This paper describes a reservoir intervention used to enhance oil recovery from high WOR patterns in the Norman Wells waterflood It discusses the methodology and resources utilized to select potential treatment candidates, develop designs and execute water control treatments in the naturally fractured carbonate reef. Quality control and execution details are briefly discussed as is the use of on the job monitoring to optimize treatment gel concentrations and volumes. Actual field data is referenced throughout the paper and results of the program are reviewed in detail.

Potential treatment candidates were selected using criteria such as high WOR, low pattern recovery, the existence of fractures, and the potential to increase the injector to producer drawdown. Production history, tracer survey, pulse test and production log information was used to high-grade the selection of candidates and to optimize treatment design. The wells were treated with a high molecular weight, crosslinked polyacrylamide gel pumped at unusually high concentrations of up to 2%. Gel placement was influenced by selective operation of wells which were connected to the fracture system being treated. Pressure monitoring at neighbouring wells provided valuable information which enhanced the understanding of gel placement and fracture characterization. Initial production results indicate that fluid flow in the reservoir has been positively impacted and learnings from the treatments described are being used to enhance future designs. A multi-disciplinary team, technical experts and a close working relationship with the pumping company were instrumental in the successful application of polymer gel technology.


The Norman Wells oil producing reservoir is located 450 metres beneath the Mackenzie River in Canada's Northwest Territories, approximately 150 kilometres south of the Arctic Circle (Fig. 1). Discovered in 1920, development occurred only on the mainland and natural islands until 1981 at which time a major expansion project was initiated using the latest technology in artificial island construction and directional drilling to access the reservoir beneath the river. A field-wide, five-spot waterflood program was implemented and in 1985 pool production increased from 475 m3/d to over 4000 m3/d. Currently, 164 active injectors and 170 producers average 4500 m3 of oil production per day.

Geologic Description

The Norman Wells reservoir produces from the Kee Scarp formation which was developed in Upper Middle Devonian time. Regional structural dip is to the southwest with the oil trapped stratigraphically in the up dip end of the reef. There is no gas cap and the aquifer provides no pressure support. The reef consists of shallowing upward carbonate cycles arranged in a "backstepping" morphology. These relationships impact the distribution and stacking patterns of the facies within the reef complex. The porous reef section overlies a non-porous basal platform and is capped by the Canol shales. The producing formation has 19 correlated cycles of reef development. The zonation and "backstepping" morphology are illustrated in the schematic stratigraphic section in Figure 2. Distinct facies development provides regional variations of porosity and permeability. Porosity ranges from 2 to 24% with an average of 8.4% and bulk matrix permeabilities are low, ranging from 0.1 to 75 md with an average of 4 md.

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