Preliminary Results From a Solvent Gas Injection Field Test in a Depleted Heavy Oil Reservoir
Authors: Miller K.A. , Carlson J.E. , Morgan R.J. , Thornton R.W. , Willis K. 
Published: March 2010

Abstract
A field test was run during 1997 and 1998 to collect preliminary data on a solvent gas injection process. The site selected for the test was a "typical" Frog Lake, Alberta, Cummings formation reservoir that had been depleted using PC pump-based cold production methods on both 4 hectare (10 acre) and 8.1 hectare (20 acre) spacing. At the time of solvent injection, area average recovery from the test location was 9.5%, and the existence of wormholes in the reservoir was strongly suggested by regional well-to-well water migration and production of reservoir sand at high initial rates and cumulative volumes.
A solvent containing 33 volume % propane and 67 volume % methane was injected at two converted central producers until cumulative volumes of 2 million m3 and 4 million m3 were achieved. This paper discusses field observations during the injection, soak, and production periods. A number of circumstances contributed to a poor economic result, but the operational and technical information obtained should prove helpful to operators considering application of solvent injection processes.

Introduction
Cold Production in Western Canadian Regional Heavy Oil Sands
PC pump-based cold production has expanded rapidly following initial development in the 1980s. This exploitation methodology provides a large percentage of the produced oil volume for most Western Canadian heavy oil producers. Some producers use only this method.
Despite continued efforts to improve PC pump-based cold production technology, current methods generally leave 80 to 95% of the OOIP behind at economic limit. While this is a large oil-inplace target for follow-up EOR processes, the cold production process appears to have strongly altered reservoir conditions. Wormhole channels have been implied and described on the basis of observed high produced sand volumes and rapid migration of edge water and injected fluids and tracers(1–3). The reservoirs are generally pressure depleted. Solution gas, which appears to help power production through mechanisms described as either foamy oil flow(4–6) or more recently as extremely low gas mobility(7), often appears to "blow down" at the end of a well's life. Water influx, likely through wormhole networks, sometimes occurs at wells distant from the original oil/water contact.
Thermal Production in Western Canadian Regional Heavy Oil Sands
During the 1960s, operators attempted steam processes in selected heavy oil regional sands to recover a higher fraction of OOIP. It was soon determined that the typical H-40 casings with non-thermal cement would not withstand the resulting thermal stresses. Insulated tubing strings with or without packers were tried, but these strings were expensive, fragile, and often did not achieve theoretical performance in the field. Thermal completions in newer wells avoided wellbore failure due to the use of premium tubulars and collars, but other problems occurred. Often the steam had to be injected at pressures exceeding the formation parting (fracture) pressure to achieve acceptable heat transfer rates to the reservoir. This resulted in rapid steam channeling to neighboring wells, or to neighboring formations.