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Featured Articles
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Feb 2010
| Source: Oilweek Magazine
| | | The Fab Five
| | | Why the Horn River, Montney, Cardium, Lower Shaunavon and Bakken plays give producers reason for optimism
| | | by R.P. Stastny
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| The combination of horizontal drilling and multi-stage fracing is about as close as western Canada´s oilpatch gets to the Midas touch. What started in the U.S. shales has swept north into the B.C. shales and, along the way, unlocked southern Saskatchewan´s light oil resource plays, the Bakken and the Shaunavon.
Now it´s Alberta´s turn with the Cardium.
But not all that horizontal multi-stage technology touches turns to gold. Western plays are far from North America´s major population centres, so another component is vital to this alchemy. And that´s government commitment to levelling the playing field between Canadian and American resource plays.
The Saskatchewan government has always known this. The B.C. administration understands it. And now, finally, Alberta´s embattled Tories seem finally to have recognized the province´s energy wealth can´t be taken for granted, that strong commodity prices and insatiable global demand is as unpredictable as next week´s weather, and that it´s time once again to stand by its oil and gas industry rather than sit on a three-legged stool at its udder.
The result of this apparent epiphany is the emerging Cardium resource play.
David Carey, ARC Energy Trust´s senior vice-president of capital markets, puts it quite succinctly: "Royalty structure is huge in these resource plays."
So as oil settles in the US$70 range and gas prices creep slowly upward-if only, perhaps, in response to winter´s chill-and rig utilization improves, the locomotives pulling western Canada´s oilpatch into a brighter future are the Bakken, Lower Shaunavon, Montney, Horn River, and Cardium.
The Cardium
Western Canada´s "big kahuna"
The big kahuna of western Canada is the Pembina field, which has produced over 1.3 billion barrels of 37° to 39° API gravity oil and over 12 trillion cubic feet (tcf) of natural gas since it was discovered in 1953. And that´s only about 17 per cent of estimated original oil in place.
Putting new horizontal multi-stage technology to work in this play is rewarding producers with impressive initial production rates averaging 225 to 250 barrels of oil equivalent (boe) per day which then level off to about 100 boe per day.
Based on the enormous resource potential of the Cardium, consistently positive drilling results to date, and strong economics, a recent Wellington West Capital Markets report states, "We believe the Cardium trend has the potential to rival other light oil resource trends, including the Bakken and Lower Shaunavon trends in Saskatchewan."
While the developed Pembina field is dominated by a limited number of landholders-Penn West Energy Trust, Imperial Oil, ARC Energy, and Enerplus Resource Fund-a growing list of juniors and intermediates are chasing the underlying Cardium shoreline trend that runs out into extensive peripheral acreages owned by a wide range of players-ARC Energy, NAL Oil & Gas Trust, Nexstar Energy, and a host of others.
NAL in particular has been a successful first mover in the linear offshore barrier bar/sand bar facies trend running through the Garrington area, northwest of Crossfield, and into the Pine Creek area northwest of Drayton Valley.
"We did some vertical tests in the summer of 2008 and saw from core sample comparisons a lot of similarities between the Bakken and the Cardium," says NAL´s Clayton Paradis.
In a presentation to Peters & Co., NAL compares the prolific Viewfield area of the Bakken to the Garrington Cardium: porosity is about the same; the Cardium has better permeability; average formation thickness tips in favour of the Cardium; the Garrington Cardium is somewhat deeper than the Bakken.
NAL believes the ultimate recovery of its Garrington horizontals will be between 150,000 and 200,000 barrels per well, not unreasonable given that some vertical producers in the area have accumulated in excess of 200,000 barrels.
"They just got lucky and managed to find that conglomerate that sits on top and is highly prolific," NAL´s Paradis says. "The Cardium sandstone that sits beneath is the resource rock and the conglomerate is the pipeline. So through a 1,000 metre horizontal leg, you´re getting enough of the permeable stuff and the fracing is opening up the tight stuff around it, which is really unlocking the resource and getting the production you need."
ARC Energy is in the fortunate position of having land in the core Pembina field as well as along its edges. It reports initial success using horizontal wells in both areas, but Carey notes these are early days in the play´s development, and full resource play-type development is still challenged by the reservoir´s heterogeneity.
"The industry had a good understanding of how the Cardium responds when drilled vertically," Carey says. "But there are multiple ways to complete a well horizontally and we need to find what works best and where."
The Alberta government will also have a hand in Cardium´s destiny: temporary royalty holidays will expire in March 2011, and the current royalty structure isn´t a great fit for resource-play wells, which typically begin their life with a burst of production.
"A high-rate well is the exact type of well that the new royalty framework penalizes the most," Carey says. "So it´s critical that we end up with a royalty structure that makes sense, otherwise you´re better off drilling in Saskatchewan."
The Bakken
Western Canada´s original light oil resource play
What can be said about the Bakken that hasn´t already been said? That it´s now essentially bound up between two powerful consolidators, Crescent Point and PetroBakken. That there´s about four billion to five billion barrels of proved and probable reserves in the Bakken. That Crescent Point is working towards a future that includes waterflood, aimed at an optimistic 30 per cent recovery of original oil in place, while PetroBakken is targeting 20 to 25 per cent primary recovery, sensing waterflood in the Bakken may be problematic. Or maybe that the play got its start in the deeper Bakken in Montana and shortly after moved north to Saskatchewan.
Trent Yanko, president and chief executive officer of Legacy Oil + Gas, (the company name changed from Glamis Resources last November), coined the term "light oil resource play" and brought Bakken development to Canada when he was the president and chief executive officer of Mission Oil & Gas. In recognition of that, he was named Saskatchewan´s Oilman of the Year in 2007.
The fate of Mission Oil is typical of many juniors in the Bakken. After growing production to 5,500 barrels a day, it sold to Crescent Point in 2006. Mission Oil´s management team recapitalized Glamis Resources/Legacy and started over in the Bakken. (Of its 270 well locations, more than 60 per cent are in the Bakken.) Today, Bakken land is sewed up tighter than ever between a few players.
Asked about the prospect of venturing back into the U.S. Bakken, Yanko says, "You don´t get too many cross-border shoppers. The guys who are playing the U.S. Bakken are typically U.S.-based companies and the Canadian Bakken is predominantly produced by Canadian-based companies."
Besides that, the U.S. Bakken is just as hot with activity as the Saskatchewan Bakken. Both sides of the border have similar economics. The U.S. Bakken is more prolific, with higher production rates and bigger reserves, but it´s deeper.
"The capital costs in the U.S. Bakken are higher-$4 [million] to $6 million a well versus $1.5 [million] to $1.6 million a well in Canada," Yanko says. "Even though the reserve size and production rates aren´t as high in Canada as in the U.S. they don´t have to be because the capital intensity isn´t there."
On a rate-of-return basis, he adds, Saskatchewan is as good, if not better, than North Dakota because of the Saskatchewan royalty incentive. On horizontal wells drilled on Crown land, the first 37,000 barrels are subject to a low 2.5 per cent royalty.
"We also have some Bakken in the deeper part of the play and we get 101,000 barrels at only 2.5 per cent, so it goes a long ways to improving the economics of the play," Yanko says. "So overall, I think the Saskatchewan Bakken play has better economics [than the North Dakota Bakken]."
The Lower Shaunavon
Catching up to the Bakken
With almost the same oil in place as the Saskatchewan Bakken, the lower Shaunavon in the southwest corner of the province is the logical corollary of the Bakken. Yet the step-change fracing technology that unlocked tight oil in both plays was first applied in the lower Shaunavon.
"Trent [Yanko] started the Bakken at Mission probably four or five years before the lower Shaunavon began to take off," recalls Neil Roszell, president and chief executive officer of Wild Stream Exploration. "But the Packers Plus multi-stage fracing technology was first used in the lower Shaunavon by Don [Rae, president and chief executive officer of Wave Energy at the time] before being applied in the Bakken."
Enough history. The Shaunavon has caught up now. And going forward, Roszell suggests the main difference between the reservoirs-which ties into the Shaunavon´s lower primary production estimates-will be how well they take to waterflood.
"We haven´t seen it yet because it´s still early days, but I believe waterflood will likely work better in the lower Shaunavon than the pilots have been working in the Bakken," Roszell says.
As in the Bakken, land availability is now a significant challenge in the Shaunavon. Last year, there was a land rush in the play. That was also when Crescent Point swept through, buying Wave Energy and Wild River (Roszell´s predecessor company to Wild Stream).
After the purchase, Roszell dove back into the Shaunavon with a recapitalization of Eagle Rock Exploration in October 2009, followed by a land acquisition from Bonterra Oil and Gas. Wild Stream´s business strategy is to achieve 5,000 to 10,000 barrels a day production over the next three to five years and sell. To get to that size, though, it will have to look outside of the Shaunavon. (It recently bought Cardium rights in the Garrington area of west-central Alberta.)
Don Rae now heads Coral Hill Energy and isn´t even looking in the Shaunavon for land. Coral Hill, he says, is an opportunity-driven junior, looking for new plays and new ideas elsewhere in the Western Canadian Sedimentary Basin.
The Montney
One of the best gas plays in North America
EnCana´s presence in the Montney goes back to the late 1990s. Since then, it has build up a whopping 700,000 net acres, over 1,000 square miles in what is one of the best natural gas resource plays in North America.
"There is a tremendous amount of gas in place in a very thick section of the Montney, close to 1,000 bcf [billion cubic feet] per section," says EnCana´s Mike Graham, executive vice-president and president of the Canadian division. "We think there might be as much as 1,000 tcf of original gas in place just in the Montney. It´s a tremendous gas play."
Extensive vertical sampling and physical tech work over the years also means EnCana knows just where the sweet spots are: on the B.C. side around Dawson where it eventually went to 1,000-metre horizontal wells and relatively small fracs. Today, typical Montney horizontals are about 2,400 metres and have 14 stages with 100 to 200 ton fracs per stage.
That´s 4,000 tons of sand in one wellbore. To put that into perspective, a railcar holds a little over 100 tons of sand. And railcars are, in fact, the mode of transport used to get the sand into the area where it´s then trucked to site. (There are efforts to source the sand locally.)
At the same time, completion techniques continue to evolve specific to where the wells are drilled. There are variations in the reservoir: at times, EnCana goes with cased-hole completions, at other times open-hole; in certain places it uses the Packers Plus multi-stage system, in others, Halliburton´s swell packers are the technology of choice.
"We experiment a lot," Graham says. "Sometimes, we´ll use CobraMax and bridge off with sand. We drive the coil tubing in the hole and frac, then bridge off that, move back and use the coil tubing to actually cut the casing, if you will, perforating the casing, and then frac again, and keep moving back."
On account of this technical evolution, and despite costs of handling all that sand and water required to open the formations, the economics of Montney continue to improve. Of all its gas plays across North America-from the Barnett and the Haynesville shales, where it has huge positions, and the Marcellus-the Montney is one of the lowest cost plays in EnCana´s portfolio.
"In some areas of the Montney, on a go-forward basis, we´re down to about $3 [an mcf]," Graham says.
Numbers like these suggest to Graham a "misconception" about western Canadian natural gas. In western Canada, production has been dropping by 10 per cent per year, whereas in the Lower 48, it has been increasing at about the same rate.
"If you could put these on a level playing field and make sure that western Canada remains competitive, there´s no reason why Canadian gas production should be declining," he says.
By level playing field, he means a competitive royalty framework, a recurring theme in resource plays at a time of global economic upheaval.
"We´ve been doing a lot of work with the B.C. Crown and they´ve done a tremendous job to incent the Montney and the Horn River," Graham says. "We´re also working closely with Alberta on our competitiveness. We also think federal government regulators and even pipeline companies have a vested interest in ensuring Canadian production continues to grow…. If we can ensure that we can compete with the big U.S. plays, we´ve got a tremendous future in western Canada."
The Horn River
Canada´s Crown jewel of gas
The Horn River rivals even the most prolific U.S. shales in terms of gas in place and the latest initial production rates. Its remoteness, however, gives it a reputation of a big-company play. In recent years, numerous intermediate and smaller producers, from the likes of Petrobakken to Storm Exploration, have staked out significant acreage positions in the basin and are also scaling the learning curve in preparation for the day when this play becomes the Crown jewel of the Western Canadian Sedimentary Basin.
From the earliest days of shale gas development, EOG Resources has been a bright light in northeastern British Columbia. This past summer, its vigour has paid off in stunning initial production (IP) rates. Three of its wells tested IP rates of 23.4 million, 19.3 million, and 17.2 million cubic feet a day. The other four wells in the seven-well program flowed between 16 million and 18 million cubic feet a day.
EOG says it was also able to reduce its drilling days by 42 per cent and drive down costs by 35 per cent over 2008 levels. It now has cost targets that provide attractive rates of return, aided by the B.C. government, which has recently approved EOG´s application for royalty incentives on a significant portion of its acreage.
"[The royalty incentives are] a big step forward in making this play competitive with U.S. shale plays," EOG says in an email to Oilweek.
Another testament to EOG´s determination and its ability to think outside the box is a memorandum of understanding with Kitimat LNG to supply a significant volume of gas to the proposed liquefied natural gas export terminal.
Nexen also prides itself on being an early mover in the Horn River. It managed to secure a contiguous land block before land prices rose dramatically and now is developing what it believes to be the heart of the play.
"Just from our lands alone, assuming a 20 per cent recovery factor, we think we could get upwards of 6 tcf," Tim Chatten, Nexen´s investor relations analyst, says in an email. "At the end of 2008, our proved reserves were approximately one billion barrels [equivalent], so this play has the potential to double the size of our company."
And this, ultimately, is the clearest statement of how important the emerging Horn River shale gas play is-not only to Nexen but to Canada.
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