Transient Flow In Naturally Fractured Reservoirs And Its Application To Devonian Gas Shales

Abstract

ABSTRACT For many years gas has been produced naturally from Devonian shales throughout the Appalachian Basin at rates which made them commercially feasible. In 1975, because of the deteriorating gas supply situation in the United States and increasing demand for energy, the U.S. Department of Energy (DOE) established the Eastern Gas Shales Project (EGSP) as part of the Unconventional Gas Recovery (UGR) program to study and characterize and to develop economically feasible technology for further exploitation of Devonian shale gas reservoirs. Devonian shale gas reservoirs typically are characterized by a low storage, high flow-capacity natural fracture system fed by a high storage, low flow-capacity rock matrix. In this study analytical solutions are developed to analyze the basic fractured reservoir parameters that control well productivity. These parameters include fracture system porosity and permeability, matrix porosity and permeability, and matrix size. It is shown that the conventional well test method does not usually work for fractured Devonian shale gas reservoirs. For most cases, the semilog plot of the drawdown and buildup data does not show two parallel straight lines with a vertical separation. Numerical solutions are also used to include the Klinkenberg effect and desorption in the shale matrix. INTRODUCTION Fractured reservoirs have been studied for several decades. However, during the last three decades, most reservoir engineering studies have been directed toward homogeneous formations. The earliest discussions of fractured reservoir performance was the analysis of the Spraberry Field in West Texas.1 In 1959, Pollard2 presented a method to determine fracture volume from pressure buildup data. The Pollard method was extended by Pirson and Pirson3 to calculate the matrix volume of a fractured reservoir. One of the classic papers on fractured reservoirs by Warren and Root4 considered a dual porosity system which consisted of a fractured porous medium in which matrix blocks acted as a uniformly distributed source. Natural fractures are replaced by equivalent sets of horizontal and vertical fractures. Warren and Root presented an approximate analytical solution for naturally fractured reservoirs based on the Barenblatt and Zheltow formulation.5 They showed that the semilog plot of pressure drawdown or buildup data for an infinite reservoir displaces two parallel straight lines whose slopes are related to the flow capacity of the formation. The vertical separation of these straight lines is related to the relative storage capacity of the fractures. Warren and Root also showed that the Pollard2 and Pirson and Pirson3 techniques could lead to erroneous results in some cases. Odeh6 presented a model similar to that of Warren and Root4. His results did not displace two parallel straight lines. He concluded that fractured reservoirs cannot be distinguished from homogeneous ones. Later, Kazemi7 presented numerical solutions for fractured reservoirs. The Kazemi model consisted of a set of uniformly spaced horizontal matrix layers separated by fractures. This model can be considered a special case of the Warren and Root model. Kazemi did not use the Warren and Root assumption (i.e., that flow in the matrix blocks is quasi-steady state). Kazemi, et al.8 studied the pressure behavior of an observation well in a naturally fractured reservoir with an adjacent well producing at a constant rate. This study showed that the early time response was substantially different from that of an equivalent homogeneous reservoir. Crawford, et al.9 analyzed more than 20 field-measured pressure buildup curves in a reservoir known to be naturally fractured and concluded that the Warren and Root model adequately described the buildup response and is, therefore, useful in determining effective fracture permeability.