Numerical Simulation of Heavy Oil Recovery for a Niger-Delta Reservoir

Abstract This research provides a comprehensive numerical analysis of the chemical flooding process in a heavy oil reservoir located in the Niger Delta region. A thorough reservoir model was created for the case study utilizing the CMG simulator program, which includes the incorporation of geochemical modeling. Initially, the reservoir is evaluated based on its depth and the viscosity of the fluid to determine the most suitable Enhanced Oil Recovery (EOR) technique for achieving maximum recovery. Following that, various chemical injection strategies were implemented employing alkali, surfactant, and polymer to determine the primary chemical agents accountable for the enhanced recovery factor. The reservoir case study is a clastic reservoir that has a depth of 7400 ft and a pay zone thickness of 12 ft. The Petrel software was utilized to construct the stationary representation of the reservoir, which was subsequently imported into the CMG 2021 simulator for comprehensive dynamic modeling and simulation. A historical match of the reservoir model was performed to accurately align it with the measured field data obtained from the reservoir. In order to accomplish this purpose, different control variables were modified within an operational restriction to obtain a history match of field output rates. The feasibility of the injection schedule was assessed at the pre-evaluation stage in order to choose the most efficient injection plan from both a technical and economic standpoint. The injection scheme comprises Polymer injection, Alkali-Surfactant injection (AS), Alkali-surfactant-polymer (ASP) injection, and nanofluid technology. In order to minimize the bypassing of crude oil, a pre-flush and post-flush water flooding technique was implemented in these injection schemes. In the post-evaluation step, the injection technique is optimized to maximize the net present value (NPV) of the project. The initial simulation findings suggest that injection sequences including polymer are the most effective due to its viscosity and its capacity to enhance oil movement in the reservoir. By combining Polymer injection with a sequence of AS flooding and pre-flush and post-flush water injection, the recovery factor from the reservoir was maximized. This was achieved through the combined benefits of high viscosity polymer mobility and the lowering of interfacial tension (IFT) and alteration of wettability caused by AS flooding. In summary, the introduction of a buffer polymer chemical slug following the initial pre-flush waterflood demonstrated the most favorable production performance, resulting in a recovery rate of up to 20%. An economic study of this injection plan was conducted by taking into account oil prices that are contingent upon the current market conditions.