SPE 158500

The Use of a Transient Multiphase Simulator to Predict and Suppress Flow Instabilities in a Horizontal Shale Oil Well H. Lee Norris III, SPT Group

Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in San Antonio, Texas, USA, 8-10 October 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract Due to its limited drainage radius, the sand face pressure in a hydraulically fractured, horizontal shale oil well will fall rapidly with cumulative production. Once the sand face pressure falls below the bubble point, flow instabilities will increase dramatically. The onset of instability can be predicted using a transient multiphase simulator such as OLGA1, and techniques to minimize instabilities can be quantitatively investigated through simulation. This paper describes flow instabilities in a typical horizontal shale oil well and demonstrates both causes and remedies for fluctuating production rates in the intermediate and latter stages of well life. Through the suppression of production instability, the ultimate recovery of reserves may be significantly increased. Introduction Through the use of horizontal drilling and hydraulic fracturing techniques, oil and gas reserves in previously un-economic, low permeability, shales can be recovered. Upon initial production, the reservoir pressure is frequently sufficiently high that the sand face pressure is above the reservoir fluid bubble point. The resulting single phase liquid flow in the wellbore can be produced at stable rates, simplifying the design and operation of surface facilities. Due to the limited drainage radius, however, the reservoir pressure will fall rapidly with cumulative production. As a result, sand face pressures may fall below the reservoir fluid bubble point within months of the start of production. When this occurs, a vapor liquid flow will occur in the horizontal section of the wellbore, possibly resulting in wildly unstable variations in fluid production rate. Even with hydraulic fracturing, the effective productivity index (PI) is low by conventional well standards, resulting in low reservoir fluid influx rates per foot of horizontal section. At the same time, the mechanical requirements of horizontal well drilling and hydraulic fracturing techniques require horizontal section liners of at least 4 in to 6 in. As a result, fluid velocities in the horizontal section are generally quite low, resulting in a stratified vapor-liquid flow in the horizontal section. This stratified flow produces a large, fairly stagnant, gas volume that can drive strong terrain slugging in the vertical section of the well through periodic gas accumulation and blow out. This vigorous, terrain-induced, slugging is an inherently transient process that depends on the details of wellbore geometry, reservoir fluid properties, reservoir pressure, completion and perforation details, production rate, and multiphase fluid dynamics. As a result, wellbore instability can be predicted only through a transient multiphase flow simulation. In addition, such a simulation suggests techniques for the suppression of the potentially severe fluctuations of well production rates.

Typical Well Simulated In order to illustrate the dynamics of flow instabilities in a horizontal shale oil well, a generic but representative horizontal well employing hydraulic fracturing in a shale reservoir has been simulated. This generic well has the following characteristics: