Diving Into The Duvernay Hype

Hopes for Alberta’s Duvernay shale are about as high as the magnificent Rocky Mountains to its west. It’s been hailed as the Canadian equivalent of the Eagle Ford. Others call out a world-class play with tremendous resource potential. Indeed, expectations are strong for the Canadian formation.

But whether all of this hype is justifiable—or perhaps leaning toward the hyperbolic —has yet to be established.

“When you compare this play’s rocks to the Eagle Ford, it certainly has similar attributes in terms of its organic content, its porosity, its depth, its thermal maturity and its thickness. All of the things that would influence its ability to deliver similar types of hydrocarbons are the same,” geologist Mark McMurray, managing director with RBC Rundle, tells Midstream Business.

“We anticipate that the initial wave of capital that’s coming into the play over the next couple of years is going to help frame that potential. The thing that is still uncertain with the play is its lateral extent both along the trend and across it. The liquids content within the play needs to be better understood and the type-curve performance needs to be better understood before we see capital tearing into development.”

There’s no questioning the Duvernay’s promise. And, likewise, there’s no doubting the industry’s commitment to capitalizing on its potential. Already, billions of dollars have been spent on land acquisitions, testing and drilling in the Duvernay, according to BMO Capital Markets. The land rush began in 2009 in the Duvernay’s Kaybob region, which today is where the bulk of activity is occurring.

However, its future remains somewhat shrouded in mystery. Data is currently limited, which has led to plenty of speculation in terms of what the liquids content will be on any individual well. But that’s set to change. By year’s end, the play will have approximately 40 additional horizontal wells coming off tight-hole status, meaning more information will become public. Results will be related to production rates, liquids content and well decline-behavior. Right now, the key challenge is related to liquids variability and decline behavior, says McMurray.

“That’s something we’re still learning about: how wide the play is and how much variability is in the liquids content,” he says. “Until we’ve got more well data across the play, we’re not going to be as prescriptive describing our investment returns.”

It’s not difficult to appreciate the lure of the play. Spanning across the bulk of central Alberta, the Duvernay spreads across 50,000 square miles and contains oil, dry gas and liquids-rich windows. Numerous deep-pocketed industry players are stepping in to claim a stake.

Great expectations

Although it has yet to prove itself, some industry leaders have likened the Duvernay to the hottest shale plays in the United States. Such comparisons stem largely from similar geology and large resource potential, says Wood Mackenzie Canada and Alaska analyst Andrew McConn. The similarities don’t end there. Like its shale cousin to the south, the Duvernay boasts three windows. Some are hopeful the Duvernay’s similar geology might allow it to replicate the same results that have been achieved in Texas. This optimism can be taken as premature, since drilling results still need to confirm that the Duvernay can be as economic as the Eagle Ford, says McConn. And there’s one thing standing in the way of Eagle Ford glory: money.

“The Duvernay is one of the most expensive plays in onshore North America,” McConn tells Midstream Business. “Costs can really slow development in the early phase. As far as predicting how big of a play it will be and comparing it with other really prominent plays like the Eagle Ford, you have to be cautious. It’s possible it could be as big, but the costs are really inhibiting.”

Duvernay drilling costs have reached upward of $15- and $20-million per well. It is not uncommon for costs to skyrocket when companies start ramping up development in an area. After all, it takes time for efficiencies to be achieved through pad drilling and the optimization of different completion techniques, says McConn. As well, given the depth and complexity of the Duvernay reservoir, costly, high-specification rigs are required. Equipment capable of handling the play’s high pressure and temperatures is necessary, too.

“The resource potential is quite large, so that’s the real initial attractor,” McConn says. “Some of the recent well results have proven the resource is there. Now it’s just determining whether the economics can make it work. The resource part is proven. It’s just the value and economic side which is unproven.”

RBC Rundle’s McMurray says the biggest challenge now will be to reduce drilling and completion costs by between 25% and 35%.

“That’s necessary in order for us to see a really profitable commercial development program undertaken,” McMurray says. “But if you look at most of the drilling and completion trends in resource plays in North America, that is a realistic expectation. There’s a lot of science going into the play right now, which will affect the capital cost.”

Given the capital intensity of the region, McConn says it’s going to take the industry’s biggest players to fully develop the area. He points to Exxon Mobil Corp.’s C$2.6 billion acquisition last year of Celtic Exploration Ltd. Other industry giants have also established a strong presence in the play.

“There are smaller players out there, but if you’re looking at a catalyst to really kick things off, I think it is going to be one of the bigger guys.”

Wait-and-see approach

The Duvernay already has existing infrastructure in place from the decades of conventional production that preceded its shale chapter. Ultimately, more midstream build out will be needed, particularly with respect to liquids-extraction and processing facilities. But those infrastructure demands aren’t likely to arise in the near future. Instead, says McConn, most Duvernay players will occupy the next few years with upstream activities such as delineation drilling and development.

“There are a few midstream companies that are trying to get commitments now and build that out before development wraps up,” he says. “You won’t see too many of those decisions made in the near term. You’ll see more infrastructure needs get addressed further down the road. It’s a long process. Infrastructure is needed, but it will be awhile.”

It’s not clear exactly how much midstream build out will be needed. This will depend largely on the play’s processing capacity and how much of it is developed. Although analysts know the size and scope of the play, they aren’t yet sure which parts will be developed, leaving it difficult to make predictions. Right now, all McConn can say with confidence is that: “If the Duvernay does ramp up, we know they’ll need more infrastructure.”

McMurray says many of the existing gas processing facilities were designed for a shallow cut. He says he would expect to see more investments made in deep-cut facilities in coming years as producers look to strip more liquids from the gas production.

“For the near term, we can access the legacy infrastructure that supported conventional production.” says McMurray. “In the longer term, the potential of this play will demand an expansion in our midstream infrastructure. Obviously every operator is going to make those build out decisions if midstream is going to be part of their business. Otherwise, we expect midstreamers to step in and support development.”

The Canadian advantage

Though its future is unclear, one thing is certain for the Duvernay: There’s no great rush to get it developed. Canada’s land- tenure system differs from privately held land in the U.S. above such shale plays as the Eagle Ford and Marcellus. And since the Canadian regulations aren’t nearly as onerous with respect to how quickly drilling must be completed, operators are free to take their time with projects. Unlike U.S. operators who are rushed by quick expirations on private licenses and leases, Canadian operators have the luxury of sitting back and waiting.

“It has the potential to be a large play in terms of production and resources, but operators have the option to take their time and most of them will, just because it’s a high-cost environment, and, in the early days like this, you can make mistakes,” says McConn. “You don’t want to make $10- and $15-million mistakes by drilling in the wrong area.”

This isn’t the Duvernay’s only advantage. Producers are able to obtain strong prices for the liquid-rich play’s condensate volumes by shipping it to Alberta’s oil sands. The light condensate is used to dilute the oil sand’s thick and viscous bitumen.

“There’s good pricing because there’s such a high demand for the condensate, which is one of the drivers of the play,” says McConn. “Of course there is a dry-gas window to the play, but for economic reasons, it’s the liquids that are getting the most attention.”

Yet another advantage for the Duvernay comes in the form of provincial royalties, says Macquarie Securities Group analyst Ray Kwan. He notes that anyone who drills a horizontal well in Alberta typically receives a 5% royalty for between 12 to 48 months. There’s also a volume limitation for both oil and gas. But Alberta is more generous with gas and oil royalties when it comes to shale plays. Anyone who drills into a shale formation receives a 5% royalty for 36 months without a volume limitation.

“I think that really attracts a lot of people to this play,” Kwan tells Midstream Business. “That royalty incentive gives a lot of producers comfort. If you’re going to bring down costs, you’re going to make money out of this play.”

Hitting the gas

Stretching across the majority of central Alberta, the Duvernay is home to billions of barrels of oil and gas, according to the Alberta Geological Survey. It’s not yet clear how much of this resource base is recoverable. Of all the energy behemoths—such as Shell, EnCana, Petrochina, Talisman, Chevron and Trilogy—stepping in to claim a stake, most are focusing on the play’s Kaybob and Willesden Green regions. With all this activity under way, Kwan says he expects the Duvernay to accelerate rather than flatten or decline.

“Certainly over the next couple of years, we’re going to see the initial delineation phase we’ve seen over the past two years move into production and production growth for the players in those specific regions,” he says. “The bottom line is that I am fairly bullish on the play.”

Though the liquids-rich and condensate window is currently being targeted, Kwan sees strong potential for the oil window as well. He anticipates that as more data emerges and delineations are completed, producers will become more active in the Duvernay’s oily opportunities. Tapping into the oil window could help strengthen the play’s economics as well, provided productivity is high enough.

“But I certainly think the condensate window is going to move to the forefront first, like it did in the Eagle Ford,” says Kwan. “And the dry-gas window, until gas prices really improve, is going to be relatively dormant.”

Kwan says there’s also a growing demand for a deep-cut plant in certain active regions of the Duvernay. (Deep-cut gas processing facilities recover lighter liquids such as ethane, propane, butane and pentane.)

Bringing such a project to life would play an important role in recovering butane and propane and could, eventually, help strengthen the play. Although propane and butane prices aren’t currently strong, Kwan expects their values to eventually rise. And when they do, he says, those liquids will likely play a large role in the overall economic equation.

“Having a deep-cut plant is potentially another critical factor in improving the economics for some of these wells,” he says. “From a midstream point of view, having that near some of these large producers who are able to process this gas will be very important.” END

Michelle Thompson can be reached at 713-260-1065 or mthompson@hartenergy.com.