CAPITAL: OTTAWA
MONETARY UNIT: DOLLAR
REFINING CAPACITY: 1,906,250 B/CD
OIL PRODUCTION: 1,998,500 B/D
OIL RESERVES: 4.7 BILLION BBL
GAS RESERVES: 61 TCF

Oil prices exceeding $25/bbl prompted Canadian operators to commit more than $9 billion during 2000 for future oil sands development projects in Alberta.

Husky Energy Inc., Calgary, planned to invest $5.25 billion over 10 years in three oil sands projects.

One project would be at Tucker Lake, west of Cold Lake, Alta. Two others would be at Kearl Lake, on leases 50 miles north of Fort McMurray.

The Tucker Lake project would be the first of the phased projects and would cost $350-450 million. Husky planned a target of 15,000-20,000 b/d of production by 2004.

The Kearl Lake No. 87 lease, which would be developed later, covered 48,880 acres. Husky owned 51%, and Imperial Oil Ltd., Toronto, had 49%.

The two companies also held a smaller adjacent lease, No. 6, to the north on a 50:50 basis.

Husky was considering a pit-mining operation to recover bitumen on the northern half of lease 87 and part of lease 6. The southern half of lease 87 was being considered for steam-assisted gravity-drainage recovery.

The southern half of lease 87 would be developed first at a cost of $1.6 billion. Production would start between 2005 and 2007. The pit-mining operation would cost at least $3.2 billion with a completion date between 2008 and 2112.

The Syncrude Canada Ltd. consortium produced 74.2 million bbl, an average 203,000 b/d, of its sweet blend crude in 2000 at its Fort McMurray oil sands operation.

It opened its Aurora Mine 22 miles north of Syncrude's main operation at Mildred Lake. It was the first remote mine-extraction facility in the oil sands industry.

Syncrude planned capital spending of more than $900 million in 2001, the largest in its history. It said two stages had been completed of a planned four-stage, $8 billion program.

Stage three included a major expansion of the Mildred Lake bitumen upgrader as well as an additional production train at the Aurora Mine. Stage three was scheduled for completion in third quarter 2004.

Cold Lake

Imperial Oil Ltd. planned a $1 billion expansion of its oil sands operations at Cold Lake.

The expansion would develop an extra 30,000 b/d of bitumen from three new production phases (Phases 14-16) in a new operating area known as Nabiye, which would add 250 million bbl of net proved reserves at Cold Lake.

It also would extend Phases 9 and 10 of the existing Mahihkan operations to an area known as Mahihkan North, adding 125 million bbl of reserves over the life of the development.

Imperial said Mahihkan North could begin production in 2005 and Nabiye in 2006.

Imperial said the expansions, along with development of Phases 11-13 in an area known as Mahkeses, would bring production to 180,000 b/d by the end of the decade.

Nabiye would require some wells, associated field facilities, and a plant to generate steam, process bitumen, and treat water.

The Mahihkan North extension would require 600 wells and other facilities over 5-10 years.

Imperial operated 10 phases of bitumen production at Cold Lake. The operation, which produced 119,000 b/d in 2000, was the largest in situ bitumen recovery project in Canada.

Phases 11-13 of the Mahkeses project, approved in 1999, were under construction in 2000, expected to be operational in late 2002.

Imperial's investment in the Cold Lake area was $1.7 billion. Construction of the Mahkeses development would add $650 million of capital expenditures over 2 years.

Other projects

Petro-Canada, Calgary, began construction of its $290 million McKay River oil sands plant, 36 miles northwest of Fort McMurray. The company also applied for a production increase to 30,000 b/d from an approved 22,000 b/d. The plant was scheduled to go on stream in 2002.

Capital and operating costs were estimated at $10/ bbl. The company also was assessing the potential of its in situ oil sands leases inventory to increase production to 80,000 b/d by the end of the decade.

Petro-Canada was also considering the use of its Edmonton refinery to upgrade and refine 80,000-150,000 b/d of bitumen from McKay River into gasoline. The company would install sulfur reduction equipment at the refinery by 2004 that would be designed so that it could later form part of a bitumen-upgrading process.

The McKay River plant would use steam-assisted gravity drainage technology to produce bitumen from oil sands using pairs of steam injection and production wells drilled horizontally into the oil-bearing formation. The technology had been successfully tested for 10 years at a pilot plant.

Enbridge Inc., Calgary, would build a $55 million, 25-mile pipeline to move McKay River bitumen to the Athabasca Pipeline.

TrueNorth Energy Corp., Calgary, planned a second phase to its proposed Fort Hills oil sands project that would double expected peak production to 190,000 b/d of bitumen and nearly double the project's cost to $2 billion.

TrueNorth and partner UTS Energy Corp. acquired oil sands Lease 8 adjacent to the original leases, 5 and 52, which were acquired in 1998. All the leases were 90 km north of Fort McMurray.

TrueNorth estimated mineable reserves of the project at 2.4 billion bbl, providing for a 30-year project life.

TrueNorth expected the Fort Hills project to produce 95,000 b/d of bitumen in 2005 and add the remainder by the fourth quarter of 2008.

UTS Energy held 22% in Fort Hills. TrueNorth Energy LP, an affiliate of Koch Petroleum Canada LP, operated the project with 78%.

Suncor Energy Inc., Calgary, planned to spend $450 million to double production from its Project Millennium oil sands site to 225,000 b/d by 2002. Suncor estimated the project would cost $2.8 billion.

OPTI Canada Inc. planned a $450 million oil sands project in the Fort McMurray region.

The project would seek approval in 2001 and production of 30,000 b/d in 2004. A second phase planned for 2005 would double output at the site near Gregoire Lake, 25 miles southeast of Fort McMurray.

The proposed plant would use steam-assisted gravity drainage technology to remove the bitumen. OPTI was building a 500 b/d pilot plant near Cold Lake to test the system.

Meanwhile, Japan Canada Oil Sands, Calgary, planned to increase production at its Hangingstone pilot project in northern Alberta from 1,500 b/d to 10,000 b/d by 2005. The project was 31 miles southwest of Fort McMurray.

The company estimated the expansion would cost $130 million. It planned to increase capacity at the pilot plant to 11,000 b/d.

Shell Canada Ltd., Calgary, said it would spend $50 million to restart a heavy oil project in the Peace River area using updated technology. The recovery process, known as soak radial, uses steam to soak bitumen and improve flow of the crude oil trapped in sand.

The company would seek to increase production to 8,000 b/d. Shell would drill 18 multilateral wells, and steam would be injected into the reservoir for 2 months to loosen bitumen for production from the same well.

Shell started a pilot project at the site in 1986 but shelved plans for a large commercial development when crude oil prices fell in 1998. The company said if results were good it would consider expanding the drilling program in 2001 to increase production to 12,000 b/d.

Mackenzie Delta

A pipeline to tap arctic Canada's gas reserves for markets in the US and Canada was a possibility once again, for the first time in more than 2 decades.

Healthy gas prices and forecasts of a 30 tcf/year US market as early as 2010 were creating interest in tapping gas reserves in the Mackenzie Delta.

Imperial Oil Ltd., Toronto, and several other producers with delta reserves were conducting a feasibility study on whether gas could be economically developed and delivered via pipeline from the remote area on the edge of the Beaufort Sea.

Imperial said the study assumed construction of an 800 MMcfd pipeline to extend from the onshore fields to Inuvik on the Arctic Coast and south from there to Norman Wells, NWT, where the company operated an oil field. The 1,090-mile line would likely cost $3 billion.

The pipeline project would be supported by 6 tcf of onshore gas reserves in three fields. Imperial held 3 tcf, Gulf Canada Resources Ltd., 1.8 tcf, and Shell Canada Ltd., 1 tcf. There was an estimated 12 tcf of gas and 1.7 billion bbl of oil in the area adjacent to the Beaufort Sea. Gas potential in the region was estimated at 65 tcf.

From Norman Wells, the gas would be shipped on a right-of-way parallel to an oil pipeline operated by Enbridge Inc., Calgary, to mainline pipe connections in northern Alberta.

Gulf Canada said the group was not expected to make a decision until sometime in 2001. It said a pipeline could be on stream within 5 years.

Three companies formed a joint venture to explore the Mackenzie Delta-Beaufort Sea region.

Chevron Corp., Burlington Resources Inc., and BP planned seismic work in 2000 and a drilling program in 2002.

Chevron Canada and BP Canada would take a 50% interest in 471,386 acres held by Chevron, and Chevron and BP would take one-third interests in 360,761 acres Burlington Canada acquired in 1999. The companies also were partners on a separate 182,851 acres.

Petro-Canada, Calgary, planned to spud the first exploration well in 2 decades in the delta.

The 8,200-ft wildcat 80 miles north of Inuvik, NWT, would cost up to $23 million. Petro-Canada had 60%, and Anderson Exploration Ltd. had 40%.

Extensive seismic work had been done by a number of companies. Four wells were planned for the winter of 2001-02 in the gas-prone region.

Onshore exploration was halted in 1977 after an inquiry recommended a moratorium on drilling in the region while aboriginal land claims were settled. Development at that time also faced opposition from environmental groups as well as poor economics, which would not support a pipeline.

Meanwhile, Canada's new Nunavut Territory opened a large part of its arctic lands to oil and gas nominations.

The Northern Oil and Gas Directorate, Hull, Que., was accepting nominations for Nunavut tracts in a large call area north of 75° N. Lat.

The call area included all of the Sverdrup basin, site of 19 discoveries during 1969-85. Those include a major gas field at Drake Point and Bent Horn oil field. Bent Horn, on Melville Island, produced 43°-gravity sweet crude from a Devonian reef during 1985-96. A group led by the former Panarctic Oils Ltd. shipped that oil by tanker in summers to a refinery at Montreal.

BC offshore

The British Columbia government stopped an effort to lift a long-standing moratorium that prohibited drilling off the province's Pacific coast.

The government said that, although coastal communities needed to diversify their economies, it was more important to protect the environment from the risk of offshore drilling.

A 1972 Canadian and provincial moratorium froze activity on 22 million hectares of federal leases off British Columbia.

In 1998 a Geological Survey of Canada report estimated the offshore region could hold more than 9.8 billion bbl of oil and 42 tcf of gas, with a combined value of more than $50 billion. Geologists said the resources are clustered near the Queen Charlotte Islands, north of Vancouver Island.

Shell Canada Ltd., Petro-Canada, and Chevron Canada still held drilling rights in the area.

An effort was begun in the 1980s to remove the drilling ban, but it ended when the Exxon Valdez tanker hit a reef and polluted Alaska's Prince William Sound in 1989.

A group of Prince Rupert, BC, citizens launched another effort to lift the ban.

The North Coast Oil & Gas Task Force said that the demise of the West Coast fishing industry had helped increase support in coastal towns for offshore exploration.

In 2000, the British Columbia government and Northern Development Commissioner John Backhouse paid a Vancouver consulting firm to gauge the depth of public support for lifting the moratorium.

That report concluded there was enough public interest in the issue, especially along the coast, for the government to reconsider the moratorium.

Terra Nova

Petro-Canada said first production from Terra Nova oil field off Newfoundland would be delayed until late in 2001. It would be the first Grand Banks field to go on stream after the Hibernia field.

Petro-Canada said the delay was due to problems with the floating production, storage, and offloading facility, the first to be used off Newfoundland.

It also said there was no final cost estimate for Terra Nova development, but it could be as much as 15% more than a previous estimate of $2.5 billion.

The company said Terra Nova remained an attractive project with estimated proven reserves of 400 million bbl of crude oil and a projected 15-year production life. Initial output would be 49,000 b/d in 2001, increasing to 129,000 b/d by the end of 2002.

Petro-Canada had 34% of the project, ExxonMobil Corp. 22%, Husky Energy Inc. 12.5%, Norsk Hydro 15%, Murphy Oil Corp. 12%, Mosbacher Operating Co. 3.5%, and Chevron Corp. 1%.

New Brunswick discovery

Province-owned Potash Corp. of Saskatchewan and Corridor Resources Inc., Halifax, NS, had an apparent gas discovery with probable gas reserves of 300 bcf. The 50:50 partners planned several step-out wells.

The McCully 1, 12 km northeast of Sussex, NB, was drilled to 2,657 m TD.

Corridor, an independent with more than 5 million acres in the Maritimes from Quebec to Newfoundland, said McCully field was large enough to serve local markets and eventually warrant connection to the Maritimes & Northeast Pipeline (M&NE).

Corridor had tried to find a partner for the project for 2 years. Drilling occurred after PCS approached Corridor to drill an injection well to dispose of salt water seeping into its potash mine.

McCully 1 cut more than 40 m of net gas-bearing sand within a 340 m gross sand-shale sequence at 2,030-2,370 m.

Within this section, the bottom sand had 22 m of net pay in a relatively continuous vertical sequence. The sands, in the Mississippian Albert formation, had low porosities and permeabilities.

Pressure in the main gas-bearing reservoir was indicated to exceed 4,100 psi. On production tests the bottom sand flowed 750 Mcfd and no water for 3 days. Corridor said McCully wells should be capable of rates of at least 2 MMcfd.

That would require 10 producing wells to initiate deliveries to M&NE, Miller said. He put completed well cost in the area at $1.5-2 million.

Grand Banks potential

The Grand Banks area off Newfoundland was Canada's top offshore exploration and development hot spot, with activity focused on oil prospects in the prolific Jeanne d'Arc basin.

The region also had substantial natural gas reserves, but most analysts put first gas deliveries at 7-10 years away.

Companies had drilled more than 115 wells in the Grand Banks area by late 2000 and identified proven crude oil reserves of more than 2 billion bbl. The Grand Banks covered 330,000 sq miles, with water depths mostly at 200-600 ft.

The Canada-Newfoundland Offshore Petroleum Board in 2000 increased its estimate of discovered reserves off Newfoundland and Labrador to 2.1 billion bbl of crude, 9.3 tcf of gas, and 413 million bbl of gas liquids. It estimated potential recoverable oil in the Jeanne d'Arc basin and the adjacent Ridge complex at 4.6 billion bbl, with 4.09 billion bbl of that in the Jeanne d'Arc basin. Potential recoverable gas in the area was estimated at 18.8 tcf, with 12.6 tcf in the Jeanne d'Arc basin. The board said potential reserves were expressed at a 50% probability, with reserves technically recoverable but economic factors not taken into account.

Hibernia, the first producing field in the region, which came on stream in late 1997, received approval in 2000 to increase production to 180,000 b/d from 150,000 b/d. Estimates of proven reserves at Hibernia were increased to 884 million bbl from 666 million bbl. Natural gas reserves estimates for the field were estimated at 1.4 tcf, and NGL reserves were estimated at 145 million bbl.

Drilling in the Hibernia sands had encountered greater than expected net pay, higher permeability, and lower water saturation, indicating a higher estimate of the original oil in place. The nearby Terra Nova field, with an estimated 400 million bbl of reserves, was scheduled to begin production in 2001. And White Rose field, with estimated reserves of 250 million bbl in the same basin, where Husky Oil Ltd. was operator, was to undergo the permitting process for development, with a production start-up target of 2004.

Other structures in the basin, including Hebron-Ben Nevis and Riverhead, were under exploration or appraisal and seen as potential stand-alone future developments.

The Canadian federal government was working to resolve a boundary dispute between Newfoundland and Nova Scotia that had blocked exploration activity in the Gulf of St. Lawrence area.

Ottawa appointed a three-member arbitration board that would attempt to resolve the jurisdictional dispute by early 2002 and encourage an interim agreement to allow oil and gas exploration to proceed.

The area in dispute covered 23,168 sq miles where 13 oil and gas companies had acquired acreage or expressed interest in exploration.

The arbitration panel's conclusions would be binding. An offshore petroleum accord reached in 1986 gave the bulk of the area to Nova Scotia, but Newfoundland disputed that boundary.

Pipelines

The 2,300-mile Alliance natural gas and liquids pipeline system from western Canada to the Chicago market started up in 2000.

The $4.5 billion line had an initial capacity of 1.325 bcfd and could be increased to 2.1 bcfd. Liquids were extracted and processed at the Aux Sables plant near Chicago.

The line, initially backed by a group of 24 Alberta producers, provided an alternative delivery system to the TransCanada PipeLines Ltd. system for export gas and eliminated a long-standing capacity bottleneck.

Planning for the line began in late 1994 when producers sought an alternative system. The construction and regulatory process took more than 4 years, including a 2-year construction phase.

The system included 14 mainline compressor stations, 37 receipt points in British Columbia and Alberta, and seven delivery points in Illinois. Interests in the Alliance Pipeline were Coastal Corp., 14.4%; Enbridge Inc., 21.4%; Fort Chicago Energy Partners, 26%; Williams Cos., 14.6%; and Westcoast Energy Inc., 23.6%.

A deepwater 85 MMcfgd gas pipeline was proposed to cross from the British Columbia mainland to Vancouver Island.

The Georgia Strait Crossing, as envisioned by partners BC Hydro, Vancouver, BC, and Williams Gas Pipeline, would begin as a 40-mile, 16-32-in. line to move gas from Sumas, Wash., to Cherry Point, Wash., in an established utility corridor.

From Cherry Point, the line would travel 44 miles across the Strait of Georgia, through Boundary Pass and the Satellite Channel in water depths of up to 1,200 ft. About 23 miles of pipe would be in Canadian waters, and 21 miles in US waters.

The line would come ashore on Vancouver Island north of Mill Bay and travel inland 8 miles to connect with the Central Gas Transmission System near Shaw Lake.

Additional compression capacity would be installed at the Sumas compressor station, as would another compressor facility on either the US mainland or Vancouver Island.

If approved, the $120 million project would begin construction during mid-2002, with completion set for November 2002. Williams would be operator.

Pipeline safety

The Canadian National Energy Board took a step toward tighter pipeline safety regulations.

NEB released the results of a survey conducted regarding the proposed Damage Prevention Regulations.

It said more than 80% of respondents indicated strong support for a number of damage prevention activities. They included one-call centers for NEB-regulated pipelines, accuracy requirements for location of lines, standardized crossing designs, development set-backs based on land use, minimum qualifications for pipeline locators, and standards for public awareness programs.

NEB said it would use the information to develop regulations to replace the existing Pipeline Crossing Regulations. The rules would govern activities on or adjacent to pipeline rights of way in the interest of public safety, the environment, and personal property.

NEB said 95% of the respondents said persons marking the locations of pipelines should meet training qualifications, 89% said pipelines should be required to participate in one-call centers, 87% said there should be accuracy requirements for locating lines, and 79% said excavators should be required to locate lines before digging.

NEB reported respondents said "many of the activities currently requiring the approval of the NEB could be delegated to the pipeline companies." It also appeared that some activities requiring approval of either the NEB or the pipeline company could be possibly allowed to proceed without approval of any kind.