Oil & Gas Inquirer March 2012

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Taking

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Root With shallow gas drilling dead, tight oil plays sprouting in southern Alberta Harvesting heavy oil New technologies focus on getting more heavy crude out of the ground

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Keeping readers regionally informed

F E A T U R E S

14

Taking root

By Darrell Stonehouse The shallow gas窶電rilling boom in southern Alberta is over, but a new tight oil boom is taking shape

23

Harvesting heavy oil

By Darrell Stonehouse Technological changes allow producers to reap more rewards from heavy crude resource

8

M AR C H 2 0 1 2 窶｢ O I L & G A S I N Q U I R E R

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29 PSAC lowers 2012 drilling forecast

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R E G I ON A L

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NE WS

British Columbia

49

• Progress spending $365 million in 2012

Southern Alberta • Crew focused on Princess oil drilling in 2012

37

Northwestern Alberta • Resthaven drives Celtic production

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Saskatchewan • Renegade production up, will spend more in 2012

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Editor’s Note

Darrell Stonehouse | dstonehouse@junewarren-nickles.com

The case for new export markets

Vol. 24 No. 2 editorial Editor

Darrell Stonehouse | dstonehouse@junewarren-nickles.com Contributing writers

Lynda Harrison, Richard Macedo, Pat Roche, Dustin Sundby Editorial ASSISTANCE MANAGER

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Creative Services

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A review of U.S. economic data makes the case for opening up Canadian oil and gas exports outside of North America.

Retail gasoline deliveries in the United States are now at 1980 levels, and 47 per cent below their peak of 67 million gallons per day in 1998. Combined with refinery closures all along the eastern seaboard, this indicates a huge tanking in gasoline demand. With the refinery closures there is a sense that this demand isn’t coming back. Oil demand is on the downward trend in the United States.

Add to this the increased domestic oil production south of the border, and it is easy to understand why the spread between West Texas Intermediate and Brent crude standards is back to over $20 per barrel. North Dakota, alone, has added almost 450,000 barrels per day of production in the last eight years, the equivalent of three average-sized integrated oilsands mines. By 2020, that Bakken production is predicted to climb to 900,000 barrels per day, another three integrated oilsands mines.

In a report released in late January, the U.S. Energy Information Administration (EIA) said it expects U.S. crude oil production to increase by 20 per cent in the next decade. Oil imports are expected to decline from 49 per cent of total supplies to 38 per cent in 2020, meaning less demand for Canadian oil.

The news is equally as grim for Canadian gas exporters. The EIA report predicts the United States will be self-sufficient in natural gas early next decade as production from tight gas and shale gas supplies grows.

Simply put, the traditional market for excess western Canadian oil and gas production is drying up. For the Canadian industry to expand, domestic demand must increase and new export markets are needed.

Canada consumes about 2.2 million barrels of oil per day, with around half of that number light crude oil imported for eastern Canadian refineries. Consumption has been flat for a decade. While many economic nationalists believe western Canadian oil could replace some of that 1.1 million barrels per day imported, it is unlikely to happen.

That leaves exports, either to the U.S. Gulf Coast and onward to international markets, or westward to Pacific Rim countries. Both the Keystone XL and the Northern Gateway are imperative if Canada is to increase production to the five million barrels of oil per day many are predicting in the next decade.

Just as important are the liquefied natural gas terminals, gas-to-liquids plants, and proposals to use more natural gas domestically in power generation and for transportation fuel. The rise of the unconventional gas industry in the United States has cut Canada’s share of North American production from 25 per cent to less than 20 per cent, while Canadian supplies have increased exponentially. Domestic consumption has been flat since 2004.

All these numbers suggest the future of Canada’s petroleum industry lies outside North America. Whether the infrastructure can be built to make this happen is the key challenge facing the country going forward.

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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

April 2012 In the April issue, we look at how midstream producers are working to integrate with the oilsands, develop new gas processing facilities and manage increased liquids supplies. Also a review of the latest in field automation.

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.

FSC logo O I L & G A S I N Q U I R E R • M AR C H 2 0 1 2

11

Stats

AT A GLANCE Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin

MONTH

552

T O TA L

145 294 974

82 127 222

453 774 1,846

Apr 2011 Jun 2011 Jul 2011

419 209 105

472 124 43

112 100 97

1,003 433 245

452 1,028 626

183 357 259

93 146 19

728 1,531 904

557 568 215

241 300 131

36 72 35

834 940 381

MONTH

OIL

GAS

Jan 2011 Feb 2011 Mar 2011

409 723 1,069

201 378 1,081

Apr 2011 Jun 2011 Jul 2011

618 428 298

Aug 2011 Sept 2011 Oct 2011 Nov 2011 Dec 2011 Jan 2012

D RY

SERVICE

T O TA L

33 38 64

17 99 164

660 1,238 2,378

509 197 97

46 12 15

81 183 88

1,254 820 498

922 1,448 1,153

262 445 321

28 24 20

80 155 49

1,292 2,072 1,543

1,170 988 419

331 359 190

27 27 15

42 115 31

1,570 1,489 655

Wells Drilled In British Columbia

Saskatchewan Completions

Source: B.C. Oil and Gas Commission

Source: Daily Oil Bulletin

MONTH

esign for their

OTHER

226 353 650

Nov 2011 Dec 2011 Jan 2012

Run Date:

GAS

Jan 2011 Feb 2011 Mar 2011

Aug 2011 Sept 2011 Oct 2011

28552

OIL

WELLS DRILLED

C U M U L AT I V E *

MONTH

OIL

GAS

TOTAL

Jan 2011 Feb 2011 Mar 2011

62 69 55

62 131 186

Jan 2011 Feb 2011 Mar 2011

136 321 316

4 6 8

3 7 4

143 334 328

Apr 2011 Jun 2011 Jul 2011

41 54 56

172 419 479

Apr 2011 Jun 2011 Jul 2011

183 217 185

11 25 5

11 89 3

205 331 193

Aug 2011 Sept 2011 Oct 2011

40 92 35

519 611 646

Aug 2011 Sept 2011 Oct 2011

413 352 457

2 4 29

13 29 46

428 385 532

Nov 2011 Dec 2011 Jan 2012

92 58 53

738 796 53

Nov 2011 Dec 2011 Jan 2012

524 332 142

4 4 10

32 61 8

560 397 160

*From year toto date * from year date

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OTHER

M AR C H 2 0 1 2 • O I L & G A S I N Q U I R E R

FAST NUMBERS

182

1,092

Number of gas wells permitted in January 2012.

Number of oil wells permitted in January 2012.

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada, February 13, 2012 Source: Rig Locator

Alberta, January 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

GAS WELLS

Jan 12

Jan 11

Jan 12

Jan 11

493

93

586

84%

Northwestern Alberta

91

57

79

73

British Columbia

60

12

72

83%

Northeastern Alberta

35

10

0

0

Manitoba

19

3

22

86%

Central Alberta

59

129

21

30

Saskatchewan

101

11

112

90%

Southern Alberta

30

33

31

46

WC Totals

673

119

792

85%

TOTAL

215

229

131

149

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada, February 13, 2012 Source: Rig Locator

Alberta, January 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

BITUMEN WELLS

Jan 12

Jan 11

Jan 12

Jan 11

511

227

738

69%

Northwestern Alberta

3

1

20

7

British Columbia

36

10

46

78%

Northeastern Alberta

0

0

35

10

Manitoba

22

3

25

88%

Central Alberta

15

9

21

63

Saskatchewan

152

40

192

79%

Southern Alberta

20

4

0

1

WC Totals

721

280

1,001

72%

TOTAL

38

14

76

81

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13

Feature

Taking

Root The shallow gas窶電rilling boom in southern Alberta is over, but a new tight oil boom is taking shape

BY DARRELL STONEHOUSE

14

M AR C H 2 0 1 2 窶｢ O I L & G A S I N Q U I R E R

Feature

Remember 2007?

That year marked the peak of the shallow gas窶電rilling boom in southern Alberta with nearly 5,000 wells drilled and another 2,200 coalbed methane wells punched into the prairie.

Three years later, in 2010, the number of conventional shallow gas wells had declined to a little over 1,200, with coalbed methane wells numbering only 600. And that decline continues to this day with gas producers focused on liquids-rich supplies along the foothills of Alberta and British Columbia. In 2011, only 750 gas wells were drilled in southern Alberta.

The incredible decline in shallow gas drilling has left a gaping void for service and supply companies in the region, as once plentiful work has dried up. But a new cycle of exploration for tight oil resources is on the launch pad and, if successful, promises a rebirth.

O I L & G A S I N Q U I R E R 窶｢ M AR C H 2 0 1 2

15

Photo: Joey Podlubny

Feature

acres of contiguous land in the area.

In the last t wo years, Crew has drilled over 100 horizontal wells in the play, reporting production of over 10,400 barrels of oil equivalent per day. And exploration and development drilling are in early stages, with the company claiming more than 900 future drilling locations mapped out, and plans underway for extensive waterfloods to optimize resource recovery.

In a year-end address to shareholders, Crew Energy president and chief executive officer Dale Shwed said 2011 Crew Energy has drilled over 100 horizontal wells in the Pekisko in the last two years. It has 900 future locations mapped out. was a watershed year for the company in the Pekisko play.

“At Princess, A lberta, for the southern Alberta industry.

Crew drilled 62 horizontal, 45 The Pekisko vertical and 13 salt-water disposal wells, which was our most active The first signs of the tight oil boom can be found at Princess, a year in the area,” he said. “Crew drilled more horizontal wells in tiny ranching community northeast of Brooks, on the hard grass 2011 than the prior three years combined. This record activity level prairie near Dinosaur Park. Crew Energy Inc. is leading the charge has resulted in significant production gains with five additional wells at Princess, exploiting the Pekisko formation on its over 280,000 waiting to be placed on production and 22 wells to be optimized.”

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Feature

Early efforts at enhanced recovery using waterfloods are also positive, he added. “Results at Crew’s initial waterflood at the Pekisko ‛K’ pool have been encouraging. Over the last four months fluid levels in producing wells have risen and production has increased from 25 to 43 barrels per day. This 18-barrel-per-day increase is directionally important, as it represents a 72 per cent increase in production,” he said.

Shwed said Crew would accelerate efforts at Princess in 2012.

Seventy-five wells are planned for the play in 2012, with 87 per cent going horizontal. Around half of wells drilled last year were horizontal. Five new waterfloods are planned, with six more planned for 2013.

Waterfloods will be a key to the long-term success of the play.

Primary recovery is expected to be around 12.5 per cent. Using waterfloods, recoverable reserves are expected to climb over 230 per cent to around 30 per cent of the oil in-place.

Guardian Exploration Inc. is an emerging company targeting the Pekisko near the community of Jenner. In July, Guardian reported the successful acquisition of 3,360 acres from Crown land sales and another 320 acres in a private transaction in the play.

Guardian said it acquired these leases based on a geological evaluation of the area, and production from an offsetting well that has already produced over 35,000 barrels of oil since coming on stream eight months earlier. Some of the acquired land was drilled in the 1980s and early 1990s with vertical wells that economically produced for several years and have since been abandoned. Guardian intends to use horizontal drilling technology to increase both initial production rates and recoverable reserves from these Pekisko pools.

F i s h i n g

An average of eight metres of oil pay and porosities ranging from 10 to 15 per cent are present on Guardian land. The company adds that unlike many of the resource plays being developed around North America, this formation would not require any hydraulic fracturing. This translates to a simpler completion process that involves less risk and is less expensive.

Guardian said its current evaluation has identified a minimum of four well locations. A 3-D seismic program is currently being planned to help identify additional step-out locations, but the initial locations can be drilled with the existing downhole and 2-D seismic data.

Guardian’s Pekisko play is part of a larger effort to develop a tight oil base in southern Alberta and Montana, said company president Graydon Kowal. Guardian has also recently added 1,276 acres around its existing Alberta Bakken position, bringing its total holdings in the play to just over 10,000 acres.

Wells continue to be dr illed and completed next to Guardian lands, primarily by Newfield Exploration and Rosetta Resources. Although no production numbers have yet become publicly available, it is known that Newfield’s Sheriff 1-11H is a producing horizontal well and is only seven miles northwest of Guardian’s Montana lands.

“The Pekisko play in this area has one of the highest investment rates of return in North America,” said Kowal of why the company has targeted the play. “Given the offsetting production and well control on our land, it is exactly what the company was looking for in terms of a low-risk and highly profitable play to complement our exploration lands in Montana. The Alberta Bakken is

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Feature still the primary focus of Guardian, and we continue to watch the activity around us and perform our own research, but developing the Montana asset won’t happen overnight. The Pekisko play will provide a solid foundation from which to build by providing consistent cash flow for years to come.”

The Alberta Bakken While the Pekisko is providing a base for tight oil development in southern Alberta, the Alberta Bakken is the big prize. Analysts estimate there is as much as 13–15 million barrels of oil in-place per section in the play that straddles the Alberta/Montana border.

Murphy Oil Corp. is an early entrant on the Alberta side of the play, drilling six wells so far. In releasing the company’s fourthquarter results for 2012, Murphy president and chief executive officer David Wood said the company is beginning to unravel the Alberta Bakken’s intricacies.

“In southern Alberta, we’ve drilled six wells and wrote off five of them,” he explained. “The sixth well is actually a pretty strong well…its initial production was over 300 barrels per day and has naturally flowed for 42 consecutive days near that level on a small

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M AR C H 2 0 1 2 • O I L & G A S I N Q U I R E R

“ We maintain the productivity potential of the Alberta Bakken is comparable to what we’re seeing in the Williston Basin.” ­— Robert Mercier, president and chief executive officer, Bowood Energy Inc.

choke. It’s high-quality oil, and we are budgeting to drill and complete two more wells…this year with an ongoing review to increase that number based on this recent good news.”

Wood said Murphy originally targeted the Exshaw formation in the Alberta Bakken but it is now targeting the Three Forks after the success of the sixth well.

“It’s not that I don’t think the Exshaw has potential,” he noted.

“A couple of those wells I think gave us some encouragement, but this is a very nice well. And so I think our focus is shifted a little bit here. And I said in our budget, we have a couple of wells. Clearly, given this well result, we’re going to do more drilling there.”

Murphy has over 150,000 acres in the Alberta Bakken. Wood said the strong Three Forks well was originally targeted as the Exshaw but the drilling team changed its strategy during operations.

“When we were drilling this well, we were drilling it for the Exshaw,” he explained. “And we drill it vertically and then the idea is to cut a core in the Exshaw and then turn the well with a [heel-to-toe] horizontal. But we realized when we went into the Three Forks underneath, that was the place with the best shows. And not trying to outsmart ourselves, our guys said, ‘Well, why don’t we float test the one that has the best shows rather than stick with prognosis?’ And as it turned out, the well has been on production 42-plus days.

We choked it back after a few days, and its pressure stayed… actually flat, and has hung in just under 300 barrels a day. So we’re pretty excited about what it means for that particular play, but that wasn’t really the play that we picked up the

Feature acreage for. So we’re in the process of kind of getting all the stuff together, understanding what it means and understanding where we need to be. But we have a pretty nice acreage footprint, and we have a piece of information, I think, that’s important. How important, I think we’ve got to work out, but it’s still early days yet.”

Canadian junior Bowood Energy Inc. is also targeting the Alberta Bakken with partner Legacy Oil + Gas Ltd. Early this year, Bowood reported exploration results from its first two joint exploration wells and updated other industry activity in the fairway. To-date, 85 wells have been licensed and permitted in the play, and 25 wells are currently on production. The recent level of activity in the play continues to be a positive sign from industry that there is significant resource potential in the fairway, the company reported.

Bowood’s first southern Alberta Bakken horizontal well, located at Spring Coulee on Freehold acreage has been completed. The well was drilled directionally to a depth of 2,197 metres with a pilot hole through the Bakken system. Cores were taken in the Second White Specks and in the Bakken petroleum system, including the Lower Banff, the Exshaw and the Big Valley formations. Analysis of the Bakken system core is consistent with company’s expectations, including vitrinite reflectance analysis that indicates that the well is in an area that is optimally located for peak oil generation. The horizontal section of the well was drilled to a 1,230-metre length and completed with a 20-stage hydraulic fracture-stimulation using water-based fluids. Following stimulation, the well was cleaned up for 15 days and recovered approximately half of the injected fracture f luid, together with 1,380 barrels of light oil. At the end of the 15-day cleanup the well was swabtested at a rate of approximately 220 barrels of oil per day at a 65 per cent oil cut. The oil cut increased steadily throughout the cleanup and swab test, as water-based injected load fluid from the fracture stimulation was recovered from the well.

Drilling is also now complete on Bowood’s second Alberta Bakken horizontal well, located at Kipp on the Blood First Nation Reserve. The well had a directional pilot hole drilled through the Bakken system to the Nisku formation. The well was cored in the Second W hite Specks and in the Bakken Petroleum system. The K ipp well was then drilled horizontally to a total measured depth of 3,610 metres and has been equipped for a 20-stage hydraulic fracture-stimulation over the 1,290-metre horizontal section. No results have been released.

Speaking at the recent Small Explorers and Producers Association of Canada investment symposium, Bowood president and chief executive officer Robert Mercier said he believes the Alberta Bakken has the potential to be as big as the main Bakken play in Saskatchewan and Montana.

“We maintain the productivity potential of the Alberta Bakken is comparable to what we’re seeing in the Williston Basin,” said Mercier.

Bowood holds some 110,000 net acres in the Alberta Bakken fairway. Estimated at 25 miles wide by 110 miles long, the Bakken fairway runs roughly north-south, straddling the Canada–U.S. border between Alberta and Montana, Mercier said.

Other producers currently active in the play include Nexen Inc., Penn West Petroleum Ltd., Murphy Oil Company Ltd., Royal Dutch Shell plc, DeeThree Exploration Ltd. and Crescent Point

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Feature

The Alberta Bakken oil play is only one target in the Bakken fairway. The Middle and Upper Banff formations and the Second White Specks are also being targeted.

Energy Corp. According to Mercier, Bowood-Legacy’s joint venture acreage lies at the heart of the fairway.

“It’s an exploration play driven by multistage fracturing technology,” he explained. “We have light oil recovery and where we’re seeing it, it’s between 35 and 40 degrees API.” Yet production results announcements from the play have been sparse.

“One of the reasons there hasn’t been a lot of information released on the southern Alberta fairway is that, of the wells that were classified as confidential, we’re just starting to see some information come out,” said Mercier. “At this point, we have the first five wells coming off confidential.”

With the passing of time, more well data will become available as confidentiality periods expire. To-date, some 87 wells have been drilled in what Mercier terms the Bakken fairway. Of these wells, about one third—36 wells—were drilled in Montana, the rest in Canada. Of the latter, 34 have been rig-released, 27 were horizontal and 20 are classed as producing wells.

In addition to its Bakken light oil potential, Mercier described the fairway as a multi-resource play, since juniors could also see production from the Middle and Upper Banff formations and the Second White Specks. Bowood currently has two fairway wells drilling—both spudded in late October—and planned to license six more on the Blood First Nation’s lands by year-end.

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Feature

Harvesting Technological changes allow producers to reap more rewards from heavy crude resource

Photo: Joey Podlubny

By Darrell Stonehouse

O I L & G A S I N Q U I R E R • M AR C H 2 0 1 2

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Feature

orizontal drilling technologies, enhanced recovery technologies like polymer floods, and thermal recovery techniques are resulting in improved heavy oil recovery in fields across western Canada.

While the improvements haven’t yet stemmed the decline in heavy oil production, government and industry continue investing in new technologies in the hopes of turning around the production curve.

Husky Energy Inc. is at the forefront of the effort to access more heavy oil resources, which are estimated to represent as much as 30 billion barrels in-place.

Speaking at Husky’s recent Investor Day, company president and chief executive Asim Ghosh said the company’s heavy oil business is in a period of transition.

“In the last two decades the principal technology driver for us has been CHOPS, which is an acronym for cold heavy oil production with sand. CHOPS is now a maturing technology, still very profitable, still very productive, but maturing,” he said. “We’ve made significant progress in

the last few years in laying the foundation for the next transition in this basin, which for us is secondarily horizontal wells, but primarily thermal horizontal wells. And we already have two successful thermal projects that are producing now and giving substantial production in that division. But we’ve now progressed construction of two additional thermal projects and we have increased the number of horizontal wells.”

CHOPS currently accounts for 65 per cent of Husky’s heavy oil production of nearly 100,000 barrels per day. Husky is working to up its thermal heavy oil recovery

Rob Peabody, Husky’s chief operating officer, says the company has begun construction on its Pike’s Peak South and Paradise Hill thermal projects, which will start producing this year and reach production of 11,000 barrels per day in 2013.

“This will take our total thermal production to about 30,000 barrels per day in that year,” he said. “At the same time, we increased our horizontal well–drilling programs, where production has reached about 5,000 barrels per day, today, and is expected to reach around 15,000 barrels per day by the end of the planned period [2016].”

“ CHOPS is now a maturing technology, still very profitable, still very productive, but maturing.”

— Asim Ghosh, president and chief executive officer, Husky Energy Inc.

to 35,000 barrels per day by 2016. It also expects to add 15,000 barrels per day in the same time period through horizontal drilling.

In 2012, it plans to spend $800 million in its heavy oil unit on two thermal recovery projects, along with drilling 250 CHOPS wells and 150 horizontal wells.

Further ahead, Husky is looking at enhanced recovery projects to maintain production in existing fields.

“We’re also progressing a number of solvent EOR [enhanced oil recovery] projects to sustain our long-term production. This is one of a number of technologies that we

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M AR C H 2 0 1 2 • O I L & G A S I N Q U I R E R

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Feature

Solvent-based EOR is being used to turn on the taps at heavy oil developments.

Thermal projects around Lloydminster are expected to add 30,000 barrels per day to Husky production.

Heavy oil plays in northwestern Alberta are also testing thermal recovery methods.

are developing to increase production from our CHOPS production base,” says Peabody.

“We have four cold EOR pilots operating, and in 2011 we completed a project to recover the CO2 from our ethanol plant in Lloydminster. And the CO2 is one of the solvents we use in these cold EOR projects.”

While Husky works to maintain its existing heavy oil production, a number of other producers are looking to grow production.

BlackPearl Resources Inc. is using a mix of existing technologies including

conventional drilling, thermal recovery and solvent floods to exploit its heavy oil resources stretching across Alberta and into Saskatchewan.

“Over the last three years we have grown production from 5,000 to 10,000 barrels of oil per day,” BlackPearl president John Festival said in Januar y.

“However, 2012 will be the start of a transition period for BlackPearl, as we have now set the stage for growth to 30,000 barrels of oil per day by 2016, as we bring on our thermal project.”

BlackPearl is targeting part of its Onion Lake properties for thermal development using steam assisted gravity drainage (SAGD) technology, common in the oilsands. Festival says the majority of the 80 million barrels of contingent resource at Onion Lake can be targeted w it h SAGD. Black Pearl is targeting areas with net pay zones greater than 15 metres for SAGD development. It expects to recover 50–70 per cent of the oil in place compared to five to eight per cent through conventional methods.

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Feature

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Heavy oil production in Saskatchewan has declined by 36,000 barrels per day from 2005 to 2010. A major research project is underway to keep storage tanks full in the future.

In January, Festival said the company had slowed its conventional drilling program at Onion Lake while awaiting approval of its SAGD project.

“This will allow us time to drill the horizontal wells that will be used when we transition to SAGD development,” said

and water, Festival reported in November.

“We encountered minor problems with some of the surface facilities during the start-up phase, but these issues have been resolved and we have been continuously injecting for over three months. The objective is to initially re-pressurize the reservoir, after

Successful microbial applications to depressurized, non-producing wells are anticipated to create incremental revenue of $1.7 million–$3.4 million per well, over five years.

Festival. “Drilling the horizontal wells before further conventional development occurs will reduce the risk associated with drilling in a partially depleted reservoir. We have filed an application with regulatory authorities for a 12,000-barrelper-day SAGD project. Upon approval, expected in the first half of 2012, we will immediately commence drilling up to 14 horizontal wells, which will be used as oil producers when SAGD operations begins.”

At Mooney in northwestern Alberta, BlackPearl is using horizontal wells for primary production while introducing an ASP (Alkali, Surfactant, Polymer) flood to increase recovery of the 37 million barrels of contingent resource.

“Phase 1 of the ASP flood began in July, with the initial injection of chemicals 26

M AR C H 2 0 1 2 • O I L & G A S I N Q U I R E R

which we would expect to see response through increased oil production. It is expected to take six to 12 months to repressurize the reservoir, and then an additional six to 12 months to reach peak production rates of between 3,000 and 4,000 barrels of oil per day. Construction of t he heav y oil bat ter y to handle increased fluid volumes is ongoing and we expect to have the facility in operation by mid-2012.”

In January, Festival said successful exploration had extended the Mooney play to the west, “which will eventually lead to an expansion of our ASP flood.”

While producers adapt existing technologies to improve heavy oil recovery, researchers are focused on new tools to keep the oil flowing.

In Saskatchewan, heavy oil production declined by 36,000 barrels per day from 2005 to 2010. The provincial and federal governments recently announced they were funding a unique project using microbes in an effort to increase production and recover more resource. The Petroleum Technology Research Centre and the University of Regina are doing the work.

Microbial EOR works by natural bacteria changing the chemical composition or characteristics of oil in the ground.

For example, some microbes might react in the reservoir and create gases such as methane, which are solvents that act to improve the viscosity of the oil, allowing it to flow to production wells more easily.

Microbial EOR is in its early stages but is being investigated as a means to pump more oil from existing reserves that are in decline. This preliminary work will characterize nutrients that occur naturally in Saskatchewan, and help determine how they might interact with certain microbes of interest. It is essential before the largerscale field tests and deployment of the technology can occur.

Successful microbial applications to depressurized, non-producing wells are anticipated to create incremental revenue of $1.7 million–$3.4 million per well, over five years.

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General News

PSAC lowers 2012 drilling forecast

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By Richard Macedo

PSAC has lowered its 2012 forecast by 11 per cent, or 1,700 wells.

The Petroleum Services Association of Canada (PSAC) has lowered its 2012 drilling forecast, blaming weak natural gas prices and labour shortages for the downgrade.

In its first update to the 2012 drilling forecast, PSAC reduced its forecasted number of wells drilled across Canada to 13,350 wells. This is a drop of 1,700 (or 11 per cent) from its original 2012 forecast released in early November 2011. However, this still represents an increase of four per cent over final 2011 drilling levels of a total of 12,917 wells drilled across Canada.

PSAC is basing its updated 2012 forecast on average natural gas prices of $3.25 per thousand cubic feet at AECO and crude oil prices of US$90 per barrel, West Texas Intermediate, and the Canadian dollar averaging 97 cents.

On a prov incial basis for 2012, PSAC now estimates 8,267 wells will be drilled in Alberta, a rise of two per cent over final 2011 drilling numbers. British Columbia is forecast to have 640 wells drilled in 2012, a three per cent rise from last year. Saskatchewan’s drilling

rate this year will climb by six per cent over last year to 3,739 wells and drilling in Manitoba will climb 14 per cent to 665.

“Due to skilled labour shortages, warm weather hampering the use of heav y equipment, wea k gas pr ices related to oversupply and the ongoing uncertainty created by the European economic debt crisis, we are seeing restricted capacity across the board,” Ma rk Sa l keld, president a nd c h ief executive officer of PSAC, said. “While PSAC’s current forecast may well be short of the 20,000-plus well counts we were forecasting only a few years ago, the complexity and depth of current wells will keep our industry well ahead of meet ing t he inc reasing dema nd for oil.”

PSAC expects to release its mid-year update on April 25.

“We are optimistic that our forecast update at the mid-year point will show relative stability from our now updated forecast of 13,350 wells, though we will still be feeling the effects of balmy weather and a labour shortage that is

not going away,” Salkeld added. “We are looking at new ways of presenting the forecast numbers, to tie them more directly to the costs of drilling in various formations across the Western Canadian Sedimentary Basin [WCSB], and we are sure the information will be insightful for people working through future financial and operational business plans.”

Salkeld said factors like weather, lower gas prices, labour and equip ment loomed la rge i n t he reduced drilling outlook.

“We aren’t drilling as many wells but the wells themselves, when we start getting into the overall metreage and days on wells, we’re going to see an interesting change there,” he said. “The overall wells are taking longer, they’re becoming far more complex to complete.

“In the old days with vertical wells, you’d get maybe 500 metres of exposure to a formation,” he added. “Now w it h t hese new wel l s, we’re goi ng 2,000, 3,000 or 4,000 metres directionally in optimal positions within the formations.”

The service sector will continue to grapple with labour issues, he noted.

“It’s always front-of-mind for PSAC member companies and their HR departments,” Salkeld said. “We’re working with the provincial government, working with the federal government.”

PSAC has written a labour paper with several suggestions, “on trying to help our area, with respect to temporary foreign workers and immigration policies,” he said. “[Our efforts also involve] talking to the U.S. government consulate here about some potential pilot projects bet ween Canada and the U.S., that would allow easier movement for workers across borders. “[It’s] an ongoing effort,” said Salkeld.

Gar y Leach, executive director of t he Sma ll E x plorers and Producers A ssoc iat ion of Ca nada, noted t hat PSAC’s drilling forecast update reflects an assessment of the impact of several influential factors on drilling activity.

O I L & G A S I N Q U I R E R • M AR C H 2 0 1 2

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General News

“Leading commodity price forecasts have recently dropped their predictions for natural gas prices significantly, and the winter has proven thus far to be fairly mild with the associated limitations on accessing certain locations and moving equipment,” he said. “As the industry shifts more towards horizontal drilling, associated with more sophisticated and expensive completion methods, the sheer

number of wells drilled is becoming a less-central, although still important, barometer of overall industry activity and financial strength.”

The latest forecasts for natural gas prices make it clear that no relief can be expected over the next year, Leach added.

“The junior and mid-cap sector has seen progress on reducing the weighting of natural gas in the sector’s overall

production but this masks the fact that some have been more successful than others in making the shift to liquids and crude oil,” he said. “We are going through a difficult period of transition but the junior and mid-cap sector rema i n s home to a lot of ta lented people. New leaders are emerging all the time and capital is still available for the right story.”

Western Canadian governments make $4.13 billion from land sales in 2011 Producers and brokers across western Canada paid $4.13 billion in 2011 to secure land rights, the third-highest bonus total in the history of the Canadian petroleum industry.

Only 2008 ($5.01 billion) and 2006 ($4.24 billion) saw higher bonus spending than last year.

The average price per hectare across Canada was $773.83, nearly flat with 2010’s $771.22 per hectare. The 2011 per-hectare price was also the thirdhighest on record (2008: $960.77 per hectare; 2006: $783.66 per hectare).

Alberta enjoyed a record land sale year in 2011. The provincial government brought in an all-time record of $3.64 billion in bonus revenue last year, on 4.61 million hectares, at an average of $790.33.

The previous record of $3.43 billion in 2006 was set due to heavy spending for oilsands acreage. The new watermark was reached because horizontal drilling and multistage hydraulic fracturing are making it possible to develop previously uneconomic formations.

The big drivers for the record expenditures included plays such as the Duvernay shale, Swan Hills tight carbonates, Montney, Alberta Exshaw/Bakken shale and tight oil, Nordegg shale and the Second White Specks.

Most of the money spent at Alberta sales last year went to lands in the northern section of the province where producers invested $3.12 billion on 3.03 million hectares at an average price of $1,029.24 per hectare. Plains bonus spending 30

M AR C H 2 0 1 2 • O I L & G A S I N Q U I R E R

totalled $331.67 million for 908,470 hectares at an average price of $365.08 per hectare, while Foothills land purchases were $80.93 million on 166,106 hectares, for an average of $487.20 per hectare.

Looking ahead to Alberta land auctions in 2012, land sale revenue will likely decline when compared to last year’s record tally. Much of the most prospective land on the unconventional resource plays has been purchased and companies will likely turn their attention to drilling, to test and prove up the lands acquired in 2011.

British Columbia, meanwhile, had a weaker land sale year. For the year, the province collected $222.68 million in bonus bids on 191,529 hectares, at an average of $1,162.66. This was the lowest bonus total since 1999, when $176.17 million rolled into provincial coffers.

In 2010, the natural gas–prone province collected $844.41 million in bonus bids on 381,132 hectares, at an average price of $2,215.54. The average price per hectare was $2,291 in 2009, and $3,518 (the record high) in 2008.

For British Columbia, the weaker numbers in 2011 reflected the impact of low gas prices and the recognition that large tracts had already been acquired by large operators, in the most economically prospective areas of the Montney and Horn River Basin.

Saskatchewan’s government received $248.77 million last year, mak ing 2011 the fourth-best on record for land sale revenue.

In 2010, t he prov ince at tracted $462.8 million in bonus bids.

T he Sw if t Cur rent area was t he only region of the province to see an increase in bonus spending year-overyear. T he area received bonus bids totalling $65.7 million in 2011 (an average of $1,231.02 per hectare), up from $41.58 million in 2010 (an average of $740.85). Southeastern Saskatchewan saw land bids of $78.43 last year, and the Kindersley/Kerrobert region saw bids of $20.24 million. The Lloydminster region received bonus bids totalling $27.58 million.

In 2011, Manitoba bested its record for Crown bonus bids in a calendar year after collecting a total of $13.14 million, passing the all-time watermark of $12.02 million set in 2010. A total of 23,091 hectares were sold in the province last year at an average of $569.04 per hectare. For all of 2010, 20,449 hectares exchanged hands at an average of $587.74.

Land sales in the oil-prone province increased due to the successful use of horizontal multi-frac technology to develop the Bakken/Three Forks play.

In total, producers secured the rights to 5.33 million hectares across the country last year, up from 4.84 million hectares in 2010, but off the high of 5.41 million hectares acquired in 2006.

In addition to the cash bonus bids, industr y secured the rights to a further 1.19 million hectares last year, v ia work commitment bids totalling $356.65 million.

— DAILY OIL BULLETIN

General News

Oil prices should stay strong this year, says analyst

Photo: Joey Podlubny

By Pat Roche

Strong oil prices driven by global demand should support drilling. Gas prices, however, are expected to weaken.

Crude oil demand is expected to grow at higher rates than supply over the next two years, according to Calgary-based analysts Peters & Co. Limited.

“So we contend that crude oil prices will stay relatively high…. We would estimate that a range of US$95–$105 for West Texas Intermediate crude oil is probably an appropriate outlook for 2012,” said Adam Twa, a principal at Peters & Co. Limited.

Increasing consumption in some emerging nations will continue to drive growth in crude oil demand as consumption remains relatively flat in developed countries, Twa told an Investment Industry Association of Canada (IIAC)/ Financial Post investment outlook lunch in Calgary.

The United States consumes about 23 barrels of crude oil per person per year while countries such as India and China consume only at roughly one-tenth of that rate—but the gap is narrowing as more people in emerging economies can afford cars, he said.

“That will continue to drive crude oil demand,” Twa predicted.

On the supply side, it’s no surprise that the biggest growth in the near term will be out of Libya, which was producing about 1.7 million barrels per day, before a revolution and civil war reduced output to just a trickle. But now, “they’re firmly ramping that up,” said Twa.

But the next source of supply growth isn’t one many people would have predicted a few years ago.

“The second-largest growth area, actually, in the world, is in the United States…. The North Dakota Bakken play is one of the most active in North America,” the Peters analyst said.

North Dakota oil production has been setting records—for example, hitting a high of 510,000 barrels a day in November.

Infrastructure bottlenecks in the United States have kept North American crude prices below world levels. “But recently there’s been some positive news on those fronts for improving pricing for North American crude oil,” Twa said.

In contrast, Twa expects North American natural gas prices to continue to weaken.

Even though North American gasdrilling rig counts and gas-well counts have dropped significantly, there has been an increase in horizontal wells with multiple fracture stimulations per wellbore.

So gas production continues to rise.

Making matters worse, he added, is the relatively mild winter in North America that has resulted in minimal gas withdrawals from storage—even though the industry is well into the peak withdrawal season. And demand growth has been relatively limited.

“So with limited or no export capacity, we are currently still awash in natural gas in North America,” Twa said.

Oil development wells focus of 2011 completions Well completions totalled 16,148 during 2011, with over half (8,893) completed as oil development wells.

Last year’s well completion count was up about 18 per cent from 13,634 wells completed from January to December 2010.

While up year-over-year, the count is still off from the 21,000–22,000 wells completed per year in 2004, 2005, 2006 and 2008.

Including development and exploratory wells, a total of 10,039 oil wells

were completed in 2011, up from 6,541 oil wells in 2010 and breaking the previous record of 8,392 oil completions in 1997.

The shift to greater use of horizontal wells to develop plays led to a record for metres completed last year. The total amount of metres completed grew to 27.92 million metres last year, up 25.5 per cent from 22.24 million metres in 2010, and eclipsing 27.78 million metres completed in 2008.

Gas completions declined nearly 24 per cent to 4,485 wells from 5,873 in 2010. The peak of 15,664 gas well completions occurred in 2004.

In western Canada, as gas drilling has declined, so too has the percentage of exploration wells completed. Last year, only 14.9 per cent of total completions were exploratory wells, down from 17.5 per cent in 2010 and above 25 per cent in 2005 and 2006.

— DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • M AR C H 2 0 1 2

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British Columbia

Progress spending $365 million in 2012

JAN/11

JAN/12

JAN/11

JAN/12

WELLS SPUDDED

80

70

WELLS DRILLED

61

69

Photo: Joey Podlubny

P rog ress is c ur rent ly produci ng approximately 130 million cubic feet per day from the North Montney, which represents a doubling of Montney production over the past year. The company currently has 10 North Montney pods at various stages of development in the Foothills of northeastern British Columbia, each targeting production of 50 million cubic feet per day.

The company holds approximately 625,000 net acres of Montney rights in the North Montney and approximately 825,000 net acres of Montney rights over its entire land base, making it one of the largest Montney land rights holders in the fairway.

The most mature development is at Town South, where Progress drilled its first Montney horizontal well less than three years ago. Since that time, Progress has drilled 21 horizontal wells

successfully targeting the Upper and Lower Montney. The company anticipates drilling approximately six to seven wells per year to maintain production at 50 million cubic feet per day. The Town South wells have consistently produced between 15 and 20 barrels of natural gas liquids per million cubic feet. Combined with the British Columbia deep drilling royalty credit of approximately $2 million per well, the well economics for production in the North Montney remain attractive.

At Gundy (100 per cent work ing interest), t he 50 -million-cubic-feetper-day facility constructed in 2011 is currently processing approximately 40 million cubic feet per day, from 10 producing horizontals and with the construction of a 16-inch sales line to the Spectra Energy Highway plant, liquid production has increased to approximately 30 barrels per million cubic feet due to enhanced liquids recovery. Both the Upper and Lower Montney were successfully tested and are on production in the area. A Middle Montney test will be completed in 2012.

A further eight to 11 locations are planned for 2012, which will see production at the Gundy pod exceed 50 million cubic feet per day. At current well performance rates, multiple zone success and higher liquids yield, further expansion of the Gundy facility may be undertaken in 2012.

The first horizontal at the West Gundy development pod (100 per cent working interest) tested over 11 million cubic feet per day and continues to produce at a restricted rate of six million cubic feet per day. Four additional wells and a 25-million-cubic-feet-per-day facility are planned for the first quarter of 2012. An additional four to eight wells along with an expansion of the West Gundy facility

Progress cut spending from $415 million to $365 million due to low gas prices. It is also shutting in 10 per cent of production.

A total capital investment of $365 million in 2012 will enable Progress Energy Resources Corp. to advance its North Montney development pods at Gundy, West Gundy, Kobes and Town North in northeastern British Columbia, while further delineating its North Montney land base.

Focused investment in the North Montney unconventional shales resulted in the company achieving its production goal of exiting 2011 at 50,000 barrels of oil equivalent per day, 11 per cent higher than its 2010 exit rate. Progress expects to exit 2012 at approximately 60,000 barrels equivalent per day, up approximately 20 per cent from 2010.

T he company has seven drilling rigs operating with three on its North Montney acreage, three on its North Montney joint venture with PETRONAS, and one pursuing its Dunvegan light oil play in Alberta.

BRITISH COLUMBIA WELL ACTIVITY

JAN/11

JAN/12

WELL LICENCES

76

46

▼

▼

▲

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • M AR C H 2 0 1 2

33

British Columbia

to 50 million cubic per day is under consideration for the second half of 2012.

At t he Kobes development pod (30 per cent working interest), Progress has seven producing horizontals with pla n s to dr i l l fou r locat ion s i n t he company-operated northern portion of the development. The 2012 wells will fill an expanded 50-million-cubic-feetper-day, Progress-operated facility that is to be completed in the third quarter of 2012.

At Town North (100 per cent working interest), Progress has eight producing horizontals and two wells currently being completed, with both the Upper and Lower Montney productive in the a rea. Two addit iona l locat ion s a re

planned for 2012, with the additional volumes being accommodated by the 25 -m i l lion- c ubic-feet-per- day Tow n Nor t h faci lit y t hat was brought on stream in the second quarter of 2011.

Progress holds a f urther 350,000 net acres of North Montney rights that fall outside of the currently defined de v e l op m e nt p o d s a n d t h e Nor t h Montney joint venture (NMJ V ). T he company plans to drill seven to nine wells in 2012 in the Greater Caribou, Bubbles and Blueberry areas in order to f u r t he r de l i neate it s la nd p osition and define additional pods in the North Montney.

P rog ress a nd PET RONA S estab lished a joint venture in 2011 on three

blocks in the North Montney, encompassing approximately 150,000 gross acres at Altares, Lily and Kahta. For 2012, the partners anticipate investing approximately $341 million gross and $47 million net to Progress on the NMJV acreage. At present, three drilling rigs are operating on the NMJV acreage and the partners are shooting expansive 3-D seismic as well as working on facility and pipeline construction.

The partners plan to drill 23 –29 horizontal wells in 2012 on the NMJ V lands along with building four compressor stations, a 50-million-cubic-feet-perday refrigeration facility at Altares and associated pipelines.

— DAILY OIL BULLETIN

Painted Pony updates B.C. Montney gas development

Photo: Joey Podlubny

Painted Pony Petroleum Ltd. has completed preliminary production testing on two previously announced horizontal Montney wells (100 per cent working interest) drilled on the Blair d-8-F/94-B-16 pad in northeastern British Columbia.

Upon termination of these tests, and on a combined basis, the two wells are currently capable of delivering approximately 17.8 million cubic feet per day of natural gas per day (2,967 barrels of oil equivalent

The Montney is proving to be a company-maker for Painted Pony.

34

M AR C H 2 0 1 2 • O I L & G A S I N Q U I R E R

per day) at the wellhead. These two wells will be permanently tied in to area facilities during the first quarter, but their production will be restricted until additional third-party processing capacity becomes available.

The Upper Montney wellbore was tested for a total of 327 hours, including 65 hours on an unrestricted basis after milling out flow-through plugs. During this latter period, the well flowed at an average wellhead rate of 9.1 million cubic feet per day (1,517 barrels equivalent per day). The final 24-hour wellhead test rate was 8.2 million cubic feet per day.

The Lower Montney wellbore was tested for a total of 275 hours, including 64 hours on an unrestricted basis, after milling out f low-through plugs.

During this latter period, the well flowed at an average wellhead rate of 9.9 million cubic feet per day. The final 24-hour wellhead test rate was 9.6 million cubic feet per day.

At the Daiber (Cameron) d-44-C/94B-16 pad (50 per cent working interest), Painted Pony recently rig-released a second Lower Montney horizontal well. The well is scheduled to be completed and production tested as soon as servicing equipment is available. It is a direct offset to the company’s Lower Montney well, which as previously reported flowed in excess of 24.5 million cubic feet per day.

The company anticipates that both Lower Montney wells on the d-44-C pad will be pipeline-connected and begin production during the first quarter. Painted Pony also plans to spud a third well on this pad targeting the middle Montney on or about January 10.

At Kobes (Cameron), drilling operations recently started on the first well at the c-75-J/94-B-09 pad (20 per cent working interest, non-operated), targeting the Lower Montney. This well is expected to be complete and production-tested during the second quarter.

Painted Pony’s field-estimated production for northeastern British Columbia during December 2011 averaged approximately 25 million cubic feet per day (4,167 barrels of oil equivalent per day), representing an increase of more than 50 per cent from average third-quarter volumes.

The company estimates that it has approximately 45 million cubic feet per day (7,500 barrels of oil equivalent per day) of total net wellhead productive capacity from the Montney project in northeastern British Columbia. Approximately 35 per cent of this capacity (2,600 barrels of oil equivalent per day) is currently shut in and waiting on pipeline tie-in and/or plant expansions, all of which are scheduled to be completed and operational by the end of the second quarter.

— DAILY OIL BULLETIN

British Columbia

Silica North planning $100-million frac sand project at Fort Liard A Calgary-based private company could be the first to build a plant—as early as the first quarter of 2013—to supply the sand used in hydraulic fracturing to producers and service companies in the Horn River Basin.

Silica Nor t h Resources Ltd. currently has five letters of intent for frac sand from three producers and two service companies totalling about 300,000 tonnes, David Brough, chief executive officer, said. The company is currently in negotiations with one producer for about 100,000 tonnes of sand per year for its frac needs.

Silica North has permits in place for the $100-million project on 2,479 acres on federal Crown land approximately 47 kilometres northwest of Fort Liard, N.W.T. Subject to financing, it expects to start construction in 2012 with anticipated production the following year.

Based on current plans, the operation has the potential capacity to produce 800,000 tonnes of frac sand per annum, with initial plans for 400,000 tonnes a year.

Silica North has completed independent industrial scale testing to develop

The company’s planned budgetedcapital expenditure for the project is also considerably less when compared to other frac sand projects currently being publicly proposed to supply proppant into the Horn River Basin.

Brough said his company intends to expedite the opening of the project, increasing the barriers of entr y for future potential competitors in the Horn River Basin, based on current market demand. With the recent addition of Jim Sadowski (formerly with Outotec) and the construction expertise of AIC Canada, the company said it believes it has the key ingredients to execute on its business plan. Sadowski has more than 36 years of mineral industry experience, including a number of years in which he was involved in overseeing several silica-processing-plant projects. A IC Canada has more than 25 years of heavy construction in remote, harsh, northern environments for the oil and natural gas, mining and public works industries.

A s e c ond c ompa ny, Va nc ou ve rbased Stikine Energy Corporation, in the first quarter of this year expects to

However, the company still sees a lot of momentum for the Horn River, due in part to proposed LNG projects at Kitimat that would provide access to Asian markets, he said. Stikine has mineral rights to claims and leases for the Nonda project, 190 kilometres northwest of Fort Nelson, in close proximity to the Horn River Basin. The site is 90 kilometres north of Muncho Lake in the B.C. portion of the Kaska traditional territory, and Stikine will be working together with the Kaska on designing and planning the environmental, socio-economic and cultural aspects of the project.

Existing suppliers are operating at or near capacity and producers are currently bringing in frac sand by rail or truck from Peace R iver, A lta., Winn Bay, Sask., and as far away as Preferred, Nebr., and Texsand, Texas, according to a Stikine presentation. The company engaged PwC Canada to conduct a study to establish volumes and pricing but ran into difficulty getting anyone to say what they were actually paying for frac sand, said Broughton. Anecdotally, though, Stikine has heard prices are

Based on current plans, the operation has the potential capacity to produce 800,000 tonnes of frac sand per annum, with initial plans for 400,000 tonnes a year. its plant process design. Included in the testing process were several rounds of third-party development performed

by Outotec (USA) Inc. and Stim Lab (a division of Core Laboratories). The use of entire core samples allowed the company to develop processes to address the organics and any possible metals in processing. This approach also provided supportable estimates of waste percentages to facilitate reclamation planning.

The project has an advantage with its location and the pre-existing infrastructure including roads, potential power sources and water for processing, said Brough. Located 100 kilometres north of the northwestern corner of the Horn R iver Basin, and approximately 630 kilometres north of the Montney play, Silica North will be able to reduce transportation and logistical costs compared to existing frac sand suppliers who are located significantly further away from the plays.

file applications with British Columbia regulators for proposed frac sand projects at A ng us and Nonda, to meet the needs of producers active in the Montney formation and the Horn River Basin, respectively. The company has completed two preliminary economic assessments that include a fair amount of detailed engineering, but first will be going back to consult with First Nations stakeholders for possible fine tuning before the application is submitted.

The company hopes to be building the plants in 2014-2015, and to be ready, “when things really take off up there,” said Scott Broughton, president and chief executive officer.

Stikine’s 100 per cent Angus project— about 60 kilometres north of Prince George and approximately 200 kilometres south of the Montney shale-gas play—likely will be the first to be built because of the lower access infrastructure costs, he said.

currently in the range of $425–$450 per tonne, he said.

For its Nonda project, the company used a base case of a delivered price of $250 per tonne and an alternative case, in a cash flow model, of $300 per tonne and, “we came back with really robust economics, because we know the industry is paying a lot more than that.” In the Montney (Angus), the base case was $225 per tonne with an alternate case of $250 per tonne and, “again we came back with robust economics.”

In 2011, the estimated demand for frac sand in the Montney was about 800,000 tonnes per annum while Horn River demand was about 200,000 tonnes per annum. By 2014, Stikine says the projected demand will increase to more than four million tonnes per annum, which would result in revenues of more than $1 billion per year, based on a frac sand price of $250 per tonne.

— DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • M AR C H 2 0 1 2

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Northwestern Alberta/Foothills

Photo: Joey Podlubny

Resthaven drives Celtic production

Celtic Exploration's Resthaven Montney play is delivering high volumes of liquids-rich gas and oil.

Based on estimates provided by field reports, Celtic Exploration Ltd. reports its production was a record 24,929 barrels of oil equivalent per day, exiting 2011.

In addition, the company has estimated that it has approximately 3,000 barrels equivalent per day of production behindpipe from wells that have been drilled, completed and tested, giving Celtic current capability of approximately 27,900 barrels equivalent per day. This compares to average production of 15,808 barrels per day in the third quarter of 2011.

At Resthaven (Triassic Montney), a horizontal well was drilled in the third quarter of 2011 on the western edge of the company’s land block, located north of the Simonette River near Jayar at 04-34-06103W6. The well was drilled to a measured depth of 5,130 metres and was completed with a 16-stage foam fracture technique.

After 82 hours of clean-up and flow, at the

end of the test the well was producing natural gas at a rate of 20.4 million cubic feet per day, and field condensate of 568 barrels per day, at a flowing wellhead pressure of 12,863 kilopascals. Additional liquids will be recovered from gas at the gas plant after this well is brought on stream.

On the southern part of Celtic’s Resthaven land block, the company drilled a horizontal well located near Horse at 12-20058-27W5 (100 per cent working interest).

The well was drilled to a measured depth of 5,361 metres and was completed with a 17-stage foam fracture technique. After 165 hours of clean-up and flow, at the end of the test the well was producing natural gas at a rate of 7.9 million cubic feet per day, and field condensate at 68 barrels per day, at a flowing wellhead pressure of 3,473 kilo­ pascals. Additional liquids will be recovered from gas at the gas plant after this well is brought on stream.

In the northeastern part of the company’s Resthaven land block, Celtic completed a re-entry horizontal well located near Simonette at 04-11-062-27W5 (100 per cent working interest). This well tested an eight-section block near Simonette, away from Celtic’s contiguous block of lands in the Greater Resthaven area. The well was completed with a 13-stage foam fracture technique. After 205 hours of clean-up and flow, at the end of the test the well was producing oil at a rate of 106 barrels per day.

Also in the Greater Resthaven area, Celtic currently has two Montney wells awaiting completion and testing for which production has not been included in the behindpipe estimates outlined above. The first well is located in the north near Karr at 13-10063-02W6 (100 per cent working interest).

Completion operations were wrapped up on Jan. 9, 2012, and the well is currently being tested. The second well is located in the south near Leland at 01-25-058-27W5 (100 per cent working interest) and was expected to be complete and tested by the end of January. In addition, the company currently has four rigs operating in the area, drilling 100 per cent working interest horizontal wells located at Jayar 16-22-061-03W6, Resthaven 02-30060-02W6, Smoky 13-33-058-01W6 and Harley 06-12-057-27W5.

In the northern part of Celtic’s Resthaven land block, the company completed a reentry horizontal well located near Lator at 02-34-062-03W6 (100 per cent working interest), targeting the Cretaceous Falher formation. The well was completed with a 14-stage foam fracture technique. After 180 hours of clean-up and flow, at the end of the test the well was producing natural gas at a rate of 6.3 million cubic feet per day, at a flowing wellhead pressure of 2,000 kilo­ pascals (290 pounds per square inch).

In addition to the horizontal completion in the Montney at the Horse 12-20-058-27W5 (100 per cent working interest) well, Celtic

NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY

JAN/11

JAN/12

WELL LICENCES

278

291

▲

JAN/11

JAN/12

WELLS SPUDDED

317

340

▲

JAN/11

JAN/12

WELLS DRILLED

281

286

▲

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • M AR C H 2 0 1 2

37

Northwestern Alberta/Foothills

is currently testing several Cretaceous sands (Bluesky/Gething/Cadomin) in the vertical section of the wellbore. In the event of a successful vertical test, Celtic plans to follow up with a horizontal multi-fracture well in the Cretaceous in the near future.

As a result of several strat wells drilled to-date in the Resthaven area, while derisking the Triassic Montney formation, Celtic has identified additional Cretaceous locations that it plans to drill horizontally in the near future.

At Fir, Celtic has drilled a well located at 12-33-059-22W5 with a measured depth of 5,802 metres. The horizontal lateral was 2,979 metres in length within the Triassic Montney formation. Completion operations have commenced. Anticipated production from this well is not included in the behindpipe estimates outlined above.

In the Kaybob area, Celtic managed the drilling and completion operations for the third horizontal well targeting the Devonian Duvernay shale formation under an existing joint venture with Trilogy Energy Corp. and Yoho Resources Inc., pursuant to which each partner has a one-third working interest in 30 gross sections of land.

The well is located at 13-36-060-20W5 and was drilled to a measured depth of 5,157 metres. The horizontal lateral was 1,727 metres

in length within the Duvernay shale formation.

The well was drilled and cased over 42 days at a cost of approximately $4.5­ million. Well completion operations began in December 2011. The well was fracture-stimulated in 25 stages and approximately 2,480 tonnes of sand and 150,100 barrels of slick water were used to stimulate the well. The total estimated cost of the completion is approximately $5.8 million. As a result, the total estimated cost to drill, complete and test the well is approximately $10.3 million.

The well was tested in-line through the Kaybob gas plant. During clean-up, the well flowed at a maximum rate of 7.1 million cubic feet per day. The well was shut-in, in order to run 2 3/8-inch production tubing.

The well was returned to production and held at a constant rate of 3.6 million cubic feet per day, at a static casing pressure of 12,500 kilopascals (1,812 pounds per square inch). At the end of the test, in addition to the sweet natural gas production, the well was producing field condensate (56 degrees API) at a rate of 339 barrels per day (92 barrels per million cubic of raw gas).

With additional liquids to be extracted from gas at the Kaybob gas plant, the company expects to yield total liquids of over 100 barrels per million cubic feet of raw gas, including the field condensate.

Celtic has shut-in the well, which will remain as such for approximately one month, to allow the water to absorb into the formation.

Also in the Kaybob area, Celtic participated in the drilling of a fourth horizontal well targeting the Devonian Duvernay shale formation at a 50 per cent working interest. This well is located northwest of the 30-gross-section joint venture mentioned above, and drilling and completion operations are being managed by the company’s joint venture partner, Yoho. The well is located at 13-22-062-21W5 and was drilled to a measured depth of 4,861 metres.

The horizontal lateral was 1,461 metres in length within the Duvernay shale formation. The well was drilled and cased over 39 days at a cost of approximately $4.9 million.

Well completion operations are currently underway and the company expected to have test results by the end of January.

Anticipated production from this well is not included in the behind-pipe estimates outlined above.

The company owns approximately 127,300 gross acres (199 gross sections) and 100,800 net acres (157 net sections) of land with Duvernay rights in the Kaybob area of Alberta.

— DAILY OIL BULLETIN

Lone Pine to spend over $200 million in 2012 Approximately $165 million in high-­ margin light oil projects at Evi will account for 80 per cent of Lone Pine Resources Inc.’s 2012 capital budget of between $200 million and $220 million.

The company plans to drill and complete up to 48 (48 net) horizontal wells at Evi as it continues to advance area development through further downspacing and additional infill drilling.

In 2011, Lone Pine made tremendous strides in its transition to light oil, more than doubling its oil production weighting through the year, and the company plans to build on that success this year, David Anderson, president and chief executive officer of Lone Pine, said.

“Given the current disparity between light oil and natural gas prices, we 38

M AR C H 2 0 1 2 • O I L & G A S I N Q U I R E R

believe that allocating minimal cap­ ital towards natural gas is the practical approach at this time,” he said. “Lone Pine is a rate-of-return driven company, and our focus in 2012 will be on growing bottom-line cash flow per share over top-line production per share.”

The company expects that its cap­ ital budget will generate a more than 50 per cent increase in adjusted discretionary cash flow in 2012 while maintaining a strong balance sheet and conservative leverage targets, said Anderson.

As Lone Pine has no significant nearterm lease expires or drilling obligations on its natural gas assets, it is able to focus exclusively on light oil projects, while North American natural gas prices continue to trade at multi-year lows, he

said. “Should natural gas prices recover through 2012, we expect to be able to quickly respond to alter spending plans and allocate capital to our drill-ready natural gas projects.”

The company plans to spend $160 million to $170 million on drilling and completions, of which $150 million to $160 million will be spent on light oil and $10 million on natural gas. Another $20 million to $25 million each will be spent on equipment and facilities, as well as land, maintenance, and general and administrative.

Based on the continued improvement in drilling efficiency it demonstrated in the second half of 2011, Lone Pine expects to complete the planned drilling program with the two rigs it currently has in place. Lone Pine also intends to

Northwestern Alberta/Foothills

continue to expand its facilities at Evi to accommodate t he grow ing cr ude oil volumes in the area and continue investment in the company-operated waterf lood pilot project that was initiated in 2011.

Lone Pine plans to fund its 2012 cap­ ital budget primarily through cash flow from operating activities.

T he compa ny i s forec a st i ng a n approximate increase of 70 per cent in

average daily oil and natural gas liquids production, with average net sales volumes of 5,500 barrels per day. The net liquids production weighting is expected to increase to 35 per cent (34 per cent oil and one per cent natural gas liquids) from 21 per cent in 2011, with a 2012 exit weighting of 40 per cent liquids.

In the fourth quarter of 2011, Lone Pine drilled 16 (16 net) wells at Evi with a 100 per cent success rate. During the

quarter, the company accelerated its previously announced capital program, which resulted in it drilling an additional six (six net) wells. Including these additional wells, Lone Pine drilled a total of 47 (47 net) wells at Evi in 2011.

It also drilled a total of six (5.5 net) wells at Narraway in 2011, including one (one net) new well drilled in the fourth quarter.

— DAILY OIL BULLETIN

Delphi completes first Bigstone Montney well Photo: Joey Podlubny

Delphi Energy Corp. reports the company’s first horizontal well at Bigstone East targeting the Montney formation (100 per cent working interest), with a surface location of 1-19-60-22W5M, has been successfully completed.

The well f low tested at an average rate of 12.5 million cubic feet per day over the final 24 hours of the fourday f low period. It was also producing approximately 770 barrels per day of condensate at the end of the test, although 100 per cent of the frac f luid hadn’t been recovered. Shallow-cut plant recoveries of natural gas liquids are expected to y ield an additional 30–35 barrels per million cubic feet.

Completion operations consisted of a 20-stage, oil-based frac program placed over the 2,760-metre extendedreach horizontal section of the well after successfully drilling the well to a total measured depth of 5,618 metres.

T he drilling operation was completed as planned with the full length of the horizontal section encountering the anticipated reser voir-qualit y rock. The extended-reach horizontal section is up to twice as long as earlier horizontal wells in the area, and is designed to reduce the number of wells required for full development by up to 50 per cent w it h total project cost-­ savings of approximately 35 per cent.

The Delphi Bigstone East 1-19 well is immediately offsetting a competitor’s well with a 1,254-metre horizontal length and reported test rates of approximately 4.3 million cubic feet per day of natural gas, and 295 barrels per day

Delphi joined others in drilling successful Bigstone Montney wells late in 2011, with its first horizontal coming in at 12.5 million cubic feet of gas and 770 barrels of condensate per day.

of condensate. In the Fir area, located approximately five kilometres to the south of Bigstone East, nine horizontal wells have now been drilled. Test rates reported to-date range from 3.5 million cubic feet per day of natural gas and 225 barrels a day of condensate, from a well with a 1,200-metre horizontal length, to a high of 15 million cubic feet per day of natural gas and 750 barrels a day of condensate, from a well with over 2,500 metres of horizontal length.

Reported drilling success in the area continues to validate Delphi’s interpretation of a large contiguous liquids-rich natural gas deposit within the Montney formation in the greater Bigstone/Fir area, it said.

A second Montney well at 5-14 60 -23W5M, located f ive k ilometres southwest of the 1-19 well, has started

dr il ling. A sim ila r f rac prog ra m is expected to be undertaken as part of the completion operations on this well.

The company has an inventory of approximately 100 horizontal Montney locations identified on its 45 (41.5 net) sections of land in Bigstone. Other emerg ing light oil and liquids-r ic h natural gas plays in the Nordegg and Duvernay formations being drilled by industry at Bigstone, offer additional potential on company lands, it said.

Delphi expects to start construction in February on its 100 per cent owned compression and field gathering infrastructure with initial capacity of 30 million cubic feet per day. Production from Delphi’s Montney wells at Bigstone East is expected to begin in April, with startup of these facilities.

— DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • M AR C H 2 0 1 2

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Northeastern Alberta

Canadian Natural managing project inflation

By Lynda Harrison

JAN/11

JAN/12

JAN/11

JAN/12

WELLS SPUDDED

209

137

WELLS DRILLED

191

135

Photo: Joey Podlubny

$500 million, as well as some smaller ones. “Basically what we’re doing on the mining side is taking what the market will give us, capturing those prospects where we can and actually containing our cost inflation.”

The company has budgeted $2 billion in capital spending this year to expand Horizon, its oilsands mine. Phase 2A is to include upgrading debottlenecking and coker expansion, as well as a 10,000-barrel-per-day increase in output for 2013 or 2014.

There remains a “pinch point” for workers, such as welders, pipefitters and electricians, around 2013-2014, so CNRL is developing labour strategies to fix that and it expects some Europeans will bring their own crews, he said.

While the first phase of the mine’s construction employed a great number of eastern Canadians, the company foresees the amount of shipbuilding now taking place in that region will reduce labour availability, so it is looking to other sources, such as the United States, for temporary workers.

In situ construction, on the other hand, is experiencing inflation of five to 10 per cent, which Bieber attributed to increased competition. CNRL is building a steam assisted gravity drainage pro­ ject, Kirby South Phase 1, which has targeted capital costs of $1.25 billion and is aiming for first steam in late 2013.

On the conventional side of the business in Canada, probably the most significant cost-pressures are on primary heavy extraction, such as for slant wells, again with inflation of five to 10 per cent, he said.

The company now estimates 2012 cash f low of almost $9 billion, based on current oil prices, up from the previously forecasted $8.5 billion. It will spend its free cash f low on increased dividends as well as asset acquisitions likely in its core region, Bieber told the conference.

There is also the potential for modest share buybacks and paying down debt, he added.

Cost inflation remains a concern with CNRL looking south to the United States to meet labour shortfalls.

A year ago, industry and investors were worried about significant cost inflation at oilsands mining projects. While that fear continues, it ’s not reality today, thanks to world events, says a Canadian Nat ura l Resources L i m ited (CN R L) executive.

“A number of things have happened on the world stage that have created some opportunities for us that we’re taking advantage of,” Corey Bieber, vicepresident of finance and investor relations, told BMO Capital Markets’ ninth annual unconventional resource conference in New York City.

The European economic crisis and Middle East turmoil have reduced the number of expansions or infrastructure developments taking place in the world, creating fewer opportunities for many of Europe’s engineering, procurement and construction contractors, said Bieber.

Europeans are considering Canada a good place to deploy some of their core crews and staff for the next few years, simply to maintain their utilization rates, he said.

As a result, CNRL has been able to secure lump-sum contracts at three significant projects, worth more than

There remains a “pinch point” for workers, such as welders, pipefitters and electricians, around 2013-2014....

NORTHEASTERN ALBERTA WELL ACTIVITY

JAN/11

JAN/12

WELL LICENCES

257

215

▼

▼

▼

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • M AR C H 2 0 1 2

41

Photo: Joey Podlubny

Northeastern Alberta

Cenovus plans on using a number of new technologies on oilsands leases if it gets regulator approval.

Cenovus applies for Telephone Lake and start-up boosting technologies Cenovus Energy Inc. says if all approvals are met, its fifth oilsands project, which could start steaming as early as 2018, will employ several technologies that the company has pioneered at existing operations, that are expected to put the pedal to the metal on start-up.

The company has applied to regulators for approval of its proposed Telephone Lake in situ oilsands project, designed for production of 90,000 barrels per day of bitumen from the McMurray formation using steam assisted gravity drainage (SAGD) and the company’s patented wedge-well technology.

The application also requests blanket approval and/or flexibility to use the following technologies and design/operational parameters during the project’s life: cold water dilation enhanced start-up, steam dilation enhanced start-up (patent pending), solvent­-enhanced start-up operations (Cenovus patent pending), well-pair spacing ranging from 50 to 200 metres, well-pair lengths up to 1,200 metres, and two operating pressures—a high pressure based on specific well parameters during the start-up stage, and a lower limit based on field-wide maximum operating pressure thereafter.

Cenovus started testing steam dilation enhanced start-up at Christina Lake where it is now routinely deployed, spokeswoman Jessica Wilkinson said.

42

M AR C H 2 0 1 2 • O I L & G A S I N Q U I R E R

“We’ve found that it reduces our SAGD start-up time of two to three months, to less than one month,” said Wilkinson.

“The typical industry standard for start-up time is three to six months, so this would make it three to six times faster. In general, steam dilation uses steam circulation and increased pressure to ‘rearrange’ the sand grains between the producer and injector wells, which accelerates communication between the two by increasing porosity and water mobility.”

Solvent-enhanced start-up is already in operation at both Christina Lake and Foster Creek.

At Christina Lake, this technology has reduced SAGD start-up time from about two months to one week, making it eight times faster, she said. “Compared to the industry standard, it’s about 12-times faster. At Foster Creek, the reserves tend to have a higher water content and in certain areas, start-up can be achieved in about one month, without applying any dilation technology. In other areas of the reservoir, using a solvent can significantly reduce the start-up time from 12 to 18 months, to about 1.5 months—nine times faster. Compared to industry, this is about two to four times faster.”

Telephone Lake is expected to be built over 72 months in two phases starting with Phase A in 2014, with an estimated

­ pera­­tional life of around 40 years. o Timing depends on regulatory approvals, projected for receipt in fourth-quarter 2013, as well as on market conditions and corporate sanction.

First steam at Phase A is proposed to start in 2018. Field construction of Phase B is forecasted to begin in 2016, with first steam in 2019.

Within the proposed project area, the bitumen zone in the McMurray formation is typically overlain by a layer of non-saline groundwater (top water). The project will use dewatering technology (Cenovus patent pending) at the majority of the well pads to facilitate the replacement, with air, of a portion of this top water prior to SAGD operations. Dewatering technology involves additional wells and well pads beyond a typical SAGD project; where required, these additional wells and well pads would be in operation one to two years prior to the first steam injection for SAGD. In November 2011, Cenovus received approval from Alberta Environment and Water and the Alberta Energy Resources Conservation Board to conduct a test of the proposed dewatering technology, and Cenovus intends to conduct this test over a period of six to 12 months, starting in 2012.

— DAILY OIL BULLETIN

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Central Alberta

Cardium success spurs growth for Whitecap

JAN/11

JAN/12

JAN/11

JAN/12

WELLS SPUDDED

240

209

WELLS DRILLED

237

202

Photo: Joey Podlubny

During the fourth quarter of 2011, the company’s estimated average production was approximately 7,800 barrels equivalent per day, a 287 per cent increase on an absolute basis over fourthquarter 2010 average.

Whitecap’s 2011 average annual production is estimated to be approximately 5,600 barrels equivalent per day, a 291 per cent increase on an absolute basis over its 2010 average annual production.

All of the 60 (47.7 net) wells Whitecap drilled in 2011 targeted oil and the company achieved a 100 per cent success rate. Of the wells drilled, 44 (35.8 net) were horizontal multi-fractured oil wells.

Whitecap said it has a current inventory of 373 (251 net) low-risk development drilling opportunities (91 per cent oil), prior to the inclusion of the Compass inventory,

which will allow the company to continue its trend of low-risk organic growth in 2012 and beyond.

“We have had strong operational success to-date throughout our core areas and look forward to carrying this positive momentum into 2012,” Whitecap said.

Of note, the company said it continues to, “demonstrate significant progress” in developing the Cardium from both a cost and well-productivity perspective.

“We are generating consistent and repeatable results that provide superior economics,” the company said.

In East Pembina, where Whitecap drilled 70 per cent of its 2011 Cardium horizontal wells, average drill and complete costs are $2.2 million with average 30-day initial production rates of 226 barrels equivalent per day (84 per cent oil).

In the fourth quarter of 2011, Whitecap drilled 13 (11.3 net) horizontal Cardium oil wells of which eight (6.9 net) were placed on production in 2011 with the remaining five wells coming on production in early 2012.

The company noted that evaluations of reduced spacing and waterflood pilot schemes for its Cardium lands continue to progress and that it plans to implement these pilot schemes in 2012.

“Positive results from these pilots have the potential to more than double Whitecap’s current inventory of Cardium horizontal locations,” the company said.

During the first quarter of 2012, Whitecap has two rigs drilling continuously until spring breakup, and the company anticipates drilling 16 gross Cardium horizontal wells, primarily in its East Pembina core area.

At the company’s Peace River Arch— Valhalla property where Montney light oil is the primary target, Whitecap drilled eight (5.0 net) wells in 2011, including two (1.0 net) horizontal multi-fractured

Things are looking up for Cardium oil producer Whitecap, which reported an almost 300 per cent increase in production year-end 2011.

Last year’s successful drilling program highlighted by strong results from its Pembina Cardium light oil play helped Whitecap Resources Inc. to exceed its 2011 exit rate production guidance.

The company reported in January that current production is approximately 8,500 barrels of oil equivalent per day with approximately 700 barrels per day to come on stream in the near term, excluding production volumes from the recently announced Compass Petroleum Ltd. transaction dated Dec. 15, 2011. That deal is expected to close in mid-February 2012.

Those volumes exceeded its guidance of 8,200–8,300 barrels equivalent per day and represent an increase of greater than about 160 per cent on an absolute basis, and a 51 per cent increase per share, fully diluted over Whitecap’s 2010 exit rate production of 3,200 barrels per day.

CENTRAL ALBERTA WELL ACTIVITY

JAN/11

JAN/12

WELL LICENCES

288

269

▼

▼

▼

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • M AR C H 2 0 1 2

45

Central Alberta

Montney Sexsmith wells, three (2.5 net) Doe Creek horizontal wells, two (1.0 net) water source wells for the waterflood expansion and one additional well. One of the three Doe Creek horizontal oil wells was brought on stream in the fourth quarter, while the other two Doe Creek wells and the two horizontal Montney Sexsmith wells are being brought on production in the first quarter of 2012.

The company said it continues to optimize its horizontal well development program in the Valhalla Montney Sexsmith oil pool from both a cost and productivity

perspective. In 2011, Whitecap said its average drill and complete costs were down 10 per cent to $4.6 million gross per well, with average 30-day initial production rates increasing over 150 per cent to 532 barrels of oil equivalent per day. Its working interest in the Montney formation is a consistent 50 per cent across the entire pool.

Whitecap noted that the first phase of the waterflood expansion is in progress, and by the end of the first quarter it will have 17 wells on injection as compared to five wells injecting at the start of 2011. It is expected that these conversions will increase the

injection into the Valhalla Montney oil pool threefold, to 7,500 barrels of water per day.

“Our full field-simulation model has been updated with recent results and continues to indicate improvement in the ultimate oil recovery in the Montney Sexsmith,” the company said.

During the first quarter of 2012, Whitecap said it will have one rig drilling continuously and it expects to drill three (2.0 net) Montney horizontal wells during the period including the first horizontal targeting the Middle Montney oil interval.

— DAILY OIL BULLETIN

Fairborne continues success at Wilrich

46

M AR C H 2 0 1 2 • O I L & G A S I N Q U I R E R

is for a 30-day initial production rate of 4.2 million cubic feet per day.

Fairborne says it drilled the first horizontal Wilrich well in western Canada in March 2009 and, since then, has successfully drilled and completed a total of 19 (13.9 net) in the Marlboro/Pine Creek area of the Deep Basin.

The company has also increased its Wilrich land position by 20 per cent through a combination of Crown land sales and a recent farm-in to a total of 39 (25 net) sections. The land includes an undrilled inventory of 59 gross wells at two wells per section and 98 gross wells at three wells per section.

Meanwhile, in the Greater Harlech area, Fairborne drilled a horizontal Cardium well during the fourth quarter at 2-15-44-15W5. The well reached a measured depth of 3,955 metres and was completed with an 11-stage, 30-tonne-per-stage fracture treatment. This well was tied in and started production in early December.

The well is performing as expected and has a 30-day average initial production rate of 330 barrels equivalent per day (including 55 barrels of condensate and natural gas liquids per million cubic feet).

Fairborne’s Cardium land base is approximately 65,000 net acres (102 net sections) and represents a horizontal Cardium inventory in excess of 300 estimated net locations.

The company anticipates that, like the Wilrich at Marlboro, continued refinement of fracture-stimulation treatments and

Photo: Joey Podlubny

Fairborne Energy Ltd. reports that with the successful completion and tie-in of its most recent horizontal Wilrich well (60 per cent working interest) plus one vertical well at Harlech recently completed and tied-in, the company achieved 2011 exit production of 16,700 barrels of oil equivalent per day.

The exit rate was within the company’s previous guidance of 16,500–17,000 barrels equivalent per day.

“Achieving a 2011 exit rate of 16,700 barrels equivalent per day illustrates the growth potential of the company’s asset base and the strong economics of both the Wilrich and Cardium plays currently targeted by the company,” Fairborne said in a news release.

Fairborne’s latest Wilrich well, which was successfully drilled to a total depth of 4,173 metres, with a horizontal length of 1,200 metres, was fracture-­stimulated over 12 inter vals. The well showed extremely strong test rates on initial flowback, was shut in after eight hours on test, and then tied in, the company said. The well has now been on production since mid-December and has been flowing at a restricted rate of 10 million cubic feet per day, plus liquids, since coming on stream (1,700 barrels equivalent per day).

The record well represents the strongest initial Wilrich production rate to date and further solidifies the Wilrich at Marlboro as one of the premier natural gas plays in western Canada, Fairborne said.

The company’s type curve for the Wilrich

Drilling success in the Deep Basin has Fairborne reporting production of 16,700 barrels equivalent per day.

completion fluids will result in enhanced f low results. Drilling and completion costs are also expected to decline as more Cardium wells are drilled.

Plans for the first quarter of 2012 include the drilling of another Cardium horizontal well to continue to de-risk this condensate-rich resource play.

Fairborne currently has four operated and one non-operated rigs active, with one at Harlech, three at Marlboro and one at Sinclair, Man. In addition, the company announces repayment, in cash, of the $100-million principal amount of Fairborne’s previously outstanding convertible debentures and accrued interest, which matured on Dec. 31, 2011, using its existing bank credit facilities.

— DAILY OIL BULLETIN

Central Alberta

Fracturing blowout near Innisfail investigated The Energ y Resources Conser vation Board (ERCB) is investigating an incident in January in the Garrington area, 35 kilometres southwest of Innisfail, in which multistage hydraulic fracturing operations appear to have blown out a nearby oil well, resulting in a release of fracturing fluids.

There were no injuries and no confirmed effects on wildlife to-date. Both wells have been shut in and cleanup is underway. The volume of the f luid

release, which included fracturing oil, nitrogen and sand, has not been confirmed, Darin Barter, an ERCB spokesman, said this morning.

Canyon Ser v ices Group Inc. was working the 15th stage of a 16-stage f rac on a Midway Energ y Ltd. well when the incident occurred, affecting a nearby oil well operated by Wild Stream Exploration Inc. Barter said the ERCB does not know what time the blowout occurred but it

was notified around 6 p.m. by the owner of the land on which the Wild Stream well is located. From that point, workers moved to lower the pressure on the fracture and to shut in both wells.

The ERCB is still working on a new regulatory system for unconventional oil and natural gas wells, which would include a section on proximity to existing wells. The document could be released this spring, said Barter.

— DAILY OIL BULLETIN

Bellatrix production up; Duvernay well planned for first quarter December production averaged 16,000 barrels of oil equivalent per day, exceeding its exit rate guidance of 15,000 barrels per day, Bellatrix Exploration Ltd. reported in January.

Production in December 2011, which was up 52 per cent over the December 2010 rate of 10,500 barrels equivalent per day, was weighted 60 per cent to natural gas and 40 per cent to crude oil, condensate and natural gas liquids.

Estimated fourth-quarter production averaged approximately 14,000 barrels equivalent per day while annual production for last year is expected to average approximately 11,900 barrels per day, ref lecting a 40 per cent increase over average volumes in the fourth quarter of 2010.

Bellatrix drilled 12 (7.64 net) wells in the fourth quarter of 2011. The company successfully drilled eight (6.68 net) Cardium light oil horizontal wells and three (0.95 net) Notikewin condensaterich horizontal natural gas wells in westcentral Alberta, and participated in one (0.007 net) dry hole that was drilled in a non-operated oil unit.

Two (1.33 net) Cardium light oil wells and two (0.45 net) condensate-rich natural gas wells that were drilled in the fourth quarter of last year will be tied in during the first quarter of 2012.

Due to infrastructure constraints Bellat r i x has shut in 1,800 bar rels

­e quiv­a lent per day of natural gas production that will be placed back on pr o duc t ion i n m id-Febr ua r y. A s a result, production in the first quarter is expected to average between 15,000 and 16,000 barrels equivalent per day.

The company plans to use its firstquarter drilling program to improve its oil/gas weighting by replacing natural gas production decline with Cardium light oil production. Bellatrix plans to complete a number of significant infrastructure improvements in west-central Alberta to allow continued liquids-rich natural gas production growth through the remainder of this year.

Bellatrix’s first-quarter 2012 drilling program is cur rently under way with four rigs that began drilling in early January. The company has an initial capital budget of $180 million for this year. Current plans call for drilling 16 (13.45 net) wells in the first half of the year. Bellatrix expects to drill 13 (10.95 net) horizontal Cardium light oil wells and two (1.50 net) horizontal Notikewin condensate-rich natural gas farm-in commitment wells in westcentral Alberta. In addition, it is planning to dr ill t he company ’s f irst 100 per cent work ing-interest horizontal Duver nay test at Fer r ier i n t he f i rst quarter of 2012.

The company’s estimated drilling budget for this year, of between $155 million

and $160 million, provides for drilling and completing approximately 51 (41.5 net) horizontal wells. Plans include 38 (31.9 net) Cardium wells, 11 (7.6 net) Notikewin-Falher wells and two (two net) Duvernay horizontal wells.

Bellatrix continues to focus on the development of its core assets and conducts exploration programs using its large inventory of geological prospects.

Exiting 2011, Bellatrix had approximately 224,559 net undeveloped acres and, including all opportunities, has in excess of 900 exploitation drilling opportunities identified, representing more than 10 years of drilling inventor y based on annual cash f low. The company continues to focus on adding Cardium prospective lands.

Be l lat r i x ’s d r i l l i ng succe s s a nd mapping rev isions have resulted in i nc rea sed Ca rd iu m a nd Not i kew i n inventory. It now has 377 net locations in the Cardium light gravity oil play and 174 locations in the Notikewin condensate-rich gas resource play yielding over ­$ 2 .1 bi l l ion i n f ut u re development expenditures based on current costs of drilling.

The Devonian-aged Duvernay shale is emerging as one of the most promising resource plays in Canada. The company now controls 44 (43 net) sections of Duvernay rights in west-central Alberta.

— DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • M AR C H 2 0 1 2

47

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Southern Alberta

Photo: Joey Podlubny

Crew focused on Princess oil drilling in 2012

Success in southeastern Alberta allowed Crew to double production to 30,000 barrels equivalent per day in 2011.

Crew Energy Inc. has set this year’s capital budget at $300 million, with 141 (132 net) wells planned over the year, the company said in January.

While strong, the budget is about­­ 14­­per cent below the $350 million that the company spent in 2011. This year’s figure is designed to roughly equal 2012 cash flow, management said in a news release.

So far, 2011 is turning out to have been a good year for Crew, who estimate that fourth-quarter volumes will average about 30,000 barrels of oil equivalent per day. The figure would mean Crew more than doubled production since the fourth quarter of 2010, when volumes averaged 14,550 barrels per day.

On the drilling front, the company surged ahead, drilling 158 (155 net) wells in 2011, the most active year in its history, more than doubling the wells drilled in 2010.

At Princess, Alta., Crew drilled 62 horizontal, 45 vertical and 13 salt-water disposal wells in the fourth quarter. The company drilled more horizontal wells in 2011 than in the previous three years combined, yielding significant production gains, with five more wells awaiting tie-in and 22 wells awaiting optimization.

Results of Crew’s initial waterflood at the Pekisko “K” pool were encouraging, management said. In the last four months, fluid levels in producing wells there have risen as production rose to 43 barrels per day from 25 barrels per day. The increase is “directionally important,” since it represents a 72 per cent increase, the company said.

The producing Pekisko wells will be further optimized by pumping higher fluid volumes, with the current injection rate of 3,400 barrels of water per day expected to rise to 6,000 barrels in this year’s first

quarter. The 72 per cent rise in oil volumes was accompanied by a 19 per cent increase in water production, management said.

In 2012, Crew will focus on oil and li­q uids production at Princess, Lloydminster and Tower in northeastern British Columbia, to capitalize on strong oil prices. The program will advance seven secondary oil recovery schemes, and de-risk oil and natural gas liquids plays in British Columbia and Alberta’s Deep Basin. The $300-million capital program will be funded mainly by cash flow from operations and bank debt.

Of the 141 (132 net) wells planned for this year, 123 wells or 87 per cent will target oil, representing about 80 per cent of budgeted capital, and the remaining 18 wells or 13 per cent will target liquids-rich gas, management said.

In 2012, about 87 per cent of Crew’s wells will be drilled horizontally, up from 52 per cent in 2011. Seventy-five wells are planned at Princess. In addtion, two facil­ ities are budgeted to be expanded and five new waterfloods are expected to be implemented, as well as the completion of a number of pipeline projects.

Crew’s heavy oil assets will attract more capital this year. While drilling 13 heavy oil wells in 2011, the company plans 36 wells targeting heavy oil this year, with plans to re-complete 40 others. Crew is completing evaluation of enhanced recovery schemes on some Lloydminster, Sask., oil pools, and expects to have government approvals for implementation in late 2012 or early 2013, management said.

At Viking-Kinsella, in southeastern Alberta, Crew plans to drill four net oil wells and one net salt-water disposal well. The company plans to implement a waterflood at Killam in Crew’s 100 per cent Lloydminster oil pool with the drilling of three net injectors and one water-source well.

— DAILY OIL BULLETIN

SOUTHERN ALBERTA WELL ACTIVITY

JAN/11

JAN/12

WELL LICENCES

203

90

▼

JAN/11

JAN/12

WELLS SPUDDED

265

126

▼

JAN/11

JAN/12

WELLS DRILLED

257

115

▼

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • M AR C H 2 0 1 2

49

Southern Alberta

Legacy sets budget at $305 million

Photo: Joey Podlubny

L egac y Oi l + Gas Inc. w i l l spend $305 million this year, $254 million of which will be directed toward drilling, tie-ins and completions as the company plans to punch 123 (96 net) wells in 2012.

“Continued success in the company’s dominant position in the Spearfish in southern Manitoba and North Dakota, and the Rundle at Turner Valley has added significantly to…drilling inventory, and

Legacy is spending $98 million developing its Turner Valley oil play in 2012.

these areas will play a key role in 2012 organic activity and growth,” Legacy said in a January 26 press release.

With an emphasis on targeting light oil, Legacy said the majority of capital spending will be allocated to the company’s major plays: Turner Valley—$98 million (32 per cent); Spearfish (Manitoba and North Dakota)—$75 million (25 per cent); conventional Mississippian—$47 million (15 per cent); Frys/Antler—$27 million (nine per cent) and Taylorton—$19 million (six per cent).

In addition to drilling, Legacy is planning capital expenditures on a pilot waterflood at Frys/Antler and Taylorton. No capital has been budgeted for acquisitions, although the company continues to evaluate new opportunities, both within and beyond its core areas.

The company also intends to spend $28 million on facilities and $18 million on land and seismic, while $5 million has been designated for “other” activities.

Given its planned capital program, Legacy anticipates 2012 production to average 16,300 barrels of oil equivalent per day (85 per cent weighted to light oil and natural gas liquids), representing growth of 29 per cent over 2011 expected average production and 26 per cent on a per share basis.

The company noted that it has incorporated a “significant reduction” in second­-quarter volumes to account for the possibility of an extended spring break up in its Williston Basin core area. Legacy expects to exit 2012 at approximately 17,900 barrels per day, representing 10 per cent growth from 2011 exit-rate guidance.

Legacy begins 2012 with an extensive light oil development drilling inventory of more than 1,200 net locations, which represents over 12 years of develop­ment potential, based on expected 2012 activ­ ity levels.

“This significant opportunit y set does not reflect the potential upside from down-spacing Bakken light oil resource play lands from four to eight wells per section, or the waterflood potential at Frys/ Antler, Taylorton, Heward/Stoughton and Spearfish, and recognizes only a portion of the Bottineau County, North Dakota, Spearfish drilling potential,” it said.

T he company added t hat it has materi­a l exposure to emerging light oil resource plays in southern Alberta for Alberta Bakken, and Maxhamish in northeastern British Columbia for Chinkeh, “that could add significantly to the development drilling inventory and growth potential” of the company.

— DAILY OIL BULLETIN

DeeThree announces significant Brazeau well results DeeThree Exploration Ltd. reports that it has completed its fourth horizontal Belly River well in its Brazeau property.

The DeeThree-operated (89 per cent working interest) well was drilled to a planned total depth with a horizontal lateral in the target zone of approximately 1,100 metres. The horizontal lateral was successfully fracture stimulated, placing 320 tonnes of sand over 16 stages using an energized waterbased system.

After stimulation the well continued to flow for approximately five days up the 4 1/2-inch frac string with final stabilizing rates of approximately 600 50

M AR C H 2 0 1 2 • O I L & G A S I N Q U I R E R

­ arrels per day, of 44 degrees API resb ervoir oil, and 250 thousand cubic feet a day of natural gas.

Final water cuts dur ing t he test were approximately 20 per cent and decreasing as load water from the fracture stimulation was recovered. A production string has been installed and the well is currently shut in to conduct pressure work.

The well is expected to be returned to permanent production shortly, at rates similar to the test rates with oil being processed and natural gas conserved at DeeThree’s nearby pipelineconnected central battery.

DeeT hree said its Brazeau Belly River development program has more than doubled the production potential from the field with the four wells drilled to-date. The company has continued to improve its drilling results through increased geotechnical knowledge and operational efficiencies. As a result of its success in the area, DeeThree will increase the pace of the development of the property by bringing in a second rig by the end of January.

The company anticipates that it will release its 2012 capital expenditure and production guidance in the next few weeks.

— DAILY OIL BULLETIN

Southern Alberta

Bowood updates Alberta Bakken fairway results Bowood Energy Inc. reports that the company’s second Alberta Bakken test well, located at Kipp, started production in December.

The well, at 8-30-8-23W4, is located on the Blood First Nation Reserve.

The company has yet to establish a stabilized production rate due to the highpressure, multiphase influx of oil, water and gas that has hampered pump performance during this early stage of production. Bowood expects these issues are now largely resolved as the well continues to clean up, and expects that production will start to increase with better pumping efficiency.

After fracture stimulation, which occurred Oct. 25–29, 2011, and subsequent flow back of completion fluid, the well was shut in for three weeks to record static bottomhole pressure. The pressure data and the extrapolated pressure gradient confirm that the formation is overpressured, as expected.

Despite the fact that the early production operations at Kipp have been delayed, between the post-frac clean up, the initial equipping operation and the

first two weeks of intermittent production, the well has recovered over 5,000 barrels of light oil and approximately 50 per cent of injected load water.

Bowood said a comparison of public data on industry wells indicates that based on early cumulative production, the Kipp

approximately 60 per cent of injected load water has been recovered.

The company believes that the modest inflow is attributable to the inability to effectively fracture-stimulate the well, due to mechanical difficulties encountered in the wellbore during completion

Bowood said it continues to believe that this area of the fairway is highly prospective for both the Alberta Bakken and the Second White Specks oil plays. well appears to have the potential to be one of the better wells in the play to-date.

Meanwhile, t he company ’s f irst Alberta Bakken test well at Spring Coulee (2-36-3-23W4) has been on production for approximately three months.

This exploration well confirmed two important criteria in establishing commercial unconventional oil production in the area. The first is that the area is over-­pressured, and the second is that it is optimally located for peak oil generation, based on core results, the company said.

The Spring Coulee well has now produced approximately 2,500 barrels of oil since it was fracture-stimulated, and

­ pera­t ions, coupled with the low pero meability of the formation.

Since the Spring Coulee well encountered the light oil and over-pressured part of the fairway, the next steps to establishing commerciality at Spring Coulee will be to determine optimal stratigraphic placement of the horizontal well path in the multiple formations that make up the Bakken Petroleum System, and to establish an effective fracturestimulation program, the company noted.

Bowood said it continues to believe that this area of the fairway is highly prospective for both the Alberta Bakken and the Second White Specks oil plays.

— DAILY OIL BULLETIN

Pace unveils $100-million spending program targeting light oil Pace Oil & Gas Ltd. says its $100-million capital program for 2012 will increase oil output by 25 per cent over 2011, to more than 8,000 barrels per day by the end of the year.

Capital will focus exclusively on oil opportunities and capital spending will be funded by cash flow.

Production for 2012 is expected to average 14,500 –15,250 barrels of oil equivalent per day, with half coming from liquids, which will generate more than­­ 80­per cent of cash flow.

“We maintain our optionality on our large gas resource prospect inventory, but the success and strong economics of our oil plays allow us to focus on our oil prospects,” said the company.

Pace is forecasting 2012 production of: 7,150–7,550 barrels of oil per day,

225–275 barrels per day of natural gas liquids and 42.8–44.6 million cubic feet per day of gas.

Pace’s capital for 2012 will be allocated as follows: Southern Alberta (Glauconite, Lithic, Pekisko, waterflood development), 35–40 per cent; Dixonville (Montney C, waterflood optimization), 15–20 per cent; Red Earth (Slave Point), 15–20 per cent; Haro South (Pekisko), about 10 per cent; and, Land, seismic, general and administrative, and other, 15–25 per cent.

The company plans to drill 33 (27 net) wells this year. Drilling and completion costs are expected to make up 75 per cent of the budget, facilities costs are expected in the five to 10 per cent range, and land, seismic, general and administrative and other contributions will c ompr i s e 15 –25 per cent of costs.

Pace has more than 300,000 net acres of high working–interest lands in southern Alberta, and is pursuing a development exploitation program of horizontal drilling to grow oil-weighted production in this area.

In 2011, Pace drilled 17 (15.8 net) wells in southern Alberta and increased oil production by more than 20 per cent from December 2010, with December 2011 output of more than 4,900 barrels equivalent per day (46 per cent liquids).

In 2012, 35–40 per cent of Pace’s cap­ ital will be allocated to southern Alberta, where the company plans to drill 24 (18 net) horizontal wells. In addition, the company will spend approximately $5 million to initiate a waterflood in the Retlaw BBB and NNN pools, and expects a response within 12 months of the initial injection.

— DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • M AR C H 2 0 1 2

51

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Saskatchewan

Renegade production up, will spend more in 2012

JAN/11

JAN/12

JAN/11

JAN/12

WELLS SPUDDED

287

357

WELLS DRILLED

274

330

Photo: The Pipeline News

$100 million from $80 million, representing a 25 per cent increase. Closing of the operating facility expansion is expected to occur near the end of January.

It drilled 17 (14.3 net) wells in the fourth quarter with a 94 per cent success rate, which included 12 (9.3 net) wells in southeastern Saskatchewan and Manitoba, and five (5.0 net) wells in the Viking.

During the final quarter of 2011, Renegade drilled 12 (9.3 net) wells in southeastern Saskatchewan with a 92 per cent success rate. Renegade successfully drilled a dual leg Souris Valley well with initial production exceeding 300 (150 net) barrels per day of light oil.

Based on the success of this well, this further supports up to 20 additional development horizontal locations within the Souris Valley pool.

Renegade has also conducted an e x plorator y prog ra m con sist i ng of seven (7.0 net) wells focused on various key opportunities in southeastern Saskatchewan and Manitoba. The success of the exploratory program has led to the discovery of new pools and the delineation of additional exploratory trends.

As a result of this recent success, Renegade has increased the number of inventory drilling locations by approximately 60 per cent in southeastern Saskatchewan and Manitoba.

Meanwhile, in the Viking, Renegade drilled five (5.0 net) wells in the fourth quarter of 2011 with a success rate of 100 per cent.

Further to the success of the 2011 program, Renegade has begun a down­ spacing program in two key areas of its operations. The initial pilot is located in the Lucky Hills area, with one well drilled at 40-acre spacing. Results from this pilot have exceeded management’s expectations, and, as such, Renegade has begun drilling further locations in Lucky Hills at 40-acre spacing. The results of the pilot have shown no negative effects on the production of either the pre-existing or down-spaced location.

In southeastern Dodsland, the company has begun its 2012 drilling program with a pilot on 40-acre spacing. With the success of these pilots, Renegade said it can aggressively de-risk and increase it s wel l i nventor y i n west- cent ra l Saskatchewan.

Renegade has approved a 2012 capital budget of $76 million for exploration and development activities (excluding major corporate or land acquisitions), with approximately 83 per cent of the total budget allocated toward drilling, completions and well-equipping activities.

The company anticipates drilling a total of 67 (61.3 net) wells in 2012. Production is expected to average 4,000–4,200 barrels

Southeastern Saskatchewan and Manitoba have proved fertile ground for Renegade Petroleum.

The company plans 67 wells this year.

Renegade Petroleum Ltd. reports that due to its successful 2011 drilling program, the company achieved exit production of approximately 3,800 barrels of oil equiva­lent per day, surpassing the previously announced 2011 exit guidance of 3,750 barrels per day.

Production for the fourth quarter averaged approximately 3,625 barrels per day, with a 96 per cent light oil weighting. Fourthquarter production was up 27 per cent from 2,852 barrels per day reported in the third quarter of 2011, and an increase of 139 per cent from 1,517 barrels per day reported in the fourth quarter of 2010.

Due to the success of its 2011 capital program, Renegade has substantially increased its drilling inventory to over 589 (498 net) locations.

T he company increased its bank line with National Bank of Canada to SASKATCHEWAN WELL ACTIVITY

JAN/11

JAN/12

WELL LICENCES

424

421

▼

▲

▲

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • M AR C H 2 0 1 2

53

Saskatchewan

per day (approximately 96 per cent light oil), with a year-over-year production increase of 68 per cent (based on 2012 average forecasted production of 4,200 barrels per day versus 2011 average production of 2,500 barrels per day).

Due to the extended breakup in 2010 and 2011 due to wet weather

­c on­d itions, Renegade has assumed an extended breakup for 2012 in southeastern Saskatchewan and has factored the extended breakup into its 2012 averages.

Renegade said it continues to be excited and optimistic about generating growth prospects in 2012 and continues to be committed to delivering per share growth and

capital efficiency. Renegade currently has over 589 potential (498 net) drilling locations in its inventory. This depth of drilling inventory positions the company well for long-term organic growth in production, cash flow, reserves and net asset value in 2012 and beyond, it said.

— DAILY OIL BULLETIN

Photo: The Pipeline News

Crescent Point buys Wild Stream production

Crescent Point added 200 sections of land in the Shaunavon play in the Wild Stream deal.

Crescent Point Energy Corp. has entered into an arrangement to buy the majority of Wild Stream Exploration Inc.’s production while Wild Stream’s remaining output will be transferred to a new, junior exploration company.

Wild Stream is a publicly traded, 90 per­cent oil-weighted company with volumes of about 6,400 barrels of oil equivalent per day. Under the terms of the arrangement, Crescent Point expects to acquire approximately 5,400 barrels a day of Wild Stream’s production, 91 per cent of which is contiguous with Crescent Point’s assets in the Shaunavon and Battrum/Cantuar areas of southwestern Saskatchewan.

54

M AR C H 2 0 1 2 • O I L & G A S I N Q U I R E R

The balance of Wild Stream’s production will be transferred into a new junior company, in which Crescent Point will hold 2.65 million shares.

Completion of the arrangement is expected to further solidify Crescent Point’s position as the largest player in the Shaunavon resource play in southwestern Saskatchewan, in terms of production and land.

Wild Stream’s assets will also complement Crescent Point’s existing position in Alberta’s emerging Beaverhill Lake light oil resource play in the Swan Hills area where the company has been expanding.

As a result of the proposed arrangement and Beaverhill Lake transactions, Crescent Point is upwardly revising its 2012 capital expenditure plans and guidance.

Capital expenditures are anticipated to increase by $50 million, up to $1.15 billion, with $42 million of the increase expected to be allocated to the Shaunavon play to drill an incremental 19 net wells, bringing the total expected for the year to 91 net wells.

Assuming the successful completion of the Wild Stream arrangement, Crescent Point’s average daily production in 2012 is expected to increase to 83,500 barrels equivalent per day from 80,000 barrels a day, and its 2012 exit production rate is expected

Saskatchewan

to rise to more than 90,000 barrels equivalent per day from 85,000 barrels a day.

In the Shaunavon resource play, the company expects to have combined production of more than 15,000 barrels per day and more than 800 net sections of land, which include more than 200 net sections expected to be acquired in the Wild Stream arrangement.

The company has also announced it has expanded its land position in the Beaverhill Lake light-oil resource play in northwestern Alberta by more than 100 net sections through a series of acquisitions and Crown land sales, including 15 net sections expected to be acquired in the Wild Stream arrangement.

As part of the Wild Stream arrangement, Wild Stream will move certain of its assets in the Dodsland area into the new company and assume debt of $43.5 million.

Key attributes of the Wild Stream assets to be acquired also include: 37 net sections of land in the Battrum/Cantuar area of southwestern Saskatchewan; more than

240 net internally identified low-risk drilling locations, including more than 190 net locations in the Shaunavon resource play and tax pools estimated at $350 million.

Independent engineers have assigned reserves using NI 51-101 reserve definitions effective Dec. 31, 2011, as follows:

light oil resource play in Alberta through a series of acquisitions and Crown land sales.

During the past six months, Crescent Point has acquired more than 85 net sections of land in the play, the majority of which are undeveloped, for aggregate consideration of approximately $38 million of cash.

In the Shaunavon resource play, the company expects to have combined production of more than 15,000 barrels per day and more than 800 net sections of land....

approximately 28.7 million barrels equivalent of proved-plus-probable and 17.6 million barrels of proved reserves; and reserve life index of 14.6 years provedplus-probable and 8.9 years proved.

In addition, Crescent Point has expanded its land position in the Beaverhill Lake

In total, and assuming the successful completion of the Wild Stream arrangement, the company will have more than 280 net sections of land in the emerging Beaverhill Lake play, of which 271 net sections are undeveloped.

— DAILY OIL BULLETIN

Production up at PetroBakken PetroBakken Energy Ltd. reported that average production for December 2011 (based on field estimates) exceeded 50,000 barrels of oil equivalent per day (87 per cent light oil and natural gas liquids), a 23 per cent increase over third-quarter 2011 production and an 18 per cent increase over December 2010 production.

The company said it remained active in all business units into December, with field operations tailing off through the end of the year as the capital program was completed ahead of schedule.

December average production of over 50,000 barrels equivalent per day was comprised of more than 23,400 barrels per day from the Bakken business unit, over 16,500 barrels per day from the Cardium business unit (with 1,450 barrels per day currently shut-in awaiting tie-in operations), and the remainder of the production generated by the company’s Saskatchewan conventional and Alberta/ British Columbia (Alberta/B.C.) business units.

During 2011, PetroBakken drilled 293 (205 net) wells.

Fourth-quarter activity saw a total of 82 (54 net) wells drilled, with 23 (16 net) wells drilled in the Bakken, 34 (22 net) wells drilled in the Cardium, 21 (12 net) wells drilled in the Saskatchewan conventional business unit and four (four net) wells in the Alberta/B.C. business unit.

At the end of the year, the company had an inventory of 15 net wells waiting to be completed or placed on production.

Of these wells, one was in the Bakken and eight were in the Cardium, with the remainder in the Saskatchewan conventional and Alberta/B.C. business units. Of particular note, two new prospect wells in Alberta have tested commercial quantities of light oil with the other two wells awaiting completion and testing operations.

The company anticipates capital de­v elopment expenditures of approximately $700 million, primarily focused on horizontal drilling and completions, predominantly in the Bakken and Cardium light oil plays. It expects that this drillingfocused activity will generate a 2012 exitproduction rate of between 50,000 and 54,000 barrels of oil equivalent per day.

Estimated year-over-year average production

growth is expected to exceed 15 per cent, on an absolute and per-share basis. This initial program is expected to be executed entirely from funds from operations.

PetroBak ken also announced in January it has entered into an agreement to sell its entire working interest in the southeastern Saskatchewan Weyburn unit (approximately a 2.2 per cent interest) for gross proceeds of $105 million, subject to adjustments.

The assets include 580 barrels of oil equivalent per day of production (based on field estimates from December 2011).

The transaction will have an effective date of Jan. 1, 2012, and, subject to satisfaction of all conditions and receipt of required regulatory approvals, is expected to close by the end of February.

Approximate transaction metrics in respect of this sale of the non-core assets are $180,000 per flowing barrel (based on field-estimated December 2011 average production), nine times 12-month trailing cash f low (October 2010-11) and $23 per barrel of gross proved-­p lusprobable reserves.

— DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • M AR C H 2 0 1 2

55

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East Coast

Shell spending $970 million on four exploration blocks offshore Nova Scotia

Photo: Joey Podlubny

By Pat Roche

Shell is expected to begin drilling on its new offshore blocks in 2014.

Royal Dutch Shell plc successfully bid $970 million for four leases about 200 kilometres southeast of Nova Scotia, the Canada-Nova Scotia Offshore Petroleum Board (CNSOPB) announced in January.

“These work expenditure bids are the highest received to-date,” said Stuart Pinks, the CNSOPB’s chief executive officer.

“These lands are located offshore southwestern Nova Scotia, where recent studies have identified oil potential,” Pinks said in a news release.

He said t he CNSOPB reg ulator y regime will ensure petroleum activities, “are only conducted by competent parties in a manner which holds the health and safety of offshore workers and the protection of the offshore environment paramount.”

The bids represent money the company intends to spend on exploration during the first six years of a nine-year exploration licence. Successful bidders are required to post a deposit of 25 per cent of the bid amount to demonstrate their commitment to conduct the intended work.

The terms of the call for bids required bidders to have experience drilling exploration

wells in water depths greater than 800 metres in the past 10 years.

The CNSOPB said Shell demonstrated that it has extensive worldwide experience in deepwater drilling including involvement in three previous deepwater exploratory wells drilled offshore Nova Scotia and Newfoundland-Labrador.

Shell is hoping to record 3-D seismic data over its new acreage next year and to drill the following year, depending on the availability of seismic crews and drilling rigs, said Stephen Doolan, a Shell spokesman.

The company plans to spend $1.76 million on Parcel 1, $303.08 million on Parcel 2, $235.03 million on Parcel 3 and $430.14 million on Parcel 4.

“This bid is an example of the reinvigorated interest in Nova Scotia’s offshore oil potential, which could be as much as eight billion barrels of oil,” Peter MacKay, minister of national defence and regional minister for Nova Scotia, said in a press release.

“Exploration off Nova Scotia’s coasts ensures that our energy sector remains dynamic and jobs are created in our communities. This is an exciting time for all Nova Scotians.”

Added Joe Oliver, federal minister of natural resources, “The energy sector will continue to be a major source of prosperity, bringing jobs and economic development to communities across Canada. We welcome this significant investment in our energy industry—the single largest bid in the area.”

No bids were received on the other four parcels included in the call for bids.

The CNSOPB’s next call for bids will be issued in May with nominations now being accepted until March 16. The board expects to soon release more information regarding future calls for bids, including forecasts of lands, which may be included.

Last year, the Nova Scotia government completed a two-year, $15-million study, which sought to explain why exploration wells drilled off the province’s coasts in recent years had been largely unsuccessful.

The play fairway analysis was designed to identify key hydrocarbon-bearing fairways and the petroleum play types that may exist in these fairways.

The detailed analysis also led to a tripling in the province’s estimate of offshore resource potential to 120 trillion cubic feet of natural gas and eight billion barrels of oil.

O I L & G A S I N Q U I R E R • M AR C H 2 0 1 2

57

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Technology News

Photo: Allmand Bros.

Allmand Maxi-Heat portable heater features greater fuel capacity

The Maxi-Heat heater can run more than 30 hours without refuelling.

A llmand Bros. Inc. has upgraded its popular Maxi-Heat portable heater with greater total fuel capacity.

The Allmand Maxi-Heat MH-1000 heater now feat ures t hree smaller, molded-poly fuel tanks instead of a single large steel tank. The new fuel tank system has one 50-gallon engine supply tank, and two 100-gallon heater supply tank s. T he nearly 60 -gallon increase will prov ide more than 30 hours of continuous operation without refuelling.

A s a n adde d b e ne f it , t he ne w molded-polymer tanks are corrosionre si st a nt. I n add it ion, t he l ig hter material reduces the overall weight of the tanks, partially offsetting the additional weight resulting from the increased fuel capacity.

Reduce d c apac it y of i nd iv idua l ta n k s mea ns t hat no si ngle ta n k is over 450 l it res (118 ga l lon s). T h i s b r i n g s t h e t r a i l e r u n de r t h e f u e l capacit y limits of Transport Canada r eg u l at ion CGSB 43.14 6, mea n i ng that no initial or subsequent tank certifications are required, resulting in a

substantial cost savings over the life of Maxi-Heat trailers.

This new increased fuel capacity is in addition to earlier Maxi-Heat upgrades that include higher static pressure and the ability to run longer ducting.

The static pressure of the Maxi-Heat increased from .5” wc, to 2.3” wc. This increase in static pressure has allowed Allmand to increase the length of the Maxi-Heat’s 16-inch ducting from 40 feet to 110 feet.

T he Ma x i-Heat play s a n i mportant role in the mining and petroleum industries, cement curing, equipment pre-heating, pipeline const r uction, restoration and general construction.

According to A llmand’s director of marketing, Doug Dahlgren, the new upgrades to Maxi-Heat have increased both the performance and versatility of the portable heating unit.

“There are many applications that now require air to be ducted up to 100 feet,” Dahlgren said. “Incorporating a new fan-motor combination and increasing the static pressure helps ensure that clean, breathable air can be delivered

to the work area, and provides a wider variety of heat distribution options.”

Ma x i-Heat feat ures t w in heater u n it s t hat produce a ma x i mu m of 1,010,0 0 0 B r it i s h t h e r m a l u n it s , and may be operated independently depending on heating requirements. A standard 1,800-rpm liquid-cooled Isuzu 3CD or optional CAT C1.5 diesel engine w it h reg ulated generator prov ides power for the heaters and electrical accessories.

In addition to t he f uel tan k s, a static pressure and ducting upgrade, Dahlgren says Allmand has incorporated another important performance feature into the Maxi-Heat. “We have also added in-line fuel heaters and prefilters to the fuel system on the unit,” Dahlgren explained. “This is especially important in those situations where fuel may be contaminated or may not be blended properly for the operating conditions. The heater/pre-filters makes the system more tolerant to dirt and variances in the viscosity of the fuel, which means improved performance and dependability.”

O I L & G A S I N Q U I R E R • M AR C H 2 0 1 2

59

Technology News

CanElson Drilling to fuel mobile equipment with stranded gas CanElson Drilling Inc. has announced it has a patent pending for the fuelling of mobile equipment with stranded or flared natural gas.

Stranded gas is defined as natural gas that is not being moved from the well to market due to a lack of infrastructure.

CanElson has tested and evaluated the technology to utilize trucked compressed natural gas (CNG) on its mechanical drilling rigs. Initial tests have been very positive and indicate strong economics to support the next phase of development, which includes implementing the technology on four of the company’s drilling rigs located in the Saskatchewan Bakken resource play during the second quarter of 2012.

This next phase of development will implement the delivery of gas directly to the drilling rigs using mobile gas transport modules. In the third and fourth quarters, CanElson expects to expand the utilization of the technology into North Dakota and the Permian Basin of western Texas. Bi-f uel is a proven technology, consisting of CNG injected into the inlet air of a diesel engine. The natural gas can replace up to 60–70 per cent of the diesel fuel when the engine is under load.

Fu r t her sav i ngs a re possible i n winter because a rig boiler can be fired on 100 per cent CNG, and there are other mobile diesel engine applications (e.g., fracture stimulation equipment).

Using heating value, the current d ie se l e qu iv a le nt v a lue of C NG i s approximately $30 per thousand cubic feet. By displacing a portion of used diesel fuel from its drilling rigs with CNG, there is a significant economic and env ironmenta l oppor t unit y for the company, as well as its customers and t he communities where t he rigs work.

President and chief executive officer Randy Hawkings says: “This is an exciting and unique opportunit y for the company to provide cost-effective solut ion s for ou r c u stomer s wh i le increasing the corporation’s profitabilit y and reducing the env ironmental footprint of our operations.”

Enviro Vault’s ThermoVault provides safe alternative for heating fluids in hazardous areas T he T her moVau lt by E nv i ro Vau lt Canada Ltd. offers a safe, effective alternative to fire tube/burner assemblies for heating above-ground storage tanks. The ThermoVault is ideally suited for use in hazardous areas such as light oil applications when fire tubes may not be allowed.

With assistance prov ided by the G over n ment of Ca nada’s Nat iona l Research Council Industrial Research

testing the system’s ability to raise and maintain fluid temperatures in aboveground storage tanks.

“Innovation is about continually looking for a better way, and our focus has always been on improving tank safety and functionality by expanding the range of benefits offered by the Enviro Vault internal chamber platform,” says Russ Hebblethwaite, president of Enviro Vault Canada Ltd.

The patented internal chamber serves to improve environmental performance, safety and operations by containing fluid spills from the tanks inlet and outlet valves, and by providing secure, freezeprotected area, ground-level access to valves and instruments.

The Enviro Vault is the patented concept whereby a recessed chamber is installed “inside” the tank with an access door through the tank wall. All valves,

“ Innovation is about continually looking for a better way, and our focus has always been on improving tank safety and functionality by expanding the range of benefits offered by the Enviro Vault internal chamber platform.”

— Russ Hebblethwaite, president, Enviro Vault Canada Ltd.

Assistance Program (NRC-IRAP), Enviro Vault contracted the services of Alberta Innovates–Technology Futures (AITF, formally the Alberta Research Council) to conduct a comprehensive research a nd de ve lopme nt a n a ly si s of t he ThermoVault’s innovative use of catalytic heaters mounted within a chamber recessed to the inside of the tank shell, 60

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ThermoVault testing revealed reductions in nitrous oxide and carbon monoxide while meeting the same heating requirements compared to conventional fire tube burner assemblies.

Based in Calgary, company founder Hebblethwaite developed the Enviro Vault to improve the safety and performance of oil storage tanks in field operations.

sample taps, electronic controls and heaters (if required) are mounted in the Enviro Vault. Enviro Vaults can be fitted in any size or shape of new tanks or in-service tanks for any specific application heavy oil and light oil production tanks, produced water, potable water, asphalt tanks, separator packages, rental tanks and any other application where a tank is required.

BUSINESS ADVICE

BUSINESS INTELLIGENCE AirCon Technologies tackles their growing pains with monthly performance measurements

By Dustin Sundby, CA

In 2007, AirCon Technologies of Fort McMurray Ltd. was faced with a problem. “A fantastic problem,” says Liam Burgess, the company’s chief executive officer and owner. They couldn’t stop growing.

The company, which provides services in air conditioning, heating and fire suppression systems on mine-mobile equipment, had been steadily growing since opening their doors 13 years earlier.

With more growth opportunities and potential customers on the horizon, AirCon took the opportunity to reassess how they were managing the financial end of their business.

“One of our goals was to develop a better understanding of our business financially,” explains Liam. “We were asking ourselves a lot of questions. Not just how much did we want to take on in terms of new business, but how do we get leaner? How do we become more efficient? We wanted to know how to maximize the financial aspect of the business all-around. There were a lot of great things happening in our business and this was an area where we recognized we wanted some more professional input and feedback.”

That was when AirCon, and Liam, started working with Greg Yaceyko, a Meyers Norris Penny LLP (MNP) business advisor. AirCon was already working with MNP’s local office to complete their yearend compliance work. “We felt that, because we used MNP for all of our accounting requirements, it was the best fit. When we wanted to discuss an issue, we were just that much farther down the road given that the information, knowledge and relationship already existed,” says Liam.

Based in Fort McMurray, Alta., Greg began working with AirCon on a performance measurement engagement. He monitors the company’s monthly financials, letting them know how they’ve done, identifying areas for improvement, and setting targets and goals with them. “Basically, I help them with whatever they need,” says Greg.

“You can manage what you can measure, and make sound business decisions accordingly. That is one of the real benefits of ongoing performance measurement.”

For Liam, one of the major benefits of the performance measurement is how it has increased his everyday awareness of the company’s financial situation. “In the past, when we weren’t involved with Greg or the program, we were definitely reactive to situations of increasing costs without them properly being identified. It would take us three or four months before we picked up on a slow bleed.

Now, every single month, we have close-out. I understand where we are and I can quickly detect areas that need to be addressed. All

those methods of measurement allow us to be very proactive in how we approach our day-to-day decisions on the financial performance of the business. It’s removed a lot of the surprises that exist out there,” he says.

In addition to the performance-measurement work, the two men have collaborated on other areas of the business. “At the end of the day, my reason for being is to help my clients succeed and maximize their wealth,” explains Greg. “With AirCon, and other clients where I have an ongoing engagement, I’m not just there once a year talking to them about their financial statements. I am familiar with the company and in close contact with the people involved. If there is another need—be it [information technology] or human resources— that MNP can help them with, I am there to help facilitate that.”

“There are so many things that we’ve come to understand as value-add services being offered by MNP,” adds Liam. “Greg and I are in such constant communication that we both understand where AirCon is today, where we will likely be tomorrow and the sort of challenges that we know are coming. It’s an interesting time in this particular market—there are so many opportunities—that I often find myself turning to Greg to help determine what the best course of action is.

“My relationship with Greg is very important. Our business has seen the benefits on paper, where it counts. Because of the level of measurement that we’ve had since we decided to strengthen our relationship with Greg and MNP, his involvement with AirCon can also be measured. And that measurement is a very positive one for this business,” he says.

As AirCon continues to grow, they will eventually require a fulltime chief financial officer in-house. But Liam is confident that change would only mean adapting Greg’s role with the company.

“We’re really happy with the performance to-date and I really get the feeling we’re working together. There are benefits in the relationship for both of us to grow this thing to its full potential.”

To find out what MNP can do for your business, contact: Greg Yaceyko, CA, Business Advisor, 1.866.465.1155.

O I L & G A S I N Q U I R E R • M AR C H 2 0 1 2

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advertisers' index Activated Environmental Solutions Inc . . . . . . . 44

Emirates Airlines . . . . . . . . . . . . . . . . . . . . . . . . . 10

NETZSCH Canada Inc. . . . . . . . . . . . . . . . . . . . . . 56

Annugas Compression Consulting Ltd . . . . . . . . 22

Ensign Rockwell Servicing . . . . . . . . . . . . . . . . . . 43

Northgate Industries Ltd . . . . . . . . . . . . . . . . . . . 56

ASAP Heating & Well Servicing Corp . . . . . . . . . 48

Expertec Van Systems Inc . . . . . . . . . . . . . . . . . . 32

Petroleum Services Association of Canada . . . . 40

Barrett Tax Law . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Flexpipe Systems . . . . . . . . . . . . . . . . . . . . . . . . . 6

Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . . 40

Bear Slashing Inc . . . . . . . . . . . . . . . . . . . . . . . . . 48

General Motors of Canada Ltd . . . . . . . . . . . . . . . 5

Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . . 27

Hughson Trucking Inc . . . . . . . . . . . . . . . . . . . . . . 32

Bilton Welding and Manufacturing Ltd . . . . . . . . 27

Infosat Communications LP . . . . . . . . . . . . . . . . . 18

Brother’s Specialized Coating Systems Ltd . . . . 48

ISA Edmonton . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

Canada Colors & Chemicals Ltd . . . . . . . . . . . . . . 52

Joule Technical Sales Inc . . . . . . . . . . . . . . . . . . . 43

Canadian Enviro-Tub Inc . . . . . . . . . . . . . . . . . . . 20

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

Canadian Standards Association . . . . . . . . . . . . 52

MCI Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Chemineer, Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Meridian Manufacturing . . . . . . . . . . . . . . . . . . . . 16

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

Minimal Impact . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Trans Peace Construction (1987) Ltd . . . . . . . . . . 36

Diversified Glycol Services Inc . . . . . . . . . . . . . . 43

MNP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Vertigo Theatre Society . . . . . . . . . . . . . . . . . . . 40

Dragon Products . . . . . . . . . . . . . . . . . . . . . . . . . 28

NAIT Corporate and International Training . . . . . 25

V.J. Pamensky Canada Inc . . . . . . . . . . . . . . . . . . . 13

Ecoquip Rentals & Sales Ltd . . . . . . . . . . . . . . . . 44

NCS Oilfield Services Canada Inc . . . . . . . . . . . . . 7

Wildrose Alliance . . . . . . . . . . . . . . . . . . . . . . . . 44

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Platinum Energy Group . . . . . . . . . . . . . . . . . . . . . 21 Southern Alberta Petroleum Show . . . . . . . . . . . 36 Sprung Instant Structures . . . . . . . . . . . . . . . . . . 19 Strad Energy Services . . . . . . . . inside front cover Systech Instrumentation Inc . . . . . . . . . . . . . . . . 12 Tartan Controls Inc . . . . . . . . . . . . . . . . . . . . . . . . 17 TCA Marketing Ltd . . . . . . . . . . . . inside back cover

TCA provides engineered steel containment solutions for the Western Canadian Oil and Gas Industry

537818 TCA Marketing Ltd full page · fp IBC ENGINEERED CONTAINMENT ADVANTAGES

WALL HEIGHTS INCLUDE

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Professionally Installed

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12"

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25"

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45"

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55"

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66” (Coming Soon)

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Completely Reusable

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Crossover Steps Available for all Wall Heights

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Expandable

For a dealer in your area

1-866-TCA-7771

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33"

Check Out the New 6 Bolt System!

www.thecontainmentanswer.com New Branch in Carlyle, SK | Ph: 306-575-8111 6404 – 53 Street, Taber, AB T1G 2A2 | Ph: 403.223.1113 | Fax: 403-223-6312

TOG E T HE R WE CAN

400250 MaXfield Inc full page 路 fp OBC

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.

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