Assessment of Hydrocarbon in Place and Recovery Factors in the Eagle Ford Shale Play
- S. Amin Gherabati (Bureau of Economic Geology, University of Texas at Austin) | Ursula Hammes (Bureau of Economic Geology, University of Texas at Austin) | Frank Male (Bureau of Economic Geology, University of Texas at Austin) | John Browning (Bureau of Economic Geology, University of Texas at Austin)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- May 2018
- Document Type
- Journal Paper
- 291 - 306
- 2018.Society of Petroleum Engineers
- Eagle Ford
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- 659 since 2007
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Correction Notice: This paper has been modified from its original version to include the following corrections: Katie M. Smye was added as the fourth author in the byline on page 291 and the author biographies on page 306. An Acknowledgments section was also added to page 305. No other content was changed and page numbering was not affected.
In a low-price environment, experts raise concerns about the economic viability of drilling in many locations across the Eagle Ford Shale play area. Although advances in drilling and completion technologies have helped to reduce the cost of production, reservoir quality still plays the pivotal role in drilling decisions. Eagle Ford reservoir quality is controlled by thermal maturity, which affects fluid composition, initial pressure, and petrophysical properties of the rock. This paper—which estimates original oil in place (OOIP), original gas in place (OGIP), and recovery factors (RFs) driven by reservoir quality—integrates geological and petrophysical analyses, fluid-properties characterization, and decline-curve analysis.
For our petrophysical analysis, we calculated total organic carbon (TOC), lithology, porosity, pay-zone thickness, and water saturation for each square mile of the Eagle Ford play. We divided the play into 12 fluid regions on the basis of reported American Petroleum Institute (API) gravity and gas/oil-ratio (GOR) values and available temperature and pressure maps, developing a representative fluid model for each region to calculate a formation volume factor (FVF). The resulting OOIP and OGIP maps show regions of hydrocarbon accumulation. Our decline-curve forecast uses two-parameter scaling curves that are based on 1D, one-phase flow to predict the estimated ultimate recovery (EUR) of approximately 15,500 existing wells with at least 16 months of oil or gas production. We calculated oil and gas RFs for all the wells, and present a map of their distribution across the Eagle Ford play area.
We generated OOIP and OGIP and RF distribution maps that help to improve the estimation of the amount of recoverable hydrocarbon. The maps reveal the areas with the greatest potential for recovery improvement as well as regions with high-recovery success. RFs calculated on the basis of EUR and well spacing are compared with a material-balance RF that is based on pressure and fluid properties. The Upper Eagle Ford can contribute to production, as indicated through RF plots.
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