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Keywords

CO2-N2 injection, CMG-GEM, EOR, fluid displacement, high-pressure reservoirs, injection strategies, minimum miscibility pressure, PETREL, reservoir simulation, water-alternating-gas

Document Type

Research Article

Abstract

This paper presents a study on the numerical optimisation of CO2 injection in sandstone reservoirs to maximise oil recovery. Using PETREL and CMG-GEM, the research explores various injection strategies, including Water-Alternating-Gas (WAG), miscible CO2, and CO2-N2 injection. The model was created based on a publicly available research paper on an onshore oil field in the Sirt Basin, Libya. The model was validated using historical production data from January 1967 to January 2003, resulting in a Global History Matching Error of 10.37%, indicating satisfactory accuracy. For miscible CO2 injection, the optimal maximum injection rate was 30 MMcfd. In the case of WAG, a 6-month cycle with a maximum water injection rate of 1000 bbl/d was determined to be most effective. For CO2-N2 injection, a mixture of 50% CO2 and 50% N2 at 30 MMcfd was used. In this high-pressure reservoir, CO2 and CO2-N2 injections yielded higher recovery rates than WAG despite the lower mobility of gases. The high reservoir pressure of 4000 psia and low-pressure differentials during injection made gas injection particularly effective due to compressibility. The findings underscore the significance of customising injection strategies to reservoir conditions to maximise oil production.

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Publication Date

31-12-2024

First Page

52

Last Page

61

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