Effect of H2S and Pressure Depletion on the CO2 MMP of Zama Oils

Abstract

Abstract Phase behaviour and minimum miscibility pressure measurements were carried out to evaluate the potential of applying miscible CO2/H2S flooding in the Zama reefs of NE Alberta, Canada. Since there is some variability in the properties of oils from different wells or reefs, the measurements were carried out on recombined reservoir fluids from two different wells. The injection solvent will be supplied from a nearby gas plant that is expected to produce CO2/H2S streams with a range of compositions due to a number of operational factors. Accordingly, three solvent injection gases were considered: pure CO2 and CO2 containing 20 and 40 mol% H2S. Minimum miscibility pressure (MMP) measurements were carried out using the rising bubble apparatus (RBA). The MMP decreased almost linearly with the amount of H2S in the injection gas in the range of compositions studied. Some evidence of precipitation of solids was observed. Measurements were also carried out to determine the CO2 MMP of these reservoir fluids as they were depleted of gas through a differential liberation procedure. The results show that the MMP decreased with decreasing liberation pressure. Key properties of the liberated reservoir fluids were also measured and compared with those of the recombined reservoir fluids. The results show that miscible flooding with sour acid gas is feasible in this case, and could provide an excellent means of storing/sequestering these gases while improving oil recovery. Introduction Vertical gasfloods have an excellent track record for producing additional oil. For example, hydrocarbon miscible floods have been carried out in a number of Canadian reefs(1–5). Vertical gravity-stable carbon dioxide floods were reported in three US fields(4–8), also with excellent additional oil recoveries. The Zama Field(9) is located in northeastern Alberta and contains a large number (600 – 800) of relatively small pinnacle reefs with up to 1.5 ? 106 m3 (10 mmbbl) of original oil in place (OOIP). The wells selected for this study produce from the Keg River Formation. Al-Dilwe and Asghari(10) described the reservoir and its production history from the 1960's. The produced oil and gas are sour and contain an appreciable amount of carbon dioxide. The centrally located Zama Gas Plant (operated by Apache Canada Ltd.) removes the H2S and CO2 from the produced gases by amine absorption. These acid gases constitute an excellent miscible flooding agent for the field, thereby achieving the double advantage of increasing the oil recovery and providing storage capacity for these gases. Trivedi et al.(9) simulated different strategies for solvent injection to maximize oil recovery and gas storage as well as delaying breakthrough, and found that pressure maintenance is a key factor in the operation. A significant degree of acid gas breakthrough is expected to occur due to the reservoir heterogeneity represented by these Zama/Keg River pinnacles. Breakthrough will occur at H2S concentrations that are too high to process through the existing amine systems. To accommodate early breakthrough, recycle compression is to be installed in order to bypass the amine systems and re-inject acid gas back into miscible flooded pinnacles.