Barnett Shale Gas-in-Place Volume including Sorbed and Free Gas Volume
Matt Mavor, Tesseract Corporation
Gas contained within unconventional shale gas reservoirs is stored by sorption within micro and mesoporosity of the rock matrix and by compression within the macroporosity and natural fracture porosity of the reservoir. Mitchell Energy cored the Kathy Keel #3 Barnett Shale well (Denton Co. Texas) with conventional and pressure coring equipment in the upper and lower Barnett to obtain core samples and data to obtain data required to estimate the gas-in-place volume stored by each mechanism. An extensive suite of data was measured that included desorption of samples to determine the sorbed gas content and gas composition as well as methane and ethane sorption isotherm data to estimate the sorbed gas storage capacity. These data were combined with other shale gas core analyses including TOC content, routine porosity, grain and bulk density, water saturation, capillary pressure, x-ray diffraction, and cation exchange capacity data to develop a log analysis model that combined log and core analysis data.
The estimates of the gas-in-place volume were significantly greater than past data measured and published in 1992 by Gas Research Institute (GRI) had indicated. The volume of gas stored by sorption within the pressure core interval was 120 scf/ton at an average TOC content of 5.2% compared to GRI’s estimate of roughly 42 scf/ton. The sorbed gas volume accounted for 61% of the total gas-in-place volume that included both sorbed and free gas. Free gas volume in-place was determined by log analyses methods that were calibrated to core analyses to obtain in-situ estimates of porosity and water saturation.
While the gas-in-place volume is large, recovery of the gas volume is hindered by relatively low absolute permeability of the reservoirs. Recovery of the sorbed gas-in-place requires that operating pressures be kept low as possible to allow the gas to be released from the sorbed state. Recovery factor depends upon the decline in average reservoir pressure. Calculation methods for gas recovery factor will be discussed to illustrate that recovery factor may range from 10 to 25% of the total gas-in-place volume with conventional technology.
AAPG Search and Discovery Article #90010©2003 AAPG Southwest Section Meeting, Fort Worth, Texas, March 1-4, 2003