly after the first oil is recovered, the oil relative permeability ( k ro) becomes less that that of water ( k rw), and k rw/ k ro approaches q f/ q m as soon as the most conductive fractures become water saturated. To include a capillary-driven fracture-matrix transfer into our model, we introduce the nonconventional parameter A f,w( S w), the fraction of the fracture-matrix interface area in contact with the injected water for any grid-block average saturation. The A f,w( S w) is used to scale the capillary transfer modeled with conventional transfer functions and expressed in terms of a rate- and capillary-pressure-dependent k ro. All predicted parameters can be entered into conventional reservoir simulators. We explain how this is accomplished in both, single- and dual-continua formulations. The predicted grid-block-scale fractional flow ( f i[ S w]) is convex with a near-infinite slope at the initial saturation. The upscaled flow equation therefore does not contain an S w shock but a long leading edge, capturing the progressively widening saturation fronts observed in numerical experiments published previously. Stephan K. Matthäi is the chair of reservoir engineering at the University of Leoben, Austria. Before that, he was a senior lecturer of computational hydrodynamics at Imperial College London, and a postdoctoral researcher at Eidgenössische Technische Hochschule Zurich, Switzerland; Stanford University; and Cornell University. His Ph.D. is from the Research School of Earth Sciences, Australian National University. He holds a diploma degree from Eberhard Karl's University, Tübingen, Germany. Hamidreza Maghami-Nick is currently a Ph.D. student in the Center of Petroleum Studies at Imperial College London. He holds M.Sc. degrees from the Utrecht University, Netherlands, and from the K.N.T. University of Technology, Iran. His research interests range from the development of numerical methods to upscaling solute transport in fractured porous media.

Description: The Shijiutuo uplift is a major uplift to the north of the Bozhong depression, the largest generative kitchen in the Bozhong subbasin, Bohai Bay Basin. Although the N35-2 trap on this uplift contains a medium-size oil accumulation and the Q32-6 trap contains China's third largest offshore oil accumulation, the Q31-1 trap between the N35-2 and Q32-6 traps with very similar evolution history was confirmed to be dry. Biomarker associations of crude oil and source rock samples were analyzed, and three-dimensional migration pathway modeling was conducted to investigate the origin of oils and mechanisms for oil enrichment and depletion on the uplift. Multiple-parameter oil-source correlation and hierarchical cluster analysis using 10 selected biomarker parameters allowed the identification of four source-related oil classes. Almost all oils from the Shijiutuo uplift are derived from the Eocene Shahejie Formation, whereas oils found between the Shijiutuo uplift and the Bozhong depression either are derived from or have important contributions from the Oligocene Dongying Formation. Variations in oil classes and biomarker parameters suggest sequential migration of oil generated from the Shahejie and then Dongying formations in the Bozhong depression, which is reasonably supported by petroleum migration pathway modeling. Oil charge from two oil-prone source rock intervals and, more importantly, focusing of oil originating from a large area of the Bozhong generative kitchen into the same trap accounted for oil enrichment and formation of China's third largest offshore oil field in the Q32-6 structure. The complexity and primary control of the sealing surface (top surface of the carrier bed) morphology on the positions of migration pathways caused the Q31-1 trap to be shielded from migration of oil originating from the Bozhong depression, resulting in oil depletion in this trap. Shadows to petroleum migration may occur because of the three-dimensional behavior of petroleum migration, and two-dimensional migration modeling may be misleading in predicting petroleum occurrences. Fang Hao received his Ph.D. from China University of Geosciences in 1995. He is now the director of the State Key Laboratory of Petroleum Resources and Prospecting and the chair of the Academic Committee of the China University of Petroleum. He has conducted petroleum geology and geochemistry studies in several Chinese basins. His interest includes petroleum generation, migration, and accumulation in the Bohai Bay Basin. Xinhuai Zhou received his Ph.D. in geology from the China University of Geosciences. He is now the chief geologist of the Technology Department of the Tianjin Branch of China National Offshore Oil Company Ltd. He has conducted petroleum geology studies in the Bohai Bay Basin for more than 10 years. His publications include studies of petroleum generation, migration, and accumulation in the offshore area of the Bohai Bay Basin. Yangming Zhu received his Ph.D. from the Guangzhou Institute of Geochemistry, Chinese Academy of Sciences in 1993. He is now a professor of geochemistry at Zhejiang University. He has conducted petroleum geochemistry studies in several Chinese basins. His interest is now in the study of deposition and evolution of lacustrine source rocks. Yuanyuan Yang graduated in 2007 with a degree in geochemistry from the Yangtze University and is now a graduate student at the China University of Petroleum. Her interest is in the study of biomarker compositions of lacustrine source rocks and crude oils in the Bohai Bay Basin.

Description: The concept of fault facies is a novel approach to fault description adapted to three-dimensional reservoir modeling purposes. Faults are considered strained volumes of rock, defining a three-dimensional fault envelope in which host-rock structures and petrophysical properties are altered by tectonic deformation. The fault envelope consists of a varying number of discrete fault facies originating from the host rock and organized spatially according to strain distribution and displacement gradients. Fault facies are related to field data on dimensions, geometry, internal structure, petrophysical properties, and spatial distribution of fault elements, facilitating pattern recognition and statistical analysis for generic modeling purposes. Fault facies can be organized hierarchically and scale independent as architectural elements, facies associations, and individual facies. Adding volumetric fault-zone grids populated with fault facies to reservoir models allows realistic fault-zone structures and properties to be included. To show the strength of the fault-facies concept, we present analyses of 26 fault cores in sandstone reservoirs of western Sinai (Egypt). These faults all consist of discrete structures, membranes, and lenses. Measured core widths show a close correlation to fault displacement; however, no link to the distribution of fault facies exists. The fault cores are bound by slip surfaces on the hanging-wall side, in some cases paired with slip surfaces on the footwall side. The slip surfaces tend to be continuous and parallel to the fault core at the scale of the exposure. Membranes are continuous to semicontinuous, long and thin layers of fault rock, such as sand gouge, shale gouge, and breccia, with a length/thickness ratio that exceeds 100:1. Most observed lenses are four sided (Riedel classification of marginal structures) and show open to dense networks of internal structures, many of which have an extensional shear (R) orientation. The average lens long axis/short axis aspect ratio is about 9:1. Alvar Braathen is a professor in structural geology at the University Center in Svalbard and an adjunct professor at the Department of Earth Science, University of Bergen. He received his M.S. degree and his Ph.D. from the University of Tromsø, Norway. His research covers aspects of fold and thrust belts and extensional tectonics, with a current focus on fault description and the importance of faults for fluid flow. After receiving his Doctor of Science title from the University of Bergen, Jan Tveranger worked as a polar Quaternary scientist for several years before being engaged by Saga Petroleum and subsequently Norsk Hydro as a reservoir geologist. He is currently employed as a senior researcher and research coordinator at the Center for Integrated Petroleum Research, University of Bergen, focusing on description and modeling of reservoir properties of faults and paleokarst features. Haakon Fossen received his Ph.D. from the University of Minnesota in 1992. He joined Statoil in 1986 and, since 1996, has been a professor in structural geology at the University of Bergen. His scientific interests cover the evolution and collapse of mountain ranges, the structure of rift basins, and petroleum-related deformation structures at various scales, with current focus on deformation bands and subseismic faults. Tore Skar received his M.S. degree and Ph.D. in geology from universities in Bergen and Amsterdam. After some years as a senior researcher at the University of Bergen, he moved to the senior geologist position in StatoilHydro. His scientific interests cover sedimentology and structural geology. Nestor Cardozo received his B.S. degree in geology from the Universidad Nacional de Colombia in 1994 and his Ph.D. in geology from Cornell University in 2003. He is an associate professor at the University of Stavanger. His scientific interests cover faults, their related deformation, and their implementation in reservoir models. Siv Semshaug works as an exploration geologist in rock source in Bergen. In parallel, she is undertaking her Ph.D. through the Center for Integrated Petroleum Research, University of Bergen. She also received her M.S. degree in structural geology from the same university. Her current research focuses on fault siliciclastic rocks and their importance for reservoir performance. Eivind Bastesen is a Ph.D. student at the Center for Integrated Petroleum Research at the University of Bergen. He also received his M.S. degree in structural geology from the same university. His current research interests are extensional faults in carbonates and siliciclastic rocks, with a focus on field descriptions and quantification of fault zones. Einar Sverdrup is the exploration manager of Dana Petroleum Norway. He received his M.S. degree and Ph.D. degrees from the University of Oslo, Norway. His research topics cover sedimentology and diagenesis, fault properties, and flow characterization of seismic to subseismic reservoir heterogeneities.

Description: Using examples from core studies, this article shows that separate identification of mechanical stratigraphy and fracture stratigraphy leads to a clearer understanding of fracture patterns and more accurate prediction of fracture attributes away from the wellbore. Mechanical stratigraphy subdivides stratified rock into discrete mechanical units defined by properties such as tensile strength, elastic stiffness, brittleness, and fracture mechanics properties. Fracture stratigraphy subdivides rock into fracture units according to extent, intensity, or some other observed fracture attribute. Mechanical stratigraphy is the by-product of depositional composition and structure, and chemical and mechanical changes superimposed on rock composition, texture, and interfaces after deposition. Fracture stratigraphy reflects a specific loading history and mechanical stratigraphy during failure. Because mechanical property changes reflect diagenesis and fractures evolve with loading history, mechanical stratigraphy and fracture stratigraphy need not coincide. In subsurface studies, current mechanical stratigraphy is generally measurable, but because of inherent limitations of sampling, fracture stratigraphy is commonly incompletely known. To accurately predict fractures in diagenetically and structurally complex settings, we need to use evidence of loading and mechanical property history as well as current mechanical states. Steve Laubach is a senior research scientist at the Bureau Economic Geology where he leads the fracture and structural diagenesis research programs. He also supervises graduate student research in structural geology and diagenesis in the Jackson School of Geosciences. He is the chair of the Jackson School's Energy Geoscience Education and Research Group. Jon Olson is an associate professor in the Department of Petroleum and Geosystems Engineering. He joined the faculty in 1995. He has six years of industrial experience. He specializes in the applications of rock fracture and continuum mechanics to fractured reservoir characterization, hydraulic fracturing, and rock mechanics. Michael Gross is a professor at Florida International University specializing in brittle deformation and the use of quantitative, field-based structural methods to joints, faults, and veins in an attempt to understand their formation, distribution, and impact on subsurface fluid flow. His current research activity focuses on fractured reservoir characterization, the influence of mechanical stratigraphy on fracture development, and flow through fracture networks in layered rocks.

Description: Methodologies and numerical tools are available (1) to construct geologically realistic models of fracture networks and (2) to turn these models into simplified conceptual models usable for field-scale simulations of multiphase production methods. A critical step remains however, that of characterizing the flow properties of the geological fracture network. The multiscale nature of fracture networks and the associated modeling cost impose a scale-dependent characterization: (1) multiscale fractures that may be characterized in local dynamic test areas, e.g., drainage areas involved in well tests, through the calibration of geologically realistic discrete fracture network (DFN) models and accurate local flow-test simulations; and (2) large-scale faults that are characterized through reservoir-scale production history simulations that involve upscaled flow models with an explicit fault representation. However, field data are commonly insufficient to fully characterize the multiscale fracture properties. Therefore, efficient inversion methodologies are necessary to sample wide ranges of property values and to characterize a variety of solutions, i.e., fracture models that are consistent with dynamic data. This article presents an inversion methodology to facilitate the characterization of fracture properties from well-test data. A genetic optimization algorithm has been developed and coupled with a three-dimensional DFN flow simulator to perform the simultaneous calibration of well-test data. As a first step, the calibration data result from interpreted well tests, i.e., data are equivalent transmissivities. Applications are presented on a geologically realistic fractured reservoir model having three facies, two fracture sets, and three wells. The characterized fracture properties are mean length, mean conductivity, orientation dispersion factors, and facies-dependent properties such as fracture density. The effectiveness of this inversion methodology to characterize physically meaningful and data-consistent fracture properties is discussed. Arnaud G. Lange is in charge of a research project dedicated to the development of methodologies for the characterization of fractured reservoirs from history matching. He joined the fractured reservoir group in the reservoir engineering division at Institut Français du Pétrole in 2002. Lange holds a Ph.D. in mechanical engineering from the University College London and graduated from MatMeca Engineering School, Bordeaux, France.

Description: A field-specific geomechanical model serves as a platform for greatly reducing costs and increasing production over the life of a field. The information contained in a geomechanical model makes it possible to reduce drilling costs and production losses through fieldwide well planning that can optimize production and minimize risk. A significant value of the geomechanical model is its application to the efficient exploitation of fractured reservoirs. The essential contribution of wellbore image technologies to this exploration and production challenge is illustrated through a case study of a compartmentalized fractured gas reservoir located in Hokkaido, Japan. A growing body of evidence reveals that, in many fractured reservoirs, the most productive fractures are those that are optimally aligned in the current stress field to fail in shear. Thus, it is necessary to obtain knowledge of both the stress magnitudes and orientations and the distribution of natural fractures to determine the optimal orientations for wells to maximize their productivity. The best well intersects the maximum number of stress sensitive fractures. Applying geomechanics and the reservoir fracture distributions to model shear-enhanced permeability as the mechanism for reservoir production appears to be a promising improvement to existing reservoir flow models. Using quantitative risk assessment and realistic uncertainties in the critical parameters, it is possible to estimate the uncertainty in predictions of optimal well trajectories and of stimulation pressures to enhance natural fractures. The results indicate that the critical parameters are not always those with the most uncertainty, and that the most effective way to reduce prediction uncertainties is to calibrate against the productivity of a preexisting well. Colleen Barton is a cofounder and senior technical advisor of GeoMechanics International (GMI). She received her Ph.D. from Stanford University in 1988 in reservoir geomechanics. Prior to cofounding GMI in 1996, she spent 10 years as a research scientist at Stanford developing techniques in in-situ stress measurement and enhanced recovery from fractured reservoirs. She is an industry expert in wellbore image analysis technologies. Daniel Moos is a cofounder and chief scientist of GeoMechanics International. He received his Ph.D. from Stanford University in 1983, cofounded the Borehole Geophysics group at Lamont-Doherty Earth Observatory, which developed and managed well logging services for the Ocean Drilling Program, and subsequently spent 10 years as a research scientist at Stanford University before GMI was founded in 1996. Kazuhiko Tezuka is a senior manager of the reservoir characterization laboratory in Japan Petroleum Exploration Co. (JAPEX) Research Center. He joined JAPEX after he graduated from Tohoku University in 1984 with a B.S. degree in geophysics. He worked as a visiting scientist at Earth Resources Laboratory at Massachusetts Institute of Technology in 1993–1994. He received his Ph.D. from Tohoku University in 1997 in earth resources engineering.

Description: We present a quantitative forward-modeling methodology to link and interpret several measurements relevant to mechanical properties of fractures such as borehole images, sonic anisotropy logs, and borehole seismic anisotropy. The analysis is applied to a case study from a north African tight gas field using data from a vertical well. Two studies are conducted independently using the same geological fracture data to model fracture-induced anisotropy. In the first study, we use the orientation of the natural and drilling-induced fractures interpreted on the image log to model the azimuthal fracture-induced anisotropy at the sonic scale. The mechanical effects of natural and drilling-induced fractures are treated using different compliance parameters for each fracture type. We show that modeled sonic fast shear azimuths could be biased by the presence of noncompliant fractures in each fracture type, and we propose an empirical selection criterion to reject noncompliant fractures prior to compliance estimation. Then, we estimate the fracture compliances and confirm that natural open fractures have larger compliances than drilling-induced fractures. In the second study, we apply interpreted borehole images toward modeling of the azimuthal vertical seismic profile (VSP) attributes as a function of source azimuthal position. Natural fractures inside a window of height, h , and located at depth, d , are included, and several volume sizes and positions (i.e., h and d ) are considered. We find a good agreement between modeled and observed transverse-over-radial displacement trends using natural fractures within windows located at the depth of the VSP receiver, and having window heights on the order of one to two VSP shear wavelengths. Romain Prioul is a principal research scientist and program manager at Schlumberger-Doll Research, Cambridge, Massachusetts. He received a Ph.D. (2000) in geophysics from Institut de Physique du Globe de Paris, France. From 1999 to 2000, he also worked as a research and teaching assistant of rock mechanics at the same institute. From 2000 to 2003, he was a research scientist at Schlumberger Cambridge Research, United Kingdom, and has been a research scientist at Schlumberger-Doll Research from 2003 to 2005 in Ridgefield, Connecticut, and since 2005 in Cambridge, Massachusetts. He is currently managing a team of researchers in geomechanics and petrophysics. His research interests include sonic and seismic anisotropy, geomechanics and rock physics of natural fractures, and surface and downhole seismic reservoir monitoring. He is member of Society of Exploration Geophysicists, Society of Petrophysicists and Well Log Analysts, and European Association of Geoscientists and Engineers. Jeroen Jocker is a research scientist at Schlumberger-Doll Research in Cambridge, Massachusetts. His expertise is in elastic wave propagation of bulk and guided waves in isotropic and anisotropic rock formations, and in sonic and geomechanics modeling and interpretation. His academic background (Delft University of Technology, Netherlands) is an M.Sc. degree in petroleum engineering, a Ph.D. on poroelastic wave propagation, and a one-year post-doctoral position researching hydraulic fracture propagation. He is a member of Society of Exploration Geophysicists, and he joined Schlumberger in January, 2006.

Description: This article describes the workflow used in continuous fracture modeling (CFM) and its successful application to several projects. Our CFM workflow consists of four basic steps: (1) interpreting key seismic horizons and generating prestack and poststack seismic attributes; (2) using these attributes along with log and core data to build seismically constrained geocellular models of lithology, porosity, water saturation, etc.; (3) combining the derived geocellular models with prestack and poststack seismic attributes and additional geomechanical models to derive high-resolution three-dimensional (3-D) fracture models; and (4) validating the 3-D fracture models in a dynamic reservoir simulator by testing their ability to match well performance. Our CFM workflow uses a neural network approach to integrate all of the available static and dynamic data. This results in a model that is better able to identify fractured areas and quantify their impact on well and reservoir flow behavior. This technique has been successfully applied in numerous sandstone and carbonate reservoirs to both understand reservoir behavior and determine where to drill additional wells. Three field case studies are used to illustrate the capabilities of the CFM approach. Creties Jenkins is a senior staff geologist for DeGolyer and MacNaughton where he specializes in reservoir characterization, geocellular modeling, and resource estimation in clastic reservoirs, including coalbed methane and shale gas accumulations. He received an M.S. degree in geology and a B.S. degree in geological engineering from the South Dakota School of Mines and Technology. Ahmed Ouenes is the president of Prism Seismic. Previously, he was the chief reservoir engineer at (RC)2 where he developed the first commercial software for the CFM technology. Ahmed's main interest is the development of improved reservoir characterization technologies especially for fractured reservoirs. Ahmed graduated from Ecole Centrale de Paris and holds a Ph.D. in petroleum engineering from New Mexico Tech. Abdel M. Zellou is director of consulting at Prism Seismic. He has worked as a consultant on numerous fractured reservoirs all over the world and contributed to the drilling of many successful wells. He codeveloped ReFract, a leading fractured reservoir software using patented technology. Abdel graduated from New Mexico Tech with an M.Sc. degree in petroleum engineering. Jeff Wingard is a senior staff reservoir engineer at DeGolyer and MacNaughton where he has developed and evaluated geocellular and simulation models for waterflood, miscible gas, and thermal Enhanced Oil Recovery projects. He earned a B.S. degree in chemical engineering from the Massachusetts Institute of Technology in 1980 and a Ph.D. in petroleum engineering from Stanford University in 1988.

Description: Two-dimensional fracture simulation is conducted to analyze the controls of different fracture parameters (variations in fracture orientation, density, and length) on fracture network connectivity. Three different scenarios, which are commonly encountered in natural fracture systems, are analyzed: (1) a single fracture set; (2) two fracture sets, with one primary through going set; and (3) two fracture sets with approximately equal parameters. The modeling reveals that certain parameters are more dominant in controlling the connectivity for each of the settings. For a single set of fractures, increases in length and dispersion and a decrease in spacing all result in higher fracture-parallel connectivity, but the decrease in spacing is the most important in increasing fracture-normal connectivity, especially where the dispersion in fracture strike is very low. Simulations of two sets of fractures reveal that the density, length, and angle between the two sets are important factors in producing complete connectivity. In cases where one set of fractures is a systematic throughgoing set, a critical combination of length of the second set and the angle between the two sets results in complete connectivity. Where both sets of fractures have varying length and density, the influence of increasing density of one set has a great effect on connectivity when the other set is short and a more subtle to insignificant change when the other set is long. The network also shows higher connectivity with increasing angles (up to 90°) between the two sets. Kajari Ghosh received her Ph.D. from the University of Oklahoma. She is currently a geoscientist with ExxonMobil Company in Houston. Her primary research interests are in structural modeling and fracture analysis. Shankar Mitra holds the Monnett Chair and Professorship in Energy Resources at the University of Oklahoma. His primary research interests are in structural interpretation and modeling and fractured and faulted reservoirs.

Description: Normal faults measured in exposures of Cretaceous carbonate rocks in Texas provide the basis for fault-strain determination, analysis of fault displacements, and exploring the function of mechanical stratigraphy in influencing fault-size distributions. Layer competence and competence contrast, measured using a Schmidt hammer, allow the analysis of mechanical stratigraphy. Fault frequency and displacement distributions exhibit patterns that correlate to mechanical stratigraphy. In particular, the average competence contrast is related to the exponent ( C ) of cumulative frequency versus displacement distributions as described by log(cumulative frequency) = (− C ) × log(displacement) + A . This correlation between competence contrast and C values is interpreted to indicate that, at low competence contrast, there are many potential nucleation sites for faults and no mechanisms by which fault displacement can be filtered. In addition, several frequency versus displacement distributions exhibit steep sections, indicating a clustering of fault displacement(s). Clustering of fault displacement(s) is also interpreted as the result of low-competence layers inhibiting the propagation of faults through the layering until a threshold displacement has been reached. This has the effect of creating a cluster of faults with displacements near the threshold displacement value. These patterns are true both for data sets surveyed along a scan line and along a key bed. An appreciation of these effects of mechanical stratigraphy on fault displacement distributions is important when using observed data to infer subseismic fault populations during reservoir evaluation and modeling. Alan Morris received his B.Sc. degree (with honors) in geology from the Imperial College of Science and Technology in 1973 and his Ph.D. in geology from the University of Cambridge in 1980. He is a licensed professional geoscientist (geology) in the state of Texas. Before joining Southwest Research Institute in 2005, he was a full professor at the University of Texas at San Antonio, having been on the faculty for 22 years. He is now a staff scientist at Southwest Research Institute and focuses on quantitative analysis of deformation processes and stress in diverse tectonic regimes and conducts research and technical assistance projects for the oil industry. David Ferrill received his B.S. degree in geology from Georgia State University in 1984, his M.S. degree in geology from West Virginia University in 1987, and his Ph.D. in geology from the University of Alabama in 1991. He is a licensed professional geoscientist (geology) in the state of Texas. Before joining Southwest Research Institute in 1993, he was an exploration geologist at Shell Offshore Incorporated. David is now a director at Southwest Research Institute and performs analyses of faulting and fracturing and reservoir deformation and does structural geological training and contract consulting for the oil and gas industry. Ronald McGinnis received his B.S. and M.S. degrees in geology from the University of Texas at San Antonio in 2002 and 2005, respectively. He is a geologist with a background in structural geology, hydrology, and geophysics. His research includes slope stability analyses on landslides; geologic and geophysical characterization to identify sources of radar scattering in various terrains throughout the world; fault analyses to provide a strain-based approach for predicting subseismic faults in various lithologies; and characterization of geologic controls on groundwater movement in the Edwards and Glen Rose formations in central, west, and south Texas.

Description: The slip direction and slip sense of a fault constrain the orientation of the stress field that caused the fault to slip. Inversion of such slip data for populations of minor faults to determine ancient stress fields is a well-established technique in structural geology. In the field and in oriented core, the slip direction and slip sense of minor faults are typically determined by observation of fault-surface morphology. Because fault surfaces are not visible in image logs, subsurface paleostress analysis based on inversion of mesoscopic fault data has only been possible with oriented cores. This contribution describes how to work with faults with associated pinnate joints to determine the slip sense and slip direction of a fault based only on observations made in image logs. Alfred Lacazette received his B.S. and M.S. degrees in geology from the University of Kentucky in 1979 and 1986, respectively, and his Ph.D. in geoscience from the Pennsylvania State University in 1991. He has been employed by Texaco Research, Western/Baker Atlas, the Fracman Group of Golder Associates, and his own consulting firm, NaturalFractures.com, LLC. He currently works as a senior exploration geologist for EQT Production in Pittsburgh, Pennsylvania.

Description: Previous research has shown the importance of understanding the relationship between fault geometry and current applied tectonic stresses in the prediction of critically stressed faults and their propensity for fluid flow via generated fracture networks along and/or around the fault plane. This article summarizes research aimed at increasing this understanding by applying the distinct element method (DEM) to predict stress within a rock mass generated by far-field stress on seismically resolvable faults within a modeled area. We showed that increases in differential over regional stress can be correlated with the presence of fractured rock as detected by petrophysical logs and core and drilling data. A case study example is used to illustrate the methodology from the Penola Trough, Otway Basin, South Australia, modeled using two-dimensional DEM. Assuming a reasonable understanding of (1) rock properties, (2) structure, and (3) far-field or regional stress, then the technique described in this article provides a valid workflow to increase confidence in the prediction of the generation of fractures and their spatial distribution. Bronwyn Anne Camac obtained a BAppSc degree in applied geology from the South Australian Institute of Technology in 1984. She subsequently joined Wiltshire Geological services as a geologist. From 1998 to 2002, she worked as a staff geologist for Origin Energy in their exploration team focusing on the Otway Basin. She commenced studies for a Ph.D. at the Australian School of Petroleum in 2002, University of Adelaide, while working as an operations geologist for Beach Petroleum Ltd. Her Ph.D. studies are directed toward developing a new tool for the petroleum industry using a distinct element code to correlate the occurrence of natural fractures with localized stress perturbations. She currently works in the exploration team at Beach Petroleum as a senior geologist looking at a wide range of conventional and unconventional oil and gas prospects. Suzanne Paula Hunt has a B.Sc. degree (Hons) in geophysics from the University of Reading, United Kingdom and an M.S. degree in mining geology, and a Ph.D. in rock mechanics from the University of Exeter, United Kingdom. She completed her Ph.D. in 1993 at the United Kingdom Geothermal Energy Project. During her Ph.D., she worked on an unconventional method for stress determination in deep boreholes. Since 1993, she has worked in a variety of geophysics-based areas, including seismic tomography, gravity, and magnetics. She spent two years in Antarctica at Mawson Station where she managed the global geomagnetic and seismological stations. She then took a lectureship position at Curtin University where she undertook research into the use of stress modeling as an exploration tool and for underground mining-induced stress determination. She was a senior research associate at the National Centre for Petroleum Geology and Geophysics before joining the school of Petroleum Engineering and Management. There she taught in the area of formation evaluation and petrophysics. She and her team advanced the application of computational modeling within the fields of seal integrity prediction, wellbore stability, and coupled fluid-flow modeling for reservoir compaction prediction. Since 2007, Suzanne has been working as a senior petroleum engineer with Santos Ltd. in Adelaide.

Description: Sequence stratigraphy has been applied from reservoir to continental scales, providing a scale-independent model for predicting the spatial arrangement of depositional elements. We examine experimental strata deposited in the Experimental EarthScape facility at St. Anthony Falls Laboratory, focusing on stratigraphic surfaces defined by discordant contact geometries, surfaces analogous to those delineated in the original work on seismic sequence stratigraphy. In this controlled setting, we directly evaluate critical sequence-stratigraphic issues, such as stratigraphic horizon development and time significance, as well as the internal geometry and migration of the bounded strata against the known boundary conditions and depositional history. Four key stratigraphic disconformities defined by marine downlap, marine onlap, fluvial erosion, and fluvial onlap are mapped and vary greatly in their relative degree of time transgression. Marine onlap and downlap contacts closely parallel topographic surfaces (time surfaces) and, prior to burial, approximate the instantaneous offshore topography. These stratal-bounding surfaces are also robust stratigraphic signals of relative base-level fall and rise, respectively. Marine onlap surfaces are of special interest. They tend to be the best preserved discordance, where widespread, allogenic-based onlap surfaces subdivide otherwise amalgamated depositional cycles amidst cryptic stacks of marine foresets; however, local, autogenic-based marine onlap discordances are present throughout the fill. A critical distinguishing feature of allogenic onlap is the greater lateral persistence of the discordance. Surfaces defined by subaerial erosional truncation and fluvial onlap do not have geomorphic equivalence because channel processes continually modify the surface as the stratigraphic horizons are forming. Hence, they are strongly time transgressive. Last, the stacking arrangement of the preserved bounded strata is found to be a good time-averaged representation of the mass-balance history. John M. Martin is presently at ExxonMobil Upstream Research Company, where his research interests are in geomorphology and the details of stratigraphic accumulation from a variety of depositional environments. He earned his Ph.D. from the University of Minnesota, Minneapolis, where much of his work was centered at St. Anthony Falls Laboratory. Chris Paola is a professor in the Department of Geology and Geophysics, University of Minnesota, Minneapolis, and does research at St. Anthony Falls Laboratory. His research interests are in physical sedimentary geology and stratigraphy, especially the dynamics of channelized systems. He received his B.S. degree in environmental geology from Lehigh University, his M.S. degree in applied sedimentology from the University of Reading, and his D.S. degree in marine geology from Massachusetts Institute of Technology/Woods Hole Oceanographic Institution Joint Program in Oceanography. Vitor Abreu received his Ph.D. from Rice University and is presently an ExxonMobil stratigraphy coordinator. He is also an adjunct professor at Rice University, teaching sequence stratigraphy and has published several articles and given numerous talks and seminars within industry and academia. He was the recipient of the Jules Braunstein Memorial Award (2002 AAPG Annual Meeting) and is currently an AAPG distinguished instructor. Jack E. Neal received his B.S. degree from the University of Tulsa and his Ph.D. from Rice University. His interests are seismic and sequence stratigraphy, structure-stratigraphic interaction, paleoclimate, and hydrocarbon systems. He has published on northwestern Europe sequence stratigraphy, graphic correlation, and lacustrine sequence stratigraphy. He has worked globally in research, exploration, development, and production assignments with Exxon and ExxonMobil since 1994. Ben Sheets is an assistant professor of marine geology and geophysics in the School of Oceanography at the University of Washington, Seattle. He earned his B.A. degree from Carleton College and his Ph.D. from the University of Minnesota, Minneapolis. His research involves processes, geomorphology, and stratigraphy in a variety of coastal and submarine sedimentary systems.

Description: Three-dimensional seismic-reflection data are used in the analysis of submarine channel systems in the Espírito Santo Basin, Brazil. The exceptional quality of the studied data set allows the detailed documentation of the geometry, regional distribution, and statistical parameters of salt-related normal faults, and their effect on the Rio Doce Canyon system (RDCS). On the Espírito Santo continental slope, normal faulting was triggered during early halokinesis (stage A) but barely controlled the initial evolution of the RDCS, which incised the continental slope axially within a salt-withdrawal basin. However, in a second stage (stage B), crestal or radial faults controlled erosion over growing salt structures, whereas synclinal and channel-margin fault sets dissected overbank strata to the RDCS. In the later part of stage B, channel sinuosity decreased sharply in response to fault activity and associated sea-floor destabilization. Vertical propagation of blind faults was triggered in a third stage (stage C), in association with crestal collapse of buried salt anticlines and regional diapirism, but synclinal and channel-margin faults did not propagate vertically above a regional unconformity marking the base of stage C strata. Statistical analyses of observed fault sets demonstrate that synclinal faults are in average 2.3 times longer than the crestal or radial types but record 60% of the throw (average 83 m [272 ft]) experienced by the latter. In addition, the fault sets are shown to have contributed to local cannibalization of the sea floor, vertical stacking of channel-fill strata, and structural and depositional compartmentalization of potential reservoir successions. As a result, channel systems show marked differences in mean values for sinuosity, height, and width in relation to five main phases of channel development. The structural setting in the study area differs from productive areas offshore Espírito Santo (e.g., Golfinho field), west Africa, and Gulf of Mexico, revealing in distal parts of the Brazilian margin the existence of local controls on submarine channel architecture and structural compartmentalization prior to the main stages of diapirism. Tiago is a research lecturer at Cardiff University. After completing his Ph.D. in geology at the University of Manchester, he worked in Portugal and then Greece through the umbrella of European Union projects (EURODOM and HERMES) dedicated to the study of continental margins. His research interests include the study of deep-water rift basins and overlying postrift successions. He is particularly interested in investigating the way tectonics influences sedimentation using novel statistical methods, petrophysical, and 3-D seismic data. Joe received his B.A. and D.Phil degrees in geology from Oxford University. He is a research professor of geophysics and the director of the 3-D Lab at Cardiff University. His research interests focus on 3-D seismic interpretation in basin analysis, with special emphasis on seal integrity analysis, the genesis of polygonal faults, the emplacement of sandstone and igneous intrusions, and silica diagenesis. Richard is a professor of petroleum geoscience and the director for the Center for Research into Earth Energy Systems at Durham University. He was formerly at ExxonMobil for 8 years. He has published more than 40 articles on the use of 3-D seismic data for understanding sedimentary, fluid flow, structural, igneous, and diagenetic processes in basins.

Description: Geologists are frequently called on to evaluate the source rocks associated with their exploration prospects or plays. The three most common questions asked and answered about the source rock during project reviews are What's the total organic carbon (TOC)?, What kerogen type does Rock-Eval indicate?, and What maturity level does the vitrinite reflectance data point to? The answers to these seemingly innocuous questions may, in fact, be providing a false sense of security about the source rock in question. Understanding how this line of questioning can lead you astray and make you the victim of the TOC myth (“If I have high TOC, I have a good source rock.”), the Rock-Eval fallacy (“The Rock-Eval data tell me what kind of kerogen is in my source rock.”), and the vitrinite reflectance deficiency (“Vitrinite reflectance will tell me if my source rock is generating.”) is important. Some of the solutions to these problems include fully integrating TOC and Rock-Eval data, supplementing Rock-Eval data with pyrolysis-gas chromatography, and using burial history diagrams to help interpret vitrinite reflectance. Harry Dembicki Jr. is a senior geological advisor for geochemistry in the Geological Technology Group at Anadarko Petroleum Corporation, where he provides technical support to both exploration and development teams. He holds a B.S. degree (1973) in geology from the State University College of New York at New Paltz and a Ph.D. (1977) in geology, with emphasis in organic geochemistry, from Indiana University. He previously worked as an organic geochemist for Conoco and Marathon.

Description: The Miocene Bear Lake Formation is exposed along the coast and mountains of the central Alaska Peninsula and extends offshore as part of the Bristol Bay Basin. The Bear Lake Formation is up to 2360 m (7743 ft) thick in an offshore well and is considered to have the highest reservoir potential in this gas-rich frontier basin. Our new macrofossil and palynological data, collected in the context of measured stratigraphic sections, allow us to construct the first chronostratigraphic framework for this formation. Biostratigraphic age assignments for the numerous, commonly isolated, onshore exposures of the Bear Lake Formation show that deposition initiated sometime before the middle Miocene (15 Ma) and extended to possibly the earliest Pliocene. The bulk of the Bear Lake Formation, however, was deposited during the middle and late Miocene based on our new findings. We interpret the Bear Lake Formation as the product of a regional transgressive estuarine depositional system based on lithofacies analysis. The lower part of the formation is characterized by trough cross-stratified sandstone interbedded with coal and pedogenic mudstone deposited in fluvial and swamp environments of the uppermost parts of the estuarine system. The lower-middle part of the formation is dominated by nonbioturbated, wavy- and flaser-bedded sandstone and siltstone that were deposited in supratidal flat environments. The upper-middle part of the Bear Lake Formation is characterized by inclined heterolithic strata and coquinoid mussel beds that represent tidal channel environments in the middle and lower tracts of the estuarine system. The uppermost part of the formation consists of tabular, bioturbated sandstone with diverse marine invertebrate macrofossil faunas. We interpret this part of the section as representing the subtidal tract of the lower estuarine system and possibly the adjacent shallow inner shelf. A comparison of our depositional framework for the Bear Lake Formation with core and well-log data from onshore and offshore wells indicates that similar Miocene depositional systems existed throughout much of the Bristol Bay Basin. The documented changes in depositional environments within the Bear Lake Formation are also important for understanding upsection changes in the geometries of potential reservoirs. Emily Finzel is a Ph.D. student at Purdue University. She holds an M.S. degree in sedimentology and structural geology from the University of Alaska-Fairbanks. From 2003 to 2006, she worked as a field geologist for the Alaska Division of Geological & Geophysical Surveys, focusing on the North Slope and Bristol Bay Basin. Her current research addresses the geodynamic development of sedimentary basins along convergent plate margins. Ken Ridgway is a professor at Purdue University. His research group addresses a broad spectrum of questions concerning crustal tectonics. Much of their research has focused on the sedimentary record in basins of southern Alaska to understand how this continental margin developed through time and how it is currently deforming. For more information on the basin analysis group, see www.eas.purdue.edu/basin. Rocky Reifenstuhl began his Alaska work in 1977, which included 18 months with Marline Oil Corporation. In 1981, he began working as a field geologist for the Alaska Division of Geological & Geophysical Surveys, and in 1983, he received a B.S. degree in geology from University of Alaska Fairbanks. He has published some 80 geologic maps and reports from every region of Alaska. Robert Blodgett is a stratigrapher and paleontologist with more than 30 years of experience on Alaskan rocks. He received his Ph.D. from Oregon State University. His research interests cover Phanerozoic biostratigraphy of western North America, and he recently coedited Geological Society of America Special Paper No. 442 “The Terrane Puzzle: New Perspectives on Paleontology and Stratigraphy from the North American Cordillera.” James White is a Geological Survey of Canada palynologist, specializing in Cenozoic and Early Cretaceous palynostratigraphy in western and northern Canada and the adjacent United States. His recent work is on modeling biostratigraphy from a literature database and on the palynostratigraphy of the Mallik gas hydrate research borehole, Mackenzie delta. Paul Decker is a geologist with the Alaska Division of Oil and Gas engaged in petroleum systems research integrating subsurface and outcrop data. From 1988 to 2004, he worked in Alaskan exploration and development for ARCO, Phillips, and ConocoPhillips. Paul holds a Ph.D. and an M.S. degree in structural geology from the University of Wisconsin, Madison, and a B.S. degree in geology from Fort Lewis College.

Description: The Upper Triassic Yanchang Formation in the Ordos Basin, central China, is a typical sandstone reservoir with an ultra-low permeability. High-angle tectonic fractures and diagenetic fractures, such as near-horizontal bedding fractures, intragranular fractures, and grain-boundary fractures, are abundant. Fractures are major pathways and enhance fluid flow in sandstone reservoirs with ultra-low permeability. Because of their weak lateral continuity and their small apertures under lithostatic pressure, bedding fractures make a relatively small contribution to the overall permeability of reservoirs. As they are both of small size and low permeability, intragranular fractures and grain-boundary fractures mainly improve the connectivity of reservoirs by connecting the matrix pores. High-angle tectonic fractures control the fluid movement in the ultra-low-permeability reservoirs. Under the effect of different successive tectonic stress fields, four assemblages of high-angle tectonic fractures developed in the sandstone reservoirs. Under the present-day stress, differently oriented fractures have different connectivities, apertures, and permeabilities. The northeast–southwest fractures parallel to the maximum principal stress have a good connectivity, large apertures, and a high permeability, forming the dominant flow paths. Knowledge of these paths can be used for optimizing well placement. Because of their sensitivity to pressure, fractures in different directions will show varying apertures as the formation pressure decreases. Therefore, the permeability of the fractures of different orientations and its impact on reservoirs vary at different developmental stages. Zeng Lianbo is a professor of geology in the Key State Laboratory of Petroleum Resource and Prospecting in China Petroleum University. He received his M.S. degree from the China University of Geosciences and his Ph.D. from the China Petroleum University. His interests include tectonic stress field, natural fracture systems, and low-permeability reservoir characterization. Li Xiang-Yang is a professor of multicomponent seismology in the School of Geosciences, University of Edinburgh. He received his B.S. degree from the Changchun Geological Institute, his M.S. degree from the China University of Petroleum, and his Ph.D. from the University of Edinburgh. His interests include tectonic stress field and fractured reservoir characterization.

Description: We use a new, mechanically based volumetric structural restoration tool to investigate the mechanics of fault-related folding using natural examples imaged in three-dimensional (3-D) seismic data. The restoration technique is based on a finite element approach that simultaneously restores folding and faulting while allowing rock properties to spatially vary during restoration. We apply these techniques to two types of structures, detachment and shear fault-bend folds, where mechanical layering is a significant factor in their development. Our examples include a detachment anticline from the Caspian Sea and a shear fault-bend fold from the deep-water Niger Delta, both of which contain syntectonic growth horizons that help to constrain the restorations. Restorations of the detachment fold most closely match displacement fields specified in the kinematic forward models when materials are defined as incompressible and rigid, yet the variation of mechanical strength in restorations is perhaps more compatible with the growth of natural structures as recorded by syntectonic growth strata. This analysis shows that the restorations of the detachment fold favor a combination of both kink-band migration and limb rotation folding mechanisms. Numerical simulations of the growth shear fault-bend fold also closely match the displacement field prescribed by the kinematics of shear fault-bend fold models when weak basal units and bedding-plane slip surfaces, enabling flexural slip, are incorporated in the model. The results demonstrate that these techniques can be used to provide full 3-D restorations that closely match established two-dimensional kinematic theories, yet allow constraint of 3-D displacement fields and strain patterns in complex structures. Chris A. Guzofski is member of the Structural Geology Team at the Chevron Energy Technology Company. He received his B.S. degree (1997) in geology from Bates College, his M.S. degree (2000) in geodynamics from Pennsylvania State University, and his Ph.D. (2007) in structural geology from Harvard University. His research interests include 3-D restoration and the mechanics and kinematics of extensional and compressional fault-related folds. Joachim P. Mueller is a structural geologist at the Chevron Energy Technology Company in San Ramon, California. He graduated in geology from the University of Karlsruhe in 1993 and received his doctorate from the Free University of Berlin in 2000. He joined the Structural Geology and Earth Resources group at the Harvard University as a postdoctoral fellow in 2004. He studies the tectonic evolution of fold and thrust belts and investigates the development and implementation of 3-D structural restoration methods. John H. Shaw is the Earth and Planetary Sciences Department Chair and Harry C. Dudley Professor of Structural and Economic Geology at Harvard University. He leads an active research program in structural geology and geophysics, with emphasis on petroleum exploration and production methods. He received a Ph.D. from Princeton University in structural geology and applied geophysics and was employed as a senior research geoscientist at Texaco's Exploration and Production Technology Department in Houston, Texas. His research interests include complex trap and reservoir characterization in fold and thrust belts and deep-water passive margins. He heads the Structural Geology and Earth Resources Program at Harvard, an industry-academic consortium that supports student research in petroleum systems. Pierre Muron is a research scientist and software developer in the Reservoir Simulation Development Team of Chevron Energy Technology Company. He completed his undergraduate studies in numerical geology and then received a Ph.D. in geosciences from Nancy-Université in France in 2005. His current technical interests include development and deployment of software solutions for reservoir modeling and simulation. Don Medwedeff received his B.S. (1981) and M.S. degrees (1983) and his Ph.D. (1988) in geology from the University of Michigan, Queen's University, and Princeton University, respectively. He was with ARCO from 1987 to 2000 and has been with Chevron since. His work has focused on the development and application of structural analysis and modeling methods and tools. Frank Bilotti is currently working in deep-water exploration for Chevron Nigeria/Mid-Africa and was most recently the Structural Geology Team leader at Chevron Energy Technology Company. He received a Ph.D. in structural geology from Princeton University in 1997 and a B.S. degree in geology and mathematics from the University of Miami. Prior to Chevron, he worked as a structural consultant in Texaco Exploration Technology and at Unocal E&E Technology. Carlos Rivero received a Ph.D. in structural geology from Harvard University in 2004 and an M.S. degree in geology in 2002. He also holds a geological engineering degree from the Universidad Central de Venezuela in Caracas. He worked as a structural geologist with Unocal E&E Technology before joining the Structural Geology Team of Chevron Corporation. His technical interests include the integration of kinematical, mechanical, and forward modeling of contractional and extensional systems with basin analysis to mitigate exploration and production risks associated with reservoir presence, source rock maturation, and hydrocarbon migration and charge.

Description: Listric growth faults in passive margin settings such as the Gulf of Mexico and Niger Delta are commonly characterized by lateral and oblique ramps related to preexisting structural or stratigraphic discontinuities. Clay experiments have been used to model the geometry, orientation, density, and connectivity of secondary faults formed along lateral and oblique ramps. Extension results in the formation of an expanding set of synthetic faults tied to the fixed footwall and a corresponding set of antithetic faults tied to a moving hanging wall. Some of the synthetic fault strands eventually connect to form the master fault, whereas antithetic faults continue to develop, with progressive transfer of slip to newly formed faults. Characteristics such as fault orientation, fault density distribution, and shape, size, and distribution of connected fault clusters vary with (1) ramp offset angles, (2) structural position, and (3) total extension. In map view, secondary antithetic and synthetic faults mimic the geometry of the main fault, but the orientations of secondary faults are approximately 25–33% of the offset angle of the oblique or lateral ramps. Fault densities and connectivities are initially higher along the frontal ramps. With increasing extension, the maximum cluster size of connected faults increases dramatically in the oblique and lateral segments due to the intersection of fault sets of different orientations. These observations regarding fault orientations, densities, and connectivities provide important insights on the structural geometry and mechanisms of formation of faults as well as the configuration of fault networks for fluid flow in passive margin settings. Shamik Bose is a Ph.D. student at the University of Oklahoma. He received his B.Sc. degree from the University of Calcutta (India), an M.Sc. degree from the Indian Institute of Technology, Kharagpur (India), and an M.S. degree from the University of Oklahoma. His research interests include analog modeling of natural structures in the extensional regime, primarily using wet clay and three-dimensional structural modeling. Shankar Mitra holds the Monnett Chair in Energy Resources at the University of Oklahoma. He received his Ph.D. in geology from Johns Hopkins University in 1977. His primary interests are in structural interpretation and modeling and their application to hydrocarbon exploration and production.

Description: Pore-throat sizes in siliciclastic rocks form a continuum from the submillimeter to the nanometer scale. That continuum is documented in this article using previously published data on the pore and pore-throat sizes of conventional reservoir rocks, tight-gas sandstones, and shales. For measures of central tendency (mean, mode, median), pore-throat sizes (diameters) are generally greater than 2 μm in conventional reservoir rocks, range from about 2 to 0.03 μm in tight-gas sandstones, and range from 0.1 to 0.005 μm in shales. Hydrocarbon molecules, asphaltenes, ring structures, paraffins, and methane, form another continuum, ranging from 100 Å (0.01 μm) for asphaltenes to 3.8 Å (0.00038 μm) for methane. The pore-throat size continuum provides a useful perspective for considering (1) the emplacement of petroleum in consolidated siliciclastics and (2) fluid flow through fine-grained source rocks now being exploited as reservoirs. Phil Nelson is a member of the Central Energy Resources Team of the U.S. Geological Survey, which provides assessments of undiscovered oil and gas. He held research positions in mineral exploration with Kennecott Exploration Services, radioactive waste storage with Lawrence Berkeley Laboratory, and petroleum production with Sohio Petroleum Company. His current interests are in the characteristics of tight-gas resources and the pressure and temperature regimes of sedimentary basins.

Description: Three-dimensional seismic data from the Fuji basin, a salt-controlled intraslope minibasin in north-central Green Canyon, Gulf of Mexico, reveal complex interactions between gravity- and suspension-driven sedimentation. Seismic volumes for late Pleistocene (∼470 ka) to Holocene fill within the Fuji basin consist of approximately 45% mass transport complexes (MTCs), 5% channelized sandy turbidites, and 50% hemipelagites and muddy turbidites. At least ten MTCs within the Fuji basin flowed radially toward its depocenter, either from basin flanks (i.e., intrabasinal) or as a result of larger-scale salt motion (i.e., extrabasinal). Sediment transport directions are inferred on the basis of elongate basal incisions and smaller-scale scours, head scarps, fold orientation within the complexes, and stratigraphic thinning trends at downdip margins. An amalgamated set of three channelized sandy turbidite complexes less than 350 m (1148 ft) thick and 3 km (1.8 mi) across represents the main sand delivery pathway into the Fuji basin. These deposits are thought to be due to shelf bypass, and possibly, to proximity to the Pleistocene shoreline. Hemipelagites and muddy turbidites are homogeneous, and their thickness is relatively consistent at basin scale. This facies represents background sedimentation. A process-driven model has been developed involving halokinetic autocyclicity as the primary control on sedimentation in the Fuji basin. Passive salt motion accounts better for both the directions of sediment transport and the frequency of late Pleistocene–Holocene MTCs than currently popular eustatic and steady-state bathymetric models. The conclusion is significant in casting doubt on the generally assumed importance of eustasy in controlling off-shelf lowstand sedimentation and in implying marked variations in stratigraphic details at length scales of less than 10 km (6.2 mi). Andrew S. Madof is a Ph.D. candidate at Columbia University's Lamont-Doherty Earth Observatory. He received his B.A. degree from Oberlin College in 2000, his M.S. degree from the University of Kansas in 2006, and his M.Phil. degree from Columbia University in 2008. His research focuses on the noneustatic controls on both shallow-marine and deep-water systems and particularly on the role of deformation in modulating accommodation. Nicholas Christie-Blick is a professor of earth and environmental sciences at Columbia University's Lamont-Doherty Earth Observatory. He completed his Ph.D. at the University of California, Santa Barbara, in 1979, and was a research scientist at Exxon Production Research Company in Houston for three years in the early 1980s. Christie-Blick's research and publications deal with such varied topics as sedimentation processes, crustal deformation, and deep-time Earth history, with emphasis on challenging conventional thinking and resolving outstanding disagreements. Mark H. Anders is an associate professor of earth and environmental sciences at Columbia University's Lamont-Doherty Earth Observatory. He received his Ph.D. from the University of California at Berkeley in 1989 working with Walter Alvarez, and joined the Columbia faculty that year. He and his students work on a wide range of topics related to faults and the faulting process, including fault growth, the effects of magmatism on extension, and more recently, the mechanics of large block slides.

Description: The Cenomanian Second Frontier sandstone, one of the major producing units of the Frontier Formation in the Powder River Basin, Wyoming, is a basin-isolated sand body that pinches out to zero thickness in both seaward and basinward direction. The Second Frontier has previously been viewed as a single, relatively homogeneous, wave-dominated sediment succession. Our high-resolution study, integrating detailed facies relationships in outcrop, core, and well logs, shows that the Second Frontier sandstone comprises an offlapping parasequence set, formed from seven regionally mappable wave-dominated parasequences. The parasequences are bounded by minor flooding surfaces that represent previously unrecognized potential flow barriers or baffles. Parasequence boundaries are oriented obliquely to the well-defined regional north-northwest–south-southeast–elongated trend of the unit, and successive parasequences offlap to the south in an along-strike direction. The seaward pinch-out of the Second Frontier sandstone is depositional in nature, as illustrated by well-preserved healing-phase deposits, whereas the basinward pinch-out is caused by marine truncation over a tectonically uplifted area. Parasequence architecture was strongly affected by syndepositional tectonic movement, which determined both (1) the distribution of the entire parasequence set, forming a depositional remnant, and (2) the position and shape of parasequences internal to the remnant. The Second Frontier is thus interpreted as a depositional remnant of a once more extensive wave-dominated deltaic shoreface complex. 2nd revised manuscript received July 10, 2008 Boyan K. Vakarelov is a lecturer at the Australian School of Petroleum, University of Adelaide, Australia, in sedimentology and sequence stratigraphy. His research interests are in shallow-marine clastic sedimentology, high-resolution sequence stratigraphy, and CO2 sequestration. He received a B.Sc. (honors) degree from the University of Toronto in 2001 and a Ph.D. from the University of Texas at Dallas in 2006. Janok P. Bhattacharya is the Robert E. Sheriff Professor of Sequence Stratigraphy at the University of Houston. His research interests include deltaic sedimentology and sequence stratigraphy, the local control of structure on stratigraphy, and reservoir architecture of clastic depositional systems. He received his B.Sc. degree in 1981 from the Memorial University of Newfoundland, Canada, and completed his Ph.D. in 1989 from McMaster University, Hamilton, Ontario, Canada.

Description: In this article we focus on the potential of fault-overlap zones as conduits for fluid flow in a variety of reservoir types. Light detection and ranging (LIDAR) technology were applied to collect a three-dimensional, spatially constrained data set from a well-exposed fault-overlap zone that crops out in the Devil's Lane area of the Canyonlands National Park in Utah. A virtual outcrop was generated and used to extract structural and stratigraphic data that were taken into a reservoir modeling software and reconstructed. The outcrop-based model was flow simulated and used to test fluid flow through a real-world fault-overlap zone. A structural framework was built based on collected outcrop data and combined with a series of nine different facies models. The different facies models included an eolian model based on the outcrop and a range of synthetic fluvial and shallow marine systems. Results show that, for certain depositional models, cross-fault reservoir communication may be poor despite the geometric connectivity of the relay beds. This was the case for low net/gross fluvial models and shoreface models. Conversely, high net/gross fluvial systems and eolian systems show good communication through the same relay zone. Overall, the results show that, in the presence of a fault-overlap zone, pressure communication across a relay ramp may still be poor depending on the scale of the faults and relay ramp as well as the geometry and volume of the sands. Atle Rotevatn received his Candidatus Scientiarum degree (M.Sc. degree equivalent) from the University of Oslo in 2004, studying ductilely deformed rocks of the East Greenland Caledonides. In 2007, he received his Ph.D. in structural geology from the University of Bergen, focusing on reservoir-scale deformation structures and their influence on fluid flow in oil and gas reservoirs. In 2006, he joined the Norwegian exploration and production company Rocksource where he currently works in international exploration. Simon Buckley received his B.Sc. degree (1999) and Ph.D. (2003) in geomatics from Newcastle University, United Kingdom. He has since been a research fellow at the University of Newcastle, Australia, and is currently a researcher at the University of Bergen. His research interests include the application and advancement of geomatics techniques, particularly LIDAR and photogrammetry, within the earth sciences. John Howell holds a B.Sc. degree (hons) from the University of Wales and a Ph.D. (1992) from the University of Birmingham (United Kingdom). After working 10 yr at the University of Liverpool, he established the virtual outcrop geology group at the Center for Integrated Petroleum Research (University of Bergen). His current research interests include collection and use of virtual outcrop data. He divides his time between the University and Rocksource, which he cofounded. Haakon Fossen received his Candidatus Scientiarum degree (M.Sc. degree equivalent) from the University of Bergen (1986) and his Ph.D. in structural geology from the University of Minnesota (1992). He joined Statoil in 1986 and, since 1996, has been a professor in structural geology at the University of Bergen. His scientific interests cover the evolution and collapse of mountain ranges, the structure of rift basins, and petroleum-related deformation structures at various scales.

Description: Joint density is studied in relation to petrographic and petrophysical parameters in two sedimentary carbonate formations characterized by different diagenetic histories: the Kimmeridgian limestones of the Chay Peninsula (western France) with a mean joint density of 6.37 fractures per meter (fr/m) (1.94 fr/ft), and the Bathonian limestones of the Bouye outcrop (western France) with a mean joint density of 1.9 fr/m (0.58 fr/ft). The Chay carbonates are characterized by a lower CaCO3 content, a higher average porosity, and a lower sound velocity than values recorded in the Bouye limestones. The compressive strength and Young's modulus of the Bouye carbonates are, respectively, 10 and 3 times higher than in the Chay carbonates. A statistical analysis was used to identify relationships between joint density and carbonate rock properties. When facies variations are marked, the joint density at outcrop scale is related to the mean bed thickness, the facies descriptors, and the Young's modulus. When textural variations are more limited, the joint density is controlled by the porosity. At the scale of a sedimentary basin, 63.8% of the variation in joint density may be accounted for by Young's modulus and the sparite/micrite ratio. The decrease in the sparite/micrite ratio reflects an increased number of grain boundaries in the carbonate rock, which limits grain deformation and enhances joint density. The variations in Young's modulus depend essentially on the porosity and mineralogy of the studied rocks. Any increase in CaCO3 content or decrease in porosity is associated with an increase in the elastic properties of the rock and a reduction of joint density. Carine Lézin holds a Ph.D. in stratigraphy and sedimentology from the University of Toulouse. She is lecturer at Paul Sabatier University (Toulouse). Her research concerns the relationship between fracturation and carbonate facies and the characterization of Liassic and Cretaceous carbonate systems. Francis Odonne is a professor at the University of Toulouse. He received his M.S. degree from the University of Grenoble and his Ph.D. from the University of Toulouse. He is a structural geologist. His research concerns the quantitative analysis of fracture systems and the analog modeling of tectonic structures. Gérard J. Massonnat holds a Ph.D. in geology and hydrogeology. He is currently the senior technical advisor for Total in reservoir modeling. He conducts research in the stochastic modeling of geological features (sedimentary facies and fractures) driven by physical processes and dynamic behavior. Another side of his scientific interests concerns the upscaling of petrophysics for reservoir modeling. Gilles Escadeillas is a professor in the Department of Civil Engineering of Institut Universitaire de Technologie A (IUT A) (University Paul Sabatier, Toulouse) and the head of the research laboratory LMDC where he conducts research on building materials. His received his Ph.D. is from the University of Paul Sabatier (Toulouse).

Description: Vertical and lateral changes in physical properties in Cenozoic mudstones from the northern North Sea Basin reflect differences in the primary mineralogical composition and burial history, which provides information about sedimentary facies and provenance. Integration of well-log data with mineralogical information shows the effect of varying clay mineralogy on compaction curves in mudstones. The main controlling factor for the compaction of Eocene to early Miocene mudstones within the North Sea is the smectite content, which is derived from volcanic sources located northwest of the North Sea. Mudstones with high smectite content are characterized by low P-wave velocities and bulk densities compared to mudstones with other clay mineral assemblages at the same burial depths. Smectitic clays are important during mechanical compaction because they are less compressible than other types of clay minerals. A comparison between well-log data and experimental work also shows that smectite may be a controlling factor for overpressure generation in the smectite-rich Eocene and Oligocene sediments. At greater burial depths and temperatures (〉70–80°C), the dissolution of smectite and precipitation of illite and quartz significantly increases velocities and densities. Miocene and younger mudstones from the northern North Sea have generally low smectite contents and as a result have higher velocities and densities than Eocene and Oligocene mudstones. Lateral differences in the compaction trends between the north and south for these sediments also exist, which may be related to two different source areas in the Pliocene. The log-derived petrophysical data from the northern North Sea Basin show that mudstone lithologies have very different compaction trends depending on the primary composition. Simplified compaction curves may therefore affect the outcomes from basin modeling. The amplitude-versus-offset response of hydrocarbon sands and the seismic signature on seismic sections are also dependent on the petrophysical properties of mudstones and will vary depending on the mineralogical composition. Øyvind Marcussen received his M.S. degree in 2003 from the University of Oslo. He is presently a Ph.D. student in petroleum geology at the same university. Brit I. Thyberg received her M.S. degree in geology in 1993 from the University of Oslo. She is presently a researcher in petroleum geology at the University of Oslo. Christer Peltonen received his B.S. in geology from California Lutheran University (1996) and his M.S. and Ph.D. in petroleum geology from the University of Oslo, Norway (2007). He is currently working as a development geologist for Venoco Inc. located in Santa Barbara County, California. Jens Jahren received his M.S. degree (1988) and his Ph.D. (1991) from the University of Oslo. He has been an associate professor first in mineralogy and petrology (from 1994) and then in petroleum geology (from 2003) at the same university. His research focuses on mechanical and chemical compaction processes in sediments. Knut Bjørlykke is a professor at the Department of Geosciences, University of Oslo. He has worked in the field of sedimentology and clastic diagenesis. In recent years, he has led a research group on sediment compaction and rock physics at the University of Oslo. Jan Inge Faleide is a professor at the Department of Geosciences, University of Oslo. He has been project leader and principal investigator for several interdisciplinary and international research projects focusing on the formation and evolution of sedimentary basins and continental margins. Most of his studies have been located offshore Norway and conducted in close collaboration with the petroleum industry.

Description: The Penglai 19-3 (PL19-3) oil field, the largest offshore oil field in China, was found in shallow reservoirs (700–1700 m, 2297–5577 ft) within the most active fault zone in east China. The PL19-3 anticline was not finally formed until about 2.0 Ma and is cut by densely distributed faults. Source rock and crude oil samples from the PL19-3 field were analyzed to determine the origin and formation mechanisms of this large oil field. Three organic-rich, oil-prone source rock intervals exist in the Bozhong subbasin, each of which has a distinct biomarker assemblage. Oil samples from different wells have different biomarker associations, and three source-related oil classes were identified within the PL19-3 field based on biomarker compositions and multivariate analysis of the data. The PL19-3 field displays considerable compositional heterogeneity. The compositional heterogeneity within the field and comparison between oil samples from the PL19-3 field and those from nearby structures suggest three field-filling directions, which is consistent with the results of migration pathway modeling. The PL19-3 field was charged in the north by oil generated from Dongying Formation source rocks in the eastern Bozhong depression and Bodong depression, in the southeast by oil generated from Shahejie Formation source rocks in the Miaoxi depression, and in the northwest by oil generated from Shahejie Formation source rocks in the central Bozhong depression. Oil charge from multiple source rock intervals and multiple generative kitchens and focusing of oil originating from a large area of the Bozhong depression into the same trap resulted in rapid oil accumulation in the PL19-3 structure and the formation of this large oil field in a very young trap within an active fault zone. Fang Hao received his Ph.D. from the China University of Geosciences in 1995. He is now a professor of geology at China University of Petroleum and the director of the State Key Laboratory of Petroleum Resources and Prospecting. He has conducted petroleum geology and geochemistry studies in several Chinese basins. His interest includes petroleum generation, migration, and accumulation in the Bohai Bay Basin. Xinhuai Zhou has a Ph.D. in geology from the China University of Geosciences. He is now the chief geologist of the Technology Department of the Tianjin branch of CNOOC Ltd. He has conducted petroleum geology studies in the Bohai Bay Basin for more than 10 years. His publications include studies of petroleum generation, migration, and accumulation in the offshore area of the Bohai Bay Basin. Yangming Zhu received his Ph.D. from the Guangzhou Institute of Geochemistry, Chinese Academy of Sciences (CAS) in 1993. He is now a professor of geochemistry at Zhejiang University. He has conducted petroleum geochemistry studies in several Chinese basins. His interest is now in the study of deposition and evolution of lacustrine source rocks. Xiaohuan Bao received his Ph.D. from the China University of Geosciences in 2008. He is now a research scientist at the university. His interest is in basin modeling and chemometric analysis of geological and geochemical data. Yuanyuan Yang graduated in 2007 with a degree in geochemistry from the Yangtze University and is now a graduate student at China University of Petroleum. Her interest is in the study of biomarker compositions of lacustrine source rocks and crude oils in the Bohai Bay Basin.

Description: Landsat-7 enhanced thematic mapper plus (ETM+) imagery was used to identify anomalous areas caused by hydrocarbon leakage in Fula'erji in the western slope of Songliao Basin, China. Three image enhancement techniques, including principal component analysis (PCA), band ratioing, and false-color composition (FCC), were used. Based on the spectral characteristics of hydrocarbon-induced minerals and the eigenvectors of PCA, the best four principal components (PCs), 1345-PC3 (the third component of the PCA on bands 1, 3, 4, and 5), 1357-PC3, 3457-PC4, and 123457-PC4, were selected for FCC combined with band ratios of 3/1, 4/3, and 7/5. According to the tonal characteristics of the surface near wells and their visual expression, four FCC images were acquired for hydrocarbon-induced area delineation. The result indicates that anomalies are expressed as a faint tone blob and are mostly located in the Holocene sediments. An analysis of two cross sections traversing the identified anomalies suggests that they are closely related to the anomalous area interpreted from the four FCC images. Field data of magnetic susceptibility and delta carbonate are consistent with the distribution of the tonal anomalies and suggest a positive spatial association between the identified anomalous area and the hydrocarbon leakage environment. Guifang Zhang is currently a Ph.D. student at the Department of Earth Sciences of Zhejiang University. She received her B.S. degree (2004) in geography information science (GIS) from the Zhejiang University. Her major research interests concern resource detection and environment assessment by remote sensing and GIS. Lejun Zou is a professor at the Department of Earth Sciences of Zhejiang University. He received his B.S. degree (1986) and his M. A. degree (1989) in geology from Zhejiang University. He has more than 10 years of experience researching for mathematical geology and computer simulation. Xiaohua Shen is a professor at the Department of Earth Sciences of Zhejiang University. He holds a B.S. degree (1982) in geology from the Zhejiang University. His research interests include geology and sedimentology. Shanlong Lu is currently a Ph.D. student at the Department of Earth Sciences of Zhejiang University. He received his B.S. degree (2003) in geology from Hunan University of Science and Technology. His research interests are remote sensing and geology. Changjiang Li is the head engineer of the Zhejiang Information Center of Land and Resources. He received his M.A. degree (1982) in geology from Zhejiang University. He has more than 30 years of experience in the research fields of mathematical geology and geochemical exploration. Hanlin Chen is a professor at the Department of Earth Sciences of Zhejiang University. He received his B.S. degree (1986) in geology from Nanjing University and his M.A. degree (1989) and Ph.D. (1998) in structural geology from Zhejiang University. His research fields are structural geology and petroleum geology.

Description: The sedimentary sequence of the south Thrace Basin (northwest Turkey) comprises Upper Cretaceous–Holocene sediments. In this basin, the Korudağ anticlinorium, which is the subject of this study, is located between the Aegean Sea in the west and the Sea of Marmara to the east. The anticlinorium, which is approximately 300 km (186 mi) long and 40 km (25 mi) wide, was formed by effects of the Neotethys subduction-accretion complex and Istranca massif collision during the late early Miocene. The Korudağ anticlinorium was deformed to its present-day structure by the oldest splay of the North Anatolian fault (upper middle Miocene) and the northern branch of the North Anatolian fault (NAF-N) (not earlier than 200 ka). Organic geochemical analysis, oil and gas to source rock correlation, and basin modeling studies suggest that the Korudağ anticlinorium should be charged by hydrocarbons generated from the Karaağaç, Ceylan (regionally), and Mezardere formations. Gas and oil are being produced from the Korudağ anticlinorium and its subparallel anticlines in the north Marmara, Değirmenköy, Seymen, Çayırdere, Karaçalı, Yulaflı, Tekirdağ, Sevindik, and Vakıflar (gas plus oil) fields. Mapping done as part of this study indicates that the Korudağ anticlinorium has not yet been tested and explored comprehensively. Şamil Şen is an assistant professor in the Geological Engineering Department of Istanbul University, Turkey. He received his M.Sc. degree (1994) and Ph.D. (2001) from the same university. He has then worked in the Thrace Basin. His works have been supported by the Turkish Petroleum Company. His interests are in oil exploration and oil supply security in the Middle East, Caspian Sea, and Russia. His paper titled Security Concerns in the Middle East for Oil Supply: Problems and Solutions was published by Energy Policy. Selin Yıllar is a research assistant and a Ph.D. student at the Geological Engineering Department of Istanbul University, Turkey. She completed her M.Sc. degree thesis, which is related to southwest Thrace Basin sedimentology, in 2005 at the same university. She also studied basin analysis and oil exploration in the south Thrace Basin after her thesis. Her research interests are in sedimentology, sequence stratigraphy, basin analysis, and oil exploration.

Description: An analysis of 31 whole cores (∼1600 ft, ∼490 m) and closely spaced wireline logs (∼500 wells) penetrating the Lower Cretaceous (Cenomanian) lower Woodbine Group in the mature East Texas field and adjacent areas indicates that depositional origins and complexity of the sandstone-body architecture in the field vary from those inferred from previous studies. Heterogeneity in the lower Woodbine Group is controlled by highstand, fluvial-dominated deltaic depositional architecture, with dip-elongate distributary-channel sandstones pinching out over short distances (typically 〈500 ft [〈150 m]) into delta-plain and interdistributary-bay siltstones and mudstones. This highstand section is truncated in the north and west parts of the field by a thick (maximum of 140 ft [43 m]) lowstand, incised-valley-fill succession composed of multistoried, coarse-gravel conglomerate and coarse sandstone beds of bed-load fluvial systems. In some areas of the field, this valley fill directly overlies distal-delta-front deposits, recording a fall in relative sea level of at least 215 ft (65 m). Correlation with the Woodbine succession in the East Texas Basin indicates that these highstand and lowstand deposits occur in the basal three fourth-order sequences of the unit, which comprises a maximum of 14 such cycles. Previous studies of the Woodbine Group have inferred meanderbelt sandstones flanked by coeval flood-plain mudstones and well-connected, laterally continuous sheet sandstones of wave-dominated deltaic and barrier-strand-plain settings. This model is inappropriate, and a full assessment of reservoir compartmentalization, fluid flow, and unswept mobile oil in East Texas field should include the highstand, fluvial-dominated deltaic and lowstand valley-fill sandstone-body architecture. William A. Ambrose is a research scientist at the Bureau of Economic Geology, John A. and Katherine G. Jackson School of Geosciences at the University of Texas at Austin. His areas of interest include unconventional energy minerals, clastic depositional systems, and stratigraphy. He holds M.A. and B.S. degrees in geosciences from the University of Texas at Austin. Tucker F. Hentz is a research associate at the Bureau of Economic Geology, John A. and Katherine G. Jackson School of Geosciences at the University of Texas at Austin. His areas of interest include sequence-stratigraphic analysis and clastic depositional systems. He holds an M.S. degree in geology from the University of Kansas. Florence Bonnaffé is a research scientist associate at the Bureau of Economic Geology, John A. and Katherine G. Jackson School of Geosciences at the University of Texas at Austin. Her previous work was with Elf Exploration Production and Compagnie Générale de Géophysique. She received her M.S. degree in applied geophysics from the University of Paris in 1996. Robert G. Loucks is a senior research scientist at the Bureau of Economic Geology, John A. and Katherine G. Jackson School of Geosciences at the University of Texas at Austin. His research interests include carbonate and siliciclastic sequence stratigraphy, depositional systems, diagenesis, and reservoir characterization. He holds a Ph.D. from the University of Texas at Austin. Frank Brown is a research professor at the Bureau of Economic Geology, John A. and Katherine G. Jackson School of Geosciences at the University of Texas at Austin. His research interests include sequence stratigraphy, depositional systems, and reservoir characterization. He holds a Ph.D. from the University of Wisconsin at Madison. Fred Wang is a research scientist at the Bureau of Economic Geology, John A. and Katherine G. Jackson School of Geosciences at the University of Texas at Austin. He has experience in reservoir characterization, shale gas production, deep-shelf and deep-water fields, CO 2 sequestration, and enhanced oil recovery. He received a Ph.D. in petroleum engineering from Stanford University. Eric C. Potter is an associate director of the Bureau of Economic Geology, John A. and Katherine G. Jackson School of Geosciences at the University of Texas at Austin. He worked for 25 years for Marathon Oil Company as an exploration geologist. He holds an M.S. degree in geology from Oregon State University.

Description: Accurate pore-pressure prediction is critical in hydrocarbon exploration and is especially important in the rapidly deposited Tertiary Baram Delta province where all economic fields exhibit overpressures, commonly of high magnitude and with narrow transition zones. A pore-pressure database was compiled using wireline formation interval tests, drillstem tests, and mud weights from 157 wells in 61 fields throughout Brunei. Overpressures are observed in 54 fields both in the inner-shelf deltaic sequences and in the underlying prodelta shales. Porosity vs. vertical effective stress plots from 31 fields reveal that overpressures are primarily generated by disequilibrium compaction in the prodelta shales but have been generated by fluid expansion in the inner-shelf deltaic sequences. However, the geology of Brunei precludes overpressures in the inner-shelf deltaics being generated by any conventional fluid expansion mechanism (e.g., kerogen-to-gas maturation), and we propose that these overpressures have been vertically transferred into reservoir units, via faults, from the prodelta shales. Sediments overpressured by disequilibrium compaction exhibit different physical properties to those overpressured by vertical transfer, and hence, different pore-pressure prediction strategies need to be applied in the prodelta shales and inner-shelf deltaic sequences. Sonic and density log data detect overpressures generated by disequilibrium compaction, and pore pressures are accurately predicted using an Eaton exponent of 3.0. Sonic log data detect vertically transferred overpressures even in the absence of a porosity anomaly, and pore pressures are reasonably predicted using an Eaton exponent of 6.5. Mark Tingay is currently an Australian postdoctoral fellow at Curtin University, where he works on stress, overpressure, and the tectonic evolution of Southeast Asia. He received his Ph.D. in 2003 from the Australian School of Petroleum. He then became a petroleum geomechanics researcher at the World Stress Map Project, where he worked on projects in 11 countries, including the United States, Egypt, Azerbaijan, and Thailand. Richard Hillis is the head of the Australian School of Petroleum and a state of South Australia professor of petroleum geology at the University of Adelaide. He received his B.Sc. (hons) degree from Imperial College and Ph.D. from the University of Edinburgh. He is a director of JRS Petroleum Research, an image log and geomechanics consulting company, and of Petratherm, a geothermal exploration company. Richard commenced his career in 1979 when he joined Mobil with assignments in the United Kingdom and the United States. He joined Durham University in 1989 and was a principal investigator for a multidisciplinary research group funded by 17 oil and gas companies. Over that period, he developed training courses in subsurface pressures and founded the company GeoPressure Technology. He is an honorary professor at Durham University and has been an AAPG member since 1982. Chris received his Ph.D. in 1983 before working for Amoco and Elf Aquitaine and as a professor at the University of Brunei Darussalam. He is currently working for PTT Exploration and Production as a senior geophysicist. He has worked as an exploration geologist and as a structural geologist in east Africa, Morocco, the Norwegian Caledonides, the Carpathians, northwest Borneo, and Thailand. Abdul Razak Damit is currently the chief geologist with the National Oil Company of Brunei (PetroleumBRUNEI). He obtained his Ph.D. at Aberdeen University and has 20 years of industry experience, primarily in Shell where he worked on both reservoir and regional evaluation. His main interests are in the geology of northwest Borneo and in raising public awareness of the natural and social history of Brunei.

Description: I appreciate Higgs' (2009) discussion of Pyles' (2008) article on the Carboniferous Ross Sandstone of western Ireland (Figure 1), and I am eager to provide a follow-up herein. In his analysis, Higgs challenges the long-established interpretation of the Ross Sandstone both in terms of its depositional environment (submarine fan) and tectonic setting (structurally confined basin). Higgs interprets the Ross Sandstone as being deposited in a large, shallow, freshwater equatorial lake located in a broad foreland basin. He uses this interpretation to argue that the Ross Sandstone is not a suitable outcrop analog for structurally confined submarine fans especially those in northern Gulf of Mexico salt withdrawal basins. Higgs concludes his discussion with a reinterpretation of several of the Earth's best studied submarine-fan outcrops and suggests that they too are lake deposits based on their gross similarities to the Ross Sandstone. This reply examines each of Higgs' criticisms and alternate interpretations and compares them with existing data in the Ross Sandstone. This analysis shows that Higgs' interpretations are inadequately justified. Figure 1 Geologic map of western Ireland and north–south cross section though the Ross Sandstone showing regional stacking patterns and the correlation of condensed sections (goniatite-bearing shale layers and marine bands). Geologic map modified from Pyles (2008). See the work of Pyles (2008) for sources of data used in cross sections. VE = vertical exaggeration. Higgs (2009, p. 1705) proposes that the Ross Sandstone contains evidence for “less-than-marine salinity.” Higgs cited the following observations to support this interpretation: (1) marine fossils are confined to a few thin goniatite-rich layers, and (2) trace fossils are rare and no Nereites ichnofacies are reported. Higgs reasons that because lakes do not contain marine body fossils or Nereites ichnofacies, the Ross Sandstone must therefore have been deposited in a lake. Both of these observations are …

Description: The geometric characteristics of natural fractures significantly impact the hydraulic behavior of fractured reservoirs. Prediction of fracture geometry is therefore important for reservoir development decisions and production forecasting. Although many geometric, kinematic, mechanical, geomechanical, petrophysical, sedimentary, and geophysical attributes correlate to fracture intensity, typically, only the attribute with the highest absolute value correlation is chosen to be carried forward to influence prediction. We employ a geostatistical Bayesian updating approach that quantitatively accounts for multiple important attributes together impacting fracture geometry prediction. The resulting models are more representative of the true geological complexity. This methodology is applied to the Oil Mountain anticline outcrop near Casper, Wyoming. Jason McLennan received his B.S. degree in mining engineering and Ph.D. in geostatistics from the University of Alberta, Canada. He is a member of the Subsurface Technology Organization at ConocoPhillips focused primarily on geostatistical modeling and reservoir performance. Tricia Allwardt received her B.S. degree in earth and planetary sciences from Harvard University and her Ph.D. in structural geology and geomechanics from Stanford University. Tricia is a member of the Subsurface Technology Organization at ConocoPhillips focused primarily on integrating structural analysis, fracture characterization, and geomechanics into reservoir performance. Peter Hennings received his B.S. and M.S. degrees in geology from Texas A&M University and his Ph.D. in geology from the University of Texas. He has held various technical and supervisory positions in Mobil Research Company, Phillips Petroleum Company, and ConocoPhillips. His research and application focus in these positions includes structure and tectonics, seismic interpretation, reservoir description, fracture characterization, and geomechanics. He is currently the manager of the Structure and Geomechanics Group in ConocoPhillips Subsurface Technology. He is a former AAPG distinguished lecturer, a Geological Society of America honorary fellow, and is an adjunct professor at the University of Wyoming. Helen Farrell received her B.Sc. degree in geology from Exeter University, United Kingdom and her M.Sc. degree and Ph.D. in structural geology from Imperial College London. She specialized in fractured reservoir characterization and geological integration with reservoir engineering for Phillips Petroleum Company and ConocoPhillips. She is currently the manager of the Nonconventional Gas Technology Group in ConocoPhillips Technology Organization. She is a former AAPG distinguished lecturer and a Texas professional geoscientist.

Description: Fracture prediction in subsurface reservoirs is critical for exploration through exploitation of hydrocarbons. Methods of predicting fractures commonly neglect to include the stratigraphic architecture as part of the prediction or characterization process. This omission is a critical mistake. We have documented a complex heterogeneous fracture development within the eolian Tensleep Sandstone in Wyoming, which arguably is one of the least complex reservoir facies. Fractures develop at four scales of observation: lamina-bound, facies-bound, sequence-bound, and throughgoing fractures that span the formation. We documented a detailed facies and fracture-intensity model using LIDAR-scanned outcrops located at the Alcova anticline in central Wyoming. Through this characterization, we reveal the existence of a striking variability in fracture intensity caused by original depositional architecture, overall structural deformation, and diagenetic alteration of the host rock. Chris Zahm is a research associate at the Bureau of Economic Geology within the Reservoir Characterization Research Laboratory (RCRL) Industrial Associates program. He received his B.S. degree from the University of Wisconsin-Madison in 1993, M.S. degree from the University of Texas at Austin in 1998 and Ph.D. from the Colorado School of Mines in 2002. His research interests are fractured reservoir characterization, including integration of stratigraphy as a fundamental control on fracture development in outcrop analogs and subsurface reservoirs. Peter Hennings received his B.S. and M.S. degrees in geology from Texas A&M University and his Ph.D. in geology from the University of Texas. He has held various technical and supervisory positions in Mobil Research Company, Phillips Petroleum Company, and ConocoPhillips. His research and application focus in these positions includes structure and tectonics, seismic interpretation, reservoir description, geomechanics, and fracture characterization. He is currently the manager of the Structure and Geomechanics Group in ConocoPhillips Subsurface Technology. He is an AAPG distinguished lecturer, a GSA honorary fellow, and is an adjunct professor at the University of Wyoming.

Description: The Mobile Bay gas field is located offshore Alabama in the northern Gulf of Mexico. Production is from eolian dunes of the Jurassic Norphlet sandstone at depths exceeding 6100 m (〉20,000 ft) and temperatures greater than 200°C. Reservoir connectivity and compositional variation, including the distribution of nonhydrocarbon gases (H2S and CO2), are critical factors in production strategy. To evaluate the controls on compositional variation and connectivity, detailed molecular and isotopic analyses were conducted for 29 wells. Analysis of volatiles in fluid inclusions suggests that the field was originally filled with oil that subsequently cracked to gas. In addition to the thermal destruction (cracking) of oil, the process of thermochemical sulfate reduction (TSR) continues to destroy the remaining hydrocarbons through oxidation of gas and reduction of sulfate to form H2S and CO2. The variable extent of the TSR process at Mobile Bay results in a wide range of hydrocarbon and H2S compositions. Condensates are almost exclusively composed of diamondoids whose composition appears controlled by H2S concentrations. In contrast to hydrocarbon and H2S contents, CO2 concentrations are relatively constant throughout the field. Carbon isotopic ratios for CO2 correlate positively with those for wet-gas hydrocarbons but are heavier than expected for CO2 originating from hydrocarbon oxidation via TSR. The narrow range of CO2 contents and heavy isotope ratios suggests that CO2 is regulated by water-rock equilibration and carbonate precipitation. The destruction of the hydrocarbon gas and mineralization of the carbon dioxide product create a volume reduction and an associated drop in reservoir pressure. This process creates several internal sinks (or exits) that may control the spill direction for gas in the field. Paul Mankiewicz received his B.S. and M.S. degrees in geology and doctorate in environmental science and engineering from the University of California, Los Angeles. He works as a geologic advisor for ExxonMobil Exploration Company, evaluating hydrocarbon systems for new opportunities worldwide. Prior to his current assignment, he worked at ExxonMobil's Upstream Research Company, conducting research in molecular and isotopic geochemistry for over 20 years. Robert Pottorf received his Ph.D. in geochemistry from Penn State University in 1979 and has worked at ExxonMobil Upstream Research since that time. He has conducted research on the origins and distribution of nonhydrocarbon gases, fluid rock interactions related to porosity prediction, developed tools to assess hydrocarbon migration timing and pathways, and applied fluid-inclusion technologies to solve exploration and production problems throughout the world. Mike Kozar received his B.A. degree in geology from the College of Wooster in 1983, and his M.S. degree from the University of Tennessee in 1986. He has worked for ExxonMobil in research and operation settings and has participated in projects ranging from regional exploration to detailed reservoir characterization studies. He has also instructed sequence stratigraphy, reservoir characterization, and seismic interpretation courses. Peter Vrolijk earned his B.S. and M.S. degrees from the Massachusetts Institute of Technology and his Ph.D. in geology from the University of California, Santa Cruz, in 1987. In 1989, he joined Exxon Production Research (now ExxonMobil Upstream Research), doing research on a wide range of topics, including most recently fault-seal analysis and reservoir connectivity analysis.

Description: Crossing conjugate normal faults are common in many hydrocarbon-producing basins. In these settings, they exert a range of influences from trapping hydrocarbon accumulations to producing permeability anisotropy by preferentially enhancing or reducing permeability, and reducing effective thicknesses of seal and reservoir units. The fault intersection region is typically poorly imaged with seismic data, and consequently, developing a coherent interpretation of deformation in the intersection region is difficult. In this article, we explore crossing conjugate normal faults across two orders of magnitude of displacement using clear field exposures from the western United States and subsurface examples from the Jeanne d'Arc Basin, offshore Newfoundland. We demonstrate common structural elements and potential pitfalls associated with interpretation of crossing conjugate normal faults, and emphasize the widespread and often unrecognized occurrence of these structures. David Ferrill received his B.S. degree in geology from Georgia State University in 1984, his M.S. degree in geology from West Virginia University in 1987, and his Ph.D. in geology from the University of Alabama in 1991. He is a licensed professional geoscientist (geology) in the state of Texas. Before joining Southwest Research Institute in 1993, he was an exploration geologist at Shell Offshore Incorporated. David is now a director at Southwest Research Institute and performs analyses of faulting and fracturing and reservoir deformation and does structural geological training and contract consulting for the oil and gas industry. Alan Morris received his B.S. degree (with honors) in geology from the Imperial College of Science and Technology in 1973 and his Ph.D. in geology from the University of Cambridge in 1980. He is a licensed professional geoscientist (geology) in the state of Texas. Before joining Southwest Research Institute in 2005, he was a full professor at the University of Texas at San Antonio, having been on the faculty for 22 years. Alan is now a staff scientist at Southwest Research Institute and focuses on quantitative analysis of deformation processes and stress in diverse tectonic regimes and conducts research and technical assistance projects for the oil industry. Ronald McGinnis received his B.S. and M.S. degrees in geology from the University of Texas at San Antonio in 2002 and 2005, respectively. He is a geologist with background in structural geology, hydrology, and geophysics. His research includes slope stability analyses on landslides; geologic and geophysical characterization to identify sources of radar scattering in various terrains throughout the world; fault analyses to provide a strain-based approach for predicting subseismic faults in various lithologies; and characterization of geologic controls on groundwater movement in the Edwards and Glen Rose formations in central, west, and south Texas.

Description: This study addresses the field-scale architecture and dimensions of fluvial deposits of the lower Williams Fork Formation through analysis of outcrops in Coal Canyon, Piceance Basin, Colorado. The lower Williams Fork Formation primarily consists of mud rock with numerous isolated, lenticular to channel-form sandstone bodies that were deposited by meandering river systems within a coastal-plain setting. Field descriptions, global positioning system traverses, and a combination of high-resolution aerial light detection and ranging data, digital orthophotography, and ground-based photomosaics were used to map and document the abundance, stratigraphic position, and dimensions of single-story and multistory channel bodies and crevasse splays. The mean thickness and apparent width of the 688 measured sandstone bodies are 12.1 ft (3.7 m) and 364.9 ft (111.2 m), respectively. Single-story sandstone bodies ( N = 116) range in thickness from 3.9 to 29.9 ft (1.2 to 9.1 m) and from 44.1 to 1699.8 ft (13.4 to 518.1 m) in apparent width. Multistory sandstone bodies ( N = 273) range in thickness from 5.0 to 47.1 ft (1.5 to 14.4 m) and from 53.2 to 2791.1 ft (16.2 to 850.7 m) in apparent width. Crevasse splays ( N = 279) range in thickness from 0.5 to 15.0 ft (0.2 to 4.6 m) and from 40.1 to 843.3 ft (12.2 to 257.0 m) in apparent width. These data show that most sandstone bodies are smaller than the distance between wells at 10-ac spacing (660 ft [201 m]). Analyses of interwell sandstone-body connectivity suggest that even at 10-ac spacing, only half of the sandstone bodies are intersected and few are intersected by more than one well. Matthew J. Pranter is an associate professor of geological sciences at the University of Colorado at Boulder and the head of the Reservoir Characterization and Modeling Laboratory. He received his B.S. degrees in geology and geological engineering from Oklahoma State University and Colorado School of Mines, respectively; his M.S. degree in geology from Baylor University; and his Ph.D. in geology from the Colorado School of Mines. He was previously with ExxonMobil Upstream Research Company and Conoco. His research interests are in reservoir geology and geophysics, sedimentary geology, and reservoir modeling. Rex D. Cole is a professor of geology at Mesa State College in Grand Junction, Colorado. He obtained his A.S. degree in geology from Mesa Junior College, his B.S. degree in geology from Colorado State University, and his Ph.D. in geology from the University of Utah. His previous employers include Unocal Corporation, Multi-Mineral Corporation, Bendix Field Engineering Corporation, Southern Illinois University-Carbondale, and Asarco Corporation. Henrikus Panjaitan is an earth scientist working in the Duri heavy oil field operated by Chevron Pacific Indonesia. He received his B.S. degree in geology from Institut Teknologi Bandung, Indonesia, and his M.S. degree in geology from Colorado School of Mines. His interests include reservoir characterization and modeling. Nick Sommer is a geologist at EnCana Oil and Gas (U.S.A.) Inc. He received his B.S. degree in geology from the University of Texas at Austin and his M.S. degree in geology from the University of Colorado at Boulder. His interests are in fluvial depositional systems and reservoir characterization and modeling.

Description: The Elm Coulee field of the Williston Basin is a giant oil discovery in the middle Bakken Formation (Devonian–Mississippian) discovered in 2000. Horizontal drilling began in the field in 2000, and to date, more than 600 wells have been drilled. The estimated ultimate recovery for the field is more than 200 million bbl of oil (31.8 million m3). The Bakken Formation in the field area consists of three members: (1) upper shale, (2) middle silty dolostone, and (3) lower siltstone. The total Bakken interval ranges in thickness from 10 to 50 ft (3.1 to 15.3 m) over the field area. The upper shale is dark-gray to black, hard, siliceous, slightly calcareous, pyritic, and fissile. The shale consists of dark organic kerogen, minor clay, silt-size quartz, and some calcite and dolomite. The kerogen consists mainly of amorphous material, and the organic material is distributed evenly throughout the shale interval (not concentrated in laminations or lenses). The upper shale ranges in thickness from 6 to 10 ft (1.8 to 3.1 m) over the field area. The middle member consists of a silty dolostone and ranges in thickness from 10 to 40 ft (3.1 to 12.2 m). The lower member in the Elm Coulee field consists of brownish-gray, argillaceous, organic-rich siltstone. Burrowing and brachiopod fragments are common in the lower member. This facies is equivalent to the lower Bakken black shale facies on the northern side of the field and is interpreted to be an updip-landward equivalent to the deeper-water, black shale facies. The lower member ranges in thickness from 2 to 6 ft (0.61 to 1.8 m). Based on the abundance of fossil content and amount of burrowing, the members of the Bakken Formation are interpreted to have been deposited under aerobic (middle member, common burrows, and rare fossils), dsyaerobic (lower member, common fossils, and lesser amount of burrows), and anaerobic conditions (upper member, rare fossils, and burrows). The main reservoir in Elm Coulee field is the middle member, which has low matrix porosity and permeability and is found at depths of 8500 to 10,500 ft (2593 to 3203 m). The current field limits cover approximately 450 mi2 (1165 km2). The middle Bakken porosities range from 3 to 9%, and permeabilities average 0.04 md. Overall, the reservoir quality in the middle Bakken improves upward as the amount of clay matrix decreases. The middle Bakken is interpreted to be a dolomitized carbonate-shoal deposit based on subsurface mapping and dolomite lithology. The main production is interpreted to come from matrix permeability in the field area. Occasional vertical and horizontal fractures are noted in cores. The vertical pay ranges in thickness from 8 to 14 ft (2.4 to 4.3 m). The Bakken is slightly overpressured with a pressure gradient of 0.53 psi/ft (0.02 kPa/m). Horizontal wells are drilled on 640- to 1280-ac (259- to 518.4-ha) spacing units. Long single laterals, dual laterals, and trilaterals have all been drilled in the field. The horizontal intervals are sand-, gel-, and water-fracture stimulated. Initial production ranges from 200 to 1900 BOPD (31.8 to 302.1 m3/day). Initial potential rates for vertical wells are generally less than 100 BOPD (15.9 m3/day). The upper Bakken shale probably also contributes to the overall production in the field. The exact contribution is unknown but estimated to be less than 20% of the total production. The Elm Coulee field illustrates that the Bakken petroleum system has enormous potential for future oil discoveries in the Williston Basin. Stephen A. Sonnenberg is a professor of geology and holds the Charles Boettcher Distinguished Chair in Petroleum Geology at the Colorado School of Mines. He specializes in unconventional reservoirs, sequence stratigraphy, tectonic influence on sedimentation, and petroleum geology. A native of Billings, Montana, Sonnenberg received his B.S. and M.S. degrees in geology from Texas A&M University and his Ph.D. in geology from the Colorado School of Mines. He has more than 30 years of experience in the petroleum industry. He has served as the president of several organizations, including the AAPG, Rocky Mountain Association of Geologists, and Colorado Scientific Society. Aris Pramudito holds an M.S. degree in geology from the Colorado School of Mines (2008) and a B.E. degree in geological engineering from the Bandung Institute of Technology (ITB) (2006). He has worked in several unconventional and conventional oil and gas plays in the United States and has been involved in several carbonate reservoir characterization studies in the northeast Java Basin and Salawati Basin, Indonesia. He is currently working with BP in Houston, Texas.

Description: Wave-dominated, shoreface-shelf parasequences are commonly modeled as simple layer-cake reservoirs, yet analysis of modern and ancient analogs demonstrates that these intervals contain a more complex physical stratigraphy. We investigate the impact of depositional and diagenetic heterogeneity associated with gently dipping clinoform surfaces on fluid flow and recovery during water flooding, using a three-dimensional model reconstructed from a well-exposed outcrop analog. We demonstrate that the volume of oil in place is affected by variations in facies thickness associated with interfingering along clinoforms, whereas waterflood sweep efficiency is affected by barriers to flow along clinoform surfaces, such as calcite-cemented layers, mudstones, and siltstones. Sweep efficiency is low when water flooding is down depositional dip because oil is bypassed at the toe of each clinothem as water flows preferentially through high-quality sandstone facies in the upper part of the parasequence. Sweep efficiency is higher when water flooding is up depositional dip because the gravity-driven, downward flow of water sweeps poorer-quality sandstone facies in the lower part of the parasequence. In both cases, injectors may offer limited pressure support to producers. Water flooding along depositional strike yields good pressure support but poor sweep because the gravity-driven flow of water into the lower part of the parasequence is significantly reduced. This yields highly variable fluid saturations but a uniform pressure gradient, which is consistent with pressure and fluid saturation data from the mature Rannoch Formation reservoir, Brent field, United Kingdom North Sea. Simple layer-cake models fail to capture the range of flow behaviors described above and overpredict recovery by up to 20% as a result. Matthew Jackson is a senior lecturer in reservoir engineering in the Department of Earth Science and Engineering, Imperial College, London. He holds a B.S. degree in physics from Imperial College and a Ph.D. in geological fluid mechanics from the University of Liverpool. His research interests include simulation of multiphase flow through porous media, representation of geologic heterogeneity in simulation models, and downhole monitoring and control in instrumented wells. Gary Hampson is a senior lecturer in sedimentary geology in the Department of Earth Science and Engineering, Imperial College, London. He holds a B.A. degree in natural sciences from the University of Cambridge and a Ph.D. in sedimentology and sequence stratigraphy from the University of Liverpool. His research interests lie in the understanding of siliciclastic depositional systems and their preserved stratigraphy, and in applying this knowledge to reservoir characterization. Richard Sech is a research scientist at ExxonMobil Upstream Research Company, Houston. He holds a B.S. degree in exploration geology from Cardiff University, an M.S. degree in reservoir evaluation and management from Heriot-Watt University, and a Ph.D. in petroleum engineering from Imperial College, London. His research interests are in reservoir modeling and quantifying the influence of geologic heterogeneity on fluid flow behavior.

Description: Judy Creek, located in west-central Alberta, is one of the largest reservoirs in the Swan Hills oil field. Judy Creek is an isolated reef complex of the Upper Devonian Swan Hills Formation. This mature field has about 350 wells drilled and nearly 6000 m (19,685 ft) of cores and thus provides a good database for depositional facies analysis and testing methods for integrating descriptive and quantitative data in facies modeling. General depositional facies and sequence stratigraphy of Judy Creek have been studied quite extensively. However, no three-dimensional numeric facies model has been built to guide the field development. One of the objectives in constructing such a model for this study was to establish a close linkage between the facies depositional analysis and modeling. As a matter of fact, there have been significant disconnects between descriptive analysis and numeric modeling in the exploration and production. Depositional facies analysis has focused on conceptual understanding for prospect generation and reservoir delineation, whereas facies modeling has emphasized data mining for field development. In this study, a method that integrates the spatial propensity from the depositional conceptual models and facies data from the wells is used to bridge the gap between the depositional analysis and stochastic modeling. Such integration has proven to be critical in building realistic subsurface models in Judy Creek because it helped improve the estimation of subsurface resources. Y. Zee Ma received his Ph.D. in mathematical geology in 1987 from the Institute National Polytechnique de Lorraine (INPL) in France, a bachelor degrees in geology from China University of Geoscience, and master degrees in remote sensing and geostatistics from INPL and Ecole de Mines de Paris in France. He worked as a consultant for Elf (now part of Total S.A.) in Pau, France, and ExxonMobil in Houston before joining Schlumberger, where he is a principal geoscientist. His interests include geostatistics, seismic attributes, depositional facies analysis and modeling, reservoir characterization and modeling, subsurface resource evaluation, and uncertainty analysis. He has conducted, or advised on, nearly 100 reservoir studies for major, independent, and national oil companies from around the world. Andrew Seto is currently the manager, reservoir studies, of Pengrowth Corporation. He obtained a B.Sc. (engineering) degree, with distinction, in 1980 and an M.Sc. (engineering) degree in 1985 both from the University of Alberta. Andrew has 24 years of experience in the petroleum industry, working for major oil and gas companies in various reservoir engineering and management capacities. He specializes in integrated reservoir studies, depletion planning, reservoir management, and reserve evaluation of conventional oil and gas, thermal, and other enhanced oil recovery projects in Canada and around the world. Ernest Gomez has B.A. and M.S. degrees in geology from the State University of New York at New Paltz and Northern Arizona University, respectively. During his career, he has worked with several operators, including Cities Service and Home Petroleum. He is currently a reservoir geology advisor with Schlumberger Data and Consulting Services in Denver, Colorado.

Description: The Jurassic Navajo Sandstone core in the Covenant field in- cludes eolian dune interbedded with carbonate playa lake and fluvial interdune facies. Dune facies samples are bleached but not depleted in iron; bleached dune facies outcrop samples are depleted in iron. Bleached dune facies in the core samples contains ferroan dolomite, quartz overgrowths that do not com- pletely fill pore spaces, grain-coating and pore-filling illite, coarse-grained gray hematite, kaolinite, and trace pyrite. Red- dish brown interdune facies are typically very fine-grained sandstone and siltstone and contain dolomite and ferroan dolo- mite cement, illite pore-filling, and very fine-grained, red he- matite. Diagenetic mineralogy and chemical compositions overlap the mineralogy and compositions of outcrop samples. The carbon and oxygen isotopic composition of dolomite in interdune facies and adjacent dune facies is derived from ground- water discharge modified by evaporation in a playa lake inter- dune environment, not from interaction with hydrocarbons. The iron in bleached dune facies is incorporated in coarse- grained hematite, ferroan dolomite, and trace pyrite. The bleached diagenetic mineral association of ferroan dolomite- hematite-pyrite with SO 4 2- is metastable relative to more re- 4 ducing conditions produced by petroleum. The reservoir temperature of 188°F (87°C) is too high for bacterial sulfate reduction and too low for geologically significant thermo-chemical sulfate reduction accounting for the association of abundant SO 4 2- in produced water and trace pyrite in the core.

Description: Carbonate rocks commonly contain a variety of pore types that can vary in size over several orders of magnitude. Traditional pore-type classifications describe these pore structures but are inadequate for correlations to the rock's physical properties. We introduce a digital image analysis (DIA) method that produces quantitative pore-space parameters, which can be linked to physical properties in carbonates, in particular sonic velocity and permeability. The DIA parameters, derived from thin sections, capture two-dimensional pore size (DomSize), roundness (γ), aspect ratio (AR), and pore network complexity (PoA). Comparing these DIA parameters to porosity, permeability, and P-wave velocity shows that, in addition to porosity, the combined effect of microporosity, the pore network complexity, and pore size of the macropores is most influential for the acoustic behavior. Combining these parameters with porosity improves the coefficient of determination ( R 2) velocity estimates from 0.542 to 0.840. The analysis shows that samples with large simple pores and a small amount of microporosity display higher acoustic velocity at a given porosity than samples with small, complicated pores. Estimates of permeability from porosity alone are very ineffective ( R 2 = 0.143) but can be improved when pore geometry information PoA ( R 2 = 0.415) and DomSize ( R 2 = 0.383) are incorporated. Furthermore, results from the correlation of DIA parameters to acoustic data reveal that (1) intergrain and/or intercrystalline and separate-vug porosity cannot always be separated using sonic logs, (2) P-wave velocity is not solely controlled by the percentage of spherical porosity, and (3) quantitative pore geometry characteristics can be estimated from acoustic data and used to improve permeability estimates. Ralf J. Weger was a postdoctoral researcher with the Comparative Sedimentology Laboratory at the University of Miami when the article was written. He received his B.S. degree in systems analysis (2000) and his Ph.D. in marine geology and geophysics (2006) from the University of Miami. His dissertation focuses on quantitative pore- and rock-type parameters in carbonates and their relationship to velocity deviations. His main interests range from processing and visualization of geophysical data to petrophysical characterization of carbonate rocks. Gregor P. Eberli is a professor in the Division of Marine Geology and Geophysics at the University of Miami and the Director of the Comparative Sedimentology Laboratory. He received his Ph.D. from the Swiss Institute of Technology (ETH) in Zürich, Switzerland. His research integrates the sedimentology, stratigraphy, and petrophysics of carbonates. With laboratory experiments and seismic modeling, his group tries to understand the physical expression of carbonates on log and in seismic data. He was a distinguished lecturer for AAPG (1996/97), Joint Oceanographic Institutions (1997/1998), and the European Association of Geoscientists and Engineers (2005/2006). Gregor T. Bächle graduated from the University of Tübingen in 1999 with a Diploma (equivalent to M.Sc. degree) in geology. In 2001, he joined the Comparative Sedimentology Laboratory (CSL) with a Scholarship of the German Academic Exchange Service to obtain a Ph.D. from the University of Tübingen. From 2004 to 2008, he was a research associate in the CSL, managing the rock physics laboratory. He is currently working for ExxonMobil Upstream Research Company, Quantitative Interpretation, Houston, Texas. Jose Luis Massaferro is a geology manager in Repsol YPF's exploration office in Argentina. He received his Ph.D. from the University of Miami in 1997. He was a Fulbright Fellow while pursuing his studies in Miami. Prior to his Ph.D. studies, he worked for Texaco as a geologist. In 1998, he joined Shell E&P and was involved in different projects, including 3-D seismic volume interpretation, high-resolution sequence stratigraphy, and kinematic modeling of compressional structures. In 2005, he joined Repsol in Madrid. Yue-Feng Sun is an associate professor at Texas A&M University. He received his Ph.D. (1994) from Columbia University. He has 25 years of experience as a geoscientist in the industry and academia. His professional interests include carbonate rock physics, poroelasticity, poroelectrodynamics, reservoir geophysics, and petroleum geology. He is a member of AAPG, the American Geophysical Union, American Physical Society, and the Society of Exploration Geophysicists.

Description: Understanding large-scale sediment distribution patterns and morphological characteristics in subsurface sedimentary systems is highly challenging and generally requires regional seismic and well coverage. Here, we test a method that aims to predict first-order morphological characteristics and type of sedimentary transport system in ancient source-to-sink systems based on trends observed in submodern (Pliocene–Holocene) depositional environments. An example from the Paleocene Ormen Lange system (Møre Basin, Norwegian Sea) demonstrates the application of the method, and several descriptive parameters are estimated for this ancient subsurface system. In the Ormen Lange system, basin-floor fan and distal-slope parameters are well constrained from seismic and well control. However, knowledge of the morphology and relationships between upper slope, shelf, and catchment characteristics and their relationships to deep-water systems is poor, and these are the parameters that are discussed in this study. Estimated parameters of catchment size derived from this technique are in good agreement with preserved remnants of fluvial valleys located onshore. Predicted sediment transport characteristics are also comparable to the depositional mechanisms interpreted from cores and well logs, suggesting a small tectonically active system with high fluvial discharge and low sediment storage potential in the catchment and shelf subenvironments. The discussed method is thus capable of predicting first-order segment characteristics in subsurface sedimentary systems with an uncertainty of one to two orders of magnitude. This information can be used to increase the understanding of unexplored basins or to add data and uncertainty ranges to well-known petroleum systems. Tor O. Sømme is currently a postdoctoral researcher at the Department of Earth Science, University of Bergen, where he also received his Ph.D. in 2009. His current research interest is related to the stratigraphic and geomorphic development of source-to-sink systems. Ole J. Martinsen is a sedimentary geologist and is presently the vice president of Exploration Research of StatoilHydro in Bergen, Norway. He has published widely on sequence stratigraphy and deep-water sedimentary systems, in other fields in sedimentary geology, and in exploration geology. He is currently the Roy M. Huffington AAPG Distinguished Lecturer and was formerly an international councilor for SEPM. John Thurmond holds a B.Sc. degree (1997) and a Ph.D. (2006) in geosciences from the University of Texas at Dallas. He has worked as a researcher for StatoilHydro (formerly Norsk Hydro) since 2004. He previously worked as a consultant for Schlumberger Doll Research and Pioneer Natural Resources, and as an intern for ExxonMobil Upstream Research.

Description: Understanding and interpreting the timing, location, orientation, and intensity of natural fractures within a geologic structure are commonly important to both exploration and production planning activities. Here we explore the application of finite-element-based geomechanical models to fracture prediction. Our approach is based on the idea that natural fractures can be interpreted or inferred from the geomechanical-model-derived permanent strains. For this analysis, we model an extensional fault-tip monocline developed in a mechanically stratified limestone and shale sequence because field data exist that can be directly compared with model results. The approach and our conclusions, however, are independent of the specific structural geometry. The presence or absence of interlayer slip is shown to strongly control the distribution and evolution of strain, and this control has important implications for interpreting fractures from geomechanical models. Kevin Smart received his B.S. degree in geology from Allegheny College in 1989, his M.S. degree in geology from the University of New Orleans in 1992, and his Ph.D. in geology from the University of Tennessee in 1996. He is a licensed professional geoscientist (geology) in the state of Texas. After 6 years on the faculty of the University of Oklahoma, he joined Southwest Research Institute in 2003. He is currently a senior research scientist in the Department of Earth, Material, and Planetary Sciences, and focuses on structural geology and geomechanics research and technical assistance projects for the oil industry. David Ferrill received his B.S. degree in geology from Georgia State University in 1984, his M.S. degree in geology from West Virginia University in 1987, and his Ph.D. in geology from the University of Alabama in 1991. He is a licensed professional geoscientist (geology) in the state of Texas. Before joining Southwest Research Institute in 1993, he was an exploration geologist at Shell Offshore Incorporated. He is now a director at Southwest Research Institute and performs analyses of faulting and fracturing and reservoir deformation and does structural geological training and contract consulting for the oil and gas industry. Alan Morris received his B.Sc. degree (with honors) in geology from the Imperial College of Science and Technology in 1973 and his Ph.D. in geology from the University of Cambridge in 1980. He is a licensed professional geoscientist (geology) in the state of Texas. Before joining Southwest Research Institute in 2005, he was a full professor at the University of Texas at San Antonio, having been on the faculty for 22 years. He is now a staff scientist at Southwest Research Institute and focuses on quantitative analysis of deformation processes and stress in diverse tectonic regimes and conducts research and technical assistance projects for the oil industry.

Description: The Teton anticline is a multiple hinge anticline containing fractured Mississippian–Devonian carbonates in the frontal part of the Sawtooth Range in Montana. The structure serves as a good surface analog for fracture patterns and connectivities within subsurface-folded carbonate reservoirs. The primary fracture sets are longitudinal and transverse relative to the axis of the fold, although two additional oblique sets are also present. The length and density of the longitudinal fracture sets are strongly controlled by position relative to multiple hinges. The transverse fractures are related to changes in fold plunge and exhibit less variation in fracture density. Fracture connectivity is dependent on the number of fracture sets, their orientations and dispersions, and the densities of the fracture sets. The connectivity is measured using two parameters: the fractional connected area (FCA), which represents the fraction of the total sample area that is connected by fractures, and the distribution of clusters of different sizes in any given area. Because the longitudinal fractures represent the dominant fracture set and also show the most variation with structural position, the fracture connectivity, as measured by both the FCAs and the distribution of cluster sizes, is greater in the vicinity of the fold hinges. The results and approaches used in the study have some important implications for subsurface-folded fractured carbonate reservoirs. The analysis of sparsely distributed fracture data from wells must be integrated with an understanding of the controls of the macroscopic structure on fracture parameters to effectively simulate fracture patterns and connectivities around subsurface structures. Kajari Ghosh received her B.Sc. and M.Sc. degrees in geology from Calcutta University, her M.S. degree from Florida International University, and her Ph.D. from the University of Oklahoma. She is currently an exploration geoscientist at Exxon-Mobil. Her research interests are in fracture analysis and 3-D structural interpretation. Shankar Mitra holds the Monnett Chair and Professorship of Energy Resources at the University of Oklahoma. His principal research interests are in 3-D structural interpretation and modeling and fault and fracture analysis.

Description: Within the Nile Delta gas province, reservoirs are dominated by Pliocene slope-channel systems, which are spectacularly imaged on high-quality three-dimensional seismic data. This article deals with the detailed seismic geomorphology of the Sequoia channel system, focusing on the geometry and distribution of its component sand bodies and the impact they have on reservoir heterogeneity. The Sequoia reservoir serves as a potential analog for similar but less well-imaged, deep-water slope systems. The reservoir consists of a succession of sandstones and mudstones organized into a composite upward-fining profile. Sand bodies include laterally amalgamated channels, sinuous channels, channels with frontal splays, and leveed channels and are interpreted to be the products of deep-water gravity-flow processes. Above a major basal incision surface, the reservoir is highly sand prone and made up of laterally amalgamated channels. The medial section of the reservoir is more aggradational and exhibits laterally isolated and sinuous channels. Within the upper part of the reservoir, channels are smaller, straighter, and built of individual channels with associated frontal splay elements and less common leveed channels. The main channel system is buried by a prograding slope succession that includes lobate sand-sheet elements. The stacking of facies within the Sequoia channel system implies a punctuated waning of sediment supply prior to eventual abandonment. The Sequoia channel is interpreted to be the late lowstand to transgressive infilling of a third-order early lowstand slope incision. The channel fill is overlain by a mudstone unit, which delineates a major correlatable hot gamma-ray event, and on seismic data, is a prominent downlap surface and therefore a possible maximum flooding surface. The Sequoia channel system shows evidence for synsedimentary faulting, including a large-scale downdip widening of the channel and small-scale channel diversions and intraslope ponding of flows. Understanding reservoir architecture in terms of sand-body geometries and connectivity is vital within Sequoia because the gas column occupies the most complex and heterogeneous upper part of the reservoir. Correspondingly, the basal sand-rich part of the reservoir will significantly influence aquifer behavior during production. Nigel Cross has a B.Sc. degree and a Ph.D. from Royal Holloway, University of London. He has worked for BG Group since 2004 first in Egypt and later in Trinidad and Tobago. Prior to BG, he worked for Petro-Canada, Hess, and Badley Ashton. His technical interests include sedimentology, sequence stratigraphy, and their subsurface application to reservoir characterization. Alan Cunningham has a B.Sc. degree from Queen's University, Belfast, and an M.Sc. degree and a Ph.D. from University College, Dublin. He has worked for BG Group since 2005 as a geophysicist in BG's Global New Ventures in the United Kingdom and later as a development geophysicist in Cairo. Prior to BG, he worked for Hess in London and Houston. Rob Cook has a B.Sc. degree and a Ph.D. from Reading University. He has worked for BG Group since 1993 as a development geologist based in the United Kingdom, Trinidad and Tobago, and later in Cairo, where he is the subsurface coordinator for the Sequoia development. Amal Taha has a B.Sc. degree in geology from Cairo University. She has been with Rashpetco since 2006 as a development geologist. Eslam Esmaie has a B.Sc. degree in geology from Tanta University, Egypt. She has been with Petronas since 2007 as a geologist. Nasar Swidan has a B.Sc. degree in geology from Azahir University, Cairo. He has been with Rashpetco since 1997 and is the Regional Studies and Prospect Evaluation General Manager. Prior to Rashpetco, he was with the Suez Oil Company.

Description: The marine Middle and Upper Devonian section of the Appalachian Basin includes several black shale units that carry two regional joint sets (J1 and J2 sets) as observed in outcrop, core, and borehole images. These joints formed close to or at peak burial depth as natural hydraulic fractures induced by abnormal fluid pressures generated during thermal maturation of organic matter. When present together, earlier J1 joints are crosscut by later J2 joints. In outcrops of black shale on the foreland (northwest) side of the Appalachian Basin, the east-northeast–trending J1 set is more closely spaced than the northwest-striking J2 set. However, J2 joints are far more pervasive throughout the exposed Devonian marine clastic section on both sides of the basin. By geological coincidence, the J1 set is nearly parallel the maximum compressive normal stress of the contemporary tectonic stress field ( S Hmax). Because the contemporary tectonic stress field favors the propagation of hydraulic fracture completions to the east-northeast, fracture stimulation from vertical wells intersects and drains J2 joints. Horizontal drilling and subsequent stimulation benefit from both joint sets. By drilling in the north-northwest–south-southeast directions, horizontal wells cross and drain J1 joints, whenever present. Then, staged hydraulic fracture stimulations, if necessary, run east-northeast (i.e., parallel to the J1 set) under the influence of the contemporary tectonic stress field thereby crosscutting and draining J2 joints. Terry Engelder, a leading authority on the recent Marcellus gas shale play, received his B.S. degree from Pennsylvania State University (1968), his M.S. degree from Yale University (1972), and his Ph.D. from Texas A&M University (1973). He is currently a professor of geosciences at Penn State and has previously served on the staff of the U.S. Geological Survey, Texaco, and Lamont-Doherty Earth Observatory. He has written 150 research papers, many focused on fracture in Devonian rocks of the Appalachian Basin, and a book, Stress Regimes in the Lithosphere . Gary Lash, an authority on various aspects of the Middle and Upper Devonian shale succession of western New York, received his B.S. degree from Kutztown State University (1976) and his M.S. degree and Ph.D. from Lehigh University (1978 and 1980, respectively). Before working in western New York, Lash was involved in stratigraphic and structural investigations of thrusted Cambrian–Ordovician deposits of the central Appalachians. Redescal Uzcátegui is a professor of structural geology at the Universidad Simón Bolívar and an I&D (Instruction & Development) associated professional in tectonics and structural geology at Petroleos de Venezuela, S.A. (PDVSA)-Intevep. He received his B.A. degree in geology at the Universidad Central de Venezuela and his Ph.D. in geosciences from the Pennsylvania State University. His current focus of research is the geometry and evolution of structures and fractures in the Perijá and Andes de Mérida foothills, and the Maracaibo Basin in Venezuela.

Description: Several methods have been developed to characterize the pore spaces in sandstone reservoirs using data on the pore-throat-size distribution obtained from mercury injection tests. The Winland equation, the threshold pressure, the displacement pressure, and Pittman's equation are mostly used for this purpose to delineate the stratigraphic traps and seals. This study examines the reliability of these methods applied to the highly permeable Nubia sandstones in their type section in southern Egypt. These sandstones are composed mainly of siliceous sandstones and constitute the main Paleozoic–Cretaceous aquifers and reservoirs in Egypt. Routine core analysis and mercury injection tests were conducted to delineate the pore network characteristics for these rocks. The relationships between helium porosity and the uncorrected air permeability from the routine core analysis, and the various parameters derived from mercury injection–capillary pressure curves were established using multiple regressions. This study indicates the high reliability of the displacement pressure at 10% mercury saturation and also reveals the apex of Pittman's hyperbole at 45% mercury saturation as a complexity apex at which the pore network becomes highly chaotic. Despite the great benefits of such types of measurements, they are not commonly used because of their high cost. This study introduces a series of empirical equations for constructing a partial pore-aperture-size distribution curve from routine core analysis for the highly permeable rocks. Bassem Nabawy received his M.Sc. degree in petrophysics, magnetism, and sedimentology from Cairo University, and his Ph.D. in the same field from Ain Shams University, Cairo. He is a petrophysicist. His research concerns matching the rock-pore fabrics to define the preferred fluid migration paths. Yves Géraud received his Ph.D. from the University of Marseilles in rock physics. He is a Maitre de Conférences in the University of Strasbourg. His research concerns porosity structures at various scales and their relationships with transfer properties in various geological contexts. Pierre Rochette received his Ph.D. from the Université Joseph Fourier in Grenoble in 1983. He has mainly worked on rock magnetism together with other petrophysical markers of rock fabric and mineralogical composition. Nicolas Bur received his M.Sc. degree from the University of Strasbourg on physical properties of Nubian sandstones. He is preparing a Ph.D. thesis on the petrophysical properties of concretes and the influence of different external factors of drying on the microstructural parameters.

Description: More than 10 gas pools have been discovered since 1983 in the shallow-water region of the Pearl River Mouth (PRM) Basin and the Qiongdongnan (QDN) Basin, offshore South China Sea. Gases produced from the QDN basin are characterized by high contents of benzene and toluene and relatively heavy δ13C2 values (−25 to −27‰). The associated condensates have a high abundance of bicadinanes and oleanane, providing a good correlation with the coal-bearing sequence of the Oligocene Yacheng Formation in the basin. In contrast, the gases from the PRM basin contain lower amounts of benzene and toluene and lighter δ13C2 values (−24 to −34‰). Widely variable concentrations of bicadinane and oleanane were identified from the associated condensates, which can be mostly correlated with the lower Oligocene Enping Formation source rocks formed in a swamp to shallow lake environment. Oil-cracked gases sourced from the Eocene oil-prone source rock may also provide some contribution to the PRM basin gases. The available geochemical data indicate that both the Yacheng and Enping formations contain mainly type III and II2 kerogens with dominant gas potential. Regional geological information indicates that the deep-water regions of the two basins share the same hydrocarbon source sags with the shallow-water areas, and they developed massive sandstone reservoirs during the Oligocene and Miocene. Fluid-flow modeling results show that the deep-water regions were on the pathway of lateral migrating gases, and the interpreted reservoirs in these zones have developed abundant seismic bright spots, which may reflect the presence of gas. The deep-water regions of the offshore South China Sea are believed to have great gas exploration potential. Weilin Zhu is chief geologist at China National Offshore Oil Corporation. He received his Ph.D. in 2001. His main research interests include petroleum systems, basin analysis, and risk evaluation of petroleum exploration. Baojia Huang is a senior geologist at the Research Institute of China National Offshore Oil Corporation Ltd., Zhanjiang, and a guest professor in Guangzhou Institute of Geochemistry, Chinese Academy of Sciences. He received his Ph.D. in petroleum geology from the Guangzhou Institute of Geochemistry, Chinese Academy of Sciences in 2002. His main research interests include petroleum geochemistry, reservoir geochemistry, and petroleum systems. Lijun Mi is a project director in the Exploration Department, China National Offshore Oil Corporation Ltd. He received his Ph.D. from China University of Petroleum in 2007. His current research interests include petroleum system analysis and risk evaluation of petroleum exploration. Wilkins was formerly a chief research scientist at Commonwealth Scientific and Industrial Research Organization Petroleum, where he worked on fluid inclusions, laser instrumentation, and novel methods for maturity determination based on the fluorescence of organic matter. Ning Fu is a senior geologist at the Research Center of China National Offshore Oil Corporation Ltd. His main research interests are petroleum geochemistry and geology. Xianming Xiao is a professor in Guangzhou Institute of Geochemistry, Chinese Academy of Sciences. He received his Ph.D. in geology from Beijing University of Mining and Technology in 1989. His current research interests include the dynamics system of petroleum accumulation, with particular attention to hydrocarbon generation and cracking kinetics.

Description: Subsurface mapping of several relay ramps from a raft-related fault array in the lower Congo Basin, offshore Angola, reveals a full spectrum of fault linkage styles. A comprehensive three-dimensional geometric and kinematic appraisal of a more complex relay system within the fault array, the Sembo relay system (SRS) highlights differences with current structural models of relay ramp genesis, evolution, and breaching. The SRS is a rearward (upper ramp) breached relay system with a maximum fault overlap and spacing of 9500 and 3600 m (~31,000 and 11,800 ft), respectively. This system is characterized by a structural geometry that becomes increasingly complex with depth as the relay system is gradually assimilated into the structural architecture of a separate and structurally deeper fault system. A detailed kinematic appraisal of the SRS indicates that the throw patterns on the frontal and rearward segments are intrinsically different. Throw backstripping reveals different initiation ages for the rearward and frontal segments of about 5.5 and 2.5 Ma, respectively. Mutual overlap is estimated to first occur about 2.5 Ma at the 5.0 Ma structural level, with fault linkage and ramp breaching occurring subsequently. The SRS therefore represents a complex amalgamation of faults that have each developed independently at different times. The genesis and evolution of the SRS have been governed through time by both salt withdrawal and associated fault detachment histories, in conjunction with increased Congo Fan progradation and sedimentation rates and phases of tectonic tilting of the underlying salt detachment surface. David Dutton is currently working for Nexen as a geophysicist on the North Sea Core Areas team. Prior to this, he worked extensively on play concepts and prospect generation in a variety of basins from the Norwegian and west African margins. For his Ph.D. studies, David researched the genesis, evolution, and breaching of relay ramps, offshore Angola. Bruce Trudgill is an associate professor in the Department of Geology and Geological Engineering at the Colorado School of Mines. His research interests are in structural controls on depositional systems and the evolution of geological structures through time. He teaches undergraduate and graduate courses in structural geology, seismic interpretation, and basin evolution.

Description: There are two opposing schools of thought that infer either the Bakken Formation or the Lodgepole Formation as the primary source rock for the Madison-reservoired oils in the Canadian Williston Basin. A recent geochemical study revealed evidence indicating the existence of significant mixing of Bakken and Lodgepole oils in the Madison reservoirs. To investigate the geographic distribution of the oil compositions, we employed a multivariate statistical method to extract source and maturity-specific geochemical signatures from a geochemical data set for spatial analysis. Oil mixing appears to be geographically dependent and restricted by a northeast-southwest–striking zone (Torquay-Rocanville trend) in southeast Saskatchewan. Thus, fracture or fault systems are inferred to have provided high-permeability zones allowing Bakken-derived oil to migrate upward across the Lodgepole Formation. The areas without significant fault or fracture systems favor lateral oil migration along porous beds, restricting Bakken-derived oil accumulation to pools in Bakken reservoirs and Lodgepole-derived oils to occur primarily in overlying reservoir beds of the Madison Group. Zhuoheng Chen obtained his Ph.D. from the Norwegian University of Science and Technology in 1993 and held a position as an associate professor at China University of Petroleum (Beijing) before joining the Geological Survey of Canada in 1998. His research interests include petroleum resource assessment (methods and applications), petroleum systems, and basin analysis. Kirk Osadetz graduated from the University of Toronto (B.Sc., 1978; M.Sc., 1983). He manages the Earth Science Sector Gas Hydrates Fuel of the Future Program and is the head of the Laboratory Services Subdivision at the Geological Survey of Canada in Calgary. He is active regarding petroleum resource evaluation and has research interests in gas hydrates, tectonics, and thermochronology. He worked previously at Gulf Canada Resources Inc. and PetroCanada Resources Inc. in Calgary. Chunqing Jiang holds a Ph.D. in organic geochemistry. He has more than 15 years of experience in analytical and interpretive petroleum geochemistry related to petroleum exploration and production in China, Australia, and Canada. He is a senior lab scientist at Gushor Inc. and the Petroleum Reservoir Group of the University of Calgary. He has worked with Humble Geochemical Services, the Geological Survey of Canada, and PetroChina. Maowen Li has been a research scientist with the Geological Survey of Canada since 1995. Since he received his Ph.D. in organic geochemistry from the University of Melbourne in 1991, he has conducted petroleum system studies in China, North Sea, Southeast Asia, North America, and Central Africa. His interest is in the study of petroleum system models and petroleum exploration strategies.

Description: A series of deformation bands from various reservoir sandstones deformed at different burial depths have been studied with respect to microstructural and petrophysical variations. In many of the examples explored, the internal microstructure, porosity, and permeability vary along the bands at the centimeter or even millimeter scale, changing and in most cases reducing the ability of the bands to act as barriers to fluid flow. Porosity varies by up to 18% and permeability by up to two orders of magnitude. Such petrophysical variations are found along different types of deformation bands, but the range depends upon the deformation mechanisms, in particular on the degree of cataclasis and dissolution in cataclastic and dissolution bands, and on the phyllosilicate content in disaggregation bands. For cataclastic bands, the grain-size distribution changes along the bands with regard to the degree of cataclasis. Furthermore, the increased specific surface area of the pore-grain interface as a result of cataclasis causes higher permeability reduction in cataclastic bands than in other types of deformation bands. Phyllosilicate content can influence the thickness of phyllosilicate bands. However, no apparent correlation between thickness and intensity of cataclasis in the studied cataclastic deformation bands is observed. Anita Torabi received her B.S. degree in geology from the University of Tehran (1993) and her Ph.D. in petroleum structural geology from the University of Bergen (2008). She joined the Center for Integrated Petroleum Research at the University of Bergen in 2004 and is currently a senior researcher. Her scientific interests include the analysis of faulted and fractured reservoirs in different stress regimes, fault-related folding and its role in hydrocarbon entrapment, and the effect of faulting on the petrophysical properties of rocks and fluid flow. Haakon Fossen received his Candidatus Scientiarum (M.S. degree equivalent) degree from the University of Bergen (1986) and his Ph.D. in structural geology from the University of Minnesota (1992). He joined Statoil in 1986 and, since 1996, has been a professor in structural geology at the University of Bergen. His scientific interests cover the evolution and collapse of mountain ranges, the structure of rift basins, and petroleum-related deformation structures at various scales.

Description: Sandstones that have high porosity and permeability at great burial depth and high temperatures are of economic importance because a significant amount of hydrocarbons have been discovered in such reservoirs. The Sawan gas field, with an expected ultimate recovery of more than 1 tcf, lies in the middle Indus Basin. The reservoir rocks, Cretaceous volcaniclastic sandstones of the lower Goru Formation, show very high porosities at a reservoir temperature of 175°C and depths of 3000 to 3500 m (9842 to 11,483 ft). The sandstones are mostly feldspathic litharenites. Strongly altered volcanic rock fragments are the most important lithic component. The clay fraction consists of Fe-rich chlorite (chamosite) and illite. Diagenetic features such as compaction, quartz overgrowths, carbonate cements, and feldspar dissolution are observed. The most distinguishing feature is a double layer of authigenic chlorite, lining the pores of the sandstones. Chlorite additionally occurs as a pore-filling cement and as chloritized detrital components, all having similar chemical composition. The pore-lining cement clearly developed in two stages: an earlier, poorly crystallized, and a later, better crystallized growth. Missing rims at grain contacts show that precipitation occurred after an initial stage of compaction but early relative to other diagenetic phases. Both chlorite rims grew by direct precipitation from pore waters, using products derived from volcanic rock fragments. In areas with no, thin, or discontinuous chlorite rims, quartz cementation is common. Well-developed chlorite rims inhibited quartz cementation, preserved porosities of up to 20%, and good permeabilities. Porosity-preserving chlorite cementation in Sawan is restricted to sediments of a shallow-marine environment. Anna Berger studied petrology at the University of Vienna in Austria and holds an M.Sc. degree in sedimentary petrology. She is currently employed at the Department of Mineralogy and Petrography at the Natural History Museum Vienna in Austria. Susanne Gier is an associate professor for sedimentary petrology at the Department of Geodynamics and Sedimentology, University of Vienna. She holds an M.Sc. degree and a Ph.D. in sedimentary petrology from the University of Vienna. She works on several collaboration projects with the industry. Her current research interests are sandstone and shale diagenesis as well as clay mineralogy. Peter Krois holds an M.Sc. degree and a Ph.D. in sedimentology from the University of Innsbruck in Austria. He joined OMV in 1990 and has held a variety of technical and managerial positions in Austria and abroad. From 1997 to 2001, he was the OMV's chief geologist in Pakistan.

Description: The use of digital outcrop models in combination with traditional sedimentological field data improves the accuracy and efficiency of qualitative and quantitative characterization of outcrop analogs for reservoir modeling purposes. In this article, we apply an innovative methodology of outcrop characterization to an Upper Triassic fluvial-dominated system, exposed in extensive outcrops with limited three-dimensional (3-D) exposure. Qualitative analysis of the study outcrop allows the subdivision of the formation into three architectural intervals. Each interval can be further subdivided into subintervals on the basis of architectural style. This subdivision provides information on reservoir compartmentalization, which is used for zonation of the geocellular model. Qualitative analysis also provides valuable information on reservoir facies distribution. A new technique termed “perpendicular projection plane” is presented as a tool for quantitative analysis of outcrops with reduced 3-D exposure. This technique improves the accuracy of apparent width measurements of geobodies exposed in outcrops, which are subparallel to paleoflow. The quantitative analysis provides a detailed data set of geobody dimensions to use as conditioning data for analog reservoir models. Statistical analysis of the dimensions provides empirical relationships to apply in subsurface analog systems to reduce uncertainty related to stochastic modeling approaches. Ivan Fabuel-Perez obtained his B.Sc. in geology (Universidad de Zaragoza) in 2003 and his M.Sc. in petroleum geosciences (University of Manchester) in 2004. He is about to finish his Ph.D. (University of Manchester) in 3-D reservoir modeling of outcrop analogs and is currently working for ExxonMobil Exploration Company in Leatherhead. His areas of research include sedimentology of continental deposits, digital outcrop modeling, and reservoir characterization. David Hodgetts is a lecturer in reservoir modeling and petroleum geology at the University of Manchester, where he leads the research in digital outcrop modeling and its application to reservoir characterization. He obtained his B.Sc. in geology (Durham) in 1991, his M.Sc. in computing in earth sciences (Keele) in 1992, and his Ph.D. in numerical modeling of continental lithospheric deformation (Keele) in 1995. Jonathan Redfern obtained his B.Sc. from Chelsea College, London, and his Ph.D. from Bristol University. He subsequently joined Fina, working in the North Sea as an exploration geologist, and then internationally in Singapore, Vietnam, and Libya. He later moved to Amerada Hess in International New Ventures as the chief geologist in their Indonesia Office. He is the director of the Petroleum Geoscience M.Sc. Program at the University of Manchester and leads the North Africa Research Group, which focuses on regional studies across the region, funded by a group of leading oil companies. His main research areas are basin studies, petroleum systems, and sedimentology (fluvial, glaciogenic, and deep water).

Description: The Ozona sandstone is a record of Permian synorogenic sedimentation in a foreland basin. The Ozona comprises terrigenous clastic slope and basin systems overlain by mixed clastic-carbonate shelf-ramp systems. Ozona sandstones form low-permeability gas reservoirs in Crockett County, Texas. I used wire-line logs and cores to map Ozona genetic stratigraphy and to reconstruct the depositional and tectonic history during the final phase of the Ouachita orogeny. Ozona depositional systems are composed of sandy turbidite channel and lobe genetic facies enclosed in laterally extensive muddy turbidite sheets and hemipelagic drapes. Channel and lobe complexes and turbidite sheets together form basin-floor apron systems. Coeval slope systems are mud-dominated products of mass transport processes. Sediment dispersal systems evolved from point sourced to line sourced. Ozona sequence development was primarily controlled by tectonic uplift and subsidence. Stratal geometries, facies associations, sediment input patterns, and depocenter locations are stable within sequences, but they change across sequence boundaries in response to tectonically driven changes in basin geomorphology. Onlapping stratal geometries in the lower sequence record excess accommodation space in the study area as plate convergence progressed from south to north. Offlapping strata in the middle and upper sequences formed in response to reduced accommodation space and intraforeland uplift in the north. At the base of each sequence, sandstone depocenters step toward the thrust belt in response to thrust-sheet loading and foredeep subsidence, but within each sequence, depocenters migrate away from the thrust belt. Foredeep migration through time provides a predictive tool for locating Ozona reservoir analogs farther south in Val Verde Basin. H. Scott Hamlin is a research scientist associate at the Bureau of Economic Geology. He received his B.A. and M.A. degrees and his Ph.D. from the University of Texas at Austin. His research interests include depositional systems, stratigraphy, reservoir characterization, and hydrogeology. His current research focuses on Wolfcampian and Leonardian slope and basin reservoirs in the Midland Basin of west Texas.

Description: The Moab fault, a basin-scale normal fault that juxtaposes Jurassic eolian sandstone units against Upper Jurassic and Cretaceous shale and sandstone, is locally associated with extensive calcite and lesser quartz cement. We mapped the distribution of fault-related diagenetic alteration products relative to the fault structure to identify sealing and conductive fault segments for fluid flow and to relate fault–fluid-flow behavior to the internal architecture of the fault zone. Calcite cement occurs as vein and breccia cement along slip surfaces and as discontinuous vein cement and concretions in fault damage zones. The cement predominates along fault segments that are composed of joints, sheared joints, and breccias that overprint earlier deformation bands. Using the distribution of fault-related calcite cement as an indicator of paleofluid migration, we infer that fault-parallel fluid flow was focused along fault segments that were overprinted by joints and sheared joints. Joint density, and thus fault-parallel permeability, is highest at locations of structural complexity such as fault intersections, extensional steps, and fault-segment terminations. The association of calcite with remnant hydrocarbons suggests that calcite precipitation was mediated by the degradation and microbial oxidation of hydrocarbons. We propose that the discontinuous occurrence of microbially mediated calcite cement may impede, but not completely seal, fault-parallel fluid flow. Fault-perpendicular flow, however, is mostly impeded by the juxtaposition of the sandstone units against shale and by shale entrainment. The Moab fault thus exemplifies the complex interaction of fault architecture and diagenetic sealing processes in controlling the hydraulic properties of faults in clastic sequences. Peter Eichhubl received his M.S. degree from the University of Vienna, Austria, and his Ph.D. from the University of California, Santa Barbara. After research positions at Stanford University and the Monterey Bay Aquarium Research Institute, he joined the Bureau of Economic Geology at the University of Texas in Austin in 2006. His research interests include the interaction of brittle deformation and diagenesis, and fault and fracture mechanics. Nicholas C. Davatzes has a Ph.D. in geology from Stanford University. He conducted postdoctoral research at Stanford and as a Mendenhall Fellow at the U.S. Geological Survey. His research explores the interaction of faulting, stress, and fluid flow. He is currently an assistant professor at Temple University and a visiting professor at the School for Renewable Energy Science. Stephen P. Becker received his B.S. and M.S. degrees in geology from the University of Missouri-Rolla (now Missouri University of Science and Technology) in 2001 and 2005 and his Ph.D. in geochemistry from Virginia Tech in 2007. He currently holds a postdoctoral position at the Bureau of Economic Geology at the University of Texas at Austin, working on the application of fluid inclusions to understanding fracturing and fluid-flow histories.

Description: Wavelengths of hummocky cross-stratified (HCS) beds (a common sedimentary feature of storm-dominated shorefaces) are documented for the first time using measurements in three-dimensional (3-D) ground-penetrating radar (GPR) data for a well-developed Upper Cretaceous lower-shoreface succession at Dry Wash in the Ferron Sandstone Member, Utah. The shallow-marine sequence consists of upward-thickening HCS sand beds alternating with interstorm deposits. The thickness variation of the storm beds indicates locally steadily growing storm intensity with at least four cycles. Weakly coarsening-upward (mud to very fine-grained sand) fair-weather background deposits suggest a slow progradation of deposition with no significant change in environment. The GPR interpretation mapped three conformable, high-continuity, high-amplitude reflections throughout the 3-D GPR data volume. The interpreted radar surfaces (RSs) are well correlated with tops of HCS sand beds (and thus paleotopographic surfaces); the associated radar units (RUs) have a uniform thickness (on average ∼0.8 m [∼2.6 ft]). The RUs and the adjacent outcrop observations suggest that the shoreface sandstone at the Dry Wash site has a simple layered internal architecture. The hummocky-swaley surfaces generally dip westerly, as a product of postdepositional structural alterations that are mostly in the shoreline direction, and contain variable-size, structurally undulating rounded features. A 2-D continuous wavelet transform analysis is applied to the detrended RSs, producing a multiresolution image decomposition of the GPR surfaces. Surface features with a wavelength range of 1–7 m (3–23 ft) are in good agreement with the observations on modern hummocky shallow-marine seabeds. Quantitative measurements indicate that the hummocky surfaces at the Dry Wash site are dominated by uniformly distributed circular to elongate bed forms with maximum correlation at 1.5–3.5-m (4.9–11.4 ft) wavelength and that the deltaic sedimentary layers were simultaneously deformed by the middle Campanian compressional stress of the Sevier orogeny transmitted from the northwest. Quantitative information on the subseismic-scale surface geometry of the HCS beds is expected to result in more refined reservoir models. In addition, the connectivity of units indicated by the scale of the morphology can be an indirect indicator of unit correlation and permeability paths. 2nd revised manuscript received August 31, 2008 Keumsuk Lee received his B.Sc. degree in mathematics (1994) and his M.Sc. degree in geological oceanography (1999) from Kunsan National University, Kunsan, Korea, and his Ph.D. in geophysics from the University of Texas at Dallas in 2005. He worked for the Bureau of Economic Geology at the University of Texas at Austin before joining the Korea National Oil Corporation, Anyang, Korea, as a senior geoscientist. His main research interests are basin analysis based on seismic sequence stratigraphy, reservoir characterization using 2-D/3-D ground-penetrating radar data, and multiresolution wavelet analysis. Robert Szerbiak received his B.Sc. degree (1971) in geoscience from Michigan State University, M.Sc. degree (1981) in geophysics from Texas A&M University, and Ph.D. (2002) in geoscience from the University of Texas at Dallas. He has worked as a geophysicist with Petty-Ray Geophysical Company, Phillips Petroleum Company, British Petroleum Exploration, and recently as a research associate at Boise State University. His specialization includes stochastic modeling, reservoir characterization, petrophysical parameter simulation, and ground-penetrating radar and seismic modeling and imaging. His outside interests include near-surface geophysical scaling studies, wavelet decomposition methods, and fluid flow and transport. George McMechan received his B.Sc. in geological engineering from the University of British Columbia in 1970 and his M.Sc. in geophysics from the University of Toronto in 1971. He is the Ida Green Professor of Geosciences at the University of Texas at Dallas. He has published approximately 230 technical articles, and in 1997, he received the Virgil Kauffman gold medal from the SEG. His main research interests are wavefield imaging, reservoir characterization, and ground-penetrating radar. He is a member of Society of Exploration Geophysicists (SEG), American Geophysical Union (AGU), Seismological Society of America (SSA), Environmental and Engineering Geophysical Society (EEGS), and Association of Professional Engineers and Geoscientists of British Columbia (APEGBC). Namsoon Hwang obtained her B.Sc. (1994) and M.Sc. (1998) degrees in oceanography from Kunsan National University, Kunsan, Korea. Her main research interest is the application of heavy mineral analysis and sequence stratigraphy to various geological and environmental problems.

Description: The Lower Cretaceous Mannville Group oil sands of northern Alberta have an estimated 270.3 billion m3 (BCM) (1700 billion bbl) of in-place heavy oil and tar. Our study area includes oil sand accumulations and downdip areas that partially extend into the deformation zone in western Alberta. The oil sands are composed of highly biodegraded oil and tar, collectively referred to as bitumen, whose source remains controversial. This is addressed in our study with a four-dimensional (4-D) petroleum system model. The modeled primary trap for generated and migrated oil is subtle structures. A probable seal for the oil sands was a gradual updip removal of the lighter hydrocarbon fractions as migrated oil was progressively biodegraded. This is hypothetical because the modeling software did not include seals resulting from the biodegradation of oil. Although the 4-D model shows that source rocks ranging from the Devonian–Mississippian Exshaw Formation to the Lower Cretaceous Mannville Group coals and Ostracode-zone-contributed oil to Mannville Group reservoirs, source rocks in the Jurassic Fernie Group (Gordondale Member and Poker Chip A shale) were the initial and major contributors. Kinetics associated with the type IIS kerogen in Fernie Group source rocks resulted in the early generation and expulsion of oil, as early as 85 Ma and prior to the generation from the type II kerogen of deeper and older source rocks. The modeled 50% peak transformation to oil was reached about 75 Ma for the Gordondale Member and Poker Chip A shale near the west margin of the study area, and prior to onset about 65 Ma from other source rocks. This early petroleum generation from the Fernie Group source rocks resulted in large volumes of generated oil, and prior to the Laramide uplift and onset of erosion (∼58 Ma), which curtailed oil generation from all source rocks. Oil generation from all source rocks ended by 40 Ma. Although the modeled study area did not include possible western contributions of generated oil to the oil sands, the amount generated by the Jurassic source rocks within the study area was 475 BCM (2990 billion bbl). Debra Higley has 5 years experience in uranium exploration and 26 years as a research geologist with the U.S. Geological Survey. Her research interests include reservoir characterization, petroleum system modeling, and petroleum resource assessment in basins in North and South America. She received her M.S. degree in geochemistry and Ph.D. in geology from the Colorado School of Mines, and her B.S. degree in geology from Mesa State College, Colorado. Mike Lewan is an organic geochemist and petroleum geologist for the Central Energy Resources Team of the U. S. Geological Survey (Denver, Colorado). Prior to his 17 years with the U.S. Geological Survey, he worked for 13 years at the Amoco Production Co. Research Center (Tulsa, Oklahoma) and 3 years with Shell Oil Co. Offshore E&P Office (New Orleans, Louisiana). He received his Ph.D. from the University of Cincinnati, M.S. degree from Michigan Technology University, and B.S. degree from Northern Illinois University. Laura Roberts graduated with a degree in geology from Colorado College. She is a recently retired emeritus scientist who had worked for the U.S. Geological Survey since 1977. Her research includes coal geology and coal resource assessment of the Fort Union Formation in the northern Powder River Basin, Montana, and the Cretaceous coals of the Colorado Plateau, and the burial and thermal history of petroleum source rocks in the Uinta-Piceance and Wind River basins. Mitchell Henry retired from the U.S. Geological Survey after 30 years of research in direct geochemical detection and remote sensing of hydrocarbons, and domestic and international petroleum resource assessments. He received his B.S. degree from Midwestern University and his M.S. degree and a Ph.D. from Texas A&M University.

Description: Interpreting seismic data requires inferences to be made from the geometry, character, and spatial association of seismic reflections. Seismic attributes that highlight such associations are essential for understanding basin-fill histories. In this article, we describe two novel attributes obtained from an automatic full-volume-flattening algorithm and apply them to a synthetic seismic volume of experimental strata. The stratal convergence attribute colors reflections according to their degree of convergence, which is commonly high in areas where strata thin because of erosion or nondeposition. The instantaneous isochron attribute measures thickness between reflections and is therefore generally proportional to sediment accumulation rate. These attributes distinguish bounding surfaces and depocenter migration in well-constrained experimental strata. By showing the diagnostic value of each attribute, our study motivates field-based applications of full-volume flattening and attribute co-rendering for seismic stratigraphic interpretation. Jesse Lomask graduated in 1993 with a B.S. degree in geology from Temple University in Philadelphia. In 2006, he earned a Ph.D. in geophysics from Stanford University. He worked as a field engineer for Schlumberger in the Gulf of Mexico for two years. He also worked as a 3-D seismic interpreter for Occidental Oil and Gas at Elk Hills, California. In 2007, he joined Chevron Energy Technology Company in San Ramon as a research geophysicist. Jason Francis is a stratigrapher at Chevron Energy Technology Company. He received his B.A. degree from Colgate University, his M.S. degree from Texas A&M University, and his Ph.D. from Rice University. His research interests include mixed siliciclastic carbonate systems, deep-water stratigraphy, and basin analysis. James Rickett completed his early studies in the United Kingdom, earning a B.A. degree in natural sciences from Cambridge University in 1994 and an M.S. degree in exploration geophysics from Leeds University in 1995. At that point, he moved to the United States and in 2001 earned a Ph.D. in geophysics from Stanford University. Since 2001, he has worked for Chevron Energy Technology Company in San Ramon, California, on both geophysical research and development and exploration and new ventures. He is currently the team leader for the seismic imaging Research and Development Team, where his interests are focused on quantitative imaging of earth properties in geologically complex areas. Marc Buursink is an earth scientist at Chevron Energy Technology Company where he works on basin analysis problems and deep-water Gulf of Mexico exploration. Previously at the U.S. Geological Survey, he applied geophysical methods to natural resources investigations. He earned a B.A. degree in physics and environmental science from the University of Virginia, an M.S. degree in geosciences from the University of Connecticut, and a Ph.D. in geophysics from Boise State University. Thomas Gerber received his B.S. degree in geology from the University of Montana in 2002 and his Ph.D. from Duke University in 2007. His main research interests are in surface processes, stratigraphy, and subsurface imaging. He joined Chevron Energy Technology Company in 2008. Martin Perlmutter received his Ph.D. in marine geology from the Rosenstiel School of Marine Sciences of the University of Miami in 1982. He joined Texaco in 1981, Argonne National Laboratory in 1994, and rejoined Texaco (now Chevron) in 1997. His career has focused on basin analysis and applying new methods for predicting reservoir trends. He is presently the team leader of the Reservoir Prediction Team for Chevron. Chris Paola is a professor in the Department of Geology and Geophysics of the University of Minnesota, Minneapolis, and does research at St. Anthony Falls Laboratory. His research interests are in physical sedimentary geology and stratigraphy, especially the dynamics of channelized systems. He received his B.S. degree in environmental geology from Lehigh University, his M.S. degree in applied sedimentology from the University of Reading, and his D.S. degree in marine geology from Massachusetts Institute of Technology/Woods Hole Oceanographic Institution Joint Program in Oceanography.

Description: This article documents the application of techniques in quantitative seismic geomorphology in quantifying the morphometrics and architecture of deep-marine leveed-channel systems within an about 10,000-km2 (3861-mi2) study area offshore eastern Trinidad, West Indies. The principal goal of this study is to assess the relationship, if any, between sea-floor morphology and channel and levee architecture and morphology toward the development of predictive models of reservoir distribution and channel-system morphology that might be applicable to the interpretation of these types of deposits in similar settings around the world. Seven channel systems, classed into three types, within a 200-ms interval of data immediately below the modern sea floor provided the data for analysis. Results suggest that local structural features and sea-floor slopes exert more influence on channel morphology and occurrence than do eustatic sea level factors. Sinuosities, channel widths, meander-belt widths (MBWs), and meander-arc height (MAH) all increase as the channel systems age. Slope and sinuosity are directly related to one another, with sinuosity increasing as slope increases. Levee heights and widths increase downslope in areas of lower slope gradients. Channel sinuosity, MAH, and MBW increase immediately downslope from localized diapirs, and channels appear to migrate updip over time because of regional inflation of distal arc prism areas. Diapirs and uplifts cause overbank splays to become more confined and cause levees to shorten and taper rapidly. Regional tilt to the south appears to affect accommodation, creating a sink for sediments near the toe of slope. Regional tilt also affects flow processes in the channels, causing an increased overbanking of flows toward the south, away from the plate margin, resulting in higher, wider levees on the south sides of the channels. Lesli Wood is a senior research scientist at the Bureau of Economic Geology in the University of Texas (UT), Jackson School of Geosciences. She received her M.S. degree in geology from the University of Arkansas (1988) and her Ph.D. in earth resources from Colorado State University (1992). Upon graduation, she worked for Amoco for 5 years and 13 days and moved to Austin in 1997. She currently runs the Quantitative Clastics Laboratory Industrial Associates program at UT. Her research interests include quantitative seismic geomorphology, martian and Earth deltas, shale diapirs, and clastic margin studies. Kristine Mize-Spansky received her B.S. degree in geology from the University of Illinois at Urbana-Champaign (UIUC) in 2000. During her time at UIUC, she worked as an intern at the Illinois State Geological Survey. She received her M.S. degree in hydrogeology from Clemson University in 2002, then completed her M.S. degree in geology from the University of Texas at Austin in 2004. She has been a geologist with EnCana Oil & Gas (U.S.A.) Inc. in Denver, Colorado, since 2005.

Description: An integrated analysis of the borehole images and open-hole logs in the Red Oak gas field has revealed the detailed sedimentary characteristics of the middle Atokan (Lower Pennsylvanian) Red Oak and Fanshawe turbidites and mass transport in the Arkoma Basin. The older Red Oak sandstone member is a multistory channel complex characterized by abundant sandy scour-and-fills with inclined bedding, mudstone-clast-rich channel fills, intrachannel mudstone drapes, and localized debrites. The younger Fanshawe turbidite system deposited a large thickness of thin-bedded sandstones and mudstones in and near a southward-trending canyon and distributary system right above the Red Oak sand depocenter. The consistent south-vergent syndepositional slump movements and associated rollover beds suggest deposition on a south-dipping paleoslope. Based on the interpretation of sedimentary textures and lithology from the multiwell borehole images and open-hole logs, 10 rock facies are classified to analyze the channel and nonchannel elements. Bedding and scour surfaces on the borehole images are classified to analyze the structural and depositional processes. Although the inclined sand bedding over scour surfaces appears similar to trough cross-bedding structures, the widely dispersed azimuth of the inclined bedding sets in the Red Oak channel sandstones suggests an irregular scour-and-fill process with unclear relation to paleocurrent directions. Linked debrites at different stages of flow transformation provide valuable insights of the depositional mechanism. Various types of syndepositional deformation structures at different scales are interpreted to help understand the structural and depositional environments. The multiwell characterization of the image facies and the vertical sequences allowed the well-to-well correlation and mapping of the Red Oak and Fanshawe turbidite systems across the field. Chunming Xu received a B.S. degree in geophysics in 1982 from the Jianhan Petroleum College, China. He worked with PetroChina for 10 years as a geophysicist on prospect evaluation and thrust tectonics in northwestern China and the Canadian Rockies and Canadian Foothills. He joined Schlumberger in 1992 as a geologist focused on stratigraphic interpretation and reservoir characterization using borehole images and open-hole logs in various sedimentary environments. Since he joined Shell in early 2006, he has been working on image log interpretation guidelines in coastal and deep-water clastic reservoirs for integrated reservoir modeling. Thomas Cronin is a senior geologist with BP in Houston and holds a B.A. degree (1980) and an M.S. degree (1983) in geology from the University of Tennessee. He has more than 25 years of experience in the petroleum industry with Gulf Oil, Amoco Production Co., Burlington Resources, and BP. In addition to his current assignment in field development in the Arkoma Basin, he has worked on development and exploration assignments in the U.S. Gulf of Mexico, Indonesia, Vietnam, Thailand, Bangladesh, China, and Trinidad. Thalbert E. (Thal) McGinness has 40 years of experience in the oil and gas industry. A senior petrophysical associate with BP, he joined Schlumberger in 1969 and Amoco Production Co. in 1979. He holds a B.S. degree from East Central State University and an M.S. degree in natural science from Eastern New Mexico State University. He retired from BP in 2008. Brad Steer holds degrees in geology from San Diego State University (M.S. degree, 1979), University of Utah (B.S. degree, 1976), and University of Northern Colorado (B.A. degree, 1974). He has been with BP (formerly Amoco) since 1980. He has worked in numerous basins, including the Suez rift, Egypt, the Columbus Basin, Trinidad, and the Arkoma Basin, Oklahoma. He is currently working with TNK-BP in Moscow, Russia.

Description: The present-day state of stress in Tertiary deltas is poorly understood but vital for a range of applications such as wellbore stability and fracture stimulation. The Tertiary Baram Delta province, Brunei, exhibits a range of contemporary stress values that reflect the competing influence of the northwest Borneo active margin (situated underneath the basin) and local stresses generated within the delta. Vertical stress (σv) gradients at 1500-m (4921-ft) depth range from 18.3 MPa/km (0.81 psi/ft) at the shelf edge to 24.3 MPa/km (1.07 psi/ft) in the hinterland, indicating a range in the shallow bulk density across the delta of 2.07–2.48 g/cm3. The maximum horizontal stress (σHmax) orientation rotates from margin parallel (northeast–southwest; deltaic) in the outer shelf to margin normal (northwest–southeast; basement associated) in the inner shelf. Minimum horizontal stress (σhmin) gradients in normally pressured sequences range from 13.8 to 17.0 MPa/km (0.61–0.75 psi/ft) with higher gradients observed in older parts of the basin. The variation in contemporary stress across the basin reveals a delta system that is inverting and self-cannibalizing as the delta system rapidly progrades across the margin. The present-day stress in the delta system has implications for a range of exploration and production issues affecting Brunei. Underbalanced wells are more stable if deviated toward the σhmin direction, whereas fracture stimulation in mature fields and tight reservoirs can be more easily conducted in wells deviated toward σHmax. Finally, faults near the shelf edge are optimally oriented for reactivation, and hence exploration targets in this region are at a high risk of fault seal breach. Mark Tingay is currently an Australian postdoctoral fellow at Curtin University, where he works on stress, overpressure, and tectonic evolution of Southeast Asia. He received his Ph.D. in 2003 from the Australian School of Petroleum. He then became the petroleum geomechanics researcher at the World Stress Map Project where he worked on projects in 11 countries, including the United States, Egypt, Azerbaijan, and Thailand. Richard Hillis is the head of the Australian School of Petroleum and State of South Australia professor of petroleum geology at the University of Adelaide. He received a B.S. degree (hons) from Imperial College and a Ph.D. from the University of Edinburgh. He is a director of image log and a geomechanics consultant of JRS Petroleum Research and of the geothermal exploration company Petratherm. Chris Morley received his Ph.D. in 1983 before working for Amoco and Elf Aquitaine and as a professor at the University of Brunei Darussalam. He is currently working for PTT Exploration and Production as a senior geophysicist. He has worked as an exploration geologist and as a structural geologist in east Africa, Morocco, the Norwegian Caledonides, the Carpathians, northwest Borneo, and Thailand. Rosalind King is a postdoctoral researcher at the Australian School of Petroleum where she studies the present-day stress and neotectonics of northwest Borneo as well as delta and deep-water fold and thrust belt systems worldwide. She completed her Ph.D. on the structural evolution of the Cape fold belt and southwest Karoo Basin, South Africa. Richard Swarbrick commenced his career in 1979 when he joined Mobil with assignments in the United Kingdom and the United States. He joined Durham University in 1989 and was a principal investigator for a multidisciplinary research group funded by 17 oil and gas companies. Over that period, he developed training courses in subsurface pressures and founded the company GeoPressure Technology. He is an honorary professor at Durham University and has been an AAPG member since 1982. Abdul Razak Damit is currently the chief geologist for the National Oil Company of Brunei (PetroleumBRUNEI). He obtained his Ph.D. at Aberdeen University and has 20 years of industry experience, primarily at Shell where he worked on both reservoir and regional evaluation. His main interests are in the geology of northwest Borneo and in raising public awareness of the natural and social history of Brunei.

Description: The Mobile Bay gas field is located offshore Alabama in the northern Gulf of Mexico. Production is from eolian dunes of the Jurassic Norphlet sandstone at depths exceeding 6100 m (gt20,000 ft) and temperatures greater than 200degC. Reservoir connectivity and compositional variation, including the distribution of nonhydrocarbon gases (H2S and CO2), are critical factors in production strategy. To evaluate the controls on compositional variation and connectivity, detailed molecular and isotopic analyses were conducted for 29 wells. Analysis of volatiles in fluid inclusions suggests that the field was originally filled with oil that subsequently cracked to gas. In addition to the thermal destruction (cracking) of oil, the process of thermochemical sulfate reduction (TSR) continues to destroy the remaining hydrocarbons through oxidation of gas and reduction of sulfate to form H2S and CO2. The variable extent of the TSR process at Mobile Bay results in a wide range of hydrocarbon and H2S compositions. Condensates are almost exclusively composed of diamondoids whose composition appears controlled by H2S concentrations. In contrast to hydrocarbon and H2S contents, CO2 concentrations are relatively constant throughout the field. Carbon isotopic ratios for CO2 correlate positively with those for wet-gas hydrocarbons but are heavier than expected for CO2 originating from hydrocarbon oxidation via TSR. The narrow range of CO2 contents and heavy isotope ratios suggests that CO2 is regulated by water-rock equilibration and carbonate precipitation. The destruction of the hydrocarbon gas and mineralization of the carbon dioxide product create a volume reduction and an associated drop in reservoir pressure. This process creates several internal sinks (or exits) that may control the spill direction for gas in the field.

Description: A series of complex experimental histories have been performed on two specimens of Nordland Shale from the cap rock of the Sleipner CO2 injection site in the North Sea. By simultaneously applying a confining back pressure, specimens were isotropically consolidated and fully water saturated under realistic conditions of effective stress. Ingoing and outgoing fluxes were monitored at all times. Multistep consolidation and hydraulic tests were performed prior to gas injection to determine baseline hydraulic properties. Both specimens were found to be relatively compressible with a general trend of reducing compressibility with increasing effective stress. Hydraulic permeability, anisotropy ratio, and specific storage were quantified by inverse modeling using an axisymmetric two-dimensional finite element model. Estimates for elastic deformation parameters were derived from the analysis of consolidation transients. Both specimens yielded comparable intrinsic permeabilities of around 4 times 10minus19 m2 (43 times 10minus19 ft2) perpendicular to bedding and 10minus18 m2 parallel to it. Specific storage was found to vary with effective stress within the range of 2–6 times 10minus5 mminus1 (0.6–1.8 times 10minus5 ftminus1). Gas transport properties were determined by multistep constant pressure test stages, using nitrogen as the permeant. Analysis of the flux data indicates gas entry and breakthrough pressures under initially water-saturated conditions of 3.0 and 3.1 MPa, respectively. Using a stepped pressure history, flow rate through the specimen was varied to examine the underlying flow law and the possible effects of desaturation. With the injection pump stopped, gas pressure declined with time to a finite value, providing a measure of the apparent threshold capillary pressure, which ranged from 1.6 to 1.9 MPa. Numerical modeling of the gas data, using the TOUGH2 code, suggests that anisotropy to gas flow is greater than hydraulic flow. Fits to the pressure data were obtained, but matching the magnitude of the flux through the sample was not possible. Based on the data and subsequent model activities, standard concepts of viscocapillary (two-phase) flow are clearly inadequate to accurately describe the processes and mechanisms governing gas flow in the Nordland Shale. Evidence suggests that gas movement occurs through pressure-induced pathway flow, accompanied by a limited degree of viscocapillary displacement. The laboratory experiments support the time-lapse seismic observations that the cap rock is performing as an effective capillary seal. The experimental results also indicate that if gas flow is induced in this type of material, it is mainly via discrete pathways, instead of distributed Darcy flow. This is consistent with observed CO2 flow patterns within the reservoir, although a satisfactory explanation for how such pathways develop remains elusive.

Description: This chapter reviews the extensive geophysical studies and Ocean Drilling Program (ODP) results that provide constraints on the occurrence, distribution, and concentration of deep-sea gas hydrate beneath the northern Cascadia margin offshore Vancouver Island. Most of this information comes from a wide range of seismic surveys and includes the mapping of the bottom-simulating reflector (BSR), as well as estimating gas-hydrate and free-gas concentrations. Recent additional constraints on the distribution and concentration of gas hydrate come from sea-floor-towed, controlled-source electromagnetic surveying and sea-floor compliance studies. These surveys and studies have been primarily deployed around a cold vent field, where seismic data show several broad blank zones, interpreted as fault-related conduits for focused fluid-gas migration, and where gas hydrate has been recovered in piston cores at the sea floor. Results from the ODP Leg 146 and the recently completed Integrated Ocean Drilling Program (IODP) Expedition 311 further constrain concentration estimates for gas hydrate and free gas in the sediments along the margin and also give insight into the complex formation mechanisms and controlling factors for gas hydrate occurrence in an accretionary complex. This summary was first presented in September 2004 at the AAPG Hedberg Research Conference on gas hydrates. Subsequently, 1 yr later, the drilling of IODP Expedition 311 resulted in a significant amount of new information and insight into the occurrence and formation processes of gas hydrate at the northern Cascadia margin. This chapter provides only a short summary of the results from that IODP Expedition. Reviews of the results from that drill coring and the downhole measurements are in progress.