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Assessment of CO2 Enhanced Recovery in Shale Gas Reservoirs: Preliminary Results from a Pilot Test in the Devonian Ohio Shale, Johnson County, Kentucky

Nuttall, Brandon C.; Riestenberg, David E.; Godec, Michael L.; Butsch, Robert J.

In 1993, the U.S. DOE conducted five CO2/sand fracs in the Devonian Ohio Shale in eastern Kentucky to compare the effectiveness of cryogenic with hydraulic and nitrogen stimulations. The study concluded that CO2 fracs clean up faster and demonstrate higher flow rates than conventional stimulations. Subsurface assessment of sequestration opportunities suggests black shale is both an effective seal for carbon storage in deeper reservoirs and a potential target for sequestration. In 2005, a study of adsorption in the Ohio Shale in Kentucky concluded CO2 is preferentially adsorbed with respect to CH4 at an average volumetric ratio of 5:1. Preferential adsorption may contribute to the enhancement of CH4 production rates. In 2007, the Kentucky General Assembly passed an energy incentives bill that included a mandate and funding to test the black shale for CO2 enhanced gas recovery. A new study was initiated to identify candidate wells, conduct reservoir modeling to design a test protocol, and conduct a pressure transient test simulating recompletion of a well to acquire data to improve understanding of enhancing production from gas shales.

An existing vertical shale well in Johnson County, eastern Kentucky, was identified for CO2 injection testing. The site also includes a shallow twin well drilled to the Mississippian Big Lime carbonate and two offset shale wells for pressure monitoring. The test well was drilled in 2002 and is cased, cemented, perforated in the Mississippian Berea Sandstone and Devonian shale, completed with a nitrogen frac, and exhibits a shut-in pressure of 320 psia. Pretest spinner and reservoir saturation logs were run and will be compared to a suite of post-test logs. Downhole memory gauges were installed to acquire a continuous record of bottom-hole temperature and pressure. Surface pressure and temperature data loggers were installed on the test well and each monitoring well. Tubing and packer were run to isolate the perforated interval in the Ohio Shale below 1,264 feet. Up to 100 tons of CO2 was injected over three days in September 2012 at up to 980 psi and flow rates to 1.5 Mcf per minute with shut-in periods allowed for pressure fall-off. This presentation will summarize the results of analyses conducted to date on the data collected during this test. Data and insights acquired during this test are expected to improve understanding of CO2 utilization and the possibilities for enhanced recovery in shale gas reservoirs.


AAPG Search and Discovery Article #90163©2013AAPG 2013 Annual Convention and Exhibition, Pittsburgh, Pennsylvania, May 19-22, 2013