Using Polymers to Improve CO2 Flooding in the North Burbank Unit

The North Burbank Unit, located in Osage County, was originally discovered in 1920. It has an extensive history of activity, including primary depletion, produced gas cycling, and water and polymer flooding to the point of very high water cut at current conditions. The current oil production rate in the North Burbank Unit is approximately 1,400 BOPD from 360 active wells at a water cut of 99.5%. The North Burbank Unit has a cumulative production of 332 million bbl of oil out of an estimated 824 million bbl of original oil-in-place. Significant reserves are currently available for post-secondary production. CO2 flooding is a good choice considering that the minimum miscibility pressure (MMP) in the North Burbank Unit is lower than the fracturing pressure and CO2 is available from a purely anthropogenic source. This paper demonstrates that a 100-year-old field is not only an excellent CO2 enhanced oil recovery (EOR) target, but is at the forefront of a new synergistic technology to couple EOR and anthropogenic CO2 that would otherwise be released to the atmosphere. It is a logical alternative to reduce CO2 emissions while increasing domestic production. High heterogeneity and high permeability at the top layers are the two main challenges of the North Burbank Unit. Two methods related to polymers are studied to improve CO2 flooding in the North Burbank Unit. One is to add polymers with co-solvent, named CO2 viscosifier, to CO2 to increase CO2 viscosity. The other is to add polymers to water to increase water viscosity during the water-alternating-gas (WAG) process, named polymer-alternating-gas (PAG) flooding. To analyze the impact of CO2 flooding in the North Burbank Unit, five tracts that best represent the characteristics of the field were selected for reservoir modelling. Based on simulation results, the conventional WAG process increased average oil recovery in the North Burbank Unit by 10.89%, and gross CO2 utilization and net CO2 utilization are forecasted to be 11.27 Mscf/bbl and 5.40 Mscf/bbl, respectively. Using CO2 viscosifier and PAG flooding could markedly delay gas breakthrough, reduce gas-oil ratio and increase oil recovery. CO2 viscosifier and PAG are forecasted to increase average oil recovery 7 to 8% more than conventional WAG flooding in the North Burbank Unit. Introduction Although CO2 flooding is a well-established EOR technique, its density and viscosity nature is a challenge for CO2 projects. Low density (0.5 to 0.8 g/cm3) causes gas to rise upward in reservoirs and bypass many lower portions of the reservoir. Low viscosity (0.02 to 0.08 cP) leads to poor volumetric sweep efficiency. In heterogeneous reservoirs with high-permeability zones and natural fractures, the condition is even worse(1). cO2 Viscosifier CO2 viscosifiers (direct thickeners) are the most direct way to increase the viscosity of CO2, hence improving overall sweep efficiency. A high-molecular-weight polymer and co-solvent are blended and pressurized together with CO2 so that CO2 viscosity can be greatly increased before CO2 is injected. A number of studies show that gas viscosifier chemicals can increase CO2 viscosity by an order of one to two and can control CO2 mobility(2-6). However, the main barriers to using viscosifiers include the following: (1) the large volume requirement of co-solvent makes pilot-testing costs prohibitive(7); (2) co-polymers do not dissolve in CO2 unless pressure far exceeds MMP (7); and (3) the environmental impact is negative(8). PAG To overcome the issues of gas breakthrough and gravity segregation, a new combination method is proposed. This new method, termed PAG, combines features of CO2 flooding with polymer flooding to produce chemically enhanced WAG flooding. Coupling polymers with CO2 is expected to improve the efficiency of the current WAG. The main feature of PAG is that the polymer is injected with water throughout the whole WAG process. Zhang et al.(1) conducted an experiment based on Saskatchewan crude, named polymer injection chased with gas alternative water (PGAW). They stated that coupled CO2 and polymer injection gave better recovery and efficiency than WAG and polymer flooding. Majidaie et al.(9) carried out the first coupled CO2 and polymer injection simulation study for light oil based on a synthetic and homogeneous model. This study showed that PAG and WAG have almost the same recovery. He also mentioned that a chemical slug of polymer with surfactant and alkali would significantly increase oil recovery. Workflow In this study, we discuss CO2 viscosifier and PAG flooding in light oils based on the field model, TR48, of the North Burbank Unit. The commercial software E100 was used, which is a simulator that can model both the solvent process and polymer flooding. The main steps in the simulation study are as follows: 1. Describe geological background, production history and reservoir characteristics in the North Burbank Unit. 2. CO2 resource. 3. Build pressure-volume-temperature (PVT) model. 4. Build reservoir model. 5. Validate the reservoir model by matching primary and secondary production data. 6. Evaluate the performance of CO2 viscosifier. 7. Evaluate the performance of PAG.