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Eresman: the future’s a gas EnCana CEO says North America ‘flush’ with resource costing less to produce Gary Park For Petroleum News
A more competitive, friendlier regime is one reason why British Columbia threatens Alberta’s once-unrivalled position as Canada’s dominant oil and natural gas region.
But there’s another, more compelling reason.
British Columbia has staggering untapped resources that are just starting to benefit from a technological “renaissance,” while Alberta is grappling with declining conventional reserves and production rates.
Consider the assessment of executives from leading production and pipeline companies speaking at a Vancouver Board of Trade energy forum on April 24.
Mike Graham, president of EnCana’s Canadian Foothills division, offered the most staggering projection of all.
He said the Horn River basin shale gas and Montney silt gas plays have combined gas in place of 800 trillion cubic feet — 800 years worth at British Columbia’s current annual production rate.
But those volumes should grow by a factor of two or three times over the next 10 to 20 years, raising B.C. from its 20 percent share of total Canadian output and “challenging Alberta as Canada’s largest gas producer.”
Graham said B.C. was the only Canadian province to record an increase in production last year and one of just three in North America, along with Texas and Louisiana, both of them also thriving on technological advances in shale gas extraction.
He said investment in the province is now about C$8 billion a year, with gas displacing lumber and mining as the most significant component of its diversified industry and export base, accounting for upwards of C$4 billion a year.
Graham said natural gas has “significant potential to displace coal for power-generation purposes.”
U.S. utilities look to gas That optimism is shared by an increasing number of U.S. utilities, who estimate gas is a transitional fuel that could reduce greenhouse gas emissions by half, bringing North America closer to its emissions targets without even factoring in other technological advances.
Spectra Energy Vice President Gary Wellinger told the Vancouver forum that the “massive deposits of clean natural gas” in B.C. represent the fastest growing industrial sector in the province.
However much renewable energy may reduce dependence on fossil fuels, “we need to be realistic. … Even by 2030, renewables are expected to account for only 8 to 10 percent of global energy supply.”
“The reality is, natural gas is typically the backup at wind and solar facilities to deal with the fickleness of nature,” he said.
Terasen President and Chief Executive Officer Randy Jesperson said gas is the “foundational energy form which will underpin the needs of society for the foreseeable future.”
He said it is not possible to achieve the projected 80 percent reduction in greenhouse gases by 2050 by focusing only on large industrial emitters, because half of the emissions stem from the use of fossil fuels in homes, businesses and institutions.
Abundance through technology EnCana Chief Executive Officer Randy Eresman also seized on the gas theme at the big Canadian independent’s annual general meeting on April 22, noting that technology has made natural gas more abundant than previously estimated, with profound implications for North America’s energy supply.
“Ultimately this will mean there will be a large, abundant supply of natural gas available to North America; it can be utilized in a lot more ways and it will likely come in at a lower cost,” he said.
He noted that a recent study by the U.S. Department of Energy said the U.S. alone has enough gas resources to cover 90 to 116 years of demand at current production levels and EnCana believes that will only grow as technology advances.
Eresman said that only two years ago shale gas was viewed as unproductive, but the technological key to accessing those reservoirs has been developed, starting a year ago when it was “broken wide open” with the use of long-reach horizontal wells with multiple-fracture stimulations.
“As a result, we believe that North America is basically flush with natural gas and will be for a very, very long period of time,” Eresman said.
But he also argued that the “game has changed,” limiting success to the lowest-cost producers.
Before the meeting, he told reporters that gas could displace coal and oil as a major energy source for power generation and transportation fuel in North America, for both long-haul trucks and domestic vehicles.
Environmentally, he said gas produces half the carbon dioxide of coal and one-third less CO2 than oil, along with insignificant quantities of sulfur dioxide and mercury compared with coal and oil.
Eresman told a conference call that along with partner Apache it expects to drill 24 gross wells in Horn River (where EnCana has about 260,000 net acres) this year, down from the previously scheduled 40, while increasing the number of fractures along each well to about 14 from eight. By reducing the number of wells, the partnership can minimize its environmental footprint.
Longer wells more economic Graham said EnCana believes it is a “bit more economic” to extend the wells and increase the number of fracs and, in trading data between the company’s Canadian Foothills and U.S.A. divisions, “it seems the bigger the frac the more productivity you can get out of them.”
He said the latest well to come on stream had 10 fracs and yielded a 30-day initial production rate of 8 million cubic feet per day, declining to about half after eight months of production — a 50 percent first-year decline rate, which he described as “very encouraging,” adding that 7 billion cubic feet should be recovered from the well.
Graham said the company estimates it can lower the cost per frac to C$750,000 from C$1 million.
In the Montney play, Graham said EnCana drilled 15.5 net horizontal wells in the first quarter and plans 60 for the year, buoyed by results that include 30-day initial production rates of more than 4 million cubic feet per day for each well, or 500,000 cubic feet on a fracture interval basis, Eresman said.
“The Montney is responding to the same technology we are using in the shale plays (the long-reach, multiple-fracture horizontal wells),” he said. The standard approach involves four to eight wells per section, with wells averaging a length of 5,200 to 6,600 feet, with about eight fractures per well.
In the emerging Haynesville shale play, straddling the Texas-Louisiana border, where its major partner is Royal Dutch Shell, EnCana has doubled its capital spending for 2009 to US$580 million by transferring savings from elsewhere in the company as the result of an internal challenge to reduce budgeted spending by 10 percent.
Jeff Wojahn, president of the USA division, said the 50 net wells will be focused on understanding the resource and meeting deadlines to retain prospective lands, where EnCana holds a net 435,000 acres, including a net 63,000 acres of mineral rights.
Although cautious about potential outcomes, the initial productivity rates and pressures are “very strong and in line with industry reports,” he said.
Cost of wells lowered In addition, by reducing its spud-to-rig release times, rig moves and the run time on directional tools, EnCana has lowered the cost of its latest three wells by about 30 percent to US$9 million.
Getting Haynesville gas to market involves a commitment to 150 million cubic feet per day of capacity on the proposed Boardwalk Pipeline Partners’ Gulf South Pipeline expansion and another 500 million cubic feet per day on the proposed Energy Transfer Partners Tiger Pipeline.
The objective is to make Haynesville “one of the most important pieces in the future of EnCana’s gas production,” said Eresman, adding that his company is “quickly moving to 50 percent (production from the U.S.). Based on our growth rate in the U.S., you could see the U.S. dominate our production in the future.”
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