Gas pipeline proposals reviving interest in Arctic Canada E&D
Oil & Gas Journal, last week´s issue
A pipeline to tap Arctic Canada's natural gas reserves for southern markets
in the US and Canada is a possibility once again, for the first time in
more than 2 decades.
But that possibility is still qualified by large questions of how, where,
when-and even if.
Healthy natural gas prices and forecast increases in annual US demand to
30 tcf by as early as 2010 are creating new interest in tapping gas reserves
in Canada's Mackenzie Delta and Beaufort Sea and the estimated 35 tcf of
proven gas reserves on Alaska's North Slope.
Major producers with substantial reserves in the onshore Mackenzie Delta
are well into a feasibility study on development of delta reserves and
a possible pipeline to the south. Most analysts estimate that 2007 would
be the earliest date that a pipeline project could complete the necessary
regulatory requirements and construction phase before gas can flow-likely
to pipeline connections in northern Alberta.
Turnaround
However, delta producers, pipeliners, politicians, and the largely aboriginal
population of Canada's Northwest Territories and Yukon Territory are now
actively considering the possibility of a pipeline as a bridge to economic
growth. That is a turnaround in public sentiment from the early 1970s,
when political and environmental opposition and poor economics killed several
pipeline proposals.
Exploration fueled by generous super-depletion allowances from Ottawa spurred
Dome Petroleum Ltd. and other major companies to explore and establish
substantial gas reserves in both the Beaufort Sea and Mackenzie Delta in
the late 1960s and early 1970s.
A 3-year inquiry during 1974-77 by Justice Thomas Berger into Mackenzie
Valley pipeline development put the final nail in the coffin of pipeline
plans with its recommendation for a 10-year moratorium on activity. Low
gas prices, the cost of pipeline projects, and Ottawa's cancellation of
generous tax treatment for frontier exploration were also factors.
The pendulum has now swung in the other direction, and most northern residents
and their political leaders have opted in favor of development.
Without that change in public support, it is questionable whether delta
producers would seriously consider pipeline development.
Pipeline feasibility study
Imperial Oil Ltd.,Toronto, Canada's largest oil company, and several other
producers with Mackenzie Delta reserves are now conducting a feasibility
study on whether gas can be economically developed and delivered via pipeline
from the remote area on the edge of the Beaufort Sea.
Imperial said recently the study assumes construction of an 800 MMcfd pipeline
to extend from the onshore fields to Inuvik on the Arctic Coast and south
from there to Norman Wells, NWT, where the company operates a long-established
oil field.The 1,090-mile line would likely cost about $3 billion (Can.)
The pipeline project would be supported by about 6 tcf of onshore gas reserves
in three fields. Imperial holds about 3 tcf; Gulf Canada Resources Ltd.,
1.8 tcf, and Shell Canada Ltd., 1 tcf: There are an estimated 12 tcf of
gas and 1.7 billion bbl of oil in the area adjacent to the Beaufort Sea.
Gas potential in the region is estimated at 65 tcf:
The gas would then be shipped on a right-of way parallel to an oil pipeline
operated by Enbridge Inc., Calgary, from Norman Wells to main line pipe
connections in northern Alberta.
Pipeline issues
Kenneth Williams, an Imperial senior vice-president, recently told a seminar
that the pipeline would be a Canadian-only development and a phased project.
"It's a bit smaller than various Alaska proposals, and it's one that potentially
could be compatible with a much larger Alaska development one day," Williams
said.
The Imperial executive said the producer group involved in the study with
Imperial-- including Gulf Canada, Shell Canada, and Mobil Oil Canada-are
not proposing a project and do not have a development plan.
"We have a development concept that we hope to improve upon after consultation
with interested parties. The feasibility of this concept is dependent not
only on the technical and economic challenges, which in the past were viewed
as the major hurdles to be overcome, but the socioeconomic and regulatory
challenges," he said.
"The most significant challenges are those that are external to our companies.
There are four key issue areas" in which the companies must:
-- Assess support from northern parties for such a development, including
the benefits associated with development.
-- Assess the regulatory and environmental approvals required, including the
process and timing of getting such approval.
-- Examine the issue of pipeline ownership and financing. Pipeline ownership
is one of the key issues, because the cost of transporting gas to market
will be paid for by producers.
-- Examine the fiscal terms, royalties, and taxes that would apply to such
a development and explore options to enhance the economics for the initial
infrastructure on a stand-alone basis.
Williams said the producer group has begun discussions with many parties,
including the NWT territorial government, aboriginal and Metis groups,
northern communities, the federal government, other gas producers, and
pipeline companies.
The Imperial executive said the development concept is based on a number
of key assumptions:
-- Development of only Canadian onshore gas.
-- Use of proven technology and centralized facilities.
-- Concurrent production of the Taglu, Parsons Lake, and Niglintgak Fields
on the delta coast, with an initial production rate of 800 MMcfd and 11,000
b/d of condensate.
-- A gas-gathering pipeline to the Inuvik area and gas processing near Inuvik
to remove water and dehydrate the gas.
-- Use of existing rights-of way (ROW) and common corridors that would minimize
the environmental footprint; a single pipeline from the delta to Imperial's
Norman Wells infrastructure and a pipeline route following the existing
ROW south of Norman Wells through the Mackenzie Valley.
-- Pipeline accessibility to other producers at commercial tariffs and terms.
-- Concept flexibility for future expansion and pipeline extension for either
additional Mackenzie Delta or nearshore gas.
Pipeline prospects
The study results are expected in early 2001, and Williams said the producer
group is cautiously optimistic about prospects for development.
"The feasibility study is a way to focus our efforts, gauge support, and
work in parallel with renewed exploration activity in the Mackenzie Delta,"
Williams said.
The Mackenzie route now under study is one of several possibilities for
moving gas from the delta and/or Prudhoe Bay. They include:
The Alaska Highway route, also know as the Foothills route, because it
was originally proposed by Foothills Pipelines Ltd.in the 1970s. It would
ship gas from Prudhoe Bay to southern markets. The 1, 674-mile line, with
an estimated price tag of $6 billion, has the advantage of already having
routing and environmental approvals from both US and Canadian regulators.
As originally proposed, it would extend from Prudhoe via Fairbanks and
Whitehorse to pipeline connections near Fort st. John, BC.
The Dempster lateral, also a throwback to the 1970s, would be a 745-mile
line through Yukon Territory following the Dempster Highway from Inuvik
to connect with the Alaska Highway line at Whitehorse in the Yukon. Cost
would be about $2 billion.
A direct line from Prudhoe Bay to the delta, connecting with a Mackenzie
Valley line to the south. This concept would involve a 1, 400mile line
with a price tag of up to $8 billion.
A 583-mile line, with a $1.5 billion price tag, from Prudhoe Bay through
the Yukon and Northwest territories to connect with a Mackenzie line. It
would have to cross Alaska's Yukon Flats Natural Wildlife reserve.
Fort Liard hot spot
Adding to the attraction of an arctic line are growing gas reserves in
the region of Fort hard, NWT, just north of the Alberta-British Columbia
borders.
Chevron Canada Resources Ltd. and partners announced first production May
1 from their K-29 discovery well near Fort hard, one of a number of discoveries
in the exploration hot spot. Chevron began producing at a rate of 35 MMcfd
and ramped up to 75 MMcfd from the prolific well. Initial estimates of
raw gas in place for the field were 400-600 bcf.
A second discovery, M-25, was drilled about 5 miles south of K-29 and is
expected to begin production by this November or December at a rate of
7 5 MMcfd. It will be tied into the K-29 pipeline system. The line takes
gas to an existing pipeline at Pointed Mountain, NWT, and into a Westcoast
Energy Inc. gas processing plant at Fort Nelson, BC, where it enters the
main sales gas system.
Interests in the two wells are Chevron, as operator, 43.43%; Purcell Energy
Ltd., 24%; Berkley Petroleum Corp., 21 %; Anderson Resources, 4.1 %; and
Paramount Resources Ltd., 2.76%. Minor interests are also held by Ranger
Oil Ltd., CanNat Resources Inc., Numac Energy Inc., AEC Oil and Gas, Talisman
Energy Inc., and several others.
In addition to the Chevron et al. wells, Ranger has begun production of
40 MMcfd from its P-66 well, the initial discovery in the region, where
there is now extensive seismic survey activity under way.
The Fort Liard discoveries and pipeline proposals have also revived exploration
interest in the Mackenzie Valley region.
Pipeline race
Rick de Wolf, senior vice-president of Calgary-based Ziff Energy Group,
said various pipeline proposals are in a horse race with no one ahead at
this stage. He said a critical factor will be what concept producers support,
and that is not clear at this stage.
John Browne, CEO of BP Amoco PLC, has made it clear that his company is
interested in participating any northern gas development. He told the World
Petroleum Congress in Calgary in June that BP Amoco would consider taking
an ownership interest in an arctic gas line. He said BP Amoco would likely
join with other companies to build a pipeline. Westcoast Energy Inc, Vancouver,
BC, and TransCanada Pipelines Ltd. and Enbridge Inc., both of Calgary,
have said they are interested in building a pipeline.
Tim Holt, CEO of BP Amoco Canada, later said the company is looking at
the feasibility of a number of routes to move gas south from Alaska and
the Mackenzie Delta. Holt said BP Amoco Canada would like to be in a position
to make a decision on a route by mid-2001 and "optimistically could have
it built and operating in a 2007 time frame." Holt said he has already
met with delegations from the Northwest and Yukon territories to discuss
pipeline possbilities, as have most of the potential players.
Ed Porter, vice-president of gas pipeline development, West, for Enbridge,
says a number of pipeline concepts are being considered as possibilities
to move both Canadian Arctic and North Slope gas. He said Enbridge is in
touch with all parties, and his company would be interested as a pipeline
builder, operator, and equity interest participant in a future project.
Porter noted that the North Slope has large established gas reserves, while
the Mackenzie Delta play "is still in its infancy."
He said that, from a Canadian perspective, a Mackenzie Valley pipeline
route is simpler, while Alaska gas could come to market via the Foothills
route or by subsea pipeline under the Beaufort Sea from Prudhoe Bay to
landfall around Inuvik, NWT
"Both sides (prospective Alaska North Slope and Mackenzie Delta gas developers)
are talking about a similar time frame, so there is a possibility that
two projects could be combined. That could create a supply glut, although
the delta gas might not have much impact. It would support declining production
in the Western Canada Sedimentary Basin," Porter said.
The Enbridge executive said an arctic gas pipeline would likely take 7
years from approval to completion, depending on the technology used. He
said Enbridge, which already operates the crude oil line from Norman Wells
and a natural gas system serving Inuvik, is in touch with all parties and
recently made a presentation to the produce group studying a Mackenzie
line.
Porter said aboriginal groups in the Northwest Territories now support
pipeline development, and his company and other potential stakeholders
have had several meetings to date with aboriginal representatives.
Local support
Apart from improvements in pipelining and drilling technology, the most
significant change affecting northern development since the 1970s is support
by northern residents for development.
In January, leaders from aboriginal communities across the Northwest Territories
issued a unanimous statement supporting pipeline development in which their
people can participate.
Harry Deneron, chief of the Fort Liard Acho Dene Koe First Nation, which
hosted a conference, said northerners now want to participate in construction
and ownership o1 a Mackenzie line. He said that is the objective of the
Aboriginal Pipeline Working Group, a task force formed to investgate strategies
for partnership in pipeline development.
Stephen Kakfwi, Northwest Territories premier, opposed development in the
Mackenzie Valley as a young man but now has swung his support behind it.
Kakfwi says the Alaska and Yukon governments support alternate routes to
get arctic gas to market, but argues a Mackenzie Valley line makes the
most economic sense for the Northwest Territories and Canada as a whole.
He noted the Mackenzie Valley is already a well-established pipeline corridor
with the crude oil line from Norman Wells to Alberta.
Meanwhile, Pat Duncan, Yukon Territory premier, says the proposed Foothills
line following the Alaska Highway through the Yukon is the best route for
arctic gas to move south and has a 3-year head start on rivals because
regulatory approvals are already in place.
Duncan said her government would support the Alaska Highway line but would
oppose a mid-Yukon route or any offshore line through the Beaufort Sea
for environmental reasons.
Mackenzie Delta revival
Industry interest in acquiring exploration permits in the Mackenzie Delta
region was revived in 1999. Prior to that, no exploration licenses had
been granted in the region since 1991, and no well has been drilled since
1992.
In September 1999, Ottawa granted four 9-year exploration licences. One
pair was awarded to a partnership of Burlington Resources Canada Energy
Ltd. and Poco Petroleums Ltd., the other pair to a partnership of Anderson
Resources and PetroCanada. The companies agreed to spend a combined $180
million on exploration and development, and seismic work is under way to
pinpoint drilling locations.
This spring, the Inuvialuit Regional Corp., which oversees an Inuvialuit
land claim in the Beaufort-Delta region, awarded four exploration licenses
on its lands in the region of Inuvik and Tukotyaktuk on the Arctic Coast.
Successful bidders were Chevron Canada Resources, Petro-Canada, and Anderson
Resources.
Ottawa recently issued a new call for exploration proposals on 10 parcels
of land in the region. |
