NEWFOUNDLAND`SSTART-UP of production from Hibernia field on the Grand Banks frontier made 1997 a pivotal year for the province.
The field, discovered in 1979 and under development planning for about 5 years, kicked off an expected 19 year productive life on Nov. 17, 1997 (Fig. 1, Table 1).
Final governmental approvals were expected in late 1997 for development of large Terra Nova oil and gas field nearby.
Intense exploration and development interest in Newfoundland sprang not only from the Hibernia production start in the Jeanne d`Arc (also known as Avalon) basin but also from realization that several years of wildcatting had all but established commercial production in western Newfoundland in the area of the Port au Port peninsula. A large portion of western Newfoundland`s land and coastal waters was under license at yearend, and exploratory drilling was to continue there in 1998.
Grand Banks production was likely to rise to 10% or more of Canada`s light crude and condensate output in 1998 and might reach as much as 30% by 2005.
Newfoundland was attempting to generate interest in exploitation of gas from Hibernia and other fields and large undrilled resources believed to lie on the Grand Banks.
Hibernia starts production
Mobil in late 1997 boosted its estimate of Hibernia`s reserves to 750 million bbl from its earlier estimate of 615 million bbl, citing application of new technology.
The field is in 80 m of water 315 km east-southeast of St. John`s. Mobil expected production to reach 135,000 b/d by early 1999. The production system, designed for 150,000 b/d, could be expanded to 180,000 b/d with additional investment.
The field`s oil reservoirs, Cretaceous Hibernia sand at 3,700 m and Cretaceous Avalon sand at 2,400 m, hold a combined 3 billion bbl of oil in place.
The 32° gravity, low sulfur oil is expected to contribute about 10% of Canada`s crude and condensate production. It is to be shipped by tanker to refineries in the Canadian Maritime Provinces and Northeast U.S.
Oil in place is estimated at nearly 2 billion bbl in Avalon and more than 1 billion bbl in Hibernia. Only about 5% of Avalon oil is deemed recoverable economically due to uncertainties regarding reservoir thickness.
Mobil said the increase in its estimate of Hibernia reserves resulted from a review of companywide experience worldwide with extended reach and horizontal drilling, water and gas injection, and seismic profiles of both reservoirs. The review suggested that of Mobil`s 135 million bbl increase, more than 50% will come from Avalon, which is farther from the production facilities, and the rest from Hibernia.
Interests in Hibernia are Mobil 33.125%, Chevron Canada Resources 26.875%, Petro-Canada 20%, Canada Hibernia Holding Corp. 8.5%, Murphy Atlantic Offshore Oil Co. 6.5%, and Norsk Hydro 5%.
Hibernia was being developed from a 680,000 ton, iceberg-resistent concrete gravity-base structure (GBS) capable of accommodating 64 wells and storing 1.3 million bbl of oil. Floating rigs were to drill as many as 25 more wells later for subsea completion and tieback to the GBS.
Terra Nova field
Another group had a $2 billion (Canadian) project to develop Terra Nova oil and gas field (Fig. 2, Table 2).
The 1984 discovery, in 90-100 m of water 35 km east of Hibernia, has reserves of 406 million bbl of 33° gravity, low sulfur crude in Upper Jurassic Jeanne d`Arc sand at 3,200-3,700 m. An undrilled eastern extension area could hold another 100 million bbl recoverable.
The field is to start up in 2001 or earlier, making about 100,000 b/d of oil and 75 MMcfd of gas from 19 producing and 13 pressure maintenance wells and producing for 15-18 years. Estimated capital cost to start up is $1.6 billion.
Interests are Petro-Canada 34.2%, Mobil Oil Canada Properties 20.7%, Husky 15.8%, Norsk Hydro AS 15%, Murphy 10.7%, and Mosbacher Operating Ltd. 3.6%.
Whiterose field
Also poised for development in 1997 was Whiterose oil, gas, and condensate field in 125 m of water 50 km east of Hibernia field (Fig. 2, Table 2).
The 1984 discovery is held by Husky, operator, 42%, Petro-Canada 25%, Talisman 17%, and Gulf Canada and Parex each 8%.
Reserves are estimated at 250 million bbl of oil and condensate and 1.5 tcf of gas in Cretaceous Ben Nevis and Avalon. The discovery well cut 100 m of net pay.
Thirteen horizontal or highly deviated producing wells and 10 injection wells could start up in 2004. Rate would be about 75,000 b/d through a floating system.
Grand Banks exploration
The ministry in 1997 tallied 21 discoveries of technically recoverable reserves in the frontier area off Newfoundland and Labrador out of 140 exploration and delineation wells drilled during 3 decades (Table 2).
Discoveries through 1996 totaled 1.6 billion bbl of recoverable oil, 4 tcf of gas, and 237 million bbl of natural gas liquids. The total oil potential of the Jeanne d`Arc area is estimated at 3.3-5.3 billion bbl.
The discoveries off Newfoundland through 1997 were Ben Nevis, Fortune, Hebron, Hibernia, Mara, Nautilus, North Ben Nevis, North Dana, South Mara, South Tempest, Springdale, Terra Nova, Trave, West Ben Nevis, and Whiterose. All are in the Jeanne d`Arc basin.
A string of basins extends from south to northeast of St. John`s generally along a southwest-northeast trend. They are the South Whale, Whale, Horseshoe, Carson, Jeanne d`Arc, Central Ridge, Flemish Pass, and Orphan basins. The East Newfoundland basin lies northeast of St. John`s and northwest of the Jeanne d`Arc basin.
The discoveries recognized in 1997 off Labrador were Bjarni, Gudrid, Hopedale, North Bjarni, and Snorri gas/condensate finds and the North Leif oil find. All were drilled in 1973-81.
Advances such as horizontal drilling rendered economic smaller fields of about 100 million bbl of reserves each, such as Mara and Nautilus near Hibernia.
Mobil, Chevron, Petro-Canada, and Norsk Hydro planned one well to appraise Hebron field, 25 miles southeast of Hibernia, discovered in 1981. Hebron was estimated to contain 195-700 million bbl of oil reserves.
Mobil and Chevron cited potential cost reductions in forming a joint venture in 1997 to explore 29 million acres in the Jeanne d`Arc basin on the Grand Banks. Mobil said the unified approach will allow the companies to move more quickly.
Amoco Canada, Petro-Canada, and Norsk Hydro in 1997 spudded a wildcat on Amoco`s West Bonne Bay prospect 9 miles northeast of Terra Nova field. Amoco listed the potential at as much as 300 million bbl of oil in the Cretaceous Hibernia and Jeanne d`Arc formations to 14,000 ft.
Mobil noted that it has a strong position in Atlantic Canada with the Hibernia, Sable Island, and Terra Nova developments. With this infrastructure in place, the company saw other attractive opportunities it said would provide profitable growth in production for Mobil and contribute to the economic growth of Canada`s East Coast.
A Husky-led, 10 company partnership let a contract in early 1997 to PGS Exploration for 45,000 CMP-km of 3D seismic surveys on the Grand Banks 300 km east of St. John`s. The contract represented the largest seismic survey conducted off Canada.
The partnership included Petro-Canada, Chevron, Gulf, Murphy, Mobil, Talisman, Parex, Norsk Hydro, and Mosbacher. Husky was to supervise operations for Whiterose field, and Petro-Canada was to oversee operations for Terra Nova and Hebron-Ben Nevis fields.
An eye toward Grand Banks gas
The government of Newfoundland and Labrador had begun expressing interest in development of its Atlantic gas resources.
Newfoundland`s Mines & Energy Ministry claimed reserves of 4 tcf off Newfoundland and a further 4.2 tcf off Labrador. It placed potential reserves at 52 tcf.
Pipeline groups proposed a spate of projects in 1997 to transport gas from eastern Canada, but almost all of the ventures involved gas from fields in the Sable Island area off Nova Scotia.
However, North Atlantic Pipeline Partners LP sought National Energy Board approval for a $3.5 billion project that would serve the Grand Banks. The 2,500 km, 3 phase system would extend from the Grand Banks to Seabrook, N.H. It would be the world`s longest undersea gas pipeline if built. It, too, would serve Sable Island fields initially.
Phase 1 called for construction of 925 km of 42 in. pipe from Country Harbor, N.S., to Halifax, N.S., and Seabrook, N.H., by November 1999. The other two phases would involve 36 in. extensions into Newfoundland and across the Laurentian Channel, allowing development of extensive reserves in those areas.
North Atlantic, represented by Tatham Offshore Canada Ltd., said the system would stimulate and enhance development of major gas reserves off Atlantic Canada. It said the proposal was the only one that addressed 50 tcf of gas estimated for the region by serving areas off Newfoundland and eastern Nova Scotia near Cape Breton.
Initially, associated gas produced with start-up of Hibernia oil field was to be reinjected and used in producing operations.
Western Newfoundland
Release of well information indicating an all but commercial oil discovery on the Port au Port Peninsula stoked interest in the western area of the island province. A large number of licenses were in force (Fig. 3).
Results of a Hunt Oil Co. and PanCanadian Petroleum Ltd. well became public on Aug. 1, 1997 after a 2 year confidential period. Drillstem test results appeared to indicate the possibility of a limited reservoir or complex geology, but the well flowed 51° gravity, unbiodegraded oil (Table 3).
Flow rates reached 1,742 b/d of oil, 2.3 MMcfd of gas, and 252 b/d of water from the Middle Ordovician Table Head Group at 3,459.2-3,462.2 m and 1,528 b/d of oil, 2.6 MMcfd of gas, and 985 b/d of water from the Lower/Middle Ordovician St. George/Table Head Group at 3,471.7-3,476.2 m. Two deeper tests of the St. George Group yielded water.
The well was believed to have proved that a Cambro-Ordovician source is charging the deep autochthonous platform, implying existence of a petroleum migration system in the area.
Various other operators planned to drill at least five other wells in western Newfoundland during end-1997 and 1998.
PanCanadian planned to spud a $9 million wildcat at Shoal Point early in 1998 (Fig. 4). The lease is held by PanCanadian and Hunt Oil Co. each 37.5% and Mobil Oil Canada Properties 25%. Hunt decided to farm out its interest.
A number of independent operators were plotting strategy for onshore license blocks covering nearly the entire western coastal strip. At least four wells as deep as 8,000 ft were to be drilled there in late 1997 and 1998. They were:
- Inglewood Resources Inc., St. John`s, Man of War I-42, projected to 8,000 ft, surface location at Campbell`s Cove on Port au Port Peninsula, bottomhole location in eastern part of EL1008 Block B.
- Inglewood, two wells in Deer Lake basin on blocks 93-103, 93-104, and 96-114.
- Vulcan Minerals, St. John`s, one well to 1,500 m on Block 96-105.
Hibernia field, despite its importance, is not the province`s first hydrocarbon production. Of nine wells drilled in the Shoal Point area of the Port au Port Peninsula, seven encountered oil, and some limited production occurred in the early 1900s. From the 1860s to 1960s, about 27 wells were drilled and some 6,000 bbl of oil produced in the Parsons Pond-St. Pauls Inlet area along the west coast north of Port au Port.
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The Hibernia platform on location 315 km east-southeast of St. John`s, on the Grand Banks, Newf. (Photo courtesy Hibernia Management & Development Co. Ltd.). (Fig. 1)
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