Abstract:

Leading Edge (Tulsa, OK) (January 2011), 30(1):48-53

The south Texas Eagle Ford shale formation in is an important emerging shale play in the United States. More than 1510 wells have either been drilled or permitted in the play. What has emerged is a well-defined downdip gas play that transitions rapidly updip into less well-defined wet gas and oil fairways. With initial gas well rates exceeding 17 million cubic feet per day and initial oil well rates in excess of 1000 barrels of oil per day common in the expanding play, exploration companies are pursuing methods to optimize drilling plans. Limited well and core data describing the Eagle Ford require the use of 3D seismic to help characterize reservoir quality variations, avoid drilling hazards, and help predict sweet spots. Modern, long-offset, full-azimuth 3D is an essential tool for building a geophysical description of the shale between wells. Anisotropic time imaging, feeding both acoustic and elastic inversions, is helping operators gain better insight into the reservoir's variability. The following discussion highlights components of an ongoing effort to extract value from seismic data in shale prospecting. Unfortunately, limited well data for calibration, as in many immature shale plays, remains the primary constraint on confident linkage between the actual reservoir quality and seismic measurements.

Abstract:

Leading Edge (Tulsa, OK) (November 2010), 29(11):1386-1392

The most advanced prestack depth-migration (PSDM) technologies available today, such as wave-equation migration (WEM) and reverse time migration (RTM), are primarily used for offshore applications like subsalt imaging. However, E&P efforts in many onshore basins can also benefit from PSDM, and there is considerable momentum in many basins to adopt this technology as the default imaging tool (Young et al., 2009). This paper highlights the application of wave-equation depth-imaging technologies (WEM and RTM) with several onshore U.S. case studies. Below we list some benefits that users of PSDM technology might expect to enjoy.

Abstract:

AAPG Bulletin (October 2010), 94(10):1607-1636

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.