Abstract
This paper summarizes the laboratory and simulation studies conducted to evaluate the potential of low-salinity polymer flood for the Gao-30 reservoir in Huabei Oilfield, China which has a high reservoir temperature of 113°C, moderate formation salinity of 9,000 ppm total dissolved solids and in-situ oil viscosity of 25 cP.
Our studies have identified GL-100, a specially designed rigid structure modified polyacrylamide, as a polymer candidate for the Gao-30 reservoir because it exhibits adequate thermal stability and acceptable injectivity. Laboratory results show that for GL-100, low-salinity brine has the dual benefits of improved thermal stability and higher viscosity compared to formation brine. Spontaneous imbibition experiments using Gao-30 core plugs show that secondary mode imbibition by softened formation brine recovers more oil than imbibition by formation brine. In addition, significant incremental oil recovery was observed with injection of low-salinity polymer into a heterogeneous Gao-30 core, compared with formation water flooding.
Corefloods in secondary mode were conducted with low-salinity and formation brines. Results were history matched to obtain the relative permeability and capillary pressure curves. These results and laboratory measured polymer rheology and adsorption were used as input into reservoir simulations to forecast benefits of low-salinity polymer flood in two pilot locations chosen from full field history matching of 20 years of waterflood in the Gao-30 reservoir.
Reservoir simulations were run to compare the incremental oil recovery resulting from injection of various slug sizes of formation-salinity polymer and low-salinity polymer. Our simulations only considered the increase in viscosity due to polymer and the improvement of thermal stability of polymer in low-salinity brine. Low-salinity chemical effects through changes in the relative permeability curves were not included. Results show that injection of 0.3 PV formation-salinity polymer and low-salinity polymer gives incremental oil recovery of 9% and 13%, respectively, compared to formation-salinity waterflood.
Preliminary economic evaluations show that formation-salinity polymer flood based on 0.3 PV of 1800 ppm GL-100 to be economical in Gao-30 reservoir based on economics of on-going polymer projects in China. The additional 4% incremental oil obtained by tuning the brine composition (the low-salinity effect) may be economical, especially if it is achieved through softened brine instead of low-salinity brine.
