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produCtion deClines, Changing aCtivity in WCsb mean another restruCturing of the gas proCessing industry. a proposed neW strategy hopes to guide the Way.

Calgary serviCe suppliers brand themselves as industry's teChnologiCal problem solvers

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Contact your local Baker Hughes representative or visit us online and find out how we can help you cut costs while advancing the performance of your reservoir.

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Caterpillar G3306TA

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Waukesha 5794 LT

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W400-JGA-3

400

Waukesha F18CL

Ariel JGA-4 Throw

W1445-JGK-3 1445

Waukesha 5794 LT

Ariel JGK-4 Throw

C630-JGJ-3

630

Caterpillar 3508 TALE Ariel JGJ-4 Throw

W1445-JGK-3 1445

Waukesha 5794 LT

Ariel JGK-4 Throw

C630-JGJ-3

630

Caterpillar 3508 TALE Ariel JGJ-4 Throw

W1680-JGK-3 1680

Waukesha 7044

Ariel JGK-4 Throw

C630-JGJ-3

630

Caterpillar 3508 TALE Ariel JGJ-4 Throw

C1775-JGC-3 1775

Caterpillar G3606 TAW Ariel JGC-4 Throw

C810-JGH-3

810

Caterpillar G3512 TALE Ariel JGH-4 Throw

C1775-JGC-3 1775

Caterpillar G3606 TAW Ariel JGC-4 Throw

hp 810

Engine

Compressor

Caterpillar G3512 TALE Ariel JGH-4 Throw

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Keeping readers regionally informed

F E A T U R E S

8

M AY 2011 • O I L & G A S I N Q U I R E R

14

Service central

21

Redrawing the map

By Mike Byfield

Calgary service suppliers brand themselves as industry's technological problem solvers

By Mike Byfield

Production declines, changing activity in WCSB mean another restructuring of the gas processing industry. A proposed new strategy hopes to guide the way.

building GROW ON YOUR MAKE brand Pop-up Displays R E G I O N A L

27

N E W S

British Columbia

49

• Encana joins Kitimat LNG export project

Southern Alberta • Services sector under greatest threat in severe, looming labour shortage

31

Northwestern Alberta • $200-million sale brings Alberta fiscal

By Lynda Harrison

57

expected to climb

By Richard Macedo

37

Northeastern Alberta

61

• Shell considers US$2-billion oilsands

43

Central Alberta

shale gas

63

East Coast • Corridor's results continue

• Enhance advances CO2 plans

By Pat Roche

Central Canada • Quebec announces new royalty for

debottleneck

By Lynda Harrison

Saskatchewan • Saskatchewan oil revenue, production

year total to $2.6 billion

downward trend

65

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O I L & G A S I N Q U I R E R • M AY 2011

9

Editor’s Note Vol. 23 No. 4 President & ceo Bill Whitelaw | bwhitelaw@junewarren-nickles.com Group Publisher Agnes Zalewski | azalewski@junewarren-nickles.com Associate Publisher Chaz Osburn | cosburn@junewarren-nickles.com Editorial director Stephen Marsters | smarsters@junewarren-nickles.com

Darrell Stonehouse | stonehouse@junewarren-nickles.com

EDITORIAL

Adding Value

Editor

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Calgary long ago made the transition from “Cowtown” to become the Canadian headquarters for global oil and gas producers.

Over 300 domestic private and public producing companies have their home base in the city, along with a few dozen foreign multinationals that have large regional offices.

In recent years, Calgary has also advanced as a global centre for the oil and gas service and supply sector. The domestic service industry has grown from being suppliers of iron labour to supplying innovative solutions for the challenges facing producers in a mature and challenging geological basin.

A famous example of this innovation is the Packers Plus Energy Services Inc. “ball drop” system for delivering multistage fractures quickly and accurately. Other providers are making similar advances, a few of which are outlined in this month’s issue.

Calfrac Well Services Ltd. is one of these homegrown success stories. Started in 1999, the fracturing and completion specialist has grown to over 3,000 employees and operates on an international basis. Driving its growth has been a relentless focus on understanding its customers’ needs and coming up with technological innovations that provide effective solutions. Most recently, this includes new pump panels to cut the amount of labour needed during fracking jobs and new fuel systems for engines that allow them to run on natural gas at remote wellsites like those in the Horn River.

PumpWell Solutions Ltd. is another company in the early stages of building a service niche by providing technology that solves producer concerns. Its pump jack monitoring and optimizing system can lift oil production as much as 50 to 100 per cent on some wells.

The service community’s ability to generate new technologies created a situation where, in some fields, the Canadian industry is oversupplied. It is now exporting technologies southward to the United States and around the world.

The first fallout from the rise of the value-added service provider is a structural change in the gas production in western Canada. Long extended-reach horizontal wells and multistage fracturing have opened up shale gas basins for production, resulting in an oversupply of gas.

Older fields are no longer competitive, meaning gas production in those areas is declining and midstream assets are going underused.

In this issue, two Calgary-based gas analysts make the case that industry needs to work together to consolidate its gas processing assets in light of this structural change. The focus is on sour gas facilities in the foothills, where production is in deep decline. The analysts make the case that by right-sizing these assets or converting them when possible to handle shale gas, both industry and government will financially benefit in the long run.

One final note: This issue of the Oil & Gas Inquirer marks the end of Mike Byfield’s tenure as editor. Over the last three years, Mike did tremendous work in moving the magazine forward to better serve you, the reader. We would like to thank him for his service.

Oil & Gas Inquirer is owned by JuneWarren-Nickle’s Energy Group and is published monthly.

GST Registration Number 826256554RT. Printed in Canada by PrintWest. ISSN 1204-4741 | © 2011 1080554 Glacier Media Inc. All rights reserved. Reproduction in whole or in part is strictly prohibited.

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N E X T

I S S U E

June edition

If you know an admirable person to profile in On The Job—he or she may be a veteran

Our next issue of the Oil & Gas Inquirer will

or apprentice, field or shop, wise or a little

look at how the Canadian service companies

crazy—please give Darrell Stonehouse

are exporting homegrown technologies to the

a call at (403) 265-3700, or email

United States and beyond. Plus we’ll take a look

dstonehouse@june­warren-nickles.com.

at how Alberta pressure vessel manufacturers

In fact, feel free to sound off about any

are doing, and what the future holds for the

concern at all—that’s a personal invitation.

industry as oilsands development picks up.

O I L & G A S I N Q U I R E R • M AY 2011

11

Stats

FAST NUMBERS

270

AT A GLANCE

billion

Dollars in sales expected to be generated by Canadian oil and gas industry in next five years.

Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin

MONTH

OIL

GAS

OTHER

TOTAL

MONTH

OIL

GAS

DRY

SERVICE

TOTAL

Apr 2010 May 2010 Jun 2010

198 400 126

418 462 117

6 51 41

622 913 284

Apr 2010 May 2010 Jun 2010

291 490 295

458 511 153

2 39 40

9 19 16

760 1,059 504

Jul 2010 Aug 2010 Sept 2010

131 168 357

110 135 638

38 43 59

279 346 1,054

Jul 2010 Aug 2010 Sept 2010

193 452 617

9 156 790

16 40 45

4 15 23

222 663 1,475

Oct 2010 Nov 2010 Dec 2010

404 579 676

460 847 403

46 169 294

909 1,595 1,373

Oct 2010 Nov 2010 Dec 2010

678 868 1,061

581 989 559

39 75 78

18 165 238

1,316 2,097 1,936

Jan 2011 Feb 2011 Mar 2011

226 353 650

145 294 974

82 127 222

413 774 1,846

Jan 2011 Feb 2011 Mar 2011

409 723 1,069

201 378 1,081

33 38 64

17 99 164

660 1,238 2,378

Wells Drilled In British Columbia

Saskatchewan Completions

Source: B.C. Oil and Gas Commission

Source: Daily Oil Bulletin

MONTH

WELLS D R I L L E D

CUMULATIVE *

MONTH

OIL

GAS

OTHER

TOTAL

Apr 2010 May 2010 Jun 2010

56 54 42

320 374 416

Apr 2010 May 2010 Jun 2010

92 86 149

10 7 7

3 3 11

105 96 167

Jul 2010 Aug 2010 Sept 2010

65 45 40

481 526 566

Jul 2010 Aug 2010 Sept 2010

220 198 197

7 12 5

0 7 6

227 217 208

Oct 2010 Nov 2010 Dec 2010

42 43 49

608 651 700

Oct 2010 Nov 2010 Dec 2010

201 217 340

12 3 2

11 64 11

224 284 353

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

*From year to date

12

600

billion

Dollars Gateway pipeline will add to Canadian GDP over next 30 years.

M AY 2011 • O I L & G A S I N Q U I R E R

S P O T P R I C E S at AECO trading hub in Alberta

GAS STOR AGE

Source: Natural Gas Exchange Inc.

Source: U.S. Energy Information Administration

in the United States

1.7

3.80

1.65 Tcf Year ago: 1.82 Tcf 5-year avg: 1.63 Tcf

$3.518/GJ Total vol.: 1,828 TJ Transactions: 272

1.6

3.55

3.30 Mar 23

Cdn$/GJ

Mar 30

Apr 6

Apr 13

1.5

Apr 20

Tcf

Source: Natural Gas Exchange Inc.

Mar 18

Mar 25

Apr 1

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada April 14, 2011 Source: Rig Locator

Alberta March 2011 Source: Daily Oil Bulletin

ACTIVE

DOWN

TOTAL

ACTIVE (Per cent of total)

Western Canada Alberta

121

449

570

21

British Columbia

44

45

89

49

0

11

11

0

15

115

130

12

180

620

800

23

0

0

0

0

Manitoba Saskatchewan WC Totals Northwest Territories

Apr 8

OIL WELLS

Alberta

GAS WELLS

Mar 11

Mar 10

Mar 11

Mar 10

Northwestern Alberta

160

46

207

171

Northeastern Alberta

181

67

2

8

Central Alberta

212

124

210

76

97

29

555

325

650

266

974

580

Southern Alberta TOTAL

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada April 14, 2011 Source: Rig Locator

Alberta March 2011 Source: Daily Oil Bulletin

ACTIVE

DOWN

TOTAL

Western Canada Alberta

ACTIVE (Per cent of total)

246

402

648

38

British Columbia

8

19

27

30

Manitoba

2

12

14

14

Saskatchewan

71

125

196

36

327

558

885

37

0

1

1

0

WC Totals Quebec

Apr 15

Source: U.S. Energy Information Administration

COALBED METHANE

Alberta

BITUMEN WELLS

Mar 11

Mar 10

Mar 11

Mar 10

Northwestern Alberta

15

18

3

3

Northeastern Alberta

0

0

179

63

Central Alberta

139

38

96

60

Southern Alberta

238

55

1

0

TOTAL

392

111

279

126

O I L & G A S I N Q U I R E R • M AY 2011

13

Feature

Calgary service suppliers brand themselves as industry’s technological problem solvers

By Mike Byfield

S

er v ici ng a nd supply i ng t he Canadian oil and gas industry is big business.

In 2006, the sector generated around $65 billion in economic activity and employed 800,000 workers across the country, according to a recent Canadian Energy Research Institute study commissioned by the Petroleum Services Alliance of Canada.

Calgary is the eye of the service and supply economic tsunami. Hundreds of service providers, both large and small, are interspersed among over 300 public and private producing companies populating the downtown core and spreading outward to industrial areas and even the suburbs. As the sector has grown in size and sophistication, oil and gas producers are increasingly relying on these companies to develop the new technologies and skills needed for coaxing oil and gas resources out of complex reservoirs, processing the bounty and sending it to market. And they are looking for one-stop shopping, where a single supplier meets their expectations in a variety of producing basins both near and far.

Calfrac Well Services Ltd. is one of Canada’s great service company success stories. Established in 1999, the Calgarybased company started as a small outfit specialized in providing fracturing, coiled tubing and cementing services. It has 14

M AY 2011 • O I L & G A S I N Q U I R E R

Feature grown into a billion-dollar enterprise with 3,000 employees working across North America and in Russia.

Calfrac’s domestic activity is concentrated in unconventional gas–focused plays such as the Montney and Deep Basin straddling the Alberta/B.C. border. It is also delivering its mix of fracturing and completion technologies into the Cardium, Viking and Bakken tight oil resource plays.

The bulk of its research and development occurs in Calgary, but the company also operates labs in the United States, Argentina, Mexico and Russia.

Calfrac has been on the leading edge of the service industry’s transition from suppliers of iron to suppliers of high-tech exploration, completion and production solutions. Driving its success has been an emphasis on working with customers to solve their problems through new technologies and on quickly bringing those technologies into commercial use.

“Technical innovation targeted to specific customer needs has always set us apart from many of our competitors,” says Doug Ramsay, Calfrac’s founder and chief executive officer.

Ramsay says the company puts a major emphasis on standardization of its equipment and procedures, allowing customers a clear understanding of the services they will receive, regardless of where the work takes place.

“Of course, we do adjust for particular circumstances, but one of our frac crews looks and works pretty much the same whether it’s in northeast British Columbia or Siberia,” he says.

In December, the company announced a $280-million 2011 capital program, bolstering its fracturing, coiled tubing and cementing capacity and instituting new technologies to cut costs. Part of that

investment will go to installing new pump panels that will enable one operator to control five pumps during hydraulic fracturing operations. Currently, there is one operator per pump.

“Reducing the number of frac crew personnel present on a well pad by half is a realistic goal. That’s an important consideration in terms of both cost and the labour shortage that’s already squeezing the industry,” Ramsay says.

The company is also designing duel fuel engine systems that would initially begin fracturing with diesel, and then switch to raw gas as it begins to flow from the well. That innovation would reduce operating costs along with slashing fuel haulage, a significant factor for remote sites like the Horn River Basin.

It is also working to answer public concerns about water usage in multistage fracturing treatments at shale gas developments. Water has become a significant issue as development has moved from traditional oil and gas regions into areas unfamiliar to the industry.

“A key focus for us is water management. Working with Shell at Groundbirch in northeastern B.C., we’re fracking with treated sewage from Dawson Creek. We’re also using waste water from Pennsylvania coal mines, and in the Fayetteville shale gas play in Arkansas, we use 70 per cent recycled water,” Ramsay says. “Ideally, we’d like to develop chemicals so environmentally friendly that frac water would remain potable, and that goal has already been partially realized.”

Calfrac has grown by meeting customers’ domestic needs, and then taking technologies proven and developed in Canadian conditions and exporting them to the world. This diversification allowed

the company to weather the storm following the financial collapse of 2008.

“In 2009, we had to lay off 40 per cent of our personnel, which really tore my guts out,” Ramsay says. “Fortunately, the domestic downturn was offset by expansion in Russia and Mexico. Canadians are very exportable, and foreign customers love that we can leverage so effectively off our Canadian experience and technology.

Last year, the Canadian business bounced back. In fact, I’ve never seen a recovery take place so quickly—we were over the worst of it in just nine months.”

Ian MacGregor is involved in three different service companies providing cutting-edge technology to oil and gas producers.

PumpWell Solutions Ltd. is a small private firm that markets a monitoring and optimizing service for oil wells that require artificial lift using proven automation equipment and software.

“Our technology can improve a well’s output by an average of 40 per cent, and we often achieve 50-100 per cent without changing equipment. High-volume wells work best for us, but we also offer significant operating cost reductions on lowvolume wells by reducing workover frequency. Capital expense is minimal—just swap in an electric motor and add our PLC [programmable logic controller], which incorporates cellular or satellite communications capability. We designed and built the specialized PLC ourselves in order to incorporate features such as video surveillance in addition to our optimization capabilities at really low cost,” says MacGregor, chair of PumpWell. “We’ve done our homework thoroughly. We have systems installed on hundreds of wells now and we’ve proven we can improve productivity and reduce

“ Canadians are very exportable, and foreign customers love that we can leverage so effectively off our Canadian experience and technology.”

Photo: Calfrac

— Doug Ramsay, Founder and Chief Executive Officer, Calfrac

Calfrac's Doug Ramsay O I L & G A S I N Q U I R E R • M AY 2011

15

Feature

Call Us for all Your ASME Design, Fabrication, Package Assembly & Service Needs

CALGARY - 403.258.3680 CROSSFIELD - 403.946.5678 SASKATOON - 306.242.8900 EMAIL - sales@maxfield.ca

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M AY 2011 • O I L & G A S I N Q U I R E R

operating costs significantly. We will continue to grow rapidly in western Canada, but can now start targeting global markets where our automated, continuously optimizing system offers really large benefits to the producer.”

A pumpjack’s sucker rod string constitutes a complex vibrating elastic system.

Its output is affected by fluid types and levels, gases, sand, wax, temperature and other variables like liquid slugging, well deviation and variable inflow.

“The mathematics used to calculate traditional operating parameters was developed in the early 1950s. People were limited to slide rule calculations, so they made assumptions and hoped for the best,” MacGregor says. “Nowadays, we have cheap computing that’s millions of times more powerful, and with the mathematics we have developed, we don’t have to make assumptions; we know what’s going on. A pumpjack’s parameters can be recalculated and optimized continuously in real time by our automated expert system. An average well has about 900 changes made in the operating parameters in a month, all automatically by the computer—it’s continuous optimization and it works. All of this is done over the Internet, so you can see the data from anywhere: your truck, office or the Brooks coffee shop, if you want.”

What if unforeseen circumstances arise?

“In effect, we’ve incorporated the highest level of human expertise into our programming. The technology can address ambiguities in the data and determine when changes in pumping parameters are required. In most cases, these can be made by the system. On rare occasions when operator intervention is required, the system sends a message to the oper­ ator’s BlackBerry or iPhone. The system can do a better job than a human because the computer is watching all the time and making the small changes that result in big improvements in production,” MacGregor says. “Our system also supplies far more downhole data than was previously available. That information can help producers work out the best completion and operation techniques for complex wells in challenging reservoirs like the Bakken.”

MacGregor is also a principal behind the Redwater upgrader planned by North West Upgrading Inc. north of Edmonton.

The project has now secured bitumen feedstock from the A lberta government's royalty bitumen and Canadian

Feature

Photo: Joey Podlubny

“ When it comes to research and development, the oil and gas sector talks a good line, but very few companies walk the talk in Calgary.”

— Steve Larter, Canada Research Chair in Petroleum Geology, University of Calgary

University of Calgary scientist Dr. Steve Larter

Natural Resources Limited. In addition, MacGregor chairs Enhance Energy Inc., which recently received a $495-million conditional funding commitment from the Alberta government for construction of a CO2 pipeline and related facilities. Pure CO2 would be sourced from the Redwater upgrader and a nearby fertilizer plant, then piped to Clive (northeast of Red Deer, Alta.) for use in enhanced oil recovery.

Although technology development is never risk-free, MacGregor thinks it’s best to work five to 20 years ahead of the curve.

“Figure out what’s coming and get into the play early while it’s still fairly inexpensive,” he recommends. “PumpWell, for example, has taken about five years to develop, test and implement its

technology. It helps alleviate the industry’s endemic shortage of skilled field and engineering staff, and the fact that so many of its experienced professionals are due for retirement. All of us old guys could see these problems coming and we believe that technology could be an important part of the productivity solution. The key is letting computers do what they are good at and allowing people to have time to concentrate on the decisions a machine can’t make. In my experience, there’s nowhere better for developing oil- and gas-related solutions than Calgary.”

While Calgary’s service and supply companies have made strides in turning the city into a technological hub for both domestic and international produc-

ers, there is more work to do, says Steve Larter, the University of Calgary’s Canada research chair in petroleum geology. He says both industry and governments need to do a better job.

“When it comes to research and development, the oil and gas sector talks a good line, but very few companies walk the talk in Calgary,” says Larter, whose resumé includes senior academic posts in Britain and Norway plus a seven-year stint with Unocal Corporation in the United States.

“Their R&D spending as a percentage of revenue is about the same as logging and mining, far less than one per cent. That’s trivial compared to genuinely researchfocused industries like pharmaceuticals and information technology.”

Photo: ©istockphoto.com/janrysavy

Selling technology to the world Bruce Graham, president a n d chie f e xec u tive o f f icer of Calgar y Economic Development (CED), thinks Calgary’s energy sector is taking off internationally.

Chinese companies like PetroChina Company Limited, Sinopec Corp. and China National Offshore Oil Corporation Limited have all established Canadian headquar ter s in Calgar y. Graham says PEME X, Mexico’s national oil company, just sent its president and other senior managers in search of technolog y capable of reversing that nation’s declining oil produc tion. And CED

staffers believe that further Asian investment in Calgary-based energy producers is highly probable.

To help accommodate this growing interest, CED opened its Global Business Centre last June. Also partnering in this initiative are Medicine Hat and Lethbridge, Alta.

“People coming here to do business needed what you might call a landing pad,” Graham says. “At the same time, Canadian companies wanting to export energy technology needed a launching pad where they could gather good intelligence and meet potential foreign colleagues.”

To address those needs, the Global Business Centre was created to address these needs.

“We’re particularly interested in fostering relations between national oil companies and Calgary energy service providers,” Graham says.

The business centre, located downtown, provides temporary desk space for short-term visits. Longer-term office space is available for organizations on international procurement missions as well as companies looking to expand or establish a presence in southern Alberta.

O I L & G A S I N Q U I R E R • M AY 2011

17

Feature

Photo: Joey Podlubny

Canada’s federal government is the biggest academic R&D spender after Sweden among G20 nations, Larter acknowledges, but the cash is not invested effectively in his judgment. The geologist points to the Natural Sciences and Engineering Research Council of Canada (NSERC), which disperses federal funding.

“There was a great outcry a while back when NSERC cut its acceptance ratio for research applications from 80 per cent to 70 per cent. The typical NSERC grant is $30,000$40,000. Unfortunately, that’s not enough

PumpWells chairman Ian MacGregor

money to perform serious research. We have loads of money and talent but very little to show for it. Silicon Valley has about the same population as Edmonton and Calgary combined. Yet these two cities produce a tiny number of patents compared to California’s information technology centre,” he notes.

“In Europe, the typical research application acceptance rate is about 20 per cent, but the individual grants are much larger.

That funding strategy actually produces results,” he continues. “Canada’s NSERC grants are an important financial support for academic staff whose real role is to teach undergraduates, not do R&D. Canadian companies see universities as a source of workers, not technology. And they’re right, as far as current practices go. This university, for instance, generates about 4,500 undergraduates per year versus 200 doctorates. We’re producing fine employees but not nearly enough researchers.”

Larter notes that Canada’s only commercial technologies for in situ bitumen recovery are cyclic steam stimulation (CSS) and steam assisted gravity drainage (SAGD).

“CSS has been around forever. SAGD was developed in 1980—more than 30

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M AY 2011 • O I L & G A S I N Q U I R E R

years ago—and we’re seeing that it only works profitably in the better-quality reservoirs,” he points out. “Technology investment will be essential to extracting our own resources and the same technology can generate export sales. Canada and Alberta have the money, there’s no shortage of innovative concepts, but the polit­ ical will to achieve is lacking.”

That complacency probably stems in part from prosperity. Calgary Economic Development reports that $20 billion in foreign capital has been invested in Western Canada’s oil and gas resource plays since the beginning of 2010, with the majority coming from Europe, China, India and Korea. The cash infusion excites Duncan Au, president and chief executive officer of Central Alberta Well Services Corp.

“That capital will eventually become our revenue and stimulate increased field activity. I believe our industry bottomed out in the fourth quarter of 2009 and we’re now in the first phase of an upward cycle,” the Calgary oilman comments. “For a company like ours, with a modern service rig fleet, the outlook is more promising than it’s been for two or three years.”

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Feature

THE

MAP

Photo: Joey Podlubny

By Mike Byfield

Production declines, changing activity in WCSB mean another restructuring of the gas processing industry. A proposed new strategy hopes to guide the way.

W

estern Canada’s conventional natural gas production has been declining for five years, reflecting a mature basin and low gas prices. The decline in production will likely result in a major consolidation of gas midstream assets, according to a major Calgary-based market analysis firm.

“We expect output to continue falling over the next decade. If so, processing plant closures are inevitable,” says Bill Gwozd, gas services vice-president with Ziff Energy Group.

Zif f, along w it h Gas Processing Management Inc. (GPMi), has proposed

crafting a consolidation strategy for large sour gas plants in the Alberta foothills as a means of dealing with these closures in an orderly fashion.

“If we rationalize efficiently, the industry can save itself $200 million annually in processing costs,” says GPMi principal O I L & G A S I N Q U I R E R • M AY 2011

21

Feature

Photo: Ziff Energy Group

Bill Armstrong. “We can also ensure that future foothills discoveries will still have access to affordable processing.”

T he t wo con su lt i ng f i r m s have invested more than $100,000 of their own money in their initial analysis of the situation, meeting several times with 50 gas producers, midstream processors, transporters, petroleum associations, government representatives and regulators.

Bill Gwozd, Gas Services Vice-President, Ziff Energy Group

• • • • • • • • • • •

“We proceeded without paying clients because the issues involved are important to all Albertans, as well as to our industry,” says GPMi principal Bob Child. “Before going further, though, we need backers.

In fact, the entire consolidation strategy as we envision it will require sector-wide cooperation rather than each company focusing exclusively on its own interest.”

Child has plenty of experience in both gas processing and operating partnerships. After graduating from the University of Alberta, the Edson-raised engineer worked for Hudson’s Bay Oil and Gas, Dome Petroleum Limited and Amoco Canada Petroleum Company Ltd. As president and CEO of Central Alberta Midstream until 2005, he operated Kaybob-area plants belonging to a consortium formed by Chevron Canada Limited and Amoco Canada (now BP Canada Energy Company).

Armstrong’s career is equally gassoaked. The native Albertan spent 36 years with Chevron Corporation (one year more than his father worked for the same firm), mainly in oil and gas facilities located in Canada and the United States.

His portfolio includes initial design and construction of the large Kaybob South No. 3 plant, a unit that the engineer later managed. He formed Central Alberta Midstream, and then headed all midstream operations for Chevron Canada.

“We live and breathe these issues. It’s quite passionate for us,” he says.

Roughly 1,000 natural gas processing plants operate across western Canada, Armstrong says, processing 11 billion cubic feet per day that’s divided almost equally between sweet and sour gas.

Because sweet gas plants require less expensive equipment and their configurations are more flexible, the proposed GPMi-Ziff study focuses only on sour facilities. Specifically, the consultants will assess larger plants that are licenced to process more than five tonnes of sulphur daily, although they think smaller facilities should also be included in the future. Currently, 3.6 billion cubic feet per day of sour gas is being processed by those larger operations.

“Over the past five years or so, drilling has moved away from deeper sour gas plays in favour of shale gas and other

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Feature

targets,” Armstrong says. “As reserves and plant throughput volumes diminish, most of the basin’s larger sour gas plants are now operating below 50 per cent utilization on the basis of total gas inlet or 30 per cent on sulphur inlet. If the present trends continue, these facilities may well reach the point where it’s no longer possible to operate the H2S removal and sulphur recovery equipment, or entire plants.

In the meantime, lower throughputs are

raising unit costs in a business that’s already financially stressed.”

Capital investment is another looming issue. Canada’s big sour gas plants were built from the 1950s to the 1980s. Cash will be needed to retool those aging facil­ ities, Armstrong notes.

“Our industry has good operators, but its record for planning isn’t strong,” he says. “As matters now stand, the operators who happen to be financially weaker will Photo: Ziff Energy Group

“Our industry has good operators, but its record for planning isn’t strong.”

— Bob Child, Principal, Gas Processing Management Inc.

fold first. But an uncoordinated retreat will not result in maximum recovery of the resource at the lowest cost.”

GPMi’s Child sees the sour processing study as a first step toward repositioning the sector based on impartial analysis.

“We’ve divided the West’s sour gas facilities into eight operating regions, including the north, central and southern foothills,” he says. “These three areas are big enough to allow creative solutions, but small enough to form practical working groups. Our analysis will assess each area as if it all belonged to one operator, and then we work out what that owner would logically do to earn the best return.”

Sour gas drilling is not in recovery mode. Producers are now focusing on more than shale gas. The hunt is also quickly intensifying for medium-depth sweet gas liquids whose price is tied to light crude prices. Child points out that liquids targets of that type are found in the Deep Basin, Drayton Valley and Kaybob, all areas with sour gas processing facilities.

“Liquids potential has to be taken into account when planning for a restructuring of the processing sector in the foothills,”

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O I L & G A S I N Q U I R E R • M AY 2011

23

Feature

Photo: Ziff Energy Group

Photo: Joey Podlubny

Bill Armstrong, Principal, Gas Process

With sour gas production declining, sulphur trains are running under capacity.

Management Inc.

the GPMi principal says. “Abandonment and reclamation are another capital expense to be borne in mind.”

The three foothills areas will each be assessed from three perspectives: 1. T he total resource base in each case will be quantified, drawing on Ziff’s expertise to include exploration potential and likely development over the next 10 years.

2. T he business performance of various players and the sector as a whole will be assessed for each area, mainly by Ziff’s specialists.

3. GPMi will apply its staff’s two centuries of professional experience in the sector to define the full sour gas processing and related infrastructure in the three areas, including gas percentages, liquids, tie-ins to transportation and more. It will also assess possible operating alternatives in each situation.

“How can we match these three factors?

How much money can be saved? What cap­ ital will you need? How would producers and midstreamers work together in each situation?” Gwozd queries. “It’s important to understand that processing cost is not the only concern of producers. Every company wants to preserve its freedom to do what it wants, when it wants.”

Armstrong agrees, but adds that costs are a constant bone of contention: “At Chevron, we midstream managers had our biggest battles with production managers in our own company. They argued that processing costs could be lower.”

D e s pite t he i ne v it able t u s sle s, Armstrong sees the Ziff-GPMi concept of an orderly, structured retreat as “pretty much a no-brainer.”

“If we can save $200 million in operating costs every year, everybody stands to benefit,” he says. “The biggest winner would be

the provincial government. First, our plan would minimize the possibility of stranded gas. Ensuring access to a top-notch processing facility in each foothills area would encourage future drilling after gas prices recover, and hopefully that drilling would generate future royalties. Second, processing costs are taken into account when calculating Crown royalties—lower costs would mean more money for government.”

Gwozd says many companies encouraged GPMi and Ziff to proceed with the series of studies. “Now we’ve sent out our study proposal and are waiting to see who steps up to the plate,” he comments. “We’d like to get support from producers, midstreamers and government. Of the 50 organizations that we approached when doing the research, two have their own rationalization plans and two others said they’re not interested. The jury is still out with the remainder, so we see a lot of positive potential.”

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Photo: Apache Corp.

Encana joins Kitimat LNG export project

Artist's rendering of the proposed Kitimat LNG Terminal.

Encana Corporation has agreed to acquire a 30 per cent interest in the planned $3-billion Kitimat liquefied natural gas (LNG) export terminal, located on the west coast of central British Columbia, and the associated natural gas pipeline.

Apache Canada Ltd. will sell down 11 per cent of the equity in Kitimat LNG and Pacific Trail Pipelines, retaining operatorship and a 40 per cent working interest. EOG Resources Canada, Inc. will sell 19 per cent, keeping a 30 per cent working interest. Financial terms of the contract have not been disclosed.

This proposed Kitimat LNG export development is intended to open tremendous new market opportunities in the Asia-Pacific region for abundant supplies of Canadian natural gas, the company notes.

British Columbia alone could see its gas production more than double within a decade.

“We expect that this project will help advance North America’s natural gas economy

across the Pacific to markets where demand is growing and natural gas prices are more closely tied to oil prices,” says Randy Eresman, Encana’s president and chief executive officer.

The proposed Kitimat LNG export development, located about 650 kilometres north of Vancouver at Bish Cove, near the Port of Kitimat, has planned initial cap­acity, from the first of two potential phases, of about 700 million cubic feet a day of natural gas, or about five million tonnes of LNG per year.

The development includes construction of a new 36-inch diameter natural gas pipeline—known as Pacific Trail Pipelines—running 463 kilometres from the Spectra Energy Corp. natural gas transmission system at Summit Lake, B.C., to the planned Kitimat LNG export facility.

Encana’s 30 per cent interest in the development includes a capacity reserve

of 30 per cent in the Kitimat LNG export facility and matching capacity on the proposed pipeline.

The partners expect to complete the front-end engineering design for the LNG export facility later this year, after which the partners will determine plans for a capital investment decision for the first phase of the development. Project construction could begin in 2012, with exports potentially starting in 2015.

The project is operated by Apache Canada, which will own 40 per cent, with Encana and EOG Resources Canada each owning 30 per cent respectively. Encana is already a partner with Apache in the Horn River Basin shale gas exploration and development in northeastern British Columbia.

“Encana is a natural partner with Apache and EOG for the Kitimat project.

All three companies have a significant presence in the Horn River Basin as well as extensive experience in British Columbia natural gas plays, which provides additional operating and commercial synergies for development of this vital energy resource,” says Janine McArdle, president of Kitimat LNG and senior vice-president of gas monetization, Apache Corporation.

Encana’s acquisition transaction is subject to receipt of appropriate regulatory approvals and satisfaction of other customary closing conditions. It is expected to close in the second quarter of 2011.

Burgeoning natural gas resources from the Horn River Basin and the Montney formation in British Columbia and Alberta are expected to provide export volumes for the Kitimat LNG project. According to industry studies, recent B.C. discoveries indicate the province will have the resource capacity to more than double current production of about 2.8 billion cubic feet a day to more than seven billion cubic feet per day in the next seven to 10 years.

— Daily Oil Bulletin

BRITISH COLUMBIA WELL ACTIVITY

MAR/10

MAR/11

WELL LICENCES

78

131

▲

MAR/10

MAR/11

WELLS SPUDDED

72

50

▼

MAR/10

MAR/11

WELLS DRILLED

92

65

▼

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • M AY 2011

27

British Columbia

Talisman to sell half its Cypress A Montney to Sasol for $1.05 billion In the second such deal in less than three months, Talisman Energy Inc. is selling a 50 per cent net working interest in its Cypress A Montney natural gas assets to South Africa’s Sasol Limited for $1.05 billion.

The two companies are planning to develop stranded gas in northeastern British Columbia by converting the large Montney gas resource into liquids using Sasol’s expertise in gas-to-liquids (GTL) conversion.

Near the end of last year, Talisman also sold a 50 per cent working interest in its Farrell Creek Montney gas assets to Sasol, again for $1.05 billion. In that deal, which closed on March 1, Sasol acquired an estimated 4.8 trillion cubic feet (tcf) equivalent of net contingent resource.

In a recently issued research report, Ticonderoga Securities, LLC estimates Sasol is paying $37,000 per net acre for the Cypress lands, less than the $41,000 per acre paid for Farrell Creek, since there is more work to be done at Cypress.

In 2009, Talisman drilled three vertical wells at Cypress with initial production

rates of around eight million cubic feet a day, Ticonderoga says. Current production is 18 million cubic feet a day.

The Cypress A transaction is subject to regulatory approvals and is expected to close by September 30.

Talisman says it will operate and manage the Cypress A and Farrell Creek areas as an integrated development project in northeastern British Columbia.

Sasol—the world’s biggest maker of motor fuels from coal—and Talisman have begun a study into the feasibility of a commercial GTL facility in western Canada.

Talisman would have the option of a 50 per cent stake in the facility.

This could provide a strategic alternative to traditional North America pipeline or liquefied natural gas markets. The GTL process produces premium, clean liquid fuels. Sasol is leading this study with a front-end engineering design decision likely in the second half of next year.

Sasol and Royal Dutch Shell plc are the only companies that operate commercial-scale

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GTL plants. Sasol has GTL projects operating in South Africa and Qatar, a project under construction in Nigeria and developments proposed in a number of other countries. Shell operates a plant in Malaysia and is building the world’s largest GTL plant in Qatar.

Talisman says the Cypress A assets are very similar to Farrell Creek and the company intends to create an integrated longterm development plan for the area.

“This transaction allows Talisman and Sasol to unlock additional value in the world-class Montney shale play and potentially accelerate development of the resources in the area,” Talisman president John Manzoni says.

Sasol chief executive Pat Davies says, “This additional acquisition of another high-quality natural gas asset will accelerate our upstream growth while also potentially advancing Sasol’s already strong GTL value proposition utilizing our proprietary technology.”

In its research note, Ticonderoga says GTL production could begin in about four

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Greater Groundbirch and the Greater Cypress area.

The Cypress A properties are part of the Greater Cypress area, about 25 miles northwest of Farrell Creek. The Talisman

and Sasol joint venture partners don’t expect to start commercial development at Cypress A, which is less mature than Farrell Creek, for several years.

— Daily Oil Bulletin

Source: Sasol

years, with one or two production trains at 48,000 barrels per day for each train.

It also notes the economics depend on the spread between oil and natural gas prices, which are currently very favourable.

Talisman says the Cypress A transaction represents the sale of about 14 per cent (5.6 tcf equivalent) of its remaining estimated 39 tcf equivalent of net contingent resource in the play, and about 17 per cent (28,600 net acres) of the company’s net top-tier acres of land in the Montney.

Sasol will pay 25 per cent of the consideration (about $260 million) in cash at closing. As well, the company will provide an additional $790 million to fund 75 per cent of Talisman’s future capital commitments in the integrated joint-venture development area.

On closing, Talisman says it will hold an estimated 34 tcf equivalent of net contingent resource and 139,000 net acres of top-tier acreage in the Montney shale play, including Farrell Creek,

Schematic of Sasol's gas-to-liquids technology.

AltaGas, Provident building pipeline to Younger deep-cut plant AltaGas Ltd. has announced an agreement with Provident Energy Ltd. and a major producer to construct a 25-kilometre, 16-inch natural gas pipeline.

The pipeline will connect up to 250 million cubic feet (mmcf) per day of additional supply to the AltaGas-operated Younger extraction facility (750 mmcf per day capacity) at Taylor, B.C. The Younger facility is the only deepcut extraction facility in British Columbia.

The facility should provide recoveries of greater than 80 per cent of C2 and

99 per cent of C3, C4 and C5+ products for all natural gas gathered on the Younger Septimus pipeline. For producers in the Montney area, such recoveries provide better plant gate netbacks, barrel-of-oil-equivalent production and reserve recoveries.

The Montney play provides sweet, liquids-rich gas well-suited for processing at the Younger facility.

A ltaGas and Prov ident w ill each ow n a n approx i mately 30 per cent interest in the pipeline and have 76 mmcf

a day of f i r m sh ippi ng capac it y. I n addition to having a 40 per cent equity interest and shipping capacity of up to 100 mmcf a day, the senior producer w i l l a lso const r uc t a nd operate t he pipeline.

The estimated cost to complete the pipeline is approximately $30 million, of which both AltaGas and Provident have committed $9 million each. The pipeline is anticipated to become fully operational by the fourth quarter.

— Daily Oil Bulletin

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Northwestern Alberta/Foothills

$200-million sale brings Alberta fiscal year total to $2.6 billion

Photo: Joey Podlubny

By Richard Macedo

A huge $200-million land sale marked the end of the 2010-11 fiscal year. With a focus on the northwest, drilling should pick up in the region later this year.

Alberta closed the books on its final land sale of the fiscal year on March 23, taking in nearly $200 million, bringing the 2010-11 total to roughly $2.6 billion.

The record year was in 2005-06 when the province took in $3.4 billion, much of it on oilsands acreage.

The most recent sale attracted $199.9 million on 188,906 hectares at an average price of $1,058 per hectare. The sale was highlighted by two parcels in northwestern Alberta, south of Grande Prairie, that combined for nearly $135 million. The large bonus parcels were all acquired by brokers.

Calendar year-to-date, the province is ahead of last year’s pace in bonus revenue, per-hectare average and total hectares sold.

After five sales this year, $660.8 million has rolled into provincial coffers on 1.1 million hectares at an average of $589.17 per hectare.

To the same point last year, the government had attracted $454.4 million in bonus bids as 898,330 hectares exchanged hands at an average of $505.82 per hectare.

The recent sale featured a bonus high bid of $96.7 million by Scott Land & Lease Ltd., paying an average of $11,801 per

one very notable licence,” says Gregg Scott, president of Scott Land. “That one parcel would be one of the top highestpriced licences in Alberta history.

“We are on track to have a record year of land sale revenue in Alberta this year. As this is a leading indicator, it bodes well for the drilling and services side going forward.”

A n adjacent parcel scooped up by Char ter Land Ser v ices Inc. went for $37.9 m i l l ion , pr o duc i n g a n a v e ra ge of $ 8 , 2 2 5 p e r he c t a r e f or t he 4 , 6 0 8 - hec ta re l icence. T he broker picked up several sections at 61-23W5, 60-24W5 and 61-24W5.

“Pretty amazing,” says Brad Hayes, president of Petrel Robertson Consulting Ltd. “Most of the tracts of lands within each of these parcels were posted for deep rights only, some below the base of the Fernie and some below [the] base of [the] Triassic.

“The Deep Basin Cretaceous and Nikanassin tight gas plays were thus excluded.”

The Montney might be in play under some of these lands, he says, but not for those tracts posted below the base of the Triassic.

“I believe that these lands were purchased either for the Duvernay shale

“I believe that these lands were purchased either for the Duvernay shale and/or for the tight oil plays being pursued on the margins of big Swan Hills reefs.”

— Brad Hayes, President, Petrel Robertson Consulting Ltd.

hectare for the 8,192-hectare licence.

The broker acquired the rights to several sections at 61-25W5, 60-25W5, 60-24W5 and 61-24W5.

“Scott Land & Lease acquired 62 per cent of the overall sale, including the

and/or for the tight oil plays being pursued on the margins of big Swan Hills reefs,” Hayes says. “Both of these plays have been very active in this general area and, being unconventional plays, they are prospective over large areas.

NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY

MAR/10

MAR/11

WELL LICENCES

127

175

▲

MAR/10

MAR/11

WELLS SPUDDED

117

212

▲

MAR/10

MAR/11

WELLS DRILLED

195

279

▲

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • M AY 2011

31

Northwestern Alberta/Foothills

Large postings and big dollars have become the pattern.”

Daily Oil Bulletin records show that on March 2, broker Canadian Coastal Resources Ltd. licensed a new pool wildcat in the Placid area at surface location 04 -33- 60 -23W5. T he pla n ned hor izontal oil well has a projected depth of 4,120 metres, with the Fernie group listed as the total depth zone.

Also in the Placid area, Rock Energy Inc. rig-released a deeper pool test on January 19 at surface location 10-07-6123W5, with gas listed as the objective.

The Montney formation was listed as the total depth zone, with a planned depth of 2,678 metres.

Delphi Energy Corp. is also a busy operator in the area. The junior was issued a licence on December 13 for a development horizontal oil well at surface location 16-06-60-23W5. The Ca rdium sa nd is listed as t he tota l depth zone, with a planned depth of 3,050 metres.

Five parcels between 59-24W5 and 59-25W5 combined for total bonus bids of $8.7 million and were all acquired by

Scott Land. A further five parcels between 60-25W5 and 60-27W5 combined for bonus bids of $10.2 million and were all picked up by brokers.

Daily Oil Bulletin records show that ConocoPhillips Canada rig released a development directional gas well on March 10 in the Wanyandie area at surface location 16-10-60-27W5. The well listed the Cadomin formation as the total depth zone, with a planned depth of 3,328 metres.

Bristol Land & Leasing Ltd. produced the land sale per-hectare high of $22,498, paying $2.9 million for a 128-hectare lease parcel. The broker acquired the eastern half of section five at 45-5W5 for petroleum and natural gas to the base of the Cardium formation.

Also during the sale, the province at t rac ted $10.7 m i l lion in oi lsa nds bonus bids on 80,256 hectares. Yearto - date, t he prov ince has at t racted $28.3 million in oilsands land sale revenue for 236,672 hectares. To the same point in 2010, just $125,990 in oilsands land sale revenue had come into the provincial treasury as 1,024 hectares exchanged hands.

Cause of fire at Husky wellsite still unknown: GASFRAC An investigation continues into the cause of a fire on March 7 at Husky Energy Inc.’s sweet wellsite near Robb in northwestern Alberta, but GASFRAC Energy Services Inc. stresses it did not occur during fracturing operations.

GASFR AC was preparing to begin routine fracturing operations when a flash fire occurred.

“We were rigging up our equipment and circulating water and methanol mix through our treating lines to warm them up in preparation for a treatment that was to start later in the day,” a GASFRAC official explains.

“There was a release of flammable product not related to the GASFRAC operation and it occurred for reasons that are yet to be determined by the ongoing investigation.

“Until the investigation is completed by the authorities involved, we will not further speculate as to the cause of the fire.”

— Daily Oil Bulletin

1981 - 2011

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32

M AY 2011 • O I L & G A S I N Q U I R E R

Northwestern Alberta/Foothills

Peyto continues to build Deep Basin gas position While many producers in western Canada are happily focused on oil plays these days, cost-conscious Peyto Exploration & Development Corp. sees this as the perfect time to build gas production.

“Natural gas is cyclical in nature,” says Darren Gee, president and chief executive officer of Peyto. “We’re out there trying to take advantage when others aren’t.”

The company is using horizontal, multi-frac technology to develop tight gas resource plays in the Deep Basin, targeting the Cardium, Notikewin, Wilrich and Falher formations.

One of the most active develop ers in the Deep Basin of northwestern Alberta, the company has placed over 30 horizontal gas wells on production since January 2010.

Deep Basin competition is heating up, however.

At a March 9 land sale, several large bonus bids in the Deep Basin south of Grande Prairie—land with potential in deeper formations such as the Duvernay shale—helped the Alberta government take

in $175.4 million. Producer interest was particularly heavy around townships 60-65, where the highest bonuses were paid.

A nd At haba sca Oi l Sa nds Cor p. announced recently it has acquired more than one million acres (100 per cent) of petroleum and nat ural gas rights in Deep Basin areas. The lands were acquired through Crown sales and from third parties.

“The last land sale was pretty heated,” Gee says. “We heard about Athabasca Oil Sands buying Deep Basin rights.

Here you’ve got oilsands players buying natural gas rights in the Deep Basin.

Obviously, it’s a very good place to be if they’re foregoing $100 oil to get into the Deep Basin. “[But the competition] doesn’t scare us. It never has. We’ve gone through periods of intense competition in the Deep Basin.”

In 2010, Peyto acquired about 100 sections (63,000 net acres) of land that was inside or complementary to its core areas, at an average price of $195 per acre. The

company added mineral rights to target deeper formations, to the base of the Spirit River group or the Bullhead group, to pick up the Notikewin, Falher, Wilrich or Cadomin zones.

“I would suggest in the Deep Basin, in any year—whether you go back three years or five years—accumulating that much acreage, at that price, is definitely opportunistic,” says Glenn Booth, vicepresident of land at Peyto. “Even as recent as [March 9], we went to the sale and in the same region we saw a lot of these lands go for two, three, five and sometimes 10 times as much. So, accumulating that acreage when we did was very opportunistic.”

I n c r e a s e d p r o du c t i o n i n 2 010 helped Pey to improve its cash f low and revenue for the fourth quarter and year ended December 31, although net income declined in both periods from a year earlier.

Formerly Pey to Energ y Trust, the company boosted average production for the 12-month period to 23,728

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33

Northwestern Alberta/Foothills

barrels of oil equivalent (boe) per day, up 28 per cent from 18,481 boe per day in 2009. Quarterly production rose 47 per cent to 28,198 boe per day from 19,134 boe per day in the fourth quarter of 2009.

The company invested $261.48 million in 2010 to build a record 15,100 boe per day of new production at a cost of $17,300 per boe per day.

At the same time, Peyto expanded three of its gas plants to accommodate this new production and, through continued land capture and development activity, replaced each drilled location with two new undeveloped locations.

Drilling, completions and well connections accounted for $224 million or 86 per cent of the capital (net of $11.73 million in drilling royalty credits) with facility expansions accounting for $19 million or seven per cent.

During the year, Peyto spud 52 (48.1 net) wells, 45 of which were horizontal, and brought on production 52 (49.2 net) new gas zones. The average horizontal well cost $3 million to drill and $1.6 million to complete, before any drilling royalty

34

M AY 2011 • O I L & G A S I N Q U I R E R

credit or natural gas deep-drilling program royalty holiday.

The Greater Sundance core area was the focus of the majority of Peyto’s 2010 capital expenditures, with 44 wells drilled and with all three gas plants undergoing expansion. The remaining capital was focused on liquids-rich

To date in 2011, six drilling rigs have been active in Peyto’s Deep Basin core areas. The company has drilled and rig released 14 (12.5 net) wells, six (5.4 net) of which were spud during 2010. All the wells drilled to date are horizontals.

Four wells (3.6 net) are currently awaiting completion.

“[But the competition] doesn’t scare us. It never has. We’ve gone through periods of intense competition in the Deep Basin.”

— Darren Gee, President and Chief Executive Officer, Peyto Exploration & Development Corp.

Cardium gas development in the northern areas of Kakwa and Cutbank.

Capital expenditures for the fourth quarter of 2010 increased to $110.56 million, up 320 per cent from the fourth quarter of 2009. Drilling and completions accounted for $82.56 million while production equipment, pipelines and facilities accounted for $14.77 million.

Land, seismic and a small acquisition/ joint venture in the Nosehill area made up the balance of the capital expenditures at $13.23 million.

Dav id T homas, v ice-president of exploration, says new horizontal technolog y is increasing Pey to’s chance of hitting the sweet spot in its target reservoirs.

“This is especially true of the river channel targets such as the Notikewin and the Falher, which have more natural variability in them than the Wilrich and Cardium beach sands,” says Thomas.

Peyto has brought on stream 11 (9.3 net) new wells since the beginning of 2011.

These wells are producing a combined

Northwestern Alberta/Foothills

— Daily Oil Bulletin

Photo: Joey Podlubny

4,500 boe per day. Total company production currently ranges between 32,000 and 33,000 boe per day as new wells are at various stages of inline testing and tie-in.

As March draws to an end, the company’s six active drilling rigs are expected to be situated on multi-well drill pads that should allow for continuous operations during the traditional April and May spring breakup months.

“The reason we’re pushing is we’re starting to see some pressure on services—frac equipment for instance,” Gee says.

The company expects to complete a 25-million-cubic-feet-per-day expansion of the Wildhay gas plant by the end of May. It will increase capacity to 50 million cubic feet (mmcf) per day.

An expansion of the Nosehill gas plant will follow in late July and will involve the addition of 50 mmcf per day of gas processing capacity. Processing capacity will rise to 120 mmcf per day.

These two expansions will eventually allow for combined production growth of over 12,500 boe per day.

Peyto continues drilling for liquids-rich gas in the Deep Basin.

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Shell considers US$2-billion oilsands debottleneck

By Lynda Harrison

MAR/10

MAR/11

MAR/10

MAR/11

WELLS SPUDDED

100

119

WELLS DRILLED

90

129

Photo: Joey Podlubny

says Lorraine Mitchelmore, Shell Canada Limited’s president and country chair.

“We’ve been going through this process since September,” Mitchelmore says. She declined to provide the upgrader’s current capacity.

The new Jackpine mine is being combined with output from the previously existing Muskeg River Mine, both feeding the expanded Scotford upgrader. Once it is fully on stream, oilsands mining will be about four per cent of Shell’s worldwide oil and gas production.

Shell is also looking into carbon capture and storage for AOSP, in a project called Quest, which could capture and store some one million tonnes of CO2 per year. The company plans to make the final investment decision in 2012.

Mitchelmore says Canada needs a national approach to its energy policy to position it in the global marketplace. “This

is about wealth creation and taking what Canada has as its competitive advantage and turning it into an economic advantage for the future,” she says, adding Canada has the resources and a deep commitment to the environment.

“You bring these two together and really create a framework that allows us to compete internationally. That is what this is about.”

She says Shell is taking this message to all Canadians, including producers, end users, First Nations, government and regulators, starting with an “educated dialogue.”

According to Mitchelmore, customers are demanding energy with a reduced carbon footprint, so Canada needs to put a price on carbon.

“I can’t say what a fair price on carbon would be because there are so many factors involved in that,” she says. “What we need to do, though, is provide affordable energy. We need to think about innovation and technology. You put a price on carbon right now, it’s going to make energy too expensive, so you need to then bring in innovation and technology to incentivize companies to innovate. That’s why I say it’s quite complicated.”

Shell Canada internally prices carbon because it believes there will be a carbon price in the future, but does not know what that price will be.

Being in Canada for 100 years, Shell expects future energy production will be less carbon intensive than it is today, so Canada needs to position itself now, explains Mitchelmore. “It’s about adapting to the future.”

O ver t he nex t four yea rs, Shel l expects to invest up to US$5 billion in heavy oil, at least US$12 billion in each of tight gas and global explorations, and around US$20 billion each in trad­ itional upstream, deepwater projects and integrated gas.

With Shell's Scotford refinery expansion almost ready, the focus is now on increasing bitumen production.

Now that the Scotford expansion is nearly complete, the next focus at Royal Dutch Shell plc’s Athabasca Oil Sands Project (AOSP) is optimization and debottlenecking.

Shell is aiming for a 2011 f inal investment decision on a US$2-billion debottlenecking project at the AOSP that will add 35,000 barrels per day with a net present break-even value of around US$45 per barrel, or about US$30 less than a full expansion. The company expects to do a series of these debottlenecking projects over the next decade.

The AOSP is 60 per cent owned by Shell, the operator.

The majority of new production at the AOSP is now going through the Scotford upgrader, and probably by the second quarter, the 100,000-barrel-per-day expansion and addition of a third processing train will be up and running, bringing output to 255,000 barrels per day, NORTHEASTERN ALBERTA WELL ACTIVITY

MAR/10

MAR/11

WELL LICENCES

112

86

▼

▲

▲

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • M AY 2011

37

Northeastern Alberta

ConocoPhillips to spend US$1.2 billion on oilsands this year ConocoPhillips Company will spend US$1.2 billion on its Alberta oilsands projects in 2011 as the company gears up to increase its Alberta bitumen output significantly over the next few years.

“We’re going to invest $1.2 [billion] in Foster Creek/Christina Lake and Surmont this year, and we’re going to invest $1 billion to $1.5 billion a year for the foreseeable future in the oilsands,” says Greg Garland, ConocoPhillips’ senior vicepresident, E&P Americas.

Most of the oilsands spending is for previously announced expansions of the Foster Creek/Christina Lake steam assisted gravity drainage (SAGD) projects owned 50/50 with and operated by Cenovus Energy Inc., as well as the ConocoPhillips-operated and 50 per cent owned Surmont SAGD project and the delineation of ConocoPhillips’ undeveloped oilsands leases at Thornbury, Clyden and Saleski.

Referring to the oilsands, Garland adds, “We plan to spend $100 million a year driving technology improvement.

So we want to reduce our environmental

footprint…. It’s also about improving efficiencies and recoveries, driving down capex [capital expenditure], driving down opex [operational expenditure].” Further details weren’t available.

In 2008, ConocoPhillips said it planned to spend $500 million on heavy oil technology development during the next five years.

Engineering work is wrapping up and site preparation work has started for an 83,000-barrel-per-day expansion at Surmont. The plan is to inject first steam by the end of 2014 and flow first oil in 2015.

Joe Mar ushack, president of ConocoPhillips’ Canadian operations, says about 150 contractors were doing

“We plan to grow our [Alberta bitumen] production by 10-15 per cent a year through 2020, and we’ll continue to grow for the next decade.”

— Greg Garland, Senior Vice-President, ConocoPhillips, E&P Americas

Eighty per cent, or $80 million a year, was to be spent on oilsands research and development—mainly on the upstream side.

“We plan to grow our [Alberta bitumen] production by 10-15 per cent a year through 2020, and we’ll continue to grow for the next decade. So by 2020, 250,000 barrels a day of production,” Garland says.

At Surmont, which is ConocoPhillips’ only operated oilsands project, January bitumen output averaged 23,684 barrels a day (before royalties, 50 per cent net to ConocoPhillips).

site preparation at Surmont, where the number of construction workers is slated to reach about 1,000 later this year.

According to Bill Lingard, president of construction contractor Flint Energy Services Ltd., work on oilsands projects in general is advancing slowly. For instance, he notes that the contract for the Surmont fieldwork has not yet been awarded. “It’s been delayed several times,” Lingard says.

“We are expecting that to come soon.”

— Daily Oil Bulletin

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Northeastern Alberta

Kearl modules downsizing for transportation To meet deadlines and cut costs, 33 of the 200-plus Korean-made modules destined for the Kearl oilsands mining project are being disassembled so they are not stuck at a port in Idaho awaiting two states’ goahead for trucking to the mine site north of Fort McMurray, Alta.

Imperial Oil Limited’s modules are being taken apart and reassembled into 60 pieces that can fit under overpasses on interstate highways through Idaho and Montana, and then into Canada.

Also, they won’t block traffic in the passing lanes, says Pius Rolheiser, Imperial spokesperson.

Imperial is still working with regulators in those states to get the permits the company needs to move future modules; however, to mitigate cost and schedule implications for the project, it is reducing the size and weight of the modules that are currently at the Port of Lewiston in Idaho, says Rolheiser.

“Our original plan remains our preferred option, and that’s to transport this equipment on U.S. [Highway] 12,

and highways through Montana and up through Alberta.”

The 60 truckloads will still require permits, but they will be like the thousands of oversize permits issued every year. Their size can be compared to that of wind turbine blades and grain silos. “They’re still large pieces of equipment,” he says.

Disassembling them has begun and is expected to take anywhere from weeks to several months. Their route is still being mapped out.

Bypassing the need for special permits, some of the modules have already arrived at the mine site, but Rolheiser could not say how many. “Not dozens,” he says.

Sixty of the modules were sized and manufactured in Korea to be able to fit under overpasses on interstate highways and were trucked from the port of Vancouver, Wash., the entry point for all the modules. The rest were barged on rivers to the Port of Lewiston, Idaho, where they sit while opponents citing safety risks have delayed their movement on rural roads.

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In mid-February, the Montana government issued a document called a Finding of No Significant Impact after a public hearing and a review of Imperial’s transportation plan. This puts the company in a position to apply for specific permits to move the remaining huge modules, and they will be applied for when Imperial is ready to transport, says Rolheiser.

He says Imperial awaits guidance from Idaho’s department of transportation on the timing of a contested case hearing process.

The $8-billion Kearl project, designed for phased capacity of 345,000 barrels per day, continues to be on track to start producing bitumen by the end of 2012, says Rolheiser. The company has not issued a new cost estimate.

The full project, including construction, engineering, procurement and contracting, is about 50 per cent complete, while on-site construction alone is roughly one-third to 40 per cent done, the spokesman says.

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Northeastern Alberta

Oilsands face new reclamation rules, security for full costs Oilsands operations’ plant sites will now be covered under new Government of Alberta reclamation rules announced March 17. A lower amount of security will be required during mines’ early and mid-lives, while a higher amount of total security will be required than under the current regime.

The new reclamation initiatives are designed to improve clarity, security and environmental performance within the oilsands and coal mining sectors, the government says.

“While industry has always been required by law to reclaim disturbed land, we recognize it is essential government strongly incent, and if necessary, compel this action,” says Rob Renner, minister of environment. “We need to provide clarity around existing reclamation efforts and the certification process, as well as restructure our reclamation security policy to ensure Albertans never have to foot the bill to clean up affected lands.”

Currently, operators post financial security for reclamation each year based

on the following year’s estimated land disturbance. The security is returned when the land is reclaimed.

The new mine financial security program takes an asset-to-liability approach which recognizes the resource value— whether bitumen or coal—as an asset in terms of cash flow.

For new mines, a base security will be collected early in the mine’s life, when the risk of mine closure or abandonment is at a minimum. Full financial security will be collected later in the mine’s life, but before assets are completely reduced. For mines already operating, existing security held by the province will be held as base security.

Over the long term, the total security amount collected will be considerably higher than with the previous approach. All oilsands mines, including those previously providing security at older rates, will now provide security based on full reclamation costs.

Oilsands processing plants located on mine sites are also now covered under the program.

In an effort to provide greater transparency and consistency of reporting,

government is also boosting the number of milestones used to track reclamation.

Previously, only three reporting milestones were used: disturbed, reclaimed and certified. Recognizing that reclamation occurs over long periods of time and goes through many stages, eight milestones will now be used by both the province and industry.

In addition, reclamation data will soon be made more accessible to Albertans with the creation of an interactive, map-based website that will bring together provincial monitoring, reclamation and approvals data for the oilsands region. This information hub is expected to be online this summer.

The province’s reclamation certificate program is also being updated. These modifications will provide industry with greater clarity on the application process and on provincial expectations on reclamation performance, objectives and outcomes, says a government release.

Updates began in 2010 and should be complete by 2012, the release notes.

— Daily Oil Bulletin

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Enhance advances CO2 plans

By Pat Roche

MAR/10

MAR/11

MAR/10

MAR/11

WELLS SPUDDED

149

294

WELLS DRILLED

182

301

Photo: Joey Podlubny

(75 per cent from the Alberta government ’s royalt y bitumen and 25 per cent from Canadian Natural Resources Limited’s thermal oil operations).

All of Enhance Energy’s government funding agreements have been signed and the small, privately held company is moving ahead with its project, Cole says.

Work on the CO2 capture facilities will start first because those will take longer to build than the pipeline, which is slated for construction in the summer of 2013, she says.

The 240-kilometre pipeline will initially deliver CO2 from Agrium and North West to the Clive oilfield operated by Fairborne Energy Ltd. in central Alberta.

The Alberta government has conditionally committed $495 million to Enhance Energy over 10 years for construction of an Alberta CO2 pipeline network and CO2 capture facilities.

In explaining the rationale for government involvement, Cole uses the analogy of the Alberta Gas Trunk Line—the natural gas–gathering system created in 1954 by then Alberta premier Ernest Manning to spur growth of the province’s natural gas industry.

In the United States—where there are thousands of kilometres of CO2 pipelines—EOR projects produce a total of 260,000 barrels of oil a day, Cole says. The Weyburn project operated by Cenovus Energy Inc. in southern Saskatchewan produces more than 25,000 barrels of oil a day using CO2 from North Dakota.

Many studies have highlighted the fact that only about three of every 10 barrels of light oil discovered in Alberta now get produced—and that there are many mature oilfields that would be amenable to CO2 flooding, But because there’s never been an economically available supply of CO2, only a few tiny CO2 EOR projects now operate in the province.

So once the 240-kilometre Alberta CO2 pipeline is built, Enhance Energy hopes it will strike deals with other producers like it did with Fairborne. Enhance Energy, which plans to operate more as an oil producer than a pipeline operator or CO2 seller, will take a stake in the oilfields to which it supplies CO2.

At Clive, for example, Enhance Energy has a 40 per cent working interest. Agrium and North West Upgrading will sell CO2 to Enhance Energy.

“Our business model is that we are developing enhanced oil recovery projects.

So we’re not a marketer of CO2,” Cole says.

“We buy the CO2 for our own account. And we’re going to use the CO2 in enhanced oil recovery. So we don’t sell the CO2.”

Cole says most of the detailed engineering has been done for Enhance Energy’s capture facilities at the Agrium plant, a 4,800-horsepower compressor

Enhance plans on capturing CO2 and shipping it to the Clive field.

A project to supply CO2 for enhanced oil recovery (EOR) in Alberta is on track to break ground next year.

Enhance Energy Inc. plans to start construction in 2012 on CO2 capture facilities at the Agrium Inc. fertilizer plant in the Redwater area near Edmonton, says Susan Cole, president of Enhance Energy.

Enhance Energy will build capture facilities and buy CO 2 f rom Agrium under a previously negotiated agreement. E n ha nce E nerg y a lso has a n agreement with North West Upgrading I nc . to t a ke t he CO 2 f r om a bit umen upg rader/ref i ner y Nor t h West Upgrading plans to build across the road from Agrium.

Construction of the first phase of the upgrader/refinery—known as the Redwater refinery—should be assured because 100 per cent of its bitumen feedstock capacity has been secured CENTRAL ALBERTA WELL ACTIVITY

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O I L & G A S I N Q U I R E R • M AY 2011

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has been purchased and bid packages are being prepared for other components. For example, the Agrium CO2 is wet, so Enhance Energy is seeking bids for the dehydration equipment.

CO 2 from North West Upgrading’s gasification process will be dry, so all Enhance will have to do is compress it for pipelining. Enhance Energy is just at the front-end engineering design stage for the North West Upgrading capture facilities.

Enhance Energy’s large compressor system at North West Upgrading will convert the CO2 from a gas at essentially atmospheric pressure to a liquid at 2,600 pounds per square inch. The target for start-up is 2014.

Except for a small, 12-inch section in the Redwater area, the pipeline will be 16 inches in diameter.

Adding pumping stations can increase the pipeline’s capacity. But pumping won’t be necessary initially, as the pipeline will only deliver about 5,000 tonnes per day of CO2 from Agrium and North West Upgrading to the Clive oilfield.

With all the pumping stations added, the pipeline will have a ma ximum

capacity of 40,000 tonnes per day. While Agrium and North West Upgrading will only be capable of filling up to oneeighth of the pipeline’s ultimate capacity, Enhance Energy and the Alberta government believe that once the CO2 distribution

rising oil prices can only make EOR even more attractive.

Apart from the economic spinoffs, the payback for the province will be the royalties it collects on the increased light oil production. And that’s a key difference

“CCS is really economically challenged. The only way to make this work is to have a revenue stream. And enhanced oil recovery gives us that.”

— Susan Cole, President, Enhance Energy Inc.

network is in place, the economics will be attractive for other EOR operators.

Two of the three elements needed for a homegrown CO2 EOR industry—CO2 emissions and mature oilfields—have been available in Alberta for many years. Now that the third element—CO2 capture and distribution infrastructure—is being added with the help of government funding, more CO2 EOR projects are expected to start.

“Before, it was a situation where no one could afford to do these projects because… t hey couldn’t suppor t building t he infrastructure,” Cole says, adding that

between CO2 EOR and pure carbon capture and storage (CCS) into deep saline aquifers.

“We don’t need to really go to aquifer storage right now when we have so much potential for EOR in the province,” Cole says. Enhance Energy believes it can eventually fill the pipeline with 40,000 tonnes of CO2 per day and keep it going for many decades supplying EOR projects in Alberta.

“CCS is really economically challenged,” Cole adds. “The only way to make this work is to have a revenue stream. And enhanced oil recovery gives us that.”

— Daily Oil Bulletin

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Central Alberta

Expert panel named for Alberta CCS regulatory review The Alberta government has appointed a global panel of experts to help guide the regulatory review for carbon capture and storage (CCS) in advance of CCS projects that are to set to begin over the next two to three years.

Stefan Bachu, distinguished scientist for CO2 storage with Alberta Innovates Technology Futures, and Don Thompson, president of the Oil Sands Developers Group, will co-chair the six-member panel that is to report back to the energy minister in the fall of next year.

“When all is said and done we will have a robust, efficient and effective regulatory system that will ensure CCS technology is used in the safest most responsible way,” Alberta Energy Minister Ron Liepert says.

“Through our CCS program, Alberta is playing a key role in advancing this gamechanging technology, and we are demonstrating our commitment to greening our energy production.”

T he minister ack nowledges that Albertans have some concerns about CCS, and he promises that the government will

be sharing information and giving citizens an opportunity to provide input on the new rules.

The review process will examine in detail existing environmental, safety and assurance processes for CCS and determine what, if any, new processes need to be put in place for commercial-scale deployment of the technology.

At present, regulatory requirements applicable to CCS are spread out over a

well as measuring, monitoring and verification requirements.

CCS can play an important part in the various means of reducing greenhouse gases produced by fossil fuels, says Bachu who is a co-recipient of the 2007 Nobel Peace Prize awarded to t he Intergover n menta l Panel on Cli­m ate Change.

The technology is especially important for Alberta because the province has

“When all is said and done we will have a robust, efficient and effective regulatory system that will ensure CCS technology is used in the safest most responsible way.”

— Ron Liepert, Alberta Energy Minister

number of pieces of legislation and directives. The review will look at the existing regulatory regime in Alberta as well as CCS frameworks from other jurisdictions.

The review will focus on a number of areas including regulatory, environmental, geological and technical considerations as

a number of large stationary sources that allow for CO2 captures and because it has the geology that permits CSS as a technology for mitigating greenhouse gases, he says.

“As the world demands ever lower carbon products, carbon capture and

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O I L & G A S I N Q U I R E R • M AY 2011

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Central Alberta

The Alberta government has committed to removing 139 megatonnes of greenhouse gas emissions annually through CCS by 2050, beginning with five million tonnes a year by 2015. storage will be a key technology to green our energy production by physically removing greenhouse gases from emission sources and safely storing them,” says Thompson. With large industrial facilities and significant expertise in process engineering and operations, Alberta has all the prerequisites for large-scale CCS, he says.

The province also already has regulatory regime for hydrocarbon development, including acid gas injection, he points out.

In addition to the expert panel, which will provide advice and peer review findings, a steering committee will oversee the process and guide the scope of the review. Working groups will develop recommendations for the steering committee’s consideration.

The expert panel, steering committee and working group members represent

a broad range of expertise from the scientific, academic, regulatory, industry and public administration fields. Several other international experts are participating in this process, as well as representatives from the governments of British Columbia and Saskatchewan and the federal government.

The Alberta government has committed to removing 139 megatonnes of greenhouse gas emissions annually through CCS by 2050, beginning with five million tonnes a year by 2015.

Bachu says he is confident the government can achieve its goal as new estimates from the Geological Survey of Canada indicate that Alberta has storage capacity of tens of billions of tonnes of CO2.

The expert panel also includes: • Peter Cook, chief executive officer of the Cooperative Research Centre for Greenhouse Gas Technologies in western Australia; • A ndrew Chadwick, head of CO2 storage research at the British Geological Survey; • E dward Rubin, a professor in the department of engineering and public policy at Carnegie Mellon University in Pittsburgh, Penn., and the founding director of the university’s Center for Energy and Environmental Studies; and • L awrence Bengal, a geologist and the Arkansas governor’s representative to the Interstate Oil and Gas Compact Commission as chairman of the Carbon Capture and Geologic Storage Task Force.

— Daily Oil Bulletin

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M AY 2011 • O I L & G A S I N Q U I R E R

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Southern Alberta

Services sector under greatest threat in severe, looming labour shortage

By Lynda Harrison

MAR/10

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Photo: Joey Podlubny

If the industry expands due to high energy prices, it will need to find a staggering 130,000 workers, both to fill new positions and to keep pace with retirements, she adds.

“We are going into a perfect storm,” Knight says. “Just when the industry needs workers the most, Canada’s labour supply will be dwindling as the overall population ages. Our industry will need to be prepared to face a labour shortage more severe than in 2007.”

Canada’s current unemployment rate is around eight per cent; however, the unemployment rate is projected to drop to the tight 2007 rate of six per cent by 2013 and fall to below five per cent by 2020, creating significant competition for workers.

Meanwhile, the growing number of in situ operations in the oilsands and the use of fracking technology to unlock shale gas and oil are creating a need for new skills

and knowledge. Software technologists/ developers, fracking operators, and water and environmental management technicians are a few of the occupations where shortages are appearing as a result.

While the services sector is the hardest hit, certain oilsands workers such as steam engineers and power engineers, instrumentation technicians, fieldworkers and supervisors are in chronically short supply, Knight tells the Daily Oil Bulletin. “Also, anything to do with drilling and completions in the unconventional plays—and believe it or not, Class 1 truck drivers are also chronically short,” she says.

PHRCC has just released the latest edition of The Decade Ahead: Labour Market Projections and Analysis for Canada’s Oil and Gas Industry to 2020. The report provides labour market projections and analysis to 2020, identifies labour supply/ demand risks and recommends workforce strategies for stakeholder consideration.

Given the uncertainty surrounding the rate of recovery, PHRCC developed three scenario projections using varying levels of commodity pricing and corresponding industry activity: • A low scenario where low oil and gas prices do not encourage capital investment. Oilsands growth is limited to the addition of production from projects currently under construction.

• A growth oil/low gas scenario where gas prices remain low and discourage gasrelated investment, but oil prices increase and encourage oil-related investment and activity, specifically in oilsands.

• A growth scenario where capital investment is encouraged and growth occurs in both oil- and gas-related activity.

K n ight say s t hat shor tages a re expected across all the industry’s core occupations as early as 2013. The industry will be hiring at every occupation and skill level, she says.

First Nations students attend a job seminar in northeastern Alberta. They will play a key role in providing a workforce for the future.

Already experiencing a chronic lack of workers in some areas, the oil and gas industry needs to prepare for a labour shortage more severe than the one it ex­perienced in 2007, according to the head of the Petroleum Human Resources Council of Canada (PHRCC).

The industry is facing a severe situation regardless of energy prices and industry activity as more people retire from the workforce, says Cheryl Knight, chief executive officer of the PHRCC. A major factor is the industry’s aging workforce, Knight says. More than 30 per cent of the core workforce is expected to retire over the next decade. PHRCC estimates show that even if prices and activity are low over the next 10 years, industry will still need to hire at least 39,000 workers to replace its most experienced, skilled people.

SOUTHERN ALBERTA WELL ACTIVITY

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O I L & G A S I N Q U I R E R • M AY 2011

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Southern Alberta

The services sector may need to hire as many as 72,000 workers over the next 10 years, says Jones. He calls for improved communication between producers and contractors for better planning.

The services sector will need to hire workers in all scenarios between 2010 and 2020: • In the low scenario, the sector’s net hiring requirement is 18,100 workers, resulting from 2,900 job losses due to decreased industry activity and 21,000 job vacancies due to age-related attrition.

• In the growth oil/low gas scenario, over 26,200 positions need to be filled: 19 per cent of the positions are new, while 81 per cent is due to age-related attrition.

Tom Huffaker, vice-president of policy and environment for the Canadian Association of

Photo: Joey Podlubny

The new reality is that labour supply is not unlike oil supply—the readily available sources are gone. Labour supply to ensure sustainable expansion of Canada’s petroleum industry will take diversification, development and collaboration, she explains.

“The key problem is that our industry has a number of occupations that are industry-specific, and the only way we can supply ourselves with those workers is from schools or foreign-trained professionals or from our competition,” Knight says. “So for some of those high-skilled, industryspecific jobs, we’re the most vulnerable because the supply sources are limited.”

Bruce Jones, past chair of the Canadian Association of Oilwell Drilling Contractors, warns that the labour shortage in the

Oilpatch workers are aging, meaning a major turnover is on the way.

services sector will ripple through the rest of the oil and gas industry.

Jones says the services sector, comprised of 83,000 workers, including 9,000 drilling rig employees, is already experiencing a critical manpower shortage. This winter’s activity was similar to peak years 2005-07, he says.

The sector was hardest hit by the economic downturn, downsizing by 13,000 to 15,000 positions, and with industry recovering, it is also one of the first to experience labour shortages. It faces real struggles attracting the experienced workers laid off in 2008-09.

Attracting new entrants isn’t as difficult, but entry-level oil and gas drilling and services fieldworker positions have turnover rates as high as 35 per cent. Seasonal work, remote locations, being away from home for long periods of time and working outdoors in all weather conditions are some of the reasons new entrants leave the sector.

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M AY 2011 • O I L & G A S I N Q U I R E R

Petroleum Producers, says that in the high scenario of increasing prices, 15,000 highly skilled oilsands workers will be needed in the next 10 years. In any case, 3,600 retirees will have to be replaced, he says.

According to the PHRCC, managing the future labour shortage will require a combination of strategies, such as: • C ommunicating the petroleum industry’s labour requirements to key stakeholders including governments and post-secondary and training institutions • A ttracting new workers from diverse, new labour supply pools • Managing labour costs • Improving collaboration, and • I ncreasing employee retention, workforce training and development, innovation and technological advancement.

Companies are reporting a chronic shortage of experienced engineers (exploitation, completions, production and mining); plant operators; steam engineers and power

engineers; maintenance trades and production accountants; field operators/specialists (slickline, snubbing and completions); rig crews (derrickhands in particular); and environmental and regulatory specialists.

Unconventional natural gas and oil activities need software technologists/ developers, geologists and engineers with knowledge of shale gas and oil reservoirs and well stimulation and completions.

Also in demand are measurement-whiledrilling specialists.

In situ oilsands projects need surface and subsurface engineers, as well as first-, second- and third-class steam engineers, and water management technicians and specialists.

According to the report, if oil prices rise but gas prices don’t, industry will need to hire for about 53,500 positions between 2010 and 2020. In this scenario, continued investment in oil-related activity creates approximately 13,000 new jobs specifically in the oilsands and services sectors, while decreased gas activity results in about 6,000 job losses. The overall result is a net increase of 7,000 jobs, or a four per cent increase from the industry’s 2009 workforce.

Also, age-related attrition accounts for the majority of hiring requirements as approximately 46,500 workers retire from the industry.

In addition, increased capital investment drives the addition of approximately 76,000 positions to the industry’s 2009 workforce.

While the industry workforce size expands by 45 per cent, there will also be approximately 54,000 vacancies due to age-related attrition.

In the growth scenario, immigration will be the primary source of new workers for the industry. The report says oil and gas companies have not hired from this labour pool in a significant way and will need to in the future.

The oilsands sector continued to hire for operations personnel throughout the economic downturn. In 2009, the sector employed approximately 12,300 workers and in every scenario, the oilsands’ workforce is projected to grow in size.

Mass hiring for a number of concurrent projects, age-related attrition and hiring for hard-to-recruit locations will contribute to the oilsands sector’s recruitment challenges. Between 2010 and 2020, the sector will need to hire for at least 9,000 positions and possibly up to 14,900 positions due to a combination of expansion and replacement demand.

Southern Alberta

Gas export revenues lowest since 1999 Prices for Canada’s gas exports to the United States fell about three per cent last year to the lowest level since 1999, according to National Energy Board data.

For the second year in a row, prices were weak, with a 2010 average of only $4.29 per gigajoule, off 13 cents from the 2009 average of $4.42 per gigajoule. Between 2003 and 2008, gas export prices ranged between $6.73 and $8.89 per gigajoule.

With lower prices and gas export volumes essentially flat last year compared to 2009, revenues from Canadian gas exports dropped to $15.15 billion in 2010, also the lowest since 1999 when producers received about $11 billion from American buyers on smaller volumes.

Part of the problem for Canadian producers last year was the rising value of the Canadian dollar.

The peak years for gas export revenues occurred in 2005, when over $35.5 billion returned to Canada from sales abroad, and 2008, when gas export revenues reached $33.1 billion.

Canadian producers sent 92.4 billion cubic metres of gas south of the border in 2010, a small rise from the previous year.

The record year for volume exports was 2007, when industry shipped nearly 107.5 billion cubic metres to American markets.

Part of the problem for Canadian producers last year was the rising value of the Canadian dollar vis-à-vis its American counterpart. In U.S. dollar terms, Americans paid more for Canadian gas in 2010 than in 2009, but those dollars were worth less when converted into Canadian currency.

Daily Oil Bulletin records show the Canadian dollar was worth about 97 cents in U.S. dollars last year, compared to only 87 cents in 2009.

For the first nine months of 2010, U.S. Energy Information Administration data shows an average import price of US$4.82 per million British thermal units of Canadian gas, up from $3.90 per million British thermal units for the same period in 2009.

— Daily Oil Bulletin O I L & G A S I N Q U I R E R • M AY 2011

51

Southern Alberta

Service sector spending increasing as demand remains strong For the second year in a row, service and supply companies are hiking their capital budgets to meet strong demand from producers chasing oil, bitumen and liquidsrich gas opportunities.

E ncouraged by a st ronger-t ha nanticipated r un in 2010 — and w it h demand for pressure pumping and horizontal drilling services showing no signs of letting up in the near-term—many service companies are increasing capital spending this year as field activity continues to rise.

“The numbers are mind-boggling,” says Mark Salkeld, president and chief executive officer of the Petroleum Services Association of Canada.

“Most companies are spending more.

Money is increasing on R&D [research and development], but it’s also increasing with respect to building new equipment, new technology equipment. A lot of that is due to the direction we’re going in with respect to horizontal drilling and multistage fracturing, and with all the pumping equipment.”

A look into the Daily Oil Bulletin database confirms Salkeld’s claims. Of service companies that have reported 2011 capital plans, many have increased spending considerably from 2010.

A sampling of 23 companies that have released their 2011 capital budget plans shows that aggregate capital spending for this year is anticipated to be about $3.24 billion. Last year, those same companies spent about $1.93 billion, while in 2009, a year many in the service sector were in survival mode, the companies spent a total of $1.58 billion, or about half of what they plan for this year.

A mong the companies that plan to spend more t h is yea r is Tr ica n Well Service Ltd., which has already announced it will hike its originally planned 2011 capital budget by $120 million to $493 million. The company spent $284.62 million last year. Precision Drilling Corporation is also bumping up capital spending substantially to about $423 million, an increase from about $176 million last year.

As well, Calfrac Well Services Ltd. announced a capital budget for 2011 of $280 million, up from anticipated 2010 capital spending of $236 million.

“The member companies that have done well over a number of years, like the Tricans, Precisions and Calfracs, those are the ones that are investing in equipment when the climate is good. It gives them a competitive edge for when things get flat, because you can offer brand-new, top-ofthe-line equipment,” Salkeld says.

“Right now, 2011 is looking good, it’s shaping up well. The producers are spending, the service companies are spending and putting people to work.”

Smaller and mid-sized service companies have also announced spending hikes. Pure Energ y Ser vices Limited plans to spend about $38 million this year. Daily Oil Bulletin records show Pure Energy’s 2010 capital budget was $14.9 million. Strad Energy Services Ltd. has a planned $66.5-million capital program in 2011, compared to $42.93 million in 2010.

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M AY 2011 • O I L & G A S I N Q U I R E R

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Southern Alberta GASFRAC Energy Services Inc. will up 2011 spending to about $150 million from $83.5 million last year, while Essential Energy Services Ltd. plans a $27-million capital budget this year compared to $20.5 million in 2010.

However, some compa nies have announced reduced spending plans for 2011. For example, Canyon Ser vices

service sector are “spending more aggressively” than last year.

“Pressure pumpers are increasing capex [capital expenditure] the most by far to meet current shortages and capitalize on increasing frac intensity. Drillers are expanding also, but less so than pumpers, and only usually when there is demand for long-term contracts,” he says.

“The problem is not demand for either pumping or high-spec rigs, but companies have to manage their capex based on what they can staff.”

— Michael Mazar, Analyst, BMO Nesbitt Burns Inc.

Group Inc. has set an initial 2011 capital budget of $68 million, compared to $80.5 million last year. Similarly, Savanna Energy Services Corp. will reduce spending this year to $89 million from $104.6 million a year earlier.

A lthough he hasn’t compiled an aggregate number, BMO Nesbitt Burns Inc. analyst Michael Mazar tells the Daily Oil Bulletin that most components of the

“The problem is not demand for either pumping or high-spec rigs, but companies have to manage their capex based on what they can staff. Shortages of people will, in some cases, dictate what companies can build.”

Salkeld agrees that in unison with the increases in activity and spending, labour shor tages are fast becoming an issue.

“We’re bottlenecked with respect to labour, so that means there’s iron sitting up against the fence that isn’t getting put to work because of a shortage of labour,” he says.

“We’re in the thick of it. However, there are companies that have rigs parked because they may have contracts for 80 rigs and they can only put 70 to work.

So, in terms of labour concerns…we’re stretched and it’s hurting. We could be doing better and we could be putting more people to work.”

Kevin Lo, service sector analyst for FirstEnergy Capital Corp., says momentum gained in 2010 will continue this year.

He expects the upward spike in oil and liquids resource play-directed activity and increased capital spending by both producers and services companies to become a theme as the year progresses.

“Clearly, the migration in Canada from dry gas to oil and natural gas liquids drilling continues to bolster activity levels, and are pushing producers to be more aggressive on their drilling programs,” he says.

“With demand for drilling extremely high in western Canada, rates are picking up, particularly for contract drillers, who

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did not experience any material uptick in 2010. We believe companies will generally guide toward a better second half of 2011, as the high demand today would entice clients to attempt to secure equipment early.”

Because of the higher activity levels witnessed so far in the first quarter, Lo notes that FirstEnergy recently increased its estimated 2011 well count to 12,735 from 12,318, while also bumping up its projections for 2012.

“In 2012, we have moved our well count to 13,800 from 13,233, which represents growth of eight per cent year-overyear. With our 2012 estimated forecasted oil price of US$95 per barrel, we expect oil activity to remain strong in all of Canada’s key oil plays,” Lo says.

“As well, large storage draws in North America are removing some of the downside uncertainty on gas prices, which in turn has the potential to put a floor under gas drilling activity.”

Despite the optimism, Lo cautions that FirstEnergy remains “somewhat conservative” on the outlook for the second half of this year, given the weak natural gas price environment.

“That said, if gas were to move materially higher, we suspect services pricing will see a much larger uplift than currently forecast. Of course, cost inflation will also ensue.”

With FirstEnergy’s increase in well count, Lo says estimated 2011 utilization is now pegged at 42.4 per cent, up from the firm’s prior estimate of 41.1 per cent.

For 2012, FirstEnergy is now calling for utilization of 45.3 per cent, up from previous estimates of 43.4 per cent.

“Utilization levels have improved materially off the 2009 bottom, yet they are still well below the 2005 peak level of 59.2 per cent,” Lo notes. “Despite utilization not being at peak levels, we still expect contract drillers to realize significant rate increases due to high demand for rigs that can drill horizontal wells.”

Lo says that as of mid-February, 525 of 800 rigs available in western Canada were able to drill to a depth greater than 2,400 metres. Since January 2010, these rigs have averaged utilization of 59.5 per cent.

That bodes well for short-term pricing.

“It is our view that when utilization averages above 50 per cent for an extended period, contract drillers are able to attain pricing power and move rates higher. Anecdotal evidence has suggested

Southern Alberta

that the drillers have moved rates up on their deeper rigs by $1,500 to $3,000 a day, depending on add-ons,” Lo says.

“Note that this rate increase is exclusive of winter additions, such as boilers.

In contrast, medium and shallow rigs have averaged utilization of 39.2 per cent and 30.6 per cent respectively, and will likely see lessened upward movement in pricing.”

However, Lo says that an active coring market and shallow oil targets have helped utilization rates in the shallow areas in the first quarter of 2011.

Scott Treadwell, oilfield ser vices analyst and vice-president, oil and gas research for Macquarie Capital Markets Canada Ltd., says the increased spending plans of some service companies is indicative of the continued upswing in the oil and gas industry as a whole.

“Big picture is that 2011 will be a little better than 2010. It seems like there’s more certainty around [producer] activity and spending, so the service companies are a little more active in spending early in the year,” he says.

“We’re calling for approximately 13,000 wells this year, with more concentration on oil over gas.”

While service sector capital spending seems to be on the upswing this year, Treadwell notes that the payoff for service companies from the deployment of new equipment into the market will lag.

“The other thing to consider is that a lot of spending in the services space is delayed in impact. Fracturing spreads are at least six months to build, rigs can be anywhere from four months to nine months. That means a lot of the dollars spent this year won’t have big impact until the end of the year or early in 2012,” he says.

— Daily Oil Bulletin

Horizontal drilling headed for another record year Industry has been swift to move to using staged fracking in horizontal wells in western Canada’s less permeable reservoirs—and it’s only going to pick up speed in 2011 after setting records last year.

Employing more equipment and staff, these more complex wells are rejuvenating Canada’s service and supply sector at a time when low natural gas prices would normally bring market weakness.

Gas drilling is even weaker in 2011 than last year’s low level of activity, but the strong surge of tight oil exploitation is pushing overall activity ahead of both 2010 and 2009.

Judging by the first two months of 2011, it looks like the year will set another high for horizontal wells.

Over the January-February period, operators licensed 1,577 new horizontal holes, up 61 per cent from 981 last year (which was a record year for horizontal permits). Moreover, the 1,577 horizontal permits were more than double the number of conventional vertical wells licensed to the end of February.

The dominance of oil targets in well licensing is also accelerating this year.

Operators licensed 2,072 wells targeting oil or bitumen production in the JanuaryFebruary period, compared to only 624 gas or coalbed methane (CBM) targets.

The 2,072 oil targets easily surpass all other years since the turn of the century and compare to the 1,348 oil permits issued in the first two months of last year.

And oil licensing was higher than a year ago in all four western Canadian provinces. Alberta led the way with

read more online at energizealberta.com Where energy, the economy, and the environment intersect.

1,186 new wells licensed for oil or bitumen production, up from 721 last year.

Saskatchewan approved 751 wells aimed at oil deposits, compared to 526 last year, and Manitoba issued 121 oil-intended licences versus 95 in the first two months of 2010.

Even gas-prone British Columbia shows 14 oil licences so far this year, up from six in 2010.

By contrast, the 624 gas-intended permits issued to the end of February is the lowest in a long time and down 47 per cent from last year’s 918 licences. The peak year was 2006, when 3,822 licences were issued in the first two months targeting gas or CBM production.

Overall, industry licensed 1,544 new wells last month, up 23 per cent from 1,256 approved for the same month in 2010. In 2009, only 871 permits were approved. Permitting activity in February was higher in all four western Canadian provinces than a year ago. Even British Columbia showed a higher count with 116 assigned licences in February, up from 74 last year, due in part to a large drilling program by Encana Corporation at Sunrise.

In the first two months of 2011, governments authorized 3,891 new wells, the most since the winter of 2008 and 21 per cent above the 3,208 licences granted to the end of February 2010.

The total this year includes 826 oilsands evaluation wells, of which 172 were issued in February. That compares to 774 oilsands evaluation holes in the first two months of last year.

— Daily Oil Bulletin

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Saskatchewan

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Saskatchewan oil revenue, production expected to climb

Oil will continue driving Saskatchewan's economy in 2011.

The Saskatchewan government is projecting a strong near-term outlook for oil with production, prices and revenue all expected to rise, while revenue from natural gas will continue to be weak.

With an election set for November, the Saskatchewan Party government tabled its budget for the coming fiscal year on March 23, which forecasts higher total non-renewable resource revenue of $2.8 billion in 2011-12, an increase of $266.2 million from the final tally expected for the 2010-11 fiscal year ending on March 31. The increase is due to growth in oil, potash, resource surcharge and other nonrenewable resources, partially offset by decreases in Crown land sales and natural gas revenue.

Non-renewable resource revenue is forecast to make up 26 per cent of total revenue in 2011-12, equal to the average over the most recent five-year period.

Oil revenue is forecast to increase $177.5 million in 2011-12 to $1.4 billion as a result of a higher average wellhead price and increased production. Oil production is expected to climb to 159.4 million barrels in 2011-12 from 150.8 million barrels the previous fiscal year.

Wellhead prices are projected to rise to $77.38 in 2011-12 from $67.24, mainly

Ken Krawetz. “It’s important that we ma i nt a i n t he moment u m t hat we have achieved.

“The Ministry of Energy and Resources will enhance the efficiency and effectiveness of services in the oilpatch by spending $13.8 million to modernize our information systems. It costs companies tens of thousands of dollars a day when rigs are idle. That’s why we will spend $1.4 million to reduce approval and licensing time.”

It’s a different story for natural gas revenue, however, which will be hampered by weak prices and lower production. Natural gas revenue is forecast at $22.5 million in the next fiscal year, a decrease of $3.1 million from 2010-11 as a result of falling production, partially offset by slightly higher average fieldgate prices.

Production is forecast to decline by 12 per cent in 2011-12 to 160.2 billion cubic feet, largely due to weaker drilling activity. Fieldgate prices are forecast to average $3.65 per gigajoule, up from $3.39 in 2010-11. By 2014-15, the province expects natural gas production to fall to 129.9 billion cubic feet on a fieldgate price of $5.63.

Crown land sales revenue is forecast at $436.4 million in 2011-12, a drop of $30.3 million. While lower than the previous year, sales of Crown petroleum and natural gas rights are projected to be the third highest on record.

“It costs companies tens of thousands of dollars a day when rigs are idle. That’s why we will spend $1.4 million to reduce approval and licensing time.”

— Ken Krawetz, Saskatchewan Finance Minister

because of a higher West Texas Intermediate oil price forecast of $93.75 compared to $81.85 the previous year, partially offset by an increase in the exchange rate.

“Oil prices are high and we are projec t i ng a not her g reat yea r for exploration,” says Finance Minister

The value of the Canadian dollar is anticipated to average 99.82 U.S. cents in 2011-12, slightly lower than current rates, but over two U.S. cents higher than in 2010-11.

The higher exchange rate reduces Canadian dollar prices for resources sold in U.S. dollars, including oil, potash and uranium.

MAR/10

MAR/11

MAR/10

MAR/11

WELLS SPUDDED

142

218

WELLS DRILLED

193

275

SASKATCHEWAN WELL ACTIVITY

MAR/10

MAR/11

WELL LICENCES

287

647

▲

▲

▲

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • M AY 2011

57

Saskatchewan In 2011-12, a US$1 per barrel change in t he average annual West Texas Intermediate oil price will result in an estimated $18.5 million change in oil royalties, while a 10 cent per gigajoule shift in the annual natural gas fieldgate price means a $900,000 change in natural gas royalties.

The province is forecasting a pretransfer surplus of $115 million in 2011-12

after an expected surplus of $40 million in 2010-11. The growth and financial security fund should have a balance of $710.8 million at the end of 2011-12, the government says.

Saskatchewan’s real gross domestic product is forecast to grow by 4.2 per cent this year and 2.8 per cent in 2012. That’s partly fuelled by higher business investment, particularly in the oil and potash sectors.

Budget investments include $3.2 million for energy industry research, including $2.3 million for the Petroleum Technology Research Centre for petroleum research projects and $2.8 million to expand the Subsurface Geological Laboratory in Regina for the benefit of industry and research institutions.

— Daily Oil Bulletin

Petrobank piloting natural gas to enhance Bakken oil recovery Petrobank Energy and Resources Ltd. says it will inject natural gas to enhance oil recovery in Saskatchewan’s Bakken light oil play.

Through experimentation with various new completion fluids and techniques, the company has landed on a new frac methodology that appears to minimize problems created by fracking out of the zone, says John Wright, president and chief executive officer.

“Our early results are very encouraging and we’re applying this technique to all our new wells, as well as to the

inventory of unfracked wells that we carried into this year and those wells that have been producing at exceptionally low rates, since they have not received any kind of fracture stimulation at all,” says Wright.

The company field-tested the concept with CO2, since it did not require the construction of additional facilities.

A simple two-day CO2 inject stimulation into a horizontal wellbore validated the reservoir stimulations, and the offsetting horizontal wells responded by more than doubling their production. After 10

months, they are still producing rates 50 per cent higher than prior to the simple two-day injection.

“We’re now proceeding with natural gas EOR [enhanced oil recovery] pilot projects. We drilled two horizontal wells that are now producing, but which will be turned into injectors—the first one later in March and the second one in the second quarter,” says Wright.

Success in these pilots will encourage the company to implement up to five natural gas EOR pilot projects in 2011.

— Daily Oil Bulletin

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Central Canada

Quebec announces new royalty for shale gas Quebec inks deal with feds for offshore development

— Daily Oil Bulletin

— Daily Oil Bulletin

Photo: Questerre Energy

based on the recovery of capital invested and returns achieved.

Busi nesses t hat have completed w e l l s — d r i l l i n g a n d c o m pl e t i o n — before t he int roduc t ion of t he new system will be able to continue oper­ ating under the current royalty regime t h r oug hout t he pr o duc t ion l i fe of those wells, even after the new royalty regime takes effect.

The government will also allow businesses participating in the strategic environmental assessment to make their wells subject retroactively to the gas development program. When the strategic environmental assessment is finished, the government could also propose new economic measures to take into account the information collected during the assessment.

An optimistic view of the recoverable potential in the province implies approximately 18,100 wells drilled in Quebec over a period of nearly 70 years. By comparison, the BAPE report says that over 28,000 wells have already been drilled in British Columbia and 400,000 in Alberta.

The federal government and Quebec inked an agreement in late March for the development of oil and gas resources in the Gulf of St. Lawrence.

According to the accord, Quebec will benefit from all revenues from the development of petroleum resources, including royalties, bonuses, forfeitures, licence fees and other forms of rev­ enue, as if these resources were on land.

The province will establish the royalty regime in the accord area and assure its application.

The governments will negotiate an agreement separate from the accord on the imposition and administration of corporate tax income and sales taxes and the sharing of tax revenues.

“After more than 12 years…we are very proud to announce that the province of Quebec has an agreement that will give us 100 per cent of the revenues from the development of our oil and gas in the Gulf,” Nathalie Normandeau, Quebec’s minister of natural resources.

The Quebec government is conducting a strategic environmental evaluation before allowing development of oil and gas in the Gulf, but the results won’t be known until 2012.

No commercial discoveries have been made in the Quebec offshore region and its potential is unknown.

The accord will be implemented by mirror legislation by the federal and provincial governments and will be implemented in steps. Environmental assessments will be done before any oil and gas development begins.

Studies have indicated that the Gulf of St. Lawrence holds potential for hydrocarbon exploration. To date, only 10 offshore wells have been drilled in the under-explored area.

Quebec shale gas leaseholders now know what type of royalties they can expect when, or if, the drilling moratorium ends.

The Quebec government is introducing a new natural gas royalty system in the province that will be sensitive to both price and production.

In its March 17 budget, the province announced that the royalty rate, when introduced, will vary from five per cent to 35 per cent. The bottom end will apply when prices and production are low and rises to the maximum when prices and well productivity are high.

Fo l l o w i n g t h e r e p o r t o f t h e Bu reau d’aud iences publ iques su r l’env i ron nement ( BA PE) t hat reco m m e n d e d a s t r a t e g i c e n v i r o n ­mental review of shale gas development, the minister of finance announced a budget of $7 million to conduct this assessment.

An additional investment of $6 million over three years will also be made to enhance the inspection of wells and facilities.

The province also announced the introduction of a gas development program modelled on the net profit royalty regime in northeast British Columbia. The progressive royalty rate starts at two per cent and varies through a four-tiered scale

O I L & G A S I N Q U I R E R • M AY 2011

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Photo: Corridor Resources

Corridor’s results continue downward trend

The location of Corridor's operations in New Brunswick.

Corridor’s production declined by more than 600 barrels of oil equivalent (boe) per day compared to 2009, resulting in a net loss of $8.61 million compared to a profit of $1.68 million a year earlier.

Cash flow declined to $13.71 million from $27.83 million in 2009.

The company said that the decrease in its revenues, cash flow from operations, and net earnings over the last three years is primarily the result of the decrease in the average realized natural gas sales price, from $11.21 per thousand cubic feet in 2008 to $7.34 in 2009 and $5.66 in 2010.

In response to the lower natural gas prices, Corridor said it began decreasing drilling activities starting in the second quarter of 2009, which resulted in an average daily gas production to 2,215 boe per day for the year ended Dec. 31, 2010, a decrease from its output of 2,859 boe per day last year.

Production in the fourth quarter of 2010 was 2,229 boe per day, compared to 3,287 boe per day in the year prior.

For the year ended Dec. 31, 2010, cap­ ital expenditures decreased to $21.87 million from $38.36 million in 2009. This was due mostly to the decision not to conduct a

fracture stimulation program at the New Brunswick McCully field in 2010, while in 2009 Corridor conducted a fracture stimulation program for three McCully wells and the Green Road G-41 well.

The company said the decrease in cap­ ital expenditures in 2010 was also due to the reduction in drilling costs and partially offset by increased midstream facil­ ities expenditures. During 2010, Corridor drilled the McCully L-37 well and three wells (two net wells) on Anticosti Island.

During the second quarter of 2010, Corridor completed perforating the L-37 wellbore in the McCully field. Initial efforts to flow test this well without stimulation resulted in relatively low rates of natural gas production. The McCully L-37 well was designed to be drilled and completed without fracture stimulation, while retaining the option to frac part of the pay section if necessary.

This completion approach is significantly less expensive than conducting a multistage frac program in the horizontal leg of the well. However, it appears that the L-37 well encountered greater amounts of bitumen in the reservoir sands than

expected, resulting in significantly lower rates of gas production than expected.

Consequently, the company said it is currently evaluating options to recomplete the well, including conducting a propane frac in the well at the next opportunity when suitable frac equipment is available in the region.

In the third quarter, the 2010 oil explor­ation drilling program on Anticosti Island was completed. As part of this program, three wells were drilled to evaluate the oil potential of the Trenton/Black River and Mingan Group formations in the Jupiter, Chaloupe and Saumon prospects located in the east-central part of the island.

The company noted that while results of the three wells drilled on Anticosti Island “appeared disappointing,” the presence of live oil shows and locally permeable reservoir development combined with the very large number of prospects are positive factors for future oil exploration on the island.

During the second and third quarters of 2010, Apache Canada Ltd. completed the drilling and casing of the first two horizontal wells in the Frederick Brook shale play located north of Elgin, N.B., pursuant to its farm-out agreement with Corridor.

Strong gas shows were encountered in the horizontal section of both the Green Road B-41 well and the Will DeMille G-59 well during drilling. In the fourth quarter, five slickwater fracture stimulation procedures were completed in each of the wells. Corridor said that the final frac in the “silty interval” of the Green Road B-41 horizontal well is approximately 630 metres from the silty interval of the Green Road G-41 vertical well drilled by Corridor in 2009.

That interval in the vertical G-41 well was fracked with propane in 2009, peaking at 11.7 million cubic feet per day with a final rate of three million cubic feet per day.

The B-41 wells and G-59 well, however, have been disappointments, says Corridor.

Corridor and Apache are currently evaluating the performance to date of the Green Road B-41 and the Will DeMille G-59 horizontal wells and are considering options for the next steps.

— DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • M AY 2011

63

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Photo: TransCanada Corp.

U.S. senators call for approval of Keystone pipeline

TransCanada is awaiting permission from U.S. President Obama on whether it can break ground on the construction of the Keystone XL expansion.

TransCanada Corporation recently welcomed the support of 14 United States senators for the controversial Keystone XL pipeline expansion.

The bipartisan group of U.S. sen­ ator s joi n s a g row i ng l ist of la ndow ners, state and federal of f icials, l ab ou r u n ion s , m i l it a r y ve te r a n s , energy experts, economists, business leaders and other supporters in urging the U.S. Department of State to take favourable action on the Presidential Permit application for this project.

In a letter to Secretary of State Hillary Rodham Clinton, the senators called for approval of the critical Keystone XL project in order to strengthen America’s energy security.

The 14 senators noted in their letter to the secretary of state that recent events in Libya and the Middle East have reminded Americans of the country’s dependence on foreign oil from those regions.

To that end, the senators state, “Americans are tired of this dependency.

Americans first want our country to develop our own domestic resources to supply our

energy needs. However, when domestic supply is going to fall short, then Americans want the U.S. to rely on countries like Canada, that are stable allies, to help us meet our energy needs. As such, we write today in support of the Keystone XL Gulf Coast Expansion Pipeline, a pro­ject that the Department of State has been considering under a Presidential Permit application since 2008. Now more than ever, it is critical that this country move forward with this project.”

TransCanada reiterated that the Keystone XL pipeline will spur more than $20 billion in new private sector investment in the U.S. economy, create at least 20,000 high-quality jobs during the pipeline’s construction phase, generate $6.5 billion in new personal income for U.S. workers and their families, and stimulate more than $585 million in new state and local taxes in states along the pipeline route.

The Perryman Group of Texas conservatively estimated that the Keystone XL pipeline would add more than 250,000 permanent jobs for U.S. workers and $100 billion in annual total expenditures to the U.S. economy. These estimates were based on the 2007 average price per barrel of oil US$66.52.

Noting that Keystone XL would “provide thousands of high-quality jobs for Americans and invest billions of private sector dollars in our nation’s economy,” the senators call the economic benefits of “this shovel-ready, multi-billion dollar private sector project… extraordinarily compelling.”

— Daily Oil Bulletin

TransGlobe plans to acquire Egyptian concession TransGlobe Energy Corporation has signed a sale and purchase agreement to acquire a 100 per cent working interest in the West Bakr concession agreement in Egypt from the Egyptian Petroleum Development Co. Ltd. (of Japan), subject to the approval of the Egyptian government and customary closing conditions.

The US$60-million all-cash deal, retroactive to July 1, 2010, brings operatorship of three fields with 28 producing wells

and is immediately accretive to funds f low from operations and net income, TransGlobe says.

The assets produce 4,000 barrels of oil per day and contain 7.4 million barrels of proved reserves and 8.8 million barrels of proved plus probable reserves.

Transaction metrics are approximately $15,000 per producing barrel of oil for the assets, or $6.82 per proved plus probable barrel of oil.

The 11,600 acres in two development leases are located immediately adjacent to TransGlobe’s existing West Gharib development leases.

The produced oil ranges from 17 degrees to 20 degrees API and is pipeline connected to the Ras Gharib terminal on the coast, which is the same export terminal West Gharib production is currently trucked to.

— Daily Oil Bulletin O I L & G A S I N Q U I R E R • M AY 2011

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first year in business?

Trevor: We went into business together because our careers had

Kristie: We are competing with well-established companies that have

taken us on the road away from each other. Working together has been

been around for decades. To set ourselves apart, we established that

a good thing for our relationship and our business.

we are an innovative non-destructive testing company that puts our cli-

Kristie: Personally, I think that any partnership will always have its chal-

ents’ and our employees’ interests first. We really focused on not only

lenges, but I really believe we bring different skills to the table. Together,

meeting but exceeding industry standards in technology and in safety.

we make a really good team and complement each other’s strengths.

All of our technologies are up to the minute and we have a skilled team of technicians and inspectors with multiple applicable industry certifi-

To date, what are some of your greatest achievements?

cations such as CWB, API and CGSB.

Kristie: I think we have established a very strong team and work culture. We believe that our people are Endeavour’s greatest asset. We

What helped you make it through the first year?

have both worked for larger companies and we really wanted to create

Trevor: We had a solid plan. Of course, there is always something you

a culture that makes employees feel like we have their best interests

didn’t think of, but having a strong foundation and vision goes a long way.

in mind. We work in an industry where employees come and go, so we

You also have to be very committed. We put everything we worked for on

make every effort to hold onto to our small team and keep them happy.

the line for our business. Nothing is handed to you; you have to earn it.

Trevor: I am proud of the technical expertise we bring to each job and

You have to celebrate the small victories and not dwell on bad days. No

how far we have come in the first year.

matter what, you have to keep forging ahead.

O I L & G A S I N Q U I R E R • M AY 2011

67

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TOOLS

OF THE TRADE A LOOK AT NEW TECHNOLOGIES

QuickFRAC system What is the QuickFRAC system?

Advantages/Benefits

Packers Plus Energy Services Inc. is releasing a new technology capable of

• Batch fracturing of multiple stages

fracturing 60 stages downhole while only pumping 15 treatments at surface.

• Faster completion times

This new system, called QuickFRAC®, is the first of its kind in the industry.

• Reduced fracturing fluids

Using limited-entry diversion techniques and proprietary technology, the

• Reduced costs

QuickFRAC system allows operators to fracture several isolated stages at

• Less environmental impact

one time through a process known as batch fracturing.

• Enhanced near-wellbore conductivity due to reduced fracture fluid usage • Improved fracture network creation due to increased rock stress from

QuickFRAC is a great technology that has met the need for an increased

simultaneous fracture initiation

number of stages in shale and tight sandstone formations such as the Bakken, the Horn River and the Cardium, as well as many others.

Is the system out in field?

QuickFRAC allows the operator to do the job of pumping 15 stages on

This system has been successfully trialled in the field and is now commer-

surface while Packers Plus does the job downhole, providing as many as

cially available.

60 individual stages. This is done by taking a single pumping treatment on surface and precisely directing it into 2-5 stages downhole. For the oper­

What benefits does it offer?

ator, pumping time and costs are reduced significantly and production

The QuickFRAC technology has been proven in shale and tight sandstone

results are greatly increased.

formations, resulting in a 60 per cent reduction in operation time compared to our standard StackFRAC® system. This is an impressive savings

Technology

and means that our customers will realize an improved return on their

• Flexible design enables optimization of fracture treatment

investment.

• Fluid or proppant fracturing compatible • System designed to prevent abrasion from sand fracturing • One ball size activates multiple QuickPORT sleeves, allowing for more stages

This story was adapted from a Packers Plus Energy Services Inc. release.

The QuickFRAC system will open up as many as 60 stages to production

O I L & G A S I N Q U I R E R • M AY 2011

69

Advertisers' Index 1214848 Alberta Ltd . . . . . . . . . . . . . . . . . . . . . . 55 Abacus Datagraphics Ltd . . . . . . . . . . . . . . . . . . 26 All Weather Shelters Inc . . . . . . . . . . . . . . . . . . . . 51 Allan R. Nelson Engineering (1997) Inc . . . . . . . . 48 Annugas Compression Consulting Ltd . . . . . . . . 59 Ansell Healthcare Incorporated . . . outside back cover Applus RTD Canada . . . . . . . . . . . . . . . . . . . . . . . 38 ASAP Heating & Well Servicing Corp . . . . . . . . . 22 Baker Hughes Canada Company . . . inside front cover Bear Slashing Inc . . . . . . . . . . . . . . . . . . . . . . . . . 62 Beaver Plastics Ltd . . . . . . . . . . . . . . . . . . . . . . . 52 Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . . 68 Bilton Welding and Manufacturing Ltd . . . . . . . . 60 Black Sivalls & Bryson (Canada) Ltd . . . . . . . . . . 42 Brother’s Specialized Coating Systems Ltd . . . . 42 Canadian Enviro-Tub Inc . . . . . . . . . . . . . . . . . . . 24 Compass Bending Ltd . . . . . . . . . . . . . . . . . . . . . 66 DaimlerChrysler Canada Inc . . . . . . . . . . . . . . . . . 5 Dean’s Pump Service Ltd . . . . . . . . . . . . . . . . . . 60 DFI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Diversified Glycol Services Inc . . . . . . . . . . . . . . 68 dmg events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Ecoquip Rentals & Sales Ltd . . . . . . . . . . . . . . . . 68 EITI Electrical Industry Training Institute . . . . . . 56

70

M AY 2011 • O I L & G A S I N Q U I R E R

Falvo Electrical Supply Ltd . . . . . . . . . . . . . . . . . 56 FDI Acoustics Inc . . . . . . . . . . . . . . . . . . . . . . . . . 64 Gas Liquids Engineering Ltd . . . . . . . . . . . . . . . . 40 Hotsy Water Blast Manufacturing LP . . . . . . . . . 23 Imperial Oil Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Iron Brothers Construction . . . . . . . . . . . . . . . . . 13 Jasper Tank . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 Joule Technical Sales Inc . . . . . . . . . . . . . . . . . . . 66 Kelro Pump & Mechanical Ltd . . . . . . . . . . . . . . . 66 LJ Welding & Machine . . . . . . . . . . . . . . . . . . . . . 62 Lockhart Oilfield Services Ltd . . . . . . . . . . . . . . . 29 London Business Conferences . . . . . . . . . . . . . . 39 LoTech Manufacturing Inc . . . . . . . . . . . . . . . . . . 64 MaXfield Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 MCI Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . 48 Meridian Mfg Group . . . . . . . . . . . . . . . . . . . . . . . 18 Meyers Norris Penny . . . . . . . . . . . . . . . . . . . . . . . 6 MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . 64 NAIT Corporate and International Training . . . . . 42 Netzsch Canada Inc. . . . . . . . . . . . . . . . . . . . . . . 66 Nexus Exhibits Ltd . . . . . . . . . . . . . . . . . . . . . . . . . 9 Northstar . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Northstar . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 Oil Sands and Heavy Oil Technologies . . . . . . . . . 30

Peace Region Petroleum Show . . . . . . . . . . . . . . 46 Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56 Petroleum Services Association of Canada . . . . 32 Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . . 40 Platinum Grover Int. Inc . . . . . . . . . . . . . . . . . . . . . 19 Propak Systems Ltd . . . . . . . . . . . . . . . . . . . . . . . 3 PTI Group Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 R & M Energy Systems . . . . . . . . . . . . . . . . . . . . 44 Shaw Cablesystems Ltd . . . . . . . . . . . . . . . . . . . . 41 Sprung Instant Structures . . . . . . . . . . . . . . . . . 54 Suncor Energy Inc . . . . . . . . . . . . . . . . . . . . . . . . 45 Telus World of Science . . . . . . . . . . . . . . . . . . . . 48 Titan Logix Corp . . . . . . . . . . . . . . . . . . . . . . . . . 53 Trans Peace Construction (1987) Ltd . . . . . . . . . . 53 TransGas Limited . . . . . . . . . . . . . . . . . . . . . . . . . 35 U F A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 Vertigo Theatre Society . . . . . . . . . . . . . . . . . . . 52 V.J. Pamensky Canada Inc . . . . . . . . . . . . . . . . . . . 12 Waydex Services LP . . . . . . . . . . . . . . . . . . . . . . 25 Weyburn Oil Show Board . . . . . . . inside back cover ZCL Composites Inc . . . . . . . . . . . . . . . . . . . . . . . 34

14th l a i n n Bie

Saskatchewan

Oil & Gas Show Exhibition Grounds Weyburn, SK

Chairman:

June 1&2 Weyburn Review Photo Greg Nikkel

John Kmita 2009 S.E. Oilman of the Year John Kmita Ltd.

2011

Nominations are now being accepted for the 2011 South East Saskatchewan Oilman of the Year

Dale Fox 2009 Please download form S.E. Oilman off our website: of the Year www.oilshow.ca Formerly of TS&M Supply Email or send to address below

Ron Carson, Carson Energy Services Ltd.

Vice Chairman:

Dennis Krainyk, Apache Canada Ltd.

Honourary Chairman: Hon. Bill Boyd, Minister of Industry and Resources

Show Highlights:

• Major industry seminars • Awards ceremony • 24-hour security • Keynote industry luncheon speaker • Golf tournament and barbecue • Excellent show facilities with improved outdoor space and storage • First class show management • Social events to broaden exposure • Complimentary loading and unloading • Latest products and services on display • Industry seminars • Free passes for attendees

Sponsored by…

WEYBURN OIL SHOW BOARD

P.O. Box 1450, Weyburn, Saskatchewan S4H 3J9 Tel: (306) 842.3232 Fax: (306) 842.3265 e-mail sk.oilshow@sasktel.net Web Site: www.oilshow.ca Platinum Sponsors:

Gold Sponsor: Bronze Sponsor:

Silver Sponsor:

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