Exploration Successes Highlighted

Canada Takes a Bow

Despite being ranked as the world's third largest producer of natural gas and the thirteenth-largest producer of crude oil, the Canadian oil and gas sector is not resting on its laurels.

Specifically, exploration and production activity has ramped up in recent years to capitalize on Canada's high impact exploration plays in the Western Canadian Sedimentary Basin, the remote Frontiers and Alberta's vast oil sands. Competing head-to-head with the best opportunities available worldwide, Canadian exploration plays have attracted the attention of American E&P companies seeking corporate growth through international exploration.

The need to increase production and profitability — combined with the financially attractive Canadian dollar — precipitated the stampede of American E&P companies investing in Canada's under-explored sedimentary basins.

And since the events of September 11, producing oil and gas within a North American continental strategy has never seemed more appropriate. Fundamental to increasing oil and gas self-sufficiency in onshore United States and Canada is the existence of a continental transportation system — one that transcends borders — to deliver Canadian product to a growing American market.

According to Canada's National Energy Board, Canadian exports of natural gas to the United States hit an unprecedented high of 3.83 Tcf for 2000-2001, generating $28.55 billion in revenue. In 2001, according to Sayer Securities Ltd., of Calgary, merger and acquisition activity in Canada hit a record level of $39 billion. The vast majority of the 2001 M&A transactions saw the transfer of Canadian oil and gas assets to American E&P firms.

Of the eleven papers to be presented at the "North American Resources" session in Houston, four will focus on Canadian E&P opportunities and Canadian oil and gas exports to the United States, providing a broad overview of the Canadian exploration scene.

Increasing self-sufficiency.

George Eynon is director of oil and gas resources for Cambridge Energy Associates in Calgary. He said the United States imports almost 60 percent of its crude oil needs (mostly from Saudi Arabia, Venezuela, Mexico and Canada) and more than 15 percent of its natural gas needs (mainly from Canada, but with a growing LNG component from overseas).

"The market is south for Canadians," said AAPG member Eynon. "For the last five years, pipeline capacity has kept pace with exploration success."

He adds, "there's lots of expansion capacity and looping capacity within the existing pipelines."

According to Eynon, each year Canadian producers must find 2.5 to 3.0 Bcfd of production just to replace gas produced — any growth component would be on top of that. From 1995 to 2000, Canadian producers averaged 0.5 Bcfd of annual production growth.

The bulk of the remaining oil and gas resources in North America lie in remote frontier areas — Alberta's oil sands, the Alaskan North Slope and Canada's Beaufort Sea, Mackenzie Delta and Mackenzie Valley.

Alberta's oil sands.

Alberta's oil sands contain 1.3 trillion barrels of bitumen, of which 255 billion barrels is considered to be potentially recoverable using modern technology. In Alberta, some $60 billion worth of mega-projects have been publicly announced, are in the regulatory approval stages or are under construction.

Shell Canada, together with its joint venture partners Chevron Canada and Western Oil Sands, is currently in the construction phase of its $1.9 billion Muskeg River Mine and oil sands processing plant. The Muskeg River Mine, situated 75 kilometers north of Fort McMurray, contains a reserve base of nine billion barrels in three leases.

The mine is scheduled to reach full production of 155,000 bopd of synthetic crude in 2003. Given the size of the bitumen reserves, output could eventually grow to 530,000 bopd.

Image Caption

The Mackenzie Delta: Harsh conditions can't hide northern Canada's potential.
Photo courtesy of Petro Canada

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Despite being ranked as the world's third largest producer of natural gas and the thirteenth-largest producer of crude oil, the Canadian oil and gas sector is not resting on its laurels.

Specifically, exploration and production activity has ramped up in recent years to capitalize on Canada's high impact exploration plays in the Western Canadian Sedimentary Basin, the remote Frontiers and Alberta's vast oil sands. Competing head-to-head with the best opportunities available worldwide, Canadian exploration plays have attracted the attention of American E&P companies seeking corporate growth through international exploration.

The need to increase production and profitability — combined with the financially attractive Canadian dollar — precipitated the stampede of American E&P companies investing in Canada's under-explored sedimentary basins.

And since the events of September 11, producing oil and gas within a North American continental strategy has never seemed more appropriate. Fundamental to increasing oil and gas self-sufficiency in onshore United States and Canada is the existence of a continental transportation system — one that transcends borders — to deliver Canadian product to a growing American market.

According to Canada's National Energy Board, Canadian exports of natural gas to the United States hit an unprecedented high of 3.83 Tcf for 2000-2001, generating $28.55 billion in revenue. In 2001, according to Sayer Securities Ltd., of Calgary, merger and acquisition activity in Canada hit a record level of $39 billion. The vast majority of the 2001 M&A transactions saw the transfer of Canadian oil and gas assets to American E&P firms.

Of the eleven papers to be presented at the "North American Resources" session in Houston, four will focus on Canadian E&P opportunities and Canadian oil and gas exports to the United States, providing a broad overview of the Canadian exploration scene.

Increasing self-sufficiency.

George Eynon is director of oil and gas resources for Cambridge Energy Associates in Calgary. He said the United States imports almost 60 percent of its crude oil needs (mostly from Saudi Arabia, Venezuela, Mexico and Canada) and more than 15 percent of its natural gas needs (mainly from Canada, but with a growing LNG component from overseas).

"The market is south for Canadians," said AAPG member Eynon. "For the last five years, pipeline capacity has kept pace with exploration success."

He adds, "there's lots of expansion capacity and looping capacity within the existing pipelines."

According to Eynon, each year Canadian producers must find 2.5 to 3.0 Bcfd of production just to replace gas produced — any growth component would be on top of that. From 1995 to 2000, Canadian producers averaged 0.5 Bcfd of annual production growth.

The bulk of the remaining oil and gas resources in North America lie in remote frontier areas — Alberta's oil sands, the Alaskan North Slope and Canada's Beaufort Sea, Mackenzie Delta and Mackenzie Valley.

Alberta's oil sands.

Alberta's oil sands contain 1.3 trillion barrels of bitumen, of which 255 billion barrels is considered to be potentially recoverable using modern technology. In Alberta, some $60 billion worth of mega-projects have been publicly announced, are in the regulatory approval stages or are under construction.

Shell Canada, together with its joint venture partners Chevron Canada and Western Oil Sands, is currently in the construction phase of its $1.9 billion Muskeg River Mine and oil sands processing plant. The Muskeg River Mine, situated 75 kilometers north of Fort McMurray, contains a reserve base of nine billion barrels in three leases.

The mine is scheduled to reach full production of 155,000 bopd of synthetic crude in 2003. Given the size of the bitumen reserves, output could eventually grow to 530,000 bopd.

The joint venture is investing an additional $3 billion in downstream infrastructure — construction of the Scotford upgrader, co-generation facility and pipelines, and modifications to the Scotford refinery.

"The mine incorporates new enabling technology, which allowed us to go ahead with the project," said Keith Firmin, Shell Canada's manager of procurement and contracts for the Muskeg River Mine.

Firmin describes this technology as "froth treatment," which enables the production of a very clean bitumen from the extraction process. That, in turn, enables the bitumen to undergo a different upgrading process.

"Rather than take the coke out of the bitumen," Firmin said, "we add hydrogen."

The Beaufort Sea, Mackenzie Delta and Mackenzie Valley.

According to a 1998 resource assessment by the National Energy Board, the Mackenzie Delta and adjacent Beaufort Sea are estimated to contain one billion barrels of recoverable oil and 9 Tcf of marketable gas. The NEB estimates, further, that an additional six billion barrels of oil and another 55 Tcf of gas are yet to be discovered in the region.

Next door, the North Slope of Alaska contains 30 Tcf of stranded gas reserves.

A three-way horse race is shaping up to determine which pipeline will be built first:

  • The Alaskan Highway Route.
  • The Over-the-Top Route from Prudhoe Bay to the North West Territories.
  • The Mackenzie Valley Route.

"The most economic route is to bring Alaskan gas east through the Beaufort Sea and down the Mackenzie Corridor in Canada," Eynon said. However, given current gas commodity prices, the Net Present Value (NPV) of all three pipeline projects looks grim.

"Today's gas prices aren't the issue," Eynon said. "It's the prices in 10 years' time."

The geology and genesis of the Mackenzie Delta is similar to that of offshore Brazil and the Niger Delta. That's according to Alula Damte, senior geologist with Petrel Roberston Consulting in Calgary.

"It has all the components — a large sedimentary source plus a passive margin with shale offshore forming a detachment or toe thrust system," Damte said.

In the Mackenzie Delta, the Lower Cretaceous Kamik Formation hosts much of the significant reserves delineated at the Parsons Lake (1.7 Tcf), Taglu (2.9 Tcf) and Tuk (230 Bcf) fields.

Damte believes that future exploration along the strike of the basin-bounding fault zone will result in additional discoveries.

Western Canadian Sedimentary Basin.

The big plays are still out there.

Drilling in Canada's gas prone Western Canadian Sedimentary Basin has shifted to deeper targets located in the Deep Basin Centre, the Foothills and the Rocky Mountain Disturbed Belt.

During the past decade, a growing number of Canadian oil and gas explorers have claimed that the Western Canadian Sedimentary Basin (WCSB) is mature, that all the giant fields have been found — but Peter Putnam, president of Petrel Robertson Consulting, challenges that paradigm.

"Intellectually, it's arrogant to say that there are no giants left," Putnam said. "Giants can take different forms.

"Giants are not found by small oil and gas companies," he continued. "They're found by large companies who are best equipped with people, resources and patience."

Putnam cites the example of the Ladyfern gas discoveries made recently by Murphy Oil, Apache Canada and Canadian Natural Resources in the Devonian Slave Point Formation.

Situated in northeastern British Columbia, the Ladyfern trend is estimated to contain combined gas reserves of one Tcf. Putnam describes Ladyfern as "a constellation of different pools that are geographically situated."

The WCSB, in contrast to numerous sedimentary basins in the lower 48, remains relatively undrilled by American standards. Historically, these plays have not been widely drilled due to difficult or seasonal access, environmental sensitivity and distance from facilities.

The Slave Point Formation, for example, has been tested on average by one well for every township in British Columbia; many operators see this as an exploration opportunity.

The provincial governments of Western Canada offer transparent exploration processes, with bi-monthly land sales and a comprehensive public domain database that includes well logs, DSTs, samples, core, and production tests.

"The process ," Putnam said, "makes Western Canada the most competitive oil and gas jurisdiction in the world."

Brad Hayes, executive vice president of Petrel Roberston Consulting, defines three high impact, exploration plays in the WCSB:

  • Thrusted Paleozoic carbonates in the Foothills and thrusted Mesozoic clastics in the adjacent Triangle Zone.
  • Deep Basin tight gas sands.
  • Deep Devonian autochthonous carbonate reservoirs.

The WCSB extends northward to the North West and Yukon Territories, which are under-explored in comparison to the provinces of Alberta and British Columbia.

AAPG member Hayes predicts that the application of advanced technology — seismic, drilling, hydraulic fracturing of tight gas sands, environmental mitigation and geological analyses — will provide the formula for exploration and production successes.

"We have a widely-spaced string of pearls," Hayes said. "I foresee people learning from early outposts of success and advancing into remote territories, where there is room for growth following infrastructure."

Disturbed Belt, Foothills and Triangle Zone.

The discovery of the giant Turner Valley Field — with 3 Tcf of gas and one billion barrels of oil in place — signaled the beginning of Alberta's oil and gas industry.

Significant discoveries followed on the heels of technological advances: in the 1940s (Jumping Pound, 3.5 Tcf) and 1950s (Waterton, 4.6 Tcf) and 1970s (Bullmoose-Sukunka, 2.3 Tcf).

The next generation of overthrust discoveries resulted from improved seismic imaging, directional drilling techniques and a better understanding of thrust-belt geometries. Most recently, fractured sandstones in the Mesozoic section in the Triangle Zone (easternmost deformation of the foothills) have yielded 1.5 Tcf of discoveries.

According to Hayes, reserves discovered to date total 32 Tcf of gas in place. A resource assessment by the Geological Survey of Canada predicts an additional 68 Tcf of gas is yet to be discovered.

Deep Basin tight gas sands.

A huge gas resource potential exists in low permeability Mesozoic sandstones situated in the Deep Basin along the western flank of the WCSB. To date, this largely continuous Deep Basin fairway of hydrocarbon-saturated clastic reservoirs has yielded 10 Tcf of gas.

In southwestern Alberta, several operators are aggressively drilling the Crossfield/Aphrodites channel sand play, which extends for 150 kilometers and is buried up to 3,500 meters.

The Elmworth/Wapiti Field, located in west-central Alberta and adjacent British Columbia, is the classic example of a tight gas sands play. In 1979, John Masters of Canadian Hunter Exploration estimated 440 Tcf of gas in the Elmworth/Wapiti Field.

While Hayes considers Master's resource number "wildly optimistic," he suggests that the number was based upon the existence of very high gas prices and the use of advanced technology. According to Hayes, 5 Tcf of gas have been discovered to date at Elmworth/Wapiti.

In 2001, when Burlington Resources purchased Canadian Hunter, it publicly stated that it would apply its production expertise from the tight gas sands in the San Juan Basin, converting sub-economic resources of Elmworth-Wapiti to producing reserves.

Deep Devonian Carbonate plays.

The discovery in 1947 of the giant Leduc Field (388 MMbbl recoverable) in the Alberta Plains established the WCSB as a major hydrocarbon-producing basin. Other giant Devonian reef discoveries followed: Swan Hills (935 mmbbls recoverable) and Clarke Lake (2.4 Tcf in place).

After successfully exploiting the reef trends in the plains of Alberta and British Columbia, operators shifted their exploration efforts westward, to the Deep Basin adjacent to the Foothills. Significant reserves have been added by giant discoveries in Devonian reefs situated in the Deep Basin — Blackstone (1.2 Tcf) in 1979 and Caroline (2.3 Tcf) in 1986 and Ladyfern (1 Tcf) in the late 1990s.

The Deep Devonian carbonates also include prospective, diagenetically-enhanced ramp facies. Giant fields discovered in ramp strata during the 1950s include Crossfield (2.6 Tcf in place) and Parkland (240 Bcf). Recent discoveries have indicated prospective carbonate ramp strata extending over large areas of the basin.

According to Hayes, 56 Tcf of gas in place has been discovered to date. A resource assessment by the Geological Survey of Canada predicts an additional 70 Tcf of gas is yet to be discovered.

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