Oil & Gas Inquirer July/August 2010

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How tHe oilpatcH recruits and trains a very different generation of young workers great gas plants

These five natural gas processing facilities demonstrate decades of top-flight technology

southern struggle With shallow gas drilling in decline, service operators focus on new oil plays in southern Alberta

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C630-JGJ-3

630

Caterpillar 3508 TALE Ariel JGJ-4 Throw

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C630-JGJ-3

630

Caterpillar 3508 TALE Ariel JGJ-4 Throw

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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

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Compressor

Caterpillar G3512 TALE Ariel JGH-4 Throw

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Table of Contents

Keeping readers regionally informed

F E A T U R E S

6

J U LY/A u g u s t 2 0 1 0 • O I L & G A S I N Q U I R E R

12

Green hands

18

Southern struggle

22

Great gas plants

29

Turf defender

by Mike Byfield How the oilpatch recruits and trains a very different generation of young workers

by Mike Byfield With shallow gas drilling in decline, service operators focus on new oil plays in southern Alberta

by Mike Byfield These five natural gas processing facilities demonstrate decades of top-flight technology

by Graham Chandler Bob Maslanko, president of the Electrical Contractors Association of Alberta, defends his trade against less-qualified rivals

Table of Contents

TCA provides engineered steel containment solutions for the Western Canadian Oil & Gas Industry R E G I O N A L

33

37

43

49

57

I N

10

N E W S

British Columbia

67

Northwestern Alberta

75

• Storm boasts higher netbacks thanks to liquids-rich gas production • $17.9M bid in Hudson’s Hope area highlights B.C. land sale

• Progress co-develops frac technology to unlock Nikanassin • North Peace to try radials and continuous steaming at Red Earth

77 79

81

Southern Alberta

• Demand for fracturing services outpaces overall drilling activity • Stoneham targets more customers and oilier activity

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International

• Undersea robots play a vital role in containing the Gulf oil spill • World Energy Congress draws industry leaders

I S S U E

Statistics at a Glance

85

On the Job • Ted Cutlan started as a service rig worker, then transformed his “gift of the gab” and a generous dollop of personal charm into a globe-trotting career in marketing with Pajak Engineering.

Tools of the Trade • The DuoVault from Enviro Vault Canada Ltd. meets the tougher tank standards proposed in Directive 055 from the Energy Resources Conservation Board.

• Completions data, spot gas prices, gas storage, drilling activity and more

83

• BP blowout delays plans for highly promising Beaufort oil prospects

• Georges Bank drilling moratorium gets extended until 2015 • Corridor advances drilling projects despite capital budget cut

Central Alberta

• ARC cautions that huge estimates of Cardium reserves are premature • Some juniors are more upbeat after Alberta’s royalty revisions

Northern Frontier

• Major oil and gas labour survey forecasts worker pinch by next year

Northeastern Alberta

• Oilsands reserves climb during 2009 despite lower investment • Logan International acquires Source Energy Tool Services for $25M

Saskatchewan

• Crescent Point’s drilling location inventory now stands above 5,000 • Legacy buys more land after Tilston oil discovery

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On the cover: (left to right ) Greg Hanson, rig manager; Zack Dupuis, lease hand; Derek Fischer, motorman.

www.thecontainmentanswer.com

Cover design and photo: Aaron Parker O I L & G A S I N Q U I R E R • J U LY/A u g u s t 2 0 1 0

7

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Editor’s Note Vol. 22 No. 7 President & ceo Bill Whitelaw | bwhitelaw@junewarren-nickles.com Publisher Agnes Zalewski | azalewski@junewarren-nickles.com Associate Publisher Chaz Osburn | cosburn@junewarren-nickles.com Editorial director Stephen Marsters | smarsters@junewarren-nickles.com EDITORIAL Editor

Mike Byfield | mbyfield@junewarren-nickles.com

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Postage Paid in Edmonton, Alberta, Canada. If undeliverable, return to: Circulation Department, 800 - 12 Concorde Place, Toronto, ON M3C 4J2 Made in Canada The opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.

Oil & Gas Inquirer and a sister publication , New Technology Magazine, are launching a new annual award, Technology Stars. Anyone may nominate any oil and gas product or service that’s considered leading-edge for its application. To qualify for entry, a company must operate in Canada and its product or service should be deployed here.

Through this program, JuneWarren-Nickle’s Energy Group (JWN) will honour superior innovation and technical progress. We’re not prophets, of course. Only years of experience can show which new equipment and services will prove the most valuable to energy producers and consumers. However, our judges can and will select Technology Stars that are outstanding, even brilliant achievements.

Canada is blessed with an enormous talent pool in the petroleum industry. Our judging panel will include well-qualified veterans from producers, service operators, and consulting firms. Over time, the JWN Technology Star will become an internationally respected award, useful for marketing at home and overseas.

For more details about this program, check out www.newtechnologystars.com, and take a look at the notice on page 71 of this issue.

Our cover story this month focuses on green hands, whose training and retention represent the future of any industry. The oilpatch is now recruiting new hires among youngsters raised on a “child-centred” philosophy — nobody ever fails a year of school and everyone who participates in the contest wins a prize. That’s not necessarily the best preparation for overcoming hard physical challenges as a young adult.

Human resources professionals like Trinidad Drilling’s April Williams work with rig managers and other field specialists. Together, they create selection and instruction programs that transform inexperienced city kids into competent field professionals.

Overall, the personnel process probably absorbs more time than before, but good results justify the effort. Accident rates are lower and rigs make hole faster than ever.

There wasn’t much joy in writing this month’s article on southern Alberta, whose traditional shallow gas activity shows no sign of recovery. Bill Gwozd, a senior VP at Ziff Energy Group, is an analyst who’s earned respect over many years. He doubts the shallow gas sector will ever revive beyond a fraction of its peak drilling levels.

Fortunately, new technology is generating activity in tight oil and gas plays across western Canada and around the world. You’ve heard it many times, but it’s very true: our future depends on technical innovation. And that’s what JWN’s Technology Stars program intends to help advance.

N E X T

I S S U E

Upcoming edition:

If you know an admirable person to profile in

The next issue of Oil & Gas Inquirer will survey

On The Job — he or she may be a veteran or

in situ projects and prospects in northeastern

apprentice, field or shop, wise or a little crazy —

Alberta’s bitumen belt, plus we’ll take a look

please give me a call at (780) 944-9333, or

at modern camps. Also, keep an eye out for

email mbyfield@junewarren-nickles.com.

the Lloydminster Heavy Oil Show Guide. If

In fact, feel free to sound off about any

you’re attending the world’s premier heavy

concern at all — that’s a personal invitation.

oil showcase, which runs Sept. 15–16, visit the JuneWarren-Nickle’s Energy Group booth.

O I L & G A S I N Q U I R E R • J U L Y / A U G U ST 2 0 1 0

9

Stats

FAST NUMBERS

27,000

AT A GLANCE

US$

wells

The number of wells that have been abandoned in the Gulf of Mexico, including 3,500 “temporarily” abandoned. The Associated Press says no one monitors these wells.

520

The value of crude bought one night in June 2009 by a drunken Steve Perkins, a trader with London’s PVM Oil Futures Ltd. Prices rose by about $1.50 per barrel, to an eight-month peak.

Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin

MONTH

OIL

GAS

OTHER

TOTAL

Jul 2009 Aug 2009 Sept 2009

79 101 146

178 212 155

77 80 78

Oct 2009 Nov 2009 Dec 2009

132 169 121

160 212 127

Jan 2010 Feb 2010 Mar 2010

253 144 264

Apr 2010 May 2010 Jun 2010

198 400 126

MONTH

OIL

GAS

DRY

SERVICE

TOTAL

334 393 379

July 2009 Aug 2009 Sept 2009

79 250 146

31 267 155

6 36 45

3 37 9

119 590 355

77 116 35

369 497 283

Oct 2009 Nov 2009 Dec 2009

331 382 283

196 244 138

32 68 34

12 10 13

571 704 468

324 308 579

62 114 198

639 566 1,041

Jan 2010 Feb 2010 Mar 2010

429 147 548

343 143 681

55 20 109

13 5 20

840 315 1,358

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

Wells Drilled In British Columbia

Saskatchewan Completions

Source: B.C. Oil and Gas Commission

Source: Daily Oil Bulletin

MONTH

M

WELLS D R I L L E D

CUMULATIVE *

MONTH

OIL

GAS

OTHER

TOTAL

Jul 2009 Aug 2009 Sept 2009

34 36 38

429 465 503

Jul 2009 Aug 2009 Sept 2009

124 116 194

27 3 7

1 6 3

152 125 204

Oct 2009 Nov 2009 Dec 2009

29 39 45

532 571 616

Oct 2009 Nov 2009 Dec 2009

157 171 139

5 11 11

7 10 9

169 192 159

Jan 2010 Feb 2010 Mar 2010

65 99 98

65 164 262

Jan 2010 Feb 2010 Mar 2010

153 169 223

18 58 32

6 4 8

177 231 263

Apr 2010 May 2010 Jun 2010

56 54 28

318 372 400

Apr 2010 May 2010 Jun 2010

92 86 149

10 7 7

3 3 11

105 96 167

*From year to date

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J U LY/A u g u s t 2 0 1 0 • O I L & G A S I N Q U I R E R

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GAS STOR AGE

Source: Natural Gas Exchange Inc.

Source: U.S. Energy Information Administration

in the United States

3.00

4.0

2.75 2.50

3.5

3.0

2.76 Tcf Year ago: 2.87 Tcf 5-year avg: 2.57 Tcf

2.25

$3.37/GJ Total vol.: 2,073 TJ

2.00 1.75

Jun 11

Cdn$/GJ

Jun 18

Jun 25

Jul 2

Jul 9

Jun 5

Tcf

Source: Natural Gas Exchange Inc.

Jun 12

Jun 19

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada July 13, 2010 Source: Rig Locator

Alberta June 2010 Source: Daily Oil Bulletin

ACTIVE

DOWN

TOTAL

ACTIVE (Per cent of total)

Western Canada Alberta

231

313

544

42%

British Columbia

54

53

107

50%

Manitoba

10

5

15

67%

Saskatchewan

85

51

136

63%

380

422

802

47%

0

1

1

0%

WC Totals Northwest Territories

Jun 26

OIL WELLS

Alberta

GAS WELLS

Jun 10

Jun 09

Jun 10

Jun 09

Northwestern Alberta

31

0

79

26

Northeastern Alberta

23

10

0

0

Central Alberta

59

24

17

21

Southern Alberta

13

2

21

96

126

36

117

143

TOTAL

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada July 13, 2010 Source: Rig Locator

Alberta June 2010 Source: Daily Oil Bulletin

ACTIVE

DOWN

TOTAL

ACTIVE

Western Canada Alberta

334

669

50%

British Columbia

14

20

34

41%

Manitoba

12

0

12

100%

Saskatchewan

123

68

191

64%

WC Totals

484

422

906

53%

1

1

2

50%

Quebec

COALBED METHANE

Alberta 335

Jul 3

Source: U.S. Energy Information Administration

BITUMEN WELLS

Jun 10

Jun 09

Jun 10

Jun 09

Northwestern Alberta

1

1

2

0

Northeastern Alberta

0

0

23

10

Central Alberta

3

14

9

7

Southern Alberta

2

33

0

0

TOTAL

6

48

34

17

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O I L & G A S I N Q U I R E R • J U LY/A u g u s t 2 0 1 0

11

Green hands How the oilpatch recruits and trains a very different generation of young workers

P

hysical labour, lots of mud and grease, shift work frequently away from home, long drives to and from some worksites, the potential for serious injury, an industry whose activity levels cycle up and down with unusual vigour — it’s easy to see why recruiting and retaining high-calibre field staff is an ongoing struggle in the oil and gas service sector.

“Finding the right individuals has been crucial to our company’s success, but it seems to be harder than ever these days,” says Mike Kallal, CEO of Mustang Well Services Ltd. “When it comes to green hands, only 1 in 10 will last more than a month or two.”

12

J U LY/A u g u s t 2 0 1 0 • O I L & G A S I N Q U I R E R

Mustang operates a fleet of six freestanding service rigs from Camrose, southeast of Edmonton. Its fabrication shop enables the four-year-old firm to maintain and manufacture its own rigs. Despite grim business conditions in the industry overall, Mustang added three new rigs during 2009. Today the busy company has had to turn down some jobs for lack of capacity. Its teams are well-trained in working with the large-diameter, long-reach casing strings required for horizontal wells in the Cardium, Viking and Bakken formations.

Kallal, who graduated from NAIT’s pet roleum eng ineer ing tec h nolog y

by Mike Byfield

program in 2002, isn’t particularly surprised at the low success rate among new hires. “The type of people who fill new entry positions in our industry has changed. We can no longer rely on farm-raised youngsters who are accustomed to working with machinery,” the Mustang CEO says. In large part, that’s because the number of farms in western Canada has shrunk drastically over the past generation. Now most green hands are city kids or townies; for most of them, the oilpatch represents a completely unfamiliar experience.

Some newcomers are deeply shocked at the pain inflicted by manual labour on

Feature

their arms, shoulders and legs. “When they feel those muscles really aching, some of them become convinced that they’re actually injured,” Kallal says. “That’s understandable — it does hurt pretty bad.

Of course, it’s just normal strain, and the rig manager will tell the new hand that the pain will clear up pretty quick as he gets stronger. But if the employee insists on seeing a doctor, we’ll take him, if only to prevent him from getting into a panic.

Working on a rig is not always an easy adjustment for someone who’s never done anything more strenuous in his life than play video games.”

The petroleum industry is not alone in its difficulties with green hands, particularly with respect to turnover. A major airline operating out of Edmonton retained just 2 of 20 applicants for

handling baggage, a job that’s less physically taxing than roughnecking. According to one member of that group intake (who asked that his name remain confidential), six failed the initial drug test. Eight more employees did not survive their probationary period due to tardiness or physical competence, and an additional four quit within the first year of employment.

Zachary Dupuis personifies the type of green hand who does succeed in the oilpatch. His father Darcy roughnecked before specializing in tank farm rentals.

The 19-year-old son grew up and graduated from high school in Devon, Alta.

He also played minor hockey (Leduc Oil Kings), gaining experience with teamwork and physical stress. At 16, Zack Dupuis had a summer job putting together food pallets for a camp catering outfit. He’s now

working as a lease hand for Patterson-UTI Drilling Company.

H i s opp or t u n it y c a me whe n a Patterson lease hand decided to go back to school. “Randy Therris, my girlfriend’s dad, is a derrickman and he asked me if I’d like to take a shot at the job,” says Dupuis. On Feb. 9, the brawny teen began his first shift at Patterson 17, a triple operating in the foothills near Hinton. “I’d never been on a rig before, although I drove to one once with my dad. I couldn’t believe the size of a triple; it was scary at first,” he recalls.

For his first shift, the new hire was toured round the rig and shown what he’d be doing as a lease hand. “My job includes keeping the shacks clean, including the sub, boiler and pump rooms,” Dupuis says.

“I learned basic rules, like not running O I L & G A S I N Q U I R E R • J U LY/A u g u s t 2 0 1 0

13

Photo: Aaron Parker

The crew of Patterson Rig 17 (from left): Kyle Myers (driller), Sheldon Crowdis (Tourmaline consultant), Zack Dupuis (lease hand), Greg Hanson (rig manager), Marshall Gray (derrickman), Justin Hockley (motorman).

Feature

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J U LY/A u g u s t 2 0 1 0 • O I L & G A S I N Q U I R E R

down stairs unless it’s an emergency. They also had me stand by the driller for a few hours so I could learn how the rig operates.” More orientation followed on the second day, such as learning how to mop properly. On day three, the green hand put in his first regular shift.

The new employee got his share of teasing by the five other members of his shift. When handling the power tongs for the first time, Dupuis used two hands and proceeded cautiously. “There’s a real learning curve to throwing the tongs,” he says. The rest of the crew, prodding him to move more aggressively, called him a big pussy and asked if he was a girl. A skilled rig hand can slap the sturdy 400-pound steel tool onto the drill pipe with one hand.

W hile handling the tongs, when Dupuis bent over to pick up the slips, another roughneck quietly dipped a Styrofoam cup in sticky thread sealant and surreptitiously glued it onto his victim’s helmet. Unaware, the greenhorn kept working while foam earplugs were stuck on, one by one, around the cup. “I didn’t realize what they were up to until the cup finally fell off. By then, they had about 20 earplugs on my helmet,” he admits.

Looking like a dork didn’t bother him much, though. “It wasn’t mean, just guys having fun like we did at hockey. Actually, I was more uncomfortable when a replacement toolpush asked me if I’d had any exciting sexual experiences. I was standing by Randy [his girlfriend’s father] at the time,” Dupuis recalls with a smile. The teasing never became physically intimidating; Patterson absolutely prohibits any form of violence on its rigs.

Within a few days, the greenhorn felt comfortable moving around the triple rig. “I was more nervous about bears and cougars than the equipment,” he says.

One night he switched on a pickup truck’s headlights and instantly saw the light reflecting off the eyes of a cougar, a predator that attacks humans on rare occasions. Hinton is also grizzly territory, and taking out garbage on a pitch-black night can stimulate the imagination. “I asked if we had any bear mace, and the guys just laughed,” Dupuis says.

When cleaning the shacks alone during a 12-hour night shift, the novice occasionally found himself getting lonely. “I’d never been away from home for so long,” Dupuis comments. Fortunately, the physical labour hasn’t been a big issue for him. “We have a front-end loader for lifting heavy loads onto

Feature the rig instead of carrying it up the stairs.

The hardest thing I’ve done so far is move casing. We’d just finished a hole and I spent four hours rolling heavy pipe to the V-door with my feet. That night, it was snowing and slippery. I definitely earned my $23.50 an hour on that shift.”

Drawing strong applicants like Zack Dupuis used to be fairly straightforward.

“Once upon a time, they came to us quite readily. Now we have to actively recruit,” says April Williams, the Nisku-based personnel manager for Trinidad Drilling Ltd. When she joined the company seven years ago, its Canadian fleet was 12 rigs.

The present fleet stands at well over 100 drilling rigs, including 53 in Canada. “At the beginning, we were just hiring every day to keep up with the growth,” Williams says. “Over time, though, we’ve created an application and training process which significantly improves our retention rate.”

Trinidad advertises information sessions in communities across western Canada, primarily targeting males 18 to 30 years old. Individuals in their 30s are not uncommon. Most will have a high school education, and possibly more.

“Some applicants have started a trade apprenticeship but find that they want to try another line of work,” Williams says.

“We’re competing with construction, the oilsands and other industries for this type of worker. The parents of these young people are attracted by the idea that rig technician is now a provincially administered trade.”

At Trinidad’s information sessions, potential applicants learn about the company, what drilling rig workers do, the petroleum industry generally and career opportunities that are open to experienced oil and gas hands. Veteran rig hands often move into specialized technologies like wireline or directional drilling, into sales and marketing, or they can be promoted within the drilling contracting world itself. Trinidad’s president and CEO Lyle Whitmarsh got his own start as a rig hand.

Interested applicants are put through a lengthy interview process that educates them further about rig work — locations, rotations, personal protective equipment and more. “We want them to understand as much as possible what the job entails before we hire them,” Williams says. “Some of these kids have never been outside the city except on vacation. They can barely imagine working where their personal cellphone

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Feature Photo: Aaron Parker

may not function.” Interviews may occur at the Trinidad office or in the applicants’ hometowns.

The next step is pre-employment medical and physical examinations, plus an eight-section classroom orientation about Trinidad’s own practices. Brand new workers get instructions about safety practices and personal protective equipment, drug and alcohol policies, violence and more.

Applicants are tested to make sure they understood the class material. Meanwhile, a physiotherapist conducts a full rundown of tests that includes push, pull and carry exercises. Trinidad is looking for physical and mechanical aptitude.

Finally comes a four-day orientation program at a rig, normally led by a driller or senior hand. “We like to see one-onone mentoring get started at this stage,” Williams says. Once at the rig, the new worker begins to get paid. He (or occasionally she) must have his own boots and gloves; the company supplies coveralls, hard hat, safety glasses and hearing protection. This on-site instruction includes a detailed tour of the rig and all of its components, a thorough outline of the employee’s duties, a look at the specific rig’s rules (e.g. some rig managers absolutely ban dirty boots in the doghouse while others permit them) and a review on the final day by the rig manager.

Once in harness, the new hire is expected to complete an On The Job Training and Competency program that

The crew of Patterson 17 gets updated at a shift-change meeting on a drill site near Edson, Alta.

discusses important procedures like hazard identification, how to use a grinder and so on. There’s a heavy safety emphasis, responding to the fact that green hands are far more prone to accidents than veterans. A senior employee signs that the training material has been taught and the novice receives a certificate.

“There’s a definite failure rate at every stage,” Williams says. “Typically, 60 per cent of new employees who get through the application process will be still be working for us after 90 days. Where a personality conflict clearly occurs, we may arrange a transfer between rigs.

When anyone leaves, we require a report from his supervisor as to what happened,

and we try to get input from the employee as well.”

J oh n B r ow n , e xe c ut i v e V P of Patterson-UTI, started drilling at the same entry level as Zack Dupuis. “As a boy growing up in a farming community, I loaded hay bales, I bicycled everywhere — once I stuck a pitchfork in my foot,” Brown comments. “Nowadays, our new hires have plenty of natural talent but the majority have not had much opportunity to develop their mechanical and manual skills. As a company, we provide the necessary instruction and training, especially with respect to safety, and it works out fine.

Today’s rig crews are just as capable as they’ve ever been.”

Good advice for entry-level oilfield workers As a young man, Marv Clifton switched from teaching at a public school to roughnecking, mainly so he could earn enough money to support his family. Clifton is now president and CEO of Technicoil Corporation, which operates specialized coiled tubing units for fracturing and drilling operations. This former teacher offers the following counsel to young people just getting started in the energy services sector: Focus more on individuals than organizations. For good reason, rig hands are usually more loyal to their toolpush and/ or driller than to a company. If you’re working for men with the technical and managerial expertise to run an efficient, clean operation, stick with them. Always work hard yourself.

Expect to be yelled at if you’re on a rig. The noise level requires loud voices, and shouting gets to be a habit. However the yelling (and swearing) should aim at instructing you and keeping you safe,

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not just inflicting abuse. Effective teaching indicates your supervisors are professionals and will help your career move forward.

A hard-drinking young man — as long as he does his own job properly — can generally work well with a crew that doesn’t drink heavily. (Often, these are older men with families.)

However, a hard-drinking crew frequently rejects a newcomer who doesn’t constantly join them in the bar. If you’re a light drinker or abstainer, tell your personnel manager and get on a compatible team as soon as possible.

The pride of the oilpatch is getting the job done right despite all difficulties. A good field crew takes a “can-do” approach whether it’s 40 degrees below or 40 degrees above zero. Get on a high-quality team, which sometimes means looking for a transfer. Then absorb that “can-do” attitude into your own bloodstream.

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Feature

Southern struggle

With shallow gas drilling in decline, service operators focus on new oil plays in southern Alberta

by Mike Byfield

For two years, Medicine Hat, Alta., has been slammed by the oilfield activity downturn, suffering proportionately as much or more than any other field centre in western Canada. Worse, the growing flow of natural gas from non-conventional shale reservoirs across North America continues to depress drilling in the conventional gas fields of southern Alberta.

In response, workers and equipment are migrating elsewhere. Businesses have folded, and older rigs are being cannibalized. On a positive note, producers are searching for oil, in particular near Princess and Del Bonita.

In 2008, CerPro Energy Services Inc. was listed by Profit Magazine among Canada’s Hottest 50 emerging growth

companies. The payroll stood at about 300. A year later, the Redcliff-based oilfield and industrial construction company went into receivership. In early 2010, Dunmore-headquar tered Advantage Oilfield Group also went belly up, forfeiting 250 jobs. “We’ve also lost a lot of smaller oil and gas service firms through bankruptcies and consolidation,” says Brad Penman, president of the Medicine Hat Oilmen’s Association.

Southeastern Alberta and neighbouring southwestern Saskatchewan are shallow gas country. Both regions were slammed in 2009, when Canada-wide gas drilling plunged by 70 per cent over 2008. That decline has continued into 2010. During the first five months of this

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Photo: Joey Podlubny

Shallow gas plays compete with large shale gas prospects whose economics are often more attractive.

year, Alberta licensed 1,476 natural gas and coalbed methane (CBM) wells versus 1,832 for the same period in 2009. In Saskatchewan, the number of natural gas wells drilled between January and May totalled 73 in 2010, according to the Daily Oil Bulletin, down from 178 in 2009.

Kevin Neveu, president and CEO of Precision Drilling Trust, says this year is shaping up better than last for the western Canadian service sector as a whole. “Obviously, we think oil well servicing will be stronger than it was in 2009 [due to good crude prices] — probably stronger than we were thinking earlier this year,” he comments. Heavy oil in the northeast and Cardium light oil prospects in west-central Alberta

Feature are exceeding earlier drilling activity estimates. In sharp contrast, the Precision CEO says, the shallow gas sector remains particularly slow.

In response, drilling contractors are reducing their shallow fleets. Savanna Energy Service Corp., for example, plans to convert 10 of its hybrid drilling rigs to top-drive singles over the next 18 to 24 months. “For 40 per cent of the cost of a new build, we can retrofit a hybrid and turn it into a 3,000- to 3,600-metre rig,” says Ken Mullen, its president and CEO. Savanna plans to put the converted singles to work in western Canada’s Viking oil prospects along with the Marcellus shale gas play in the eastern United States.

Later this year, Savanna will export two hybrid drilling rigs to Australia, along with two workover rigs. They’ll be deployed in a CBM to liquefied natural gas project in Queensland. That $220-million, five-year deal was signed last year. The Calgary-based contractor hopes to broaden its foreign operations to Indonesia, possibly India, and other countries where shallow wells are drilled in rapid succession. Its hybrid rig platform is being shrunk to adapt to tighter roads and tighter locations.

When the downturn began in 2008, the Alberta government raised its royalty take in the teeth of a sliding market.

Recently, the province revised its royalty structure again, this time acting more helpfully toward producers. “Royalties in Alberta can’t get much lower than they are,” says Gary Leach, president of the Small Explorers and Producers Association of Canada (SEPAC). However, he adds, conventional gas activity will not recover until gas prices increase significantly. “If you don’t have a lot of options other than gas, [the situation] is very, very challenging.”

Larger producers are redirecting their efforts toward shale gas plays that have big growth potential. For example, Houston-based EOG Resources, Inc. recently announced that it will sell its shallow gas properties in southeastern Alberta and southwestern Saskatchewan, whose production stands at about 150 million cubic feet per day. EOG hopes to raise US$1 billion to US$1.5 billion for possible investment in Marcellus and Horn River shale lands.

The Medicine Hat Oilmen’s Association has about 450 members. W h i le

southeastern Alberta is going through grim times, Penman comments that “it’s not as bad as most people think.” On a scale of 1 to 10, he’d peg the severity of the ongoing activity downturn at 6. His own firm, Guardian Chemicals Inc., is busy in the area thanks to corrosion and well optimization programs by gas producers.

“Some of us can still work locally,” says the association president. “Others have found jobs in the Bakken [tight oil play of southeastern Saskatchewan]. They work around Estevan while their families continue to live here.”

Given today’s commodity prices, the surest cure for the shallow gas blues is an excellent oil prospect. Several ongoing crude developments have promise for service firms based along the Swift Current– Medicine Hat–Brooks axis: • At Suffield, Cenovus Energy Inc. is pursuing 100 million barrels of heavy oil.

“If you don’t have a lot of options other than gas, [the situation] is very, very challenging.”

— Gary Leach, President, SEPAC

• C rescent Point Energy Corp. plans to spend more than $110 million this year targeting the Lower Shaunavon tight oil-bearing formation in southwestern Saskatchewan. (See article on Page 67.)

• In early June, 140 horizontal wells were licensed for drilling in the Dodsland Viking formation. The target is light oil.

Operators included Penn West Energy Trust, Husky Energy Inc., Baytex Energy Trust, Harvest Energy Trust, Petrobank Energy and Resources Ltd., WestFire Energy Ltd., and Crescent Point.

• A nother play focuses on the Pekisko formation at Princess. “We’ve seen some fairly compelling results from Crew [Energy Inc.] and now others are getting in,” says Chris Theal, an analyst with Macquarie Capital Markets Canada.

Hugh Ross, president of Novus Energy Inc., is intimately familiar with the Dodsland Viking and Pekisko prospects.

In 2000, Ross founded Gentry Resources Ltd. with seed financing of $2.5 million. In 2008, Crew absorbed Gentry in a share deal worth $300 million. Ross then launched Novus, whose 70 net sections of Dodsland Viking lands include 230 potential drilling locations for horizontal wells.

Ross says the Dodsland Viking formation was originally estimated to have two billion barrels of original oil in place. The crude is sweet and light, about 36 degrees API. The lower Viking holds an estimated four billion more barrels, potentially accessible through modern horizontal drilling and multi-stage frac completions. Thanks to thousands of vertical wells drilled as long ago as the 1950s, the reservoir is welldelineated and geologically low-risk.

Novus has drilled 16 horizontal wells into the Viking. Its average cost to drill and case a 700-metre lateral using a four-anda-half inch monobore is about $400,000 to $450,000. Perforations are done intermittently and are based on the gas response recorded during drilling. Intervals are isolated using a coiled tubing unit and packers. The number of stages per well varies from 11 to 15, using 13 to 20 tons of sand per stage. The frac fluid consists of either slick water, hydrocarbon or a mixture of native crude oil.

Novus reports that its full cost ranges from $500,000 to $750,000 per well, with a payback period of less than a year (in part due to Saskatchewan’s generous royalty incentives for horizontal wells). The first multi-frac horizontal drilling in the Dodsland play dates back to late 2007, with initial daily production of 70–75 barrels declining to 30–35 barrels over two years.

Novus plans to drill at least 35 Viking oil wells in 2010.

Like the Novus/Gentry team, Crew Energy has specialized in acquiring largescale unconventional reserves that can be exploited with modern drilling and completions technology. Dale Shwed, its president and CEO, and John Leach, Crew’s senior VP and CFO, previously were co-founders of Baytex Energy Ltd. There they developed the Seal heavy oil resource play in northern Alberta. When Baytex converted to a trust in 2003, Shwed and Leach moved on to Crew, a spinout junior with initial output of 1,500 barrels of oil equivalent (boe) per day (all from shallow gas wells with steep decline curves).

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Photo: Joey Podlubny

Feature

Ziff’s Bill Gwozd says service firms must grind down costs and forge long-term customer alliances.

Crew’s daily production averaged 15,000 boe during the first quarter of 2010, including liquids-rich tight gas from northeastern British Columbia. Oil production at Princess has surged from 2,200 boe per day to 5,200 boe over the past two years. Pekisko crude is medium weight (26 degrees API), more valuable than heavy oil. During the quarter, the company drilled 14 oil wells at Princess — seven single-lateral horizontals, three dual-lateral horizontals and four vertical wells.

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The Pekisko reservoir is a limestone carbonate, a type of formation that hasn’t drawn much attention from drillers for many years. Crew’s ongoing experimentation at Princess is paying off. Its best horizontal well in the first quarter had initial production of 755 boe per day. Over two years, operating costs at Princess have fallen from $16.50 per barrel to $11. “Our wells are inexpensive — they’re open-hole completions with a pumpjack,” Leach says.

This summer, the company plans to drill its first Pekisko multi-frac horizontal

along with a few verticals. Just like shallow gas, the key to large resource plays is repeatability. Crew has about 500 net sections of Pekisko land at Princess, and the company has identified 610 horizontal well paths. “That figure will increase.

All of our well location inventory lies within a 102-section block. We need more time to assess the remaining 80 per cent of our current acreage in the play,” Leach predicts.

Shallow gas, in comparison to oil, has little or no visible upside in the province. Ziff Energy Group says about 7,500 gas wells were drilled across southern Alberta in 2003. “In 2009, the total may have gotten just past 1,500, and we expect the annual average to remain under 2,000 wells through to 2020,” says Bill Gwozd, Ziff VP of gas services. “The average gas well in southern Alberta currently produces 0.1 million cubic feet per day, and that figure will decline gradually to 0.06 [million],” the veteran energy analyst says.

His advice to service providers: “Keep grinding your costs down and make stable alliances with producers. You’re in a real tough battle, there’s no escaping that fact.”

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Feature

Great

gas plants These five natural gas processing facilities demonstrate decades of top-flight technology

C

anada is a natural gas heavyweight. According to the BP Statistical Review of World Energy, this country produced 5.7 trillion cubic feet last year. Canada ranked as the world’s third-largest producer, with 5.4 per cent of the global total in 2009. (The United States was first with 20.1 per cent, Russia second at 17.6 per cent and Norway fourth with 3.5 per cent.) The Canadian Association of Petroleum Producers reported that 76 per cent of Canada’s gas output in 2008 came from Alberta, 17 per cent from British Columbia, 4 per cent from Saskatchewan, 2.3 per cent from the Sable energy project offshore Nova Scotia and minor volumes from the rest of Canada.

Purifying and pipelining — the midstream sector of the gas industry — is a major economic driver. Canadians have long been respected internationally for their natural gas processing skills, particularly with respect to poisonous hydrogen sulphide (H2S) and operating in extreme cold. Engineers here have made enormous strides on critical issues like reduced emissions and improved energy efficiency.

First, for readers who are not familiar at all with the midstream, some basic explanation is in order. Raw gas emerging from underground formations must be processed to nearly pure methane before it can be shipped via trunk pipelines across the continent. Gas emerging from wells is fed via gathering pipelines to a facility that removes free water and condensate, a valuable refinery feedstock. The semiraw gas gets piped to a processing plant, or fractionator.

Processing facilities can be configured in many ways depending on the technology in use. Any acid gases present (H2S and CO2) are removed first, typically using an amine process or polymeric membranes. (Where appropriate, the segregated acid gases will be routed to a sulphur recovery unit.) Next water vapour will be removed, again

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by Mike Byfield

through several possible technologies, followed by mercury, nitrogen and helium if they’re present. Common treatment technologies are absorption (glycol dehydration), pressure swing adsorption or membranes. In the following stage, natural gas liquids (NGLs) can be separated through refrigeration, dehydration or other alternatives. The NGL stream may be fed through a fractionation train that includes three distillation towers: a deethanizer, a depropanizer and a debutanizer.

Gas processing has been a growth business. In 2007, Alberta had 889 gas plants, compared to more than 1,000 now listed by the province’s Energy Resources Conservation Board (ERCB).

Three years ago, British Columbia was home to 34 gas plants, the majority of them very large. Last February, the BC Oil & Gas Commission said it was juggling its staff to cope with five new gas plants, three more plants under construction and four in the application process. The provincial regulator also anticipated applications for two additional new plants along with two expansions.

The gas plants range from modest to momentous. Encana Corp., for example, estimates the first phase of the proposed Cabin Gas Project in northeastern British Columbia will cost $400 million and will have a capacity of 400 million cubic feet per day. The producer consortium behind this development near Fort Nelson hopes to double that capacity if shale gas development proceeds well in the Horn River Basin. The Cabin project appears poised to become another memorable step for an industry that’s already rich in achievements.

Oil & Gas Inquirer has selected five notable gas plants that illustrate the sector’s breadth and history in this country (listed in no particular order).

Feature

1

Photo: Shell Canada Limited

Shell Jumping Pound Gas Complex In 1944, Shell made a wet, sulphur-rich gas discovery about 33 kilometres west of Calgary. The Jumping Pound strike was Canada’s first natural gas field found largely through seismic mapping, its first gas field to be produced on a unitized basis, and the first sulphur-from-gas production facility anywhere.

Due to a lack of export pipeline capacity from Alberta, the Jumping Pound processing facility did not come on stream until 1951.

Drawing on California experience, Shell and its engineering firm, Fluor Corp. of Los Angeles, left the processing facilities exposed to open air. That winter, engines froze, and gas and water crystallized as hydrates. Due to weather complications, the operation barely functioned. By the next winter, equipment had been sheltered in buildings, the sulphur plant began producing and Shell engineers started to define standard procedures for dealing with hazardous materials.

The initial discovery totalled about one trillion cubic feet, and more finds have since been added in the same area. Today, the Jumping Pound complex employs about 100 people who process 272 million cubic feet of gas along with nearly 7,000 barrels of liquids and 590 tonnes of sulphur per day. Jumping Pound has been called Canada’s sour gas laboratory because its operators learned lessons that have been adopted around the world.

2

The Empress Straddle Plant has enormous capacity, six billion cubic feet per day. The facility, built in 1971, rises from a patch of bald prairie in southeastern Alberta near the Saskatchewan border. The original owners were Dome Petroleum and a subsidiary of TransCanada PipeLines. Dome later went bankrupt. Today, the straddle plant belongs to the multinational BP, which calls Empress “one of the largest gas processing facilities in North America.”

Straddle plants form a key component in Alberta’s petrochemical manufacturing industry, the largest in Canada. These large “deep cut” plants strip ethane from the natural gas that flows through the province’s trunk pipeline grid. Ethane is the primary building block in ethylene, the plastic on which the provincial petrochemical industry is based. BP Empress sends its ethane to petrochemical operators in Fort Saskatchewan and Joffre (near Red Deer, Alta.).

BP Empress consists of four interconnected facilities, including capacity for 75,000 barrels per day of ethane and 46,000 barrels of natural gas liquids. The complex includes 11 re-compressors — 3 driven by gas turbine engines and the remaining by electric motors as powerful as 54,000 horsepower. The Empress plant is one of the largest single industrial consumers of electric power in Alberta.

Before the big straddle plants were built, the ethane was harvested in the United States and Ontario. Through regulatory intervention, the Alberta government successfully fostered its own industry.

Ethane increased markedly in value, prompting producers to begin

Photo: BP Canada Energy Company

BP Empress Straddle Plant

stripping the petrochemical feedstock at the wellhead. Quarrelling then erupted between producers determined to control their own ethane on the one hand, and straddle operators and petrochemical manufacturers on the other. The ensuing regulatory hearing was arguably the fiercest fight ever to internally divide western Canada’s petroleum sector. Although the ERCB came up with a workable compromise, the debate still echoes to this day.

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Feature

3

Spectra Energy’s Fort Nelson Gas Processing Plant

Photo: Spectra Energy Corp.

In Alberta, most gas processing is handled near the wellhead and producers have historically striven to control their own processing operations. British Columbia, from the inception of its gas industry, adopted another strategy. The raw fuel is typically collected across a wide region and processed in centralized facilities. For that reason, B.C. gas plants are often large-scale.

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The Fort Nelson Gas Processing Plant is North America’s largest sour gas processing facility as well as the continent’s most northerly major gas processing facility. Originally launched in 1964, several expansions have boosted its processing capacity to about one billion cubic feet per day. Natural gas is gathered through approximately 1,000 kilometres of pipeline facilities that extend from the Northwest Territories to northeastern British Columbia to northwestern Alberta.

The operation, located south of Fort Nelson, is entirely selfsufficient in terms of water, power and other utilities. Its principal components include seven gas processing trains, three sulphur trains, three main electricity generators, one emergency generator and three main power boilers. Spectra Energy, the plant operator, is now evaluating a carbon capture project that would be the world’s largest if the company proceeds with construction.

Spectra recently received approval from the National Energy Board to proceed with construction of its Fort Nelson North Processing Facility, with an inlet capacity of 250 million cubic feet per day. The plant will be built on a site adjacent to an existing compressor site at Cabin Lake. (The producer consortium led by Encana is planning another processing facility at Cabin Lake.) Spectra’s new plant is scheduled to be in service by the spring of 2012.

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Feature

Photo: Shell Canada Ltd.

4

Shell Caroline Complex In 1986, Shell Canada discovered two trillion cubic feet of extremely sour gas (37 per cent H 2 S) near Caroline, about 170 kilometres northwest of Calgary. The geological reef formation — more than 30 kilometres long and several kilometres wide — sits in an area that had already been heavily explored.

Even so, Shell’s team of brilliant geological and geophysical analysis led to western Canada’s largest hydrocarbon find in at least two decades.

Although slightly less emotional than the industry-wide ethane arguments, Shell and Husky Oil fought hard over the Caroline development. Husky wanted to process the Caroline gas at its already-built Ram River plant and sought an ERCB order to that effect, alleging a reduced environmental impact.

Shell eventually won the fight and proceeded to construct a $1-billion facility.

Opened in 1993, the Caroline facility processes 250 million cubic feet of gas daily (its potential capacity is 380 million cubic feet), along with 3,500 tonnes of sulphur and nearly 16,000 barrels of condensate and NGLs. The complex includes the gas field, 14 wells, 3 compressor stations, a major gas processing plant and a sulphur-forming and storage facility.

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Feature

5

Sable Offshore Energy Project Its sponsors proudly claim the Sable Offshore Energy Project (SOEP) as the largest project ever undertaken in Nova Scotia. A corporate consortium — ExxonMobil Canada, Shell Canada, Imperial Oil Resources, Pengrowth Energy Trust and Mosbacher Operating Ltd. — produces between 400 million and 500 million cubic feet of natural gas and 20,000 barrels of NGLs every day.

The Thebaud processing platform forms the hub of Sable’s offshore activity. This facility, which came on stream in 1999, handles preliminary processing of gas from Thebaud wells, as well as

the gas from two other production platforms — North Triumph and Venture. The Alma and South Venture production platforms began producing gas in 2003–2004.

From Thebaud, the Sable gas heads through 200 kilometres of pipe to the SOEP Goldboro Plant, whose full capacity is 600 million cubic feet daily. The NGLs are then piped from Goldboro to Point Tupper on Cape Breton Island, where a fractionation plant separates the liquid feedstock into propane, butane and condensate. The consortium is now evaluating the possibility of developing new gas fields in the Sable area.

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Photo: Sable Offshore Energy Project

The Thebaud gas processing platform sits offshore Nova Scotia near Sable Island.

Feature

Photo: Aaron Parker

Turf defender

Bob Maslanko, a chief estimator at Aecon Lockerbie Industrial, was recently elected president of the Electrical Contractors Association of Alberta.

Bob Maslanko, president of the Electrical Contractors Association of Alberta, defends his trade against less-qualified rivals

by Graham Chandler Professionally, Bob Maslanko believes in standards, and he fights hard for them.

The president of the Electrical Contractors Association of Alberta — elected at the ECAA’s annual meeting in May — sees the following issues as priorities for his sector: • P reparing for a looming shortage of qualified electricians as oilsands investments accelerate in 2012, • Promoting tighter regulation of fire alarm companies that “certify” installations with inadequately qualified personnel, • Ensuring that cathodic protection on pipelines continues to be installed and serviced by well-trained tradespeople, and

• Maintaining the role of master electricians in applying for the municipal and provincial permits that contractors must obtain for electrical projects.

Maslanko works as Aecon Lockerbie Industrial’s chief electrical/instrumentation estimator at its facility in Sherwood Park, Alta. The multi-trade contractor focuses on heavy industrial construction and maintenance services. His step into the presidency of the ECAA comes after four years as the association’s treasurer and VP. “Our biggest battle [over the past year or so] has been the Master Electrician Program,” Maslanko says. In Alberta, a

master’s ticket is required to pull permits for electrical and gas fitting work, whose inherent risks are self-evident. The requirement has been in place for decades. To qualify as a master electrician, the applicant requires a 75 per cent average through courses covering the electrical code, best business practices and related material. “To me, if you have attained that standard, the installation is going to be that much better, whether it be the oil and gas industry, the commercial industry, the servicing industry or housing,” Maslanko comments.

In recent years, the ECAA created two new master designations: the certified O I L & G A S I N Q U I R E R • J U LY/A u g u s t 2 0 1 0

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Feature

master electrician (CME) and the registered master electrician (RME). “The CME is a master but has gone the extra step — we made it mandatory for them to take an ethics course and also a code cycle upgrade,” the ECAA president says. (The electric code comes out with updates every three years.) “An RME is a master electrician who isn’t actively pulling permits but still wants to receive the updates.”

However, Maslanko acknowledges that some individuals do not wish to invest the time and effort involved in qualifying as a master electrician. These people have argued that there’s no real need for the permit pulling restriction, an objection that was taken up by provincial officials.

The ECAA’s lengthy discussion with government on the issue has now resulted in a revamped form of the legacy requirement.

Permit pulling will still be restricted to someone holding a master ticket. However, the Master Electrician Program will be administered by government, not by industry. The ECAA will retain its RME and CME programs as additional designations available to its members. To round out the new arrangement, the association plans to add educational programs such as electrical supervision courses to prepare journeymen for foreman or superintendent positions.

Now moving to the top of the ECAA’s agenda is cathodic protection, an electrical sub-specialty. This form of structural protection is widely used to prevent corrosion of steel and other metals that come into contact with electrically conductive environments such as soils or water. The method is employed extensively in the oil and gas industry, notably with buried pipe.

Large pipeline operators are now lobbying to create their own cathodic protection technicians. Maslanko defends the

need for certified electricians in this work.

“There is a lot of voltage involved with cathodic protection and it’s underground.

It’s accessible to the public, especially where it runs through farmlands, and we want to make sure the public is protected by a proper installation,” says the new president. “It’s a huge safety issue.”

If the government does opt for cathodic protection technicians, the ECAA wants to ensure proper training requirements and standards. A multinational company put on a cathodic protection course for 30 technicians at the Vermilion campus of Lakeland College, Maslanko says. “The exam was marked not by the instructor or through

At the association’s annual meeting, however, the buzz among most delegates did not focus on fire alarms and cathodic protection. Their attention was fixed on a possible shortage of electrical journeymen in the near future. “We are looking at 2012 being like 2008 all over again,” Maslanko comments. “If all these oilsands projects go ahead, such as Kearl Lake and the North West upgrader, there will definitely be another labour shortage.”

ECAA members haven’t been sitting on their hands. Unionized companies will first go to the union, then proceed if necessary with recruiting offshore. “Because of 2007, several contractors already have a pool of

“If all these oilsands projects go ahead, such as Kearl Lake and the North West upgrader, there will definitely be another labour shortage.”

— Bob Maslanko, President, Electrical Contractors Association of Alberta

a program but by the company itself, who said, ‘Well, here we are, we’re producing trained techs,’” the veteran specialist charges. “In all fairness, they’re not producing trained techs.”

The ECAA is also alarmed about another training issue. “Unqualified people are installing fire alarms today,” says Maslanko.

“I think you’ve got these fly-by-nighters coming into the industry and ‘certifying’ installations.” He emphasizes that some fire alarm company personnel are legitimately qualified and pose no concern. “But if the inspector is not certified and he puts a stamp on it, the owner thinks ‘I’m certified, so I’m fine.’ But he really does not have it certified.

So if there’s a fire and [the authorities] say, ‘Let’s see your certification,’ and it turns out the inspector wasn’t legitimate, there’s a problem. We are saying it is structural wiring so it belongs in the electrical industry.”

foreign workers that we were drawing on, such as those from Germany, Thailand and India, to name a few,” the ECAA president says. “Those contacts and individuals are already set up, so we can go back to those labour brokers and hire individuals.”

Across Canada, the Red Seal program provides qualified tradespersons with an endorsement on their provincial or territorial certificates, enabling them to work anywhere in the country after writing related tests. To eventually eliminate the need for such an endorsement, the ECAA is working with national and provincial associations “on standardizing requirements across the country,” says Maslanko.

“Right now, they don’t all teach the same curriculum.” Standardizing qualifications, he believes, will help create greater nationwide trade mobility along with more consistently reliable results on the job.

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British Columbia

Storm boasts higher netbacks thanks to liquids-rich gas production

by Pat Roche

Storm has 21 horizontal wells in its Parkland discovery, averaging 2.4 million cubic feet per day.

Storm Exploration Inc. has laid out capital spending plans totalling $85 million to $90 million for 2010, up from last year’s $55.6 million due to more profitable gas operations. “This is the benefit of producing liquids-rich, high–heat content gas,” said Brian Lavergne, Storm’s president and CEO. On June 9, the company was acquired

by ARC Energy for about $680 million plus assumption of $90 million in debt.

Storm is enjoying much higher netbacks from its Parkland/Fort St. John area in northeastern British Columbia. Last year, its netback at Parkland was $19.62 per barrel of oil equivalent (boe) at an average AECO spot price of $3.76 per gigajoule. This year — assuming an AECO spot price of only $3.92 per gigajoule from June through December — Storm’s Parkland netback would be $27.11 per boe.

The rate of return on a typical Storm horizontal well at Parkland jumped to

47 per cent in the first quarter, up from 28 per cent in all of last year. This includes an $812,000 credit from B.C.’s deep horizontal royalty credit program. Based on firstquarter results, a typical Storm horizontal well will now pay out in 1.4 years versus 2.3 years in 2009.

“We spent a lot of money and put a lot of time and effort into [installing at Parkland] a refridge plant to strip liquids out from half of our gas stream [23 million cubic feet per day],” Lavergne said.

Storm’s liquids production is currently about 500 barrels a day higher than last November before the refridge plant came on stream. The refridge plant saves the company about $0.35 per thousand cubic feet in processing fees, or about $2.8 million per year.

Output was reduced by 250 boe per day due to the failure on Feb. 12 of a fire tube in a process heater in the new refridge plant.

Current production from this area is about 8,200 boe per day with 8,000 boe per day from the Parkland property.

In the second half of 2010, Storm plans to drill 6 to 9 horizontals (6 to 7.1 net) in the Montney at Parkland. This will include three earning horizontals on lands Storm farmed in on during the quarter, plus a second horizontal into the lower sands. As well, two more vertical Montney step-outs (1.6 net) will be drilled as part of Storm’s focus on expanding the proved plus probable reserve area.

The first horizontal in the lower sands of the Upper Montney formation was drilled, completed with seven 50-ton fracs and tied in for a total cost of $4.5 million. Storm expects to drill a second horizontal into the lower sands in the third quarter, which will be completed with nine 75-ton fracs to improve the production rate. No reserves have yet been assigned to the lower sands.

Twenty-one horizontal wells are currently producing from Storm’s Parkland Montney discovery with first-year rates averaging 2.4 million cubic feet per day a day of raw gas. The average cost to drill, complete and tie in a horizontal well in the upper sands was $5.5 million in the first quarter.

This year Storm expects to spend $12 million to advance its Horn River Basin shale project towards commerciality. The company expects it will be mid-2011 before it has enough production data from horizontal wells to have an opinion on whether its Horn River shales are commercial.

The company expects one horizontal well will be drilled on its Horn River lands during the coming summer. Completion is planned for the fall. A pad for a second horizontal location was built. Drilling and completion are contingent on the results of the first horizontal well. First gas sales from successful horizontal wells is possible in early 2011.

— DAILY OIL BULLETIN

BRITISH COLUMBIA WELL ACTIVITY

JUN/09

JUN/10

WELL LICENCES

47

48

▲

JUN/09

JUN/10

WELLS SPUDDED

25

59

▲

WELLS DRILLED

JUN/09

14

JUN/10

43

▲

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • J U LY/A u g u s t 2 0 1 0

33

British Columbia

$17.9M bid in Hudson’s Hope area highlights B.C. land sale A drilling licence that went for nearly $18 million helped power British Columbia’s May land sale on May 19, which produced $76.6 million in total bonus bids. The May sale offered 96 parcels covering 47,374 hectares (ha), and the province sold 92 parcels covering 45,671 ha.

The average price per hectare for the sale was roughly $1,677. The May sale last year generated $10.2 million in bonus bids at an average of $488.98/ha. Year-to-date, the province has brought in $204.9 million in bonus bids compared to $68 million to the same point in 2009.

Charter Land Services Inc. tendered the bonus high, pay ing $17.92 million for a 3,981 ha licence parcel in the Blueberry West field, 75 kilometres north of Hudson’s Hope. The parcel produced an average of $4,503/ha. Four tracts were sold, which included several units at 94-B-9 and 94-A-12.

Windfall Resources Ltd. was successful in acquiring a 1,141 ha licence at 94-B-9 for $4.74 million, which produced an average of $4,157/ha. Daily Oil Bulletin

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(DOB) records show Talisman Energy Inc. rig released a well at surface location A-10J/94-B-9 in February with the Montney formation as the terminating zone in the Kobes area.

In March, Progress Energy Ltd. also rig released a well in the Gundy area at surface location C-67-J/94-B-9, also with the Montney as the terminating zone.

Five leases in the Blair Creek field, 100 kilometres north of Hudson’s Hope at 94-B-16, went for a combined $12.6 million, with broker Scott Land & Lease Ltd. as the successful bidder.

In April, Canadian Natural Resources L imited r ig released a well in t he Chowade area at surface location D-19L/94-B-9 with the Taylor Flat formation as the terminating zone.

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British Columbia

EOG Resources agrees to buy stake in Kitimat LNG export terminal EOG Resources Canada Inc. has agreed to acquire the shares of Galveston LNG Inc., a private Calgary-based company whose subsidiary Kitimat LNG Inc. is helping to develop an export facility on British Columbia’s north coast. Kitimat LNG owns 49 per cent of the planned liquefied natural gas export terminal to be located at Bish Cove, near the Port of Kitimat, about 652 kilometres north of Vancouver.

On Jan. 13, Apache Corporation announced an agreement with Kitimat LNG to acquire 51 per cent of the planned Kitimat project. Apache will be the operator.

Planned capacity of the proposed Kitimat LNG terminal is about 700 million cubic feet per day or five million metric tons of LNG per year. Preliminary construction costs, currently estimated to be approximately C$3 billion, will be revised at the conclusion of front-end engineering and design.

Under the terms of the agreement, EOG’s offer to purchase the shares of Galveston LNG is conditional on the achievement of certain commercial and regulatory milestones. Last summer,

Kitimat LNG signed a memorandum of understanding (MOU) with EOG to supply natural gas to the terminal.

“We had originally started our discussions with EOG with that MOU, and they were looking at moving gas through our terminal more through a processing arrangement,” said Ilene Schmaltz, VP of supply marketing with Kitimat LNG. “Over time, they realized that they would rather own part of the project than just have the transportation agreement, so this replaces it.”

Up on EO G’s acqu i sit ion of t he Galveston LNG shares, EOG and Apache propose to construct, own and operate the terminal. The K itimat terminal is designed to link to the pipeline transmission system serving western Canada’s natural gas producing regions via the proposed Pacific Trail Pipelines, a $1-billion, 463-k ilomet re project originating at Summit Lake, B.C. Through its deal with Galveston, EOG will acquire a 24.5 per cent interest in the Pacific Trail Pipelines, a partnership between Galveston, Apache and Pacific

Northern Gas Ltd. The proposed pipeline has received environmental assessment approvals from both the federal and provincial governments.

“EOG is pleased to partner with Apache in the development of this new market opportunity for natural gas from our Canadian operations. By combining our experience and resources, we are confident

"By combining our experience and resources, we are confident we can move this project to completion."

— Mark Papa, Chairman and CEO, EOG

we can move this project to completion,” said Mark Papa, chairman and CEO of EOG, in a news release. “As a part of this process, we look forward to continuing to build on the relationship with the Haisla First Nation and being a part of Kitimat and surrounding communities.”

Spectra plans new gas plant near Dawson Creek Responding to customer demand in the Montney play of northeastern British Columbia, Spectra Energy has announced plans for a new 200 million cubic feet per day natural gas processing plant west of Dawson Creek. The proposed Dawson processing plant will be built in two phases with the first 100 million cubic feet per day of processing capacity available in late 2011 and the remaining capacity available in

early 2013. The expansion facilities are supported by long-term customer commitments.

“The new plant is an important part of our growth strategy and our now about $1.5-billion investment opportunit y in northeast British Columbia,” said Doug Bloom, president, Spectra Energy Transmission West, on June 10. “The new plant capacity is fully contracted, further extends our asset base in the

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rapidly growing Montney natural gas play and will be integrated with our existing natural gas gathering and processing facilities in the area.”

With B.C.’s gas production forecast doubling, further development opportunities in northeastern B.C. are anticipated, said the company. Construction of the proposed new facilities is subject to all customary regulatory and other approvals.

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O I L & G A S I N Q U I R E R • J U LY/A u g u s t 2 0 1 0

35

Northwestern Alberta/Foothills

Progress co-develops frac technology to unlock Nikanassin

NEED PHOTO

Calfrac and Progress use oil under high pressure to convey sand/proppant into Nikanassin fractures.

Progress Energy Resources Corp. continued its successful drilling program in the Gold Creek/Wapiti area during the first quarter of this year, drilling 13 wells (12.5 net). Greg Kist, Progress VP of investor relations, said the SlikPro technique — co-developed with Calfrac Well Services Ltd. — has produced initial production rates that are 10 times better than industry’s historical results, Kist said.

“It was in recognition of the fact that the Nikanassin formation had long been known to hold commercial quantities of natural gas,” Kist said. “But when fracture stimulated using the available technologies, it flowed sub-economic gas rates…in the range of 200 [million] to 300 million cubic feet per day.”

The SlikPro technique uses oil to carry the sand/proppant and that oil is pumped into the formation at very high pressures.

As a result of the two-year-old initiative, Progress said productivity of the Nikanassin

zone has changed from being marginally economic to, in many cases, justifying wells that target only the Nikanassin.

Since February 2008, Progress has drilled 22 wells in the Gold Creek/Wapiti core area with the Nikanassin as the primary target. It has reportedly been able to achieve economic rates from a zone long considered uneconomic to drill. As a result, many wells in the Gold Creek/ Wapiti area have Nikanassin pay that was left unperforated and now present recompletion and new drill opportunities.

Production from wells where the Nikanassin has been a target zone has grown significantly from less than 500 barrels of oil equivalent (boe) per day in early 2008 to approximately 6,000 boe per day currently.

“We’ve had now almost two years’ worth of activity specifically to the Nikanassin,” president and CEO Michael Culbert, said at the company’s annual meeting in May.

“We’ve added another, call it unconventional or resource-play zone to the multizone opportunities that we have within the Deep Basin.”

In its first-quarter report, management said that the regulatory environment in Alberta has continued to improve with the government’s recent decision to permit drilling of four wells per section within this area that will allow Progress to more efficiently increase the number of wells drilled on each section.

Progress’s production for the three months ended March 31, 2010, averaged 35,070 boe per day, 6 per cent higher than the same three-month period of 2009. The production portfolio in the quarter was weighted 85 per cent to natural gas, 5 per cent to crude oil and 10 per cent to natural gas liquids.

Progress has also established a strong position in the Montney fairway in the foothills of northeastern British Columbia. The company’s land base now covers approximately 900,000 net acres of Montney rights, of which 680,000 net acres are in the foothills in large contiguous blocks.

First-quarter drilling activity has increased Montney production from approximately 8 million cubic feet (MMcf) per day of natural gas at the beginning of the year to around 30 MMcf per day (5,000 boe per day).

The company’s 2010 capital investment program is focused on investing $350 million in its two key resource play regions in the foothills and Deep Basin and includes $50 million to be invested in the acquired properties in northeastern British Columbia The successful first-quarter program delivered material growth in the Montney play, which achieved commercial production, and the Nikanassin-focused program delivered another quarter of strong drilling results.

Production is forecast to exit 2010 in the range of 45,000 to 46,500 boe per day.

— DAILY OIL BULLETIN

NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY

JUN/09

JUN/10

WELL LICENCES

121

214

▲

JUN/09

JUN/10

WELLS SPUDDED

57

128

▲

JUN/09

JUN/10

WELLS DRILLED

39

69

▲

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • J U LY/A u g u s t 2 0 1 0

37

Northwestern Alberta/Foothills

North Peace to try radials and continuous steaming at Red Earth North Peace Energy Ltd. says it will employ top-down steam drive to improve oil recovery from its cyclic steam stimulation oilsands pilot project at Red Earth in its pursuit of commercial-scale production while also seeking strategic alternatives.

On the first cycle of the L1 and L2 wells, North Peace did not get effective use of the steam injected and did not heat most of the horizontal section of the wells, Louis Dufresne, president, chief executive officer and director told the company’s annual meeting in June.

“It appeared that we chased the steam away, in turn leading to high steam to oil ratios. Backing off on the steam injection of L1’s second cycle supports this since we’ve now reached a significantly better steam to oil ratio.”

The second cycle of the L1 well at the Red Earth pilot in northern Alberta is nearing completion and its steam to oil ratio (SOR), which continues to decrease as production is maintained, is now approximately 4.1. This is a 50 per cent improvement over the initial cycle, the

company reported along with its firstquarter results.

For comparison purposes, the company indicated in its first-quarter results report, SOR when adjusted for heat content of injected steam equates to a steam assisted gravity drainage (SAGD) SOR of 3.5. This SOR compares favourably with the current industry average SOR of 3.7 for existing SAGD projects in commercial operations,

to optimize the overall area of recovery in future.

The L2 well has presented its own challenges, although they are somewhat similar in nature to L1’s first cycle.

“We’ve got a steam to oil ratio which is in a commercial range, but we’ve got to get better at distributing steam all day and every day in our reservoir, and I am telling you we are very confident we know how to

" We’ve got to get better at distributing steam…in our reservoir, and I am telling you we are very confident we know how to do it." ­— Louis Dufresne, President and CEO, North Peace Energy Ltd.

the company said. The production rate to date for the cycle is 25 barrels per day over a period of 30 weeks, which includes both steam injection time and production time.

The L2 well remains shut-in for a pump change, and preparations are underway for conversion to a steam circulation test designed to get additional reservoir knowledge, which will help

do it,” he said. “The focus is now on providing the right geometry required to achieve high steam injectivity in a fashion which will not allow the steam to get away too far from the producing well,” Dufresne said.

While other companies have used radial legs jetting out from vertical steam injectors to aid in steam distribution, what’s new about North Peace’s approach

? t c e j o r p e in l e Y O s i U p i R p N E E R G w o H

38

J U LY/A u g u s t 2 0 1 0 • O I L & G A S I N Q U I R E R

Northwestern Alberta/Foothills

is the use of radials in combination with horizontal producers in a continuous process it is referring to as top-down steam drive, the annual meeting heard.

“We think that’s the right way to go because with that kind of development, where the wells are no longer unbound but are working together, we get much better recoveries than with just the one well,” said Dufresne. The company may proceed with the already-drilled L1 well only as the capital costs to build a temporary steam line and minor wellhead modifications are only about $1 million.

The top-down steam drive process is expected to cost about $10 million for two horizontal wells, six injectors, radial legs on each well, a six-inch steam line and insulated tubing.

North Peace has applied for an amendment to its common scheme approval filed with the Alberta Energy Resources Conservation Board for permission to inject steam in its two observation wells, with the addition of the radial legs, which are within its pilot project site.

The project has been on continuous production since May 2009 and has

produced 22,000 barrels of 10-degree API bitumen to date.

Radcan Energy Services Inc. will jet the radial legs. Installed at multiple levels, radials will be drilled up to 100 metres long using high fluid pressures perpendicular from the main wellbore, perforating twoinch holes in the casing at selected depths and directions.

North Peace has a little more than $3 million in working capital, which should take it to 2011.

The company is in a strategic alternatives review process, which Dufresne declined to comment upon except to say alternatives could entail joint ventures, sale of assets, farm-ins and accessing additional equity.

During the first quarter, North Peace sold a portion of its drilling royalty credits, which were earned as part of the conventional exploration program, for $450,000.

Capital expenditures of $860,000 during the quarter focused on completion of drilling programs begun in the fourth quarter of 2009. The company had oil sales of $208,387 from the Red Earth pilot and $91,473 from conventional assets.

Bonnett's reports improved Q1 Bonnett’s Energy Services Trust reported higher revenues and net income for the first quarter of 2010. Profits rose to $3 million for the three months ended March 31, 2010, from $615,000 for the same period last year. The trust generated revenues from operations of $22.8 million for the first quarter, $2.1 million more than generated in the comparable period of 2009.

Demand for t he tr ust ’s ser v ices increased over the same period last year.

Unlike the first quarter of last year, many customers continued to request services through the end of March despite the warmer weather, which typically brings a slowdown in activity, Bonnett’s said.

Drilling activity is a key indicator of demand for the trust’s services, and is forecast to be 35 per cent higher in 2010 than 2009, which may bring added revenue to the trust.

Revenues were up 10 per cent over the same period of the prior year, and the trend is expected to continue.

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O I L & G A S I N Q U I R E R • J U LY/A u g u s t 2 0 1 0

39

Northwestern Alberta/Foothills

Arcan initiates what it calls a new light oil play at Swan Hills After drilling eight horizontal wells at Swan Hills, Alta., including six through breakup in the second quarter, Arcan Resources Ltd. plans to keep up the momentum through the rest of the year.

“Arcan has the ability to drill up to 15 horizontal wells this year while remaining within cash flow and its existing bank lines,” Ed Gilmet, president and CEO, told the company’s annual meeting in late May. Ian Fisher, Arcan’s operations manager, said all the wells within the Deer Mountain Unit 2 were horizontal legs drilled off existing vertical producers so the tie-ins are essentially 20 metres. The plan is to keep two rigs busy through the summer at Deer Mountain resulting in two horizontals per month with all the wells on production in the third quarter.

“We have tied up a substantial portion of what we view as a new emerging light oil resource play with horizontal technology,” said Fisher. “We’ve got an enviable land position on a very profitable light oil horizontal play and the capacity to exploit it.”

Arcan has a proposed capital program of up to $110 million for this year (including a $52.8-million acquisition in the first quarter) with approximately $30 million in cash flow based on estimated average production of 2,500 to 3,000 barrels of oil equivalent (boe) per day and estimated exit production of 3,500 to 4,000 boe per day.

The junior is looking to horizontal multi-stage acid fracturing technology to increase recovery rates and accelerate production from the Swan Hills complex which was first developed in the 1950s and ’60s.

The company started out in 2005 with 9.5 sections (81 per cent working interest) in Deer Mountain Unit 2, which it had planned to develop with vertical wells that were economic but had slow reserves recovery. Following the recent acquisition of adjoining lands to the south, it has a total of 150 gross (140 net) sections (90,000 undeveloped acres).

At three horizontal wells per section, Arcan could potentially drill 220-plus horizontal wells over two townships. It now is looking at four horizontals per section, with the potential for two more later in the centre.

With a waterflood, the estimated ultimate recovery is up to 184 million barrels of oil out of an estimated original oil in place of more than 460 million barrels (4 million to 10 million boe per section).

40

J U LY/A u g u s t 2 0 1 0 • O I L & G A S I N Q U I R E R

Swan Hills, a historic oil-producing region, is regaining momentum thanks to new technology.

While the tighter (less permeable) areas on the east side of the Swan Hills Reef complex hold significant oil in place, the vertical wells historically have been less productive resulting in a low recovery rate. Arcan is targeting a minimum 40 per cent recovery over the longer term at Deer Mountain and its recently acquired lands, up from a 15 to 20 per cent primary production recovery rate, Gilmet said.

Late last year, Arcan drilled its first (81 per cent working interest) horizontal well into the Beaverhill Lake formation and in

intends to truck the oil until it can be connected to its existing infrastructure.

The main drilling this year will be within the Deer Mountain unit, which has a waterflood in place. The unit also has a 4,000-barrel-per-day battery, which is expandable to more than 8,000 barrels per day at a cost of about $1 million, which the company currently is working on, he said.

The new lands to the south are at virgin pressure, which will give the company about a year before a waterflood is needed, according to Fisher. Later this year, Arcan expects to

" We’ve got an enviable land position on a very profitable light oil horizontal play and the capacity to exploit it."

— Ian Fisher, Operations Manager, Arcan Resources Ltd.

January the well was completed using multistage acid-fracturing technology. The well took 10 fracs using 28 per cent hydrochloric acid. The acid dissolves permanent passages in soluble carbonate rock, while horizontal drilling enables multiple acid fracs in a single well. The well tested more than 600 boe per day and after three months on production is stabilizing at around 350 to 400 boe per day, said Fisher.

A second horizontal well drilled on acquisition lands with a 1,200-metre leg tested 700 boe per day, and following installation of a pumpjack, it is currently producing approximately 500 boe per day.

Arcan has built a new road to the site and

begin work on the new lands to the south with an initial 30 to 60 horizontal well inventory and the construction of a new 20,000-barrelper-day battery late in 2011, he said.

While a typical vertical Swan Hills well will have an initial production (IP) of 80 boe per day and an average one-year rate of 38 boe per day, the potential IP for a horizontal well is 3 to 10 times that of a vertical with an estimated one-year average of 300 boe per day, according to Fisher. With more prolific wells, the company hopes to reduce its reserve life index to about 10 years from the current 30 years, said Fisher.

Arcan’s typical horizontal well with a 1,000 -metre horizontal leg and a

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In his presentation, Fisher pointed out that Arcan’s Swan Hills play was economic with vertical wells, unlike some other tight oil plays such as the Bakken and Cardium.

The company is looking at an ultimate recovery of 600,000 boe per well compared to 200,000 boe for the Pembina Cardium.

The biggest difference between the two plays is the permeability. While the Cardium is less than one millidarcy, the Swan Hills on average is four to five millidarcies, said Fisher. “You are comparing clastic sandstones [Cardium and Bakken] to a Devonian reef,” he said in response to a question from a shareholder. “The Devonian reef is a far superior reservoir.”

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IN

— DAILY OIL BULLETIN

Yoho plans to drill $6M Duvernay shale gas well Yoho Resources Inc. has successfully completed a pooling of its Kaybob lands with two other industry parties whereby Yoho has contributed eight 100 per cent sections of Duvernay mineral rights (5,120 acres), resulting in a post pooling interest of 33.3 per cent working interest in 27 sections of Duvernay mineral rights (17,280 gross acres).

All parties in the pooled lands have agreed to proceed with the drilling of a 4,700-metre horizontal well targeting the Duvernay shale. This well will be completed with a multi-stage frac program in the horizontal section of the wellbore.

Total cost to drill, case and complete the well, including the frac program, is estimated to be $6 million. Yoho will participate in this well to its 33.3 per cent pooled working interest.

These lands are located in the prime fairway for a potential new shale gas resource play in the Duvernay formation.

The Duvernay has long been considered to be a world-class source rock in the Western Canadian Sedimentary Basin, and recent specialized reservoir and rock studies by Yoho indicates that this shale has all of the key parameters required for successful shale gas plays. The well is anticipated to spud this summer.

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Finding innovative ways to limit environmental impacts is key to meeting our energy needs responsibly.

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A message from Canada’s Oil Sands Producers The Canadian Association of Petroleum Producers (CAPP) represents member companies that produce approximately 90 per cent of Canada’s natural gas and crude oil, including Canada’s Oil Sands Producers.

Northeastern Alberta

Photo: Joey Podlubny

Oilsands reserves climb during 2009 despite lower investment

Oilsands mining companies added one billion barrels of bitumen to their proved reserves for 2009.

Although many projects were cancelled or deferred during 2009, Canada’s proved oilsands reserves continued to rise, particularly for in situ projects. At year-end, the largest owners of proved in situ bitumen reserves were ConocoPhillips Canada (1.13 billion barrels), Cenovus Energy Inc. (866 million barrels) and Suncor Energy Inc. (666 million barrels).

Companies reported proved oilsands reserves of a total of 14.9 billion barrels at the end of 2009, up from 11.67 billion reported at the end of 2008. Proved in situ reserves jumped to 5.37 billion barrels from 3.18 billion a year earlier, while proved mining reserves (bitumen and synthetic) rose to 9.53 billion barrels from 8.49 billion the previous year. The large gain in proved in situ reserves was partly due to reporting differences between the two years by companies such as Encana Corporation and Husky Energy Inc.

In situ oilsands producers added 564 million barrels from field activity to their proved reserves last year, much more than the 163 million barrels that were produced in 2009. The big gains were at ConocoPhillips (extra 118 million barrels), Encana (extra 159 million barrels before it transferred all of its bitumen to Cenovus) and Husky Energy, which booked 69 million extra barrels from field work and 76 million barrels from economic factors.

Probable in situ bitumen reserves increased by more than 500 million barrels last year as several new players were able to book reserves for the first time.

Osum Oil Sands Corp. (320 million barrels), Athabasca Oil Sands Corp. (113.9 million barrels) and Southern Pacific Resources Corp. (54.1 million barrels) were the major contributors to the yearover-year rise.

On the mining side, proved bitumen and synthetic reserves rose by about 1.04 billion barrels in 2009 to 9.53 billion barrels. Suncor Energy topped the list, adding reserves from its acquisition of Petro-Canada (which had an interest in Syncrude Canada Ltd.) and from its Steepbank mine expansion.

Suncor ended 2009 with nearly 1.9 billion barrels of net synthetic oil reserves in its mining operations plus a further 524 million barrels of probable reserves from its mining assets. As a result of continued development of its North Steepbank extension, some 500 million barrels of reserves were moved from probable undeveloped.

Of the total, 330 million barrels moved to proved reserves and the remainder was moved to probable developed.

Imperial Oil Limited held about 1.65 billion barrels of proved mining reserves at the end of last year. Imperial had 961 million proved barrels of synthetic crude from its Syncrude Canada ownership at the end of 2009 plus a further 962 million barrels of proved bitumen from its Kearl oilsands project under construction. The company holds a 71 per cent interest in the Kearl project, which has total estimated recoverable resource of 4.6 billion barrels of bitumen before royalties.

Canadian Natural Resources Limited had 1.65 billion barrels of proved reserves booked for its Horizon oilsands mine at the end of last year, down from 2008 due mainly to a negative 307 million revision attributed to economic factors.

Shell Canada Limited had nearly 1.6 billion barrels of proved synthetic mining reserves at the end of 2009. The company’s reserves benefited from the switch to synthetic reporting from bitumen reporting (due to its hydrogen addition process) and it added 423 million barrels due to mine extensions last year.

— DAILY OIL BULLETIN

NORTHEASTERN ALBERTA WELL ACTIVITY

JUN/09

JUN/10

WELL LICENCES

22

36

▲

JUN/09

JUN/10

WELLS SPUDDED

35

49

▲

WELLS DRILLED

JUN/09

31

JUN/10

64

▲

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • J U L Y / A U G U ST 2 0 1 0

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Northeastern Alberta

Logan International acquires Source Energy Tool Services for $25M Logan International Inc. (whose name was recently changed from Destiny Resource Services Corp.) has acquired Source Energy Tool Services Inc., a privately held technology-focused oilfield services company providing downhole equipment and multi-fracturing tools and services, headquartered in Lloydminster, Alta.

The acquisition is consistent with Logan’s strategy of growth in the downhole tool market. The company expects the acquisition to be accretive to 2010 earnings before interest, taxes, depreciation and amortization. Logan paid $25 million cash for all of the issued and outstanding common shares of Source and assumed approximately $1.1 million of debt. The acquisition has been funded by cash on hand and by drawing on existing credit facilities, which were slightly modified to provide the acquisition financing.

The four key principals of Source have entered into employment and noncompetition agreements. The existing principals of Source will be entitled to earn up to an additional $4 million, payable over two years, if certain sales growth targets are

achieved for Source’s proprietary horizontal multi-fracturing tool and services division.

“The acquisition of Source fits perfectly with our growth and acquisition strategy,” said Gerald Hage, CEO of Logan International. “Source’s MultiStim Fracture Isolation system is a proprietary

manufacturing excellence and by increasing sales through the expanded combined distribution systems of Logan Oil Tools and Source.

Source, founded in 2001, is a provider of equipment and services for completion, workover fishing activities and drilling

"Source's MultiStim Fracture Isolation system is a proprietary multi-fracturing completion technology that is being adopted...for the fracturing of horizontal wells."

— Gerald Hage, CEO, Logan International

multi-fracturing completion technology that is being adopted by oil and gas producers for the fracturing of horizontal wells. We intend to aggressively grow this business in Canada and introduce the technology in the U.S. and internationally through our existing network and relationships.”

Additionally, Hage said that Logan expects to achieve significant synergies by leveraging its engineering expertise and

motor systems in the Western Canadian Sedimentary Basin (WCSB). It is headquartered in Lloydminster and has service locations in Lloydminster, Edmonton, Grande Prairie, Bonnyville and Brooks, Alta., as well as in Kindersley, Sask., and has a sales office in Calgary.

Source has a proprietar y multifracturing completion technology that is fully retrievable post-fracturing. The benefit of this technology is that it leaves

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Other Source downhole products include packers, bridge plugs, fishing tools and services, liner hangers, casing patches and mud motors.

Source services producers that are focused on both heavy and light oil play development. It has an established base of operations in Kindersley, servicing the Viking light oil play. Logan said it will use the majority of the Source product line in key unconventional oil and natural gas resource plays in the WCSB and will be introducing the proprietary MultiStim Fracture Isolation technology into the United States, initially focusing on the Bakken light oil play in North Dakota.

With the completion of the acquisition, Logan has net debt of US$29.2 million, of which $12.7 million is term debt and the balance is short-term/revolver-based or due to the Source shareholders. On March 25, Logan completed its previously disclosed sale of all of the outstanding stock of Diamant Drilling Services S.A. Logan International expects to record a small gain on the sale.

— DAILY OIL BULLETIN

Solara Exploration proceeds with Sparky drilling on Dewberry project Solara Exploration Ltd. says it has received the approval by the Energy Resources Conservation Board for its application for a Primary Recovery Scheme for a Sparky oilsands development underlying 16-54-4W4 located in northeastern Alberta.

The company also announced that it has set in production casing in a potential oil well it recently drilled in the North Sounding Lake area of eastern Alberta.

The company has plans to complete the well for production immediately

To date, Solara has drilled five successful primary recovery wells on its Dewberry oilsands development project.

The Primary Recovery Scheme allows Solara to drill one well on 20 acres (8 hectares) versus the previous well spacing requirements of one well per 160 acres (64 hectares) for the purpose of developing the Sparky oilsands. In May, the company said it would start drilling four wells on the project lands immediately, subject to surface access. As well, Solara has plans to drill three wells on its 100 per cent interest lands directly adjacent to section 16. To date, Solara has drilled five successful oil wells on the Dewberry project lands.

contingent on surface access. The new well directly offsets a producing oil well that Solara drilled in October 2009. The company owns an 80 per cent working interest in the new well.

Solara said it plans to drill a horizontal well to evaluate the Cardium oil potential underlying lands in which it owns a 40 per cent working interest in the Buck Lake (Pembina) area of western Alberta. The well was scheduled to commence in late June, subject to regulatory approvals.

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Northeastern Alberta

Imperial signs solvent services deal with Keyera Keyera Faci lit ies Income Fund has entered into a second multi-year agreement with Imperial Oil Limited related to its Kearl oilsands project. Under the terms of the new solvent services agreement, Keyera will use a combination of new and existing infrastructure at its Alberta Diluent Terminal (ADT) site in Edmonton to provide Imperial with a segregated solvent-handling service that includes rail off loading, storage and truck loading. The initial term is three years with the ability to extend the agreement to seven years.

Late last year, Keyera signed a longterm agreement with Imperial to provide diluent transportation, storage and rail offload services in the Edmonton/ Fort Saskatchewan area for the Kearl operation. Under the agreement, Keyera will be required to construct additional pipeline connections and pumping and metering facilities to extend and enhance its existing infrastructure.

With the development of the solvent project at an estimated capital expenditure of $9 million, Keyera expects it will

be well positioned to provide longer-term specialty product services to Imperial and others. With its natural gas liquids infrastructure in the Edmonton/Fort Saskatchewan area, Keyera expects to benefit from the growing demand for condensate for blended bitumen as the oilsands sector continues to develop, he told the meeting. “There is increasing demand for the services we provide for these assets,” said Jim Bertram, Keyera’s president and CEO. T he Canadian A ssociation of Petroleum Producers has estimated that bitumen production will rise to 2.25 million barrels per day by 2025, he said.

With a 30 per cent diluent ratio, those volumes would require about 800,000 barrels per day of condensate, most of which will have to be imported from the United States or offshore.

Engineering design work is underway for the pipeline connection between the Enbridge Inc. Southern Lights diluent terminal and Keyera’s ADT. Access to condensate delivered on the pipeline from Chicago is expected to enhance the

diluent receipt options available for customers, said Keyera management.

Keyera expects to implement its conversion to a corporation effective Jan. 1, 2011, which will allow it to maximize the tax benefits of its current trust structure through 2010. The trust expects to maintain its dividend at the same level as its current annual distribution ($1.80 per unit) when it converts to a corporation, said Bertram.

Keyera’s capital spending was $12.2 million in the first quarter of this year, including $6.4 million for the Caribou gas plant expansion, which is expected to be ready for commissioning by mid-year. The plant will be expanded by 40 million cubic feet per day expansion to 105 million cubic feet per day. Another $2.8 million was spent on the acquisition of two gathering lines that connect to the Pembina North and Brazeau River gas plants.

The fund is pursuing a number of growth opportunities, and continues to expect to invest between $80 million and $100 million this year on growth initiatives.

— DAILY OIL BULLETIN

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Central Alberta

ARC cautions that huge estimates of Cardium reserves are premature

by Pat Roche

ARC says it is booking minimal reserves per well until Cardium productivity is better documented.

T he second-largest operator in the Pembina Cardium warned against “outrageous” reserves claims in the emerging unconventional light oil play. “We don’t have enough information yet to tell what the reserves on an individual well will be,” John Dielwart, president of ARC Energy Trust, told shareholders at its annual meeting in Calgary on May 18.

Dielwart said ARC’s Cardium wells are among the best drilled into the formation to date. He said the trust, which has no land tenure issues at Pembina, is moving at “a more measured pace than other companies,” and “we’re not going out and drilling anywhere and everywhere.” The veteran reservoir engineer concluded: “It’s very, very difficult to accurately predict reserves yet. So it’s a work in progress for us. But it is an important one and we’re going to [spend] a lot of capital.”

The Cardium is Canada’s biggest onshore oil resource, but a relatively small

portion of that oil has been recovered in the decades since the formation was discovered. In the past year, advances in horizontal drilling and multi-stage fracturing kindled hopes that the Cardium’s recovery factor can be increased. Companies are scrambling to get a piece of the Cardium action in the hope they can apply technologies that opened up shale gas plays and tight oil plays such as the Bakken in southern Saskatchewan.

The biggest portion of the Cardium is in the giant Pembina field of central Alberta, and Dielwart is bullish about the opportunities it presents. “This is an eight billion barrel original oil in place field,” he said. If an estimated recovery factor of 20 per cent is correct, then 80 per cent of that oil is still in the ground. Just increasing the recovery factor by one percentage point to 21 per cent would boost industry-wide reserves by 80 million barrels, Dielwart said.

The trust is the second-largest operator in the Pembina Cardium, after Penn West Energy Trust. ARC operates 1,415 — or 25 per cent — of the gross wells with an average working interest of 66 per cent. Its current operated Pembina production is about 6,400 barrels of oil equivalent (boe) per day, but the average well rate is only 9.9 boe per day. The average water cut is 93 per cent and the proved-plus-probable reserve life index is 17.8 years.

ARC plans to spend $54 million in the Pembina field this year and drill 16 vertical and 16 horizontal wells. The trust says the geology of the Pembina field is quite variable, so it needs to test horizontal well completions in several geological settings before it can estimate where the technology can be effectively applied.

“We hear some pretty outrageous comments, to be perfectly honest, about the reserves per well,” he said. “We have booked minimal horizontal production reserves in Pembina because we feel it’s just too premature.” ARC’s CEO displayed a chart showing the 30-day initial production rates for 63 Pembina wells. While one well had a 30-day initial production rate of more than 800 barrels per day, the rest ranged from less than 300 barrels per day down to about zero. So Dielwart advised skepticism about early claims of “hundreds of [Cardium drilling] locations with hundreds of thousands of BOEs of reserves per well.”

He displayed another graph showing horizontal well “type curves” that are used to estimate a well’s future output based on its initial production. ARC found significant variability in Cardium production curves. “And as this continues to evolve, companies will drill wells at all ends of this spectrum. And it’s very clear the wells drilled in the bottom quartile are going to be sub-economic,” Dielwart said.

— DAILY OIL BULLETIN

CENTRAL ALBERTA WELL ACTIVITY

JUN/09

JUN/10

WELL LICENCES

152

276

▲

JUN/09

JUN/10

WELLS SPUDDED

99

162

▲

JUN/09

JUN/10

WELLS DRILLED

95

131

▲

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • J U LY/A u g u s t 2 0 1 0

49

Central Alberta

Some juniors are more upbeat after Alberta’s royalty revisions Photo: Joey Podlubny

In stark contrast to 2009, the mood was much improved at the 2010 Spring Investor Showcase sponsored by the Small Explorers and Producers Association of Canada (SEPAC) in Calgary on June 3. The improved outlook was due in large part to industry-friendly revisions to Alberta’s royalty structure.

“I think [the revisions] will stimulate activity in specific areas that were targeted in some of the emerging resource and technology packages…. We’ll have to wait and see as particular companies assess the impact. But I think the early indications are it certainly will be positive,” commented Gary Leach, SEPAC’s executive director. “I know some of the services associations have upped their forecast on drilling based on what they expect to see. But a lot of the changes were anticipated. There were not a lot of surprises in what the government did. We felt they responded, I think, well to industry proposals that were put on the table.”

Leach, who was an active participant in the industry-government dialogue that led to the formation of the new royalty

SEPAC executive director Gary Leach hopes investment will stop fleeing to other jurisdictions.

structure, was especially pleased with what the province has done to encourage and incent deep natural gas drilling.

“Those changes were made permanent, [and] the depth has been reduced to 2,000 metres. There’s an awful lot of gas wells in Alberta at those depths,” he said.

“I think the juniors are well poised to take advantage of that program.”

All of this is a positive turnaround from last year, when companies were diverting their tightly held capital budgets to neighbouring jurisdictions, Leach noted. “I’m actually hoping that the junior

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J U LY/A u g u s t 2 0 1 0 • O I L & G A S I N Q U I R E R

Central Alberta sector and the mid-cap sector will see some real reason to increase their investment in Alberta.”

Daily Oil Bulletin records already show a revival of activity by juniors this year. Of the 4,196 wells drilled in Canada to the end of May this year, 1,423 were drilled by medium and small companies (excluding trusts), compared to only 770 wells drilled by these firms over the first five months of 2009.

A lan Bey, president and CEO of Rock Energy Inc., said with his company focused on its heavy oil prospects in the Lloydminster area and a longer-term natural gas resource play at Elmworth, targeting the Montney and Nikanassin, the changes to royalties will have a profound impact going forward.

“What’s a challenge for us, of course, is the actual economics of these wells.

So, with this new royalty regime that’s been announced, we see a very significant improvement for us. Because we are drilling horizontal wells, we do qualify for the extra length, and of course, the 2,000 metres from the 2,500 metres also impacts us,” Bey said. “So this obviously helps us realize the price we need on a gas price to get our threshold economics in place, so we see this as a very positive thing.”

Bey said the royalty changes won’t prompt immediate increases in his firm’s capital expenditures, which are weighted to heavy oil in 2010. “It maybe as early as the fourth quarter of 2010, but likely the first quarter of 2011 before you actually see Rock accelerate its gas program,” he predicted.

Steve Moran, president and CEO of Bellamont Exploration Ltd. said that the certainty that has come with the recent

Bellamont’s capital budget of $35 million for 2010 is weighted towards oil projects, which will continue to increase the company’s oil weighting and netback through the year. Changes to the deep drilling measures should benefit juniors, who often take the most risks drilling exploratory wells in the province.

Glenn Dawson, president and CEO of Nuloch Resources Inc., which is focused

"Those changes were made permanent, [and] the depth has been reduced to 2,000 metres. There’s an awful lot of gas wells in Alberta at those depths."

— Gary Leach, Executive Director, Small Explorers and Producers Association of Canada

royalty decision provides a bit more stability in an already highly volatile industry. “I think they’ve got it right now,” he said. “I’m pretty happy that they found a way. The landscape has changed with the type of wells getting drilled. Everything’s basically going horizontal with multi-stage frac,” Moran added. “They were penalizing companies that were getting great rates on wells but had thrown a lot of money into getting those rates. We can’t get penalized for making that happen.”

on oil targets in Saskatchewan and North Dakota, said the royalty decision won’t spur a massive shift of capital from those jurisdictions to Alberta, but praised the government’s moves. “We made our stake and we have so much land now,” he said. “The royalties are st il l bet ter in Sask atc hewa n. W hat Alberta’s done is attractive but most of the resource land in the current plays are taken up.”

— DAILY OIL BULLETIN

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Central Alberta

Associations launch study to determine purity needs for CO2 Two industry associations — the Integrated CO2 Network (ICO2N) and the Petroleum Technology Alliance of Canada (PTAC) — together with international partners and the Alberta Department of Energy have joined to undertake a study for determining the purity needs for capture, transport and storage of CO2 as part of a carbon capture and storage (CCS) system in Canada.

The study will be facilitated by PTAC to secure funding from provincial and federal governments, issue the request for proposals, manage the contracts and disseminate the information. The CO2 purity study is expected to be completed in early 2011.

Determining the overall level of CO2 purity is necessary for establishing the optimal conditions under which CO2 capture, transportation, long-term storage and enhanced oil recovery can occur. Capture processing costs increase to meet higherquality CO2 specifications, and capture purity varies by industry and the choice of CO2 capture technology.

Enhanced oil recovery markets can be compromised by poorer-quality specifications. In addition, pipeline specification standards designed to protect CO2 pipelines

will also influence the optimal CO2 purity determination.

The study will examine CO2 purity, contaminants, temperature and pressure and looks to build on Alberta’s extensive CCS knowledge. It seeks the balancing point for purity requirements and cost

“ICO 2 N is ver y fortunate to have access to proprietary CO2 capture information, from its members, on which to build this analysis,” said Robert Craig, director of strategy and technology for ICO2N. “We are pleased to be able to collaborate with organizations locally and

"This study exemplifies collaboration...among oil and gas producers, emitters and transporters...."

— Soheil Asgarpour, President, Petroleum Technology Alliance of Canada

effectiveness as it pertains to all stages of a CCS system — capture, transportation, sequestration and enhanced oil recovery use.

There has been a lot of research on CCS in Alberta, and the development of a CO2 purity standard will serve as an essential piece of information in developing Alberta’s CCS infrastructure. “This study exemplifies collaboration and partnership among oil and gas producers, emitters and transporters at the national and international level,” said Soheil Asgarpour, PTAC president.

globally in understanding this significant technology, its effectiveness and financial costs.”

Studies by ICO2N indicate that through a phased buildup of CCS, there is the potential to ultimately reduce CO2 emissions by more than 20 million tonnes per year across Alberta over the next decade — the equivalent of annually removing more than four million cars off the road. With the right long-term approach, reductions could grow to more than 100 million tonnes per year, roughly 13 per cent of Canada’s current emissions.

Central Alberta Well Services reduces quarterly loss Central Alberta Well Services Corp.’s revenues increased to $20.1 million in the first quarter of 2010 from $19 million for the same period in 2009. Improved utilizations in the well servicing segment translated to revenues of $15.9 million, compared to $13 million in the same period of 2009. The company reported a net loss of $779,495 for the period, an improvement over the 2009 net loss of $1.43 million.

Cash flow improved to $2.93 million from $2.17 million for the same three months in 2009. Capital spending for the first quarter was only $152,886. Central Alberta Well Services said it realized increased activity in its well servicing segment as the marketing of products to larger energy producers continued to pay off. The company continues to operate a fleet of 46 service rigs and 8 coiled tubing units in this segment.

The company said it continued to examine all areas for additional cost

savings and efficiencies in operations.

Rationalization of staff and revisions in pay structures has resulted in streamlined processes and the conversion of fixed salar y costs to variable wages.

31.9 per cent in the same period of 2009, Central Alberta Well Services said. The well servicing segment is showing improvement in utilization and a slight recovery year over year and it is anticipated that the summer

The well servicing segment is showing improvement in utilization and a slight recovery year over year.

The implementation of new software allows for better communication on purchase request from field personnel to management for approval and centralized ordering, thus reducing time required and providing timely information to management.

The first quarter of 2010 showed the impact of the cost controls that have been put in place through 2009 as gross profit has increased to 34.6 per cent in 2010 from

months leading up to the fourth quarter this year will be more active than 2009.

With the recent debt restructuring, Central Alberta Well Services said it will continue to strengthen its financial position through 2010 with continued cost control and operational efficiencies. The company has no plans for fabrication of any equipment for expansion purposes and will continue to focus on efficiency with the current fleet size.

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Central Alberta

Alberta government negotiates processing arrangement for North West Upgrading refinery Negotiations are underway to build a new bitumen refinery project in Alberta’s Indust r ial Hear t land, nor t heast of Edmonton, as part of the Alberta government’s Bitumen royalty-in-kind (BRIK) initiative, the province announced on May 18. The 150,000-barrel-per-day refinery proposed by North West Upgrading, to be built in three stages, will also include the application of newer technologies and an integrated carbon capture and storage (CCS) capability to reduce CO2 emissions.

“This project has significant potential for Alberta to support the provincial energy strategy goals of increased value-added production and clean energy production,” said Alberta Energy Minister Ron Liepert.

“It’s not a done deal, but I am committed to pursuing an agreement that’s in the best interests of Albertans.”

Processing of the bitumen will go beyond upgrading to synthetic crude oil to include higher value products such as diesel fuel. Once completed, North West

Upgrading would process 75,000 barrels per day of BRIK on behalf of the province.

The project was selected following a comprehensive review of proposals submitted to the government of Alberta as a result of a Request for Proposals that was issued in July 2009 and closed in January.

Upgrading said it submitted a tender in response to the Request for Proposals under the BRIK program in January to process the province’s bitumen barrels. “We believe our tender offers the province a considerable economic return on its resources and a progressive environmental strategy, while

“This project has significant potential…to support the provincial goals of…increased value-added production and clean energy production.”

— Alberta Energy Minister Ron Liepert

As the steward of the resource for Albertans, the Alberta government is entitled to take its royalty share of bitumen production-in-kind, as it currently does for conventional oil production.

Negotiations on the processing arrangements are expected to conclude before the end of the year.

Following five years and 847,000 hours of engineering work, North West

creating a large number of high-value jobs for construction and operation,” the company stated in a news release.

“North West Upgrading’s refining process maximizes the value of bitumen by making high-value finished products, such as ultra low–sulphur diesel, and our technologies mean a significantly reduced carbon footprint for each produced barrel of product,” the company said.

Parkland Energy Services acquires Ace Oilfield for $2.5M Parkland Energy Services Inc. has agreed to acquire Ace Oilfield Construction Ltd., a private Alberta company, from Sandra Woitas and Jane Wyatt for $2.5 million.

The price includes $1.5 million in cash.

Ace is an oilfield construction company based in Sylvan Lake, Alta.

On April 30, Parkland also issued debentures totalling US$1.4 million together with 621,524 bonus shares at a deemed value of $0.23 per share,

representing a partial closing of its previously announced debt financing.

These debentures were issued to related parties to Parkland, including Gordon Hillman, the president of Park land and Hillman Holdings Inc., a company controlled by Hillman, in consideration for indebtedness owing to each of them by Parkland or its subsidiaries.

Following the transaction, Hillman will own or control a 37.61 per cent

interest in Red Deer–based Parkland, compared to 51.47 per cent prior to the transactions. Additionally as a result of the issuance of shares for the Ace acquisition and the conversion of debt to debentures, Sandra Woitas and her family will hold 22.22 per cent of the issued and outstanding share capital of Parkland. Woitas has been a business associate of directors of Parkland for approximately two and a half years.

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Southern Alberta

Demand for fracturing services outpaces overall drilling activity

by James Mahony

The intense application of horizontal multi-stage fracturing is driving the growth of pumper fleets.

Fracturing fleets are seeing very strong dema nd a nd rapid ex pa nsion, t he Petroleum Services Association of Canada’s Investment Symposium heard on June 17. “Fracturing and related services are increasing at a faster rate than drilling, a trend we expect to continue,” Lara King, a financial analyst with investment firm TD Newcrest, told conference participants.

“We’re expecting overall drilling operating days [in the Western Canadian Sedimentary Basin] to be up 40 per cent in 2010 over 2009, rising a further 20 per cent in 2011,” King said. TD Newcrest is forecasting 96,000 operating days in Canada this year, rising to almost 120,000 in 2011, just 2 per cent below 2008 levels.

Fleet utilization numbers will be helped by the reduction of almost 50 rigs in Canada. Contractors are assessing the type of rig likely to work in this new environment, and are cannibalizing

older rigs for parts. As well, some drillers continue to move rigs out of Canada.

“Shallow gas drilling is succumbing to the reality of low gas prices, and although still going strong, some of the urgency may be coming off the Montney and deeper gas programs in B.C.,” King said. On the other hand, Cardium oil plays and liquids-rich gas are driving increases in west-central Alberta. In Saskatchewan, the Bakken and Mississippian oil plays are continuing strong in the southeast, while the Viking and Shaunavon plays are active in the southwest.

“Almost overnight, the Cardium is approaching the Bakken, in terms of oilfocused activity, [and] the wide range of E&Ps [explorers and producers] able to participate in the play lead us to believe that it could take the lead in 2010. Specifically, our analysts estimate that more than $1 billion may be spent on the Cardium this year,” King told the investment symposium.

On the gas side, there were almost 70 per cent fewer gas wells drilled in 2009 than in 2007. The wells still being drilled continue to be mostly vertical. In both Canada and the United States, demand for fracturing equipment and related services has risen exponentially.

Strong crude prices are behind much of the increased interest in oil plays and technological advances are providing the opportunities. Much of this year’s forecast increase in activity will be driven by horizontal wells, which made up just over half of all oil wells drilled in Alberta last year, up from 31 per cent in 2007.

T D Newcrest expects t he trend toward horizontal wells to continue, and fracturing companies will be among the main beneficiaries of the trend. Last year, horizontals made up 29 per cent of all wells drilled in western Canada, up from just 6 per cent in 1999, another speaker said at the event.

Dale Dusterhoft, president and CEO of Trican Well Service Ltd., told the conference his company will add 110,000 horsepower of fracturing capacity this year, boosting the company’s Canadian capacity to 265,000 horsepower by year-end. “You’re seeing increased horizontal fracturing, and we’re seeing our customers move to horizontal wells on a number of different reservoirs.

“In 2008, we were fracturing on just over 5 reservoirs, while last year, it was over 25, and this year, we’ve cracked 30 reservoirs,” he said. “Our customers go through their portfolios, looking at where they can apply horizontal fracturing. That’s a trend that’s not stabilized yet.” Another factor that’s on the rise is the number of fracs per well, which has not yet levelled out. Last year, Trican completed an average 14 fracs per well in the Horn River Basin, while the figure is averaging 20 per well this year.

— DAILY OIL BULLETIN

SOUTHERN ALBERTA WELL ACTIVITY

JUN/09

JUN/10

WELL LICENCES

228

252

▲

JUN/09

JUN/10

WELLS SPUDDED

105

37

WELLS DRILLED

JUN/09

102

JUN/10

29

Source: Daily Oil Bulletin

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Southern Alberta

Stoneham targets more customers and oilier activity Stoneham Drilling Trust wants to expand its client base and become more involved in drilling oil wells. “We’re…seeing an increased interest in activity in oil. I think we’ve got about 37 per cent of our fleet now actually today drilling for oil,” Bruce Jones, president and CEO, told the trust’s annual meeting on June 2.

Stone h a m sa id it cont i nue d to deliver industry-leading rig utilization levels, exceeding the Canadian industry average by 37 per cent in the f irst quar ter. Operating days in Canada rose 71 per cent from last year to 1,104 days, and the contractor’s rig utilization was 72 per cent. As producers continue to pa r t ic ipate i n e x plor at ion a nd development of oil reserves, Stoneham expects its utilization to continue to be well above the industry average.

The scale of the company’s equipment positions it well for resource-style applications, Jones said. Also positive are rosier outlooks from drilling associations. In the most recent one, the Canadian Association of Oilwell Drilling

Contractors is forecasting increased activity in the second half of this year.

The association expects activity in western Canada in both the third and fourth quarters will see an average 50 per cent rig utilization with an average of 400 rigs anticipated in the field. That’s double the previous forecast of 200 active rigs in

Jones said. “We’re not quite sure where Haynesville and some of these other gas plays are going to go, especially given some of the current regulations being discussed, given the fact one of the anomalies [is] the need to drill for land retention.

Once this drilling for retention stops, then we’re not quite sure how many rigs they’re

“We’re…seeing an increased interest in activity in oil. I think we’ve got about 37 per cent of our fleet now actually today drilling for oil."

­— Bruce Jones, President and CEO, Stoneham Drilling Trust

July, August and September. “Because of the new style of drilling, the unconventional resource plays that people are going after…we’re seeing the days on the wells increasing as we get on these long-reach horizontals,” Jones said.

Stoneham’s rig utilization in the first quarter of 2010 was 30.6 per cent in the United States “One of the issues in the Lower 48…is there’s still some uncertainty when it comes to gas in the short-term,”

going to need down there, so we’re just being a little patient.”

The trust, meanwhile, is reviewing its possible future corporate operating structure. Many trusts have been converting to corporations in light of the trust tax deadline of Jan. 1, 2011. “[There’s] no urgency for us at this point in time also because of our [tax] pools,” Jones said. “It’s not necessarily a drop-dead date for us Dec. 31, 2010.”

— DAILY OIL BULLETIN

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J U L Y / A U G U ST 2 0 1 0 • O I L & G A S I N Q U I R E R

Southern Alberta

CanElson acquires Totem Drilling and sets quarterly revenue record Fresh off a first quarter that saw it set a record for quarterly revenue, CanElson Drilling Inc. announced on May 25 that it will acquire Totem Drilling Ltd. for about $40 million in cash and shares.

Totem, a private corporation, owns five fully crewed modern heavy-duty telescopic double rigs (depth ratings of 3,500 metres), purpose-built for horizontal and resource play drilling. “ Tote m’s d r i l l i ng r ig f leet ha s been focused on drilling in southeast Saskatchewan, which currently has the highest rates of drilling activity in western Canada,” CanElson stated. During the 12-month period ended March 31, 2010, Totem operated at 54 per cent utilization compa red to t he average indust r y utilization of 29 per cent. Currently, four of the five Totem drilling rigs are operating, while the fifth drilling rig’s operations are pending completion of recertification.

Mea nwh i le, C a n E l son r ep or te d first-quarter revenues of $11.62 million, compared to $2.98 million for the three months ended March 31, 2009.

The company said it recorded utilization in Canada of 86 per cent for the period, which is the highest reported utilization by any Canadian Association of Oilwell Drilling Contractors contractor.

CanElson increased its west Texas drilling fleet from one drilling rig to three drilling rigs and continued to see improved operating efficiencies in Mexico during its first full quarter of joint venture operations there. The two heavy-duty telescopic drilling rigs added in west Texas include a drilling rig previously constructed in 2009 for operation in Canada, which was subsequently retrofitted and deployed to Texas in January 2010.

As of May 10, the company was operating four drilling rigs in the Western Canadian Sedimentary Basin, three drilling rigs in west Texas and two drilling rigs and one service rig in the Ebano-PanucoCacalilao fields in Mexico.

In Canada, first-quarter operating days (spud to rig release) were 308 versus 114 for the same period last year, while utilization increased to 86 per cent from

70 per cent. The increase was due to a diversification of the company’s customer base and was a result of CanElson’s drilling rigs primarily working in central Alberta, which traditionally has more available drilling days available prior to spring breakup.

During the fourth quarter of 2009, the company commenced operations in the United States and Mexico and the first quarter of 2010 represented the first full quarter of operations in those countries.

There were also two more rigs operating in Canada, and as a result CanElson’s firstquarter 2009 operations vary significantly from the first quarter of 2010.

During the first quarter of 2010, the company incurred $7.08 million (2009: $5.24 million) of capital expenditures related to rig construction and asset acquisitions. During the three-month period ended March 31, 2010, CanElson started and substantially completed construction of a heavy-duty 3,600-metre telescopic double rig and incurred various other miscellaneous construction and capital projects.

— DAILY OIL BULLETIN

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Southern Alberta

Canyon reports record Q1 earnings and a big profit With larger jobs and higher prices for its services, Canyon Services Group Inc. reported record quarterly revenue of $41.46 million in the first three months of 2010, up from $24.1 million a year earlier. Net income was $12 million for the three months ended March 31, 2010, 13 times greater than the $0.9 million recorded last year.

During the quarter, Canyon said it continued to implement its strategy of improving its market share in the Deep Basin of northwestern Alberta and northeastern British Columbia. The company’s increased equipment fleet capacity, which averaged 50,000 hydraulic horsepower (HHP) in the quarter, combined with a much-improved operating environment for the well stimulation industry.

Average consolidated revenue per job increased to $62,646 in the first three months of 2010, representing 30 per cent growth over the fourth quarter of 2009 and a 31 per cent increase over the first quarter of 2009. A shift to larger, higher-priced jobs and improved pricing were the leading factors for the strong revenue performance and higher average revenue per job.

D u r i n g t h e q u a r t e r, C a n y on ’s c u stomer s e x pa nded t hei r c apit a l expenditure programs with a focus on pressure pumping–intensive resource plays requiring significantly more HHP capacity to complete the well. As a result, HHP capacity was strong in allowing pressure pumping companies to improve prices over historically low levels experienced in 2009.

The industry recovery was underpinned by strong oil prices and increased activity in emerging and established oil

plays such as the Cardium and Bakken.

In addition, natural gas resource plays in northeastern British Columbia and northwestern Alberta, such as the Montney and Horn River, were also very active.

I m p o r t a n t l y, e x p l o r a t i o n a n d production companies have increased proportionately the number of oil wells drilled, which accounted for about 50 per cent of all wells drilled in the Western Canadian Sedimentary Basin in the first quarter of 2010, compared to about 30 per cent historically. Also, the higher oil prices

$34.4 million, of consolidated revenues during the quarter, compared to 47 per cent, or $11 million, in the first quarter of 2009. The average revenue per job within this division increased by 34 per cent over the first quarter of last year.

On April 6, 2010, the company closed its previously announced bought deal equity financing and issued 12.31 million common shares at a price of $3.80 per common share for total gross proceeds of $46.8 million. The net proceeds, estimated at $44 million, will be

Canyon completed 661 jobs in the first quarter, up 32 per cent from 502 jobs completed for the same three months last year. have improved the economics of liquidsrich natural gas plays, helping to offset the impact of the ongoing weakness of natural gas prices.

Canyon exited the first quarter with approximately 75,000 HHP and averaged approximately 50,000 HHP throughout the quarter. Subsequent to the quarter, Canyon closed a $47-million equity financing. The net proceeds of the financing will be used to fund the expansion of the pressure pumping equipment fleet to 125,000 HHP. The additional HHP is expected to be delivered by year end.

Canyon completed 661 jobs in the first quarter, up 32 per cent from 502 jobs completed for the same three months last year. The company said its continued penetration into the deeper segments of the market resulted in its Hydraulic Fracturing Division contributing 83 per cent, or

used to fund Canyon’s expanded capital expenditure program.

Capital expenditure programs commencing in November 2009 and totalling $89 million are well underway. In addition to the $16 million spent in the fourth quarter of last year, Canyon invested $20 million in the first three months of this year. The remaining $53 million will be funded from the $44 million of net proceeds from the April equity offering, funds from operations and available credit facilities.

The program is expected to be completed by year-end 2010. The combined capital expenditure programs will add approximately 100,000 HHP of additional pumping equipment, high-rate blending equipment and sand transportation and storage equipment.

— DAILY OIL BULLETIN

Essential buys five coiled tubing rigs and expands capital budget Essential Energ y Ser v ices Ltd. has assigned a letter of intent to purchase five coiled tubing rigs for $2.3 million, including blowout preventers, coiled tubing inventory, trailers and other peripheral equipment. The acquired coiled tubing rigs vary in age and hour usage, but are all relatively new. Essential plans to convert three of the coiled tubing rigs to intermediate depth over the next few months and use two of the rigs as upgrades to the existing fleet.

60

J U L Y / A U G U ST 2 0 1 0 • O I L & G A S I N Q U I R E R

In conjunction with the closing of this transaction, Essential plans to remove three of its older shallow coiled tubing rigs from service. The acquisition will further increase the depth capacity of Essential’s fleet. The company currently has 30 coiled tubing rigs, the largest coiled tubing well service fleet in Canada.

After the acquisition and planned conversions, Essential will have 32 coiled tubing rigs including 17 shallow rigs, 14 intermediate rigs and 1 deep rig. A second deep coiled

tubing rig currently being built is expected to go into service late in the fourth quarter.

Based on the recent improvement in customer activity, Essential has increased its 2010 capital spending budget by $5.8 million.

This increases the company’s capital spending budget from $6.2 million to $12 million.

The incremental spending will include $2.8 million for growth capital and $3 million for net maintenance capital. The increased growth capital will be used primarily to build an additional deep coiled tubing rig.

Southern Alberta

Founding president Roger Soucy retires from PSAC after 29 years technical committees, you don’t really understand how much positive work PSAC does for our industry behind the scenes.

Whether it’s working on government legislation, developing safe and consistent technical procedures, helping member companies manage their staff and HR issues, or providing investors and members with valuable data about the sector, PSAC plays a major role in keeping this massive

and critically important industry working effectively and efficiently,” Yager said.

PSAC represents a diverse range of over 250 member companies, employing more than 52,000 people and contracting almost exclusively to oil and gas exploration and production companies. PSAC member companies represent over 80 per cent of the business volume generated in the petroleum services industry.

Photo: Joey Podlubny

In May, the Petroleum Services Association of Canada (PSAC) announced that a special committee of the board of directors has begun the search for a new president and CEO. Roger Soucy, PSAC president and CEO since the association’s inception in 1981, has announced his intention to retire.

Soucy is the longest-serving oil and gas industry trade association president in Canada. The special committee is striving to have a new president and CEO in place by the date of PSAC’s annual general meeting, which is usually held around Oct. 31.

“In his 29 years of dedicated service, Roger Soucy has done an outstanding job of being the main spokesman for our large and diverse oilfield service sector. PSAC was born in the aftermath of the National Energy Program, and Roger has seen more booms and busts than most of today’s industry and political leaders,” said David Yager, this year’s PSAC chairman.

“Unless you’ve been involved on the PSAC board as I have been for the past five years, or worked with one of its diverse

Roger Soucy as he looked in his original PSAC appointment notice and shortly before his retirement.

Well licensing points to a decade high in oil activity Well permitting for oil is at a decade high in both Saskatchewan and Manitoba so far this year, with Alberta showing its strongest oil year since 2006. Overall, the four western Canadian provinces have issued 3,054 new well licences targeting oil or bitumen deposits in the first five months of 2010.

In normal times, that oil outlook should translate into one of the better years for drilling. However, natural gas operators are showing no more enthusiasm now than they did in the dismal year of 2009, which saw an activity collapse. North American gas inventories are high, and prices are expected to remain low due to the massive supply potential of shale gas.

Only 2,006 new well licences were approved for gas targets in the four western provinces to the end of May, slightly below last year’s 2,063 permits. Those numbers are one-quarter of the peak year of 2006, when operators licensed 8,240 licences to drill for gas for the same five months.

The number of horizontal wells looks set for a new Canadian record in 2010.

Operators secured permits for another 472 horizontal wells in June, bringing the January–May total to a record 2,213 wells, more than double last year’s 1,088 licences. The previous five-month high occurred in 2006, when 1,354 permits for horizontal wells were approved.

Well permitting in the month of May showed a strong surge from last year but

Wells targeting conventional oil in the province have surged this year to 921 from only 208 a year ago. remained the second lowest May count of the past decade. Governments across Canada approved 1,034 new wells last month, 72 per cent more than the 600 approved for the same month in 2009. All four western Canadian provinces and eastern Canada saw an increase from 2009.

A lberta’s Energ y Resources Conser vat ion Boa rd i ssued 4,156 new

licences to the end of May, up from 3,465 a year earlier but still the second-lowest total since 2000. Wells targeting conventional oil in the province have surged this year to 921 from only 208 a year ago, while wells licensed for bitumen development increased to 660 from 381 in 2009.

Saskatchewan has rebounded nicely from an unusually low count in 2009 with 1,436 permits granted through the first five months of 2010, up from 657 a year ago. Because of the absence of gas drilling in Saskatchewan this year, this year’s fivemonth licence total remains below permit counts from 2003 through 2008.

Despite weak gas prices, B.C. well assignments have climbed this year to 440 from only 277 in the first five months of 2009, making 2010 one of the stronger years for activity in the past two decades.

And Manitoba appears headed to a record year with 202 permits to the end of May, up from only 59 at this time last year.

— DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • J U L Y / A U G U ST 2 0 1 0

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Southern Alberta

CSUG report pegs Canada’s natural gas in place at almost 4,000 Tcf A study by the Canadian Society for Unconve nt ion a l Ga s (C SUG) say s abundant shale and tight gas resources have dramatically changed the picture of Canada’s gas potential. The report includes both conventional and unconventional resources and concludes that Canada’s natural gas in place resource is almost 4,000 trillion cubic feet (Tcf) — the marketable portion being between 700 and 1,300 Tcf. “The magnitude of these numbers may blow you away,” CSUG president Mike Dawson said in May. “We have an awful lot of natural gas potential lying within the country.” Of the estimated 700 to 1,300 Tcf of marketable gas, the CSUG report said 357 Tcf are conventional and between 376 (low case) and 947 Tcf (high case) are unconventional.

CSUG’s low- and high-case projections of marketable resources are about two to four times higher than previous estimates. In a 2006 report, the Canadian Gas Potential Committee determined that Canada’s marketable gas resources were at 367 Tcf, about one-quarter of CSUG’s updated numbers.

And Dawson noted that the numbers will almost certainly grow higher, as the assessment doesn’t include some plays that industry is only now beginning to tinker with. “We have collectively over 100 years of natural gas resource potential, even at marketable and low case [projections],” Dawson said. “These resource numbers do not include the emerging [shale] plays…in the Duvernay, the Horn River extension up into the Northwest Territories or the Liard Basin [in northeastern British Columbia, west of the Horn River play] for example.

Those numbers have not been quantified, so they’re not part of the assessment.”

Other excluded plays included the Alberta Montney formation; the Devonian shales in the Mackenzie Valley corridor; the deep thermogenic Colorado group of shales in western Alberta; the St. Lawrence lowlands, save for the part of Quebec’s Utica shale where estimation methodologies could be identified and included; the Central Maritimes basin, located predominately in the Gulf of St. Lawrence with an onshore component in New Brunswick and the southern tip of Newfoundland; and natural gas hydrates.

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“ T his study doesn’t address gas hydrates, and that’s a whole different order of magnitude in terms of resource potential in the country,” Dawson said.

The findings of the CSUG report mirror a similar undertaking conducted by the U.S. Potential Gas Committee, which in 2009 said the Lower 48 states also have about century’s worth of gas supply — about 1,836 Tcf of technically recoverable natural gas resources.

Dawson said that during the past several years, the development and widespread deployment of a variety of horizontal drilling and companion reservoir stimulation technologies has demonstrated that vast additional natural gas resources within coal seams, tight gas reservoirs and shales will play a major role in shaping Canada’s long-term natural gas supply opportunity.

“ The magnitude of these numbers may blow you away. We have an awful lot of natural gas potential lying within the country.”

— Mike Dawson, President, CSUG

According to the report, Canada’s gas in place estimates by resource type are conventional (692 Tcf), coalbed methane (801 Tcf), tight gas (1,311 Tcf) and shale gas (1,111 Tcf).

The report said the emerging nature of much of Canada’s unconventional gas resource is reflected in the “broad range” of potential marketable gas. Broken down by resource type, the CSUG report est imates convent iona l ma rketable natural gas at 357 Tcf, coalbed methane at between 34 and 129 Tcf, tight gas (including British Columbia’s Montney play) in the 215 to 476 Tcf range and shale gas at between 128 and 343 Tcf. “In the past, numbers regarding Canada’s [gas] resource potential have been skewed and all over the map,” Dawson said.

“As far as we know, this is the first time all these numbers have been put in one place.

No question, these numbers are big.”

— DAILY OIL BULLETIN

Energize Alberta will educate a large readership A new publication that links energy to the everyday lives of Albertans rolled out across the province in mid-May. Energize Alberta, a bimonthly tabloid newspaper, will be the largest circulation publication of its type in western Canada. Its readership ranges from downtown Calgary to rural Alberta.

Energize Alberta is the result of a unique divisional partnership within the Glacier Media Group. JuneWarren-Nickle’s Energy Group (JWN), Great West Newspapers and Farm Business Communications have collaborated on the new initiative. JWN publishes the Daily Oil Bulletin, Oilweek, Oilsands Review, Oil & Gas Inquirer and other magazines.

Albertans have a desire to heighten their knowledge of how energy issues impact their lives, noted JWN president and CEO Bill Whitelaw. The publication and its related website will focus on three energy cornerstones: petroleum, electricity and renewables. “Our goal is to link readers to the importance of how improved energy literacy will better equip Albertans to deal with some of the complex energy challenges and opportunities they’ll face in the future,” Whitelaw said. “We’ll tell Alberta’s energy stories through the experiences of the people in the trenches.”

Energize Alberta will be distributed to approximately 140,000 rural households in markets served by Great West newspapers, 40,000 farm households served

by Farm Business Communications and thousands of energy and business offices in downtown Calgary and Edmonton. As well, many companies and organizations have already requested copies to distribute to their own staff.

An advisory group of key energy players — from landowners and students to educators and regulators — provided key input into the product’s focus. “Our readership linkage is unique; there’s nothing out there that connects these communities to each other through a subject that links them so profoundly. Energize Alberta’s focus is to help Albertans connect to their energy future in a way that’s lively and engaging — and educational,” Whitelaw said.

Southern Alberta

Technicoil reports Q1 earnings after nine months of red ink After three consecutive quarterly losses, Technicoil Corporation returned to profitability in the first quarter of 2010, reporting record quarterly net earnings of $3.6 million, up from $0.7 million for the same period of the prior year. Technicoil’s revenue jumped to $24.5 million in the first quarter of 2010, an increase of 44 per cent over the prior year.

Revenue for the well servicing segment increased by 46 per cent to $19.31 million from $13.26 million a year earlier, while drilling segment revenues rose by 39 per cent to $5.21 million from $3.75 million in the first quarter of 2009. The significant improvement in comparison with the same period of the prior year was primarily a result of the record well servicing operating hours achieved and higher drilling rig utilization, the company said.

Continued expansion and penetration of rigless completion services provided by coiled tubing rigs in the Horn River, Montney, Cardium, Shaunavon and Bakken resources plays, together with new markets for the conventional service rigs, were the primary drivers of the firstquarter success, Technicoil said.

The company’s well service segment achieved 17,902 operating hours, of

which 94 per cent were derived from non-fracturing services including rigless completions in the resource plays, drilling support for steam assisted gravity drainage (SAGD) operations by the coiled tubing rig fleet, and conventional well services by the storm service rigs fleet. As of March 31, Technicoil had a modern rig fleet comprised of 17 coiled tubing service rigs and nine conventional service rigs, with an average age of approximately five years.

Tec h n icoi l a lso repor ted record utilization for its well servicing segment of 79 per cent and the highest utilization for the drilling segment since the first quarter of 2006. Similarly, activity levels increased significantly for the drilling segment, which recorded a 44 per cent increase in operating days to 312 days in the quarter. The drilling rigs provided sur face hole dr i l ling prog ra ms for SAGD operations, heavy oil coring and shallow gas drilling during the quarter.

As of March 31, 2010, Technicoil had six drilling rigs available with an average age of approximately five years.

The company said it strengthened its abilit y to pursue additional nonf racturing ser v ices w it h t he coiled

tubing rig f leet, and to work directly for ex plorat ion a nd produc t ion companies and other pressure pumping companies, as a result of the expiration of an operating contract with a pressure pumping company in February 2010.

And it eliminated all outstanding patent and related civil litigation matters regarding certain coiled tubing technology without having a material impact on the assets, liabilities or the current or future prospects of the corporation.

Technicoil said it has repositioned itself to capitalize on the changing trends in the Western Canadian Sedimentary Basin, which has been redefined as a result of horizontal drilling and multiple fractures in the lateral section. These developments have attracted resources away from the conventional shallow gas market to the prolific shale gas and oil plays. A majority of the corporation’s equipment is capable of and presently services segments other than the shallow gas regions including gas development in the Horn River and Montney; oil development in the Cardium, Shaunavon and Bakken; and continued development of the oilsands.

— DAILY OIL BULLETIN

Cathedral Energy plans to build eight testing units Cathedral Energ y Ser vices Ltd. says it is now planning to build eight highpressure production testing units, up from a planned six-unit expansion. All of the units are contracted. Three of the units will be part of Cathedral’s entry into the Marcellus shale play in the U.S. northeast. Another three high-pressure units have now been contracted to a

major oil and natural gas producer in the Montney area in northeastern British Columbia.

T he t wo ot her units w ill be deployed: one i n t he U. S. Ba k ke n region and one in Canada. The company expects the Marcellus units to be operational in the current quarter. The remaining units are all expected to be

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operational upon build-out in early in the third quarter.

Upon the completion of the company’s current build-out of production testing units, there will be 25 units in Canada and 19 units in the United States for a total of 44 units, which represents an approximate 25 per cent increase in Cathedral’s production testing fleet since December 2009.

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Southern Alberta

Trinidad remains “cautiously optimistic” in 2010 DeckX Transport is an open deck transportation company consisting of 200 trucks.

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J U L Y / A U G U ST 2 0 1 0 • O I L & G A S I N Q U I R E R

Lyle Whitmarsh, president and CEO of Trinidad Drilling Ltd., told its annual general meeting in Calgary on May 9 that “day rates in a number of areas have reached bottom, and we are cautiously optimistic for the remainder of 2010.”

The company’s first-quarter 2010 net loss was $791,000, compared to net earnings of $3.9 million in the fourth quarter and a loss of $5.6 million in the same period a year earlier.

The decrease in net loss in the quarter was largely driven by the absence of an impairment of intangible assets of $23.2 million that was recorded in the first quarter of 2009, a lower loss on sale of assets and lower income taxes. First-quarter 2010 cash flow dropped to $40.64 million from $51.48 million a year earlier.

Ensign CFO Brent Conway noted, “Demand in the U.S. has been growing and our Canadian customers seem eager to return to work once breakup is over in western Canada — 2010 has progressed better than we anticipated and we remain cautiously optimistic for the rest of the year.

“We are carefully watching market indicators and we anticipate drilling activity to remain focused on unconventional shale and oil targets until there’s an overall improvement in natural gas pricing,” Conway said. “Moving forward, our most likely avenue for expansion in the near term is redeployment of existing assets into higher activity areas.”

Revenue for the first quarter of 2010 was $170.1 million, up $21.9 million or 14.8 per cent from the previous quarter, as a result of increased operating days, particularly in the company’s Canadian dr i l ling seg ment. In compa r ison to t he sa me qua r ter of 20 09, revenue was down 11.2 per cent, largely due to lower day rates ref lecting weaker industr y conditions, a changing r ig mix and a lower U.S./Canadian dollar exchange rate.

Tr i n i d a d ’s f i r s t- q u a r t e r 2 010 C a n ad ia n d r i l l i ng ut i l i z at ion r ate increased strongly to 67 per cent, up 52.3 per cent from the previous quarter and 31.4 per cent from the same quarter

Southern Alberta

last year. “Trinidad continued to achieve industry-leading utilization levels in the quarter, achieving a level of 15 percentage points above the Canadian drilling industry average of 52 per cent,” Whitmarsh noted.

Howe ve r, t he i mpac t of h ig he r utilization was mostly offset by lower day rates in the quarter. Day rates in the Canadian drilling segment averaged $21,868 per day i n t he f i rst t h ree months of 2010, down 13 per cent from the same period last year and down 3 per cent from the previous quarter, largely due to a change in the rig mix and a delayed reaction to increasing activity levels.

Canadian revenue increased to $84.5 million in the first quarter, up 8 per cent from $78.2 million in 2009 due to higher rig utilization and increased operating days. Operating days increased by 24.6 per cent to 3,170 in the first quarter compared to the same quarter last year despite the Canadian drilling segment having four fewer rigs in its fleet.

The change in rig count from 57 down to 53 reflects the redeployment of four Canadian rigs to Mexico in 2009, the removal of one rig from active marketing and the addition of one new rig in the first quarter of 2010. This additional rig was built to meet customer demand and is operating in the Montney in northeastern British Columbia, under a long-term, takeor-pay contract.

While day rates remained at low levels in the first quarter of 2010, they appear to have stabilized and were relatively unchanged from the previous quarter. “The stability in day rates reflects growing industry activity levels and the impact of increasing demand, particularly for equipment suited for unconventional shale drilling or specific oil plays,” Whitmarsh said.

Trinidad invested a total of $35 million during the three months ended March 31, 2010, compared to $66 million for same period last year. The company is completing its 2010 rig construction program and in addition to the rig added to the Canadian operations in the first quarter, Trinidad will have six new rigs delivered into its U.S. operations under long-term, take-or-pay contracts throughout the remainder of the year.

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— DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • J U L Y / A U G U ST 2 0 1 0

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Saskatchewan

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Crescent Point’s drilling location inventory now stands above 5,000

Crescent Point would like to double its proved-plus-probable reserves over the next three years.

Crescent Point Energy Corp. holds a dominant land position in both the Bakken and Lower Shaunavon plays of Saskatchewan.

Scott Saxberg, its president and CEO, told the company’s annual meeting on May 31 that “we have the potential to more than double our current proved-plus-probable reserves over the next three to five years, just through infill drilling, waterflood implementation and production optimization.”

Its mainly untapped resource pools “provide us with over 5,000 drilling locations and the potential to add over 500 million barrels of reserves, which could potentially double our current [reserves],” Saxberg said.

When including the assets acquired in its recent $1.1-billion purchase of Shelter Bay Energy Inc., as well as the company’s recent acquisition of certain assets in southwestern Saskatchewan from Penn West Energy Trust, Crescent Point’s total

estimated proved-plus-probable reserves currently sits at about 340 million barrels of oil equivalent. At eight wells per section, the company estimates it has an inventory of about 3,800 net drilling locations in the Bakken and 1,500 in the Lower Shaunavon.

company currently operates two waterflood pilot projects in the Bakken field and has received regulatory approval to implement another. With more than 18 months of production data from the first pilot and more recent data from the second, Crescent Point is becoming increasingly confident in the potential for broader application of a waterflood throughout the Bakken resource play.

“We’re going to continue to push the technology here. We’re continuing to move more towards cement liners versus the Packer’s system. We’re moving more towards development of the waterflood then just focusing on primary drilling,” Saxberg said, adding that initial results indicate that waterflood has the potential to increase recovery factors in the Bakken from about 10 to 30 per cent.

“So in 2010…our goals are to really prove up the waterf lood further and improve how we actually do the waterflood,” the company CEO said. “We believe it works very well, but we want to enhance that as best we can. We also want to enhance the completion technique and fine-tune that.”

Saxberg said that by this time next year, Crescent Point will have about six waterflood pilots up and running in the

“We’re continuing to move more towards cement liners versus the Packer’s system. We’re moving more towards development of the waterflood then just focusing on primary drilling.”

— Scott Saxberg, President and CEO, Crescent Point Energy Corp.

In the Bakken, which Saxberg called the “main engine” for the company’s future growth, Crescent Point will continue to pursue secondary recovery and tinker with its completion strategy. The

Bakken and that the company will “be in a position to further expand that.”

After having drilled more than 1,000 wells in the Bakken, Saxberg said the company’s Lower Shaunavon program,

JUN/09

JUN/10

JUN/09

JUN/10

WELLS SPUDDED

164

237

WELLS DRILLED

161

216

SASKATCHEWAN WELL ACTIVITY

JUN/09

JUN/10

WELL LICENCES

140

228

▲

▲

▲

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • J U LY/A u g u s t 2 0 1 0

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Saskatchewan where about 20 0 wel l s have been punched to date, should benefit from experienced gained and that the learning curve will not be steep. “This pool is kind of where the Bakken was three years ago. It has the advantage that we have all the technology and knowledge from the Bak ken…. We’ve got a tremendous amount of knowledge…that we can transfer over into the Lower Shaunavon,” he said.

Saxberg said that because of the Shelter Bay acquisition, the company recent ly i nc reased it s 2010 capita l budget to $750 million from $625 million, and t hat about 15 per cent of the total will be directed toward the Lower Shaunavon, where 70 net wells are planned and an initial waterf lood pi lot prog ra m is e x pec ted to commence. “We’re going to have probably three waterflood pilots running [in the Lower Shaunavon] by the end of the year, before the first quarter of 2011,” he said.

Although Alberta’s Cardium light oil play has garnered a significant amount of industry attention of late, Saxberg and Crescent Point are not the least bit env ious. Instead, he believes his

company’s strategy of consolidating its position in the two Saskatchewan plays bodes well for the future, especially when the fragmented nature of land holdings in the Cardium and the high cost of land there are factored in.

“If you look back and think of some of the newer plays that are emerging in Alberta and elsewhere and the fight that is happening over those plays and how difficult it is to consolidate [land] in a complete play…and decide how it’s going to be managed going forward, it highlights to me that it’s really hard to acquire and obtain large oil accumulations,” Saxberg said.

While Crescent Point plans an active 2010 drilling program involving a total of 331 net wells with the Viewfield Bakken program (185 net wells) and Lower Shaunavon (70 net wells) seeing the drill bit the most, Sa xberg said about $130 million will also be spent on much-needed facility enhancements to service both plays as the company looks to grow 2010 production by about 10 per cent to 61,000 barrels of oil equivalent per day with a forecast exit rate of 69,500 barrels of oil equivalent per day.

— DAILY OIL BULLETIN

Legacy buys more land after Tilston oil discovery Legacy Oil & Gas Inc. says it has established a position in two emerging light oil resource plays, one in North Dakota.

Keying off of the Tilston light oil new pool discovery made in 2009, the company has expanded its opportunity base at Nottingham through an active freehold leasing program and success at the April and June Saskatchewan Crown land sales.

Legacy’s latest horizontal well in the area has been on production since early October 2009 and continues to produce at 200 barrels of oil equivalent per day. Interpretation of the 36-square-mile 3-D seismic survey shot in early 2010 has led to the identification of an extension to the Tilston pool discovered in 2009. The company said it has also identified a new separate Tilston pool, which has been confirmed with the drilling of a successful vertical well.

This discovery well encountered a 14-metre oil column in the Tilston and on completion flowed light oil (38 degrees API)

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J U LY/A u g u s t 2 0 1 0 • O I L & G A S I N Q U I R E R

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Saskatchewan and associated natural gas at significant rates. Legacy said it has identified 22 gross (22 net) horizontal Tilston locations in the area and has plans for a central battery and saltwater disposal facility.

Through a number of transactions, the company has assembled 31,292 gross (25,033 net) acres or nearly 49 gross sections of undeveloped land in Bottineau County, North Dakota. The lands are operated by Legacy (80 per cent working interest) and are located southeast and on trend with the Waskada light oilfield in southern Manitoba.

Legacy expects these lands to be prospective for Spearfish (Amaranth) development opportunities. Offsetting acreage in both Manitoba and North Dakota has seen Spearfish drilling success by other operators, with more than 130 multi-frac horizontal wells drilled to-date, at well densities up to 24 wells per section.

The Spearfish reservoir produces 36 degrees API light sweet crude from a depth of approximately 950 metres. The company is in the process of permitting six wells in the area, with plans to initiate drilling in the third quarter of 2010.

Legacy estimated it will drill 76 (58.7 net) wells this year with its $117-million capital plan, which includes construction

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of a central battery at Taylorton to be followed up with a gas plant in 2011.

Most of the company’s drilling activities t h i s yea r — 6 0 to 65 p er cent — are Bak ken-related at Taylorton and Stoughton-Heward, with the remainder d i rec ted towa rds it s M i ssi ssippia n opportunities. It will also drill nine wells at Fr ys-Sadler in southeastern Saskatchewan.

“We’re not too particular. Because t hey ’re a l l k ind of equiva lent-t y pe opportunities, we’re not fighting land

based private oil company, for total consideration of $18 million in cash a n d 8 .1- m i l l i o n L e g a c y c o m m o n shares. T he share exchange ratio as part of the transaction was determined usi ng a pr ice of $12 .95 per L egac y common share.

T he p r o duc i n g p r op e r t ie s a r e predominately operated with high working interests, 3-D seismic coverage and control of key producing infrastructure and are associated with a light oil prospective undeveloped land base. The acquisition

"Because they’re all kind of equivalent-type opportunities, we’re not fighting land expiries, so whatever gets ready first gets drilled."

— Trent Yanko, President and CEO, Legacy Oil & Gas Inc.

expiries, so whatever gets ready first gets drilled,” said Trent Yanko, president and CEO. Probably 15 wells will be drilled at Taylorton and around 10 will be drilled at Stoughton-Heward, depending on what’s ready in the drill schedule, among other things, said Yanko.

L egac y has a lso ag reed to buy Villanova Resources Inc., a Saskatchewan-

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also adds several key sections of land in Legacy’s Taylorton core area.

Current Villanova production is 1,000 barrels of oil equivalent per day, 100 per cent light oil. Proved-plus-probable reserves are estimated at 4.5 million barrels of oil equivalent. Undeveloped land amounts to 60,818 net acres.

— DAILY OIL BULLETIN

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Saskatchewan

Southeastern region powers Saskatchewan June land sale Heavy interest in the Weyburn-Estevan area helped power Saskatchewan’s June land sale, which produced $46.2 million in bonus bids, the second highest June land sale on record. A total of 36,834 hectares (ha) were sold at an average of $1,255/ha.

Saskatchewan auction revenue is well ahead of last year’s pace. The province has collected $275.8 million year-to-date on 249,670 ha at an average of $1,104/ ha. To the same point last year, the government had brought in just over $36 million on 123, 662 ha at an average price of $291.54/ha.

June’s sale included six petroleum and natural gas exploration licences that sold for $21.4 million and 172 lease parcels that attracted $24.8 million in bonus bids.

Energy Minister Bill Boyd said things have improved this year thanks, in part, to strong oil prices. “Some of that new technology [used in the Bakken] is being employed in other locations in Saskatchewan as well,” he told the Daily Oil Bulletin (DOB). “It ’s also a function, we think, of the confidence

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that companies have in the economy of Saskatchewan and in things like the royalty structure. We’re quite positive with respect to land sales.”

Lands in the southeast once again played a prominent role in the sale, accounting for nearly three-quarters of the total revenue. The total bonus in the Weyburn-Estevan area was $34.5 million, an average of $2,221/ha.

The Lloydminster area brought in $5.8 million, followed by the Swift Current area at $3.2 million and KindersleyKerrobert, which attracted $2.7 million in bonus bids.

Top purchaser of acreage in the Weyburn-Estevan area was Scott Land & Lease Ltd., which spent $19.4 million to acquire 12 lease parcels and two licences.

Top price paid for a single licence in this area — and the land sale overall bonus high — was $10.3 million paid by Scott for a 1,911 ha block adjacent to the Flinton Tilston beds pool, six kilometres east of Corning. The broker acquired the rights to several sections at 11-6W2 and 11-7W2 at an average of $5,432.

Scott also picked up an adjacent 1,807 ha licence for $6.5 million at an average of $3,600, which included several sections at 11-7W2 and 11-8W2.

DOB records show Shelter Bay Energy Inc. was issued a licence on June 9 in the Flinton area at surface location 14-1-117W2 with the Bakken listed as the projected zone. The area has been drilled extensively by industry. PetroBakken Energy Ltd. is a busy operator in the Corning area.

Top pr ice paid for a single lease at Weybur n-Estevan was $4 million

by Mammoth Land Services Ltd. for a 65 ha parcel three k ilometres south of the Heward South Frobisher beds pool, 44 kilometres east of Stoughton.

T his generated the per-hectare land sale high of $62,222 and included the northwestern quarter of section 19 at 8 -9W2. DOB records show Crescent Point Energy Corp. was issued a licence on June 7 at 3-34-8-9W2 in the Heward area, with the Frobisher listed as the projected zone.

— DAILY OIL BULLETIN

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Saskatchewan

PetroBakken outlines its Bakken and Cardium plans for this year PetroBakken Energy Ltd.’s production is 87 per cent light oil and natural gas liquids at a time when crude oil prices are strong. The company boasted a strong operating netback of $52.93 per barrel of oil equivalent and cash flow of $189 million in the first quarter. Yet its share price in late May fell as low as $21.21, down sharply from a high of $35.94 shortly after the company was created last fall.

PetroBakken was created last Sept. 30 from TriStar Oil & Gas Ltd. and the light oil assets of PetroBank Energy and Resources Ltd. Earlier this year, the company did three acquisitions in the Cardium light oil play of central Alberta, where it hopes to apply the multi-stage fracturing in horizontal wells it successfully used in the Bakken.

Gregg Smith, PetroBakken’s president and COO, said the company (through predecessor Petrobank) was the first to use multi-stage fracture stimulations in the Bakken. “We’re opportunity rich with over a million acres of land to work with and over 2,319 locations to be developed,” Smith said. Reserves total about 145 million barrels of oil equivalent.

The company plans to drill more than 100 (net) wells this year in the Bakken using eight rigs. Its program also calls for seven rigs operating in the Pembina Cardium, where it will drill 65 (net) wells in 2010, Smith said. As well, the company plans to have two rigs working in the conventional plays of southeastern Saskatchewan, where it hopes to have 35 wells drilled by year’s end.

In the Bakken, PetroBakken plans to boost its infrastructure by adding two facilities to the north and expanding its main facility. “We will be increasing [the main facility’s] capacity to handle natural gas as we tie in more batteries and wells — conserving natural gas, but also pushing our operational costs lower,” Smith said.

“Ever y well we drill now in the Bakken play is a bilateral, and bilaterals continue to both outperform the singleleg horizontal neighbours as well as the expectations from our reserve auditors,” he said. Reserve auditors “liked what they were seeing” from the bilateral horizontal wells, Smith added, but felt it was too early to recognize that performance in

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the company’s reserve bookings. “So our reserve report reflects the $2.3 million cost for us to drill a bilateral, but does not reflect the absolute performance that we’re seeing from the bilaterals today,” he said.

In the Cardium formation, PetroBakken’s lands are focused in the Pembina area. Smith said the company feels its entry into the play has been “validated to some degree” by what other companies are now paying for Cardium acreage. He displayed a slide showing recent land sale activity.

“The land sales here represent… between $5.5 million and $9.5 million per section of land,” the PetroBakken COO said. With respect to the company’s base-case expectations are for a typical Cardium well, Smith referred to a well that has a proved reserve booking of 145,000 barrels and a proved-plusprobable reserve booking of 250,000 barrels. “So sort of using that as what we’re looking for on an individual-well basis,” he said, “our expectation and hope is that we get better.”

— DAILY OIL BULLETIN

Saskatchewan

Enbridge reports progress on Saskatchewan system expansion Enbridge Income Fund reports progress during the first quarter of 2010 on Phase 2 of the Saskatchewan System Capacity Expansion, which includes three separate projects to address capacity constraints at a variety of locations. All three projects are currently targeted to be complete in the fourth quarter of 2010, said Jim Schultz, president of Enbridge Management Ser v ices Inc. (wh ic h ma nages t he Enbridge fund).

The Benson expansion project on the Saskatchewan Gathering System includes terminal modifications, pump upgrades and installation of new pipe. The Bryant to Steelman expansion project on the Westspur System involves installation of new crude oil pipe, and station and terminal upgrades.

Lastly, the Steelman Crude/natural gas liquids (NGLs) conversion project involves the conversion of an existing NGL line to crude oil on the Westspur System, a new NGL pipeline and pump station on the Saskatchewan gathering system, as well as the conversion of an existing crude oil line to relocate NGLs

from the BP Steelman gas plant to the NGL line at Alida, Sask.

Collectively, the projects are expected to increase crude oil capacity across the system by approximately 125,000 barrels per day at a cost of approximately $120 million.

Construction was completed on the pipeline portion of the Benson expansion project in the fourth quarter of 2009. However, this pipeline will not be placed into service until late 2010, which is when the associated facilities are expected to be complete.

The fund’s assets are a 50 per cent interest in the Alliance Canada Pipeline and a 100 per cent interest in Enbridge Pipelines (Saskatchewan) Inc. Its Green Power arm has a 50 per cent interest in NRGreen Power Limited Partnership, which operates electrical generation facilities using waste heat, and holds interest in three wind power projects in western Canada.

These assets are integral to the pipeline and energy conglomerate run by Calgary-based Enbridge Inc. Enbridge Income Fund is managed by Enbridge Management Services Inc.

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Enbridge Income Fund has announced earnings of $3.6 million for the three months ended March 31, 2010, up from $3.3 million a year earlier. The increase was primarily due to higher distributions received from the Green Power segment, which has experienced improved operational performance in the first quarter of 2010.

“The fund’s natural gas transportation business also saw progress in its organic growth strategy during the first quarter of 2010 with Alliance Canada receiving regulatory approval for two new receipt point interconnections in northeastern British Columbia,” said Schultz. “As shale gas production out of northeastern British Columbia ramps up, we anticipate continued growth in demand for services like these, which offer customers more choice and flexibility at attractive tolls.”

Saskatchewan System first-quarter earnings of $4.9 million increased by $700,000 from the first quarter of 2009.

This increase primarily reflected the positive impact of higher crude oil prices on the sale and revaluation of allowance oil inventory on the Weyburn System.

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Northern Frontier

BP blowout delays plans for highly promising Beaufort oil prospects

Photo: Maurice Smith

by Elsie Ross

The last offshore drilling in Canada’s Arctic was Devon Energy’s Beaufort Paktoa well in 2005­–2006.

As melting sea ice in the Beaufort Sea makes oil tanker shipments through the Northwest Passage more feasible, ConocoPhillips and Chevron Corporation are assessing development options for the large Amauligak oil find. However, operators face potentially crippling political and technical concerns due to the ongoing BP deepwater crude oil blowout in the Gulf of Mexico.

The BP well blew up on April 20. The massive crude spill is ongoing as relief wells are drilled. The National Energy Board (NEB) had scheduled a hearing for this year to examine a key safety policy for the Canadian Arctic. In the event of a blowout, operators must have the capability to drill a relief well the same year. Imperial Oil Limited has argued that the one-year relief well provision is unrealistic for deeper wells due to the short Arctic drilling season.

It is still too early to predict how the BP blowout will affect Arctic drilling in the long term. However, most participants in the proposed hearing told the NEB that they’d prefer to have the proceeding delayed until it’s understood

what triggered the ongoing incident in the Gulf of Mexico.

Lying about 50 kilometres offshore, Amauligak is the largest oil and gas field in the region with an estimated 350 million to 360 million barrels of recoverable oil and 2.3 trillion cubic feet of natural gas. Reservoir sandstones contain up to 125 metres of net oil pay and 50 metres of net gas pay in more than 30 separate sand units, according to an article in 1988 by Robert Sharpe and Gerry Gurba in the American Association of Petroleum Geologists Bulletin.

There are two more oil discoveries, Tarsuit Island and Pitsiulak, within 30 to 50 kilometres. “I’ve got to think they’d be looking at tankers,” says Jim Guthrie, the senior manager in Tuktoyaktuk in the 1980s for Beaudrill Ltd., Gulf’s marine drilling subsidiary and current VP of northern services at Horizon North Logistics. Various pipeline configurations have also been proposed in the past.

In 1986, Gulf Canada conducted an “extended flow test” for the Amauligak well. In three weeks, it produced 317,000 barrels (an average of more than 15,000

barrels per day) of light sweet crude. “It was incredible,” Guthrie says. “This wasn’t a production well, this was just out of an ordinary choke, just free flow.” The crude was sent via tanker to Japan.

In it s a n nua l reg ulator y f i li ng, operator ConocoPhillips, which has a 50.9 per cent working interest, says it is currently reviewing a range of development solutions for the Amauligak significant discovery licence in which it recently increased its ownership. The company periodically updates feasibility plans. Currently, there is no formal project team nor is there any funding associated with the program, emphasized spokesman Rob Evans.

Chevron Corporation says it continues to assess development concept alternatives for the field in which it has a 32.3 per cent non-operated interest, but it has declined to provide further details. Imperial Oil Limited has a 7.3 per cent interest in the Amauligak field, which was discovered by Gulf Canada Resources in 1983.

In 2007, Imperial and ExxonMobil Canada Properties jointly agreed to spend $585 million to acquire access to a 205,321-hectare parcel in the Beaufort.

The following year, BP Exploration Compa ny Ca nada placed a record $1.18-billion work commitment bid to secure an adjacent 202,380-hectare parcel to the northeast.

Last summer, BP conducted a 3-D seismic program over 1,600 square kilometres, the most northerly 3-D survey ever undertaken. The project also had the largest array of towed marine streamers deployed in the High Arctic. The previous year, Imperial also conducted a 3-D seismic program over its Beaufort leases.

In 2006, Devon Canada Corporation drilled the Beaufort Paktoa C-60 well in 13 metres of water just off Beluga Bay. Potential reserves were estimated at 240 million barrels. It has no plans at this time for the well, says spokeswoman Nadine Pettman. “Until the NEB finishes their review, there will be nothing on the horizon,” says Guthrie.

— DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • J U LY/A u g u s t 2 0 1 0

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Central Canada

Major oil and gas labour survey forecasts worker pinch by next year

Photo: Brian Zinchuk, Pipeline News

by Lynda Harrison

The Petroleum Human Resources Council foresees the need for up to 105,000 new workers by 2020.

Even under the most pessimistic growth scenario, Canada’s oilpatch will struggle to find employees this decade, according to a new survey by the Petroleum Human Resources Council of Canada (PHRCC).

The survey also suggests that the labour shortage will be experienced most sharply by the service and supply companies, which do the bulk of field work for the industry.

“What the report makes abundantly clear is that even if growth stalls, the industry will still have a labour shortage due to a lack of supplied workers and retiring workers,” said Cheryl Knight, PHRCC executive director and CEO. “Even in the base scenario, our pessimistic numbers show the industry heading into a tight labour market as early as 2014, needing 15,000 additional workers by 2020.

“That’s a lot of people when you consider that it’s a scenario where conventional gas and oil production falls and the oilsands only hire what is needed to keep up to today’s levels and the projects on the table right now.”

The PHRCC Supply/Demand Analysis 2009–2020 report projects labour demand for the main parts of the industry and

forecasts specific jobs that will be needed into the future. It deals with operational needs only, not construction requirements.

The PHRCC ran two scenarios through an economic model that took into account the industry’s expected production levels provided by the Canadian Association of Petroleum Producers (CAPP), commodity price forecasts and other variables.

The growth scenario foresees a far tighter labour pinch. In it, the need balloons to about 105,000 additional workers. For some occupations, demand will be “extremely high,” said Knight.

Right now, the industry is still in recovery and stabilizing, and some sectors may experience even more layoffs, but employment growth is expected to resume in 2011.

Some employers are already reporting problems finding enough people for certain jobs, Knight said.

The services sector will find it toughest, she added. That sector is growing, it is affected by seasonality, has less appeal to some types of workers because it entails working away from home and outdoors, and it was hardest hit during this most recent downturn. Service and drilling

companies can’t afford to keep people on when they don’t have contracts, so they are most sensitive to what’s going on in the environment, the council’s CEO said.

“Perception and the appeal of that sector may be the most difficult things to overcome, but it’s critical.”

Elizabeth Aquin, senior VP of the Petroleum Services Association of Canada, told the press conference her sector lost 16,000 to 20,000 workers between 2008 and 2009. Trades, engineers, operators and field workers are already in short supply, and many companies are already struggling finding people with the right skills, she added.

Janet Annesley, communications VP for CAPP, said Canada’s workforce growth will come entirely from immigrants by next year, suggesting industry needs to change its hiring practices. “We already have immigrants in Canada who have skills and training that are needed for the oil and gas industry yet we’re not taking advantage of that supply,” she commented.

According to the report, over the next decade, the petroleum industry will be looking for about 3,500 oil and gas servicing and drilling labourers. It will need more than 3,000 operators, both steam and nonsteam — essential for the oilsands, noted Knight; 2,500 heavy equipment operators; 2,000 drilling coordinators and production managers; 1,500 petroleum engineers and almost 1,500 geologists and geophysicists.

The supply/demand analysis will be updated annually. The report’s survey found: • 90 per cent of respondents are currently recruiting due to expansion and/or replacement demand.

• K ey eng ineer ing roles, including chemical, mechanical and petroleum engineers, will experience shortages after 2011 through to 2020.

• Key trades occupations will experience shortages beginning in 2012.

• Non-steam and steam operators will experience shortages beginning in 2012.

• Geologists and geophysicists will experience shortages beginning in 2011.

— DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • J U LY/A u g u s t 2 0 1 0

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East Coast

Georges Bank drilling moratorium gets extended until 2015 Newfoundland well will be tested this summer

Georges Bank is the most westward of the Atlantic fishing banks, located in U.S. and Canadian waters.

The governments of Nova Scotia and Canada will extend the moratorium on oil and gas exploration and drilling on Georges Bank for a further three years, to Dec. 31, 2015.

“We k now that any decision on whether or not to lift the moratorium on Georges Bank could have significant economic and environmental impacts on the province, the country and beyond,” Nova Scotia Premier Darrell Dexter said in a news release. “It is critical that government understands these impacts before such a decision is made.”

The premier said the governments would want solid science and a full public review before making any decision to lift the moratorium. “I have heard the public’s concerns, and I am confident that extending the moratorium will put people’s minds at ease,” he said.

The Government of Canada is committed to the responsible management of Canada’s offshore resources and will continue to work closely with the Province of Nova Scotia on studies and decisions relating to Georges Bank, said Christian Paradis, minister of natural resources.

W hen the moratorium was f irst extended in 1999, t he federal and provincial governments committed to try to work with U.S. agencies as Georges Bank crosses international borders. The United States has also opted to ban oil and gas exploration on Georges Bank.

Both levels of government also agreed to gather and develop information on the delicate Georges Bank ecosystem, particularly about fishing and petroleum activities and technologies.

Research began only recently, and preliminary results suggest there will be more work to do. The extension will allow this process to be completed, as critical research results are expected later this year. Government will then assess the findings and focus on filling research gaps.

A preliminary review is researching potential env ironmental and socioeconomic impacts of offshore petroleum activities on Georges Bank, if permitted.

Another study is assessing technologies and practices in offshore exploration, drilling and production that have been developed since t he 1999 Georges Bank review.

Vulcan Minerals Inc. has been advised by the operator, Nalcor Energy Oil and Gas, that the Seamus No. 1 well in western Newfoundland has reached total depth at 3,160 metres.

The well has encountered a hydrocarbon-bearing zone that warrants flow testing based on gas shows while drilling and geophysical log responses. The zone is behind casing and the well is currently suspended.

In order to determine flow characteristics and the volumes of gas in place, the operator proposes to test the well later this summer with a service rig. This will allow the drilling rig to move to the second well, Finnegan No. 1, which is expected to commence drilling soon.

As well, the company is advised that approval has been received from the Environmental Review Process relating to new road construction required to access the third drill location, Darcy No. 1. New road construction is expected to commence in mid-summer followed by drilling in the fall after Finnegan No. 1 is completed. Seamus No. 1 is the first of a planned three well wildcat drilling program at Parsons Pond in western Newfoundland.

Vu lca n has a 10 per cent nonoperating participating interest in the well. The company considers these earlystage drill results to be very encouraging for the overall exploration of the area, and it looks forward to the forthcoming test results and the continuation of the drilling program.

These wells are the first deep wells to be drilled in this part of the CambrianOrdovician aged Anticosti Basin in western Newfoundland.

Vulcan, a junior, says its strategy calls for recruiting a major partner to help develop a promising discovery.

O I L & G A S I N Q U I R E R • J U LY/A u g u s t 2 0 1 0

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East Coast

Corridor advances drilling projects despite capital budget cut Corridor Resources Inc. reports that Apache Canada Ltd. is commencing drilling operations at the Green Road B-41 well approximately four kilometres north of the village of Elgin, N.B. On a lesswelcome note, low natural gas prices have prompted Corridor to cuts its 2010 capital budget to $42 million from $48 million.

Natural gas revenues decreased to $9.1 million in the first three months of this year from $23.21 million in the first quarter of 2009 due to the decrease in the average natural gas sales price, which resulted largely from forward sale contracts of 10,000 million British thermal units per day at an average sales price of US$14.95 per million British thermal units in effect from Nov. 1, 2008, to March 31, 2009.

During the first quarter, Corridor’s net gas production fell to an average of 14.9 million cubic feet per day (including production from penalty wells) versus 17.9 million cubic feet per day for the first three months of 2009. The company reported a net loss of $695,000 for the

first quarter versus a $6.82-million profit a year ago.

The well near Elgin is the first of a planned two-well commitment program

by Apache to horizontally drill, fracture and test a silty section of the Frederick Brook shale formation as part of a farmout program by Corridor. The B-41 well offsets Corridor’s Green Road G-41 vertical well, which successfully flowed natural gas following fracing operations in two separate intervals within the Frederick Brook shale.

Cor ridor has completed t he mobilization of a coiled tubing drilling rig and associated equipment to Port Menier on Anticosti Island in preparation for drilling four onshore oil exploration wells on the island this summer. The drilling operations are expected to commence at the first well (Jupiter) around the beginning of July. The primary objective of the program is to evaluate the potential for light oil production from the carbonates of the Trenton/Black River formation.

Corridor is partnered with Petrolia Inc. of Quebec for all four wells. As part of the planned drilling program, Corridor and Petrolia plan to cut a conventional core in the oil-saturated Macasty shale (Utica equivalent) in one of the wells to evaluate the shale oil potential of this formation. The Macasty shale blankets the entire island and is estimated

by Corridor to contain very large volumes of oil in place within the Corridor/Petrolia joint lands (approximately 1.6 million acres).

Corridor also has completed perforating the seven-inch casing over several sand intervals within a horizontal section of the L-37 wellbore in the McCully Field in New Brunswick. Initial efforts to flow test the well without stimulation have resulted in relatively low rates of natural gas production.

The well is currently shut in for a pressure buildup before conducting further testing operations. Corridor retains the option to frac a portion of the completion interval if necessary, depending on the results of the current testing program.

— DAILY OIL BULLETIN

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International

Undersea robots play a vital role in containing the Gulf oil spill

Photo: Oceaneering International Inc.

World Energy Congress draws industry leaders

An Oceaneering ROV (remotely operated vehicle) selects a cage-delivered tool one mile underwater.

A subcity of underwater robots is busily working 5,000 feet below the surface to help contain the blowout that has gushed since the Deepwater Horizon blew up April 20, killing 11 workers.

Undersea robots can withstand great pressure, lift up to a ton, take 3-D video images and transfer hydraulic power to other equipment.

The remotely operated vehicles are helping to hook up fluid connectors, hoses and plumbing; install newly developed oil recovery systems; and build the relief wells that are considered the best hope of stopping the BP-operated gusher. On June 23, a robot bumped into the oilcollecting cap placed over the wild well, forcing BP to remove it for about 10 hours.

But there’s been only one other problem in two months.

Pilots operate the robots from comfortable chairs. On the left armrest of each is a joystick that moves the robot’s mechanical arm. On the right is the joystick that manoeuvres the machine through the water. In front of the pilot are 11 monitors, DVD recorders and a sonar screen.

“It’s the most fun job in the world,” said Jef f rey Ha r r is of Ocea neer ing International Inc., which is providing about 14 robots to work on the Gulf spill.

The most popular is the Millennium, an 11.5-foot, 8,000-pound, rectangular, foam-topped device with humanlike arms that has the added benefit of wrists that can rotate continuously like a drill.

The devices using fibre optic technology are what allow the oil industry to drill and remove oil and natural gas from thousands of feet under the water. While a human cannot work in underwater pressures of more than 1,000 feet, these robots have been able to operate in depths of up to 18,000 feet, and for unlimited time, as long as parts don’t fail.

Robots have been part of offshore drilling since the 1980s, said Andrew Bowen, director of the National Deep Submergence Facility at Woods Hole Oceanographic Institution. The technology was first developed by the U.S. Department of Defence to examine downed Soviet submarines.

— THE ASSOCIATED PRESS

It comes every three years and packs a wallop. The World Energy Council (WEC), the world’s foremost multi-energy organization with a stated mission of promoting “sustainable supply and use of energy for the greatest benefit of all people,” is holding its World Energy Congress this Sept. 12–16 in Montreal.

Fa l l i ng n i ne mont h s a f ter t he Copenhagen talks (COP15), around two months after the G8/G20 Summit in Canada and just a few months before COP16, the energy industry urgently seeks solutions to global energy challenges that will require an unprecedented level of cooperation between the energy industry and government.

Overall, 3,500 leaders from all energy sectors are expected to meet in Montreal this September. For the first time, the Youth Program will be fully integrated into the congress program.

“With energy at the heart of current events, topics such as policies and energy sector regulation will be addressed during the issue sessions,” says Stéphane Bertrand, WEC Montréal 2010’s executive director.

More than 200 speakers are scheduled, including Khalid A. Al-Falih, president and CEO of Saudi Arabian Oil Company.

The Financial Times Energy Leaders Summit — taking place for the first time outside of London — will be held in conjunction with WEC Montréal 2010. Twelve other major international energy-related parallel events will take place at the WEC event, including a special meeting of energy ministers from the 70 state and government members of the International Organization of La Francophonie, the 2010 Canadian Energy and Mines Ministers’ Conference, and the American North East and Eastern Canadian Provinces Technical Meeting (NICE).

For more information and to register, visit wecmontreal2010.ca.

O I L & G A S I N Q U I R E R • J U LY/A u g u s t 2 0 1 0

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JOB Careers in the Oilpatch

How did you get your start in the oil and gas industry?

I worked on a service rig one hot summer and wasn’t thrilled with being soaked to the hide in crude oil every day. A friend suggested that the drilling fluids industry was a good choice of careers. Like many people, I trained with a major American fluids company, and gravitated to an independent operator. In my case, I was lucky to have Nick and Joan Nixon at Mudco tuck me and my young family under their collective wings and away we went. When I wanted to go into sales, he gave me a blank cheque and sent me down to Don Forster’s for a bespoke suit. I’ll never forget that. I still have that suit.

What prompted you to move from fieldwork in the service and supply industry into sales of drilling fluids?

Frankly, I think I was better at and more interested in dealing with people and smoothing out problems than I was in furthering myself in the technical department. A natural progression was to earn your chops in the field and sales was the next step up.

What was the biggest challenge in moving from a sales role into a managerial and business development role?

I think that was a smooth transition for me — I am more in my element identifying opportunities and putting people and situations together. My friends joke that I can enter a reception hall knowing no one and leave knowing everyone, including the janitor.

What has been your biggest career challenge and how did you successfully meet that challenge?

Learning to cope with the idea that we cannot always control what happens in our business and that one is not personally responsible for, nor can solve, every problem that arises. It is challenging during downturns when we talk to solid people who are without work and there simply isn’t anything going on in the field.

What advice can you offer someone contemplating a

Photo: Christina Ryan

career in the oil and gas industry?

The best advice I had from the old salts was, “Don’t try to B.S. the guys in the field, listen and watch intently and keep your mouth shut.” Look out for the safety of other guys. Be yourself and remember that humility, being kind and getting along well with people at every level will always serve you well, plus it is the right way to behave.

The only dumb question is the one you don’t ask.

Ted Cutlan Age: 57 Position: International Business Development Consultant Company: Pajak Engineering Years in Position: With Pajak since 2006 Education: Post-secondary studies in English Literature, as well as industry technical training and field experience O I L & G A S I N Q U I R E R • J U LY/A u g u s t 2 0 1 0

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PRODUCER

20 10 SUPPLIER WE NEED YOUR HELP! NomiNatioNs are Now opeN for Oilweek’s 2010 producer aNd supplier of the Year

Every year, Oilweek honours the performance of outstanding oil and gas producers and service and supply companies with our annual Producer of the Year and Supplier of the Year awards, affectionately known as our POY and SOY awards. In 2009, Crescent Point Energy, fresh from its stunning development of the Bakken tight oil reservoir in Saskatchewan, was named Producer of the Year. Packers Plus picked up Supplier of the Year in recognition of its revolutionary multi-stage fracture stimulation technology that has opened shale gas plays to aggressive development across North America, and which is now being used to coax more oil from tighter conventional reservoirs in western Canada.

Take a few minutes to think about producers and suppliers you have come across this year that have made an impact—on you, your colleagues, your industry.

Then, take a few more minutes to nominate them for consideration in Oilweek’s 2010 Producer and Supplier of the Year. The Oilweek editorial team will make the selections, and the winning companies (and runners up) will be featured in the November (Supplier of the Year) and December (Producer of the Year) editions of Oilweek. POY and SOY winners will also be honoured at the 35th Oilweek/ATB Financial Annual Report Awards luncheon in November.

Don’t delay! Nominate your choices for Producer and Supplier of the Year today!

Supplier of the Year nomination deadline August 17, 2010. • Producer of the Year nomination deadline September 18, 2010.

Tools of the Trade

TOOLS

OF THE TRADE A LOOK AT NEW TECHNOLOGIES

Enviro Vault DuoVault

Who is Enviro Vault Canada Ltd.?

People, planet and profit, or the triple bottom line, has always been a cornerstone at Enviro Vault Canada Ltd. Our flagship product is the Enviro Vault, which is an internal chamber in a storage tank that prevents oil spills (or other fluid) and freezing. We are not a tank manufacturer — rather we work with them.

What is an Enviro Vault?

The Enviro Vault is a patented concept whereby a recessed chamber is installed inside the tank with an access door through the tank wall. All valves, sample taps, electronic controls and heater (if required) are mounted inside the Enviro Vault. Enviro Vaults can be fitted in any size or shape of new tank or in-service tank for any specific application — heavy oil, production tanks, produced water, rental tanks, instrumentation packages, separator packages and any other application where a tank is required.

Photos: Enviro Vault Canada Ltd.

What is the DuoVault?

The DuoVault is a tank-in-a-tank design that was developed by Enviro Vault to be a true secondary containment tank. Continuous uninterrupted interstitial space, 110 per cent secondary containment, spill containment, portability and protection from the elements for valves are its competitive advantages.

What is Energy Resources Conservation Board Directive 055?

In Alberta, the Energy Resources Conservation Board (ERCB) Directive 055 regulates the storage requirements for the upstream petroleum industry. In July 2009, the ERCB released the report, Updates to Storage Requirements for the Upstream Petroleum Industry Discussion Document on Directive 055. It indicated that “the majority of releases from tanks are the result of operational issues (e.g. overfilling, leaks and drips from valves and fittings, and spillage associated with inventory movement), not catastrophic tank failures or releases that would be contained by the second wall of a double-wall aboveground storage tank.”

Also, the report says, “ERCB inspectors are finding numerous double-walled aboveground storage tanks configured with manways (the majority are singlewalled) and piping through the walls of the tanks.” Enviro Vault is of the opinion that because of these issues, it was noted in the discussion document that, “the ERCB will require all double-walled aboveground tanks installed after Jan. 1, 2010, to be surrounded by a dike, meeting the requirements specified in Section 5.3.2.1(a) of Directive 055.” This change has yet to be implemented and is not enforced in Alberta to date.

According to the discussion document, “the use of a tank as secondary containment or a tank-in-a-tank assembly is not categorized as a double-walled above-ground tank, provided that the construction, secondary containment and leak detection requirements of Section 5.3 of Directive 055 are being satisfied,” and that “the tank has been designed by a professional engineer practicing in Alberta.”

The DuoVault design has been approved and stamped by an appropriately qualified engineer, which we believe enables oil and gas producers to comply with the ERCB directive and its adopted changes. It should be noted that Enviro Vault is not associated in any way with the ERCB and that the regulatory agency does not endorse specific products.

3-D renderings of the DuoVault tank-in-a-tank design.

Information provided by Mike Nielsen, General Manager, Enviro Vault Canada Ltd.

O I L & G A S I N Q U I R E R • J U LY/A u g u s t 2 0 1 0

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Political Cartoon

Advertisers' Index 1174365 Alberta Ltd . . . . . . . . . . . . . . . . . . . . . . . . 73 1214848 Alberta Ltd . . . . . . . . . . . . . . . . . . . 54 & 63 Accuform Welding Ltd . . . . . . . . . . . . . . . . . . . . . 76 Annugas Compression Consulting Ltd . . . . . . . . . 28 Bear Slashing Ltd . . . . . . . . . . . . . . . . . . . . . . . . . 56 Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . . 76 Beretta Pipeline Construction Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Outside back cover Bilton Welding and Manufacturing Ltd . . . . . . . . . 14 Black Sivalls & Bryson (Canada) Ltd . . . . . . . . . . . 58 Brews Supply Ltd . . . . . . . . . . . . . . . . . . . . . . 31 & 32 Brother’s Specialized Coating Systems Ltd . . . . . 52 Brownlee LLP . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78 Calgary Health Trust . . . . . . . . . . . . . . . . . . . . . . . 70 Canadian Association of Petroleum Producers (CAPP) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 Canadian Enviro-Tub Inc . . . . . . . . . . . . . . . . . . . . . 11 CARES Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 CG Industrial Specialties Ltd. . . . . . . . . . . . . . . . . 66 Christie Corrosion Control (1983) Ltd . . . . . . . . . . 52 City of Grande Prairie . . . . . . . . . . . . . . . . . . . . . . 36 Compass Bending Ltd . . . . . . . . . . . . . . . . . . . . . . 78 Contain Enviro Services Ltd . . . . . Inside back cover

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J U LY/A u g u s t 2 0 1 0 • O I L & G A S I N Q U I R E R

Crompton Western Canada Inc . . . . . . . . . . . . . . . 24 DaimlerChrysler Canada Inc . . . . . . . . . . . . . . . . . . 5 Deck X Transport . . . . . . . . . . . . . . . . . . . . . . . . . 64 DFI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Diversified Glycol Services Inc . . . . . . . . . . . . . . . 64 dmg world media . . . . . . . . . . . . . . . . . . . . . . . . . . 68 Ecoquip Artificial Lift Ltd . . . . . . . . . . . . . . . . . . . . 15 EITI Electrical Industry Training Institute . . . . . . 69 Falvo Electrical Supply Ltd . . . . . . . . . . . . . . . . . . 70 Flexpipe Systems . . . . . . . . . . . . . . . . . . . . . 38 & 39 International Pipeline Conference . . . . . . . . . . . . 76 LJ Welding & Machine . . . . . . . . . . . . . . . . . . . . . . 27 Lloydminster Heavy Oil Show . . . . . . . . . . . . . . . . 82 Lockhart Oilfield Services Ltd . . . . . . . . . . . . . . . 35 LoTech Manufacturing Inc . . . . . . . . . . . . . . . . . . 65 MCI Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 Meridian Mfg Group . . . . . . . . . . . . . . . . . . . . . . . 25 MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . . 41 NAIT Corporate and International Training . . . . . 50 Northgate Industries Ltd . . . . . . . . . . . . . . . . . . . 74 Northstar Energy Services Inc . . . . . . . . . . . . 4 & 48 Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . . . 51 Oil Lift Technology Inc . . . . . . . . . . . . . . . . . . . . . . 20

OilPro Oilfield Production Equipment Ltd . . . . . . 34 Pembina Controls Inc . . . . . . . . . . . . . . . . . . . . . . 52 Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . . . 44 Platinum Energy Services Corp . . . . . . . . . . . . . . 21 Platinum Grover Int. Inc . . . . . . . . Inside front cover PrintWest Communications . . . . . . . . . . . . . . . . . 74 Production Control Services . . . . . . . . . . . . . . . . 55 Propak Systems Ltd . . . . . . . . . . . . . . . . . . . . . . . . 3 Prostate Cancer Canada Network . . . . . . . . . . . . 72 Radafab Oilfield & Industrial Supply Inc . . . . . . . . 10 Suncor Energy Inc . . . . . . . . . . . . . . . . . . . . . . . . . 59 Synergy Alberta . . . . . . . . . . . . . . . . . . . . . . . . . . 78 Systech Instrumentation Inc . . . . . . . . . . . . . . . . 80 TARM Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78 TCA Marketing Ltd . . . . . . . . . . . . . . . . . . . . . . . . . 7 Vertigo Theatre Society . . . . . . . . . . . . . . . . . . . . 72 V.J. Pamensky Canada Inc . . . . . . . . . . . . . . . . . . . 26 Waydex Services LP . . . . . . . . . . . . . . . . . . . . . . . 47 World Energy Congress . . . . . . . . . . . . . . . . . . . . 45 ZCL Composites Inc . . . . . . . . . . . . . . . . . . . . . . . . 17

PIPELINE CONSTRUCTION LTD.

Serving Alberta & Saskatchewan Since 1978 Pipeline Construction: • • • • • • • • •

Facility Construction:

Beretta Pipeline Construction Ltd. offers construction of: New steel and fibreglass pipeline Steel and fibreglass pipeline replacement Lowering and repair of existing pipelines including “clock spring” repairs Oil gathering systems Hot oil transmission lines Oil and condensate transmission lines Gas gathering system and sales lines Road crossings—punched and bored Directional drilling crossing of roads, rivers, muskeg, etc.

• • • • • • • • •

Grassroots construction as well as expansions of: Compressor stations Heavy oil batteries Oil and condensate pump stations Pipeline terminals River waste intake stations Ecology pit construction Satellite installations Pigging facilities Turnkey construction of bulk fuel distribution outlets

PO Box 21042, Lloydminster, AB T9V 2S1

Office: 780-875-6522 Fax: 780-875-6524 E-mail: beretta@telusplanet.net