Multi-frac Horizontals A Game Changer For Western Canada

By Pat Roche

Not long ago, the world's biggest oil companies had largely written off Western Canada.

Apart from the oilsands, all the big prizes had been found, the thinking went, and the billions of barrels of crude oil and trillions of cubic feet of natural gas remaining in known fields were deemed unrecoverable.

Industry giants were selling acreage and heading overseas, or offshore and even into the Arctic.

But that was before advances in horizontal drilling and completion techniques opened up gigantic new gas plays in the northeastern British Columbia and crude oil resources in southern Saskatchewan.

Now the multi-frac horizontal technology that opened up B.C.'s Montney and Horn River gas riches and Saskatchewan's Bakken tight oil treasure are being deployed in many other formations across Western Canada.

The success of companies such as EnCana Corporation in the Montney and Petrobank Energy and Resources Ltd. in the Bakken has been extensively reported. This article is merely a sampling, not an exhaustive summary, of attempts to take multi-stage fracturing in horizontal wells beyond those horizons.

The technology is already being called a game changer that could launch a new era of growth -- just as the first horizontal wells and three-dimensional seismic revived the industry in earlier decades.

Packers Plus Energy Services Inc. -- whose name is synonymous with multi-stage fracturing because of its pioneering success in those blockbuster plays -- has now deployed its technology for more than 100 companies in 26 formations across Western Canada, said president Dan Themig.

So far, no one has proclaimed a second Montney or Bakken. But scores of companies have had positive drilling results in individual wells over a broad range of formations.

Old fields discovered half a century ago are being re-examined. Zones that were uneconomic with vertical wells are suddenly profitable. And despite the worst drilling downturn since the early 1990s, the implications are creating a sense of excitement about the basin's potential.

"Technology is driving a return to the old plays of the '50s in a new way, and making them economic," said Ed Dancsok, assistant deputy minister of petroleum and natural gas with Saskatchewan's Ministry of Energy and Resources. "Everything is being attacked with a new vigor."

"I would say there isn't any formation that people are not looking at," said Dale Dusterhoft, vice-president of technical services with Trican Well Service Ltd., adding it has already been tested in many new horizons in the past six months.

ARC Energy Trust -- whose pioneering work at Dawson four years ago spawned B.C.'s Montney gas bonanza -- is now testing the technology in Montney oil at its Ante Creek field on the Alberta side of the border.

Two multi-frac horizontal Montney oil wells drilled at Ante Creek last winter each came on at 300 bbls of oil equivalent a day (including solution gas). Current output is more than 150 bbls of oil equivalent (BOE) a day, though still declining.

(Meanwhile, ARC's original Dawson discovery well -- onstream longer than any other horizontal Montney gas well -- is still flowing one mmcf a day after four years. ARC's total Dawson output of 55 million cubic feet (mmcf) a day will rise with completion of a new gas plant.)

What's truly amazing is some of the multi-frac horizontal plays are economic at gas prices that are a disaster for most of the basin.

"We're taking formations that -- standalone -- would be marginally economic to uneconomic," said Steven VanSickle, president of Fairborne Energy Ltd. But in those same formations it is now possible to drill a horizontal well, fracture it eight to 12 times "and make that a very economic operation ... even at today's gas prices."

As an example he cites Fairborne's play in the Wilrich formation at Marlboro, northeast of Edson in northwestern Alberta where the company is drilling its third horizontal well.

Fairborne's first Wilrich well came on at more than four mmcf a day, and was still producing more than three mmcf a day after four months.

A Wilrich horizontal well has a 10-15% rate of return at an AECO price of $3.50 per gigajoule, VanSickle said.

Profitability is greatly enhanced by Alberta's drilling incentives, but VanSickle said these multi-frac horizontals are still economic without the royalty breaks.

Fairborne has also reported success with three multi-frac horizontals in the Nordegg formation at Harlech in west-central Alberta.

After more than a year onstream, the oldest Nordegg horizontal is producing slightly less than half its original rate of about seven mmcf a day -- still a very good well.

At measured depths of 4,500 to 4,800 metres, the Nordegg wells qualify for between $900,000 and $960,000 under Alberta's $200-a-metre royalty credit.

"And with the deep gas royalty credit, we're getting $3 million to $3.5 million for those wells," said VanSickle. "So about half of the well cost is covered by the deep gas royalty credit and the $200-a-metre incentive."

Since many of these plays are in established fields, existing infrastructure greatly enhances the economics.

In a recent investor note, Peters & Co. Limited said Bonavista Energy Trust’s play in the Glauconite formation in west-central Alberta breaks even at $4 per mcf. Based on their analysis, Peters' Jeff Martin and Cindy Mah concluded the play -- known as the Hoadley -- is one of the most profitable gas plays in Western Canada.

"One of the reasons the economics are so competitive in the Glauc play is just because of the substantial infrastructure that's built up in this area already," said Keith MacPhail, Bonavista's chairman.

But the economics aren't the only compelling feature.

Bonavista estimates it has 1.2 tcf to 1.5 tcf of original gas in place on the 409,000 net acres it bought from EnCana earlier this year for $694 million. So far, only 0.18 tcf of this gas has been produced. Assuming the low end of the in-place estimate, that works out to 15% recovery.

"We believe that over time the recoveries will exceed 50%" -- though gas prices will largely dictate spending, said MacPhail. Based on the lower in-place estimate, a 50% recovery factor would work out to 600 bcf of gas.

That's small compared to the multi-tcf estimates for the major North American shale plays or even the Montney. The Hoadley resource didn't loom large for EnCana whose second quarter output averaged 767,000 BOE a day (after royalties).

"But it's still a meaningful amount of a company our size," said MacPhail. Bonavista's second quarter output averaged 52,000 BOE a day (before royalties). "It's going to be a cornerstone of our company for many years. It's going to be an area that receives much of our capital and much of our focus and attention."

Bonavista has drilled about a dozen horizontal wells in the Hoadley area, about 10 of which are onstream. The wells are fraced in about eight stages with 50-60 tonnes per stage.

MacPhail, who has three decades of oilpatch experience, describes the multi-frac horizontals as a "game changer" because of the potential to increase recoveries from established plays.

"I think it's starting to sink in that there is a lot of gas still to be found and produced through new technology," he said. "And so what that tells me is that gas prices will certainly have an upper limit ... for the next five to 10 years because of that supply."

He believes an AECO gas price of $5 to $7 per gigajoule will be needed to develop some of the bigger plays -- especially those that don't enjoy Hoadley's advantage of existing infrastructure. "We can make some money with the Glauc play below $5 an mcf -- but it's a pretty unique play."

Meanwhile, the number of formations where multi-frac horizontals are being tried continues to grow.

The biggest potential prize is locked in the Cardium formation. Spread over several fields, the Cardium's initial oil in-place oil is almost a quarter of the total in the Western Canada Sedimentary Basin, according to the Alberta Geological Survey’s geological atlas of the WCSB.

The largest field, discovered in 1953, is the Pembina Cardium with more than seven billion bbls of oil in place. "The low recovery factor makes this formation Canada's single largest conventional petroleum reserve," the atlas says.

Privately held TriAxon Resources Ltd. was a pioneer in the use of multi-frac horizontals in the Pembina Cardium.

"Two years ago we did a well and we fraced it with five stages. So that was the first," says Jeff Saponja, TriAxon's president.

The first well averaged 75 BOE a day (10-15% gas) over three months. After two years it is producing about 30 bbls a day, and will probably see declines below five per cent as is typical of Pembina Cardium wells, said Saponja.

Considering the well had only a five-stage frac, TriAxon is quite happy with the result. Meantime, Alberta' royalty changes prompted the company to focus much of its capital on Saskatchewan.

TriAxon drilled a third Pembina Cardium well last fall, but at that point global oil prices were collapsing. The company, like most juniors, cut spending, delaying the $1 million stimulation. TriAxon now plans to do a 12-stage frac on its second and third Pembina Cardium wells.

At Pembina, operators are taking either of two approaches. Some are using multi-frac horizontals on the edges of the field in virgin reservoir that was too thin or too tight to produce from vertical wells.

Others, like TriAxon, are drilling in the main part of the field where there's been depletion and waterflooding, but where some of the units have very low recovery factors. There are typically sandstone reservoirs.

Cardium is either conglomerate or sandstone, and the conglomerate typically has better permeability, and therefore had better recovery from vertical wells.

So operators doing multi-frac horizontals in the main part of the field today are typically targeting the sandstone where there's more oil left.

Bonterra Oil & Gas Ltd. has drilled three wells in the tight rock on the edges of an established Pembina Cardium pool. The first well came on at 250 bbls a day and was still doing 100 bbls a day six months later, and the others were similar, said Randy Jarock, Bonterra's president. The Pembina Cardium is Bonterra's biggest core area.

ARC Energy is using multi-frac horizontals in the main part of the field. However, the first two multi-frac horizontals the trust drilled in the Pembina Cardium (each of which came onstream at 300 bbls a day) were underneath an environmentally protected river valley that couldn't be accessed by vertical wells.

But ARC just drilled a third well that may be a better indicator, said David Carey, ARC's senior vice-president of capital markets.

That well -- which was recently awaiting completion -- was drilled in an area that has been drained vertically, but with a low recovery factor. ARC hopes the multi-frac horizontal will recover oil vertical drilling couldn't access.

ARC may drill up to four more wells at Pembina in the next few months. It also plans to drill two to four multi-frac horizontals in the Cardium in the Garrington area.

NAL Oil & Gas Trust drilled about 10 multi-frac horizontals targeting Cardium oil in the Garrington area in the past year. NAL says average first-month output ranges between 150 and 400 BOE a day, and the six-month rates range from 50 to 125 BOE a day.

The trust is also targeting the Cardium at Cochrane (one horizontal well drilled) and Pine Creek (several wells to be drilled by year's end). NAL, which characterizes its Cardium play as emerging, expects to have 20 to 25 horizontals drilled across its three areas by year's end.

In all, NAL has participated in multi-frac horizontals in five formations -- the Cardium, Bakken, Falher, Montney and Mannville.

"It's not rocket science -- you basically look for low recovery factors [and] large oil in place numbers," said Marlon McDougall, NAL's chief operating officer. "The large oil in place numbers/low recovery factors gives you a starting point."

Beyond that, the trick is to get three to five times as much initial production and ultimate reserve recovery from the multi-frac horizontals as from vertical wells, which may cost half as much, said McDougall. "It's no more difficult than that."

The NAL executive believes multi-frac horizontals will give old fields a new lease on life.

"If you look at the distribution of reserves in the basin ... the largest number of unexploited resources are sitting in these tight reservoirs where they're known, and it's understood there's a significant resource, but it wasn't viable through vertical drilling," he said.

Capital budgets favour oil these days because of its relatively strong price, but multi-frac horizontals have extensively targeted gas as well.

Vero Energy Inc. began using multi-frac horizontals in the Rock Creek formation four years ago, and has since tested Notikewan and Bluesky gas as well.

The company did its first Packers Plus completion in December 2005 and has now drilled 28 horizontals in its Deep Basin area, including 17 in the Rock Creek.

After a year, the Rock Creek wells are producing about 750-800 mcf a day, and continue to decline, said Doug Bartole, Vero's president. He expects after two or three years on production the wells may settle into a 20% decline.

Vero is doing four to five fracs per Rock Creek well, or one every 200-250 metres in the horizontal leg.

In the Notikewan (where the company has about 10 wells) initial rates are more consistent, averaging nearly three mmcf equivalent a day in the first three months, about 1.7 mmcfe a day in the first year and finishing the first year at roughly 850-900 mcfe a day, said Bartole.

After B.C.'s Montney and Horn River successes, the technology's biggest Canadian achievement has been the Bakken tight oil play in southeastern Saskatchewan.

Oil has trickled from vertical Bakken wells since 1952, but most of this huge in-place resource remained locked in tight rock until the second half of this decade when the success of multi-frac horizontals produced a land rush and drilling boom that has been dubbed Saskatchewan's oilsands.

From negligible production at mid-decade, Bakken output soared to a record 58,000 bbls a day early this year before slipping below 50,000 bbls a day by mid-year. (At 50,000 bbls a day from about 1,150 wells, Bakken production averages about 44 bbls of oil per well. The best wells exceed 200 bbls a day.)

The drop in Bakken production had nothing to do with reservoir deliverability. Shrinking corporate cash flow and reduced access to financing constrained drilling after the September 2008 global financial crash. So output fell as new wells failed to keep up with natural declines, said Dancsok.

The Saskatchewan government official believes Bakken light oil would still be economic even if world oil prices fell below $40 (US) a bbl. Dancsok said thermal oilsands projects -- which use capital-intensive surface facilities and huge volumes of gas to produce bitumen, which has to be upgraded -- are considered economic at $60 (US) a bbl.

"So if that's economic at $60 a bbl, the Bakken is going to be much less -- probably at least half that," he suggested.

Bolstering Bakken economics is the Torquay light oil play. Located along the Saskatchewan-Manitoba border, the tight Torquay formation is in direct communication with the Bakken. Some companies produce from both formations.

Multi-frac horizontals are also tapping into light oil in the Lower Shaunavon, which is completely separate from the Bakken. While both are tight oil formations, there are several differences.

The emerging Lower Shaunavon play is in southwestern Saskatchewan; the Bakken is in southeastern Saskatchewan. The Shaunavon contains medium-gravity crude; the Bakken has light oil.

The Lower Shaunavon is Jurassic-age crystalline limestone. Bakken production in Saskatchewan comes from the middle member of the Bakken formation, which is siltstone-to-sandstone dolomitic rock of Late Devonian to Early Mississippian age.

Lower Shaunavon production peaked in January at 9,000 bbls a day from about 135 wells before declining, presumably because drilling failed to keep pace with natural declines. That works out to about 67 bbls a day per well.

A testimonial to the strength of the Shaunavon play is Crescent Point Energy Corp.’s recent decision to buy privately held Wave Energy Ltd. for $665 million. Wave had the largest land position in the Lower Shaunavon with more than 150 net sections.

In 2006, Wave became the first to use Packers Plus's horizontal multi-frac technology in the Lower Shaunavon, and was also the first producer to successfully use it on a multiple-well commercial oil project in Saskatchewan, according to Packers Plus.

Up to that point, the technology had been used mostly on gas reservoirs. To date, Wave has drilled about 75 multi-frac horizontals in the Lower Shaunavon, said Don Rae, Wave's president. (Crescent Point's purchase of Wave is set to close later this month.)

Saskatchewan's other emerging play is sweet, light oil in the shallow Viking formation near the Alberta border. Vertical Viking wells have been producing light oil for many years. Current output is 9,500 bbls a day from 6,700 wells, or less than 1.5 bbls a day per well.

However, production from the Viking's 50 horizontal wells reached about 1,500 bbls a day in January -- or about 30 bbls a day per horizontal well.

"Still nothing to stand up and shout about, but at the same time encouraging results," said Dancsok. "These horizontal wells are being drilled in existing reservoirs that were thought to be depleted."

TriAxon's Saponja describes the Viking as the company's next emerging play.

With six multi-frac horizontals under its belt, TriAxon is claiming success in the undeveloped land outside the established Viking pool. The wells average 50 to 70 bbls a day in the first three months, then stabilize at about 30 bbls a day.

Saponja said a Viking horizontal costs $1.2 million to drill, complete and put on production, pump jack included. It also qualifies for Saskatchewan's 37,500-bbl royalty holiday.

The Bakken, Shaunavon and Viking plays are all in areas with established infrastructure, greatly improving the economics.

Multi-frac horizontals have invigorated Manitoba's tiny oil oilpatch where the technology is being deployed by big players as well as juniors.

EOG Resources, Inc. estimates it has 25 million bbls of net recoverable oil in the Triassic-age Amaranth (a.k.a. Spearfish) shaley-sand formation at the Waskada field.

EOG, which completed about 30 horizontal wells in the field, expects its net Waskada output to reach 9,500 bbls a day exiting 2012, up from 1,900 bbls a day earlier this year.

In 2007, horizontal wells accounted for only about 17% of Waskada oil production, said Keith Lowdon, director of the petroleum branch at Manitoba's Science, Technology, Energy and Mines Ministry.

Last year, the horizontals produced 31% of the field's oil output, and this year horizontal production is poised to top 50%, he said.

ARC Energy has also been targeting the Amaranth formation in Manitoba at its Goodlands field. ARC drilled three multi-frac horizontals into the Amaranth late last year, and recently drilled four more.

"We're seeing IP rates in the 100 to greater than 200 bbls per day," said ARC's Carey. He said four wells that have been on production for more than six months are still averaging about 65 bbls a day.

"The best well paid out in six months," helped by Manitoba's "very industry-friendly" royalty regime, said Carey.

The other major focus of activity in Manitoba is the Torquay formation (sometimes called the Bakken/Three Forks) at the Sinclair field of southwestern Manitoba.

Sinclair oil production from horizontals rocketed to 28% this year from only one per cent in 2007, said Lowdon.

He said 142 horizontal and 26 vertical wells are being drilled this year -- a dramatic reversal from 146 vertical and 77 horizontal wells a year ago. Even though the well count is down from a year ago, the total metres drilled is up because the horizontals are longer, said Lowdon.

Fairborne Energy has 27 horizontal wells in the light-oil Torquay formation at Sinclair.

Fairborne's Torquay wells average 60-65 bbls a day on their first month of production and stabilize at 25-35 bbls a day after a year onstream, said VanSickle.

But the most compelling feature of Torquay light oil is the economics -- Fairborne boasts an impressive 60% rate of return on those wells. Although the rock is very tight, the reservoir is quite a bit shallower than Fairborne's other multi-frac horizontal plays.

In the Nordegg in Alberta, Fairborne pumps eight fracs at 100 tonnes per frac. In the Torquay it pumps eight to 12 fracs, but only 10 tonnes per frac. "So it's an order of magnitude smaller fracs," said VanSickle.

The Torquay oil play is also much further advanced than Fairborne's multi-frac horizontal gas plays in the Wilrich and Nordegg formations in Alberta. While the company has enjoyed drilling success, both gas plays are still in the early stages. In the Torquay, development drilling is in full swing.

So what will be the limits of multi-frac horizontal technology? As producers expand its geographic and geological boundaries, Packers Plus continues to push the technical envelope.

In August, the company said it successfully ran a 20-stage Bakken frac for Petrobank. Announced less than two months ago, that milestone is already history.

Packers Plus is already doing up to 32-stage fracs for Bakken clients in the U.S., and even that astonishing record will soon bite the dust, said Themig. "We're very close to release of a second-generation HD system that potentially will give us over 60 fracs."

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