The injection of low-salinity water into a reservoir at different salt mass concentrations was simulated in order to investigate the changes in the recovery rate during crude oil extraction.The simulation results and the experimental data showed a good agreement between the two.In addition,the formation damage of dense rock core samples under low salinity water injection was evaluated by core replacement tests at salt mass concentrations ranging from 1500 mg·L-1 to 4000 mg·L-1 and temperatures ranging from 25 ℃ to 100 ℃.The results of the simulations showed good agreement with the experimental data.The rock permeability was reduced to about 83% of the initial value for the low-salinity water injection scenario.The formation damage during low salinity water injection was predicted and the R2 of the predicted value to the experimental data was greater than 0.97.In addition,the recovery during low salinity water injection with DTPMP (diethylenetriamine penta(methylene phosphoric acid)) and nano-particles (TiO2,SiO2,Al2O3) was also analyzed.The results of core drive tests showed that the use of scale inhibitors could increase the recovery by more than 8%.Meanwhile,the highest recovery rate was achieved in the presence of 0.05% SiO2 nanoparticles.Compared with TiO2 and Al2O3,SiO2 nanoparticles were more effective in driving off crude oil in porous media.In the presence of DTPMP,the recovery was 72.2%,62.4% and 59.8% for SiO2,TiO2 and Al2O3,respectively.Among the studied nanoparticles,the lowest crude oil viscosity and oil-water interfacial tension were observed with SiO2.
关键词
注水工艺/提高采收率/纳米粒子/界面张力
Key words
Water injection process/Enhanced recovery/Nanoparticles/Interfacial tension
维普
万方数据