Page 1

MARCH 2010 â– $6.00

CaRdium RusH Penn West CEO Bill andrew outlines a vast new tight oil play in central alberta

Canadian Publication Mail Product Agreement #40069240

Check out this story and more in the Red Deer Focus section inside

Re-inventing the service rig

Technicoil’s Marv Clifton and Ben Nowell are adapting coiled tubing to multi-stage frac completions

High-pressure outlook

Pressure vessel manufacturers face still-slow oilsands activity and increasing foreign competition


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5

Page


Table of Contents

Keeping readers regionally informed

F E A T U R E S

12

Re-inventing the service rig by Mike Byfield Technicoil’s Marv Clifton and Ben Nowell adapted coiled tubing to multi-stage frac completions

18

High-pressure outlook by Graham Chandler Pressure vessel manufacturers worry about still-slow oilsands activity and increasing foreign competition

DEDEEERRTEA RTA R& E AL ALBALBER RDERD NTRAL CE&NCTE

A regi

to to plement plement onal sup onal sup A regi

March

2010 2010 March

(er) cheap Talk is

n or LiTaT CeS friCTio TCh y faCi dU e Pa SynergWaTerS re TS and Th a KriST n reSiden ee beTW

Focus on Red Deer begins after page 24 The Cardium tight oil play is sparking renewed field activity in Central Alberta. Take a look at the players, and how stakeholders are striving to remain neighbourly in an increasingly crowded corridor.

PLUS S hoLe acquire TighT e race is on to in cretiv ights A se g ins n d drillin formatio land an rdium a’s Ca Albert

Sh w iUm rU Card st CEO Bill Andreoil play tight nn We Pe new a vast a outlines al Albert in centr

As the economy strengthens, look for stories with the Recession to Recovery logo to help you through uncertain times. And be sure to check out junewarren-nickles.com/r2r for Recession to Recovery stories from all JuneWarren-Nickle’s publications.

6

March 2010 • OIL & GAS INQUIRER


Table of Contents

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

25

ENGINEERED CONTAINMENT ADVANTAGES

N E W S

British Columbia

37

• In 2010, EnCana will frac Horn River wells

• Some oilfield service companies see

in as many as 23 stages

stronger prices on the horizon

• Apache invests in $3B LNG terminal and

• PSAC raises its 2010 drilling forecast

plans Canadian expansion

29

Northwestern Alberta/Foothills

by 1,000 wells

43

• Orion focuses its $85M capital budget

Northeastern Alberta

expertise to Alberta Cardium

45

• ConocoPhillips and Total proceed with

Central Alberta

Central Canada • Environmental policies that damage

Surmont SAGD expansion

33

Saskatchewan • PetroBakken will apply its Sask

on Kaybob and Redwater

31

Southern Alberta

the West hurt all of Canada

47

• Ron Liepert becomes Alberta’s energy

International • Three Canadian energy service

minister in a cabinet shuffle

companies land overseas contracts

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I N

10

E VE R Y

I S S U E

Statistics at a Glance

51

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

49

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Editor’s Note Vol. 22 No. 3 President & ceo Bill Whitelaw | bwhitelaw@junewarren-nickles.com

Mike Byfield | mbyfield@junewarren-nickles.com

Publisher Agnes Zalewski | azalewski@junewarren-nickles.com

Stelmach’s last chance

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

Joseph Caouette, Marisa Kurlovich, Kelley Stark proofing@junewarren-nickles.com Contributors

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Rianne Stewart | rstewart@junewarren-nickles.com INTERIM ART DIRECTOR

Ken Bessie | kbessie@junewarren-nickles.com CREATIVE SERVICES SUPERVISOR

Tamara Polloway-Webb | tpwebb@junewarren-nickles.com Graphic Designer

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Jerry Chrunik | jchrunik@junewarren-nickles.com Nick Drinkwater | ndrinkwater@junewarren-nickles.com Michael Goodwin | mgoodwin@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 For advertising inquiries please contact adrequests@junewarren-nickles.com Marketing Senior Marketing Coordinator

Alaina Dodge-Foulger | adodge@junewarren-nickles.com Marketing / Trade Show Coordinator

Ryan Mischiek | rmischiek@junewarren-nickles.com

Marv Clifton and Ben Nowell of Technicoil Corporation fit the classic patch profile—both originally blue-collar boys from the sticks who got their start labouring in the oilfield. Thanks to financial pressure and brilliant inspiration, these two Calgarians developed the coiled tubing service rig. Others soon came up with variations on the same theme, including Trailblazer and Xtreme Coil. Altogether, it’s a great extension of western Canada’s world-leading achievements with coiled tubing. From land-based rig top drives to multi-stage fracs, the West has a strong record of innovation. Our economy will do fine as long as men like Nowell and Clifton have the opportunity to work effectively and create wealth. Unfortunately, that’s not the case today. This industry has not only been afflicted with an unstable royalty regime, but it’s seriously over-regulated. The provincial government’s Competitiveness Review heard all about over-regulation when it met with the Canadian Association of Petroleum Producers and the Small Explorers and Producers Association of Canada. Although the sessions were not open to the media, I’m told that oilmen protested even more bitterly against the job-strangling snarl of regulations than royalty rates. As this issue of Oil & Gas Inquirer goes to press, the Competitiveness Review was expected to release its report within a few weeks. Conducting that review are former Nexen VP Roger Thomas and Chris Fong, formerly with the Royal Bank of Canada. They’ll probably make the right recommendations. But will Premier Ed Stelmach and his team listen? If recent public opinion polling is correct, most Albertans now question the wisdom of leaving the same political party in office for four decades. The white-hot core of that opposition is the petroleum industry. At this late stage, its distrust won’t evaporate even if the royalty structure is reformed properly. However, slashing red tape quickly and decisively would restore some respect, maybe even gratitude, toward Stelmach within the province’s key industry. Regulatory streamlining represents his best shot—if not his only shot—at retaining power.

Marketing designer

Andrew Brien | abrien@junewarren-nickles.com OFFICES Calgary

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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 | © 2010 1072125 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 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

An oilpatch salute to women

If you know an admirable person to profile in

Virtually everyone anticipates another

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

shortage of energy services personnel when

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

field activity rates rebound. Can women help

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

make up that shortfall in significant numbers?

email mbyfield@junewarren-nickles.com.

Oil & Gas Inquirer profiles women who have

In fact, feel free to sound off about any

made careers in this demanding sector.

concern at all—that’s a personal invitation.

OIL & GAS INQUIRER • March 2010

9


Stats

FAST NUMBERS

199,668

AT A GLANCE

Number of Albertans employed directly or indirectly due to natural gas activity in 2008, according to a new study from IHS Global Insight

133 per cent

Reserve replacement ratio achieved in 2009 by Exxon Mobil Corporation, largely due to almost one billion BOE credited to LNG projects in Papua New Guinea and Australia.

Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin

MONTH

OIL

GAS

OTHER

TOTAL

MONTH

OIL

GAS

DRY

SERVICE

TOTAL

Feb 2009 Mar 2009 Apr 2009

116 321 111

899 979 344

120 317 140

1,135 1,617 595

Feb 2009 Mar 2009 Apr 2009

269 433 111

1,060 1,121 342

113 165 61

36 86 12

1,478 1,805 526

May 2009 Jun 2009 Jul 2009

71 36 79

187 143 178

53 42 77

311 221 334

May 2009 Jun 2009 July 2009

71 177 79

187 211 31

46 45 6

35 27 3

339 460 119

Aug 2009 Sept 2009 Oct 2009

101 146 132

212 155 160

80 78 77

393 379 369

Aug 2009 Sept 2009 Oct 2009

250 146 331

267 155 196

36 45 32

37 9 12

590 355 571

Nov 2009 Dec 2009 Jan 2010

169 121 253

212 127 324

116 35 62

497 283 639

Nov 2009 Dec 2009 Jan 2010

382 283 429

244 138 343

68 34 55

10 13 13

704 468 840

Wells Drilled In British Columbia

Wells Drilled In Saskatchewan

Source: B.C. Oil and Gas Commission

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

MONTH

WELLS D R I L L E D

CUMULATIVE *

Feb 2009 Mar 2009 Apr 2009

117 75 33

242 317 350

May 2009 Jun 2009 Jul 2009

26 19 34

376 395 429

Aug 2009 Sept 2009 Oct 2009

36 38 29

465 503 532

Nov 2009 Dec 2009 Jan 2010

39 44 31

571 615 31

* from year to date

OIL

GAS

OTHER

D RY

T O TA L

Vertical Wells

Lloydminster Kindersley Swift Current Estevan

48 3 8 11

0 0 40 0

1 1 1 4

1 3 2 12

50 7 51 27

3 18 14 81

0 0 0 0

0 0 0 0

0 0 0 0

3 18 14 81

51 21 22 92

0 0 40 0

1 1 1 4

1 3 2 12

53 25 65 108

Horizonal Wells

Lloydminster Kindersley Swift Current Estevan Total Wells

Lloydminster Kindersley Swift Current Estevan

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March 2010 • OIL & GAS INQUIRER

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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

5.5

2.75

$4.97/GJ Total vol.: 1,576 TJ Transactions: 158

2.02 Tcf Year ago: 1.99 Tcf 5-year avg: 1.97 Tcf 2.25

5.0

4.5

in the United States

1.75

Jan 20

Jan 27

Feb 3

Feb 10

Feb 17

Jan 15

Jan 22

Jan 29

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada February 16, 2010 Source: Rig Locator

Alberta January 2010 Source: Daily Oil Bulletin

ACTIVE

DOWN

TOTAL

(Per cent of total)

Western Canada Alberta

ACTIVE

384

178

562

68%

British Columbia

94

22

116

81%

Manitoba

10

3

13

77%

Saskatchewan

71

39

110

65%

559

242

801

70%

2

2

4

50%

WC Totals Northwest Territories

Feb 5

OIL WELLS

Alberta

GAS WELLS

Jan 10

Jan 09

Jan 10

Jan 09

Northwestern Alberta

53

42

76

153

Northeastern Alberta

27

24

1

7

Central Alberta

141

76

69

174

Southern Alberta

32

15

178

269

253

157

324

603

TOTAL

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada February 16, 2010 Source: Rig Locator

Alberta January 2010 Source: Daily Oil Bulletin

ACTIVE

DOWN

TOTAL

ACTIVE

Western Canada 331

240

562

68%

British Columbia

23

11

34

68%

Manitoba

10

1

11

91%

Saskatchewan

134

50

184

73%

WC Totals

498

302

800

62%

1

1

2

50%

Quebec

COALBED METHANE

Alberta

Alberta

Feb 12

BITUMEN WELLS

Jan 10

Jan 09

Jan 10

Jan 09

Northwestern Alberta

1

9

7

19

Northeastern Alberta

0

0

27

22

Central Alberta

19

49

84

24

Southern Alberta

74

89

0

0

TOTAL

94

147

118

65

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Blank page for duplexing


Feature Photo: Technicoil Corporation

CT Service Rig

Photo: Technicoil Corporation

Re-inventing THE Service Rig Technicoil’s Marv Clifton and Ben Nowell are adapting coiled tubing to multi-stage frac completions by Mike Byfield

CT Service Rig

F

rom 2002 to 2008, Technicoil Corporation built a fleet of coiled tubing rigs designed to work with vertical shallow gas and coalbed methane wells. In 2007–08, however, the boom ended, slamming the shallow drilling sector hardest of all. In its determined thrusts to find new work, Technicoil did more than just survive—the Calgarybased firm has pioneered revolutionary changes to the service rig business. Technicoil president Marvin Clifton and technical specialist Ben Nowell have adapted coiled tubing (CT) technology to a pair of new functions: first, rigless 12

March 2010 • OIL & GAS INQUIRER

completions of horizontal wells with multi-stage fracs and, second, running wireline in horizontal steam assisted grav it y drainage (SAGD) wellbores. “For these tasks, we’ve shown that our masted CT units are faster, safer, and less intrusive than traditional service rigs,” Clifton comments. Technicoil’s fleet consists of 17 masted CT service rigs (the largest fleet of coiled fracturing units anywhere), and 6 hybrid CT drilling rigs. In addition, the company purchased a fleet of nine conventional service rigs (eight singles and a double) in 2007, a diversification from exploration

and development into the more stable production side of the industry. The personnel roster stands above 250 and this winter the company is 30 per cent busier than it anticipated just a few months ago. Su r v iv a l h a s come at a pr ice. Technicoil’s share value has plunged from the $4 range in 2006 to $0.65 currently, and the company lost $2.9 million on revenue of $30.6 million for the first nine months of 2009 (the last period for which financial results are available). Like many service companies, the company can be grateful for low interest rates on its debt (today’s bank prime rate of 2 to 3 per cent


is a stark contrast to the oilpatch collapse of the early 1980s, when interest rates ran as high as 20 per cent). While its conventional service rigs are operating at about the same rate as last year, Technicoil’s CT units are doing much better thanks to resource plays and SAGD activity. “I think the classic service rig will have its place in our industry for a long time to come, but it will be pushed more and more onto the production side,” Clifton predicts. “For well completions, I think CT service rigs will continue to gain market share.” The Technicoil CEO grew up in Taber, where his father worked in a sugar refinery.

Photo: Technicoil Corporation

Photo: Jack Cusano

Technicoil CEO Marvin Clifton (left) and technical specialist Ben Nowell designed CT service rigs for frac through coiled tubing in multi-frac horizontal well completions.

Clifton first started in the patch working summers as a rig hand while earning his bachelor’s degree (sociology and psychology plus an education credential) at the University of Lethbridge. He taught school for two years in Vauxhall, Alberta, then decided to study commerce at Utah’s wellknown Brigham Young University. On joining Bow Island Drilling in 1974, the former teacher took to oil and gas like a duck to water. After rising to general manager of Atco Drilling, he moved to Cactus Drilling from 1980 to 1997, becoming president of that company. When Cactus was taken over, Clifton became senior VP

CT Drilling Rig

of operations in Precision Drilling’s well servicing arm. Technicoil brought him on board at the end of 2002. The young company had already made a name for itself by building a dozen CT units that featured masts. A classic CT rig feeds its coiled tubing into the well by an injector head that’s suspended from an overhead crane. Technicoil found that suspending the injector head from a mast offers greater efficiency and safety. Technicoil’s CT rigs were self-propelled body units (i.e. the front cab and engine form a single unit with the coiled tubing OIL & GAS INQUIRER • March 2010

13


Feature

assembly). They offered mobility plus a small footprint on the farmlands where most shallow gas drilling takes place. The original concept had been to drill vertical wells with this innovative equipment, but it proved more suitable for “frac through coil” completion services. Halliburton contracted the entire fleet, then triggered a crisis by not renewing at the end of the contract term. “At that point, Halliburton bought five of the units. I was hired as chief operating officer by Art Dumont [then Technicoil’s CEO] to get the rest of our equipment back to work,” Clifton says. About the same time, Technicoil took another stab at building CT shallow drilling rigs, completing two more self-propelled units, this time incorporating top drives. Fortunately, coalbed methane drilling was starting to take off in central Alberta’s Horseshoe Canyon formation. Each vertical CBM well requires a series of hydraulic fracs, performed precisely and quickly.

“They are among the most modern and advanced coiled drilling rigs in the world.” –Marvin Clifton, President, Technicoil

Calfrac Well Services Ltd., primarily a pressure pumping firm, breathed new life into Technicoil by subcontracting its uniquely configured “frac through coil” fleet. Techncoil continued to innovate. Its CT self-propelled body units, although capable of moving across fields, were too heavy to qualify for highway permits. At that time, CBM wells tended to be much further apart than shallow gas wells, so the CT rigs had to be loaded onto 40-wheel trailers. In 2006, to implement a more cost-effective alternative, Dumont and Clifton hired a man who relishes mechanical challenges. Ben Nowell has dedicated most of his working life to oil and gas completions. After finishing high school at Sandy Lake in the southwestern corner of Manitoba, he came to Alberta. “I’ve roughnecked, pushed tools, and built rigs as a project manager,” Nowell says. His first project at Technicoil was lopping the cab and engine

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March 2010 • OIL & GAS INQUIRER

Technicoil’s innovative CT service rigs are based on technology that was originally intended for drilling shallow wells.

off each body unit, then replacing the drive train with a 24-wheel suspension. With the addition of a separate tractor, the firm had created a highly mobile, compact solution that could be hauled without expensive third-party truckers. Technicoil has continued to evolve its CT rigs—a term that the company now uses in place of “frac through coil”. Since 2005, Nowell has supervised construction of 10 new CT service rigs, with the first unveiled at Calgary’s Global Petroleum Show in 2006. Trailers have become progressively longer, depth capacities greater.

Nowell also managed the creation of five hybrid drilling rigs (a reference to their use of both CT and jointed pipe), the last being completed in 2008. These top drive-equipped units, built by Foremost Industries LP in Calgary, can drill to 2,000 metres. “They are among the most modern and advanced coiled drilling rigs in the world,” Clifton says. During the boom, construction was often delayed by late deliveries and other difficulties that are typical during busy times. But even before Technicoil’s “bleeding edge” fleet of CT service and drilling rigs was complete, the bottom fell off the


Feature Photo: Technicoil Corporation

market due to declining natural gas prices. “CBM drilling peaked in 2006 and we were overbuilt for the western Canadian market,” Nowell says. Additionally, the relatively small service company didn’t have international exposure. Fortunately, the black economic cloud did have a silver lining, and a big one. Northeastern British Columbia’s Montney and Horn River Basin shale gas plays are so potent in terms of potential reserves that they’ve continuously moved forward. Shale gas development is completely dependent on multi-stage fracturing of long horizontal wellbores. “Shell and a

OIL & GAS INQUIRER • March 2010

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March 2010 • OIL & GAS INQUIRER

few other producers were already interested in rigless completions,” Nowell says. “We recognized that our CT service rigs are well-suited to rigless completions. We can rig up and tear out more quickly than a conventional service rig. Like a snubbing rig, we can enter a well under pressure. There, our competitive advantage is that fact that continuous coil means faster operations than jointed pipe, which snubbing units use.” At that stage, the challenge was convincing shale gas operators that coiled tubing could deliver reliable results. Their concerns included mast size (so a CT rig could accommodate a long enough tool string), reel size (which determines much coiled tubing is available for long wellbores), and the relatively small doghouse. “There are a lot of people on site when a shale gas well is being drilled and everyone wants to be at the centre

“With each new resource play, we’ve been there right off the hop.” – Marvin Clifton, President, Technicoil

of the action,” Nowell says with a smile. “In fact, we easily made all of the adaptations necessary for shale gas completions. Our equipment also offers another important advantage: when a CT service rig has finished the job, it can hang off the coiled tubing as a production string. There are Montney wells that will never see a conventional service rig.” Again working with Calfrac, Technicoil did its first shale gas work in the Montney on wells belonging to EnCana Corp. and Duvernay Oil Corp., which has since been acquired by Shell Canada. Today the company has six CT service rigs in northeastern British Columbia. It’s also entered the Bakken tight oil development in southeastern Saskatchewan, and is now working in Alberta’s rapidly expanding Cardium tight oil initiatives. “With each new resource


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play, we’ve been there right off the hop,” Clifton says. At least 15 per cent of Technicoil’s revenue now comes from SAGD ranging in bitumen reservoirs. SAGD requires pairs of horizontal wellbores, one above the other. Steam reaches the bitumen through the injector well, warming the tarry crude so it drools downward into the production well. Hence the producer wellbore must be drilled in parallel with the injector well (typically the pair is about 15 metres apart) for thousands of metres. Technicoil offers what it calls smart coil, an e-line inside coiled tubing. A CT service rig feeds e-line into the injector wellbore. A magnetic signal generated by the e-line guides the drilling rig as it drills the producer wellbore. There is a cheaper alternative: the e-line can be towed along the injector wellbore by a small tractor. However, Nowells points out, the tractor can be blocked by debris in wellbore, it can slip on bitumen in the raw hole, and it’s slow. “Because we push and pull from surface, our rigs can move the e-line more quickly and wellbore integrity won’t hold us up,” he says. Operating efficiencies being developed by producers in nor theastern British Columbia, particularly the Horn River Basin, will shift cash flows within the service sector, according to the Technicoil CEO. (Arthur Dumont retired in 2008 but remains a director.) Producers are drilling up to 16 wells from a single pad, with talk of 24 wells in the future. As a result, hundreds of fracs being performed on the same wellsite, which remains in use for months at a time. “Obviously, you need a lot less construction and trucking if you consolidate so much drilling onto one pad,” Clifton says. “I think we’ll see a similar trend toward consolidation in other western Canadian resource plays over time.” The Technicoil CEO’s long record as a senior executive has been critical to his company’s momentum. “Customers and our own directors respect his judgement. That confidence enables us to take more risks than usual,” Nowell says. Clifton himself does not foresee any slackening in the patch’s pace of change. “Working conditions, for example, are incomparably cleaner on a CT service rig than a traditional service rig,” he says. “And the other day, I approved maternity leave for a male rig hand—we’re in a new world compared to just a few years ago.”

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OIL & GAS INQUIRER • March 2010

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Alberta’s pressure vessel and heat exchanger manufacturers are major employers in Edmonton and Calgary.

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March 2010 • OIL & GAS INQUIRER


High-pressure

outlook

Pressure vessel manufacturers worry about still-slow oilsands activity and increasing foreign competition by Graham Chandler Photography by Joey Podlubny

S

ince January, Albertans concerned for t he i r e conomy h ave b e e n encouraged by a spate of headlines: “Oilsands roar back to life with move by Husky, BP”; “Oilsands rolling again”; and “Conoco, Total give boost to oilsands” do seem encouraging. Yet the 20 member companies of the Alberta Pressure Vessel Manufacturers’ Association (APVMA) aren’t ready to start cheering quite yet. Their concerns: oilsands construction plans remain smaller in scale than previous years and foreign competition is intensifying. The oilsands have long been the principal market for the province’s pressure vessel and heat exchanger manufacturers. “They are really the key here,” says APVMA chairman Riley Milford. “There are some coalbed methane and other natural gas developments, but there’s not as much infrastructure required for these projects—typically just pumping gas to plants where they have extra capacity.” Oilsands producers, determined to control costs, are striving to avoid another traffic jam of massive construction contracts. “In 2007 and 2008, Alberta had several multi-billion-dollar oilsands projects on the go,” Milford notes. “So what we’re seeing is a real shift away from that. Now, a lot of the majors are indicating that they are going to go with smaller projects—breaking multi-billion-dollar projects into three or four stages.” Oilsands expansions have been hobbled by lower crude prices and higher provincial royalties. The Edmonton region is home to about 60 per cent of Alberta’s capacity to manufacture pressure vessel and heat exchangers while the rest resides in Calgary. Both cities have been slammed by the oilsands downturn. Aker Solutions, for example, just closed a Calgary fabrication shop that employed 75 or more people in better times. The multinational will continue to maintain a sizable engineering and sales team in the city but will outsource its fabrication. “When the government was deciding on the new royalty regime, we had lobbied them to really take a good look at what was best for Alberta as a whole, including our industry,” says Milford, the business development manager for Calgary-based Exchanger Industries. “We wanted to emphasize the subsequent effects that an excessive increase in royalties would have on our industry and the huge trickle-down impacts that would OIL & GAS INQUIRER • March 2010

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be felt by all Albertans.” The APVMA chair hopes the royalty impediments will soon be eased. That hope springs from a recent cabinet shuffle by Premier Ed Stelmach and his promise to re-examine the royalty structure. The size of a pressure vessel often dictates where it gets built. A small unit would be pipe size, 12 inches in diameter and 6 feet long. A bigger vessel can be up to 32 feet in diameter and over 100 feet long. “One of those coke drums you’ve seen pict ures of going f rom Edmonton to Fort McMurray weighed over one million pounds,” Milford says. “Edmonton vessel fabricators typically build the really big stuff.” Alberta’s famed oilsands have drawn global attention, a factor welcomed by cost-conscious bitumen producers. “We have been seeing more and more foreign competition in this market,” Milford says, adding that some of the upcoming oilsands projects will likely include international components. The APVMA views quality as a key competitive advantage for its members. “We in Alberta have

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March 2010 • OIL & GAS INQUIRER

very stringent requirements; every one of our units has to meet ABSA [Alberta Boilers Safety Association] approval— both a design review and inspection once it’s complete and hydro tested,” says the association’s chair. “There have been cases of products from the Far East that have needed repair once they arrive here from not meeting Alberta regulations. But we are hearing that they have picked things up for the most part,” Milford says. In his view, foreign competition is now the greatest

APVMA members estimate that imports have already accounted for well over $50 million in business. “It’s frustrating to see trucks loaded with imported vessels and exchangers rolling by a plant gate that has a ‘Closed’ sign posted on it,” says one recently laid-off worker (who requested that his name be kept private). The APVMA is deeply concerned that the competition be fair. Saari, who’s been involved in this industry for 23 years, is leading a government lobbying initiative. To develop a case, the association sent out

“It’s frustrating to see trucks loaded with imported vessels and exchangers rolling by a plant gate that has a ‘Closed’ sign posted on it.” –Anonymous worker (recently laid off)

challenge facing pressure vessel and heat exchanger manufacturers based in western Canada. “There’s all this work from South Korea coming here and we are being hurt by that,” says Bob Saari, the association’s manager.

questionnaires to members asking what foreign companies are bidding in this market, what projects were involved, and the estimated cost differential offered by foreign fabrictors. “We also tried to factor in how much work Alberta fabricators lost


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[to date] to this competition,” the APVMA manager adds. The industry group has explored the possibilit y of building an antidumping case against this class of imports. (Dumping is a term that refers to a company selling a product in Canada for less than it fetches in its homeland.) Crafting a robust anti-dumping case is labourious as well as expensive, consuming six to twelve months. The APVMA’s Ottawa-based consultant “outlined the total process and said it would cost us at least $150,000 in legal costs,” says Saari. “We don’t have that kind of money,” especially since the actual price tag could well be significantly higher. “Each one of our member companies would have to lay out: here’s what we sold in the past three years, here’s what we project for the next two years, here’s where we are being hurt by the competition, etc,” Saari explains. “Then the companies that are importing that equipment would have to defend their position. You would then have to go to Revenue Canada and prove to them that we have been injured. They would go to Korea and get them to open

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their books to prove whether or not they have been subsidizing their industry. Once you gain all of this information, you then come back to Canada and have to appear before the CITT [Canadian International Trade Tribunal] and present the case again before they make a ruling.” The APVMA has decided to try a lower-cost alternative. “We have written a paper on this proposing to put together a task force on how the industry is being hurt and to have something to show the

somewhat limited,” says Saari. “So we chose to get involved with some of the government-run bodies that impact our association.” To this end, one of its members chairs ABSA, which is the governing body for the rules and regulations for pressure vessel manufacture in the province. Another member chairs the Boilers and Pressure Vessel Council, which looks at technical issues. “On the safety side, we have a member on the board of the Manufacturers’

“Where you used to have good relationships with local engineering and purchasing staff, you are now dealing with outfits that are international in scope.” –Bob Saari, Manager, Alberta Pressure Vessel Manufacturers’ Association

government—that would be our major lobbying effort now,” Saari says. “I have recommended a series of items that are going to the membership, after which I’m hoping we will be prepared to release it.” On most issues, the association approaches governments indirectly. “Realistically, our lobbying efforts are

Health & Safet y A ssociation, which we were a major part of founding in 1992,” says Saari. “And we have another member on CSA 51, a national committee on pressure vessel standards.” He feels this approach is better. “Instead of the staff person lobbying, we choose to place them on those organizations—it is more

efficient working from within rather than trying to lobby from outside.” The APVMA would also like to prepare a SWOT analysis—strengths, weaknesses, opportunities, and threats. “When we did a study a couple of years ago, one of the things we found was that our competitors in other countries, including the United States, don’t necessarily have to adhere to the same safety and reporting regulations that we have to comply with here in Canada,” Saari says. “They have different requirements where they are located. For instance, for pressure vessel design approvals we have to go through ABSA and in the U.S. [and elsewhere] that requirement is performed by an insurance company.” Compounding the difficulties of foreign competition for APVMA members is a new marketing hurdle. Many global engineering companies used to maintain offices in Alberta, but times have changed. “These major [engineering] companies now have a central office, say in San Francisco, and they work on world mandates,” Saari explains. “They will shop the world for pricing on various products. Where you used to have

The Alberta Pressure Vessels Manufacturers’ Association alleges that Asian competitors are dumping product into the oilsands market. 22

March 2010 • OIL & GAS INQUIRER


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good relationships with local engineering and purchasing staff, you are now dealing with outfits that are international in scope—it’s harder to create and maintain those relationships.” Still, the APVMA sees positive signs for a turnaround in the sector, the most important being world oil pricing that has stabilized about US$70 per barrel for a period of months and less restrictive credit for resource companies. “We are hopeful that…this will give the producing community a level of comfort that things have stabilized so that they can move forward with projects that had previously been put on hold or cancelled,” Milford says. The association chair also thinks U.S. President Barack Obama’s recent green energy initiatives could open new business opportunities. “Solar, geothermal, and other green energy sources are touted as becoming more prevalent in the U.S. We are hoping that these emerging markets will be open to Canadian supply,” Milford says. For the present, however, the APVMA’s crucial concerns are oilsands development, provincial royalty reform, and reasonable protection against dumping by Asian countries in this market.

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EDITOR'S NOTE

Boom, boom, boom Mike Byfield

Listen carefully and you’ll hear a drum beat—boom, boom, boom—rolling across the parklands of central Alberta. The sound is still gentle but it’s getting louder with every passing week. Like southeastern Saskatchewan’s Bakken formation, the Cardium is tight rock that’s yielding up its light crude through multi-stage fracs in horizontal wells. The Cardium boom won’t mature in a day. We’re looking at a tech play, not a land rush triggered by an elephant discovery. Activity w ill grow as producers gain experience w ith the best ways to produce light oil from the formation. The same technology promises plenty of future drilling and jobs in the Viking, the Peace River Arch, and other formations across western Canada. Spearheadi ng the Cardiu m development is an i mprobable leader—the subsidiary of a life insurance company. Trusts are supposed to be low-risk operators. Yet NAL Oil & Gas Trust has

been probing tight sections of the Cardium for two years, reportedly with growing success. The Calgary-based outfit, owned by Manulife Financial Corporation, has core properties in southeastern Saskatchewan, central Alberta, and northeastern British Columbia—all areas that are prone to resource plays. Cautious folks will tell you that the Cardium game is still in the first period, and that’s true. Conceivably, the play will fizzle or sputter. But this prospect presents exactly the same type of tightrock engineering challenges that are already being licked from the Barnett shale of Texas to British Columbia’s Horn River Basin. Tight oil is big. Really big. Combined with coalbed methane and shale gas, tight oil will drive decades of drilling activity in the western basin, with plenty of that benefit going to central Alberta. In fact, this region may well be on the brink of its richest period to date.

table of contents

4 7 9

Cardium rush  enn West CEO Bill Andrew outlines a vast new tight oil play P in central Alberta

by Mike Byfield

Tight holes

A secretive race is on to acquire land and drilling insights in Alberta’s Cardium formation

by Paul Wells

Talk is cheap(er)  lberta’s growing synergy network reduces friction A between residents and the patch by Mike Byfield

SUPPLEMENT TO OIL & GAS INQUIRER · MARCH 2010 RD3


Photo: Christina Ryan

CARDIUM

red deer & Central Alberta Focus

Penn West CEO Bill Andrew has amassed more than half of all mineral rights in the Cardium formation, where he anticipates future production totalling hundreds of thousands of barrels per day.

RD4 SUPPLEMENT TO OIL & GAS INQUIRER 路 March 2010


red deer & Central Alberta Focus

CARDIUM Andrew

Cardium rush Penn West CEO Bill Andrew outlines a vast new tight oil play in central Alberta by Mike Byfield The near-death experience is slowly ending. Over the past two years, provincial royalty changes and low natural gas prices all but eliminated field activity in central Alberta beyond routine production. Now an exploration frenzy is gradually building up, with a flock of companies and crews targeting Cardium tight oil and other emerging plays. At stake are billions of barrels of light crude. Penn West Energy Trust owns the mineral rights to about half of the entire Cardium geological formation in central Alberta. “The ERCB [Energy Resources Conservation Board] recognizes 10 billion barrels of original oil in place for the Cardium, including 1.7 billion that have already been produced,” says Bill Andrew, Penn West’s CEO. “In our view, original oil in place could easily be 15 billion barrels and I’d say a 20 to 30 per cent recovery rate is a realistic prospect. So there’s potential there for production totalling tens of thousands of barrels per day.” Andrew gives full credit for initiating the Cardium play to other producers. “NAL, Nexstar, Bonterra, and others saw the opportunity and moved quickly,” he says. In essence, the technology that unlocked the Bakken tight oil play in southeastern Saskatchewan over the past few years has been applied by a handful of other companies to tight rock in Alberta. With Cardium estimates of oil in place running a possible eight million barrels per section, the outlook is bringing the junior sector back to life. Penn West, now in the process of converting from trust to corporation, is western Canada’s largest producer of light and medium oil. These grades, which are significantly more valuable per barrel than heavy oil, make up 44 per cent of its total output, which currently stands at about 170,000 barrels of oil equivalent per day. The remainder is heavy oil (15 per cent) and natural gas (41 per cent). “Cardium oil is light—36 or 37 degrees API—and sweet. This is first-class crude,” Andrew says. In his view, the trusts and other larger independent producers are well-positioned to develop the play. “We have the resources to run pilot projects and refine the best methods for producing from difficult reservoirs,” the Penn West CEO explains. “Once they’ve built up production to five or ten thousand barrels per day, many juniors are happy to exit through a sale to a larger independent such as ourselves. They’re explorers more than operators. The trusts, on the other hand, were always intended to be operators who specialize in squeezing as much oil and gas as possible from known fields.” The native of Prince Edward Island, an engineer by profession, joined Penn West in 1992 when its production was 500 barrels per day. Previously, he’d worked for Shell Canada, Gulf Canada, Canadian Occidental (now Nexen), Ocelot, and Opinac. Under his leadership, the trust consolidated a massive position in central Alberta through acquisitions from Petro-Canada, Cabre, Pan Canadian, Canadian Occidental,

BP Amoco, Petrofund, and Crescent Point. “We probably own 50 per cent of Cardium play, perhaps more, and we’re still buying,” Andrew says. His big-picture goal: to halt and possibly even reverse the long-term decline in conventional oil production from the Western Canadian Sedimentary Basin (WCSB). Daily output from the basin peaked in 1973 at 1.74 million barrels per day. In 2008, WCSB conventional oil production stood at one million barrels per day, a 42 per cent drop. Alberta’s output over the same 35 years plummeted by 65 per cent, from 1.43 million barrels per day to 505,000. A simple fact underpins Andrew’s optimism for the future: most of the WCSB’s conventional oil is still in the ground. Petroleum Technology Alliance Canada (an industry association) pegs the basin’s original oil in place at 98 billion barrels, of which 77 billion remains untapped. Unaided, only a certain amount of oil will flow into a wellbore. Add flooding with water, lighter hydrocrabons, or CO2 and the recovery percentage will rise. In Leduc pools and other reservoir whose rock has excellent permeability and porosity, recovery rates can reach as high as 60 to 70 per cent. Formations with tighter rock and less permeability have yielded far smaller shares of their oil in place. These reservoirs could not be effectively tapped with vertical drilling and fracturing. “The combination of horizontal drilling and multi-stage fracturing has dramatically improved our capacity to economically produce from tighter rock,” Andrew says. One measure of the importance and speed of this development: in 2007, 90 per cent of Penn West’s drilling investment went into vertical wells. For 2010, horizontal operations should account for 90 per cent. The Cardium formation is typical of the tighter oil prospects, with just 17 per cent of its estimated original oil produced to date. The reservoir consists of tight sandstone, with pay zones characteristically about seven metres thick. Where the sand became intermingled with chert gravel beds, porosity and permeability improves dramatically. These “sweet spots” account for central Alberta’s prolific Cardium fields, including Willesden Green, Garrington, Caroline, Carrot Creek, Harmattan, and Keystone. The granddaddy of them all, though, is the Pembina Cardium. This sprawling oilfield near Drayton Valley has produced 1.3 billion barrels since drilling began in 1953. In fact, Pembina briefly was the world’s largest onshore oilfield, Andrew says, and it’s still considered one of this continent’s top 10 conventional fields and the continent's largest field by aerial extent. Penn West has nearly 900 net sections of land in the west-central Alberta Cardium, producing 25,000 barrels of oil equivalent per day from 2,400 net wells. “As technology improves, we’ll see higher estimates of the original oil in place for formations like the Cardium and higher recovery rates,” Andrew says. He points out that Cardium production to SUPPLEMENT TO OIL & GAS INQUIRER · March 2010 RD5


CARDIUM

red deer & Central Alberta Focus

date has been very concentrated within the permeable sweet spots. For example, less than one per cent of the Pembina field’s total area accounts for 250 million barrels produced to date. More than 400 million barrels have been pumped from less than 10 per cent of the Pembina field. At Willesden Green, 10 per cent of the field’s area has yielded 500 million barrels. NAL and other innovators have focused their recent horizontal drilling on tighter reservoir rock along the flanks of the historical sweet spots at Pembina and elsewhere. Their successes indicate that a far larger portion of the formation could very well become profitably productive in the future. That’s an exciting prospect. From its heart at Drayton Valley, the Cardium formation arcs south past Cochrane, north beyond Edson, east as far as Calgary, and west to the Rocky Mountains. In the area, the Cardium oil-bearing formation ranks as the most extensive in North America. (Andrew says its only real peer on this continent is the Viking formation of Alberta and Saskatchewan, also now emerging as a hot tight oil prospect.) Much of this immense, easily accessible prospect is well-known to be oil-bearing. A typical Cardium vertical well in tight rock, fraced once, flushes 30 barrels of oil per day, then declines to maybe seven barrels over a couple of years. On the plus side, that low-rate production continues for decades. Thousands of these stripper wells dot western Alberta. Although the Cardium was rarely a drilling target outside of known oilfields, a producer who’d failed to score on a deeper primary target sometimes chose to frac and complete in the Cardium zone, hoping to recover some of its costs. A vertical well in the Cardium would typically cost about $1 million to drill, according to Penn West. A horizontal well, fraced at eight points along the wellbore, should generate oil production equivalent to six to eight vertical wells yet costs only $3 million, including

completion and tie-in. That cost is expected to fall with greater experience. Even now, returns from Cardium tight reservoir projects are promising. Although the province helps out with important royalty breaks, producers warn that the program (currently temporary) needs to be made permanent. Andrew says the existing low-output vertical wells provide excellent well control along with infrastructure like gathering pipeline systems and access roads. “We’re in a strong position to get up the operating curve once we learn how to produce from tight Cardium rock,” he comments. Penn West’s capital expenditures budget, slated to fall between $750 million to $900 million this year, includes 30 to 35 Cardium wells in west-central Alberta. That could rise, as could the $100 million designated for the play this year. Meanwhile, the trust is also focused on recovering additional oil from the Pembina Cardium’s sweet spots, where 70 per cent of the original crude typically remains in place. Here an operating challenge is high water cuts in production due to extensive earlier floods in the historic field. Penn West is reportedly making progress with this work, although much of the results to date remain confidential. Beyond central Alberta, Penn West has tight oil initiatives at Waskada in southwestern Manitoba, Dodsland in Saskatchewan (a Viking play), and Swan Hills and Otter in northern Alberta. Technological advances will continue to drive the industry, Andrew predicts—like more frac stages per well, research into the most effective proppants for fracs in specific reservoir conditions, and so on. “The oil is there, we also know there’s a lot of gas left, and now we’ve got the tools needed to produce it,” the Penn West CEO says. “I think western Canada is entering its best-ever generation of energy development.”

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red deer & Central Alberta Focus

CARDIUM

Tight holes A secretive race is on to acquire land and drilling insights in Alberta’s Cardium formation by Paul Wells Alberta’s Cardium resource play could see 200 or more horizontal wells drilled this year. “The combination of the real extent of the trend, extensive well control, known hydrocarbon-rich, water-free system, and very encouraging initial test rates from a number of operators on a growing number of wells all point towards huge potential,” said Kim Page, an analyst with Toronto-based Wellington West Capital Markets Inc. In a report, Wellington West said that while still early in the productive history of the majority of Cardium horizontal multi-stage wells drilled, it appears that these wells have initial production (IP) rates in the 200 to 250 barrels of oil equivalent (boe) per day. They then decline to the 100-boe-per-day range within six months, then production drops further but stabilizes in the range of 70 to 80 boe per day within a year. “Based on our economic runs, Cardium horizontal wells have the potential to rival Bakken wells in terms of expected rates of return, reserve potential on a per-well basis, and ultimate potential for resource development in and around existing fields,” Page said. Companies that are active or hold large acreage positions within or surrounding the Cardium field include ARC Energy Trust, Bonterra Oil & Gas Ltd., Enerplus Resources Fund, NAL Oil & Gas Trust, Midway Energy Ltd., Penn West Energy Trust, West Energy Ltd., Daylight Resources Trust, Angle Energy Inc., Result Energy Inc., and Bellatrix Exploration Ltd. Other early entrants into the play such as Berens Energy Ltd., Nexstar Energy Ltd., and Triaxon Resources Ltd. have recently been acquired by other companies looking to increase their position in the emerging play. “If you plot the last two weeks of producers’ performance, you’ll see that the Cardium producers have heavily outperformed their peers in market performance,” said Cristina Lopez, an analyst with Macquarie Capital Markets Canada. “Absolutely, this has been a play that has garnered a lot of attention and will continue to do so.” In a research paper, Macquarie credited NAL with advancing the Cardium light oil play in Alberta after it witnessed the success multistage horizontal drilling had in the Bakken and opted to try the same technique on some of its Cardium acreage. “Although the use of multistage horizontal drilling was believed to be amenable to other areas, NAL Oil & Gas Trust was the first to experiment with the technology in the Cardium [outside of a waterflood] during the fourth quarter of 2008,” the report said. Following on NAL’s success at Garrington, Macquarie says development of the Cardium has grown steadily in the past six months and is “expected to explode in 2010” with an estimated 200-plus horizontal

multi-stage frac wells targeting the Cardium, up from an estimated 35 wells in 2009. The Macquarie report said notable players that have indicated Cardium oil programs in 2010 include Penn West at around 30 wells, ARC at 32 wells with approximately half completed with multi-stage fracs, NAL at 20 to 25 wells, Bonterra at approximately 25 wells, Bonavista Energy Trust at around 20 wells, Daylight at between 15 and 20 wells, West Energy at 24 wells, Bellatrix plans 5 to 10 wells, Angle up to 8 wells, Vermilion Energy Trust 6 wells, and Baytex Energy Trust 5 wells. [As of Dec. 15] there are 55 wells licensed in the Cardium and we expect these licenses to pick up materially in the first quarter of 2010 as capital budgets are established and additional test results are released,” Macquarie said in its report. The Cardium in the smaller Garrington field is generally tighter than at Pembina. The tight-rock reservoir characteristics make Garrington an ideal candidate for experimentation with horizontal stage fracs and in the fourth quarter of 2008, NAL initiated its first four-well program at Garrington using multi-stage fracture completions and has become a pioneer in a play that is revitalizing the extensive Cardium trend in west-central Alberta. According to the Macquarie report, NAL initially used six- to eightstage 20-tonne oil based fractures on 1,000-metre-long horizontal legs. While results were variable, one-month IP rates of 200 to 500 boe per day were “very encouraging and underscored the massive potential through re-entering the tight Cardium oil package.” Macquarie said producers will soon begin experimenting with slickwater fracs that will save an estimated $400,000 per well. The report also notes that current completions are between 8 and 11 frac intervals in horizontal wellbores ranging from 1,000 to 1,600 metres, with frac sizes of approximately 20 to 30 tonnes. John Dielwart, ARC Energy Trust’s CEO, said the trust is the second-largest landholder in the Cardium behind Penn West Energy Trust, it is only in the early stages of developing the light oil resource play. For 2010, ARC has allocated $54 million to Pembina and plans to drill 32 Cardium locations on operated lands. Over half of these wells will be horizontal, multi-frac completions. “The intention of that program is to test a multitude of different opportunities, from very tight rock to horizontal wells in the sandstone, underneath the water-swept conglomerate,” Dielwart said. “We think the opportunity is very substantial. We’ll be a big player in it…. You will hear a lot more from us in the coming year as we finish drilling those wells.” — DAILY OIL BULLETIN SUPPLEMENT TO OIL & GAS INQUIRER · March 2010 RD7


red deer & Central Alberta Focus

Photo: Photo Magic/Linda Dubois

Synergy

Krista Waters, a professional facilitator, says face-to-face communication about energy-related issues is crucial to maintaining neighbourly relations.

RD8 SUPPLEMENT TO OIL & GAS INQUIRER 路 March 2010


red deer & Central Alberta Focus

Synergy

Talk is cheap(er) Alberta’s growing synergy network reduces friction between residents and the patch by Mike Byfield

Petroleum producers require prompt, affordable entry to their oil and gas leases. No factor, not even natural gas prices, is more important than reliable access to land. The multi-billiondollar issue for Red Deer and central Alberta: in a region that’s getting more crowded every month, will neighbours remain neighbourly? The alternative is an industry that finds itself increasingly bogged down in time-consuming regulatory disputes. Land use is a province-wide issue, of course. To coordinate the needs of all industries, social groups, and the environment, an array of provincial planning initiatives is underway. Among the most important are the Clean Air Strategic Alliance, the Alberta Water Council, the Alberta Land-use Framework, and dozens of local stakeholder groups. The overall strategy—based on a social philosophy called synergy— originated in central Alberta. That’s not a coincidence—the heartland between Calgary and Edmonton is a focal point for intense development. Its well-watered soils rank among the province’s very best agricultural land, supporting operations that range from export-quality hay crops to large hog barns. Its beautiful landscapes attract thousands of acreage owners. The rich promise of the region’s light oil–bearing geological formations is reviving the traditional patch, and its lavish coalbed methane reserves will also drive extensive drilling activity when gas prices rise again. Fostering harmony between these different folks is the role of Krista Waters, who works with local synergy groups as a professional facilitator. A typical synergy group includes landowners, other residents, petroleum producers, municipal government representatives, regulators, and any other interested stakeholders in a specific district. The group acts as a forum where both education and negotiation can occur, minimizing potential conflicts in resource development. Waters, who lives northeast of Caroline, Alberta, has plenty of experience with the concerns of central Albertans. The consultant works with the Central Mountainview Action Group (originally sparked by coalbed methane development around Olds), the West Central Stakeholders Group (in the Rocky Mountain House-Caroline area), and the Wetaskiwin Synergy Initiative. She’s also handled specific contracts for the Sundre Petroleum Operators Group (the province’s first synergy group) and the Calumet Synergy Group (a district east of Ponoka).

“The value comes from bringing all of the right people face to face at the same table. After people explain where they are coming from and all the information is ‘on the table,’ we often see new solutions emerge on questions like where a wellsite should be located,” Waters says. “It changes the nature of the discussions or negotiations when all the points of view are shared. It also helps when landowners feel well informed.” Barriers to communication include lingo that’s second nature to oilmen but confusing to outsiders—for example, ‘spudding’ a well or even ‘barrel’ when there’s not a single potato or barrel in sight. A synergy meeting may review a general subject like drilling and water tables, with specialists in attendance to speak to that issue. Although industry pays the bills for most synergy groups, speakers and experts are called on from a broad range of organizations including government officials or an environmental lobby group like the Pembina Institute. Alternatively, a synergy meeting may focus on a specific situation. For instance, several landowners may be concerned about excessive pipeline densities. A quarter-section can become so riddled with pipeline setbacks that constructing a new home or even selling the property becomes problematic. Besides water impacts and well location, typical landowner concerns include compensation, heavy traffic, noise and dust, emissions and odours, access road placement, scenic values, ultimate abandonments, and other details. Waters says the synergy process scales up and down efficiently, from the widespread concerns of acreage owners around a recreation lake to a parent concerned about rig hauls during school hours. Waters grew up on a farm near Caroline and later worked as a newswoman in Red Deer. The mother of three says residents’ expectations of producers have evolved a great deal over the last few decades. “As residents become more informed, they do expect more and different things from the industry. Industry has adapted and continues to improve at informing the public about their operations and cooperating with their concerns. Directional drilling has added a lot of flexibility for producers in terms of well location. It also helps that multiple wells can be drilled from one pad, which reduces the footprint,” she comments. At the neighbourhood level, natural gas laced with poisonous hydrogen sulphide is arguably the mother of all environmental issues. Waters says sour gas continues to generate controversy when deep, high-volume wells are drilled in the foothills. “However, we’ve also SUPPLEMENT TO OIL & GAS INQUIRER · March 2010 RD9


red deer & Central Alberta Focus

Photo: Photo Magic/Linda Dubois

Synergy

Judy Winter (left), a retired teacher, discusses energy with Krista Waters. had lot of sour gas production in the Rocky Mountain House-Caroline region,” the facilitator states. “I’ve experienced cases where residents have enough confidence in the regulations and the safety systems for sour gas operations that companies can’t muster up interest to attend an open house a proposed sour gas well.” David Pryce is VP, operations for the Canadian Association of Petroleum Producers (CAPP), which whole-heartedly supports the synergy movement. “When an oil and gas company arrives at a landowner’s door, that family may have a sense of ‘Whoa, what’s up here, this is new!’ That’s understandable—it’s a new situation for them. But that family will soon discover that resources are available. More than most Albertans realize our industry has made a huge effort in learning to live with all stakeholders.”

RD10 SUPPLEMENT TO OIL & GAS INQUIRER · March 2010

Pryce handled the environmental and community aspects of the Wolf Lake thermal bitumen project in the early 1980s, then went on to head BP’s environmental group in Calgary. “Synergy amounts to working through disparate issues until a common position can be reached. It’s a continuous process that adapts to new factors as they bubble up,” says Pryce. In his view, the Clean Air Strategic Alliance (CASA) was a pivotal development in Alberta’s homegrown synergy movement. The non-profit association was established in 1994 as a new way to manage air quality issues, notably flaring of sulphur dioxide. CASA is a multi-stakeholder partnership, composed of representatives selected by industry, government, and non-government organizations. CASA’s key decision-making tool is the Comprehensive Air Quality Management System. CAMS integrates matters relating to health, environment, energy, and the economy into decisions that affect air quality. The board of directors, representing all stakeholders, determines what issues need to be addressed. As needed, organizing committees and projects teams are created to deal with specific problems. With respect to flaring, Pryce launched a project team with an environmental activist, the late Martha Kostuch. The team developed a test that assesses the value of flared gas versus the cost of the equipment needed to eliminate the emissions. “Martha was determined, but she had the ability to see a situation from the perspective of others. That willingness is the key to coming up with a workable fix. Over time, we’ve reduced the flaring of solution gas at oil batteries by 72 per cent and we’re still making progress,” the CAPP VP says. “I believe the flaring situation is now viewed as well-managed by pretty much everyone involved.” As CASA worked on a province-wide basis, synergy groups began appearing at the district level through the 1990s. Alberta is home to


red deer & Central Alberta Focus at least 31 local synergy groups, from Taber to Peace River. In 2002, CAPP and the Alberta Energy Resources Conservation Board (the ERCB was called the Energy & Utilities Board at the time) sponsored the first provincial synergy conference. For two days, 248 participants were coached in the art of mediating solutions within a disparate group. Synergy Alberta, a provincial umbrella group, organizes annual conferences and workshops. The non-profit organization also provides some basic online resources. Even so, it’s still very much a locally driven phenomenon. “CAPP simply does not have the resources to participate in all of those local groups,” Pryce says. “The ball has to be carried by producers who are active in a specific area, along with other local stakeholders.” Alberta’s ongoing development, which is most evident in the central Edmonton-Calgary corridor, prompted the provincial government to initiate the Land-use Framework (LUF) in 2008. The LUF is intended to address combined or cumulative effects of all human activity, including impacts on water supply, wildlife habitat, and many other factors. In essence, Alberta has been chopped into seven regional divisions, each of which will have its own detailed land-use plan. Parallel examples are cities that are routinely zoned into areas that are primarily used for single-family homes, higher-density residential units, commercial, light industrial, and so forth. The LUF will define the primary usage of lands within a division. For example, the land on either side of the Calgary-Edmonton highway will be allocated for transportation as a primary use, and property owners can plan their own developments accordingly. “I see our future land-use and water strategies being developed in a synergistic fashion,” Pryce says. “Working together, stakeholders must define the issues, consider the needs of all parties, and define a path

Synergy

forward by favouring reasonable compromise.” Detailed land-use plans are now being worked out for northeastern Alberta (oilsands country) and southern Saskatchewan, which embraces most of southern Alberta. Completion is scheduled for this year. This year, the province plans to initiate division planning for the North Saskatchewan and Upper Athabasca. Red Deer, Upper Peace, and Lower Peace will follow in 2011. Each division plan should be completed by the following year, meaning all plans are slated to be in place by 2012. Following what is likely to be many months (or years) of discussion and debate, the final versions of these plans will have the force of law. LUF experts and other participants will be working closely with the Alberta Water Council, a synergy initiative modelled on CASA. CAPP plans to participate in each watershed group that’s formed by the province-wide water council. “More than half of all oil production in Alberta is assisted by steam or waterflooding,” Pryce says. “Water is a critical resource. In planning its use, we must balance social, economic, and environmental needs rather than being co-opted into seeing through a single lens.” As far as Krista Waters is concerned, the synergy approach is working well so far. “Each year, the number of cases that go to the ERCB’s ADR [alternative dispute resolution] or even the hearing process is small compared to the number of well drills,” she says “Each hearing is very expensive, takes a lot of time, and often has an outcome that’s less than favourable for at least one of the involved parties. It’s in everyone’s interest to reach sensible compromises wherever possible, preferably early on, at the ‘kitchen-table’ stage of discussion.” Delays and unpredictability make planning extremely difficult for energy managers. And Alberta is already one of the world’s highestcost operating arenas for an oil and gas producer.

SUPPLEMENT TO OIL & GAS INQUIRER · March 2010 RD11


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British Columbia

In 2010, EnCana will frac Horn River wells in as many as 23 stages

Photo: EnCana Corporation

by Elsie Ross

In the Horn River Basin, EnCana plans to experiment different well spacing and other variables.

This year, EnCana Corp. and Apache Canada will be targeting well completions in the Horn River Basin using an average of 19 fracturing stages per well, with some as high as 23. Kevin Smith, VP of EnCana’s Fort Nelson business unit, said, “There is a correlation between the number of stages pumped in a well and the actual performance of a well.” Smith was addressing a Calgar y conference sponsored by the Canadian Institute on Jan. 26. The two companies are 50-50 partners in the play. In 2009, they completed three 14-stage wells and one 12-stage well. In an earlier 10-stage well, the 30-day average rate was about nine million cubic feet per day. EnCana is continuing to drill longer horizontal laterals to accommodate the increase in stages, although it has no plans to shorten the distance between stages within a wellbore. Developing

more acreage with a single wellbore is key and “very accretive” to the economics of the play, according to Smith. In drilling more and longer wells on a single well pad, the company is also reducing its environmental footprint. “W hat we are heading into is a real game-changer as far as the development goes here,” Smith said. EnCana is

With 16 wells and an average of 19 fracs per well, that will mean more than 300 fracs per well pad. Pumping 24 hours a day, it will take two to four months to complete a single pad. “Our frac company should be building permanent housing out here,” Smith joked. “It is going to be a very different application of their hardware.” That’s also where EnCana expects a lot of its efficiencies as it benefits from the 24-hour utilization of the service company’s pumping equipment. Since entering the Horn River basin in 2003, EnCana has drilled 50 gross wells with 13 gross wells on production at the end of 2009. This year, it expects to drill about 21 net wells, the company said earlier. Up until this point, EnCana has consistently maintained a 40-acre spacing, but as it moves forward it is going to be testing a lot of different spacing variables, said Smith. It also will be employing different job sizes, different sand tonnages, and using perforation clusters rather than single perf intervals as it experiments to find the optimum approach. The production plot is notable in the similarity in character of the curves, the conference heard. “What that really tells me… is that we have something that is very homogeneous, at least in our area of development,” he said. Results that EnCana has seen from around the basin support that belief.

“Our frac company should be building permanent housing out here.” –Kevin Smith, Vice-President, EnCana’s Fort Nelson business unit

now drilling up to 16 wells on a single pad with the longest well drilled so far, achieving a total measured depth of 5,400 metres. “That gives us 2,200 to 2,400 metres of horizontal lateral which we are completing.”

Cooperation between producers in terms of infrastructure and sharing their development plans for the area has been an unusual aspect of the basin since Apache, EnCana, Nexen Inc., EOG Resources Canada Inc., and Devon Canada

JAN/09

JAN/10

JAN/09

JAN/10

WELLS SPUDDED

161

101

WELLS DRILLED

130

61

BRITISH COLUMBIA WELL ACTIVITY

JAN/09

JAN/10

WELL LICENCES

107

100

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • March 2010

25


British Columbia

Corporation started the Horn River Basin Producers’ Group, said Mike Simpson, Nexen’s manager of unconventional exploration. “Industry cooperation on surface issues and technology can benefit all stakeholders and minimize our footprint in spite of our traditional competitive nature of our industry,” Simpson said. When it comes to unconventional resources, collaboration is the way of doing business simply because of the potential scale of development, the Nexen executive told the conference. “I don’t think we have a choice,” said Simpson. “We talk in townships, not in sections or quarter-sections, and your impact is so widespread that just by definition it involves a number of companies, and if we don’t collaborate on the surface issues for sure we are going to essentially hurt the credibility of industry.” The producers’ group recognizes that surface issues are not an afterthought, he said. In planning, stakeholder concerns need to be built in right from the

beginning and the producers’ group has been doing that quite effectively, according to Simpson. The producers, for example, have worked together on shared roads that also include pipeline rights-ofway to reduce the overall environmental disturbance. Multi-well pads with horizontal wells also help in that objective. EnCana has also been active in the tight gas Montney play where it has 730,000 net acres (1,100 sections) of land between Grande Prairie, Alberta and Dawson Creek, British Columbia, with an estimated 70 trillion cubic feet of gas in place. In 2009, EnCana drilled about 60 wells focusing on both the Upper and Lower Montney zones but took a different approach to completions, said Smith. In t he Upper Montney, it used Halliburton Corporation’s CobraMax fracturing application to complete the wells, while in the Lower Montney it used openhole swell packers primarily with energized fluids and then slick water. “We see some

really encouraging performance with an average of over four MMcf [million cubic feet] per day from the initial completion over a 30-day rate with some wells coming in at over 10 MMcf a day,” Smith said. Similar to Horn River, EnCana is adding length and fracturing stages to increase and enhance the performance of the wells. Where there is both Upper and Lower Montney potential, the company is drilling 8 to 10 wells per section to develop. “The tight curve performance is actually living up to actual data we are getting,” said Smith. With this performance, from a largescale perspective, the Montney is one of the strongest performing assets in EnCana’s portfolio with a rate of return approaching 50 per cent and a supply cost close to US$3 per thousand cubic feet. “We have come a long way,” he said. “In 2006, we were struggling to get a 12 per cent rate of return out of the Montney.” — DAILY OIL BULLETIN

Apache invests in $3B LNG terminal and plans Canadian expansion Apache Canada Ltd. has agreed to acquire 51 per cent of Kitimat LNG Inc.’s planned liquefied natural gas (LNG) export terminal in British Columbia. Apache also reserved 51 per cent of capacity in the terminal. “The growing supply of natural gas in the United States and Canada is transforming North American energy markets, and this increased resource has significant potential for global impact,” said G. Steven Farris, Apache Corporation’s chairman and CEO.

“Development of the Kitimat LNG project has the potential to open new markets in the Asia-Pacific region for gas from Apache’s Canadian operations, including the Horn River Basin in northeastern British Columbia, where our net estimated resource potential exceeds 10 trillion cubic feet of gas,” Farris said on Jan. 13. T he pr op o s e d K it i m at pr oj e c t , located at Bish Cove near the Port of K itimat about 652 k ilometres north of Vancouver, has planned capacity of

Apache wants access to global markets from B.C. via LNG tankers. 26

March 2010 • OIL & GAS INQUIRER

about 700 million cubic feet of natural gas per day, or five million metric tons of LNG per year. Preliminary construction cost estimates of C$3 billion will be refined at the conclusion of front-end engineering and design (FEED). The project will employ an estimated 1,500 people during construction and 100 on a permanent basis. Kitimat LNG received its Provincial Environmental Certificate for the liquefaction terminal in December 2008 and the Federal Environmental Certificate in January 2009. “The economic fundamentals remain strong for exporting natural gas from western Canada to international markets where natural gas is in demand, such as Asia,” said Alfred Sorenson, CEO of Galveston LNG Inc., parent company of Kitimat LNG Inc. “As natural gas supply and reserves continue to increase in North America, Kitimat LNG’s terminal will provide producers in Canada with secure access to key worldwide markets.” Under the terms of the agreement, Apache will make an initial payment to the current owners of Kitimat LNG with additional consideration due upon achievement of certain commercial and regulatory


British Columbia

milestones. Apache will fund the project’s FEED—to begin shortly—with a final investment decision expected in 2011. First LNG shipments are projected for 2014. Apache will become operator of the project. Kitimat is designed to be linked to the pipeline system servicing western Canada’s natural gas producing regions via the proposed Pacific Trail Pipelines, a $1.1-billion 463-kilometre project originating at Summit Lake, British Columbia. Through its acquisition of a 51 per cent interest in the Kitimat project, Apache will acquire a 25.5 per cent interest in the pipeline, currently a 50-50 partnership between Galveston LNG and Pacific

America will have a surplus of gas, Tim Wall, president of Apache Canada, said in a conference call. “I do think it could benefit other markets by being able to export some of that surplus gas.” Rosemar y Boulton, president of Kitimat LNG, said her company has additional memorandums of understanding with other gas producers but is still looking for additional investors. “There certainly is an opportunity for us to bring additional partners, on either capacity or equity, into the plant,” she said. In December, Apache announced it will embark on evaluation of the commercial potential of gas development in New

In December, Apache announced it will embark on evaluation of the commercial potential of gas development in New Brunswick, in the Frederick Brook shale formation, and light oil development at the recent Caledonia oil discovery. Northern Gas Ltd. The proposed pipeline has received both the federal and provincial governments’ environmental assessment approvals and has created an innovative arrangement to partner with the First Nations along the pipeline route. With the development of the Marcellus shale play in Pennsylvania and the Horn River and other Canadian gas, North

Brunswick, in the Frederick Brook shale formation, and light oil development at the recent Caledonia oil discovery. The Houston-based producer and its jointventure partner EnCana Corporation plan to have 27 horizontal gross wells on production in the Horn River Basin in northeastern British Columbia by the end of the first half of 2010.

However, in interviews last month, officials at TransCanada Corporation, who are hoping to build their own pipeline transporting gas from the Horn River basin into the Alberta system, expressed skepticism about the economics of the Kitimat LNG project. A producer shipping gas to the West Coast would need a netback higher than $9.25 per thousand cubic feet, assuming a natural gas price at the wellhead of $5.25 per thousand cubic feet, $1 for pipeline transportation to Kitimat, and $3 for liquefaction, said Russ Girling, COO. In contrast, a shipper who wants to get Horn River gas to the Alberta Hub would pay a receipt charge of $0.25 per gigjoule for a minimum of three years. The Canadian mainline toll to the eastern zone would add another $1.60 per gigajoule. And while LNG proponents are eyeing prices such as $15 per mmBtu from Asian buyers for Canadian LNG, Hal Kvisle, TransCanada president and CEO, questioned the assumption that LNG will continue to be priced off oil in a world where there is a surplus of LNG. “If I was a Japanese utility buyer, I would be saying, ‘Why should I do that [pay that price],’” he said. “The world has changed. There’s now lots of LNG out there and let’s see what the price of LNG is rather than tying it to oil.” — DAILY OIL BULLETIN

B.C. brings in nearly $13M in first land sale of 2010 The B.C. government brought in nearly $13 million in revenue on the sale of 19 parcels in its first land auction of 2010. January’s sale saw 9,444 hectares sold for a total of $12.95 million, which worked out to an average of $1,371 per hectare. That’s an improvement from the same sale last year, which delivered $7.1 million to the province on 10,280 hectares for average of $690.39 per hectare. One lease in the Sunrise gas field area 20 kilometres northwest of Dawson Creek produced a per-hectare bid by Britt Resources Ltd. of over $20,687 per hectare, the land sale high. The broker paid over $5.3 million—nearly half the entire land sale—for the 259-hectare lease at 14-79-17W6. Producers in the area have been actively targeting the Montney

formation. EnCana Corporation has several wells licensed in the area. Six leases in the Blair Creek area, roughly 115 kilometres north of Fort St. John, went for bids of between $1,088 and $4,249 per hectare, totalling over $4.7 million. Windfall Resources Ltd. plunked down $1.2 million for 283 hectares (4,248 per hectare) for units 74, 75, 84, and 85 at F-94-B-16. Broker Canadian Coastal Resources Ltd. paid the same amount for units 94 and 95 at F-94-B-16 and units four and five at K-94B-16. Daily Oil Bulletin records show that Painted Pony Petroleum Ltd. spudded a well in the Blair area on Jan. 19 at C-55-F-94-B-16 licensed to the Belloy formation. The well has a projected depth of 2,600 metres. — DAILY OIL BULLETIN

B.C. land is drawing more interest. OIL & GAS INQUIRER • March 2010

27


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Northwestern Alberta/Foothills

Orion focuses its $85M capital budget on Kaybob and Redwater

Photo: Joey Podlubny

by James Mahony

Like other classic oilfields in Alberta, Redwater and Kaybob are triggering renewed interest.

Orion Oil & Gas Corp. plans a capital spending program this year of $85 million, primarily directed toward its Kaybob and Redwater properties. The program, which began with a winter drilling program in November 2009, includes the drilling of 17 development wells at Kaybob and 18 development wells at Redwater, with the remainder to be spent on optimization, workover, and facilities programs at Orion’s Kaybob, Redwater, and Bigstone properties. Current production from its properties is approximately 2,650 barrels of oil equivalent (boe) per day with a mix of 55 per cent natural gas and 45 per cent light oil and natural gas liquids. For 2010, Orion expects production to average between 4,050 boe per day and 4,900 boe per day with operating costs of between $10 and $12 per boe. Orion expects to generate approximately $60 million in cash flow in 2010. Beyond 2010,

production plans call for 5,000 to 7,000 boe per day. Once this level is reached, Orion anticipates that significant free cash flow will be available for redirection to other global projects. Orion’s president and CEO is Gary Guidry, who recently served as CEO of Tanganyika Oil Company Ltd. until its acquisition by Sinopec International Petroleum Exploration and Production. In January, Orion Oil & Gas Corp. emerged as a publicly traded firm from a threecornered amalgamation that included privately held Orion Oil & Gas Ltd. In January, Orion’s winter drilling program was reportedly on schedule, w ith si x wells drilled and cased at K ay b ob a nd eig ht at Redwate r i n November and December for a 100 per cent success rate. The combined results of these operations are expected to add 1,760 boe per day to 1,800 boe per day of

production by the end of the first quarter of 2010. The Kaybob property (91 per cent working interest) contains the Swan Hills natural gas condensate field, and represents approximately 80 per cent of Orion’s production and reserve value. The property is completely covered with 3-D seismic and is well delineated. Orion has historically drilled eight wells on its Kaybob property with a 100 per cent success rate and all of these wells are on production. In addition to the development wells at Kaybob, Orion plans to complete one major workover. The new wells are expected to add 200 boe per day to 300 boe per day of production and 500,000 boe of reserves per well. Well costs at Kaybob are estimated at $4 million per well to drill, complete, and tie-in, and all six wells have or are estimated to come in on or under budget. The first well at 5-15-61-19W5 was drilled to 3,320 metres and was put on production Dec. 22, 2009, with a stabilized flow rate of 1.8 million cubic feet per day of raw gas. All six wells are expected to be on production by the end of the first quarter, adding sales of 1,200 to 1,800 boe per day. At Redwater, (100 per cent working interest), Orion has 13 existing wells in the Ellerslie light oil formation with the planned 18 new wells (8 before breakup) expected to add 20 to 25 boe per day of production and 30,000 to 40,000 boe per day of reserves per well. Well costs at Redwater are estimated at $750,000 to drill, complete, and tie-in. Orion is pursuing business development in Colombia, Argentina, and Peru— all areas in which Orion’s management team has significant experience and believes there are excellent opportunities to generate significant growth. — DAILY OIL BULLETIN

NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY

JAN/09

JAN/10

WELL LICENCES

235

251

JAN/09

JAN/10

WELLS SPUDDED

251

304

JAN/09

WELLS DRILLED

251

JAN/10

304

Source: JuneWarren–Nickle’s Energy Group

OIL & GAS INQUIRER • March 2010

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Northeastern Alberta

ConocoPhillips and Total proceed with Surmont SAGD expansion

Photo: Joey Podlubny

by Pat Roche

The proposed Surmont expansion will create an estimated 2,500 jobs on site during construction.

ConocoPhillips Canada and Total S.A. have announced an 83,000-barrel-perday expansion of their 50-50 thermal oil joint venture at Surmont in northeastern Alberta. Work to be done this year will include some Surmont 2 site clearing, ordering some long-lead equipment, and focusing on finalizing the engineering, said Matt Fox, president of ConocoPhillips. ConocoPhillips did not release cost estimates for the project, located 63 kilometres southeast of Fort McMurray. Most of the construction work at Surmont would occur during 2011 through 2014. Fox said roughly 100 steam assisted gravity drainage (SAGD) well pairs will be drilled to achieve annual average output of 83,000 barrels of bitumen a day, which would be reached “a few years” after the project comes on stream. “We expect we will start operations in 2014. And then first production will

be early in 2015 or late 2014,” Fox said on Jan. 19. Direct employment on site will climb to about 2,500 during construction, with more jobs created indirectly in the manufacturing and service sectors in Alberta and elsewhere in Canada. Phase 2 would raise total Surmont production to 110,000 barrels of bitumen a day. No Alberta upgrader is planned. Fox said production will continue to be sold on the open market or shipped to ConocoPhillips refineries in the United States. Fox expects the steam-oil ratio from phases 1 and 2 will level off at around 2.5 to 1. Production from the project’s first phase—which flowed first oil in October 2007—was about 20,000 barrels per day exiting last year, Fox said. Phase 1 design capacity is 27,000 barrels per day, but with normal downtime and maintenance, actual output is expected to average about 23,000 barrels per day. “We anticipate we will be

continuing to ramp up over the next few years,” Fox said of Phase 1 output. Surmont is Houston-based ConocoPhillips’s only operated thermal oil project worldwide. However, the company is also a 50 per cent owner of the Foster Creek/Christina Lake SAGD project operated by Cenovus Energy Inc. In early January, Cenovus said Foster Creek/Christina Lake gross output is about 115,000 barrels of bitumen per day before royalties (50 per cent net to each company). ConocoPhillips hopes to exit oilsands mining. Last fall, it announced it was putting its nine per cent stake in Syncrude Canada Ltd. on the auction block. All the company’s undeveloped bitumen leases would be produced by drilling wells rather than mining. “Surmont is an important part of our oilsands portfolio, and we’re pleased to announce its next phase of development,” said John Carrig, president and COO of ConocoPhillips. “The oilsands are an area of significant future oil production growth and are important for short- and long-term energy and economic security in North America.” The company expects to spend $300 million in heavy oil technology research and development over the next few years to improve economic and environmental performance. “We believe that our oilsands projects—and the conversion of crude oil produced from oilsands to fuel— can be conducted in an environmentally sustainable manner and that technology will play a significant role in managing the environmental footprint,” Carrig said. Yve s-L ou i s Da r r ic a r rère, pre sident of exploration and production for Paris-headquartered Total, said: “The responsible development of Canada’s oilsands—particularly with respect to the environment—will be crucial in providing a secure source of energy for the future. — DAILY OIL BULLETIN

NORTHEASTERN ALBERTA WELL ACTIVITY

JAN/09

JAN/10

WELL LICENCES

172

107

JAN/09

JAN/10

WELLS SPUDDED

103

139

JAN/09

WELLS DRILLED

95

JAN/10

135

Source: JuneWarren–Nickle’s Energy Group

OIL & GAS INQUIRER • March 2010

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Central Alberta

Ron Liepert becomes Alberta’s energy minister in a cabinet shuffle

Photo: Government of Alberta

by Richard Macedo

Alberta Energy Minister Ron Liepert hopes to improve his government’s rapport with the oil industry.

Calgary-West MLA Ron Liepert, after a controversy-ridden stint as health minister, is Alberta’s new energy minister following a cabinet shuffle by Premier Ed Stelmach on Jan. 13. Liepert takes over the portfolio at a critical time. The province is in the middle of an oil and gas competitiveness review after a tumultuous couple of years marked by a new royalty regime and a deep recession. The new minister replaces Mel Knight, who has been shuff led to sustainable resource development after just over three years of handling the energy portfolio. Knight is a former oil and gas services entrepreneur from Grande Prairie, Alberta. Ted Morton, MLA for FoothillsRocky View, is the new finance minister. Industry organizations greeted the appointment of Liepert warmly but maintain that there’s still some heavy lifting to get Alberta back on track competitively

with other jurisdictions. Gary Leach, executive director of the Small Explorers and Producers Association of Canada, said the appointment makes sense due to Liepert representing Calgary, where most of the industry is headquartered. “We believe strong economic policy guiding our provincial energy strategy will help accelerate Alberta’s recovery from this recession,” Leach said in a prepared statement. “The first step to achieving this goal is for government and industry to work together to complete the competitiveness review. “SEPAC made a point of getting to know [Liepert] last year as part of a broader effort to make sure the concerns of our sector were on the table with senior ministers in the [Stelmach] government,” Leach told the Daily Oil Bulletin. “He will be on a steep learning curve, no doubt, but will benefit from the fact that a key piece

of business, namely the competitiveness study, is nearing completion and we look forward to working with him to complete that project.” “I believe he does have a general understanding of the industry issues,” added Roger Soucy, president of the Petroleum Services Association of Canada. “The primary issue he needs to shepherd at the moment is the Competitiveness Review which is coming to a conclusion.” The Canadian Association of Petroleum Producers (CAPP) added that the oil and gas industry competitiveness issue has a profound sense of urgency. “We look forward to seeing this process through with [Liepert],” said CAPP spokesman Travis Davies. In a conference call, Stelmach said the fact that Liepert is based in Calgary should help improve communication with the industry. “The oil and gas industry, especially on the natural gas side, is going through significant structural changes,” the premier said. “We have to move the industry towards unconventional gas, shale gas. It requires new investment. We are partners, we are really partners with the industry. We own the resource, but they are the ones who put up all of the critical dollars and those dollars, of course, are at risk unless you have a very good competitiveness position as a province.” Many industry executives have commented in private that the Competitiveness Review has been conducted by personnel who appear to grasp the realities of the energy sector. Danielle Smith, the leader of the upstart Wildrose Alliance, said Stelmach’s cabinet changes will not make a difference. “You can change the faces of the deck crew, but Albertans will only see real change when the Wildrose Alliance replaces this tired, rudderless government,” she said. — DAILY OIL BULLETIN

CENTRAL ALBERTA WELL ACTIVITY

JAN/09

JAN/10

WELL LICENCES

177

214

JAN/09

JAN/10

WELLS SPUDDED

192

271

JAN/09

JAN/10

WELLS DRILLED

192

251

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • March 2010

33


Central Alberta

NAL’s $175M capital budget has a strong focus on Cardium oil play NAL Oil & Gas Trust plans a $175-million capital program this year and expects to drill 137 (67 net) wells, the most in its 14-year history. The 2010 program is focused 80 per cent on Cardium formation oil development opportunities in Alberta and Mississippian oil projects in Saskatchewan, with some capital committed to strategic natural gas drilling in Alberta and British Columbia. “The trust plans to maintain its leadership position in the Cardium oil resource play in central Alberta, continue ongoing activity in the attractive Mississippian oil portfolio in southeast Saskatchewan, and invest in strategic gas opportunities on the trust’s expanded land portfolio,” NAL stated in a media release on Jan. 21. In 2010, the trust is budgeting $140 million for drilling, completions, and tie-ins, $7 million for recompletions, $8 million for plants and facilities, and $10 million for land and seismic. Another $10 million is set aside for other items. The capital figure is $10 million in Alberta drilling credits. Last year, the trust’s capital budget was $130 million, although its final spending

figures for 2009 haven’t been released. In 2010, NAL plans to spend about 35 per cent of its capital budget in the first quarter. Highlights of the 2010 program include: * Cardium formation oil projects in central Alberta will continue to be a focus at NAL’s existing Garrington/Westward Ho core area as well as delineating trend acreage to the south at Lochend (Cochrane) and to the north at Pine Creek. * In Saskatchewan, a large inventory of conventional oil prospects on existing lands

The 2010 capital program is forecast to deliver production volumes averaging between 29,500 and 30,500 barrels of oil equivalent (boe) per day. coupled with new opportunities added in 2009 will lead to drilling 61 (30 net) horizontal wells. These wells are expected to add production and continue to delineate several existing Mississippian trends, adding new locations to future inventory.

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Central Alberta

and utilities primarily in Saskatchewan. Operating costs are projected to fall between $11 and $11.50 per boe. NAL said it will operate more than 90 per cent of its capital spending in 2010 and is not facing material land expiries. This provides significant flexibility for adjusting the timing and scale of the program in response to commodity prices and market conditions. As in 2009, NAL said its balance sheet strength and access to capital markets position the trust to take advantage of value-adding acquisition opportunities. Subject to final bank documentation being completed, the trust’s credit facility is expected to be increased to $550 million from $450 million as a result of the Breaker Energy Ltd. acquisition, which closed on Dec. 11, 2009. The trust’s management said it continues to assess alternatives for conversion to a corporation and reiterates that the company plans to maintain a yieldoriented business model after conversion. Conversion is expected to occur in late 2010 or early 2011 to maximize the tax shield for the trust model and protect its $1.2 billion of available tax pools. — DAILY OIL BULLETIN

Midway encouraged by Cardium drilling results at Garrington Midway Energy Ltd. says it is “extremely pleased” with the initial results of its Cardium horizontal drilling program at Garrington, south of Red Deer. The company drilled three (2.7 net) operated Cardium horizontal wells in the fourth quarter of 2009 and participated in the drilling of one (22.5 per cent working interest) non-operated Cardium horizontal well. Two of the operated wells were fractured in the fourth quarter of 2009 and the third was fraced in the first week of January 2010. All three wells reportedly showed similar reservoir characteristics and frac responses. The non-operated well is expected to be fraced mid-January. Midway said all three of the operated wells have now been completed at an average cost of $1.15 million gross per well. Each of the three wells has been completed using different multi-stage frac completion methods. Midway believes that completion methods will become the biggest area of achieving efficiencies in the future. The first well has produced back the frac fluid and is producing formation oil (restricted

by pumpjack capacity) at an average rate of 300 barrels of oil equivalent per day for its first week of production. The well was drilled on an existing surface lease and tied into the company owned gathering system and production facility. The second well has also been equipped and tied into Midway’s gathering system and is currently recovering frac fluid at a production rate similar to the first well. Upon producing out its frac fluid, the well will be shut in for bottomhole pressure data. This well was expected to be producing formation oil by the last week of January. The third Cardium well was fraced in early January and is currently flowing back its frac fluid. The well is showing similar production characteristics as the first two wells and it is expected that this well will be on production by the end of January after producing back its frac fluid. Midway intends to drill an additional three Cardium horizontal wells in the first quarter of 2010. — DAILY OIL BULLETIN

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Southern Alberta

Some oilfield service companies see stronger prices on the horizon

Photo: Joey Podlubny

by Elsie Ross

Some managers report that oil and gas service prices have bottomed out and started to rise gradually.

The worst of the downturn in oil and gas activity appears to be over, according to some service companies. “We just put a $500 [per day] increase across all rigs in the Rockies and we have been starting to move the price a little bit as the demand has been increasing,” Bob Geddes, president and COO of Ensign Energy Services, said on Jan. 12. Geddes was addressing the BMO Capital Markets North American unconventional resources conference in New York. Ensign has 30 proprietary automated drilling rigs (ADRs) in the Rockies. “We saw pricing kind of trough in Q2, saw stability coming in though Q3, and probably are seeing some recovery in Q4 and heading into Q1,” said Tom Medvedic, senior VP of corporate development for Calfrac Well Services. However, Calfrac, primarily a pressurepumping company, thinks it likely will be

mid-year before it sees significant price increases, Medvedic said. While Calfrac is currently extremely busy, it has locked in arrangements with its core customers for the next couple of quarters. When it comes to recontracting rigs, Ensign has been able to hold rates on its ADRs “reasonably well,” although they are down a bit from new construction contracts, said Geddes. Ensign has constructed 70 of the rigs, which require two fewer workers and offer greater efficiency and safety, according to the company. “There is no question…that efficiency is well rewarded and does create real value so I think we will get back to those rates,” Geddes said. “Certainly, we are at those numbers on new discussions we are having currently with customers on new rigs through 2010.” While Ensign has operators who would like to sign three- and five-year contracts, right now

the company is taking only six-month and one-year contracts on the ADRs. The companies indicated little interest in expanding their fleets with acquisitions at fire-sale prices. “We are more concerned about the type of rig,” said Geddes. “We have the ability to purchase and/or build rigs, so we are a lot pickier at what we are looking at these days because the value model has changed.” Christopher Strong, CEO of Union Drilling Inc., agreed that “we are probably at the bottom” in terms of pricing. His Texas-based firm is active in the Marcellus shale play in Pennsylvania, concurred. “There are a lot of distressed companies out there, and one would think this would be a good time to acquire distressed assets, but we have spent a good amount of time looking at different fleets…and there’s not a lot out there that is really attractive for the plays that have the most demand,” he said. “A lot of what’s for sale is that last hired, first fired type of equipment and that’s why it’s distressed.” Last summer, Calfrac closed two separate transactions, one in Canada and one in the United States, said Medvedic. “We were satisfied with the opportunity at that point in time, but don’t expect there is going to be a whole lot more opportunity in Canada,” he said, noting that approximately 85 per cent of the capacity in western Canada is held by five service companies. There has been a major change in rig technology in the last three or four years, with features such as top drives, automated handling, and self-moving pad rigs, and there will be little demand for olderstyle rigs, Geddes predicted. “There’s no question that box-on-box style 1,000- to 1,500-horsepower rigs are going to die,” he commented. — DAILY OIL BULLETIN

SOUTHERN ALBERTA WELL ACTIVITY

JAN/09

JAN/10

WELL LICENCES

349

242

JAN/09

JAN/10

WELLS SPUDDED

529

303

JAN/09

JAN/10

WELLS DRILLED

524

297

Source: JuneWarren–Nickle’s Energy Group

OIL & GAS INQUIRER • March 2010

37


Southern Alberta

PSAC raises its 2010 drilling forecast by 1,000 wells In its first update to its 2010 drilling forecast, the Petroleum Ser vices Association of Canada (PSAC) is forecasting a new total of 9,000 wells drilled (rig released) across Canada for 2010. That figure represents an increase of 1,000 wells (12 per cent) from the association’s original 2010 forecast, released in early November 2009. On a provincial basis for 2010, PSAC estimates 6,095 wells will be drilled in Alberta, an increase of four per cent over final 2009 drilling levels. All of the 1,000 wells added to this year’s forecast are attributed to Alberta, where activity was originally expected to be flat compared to 2009. PSAC expects British Columbia to have 630 wells drilled in 2010, an increase of 10 per cent from last year. Saskatchewan’s drilling rate in 2010 will see an 11 per cent increase over 2009 to 1,935 wells, while drilling in Manitoba will increase 29 per cent to 300 wells. I n t he l a s t we e k of Ja nu a r y, JuneWarren-Nickle’s Energy Group’s Rig Locator publication showed nearly 70 per cent of the Canadian fleet active. While the

rig count was higher throughout January, the increased peaked in the final week with 558 units at work, 92 more than in the final week of January in 2009. On Jan. 26, the Rig Locator found 378 units active in Alberta, 91 working in British Columbia, 74 in Saskatchewan,

per thousand cubic feet (AECO) and crude oil prices of US$74 per barrel for West Texas Intermediate. “Industry is expecting commodity prices to strengthen further this year,” said Roger Soucy, president of PSAC. “Improved prices led to a spurt in drilling

“Improved prices led to a spurt in drilling activity in December 2009, and we expect stronger pricing to continue to impact drilling levels as we move through 2010.” – Roger Soucy, President, PSAC

13 in Manitoba, and 2 in northern Canada. That compares to 303 active in Alberta, 109 in British Columbia, 46 in Saskatchewan, 7 in Manitoba, and 1 in northern Canada in the final week of January 2008. T he 1,000 -well increase for t he 2010 forecast is primarily the result of strengthening prices for both crude oil and natural gas, the association said. PSAC is basing its updated 2010 forecast on average natural gas prices of C$5.50

activity in December 2009, and we expect stronger pricing to continue to impact drilling levels as we move through 2010.” The final tally for 2009 was 8,450 wells drilled across Canada. “We are cautiously optimistic about 2010,” Soucy said. “The commodity pricing signals have been positive so far, but this may not be the quick and complete turnaround everyone is hoping for. The real test will come after spring breakup.” — DAILY OIL BULLETIN

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Southern Alberta

EnCana missing bolt does not justify harsh enforcement action, ERCB rules by Elsie Ross The Energy Resources Conservation Board (ERCB) has upheld an appeal by EnCana Corporation rescinding the High-Risk Enforcement Action 1 taken by board staff. The EnCana case involved a disagreement in interpretation between the company and ERCB staff over a missing bolt on a fire-tube inlet flange. In the appeal decision issued in mid-January, the board ruled that the issuance of an enforcement action was “not appropriate” and suggested that discretion be used in assessing the adequacy of the equipment in sim i la r situations. Board staff determined during an inspection March 4, 2009, at an EnCana gas facility at 6-1874-6W6 (near Sexsmith in northwestern Alberta) that a flame arrester did not comply with the requirements and procedures for facilities because it was missing

a bolt and was less than 25 metres from a process vessel. After unsuccessful appeals to both E RCB sta f f a nd t he boa rd’s Enforcement Advisor, EnCana appealed to the board on the grounds that the regulations referred to in the enforcement letter did not support taking enforcement action in this circumstance and the applied risk level was out of proportion to the actual risk. EnCana argued that the regulation cited is inadequate and inappropriate to support enforcement of a missing bolt on a fire-tube inlet flange. The flame-type equipment at issue was equipped with an adequate/workable flame arrester with all bolts in place, was not saturated with oil, appeared to be properly fitted and had a gasket in place, it said. The missing bolt was not associated with the flame arrester

itself, but is one of many components of the overall piece of equipment in question, according to EnCana. It is common knowledge that a flame arrester is typically cylindrical in shape and generally finely packed with corrugated metal too narrow for the passage of flame, the company added. The highrisk rating is based on an inadequate flame arrester but has been inappropriately applied to a different component of the flame-type equipment, and there is no mechanism within the regulations to adjust the risk level or apply any discretion, said the company. To clearly establish the actual risk (which it believed was low), EnCana engaged a third-party engineering firm (DPH Focus), which determined that on this particular f lange design, an adequate seal would still be provided even if every second bolt (six bolts in total) were missing. It concluded there is a low risk of leakage as the result of a missing

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39


Southern Alberta

bolt. The operations VP of the manufacturer, Gas and Oil Production Equipment Ltd., also was of the view the missing bolt did not present a safety hazard, according to EnCana. In their response, ERCB staff said that in their interpretation of the regulations an “adequate” flame arrester has all of the nuts, bolts, and gaskets designed by the manufacturer. The portion of the flametype equipment from which the bolt is missing is an integral part of the unit as a whole and ERCB requirements explicitly state that operators must ensure that flame arresters have all bolts, they said. “The ERCB cannot reasonably be expected to test flame arresters that are missing bolts to determine their continued workability or level of safety risk before issuing an enforcement action,” said ERCB staff. “Such an approach is unworkable on a provincial basis, would inevitably lead to inconsistent enforcement processes, and [would] compromise public safety.”

The risk category assigned to a given deficiency is predetermined, and field staff have no discretion other than to issue the enforcement action prescribed if the facts show that the substantive requirement has not been met, they added. EnCana’s interpretation was that the fire-tube inlet flange is not part of the flame arrester and even if the ERCB found that it were, the flame arrester in question was adequate as supported by the third-party engineering assessment and the expert opinion of the equipment manufacturer. The company contended the regulation and its associate risk level were improperly and rigidly applied to a component other than what is commonly accepted as a flame arrester. In granting the appeal, the board found that the issuance of the enforcement action was not appropriate and suggested that discretion be used in addressing the adequacy of the equipment in similar circumstances.

In its decision, the board said it is not persuaded by the evidence before it that the flame arrester at issue was not in an adequate or workable state at the time of inspection. “In fact, the staff arguments focused not on the inadequacy of the flame arrester due to the missing bolt, but rather on the stated inspection parameters in the directive and the reasonableness and efficiency of inspecting and enforcing in this manner,” it said. “The board is concerned with such an approach.” The primary goal of the ERCB’s inspection and compliance and assurance program is to ensure that requirements are met with a focus on ensuring public safety in doing so, said the board. In this situation, the primary focus should be to ensure that the matter is remedied by an operator willing to do so as soon as possible. The board noted that the decision of the enforcement advisor said the operator took corrective action at the time of the inspection by replacing the missing bolt. — DAILY OIL BULLETIN

Ember ramps up its coalbed methane program at Acme Ember Resources Inc. says it has entered into agreements that will significantly expand drilling and production activities in its core area of Acme, Alberta. Coalbed methane (CBM) drilling at Acme, operated by Ember, could exceed 140 gross wells over the next two years, the company said in mid-January. Production from the area is expected to grow to 20 million cubic feet (MMcf) per day (11 MMcf per day net to Ember) from 7 MMcf per day (4.5 MMcf per day net), the company said. Ember and a major industry partner have pooled their interests in 12 sections of land in the Acme area, with Ember taking a 25 per cent stake. The pooled lands are on the Horseshoe Canyon CBM trend and include rights to the base of the Belly River sands. Ember will operate all drilling and production operations. Production will be processed through facilities currently contracted by Ember and located at the Acme property. With the addition of these pooled lands, Ember has increased its inventory of locations in the area to 260 gross (75 net) locations. Under the first phase of the agreement, Ember has committed to drilling 70 gross wells. In the second phase, Ember 40

March 2010 • OIL & GAS INQUIRER

will commit to drilling an additional 70 gross wells. By the end of the first quarter, Ember will have drilled 35 wells under the agreement. The balance of the first 70-well commitment is expected to be completed prior to the end of the year. During the fourth quarter of 2009, Ember drilled 28 wells (20.5 net), all of which were cased as successful Horseshoe

The fourth quarter of 2009 and first quarter of 2010 drilling programs are expected to grow Ember’s production from an average of 23.5 MMcf per day in the final quarter of last year to an average of 25 MMcf per day in the current quarter. “We have been aggressively manag i ng our busi ness i n t he low gas pr ice env i ron ment by f i ndi ng new

"We have de-levered the balance sheet, expanded opportunities in a key area, and driven down our cost structure.” – Doug Dafoe, president and CEO, Ember Resources Inc.

Canyon CBM wells. Twenty wells (12.5 net) were drilled at Acme and eight (eight net) in the Bashaw area. To date, 16 of the wells (12.2 net) have been placed on production and the remainder should be onstream by the end of January. In first quarter 2010, Ember said it is planning to drill 30 wells (17.4 net), all expected to be on stream prior to the end of March. Fifteen wells (4.9 net) are planned for Acme and 15 wells (12.5 net) are planned in the Bashaw area.

opportunities to strengthen our operations and our financial position. We have de-levered the balance sheet, expanded opportunities in a key area, and driven down our cost structure,” said Doug Dafoe, president and CEO. “2010 has started on a positive note with natural gas prices. If that trend continues, our Horseshoe Canyon resource play and extensive drilling inventory are ready to resume our historical growth profile.” — DAILY OIL BULLETIN


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Saskatchewan

PetroBakken will apply its Sask. expertise to Alberta Cardium by Paul Wells

JAN/09

JAN/10

JAN/09

JAN/10

WELLS SPUDDED

222

236

WELLS DRILLED

216

226

Photo: Joey Podlubny

reservoir rock that often lacks permeability. Exploitation of these resources has only become economically possible in the last few years through the development of costefficient multi-stage reservoir fracturing along horizontal well bores. Despite its Cardium ambitions, the PetroBakken CEO says the majority of his Calgary-based firm’s 2010 program will be focused on drilling 141 (128 net) wells in the Bakken resource play, supplemented by a further 121 (88 net) wells in its conventional light oil plays in southeastern Saskatchewan and Manitoba. “Result has assembled a premier position in the Cardium light oil resource play through an aggressive strateg y of land sale purchases, acquisitions, and farm-in opportunities,” said Brett Herman, Result’s president and CEO. “The Cardium play holds tremendous potential, and we believe PetroBakken

provides our shareholders with an excellent vehicle for its development, as PetroBakken will use its access to capital, economies of scale, and technical experience to accelerate the development of this significant resource play.” After PetroBakken’s acquisitions of Result and Berens are in the books, the company will have access to over 225 gross (150 net) sections of land that are prospective for the Cardium exploitation. Its drilling inventory will then reportedly include over 400 net potential Cardium locations with the expectation of a higher figure through further evaluation of the lands. The management teams of Result and PetroBakken have been merger-andacquisition dance partners previously. In August 2009, PetroBakken itself was formed when Petrobank Energy and Resources Ltd. and TriStar Oil and Gas Ltd. agreed to merge certain assets. The new entity became the dominant player in southeastern Saskatchewan’s prolific Bakken light oil play. Following that deal, the former TriStar management team took the reins of Calgary-based Result and quickly made a number of moves that positioned the junior producer as a player of note in the emerging Cardium trend. Among Result’s quick moves was the acquisition of Nexstar Energy and its stable of Cardium assets. Result had a 2009 exit production of more than 750 barrels of oil equivalent (boe) per day. Its proved-plus-probable reserves totalled more than 2.9 million boe. Drilling on Result lands has recently commenced with plans to drill 10 (8 net) Cardium horizontal wells in the first quarter of 2010. Based on field receipts for December, Berens currently has estimated production of 3,650 boe per day (78 per cent gas). — DAILY OIL BULLETIN

PetroBakken plans to drill 141 wells (128 net) in the southeastern Saskatchewan Bakken play in 2010.

In January, PetroBakken Energy Ltd. acquired two junior producers for $816 million, with the intention of applying lessons learned in southeastern Saskatchewan’s Bakken formation to Alberta’s tight-oil Cardium formation. “Why the Cardium play? It looks a lot like the Bakken but only thicker,” said Greg Smith, PetroBakken’s president and CEO. On Jan. 28, his company announced the acquisition of Result Energy Inc. in a $480-million stock and cash deal. In early January, PetroBakken purchased another junior player, Berens Energy Ltd., in a deal valued at approximately $336 million. “We’ve drilled over 500 horizontal and multi-stage fracs [in the Saskatchewan Bakken] and we’re very competent at bringing that technology to most plays in western Canada,” Smith said. The Bakken and Cardium geological formations both consist of oil-soaked SASKATCHEWAN WELL ACTIVITY

JAN/09

JAN /10

WELL LICENCES

144

271

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • March 2010

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Central Canada

Environmental policies that damage the West hurt all of Canada

Photo: Joey Podlubny

by Pat Roche

The oilsands carries a big chunk of the national economy, according to the Canada West Foundation.

Climate change policies that hurt western Canada’s oil and gas industry would also do widespread damage to the national economy, says a Canada West Foundation study. “Debate about how to reduce Canada’s greenhouse gas emissions has led some to argue that Canada’s oil and gas industry needs to be reined in or even shut down,” warns the 20-page report released on Jan. 28. “This position is often accompanied by one or more dubious claims: the economic consequences will be minimal, the economic pain will be contained within western Canada, and green investment and jobs will fill in the void left by a smaller oil and gas industry,” says the report. The report—titled “Look Before You Leap”—isn’t suggesting environmental goals be abandoned, but stresses the need to understand the full ramifications of measures that hurt western’s Canada’s hydrocarbon industry because the impact will extend into other regions and other industries across the country. “Our concern was some of the stories and commentary coming out—particularly on the oilsands—sort of assumes that

if the industry is damaged, that damage is confined to Alberta,” commented Roger Gibbins, president of the Canada West Foundation. “However, the point we want to stress is that the strength of the western Canadian economy plays a significant role in supporting federal programming that

The report says oil and gas generates much more employment than the 130,000 jobs created directly within the industry.

benefits Canadians living elsewhere in the country,” the report says. Western Canada’s share of the national gross domestic product—the value of all goods and services produce—has already surpassed Ontario’s. “And if the manufacturing base in Ontario continues to feel the pinch from a high Canadian dollar and

growing global competition in the years ahead, then the contribution of western Canada will become even more important as Ontario’s historical role as the fiscal linchpin in Confederation becomes difficult to sustain.” When it comes to climate policy, the oil and gas industry—and the oilsands in particular—has a big target on its back, the report says. “However, because the industry is a key driver of the western Canadian economy, which, in turn, is a key driver of the national economy, we should be wary of undermining its ability to play this role.” The report says it’s safe to assume the number is much greater than the 130,000 direct jobs generated in oil and gas work. It would include accountants who do most of their work for small oilpatch clients, steel mills in Ontario supplying oilsands projects, and teachers and nurses in northern Alberta who likely wouldn’t be employed without hydrocarbon activity in the area. Capital spending in oil and gas exploration, extraction, and refining totalled $53.4 billion—31.3 per cent of total investment in western Canada— in 2007. Nat ural resource revenue accounted for 32.3 per cent of the Alberta government’s revenue in 2006–07, 19.3 per cent of Saskatchewan’s revenue and 11.3 per cent of British Columbia’s. The report also cites more intangible benefits such as the fact that the mutual funds in most people’s RRSPs likely include oil and gas stocks. And it acknowledges that many thousands of central and Atlantic Canadians have found jobs in western Canada. Resource revenue also underpins the federal equalization program, which cost Ottawa $14.2 billion in payments to six provinces in fiscal 2009–10. During the fiscal year ending this March 31, Alberta, British Columbia, and Saskatchewan receive no equalization payments. Ontario gets $347 million, or $27 per capita, while Québec gets $8.36 billion, or $1,067 per capita, the report says. — DAILY OIL BULLETIN OIL & GAS INQUIRER • March 2010

45


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International

Photo: Xtreme Coil Drilling Corp.

Three Canadian energy service companies land overseas contracts

Xtreme Coil, already working in Mexico (shown above), has now gained a toehold in the Middle East.

Trican Well Service Ltd. reports that its Russian initiative is doing well, Wavefront Technology Solutions Inc. says Pemex (Mexico’s state-owned oil monopoly) has decided to expand its use of the company’s Powerwave well stimulation technology, and Xtreme Coil Drilling Corp. has won a toehold in the Middler Eastern market. In 2010, Trican says it will be working for 7 of Russia’s top 10 oil companies and its two largest gas companies, servicing these contracts from its 9 operating bases in Russia and Kazakhstan. Based on the scope of work awarded, management expects that 2010 activity levels will exceed those of 2009 by approximately 10 to 15 per cent. The company said it has been successful in winning work in the majority of the tenders in which it participated. Overall, pricing in the tender awards has modestly improved relative to 2009 pricing. Based on current contract awards, management expects high fracturing utilization for existing equipment. New equipment added from the 2010 capital program will also allow the company to pursue additional work throughout the year. Management also anticipates almost full utilization of its

coiled tubing fleets, including the sixth unit, which is expected to be in service during the second quarter of 2010. Cementing capacity continues to be underutilized, but the company is still awaiting confirmation regarding the award of tenders submitted for some large cement projects. Wavefront says the Activo Integral Poza Rica-Altamira (an oil production asset of Pemex) will undertake five single well stimulations using its Powerwave waterflood pulsing technology, beginning this winter. The approval for the well stimulations follows the non-binding letter of intent signed in October 2009. The stimulations represent the continuation of an extensive Powerwave undertaking with Pemex. “This is a very important step in the continuation of the relationship between Wavefront and Pemex,” Brett Davidson, Wavefront’s president and CEO. “Pemex has indicated to Wavefront that its longer term intent is to use Powerwave in the Chicontepec field to help Pemex recover reserves that would otherwise remain unrecoverable. We see this as a significant vote of confidence in the performance of Powerwave.”

Pemex has estimated that about seven per cent or 18 billion barrels of the 139 billion barrels of original oil in place in the Chicontepec field is recoverable under current technology. Wavefront also reported that the first of four Powerwave single well stimulations announced in December 2009 for the Samaria-Luna oil production asset of Pemex was successfully completed. Production results related to the stimulation work are pending. The remaining Powerwave stimulation work is imminent. Xtreme announced its entry into the Middle Eastern drilling market after receipt of two letters of intent from a major diversified oilfield services company. Under terms of the letters, Xtreme Coil will agree to provide two newly designed Coil Over Top Drive XTC 200DTRPLUS drilling rigs customized for re-entry drilling projects in the Middle East. Xtreme Coil completed the first of the two customizations and, subsequently, mobilized the first rig to the Middle East. The second rig was recently moved to Texas to undergo similar customization, which the company expects to complete within approximately three months. The customer will be responsible for mobilization expenses for both rigs. Once executed, the long-term contracts related to the letters of intent are expected to require Xtreme Coil’s drilling rigs for two years and to include options for oneyear extensions for each rig. The rigs will perform ultra-deep coiled tubing re-entry drilling using Xtreme Coil’s patent-pending XTC 200DTRPLUS rig design. The first rig is expected to commence operations in the first quarter and the second rig during second quarter of this year. In connection with this new business, Xtreme Coil expects to create joint-venture companies for the Middle East and North Africa in which its wholly owned subsidiary, Xtreme (Luxembourg) S.A., will hold an 80 per cent interest. The new joint ventures may be used to provide certain Xtreme Coil contract drilling services and products in a number of international regions. — DAILY OIL BULLETIN OIL & GAS INQUIRER • March 2010

47


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5


On the Job

onthe

JOB

Don Montgomery

Careers in the Oilpatch

What are business conditions like in the central Alberta oilpatch? For the past year, a great deal of my work has been insolvencies, mainly welding and fabrication companies. In December, I handled an oilfield instrumentation shop in Drayton Valley, another insolvency. The more specialized big oilfield equipment, like drilling rigs, goes to the large auction outfits like Ritchie Brothers and Kruse. We handle backhoes, crawlers, scrapers, trucks, and so on. You read that the economy is getting better, but I feel that is yet to be seen. What drew you to auctioneering? As a boy, I enjoyed livestock auctions. My parents ranched near Cremona [northwest of Calgary] and my heart is still in agriculture. After high school, I apprenticed as a partsman journeyman, spending 17 years with a Ford dealer in Red Deer, including 13 years wholesaling on the road. A partsman’s skills— cataloguing, sourcing, evaluations, selling, and so on—are exactly what’s needed to run an auction business. How did you get your auction training? The Western College of Auctioneering in Billings, Montana, covered the basics well:

Age: 53 Training: Owner Company: Montgomery Auction Services Ltd Location: Blackfalds, Alberta Education: Journeyman partsman, accredited auctioneer—Western College of Auctioneering, certified personal property appraiser

bid calling, how to breathe, voice projection, and memory, along with handling merchandise from real estate to equipment. I started

of Alberta. Reputation and integrity are more

said earlier, advertising is key, along with real-

Montgomery Auction Services in 1988 work-

important than the amount of commission you

istic expectations for your equipment.

ing it part-time for two years. At the time,

are being charged. Advertising to the right

automotive electronics and technology was

buyers is key. It’s true that a multinational auc-

Where are auctions headed in the future?

getting big and many older mechanics chose

tion company may attract more potential cus-

It’s not a big thing for our company, but online

to retire rather than learn the new technology.

tomers but will not necessarily translate into

auctions will continue to grow as a percentage

Auctioning off the assets of my former cus-

more money for your equipment. Buyers tend

of the industry. An “online internet-only” auc-

tomers helped me get started. Today we are

to pay less money for a piece of equipment if

tion normally means the buyer pick will up the

one of central Alberta’s leading multi-facet

multiples of the same equipment is also on

item from the consignor, which saves trans-

auction companies.

the block to choose from. Bidding reaches top

portation, set up, and the need for an auction

dollar more often if there’s only one item avail-

yard. It’s cost-efficient. Still, there will always

What advice would you give to someone

able. Also, be careful about minimum price

be live auctions. People like to see the mer-

with equipment to sell?

guarantees or selling outright to the auction

chandise and meet each other. It’s a wonderful

Shop carefully for your auction company, and

company. They are going to leave plenty of

business full of variety—I look forward going

use a member of the Auctioneers Association

margin for error or selling price shortfalls. As I

to work each day. OIL & GAS INQUIRER • March 2010

49


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#1 directory for the who OIL & GAS PRODUCERS, EXPLORERS & DEVELOPERS SERVICE & SUPPLY COMPANIES

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CONSULTANTS – ENGINEERING, GEOLOGICAL & GEOPHYSICAL

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CONSULTING SERVICES

225

DATA PROCESSORS/SOFTWARE DEVELOPERS

233

ENGINEERS, PIPELINE CONTRACTORS, DESIGNERS, CONSTRUCTION & FABRICATORS

247

ENVIRONMENTAL SERVICES

259

FINANCIAL & INVESTMENT

267

GEOPHYSICAL DATA BROKERS & CONTRACTORS

271

LEASE BROKERS & LAND AGENTS

277

MANUFACTURERS

299

OILWELL DRILLING CONTRACTORS

311

OILWELL SERVICING

329

PIPELINE COMPANIES & POWER DISTRIBUTORS

335

PETROCHEMICAL PRODUCERS – REFINERS, PROCESSORS, MARKETERS & PLANT OPERATORS

339

TRANSPORTATION AND OILFIELD CONSTRUCTION COMPANIES

355

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Tools of the Trade

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Who is Enventure Global Technology, LLC?

Remediation with expandables is a reliable, one-time solution for parted con-

Enventure Global Technology, LLC is the world’s leading provider of solid

nections, corroded casing, and shutting off unwanted perforations. However,

expandable technology solutions for the energy industry. Enventure was

we are constantly innovating how expandable technology is used to benefit

established in 1998 after proof-of-concept tests demonstrated the feasibil-

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ity of expanding oil country tubulars. We lead the industry in experience with

From saving a multi-million-dollar exploratory well with a record 6,935-foot

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liner, to remediating watered-out perforations in a 40-year-old well with a

ability of 97 per cent. What is SET technology? SET solid expandable solutions involve the controlled expansion of solid steel tubulars in the downhole environment for enhanced drilling, production, completion, and remedial operations. SET technology utilizes a cold-working process that permanently deforms expandable casing. SET pipe, called EX-80, meets standards beyond those specified by the American Petroleum Institute (API) for oil and gas well use, but with pre-expansion properties similar to those of API L-80 material. Enventure’s expandable systems utilize a solid cone to expand the casing from the bottom up. What are the competitive advantages of SET technology?

30-foot string—our expandable technology creates value-based solutions. Do you have future development plans for this product? New, high-temperature systems are giving operators who are developing steam assisted gravity drainage wells the option to repair casing with minimal loss of ID. High-performance SET technology is increasing the collapse and yield ratings of expandable systems, providing additional drilling and remediation solutions. In unconventional plays, expandable systems are beginning to offer new ways of completing multi-zone fracturing designs and increasing assurance of successful fractures. These are just a few samples of how expandables are continuing to evolve to serve the oil and gas industry and help operators maximize the value of their assets.

When SET systems are expanded downhole, Enventure’s solutions ensure maximum internal diameter (ID). In drilling operations, this translates to additional casing design options, reassurance of reaching total depth with the required completion size, and reductions in overall non-productive time.

Answered by Kevin Waddell, VP, Technology & Marketing for Enventure Global Technology, LLC

OIL & GAS INQUIRER • March 2010

51


Political Cartoon

Advertisers' Index 1174365 Alberta Ltd . . . . . . . . . . . . . . . . . . . . . . 42

Cover-All Alberta . . . . . . . . . . . . . . . . . . . . . . . . . 5

OilPro Oilfield Production Equipment Ltd . . . . 44

Abacus Datagraphics Ltd . . . . RD Inside Front Cover

Crompton Western Canada Inc . . . . . . . . . . . . . 44

Opsco Energy Industries Ltd . . . . . . . . . . . . . . . 17

AGI-Envirotank . . . . . . . . . . . . . . . . . . . . . . . . . . 5

DFI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 & RD12

Pembina Controls Inc . . . . . . . . . . . . . . . . . . . . . 28

All Weather Shelters Inc . . . . . . . . . . . . . . . . . . . 15

Diversified Glycol Services Inc . . . . . . . . . . . . . . 41

Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Annugas Compression Consulting Ltd

dmg world media . . . . . . . . . . . . . . . . . . . . . . . . 46

Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . 32

. . . . . . . . . . . . . . . . . . . . . . . . Outside Back Cover

Ecoquip Artificial Lift Ltd . . . . . . . . . . . . . . . . . . 16

Platinum Energy Services Corp

ATB Financial . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Edmonton Exchanger & Manufacturing Ltd . . . 23

. . . . . . . . . . . . . . . . . . . . . . . . . Inside Front Cover

BC Resources Expo . . . . . . . . . . . . . . . . . . . . . . 28

Falvo Electrical Supply Ltd . . . . . . . . . . . . . . . . 36

Propak Systems Ltd . . . . . . . . . . . . . . . . . . . . . . 3

Bear Slashing Ltd . . . . . . . . . . . . . . . . . . . . . . . . 30

Flexpipe Systems . . . . . . . . . . . . . . . . . . . 38 & 39

Prostate Cancer Canada Network . . . . . . . . . . 46

Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . 50

ISA Edmonton . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Pumps & Pressure Inc . . . . . . . . . . . . . . . . . . . . 34

Bidell Equipment LP . . . . . . . . . . . . . . . . . . . . . . 32

ITT Water & Wastewater . . . . . . . . . . . . . . . . . . 41

Radafab Oilfield & Industrial Supply Inc . . . . . . . 11

Bilton Welding and Manufacturing Ltd . . . . . . . 50

Joule Technical Sales Inc . . . . . . . . . . . . . . . . . . 44

Stealth Oilfield Inspections Ltd . . . . . . . . . . . RD6

CADE/CAODC Drilling Conference . . . . . . . . . . 42

LJ Welding & Machine . . . . . . . . . . . . . . . . . . RD10

Suncor Energy Inc . . . . . . . . . . . . . . . . . . . . . . . 48

Canadian Enviro-Tub Inc . . . . . . . . . . . . . . . . . . . 10

LoTech Manufacturing Inc . . . . . . . . . . . . . . . . . 36

Systech Instrumentation Inc . . . . . . . . . . . . . . . 30

Canadian Standards Association . . . . . . . . . RD11

MaXfield Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

TARM Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

CARES Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . 36

TCA Marketing Ltd . . . . . . . . . . . . . . . . . . . . . . . . 7

Compass Bending Ltd . . . . . . . . . . . . . . . . . . . . 50

Northstar Energy Services Inc . . . . . . . . . . . . . . 4

Trans Peace Construction (1987) Ltd . . . . . . . . . 28

Contain Enviro Services Ltd . . . Inside Back Cover

Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . 32

ZCL Composites Inc . . . . . . . . . . . . . . . . . . . . . . . 5

52

March 2010 • OIL & GAS INQUIRER


Oil & Gas Inquirer - March 2010  

Cardium Rush - Penn West CEO Bill Andrew outlines a vast new tight oil play in central Alberta

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