ALBERT

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.