Daqing sandstone is the largest producing field in China, operated by CNPC's Daqing Oilfield Company. Despite more than 50 years of development, annual crude production currently is almost 40 mln tons of oil that is about 80% of plateau level. This successful long-term development is made possible through EOR programs. Chemical EOR is deployed in Daqing field from 1992 and currently accounts for ~14 mln tons of oil production annually, mainly by polymer flooding, world-largest in scale.
Conventional hydrolyzed polyacrylamide (HPAM) copolymers were used in Daqing projects with fresh water for preparation of injection solution since the beginning. Today, mainly produced water is used for polymer preparation to improve field environmental and commercial performance. The salinity of produced water is moderate, of about ~5,100 mg/l. However, it contains crude oil, suspended solids, bacteria, iron, sulfide, residual polymer and other chemicals. Altogether they have large influence on polymer viscosity: for medium- and high-molecular-weight copolymers it can be reduced by 40-50% when switching from fresh to Daqing produced water. Then higher polymer concentration is required to achieve target viscosity.
Operating Daqing Oilfield company, its institute, and polymer suppliers have conducted thorough experimental polymer screening with the following criteria: salinity resistance; providing target viscosity range at smaller concentrations (compared to regular HPAM); if feasible, better sweep efficiency – to increase oil recovery. Viscosity build-up, its retention, thermal stability, salinity tolerance, adsorption and oil displacement were compared.
Terpolymer LH2500 was selected for field trial for produced water injection. It is manufactured by introducing 2-Acrylamido-2-methylpropane sulfonic acid (AMPS) group and micro-block template to HPAM molecule that improves the polymer linearity and resistance to salts and temperature. In different zones of Pu I2-3 layer two types of polymers were injected – conventional HPAM in fresh water and LH2500 polymer in produced water. In both areas watercut prior to polymer injection was similar – 95.9 and 95.5%, respectively; reservoir and fluids properties are very similar. LH2500 was injected in five-spot patterns with ~140 m well spacing. There are 33 injection wells and 37 producers in this area. LH2500 has demonstrated good injectivity, better sweep efficiency and in-situ viscosity stability and, therefore, recommended for use in the project expansion. Watercut reduction achieved is 16.6%, higher than for conventional HPAM with fresh water injection. Increase of oil production was observed in all 37 producers. The incremental recovery by LH2500 is greater at the same injection volume, which overperforms HPAM by adding 3.3% of oil-in-place to production on the date of analysis at similar injection volume. Also, this result is achieved with 35% less polymer that improves economics of polymer flooding in Daqing even further. The results correlate well with previous experimental findings. Incremental recovery in patterns swept by LH2500 continues to grow and forecasted to achieve over 18% (Zhou et al. 2015).
This paper presents detailed description of AMPS terpolymer, polymer selection, experimental evaluation, field performance of LH2500 terpolymer, and incremental oil recovery analysis.