In 1961 approximately 104,772 x 106m3 (3.7 trillion ft3) of in-place sour gas resources were discovered within the Late Devonian Swan Hills Formation (Beaverhill Lake A pool) at Kaybob South field of west-central Alberta. Production at Kaybob South is managed as three operational units (Gas Units #s 1, 2 and 3) and commenced in 1968 at Gas Unit #1 with the secondary recovery of natural gas liquids and condensate from produced gas and re-injection of by-product lean sweet gas. Liquid and gas production through this process of gas cycling continued at Gas Unit #1 until 1983, after which gas was harvested through pressure depletion. Cumulative gas production to date at Gas Unit #1 suggests that only 47–56 percent of the in-place gas will be ultimately captured by the remaining productive wells. This relatively low recovery is attributed to wellbore mechanical failure resulting from corrosive formation fluids, and both wellbore and reservoir permeability loss caused by the precipitation of hydrocarbon liquids and various mineral precipitants.

Work presented in this study suggests that the drilling of 17 infill development wells may capture between 1,183 x 106m3 (42 bcf) and 5,192 x 106m3 (183 bcf) of by-passed gas resources. These reserve additions, combined with the 651 x 106m3 (23 bcf) reserves that are anticipated to be recovered by the current producing wells in their remaining well life, will increase the ultimate recovery at Gas Unit # 1 to 63–77 percent of OGIP. This recovery factor is comparable to analogous Swan Hills Formation gas pools within the region.

The Swan Hills Formation at Gas Unit #1 accumulated as a platform margin succession of shallow marine carbonates that are partitioned into five high-frequency depositional sequences (HFS-2 through HFS-6). HFS-2 through -4 are characterized by an aggradational to slightly retrogradational stacking pattern, whereas HFS-5 and -6 are stacked in a more strongly retrogradational fashion. The priority assigned to future development wells should take into account the geologic attributes that influence well performance. The best reservoir quality and production performance is associated with dolomitized reef margin and stromatoporoid shoal facies associations. Due to pervasive fracturing, sequence boundaries and associated facies distributions are not thought to compartmentalize flow units. Future development wells may be ranked according to their likelihood of favourable well performance by considering their location relative to the predicted distributions of dominant facies, structural position, gas-saturated pore-volume thickness, Kmax permeability, fracture density, and proximity to currently producing wells. Following assessment of all prospective development wells, three prospects were successfully drilled during the 4th-quarter of 2006 and 2007 and serve as an independent test that strengthens the geologic interpretation and confirms the existence of significant bypassed gas resources that may be captured through infill development.

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