The preceding year has brought a raft of changes to the international exploration picture; the CSEG Recorder looks at some of the hot-spots, not-spots and up-and-comers for the year.
Since early 1999, the price of oil has almost tripled, but seismic exploration has lagged. “It’s better this year, the only question is, how much better?,” says Charles Darden, president of the International Association of Geophysical Contractors (IAGC), based in Houston.
“It’s not as busy as it should be,” agrees Western Geophysical’s Jeff Mayville, in Houston. “Seismic just hasn’t turned around as quickly as drilling.”
Fortunately, one of the major hot-spots for exploration in 2000 has been right in our own backyard; the Mackenzie Delta. While natural gas discoveries in the region have dated back to the 1970s, a number of positive factors have recently come together to rejuvenate Canada’s north; sustained high prices and demand in the U.S., the settlement of Aboriginal land claims, improved pipeline technology and the extension of infrastructure northwards.
The result has been a stampede into the Arctic. In January, Chevron Canada Resources completed a gas well near Fort Liard, (just north of B.C.) that tested at 50-75 mmcf/d. The well confirmed a previous discovery well, drilled in 1999, that tested at 75 mmcf/d.
AEC will drill up to four wells this year near oil-prone Norman Wells in an effort to find oil fields in excess of 100 million barrels.
Petro-Canada, Anderson Resources, Burlington Resources and Poco have work commitments totaling $183 million following successful bidding in 1999 for mineral parcels in the Mackenzie Delta, and Imperial Oil, Gulf Canada Resources, Shell Canada and Mobil Oil Canada will launch a feasibility study to exploit 6 Tcf of previously discovered Mackenzie Delta reserves.
There are three main exploration targets in the Mackenzie Delta. “The Fort Liard play is a largely structural, a foothills type fold and thrust belt that creates large anticlinal features,” says David Newman a geologist with Sproule Associates (which recently completed a study entitled Hydrocarbon Potential and Exploration Play Trends in the Northwest Territories and Yukon). “The reservoirs are low porosity Devonian carbonates with high fracture-induced permeability. So far, 1.2 Tcf of gas has been discovered in four fields, with the potential for a further 4 Tcf of gas.”
The Norman Wells oil play (approximately 600 km north, in the Mackenzie River valley), is in Devonian carbonate reefs. “The reefs create a drape feature that shows up especially well on seismic,” says Newman. “So far, 260 million barrels of oil have been discovered, with the potential for another 100 million barrels. There is a small amount of associated gas, with the potential of 1.5 Tcf.”
The Mackenzie Delta, which lies another 500 km north, adjacent to the Beaufort Sea, has several distinct traps. “Tertiary delta sands from the Mackenzie system have been folded and faulted to create structural traps in which 2 Tcf have already been discovered,” says Newman. “Undiscovered gas stands at approximately 8 Tcf. There is also 164 million barrels of oil, with the potential for another 371 million bbls.”
Finally, Tertiary sands that have been deposited further out in the Beaufort Sea hold great promise. “In all, undiscovered reserve potential stands at 5 billion barrels of oil and 53 Tcf of gas for the region,” says Newman.
And, they’ll all need new seismic coverage. “There’s about 30,000 kilometres of 2D from the 1970s and 1980s,” says Rudy Belanger, spokesman for KP Seismic. “There’s a dense grid of data in some areas, but there’s still sparse coverage in most of the Mackenzie Delta. There’s a lot of ground to cover.”
“Business is good,” says Al Chatenay, Canada Manager for Schlumberger’s Reservoir Evaluation Seismic Division. “We had over 2,000 channels of equipment scheduled from mid-summer through December last year (near Ft Liard), which is half a crew year, and I think we’ll see something similar this year.”
Schlumberger is also present in Norman Wells. “We shot 300 km of 2D this last winter around Norman Wells, which is the primary season,” say Chatenay. “You can get equipment in via ice roads.”
The building of a pipeline remains the main question mark to further Arctic exploration. The Foothills or Alaska Natural Gas Transportation System (ANGTS), that routes its way through Alaska and the Yukon into Northeast BC., already has regulatory approval. “But it’s expensive, at around $6 bn,” says Bob Reid, vice president for TCPL.
The other major route is straight down the Mackenzie Delta. “We think it can be done for less than $3 billion, with a toll to the Alberta border of under $1, which is economic at today’s gas prices,” says Reid. The most optimistic completion date is near the end of the decade, giving oil and gas companies a 10-year window to find and prove up reserves.
East Coast Offshore
The second major play to see an increase in activity this year is also in Canada. “The East Coast was one of the bright spots for industry this winter, and we’re quite pleased with the level of activity,” says the IAGC’s Darden.
“We will acquire a great deal of 2D and 3D seismic this summer,” says Doug Bogstie, exploration services manager for Schlumberger. “The activity is based on lease sales, and we expect to see a lot, especially off the Scotian Shelf. There’s going to be more seismic activity there this summer than in any one of the last 10 years.”
There are two major plays on the East Coast; the Scotian Shelf and the Grand Banks. The Grand Banks play, located on the continental shelf approximately 400 km off the coast of Newfoundland, has been explored for over two decades. “The main reservoirs are unconsolidated Jurassic and Cretaceous sands,” says Sproule’s Newman. “Most of the fields are found in a large, trans-basin fault trend that has resulted in a horst-graben configuration. Various structural plays including normal faults and drape features, provide seals and/or traps.”
The first major discovery, Hibernia, came on-stream in 1997 with production exceeding 150,000 b/d, and Husky is firming up development plans for the South White Rose field, with recoverable oil reserves in the 250 million barrel range. “Total recoverable oil reserves for the Grand Banks now stand at 1.6 billion barrels,” says Newman. “Over 4 Tcf of gas has been discovered, with an undiscovered potential of 10 Tcf.”
But the major area of activity this year is on the Scotian Shelf. Located approximately 250 km southeast of the Nova Scotia shoreline, the play follows a northeast-southwest trend for over 500 km. “The main reservoirs are unconsolidated Jurassic sands with high porosity and permeability,” says Newman. “Plays include a mix of structural traps associated with spreading margins, salt and mud diapirs, and basement deformation.”
In late 1999, Sable gas field went on-line with 100 mmcf/d being delivered to shore. By the end of 2000, production is expected to climb to over 500 mmcf/d. While official estimates place undiscovered potential at 18 Tcf, some explorationists think it may go as high as 50 Tcf.
Thanks to a series of recent sales, work commitments for offshore Nova Scotia now total approximately $700 million. Shell plans to shoot 2,500 km of 3D, Petro-Canada has 2,000 sq. km of 3D scheduled, and PanCanadian will run 6-8000 sq. km of 3D and 1,500 km of 2D during the spring and summer.
Much of the recent activity is spurred on by a successful PanCanadian well completed last winter. “We drilled into a deeper zone beneath the Panuke (oil) field and tested over 500 mmcf/d,” says Boras. “One possible scenario (for gas reserves) is 1 Tcf, but there’s still a long ways to go. If we develop Panuke into Sable size, we’re talking around 60,000 to 80,000 boe/d by 2008.”
Gulf of Mexico
Several of Canada’s major international players, including Canadian Occidental and PanCanadian, continued exploration in the deepwater Gulf of Mexico, where BP Amoco-Mobil recently discovered the Crazy Horse field (with around 1 billion boe).
Canadian Occidental, which currently produces 10,000 boe/d and 95 mmcf/d from its shallow and onshore fields in the Gulf, has 69 deep water blocks. In 1999, two deep water wells were drilled - Kilimanjaro and Nag. In 2000, CanOxy plans to start drilling wells in ultra deep water - 1,600 m or deeper.
PanCanadian has 39 blocks in the deepwater Gulf of Mexico. “We are planning to drill three or four wells this year to delineate the Llano discovery of 1997,” says spokesman Al Boras. “The Llano development could hit 80,000 b/d, which nets out 16,000 to us.”
Seismic work has tapered off, however. “There are 19 crews working the deepwater Gulf of Mexico, which is down considerably from last year,” says IAGC’s Darden. “Much of the seismic fleet working down in Brazil came from the Gulf of Mexico.”
In spite of the success of oil plays in the region, there is some concern that the region holds less natural gas than expected. “The deepwater Gulf of Mexico has not turned out as hoped,” says Michael Doyle, president of Petrel Robertson, an oil and gas consultancy. “Why do you think they’re suddenly looking at the Mackenzie Delta?”
The deepwater play off the west coast of Africa extends for over 2,000 kilometres, from Equatorial Guinea in the north, to Namibia in the south. It is all part of the passive margin spreading that occurred during the latter half of the Mesozoic. Thick fans of Jurassic and Cretaceous river clastics spilled into the widening basins, and turbidites and other deepwater clastics also began to accumulate further offshore. Fault movements, salt diapirs and slump features created various trap structures in the sediments that may hold as much as 30-40 billion barrels of oil.
Although Nigeria has traditionally proved a favourite hunting spot for oil companies, Angola is the number one target for 2000. “All along the coast is good, but Angola is no doubt the hottest play,” says Rudy Cech, vice president of Sproule Associates. “They have 37 blocks for license, and some are still open. Agip’s block 15 alone is estimated to contain four billion barrels.”
Cech estimates that 10-15 wells will be drilled off Angola this year. “Most are extension wells in areas like Chevron’s Kuito Field and Elf’s Girassol field. It’s all pushed by deepwater technology developed by the Brazilians and Norwegians.”
The African country hopes to get production onstream as quickly as possible. “In 1990, Angola had around 500,000 b/d production, and by 2003, it’s going to be over one million,” says Cech. “Over the next three years, companies are looking at spending $4 billion in exploration and development.”
Brazil, the geologic mirror image of west Africa, has onshore and offshore reserves estimated at 20-25 billion barrels. The offshore Campos Basin alone holds an estimated 11.5 billion barrels in Upper Cretaceous and Tertiary stratigraphic reservoirs.
Much of the exploration activity in 1999 was spurred by the signing of 12 contracts for offshore work, a first for Brazil. Approximately 22 seismic vessels plied the waters and over 60 well completions were recorded, including a world record for deepwater, a wildcat in 2,770 m of water.
Although seismic work continues this year at a healthy pace, many of the contractors are banking on E&P companies picking up the tab at a later date. “The problem is that most of the seismic fleet offshore Brazil is spec, not proprietary,” says Darden. “They assume all the risk, and that’s not the way we prefer it.”
The exploration potential of the Caspian Sea, with water depths exceeding 450 m, is slowly being proven up. “There are two trends; the gas-prone Azerbaijan play trending SE into Iranian waters, and the (oil-prone) North Caspian,” says Cech.
The big news over the last year has been the BP Amoco/Statoil Shah Denis gas discovery in Azerbaijan waters. “There could be 1.5 Tcf and 1.5 billion barrels of condensate,” says Cech.
The well with the highest expectations in the North Caspian, Lukoil’s Khvalynskaya-1 (in Russian waters), is still drilling. “Estimates (for the structure) range from 2-14 billion barrels,” says Cech.
Regardless of the outcome, the main drawback of the Caspian is building a safe and secure pipeline. “There’s no easy way to get it to market,” says Cech. “You’ve got Russia to the north and Iran to the south.”
“North Africa is where Canadian companies are having success,” says Petrel Robertson’s Michael Doyle. “There have been some very substantial discoveries in Algeria and Libya, and Tunisia is slow but steady.”
The biggest change has been the revived openness by Libya after reductions in international sanctions. “Lundin Oil (of Vancouver) made two recent discoveries the En Naga fields in the Sirte Basin which may hold over 100 million barrels,” says Cech. “They’ve got 2D and 3D seismic planned. There could be up to one billion barrels in the basin.”
Several plays, including the Carnarvon Basin in Australia, onshore Colombia and offshore Indonesia continue to attract international attention, but it may be some time before they see major seismic activity. “Some contractors think that the improvement will be marginal, while others are more optimistic, and see some major improvement in the 3rd and 4th quarters,” says Darden. “Nobody has a crystal ball to tells when the oil company budgets will open up again.”