Delving into the Duvernay

Juniors to majors are seeking a sip at the Holy Grail

duvernay map
It's easy to get caught up in the excitement of a hot new play. Big land sales. Escalating values as producers jump the train before it leaves town. A swell of activity. And, if test well results are promising, market coverage and buzz. Lots of buzz—and today most of it is about west-central Alberta's Duvernay formation.

In the capital-intensive oil and gas business, buzz is good. It generates investor interest and a favourable financial environment for development. It helps launch joint-venture agreements like the one announced last December between PetroChina Company Limited and Encana Corporation, giving PetroChina a 49.9 per cent stake in Encana's Duvernay acreage for $1.18 billion upfront and $1 billion in development costs during the next four years.

The Duvernay is taking its place next to world-class plays like British Columbia's Montney, or the Marcellus in Pennsylvania—heralded as the "Saudi Arabia of natural gas," a shale formation that has spawned so much activity in the last few years that it's now the largest producing region in the United States, producing in excess of 10 billion cubic feet of gas per day. Proximity to North America's biggest natural gas consumer market, the U.S. Northeast, and the best liquids-rich gas economics in North America have analysts forecasting that the Marcellus is en route to 18 billion cubic feet per day by 2018 when it will surpass the total production of western Canada.

So what does the Duvernay offer? Could it and the Montney counter U.S. shale gas heft? According to the Energy Resources Conservation Board, the Duvernay holds an estimated 443 trillion cubic feet of gas, 11.3 billion barrels of natural gas liquids and 61.7 billion barrels of oil.

It's a proven source rock for much of the Devonian conventional oil and gas that launched the modern oil and gas era in Alberta in 1948 with the spudding of Leduc #1. Promising early results in the liquids-rich Duvernay window that runs 300-plus kilometres from Grande Prairie, northwest of Edmonton, to Olds, Alta.—where virtually all current exploration activity is taking place—have analysts at Wood Mackenzie expecting 1.5 billion cubic feet per day and 130,000 barrels a day of liquids by 2020.

Alberta's Duvernay land rush kicked off in 2009 and culminated in a record sale of 446 Montney and Duvernay area leases in 2011. A bundle of large and small operators has divvied up the land. Among the big boys are Encana, Canadian Natural Resources Limited, Talisman Energy Inc., Shell Canada Limited and Chevron Canada Limited. Each has stakes in the hundreds of thousands of acres.

Smaller companies like Yoho Resources Inc. jumped in, too. Yoho has 36,000 acres in what its president and chief executive officer, Brian McLachlan, says is probably some of best liquids-rich sweet spots in the play.

"We were buying land at Crown sales very quietly in 2009 for about $20,000 per section," he says. "From there, prices went up to as high as $3 million to $3.5 million per section."

Simon Mauger, director, gas supply and economics for the consultancy Ziff Energy Group, says Duvernay land is the single biggest cost in the play for some operators. And it's one of the most expensive plays in North America to drill and complete.

A Wood Mackenzie report released at the end of 2012 lists completed well costs at between $12 million and $15 million. But Encana's Kevin Smith, vice-president of its northwest business unit, lifts an eyebrow at those figures.

2012 Nov-Kaybob D Chevron Jim MacDonald2Chevron Canada has been an active Duvernay driller.
"Twelve to $15 million is certainly something in terms of much shorter laterals in shallower portions of the play, with fewer frac intervals and lower production compared to what we would expect for our type curve," he says. "Our initial appraisal wells were in the range of $20 million to $25 million per well."

The largest holder of publicly disclosed Duvernay rights is Athabasca Oil Corporation. Its 640,000 acres has analysts speculating about joint ventures. Athabasca has so far remained mum on the topic other than to say the Duvernay "is an area where smaller companies will have to take partners in the future if they want to develop in a timely fashion." (Talisman has said the same of the Duvernay. It's among several areas where the company is considering partnering.)

Celtic Exploration Ltd., which has over 100,000 Duvernay acres, shored up its finances this February when it was bought by Exxon Mobil Corporation's resource play division, XTO Energy Inc., for $3.1 billion.

The economics of the Duvernay stand on prolific, condensate-rich production. Encana is spending $600 million (gross with Phoenix Energy Holdings Ltd.—PetroChina's Canadian subsidiary) in the play this year. It has drilled 13 wells on a rig release basis to date. One of those wells has produced a widely publicized 1,400 barrels per day of condensate and four million cubic feet per day of natural gas after 30 days.

"Like any other play, there are going to be sweet spots," Smith says. "Our exploration work is positioned around the key criteria of sweet spots within that highly economic liquids window—between 45 barrels per million [cubic feet] and 300 barrels per million."

For Yoho Resources, the Duvernay represents 55–65 per cent of the company's total reserves and its $35 million and $38 million capital program is mostly focused on the Duvernay.

Some encouraging Yoho results include an 11-day test well producing six million cubic feet of gas per day and 109 barrels of field condensate per million cubic feet of gas.

"We're seeing 100 to 160 barrels per million [cubic feet of gas] and as high as 200 barrels per million of liquids, of which 65 per cent is condensate," McLachlan says.

High condensate yields and robust condensate prices (currently yielding a 10 per cent premium to West Texas Intermediate oil pricing in Alberta) have Yoho's netbacks looking very much like oil netbacks in the Duvernay—over $43 per barrel equivalent, says McLachlan.

Numbers like this are spawning comparisons to the Eagle Ford in the United States, the highly profitable south Texas shale gas and oil play. Mauger says the Duvernay has the potential to become one of the top five plays in North America.

"We're already pretty sure about the north Duvernay," he says. "The south Duvernay is a little further behind in development—a year or two."

By "north" and "south" Duvernay, he's referring to the liquids-rich Duvernay window that runs 300-plus kilometres from Grande Prairie to Olds and is divided into two main regions: the area around Kaybob, where most of the activity has taken place to date; and the area around Willesden Green and Ferrier in the south (see map).

Proving it out
What attracted McLachlan to the Kaybob area is the Duvernay's thickness there, its favourable reservoir characteristics and the uniformity of the shale from top to bottom, as opposed to the limestone streaks that begin to mark the shale south around Ferrier.

At the outset, Yoho was caught off guard by the formation's high pressures, which forced it to forego completing its first horizontal well.

"We had no idea that we're looking at the second-highest reservoir pressure in North America," McLachlan notes. "You're probably looking at 60-plus MPa [megapascals], which is pretty substantial. So you have to be prepared for the pressure, but then it helps in production."

Yoho then drilled eight horizontal wells, all of them good wells, according to McLachlan. It has taken the information about these wells and traded it with other companies operating in the area.
"So we're getting information on about 25 different wells out there," he says.

Trading information is an important strategy at this stage of development in this expensive play. Encana is also trading information with other producers, prompting a subtle shift in terminology: instead of referring to "competitors," Smith talks of "industry counterparts."

"It seems, at least initially in talking to our industry counterparts, there's a willingness and an openness to sharing," Smith says. "When you're investing this much money into a well and collecting that amount of rich data, sharing is really a best practice amongst companies and really helps the efficiency of the play overall."

Encana is working in both the north and south ends of the liquids-rich Duvernay window. Smith considers it still too early to say which region will provide better results, but its best results to date have been in the north around Kaybob.

"We're proceeding with a very deliberate, logical test," he says. "We're testing different completion approaches to arrive, as quickly as possible, at the most optimal completion design. And that varies from area to area."

One of the early learnings in this region is that longer laterals and more frac stages drive better economics.

"We've always been proponents of longer laterals where you maintain the same stage spacing," Smith says. "We feel this is more accretive than drilling more wells. What we've seen from official results is that the stimulated rock volume is a huge driver in the productivity of this play."

To arrive at optimal stimulated rock volumes, Encana is experimenting with tighter frac spacing, longer frac intervals but more entry points, cased wells and, in June, it landed its first open-hole packer ball drop system.

At low current production levels in the Duvernay, producers aren't yet particularly concerned about optimizing their gas processing options. Most of the gas goes to third-party shallow-cut plants. Since a shallow-cut captures the same amount of condensate as a deep-cut (which also captures the ethane, propane and butane) producers will likely stay this lower-cost course.

"It's really about maximizing condensate," Smith says. "Condensate has strong local demand and it will persist. The marginal barrel is a significant amount of condensate that's coming up from the Gulf Coast."

As Duvernay production rises, deep-cut processing might become an option but the prices of ethane, propane and butane will have to strengthen from current lows due to oversupply.

The land in the Duvernay is mostly locked up now, but asset deals and partnering announcements will continue. Some producers, such as Bonavista Energy Corporation, will leave the play (it sold most of its quarter-million net acres last year).

Some, such as Bellatrix Exploration Ltd., will hold on to their Duvernay assets (Bellatrix has 53 net sections) and "wait to see how it goes for the big guys in there," executive vice-president Brent Eshleman says, but focus elsewhere to make money.

And many, like Encana, or Yoho or Chevron Canada (which has 250,000 acres in the Duvernay near Kaybob and is in the midst of a 13-well program) will continue their appraisal to better understand the huge potential of the Duvernay.