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Number two, with a bullet Rapid pace of Bakken development moves North Dakota up the oil production charts in the United States

Canadian service firms gaining foothold in North Dakota


By James Mahony

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Manitoba oilpatch driven by strong regulatory environment, new fracturing technology

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51 Central Alberta Is the Duvernay the

35 British Columbia

next Eagle Ford?

By Richard Macedo

China a potential market for B.C. LNG By Richard Macedo

41 Northwestern Alberta Multi-zone drilling strategy paying off for Celtic

55 Southern Alberta Cardium, Dunvegan plays help TriOil achieve record results

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57 Saskatchewan

Torquay’s Saskatchewan operating

45 Northeastern Alberta with tight oil projects

west Manitoba, and text new drilling and completion technologies to exploit the tight oil plays driving exploration. Tundra is also building out infrastructure to handle increased production. In August its subsidiary, Tundra Energy Marketing Limited, announced it was adding 410,000 barrels of oil storage to its terminal at Cromer to meet the growing needs of crude oil producers and shippers in Manitoba and southeastern Saskatchewan. With Tundra currently having 70,000 barrels of oil storage at Cromer, this initiative represents roughly a sixfold increase in its capacity. Site preparation began in the summer. Construction of the two tanks, each 205,000 barrels in size, will continue for approximately 15 months and they should be operational in the fourth quarter of 2013. “This project is a major investment for us and we are pleased to have received regulatory and board approval to proceed,” says Bryan Lankester, president of Tundra Energy Marketing. “The added tankage will be a very welcome addition to our business and that of our customers. It will provide us with enormous flexibility during times of volatile oil price behaviour. It will allow us to manage in a variety of supply-demand environments.” Tundra has some high-quality competitors in the Spearfish tight oil play driving growth in the province, including Legacy Oil + Gas Inc., Penn West Exploration Ltd., and EOG Resources Inc. Legacy has over 27,000 net unexplored acres in the Spearfish play at Pierson. Production from 22 Legacy-drilled wells to the end of the second quarter of 2012 had a restricted 30-day average of 96 barrels of oil per day per well. Legacy has achieved these rates while constraining production to maximize ultimate recovery, leading to superior long-term performance, higher per well reserve bookings, plus additional locations booked. Legacy has identified 210 net locations on its lands at Pierson, approximately 77 per cent unbooked in the most recent independent reserves report. Its success in Manitoba has allowed it to expand its Spearfish play in to North Dakota. Production to the end of the second quarter of 2012 from eight Legacy-drilled wells had a 30-day average of 86 barrels oil per day per well. Legacy has achieved these rates while constraining production to maximize ultimate recovery, leading to superior long-term performance, higher per well reserve bookings, plus additional locations booked. Legacy has identified 230 net locations on the northern portion only of its lands in Bottineau County, approximately 97 per cent unbooked in the most recent independent reserves report. This location count could grow significantly as Legacy de-risks

By Darrell Stonehouse

426015 Brews Supply full G E page N E R A ·LfpN E W S editorial By Darrell Stonehouse


Small is beautiful

anitoba hasn’t been blessed with the resource endowment of neighbouring Saskatchewan. But a strong regulatory environment and forwardthinking operators are making the best of what oil resource the province does have. Just how good is the Manitoba regulatory environment? The Fraser Institute ranked the province the best jurisdiction in Canada for oil and gas investment and the fifth best jurisdiction in the world in its 2012 survey. Results of the annual survey are based on the opinions of 623 petroleum executives and managers at 529 companies. The Fraser Institute said the exploration and development budgets of participating companies account for half of annual spending on petroleum exploration and production among international oil companies. The survey questionnaire sought the opinions of senior personnel on matters such as royalties, taxes, the cost of regulatory compliance, trade and labour regulations, legal system fairness and transparency, and political stability. The success of the province in attracting investment can be seen in the number of wells being drilled in the province, and in the number of companies attracted to the growing oil plays in the southwestern corner of the province. Drilling in the province has been on a steady rise. In 2010, 512 wells were drilled, with the number climbing to 578 last year. This year, over 600 are expected. In July, Manitoba was the only province to see in increase in year-over-year permitting for the month. The province granted 62 well authorizations last month, up one from August 2011. Over the first eight months of the year, Manitoba has licensed 459 new wells, up 16.5 per cent from 394 in the comparable period last year. Dollars are flowing into the province as well. In 2010, $894 million was invested exploring for oil in Manitoba. Last year, that number climbed to over $1 billion. As of December 2011, Manitoba was producing around 46,000 barrels of oil per day. Winnipeg-based private producer Tundra Oil & Gas Ltd. is the largest operator in the province, operating around 1,800 wells and producing around 40 per cent of the daily oil supply. In 2011, Tundra drilled 189 wells in the Manitoba and expects to drill 220 wells this year. Speaking at Mining Week in Manitoba last spring, Tundra president and chief executive officer Dan MacLean said the company has been on a steady growth curve since 2005. He added the company is continuing in, “growth mode,” and continues to buy land in south-

costs rise

59 Central Canada Ontario government takes

By Elsie Ross

shine to oilsands By James Mahony



The impending knowledge deficit. When workers retire, they take their skills and know-how along with them.

By Bryan Leach


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Bullet North Dakota moveS UP the U.S. oiL ProDUctioN chartS, DriveN by bakkeN PLay

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Editor’s Note

Is there really a labour shortage?



Joseph Caouette, Bryan Leach, Richard Macedo, James Mahony, Pat Roche, Elsie Ross EDITORIAL ASSISTANCE MANAGER


Darrell Stonehouse |



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Hand-wringing over shortages of skilled workers has been a preoccupation of the oil and gas industry since the second wave of oilsands development began in the late 1990s. Every year a new study comes out predicting huge shortfalls in various trades. Yet every year the work gets done and new supply comes on stream. The most recent cause for worry was an Alberta government report this summer claiming a shortage of 114,000 workers by 2021, or less than 10 years ahead. The endless doom stories about labour shortfalls have created a crisis mentality in the industry, while the government opens up the gate to foreign workers in an effort to quell the concern. Labour organizations, however, are questioning whether a worker shortage even exists. And a new study from the Certified General Accountants Association of Canada (CGA-Canada) also questions whether the tight labour market is as bad as industry and government have claimed. The Alberta Federation of Labour says the provincial government’s claim of a 114,000worker shortfall by 2021 is nonsense. To back this claim up, it points out that in every year of the provincial projection there is an excess supply of labour when balanced against demand. CGA-Canada released a report in July called Shortages in Skilled Trades—The Best Guestimate?, which explores skilled-labour shortages in five provinces, including Alberta and Saskatchewan. The report found that while shortages exist, they are sporadic and short-lived. The belief that the skilled-labour workforce is aging also doesn’t give a realistic picture, say the accountants. The report also found that 64 per cent of skilled trades have relatively young age structures, comprising of more workers in the early stages of their careers than those nearing retirement. “Each province and occupation ages at a different pace,” says Rock Lefebvre, vice-president of research and standards, and co-author of the report. “This indicates that the impact of the retiring baby boomer population on shortages of skilled-trade workers may be marginal in specific trades.” In 2011, young workers exceeded the number of those close to retirement in many skilled trades, including plumbers, pipefitters and gas fitters; electrical trades; carpenters and cabinetmakers, other construction trades; and other installers and repairers experienced a higher ratio of young workers to those retiring. However, data on machinists and related occupations, heavy equipment operators, and machinery and transportation equipment mechanics reflect the opposite. “Short-term labour shortages of this nature are best dealt with through short-term solutions that can generate positive outcomes for Canadian employees and businesses,” adds Lefebvre. Brief labour shortages may have certain benefits, the report notes. For example, tighter labour markets may encourage professional development and growth opportunities for employees, and better align wages with growth in productivity. Businesses may likewise optimize their organizational and operational structure, invest in machinery and equipment, and improve overall efficiency, the accountants said.

Subscription Inquiries Telephone: 1.8.543.7888 Email: Online: junewarren– GST Registration Number 8225554RT. Printed in Canada by PrintWest. ISSN 1204-4741 | © 2012 JuneWarren-Nickle's Energy Group. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number 4009240. Postage Paid in Edmonton, Alberta, Canada. If undeliverable, return to: Circulation Department, 80 Valleybrook Dr, North York, ON M3B 2S9 Made in Canada The opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.



December 2012 Outlook for 2013: Commodity prices and where the action will be next year. PLUS A look at the progess to connect growing oil supply to export markets.

Want to sound off on any content in Oil & Gas Inquirer? Send your emails to Please mark them as “Letter to the Editor” if you want them published.




Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin OIL



Sep 2011 Oct 2011 Nov 2011

1,448 1,153 1,170

445 321 331

0 1 1

Dec 2011 Jan 2012 Feb 2012

988 419 84

55 127 37

1 1 2

Mar 2012 Apr 2012 Jun 2012

95 3 12

 1 2

Jul 2012 Aug 2012 Sep 2012



Sep 2011 Oct 2011 Nov 2011

1,028 2 557

357 259 241

14 19 3

1,1 0 

Dec 2011 Jan 2012 Feb 2012

58 215 491

300 131 177

72 35 50

Mar 2012 Apr 2012 Jun 2012

515 403 205

147 141 12

Jul 2012 Aug 2012 Sep 2012

348 380 447

4 98 5





24 20 27

155 49 42

2,072 1,543 1,570

359 190 244

27 15 21

115 31 52

1,489 655 1,153

99 08 37

180 192 25

33 31 40

 157 8

1,275 988 449

0 82 813

92 148 75

1 9 9

105 7 11

873 986 908

Wells Drilled in British Columbia

Saskatchewan Completions

Source: B.C. Oil and Gas Commission

Source: Daily Oil Bulletin



C U M U L AT I V E *






Sep 2011 Oct 2011 Nov 2011

92 35 92

611 646 738

Sep 2011 Oct 2011 Nov 2011

352 457 524

4 29 4

29 4 32

 2 0

Dec 2011 Jan 2012 Feb 2012

58 53 66

796 53 119

Dec 2011 Jan 2012 Feb 2012

332 142 29

4 10 

1 8 20

 10 22

Mar 2012 Apr 2012 Jun 2012

39 86 13

158 244 334

Mar 2012 Apr 2012 Jun 2012

414 172 144

0 0 0

40 49 10

 221 1

Jul 2012 Aug 2012 Sep 2012

57 53 11

401 454 465

Jul 2012 Aug 2012 Sep 2012

232 29 302

0 4 1

1 9 7

2 0 10

*From year to-date * from year to date







barrels per day

Current North Dakota oil production.


barrels per day

North Dakota production from Bakken/Three Forks formations.

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada, October 11, 2012 Source: Rig Locator

Alberta, October 11, 2012 Source: Daily Oil Bulletin




(Per cent of total)

Western Canada Alberta




Aug 12


Aug 12

Aug 11





Northwestern Alberta





British Columbia





Northeastern Alberta









Central Alberta










Southern Alberta















Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada, October 11, 2012 Source: Rig Locator

Alberta, October 11, 2012 Source: Daily Oil Bulletin




(Per cent of total)

Western Canada Alberta




Aug 12

Aug 11


Aug 11





Northwestern Alberta





British Columbia





Northeastern Alberta










Central Alberta










Southern Alberta























With a



ust how quickly is oil production climbing in North Dakota? full development mode, we expect to generate further efficiencies In the first six months of the year, production growth that will continue to improve the value of this asset,” he said. averaged 21,600 barrels per day per month, adding almost Continental president and chief operating officer Rick Bott 130,000 barrels per day over the time period. said the entire industry is wrestling with cost escalation in its In the last year production has doubled, reaching 675,000 bardrilling and completion operations. This is leading producers to rels per day. Driving that growth is the Bakken, Sanish and Three focus on their own operations while delaying or choosing not to Forks tight oil plays, now producing 610,000 barrels per day. As participate in wells operated by other companies. This has crea result, North Dakota has passed Alaska and is now the secondated opportunities for Continental to consolidate ownership in largest oil producing state in the United States, trailing only Texas. the Bakken. The breakneck pace of development in North Dakota, however, is “We have chosen a contrarian long-term approach and, now slowing as producers look to become more efficient at exploiting instead, have taken up these available interests in both our operthe massive tight oil resource and consolidate holdings in the play. ated wells and those operated by others,” he explained. “This has In July, production climbed only 9,500 barrels per day from resulted in a 28 per cent higher working interest on average in our wells drilled during the first half of the year. We also increased the previous month as the number of rigs drilling in the state dropped to 194 from a high of 214 in May. working interest through trades, farm-ins, ongoing leasing and Continental Resources Inc. is the largest leaseholder in the Bakken and Three Forks tight oil plays, with almost 950,000 “As more pipeline capacity out of the Bakken increases, we expect prospective acres. At Continental’s seconddifferentials to come down.” quarter report to shareholders, chief ­— Continental president and chief operating officer Rick Bott executive officer Harold Hamm said the company is currently focused on improving efficiency in its drilling and completion operations through faster drilling operations and increased pad strategic acquisitions. We have seen this as an opportunity to take drilling, while proving up its huge land position. higher interest in wells we really like.” “In the Bakken, we improved drilling cycle times by approxiBott said cost increases in both operated and non-operated wells are mately 30 per cent,” said Hamm. “In essence, we are accomplishclimbing, and the company remains focused on managing those costs. ing more with less.” “Non-operated wells are running $2 million higher than our Over the next year Continental expects to de-risk and estaboperated wells, which are currently averaging $9.2 million in the lish the productivity of each unit it controls in the North Dakota North Dakota Bakken,” he explained. Bakken. From there, Hamm says, it will move to pad drilling to “Continental continues to work with service providers to bring develop its land base. down operating costs in order to maintain this low-cost leadership “We’ve already made significant progress and are rapidly transthrough operational efficiencies, addressing supply chain issues forming from single well to ECO-Pad drilling, with nearly half of and reducing the strain on infrastructure in the areas in which our Bakken rigs currently drilling on ECO-Pads. Pad drilling is we operate. And where—when we’ve needed to—we’ve also laid yielding up to 10 per cent cost savings per well. As we move into down some iron.” OIL & GAS INQUIRER • NOVEMBER 2012



Despite cost pressures, Bott said Continental continues exploring the geographic limits of the Bakken play. “Since January 2012, our stepout and exploration drilling program has de-risked approximately 50,000 additional net acres, including areas east and west of Nesson anticline, north of Elm Coulee and south along the southern extent of the play. We’ve also established commercial production using the — William Thomas, newest technologies in areas that EOG president were previously considered marginal,” he explained. “A key focus of our investment will be testing approximately eight additional Bakken Three Forks wells in the lower benches of the formation, half of those being in the second and half in the third bench. We’ve proven the second bench to be commercial with the first two wells and now that we are past some of our permitting issues, we are preparing to spud these additional second bench tests and our first test in the third bench to extend the play vertically.” Continental also continues looking for ways to improve oil transportation out of North Dakota to reduce discounts it is currently facing. In the second quarter, Bakken crude suffered a $12.63 per barrel discount on West Texas Intermediate.

” We have plenty of room to run in the Bakken and Three Forks.”



“As more pipeline capacity out of the Bakken increases, we expect differentials to come down. The key takeaway, though, is what we’re doing to maximize the long-term value of Bakken crude,” he explained. “We continue to add opportunities to transport Bakken oil to coastal U.S. refi neries that yield the highest net price per barrel at the wellhead. Additionally, we are actively supporting expansion and construction of a new pipeline. These and other infrastructure improvements such as the reversal and expansion of the Seaway Pipeline, as well as increased rail capacity, will result in realizing the intrinsic value of the high-quality Bakken crude.” EOG Resources is focusing its efforts in developing its 90,000 acres at the core of the Bakken play, while exploring its undeveloped land base. It is now infi ll drilling, and results have been encouraging, says company president William Thomas. “Our 320-acre infi ll drilling in the Bakken Core continues to generate positive results,” he said. “The reason we’re so excited about EOG’s core area down-spacing is that our 90,000-net-acre core is the sweetest spot in the entire Bakken, and it’s where 22 of the 30 best Bakken wells in the entire play have been drilled. So this is a rich hunting ground for down-spacing. With our Bakken acreage now held by production, we are shifting our focus to increasing the recovery factor with down-spacing and improved frac technology.” EOG is also enjoying success with its Bakken exploration program, reporting strong production from wells in its Antelope Extension area 25 miles southwest of its core area and across the border in Montana. In the Antelope Extension, recent wells have


Alberta Bakken still a riddle for producers Two years ago the Alberta Bakken in Montana looked set to become the next great tight oil play in North America. Explorers, however, continue struggling to economically exploit the play and some are cancelling programs to focus on already profitable opportunities. This summer Rosetta Resources Inc., which has options to develop 300,000 acres in the play, announced in its second-quarter report that it is suspending all exploration drilling on the play to focus on its more lucrative Eagle Ford shale play assets.

Rosetta senior vice-president of asset development John Clayton said the decision to suspend operations in the Alberta Bakken came after drilling seven horizontal wells. “Of the seven horizontal wells drilled, five have been completed,” he explained. “Of those five completions, the initial three were completed in late 2011 as open-hole completions with swell packers and sliding sleeves. As a reminder, these three wells averaged initial rates ranging from 104 barrels of oil per day equivalent to 403 barrels per day. The most recent two completions were cased-hole completions with

tested around 1,800 barrels per day. In Montana, where EOG has around 200 potential drilling locations, an exploration well came in at 1,260 barrels per day. “As you can see, we have plenty of room to run in the Bakken and Three Forks,” he said. “Additionally, we continue our Bakken Core waterflood pilot project, and we expect to have preliminary results by year-end.” While early entrants into the North Dakota tight oil plays focus on development drilling in core areas while exploring undeveloped

perf-and-plug techniques. Those wells averaged 50–205 barrels of equivalent per day. We were targeting 30-day initial production rates of 250 barrels per day and an expected ultimate recovery of 185,000 barrels. Based on the results to date, which are below the targeted type-curve, we have decided to suspend all capital activity on this project. At this point in time, we have no plans to complete the remaining two horizontal wells. Currently, Rosetta Southern Alberta Basin position has leases and lease options, which will begin to expire no earlier than January 2014.”

lands, other operators are focused on consolidating their land positions through corporate acquisitions. Exxon Mobil Corp. solidified its hold in the Bakken in September after buying Denbury Resources Inc.’s acreage in North Dakota and Montana for $1.6 billion. Exxon said the properties being bought consist of about 196,000 net acres, with expected production of more than 15,000 barrels of oil equivalent per day by year-end. The acquisition will increase Exxon’s holdings in the Bakken region to nearly 600,000 acres.

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While booming oil production coming out of North Dakota drives all the headlines, behind the scenes there is an emerging story about natural gas production taking shape. And that growing gas production could have a major effect on Canadian producers, according to a report by Bentek Energy. The report, entitled The Williston Basin: Greasing the Gears for Growth in North Dakota, says North Dakota’s gas production has grown from around 150 million cubic feet per day to 536 million cubic feet per day in the last decade. It predicts it could grow to 3.1 billion cubic feet per day by 2025. Bentek says the only thing holding back Bakken gas production is a lack of gas gathering and processing facilities. Once put in place, there is some spare take-away capacity to market the gas in the U.S. Midwest. And, given the proximity of the Bakken to markets, it could also replace Canadian gas exports. Given that the gas is a by-product of oil drilling, Bentek says the Bakken has great advantages over competing gas basins. It estimates the typical Bakken well is earning an internal rate of return of 58 per cent, based on gas prices of $2.45–$2.86 per million British thermal units and West Texas Intermediate prices of $84–$100 per barrel. Canadian gas exports to the United States have declined by 40 per cent since the market crash in 2008. Bentek expects this trend to continue, falling from 5.7 billion cubic feet per day last year to 3.2 billion cubic feet in 2017. Bentek says the decline in Canadian exports will create pipeline capacity for Bakken gas.

QEP Resources Inc. is also building a Bakken land base. Earlier this year it spent $1.38 billion acquiring acreage from a number of operators to grow its North Dakota operations. The transaction will raise QEP’s net acreage in the Williston Basin to about 118,000 acres. “We expect the growth potential of these assets to have a significant impact on our overall production and, more specifically, on our crude oil production,” QEP president and chief executive officer Chuck Stanley said. The properties, located in Williams and McKenzie counties, have an aggregate net proved-plus-probable reserves of about 125 million barrrels of oil equivalent.

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Canadian service firms gaining foothold in North Dakota By James Mahony

Photo: Joey Podlubny


s natural gas drilling continues to slide in the United States, producers are still exiting dry gas plays for greener pastures, mainly crude oil and natural gas liquids plays that hold out the promise of profitability and longerterm activity. Many of the producers that abandoned gas made oil their new focus, putting down stakes in basins like the Permian and Williston, which covers much of North Dakota. As U.S. producers, and then U.S. service companies, rushed to join North Dakota’s Bakken play, anxious for a share of the action, Canadian oilfield service firms were close behind, and many now have a presence there. Most also quickly realized they were not the first to the table. Take Trican Well Service Ltd., for example. In a second-quarter conference call, its executives said fierce competition among pumping companies had taken a toll on rates for equipment in North Dakota. Indeed, if the rate situation gets much worse, Trican chief executive Dale Dusterhoft told shareholders the company would consider racking equipment—albeit as a last resort—rather than renting it out at fire-sale prices.




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While no other Canadian service company announced similar plans, North Dakota is clearly heating up. According to one industry analyst, the U.S. landscape for pumping companies has been crowded in the past 18 months and is now oversupplied. Several contractors have added capacity in recent months, at a time when gas prices have hovered near 10-year lows. “As often happens when there’s a downturn in the fracturing sector, companies are aggressively adding capacity as quickly as they can,” Brian Purdy, oilfield services analyst for Global Hunter Securities LLC says. “It’s been a big growth area, but when you get a slight downturn, you end up with this oversupply.” While the United States as a whole is oversupplied, Purdy feels demand in particular areas, especially oilier basins, is brisk enough to absorb most of the pumping capacity being added. In particular, he believes the Bakken and Texas’ Permian Basin can still add pumping capacity without fear of oversupply—at least for now. “Not only has there been consistent activity, but it’s been growing. Maybe it’s just starting to plateau a bit now, but there’s been room to put new fracturing equipment in there,” he said. At the same time, he noted, the rates pumping companies are getting for their equipment have started to fall off, squeezing profit margins. “The oversupply is beginning to affect the oil-oriented basins as well,” he said. Despite the stiff competition, not all players are equally concerned. At Calfrac Well Services Ltd., which has been active in North Dakota for two years, Doug Ramsay, chief executive officer, said he expects competition, but not a huge influx of pumping companies. “Everybody’s talking about going there, but we don’t see evidence of every frac company in the U.S. putting down a base in North Dakota,” he said. “Not yet.”

Photo: Gerald Ford

Canadian drilling companies continue growing operations in North Dakota.


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Pressure pumpers are all focused on the Bakken as shale gas plays in the U.S. slow down.

In part, Ramsay attributes that forbearance to barriers to market entry, citing the state’s extremes of weather—both hot and cold— which are hard on equipment not built for the climate. Other barriers include a sparse population that hasn’t kept up with industry demand for workers, as well as the challenges of securing customers. “We’ll go through a bit of a price erosion, and we’ll shake out contractors that aren’t focused on quality or don’t have the technology,” he said. When it comes to pumping trucks, Ramsay acknowledged North Dakota might be showing a “little bit of a balance” on the excess side, but “not a large excess.” As for what effect that might have on the rates pumping companies charge, he said it would mainly be short-term, affecting “call-out” work and spot-market rates, rather than longer-term rates, which are set by contract. Estimating 60–70 per cent of Calfrac’s work in North Dakota is under long-term contract, Ramsay believes the company’s business is, for that reason, better insulated against the corrosive effects of a crowded market than some of its competitors, although he mentioned no names. Much of Calfrac’s work may be under contract, but not all pumping companies live by the same rule. Indeed, Global Hunter’s Purdy said a lot of the fracturing equipment built in the past year was built “on spec”—without contracts—a practice that can get companies into trouble if a downturn materializes. In effect, those building on spec are betting the market will still need their equipment when it arrives, he said. “What happens when the market gets busy—everybody orders at the same time—and it takes more than a year for the equipment to arrive?” he asked. “You’ve got to have a good crystal ball to be

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“We really expect sustained drilling activity down there for a very long time.” — Dan Themig, Packers Plus president

sure the equipment will go to work when it arrives. We’re running into a situation now where some…equipment is going to end up on the sidelines until the market recovers.” For Precision Drilling Corporation, North Dakota is no flash in the pan, according to company spokesman John Higgins, who said the currently brisk pace of business in the state has led Precision to move both drilling and service rigs there in recent months, often from U.S. gas plays, while the company has also sent rigs there from western Canada. Currently, Precision has 21 drilling and 10 service rigs in the state, and Higgins is not concerned that the current influx of equipment—from Precision and other contractors—will cause a glut any time soon, because activity on U.S. oil plays has on the whole been steady, and if anything, seems to be expanding. At the same time, he would not rule out a possible oversupply of drilling rigs on North Dakota’s spot market, while emphasizing Precision does not move rigs to market without first finding customers. Without a contract, “we’re not going,” he said. On the service rig and rentals side, “we’re out of equipment,” he said. “It’s certainly busy.” Canadian drilling contractor Savanna Energy Services Corp. operates one drilling and several service rigs in the North Dakota

Bakken. In a second-quarter conference call, Ken Mullen, president and chief executive officer, noted that Savanna’s fleet expanded during the quarter. “In the U.S., our North Dakota well-servicing business grew by another rig, bringing the fleet to 12 rigs, and the adverse weather that affected much of western Canada did not materialize there. As a result, this business unit has generated very strong results and we anticipate transferring another workover rig to this base in the second half of 2012.” Beyond the drilling sector, companies such as Packers Plus Energy Services Inc. are finding the Bakken a lucrative place to be. Indeed, Packers president Dan Themig called it “probably the busiest remote [U.S.] basin.” Unfortunately, the state’s lack of workers has been a tough nut to crack. “It’s been a tremendous challenge,” he said. “I won’t say [the stress on the Williston Basin has] been alleviated, but things are much better this year than a year ago. There are massive [work] camps set up north of Williston. There’s still a strain, but it’s better now. A year from now, I think it will be even better. We really expect sustained drilling activity down there for a very long time,” he said.

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Small is beautiful Manitoba oilpatch driven by strong regulatory environment, new fracturing technology By Darrell Stonehouse


anitoba hasn’t been blessed with the resource endowment of neighbouring Saskatchewan. But a strong regulatory environment and forwardthinking operators are making the best of what oil resource the province does have. Just how good is the Manitoba regulatory environment? The Fraser Institute ranked the province the best jurisdiction in Canada for oil and gas investment and the fifth best jurisdiction in the world in its 2012 survey. Results of the annual survey are based on the opinions of 623 petroleum executives and managers at 529 companies. The Fraser Institute said the exploration and development budgets of participating companies account for half of annual spending on petroleum exploration and production among international oil companies. The survey questionnaire sought the opinions of senior personnel on matters such as royalties, taxes, the cost of regulatory compliance, trade and labour regulations, legal system fairness and transparency, and political stability. The success of the province in attracting investment can be seen in the number of wells being drilled in the province and in the number of companies attracted to the growing oil plays in the southwestern corner of the province. Drilling in the province has been on a steady rise. In 2010, 512 wells were drilled, with the number climbing to 578 last year. This year, over 600 are expected. In July, Manitoba was the only province to see an increase in yearover-year permitting for the month. The province granted 62 well authorizations last month, up one from August 2011. Over the first eight months of the year, Manitoba has licensed 459 new wells, up 16.5 per cent from 394 in the comparable period last year. Dollars are flowing into the province as well. In 2010, $894 million was invested exploring for oil in Manitoba. Last year, that number climbed to over $1 billion. As of December 2011, Manitoba was producing around 46,000 barrels of oil per day. Winnipeg-based private producer Tundra Oil & Gas Ltd. is the largest operator in the province, operating around 1,800 wells and producing around 40 per cent of the daily oil supply. In 2011, Tundra drilled 189 wells in Manitoba and expects to drill 220 wells this year. Speaking at Mining Week in Manitoba last spring, Tundra president and chief executive officer Dan MacLean said the company has been on a steady growth curve since 2005. He added the company is continuing in “growth mode” and continues to buy

land in southwestern Manitoba, and test new drilling and completion technologies to exploit the tight oil plays driving exploration. Tundra is also building out infrastructure to handle increased production. In August its subsidiary, Tundra Energy Marketing Limited, announced it was adding 410,000 barrels of oil storage to its terminal at Cromer to meet the growing needs of crude oil producers and shippers in Manitoba and southeastern Saskatchewan. With Tundra currently having 70,000 barrels of oil storage at Cromer, this initiative represents roughly a sixfold increase in its capacity. Site preparation began in the summer. Construction of the two tanks, each 205,000 barrels in size, will continue for approximately 15 months and they should be operational in the fourth quarter of 2013. “This project is a major investment for us and we are pleased to have received regulatory and board approval to proceed,” says Bryan Lankester, president of Tundra Energy Marketing. “The added tankage will be a very welcome addition to our business and that of our customers. It will provide us with enormous flexibility during times of volatile oil price behaviour. It will allow us to manage in a variety of supply-demand environments.” Tundra has some high-quality competitors in the Spearfish tight oil play driving growth in the province, including Legacy Oil + Gas Inc., Penn West Exploration Ltd. and EOG Resources Inc. Legacy has over 27,000 net unexplored acres in the Spearfish play at Pierson. Production from 22 Legacy-drilled wells to the end of the second quarter of 2012 had a restricted 30-day average of 96 barrels of oil per day per well. Legacy has achieved these rates while constraining production to maximize ultimate recovery, leading to superior long-term performance, higher per-well reserve bookings, plus additional locations booked. Legacy has identified 210 net locations on its lands at Pierson, approximately 77 per cent unbooked in the most recent independent reserves report. Its success in Manitoba has allowed it to expand its Spearfish play in to North Dakota. Production to the end of the second quarter of 2012 from eight Legacy-drilled wells had a 30-day average of 86 barrels of oil per day per well. Legacy has achieved these rates while constraining production to maximize ultimate recovery, leading to superior long-term performance, higher per-well reserve bookings, plus additional locations booked. Legacy has identified 230 net locations on the northern portion only of its lands in Bottineau County, approximately 97 per cent unbooked in the most recent independent reserves report. This location count could grow significantly as Legacy de-risks OIL & GAS INQUIRER • NOVEMBER 2012



the opportunity on the southern portion of its lands over the coming years. The total Spearfish play development drilling inventory of 440 net potential locations (88 per cent unbooked) is based on eight wells per section. Based on other operators’ results in the play, Legacy’s location count could increase by 50 per cent through down-spacing. In addition, the company is evaluating the waterflood potential in the play and anticipates recovery factors of up to 14 per cent, based on analogous pools. Legacy likes the Spearfish play because it is relatively shallow (about 1,000 metres) with horizontal multistage frac wells costing about $1.5 million all-in. “It’s essentially a conventional reservoir that just didn’t produce very well from vertical wells, and that’s very typical of a lot of the resource plays that we are chasing in Canada,” Legacy president and chief executive officer Trent Yanko recently told a conference in Calgary. The company began drilling intensively in the area late in 2011 after the flooding in Manitoba had subsided. Activity has continued into this year, with forecast capital spending of about $75 million this year. “We like what we are seeing and have had very good success as we have continued to modify the drilling program and the frac program to achieve better than expected results,” said Yanko. Legacy Spearfish wells in Manitoba are achieving much higher initial rates than the expected type curve of an ultimate recovery rate 67,000 barrels of oil, he said. The company is constraining the production because it believes it will lead to better reserve recovery and lower the decline profile. “We have been able to keep production essentially

flat for these new wells and we should see an incremental reserve booking by the end of the year,” said Yanko. The Spearfish produces 36 degree API crude with field netbacks of about $70 per barrel, which means payouts of 12 months or under. “There’s huge running room, huge development drilling upside,” Yanko told the meeting. Drilling, infill drilling and waterfloods could increase potential Spearfish reserves to 150 million barrels to 200 million barrels, the meeting heard. Legacy is moving quickly to develop waterfloods, which Yanko said can add significant reserves, help attenuate declines and provide a steady source of free cash flow for other projects. At Frys/Antler in Manitoba, it is planning a large waterflood project later this year, which it believes will add 25 million barrels of light oil reserves. Penn West Exploration is well into development of its 75,000 acres in the Spearfish play in Manitoba. Penn West is investing over $200 million in 2012 to drill between 60 and 70 wells in the play. Current production from the Spearfish is around 8,500 barrels per day. Speaking at Penn West’s second-quarter 2012 conference call, executive vice-president and chief operating officer Hilary Foulkes said as the company has moved from exploring to developing the Spearfish, costs are declining in the play. The company is using pad drilling for fullscale development, with 24 wells being drilled per section. “We are realizing a reduction of approximately 15 per cent from our first-quarter costs. This equated to a savings of approximately $200,000 per well,” she explained. “We view the Spearfish as an example of the efficiencies that can be gained when full-scale development occurs.”

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General News

Wet spring lowers service company financials

Photo: Gerald Ford

An extended breakup period due to wet weather kept workers out of the fields in the second quarter.

For many Canadian service and supply companies, financial results for the second quarter were negatively impacted by an early spring breakup, an unusually wet spring and an extended breakup period. The 45 service and supply companies (including midstreamers) that were surveyed as part of the recent edition of sister publication Statistics Quarterly reported second-quarter net income of $276.36 million, almost double the $139.93 million in the three months ended June 30, 2011. Four of the five companies reporting the greatest year-over-year profit gains during the second quarter were midstream/ infrastructure companies. For the three-month period, the largest increases in profit, compared to the second quarter of 2011, were booked by Gibson Energy Inc. (up $139.76 million), Inter Pipeline Fund (up $43.36 million), Pembina Pipeline Corporation (up $32.37 million), Poseidon Concepts Corp. (up $24.84 million) and AltaGas Ltd. (up $12.49 million). Excluding results from midstreamers, the profit picture for companies in the second quarter was less rosy.

Due to the extended spring breakup, 20 companies reported year-over-year declines in second quarter net income, led by Trican Well Ser v ice Ltd. (off $80.94 million) and Calfrac Well Services Ltd. (off $23.93 million). During the first half of 2012, net income and cash flow rose 43 per cent and 19 per cent, respectively, from the comparable period of 2011. The surveyed companies reported net income of $1.36 billion for the six months ended June 30, 2012, up from $955.50 million in the year-prior period. Gibson had the largest year-over-year profit increase for the half. The company’s net income lifted to $49.56 million from a loss of $90.11 million in January-to-June 2011 (up $139.67 million). Other companies reporting large increases in first-half profits included Inter Pipeline (up $58.51 million), Poseidon (up $49.19 million), Precision Drilling Corporation (up $47.38 million) and Ensign Energy Services Inc. (up $28.44 million). Of the 45 companies, 11 posted yearover-year declines in first-half revenue, led

by Trican (down $73.98 million), Keyera Corp. (down $58.11 million), GASFRAC Energy Services Inc. (down $11.59 million), Veresen Inc. (down $8.80 million), and Xtreme Drilling and Coil Services (down $3.59 million). Six-month cash flow rose to $2.87 billion from $2.41 billion for the 45 companies surveyed for this edition of Statistics Quarterly. Poseidon narrowly recorded the largest year-over-year hike in cash flow (up $47.51 million to a total of $78.34 million), edging out Precision, which posted a $47.01-million increase (to a total of $310.11 million). During the half, revenues for the 45 companies climbed about 23 per cent to $16.65 billion from $13.52 billion in the comparable period a year ago. Five companies posted a greater than $200 million year-over-year increase in their six-month revenues: Pembina (up $439.13 million), Secure Energy Services Inc. (up $339.63 million), Ensign (up $304.89 million), Keyera (up $266.84 million) and Calfrac (up $203.02 million). Only two companies—Inter Pipeline (down $3.45 million) and AltaGas (down $59.10 million)—reported lower year-overyear revenue figures for the half. Poseidon reported the highest return on revenues (profits divided by revenue) for the half at 56.84 per cent, followed by Inter Pipeline (32.12 per cent), Pulse Seismic Inc. (27.77 per cent), High Arctic Energy Services Inc. (22.84 per cent) and Pason Systems Inc. (19.69 per cent). All but four of the surveyed companies reported a positive return on revenue. GASFRAC, Leader Energy Services Ltd., Calmena Energy Services Inc. and Xtreme all posted negative return on revenue. Capital spending for the six months ended June 30, 2012, rose to $4.79 billion from $2.87 billion in the first six months of 2011. — DAILY OIL BULLETIN OIL & GAS INQUIRER • NOVEMBER 2012


General News

Natural gas finding and development costs decline By Pat Roche Although average well costs have skyrocketed because of multi-frac horizontal wells, finding and development (F&D) costs for natural gas in western Canada have fallen dramatically for the same reason. The widespread adoption of long horizontal wells with multiple fracture stimulations per wellbore has enabled producers to book significantly more gas reserves per well. As a result the average F&D cost for gas in western Canada fell to less than $2 per thousand cubic feet last year—a drop of 45 per cent from 2006, according to Ziff Energy Group’s 26th annual F&D cost study. That’s despite the fact that the average cost of drilling and completing a well in western Canada roughly tripled in recent years, according to Peter Tertzakian, chief energy economist at ARC Financial Corp. “The big ramp-up in the transition period between 2004 and 2010—from $1.3 million to $3.6 million per well—was due to the quick migration into the capital-intense

world of unconventional plays like shale gas and light tight oil,” Tertzakian wrote in a recent commentary with his weekly energy charts. He emphasized this is the average well cost across western Canada, and that costs vary by region. In northeastern British Columbia, for example, the average well cost now exceeds $6 million. But these complex expensive wells are finding so much more gas than conventional wells that the F&D cost per thousand cubic feet has fallen sharply, said Bill Gwozd, Ziff Energy’s senior vicepresident. That is the good news. The bad news, of course, is that producing dry gas in western Canada remains uneconomic because of extremely low gas prices. Ziff Energy estimates last year’s fullcycle F&D cost for gas was $5.19 per thousand cubic feet—a whopping 50 per cent more than last year’s average gas price of $3.46.

In the past four years, the price Canadian producers got for their gas has been consistently lower than the full-cycle cost for new gas, Ziff Energy noted. On the oil side, producers have obviously enjoyed much better economics, but the F&D cost has shot up. The cost for oil last year was more than $25 a barrel— almost twice the level five years ago, said Paul Ziff, president of Ziff Energy. With West Texas Intermediate crude just under US$100 a barrel, producers can handle an oil F&D cost of more than $25 a barrel. “However, there still is the risk of a potential economic slowdown, which would bring oil prices lower. So F&D still does count on the oil side,” Ziff said. In 2009, 2010 and 2011, the industry added more than half of its gas reserves at an F&D cost of less than $2 per thousand cubic feet, Ziff said. “Obviously the other reserves have been added at a cost higher than $2. So it indicates there are some companies that are sustainable and

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others that are really destroying value,” he added. On the oil side, he said, slightly more than half the reserves were added at a cost of $20 a barrel, but almost half were added at a cost well above $20. “So both on the oil and the gas side, it really depends on how well a company is executing—whether they are going to be creating a sustainable future or not,” Ziff said. But with an AECO gas price of about $2 a gigajoule, the Ziff Energy president said any producer that is weighted heavily toward

dry gas is “under tremendous financial pressure—especially if they have any debt.” So is what’s currently happening in the Canadian oilpatch more than just another cyclical downturn? Most defi nitely, says Tertzakian. Until about a decade ago, you could start a successful oil and gas company in Calgary with $10 million or $20 million. Now initial capitalizations are in the $100 million to $200 million range to fund enough multi-frac horizontal wells to mitigate the risk of failure, the ARC Financial economist said.

What that means, he believes, is the tiniest companies—as a group—are likely to disappear. “If they can’t raise capital, it’s just very difficult for them to be able to afford to drill enough wells to prove up the plays to be able to then sell to bigger companies,” Tertzakian said. So how small is a producer that’s too small to survive? “Where the cut-off is I think has yet to be defined,” he said, adding: “It’s a capitalization cut-off. It’s not a production cut-off.” He believes the initial capital requirement is now at least $100 million.

New diluent sources needed for oilsands By Elsie Ross Oilsands producers may need to look offshore for new supplies of pentanes-plus and condensate to meet the growing demand for diluent required by surging production in non-upgraded bitumen. By 2035, oilsands developments may need up to 1.2 million barrels per day of

pentanes/pentanes-plus and operators will be looking for sources of condensate from as far away as Asia-Pacific and Sout h A mer ica, says t he Canadian Energy Research Institute (CERI) in a new overview and outlook for North American natural gas liquids to 2035.

However, that requirement will be totally dependant on the timely construction of the export pipelines including Enbridge Inc.’s Northern Gateway, emphasized Peter Howard, CERI president and chief executive officer. “No pipes, no need for large quantities of diluent.”

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O f f shor e d i lue nt cou ld pr ov ide another source of supply in addition to t he a nt ic ipated st rong volu me s available from the growth in liquidsrich shale plays in the United States, according to Greg St r ingham, v icepresident of oilsands and markets for the Canadian Association of Petroleum Producers. T he proposed Nor thern Gateway pipeline that would transport 193,000 barrels per day of impor ted diluent f r om K it i m at , B .C ., t o E d m ont on “would be a huge advantage,” he said. “Depending on the timing of Gateway, we could accelerate the diluent line or do them both [diluent and crude] at the same time.” O i l s a n d s o p e r at o r s h a v e b e e n importing diluent since about 2004 as the required volumes of pentanes-plus and condensate have significantly outpaced domest ic product ion capacit y, says the CERI study. In 2010, an estimated 260,000 barrels per day of diluent was required while total Canadian domestic production was about 160,000 barrels per day, indicating that close to 40 per cent (100,000 barrels per day) of the required diluent needed to be imported, says the study. “This trend is bound to continue as increasingly produced oilsands volumes are expected to be more of crude bitumen than synthetic crude oil,” it says. Canadian pentanes-plus production averaged 153,0 0 0 ba r rel s per day bet ween 2000 and 2010, showing a relatively flat but declining trend, driven by declines in production at the natural gas–field plant level, says the CERI study. While there have been increases in field condensate volumes, straddle plant volumes of pentanes-plus, and more importantly fractionator production levels, they have failed to offset the declines from the field plants, which are by far the main source of pentanes-plus, says the study. T he va r ious pipeline systems designed to carry diluent to oilsands operations will account for a fraction of the required volumes, according to the study. Enbridge’s existing Southern Lights diluent pipeline from Chicago, Ill., to Edmonton has a capacity of 180,000 barrels per day (expandable to 300,000 barrels per day), but currently has takeor-pay contracts for 77,000 barrels per day. The company recently held an open

General News

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The proposed Northern Gateway would add 193,000 barrels per day of needed diluent.

season for 85,000 barrels per day, but has not yet released the results. Kinder Morgan Cochin ULC also is proposing to reverse the western leg of the Cochin pipeline, transporting up to 95,000 barrels per day from Windsor, Ont., to Edmonton by 2014. “ P r ov ide d t h at t he s e i mp or te d supplies can be acquired at reasonable prices, oilsands producers will continue to acquire diluent supplies from external markets and develop t he necessar y infrastructure for their transportation,” says the CER I study. “A lternatively, given the proper market conditions, f u r t her development of upg radi ng capacity in Alberta would reduce the need for diluent.” Without pipeline access to conde n sate, some A t h aba sc a a r ea producers have been using synthetic crude oil for blending with bitumen. Some refineries prefer a blend as they cannot handle pure SCO (synthetic crude oil), while others can process pure SCO only in limited quantities, said Howard. “Really it’s a function of what your market is, and if it’s summer and you are looking for asphalt, you are not going to get it out of that [because SCO is lighter on the bottoms of the barrel].” SCO also is blended with other heavy crude blends in the product that is sold as Western Canada Select.

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British Columbia

China a potential market for B.C. LNG By Richard Macedo

Any potential replacement of the use of coal, especially by LNG, is being pursued by the Chinese, he added. There are a growing number of LNG export proposals in North America designed to take advantage of the pricing arbitrage between here and Asia. Proposed projects are being planned for Prince Rupert and Kitimat on the B.C. north coast and in Oregon, as well as along the U.S. Gulf Coast. China, meanwhile, also has potential domestic shale gas resources, but Jiang said these are not likely to be developed in a significant way any time soon. “The Chinese don’t believe the hype,” he said. “The location is remote; infrastructure access is difficult.” Some of the technologies from North America can be moved over there and be used to unlock hydrocarbons, he noted. “People say they’re buying our technology to extract the resource. It’s not that

simple,” Jiang pointed out. “Geological conditions are different. Many of China’s shale reserves are deeper and the rock formations are more difficult than in North America.” Another difficulty is a lack of water in China. “There’s a very severe water shortage and many of this shale extraction would require large volumes of water,” Jiang said. “I’m more optimistic about our LNG ventures and to export them to China.” Efforts to develop LNG infrastructure continue to gain steam. In September the B.C. government and the Haisla Nation announced a framework agreement that could spur the development of another natural gas export facility in the northwestern part of the province. The framework agreement provides the structure for a land purchase or lease that will allow the Haisla to partner with industry to develop an LNG facility and marine export terminal on the west side of the Douglas Channel in the areas around Haisla Reserve #6. This agreement has the potential to fasttrack a major LNG facility in the Kitimat area. The agreement also signals a closer working relationship between the Haisla and British Columbia in and around the Kitimat and Douglas Channel area, the government said. It commits both parties to start work on land-use planning for areas around the Douglas Channel, which has tremendous potential as a marine port. “This certainty will allow other development projects in the area to proceed,” the province said. Currently, two LNG facilities and marine export terminals have received export licences from the National Energy Board—Kitimat LNG and B.C. LNG Douglas Channel. Other proponents are in various stages of assessing additional LNG facilities, including the recently announced LNG Canada proposed by Royal Dutch Shell plc and its partners.

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Photo: Joey Podlubny

China wants B.C. gas to replace coal in power plants.

China could be a key market for potential liquified natural gas (LNG) exports, as the Chinese look to move away from coal and use a greater amount of natural gas to lower CO2 emissions, a conference heard last month in Calgary. “Seventy per cent of China’s energy comes from coal,” Wenran Jiang, special advisor on China to the U.S.- and Canadabased Energy Council, told an Insight Info Northeast B.C. Natural Gas Summit. “But look at natural gas; it’s three per cent [of the energy mix], so it’s a very small portion.” China has experienced explosive economic growth, and with that, an urbanization process has occurred, which in turn has caused a surge in energy demand. “If you look at, currently, China’s electricity generation, most of it comes from the burning of coal, many of them dirty burning, low quality,” Jiang said. “The coal burning is primarily responsible for the CO2 emissions of China.” BRITISH COLUMBIA WELL ACTIVITY

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Source: Daily Oil Bulletin



British Columbia “This agreement allows the Haisla to look at the land on the west side of the Douglas Channel in a different light,” Ellis Ross, chief councillor of the Haisla Nation, said in a news release. “This gives the Haisla and associated projects the certainty needed for the LNG proposals and other

projects coming forward for our territory. If we are able to do this, the Haisla people will benefit, as will all British Columbians and Canadians.” In May 2012, British Columbia introduced Bill 43, the First Nations Commercial a nd I ndu s t r i a l D e v e lop m e nt A c t

Implementation Act, in part to facilitate the development of the Kitimat LNG terminal on the Haisla Reserve near Bish Cove. This legislation allows British Columbia to enter into agreements with Canada and First Nations to administer provincial laws on reserve lands for specific projects.

Artek updates Inga drilling results Artek Exploration Ltd. reports it has successfully drilled and completed its fourth of a seven-horizontal-well program (60 per cent working interest), planned for 2012, at 13-3387-23W6 at the south end of its Doig natural gas and condensate pool in the Inga area of British Columbia. Preliminary results after a 103-hour test that was conducted in-line indicate the horizontal well was still cleaning up and flowing at a restricted average rate of 6.7 million cubic feet per day of natural gas (26 per cent load C3) and 1,503 barrels per day of condensate or a total of 2,623 barrels of oil equivalent per day (2,335 barrels a day net of load) over the last six hours at a flowing pressure of 1,118 pounds per square inch.

The well was drilled to a lateral distance of approximately 1,500 metres and was completed with a 14-stage propane fracture program, and management said it is very encouraged by the results from this poolextending well. The tie-in of the sales line to a new deeper-cut processing plant from Artek’s operated facility at Inga has now been completed. In addition to providing the company with two plant options to reduce plant-related interruptions, the new deeper-cut facility is expected to result in the plant’s liquids recovery increasing by 15 barrels per million cubic feet to approximately 30–35 barrels, in addition to the free liquids recovered at the well.

Earlier in the year Artek reported that its second horizontal Inga well of 2012 had been dually completed in both the Doig and the Charlie Lake formations. The company is unable to dually produce the well due to complications with producing a natural gas/ condensate zone along with an oil zone up the same wellbore. As a result, approximately 315 barrels equivalent per day (190 barrels a day net) of Doig production has been suspended so the uphole Charlie Lake zone, which was perforated in the vertical section of the well, can be produced up tubing and evaluated for further capital investment. After four days the Charlie Lake zone was flowing at approximately 200–220 barrels per day of light oil (120 to 130 barrels

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Artek continues drilling high-volume condensate wells at its Inga play.

a day net). The company has 19 (11 net) sections of Charlie Lake mineral rights at Inga that it is looking forward to evaluating with the drillbit in early 2013. The third horizontal well of the year at Inga was drilled out as a horizontal re-entry

of a vertical well to a lateral distance of 1,200 metres earlier in the summer. Mechanical difficulties were experienced during the early stages of the completion and, although management was encouraged by the results, the completion of the operation must wait for

slim-hole tools to conduct repairs that management now estimates will take approximately eight to 10 weeks. The company is currently drilling out the lateral leg on its fifth horizontal well of 2012 at Inga A16-10-88-23W6, off the pad that it drilled its first Doig horizontal of the year, which Artek reported tested at approximately 2,520 barrels equivalent per day (1,700 barrels per day of condensate) net of load at 1,046 pounds per square inch after an 80-hour cleanup test period. The well is expected to be complete in early October. Up to two additional horizontal wells in Artek’s Inga gas/condensate drilling program are planned from late September through November with all wells anticipated to be completed and on production by year-end. Average test rates for the company’s first seven horizontal Doig wells in the Inga area have been consistently strong at over 2,100 barrels equivalent per day, averaging approximately 1,300 barrels a day of condensate despite variations in horizontal length, frac density and frac size. Longer horizontals with larger and more fracs have yielded the best well results to date. — DAILY OIL BULLETIN



British Columbia

Painted Pony updates Montney operations In an operations update of the company’s Montney gas project in northeastern British Columbia, Painted Pony Petroleum Ltd. reports it recently completed four (1.4 net) new Montney gas wells in the Daiber/ Kobes area that are undergoing production testing. All four of the wells were drilled earlier in 2012. The Daiber d-A44-C/94-B-16 (50 per cent working interest; operated) lower Montney well is currently testing in-line through the company’s Daiber facility.

24-hour rate was 9.3 million cubic feet a day at a current flowing casing pressure of 1,039 pounds per square inch. The Daiber d-B44-C/94-B-16 (50 per cent working interest; operated) middle Montney well is currently flowing back on initial cleanup. In addition to the middle Montney completion, this well was perforated and simulated across one stage in the upper Montney. During the past three days, this well flowed at an average wellhead rate of 3.2 million cubic feet a day over 65 hours. Additional test data from

The 24-hour peak rate averaged 13.1 million cubic feet a day, and the most recent 24-hour rate was 9.3 million cubic feet a day. During the past 12 days, this well has flowed at an average wellhead rate of 10.2 million cubic feet per day over 277 hours. The 24-hour peak rate averaged 13.1 million cubic feet a day, and the most recent

this well is expected within the next several weeks following the installation of production tubing. The Kobes c-75-J/94-B-09 (20 per cent working interest; non-operated) lower

Montney well is currently testing in-line through the non-operated Gundy facility. During the past six days, this well flowed at an average wellhead rate of 5.6 million cubic feet per day over 131 hours. The latest 24-hour test rate was 5.3 million cubic feet a day at a current flowing tubing pressure of 570 pounds per square inch. A second lower Montney well on the Kobes pad, the c-A75-J/94-B-09 location (20 per cent working interest; non-operated), is also producing on test through the Gundy facility. During the past six days, this well flowed at an average wellhead rate of eight million cubic feet a day over 133 hours. The latest 24-hour test rate was 9.7 million cubic feet per day at a flowing tubing pressure of 966 pounds per square inch. On the Blair block, Painted Pony has recently spud the fi rst of two additional Montney wells (100 per cent working interest), which are planned to be drilled, completed and tested prior to year-end. Both of these wells are located on the Town c-11-F/94-B-16 pad. — DAILY OIL BULLETIN

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Northwestern Alberta/Foothills

Multi-zone drilling strategy paying off for Celtic

Photo: Joey Podlubny

Celtic is on track to deliver 29,900 barrels equivalent per day by year-end.

Celtic Exploration Ltd.’s strategy to focus its exploration efforts in areas of multizone hydrocarbon potential has the company on track to meet its 2012 production exit guidance of 29,900 barrels of oil equivalent per day. At Jayar, Alta., in the northern portion of the company’s Resthaven land block, Celtic has completed a horizontal well located at 4-22-61-3W6 (100 per cent working interest, or WI). The well was drilled with a horizontal lateral of 1,545 metres in the Montney formation and was completed with a 900-tonne, 18-stage nitrogen foam fracture. The well was flowed on cleanup for 194 hours, and during the last 24 hours of the test the well was flowing at 11.7 million cubic feet per day of raw gas and 362 barrels per day of condensate with a flowing

tubing pressure of 8,748 kiloPascals (kPa), or 1,268 pounds per square inch (psi). After processing the gas with shallow-cut recoveries at the gas plant, the company said it expects liquids production, including field condensate, to be in the range of 45–50 barrels per million cubic feet of raw gas. At Kakwa, Alta., north of Celtic’s Resthaven land block, the company has completed a horizontal well located at 3-28-64-4W6 (100 per cent WI). The well was drilled with a horizontal lateral of 1,492 metres in the Montney formation and was completed with a 900-tonne, 15-stage nitrogen foam fracture. The well was flowed on cleanup for 132 hours, and during the last 24 hours of the test the well was flowing at 1,596 barrels per day of 45 degree API oil with associated gas

of 2.5 million cubic per day, at a flowing tubing pressure of 2,960 kPa (429 psi). This well offsets a well previously drilled by Celtic that has been on production for a year and has produced approximately 86,000 barrels of oil and 193 million cubic feet of natural gas. The company has also been active in building up its infrastructure capabilities at Resthaven. Construction of the remaining six-kilometre portion of the main pipeline system in the southern portion of the Resthaven land block, including a river crossing, is just being completed. After pressure testing the pipeline and final well tie-ins, Celtic expects to begin production from two Montney horizontal wells and one dual Montney-Cretaceous horizontal well in the southern block during the week of September 24. In the Fir-Kaybob-Chickadee areas of Alberta, the company has drilled three (100 per cent WI) horizontal wells in the Dunvegan formation. The first well, located at 1-27-60-17W5, was drilled with a horizontal lateral of 1,767 metres and was completed with a 526-tonne, 20-stage nitrogen foam fracture. The well was flowed on cleanup for 91.5 hours, and during the last 24 hours of the test the well was flowing at 1,899 barrels per day of 32 degree API oil with


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Source: Daily Oil Bulletin



Celtic is using as many as 25 stages in fracturing the Duvernay shale.

associated gas of 985 thousand cubic feet per day, at a flowing tubing pressure of 2,720 kPa (394 psi). The second well, located at 2-21-6019W5, was drilled with a horizontal lateral of 1,239 metres and was completed with a 432-tonne, 18-stage nitrogen foam fracture. The well was flowed on cleanup for 107 hours, and during the last 24 hours of the test the well was flowing at 255 barrels per day of 32 degree API oil with associated gas of 248 thousand cubic feet per day, at a flowing tubing pressure of 167 kPa (24 psi). The third well, located at 4-26-5922W5, was drilled with a horizontal lateral of 2,834 metres and was completed with a 552-tonne, 22-stage nitrogen foam fracture. The well is currently being tested. To date in 2012, Celtic has drilled five (3.7 net) horizontal wells in the Duvernay shale formation at Kaybob. The status of these wells is as follows: 4-11-60-20W5 (33.3 per cent WI)—drilled, completed six fractures and tested; 15-31-60-19W5 (100 per cent WI)—drilled, completed 22 fractures, with five fractures remaining;

1-25-59-19W5 (100 per cent W I)— drilled, completed 25 fractures and currently testing; 13-9-60-19W5 (50 per cent WI)—drilled and waiting on completion; and 16-33-59-19W5 (86.1 per cent WI)— drilled and waiting on completion. The company said it expects to provide another operations update after it has obtained well test results from the above mentioned Kaybob Duvernay wells. Meanwhile, the company said its 2012 net capital expenditure program remains at $322 million. Celtic expects production in 2012 to average between 22,000 and 23,000 barrels equivalent per day. Average production in 2012 is expected to be weighted 24 per cent oil and 76 per cent natural gas; however, operating income in 2012 is expected to be weighted 78 per cent oil and 22 per cent natural gas. At the low end of the range of 2012’s average production forecast, this represents a 36 per cent increase from average production of 16,212 barrels per day in 2011. On a production-per-common-share basis, the increase would be 26 per cent. — DAILY OIL BULLETIN

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Northwestern Alberta/Foothills

Northwestern Alberta/Foothills

Photo: Joey Podlubny

Cequence makes Falher discovery at Simonette/Resthaven Cequence Energy Ltd. reports its first Falher horizontal well at Simonette/ Rest haven, t he operated 16 -18 - 6101W6 well, was drilled to a final measured depth of 4,550 metres, including approximately 1,589 metres of horizontal section in the Falher formation. A total of 15 55-tonne fracs were successfully placed using a frac port system and slickwater. T he well f lowed on cleanup for 119 hours at a final rate of 14 million cubic feet per day with 12.7 megaPascals (1,850 pounds per square inch) f low i ng pr e s su r e t h r oug h a 15.9 millimetre choke. Natural gas–liquid yield is expected to be approximately 20 barrels per million cubic feet. T he e x plor at ion d i s c ove r y w a s flow tested in-line to sales through the Cequence-owned Simonette gathering system. The 16-18 well was drilled as a farm-in commitment well and Cequence retains a 65 per cent working interest.

The Falher discovery is expected to produce 20 barrels of NGLs per million cubic feet of gas.

Management believes that this successful test validates a 20-section geological prospect previously defined by well control and confirmed by 3-D seismic on Cequence lands. Based on publicly available data, t he a na log pool at Musreau / K a k wa (20 m i le s to t he nor t hwe st) i s c u rrently estimated to be producing over 6 0 m i l l ion c ubic feet p e r day f rom 21 horizontal wells drilled on a t y pical spacing of t wo wells per section, Cequence said. The company believes t hat t he Si monet te/ Rest haven pool i s l i k e l y s i m i l a r t o t h e Mu s r e au / K a k w a p o ol i n t e r m s of r e s e r v oi r qualit y, t hick ness and pressure, and m ay pr ov ide a mo de l for e x p e c te d results once more production histor y is available. Well costs to drill and complete the 16-18 well were approximately $6.6 million and are expected to decrease as the pool is developed in the future. — DAILY OIL BULLETIN

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Northeastern Alberta

In situ oilsands competitive with tight oil projects By Elsie Ross

result with an in situ steam to oil ratio (SOR) of 3.5 and “excellent” comparatives with an SOR of 2.5, he said. “Operators like Cenovus have shown that with time and scale, the manufacturing advantages can be achieved.” While the start-up of these projects is more inefficient than greenfield and brownfield expansions, “gains are realized and compounded once the commercialized projects are established,” said Schmidt. “Innovations such as solvent [and] infill wells are leading to further reductions in supply costs below that of the base-case steam recovery,” he said. “As an industry, we are seeing lower SORs, faster start-ups and techniques, and expansions built on these initial operations.” The Canadian oilsands without question can compete on scale, said Schmidt,

quoting BP plc that “there is no greater giant field than the oilsands,” which has 1.7 trillion barrels in place. Laricina is focused on the next two largest plays in the oilsands (after the McMurray). The Grosmont contains more than 400 billion barrels in place and the Grand Rapids has 150 billion barrels in place. Laricina, which is commit ted to innovation and new technologies as they apply to in situ recovery, has an inventory of 500,000 barrels per day of production potential with an economic potential of about $11 billion. It is expanding both its Grosmont carbonates pilot project at Saleski and the commercial demonstration project at Germain, which is currently under construction. While the long life of oilsands is one attraction for investors, technology can also enhance the value of oilsands projects. “The reservoirs are of such good quality that incremental recovery with solvents is expected to add a recovery of 10 –15 per cent of the oil in place,” he said. “Solvents significantly improve capital efficiency by decreasing SORs by an estimated 30 per cent, leading to a significant gain in net present value,” said Schmidt. “Solvents are only one of the innovation opportunities being exploited.”

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Photo: Joey Podlubny

The best SAGD operations are competitive with tight oil plays like the Eagle Ford, says Peters & Co.

Many new in situ oilsands projects are capable of competing favourably with other North American tight oil plays, an investment conference heard in September. Tight oil half-cycle economics show typical supply costs in the range of $60 per barrel to $80 per barrel West Texas Intermediate ( W TI), Glen Schmidt, president and chief executive officer of privately held Laricina Energy Ltd., told the Peters & Co. Limited conference in Toronto. “The right in situ development, of the right size, in the right location, can compete with tight oil.” A recent Peters’ study comparing and contrasting a 30,000-barrel-per-day development in the Eagle Ford, a leading North American tight oil play, and a 30,000-barrel-per-day in situ oilsands development found a “competitive”


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Source: Daily Oil Bulletin



Northeastern Alberta The use of solvents adds incremental value of approximately 30 per cent, which would increase Laricina’s economic value to about $14 billion with a break-even price of about $55 per barrel WTI, the conference heard. “And that is competitive and can be a compelling oil opportunity,” he said. While in situ oilsands innovation can capture value in the cost and performance of a project, drilling optimization, such as multi-lateral wells, addresses cost and well productivity, said Schmidt. In Laricina’s most recent work at its Saleski pilot, it doubled the production per metre of horizontal length by optimizing drilling and completion operations. Oilsands operators can take advantage of the invested heat in the reservoir with the use of wedge wells between we l l p ad s, t he c on f e r e nc e he a r d. Laricina, though, is also focused on leveraging the energy between horizons, he said. The selection of the location for the Saleski pilot was based on the stacking of the horizons in the Grosmont. Heat can be recovered both vertically and horizontally to make it an extremely efficient program.

Cavalier Energy Inc., a private company whose oilsands assets were spun out of Paramount Resources Ltd. last year, also will target the Grand Rapids formation in its planned 100,000-barrelper-day SAGD project at Hoole, in the western Athabasca oilsands. T he compa ny e x p ec t s to subm it an application for t he f irst phase, a 10,000-barrel-per-day project, to the Energy Resources Conservation Board in the fourth quarter of this year, Will Roach, president and chief executive of f icer, told a na ly st s. T he t i mel i ne ca l ls for reg ulator y approva l in t he f i r st qua r ter of 2014 w it h t he f i r st full year of production anticipated in 2016. By that time, Cavalier expects to have delineated its other leases, said Roac h, t he for mer president of U TS Energy Corp. The capital cost of the first phase is estimated at $452 million with estimated capital costs of $1.3 billion per phase for the three subsequent phases of 30,000 barrels per day. Before Cavalier proceeds with the second phase, it wants to see a year’s production from the first phase, he said.

Aboriginals could provide half of labour needs, says Newell By Joseph Caouette Few would argue the point that Canadian industry is facing a massive head-on collision with a skilled-worker shortage in the coming decade, due in no small part to rising activity in the oilsands. But Eric Newell, the former chief executive officer of Syncrude Canada Ltd., believes the country’s aboriginal population could help meet almost half of the projected labour demand—if industry moves quickly enough to open up education opportunities. “It’s like what Will Rogers said. If you’re going down the track in the right direction, but you’re not going fast enough, the train’s going to run you over anyways,” Newell said. “And we’ve got a train coming at us in western Canada, and probably across the country.”



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Northeastern Alberta He was referring to a Conference Board of Canada study that indicates the country will be short one million skilled workers by 2020. Bringing aboriginal education and employment rates up to levels equal to those found in the non-aboriginal populace could create 400,000 new workers, Newell said. “If we start looking at [aboriginal education] as an opportunity and not a problem, we’ll deal with our skills shortages,” he said. Newell, who retired as chief executive officer of Syncrude in 2003, was speaking at an awards luncheon in Edmonton on Monday. It served as a preview of a larger gala event that will be held in Vancouver on Thursday, where Newell will receive the Award for Excellence in Aboriginal Relations. Newell is just the second person to win the award, following last year’s inaugural recipient, former prime minister Paul Martin. The award is handed out by the Canadian Council for Aboriginal Business (CCAB) and sponsored by Sodexo Canada. The award is given to individuals who are dedicated “to building bridges between aboriginal people and Canada’s business community,” according to a CCAB release.

One of the key factors in winning Newell recognition was his work at Syncrude. The company is one of a small group of businesses to earn gold-level certification in CCAB’s Progressive Aboriginal Relations (PAR) program. Newell’s efforts have also helped push Syncrude to do $1.7 billion in total business with aboriginal companies so far. Newell described Syncrude’s efforts to reach out to the aboriginal business communit y when he first joined the company as not “very well-focused.” At the time, Syncrude only did $2 million to $3 million per year in transactions with aboriginal firms. “There were no benchmarks, so we pulled this number out of the air—$30 million a year of business for aboriginal business,” he said in an interview with the Daily Oil Bulletin. “But, of course, today Syncrude does almost $150 million [per year] in business with aboriginal companies it helped create.” For other oil and gas companies looking to tap the expanding aboriginal labour market and business community, Newell pointed to CCAB’s PAR program as an invaluable resource.

“It’s built on best practices of companies like mine, Syncrude. They don’t have to make all the mistakes we made, because we made every mistake in the book,” he laughed. “Believe me.” Syncrude was a big proponent of aboriginal employment stretching back to its earliest building phases in 1974, Newell recalled. The company hired at least 500 aboriginals to work on construction. “Our first mistake was to think we were just in a hiring program, because you brought people who grew up in a little community of 200–250 and threw them into a huge industrial complex like Syncrude,” he said. “It’s not a formula for success—I don’t care if you’re aboriginal or not.” He said the company soon realized it was a development program, not simply a hiring agency. “So then we hired a native advisor, we started to work with communities, we got really good role models [that] we got the chiefs to hand-pick, so we got good young people in there, we put all of our management through crosscultural training so they would look at the world through the eyes of the aboriginal, because you’ve got to build trust and positive relationships.”

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The company also began reaching out to colleges to create educational opportunities for aboriginal youth—a particular passion of Newell’s that has defined his post-Syncrude career. From 2004 to 2008, he was chancellor of the University of Alberta, where he was involved in numerous efforts aimed at bringing aboriginal youth into the post-secondary education system. He helped found the university’s Council on Aboriginal Initiatives, donated $1 million towards the construction of the Aboriginal Gathering Place on campus and established a scholarship for students entering native studies. He also currently serves as chair of Careers: The Next Generation, an organization focused on encouraging students—both aboriginal and non-aboriginal—to explore employment in trades and technical fields. Newell often jokes that Syncrude’s aboriginal relations program was an overnight success story that took 40 years. Unsurprisingly, he advised other oilsands companies to realize there are no quick fixes to the challenges of engaging Canada’s First Nations in the workforce. “You need to be committed—and committed right at the top of the organization— and don’t give up,” he said. “You win this game one child at a time.”

Solid outlook for oilsands By Richard Macedo Odds are favourable that investment and employment in the oilsands will remain strong over the next three to five years, Todd Hirsch, senior economist with ATB Financial, said in September. During a Speaker Series event at the Calgary Petroleum Club hosted by JuneWarren-Nickle’s Energy Group and Fluor, he estimated the odds are around 80 per cent that scenarios will play out in Alberta as expected. “There’s an 80 per cent probability that in the next, say, three to five years, things will unfold as a lot of people in this city expect,” he said. “In other words, the investment will 48


Northeastern Alberta be there, the pipelines, wherever they’re going, will eventually be built; progress and more production comes out of those oilsands and the employment continues to grow.” In this case, labour shortages would intensify and there would be solid employment growth in the oilsands. “We constantly need to be aware…there is a 20 per cent possibility that things don’t go as planned,” Hirsch said. “A lot could still go wrong with those global oil prices, and I think we’d be foolish to ignore those possibilities.” There are several risks to the downside for world oil prices to fall below $70, including a major downturn in China. “I’m not expecting a major downturn, but nobody expected Japan to fall flat on its face in 1989 either, and go through 20 years of stagnation,” Hirsch said. “If they can negotiate or engineer a soft landing in China, I think we’ll be okay, but there are no guarantees. “Right now, China and those emerging economies are about the only leg of the global stool that’s still actually operating quite well.” World oil prices have bounced around, from $100 to the mid-$70s, then rebounded and are now hovering around $90. Geopolitical tension and the state of the global economy have contributed to this volatility. “The Chinese economy is moderating, there is no question about that, but if it moderates too much, that has the potential to bring oil prices lower,” Hirsch said. In Canada, he noted that Statistics Canada reported gross domestic product (GDP) growth in the second quarter of 2012 was 1.8 per cent, annualized. “We’re the best of a bad lot,” he said, when comparing Canada to other countries in the G7. “Probably around three per cent real GDP growth is where, potentially, the Canadian economy could be or should be. “Most of the softness we are seeing is concentrated in central Canada, Ontario and Quebec particularly, where the unemployment rates are higher.” As for the United States, Hirsch said that country’s economy is currently treading water. “Treading water is different than 10 feet under the waves, and that’s sort of where they were in 2008/2009,” he said. “They’re treading water, but they’re not really getting anywhere; they’re having a hard time gaining any sort of traction, any kind of momentum in their economy.” Key indicators at the moment are moving sideways with not much momentum. “There's not enough jobs being created to get that unemployment rate down,” Hirsch said.


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Central Alberta

Is the Duvernay the next Eagle Ford? By Richard Macedo

The Duvernay shales have been credited as the source rock for many of the large Devonian oil and gas pools in Alberta, including the Leduc field discovery in 1947. In central Alberta, the Duvernay shale basin spans roughly 50,000 square miles, much of which is within the thermally mature or “wet” gas window, according to a report from BMO Capital Markets. An estimated 7,500 square miles is thought to be in the liquids-rich gas window where reported liquids recoveries range from 75 to 150 barrels per million cubic feet. Since late 2009 to now, producers have spent billions at Crown land sales amassing acreage positions. The Kaybob area was the first to see land-sale activity thought to be associated with the Duvernay, and is the area that is most mature in the overall development of the play. McMurren said that unlike the Eagle Ford where there are hundreds of wells

drilled, completed and on production with a lot of data, there’s a fraction of that in the Duvernay. “There are older wells, Cretaceous gas wells, that have been on production for a number of years, and a lot of the facilities right now are set up as sweet gathering systems,” he said. “To date, the Duvernay has been a sweet-gas zone. There have been tests of sour product from it and it does sit in the Devonian age around zones like the Beaverhill Lake that are very sour in the area. “It might stand to reason that it may be sour one day.” The company is setting up the infrastructure needed to handle high-pressure liquids-rich gas. “We have constructed a 63-kilometre pipeline…essentially from the town of Fox Creek all the way over to the Simonette Keyera gas plant,” McMurren said. Three batteries are planned for Saxon, Kaybob West and Kaybob East, and are expected to be on stream this year to handle both oil and gas. Greg Niebergall, exploration manager with Yoho Resources Inc., noted that the company was an early-mover at Kaybob, picking up its initial lands at less than $30 an acre. “We now have 54 gross sections, or 21 net to Yoho, and five successful horizontal wells spread across our lands,” he said. “We can support over 145 development locations, and those are net to Yoho.” The company focused on the Kaybob area because it has the thickest section of high-porosity Duvernay shale and it’s also located in a prime liquids-rich window. “The Duvernay section at Kaybob is very thick; in places it’s over 50 metres and the high-quality organic-rich shale is continuous from top to bottom,” Niebergall added. “The Duvernay is very overpressured. In fact, we’re seeing pressure gradients between 18 and 19 kiloPascals per

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Photo: Joey Podlubny

So far, the Duvernay remains shrouded in mystery as companies keep drilling results hidden.

While the Duvernay shale play in Alberta has drawn parallels to the Eagle Ford shale in Texas in terms of oil and liquids production potential, there’s simply not enough information to know for certain at this point if the two are comparable. Some view the Eagle Ford as the premier liquids-rich resource play in North America, and there is hope that the Duvernay will be similar. But there hasn’t been enough drilling in the Duvernay to know for sure. “At the state we’re at in the Duvernay, we’re very much in the exploration phase,” Gary McMurren, director of light oil with Athabasca Oil Corporation, told the Peters & Co. Limited 2012 Energy Conference. “Will the Duvernay be the next Eagle Ford shale? With certainty, I can tell you that no one can answer that question…with any certainty.” CENTRAL ALBERTA WELL ACTIVITY

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Source: Daily Oil Bulletin



Central Alberta metre, versus nine to 10 in the conventional reservoirs in the Kaybob area. “It has very high quartz and low clays, and that makes it suitable for achieving big fracture networks, which is very important in our completions.” Jim Riddell, chief executive officer of Trilogy Energy Corp., noted that industry has spent $1.7 billion on Duvernay rights in the Kaybob area since December 2009, adding that 65 wells have been drilled/or are drilling to date and 18 horizontal wells licensed. Roughly close to $1 billion has been put into the play in terms of drilling. “It is fairly well understood where the shales are. We slowly have started to

understand what the burial history of those shales has been and where would be the areas that were subjected to the highest heat and maybe a little less heat,” he said. “That’s determined how much the organic matter within the shales has been cooked and what it has done to generate the hydrocarbons. The hotter, deeper, higher-pressure burial history has generated dry gas and the less is an oilier part.” The Duvernay can be as much as 60 or 70 metres thick. “We go from the southwest corner, an area we have interpreted to be a drier gas, a liquids-rich gas in the middle and then an oilier area to the north,” Riddell added.

The company has around 100 sections of land in the oilier, still-to-beproven area and another 100 sections in t he liquids-r ic h area, “ whic h we think is pretty close to being declared as commercial.” He cited the 3-13-60-20W5 well, which the company put on stream last April. It started at three or four million cubic feet per day and it’s got a hyperbolic decline that’s flattened right out at about one million cubic feet per day now. “It also is producing 80 or 90 barrels a million of free condensate, plus additional liquids that we recover at the plants,” Riddell said.

Sasol Canada study backs gas-to-liquids plant

Sasol is looking to the Industrial Heartland as a possible location for its gas-to-liquids plant.

A feasibility study has made a compelling argument for a proposed gas-to-liquids (GTL) project in Canada, which will go to the board of South Africa’s Sasol Limited for a decision on whether to proceed with the next step, a Sasol Canada official said in September. “This is clearly something which we believe is a very strong value proposition,” Rudi Heydenrich, president of new business development for Sasol Canada, said. The proposed multi-billion dollar project will go to the board in early December for a decision on a front-end engineering and design (FEED) study, he said. If the board proceeds with the FEED study, it could take 45–50 months from the final investment decision to “first 52


product in the tank,” he said. With all approvals at the right stages, Sasol could be looking at start-up by the end of this decade, he said. “Obviously, it very much depends…on the level of activity that you have in the area at the time you sanction the project.” The proposed GTL plant will add value to natural gas by converting it into high-quality transportation fuels such as diesel and jet fuel, and petrochemical feedstocks. The initial phase would produce 48,000 barrels per day of diesel fuel (71 per cent to 72 per cent) and naphtha, which could be sold for diluent for oilsands bitumen. The plant could have an ultimate capacity of 96,000 barrels per day in two phases.

Sasol believes that the current structural disconnect in North America between oil and natural gas will remain, said Heydenrich. “We believe that what you are seeing here is real and that it’s going to be with North America as a whole for awhile,” he said. In the meantime, Sasol Canada has obtained an option to purchase a 526-hectare site in the Alberta Heartland area northeast of Edmonton, in the County of Strathcona. The site, which would be acquired from Total E&P Canada (which had planned to build an upgrader for its bitumen), is attractive because it is already zoned for industrial use, he said. “It’s big enough to support the longer-term aspiration and it is in an area where there is a lot of existing infrastructure to get access to product pipelines, and the proximity relative to the modularization workshops makes it attractive.” The proposed project area is approximately four kilometres northeast of the city of Fort Saskatchewan. The site is south of the North Saskatchewan River, north of Highway 15 and bounded on the west by Range Road 220. Talisman Energy Inc., which is partnering 50/50 with Sasol in upstream operations, has opted not to participate in the FEED phase of the project. Sasol, which for now will go it alone on the FEED study, still has a 50 per cent interest in Talisman’s Farrell Creek and Cypress natural gas assets in the Montney play of northeastern British Columbia. Sasol operates commercial-scale GTL plants overseas, but the Alberta project would be its first in Canada.

Photo: Joey Podlubny

By Elsie Ross

Central Alberta

Williams plans oilsands off-gas plant By Elsie Ross Williams has signed a new long-term gas processing agreement with a Canadian oilsands producer to acquire bitumen upgrader offgas, requiring an investment of $500 million to $600 million. Under the new long-term agreement, Williams will extract, transport, fractionate, own and market the natural gas liquids (NGLs) and olefins recovered from the off-gas at the oilsands producer’s upgrader near Fort McMurray. Williams expects to recover approximately 12,000 barrels per day of NGL/olefins by mid-2015, increasing to approximately 15,000 barrels per day by 2018. To support the new agreement, Williams plans to build a new liquids extraction plant and supporting facilities at the oilsands producer’s upgrader. It also plans to build an extension of its Boreal pipeline that will enable transportation of the NGL/olefins mixture to its expanded Redwater facility outside Edmonton. The company expects to fund the project using cash flows from its Canadian

operations as well as with international cash on hand. The NGL/olefins mixture will be fractionated at Williams’ Redwater facilities into an ethane/ethylene mix, propane, polymergrade propylene, normal butane, an alkylation feed and condensate. The ethane price risk associated with this deal is mitigated via the previously announced long-term agreement to supply NOVA Chemicals Corporation with up to 17,000 barrels per day of ethane and ethylene. The propane recovered will be sold into the local propane market and potentially would be used as feedstock at Williams’ proposed propane dehydrogenation facility in Canada. The other products will be sold into the established markets where Williams sells existing NGLs and olefins produced in Canada. “This new agreement will build on the unique expertise and large-scale infrastructure we’ve built in Canada,” David Chappell, president of Williams Energy Canada, said in a news release. “The scale that we are building

here—with fractionation, distribution and storage—gives us the ability to generate significant long-term incremental value from our operations. The new operations will also further reduce greenhouse gas and sulphur dioxide emissions from the upgrader’s operations, and produce valuable commodities that previously were being burned, he said. The off-gas processing that Williams pioneered significantly reduces emissions at its customers’ oilsands production facilities. Williams captures and processes a rich NGL/olefins mixture that would normally be burned by an oilsands producer. The producer instead burns methane that Williams provides in exchange for the NGL/olefins mixture. Once full operating capacity is achieved at the producer’s location, processing the offgas is expected to reduce emissions of carbon dioxide (CO2) by an average of approximately 200,000 tonnes per year and emissions of sulphur dioxide (SO2) by an average of approximately 2,000 tonnes per year.

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Southern Alberta

Cardium, Dunvegan plays help TriOil achieve record results

dispositions exceeding 425 boe per day, the company noted. In the same period, TriOil increased its oil and natural gas liquids weighting to 76 per cent from an initial 48 per cent, reduced operating costs to $13.35 per boe from $31.53 per boe ($19.09 boe in the second quarter of 2011) and improved operating netbacks to $39.55 per boe from $14.34 per boe. TriOil’s $18.4-million capital program in the second quarter included drilling and completing seven (3.8 net) wells and bringing five (3.3 net) wells on production. In the first half of the year, the company spent $50.54 million as it drilled 16 (9.4 net) wells, completed 15 (8.9 net) wells and brought 12 (6.9 net) wells on production. At the end of the quarter, TriOil had three (1.1 net) wells waiting on completion and/or tie-in. Subsequent to the end of the second quarter it drilled eight (5.3 net)

wells, with seven (4.5 net) wells waiting to be completed or brought on production. At Lochend, activity levels during the second quarter were lower than anticipated due to an early spring breakup as TriOil drilled two (0.68 net) horizontal Cardium wells, completed two (0.7 net) wells and brought two (0.8 net) wells on production. As of mid-August, the company had drilled another four (2.3 net) wells and brought one (0.34 net) well on production, resulting in an inventory of four (2.4 net) wells waiting to be completed or brought on production. Test results from Cardium oil wells completed in the second and third quarters, including the recently completed long-reach Cardium horizontal well drilled near Cochrane, have all met or exceeded expectations, it said. The Lochend Cardium light oil project continues to provide strong production and reserve growth along with top-quartile second-quarter 2012 netbacks of $50.98 per boe, said TriOil. The company has now participated in 13 slickwater multistage completions in the higher-impact central and western Lochend trends, and the most recent well (50 per cent interest) achieved a 30-day initial production (IP30) rate of 370 boe per day (81 per cent oil). TriOil’s initial eight wells achieved an average 30-day production rate of 380 boe per day (82 per cent oil) with five wells drilled and/or completed, waiting to reach 30-day production rates. TriOil owns 80 (55 net) sections on the Lochend Cardium trend with a current derisked Cardium horizontal drilling inventory of approximately 117 (66 net) locations, and it continues to de-risk additional acreage on the play and add to its drilling inventory. At Kaybob, TriOil was able to conduct an active drilling and completion program prior to breakup, but heavy spring and summer rains have hampered drilling, completion and production operations. Despite the

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Photo: Joey Podlubny

TriOil continues building production drilling extended-reach horizontal wells with hybrid frac jobs at Lochend.

TriOil Resources Ltd. achieved record operational and financial results in the second quarter with corporate volumes exceeding the 2,000-barrels-of-oil-equivalentper-day milestone for the first time in the company’s history. Production rose by 72 per cent in the three months ended June 30, 2012, to 2,091 barrels of oil equivalent (boe) per day from 1,212 boe per day in the second quarter of 2011, along with higher earnings, revenue and cash flow. Funds from operations rose to new highs of $6.66 million (13 cents per share) from $2.21 million (seven cents per share) in the 2011 quarter, as a result of TriOil’s successful Cardium and Dunvegan drilling programs at Lochend and Kaybob. Output has grown steadily from 426 boe per day in its initial quarter of operations in 2010 with non-core property SOUTHERN ALBERTA WELL ACTIVITY

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Source: Daily Oil Bulletin



Southern Alberta wet weather and difficult surface conditions, the company has been able to execute an active capital program. It drilled four (2.9 net) horizontal Dunvegan wells, completed four (2.9 net) wells and brought five (3.3 net) wells on production during the quarter. To date in the third quarter, TriOil has drilled another three (two net) wells and brought two (0.5 net) wells on production, resulting in an inventory of four (2.6 net) wells waiting to be completed or brought on production. TriOil now has eight wells with at least 30 days of production history at Kaybob. It reported IP30 rates for the most recent wells of 391 boe per day (91 per cent oil) in a 100 per cent interest well and 305 boe per day (87 per cent oil) for a well in which it has a 61.5 per cent interest. The early results on the play have been very encouraging, with the average IP30 rate for the initial eight wells coming in at 343 boe per day (83 per cent oil), said the company. While TriOil said it expects to see a range of well results due to variable reservoir quality and thickness along the trend, it believes that the average IP30 rates achieved with the initial wells on the play are indicative of future average results.

Six of the initial eight Kaybob Dunvegan wells have achieved IP30 rates ranging from 260 boe per day to 795 boe per day, with an average IP30 of 420 boe per day (86 per cent oil) for the six wells. Two of the initial eight wells experienced mechanical issues during completion operations that affected test rates and early production, said TriOil. Both wells were drilled in good-quality reservoir, with one well drilled in a thick, 10-metre sand and the other drilled in a thinner, two-metre sand. Both wells have performed very well considering their limited stimulations, said the company, which is moving ahead with offsetting drilling operations in both cases. One of the initial wells tested was drilled in fair-quality reservoir with average sand thickness of five metres and has performed below expectations but with steady production, with an IP30 of 107 boe per day, IP60 of 105 boe per day and IP90 of 97 boe per day (averaging 56 per cent oil), said the company. The Dunvegan play is still in its early development stages and TriOil said it is excited about the potential high rates, high recoveries, high netbacks, lower declines and

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waterflood potential afforded by this resource play. It said it has established a solid position at Kaybob with a current drilling inventory in excess of 35 net locations and plans to be active on the play for the balance of the year. In the second quarter, the company closed $2.6 million of non-core asset dispositions with a further $4.5 million in dispositions in July 2012. TriOil exited the quarter with a strong balance sheet with positive working capital of $6.9 million and undrawn bank lines of $50 million. The company has a strong commodity hedge program with 900 barrels per day hedged to December 2012 at a weighted average price of C$94.97 per barrel West Texas Intermediate and 800 barrels per day hedged for calendar 2013 at a weighted average price of $101.93 per barrel. TriOil said it will continue to monitor commodity prices in order to retain the flexibility to adjust its capital program as necessary to ensure that acceptable debt levels are maintained. TriOil also reported that its board of directors has approved the adoption of a shareholder-rights plan, effective immediately.

Saskatchewan continues to experience rapid economic growth year after year. Potash mines are multiplying across the Province, construction cranes are rising above our cities, and power plants are increasing their capacities. Each mine, industrial site, refinery, or office building needs a dependable supply of natural gas to power its expansion and future operation. TransGas is strategically positioned to provide safe and reliable natural gas transportation and storage services to support this unprecedented growth in Saskatchewan.


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Torquay's Saskatchewan operating costs rise Average year-to-date prices declined $4.60 per barrel compared to the first six months of 2011, but have recovered substantially in the third quarter of 2012. Year-to-date netbacks have averaged $48.51 per barrel for the first six months of 2012. One-time charges resulting in a net decrease in netbacks of $4.79 per barrel year to date are not expected to reduce netbacks in future quarters.

Industry activity is moving towards applying the same fracture stimulation techniques that have been successful in the Bakken. The weather cost Torquay six weeks this spring, but the company still managed to raise production by

Photo: Gerald Ford

nine per cent.

Torquay Oil Corp. production rose nine per cent during the second quarter of 2012 compared to the same quarter a year ago, thanks to new volumes from Queensdale, Sask., despite operations being shut in for six weeks due to spring road bans that reduced volumes by about 90 barrels of oil equivalent per day. Production was up 31 per cent year-todate, compared to the same period last year. A seismic program that was shot at Queensdale in the first quarter has been interpreted, and the company expects to drill at least one additional location in this area in the third or fourth quarters of this year. Operating costs jumped during the second quarter due to a large, previously unbilled and unexpected processing fee that was received for third-party processing at Viewfield. This agreement was inherited at the time of the initial acquisition of the Viewfield property. The invoice covered processing

charges from September 2010 to June 30, 2012. The charge related to 2010 and 2011 was approximately $277,160, or $3.31 per barrel year-to-date. Operating costs were $24.40 per barrel and $15.09 per barrel for the three and six months ended June 30, 2012, compared to $17.78 per barrel and $14.95 per barrel for the three months and six months ended June 30, 2011. Capital activity was reduced during the second quarter due to seasonal breakup and to maintain the balance sheet during this period of volatile commodity pricing. Replacement of a damaged tank farm at the Viewfield battery is well underway and production is expected to resume by midSeptember. The financial impact of the damage to Torquay is limited to insurance deductibles of around $136,000, which includes a $25,000 deductible on equipment replacement and 15 days of net production.

According to Torquay, industry activity is moving towards applying the same fracture stimulation techniques that have been successful in the Bakken on other formations such as the Midale. The Midale formation is well-suited to this type of stimulation as it typically has low permeability and is sandwiched between two evaporite beds, which help contain the fracture stimulation. Torquay has been monitoring stimulations in the Midale and is well positioned to apply this step change in technology on its lands at Alameda and Midale. At Lake Alma, Sask., the company holds more than 57,000 net acres, the majority of which do not expire until March 2016. Industry activity in North Dakota has become increasingly focused on the Three Forks formation, which is pervasive underneath Torquay’s land block and is now productive within 35 kilometres of its land position. The company said it continues to evaluate the Bakken formation along with the emerging Three Forks play. — DAILY OIL BULLETIN


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Source: Daily Oil Bulletin




CanElson strikes CNG delivery deal with SaskEnergy A n A lber t a dr i l l i ng cont rac tor ha s struck a deal to deliver compressed natural gas (CNG) for use on drilling rigs in western Canada. CanElson Drilling Inc. said its subsidiary, CanGas Solutions Inc., has signed a three-year agreement with Bayhurst Energy Services Corporation, a unit of SaskEnergy, Saskatchewan’s Crown-owned natural gas utility. Under the deal, SaskEnergy will build a high-capacity CNG facility at Weyburn, Sask., allowing CanGas to become the first commercial supplier of trucked CNG for diesel engines on oil and gas drilling rigs in western Canada. “With this agreement, we can start rolling out our plan to substitute diesel fuel with clean and inexpensive natural gas in our own fleet of mobile drilling rigs in Saskatchewan,” Randy Hawkings, CanElson’s president and chief executive, said in a news release. “We expect this agreement to serve as a regional model under which we can quickly expand our CNG road transport services

business to supply drilling rig engines and other equipment in North American markets,” he added. Thanks to its deal with SaskEnergy, CanElson will focus $9 million of its $20-million investment in CanGas to establish a f leet of 30 Saskatchewanbased, truck-hauled CNG delivery trailers, and to convert the diesel engines on its 14 drilling rigs in Saskatchewan to bi-fuel capability so the engines can run on a natural gas–diesel mixture. “This agreement demonstrates how SaskEnergy can strategically use existing infrastructure to offer a new service in a region where more than 40 per cent of Saskatchewan’s oil and gas drilling occurs,” Doug Kelln, SaskEnergy’s president and chief executive, said in the same news release. Kelln said SaskEnergy and CanElson have developed a relationship that supports continued growth of the oil and gas sector, and a viable way for the industry to significantly cut emissions as drilling rig engines are converted to cleaner-burning gas.

SaskEnergy expects its three-year deal with CanGas to generate $2.3 million in revenue. The proposed CNG cardlock loading facility at SaskEnergy’s Weyburn Town Border Station will not affect the company’s ability to provide gas to its customers in the Weyburn area, management said. CanGas will use a portion of the Weyburn CNG facility’s gas, allowing SaskEnergy to pursue other customers in the area. W hen completed, Sa sk E nerg y ’s Weyburn CNG loading facility will be the first commercial station in western Canada designed to load trailer-sized CNG containers for truck-haul delivery. CanElson expects the station will be partly operational by the end of the third quarter and fully working next year. CanGas will be the initial anchor customer for the Weyburn station. With significant current cost savings between gas and diesel fuel, CanElson plans to negotiate more CNG supply agreements in Canada, as well as in Texas and North Dakota, where the contractor also operates drilling rigs. — DAILY OIL BULLETIN

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Central Canada

Ontario government takes shine to oilsands By James Mahony

Photo: Joey Podlubny

The oilsands will help fuel the Canadian economy, said Ontario finance minister Dwight Duncan.

When it comes to Alberta’s oilsands, the Ontario government is singing a different tune these days. Visiting Alberta in September to tour the oilsands, Ontario Finance Minister Dwight Duncan expressed strong support for the sector on behalf of the Dalton McGuinty government. “We’re proud of our sister province, Alberta, and we will work with you to develop the oilsands to allow the prosperity you’re experiencing to continue to flourish, because a strong Alberta means a strong Ontario and a strong Canada for all of us,” Duncan said to loud applause from a Calgary business audience. He described Alberta’s oilsands as a valuable resource both for this province and the entire country, adding that the sector will “help fuel the Canadian economy and our entire country’s future.” Duncan’s remarks at a lunch organized by the Alberta Enterprise Group were a sharp departure from those delivered earlier this year by Premier McGuinty, who blamed the oilsands sector for so-called “Dutch disease,” a term for the adverse effects the

Canadian dollar’s swift rise has caused Ontario’s manufacturers, who saw foreign sales plunge as the loonie soared. Asked to explain Ontario’s reversal on the oilsands, Duncan chalked it up to McGuinty’s discontent with the problems caused by the strong dollar. “When the premier spoke earlier this year, he was expressing the very real frustration at the challenges posed for Ontario by the rise of the Canadian dollar over the last nine years,” he said. Duncan recalled the toll the recession took on Ontario’s economy, in particular manufacturing. Yet, despite the recession, the province’s gross domestic product has risen 7.5 per cent since the second quarter of 2009, considered the recession’s low point, he said. “A big driver of that growth has been business investment in machinery and equipment, which rose almost 20 per cent in 2011. Many of the components needed for developing the oilsands—tires, trucks, valves, pumps and more—are produced in the industrial regions of central Canada,” he said.

Over the next 25 years, he said, Alberta’s oilsands sector is expected to buy some $63 billion worth of goods and services from Ontario. Indeed, projected Ontario sales to the oilsands sector could potentially surpass sales to many of that province’s traditional export markets, including China, Hong Kong and Norway. As well as sales of goods and services to Alberta, Duncan acknowledged that skilled workers from his province play a vital role in oilsands development. By 2035, he estimated that seven per cent of all jobs generated by the oilsands will be created in Ontario. Citing one case, he said Canadian Natural Resources Limited hired 350 Ontario-based companies during construction of the Horizon project, paying them a total of roughly $770 million. “As you can see, our partnerships… are prospering. So let me say: ‘Thank you, Alberta,’ ” he told the audience. Yet, the loudest applause Duncan drew came when he differentiated his government’s views on the oilsands from the far less supportive views expressed earlier this year by Federal Opposition Leader Thomas Mulcair, who also toured the oilsands during his stay in Alberta this summer. “Let me say that Mr. Mulcair does not represent the views of central Canada on the oilsands,” he said. Later, Duncan expanded on his remarks about Alberta’s contribution, underscoring the need to recognize the economic benefits the oilsands have created for Ontario and the rest of Canada. “A strong Alberta, a strong western economy and a strong energy economy make for a stronger Canada,” he said. At the same time, the former Ontario energy minister and current deputy premier said the rapid rise of the Canadian dollar has been hard on Ontario. “It’s been tough, but you can’t hide behind a low dollar. The challenge for the Canadian and Ontario economies is productivity. When OIL & GAS INQUIRER • NOVEMBER 2012


Central Canada we have too low a dollar, you lose that edge,” he told the audience. In his hometown of Windsor, which faces Detroit, Mich., Duncan said tool and die shops are busy these days, but are making fewer parts for the United States and are employing fewer people than formerly.

equipment, which will make us more productive. Your investments here in Alberta benefit us,” he added. Following his speech, Duncan acknowledged that some Ontarians travel to Alberta to work, indicating his government would be open to discussing a trade

Following his speech, Duncan acknowledged that some Ontarians travel to Alberta to work, indicating his government would be open to discussing a trade and labour mobility agreement, not unlike the Trade, Investment and Labour Mobility Agreement accords Alberta has signed with neighbouring British Columbia and Saskatchewan.

“They’re [now] producing things for the oilsands [and] for the domestic and international auto industry. [Windsor] is coming back, and it’s coming back with record investment in machinery and

and labour mobility agreement, not unlike the Trade, Investment and Labour Mobility Agreement accords Alberta has signed with neighbouring British Columbia and Saskatchewan.


“I think we need to explore that,” he told reporters. “I’ve had that issue raised by a number of people while I’ve been here, and when we head back to Toronto, we’ll talk to our folks about it. A lot of Ontarians work here, and a lot of Albertans come to Ontario, and it makes good sense to me for Ontario to look at that,” he said. The only exceptions, he suggested, might be the self-governing professions, which he described as “very independent,” although some have been amenable to striking agreements on issues of training and qualifications. According to Duncan, Ontario and Alberta are on the same page in another way: the federal equalization program. Ontario is a net contributor to the program, which is geared to balancing economic differences among provinces. This year, he estimated, Ontarians will pay $6 billion into the program, getting back about half that amount. “Despite the economic change we’re seeing across the country, Ontario remains the largest net contributor to the equalization program,” which he described as “flawed.” He noted Alberta has expressed similar sentiments in the past, and said the long-standing federal program is “harmful to both our economies.”



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The impending knowledge deficit. When workers retire, they take their skills and know-how along with them. By Bryan Leach

Over the past year, numerous articles have appeared in business magazines

What does this accumulating knowledge deficit have on the efficiency and pro-

regarding the current and growing labour shortage in the oil and gas industry

ductivity of the industry? And what are the industry and the companies that

in western Canada, generally, and oilsands megaprojects in particular. The

operate within it doing to retain this valuable knowledge resource?

focus of these articles has been the challenges of finding, hiring and retain-

As noted in the September 2011 issue of Oilfield Technology, “pressures

ing suitably qualified and skilled workers in the face of stiff competition from

are great to harvest this knowledge before it walks out the door.” Much of

other firms in the industry. Some of the articles have made a passing refer-

the valuable knowledge that the retiring baby boomers possess is so-called

ence to the labour shortage being exacerbated by the baby boomers starting

tacit knowledge (know-how) that is difficult to articulate in written form. In

to retire from the workforce.

contrast, the less valuable so-called explicit knowledge (know-what) can be

The September 2011 issue of Oilfield Technology reported that “experts

stored in documents and databases that tend to be little used.

tell us that nearly 40 per cent of the oil and gas workforce will turn over in

Research has shown that people are five times more likely to seek a know-

the next 15 years due to retirements.” The May 2012 issue of Oilsands Review

ledgeable person to help solve a problem rather than access a database or a

noted that “about one-third of all those currently employed in the Canadian

report. Companies are looking to maintain access to the retiring baby boomers’

oil and gas industry will need to be replaced by 2020,” and, according to

knowledge by retaining them on contract post-retirement as consultants.

Statistics Canada, “there are now about 170,000 people employed in the

While this type of arrangement offers a short-term benefit to both the company

Alberta resource sector” and “no other factor is as serious a threat to the

and the retiree, it does nothing to promote the transfer of knowledge to the

oilsands as the inability to replace retiring baby boomers with experienced

younger generation within the company.

and skilled workers.”

Companies need to identify key knowledge assets that baby boomers

This data would suggest that the Alberta oil and gas industry could expect

possess and that comprise the company’s source of competitive advantage.

to lose of the order of 7,000 highly knowledgeable, skilled and experienced

The company then needs to develop a knowledge management strategy to

workers a year, due to the baby boomers retiring over the next eight years.

affect the timely transfer of these assets to other younger people in the

In addition to the challenge of replacing retiring workers, there is the chal-

company before the baby boomers retire. These strategies may involve cul-

lenge of attracting young people into the industry. The June 2012 issue of the

tural changes whereby sharing rather than hoarding knowledge is promoted,

Off-Shore Engineer noted that “in 2007, only 1,700 were studying petroleum

recognized and rewarded, the provision of infrastructure and technologies

engineering in 17 U.S. universities, compared with over 11,000 in 34 universi-

to promote collaboration and sharing, and measurement of the benefits of

ties in 1993.”

knowledge sharing. Baby boomers should be actively encouraged to mentor

These articles have viewed the labour-shortage issue primarily from

the next generation.

a body-count perspective, with some focus on the levels of training,

Consideration should also be given to having junior staff serve cogni-

skill and experience required to enter the industry, and the investments

tive apprenticeships (similar to the more traditional craft apprenticeship)

needed to att ract and retain people in the ongoing talent war. In contrast,

with baby boomers before their retirement to spur the timely transfer of

litt le attention has been given to the irreplaceable career’s worth of accu-

the baby boomers’ valuable tacit knowledge assets. As noted in the April

mulated skill, knowledge and experience that each retiring baby boomer

2012 issue of Oilweek, “given the province’s economic growth and its demo-

will take with them.

graphic of retiring workers, the Alberta Competitiveness Council warns the

In simple terms, the labour shortage, when viewed as a body-count issue, considers factors like how many workers are needed, how many workers

impending labour shortage is Alberta’s ‘single greatest’ threat to economic competitiveness.”

there are and how many are retiring. The problem, however, is much more

As indicated earlier, the impending knowledge deficit and the loss of orga-

acute if considered in the context of an organization’s memory comprising

nizational memory due to baby boomers retiring may be just as great a threat

an inventory of its skills, knowledge and experience.

and worthy of similar attention as the labour shortage.

If a retiring baby boomer with, say, a 35-year career is replaced with a

Bryan Leach, P.Eng., is the principal catalyst with Imparando Consulting Ltd. of

person with 10 years’ experience, then the body count remains the same, but

Calgary, a company focused on helping organizations learn. Trained in geology

the organization stands to lose 25 years worth of accumulated skill, know-

and geological engineering, he has lived and practiced in the United Kingdom,

ledge and experience.

Hong Kong, Canada and Italy. He has a certificate in adult and workplace learn-

With 7,000 baby boomers potentially leaving the industry per year, this amounts

ing, and a masters in continuing education, specializing in leadership and devel-

to an annual knowledge deficit of 175,000 person-years of skill, knowledge and

opment in organizations. In 2009 he retired from a 36-year career in consulting

experience—even as they are replaced by less-experienced younger workers.

engineering and set up Imparando Consulting (



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Calroc Industries Inc . . . . . . . . . . inside back cover

FlexSteel Pipeline Technologies Inc . . . . . . . . . . . 6

SMS Equipment Inc . . . . . . . . . . . . . . . . . . . . . . . 20

Canadian Standards Association . . . . . . . . . . . . .11

Gorman-Rupp of Canada Limited . . . . . . . . . . . . 53

Sprung Instant Structures. . . . . . . . . . . . . . . . . . 21

CanElson Drilling Inc . . . . . . . . . . . . . . . . . . . . . . 30

Hazloc Heaters . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Suncor Energy Inc . . . . . . . . . . . . . . . . . . . . . . . . 47

Chevron Delo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Hughson Trucking Inc. . . . . . . . . . . . . . . . . . . . . . 54

Systech Instrumentation Inc . . . . . . . . . . . . . . . . . 7

City of Fort Saskatchewan . . . . . . . . . . . . . . . . .44

Imperial Oil. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Tervita . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Clean Harbors . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Joule Technical Sales Inc . . . . . . . . . . . . . . . . . . .46

TransGas Limited. . . . . . . . . . . . . . . . . . . . . . . . . 56

ClearStream Energy Services . . . . . . . . . . . . . . . 50

MaXfield Inc. . . . . . . . . . . . . . . .outside back cover

Trans Peace Construction (1987) Ltd. . . . . . . . . . 42

Daemar Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . 36

Triland International . . . . . . . . . . . . . . . . . . . . . .46

DFI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

NCS Oilfield Services Canada Inc . . . . . . . . . . . . 39

Vertigo Theatre Society . . . . . . . . . . . . . . . . . . .60

Diversified Glycol Services Inc . . . . . . . . . . . . . . 16

NETZSCH Canada Inc. . . . . . . . . . . . . . . . . . . . . . 49

VJ Pamensky . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Do All Industries Ltd . . . . . . . . . . . . . . . . . . . . . . 37

NRG Process Solutions Ltd . . . . . . . . . . . . . . . . . 54

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Oil & Gas Inquirer November 2012  

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