Conclusions
Gel-polymer treatments at three injection wells in the Sooner Unit have not resulted in oil production increases or water-cut decreases after one year of monitoring. Total fluid production has decreased at wells which offset the treated injection wells because of lower injection rates. Treatment size averaged about 1200 lb MARCIT™ Water-Cut 204® in 450 bbl of water at concentrations of 6000 to 10,000 ppm into reservoir intervals which average 17 ft of net thickness. The gel-polymer has remained stable and not degraded at the relatively high reservoir temperature of 220° F. Pre and post-treatment pressure falloff tests and temperature surveys were run in two of the treated wells. Temperature logs indicate no fluid movement outside of the reservoir intervals. Analysis of the falloff test data indicate significant reduction in kh without changes in wellbore skin. It is concluded that the treatment concentrations were probably too high and resulted in a negative impact on cashflow. Based on the experience from these treatments, a recommendation for future tests of the technology would be to use lower concentrations of less than 5000 ppm in a larger volume of 1000 bbl.