A Comparative Analysis of Natural Flow and Water Flooding for a Black Oil Reservoir Using CMG IMEX Simulator

Abstract

Abstract Maintaining oil and gas production presents a significant and ever-growing challenge within the hydrocarbon industry. As hydrocarbons are extracted from a reservoir, the natural pressure that drives their flow toward the wellbore inevitably declines. This phenomenon, known as reservoir pressure depletion, significantly hinders the effectiveness of primary recovery methods, which rely solely on this inherent pressure for production. The limitations of relying solely on natural flow for hydrocarbon recovery cannot be overstressed. The study underscores the significant benefits of implementing improved oil recovery techniques, particularly water flooding, to maximize oil and gas production from the reservoir. This study investigated the effectiveness of improved oil recovery techniques for a black oil reservoir using CMG IMEX reservoir simulation software. A detailed digital reservoir model was constructed, incorporating fluid properties, rock characteristics, and well configurations representative of a mature oil field. The reservoir initially contained an estimated 88.8 million stock tank barrels (STB) of oil, 132 million STB of water, and 122 billion standard cubic feet (SCF) of gas. The research compared two recovery scenarios simulated over 20 years (2016-2036). Natural depletion, relying solely on solution gas drive without aquifer support, resulted in a low ultimate recovery, reaching only 9% of the original oil in place (OOIP) and 20% of the initial gas in place (IGIP). While the presence of an aquifer slightly improved recovery, it also substantially increased water production. Implemented with 10 producers and 2 injectors, water flooding demonstrated improved sweep efficiency. This technique recovered approximately 21% OOIP and 45% GIIP without aquifer support. Water flooding yielded even better results when combined with aquifer support, reaching 27% OOIP and over 50% GIIP.