Controls on Gas Production, New Albany Shale, Northern Biogenic Trend

Steven M. Ferris
Nytis Exploration Company, Catlettsburg, KY 44129, [email protected]

Analysis of a conventional core of the New Albany shale section from a well in Owen County, Indiana sheds light on many parameters that control production rate and ultimate recovery in this developing gas play. Ultimate recovery is determined primarily by adsorbed gas content and reservoir pressure which in turn are controlled by biogenic activity, thermogenic maturity and burial depth. Fracture spacing and orientation, matrix permeability, and degree of saturation control production rate.

Matrix porosity ranges from 1.9% to 7.5%. Reservoir permeability ranges from about 70 to 160 nanodarcies (nd) with most of the section near or over 100 nd, the threshold for medium grade reservoir. Mobile oil saturations over 25% of pore volume in a portion of the core has reduced permeability to below 100 nd.

Gas content is shown to vary with Total Organic Carbon (TOC). The Langmuir Volume for rock with a TOC of 8% (about average for the New Albany in the well) is just under 120 scf/ton methane. At actual reservoir pressure, the storage capacity is approximately 52 scf/ton with the actual gas content of 28 scf/ton - indicating a significant degree of undersaturation. The initial reservoir pressure was approximately 550 PSI. A pressure drawdown of approximately 300 psi is necessary before gas from the majority of the reservoir will desorb. Initial gas production from the well was likely free gas stored in the natural fractures but gas will not desorb and flow to the well bore until the reservoir pressure decreases through water production.

AAPG Search and Discovery Article #90095©2009 AAPG Eastern Section Meeting, Evansville, Indiana, September 20-22, 2009