Abstract
Abstract In this paper we will present the outcome of a study conducted to evaluate the feasibility of large scale injection of sour and/or acid gas into a low permeable carbonate reservoir to enhance oil recovery. Other than for disposal, H2S containing mixtures have rarely been injected as a miscible agent in oil recovery projects. Moreover, the very few projects that have actually been executed are relatively small (generally less than 10 MMscf/d). In this study different recovery processes were evaluated such as water flooding, lean gas injection, sour gas (natural gas with a large H2S content) injection, acid gas injection, acid gas (mixture of H2S and CO2) after a slug of sour gas and CO2 injection. To evaluate these different (EOR) recovery processes, a detailed reservoir description is essential and for this purpose element-models were used. The critical importance of a thorough understanding of reservoir geology and rock properties for miscible gas injection schemes has been confirmed by the experiences of water breakthrough and over-ride in a number of reservoirs in Abu Dhabi and the poor performance of some miscible gas injection projects in the industry. The simulation study shows that miscible acid gas injection is the preferred recovery mechanism for part of the reservoir under study. This is a result of several key factors, including the favorable miscibility with the native oil (lower miscibility pressure with reservoir crude), better solvent for asphaltene, a more favorable mobility ratio due to high acid gas viscosity and density and availability of large quantities of acid gas from the underlying formation. Acid gas is therefore an attractive, low cost, miscible, enhanced oil recovery agent, provided fully adequate corrosion mitigation procedures and HS&E management systems are implemented in the development.
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