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Showered with praise EnCana, Canada’s federal regulator and T. Boone Pickens in no doubt that tight and shale gas has changed North American dynamic Gary Park For Petroleum News
EnCana and the National Energy Board, two of Canada’s most powerful petroleum voices, along with energy guru T. Boone Pickens, are marching to the same drumbeat in touting the prospects for shale gas in North America’s supply mix.
Already a long-time advocate of what it calls resource plays (tight gas, shale gas and the oil sands), EnCana is pouring its money and future into shale development at Haynesville in Louisiana and Horn River in British Columbia.
“The emergence of shale gas has changed the landscape of North American gas,” Chief Executive Officer Randy Eresman told analysts July 23.
He said that despite Canada’s traditional challenge in competing with U.S. cost structures, dealing with currency exchange rates and gaining access to supplies and services, the pendulum is swinging in a new direction.
Eresman said the Alberta royalty structure is actually working in EnCana’s favor, putting Canadian plays on a more competitive footing.
“Generally, wherever you have the most concentrated resources and lowest development-operating costs, those are the ones that are going to be developed first in this kind of dynamic environment,” he said.
Eresman said drilling results in Horn River have met or exceeded expectations for initial production and anticipated resource size, adding to a belief that shale gas could be among the most important in the company’s history.
B.C., Louisiana joint drilling A joint drilling program with Apache at Horn River has completed 32 wells to evaluate the basin and 10 horizontal wells are now producing, coming on stream in the second quarter at 9.5 million to 11 million cubic feet per day, although supply costs are $1 per thousand cubic feet more than Haynesville.
EnCana, which has a joint venture with Shell, has drilled 25 gross horizontal wells in Haynesville, increasing fracture stimulations in each well to as many as 14 from eight (similar to Horn River), raising initial output from each $9 million well by about 25 percent.
The Shell venture is now producing a gross 100 million cubic feet per day from North Louisiana leases.
With these strong results, Eresman has no hesitation in proclaiming shale gas as a key to solving some of North America’s toughest energy, environmental and economic challenges, noting that EnCana is pressing legislators in Canada and the U.S. to view gas as an alternative to foreign oil for transportation and power generation.
EnCana has taken its own symbolic step to reinforce that argument by converting a “portion” of its vehicle fleet to run on gas in selected Canadian and U.S. operational locations.
Even more conclusive evidence of EnCana’s future direction was its deal earlier in July to sell a large chunk of its conventional gas assets to Bonavista Energy Trust for about C$694 million — a package that included 492,000 acres, 53.2 million cubic feet per day of gas production and could be part of divestitures totaling C$1 billion this year.
Eresman’s views are shared by Pickens, who recently described North America’s shale deposits as a “game changer” for the continent’s energy mix.
Report shows shift There is plenty more ammunition for the shale advocates in a National Energy Board study released July 21.
In updating a 2007 reference case energy outlook to 2020, the rapid emergence of unconventional gas (tight and shale) and oil is accelerating the shift away from conventional resources.
The regulator estimates Canadian gas production could range from 10 billion to 21 billion cubic feet per day by 2020, with a “reference case scenario” targeting 15.8 bcf per day from a remaining marketable gas resource base of 439 trillion cubic feet, of which tight gas currently accounts for about one-third and is expected to reach 40 percent in 2020.
Western Canada contains significant unconventional resources, including coalbed methane and shale gas, which comprise 65 tcf.
The revised reference gas production of 15.98 bcf per day is up 2.4 bcf per day from the 2007 projection, with the biggest change stemming from tight and shale gas, which could account for between 7.8 bcf and 10 bcf per day, compared to 5 bcf per day in 2008 and a 2007 reference gas for 2020 of only 1.5 bcf per day.
Conventional gas production in Western Canada is forecast to slide 6 bcf per day between 2007 and 2020 to 5.3 bcf per day.
The NEB believes lower gas prices and a glut of gas on the North American market will drop gas well completions this year to between 4,500 and 7,500, with the reference scenario at 5,900.
It said prices of US$7.00-$7.50 per million British thermal units would see a very gradual decline in Canada from about 12,000 wells in 2013 to 9,200 by 2020, under the reference case.
A high price case could boost drilling to 15,000 wells by 2021, then start a slow decline, well below the 2007 reference case of 18,000 wells because of the heavier reliance on a smaller number of more prolific tight and shale gas wells.
The Henry Hub price of gas in the 2009 reference case rises to $6.70-$7.20 by 2020, bracketed by a low price case of $5.10-$6.50 and a high price case of $8.30-$11.00.
US$60-$120 WTI by 2020 On the oil front, the NEB expects prices to range from US$60 to $120 per barrel by 2020 for West Texas Intermediate.
It suggests oil sands projects already well under way and scheduled to be completed in 2009 and 2010 will be finished, while others will wait until economics improve.
Production from the oil sands is targeted at 2.8 million barrels per day by 2020, down 504,000 bpd from the 2007 reference case.
The estimates of initial capital spending required for new oil sands projects and threshold prices needed to justify construction of greenfield projects assume a 30 percent decline from last year’s peak in most input costs, including materials and labor.
The NEB now calculates that integrated mining and upgrading projects would cost US$80,000-$100,000 of capacity to build with an oil price of $60-$70 per barrel required to make a greenfield project economic.
For projects which produce non-upgraded bitumen, steam-assisted gravity drainage schemes and cycling steam stimulation projects, capital outlays are estimated at $30,000-$40,000 per barrel and a WTI price of $55-$65 per barrel as a threshold price.
These estimates allow for a 10 percent real rate of return on investment for the owners.
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