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A novel means of mitigating steam channeling and premature steam breakthrough in steamdrives has been successfully applied in the West Coalinga Field, California. A unique polymer gel system, organically crosslinked in-situ, has shown the ability to divert steam from pre-existing steam channels thus, improving areal steam sweep efficiency. Small volumes of this specially designed polymer gel system (less than 500 bbls [less than 79.5 m3]) were injected in six steamdrive injection wells. The applied treatments required only a minor interruption to continuous steam injection and were performed without any interruption to project production. Analyses of treatment performances have shown positive results in less than one month. Sustained performance of the first treated injector lasted over six months. Others have continued five months without signs of significant degradation. In treating early steam breakthrough cases, effective polymer gel placement has reduced casing effluent (steam) rates and casing pressures. Reduced casing pressure combined with increased pumping efficiency has resulted in oil production rate increases. By reducing the volume of live steam produced out of the casing, the project thermal efficiency has been improved through increased utilization of injected heat. Temperature observation well data have shown substantial reservoir temperature decreases two months after injecting the gel system. These data suggest a redistribution of reservoir heat thus, improved areal sweep.


Since first being applied in the 1950's steam injection has become the most widely used EOR process to recover heavy oil reserves. More than one million barrels of heavy crude are produced daily worldwide. The majority of this comes from continuous steam injection, or steamflooding, operations. One of the most significant problems associated with steamflood operations is the occurrence of early steam breakthrough at production wells. Early steam breakthrough usually results from severe steam gravity override or by direct steam channeling through high permeability streaks. In either case, injected steam bypasses unswept portions of the reservoir. This results in an inefficient use of injected heat and a reduction in the ultimate steamflood oil recovery. In addition, high velocity vapor entering the wellbore cuts downhole tubulars and causes severe sanding and other production problems. Full scale steamflooding in the West Coalinga Field began in 1961. Current steamflood operations target heavy oil recovery from the Miocene Temblor Formation. Within the West Coalinga Field the Temblor Formation is situated in a monoclinal structure dipping 10–15 southeast. The Temblor sands are thought to have been deposited in a shallow marine-nearshore environment. Heavy oil production is from multiple discrete sandstone reservoirs each separated by laterally continuous shales. The internal stratigraphy is complex and results in a heterogeneous reservoir character. Most steamfloods in the West Coalinga Field have five acre well spacing and are arranged in inverted five spot configurations. Production wells have slotted liner or gravel pack completions and are open to all Temblor sands. Initial projects begin by injecting continuous steam into the lower Temblor sands, or Zone II. As thermal maturity is reached the steamflood then is vertically expanded to process the remaining upper Temblor sands. Continuous steam injection rates are designed to optimize project economics while maximizing generator utilization. Under these conditions full areal steam coverage is predicted to occur in six years. At that time design strategy recommends injection rate reductions to meet minimum heat requirements.

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