The Floyd (Neal) Shale is an organic-rich black shale in the Black Warrior Basin that is being explored for its unconventional gas potential. To understand the stratigraphic architecture of the black shale facies in Mississippi, a detailed examination of well logs, conventional core, well log correlation (cross sections) and isopach maps were used to delineate and characterize the Neal Shale depositional facies. From this study it can be concluded that parasequences associated with the upper Pride Mountain Formation, Hartselle, Floyd Shale and Bangor Limestone are equivalent to resistive units in the Neal Shale in Alabama. In Mississippi, the upper Pride Mountain Formation and Hartselle are distinctly separate and the Floyd Shale and Bangor Limestone comprise all equivalent units in the Neal Shale. The Neal Shale reaches maximum thickness of 125 ft and structurally deeper areas with maximum thickness of shale are key areas to focus for future potential gas exploration.

Carbon dioxide (CO2) is a primary source of greenhouse gases. Injection of CO2 from power plants near coalbed reservoirs is a win-win method to reducing emissions of CO2 to the atmosphere. Limited studies have investigated CO2 sequestration and enhanced coalbed methane production in San Juan and Alberta basins, but reservoir modeling is needed to assess the potential of the Black Warrior basin. Alabama ranks 9th nationally in CO2 emissions from power plants; two electricity generation plants are adjacent to the Black Warrior coalbed methane fairway. This research project was a reservoir simulation study designed to evaluate the potential for CO2 sequestration and enhanced coalbed methane (ECBM) recovery in the Blue Creek Field of Black Warrior basin, Alabama. It considered the injection and production rate, the components of injected gas, coal dewatering, permeability anisotropy, various CO2 soak times, completion of multiple reservoir layers and pressure constraints at the injector and producer. The simulation study was based on a 5-spot well pattern 40-ac well spacing. Injection of 100 percent CO2 in coal seams resulted in average volumes of 0.57 Bcf of sequestered CO2 and average volumes of 0.2 Bcf of enhance methane production for the Mary Lee coal zone only, from an 80-acre 5-spot well pattern. For the entire Blue Creek field of the Black Warrior basin, if 100 percent CO2 is injected in the Pratt, Mary Lee and Black Creek coal zones, enhance methane resources recovered are estimated to be 0.3 Tcf, with a potential CO2sequestration capacity of 0.88 Tcf. The methane recovery factor is estimated to be 68.8 percent, if the three coal zones are completed but produced one by one. Approximately 700 wells may be needed in the field. For multi-layers completed wells, the permeability and pressure are important in determining the breakthrough time, methane produced and CO2 injected. Dewatering and soaking do not benefit the CO2 sequestration process but allow higher injection rates. Permeability anisotropy affects CO2 injection and enhanced methane recovery volumes of the field. I recommend a 5-spot pilot project with the maximum well BHP of 1,000 psi at the injector, minimum well BHP of 500 psi at the producer, maximum injection rate of 70 Mscf/D, and production rate of 35 Mscf/D. These technical results, with further economic evaluation, could generate significant projects for CO2 sequestration and enhance coalbed methane production in Blue Creek field, Black Warrior Basin, Alabama.

The southern end of the Black Warrior Basin has been the site of limited drilling operations, but a critical need now exists to establish a greater understanding of the regional stratigraphy. The objectives of this study were to define a sequence stratigraphic framework for the southernmost Black Warrior Basin, to identify chronostratigraphic timelines within depositional environments, identify regional transgressive and high stand systems tracts. This information was used to identify three target reservoirs, characterize petrophysical properties, and confirm integrity of reservoir and seal formations for geologic storage. Methods include correlation of petrophysical well logs in the study area, well log analysis, as well as petrographic and core analyses. Five cycles were identified in well log cross sections. Sequence boundaries will be identified in both cross sections seismic data. Cretaceous sediments deposited above a regional sequence boundary above the Paleozoic that may represent as much as ~141 ma of erosion or non-deposition. The results of this study will contribute to development of a proposed geologic carbon sequestration facility in Kemper County, Mississippi.

A depositional framework for the Mississippian (Chesterian) Pride Mountain Formation/Hartselle Sandstone clastic tongue and the lower Bangor Limestone carbonate ramp in the Black Warrior basin, Mississippi and Alabama, is constructed from approximately 250 geophysical well logs, 15 well cuttings descriptions, and outcrop data. The framework is based upon cross sections, isopach maps, and transgressive-regressive sequence stratigraphy. The Lowndes-Pickens synsedimentary fault block controlled sediment dispersal in during Pride Mountain/Hartselle deposition. The basin filled from the southwest, which pushed the depocenter northeastward during Hartselle deposition. The Hartselle sub-basin is composed of the Hartselle barrier-island and back-barrier deposits to the southwest, including the Pearce siltstone. The Pearce siltstone, a previously unidentified subsurface unit, was deposited in a restricted environment controlled by the Lowndes-Pickens block. The Pride Mountain, Hartselle, and lower Bangor succession contains one complete and one partial transgressive-regressive stratigraphic sequence. An exposure surface at the top of the Hartselle Sandstone and Monteagle Limestone is a maximum regressive surface. The upper part of the Bangor ramp is highly cyclic and grades from oolitic shoal deposits southwestward into a condensed section, the Neal black shale, at the toe of the ramp. The entire thickness of the lower Bangor is equivalent to the Neal shale.

The Lowry Method of Protein Assay is an effective alternative to point count or culture methods to determine the relative abundance of microorganisms in geologic samples. Results of this project show that the outcome of the Lowry assay is not affected by the constituents of a sandstone reservoir and that a relationship exists between microbes and clay minerals. Core samples were taken from the Carter sandstone at the North Blowhorn Creek Unit in Lamar County, Alabama. Samples were chosen based on mineralogic heterogeneity. The samples were placed in an anaerobic glove bag and given nutrients to induce the growth of in situ microorganisms. Samples were then assayed. Results of the protein assays show that the Lowry Method of Protein Assay is effective in determining protein concentrations in geologic samples with varying mineralogies. The assays also indicated that samples with abundant clay minerals show the greatest amount of microbial growth.