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OIL OI COUNTRY central entral alberta's tight light oil plays pump neW life into conventional oil industry Wizards of West central alberta

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New industrial cleaning method taking off and paying off in oil fields

F

ive years ago the term dry ice blasting was virtually unheard of in the oil and gas industry. Today, however, the process is rapidly becoming the preferred method of cleaning among the industrial, commercial, utility, and environmental sectors. Regina-based Medius Industrial is now bringing the technology to Saskatchewan oil fields.

So, how does it work? And why is it so quickly replacing previous cleaning techniques?

Dry Ice Blasting at a glance

efficient cleaning and restoration methods. The oil and gas sector, in particular, has seen a spike in the use of this new technology. Because the process allows for equipment to be cleaned hot whilst online, there is no need for disassembly or shutdown. This equates to less downtime and greater profitability. Dry ice blasting is also non-toxic, non-abrasive, non-conductive and environmentally responsible.

BEFORE

Tiny CO2 (ice) pellets are blasted at supersonic speeds through a jet of compressed air at -78 degrees C or -109.3 degrees F. Upon contact with the ice, contaminants shrink and lose adhesion from subsurfaces. The dry ice is then converted back into carbon dioxide gas and evaporates into thin air.

The process effectively and efficiently removes contaminants such as bitumen, corrosion, chemicals, acids, and heavy oils without causing any damage to the underlying surface or creating any secondary waste.

Greater profits The benefits of CO2 blasting are many, leading more and more industries to move away from traditional less

AFTER Photos courtesy of Cold Jet

More versatility Chris Krasowski, General Manager for Medius Industrial says, the possibilities with their dry ice blasting service are virtually limitless, “One of the greatest advantages to our dry ice blasting process is its extreme versatility. Clients can use it to clean piping, wellheads, valves, vessel interiors and, well... pretty much anything they need cleaned.” Those in the oil and gas sector find the system particularly attractive as it reduces the chance of foreign materials such as sand or debris from entering and damaging process equipment.

With oil drilling set to increase by 6% in Saskatchewan during 2012, dry ice blasting will undoubtedly be an option more will be considering.

“After cleaning a surface, dry ice pellets convert back into carbon dioxide gas, which means there’s virtually no residue left behind other than the contaminants removed during cleaning.” - Chris Krasowski, General Manager, Medius Industrial

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oil country

Wizards of west-central alberta

Central alberta’s tight light oil plays pump

Natural gas liquids keep drillers busy

new life into province’s petroleum industry

in deep Basin and foothills

By Darrell Stonehouse

By Darrell Stonehouse

GEnERAl nEwS

31

td securities’ oilfield services outlook still bullish

49 british columbia apache claims big resource at liard Basin

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OIL & GAS INQUIRER • august 2012

9

Editor’s Note

Vol. 24 No. 6 EDITORIAl EdITOR

Darrell Stonehouse | dstonehouse@junewarren-nickles.com

CONTRIbUTING wRITERS

There's no fixing stupid

darrell stonehouse | dstonehouse@junewarren-nickles.com lynda harrison, richard macedo, pat roche, elsie ross EdITORIAL ASSISTANCE MANAGER

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Ken zacharias, cma | kzacharias@junewarren-nickles.com OFFIcES calgary

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new democratic party leader thomas mulcair toured western Canada last month selling his vision of gutting the west’s economy to prop up eastern manufacturers being hurt by a high Canadian dollar.

Mulcair’s theory is that the success of Canada’s petroleum industry in creating wealth, jobs and tax revenues across the country is damaging the economy. What he means, of course, is it’s damaging the Ontario and Quebec economies because his version of the country ends at the 100th meridian. His goal is to save union manufacturing jobs that are being destroyed by a combination of automation and globalization. His strategy is to drive down the Canadian dollar to the point where eastern manufacturers can compete with countries where industry has low labour costs or have invested in capital improvements, making their factories more productive. It’s a fool’s errand as the U.S. market where the vast majority of Canadian manufacturing exports go is stagnant, Europe is in even worse shape and most of the rest of the world either has no money or is competing fiercely for First World dollars.

Driving down the dollar will, of course, make any imports coming into the country much more expensive—something Mulcair seems unconcerned about.

The talk of the New Democrat leader would be meaningless if so many Canadians didn’t agree with him. Nationwide, the New Democrats are polling almost even with the governing Conservatives. It seems there is a big market for economic snake oil among Canada’s masses.

Sadly, western governments or the energy industry can do little to sway the views of the Canadians buying into Muclair’s vision for the country. Attempting to argue with them with facts is futile as they have their own version of the facts. They believe the environmental costs of the oilsands outweigh the economic benefits. They believe piping oil to the west coast is too risky. Fracking for tight oil or shale gas pollutes groundwater.

Empirical evidence is meaningless because anecdotal evidence drives their emotions and their emotions drive their politics.

Economic arguments are also ineffective. Most Canadians live in cities and work in the service economy. They can’t see the connection between their wages and how that wealth is actually generated. As Ken Kowalski used to say, “there are no oil wells in downtown Calgary.”

The wake-up call will come if the New Democrats gain power and Mulcair actually puts the country’s money where his mouth is. There’s nothing like a dose of widespread unemployment, small and large business bankruptcy, and declining asset values to wake people up.

But other than a good hard hit to the nation’s pocketbook, I don’t think there’s any other way to fix the stupid currently gripping a big piece of the land.

subscription inquiries Telephone: 1.866.543.7888 Email: circulation@junewarren-nickles.com Online: junewarren–nickles.com GST Registration Number 826256554RT. 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 40069240.

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.

NE X T

I S S U E

september 2012 Tracking the in situ oilsands producers as they leverage technology to cut costs and pump up production volumes. Plus a look at the southwestern Saskatchewan tight oil boom.

Want to sound off on any content in Oil & Gas Inquirer?

Send your emails to dstonehouse@junewarren-nickles.com.

Please mark them as "letter to the editor" if you want them published.

OIL & GAS INQUIRER • august 2012

11

StatS AT A GLANCE

alberta completions

Wcsb oil & gas completions

Source: Daily oil Bulletin

Source: Daily oil Bulletin

MONtH

OIL

Jul 2011 aug 2011 sep 2011

105 452 1,028

oct 2011 nov 2011 dec 2011

GaS

OIL

Jul 2011 aug 2011 sep 2011

298 922 1,448

97 262 445

904 834 940

oct 2011 sep 2011 nov 2011

1,153 1,448 1,170

35 50 55

381 718 717

dec 2011 feb 2012 mar 2012

127 24 37

671 394 254

apr 2012 may 2012 Jun 2012

t O ta L

43 183 357

97 93 146

245 728 1,531

626 557 568

259 241 300

19 36 72

Jan 2012 feb 2012 mar 2012

215 491 515

131 177 147

apr 2012 may 2012 Jun 2012

403 297 205

141 83 12

GaS

D RY

SERVICE

t O ta L

15 28 24

88 80 155

498 1,292 2,072

321 445 331

20 24 27

49 155 42

1,543 2,072 1,570

988 846 996

359 244 180

27 21 33

115 52 66

1,489 1,153 1,275

608 394 376

192 130 25

31 123 40

157 16 8

988 713 449

Wells drilled in british columbia

saskatchewan completions

Source: b.C. Oil and Gas Commission

Source: Daily oil Bulletin

MONtH

WELLS DRILLED

C U M U L at I V E *

MONtH

OIL

GaS

OtHER

tOtaL

Jul 2011 aug 2011 sep 2011

56 40 92

479 519 611

Jul 2011 aug 2011 sep 2011

185 413 352

5 2 4

3 13 29

193 428 385

oct 2011 nov 2011 dec 2011

35 92 58

646 738 796

oct 2011 nov 2011 dec 2011

457 524 332

29 4 4

46 32 61

532 560 397

Jan 2012 feb 2012 mar 2012

53 66 39

53 119 158

Jan 2012 feb 2012 mar 2012

142 296 414

10 6 0

8 20 40

160 322 454

apr 2012 may 2012 Jun 2012

86 77 13

244 321 334

apr 2012 may 2012 Jun 2012

172 83 144

0 0 0

49 9 10

221 92 154

*From year toto date * from year date

12

MONtH

OtHER

august 2012 • OIL & GAS INQUIRER

FaSt NUMBERS

574,000

barrels per day

224,000

barrels per day

North dakota Bakken production May 2010.

North dakota Bakken production in May 2012.

Source: State of north Dakota

drilling rig count by province/territory

drilling activity: oil & gas

Western Canada, July 12, 2012 Source: Rig Locator

alberta, July 12, 2012 Source: Daily oil Bulletin

aC t I V E

DOWN

t O ta L

(Per cent of total)

Western Canada alberta

aC t I V E

OIL WELLS

Alberta

June 12

GaS WELLS June 11

June 12

June 11

225

348

573

39%

northwestern alberta

36

32

10

55

british columbia

30

25

55

55%

northeastern alberta

56

46

0

0

manitoba

16

11

27

59%

central alberta

100

128

2

48

saskatchewan

75

59

134

56%

southern alberta

13

10

0

25

346

443

789

44%

total

205

216

12

128

Wc totals

service rig count by province/territory

drilling activity: cbm & bitumen

Western Canada, July 12, 2012 Source: Rig Locator

alberta, July 12, 2012 Source: Daily oil Bulletin

aC t I V E

DOWN

t O ta L

(Per cent of total)

Western Canada alberta

aC t I V E

C Oa L B E D M E t H a N E

Alberta

June 12

June 11

BItUMEN WELLS June 12

June 11

443

315

758

58%

northwestern alberta

0

0

7

6

9

22

31

29%

northeastern alberta

0

0

46

56

15

8

23

65%

central alberta

0

30

47

30

saskatchewan

157

45

202

78%

southern alberta

0

15

0

0

Wc totals

624

390

1,014

62%

total

0

45

100

92

british columbia

manitoba

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Feature

OIL COUNTRY central alberta’s tight light oil plays pump neW life into province’s petroleum industry by darrell Stonehouse How quickly has the tight light oil boom taken hold in central Alberta?

Just four short years ago, there was no tight production from the Cardium formation stretching from north of Calgary to northwest of Edmonton.

By April of last year, the play was producing almost 40,000 barrels per day from a little over 4,000 wells, according to the National Energy Board.

OIL & GAS INQUIRER • august 2012

15

Feature

viKing 3,000

18,000 16,000

saskatchewan alberta producing Well Count

2,000

14,000 12,000

1,500

10,000

1,000

6,000

8,000 4,000

500

2,000

0 1 01

r2

11 20

n Ja

ap

10 20

0 01

o

ct

0

l2

01

Ju

r2

10 20

ap

09

Ja

n

20

o

ct

00

9

9

l2

00

Ju

r2

ap

20

09

08 n

20

Ja

o

ct

00

8

8

l2

00

Ju

r2

20

08

0 ap

n Ja

production (bbls/d)

production (m3/d) and producing Well count

2,500

Source: The NaTioNal eNergy Board

Production from the Viking play stretching from the Saskatchewan border to north of Edmonton has climbed from less than 1,000 barrels per day to over 6,000 barrels in the same time period. And production in the tight Beaverhill Lake/ Slave Point play north of Edmonton has gone from almost nothing to 14,000 barrels per day.

And activity is just beginning. The Alberta Energy Resources Conservation Board expects tight oil production in the province to add another 170,000 barrels per day by 2014.

Much of that production will come from the Cardium, where developers continue fine-tuning drilling and completion programs to optimize production.

Penn West Exploration has approximately 665,000 net acres in the Cardium, making it the biggest player in the massive tight oil play. Current production is around 10,000 barrels of oil equivalent per day from its horizontal drilling program. It had six rigs working the Cardium in the first-quarter drilling at Willesden Green, Alder Flats and West Pembina. The company drilled 28 wells and tied in 36 wells, including an eight-well pad at Willesden Green.

Penn West expects to spend as much as $300 million in the Cardium in 2012, drilling up to 150 horizontal wells.

Like other producers, Penn West is switching to water-based fractures in the play in an attempt to lower costs and raise production.

The success of the water-based systems is being demonstrated by Whitecap Resources Inc. Whitecap has been using the system at its Garrington development since taking it over from Midway Energy Ltd. in April 2012.

“We have fracture stimulated six wells utilizing the foamedwater frac system compared to the hydrocarbon system which was used previously,” Grant Fagerheim, president and chief executive officer, reported to shareholders in an update in late 16

august 2012 • OIL & GAS INQUIRER

June. “The foamed-water frac system has allowed us to reduce completion costs by 36 per cent from $1.1 million to $0.7 million, bringing our total drilling and completion costs to $2.25 million from $2.7 million. Production results continue to meet or exceed our type curve and we have not seen a difference in productivity between the two completion methods. In addition to increased capital efficiencies, we have reduced our average spud-to-on-production time by 42 per cent, from 55 days to 32 days.”

Overall, Whitecap is seeing improved performance across its Cardium assets.

“We are seeing continued success in our Pembina Cardium drilling program from both productivity and cost perspectives,” added Fagerheim. “Our average well productivity IP[30] rates for our 2012 wells to date is 237 barrels of oil equivalent per day [90 per cent oil and natural gas liquids], which is seven per cent above our average type curve expectation of 222 barrels of oil equivalent per day. Costs continue to improve with average drilling costs of $1.3 million and completion costs of $0.8 million using our foam-water frac system, approximately $100,000/well lower than in 2011.”

The carbonates north of Edmonton are also generating plenty of new oil. Penn West has 500,000 net acres in the carbonate in two plays, the Slave Point and the Swan Hills.

North of the town of Slave Lake, Alta., Penn West has grown its output from the Slave Point formation to 6,000 barrels a day from virtually nothing less than two years ago, executive vicepresident and chief operating officer Hilary Foulkes told shareholders at Penn West’s first-quarter conference call. Foulkes said that production would rise to about 8,000 barrels a day by the third quarter.

In the first quarter, Penn West drilled 23 carbonate wells, including 14 dual-laterals, with an average of eight rigs, growing

Feature

beaverhill laKe/slave point 16,000 14,000

slave point Beaverhill lake producing Well Count

2,000 1,500

12,000 10,000 8,000

1,000

6,000 4,000

500

2,000 0 11

m

ay

20

11 20 b fe

no

v

20

10

10 g

au

ay m

20

10 20

10 20 b fe

no

v

20

09

09

au

g

20

09 20 ay

m

b

20

09

0

fe

production (bbls/d)

production (m3/d) and producing Well count

2,500

Source: The NaTioNal eNergy Board

its total horizontal production to more than 7,500 barrels of oil equivalent per day.

“We are just in love with this play,” said Foulkes. “The ability for us to go into the Otter area and do those dual laterals is a huge advantage, and we are going to continue to put a lot of time and money and effort into this.”

Two years into the development, the potential in the carbonates is twice what Penn West initially expected, said company president and chief executive officer Murray Nunns.

“We used to think we had a two- to three-year trajectory; we now believe we have a five- to seven-year-plus trajectory,” he says. “We need to at least maintain the current pace of capital if not increase it by 10, 20, 30 per cent.”

At Swan Hills, Penn West is continuing to selectively develop the most prospective sections of its lease holdings.

In the first quarter, it was active at both East Swan Hills and Virginia Hills.

At Otter, the company is in full-scale development. In the first quarter, it had four rigs drilling mainly dual lateral wells with initial rates in excess of 300 barrels of oil equivalent per day, and the area will account for about 70 per cent of Slave Point capital spending. At Red Earth, appraisal work is largely completed, and Penn West is transitioning into the development phase. Work is currently underway on the expansion of both the crude oil battery at Otter and the gas-handling facility at Red Earth, which will handle both the Otter and Red Earth areas.

At Sawn Lake, more appraisal work is needed but the results are very encouraging, said Foulkes. It drilled six single-leg appraisal wells that it will bring on stream late in the second quarter or early in the third quarter.

“Our confidence in the area is high as our two discovery wells are producing a combined rate of over 500 barrels per day after 12 months,” she said.

Penn West plans to spend $250 million–$300 million on the Slave Point this year and $50 million–$100 million on the Swan Hills carbonates.

Arcan Resources Ltd. is also seeing massive growth in the carbonates. The company reported first-quarter production was up 91 per cent over the previous year to almost 5,000 barrels of oil equivalent per day.

At Virginia Hills, Arcan reported a Beaverhill Lake horizontal well that flowed at over 1,773 barrels of oil equivalent per day for seven days and averaged over 1,200 barrels per day over the first 21 days.

Arcan spent $106.08 million of capital on properties in the first quarter, up from $44.16 million in last year’s period.

The company invested heavily in drilling, building waterflood infrastructure, and equipping and tying in wells. A key expense was the construction of a pipeline through Ethel to Deer Mountain, both located in the Swan Hills area, northwest of Edmonton.

T he company announced it has completed the startup of its recently constructed oil-gathering pipeline in the Ethel area. This new pipeline will pump Arcan’s production from 30 horizontal wells in the Ethel field for processing at the Deer Mountain Unit #2 facility. In addition, Pembina Pipeline Corporation has completed construction on the new Moosehorn pipeline, replacing an older line that had been operating at reduced capacity since it was impacted by severe weather in late 2011. This new infrastructure will enable Arcan to deliver its entire production volume to the Pembina sales terminal via pipeline.

“The start-up of our Ethel pipeline is a significant milestone for Arcan’s field operations,” says new Arcan president Douglas Penner. “Together with Pembina’s Moosehorn project, these two pipeline systems will contribute to lower operating costs OIL & GAS INQUIRER • august 2012

17

Feature

cardium 6,000

40,000 35,000 Cardium production producing Well Count

4,000

30,000 25,000

3,000

20,000

2,000

15,000 10,000

1,000

5,000

0 1 01

r2

11 20

n Ja

ap

10 20

0 01

o

ct

0

l2

01

r2

Ju

10 20

ap

09

Ja

n

20

o

ct

00

9

9

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Ju

r2

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20

09

08 n

20

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8

8

l2

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20

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production (bbls/d)

production (m3/d) and producing Well count

5,000

Source: The NaTioNal eNergy Board

and reduced downtime across both the Deer Mountain Unit and Ethel. The new infrastructure provides the foundation for full field development of this long-life, light oil asset.”

“Having advanced our core Ethel asset from two townships of undeveloped land only a year ago into a strongly producing region with full infrastructure and waterf lood, we are now

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Feature

shifting…to a program of sustainable growth, strengthening our balance sheet and focusing on cost reduction,” says Arcan chief executive officer Ed Gilmet in the company’s first-quarter report to shareholders.

Arcan hopes to bring up to 30 wells on stream in 2012. It has also received approval to expand its waterflood operations at Ethel and is seeing the expected waterflood response from water injection at its Deer Mountain Unit #2, also in the Swan Hills area.

Arcan has now implemented or is nearing approval for waterf lood programs in three separate project areas: Deer Mountain Unit #2, the Morse River Unit and the Ethel Unit.

Like Arcan, Penn West believes waterfloods are the future of tight oil plays across central Alberta.

Penn West’s Foulkes says that enhanced oil recovery (EOR) is a “very, very large part” of the company’s long-term plans for tight oil plays. Penn West already operates 140 waterfloods across Alberta.

“About 25–30 per cent of our production, around 40,000 barrels a day, I believe, comes from secondary recovery,” she says.

“And we know that we have to get more water into the ground sooner on these emerging plays, the Cardium and the carbonates in particular,” says Penn West’s Nunns. “We see this as a very significant piece of our business going forward, the marriage of horizontal technology and EOR technology.”

At Otter, the major focus of current development in the Slave Point carbonate play, the company has already submitted

an application for a waterflood, says Bob Shepherd, senior vicepresident of EOR. “Most of that play looks amenable to waterflood,” he says.

Penn West would like to have water going in the ground by the end of the year or early in the first quarter of 2013 as the beginning of a continuous build-out of a waterflood program in the area, he added. To optimize ultimate recovery, it wants to keep the EOR program within one to two years of the development program.

Anderson Energy Ltd. is looking at a different kind of EOR on its central Alberta oil plays. It is looking to leverage its unprofitable gas in the area as a means to enhance oil recovery.

Anderson recently undertook a computer reservoir simulation of its Garrington field to determine the most appropriate f luid and scheme for enhanced recovery of Cardium oil using horizontal drilling. The study found a gas f lood would be the most economical scheme and could potentially double recovery.

Anderson plans to use its up-hole Edmonton sands gas and/ or Cardium solution gas as an injection fluid to enhance recovery. The earliest injection date would be in the last quarter of 2012, subject to regulatory approval and gas compression installation.

In the first quarter, Anderson completed its first slickwater Cardium frac. This new well was brought on stream April 3, with a first 30-day average rate of about 700 barrels of oil a

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19

Feature

day (65 per cent oil and natural gas liquids). The company is planning to use this technology on future completions.

Regarding its Ferrier Cardium oil pool development, Anderson says four (2.5 net revenue) Cardium horizontal oil wells are on production. The company has expanded its oil battery gas compression system and plans to drill three additional wells in the third quarter of 2012.

Anderson says it has grown its drill-ready net prospect inventory of horizontal Cardium oil wells by 13 per cent

anderson says it has identified a prospect inventory for light oil drilling in the Second White Specks, Viking and Belly River zones in central alberta.

since March 19, to 284 (187 net) locations. Those are at the Garrington, Willesden Green, Ferrier and Pembina fields.

Net prospect inventory has increased as a result of information gained from new discoveries as well as additional farm-in and leasing transactions.

Anderson has completed all of its Cardium facility construction projects. Future wells drilled from the Cardium inventory could be simply connected to the new company-owned infrastructure.

The company is also looking to develop other zones on its central Alberta land. Anderson says it has identified a prospect inventory for light oil drilling in the Second White Specks, Viking and Belly River zones in central Alberta. So far, the company has not drilled any horizontal wells into these horizons.

Many of the wells identified could also be connected to Anderson’s existing Cardium oil infrastructure.

A total of 91 (50 net) horizontal drilling locations have been identified in those Second White Specks, Viking and Belly River zones.

Anderson has 134 (70.6 net) sections of land in the Second White Specks fairway. The drilling inventory for the Second White Specks is based on the company’s interpretation for horizontal oil prospectivity in the silt portion of the Second White Specks.

Industry competitors have drilled and placed on production two horizontal Second White Specks wells offsetting Andersoninterest lands. It will monitor the performance of those wells to analyze the impact on its acreage. Anderson used geological well control and successful industry horizontal oil analogs to identify the prospects in the Viking and Belly River.

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Feature

Wizards

of west-central alberta Natural gas liquids keep drillers busy in deep basin and foothills

By Darrell Stonehouse Canada’s natural gas exploration and development sector is in a state of collapse.

Gas prices have declined from over $10 per gigajoule in November 2008, to a little over $2 per gigajoule in the same month of 2011. The number of gas wells drilled has fallen from a high of over 9,600 in 2007 to only 2,700 in 2011.

The price collapse has put gas producers in survival mode, with companies slashing gas-directed budgets, writing down reserves and, in some cases, looking to sell the company.

But the one bright spot in the natural gas extraction sector is the Deep Basin and foothills of west-central

Alberta, where high liquids content is keeping exploration and production in the black.

Peyto Exploration and Development Corp. is a major operator in the Deep Basin, with over 313,000 net acres in the play. At the company’s year-end conference call, chief operating officer and executive vice-president Scott Robinson said the liquids produced from Deep Basin formations make the play economic at prices as low as $1 per gigajoule. Robinson said the liquids content is 40–60 barrels per million cubic feet of gas from Peyto’s Cardium wells, and 13–18 barrels per million cubic feet in the Notikewin and the Falher formations.

OIL & GAS INQUIRER • august 2012

23

Feature

“Our driest wells would still make over $1.50 per thousand cubic feet if sales gas is at $1 per gigajoule,” Robinson said. “On a typical Cardium horizontal well in Sundance, for instance, if we have deep-cut capacity in place and we can get a 10 per cent reduction in our service costs because of inactivity in the industry, then we still generate something like 30 per cent returns at $1 gas prices.”

Controlling infrastructure also helps make Peyto’s Deep Basin operations economic at low prices. The explorer has five gas plants in the play, along with 1,200 kilometres of pipeline. Operating costs were only $2 per barrel equivalent last year.

Company president and chief executive officer Darren Gee said Peyto is still drilling for gas because its costs are low enough that it is still making money.

“Today we’re bucking the trend because the returns for us are still very strong,” Gee said, citing Peyto’s low cost structure. He suggested the company’s costs are probably about $10 per barrel of oil equivalent lower than the industry average. “Ten dollars a barrel on $50 a barrel of revenue is 20 per cent. That’s the return that most guys are looking for. So when they’re breaking even, we’re making 20 per cent, which is where we are today,” Gee said.

Even with its liquids advantage, however, Peyto is adjusting its capital program in light of the extremely low prices. It shut down operations through spring breakup rather than risk extra 24

august 2012 • OIL & GAS INQUIRER

expenses due to unpredictable spring weather. The timing of Peyto’s 2012 capital program of $400 million–$450 million has been weighted to the later months of 2012 to take advantage of an expected reduction in gas drilling, and therefore reduced service costs.

“Both natural gas prices and service costs will be monitored carefully and this level of capital investment will only be pursued if Peyto’s traditional return objectives can be met,” the company said. With the current disparity between gas and liquids prices, the company plans to focus on its inventory of liquids-rich opportunities as well as profitable, low-risk, facilityenhancement projects. The timing of those projects will be accelerated as much as possible.

In Peyto’s first-quarter conference call, Gee said the persistent low-price environment is forcing the company to get more and more efficient at drilling and producing natural gas.

“We’re just having to adapt to it; we’re getting better at making money at these low levels. When we do see a longer-term increase, we’re very well set up to profit from that,” he said.

The company reported first-quarter production was up 30 per cent to 40,903 barrels of oil equivalent per day. Natural gas liquids made up 10 per cent of its production and realized 92 per cent of the light oil price. The revenue from these liquids was more than sufficient to cover all of Peyto’s cash costs.

Photo: Aaron Parker

drilling in the deep Basin continues due to the high liquid content of the gas.

Feature Peyto has drilled 136 horizontal wells with multistage fracture completions in the Deep Basin since 2009. In that time, drilling times have been reduced by over 30 per cent from an average of 33 days (spud to rig release) down to 23 days. While this normally would have translated into substantial reductions in drilling costs, it has only served to offset the inflation in drilling rig rates and the increased fuel costs that have been driven by higher oil prices. In the present low–gas price environment, fewer wells are being drilled, which should bring lower service rates and allow Peyto to realize the financial gains of these operational efficiencies.

Despite this service rate inflation, a new drilling design has recently been tried that has resulted in measurable cost savings in Peyto’s Cardium play at Sundance. The last four Cardium horizontal wells were drilled using a monobore well design resulting in further reducing drilling times and eliminating some casing costs.

This has lowered average drilling costs for this type of well by over 20 per cent to $2 million.

Tourmaline Oil Corp. also continues to maintain its profitability by focusing on liquids-rich targets in the Deep Basin and foothills. The company has 1.1 million net acres in the Deep Basin.

Tourmaline has been growing its liquids production by refocusing its exploration program, company president and chief executive officer Mike Rose told shareholders at the company’s annual meeting. Liquids production has increased to 7,500 barrels per day (70 per cent condensate) from 3,500 barrels a day in the third quarter of 2011. Rose said he expects liquids production to climb to 10,000 barrels a day by the end of the year and to 15,000 barrels per day in the fourth quarter of 2013.

“And that’s without having to go buy an oil company and dilute shareholders or delve off into a brand new play area with its whole new set of risks,” said Rose.

In the past year, the company has drilled the best wells it has ever drilled in its operated areas, said Rose. Among them were a Falher horizontal well at Kakwa that tested at 25 million cubic per day and a Wilrich horizontal well (#4), also at Kakwa, which tested 19.4 million cubic per day. In addition, a Spirit River–Charlie Lake well tested 875 barrels per day of oil and 1.6 million cubic feet per day of gas, while a Sunrise Montney well tested 18 million cubic feet per day of gas and 700 barrels per day of condensate.

Like Peyto, Tourmaline is focused on lowering operating costs. Its goal for this year is to average $5.25 per barrel of oil equivalent.

Drier gas in the Deep Basin and foothills is also profitable in some instances. Fairborne Energy Ltd. president and chief executive officer Steven VanSickle told shareholders at the company’s annual meeting that the prolific Wilrich formation could explode as companies continue reporting successful exploration of the play.

The Wilrich offers seven to 10 barrels of liquids per million cubic feet, VanSickle said. But because of its high initial production it is economic at current gas prices. Wells in the Wilrich have come on stream at rates as high as 30 million cubic feet per day.

“It does offer up very good finding costs and extremely low onstream costs of just around $8,000 a flowing barrel, so it is economic today,” he said.

Talisman Energy Inc. is in the midst of capturing the value of liquids production from its legacy assets in the Edson area. At Wild River, it has 90,000 net acres and around 1,000 undeveloped drilling locations.

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25

Feature

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august 2012 • OIL & GAS INQUIRER

tourmaline continues expanding its liquids production in the deep Basin.

“We’ve already initiated a shift to liquids-rich gas and oil plays in our legacy positions in Canada,” Paul Smith, Talisman’s executive vice-president for North America, told shareholders at the company’s investor days in Toronto. “We are executing the Wild River project to deliver up to 150 million cubic feet a day to a midstream deep-cut processing plant expected to be on stream by the end of 2013. This plant will allow us to take our average liquids yield from 10 barrels [per] million cubic feet a day to over 70 barrels per million cubic feet a day when that plant comes online at the end of next year, and will allow us to enjoy the benefits of over 10,000 barrels per day of the liquid stream by the end of next year from our Wild River assets.

“The ethane stream, which comes as part of the product from the deep-cut facility, has been sold under an attractive long-term supply agreement with Dow Chemicals in the industrial heartland of Alberta,” he added. “Our recent strategy work shows that our liquids-rich gas inventory in the Greater Edson area has an unrisked exposure of potentially up to 900 million barrels of oil equivalent with nearly 2,000 drilling locations already identified and providing a platform for significant liquids growth.”

Talisman is also focused on what could be the biggest liquids play of them all, the Duvernay, where the company has over 360,000 net acres of land. Smith said Talisman currently has two wells on production in the play and plans to drill six wells by the end of the year.

“Industry results to date have been encouraging with 12 wells released to date,” Smith said. “The average liquids yields

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Feature have been in the range of 50–300 barrels of condensate per million cubic feet with further upside likely through the processing of the wet gas stream. Our first two wells, which we’ve drilled and indeed completed in the north, have been very encouraging, and we’ll be completing our third well post-breakup before moving to the southern end of the play to drill and complete a further three wells.”

Encana Corporation shares Talisman’s optimism about the Duvernay. The company has around 400,000 acres in the play and plans to drill 10 wells in 2012.

“These Duvernay shales are considered to be the primary source rock for the Leduc, Slave Point and Keg River Reef pinnacle pools,” said Mike McAllister, executive vice-president and acting president of the Canadian division, during Encana’s investor day.

“The Duvernay is one of the largest single-sourced hydrocarbon systems in the world, having been a key source rock for the Canadian oilsands and many conventional plays, including the historic Leduc #1 discovery well.

“The vast majority of our land is in the gas condensate window,” he added.

Five horizontal wells have been drilled to date with another five horizontals planned during the second half of the year.

“Initial results have been very encouraging, as they’ve confirmed our initial reservoir interpretations of net pay, porosity, pressures and, most importantly, the liquids content,” McAllister said. “Our current appraisal of the Duvernay play indicates a huge resource of 8.7 billion barrels of oil equivalent on our lands with a more than 20-year drilling inventory.”

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tel: 403.209.3502 | email: sheri@jobsite123.ca The Duvernay also benefits from being located in an area of Alberta with legacy, underutilized infrastructure.

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“Although the Duvernay is in its early days of evaluation, we are very encouraged by initial results. We have a direct line of sight to reducing costs and moving the Duvernay from an emerging play to a key major resource play for Encana.”

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by Pat Roche A year ago, a TD Securities analyst said the outlook for the Canadian oilfield services sector was “so bright, I gotta have shades.”

Roger Serin based his strong growth prediction on the increasing number of deep and long horizontal wells, foreign investment in Canadian oil and gas, and the shift to oil targets using new drilling and completion technologies.

But since then, natural gas prices plunged to a decade low, and more recently oil prices have fallen significantly, too.

So when Scott Treadwell, TD Securities’ oilfield services analyst, addressed the annual Petroleum Services Association of Canada (PSAC) investor conference, his message was more subdued. But he still sees reasons for optimism.

“Last year, Roger used the title ‘The future’s so bright, I got to wear shades.’ I went into my ’80s LP collection and pulled out a great Corey Hart classic, ‘Sunglasses At Night,’” Treadwell joked.

“I don’t think it’s quite that dark,” he added.

Last year, Serin gave the top seven reasons why TD is bullish about oilfield services. This year, Treadwell still sees reasons to be bullish, “with an asterisk, sort of.”

“A lot of the same topics are still here in play,” he said. “But there’s probably been a little bit of realism injected into this and obviously some downside from commodity prices and resulting cash flows.”

Summing up his 2012 out look, Treadwell said, “Instead of ‘the future is so bright,’ we say, ‘the sun will come out tomorrow.’”

The oilfield services analyst describes TD’s drilling forecast as, “slightly more pessimistic than some that [are] out there. We’re calling for 11,500 wells this year—although we are calling for a continuing increase in days per well, so that should offset a lot of impact for some service companies.”

For 2013, TD is forecasting 12,250 wells, but Treadwell cautions this depends on commodity prices. “If things stay the way they are, it stands to reason that there are going to be some downsides there.”

Treadwell discussed six factors affecting the oilfield services sector.

oil exploration and development should keep service companies busy, says td securities.

Well licences: Given the number of well licences issued so far this year, he expects western Canada will end up with somewhere around 12,000 wells drilled in 2012.

He said the question then becomes how the typically slow summer drilling season will unfold: Will it plummet like in 2009, or maintain a nice steady pace as in 2010 and 2011?

“Our sense is obviously we’re going to drill fewer wells than 2010…but we certainly don’t think it looks like 2009,” Treadwell said.

Land sales: “In the last two years we have seen producers spend in the order of $4 billion on land purchases in western Canada. This year, we’re down 50 per cent, year to date, on the land sales,” he said.

“If that continues, we’ll spend $2 billion less than we did in 2011 and 2010. If the current pace continues and we don’t see an uptick in the back half of the year, it could be as much as $3 billion less.”

However, he said land prices look like they might be picking up. He noted land prices are driven by light oil plays in Saskatchewan and by the prospect of liquefied natural gas exports in British Columbia.

“But in Alberta, the last two years have been marked by specific plays driving the bus. Two years ago, it was the Cardium and the Alberta Bakken. Last year, it was the Duvernay,” he said.

Treadwell is unsure whether there’s another play with enough momentum to drive Alberta land prices this year.

He said the carbonates “certainly look interesting,” but, “I’m not sure that’s enough,” to raise the volume and value of Alberta land sales to the level of the past two years.

Technology and new play types: The play types continue to change. The big positives are the Bakken, Viking and Cardium. Obviously the big negative is shallow gas.

The number of frac stages per horizontal wellbore continues to increase.

OIL & GAS INQUIRER • august 2012

31

General News

A bias to oil and natural gas liquids continues. “This was a hugely positive topic last year. I think the shine has come off slightly,” said Treadwell. Gas—once the dominant target in western Canadian drilling—now represents only about 20 per cent of wells licensed.

Impact of natural gas liquids (NGL) production on pricing: Increased production of natural gas liquids has hurt prices.

Treadwell said U.S. NGL production is now about two million barrels a day, up 10 per cent year over year and more than double 2009 output.

“There’s, obviously, impact on pricing,” he said, noting various NGL prices have dropped by an average of 28 per cent since May 1.

He ac k nowledged some of t h is decrease is in conjunction with the drop in the price of West Texas Intermediate oil.

“Where last year NGLs were seen as a bit of a rescue for dry gas wells that had marginal economics…the shine seems to have come off of some of these,” Treadwell said, but added this doesn’t have the same impact on wells with better economics.

Joint ventures: “Less noise on this than we certainly saw a year ago. But joint ventures are still very much a source of funds…whether it’s in Canada or the U.S.,” said Treadwell.

He believes L NG contracts need more booked reser ves, wh ic h w i l l require more drilling.

“If you’re going to deliver however many billion cubic feet a day to Kitimat or Prince Rupert, you’re going to need multiple trillion cubic feet of booked reser ves. A nd that may cause more [joint ventures] and more deal flow to occur here in the short to medium term,” Treadwell suggested.

“I think the question that would probably be most germane here is: Will the low gas prices mean that people will go out and buy rather than drill for reserves?” he argued.

He predicts the latter.

“I think, largely, producers tend to like to have things done their way. Buying reserves, buying resource—there’s always a little bit of mistrust there: Are the numbers actually what they think they are?” he said. “Due diligence gets you some of the way there. But I think there’s much more comfort with drilling to book the reserve than there is with buying.”

This would be good news for oilfield services. Treadwell expects the Horn River Basin, for example, will generate some capital announcements, “probably by 2013.”

U.S. pressure pumping: The supply/ demand balance was disrupted by low gas prices, which destroyed demand for dry gas, which in turn hurt demand for drygas fracture stimulation equipment.

Slickwater fracs used in dry gas plays are typically huge in tonnage and require massive horsepower. Generally speaking,

NGL and oil tend to respond better to smaller, gel-based fracs that require less horsepower, Treadwell said.

“Oil works more in the early days. You don’t have eight, 10, 20 well pads that pressure pumpers can sit on for weeks at a time,” he added. “So you need more driving time.

Chances are you don’t need on-site maintenance…. So you’re likely losing two to three days a month of potential utilization.”

And so the U.S. market is oversupplied with pressure-pumping equipment.

Treadwell said the U.S. pressurepumping market is very different from the same sector in Canada in that it has a number of “marginal players” who got into the business five or six years ago, probably funded by private equity.

“They probably tripled their money if they worked in the Haynesville or the Eagle Ford, the Permian or any of the big shale plays in the last three or four years,” he said.

“They’re now probably concerned just about cash costs. They’re probably not worried about long-term viability of the industry. They’re not worried about [gaining] market share. They just want to pay their bills.”

At the same time, “we think the larger players are going to start to be more flat in their outlook,” he predicted. These companies are, in effect, saying, “‘Things are not getting worse; we just don’t know how they’re going to get materially better.’”

rail, pipeline expansions moving trapped oil out of west While pipelines will continue to be the dominant mode of transportation for crude oil, transport by rail is expected to increase sharply in the short term, says the Canadian Association of Petroleum Producers (CAPP).

“Growing conventional, oil shale and oilsands production has created an urgent need for additional transportation infrastructure,” says the association in its annual crude oil forecast released early this summer. A number of projects, including new pipelines, expansions or modifications to existing infrastructure have been proposed to address the issue, but it will take a few years for that to be built, it points out. In the short term, crude oil transport by rail will increase 32

august 2012 • OIL & GAS INQUIRER

sharply due to the ability to add rail capacity relatively quickly and in small increments as needed and to use the rail infrastructure already in place.

Rail exports from North Dakota rose to about 225,000 barrels per day in March 2012 from about 50,000 barrels per day in March 2011, according to estimates from the North Dakota Pipeline Authority.

Transportation by rail of crude oil production originating from western Canada is also growing. It is comparatively small—about 20,000 barrels per day last year—but is beginning to account for a larger proportion of the crude oil transportation than it historically has held, says CAPP. The existing rail network has access to the Pacific,

Atlantic and Gulf coasts and eastern Canada. Test trains have been sent to California, Texas and Louisiana. The rail industry also has proposed the option of using heated rail cars to transport bitumen that could then be blended to specifications at terminals near the destination refineries.

Enbridge Inc. is proposing to enhance its North Dakota crude oil system by upgrading and expanding its current facilities in Berthold, N.D., to connect into a rail-car loading facility south of its existing Berthold Station.

According to StatsCanada, about 8,823 rail cars (706,647 tonnes) were loaded in March 2012 for transporting fuel oils and crude petroleum, compared

General News

to 5,602 rail cars (458,696 tonnes) in March 2011. Transporting crude by rail requires capital investment in new loading terminals that must also have corresponding unloading terminals at the destination centre, says the study.

“Rail-car supply is tight and it takes about a year to put new rail cars into service,” it adds.

The potential for constraints in transportation capacity is currently one of the oil industry’s major concerns, according to CAPP. The association forecasts that total Canadian production, including the oilsands, will climb to 3.8 million barrels a day in 2015 and to 4.7 million barrels a day in 2020. With the resurgence in conventional plays through the use of horizontal drilling and multistage fracturing, anticipated production is 1.3 million barrels a day in 2015, up from 1.1 million barrels a day in 2011 and is expected to grow until at least 2017. Higher-than-forecast oilsands production is forecast to average 2.3 million barrels a day in 2015 and 3.2 million barrels a day in 2020, up from 1.6 million barrels a day in 2011.

“The forecasted higher growth in supply for western Canadian crude oil has resulted in increased awareness regarding the potential for pipeline constraints,” says CAPP. Although the largest market for western Canadian crude has traditionally been the U.S. Midwest, future production growth requires Canadian producers to look to extend their reach and serve new markets, it says. “Avoiding constraints in transportation capacity to markets is essential to a well-functioning crude oil market.”

Transportation out of western Canada is provided by four major pipelines directly connected to the Canadian supply hubs at Edmonton and Hardisty, Alta.: the Enbridge Mainline, Kinder Morgan’s Trans Mountain and Express Pipeline, and TransCanada Corporation’s Keystone Pipeline. They provide total capacity of 3.5 million barrels per day with an additional 1.93 million barrels a day of proposed additional capacity between now and 2017.

Existing capacity is currently constrained somewhat by the available takeaway capacity of connecting downstream pipelines. Capacity was further affected in 2011 and early 2012 by short-term disruptions and pressure restrictions.

— dAILY OIL bULLETIN

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General News

tight cash flow could kill some operators, says essential If it did little else, the global credit crisis of 2009 underscored the need for oilfield service companies to track their accounts receivable while monitoring their corporate customers’ financial health.

During its annual meeting, shareholders of Essential Energy Services Ltd. heard the company’s approach to accounts receivable changed for good with the credit crisis, as management began paying more attention to their customers—the producers that are driving some of Canada’s biggest oil and gas plays.

In particular, the precarious financial health of a few natural gas producers came up during a question-and-answer session, when a shareholder asked if Essential was concerned about the growing number of junior producers experiencing cash flow issues while gas prices hover at or near record lows.

When the dust finally clears, Essential’s top executive conceded the list of western Canada’s gas producers might look quite different a year from now than it does today.

“There’s a very real possibility there are [producers]—names we all know— that could hit the wall this year and disappear,” Garnet Amundson, Essential’s president, chief executive officer and director, told shareholders in Calgary.

“We’re obviously cheering for, and hoping for, our natural gas customers to do well.”

— garnet amundson, essential’s president, chief executive officer

Those at risk include gas-weighted companies that put themselves up for sale as part of a “strategic alternatives” scenario, but closed no deals as a result.

While expressing hope that “it doesn’t

come to that,” Amundson said his staff is nevertheless keenly aware of just which producers are weathering serious cash flow troubles.

“We’re obviously cheering for, and hoping for, our natural gas customers to do well,” he added. “The difficulty they have today is they need oilfield services to do work to continue their cash flow, but we’ll have a judgment call to make on whether they’re able to pay the bills.”

Since 2009, he said there’s been better and more open dialogue between service companies like Essential and western Canada’s producers. That has allowed the company to clearly outline its expectations for customers and to know the extent of its own exposure at any given point in time.

“I think the good gas companies are very open to that, and we’ll continue to work with them. But anyone who starts masking, hiding or [is] not willing to share their financial distress or circumstances— that makes us a little more nervous.”

— dAILY OIL bULLETIN

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British Columbia

apache claims big resource at liard basin

by Richard Macedo

With 48 trillion cubic feet of gas in place on its lands, apache says the liard Basin is the best

Photo: Joey Podlubny

shale play in the world.

Apache Corporation said in June it has validated a new shale play in the Liard Basin in northern British Columbia.

Net estimated sales gas is 48 trillion cubic feet of natural gas (eight billion barrels of oil equivalent) across 430,000 acres held with a 100 per cent working interest. The resource estimate at Liard is based on recent drilling, test results and earlier well control points, the company said on June 14.

“The D-34-K well is one of the best shale wells we’ve seen in any play,” said Steven Farris, Apache’s chairman and chief executive officer. “Our analysis indicates that the formation characteristics are remarkably consistent across the basin.”

According to the company’s investor day presentation on the D-34-K, the horizontal well had a vertical depth of 12,600 feet, and a lateral length of 2,900 feet

with six frac stages. The 30-day initial production rate was 21.3 million cubic feet (mmcf) per day, 3.6 mmcf per day per frac and estimated ultimate recovery is 17.9 billion cubic feet.

It’s believed to be the most prolific shale gas resource test in the world, the company stated.

In terms of the commercial outlook for the Liard, infrastructure already exists. All Apache wells are connected to a sales gas pipeline, there’s access to major incremental infrastructure, it’s connected to the North American gas market and will have access to Asia Pacific via liquefied natural gas.

“Like all gas prospects, it is challenged by gas prices,” John Bedingfield, vice-president of exploration and new ventures, told the investor-day audience.

“What’s really critical here is recognition of this resource.

“This is, in my view, certainly in my estimation, the best shale gas reservoir in the world, certainly from a performance perspective.”

This was the first time the company has spoken publicly about Liard, he added.

The development model includes pad drilling with 12 wells per pad; 600-metre, inter-well spacing; two rigs drilling per pad with 110–120 drill days per well.

“We’re not going to jump into the development on this right away, but it’s a tremendous resource,” Bedingfield said. “What we’re doing now here is we’re drilling tenure wells to hold the acreage together.”

According to a recent B.C. government report, the Liard Basin and Fold Belt region, which straddles the borders of the Northwest Territories and Yukon with British Columbia, remains a relatively unexplored area situated on the eastern margin of the Cordilleran Fold and Thrust Belt.

In northeastern British Columbia, the region covers an area of approximately 1.25 million hectares and contains over five kilometres of sedimentary strata of Cambrian to Upper Cretaceous age.

Potential hydrocarbon objectives occur in the Devonian Dunedin/Nahanni formation, the Mississippian Banff, Debolt and Mattson formations, the PermoPennsylvanian Kindle and Fantasque formations, the Triassic Toad formation, and the Cretaceous Chinkeh and Scatter formations. The Nahanni holds significant potential in dolomitized reservoirs in the structural belt.

The Debolt, Mattson, Kindle, Fantasque, and possibly the Triassic Grayling a nd Toad for mat ions, a re potential objectives in structural closures on the Bovie Lake structure on the margin of the basin. The Banff and Debolt formations are also potential

british columbia Well activity Well liCeNCes

JUN/11

JUN/12

92

86

▼

Wells spudded

JUN/11

JUN/12

46

17

▼

Wells drilled

JUN/11

JUN/12

35

16

▼

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • august 2012

37

British Columbia

objectives in stratigraphic traps on the platform to the east.

In 2009, the most significant land sale in the Liard Basin happened at the July 15 disposition, where land brokers purchased seven drilling licences for $31.3 million on 46,258 hectares. The purchased parcels were

located just north of the Patry area at 94-O12 and 94-O-13. At the Jun. 23, 2010, rights disposition, 14 licences were purchased to the northwest and southwest of the Patry area totalling $110.4 million on 66,645 hectares.

The report added that well activity in the area indicates that Apache Canada Ltd.

drilled two experimental vertical wells in 2010, one of which was rig released in late December at D-34-K/94-O-5. The D-34-K well lists the Upper Devonian Fort Simpson as the projected formation. There were no Petroleum and Natural Gas Rights sales in the Liard Basin in 2011.

artek has years of growth ahead at inga Artek Exploration Ltd. plans to drill up to four wells in the second half of the year as it continues to pursue its high-impact growth oil/condensate-rich natural gas play at Inga/Fireweed.

“It’s a key play for us,” Darryl Metcalfe, president and chief executive officer, told the company’s recent annual meeting. “It happens to be one of the best return projects out there right now.”

per gigajoule for gas and $100 per barrel for oil, the return on investment is between 115 per cent and 215 per cent.

Artek has 41 (25 net) sections of Doig rights and a 60 per cent operated facility that was expanded to 16 million cubic feet per day in November of last year. With 48 (29 net) mapped horizontal locations at three horizontal wells per section, Artek has a Doig inventory of more than five

artek has been increasing the number of fracs per well, which has resulted in a test of 2,520 barrels equivalent per day, including 1,700 barrels of condensate per day, from 14 fractures on its sixth well in the area.

Artek is seeing ratios of 200-plus barrels per million cubic feet of 48–50 degree API condensate from the Triassic Doig formation, and it fetches a premium of $5–$7 per barrel above West Texas Intermediate.

The company is basing its assumptions on an all-in cost of $6 million–$7 million per horizontal well and 30-day initial production of 900 barrels of oil equivalent per day (30–35 per cent liquids), with an estimated ultimate recovery of 500,000–800,000 barrels equivalent per well. At a price of $2.50

years. “And we think that’s conservative. We are preparing for long-term growth,” said Metcalfe, whose company recently acquired 44 sections on a new oil/liquids-rich exploration play in the Greater Inga area.

The Inga pool is a 25- to 30-metre thick Doig reservoir defined by 3-D seismic and 10 wells on 21 (15 net) sections of land. Artek has an internal estimate of 12 billion cubic feet of gas and four million barrels of condensate in place per section.

The six horizontal wells (60 per cent working interest) drilled so far have tested

at a gross average of more than 2,150 barrels equivalent per day with an average condensate rate of more than 1,350 barrels per day for an average liquids-rate of more than 290 barrels per million cubic feet. The wells, which cost $6 million– $7 million to drill, pay out from six-and-ahalf to seven months to about a year.

Artek has been increasing the number of fracs per well, which has resulted in a test of 2,520 barrels equivalent per day, including 1,700 barrels of condensate per day, from 14 fractures on its sixth well in the area.

In the Peace River Arch, where current production is 400–500 barrels equivalent per day, Artek has 90 net sections of land.

This year it is focusing on 50 sections of land where it sees Charlie Lake and Montney oils, conventional oils with water above at a depth of 1,100–1,500 metres. The company expects 22–30 horizontal locations.

Artek has already drilled three horizontal Triassic oil wells with average test rates of 250 barrels per day (56 per cent light oil) and has got the water rate down to 800–850 barrels of water per day.

The company also has 82 net sections of land in the Deep Basin but in the near term has no drilling plans, although it will revisit its plans next year.

— dAILY OIL bULLETIN

transcanada to build lng pipeline TransCanada Cor poration has been chosen by Shell Canada Limited and its partners to design, build, own and operate the proposed Coastal GasLink project, an estimated $4-billion pipeline that will transport natural gas from the Montney gas producing region near 38

august 2012 • OIL & GAS INQUIRER

Dawson Creek to the recently announced LNG Canada liquefied natural gas (LNG) export facility near Kitimat, B.C. The LNG Canada project is a joint venture led by Shell, with partners Korea Gas Corporation, Mitsubishi Corporation and PetroChina Company Limited. The

project was officially announced in May. Shell and TransCanada are working toward the execution of definitive agreements on the Coastal GasLink project.

“We look forward to having open and meaningful discussions with aboriginal communities and key stakeholder

British Columbia

g r oup s, i nc lud i ng lo c a l r e side nt s, elected officials and the Government of British Columbia, where we will listen to feedback, build on the positive and seek to address any potential concerns,” said Russ Girling, TransCanada’s president and chief executive officer, in a news release. “Coastal GasLink will add value to British Columbians, particularly Aboriginals and communities along the conceptual route, by creating real jobs, making direct investments in communities during construction and providing economic value for years to come.”

TransCanada currently has approximately 24,000 kilometres of pipelines in operation in western Canada including 240 kilometres of pipelines in service in northeastern British Columbia, with another 125 kilometres of proposed additions either already having received regulatory approval or currently undergoing regulatory review. These pipelines form an integral and growing part of TransCanada’s NOVA Gas Transmission Ltd. (NGTL) System. The company also owns other natural gas pipelines that have been safely operating in British

Columbia for more than 50 years as part of its Foothills pipeline system.

“Business evolves over time and in response to market needs,” said TransCanada spokesman Shawn Howard.

“Coastal GasLink is a large market-driven project, and it makes sense for us to be involved in it. The interconnectivity with the NGTL makes good sense for all stakeholders in our system.”

The potential Coastal GasLink pipeline project includes a receipt point near Dawson Creek, B.C., and a delivery point at the proposed LNG facility near Kitimat.

Natural gas supplies will come from B.C.’s Montney, Horn River and Cordova basins and elsewhere from the Western Canadian Sedimentary Basin. The pipeline length will be 700 kilometres of large-diameter pipe with an initial capacity of over 1.7 billion cubic feet per day.

It is estimated the project will create between 2,000 and 2,500 direct construction jobs over two to three years.

Detailed cost information will be developed following completion of project scoping and planning. The current estimate is approximately $4 billion.

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In addition to the transportation of B.C. natural gas to the West Coast, Coastal GasLink will provide options for shippers to access gas supplies through an interconnection w it h t he NGT L System and the liquid NOVA Inventory Tra n sfer t radi ng hub operated by TransCanada. A proposed contractual extension of TransCanada’s NGTL System using capacity on the Coastal GasLink pipeline, to a point near the community of Vanderhoof, B.C.—about an hour’s drive west of Prince George—will allow NGTL to offer delivery service to its shippers interested in gas transmission service to interconnecting natural gas pipelines serving the West Coast. NGTL expects to elicit interest in and commitments for such service through an openseason process in late 2012.

— dAILY OIL bULLETIN

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Northwestern Alberta/Foothills

rmp energy looking for montney oil

by Lynda harrison

Photo: Joey Podlubny

rMp energy is the latest company targeting the hot Montney oil play.

RMP Energy Inc. has significant natural gas potential at Kaybob and Pine Creek, which it will keep an eye on, but it is focusing on its oil right now for economic reasons, the company’s annual general meeting heard.

The Montney oil fairway is getting all the company’s capital, said John Ferguson, president and chief executive officer.

RMP believes there are more than 400 million barrels in place on that land base of just under 60 net sections, where the company estimates it has around 250 drilling locations and is drilling about 12 wells per year.

The company has 40 locations on the fairway surveyed and ready to go, Ferguson told the meeting.

Wells have been generating netbacks of about $50 per barrel, but with the recent pullback in oil prices that might be around $45 per barrel now; however, they still provide great economics, he said.

So far RMP has drilled 22 wells into its Montney oil play, five of them in the first quarter of this year. Four have been completed this year. A fifth well was not completed until early second-quarter due to an

early spring breakup, and is being flowed back, said Ferguson.

“Obviously, we’re encouraged in what we’re seeing,” he said.

For the remainder of this year it has seven more wells planned in the area and spudded the first of them at the beginning of June.

Infrastructure is in place for the 2012 drilling program: 10 pads are built; pipelines are in the ground; and its new, on-budget, $18.5-million battery has capacity for 2,500 barrels per day of oil and about 10 million cubic feet per day of gas.

The battery has significantly reduced costs, said Ferguson.

Expansion of the battery is expected to accommodate third-party volumes as well as the company’s Ante Creek production.

A recently operational water disposal well is expected to save about $100,000 a month in water disposal and trucking expenses, he added.

Wells cost about $5 million to drill, and through smaller fracs, pad drilling and other reduced costs, RMP believes that number can be reduced to $4.5 million.

The company is also encouraged by its second-quarter acquisition of 12 sections in its Waskahigan-area light oil resource play, the meeting heard.

RMP anticipates spudding a well in the area either late this year or early next year, Ferguson told shareholders.

Another company has drilled a significant well south of RMP’s property that has produced roughly 1,700 barrels of oil equivalent per day on a test, and a Nordegg well to the west of RMP that does not appear as prolific, he said.

“We think they fracked into the Montney, so we think it proved up the Montney for us,” said Ferguson.

A competitor’s vertical well at the northern end of the block has had cumulative production of around 7,000 barrels of oil, he said.

The company also has a six-section block at Ante Creek where it drilled a strat test well for Montney oil and to see if there was an underlying water section, and was encouraged that it did not reach one.

“We then went in and drilled the well horizontal, cleaned it all up, produced it for three days, and after cleanup the well produced 7,200 barrels. That’s very significant,” said Ferguson. It is currently being tied in to Canadian Natural Resources Limited’s system and RMP anticipates that will be done by the fourth quarter.

The company hopes to drill another well at Ante Creek this year.

In partnership with Peyto Exploration and Development Corp., the company also has a play at Pine Creek where a well drilled in the first quarter came on stream in the past few days, but no further drilling is anticipated this year.

A gas play at Ricinus is not getting any capital this year. RMP also has a high-risk exploration play in Saskatchewan at Muddy Creek.

“We’re trying to get somebody else’s money to do some farm-in work there,” said Ferguson.

northWestern alberta/foothills Well activity Well liCeNCes

JUN/11

JUN/12

297

197

▼

Wells spudded

JUN/11

JUN/12

119

113

▼

Wells drilled

JUN/11

JUN/12

73

71

▼

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • august 2012

41

Northwestern Alberta/Foothills

pinecrest production up The company generated a field netback of $71.60 per barrel of oil equivalent before hedging losses, or $69.51 per barrel of oil equivalent after realized hedging losses.

During first-quarter 2012, Pinecrest increased its net acreage by 34 per cent to approx imately 157,893 net acres with an average working interest of 93 per cent compared to the fourth quarter of 2011.

First-quarter 2012 production and transportation costs per barrel declined to $13.82 from $18.04 in the same quarter of 2011, a 24 per cent decrease.

pinecrest has more than 235 net drilling locations in the slave point play.

Pinecrest Energy Inc.’s drilling of nine (8.75 net) wells in its Red Earth area of Alberta has increased first-quarter 2012 production to 3,358 barrels of oil equivalent per day, compared to 753 barrels equivalent per day in the same quarter a year ago.

Initial rates and overall reservoir quality continue to meet the company’s expectations, and these wells will be assigned on average between 210,000 and 250,000 barrels of reserves.

Contributing to Pinecrest’s current production of about 3,500 barrels per day (99 per cent light oil) as of mid-May were four (four net) wells that had been on production for only about two weeks.

42

august 2012 • OIL & GAS INQUIRER

Output was affected by limited access to wellsites as a result of spring breakup.

The four wells are still in the initial cleanup phase, recovering completion f luids, so have not yet reached their expected, stabilized rate.

In addition, the company has two (two net) wells drilled and completed in the first quarter that have not yet been brought on production.

Also during the first quarter of 2012, Pinecrest turned a profit, compared to a loss in the same quarter a year ago.

The company increased funds flow fourfold to $20.27 million from the first quarter of 2011 and by 39 per cent from $14.6 million in the fourth quarter of 2011.

Also during the quarter, the company closed an acquisition in its core area, adding six drilling locations to bring its inventory to more than 235 net Slave Point drilling locations (at four wells per section—435 drilling locations at eight wells per section).

Some first-quarter capital spending was deferred to later in the year to take advantage of anticipated cost savings created by a general slowdown in industry activity because of low natural gas prices. Spending was also deferred to take advantage of the lower cost structure usually associated with summer operations.

P i nec rest is cont i nu i ng w it h it s 2012 forecasted capital program and remains committed to its prev iously stated guidance of achieving year-end production of 5,000 –5,200 barrels of light oil per day.

— dAILY OIL bULLETIN

Photo: Aaron Parker

During first-quarter 2012, Pinecrest increased its net acreage by 34 per cent to approximately 157,893 net acres with an average working interest of 93 per cent.

Northwestern Alberta/Foothills

Photo: Aaron Parker

strategic progresses at steen river Strategic Oil & Gas Ltd. delivered production of 1,631 barrels of oil equivalent per day during the first quarter (85 per cent oil) as compared to 790 barrels per day during the similar period last year.

Combined oil and natural gas liquid sales volumes increased to 1,388 barrels per day, representing a 146 per cent jump, quarter over quarter.

Output from the company ’s 2012 drilling program began to ramp up in mid-March with two new wells on stream. By mid-April, six of the nine wells were on production to boost field production for the month of April to 2,400 barrels per day.

Production for the month of May was expected to be above 2,800 barrels per day (88 per cent oil), with seven of the nine wells on production. The remaining two wells are planned to be on production in the third quarter. The company said it is on track to realize an annualized average production of 2,400 barrels per day in 2012 and an exit rate of 3,000 barrels per day.

Strategic said 13 wells have been drilled at Steen River during the second half of 2011 and the first quarter of 2012, when a nine-well program was executed.

The vertical Keg River well 102/1522, drilled during the fourth quarter of 2011, has produced over 42,000 barrels of oil in five months. Five of the seven wells drilled in the first quarter of this year that are currently on production at Steen River had initial 30-day production rates of 300 barrels per day or higher.

The company said the wells have maintained steady oil rates with no significant decline. Step-out exploratory wells 10-28 and 11-24 have expanded the Keg River and Sulphur Point plays two kilometres to the west and two kilometres to the east of the existing North Marlowe pool.

Strategic said that success in its recent drilling programs has resulted in a large inventory of follow-up drilling locations. The company intends to resume drilling activities in the third quarter of 2012 and expects to drill a minimum of five additional wells before the end of the year.

Additional work at Steen will include the acquisition of follow-up 2-D seismic

data, the extension of all-weather lease roads and the expansion of oil processing facilities.

Plans for further activity are proceeding at Maxhamish. Strategic continues to work closely w it h Legac y Oil + Gas Ltd., its operating partner, to advance this property. It is anticipated that activity will resume in the third quarter.

In 2011, the company acquired a large land position in an emerging oil

play in Amber. Strategic has identified multiple prospective oil zones underlying its lands. Extensive road and pipeline infrastructure exists in the Amber area.

The company said it plans to drill two exploratory wells on these lands beginning in the third quarter.

Strategic noted that it has access to three drilling rigs for the remainder of 2012 with options for continued utilization into 2013.

— dAILY OIL bULLETIN

strategic's first five steen river wells had average 30-day ips of 300 barrels equivalent per day.

OIL & GAS INQUIRER • august 2012

43

Northeastern Alberta

ercb nixes e-t energy project

by Elsie Ross

the erCB says e-t energy must demonstrate the effectiveness of its technology before launching

Photo: Joey Podlubny

a commercial development.

Management of a private Calgary-based company will be considering other alternatives after the Energ y Resources Conservation Board (ERCB) turned down its application for a commercial in situ project in the Athabasca oilsands that would use an electrical current to heat the bitumen.

E-T Energy Ltd. said that in light of the decision, the timing of the results from an ongoing field test and weak capital markets, it might consider a smaller project building upon the existing Step 3 field test surface assets of the electro-thermal dynamic stripping process (ET-DSP) at Poplar Creek.

“We’re really comfortable that with the 10,000 barrels a day the economies of scale are there at that level…. I think we’d have to really sharpen our pencils at something smaller,” Peter Johanson, chief financial officer, said.

In its decision, the ERCB found that based on the limited production data

available to date it was of the view that E-T Energy has not demonstrated that the proprietary ET-DSP process is capable of obtaining or sustaining commercial bitumen production rates. The board encouraged E-T Energy to continue testing the technology and noted that its decision does not preclude the company from reapplying as future performance data from Step 3 demonstrates commercial viability.

The company initiated the application process with the board in July 2009, requesting approval for a 10,000-barrelper-day commercial project at Poplar Creek, where it has a 100 per cent working interest in 16.5 contiguous sections of land immediately north of Fort McMurray, Alta., outside of the surface minable area.

The application included data from E-T Energy’s previous field-testing of ET-DSP but did not include the results of

the current field test, the most significant test the company has undertaken to date.

In January of this year, the company commissioned the 250-barrel-per-day Step 3 field test, which is intended to allow more definitive heat and material balances to be determined. Test results are expected to be available late this year.

E-T said it has had several discussions with the ERCB and has responded to several rounds of supplemental information requests, with the last formal submission to the board on March 5.

Management said it accepts the ERCB’s assessment and looks forward to re-filing a commercial application for the 10,000-barrel-per-day commercial project as more data from Step 3 becomes available. The recovery factor and the energy/ oil ratio required to produce bitumen will not be established until later this year or early next year, said the company.

E-T Energy believes there is great potential for the technology, which can access stranded bitumen resources at depths between 50 and 150 metres—too deep to mine but too shallow for other in situ methods, said Johanson. A screen

by McDaniel & Associates Consultants Ltd. estimated that the Alberta oilsands has 150 billion barrels of oil in place that would fit into that range, he said.

In 2007, E-T Energy conducted a proofof-concept pilot that included 13 wells consisting of nine electrode and four extraction wells to a depth of 95 metres (not including sensor wells). Surface facilities consist of an above-ground piping system that leads from the wellheads to a tank and treatment system capable of processing up to 1,000 barrels per day of bitumen, producing a marketable bitumen product that is blended with diluent and trucked to market. The bitumen product has been sand- and emulsion-free and has minimum pipeline specifications.

northeastern alberta Well activity Well liCeNCes

JUN/11

JUN/12

69

95

▲

Wells spudded

JUN/11

JUN/12

78

140

▲

Wells drilled

JUN/11

JUN/12

68

146

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • august 2012

45

Northeastern Alberta

In 2010, the company completed extensive field testing (Step 2 field test) to demonstrate the reliabilit y of newly designed electrodes and subsurface electrical connections after it encountered failure rates in the 75 per cent range in some early field trials. Step 2 achieved failure rates of less than five per cent.

“We are really excited about this technology,” said Johanson. E-T Energy has

licensed the established technology from McMillan-McGee Corp., which uses it in remediating contaminated soil.

It produces essentially no on-site greenhouse gas or other emissions, has no freshwater requirements and lower overall water usage. Total E&P Canada Ltd. is also closely watching the results, and last year provided $2 million for field testing.

The company also received $6.86 million

from the Climate Change and Emissions Management Corporation as part of its clean energy funding.

E-T Energy said ET-DSP, with its simple process and limited surface facilities, results in low capital and operating costs that would make projects economic at lower oil prices.

There also would be limited surface disturbance with reclamation beginning within three years of initial project development.

industry, labour unions work on skilled worker shortages Canada’s Building Trades Unions and the Canadian Association of Petroleum Producers (CAPP) have announced a joint agreement to advance the long-term competitiveness of the oilsands industry with a particular focus on the development of a stronger skilled trades workforce.

Under the CAPP–Building Trades agreement, the two organizations will promote careers in skilled trades and work with governments on initiatives to improve workforce availability, including workforce mobility, skilled trades training and apprenticeship opportunities, and immigration.

“Ensuring Canada has a strong skilled trades workforce benefits all Canadians,” Dave Collyer, CAPP president, said in a news release, noting that the oilsands is the largest employer of skilled trades workers in Canada.

“We need to work jointly to attract more Canadians into the skilled trades, provide more classroom and employment-based training opportunities, improve incentives to move within Canada for work, and as needed, increase both permanent and temporary immigration,” he said. “More skilled people who are mobile, certified and ready to work is a win-win.”

Canada’s oilsands industry provides more than 200 million work hours annually for 14 unions with locals from coast to coast, said Robert Blakely, director of Canadian affairs for the Building and Construction Trades Department. “Ongoing responsible oilsands development is our goal, working with the industry to ensure Canada has the skilled people needed to grow our economy over the next several decades.”

46

august 2012 • OIL & GAS INQUIRER

According to the most recent forec a s t b y t h e f e de r a l g o v e r n m e nt ’s C on s t r uc t ion Se c tor C ou nc i l, const r uction employ ment w ill increase by 180,000 jobs by 2018, while about 200,000 sk illed trades workers w ill retire. A lthough about 170,000 new ent ra nt s a re e x pec ted, a 20 0,0 0 0 worker gap is forecast. Worker shortages have inf lationar y implications,

“Canada’s skilled trades labour unions train 80 per cent of construction apprentices, including 40,000 trained annually in concert with the oilsands industry and our employer partners.”

— robert blakely, director of canadian affairs for the building and construction trades department

including cost increases for construct ion projects and increased project execution risk, and could affect the industry’s ability to attract investment.

Cheryl Knight, executive director and chief executive officer of the Petroleum Human Resources Council of Canada, also warned that the oilsands sector will be especially hard hit as they also are experiencing age-relation attrition.

“Canada’s skilled trades labour unions train 80 per cent of construction apprentices, including 40,000 trained annually in concert with the oilsands industry and our employer partners,” said Blakely.

“With cooperation between oilsands companies and unions, oilsands will be Canada’s skilled trades–training superhighway, deliver good-paying jobs, the next generation of skilled trades people and grow our economy.”

The industry is already working with educational institutions, starting at the high school level, to encourage students to look at careers in the trades, said Travis Davies, a CAPP spokesman. It also has relationships with technical institutes across the country as well as universities in every province. And while the first priority of oilsands companies will always be Canadian workers, the industry also needs to be able to bring in temporary foreign workers in the short term when needed, he said.

CAPP and Canada’s Building Trades Unions recently launched an featuring Larry Matychuk from the United Association of Pipefitters and Martyn Piper from the United Brotherhood of Carpenters. The ad is one of several initiatives to build awareness of employment opportunities and the important role skilled trades people play in the Canadian economy.

The North America–wide Building and Construction Trades Department coordinates activities and provides resources to 15 affiliated trade unions in the construction, maintenance and fabrication industries. In Canada, it represents 500,000 skilled trades workers.

— dAILY OIL bULLETIN

Northeastern Alberta

Japan will buy bitumen from export pipeline, says official

Photo: Joey Podlubny

In a further sign of growing Asian suppor t for A lber ta’s oilsands sector, a senior Japanese government official said in Calgary that his country’s utility firms would import bitumen from the province in case an export pipeline is built from the land-locked province to the Pacific Coast.

“We have a big appetite for energy and along with bitumen, would also like to import LNG [liquefied natural gas] from British Columbia,” Hirohide Hirai, director of petroleum and natural gas at the Ministry of Economy, Trade and Industry (METI), said in an interview.

Recently, Kinder Morgan approved a C$4.1-billion expansion of its Trans Mountain crude oil pipeline that will more than double capacity of the line to 750,000 barrels per day.

Also, National Energy Board hearings are underway for Enbridge Inc.’s $5-billion Northern Gateway pipeline that will allow

for the transport of 525,000 barrels per day of bitumen from Edmonton to Kitimat, B.C. The proposed Northern Gateway pipeline is facing opposition from several First Nations due to environmental concerns.

An LNG pipeline seems to have more First Nations support, however.

“We view this First Nations opposition as a domestic issue and are hopeful it will be resolved soon,” Hirai said, adding, “Japanese companies have to look at cheap and stable supplies and from that perspective Canadian LNG projects are lucrative for us. The investment climate in Canada is stable and any investments we make here will be stable.”

The geographical proximity of the Canadian Pacific coast—compared with Qatar—is also another favourable factor, Hirai said, indicating the sailing time for an LNG cargo from Kitimat to Tokyo Bay is 10 days, compared with about 20 days from Ras Laffan, Qatar.

Japan wants to see oil and lNg export pipelines built to the west coast.

“Our focus is on the upstream sector and the preference of Japanese firms will be to take Canadian LNG to consumers in Japan, rather than market it in North America,” Hirai said.

He is part of a Japanese delegation that was in Calgary on a two-day visit to launch an energy policy dialogue with Canada to discuss how Japan’s investments could be accelerated in unconventional oil and gas developments in Alberta and British Columbia. The delegation includes other officials from METI, JGC Corporation and Japan Oil, Gas and Metals National Corporation.

“The Canadian prime minister was in Tokyo in March and we discussed cooperation in the energy sector related to regulatory structures and sharing of technology. We feel the Canadian regulatory system could be improved and are willing to assist the Canadian government in case there will be a need,” he said, without elaborating further.

The METI delegation’s visit comes at a time when, flush with cash and a strong yen, Japanese companies and trading houses are on the hunt for overseas hydrocarbon assets and taking equity positions in international oil and gas ventures.

Since January this year, Japanese investments in Canada’s oil and gas sector include a C$602-million commitment by Toyota Tsusho Corporation to Calgarybased Encana Corporation to invest in a coalbed methane project in southern Alberta; Mitsubishi Corp. signing a C$2.9-billion deal with Encana to take 40 per cent interest in its undeveloped Cutbank Ridge assets in British Columbia; and just recently Mitsubishi joining Royal Dutch Shell plc as a 20 per cent partner to develop a 12-million-tonne-per-year LNG complex at Kitimat, B.C. “Asian interest in western Canada’s oil and gas sector has been on the rise since the global economic meltdown of 2008 and there never was a doubt that Japanese firms would sign offtake deals from here,” said Greg Stringham, vice-president of markets and oilsands at the Canadian Association of Petroleum Producers. “Canada is still one of the few countries that still allow upstream access to oil companies, and this is of great significance to the Japanese from an energy-security view.”

— dAILY OIL bULLETIN OIL & GAS INQUIRER • august 2012

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Central Alberta

peyto waits out natural gas glut

by Pat Roche

Photo: Joey Podlubny

separating out liquids from the gas stream will keep peyto in the black until gas prices rise.

Peyto Exploration and Development Corp. will survive low natural gas prices and will be around for a long time into the future, shareholders heard at the company’s annual meeting.

And the company has no intention of selling itself, president and chief executive officer Darren Gee told shareholders.

“We’re not going anywhere. Unlike many companies whose sole goal is to be sold, we don’t need an exit strategy…. We have longlife assets that will last significantly longer

than the rest of the industry,” Gee said. “So time is on our side.”

Peyto claims to have 75 per cent more producing reserves than the average for about 20 of its peers.

“Now that the industry has the technology to unlock even more of these tight sandstone reservoirs in the Alberta Deep Basin, we have even more locations to drill. At last count we had well over 10 years of drilling inventory,” Gee said.

The company says 410 future horizontal well locations are recognized in its independent reserves report for year-end 2011, and it also boasts 527 unbooked horizontal locations.

In an annual meeting presentation that didn’t discuss the company’s specific properties, activities or plans, Gee talked at length about how Peyto claims to outrank other western Canadian producers.

He even argued that Peyto has a different type of shareholder; “one that’s not interested in us doing a quick flip and selling out.”

Commenting on the outlook for Alberta gas prices, Gee acknowledged it will be affected by a myriad of factors. The favourable factors include coal-to-gas switching for power generation, the push to use methane as a transportation fuel, the steep declines in new production and the potential for LNG exports.

He listed the negatives as the excess amount of gas in storage, the big increase in supply produced by multistage fracturing technology and the possibility that liquefied natural gas exports won’t occur.

Gee expects Alberta gas prices will plateau at around $3.50 a gigajoule pretty soon—once the storage glut created by “the fourth-warmest winter on record,” has been eliminated.

And even though $3.50 “isn’t a great price relative to what we’ve seen over the last decade,” Gee said that’s more like $5.50 per thousand cubic feet equivalent for Peyto because of the high natural gas liquids content in its gas.

He said last year Peyto had an average finding, development and acquisition cost of $2.12 per thousand cubic feet equivalent and cash costs of $1.35 per thousand cubic feet— for a total of $3.47. Subtracted from an average sales price of $5.47, that leaves a profit of $2 or 37 per cent, Gee said.

But even if Alberta gas prices don’t return to $3.50 a gigajoule, Gee argued Peyto will manage because of its low cost structure and its abundance of liquids such as propane, butane and the condensate.

central alberta Well activity Well liCeNCes

JUN/11

JUN/12

312

329

▲

Wells spudded

JUN/11

JUN/12

197

169

▼

Wells drilled

JUN/11

JUN/12

167

158

▼

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • august 2012

49

Central Alberta

fracturing near abandoned wells a concern, says province Hydraulic fracturing in Alberta is generally considered safe except, perhaps, in areas where there are poorly cemented wells that have been abandoned, a recent forum heard.

Groundwater protection—guarding against the possibility of groundwater contamination because of hydraulic fracturing—is a big concern among Alberta’s landowners, said Robert George, a hydrogeologist and a policy adviser with the province’s water policy branch of the Ministry of Environment and Sustainable Resource Development.

“We’ve looked pretty hard at that. We’re pretty sure fractures from 2,000-metre hydraulic fracking operations are not going to migrate upwards to the surface. It’s a very, very low risk,” George told the Petroleum Technology Alliance Canada’s eighth annual Spring Water Forum in Calgary.

But there are thousands of old, abandoned wells in Alberta that are a potential risk due to poor cement if they are adjacent to fracturing operations, and these need to be addressed, he said.

50

august 2012 • OIL & GAS INQUIRER

There are a lot of such wells in the Cardium, and they are potential conduits for fracking fluid if they weren’t cemented very well in the 1950s or 1960s, he added.

“We think those need to be addressed and we will be addressing those risks,” said George, who is working with other Government of Alberta staff on the development of a water conservation policy for the oil and gas industry, and a policy to address hydraulic fracturing issues.

Hydraulic fracturing of shale formations in combination with horizontal drilling over the last decade has raised questions about potential environmental and human health risks, the meeting heard.

According to the Alberta government, about 170,000 wells have been fractured in the province, starting with conventional vertical wells in the 1950s, and about 4,200 wells have been drilled using multistage fracs since 2008. About two-thirds of those wells were drilled in tight oil plays and roughly 70 per cent of wells drilled today are horizontal.

“The ERCB [Alberta’s Energy Resources Conservation Board] has documented there

haven’t been any cases of groundwater being contaminated as a direct result of hydraulic fracturing in Alberta,” said George. “So some of the controversy in other parts of the world doesn’t seem to directly apply to Alberta.

[That] doesn’t mean there are no risks. There are risks associated. Hydraulic fracturing is one of the more risky parts of the oil and gas business, but we don’t see the same level of risk as has been pointed out [in other areas].”

Water use for fracturing operations—a source of controversy—has been reduced substantially in some areas over the past few years thanks to innovations surrounding water sources and recycling, he said. The Alberta government believes research and innovation will solve at least part of the problem.

Groundwater sustainability is important, added George. The scale of the shale gas resources in Alberta are extensive, and if the industry is going to use saline or fresh groundwater, the government needs to look at how sustainable they are and have a better idea of their inventory, he said.

Companies are required to provide fracture fluid information to the ERCB.

Central Alberta

A new approach is needed for areas of full-scale shale gas development.

Coordination of development is going to be essential to reduce costs and user conflicts, he added. There are infrastructure and construction issues, and ecosystem and community impacts will need attention.

The government needs to reduce growing concerns about water quality and potential contamination from chemical additives to fracture fluids such as friction reducers, biocides and scale inhibitors. Industry must lead and collaborate with other stakeholders on water-management plans and infrastructure to minimize development footprints and ecosystem/community impacts, George said.

The Alberta government expects to enhance its regulatory system to address the larger scale and faster pace of shale gas development by expanding programs for groundwater assurance, baseline testing of wells and groundwater inventories, he said.

There will be a greater focus on play-based development planning and outcome-based environmental compliance, George added.

The ERCB is building an unconventional regulatory framework that’s more of a playbased, well-by-well, risk-based set of rules that

depend on collaboration with industry and between industry players, said George, adding that performance measures and public reporting are going to be enhanced among plays where hydraulic fracturing occurs.

Stakeholder engagement is going to be a very big part of play-based development plans, so industry and government are going to have to do a better job of engaging with the public and other stakeholders, said George.

Brent Moore, environmental adviser for Devon Canada Corporation, told the forum the ERCB conducted a study of all the water-well complaints in the province—38,000 of them. Only one well had been impacted by the oil and gas industry, he said, adding it was related to a cementing approach that has since been corrected.

The Canadian Association of Petroleum Producers (CAPP) admits potential contamination of drinking water can occur from methane gas and fracturing fluid chemicals but shale gas is being developed safely in Canada, Tara Payment, CAPP’s manager of water and reclamation, told the forum.

She said there have been about 175,000 wells fractured in British Columbia and Alberta with no evidence of groundwater contamination due to hydraulic fracturing.

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Impacts to water wells due to improper wellbore construction are rare, groundwater protection is regulated at all stages of activity and there are multiple barriers to prevent fluids or gas from migrating from wellbore to aquifers, said Payment.

For example, the typical shale formation is about three kilometres deep while the typical domestic water well is less than 300 metres below surface.

In addition, multiple steel casings are installed and cemented in place and wellbore construction is strictly regulated. Meanwhile, shale rock has low permeability, she added.

CAPP is developing generic procedures for wellbore construction quality assurance. Companies will modify and adopt them, and make them publicly available.

“That’s one requirement of all the practices, is that you make your own company’s practice publicly available, so if a concerned landowner has a question about how you’re meeting the intent of these practices, you should be able to answer them.”

The association is also developing generic procedures for transport, handling, storage and disposal of frac-fluid additives.

— dAILY OIL bULLETIN

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OIL & GAS INQUIRER • august 2012

51

Central Alberta

lng exports raise concerns in alberta

Justin riemer, assistant deputy minister, enterprise division, alberta enterprise and advanced education

Ensuring that Alberta petrochemical producers have access to the growing volumes of natural gas liquids (NGLs) from shale plays in western Canada is critical to the growth of the sector, a petrochemical conference heard early this summer.

“For the first time in decades, feedstocks could fuel a renaissance in Alberta petrochemicals,” said Matthew Foss, acting assistant deputy minister, resource development policy, Alberta Energy. “The opportunity is huge.”

The key to expanding these sectors will be ensuring that the gas liquids are kept within the province or at least be available for that opportunity, he said.

“The question is: are there ways government can get involved that make sense that don’t run afoul of market principals?”

The conference, sponsored by the Canadian Energy Research Institute (CERI), heard concerns that natural gas liquids might be left in gas exported to Asia as liquefied natural gas (LNG) rather than first being extracted.

Foss said petrochemical companies need to be proactive in obtaining their needed feedstock. “It’s in your interests to negotiate a long-term sustainable supply of ethane because once it goes out it is going to be very difficult to find ways to tap that back,” he said. “We are 52

august 2012 • OIL & GAS INQUIRER

already finding that with the Alliance Pipeline [which ships liquids-rich gas to the Chicago, Ill., area].”

Dow Chemical Canada ULC, for one, would be interested in accessing NGLs for feedstock, said Tyler Edgington, associate commercial director. “Depending on where it is, it could be a matter of running it through a processing plant,” he said.

Foss acknowledged there is a value to the ethane in any exported LNG because of the higher heat content.

However, with the wide frac spreads, producers will want to continue to see the value of their liquids achieved by extraction in the field as opposed to being left in the gas stream and shipped via the LNG route to export markets, Graeme Flint, vicepresident, olefins business development, NOVA Chemical Corporation, said in an executive panel discussion. “Although that gas value is high in export markets, we think that when you subtract the cost of getting it there you are going to get a fair value for extracting liquids in Canada and moving those back to markets,” he said.

The higher heat content would require some extraction, likely before it goes on the pipeline, according to Flint.

“What you want to do is try and avoid any transportation or commercial arrangement associated with LNG that results in an economic penalty for extraction of those liquids.”

The industry should not look to the Alberta Energy Resources Conservation Board (ERCB) to regulate the liquid content of gas, said Dan McFadyen, board chairman. Rather, it’s up to the markets to determine the cut.

The ERCB gets involved on a facility basis in applications for opportunities to extract liquids off the common stream, such as in side-streaming or co-streaming, and the appropriate location for extraction in the public interest, he said. “The market has to decide; we are all about fairness.”

For a long time natural gas was the province’s largest revenue stream but the glut of gas and low prices has reduced the economic benefits, Justin Riemer, assistant deputy minister, Enterprise Division, A lb e r t a E nte r pr i se a nd A dv a nced Education, told the conference.

To counter this, the Alberta government needs to work with industry on a strategy focused on creating greater

in-province benefit from natural gas through value-added development, he said. This in turn will create greater demand for gas in the province.

Pet roc hemica l facilit ies prov ide long-term benefits to the region, and Alberta greatly benefits from long-term manufacturing facilities that draw on extraction industries as a source of feedstock, said Riemer.

Petrochemical manufacturing is heavily reliant on high-value feedstock and generates large indirect benefits creating a significant economic multiplier of 7.3, he pointed out. There also are benefits to other provinces, that can source equipment and materials across the country and internationally.

“A lbertans are the owner of the resource, and I think we sometimes forget that,” said Riemer. “We need to be looking at things from an owner’s perspective.”

That means the whole question of market product diversification, which is the central goal within a provincial energy strategy, needs to be looked at along with how governments can facilitate that, he said.

“A lot of questions have been raised about concerns about gas going to the West Coast at the expense of liquids and oil to the West Coast without upgrading,” said Riemer. “We need market access to the East Coast and the West Coast for oil, and we are seeing that happening. We also need to be continually pushing product diversification.”

The Alberta government also needs to consider whether it can play a role in an industry-led NGL markets hub, said Riemer.

“There are a number of layers of complexity around the whole system and we have to try and understand how we can best work through industry to promote that.”

While the government hasn’t yet determined the next steps, it’s something it wants to continue to engage and work with industry on, he said. “Obviously, various industry players along the value chain have different approaches and views on that.”

An ERCB study on Alberta shale gas resources expected to be released this summer will indicate that Alberta is not short of shale resources both in gas and gassy oil, said McFadyen. “That’s going to put the potential for a lot of liquids back into the Alberta marketplace going forward,” he said.

— dAILY OIL bULLETIN

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Southern Alberta

producers continue working to unlock alberta bakken

by Richard Macedo

Photo: Joey Podlubny

the alberta Bakken is in the early exploration stages with producers looking for areas with tight siltstone and over-pressurized formations.

In 2010, the Bakken/Exshaw oil play near the Canada-U.S. border attracted fanfare in Alberta as producers quickly snapped up Crown land, which drew great optimism for its potential.

Two years later, producers are still trying to get a handle on the best way to drill the rocks in that area by using various completion techniques, as well as testing different zones.

The Bakken shale on the Montana side of the Alberta basin and its geological equivalent on the Canadian side, the Exshaw shale, are the same age (late Devonian to early Mississippian) and of similar deposition to the Williston Basin Bakken shale, but are part of a separate geological system.

Canadian-side producers, noted a report earlier this spring by Scotia Capital, include Crescent Point Energy Corp., Canadian Natural Resources Limited, Encana

Corporation, Nexen Inc., ExxonMobil Canada Ltd., Murphy Oil Corporation, Shell Canada Limited, Argosy Energy Inc., Blacksteel Energy Inc., Bowood Energy Inc. (which has since announced a deal with fellow Bakken/Exhaw player Legacy Oil + Gas Inc. [Daily Oil Bulletin, May 14, 2012]), DeeThree Exploration Ltd., Pace Oil & Gas Ltd. and PetroSpirit Resources Ltd. (a private company).

Companies developing the play in the United States include A nschutz E x plorat ion Cor porat ion (pr ivate), Newfield Exploration Company, Quicksilver Resources Inc., Rosetta Resources Inc., Abraxas Petroleum Corporation, Arkanova Energy Corporation, American Eagle Energy Inc., Canadian company Compton Petroleum Corporation, Mountainview Energy Corporation, Passport Energy Ltd., Calgary-based Primary Petroleum Corporation and Stone Energy Corporation.

“The Exshaw formation in Alberta and northern Montana is a dark, organicrich shale—an excellent source rock that has produced much of the oil found in conventional reservoirs in Alberta,” said Brad Hayes, president of Petrel Robertson Consulting Ltd. It is the same age as the Bakken shale in the Williston Basin of Saskatchewan and North Dakota and has many of the same properties. But there are two key attributes of the Bakken that have not been demonstrated yet in the Exshaw, he noted.

“First, the Bakken has a low-permeability sandstone or siltstone bed in the middle that is a great tight oil reservoir, and is the target for horizontal drilling,” Hayes said.

“Secondly, the Bakken is overpressured in the Williston Basin, giving the reservoir more energy to produce oil. We see a tight siltstone in the Exshaw in places, and the small amount of well control suggests over-pressuring to the west, but we haven’t yet demonstrated these factors to be as well developed or extensive as in the Bakken.”

Hayes said that companies exploring the Exshaw in southern Alberta and further down into northern Montana are trying a variety of drilling and completion techniques to improve their understanding of the reservoir and to work out how best to produce it. “ T he best met hods — hor i zont a l length, number of fracs, pressures, proppants, et cetera—may vary from place to place as the reservoir conditions vary,” he noted. “We can’t tell yet whether the Exshaw will be as good as the Bakken.

My guess is that the early signs indicate a more difficult reservoir that won’t be as productive.

“Experienced companies have been working this play for a couple of years now, and the lands are pretty tied up, but we are not seeing a lot of announcements

southern alberta Well activity Well liCeNCes

JUN/11

JUN/12

132

106

▼

Wells spudded

JUN/11

JUN/12

44

29

▼

Wells drilled

JUN/11

JUN/12

27

29

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • august 2012

55

Southern Alberta

of positive results yet,” Hayes added.

“Contrast that with the Duvernay, where we have heard some pretty big flow rates from many of the initial wells.”

But, he noted, there’s “too much money into the Exshaw play to give up on it.”

“I think companies will continue to experiment and assess, although the pace may slow until bigger rewards are realized,” Hayes said.

Rick Morgan, consultant, senior exploration analyst, with Canadian Discovery Ltd., said that in the Williston Basin, geochemical studies indicate that the voluminous hydrocarbons generated have not been expelled from the source rocks, except to occasional porous fractions of the rock immediately overlying (Lodgepole) or underlying (Torquay, Sanish members of the Three Forks) the Bakken.

In Alberta/Montana, the system deepens to the southwest, so the potential for generation in Alberta and Montana is probably about the same.”

He added that the play is still in the early exploration stage.

“T he wells put on production to date have not really been boomers with three of 22 wells reporting February production greater than 100 barrels of oil per day…and the rest below 50 barrels of oil per day,” Morgan said. “The main optimization method to date is the stratigraphic placement of wells in the various zones that make up the Exshaw Petroleum System.

“Murphy has recently announced success by placing wells in the Wabamun/ Big Valley, rather than the Exshaw. This is really the hunt for where the sweet spots

“it’s still early, but we like technically what we are seeing. industry has started to zero in, and we are all converging on a solution."

— trent yanko, legacy oil + gas ltd.

This forms the Bakken Petroleum System, which includes these adjacent zones and contains a tremendous resource in place.

“Presumably, the situation is the same in the Alberta/Montana play to the west, with the Lower Banff, Exshaw, and the Big Valley and Stettler members of the Wabamun comprising an Exshaw Petroleum System,” Morgan said. “In the Williston Basin, the system deepens to the south, so most of the hydrocarbons were generated in North Dakota, and most of the production has been established there.

are. Optimization for effective stimulation programs is just beginning.”

There is currently more production and drilling activity in Alberta than just over the border in Montana, not including Elm Coulee in the Williston Basin of eastern Montana, he added.

TORC Oil & Gas Ltd., a private company, noted in an investor presentation that it has drilled seven successful southern Alberta wells to date, with a 78 per cent success rate (seven of nine). It has over 100 net prospective sections on the primary Monarch play.

DeeThree holds 200,000 acres in the Lethbridge area prospective for the Sunburst and Bakken.

The company reported that a Bakken horizontal well this year on its eastern block had a 30-day initial production rate of 415 barrels per day. A second well flow-tested at 800 barrels per day, while a third and fourth well tested at 940 and 960 barrels per day, respectively. A total of 11 Bakken horizontal wells are to be drilled this year.

Crescent Point has access to a significant land base in southern Alberta and has been pursuing several exploration projects in the area. During the first quarter, it drilled two (two net) wells to follow up on previously drilled unconventional exploration wells in the Alberta Bakken play. The wells are currently being evaluated. Plans for 2012 include drilling up to 19 net conventional and unconventional wells on these lands.

Penn West Petroleum Ltd. has roughly 80 sections in the Alberta Bakken play, noted Jason Fleury, senior manager of investor relations.

“We entered into the play focused on a different horizon which was more conventional in nature,” he said. “While our results to date have been positive, we remain cautiously optimistic; this play is showing itself to be very much acreageand area-specific.”

Trent Yanko, president and chief executive officer of Legacy, said that the Alberta Bakken has the attributes of a light oil resource play, but it is still in the embryonic stage, which is the challenge.

“It’s still early, but we like technically what we are seeing,” he said. “Industry has started to zero in, and we are all converging on a solution.

“A number of our competitors have had very good well results that are starting to

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build, but that’s very typical in these plays.

I think it kind of got overheated initially.

People had these high expectations, but it was something that’s never been tried so it takes a little while.

“We want to stay in it. We want to keep the exposure for Legacy; we want the Bowood shareholders to have a chance to realize the potential they put into it.”

Yanko added that there’s likely going to

be multiple play types and multiple zones.

“It’s all for light oil. A lot of it looks like it’s over-pressured so it has a lot of these things you look for,” he said. “I think the main success today has been in the Big Valley.”

Photo: Joey Podlubny

producers adding gas reserves 1.16 trillion cubic feet of proved gas reserves of 43.36 trillion cubic feet, up reserves from their year-end statements 5.85 per cent from the start of the year.

Success with tight gas plays and in 2011 due to economic factors. Since North American gas prices began fallincreased drilling in liquids-rich gas plays—in concert with horizontal drilling ing in 2008, producers have de-booked and multistage fracturing—boosted over2.77 trillion cubic feet of proved reserves all proved gas reserves. due to economic factors, including 598 bilData shows a record 6.28 trillion of lion cubic feet in 2010, 806.73 billion cubic proved gas reserves were added through feet in 2009 and 201.51 billion cubic feet discoveries and extensions. During 2011, in 2008. only 2,350 of the wells with a final rigA total of 11 companies had more than released status were listed as gas wells, one trillion cubic feet of proved Canadian compared to 4,479 the prior year. gas reserves at the end of 2011.

Meanwhile, the same 166 compaCanada’s largest gas producer during nies reported Canadian production of 2011 was Encana Corporation. The 4.58 trillion cubic feet, indicating a procompany’s proved gas reserves stood at duction replacement rate of 137 per cent 7.07 trillion cubic feet at Dec. 31, 2011, August Expertec ad best for performance Oil & Gas over Inquirer up 4.62 per cent from the start of the year for 2011, the the (6.76 trillion cubic feet). It also produced past decade.

If revisions are x included, CMYK press res pdf: 7.0625” 2.25” 556 billion cubic feet of gas during the year. the production replacement rate for 2011 gas reserves climbed almost six per cent in 2011. climbs to 163 per cent.

Canadian Natural Resources Limited, There is an additional 1/8” bleed included in the tiffthefile.

Besides success with their drilling country’s second-largest gas proIf you use the tiff fileCanada in your publication, pleasebooked put a positive 1 pt blackducer, border around it.gas reserves by Natural gas producers across programs, producers boosted proved were able to more than replace production 4.25 per cent to 4.27 trillion cubic feet at revisions totalling 1.19 trillion cubic feet during 2011 with new reserves, despite a the end of 2011 compared to 4.09 trillion last year, off from 1.22 trillion cubic feet continued drop in the number of gas wells cubic feet at the start. Canadian Natural in 2010, but still the second-highest tally drilled across the country. in the last decade. produced 449 billion cubic feet during Daily Oil Bulletin data on 166 producLow gas prices took a toll on some gas the year. ers indicates year-end 2011 proved gas plays last year as the producers knocked — dAILY OIL bULLETIN

OIL & GAS INQUIRER • august 2012

57

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Saskatchewan

bakken, shaunavon infill drilling can double crescent point’s reserves, says company

by Pat Roche

Photo: Joey Podlubny

infill drilling and waterfloods could add one billion barrels to Crescent point's reserves.

Crescent Point Energy Corp. can double its reserves just through infill drilling at its Shaunavon and Viewfield properties, shareholders heard at the company’s annual meeting.

Crescent Point’s current proved-plusprobable reserves total 496.8 million barrels of oil equivalent. This includes year-end 2011 reserves adjusted for 2012 acquisitions and dispositions, and assumes the closing of the Cutpick Energy Inc. acquisition.

“These two properties—Shaunavon and Viewfield—have the ability, just through simple infill drilling, to double our reserve base as a company,” Crescent Point president, chief executive officer and director Scott Saxberg said.

Referring to the company’s total asset base, he said, “We believe right now— just through infill drilling and some waterf looding on existing assets—we have the potential to add over a billion

barrels of reserves above and beyond our current base.”

He said the company has $16-billion worth of development inventory and more than 7,500 future drilling locations—“all defined by 3-D seismic, geology and engineering.”

Crescent Point—which is 91 per cent oil weighted—is forecasting average 2012 production of 88,500 barrels a day, but has already surpassed that forecast. The company’s first-quarter output averaged a record 90,285 barrels a day.

In the first quarter, the tight-oil producer bagged $1.3-billion worth of acquisitions and is forecasting 2012 exit production of 97,500 barrels a day.

In 2012, the former income trust expects to pay dividends of $900 million, or $2.76 a share. In other words, it expects to pay out roughly 57 per cent of its cash flow to shareholders.

Crescent Point has a 2012 capital budget of $1.25 billion and plans to drill 408 net wells this year.

The company expects to increase production to about 132,500 barrels equivalent per day over the next five years.

That includes raising output from its Saskatchewan Bakken area to 74,000 barrels per day from about 60,000 barrels per day in the first quarter.

Shaunavon production would shoot up to 35,000 barrels per day over the next five years from 18,500 barrels per day in the first quarter. Production from the Viking formation would edge up to 8,000 from 7,000 barrels per day and Swan Hills output would more than double to 6,000 from 2,260 barrels per day.

The company’s other core areas are in North Dakota, southern Alberta and Manitoba.

Saxberg described Crescent Point’s Swan Hills, North Dakota and southern Alberta Viking properties as emerging plays.

“We don’t have a lot of growth in those areas at this stage in this five-year model,” he said. “I think that’s key in the fact that we’re not relying on some new area to grow the next five years…. This model is based on infill drilling—mainly Shaunavon and Bakken—and the growth is mainly going to happen from there— which is low risk and easily achievable.”

He also noted that the plan to grow to 132,500 barrels per day in five years doesn’t include any Bakken or Shaunavon waterf looding impact, and it doesn’t include any additional acquisitions or increased output due to future technology improvements.

“So we have a very low-risk, five-year plan to grow production four to eight per cent per year on a per-share basis for a six to seven per cent dividend,” said Saxberg.

sasKatcheWan Well activity Well liCeNCes

JUN/11

JUN/12

425

368

▼

Wells spudded

JUN/11

JUN/12

311

209

▼

Wells drilled

JUN/11

JUN/12

290

226

▼

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • august 2012

59

Saskatchewan

legacy expects infill drilling and eor to increase spearfish reserves to as high as 200 million barrels.

Technology has played an important role in the growth of Legacy Oil + Gas Inc., as it has grown to an intermediate light oil– focused company in just under three years.

“We do use technology a lot—we work on the drilling side, the completions, our fracking, our production operations,” Trent Yanko, president and chief executive officer, told the company’s annual meeting. “Everything we do, we try to leverage technology.”

Legacy has a group that is second to none when it comes to the application of technology and the creation of new technology, he said. “We are not just the guy inventing it; we actually are very good at applying it.”

The company has not only successfully accumulated an attractive inventory of light oil opportunities, but “are actually very good at going out there and getting it out of the ground.”

Legacy has rebounded with current production of about 16,000 barrels of oil equivalent per day (85 per cent light oil and natural gas liquids), up from about 10,000 barrels per day a year ago when operations were affected by extensive flooding in Manitoba. “We definitely have not missed a step and the momentum continues to build for 2012 and beyond,” said Yanko.

The company has two core assets, southern Alberta (Turner Valley) and the Williston Basin (Saskatchewan, Manitoba and North Dakota). With production of 5,000 barrels per day, Turner Valley accounts for 99 per cent of Legacy’s 60

august 2012 • OIL & GAS INQUIRER

Alberta production while the Williston Basin contributes 11,000 barrels per day.

Legacy has an inventory of more than 1,200 light oil drilling locations representing an eight- to 10-year drilling inventory, shareholders heard. That does not include many emerging plays such as a light oil play at Maxhamish and the Cardium at Turner Valley (where a horizontal multistage frac test well is planned for later this year), along with infill wells in the Bakken.

The 2012 capital budget is $305 million with 83 per cent directed to drilling and completing 123 (96 net) wells. Of those, 95 per cent will be horizontals and 77 per cent of those will be fractured. The average crude quality is 39 degrees API. The company has nearly 500,000 net acres of land, including 4,042 square miles of 3-D seismic coverage used for the exploitation of both conventional and resource plays.

A longer-than-normal reserve life index of 16.2 years provides the sustainability to enable Legacy to continue its rate of growth for the long haul, said Yanko.

At Turner Valley, a large oil in place reservoir (1.3 billion barrels) with only a 12 per cent recovery, the company has identified at least 86 net Rundle horizontal locations with 3-D seismic used to place new wells. The field produces 40 degree API oil with a historical decline rate of less than one per cent.

Legacy also likes the upside with a lot of potential for infill wells. It has drilled

eight infill horizontal wells with seven on production, using a combination of fractured and unfractured completions. Yanko said the company is quite pleased with what it is seeing, and drilling costs have come down dramatically as well results continue to improve.

The Williston Basin is a combination of conventional Mississippian assets (drilled horizontally with no fracs) and resource plays. The resource plays include the Spearfish play in Manitoba and North Dakota along with the Bakken at Stoughton/Heward, Taylorton and Star Valley, and the Torquay at Frys/Antler on the Saskatchewan/Manitoba border.

Legacy originally got into the Spearfish resource play in North Dakota in late 2009 with a land purchase in the state, mapping the trend down from Waskada, Man. It drilled some wells and last year it made an acquisition at Pierson, Man. L egac y li kes t he Spea r f ish play because it is relatively shallow (about 1,000 metres) with horizontal multistage frac wells costing about $1.5 million allin. “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.”

The company began drilling intensively in the area late in 2011 after the f looding in Manitoba had subsided.

Activity has continued into this year with forecast capital spending of about $75 million.

“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-thanexpected results,” said Yanko.

Legacy’s Spearfish wells in Manitoba are achieving much higher initial rates than the Sproule 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.

The Spearfish produces 36 degree API crude with field netbacks of about $70 per barrel, which means payouts of 12 months or under.

Photo: Joey Podlubny

legacy pushes technological envelope

Saskatchewan

“There’s huge running room, huge development drilling upside,” Yanko told the meeting. Legacy has identified 440 net drilling locations in Manitoba and North Dakota of which only 12 per cent are booked.

The Spearfish also offers the potential for infill drilling. EOG Resources, Inc. and Penn West Petroleum Ltd. are drilling 24 wells per section while Legacy is drilling eight wells per section, which can be

“Everything we do, we try to leverage technology.”

— trent yanko, president and chief executive officer

down-spaced to 12 per section. As well, there is waterflood potential. An adjacent waterflood developed in 1993 doubled the recovery factor to 14 per cent from seven per cent, he noted.

Drilling, infill drilling and waterfloods could increase potential Spearfish reserves from 150 million 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 that it believes will add 25 million barrels of light oil reserves. It also has a waterflood at Taylorton that is showing some response, and one at Heward in the Bakken that is showing some remarkable response.

Legacy also has a large land base for its conventional assets, which are sometimes overlooked as everyone focuses on the unconventional, said Yanko. “We have made some very interesting modifications to developing these conventional assets that has led to some very spectacular well results.”

He later explained that the company is just continuing to work those assets. “It’s not just taking what we have been doing for 20 years,” said Yanko. “We continue to look at drilling techniques, completion techniques, spacing.”

Turner Valley, for example, is a conventional field, but Legacy is applying an unconventional completion technique (acid fractures) because the Rundle is a carbonate.

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— dAILY OIL bULLETIN OIL & GAS INQUIRER • august 2012

61

Saskatchewan

petrobakken continues with gas flooding in the bakken PetroBakken Energy Ltd. is continuing to test the concept of using natural gas flooding as an agent for enhanced oil recovery in the Bakken.

Asked about the pros and cons of natural gas flooding versus other methods, John Wright, president and chief executive officer, said the company examined three different tried-and-true concepts to apply in the Bakken.

“We looked at waterflooding, we looked at natural gas flooding and we looked at CO2 flooding,” he told the annual general meeting. “It would appear that CO2 probably is the best technical solution for the Bakken.”

The next best solution appears to be natural gas, while the least effective from a recovery perspective is waterflooding.

“You have to think of the Bakken as an incredibly poor-quality rock, so the ability to actually inject a fluid into it at ratable rates is difficult,” Wright said. “One of the single biggest issues associated with CO2 is that it’s a great fluid to inject into the

reservoir and it’s a horrible fluid to run through your facilities.

“CO2 forms carbonic acid and carbonic acid eats through everything.”

Existing field performance studies indicate gas will be an effective injection fluid. According to the company’s investor presentation, natural gas is less expensive and less corrosive than CO2.

The majority of natural gas will be recovered and sold at a later date, enhancing the full-cycle economics of enhanced oil recovery due to future expected natural gas prices, the company said. “[In the Bakken] when we’re done our primary [recovery], we’re only going to recover 15–17 per cent of the oil in place, which 10 years ago would have been considered a miracle,” Wright said. “The flip side of that is we’re going to leave 83–85 per cent of the oil behind because we don’t have a way to get it out.

“The concept that we’re pushing hard with is natural gas flooding. We’re going to have six pilots going by the end of this year."

OR !

S F NOW N TIO ALE RIP N S C BS 3 O SU /201 12 20

If this cracks the code on the next layer of growth, “we’re off to the races again,” he added.

In its first-quarter report, the company said that the 2012 capital plan was updated as a result of the two asset dispositions and, as previously announced, PetroBakken plans to use a portion of the sales proceeds to increase its capital program by $175 million–$875 million.

The majority of the additional capital spending will be directed toward the Cardium play, and the company expects 2012 exit production rates of between 52,000 and 56,000 barrels of oil equivalent per day.

The company reported first-quarter production, after dispositions, rose 12 per cent to 46,722 barrels per day compared to first-quarter 2011, while the company drilled 68 (47 net) wells.

First-quarter 2012 production weighting was 86 per cent light oil and liquids.

— dAILY OIL bULLETIN

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Saskatchewan

saskatchewan slips in fraser petroleum rankings Manitoba is Canada’s best jurisdiction for oil and gas investment, followed by Saskatchewan and Alberta, according to the Fraser Institute’s Global Petroleum Survey 2012.

Results of the annual survey—based on the opinions of 623 petroleum executives and managers at 529 companies—were released in June. 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.

Globally, the top 10 most attractive jurisdictions in this year’s survey are Oklahoma, Mississippi, Texas, North Dakota, Manitoba, Netherlands, New Mexico, Kansas, Denmark and West Virginia.

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Russia—Eastern Siberia, Libya, Ecuador, Uzbekistan, Argentina—Santa Cruz, Iraq and Russia—other.

Alberta vaulted to 21st from 51st overall, mainly because of improved scores on questions about the regulatory climate.

The Fraser Institute said this suggests respondents approve of plans the government announced in May 2011 to simplify regulatory processes and procedures for oil and gas drilling permits, project development and site remediation.

“Two years ago, Alberta ranked 60th in the world for oil and gas investment, the result of what the industry saw as an unexpected royalty grab by the provincial government,” said Gerry Angevine, the Fraser Institute’s senior economist at its Global Resource Centre and co-author of the survey.

“Today, investors say they are less concerned about regulatory uncertainty, the cost of regulatory compliance, and regulatory duplication and inconsistency,” he said in a press release.

Angevine said the Prairies offer the “clearest, most consistent and most

competitive policies for oil and gas investment in Canada. Through safe and sensible petroleum development, these provinces are paving the way for a prosperous future for Canadians and their families.”

Saskatchewan slipped to No. 2 among Canadian provinces and territories after ranking as the top Canadian jurisdiction in 2011, while Alberta climbed to third from sixth.

While Saskatchewan outperformed Manitoba in some important areas such as fiscal terms, Manitoba improved its scores on questions pertaining to taxation in general, the cost of regulatory compliance and uncertainty over environmental regulation.

Globally, Manitoba ranked f if th out of 147 jurisdictions included in the survey, up from 12th of 135 in 2011, while Saskatchewan fell to 13th from 11th.

British Columbia was ranked the fifth most-attractive Canadian jurisdiction, up from eighth in 2011, while Newfoundland and Labrador dropped to sixth from fifth.

— dAILY OIL bULLETIN

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Saskatchewan

renegade weathers storm

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Renegade Petroleum Ltd. is well positioned to weather the current economic storm with its strong balance sheet and 96 per cent oil weighting, president Michael Erickson told shareholders in June.

W hile some producers are cutting capital budgets amid falling oil prices and unprofitably low natural gas prices, Renegade actually raised its budget in May to $130 million from the initial $76 million.

They plan to drill about 78 (70 net) wells this year. Its focus is the Mississippian plays in southeastern Saskatchewan, the Slave Point multi-frac horizontal play in north-central Alberta and the Dodsland Viking in Saskatchewan.

In the Williston Basin of southeastern Saskatchewan, Renegade’s primary targets are the Mississippian Souris Valley and Frobisher formations. In the first quarter the company drilled four dualleg horizontal wells with average unoptimized 30-day production rates of 130 barrels a day.

“The key to this play is having facilities. You do get a lot of water with your production,” Erickson said. Once Renegade optimized its facility at Crystal Hill, one horizontal well achieved an average 60-day production rate of 160 barrels a day.

“These are conventional open-hole wells that we’re drilling in some higher porosity, higher permeability carbonates,” Erickson said of the dual-leg horizontals.

In Renegade’s conventional Mississippian plays of southeastern Saskatchewan, a singleleg horizontal well costs about $1.1 million to drill, complete and equip, while a dual-leg horizontal costs about $1.35 million. “We don’t have the expensive multi-frac completions,” Erickson pointed out.

On average, these Mississippian pools have about six million to 10 million barrels of oil in place per section, and the pools are typically around four to six sections in size.

“So there’s a lot of oil in place. Recovery factors tend to be around 10–12 per cent,” Erickson said.

After the initial decline, the southeastern Saskatchewan Mississippian single-leg horizontals wells produce “for many, many years,” Erickson said. “As long as you have those facilities, you can very economically produce these wells.”

— dAILY OIL bULLETIN

64

august 2012 • OIL & GAS INQUIRER

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Fast frac isolation, mechanical sleeve shift The coiled tubing running string permits the use of a remarkable, patented, dual-purpose tool that 1) isolates the target zone during the frac and 2) shifts the sliding sleeve open at each stage. This sand-friendly Multistage Unlimited resettable bridge plug eliminates the need for

pump-down plugs and sleeve-shifting balls, cutting time between fracs to only 5 minutes. Fracs are pumped down the coiled tubing/casing annulus (smaller, low-rate fracs can be pumped through the coiled tubing).

Circulation path to the frac zone The circulation path to the frac zone throughout the completion operation provides four important benefits: • It is a means to monitor actual frac-zone pressure in real time for better control of sand placement • It provides a way to manage fluids to reduce water and chemicals consumption up to 50% • It provides quick recovery from screenouts by reverse circulating excess sand out of the well • It enables the use of sand-jet perforating to add stages in blank casing, without tripping out of the hole.

It all adds up to better frac control, lower-cost completions, and lower environmental impact. Call us or visit our website for more information.

Leave nothing behind.

ncsfrac.com

409.925.7160 (US)

403.862.0870 (Canada)

info@ncsfrac.com

©2012, NCS Energy Services, Inc. All rights reserved. Multistage Unlimited, and “Leave nothing behind.” are trademarks of NCS Energy Services, Inc. Patents pending.

Technology News

consortium tests electromagnetic heating technology for oilsands

Photo: Joey Podlubny

electromagnetic heating could replace steam at some oilsands operations.

A technology and energy production consortium has successfully completed initial proof-of-concept testing of a unique oilsands extraction method that has the potential to improve environmental performance and reduce development costs.

The consortium of Laricina Energy Ltd., Nexen Inc., Suncor Energy Inc. and Harris Corporation completed its initial phase testing of the Enhanced Solvent Extraction Incorporating Electromagnetic Heating (ESEIEH—pronounced “easy”) project at Suncor’s Steepbank mine facility north of Fort McMurray, Alta.

The $33-million program is supported by the Climate Change and Emissions Management Corporation (CCEMC) and the test was approved by the Energy Resources Conservation Board.

The test confirms the ability to successfully generate, propagate and distribute electromagnetic heat in an oilsands formation. It also validates the analytical tools and methods used to predict the performance of the process, thereby increasing the consortium’s confidence as it moves to a field pilot next year. While these preliminary results are encouraging, additional

work remains before the commercial viability of the process can be determined.

“ESEIEH is a key project for the CCEMC and Alberta, and offers the potential to reduce greenhouse gas emissions during oilsands production. The ESEIEH team is making excellent progress and we look forward to the upcoming pilot project,” said Eric Newell, chair of the CCEMC.

ESEiEH replaces the need for water by applying Harris’s patent-pending antenna technology to initially heat the oilsands electrically with radio waves.

Approximately 1.6 million barrels per day of crude oil are currently being produced through surface mining and in situ recovery processes in Alberta. In situ processes, including steam assisted gravity drainage and cyclic steam stimulation, now

contribute roughly half of the total daily production from the Canadian oilsands.

Mining and in situ processes use hot water or steam to separate bitumen from the sands, requiring both water and energy.

These two key factors affect environmental performance, and associated capital and operating costs in oilsands development.

ESEIEH replaces the need for water by applying Harris’s patent-pending antenna technology to initially heat the oilsands electrically with radio waves. An oil solvent is then injected to dilute and mobilize the bitumen with minimal energy requirements, so that it can be extracted and transported for further processing. By reducing the energy required and eliminating the need for water, the ESEIEH process is expected to improve environmental performance while providing greater efficiency and versatility in oilsands recovery operations.

The anticipated benefits of ESEIEH technology in oilsands production include: • Reducing greenhouse gas emissions by eliminating fossil fuels to generate steam; • Increasing operating-cost efficiencies through reducing the amount of energy necessary in the extraction process; • Increasing capital and operating-cost efficiencies by removing the need for steam generation and water treatment facilities; • I mprov i ng t he qua l it y of t he extracted oil as a result of using electromagnetic versus steam heating in the extraction process; and • Increasing the amount of oilsands deposits deemed economically viable by reducing the extraction costs— permitting economic access to otherwise stranded oil deposits.

The electromagnetic heating technology was first evaluated and tested in Florida last year and then moved to Fort McMurray for the proof-of-concept field testing. The next phase—an expanded pilot field test—is scheduled to begin in 2013. Some elements of the technology solution may become commercially available prior to the final testing.

OIL & GAS INQUIRER • august 2012

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Technology News

sanjel releases single-trip retrievable ball and seat system

sanjel's new surestack will speed postfracture workover times.

Sa njel Cor porat ion u nvei led it s S U R E s t a c k mu lt i s t a g e f r a c t u r i n g system, the world’s first proven singletr ip f ully retr ievable ball and seat system that requires no milling or drilling, at the Global Petroleum Show in June. This revolutionar y technology will leave the wellbore completely intact with full access for conventional workover tools.

The SUREstackTM multistage isolation system’s innovative technology offers an efficient single-trip retrievable ball and seat system using coiled tubing or jointed pipe. The system provides

operators with an effective alternative to the conventional milling or drilling process while saving up to 40 per cent on post-fracturing workover time. The single-trip retrieval system allows for immediate production and provides unobstructed flow from toe to heel.

“This cutting-edge technolog y is another example of how Sanjel continues to provide leading-edge solutions for the oilfield industry and how our customers can continue to expect the unconventional,” said Ron Gusek, Sanjel’s v ice-president of cor porate engineering.

Aquatech International, a global leader in water purification technology for the industrial and infrastructure markets, unveiled its SMARTMOD™ modular evaporator technology for the oilsands market at the 2012 Global Petroleum Show.

Modular, flexible and redeployable, SMARTMOD is the lowest CAPEX and life cycle cost-evaporator system available

SMARTMOD is also engineered to minimize field installation labour and costs. With its dramatically reduced centre of mass and evaporator weight, the SMARTMOD module and vessels eliminate the need for building a large evaporator building or expensive foundation labour and materials. Its innovative design also reduces freight costs for transportation of the complete system to site.

"the SMaRtMoD provides high-distillate purity, high continuousdistillate production availability and significant reduction in field installation costs of approximately 75 per cent,” — alan daza, vice-president of sales and business development for aquatech

today, says the company. It utilizes vertical tube falling film evaporator design, a proven technology for treating difficult produced water sources. Benefits of SMARTMOD over conventional evaporator systems include 10 per cent lower power consumption. Its multiple section design ensures ASME distillate quality, and online washing allows for continuous distillate production at greater than 70 per cent of design capacity during washing.

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august 2012 • OIL & GAS INQUIRER

“Aquatech is pleased to introduce this new evaporator design, which adds to our industry-leading portfolio of solutions for oil and gas producers, and provides our clients with a unique solution to treat and reuse their produced water. We see a bright future with SMARTMOD in the oilsands market and believe that this technology will further expand our already successful global footprint in produced water treatment,” said Alan Daza,

vice-president of sales and business development for Aquatech.

Steam assisted gravity drainage is an enhanced oil recovery technology for producing heavy crude oil and bitumen. It is an advanced form of steam stimulation where high-pressure steam is injected into the formation, heating the bitumen in the formation, which lowers its viscosity and allows the mixture of bitumen and water from condensed steam to be pumped out.

The liquid that is pumped to the surface is a mixture of oil and water. The mixture is separated to predominantly oil and water fractions in the de-oiling process. The water fraction is sent to the Aquatech system for treatment and reuse in the facility. In addition to the evaporator technology, Aquatech has supplied conventional systems that include walnut shell filters, warm lime softening, afterfilters and ion exchange softening.

Once purified, the produced water is used as feed to the boiler for steam generation and injected into the formation, and the cycle continues.

“Aquatech’s evaporator systems, like SMARTMOD, are an excellent fit for the oilsands market. Whether it’s for produced water or boiler blowdown treatment, the SMARTMOD provides high-distillate purity, high continuousdistillate production availability and significant reduction in field installation costs of approximately 75 per cent,” Daza noted.

Photo: Joey Podlubny

aquatech introduces modular evaporator technology for oilsands

Technology News

eor market to reach $1.3 trillion by 2015 Dependency on oil has spurred worldwide government interest in enhanced oil recovery (EOR) to increase oil production. According to a recent report from energy research publisher SBI, the market for worldwide EOR production will reach $1.3 trillion by 2015.

EOR, also referred to as improved oil recovery or tertiary oil recovery, is most often achieved by injecting a liquid or gas into an oil reservoir, thereby lowering oil viscosity and increasing the amount of oil available for production.

According to the report, some of the more common EOR methods include CO2 -EOR, thermal EOR and chemical EOR; other methods, such as microbial EOR and seismic EOR also hold a strong niche in the EOR market.

“Conventional oil production processes extract only 10–30 per cent of available oil. EOR methods can enhance these recovery rates by an additional five per cent to 20 per cent on average,” said Shelley Carr, publisher of SBI. It is expected that EOR will continue to perform extremely well in the world marketplace; technological challenges, hazy regulations and costly implementation have, in the past, often kept oil

eor can add five to 20 per cent in additional reserves.

companies from using EOR. However, the report finds EOR is quickly becoming more feasible due to rising government interest and investment, new technologies and increased availability of required materials such as CO2.

“The market will continue to grow as more countries begin to see EOR results

and as it becomes more feasible and common to oil producers,” said Carr.

The report, SBI Bulletin: EOR Around the World: Projects and Markets 2009-2015, includes coverage of EOR activity in Iran, Canada, Saudi Arabia, Russia, United States, Angola, United Arab Emirates, Venezuela, Kuwait and many other countries.

Photo: Joey Podlubny

tervita opens new waste-treatment facility Ter v ita Corporation has announced the official opening of its new South Taylor treatment, recover y and disposal facility.

This high-volume, state-of-the-art facility, located 10 kilometres south of Taylor, B.C., will become a premier centre for oilfield waste processing in northeastern British Columbia.

“Oi l a nd ga s compa n ie s i n t he region are look ing for env ironmentally sustainable ways to deal w ith potent ia l ly ha r m f u l wa ste mater ia l s produced at t hei r site s,” Joh n Gibson, Ter v ita president and chief e xe c ut i ve of f ic e r, s a id i n a ne w s relea se. “I n add it ion, gover n ment agencies and local communities have high standards for the proper handling

of waste. We intend to exceed their expectations at our new facility.”

Safety was one of Tervita’s primary considerations both in selecting and preparing the site location. “To ensure safety on the main site access road and minimize truck traffic on local secondary roads, we took specific measures such as widening the access road to provide acceleration and deceleration lanes,” said Gibson.

The South Taylor TRD will employ up to 16 workers from the Peace region and its operational investments will contribute to the community each year. “Our environmental services and facilities not only play a vital role in the oil and gas industry,” Gibson added, “but also help ensure a robust local economy.”

Te r v it a c ont i nue s to i nve s t i n infrastructure in northeastern British Columbia, with two new waste-water treatment facilities in Maxhamish and Mile 103 that were scheduled to be fully operational by the end of June.

Ter vita also maintains a net work of environmental solutions in the area, including other TRD facilities, landfills, salt-water disposal facilities and a waste-transfer station.

By expanding its regional infrastructure, Tervita said it is helping oil and gas companies minimize the costs of waste processing by reducing travel distances to facilities. This lowers transportation costs, enables customers to improve safety, and minimizes traffic, road wear and greenhouse gas emissions.

OIL & GAS INQUIRER • august 2012

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advertisers' index Abacus datagraphics Ltd . . . . . . . . . . . . . . . . . . 36

Ecoquip Rentals & Sales Ltd . . . . . . . . . . . . . . . . 54

Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . .48

Advantage Valve Maintenance Ltd . . . . . . . . . . . 39

Expertec Van Systems Inc. . . . . . . . . . . . . . . . . . 57

Platinum Grover Int. Inc . . . . . . . .inside front cover

Allmand bros Inc . . . . . . . . . . . . . . . . . . . . . . . . . 54

Flexpipe Systems . . . . . . . . . . . . . . . . . . . . . . . .64

Platinum Pumpjack Services Corp . . . . . . . . . . . 21

Annugas Compression Consulting Ltd . . . . . . . .66

General Motors of Canada Ltd . . . . . . . . . . . . . .40

Quinn Contracting Ltd . . . . . . . . . . . . . . . . . . . . . 19

bear Slashing Inc . . . . . . . . . . . . . . . . . . . . . . . . .44

G.L.M. Industries LP. . . . . . . . . . . . . . . . . . . . . . . 51

belzona western Ltd . . . . . . . . . . . . . . . . . . . . . . 22

hazloc heaters . . . . . . . . . . . . . . . . . . . . . . . . . .48

Radafab Oilfield & Industrial Supply Inc . . . 13 & 56

bilton welding and Manufacturing Ltd . . . . . . . . 33

IdE Technologies Ltd . . . . . . . . . . . . . . . . . . . . . . . 8

brews Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

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

brother’s Specialized Coating Systems Ltd . . . . 20

jobsite123.ca . . . . . . . . . . . . . . . . . . . . . . . . 25 & 27

Chemineer, Inc . . . . . . . . . . . . . . . . . . . . . . . . . . .48

Joint Economic development Initiative. . . . . . . . 54

Clean harbors . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Joule Technical Sales Inc . . . . . . . . . . . . . . . . . . . 58

RIdE Inc . . . . . . . . . . . . . . . . . . . . inside back cover Risley Equipment Inc . . . . . . . . . . . . . . . . . . . . . . 22 Silver Fox Completion Services Inc . . . . . . . . . . . 14 Sirius Instrumentation and Controls Inc . . . . . . . 34 SMS Equipment Inc . . . . . . . . . . . . . . . . . . . . . . . 26 Summit Safety Inc . . . . . . . . . . . . . . . . . . . . . . . . 18

ClearStream Energy Services . . . . . . . . . . . . . . . . 4

kubota Canada Ltd . . . . . . . . . . . . . . . . . . . . . . . 35

Compass bending Ltd . . . . . . . . . . . . . . . . . . . . . 14

Lloydminster heavy Oil Show . . . . . . . . . . . . . . . 53

daemar Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

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

dean’s Pump Service Ltd . . . . . . . . . . . . . . . . . . . 18

Medius Industrial. . . . . . . . . . . . . . . . . . . . . . . . . . 5

Trans Peace Construction (1987) Ltd. . . . . . . . . . 39

diversified Glycol Services Inc . . . . . . . . . . . . . . 33

MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . 14

Vertigo Theatre Society . . . . . . . . . . . . . . . . . . . 62

do All Industries Ltd . . . . . . . . . . . . . . . . . . . . . . 50

NCS Oilfield Services Canada Inc . . . . . . . . . . . . 65

Veyance Technologies Inc . . . . . . . . . . . . . . . . . . 61

draeger . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Northgate Industries Ltd. . . . . . . . . . . . . . . . . . . 30

Viking Pump of Canada Inc . . . . . . . . . . . . . . . . . 20

dragon Products . . . . . . . . . . . . . . . . . . . . . 28 & 29

Ocean Fluids & Filtration . . . . . . . . . . . . . . . . . . . 30

V.J. Pamensky Canada Inc . . . . . . . . . . . . . . . . . . 12

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august 2012 • OIL & GAS INQUIRER

TCA Marketing Ltd. . . . . . . . . . . . . . . . . . . . . . . . . 9 TransForce Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

EGRESS SOLUTIONS • No connect/disconnect • Multiple run capability for training and drills • Automatic braking system • Overhead fall arrest connection points • Virtually maintenance free • Rugged design • Light weight and portable • Quick set up time • Fully engineered • Highly adaptable to any elevated platform • User friendly and Internationally accepted

www.rideinc.com

TOGE THE R WE CAN

For over 10 years MaXfield has quietly been gaining the expertise and experience to handle your next project.

From custom vessels to structural steel, piping and modular packaged equipment, MaXfield is now your one-stop shop for industrial fabrication.

w w w. m a x f i e l d . c a