Four pattern-scale CO2-foam field trials were conducted to determine the effectiveness of foam in reducing CO2 channeling, to evaluate the economic potential of the process, and to develop application criteria and procedures. The trials were conducted under various process and geologic conditions so that the resulting technology would be applicable in a number of different CO2 floods. Two different surfactants, Rhodapex (formerly Alipal) CD-128 and Chaser CD-1045, and two injection methods, alternating vs. coinjection of CO2 and surfactant, were tested in San Andres (west Texas) and platform carbonate (southeast Utah) reservoirs. In all, 161,000 lbm of active surfactant was injected in the four field trials, with one well undergoing foam treatment for as long as 18 months. The treatments resulted in a significant reduction in gas production and indications of increased oil production. The total cost of the four treatments (excluding labor and overhead) was $700,000.
In recent years, foam has been applied to reduce gas channeling in steam, hydrocarbon gas, and CO2 miscible floods, and significant academic and industry research has focused on the processes involved. Application of foam involves injecting a surfactant along with water and gas into the reservoir through either an injection or a producing well. This work is limited to foam applied through injection wells. The surfactant stabilizes liquid films (lamellae) that form in the rock, thus trapping and reducing the permeability of the porous media to gas. Reports of five CO2-foam field treatments have appeared in the literature; Ref. 5 reports a recent major U.S. Dept. of Energy (DOE)/industry treatment that has highlighted interest in the process. CD-128, one surfactant used in all the treatments reported here, has been studied extensively for use as a CO2-foaming agent.
Potential Benefits of Foam. The benefits of foam in CO2 flooding may include (1) improved CO2 utilization efficiency (reduced CO2 requirement per unit of oil produced), (2) reduced gas production and associated processing costs, (3) increased oil recovery (through improved reservoir sweep), and (4) accelerated oil production. Channeling and premature breakthrough of the high-mobility gas can result in increased CO2 requirements and increased gas processing costs. Foam reduces the gas mobility, and may thereby reduce gas channeling and the relative rate of gas production. Oil recovery may increase because the bottomhole injection pressure can often be increased with foam, which may result in increased CO2 flow to previously unswept areas of the reservoir.