Injection-Well Testing To Optimize Waterflood Performance

Abstract

A method for injection-well testing is presented that is designed to optimize injection-well operating conditions and to maximize oil recovery from a waterflood without causing unnecessary, damage to the reservoir. This is accomplished by instituting a systematic program for data collection and testing on injection wells. Introduction During the late 1950's and early 1960's, West Texas waterflood experiences, such as premature water breakthrough and poor sweep efficiency caused by improper injection-well operation, indicated the need for a systematic procedure for optimizing injection-well operation. Many waterflood projects were initiated with peripheral or other dispersed patterns having a low ratio of injection wells to producing wells. During the 1960's, when allowables in prorated states started increasing, individual per-well injection rates often were increased to keep abreast of increased withdrawals. These increases sometimes resulted in performance problems that indicated the need for a better understanding of the reservoir and the factors that affect it during waterflood operations. Thus, there evolved a need for a systematic procedure for maximizing injection and producing rates, while allowing for adequate surveillance of reservoir and operating conditions to preclude any reservoir damage that might jeopardize waterflood recovery. This paper presents a philosophy and method for injection-well testing for optimizing injection-well operation, thus maximizing recovery from a given waterflood pattern. Injectivity is optimized by instituting a planned series of step-rate tests, pressure falloff tests, profile surveys, and temperature surveys during an initial start-up period of about I year, and by continuously collecting and analyzing rate and pressure data, pressure transient data, and profile data throughout the remaining life of the injector. Objectives and Basis for Injection-Well Testing The first objective of the systematic injection-well testing approach is to allow maximum pressure differential between the injector and the producer within formation fracture pressure restraints. A simple application of Darcy's law to injection wells shows injection rate to be proportional to pressure differential. Consequently, higher injection rates should result in quicker response and higher production rates. For several reasons it is imperative that this maximum pressure differential be attained below formation fracture pressure. First, the fracture caused by injecting above the formation fracture pressure is not necessarily limited to the oil pay. Fracturing can be to an aquifer or to a nonproductive interval. Thus, injecting above the formation fracture pressure can result in significant ineffective injection that, if carried to extremes, could result in less water effectively sweeping the oil pay. Second, when injecting above the formation fracture pressure, the direction of fracturing is not predictable. JPT P. 1337^