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The Discovery, Reservoir Attributes, and Significance of the Hawkville Field and the Eagle Ford Trend: Implications for Future Development
The discovery of the Hawkville Field in LaSalle County, Texas, in October 2008 by Petrohawk Energy Corporation marked the first commercial production from the Eagle Ford Shale. Since that time the field has proved to be one of the most significant discoveries in North American oil and gas history. With cumulative production through October 2014 of over 1 billion barrels and 4.4 trillion cubic feet of natural gas, the field has been one of several that has reversed the decades’ long trend of domestic oil production decline and has been a primary reason that U.S. oil production has almost doubled in the last 8 years.
The process of exploration for unconventional resources from shale reservoirs has some distinct differences from exploration for conventional reservoirs. The best way to describe the difference is that when exploring for large-scale shale reservoirs one must take an “inside out” approach versus an “outside in” approach. This applies to all aspects of the exploration process: prospect identification, geophysical analysis, stratigraphic analysis, and reservoir analysis. In the case of the discovery process for the Eagle Ford, the Petrohawk exploration team utilized three key findings to support the testing of the play: a key petrophysical data point, a set of key geochemical data points, and a geophysical model of the reservoir.
After the initial phase of exploration was deemed commercially successful, the appraisal process was primarily driven by a rigorous petrophysical analysis and associated work flows. The key building block to the petrophysics was applying the extensive data obtained from the whole-core analysis and calibrating those data to the regional subsurface data across the play. While the basic core and log data that is common to all reservoir analysis, such as porosity, permeability, and hydrocarbon saturation, forms the foundation for the understanding of the reservoir quality, the data derived from whole core such as mineralogy models derived from x-ray diffraction (XRD) and scanning electron microscope (SEM), geochemical characteristics such as total organic carbon (TOC), thermal maturity (Ro), and pyrolysis oven temperature resulting in maximum generation of hydrocarbons (Tmax) and geomechanical attributes such as Young’s modulus, Poisson’s ratio, and other elastic measurements are critically essential to obtaining a full understanding of the quality of a shale reservoir.
Upon entering the development phase of a large-scale shale reservoir such as the Eagle Ford, which covers over 7 million acres, the focus shifts away from the previously discussed nanoscale data to more macroscale data such as 3D seismic and the regional geologic distribution of the reservoir facies. Imbedded within the regional facies analysis is the decision regarding the optimum target selection for the horizontal wellbores and the implementation of that operation with the relatively new geologic function of geosteering. While the geologist is a key component of a successful horizontal operation, the real key to success is the collaboration of all technical functions including the drilling engineers, the completion engineers and the production engineers. Never has the need for this interaction between all functions been more critical to success than in large-scale shale development.
It is readily apparent that the Eagle Ford shale has been a highly commercial oil and gas reservoir throughout the South Texas. What has yet to be determined is the economic viability of the Eagle Ford in Mexico. There is little doubt that some area of Mexico will prove to be commercially viable, and the handful of wells that have already been drilled help support that premise. The main question yet to be answered is to what extent the play will reach across Mexico. Regional geology suggests it could be extensive, but much more drilling will need to be accomplished before that premise can be validated.
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