Abstract

Carbon dioxide injection in the Dollarhide Devonian reservoir commenced in May 1985. Subsequently, CO injection was expanded to an area of the majority southern fault block. As of May 1995, CO injection has been implemented in the entire Devonian formation in five phases. Hybrid CO injection was chosen to be the primary mode of operation. During the course of this project, the operator experienced reduction in injectivity when switching to WAG after injecting a 10% hydrocarbon pore volume CO slug in phases 1 and 2. Oil production consequently decreased due to reduced injectivity. This study was designed to answer operation related questions. We selected a 5-spot pattern in the southern fault block for this study partly because it had the longest production history with hybrid CO injection, and also because the study area was not complicated by faults. Forecasts were made over a period of twenty years for four scenarios. The cause of sustained high water cut at the central producer was also investigated. A fine grid model was used in this study in order to compare more accurately the recovery efficiencies between a single CO slug and hybrid CO injection, and to investigate the advantages of operating at a lower pressure.

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