Optimizing Reservoir Oil Displacement and CO2 storage in the Texas Farnsworth Unit
A core flooding setup was built to replicate Morrow B Reservoir conditions (4400psi and 168°F) in the Farnsworth Unit (FWU), Ochiltree County, Texas. The core and oil samples were obtained from the reservoir pay zone (7680 ft. subsurface). The Morrow B is coarse subarkosic sandstone deposited as part of an incised valley fluvial system. Brine salinities from 1000 to 225,000 ppm were used for the brine/CO2 relative permeability test; WAG and SWAG ratios of 1:3, 1:1 and 3:1; and four different brine/CO2 injection sceneries were tested.
Imbibition and drainage relative permeability curves were determined for the brine/CO2.Recovery factor, water cut, gas cut, injected and produced water pH, and produced and remaining oil were determined for each of the oil recovery tests performed. Results show that salinity has little effect on the displacement of brine and CO2, simultaneous injection of brine and CO2 with a higher CO2 cut is better than alternating brine with CO2. Finally, CO2 injected first followed by brine had a higher recovery in this system then brine followed by CO2.
Results show optimum methods for maximizing oil recovery, although in the cases such as the co-injection of brine/CO2, other factors such as practical operations and relative permeability may prevent recommended implementation. This work is providing guidance for FWU operations and can aid in other projects.
Funding for the project is provided by DOEâs National Energy Technology Laboratory (NETL) through the Southwest Regional Partnership on Carbon Sequestration (SWP) under Award No. DE-FC26-05NT42591. We also thank Chaparral Energy LLC, the site operator of the FWU for their collaboration and support on the project.