The Blueberry Debolt Oil Field of northeastern British Columbia, discovered in 1956, has over 36 years of production history. It is a complex carbonate reservoir with the oil trapped against the up dip termination of a thrust fault. Reservoir quality is extremely variable and controlled by dolomization and fracturing. There is a down dip water leg and early testing indicated the presence of an up dip gas cap.
The production performance of the field was difficult to evaluate, in particular, water production. Numerical modeling (simulation) has given significant insights into the production mechanisms in the reservoir. The source of water production is better understood and the location of the gas cap better defined. With this information a successful infill drilling program was implemented which has resulted in significant production increases for a very mature property.
The approach utilized and results obtained are described. Successful optimization of this field required integration of geological description, production performance, material balance, well test analysis, numerical simulation, and infill drilling results.
The Blueberry field is located approximately 60 miles northwest of Fort St. John in northeastern British Columbia. The discovery well was drilled in 1956 at d82- L/94-A-12. Commercial production was obtained from a depth of approximately 2075 meters (6800 feet). Production commenced in 1957, following further development drilling. The oil is medium-light with a 36 ° API gravity.
Based on interpretations of DSTs and production tests, early in the life of the reservoir, a gas cap had been interpreted in both the north and south pools.
Production is obtained from the Mississippian Debolt formation. Oil is trapped against the up dip extreme of a thrust fault related to the Laramide progeny. The general structure is shown in Figure-I. There is thought to be only a minor amount of roll-over. From an aerial view, the reservoirs are outlined in Figure-2. The leading edge of the thrust fault trends northwest - southwest. Towards the south part of the pool there is a break in the trend of the main thrust. It was thought that there may be a lateral tear, with displacement taken up in two smaller thrusts. It was not clear if this lateral tear was sealing or not.
There are two main pools, which are designated as the South and North Pools. Lateral faults and/or low permeability are thought to separate the two main pools. The exact location of the division has not been determined.
At the start of the study, a total of 15 producers were drilled in the South pool, including one horizontal well. Overall GOR levels have increased, from 113 m3/m3 (635 scflbbl) initially to 278 m3/m3 (1575 scflbbl). This indicates some pressure maintenance. Watercuts have increased steadily to 50 percent at the start of the study. More detailed analysis, on a well by well basis, indicated that the updip wells in the southern most part had the highest watercuts. The reservoir pressure had dropped from the initial pressure of 19,000 kPa (2755 psi) to 13,000 kPa (1885 psi), as shown in Figure-3.