A laboratory study was performed to identify a robust chemical EOR solution for a complex low-permeability carbonate reservoir. The study consisted of two phases of work. The first phase included development of a surfactant-based EOR method (Jabbar et al., 2017). The results were promising, but the proposed surfactant design was economically challenged due to high surfactant adsorption. Initial screening recommended polymer to be considered for sweep improvement and conformance control although reservoir complexity and current field development presents a challenge.

This paper is focused on the polymer EOR evaluation and discusses the extensive evaluation process that was followed. The laboratory study included polymer rheology, thermal stability, and transport tests with a novel pre-shearing method, live-condition core flood tests to evaluate dynamic polymer adsorption and description of key chemical and flow properties, and a history match of the core flood test results. In addition, preliminary simulation studies were performed, which demonstrated the recovery potential of polymer flooding.

Two modified, low-molecular weight HPAM polymers were tested and have suitable viscosifying power in injected seawater (41 g/mL TDS) at 100°C. The long-term thermal stability results showed that only the more salt-tolerant polymer is stable at 100°C and retains >80% of initial viscosity at 300 days. The stable polymer was tested in a series of single-phase core floods to evaluate transport through low-permeability (5-10 mD) reservoir cores at 100°C. A novel pre-shearing method was developed where pre-sheared polymer solution with 30% of its original viscosity (~3 cP) transported without significant plugging. Finally a high-pressure live-oil two-phase oil recovery coreflood in preserved reservoir core was performed. The incremental oil recovery with three PV's of polymer solution injection was approximately 17% OOIP. Pressure drop was 47 psi/ft., ~3-5 times higher than that of waterflood, for the 3 cP polymer solution. The polymer breakthrough times and resistance factor were reasonable with no evidence of plugging or injectivity issues considering permeability and viscosity of fluids. The polymer retention was measured to be 150 ± 50 μg/g rock, which is higher than a traditional HPAM flood in high-permeability sandstone rock.

The laboratory results obtained thus far are promising considering very harsh and challenging reservoir conditions. The study also highlights an "up-scaleable" pre-shearing method for field application. In the simulation study, a sector model with representative geological features was taken from the full-field simulation model. Measured physical properties from the laboratory evaluation were used as input for the polymer flood simulation. Recovery uplift from polymer flood was found to be ~5% OOIP with significant reduction in water production and reasonable chemical utilization of <10 lbs. per incremental barrel. The simulation study demonstrated promising potential of polymer flooding for the targeted reservoir.

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