Abstract The Holstein Field consists of poorly lithified turbidite sands deposited during the Pliocene Epoch. Dense arrays of cataclastic deformation bands have been observed in all cores from wells that penetrate the K2 reservoir sand, the highest density of which are located near the hinge of a monocline. The predominant set of deformation bands strikes parallel to the fold axis, and dips at both high and low angles with respect to bedding. Deformation band orientation and offset of marker beds indicate reverse shear and are consistent with a flexural slip origin during folding. Restorations suggest that the monocline and associated deformation bands formed early during the burial process with high pore pressure. Reservoir permeability estimates from well tests indicate a bulk permeability approximately one-third of the reservoir core permeability in regions with deformation bands, whereas other areas are unaffected. Bulk permeability estimated from the permeability of the reservoir and deformation band network is lower than the reservoir permeability alone, but exceeds the permeability observed in the well tests by a factor of 2. A reduction in permeability of oil relative to water for both the fault and host sand is required to match the well-test permeability with that measured from core.

Abstract The distribution of fault rocks interpreted across a modelled fault in oil or gas reservoirs is most often described by its clay content derived from standard industry algorithms such as shale gouge ratio and clay smear factor. These distributions are below the mapping resolution in seismic data, and the actual processes and mechanisms for the fault-rock development are not well understood. A well-exposed and well-preserved low-throw fault in an old railroad tunnel near Salina, Utah provides the access and scale to interpret fault-rock distributions, measure their clay contents and describe the fault-rock development. A significant number of fault-rock elemental compositions were measured quickly on the outcrop surface using a hand-held X-ray fluorescence (XRF) elemental analyser with a novel surface preparation and analysis strategy. The elemental data were converted to clay contents using a small set of samples where elemental composition was calibrated to X-ray diffraction mineralogy. The mineralogy data provide a basis for evaluating the degree of mixing of protolith beds during fault-rock development in the fault core. The fault core is not randomly mixed fragments derived from the protolith (gouge or breccia), but rather discrete, thin layers parallel to the fault surface, many of which can be traced back to a source sandstone or mudstone bed. The mineralogical composition of some fault-rock layers are unchanged from their protolith source bed, but other layers are mechanical mixtures of several source beds. The shale gouge ratio algorithm under-represents the average measured fault-rock clay content. The clay smear algorithm more accurately describes the clay content distribution, but underestimates the clay content heterogeneity along the smear length. A key uncertainty for predicting fault sealing remains prediction of the lengths and continuity of smears.

Abstract Chalk is an important reservoir rock. However, owing to its low permeability, fractures are key to producing hydrocarbons from chalk reservoirs. Fractures in chalk usually form one of three geometric patterns: localized fractures (commonly concentric rings) developed around tips, bends and splays in larger faults; regularly spaced regional fracture sets; and fracture corridors comprising narrow zones of closely spaced parallel fractures. Localized fracture patterns are likely to give only local permeability enhancement; regional fracture sets and, especially, fracture corridors may provide long, high-permeability flow pathways through the chalk. Field mapping shows that both localized fracture patterns and fracture corridors often nucleate around larger faults; however, the fracture corridors rapidly propagate away from the faults following the regional stress orientation. It is therefore not necessary to know the detailed fault geometry to predict the geometry of the fracture corridors, although the fault density can help to predict the spacing of the fracture corridors. Mechanical modelling shows that while localized fracture patterns can form under normal fluid pressure conditions as a result of local stress anomalies around fault bends, tips and splays, fracture corridors can only form under conditions of fluid overpressure. Once they nucleate, they will continue to propagate until they either intersect another fault or the fluid pressure in them is dissipated.

Abstract This paper describes normal growth faults at the base of the Ferron Sandstone exposed along the highly accessible walls of Muddy Creek Canyon in central Utah. Although there have been several studies of growth faults in outcrops this is the first that integrates detailed sedimentological measured sections with fault kinematics and section restorations. We measured 20 sedimentological sections and interpreted a photomosaic covering approximately 200 m (550 ft) lateral distance. The outcrop is oriented parallel to depositional dip and perpendicular to the general strike of the faults. Distinctive pre-growth, growth, and post-growth strata indicate a highly river-dominated crevasse delta, that prograded northwest into a large embayment of the Ferron shoreline. The growth section comprises medium- to large-scale cross stratified sandstones deposited as upstream and downstream accreting mouth bars in the proximal delta front. Deposition of mouth bar sands initiates faults. Because depositional loci rapidly shift, there is no systematic landward or bayward migration of fault patterns. During later evolution of the delta, foundering of fault blocks creates an uneven sea-floor topography that is smoothed over by the last stage of deltaic progradation. Faults occur within less than 10 m (30 ft) water depths in soft, wet sediment. Detailed examination of the fault zones shows that deformation was largely by soft-sediment mechanisms, such as grain rolling and by lubrication of liquefied muds, causing shale smears. Mechanical attenuation of thin beds occurs by displacement across multiple closely spaced small throw faults. Analogous river-dominated deltaic subsurface reservoirs may be compartmentalized by growth faults, even in shallow-water, intracratonic, or shelf-perched highstand deltas. Reservoir compartmentalization would occur where thicker homogenous growth sandstones are placed against the muddy pre-growth strata and where faults are shale-smeared, and thus potentially sealing.