Oil & Gas Inquirer - December 2010

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Technology

page 13

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F E A T U R E

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eatherford International Ltd. W in collaboration with Suncor Energy Inc.:

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BBJ Tools Inc.:

Pr od

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MicroSeismic, Inc.:

ing Technology

6

DECEMBER 2010 • OIL & GAS INQUIRER

FracStar and Buried Array monitoring systems

Multiphase Performance Drilling system

Revolutionary fluid hammer

20

Baker Hughes Inc.:

22

Can-K Group of Companies:

24

Suncor Energy Inc.:

st D r il l

JuneWarren-Nickle’s Energy Group, working with expert judges, awards Technology Stars for six innovative oil and gas products in four categories — Exploration, Drilling, Production and HSE

14

Be ★

by Maurice Smith and Mike Byfield

Ultra-temperature electrical submersible pumping systems

Electric submersible twin screw pump

TRO tailings management technology

Heavy-duty mentor

Merry Christmas

by James Menzies

from all the staff at

T E C H N O L O G Y

26

Inthinc's trucker-coaching software reinforces best-practices driving

R E G I O N A L

31

F E A T U R E

N E W S

British Columbia

49

• Groundbirch tight gas drilling and

• Enbridge has Bakken pipeline plans for

production are scaling up fast

35

Northwestern Alberta

Saskatchewan and the U.S.

53

• Encana targets liquids-rich gas at

Northeastern Alberta

boosted annual GDP by $65B

55

• SilverBirch CEO welcomes

Central Alberta

proposed offshore liability hikes

57

• Alberta passes the $2B mark as land

International • Shell VP says lower gas costs are vital

sales revenue recovers in 2010

43

East Coast

to tapping foreign markets

Southern Alberta • Drilling contractors rebuild and retool

10

E VE R Y

I S S U E

Statistics at a Glance

61

• Completions data, spot gas prices, gas

Tools of the Trade deploying the Cessna Citation

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Political Cartoon

COVER DESIGN: Birdeen Selzer

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Editor’s Note Vol. 22 No. 12 President & ceo Bill Whitelaw | bwhitelaw@junewarren-nickles.com Publisher Agnes Zalewski | azalewski@junewarren-nickles.com Associate Publisher Chaz Osburn | cosburn@junewarren-nickles.com

Mike Byfield | mbyfield@junewarren-nickles.com

Editorial director Stephen Marsters | smarsters@junewarren-nickles.com

Bravo, Suncor!

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The 2010 Technology Stars are shining. Taken together, the six winners and three runners-up form a stunning showcase of ingenuity and innovation. We at JuneWarren-Nickle’s Energy Group thank all the entrants who participated in the first year of this program.

We’re especially grateful to the three industry judges who selected our Technology Stars. Their credentials are as impressive as the winners: • A rthur Dumont ranks high among Canada’s service company executives. A mechanical engineer by training, he has been a senior executive (chairman, CEO or COO) of Technicoil Corp., Precision Drilling Corp., Western Rock Bit Co., CenAlta Energy Services Inc. and several other firms. His numerous contributions in the non-profit sector include chairing the University of Saskatchewan’s Board of Governors.

• Grant Shomody, president and founder of Calgary-based Grantech Engineering International, specializes in front-end engineering, design and project management consultancy services for natural gas facilities. A professional engineer for more than 20 years, Shomody also led the development of O&G Advisor, a software program that generates capital and operating cost estimates for field facilities.

• Roger Soucy became the founding head of the Petroleum Services Association of Canada (PSAC) in 1981, retiring as its president and CEO earlier this year. During his tenure, PSAC’s membership expanded to more than 250 service companies. Soucy has also chaired Petroleum Human Resources Council of Canada and the Petroleum Communication Foundation.

Also participating in the judging were Stephen Marsters (editorial director of JuneWarrenNickle’s Energy Group), Maurice Smith (editor of New Technology Magazine) and myself.

Our judges couldn’t help being struck by the research and development contributions of Suncor Energy Inc. Thanks to an investment on the order of $250 million, Canada’s largest oil company harvested a Technology Star in its own right. Suncor’s new proprietary tailings reclamation process represents a decisive step in reducing the scale and time frame of bitumen tailings ponds. That achievement will help stymie political foes as well as reduce the environmental footprint of oilsands operation.

Suncor has also acted as a research and development partner for all four companies selected as winners in the drilling and production categories, playing a critically important role in at least two of those projects. Better yet, the two drilling technologies — developed by very different companies — work together to achieve even more impact. As a result, Suncor’s time for drilling a typical deep foothills well has reportedly plunged from 180–200 days down to as few as 70 days.

JuneWarren-Nickle’s Energy Group is no neophyte when it comes to honouring achievement.

The Oilweek Annual Report Awards have been an industry hallmark for 35 years, and our sister publication’s Rising Stars program continues to strengthen. Now we’ve gained more insight into managing an engineering-oriented program. Stay tuned for bigger and better in 2011!

N E X T

I S S U E

January/February edition In our next issue, Oil & Gas Inquirer will review recent developments in drilling tools, including rock bits and directional equipment. Plus we’ll take an in-depth look at technical and economic trends in heavy crude, the oil that’s taking an increasing market share globally.

If you know an admirable person to profile in On The Job — he or she may be a veteran or apprentice, field or shop, wise or a little crazy — please give me a call at (780) 784-4251, or email mbyfield@junewarren-nickles.com. In fact, feel free to sound off about any concern at all — that’s a personal invitation.

OIL & GAS INQUIRER • DECEMBER 2010

9

Stats

FAST NUMBERS

3,947

AT A GLANCE

3,477

The number of natural gas development wells drilled over the first 10 months of 2010, nine per cent less than the same period in 2009 and far below the 2005-07 drilling rate.

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

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

Feb 2010 Mar 2010 Apr 2010

144 264 198

308 579 418

114 198 6

566 1,041 622

Feb 2010 Mar 2010 Apr 2010

147 548 291

143 681 458

20 109 2

5 20 9

315 1,358 760

May 2010 Jun 2010 Jul 2010

400 126 131

462 117 110

51 41 38

913 284 279

May 2010 Jun 2010 Jul 2010

490 295 193

511 153 9

39 40 16

19 16 4

1,059 504 222

Aug 2010 Sept 2010 Oct 2010

168 357 404

135 638 460

43 59 46

346 1054 909

Aug 2010 Sept 2010 Oct 2010

452 617 678

156 790 581

40 45 39

15 23 18

663 1475 1316

Wells Drilled In British Columbia

Saskatchewan Completions

Source: B.C. Oil and Gas Commission

Source: Daily Oil Bulletin

MONTH

WELLS D R I L L E D

CUMULATIVE *

MONTH

OIL

GAS

OTHER

TOTAL

Nov 2009 Dec 2009 Jan 2010

39 45 65

571 616 65

Nov 2009 Dec 2009 Jan 2010

171 139 153

11 11 18

10 9 6

192 159 177

Feb 2010 Mar 2010 Apr 2010

101 98 56

166 264 320

Feb 2010 Mar 2010 Apr 2010

169 223 92

58 32 10

4 8 3

231 263 105

May 2010 Jun 2010 Jul 2010

54 41 65

374 415 480

May 2010 Jun 2010 Jul 2010

86 149 220

7 7 7

3 11 0

96 167 227

Aug 2010 Sept 2010 Oct 2010

43 39 28

523 562 590

Aug 2010 Sept 2010 Oct 2010

198 197 201

12 5 12

7 6 11

217 208 224

*From year to date

10

The number of oil development wells drilled over the first 10 months of 2010 in western Canada, up by 76 per cent over 2009.

DECEMBER 2010 • OIL & GAS INQUIRER

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

G A S S T O R A G E in the United States

Source: Natural Gas Exchange Inc.

Source: U.S. Energy Information Administration 4.00

3.75

3.25

2.75

3.75

$3.54/GJ Total vol.: 1,464 TJ Transactions: 202 Oct 20

Cdn$/GJ

Oct 27

Nov 3

Nov 10

3.50

Nov 17

Source: Natural Gas Exchange Inc.

Tcf

3.84 Tcf Year ago: 3.83 Tcf 5-year avg: 3.52 Tcf

Oct 15

Oct 22

Oct 29

Nov 5

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada November 15, 2010 Source: Rig Locator

Alberta October 2010 Source: Daily Oil Bulletin

ACTIVE

DOWN

TOTAL

ACTIVE (Per cent of total)

Western Canada Alberta

317

235

552

57%

British Columbia

51

40

91

56%

Manitoba

15

3

18

83%

Saskatchewan

71

71

142

50%

454

349

803

57%

0

1

1

0%

WC Totals Northwest Territories

OIL WELLS

Alberta

GAS WELLS

Oct 10

Oct 09

Oct 10

Oct 09

Northwestern Alberta

65

19

79

31

Northeastern Alberta

93

9

6

0

183

95

30

24

63

9

345

103

404

122

460

158

Central Alberta Southern Alberta TOTAL

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada November 15, 2010 Source: Rig Locator

Alberta October 2010 Source: Daily Oil Bulletin

ACTIVE

DOWN

TOTAL

ACTIVE

Western Canada Alberta

267

660

60%

British Columbia

15

14

29

52%

Manitoba

14

2

16

88%

Saskatchewan

139

51

190

73%

WC Totals

561

334

895

63%

0

1

1

0%

Quebec

COALBED METHANE

Alberta 393

Nov 12

Source: U.S. Energy Information Administration

BITUMEN WELLS

Oct 10

Oct 09

Oct 10

Oct 09

Northwestern Alberta

6

3

1

1

Northeastern Alberta

0

0

63

9

Central Alberta

10

11

80

61

Southern Alberta

48

12

0

0

TOTAL

64

26

144

71

OIL & GAS INQUIRER • DECEMBER 2010

11

the Judges

★ B est

h Tec E ion T ec h n olo gy ★ B est H S

lo no

gy

The technologies selected as winners by these judges span the breadth of the oil and gas sector — large and small, Canadian and multinational. Their achievements, however, do reflect several common denominators: ingenuity, leadership and unrelenting perseverance.

President and Founder, Grantech Engineering

Be

no

h

Grant Shomody

c Te

CEO, Retired Technicoil Corp.

st

on

Pr od

ati lor

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Exp

Arthur Dumont

lo

gy

★

★

Be

st D

r il li n g

Technology

A great resource can be found in the minds of those who champion new ideas.

In this issue, we recognize six of the

most innovative technologies as our inaugural Technology Stars. It is also a recognition of those individuals who pushed

Roger Soucy CEO, Retired PSAC To learn more about the judges, see Editor's Note on page 9 or visit us online.

the boundaries to rise to the top and of the creative and entrepreneurial spirit that

remains alive and well throughout the oil and gas sector — a spirit that above all else ensures the industry will continue to prosper in the years ahead. > OIL & GAS INQUIRER • DECEMBER 2010

13

N

TECH

G Y S TA R S

MicroSeismic maps hydrological fracturing results in real time

by Maurice Smith

2010

WINNER

H

orizontal drilling and multi-stage hydraulic fracturing form the indispensable duo that’s driving shale gas plays across North America. That innovative revolution has transformed a sunset industry into a thriving sector that’s apparently capable of supplying the continental gas market for the next century.

But as the technology spreads, operators have found what works in one play doesn’t

Best S Exploration Technology:

Y S TA R

MicroSeismic, Inc. Product:

FracStar and Buried Array monitoring systems

2010 Service:

RUNNER-UP

Real-time mapping of hydrological fracturing Competes with:

Listening to the fracing ground cutline

MicroSeismic president Peter Duncan says Encana Corp. pioneered his firm's surface and buried monitoring systems in the Haynesville shale gas play.

14

DECEMBER 2010 • OIL & GAS INQUIRER

Photo: MicroSeismic, Inc.

Purpose-drilled adjacent wells

Photo:

OG

O

LO

Illustration: MicroSeismic, Inc.

TECH

N

MicroSeismic, Inc., specializes in the monitoring and interpretation of seismic signals generated by the fracturing of oil and gas reservoirs over time. The company uses FracStar surface-based data acquisition or a Buried Array permanent network of geophones buried in shallow ground to gather low G Y S TA R S level acoustic energy emissions.

LO Its O Tomography Passive Seismic Emission system sums the output of the entire array to detect and locate microseismic activity.

Read Peter Duncan's bio online.

2010

WINNER

N

output of the entire array to detect and locate microseismic activity deep below.

Canadian-born Peter Duncan, MSI’s founder and president, says the technology has been taken up by some of the continent’s biggest producers. It’s now in use in tight gas plays from the Marcellus and Haynesville in the United States to British Columbia’s Montney and Horn River Basin, along with the Bakken tight oil play in Saskatchewan.

Duncan, a geophysicist who founded MSI in 1993, describes himself as “more like the midwife than the inventor” in this case. A Colorado University professor developed earlier versions for hydrothermal exploration in Russia. MSI, purchasing the technology, advanced and adapted it for oil and gas applications.

“What it has become is a tool for putting large-aperture arrays over entire oilfields, turning them on and listening to all the production activity in the oilfield, whether its frac monitoring or injection of fluids or production of fluids, in order to hear those sensitive sounds, pinpoint their location and their nature, and really allow the reservoir engineer to know something about the dynamics of what is going on in his oilfield,” Duncan says.

Encana Corporation, an early user, tested the surface-based FracStar in 2007 and installed the first permanent Buried Array in 2008. Both systems were applied at its Haynesville shale gas play in northern Louisiana. The Calgary-headquartered producer went on to install another three permanent Buried Arrays in the Haynesville.

MSI has now installed about 20 Buried Arrays, almost all to monitor frac operations.

But the rapidly growing company also sees potential in monitoring everything from steam injection in the oilsands to carbon sequestration and enhanced geothermal systems. “We have only begun to scratch the surface,” Duncan says.

O

LO

G Y S TA R S

TECH

necessarily translate to the next. Each geological prospect has to be “solved” before large-scale commercial production can be a success.

An important tool for helping operators to crack new plays quickly has been derived from technology used to monitor earthquakes and geothermal activity. Houston-based MicroSeismic, Inc. (MSI) has developed the capability to monitor hydrological fracturing of gas-bearing shales. From the surface or near-surface, an operator can monitor and interpret the tiny vibrations triggered when tonnes of frac fluids and proppants are pumped at high pressure into reservoirs some 5,000–15,000 feet underground.

The technology creates high-definition imagery that indicates the direction and penetration of the fracs, with results reportedly superior to the more costly method of drilling adjacent monitoring wells to reservoir depth.

Further, MSI’s product performs that task in real time. Operators can adjust and tweak as the fracing procedure advances stage by stage down the length of the horizontal wellbore.

In addition, future horizontal wells and frac stages can be more effectively placed across the shale gas play.

The technology is being used not only to help solve new shale plays, but to optimize production within plays. “The variability of the shales from well to well is driving more and more operators to monitor 30–40 per cent of their wells, and in some plays 100 per cent,” Duncan says. “It is a matter of value proposition. As the unit price comes down, operators are able to employ the monitoring on more and more wells. At some price point it will make sense to do it on every well.”

MSI uses either of its FracStar surfacebased data acquisition or its Buried Array permanent network of geophones (guaranteed for at least 10 years) buried from 100 to 500 feet underground — to avoid nearsurface noise — to gather very low-level acoustic energy emissions. The process relies on the small seismic events, or microearthquakes, created at depth by the frac procedure. There’s no need for an active source of vibration, such as dynamite, air guns or vibroseis vehicles.

Fracing data is wirelessly communicated to MSI’s Passive Seismic Emission Tomography (PSET) system for interpretation. Signal attenuation by the overburden makes conventional seismological earthquake location techniques ineffective. In contrast, PSET allows MSI to use the dense array of geophones to “beam steer” or sum the

2010

RUNNER-UP

GeoLOGIC Systems Ltd. Knowledge equals profit. Geologists, geophysicists, engineers and accountants from no less than 19 producers notified JuneWarren-Nickle’s Energy Group that they rely on GeoSCOUT, a product of Calgary-based GeoLOGIC Systems Ltd. This comprehensive software package generates a range of sophisticated reports, integrating data sources that cover the life cycle of an oil and gas project.

OIL & GAS INQUIRER • DECEMBER 2010

15

N

TECH

G Y S TA R S

2010

Weatherford’s Multiphase Performance Drilling system increases penetration rates in hard, abrasive formations

by Maurice Smith

WINNER

A

ny time a driller can double, triple or even quadruple its rate of penetration (ROP) in a well, it must be doing something right.

Particularly for producers dealing with hard, abrasive formations, a dramatically improved ROP can open up many opportunities. When Weatherford Canada and Suncor Energy Inc. achieved a drilling breakthrough of that magnitude in the Alberta

hard rock star

Best S drilling Technology:

Y S TA R

for a company with 100 employees or more

Weatherford 2010 International Ltd. RUNNER-UP

with Suncor Energy Inc. Product:

Multiphase Performance Drilling (MPPD) system Service:

Enhances drilling rate of penetration Competes with:

Conventional drilling systems

Photo:

OG

O

LO

cutline

Multiphase Performance Drilling was originally developed for the slow drilling formations encountered in the Panther field near Sundre, Alta.

16

DECEMBER 2010 • OIL & GAS INQUIRER

The amount used can be adjusted depending on the type of rock being drilled. And because it’s an inert gas, it renders drilling low-risk. “We like to drill with maximum nitrogen to get the lightest weight that we can,” Staysko says. “Membrane nitrogen generated on site is compressed and injected, along with the drilling fluid down the drill string through the bit, resulting in a lighter mud weight and that has a direct relationship to the rate of penetration, so you’re able to drill faster.”

In order to handle the increased cuttings coming to surface because of the higher ROP, specific operating procedures have been implemented and strictly followed by both Weatherford and rig contractor employees. Annular effluent is safely handled by Weatherford’s specialized surface equipment, processes and engineering.

Weatherford uses its model 7000 rotating control device (RCD) to provide precise control of the wellbore pressure profile. At Kelly Lake, Weatherford was able to reduce equivalent circulating density to less than 600 kilograms per cubic metre mud weight compared to 950 kilograms per cubic metre during conventional operations.

MPPD is used in applications that meet a set of criteria before a project is approval.

Complex wells of this kind need proper planning to ensure flawless execution, says Alek Ozegovic, engineering manager of Weatherford’s Secure Drilling Services group. Weatherford creates a customengineered drilling program for all MPPD projects to complement the operator’s well program. “Extra equipment is needed in a multi-phase application, but despite the extra up-front costs, savings in the end justify the means,” Ozegovic says.

Photo: Aaron Parker

foothills, the innovative technology soon began spreading elsewhere.

After developing the patent-pending Multiphase Performance Drilling (MPPD) system in the Panther field, the two companies have expanded its use to Suncor’s Kelly Lake and Gwillim plays in British Columbia. Now Weatherford is poised to take the new technology worldwide.

“We see potential anywhere where there is large meterage of hard formations to drill.

As long as it is consolidated rock that has good hole stability while you are drilling it, it can be a candidate, so it has global application,” says Rich Norton, Weatherford Secure Drilling Services operations manager. “We have had several different countries looking at it. It’s one of those things that has only been done in Canada, but it’s time to open it up and push it out further. The potential market is huge.”

The technique is optimal for drilling in harsh, abrasive formations like the Nikanassin or Cadomin. MPPD is changing the game for operators in these challenging conditions, the companies say. The marked increase in ROP using nitrified-invert MPPD has allowed Suncor to save as much as $1.5 million per well. At Kelly Lake, distances drilled per day through hard formations were about three times greater with MPPD, saving 4 to 7 days of drilling time for intermediate sections and 7 to 10 days for horizontal sections of a well.

Drilling the Nikanassin formation in the Gwillim field also netted significant improvements, when ROP went from two to nine metres per hour. “Time is money when drilling. When you go from 35 days to 9 days drilling, you can see the economics are significant,” says Bob Staysko, contract drilling specialist with Suncor.

Key to the process is the controlled use of nitrogen to lighten mud weight.

Suncor's Secure Drilling Services group includes (from left) Dwight Affleck, Rich Norton and Larry Lavigne.

A producer-service partnership generates step-changing technology Weatherford has high praise for its partner in developing the Multiphase Performance Drilling (MPPD) system since the concept was raised with Suncor in 2004. The multinational services firm says few client companies have the patience and the willingness to make sometimes costly long-term investment necessary to perfect such systems.

“Suncor was committed to making a change in their drilling process versus doing it the traditional way,” says Keith Corb, a technical support consultant with Weatherford. “It was a real commitment on their part in helping develop the process, not just trying it once and walking away.”

Corb and four other specialists from Weatherford and Suncor were involved as the system was tested, modified and, at times through mere

trial and error and an abiding willingness to try less conventional concepts, perfected.

“Initially, we really weren’t sure how this was going to work,” concedes Alek Ozegovic, engineering manager of Weatherford’s Secure Drilling Services group. “Every hole that we did was an improvement on the previous one, but I would say, between the first and the second one was the biggest, step change. After that it was just tweaks and modifications that we incorporated, pushing the envelope a little bit more each time.” Weatherford, with some 35 MPPD projects now under its belt, continues to improve on the technique.

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BBJ Tools transforms the traditional fluid hammer into a revolutionary drilling tool

by Mike Byfield

2010

WINNER

Best S drilling Technology:

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n t he s pr i ng of 2 010, Su nc or E nerg y I nc . d r i l led a foot h i l l s horizontal wellbore to 6,500 metres using a fluid hammer from top to bottom. That feat had never been achieved previously with this type of tool. “ROP [rate of penetration] was improved by 30–50 per cent,” explains Brad Cote, president of Calgary-based BBJ Tools Inc. “Our fluid hammer represents a revolutionary

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BBJ Tools Inc.

2010 Product:

RUNNER-UP Fluid hammer Service:

Enhances drilling rate of penetration Competes with:

high-tech hammer Photo: Aaron Parker

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BBJ founder Brad Cote says his firm's proprietary fluid hammer works with delicate PDC bits as well as traditional roller cones.

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improvement in terms of maintaining drill bit integrity, steering ability, operating f lexibility and other critical performance factors.”

BBJ carries fluid hammers for all standard hole applications. Its patent-pending proprietary hammer maintains the drill bit in constant contact with the rock face, creating axial percussion force directly above the bit and exerting tremendous percussive force at hundreds of cycles per minute. BBJ’s fluid hammer incorporates a positive displacement motor (PDM) and adjustable housing, which enables the driller to steer the drill bit, unlike conventional fluid hammers, which cannot be steered.

The recent foothills well was drilled with tri-cone insert rock bits. Today, however, most wells are drilled with polycrystalline diamond compact (PDC) bits. “The synthetic diamond cutters are much more delicate than roller cones, so we had to undertake focused research and development to tailor the fluid hammer to PDC applications,” Cote says. The fluid hammer has been proven viable for a number of PDC applications. BBJ credits Tourmaline Oil Corp. as a tremendously helpful customer for its PDC development.

The percussion force is developed in the lower housing directly above the bit box.

When weight is applied to the bit, the fluid hammer engages while keeping the bit in compression, delivering axial movement to the outer housing. “This design provides efficient weight-to-bit transfer for centre percussion force,” Cote says. “This design allows for diversified percussion control as rock formation compressibility variations are encountered. For example, when the driller needs more force, he simply puts more weight on the bit. If all weight is removed from the bit, the hammer cycle stops, which is unique to BBJ’s fluid hammer design.”

The BBJ fluid hammer is integrated with major components of the mud motor.

“Not only can our tool compete in every application where a mud motor is used, it outperforms them,” Cote says. “Mud flow and type are not restricted or diverted.

Our technology eliminates f low issues for LCMs [lost circulation materials like sawdust], high solids content and torque beads. In addition, there are no interruptions to the MWD [measurement while drilling] signal. With the cycling of the hammer, it develops movement to the outer housing which acts like an agitator tool, eliminating drag to the bit and increasing ROP.” The BBJ fluid hammer’s percussion mechanism transmits powerful left-hand reactive torque to the housing. “Reactive torque was our most difficult engineering hurdle,” Cote comments. “We came up with an anti-backoff connection that in itself is a breakthrough. This concept has other possibilities that we’ll work with in the future with respect to mud motors.”

Traditional fluid hammers exert continuous percussive force whether the rig is drilling ahead or not, an action that cannot be controlled from surface.

The BBJ hammer is operator-controlled through the weight placed on the drill bit. The patentpending mechanism stops hammering when drilling halts.

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From hockey enforcer to Technology Star Brad Cote spent much of his boyhood in North Battleford, Sask., on the ice. While still in high school, he competed at a major-junior level in the Western Hockey League (WHL), playing for the Portland Winterhawks and later the Moose Jaw Warriors. However, “to save my hands,” the hard-hitting left-winger quit hockey and entered the oilfield.

“I’ve always wanted to know how things worked,” recalls the president of BBJ Tools Inc. The mechanically inclined youth was soon roughnecking for a major drilling contractor. “From the moment I first set foot on a rig, I developed a passion for the industry and technology,” Cote recalls.

Eventually, he became toolpush of one of Canada’s deepest-rated rigs

and a senior troubleshooter. “The inspiration for BBJ Tools’ technology originated from a desire to improve project efficiencies in the oilsands and foothills,” the company co-founder comments.

BBJ was launched in 2004, making its first mark with the slotted liner assist tool and cuttings bed removal tool. Combined, these two devices broke new ground for drilling modern extended reach and steam assisted gravity drainage wells. The fluid hammer followed, outclassing any competitive device from a major company. “Luis Guzman [a co-owner of BBJ] and I produced this tool in less than two years,” Cote comments. “I’m still amazed at what our small team has been able to achieve in short time.”

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Baker Hughes’ latest electrical submersible pump system rises the SAGD operating bar to 250°C

by Mike Byfield

2010

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a ker Hughes Ca nada sees it s l ate s t u lt r a - te mp e r at u r e electrical submersible pumping (ESP) systems as a big step forward for steam assisted gravity drainage (SAGD) technology. “In subsurface bitumen reservoirs, higher heat creates a larger steam chamber and makes the oil more missive, which translates into higher production,” says Kelvin Wonitoy, project manager for Photo: Aaron Parker

WINNER

Best S production Technology:

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for a company with 100 employees or more

Baker Hughes Inc. 2010 Product: RUNNER-UP Ultra-temperature

electrical submersible pumping systems Service:

Operates in steam assisted gravity drainage wellbores up to 250°C Competes with:

Other electric submersible pumps

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Kelvin Wonitoy at Baker Hughes' Centrilift plant in Leduc.

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beating the heat

says. “First, we required better insulation materials for the stator, cable and motor lead extension. Second, we had to develop metallic materials that would enable all parts to remain within appropriate mechanical tolerances despite the dimensional changes caused by higher temperatures.”

Besides more heat, ESPs in SAGD applications must cope with temperature cycling (due to shutdown, steam optimization and other field operations), slugs of gas and steam in the bitumen flow, and the fine abrasives that inevitably slip through screening systems. The Claremore test facility (shown at right) puts all materials through more aggressive stress conditions than would ever be encountered under reallife operating conditions.

To protect the magnet wire used in the stator (a component of AC electric motors), Baker Hughes’ chemists helped create a high-purity polyamide film along with a proprietary outer Perfluoroalkoxy (PFA) insulation. Half a dozen metallurgies were addressed. The pump shaft, for example, is manufactured with a space-age material called Inconel, and bearings are hardened.

A multi-vane pump stage was developed to eliminate gas lock, along with a new intake design that operates well in a horizontal application. Chemists also ran tests to identify motor oils capable of standing up under SAGD operations.

Since April 2010, Baker Hughes has installed 12 pumping systems capable of operating at 250°C. “We’re working with four producers in northeastern Alberta,” Wonitoy reports. Although results remain confidential at this point, he is confident of success. “We’ve invested $5 [million] or $6 million in our testing facilities alone, a greater commitment to SAGD than any other ESP manufacturer has been willing to make.

That R&D investment is really paying off for producers now.”

Photo: Baker Hughes Inc.

Baker Hughes artificial lift systems. “We’re the first company to deploy ESPs capable of operating reliably at downhole temperatures as high as 250°C. This generation of ESPs is also designed to be more robust in operation, which will result in longer runlife, less downtime, less pulling costs and, as a result, will provide a greater return on the client’s investment.

The specialist, based in Leduc, Alta., has been Baker Hughes’ Canadian lead for ESP applications in SAGD since the company first entered the sector in 2003. “Conventional oil reservoirs rarely rise above 100°C. We’ve continuously adapted our core product ESPs [used for conventional crude] for this new operating environment,” Wonitoy says.

Initially, SAGD wells operated at bottomhole temperatures of about 180°C. In 2005, the heat limit had risen to 200°C, then 220°C by 2008. In Wonitoy’s view, raising the bar to 250°C required more extensive improvements in manufacturing materials and design than did previous stages.

Baker Hughes began research into ESP deployment at higher temperatures for use in geothermal power generation during the 1980s. At Claremore, Okla., the multinational services firm constructed a vertical test well that remains unique in the industry. That research and development facility was upgraded in 2003 for SAGD applications with a hot loop, gas loop and slurry loop. In 2009, Baker Hughes added a second hot loop at its testing facility at Claremore, designed to rigorously stress ESP systems as high as 300°C. Provision was also made for the horizontal pump placement used in SAGD bitumen wells.

An ESP system includes a pump, motor and downhole power connection, with the entire assembly fitting inside casing that’s 9 5/8 inches in diameter. “There were two key hurdles to overcome when designing an ultra-temperature ESP system,” Wonitoy

Baker Hughes tests with a hot loop at its Claremore research facility.

“In subsurface bitumen reservoirs, higher heat creates a larger steam chamber and makes the oil more missive, which translates into higher production.˝ — Kelvin Wonitoy, Project Manager, Baker Hughes

Kelvin Wonitoy has worked from 65°C below to 54°C above As Baker Hughes Canada’s project lead for ultra-temperature SAGD electric submersible pumps, Kelvin Wonitoy liaises between research and manufacturing teams in Alberta and Oklahoma as well as Canadian bitumen producers. “I’ve worked in some pretty extreme temperatures myself,” he notes with a smile. “It hit 65 below in the Arctic when I was a rig hand with Commonwealth Hi-Tower. When I worked in southern Libya, the temperature in the Sahara [Desert] reached 54°C. It felt like walking into a furnace.”

Raised on a dairy farm near Camrose, Alta., Wonitoy roughnecked before taking an electrician’s apprenticeship through the Northern Alberta Institute of Technology (NAIT). Almost 26 years ago, he joined

Baker Hughes as a field technician. Since then, he’s received intensive in-house training in mechanical engineering, risen to senior super-visory positions and authored several papers.

His oil and gas work has taken him to Europe, Africa and Asia, operating on and offshore. “We’re the only company that manufactures all major components of electrical submersible pumping systems,” Wonitoy comments. “That way, we can ensure consistent quality at the highest level, we provide consistent compatibility across the full ESP system and we provide one customer point of contract for effective management. The technical breadth of Baker Hughes is a constant challenge. However, I’m still vertical and kicking — it’s been a very satisfying career.”

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2010

Can-K’s electric submersible twin screw pump is designed to handle the nastiest crudes

by Mike Byfield

WINNER

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a n-K Group of Compa n ies is about t wo -t h i rds of t he way t h rough bui ldi ng a n elec t r ic submersible t win screw pump ( E STSP) for Kuwa it Oi l Compa ny (KOC). The unique downhole pump, coupled to a suitable electric motor and related equipment, is scheduled for service in a complex oil well characterized by high asphaltene, hydrogen sulphide and very

double twist

Best S Production Technology:

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for a company with fewer than 100 employees

Can-K Group of Companies 2010 RUNNER-UP Product:

Electric submersible twin screw pump Service:

Pumping heavy crudes heavily laced with asphaltenes, hydrogen sulphide, wax, methane and more Competes with:

Other electric submersible pumps

Photo: Aaron Parker

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The design of Can-K’s electric submersible twin screw pump incorporates two shafts, separated by a timing gear.

Each shaft carries short sections of screws that interlock at extremely close tolerances but never touch.

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“Because it is a positive displacement pump, it is always volumetric. Pressures remain the same with varying speed,” Dass explains. “The pump does not distinguish between gas and liquid because it interprets volume only. Unlike a centrifugal pump, the twin screw unit has no best efficiency point, and it can draw down to vacuum conditions.” Gas content can be as high as 97 per cent, with 3 per cent liquids required for motor cooling and lubrication.

The Can-K president says the ESTSP works well for asphaltene and waxy wells because it has low shear, which minimizes breakout. “Residual asphaltene improves efficiency because it increases viscosity, a fact that has been clearly noted during field applications,” he comments. “Although an ESTSP is not a sand pump, it can handle more sand than a conventional ESP [electric submersible pump]. That’s because the twin screw pump does not have a centrifugal component so it does not throw the sand around.” The company has also come up with a patented screw design that impedes pump seizure due to sand and other solids.

Everything that comes out of the well goes into the pump.

The ESTSP utilizes downhole electric motors from othermanufacturers.

Bottomhole temperature can be as high as 280 degrees Celsius as far as the pump is concerned. Motor is the limitation. Besides ESTSP, the company offers a top-drive twin screw pump that is sucker-rod driven or coiled-tube driven. It also has rigless topdrive twin screw pump that can be installed using coiled tubing, slick line or a sucker rod.

“The inherent efficiencies of the twin screw pump give it the potential to replace conventional ESPs,” Dass says. “However, a lot of lessons could only be learned the hard way, through trial and error. KOC has more than 48 similar wells, so we’re looking at an exciting opportunity. Can-K just moved into a larger manufacturing facility in Edmonton, and we are ramping up our manufacturing capability for major production by 2011 or 2012.”

Photo: Aaron Parker

high wax content. Can-K won the large turnkey project because no other artificial lift technology can handle such a well at depths in excess of 12,500 feet deep.

“Suncor [Energy Inc.] gave us an opportunity during the initial Firebag installations to test our pumps in their SAGD [steam assisted gravity drainage] wells at 225 degrees Celsius,” says Pradeep Dass, who founded Can-K in 1991. “Suncor’s willingness to test our pumps gave us a lot of field experience in SAGD applications. We are now ready to land ESTSP in SAGD wells. We are also developing rigless ESTSP at this time with permanent magnet motors. We hope to be ready by sometime in 2011 with field trial capabilities.”

“Twin screw technology has been around for ages,” Dass acknowledges. “It’s a very efficient volumetric design type of pump with many advantages for petroleum production.

However, it’s very difficult to manufacture an ESTSP small enough to fit within well casing while generating the high pressures needed to move large volumes of heavy oil. There are other design challenges as well — our company has climbed a steep learning curve over the years.”

The traditional rod pump is relatively inexpensive, but is typically limited to wells producing daily volumes under 2,000 barrels. Progressing cavity pumps (PCPs), also quite affordable, handle sand and heavy crude well but are even more restricted with respect to daily volumes. Can-K claims that its ESTSP models can be adapted to pump 150–56,000 barrels per day and directly compete against ESP, gas lift and some PCP designs.

Its patented design incorporates two shafts, separated by a timing gear. Each shaft carries short sections of screws that interlock at extremely close tolerances but never touch. Because the screws don’t touch, there is less friction and less torque is needed, resulting in lower electricity consumption. It is very efficient when compared to ESP systems, especially in more viscous and high gas-to-oil ratio mediums.

Can-K president Pradeep Dass has invested years in adapting twin screw pump technology for oil.

“Suncor’s willingness to test our pumps gave us a lot of field experience in SAGD applications.

We are now ready to land ESTSP in SAGD wells.˝ — Pradeep Dass, Founder, Can-K

Pradeep Dass tackled a steep learning curve Born in Singapore, Pradeep Dass studied mechanical engineering at Bangalore University in southern India. His family owns a high-tech company in India that manufactures space- and

mining-related products. “The truth is that I’ve never worked for anyone else [as a salaried employee], and I doubt that I could hold a job,” says the 53-year-old Edmontonian.

As a youth, he chafed in Singapore, a city state in southeast Asia whose exceptional prosperity is tempered with limited freedom of speech. “I came to Canada in 1991 as a

business-class immigrant and looked for opportunities in engineering and manufacturing. Most of our sales are international, but SAGD represents an opportunity for us on our own doorstep.”

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Suncor’s TRO technology slashes the time to reclaim oilsands waste by two-thirds

by Mike Byfield

2010

WINNER

S

uncor Energy Inc. estimates that its TRO tailings management technology will slash the time required to reclaim oilsands tailings from 30 years to 10 years or less. “Thanks to this development, we’ve eliminated the need to construct new tailings ponds at our bitumen mining operation,” says Bradley Wamboldt, Tailings Reduction Operations director for Suncor in Fort McMurray, Alta. “In addition, we plan

Best HSES Technology:

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Suncor Energy Inc. Product:

Tailings Reduction Operations (TRO) system 2010

RUNNER-UP Service:

Greatly reduces reclamation time for bitumen mining waste Competes with:

Consolidated tailings and conventional reclamation systems

tailings triumph cutline The TRO process is based on clay particles clinging to a polymer material. After flocculation, the MFT/polymer flocs are dried in thin layers over gently sloped sand banks, then left in place or moved to another location.

Here, Suncor TRO director Bradley Wamboldt examines a bed of drying tailings.

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Photo: Suncor Energy Inc.

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The Suncor tailings breakthrough will save money Bradley Wamboldt categorically rejects the notion that Greenpeace and other enviro-lobby groups bullied Suncor Energy Inc. into cleaning up its tailings act. “Tailings management has always been integral to this industry’s planning, long before it became a high-profile issue beyond Alberta,” says the chemical engineer, a graduate of McGill University in Montreal. “Any oilsands operator is legally obliged to restore its leases back to their original condition or a comparable state. Nothing new there.”

The key question was never ‘if’ but ‘how.’ “Producers have been chasing a solution for MFT [mature fine tailings] for a long time,” admits Wamboldt, who’s worked overseas as well as Canada.

He came to the oilsands in 1997, helping with initial development of Shell Canada’s Muskeg River Mine project. “Technically, tailings have proven to be a challenge, as they are for many other mining industries,” the Suncor Tailings Reduction Operations director comments. “Now we have the necessary technology to address the problem.”

Before TRO technology was developed, Suncor planned to construct five more tailings ponds.

“Dikes aren’t cheap to build, and these would have been large structures,” Wamboldt says. “Suncor will also generate a significant cost saving by shortening the distance that mine waste material has to be transported. We crunched the numbers and TRO came up the winner both economically and environmentally. That’s not really surprising. New technology that’s environmentally sound often makes financial sense as well.”

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Suncor pumps a slurry of mature fine tailings and polymer flocculant over a gently tilted slope for drying.

The TRO process works only during seasons without freezing weather.

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exposing more wet material to the air. The entire drying process occurs within weeks. The TRO process can only take place in months without a firm freeze-up. During that period, Suncor’s project work force rises to the range of 200.

Suncor currently processes 180 million tonnes of oilsand annually, ingesting 50,000 tonnes per day of fine clays. Half of these fines are captured in the tailings beaching operation as they are pumped into the big ponds. The remaining 25,000 tonnes per day eventually settle into MFT and will be treated by the TRO process. “In 2009, our team processed MFT at a rate of 1,500 dry tonnes per month, utilizing 30 hectares of land,” Wamboldt says. “This year was our big ramp-up. We now have four drying sites totalling 350 hectares, capable of handling 25,000–30,000 tonnes per month.

Remember, though, that we can’t dry in winter. So we plan to add 90 hectares annually for the next three years — it’s mostly a matter of clearing the land.”

Last year, the Alberta government introduced regulations that impose annual targets for reducing MFT. “We are in a position to meet or beat those targets,” Wamboldt says. The company has spent “in the low hundreds of millions” of dollars developing the TRO method, he says, with a further billion dollars budgeted for MFT processing in the years ahead. The patented process remains confidential. Suncor is willing to share its innovative methodology with other oilsands miners — if they help pay some of the TRO technology research and development cost.

Photo: Suncor Energy Inc.

to reduce the eight existing ponds to just one over time.”

Oilsand producers use hot water to separate bitumen from sand and clay. The clay is then stored in shallow ponds, which currently cover a total area of 170 square kilometres. (This figure, equivalent to an area 13 by 13 kilometres, includes all oilsands mining companies.) The clay particles are suspended in water with traces of hydrocarbon, forming a thick soup that requires centuries to consolidate on its own.

Consolidated Tails (CT), a process pioneered

by Suncor in the 1990s, accelerates consolidation by adding sand and gypsum.

As oilsands bitumen output continues to increase, however, the CT time frame wasn’t tight enough to halt the expansion of the huge slurry ponds. Suncor began experimentation with drying out tailings in 2003. The tailings reduction operations (TRO) process, first field tested in 2008, is based on clay particles clinging to a polymer material. The resulting flocs readily come out of suspension in water. (The chemical term is flocculation.) “Mature fine tailings [MFT] and polymer solution are both viscous materials. They must be mixed but not too much. Over the past two years, we’ve worked out operating parameters which we can now pretty much just dial in,” Wamboldt explains.

After flocculation, the MFT/polymer flocs are dried in thin layers over gently sloped sand banks, then left in place or moved to another location for final reclamation. From time to time, the flocculent beds are ploughed,

2010

RUNNER-UP Two nominees were selected for honourable mention in the HSE category:

Environment Refuelling Systems Inc. of Calgary would have won a 2010 Technology Star if safety were a separate category (an option that will be considered carefully next year).

Its FracShack is a stand-alone modular unit that provides a low-pressure fuelling system for a fleet of pumpers and other heavy vehicles while they’re completing a well on closely packed drilling pad.

Questor Technology Inc. designs and manufactures state-of-theart incinerators, providing up to 99.99 per cent combustion efficiency without any particulate matter, polynuclear aromatic hydrocarbons or unburned hydrocarbons.

Our judges ranked this product as the best in the environment category from a small firm.

OIL & GAS INQUIRER • DECEMBER 2010

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Inthinc's screens can be seen by drivers and supervisors.

mentor Inthinc’s trucker-coaching software reinforces best-practices driving

by James Menzies

T

he t rend towa rd keepi ng a n i nc r e a si ng ly c apable e ye on truck drivers through automated monitoring systems continues to gather momentum. Todd Follmer, CEO of Salt Lake City–based Inthinc Technology Solutions Inc., says the resources sector — particularly safety-conscious oil and gas service companies — is setting the pace for introducing this technology in Canada.

Follmer believes the primary strategy should be coaching drivers, not just Big Brother–type monitoring and enforcement.

The NASCAR racing organization installed Inthinc’s crash data recorders into its cars and trucks following the death of driver Dale Earnhardt in 2001.

Today, the company produces the tiwi and waySmart driver mentoring systems.

This technology provides audible alerts to drivers who speed, manoeuvre too aggressively or don’t buckle up. Verbal warnings advise the driver of unsafe behaviour.

In September, Inthinc Canada opened its first office, which it originally planned to locate in Toronto. However, oilpatch

interest prompted a change to Alberta.

“We’ve had a significant presence in Canada with some of our oilfield services customers,” Follmer says. “Most of the oilfield services companies have a major presence in western Canada, which is why we’ve started in Calgary.”

An Inthinc report on its U.S. experience indicated a 73 per cent increase in seatbelt usage, 86 per cent reduction in speeding violations, 89 per cent reduction in aggressive driving behaviours and 80 per cent improvement in crash rates.

Follmer says the technology can also monitor and reduce vehicle idle-time.

After two years of testing, Barrick Gold Corporation recently announced it is spending $16 million to install waySmart in all its worldwide vehicles. Full deployment in about 3,000 company-owned vehicles is expected to be complete as early as December, according to Inthinc. For Barrick, a haul truck accident can cost millions of dollars in damage and even more in downtime.

That factor weighs just as heavily in the upstream petroleum business, the

Inthinc CEO says. “Halliburton can have an accident with a vehicle with $1-million worth of equipment on it, but it may also be a key part of an eight-asset operation at a wellhead,” he explains. “If they don’t have this one, none of those other ones get to work either. And if they don’t produce a barrel of oil today, by definition that barrel of oil becomes the last barrel that ever gets produced out of that well — and that could be 15 years from now. If they don’t get that job done today, that revenue effectively gets pushed way out into the future, so it’s very expensive to have an asset go offline in that context.”

Besides monitoring driving behaviour, the waySmart system allows for the electronic logging of driver hours of service.

The software can follow workers from vehicle to vehicle, a capability that attracts big services companies such as Schlumberger.

“They have drivers who will go from one vehicle to another, so the logs have to travel with them in real-time,” Follmer says.

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into that van, they all log in and their hours begin to accumulate. Then when they get to the job site and get into another vehicle, the hours that were in that van have to follow them into this other vehicle and be current. It’s a very complex problem to solve and somewhat unique for that type of application, but it’s common in the oilfield services industry.”

Inthinc’s tiwi and waySmart offerings can prevent speeding anywhere in North America. The system correlates real-time vehicle speed to the company’s uniquely comprehensive database of speed limits, which includes more than 40 million road segments. That information is collected from states, provinces and municipalities.

If a customer believes the database is in error in any locale, Inthinc will then investigate the discrepancy and update its proprietary database if necessary.

The waySmart system features accelerometers that can detect aggressive driving manoeuvres like hard braking or sudden acceleration and lane changes. Fleet managers can customize the settings to indicate how much leeway they wish to give their drivers before being notified of infractions.

The systems are designed be corrective rather than punitive, Follmer says. “You have to give your driver a chance to change their behaviour in real time or it’s just a gotcha system,” he advises. However, if a driver fails to comply promptly with warnings, the Inthinc system can be programmed to alert his fleet manager or safety supervisor.

“Halliburton can have an accident with a vehicle with $1-million worth of equipment on it, but it may also be a key part of an eight-asset operation at a wellhead. If they don’t have this one, none of those other ones get to work either.”

— Todd Follmer, CEO, Inthinc Technology Solutions Inc.

In the near future, the company plans to add the capability to automatically put cellphones into “safe mode” so they can’t be used to call or text while the vehicle is in motion. By next year, Inthinc is slated to offer a walk-around inspection feature that will instruct a driver on what to check during a pre-trip inspection. The system will include a timer, so the manager can ensure

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British Columbia

Groundbirch tight gas drilling and production are scaling up fast

Photo: Eagle Vision Video Productions Ltd.

by Richard Macedo

B.C.’s Montney formation ranks among the lowest cost sources of unconventional gas in North America.

At the World Energy Congress held in Montreal this fall, the Groundbirch area of British Columbia was mentioned as a key growth area by Peter Voser, CEO of Royal Dutch Shell plc. Besides Shell, other large operators have established sizeable land position in this play west of Dawson Creek.

To the end of July, 17 wells were rig released at Groundbirch. Shell Canada Limited drilled 13 of those wells, according to information from the B.C. government. Last year, 10 wells were rig released, with Shell accounting for 5.

Shell established its position in the play through Crown land sales and a $5.9billion takeover of Duvernay Oil Corp. two years ago. “In this area, we are producing natural gas from a very thick Montney reservoir consisting primarily of tight siltstone and shale,” Philippe Gauthier, Shell’s manager of onshore Canadian exploration, told a recent northeastern B.C. gas conference.

In November 2009, Shell reported production of 100 million cubic feet per day (MMcf/d) from Sunset-Groundbirch and has holdings of roughly 243,000 hectares in the prime Montney gas fairway, according to B.C.’s Ministry of Energy, Mines and Petroleum Resources. “As

the community [will be] about the same as our activity today.”

He added that Groundbirch is still a young asset with a bright future, although commercial factors such as gas prices, allocation of capital and the overall competitiveness of the project versus others in the company’s portfolio will control the pace of growth. “We’ve drilled so far about three per cent of the wells that we think we’ll need to develop that asset and only one per cent of the volumes have been produced,” Gauthier said.

In September, Pengrowth Energy Trust bolstered its position at Groundbirch by closing a takeover of Monterey Exploration Ltd. The highlight of the Monterey asset base is its focused, operated 21 (19 net) sections at Groundbirch, a highly prospective Montney focused resource asset.

Diane Shirra, Pengrowth’s V P of Montney gas development, said, “We’re in a key part of the Groundbirch area. We’re west of some of the bigger players...but we think we’re in a key part of the reservoir.

We are over-pressured and we have very thick pay in the Upper Montney, which is our target zone.”

Pengrowth has boosted its capital expenditure budget by roughly $65 million in 2010, with the majority of that

“We’re in a key part of the Groundbirch area. We’re west of some of the bigger players...but we think we’re in a key part of the reservoir. We are over-pressured and we have very thick pay in the Upper Montney, which is our target zone.”

— Diane Shirra, VP of Montney gas development, Pengrowth Energy Trust

with any unconventional gas project, the pace of production growth will be related to drilling capital,” Gauthier said. “We think we could approach [500 MMcf/d at Groundbirch] by 2014. Because of our improvement in drilling performance and usage of pads, the actual disturbance on

increase being directed to drilling activity in the Monterey Groundbirch area.

The trust currently plans to drill six 100 per cent working interest wells on Monterey Groundbirch lands this year.

The remainder of the capital has been assigned to the 28 MMcf/d natural

OCT/09

OCT/10

OCT/09

OCT/10

WELLS SPUDDED

29

43

WELLS DRILLED

27

41

BRITISH COLUMBIA WELL ACTIVITY

OCT/09

OCT/10

WELL LICENCES

82

56

▼

▲

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • DECEMBER 2010

31

Photo: Eagle Vision Video Productions Ltd.

British Columbia Montney alone on Monterey lands at Groundbirc h, according to Pengrowth, of which only 15 net locations (approximately 15 per cent) have been included in Monterey’s current reserve book ings, leav ing a significant amount of reserves conversion from resource to reserves to occur over time.

This significantly e x pa nd s Pe ng r ow t h’s d r i l l i ng i nventor y w it h the addition of approximately $650 m i l l ion of low-r isk dr i l l i ng i n t he Upper Montney. Monterey dr illed t hree hor izonta l test wells and two vertical stratigraphic wells into its Groundbirch development with the first three hor izontal wells averaging initial test rates of over Pengrowth says its low-risk inventory in the Montney formation 7. 3 M Mc f /d out of t he Upper Montney. will cost about $650 million to drill.

T here’s access to key infrastructure in the area including the gas–processing facility currently under new gas processing plant expected to construction and tie-in activity. be completed by the end of the year and A number of analysts rank the Montney formation as one of the lowest cost sources a second 28 MMcf/d plant anticipated of unconventional gas in North America. online before the end of December next GLJ Petroleum Consultants Ltd. prepared year. Pengrowth estimates that increasan independent resource assessment effecing the well density from five to eight wells per section could result in the tive April 21 with a best estimate of disrecovery of incremental Upper Montney covered petroleum initially in place on the Groundbirch asset of 2.46 trillion cubic feet resources with favourable economics.

(Monterey interest share). GLJ’s assessment Earlier this year, Terra Energy Corp. applied only to the Upper Montney zone and announced success at its Groundbirch did not include any incremental assessment property, releasing the results of two of the Lower Montney, Lower Doig or Doig horizontal wells. The first well was phosphate zones. tested at roughly 6 MMcf/d and the T he re ’s a d r i l l i ng i nve ntor y of second test was about 7 MMcf/d. Terra 105 (95 net) locations into the Upper has varying interests in a 14-section

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block of contiguous land, with interests ranging from a 2.5 per cent gross overriding royalty interest to a 100 per cent working interest. Its partner in the area was Monterey.

Christopher Adams, an oil and gas specialist with B.C.’s Ministry of Energy, Mines and Petroleum Resources, said Duvernay’s early activity at Groundbirch delineated an 80-kilometre-long and three-kilometre-wide fairway with additional potential in formations above and below the Doig.

The Doig gas in the Sunset Prairie– Groundbirch complex is interpreted to be in a distal shelf sandstone unit. The basal portion of the Doig is notable for its phosphate zone, an excellent hydrocarbon source rock and one that may house significant shale gas potential. “It really does have to do with the technological angle,” Adams said with respect to the play.

“Because it’s been a major area of activity before, it’s closer to infrastructure.”

Production of the growing unconventional natural gas supplies in northeast British Columbia received a boost in early March when the National Energy Board approved construction of the Groundbirch Mainline Project, an extension of TransCanada Cor poration’s Alberta system. The project is a 77kilometre, 36-inch diameter pipeline that will transport natural gas from the Dawson Creek area to a tie-in point on TransCanada’s Alberta system. It’s expected to be operational in the fourth quarter.

“Construction of the Groundbirch pipeline began in August...and is estimated to be in service by November,” said Cecily Dobson, a TransCanada spokeswoman. The approximate $200-million project has firm transportation contracts that will reach 1.1 billion cubic feet per day by 2014.

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Encana targets liquids-rich gas at Bighorn with $340M budget hike

Photo: Joey Podlubny

by Elsie Ross

Encana is preparing large packages of gas plays in Canada and the United States for possible joint ventures.

Based on success in the Alberta Deep Basin at Bighorn, Encana Corporation plans to increase its 2010 capital spending in the area to about $340 million while taking advantage of the liquids-rich content of the natural gas.

The company also is preparing large packages of natural gas plays in both western Canada and the United States for potential joint ventures. The goal: accelerating the value recognition of its asset base by investors, Randy Eresman, president and CEO, said in a conference call to discuss third-quarter results. Encana posted net earnings of US$569 million for the quarter, along with increased production.

Encana’s Deep Basin assets have a “reasonably high” liquids content, usually between 10 and 40 barrels per million cubic feet (MMcf), depending on the well location. The company is adding liquids extraction equipment at some of its midstream

facilities in the area, said Mike Graham, Canadian division president. “This will allow us to strip out the liquids from the gas stream, thereby capturing more value and enhancing returns.”

Encana did an extensive study this past summer on ethane opportunities from deep cut processing. “The contracts we lock in over the long term make these projects very economic,” said Renee Zemljak, executive VP of midstream, marketing and fundamentals.

Production at Bighorn averaged 260 million cubic feet equivalent per day (MMcfe/d) in the third quarter. Encana has increased its production guidance for the year to 240 MMcfe/d this year from its earlier forecast of 230 MMcfe/d. Falher horizontal wells are completed with about 13 hydraulic fracture stages. Recently, first month initial production rates have been averaging 9 MMcfe/d, well ahead of the type curve, said Graham.

Total Canadian production of 1.5 billion cubic feet equivalent per day (Bcfe/d) in the third quarter was due in part to bringing shut-in gas back on production and to success in the Deep Basin business unit, which includes Bighorn and Cutbank Ridge, he said. Year-to-date per unit operating costs were $1.02 per thousand cubic feet equivalent, in line with the 2009 period reflecting increased volumes and cost efficiencies.

At Cutbank Ridge, which includes Encana’s Montney assets, third-quarter production averaged 463 MMcfe/d. The company drilled 16 net well, including 13 in the Montney where it expects to average 12 fractures per well. Costs have continued to decline with recent all-in fracture costs (drilling, completion and tie in) averaging about $500,000 per stage, down more than 20 per cent from the average 2009 cost of $650,000 per frac. Also at Cutbank, Encana has now completed a 14-stage Cadomin well that is currently flowing at about 6 MMcfe/d, about 80 per cent above expected output.

In its Horn River shale gas play, production averaged about 33 MMcf/d in the third quarter. Encana has completed fracturing operations on the south half of its 63K pad with more than 255 fracs completed to the end of the quarter, the largest frac program to date at Horn River. Over the course of 110 days, the company has completed an average of 2.3 fracs per day. Early production rates are meeting its expectations with per well rates of up to 20 MMcf/d, said Graham.

Encana’s Debolt formation water treatment facility is up and running and is in use at its 63K pad. Non-potable water from the formation currently averages 80 per cent of the total water used at the “gas factory.”

The cost of sourcing and supplying water currently accounts for about $75,000 (12 per cent) of the total $600,000 all-in cost per frac stage. The Debolt water treatment plant is expected to reduce this cost component by about 40 per cent.

NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY

OCT/09

OCT/10

WELL LICENCES

216

277

▲

OCT/09

OCT/10

WELLS SPUDDED

115

219

▲

OCT/09

OCT/10

WELLS DRILLED

104

174

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • DECEMBER 2010

35

Northwestern Alberta/Foothills

Graham said the company’s farmout agreement with Korea Gas Corporation (KOGAS) has been progressing well. It has already drilled four wells in the Montney and plans to drill about three more wells this year. In the Horn River Basin, third-quarter activity consisted of constructing the first wellsite for a planned 10-well pad with the first horizontal well expected to spud later this year. Encana also believes there is the potential for an expansion of the KOGAS agreement, he said.

Encana is still in negotiations with China National Petroleum Corporation (CNPC) leading to a potential joint venture, including development of unconventional gas plays on Encana lands in northeastern British Columbia. “I’m not sure where they are going to go at this point in time,” said Eresman.

Encana also reports good returns on its coalbed methane play even at today’s gas prices. Despite this summer’s wet weather, the company drilled more than 430 net wells in the first nine months with production averaging 312 MMcfe/d. It currently has 13 rigs in operation and drill, complete and tie-in costs are about five per cent below 2010 budget estimates.

Encana will continue to focus on cost efficiencies across the company and “we will not chase growth at any cost,” said Eresman. Teams are working to develop new and innovative solutions for managing its pumping equipment requirements, including the development of new fit-forpurpose completions equipment. These efforts are expected to cost effectively reduce Encana’s backlog of wells awaiting completion by the second half of next year, he said.

Encana is currently working with its advisers to prepare packages of potential joint ventures and expects to have packages of Canadian properties available in weeks and U.S. packages ready in a month, said Bob Grant, executive VP, corporate development. “The goal is to find thirdparty funding to help us accelerate the development of our properties where we wouldn’t be able to get to otherwise for 10-plus years,” he said.

When the company started developing its inventory, “we far exceeded our expectations for the quality of the resource and the size of the inventory that we actually created,” said Eresman. “It presented an

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opportunity for us to find ways to accelerate development of those resources.”

Encana believes that the current New York Mercantile Exchange (NYMEX) gas price below $4 per million British thermal units is unsustainably low, said Eresman. If low prices do persist, Encana may look at reducing capital spending next year to bring it more into line with cash flow, Eresman suggested. The company’s long-term strategy to double production on a per-share basis over the next five years was based on average capital expenditures of $6 billion and would have required an average annual growth rate of about 14 per cent. “However, our view right now is that in light of what could be an extended period of lower prices, it’s just not prudent for us to continue to develop natural gas production at that same pace in the short run.”

At the same time, there are several areas such as in the Horn River Basin and the Montney play where it will need to continue to expand processing capacity and the build-out takes several years. And while the company has not shut in any gas this year, it is getting to the point where it is again under consideration, Eresman said.

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SilverBirch CEO welcomes consolidation trend in oilsands

Photo: Joey Podlubny

by Paul Wells

SilverBirch CEO Howard Lutley says international investors bring useful project engineering skills.

The head of Canada’s newest oilsands company welcomes the “major” consolidation trend that he sees under way in the sector. Howard Lutley is president and CEO of SilverBirch Energy Corporation, which was officially launched Oct. 4. The new firm represents the remaining assets of UTS Energy Corporation after Total E&P Canada Ltd. purchased UTS’s 20 per cent share of the Fort Hills mining project.

“This event [the UTS-Total deal] actually has illustrated one of the major trends going on in the industry, and that is consolidation. It seems that every month a transaction is announced that furthers this trend,” Lutley said in Calgary during a presentation to the 2010 Energy Roundtable event held in October.

“As time progresses, the number of small independent operators is diminishing. In fact, our 50 per cent interest in the Frontier-Equinox projects are the

only large-scale mining assets remaining that are not owned by the major [players],” Lutley said. “We believe this is very significant for us as we advance this project through the engineering and regulatory process.”

Teck Resources Ltd., the operator, and SilverBirch each have a 50 per cent working

Lutley said the upswing in consolidation activity is a boon to the industry on a number of levels, including increasing the focus and spending on technology deployment and development, and adding an influx of new capital to push projects forward, especially from the deep pockets of foreign companies entering the oilsands fray.

“The major international companies bring additional capital and project execution expertise to the industry as well as the resurgent development capabilities associated with these companies. Over time, this should serve to bring more engineering capacity to complement the reciprocal and ongoing R&D efforts in the oilsands by existing operators,” Lutley said. “I believe this will lead to a resolution of many technological challenges the industry faces.”

He noted that oilsands operators are also increasingly adopting a collaborative approach to tackling the myriad issues and public perception fallout endured by the industry in recent years as antioilsands activist ramp up their respective campaigns against the sector.

“We’re seeing a trend amongst the oilsands operators for cooperation and partnering on technology development at an [increased] level...[and] a number of major companies are participating in technology

“Our 50 per cent interest in the Frontier-Equinox projects are the only large-scale mining assets remaining that are not owned by the major [players].”

— Howard Lutley, President & CEO, SilverBirch Energy Corporation

interest in the Frontier and Equinox potential oilsands projects. Lutley said the 50 per cent working interest share in the projects provide the company with a foundation of 891 million barrels of minable contingent resources (best estimate).

development, which is quite unique in this industry,” he said. Lutley alluded to recent and continued work by industry and government to improve industry performance in regard to tailings management and reducing greenhouse gas emissions.

OCT/09

OCT/10

OCT/09

OCT/10

WELLS SPUDDED

60

50

WELLS DRILLED

70

62

NORTHEASTERN ALBERTA WELL ACTIVITY

OCT/09

OCT/10

WELL LICENCES

105

134

▲

▼

▼

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • DECEMBER 2010

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Peter Watson, deputy minister of Alberta Energy, agreed that continued and increased industry-government collaboration is key to ensuring the long-term role of the oilsands as a stable, secure and prolific component to the world’s energy mix.

“Getting access to new markets and also rapidly growing markets will allow us in Alberta to get maximum benefits from our resources for Albertans.... In an oilsands context, our exports go to the United States, and we’re pleased to be situated next to such a fantastic market,” Watson told the 2010 Energy Roundtable.

“But at the same time, we think there’s an opportunity to expand our reach into some other markets that will have a need for oil going forward in the future, and that would mitigate some risks for Alberta,” he added. “We’re going to continue to pursue that, and we do expect that we will see an expansion from our core markets into other regions when there’s more demand pressures.”

With the Canadian Association of Petroleum Producers forecasting that total Canadian oil production will rise from today’s level of about 2.5 million barrels per day to more than four million barrels per day by 2025 — and with most of that increase coming from oilsands operations — Watson said it is essential that access to new and emerging markets comes to fruition.

United Kingdom–based AMEC plc, which is one of the world’s largest engineering firms, has worked with many of the largest oilsands companies. Samir Brikho, AMEC’s CEO, said that while Canada’s private and public sectors have already taken “some important steps” to address lingering issues over the development of the vast resource, the challenge is far from over.

“Heavy oil production and processing is...energy intensive. The growing concern of carbon footprint is high on the Canadian political agenda. [Reducing] the environmental impact of the oilsands means managing technologies, but it also means that managing public perception around the development of these reserves continues to be of great importance,” Brikho said.

“Canada is not alone in the energy world in facing challenges, but, having the world’s second-largest oil reserves, there are a different set of challenges here,” he commented. “Sustainable use of these resources, which minimize carbon impacts perhaps through carbon capture and other means, is a critical challenge.”

Alberta names six scientists to watermonitoring panel Six scientists from across North America will lead a provincial review of water monitoring data collected from Alberta’s oilsands region. The focus of the committee will be to examine monitoring data and methodology of both government and academic research findings. The process is expected to be completed by February 2011.

The scientists bring with them expertise in a variety of areas: metal transportation in fresh water, airborne pollution, effects of toxic chemicals on aquatic organisms, environmental chemistry, ecotoxicology and trace metal loading in the environment.

Individuals were selected based on recommendations by both Alberta Environment scientists and Dr. David Schindler, a water expert at the University of Alberta.

The committee members are: • Peter Dillon, director of the Worsfold Water Quality Centre at Trent University.

His expertise is in the field of airborne pollution and its interaction with watersheds.

• George Dixon, VP of research and professor of biology at the University of Waterloo. His specialty is effects of toxic chemicals — including metals and oilsands process water — on aquatic organisms, principally fish.

• Charles Driscoll, a university professor of environmental systems engineering at Syracuse University in New York state and a member of the U.S. National Academy of Engineering.

• Stuart Hurlbert, director of the Centre for Inland Waters and professor emeritus at San Diego State University. He specializes in human population issues, biostatistics and limnology.

• John Giesy is currently part of the department of veterinary biomedical sciences and toxicology centre at the University of Saskatchewan and was recently elected to the Royal Society of Canada. He is regarded as one of the world’s eminent ecotoxicologists (study of toxic effects, caused by natural or synthetic pollutants, to entire ecosystems).

• Jerome Nriagu, a professor in the School of Public Health as well as a research professor in the Center for Human Growth and Development at the University of Michigan.

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DECEMBER 2010 • OIL & GAS INQUIRER

Central Alberta

Alberta passes the $2B mark as land sales revenue recovers in 2010

SEPAC executive director Gary Leach says strong land sales will bolster drilling activity in 2011.

Alberta’s revenue from Crown land auctions reached $2.07 billion after the province garnered $151.6 million from its provincial land sale on Oct. 27. The equivalent figure for 2009 to that date was $189.9 million.

The Oct. 27 Crown auction featured 296,027 hectares (ha) exchanging hands at an average of $512.16. Year-to-date, 3.29 million hectares have been purchased at an average price of $629.57/ha. To the same point last year, Alberta had auctioned off 1.47 million hectares at an average of $189.91. “[T here were] lots of parcels in [the] west-central Deep Basin, most with deeper rights, so these probably are focused on a number of plays from Cretaceous multi-zone commingled, down to Montney and Duvernay tight/ sha le gas plays,” said Brad Hayes, president of Petrel Robertson Consulting Ltd., when asked about the Oct. 27 sale.

Highlights included a land sale high bid of $14.22 million by Plunkett Resources Ltd. The broker acquired the 4,032 ha parcel, which included several sections, at 62-22 W5 and 63-22 W5, for petroleum and natural gas below the base of the Nordegg member.

Nine licence parcels from 88-8 W5 to 89-8 W5 in the Red Earth Creek area combined for bonus bids of $43.48 million.

The area has been a focus of heavy industry activity and several wells were recently licensed to the southwest of these parcels.

Two of these bids by Canadian Coastal Resources Ltd. tied for a per-hectare average of $15,700. One was a 488 ha licence that produced a bonus of $7.03 million.

The broker acquired the southern half and northeastern quarter of section three and the eastern and western halves of section 10 at 88-8 W5. The other parcel was a 512 ha licence, which produced a bonus

of $8.03 million. The broker successfully picked up sections 27 and 34 at 898 W5.

Two lease parcels bet ween 88-9 W5 and 89-9 W5 produced total bids of $8.11 million. One of these bids of $6.1 million by Plunkett Resources produced the per-hectare high of $21,200. The broker acquired the 288 ha parcel at 88-9 W5.

Daily Oil Bulletin records show that on Oct. 12, Penn West Petroleum Ltd. spudded a horizontal development oil well in the Red Earth area at surface location 3-16-88-8 W5 with the Slave Point formation listed as the total depth zone to a projected depth of 3,110 metres. “[T here were] some interesting, expensive parcels up north, 88-9 W5 in particular,” Hayes added. “I think this would be an oil-prone area, looking for either Duvernay shales or for tight oil reservoirs in Devonian carbonates.”

Gary Leach, executive director of the Small Explorers and Producers Association of Canada, added that the factors that have influenced the pace of sales over the year still apply: the most likely parcels attracting the highest bids will be those with oil as the target or plays like the Duvernay that offer the prospect of superior returns.

“The shift of capital to the emerging resource opportunities in Alberta that started late last year has not yet run its course and the amounts being paid for land sales reflects that,” Leach said. “It’s encouraging and should bolster the recent forecasts for drilling activity in 2011 that will be at least as good if not better than 2010.”

Oilsands parcels attracted $1.2 million in bonus bids for 16,128 ha at the Oct. 27 sale. Year-to-date, the province has attracted $19.98 million in oilsands land sale revenue for 110,354 ha. To the same point in 2009, Alberta had brought in $6.72 million in oilsands revenue for 62,537 ha.

— DAILY OIL BULLETIN

CENTRAL ALBERTA WELL ACTIVITY

OCT/09

OCT/10

WELL LICENCES

209

247

▲

OCT/09

OCT/10

WELLS SPUDDED

167

344

▲

OCT/09

OCT/10

WELLS DRILLED

161

327

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • DECEMBER 2010

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DECEMBER 2010 • OIL & GAS INQUIRER

Southern Alberta

Drilling contractors rebuild and retool for resource plays

Photo: Xtreme Coil Drilling Corp.

by James Mahony

Xtreme Coil Drilling is building its first Coil Over Top Drive rig since 2008, rated to 21,000 feet.

Western Canadian drilling activity is still not strong overall, with about half of Canada’s rig fleet active. Producers continue to shift toward horizontal drilling, typically in search of oil and large-scale tight gas targets. Still deep in the doldrums, due to low natural gas prices, is the shallow gas and coalbed methane activity that used to be the bread and butter of many drillers.

Dale Tremblay, chairman and CEO of Western Energy Services Corp., believes that competitiveness in this sector depends largely on company size and its fleet configuration. In roughly the last year, Western Energy has made five acquisitions. Its most recent move was buying Pantera Drilling Income Fund for $64.1 million.

That all-paper deal will add seven “efficient, long-reach” (ELR) drilling rigs to Western Energy’s fold, bringing the company’s Canadian ELR fleet to 22 rigs.

When the acquisition closes, virtually all

of Western Energy’s fleet will be ELR rigs that are well-suited to horizontal drilling.

This year, Western Energy’s capital budget will come in at about $20 million, before accounting for acquisitions.

In February, Enseco Energy Services Corp. bought Focus Directional Services, a U.S. company for just under US$8 million. In the spring, Enseco acquired Texas-based Pet roleum Direc t iona l Services. Later, the Calgary-based company picked up seven more directional drilling kits for $2.3 million, bringing its recent total to 47 kits.

Xtreme Coil Drilling Corp. has not built a new rig since 2008. However, Xtreme recently signed a service contract for a Coil Over Top Drive rig, the XTC 500, which has the capacity to drill horizontally to depths of 21,000 feet. It’s scheduled to be in service by the second quarter of 2011, is purpose-built for deep resource plays.

John Tasdemir, an oilfield services analyst in Houston with Canaccord Fina ncia l Inc., says t he indust r y ’s current bottleneck is not drilling iron but hydraulic frac pumping power in both Canada and the United States. American pumping capacity stands at roughly 7.5 million horsepower. Even so, Tasdemir estimates between 2,500 and 3,000 U.S. wells are currently awaiting completion, most due to a lack of pumping capacity.

Tasdemir estimates that Canada’s pumping horsepower now totals as much as 1.2 million. Canada’s senior producers often have long-term relationships with service companies, ensuring their access to frac capacity. Smaller players, however, sometimes find themselves at the end of the proverbial line. Analysts expect pumping capacity in western Canada to grow 30 per cent this year, but Tasdemir doubts whether even that much expansion will prove sufficient to satisfy demand in a still-swelling market.

Directional drilling specialists are also thriving in the current market. Phoenix Technology Income Fund, for example, of fers measurement-whi le- dr i l ling, logging-while-drilling, mud motors and downhole tools that are key to steering directional and horizontal wells. So far this year, the company has spent a record $42 million on expansion, up from $17 million in 2009.

In the second quarter of 2010, Phoenix estimates, four of five wells drilled in Canada and two-thirds of those drilled in the United States used horizontal or directional drilling technology. In this country, about two-thirds of the wells the company worked on targeted crude oil rather than gas.

“The world has changed,” says John Hooks, Phoenix’s president and CEO. “[Producers] have gone back into formations that can be productive if fraced with multi-stage or well-isolated fracs.

— DAILY OIL BULLETIN

SOUTHERN ALBERTA WELL ACTIVITY

OCT/09

OCT/10

WELL LICENCES

251

201

▼

OCT/09

OCT/10

WELLS SPUDDED

103

358

▲

OCT/09

OCT/10

WELLS DRILLED

104

358

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • DECEMBER 2010

43

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Southern Alberta

Precision Drilling increases its capital budget and day rates Precision Drilling Corporation is boosting its capital spending this year by $29 million to meet demand and now expects to spend $218 million in 2010 with an additional $82 million to build new rigs in 2011. The company has also repaid its debt by $104 million.

Its 2010 new–rig build program currently stands at nine rigs. On top of the

The third quarter of 2010 was the second consecutive quarter in which Precision realized improved average revenue per day over the previous quarter in the United States, said Neveu. “This confirms our previously stated view that the second quarter of 2010 represented the bottom of Precision’s average day rate for this cycle.”

“If low natural gas prices persist, there is the potential for further regional pullback in gas related activity.”

— Kevin Neveu, President and CEO, Precision Drilling

previously announced capital expenditure plan of $189 million, Precision plans to spend more for North American and international rig and asset upgrades to meet customers’ needs.

Kevin Neveu, Precision’s president and CEO, said the strong customer demand for high-performance rigs targeting oil has led the rig count higher. Approximately 60 per cent of Precision’s rigs working today are drilling for oil or natural gas liquids targets and approximately 80 per cent are drilling complex horizontal or directional wells.

During the third quarter of 2010, an average of 82 drilling rigs worked in Canada and 94 in the United States and Mexico, totalling an average of 176 rigs working.

This compares with an average of 130 rigs working in the second quarter of 2010 and 106 rigs in the third quarter a year ago “If low natural gas prices persist, there is the potential for further regional pullback in gas related activity; however, we would expect most of these rigs to be absorbed by oil and natural gas liquids rich drilling activity,” Neveu commented. “As demand

for Tier 1 Super Series and Tier 2 rigs remains strong, day rates in the U.S. markets are continuing to modestly improve from previous quarters.”

Higher-than-normal rainfall through much of the Western Canadian Sedimentary Basin during the third quarter hampered drilling activity. Precision has recently reactivated approximately 30 rigs sidelined due to poor weather conditions. Its current active rig count in Canada is at 119 and, despite the wet weather, the average rig count of 82 for the third quarter of 2010 was 62 per cent higher than the comparable quarter of 2009.

Due to the increased demand for drilling rigs, Precision is experiencing more demand for rig personnel. On Oct. 1, a wage increase to Canadian rig-based personnel went into effect. Precision is also seeing this increase in demand for rig personnel and a near-term wage increase in the United States is a possibility. The company expects to recoup the majority of these wage increases, if implemented, through higher day rates to its customers.

— DAILY OIL BULLETIN

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Southern Alberta

Gas-weighted juniors look toward stronger gas prices in late 2011 Chris Theal, an analyst with Macquarie Capital Markets Canada, says his firm’s latest natural gas price forecast suggests that more pain is in store for the natural gas sector, with smaller companies being the most affected. Macquarie now expects AECO to average of C$3.95 per thousand cubic feet (Mcf) in 2011, down from its previous estimate of $4.90. The NYMEX price has been downgraded to US$4.40/Mcf from $5.10/Mcf. Longer-term projections are no better.

Most analysts think that North American shale gas production will rise while North American demand remains stagnant.

“We see companies banging up against bank lines,” Theal warns. “When you look at where the engineers are setting their price decks for the year in their engineering reports, there’s going to be some economic limit issues [for renewing loans].”

Peter Howard, interim president of the Canadian Energy Research Institute, paints an even darker picture for the natural gas–weighted junior sector, saying its difficulties will mount in the short term and perhaps beyond.

“If you go around to these small guys in Calgary, they’re probably running off cash flow and they just can’t sit back and say, ‘Well, we will just shut in our wells because we’re not going to sell our gas at this price.’ They’re going to sell it — if they can make a nickel on it, they’re going to make a nickel on it,” Howard says. “I think that’s the fallout of a continued soft market — the juniors could disappear.”

Gary Leach, executive director of the Small Explorers and Producers Association of Canada (SEPAC), says the investment community is “watching closely” to determine which companies among the junior and mid-cap sector will be able to develop,

and then execute, a revamped business model for a low gas price world.

“These large resource play opportunities are not generally available to the junior and mid-cap sector, although a few have positioned themselves in some of the shale gas plays. Even price-hedging strategies, to the extent they were adopted by juniors, are less useful given the bleak outlook for prices signalled by the futures market,” Leach notes.

“Many Canadian junior and midcap producers — some recapitalized with new money and new management teams — started last year to shift their exposure away from natural gas, unless it was the liquid-rich variety, and towards oil targets,” the SEPAC executive director says. Targets include oil resource plays, heavy oil opportunities and even shale oil in a few cases.

Cam Bailey, CEO of Fortress Energy Inc., says, “Canada’s [natural gas] production has dropped from a high of 17 billion cubic feet [Bcf] per day to barely treading water at 13 Bcf per day, and is likely to continue its descent. Meanwhile, south of the boarder, activity continues to be brisk, exploiting unconventional plays, particularly shales.”

Debate continues to focus on whether shale gas plays make money. Chesapeake Energy Corporation, a shale champion, has seen its share price drop by 25 per cent this year. Encana Corporation, also shale gas–driven, has fallen 20 per cent in value.

U.S. natural gas drilling remains strong in large part because of lease retention issues. Bailey says that a significant amount of land was acquired by operators throughout 2008 with a shortened three-year term and 25 per cent royalties in hopes of capturing the value of

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then $8/Mcf natural gas. In some cases, cost per acre was upwards of $15,000 in the Haynesville area resulting in a cost per spacing unit (640 acres) of approximately $9 million.

“As the third year of the lease terms approaches, the question becomes, ‘Do you walk away from a $9-million investment or drill a well to protect the investment?’”

Bailey says, adding that there could be relief in the not-too-distant future. “After the first half of 2011, it is likely we will observe a change in operators’ behaviour where lease retention will become less of a factor in drilling activity and economics derived from the forward prices will prevail,” he predicts.

Shale gas wells have high decline rates. “Without at least 980 rigs operating [in the United States], of which over 70 per cent [are] focused exclusively on resource plays, production will fall quickly,” Bailey suggests. “With a mere 15 per cent drop in rig count, it is possible to experience a decrease in U.S. production from current levels of 59 Bcf per day to 52 Bcf per day at the end of 2011. This would set up the biggest bull market in gas since the first half of 2008.”

However, Bailey cautions that even if drilling activity does fall off, don’t expect an immediate improvement in fundamentals. “The number of wells drilled and yet to be completed is staggering.

For example, in the Haynesville [as of Sept. 18], there were 657 wells producing, 123 wells drilling and 450 wells standing waiting on completion, representing 68 per cent of the producing wells. A prolonged downturn in drilling activity is required to absorb much of this backlog generated by an overly enthusiastic industry.”

— DAILY OIL BULLETIN

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Saskatchewan

Enbridge has Bakken pipeline plans for Saskatchewan and the U.S.

by Elsie Ross

Enbridge estimates that Bakken production will be at nearly 600,000 bbl/d by 2018, double the 2009 capacity.

Enbridge Inc. is planning new pipeline projects to get rapidly growing volumes of Nor t h Dakota, Montana and Saskatchewan Bakken crude to market.

Steve Wuori, president of Enbridge liquids pipelines, told a Toronto investment seminar in early October that his company is also working on a new pipeline proposal from Cushing, Okla., to Houston, Texas.

In the North Dakota Bakken, plans call for a $560-million expansion program with new pipe on both sides of the border that initially would bring 145,000 barrels per day (bbl/d) of incremental capacity into the main system at Cromer, Manitoba, with an in-service date in the first quarter of 2013. The line could ultimately be expanded to 325,000 bbl/d depending on the production growth coming out of North Dakota and Saskatchewan.

The Bakken, currently the only major oil play in the United States, has an

estimated six billion to seven billion barrels of proven reserves of a tremendously highquality, low-sulphur and wax-free light oil, said Wuori. Enbridge believes that Bakken production generally will need to go east to refineries that are configured for light oil and have not made investments in cokers, rather than south to the U.S. Gulf Coast. “It is pointless, I think, for Bakken barrels to go up against Arab Light with its cost structure in the Gulf Coast market; you would probably get beat.”

Enbridge estimates that Bak ken production could grow to just under 600,000 bbl/d by 2018. That’s double the 2009 capacity of 300,000 bbl/d, which included internal use by the Tesoro refinery and other export pipelines but excluded rail and truck transport. Enbridge Energy Partners added 52,000 bbl/d of incremental capacity in January of this year and the line was immediately full.

In Saskatchewan, a $120-million system expansion is underway with a capacity of 125,000 bbl/d to be done in two stages. The first phase will be the reversal of the existing portal link between Saskatchewan and North Dakota to flow 25,000–35,000 bbl/d north into the Saskatchewan system to alleviate bottlenecks on the North Dakota side. That should be complete by the fourth quarter of this year.

“We are looking to leverage our existing infrastructure positions, we are looking to eliminate bottlenecks and provide the fastest way for pipeline access for barrels that need to exit the basin,” said Wuori.

In Alberta, Enbridge is also working on a northbound industry condensate pipeline to meet growing producer demands for diluent for bitumen production. The line would run from Edmonton along the east side of Alberta, likely through Cheecham, although that hasn’t yet been confirmed, said Wuori.

Enbridge is also working on developing new eastern and Gulf Coast projects, analysts heard. As the heavy crudes come into PADD II (U.S. Midwest) where refinery conversions have occurred, it will displace the demand for Canadian and other light crudes in that area, he said. “Those crudes cannot go south; light crudes are already hopelessly bottlenecked at Cushing."

To the south, Enbridge’s proposed Monarch Gulf Coast extension project would be a pipeline from Cushing to Houston. “We really feel that there is a need for a drain for Cushing,” said Wuori.

At present, West Texas Intermediate is disconnected from world pricing largely because of the bottleneck at Cushing. As Canadian heavy crudes increasingly fill up northern U.S. refiners, there will be less need to move crudes north out of Cushing.

The only place for those volumes will be to the south, he said.

— DAILY OIL BULLETIN

SASKATCHEWAN WELL ACTIVITY

OCT/09

OCT/10

WELL LICENCES

261

346

▲

OCT/09

OCT/10

WELLS SPUDDED

195

317

▲

OCT/09

OCT/10

WELLS DRILLED

187

345

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • DECEMBER 2010

49

Saskatchewan

Saskatchewan’s October land sale brings in $35.54M Interest in the Weyburn-Estevan area continues to fuel Saskatchewan’s land sale revenues, accounting for $25.5 million of the province’s total of $34.54 million in bonus bids at its October sale. The province disposed of 73,120 hectares (ha) at an average price of $472.39/ha. The October sale last year generated $32.41 million in bonus bids on 61,828 ha at an average of $524.24/ha.

Year-to-date, the province’s land sale revenue has recovered after a dip in 2009. With one sale left in December, Saskatchewan has collected $406.17 million for 389,626 ha, an average of $1,042/ha. To the same point last year, $83.24 million had rolled into provincial coffers as 232,681 ha exchanged hands at an average of $357.76/ha.

“The majority of parcels posted and sold in the Weyburn-Estevan area this sale form a halo around the proven Bakken play, which supports...thoughts that producers continue to push the limits of the Bakken in all directions,” sa id Pau l Ma h n ic, d i rec tor of t he petroleum tenure branch.

Of particular note this sale are the five exploration licences that sold for $15.7 million between Moosomin and Carlyle in southeastern Saskatchewan,

Mahnic said. These parcels accounted for nearly half of the entire sale and the high level of interest can be attributed to multiple targets in the area, including the emerging Devonian Birdbear formation, the Bakken formation and conventional oil targets in the Mississippian (Tilston and Souris Valley beds) towards the town of Carlyle and the Jurassic (Red Jacket and Gravelbourg formations) in the direction of Moosomin.

The sale’s top bonus of just over $7 million was submitted by Prairie Land & Investment Services Ltd. for a 2,561 ha licence six kilometres north of the Parkman Souris Valley Beds (Oil) Pool, 23 kilometres southwest of Moosomin.

The broker acquired several sections at 11-32 W1, 12-32 W1, 11-33 W1, 12-33 W1 and 12-34 W1.

Daily Oil Bullet in records show Reliable Energ y Ltd. licensed a well in early Aug ust at surface location 16 -8-12-33 W1 in the Wawota area with the Birdbear listed as the total depth zone to a projected depth of 1,120 metres. Other operators in the area include Tundra Oil & Gas Partnership and Harvest Operations Corp.

P ra i r ie L a nd & I nve st ment wa s the top purchaser of acreage in the

prov ince, spending $17.5 million to acquire nine lease parcels and f ive exploration licences. The broker also paid the top price for a single lease of $1.6 million for a 1,036 ha parcel 10 kilometres west of the Amulet Ratcliffe Beds (Oil) Pool, six kilometres north of Ogema in southeastern Saskatchewan.

The parcel included sections 9, 10, 15 and 16 at 8-22 W2.

Aldon Oils Ltd. produced the highest per-hectare high average of $9,343 for a 129.5 ha parcel one kilometre west of the Ceylon Bakken (Oil) Pool, 14 kilometres west of Radville, Sask. The company paid a bonus of $1.2 million for the eastern half of section 16 at 6-19 W2.

Daily Oil Bul let in records show that A ldon rig released a horizontal development oil well on May 10 with t he Ba k ken for mat ion listed as t he total depth zone at surface location 14-10-6-19 W2 in the Ceylon area to a total depth of 2,867 metres.

Gas-prone areas of the prov ince attracted bonus bids of $1.2 million for 7,510 ha at an average of $158.72/ha.

Parcels offering deeper rights brought in $225,327 (0.65 per cent of the sale) for an average price of $90.39/ha.

— DAILY OIL BULLETIN

Palko plans to provide oil emulsion treatment at Midale through a unique deal Palko Environmental Ltd. has entered into an arrangement to use excess capacity of an oil battery and disposal well operated by an intermediate producer to provide custom treating of oil emulsions, pipeline access for crude oil and disposal of water.

Leveraging the company’s single shipper and marketing agreement with Gibson Energy ULC, Palko said it will provide a logistically streamlined, one-stop service for the handling and marketing of oil emulsion in southeastern Saskatchewan.

Located in Midale, Sask., the facility includes a truck terminal for the acceptance of dry oil, custom treating for emulsions, water disposal capacity and a direct pipeline connection to deliver oil to market. Palko

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DECEMBER 2010 • OIL & GAS INQUIRER

said it will provide accurate and accountable custody transfer and measurement through a certified Micro Motion measurement system. “ We a r e v e r y e x c i t e d a b o u t entering into this unique and mutually beneficial arrangement,” said Steven Peterson, president of Palko. “ T he relationship partners our Gibson singleshipper agreement, treating expertise and customer relationships with an underutilized oil battery and disposal well.

“We will now be able to provide an expanded and needed service to our current and future customers within the region. The location of the facility will allow us to leverage off our resources in

place at our existing Midale full-service waste facility, while advancing an innovative network-based midstream strategy for our customers.”

Palko estimates that the facility should ultimately provide its customers with access to approximately 10,000 cubic metres per month, in custom oil treatment and shipping capacity.

In October, Palko also announced the formation of a technical advisory group, which will act as an innovation forum to assess and apply leading-edge treatment technologies and processes to oilfield wastes. The group is comprised of four individuals from the Schulich School of Engineering at the University of Calgary.

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Central Canada

PSAC study says oil and gas services boosted annual GDP by $65B

PSAC says 36 Canadian service firms generated $12.8 billion in export sales and services during 2009.

A study commissioned by the Petroleum Services Association of Canada (PSAC) found that the oil and gas services sector contributed $65 billion to Canada’s gross domestic product (GDP) in 2006. A second PSAC-sponsored study indicates that 36 Canadian service companies generated total revenue of $12.8 billion in 2009 from international operations and export sales of manufactured product export sales.

The reports were released by PSAC in early October. In the GDP study, the Canadian Energ y Research Institute (CERI) estimated that the oil and gas service sector employed 800,000 workers across Ca nada a nd cont r ibuted $9 billion in personal and corporate taxes to federal and provincial governments. Using the same methodology, CERI calculated that the 2006 GDP of Canada’s automobile industry was $25 billion; agriculture, $26 billion; mining, $18 billion; forestry, $29 billion; and residential construction, $34 billion.

P S A C c h a i r m a n D a v i d Ya g e r acknowledged that 2006 was a strong year in the oilpatch. Even so, he argued that “this is probably one of the largest

industries in Canada that really is not understood.” The services association undertook this research project with the following objectives:

that the oil and gas ser v ice sector is consulted and in the creation of future energy policies and industrial strategies.

“If you take the prov ince of A lberta, the debate on economic rent tends to focus on royalties with comparisons on ot her jur isdic t ions,” Yager sa id. “ T he rec yc le rat io of t he dol la r i n Canada through the Canadian industr y is extraordinarily high. You can make the case that if you leave a dollar in the royalty system at the wellhead and allow that to churn through the economy down to research and development a nd pa r t icipat ion, you may create more than a dollar in economic va lue. We’re t r y i ng to broaden t he economic discussion of the impact of the oil and gas industr y...beyond the simple royalty debate.”

The CERI study was done using an input /out put model, as well as data from Statistics Canada from the most recent comprehensive business survey conducted in 2006. PSAC contracted Mission Capital Ltd. to compile informat ion about t he i nter nat iona l (a l l

“You can make the case that if you leave a dollar in the royalty system at the wellhead and allow that to churn through the economy down to research and development and participation, you may create more than a dollar in economic value.”

— David Yager, Chairman, Petroleum Services Association of Canada

• I llustrate the significant contribution made through oil and gas services to the Canadian economy through economic activity, jobs and taxes; • S eek recognition for the skills, technolog y a nd i n nov at ion t hat have made Canadian energy service firms into world leaders, with that success proven through commercial growth i n i nter nat iona l ma rket s a nd t he purc hase of Ca nadia n tec h nolog y companies by global players; and • G ive policy and opinion makers the i n for m at ion t hey need to en su re

countries outside of Canada) revenues of 51 selected Canadian oil and gas service companies.

Of the total, 36 had international operations. A company is considered to be Canadian if it was founded in Canada; headquartered in the country; and has cent ral f inance, operations and control functions residing in the head office. “The advantage there has been technology,” Yager said. “That is one of the aspects of this business that is not particularly well understood.”

— DAILY OIL BULLETIN OIL & GAS INQUIRER • DECEMBER 2010

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The patch reacts cautiously to proposed offshore liability hikes

Photo: Joey Podlubny

by James Mahony

Regulators and producers are debating who pays how much if an Atlantic or Beaufort well blows out.

The prospect that the federal government could raise liability limits for environmental incidents in Canada’s offshore has been topical since BP’s massive oil blowout in the Gulf of Mexico last April. “The liability limits need to be greatly increased,” said Will Amos, director of Ottawa’s Ecojustice Environmental Law Clinic. “We should be looking to the U.S., where the debate is on whether the limits should be abolished or raised significantly.

“At a minimum, we should be matching the U.S. liability limits [of US$75 million], given that we’re dealing with a situation that in the Arctic...would be so much more difficult [to manage],” Amos says. Unlike the Gulf of Mexico, he notes that Arctic waters are often inaccessible for several months a year, a factor that could exacerbate damage from a blowout.

David Pryce, operations VP for the Canadian A ssociation of Petroleum Producers (CAPP), is concerned about how far any proposed liability reform would go. “We need to strike a balance... without [increasing the limit] to an extent that it would preclude [offshore] activity.

We’re interested in trying to find the right

balance in terms of what an appropriate amount would be for limited liability.”

Ola Morten Aanestad, VP of media relations for Statoil North America, shared CAPP’s concern: “[As a company], we need to assess the risk-reward picture in all the basins [where] we work, and base our investment decisions on a totality of factors,” he pointed out “This is an industry with

As part of a comprehensive review of offshore drilling, the National Energy Board (NEB) will take a closer look at the financial liability provisions that benefit producers working Canadian waters. The NEB’s jurisdiction includes Canada’s North and the West Coast. On the East Coast offshore, producer liability is governed by the federal-provincial Atlantic Accords.

Some environmentalists believe that the Canada Oil and Gas Operations Act (COGOA) would oblige a producer to pay at most $40 million toward remediation of an offshore incident, with governments footing any remaining costs. “The taxpayer can’t afford to be chasing down oil companies...for portions of the damage caused to our country,” Amos said. “We need a system that allows for full, comprehensive liability protection.”

In public documents, the NEB has said that the COGOA “does not limit...liability, but imposes additional absolute liability” up to $40 million on a company responsible for an offshore incident, without the need to prove liability. The board went on to say that, with proof of fault or negligence, “there is no upper limit of liability for loss or damage.”

Canada could also choose to emulate America’s Oil Spill Liability Trust Fund, a federal body that has been called a “war chest” against environmental catastrophe.

“The taxpayer can’t afford to be chasing down oil companies... for portions of the damage caused to our country.”

— Will Amos, Director, Ottawa’s Ecojustice Environmental Law Clinic

enormous capital expenditure, and stable, predictable...conditions are important in order to maintain and attract investment.”

For incidents in Canada’s offshore, the current liability cap is $40 million in Arctic waters and $30 million in the East Coast offshore. The BP blowout prompted a review of offshore drilling by Canada’s Senate. After public hearings, the senators said a ban on offshore drilling in Canada was not justified, recommending that other steps be taken instead, including a review of the liability issue.

For years, the fund has been financed by a small per-barrel fee on crude oil at the refinery gate. At the same time, it’s not clear how far the fund has offset the ongoing cleanup and remediation costs of the BP blowout.

One benefit of an industry-wide fund is that, like Alberta’s Orphan Well Fund, it would exist indefinitely. In particular, the fund would survive the bankruptcy or insolvency of individual oil and gas companies, potentially including those liable for offshore environmental incidents.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • DECEMBER 2010

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International

Shell VP says lower gas costs are vital to tapping foreign markets

Shell’s Lorraine Mitchelmore says global gas markets could expand by almost 50 per cent over 20 years.

Canada must drive down its natural gas costs so it can meet soaring future demand for the clean-burning fuel overseas, according to Royal Dutch Shell plc’s top executive in this country. “The opportunity is in the global liquefied natural gas [LNG] arena,” said Lorraine Mitchelmore, Shell’s country chair for Canada and VP of onshore gas exploration and appraisal for the company’s upstream Americas division.

“At Shell, our view is that global gas demand could rise by one-quarter by 2020, and almost 50 per cent by 2030,” Mitchelmore told a Calgary Chamber of Commerce audience on Oct. 28. “To see what underpins our forecast, one need look no further than China, [which] wants to more than double the share of natural gas in [its] energy mix, to around 8–10 per cent by 2020.”

As a result, Shell estimates that China’s annual gas demand could be comparable to half of the current U.S. demand within a decade. “This is part of the reason why, even in these difficult times, China and other Asian countries remain keen to secure supplies through long-term contracts,” Mitchelmore said.

Canada is the world’s third-largest gas producer at about six trillion cubic feet per year, and the top gas exporter to the United States. On the supply side, the world now has enough “technically” recoverable gas to last 250 years at current production rates, said Mitchelmore, who’s a geophysicist by profession.

She said its abundance makes the fuel attractive for electricity generation.

Supply is being boosted by a surge of shale gas production in the U.S., which has also driven down prices in North America. The Shell executive added that the difference between gas prices in North America and Asia (where the price is tied to oil) is sufficient to justify construction of an LNG export terminal off Canada’s West Coast.

“But we’ve got to think about ways to drive our costs down as a country to attract the Chinese and [other] Asian countries to come to our market. And that’s what’s key because they’re looking to diversify their market,” Mitchelmore said. “It’s very important for us to access that growing market.”

Shell doesn’t disclose its Canadian production, but it is a big gas producer,

notably from the Montney play in British Columbia and the Deep Basin. In 2008, Shell paid $5.8 billion for Duvernay Oil Corp., a successful B.C. gas player. “[We are] investing billions in natural gas because we believe that gas is essential to helping to meet the challenge of a growing world population at a much lower environmental cost,” Mitchelmore said.

“As natural gas emits 50 per cent lower CO 2 , it can displace coal in the near term and support cleaner air for the long run.” In reply to a question from the audience later, the Shell executive suggested it makes more sense for Canada to generate power from gas than coal.

“We should use in Canada our cleanestburning fuel. It is less costly than coal,” she said.

To establish financial predictability for energy producers, Shell also supports government imposition of a carbon emissions trading system. To bring all these elements together, Mitchelmore argued that Canada “urgently” needs a national energy strategy to deal with resource production and transportation and consumer conservation.

“We are hampered by the existing infrastructure and must find a timely way to build major new infrastructure projects that are needed to open up new markets for Canadian energy,” the Shell VP said. “These include Enbridge’s Northern Gateway project, TransCanada’s Keystone Pipeline, the Mackenzie Valley Pipeline and potentially [an LNG] terminal off the west coast of B.C.” The Newfoundland native made a plea to her business audience to pressure politicians to end the “infighting. We are acting like 10 different countries. We need to act as one country and position ourselves for the future,” Mitchelmore said. “Alberta should not be against Ottawa. We [Albertans] should not be against Quebec. We’ve got to start coming together to actually really try to stand together to compete globally. Because that’s the future.”

— DAILY OIL BULLETIN OIL & GAS INQUIRER • DECEMBER 2010

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onthe

JOB Careers in the Oilpatch

Deborah Close Age: 57 Title: President Company: Concord Well Servicing Location: Calgary Education: BA from the University of Calgary; many in-house engineering courses

Photo: Christina Ryan

What do you do?

invoicing. Eight years later, DO2 was purchased by a global company. In August,

Two months ago, I became president of Concord Well Servicing, a division of

CCS brought me on board as president.

CCS Corporation. We’ve got 131 rigs operating across the Western Canadian Sedimentary Basin. Like everyone else, our rig utilization has been lower for a

How would you describe sector-wide conditions for service rig companies?

couple of years. Now we’re ready to start growing the operation again.

Tough but getting better. The Canadian fleet has fallen from 1,100 to 900 active rigs in two years. On the gas side, coiled tubing [CT] competitors have bit off

What brought you into the oilpatch?

some of our service business because they can work on a well under pressure.

Oil and gas companies had a dearth of qualified personnel in the ’70s. Even

However, killing an oil well has far less negative impact on future production,

a French major like me could get started on a career if she had talent and a

and service rigs cost a lot less than CT, so for oil CT isn’t as advantageous.

strong work ethic. The ERCB [Energy Resources Conservation Board] hired me

Producers are now shifting to oil as fast as they can, which is great for us. Also,

at a clerical level in the gas department. At the board, I did basic reservoir work

there are many thousands of existing wells with jointed pipe that will need

like calculating reserves and tracking water production. Then Amoco Canada

service rigs for a long time to come. Finally, CT is not well-suited to SAGD

made me an engineering technologist, sending me to many technical courses

[steam assisted gravity drainage] and heavy oil projects, which require larger-

in Tulsa over nearly 10 years. I handled reservoir-related work, production

diameter pipe. All in all, I’m optimistic.

operations and finally supply and marketing. I spent nearly 10 years with Amoco and I’ll always be grateful for that opportunity.

What are your plans for Concord?

Even through the downturn, we remained profitable, largely because our crews

How did you get onto the management track?

and equipment are really appreciated by our customer base. Technologically,

I decided to jump over to the business side, going into sales with a couple of

Concord has always been progressive. We have a service rig simulator for

small software and data companies in Calgary. That was a big change. The

training purposes, for instance, and we were the first operator to introduce

second company was acquired by Landmark Graphics, which pioneered 3-D

electronic tour sheets on service rigs. That tradition will continue. Concord

interpretation of seismic data. Later Halliburton bought Landmark. I became

has plans for technical, marketing and maybe one or two staffing innovations

a vice-president for different regions, and lived in Texas and London. In 2002, I

in the near future. I’m not in a position to tip my hand yet in terms of specifics,

moved to DO2 Technologies, a Calgary company that specialized in electronic

but call me again in a year.

OIL & GAS INQUIRER • DECEMBER 2010

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TOOLS

OF THE TRADE A LOOK AT NEW TECHNOLOGIES

Cessna Citation Mustang Who is Opus Aviation?

Opus Aviation, a subsidiary of The Ledcor Group of Companies, is a private jet charter service based in Edmonton and Vancouver. Over the past decade, Ledcor has leveraged its internal aviation department to help grow its own business across the continent and as of September 2010, now offers its diverse fleet to customers throughout western Canada.

What is the Cessna Citation Mustang?

Opus Aviation’s advantage is its diverse fleet offering of “right-sized aircraft” for Alberta and B.C. travellers. Opus is one of the first commercial operators of the new Very Light Jet (VLJ) class of aircraft with the Cessna Citation Mustang. It’s an entirely new kind of business jet with seating for four passengers, true jet speed and most importantly a radical shift in jet charter costs. Forbes Magazine noted that when the Cessna Mustang flies with a full cabin, its fuel efficiency at 41,000 feet rivals a Honda Accord with a solo driver at 70 miles per hour. Opus currently has two Mustangs, one based at the Edmonton International Airport and the second at the Vancouver International Airport.

What are the competitive advantages of Cessna’s Very Light Jet? Performance. The Citation Mustang is incredibly versatile: • A ble to access hundreds of additional airports due to its shorter runway requirements.

• Higher flight altitude and hot temperature takeoff performance provides greater mission flexibility than other VLJs. • Climbs to more fuel-efficient altitudes faster and transitions through weather more quickly than other VLJs. • Slower critical airspeeds enhance safety during takeoff and landing.

• Consumes less fuel on every mission.

Opus Aviation also has a Gulfstream G100 and a Dassault Falcon 50EX to fulfill long-haul flights and higher passenger capacity missions.

Both these aircraft have extremely long range and can carry up to

7–9 passengers, respectively. By combining the Cessna Mustang with a midand heavy-sized jet, Opus Aviation is able to provide maximum operational flexibility to its clients.

How did Lecor, with its oilfield construction roots, get into aviation?

Ledcor historically has had great success moving key employees, customers and critical components to remote project sites with its aircraft, which can be a costly expenditure for most companies. Opus Aviation now offers this same competitive advantage for other companies doing business throughout Alberta and B.C. The relatively low operating costs of the Cessna Mustang make it an excellent choice for companies and individuals who need to move strategic assets into and out of the field. The Cessna Citation Mustang’s jet speed and 40,000 feet “above the weather” capability provide an excellent tool for businesses that need fast and efficient transportation.

Answered by: Danica Wolfe, Corporate Communications, Ledcor Industries Inc.

OIL & GAS INQUIRER • DECEMBER 2010

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DECEMBER 2010 • OIL & GAS INQUIRER

EITI Electrical Industry Training Institute . . . . . . 42 FalCan Industries Ltd . . . . . . . . . . . . . . . . . . . . . 30 Falvo Electrical Supply Ltd . . . . . . . . . . . . . . . . . 54 FDI Acoustics Inc . . . . . . . . . . . . . . . . . . . . . . . . . 33 Flexpipe Systems . . . . . . . . . . . . . . . . . . . 44 & 45 Gaugetech Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 GlobalFlow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54 Iron Brothers Construction . . . . . . . . . . . . . . . . . 11 Joule Technical Sales Inc . . . . . . . . . . . . . . . . . . 60 Kal Tire . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 LJ Welding & Machine . . . . . . . . . . . . . . . . . . . . . 52 Lockhart Oilfield Services Ltd . . . . . . . . . . . . . . 32 LoTech Manufacturing Inc . . . . . . . . . . . . . . . . . 48 Marv Holland Apparel Ltd . . . . . . . . . . . . . . . . . 40 MCI Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 Meridian Mfg Group . . . . . . . . . . . . . . . . . . . . . . 28 Millennium Directional Service Ltd . . . . . . . . . . 34 MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . 38 Norseman Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 Northgate Industries Ltd . . . . . . . . . . . . . . . . . . 54

Northstar Energy Services Inc . . . . . . . . . . . . . . . 4 Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . 46 OilPro Oilfield Production Equipment Ltd . . . . . 54 Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39 Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . . 34 Platinum Energy Services Corp . . . Outside back cover Platinum Grover Int. Inc . . . . . . . Inside front cover Propak Systems Ltd . . . . . . . . . . . . . . . . . . . . . . . 3 Prostate Cancer Canada Network . . . . . . . . . . . 51 Savanna Energy Services Corp . . . . . . . . . . . . . . . 5 Silverado Oilfield Ventures Ltd . . . . . . . . . . . . . . 39 Summit Telecom Services . . . . . . . . . . . . . . . . . 48 Suncor Energy Inc . . . . . . . . . . . . . . . . . . . . . . . . 33 Systech Instrumentation Inc . . . . . . . . . . . . . . . . 7 Trans Peace Construction (1987) Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 Vertigo Theatre Society . . . . . . . . . . . . . . . . . . . 51 V.J. Pamensky Canada Inc . . . . . . . . . . . . . . . . . . 10 Waydex Services LP . . . . . . . . . . . . . . . . . . . . . . 51

“Reducing the cO2 fOOtpRint Of OuR Oil sands OpeRatiOns – that’s the best paRt Of my jOb.” It’s exciting, working to capture one million tonnes of greenhouse gases every year from oil sands production and safely storing it two kilometres underground.

That’s like taking 175,000 cars off the road. We’re doing it by pulling together a groundbreaking team of experts to better understand the unique challenges of CO2 storage on this industrial scale. The same geological properties that naturally trap oil and gas will also safely store the CO2 deep underground.

As we solve problems, the solutions and knowledge will be shared so others can build on it.

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

Get the real story at capp.ca/oilsands

Syrie Crouch Shell Canada

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

g n i t a ! r s b r e l a Ce ye2010

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