ALBERT

Description: We present a generic algorithm for automating sedimentary basin reconstruction. Automation is achieved through the coupling of a two-dimensional thermotectonostratigraphic forward model to an inverse scheme that updates the model parameters until the input stratigraphy is fitted to a desired accuracy. The forward model solves for lithospheric thinning, flexural isostasy, sediment deposition, and transient heat flow. The inverse model updates the crustal- and mantle-thinning factors and paleowater depth. Both models combined allow for automated forward modeling of the structural and thermal evolution of extensional sedimentary basins. The potential and robustness of this method is demonstrated through a reconstruction case study of the northern Viking Graben in the North Sea. This reconstruction fits present stratigraphy, borehole temperatures, vitrinite reflectance data, and paleowater depth. The predictive power of the model is illustrated through the successful identification of possible targets along the transect, where the principal source rocks are in the oil and gas windows. These locations coincide well with known oil and gas occurrences. The key benefits of the presented algorithm are as follows: (1) only standard input data are required, (2) crustal- and mantle-thinning factors and paleowater depth are automatically computed, and (3) sedimentary basin reconstruction is greatly facilitated and can thus be more easily integrated into basin analysis and exploration risk assessment.

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.

Description: Gas seepages along the Ionian coast of the northwestern Peloponnesus (Greece), at Killini, Katakolo, and Kaiafas reflect deep hydrocarbon-generation processes and represent a real hazard for humans and buildings. Methane microseepage, gas concentration in offshore and onshore vents, and gas dissolved in water springs, including the isotopic analysis of methane, have shown that the seeps are caused by thermogenic methane that had accumulated in Mesozoic limestone and had migrated upward through faults, or zones of weakness, induced by salt diapirism. A link between local seismicity and salt tectonics is suggested by the analyses of hypocenter distribution. Methane acts as a carrier gas for hydrogen sulfide produced by thermal sulfate reduction and/or thermal decomposition of sulfur compounds in kerogen or oil. Methane seeps in potentially explosive amounts, and hydrogen sulfide is over the levels necessary to induce toxicological diseases and lethal effects.

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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: 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: 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: 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: 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: 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: 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: 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: 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: 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: 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: 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: 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: 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 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: 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: 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: 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: 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: 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 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 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 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: 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.