Abstract Three-dimensional circumferential CT-scans have transformed how core is described and calibrated with borehole image (BHI) datasets to refine reservoir rock typing and facies description. This paper focuses on the value of circumferential CT-scans in the assessment of plug and bed-scale heterogeneities. It shows how careful re-orientation and calibration with borehole images can help unravel sandbody geometries and orientation, and the potential effects of cross-cutting deformation bands on permeability architecture and sweep efficiency. This is demonstrated using aeolian-dominated core examples, supported with circumferential CT-scans, minipermeability data, conventional logs and BHI data, taken from the Jurassic Norphlet Formation from producing fields in the Gulf of Mexico. The formation overlies Early Jurassic Louann Salt, and syn-depositional halokinesis significantly influenced depositional accommodation space, facies distribution, and preservation potential. Furthermore, deposition during active salt tectonics has resulted in complex deformation band networks within these clean sandstones. CT-scan density contrasts highlight stratification types and deformation bands not always visible on slabbed core. Furthermore, BHI re-orientated CT-scans provide high-resolution dip/azimuth data and aid aeolian bedset bounding surface definition, which is important for determining dune geometry and stacking patterns. Hence, an integrated approach using core, circumferential CT-scan and calibrated BHI has been essential for deciphering the complexity of these deposits.

ABSTRACT Exploration for oil in the Norphlet reservoir in the deep-water Gulf of Mexico began in 2003 at prospect Shiloh (DC269). The well found oil but not an economic volume. The second prospect, Vicksburg (DC353), was drilled in 2007. This well found a larger in-place volume of oil, but with an immovable solid hydrocarbon component within pore spaces, there was great uncertainty as to the potential producible volumes. Two subsequent wells (Fredericksburg [DC486] and Antietam [DC268]) were dry and had a very small amount of oil, respectively. Finally, in late 2009, the fifth well (Appomattox [MC392]) was a significant discovery of high-quality oil in a thick aeolian Norphlet sandstone.

Abstract The Oxfordian Smackover Formation is generally acknowledged to be a hydrocarbon source for numerous reservoirs in the Gulf of Mexico, both onshore and offshore. More than 25 wells in the eastern Gulf of Mexico have penetrated the Smackover since 2003. Offshore, the Smackover consists predominantly of limestone and shale containing thin organic layers. Immediately above the lower Smackover is a widespread shale marker. This thin shale is correlated as the base of the upper Smackover Formation, which consists of interbedded shale and limestone. This study will demonstrate that the lower Smackover Formation in the eastern Gulf of Mexico (Mississippi Canyon and De Soto Canyon offshore areas) is composed of a series of seven units that occur in the same sequence in virtually every well in which the lower Smackover has been encountered. Although the seven individual units can be resolved readily with the proper wireline suite, each has a sub-seismic thickness. The overall thickness of the lower Smackover is about 300 +/-100 feet. Unlike the lower Smackover, the surrounding Mesozoic formations, from Cotton Valley to Norphlet, vary greatly in thickness in the eastern Gulf. The initial correlations of the units in the lower Smackover were made by comparing the gamma ray, resistivity, and density log patterns with the computed mineralogy of Elemental Capture Spectroscopy (ECS) wireline logs. It was immediately obvious that the same sequence of beds/units was present in the lower Smackover in well after well. Within the lower Smackover Formation is a conspicuous zone characterized by iron-bearing minerals having a matrix density in excess of 3.0 g/cm 3 throughout. However, X-Ray Diffraction (XRD) data from rotary sidewall cores was necessary to validate the mineralogy. Because the mineralogy of the ECS log is a model-based calculation from the elemental concentrations of iron, calcium, aluminum, etc,. rather than a direct measurement, the modeled mineralogy can be inaccurate as was the case in the bottom two units. Mineralogy of the seven units has been verified by XRD analyses, albeit from a limited number of rotary sidewall cores obtained in only five wells. The top three units are limestones which vary in carbonate, clay, and pyrite content. The fourth and fifth units contain significant amounts of high density minerals, particularly siderite and pyrite. The sixth zone is dominated by anhydrite. The seventh unit is a hematite-rich shale and its base is an unconformity. Although wireline data are plentiful, analysis of the seven units within the lower Smackover is hampered by the limited amount of rock data and the complete lack of whole core. Many depositional and geochemical questions suggested by the unusual mineralogy and sequence of beds remain unanswered.

Abstract Large parts of the De Soto Canyon Salt Basin are unexplored, and structural and petroleum system models may facilitate continued hydrocarbon exploration, as well as the development of geologic CO 2 storage programs. The basin contains four structural provinces: (1) Destin fault system, (2) salt pillow province, (3) diapir province, and (4) salt roller province. The Destin fault system bounds half grabens that formed near the updip limit of salt. The faults have variable displacement and were active mainly during the Cretaceous. Broad salt pillows occur basinward of the Destin fault system, and the largest of these structures forms the core of Destin Dome. Salt pillows basinward of Destin Dome began forming shortly after Smackover deposition, whereas Destin Dome largely post-dates the Destin fault system. The diapir province is in the structurally deepest part of the salt basin, and diapirism occurred from the Jurassic into the Tertiary. The salt roller province contains a complex array of normal faults and rollover structures that record gravitational shelf spreading during Jurassic time. Petroleum systems analysis indicates that the basin contains a distinctive suite of source rocks, sealing strata, reservoir strata, and trap types. Exploration efforts have thus far proven successful in structures that formed before or during hydrocarbon expulsion, and many such structures remain untested.

Subsurface thermal conductivity, thermal gradient, and heat flow are significant parameters when determining the feasibility of utilizing a geologic unit to generate industrial geothermal power. Cores from 18 wells of the subsurface Jurassic Smackover Formation in southwest Arkansas were analyzed at the Arkansas Geological Survey, where thermal conductivity, thermal gradient, and heat-flow values were estimated. Thermal conductivity of several samples was obtained using a KD2 Pro Thermal Analyzer at room temperature. Thermal gradients were estimated from Smackover Formation borehole temperatures, and heat-flow values were calculated from thermal conductivity and thermal gradient values. Average thermal conductivity values for the Smackover Formation are greatest in northeastern Lafayette County at 2.57 W/m·K, followed by southern Columbia and western Calhoun Counties at 2.47 W/m·K each. Northwestern Columbia and northeastern Lafayette Counties exhibit the highest thermal gradient and heat flow, with values averaging 3.51 °C/100 m and 72.3 mW/m 2 , respectively. Interpretation of these parameters confirms that this area exhibits the highest geothermal potential for the Smackover Formation in southwest Arkansas. Investigations further characterizing the Smackover Formation, including in situ thermal properties and borehole temperature measurements, are recommended for future geothermal feasibility studies.