Study and Field Trial of Discontinuous Chemical Flooding for Mature Offshore Oilfield with Ultra High Water Cut

Abstract Large portion of offshore oilfield in China are mature oilfields with ultra high water cut and recovery rate. The fragmentary distributed remaining oil and aged downhole equipment bring great challenges to the sustainable oil production. A new chemical flooding technique called discontinuous chemical flooding (DCF) was developed to achieve effective remaining oil extraction and has been implemented in oilfield Q, a typical mature oilfield with a water cut of 95% and a recovery rate of more than 40%. Different chemical agent slugs were designed to deal with channeling effects and injectivity problem. Two great challenges were encountered during the field implementation. The injection pressure rose sharply by 6.6 MPa within two months after polymer injection. Acidizing, re-perforation, and alternating injection of polymer with different molecular weights (MW) were implemented for injectivity improvement. Hydrogen sulfide (H2S) was detected from the platform, and the polymer viscosity was greatly affected. Bactericide was added to the production system to reduce the concentration of H2S. Nitrogen replacement method was used in the polymer dispensing equipment to block the contact between polymer and oxygen. A total of 13 acidizing treatments were performed since the project start. The apparent injectivity index improvements with a maximum value of 300% were achieved. The re-perforation treatment was conducted in Well I6. Deep penetration perforation was conducted from the original well section with a density of 20 SPM and a longitudinal extension of 6.1 meters. Significant improvements were observed in both injectivity and pressure rise rate. The water injection rate was increased from 100 m3/d to 445 m3/d at polymer concentration of 800 mg/L, and the stable injection was maintained for 8 months. A moderate MW polymer was injected for trial. The average pressure rise rate was reduced by 0.097MPa/d. Under non-plugging conditions, the polymer with lower MW yields decent injectivity improvements. The wellhead polymer viscosity was reduced by 42% due to H2S. Numerical simulation inversion indicates that the in-situ polymer viscosity is only 2.8 mPas. After H2S treatment, the concentration in the production system was reduced from 50ppm to less than 15ppm. The wellhead polymer viscosity was recovered. Within 2 years of agent adjustment, well intervention and H2S treatment, 11 out of 17 wells had great oil incremental performance. The incremental oil production is evaluated to be 1.69×104 m3. The field trail proves the technical feasibility of enhancing oil recovery through DCF in mature offshore oilfields with ultra high water cuts.