Stepping on Screening and Feasibility of Gas Development with In-Situ CO2 Sequestration in Associated Aquifer of a Giant Contaminated Offshore Field
Authors: Tiwari P. K. , Mazeli A. H. , Musa I. H. , Mohamad M. N. , Wan Sagar S. F. S. , Che Mat M. N. F. , Sabri S. N. M. , Othman H. , Dzulkefli F. S. , Sahad S. M. , Khanifar A. , Leem J. , Trianto A. , Leite R. J. , Tewari R. D. , Tan C. P. 
Published: October 2023

Abstract
As the energy sector seeks to decarbonize while still relying significantly on natural gas, the industry is turning to the development of offshore, highly contaminated gas fields to bridge the gap between supply and demand. However, the development of these fields is both technologically and financially demanding, and associated projects involve significant risks and uncertainties that must be carefully managed. This study examines the feasibility of developing a giant contaminated gas field with in-situ CO2 sequestration, as well as the strengths and weaknesses of various components of a CO2 storage hub located offshore in Malaysia.
A comprehensive workflow was developed to evaluate the feasibility of in-situ injection in an associated aquifer, using an integrated approach that combined petrophysical, geophysical, geological, geomechanical, and fluid dynamics knowledge of the storage site. The integrated containment assessment was conducted to prevent potential leakage from existing exploration wells, faults, or diffusion across shale/coal layers that could contaminate hydrocarbon layers. Geomechanical modeling was carried out to assess the potential for fracture margin available for CO2 injection into target aquifers and the potential risks associated with fault reactivation and upliftment. Finally, dynamic simulation was conducted to demonstrate the feasibility of CO2 storage in associated aquifers by pressure management while creating voidage from hydrocarbon production. Multiple injection scenarios were simulated to maximize storage capacity by producing water from the aquifer leg of selected hydrocarbon reservoirs while maintaining the fracture margin.
Results from the screening and coupled simulation indicate that the significant distance between hydrocarbon producers and CO2 injectors does not create enough pressure sinks, adversely affecting the initial injection rate. To address this issue, the optimal locations of injectors and producers were determined to achieve efficient injection rates and maximize the safe volume of CO2 injection. To maximize the storage capacity with delayed CO2 breakthrough, the placement of CO2 injectors far from the gas-water contact and optimizing the rate of CO2 injection with additional water producers were found to be effective in avoiding CO2 recycling while maintaining reservoir integrity. The study concludes that gas production and CO2 injection in the water leg of the same reservoir are technically and economically feasible. The selected well placement and injection/production rates suggest that a CO2 breakthrough may occur after 20 years.
The study identifies the essential factors that enable the storage of CO2 in the associated aquifer of gas fields planned for development. Furthermore, it highlights the strengths and weaknesses of the factors that impact the planning, execution, and integrity of the storage process, providing valuable insights for effective management.