Norman Wells - A New Look at One of Canada's Largest Oil Fields

Abstract

Summary A major development plan for the Norman Wells oil field in the Northwest Territories has been based on a recent synergistic geological and engineering study of the reservoir. Information from oriented cores, well tests, fluid and pressure surveys, outcrop studies, and surface photos have shown that natural vertical fractures present in the reservoir have a strong N30 deg. E orientation. The proposed development plan will make use of the directional permeabilities resulting from natural fractures. Introduction Oil sands and hydrocarbon seepages along the MacKenzie River in the Northwest Territories have been reported since the late 1700's by explorers and fur traders. In 1920, Imperial Oil Ltd. drilled the discovery well near oil seepages at Norman Wells 900 miles (1500 km) north of Edmonton, Alta. (Fig. 1). The remote location of the field delayed development until the early 1940's when, under the Canol Agreement, the U.S. Army, Canada, and Imperial Oil drilled 60 wells, expanded the existing refinery, and constructed a road and pipeline to Whitehorse 620 miles (1000 km) to the southwest. Pool production peaked at 4,400 B/D (700 m3/d) in 1944. The pipeline to Whitehorse was dismantled after 1945, but the pool has continued to supply northern Canada. Demand has grown to the present level of 3,000 B/D (480 m3/d).Total pool production to the end of 1980 under primary solution-gas drive has been less than 4% of the estimated 630 million bbl (100 x 106 m3) of original oil in place (OOIP). The MacKenzie River overlies the bulk of the reservoir, and since the reef is relatively shallow at a depth of 1,000 to 1,600 ft (300 to 500 m), development has been limited to three producing areas known as the Mainland, Goose Island, and Bear Island (Fig. 2). Typical-well oil rates have declined by 50% to a range of 60 to 500 B/D (10 to 80 m3/d). The present GOR's have escalated to between 2,000 to 4,000 cu ft/bbl (350 to 700 m3/m3) from a solution GOR of 335 cu ft/bbl (60 m3/m3).Activity has increased significantly since 1979 with the drilling of seven delineation wells from grounded river-ice platforms and land areas, seven highly deviated wells for water injection and production, and one horizontal well intersecting 4,000 ft (1200 m) of reservoir rock from the Mainland to the central pool area under the river.A line-drive waterflood employing 13 wells was started in 1980 for the Mainland area, and an extensive monitoring system has been installed to measure fluid production and injection, GOR'S, and pressures by individual well and zone. In March 1980, an application was made to the Canadian Federal Dept. of Indian Affairs and Northern Development for approval to expand the Mainland waterflood to a fieldwide pattern waterflood system. Reservoir Geology Summary Hydrocarbons at Norman Wells are pooled in the Devonian Kee Scarp formation limestone reef buildup, which is 15 miles (25 km) long and 5 miles (8 km) wide. The reef complex began to develop during Upper Middle Devonian time on shale banks of the Hare Indian formation (Fig. 3). Minor variations in sea level localized major reef growth on a thin open marine platform along the basinward edges of the Hare Indian shales. Reef growth proceeded during two major upward shoaling cycles and was terminated by the advancing clastic sediments of the Canol and Imperial formations, which serve as the top seal for the reef buildups. The Kee Scarp reef at Norman Wells attains a maximum thickness of 525 ft (160 m) with a reservoir thickness of 360 ft (110 m). The regional structural dip is about 4.5 deg. to the southwest. Oil is trapped stratigraphically in the extreme updip end of the reef buildup. There is no gas cap, and a limited water leg provides no pressure support. JPT P. 985^