Why should U.S. shale producers have all the fun? Enthusiasm about shales boosting North American natural gas supply now extends a long way, from the pines of northeast British Columbia to the cacti in South Texas, where the Eagle Ford shale is being developed. It also grips the largest gas producers on the continent—ExxonMobil, EnCana Corp., Devon Energy Corp.—and dozens of smaller companies and landowners.

On both sides of the Canadian border, producers are revamping their asset mix in order to deploy more capital in unconventional and shale plays. In December, Talisman Energy became the latest, cutting 220 people, 15% of its North American staff, to refocus on unconventional gas.

At the same time, the Calgary firm said it will double its development budget to $1.6 billion in two shale plays, the Marcellus in the U.S. and the Montney in northeast British Columbia.

In the latter, Talisman’s focus in 2009 was in the Greater Groundbirch, Greater Farrell and Greater Cyprus areas. The company expected to complete 20 pilot wells (11 horizontals). It holds 270,000 net acres in the Montney.

The Montney area is generally west of the Alberta-B.C. border, south of Fort Nelson and around the town of Dawson Creek, which was the southern terminus and staging area for construction of the Alaska Highway years ago.

“There is a lot of activity going on. Some 1 to 1.5 Bcf a day is scheduled to come on the books from 2009 to the end of 2011,” says Bob Fitzmartyn, vice president and director of institutional research for FirstEnergy Capital Corp. in Calgary. “The biggest challenge is managing people’s expectations and growing the play without inflating your costs.”

The Attraction

What is the attraction of the Montney? It is a tight, fine-grade sandstone-siltstone with shale embedded, but most people refer to it as a shale. Whatever it is, says Fitzmartyn, it holds a lot of gas: some say 15 trillion cubic feet.

Porosity ranges from 3% to 6%, but initial production rates (IPs) are 4- to 10 million cubic feet per day per well. Estimated ultimate recoveries are thought to be 4- to 5 billion cubic feet, sometimes more.

EnCana has said it estimates up to 300 billion cubic feet of gas per section and some 70 trillion cubic feet of original gas in place on its extensive holdings.

Montney Shale

ARC Energy Trust drilled the first horizontal well in the Montney shale in 2005. It plans some 37 wells for this year. Here, the first of its three planned gas plants.

This play has drawn companies of every size. The top producers and acreage holders are EnCana, ARC Energy Trust, Shell Oil (by virtue of its $6-billion buy of Duvernay Oil Corp. in 2008), Talisman Energy Inc. and Murphy Oil Corp. A host of smaller companies are also involved, such as Advantage Oil & Gas Ltd., Progress Energy Ltd., Monterey Exploration Ltd. and Cequence Energy Ltd.

By some estimates, operators are producing nearly 450 million cubic feet of gas per day from the Montney currently, from less than 50 million cubic feet of gas per day in 2005. The National Energy Board of Canada estimated that production could reach 906 million cubic feet per day by year-end 2010—double what it is today.

The play compares very favorably to other shales in North America, but unlike the Horn River Basin shales found to the north, it does allow year-round drilling, and a lot of gas infrastructure is already in place. What’s more, its areal extent and pay thickness are greater than the Horn River shales.

The land grab in northeast British Columbia for this shale from 2006 to 2008 was understandably fast-paced. It is mostly over now, after setting some lease records in 2008.

Land sales in 2009 commanded anywhere from $5,000 to $13,000 per hectare. Despite low natural gas prices that have plagued Canadian producers as much as their U.S. peers, operators continue to be enthusiastic about the play. Several have announced a larger drilling budget for 2010.

Like most shale plays, the Montney has a wide areal extent and boasts tremendous reserve potential. And like its stateside cousins, its development will be firmly controlled by the pace of infrastructure construction and gas wellhead prices.

Several new gas processing plants will go online this year to facilitate even more production. TransCanada Pipeline is building a 36-kilometer Groundbirch line from the Alberta border west about 30 miles to the Dawson area, with capacity of 1 billion cubic feet per day. It is said that Shell bought Duvernay for the latter’s ample Groundbirch leasehold.

EnCana executives have said the Montney is as cost-competitive as any other shale in North America.

British Columbia’s graduated royalty scheme (based on natural gas prices) and other incentives add to the business model here. At press time, the Alberta government was about to announce new incentives to attract more companies back to its natural gas plays.

Size of the Prize

The Montney play trends from the northwest to the southeast and covers an estimated 120 miles by 50 miles. It is present under a significant part of Alberta and most of northeast British Columbia, explains Glenna Jones, vice president, Canadian equities, Ross Smith Energy Group in Calgary.

“The sweet spot is near Dawson Creek. The conventional part of the play has been a target since the 1950s, but now we are tackling the deeper, tighter sections, that were not economic before multistage fracs.

“So far, the decline seems less severe relative to other shale plays,” says Jones.

Gas-in-place estimates are impressive.

“Within the Montney, from Tommy Lakes in northeast British Columbia, down through to Bighorn in west-central Alberta, there is an identified 600 trillion cubic feet of gas in place, based on a 3% porosity cutoff distributed, as estimated by the industry’s No. 1 Montney producer, EnCana,” according to a FirstEnergy Capital Corp. report.

“EnCana estimates 165 Tcf OGIP (original gas in place) from its approximately 1,200 sections of Montney acreage…reduced further to 71 Tcf when isolating for Upper and Lower Montney. Of this, 26 Tcf has been deemed as ‘economically accessible…,’” the report says.

“Our view is that the Montney is huge. There’s no question about that,” says John Dielwart, chief executive of ARC Energy Trust. The Calgary trust, which will convert to a corporation by year-end, drilled the first horizontal well in the play in 2005.

This year, it plans to drill 32 horizontal wells in its Dawson Field, and five more on its Montney West lands. It will open its new gas plant in the second quarter with 60 million cubic feet a day of capacity, a second plant of equal size in 2011, and a third in 2012.

ARC’s activity is designed to increase operated production from 55 million a day in 2009 to a stabilized rate of 105 million a day upon completion of the first gas plant this year.

“We have identified 8.1 Tcf in just the Upper Montney alone, that’s just net to our interests. The other major players—Shell, EnCana and Murphy Oil—will all have substantial amounts as well,” says Dielwart.

“Not all of this will be drilled up, but if you add in all the smaller players, you get to multiple Tcfs in a hurry.”

He thinks there is 40 to 50 Bcf per section in the Upper Montney and up to 100 Bcf per section as the play moves westward. On its West Montney lands, ARC has budgeted $47 million to further delineate the potential, and for continued development of a partner-operated Montney project at Sunrise that will contribute a stable 10 million cubic feet of additional production net to ARC in 2010.

Additionally, ARC expects to have another 60 million a day of production on the operated lands at Sunrise in early 2012. It has also allocated $20 million towards Montney development and exploration on the Alberta side of the border at Pouce Coupe, Progress and Valhalla.

The unconventional part of the Montney is found from 6,500 to 9,000 feet, deepening to the west. It was deposited in an open-shelf marine environment during the Lower Triassic age, according to a FirstEnergy Capital report. The sediment source was from Permian and Mississippian material, forming submarine fans and turbidite channels in the Lower Montney and lower shoreface sands in the Upper Montney. Just above it lies the Doig Phosphate zone, a sandstone that looks like a shale. The Montney itself has a gross maximum thickness of 350 meters in some places, while several small targets within that can be 50 meters thick.

ARC’s Dielwart says the play compares very favorably to other shales. “We’re still looking at optimal well spacing, but one frac every 200 meters seems to work. But here, one well holds nine square miles, whereas in the States, one well holds only one square mile.

“Plus there are drilling and royalty incentives in British Columbia, and we have year-round access, unlike in the Horn River Basin to the north.”

Collaboration

Last July, Object Reservoir Inc., Houston, announced a multicompany collaborative exploitation project (CEP) to deliver best practices for the Montney. The project focuses on strategies for data gathering, completion design, stimulation, well spacing, reserves estimation, and workflows that can speed up the learning curve for optimal exploitation and monetization of operators’ acreage.

Three leading Upper Montney operators holding a combined 440 sections—Shell, ARC and Murphy Oil—are submitting data from multiple producing wells for analysis. Object Reservoir plans to offer similar collaboration projects in other areas of the Montney. This is the second CEP led by Object Reservoir in 2009. Its Haynesville CEP began in April 2009 with 12 operators, who represent 60% of the leased acreage in that play.

“Our Montney shale CEP continues apace and our activity in the play is expected to expand this year to more companies and more areas,” says Hamish C. S. Nicol, vice president, business development for Object Reservoir.

“The industry appears to be crying out for a proper physics-based approach, in order to get all the capital we need a lot sooner. We can do better at understanding shale-well performance,” he says.

“Critically, in our opinion, collaboration is helping…and of course, if we can take something to the auditors derived from the Montney data, as opposed to something based on a comparative dataset, then we are starting to get…a better understanding of the potential of this play, as revealed by performance, in a way that can feed to an earlier de-risking of options.”

Nicol says operators have indeed found some variability in the geology in the play. “As you know, it’s not strictly a ‘shale’ but has many of the characteristics of a shale. The quality of Canadian data has really helped our work in deciphering the mechanisms here that impact well spacing, etc. We have looked thus far at nearly 30 Montney wells in reasonable close proximity to each other.”