Over the past 30+ years, the North American oil industry has constructed over 3,100 miles of CO2 mainline pipeline systems and produced in excess of 1.2 billion barrels of incremental oil from CO2 EOR. In the process, the industry has developed the requisite operating practices of corrosion management, metallurgies, elastomers, compression/pumping, separation, dehydration, and CO2 injection and production well completion and operation. A CO2 EOR project is a capital-intensive undertaking. It involves drilling or reworking wells to serve as both injectors and producers, installing a CO2 recycle plant and corrosion resistant field production infrastructure, and laying CO2 gathering and transportation pipelines. Generally, however, the single largest project cost is the purchase of CO2. As such, operators strive to optimize and reduce the cost of its purchase and injection wherever possible. Total CO2 costs (both purchase price and recycle costs) can amount to 25 to 50 percent of the cost per barrel of oil produced. Note: the volume of CO2 purchased per incremental barrel is typically 4-5 Mcf, although 20-25% of the CO2 is often recycled after the initial phase of injection. Additionally, the initial CO2 injection volume must be purchased well in advance of the onset of incremental production. Hence, the return on investment for CO2 EOR tends to be low, with a gradual, long-term payout. Transportation of CO2 is another primary concern. CO2 can be moved by truck, but pipelines are more economical for large volumes. In highly developed areas, pipeline right-of-way acquisition may be extremely difficult or impossible. Given the significant front-end investment in wells, recycle equipment, and CO2, the time delay in achieving an incremental oil production response, and the potential risk of unexpected geologic heterogeneity significantly reducing the expected response, CO2 EOR is still considered to be a risky investment by many operators, particularly in areas and reservoirs where it has not been implemented previously. Experience has shown that light, low-viscosity oil is preferable for this process and that the probability of a successful CO2 EOR project is increased when the reservoir has: • Low vertical permeability in the case of a horizontal reservoir • No natural water drive • No major gas cap • No major fractures. Many factors therefore play a role in the suitability and economics of CO2 EOR applications, not the least of which are the price of oil and the cost and availability of CO2. Common in CO2 supply contracts for CO2 EOR, is the practice of pegging the CO2 price to the price of oil. Consequently, there can be a substantial gap between a “technically recoverable resource” and a proven reserve volume booked to an oil company’s balance sheet.
"Experience has shown that light, low-viscosity oil is preferable for this process"
I'm doing research on asphaltene precipitation in fawag-co2 injection. It is found out light oil can cause asphaltene precipitation due to low solvency of asphaltene (soluble in high molecular, e.g. heavy oil) . And fawag might be the potential key to solve this problem. Surfactant will create foam and increase the mobility of gas from creating "fingering". but parameters need to be changed until it is optimized. The parameter that i doing are : surfactant type and concentration, injection pressure, water salinity, and fawag ratio.
Im still doing research on this. and hopefully you can provide insight of what parameter that i miss and i should consider?