|
Mackenzie needs hard numbers Exploration spotlight intensifies along Canada’s natural gas pipeline route Gary Park Petroleum News Calgary Correspondent
The Mackenzie Gas Project is entering a new phase, with the pressure on potential shippers to start attaching numbers to the gas volumes they anticipate delivering to the C$4 billion pipeline.
Imperial Oil, which spearheads the venture, has asked for signed “precedent agreements” by mid-December with shippers so that it can give substance to its regulatory filings with the National Energy Board in 2004.
Hart Searle, a spokesman for Imperial, told Petroleum News that the proponents now need further confirmation of the numbers offered during a non-binding open season last year “so that we can really nail down the pipeline configuration.”
But, emphasizing a desire to maintain flexibility and “keep the doors open,” he said final firm-service agreements will not be required until regulatory approvals have been obtained — which the agencies have indicated could be about 2006.
For now, the three anchor fields on the Mackenzie Delta — Taglu, Niglintgak and Parsons Lake — are seen as contributing 800 million to 1 billion cubic feet per day.
The preliminary information package released in June calls for a 30-inch diameter line from Inuvik, Northwest Territories, to northern Alberta with capacity for 1.2 billion cubic feet per day that could be expanded to 1.9 bcf per day with additional compression.
Even to reach the 1.2 bcf level by projected start-up in 2009 increases the pressure on all shippers to put a harder edge on their projected numbers and build on the modest reserves available outside the 5.8 trillion cubic feet controlled by Imperial and its partners in the Mackenzie Delta Producers Group — ConocoPhillips Canada, Shell Canada and ExxonMobil Canada.
As negotiations move ahead on pipeline size and capacity, they are being accompanied by stirrings on the Northwest Territories drilling front and what is in store for the next five winters.
“We know a lot of activity is under way or planned,” said Searle.
Ramp up in exploration expected It is expected the deal signed earlier this year with the Aboriginal Pipeline Group, which lays the foundation for one-third aboriginal ownership of the pipeline, will ramp up exploration, although those programs are still mostly under wraps.
There was a mild setback this month when Devon Canada Chief Executive Officer John Richels said his company will not drill on the Delta in the coming winter after participating in five wells over the past two seasons.
Despite the Tuk M-18 discovery of 200-300 billion cubic feet with Petro-Canada and despite being the largest Delta landholder at 1.8 million gross acres, Devon prefers to wait for the pipeline to move closer to reality before resuming onshore exploration, he said.
However, North America’s largest oil and gas independent will not be idle in Canada’s Arctic.
Richels said September 18 that Devon is trying to line up partners to revive drilling in the Beaufort Sea for the first time since the 1980s.
If it succeeds in talks with several multinationals, Devon hopes to drill as many as four wells, starting in the 2005-06 winter, he said. Any discoveries could see Beaufort gas fed into the Mackenzie pipeline by 2012.
Armed with three-dimensional seismic covering about 460 square miles and attracted by the Beaufort’s shallow waters, which are only about 40 feet deep as much as 60 miles offshore, the company is eager to take on the gamble of drilling wells at a cost of about C$50 million each.
But Richels, indicating that deals could be announced in the next few months, said Devon would limit itself to 25 percent to 50 percent interest in such high-impact, high-risk plays. Official view of Beaufort optimistic Estimates by Canada’s National Energy Board lend weight to the optimistic view of the Beaufort, with reserve projections of 54 tcf, compared with 17 tcf on the delta.
Exploration in the 1970s and 1980s, heavily supported by Canadian government incentives, yielded several significant discovery licenses, with a total of 39 gas fields accounting for 8.8 tcf of marketable gas.
Industry consultant Robert Meneley told geologists and geophysicists at a June meeting that future discoveries are “unlikely to be larger than the large simple early discoveries that have already been made. It will take a lot of smaller wins to add up to significant volumes.”
However, other technological advances in the hiatus since Beaufort drilling was suspended could enhance the region’s prospects.
Christopher Bergquist, a geologist with Devon Canada, said purpose-built Arctic rigs have cut drilling time by 30 percent, while consistent and integrated 3-D data is becoming a valuable tool.
Fueling optimism is a forecast by Peters & Co. analyst Brian Prokop that key U.S. independents — Anadarko Petroleum, Apache, Burlington Resources and Devon Energy — will hike their Canadian capital spending in 2004 by as much as 20 percent, pushing the combined total above C$2 billion as they employ about 200 rigs to accelerate their hunt for natural gas.
“This is still the best gas market in the world,” Apache Canada president Floyd Price told a Peters & Co. investment conference September 17.
Active winter planned onshore For the onshore plays, there are preliminary indications of an active winter:
• On the delta, EnCana has a Nabors rig being barged to Tuktoyaktuk and Chevron Canada Resources has signaled its intention to build on the success of last winter’s North Langley K-30 well, drilled in partnership with BP Canada Energy and Burlington Resources Canada. Chevron, which is mobilizing equipment to be barged to a base camp, is targeting the Ellice Island well site about 45 miles northwest of Inuvik. Chevron and BP plan to spend C$20 million conducting three-dimensional seismic this winter. EnCana is leading a partnership with ConocoPhillips Canada and Anadarko Canada to drill a well on Richards Island and extend the knowledge gained from drilling in the 1970s.
• At Colville Hills, in the north-central Northwest Territories, partners Paramount Resources and Apache Canada aim to follow up on successful drilling last winter by re-entering two wells on a 40,000 acre prospect to assess the untested zones and drill additional wells to delineate the find. The Nogha C-49 well was reported to have encountered multiple zones of gas-bearing sandstone reservoir, while Nogha M-17 was cased and completed as a successful gas producer. Price said now that Imperial is trying to firm up volumes he anticipates a “fair amount of drilling this winter and next,” saying his firm could drill as many as seven wells in the Colville area. But Imperial has made it clear that it will not build any pipeline laterals from fields such as Colville.
• Canadian Natural Resources drilled two dry holes at Colville Lake last winter and said it has no intention of spudding any further wells this winter.
• In the Sahtu region, EnCana is gearing up to drill near Tulita, while Northrock Resources is endeavoring to strike deals on road access and aboriginal business opportunities so that it can proceed with a two-well, C$15-million program.
• A full agenda is shaping up for the Fort Liard area of the lower Northwest Territories, with Anadarko Canada — pending a resolution of the parent company’s future — planning to drill a number of wells after filing four significant discovery licenses from nine exploratory wells last winter. Anadarko also hopes to build a pipeline to tie-in the four significant discovery licenses. BP has licensed some wells for re-entry in the Pointed Mountain area and Canadian Forest Oil is close to completing a 15,000-foot well just north of the Northwest Territories-British Columbia border.
| 