A sea change in North America

Shale revives dreams of energy self-sufficiency extending over hundreds of years, driven by technological gains, oil prices

Gary Park

For Petroleum News

Whimsical or not, more commentators are suggesting that North America is on the verge of pushing back the “peak oil” threshold by hundreds of years.

That was reminiscent of the loose talk in the 1960s that there was no apparent end to the continent’s oil horizon.

But, in an industry where hope springs eternal, there is a quietly building school of thought that the United States and Canada could be self-sufficient in fossil fuel energy for a very long time — presumably if they can find a way to stifle greenhouse gas emissions and limit the environmental fallout of a rapidly developing new source of oil and gas.

It’s all tied to the treasure trove in the billions of barrels and multiple trillions of cubic feet trapped in huge shale deposits.

Just three years ago, the U.S. think-tank Rand Corp. suggested shale oil could add 800 billion barrels to crude supply provided oil prices topped the then-unthinkable barrier of $75 a barrel.

The study’s authors estimated that 500 billion to 1.1 trillion barrels were “technically recoverable” from deposits sprawling across Colorado, Utah and Wyoming, good for meeting U.S. needs through the year 2400.

The Rand researchers said at the time that rising oil prices and advances in extraction techniques could make oil shale deposits an economic alternative to conventional crude.

Environmental impact an issue

Rand senior policy researcher James Bartis said the risks were considerable until it became clear how new technologies would affect land, air and water.

“In the past 25 years, there have been significant technical advances in mining, minerals-processing and controlling environmental damage,” he said.

“That may be good news for oil shale, but we don’t yet know how these technical gains translate into lower costs or whether they significantly reduce adverse environmental impacts,” Bartis said.

The study even suggested that adverse land and ecological impacts would go hand-in-hand with shale development no matter what development method was used, resulting in “severely limiting” airborne and greenhouse gas emissions.

If those challenges can be solved, the Rand study estimated a shale output of 3 million barrels per day could generate economic benefits of $20 billion a year — based on 2005 dollars and oil prices — half of that going to federal, state and local governments.

It forecast those same production volumes could trim 3-5 percent off oil prices, saving U.S. oil consumers $15 billion to $20 billion annually, while creating several hundred thousand jobs.

Shale technology promising

Among those on the leading edge is independent Equitable Resources, which says a complex directional production method for drilling horizontal shale gas wells could become a standard for those plays.

Backed by years of production from conventional shallow wells in Appalachia, Equitable is now testing multi-lateral drilling to raise the recovery rate from well bores.

Company President Steve Schlotterbeck said several individual holes are punched out diagonally from a horizontal well, opening access to more of a gas reservoir.

He said the wells, despite the greater number of feet drilled, promise to be economic because it is not necessary to fracture-stimulate them. Instead, the wells intersect enough natural fractures to allow the gas to flow freely.

Schlotterbeck said Equitable’s computer models indicate multilaterals and stacked multilaterals could improve the gas recovery rate to 50-60 percent from the current 8 percent.

But based on results from one well, he said more work is needed to determine is the multi-lateral concept really works.

Los Alamos has DOE assignment

The DOE asserted in 2004 that commercial shale oil production could start in 2011 at 200,000 bpd, rising to 2 million bpd in 2020. It has not provided any updated forecasts.

However, the U.S. Geological Survey said in an April report that the Bakken shale formation in North Dakota and Montana, that spills across the border into Saskatchewan, could hold as much as 3.65 billion barrels of oil and 1.85 trillion cubic feet of gas, making it the largest continuous oil accumulation ever discovered in the US.

The area, covering 25,000 square miles, is also capable of yielding 148 million barrels of natural gas liquids, the USGS said.

In 1995, the USGS figured the Bakken play contained about 151 million barrels of oil — a number that it has been able to boost because of advances in technology and geological understanding.

Shale gas 4% production

By far the most prolific new gas play in the U.S., the Barnett may soon have to share that place with the Haynesville play of Louisiana and the Marcellus shale of Appalachia.

Chesapeake Energy — forced into the spotlight by smaller independents Petrohawk Energy and Goodrich Petroleum — disclosed in March that its Haynesville discovery has resource potential of 7.5-10 tcf of equivalent gas at depths between 10,500 and 13,000 feet over 200,000 acres.

Chesapeake Chief Executive Officer Aubrey McClendon said Haynesville and other big shale plays could stall the need for liquefied natural gas imports, suggesting the U.S. should probably be thinking about building a liquefaction exports plant rather than a regasification import terminal.

Investment bank JP Morgan estimated the Haynesville wells could yield 5 billion cubic feet each at a cost of up to $6 million per well, meaning the economics would rival that of the Barnett play.

Jeffries analyst Subash Chandra said the Chesapeake well rates are 11 million to 17 million cubic feet per day.

Meanwhile, XTO Energy completed two shale acquisitions in April — a $520 million expansion of its holdings in the Fayetteville shale of Arkansas and a $600 million deal with Linn Energy to add the Appalachia’s Marcellus shale of Pennsylvania and West Virginia to its portfolio.

Following a series of acquisitions, XTO has shale holdings of 500,000 acres in Fayetteville, 250,000 acres in Barnett, 260,000 acres in Woodford and 152,000 acres in Marcellus.

Others with interests in Fayetteville include Chesapeake, Range Resources, Cabot Oil & Gas, Petroleum Development Corporation, Atlas Energy Resources and Equitable Resources.

Expensive initial learning curve

He noted that Barnett wells lose 60 percent of their production in the first year, but added it could take another 60 years for the wells to become uneconomic.

An additional note of concern was delivered at a June conference by Jack Ward, a partner with small Appalachian player PetroEdge Resources, who said the costs of buying water for shale plays are rising and governments are concerned about the growing competition with industry for water.

He forecast water disposal will become a similarly big issue, suggesting that getting rid of frac water could be more difficult than obtaining it in the first place.

Ward said a $1 million well in West Virginia could require $200,000 to move water on and off the location.

Schlotterbeck said that ratio would apply to a vertical well, whereas for a horizontal well “the amount will be multiplied.”

Southwest Energy Chief Executive Officer Harold Korell said water is less of a concern in the Fayetteville Shale in Arkansas, where the average annual rainfall is about 55 inches.

He said his company has obtained water from municipalities and quarries and has built ponds to capture rainwater. As well it mixes that water with frac water for recycling.

Industry hails the shales of B.C.

In the space of less than two years, they have catapulted a resource that was scarcely known outside their world — and little valued within it — into the best chance of stretching Canada’s gas reserves well beyond the 58 trillion cubic feet of remaining established reserves.

The National Energy Board underscores the importance of new supply sources from Arctic and East Coast frontier regions, coalbed methane, liquefied natural gas and shale gas.

The regulator says that in “coming years it is expected that North American demand for natural gas will continue to outpace the growth in domestic supplies” as supplies from the Western Canada Sedimentary basin and Nova Scotia’s offshore Sable field continue their decline, while gas consumption in the Alberta oil sands and Ontario’s gas-fired electrical generation keeps rising.

Almost as an after-thought the NEB, in its latest annual energy assessment, notes that in 2007 land sales in the shale region of British Columbia were of “particular interest.”

Not just juniors involved

Sister companies Imperial Oil and ExxonMobil, not known for faddish behavior, have joined the ranks by acquiring combined license holdings of 115,000 acres in the Horn River play, indicating they don’t want to be left out of a “new opportunity with considerable resource potential.”

BP Canada, ConocoPhillips, Shell Canada and Duvernay Oil are rumored to be among other successful bidders at government land sales.

Robin Mann, chief executive officer of AJM Petroleum Consultants, said the advent of new technology will turn the Upper Montney into “one of the major plays of the future,” with gas-in-place estimated at more than 50 tcf.

Even if that estimate is cut in half “we have a major resource we didn’t even have two or three years ago,” he said.

Wood Mac likes Horn River

It puts the play on a “global scale,” with recoverable resource estimated at 37 tcf, comparable in the firm’s assessment to the main fields expected to back an Alaska gas pipeline.

Wood Mackenzie analyst Fraser McKay said three Horn River announcements by EOG, Apache and Nexen point to “rock properties and well scenarios which were highly consistent; each suggesting the play could be even more prospective than Texas’ prolific Barnett Shale. The potential resources are world scale.”

McKay said that once estimates move beyond the preliminary stage, the recoverable calculations could climb to 50 tcf.

A preliminary analysis by the firm suggested economic returns would be in line with other major global gas supply projects, requiring a Henry Hub price of about $6.50 per thousand cubic feet to achieve a 10 percent rate of return.

He said Apache has announced an average resource estimate of 12.5 tcf, indicating its joint venture partner EnCana could be exposed to a similar level of resource potential, while EOG and Nexen have reported resources of 7.8 tcf and 4.5 tcf respectively.

Wood Mackenzie assumes that once more exploration work is completed, Imperial, Devon and Quicksilver Resources may all hold multi-tcf positions.

Reinforcing those conclusions, the study said British Columbia offers a “political and fiscally stable environment,” including royalty incentives that make the projected 10 percent rate of return realistic, even in a high-cost scenario.

Wood Mac also sees challenges

He said current resource estimates are “based on extrapolations from relatively few wells and will require to be firmed up through further drilling and analysis of long-term well performance.”

“However, with conventional Western Canadian gas production in decline, the emergence of shale gas as a future source of supply could be vital in maintaining Canada’s position as a major producer of natural gas.”

The firm said that with few exploration surprises anticipated, “gas-in-place estimates are likely to creep upwards over time rather than be revised down.”

AJM Petroleum Consultants said land prices for the Upper Montney have averaged C$2,284 per hectare (C$5,644 per acre), while the more remote Horn River near the Northwest Territories border is fetching C$1,703 per hectare, although Mann noted the Upper Montney is not a pure shale play because of its “turbidated dirty, sandy, shaley hodgepodge of everything.”

Investment dealer Peters & Co. agrees with Wood Mackenzie that many of British Columbia’s unconventional plays are economic at prices of C$6.50 per thousand cubic feet.

Shales could require C$8

“In addition, further cost improvements due to increased operator and service company experience and a migration towards fewer yet longer wellbores with additional stimulation events per well will serve to increase already superior returns,” Peters said.

Mann noted that Horn River wells are not cheap at up to C$10 million each, but operators are pointing to a decline to C$6 million-C$8 million, although access to well sites remains a “big problem.”

ARC Energy Trust Chief Executive Officer John Dielwart, which has 76,800 gross acres (64,000 net) in the Montney play, has boosted its capital budget for the play twice this year, allocating C$125 million.

But he said ARC, which is producing about 46 million cubic feet per day from 75 wells, faces processing constraints which threaten to become a major issue as companies ramp up their production.

“We are reserving space all over the place,” he said. “There’s a bit of a race going on.”

Juniors talk plans

While the majors are mostly keeping their eventual plans under wraps, although Apache Chief Executive Officer Steven Farris, has talked of spending C$5 billion or more over the next decade, the juniors are giving an added buzz to the resource and offering a chance to track developments. Consider just a few:

• Canbriam Energy has struck an equity financing deal of up to US$300 million with Warburg Pincus and ARC Financial to acquire, explore and develop oil and gas interests, with a primary focus on shales in B.C. and Alberta.

• Terra Energy has hired Tristone Capital to help market rights in the Montney formation, including 70,000 acres in the core Fort St. John operating area. It recently offloaded 3,200 acres to an industry partner for C$5 million.

• Bellamont Exploration, although starting out on the Alberta side of the Montney formation, is gaining a toehold in British Columbia. It is typical of the high-flying juniors in the Montney play. Launched in late 2006 with an initial public offering of C$11 million, its market capitalization has cracked C$100 million, with first-quarter production averaging 340 barrels of oil equivalent per day and gross land holdings at 52,000 acres.

• Canada Energy Partners has unveiled an exploration strategy for its 41,000 acres in the Montney-Doig shale play, while director John Proist scooped up 34,000 shares for C$0.64 each in early February.

• Birchcliff Energy, which plans four Montney-Doig horizontal wells before mid-year and tie in three to four wells as part of its winter program, announced a C$115 million bought-deal financing, with prominent investor Seymour Schulich acquiring 1.8 million shares at C$7.46 each to gain a controlling interest of 18.8 million shares. The company expects to drill four to six more wells in the second half. It also holds about 13,000 acres of undeveloped land in the Pouce Coupe area, which it believes could extend the Montney-Doig play.

• Crew Energy has 7,360 net acres in the Muskwa play, where EOG made its find. A third-party evaluation estimates its potential gas-in-place at 400 bcf-1.2 tcf. CEO Dale Shwed says “everybody is looking at bidding for land up there.” Last fall, Crew completed a bought-deal financing of C$54.5 million.

• Storm Exploration reports 100 percent success from five net wells, is producing 5 million cubic feet per day from two Montney wells and expects to drill 18 more wells this year.

• Grey Wolf Exploration has budgeted C$15 million to exploit its Pouce Coupe properties this year and is weighing horizontal wells in the Montney-Doig reservoirs.

• Seaview Energy has entered into three separate farm-ins, involving a four-well commitment to earn an interest in 4,480 gross acres in Pouce Coupe, exposing the company to 30 bcf of resource potential. The focus area is in a fairway