Canada's East Coast offshore E&D poised for decades of expansion

One of the jackets recently installed for a platform being constructed in the Sable Island area off Nova Scotia as part of the Sable Offshore Energy Project (SOEP), a gas field development led by Mobil Oil Canada Properties. Photos courtesy of Mobil.

The Saipem S-7000 heavy lift vessel working on the SOEP project in the Sable Island area. Photos courtesy of Mobil. [40,865 bytes]
Sedimentary Basins Off Eastern Canada [154,817 bytes]
Grand Banks Fields [44,506 bytes]
Terra Nova Development Schematic [88,249 bytes]
Scotian Shelf Discoveries [112,903 bytes]
Sable Project Layout [141,262 bytes]
Maritimes & Northeast Gas Pipeline [242,614 bytes]
Canada's East Coast offshore exploration and development play is at the starting gate to several decades of expansion.

Crude oil began flowing last November from Hibernia field in the Jeanne d'Arc basin on the Grand Banks off Newfoundland, 200 miles east-southeast of St. John's.

Gas fields with more than 3 tcf of combined reserves near Sable Island off Nova Scotia are under development. Pipeline connections from the Sable Island fields to markets in Atlantic Canada and the U.S. Northeast have been approved.

Work is under way at Terra Nova, the second field being developed on the Grand Banks.

Elsewhere along and off Canada's East Coast, exploration leasing and drilling activity are occurring apace. A lease sale last month of acreage on the Grand Banks netted more than $175 million (Canadian) in winning work commitment bids (OGJ, Sept. 28, 1998, p. 40).

The Grand Banks, which covers 330,000 sq miles with water depths of 300-600 ft, includes five largely unexplored basins where about 90 wildcat tests have been drilled: East Newfoundland, Whale, Flemish Pass, Horseshoe, and Carson (see map, p. 26).

Most activity on the Grand Banks has been centered on the Jeanne d'Arc basin, where more than 63 exploration and delineation wells have been drilled and companies have found 17 fields and 1.6 billion bbl of oil reserves.

The Jeanne d'Arc and Sable areas will continue to be the primary focus of East Coast activity as companies seek to find and delineate more of a postulated hydrocarbon resource estimated at 24 billion boe. About 4 billion boe has been discovered to date.

But initial exploration tests are under way in several other areas that are seen as strong prospects. These include: West Newfoundland, the Laurentian basin south of Newfoundland, and the Anticosti Island area in the Gulf of St. Lawrence.

Hibernia

Production from Hibernia last fall marked the first major payoff on the East Coast since companies began acquiring extensive acreage in the area in 1969 and the field was discovered in 1979.

E&D spending off Newfoundland to date totals more than $9 billion (Canadian).

The $5.819 billion Hibernia project, with estimated reserves of 615 million bbl of crude oil, includes a subsea production system and gravity-based production platform with 150,000 b/d capacity. It is specially designed to neutralize the threat of icebergs, which are a hazard in the area.

Mobil Oil Canada Ltd., a lead partner, has increased its reserves estimates for Hibernia to 750 million bbl and says that peak production could increase to 180,000 b/d from 150,000 b/d. Interests in Hibernia are: Mobil 33.125%, Chevron Canada Resources Ltd. 26.875%, Petro-Canada 20%, Canada Hibernia Holding Corp. 8.5%, Murphy Oil Corp. 6.5%, and Norsk Hydro AS 5%.

Jeanne d'Arc basin

Hibernia is the jump-off point for a number of other fields in the Jeanne d'Arc basin that will be developed as either stand-alone projects or as satellite fields (see bottom map, this page).

Partners in Terra Nova oil field, 22 miles southeast of Hibernia, received regulatory approval in February for their $4.5 billion (Canadian) development project. It will use a steel monohull floating production system (see chart, p. 27). Development drilling is well under way.

In Terra Nova, Petro-Canada has a 29% interest, Mobil 22%, Husky Oil Operations Ltd. 17.5%, Norsk Hydro 15%, Murphy 12%, Mosbacher Operating Ltd. 3.5%, and Chevron 1%. Talisman Energy Inc. also has an interest in an undrilled area of the field.

Gary Bruce, vice-president, offshore, for Petro-Canada, which discovered the field in 1984, says the company expects to have Terra Nova in production by 2000, or possibly sooner.

Bruce says that Petro-Canada and its partners will continue to focus on Jeanne d'Arc for a number of reasons.

For one, the Geological Survey of Canada (GSOC) estimates potential oil reserves in the Jeanne d'Arc basin at up to 5 billion bbl. There could be recoverable hydrocarbons in the other basins, which have been only lightly explored. The pools discovered in the basin to date have substantial reserves. And new technology has reduced the cost of developing offshore fields that less than 10 years ago would not have been economic.

Terra Nova area

Terra Nova has estimated reserves of 400 million bbl of crude, with 300 million bbl in the Graben and East Pool blocks and an estimated 100 million bbl in the Far East pool.

The oil is located in five main reservoirs at depths of 11,000-13,000 ft. Eight delineation wells have been drilled since the discovery was made. A total of 24 will be drilled by start-up.

A production profile calls for Terra Nova oil to be recovered over 16 years, with peak production of about 115,000-125,000 b/d. Use of horizontal well technology for the production wells has increased estimates of recoverable oil.

Petro-Canada was operator for a 3D seismic survey this summer covering 386 sq miles on Grand Banks leases acquired earlier by Petro-Canada, Chevron, Mobil, and Norsk Hydro south of Hibernia field and southwest of Terra Nova.

Bruce says Petro-Canada expects to see a new field developed every 2-3 years in Jeanne d'Arc for the next 15-20 years.

He cites three significant discoveries close to Terra Nova that could be tied into the field, including Hebron field, which had initial reserves estimates of 190-200 million bbl. There could also be substantial reserves in Ben Nevis fields, northeast of Terra Nova. Chevron said recently that the Hebron-Ben Nevis fields could contain a combined 600 million bbl of oil, three times the original estimates made in 1981, subject to delineation drilling results.

"We will be trying to decide by 1999 where we are going to go after Terra Nova. There are a number of options. Hebron has the potential to be a stand-alone field, and we are planning a delineation well there," Bruce said.

"Our next plan is to drill two wells at Whiterose and confirm that it has reserves that could be in the 150-300 million bbl range. Then we are looking at an exploration well on a large structure called Riverhead, south of Terra Nova, with the potential to be as big as Hibernia. We hope that Hebron, Whiterose, or Riverhead will have the potential to be stand-alone fields, and the results of drilling will establish our priorities."

Drilling plans

A consortium of Chevron Canada Resources, Mobil Canada, Petro-Canada, and Norsk Hydro has disclosed plans for up to four exploratory tests in a 1-year drilling program in the Jeanne d'Arc basin. The first two wells will be drilled in Hebron and Whiterose fields, with the first test slated to spud in October.

Amoco Canada Ltd. is considering a follow-up well to its successful West Bonne Bay test late in 1997, which was designated as a significant discovery area. The company has not released results from the first well, 9 miles northeast of Terra Nova, but said in 1996 that the structure potentially could contain 300 million bbl of oil. A second test with partners is possible in 1999.

Husky, as operator with a 43.8% interest, plans delineation drilling in September in Whiterose. The company, which has interests in 11 significant development areas and a 50% interest in the Cape Race exploration license, is expanding its East Coast activity. The company bought additional interests in June in 12 significant discovery areas including Whiterose, Terra Nova, North Ben Nevis, Nautilus, and Mara fields from Gulf Canada Resources Ltd. and Talisman Energy Inc. The deal added 54,362 net acres to Husky's holdings in the Jeanne d'Arc basin.

Companies are building up their land portfolios in the area. At the Grand Banks lease sale last month, seven companies spent $175.3 million to acquire additional lands in the Jeanne d'Arc and Flemish Pass basins. Mobil Oil Canada was the biggest spender at $48.37 million. Other companies, most already active in the area, were Chevron Canada, Petro-Canada, Norsk Hydro, Husky, PanCanadian Petroleum Ltd., and newcomer Tatham Offshore Ltd., which spent $1 million for a seat at the table.

Bruce says the Hibernia and Terra Nova fields are the key projects that will establish the oil industry off Newfoundland and sustainable production in the area over the next 20-30 years.

Scotian Shelf

The first major gas field development is under way on the Scotian shelf off East Canada, and a new joint venture exploration program has been announced in the area.

GSOC estimates Scotian shelf postulated gas reserves at 18 tcf.

Development drilling is well advanced at the Sable Offshore Energy Project (SOEP), near Sable Island off Nova Scotia. The $3 billion project will produce more than 3 tcf of natural gas and send the gas via pipeline to markets in Atlantic Canada and New England. Partners are: Mobil Oil Canada Properties Ltd., Shell Canada Ltd., Imperial Oil Resources Ltd., Nova Scotia Resources Ltd., and Mosbacher Operating Ltd. The $2 billion first phase, slated for completion by December 1999, includes production and gathering facilities in Thebaud, North Triumph, and Venture fields and a $1 billion pipeline and gas processing plant at Goldboro, N.S. (see schematic above).

The Maritimes & Northeast pipeline project, which is linked to SOEP, has received approval and is scheduled to be put in service in 1999. It will move sales gas at volumes of 460 MMcfd. The $1 billion second phase, slated for completion by 2006, includes facilities and gathering lines for Alma, Glenelg, and South Venture gas fields. Initial production will be for 25 years.

Mobil Canada's outlook

Ken Miller, Mobil Canada frontier vice-president, says more than 2 tcf of additional gas has already been identified at about 11 Sable satellite fields that could be tied into production at Thebaud when needed. He says the SOEP is market-driven, with the market anchored in growing gas demand in the U.S. Northeast; accordingly, he expects SOEP to be producing well beyond an initial 25 years.

Miller says Mobil is the only company that has interests in all areas off the East Coast, including West Newfoundland, Artimon, and the Laurentian basin.

"Mobil has a very large position, and we believe the East Coast is going to be a core producing area for Mobil for a very long time. We expect to have 100,000 boed flowing by 2000-and that's Mobil's share only-and our goal is to double that in the next 5-10 years. The East Coast is one of the jewels in the Mobil crown," Miller said.

A new joint venture of Mobil, Shell, and Imperial covers acreage surrounding the SOEP. Mobil and Shell each have 40% and Imperial 20% in the acreage, with a joint technical team to manage an exploration program. That included a $15 million 3D seismic survey on the acreage this summer. The companies acquired property in May covering more than 59,000 acres. They also hold acreage in the area acquired in 1995, which includes the Adamant prospect adjacent to Thebaud field. Exploratory tests are being considered for the Adamant area in 1999 or 2000.

Among other eastern Canada offshore operators bidding for acreage this past spring, Chevron won a license for acreage near Sable Island, and PanCanadian Petroleum Ltd. acquired two licenses in the area, one near its Cohasset oil field.

PanCanadian's two offshore parcels cover 48,824 acres and 257,613 acres, respectively. It has a development agreement for the areas with Norsk Hydro and Murphy.

PanCanadian said it remains optimistic on East Coast prospects, although it came up dry in June on a $15 million exploration program on the Grand Pre Block, 15 miles west of Sable Island. The location is adjacent to Cohasset field, where the company now produces oil.

West Newfoundland

West Newfoundland is seen as an elephant-hunting area with considerable geological potential that has been only lightly explored to date. Structures are similar to the Ellenburger and Arbuckle dolomites of West Texas and Oklahoma.

Hunt Oil Co. and PanCanadian Petroleum Ltd., leaders in recent exploration in the area, plan to drill a new test on Shoal Point on the Port au Port Peninsula, with spudding scheduled for December 1998.

The $10 million test, on exploration license 1021 using a conventional land rig, will be drilled from a location near the end of Shoal Point to a targeted formation at 7,874 ft and about 2,296 ft laterally offshore from the drillsite.

The wildcat is the latest in a series of tests in the area dating to September 1994, when Hunt/PanCanadian spudded Port au Port 1 on the southwest corner of the peninsula. It was drilled to 15,318 ft and encountered one hydrocarbon-bearing zone as well as several other reservoirs. Hunt, the designated operator, tested four intervals in the well, two of which flowed oil. One test yielded 1,528 b/d of oil, and the other flowed 1,742 b/d.

In 1995, Hunt and PanCanadian drilled Long Point M-16 from an onshore location on a license held by Mobil Oil Canada Properties. The well was abandoned.

In February 1996, Talisman Energy spudded the Long Range A-09 well at Cape St. George on the Port au Port Peninsula to an offshore location on license 1008. The well tested water and was abandoned.

In May 1996, Hunt/PanCanadian spudded the St. George's Bay A-36 offshore test 4.5 miles southwest of Cape St. George. The test, drilled in 262 ft of water with the Rowan Gorilla IV jack up, was abandoned after reaching a depth of 10,630 ft. It was the first well drilled from a location off West Newfoundland.

Several other companies have drilled in the area.

The Delpet Vinland Big Spring No. 1 onshore well targeted the Catoche and Table Point formations within the St. Georges and Table Head zones at a target depth of 4,000 ft. It was suspended after encountering oil stains and sour gas at 1,148 ft. The company said it was encouraged by hydrocarbon traces at shallow levels and is seeking additional funding for the project.

The Man of War I-42 test was spudded late in 1997 adjacent to PanCanadian/Hunt acreage. The target depth is 8,000 ft, to the Cambro-Ordovician formation, which features a large structure both onshore and offshore. The well has been suspended, and partners are seeking additional funds. The consortium seeking a farmout on a Vinland concession consists of Inglewood Resources of St. John's, Newf., and LMX Resources Ltd., Vancouver, B.C.

In addition, a farmout has been negotiated with the Inglewood/LMX group on Vinland acreage covering 148,258 acres in the Deer Lake basin of West Newfoundland.

Anticosti Island

Two tests have been drilled in a four-well farmout by Shell Canada Ltd. and Encal Energy Ltd. on lands held by Corridor Resources Ltd., Halifax, N.S.

Shell Vice-Pres. Roger Brundit says that geology at Anticosti in the Gulf of St. Lawrence is similar to West Newfoundland and that costs are lower. Previous tests by other companies have produced oil shows.

Shell was operator for the Roliff No. 1 test this summer, which was abandoned after it encountered minor shows of natural gas but no commercial quantities of hydrocarbons.

A second test, Jupiter 1, also encountered gas shows but no commercial hydrocarbons.

A third test is scheduled by yearend 1999 and a fourth by yearend 2000. Shell and Encal also completed acquisition of 248 miles of new seismic data this summer.

Laurentian subbasin

Exploration activity in the Laurentian subbasin has been hampered by jurisdictional problems in this area south of Newfoundland and the French islands of St. Pierre and Miquelon.

France recently granted Gulf Canada an exclusive, 3-year permit to explore an 800,000-acre block 56 miles south of the French islands. Several other companies are also interested in the area.

The Gulf permit area is part of a 5.4 million-acre exploration block subject to an exploration moratorium since the late 1960s. The remaining 4.6 million acres is under the jurisdiction of Newfoundland and Nova Scotia, which have negotiated this year to try to resolve jurisdictional issues.

Gulf has acquired and reprocessed seismic data over the whole area. It plans additional seismic work and a well on the French acreage in 2000.