Abstract

Over the last several years, intensive reservoir studies were performed on the Davis formation (known locally as the Pregnant Shale) in the Fort Worth Basin, and the Travis Peak formation in the East Texas Basin. These studies were part of the Gas Research Institute's Tight Gas Sands Program designed to improve the overall understanding of hydraulic fracturing processes and production performance in tight gas sand reservoirs.

The reservoir studies consisted of production data analysis using analytical models and reservoir simulators. In addition, pre-fracture and post-fracture pressure buildup tests were analyzed using both conventional transient analysis techniques and reservoir simulators. This approach allowed us to evaluate various reservoir conditions ranging from simple single-phase, single-layer models to multiphase, three-dimensional models. As such, the analyses provided a more thorough description of the reservoir parameters that control well performance, one of which is the effective drainage area or recovery efficiency.

This paper summarizes the results of the reservoir studies conducted on the Davis formation and the Travis Peak formation and demonstrates the importance of proper reservoir characterization to maximize per well recovery and drainage pattern efficiency.

Introduction

The Davis sandstone, located in the Fort Worth basin of north-central Texas and the Travis Peak sandstone located in the East Texas basin of northeast Texas, have been identified as potential candidates for additional reservoir performance studies.

The studies on the Davis and Travis Peak formations were performed as part of the Tight Gas Sands (TGS) program sponsored by the Gas Research Institute (GRI). This program was implemented to perform research on hydraulic fracturing and to further the gas industry's understanding of the performance of tight gas sands in general.

To learn more about the Davis and Travis Peak formations, intensive cooperative research efforts were initiated with area operators to study the formations. As such, several wells in each basin were analyzed to determine values of formation permeability, the degree of stimulation (skin factor or effective fracture half- length), and drainage area. The analyses consisted of production data history matching using simple analytical models and reservoir simulators ranging from single-phase, two-dimensional models to multiphase, three dimensional models. In addition, prefracture and post-fracture pressure buildup tests (PBU) were analyzed using both conventional transient analysis techniques and various reservoir simulators.

Results of the reservoir analyses indicated both the Davis and Travis Peak formations to be typical of tight gas sand reservoirs, with average permeabilities below 0.1 md. However, analysis of the effective propped fracture lengths and average drainage areas for both areas indicated surprising results. For example, the Travis Peak formation has been drilled on 320 acre spacing, with optional 160 acre spacing. The Davis formation has been drilled on 160 acre spacing, or higher.

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