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FRANTZ, JOSEPH H., JR., S. A. Holditch & Associates, Inc., Pittsburgh, PA, KENT GUIDRY and DON LUFFEL, ResTech Houston, Inc., Houston, TX, and WEST KUBIK, K&A Energy Consultants, Tulsa, OK

ABSTRACT: Evaluation of the Berea Sandstone Formation in Eastern Pike County, Kentucky

Geologic, reservoir, and stimulation descriptions for the Berea sandstone formation in eastern Pike County, Kentucky, were obtained by integrating geologic, core, log, well test, and hydraulic fracture analyses. Our results indicate the Berea in this area is a very low-permeability (0.1 md), naturally fractured, multilayer reservoir with porosities ranging from 5 to 9%, water saturations from 30 to 70%, net pays from 30 to 70 ft, and reservoir pressures from 700 to 800 psia. Clays, mica, cement, and very fine quartz grains account for the low permeability. We identified two independent, noncommunicating Berea sand packages, each with its own system of short, near-vertical, natural fractures. Natural fractures were observed in the core, on the formation microscanner log, and on the bor hole television in both the upper and lower sands. In both sand packages, an anisotropic fracture network exists consisting of a dominant northeast-southwest-trending set, and a less abundant intersecting set. We determined the hydraulic fracture propagated northeast-southwest, and thus parallel the most closely spaced natural fractures, limiting the impact of the hydraulic fracture treatment in the Berea. In addition, the natural fracture frequency is inferred to be highly variable between wells based on long-term production from older, Berea-only completions in this area ranging from 40 million scf to 2.5 Bdcf.

The Gas Research Institute (GRI) has been sponsoring a cooperative well program with Ashland Exploration, Inc. (AEI) during the past two years targeting the Devonian Shale and Berea sandstone formations in Pike County of eastern Kentucky. Operators typically complete both the shales and Berea in one well bore in this area. This presentation summarizes the research results of the Berea cooperative well, the COOP 2 (Ashland FMC 80). The specific objectives of the Berea evaluation in the COOP 2 were to develop an integrated reservoir description for stimulation design and predicting long-term well performance, identify geologic production controls, determine the in-situ stress profile, and develop Berea log interpretation models for gas porosity and stress. To satisfy these objectives, d ta were collected and analyzed from 146 ft of whole core, open-hole geophysical logs, including formation microscanner and digital sonic, in-situ stress measurements, and prefracture production and pressure transient tests. In addition, data from a minifracture, a fracture stimulation treatment, and postfracture performance tests were analyzed.

We determined the integrated reservoir/hydraulic fracture descriptions from analyzing the data collected in the open- and cased-hole, in addition to the log interpretation models developed to accurately predict gas porosity and stress profiles. Results can be applied by operators to better understand the Berea reservoir in the study area, predict well performance, and design completion procedures and stimulation treatments. The methodology can also be applied to other tight-gas sand formations.

AAPG Search and Discovery Article #90995©1993 AAPG Eastern Section Meeting, Williamsburg, Virginia, September 19-21, 1993.