Oil & Gas Inquirer April 2010

APRIL 2010 � $6.00

Keeping readers regionally informed

We Can Do It!

Canadian Publication Mail Product Agreement #40069240

A sAlute to Women In oIl AnD gAs servICes

Catskinner Dana mcmurray

A tough job with flare lionhead engineering plugs a historic gas well that leaked for decades beside the community of turner valley

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1-877-539-9222 • www.northstar-inc.com SE RVI N G WEST ERN CAN ADA FROM FORT ST. JOHN • GRANDE PRAIRIE • CALGARY • REGINA

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EAGLE DRILLING SERVICES Ltd. ONE MILLION MAN HOURS WITH ZERO LOST TIME ACCIDENTS Carlyle, Saskatchewan, February 1, 2010 – Eagle Drilling Services Ltd. hit another major milestone today when it surpassed one million man hours with Zero Loss Time Accidents (LTA).

“I am very proud our operations are run as smooth as they are, and our people are as diligent toward safety as they are, in order to reach this mark,” says Derrick Big Eagle, President and General Manager, Eagle Drilling Services Ltd. This milestone, a rarity in the Canadian oil industry, was achieved by all the people who have worked for Eagle Drilling Services since the first rig went into the field in 2005.

Their hard work and focus on safety ensured Eagle Drilling has built and maintained such an impressive safety record.

“This is not something a company can buy or acquire, it’s something you achieve. Eagle Drilling achieved this milestone because of the elite and highly-trained staff we have in the field. The men and women who work at Eagle constantly maintain competitive drilling times, overpowering the theory that safety slows you down,” says Rob MacCuish, Chairman of the Board of Directors, Eagle Drilling Services Ltd. The Canadian oil industry holds safety to the highest standard and by reaching this milestone Eagle Drilling is leading the industry by example. Eagle’s worker-friendly rigs allow operations to be run smoother, making them a safer environment for our people.

Congratulations to everyone who was involved in reaching this milestone!

Table of Contents

Keeping readers regionally informed

14 F E A T U R E S

13 18

16

20

22

14 16 18 20 22

24 6

April 2010 • OIL & GAS INQUIRER

We can do it!

by Mike Byfield A salute to women in oil and gas services, from roughnecking to entrepreneurship

Catskinner:

Dana McMurray operates Cats and excavators alongside hundreds of men

Rig hand:

Carolyn Chicoine worked derricks despite her fear of heights

Field personnel recruiter:

Cindy Hames supervises all field staff hiring for Ensign Energy Services

Entrepreneur and CEO:

Sandra Minifie has built a service company, but as a woman she still isn’t allowed to join an oilmen’s association

Instrument mechanic and manager:

Spectra’s pioneer Lisa Stewart sees women as the best solution to the skilled trades shortage

A tough job with flare

by Graham Chandler Lionhead Engineering plugs a historic gas well that leaked for decades beside the community of Turner Valley

Table of Contents

R E G I O N A L

N E WS

29 British Columbia • EnCana plans a tenfold jump in its Horn River output over two years

31 Northwestern Alberta • A spectrum of tight gas plays is evolving in the Deep Basin

33 Northeastern Alberta

55 East Coast • Corridor has big plans for New Brunswick, Newfoundland, and Anticosti Island

57 International • Technology drives Schlumberger/Smith International merger

• Oilsands resurgence draws big, small, and government-owned players • ERCB says Total triggered Joslyn crater

I N E V E R Y

I S S U E

with excessive steam injection pressure

39 Central Alberta • Alberta’s oilsands royalties are expected to eclipse natural gas • Keyera sees reviving activity and strengthens infrastructure plans

43 Southern Alberta • Service firms fear active winter will be followed by weak summer • Western Energy Services buys Horizon Drilling and Cedar Creek

49 Saskatchewan • Birdbear heavy oil play helps spur strong land sale in Saskatchewan • Emerge focuses $55M capital budget on Lloydminster heavy oil

53 Central Canada • Successful wildcat well generates shale gas excitement in Quebec

10 Statistics at a Glance Completions data, spot gas prices, gas storage, drilling activity, and more

59 On the Job Clark Luhning fixes the big valves used in the oilsands. The territory manager for Tyco Flow Control in Fort McMurray has overseen the largest valve jobs ever in Canada, and possibly North America.

61 Tools of the Trade The Ecoquip 9000-6 series of pumpjacks is based on a patented free-floating piston and a nitrogen counterbalance ballast. Its hallmarks are reliability, portability, a small footprint, and a rapid service response when a unit does occasionally go down.

62 Political Cartoon Cover Photo: Aaron Parker

OIL & GAS INQUIRER • April 2010

7

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Editor’s Note Vol. 22 No. 4 President & ceo Bill Whitelaw | bwhitelaw@junewarren-nickles.com

Mike Byfield | mbyfield@junewarren-nickles.com

Rosie the Roughneck

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 EDITORIAL ASSISTANCE

laura Blackwood, Samantha Kapler, Marisa Kurlovich proofing@junewarren-nickles.com CONTRIBUTORS

Graham Chandler, richard Macedo, James Mahony, pat roche, paul Wells CONTRIBUTING PHOTOGRAPHER

Aaron parker creAtive

PRINT, PREPRESS & PRODUCTION MANAGER

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Jerry Chrunik | jchrunik@junewarren-nickles.com Nicole Kiefuik | nkiefuik@junewarren-nickles.com David Ng | dng@junewarren-nickles.com AD TRAFFIC COORDINATOR—MAGAZINES

Elizabeth Mclean | atc@junewarren-nickles.com

During World War ii, the flood of young men into the military prompted North American companies to recruit women for industrial occupations by the hundreds of thousands.

This month, our cover is modelled on a poster drawn in 1942 by J. Howard Miller. “Rosie the Riveter” became an iconic hit song, and the image changed what seemed culturally normal to most people.

When peace came in 1945, most women left the factories, returning home or switching to offices, schools, and other non-industrial occupations. Two generations later, our industries again face a shortage of native-born men for the hard trades. Are women now a viable option in the oilfield?

Read this month’s cover feature and make your own call. During my interviews, however, I was struck by one theme: most oilmen have welcomed these five courageous oilwomen. Inevitably, there are exceptions. Overall, however, their reports indicate good experiences, and I’ve heard the same from other women in oil and gas.

Many moons ago, I served a couple of years in the U.S. Navy. (My mother is Americanborn.) I recall a black sailor—just arriving on our ship—saying that for him there was no racism. To me, this young man seemed foolish. True, the navy did suppress racism very effectively. But resentments still lingered here and there, and everyone knew it.

That sailor turned out to be a great guy, always willing to stand watch for a friend who wanted to go on leave, volunteering for more than his share of the dirtier work details, with lots of jokes and a sympathetic ear for anyone’s troubles. Everybody liked him.

Everybody. For this individual, I realized, there really was no racism. In his life, that form of ill will dissolved like darkness before headlights.

I believe the lady in the poster is right—we can do it.

For advertising inquiries please contact adrequests@junewarren-nickles.com MArketing SENIOR MARKETING COORDINATOR

Alaina Dodge-Foulger | adodge@junewarren-nickles.com MARKETING / TRADE SHOW COORDINATOR

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A sAlute to Women In oIl AnD gAs servICes

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Keeping readers regionally informed

Catskinner Dana mcmurray

A tough job with flare lionhead engineering plugs a historic gas well that leaked for decades beside the community of turner valley

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I S S U E

Automation, instrumentation, and telecommunications Oil & Gas Inquirer gives you a look at how producers and pumping pressure providers manage massive multi-stage fracs in real time from state-of-the-art control centres.

If you know an admirable person to profile in On The Job—he or she may be a veteran or apprentice, field or shop, wise or a little crazy— please give me a call at (780) 784-4251, or email mbyfield@junewarren-nickles.com.

In fact, feel free to sound off about any concern at all—that’s a personal invitation.

OIL & GAS INQUIRER • April 2010

9

Stats

FAST NUMBERS

3.26 Tcf

AT A GLANCE

The National Energy Board says Canada’s natural gas exports fell to 3.26 trillion cubic feet in 2009, down by 7 per cent from 2008 and 14 per cent from the all-time high in 2007.

48 per cent

A Gallup poll taken in March indicates that 48 per cent of Americans believe global warming concerns are exaggerated, compared to 41 per cent in 2009 and 31 per cent in 1997.

Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin

MONTH

OIL

GAS

OTHER

TOTAL

MONTH

OIL

GAS

DRY

SERVICE

TOTAL

Mar 2009 Apr 2009 May 2009

321 111 71

979 344 187

317 140 53

1,617 595 311

Mar 2009 Apr 2009 May 2009

433 111 71

1,121 342 187

165 61 46

86 12 35

1,805 526 339

Jun 2009 Jul 2009 Aug 2009

36 79 101

143 178 212

42 77 80

221 334 393

Jun 2009 July 2009 Aug 2009

177 79 250

211 31 267

45 6 36

27 3 37

460 119 590

Sept 2009 Oct 2009 Nov 2009

146 132 169

155 160 212

78 77 116

379 369 497

Sept 2009 Oct 2009 Nov 2009

146 331 382

155 196 244

45 32 68

9 12 10

355 571 704

Dec 2009 Jan 2010 Feb 2010

121 253 144

127 324 308

35 62 114

283 639 566

Dec 2009 Jan 2010 Feb 2010

283 429 147

138 343 143

34 55 20

13 13 5

468 840 315

Wells Drilled in British Columbia

Wells Drilled in Saskatchewan

Source: B.C. Oil and Gas Commission

Cumulative to March 5, 2010 Source: Saskatchewan Energy & Resources

MONTH

WELLS D R I L L E D

CUMULATIVE *

Mar 2009 Apr 2009 May 2009

75 33 26

317 350 376

Jun 2009 Jul 2009 Aug 2009

19 34 36

395 429 465

Sept 2009 Oct 2009 Nov 2009

38 29 39

503 532 571

Dec 2009 Jan 2010 Feb 2010

45 65 71

616 65 136

*From year to date

OIL

GAS

OTHER

D RY

Vertical Wells

lloydminster Kindersley Swift Current Estevan

112 3 13 21

4 0 54 0

2 1 1 6

5 4 2 20

123 8 70 47

7 38 22 179

0 0 0 0

0 0 0 3

0 0 1 0

7 38 23 182

119 41 35 200

4 0 54 0

2 1 1 9

5 4 3 20

130 46 93 229

Horizonal Wells

lloydminster Kindersley Swift Current Estevan Total Wells

lloydminster Kindersley Swift Current Estevan

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April 2010 • OIL & GAS INQUIRER

T O TA L

FLATpak umbilicals offer a wide range of dual and triple options, tailored to your specific needs

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

GAS STOR AGE

Source: Natural Gas Exchange Inc.

Source: U.S. Energy Information Administration

4.75

2.25

$3.90/GJ Total vol.: 1,251 TJ Transactions: 154

4.25

3.75

in the United States

Feb 22

Mar 1

Mar 8

1.63 Tcf Year ago: 1.89 Tcf 5-year avg: 1.61 Tcf

1.75

1.25

Mar 15

Feb 12

Feb 19

Feb 26

Drilling rig Count by province/Territory

Drilling Activity: Oil & Gas

Western Canada March 16, 2010 Source: Rig Locator

Alberta February 2010 Source: Daily Oil Bulletin

ACTIVE

DOWN

TOTAL

ACTIVE (Per cent of total)

Western Canada Alberta

232

321

553

42%

British Columbia

70

44

114

61%

Manitoba

11

5

16

69%

Saskatchewan

62

59

121

51%

559

242

801

70%

2

2

4

50%

WC Totals Northwest Territories

OIL WELLS

Alberta

GAS WELLS

Feb 10

Feb 09

Feb 10

Feb 09

Northwestern Alberta

45

29

89

114

Northeastern Alberta

8

22

1

0

Central Alberta

66

47

51

145

Southern Alberta

25

20

167

631

144

118

308

890

TOTAl

Service rig Count by province/Territory

Drilling Activity: CBM & Bitumen

Western Canada March 16, 2010 Source: Rig Locator

Alberta February 2010 Source: Daily Oil Bulletin

ACTIVE

DOWN

TOTAL

ACTIVE

Western Canada Alberta

291

676

57%

British Columbia

25

12

37

68%

Manitoba

11

2

13

85%

Saskatchewan

111

64

175

63%

532

369

901

59%

1

1

2

50%

Quebec

COALBED METHANE

Alberta 385

WC Totals

Mar 5

Tcf

Cdn$/GJ

BITUMEN WELLS

Feb 10

Feb 09

Feb 10

Feb 09

Northwestern Alberta

1

3

1

3

Northeastern Alberta

0

0

8

21

Central Alberta

27

75

30

20

Southern Alberta

47

123

0

0

TOTAl

75

201

39

44

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Cover Feature

We Can Do It! A salute to women in oil and gas services, from roughnecking to entrepreneurship

by Mike Byfield

s the huge baby-boom generation reaches retirement age—a person born in 1945 turns 65 in 2010—the upstream petroleum sector faces a labour shortage of large proportions over the coming decade. Fortunately, today’s oil and gas technology makes it far easier for women to help meet that personnel challenge.

Power tongs have vanished from auto automated drilling rigs. No job in the patch is messier than the traditional ser service rig, but workers stay clean on a coiled tubing service rig. From power steering to single-person bedrooms in camps, the mod modern oilfield is evolving quite naturally into a femalefriendly workplace.

Illustration: J. Howard Miller

For the five pathfind pathfinders profiled here, the energy sector is home. If their experi experiences ences are any indication, they will be fol followed by many more oilwomen within the near future.

OIL & GAS INQUIRER • April 2010

13

Dana McMurray has been working on wellsites since she was 14.

Catskinner Dana McMurray operates Cats and excavators alongside hundreds of men

When Dana McMurray arrived at imperial Oil’s Kearl Lake oilsands project, many of her male co-workers wondered how the 26-year-old catskinner and excavator operator landed her job. K2 Mining, under contract to Imperial, has well over 200 heavy equipment operators at work on the future mine site, but only four women are on McMurray’s crew (one of three crews on the site). “Guys just seem to naturally suspect that a woman in my situation might have a family member or boyfriend in management,” she says. “Once the guys see you actually have a clue and can run the equipment, you’re fine. If you’re a woman up here, respect definitely has to be earned.”

She’s a third-generation oilpatcher from Blackfalds, Alta., near Red Deer.

Her grandfather was a drilling consultant, her father runs a petroleum-focused 14

April 2010 • OIL & GAS INQUIRER

NAME: JOB: AGE: COMpANy: lOCATiON:

Dana McMurray Heavy equipment operator 26 K2 Mining Kearl Lake, Alberta

“If you’re a woman up here, respect definitely has to be earned.”

construction firm, and an uncle owns a flock of low-volume oil and gas wells.

“We’re an oil family. My sister Hannah, who’s only three years old, likes to go through industrial auction catalogues and magazines naming the different types of equipment in the photographs,” McMurray says. “I was 14, maybe even younger, when I started mowing weeds and doing manual labour on lease sites with my brother. We also did things around the shop.”

Trained on highly maneuverable skid loaders (commonly called bobcats) by her father, the high school graduate naturally moved on to excavators, whose controls are similar. McMurray got an important break when Pidherney’s, a construction and trucking outfit based in Rocky Mountain House, Alta., hired her for a camp-based job near Hinton, Alta. Laid off due to the downturn in natural gas– focused activity, the female operator then headed for Kearl Lake, an $8-billion openpit mining project located 80 kilometres northeast of Fort McMurray.

McMurray now lives in a camp about a 15-minute drive from the mine. Each worker has his or her own room, with one bathroom shared between two people.

“Actually, the guys here act like a big bunch of girls would behave without men around—they bitch and bicker with each

Photos: Aaron Parker

Cover Feature | We Can Do It!

Photos: Aaron Parker

We Can Do It! | Cover Feature

Dewatering Power

McMurray says oilsands workers are “just cleaning up the world’s largest oil spill.”

other, especially getting near the end of our days in. We work 20 days, then get 10 days off, so people miss their families. In fact, it’s impressive how many of the older men manage to maintain stable families despite being forced to spend so much time away from home. Unlike some of the younger guys, you don’t see them negotiating ‘extra services’ from the female camp attendants.”

K2 Mining began draining muskeg with ditching and is now stripping overburden and finishing the future plant site. The site for the dike’s foundation has been prepped and after spring breakup construction will begin on the dike itself.

“The dike is going to take about 18 months.

Altogether, this is projected to be around a three-year project,” McMurray says.

How does she feel about the international notoriety generated by the oilsands, in particular the tailings ponds? “At Kearl Lake, we’ve hit bitumen as close as one metre from the surface,” the heavy equipment operator replies. “If that oil came from a well, the environmentalists would be freaking out about an oil spill. I agree with my grandfather, who says we’re just cleaning up the world’s biggest oil spill.”

Kearl’s total recoverable bitumen is estimated to be 4.6 billion barrels.

McMurray spent most of her time in excavators prior to Kearl Lake but appreciates the opportunity to acquire more experience on bulldozers. Far from considering herself macho-brave, she refuses

to drive the huge heavy haulers that haul up to 240 tonnes. “They threw me in one of those big trucks [a Caterpillar 777] and gave me a ride-along. I knew right away that it wasn’t for me,” the operator says.

“Too many blind spots, they move fast, and there’s lot of traffic. I prefer crawlers, not rubber tires.”

In November, a 41-year-old woman driver was killed when two heavy haulers collided at Syncrude Canada’s Mildred Lake North oilsands mine. “One of the drivers wasn’t wearing a seat belt and we sure got the seat belt lecture big-time about that,” McMurray says. Kearl Lake’s safety record is reassuringly strong, in her view. “This project had more than two million work-hours without a serious incident before someone flipped a gravel truck.

Now we’re back to about 500,000 hours.”

How can a woman (or man, for that matter) get started in driving heavy equipment? “Generally, you have to begin as a labourer. When you work your way up to operator, you’d normally work first on something slow and easy like a packer,” McMurray says. In her experience, bias isn’t a decisive barrier to getting ahead. In fact, at Kearl Lake, there’s a diverse range of people: Aboriginals, French Canadians, and Newfies, to name a few. “No matter who you are, you’ll get skidded out if you screw up. If you’re good, you’ll be treated fine. Honestly, this would be a great job if it was an hour from home.”

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15

Photos: Brian Zinchuk, Pipeline News

Cover Feature | We Can Do It!

Like many female oilfield workers, Carolyn Chocoine grew up in the patch.

rig hand Carolyn Chicoine worked derricks despite her fear of heights

Green hands are usually nervous when they first arrive on a drilling rig, intimidated by heavy metal and unfamiliar movements. “I was scared even though my toolpush and my driller were my brothers, and my dad helped start Big Sky Drilling,” recalls Carolyn Chicoine. “It was a jackknife double. We were on short holes that only took about three days, so I got familiar with the drilling process pretty quick.

In just a week or two, I felt comfortable on the rig floor.”

Chicoine spudded her first well in the summer of 2005. Raised in the southeastern Saskatchewan village of Storthoaks, she’d just graduated as an English major from the University of Regina. “I was planning to get my education degree the next year.

Roughnecking was supposed to be a summer job, but I loved it and never did go back to college,” says the 27-year-old rig technician. “In eight months, I was put on motors and later I worked as a relief derrickhand.”

16

April 2010 • OIL & GAS INQUIRER

NAME: JOB: AGE: COMpANy: lOCATiON:

Carolyn Chicoine Rig technician 27 Big Sky Drilling Storthoaks, Saskatchewan

“If you let the teasing get to you, they’ll just do it more.”

After four years on the rigs, Chicoine opened a bar in Storthoaks in 2009. It’s called the Doghouse, named after the steel-sided crew room that’s adjacent to the rig floor. “The bar was supposed to be a fallback because the drilling business is so up and down, but it’s become kind of permanent,” Chicoine says. “I’d prefer to go back to drilling—I really enjoy being out of doors with a crew doing physical work—but for now I can’t find anyone else to run the Doghouse.”

Her most challenging labour on a rig was shifting heavyweight drillpipe through the V-door. (This opening, shaped like an upside down V, enables pipe and long tools to be moved in and out of the derrick.) “Do that for a couple hours and you’ll be tired,” Chicoine says. “Still, I never felt that roughnecking was too much for me. Tripping in and out of the hole with the tongs was something I actually enjoyed doing for half a shift. It’s harder work, but the crew is together and chats, which made me feel more upbeat.”

Although many of her fellow workers over the four-year period “did not know the Chicoine family from a hole in the ground,” the rig tech experienced no harassment beyond the teasing that’s normal among drilling crews. “You get told to take a big bucket sample to the geologist [who actually requires only a cupful of sample rock cuttings from the hole] or someone tells you to get the key to the V-door [which

Photos: Brian Zinchuk, Pipeline News

We Can Do It! | Cover Feature Chicoine, seen here with helper Brooklyn Garnier, now runs the Doghouse bar in Storthoaks but she would like to return to the rigs.

actually has no door],” she says. “If you let the teasing get to you, they’ll just do it more. I was lucky because my brothers warned me about most of those tricks.”

To this day, Chicoine remains uncomfortable on a roof due to her fear of heights.

Even so, she performed effectively as a derrickhand at the top of the rig. “I got to love working on the doubles, although a triple did seem high,” the oilpatcher recalls. “You feel safe up there because you’re always wearing a safety belt and fall arrester.” On the rig floor, a swinging elevator jammed her elbow into the

drillpipe stump and fractured her arm.

“Fortunately, I didn’t need surgery or pins, and I wasn’t afraid to return to work,” she comments.

Chicoine’s father Brian is an imposing figure, known throughout the region as the “big guy from Big Sky.” (The company was acquired by Ensign Energy Services Ltd. three years ago but he remains general manager.) His daughter, in contrast, stands five foot two. Although she hasn’t run into many female rig hands, “I do have a girlfriend who’s doing it.” she says.

In her view, an average-size woman with

determination can roughneck successfully, even on a drilling rig that lacks automated pipe-handling equipment.

Driving to and from the rig every day is probably the most dangerous aspect of the work, in her judgment. “I never hesitated to pull over to the side of the road and sleep, and that’s very important,” Chicoine says. “The nice thing about working at the Doghouse is not having to drive two hours every day to get there. The bar is doing fine, we’re making a living, we get a lot of oilfield guys in here—but I miss working on the rigs.”

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OIL & GAS INQUIRER • April 2010

17

Cover Feature | We Can Do It!

Cindy Hames says rig experience can become the foundation of many other careers in the oilpatch.

Field personnel recruiter Cindy Hames supervises all field staff hiring for Ensign Energy Services

As a little girl, Cindy Hames often sat in a truck cab watching her father move rigs in the Lloydminster area of Alberta. “To me, seeing a drawworks or some other huge hunk of steel being hoisted through the air seemed ordinary,” says Hames, the Nisku-based director of Global Strategic Management–Field Resources for Ensign Energy Services Inc. “Now I understand that our industry isn’t ordinary at all, that we actually require extraordinary individuals. Whether you’re male or female isn’t the question.

“How strong is your mechanical aptitude? Can you work physically for a 12-hour stretch, day after day? Can you endure isolation? Can you integrate well within a team? Can you cope with a business that’s both seasonal and cyclical? If necessary, would you be willing to work overseas? Ensign’s field jobs are certainly not for everyone. However, the right individual—man or woman—can enjoy what I would call living large.”

Ensign ranks among Canada’s largest drilling and service rig operators, along with its other divisions. Female applicants can rest assured that gender bias 18

April 2010 • OIL & GAS INQUIRER

NAME: Cindy Hames JOB: Director of Global Strategic Management–Field Resources AGE: 39 COMpANy: Ensign Energy Services Inc. lOCATiON: Nisku, Alberta “The issue is not gender, it’s individual character.”

won’t limit their chances of being hired as a green leasehand, Hames promises.

“A couple of years ago, during the boom, I had 12 field recruiters working for me.

Only one was a man. With the activity downturn, we’ve cut back to four recruiters, three of which are women.”

Although Hames has a degree in sociology from the University of Alberta, her own career at Ensign started with a routine clerical position. “The oil and gas service sector is a business where people work their way up, and being female doesn’t limit your opportunities,” says the 39-year-old manager. “On one of our rigs, gender is pretty much a non-issue in my experience—what counts is whether you do the job well.”

A rig hand needs upper body strength, according to Hames, with endurance and coordination being more important than muscle mass. “Can you carry a 88-pound bag of gel over uneven ground to the mixing shack, repeatedly over the 12-hour tour? Can you learn the body motion that’s needed to swing tongs [when tripping drill pipe in or out of the hole]?” she queries. “We’ve had 130-pound women who did fine as rig hands. I’ve also seen a bodybuilder whose showpiece muscles lacked the necessary endurance. In general, Ensign has more women working on our wireline and production testing operations. That’s partly because those jobs are normally nonrotational and closer to home.”

Ensign isn’t concerned that most women will eventually marry and have children. “We’re happy if a field employee gives us five years,” Hames says. The initial attraction for the typical new recruit is cash, she adds—for example, $23 an hour to start working on a drilling rig. But beyond wages, oilfield skills can later lead to other careers for a woman (or man).

“Our maintenance shop foremen love

We Can Do It! | Cover Feature

getting a person with field experience,” the recruiting director notes. “We also have plenty of women working in safety, in personnel, in our operations centres, and elsewhere in the company—and these are all areas where field experience is valued.”

NAIT, SAIT Polytechnic, and other educational organizations also prize oil and gas field skills when hiring instructors. So do a wide variety of service companies looking for sales and marketing personnel, purchasing agents, and qualitycontrol specialists. Petroleum veterans who are willing to acquire further education find that their field experience gives them a leg up with employers in search of welders, drafting technicians, machinists, and other occupations, up to and very much including professional technologists and engineers.

No one heads out to an Ensign rig in less-than-safe shape. The company gives applicants a thorough physical before they’re hired, checking cardio, flexibility, strength, and related factors. “Our highest failure rate on the physical is among males 18 to 25, the Nintendo generation that’s spent its life in front of a computer,”

Hames worked her way up from a clerical position.

Hames says. “The people who do better tend to have spent some time as labourers in construction or on a farm, or they may be active in sports. Once a new hire is on the job site, the key factors are work ethic and attitude. Do you listen carefully?

When you see someone working, do you immediately go help or do you continue standing around? Again, the issue is not gender, it’s individual character.”

Of course, females remain vastly outnumbered in the oilfield by males, and that situation will evolve only gradually. “So far, none of our women has risen above motorhand [one did work as a temporary derrickhand] on a drilling rig, primarily due to their own personal choices,” Hames says.

“On the other hand, we’re going to need more women, including in the field. Our industry is heavily weighted toward people who will soon be retiring in large numbers.

Fortunately, technology is making our field equipment easier, safer, and even cleaner to work with. An Ensign ADR [automated drilling rig], for example, has no tongs. So the working environment is getting steadily better-suited to women just when our industry is really going to need them.”

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OIL & GAS INQUIRER • April 2010

19

Cover Feature | We Can Do It!

Sandra Minifie loves the oilpatch and Dawson Creek.

Entrepreneur and CEO Sandra Minifie has built a service company, but as a woman she still isn’t allowed to join an oilmen’s association

Sandra Minifie has built up Action Health & Safety Services around a straightforward concept: first-aid attendants and paramedics can also help with security and safety duties at remote oil and gas sites. “Why should a medic just sit in an MTC [mobile treatment centre]? By combining the onsite first aid role with other duties, everyone wins. Our customers receive added value, while our employees benefit from being more broadly trained,” says the oilfield entrepreneur.

“We were the first service provider to adopt this approach in northeastern B.C. It’s gone really well. Our company employs upwards of 60 people,” Minifie says. As a woman working in the patch, the Action CEO values the cooperation that she’s received from petroleum producers and most of her service sector colleagues. “I love Dawson Creek,” she says.

“It’s a friendly, stable city in an attractive area—I can’t imagine a better place for Ward [her husband] and me to raise our three children. The winters are long here, but most long-term residents make 20

April 2010 • OIL & GAS INQUIRER

NAME: Sandra Minifie JOB: President COMpANy: Action Health & Safety Services lOCATiON: Dawson Creek, British Columbia “A previous president [of the South Peace Oilmen’s Association] suggested that as a woman I could tend bar at the monthly meetings or we could start an oilwomen’s association.”

enough money to take a winter break in a warm country.”

In return, Action strives to add value to its community. In 2007, despite the slowdown in oilfield activity, Minifie brought in instructors from the University of Alberta to train 20 local people in occupational health and safety. More than onethird of the company’s employees come from three local Metis communities. In 2008, as a public service, Action created a training video, in partnership with the

STARS Air Ambulance service and Encana Corporation, on preparing a remote site for a helicopter medical evacuation.

In one respect, though, this oilwoman has found the petroleum industry less than welcoming. “For several years, I’ve tried to join the South Peace Oilmen’s Association, but they’ve rejected me on the grounds that I’m female,” she reports. Association president Terry Wheeler says the Dawson Creek–based group has always been a social club whose monthly meetings are men-only. “We’ve raised a lot of money for charities,” he notes, “and everyone can take part in our annual [curling] bonspiels, golf tournaments, and lobsterfests.”

All true, responds Minifie. “It’s a valuable organization that happens to be the only oil and gas venue in Dawson Creek,” she says. “Until Ward joined our company a year ago, Action’s managers were all women—none of us qualified to join the association. A previous president suggested that as a woman I could tend bar at the monthly meetings or we could start an oilwomen’s association. In that case,

We Can Do It! | Cover Feature though, there wouldn’t be the same opportunities for networking and mentoring.”

Not that business executive lacks for extra-curricular activities. “I sit on a number of boards and committees, including the Bear Mountain Ski Hill and a Malawi girls’ educational program,” she says. “Our company provided winter clothing to 22 people who had no daytime shelter, we support Ducks Unlimited, the oilmen’s [association], we sponsor several sports teams, and we are huge supporters of the Encana Events Centre.” Her husband and she also sit on provincial and industry committees targeting health, safety, regional promotion, and Northern Lights College.

Raised in Prince Rupert on the Pacific coast, Minifie has previous experience in a traditionally male work environment. The Russian linguist served 10 years with the Canadian Forces. Her military occupation, monitoring overseas communications, had only recently been opened up to females because it often involves being based in remote locations. At Alert, an Arctic listening post about 800 kilometres from the North Pole, the garrison of 250 included just 20 women.

Minifie employs more than 60 people.

“At that time, the Soviet Union was breaking up and its internal conditions were pretty chaotic,” the businesswoman recalls. “We’d listen to airline pilots drinking on the job and they often ran out of fuel.” (Due to a lack of cash, Russian aircraft would carry just enough fuel to make a flight, then find themselves forced to land unexpectedly if the weather proved more adverse than forecast.) Minifie joined Action Health & Safety in 2005

under its founder Gary Caldwell, taking over as president and owner in 2008.

In the ongoing gender debates, this British Columbian sometimes finds herself sympathetic to men. “Reverse discrimination can and sometimes does go too far. For instance, the Boy Scouts got a court order to admit girls while the Girl Guides are permitted to remain girls-only. That’s ridiculously unfair,” she says. “I also saw the stresses that can result when you throw a few females among a bunch of guys. A woman who’s a ‘3’ down south was a ‘10’ at Alert, and some women handled that situation poorly.”

Ironically, the entrepreneur endorses men and women having gender-separate social clubs, sports teams, and so on.

“That’s human nature. There are limits, though. When an organization is industryoriented, I believe any responsible person from that industry should be eligible to join.” Looking forward, Minifie says she will never take the South Peace Oilmen’s Association before a human rights commission or law court. “On balance, the oil and gas industry has been good to me— very good, in fact,” she comments. “Social change takes time, but I’m confident that sooner or later we’ll get it right.”

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OIL & GAS INQUIRER • April 2010

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Cover Feature | We Can Do It!

Lisa Stewart wants to start a stakeholder group encouraging women to enter skilled trades.

instrument mechanic and manager Spectra’s pioneer Lisa Stewart sees women as the best solution to the skilled trades shortage Time: 2 a.m. Temperature: Minus 32 degrees Celsius. Place: Compressor station at Yoyo, about 150 kilometres east of Fort Nelson in northeastern British Columbia. The natural gas compressor has been knocked offline due to frozen liquids in the inlet separator.

Unable to resolve the problem on his own, the station operator has called for specialized help, and now he sees headlights coming through the dark. The grizzled veteran steps out to greet the technician, then does a double take when a pretty young blonde jumps out of the pickup.

“Twenty years ago, it was shocking for some of the older men when I started working in the field,” recalls Lisa Stewart, who today is a maintenance planning team lead for Spectra Energy. An industrial instrument mechanic at the time, Stewart was the second woman in British Columbia to earn that ticket. (Her predecessor became an instructor.) The Fort St. John resident subsequently earned a 22

April 2010 • OIL & GAS INQUIRER

NAME: Lisa Stewart JOB: Maintenance planning team lead COMpANy: Spectra Energy lOCATiON: Taylor, British Columbia “As a woman, you only realize barriers if you stop to notice them.”

master’s degree in business administration from the University of Northern British Columbia. As the final project in her MBA program, Stewart produced a study of barriers to women entering industrial trades in the region’s resources sector.

Like Canada as a whole, Stewart says, the energy sector faces a serious demographic difficulty that has been described as “the pig in the python.” Baby boomers are a huge generation, typically defined as those born from 1945 to ‘60. This year, the first boomers will hit age 65, and a stupendous

spate of retirements is already underway.

Because the boomers had too few children to replace themselves, no large industry can safely rely entirely on Canadian-born males as their sole future source of labour supply.

What are the alternatives? “Hiring programs often refer to women, Aboriginals, the handicapped, and immigrants,” Stewart notes. “Research indicates that any readily identifiable new group of employees will be perceived as ‘different’ by the majority until it makes up about 15 per cent of a labour force. At that level, the discrimination and other problems associated with ‘tokenism’ will disappear,” Stewart says. “Unfortunately, with the possible exception of welding, women do not constitute even close to 15 per cent of any industrial trade in B.C. “Everyone should be treated fairly, no matter who they are. However, practically speaking, the majority of the industrial skills shortfall can most

We Can Do It! | Cover Feature easily be met through training women,” Stewart contends. Aboriginals make up less than five per cent of the provincial population, she points out, while immigrants face communication barriers and tend to cluster in large urban centres.

“Over half of the population consists of women, we live in the region, most of us speak English, and we’re capable of learning these trades.”

Unfortunately, the Spectra Energy manager says, Canadians overwhelmingly want their children, both male and female, to avoid trades in favour of careers that require more academic qualifications. This parental bias persists despite research indicating that skilled trades careers are better paid on average than white-collar jobs. In response, Stewart is now organizing a stakeholder group aimed at getting more women into industrial trades. This committee would include employers, government agencies, women’s groups, and regional development agencies.

“High school is too late to begin the process of promoting trades among students,” the instrument mechanic asserts.

“We need to engage youngsters and their

parents in the stage which they develop their purpose and identity.” Stewart thinks that companies should send male and female tradespeople (not just community liaison specialists) into primary schools to act as role models, and begin providing relevant career discovery programs to junior high students. “Yes, this type of program takes time and money, but employers will start to see results within four years or so,” she comments.

“This investment is essential to securing a skilled workforce for the future.”

When women do enter trade apprenticeships, Stewart advises them to press forward persistently, but she pushes gently against traditional stereotypes. “Pushing too aggressively can slow progress down rather than speed it up. The old boys’ networks are already beginning to break up,” she comments. “Even when you run into one or two individuals who resist change, it’s important to remember that most people do accept the idea of more women working in industrial trades. As a woman, you only realize barriers if you stop to notice them.”

Stewart says tradesfriendly education should start as early as primary school.

OIL & GAS INQUIRER • April 2010

23

Lionhead's crews were working with an exceptionally tight wellsite.

A tough job with f Lionhead Engineering plugs a historic gas well that leaked for decades beside the community of Turner valley

by Graham Chandler | photos by lionhead Engineering

24

April 2010 • OIL & GAS INQUIRER

“In the 1940s, the plan was to pull the casings out and reuse or sell them, as they did not cement the strings in place after setting."

– Will Hewitt, lionhead’s manager of operations

1949 1960

1920

1914

cutters and internal rotating cutters are used to separate casings. This gives more precision on the cuts and protects the formation face from blasting damage.”

In 1981, a service rig re-entered the well in an attempt to abandon the well properly. The crew encountered holes in the surface conductor, which led to lost circulation near the surface and eventually losses from the wellbore to the riverbank. “They couldn’t get past about 30 metres because they were losing circulation,” Hewitt says. “Those lost fluids were migrating through unconsolidated rock

1950

In 1914, the crew reported natural gas in the 968-metre well from seven different levels.

liquids, triggered jubilation in a province that still produced no crude oil. Over time, though, the step-out well deteriorated into a festering embarrassment. In 2008, the well's owner—Alberta Culture and Community Spirit—hired Lionhead Engineering, a subsidiary of CCS Corporation, to fix the problem once and for all. (The Energy Resources Conservation Board granted approval in 1989 for the sale of the well to the Alberta government as part of the historical Turner Valley Gas Plant property.)

“In the 1940s, the plan was to pull the casings out and reuse or sell them, as they did not cement the strings in place after setting,” says Will Hewitt, Lionhead’s manager of operations and QHSE (quality, health, safety, and environment). “When resistance was met while pulling the casing, the crew used nitroglycerin blasts to separate the pipe. The nitroglycerine caused damage to the formation. (It creates a void in some cases.) Today, chemical

1940

hen a cable rig drilled Dingman No. 2 near Turner Valley, Alta., in 1914, the crew reported natural gas in the 968metre well from seven different levels.

For nearly a century, sour and sweet gas seeped along the wellbore to the surface, emerging beside the nearby Sheep River.

Two previous attempts at abandoning the well, in 1949 and 1981, were unsuccessful. Instead, the sour gas was flared, a safe but hardly permanent solution.

The problem well was originally a stepout from Dingman No. 1, drilled earlier in 1914. The discovery, very wet with gas

1930

W

Turner Valley, once called Hell's Half Acre, is actually one of the loveliest districts in Alberta.

Read more about Dingman No. 2 in our April editions of Oilweek and New Technology Magazine.

Oilweek reports on how the permanent abandonment of this historic well opens the door to a new understanding of the industry's legacy. New Technology Magazine describes new technologies being used to secure non-producing wells. For subscription information, call 1-800-563-2946.

h flare

The old well casing was riddled with holes.

fire out, collect the sour gas, and sweeten it,” Bessel says. The seep-fed fire measured about five by ten metres. Lionhead’s solution was to take a membrane and put it over the top “like a plastic bag, to collect the gas,” Bessel continues. "[We inserted] a pipe [through the membrane] and then put [the gas] through a drum filled with granular iron oxide to sweeten it."

To ensure that no further leakage occurred, the company used air monitors, both stationary and truck-mounted units.

Many local residents did not appreciate losing the well-known landmark fire that In 1981 the crew encountered holes in the surface conductor, which led to lost circulation near the surface and eventual losses from the wellbore to the riverbank.

2000

2010 1990

1981 1980

1970

1960

to the riverbank. They eventually set and cemented a 127-millimetre liner at 30 metres inside the conductor.” Without a proper mud system, the team was unable to continue operations.

Al Bessel, a project manager who focuses on engineering regulatory compliance services, says Lionhead started the project with a thorough review of the well records. Six months were invested in an analysis of Dingman No. 2’s unusually long and problematic history. All of the old records are hand-written, Hewitt says, and they were brief. “Mostly one-liners,” he adds. “For a whole day, you’d get a few sentences to determine the operation. So we had to make some assumptions along the way—for example, we had to assume they met the licence requirements of placing cement plugs after they pulled casings.”

Before any rig could work on the site safely, that open flame by the river had to be addressed. “Basically we had to put the

OIL & GAS INQUIRER • April 2010

25

26

April 2010 • OIL & GAS INQUIRER

not afford a washout underground and jeopardize sliding into that river.”

Bessel says several different bits were used on this job. “We had to mill out a 127-millimetre liner at the beginning—we used a conventional washover pipe initially, but eventually used a standard tooth bit to drill it up. Our bits were all conventional.

We did the most of the drilling with tapered mills and watermelon mills. With all the junk in the well, conventional tri-cone tooth bits tended to hang up too much.”

Even so, the crew did not make it to the bottom of the hole as originally planned, says Bessel. “We did manage to get down to about 540 metres and last time they only got down to 23 [metres],” he notes.

New casing was set and cemented at that depth to isolate porous intervals and ground-water. “The abandonment is successful so far, but we are still monitoring it to make sure it is permanently abandoned,” Hewitt says. Only after no seepage occurs throughout this year will Lionhead consider itself entitled to declare a complete victory.

1960

1949

1950

1940

1920

1914

The Dingman job called for an exceptionally robust rig. “Your newer top drive rigs are built for making hole, but that wasn’t what we were doing,” says Bessel, an engineer. “We were grinding away on casing.” In fact, the wellbore was cluttered with remaining sections of casing that were not in any reports from the time of abandonment in 1949. “We had to work through these,” Hewitt says.

“The bits wanted to go sideways on you through sections. We had things like rock debris, wood timbers from previous operations, and mangled casing sections that wanted to throw us off course. It was a real challenge to stay straight and in the hole.”

Maintaining wellbore fluids was critical or the entire operation would have failed. “So we really focused on wellbore integrity,” Hewitt says. “We learned from the problems encountered with previous attempts. If we lost circulation, we’d stop and wouldn’t keep pumping. We didn’t only want to protect the river and water wells from lost circulation, but we could

1930

had been there all of their lives. “Some of them really missed that flame; the other half was glad it was gone,” says Hewitt.

With the seep secured, Lionhead moved in a coil rig for the initial re-entry.

Environmental and safety considerations were paramount. The crew was working on the edge of Turner Valley, and a municipal water well was within 50 metres of the operation. “When we re-entered [the well] with the coil, we used a fluorescent medical dye and fresh water,” Hewitt says. “We used coil and cement to secure the permeability encountered in 1981. I think we saved a lot of money by conducting this coil work prior to moving on the drilling rig.”

Once the coiled tubing rig had completed its work, the company employed a conventional drilling rig, modifying it to fit the odd size of the wellsite. “Where you normally have 100 by 100 metres, we were down to about 20 by 40. A lot of the newer rigs are set up to work within a bigger footprint than we had in this case,” Hewitt says.

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British Columbia

Encana plans a tenfold jump in its Horn river output over two years

Photo: Encana Corporation

by Pat Roche

A rig may spend up to a year on an Encana Horn River well pad, drilling as many as 20 wellbores.

Encana Corporation’s manufacturingst yle completion process is shif ting into high gear in the Horn River shale gas play with about 800 fracture stimulations planned for this year alone, a conference call heard on Feb. 11.

Today, Encana’s Horn R iver production is less than 20 million cubic feet (MMcf ) per day, but that should rise to 100 MMcf per day by year’s end, and to 200 MMcf per day exiting 2011, said Mike Graham, president of Encana’s Canadian division.

Graham expects Encana’s Horn River output to average 50 MMcf per day this year. (All volumes are net to the company and net of royalties.) “It’s ‘all systems go’ on the Horn River,” Graham told analysts and reporters on the company’s fourthquarter earnings call. The Calgary-based firm reported lower production and profits for the quarter in which its oil assets

were hived off into a new company, Cenovus Energy Inc. Encana is gearing up for a surge in production this year. “We only put on four wells in the Horn River last year and we drilled like 20 net wells in the Horn River, and we’re drilling another 20 net wells [this year],” said Graham. “We do about two to two and a half fracs each and every day.”

A drilling rig may take close to a year to drill one of Encana’s Horn River well pads, which can have up to 20 long horizontal wells. Fracing the wells on a pad can take as much as six months with the frac spread working around the clock.

Encana has now received an environmental assessment certificate from the B.C. Environment Ministry for the proposed Cabin gas plant. The plant, which will process Horn River output, still needs B.C. Oil & Gas Commission approval.

Pending that approval, which Encana expects in the spring, the first phase of the 400 MMcf per day plant should be on stream by September 2012 with the potential for later expansion of up to 800 MMcf per day, Graham said.

Across its major resource plays in North America, Encana’s gas production fell in the fourth quarter. Amid dismally low gas prices last year, the company shut in significant production volumes, but most of that output is now back on stream, and more is about to be added.

“We’re out there completing an awful lot of wells in Cutbank as well as Horn River,” said Graham.

In the fourth quarter, gas production from the Greater Sierra tight gas play in northeastern British Columbia averaged 178 MMcf per day, down from 228 MMcf per day in the fourth quarter of 2008.

Production from Cutbank Ridge, which is dominated by the B.C. Montney formation, averaged 254 MMcf per day, down from 311 MMcf per day a year earlier.

In the same periods, Bighorn output averaged 142 MMcf per day, down from 165 MMcf per day. Alberta coalbed methane production averaged 306 MMcf per day, almost unchanged from 308 MMcf per day a year earlier.

South of the border, gas output from the Jonah field averaged 566 MMcf per day in the fourth quarter, down from 573 MMcf per day in the corresponding 2008 period.

I n t he P ic e a nc e B a s i n , out put averaged 375 MMcf per day, almost unchanged from 377 MMcf per day.

In East Texas (characterized by the Deep Bosier Basin) output plunged to 281 MMcf per day from 408 MMcf per day a year earlier. And at Fort Worth (the Barnett shale), output averaged 124 MMcf per day, down from 143 MMcf per day the year before.

— DAILY OIL BULLETIN

BriTiSH COlUMBiA WEll ACTiViTy WELL LICENCES

FEB/09

FEB/10

70

78

▲

WELLS SPUDDED

FEB/09

FEB/10

85

84

▼

WELLS DRILLED

FEB/09

FEB/10

117

97

▼

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • April 2010

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Northwestern Alberta/Foothills

A spectrum of tight gas plays is evolving in the Deep Basin

by Paul Wells

Multi-stage fracs can induce commingled gas flow from multiple tight horizons in the Deep Basin.

Despite relatively low natural gas prices, operators are chasing an increasingly larger number of tight sand formations in Alberta and commingling production to boost volumes and reserves on the back of technological advancements in drilling and completions. Formations that are now in vogue that might not otherwise have been a few years back include the Cadomin, Nikanassin, Wilrich, Notikewin, as well as liquids-rich Bluesky and Cardium gas.

Brad Hayes, president of Petrel Robertson Consulting Ltd., says three examples characterize the range of tight sand play types and strategies that have evolved in the Western Canadian Sedimentary Basin since the early 2000s: The Nikanassin structural play is a thick—up to about 1,000 metres—fluvial to shallow marine sandstone-dominated section, with permeability enhanced by natural fractures associated with faulting.

The Cretaceous multi-formation commingled play where reservoirs are evaluated in up to 10 separate formations, with production commingled from the four or five best zones in each wellbore has also begun to see more activity.

Chris Theal, managing director of oil and gas research with Macquarie Capital Markets Canada, says multi-frac technology is being employed on both horizontal and, in many cases, vertical wells. “With vertical multifracs, you can frac three zones in a well, for instance. You’re seeing some results from this with wells doing five to seven MMcf [million cubic feet] a day initial production rates,” Theal says.

“It’s a highly efficient way to do it,” the analyst says. “It’s essentially about $2 million to take a well down to the Nikanassin and then depending on what you see on logs, it’s maybe $200,000 or $300,000 per frac interval vertically. So really what you’re seeing

is industry grounding their economics on the ‘Nik’ and then getting leverage out of anything they can tie into uphole.”

Theal says this “stack-zone concept” combined with newer drilling and completion techniques are changing the face of drilling in Alberta. “If permeability was your constraint in chasing these plays historically in terms of permeability being too tight, with the advent of multi-stage frac technology, it kind of opens up a whole different universe of reservoir to go and chase,” he says.

Whether they are pursuing horizontal multi-stage frac opportunities or vertical multi-zone options, producers are increasingly encouraged by what’s occurring in the areas like the Deep Basin or the Peace River Arch, both in terms of production rates and the economics. “A lot of guys are having success,” says Lyle Michaluk, CFO of Open Range Energy Corp.

By taking a horizontal to 4,000 metres, Michaluk says a company gets $800,000 in the meterage credit ($200 per metre) while the province’s natural gas drilling credit chips in another $2.9 million. “So you’ve got a good starting point from an economics point of view. You’ve got potentially about $3.7 million of credits and you’ve also got this five per cent royalty on the first 0.5 billion cubic feet of production. So that first-year payout with some of the initial production rates you’re seeing, the payout in months looks good.”

Michaluk says that even with a $5 per thousand cubic foot natural gas price, some wells will be paying out in 10 to 12 months.

“When you really boil down the economics, we think we’re just a competitive as any of the other plays going on right now.”

Roger Soucy, president of the Petroleum Services Association of Canada, says, “I think that it will be at least a year or two before the industry will really be able to judge the future prospects of these new developments and the eventual impact on the drilling numbers.”

— DAILY OIL BULLETIN

NOrTHWESTErN AlBErTA/FOOTHillS WEll ACTiViTy WELL LICENCES

FEB/09

FEB/10

89

181

▲

WELLS SPUDDED

FEB/09

FEB/10

155

275

▲

WELLS DRILLED

FEB/09

FEB/10

186

284

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • April 2010

31

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Northeastern Alberta

Oilsands resurgence draws big, small, and government-owned players

Photo: Joey Podlubny

by Paul Wells

Stable oil prices and lower construction costs are helping to kickstart new oilsands projects.

The recent resurgence of investment in Alberta’s oilsands will continue, and companies that get an early jump on their peers are likely to benefit, says a new report from Macquarie Capital Markets Canada. Analyst Chris Feltin, co-author of the report, said the oilsands sector has seen “renewed life” recently and estimates that nearly 590,000 barrels per day of bitumen capacity is currently under construction. Of this amount, 486,000 barrels per day is raw bitumen, as only Shell Canada’s Jackpine project is directly integrated with an upgrader.

Macquarie predicts that increased foreign investment, the commercial emergence of new technologies, and output from previously untapped reservoirs such as the Grosmont will define the next wave of oilsands activity. He estimates that current projects represent nearly C$38 billion in capital investment.

“The fundamentals in terms of oil pricing, natural gas pricing, and access

to labour and materials are definitely in the producers’ favour [compared to a year ago], so it’s not too surprising to see some of these projects come of the shelf,” Feltin says.

Although large firms with deep pockets are expected to continue as the dominant players in the sector over the long term, the report points out that a handful of smaller companies, such as Connacher Oil and Gas Ltd., are also proceeding with development plans.

The investment firm also expects that approvals for a handful of projects will be granted in 2010. The most visible, from Macquarie’s perspective, are Canadian Natural Resources Limited’s Kirby steam assisted gravity drainage and Horizon Phase 2 mining projects, Petrobank Energy and Resources Ltd.’s May River commercial project, and Laricina Energy Ltd.’s Germain pilot and commercial projects targeting the Grand Rapids

formation. “These projects represent an incremental 172,000 barrels per day of production capacity,” the report says.

While the McMurray formation has witnessed the lion’s share of oilsands development to date, Feltin thinks new areas of exploitation are set to emerge as pilot phase projects on leases containing untapped bitumen reservoirs are set to commence. “The largest of these is the Grosmont carbonate, estimated to contain 318 billion barrels of oil in place,” the report says, noting that emerging oilsands companies Laricina and Osum Oil Sands Corp. are poised to build the first pilot project in 2010.

Back in the sands, the Macquarie report said Laricina and BlackPearl Resources Inc. are moving ahead with test programs in the Grand Rapids reservoir on the western portions of the Athabasca fairway.

“A number of companies are implementing new technologies, with the intent of driving down project costs and improving oilsands project returns,” the report says. For example, technologies such as Petrobank’s Energy’s toe to heel air injection in situ combustion, E-T Energy’s electrothermal reservoir heating, and Ivanhoe Energy Inc.’s heavy-to-light upgrading process each “have the potential to provide a step-change” in the valuation of oilsands projects.

The report added that recent deals like the $1.9-billion acquisition by PetroChina International Investment Company Limited of a 60 per cent stake in Athabasca Oil Sands Corp.’s MacKay River and Dover oilsands properties may become more commonplace.

“This deal could well prove to be the first of several similar partnerships,” Feltin writes in the report. “I think there’s going to be an ongoing theme, as the AthabascaPetroChina deal is a pretty good indicator that there is some interest by some of these national oil companies.”

— DAILY OIL BULLETIN

NOrTHEASTErN AlBErTA WEll ACTiViTy WELL LICENCES

FEB/09

FEB/10

68

77

▲

WELLS SPUDDED

FEB/09

FEB/10

107

67

▼

WELLS DRILLED

FEB/09

FEB/10

116

173

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • April 2010

33

Northeastern Alberta

ErCB says Total triggered Joslyn crater with excessive steam injection pressure Total E&P Canada Ltd. was exceeding the approved steam-injection pressure at its Joslyn Creek thermal bitumen project in 2006 when the reservoir cap rock was breached, blasting a huge crater into the ground and hurling rocks hundreds of metres into the air. The Alberta Energy Resources Conservation Board (ERCB) finally reached that conclusion after an exhaustive investigation of the May 18, 2006, incident.

No one was hurt and no harmful gases were emitted when the blast occurred around 5:15 a.m. at the steam assisted gravity drainage (SAGD) project northwest of Fort McMurray, Alta. The ERCB’s 177-page report found the steam release occurred near the heel of the first well pair in pad 204, creating a 125-by-75 metre “surface disturbance” and hurling rocks “up to 300 metres horizontally from the main crater.”

A one-kilometre-long dust plume extended to the southwest after the blast.

“The majority of this displaced material was deposited in the immediate

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area, but there was evidence of a fine dusting of material and rock across an area about one kilometre long by 100 metres wide to the southwest of the release point,” says the report, which was released in late February. Total E&P Canada is a unit of the French-owned supermajor producer Total S.A. Josly n SAGD reser ves were de booked at the end of 2008, and last June Total received ERCB approval to suspend

• Operating at bottomhole pressures significantly higher than the 1,400 kilopascals (absolute) proposed in its scheme application, • Failing to implement alarms and automatic shutdown of wells exceeding the 1,800-kilopascal bottomhole reservoir fracture pressure, and • Exceeding the Directive 051 approved maximum wellhead injection pressure of 1,800 kilopascals.

"There was evidence of a fine dusting of material and rock across an area about one kilometre long by 100 metres wide to the southwest of the release point."

– Energy resources Conservation Board report, February 2010

operations. Last month, the company applied to abandon the project, said Elizabeth Cordeau-Chatelain, a Total Canada spokeswoman.

E RC B i n v e s t i g at o r s c o n c lu de d Total was in non-compliance with its reg ulator y approval conditions by:

Board investigators concluded the following is the most likely steam release scenario: • The underlying cause of the steam release was the injection of steam at excessively high pressures.

• The conversion of the well pair from

Northeastern Alberta steam circulation to semi-SAGD forced high-pressure steam into the bitumen reservoir. Eighteen days later, on April 12, 2006, a vertical fracture was initiated near the heel of the injector and established communication with the Wabiskaw C gas sand.

• High-pressure steam and water pooled under the Wabiskaw A shale, causing it to fail on April 21, 2006, and establishing communication between the injector and the Wabiskaw A water sand directly underlying the Clearwater cap rock.

• Between April 21 and May 18, 2006, high-pressure steam and water pooled under the Clearwater cap rock, causing it to fail.

• Once the Clearwater was breached, pressure fell rapidly.

“This pressure drop caused hot water that had accumulated in the Wabiskaw A water sand and the Wabiskaw C gas sand to flash to vapour. This provided the energy for a catastrophic explosion that disturbed a large surface area and subsurface volume and threw rocks several hundred metres into the air.”

— DAILY OIL BULLETIN

Business council foresees more oilsands investment by China China’s investment in the oilsands and energ y sector and mining sector in Canada is about take off even more significantly than it has in the last number of years, Peter Harder, president of the Canada-China Business Council (CCBC), told a Calgary oilsands summit on Feb. 2.

“There is no doubt that China needs and wants energy,” Harder told an Insight Information conference in Calgary.

The council, the oldest and bestestablished foreign trade association in modern China, has called for Canada to remove the regulatory barriers that discouraged Chinese investment in the oilsands. “We made it quite clear that we believe unfettered Chinese investment in Canada’s energy sector is good for Canada and good for global trade,” said Harder, a senior policy advisor with the law firm Fraser Milner Casgrain.

Energy is a preoccupying concern for China’s government because the need is so great: the country is currently

producing only half of its oil consumption of 7.8 million barrels per day, the summit heard. China has already targeted Canada’s resource assets. The most significant deal to date has been the $1.9-billion acquisition by PetroChina Internationa l Invest ment Compa ny L im ited (PetroChina) of a 60 per cent stake in Athabasca Oil Sands Corp.’s MacKay River and Dover oilsands properties.

“The stress-free approval of this deal went a long way to ease fears that there would be political barriers to China’s investment in Canada,” said Harder.

CCBC members had indicated prior to the approval that their contacts in China were being told that Canada was open for business but they needed to see some proof, he said. “The approval of the Athabasca deal is, I believe, the necessary proof for China to see.”

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Northeastern Alberta

Harper’s visit to China in early December was a critical event for China.”

Harder later said he sees the current Chinese strategy as buying an interest and not coming in and taking a 100 per cent position or even the majority position. This approach will enable Chinese companies to learn about the market, reducing the level of political focus on the investment, and make it a two-way learning process.

The CCBC head said China and Canada have struggled over the last few years to maintain the depth of the relationship as

Photo: Government of Canada

acquired for US$122 million, opened the door for Chinese investment in Canada in 2005. Sinopec Group followed with the purchase the same year of a 40 per cent share of Synenco Energy Inc.’s proposed Northern Lights oilsands mining project northeast of Fort McMurray.

The CCBC is confident there is regulatory framework in place to protect Canada’s interest in these discussions and is encouraged by developments in Ottawa in the China-Canada relationship, he said. “We believe Prime Minister Stephen

it existed for many years. “A disconnect at the highest, most senior level of this relationship created a cooling off,” Harder said. “From our perspective, you cannot have hot economics and cold politics in a business relationship with China.”

However, a flurry of high-level contacts between Canada and China that began last spring is beginning to remedy that situation, said Harder noting that in 2009 there were no fewer than five senior ministerial visits to China, including two

by Finance Minister Jim Flaherty. The council views Harper’s speech to a business group in Shanghai in December as beginning the process of strengthening the high-level political contact, which is so necessary in building good business relationships with Chinese state-owned enterprises and the private sector in China, he said.

According to Harder, during that visit, Harper laid out what amounts to the Tory government’s blueprint for Canada-China relationship. “He said that one area where Canada and China shared mutually beneficial objectives was in energy.”

A visit by Prime Minister Stephen Harper and his wife Laureen boosted China’s confidence in Canada.

— DAILY OIL BULLETIN

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Alberta’s oilsands royalties are expected to eclipse natural gas

Photo: Joey Podlubny

by Richard Macedo

Despite concern over CO 2 emissions and tailings ponds, oilsands investment is starting to accelerate.

Oilsands royalties are for the first time expected to eclipse natural gas as the largest source of Alberta’s resource revenues thanks to stronger oil prices, higher production, and amended royalties. The provincial budget released on Feb. 9 projects that oilsands royalties will make up nearly 50 per cent of resource revenue by fiscal 2012–13, while natural gas will comprise just 22 per cent.

Natural gas royalties made up over 70 per cent of the Alberta government’s resource revenue in 2002–03 and 2003–04. But gas revenue will likely continue to struggle as North American prices are held back by growing supplies of shale gas and Alberta’s production continues to fall sharply.

Gary Leach, executive director of the Small Explorers and Producers Association of Canada, said the shift to oilsands as the leading contributor is likely permanent due to climbing production from the province’s bitumen regions. “It also illustrates

why we have to focus on improving the investment situation for the conventional oil and natural gas sectors; this is what the [provincial government’s] competitiveness study is all about,” he said.

Leach added that the cliff-like drop in natural gas royalties is a big reason the government opened up dialogue with the oil and gas industry to address the problem. “I don’t think Alberta is too far behind to catch up [to British Columbia and the United States],” he said. “We still have a large resource endowment in Alberta and it’s not clear yet that shale gas in the northeast U.S. will be able to avoid challenges and delays from opponents.”

Greg Stringham, VP of oilsands and markets with the Canadian Association of Petroleum Producers, said, “The natural gas supply dynamic has drastically changed with the new shale gas discoveries, and this has had an impact on

Alberta’s ability to attract investment. The natural gas industry and many thousands of Albertans whose livelihood depends on natural gas activity have been dealing with this for the last year.”

The province, which promised to hold the line on taxes, remains on a path of red ink with deficits of $3.6 billion in 2009–10 ending this March 31, then $4.7 billion and $1.1 billion the following two fiscal years before returning to a surplus of $505 million in 2012–13, part of Premier Ed Stelmach’s plan to be “back in the black” by 2013.

Non-renewable resource revenue is expected to fall to $6 billion in fiscal 2009–10, roughly half of the previous fiscal year as the recession hammered government coffers. In 2010–11, resource revenue is expected to climb to $7.3 billion.

After falling to $5.8 billion in 2008– 09, natural gas royalties are expected to plunge further to collapse to $1.7 billion in 2009–10, then rise slightly to $1.9 billion the following fiscal year. Prices are forecast to average C$3.40 per gigajoule in 2009–10 and $4.25 the following year.

In a continuing trend, total production is forecast to drop to 4.7 trillion cubic feet (Tcf) in 2009–10 from 4.9 Tcf the previous fiscal year. The budget projects the fall in gas production will continue to 4.3 Tcf in 2010–11, four Tcf in 2011–12 and 3.9 Tcf in 2012–13.

Synthetic crude and bitumen royalties brought in nearly $3 billion in fiscal 2008–09, and after an anticipated decline to $1.9 billion in 2009–10 revenues recover to $3.2 billion the subsequent year.

Royalties for conventional crude are forecast to be relatively flat at $1.8 billion for the fiscal year ending in March, then should rise to $2.1 billion in 2010–11.

Drilling stimulus initiatives are expected to cost $441 million in 2009–10, down from the budgeted $842 million, and $732 million the following fiscal year.

— DAILY OIL BULLETIN

CENTrAl AlBErTA WEll ACTiViTy WELL LICENCES

FEB/09

FEB/10

130

264

▲

WELLS SPUDDED

FEB/09

FEB/10

178

247

▲

WELLS DRILLED

FEB/09

FEB/10

174

238

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • April 2010

39

Central Alberta

Spartan sets $31M capital budget for 2010 Spar tan Exploration Ltd.’s board of directors has approved a $31-million capital budget for 2010 concentrating on oil prospects. Approximately 80 per cent ($25 million) of this amount will be spent on drilling and completions, with a further $2.6 million allocated to facilities and tie-in expenditures and $3.4 million to land, seismic, and other expenditures.

The company plans to drill up to 15 gross (11.7 net) wells targeting highquality light oil, including eight (net) horizontal Cardium wells on its Pembina acreage with five (2.2 net) Bakken wells planned in southeastern Saskatchewan and t wo (1.5 net) Shaunavon wells planned in southwestern Saskatchewan.

From a capital investment perspective, approximately 85 per cent of Spartan’s

2010 capital budget is allocated to the company’s Pembina area. Spartan expected to spud its first Cardium horizontal well in early March. Due to spring breakup and the time required to obtain necessary regulatory approvals for drilling horizontal wells in Alberta, approximately 85 per cent of Spartan’s 2010 capital budget will be invested during the second half of the year.

Spartan recently drilled and completed a Bakken horizontal well (0.42 net) in southeastern Saskatchewan at its Midale/ Viewfield property. The well flowed at rates in excess of 500 barrels per day (210 barrels per day net) of oil on the initial completion test following a 12-stage water-based frac.

Management expects to produce the well at initial rates in excess of 200 barrels per day (84 barrels per day net) of oil.

Spartan is forecasting average 2010 production in excess of 650 barrels of oil equivalent per day (82 per cent oil) and exit production, based on estimated production for the fourth quarter, in excess of 1,200 barrels of oil equivalent (boe) per day (81 per cent oil). Operating costs are forecast at approximately $10 per boe (including transportation) and general and administrative costs will approximate $3 per boe.

Spartan has access to over 13.5 net sections in the Pembina area (owned and farm-in) and has identified 57 net horizontal drilling locations on these lands. There has been a significant amount of recent activity in proximity to the company’s lands at West Pembina, with 17 horizontal Cardium wells currently either drilled or licensed, which offsets Spartan’s lands.

— DAILY OIL BULLETIN

Keyera sees reviving activity and strengthens infrastructure plans

40

April 2010 • OIL & GAS INQUIRER

wells are being drilled horizontally and are targeting tight gas formations.

Keyera also signed a new agreement with a large producer to process gas at its Nevis gas plant in central Alberta. Late in the quarter, Keyera also signed an agreement with a producer in northeastern British Columbia, which will allow the fund to complete the 40 million cubic feet per day expansion at the Caribou gas plant.

Several other producers were also drilling around Caribou in the fourth quarter. “ T he a n nouncements by severa l producers of increased drilling projects

are a positive sign for increased drilling activity in 2010,” said Jim Bertram, Keyera’s president and CEO. “From a business perspective, I’m very encouraged by the positive signs I see in western Canada. “Since the fall, we’ve had more and more producers approach us seeking gathering and processing services.” In 2010, management anticipates investing between $80 million and $100 million of growth capital but has the financial flexibility to undertake larger transactions.

— DAILY OIL BULLETIN Photo: Keyera Facilities Income Fund

Keyera Facilities Income Fund has announced plans to strengthen its natural gas liquids (NGL) infrastructure in central Alberta. Keyera will use new and existing pipelines to collect and deliver NGL mix from west-central Alberta, including its Strachan gas plant, for delivery to its fractionation facilities in the Edmonton/Fort Saskatchewan area.

In order to enhance its NGL transportation network, Keyera will convert an existing pipeline into NGL service, adding storage facilities and constructing a sixkilometre pipeline connection. The total capital cost is expected to be approximately $11 million.

The new pipeline will enable Keyera to deliver NGLs into the Plains Midstream Canada Rangeland pipeline system for delivery to the Rimbey gas plant and north on Keyera’s Rimbey Pipeline to Keyera’s Fort Saskatchewan fractionation and storage facility.

In the fourth quarter, Keyera saw continued drilling activity in the foothills front region of Alberta, particularly around the Strachan, Nordegg River, and Brazeau River gas plants. To the east, activity increased in the fourth quarter around the Rimbey gas plant as producers continued their drilling programs. Many of the new

Keyera has new processing contracts in Alberta and B.C.

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Service firms fear active winter will be followed by weak summer

Photo: Joey Podlubny

by James Mahony

Field worker shortages are typical during the winter activity peak and this year was no exception.

A shortage of experienced workers is keeping some of western Canada’s oilfield service companies from hitting their full stride this winter, according to industry executives. Drilling activity is stronger than many expected with active rig counts more than 70 per cent of the available fleet at work in mid-February. At that time, 570 units were at work, 186 more rigs than last year at the same time.

“The biggest thing holding back our [service rig] utilization numbers today is [a lack of qualified] people,” said Brad Kingston, general manager and VP of Savanna Energy Services. “We would have much higher utilization if we had the people, but we’re turning down anywhere from five to nine [jobs], and some weeks, up to 15 jobs.” With 58 service rigs and six coiled tubing rigs in western Canada, Savanna was keeping about 60 per cent of its fleet busy, up sharply from last year’s fourth quarter.

Across the industry, many oilfield service workers were laid off in the past 12 months as producers dramatically cut capital spending following the oil price crash of late 2008 and early 2009 and as natural gas prices remained weak. “We keep hearing about all the service sector employees

an informal sur vey by the Daily Oil Bulletin indicated. “There are only so many people to go around,” said Duane Mather, president and CEO of drilling contractor Nabors Canada, which had 37 active rigs [45 per cent] of a total 82 drilling rigs in western Canada in one recent week. “We could have been a few rigs stronger than we are right now. There was work for our tele-doubles, but we couldn’t find people for them.”

The problem is not in getting workers per se, but in recruiting those with drilling experience, said Mather, noting that contractors have had little trouble finding workers new to the industry, but they need training. Usually, that means matching them with experienced hands, but in the current climate, that’s been difficult.

The situation didn’t happen overnight, but evolved over time as drilling and wellservice contractors scaled back last year in response to the drilling slowdown, laying off workers, including experienced hands.

The ramp-down has impacted both drilling and well-service contractors, as industry went from drilling 23,000 wells a year to a forecast 8,000 to 9,000 wells this year, according to Mather.

T he problem affects not just the industr y ’s heav y hitters, but smaller

"There was work for our tele-doubles, but we couldn’t find people for them."

– Duane Mather, president and CEO, Nabors Canada

that are available, but we don’t know where they’re at,” said Kingston. “They’re certainly not beating down our doors.”

Other service companies, including drilling contractors, have also been challenged to find the right people recently,

contractors like Brazeau Well Servicing, wh ic h r u n s 12 ser v ice r ig s i n t he Drayton Valley area. “A lot of [experienced rig hands] have left the field,” said Ron Martens, Brazeau’s associate general manager. “They’ve moved on

SOUTHErN AlBErTA WEll ACTiViTy WELL LICENCES

FEB/09

FEB/10

240

178

▼

WELLS SPUDDED

FEB/09

FEB/10

363

407

▲

WELLS DRILLED

FEB/09

FEB/10

374

409

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • April 2010

43

Southern Alberta

to other things. They just didn’t trust it after last summer.”

The sense that those leaving the sector are seeking regular hours is hard to miss.

“We know that’s the situation in lots of instances,” said Brad Kingston of Savanna.

“I’d say anywhere from 10 per cent to 15 per cent or 20 per cent of those not willing to come back told us that exactly. They have full-time employment in others sectors that doesn’t pay nearly as well, but it’s a lot more steady.”

Most telling, perhaps, one oilfield service executive recalled a chance meeting with a former field employee at a store in town recently. After some small talk, the executive told the worker that his former job was open, should he want to return.

Neveu. “But that’s the business we’re in, so we don’t spend much time complaining about it. I don’t think this [year] is any better or worse than any other hard rampup for winter.”

For its part, Trican Well Service Ltd. is actively hiring and has been since September, according to CEO Dale Dusterhoft, who was candid when asked if his recruiters have had trouble getting crews. “We have to work really hard at it, and you don’t get them right away, but if you keep at it, you do,” he said.

Notwithstanding that challenge, he said business has been good.

“Activity in [the first] quarter is very high for us across western Canada.

Saskatchewan is very busy, driven by the

“I’d say anywhere from 10 per cent to 15 per cent or 20 per cent of those not willing to come back told us they have full-time employment in others sectors that doesn’t pay nearly as well, but it’s a lot more steady.”

– Brad Kingston, General Manager and Vp, Savanna Energy Services

“Never again,” the worker said, explaining that, despite its lower pay, the store job offered benefits, not least of which was the chance to spend time with his wife and kids daily.

Although no one is calling it an exodus, the departure of oilfield service workers from the sector concerns some industry executives, who think the trend might not easily be reversed. “People won’t come to this industry to work 80 to 100 days in the first quarter,” said Mather, who will retire from Nabors Canada this June. “They’ve gone on to something else and adjusted their lives accordingly.”

Not everyone senses a change. The head of one of Alberta’s largest drillers notes that every winter brings challenges of one kind or another for contractors needing staff, and this season is no different. “It’s always a challenge manning up for winter, because you’re going from maybe 90 rigs to 150,” said Kevin Neveu, president and CEO of Precision Drilling Trust, which has 203 drilling rigs in western Canada, 135 of which are currently active.

“You’re ramping up like crazy after ramping down the prior spring,” said 44

April 2010 • OIL & GAS INQUIRER

Bakken oil play. There’s also significant increased activity through the Cardium, Viking, and Shaunavon oil plays in central Alberta and central Saskatchewan.

Looked at year-over-year, there’s a significant increase in that part of the business.”

In particular, the pace of fracturing has been brisk. “If you looked at the basin overall, we’re in a situation where we’re going to drill less wells, but fracture them a lot more. Cementing is also related to the number of wells drilled, so that service line is busy, but not as busy as fracturing,” Dusterhoft said.

At Ensign Energy Services Inc., the labour market was also noticed. “We’re finding that crews are tapped out,” said Bob Geddes, Ensign president and COO. “The industry is quite at its max currently, and hanging on until spring breakup.” Geddes said the drilling market has been quite strong through the winter. “A little stronger than expected, frankly. It looks like we’ll be quite busy until the thaw comes.”

As for this summer, he expects a busy market, with signs of activity in most depth ranges. Yet, Geddes anticipates shallow drilling will have a tough market this summer.

Asked if he’d had trouble finding experi enced workers, the manager of Essential Energy Services Trust’s Slave Lake service rig operations was blunt.

“Yes,” said Greg Kubel, noting that some older job applicants never made it through the company’s drug screening.

“We went w ith the [new] guys, because we had enough experienced people. There were young guys that could pass the [drug] test. The biggest thing is getting them to pass that, and it’s not for marijuana. It’s the harder stuff,” he said.

Formerly known as Classic Well Servicing, the company runs 10 service rigs in the Slave Lake area.

Optimism in the drilling sector is hard to come by despite the unexpected amount of activity this winter. While drillers are always concerned about the period after breakup, this year’s outlook appears especially dim. “It’s going to be a bloodbath,” said Nabors’ Mather. “There’s nothing that will happen in the second quarter [and] no price structure for the main commodity—gas—that we’re drilling for right now.”

Earlier this year, the Petroleum Services Association of Canada raised the number of wells it forecasts will be drilled in western Canada this year to 9,000 from about 8,000. The extra holes will probably be drilled in the fourth quarter, said Mather, given the industry’s typically slow pace entering the third quarter. “We’re late in the second before the road ban comes off…[and] I don’t think there’s much to look forward to until the late third quarter or early fourth quarter, beyond 30 to 40 per cent utilization, if that.”

Among the industry’s suppliers, there is somewhat more hope. Comparing the current winter season to last year’s, Allan Cheng, president of Cantak Corporation, said sales of production tubing, well casing, and line pipe were up roughly 20 per cent, although he said an overhang of inventory still exists.

“We’re seeing a lot more activity in B.C. and Alberta, and the Cardium play seems to be fairly hot. We’re starting to see people doing more drilling in that play,” Cheng said. At the same time, there is concern about what will happen after breakup: that a weak spring may be followed by a weak summer. “It may take until the late fall before it starts to improve again,” he said.

— DAILY OIL BULLETIN

Southern Alberta

Western Energy Services buys Horizon Drilling and Cedar Creek In two separate deals, Western Energy Services Corp. has agreed to acquire two privately owned companies—Horizon Drilling Inc. and Cedar Creek Drilling Ltd.—for a total purchase price of approximately $84 million, including the assumption of debt. Horizon would account for $66 million in a deal that includes cash payment and debt assumption.

Horizon’s assets include eight drilling rigs, including two AC triples with a depth rating of 4,500 metres and 1,200-horsepower drawworks; four AC Range III singles with a depth rating of 3,000 metres and 1,100-horsepower draw works; one AC Range III single with a depth rating of 2,000 metres and 600-horsepower drawworks; and one conventional single with a depth rating of 1,200 metres and 350-horsepower drawworks.

Western Energy said all of Horizon’s rigs have top drives, are capable of drilling horizontal wells, and have achieved above industry average utilization in 2009 of 42.5 per cent. Currently seven of the eight rigs are working.

Under the terms of a pre-acquisition agreement with Cedar Creek, Western Energ y will pay $22 million, which includes debt of approximately $13 million. The assets of Cedar Creek include three telescopic double drilling rigs with a depth rating of 3,500 metres and 750-horsepower drawworks. All of the Cedar Creek drilling rigs are well suited for horizontal drilling.

with immediate cash flow, sustainable profitability, key human resource capabilities, and operational expertise. This platform will help Western achieve its goal of creating an oilfield services leader.”

The company has entered into a bought deal financing agreement with a syndicate of underwriters co-led by Cormark Securities and Raymond James and including FirstEnergy Capital Corp.,

Western Energy will pay $22 million, which includes debt of approximately $13 million.

Upon closing of the acquisitions, Western Energy will have a fleet of 11 drilling rigs which are, on average, less that four years old, have modern designs, move and rig up efficiently, and enjoy a premium customer base. “The acquisitions of Horizon and Cedar Creek provide an important stepping stone for the development and growth of Western,” said Dale Tremblay, CEO of Western Energy.

“These two transactions provide Western

Peters & Co. Limited, and Thomas Weisel Partners Canada Inc. to issue 375 million Western Energy shares at a price of $0.20 per Western Energy share for gross proceeds of $75 million.

Western Energy’s management team is focusing on three core business lines in Canada: contract drilling, service rigs, and rental and production services. Its business plan includes further acquisitions.

— DAILY OIL BULLETIN

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45

Southern Alberta

precision is negotiating deals for new drilling rigs Although Precision Drilling Trust’s 2010 capital plan excludes any new-built rigs, the trust is in the final stages of negotiations with customers for new Tier 1 (Super Series) rigs on favourable economic terms. “While debt repayment remains a priority, Precision has the financial strength and flexibility to be aggressive in capturing additional customer demand for new builds or upgrades on our current fleet,” president and CEO Kevin Neveu said on Feb. 12.

The trust could produce its first newbuild rig as early as May and the second one a month to six weeks later, he said.

“We could probably deliver one or two more before the end of the year, but by 2011 we could be back up to as many as four to six per quarter, provided the demand is there,” said Neveu. “We think we can build rigs as quickly as our customers can take them.”

In new build rigs, Precision is looking for two four-year terms with payback on the original capital before taxes w ith interest in a four-year period, said Doug Strong, CFO, in a telephone

conference to discuss fourth-quarter financial results.

In the meantime, Precision is working with its customers to upgrade some of its deeper Tier 3 rigs to Tier 2 (capable of drilling horizontal wells) and some of its Tier 2 rigs to Tier 1 capability, specifically for unconventional drilling opportunities.

The trust expects the 15-tier upgrades earlier announced will be fully utilized and the number of upgrades will increase if customer demand increases at the pace seen so far this year, he said.

The upgrade to Tier 1 from Tier 2 is actually a mobility issue and in most cases that means converting an existing rig to a pad type of configuration, analysts heard. Depending on the scope of the upgrade, that can cost from a few hundred thousand dollars to as much as $3 million or $4 million.

Precision sees oppor t unit ies for new builds in all unconventional areas in both Canada and the United States such as in the Waskada, Manitoba, and Pembina (Drayton Valley) oil plays and in the Marcellus shale in the United

States, said Gene Stahl, president of drilling operations.

In t he four t h quar ter, t he tr ust strengthened its positions in the Montney gas play and the rapidly developing Cardium light oil play, said Neveu. It also continued its strong presence in Canadian heav y oil with t wo of the three super single rigs deployed from the United States in late 2009 specifically for heavy oil applications. “We are light in the Saskatchewan Bakken and Horn River, but expect to see our Horn River position improve as we complete our rig upgrades later this year,” he said.

Precision averaged an active drilling rig count of 72 in Canada in the fourth quarter, an increase of 21 rigs or 41 per cent, and in the United States the active count averaged 64 rigs, an increase of 22 per cent over the third quarter. In the fourth quarter, about 60 per cent of wells drilled in Canada were looking for oil, while in the United States 70 per cent of the rigs had natural gas targets. About 80 per cent of Precision’s rigs were drilling horizontal and directional wells.

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Southern Alberta

on some wells. “We see daylight at the end of the tunnel for day rates for the first time in several quarters,” Neveu said.

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—DAILY OIL BULLETIN

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best I would call it fragile and fraught with risk,” said Neveu. “Precision remains mindful of this risk and will continue to tightly manage its expenses and capital spending this year.”

Photo: Joey Podlubny

In Precision’s productions and completions business, while activity was up 21 per cent over the third quarter, the rig rates did not show much pricing response, analysts heard. Much of the activity increase is in the conventional and heavy oil markets, which tend to be less complex than the more profitable gas completions business from which Precision benefited from for much of the past decade, he said.

Precision currently has 130 to 140 rigs active compared to its earlier forecast that rig activity would peak at 110 rigs this winter. In both Canada and the United States, all of Precision’s Tier 1 rigs are working along with about 60 per cent of Tier 2 rigs and 20 per cent of Tier 3 rigs. Precision said it expects low Tier 3 utilization to persist into 2010 and potentially longer depending on natural gas prices.

Day rates on the spot market have generally started to move up during the fourth quarter, dependent to a large extent on geography and rig tier. Daily improvements for Tier 1 rig class are as much as $3,000 per day in some markets, and even Tier 3 rigs are seeing modest improvements (increases of $100 to $300 per day)

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Saskatchewan

Birdbear heavy oil play helps spur strong land sale in Saskatchewan

Photo: Joey Podlubny

by Paul Wells

Heavy oil activity is starting to roll again thanks to another tight reservoir play in Saskatchewan.

Fresh off a $39.5-million February land sale that was the province’s second highest ever for that month, Saskatchewan officials say a rebound year from 2009 appears to be in the cards. Activity will focus on the Bakken and Lower Shaunavon light oil plays, but a new heavy oil play also looks promising.

Daily Oil Bulletin (DOB) records show 397 wells drilled in the province so far in 2010, up from 331 a year ago. “There’s been a recent uptick in land sale activity—not compared to 2008, which was a crazy year—but we’re seeing an uptick in not only the amount they’re paying for the land but the amount of land being posted,” said Ed Dancsok, assistant deputy minister of the provincial energy department.

Dancsok was interviewed in Calgary on Feb. 24 at a workshop called the Saskatchewan Natural Gas Advantage.

The next provincial land sale will be

held April 12 and 375 parcels are posted for bidding.

The first sale of Saskatchewan’s calendar year delivered the $39.5 million at an average of $410.59 per hectare. Last year’s February sale brought in $6.3 million on 32,948 hectares, which worked out to $189.84 per hectare. The still-hot Bakken play accounted for the lion’s share of the $25.9 million of bonus bids from the Weyburn-Estevan area, the leading area in the February land sale.

Paul Mahnic, the energy ministry’s director of petroleum tenure, said about 80 per cent of the bonus bids in the southeast were for land with Bakken production potential. But he noted that a cluster of parcels located west of Estevan have multiplehorizon potential. “There are about eight potential horizons in the area that are producing,” Mahnic said, referring to production horizons in Mississippian, Bakken,

Winnipegosis, and Red River formations.

“You’re looking at multiple targets. If one doesn’t work, you work your way up.”

Accordi ng to DOB records, t he February sale included 18 petroleum and natural gas exploration licences that sold for $10.3 million and 293 lease parcels that attracted $29.2 million in bonus bids. The Weyburn-Estevan area received nearly $25.9 million in bonus bids, largely on the strength of the Bakken play. Next was the Lloydminster area at $5.7 million, followed by Swift Current at $4 million and the Kindersley-Kerrobert area, which drew $3.9 million.

Standard Land Company Inc. produced the land-sale high, paying $2.1 million for a 1,552-hectre licence near Unity in the Lloydminster area. In addition, the highest price on a per-hectare basis was $6,512 by Baytex Energy Ltd., which bid $105,427 for a 16-hectare lease parcel near Maidstone, also in the Lloydminster area.

Companies are apparently kicking the tires of the Birdbear heavy oil formation, which lies just below the Mannville formation. Dancsok said it appears that there is growing interest in that play. Dancsok noted that mineral rights below the Mannville have reverted to the province since the late 1990s.

To date, the new Birdbear play is restricted to a fairly narrow area of approximately 10 miles by 30 miles bet ween the tow ns of Mack lin and Unity in west-central Saskatchewan.

“Companies are posting them now, so I think the proof is in the pudding when it comes to companies posting the lands and paying fairly significant dollars per hectare,” Dancsok said. “That tells me that people are seeing success.

“Recent land sale activity has of course extended beyond this area as companies attempt to get a land position in the play.

Most of the new land acquired recently

SASKATCHEWAN WEll ACTiViTy WELL LICENCES

FEB/09

FEB/10

133

295

▲

WELLS SPUDDED

FEB/09

FEB/10

105

235

▲

WELLS DRILLED

FEB/09

FEB/10

115

255

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • April 2010

49

Saskatchewan is in the name of land companies,” he said.

“There are approximately two dozen wells completed in the Birdbear in the area.”

According to Dancsok, the companies that presently have wells in the play (in order of numbers) are: NuVista Energy Ltd., Husky Energy Inc., Talisman Energy Inc., and BlackPearl Resources Inc. Dancsok said advancements in technology and the knowledge gained by industry from the numerous wells that have been drilled into the Mannville but that have also penetrated the Birdbear are aiding companies looking to exploit the Birdbear, which contains heavy crude in the range of 17 to 18 degrees API. As well, strong heavy-to-light oil differentials help the economic outlook of the just emerging play.

“Companies are now coming and trying the newer technology, and we’ve seen an uptick in the land-sale revenue from the Unity area where the Birdbear is being exploited. I’ve signed quite a few approvals for horizontals in the Birdbear in that area,” Dancsok said. “Technology is the key, but the differentials are also helping a lot.”

Also during the February land sale, three special exploratory permits were awarded to Scott Land & Lease for work commitments of $1.5 million over two years for 104,300 hectares north of Prince Albert between Big River and Nipawin. Dancsok, who said one company has drilled about three wells looking for shale gas in the area, noted that these are the first exploratory permits issued since 2008, when the price of oil and natural gas dropped like a stone.

“Those permits were drawn up without a bonus bid upfront, just a work commitment. They are starting to take a look at picking up some of that stuff, planning for the future,” Dancsok said. “We’ve always had these around—there are large, vast amounts of land to take advantage of and explore. We haven’t seen any of that in about a year and a half.”

curb activity this year. “Industry hasn’t really shown more interest at this point. If you use land sales as a barometer, there’s really not been a lot of land sale activity in gas-prone areas.”

However, Dancsok continues to believe in the ultimate potential of the natural gas industry in his province, and noted that the results of a recent joint study by the

“If you use land sales as a barometer, there’s really not been a lot of land sale activity in gas-prone areas.”

– Ed Dancsok, Assistant Deputy Minister, Saskatchewan provincial Energy Department

Mel i nda Yu rkowsk i, a resea rc h petroleum geologist for the province, said many questions remain about the future potential of shale gas exploration in the province. “There’s still information we don’t know geologically because the shales are…very diverse, moving up faults through the entire Colorado,” she said. “So there’s still a lot of unknowns.

Of course, that’s the extreme east of the province. But also moving over to the west, away from the major sandstones, there’s a whole area that really needs to be addressed and looked at [for shale potential].”

Dancsok said that 2009 was a bleak year for natural gas drilling in the province, with only about 230 gas-directed wells being punched—far removed from an average of about 1,000 per year drilled during the past decade. And he expects that still-low natural gas prices will again

province and the National Energy Board were encouraging. “The report showed significant improvement in the technically recoverable reserves of natural gas,” he said. “Basically, our remaining natural gas reserves sit at around 2.9 Tcf [trillion cubic feet], and the report indicates that there’s probably another equivalent amount that’s designated as technically recoverable. It’s a significant increase from previous studies.”

Following on its already-established blueprint of continually monitoring Saskatchewan’s competitiveness in relation to other petroleum-producing jurisdictions, the province is looking to offer incentives that could spur on natural gas drilling. “We are looking at fiscal opportunities here such as exploratory incentives. We’re looking to see if there are any further opportunities for further incentives, but it’s still a work in progress,” Dancsok said.

— DAILY OIL BULLETIN

Northland plans $700M gas-fired power plant near North Battleford Northland Power Income Fund reports that a wholly owned subsidiar y has entered into a 20-year power purchase agreement (PPA) with the SaskPower to build and own a new natural gas–fired power plant to provide baseload power to the Saskatchewan energy system. The 261-megawatt natural gas–fired combined cycle plant will be built near North Battleford, Sask., about 150 kilometres northwest of Saskatoon. All power produced by the plant will be sold under the PPA to SaskPower.

The plant will use a General Electric gas turbine with associated heat recovery and a steam turbine to produce the electricity. Construction is expected to begin 50

April 2010 • OIL & GAS INQUIRER

in July 2010, and the plant is scheduled to begin commercial operations in 2013.

The total cost of the project is budgeted at approximately $700 million.

“We are very pleased that SaskPower has again shown its confidence in Northland Power and selected us as their partner to help meet their needs for reliable generation capacity,” said John Brace, CEO of the fund. “With construction of our peaking plant near Spy Hill to begin in the spring, this will further strengthen our presence in Saskatchewan and allow us to participate in the province’s continued growth. We are very confident that the North Battleford facility, modelled closely on our cogeneration plant that is about to begin commercial

operations in Thorold, Ontario, will satisfy SaskPower’s requirements in an efficient and economical manner.”

Under the PPA, the project will receive monthly payments that are designed to cover all fixed costs and investment returns. The PPA also provides protection against changes in the market price of natural gas, as fuel costs are passed through to SaskPower. Northland Power will be responsible for operating the plant to achieve specified efficiency and reliability levels. The contractual structure of the project is designed to ensure predictable, stable, and sustainable cash flows over the entire 20-year term of the PPA. — DAILY OIL BULLETIN

Saskatchewan

Emerge focuses $55M capital budget on lloydminster heavy oil Emerge Oil & Gas Inc.’s board of directors has approved a 2010 capital expenditures budget of $55 million for exploration and development activities. This represents a more than 100 per cent increase over the company’s 2009 capital expenditures budget for exploration and development activities.

Nearly 50 per cent of the planned expenditure is expected to be directed toward drilling, completions, and equipping activities. Emerge anticipates drilling a total of 55 (55 net) wells, with over 80 per cent of the locations planned for the Lloydminster area, primarily in Saskatchewan, targeting multi-zone, heavy oil within the Mannville group.

A further 25 per cent of the company’s 2010 capital budget is allocated to reactivation and recompletion activities, primarily on certain shut-in and suspended wells acquired by the company in November. Emerge expects to target up to 110 wells in its reactivation program, with the majority focused in the company’s Lloydminster heavy oil area.

Approximately 12 per cent of the company’s capital budget is expected to be invested in facilities and infrastr ucture projects, primarily in the Lloydminster area, to accommodate the growth in oil production in the area.

This will include expansion of central

in 2009. Current production, based on field estimates, is approximately 4,600 boe per day, weighted approximately 98 per cent to oil. To date in 2010, the company has drilled nine (nine net) Sparky heavy oil wells in Saskatchewan at a 100 per cent success rate.

To date in 2010, the company has drilled nine (nine net) Sparky heavy oil wells in Saskatchewan at a 100 per cent success rate.

oil batteries, construction of gathering systems and a sales line, and waterflood project infrastructure.

Execution of the 2010 capital budget is anticipated to result in 2010 average daily production of between 5,400 to 5,600 barrels of oil equivalent (boe) per day as compared to average daily production of approximately 1,240 boe per day

In the fourth quarter of 2009, the company grew production to an average 2,400 boe per day, up 69 per cent from the third quarter of 2009, and up 2,186 per cent compared to the fourth quarter of 2008.

The company drilled 14 (14 net) heavy oil wells in the fourth quarter of 2009 at a 100 per cent success rate.

— DAILY OIL BULLETIN

OIL & GAS INQUIRER • April 2010

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April 2010 • OIL & GAS INQUIRER

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Central Canada

Photo: Questerre Energy Corporation

Successful wildcat well generates shale gas excitement in Quebec

Quebec offers favourable royalty and tax rates plus a premium position near natural gas markets.

In late Februar y, Questerre Energ y Corporation announced successful stimulation results from the St. Edouard No. 1A horizontal well in the St. Lawrence Lowlands, Quebec. The horizontal well was successfully completed with eightstage fracture stimulations. Cleanup and flow back commenced Jan. 29. Initial rates were over 12 million cubic feet (MMcf) per day. During the test, the well flowed natural gas at an average rate of over six MMcf per day.

The well is currently still flowing on an extended production test. The current rate is approximately five MMcf a day at a flowing tubing pressure of 4,412 k ilopascals (640 pounds per square inch) with a choke size of 5/8 inch. “This first horizontal result is simply excellent!” said Questerre president and CEO Michael Binnion.

During the completion, microseismic data was gathered using the St. Edouard No. 1 vertical well as a monitoring well.

Preliminary analysis indicates the fracs were successful in stimulating sufficient rock volume in the entire Utica sequence. “The initial rates from St.

Edouard exceed our internal threshold for commercial production on a per-well basis based on targeted development costs,” Binnion said.

The company and the operator are evaluating pipeline options to tie in the St. Edouard location. Questerre’s shares hit a 20-month high in response to the successful wildcat exploration well.

Meanwhile, Forest Oil Corporation’s will be shooting seismic in Quebec’s Utica shale play as soon as the snow clears in preparation for its next horizontal well, which is targeted for 2010. “The excellent data point that was just released from an industry well further demonstrates the evolution of horizontal technology applications in shale plays, particularly here,” said J.C. Ridens, executive VP and COO. “We were a first mover in this play,” Ridens noted. “Just as others have gone to school on our work, we now have the opportunity to do the same. As we said earlier, our large acreage position in Quebec has excellent term and a favourable royalty and tax regime, and this combined with a premium gas market results in an enviable position.”

Last year, Forest divested about 120 MMcf of Canadian, non-operated properties and the company has signed agreements to sell a further roughly 13 MMcf of remaining non-core Canadian properties, expected to close in the first quarter of 2010. The American producer now has has seven or eight rigs running in Canada, where it plans to spend $168 million this year, up 26 per cent over last year.

Beyond Quebec, Forest’s focus will be on the Deep Basin and includes an infill program underway at Wild River and Evi. About $20 million of its budget will be spent on pipelines. Regulatory approval for further downspacing at Wild River was received last year and the company is taking advantage of that along with Alberta’s revised royalty program and drilling credits, said Ridens.

The company saw service costs fall in 2009, probably by more than the 20 per cent predicted at the beginning of the year, said Craig Clark, Forest’s president and CEO. The exceptions to lower overall costs were for mud, frac proppant, and fuel.

Forest is somewhat insulated from rig costs, having its own rigs, but is experiencing some pressure from ser vice companies this year as well, mostly in pressure pumping, fracs, tubulars, and directional drilling, said Clark, adding that the company is projecting a 5 to 10 per cent increase in service costs in 2010.

The company reported a net loss of $923.1 million for 2009, due primarily to a non-cash ceiling test writedown of oil and gas properties. For the year, the company’s adjusted net earnings of $200 million decreased 46 per cent, while adjusted cash flow of $638 million decreased 43 per cent from the corresponding 2008 period.

“Looking forward to 2010, we expect to grow our production organically from our more focused asset base at an expected rate of 10 to 12 per cent, while maintaining one of the lowest cost structures in the industry,” Clark said.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • April 2010

53

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April 2010 • OIL & GAS INQUIRER

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Corridor has big plans for New Brunswick, N.l., and Anticosti

Corridor Resources hopes to conduct wildcat drilling on Quebec’s remote Anticosti Island this year.

Corridor Resources Inc.’s 2010 capital expenditure program of $28.6 million will include drilling and completing two natural gas wells in the upper part of the Hiram Brook formation in the McCully field of southern New Brunswick.

The company’s priorities for 2010 also include: • conducting a joint-venture, four-well oil exploration program on Anticosti Island (contingent upon participation of Corridor’s joint-venture partner); • conducting a site survey at a proposed drilling location on the Newfoundland side of the Old Harry structure in the Gulf of St. Lawrence in preparation for drilling an exploration well on this giant prospect.

Corridor is immediately commencing efforts to contract a suitable floating drilling rig to drill an initial well on this prospect within the next two years; • installing an inlet separator and compressor at the McCully gas plant; • drilling an exploration core-hole at Sally’s Brook, about 17 kilometres north of the McCully field, to test the oil and gas potential of the Hiram Brook and Frederick Brook formations at that location; and

• undertaking gas plant maintenance and other corporate expenditures.

An additional $3 million ($2.7 million net to Corridor) in expenditures are planned for McCully well workover operations in 2010 and are budgeted for in operating expenditures instead of the capital budget.

The company budget for 2010 forecasts that one new McCully horizontal development well (L-37) will be drilled, completed, and tied in by the end of May 2010 at an estimated net cost to Corridor of $7.5 million, forecast to initially add six million cubic feet per day (100 per cent Corridor). A second wholly owned horizontal well is forecast to be drilled, completed, and tied in by the end of the fourth quarter at a net cost to Corridor of $7 million, assuming the well is drilled from the same well pad as L-37.

Additional funds have been allocated to other activities, including $6 million to install an inlet separator and compressor at the McCully gas plant (which Corridor forecasts will add five million cubic feet per day to the gross field production rate), $4.4 million for Corridor’s share of the four exploration wells on Anticosti Island, $600,000 for drilling an exploration core hole at the

Sally’s Brook prospect 17 kilometres north of the McCully gas plant, $800,000 for a wellsite survey at Old Harry, and $2.3 million for gas plant maintenance and other corporate assets.

Corridor has farmed out the majority of its New Brunswick properties with shale gas and oil potential to Apache Canada Ltd., wherein Apache has committed to a $25 million appraisal program that is to be completed prior to June 1, 2011.

Consequently, no expenditures by Corridor for oil exploration or shale gas appraisal in New Brunswick are planned for 2010.

The Apache program is of particular interest to Corridor because of its potential to open up the initial development of the resources outlined in an independent shale gas resource study conducted by GLJ Consultants of Calgary describing a shale gas resource-in-place potential in excess of 60 trillion cubic feet in the Sussex/Elgin area of New Brunswick.

The company’s 2010 capital budget is designed to be affordable within its projected fiscal capacity, including approximately $11 million of working capital carried forward from its 2009 fiscal year plus about $25.5 million of anticipated net cash flow from McCully production during 2010.

Corridor is proposing to drill the McCully L-37 horizontal well using an oilbased mud to minimize formation damage during drilling operations. Based on the quality of reservoirs observed in the upper part of the Hiram Brook formation in the McCully P-47, J-47, and I-47 wells, the company expects that a horizontal well penetrating this part of the reservoir section may be free of bitumen and productive based on perforating stimulation alone (i.e. no fracs).

This completion approach, if successful, will be significantly less expensive than conducting a multi-stage frac program in the horizontal leg of the well.

However, the option to carry out a multistage frac program will be retained in the event the perforated completion is unsuccessful and provided it can be economically justified.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • April 2010

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April 2010 • OIL & GAS INQUIRER

International

Technology drives Schlumberger/ Smith international merger

by Pat Roche

Schlumberger thinks pumping power will become less significant as better drilling techniques evolve.

Schlumberger Ltd. and Smith International, Inc. announced on Feb. 21 that the two companies will merge. Corporate spokesmen said the move is unlikely to result in job cuts because the two businesses are complementary rather than competitive, the companies have already been through major layoffs, and the petroleum industry appears poised for an upturn.

Andrew Gould, Schlumberger’s chairman and CEO, told a conference call that a key driver behind the merger is his company’s sense that the role of fracturing may decline over the long term in proportion to drilling—thanks to shale gas. In response to an analyst’s question, Gould explained his technological thesis in some detail.

“I don’t think there is any doubt that, long term, shale gas is going to be one of the big new energy sources, both in the U.S. and overseas. However…I don’t think that the actual optimum technology set for producing shale gas has yet been defined,” the Schlumberger chairman said.

“At the moment, we’re doing it by brute force and ignorance. In other words, we drill horizontal wells and then we frac them geometrically. And therefore there’s

going to be a lot of progress, and I would not be at all surprised to see that some of that progress means perhaps more drilling and less fracing,” Gould predicted.

Schlumberger believes more drilling is needed to sustain and increase world oil and gas output. Increasingly, wells are being drilled in more challenging environments and in new resource plays, with longer and more complex profiles. The company already has the expertise in the measurement and steering technologies that are necessary to drill these profiles.

“We firmly believe, however, that the next breakthrough will be through engineered drilling systems that optimize all the components of the drill string, allowing our customers to drill more economically in demanding conditions,” Gould said. “This step-change in drilling performance and well productivity must come from combining measurement and steering capabilities with the engineering and design of the complete bottomhole assembly and its various components—including the drilling fluids and drill bit—with the hydraulic and mechanical environment in which they operate.

“Smith’s drilling technologies, other products, and expertise complement our own, while the geographical footprint of Schlumberger means we can extend our joint offerings worldwide,” John Yearwood, Smith’s CEO, told the conference call. “We believe this transaction brings significant benefits to the customers and shareholders of both companies, and we look forward to welcoming Smith employees to Schlumberger.

“The fact that there is virtually no product or service overlap between the two companies, and the clear technological and operational strength that comes with the Smith portfolio, means that there is no redundancy as a result of this combination.” The all-stock deal is expected to close in the second half of 2010.

Smith’s Canadian revenues were US$638 million last year and $851 million in 2008, which compares with only $287 million in 2002. Smith is a majority owner of CE Franklin Ltd., a major Calgary-based oilfield supplier. Franklin has 434 employees, according to the Canadian Oil Register.

Schlumberger no longer discloses its Canadian revenues but had Canadian revenues of $410 million in 2003, the last year it reported results from its Canadian segment. Stephen Whittaker, a Parisbased spokesman for Schlumberger, said it’s too early to rule out job cuts altogether, but “given the complementary nature of our operations, we wouldn’t think so.

“We’ve all been through the terrible job layoffs of the last 18 months and both Schlumberger and Smith are right-sized,” Whittaker told the Daily Oil Bulletin.

He said a third factor making job cuts unlikely—besides the global down sizing and lack of overlap—is the industry is “probably not too far off entering a new phase of growth.”

The merger is subject to various conditions including Smith stockholder approval and regulatory approval. Schlumberger expects to realize incremental pretax synergies of $160 million in 2011 and $320 million in 2012.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • April 2010

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On the Job

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JOB CArEErS IN ThE OILPATCh

Clark luhning Age:

31

Title:

Territory manager

Company:

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location:

Fort McMurray, Alta.

Education: Bachelor of Mechanical Engineering, University of Victoria

how busy are the oilsands this spring?

You can feel the pace starting to heat up. Although companies are nowhere near as busy as a couple of years ago, I think another round of boom-level activity is probably shaping up.

What do you do?

I’m a valve specialist. There are no schools that specialize in this technology; you learn through experience. I’ve torn down a lot of valves doing failure analysis, I’ve consulted on design and sizing the best valves to meet the customer’s application, and I’ve sold valves. Right now, I manage Tyco’s shop in Fort McMurray—as far as I know, we’re the only valve manufacturer that has a service operation in this region.

What drew you to this industry?

What sort of valve jobs do you handle?

When I was a boy, I was obsessed with figuring out how things work. I col-

valves used for bitumen production and processing are really large—our

lected old watches and took them apart—of course, the real challenge was

seven-person shop in Fort McMurray has performed the biggest jobs ever

trying to put them back together! I also have a strong family connection to

seen in Canada, and maybe North America. We just brought in a 33,000-

the oilsands; my father helped develop SAGD [steam assisted gravity drain-

pound test stand that can handle ANSI and API valves as well as knife gates.

age] in its early days. I worked on Suncor’s Firebag SAGD project before I

I constantly juggle between regularly scheduled jobs and unexpected situa-

began working with valves.

tions, which typically need a rush response.

Our work is often performed under high-pressure conditions. Right now,

What are the advantages of being located in Fort McMurray?

for example, we have two very large valves in the shop that were damaged

We are in the service business, which means we need to be close to our custom-

in a fire. Until they’re repaired, a customer’s coking unit will remain down,

ers. They often stop by to see their work being done, sometimes 10 guys at a

and that’s expensive. These are specialty valves that we’ve seen in our shop

time. It’s easier to explain what has to be done when they see it. Also, if a part

before. After reviewing our previous service records, we had an idea of what

is made from a metal that will take a long time to make or repair, I can easily talk

was coming and issues we could be facing. This allowed us to proactively

to the producer's own specialists and work out a suitable alternative material.

source the required parts and material and to meet the deadline.

OIL & GAS INQUIRER • April 2010

59

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HAPPY BIRTHDAY COSSD! You know you’ve left your mark when someone can still remember that first encounter, even more than a decade later.

Brian Zinchuk, editor of Pipeline News, recalls first hearing about the Canadian Oilfield Service and Supply Directory (COSSD) while working as a pipeliner during the late 1990s. “Someone back then told me, ‘You need to get this book.

It is the bible of the oilpatch.’”

The COSSD is just memorable that way.

Now celebrating its 30th anniversary, the directory has grown remarkably since its first edition in 1981—though the instantly recognizable yellow cover has remained a constant. For users, “the big yellow book” is indispensable for doing business in the Canadian oilpatch.

Lorne Stark, vice-president of sales and marketing for Maverick Oilfield Services, agrees. “I think it’s a very useful tool,” he says. “Our men carry it around in their pick-up trucks. It provides them with information in one concise format.”

When asked to account for the COSSD’s continued success, directory publisher Agnes Zalewski says, “The COSSD has done some things very well, and one has been to be very comprehensive.” With over 12,000 listings in 1,900 categories, the directory offers an exceptionally detailed portrait of the service and supply sector in the Western Canadian Sedimentary Basin.

However, don’t let the name fool you.

The directory is more than just service and supply. It also provides information on explorers and producers, environmental companies, and hotels and motels, all divided up alphabetically, and by category and town location. The goal is to make sure users can find the information they need as quickly and easily as possible.

Accessibility is the key word when it comes to the directory, which is why it is offered in a wealth of formats beyond the traditional print book. Keep the DVD version with your laptop, or search for a business online at cossd.com. Whatever

30 the situation, there’s a version of the COSSD to suit your needs.

Camille Legace, owner of Nitrogen Technologies of Canada, is an enthusiastic user of the directory online. “If I’m in the office, first and foremost, it’s the web page,” he says, although he still keeps several copies of the book in the office, and also hasEst. handed out the DVD to clients.

1980

For most users, one version of the directory just isn’t enough. “I always start with the website,” Zinchuk explains, “and then I keep a copy in my truck at all times.”

You just never know where you’ll find yourself needing COSSD. That’s why the directory is now offered on GPS Garmin units, new for the 30th edition. If your equipment breaks down in the field and time is of the essence, one click of a button can guide you right to the front

door of the nearest supplier. “Every advertiser on cossd.com has their data now delivered on a Garmin,” explains Rob Pentney, sales director for the COSSD. “You can download it from our website, but if you buy a copy of PatchMap, it comes bundled as a no-cost extra.”

Innovating with new technologies is a major part of the directory’s past and continued success. When asked to speculate about the future of the COSSD, Pentney is optimistic. He sees the directory’s information being delivered in many new ways as technology evolves, but always with the same goal of providing users the best resource for making good buying decisions.

As Pentney says, the coming years promise to be as memorable as the directory’s proud history. “In my mind, this product has an even brighter future than it has a past.” ■

COSSD.COM THE BUYER’S GUIDE FOR THE CANADIAN OIL & GAS INDUSTRY 1-800-563-2946

Tools of the Trade

TOOLS

OF ThE TrADE A LOOK AT NEW TEChNOLOGIES

Ecoquip Series 9000 hydraulic pumpjack

Who is ecoquip Artificial lift ltd.?

We manufacture, rent, and service the Ecoquip 9000 series hydraulic pumpjacks. Since 1995, Ecoquip has provided a rental fleet for servicing western Canada, while also selling its exceptionally reliable pumping units to oil producers for their testing, problematic, and permanent wells. The familyowned company operates its manufacturing and testing facility in Calgary.

What is the ecoquip 9000–6 series hydraulic pumpjack?

The Ecoquip 9000–6 series is a portable unit capable of replacing the work of a standard 640 or 912 pumpjack despite being smaller in size. Its patented design utilizes a free-floating piston and a nitrogen counterbalance ballast. Stroke lengths can be set from 4 inches up to 144 inches inclusively, with speeds reaching six or seven strokes per minute and lifting capacity up to 32,000 pounds.

What are the competitive advantages of this product?

A crew of two can set up the Ecoquip unit in a matter of hours. No site set-up is needed, and no footprint is left behind. Changes to stroke speeds and lengths are handled by one person from a rugged control panel, resulting in substantial service savings. Our nitrogen counterbalanced system acts as a shock absorber, which smoothes and controls the pumping of your well. This improved performance cuts fuel consumption and reduces wear on surface equipment, downhole pumps, and rods. There are no jumping hoses, and the pressure peaks are minimal. Nor does the Ecoquip unit employ proximity switches, which are unreliable and can cause shutdown. Instead, we utilize long-life internal controls that withstand all weather conditions.

Answered by chris grabill, vP operations for ecoquip Artificial lift ltd.

What field experience do you have with ecoquip 9000–6 series?

It’s our most common and functional model. We have over 40 units in our rental fleet as well as a growing number of customer-owned units. Only rarely does a 9000–6 series pumpjack shut down unexpectedly, but our technicians are always available to advise operators. In addition, to ensure that no unit is shut down for more than 24 hours, Ecoquip maintains its own fleet of service vehicles. We offer rental and repair service in Calgary and also through an authorized dealer in Manning, Alta., which helps to provide convenient province-wide coverage.

What future development does ecoquip have in mind for this technology?

We recently developed a more reliable control panel with a low 10 to 30 volt power requirement, a wider operational temperature range of minus 40 to plus 70 degrees Celsius, improved ease-of-use controls, and better stroke management. Improved cooling of the unit is provided by the use of a hydraulic motor. Standard Ford or GM multi-cylinder engines or electric motors are still used for power. Ecoquip’s reputation for portability and dependability in harsh environments has drawn international interest, and we are exploring opportunities to prove our equipment in new and operationally challenging areas.

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