Costs and efficiencies make Saskatchewan’s Viking play a top tight oil spot in North America

Costs and efficiencies make Saskatchewan’s Viking play a top tight oil spot in North America

By R.P. Stastny

Nov. 14, 2016, 3:23 p.m.

The crushing pressure of $40-something WTI oil prices has forged a stronger, more resilient resource industry. Advances in multi-frac technology—faster drilling, quicker completions, longer wells, more stages, more sand, better practices—coupled with painful cuts to wages and staff slashed break-even tight oil production to less than $30/bbl in some of the best plays in North America, including the Viking Formation in southwest and central Saskatchewan.

Unlike big name U.S. resource plays, the Viking is relatively shallow—about 750 metres in the areas that see the most activity—so it’s cheaper to drill but also requires a lot of wells to tap a significant volume. That reality shapes the kind of company that does well in the play and how it goes about its business.

“There’s a statistic I like to quote,” says Jason Denney, president and chief executive officer of Teine Energy, the play’s largest producer at about 27,000 bbls/d including production from its $975-million acquisition of Penn West Petroleum’s Viking light oil and conventional Bakken heavy oil properties this summer.

“That statistic is that roughly 50 per cent of the reserves of a well in this play come out of that well after it is producing just 10 bbls/d.”

As a private pure-play company, Teine was able to take a longer-term view of development. Early in the development of the play, it recognized the importance of infrastructure to cost-effectively managing wells as they move into later life.

“A good solid infrastructure system with pipelines and gas gathering I think is the answer to keeping those barrels profitable,” Denney says.

“So we focused on building the infrastructure, which in the beginning probably had our costs slightly elevated [compared to] our public competitors because they focused more on drilling wells. But longer term now, you can see it in our operating costs…. We’re towards 25 per cent lower cost on the operating and transport side. That’s going to be with us for the rest of the development of the play.”

When drilling hundreds of wells each year (Teine is on track to drill 220 wells in 2016), achieving the best economics also requires seamless execution. The ability to spud a well and bring it on production in roughly 20 days keeps capital costs down.

“We were also one of the first guys to run a SCADA [supervisory control and data acquisition] system, which is really a data system,” Denney says.

“Our single largest operating cost out in the field is manpower, so we wanted to be smarter with our manpower instead of just hiring more bodies.”

Teine manages more wells with fewer people by giving its operators real-time production information, so they can decide which wells need attention and which don’t instead of making the rounds to each wellhead.

In the early days of the Viking, analysts mostly dismissed the play for its 50-bbl/d wells. But that was when horizontals drilled and completed in the Viking cost about $1.3 million each. Today, well costs are in the low $600,000s, and the play has attracted more than a dozen players.

“Services costs have troughed,” says Neil Roszell, president and chief executive officer of Raging River Exploration, the Viking’s second-largest producer at almost 20,000 bbls/d. Raging River’s wells cost it about $625,000 to drill complete and tie-in.

“I think we’ve seen the bottom of the cost structure. Our costs have been stable since June, and we haven’t seen any real reductions since then,” Roszell says.

Raging River is another pure-play company and it’s also been on the acquisition trail this year. In the second quarter, it closed its purchase of Rock Energy for $111 million, issuing 3.896 million Raging River common shares and assuming about $70 million of net debt and other liabilities.

Raging River also completed its Forgan land consolidation, a 30-net-section property acquisition of crown land and 100 bbls/d of Viking light oil for $25.1 million in cash (prior to closing adjustments).

Today the Viking gets a lot of attention. Its economics are on par with the best light oil plays in North America, some of which boast sub-$30/bbl break-evens. To that, however, Roszell adds a qualifier.

“I spend a lot of time looking at the U.S. plays—the Permian, the SCOOP [South Central Oklahoma Oil Province], the STACK [Sooner Trend Anadarko Basin Canadian and Kingfisher Counties], the Eagle Ford, the Marcellus—and bottom line is that the best of the best wells, where there is no risk, certainly the rate of return neutral is $30/bbl, but that’s very few and far between.

“The way I look at it is a little different. The top 50 per cent of our drilling inventory would be reasonably economic at $45 WTI. I think we’re very comparable to the Permian in that regard. The balance of our drilling inventory starts to need more like $55-plus oil to make an advancement,” Roszell says.

Denney notes the same variability within plays.

“One of the misconceptions out there is people looking at sweet spots and saying break-even costs are $35,” Denney says. “But you have to look at your portfolio in aggregate and provide more realistic views on where you’re actually breaking even.”

Teine’s average break-even is in the $35 range, Denney says, but he doesn’t like to get caught up in discussions of misleading half-cycle economics. “You really need to look at the overall return on capital employed by the company. People invest in companies, not in wellbores. So to ensure that a company can provide returns at this oil price is more important.”

Technology and practices in the Viking continue to evolve. While most producers have settled on average horizontal well lengths of about 600 metres with 18 or 20 fracture stages, both Teine and Raging River are also currently testing extended-reach horizontals.

About 70 per cent of the completions in the Viking fairway are done with straddle coil fracking (coil tubing conveyed perforations). The other 30 per cent is sliding sleeve on coil completions, such as NCS Multistage’s system.

“I think we’re getting to that optimal frac design, but I don’t think we’re there 100 per cent yet,” Deney says. “What we’re finding is that frac design is becoming area-specific within the play. There is no one-size-fits-all. But we are seeing longer wells being drilled, three-quarter-length wells, full-length wells, so there are changes to the completion as you extend these wells, and it’s still evolving.”

A production spike in the Viking in early 2014 created some takeaway constraints, but since IPL’s pipeline expansion doubled the takeaway capacity in the region to about 110,000 bbls/d, there haven’t been any issues. Roszell doesn’t foresee any problems in the future, even as the play’s top producers plan on aggressive growth in the area. Raging River expects it can drill 300 wells in 2017 based on a $48–$50 WTI oil price deck.

A third player in the ring is Whitecap Resources. This is a bigger, geographically diversified producer closing in on 50,000 bbls/d across three regions. The Viking is a high rate-of-return play from which it maintains 20–25 per cent of its corporate production.

“This percentage allows us diversity and balance within our program and portfolio,” notes Whitecap’s president and chief executive officer, Grant Fagerheim. Whitecap will drill about 52 Viking wells this year and 90–120 in 2017. “We have the opportunity to continue to grow our production and value in this play for many years to come.”




About prosperitysaskatchewan

Consultant on Saskatchewan's natural resources.

Posted on November 14, 2016, in economic impact, oil, political. Bookmark the permalink. Leave a comment.

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