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.
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
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
"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
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
"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
"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
"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
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
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
- 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
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
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
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
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.