CAPITAL: Ottawa
MONETARY UNIT: Dollar
REFINING CAPACITY: 1.85 million b/d
OIL PRODUCTION: 1.88 million b/d
OIL RESERVES: 4.84 billion bbl
GAS RESERVES: 65 tcf
Eighteen years after its discovery, giant Hibernia field off Newfoundland started producing oil on Nov. 17, 1997. The landmark followed spending of more than $5.819 billion (Canadian).
Hibernia`s start-up capped a year of Canadian activity that also included a race to increase natural gas export capacity to the U.S. and growth of Canada`s oilsands industry.
Hibernia start-up
Shortly before production start, partners in the Hibernia project increased the reserves estimate for the field to 750 million bbl of oil from 615 million bbl.
Output from the field`s first well on production was to gradually increase to 20,000 b/d. Plateau field production was to be 135,000 b/d from a gravity base platform with design capacity of 150,000 b/d.
The field produces from Cretaceous Hibernia sand at 3,700 m and Cretaceous Avalon at 2,400 m, which together hold 3 billion bbl of 32° gravity, low-sulfur oil in place. The reserves increase came after a review of seismic profiles of the reservoirs and consideration of extended-reach and horizontal drilling capability plus possibilities for water and gas injection.
Hibernia partners at production start were Mobil Oil Canada Ltd. 33.125%, Chevron Canada Resources Ltd. 26.875%, Petro-Canada Ltd. 20%, Canada Hibernia Holding Corp. 8.5%, Murphy Oil Canada 6.5%, and Norsk Hydro AS 5%.
Work leading to first oil in 1997 included mating of the gravity base structure and topsides in February, tow-out of the platform to the Grand Banks in May, installation in June, and start of drilling by two rigs in late July.
Hibernia is the largest of 16 disclosed discoveries in the Jeanne d`Arc subbasin off Newfoundland. Others, and their reserves estimates, include Terra Nova 400 million bbl, Hebron 195 million bbl, and Whiterose 178 million bbl.
Drilling, production
Drilling in Canada reached record levels in 1997.
OIL & Gas Journal estimated that operators completed 15,133 wells during the year. The Baker Hughes count of active rotary rigs averaged 363 rigs/week, up 34% from 1996.
In the last week of 1997, 493 rigs were at work in Canada, compared with 204 in the last week of 1996. The rig count was up nearly 300% since bottoming in 1992.
OGJ projected completions totaling 14,339 wells in 1998. The decline was expected to result from declines in oil and gas prices from 1997 levels and rising costs of oil field equipment and services.
A concern expressed by some analysts in 1997 was a relative stagnation of gas well drilling. In 1997, oil completions were up about 40% year on year, while gas completions were unchanged. Oil wells accounted for nearly two thirds of all wells drilled in Canada.
GAS reserves, meanwhile, fell to 65 tcf from 68 tcf. To replace production, rising on the strength of Canadian demand growth while export capacity to the U.S. awaited additions to pipeline capacity, Canadian operators were likely to have to increase gas drilling.
At midyear 1997, the National Energy Board reported that gas production in Canada rose to a total of 5.6 tcf in 1996 from 5.3 tcf in 1995. The 1996 total reflected a 32% increase over the prior half-decade.
GAS production through October 1997, according to the latest estimates available at yearend, had totaled 5.36 tcf.
In its midyear report, NEB noted that reserve additions replaced 82% of total production in 1991-95.
Production of conventional heavy crude increased to a record 517,667 b/d in 1996 from 461,686 b/d in 1995 and of bitumen to a record 164,798 b/d from 149,073 b/d, NEB said.
Conventional light oil production fell to 880,600 b/d in 1996 from 912,679 b/d in 1995. Production of synthetic oil dropped to 268,583 b/d from 271,728 b/d.
Exports
Natural gas exports through August, latest figures available at yearend 1997, totaled 54.19 billion cu m, compared with 52.92 billion cu m in the same period of 1996, according to the National Energy Board.
The average export price for natural gas through August 1997 was $2.66(Canadian)/ gigajoule, up from $2.31/gigajoule in the comparable period of 1996.
Of the total exports through August 1997, 8.75 billion cu m went to the Pacific Northwest, 14.25 billion cu m to California, 450 million cu m to the Mountain States of the U.S., 18.88 billion cu m to the U.S. Midwest, and 11.85 billion cu m to the U.S. Northeast.
Exports of crude oil and total products also were running ahead of year-earlier levels
Crude exports averaged 1.147 million b/d through July 1997 vs. 1.098 million b/d through July 1996.
Heavy crude exports rose to 667,000 b/d in the first 7 months of 1997 from 561,000 b/d in the same period a year earlier. Exports of light crude fell to 480,000 b/d from 536,000 b/d in the same period.
Exports of all the main petroleum products rose to a total of 8.747 million cu m in January-July 1997 from 8.314 million cu m in the comparable period of 1996.
Pipeline competition
Pipeline projects worth an estimated total of $20 billion were proposed to expand Canadian exports of natural gas to the U.S. Midwest and Northeast and shipments to Canada`s East in 1997. Not all of them would be built.
One of the projects competing to carry gas from western Canada to the Midwest, the Alliance Pipeline, received approval for its U.S. portion and sought Canadian approval in 1997. The line would run from the Alberta-British Columbia border to Chicago.
Targeting the same market, FootHills Pipelines Ltd. and U.S. partner Northern Border worked to place 700 MMcfd of export capacity in service by mid-1998 and planned another expansion in 2000.
TransCanada PipeLines Ltd. announced a series of expansions in 1997 that would expand its export capacity. One of the projects was the planned TransVoyageur Transmission pipeline running 625 miles from Empress, Alta., to Emerson, Man. At Emerson, the TransVoyageur line would connect with the proposed Viking Voyageur line to Joliet, Ill.
TransCanada held a 40% in the Viking Voyaguer project, Northern States Power 40%, and Nicor Inc. 20%. TransCanada in 1997 was talking with prospective partners in the TransVoyageur project.
TransCanada also held interests in a project called Vector from Joliet to Dawn, Ont., and another called Millennium from Dawn to New York City. Other Vector partners were IPL Energy Inc., Columbia Gas Transmission, and MCN Energy Group Inc. Other Millennium partners were Columbia Gas, Westcoast Energy Inc., and MCN.
Sponsors of competing projects were reported to be in communication with one another, so combinations were possible. Some projects discussed earlier were either on hold or considered defunct.
Elsewhere in Canada, three projects were competing to carry gas from Sable Island on the Grand Banks off Nova Scotia to markets in eastern Canada and New England.
One of them, the Trans-Quebec and Maritimes Pipeline, would transit Canada`s maritime provinces and Quebec and terminate in Boston. Sponsors included Montreal gas distributor Gaz Metropolitain, TransCanada PipeLines, and IPL Energy.
Another project, Maritimes & Northeast Pipeline, would pass through Nova Scotia and New Brunswick, bypassing Quebec. Its backers were Westcoast Energy, Mobil Oil Canada Ltd., and Duke Energy.
Either project would connect with the proposed and approved Portland Natural Gas Transmission System from Portland, Me., to Boston.
The third project, sponsored by North Atlantic Pipeline Partners, would use 2,500 km of offshore pipelines to deliver Grand Banks gas to Canada`s Atlantic seaboard and New England. A 925 km first phase pipeline would start at Country Harbour, N.S., and make landfall in Halifax, N.S., and Seabrook, N.H. Later phases would extend the system to Newfoundland.
Mobil Canada Ltd. late in 1997 threatened to suspend the $3 billion gas development project off Sable Island if a decision were not made soon on a pipeline. It and partners had applied to develop six gas fields in the area.
A joint public review panel and the National Energy Board (NEB) late in October 1997 approved the Maritimes and Northeast Pipeline project. The other projects appealed to the Federal Court of Canada.
OILsands activity
A combination of federal and provincial incentives and falling production costs kept Canadian oilsands activity on high boil in 1997.
Suncor Inc. announced a $2.2 billion expansion of its oilsands operation near Ft. McMurray, Alta., to boost production to 210,000 b/d by 2002 from 85,000 b/d. A project under way at the time of the announcement was to take production to 105,000 b/d by 1999.
Suncor expected its production costs to drop to $10-11/bbl by 2002 from $15/bbl in 1997.
Also at Ft. McMurray, Syncrude Canada Ltd. planned to spend $3 billion to expand its crude oil upgrader at the Mildred Lake mine to 175 million bbl/year by 2007 from the 110 million bbl/year capacity approved at the time of its announcement.
It also received approval late in 1997 to devlope the Aurora Mine oil sands project in four phases.
Syncrude expected production from its Ft. McMurray area leases to increase to 260,000 b/d in 2001, 340,000 b/d in 2003, and 480,000 b/d in 2007. It projected operating costs of $11-12/bbl in 2000-2002 and $9-10/bbl in 2002-2007.
To accommodate the Syncrude expansion, AEC Pipelines Ltd. planned to raise capacity of its Alberta Oil Sands Pipe Line to 300,000 b/d from 238,000 b/d.
Syncrude expected to ship more than 76 million bbl of synthetic crude in 1997. It said operating costs had fallen to about $13/bbl.
Gulf Canada Resources Ltd. said it would spend $1.1 billion in five stages to develop its Surmount heavy oil leases 36 miles southeast of Ft. McMurray. It planned to use horizontal drilling rather than mining to recover the oil. Production was to start in 2000 and rise to 20,000 b/d in 2002 and 100,000 b/d by 2006.
Shell Canada Ltd. announced plans for a mining and extraction plant with capacity of 120,000-150,000 b/d 43 miles north of Ft. McMurray. It further planned to build a $1.8 billion upgrader at its Scotford refinery northeast of Edmonton. The plant was to be able to process 140,000 b/d of bitumen, producing an oilsands slurry that could be processed in Alberta or at Shell`s Sarnia, Ont., refinery.
In conjunction with the project, Shell Canada proposed to lay a 311 mile pipeline to Edmonton.
Mobil Oil Canada Ltd. disclosed it was considering a $1 billion oilsands plant at Kearl Lake in the Ft. McMurray region with a production target of 100,000 b/d by 2003. It planned to decide by 2000 whether to proceed.
Weyburn expansion
In a major Canadian upstream project not involving oilsands, PanCanadian Petroleum Ltd. and 36 working interest owners agreed to begin a $1.1 billion miscible carbon dioxide enhanced oil recovery project in 1999 at the Weyburn pool in southeastern Saskatchewan.
CO2 for the project will come to the field in a new 202 mile pipeline to be built by Dakota Gasification Co., Bismarck, N.D. It will be produced in Dakota Gasification`s coal gasification project at Beulah, N.D.
PanCanadian expected the project to boost ultimate recovery by at least 122 million bbl and to extend Weyburn field`s life by more than 25 years.
The project would become Canada`s largest commercial CO2 project.
PanCanadian planned to start injecting CO2 into the Midale reservoir in 1999, reaching rates of 95 MMcfd. It expected production to rise to nearly 30,000 b/d from 22,000 b/d in 1997 and probably 18,000 b/d by the time injection began.
The Midale, encountered at an average depth of 4,655 ft, produces 25-34° gravity crude and small volumes of solution gas.
Injection initially was to involve 17 patterns of nine wells each, covering 25% of the total project area. The pattern total was to climb to 36 after injection began and eventually reach 75.
The 52,000 acre Weyburn unit in 1997 had 534 vertical wells, 115 horizontal wells, 171 injection wells, and 146 wells that had been suspended or abandoned.
Discovered in 1954 by Central Del Rio Oils Ltd., which became part of PanCanadian in 1971, Weyburn is one of Canada`s largest oil fields. It had original oil in place of 1.28 billion bbl at the time of discovery. Cumulative production at yearend 1996 was 328 million bbl.
Peak production came in the mid-1960s at more than 45,000 b/d. The field has been under waterflood for more than 30 years.
To deal with production decline, PanCanadian drilled infill wells, followed by single lateral horizontal development wells in the early 1990s, then multilateral horizontal wells.
Other plays
The Weyburn activity was part of a revival of Williston basin interest on both sides of the Canada-U.S. border.
Berkley Petroleum Corp. of Calgary at midyear was conducting one of the basin`s busiest programs in the Weyburn-Midale area, where it and its partners had drilled more than 20 successful wells around a late-1995 deeper-pool strike at Berkley et al. 4-2-7-11w2. The well flowed nearly 2,900 b/d from Ordovician Red River B pay.
The discovery and related successes triggered a flurry of drilling and leasing activity in Saskatchewan and southwestern Manitoba. Both provinces offered operators tax and other drilling incentives.
In western Alberta, Talisman Energy Inc. reported two big gas discoveries in 1997. Talisman Renata Apetowun flowed 52.8 MMcfd of raw gas on initial test near Edson, Alta.. And Talisman HZ Lovett River flowed 22.6 MMcfd after acid treatment with a 3,280 ft horizontal section in the Turner Valley formation.
LNG projects
Phillips Petroleum Co. and partners in 1997 disclosed plans to build what would be the largest liquefied natural gas project in North America.
They planned a $1.4 billion, 3.5 million metric ton/year liquefaction plant at Kitimat, B.C., fed by a new 300 mile, 24 in. pipeline from Westcoast Energy Inc.`s main trunk line at Summit Lake, B.C. The pipeline, parallel to an existing gas line, would have a capacity of 750 MMcfd.
The liquefaction plant would use Phillips`s Optimized Cascade process.
Phillips held a 35% interest in the project. Other participants were Daewoo Corp. 25%, Bechtel Enterprises Inc. 10%, and Pac-Rim LNG Inc. 20%. Korea Gas Corp. was expected to acquire the remaining 10%.
Deliveries to South Korea were to begin late in 1999.
Separately, Westcoast Energy proposed to build an LNG peaking complex in a remote area of southern British Columbia. The facility, east of Sechelt, would be able to liquefy 16 MMcfd of gas for storage in a single LNG storage sphere with a capacity of 3 bcf. During periods of peak demand, the gas would be injected into Centra Gas British Columbia Inc.`s Vancouver Island gas pipeline.
The project was proposed as an alternative to a plan by BC Gas Utility Ltd. to build a 312 km, 24 in. pipeline from Yahk to Oliver, B.C.
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