The Grand Forks Lower Mannville 'D' Pool located in southeastern Alberta is a good reservoir quality Lower Cretaceous channel sand which contained 15.9 × 106 m3 original oil-1n-place. The reservoir fluid is an undersaturated crude oil with an in-situ viscosity of 11 cps and a stock tank gravity of 26 ° API. Production from the pool began in 1968 and the waterflood scheme was implemented in 1976. Twenty-four percent of the original oil-in-place had been produced by the beginning of 1984.
The waterflood performance was simulated using a three-dimensional numerical model. The ultimate oil recovery by waterflood was calculated to be 39.5% of the original oil-in-place in the year 2005. The waterflood displacement mechanism is dominated by gravity and the optimum operating strategy for the pool is to continue the present practice of one main water injector located in the centre portion of the pool giving pressure support to 34 producing wells.
The waterflood recovery efficiency is sensitive to the producing and injection infill drilling and number of injectors. The reason for these results and the potential enhanced recovery using tertiary methods discussed.
The Grand Forks Lower Mannville "D" Pool is located. In Townships 11 and 12, Range 13, in southeastern Alberta., as shown in Figures 1 and 2. The pool, which is a lower Cretaceous channel sand, is one of the most productive oil reservoirs in the area. The original oil-in-place is estimated to be 100 MMSTB or 15.9 × 106 m3.
The pool was discovered in 1968 and placed under primary production for approximately 8 years. In 1976, a linear waterflood scheme was implemented with three water injectors. In 1980, a fourth water injector located in the south end of the pool was put on to improve the sweep efficiency. Total oil production to 19133-12-31 is 24 MMST8 (3.97 × 106 m3) or 24% of OOIP. The pool now has 34 producers and 4 water injectors with current injection rate of 19,500 STB/D or 3,100 m3/D. Current oil production rate is approximately 6,000 ST9/D (950 m3/D) with average water cut of 76%. Figure 3 shows the pool cumulative oil production versus cumulative water injection.
The reservoir fluid is highly undersaturated with a reservoir viscosity of 11 cps and a stock tank gravity of 26 ° API. Although the reservoir oil is slightly heavy, it appears that the waterflood is very effective for the pool. A substantial amount of ail produced is attributed to the waterflood as shown in Figure 4.
The oil production rate for the subject pool was peaked at 9,500 ST9/D in 1979. Since then, the production declined drastically until 1981 when an infill drilling program was implemented. However, the oil production rate started dropping again in 1982 due to increasing water cut.
Pressure surveys indicated that an extremely high pressure area has existed in the south end of the pool for the last several years.
