Physical Simulations of CO2–Oil–Brine–Rock Interaction at in situ Pressure-Temperature Reservoir Conditions
To understand the interaction of CO2 and sandstone saturated formation water after CO2 injection under reservoir condition, we designed two sets of CO2-displacement experiments. The first experiment (oil-free) uses arkose sandstone saturated with formation water, while the second experiment (oil-bearing) uses arkose sandstone containing both formation water and oil. Both experiments were undertaken at the same P-T condition. Compared with the oil-free sandstone experiment, the presence of oil can substantially reduce the reaction degree between fluid with CO2 and sensitive minerals. The corrosion rates of the K-feldspar and the carbonate minerals for the oil-bearing experiment are 1/5 and 1/4 of that for the oil-free experiments, respectively. For the silicate minerals represented by the K-feldspar, the presence of oil mainly delays the corrosion in the experiment, and reduces the equilibrium corrosion rate. For the carbonate minerals, the presence of oil mainly affects the corrosion at the beginning of the experiments, and reduces the corrosion rate once it reaches to its maximum. The core permeability is reduced after the CO2-water flooding for both the oil-free and oil-bearing cases. The reduction in permeability resulted from the presence of clay particles released by the dissolution of the carbonate cement, which travel in the fluid flow path and accumulate at pore throats. The results provide new insights into CO2 trapping mechanisms in depleted oil and gas reservoirs, and into the potential formation damage that may result from massive injections of CO2 into reservoirs during enhanced oil recovery programs.
AAPG Datapages/Search and Discovery Article #90216 ©2015 AAPG Annual Convention and Exhibition, Denver, CO., May 31 - June 3, 2015