Oil & Gas Inquirer - October 2009

OCTOBER 2009 � $6.00

Keeping readers regionally informed

Dawson Creek Construction patriarch Herb Nodes rides the Montney play

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TransCanada’s $12B megaproject will pipe Alberta crude as far as Texas

Bring Cash B.C. strives to capture more service and supply dollars Scott Gordon, business development manager for Energy Services BC

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Table of Contents

Keeping readers regionally informed

F E A T U R E S

6

october 2009 • OIL & GAS INQUIRER

12

Bring Cash

20

Riding the Montney

24

The bullet line

by Mike Byfield

Northeastern British Columbia mounts a drive to capture more oilfield service and supply dollars

by Mike Byfield

Herb Nodes, patriarch of the service sector around Dawson Creek, grew up in a homesteading family

by Graham Chandler

TransCanada’s Keystone XL pipeline will transport bitumen from Hardisty directly to Texas

Table of Contents

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

31

ENGINEERED CONTAINMENT ADVANTAGES

N E W S

British Columbia

49 Southern Alberta • Calfrac expands its capital budget and acquires Pure Energy assets

• B.C. government’s stimulus package

• Canyon Services maintains revenue

could boost field activity

despite fewer jobs

• British Columbia government approves 31 new road and pipeline projects under royalty program

35

57

• Buzz over Three Forks–Sanish oil

Northwestern Alberta/Foothills

formation spreads to Saskatchewan • Petrobank-TriStar deal creates a

• Galleon will focus on infrastructure

dominant heavyweight

before shifting to drilling

39

Northeastern Alberta

63

pipeline workers are being injured

three more THAI projects “extremely profitable”

45

Central Canada • National Energy Board says more

• Despite difficulties, Petrobank prepares • Devon says its Jackfish SAGD project is

Saskatchewan

65

International

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• Ford’s new commercial van will plug

Central Alberta

into the American power grid • Brigham completes 24-stage frac

• More oil and gas people sought help for alcoholism in 2006–2008 • 4-H kids learn what’s a mile below the wheat

I N

10

E VE R Y

I S S U E

Statistics at a Glance

69

Rig Talk

Completions data, spot gas prices, gas

The Universal Pump Hold Down

storage, drilling activity, and more

System from Swift Current-based Dura Products allows a conventional

67

reciprocating rod pump or rotational

On The Job

progressive cavity pump to be installed

Jordan LaBonte operates and

interchangeably into the same well.

troubleshoots in the water treatment plant at Devon Canada’s Jackfish SAGD project in northeastern Alberta.

by Deborah Jaremko

70

Political Cartoon

For a dealer in your area

1-866-TCA-7771 6404 – 53 Street, Taber, AB T1G 2A2 Ph: 403-223-1113 Fax: 403-223-6312

tcamark@telus.net OIL & GAS INQUIRER • october 2009

7

Screw Piles Piledriving Pile Supply Pile Pre-drilling Cranes & Pickers Bed & Winch Trucks Hydrovac Service

1.877.334.7453 www.dfi.ca Edmonton • Rycroft • Brooks • Grande Cache • Peace River • Edson

Editor’s Note

Vol. 21 No. 10

Mike Byfield | mbyfield@junewarren-nickles.com

President & ceo Bill Whitelaw | bwhitelaw@junewarren-nickles.com

Bombs and jobs

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

Samantha Kapler, Marisa Kurlovich, Kelley Stark proofing@junewarren-nickles.com Contributors

Graham Chandler, Lynda Harrison, James Mahony, Pat Roche, Kelley Stark, Paul Wells Creative Print, Prepress & Production Manager

Michael Gaffney | mgaffney@junewarren-nickles.com Publications Manager

Audrey Sprinkle | asprinkle@junewarren-nickles.com Publications Supervisor

Rianne Stewart | rstewart@junewarren-nickles.com LEAD, CREATIVE SERVICES

Tina Tomljenovic | ttomljenovic@junewarren-nickles.com Graphic Designer

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Birdeen Jacobson, Cathlene Ozubco, Alanna Staver

Sales DIRECTOR OF SALES

Rob Pentney | rpentney@junewarren-nickles.com SALES MANAGER, MAGAZINES

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

Elizabeth McLean | atc@junewarren-nickles.com Marketing Senior Marketing Coordinator

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Ryan Mischiek | rmischiek@junewarren-nickles.com Marketing designer

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Between October 2008 and July 2009, six bombs have exploded at EnCana facilities in the Tomslake district of northeast British Columbia, near Dawson Creek. The bomber sent a note to a newspaper in mid-July, claiming that he’d resume in three months if EnCana doesn’t shut down in the region. So far, hundreds of RCMP investigators have failed to track down the criminal.

A lot of people in Dawson Creek appreciate EnCana. Among its local donations and projects, the Calgary-based giant helped fund the EnCana Events Centre, a sports and concert venue that attracts big-name stars to the small city. Brooks & Dunn, Lonestar, Alan Jackson, Rita MacNeil, and figure skater Kurt Browning are current billings at the 6,500seat facility.

On the other hand, some people around Dawson Creek don’t like EnCana. British Columbians, being human, sometimes resent interlopers from Alberta. Also, the Calgarybased producer was the first big energy operator to disturb the bush-and-farm country around Tomslake.

Equally prone to bias are local energy service companies and contractors that didn’t win contracts for EnCana’s Montney gas resource play in the district. To complicate matters further, just down the highway from Tomslake is the family commune run by Wiebo Ludwig near Hythe, Alta. In 2001, Ludwig was sentenced to 28 months in prison on charges relating to bombings and vandalism. His targets were EnCana facilities.

Some local oil and gas workers think the current bomber is likely someone who has worked on EnCana operations. That belief stems from the fact that the terrorist has accurately identified low-pressure vertical wells as targets. Fortunately, these facilities represented a relatively modest risk to life. Heaven help anyone nearby if a future bomb lifts the top off a big horizontal gas well or blows up a major processing plant. These potential targets are all but impossible to guard against a skillful intrusion.

Will the bomber now fade away? Will he (or they, or conceivably she) continue to create small-scale incidents? Or will the violence escalate? On the Internet’s wackier green forums, I’m told that eco-extremists have urged the bomber to draw blood.

Northeastern B.C.’s shale and tight gas projects rank among the few strengths in a national economy and energy sector that are struggling to move from recession to recovery. (Look for other stories in this issue, such as TransCanada’s Keystone pipeline project, as part of JuneWarren-Nickle’s Energy Group’s Recession to Recovery coverage to help you navigate through the slow recovery from the global recession. We've created a logo to help you easily spot coverage.) If the Tomslake violence escalates, the bomber may well delay the creation of many jobs even if we’re fortunate enough to avoid outright deaths.

Subscription Inquiries

Telephone: 1.866.543.7888 Email: circulation@junewarren-nickles.com Online: junewarren–nickles.com Oil & Gas Inquirer is owned by JuneWarren-Nickle’s Energy Group and is published monthly.

GST Registration Number 826256554RT. Printed in Canada by PrintWest. ISSN 1204-4741 | © 2009 1062810 Glacier Media Inc. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number 40069240.

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

N E X T

I S S U E

Unconventional gas

If you know an admirable person to profile in

Methane in high volumes from shales, tight

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

rock, and coalbeds continue to revolutionize

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

the natural gas market in North America.

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

In November, Oil & Gas Inquirer looks at

email mbyfield@junewarren-nickles.com.

Canadian contributions to this extraordinary

In fact, feel free to sound off about any concern

development.

at all—that’s a personal invitation.

O I L & G A S I N Q U I R E R • OCTOBER 2 0 0 9

9

Stats

FAST NUMBERS

US

AT A GLANCE

tcf

EnCana’s gas-in-place estimate for B.C.’s Horn River Basin, which it considers the richest shale play in North America

Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin

MONTH

OIL

GAS

OTHER

T O TA L

MONTH

OIL

GAS

D RY

SERVICE

T O TA L

Sep 2008 Oct 2008 Nov 2008

414 297 273

1,084 937 1,075

200 241 136

1,698 1,475 1,484

Sep 2008 Oct 2008 Nov 2008

728 636 594

1,250 1,308 1,313

173 194 142

77 69 45

2,228 2,207 2,094

Dec 2008 Jan 2009 Feb 2009

496 156 116

1,793 606 899

200 96 120

2,489 858 1,135

Dec 2008 Jan 2009 Feb 2009

917 248 269

2,380 813 1,060

173 70 113

137 47 36

3,607 1,178 1,478

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

Wells Drilled In British Columbia

Wells Drilled In Saskatchewan

Source: B.C. Oil and Gas Commission

Cumulative to September 4, 2009 Source: Saskatchewan Energy & Resources

MONTH

WELLS DRILLED

C U M U L AT I V E *

Sep 2008 Oct 2008 Nov 2008

83 66 61

713 779 840

Dec 2008 Jan 2009 Feb 2009

79 125 117

919 125 242

Mar 2009 Apr 2009 May 2009

75 33 26

317 350 376

Jun 2009 Jul 2009 Aug 2009

19 34 22

395 429 451

* from year to date

10

500

$37B

Chevron’s estimated capital cost for its Gorgon LNG project in Australia

OCTOBER 2 0 0 9 • O I L & G A S I N Q U I R E R

OIL

GAS

OTHER

D RY

T O TA L

247 62 24 32

5 29 172 0

8 6 3 13

5 18 4 22

265 115 203 67

24 8 35 334

0 0 0 0

0 0 0 0

0 0 0 0

24 8 35 334

271 70 59 366

5 29 172 0

8 6 3 13

5 18 4 22

289 123 238 401

Vertical Wells

Lloydminster Kindersley Swift Current Estevan Horizonal Wells

Lloydminster Kindersley Swift Current Estevan Total Wells

Lloydminster Kindersley Swift Current Estevan

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 3.50

$2.63/GJ Total vol.: 1,321 TJ Transactions: 149

2.5

2.0

Tcf

Cdn$/GJ

3.0

Aug 12

Aug 19

Aug 26

Sep 2

in the United States

3.25

3.00

Sep 9

3.39 Tcf Year ago: 2.89 Tcf 5-year avg: 2.89 Tcf

Aug 7

Aug 14

Aug 21

Aug 28

Sep 4

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada September 14, 2009 Source: Rig Locator

Alberta August 2009 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

AC T I V E (Per cent of total)

Western Canada Alberta

118

468

586

20%

British Columbia

38

76

114

33%

Manitoba

7

5

12

58%

Saskatchewan

55

72

127

43%

218

621

839

26%

0

3

3

0%

WC Totals Northwest Territories

OIL WELLS

Alberta

GAS WELLS

Aug 09

Aug 08

Aug 09

Aug 08

Northwestern Alberta

16

38

22

108

Northeastern Alberta

12

21

0

3

Central Alberta

68

181

59

122

5

22

131

132

101

262

212

365

Southern Alberta TOTAL

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada September 14, 2009 Source: Rig Locator

Alberta August 2009 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

AC T I V E

Western Canada

C OA L B E D M E T H A N E

Alberta

Alberta

281

608

889

32%

British Columbia

11

29

40

28%

Manitoba

6

1

7

86%

Saskatchewan

107

71

178

60%

WC Totals

405

709

1,114

36%

1

1

2

50%

Aug 09

Aug 08

Aug 09

Aug 08

Northwestern Alberta

0

0

5

4

Northeastern Alberta

0

0

12

21

27

10

30

72

6

6

0

0

33

16

47

97

Central Alberta

Northwest Territories

BITUMEN WELLS

Southern Alberta TOTAL

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O I L & G A S I N Q U I R E R • OCTOBER 2 0 0 9

11

Bring

Cash

Northeastern British Columbia mounts a drive to capture more oilfield service and supply dollars

by Mike Byfield

12

OCTOBER 2 0 0 9 • O I L & G A S I N Q U I R E R

British Columbia has a population of 4.4 million, but only 1.6 per cent live in the northeastern region of the province. Rick Pavlis, a trucker and construction contractor from Dawson Creek, recalls how another oilfield service operator confounded former B.C. Energy Minister Richard Neufeld with that statistic. The politician informed an oil and gas audience that his government’s royalty policies had generated more than 140,000 petroleum service jobs. “That’s more than two jobs for every man, woman, and child on this side of the Rockies, as this guy pointed out,” Pavlis recalls. “He asked Neufeld if most of those jobs were going to workers from Alberta. No one answered his question.”

The minister was a Liberal MLA for Peace River North, a riding in the heart of oil and gas country. Pavlis and Bob Fedderly from Fort St. John lobbied him relentlessly in favour of forcing Calgarybased producers to use local contractors and suppliers as much as possible. Pavlis has also complained on oilfield leases

about the presence of Alberta workers when B.C. alternatives were available.

“They’re our champions,” comments the president of another B.C. service firm, who requested that his name not be used.

“They shout what most of us won’t say in public because we don’t want to offend the producers who hire us.”

Confirming Pavlis’s case is A lec Pryndik, founder of Pryndik Bit & Supply Ltd. He’s been re-tipping drill bits in northeastern B.C. since 1968. “Despite the growth of the service sector in this region, it’s harder than ever for a local company to sell to producers,” says Pryndik, who was named Oilman of the Year by the Fort St. John Petroleum Association in 2008.

“At one time, the drilling engineer or consultant had quite a bit of authority in how a well was drilled and purchasing some services. Nowadays, all of the decisions are handled directly from Calgary, down to small details.”

Calgary-based producers naturally tend to buy from trusted associates in

their own province, Pryndik explains.

“That means a lot of B.C. business goes to companies operating from Grande Prairie [in northwestern Alberta]. I have to say that a lot of Albertans have developed big egos. If a guy like me goes to Calgary on a sales visit, the snootier executives won’t even bother to see him,” the veteran entrepreneur reports. “A B.C. service company might break into the market by having a permanent salesman in Calgary.

But supporting that fellow will cost $20,000 a month, which is way beyond what a smaller contractor can afford.”

Adding to the pressure on B.C. service firms is the activity downturn that’s currently bedevilling the upstream natural gas industry. In Fort St. John, Pryndik says service sector revenue appears to be off by nearly 50 per cent over the last six months. “We had 120 to 130 rigs in northeastern B.C. last winter. This year it’s less than 40,” the bit refurbisher states. A provincial royalty incentive that came into effect as of September should help boost

A Trinidad rig drills in the Montney play near Tomslake. Alberta workers joke that B.C. stands for "bring cash" and Energy Services BC agrees with that point.

O I L & G A S I N Q U I R E R • OCTOBER 2 0 0 9

13

Feature

“We had 120 to 130 rigs in northeastern B.C. last winter.

This year it’s less than 40.”

— Alec Pryndik, Founder, Pryndik Bit & Supply Ltd.

drilling activity. Still, hard times are expected to continue, particularly south of Fort Nelson.

Tyler Kosick, president of the Fort St. John Petroleum Association, agrees that activity is slow, although the crunch varies considerably between individual businesses. “We’re going through a big shakeout in the service sector here,” says the head of Trans Carrier Ltd. To generate cash flow, some debt-strapped service operators are reportedly cutting prices to loss-making levels. In due course, unless the downturn ends sooner than expected, most of these floundering firms will go broke. After gas prices rise again, Kosick predicts that the surviving service companies will benefit all the more from reduced competition.

W hen t he upst rea m i ndust r y does regain full profitability, British Columbia’s service sector will be better organized than ever before to grab a 14

OCTOBER 2 0 0 9 • O I L & G A S I N Q U I R E R

greater chunk of producers’ field expenditures. Spearheading that drive is Energy Services BC (ESBC), a trade association with 140 members. Scott Gordon, project manager of ESBC’s Business Development Initiative, insists that its goal is a fair and open bidding process for oil and gas contracts, not for building artificial walls against interlopers from Alberta.

“B.C.’s service sector was relatively small until recent years. In the '80s, about 200 wells were being drilled annually; in the '90s, drilling activity averaged about 430 wells per year; in 2006, drilling peaked at 1,430 wells. We’ve seen substantial growth in the service and supply sector over the past decade,” Gordon says. Many companies who opened their doors or expanded operations to meet the increased activity levels have come upon hard times as conventional drilling activity has dropped by 50 per cent over the past three years. While the downturn in

conventional drilling is a major concern, the two massive natural gas resource plays—the Horn River Basin to the north of Fort Nelson and the Montney play around Dawson Creek, with preliminary resource estimates of many trillions of cubic feet in place—are helping to raise the hopes of many companies who hope to participate in the exploration, development, and operation of these fields.

The Horn River and Montney prospects are both tight reservoirs. Their exploitation is only economically possible thanks to the recent development of efficient formation fracturing technology for long-reach horizontal wellbores. A Horn River frac, for example, can require 1.5 million gallons of water, and other materials and equipment on a similarly massive scale. If the huge prospects prove as profitable as producers hope, they will require plenty of investment in the field for decades to come.

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Feature

Despite low gas prices, no producers have shut in B.C. Montney wells to date, a strong indicator of low-cost operation.

Although the Horn River Basin has not yet been officially deemed an economic play, more than a dozen producers are already committing tens of millions of dollars to new pipelines and processing capacity, also an encouraging signal. “In practical terms, I’m very confident that we’ve got a success on our hands,” says Bill Streeper, a former oilfield trucking company owner who’s now mayor of Fort Nelson. “We’ve had no recession whatsoever in this town.”

G or don c r e d it s f or me r e ne r g y minister Neufeld (now a federal senator) for putting in place a provincial royalty and fiscal regime that attracted billions of dollars in new investment capital.

“Our competitors for that money were Russia, the U.S., and other hydrocarbonproducing countries, not just Alberta,” the ESBC spokesman says. “There was no way to expand the service sector here until investment began to flow here in larger quantities.”

Responsible producers understand their own long-term need for a skilled and stable work force, according to Gordon. “Buy locally, hire locally, pay local taxes—that’s the only way we can create communities with good schools, first-class recreation facilities, and the other amenities that will attract highcalibre employees and their families,” he explains. “I believe producers are on the same side as the provincial government with respect to community building. The municipalities also understand that benefitting from an opportunity of this magnitude requires cooperation across the region. So we’re all pulling together.”

While agreement may have been reached in pr inciple, t he business development manager cautions that implementation of a regional energy strategy will require a major effort.

“Studies indicate that 65 cents of every service dollar spent here in the oil and gas sector was going outside of B.C., mostly to Alberta, and that figure is still close to 60 cents,” he comments.

Blair Lekstrom, B.C. Minister of Energy, Mines and Resources, is now fine-tuning provincial policies to help harvest more producer spending for the regional service sector. In May, Lekstrom was elected for his third term as MLA for 16

OCTOBER 2 0 0 9 • O I L & G A S I N Q U I R E R

“We may not have many voters but we’re being heard within this government.”

— Scott Gordon, Project Manager, ESBC Business Development Initiative

Peace River South. “We’re fortunate that two consecutive energy ministers have come from this area and understand its needs thoroughly,” Gordon says. “We may not have many voters but we’re being heard within this government.”

ESBC says its members face several hurdles in winning a greater share of service contracts from producers: • With remarkably few exceptions, the Canadian oil and gas producer community is headquartered in Calgary. Those producers have what Gordon describes as “long and strong” relationships with Albertabased service and supply companies.

In tough times like the present, the primary attention of many producers may be focused on securing the cheapest possible price for equipment and services, not buying regionally.

• Even if the executive officers of a major producer support a policy of buying locally, that policy may not be effectively deployed across the company at mid-management levels.

• P roducers who genuinely prefer to spend dollars regionally have had no

convenient way of knowing what services are available in northeastern B.C. • Perhaps most important of all, B.C. service firms are rarely large enough to bid on a large contract, say in the $50-million range. Yet big contracts are common in the Montney and Horn River plays.

In response, ESBC has come up with a handful of solutions: • A searchable trade director y went online this summer, listing available oil and gas services in northeastern B.C. • P rocurement offices, each with an experienced staffer, have just been opened in Dawson Creek and Fort Nelson, supplementing the ESBC centre in Fort St. John. The Fort Nelson position is funded by the Horn River Producers Group, a consortium of active players in the area.

• E arlier this year, ESBC held the sixth annual B.C. Oil & Gas Service Sector Trade Show in Calgary. “Even a producer that ignores a service company’s call will probably respond to the invitation of an association,” Gordon maintains.

• P roducers are being urged by ESBC to make their contracting operations easily visible to every potential participant. On large projects, Gordon particularly wants producers to have a significant weighting on how the bidder not only supports the local community, but also on his or her processes to allow subcontracting opportunities for local and regional service and supply firms.

• The official ESBC initiative is being reinforced by more informal measures. For instance, Lekstrom invited the CEOs of major oil and gas producers active in the province to visit his office in Victoria this summer. That trip in itself marks a change from the traditional ministerial pilgrimage to Calgary. Although the substance of that meeting remains private, Gordon has no doubt that the oilmen were urged to place a strong priority on buying regionally for their B.C. operations.

In 2008, Fort St. John had a population of just under 19,000. Dawson Creek, the focus of the still-extending Montney play, stood at about 12,000. Fort Nelson, at 4,700, probably has the best growth prospects of the three northeastern communities due to the shale gas prospects to the north. “In the future, I think all three will wind up being cities of roughly the same size,” Gordon forecasts. “The resource base to support that growth is in place—if we work together.”

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Photos: H.F. Nodes Construction Ltd.

Feature

Herb Nodes says this downturn is not yet nearly as bad as the early 1980s.

The photos to the left portray early operations of his company.

Riding the Montney Herb Nodes, patriarch of the service sector around Dawson Creek, grew up in a homesteading family

by Mike Byfield

If all goes well, Herb Nodes will keep the bulk of his oilfield construction crews and 100 machines busy through this winter. “Our business is off by close to 40 per cent from the peak two years ago, and we’re still not sure what the field activity levels will be later this year,” says the founder and president of H.F. Nodes Construction Ltd., based in the Dawson Creek area of northeastern British Columbia.

With drilling and development activity slowing down somewhat in the Montney resource play, Nodes realizes that the local service sector will inevitably experience layoffs. Still, he detests them. “A good worker develops a genuine commitment to the job. He’ll go the extra mile to do what has to be done every day, and that’s how you create great teams,” says the native northerner. “If you lay that fellow off, he may come back to work later, but his attitude is never quite the same. A trust has been broken.”

Ask any local rig hand or catskinner who’s the patch patriarch of the Dawson Creek district and you’ll likely

20

OCTOBER 2 0 0 9 • O I L & G A S I N Q U I R E R

be di rec ted towa rd Herber t Fra n k Nodes. His company’s core staff numbers upwards of 75, a majority of them longtime employees in an often transient industry. Besides business competence and integrity, the man has an exceptionally bright twinkle in the eye that beams good will toward all comers.

I n fac t, Nodes ’ neighbou rl i ness saved his financial bacon in the early 1980s after a major producer committed a minor trespass. At the time, the federal National Energy Program and low commodity prices had combined to devastate the energy business in the West.

“It was a brutal period for the service sector, far worse than today,” the company founder recalls.

Without receiving prior permission to do so, a crew working for Canadian Hunter happened to go down a private road on land that belonged to the Nodes family. “The company landman acknowledged that a trespass had occurred,” Nodes recalls. “I told him that no damage had been done and he should just pay me whatever compensation seemed suitable.”

In due course arrived a cheque for $250, a less-than-generous settlement that Nodes accepted without complaint.

“Canadian Hunter ’s manager in Grande Prairie called to thank me,” the oilfield contractor says. “He said he’d try to steer some work our way. Starting with a few site cleanups, we’ve done a lot of work ever since for CanHunter [and its successor companies] Burlington and ConocoPhillips. Many small contractors went broke in the early ’80s and, without that break, I couldn’t have made my equipment payments either.”

Nodes points out that the decision to expand presents a risky yet unavoidable puzzle for service firms. Much more may be on the line than a simple greed for growth. “During boom periods, producers must put a lot of pressure on their service contractors and suppliers to expand their capacity. A service company that doesn’t respond to that pressure will often risk losing its customers,” the entrepreneur comments. “On the other hand, the downturn will always come, sooner or later. At that point, it’s the service companies that

Feature

O I L & G A S I N Q U I R E R • OCTOBER 2 0 0 9

21

Feature Pouc e C oup e w a s nor t he a s te r n B.C.’s first district capital, home to a bank, an RCMP post, and so on. “Back then, practically every quarter section in the Tomslake district was occupied but no one could make a living raising crops or beef,” Herb Nodes says. Some families had a sawmill, others raised dairy cattle or mink. Many found jobs away from their own land. Joe Nodes, for example, laboured on the A laska Highway when the U.S. Army began its construction in 1942. Later he specialized as a cook and baker.

To attend school, Herb Nodes walked nine miles daily. “I loved growing up here,” says the 73-year-old pioneer, whose formal education stopped at Grade 8. “We lived near wonderful folks like the Gunters, who drove their horses here all the way from Saskatchewan and raised sheep.” Vic Leslie, another neighbour,

“In the early 1980s, the U.S. was doing bet ter t ha n Ca nada, a nd t hat drew some equipment out of this market.

Today both countries are pretty much in the same boat, and the recovery of the ser vice sector in western Canada may be slower.”

Coping with risk and hardship is second nature to the families that pioneered North America’s last agricultural frontier. The B.C. portion of the Peace River Valley was not opened to homesteading until 1912. Although exceptionally cold and geographically isolated, the region drew a steady stream of settlers from prairie droughts and Europe.

Among those immigrants was Joe Nodes, who f led Czechoslovak ia in the late 1930s after the German Nazis invaded his homela nd. T he for mer miner and storekeeper was assigned a homestead close to Tomslake, a hamlet between the Alberta border and Pouce Coupe (whose pronunciation rhymes with ‘droopy’). An earlier claimant had already abandoned the hilly, heavily treed property.

served as a tail gunner in a bomber over Germany during the Second World War. In that job, the odds of living beyond 10 missions were poor, but Leslie survived 40 missions. “Vic was a great shot, which many men were around here—we were so poor that even squirrel pelts had value,” Nodes says.

In 1930, Northern Alberta Railways selected Dawson Creek as its end of steel.

In wartime, the railhead town’s growth was further spurred when it became Mile Zero on the Alaska Highway. Postwar, Imperial Oil, Mobil, Texaco, and other producers set up their first northern B.C. headquarters at Dawson Creek.

When exploration subsequently shifted northward, much of the energy industry migrated to Fort St. John, now the largest population centre in northeastern B.C. Pouce Coupe gently subsided into a backwater. After the war, most families abandoned the land around Tomslake in favour of better-paying city jobs. Nodes, however, stayed in Pouce Coupe while he drove for Northern Freight ways, beginning in 1956. “I hauled all over

the North, to Alaska after the earthquake there, for the construction of the Dempster Highway [in the Northwest Ter r itor ies], for t he oi l projec ts at Boundary Lake, and a whole lot more. I met Myrna [his wife] in 1962 while I was doing the Prince George run,” the former trucker reminisces.

By 1965, however, years of sleeping poorly in truck cabs on rough gravel roads had triggered persistent ulcers.

Node bought an old caterpillar tractor and began working summers on highway construction, switching to oil and gas lease roads and wellsites in the winter.

With Myrna keeping the books, the company opened a construction subsidiary in Alberta and also branched into oilfield supply at Pouce Coupe.

Then lightning struck. Since 2005, the Pouce Coupe and Tomslake area has emerged as the epicentre of the Montney Photos: H.F. Nodes Construction Ltd.

get stuck with the surplus capacity, not the producers.”

The present surplus capacity would be even worse, in his view, if manufacturers had been able to keep up with customer demand during the recent boom. “More people would have bought more equipment if they could have got their hands on it,” Nodes observes. On the downside, though, he notes that American demand for petroleum and construction hardware is now weak:

22

OCTOBER 2 0 0 9 • O I L & G A S I N Q U I R E R

Herb Nodes and his wife Myrna (above) have been building oilfield roads, wellsites, and other facilities since the 1960s, illustrated by these historical photos.

natural gas play. Its sandstone, siltstone, and shale sequences contain an estimated resource of 50 trillion cubic feet, much of it laced with poisonous hydrogen sulphide. Wells, gas plants, and pipelines now honeycomb the district. Active explorers include EnCana Corp., Murphy Canada, A RC Energ y Trust, ConocoPhillips, Shell Canada, and others.

Boom or bust, the Nodes family probably won’t change its attitude. Herb still prefers not to make fixed appointments (“Just call me when you get to town.”) in case he’s suddenly needed in the field, and Myrna still keeps a sharp eye on cash f low. Their son Joe is taking the family businesses into the next generation. Likewise, most of their neighbours will carry on, taking sour gas and busy field crews in their stride. The valley sometimes called the Mighty Peace has bred a people worthy of the name.

e h T

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OCTOBER 2 0 0 9 • O I L & G A S I N Q U I R E R

Feature

TransCanada’s Keystone XL pipeline will transport bitumen from Hardisty directly to Texas

by Graham Chandler Photos courtesy TransCanada

Construction is already underway on the $12 billion Keystone pipeline project.

It looks like a go.

“We’ve got enough contracts now to proceed,” says Robert Jones, TransCanada’s VP of the Keystone Pipeline project. “The system [Keystone Pipeline together with Keystone XL] will be able to move 1.1 million barrels per day and we have contracts for a little over 900,000 now.” And those contracts are long-term, too. “Most are 20 years, but our average is something like 17 or 18 years,” Jones says.

National Energy Board (NEB) hearings were scheduled to start in mid-September but TransCanada is optimistic about receiving regulatory approval. American refineries already process 60 per cent of Alberta’s bitumen production and they want more.

Gulf Coast imports from Mexico and Venezuela have dropped 24 per cent in the past four years, and the Keystone XL express or bullet line is cheapest way to replace that oil.

Producers are equally eager to oblige.

By 2013, the Canadian Association of Petroleum Producers estimates, Alberta’s oilsands output will increase by 1.1 million barrels per day. One of the first to sign onto the Keystone project was Canadian Natural Resources Ltd., committing 120,000 barrels per day (bbl/d) for 20 years from its Horizon oilsands project.

TransCanada, traditionally a natural gas shipper, has made a massive commitment to oil through its Keystone pipeline system, of which XL forms a part. TransCanada became sole owner of the project after agreeing to buy out ConocoPhillips’ share in June this year.

Total capital cost for the Keystone project is expected to hit US$12 billion.

Approximately $2.7 billion has been spent to date with the remaining $9.3 billion to be invested between now and the end of 2012.

To mitigate risk, TransCanada says capital costs related to Keystone construction are subject to a capital cost risk-and-reward sharing mechanism with its customers.

The first phase of Keystone is already under construction. With a nominal capacity of 435,000 bbl/d, it spans 3,456 kilometres from Hardisty, Alta., to U.S. Midwest markets in Wood River and Patoka, Ill. A large section of this line, through Saskatchewan and Manitoba, is a conversion of TransCanada’s original 1958 natural gas pipeline. Commissioning is expected to commence in late 2009 with commercial operations to follow in early 2010. The line will be expanded to a capacity of 590,000 bbl/d and extended to Cushing, Okla. That segment is scheduled to come on stream late next year.

O I L & G A S I N Q U I R E R • OCTOBER 2 0 0 9

25

Feature

Keystone XL will expand and extend this system. Currently under regulatory application in Canada and the U.S., it will offer additional capacity of 500,000 bbl/d direct from Hardisty to the U.S. Gulf Coast in 2012. The express line, sometimes referred to as a bullet line, will be 2,720 kilometres (1,690 miles) in length, from Hardisty in east-central Alberta to a delivery point near existing terminals in Port Arthur, Texas.

A glance at the map shows Keystone XL offers pretty much the shortest distance from Alberta producer to refiners along the Gulf Coast. Construction of the expansion facilities is anticipated to be cranked up in 2010 following regulatory approvals. It’s aimed squarely at companies with oilsands projects due to start up in the 2009 to 2012 period, who want transportation in service when their crude is ready to flow.

To s t r e a m l i n e c o n s t r u c t i o n , TransCanada has brought in some innovations to traditional methods. XL incorporates 41 virtually identical pump

site—electrical houses, motors, pumps, skids, measurement and control systems, etc. “Our approach to this was to get it done in time, and do it effectively,” the TransCanada VP comments.

Eventually the pipeline firm selected two contractors but with the same specifications, including a group of GE companies and a consortium under Siemens. Another collection of contractors will do the civil work at each location. TransCanada supplies them with the modularized pump and motor platform on a base. “All the contractor has to do is like a Meccano set—tie in all the electrical and the mechanical piping.” Jones says. The strategy is not unique, he adds, “but for traditional crude oil pipelines that I’ve been involved in, we typically did everything on site.”

Average depth of cover over the buried pipe is four feet, “which minimizes damage caused by third-party strikes,” says Jones. “So a number of our contractors decided to go with backhoes rather than using traditional wheel ditchers.

last year, starting at the border and working south,” Jones says. Distances completed depend on a number of factors, he adds: “You look at what a typical contractor can do in a season. On the Prairies, they can do about 120 miles [194 kilometres].

So two started in North Dakota, and by the end of 2008 we were completed there plus a little piece of South Dakota.” From there to Illinois, the Keystone VP says, the spreads are about equal in length, each assigned to a different contractor.

Keystone will move whatever fluids need to be moved, although its main product is expected to be bitumen. “We build to traditional North America pipeline specs, which are viscosity-based,” Jones says.

“It doesn’t matter if it’s been upgraded to synthetic crude or it’s a blend.” Western Canada Select, for example, is a combination of bitumen plus blending synthetic, light crudes, and conventional heavy crude.

And there’s competition. Keystone XL is one of several export pipelines under construction or in the planning stages

“I think what the market has determined is they never want to be short of pipeline capacity."

— Robert Jones, VP of the Keystone Pipeline project, TransCanada

stations—about one every 80 kilometres— which offer the advantage of some massproducing. And they’re large stations with two or three pump units apiece, each driven by 6,500-horsepower electric motors. If future expansions are made, each station can house five pumps driven by a total of 32,500 horsepower. It took some innovative thinking.

“We wondered, how can we build all these pump stations so that they can come on all at the same time and work?” says Jones. “We thought about it and came up with a modularized pump station design.

We tried to create cookie-cutters and going to a general contractor, instead of being stick-built.” The pipeliner wanted as much as possible manufactured off 26

OCTOBER 2 0 0 9 • O I L & G A S I N Q U I R E R

When we went to buy easement, a lot of landowners were really supportive of that.” For coatings, TransCanada decided to use fusion-bonded epoxy. “And we went with the two-part epoxy to coat the welding joints,” Jones says.

Because of the distances involved, typically constructors divide pipeline builds into regional portions known as spreads.

“We had the challenge of dividing the construction across three provinces and seven states,” Jones notes. The Alberta work is divided into two spreads built from a single camp. Work in the south will be done in one season, while construction in the north will be done in the second season.

The American portion of the XL project incorporates eight spreads. “We did two

being considered in light of anticipated new bitumen production. In fact, the spectre of temporary overcapacity looms because lower crude prices have slowed upstream development of new supply.

Enbridge, whose pipeline system to eastern markets has long moved western Canada’s crude, has presented evidence to the NEB indicating Keystone XL would “create an unnecessar y and unprecedented level of excess pipeline capacity between western Canada and U.S. markets.” The result would be higher overall tolls, according to Enbridge, so regulatory approval of XL would not be in the overall Canadian public interest.

Jones isn’t worried. “With regard to all the competing projects, the market will

Feature

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OCTOBER 2 0 0 9 • O I L & G A S I N Q U I R E R

decide what eventually gets built,” he says.

“I think what the market has determined is they never want to be short of pipeline capacity. And of course none of these projects is small; they don’t come in tens of thousands of barrels per day capacity.

It’s the economics; these are hundreds of thousands of barrels per day capacity at a time—usually up to 600,000 a day. So the market needs to be confident.”

Another possible hurdle to bitumen shipments is proposed U.S. legislation against importing so-called “dirty oil,” typically defined as any foreign crude whose production causes more greenhouse gas emissions than American crude. A harbinger of whether the legislation will have teeth or not came with this August’s State Department permit issued to Enbridge for its Alberta Clipper bitumen pipeline to Superior, Wis. Environmental activist organization Earthjustice issued a news release claiming the decision “contradicts President Obama’s premise to cut global warming pollution and America’s addiction to oil while investing in a clean energy future.”

Again, Jones shows little worr y.

“We’re not yet sure what the legislation is going to be,” he says. I think the fact of the matter is that this crude oil meets a demand that the U.S. requires. They’ve already got a number of refineries looking for alternate sources, other than Mexico, Venezuela, or the Middle East.”

Adding that there are weather-related problems with crude oil supply. “With oil that’s imported on supertankers, whenever there’s a hurricane like Katrina or Rita, those tankers have to stay way outside the Gulf Coast,” the TransCanada VP says. “A pipeline gives them another source of crude oil which is far more reliable than tankers. So for a secure source of supply, Canada is considered the source of choice.”

His optimism is shared by Bill Gwozd, VP of Ziff Energy Group, who has been analyzing oil and gas markets for 30 years.

“At the end of the day, the EIA [Energy Information Administration] has been quite clear insofar as the U.S. will continue to be required to import oil and natural gas.” Beyond the physical need for hydrocarbons, the independent analyst adds the political element: “When you have turmoil in other [oil-producing] countries it’s very challenging to import energy—and this is the way the U.S. will be based for the next 25 years.”

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OCTOBER 2 0 0 9 • O I L & G A S I N Q U I R E R

British Columbia

B.C. government’s stimulus package could boost field activity

B.C. expects to recover $2.50 in government revenue for every $1 spent in the form of royalty credit.

British Columbia’s new stimulus package could help boost drilling activity in the province this winter, although the effects won’t be known until later in the year as producers firm up capital spending plans. Dav id Pr yce, operations VP with the Canadian Association of Petroleum Producers, said the moves appear aimed at generating short-term activity while positioning the province and industry to “leap” out of the economic downturn when the time comes.

T he pac k age inc ludes a oneyear, two per cent royalty rate for all wells drilled in a 10 -month window (September 2009– June 2010), which Pr yce said could stimulate dr illing.

Other royalt y initiatives in the package include: • A n increase of 15 per cent in the existing royalty deductions for natural gas deep drilling.

• Qualification of horizontal wells drilled between 1,900 and 2,300 metres into the deep royalty credit program.

• A n additional $50-million allocation for the infrastructure royalty credit program to be offered this fall to stimulate investment in oil and gas roads and pipelines.

Energ y Minister Blair Lek st rom rolled out details of the plan on August 7. Regulatory initiatives in the package included commingling in the plains area, to be announced by the B.C. Oil and Gas Commission in the near future. There will also be amendments to the drilling licence regulation to create flexibility that will allow industry to move wells to production while not losing privileges to convert drilling licences to leases.

“B.C. has been very clever; they’ve realized that all the companies right now are going through their budgets for the drilling season in 09/10 and so they’ve

put this in front of them as they plan their budgets for that drilling season,” Pryce commented. “Companies have just spent a whole bunch of money on acquiring lands in the Montney and the Horn and so they’re going to want to be proving up those lands.”

According to an analysis by Peters & Co. Limited, due to limited foreseeable drilling activity over the eligible 2 per cent royalty window, “few entities are likely to be able to take advantage of the fixed 2 per cent royalty rate in a meaningful way.”

The 15 per cent increase in the deep royalty credit and lowering of the cut-off to 1,900 metres for horizontal wells are permanent, though, which Peters & Co. said will provide longer-term benefits.

Does the B.C. package put pressure on other producing provinces? When asked, Lekstrom merely commented that Alberta and Saskatchewan will “make their [royalty] decisions based on what their economy is, what their budget allows them to do, and how their regulatory regime works.”

EnCana Corporation, the most active driller in B.C., applauded the announcement. “They have certainly made themselves one of the most competitive jurisdictions in North America,” said spokeswoman Carol Howes. “It comes at a time where we’re just going into the budget process…but it’s too early to say the impact it will have on capital spending.”

Gary Leach, executive director of the Small Explorers and Producers Association of Canada, said, “The B.C. government calculates that after three years they conservatively estimate these incentives will return $2.50 in net incremental government revenues for every $1 of royalty credit provided. This is a theme SEPAC consistently puts in front of federal and provincial governments.”

— DAILY OIL BULLETIN

BRITISH COLUMBIA WELL ACTIVITY

AUG/08

AUG/09

AUG/08

AUG/09

AUG/08

AUG/09

WELL LICENCES

136

48

WELLS SPUDDED

72

23

WELLS DRILLED

74

33

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • OCTOBER 2 0 0 9

31

British Columbia

British Columbia government approves 31 new road and pipeline projects under royalty program Thirty-one new road and pipeline projects to improve access to underdeveloped areas of northeastern British Columbia have been approved under a provincial program that cuts royalty payments for participating companies. About 19 companies will participate in the program, which will amount to $120 million in royalty credits.

Energy Minister Blair Lekstrom said there were applications for 68 projects totalling about $760 million in estimated construction costs. “Different companies put forward different proposals based on pipelines they need to build or roads they need to build in order to expand on their oil and gas,” Lekstrom explained. The program provides oil and gas companies with a cut in the royalties they must pay in exchange for industr y investment in road and pipeline infrastructure.

Under the program, the companies must fundJuneWarren_RAMM_7.0625_4.625.pdf the entire cost of an approved infrastructure project, but can then receive

B.C. road reconstruction this summer includes bridge work, like this project at Pouce Coupe.

up to 50 per cent of the eligible project costs from the province, paid in the form of royalty deduction when the project is completed. “In a nutshell, the wells that we get drilled as a result of these programs, wouldn’t be drilled without these incentive 8/27/09 2:22:37 PM programs,” said Lekstrom.

The incentive program, which began in 2004, is very popular, said Lekstrom and as of March 31 of this year, the program was responsible for the development of 58 new or upgraded all-season roads and 52 pipeline projects in the province.

— CANADIAN PRESS

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OCTOBER 2 0 0 9 • O I L & G A S I N Q U I R E R

British Columbia

Kitimat LNG attracts second big Horn River producer, Apache Corp.

Kitimat LNG has attracted another major supplier for a liquefied natural gas (LNG) export terminal it is planning to build on British Columbia’s northern coastline.

The privately-held company said it has signed a memorandum of understanding with Houston-based Apache Corp., which could supply between 200 million and 300 million cubic feet of natural gas per day to the Kitimat facility.

The terminal has a planned capacity of 700 million cubic feet per day. Apache, a joint-venture partner with EnCana Corp. in northeastern B.C.’s promising Horn River Basin, has an option to buy an equity stake in the Kitimat project. “We are very pleased to welcome an industry leader such as Apache to our growing team of exceptional project partners,” Kitimat president Rosemary Boulton said on August 10.

At the terminal, natural gas would be condensed into a liquid in ultra-cold temperatures. It could then be loaded onto special tankers, and shipped around the world, making a once regional commodity a global one. North America has been

awash in natural gas supplies, thanks to emerging shale plays in British Columbia, Pennsylvania, Louisiana, and Texas. As LNG, those huge volumes could find a home in more lucrative overseas markets in Asia and Europe.

Recently released drilling results show Apache’s individual horizontal wells in the Horn River Basin could recover 10 billion

is also a big player in northeastern B.C. Companies such as Korea Gas Corp. and Spain’s Gas Natural have already agreed to buy the LNG that will be produced from the Kitimat plant.

Kitimat LNG was originally conceived as an import terminal, but, recognizing a fundamental shift in the North American marketplace, decided late last year to

Recent drilling results show Apache’s individual horizontal wells in the Horn River Basin could recover 10 billion cubic feet of natural gas.

Apache holds about 210,000 net acres in Horn River.

cubic feet of natural gas. Apache holds about 210,000 net acres in Horn River.

Kitimat has received federal and provincial regulatory approval. Startup is expected to take place some time in the fourth quarter of 2013.

Last month, Kitimat LNG got the backing of its first natural gas producer, Houston-based EOG Resources, which

reverse it. So far, North American has been a receiver of LNG cargoes, with terminals dotting the U.S. Eastern Seaboard.

In June, Canada’s first LNG project—the Canaport regasification plant owned by Irving Oil and Spain’s Repsol YPF, SA in Saint John, N.B.—began receiving imported gas.

— CANADIAN PRESS

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Galleon will focus on infrastructure before shifting to drilling

With much of its drilling focused on oil, Galleon expects to keep moving ahead in the coming year.

Galleon Energy Inc. plans to direct a large portion of its capital expenditure program in the current quarter towards optimizing infrastructure and increasing facility capacity. The plant expansion in Central Montney No. 1 project has received necessary regulatory approvals with completion expected at the end of the third quarter of 2009.

Drilling projects are anticipated to receive the largest portion of the fourth and first quarter 2010 capital spending in order to take advantage of the benefits from the recently announced Alberta royalty incentive programs and to fill the expanded facility capacity.

Based on current commodity prices, Galleon plans to drill up to 22 wells in the second half of 2009, of which 60 per cent will target light oil. One vertical well and up to six horizontal wells are planned in the Eastern Montney project to capture

new reserves and to further advance the developed area of the project.

This financially prudent approach positions Galleon to quickly ramp up production as commodity prices recover, the company noted.

The company said up to three wells are planned in its Central Montney No. 2 project to further advance the developed area of the project. As many as four horizontal Nordegg oil wells are planned to increase production and to prove up reserves in this new project.

Up to three wells are planned in the Doig light oil resource project.

One exploration well is planned in B.C. targeting light oil. Galleon said its remaining four wells scheduled for the second half of this year will be development locations on existing projects.

Production for the second quarter averaged 16,076 barrels of oil equivalent

per day (boe/d), down from both the first quarter of this year and from the second quarter of last year. Galleon said its output in 2009 is expected to average approximately 17,000 boe/d.

The company reported an operating netback of $24.11/boe in the second quarter, helped by stronger oil prices. About 36 per cent of Galleon’s production consists of oil and natural gas liquids. However, lower gas prices have had an impact. Revenue declined by some $70 million in the second quarter of 2009, while cash flow was cut in half compared to the same three months in 2008. The company recorded a net loss of $22.01 million for the quarter, mainly due to an unrealized loss of $25 million on crude oil derivatives.

Funds from operations totalled $29.6 million for the second quarter, while capital spending fell to $19.62 million from $34.8 million a year earlier. Operating expenses averaged $9.43/boe in the period, a decrease of 26 per cent from last year and a 12 per cent decrease from the first quarter of this year.

In the second quarter Galleon drilled and cased for production 7 (6.8 net) wells: 3 (3 net) Eastern Montney gas wells, 2 (1.8 net) Central Montney gas wells, 1 (1 net) light oil resource well, and 1 (1 net) multi-zone shallow gas well.

Also in the second quarter of 2009, the firm successfully drilled three (100 per cent interest) Eastern Montney horizontal multifractured wells. Results have reportedly met expectations.

Galleon has slowed the pace of drilling in this area because of low gas prices, but the company plans to accelerate its program when gas prices increase. The use of pad drilling will resume as the pool continues to be developed. The company has identified 350 horizontal drilling locations on over 200 sections of owned land within the delineated Eastern Montney fairway.

— DAILY OIL BULLETIN

NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY

AUG/08

AUG/09

AUG/08

AUG/09

AUG/08

AUG/09

WELL LICENCES

259

123

WELLS SPUDDED

276

93

WELLS DRILLED

289

91

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • OCTOBER 2 0 0 9

35

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OCTOBER 2 0 0 9 • O I L & G A S I N Q U I R E R

Northeastern Alberta

Despite difficulties, Petrobank prepares three more THAI projects

Photo: Joey Podlubny

by Pat Roche

Petrobank senior VP Chris Bloomer says its best THAI well to date has achieved 200 barrels per day.

Discussion concerning the Whitesands in situ project dominated the second-quarter conference call of Petrobank Energy and Resources Ltd. on Aug. 13. The company told analysts and investors that it has tremendous confidence in its unique THAI (toe to heel air injection) technology despite the fact that its best Whitesands well to date has achieved average production of about 200 barrels a day.

Chris Bloomer, Petrobank’s senior VP and COO for heavy oil, said air injection drives the process, and the project hasn’t had continuous air injection for a significant period because of operational issues.

“But we have seen these wells produce in that 400 to 500 barrel a day range. So certainly that capacity is there…. Bear in mind that the first wells that we drilled were the problematic wells,” Bloomer said.

Beyond Whitesands, near Conklin in northeastern Alberta, Petrobank has three

other THAI in situ combustion oilsands projects in the works: • It filed a regulatory application for a 10,000 barrel a day in situ combustion project, called May River, on nearby oilsands leases west of Conklin. Front-end engineering and design (FEED) for this project began last fall and is expected to finish later this year.

• Petrobank’s Dawson project is designed to use in situ combustion to recover Bluesky heavy oil near Peace River in

plc, which bought Duvernay in August 2008, had no comment on the proposed project at press time.

• Regulatory approval was received on July 9 for a two-well project using THAI in a conventional heavy oil reservoir at Kerrobert in southern Saskatchewan.

This is a 50-50 joint venture with Baytex Energy Trust, which purchased True Energy Trust’s Saskatchewan assets. With the approval of the Kerrobert project, Petrobank earned a 50 per cent interest in an initial four sections of land.

Kerrobert drilling began on July 18 and the first production well, KP1, finished drilling on Aug. 5. KP2 began drilling on Aug. 7. First production is expected soon after air injection begins in early October.

Whitesands was initially plagued by high sand production, but Petrobank believes it solved the sanding problem with the use of FacsRite liners, which it also plans to use at Kerrobert. An analyst asked whether the company feels its original expectation that THAI wells would produce 600 barrels a day might still be achievable with the new liners.

“The initial design at Whitesands is 600 barrels a day. We certainly think that’s the capability there. And it’s a similar forecast and design for Kerrobert,” Bloomer noted. Pressed by an investor, he said the goal is to reach full production capacity at Kerrobert in December or January.

Bloomer described the Kerrobert project as a “much more friendly environment” than

Petrobank says its Kerrobert project has a "much more friendly environment" than Whitesands. The oil is lighter, the reservoir more homogeneous, and costs in southern Saskatchewan are lower than at Conklin, Alta. northwestern Alberta. A stratigraphic well was drilled last August and a regulatory application filed on April 2.

Petrobank was partnered with Duvernay Oil Corp. for this test. Royal Dutch Shell

Whitesands. For example, the oil is lighter and the reservoir is more homogeneous.

A l so, he sa id, cost s i n sout he r n Saskatchewan are lower than at remote Conklin in the Alberta oilsands fairway.

NORTHEASTERN ALBERTA WELL ACTIVITY

AUG/08

AUG/09

AUG/08

AUG/09

AUG/08

AUG/09

WELL LICENCES

69

37

WELLS SPUDDED

61

99

WELLS DRILLED

61

92

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • OCTOBER 2 0 0 9

39

Northeastern Alberta “The drilling has gone very well and we’ve encountered excellent reservoir on both the wells,” he commented. “ Certainly this is a far cry from Whitesands, where we had a lot of unanswered questions.”

One analyst asked whether Kerrobert would be regarded as experimental, or whether its production would be reported quarterly when the company discloses its financial results. “We certainly think the Kerrobert project, even on a two-well basis, is commercial. And on that basis we would expect to be showing those volumes,” replied Corey Ruttan, Petrobank’s CFO. In a news release reporting its secondquarter results Petrobank said its Alberta Dawson project would be “virtually the same” as the Saskatchewan Kerrobert project but will demonstrate the THAI technology in a more mobile “oilsands” reservoir.

The company has the cash to proceed with further THAI developments. At a time when many producers are reporting losses and lower production, Petrobank reported a second quarter profit of nearly $35 million—albeit reduced from a year earlier— and a 72 per cent increase in production to 41,127 barrels of oil equivalent per day.

Petrobank, one of the top players in Saskatchewan’s prized Bakken tight oil play, and TriStar Oil and Gas Ltd. have agreed to merge to create PetroBakken Energy Ltd. (See article in the Saskatchewan regional news section on page 60.) Petrobank’s Canadian production rose by 19 per cent to 19,579 barrels of oil equivalent a day in the second quarter while its Latin American output soared by 194 per cent to 21,548 barrels a day.

Canadian production expenses fell by 27 per cent to $6.52 per barrel of oil equivalent while Latin American production costs dropped by 28 per cent to $7.86 a barrel. But despite Petrobank’s relatively strong performance throughout most of its business, many of the conference call questions focused on the three-year-old Whitesands in situ combustion project.

“The best performance of any THAI well has been 200 barrels per day of sustained and uninterrupted production, and that works out to about $75,000 per flowing barrel….

That to me isn’t successful. I would think the goal there is to have performance of about 500 barrels-plus per well,” said one investor.

“What has to take place for us to get from 200 barrels a day to 500 barrels a day? What gives you confidence that we can get to that?”

Asked when its independent reserves evaluator, McDaniel & Associates Consultants Ltd., might give Petrobank credit for THAI, Bloomer said: “I think by the end of the year we should be able to discuss that…. This is a new technology and we are breaking trail with respect to that.”

Petrobank executives were also grilled about another new process, called CAPRI, that injects a catalyst into its new wells to improve the oil quality. An analyst wondered whether the three-degree improvement in API gravity justifies the additional cost of a CAPRI well. Bloomer said the all-in cost of the CAPRI wells is probably $1.5 million more than that of the old THAI wells, and acknowledged that a three-degree-API gain “is probably sub-economic” at that cost.

But he also expressed confidence Petrobank can achieve a greater degree of upgrading in the reservoir while lowering the cost of the CAPRI wells. Asked about the cost estimate for May River, on which engineering is continuing, Bloomer stuck with the earlier estimate of $20,000 per flowing barrel. While costs have fallen in the non-oilsands sectors of the oil and gas industry, Petrobank hasn’t found this to be the case with in situ oilsands projects.

— DAILY OIL BULLETIN

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OCTOBER 2 0 0 9 • O I L & G A S I N Q U I R E R

.

Northeastern Alberta

Devon says its Jackfish SAGD project is “extremely profitable” Photo: Joey Podlubny

Rising production from Devon Energy Corporation’s Jackfish oilsands project led the company’s operational highlights for the second quarter. Production at Devon's wholly owned project in northeastern Alberta averaged 28,000 barrels of bitumen a day in June, and was as high as 33,000 barrels a day during the month, the company said. That’s up from 14,500 barrels a day exiting June 2008.

Climbing output from the steam assisted gravity drainage (SAGD) project helped lift Devon’s total Canadian production for the quarter by nearly 12,000 barrels of oil equivalent (boe). About a year ago, the company expected Jackfish to reach its design capacity of 35,000 barrels a day in the first half of 2009. That is now expected to happen in the fourth quarter following two weeks of scheduled downtime for plant maintenance in September.

Jackfish’s success isn’t limited to production growth. “With current oil and gas prices, favourable differentials, and nonfuel operating expenses running below $6 per barrel, Jackfish is extremely profitable,” said Dave Hager, the Oklahoma

Jackfish should achieve full production this year.

City–based company’s executive VP of exploration and production.

“Well and reservoir performance continue to lead the industry,” Hager told the company’s second-quarter earnings conference call on Aug. 5. When it planned Jackfish, Devon expected a steam-to-oil ratio of less than three. But thanks to better-thanexpected reservoir performance, “we’re actually on many parts of that project below 2.6,” said Devon president John Richels.

He told analysts this equates to one million cubic feet of natural gas being burned (as fuel for steam boilers) to produce one barrel of bitumen. “And the wells continue to produce at levels which are really industry-leading results. So it’s been just a terrific lease for us and terrific project,” Richels commented.

Meanwhile, about 300 million barrels of proved Jackfish bitumen reserves that had been de-booked for year-end 2008 were put back on Devon’s books in the second quarter, Richels said. This includes Jackfish 2—the SAGD project’s second phase—where Devon has so far booked only 80 million barrels of reserves because it isn’t yet on stream. Jackfish 2 is expected to ultimately recover 300 million barrels of bitumen.

Construction of Jackfish 2—also with a design capacity of 35,000 barrels a day—is about 40 per cent finished. The first plant module arrived on site last month as Devon began drilling the first of 28 planned well pairs.

In the Horn River Basin of northeastern British Columbia, Devon drilled a third horizontal well during the

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Northeastern Alberta second quarter. Completion operations are underway and the company expects to tie in these wells and have initial production rates in time for its third-quarter earnings conference call. Devon has 153,000 net acres in the Horn River play.

I n t he second qua r ter, Devon’s Canadian gas output rose mainly due to lower Crown royalties. The company said the royalties are calculated on a sliding scale. At lower product prices, Devon’s share of its gas production increases.

Devon’s total worldwide production averaged a record 718,500 boe/d in the second quarter, up from 642,600 boe/d in the same period last year. Production in the first half of the year averaged 701,700 boe/d, up from 641,500 boe/d.

(Volumes are net of royalties and dollar amounts are U.S.) D e s pit e t h e s t r on g p r o duc t ion growth, revenues from oil, gas, and natural gas liquids sales fell by 58 per cent to $1.7 billion in the second quarter of 2009. Worldwide, Devon’s average realized gas price fell by 70 per cent to $2.91 per million cubic feet in the second quarter compared to the same period last year.

— DAILY OIL BULLETIN

Osum’s Taiga project takes a step forward Alberta Environment has issued Osum Oil Sands Corp. the final terms of reference for an environmental impact assessment (EIA) report on the company’s proposed 35,000 barrel per day Taiga oilsands project near Cold Lake. Pending regulatory approval, it is Osum’s intention to begin construction in the third quarter of 2011 with subsequent start-up expected in the second quarter of 2013 and first bitumen production in early 2014.

Osum is proposing to develop the project about 20 kilometres north of Cold Lake in township 65, ranges 1 and 2, and township 66, ranges 1 and 2, west of the fourth meridian, using steam assisted gravity drainage (SAGD) technology for the majority of its development and cyclical steam stimulation (CSS) technology later in the project’s anticipated 30-year life.

Bitumen will be recovered from the Lower Grand Rapids and Clearwater formations within the project area, at depths between 360 and 460 metres. Osum’s engineers are in the process of designing optimal recovery processes that match the reservoir conditions on its leases.

The main components of the project include a common central plant with steam-generation facilities, as well as steam delivery and product recovery pipelines and well pads with horizontal wells for both SAGD and CSS. Water treatment and recycling, bitumen treatment, and deep disposal wells for disposal of concentrated brackish water will also be included in the development.

According to Osum, the Taiga project will be among the first in Alberta to eliminate fresh water usage for steam generation. Instead, saline water from brackish sources will be drawn from deep wells in the McMurray formation. Steam facilities will have recycling capabilities up to 95 per cent while a small amount of fresh water may be required for basic amenities on the project site.

The Taiga project’s evaporator technology for plant facilities and water treatment will eliminate lime sludge ponds and permit safe disposal of concentrated brackish water far below the surface of the earth.

— DAILY OIL BULLETIN

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OCTOBER 2 0 0 9 • O I L & G A S I N Q U I R E R

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Ace now employs over 40 people and recently built a 16,000 square foot facility. Their store room stocks over 2,000 different lines of instrumentation products. Their inside sales team is always there to answer your questions and provide solutions.

Ace’s large rental fleet consists of a variety of quality test and calibration equipment. Their lead shop repair technician has over 15 years’ experience in repairing and calibrating oilfield equipment. With customer service in mind, Ace has in place an exchange program for Texsteam and Kimray Glycol pumps.

Ace Instruments also has a fabricating shop in their new facility. Here metering skid shacks and portable skid units are assembled. With their experience in the oilfield industry, Ace is able to provide custom solutions and designs for their clients’ needs. Ace’s Canadian Distributor Of

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OCTOBER 2 0 0 9 • O I L & G A S I N Q U I R E R

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More oil and gas people sought help for alcoholism in 2006–2008

The half million people who work in oil and gas seek counselling services above the national average.

A petroleum labour force report released in August by Shepell-fgi Research Group pointed to a 481 per cent increase in Employee Assistance Programs (EAP) access for alcohol abuse from 2006 through 2008. Sheppell-fgi, a provider of workplace health and productivity solutions, concluded that substance abuse, particularly alcohol, remains a chronic challenge in the oil and gas industry.

T he r e p or t , c a l le d H e a l t h a n d Wellness Trends in the Oil and Gas Sector, examined E AP data for 36 upstream petroleum industry organizations for the three-year period, and compared the results to national norms. According to the report: • E mployees in the oil and gas industry accessed their EAP at a rate 34 per cent higher than the Canadian norm in 2006, and 40 per cent higher in both 2007 and 2008.

• E AP utilization increased almost five per cent per year over the three-year period.

• E AP utilization by the spouses of workers employed in the oil and gas industry was 33 per cent higher than the national norm in 2006, 56 per cent higher in 2007, and 75 per cent higher in 2008.

in the oil and gas industry, and their dependents, are primarily looking to the EAP for assistance with work-life issues, including family support services and substance abuse intervention. Workplace health and safety, including substance abuse policies and programs, is of critical concern where heavy industrial construction and technical competency are fundamental components of the work environment.”

The oil and gas sector employs over 500,000 people, 58 per cent of them in Alberta. The industry is Canada’s largest single private investor, and has invested $50 billion in the past two years. It holds 25 per cent of the value on the Toronto Stock Exchange, and paid $24 billion to federal and provincial governments in the past year alone.

Looking at data for 2008, oil and gas employees and their dependents used their EAP at greater rates than the national norm for eldercare services (120 per cent higher), childcare services (43 per cent higher), addiction counselling (35 per cent higher), nutritional counselling (21 per cent higher), and family counselling (18 per cent higher).

“Oil and gas workers face socioeconomic stressors involved in locating suitable resources to support family who

“Working in stressful jobs in remote locations, combined with distance or long periods of time away from family, is a prime cause for such problems as addiction."

- Rod Phillips, CEO, Sheppell-fgi

“Working in stressful jobs in remote locations, combined with distance or long periods of time away from family, is a prime cause for such problems as addiction,” said Rod Phillips, CEO of Shepell-fgi. “Employees

accompany them to a new city, but have no social infrastructure to rely on,” said Phillips. “The current economic crisis may also contribute to a higher incidence of EAP access for family support services.”

CENTRAL ALBERTA WELL ACTIVITY

AUG/08

AUG/09

AUG/08

AUG/09

AUG/08

AUG/09

WELL LICENCES

390

89

WELLS SPUDDED

402

142

WELLS DRILLED

404

142

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • OCTOBER 2 0 0 9

45

Central Alberta Phillips said that substance abuse can affect the job in terms of lateness, absence, job function, work relationships, family welfare, financial risk management, and legal risk management.

The report also looked at trends in employee health, and highlighted reasons why EAP access for family support issues have increased year over year.

The reasons include: • E xpansion of the oilsands, and growth of the industry to support an increasing global demand for petroleum and energy products.

• I ncreased worker mobility for skilled trades.

• Worker absence from the family.

• L imited social network and local infrastructure to support family members.

“A s t h e i n du s t r y c o n t i nu e s t o develop in remote sites, it will be necessa r y to address t he soc ia l i n f rast r uc t u re, se r v ice s, a nd re sou rce s for retraining the existing workforce and attracting new hires to the industry,” said Karen Seward, Sheppell-fgi’s senior V P of business development, adding that accessing the EAP is a selfdeclaration for help.

—DAILY OIL BULLETIN

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46

OCTOBER 2 0 0 9 • O I L & G A S I N Q U I R E R

4-H kids learn what’s a mile below the wheat

by Kelley Stark Eighty-one 4-H delegates, along with nine of their camp-counsellors and assorted staff, took a break from canoeing and other camp activities to visit the Canadian Petroleum Discovery Centre in Devon this summer thanks to the generosity of Penn West Energy.

Penn West Energy prides itself on its community involvement and support for not-for-profit organizations. Both Alberta 4-H and the Canadian Petroleum Discovery Centre are organizations that Penn West supports, so bringing them together seemed natural.

“Not only does Penn West wish to make a positive impact in the communities where we live, work, and play—but we also seek opportunities to introduce our community partners to each other,” says Nicole Collard, manager of public affairs for Penn West. “It is very rewarding when we can be a catalyst for educating 4-H youth about the environment and energy industry issues with a partner such as the Canadian Petroleum Discovery Centre.”

T he 4 -H organization’s motto is “Learn to Do by Doing.” The organization teaches youth (normally from an agricultural background) everything from raising calves to be sold at the end of the year, to learning to sew to participate in a fashion show, to training dogs and riding horses. The young people are encouraged to volunteer in their communities and participate in public speaking. 4-H assists kids in increasing their knowledge and developing life skills.

T h i s f ield t r ip to t he Ca nadia n Petroleum Discovery Centre gave some 4-H kids an opportunity to learn about energ y in A lberta. Mark Shand, 4 -H Specialist—Programs at the government of A lberta says, “My goal is to provide our summer program participants with a qualit y experience that educates them about the industries and future of our province. In addition to all the other fun and exciting activities we offer at the Alberta 4-H Centre, this field trip provides yet another unique 4-H program experience.”

Central Alberta Photo: Aaron Parker

The Canadian Petroleum Discovery Centre is an educational centre teaching its guests the facts and history of energy in Alberta. Retired oilfield vets volunteer their time to show their guests how a drilling rig works, share stories about what it was like in the patch, and answer whatever questions are thrown their way.

The centre also provides a Jr. Roughneck camp, which is what the 4-H delegates participated in.

Campers were picked up from Camp Wohelo (on the northern shore of Pigeon Lake) first thing in the morning and taken to the Discovery Centre. They spent the first half of their field trip looking at equipment that has been used in the patches of the past, learning the history of Leduc #1, and watching retired oilpatch workers work on an actual drilling rig.

After lunch they visited a learning lab where they looked at drilling mud and petrochemicals through microscopes; the Leduc #1 Gallery where they built ice cream formations (chocolate syrup on the bottom representing the oil with layer upon layer of edible goodies); the IPSCO Gallery where they built their own pipelines; and a fossil workshop where they made their own imitation fossils.

Penn West sponsored a visit by 81 4-H students to the Canadian Petroleum Discovery Centre in Devon.

Penn West Energy felt that bringing the 4-H organization to the Canadian Petroleum Discovery Centre would give the youth the opportunity to understand how the two industries—agriculture and oil and gas—work together. Many of their families work on the patch and many have oil and gas activity occurring

on their properties. “Two crops where there used to be one: one on the surface and one a mile deep,” points out Jeanne Visser-Vliegen, education director at the Discovery Centre. “Here at the centre, those young people got an insight of the energy in Alberta, from conventional oil to oilsands and alternative resources.”

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OCTOBER 2 0 0 9 • O I L & G A S I N Q U I R E R

Southern Alberta

Calfrac expands its capital budget and acquires Pure Energy assets

Photo: Joey Podlubny

by Lynda Harrison

Calfrac plans to add horsepower and deep coiled tubing equipment for unconventional gas plays.

Calfrac Well Services Ltd. is giving its 2009 budget a $26 million boost to total $61 million. The Calgary-based company says this cash, coupled to its acquisition of Pure Energy Services Ltd.’s Coloradobased well fracturing division, should enable it to expand on a global basis.

Calfrac paid about $42.8 million for the Pure assets. Calfrac plans to further expand its geographical footprint in the U.S. pressure pumping market as well as supplement its fracturing and coiled tubing equipment fleet within Canada, Russia, and Mexico.

The company is taking advantage of the current industry downturn, Doug Ramsay, president and CEO, explained to analysts during a conference call on August 7 to discuss second-quarter results.

“It’s very hard to take advantage of opportunities when you’re at the top of the cycle,” he said.

Calfrac has been keeping its eye on potential acquisitions for quite some time, Ramsay added, but valuations were way too high. He noted that the ten-year-old firm was originally launched in an environment not too different from the current one. At that time, Calfrac used low prices for equipment to its advantage.

“We have to be able to skate through the down cycle and I think we’ve done a good job of that—a very good job of that and we see some opportunities on the other side,” said Ramsay. “We’re bullish because we can see the other side through the fog.

Will it turn around tomorrow? Nope. Will it turn around in the future? Yes.” In Canada, Calfrac said it plans to augment its horsepower capabilities and expand its deep coiled tubing equipment fleet to gain a larger presence in unconventional natural gas resource plays.

The new capital allocated to Russia will

expand Calfrac’s coiled tubing f leet while Mexican capital will facilitate the start of cementing operations as well as increase its presence in that country’s fracturing market.

The additional capital expenditures are expected to be funded from the company’s cash on hand, funds provided by operations, and available credit facilities.

During the second quarter, the company said, it completed cost reduction measures in Canada and the U.S. through workforce restructuring at a cost of $600,000. A 30 per cent reduction in personnel achieved an estimated cost savings in excess of $2 million per month.

In April, Calfrac suspended its primary cementing operations in Canada and commenced transferring equipment and personnel to the U.S. and Mexico. During the third quarter, Calfrac redeployed four cementing crews including bulk transportation and mixing plant equipment with related infrastructure into the Chicontepec region, thus diversifying its pressure pumping operations in Mexico.

In Russia, fracturing and coiled tubing activity levels reached record levels. Also during the second quarter, activity levels for the company’s cementing operations in Argentina reached record levels. Calfrac plans to add a third cementing unit during the third quarter of 2009 to meet increasing demand in Argentina.

Fracturing and coiled tubing activity levels in Canada are highly uncertain but are anticipated to improve as the year progresses, said Calfrac. To date in the third quarter of 2009, activity levels in northwestern Alberta, northeastern B.C., and southeastern Saskatchewan are increasing as producers increase their focus on unconventional drilling in the Montney, Horn River, and Bakken resource plays, it said.

— DAILY OIL BULLETIN

SOUTHERN ALBERTA WELL ACTIVITY

AUG/08

AUG/09

AUG/08

AUG/09

AUG/08

AUG/09

WELL LICENCES

428

101

WELLS SPUDDED

402

100

WELLS DRILLED

421

105

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • OCTOBER 2 0 0 9

49

Southern Alberta

Canyon Services maintains revenue despite fewer jobs For the second quarter of 2009, Canyon Services Group Inc. reported that it benefited from large, horizontal multi-stage fracs in the Montney formation, which boosted its average revenues per job.

Although the number of jobs it completed fell 27 per cent from last year, Canyon’s second quarter revenues of $4 million were relatively flat with the same three months last year.

Still, hard times in the gas sector are taking its toll on the Calgary-based company. Its second quarter revenues were way down from first quarter 2009 revenues of $24 million. Canyon recorded a net loss of $5.4 million for the second quarter of this year compared to a $6.56 million loss for the same quarter in 2008.

In the second quarter of 2009, Canyon said it completed 97 jobs compared to 132 jobs completed for the same three months in 2008, a decrease of 27 per cent, while for the first six months of 2009 total jobs completed decreased to 599 from 632 in the 2008 comparable period.

Average revenue per job increased in the second quarter by 27 per cent to $41,228 from $32,521 last year, while for the first six months of 2009, average revenue per job increased by 30 per cent to $46,947 from $36,111 in the 2008 comparable period.

During the second quarter, Canyon said it expanded its customer base with the completion of a multi-well pilot project for a major, international exploration and

production company, employing the patented Grand Canyon technology process.

The results are presently being evaluated by the customer.

As a result of significant, companywide cost reductions implemented in late March, fixed costs and selling, general, and administrative costs before stock based compensation expense were reduced by 28 per cent in the second quarter compared to the first quarter of this year.

Operating expenses decreased by 10 per cent to $5.4 million in the second quarter from $6 million a year ago, as a result of the reduced job count and reductions in the fixed component of operating costs implemented in late March this year.

— DAILY OIL BULLETIN

CNRL reallocates $100M from oil to gas in its 2009 spending plans The Canadian natural gas industry is at a crossroads where reducing costs is crucial to the industry’s future, Allan Markin, chairman of Canadian Natural Resources Limited, warned on August 6. He made the comment in a conference call where the company said it drilled no gas wells in the second quarter and has shifted $100 million from gas projects to oil in its 2009 budget.

CNRL said it will drill only about 110 gas wells this year, down from its previous plan for 140. Planned drilling activity for the third quarter includes 24 net gas wells.

“The gas wells that are now being drilled in 2009 are being drilled to offset drainage, conserve land, or are strategic in nature,” said Steve Laut, CNRL’s president. “With

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production at design capacity targeted for the fourth quarter, the company said.

At its Primrose East thermal project, CNRL discovered oil seepage at the surface on one of the new multi-well pads. A significant amount of diagnostic work has been completed and the company believes it has identified the issue and the remedial action required.

CNRL continues to work with the regulators on resolving the issue and returning Primrose East to normal operations. CNRL has received regulatory approval for diagnostic steaming which is targeted to start this month. The conference call heard it may be early next year before the project is back to full steam.

— DAILY OIL BULLETIN

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the current gas price and cost environment, it makes no sense to drill gas wells for any other reason.”

“We have allocated roughly $100 million of capital from gas to oil. We’ll…add 121 oil wells made up of 86 primary heavy oil wells, 7 Pelican wells, 17 thermal wells, and 11 light oil wells,” Laut added. With no gas drilling, the company’s gas output fell as it had predicted. However, overall production was up as the ramp-up continued at CNRL’s new Horizon oilsands mine.

Horizon production averaged 59,599 barrels a day of synthetic crude oil in the second quarter with production ramp-up exceeding expectations in May and June.

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Savanna’s net loss grows while revenues and cash flow decrease Savanna Energy Services Corp.’s net loss increased to $8.9 million for the second quarter of this year from $6.55 million during the second quarter of 2008. Second quarter cash flow was negative $4.44 million compared to negative $610,000 during last year’s second quarter. Second quarter revenues of $27.1 million in 2009 were down considerably from $49 million for the same period last year.

Second quarter 2009 operating days decreased to 974 from 1,816 last year while revenue per operating day dropped to $18,422 from $20,507. The number of spud to release days decreased to 896

from 1,624 and metres drilled dropped to 202,671 from 386,161 during the second quarter last year.

In the second quarter of this year, the contract drilling segment averaged a deployed fleet of 99 net rigs and exited the quarter with the same number. In 2008 the company operated an average fleet of 95 net rigs, exiting that quarter with 99 net rigs.

The downturn in the North American oil and gas industry also resulted in a decrease in the oilfield services division’s revenue and operating hours for the second quarter of 2009 compared to the

same period in 2008. Revenue decreased to $8.96 million from $11.44 million while operating hours were 11,470 versus 15,994.

During the second quarter, the oilfield services division’s f leet size averaged 66 (64 net) service rigs, 8 coiled tubing service units, and 34 boilers, compared to the same period last year when the division operated an average of 57 (54.5 net) service rigs, 8 coiled tubing service units, and 34 boilers. The oilfield services division exited the quarter with 66 (64 net) service rigs, 8 coiled tubing service units, and 34 boilers.

— DAILY OIL BULLETIN

Trinidad Drilling sustains $8.59M loss in Q2 Trinidad Drilling Ltd. suffered a net loss in the second quarter though its focus on deep drilling and long-term contracts resulted in the company generating utilization levels of 14 per cent for the second quarter and 32 per cent in the first half. Its average secondquarter utilization was reportedly three percentage points higher than the industry-wide rate, and nine percentage points more than the industry average in the first six months.

Trinidad said it continues to benefit from the industry trend towards deeper, more complex drilling and away from conventional drilling. The company expects this trend to continue over the long term as more robust economics on the deeper plays drive more activity than the shallower plays, even in today’s challenging environment. Trinidad’s rigs are purpose-built for these deeper, more technically challenging resource plays.

The company’s Canadian drilling segment saw a sharp decline in operating days in the second quarter with 692 operating days—a 60.3 per cent decline year over year. Year-to-date in 2009, Canadian operating days fell by 43.7 per cent, to 3,237 days year over year due to lower utilization levels and strategic rig deployments.

Although operating days fell, Trinidad said it has been able to maintain relatively stable day rates year over year. This was due to the deeper-capacity drilling rig mix operating in 2009 versus 2008.

Canadian revenue fell to $23.77 million in the second quarter, down from $44.34 million in the second quarter of 2008. In the first half of this year Trinidad’s revenue was $102 million, down from $176.45 million from the same period in 2008. The Canadian drilling segment had nine fewer rigs in its fleet

on June 30 than in 2008 as a result of redeployments to the company’s U.S. and Mexican operations.

Operating costs as a percentage of revenue decreased from 68.5 per cent in the second quarter of 2008 to 60.9 per cent in 2009, thus increasing Trinidad’s Canadian drilling segment’s gross margin percentage to 39.1 per cent for the quarter compared to 31.5 per cent in 2008.

A driver behind this increase in gross margin percentage was early termination revenue of about $5 million related to the coring and pre-setting division.

In response to weak industry conditions, Trinidad undertook a number of cost-reduction measures in the first six months of 2009, including staffing reductions, wage rollbacks, reductions in support costs, and lower discretionary spending.

— DAILY OIL BULLETIN

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OCTOBER 2 0 0 9 • O I L & G A S I N Q U I R E R

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Ensign thinks natural gas prices won’t recover strongly until economic recovery drives demand.

Ensign Energy Services Inc.’s profit, cash f low, and revenue fell sharply in the second quarter of 2009 due to weakness in the Canadian and United States markets.

“Until there is a significant improvement in the commodity price for natural gas, we do not expect demand for oilfield services in Canada to improve,” the company said in releasing its quarterly results.

“Additionally, there remains an oversupply of oilfield services equipment that must be addressed before margins can improve,” Ensign stated. Despite higher oil prices and Alberta’s short-term royalty incentives, producers have utilized new capital in part “to fix balance sheet issues,” Ensign said. “There has not been a meaningful increase in demand for oilfield services.”

Ensign’s adjusted net income (net income before the tax-effected stockbased compensation expense) for the second quarter of this year was $23.1 million, a decrease of 41 per cent from adjusted net income of $39.2 million for the second quarter of 2008.

While there are some signs the U.S. market has hit bottom—recent rig count data has stabilized and even shown a modest increase from 2009 due to higher

oil prices—it’s still too early to turn optimistic, Ensign said. “Fundamentals driving oilfield services activity will not improve until economic conditions strengthen to levels that improve the demand for energ y commodities. It remains anybody’s guess as to when this might occur,” the company said.

Canada accounted for only 23 per cent of Ensign’s revenue in the second quarter of 2009 (2008—32 per cent) and for 37 per cent in the first half of 2009 (2008— 46 per cent). Even when the normal slowdown of spring break-up is accounted for, Canadian results reflected a weak quarter, Ensign said.

Drilling days recorded by Ensign’s Canadian division in the second quarter dropped by 63 per cent from the second quarter of 2008. In the six months ended June 30, Canadian drilling days fell by 46 per cent from the same period last year.

Similarly, Canadian well servicing hours fell by 29 per cent in the second quarter of 2009 and by 30 per cent in the first half of 2009 from the first half of 2008.

Ensign’s U.S. operations recorded revenue of $94.6 million in the second quarter, a 38 per cent drop from $152.8 million a year earlier. The U.S. accounted for 42 per cent of Ensign’s revenue in the second quarter (2008—45 per cent).

Ensign’s U.S. drilling days fell by 59 per cent in the second quarter from the same period last year. U.S. well servicing hours in the second quarter were down 21 per cent from the second quarter of 2008.

Ensign said its U.S. results were better in relative terms than its Canadian results, largely due to a greater contractual coverage of the U.S. oilfield services equipment fleet compared to the Canadian fleet.

Ensign’s overseas operations recorded second quarter revenue of $79.3 million, a four per cent increase from the $76.6 million recorded in the second quarter of 2008. The overseas division contributed 35 per cent of Ensign’s revenue in the second quarter (2008—23 per cent).

Overseas drilling days recorded in the quarter fell by 29 per cent from the second quarter of 2008.

— DAILY OIL BULLETIN

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O I L & G A S I N Q U I R E R • OCTOBER 2 0 0 9

53

Southern Alberta

Despite revenue drop of 46 per cent in Q2, Technicoil reduces debt Technicoil Corporation reduced its longterm debt in the second quarter, a period that brought a 46 per cent decline in revenues compared to a year ago and a net loss of $3.28 million. The service company reduced its gross long-term debt by $4.5 million to $12.1 million as of June 30 of this year from $16.6 million as of March 31 of this year and by $10.2 million from year-end 2008.

The company reported second-quarter revenue of $3.4 million on 4,298 well servicing operating hours and 21 drilling operating days, down from revenues of $6.4 million on 5,707 well servicing operating hours and 83 drilling operating days for the second quarter of 2008.

Technicoil said it increased coiled tubing service rig operating hours for nonfracturing activities relative to the second quarter of 2008 as a result of continued success in the Montney and Horn River resource plays and drilling support for steam assisted gravity drainage (SAGD) operations.

It also implemented cost-saving initiatives during and subsequent to the six-month

period ended June 30 to respond to the weak economic environment including compensation reductions for office and field employees, senior management, and directors, and the company reduced overhead staffing levels by approximately 10 per cent.

decline of 25 per cent. Expansion and diversification into conventional service rigs, and into new basins with the coiled tubing service rigs, including the Montney and Horn River, account for the nonfracturing hours.

Operations overhead fell by 13 per cent in the second quarter of 2009, while operating hours for the well servicing segment were 4,298, down from 5,707 in the same quarter of 2008.

Technicoil maintains a variable cost field labour structure resulting in field labour costs only being incurred during periods when field workers are required.

Other cost-saving initiatives implemented, including a 10 per cent reduction in overhead staffing levels since year-end, contributed to a 13 per cent reduction in operations overhead in the quarter relative to the same period of 2008.

Operating hours in the second quarter of 2009 for the well servicing segment were 4,298, down from 5,707 in the comparable period of the prior year, representing a

The well servicing segment managed to maintain operating hours only slightly lower than the first six months of 2008, with such activity being generated primarily from non-fracturing services from the corporation’s conventional rig fleet and services provided by the coiled tubing service rigs in the Montney and Horn River resource plays and in SAGD drilling support operations. In aggregate, 17,842 operating hours were generated by the well servicing segment year-to-date in comparison with 18,139 hours for the first half of 2008.

— DAILY OIL BULLETIN

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O I L & G A S I N Q U I R E R • OCTOBER 2 0 0 9

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OCTOBER 2 0 0 9 • O I L & G A S I N Q U I R E R

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Saskatchewan

Buzz over Three Forks­­­–Sanish oil formation spreads to Saskatchewan

by Paul Wells

Photo: Brian Zinchuk, Pipeline News

“When you start looking at the results you’re seeing in the Three Forks…some of these companies are having very good success—it’s encouraging,” said Ron Ness, president of the North Dakota Petroleum Council, a trade organization representing 135 companies in the state.

“If [the Three Forks–Sanish] provides a separate and unique target, that’s entirely an incredible opportunity for us. More importantly, the exciting part would be if we can develop the Three Forks in areas where we’ve been in and been unsuccessful in developing the Bakken,” Ness commented.

However, there’s still nagging doubt whether Three Forks is indeed a separate producing zone or just a mop that soaks up residual Bakken-generated crude that has seeped downward. “That’s the big great unknown,” Ness admitted.

Calgary-based junior NuLoch Resources Inc. is confident the two formations are

distinct and believes its land holdings just across the North Dakota border in the Tableland area of Saskatchewan have the potential to extend the play north. “They are separate. It’s a no-brainer. I don’t even know why they are trying to determine that,” said Glenn Dawson, NuLoch president and CEO. According to Dawson, the Sanish is a member of what’s called the Three Forks formation in North Dakota but what is named the Torquay once you cross the border into Saskatchewan. In 2008, pursuant to a farm-in, the company earned approximately 51 gross (20 net) sections of land by drilling a horizontal well in the Sanish formation at Tableland to a depth of 2,250 metres. The earning represented 50 per cent of the farmor’s interest in the lands to depth drilled.

“At the time, the play was just starting to emerge and we farmed in on a private U.S. company that had a large land position in Saskatchewan,” Dawson explained.

Through a purchase closed last May, NuLoch acquired the remaining 50 per cent of the farmor’s interest in the 51 gross sections, the farmor’s interests in all of its other lands at Tableland, and the farmor’s 100 per cent before payout working interest in a producing Sanish oil well.

A total of 16,800 net undeveloped acres are included in the transaction.

“We’re the only Canadian public company that has a significant position in this play other than Second Wave Petroleum Inc., who are our partners,” Dawson said.

Through the acquisition, NuLoch expanded its net undeveloped acreage position at Tableland from 19,500 to 36,300 acres. The land is largely contiguous. NuLoch’s working interests now range from 50 per cent to 100 per cent and average 74 per cent. Dawson noted that there is Bakken and Sanish production in the vicinity.

Results from just over 100 new wells in the Three Forks–Sanish formation appear to be encouraging.

A potentially prolific light crude oil reservoir that sits below portions of the Bakken formation in North Dakota has generated excitement among government and industry officials in that state.

The Three Forks–Sanish formation lies directly underneath the Bakken zone, and it extends into Saskatchewan.

Until recently, the Three Forks–Sanish formation was considered merely a drip pan to the Bakken. However, that belief is now in question, based on the latest production results from just over 100 newly tapped wells in the formation, some of which have shown more productive results than the Bakken wells.

A recent joint state-industry initiative has been conducted in an effort to prove the situation one way or another. Its initial results indicate that the two zones may indeed be distinct, which is encouraging news for the industry in North Dakota.

SASKATCHEWAN WELL ACTIVITY

AUG/08

AUG/09

AUG/08

AUG/09

AUG/08

AUG/09

WELL LICENCES

550

152

WELLS SPUDDED

525

160

WELLS DRILLED

528

167

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • OCTOBER 2 0 0 9

57

Saskatchewan Photo: Brian Zinchuk, Pipeline News

“The large U.S. private company has about 260,000 acres just south of us in North Dakota and they’ve been working the play for about the last three years.

They’ve had some failures and successes, but I think they’ve got it turned around now,” Dawson said. “They’re starting to make some pretty good wells, so we’ve got production [in North Dakota] within about four miles of our block.”

NuLoch’s earning well (one net), drilled in 2008, recovered formation oil and natural gas during extended testing operations. However, water cuts were much higher than expected, load oil was never fully recovered, and the well is currently not producing.

Dawson said that planned follow-up location will use a different completion technique to minimize or eliminate contact with water-bearing zones in adjacent formations. He said some of the companies that have been kicking the tires of the Three Forks–Sanish stateside have “dialed in” and are now fracing with water and going case hole instead of employing the Packer’s Plus system, and NuLoch plans to follow suit.

“You hope to get it right with the first well, but it never seems to happen that

Canadian companies in the Three Forks-Sanish play include NuLoch, Baytex, and Second Wave.

way. So we’re re-loading and we’re going to get back in there drilling,” Dawson said.

“Our target is to be drilling in the fourth quarter. We’re going to try to drill two to three delineation wells in the in the next nine months and by the end of the fourth quarter, we’re hoping to have three wells into the play.”

Baytex Energy Trust has a Three Forks– Sanish/Bakken project located in Divide

and Burke counties of North Dakota.

Production is primarily from horizontal wells using multi-zone hydraulic fracturing in the Bakken and Three Forks formations. Both zones are accessed through a single horizontal lateral.

To date, the trust’s U.S. subsidiary has invested in approximately 251,000 (94,000 net) acres of land. In 2008, Baytex participated in eight gross (three net) wells. The

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Saskatchewan trust also participated in the acquisition of a new 3-D seismic survey covering 188,000 acres, which has since been completed.

Net production from the project was approximately 341 barrels of oil equivalent per day in the fourth quarter of 2008.

Baytex president and CEO Tony Marino says that ultimately, the project has the potential to include 150 to 300 wells with average initial rates expected to be 190 barrels of oil equivalent per day or more per well and average recoveries expected to be 280,000 barrels of oil equivalent per well or more.

“Results to date I think actually are quite encouraging. The current program, with the results that are in place with the drilling we did last year, is certainly economic at current prices,” Marino said.

“In fact, we do think that over time we’re going to get a lot better results, both on a cost side and the production side as the play moves up the curve.”

Because of low crude oil prices at the time, Baytex curtailed drilling activities in the play from around Christmas of 2008 until recently. Marino said that since the seven-month hiatus, the trust has picked up the pace and started with a re-drill of a vertical well that has since been turned

into a horizontal well. That well is not yet completed, but Baytex recently finished the drilling and casing phase of that well.

“I think the most number of fracs that we actually ended up getting into one of those wells last years was about six. But we’re targeting 11 for the vertical well that we just re-drilled,” Marino said. “We actually think we can improve quite a bit on the fracturing design. We are operating the wells in this phase of the project—the drilling and completion phase—so we do think we’re going to get improvements in productivity.”

For the remainder of the year, Marino said the trust plans to drill one well in the Three Forks about every 35 days, meaning four new wells are anticipated. “It’s going to take a bit of time to complete those wells, so none are going to be on production at least for the next month or so,” he explained. “After that, we’ll start to get some contribution from those wells.”

Marino noted that while wells currently are coming in at about US$4.5 million, those costs are expected to decrease as the trust continues to advance its knowledge of the play and service costs continue to decline.

The government of Saskatchewan is taking a wait-and-see approach before

labelling the Three Forks (Torquay) Sanish an emerging prospect for that province’s oil industry. “From our perspective, it’s obviously premature for us to speculate. From what I’ve seen, the Americans are trying to determine whether it’s a regional play or whether it’s localized.

Again, we don’t have that data yet,” said Paul Mahnic, acting director of the province’s Petroleum Tenure Branch.

“Notwithstanding this sort of lack of geological data that we’ve got, there’s certainly an area [in the province] that we’re cautiously optimistic about, which is the term we like to use. Anything that’s associated with oil that’s likely sourced from the Bakken shale is definitely going to raise our interest.”

Although Manitoba has an extension of the Three Forks in the southwest corner of the province, government officials say it’s a different geological setup from that in North Dakota and parts of Saskatchewan.

“In North Dakota and Saskatchewan, the Bakken and Three Forks may be separate reservoirs, but in Manitoba this is not the case,” said Keith Lowdon, director of Science, Technology Energy and Mines Petroleum Branch.

— DAILY OIL BULLETIN

O I L & G A S I N Q U I R E R • OCTOBER 2 0 0 9

59

Saskatchewan

Petrobank-TriStar deal creates a dominant heavyweight Petrobank Energy and Resources Ltd. and TriStar Oil & Gas Ltd. have agreed to merge a cash and stock deal that will see the new entity—called PetroBakken Energ y Ltd.—become the dominant player in southeast Saskatchewan’s prolific Bakken light oil play. The new company hopes to eventually recover close to 400 million barrels from the tight reservoir formation.

“This is a unique opportunity to bring together two like-minded organizations to c reate a pre m ie r sout hea ste r n Saskatchewan light-oil producer offering exceptional growth potential, focused on applying leading-edge technology to major resource plays, with our primary attention directed initially at the Bakken formation,” said Petrobank president and CEO John Wright in a conference call on Aug. 5.

Petrobank will receive 64 per cent of PetroBakken’s shares, while TriStar holders will get $580 million in cash and 61.8 million shares, or 36 per cent of the new entity.

1750-??? October OGI adOL.indd 1

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OCTOBER 2 0 0 9 • O I L & G A S I N Q U I R E R

Following completion of the transaction, PetroBakken plans to divest a package of Alberta-based assets consisting of approximately 9,500 barrels of oil equivalent per day (44 per cent light oil, 56 per cent natural gas), and 40.1 million barrels of oil equivalent of proved-plus-

Saskatchewan, making PetroBakken the single largest landholder in this region.

Of this, over 280,000 net acres (440 net sections) are located in the Bakken play fairway with significant further exposure to Bakken exploration activity, including 80,000 net acres in Montana.

PetroBakken Energy Ltd. hopes to recover 400 million barrels from the Bakken. probable reserves to further enhance the focus of PetroBakken on southeastern Saskatchewan light oil resource plays.

Fol low ing t he divest it ures, PetroBakken will primarily be a pureplay, southeastern Saskatchewan, light oil-focused company with 2009 exit production of more than 37,000 barrels of oil equivalent per day, more than 95 per cent light oil, more than 70 per cent of which will be from the Bakken. “On a consolidated basis, PetroBakken will be the most Bakken-weighted public oil producing company in Canada,” Wright said.

T he merged company w ill have over 800,000 net acres in southeast

The new company will have more than 1,300 future Bakken drilling locations. A typical Bakken section is generally recognized by third-party evaluators as holding about four million barrels of oil in place with proved-plus-probable recovery estimated at 12.5 per cent. PetroBakken’s own assessment, based on strong production performance combined with higher well density and frac intensity, is that the recovery factor can ultimately be increased to 22.5 per cent of the original oil in place.

At that rate, the 440 net sections of land controlled by the company could eventually prove up close to 400 million barrels of recoverable oil.

8/13/09 4:25:15 PM

Saskatchewan

Photo: Brian Zinchuk, Pipeline News

“We believe the consolidation of the southeast Saskatchewan and Bakken assets of Petrobank and TriStar, and the combination of each company’s strong technical staff is the next step in the evolution of our company,” said Brett Herman, president and CEO of TriStar.

Wright said the new company will have significant future development opportunities in the Horn R iver and Montney gas resource plays in northeastern British Columbia that will add long-ter m g row t h to Pet roBa k ken’s attractive light oil position. He estimated PetroBakken’s potential resource at 5 trillion to 20 trillion cubic feet of original gas in place in northeastern B.C. contained in more than 63,000 net undeveloped acres, with over 400 potential drilling locations.

PetroBakken plans to execute a 2010 capital budget of approximately $550 million based on a US$75 WTI oil price. Under the plan of arrangement, Wright will serve as chairman and CEO of PetroBakken, Gregg Smith as president and COO, and Corey Ruttan will be the CFO—all are executives of Petrobank Energy.

— DAILY OIL BULLETIN

PetroBakken's capital budget for 2010 is pegged at $550 million, assuming a WTI oil price of US$75.

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O I L & G A S I N Q U I R E R • OCTOBER 2 0 0 9

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National Energy Board says more pipeline workers are being injured

Photo: Joey Podlubny

by James Mahony

Factors that boost injury rates include more construction, staff inexperience, and deadline pressure.

A National Energy Board (NEB) study on worker sa fet y i n t he Ca nadia n pipeline sector suggests the business may be getting riskier for those working in the field. The study found that nearly 2 of ever y 100 pipeline workers suffered a serious workplace injury in 2007, almost twice the seven-year average for the industry.

The rate of injuries per 100 workers rose 18.8 per cent between 2006 and 2007, according to the study, which covered t he 20 0 0 to 20 07 per iod.

Acknowledging 2007 was the tenth year in which there were no work-related fatalities during construction or operation of board-regulated pipelines, the NEB nonetheless noted that two deaths occurred on Canadian pipelines last year, and indications are that the injury rate for pipeline workers is rising (a death in 2005 was deemed non-work-related).

According to the board’s sur vey, the natural gas pipeline sector, which accounts for two-thirds of board-regulated pipelines, was the biggest contributor to the higher rate of injuries reported in 2006 and 2007. The latter was the

second consecutive year the injury rate for workers rose, leading the board to express concern about the trend.

In 2007, the NEB boosted safet y inspections of field activities, including pipeline construction. Inspections are geared to monitor activities so the board can better understand and communicate measures to improve worker safety, the NEB said. Inspections found that compliance with NEB regulations increased for the third consecutive year.

example, although contractors booked just 1.6 million work hours compared to 4.8 million hours for carrier employees, 40 injuries were reported among contractors, versus only 18 among employees.

More recently, the gap between the two groups has narrowed somewhat, as 33 injuries were reported in 2007 among contractors who booked 2.9 million hours, versus the 22 injuries reported by employees that worked just under 2.9 million hours the same year.

While the NEB’s survey showed a marked increase in the number of injuries a mong pipel i ne ca r r ier employees between 2005 and 2007, the board said a survey by the Canadian Association of Petroleum Producers showed a decreasing frequency of such injuries during the same period.

A mong f ac tor s c ont r i but i ng to more frequent injuries, the NEB cited increased pipeline construction in recent years, level of employee experience, pressure to meet deadlines, and workplace complacency.

“We have been aware of the increasing [injur y] frequency over a period of time and continue to work with [the NEB] to ensure that our programs are trying to attack that,” said Kim McCaig, V P of operat ions for t he Ca nadia n Energ y Pipeline Association (CEPA).

“There has been significant infrastructure renewal going on in the last number of years and it will likely continue for the

In 2007, the NEB boosted safety inspections of field activities, including pipeline construction.

Workers covered by the study included two main groups: employees of NEBregulated pipeline carriers and independent contractors. Among the longer-term trends emerging from the study was a differing injury rate between pipeline employees, on one hand, and those working for contractors, on the other.

The injury rate among contractors has been consistently higher than for employees, and has risen for the past four years, the federal study said. In 2001, for

next decade. As a result, there is more exposure to risk and we’ve got to make sure we understand that and put in place things to mitigate it,” McCaig said.

He defined success in the field of workplace safety as reaching an injury rate of zero. “In 2008, we’re already seeing, at least in CEPA’s statistics, a reduction in the frequency of injuries, so we think there’s been some success in some of the programs,” McCaig said.

— DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • OCTOBER 2 0 0 9

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OCTOBER 2 0 0 9 • O I L & G A S I N Q U I R E R

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Ford’s new commercial van will plug into the American power grid Brigham completes 24 stage frac

— ASSOCIATED PRESS

— DAILY OIL BULLETIN

Photo: courtesy of Ford

about how electric car owners will seek to recharge their vehicles.

General Motors Company is set to release its Chevrolet Volt next year, a rechargeable electric vehicle the company says will get up to 370 kilometres on a single gallon of gas. The Volt differs from Ford’s forthcoming Transit Connect as the Volt contains an internal combustion engine, which kicks in after driving about 65 kilometres.

Ford’s Transit Connect will not contain a combustion engine and the number of kilometres a user can drive will be determined by the size of the battery Ford installs in the car, company officials said.

Specifics on the vehicle’s driving range and price have not been released.

Ford said it is working to build connectivity between its electric vehicles and local power grids in certain areas, so owners can choose to recharge at offpeak times when electricity is cheaper, or when wind, solar, or renewable energy is driving the grid, said Nancy Gioia, director of Ford’s sustainable mobility technologies division.

Brigham Exploration Company announced on August 10 that the Anderson 28-33 #1H well in North Dakota produced approximately 2,154 barrels of oil equivalent (boe) per day from the Bakken formation during its early 24-hour flow back period.

Brigham’s Anderson 28-33 #1H well, to the company’s knowledge, is the first successful 24-stage fracture stimulation completion in the Williston Basin.

The Anderson 28-33 #1H was successfully fracture stimulated and produced approximately 1,838 barrels of oil and 1.9 million cubic feet of natural gas, from the Bakken formation during its early 24-hour flow back. Brigham maintains an approximate 66 per cent working interest and 55 per cent net revenue interest in the Anderson 28-33 #1H well, located in Mountrail County.

Also in the Ross area, Brigham recently announced the Strobeck 27-34 #1H Three Forks discovery, which produced approximately 2,021 boe per day during its early 24-hour f low back. Brigham controls approximately 35,200 net acres in the Ross area, and assuming three Bakken and three Three Forks wells per 1,280 acre drilling unit, Brigham could potentially drill 165 net wells for full development.

Last year the company drilled the Adix 25 #1H Three Forks well and the Carkuff 22 #1H Bakken well in the Ross area.

Those wells commenced production at 928 and 1,234 boe per day, respectively. The Adix 25 #1H and Carkuff 22 #1H were short lateral wells with 11 and 12 frac stages, respectively.

“Although they are very good wells, it appears that our 18 stage fracture stimulation long lateral Strobeck 27-34 Three Forks well and our 24 stage fracture stimulation long lateral Anderson 28-33 Bakken well should provide stronger returns for our shareholders,” said Bud Brigham, Brigham’s president and CEO.

Ford's new Transit Connect all-electric van aims at reducing gasoline consumption.

Ford Motor Company says its future electric cars will “talk” to power grids across the country, allowing car owners to control when they charge vehicles and for how long. In August, the second-largest American automaker released details of a two-year collaboration with 10 utility companies and the U.S. Department of Energy on the design of a system it hopes will drive greater interest in alternative energy vehicles.

Ford’s first battery electric vehicle, the Transit Connect commercial van, will be available next year. A battery electric Ford Focus compact car will go on sale in 2011.

“At the end of the day this has to be easy for our customer,” said Ford chairman Bill Ford Jr. Ford and the utility companies are testing the system and have logged 75,000 miles on a Transit Connect test fleet.

Utility companies say their grids are ready to handle electric cars, although some drivers are likely to need additional equipment installed in their garages, depending on the vehicle’s voltage requirement. Vincent Dow, Detroit Edison’s vicepresident of distribution operations, said there are “more questions than answers”

O I L & G A S I N Q U I R E R • OCTOBER 2 0 0 9

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On the Job

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JOB Careers in the Oilpatch

Jordan LaBonte Age: 23 Title: Water plant operator Employer: Devon Canada Education: Third Class Power Engineer Certificate, Portage College, Lac La Biche, Alberta Length in Position: Two years with Devon Energy’s Jackfish SAGD Project

What does your job involve?

I am responsible for the safe operation of the water plant.

My specific duties involve producing water for our boilers, making sure equipment is operating correctly, and troubleshooting any problems that may come up during my shift.

What skills are essential for a plant operator?

Probably the biggest one is having a thorough understanding of the processes that occur in the plant. That understanding is critical when it comes to identifying and addressing various problems that can arise, ranging from a check valve stuck open or shut to an electrical or instrumentation issue.

Being a strong communicator is another essential skill. You need to have a strong, two-way flow of communications between your control room operators and your fellow operators [steam plant, process, and field operators].

What’s the best part of your job?

The camaraderie. Everyone gets along very well. We can crack a joke, but when it’s time to get serious, everyone gets down to business to finish the work.

What’s the most difficult part?

The hardest part for me would be transitioning into my first night shift. We work seven-12 hour day shifts and then get a week off. Then we work seven 12-hour night shifts followed by another week off. Most workers have their own ways to cope with the transition. I personally find taking a nap in the afternoon helps me feel more refreshed for a night shift.

Photo: Joey Podlubny

What advice can you offer someone who wants to become a plant operator?

Listen to your senior operators. They have a lot of knowledge and good advice to pass on. Come in with an open mind and an eagerness to learn.

O I L & G A S I N Q U I R E R • OCTOBER 2 0 0 9

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Rig Talk

A LOOK AT NEW DRILLING TECHNOLOGIES

Universal Pump Hold Down System

Who is Dura Products?

Dura Products is a Canadian company based in Swift Current, Sask., for almost 30 years. Our primary business is the manufacture of bottomhole pumps and related production equipment. Most of our business is in western Canada, although recently we have been working to develop a more international customer base. Being a small company, we can react very quickly to customer requests. This strength, combined with our in-house downhole equipment design expertise, enables us to provide new designs that meet specific customer needs within aggressive time frames.

What is the Universal Pump Hold Down System?

The Universal Pump Hold Down System (patent pending) allows a conventional reciprocating rod pump or rotational progressive cavity pump (PCP) to be installed interchangeably into the same pump seating nipple. This feature makes the product particularly well suited for thermal production where operators may have a need to change the pump type as the well’s temperature profile changes during steam injection or oil production. The system can be configured for either top or bottom hold down configuration as required. The system also incorporates Dura’s patented and field-proven metal-to-metal hold down sealing rings that have proven highly reliable in aggressive high-temperature wells over many years.

What are the competitive advantages of this system?

The primary advantage of the system is the interchangeability of pump type—reciprocating or rotary. Either pump type can be located into the universal seating nipple—even the running and pulling methods are identical.

Set down weight to install, straight pull to release—no orientation or rod manipulation is required. This means that the pump can always be retrieved, even if it has seized internally. We do not know of any other system offering this simplicity and flexibility.

The design has also generated a lot of interest with PCP manufacturers.

Insert PCP systems are not a new idea; however, the simplicity of design and operation of the Dura Universal Pump Hold Down System appears to overcome some of the limitations of previous designs. The releasing mechanism is completed isolated from well fluids—and therefore particulates—which could prevent retrieval. This has been a major failure mode for previous systems.

Has this technology been deployed in the field?

This is a brand new product—we do not have any field installations as yet, although we have live quotations in Canada, the U.S., Asia, and the Middle East. We have prototype tested both the three-and-a-half inch and fourand-a-half inch sizes to 3,500 foot pounds and 5,000 foot pounds, respectively—well above any torque that the rod string could ever apply. Given the simplicity of the design, we can configure a system to fit any nominal tubing size, with no additional O.D. or I.D. constraints imposed.

Answered by Paul McCreedy, General Manager Dura Products Inc. O I L & G A S I N Q U I R E R • OCTOBER 2 0 0 9

69

Political Cartoon

Advertisers' Index 1174365 Alberta Ltd....................................................... 56 Ace Instruments (1995) Ltd........................................... 43 Alberta Magazine Publishers Association...................... 32 All Weather Shelters Inc................................................. 29 Allan R. Nelson Engineering (1997) Inc........................68 Annugas Compression Consulting Ltd........................... 17 ASAP Heating & Well Servicing Corp.............................30 ATCO Structures Inc.......................................................28 BC Hydro........................................................................ 27 Bear Slashing Ltd............................................................ 38 Bidell Equipment LP....................................................... 55 Bilton Welding and Manufacturing Ltd..........................48 Black Sivalls & Bryson (Canada) Ltd.............................. 10 Brews Supply Ltd.................................... Inside front cover Brother’s Specialized Coating Systems Ltd....................30 Brownlee LLP................................................................. 53 Canadian Enviro-Tub Inc......................Outside back cover Compact Compression.................................................... 56 Compass Bending Ltd..................................................... 38 Delta Industrial Valves Inc.............................................23 Dean's Pump Service......................................................46 DFI.................................................................................... 8 Dicks Boiler Ltd.............................................................. 33 Diversified Glycol Services Inc....................................... 53 Double S Oilfield Services Ltd........................................ 50

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OCTOBER 2 0 0 9 • O I L & G A S I N Q U I R E R

Enform...........................................................................66 Enviro Vault Ltd.............................................................. 58 Eveready Inc................................................................... 55 Falvo Electrical Supply Ltd.............................................34 Fence Inc........................................................................ 47 Flexpipe Systems...................................................... 40/41 Global Oil & Pipe Inc....................................................... 29 Joule Technical Sales Inc................................................ 52 Kangabags......................................................................30 Kenilworth Combustion Ltd........................................... 38 Laird Plastics (Canada) Inc............................................. 62 LJ Welding & Machine....................................................46 LoTech Manufacturing Inc.............................................48 Meridian Mfg Group.......................................................48 MPI-Marmit Plastics Inc.................................................34 Multicon Ltd................................................................... 53 Norsteel Buildings Ltd....................................................64 Northern Bridge And Mat Rentals Ltd...................... 18/19 Northern Industrial Camp Maintenance........................ 29 Northgate Industries Ltd................................................44 Norwesco Canada Ltd.....................................................44 Oil Lift Technology Inc...................................................54 OilPro Oilfield Production Equipment Ltd..................... 53 P & H MinePro Services of Canada................................. 56 Pedestal Supply..............................................................66

Pembina Controls Inc.....................................................44 Penfabco Ltd................................................................... 47 Phoenix Fence Inc........................................................... 47 Platinum Energy Services Corp...................................... 15 Platinum Grover Int. Inc........................................... 36/37 Propak Systems Ltd.......................................................... 3 ProstAid Calgary Society...............................................68 R. Pollitt Oilfield Construction Ltd.................................64 Radafab Oilfield & Industrial Supply Inc........................ 11 Risley Equipment Inc......................................................34 Rogers Communications.................................................. 4 Sil Industrial Minerals.................................................... 42 Singletouch...................................................................... 5 SkyBase Geomatic Solutions Inc..................................... 61 Systech Instrumentation Inc.......................................... 51 T & E Pumps Ltd.............................................................. 52 TCA Marketing Ltd........................................................... 7 Trans Peace Construction (1987) Ltd............................. 62 Tremcar Inc.................................................................... 59 Vertigo Theatre Society..................................................64 Wellhead Distributors Int’l Ltd............... Inside back cover ZCL Composites Inc........................................................60

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