THE CONTROL OF THE DIAGENETIC SEQUENCE AND BURIAL HISTORY ON CHEMOMECHANICAL RESPONSES DURING CO2 INJECTION INTO SANDSTONE

CO₂ injection into subsurface reservoirs impacts fluid-rock equilibria, including the generation of acid that alters minerals, which can change porosity, permeability, and rock mechanical properties. We have conducted nineteen flow-through experiments involving the brackish solution from the reservoir with and without dissolved CO₂ at reservoir or slightly elevated pressure and temperature conditions to explore coupled chemomechanical processes from several hydraulic flow units of the Morrow B sandstone from the Farnsworth Unit of the Anadarko Basin in Texas. Evaluation of fluid chemistry, post-test thin sections, and X-ray computed tomography indicated dissolution of carbonate cements, alteration of chlorite and siderite to iron oxide, and precipitation of clays. We observed variable porosity increases and decreases. Some cores underwent permeability decreases due to migration of fines or secondary mineralization, but other cores increased in permeability due to dissolution, leading to more connected flow paths. Pre- and post-test ultrasonic wave velocity measurements generally decreased from mineral dissolution. We also conducted tensile strength tests on four subsamples from many of the cores and generally found negligible changes. However, we did observe tensile strength weakening in a core dominated by poikilotopic calcite cement. The minimal change in tensile strength is due to quartz overgrowth cements that were minimally altered and formed early to provide structural support. Cement distribution and abundance for more reactive mineral phases also control the mechanical response. In addition, the Farnsworth Unit is at a lower burial depth with lower effective stress and pore fluid pressure than in the past, which also led to minimal damage. We conclude that the characterization of cement timing, mineralogy, and texture and an understanding of the burial history of the reservoir provide critical information that can be used to predict the risks associated with CO₂ injection into subsurface reservoirs.

Funding for this project is provided by the U.S. Department of Energy’s National Energy Technology Laboratory through the Southwest Regional Partnership on Carbon Sequestration under Award No. DE-FC26–05NT42591. SNL is managed and operated by NTESS under DOE NNSA contract DE-NA0003525.