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A miscible C02 project was initiated in the Rangely Weber Sand Unit in northwest Colorado in 1986, Over the past seven years, the project has expanded areally to include 80% of the Unit, and substantial investments have been completed in injection, production and gas recompression facilities. As the project matures, emphasis has shifted from adding new C02 injection patterns to management of C02 injection, with goals of maximizing recovery and reducing operating costs. Optimization of the Water-Alternating-Gas (WAG) injection process is an important part of this effort.Our initial injection strategy was based on reservoir simulation studies. It became apparent as the project matured that we would need to make changes in WAG processes to adapt to operational constraints and maximize pattern economics. Flood performance was optimized through further simulation and field testing of changes to C02 slug size and WAG ratio tapering sequence. New methods for managing the WAG process based on injection pattern performance and economic triggers have been adopted. We have completed an initial comparison of predicted versus actual performance for injection patterns with tapered WAG ratios.References and illustrations at end of paper. 141

Steam injection Wells 1-9W, 2-9W, and 2-8W were treated with lignosulfonate gel in the upper J zone of the Temblor sand, long string, to improve steam volumetric sweep in the surrounding patterns. The objective was to divert most of the injected steam from the upper to the bottom part of the sand by placing gel into the top set of perforations on all three wells. The near wellbore region was cooled by injecting 300 barrels of cold water prior to the test on injector 1-9W, 100 barrels on injector 2-9W, and no water was injected into 2-8W prior to the test. There was between 850–1155 barrels of lignosulfonate solution placed per well over a 30 to 64 hour period. During chemical injection, a 39% to 75% decrease in injectivity was measured. The wells were still below parting pressure at the end of lignosulfonate injection. Chemical cost was about 50% lower on a per barrel basis than for a currently marketed high temperature gel system. Treatment results were evaluated by comparing injection profiles, temperature logs in a nearby observation well, flow line temperatures, and offset production response before and after gel placement. Two of the three treatments resulted in a substantial redistribution of steam both vertically and areally, based on the collected data. Introduction / Strategy Inadequate sweep efficiency due to reservoir heterogeneity is often the cause of poor oil recovery and early injected fluid breakthrough. Gel technology is most suitable to reservoirs where a few strata dominate the flow (fractures, channels, high-permeability streaks); and where a strategically placed gel could smooth out the uneven sweep of the reservoir by the injected fluid. Few gel systems are designed for applications in hot reservoirs (T>190 F), such as hot waterfloods and steamfloods. The few that were found to be effective in laboratory and field tests are very expensive ($4 to $5/lb of active polymer in the US) and require polymer concentration in the 1% to 3% range. Lignosulfonate gels have also been studied and tested in the past for high temperature applications. Lignosulfonates are derived from lignin which is a waste product in paper mills. They are much cheaper than currently used polymers ($0.10/lb active in the US). Lignosulfonate gels are therefore good candidates for conformance control in hot reservoirs such as the California steam floods. A three-prong strategy was implemented. In the first phase, basic lignosulfonate gels properties were studied in the laboratory. It was found that gels of controllable strength could be formed under conditions that are typical for hot reservoirs such as steamfloods and hot waterfloods. The second phase was to test this technology in a steamflood in California. If success is achieved, then the third phase would be to adapt this technology to other steamfloods and hot waterfloods, possibly using lignosulfonates manufactured from local lignin sources. This paper summarizes the results of a field test of this technology conducted in November, 1995 in Wells 1-9W, 2-9W, and 2-8W, Section 31 A of a California steamflood. Well selection Process: It was decided to test this technology in three injectors from contiguous patterns in order to give it the best chance for impacting both areal and vertical sweep. Historically, applications of standard low temperature gel technologies were successful in less than 50% of the cases. Therefore, proper selection of wells where either injection or production performance could be improved by gel technology was crucial for success. The following criteria were used in the well selection process: P. 299^

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