Mapping impedance helps high-grade locations.
The South Texas Eagle Ford shale formation is an important emerging shale play in the US. More than 510 wells either have 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 gas well rates exceeding 17 MMcf/d and oil well rates in excess of 1,000 b/d of oil common in the expanding play, exploration companies are actively pursuing methods to optimize drilling plans for optimal gas and oil recovery. The relatively narrow depositional and petroleum fairways combined with the 150- to 250-ft (46- to 76-m) thickness support the use of advanced geophysical techniques, in particular, frequency, coherency, and azimuthal attributes.
Middle Cretaceous to Upper Cretaceous (Turonian)-age Eagle Ford shale was deposited during an extreme marine high stand resulting in the accumulation of varying thicknesses of deepwater, organic-rich marine shales. Forms of marine environments were controlled largely by the interaction of basement zones of weakness, underlying carbonate paleogeography, salt tectonics, and eustatic sea level. Tectonically, the region was relatively quiet with small but significant southeasterly gravitational sliding and a rapidly deepening southern-bounding Bisbee-Chihuahua trough. Additionally, intrusive and extrusive volcanics occurred in the north and western parts of the basin.
Low stands preceding and during deposition generated a regional flooring carbonate horizon (the Buda limestone) and an internal carbonate marker (the Kamp Ranch member) that divide the organically rich basal section (lower Eagle Ford or Britton/ Pepper shale) from the overlying, leaner, and more calcareous member (upper Eagle Ford or Acadia Park). The upper surface is a sequence boundary where the overlying Austin Chalk downlaps unconformably onto the uppermost member of the Eagle Ford shale.
Rock properties of this succession are well suited for seismic analysis. The underlying Buda, a tight (2% to 3% porosity), massive, micritic wackestone, is present regionally, ranging in thickness from 40 to 160 ft (12 to 49 m). Seismic impedance is consistent between 48,300 and 51,700 ft per second times grams per cubic centimeter (ft/sec x g/cu cm). In marked contrast, the overlying Eagle Ford shale is organic-rich (4% to 7% total organic content or TOC), relatively thick (50 to 250 ft or 15 to 76 m), and porous (7% to 15% porosity). Acoustic impedance varies from 31,400 to 35,700 ft/sec x g/cu cm as a result of the anomalously low density resulting from the high organic content and related high porosity. Above this, the upper calcareous member of the Eagle Ford shale generally has lower organic content and lower porosity (2% to 5% TOC and 7% to 12% porosity), is more variable in thickness, and has erosional upper contact with the overlying (organic-efficient) Austin Chalk. The upwards decrease of porosity and organic content results in a gradual change in density and acoustics, and as a result, strong seismic reflection surface is not likely.
With today’s limited subsurface data, comprehensive understanding of local and regional variations within Eagle Ford fairways still poses challenges to companies. Newly acquired 3-D seismic datasets provide the opportunity to better manage a great deal of the geological uncertainty by providing higher fidelity resolution of the subsurface. This includes better definition of drilling hazards due to faults, better definition of potential reservoir properties due to acoustic variations, and clearer definition of fractures and regional stress for better wellbore planning.
Seismic data offer a number of opportunities to understand potential heterogeneities in Eagle Ford shale reservoir rocks. Identification of the Austin Chalk and Buda horizons yields well-constrained isochron and isopach maps that illustrate variations in thickness of the target formation. These are central to the development of reliable gas- or oil-in-place maps. The greatest thickness variations appear to be associated with active faulting during deposition and can result in rapid 30- to 50-ft (9- to 15-m) Eagle Ford changes. Coherence and curvature attributes highlight lineaments associated with small-throw faults and possible fracture trends. Effective interpretation and 3-D visualization of the target shale section can illustrate internal variations that can impact well positioning and reduce drilling risk.
Processing data with focus on preserving amplitude across offsets and azimuths ultimately can be the key to identifying sweet spots in this trend. Critical to achieving this will be the collection of high-frequency, high-fold data with focus on long offsets and full-azimuth shooting.
In processing current Eagle Ford 3-D seismic, it is possible to extract more information from the shale section. Long-offset and full-azimuth 3-D datasets allow for derivation of anisotropic parameters in the shale. Layer anisotropy (vertical transverse isotropy) and azimuthal anisotropy (horizontal transverse isotropy) can help infer pressure cells, clay content, and stress/fracture potential. Rock property changes typically apparent in far-offset gathers, but muted in stacked volumes, offer insight into elastic rock properties. Attention to this aspect of the seismic shoot enhances the overall image of the section and provides fracture or stress information critical in planning drilling programs. It also is necessary to address anisotropy prior to elastic inversion attempts. Far-offset amplitude variations due to poor characterization of velocity and anisotropy fields can lead to incorrect elastic parameters in the inversion.
With refined processing products, it is possible to begin extracting rock property information through inversion of the seismic. Acoustic impedance inversion is the simplest and most robust first step in pursuit of Eagle Ford rock properties. The inversion uses a 3-D model, the seismic velocity field, and an estimation of the seismic wavelet to convert seismic volume to impedance volume. Rock property studies in the Eagle Ford indicate impedance and porosity are well correlated; so mapping impedance should help high-grade better locations. With added well data (including shear velocity), elastic inversion can be performed to help highlight variations in density, Poisson’s ratio, and rock strength. Maps indicating “fracability” are the ultimate goal of elastic inversion. While it is easy to create apparent rock property treasure troves from seismic datasets, getting value from the exercise requires careful calibration with multiple wells combined with a well-acquired and processed 3-D dataset.
Ultimately, pursuit of Eagle Ford acreage and designing of an Eagle Ford drilling campaign is best accomplished through comprehensive understanding of geologic framework coupled with focused interpretation of seismic. Eagle Ford currently is one of the most popular shale plays and presents ample opportunities to make and lose money. Smart operators can use the tools available to study the target section while recognizing limitations of the technology.