ALBERT

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: 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: Mapping of normal faults cutting the Bishop Tuff in the Volcanic Tableland, northern Owens Valley, California, using side-looking airborne radar data, low-altitude aerial photographs, airborne light detection and ranging (LiDAR) data, and standard field mapping yields insights into fault scarp development, fault system evolution, and timing. Fault zones are characterized by multiple linked fault segments, tilting of the welded ignimbrite surface, dilation of polygonal cooling joints, and toppling of joint-bounded blocks. Maximum fault zone width is governed by ( i ) lateral spacing of cooperating fault segments and ( ii ) widths of fault tip monoclines. Large-displacement faults interact over larger rock volumes than small-displacement faults and generate larger relay ramps, which, when breached, form the widest portions of fault zones. Locally intense faulting within a breached relay ramp results from a combination of distributed east-west extension, and within-ramp bending and stretching to accommodate displacement gradients on bounding faults. One prominent fluvial channel is offset by both east- and west-dipping normal faults such that the channel is no longer in an active flowing configuration, indicating that channel incision began before development of significant fault-related geomorphic features. The channel thalweg is "hanging" with respect to modern (Q1) and previous (Q2) Owens River terraces, is incised through the pre-Tahoe age terrace level (Q4, 131–463 ka), and is at grade with the Tahoe age (Q3, 53–119 ka) terrace. Differential incision across fault scarps implies that the channel remained active during some of the faulting history, but it was abandoned between Q2 and Q3 time, while faulting continues to the present day.

Description: Analyses of normal faults in mechanically layered strata reveal that material properties of rock layers strongly influence fault nucleation points, fault extent (trace length), failure mode (shear v. hybrid), fault geometry (e.g. refraction through mechanical layers), displacement gradient (and potential for fault tip folding), displacement partitioning (e.g. synthetic dip, synthetic faulting, fault core displacement), fault core and damage zone width, and fault zone deformation processes. These detailed investigations are progressively dispelling some common myths about normal faulting held by industry geologists, for example: (i) that faults tend to be linear in dip profile; (ii) that imbricate normal faults initiate due to sliding on low-angle detachments; (iii) that friction causes fault-related folds (so-called normal drag); (iv) that self-similar fault zone widening is a direct function of fault displacement; and (v) that faults are not dilational features and/or important sources of permeability.

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.