Abstract Analysis of well core and cuttings from the Black Warrior Basin in Mississippi reveals the presence of a Middle Ordovician (Whiterockian) erosional unconformity interpreted to be equivalent to the well-known Knox-Beekmantown unconformity in eastern North America. The unconformity occurs at the top of a peritidal dolostone unit known informally as the upper dolostone, whose stratigraphic placement has been the subject of a long-standing controversy. The unconformity, which represents the Sauk-Tippecanoe megasequence boundary on the North American craton, was previously thought to be short-lived or altogether absent in the Black Warrior Basin. The unconformity is characterized by subunconformity solution pipes, solution-collapse breccias, internal sedimentation, and erosional truncation of the underlying dolostone unit. This erosional surface is veneered with sand- to pebble-size, rounded and angular lithoclasts of the underlying dolostone, and rounded and angular quartz sand and silt. Extensive secondary porosity developed in the upper dolostone below the unconformity. Although much of this porosity was later occluded by internal sedimentation and pore-filling dolomite and calcite cement, porous zones remain in the upper dolostone. Based on conodont biostratigraphy from four cores and from a previous study on cuttings from a nearby well, the unconformity is middle Whiterockian in age and likely spans most or all of the Histiodella holodentata Biozone.

Abstract This paper represents a study of reservoir pore modification accompanying diagenetic secondary porosity development within a deep (13,400 ft) overpressured Anahuac Formation sandstone in southern Louisiana. Secondary porosity formed by dissolution of carbonate cement, detrital grains, and other soluble minerals comprises a significant portion of porosity formed in U.S. Gulf Coast Tertiary reservoir sands. The primary pore system within this reservoir is believed to have been significantly enlarged (by up to 32% porosity) by acidic fluids generated during hydrocarbon maturation and dewatering of adjacent shales. Subsurface secondary porosity development within sandstones is significant in influencing the development of potential reservoir porosity after much of the primary porosity has been destroyed by mechanical and chemical compaction. Properties of the reservoir pore system that affect fluid flow and mechanical resistance of the reservoir to compaction accompanying production will also be influenced. Characteristics of the reservoir pore system were established by study of whole core samples using scanning electron microscopy, petrographic examination, mercury injection, and simulated in-situ reservoir condition core testing. Secondary pore size and distribution was found to be influenced by sandstone mineralogy, grain size, sorting and angularity, the pore matrix content, and by sedimentary structures and resulting textural components that may hinder fluid flow. Changes in the mechanical resistance to compaction caused by the development of secondary porosity in sandstone reservoirs is important when considering reservoir stress sensitivity. Keystone bridging relationships between grains can be established during the initial phases of compaction so that when leaching of cement and soluble grains occurs, a less soluble quartz grain matrix is left to support porosity development. Special core tests were performed at simulated in-situ reservoir conditions of pressure and temperature to examine porosity and permeability reduction as a function of effective stress generated by pore pressure reduction (simulated fluid production). Observed volumetric strain to uniaxial compaction at reservoir conditions was determined within portions of the sand containing high (25–30%) porosity. Test results exhibited less than 1% reduction in total bulk volumes accompanying a 60% reduction in pore pressure. Permeabilities measured at in-situ conditions were commonly an order of magnitude less than those measured at ambient conditions. However, with increased effective stress applied to the rock fabric, data suggest that permeabilities decrease at a much slower rate, reflecting constriction of pore throats rather than constriction of stress-induced microfactures thought to exist in core samples at ambient conditions.

Abstract The Pliocene Pico and Repetto Formation turbidites of the Ventura Basin were the subject of early research on deep-water sedimentation. We focus on the subsurface Repetto Formation, primarily using cores and well logs to characterize the sandstone reservoirs and describe sand-body geometry and stratigraphic stacking. The generally poorly sorted, coarse-grained sandstone facies deposited in this elongate basin dominated by longitudinal flows have been recognized as differing from those in traditional submarine–fan–lobe facies models. They have been variously described as ribbon or shoestring sands, compensationally stacked elongate-lobe elements, and components of a braided-lobe complex. Our study utilizes recently acquired subsurface data from cores and well logs and new analytical techniques to improve our understanding of facies distributions and rock properties. Our subsurface data, however, come from only a small area of the basin and therefore afford only a limited perspective on basin-wide depositional systems. An important tool for our work is a well-log–based petrofacies model that ties directly to lithofacies. This technique enables us to delineate in significant detail lithofacies stacking patterns and lateral facies variations in wells without core. The petrofacies enable us to improve the geologic context of well-log correlation. Linked with core observations, petrofacies determination helps to define the geometry of architectural elements on the vertical scale of 50 to 100 ft (15–30 m) and laterally on the scale of typical well spacing (hundreds of feet/meters). Facies stacking and lateral relations also enable us to identify important stratigraphic surfaces. In the coarsest-grained elements, we identify two lithofacies stacking patterns that likely represent different depositional settings. Both have pebble-to-gravel–sized clasts in a sandy matrix and angular mudstone clasts at their bases. One element exhibits a fining-upward stacking pattern often characteristic of channel-fill sequences and potentially represents a distributary channel system that eventually migrates or is abandoned. The second coarse-grained element has a blocky stacking pattern consisting predominantly of amalgamated sandstone beds and remains coarse-grained nearly to the top of the unit. This depositional geometry could be consistent with a braided-lobe complex, characterized by multiple broad and low-relief channels with intervening bar forms. Both coarse-grained elements likely represent axial positions in their respective depositional settings and are relatively easy to map between wells because of the abrupt facies change at the base of the units and their relative thickness (tens of feet/meters). Thinner-bedded, finer-grained sandstone bedsets show more variability in stacking pattern and are more difficult to map over larger distances. The correlation geometry of these stratal elements is generally planar and subparallel, but individual sandstone beds are less continuous. The sandstone beds are often interbedded with mudstone and sometimes slurry deposits. We interpret these units to represent off-axis or distal deposition. Petrofacies are key for predicting reservoir properties, since porosity and permeability are closely correlated to lithofacies. For example, the petrofacies technique enables us to differentiate the coarsest-grained bedsets, deposits of high-density turbidity currents (generally poorly sorted sandstone with lower matrix porosity and permeability), from thin-bedded sandstone (generally finer-grained and better sorted, with higher matrix porosity and permeability).