The objective of this research was to map and determine the updip limit and locate reservoir potential of the Smackover Formation in southeast-central Mississippi. This subsurface study was conducted using well log correlation and analysis, structure top and isopach thickness mapping, 2-D seismic analysis, and core descriptions. The conclusions from the study led to an alternate interpretation of the Smackover updip limit affected by basement paleotopography in a possible ridge-valley complex similar to south Alabama based on evidence from Smackover isopach thickness, structure top map of a Pre-Smackover surface that represents underlying formations, and 2-D seismic analysis that agreed with the isopach pinch out. Evidence from two core observations from in the updip and downdip area revealed oomoldic porosity and dolomite lithologies with decreasing porosity and connectivity updip. Strong diagenetic features with no visible porosity were present in some core sections. Analysis to determine reservoir-grade porosity updip would be necessary.

A petrophysical study of the upper grainstone/packstone reservoir of the Oxfordian Smackover Formation in Little Cedar Creek Field was conducted, integrating core description, thin section analysis, log interpretation and cathodoluminescense to characterize controls on oil production in the upper reservoir. Little Cedar Creek Field produces approximately 2.4 million barrels (bbls) of oil annually and is currently in secondary recovery. By analyzing petrophysical characteristics such as porosity and pore type and correlating them to facies changes, better predictions can be made to optimize secondary recovery. The diagenetic history of the ooid-peloid grainstone records six separate events. Early marine phreatic dogtooth sparry rim cement helped create the framework that allowed it to maintain a good portion of its depositional porosity as it underwent subsequent compaction, dissolution and cementation events. The most common porosity types are vuggy, oomoldic and intercrystalline. The Smackover Formation ooid-peloid grainstone/packstone unit consists of multiple alternating ooid-peloid grainstone and peloid packstone/wackestone facies with varying porosity types. The most common types are oomoldic and vuggy with a range of preserved intergranular porosity. Porosity in the grainstone facies averages 17% and 5.6% in the packstone/wackestone facies. The number of facies changes within the upper reservoir does not play a significant role in controlling well production. Facies changes are too thin to be identifiable utilizing well logs alone, although neutron and density well logs do trace a close relationship between log values and core plug analysis values of porosity. Core reports indicate that porosity and permeability correlate strongly with pore size and facies. Areas with thicker accumulations of grainstone facies have higher porosity and permeability values and have higher oil production. Isopach maps of the cumulative grainstone facies indicate thick build-ups parallel to strike for the formation, consistent with a shoal environment. The strongest predictor of well production is the cumulative thickness of grainstone facies within the grainstone/packstone unit of the Smackover Formation. The grainstone is thickest in the southwest part of the field and pinches out updip in the northwest. Secondary recovery gas injection would be most effective if applied in the southwestern portion of the field because it could effectively sweep the oil updip towards the stratigraphic trap.

The purpose of this study was first to develop a method by which a detailed porosity classification system could be utilized to understand the relationship between pore/pore-throat geometry, genetic porosity type, and facies. Additionally, this study investigated the relationships between pore/pore-throat geometry, petrophysical parameters, and reservoir performance characteristics. This study focused on the Jurassic Smackover reservoir rocks of Grayson field, Columbia County, Arkansas. This three part study developed an adapted genetic carbonate pore type classification system, through which the Grayson reservoir rocks were uniquely categorized by a percent-factor, describing the effect of diagenetic events on the preservation of original depositional texture, and a second factor describing if the most significant diagenetic event resulted in porosity enhancement or reduction. The second part used petrographic image analysis and mercury-injection capillary pressure tests to calculate pore/pore-throat sizes. From these data sets pore/pore-throat sizes were compared to facies, pore type, and each other showing that pore-throat size is controlled by pore type and that pore size is controlled primarily by facies. When compared with each other, a pore size range can be estimated if the pore type and the median pore-throat aperture are known. Capillary pressure data was also used to understand the behavior of the dependent rock properties (porosity, permeability, and wettability), and it was determined that size-reduced samples, regardless of facies, tend to show similar dependent rock property behavior, but size-enhanced samples show dispersion. Finally, capillary pressure data was used to understand fluid flow behavior of pore types and facies. Oncolitic grainstone samples show unpredictable fluid flow behavior compared to oolitic grainstone samples, yet oncolitic grainstone samples will move a higher percentage of fluid. Size-enhanced samples showed heterogeneous fluid flow behavior while the size-reduced samples could be grouped by the number of modes of pore-throat sizes. Finally, this study utilized petrographic image analysis to determine if 2- dimensional porosity values could be calculated and compared to porosity values from 3-dimensional porosity techniques. The complex, heterogeneous pore network found in the Grayson reservoir rocks prevents the use of petrographic image analysis as a porosity calculation technique.

The purpose of this study was first to develop a method by which a detailed porosity classification system could be utilized to understand the relationship between pore/pore-throat geometry, genetic porosity type, and facies. Additionally, this study investigated the relationships between pore/pore-throat geometry, petrophysical parameters, and reservoir performance characteristics. This study focused on the Jurassic Smackover reservoir rocks of Grayson field, Columbia County, Arkansas. This three part study developed an adapted genetic carbonate pore type classification system, through which the Grayson reservoir rocks were uniquely categorized by a percent-factor, describing the effect of diagenetic events on the preservation of original depositional texture, and a second factor describing if the most significant diagenetic event resulted in porosity enhancement or reduction. The second part used petrographic image analysis and mercury-injection capillary pressure tests to calculate pore/pore-throat sizes. From these data sets pore/pore-throat sizes were compared to facies, pore type, and each other showing that pore-throat size is controlled by pore type and that pore size is controlled primarily by facies. When compared with each other, a pore size range can be estimated if the pore type and the median pore-throat aperture are known. Capillary pressure data was also used to understand the behavior of the dependent rock properties (porosity, permeability, and wettability), and it was determined that size-reduced samples, regardless of facies, tend to show similar dependent rock property behavior, but size-enhanced samples show dispersion. Finally, capillary pressure data was used to understand fluid flow behavior of pore types and facies. Oncolitic grainstone samples show unpredictable fluid flow behavior compared to oolitic grainstone samples, yet oncolitic grainstone samples will move a higher percentage of fluid. Size-enhanced samples showed heterogeneous fluid flow behavior while the size-reduced samples could be grouped by the number of modes of pore-throat sizes. Finally, this study utilized petrographic image analysis to determine if 2- dimensional porosity values could be calculated and compared to porosity values from 3-dimensional porosity techniques. The complex, heterogeneous pore network found in the Grayson reservoir rocks prevents the use of petrographic image analysis as a porosity calculation technique.

Little Cedar Creek field is a mature oil field located in southeastern Conecuh County, Alabama, in the northeastern Gulf of Mexico. As of May 2012, 12.5 MMBLS of oil and 14.8 MMCF of natural gas have been produced from the field area. The main reservoirs are microbial carbonate facies and associated nearshore high energy shoal facies of the Upper Jurassic Smackover Formation that overlie conglomerate and sandstone facies of the Norphlet Formation and underlie the argillaceous, anhydritic-carbonaceous facies of the Haynesville Formation. These carbonate reservoirs are composed of vuggy boundstone and moldic grainstone, and the petroleum trap is stratigraphic being controlled primarily by changes in depositional facies. To maximize recovery and investment in the field, an integrated geoscientific-engineering reservoir-wide development plan is needed, including reservoir characterization, modeling, and simulation. This research presents a workflow for geological characterization, formation evaluation, and 3D geologic modeling for fields producing from microbial carbonates and associated reservoirs. The workflow is used to develop a 3D geologic model for the carbonate reservoirs. Step I involves core description and thin section analysis to divide and characterize the different Smackover facies in the field area into 7 units. The main reservoir facies are the microbial boundstone characterized by vuggy porosity and nearshore/shoal grainstone characterized by moldic porosity. Step II is well log correlation and formation evaluation of 113 wells. We use wireline logs and conventional core data analysis data to calculate average porosity values, permeability and water saturations. Neural networks are utilized at this stage to derive permeability where core measurements are absent or partially present across the reservoirs. Step III is building the 3D structural and stratigraphic framework that is populated with the petrophysical parameters calculated in the previous step. Overall, the integration of reservoir characterization, formation evaluation, and 3D geologic modeling provides a sound framework in the establishment of a field/reservoir-wide development plan for optimal primary and enhanced recovery for these Upper Jurassic microbial carbonate and associated reservoirs. Such a reservoir-wide development plan has broad application to other fields producing from microbial carbonate reservoirs.

Sedimentary characteristics of grainy non-skeletal tidal flats along windward platform margins have not been described in modern environments and may be misidentified or misclassified in the rock record. This study describes the sedimentology of such an environment to aid in accurate identification and characterization in the ancient. At Shroud Cay, a grain-dominated tidal flat is sheltered from the high energy of the shelf by a ring of cemented Pleistocene and partly indurated Holocene eolianite islands separated by several narrow tidal passes. Depositional texture, environment of deposition and geobody mapping, extensive sediment sampling, and vibracoring have shown that, though the cemented island provide a barrier from the high energy of the shelf, a high degree of tidal energy still occurs behind this barrier as indicated by the overwhelmingly grainy nature of all of the tidal flat sub-environments. Intertidal flats comprise the majority of the tidal flat surface. These flats are characterized by patchy Scytonema mats overlying bioturbated peloid-ooid grainstones to packstones with cemented lithoclasts. Three main tidal channels dissect the tidal flat and allow diurnal flow, one of those tidal channels does not exit the tidal flat but dead-ends behind a cemented Holocene beach dune ridge along the eastern side of Shroud Cay. Peloid-ooid-skeletal grainstone tidal bars and peloid-ooid packstones fill much of the channels. Most of the channels are bordered by low-relief grain-rich packstone levees often capped by red mangroves and algal mats. The interior-most supratidal parts of the flat, often in the lee of the windward Holocene ridge, are covered by a thick (5-~25cm) Scytonema microbial mat underlain by grain-rich ooid-peloid packstones. Ancient grain-dominated carbonate tidal flats and eolianite deposits like Shroud Cay?s are the reservoir rocks in some of today?s largest hydrocarbon fields. We develop a model for the evolution of the grain-dominated tidal flat, document and compare differences between the grain-rich tidal flat and surrounding environments of deposition, and develop a set of criteria for recognition. These criteria can be used to more accurately characterize reservoirs such as the Jurassic Smackover fields, to avoid mis-classification of similar settings, and more effectively produce those reservoirs.