ALBERT

Description: The porosity dependence of the formation factor of geologic media is examined from the perspective of universal scaling laws from percolation and effective medium theories. Over much of the range of observed porosity, the expected percolation scaling is observed, but the values of the numerical prefactor do not conform to the simple predictions from percolation theory. Combining effective medium and percolation theories produces a numerical prefactor whose value depends on both the threshold porosity and the porosity above which the formation factor crosses from percolation to effective medium scaling. This change allows extraction of a numerical value of the prefactor, which is reasonably close to experimental values. Subsequent evaluation of the porosity dependence of the formation factor shows that difficulties in prior comparisons of theory and experiment are largely removed when percolation scaling is allowed to transition to effective medium scaling far above the percolation threshold.

Description: Montgomery et al. (2005) have written a very useful, information-filled review article on the state of knowledge of the Barnett Shale play in north Texas, a topic of great current interest and importance. One error exists, however; the burial history that they present shows no uplift during the early and middle Mesozoic and strong uplift after the Cretaceous, whereas the geologic record indicates major pre-Cretaceous uplift. This error substantially affects the discussion of the maturation history of the Barnett and should be corrected in the literature. I will also briefly discuss the implications of pre-Cretaceous erosion and Ouachita thrusting to Barnett maturity in the deep Fort Worth basin. In Montgomery et al.'s (2005) figure 7, they show a time-depth burial history diagram for Eastland County that is contrary to what is known about the area. In that figure and in the text, they indicate that the Barnett was rapidly buried during the Pennsylvanian and Early Permian, remained at depth with no uplift or subsidence except for minor subsidence in the Early Cretaceous, then was uplifted some 1.8 km (6000 ft) between the middle Cretaceous and the Eocene (with very slight subsidence to the present). The surface geology of Eastland County and surrounding areas (Barnes, 1972) shows that flat-lying Lower Cretaceous strata (Antlers Sand and overlying Edwards Group marine carbonates) lie unconformably above units, ranging from the Strawn Group (Mingus Formation, Desmoinesian regional age) in the southeast to the lower Cisco Group (Graham Formation, Virgilian regional age) in the northwest. The west-northwest–dipping Pennsylvanian strata form part …

Description: The Upper Jurassic Haynesville Shale is currently regarded as one of the most prolific emerging shale-gas plays in the continental United States. It has estimated play resources of several hundred trillion cubic feet and per-well reserves estimated as much as 7.5 bcf. The reservoir spans more than 16 counties along the boundary of eastern Texas and western Louisiana. Although this basin has a long history of exploration and analysis of its Mesozoic section, a comprehensive subsurface study characterizing the Haynesville Shale has not been conducted. This article is the first to address the structural setting, stratigraphy, depositional environment and facies, fracturing, and production challenges of the Haynesville shale-gas play. Basement structures and salt movement influenced carbonate and siliciclastic sedimentation associated with the opening of the Gulf of Mexico. The Haynesville Shale is an organic- and carbonate-rich mudrock that was deposited in a deep partly euxinic and anoxic basin during the Kimmeridgian to the early Tithonian, related to a second-order transgression that deposited organic-rich black shales worldwide. The Haynesville Basin was surrounded by carbonate shelves of the Smackover and Haynesville lime Louark sequence in the north and west. Several rivers supplied sand and mud from the northwest, north, and northeast into the basin. Haynesville mudrocks contain a spectrum of facies ranging from bioturbated calcareous mudstone, laminated calcareous mudstone, and silty peloidal siliceous mudstone, to unlaminated siliceous organic-rich mudstone. Framboidal to colloidal pyrite is variably present in the form of concretions, laminae, and individual framboids and replaces calcite cement and mollusk shells. Haynesville reservoirs are characterized by overpressuring, porosity averaging 8 to 12%, Sw of 20 to 30%, nanodarcy permeabilities, reservoir thickness of 200 to 300 ft (70 to100 m), and initial production of as much as 30 mmcf/day. Reservoir depth ranges from 9000 to 14,000 ft (3000 to 4700 m), and lateral drilling distances are 3000 to 5000 ft (1000 to 1700 m). Typical Haynesville wells exhibit a steeper decline curve (∼80% in the first year) than other shale-gas plays, which is attributed to a very high overpressure. Ursula Hammes is a research associate at the Bureau of Economic Geology, where she is leading the STARR project conducting reservoir characterization and regional studies in Texas. Her current research interests are focused on facies, depositional environments, and sequence stratigraphy of mudrock systems. Dr. Hammes has a diploma in geology from the University of Erlangen, Germany, and a Ph.D. in geology from the University of Colorado, Boulder. H. Scott Hamlin is a research associate at the Bureau of Economic Geology. He received his B.A. and M.A. degrees and his Ph.D. from the University of Texas at Austin. His research interests include depositional systems, stratigraphy, reservoir characterization, and hydrogeology. His present research focuses on Wolfcampian and Leonardian slope and basin reservoirs in the Midland Basin of west Texas. Thomas Ewing, consulting independent geologist and partner in Yegua Energy Associates, explores hydrocarbons in Texas and elsewhere and seeks to understand the geologic history of Texas and the Gulf of Mexico, emphasizing Claiborne Group sequence stratigraphy, Mesozoic regional stratigraphy, Texas tectonics, and surface-subsurface relationships in the Balcones area. He received his Ph.D. from the University of British Columbia.

Description: The middle Eocene Claiborne Group was assessed for undiscovered conventional hydrocarbon resources using established U.S. Geological Survey assessment methodology. This work was conducted as part of a 2007 assessment of Paleogene–Neogene strata of the northern Gulf of Mexico Basin, including the United States onshore and state waters (Dubiel et al., 2007). The assessed area is within the Upper Jurassic–Cretaceous–Tertiary composite total petroleum system, which was defined for the assessment. Source rocks for Claiborne oil accumulations are interpreted to be organic-rich, downdip, shaley facies of the Wilcox Group and the Sparta Sand of the Claiborne Group; gas accumulations may have originated from multiple sources, including the Jurassic Smackover Formation and the Haynesville and Bossier shales, the Cretaceous Eagle Ford and Pearsall (?) formations, and the Paleogene Wilcox Group and Sparta Sand. Hydrocarbon generation in the basin started prior to deposition of Claiborne sediments and is currently ongoing. Primary reservoir sandstones in the Claiborne Group include, from oldest to youngest, the Queen City Sand, Cook Mountain Formation, Sparta Sand, Yegua Formation, and the laterally equivalent Cockfield Formation. A geologic model, supported by spatial analysis of petroleum geology data, including discovered reservoir depths, thicknesses, temperatures, porosities, permeabilities, and pressures, was used to divide the Claiborne Group into seven assessment units (AUs) with three distinctive structural and depositional settings. The three structural and depositional settings are (1) stable shelf, (2) expanded fault zone, and (3) slope and basin floor; the seven AUs are (1) lower Claiborne stable-shelf gas and oil, (2) lower Claiborne expanded fault-zone gas, (3) lower Claiborne slope and basin-floor gas, (4) lower Claiborne Cane River, (5) upper Claiborne stable-shelf gas and oil, (6) upper Claiborne expanded fault-zone gas, and (7) upper Claiborne slope and basin-floor gas. Based on Monte Carlo simulation of justified input parameters, the total estimated mean undiscovered conventional hydrocarbon resources in the seven AUs combined are 52 million bbl of oil, 19.145 tcf of natural gas, and 1.205 billion bbl of natural gas liquids. This article describes the conceptual geologic model used to define the seven Claiborne AUs, the characteristics of each AU, and the justification behind the input parameters used to estimate undiscovered resources for each AU. The great bulk of undiscovered hydrocarbon resources are predicted to be nonassociated gas and natural gas liquids contained in deep (mostly 〉12,000-ft [3658 m], present-day drilling depths), overpressured, structurally complex outer shelf or slope and basin-floor Claiborne reservoirs. The continuing development of these downdip objectives is expected to be the primary focus of exploration activity for the onshore middle Eocene Gulf Coast in the coming decades. Paul Hackley received his M.S. degree in geology in 1999 from the George Washington University. He joined the U.S. Geological Survey Energy Resources Program in 2001 and has worked primarily in the Gulf Coast Basin since that time, investigating coal, coalbed methane, conventional oil and gas, and shale gas resources. His current research interests include the application of organic petrology techniques to resource assessment. Thomas Ewing received a Ph.D. in geological sciences from the University of British Columbia in 1981. Working with Venus Oil and Venus Exploration since 1985, he has played a main role in the successful exploration of the Yegua trend in the upper Claiborne of the Gulf Coast Basin, which he continues as a partner in Yegua Energy Associates, LLC. He is the author of more than 70 articles and abstracts related to Gulf Coast geology.