Simulating the Chemical Interaction of Injected CO2 and Carbonic Acid
- Dennis Denney (JPT Senior Technology Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- July 2013
- Document Type
- Journal Paper
- 125 - 127
- 2013. International Petroleum Technology Conference
- 1 in the last 30 days
- 96 since 2007
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This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 16703, "Simulation of the Chemical Interaction of Injected CO2 and Carbonic Acid Based on Laboratory Tests in 3D Coupled-Geomechanical Modeling," by Rahim Masoudi, SPE, and Mohd Azran Abd Jalil, Petronas; Chee Phuat Tan, SPE, David Press, SPE, John Keller, and Leo Anis, SPE, Schlumberger; and Nasir Darman and Mohamad Othman, SPE, Petronas, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.
The M4-field reservoir is approximately 2000 m below sea level in a water depth of approximately 120 m. A carbon dioxide (CO2) geological-storage study was carried out to determine the feasibility of injecting and storing CO2 in the depleted M4 carbonate gas reservoir. The study used 3D coupled-geomechanical modeling. The water level in the reservoir has risen close to the caprock, which implies a strong aquifer. Laboratory tests were carried out on core samples before and after injecting CO2-saturated brine solution, and the results were used to determine material-strength and elastic-property degradation caused by acid/carbonate interaction.
Controlling the trapping of CO2 in the subsurface is fundamental for safe geological storage of CO2. Rock formations can be impervious enough to act as flow barriers to CO2 over geological periods of time. Delineating such a seal, safeguarding its integrity under operational conditions, and verifying its isolation effectiveness are key objectives in achieving a successful CO2-storage project.
During CO2 injection, the increasing fluid pressure, temperature variation, and chemical reactions between the gas and rock will inherently affect the stress state of the reservoir and its surroundings. Also, the rock mechanical properties may be altered by exposure to CO2 or by pressure and stress changes. Further, rock mechanical properties, pore pressure, in-situ stresses, and the stress evolution under injection conditions control reactivation of a fault and, therefore, risk of fault-seal breach. The effect of the resulting stress and pressure change, the associated caprock deformation, and the fault-seal integrity must be assessed to manage containment performance and leakage-related risks properly.
To address these issues, a good understanding of the flow dynamics, in-situ stresses, pore pressure, and rock mechanical properties in the field is necessary. The fracture initiation, propagation, and containment in the injection zones, and caprock and fault-seal integrity, are related to the in-situ stresses and the coupled pressure/thermal behavior while injecting.
A comprehensive program of mechanical- and petrophysical-property tests was conducted on selected overburden-shale and reservoir-limestone cores from Well A-2. The tests evaluated potential interaction between injected CO2 and the reservoir rock and caprock that could result in a change in mechanical properties of the rock materials and affect CO2 storage and containment.
Shale samples from two core depths and limestone samples from three core depths were tested. The study consisted of comprehensive evaluation of near-identical sets of samples from each core depth. One set of samples was tested without being treated with CO2, while the other set of samples was tested after CO2 injection to simulate reservoir-injection conditions. A standardized CO2-injection procedure was used in an effort to quantify the potential effect that CO2 injection has on shale and limestone properties under controlled test conditions.
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