ALBERT

Description: Mature and aging clastic-dominated hydrocarbon fields commonly become increasingly difficult to produce, causing lower economic return than initially forecast. A major cause of this reduced economic viability is compartmentalization, defined as limitation on the ability to produce hydrocarbons resulting from permeability barriers within a field. Three primary causes of compartmentalization are structural variations in permeability, stratigraphic variations in permeability, and permeability reduction resulting from compaction adjacent to producing wellbores. Recognition and delineation of compartmentalization permit formulation of development and depletion plans to maximize recovery and economic value. Here, we examine one of 52 reservoir-scale faults that compartmentalize the eastern shallow oil zone (ESOZ), Elk Hills field, California. Using well-log, stratigraphic, structural, and pressure data, we apply standard fault seal analyses to the selected fault. Results are compared with known pressure conditions across the fault and show the fault capable of supporting pressure differentials two to three times those expected from standard static fault seal measures. Although this observation could be used as a basis for local calibration of standard fault seal measures for a dynamic seal, such an approach assumes that these fault seal mechanisms are in fact the cause of sealing behavior. Alternatively, one of the most significant changes in ESOZ reservoir conditions over the production lifetime of the field is the reduction of fluid pressure from approximately 1500 to approximately 200 psi (from ∼10.27 to ∼1.37 MPa). Decreasing fluid pressure would have driven stress states acting on faults in the reservoir from critical (near or at slip) to stable (nonslipping) conditions. Critically stressed faults and fractures are more transmissive than those that are noncritically stressed. We propose that decreasing fluid pressure can cause faults to become less leaky, causing production-induced reservoir compartmentalization.

Description: The Hidden Valley fault is exposed in Canyon Lake Gorge (central Texas) and cuts the Cretaceous Glen Rose Formation. This exposure provides an opportunity to explore the relationship between deformation mechanisms and fault displacement along 830 m (2723 ft) of a normal fault typical of those in carbonate reservoirs and aquifers around the world. The fault zone has five domains: gently deformed footwall damage zone, intensely deformed footwall damage zone, fault core, intensely deformed hanging-wall damage zone, and gently deformed hanging-wall damage zone. Footwall deformation is more intense and laterally extensive than hanging-wall deformation, and the intensely deformed hanging-wall damage zone is narrow and locally absent. The fault core contains thin clay-rich gouge or smear in most places but is locally represented by only a slickensided surface between limestone layers. The 55- to 63-m (180-207-ft) fault throw across a 43- to 98-m (141- to 322-ft)-wide fault zone is accommodated by slip along the fault core, layer tilting (synthetic dip development) in footwall and hanging-wall damage zones, and distributed faulting in footwall and hanging-wall damage zones. Total offset across the fault overestimates actual stratigraphic offset by 8 to 12 m (26-39 ft) or about 14 to 21%. In our interpretation, the Hidden Valley fault zone records both early extensional folding of the Glen Rose Formation and subsequent normal faulting that propagated downward from the overlying competent Edwards Group. The damage zone width is thus established before fault breakthrough.

Description: Eastern California and southwestern Nevada represent an area of Tertiary and Quaternary extensional and dextral transtensional deformation. We used zircon and apatite fission-track thermochronology to study the distribution and timing of tectonic exhumation resulting from extensional and transtensional detachment faulting in this area. Sampling efforts were focused on Paleozoic and Precambrian clastic sedimentary and metasedimentary rocks. Sixty-nine new apatite and zircon fission-track cooling ages from 50 samples, analyzed in conjunction with published fission-track data from the region, indicate a distinct population of young (Miocene) fission-track ages and a population of irregularly distributed older (pre-Miocene) fission-track ages. Miocene (young population) fission-track ages become younger toward the west—indicating westward migration of the cooling front, consistent with well-documented Miocene extension of the Basin and Range Province. The younging pattern is also consistent with west-northwest displacement of the hanging wall of a crustal-scale extensional fault system and consequent progressive footwall exhumation. The active trailing edge of the hanging wall of this system generally coincides with Death Valley. Migration rates of the cooling front in the footwall of this system are on the order of 10–11 mm/yr. Based on the distribution of the Miocene fission-track ages, we interpret that the crustal faults that defined the eastern edge of the detachment system originated as separate normal faults that were linked by the formation of a transfer fault. Extrapolation of apatite fission-track closure ages from two transects across the eastern margin of the Death Valley region suggests that exhumation along the eastern margin of the system continues beneath Death Valley today.

Description: Failure behaviors can strongly influence deformation-related changes in volume, which are critical in the formation of fault and fracture porosity and conduit development in low-permeability rocks. This paper explores the failure modes and deformation behavior of faults within the mechanically layered Eagle Ford Formation, an ultra-low permeability self-sourced oil and gas reservoir and aquitard exposed in natural outcrop in southwest Texas, USA. Particular emphasis is placed on analysis of the relationship between slip versus opening along fault segments and the associated variation in dilation tendency versus slip tendency. Results show that the failure mode and deformation behavior (dilation versus slip) relate in predictable ways to the mechanical stratigraphy, stress field, and specifically the dilation tendency and slip tendency. We conclude that dilation tendency versus slip tendency patterns on faults and other fractures can be analyzed using detailed orientation or structural geometry data and stress information and employed predictively to interpret deformation modes and infer volume change and fluid conduit versus barrier behavior of structures.

Description: The increasing exploration and production in unconventional resource plays in the past decade has been accompanied by a greater need for understanding the effectiveness of multistage hydraulic fracturing programs, particularly in long (〉1500 m or 5000 ft) subhorizontal boreholes (laterals). Traditional (analytical) analysis techniques for estimating the size and orientation of fractures induced by fluid injection typically result in predictions of relatively long and planar extension (mode I) bi-wing fractures, which may not be representative of natural systems. Although these traditional approaches offer the advantage of rapid analysis, neglect of key features of the natural system (e.g., realistic mechanical stratigraphy, pre-existing natural faults and fractures, and heterogeneity of in situ stresses) may render results unrealistic for planning, executing, and interpreting multimillion-dollar hydraulic stimulation programs. Numerical geomechanical modeling provides a means of including key aspects of natural complexity in simulations of hydraulic fracturing. In this study, we present the results of two-dimensional finite element modeling of fluid-injection-induced rock deformation that combines a coupled stress–pore pressure analysis with a continuum damage-mechanics-based constitutive relationship. The models include both the natural mechanical stratigraphic variability as well as the in situ stress-state anisotropy, and permit tracking of the temporal and spatial development of shear and tensile permanent strains that develop in response to fluid injection. Our results show that simple, long planar fractures are unlikely to be induced in most mechanically layered natural systems under typical in situ stress conditions. Analyses that assume this type of fracture geometry may significantly overestimate the reach of hydraulically induced fractures and/or effectively stimulated rock volume.

Description: Outcrops of the middle Eagle Ford Formation in south-central Texas reveal well-developed joint networks in subhorizontal competent carbonate (chalk) beds and less well developed networks in interlayered incompetent calcareous mudrock beds. Northeast-striking bed-perpendicular joints in competent beds have the longest trace lengths and are abutted by northwest-striking joints. All observed joints terminate vertically in incompetent beds. Normal faults are common but less abundant than joints; dominantly dip north, northwest, or southeast; and are abutted by the joint sets and, thus, predated jointing. The faults cut multiple competent and incompetent beds, providing vertical connectivity across mechanical layering. Products of hybrid and shear failure, the dip of these faults is steep through competent beds and moderate through incompetent beds, resulting in refracted fault profiles with dilation and calcite precipitation along steep segments. Fluid inclusions in fault zone calcite commonly contain liquid hydrocarbons. Rare two-phase fluid inclusions homogenized between about (1) 40 and 58°C, and (2) 90 and 100°C, suggesting trapping of aqueous fluids at elevated temperatures and depths on the order of 2 km (6562 ft). Fluid inclusion and stable isotope geochemistry analyses suggest that faults transmitted externally derived fluids. These faults likely formed at depths equivalent to portions of the present-day oil and gas production from the Eagle Ford play in south Texas. Faults connect across layering and provide pathways for vertical fluid movement within the Eagle Ford Formation, in contrast to vertically restricted joints that produce bed-parallel fracture permeability. These observations elucidate natural fractures and induced hydraulic fracturing within the Eagle Ford Formation.

Description: Production from self-sourced reservoirs relies on natural and induced fracturing for permeability and conductance of hydrocarbons to the producing wellbores, thus natural or induced fracturing is often a key to success in unconventional reservoir plays. On the other hand, fractures may compromise seals and large or well-connected fractures or faults may cause undesirable complications for unconventional reservoirs. Natural and induced fractures are influenced by (1) mechanical stratigraphy, (2) pre-existing natural deformation such as faults, fractures, and folds, and (3) in situ stress conditions, both natural and as modified by stimulation and pressure depletion. This special issue of the AAPG Bulletin elucidates some of these structural geologic and geomechanical controls. Understanding the occurrence and controls on natural and induced faulting and fracturing in self-sourced reservoirs is a key component for developing effective approaches for exploiting self-sourced reservoirs.

Description: Faults are important components of hydrocarbon and other reservoirs; they can affect trapping of fluids, flow pathways, compartmentalization, production rates, and through these, production strategies and economic outcomes. Displacement gradients on faults are associated with off-fault deformation, which can be manifest as faulting, extension fracturing, or folding. In this work, displacement gradients—both in the slip direction and laterally—on a well-exposed large-displacement (seismic-scale) normal fault within the Balcones fault system of south-central Texas are correlated with anomalous deformation patterns adjacent to the fault. This anomalous deformation consists of two superimposed small-displacement fault systems, including (1) an earlier set that formed in response to a displacement gradient in the slip direction, and (2) a later set of oblique faults that formed in a perturbed stress-and-strain field in response to a lateral displacement gradient on the fault. Bed dip, fault-cutoff relationships, and small-displacement fault patterns in the adjacent rock volume inform strain and paleostress estimates. Results indicate that seismically resolvable displacement gradients on and bed dips adjacent to the seismic-scale fault provide a means by which the smaller (subseismic-scale and off-fault) deformation features can be predicted both in terms of orientation and intensity. Specifically, lateral displacement gradients on a normal fault with dip-slip displacement will generate fault-strike-parallel extension, causing anomalously oriented (in the far-field stress context) deformation features adjacent to the fault. Displacement gradient analysis can be used to help predict the characteristics of subseismic-scale deformation within a reservoir adjacent to a seismic-scale normal fault.

Description: Field structural data from the Big Brushy Canyon monocline developed in Cretaceous strata of west Texas are combined with nonlinear finite element modeling to help bridge the gap between geometric, kinematic, and mechanical analysis techniques for understanding the deformation history of reservoir-scale geologic structures. The massive Santa Elena Limestone is offset along a steep normal fault, and fault displacement is accommodated upward by the folding of the Buda Limestone and Boquillas Formation and the thinning in the intervening Del Rio Clay. Mesostructures within competent Buda Limestone beds are concentrated in the monocline limb instead of the hinge and include bed-perpendicular veins that accommodate bed-parallel extension and bedding-plane slip surfaces that offset the veins and accommodate flexural slip. Finite element models were constructed to reproduce the monocline geometry and deformation distribution as well as to assess the effect of material properties and boundary conditions on structural evolution. The initial model configuration replicated the assumed predeformational geometry, included frictional sliding surfaces to allow for bedding-parallel slip, and used a displacement boundary condition at the base of the Santa Elena footwall to simulate fault motion. Geometry and strain evolution were tracked so that (1) fold shape, (2) cumulative extension, and (3) layer-parallel shear strain could be compared to field observations. Iterative model runs successfully matched field data and revealed the importance of benchmarking the model results against monocline geometry, layer-parallel extensional strain, and bedding slip in the natural example. Our results illustrate the potential use of this modeling approach whereby calibration is performed using available data and is followed by strain measurement throughout the model domain to aid in prediction of subseismic faults and fractures. This geomechanical modeling approach provides a powerful tool for site-specific subsurface deformation prediction in hydrocarbon reservoirs that incorporates details of the local mechanical stratigraphy and structural setting. 2nd revised manuscript received July 29, 2009 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 six 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 structural geological training and contract consulting for the oil and gas industry. Alan Morris received his B.Sc. degree (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, Alan 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. Barron Bichon received his B.S. degree in civil engineering from the University of Memphis in 2002, his M.S. degree in civil engineering from the University of Illinois at Urbana-Champaign in 2003, and is currently working on his Ph.D. in civil engineering at Vanderbilt University. He joined Southwest Research Institute in 2007 where he serves as a research engineer applying and developing methods to quantify the reliability of engineered components and systems across a wide spectrum of industries. David Riha received his B.S. degree in aerospace engineering from the University of Texas at Austin in 1991, his M.S. degree in mechanical engineering from the University of Texas at San Antonio in 1998, and is currently working toward a Ph.D. in biomedical engineering at the University of Texas Health Science Center at San Antonio. He joined Southwest Research Institute in 1988 and is currently a principal engineer where he conducts probabilistic analyses and reliability assessments for commercial and government clients. Luc Huyse received his B.Sc. degree in civil engineering from Katholieke Universtiteit Leuven, Belgium, in 1991, and his M.Sc. degree (1996) and Ph.D. (1999) in civil engineering from the University of Calgary, Canada. After working at the NASA Langley Research Center (Hampton, Virginia) and Southwest Research Institute (San Antonio, Texas), he joined the Reliability and Integrity Unit at Chevron's Energy Technology Company (Houston, Texas) in 2008 where he develops new inspection data modeling techniques, optimal inspection, and repair strategies, and performs probabilistic integrity assessments for fixed equipment assets.

Description: Characterizing natural fracture systems involves understanding fracture types (faults, joints, and veins), patterns (orientations, sets, and spacing within sets), size distributions (penetration across layering, aperture, and trace length), and timing relationships. Traditionally, observation-based relationships to lithology, mechanical stratigraphy, bed thickness, structural position, failure mode, and stress history have been proposed for predicting fracture spacing along with the relative abundance of opening-mode fracture versus faults in fractured rocks. Developing a conceptual fracture model from these relationships can be a useful process to help predict deformation in a fractured reservoir or other fractured rock systems. A major pitfall when developing these models is using assumptions based on general relationships that are often site specific rather than universal. In this paper, we examine a mixed carbonate-shale sequence that is cut by a seismic-scale normal fault where fracture attributes do not follow commonly reported fracture relationships. Specifically, we find (1) no clear relationship between frequency (or spacing) of opening-mode fractures (joints and veins) and proximity to the main fault trace and (2) no detectable relationship between fracture spacing and bed thickness. However, we did find that (1) the frequency of small-displacement faults is strongly and positively correlated with proximity to the main fault trace, (2) fracture networks change pattern and failure mode (extension versus shear fracture) from pavement to pavement through the mechanically layered stratigraphic section, and (3) faults are more abundant than opening-mode fractures in many areas within the fracture network. We interpret that the major fracturing initiated near maximum burial under relatively high-differential stress conditions where shear failure dominated and that mode-1 extension fracturing occurred later under lower differential stress conditions, filling in between earlier formed shear fractures. We conclude that whenever possible, site-specific observations need to be carefully analyzed prior to developing fracture models and perhaps a different set of fracture network rules apply in rocks where shear failure dominates and mechanical stratigraphy influences deformation.