No abstract

This paper reports on an optimization study for acid gas injection into a fully depleted oil reservoir by numerical modeling. 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% CO2 and 20 – 40% H2S) 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 CO2 in combination with H2S (acid gas) is known to reduce the minimum miscibility pressure with reservoir oils relative to using pure CO2 as a miscible agent. Storing H2S with the CO2 in underground reservoirs will double the benefit for the environment in terms of both short- (mainly H2S) and long-term (mainly CO2) 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 CO2/H2S 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:miscibility;gravity override;cyclic injection;injection rate; and,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. Introduction The natural gas sweetening process produces sales gas and acid gas (CO2 and H2S) as a waste with a high percentage of CO2 in the Zama Field. The catalytic conversion of H2S into element sulphur, commercially called a Clause process, is a good economic process during times of high demand and high prices for sulphur. Reduction in world price of sulphur and the environmental hazard of stockpiling elemental sulphur in large blocks is a cause for concern in the oil and gas industry. Energy producers around the world are focusing on a value-added approach to enhanced oil recovery (EOR) or enhanced gas recovery (EGR) for greenhouse gas (GHG) disposal(1–4). Different injection strategies for CO2 injection, flue gas injection and Water Altering Gas (WAG) with CO2 have been studied and implemented for EOR since the 1970's(5–10). Acid gas was found to be an effective EOR agent since H2S reduces the minimum miscibility pressure (MMP) of CO2(11–13). By 2003, approximately 2.5 Mt CO2 and 2.0 Mt H2S have been stored in depleted oil/gas reservoirs or deep saline aquifers(14).

To permanently remove CO2 from the atmosphere large scale injection of CO2 from stationary sources such as coal fired power plant and heavy oil production into brine filled formation is seen as one of the most viable options. One of the main risks identified with storing CO2 into the subsurface is the potential for leakage through existing wells penetrating the cap rock. The wellbore system has several components which can fail and create leakage paths such as type and placement of wellbore casing and cements, completion method, abandonment and wellbore expansion or contraction by changes in temperature and pressure. Of the 1000 wells in the study area near Lake Wabamun, Alberta 95 wells penetrated the immediate cap rock above the proposed Nisku injection formation and was identified as potential leakage pathways. The leakage risk of these wells was evaluated based on the knowledge of well design, current well status and historical regulation’s in the area. For the subset of 27 well studied on only 4 wells were identified as wells requiring work over which was less of a problem than anticipated. To evaluate the risk of creating leakage paths by thermal and pressure changes caused by CO2 injection, a three dimensional finite-element model was built which used elasto-plastic material models for cement and formation. Multi-stage simulations for casing-cement and cement-formation interactions with temperature enabled elements were conducted. Because of the uncertainty on cement properties in old wells, a parametric study of cement properties was conducted. The simulation results indicated that thermal cooling might reduce near-wellbore stresses which will increase risk of integrity loss in casing-cement and cement-formation. The parametric study reviled that the risk of debonding and tensile failure will increase with increasing Young’s modulus and Poisson’s ratio of the cement under dynamic loading conditions. In addition, low mechanical cement strength will increase risk of shear failure in the cement.

No abstract

No abstract