CO and Flue Gas Sequestration During Tertiary Oil Recovery: Optimal Injection Strategies and Importance of Operational Parameters

This paper reports on an optimization study for acid gas injection into a fully depleted oil reservoir by numerical modelling. As a special case, the Zama Keg River Z3Z Oil Pool with one horizontal production well and previous acid gas disposal was considered. Acid gas generation (60 - 80% CO 2 and 20 - 40% H 2 S) and safe geological disposal, or conversion to elemental sulphur with associated emissions, is an ongoing concern at Apache's Zama Gas Plant operations. The opportunity for a possible enhanced oil recovery application in the Zama field was foreseen given that use of CO 2 in combination with H 2 S (acid gas) is known to reduce the minimum miscibility pressure with reservoir oils relative to using pure CO 2 as a miscible agent. Storing H 2 S with the CO 2 in underground reservoirs will double the benefit for the environment in terms of both short- (mainly H 2 S) and long-term (mainly CO 2 ) effects to the environment. Ten (10) pinnacles were selected as potential candidates for a pilot project of acid gas injection (sequestration and EOR). Optimal conditions that maximize the oil recovery and the amount of acid gas sequestered were identified for one of these ten pinnacles-the Zama Keg River Z3Z Pool. Special attention was given to breakthrough times, incremental oil recovery and CO 2 /H 2 S sequestration volumes. After constructing the static reservoir model using the available data with stochastic/geostatistical techniques, history matching was performed. The compositional simulation option of a commercial simulator (ECLIPSE) was used for this purpose. Available PVT data were used and other data needed were generated using correlations. A number of different injection scenarios were then tested for the combination of optimum incremental oil recovery and acid gas sequestration. The following parameters were considered in the optimization study: a) miscibility; b) gravity override; c) cyclic injection; d) injection rate; and, e) injection and production well constraints (completion). Optimum injection strategies yielding maximum oil recovery and maximum acid gas storage, as well as delaying breakthrough time, were evaluated for these cases.