Summary
The gel-polymer has remained stable and not degraded at the relatively high reservoir temperature of 220° F at the Sooner Unit; however, the polymer concentrations were probably too high. Three injection wells were treated with approximately 1200 lb of MARCIT™ Water- Cut 204® in 450 bbl of water at concentrations of 6000 to 10,000 ppm. The cross-linking agent was Water-Cut 684®. Polymer-gel treatments resulted in significantly reduced injectivity and kh calculations from pressure fall-off tests. Similar negative skins were computed before and after treatments and characteristic shapes of the pressure fall-off plots did not change. The polymer-gel has been stable at each injection well as indicated by continuation of elevated injection pressures and reduced injection rates. Before polymer-gel treatments, total water injection was about 2700 bbl water per day (bwpd), while the current injection rate is about 2300 bwpd. Injection at higher rates at treated wells is not possible because of pressure limitations of injection lines and reservoir-fracture pressure. No increase of oil production has been observed after 12 months from any producing well at the Sooner Unit following polymer-gel treatments. Total fluid production has decreased from wells which offset polymer treatments but the oil cut has remained the same. At the time of the first treatment in March 1996, the Sooner Unit was producing 391 bbl oil per day (bopd) and 1350 bwpd (78 percent water cut). By the end of February 1997, total production from the Unit was 174 bopd and 1109 bwpd (86 percent water cut). Cumulative oil from the Unit was 1,565,000 bbl or 22.7 percent of original-oil-in-place (6,900,000 stb). After one year, it cannot be said that the polymer treatments have resulted in a technical success by increasing oil cut.