Oil & Gas Inquirer - January/February 2011 by JWN | Trusted energy intelligence

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Canada’s strong dollar and buoyant eConomy now float on prospeCtive Cash flows from its oil and natural gas. who Created that prosperity? no single individual, however riCh or famous, Can reasonably be assigned more than a tiny sliCe of the total Credit for upstream petroleum development. instead, Canadians owe their thanks to tens of thousands of oil and gas workers. to Joe Citizens who look perfeCtly ordinary but Canada’s strong dollar and buoyant eConomy now float on prospeCtive Cash flows from its oil and natural gas. who Created that prosperity? no single individual, however riCh or famous, Can reasonably be assigned more than a tiny sliCe of the total Credit for upstream petroleum development. instead, Canadians owe their thanks to tens of thousands of oil and gas workers. to Joe Citizens who look perfeCtly ordinary but are aCtually teChnology-armed revolutionaries.to individuals like bruCe peaChey, a quiet-spoken edmontonian who has dediCated most of his working life to heavy oil and bitumen. peaChey is well aware that researCh and development invested in this energy-riCh gunk Can pay off hugely— twiCe over. “first, we’ll reCover billions of barrels in future produCtion. seCond, we Can export our teChnology and expertise to a world that needs more energy,” the Consultant prediCts. “in terms of making a signifiCant global Contribution, alberta’s most promising opportunities still revolve around our hydroCarbon resourCes.” peaChey’s grandfather, John kennedy, supervised maintenanCe at a power plant in regina. “he was the ClassiC teChniCally inClined sCot from glasgow. his example inspired my own interest in solutions that resolve praCtiCal problems and avoid waste,” says the professional engineer. in 1976, he graduated in ChemiCal engineering at the university of saskatChewan. “when i first went to Cold lake in 1977, imperial had two small-sCale bitumen pilot tests underway,” peaChey reCalls. “bitumen was used for low-value produCts like asphalt paving and shingles.” at that time, heavy and extra heavy Crudes aCCounted for about 15 per Cent of Canada’s produCtion. however, light and medium output had already begun to drop, a deCline that has so far proven irreversible. in response, engineers and teChnologists developed heavier Crude produCtion from lloydminster, fort mCmurray and Cold lake/bonnyville in alberta. today, heavy oil and bitumen make up twothirds of this Country’s total petroleum produCtion. thanks to that inCrease, Canada’s net exports of oil now stand at about one million barrels per day, forming a powerful pillar within the national eConomy. over his Career, peaChey has worked with most aspeCts of oil development. by 1990, he was a senior member of the imperial team that managed annual Capital investment of $100 million at Cold lake, along with operational spending of $250 million. nowadays, as the prinCipal of new paradigm engineering ltd., his present and past Clientele inCludes a lengthy roster of heavy oil and bitumen produCers, government researCh agenCies and the upstream seCtor’s Collaborative researCh and development organizations. an enthusiastiC mentor of fresh talent, he also teaChes engineering students at the university of alberta. heavy oil is defined as Crude that’s 20 degrees api and Capable of flowing without the addition of heat. bitumen is thiCker yet and typiCally won’t flow without artifiCial for that matter, more2011 than  90 per Cent of heavy oil also won’t move to a wellbore using traditional walking beam pumps and vertiCal stimulation. January/February $6.00 wells. at lloydminster, the maJor stumbling bloCk to heavy oil produCtion was sand. large quantities of grit and sand flowed with the Crude into wellbores, Choking off traditional walking beam pumps. by the late 1970s, manufaCturers had Come up with effiCient progressing Cavity pumps (pCps), designed speCifiCally for large sand throughput. pCps enabled field operators to initiate Chops. “in a Chops system, methane gas bubbles out of solution with the heavy Crude and Carries along the finer partiCles of sand,” peaChey explains. “at first, a new well’s produCtion is frothy, a mix of oil with up to 40 per Cent sand by volume. this stuff has the ConsistenCy of shaving Cream.” as the finer sand is evaCuated, the heavier partiCles Consolidate, enabling “wormholes” to form within the Crude reservoir. those wormholes aCt like mini wellbores for additional oil flow. aChops only works effeCtively in relatively thin oil-bearing formations, typiCally two metres thiCk or less. “wormholes form due to pressure distribution within the reservoir, that muCh we know,” peaChey says. “but we don’t know what the reservoirs and wormholes aCtually look like. people still argue over the meChanism behind their formation, and so far no one has been able to simulate the proCess reliably with Computer models.” wormholes render waterflooding ineffeCtive as a teChnique for enhanCed oil reCovery (eor). “in faCt, Chops and waterflooding are mutually exClusive meChanisms,” peaChey says. “Chops produCes a lot of sand but little water. a signifiCant water breakthrough signals the end for a Chops proJeCt.” even so, waterflooding has potential for all mobile Crudes, inCluding heavy oil. the petroleum teChnology allianCe Canada estimated five years ago that low-Cost water management Could add a billion barrels to western Canada’s oil reserves. sinCe then, alberta energy resourCes Conservation board has been approving new eor appliCations at a fairly steady rate: 39 in 2006, 37 in 2007, 32 in 2008, 31 in 2009 and 27 as of mid-oCtober in 2010. nearly all of those new proJeCts were waterfloods. “in heavy oil reservoirs, floods work best where any underlying water is not well-ConneCted to an aquifer,” peaChey explains. waterflooding pushes heavy and light Crude ahead toward a wellbore, but the drive meChanism varies signifiCantly for heavy oil. “we still only have a very limited understanding of the prinCiples involved, based on studies by the saskatChewan researCh CounCil and others,” he says. “slow waterfloods are best. the water gradually seems to drag the oil with it. my view is that the proCess is probably almost like erosion.” theoretiCally, peaChey aCknowledges, waterflooding shouldn’t work at all in heavy oil. “in praCtiCe, we’ve learned through trial and error that flooding Can generate good results as long as bottom water remains inaCtive. [only if underlying water remains inaCtive Can produCers Create and maintain a pressure differential between inJeCtion and produCing wells.] the advanCes in horizontal drilling teChnology have been a big help with heavy oil waterfloods. horizontal inJeCtors and produCing wells have proven to be more effeCtive than vertiCal wells.” where a heavy oil reservoir does have a strong ConneCtion to an underlying aquifer, produCers Can strive to Create an aCtive water drive. in that Case, Crude produCtion may be enhanCed until the water breakthrough beComes exCessive. peaChey suggests that proJeCts of this type may be suitable for ChemiCally enhanCed eor teChniques, espeCially the use of polymers mixed with water. polymers are long-Chained hydroCarbon moleCules that Create a thiCker, more visCous fluid (similar in ConsistenCy to hand lotion) Capable of dragging along more oil. “polymers are salt-sensitive petroChemiCals, whiCh is why they are rarely used to enhanCe light and medium Crude reCovery. those grades of oil are CharaCteristiCally formed at depths where salt water is usually present,” peaChey says. “heavy oil reservoirs are shallower and more often CharaCterized by fresh water, whiCh is a CritiCal key faCtor for polymers.” steaming amounts to flooding with heat. peaChey arrived at Cold lake while sCientifiC pioneer roger butler was experimenting with steam-assisted reCovery of bitumen through well pairs. “butler’s ideas led to the drilling of imperial’s first horizontal well in that proJeCt, whiCh was designed to ColleCt oil released through steam inJeCtion from a vertiCal well,” the new paradigm prinCipal remembers. “we weren’t able to establish an effeCtive steam Chamber. at that time, we still didn’t have drilling teChnology Capable of drilling the parallel horizontal well pairs that are used today for sagd reCovery.” to drill one horizontal well preCisely above another horizontal well, the alberta oilsands researCh and development authority Created an underground test faCility near fort mCmurray. that provinCially sponsored proJeCt proved that steam inJeCted into an upper wellbore would Cause an eConomiC quantity of bitumen to flow downward into a ColleCtor well. from that initiative Came today’s bitumen sagd proJeCts, and thermal flooding is being applied to heavy oil as well. “to Create an eConomiCally viable steam Chamber for heavy oil, the reservoir formation must be at least 10 metres thiCk,” peaChey says. “otherwise, too muCh heat is absorbed by the surrounding roCk.” to date, Chops has been the most effeCtive new teChnique for heavy oil but its initial rush of development is Cresting; the teChnology has been applied to many of the most suitable geologiCal formations. emphasis is now shifting toward water and ChemiCal inJeCtion. “we’re seeing enCouraging results from polymer flooding, whiCh is relatively inexpensive,” peaChey reports. “Co2 floods have been more problematiC at lloydminster, although several small proJeCts are ongoing. Carbon dioxide beComes misCible with Crude only at high pressure, making it a good ChoiCe for light and medium oil. heavy oil reservoirs are typiCally too shallow to provide the required pressure. also, pure Co2 is expensive.” at one time, the eor veteran points out, Cold produCtion with sand was widely seen as impraCtiCal. “now we know that Chops will enable us to reCover an additional five to 10 per Cent of the total oil in plaCe,” he Comments. “that suCCess has been a big boost in seCuring funding for further r&d.” besides the Current proJeCts, future teChnologiCal possibilities for heavy oil and bitumen inClude solvents, energy pulsing, miCrobial aids, new mining teChniques and innovative drilling tools. as long as oil remains, peaChey says, Canada’s innovators will Continue to wrest more of it from the roCk. Canada’s strong dollar and buoyant eConomy now float on prospeCtive Cash flows from its oil and natural gas. who Created that prosperity? no single individual, however riCh or famous, Can reasonably be assigned more than a tiny sliCe of the total Credit for upstream petroleum development. instead, Canadians owe their thanks to tens of thousands of oil and gas workers. to Joe Citizens who look perfeCtly ordinary but are aCtually QUIET REVOLUTIONARIES dediCated most of his working life to teChnology-armed revolutionaries.to individuals like bruCe peaChey, a quiet-spoken edmontonian who has heavy oil and bitumen. peaChey is well aware that researCh and development invested in this energy-riCh gunk Can pay off hugely—twiCe over. LIkE bRUcE pEAchEy AREneeds more “first, we’ll reCover billions of barrels in future produCtion. seCond, we Can export our teChnology and expertise to a world that energy,” the Consultant prediCts. “in terms of making a signifiCant global Contribution, alberta’s most promising opportunities still revolve bRINgINg pROSpERITy TO around our hydroCarbon resourCes.” peaChey’s grandfather, John kennedy, supervised maintenanCe at a power plant in regina. “he was the ClassiC teChniCally inClined sCot from glasgow. his example inspired my own interest in solutions that resolvewITh praCtiCal problems and avoid cANAdA A RISINg waste,” says the professional engineer. in 1976, he graduated in ChemiCal engineering at the university of saskatChewan. “when i first went to Cold fLOOd Of hEAVIER cRUdES lake in 1977, imperial had two small-sCale bitumen pilot tests underway,” peaChey reCalls. “bitumen was used for low-value produCts like asphalt paving and shingles.” at that time, heavy and extra heavy Crudes aCCounted for about 15 per Cent of Canada’s produCtion. however, light and medium output had already begun to drop, a deCline that has so far proven irreversible. in response, engineers and teChnologists developed heavier Crude produCtion from lloydminster, fort mCmurray and Cold lake/bonnyville in alberta. today, heavy oil and bitumen make up twothirds of this Country’s total petroleum produCtion. thanks to that inCrease, Canada’s net exports of oil now stand at about one million barrels per day, forming a powerful pillar within the national eConomy. over his Career, peaChey has worked with most aspeCts of oil development. by 1990, he was a senior member of the imperial team that managed annual Capital investment of $100 million at Cold lake, along with operational spending of $250 million. nowadays, as the prinCipal of new paradigm engineering ltd., his present and past Clientele inCludes a lengthy roster of heavy oil and bitumen produCers, government researCh agenCies and the upstream seCtor’s Collaborative researCh and development organizations. an enthusiastiC mentor of fresh talent, he also teaChes engineering students at the university of alberta. heavy oil is defined as Crude that’s 20 degrees api and Capable of flowing without the addition of heat. bitumen is thiCker yet and typiCally won’t flow without artifiCial stimulation. for that matter, more than 90 per Cent of heavy oil also won’t move to a wellbore using traditional walking beam pumps and vertiCal wells. at lloydminster, the maJor stumbling bloCk to heavy oil produCtion was sand. large quantities of grit and sand flowed with the Crude into wellbores, Choking off traditional walking beam pumps. by the late 1970s, manufaCturers had Come up with effiCient progressing Cavity pumps (pCps), designed speCifiCally for large sand throughput. pCps enabled field operators to initiate Chops. “in a Chops system, methane gas bubbles out of solution with the heavy Crude and Carries along the finer partiCles of sand,” peaChey explains. “at first, a new well’s produCtion is frothy, a mix of oil with up to 40 per Cent sand by volume. this stuff has the ConsistenCy of shaving Cream.” as the finer sand is evaCuated, the heavier partiCles Consolidate, enabling “wormholes” to form within the Crude reservoir. those wormholes aCt like mini wellbores for additional oil flow. aChops only works effeCtively in relatively thin oil-bearing formations, typiCally two metres thiCk or less. “wormholes form due to

in the

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Keeping readers regionally informed

F E A T U R E S

Heavy and extra heavy By Mike Byfield

Quiet revolutionaries

Good times in the border city

Canadian prosperity—present and future—relies heavily on technology specialists like Bruce Peachey who force thick crude from rock

Lloydminster is humming on the strength of high crude prices

23 The dog reborn

Husky Energy’s new boss spends heavily to restore growth

Destroying rock with finesse By Mike Byfield

26 Bit of a gamble

Drilformance, a new PDC drill bit manufacturer in Leduc, takes on the global giants

30 Cutting-edge career

Inventor Ian Gillis lived through the breakthrough development of PDC drill bits

32 Grinding faith 26

J A N U A R Y / F e b ruary 2 0 1 1 • O I L & G A S I N Q U I R E R

Sicotte’s Steve Shim believes roller cone drill bits will always have a place in the western basin

R E G I O N A L

35 39

N E W S

British Columbia • First phase of Apache-EOG Kitimat

LNG export plant budgeted at $3B

profile helps service sector

by Richard Macedo

by Paul Wells and Richard Macedo

Northwestern Alberta • Paramount Energy focuses capital

plans on Grande Prairie and Kaybob

Northeastern Alberta • Total and Suncor launch Voyageur

Central Alberta • Alberta Crown land sales in 2010 are

second-highest ever at $2.4B

Saskatchewan • Crescent Point Energy pegs its

2011 capital program at $800M

and Fort Hills oilsands projects

Southern Alberta • Changing western Canadian well

Central Canada • Enbridge defends export

project after federal MPs favour tanker ban

International • Energy service sector is poised

for greater global growth in 2011

I N

E V E R Y

I S S U E

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O I L & G A S I N Q U I R E R • J A N U A R Y / F e b ruary 2 0 1 1

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Editor’s Note Vol. 23 No. 1 President & ceo Bill Whitelaw | bwhitelaw@junewarren-nickles.com

Mike Byfield | mbyfield@junewarren-nickles.com

Canadian success, American failure

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Although few Canadians really grasp the fact, Canada has achieved enormous success in domestic crude oil production. In contrast, the United States has failed by any measure. During the first half of the 20th century, Canada struggled desperately to produce oil from its small proven reserves for two world wars. Simultaneously, the U.S. accounted for 70 per cent of world oil production in 1925, 63 per cent in 1941 and over 50 per cent in 1950. South of the 49th parallel, however, domestic reserves were not replaced despite the fact that American technology dominated the global oil industry. By 1970, the U.S. could no longer supply its own crude consumption. In 2009, Americans imported 63 per cent of their oil. Dependence on foreign energy drains their economy and jeopardizes their national security. Canada could easily have fallen down the same economic crack. Our domestic light and medium crude production peaked in 1973 and has been decreasing ever since. Fortunately, this country developed its heavy and extra-heavy crude resources, as outlined in this issue’s cover story. We’re now better off than ever, and the picture promises to improve further in future. The U.S. did not necessarily have to fall so abysmally short. Its shale oil resource, although technically daunting, has been quantified on an immense scale, easily comparable to Canada’s oilsands and heavy oil. Yet even now, the federal government in Washington continues to downplay shale oil development in Colorado and Wyoming. Ironically, innovative shale oil technology pioneered by Shell Oil in the U.S. may well be deployed more effectively in Alberta’s carbonate bitumen reserves. Canadians do not hear much good about heavy and extra-heavy crude. “Dirty oil,” sneers a tribe of critics across North America—yet they offer no alternative energy sources that would be even faintly reliable. If these perfectionist folks had been on our backs, westerners could not have built transcontinental railways and harnessed the Prairie soil to feed a hungry world. In our own time, two generations of western oilmen have performed on that same magnificent scale.

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Subscription Inquiries Telephone: 1.866.543.7888 Email: circulation@junewarren-nickles.com Online: junewarren-nickles.com Oil & Gas Inquirer is owned by JuneWarren-Nickle’s Energy Group and is published monthly. GST Registration Number 826256554RT. Printed in Canada by PrintWest. ISSN 1204-4741 | © 2011 1080554 Glacier Media Inc. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number 40069240. Postage Paid in Edmonton, Alberta, Canada. If undeliverable, return to: Circulation Department, 800 - 12 Concorde Place, Toronto, ON M3C 4J2 Made in Canada The opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.

N E X T

I S S U E

March edition In March, Oil & Gas Inquirer visits Grande

If you know an admirable person to profile in

Prairie, Alta., where petroleum producers and

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

service providers are battling low natural gas

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

prices through technical innovation and an

please give me a call at (780) 784-4251, or

intensifying hunt for liquids-rich formations.

email mbyfield@junewarren-nickles.com.

Plus, we review western Canada’s technical

In fact, feel free to sound off about any

colleges, where tomorrow’s oilpatchers are

concern at all—that’s a personal invitation.

trained through state-of-the-art programs. O I L & G A S I N Q U I R E R • J A N U A R Y / F E b ruary 2 0 1 1

Stats

FAST NUMBERS

12,145

AT A GLANCE

Canadian well count for 2010, 45 per cent higher than 2009

million metres

Canadian drilling total for 2010, 62 per cent higher than 2009

Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

MONTH

OIL

GAS

OTHER

TOTAL

MONTH

OIL

GAS

DRY

SERVICE

TOTAL

Jan 2010 Feb 2010 Mar 2010

253 144 264

324 308 579

62 114 198

639 566 1,041

Jan 2010 Feb 2010 Mar 2010

429 147 548

343 143 681

55 20 109

13 5 20

840 315 1,358

Apr 2010 May 2010 Jun 2010

198 400 126

418 462 117

6 51 41

622 913 284

Apr 2010 May 2010 Jun 2010

291 490 295

458 511 153

2 39 40

9 19 16

760 1,059 504

Jul 2010 Aug 2010 Sept 2010

131 168 357

110 135 638

38 43 59

279 346 1054

Jul 2010 Aug 2010 Sept 2010

193 452 617

9 156 790

16 40 45

4 15 23

222 663 1475

Oct 2010 Nov 2010 Dec 2010

404 579 676

460 847 403

46 169 294

909 1595 1373

Oct 2010 Nov 2010 Dec 2010

678 868 1061

581 989 559

39 75 78

18 165 238

1316 2097 1936

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

Jan 2010 Feb 2010 Mar 2010

65 101 98

65 166 264

Jan 2010 Feb 2010 Mar 2010

153 169 223

18 58 32

6 4 8

177 231 263

Apr 2010 May 2010 Jun 2010

56 54 41

320 374 415

Apr 2010 May 2010 Jun 2010

92 86 149

10 7 7

3 3 11

105 96 167

Jul 2010 Aug 2010 Sept 2010

65 43 39

480 523 562

Jul 2010 Aug 2010 Sept 2010

220 198 197

7 12 5

0 7 6

227 217 208

Oct 2010 Nov 2010 Dec 2010

42 43 41

604 647 688

Oct 2010 Nov 2010 Dec 2010

201 217 340

12 3 2

11 64 11

224 284 353

*From year to date

20.5

wells

J A N U A R Y / F e b ruary 2 0 1 1 â&#x20AC;˘ O I L & G A S I N Q U I R E R

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

GAS STOR AGE

Source: Natural Gas Exchange Inc.

Source: U.S. Energy Information Administration

4.00

3.5

$3.695/GJ Total vol.: 1,553 TJ Transactions: 228

2.72 Tcf Year ago: 2.64 Tcf 5-year avg: 2.67 Tcf

3.0

3.75

3.50

in the United States

Dec 22

Cdn$/GJ

Dec 29

Jan 5

Jan 12

2.5

Jan 19

Source: Natural Gas Exchange Inc.

Tcf

Dec 17

Dec 24

Dec 31

Jan 7

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada January 18, 2011 Source: Rig Locator

Alberta December 2010 Source: Daily Oil Bulletin

ACTIVE

DOWN

TOTAL

ACTIVE (Per cent of total)

Western Canada Alberta

453

116

569

British Columbia

Manitoba

Saskatchewan

110

WC Totals

629

163

792

Northwest Territories

OIL WELLS

Alberta

GAS WELLS

Dec 10

Dec 09

Dec 10

Dec 09

Northwestern Alberta

114

Northeastern Alberta

167

Central Alberta

373

Southern Alberta

219

TOTAL

676

403

125

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada January 18, 2011 Source: Rig Locator

Alberta December 2010 Source: Daily Oil Bulletin

ACTIVE

DOWN

TOTAL

ACTIVE

Western Canada Alberta

204

650

British Columbia

Manitoba

Saskatchewan

149

184

WC Totals

641

248

889

100

Quebec

COALBED METHANE

Alberta 446

Jan 14

Source: U.S. Energy Information Administration

BITUMEN WELLS

Dec 10

Dec 09

Dec 10

Dec 09

Northwestern Alberta

Northeastern Alberta

166

Central Alberta

168

Southern Alberta

TOTAL

342

O I L & G A S I N Q U I R E R â&#x20AC;˘ J A N U A R Y / F e b ruary 2 0 1 1

Quiet Feature

Canadian prosperity—present and future—relies heavily on technology specialists who force thick crude from rock by Mike Byfield

anada’s strong dollar and buoyant economy now float on prospective cash flows from its oil and natural gas. Who created that prosperity? No single individual, however rich or famous, can reasonably be assigned more than a tiny slice of the total credit for upstream petroleum development. Instead, Canadians owe their thanks to tens of thousands of oil and gas workers. To Joe Citizens who look perfectly ordinary but are actually technology-armed revolutionaries. To individuals like Bruce Peachey, a quiet-spoken Edmontonian who has dedicated most of his working life to heavy oil and bitumen. Peachey is well aware that research and development invested in this energy-rich gunk can pay off hugely—twice over. “First, we’ll recover billions of barrels in future production. Second, we can export our technology and expertise to a world that needs more energy,” the consultant predicts. “In terms of making a significant global contribution, Alberta’s most promising opportunities still revolve around our hydrocarbon resources.” Peachey’s grandfather, John Kennedy, supervised maintenance at a power plant in Regina. “He was the classic technically inclined Scot from Glasgow. His example inspired my own interest in solutions that resolve practical problems and avoid waste,” says the professional engineer. In 1976, he graduated in chemical engineering at the University of Saskatchewan. “When I first went to Cold Lake in 1977, Imperial had two small-scale bitumen pilot tests underway,” Peachey recalls. “Bitumen was used for low-value products like asphalt paving and shingles.” 12

J A N U A R Y / F e b ruary 2 0 1 1 • O I L & G A S I N Q U I R E R

At that time, heavy and extra heavy crudes accounted for about 15 per cent of Canada’s production. However, light and medium output had already begun to drop, a decline that has so far proven irreversible. In response, engineers and technologists developed heavier crude production from Lloydminster, Fort McMurray and Cold Lake/Bonnyville in Alberta. Today, heavy oil and bitumen make up two-thirds of this country’s total petroleum production. Thanks to that increase, Canada’s net exports of oil now stand at about one million barrels per day, forming a powerful pillar within the national economy. Over his career, Peachey has worked with most aspects of oil development. By 1990, he was a senior member of the Imperial team that managed annual capital investment of $100 million at Cold Lake, along with operational spending of $250 million. Nowadays, as the principal of New Paradigm Engineering Ltd., his present and past clientele includes a lengthy roster of heavy oil and bitumen producers, government research agencies and the upstream sector’s collaborative research and development organizations. An enthusiastic mentor of fresh talent, he also teaches engineering students at the University of Alberta. Heavy oil is defined as crude that’s 20 degrees API and capable of flowing without the addition of heat. Bitumen is thicker yet and typically won’t flow without artificial stimulation. For that matter, more than 90 per cent of heavy oil also won’t move to a wellbore using traditional walking beam pumps and vertical wells. To boost recovery rates, oilmen have created new technologies. The most common techniques are: • Cold heavy oil production with sand (CHOPS) • Waterflooding in various configurations • Chemical flooding • Steam injection, either through steam assisted gravity drainage (SAGD) and cyclic steam stimulation. At Lloydminster, the major stumbling block to heavy oil production was sand. Large quantities of grit and sand flowed with the crude into wellbores, choking off traditional walking beam pumps. By the late 1970s, manufacturers had come up with efficient progressing cavity pumps (PCPs), designed specifically for large sand throughput. PCPs enabled field operators to initiate CHOPS.

Photo: Aaron Parker

revolutionaries

t Photo: Aaron Parker

Feature

Bruce Peachey considers himself a typical working engineer from an extraordinary generation. O I L & G A S I N Q U I R E R â&#x20AC;˘ J A N U A R Y / F e b ruary 2 0 1 1

Feature

“In a CHOPS system, methane gas bubbles out of solution with the heavy crude and carries along the finer particles of sand,” Peachey explains. “At first, a new well’s production is frothy, a mix of oil with up to 40 per cent sand by volume. This stuff has the consistency of shaving cream.” As the finer sand is evacuated, the heavier particles consolidate, enabling “wormholes” to form within the crude reservoir. Those wormholes act like mini wellbores for additional oil flow. CHOPS only works effectively in relatively thin oil-bearing formations, typically two metres thick or less. “Wormholes form due to pressure distribution within the reservoir, that much we know,” Peachey says. “But we don’t know what the reservoirs and wormholes actually look like. People still argue over the mechanism behind their formation, and so far no one has been able to simulate the process reliably with computer models.” Wormholes render waterflooding ineffective as a technique for enhanced oil recovery (EOR). “In fact, CHOPS and waterflooding are mutually exclusive mechanisms,” Peachey says. “CHOPS produces a lot of sand but little water. A significant water breakthrough signals the end for a CHOPS project.” Even so, waterflooding has potential for all mobile crudes, including heavy oil. The Petroleum Technology Alliance Canada estimated five years ago that low-cost water management could add a billion barrels to western Canada’s oil reserves. Since then,

The Petroleum Technology Alliance Canada has estimated that low-cost water management could add a billion barrels to western Canada’s oil reserves.

Alberta’s CO2 strategy teeters

on the brink of collapse A

s an independent consultant, Bruce Peac hey has ear ned a reputation for occasionally voicing awkward facts. Right now, the principal of New Paradigm Engineering Ltd. wonders if the Alberta government’s CO 2 sequestration strategy is teetering on the brink of collapse, along with the province’s strongest remaining prospect for a new bitumen upgrader. Peachey’s concerns focus on an upgrading project proposed for Sturgeon County and an associated 240-kilometre CO2 pipeline to oilfields in central Alberta. CO2 is a greenhouse gas, potentially an agent in triggering human-induced climate change. Oilsands upgrading generates large volumes of CO2 . However, this chemical is also a highly effective injectant for enhanced oil recovery (EOR). A handful of Calgarians have blended those two factors into a pair of allied projects that have attracted favourable attention from the Alberta government. As yet,

though, the province has not decided whether to proceed with them or not. North West Upgrading Ltd. and Canadian Natural Resources Limited propose to construct an upgrader/refinery near Edmonton. The new facility would be engineered to create generous volumes of high-purity CO2 , specifically 3,500 tonnes daily when all proposed phases are completed. Total CO2 supply in the area would be raised to about 5,100 tonnes (1.8 megatonnes per year) with emissions from a nearby fertilizer plant operated by Agrium Inc. That CO2 would be shipped to EOR projects in central Alberta via a provincially subsidized pipeline proposed by Enhance Energy Inc. CO 2 -driven EOR projects have the potential to boost recovery rates of light and medium crude by an estimated 10-15 per cent of the original oil in place. The Alberta government’s Carbon Capture and Storage Development Council says

J A N U A R Y / F e b ruary 2 0 1 1 • O I L & G A S I N Q U I R E R

that 1.4 billion barrels of otherwise untapped oil could be produced from existing conventional reser voirs in Alberta through EOR projects employing CO2 . The council also estimates that, at $75 per barrel of oil, this increased output could generate between $11 billion and $25 billion in provincial royalties and taxes. Peachey, an EOR advocate, says CO2 has enhanced recovery rates in many oilfields in the United States, where high purity carbon dioxide can be produced from naturally occurring reservoirs. Unfortunately, western Canada has no large geological sources of this gas in a pure form. Industrial sources, including coal-fired power plants, generate impure CO 2 that’s prohibitively expensive to upgrade to EOR quality. In Peachey’s view, the North West and Agrium plants on their own cannot provide enough CO 2 to underpin the economics of a new pipeline from the Edmonton area to central Alberta. His point is not particularly controversial. Enhance itself always planned to tap additional CO2 supply from other new upgraders that have been planned near the provincial capital. “Unfortunately,

Feature

Illustration: Aaron Parker

those upgraders now appear unlikely to be built,” the consultant comments. “It ’s muc h c heaper to use sur plus capacity or even add upgrading capacity to existing refineries in the U.S. than to construct standalone upgraders in Alberta.” Existing refineries can benefit from much of their already-constructed infrastructure, Peachey points out, especially if their traditional heavy crude feedstocks from Venezuela and Mexico are shrinking. Energy consumption is another factor that heavily favours existing refineries. The bitumen, once heated to upgrading temperatures, can move immediately to the refining stages with minimal reheating. In addition, upgrading generates by-products that have little market in Alberta, and the province has limited pipeline or rail capacity for exporting those valuable products to international markets. A s a consequence, several new upgrader projects in Alberta remain on the shelf rather than in the ground. Instead, western Canadian bitumen producers have made long-term alliances with refiners in the U.S. Midwest and Gulf regions. New oilsands mining

Alberta Energy Resources Conservation Board has been approving new EOR applications at a fairly steady rate: 39 in 2006, 37 in 2007, 32 in 2008, 31 in 2009 and 27 as of mid-October in 2010. Nearly all of those new projects were waterfloods. “In heavy oil reservoirs, floods work best where any underlying water is not well-connected to an aquifer,” Peachey explains. Waterflooding pushes heavy and light crude ahead toward a wellbore, but the drive mechanism varies significantly for heavy oil. “We still only have a very limited understanding of the principles involved, based on studies by the Saskatchewan Research Council and others,” he says. “Slow waterfloods are best. The water gradually seems to drag the oil with it. My view is that the process is probably almost like erosion.” Theoretically, Peachey acknowledges, waterflooding shouldn’t work at all in heavy oil. “In practice, we’ve learned through trial and error that flooding can generate good results as long as bottom water remains inactive. [Only if underlying water remains inactive can producers create and maintain a pressure differential between injection and producing wells.] The advances in horizontal drilling technology have been a big help with heavy oil waterfloods. Horizontal injectors and producing wells have proven to be more effective than vertical wells.” Where a heavy oil reservoir does have a strong connection to an underlying aquifer, producers can strive to create an active

projects such as Imperial Oil’s Kearl and Husky Energy’s Sunrise projects do not include upgraders. And industry analysts have pointed out that the provincial government cannot intervene to retain additional upgrading within Alberta unless taxpayers are willing to incur potentially large financial risk. “Does it make sense to build a carbon dioxide pipeline with a capacity of 40,000 tonnes per day if you’re never likely to have more than 5,000 tonnes of suitable CO2 available for that pipeline?” Peachey queries. “And if there’s no CO2 pipeline, why would anyone build an upgrader-refinery that’s designed to produce large quantities of CO2?” But t he prospec t of rema i n i ng raw bitumen producers, with little value added, upsets many Albertans. Last year, delegates to the A lberta P r og r e s si ve C on s e r v at i ve Pa r t y ’s annual convention urged the provincial government to take steps to ensure that at least 65 per cent of bitumen is upgraded within the province. That’s an ambitious goal. In its most recent oil supply forecast, the Canadian Association of Petroleum Producers estimated that (assuming no

government intervention) the actual upgrading figure will be 36 per cent by 2020 (including upgraded heavy oil). “We have enough diluents available to ship the remaining bitumen elsewhere for processing,” Peachey says. “While everyone wishes we could do all of the upgrading here, the reality is the same for bitumen as it is for the cattle, grain, lumber, plastics and minerals produced in Alberta. We have enough people to produce the raw products. We don’t have the people, infrastructure or access to markets do allow us to do much value addition here without aggressive subsidization or artificial limits on exports of raw goods.” Peachey, as a technical analyst, takes no political position on government policy decisions such as publicly sub-sidizing bitumen upgraders. He does point out that Alberta happens to have an additional source of high-purity carbon dioxide that’s well-suited to EOR. “The big sour gas processing plants in the foothills produce a lot of CO2 ,” he says. Those gas plants are located fairly near conventional oilfields in districts that already have many established pipeline rights-of-way.

O I L & G A S I N Q U I R E R • J A N U A R Y / F e b ruary 2 0 1 1

Feature

water drive. In that case, crude production may be enhanced until the water breakthrough becomes excessive. Peachey suggests that projects of this type may be suitable for chemically enhanced EOR techniques, especially the use of polymers mixed with water. Polymers are long-chained hydrocarbon molecules that create a thicker, more viscous fluid (similar in consistency to hand lotion) capable of dragging along more oil. “Polymers are salt-sensitive petrochemicals, which is why they are rarely used to enhance light and medium crude recovery. Those grades of oil are characteristically formed at depths where salt water is usually present,” Peachey says. “Heavy oil reservoirs are shallower and more often characterized by fresh water, which is a critical key factor for polymers.” Steaming amounts to flooding with heat. Peachey arrived at Cold Lake while scientific pioneer Roger Butler was experimenting with steam-assisted recovery of bitumen through well pairs. “Butler’s ideas led to the drilling of Imperial’s first horizontal well in that project, which was designed to collect oil released through steam injection from a vertical well,” the New Paradigm principal remembers. “We weren’t able to establish an effective steam chamber. At that time, we still didn’t have drilling technology capable of drilling the parallel horizontal well pairs that are used today for SAGD recovery.” To drill one horizontal well precisely above another horizontal well, the Alberta Oilsands Research and Development Authority created an underground test facility near Fort McMurray. That provincially sponsored project proved that steam injected into an upper wellbore would cause an economic quantity of bitumen to

flow downward into a collector well. From that initiative came today’s bitumen SAGD projects, and thermal flooding is being applied to heavy oil as well. “To create an economically viable steam chamber for heavy oil, the reservoir formation must be at least 10 metres thick,” Peachey says. “Otherwise, too much heat is absorbed by the surrounding rock.” To date, CHOPS has been the most effective new technique for heavy oil but its initial rush of development is cresting; the technology has been applied to many of the most suitable geological formations. Emphasis is now shifting toward water and chemical injection. “We’re seeing encouraging results from polymer flooding, which is relatively inexpensive,” Peachey reports. “CO 2 f loods have been more problematic at Lloydminster, although several small projects are ongoing. Carbon dioxide becomes miscible with crude only at high pressure, making it a good choice for light and medium oil. Heavy oil reservoirs are typically too shallow to provide the required pressure. Also, pure CO2 is expensive.” At one time, the EOR veteran points out, cold production with sand was widely seen as impractical. “Now we know that CHOPS will enable us to recover an additional five to 10 per cent of the total oil in place,” he comments. “That success has been a big boost in securing funding for further R&D.” Besides the current projects, future technological possibilities for heavy oil and bitumen include solvents, energy pulsing, microbial aids, new mining techniques and innovative drilling tools. As long as oil remains, Peachey says, Canada’s innovators will continue to wrest more of it from the rock.

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New Owners Continue

Tradition of Excellence at Copp’s

opp’s Pile Driving is an oilfield services company based in Red Deer, Alberta, with a proud tradition of operational excellence and customer service. Going forward, that tradition will continue with the purchase of Copp’s by Dennis and Jason Weinberger, who took over Copp’s from Big Eagle LLP in November 2010. The Weinbergers bring a proven business history in the Western Canadian oilfield services industry to Copp’s Pile Driving. “We are service company guys,” says Jason, the new president of the firm. The Weinbergers founded and built Jade Oilfield Service, a family-owned business in Red Deer, which operated a fleet of 30 water and vacuum trucks servicing drilling rigs throughout Western Canada. In 2004, they founded Canyon Technical Services, a pressure pumping company providing fracturing, coil tubing, nitrogen, acidizing and cementing services. Headquartered in Calgary, Canyon operates Alberta bases in Red Deer, Grande Prairie and Medicine Hat, and a Saskatchewan location in Estevan. Dennis Weinberger was Canyon’s chief executive officer until he retired in the fall of 2009. Jason was Canyon’s vice president of operations until October 2010, when he stepped down in order to take the helm of Copp’s Pile Driving. The new owners plan to maintain pile driving services as the company’s core business. They also plan to update the equipment fleet, expand product and service lines, and open new bases in strategic areas within the next few years. The company’s long-standing tradition of operational excellence and customer service dates back to 1992, when it was established as a family business by Rodney Copp, with a focus on consistently high performance standards. Copp’s Pile Driving is a leading provider of pile driving and related services for the oil and gas, construction, and infrastructure industries. Its clients are primarily oil and gas producers, including several oilsands operators in the Fort McMurray area of Alberta. The company has grown rapidly from day one, thanks to its innovative service offerings and

industry-leading customer service. Its main focus is pile driving, which is primarily used in oilfield applications. Copp’s also provides all-terrain pile driving services, pre-drilling services, picker services, and pipe sales and transportation throughout the entire Western Canadian Sedimentary Basin. Copp’s Pile Driving takes pride in being a leader in customer service, with a strong management team, experienced operators, modern equipment, strong industry relationships, an excellent reputation, and the ability to respond quickly to new opportunities. The Weinbergers have retained all of the company’s existing staff and are currently ramping up staffing numbers for winter, in conjunction with adding to the firm’s equipment fleet and expansion into new areas. “There will be employment opportunities in all areas of the business,” says Jason. To take the business forward, Jason will work closely with general manager Andy Attfield, who learned the business from the company’s founder. In addition to its core service, Copp’s Pile Driving will add services related to the pile driving industry, as required by customers. Going forward, the company will continue to focus on diversification throughout the Western Canadian Sedimentary Basin. “Our forte is customer service whether on smaller daily jobs or large-scale, multi-year projects,” Jason says. “We service a wide range of projects.”

Contact Information: Copp’s Pile Driving | A Div. of Copp’s Services Inc. Phone: 403.347.6222 | Toll-free: 1.866.887.3606

www.coppspiledriving.com

Photo: Joey Podlubny

Good times

Photo: Joey Podlubny

Feature

in the border city

Lloydminster is humming on the strength of high crude Prices by Mike Byfield

he Alberta-Saskatchewan border region is benefiting from good times, according to the Lloydminster Chamber of Commerce. Pat Tenney, its executive director, says the chamber now has 555 member firms, up from about 300 a decade ago. “New people are walking through the door every day,” she reports. “We’re seeing a lot of entrepreneurial start-ups in the retail sector—clothing, print, food specialties and so on. Unemployment is low, the community is still very short of rental accommodation, and real estate prices are strong but affordable.” Driving Lloydminster’s prosperity is capital spending by heavy oil producers, fuelled in turn by high oil prices. In late December,

West Texas Intermediate light crude fetched about US$90 per barrel, while heavy grades from western Canada hovered at C$75 or higher. The bulk of that oil moves to market through the pipeline grid operated by Enbridge Inc. In January, producers overbooked portions of Enbridge’s Midwestern pipelines by 26-43 per cent. Simultaneously, Kinder Morgan could meet only 40 per cent of the requested demand on its TransMountain pipeline system from Alberta to Vancouver. The pipeline choke backed up surplus crude into Alberta and prompted a widening of the price differential between light and heavy grades. That spread widened to about $21 per barrel for January delivery, up by one-third or more from the beginning of December. Although some marketers expect transportation difficulties to continue, Enbridge chief executive officer Pat Daniel is optimistic that major capacity restrictions will be shortlived. Either way, Alberta’s heavy producers are bound to see

O I L & G A S I N Q U I R E R • J A N U A R Y / F e b ruary 2 0 1 1

Feature

“Our international business has multiplied by roughly 10 times over the past seven years, and we’ve just had another strong year.”

Conventional heavy oil activity has sparked little landowner protest.

— Hans Gjerdrum, International Sales Manager, Kudu Industries Inc.

booming oil markets as reason to continue making field investments through the coming year. Plans announced for 2011 by Harvest Operations Corp. are typical for a larger heavy oil producer in western Canada. Harvest intends to drill heavy oil wells near Lloydminster and Suffield. The Calgary-based firm has also budgeted $240 million toward its BlackGold bitumen project near Conklin, Alta. Facility construction and productionwell drilling for the BlackGold steam assisted gravity drainage (SAGD) oilsands project are scheduled to commence in 2011. Of that cost, $190 million will be spent on construction and design of BlackGold’s facility while approximately $50 million will be spent on drilling 10 production well pairs and 12 observation wells. Smaller companies are also joining the heavy oil hunt. For example, Hawk Exploration Ltd. recently announced a significant new heavy oil discovery at an unidentified location in western Saskatchewan. Over the first month of production, the single-leg horizontal discovery well reportedly averaged over 80 barrels per

day of heavy crude oil with an associated water cut of 45 per cent. Based on Hawk’s analysis, this discovery represents the first commercial production from this formation. This unnamed formation is a Devonian-aged carbonate reservoir located at a relatively shallow depth with excellent permeability, according to Hawk. No fracture stimulation of the reservoir was performed in the initial horizontal well, nor is any expected in future wells. Full development of the play could see up to 16 horizontal legs drilled per section, on a land position that currently stands at 11 sections. Hawk said it plans to start development of this play by drilling three dual-leg horizontal wells in the first quarter of 2011. In fact, heavy oil production is surging pretty much everywhere this thick grade of crude can be found. “Our international business has multiplied by roughly 10 times over the past seven years, and we’ve just had another strong year,” says Hans Gjerdrum, international sales manager for Kudu Industries Inc. The Calgary-based company manufactures progressing cavity pumps (PCPs), used primarily for heavy oil. “Kudu has sold its PCPs in 35 countries,” says Gjerdrum. “We constantly find Canadian specialists and equipment at work in these oilfields— that’s natural because Lloydminster was the first big centre of heavy oil production.”

The Lloydminster Heavy Oil Show attracted more than 225 exhibitors in September. 20

J A N U A R Y / F e b ruary 2 0 1 1 • O I L & G A S I N Q U I R E R

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dog Feature

The

reborn Husky Energy’s new boss spends heavily to restore growth

by Mike Byfield

usky Energy Inc., the granddaddy among heavy oil producers, expects to pour $4.9 billion this year into reversing its slipping production and profitability. Profits for the first nine months of 2010 fell to $868 million from $1.1 billion for the same period in 2009. Husky’s global output averaged 289,000 barrels of oil equivalent (boe) per day for the first nine months of 2010, versus 356,000 boe two years earlier. In part, the Calgarybased firm’s decline stems from its Tucker thermal oilsands project in northeastern Alberta, which has been pumping 5,000 barrels per day rather than the scheduled 30,000 barrels. Leading Husky’s multibillion-dollar recovery campaign is a man who’d never previously pumped a barrel of oil in his life. Asim Ghosh, appointed president and chief executive officer in June, began his career in Canada as a packaged goods specialist with Procter & Gamble. He moved on to a senior vice-president role with Toronto

brewer Carling O’Keefe and then became the co-founding chief executive officer of Pepsi Foods’ start-up operations in India. In 1998 Li Ka-shing, the Hong Kong tycoon who controls Husky, put Ghosh in charge of Vodafone Essar, then a virtual start-up mobile phone company. The Indian operation was sold in 2007 for US$18 billion. At Husky, Ghosh hit the ground running. In November, Husky purchased oil and gas properties in Alberta and British Columbia from ExxonMobil Canada Ltd. for $860 million. The company also announced that it will proceed in partnership with BP plc with the $2.5-billion first phase of their Sunrise oilsands project, which is expected to produce about 60,000 barrels per day beginning in 2014. “We’ve done some organic increases in what I call our bread and butter, which is western Canada and heavy oil, to give us results in a very near-term time frame starting from the end of 2011 and going on into 2012,” Ghosh told a Toronto investor audience in early December. “At the same time, we are keeping our mid- and longterm growth pillars alive. Those pillars are, in chronological order, Southeast Asia [where Husky has offshore properties], Sunrise and the repositioning of the East Coast [in Canada].” Husky has ambitiously set its sights on replacing reserves by at least 140 per cent annually, raising its total production by O I L & G A S I N Q U I R E R • J A N U A R Y / F e b ruary 2 0 1 1

Feature Photo: Joey Podlubny

about 50 per cent within a decade. Rob Peabody, Husky’s chief operations officer, says its output is scheduled to increase by about 150,000 boe per day by 2010, including 100,000 barrels from oilsands. The company plans to expand heavy oil output from Pike’s Peak South near Lloydminster in the near term. “We look to maintain our western Canada heavy oil volumes and over the plan period, [and] maintain our East Coast [offshore] production volumes, though we’ll be putting in place a plan to increase those volumes at the later part of the plan period,” Peabody says. After 64 years of production, Husky has produced 775 million barrels of oil in Lloydminster. “That only represents eight per cent of the oil that’s under Husky’s leases in the ground at Lloydminster—90 per cent of the oil is still there,” Ed Connolly, Husky’s vice-president of heavy oil, told the conference in Toronto. “Husky has today 470 million barrels of oil identified that can be exploited using new technology...[and] 800 million barrels is what we think we can get with the technologies that Husky is now developing today. It’s a bit more distant, it’s more towards the second half of the decade, but it’s more oil than has come out of the ground today.” Husky oilsands vice-president John Myer says, “Sunrise has received project sanctioning and major contractors have been finalized. We will commence horizontal drilling in the first quarter of 2011. The site has been graded, prepped and we can start

— Ed Connolly, Vice-President of Heavy Oil, Husky

the installation of undergrounds in mid-2011, targeting first oil in 2014.” Myer adds that Sunrise Phase 2 pre-engineering work will also commence in 2011, with a go decision tentatively targeted for 2014. “We will look to optimize the phase sizes for us to get to 200,000 barrels per day and beyond.” Under the terms of the Sunrise joint-venture agreement, BP will pay the first $2.5 billion in development costs. Husky will contribute the first $2.5 billion in costs on the expansion and conversion of a jointly owned refinery in Toledo, Ohio, which will be used to process bitumen from Sunrise. Myer says the Toledo facility has current capacity of about 160,000 barrels per day and can accommodate Sunrise Phase 1 production with “relatively modest changes.” 24

J A N U A R Y / F e b ruary 2 0 1 1 • O I L & G A S I N Q U I R E R

Husky is investing heavily in SAGD (above) but not Canadian upgrading/refining (below). Photo: Joey Podlubny

“Husky has today 470 million barrels of oil identified that can be exploited using new technology...[and] 800 million barrels is what we think we can get with the technologies that Husky is now developing today.”

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Bit of a gamble Drilformance, a new PDC drill

bit manufacturer in Leduc, takes on the global giants

Photos: Aaron Parker

by Mike Byfield

J A N U A R Y / F e b ruary 2 0 1 1 â&#x20AC;˘ O I L & G A S I N Q U I R E R

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" On the buy side, customers are attracted by the fact that our bits reduce their drilling costs. Drilformance’s technology is the cream of the crop in terms of durability in tough rock and steerability for directional drilling." — Sean Gillis, Engineering Manager, Drilformance

rilformance ULC began making polycrystalline diamond compact (PDC) drill bits in 2008, just as rig counts began plunging across North America. Besides timing its launch to the worst upstream market conditions in the past decade, the Albertabased manufacturer had jumped into an arena dominated by oilfield giants: Schlumberger Limited (Smith Bits), Halliburton Company (Security DBS), National Oilwell Varco, Inc. (ReedHycalog) and Baker Hughes Inc. And there are other players, including Chinese price lowballers.

So how’s business? “We’re doing pretty well,” says Sean Gillis, engineering manager at Drilformance’s plant in Leduc. At age 30, he runs research and manufacturing under company chairman Rusty Petree, a well-known entrepreneur from Houston. “The industry slowdown has benefited us on the supplier side. Steel is instantly available, for example, and everyone bends over backward to help,” Gillis says. “On the buy side, customers are attracted by the fact that our bits reduce their drilling costs. Drilformance’s technology is the cream of the crop in terms of durability in tough rock and steerability for directional drilling.”

Engineering manager Sean Gillis (left) says his boyhood machine shop experience helps him lead the Drilformance manufacturing team.

O I L & G A S I N Q U I R E R • J A N U A R Y / F e b ruary 2 0 1 1

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Although the new firm’s payroll is small—about 30, including sales offices in the United States and overseas—the firm can nonetheless access state-of-the-art manufacturing technology. “We use some of the world’s most sophisticated CNC [computerized numerical control] programs and machinery,” Gillis says. “Compared to larger companies, we’re more willing to push the design envelope if a customer wants to try out an idea, and our team can move quickly.” Drilformance PDC bits are milled from a single block of steel. The compact unibody, flat profile and PDC cutter layout are engineered to generate smooth, consistent reactive torque, which enhances directional responsiveness downhole. The company has developed several manufacturing technologies, including: • Rhino Armour Gauge Protection is a proprietary hard-facing process that reportedly provides maximum protection to critical bit surfaces.

• After the armoured bit cools, PDC diamond cutters are brazed into place. Drilformance is in the process of patenting Cryo Edge, a technology that enhances the thermal stability of its polycrystalline diamond wafers. • The company’s Shadow Path work sharing system is another patent-pending element, designed to mitigate heat buildup while adding diamond volume to the bit shoulder. • The HeliPath stability system (also patent pending) is a radial spiral breakthrough that reportedly increases depth of cut while increasing bit stability. • Opti Trac Directional is modelled for good steerability, utilizing optimal custom back rake, side rake and other design elements. Drilformance has case studies demonstrating superior rate of penetration in tough geological formations like the Basal Belly

"A downhole drilling system with the potential to create a step-change improvement in drilling performance for both vertical and directional applications." — Rusty Petree, Chairman, Drilformance

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" Compared to larger companies, we’re more willing to push the design envelope if a customer wants to try out an idea, and our team can move quickly." — Sean Gillis, Engineering Manager, Drilformance

River, Glauconite and Ellerslie. For instance, in British Columbia’s Montney tight gas play, Encana Corp. reportedly drilled two offsetting wells, one using a Drilformance 156 millimetre PDC bit and the other with a competitor’s bits. “The drilling crew completed the horizontal portion of our well in 133.5 hours, compared to 201.3 hours for the other well,” Gillis says. “That’s a 34 per cent improvement under very similar operating conditions.” The professional engineer says that “for me, coming to work each day is like going to the race track. I’m always examining how fast and how far we went, and thinking about how that performance might be improved. Our people on the floor are great to work with. They’re experienced hands who truly understand the practical aspects in manufacturing—the precise temperatures and methods for making bits that will perform consistently in the field.”

Gillis himself worked in machine shops during summer breaks while still in high school and later when he was studying mechanical engineering at the University of Alberta. “Too often I heard machinists cursing engineers for poor designs. I took those complaints to heart,” the engineering manager says. “Theory isn’t enough, not even close. I’m grateful that I had the opportunity to ‘touch the steel’ and learned to respect the manufacturing process.” Drilformance is preparing tools well beyond its current PDC bit lineup. In 2009, Petree said publicly that his company is preparing “a downhole drilling system with the potential to create a stepchange improvement in drilling performance for both vertical and directional applications.” Gillis won’t even hint further at this point about what’s in the works: “Let’s just say that our guys are always interested in developing new and exciting ways to destroy rock!”

O I L & G A S I N Q U I R E R • J A N U A R Y / F e b ruary 2 0 1 1

Cutting edge career Inventor Ian Gillis lived through

the breakthrough development of PDC drill bits by Mike Byfield

J A N U A R Y / F e b ruary 2 0 1 1 â&#x20AC;˘ O I L & G A S I N Q U I R E R

g e r

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" Believe me, no one feels happy when a $50,000 bit wears out in two hours." — Ian Gillis, Founder, United Diamond

In 2000, Ian Gillis became the founding partner of United Diamond Ltd., an Alberta-based company that manufactures polycrystalline diamond compact (PDC) bits. At the time, roller cone drill bits still accounted for perhaps 80 per cent of the total petroleum footage drilled for oil and gas, while PDC bits handled 20 per cent. Today, those market shares have been nearly reversed in favour of PDC bits, a radical evolution that’s still ongoing. United Diamond was sold in 2008 to Ulterra Drilling Technologies, LP, reportedly for about $100 million. The Texasbased purchaser was especially eager to acquire the Torkbuster, a Gillis invention that addresses the downhole operating difficulty called stick-slip. “Actually, I started a drill bit manufacturing company so I could generate cash flow for developing the Torkbuster,” says the former director of drilling tool technology for Halliburton. Throughout his career, this Nova Scotia–raised mechanical engineer has been immersed in drilling technology. Modern drilling dates back to 1909 when Howard Hughes Sr. received a patent for a rotary rock bit that featured two interlocking, rotating cones. “It was a brilliant piece of engineering,” Gillis comments. In 1933, two engineers working for what is now Baker Hughes created the tricone bit, a design often imitated by others after the original patent expired in 1951 and still popular today. The roller cones are studded with tungsten carbide steel inserts, all or some of them impregnated with industrial-grade diamond particles. The cones grind as they roll, crushing the rock face through an action similar to using sandpaper. Originally, the industrial diamond used for roller cones came from mines. Natural diamond cannot be used for making cuttershaped tools. By the 1970s, however, General Electric learned to manufacture synthetic diamond on a commercial scale. This material could be coated onto thin wafers of tungsten carbide for use as drill bit cutters. Compared to grinding, cutting is an aggressive action that can make hole more quickly. However, the bits must withstand the enormous drag stresses involved in scraping rock. “The early PDC bits were prototypes. It’s very expensive to make prototypes because economies of scale haven’t kicked at that stage,” Gillis says. “Manufacturing cost was also high due to manufacturing difficulties. For example, tungsten carbide has a relatively high coefficienct of thermal expansion while diamond is much lower. The diamond coating tended to break off the cutters while the inserts were being brazed onto the bits.” PDC bits often performed exceptionally well in softer rock, but there was no consistency for many years. “On one well, we’d do great and then the next well might easily be a complete dud. We didn’t really understand how rock formations break down under drag, so we couldn’t place the cutters strategically on the bit,”

Gillis remembers. “Believe me, no one feels happy when a $50,000 bit wears out in two hours.” To help minimize breakage, specialist “bit hands” would help when a rig crew was drilling with PDC bits, which added to operating cost. PDC bit destruction got much worse when the bits drilled into harder, more abrasive rock. Cutter breakage was initially attributed to the brittle quality of the diamond coating. Only later, Gillis says, did engineers realize that polycrystalline diamond was vulnerable to heat, an insight that led to design improvements. After 30 years of development, PDC bit manufacturers achieved reasonably consistent performance across a broadening range of rock types. The expanding market enabled manufacturers to reduce prices, which in turn attracted more customers over the past 10 years. Even so, the challenge of stick-slip persisted. A PDC bit can stick when it attempts to shear a really hard rock like quartz. Once the bit stops, the rotating drillstring begins to wind up like a spring. Eventually enough torque accumulates to slice the rock. At that point, the PDC bit will slip and the drillstring releases with enormous force. The longer the bit remains stuck, the greater the jarring upon release. That vibration can damage the bit itself as well as other components in the bottomhole assembly. Enter the Torkbuster. The Ulterra tool operates on the same fundamental principle as pneumatic wrenches. “If you tighten or loosen the lug nuts on a car wheel by hand with a tire iron, you can only deliver so much torque,” Gillis explains. “A pneumatic wrench uses compressed air to generate far more torque while remaining light enough to hold with your hand.” The pneumatic wrench actually hammers the lug nut with a series of sharp impacts. Similarly, the hydraulically driven Torkbuster applies 800-1,500 torsional impacts per minute to the drill bit, which ensures steadier rotation and less stick-slip. In theory, the drilling tools specialist tried to semi-retire after selling United Diamond. Among his investments was a sizable stake in a modular housing manufacturer based in Barrhead, northwest of Edmonton. But the company suffered near-catastrophe in the recent economic downturn, jeopardizing a personnel roster that peaked at 200. In a rescue bid, Gillis has taken over as its chief executive officer. “The operation is turning the corner as the economy improves,” the newly minted construction boss reports. Gillis has no role in Leduc-based Drilformance ULC, where his son Sean works as engineering manager. In a parallel to United Diamond’s original business strategy, however, Drilformance is generating cash flow by manufacturing PDC bits while the company simultaneously develops an innovative downhole drilling system (see previous article on page 26). In this instance, as the proverb says, the acorn didn’t fall far from the tree.

O I L & G A S I N Q U I R E R • J A N U A R Y / F e b ruary 2 0 1 1

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" In Alberta, we’re seeing more deep basin drilling in the Foothills and fewer shallow gas wells."

teve Shim, president and chief executive officer of Sicotte Drilling Tools Inc., must adapt to the rising use of polycrystalline diamond compact (PDC) bits. Sicotte handles only roller cone bits, selling and renting most makes, both new and reconditioned. “Roller cone bits are never going to disappear in this market. In fact, their role might expand in the future,” the 42-year-old Edmontonian asserts. As a grinding mechanism, he contends, roller cone bits still provide superior accuracy in directional drilling, along with greater reliability in the hardest geological formations. “PDC bits, because they shear the rock formation instead of indenting and crushing it, tend to whirl more. That whirling can make it significantly more difficult to steer the drillstring precisely,” and can damage downhole equipment, Shim suggests. “Superior steerability means roller cone bits is a better option for drilling directional wells with high collision and aggressive shortbuild sections for SAGD [steam assisted gravity drainage] wells in the oilsands.” Roller cone bits do not chew through some formations as quickly as PDC bits, the Sicotte president concedes. “But our bits are still more reliable across a full spectrum of rock types. You should also factor in roller cone bit longevity, which has increased by 30 per cent, even 40, over the past five years. There is less tripping to change bits due to this improvement,” he says. “In Alberta, we’re seeing more deep basin drilling in the Foothills and fewer shallow gas wells.” Like many oilfolk, Shim grew up on a farm—but far from the winter-frozen Prairies of his adopted homeland. “My father was a small-scale farmer in Malaysia, a tropical country in Southeast Asia. Our family was poor,” he says. Although his formal schooling was sparse, the technologically gifted youngster worked his way into the music industry, handling front-end light and sound engineering for concerts with audiences as large as 50,000. Malaysia’s ethnic Chinese and Indian minorities live uneasily alongside a Malay Muslim majority. Racial troubles, including official government discrimination in education and business, prompted Shim to emigrate in 1993 at age 25. “Coming to Alberta was a shock, not unexpected but still difficult,” he recalls. “After bartending and bussing tables for a while, I was grateful to get a job with Sperry-Sun Drilling Services, cleaning heavy tools, loading trucks and doing other general labour.” Over the next three years, Shim was technically trained on a variety of drilling equipment. By 1996, the repeatedly promoted manager headed asset management and assisted with product development for roller cone and PDC bits at Halliburton/Security DBS. “I stayed there until 2003, when I bought Sicotte,” he says. A 32

J A N U A R Y / F e b ruary 2 0 1 1 • O I L & G A S I N Q U I R E R

family-owned firm established in 1976, Sicotte had four employees at the time. “Although our business has slowed since the downturn in 2008, we have 20 staff and full-time contractors,” its president reports. By his estimate, roller cone bits now account for approximately 35-40 per cent of total oil and gas drilling footage in western Canada. During a period when this technology was losing market share at a rapid rate, Sicotte managed to expand its operations. Key to that success has been its innovative relationship with Diamond Drill Ltd. (Bit-Tech Canada), an exclusive PDC bit company based just outside Edmonton in Acheson. Diamond Drill’s president is Gordie Bath, a former colleague at Halliburton. (Shim and Bath both know fellow Halliburton veteran Ian Gillis, featured in the article on page 30 of this issue.) Diamond Drill and Sicotte are about the same size, Shim notes. “Although the two companies remain separate in ownership, we share a single sales force and a sales and billings system. We also share distribution centres across the West. Through this working partnership, both companies benefit from operating efficiencies and a more powerful presence in the market than either of us could achieve by ourselves.” When cash flows get lean at home, western Canadian service firms have often sought work elsewhere. Sicotte has found a way to do just that. “We’re the exclusive North American distributor for roller cone bits manufactured by TIX-TSK of Japan,” Shim says. Although the Tokyo-based firm is best established in geothermal drilling bits, TIX Holdings Company Limited has long made a line of TSK petroleum roller cone drill bits as well. Until now, though, most of its oil and gas–related sales have been in the Asian-Pacific and Gulf regions, outside the home ground of U.S.-based oilfield champions like Baker Hughes, Halliburton, ReedHycalog and Smith. Besides acting as a distributor, Sicotte has also handled technical support assignments in Brunei, Egypt, Sudan and elsewhere for TIX-TSK. “Their roller cone bits are exceptionally reliable and the company ’s manufacturing capabilit y is world-leading,” Shim comments. “A North American drill bit manufacturer will typically employ one worker at a state-of-theart work station. Using robotic technology, a single worker in a TSK plant can control as many as four work stations.” Thanks to robotics and computer-driven engineering, he adds, TIX-TSK can complete a new generation of drill bit, from initial design to mature prototype, in three months. “Not very long ago, that same process took a year or more. I’ve also found the Japanese to be exceptionally skilled at using specific application requirements from our customers to customize their products for specific markets,” the Sicotte president says. “Across the entire industry, development times are speeding up. Technologically, we’re living through a very interesting period.”

Photo: Aaron Parker

— Steve Shim, President and Chief Executive Officer, Sicotte Drilling

Grinding faith Sicotteâ&#x20AC;&#x2122;s Steve Shim believes roller cone drill bits will always have a place in the western basin

Photo: Aaron Parker

by Mike Byfield

O I L & G A S I N Q U I R E R â&#x20AC;˘ J A N U A R Y / F e b ruary 2 0 1 1

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First phase of Apache-EOG Kitimat LNG export plant budgeted at $3B By Richard Macedo

The proposed LNG terminal at Kitimat will have a daily export capacity of 700 million cubic feet.

The planned Kitimat LNG export terminal will have an initial capacity in 2015 to process roughly 700 million cubic feet per day and cost $3 billion with an option to expand in a planned second phase, according to an LNG export licence filed with the National Energy Board (NEB) in late December. The application is the first application for an LNG export licence to come before the federal board. The K M LNG Operating General Partnership is looking for NEB approval for a licence to export up to 10 million tonnes of LNG per year, a natural gas equivalent of approximately 468 billion cubic feet (bcf) per year over a term of 20 years. The terminal will be owned by Apache Canada Ltd. (51 per cent) and EOG Resources Canada Inc. (49 per cent). The terminal will have the initial capacity in 2015 to process approximately 700 million cubic feet per day with a send

out capacity of up to five million tonnes per year of LNG (natural gas equivalent of approximately 234 bcf per year). The approximate cost for what the companies called Phase 1 is $3 billion.

send out capacity of 10 million tonnes per year of LNG (natural gas equivalent of approximately 468 bcf per year). Tara O’Donovan, a spokeswoman with the NEB, said the board is required to hold a public hearing regarding the issuance of a licence. “The board will be reviewing this application over the coming weeks and will inform the public of the hearing process to be followed in a hearing order, to be released at a later date,” she said. Kitimat LNG stated in the filing that it is in active “arm’s length” negotiations with several potential buyers in the Asia Pacific region. “Current expectations are that long-term firm sales arrangements [up to 20 or more years] can be in place by the fourth quarter of 2011,” the application said. “A long-term export licence is considered a critical component of the overall ability to attract and finalize transactions with LNG buyers in the Asia Pacific market.” Gas sales agreements were not included in the application because ongoing negotiations “cannot be successfully concluded until security of supply concerns with LNG buyers are first addressed through the issuance of a long-term export licence.”

“Current expectations are that long-term firm sales arrangements [up to 20 or more years] can be in place by the fourth quarter of 2011.” — KM LNG Operating General Partnership

An additional train is proposed for around 2017-2018 at an incremental $1.5 billion, although this timing could be accelerated based on market conditions and engineering studies. This expansion will double the processing capacity of the terminal to 1.4 bcf per day with a

Features of the application include: • Gas production will be liquefied at the Kitimat LNG terminal and directly transported by LNG carriers, primarily to Asia Pacific markets. • A sia Pacific represents a new, long-term and stable market for Canadian natural

DEC/09

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WELL LICENCES

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WELLS SPUDDED

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Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • J A N U A R y / F e b ruary 2 0 1 1

British Columbia

gas supply, the application stated. The Kitimat LNG terminal is well positioned to take advantage of the presently forecasted supply deficit market opportunity expected to occur in the 2014-2018 time frame. • K M LNG is applying to obtain the licence in an amount equal to the full capacity of the Kitimat LNG terminal. KM LNG will be processing and exporting allnatural gas delivered to the terminal on behalf of the terminal owners. The terminal owners, in turn, will be responsible for the provision of gas supply and effecting LNG sales arrangements. • Unlike continental North American natural gas markets served by onshore pipelines, Asia Pacific LNG buyers are seeking long-term secure gas supply arrangements with regulatory certainty before committing to long-term contractual commitments. Therefore, a long-term gas

export licence is required prior to completing gas export sales contracts. • N at ura l gas produced in wester n Canada will be transported from a delivery point on the Spectra Energy B.C. pipeline near Summit Lake, B.C., to the Kitimat terminal by PTP Limited Partnership’s proposed $1.1-billion Pacific Trail Pipeline. A f inal investment decision on t he proposed Kitimat LNG export project by proponents won’t be made until late in 2011. In November, members of the Haisla Nation voted in favour of approving a lease of reserve lands requ i red for t he con st r uc t ion a nd ongoing operation of t he ter minal. The project has federal and provincial environmental authorizations. Apache’s share of LNG to be exported under the application will be sourced f rom it s ow nersh ip of nat u ra l gas

reser ves and production in Canada, currently British Columbia, Alberta and Saskatchewan, as it may evolve over the duration of the licence. EOG’s corporate supply pool mainly consists of unconventional gas in British Columbia. The company is rationalizing its Alberta-based reserves and the anticipated commercial transactions will impact this source of supply. For the purposes of demonstrating that EOG has adequate reserves and supply to support the licence, the company has focused on its B.C.-based reserves within the Horn River area. The company’s Horn River marketable gas volumes as of Oct. 1, 2010 include total 3P and contingent resource of 9.69 trillion cubic feet (tcf ). EOG reported proved reser ves there of 1.5 tcf and proved plus probable totalling 3.7 tcf. — DAILY OIL BULLETIN

Talisman sells half of Farrell Creek to South Africa’s Sasol for $1.05B A South African company, Sasol Limited, w ill pay $1.05 billion to acquire a 50 per cent working interest in Talisman Energ y Inc.’s Farrell Creek Montney shale gas assets in northeastern British Columbia in a strategic partnership to develop the play. “This is a strategic move towards unlocking some of the value of our Montney assets for us and our new partner, consistent with the strategy of derisking and developing Talisman’s very large shale opportunities in the region,” John Manzoni, the company’s president and chief executive officer, said in a news release on Dec. 20. “We believe this transaction reflects the quality and potential of our broader Montney position,” Manzoni said. “We are delighted to have Sasol as a partner. They are a world-class company and their expertise will enable us to jointly explore the option of a GTL [gas to liquid] facility in western Canada.” The transaction allows Talisman to develop the Farrell Creek area and unlock some of the value of the estimated 44 trillion cubic feet equivalent (tcfe) of net contingent resource held across its Montney shale play. Farrell Creek 36

represents approximately 22 per cent (9.6 tcfe) of Talisman’s resource potential in the play and about 27 per cent (51,000 net acres) of the company’s 190,000 net Tier 1 acres of land in the Montney. Sasol will pay 25 per cent of the consideration (approximately $260 million) in cash at closing and carry 75 per cent of Talisman’s future capital commitments in the Farrell Creek area to a total of approximately $790 million. “The acquisition of this high-quality natural gas asset will accelerate our upstream growth while also advancing Sa sol’s a l ready st r ong GT L v a lue proposition,” said Pat Davies, Sasol chief executive officer. “In partnering with a credible international shale gas operator such as Talisman, we reap the dual benefit of leveraging their experience as we grow our own shale gas expertise.” The play has been largely de-risked and production at Farrell Creek is expected to exit this year at between 40 million cubic feet equivalent (mmcfe) and 60 mmcfe/d. Talisman’s processing facilities at Farrell Creek have been expanded to 120 mmcf/d, and the company has secured over 500 mmcf/d of egress capacity from the region.

J A N U A R Y / F e b ruary 2 0 1 1 • O I L & G A S I N Q U I R E R

As part of the agreement, the partners have agreed to conduct a feasibility study around the economic viability of a facility in western Canada to convert natural gas to liquid fuels using Sasol’s commercial gas GTL technology. This could provide a strategic alternative to traditional North American pipeline or liquefied natural gas marketing. The outlook for GTL could be very positive if North American natural gas prices continue to decouple from oil prices. The GTL process produces premium, clean liquids fuels. Sasol will acquire a 50 per cent working interest in all Talisman lands, existing wells and processing facilities in the Farrell Creek region. Talisman and Sasol will each own 50 per cent of the Farrell Creek assets, with Talisman as operator of the partnership. Talisman and Sasol have also agreed to collaborate on certain other western Canadian natural gas opportunities. Sasol is an integrated energy and chemicals company and one of two companies with commercial GTL technology, with operating GTL projects in South Africa and Qatar, a project under construction in Nigeria and proposed developments in a number of countries around the world. — DAILY OIL BULLETIN

British Columbia

B.C. racks up fourth-highest annual land sale revenue in 2010 Thanks to a $35.1-million bonus in the Horn River Basin, the B.C. government attracted a total of $42.3 million in its final land sale of 2010, pushing the year-end total to $844.4 million, the fourth-best annual tally in history, despite depressed natural gas prices. A total of 381,132 hectares (ha) were sold this year in northeastern British Columbia at $2,215/ha. In 2009, the province attracted $892.9 million in bonus bids on 389,664 ha at an average of $2,291. The province has enjoyed a strong run of land sales over the past few years, fuelled by producers locking up Horn River and Montney lands. Over a five-year period from 2006 to 2010, British Columbia has attracted an average of $1.2 billion in bonus revenue at $2,159/ha. The top four calendaryear bonus totals were all recorded from 2007 to 2010, with the highest coming in 2008 when $2.7 billion filled the provincial treasury. “Despite the pressures of a global recession and the decline in average gas prices, we have reached another strong year in natural gas and petroleum sales,” Energy Minister Steve Thomson said in a statement. “Industry has come forward with their commitment to produce here in B.C. ensuring the natural gas and petroleum sector will maintain a longterm role in creating jobs and generating government revenue.” The top bonus of $35.1 million was tendered by Scott Land & Lease Ltd. for a 6,619 ha parcel in the Horn River Basin. The broker paid an average of $5,302 for the parcel, which included several units at 94-O-8, 94-P-4 and 94-P-5. The area is being developed by large operators like

Encana Corporation, Nexen Inc., Apache Canada Ltd. and Imperial Oil Limited. Chris Theal, president and chief executive officer of Kootenay Capital Management Corp., said it was likely a larger player aggregating land. “It is Horn River gas, I think, that’s being targeted there,” he said. “With what’s happening in Kitimat [for the LNG export terminal] I think you’re just seeing companies inventorying big blocks of land that can

said when asked about 2011 land sale activity. “Is it going to be up at the level of this year? Hard to say. One thing that can change is tight light oil and horizontal drilling technology.” Quicksilver Resources Inc., for example, is testing the Exshaw formation in B.C. for oil at the Horn River Basin. “If you do see some commercial rates on some of those oil plays, then it’s going to attract capital to land up there,” Theal said.

“Industry has come forward with their commitment to produce here in B.C. ensuring the natural gas and petroleum sector will maintain a long-term role in creating jobs and generating government revenue.” — Steve Thomson, B.C. Energy Minister

backstop a long-term supply off-take agreement. It is more, I think, related to this evolving LNG game and it’s a longerterm view and it’s also gas that potentially gets indexed to crude oil.” T he Canadian A ssociation of Petroleum Producers has forecasted that industry investment—an indication of future development and activity—will reach $7 billion this year, up from the $5.2 billion invested in 2009, the province said. “I still think there’s some land capture to be done in the Fort Liard Basin so it has the potential to see some activity,” Theal

read more online at energizealberta.com Where energy, the economy, and the environment intersect.

Brad Hayes, president of Petrel Robertson Consulting Ltd., added that, in general, B.C. will have a slower year in 2011 because it is more gas prone. More effort will be focused in Alberta and the hot B.C. play trends, Montney and Horn River, have been largely bought up. “There is still room for some land buying, pushing more plays like...the Liard Basin or Foothills areas and new play concepts,” he said. “If Quicksilver’s interest in an oily Exshaw in the Horn River Basin pans out, there may be some new ideas regarding posting lands for that reservoir.”

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Northwestern Alberta/Foothills

Paramount Energy focuses capital plans on Grande Prairie and Kaybob

Paramount is drilling and constructing facilities for its Grande Prairie and Kaybob operating units.

Based on encouraging drilling and completion results achieved to date, Paramount Resources Ltd. expected to continue its accelerated development plans in the Kaybob and Grande Prairie areas of Alberta in the last weeks of 2010. The company anticipates that it will spend more than the planned $130 million for exploration and development. Paramount’s output improved 16 per cent in the third quarter of 2010 compared to the third quarter of 2009, primarily associated with new well production in the Kaybob and Grande Prairie operating units and the impact of the June 2010 Redcliffe Exploration Inc. acquisition. Based on recent successful drilling results, the Kaybob corporate operating unit (COU) has commissioned the construction of a processing plant at Musreau with a capacity of up to 50 million cubic feet (mmcf) per day, anticipated to be

operational in the third quarter of 2011, and has also nominated for an additional 50 mmcf per day of processing capacity in a third-party facility expansion at Smoky, anticipated to be operational in the third quarter of 2012.

new well being brought on production at Smoky during the third quarter and a full quarter of production from four (two net) wells brought on production in the second quarter, partially offset by natural production declines. Capital expenditures for the Kaybob COU during the third quarter were approximately $11.1 million, excluding land acquisitions and drilling royalty credits. Third-quarter activities included completing and equipping one (one net) well at Smoky, which was subsequently brought on production in early October, recompleting a well in Musreau, and starting preparatory work for wells that would be drilled in the fourth quarter. The Kaybob COU expected to drill up to seven (4.3 net) horizontal wells prior to year-end, targeting liquids-rich natural gas from the Fahler and Dunvegan formations. The majority of the wells planned will be drilled from existing leases or new multiple-well pads, reducing per-well drilling costs by minimizing mobilization and demobilization activities and allowing surface equipment and pipelines to be shared. Where two or more wells are drilled f r om a si ng le lea s e, t he compa ny

Paramount’s output improved 16 per cent in the third quarter of 2010 compared to the third quarter of 2009. In 2010, third-quarter sales volumes for the Kaybob COU increased 794 barrels of oil equivalent (boe) per day to 4,829 boe per day, consisting of 25.6 mmcf per day of natural gas and 570 barrels per day of oil and natural gas liquids. This increase was due to one (one net)

anticipates performing the f racture stimulations back to back, increasing equipment and personnel efficiencies and reducing per-well completion costs. Production from these seven (4.3 net) planned wells is not expected until the first quarter of 2011.

NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY

DEC/09

DEC/10

WELL LICENCES

329

434

▲

DEC/09

DEC/10

WELLS SPUDDED

271

232

▼

DEC/09

DEC/10

WELLS DRILLED

266

237

▼

Source: Daily Oil Bulletin

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

Northwestern Alberta/Foothills

The Grande Prairie COU continues to make progress in expanding gathering and processing capacity at Karr-Gold Creek, which is expected to be operational before the end of 2010. Grande Prairie COU third-quarter sales volumes were 3,425 boe per day, an increase of seven per cent from the prior quarter. The increase was primarily due to new production from wells drilled and completed in Karr-Gold Creek and Valhalla and the impact of the June 2010 Redcliffe acquisition, partially offset by natural declines. Total capital expenditures in the Grande Prairie COU for the third quarter were approximately $26.3 million, excluding land acquisitions and drilling royalty credits. During the quarter, three (2.4 net) horizontal Montney gas wells were drilled at Karr-Gold Creek and one (0.6 net) horizontal Montney gas well was drilled at Valhalla. Two (two net) wells drilled

previously were completed and brought on production at Karr-Gold Creek. Due to capacity constraints, wells previously on production were shut in to allow the newly completed wells to be tied in and tested. The first phase of the compression/ dehydration facility at Karr-Gold Creek was expected to be completed in the fourth quarter of 2010, followed by start-up. The project has been delayed by wet weather, which made the site inaccessible to heavy equipment for an extended period. The initial 20 mmcf per day raw gas processing capacity of the facility is planned to be expanded to 40 mmcf per day in the first quarter of 2011. This will allow wells that are currently restricted or shut in to be brought on stream and for further horizontal drilling to take place in 2011. At Valhalla, five wells have now been drilled and completed (including the well completed in the third quarter). Construction

of the Valhalla gas gathering system is progressing and the system is expected to be operational in early 2011. The company is evaluating opportunities to target other formations at Valhalla to increase liquids recoveries and enhance returns. The Northern COU’s capital program is substantially complete. One (one net) well drilled in the first quarter was expected to be brought on in the fourth quarter of 2010. Third-quarter 2010 sales volumes in the Northern COU were 2,646 boe per day, consistent with the second quarter of the year. Third-quarter capital expenditures for the Northern COU were approximately $400,000, which was related to seismic work and lease preparation for the current winter drilling season. A Cameron Hills well drilled earlier in 2010 was expected to be brought on production in the fourth quarter, subject to the receipt of regulatory approvals. — DAILY OIL BULLETIN

Forest goes horizontal in the Nik while drilling pace heats up at Red Earth Forest Oil Corporation continued to be busy working its Nikanassin play in the Deep Basin during the third quarter of 2010, delineating the prospect with vertical wells and setting up its first horizontal well there for completion in the first quarter of 2011. Drilling activity was scheduled to resume on its Red Earth/ Evi oil play in northern Alberta in the fourth quarter. The Denver-based producer continued its delineation efforts in the third quarter in the Nikanassin, drilling and completing three wells that had an average 24-hour initial production rate of nine million cubic feet equivalent (mmcfe) per day. In total, Forest has drilled and completed 15 wells in the play with an average 24-hour initial production rate of 13 mmcfe per day. Forest has approximately 25 to 30 mmcfe per day of net production shut-in awaiting completion of infrastructure projects. These projects were expected to be completed and production turned to sales in the near future. Current net production out of the Nikanassin was roughly 25 mmcfe per day, so that figure will roughly double it when the infrastructure work is complete. 40

Forest has been operating two rigs in the play. “Going horizontal in the Deep Ba si n i n ou r Ni k a na ssi n play area could be a game changer for both the industr y and our company,” said Craig Clark, president and chief executive officer.

Ridens, chief operating officer. “It looks like this horizontal oil play has really become hot as the latest land sale prices eclipsed $6,000 per acre. “We added land this year at an average of $650 per acre, so it looks like we bought the bulk of the land at a very good time.”

" Going horizontal in the Deep Basin in our Nikanassin play area could be a game changer for both the industry and our company." — Craig Clark, President and Chief Executive Officer, Forest Oil Corporation

At Red Earth/Evi, Daily Oil Bulletin records show that the company recently licensed several wells in the Evi/Otter fields, west of Red Earth Creek in the area around 87-12W5 and 87-11W5. The Slave Point formation was listed as the total depth zone. The area has been a focus of heavy industry activity. “O u r Ev i posit ion cont i nues to increase in value based on the prices being paid for offset leases,” said J.C.

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

The company has roughly 40,000 net ac res i n t he play where Forest re su med d r i l l i ng w it h t wo r ig s i n N o v e m b e r 2 010 , R i d e n s a d d e d . During the third quarter of 2010, the company’s Canadian production fell to 12,650 barrels of oil equivalent (boe) per day (net production after royalty) from 13,517 boe per day during the same period in 2009. — DAILY OIL BULLETIN

Northwestern Alberta/Foothills

AltaGas Ltd. has announced it will be constructing a 120-million-cubic-feetper-day gas processing facility and an associated gas gathering system in the Gordondale area of the Montney resource play, approximately 100 k ilometres northwest of Grande Prairie, Alta. The plant will be equipped with liquidsextraction facilities to capture the natural gas liquids value for customers. “The Gordondale gas processing facility is an exceptional gas infrastructure project located in an area of strong natural gas supply growth that will provide long-term, stable cash flows,” said David Cornhill, chairman and chief executive officer of AltaGas. “The project is consistent with our strategy to optimize our existing base business and to partner with leading North American natural gas producers.” T he G ordonda le ga s processi ng facility and gathering system will cost approximately $235 million. The gas processing facility is expected to be in service in late 2012. By using existing infrastructure in the area, AltaGas anticipates providing processing for early production by mid-2011. The project is subject to regulatory approval. AltaGas has secured a long-term gathering and processing agreement with Encana Corporation to supply natural gas to the new Gordondale processing facility. “The continued strength of natural gas liquids prices offers Encana opportunities to capture additional value and enhance project returns by stripping the propane, butane and ethane from the extensive liquids-rich production in our deep basin resource plays,” said Mike Graham, Encana’s executive vice-president and president, Canadian division. The plant is located in the Montney resource area, one of the largest, low-cost, liquids-rich resource plays in the Western Canadian Sedimentary Basin. This plant will allow AltaGas to provide a midstream solution to a number of producers in the area. The addition of deep-cut facilities to the project allows producers to extract additional value for liquids from the gas they bring to the plant for processing.

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Northeastern Alberta

Photo: Joey Podlubny

Total and Suncor launch Voyageur and Fort Hills oilsands projects

Engineering and procurement contracts for Fort Hills and Voyageur should be awarded this year.

Total E&P Canada Ltd. and Suncor Energy Inc. have strengthened their oilsands alliance, inking partnership agreements to develop the Suncor-operated Fort Hills mining project, the Total-operated Joslyn mining project and the Suncor-operated Voyageur upgrader project. In cash terms, Total will pay Suncor C$1.75 billion. As a result of the agreements, Total will no longer proceed with its planned construction of a 295,000-barrel-per-day upgrader near Edmonton since its Joslyn mine will use Suncor’s Voyageur upgrader near Fort McMurray, Alta. Total Canada president Jean-Michel Gires said that it’s a logical step since the companies had assets in the same region. “We always said we wanted to have an integrated strategy and to be part of the upgrading game as well in Alberta,” he said on Dec. 17. “Before that, because we were trying to push the development by ourselves,

[we] couldn’t find another partnership for the upgrader. Obviously, a lot of synergies and better coordination can be achieved when such major oil and gas companies like Total and Suncor start coordinating.” Total is acquiring 19.2 per cent of Suncor’s interest in the Fort Hills project. Taking into account Total’s acquisition of UTS Energy Corporation finalized last October, the company will have an overall 39.2 per cent interest in Fort Hills. Suncor, as operator, will hold 40.8 per cent. Teck Resources Ltd. continues to own its 20 per cent stake. Suncor is acquiring 36.75 per cent of Total’s interest in the Joslyn project. As operator, Total will retain a 38.25 per cent interest in the project, with Occidental Petroleum Corporation (15 per cent) and INPEX Corporation (10 per cent) holding the remaining 25 per cent. Total is also acquiring a 49 per cent stake in the Suncor-operated Voyageur

upgrader project near Fort McMurray. The facility, where construction was suspended in 2008, will have a capacity of around 200,000 barrels per day of upgraded products and will process Total’s Fort Hills and Joslyn bitumen production. Work will resume once the front-end engineering design is updated this year. Suncor has estimated that the cost to build the Voyageur upgrader, currently in “safe mode” after work was suspended in late 2008, would be $11.6 billion. It has spent $4 billion on it to date, company officials said in November, and that work will eventually continue. Suncor and Total have agreed to a joint commitment to develop Fort Hills and Voyageur in parallel so that both come on stream early 2016. The main engineering and procurement contracts for these two projects will be awarded this year. Both companies have also confirmed the Joslyn North mine timetable, with production of 100,000 barrels per day starting in 2017-2018, subject to receiving the necessary permits. Total operates the Joslyn project and owned a 75 per cent interest until now. Production potential of this mining project is currently estimated at 200,000 barrels per day, with the Joslyn North project at 100,000 barrels per day. Total owned a 20 per cent interest in the Fort Hills project until now. The project will be developed in two phases. The first phase of approximately 164,000 barrels per day has already obtained the necessary administrative approvals. Total also owns a 50 per cent interest in the Surmont steam assisted gravity drainage project. Phase 1 production began in 2007 and averages 23,000 barrels per day. Phase 2 development began in January 2010 with production scheduled to start up in 2015, enabling Surmont’s total production to increase to around 110,000 barrels per day. — DAILY OIL BULLETIN

NORTHEASTERN ALBERTA WELL ACTIVITY

DEC/09

DEC/10

WELL LICENCES

158

308

▲

DEC/09

DEC/10

WELLS SPUDDED

▲

DEC/09

DEC/10

WELLS DRILLED

▲

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • J anuary / F e b ruary 2 0 1 1

Northeastern Alberta

Boost in oilsands monitoring welcomed by industry Industr y spokesmen are welcoming an announcement of enhanced environmental monitoring by the Alberta and federal governments. In December, the two levels of government said they are prepared to act on the report of a federally appointed advisory panel on oilsands water monitoring. In its report, the federal panel said that designing, implementing and operating the proposed governance structure and performing monitoring to fill identified gaps will require additional funding. It recommended that the user pays principle should be the basis for determining funding responsibility, with industry being responsible for any new funding requirements. “We have to build on this for the future and as the industry grows clearly the monitoring needs to grow,” said Don Thompson, president of the Oil Sands Developers Group, which represents oilsands mine operators. T hompson said that through its involvement in programs such as the Regional Aquatics Monitoring Program and Cumulative Environmental Management Association, industry is already paying $20 million a year over and above what companies spend on monitoring internally. “I am pretty confident that within that $20 million a year, we can find sufficient funds to move forward.” As for user pay, “that’s like a double-edge sword,” he said. “Everybody says ‘user pay’ but then the next thing they say is criticizing reports that are industry-funded and it’s a bit of a no-win situation,” said Thompson. “I think there’s a responsibility on the part of everybody to carry their share.”

In its report, the panel identified shortcomings in the monitoring system as a whole and said these need to be addressed or the debate on environmental performance in the oilsands will continue to revolve around the adequacy of the data collected rather than on data interpretation and implications. The monitoring efforts of provincial and federal governments and other stakeholder groups including industry lack a coherent data-management framework where information can be uploaded,

together to build a world-class monitoring system. In its report, the panel said it has been told by many that the trusted and recognized organizational source of broad science capacity rests within Environment Canada. The federal minister said his government will accept the responsibility of Environment Canada taking a lead role in designing and implementing the environmental monitoring systems and will ensure the necessary systems are properly and securely in place.

“Everybody says ‘user pay’ but then the next thing they say is criticizing reports that are industry-funded and it’s a bit of a no-win situation." — Don Thompson, President, Oil Sands Developers Group

organized, and accessed in a standardized and coordinated manner, according to the panel. Until recently much of the data has been submitted to Alberta Environment in annual hard-copy reports, it noted. Many of the monitoring programs were unable to definitively distinguish (with reasonable statistical confidence a nd /or power) oi l sa nds i ndust r ia l impacts, said the report. “This inability to adequately measure impacts was often attributable to deficiencies in sampling program design (including insufficient replication in space or time), lack of hypothesis-driven sampling regimes, illdefined or undefined baseline conditions for inter-comparisons, and inadequate analytical capabilities.” In releasing the report in Ottawa, federal Environment Minister John Baird said that he and Alberta Environment Minister Rob Renner have agreed to work

Baird said he has directed senior department officials to work together to design a water-monitoring system within 90 days. “We will then consult with a group of independent scientists to ensure that the proposed design is appropriate and then move immediately to implementation,” said Baird. The federal government then intends to apply the lessons learned in this project to designing world-class monitoring systems for air quality and biodiversity. Renner announced that a group of independent experts will provide detailed action items on how to best set up, operate and govern a world-class environmental monitoring, evaluation and reporting system for the oilsands. The independent experts are to be in place by January 2011 and will report back to the provincial minister by June 2011. — DAILY OIL BULLETIN

Enbridge plans another $200M expansion of its Athabasca Pipeline Enbridge Inc. will spend approximately $200 million on a further expansion of its Athabasca Pipeline to its maximum capacity of approximately 570,000 barrels per day transporting crude oil from various oilsands projects to the mainline hub at Hardisty, Alta. In September, Enbridge announced that it would undertake a $185-million expansion of its Athabasca Pipeline to accommodate shipping commitments by 44

the Christina Lake oilsands project operated by Cenovus Energy Inc. It now anticipates the combined expansions will both be fully completed by early 2014. “The low cost of incremental capacity on the Athabasca Pipeline is one of the strengths of our regional oilsands system,” Stephen Wuori, Enbridge’s president of liquids pipelines, said in a news release. “Given recent announcements of continued growth and investment in the oilsands,

J anuary / F e b ruary 2 0 1 1 • O I L & G A S I N Q U I R E R

this is an opportune time to capture construction economies by undertaking a single large expansion project.” Enbridge currently has a total of $2.4 billion of commercial secured expansions of or additions to its regional oilsands system, which will go into service by 2014, as well as a significant portfolio of additional projects that are under development to meet oilsands growth. — DAILY OIL BULLETIN

Northeastern Alberta

CNRL boosts crude spending with 2011 budget pegged at $5.6B-$6B Canadian Natural Resources Limited plans to boost capital spending to between approximately $5.6 billion and $6 billion this year, with a major focus on Canadian oil, which will see a 54 per cent rise in spending from 2010. The company is targeting overall production growth of six per cent (10 per cent for crude oil) in 2011. While total capital spending this year won’t be significantly higher than last year’s forecast of $5.6 billion, the 2010 number includes about $1.9 billion of expenditures on acquisitions, dispositions and midstream versus a forecast this year of only $110 million. The budget allocates a total of $3.75 billion for crude oil activity (excluding the Horizon oilsands project), an overall 54 per cent increase from $2.43 billion budgeted in 2010. Natural gas spending will be $600 million, a 14 per cent drop from $700 million in 2010. The forecast production of 645,000 barrels of oil equivalent per day to 694,000 barrels of oil equivalent per reflects a 10 per cent increase in primary heavy oil; a 17 per cent increase at Pelican Lake due to the ongoing conversion to a polymer

flood; 12 per cent production growth at Primrose East, North and South; and an 11 per cent increase in light oil production. The estimated growth also reflects increased reliability at the Horizon oilsands mining project with budgeted production of 105,000 barrels per day to 112,000 barrels per day of light synthetic crude, approximately 19 per cent higher than this year. TNatural gas production is forecast to decline three per cent to 1.18 billion cubic feet per day per day to 1.25 billion cubic feet per day as gas drilling is forecast to decline by 28 per cent to only 72 wells from 100 in 2010—as a result of the company’s short- to mid-term outlook for low natural gas pricing, offset somewhat by new Montney production at Septimus and acquired volumes over the course of 2010. Plans call for 138 net light oil wells, 790 net primary heavy oil wells and 465 primary heavy oil well recompletions and 201 producer thermal heavy oilsands wells along with 16 Kirby steam assisted gravity drainage pairs. Another 11 producers and 82 injectors will be drilled at Pelican. Tighter inter-well spacing on new pads at Canadian Natural’s Primrose cyclic steam

t in e G

— DAILY OIL BULLETIN

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stimulation project in northeastern Alberta should result in additional bitumen production and ultimately higher recovery rates. Spacing has been reduced to 80 metres from 190 metres. After the first steam cycle, which was completed in August, it became apparent that the company had achieved a higher degree of inter-well communication than expected, Steve Laut, president, said in a conference call to discuss third-quarter results. Rather than steaming one set of wells and then working through the pad, the company is block steaming in which all wells are steamed at the same time, Laut said. “You get a better recovery that way and better results.” However, that changes the whole steam cycle, requiring more steam and taking longer. And when it comes back, the first volumes include a lot of hot water. Now that it knows what to expect, though, Canadian Natural should be able to manage that, he said. The company is now looking at an overall recovery rate of between 25 and 30 per cent for the area.

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O I L & G A S I N Q U I R E R • J anuary / F e b ruary 2 0 1 1

Northeastern Alberta

Shell takes US$1B writedown on former BlackRock assets Royal Dutch Shell plc has taken a US$1-billion impairment charge against the bitumen assets it picked up through the acquisition of a Calgary-based producer about four years ago. Shell Canada Limited, which was then a publicly traded, majority owned unit of Royal Dutch Shell (but is now a wholly owned subsidiary), paid $2.4 billion in 2006 for BlackRock Ventures Inc. which had conventional bitumen production and a small steam assisted gravity drainage (SAGD) project. At the time, the 10,000-barrel-per-daycapacity Hilda Lake/Orion commercial SAGD project was under construction 30 kilometres northwest of Cold Lake, Alta. A two-well pilot had operated for eight years. Output from the commercial SAGD project has been lacklustre. In 2010, monthly bitumen production has ranged between a low of 2,281 barrels per day in February to a high of 3,626 barrels per day in July. In August, output averaged 3,500 barrels per day— only 35 per cent of its nameplate capacity—with an instantaneous steam to oil ratio of

5.8 and a cumulative steam to oil ratio of 5.2, according to a Peters and Co. Limited update on in situ bitumen project performance. BlackRock’s flagship production was conventional output at Seal—which averaged 10,367 barrels a day in the first quarter of 2006 a few months before Shell

The BlackRock writedown was based on two factors, Simon Henry, Shell’s chief financial officer, told a recent earnings conference call. “One is quite a detailed review of the subsurface technical capability of the assets. And they look overall less good than we previously expected based on the original acquisition,” Henry said.

“One [factor] is quite a detailed review of the subsurface technical capability of the assets. And they look overall less good than we previously expected based on the original acquisition.” — Simon Henry, Chief Financial Officer, Shell

made its friendly takeover bid. This production was lucrative because no steam was required to produce the roughly 12-14 degree API oil, but the project enjoyed a one per cent royalty until payout because of its location within Alberta’s legally defined oilsands region.

J anuary / F e b ruary 2 0 1 1 • O I L & G A S I N Q U I R E R

The second reason he cited for the writedown is Shell’s current oilsands priorities is its mining expansions (in the Athabasca oilsands region of northeastern Alberta) and its Carmon Creek thermal project (in the Peace River oilsands region of northwestern Alberta).

Northeastern Alberta

Henry said that most of the BlackRock assets aren’t producing. On the mining side, the first major expansion of the Shell-operated and 60 per cent–owned Athabasca Oil Sands Project (AOSP) will come on stream in the first quarter and is slated to raise total mined production capacity to 255,000 barrels per day. Shell’s next planned bitumen mining expansion is a de-bottlenecking designed to add another 90,000 barrels a day of capacity to AOSP. In northwest Alberta, Shell’s 100 per cent–owned Carmon Creek project, which is going through the regulatory process, will increase its thermal production capacity from the Peace River oilsands to as much as 80,000 barrels of bitumen per day using vertical well steam-drive technology. Shell’s current Peace River thermal project, which uses cyclic steam stimulation, is licensed for up to 12,500 barrels of bitumen per day. But 2010 monthly production has ranged between 8,429 barrels per day in January and 6,674 barrels per day in July. — DAILY OIL BULLETIN

Imperial Oil reconfigures its Kearl development plans With two and a half years of construction of the first phase of its Kearl Lake oilsands mining project behind it, Imperial Oil Limited is reconfiguring the project development plan to minimize facility requirements and potentially reduce the plant’s footprint. The initial plan was to develop the $8-billion project in three phases with ultimate production of about 330,000 barrels per day by about 2020, said company spokesman Pius Rolheiser. While plans still call for the initial phase of 110,000 barrels per day to be on production at the end of 2012, Imperial is looking at a combination of debottlenecking the initial facilities, then expansion, then potentially another debottlenecking to achieve the total resource development in about the same time period. Production, in fact, may be slightly higher at about 345,000 barrels per day, Rolheiser said. “The primary driver behind this is the desire to leverage our executional learnings [and] take advantage of the

“The primary driver behind this [redesign] is the desire to leverage our executional learnings [and] take advantage of the investments in infrastructure that we’ll do early that won’t need to be duplicated in the future.” — Pius Rolheiser, Company Spokesman, Imperial OIl

investments in infrastructure that we’ll do early that won’t need to be duplicated in the future. We’ll get to the same endpoint in the same period of time, but we’ll get there in a more efficient way.” While the reconfiguration is resulting in accelerated capital spending early in the project, he said it’s difficult to estimate that cost at this point. “This shouldn’t be interpreted as a cost overrun because it isn’t.” — DAILY OIL BULLETIN

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O I L & G A S I N Q U I R E R • J anuary / F e b ruary 2 0 1 1

Northeastern Alberta

Industry ramps up oilsands evaluation drilling Delineation drilling and resource assessment in Alberta’s oilsands have revived this winter, judging by the larger number of core holes planned for drilling compared to the past winter, but the pace remains below peak year activity. T he A lber ta E nerg y Resou rces Conservation Board approved a total of 985 oilsands evaluation well licences between Sept. 1 and Dec. 3, 2010, compared to just 387 licences issued in the same period of 2009. By far the most went to Cenovus Energy Inc., which licensed 479 evaluation wells. Licences are in effect for five years, so there is no guarantee the wells will be drilled in 2011, but they give some indication of exploration and new project development interest. There were 2,406 oilsands evaluation licences issued in Alberta from November 2008 through January 2009, the three months of the year in which most oilsands evaluation licences are approved. That was a nearly 50 per cent drop compared to the 4,683 licences issued in the same three months a year earlier.

The oilsands evaluation wells are non-production wells and can include core holes/stratigraphic tests, delineation/appraisal wells, observation wells and water wells—all oilsands related, predominantly in situ. D u r i ng 2010 Ca nad ia n Nat u ra l Resources Limited drilled between 200 and 220 strat/observation wells on its thermal oilsands leases with the exception of Pelican Lake. Cenovus has licensed the most wells by far— 479 evaluation wells, including about 450 stratigraphic wells in its winter program. About half of those strat wells are designed to expand contingent resources and advance new projects into the regulatory queue. That’s double what it plans to drill this year (220 gross wells). This year Cenovus plans to drill 160180 gross stratigraphic wells at its operating in situ oilsands projects: 110-120 at Foster Creek and 50-60 at Christina Lake, and 40-45 strat wells at Pelican Lake–Wabiskaw.

Next is Devon Nec Corporation with 140 evaluation wells licensed. Devon Canada Corporation has licensed eight wells. At Devon’s 50/50 bitumen joint venture with BP plc about 11 rigs will be working on thermal oil projects this winter, primarily drilling stratigraphic wells at Pike (formally called K irby) where Devon has begun the appraisal d r i l l i ng requ i red to deter m i ne t he optimum development configuration. Devon expects to complete appraisal drilling at Pike this winter with a goal of launching the regulatory process for the first phase of development around the end of 2011. Canadian Natural has reported it is drilling 385 stratigraphic wells this winter: 40-50 at Pelican, 50 at Grouse, 104 at Primrose, 41 at Kirby, 120 at Birch Mountain East and 20 at Germain. Sunshine plans to drill 133 core holes at a cost of between $75 million and $80 million, as well as two water wells and 12 development wells. “It’s quite a program we’ve co-barrelled together,”

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J anuary / F e b ruary 2 0 1 1 • O I L & G A S I N Q U I R E R

Northeastern Alberta

said John Kowal co–chief executive officer of the private Calgary-based company. T h i s ye a r ’s c or e hole s w i l l b e s c a t t e r e d t h r o u g h o u t S u n s h i n e ’s 1.1 million acres at its Harper, Ells, Thickwood and Legend Lake leases. Sunshine aims to convert a portion of its barrels of petroleum initially in place to best-case contingent barrels. “It’s a very aggressive program that puts us into the next stage of growth,” said Kowal. The company has applied for its 10,000-barrel-per-day West Ells plant, submitted and received approval for its Harper carbonate pilot plant and begun production of cold flow at its conventional heavy oil in the Muskwa area. Muskwa cold-flow production, currently just under 200 barrels per day, commenced Sept. 30 and is ramping up, he said. The first pad of six wells has been built, the second pad has been constructed and the third well of 10 has been completed. In 2010 the company drilled 17 core holes and three test wells. In the company’s four years of existence, it has drilled 78 wells, including test wells.

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Imperial will drill up to 16 oilsands evaluation wells in its Cold Lake area of Alberta and an undisclosed number of core holes in its acreage south of Fort McMurray, spokesman Pius Rolheiser told the Daily Oil Bulletin.

its first small cyclic steam pilot for this winter, including 54 stratigraphic test wells designed to prove up the acreage in the Peace River region of northwestern Alberta. That’s a 75 per cent increase in the number of stratigraphic test wells,

“[This year's core hole drilling is] a very aggressive program that puts us into the next stage of growth.” — Simon Henry, Chief Financial Officer, Shell

Pengrowth Corporation will drill three core holes to help delineate its proposed Lindbergh steam assisted gravity drainage pilot project in eastern Alberta, near the Saskatchewan border, next year. That is the same amount of core holes drilled this year, said Wassem Khalil, manager of investor relations. Southern Pacific Resource Corp. says it will drill up to 35 wells this winter at its proposed STP-McKay thermal project, 40 kilometres northwest of Fort McMurray. That compares to 21 such wells drilled last year. Penn West Energy Trust has budgeted $70 million for construction of

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most of it focused in the thermal area, the trust drilled in the last eight years, said David Middleton, Penn West’s executive vice-president of engineering and managing director of the joint venture with Chinese sovereign wealth fund China Investment Corporation. A lso under the 2010-2011 Peace River program Penn West plans to drill 12 horizontal appraisal wells in some of the areas where stratigraphic wells were drilled in past years. Seven rigs will be used for the appraisal program. Athabasca Oil Sands Corp. has said it plans to drill in the Birch, Grosmont,

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Northeastern Alberta Dover West and Hangingstone areas this winter, expecting to employ 14 rigs to drill approximately 140 core-hole wells. In addition, it plans to acquire three 3-D seismic surveys of approximately 60 square kilometres as well as approximately 130 kilometres of 2-D seismic data. MEG Energ y Cor poration’s 2011 budget includes $80 million to $90 million for core drilling and seismic programs at Christina Lake, Surmont and growth properties, on MEG’s 800 square miles of 100 per cent-owned oilsands leases Alberta Oilsands Inc.’s Grand Rapids area 2010–2011 exploration season, comprised of 10 core holes and 15 contingent locations, will provide a first estimate of potential on its 18 sections. The initial Algar Lake exploration plan calls for approximately 20-30 bitumen core holes and 30 contingent locations. Grizzly Oil Sands ULC has four rigs and a 90-well core-hole drilling program lined up for this winter: 40 core holes at Thickwood, 25 at its Firebag lease (east of Suncor’s existing Firebag project) and 25 at its Algar Lake area, said chief executive officer John Pearce. It didn’t drill any last year because the company was without a

vice-president of exploration, said Pearce. It has since hired one. Grizzly drilled 62 delineation wells during the 2006-2007 winter drilling season and an additional 64 wells during the winter seasons in 2007, 2008 and 2009. Connacher Oil & Gas Limited has reported it will drill about 80 core holes this coming winter in its Great Divide region, where its exploration program is being initiated this year. Harvest Operations Corp. has said it is ramping up work on its BlackGold thermal bitumen project in northeastern A lberta and will spend bet ween $450 million and $500 million on the project by the end of 2012. The company said details of this year’s spending will be disclosed when it releases its 2011 budget. During the period of Sept. 1 to Dec. 3, 2010, Marathon Oil Corporation licensed 97 wells, Nexen Inc. licensed 86 wells, Suncor Energy Inc. licensed 34 wells, Imperial Oil Resources Limited licensed 29 wells, ConocoPhillips Canada Limited licensed nine wells, Statoil Canada Ltd. licensed 13 wells and Koch Exploration Canada G/P Ltd. licensed one well.

AKITA Drilling Ltd. has about six singles rigs in its shallow fleet that will drill observation or delineation wells for oilsands that are in high demand for heavy oil in 2011, said Karl Ruud, president. “The demand for heavy oil coring operations is very high for two reasons: one, the oilsands business appears to be active and secondly, some of those programs were deferred after the 2008 meltdown, so there was kind of a season that was taken off, so I think a lot of the projects are back on and starting to go.” Getting enough competent people to crew them, however, is “very, very difficult,” said Ruud. Akita has had to turn down a couple of jobs because it does not have enough manpower to operate the rigs, he said. Precision Drilling Trust has 30 conventional shallow rigs that will drill core holes this winter, said Doug Evasiuk, vicepresident of sales and marketing. He estimated that number was up over a year ago. Calmena Energy Services Inc. has reported signs of a significant increase in heavy oil and oilsands coring projects, which will result in higher pricing and nearly 100 per cent utilization for its single rigs. — DAILY OIL BULLETIN

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Alberta Crown land sales in 2010 are second-highest ever at $2.4B

The province’s previous record for non-oilsands land sale revenue was $1.83 billion in 2005.

Alberta’s final land sale of $207.5 million on Dec. 15 was icing on the cake for the Alberta government, which received the second-largest annual bonus spending from auctions of Crown land, a sign of industry’s renewed interest in the province following introduction of a much improved royalty regime. The year ended with a total of $2.4 billion in bonus bids flowing to the provincial treasury on 3.9 million hectares (ha) sold. That puts 2010 second only to the 2006 tally when Alberta attracted $3.43 billion in bonus bids thanks to heavy spending for oilsands acreage. The average price per hectare for 2010 was $606.13, up 51 per cent from $402.63 per ha in all of 2009. The Dec. 15 sale capped off a record year of auctions of Crown rights (excluding oilsands acreage) as the province netted a total of $2.39 billion. This was the

first time the province exceeded $2 billion. The previous record for non-oilsands land sales was $1.83 billion set in 2005.

130,322 ha compared to last year’s $9.9 million for 101,449 ha. In 2010, producers continued to scoop up land in the Deep Basin, the Duvernay tight/shale gas play attracted attention, while the Exshaw formation emerged as a hot spot earlier in the year as interest in the southern Alberta Bakken play in Montana spilled across the border. Highlights of the Dec. 15 sale included seven licence parcels northwest of Red Deer bet ween 43- 4W5 and 44 -7 W5 that combined for total bonus bids of $144.5 million. All the parcels were acquired through brokers. “Almost all those lands were deeper rights only; most of them below the traditional producing zones Cardium down to Rock Creek,” said Brad Hayes, president of Petrel Robertson Consulting Ltd. “We are too far south for the Montney; it doesn’t occur in this area. We are near the southern limit of the Western Shale Basin where the Duvernay shale was deposited, so I would speculate that the Duvernay is a primary target.”

“ This is excellent news for the province. It shows Alberta continues to remain competitive and attract new investment.” — Ron Liepert, Energy Minister

“This is excellent news for the province. It shows Alberta continues to remain competitive and attract new investment,” Energy Minister Ron Liepert said. “I credit changes to the royalty structure, particularly the emphasis on using new technologies, for contributing to these record sales. These historic land sale results solidify Alberta’s status as the jurisdiction for industry to invest.” Oilsands acreage in 2010 attracted $26.8 m i l l ion i n b onu s bid s on

The Soo Line Resource Group Ltd. produced the bonus high bid of $40.2 million for the rights to an 8,192 ha licence. The broker picked up several sections at 43-4W5, 44-5W5, 43-5W5 and 44-4W5, paying $4,910 per ha. Cavalier Land Ltd. picked up an adjacent 8,192 ha licence at 43-6W5, paying $32.9 million for several sections at an average of $4,028. Badger Pass Minerals Inc. also scooped up an 8,192-ha licence parcel at 43-6W5, paying a bonus of $22.5 million at an average of $2,743.

DEC/09

DEC/10

WELLS DRILLED

194

266

CENTRAL ALBERTA WELL ACTIVITY

DEC/09

DEC/10

DEC/09

DEC/10

WELL LICENCES

293

288

WELLS SPUDDED

184

249

▲

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • J A N U A R Y / F e b ruary 2 0 1 1

Central Alberta

Daily Oil Bulletin records show that several wells were licensed in the area in December. Penn West Petroleum Ltd. has licenced four wells in the area. On Dec. 14, the company licensed two planned development horizontal oil wells in the Pembina area with the Cardium formation as the total depth zone. One at bottom location 15-18-45-5W5 has a projected depth of 3,190 metres, the second at bottom location 16-18-45-5W5 has a projected depth of 3,165 metres. “We don’t comment on land sales. Mostly we buy as Penn West,” Bill Andrew, Penn West’s chief executive officer said in an email response, when asked if the company picked up any of the largebonus acreage.

Hayes said that a combination of factors drove producer interest in Alberta land this year. “From the geological point of view, we have known for some time that liquids-rich and oily unconventional targets like the Duvernay and southern Bakken might have potential, but companies concluded in 2010 that the potential could be economic and thus they began to move on buying lands on these plays,” he said. Interest in the Montney and Cardium expanded as companies tried out new technologies on these formations and found success in some areas, Hayes noted. “For all these unconventional plays, large areas can be prospective and the potential rewards are great because of large oil in place and gas in place potential, so we saw high land

“ Continued technological refinements, particularly in the areas of horizontal drilling and multi-frac completions, contributed greatly toward making the hydrocarbon potential of these zones economic.” — Brad Hayes, President, Petrel Robertson Consulting

On Dec. 14, Harvest Operations Corp. licensed a development gas well in the Willesden Green area at surface location 4-1-44-8W5 with the Notikewin member as the total depth zone. The well has a projected depth of 3,533 metres. Two parcels at 66-8W5 combined for total bids of $10.5 million. One of the parcels produced the land sale per-hectare high of $5,415 with LandSolutions Inc. paying a total bonus of $4.2 million for the 768 ha parcel. The broker acquired the rights to sections 14-16 at 66-8W5.

prices over relatively large areas,” he said. “Continued technological refinements, particularly in the areas of horizontal drilling and multi-frac completions, contributed greatly toward making the hydrocarbon potential of these zones economic.” Continued good oil and liquids prices also contributed to the economics and the royalty revisions, particularly those aimed at promoting deep and horizontal drilling, also helped, Hayes added. “There is still sufficient land available in Alberta in the geological fairways of interest to support

good land sale prices into 2011,” he suggested. “Interest will spread somewhat from the current hot spots as companies refine their ideas regarding prospectivity in these intervals and post acreage outside of what is currently regarded as the best sweet spots.” If gas prices improved, for example, there could be a resurgence of interest in gassier targets in the Deep Basin, Hayes said. This would impact both the plays being accessed with horizontal wells like the Wilrich and areas where vertical wells are drilled and completed in numerous stacked lower-quality reservoirs. Gary Leach, executive director of the Small Explorers and Producers Association of Canada (SEPAC), noted that while the trend of land sales in Alberta was visible throughout 2010, he was surprised by the persistent strength of the rebound all year, which finally reached three times the total for 2009 “Given the depressed state of natural gas prices, overall, the land sale totals tell you that other things like potential shale targets, oil resource plays and of course the changes and incentives from the royalty adjustments were very strong drivers of spending on land sales,” Leach said. “This is a very competitive industry and with the fast moving changes we’ve seen in the last 24 months, such as where the new resource potential lies, have forced companies to move fast and spend money to make sure they are positioned to take advantage of these new opportunities,” the SEPAC president said. “I doubt this level of spending would be seen two years in a row, but 2011 promises to continue to be a good year for land sales.” — DAILY OIL BULLETIN

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J A N U A R Y / F e b ruary 2 0 1 1 • O I L & G A S I N Q U I R E R

Central Alberta

Devon Energy focuses on Cardium/Viking oil and bitumen in 2011 During 2011, Devon Energy Corporation plans to pursue light and heavy oil projects while spending minimal capital in the Horn River shale gas play. The company holds about six million acres in the Western Canada Sedimentary Basin. “We have a large number of oil and liquids-rich plays in Canada that we’re pursuing,” said Dave Hager, executive vicepresident of exploration and production. “They’re in the early stages, most of them, but they could grow into something material over the longer term.” In the Ferrier area of west-central Alberta, Devon plans to evaluate Cardium light oil plays with horizontal wells in 2011. “Additionally, we’re going to be pursuing a number of other zones horizontally with multi-stage fracturing targeting liquids-rich gas and light oil,” Hager told the company’s 2010 third-quarter earnings conference call. This year, the company expects to be “testing the Viking light oil play where we have about 900,000 acres of fee lands in Saskatchewan,” Hager said.

Canadian capital spending this year is expected to be similar to the estimated 2010 spending of about $1 billion, said Nadine Barber, a spokeswoman for the Canadian subsidiary, Devon Canada Corporation. Hager said the company will probably have about 20 rigs working in Canada this winter and roughly eight to 10 through the rest of the year. About 11 rigs will be working on thermal oil projects, primarily drilling stratigraphic wells at Pike (formally called Kirby)— Devon’s bitumen joint venture with BP plc. At Pike, Devon has begun the appraisal drilling required to determine the optimum development configuration. “We expect to complete appraisal drilling this winter with a goal of launching the regulatory process for the first phase of development around the end of 2011,” Hager said. Also during the winter, Devon expects to run a couple of rigs at Lloydminster and about seven or eight more on other Canadian plays such as Cardium light oil, he said. Company-wide, Devon will continue to steer clear of dry gas in its 2011 spending,

given the outlook for continued weak gas prices and strong oil prices, president John Richels indicated after releasing the company’s 2010 third-quarter results. Devon Canada reported slightly lower production in the third quarter. “Given the significant divergence of oil and natural gas prices, similar to what we did in 2010, we expect to focus more than 90 per cent of our 2011 capital on oil and liquids-rich opportunities within our existing portfolio,” Richels told the conference call. That means the company that established its reputation as a shale gas oper ator in the Barnett shale of Texas won’t be doing much in northeastern British Columbia this year. “Given that the Horn River is dry gas, we plan to spend minimal capital there in 2011,” Hager said. However, Devon is happy with its 2010 Horn River results. The company drilled all seven horizontal wells slated for this year. Four have been completed, and Devon expected to have them tied in and producing by the end of 2010.

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O I L & G A S I N Q U I R E R • J A N U A R Y / F e b ruary 2 0 1 1

Central Alberta

“ Given the significant divergence of oil and natural gas prices, similar to what we did in 2010, we expect to focus more than 90 per cent of our 2011 capital on oil and liquids-rich opportunities within our existing portfolio.” — John Richels, President and Chief Executive Officer, Devon Energy

“Our producing wells at Horn River continue to perform better than expected, supporting an average EUR [estimated ultimate recovery] of seven to eight bcf [billion cubic feet] equivalent per well,” Hager said. Devon’s Horn River wells are recovering about one million cubic feet of gas per day per frac stage. “That’s what we wanted to see,” said Hager. “We’ve been doing them so far in the order of four to eight stages, although we haven’t really decided what the optimum number of stages will be when we go to full development. Those wells have been costing on the order of about $8 million per well completed.”

In northeast Alberta, net production from Devon’s Jackfish thermal oil project averaged 21,300 barrels per day (net of royalties) in the third quarter. The steam assisted gravity drainage (SAGD) pro ject was taken offline for scheduled plant maintenance for the last three weeks of the third quarter and resumed operations on Sept. 30. Construction of Devon’s second Jackfish thermal bitumen project is now about 90 per cent complete and is “continuing to trend under budget,” Hager said. The company plans to start steam injection at Jackfish 2 in the second quarter of 2011,

with first oil expected in late 2011 and production ramping up through 2012. In the third quarter of 2010, Devon sanctioned its third Jackfish development project and filed a regulatory application. Pending regulatory approval, site work and facilities construction at Jackfish 3 could begin by the end of 2011, and plant startup could occur in 2015. Devon operates the Jackfish projects and owns 100 per cent working interest. “Between Jackfish and Pike, we expect to grow our SAGD oil production to between 150,000 to 175,000 barrels per day by 2020,” Hager said. “Assuming a similar level of drilling activity for 2011—with some inflation for service costs—I would expect our [company-wide] 2011 E&P [exploration and production] capital budget [to range] between $4.5 [billion] and $4.9 billion,” Richels said. — DAILY OIL BULLETIN

Keyera constructs Carlos gas-gathering pipeline in Hoadley district K e ye r a Fac i l it ie s I ncome Fu nd announced on Dec. 15 that it is proceeding with construction of the Carlos pipeline southwest of the Keyera Rimbey gas plant into the Hoadley region of central Alberta. The pipeline will allow producers in the area to deliver liquids-rich gas to the Rimbey plant, which is equipped to remove a high percentage of natural gas liquids (NGLs) from the gas stream. The Hoadley area is undergoing active development, as multiple producers target liquids-rich natural gas reserves found in the Glauconite geological zone. The 45-kilometre, 12-inch raw gas– gathering pipeline is expected to be in

service in the second quarter of 2011 and has already received all regulatory approvals. Total cost is estimated to be $30 million. To support this project, Keyera has secured a long-term, fee-for-service transportation and processing agreement with Bonavista Energy Trust, a major producer in the area. Bonavista, as operator, has drilled 51 horizontal wells into the Glauconite, including 31 in 2010 and had 48 wells on production as of November 2010. It has budgeted to drill a further 42-45 wells this year and plans to build an 80-millionc ubic-feet-per- day compressor a nd dehydration station at Gilby.

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“We are extremely pleased to work with our customers and extend our pipeline infrastructure into highly prospective regions like the Hoadley area,” said Jim Bertram, president and chief executive officer of Keyera. “With the construction of the Carlos pipeline project, we will be able to deliver NGL-rich production in the area to our Rimbey plant, which is one of the most flexible and efficient gas processing plants in Canada. The Rimbey plant is able to extract a “deep cut” of NGLs; fractionate them into specification ethane, propane, butane and condensate; and deliver these products directly into the Edmonton/Fort Saskatchewan NGL energy hub.

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Southern Alberta

Changing western Canadian well profile helps service sector

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By Paul Wells and Richard Macedo

PSAC expects oil-related drilling to account for two-thirds of total activity in 2011.

The changing well profile in the Western Canadian Sedimentary Basin (WCSB) means “less is more” and the overall well count is no longer the main barometer in judging future activity levels in the service sector, says an industry analyst. “There has been a shift in the nature of activity here in western Canada and in our view the well count no longer tells the true story of the health of the services business,” says Dan MacDonald of RBC Capital Markets. MacDonald, who is calling for about 12,000 wells to be drilled in the WCSB in 2011, expects that oil and liquidsrich natural gas activity “will more than offset reductions in dry gas spending” next year. “We continue to see growth in the oil well count in 2011. We expect that to be up by 11 per cent and we continue to expect horizontal well counts to go up another 26 per cent,” he told

the Petroleum Services Association of Canada’s (PSAC) Canadian drilling activity forecast and industry outlook session in November. “ T h is is dr iv i ng i nc reasi ng service intensity for oil. And based on our

“I’m not going to pretend that sub-$4 gas is good for anybody—it’s definitely not. But I don’t think, given the changing nature of what we’re doing now here in western Canada, that $4 gas is quite the death sentence it would have been for activity levels just a few short years ago,” MacDonald said. His natural gas outlook remains muted and he’s calling for an average price of US$5 per thousand cubic feet in 2011, with a bump to $5.50 in 2012. He expects crude prices will remain stable and in the low to mid-US$80 West Texas Intermediate (WTI) range into 2012. MacDonald said that based on RBC’s projections of slightly improving economic conditions in t he United States’s economy next year, “We do definitely have some reason for optimism on the natural gas side in the second half of 2011 and definitely leading into 2012.” Despite forecasted well counts for next year that will see about half the holes punched in western Canada than the heady days of the mid-2000s, the changing well profile in the basin means strong metres drilled and rig operating day numbers for the service sector going forward. And that marks a “new beginning” for service providers, PSAC’s outgoing

"Based on our estimates, we believe that the average well costs from 2009 to 2011 are going to increase about 45 per cent." — Dan MacDonald, RBC Capital Markets

estimates, we believe that the average well costs from 2009 to 2011 are going to increase about 45 per cent,” MacDonald noted. Only a few years ago, he suggested, languishing low gas prices would have had far more impact on the industry than they do this time around.

president Roger Soucy told the outlook session. PSAC was forecasting that 11,350 wells would be rig released last year and that number will rise by eight per cent to 12,250 in 2011, led by oil-related activity, which will account for 63 per cent of the wells drilled this year.

DEC/09

DEC/10

WELLS DRILLED

223

329

SOUTHERN ALBERTA WELL ACTIVITY

DEC/09

DEC/10

DEC/09

DEC/10

WELL LICENCES

284

160

WELLS SPUDDED

226

312

▲

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • J A N U A R y / F e b ruary 2 0 1 1

Southern Alberta

“Although still a long way from the almost 25,000 wells drilled in 2005, it represents a new beginning on a number of fronts,” Soucy said, noting that PSAC is calling for total rig operating days to increase 25 per cent to 108,000 in 2011 from an estimated 86,300 last year, and meterage to jump to 19.93 million (1,626 per well on average) in 2011 from 16.2 million (1,425 per well) in 2010. “These are all positives for the service and supply industry.” Incom i ng PSAC c ha i r ma n Br ia n Coston said that the horizontal well count in the WCSB has increased from 2,000 in 2009 to 4,540 in 2010 —an increase of 125 per cent. “This reflects the changing technology and the industry’s ability to quickly adapt to different circumstances,” he said. And that change means that despite fewer wells being drilled than in the mid-2000s, meterage is holding its own. Coston noted that in 2006 the industry drilled 23,000 wells at a total of roughly 28 million metres. In 2011, 12,250 wells are expected to be drilled at about 20 million metres, which means “there’s

just over half as many wells in 2011 from 2006 but with 76 per cent of the metres drilled.” David Yager, outgoing PSAC chairman, said the move toward more technologically challenging drilling with a focus on oil targets is positive for the service sector, but not across the board. “The switch to oil from gas drilling, while obviously the activity increase is positive, the participation, if you will, by the service sector is changing. Companies that can win through this are well known—the pressure pumpers, the horizontal drillers, rigs in certain size classes,” Yager said. “But from 1992 to 2008, 70 per cent of the wells drilled in western Canada were natural gas. Natural gas obviously has its own set of challenges, so consequently oil service participation is a bit uneven, particularly for many companies who have hung their hat on natural gas drilling, possibly for the better part of a generation,” Yager added. Chris Theal, president and chief e xec ut ive of f icer of newly m i nted Kootenay Capital Management Corp.

and former oil and gas industry analyst with Macquarie Capital Markets Canada, agreed that the dramatic growth of horizontal drilling and multistage fracturing activity will continue to dominate the operational landscape in western Canada and is unlocking even more tight oil plays. “That’s really created new demand for rigs and specialized services in the service industry…. We’re drilling more oil wells in the basin, more than we have in 25 years,” Theal said. He expects the natural gas market to begin correcting itself over the coming months. Land retention–related drilling in some major U.S. shale plays is nearing an end, and with the forward strip price for natural gas limiting hedging opportunities, Theal expects the U.S. rig count to drop in 2011. “I think we’re at the point of maximum pessimism. We’re going to see budgets over the next six to eight weeks come out and realign with the reality of the gas market, ultimately translating into reduced shale activity,” he said. — DAILY OIL BULLETIN

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Drilling rig fleet utilization rate surges to 47 per cent in 2010 A 59 per cent surge in active drilling rigs in 2010 combined with another dec l i ne i n t he tota l ava i lable f leet pushed f leet utilization to 47 per cent in 2010, almost 20 percentage points more than 2009 and even with 2008 f leet utilization. The final Rig Locator survey of 2010 showed 458 active drilling rigs in western Canada; the full year average stands at 374 working units, up from a ver y weak 236 active rigs in 2009. The 2010 average was higher than in 2009, 2007 (370 active rigs) and 2002 (300 rigs), but lower than in all other years since the turn of the century. The peak year for drilling was 2005 when an average of 527 rigs were at work in western and northern Canada. The peak years for f leet utilization occurred between 2000 and 2006 when utilization rates ranged from a low of 61 per cent to a high of 71 per cent with the exception of 2002 when a drilling downturn lowered utilization to only 45 per cent.

For the earlier years in the past decade strong utilization rates were supported by a smaller fleet size of less than 700 available rigs in Canada. The fleet size climbed during the decade, peaking at 863 available units in 2007. The average fleet size for 2010 was 802 units, marking the third consecutive year of a declining fleet. A strong increase in drilling in Alberta, Saskatchewan and Manitoba with a smaller rise in gas-prone British Columbia was seen in 2010. Alberta operators employed an average of 237 drilling rigs in 2010, up 68 per cent from only 141 in 2009. Still the 2010 active rig count in the province was the fourth lowest since 1997 due to weak natural gas prices. High oil prices helped Saskatchewan post its best drilling year since 1997. An average of 69 rigs were at work in the province in 2010, up 63 per cent from 43 rigs in 2009 and 67 rigs in 2008. Likewise, Manitoba, which is undergoing a drilling boom thanks to horizontal wells with multistage fracs, saw its average working

rig count more than double to 10 rigs in 2010, a record high for the province. B.C. operators employed an average of 57 rigs in 2010, 21 per cent more than in 2009 but well below the peak years of 2005 and 2006 when over 70 rigs were active in the province. The late December 458 active drilling rig count was 121 units higher than the previous year. The weekly rig count in 2010 exceeded 2009 counts all year. The busiest two operators one week were Husky Energy Inc. with 25 rigs on the go and ConocoPhillips Canada Limited with 24 active rigs. Service rig fleet utilization also rose in 2010 mainly due to a sharp decline in the fleet to 887 available units, the lowest since 2004 and down from 1,094 rigs available for work in 2009. Overall, an average of 481 service rigs were at work in 2010, up from 430 rigs a year earlier. The peak year was 2006 when 668 rigs were employed. Fleet utilization jumped to 54 per cent in 2010 from 39.3 per cent in 2009. — DAILY OIL BULLETIN

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O I L & G A S I N Q U I R E R • J A N U A R Y / F e b ruary 2 0 1 1

Southern Alberta

Frac service providers now rival drillers in financial performance Calfrac’s nine-month revenues rose by $249 million from 2009 to $667.2 million and Canyon’s revenues surged to $130.7 million from $32.72 million a year earlier, a gain of $98 million. With higher drilling activity in 2010, both Precision and Ensign also booked more revenues to the end of September 2010 but the gains ($82.7 million and

$92.8 million, respectively) were a bit more modest. Precision’s nine-month revenues totalled $994 million while Ensign’s revenues reached $952 million. A s a g r oup, t he 55 r e p or t i n g companies had a combined third-quarter profit of $395 million with the largest net loss reported by Divestco Inc. (a loss of $49.88 million). The $395 million compares to a net loss in the second quarter of 2010 for the entire group of companies and a third-quarter 2009 profit of $222.6 million. T hird-quarter cash f low totalled $999 million (the highest in 2010), which was 66 per cent more than the $601 million in funds f low recorded a year earlier. Over the first three quarters of 2010, cash flow totalled $2.21 billion,

Fracturing companies appear poised to increase their capital spending again in 2011. 62

13 per cent more than 2009 but still below the 2008 total of $3.16 billion. Nine-month revenues were also stronger than 2009 but still $3.7 billion below in 2008. Despite improved fortunes in 2010 service and supply companies as a group were restraining capital spending in 2010 with $1.52 billion invested to the end of September (excluding acquisitions), down

As a group, the 55 reporting companies had a combined third-quarter profit of $395 million.

Photo: Encana Corporation

Service companies assisting producers with fracture operations were the star financial performers in the third quarter of 2010, and Canada’s two largest public companies in this sector now rival the country’s big drillers in revenues. For the three months ended Sept. 30, 2010, the largest year-over-year profit increases occurred at Trican Well Service Ltd. (up $61.13 million), Calfrac Well Services Ltd. (up $28.35 million) and Canyon Services Group (a gain of $22.11 million from the third quarter of 2009). Precision Drilling Corporation still had the highest third-quarter profits ($61.08 million) out of 55 reporting companies but Trican was a close second at $53.74 million and Trican’s third-quarter revenues of $407.75 million were higher than Precision’s $359 million. Since t he f irst quar ter of 2009, Trican’s revenues have grown by $140 million while Calfrac’s revenues climbed from $180 million to $275 million in the third quarter of 2010, an increase of about $95 million. Over the same period (Q1, 2009 versus Q3, 2010), Precision’s revenues declined $89 million while Ensign Energy Ser vices Inc.’s revenues dropped by $59 million to $341 million. For the first three quarters of 2010, Trican’s revenues topped $1 billion and the company posted the largest year-over-year increase ($452.7 million more than in 2009).

J A N U A R Y / F e b ruary 2 0 1 1 • O I L & G A S I N Q U I R E R

from $1.85 billion in 2009 and $2.56 billion in 2008. The biggest increase in investments, not surprisingly, is occurring in the fracturing service companies, led by Trican, which invested $198 million (excluding acquisitions) to the end of September, up $166 million from 2009. Similarly, Canyon Services invested $55 million more than in 2009, while Calfrac’s capital spending was $30 million higher. Ensign was also more aggressive on the investment front in 2010 with a capital outlay of nearly $151 million, $33 million more than in 2009. Acquisition activity also remained muted with an outlay of $388 million over the first three quarters of 2010. While only nine service companies have announced their 2011 capital spending plans, the trend is up from the initial 2010 capital budgets announced late in 2009 and ahead of what the nine companies were actually going to invest in 2010. Many of them hiked their budgets for the year as demand for services grew and activity levels turned out to be better than expected. T he nine companies w ill invest $1.47 billion on capital expansion projects in 2011, an increase of $777 million from the initial 2010 capital spending budgets and $180 million more than what actual capital spending was expected for 2010. The main reason for the increase last year is Precision’s 2011 capital spending budget of $405 million, which compares to a 2010 budget of $218 million. — DAILY OIL BULLETIN

Southern Alberta

Industry ramped up its spending in the third quarter of 2010 Despite weakening cash flow as natural gas prices declined, operators working in Canada pushed forward aggressively with capital spending in the third quarter, investing some $5 billion more than a year earlier and $2.68 billion more than in the second quarter of 2010. A total of 75 out of 127 reporting producers invested more in capital expenditures than their cash flow in the third quarter, resulting in capital outlays (including $4.34 billion in acquisitions) exceeding cash flow by $6.4 billion. Excluding acquisitions, producers’s capital spending totalled $12.42 billion for the three months ended Sept. 30, 2010, comparable to spending levels in 2006-07 but way more than the recession-induced weak investment level of $7.45 billion in 2009. A pick-up in oilsands investment by some companies and increased drilling at higher costs (due to the preponderance of horizontal well and multi-frac operations) are the main reasons for the higher capital spending in 2010, which totalled about

$33 billion to the end of September, up from only $24.29 billion a year earlier. Excluding acquisition investments, only 16 producers reported lower capital spending in the third quarter of 2010 compared to a year earlier while 98 companies invested more than last year. The largest decreases occurred at Connacher Oil And

spending increases occurred at Imperial Oil Limited (up $1.38 billion from 2009), which is building a new oilsands mine and Suncor Energy Inc. (up $1.28 billion), which restarted its Firebag expansion this past year. Husky Energy Inc., Crescent Point Energy Corp. and Talisman Energy Inc. also invested a lot more in 2010 although

A pick-up in oilsands investment by some companies and increased drilling at higher costs (due to the preponderance of horizontal well and multi-frac operations) are the main reasons for the higher capital spending in 2010. Gas Limited (down nearly $51 million) and Nexen Inc. (off $48 million). Capital spending through the first nine months of 2010 was still more than $7 billion below investment outlays over the same period in 2008. Compared to 2009 (and excluding all acquisition spending), the biggest capital

most of Talisman’s investment occurred in the United States. Among the few companies with smaller capital programs in 2010, the largest were Nexen (down $153 million), Encana Corporation (off $133 million from 12009) and OPTI Canada Inc. (down $69 million). — DAILY OIL BULLETIN

GASFRAC plans to invest $150M in 2011 GASFR AC Energy Ser vices Inc. has announced a 2011 capital expenditure program of $150 million. The investment will expand the company’s hydraulic horsepower (HHP) by 45 per cent from 105,000 HHP in the first quarter of 2011 to 152,500 HHP in the fourth quarter of next year. In addition, the capital spending will include a 100 per cent increase in proppant and fluid-handling capabilities of the company. The increase will allow

GASFR AC to strive toward a capital balance of three proppant and f luidhandling systems per set of HHP, which will enhance HHP utilization and allow for larger volumes of liquefied petroleum gas to be pumped in a single fracturing stage. As part of this capital expansion, GASFRAC said it will construct a fracturing simulator which will be used as a training tool for new employees as the company staffs the additional equipment.

It is anticipated that the assets from this capital build program will be delivered in four sets, with the first assets being deployed and on stream in late August 2011 with the remaining assets being fully deployed and on stream by the end of November 2011. GASFRAC said it will be financing the capital program through a combination of cash, debt and cash proceeds from the sale of common shares.

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Korean subsidiary acquires Hunt’s Canadian assets in $525M deal Har vest Operations Cor p., a wholly owned subsidiary of Korea National Oil Corp., will pay $525 million to acquire Hunt Oil of Canada Inc.’s Canadian producing and undeveloped assets, including liquids-rich natural gas production with exposure to emerging tight oil plays in western Canada. “We’re buying not just for the sake of buying, we’re buying because we think we can do something with it and create some value,” John Zahar y, Har vest ’s president and chief executive officer, said on December 15. T h i rd qua r te r pr o duc t ion f r om Hu nt Oi l Compa ny of Ca nada I nc. and Hunt Oil A lberta Inc. consisted of approximately 11,720 barrels of oil equivalent per day consisting of 1,085 barrels of light oil, 3,050 barrels a day of natural gas liquids and 45.5 million cubic feet per day of natural gas. The Hunt assets, which are approximately 35- 40 per cent liquids, were one of the more liquids-rich packages on the

market, said Zahary. Following closing of the acquisition, Harvest’s weighting will be about 65 per cent crude oil and natural gas liquids. Harvest will be acquiring 52.9 million barrels of oil equivalent of proved plu s probable re ser ve s a s of Ju ne 30, 2010, as determined by Sproule A ssociates Limited. T he assets also include approximately 377,000 net acres of undeveloped land and complementary land positions in Willesden Green, t he Peace R iver A rch and sout her n Alberta, along with access to resource plays in the Willesden Green and in the Horn River Basin of northeastern British Columbia. The acquisition is complementary to most of the areas in which Harvest is already active, apart from the Horn River shale gas play, said Zahary. At Horn River, Hunt had approximately 54 sections and earlier in 2010 Hunt received BC Oil and Gas Commission approval for an experimental scheme to

evaluate and test shale gas potential in the Evie Bank area. Hunt, which entered Canada in 2000 with the acquisition of Newport Petroleum Corporation, is “definitely not leaving Canada,” a spokeswoman for the private Dallas-based company said. “We have developed a business plan that has a tighter focus in the Deep Basin, with more oil-prone assets as opposed to more diversified,” said Jeanne Phillips, senior vice-president, corporate affairs and international relations for Hunt Oil Company, its Dallas-based parent company. Mike Gilchrist, senior vice-president a nd genera l ma nager of Hu nt Oi l Ca nada, w i l l rema i n i n c ha rge of Canadian activities and strategy. The company will initially be focused on specific areas of the WCSB, emphasizing the application of the latest industry technologies in and around areas most likely to benefit from the application of these new technologies. — DAILY OIL BULLETIN

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Crescent Point Energy pegs its 2011 capital program at $800M

Crescent Point plans to drill about 200 wells in the Viewfield Bakken area during 2011.

With a focus on its core Bakken and Lower Shaunavon resource plays in Saskatchewan, Crescent Point Energy Corp. said that it will spend $800 million in 2011, 84 per cent of which will be used to drill and complete 311 net wells. The remainder of the budget is expected to be allocated to infrastructure investments, undeveloped land acquisitions and seismic. The 2011 budget represents a slight decrease from 2010. During the first nine months of last year, Crescent Point spent about $722 million (excluding acquisitions) and the company expected to spend about $925 million in 2010, more than double the $450 million projected in its initial 2010 budget. The company said the 2011 budget is expected to increase average daily production to more than 72,500 barrels of oil equivalent (boe) per day, weighted 90 per cent to light and medium crude oil

and liquids. The exit production rate next year is anticipated to be greater than 75,000 boe per day. Crescent Point’s output for the first nine months of 2010 averaged 58,875 boe per day. In 2009, the company produced an average of 44,883 boe per day. “We have grown year over year since inception, and we plan to continue that success in 2011 by focusing on the development and waterflood expansion of our core Bakken and Lower Shaunavon resource plays,” president and chief executive officer Scott Saxberg said on Dec. 15. Cash flow for 2011 is expected to be approximately $1.1 billion, based on forecast West Texas Intermediate pricing of US$85 per barrel, C$3.75 per thousand cubic feet AECO gas and a US99 cent exchange rate. In setting its 2011 guidance, the company said it has not included any upside relating to production performance associated with its Bakken waterflood program,

but has included the anticipated production impact of the shut-in and conversion of producing wells to water injection wells. Also, as a result of the wet weather conditions experienced during 2010, the 2011 guidance outlook assumes a longer than usual spring breakup during second quarter. Crescent Point said it expects to spend approximately 62 per cent of its 2011 budget in the Viewfield Bakken area of southeastern Saskatchewan, drilling approximately 200 net wells in the area in 2011. To accommodate continued growth of its Bakken production, Crescent Point said expects to invest up to $45 million in infrastructure projects. As part of its ongoing waterflood implementation project, the company expects to convert up to 23 net horizontal wells into water injection wells, increasing the total number of Bakken water injection wells to approximately 36 by year-end 2011. At its asset base in the Shaunavon area of southwestern Saskatchewan, Crescent Point plans to spend approximately 16 per cent of the 2011 budget, drilling approximately 44 net wells, which will target both the Lower Shaunavon resource play and the Upper Shaunavon emerging resource play. The company said it also plans to implement its fourth waterflood pilot in the Lower Shaunavon and to invest up to $27 million in infrastructure projects, including the construction of a gas processing plant, a central oil battery and expansion of the area’s crude oil and natural gas–gathering systems. Approximately 10 per cent of the budget is expected to be allocated to the company’s Flat Lake resource play in southeastern Saskatchewan and North Dakota, as well as the emerging resource plays like the Alberta Bakken in southern Alberta. Approximately 23 net wells are planned for these areas. The remainder of the budget will be allocated to Crescent Point’s other conventional properties in Saskatchewan and Alberta. — DAILY OIL BULLETIN

SASKATCHEWAN WELL ACTIVITY

DEC/09

DEC/10

WELL LICENCES

236

258

▲

DEC/09

DEC/10

WELLS SPUDDED

164

225

▲

DEC/09

DEC/10

WELLS DRILLED

189

270

▲

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • J anuary / F e b ruary 2 0 1 1

Saskatchewan

Saskatchewan looks to Chinese investors as potential oilsands partners Despite the province not yet having a commercial oilsands industry after years of testing, Saskatchewan Energy Minister Bill Boyd remains confident that the resource will eventually be developed. “The Chinese are very interested in dev elopments in Saskatchewan [and] oilsands developments,” he said. “We’ve had a team speaking to them for some period of time about the possibilities.” Given significant incremental capital required to advance its oilsands assets in Saskatchewan and Alberta and little in the bank to do so, Oilsands Quest Inc. said in August it was putting the brakes on its Axe Lake steam assisted gravity drainage pilot and Wallace Creek drilling program as it seeks strategic alternatives that could include the sale of the company. “We’re waiting to see what the next stages of [oilsands] development will be,” Boyd said. “I think you will see it developed in a very aggressive way once the technology and engineering challenges have been met. It’ll either be met by companies within Canada and the United States or it will be met by someone else.” Boyd said he’s heading to China in the early part of this year to speak to com panies about opportunities in the province. “We hope that through a process of bringing together investment dollars, we’ll see that area developed in Saskatchewan in the near future,” he added. Challenges exist with regard to having a sufficient road network and power infrastructure in the remote region of northwestern Saskatchewan, but Boyd was confident there will be solutions. “Some of the ways

we may be...looking at for power infrastructure is small nuclear reactors,” Boyd said. “We think there’s some good potential for that kind of application into more remote areas. We have the uranium as a province, so we certainly should be using it.” Speaking at The Canadian Institute oilsands symposium on Nov. 30, the minister said that technological and engineering challenges are the largest hurdles at the moment. “Our oilsands are much deeper into the earth’s surface and as a result of that, it will be in situ extraction methods that will be employed,” he said.

Boyd, meanwhile, said the province, led by Premier Brad Wall, has been a staunch defender of the Alberta oilsands in the United States, countering the “dirty oil” assertion south of the border by environmental groups opposed to oilsands development. “We think as a province, aligned with Alberta and British Columbia, we can be part of a solution for the energy security needs of Canada and the United States,” he said. “Our premier has been very aggressively...speaking to that [dirty oil] issue in the United States, about energy security and how much out

“[We are] looking at for power infrastructure is small nuclear reactors. We think there’s some good potential for that kind of application into more remote areas. We have the uranium as a province, so we certainly should be using it.” — Bill Boyd, Saskatchewan Energy Minister

“Perhaps things like the THAI [toe to heel air injection] will be a part of that, that’s a possibility. It’s not a case of companies just not being prepared to move in that area just yet, it’s a technological challenge, an engineering challenge.” O i l s a n d s Q ue s t a n n ou n c e d i n September that it was initiating a process to divest its Eagles Nest oilsands lease and Pasquia Hills oil shale permits, following a determination by the board of directors that these assets are non-core. The company retained TD Securities Inc. to assist the company in reviewing strategic alternatives and the sale process for these non-core assets. Petrobank Energy and Resources Ltd. also holds land in the Saskatchewan oilsands region.

of line that is with the reality of what’s happening in oilsands development. “We also talk about something that really resonates with the United States right now, and I think that is simply conflict-free oil. I think they’re getting that message loud and clear in Washington these days.” Boyd also reaffirmed past commitments that the province will not make changes to its royalty structure. “Oil, after all, is a very significant contributor to our economy,” he said, adding that 27,000 people are directly employed in the oil industry in the province and there is an annual investment of roughly $2 billion for exploration and development. — DAILY OIL BULLETIN

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Take your knowledge and skill set to the next level! PSAC’s Spring Conference is the only conference that provides ideas and practical solutions for oilfield service companies on transportation management, human capital management and personal development for frontline managers, operations and field staff. Conference Topics Include: • Hours of Service • Fatigue Management • HR 101 – What You Need to Know • Team Development • Corporate Social Media: Getting Noticed in the Virtual World • Recruiting and Keeping Key Talent • Industry Training Best Practices

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Register early for preferred pricing The knowledge you gain at this conference will help position you and your company at the forefront of the industry.

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To register, sponsor or request more information, contact the Petroleum Services Association of Canada: Email: info@psac.ca Phone: 403.264.4195 Web: www.psac.ca Industry Sponsor:

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Central Canada

Enbridge defends export project after federal MPs favour tanker ban

Banning tankers off northern B.C. could increase traffic in waters near Vancouver, Enbridge warns.

Enbridge Inc., which is proposing the Northern Gateway pipeline to the West Coast, has defended its proposal after Canadian Members of Parliament narrowly (143-138) supported an Opposition party motion urging the government to impose a formal moratorium on oil tanker traffic on British Columbia’s northwest coast. In early December, Liberal and Bloc Québécois parties backed the NDP motion calling on the government to immediately propose legislation to ban bulk oil tanker traffic through the Dixon Entrance, Hecate Strait and Queen Charlotte Sound off the north coast of British Columbia. The Conservative government is not required to act on the Opposition motion, Enbridge reacted to the political grandstanding against its project. “Contrary to the opening comments made by Mr. [Nathan] Cullen [NDP] in introducing the motion, there is no imminent risk and threat to B.C.’s north coast,” said company spokeswoman Gina Jordan. Jordan also expressed concern that a rigorous public regulatory process established by Parliament and conducted by two institutions created by Parliament is

“at risk of being ignored in a rush to come to judgment without the benefit of reviewing or testing the evidence on the matter.” Northern Gateway, whose pipeline would run from the Edmonton area to Kitimat, B.C., is committed to putting in place a comprehensive, world-class marine safety program for the project that would make the B.C. coastline a model of world-class marine safet y, said Jordan. This would include the use of only modern double-hulled tankers, independent B.C. pilots and International Maritime Organization–certified tanker crews, an escort tugboat tethered to laden tankers and a radar system to augment the automatic identification system being installed along coastal routes. All tankers would be vetted by a third-party agency before gaining entry to port. Over the past 25 years, more than 1,500 ships have safely travelled in and out of Kitimat, 250 tankers (50-60 of which are crude oil tankers) call annually at the port of Vancouver, and many more trade in eastern Canada, and worldwide. In 2009, Port Metro Vancouver reported

visits from 2,791 vessels of which 255 were tanker vessels that moved eight million tonnes (approximately 55 million barrels) of oil from Vancouver, of which four million tonnes (approximately 25 million barrels) was crude oil. A Joint Rev iew Panel (J R P) representing the National Energy Board a nd t he C a n ad i a n E nv i r on me nt a l Assessment Agency is currently reviewing the Gateway project. The panel will hold a public hearing on the proposed project to determine in terms of the Canadian Environmental Assessment Act whether the project will cause significant adverse effects on the environment and whether the project is in the public interest in the terms of National Energy Board Act. Parliament passed the Canadian Environmental Assessment Act and the National Energy Board Act to ensure that those with issues and concerns regarding environmental risks have an open and fair forum to have their views heard and their evidence given and verified, said Jordan. “Surely, it is in the public interest, today and with a view to all future projects for which hearings will be required to allow the JRP to conduct its proceedings in accordance with the relevant statutes and the wishes of Parliament.” In addition to the JRP review process, the marine components of the Northern Gateway Project are also undergoing a review under the TERMPOL Code, which sets out recommended standards for the safety and prevention of pollution for marine transportation systems and related assessment procedures. The purpose of this review is to identify and evaluate marine vessel movements and marine terminal operations. “It is ironic that one of the unfortunate outcomes of a successful Opposition motion would be to effectively support an increase in marine tanker traffic through the Port Metro Vancouver, the Strait of Georgia, Haro Strait and the Strait of Juan de Fuca,” said Jordan. — DAILY OIL BULLETIN

O I L & G A S I N Q U I R E R • J A N U A R Y / F e b ruary 2 0 1 1

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Energy service sector is poised for greater global growth in 2011

Baker Hughes’ revenue rose by an industry-leading 38 per cent in the first nine months of 2010.

The global oilfield service sector is poised for greater growth in 2011, despite being hit hard by last year’s Gulf of Mexico drilling moratorium, says an IHS Herold review of the sector. A general recovery is being driven by rising oil prices, unconventional drilling in North America and multiple offshore opportunities worldwide, said the Massachusetts-based consultancy. The review, which compared key oil company financial performance for the first nine months of 2010 against sector performance for same period in 2009, included both multi-service compa n ie s suc h a s Ba ker Hug he s Incorporated, Halliburton Company and Schlumberger Limited, as well as offshore drillers Transocean Ltd., Diamond Offshore Drilling, Inc. and Oceaneering International, Inc., among others. Many of the ser vice companies— and in particular the offshore drilling companies—took a financial beating following the Gulf drilling moratorium. Companies exposed to the Gulf incurred costs related to redeploying assets and personnel—primarily to onshore North America or international markets, said

John Parry, principal energy analyst at IHS and author of the service industry review. “With the lifting of the moratorium, the industry has moved to a more offensive posture,” he said. “While valuation of the underlying equities in the sector remain about 35 per cent below their peak in 2008, we believe strong oil prices and higher exploration and production budgets will help drive growth in the oilfield services sector in 2011. And current forward earnings estimates suggest a potential restoration to prior peak 2008 stock price levels by 2012.” Baker Hughes led the pack of multiservice providers with a 38 per cent increase in nine-month revenues to US$9.9 billion in 2010 from US$7.2 billion in 2009. It was followed by Halliburton, which posted a 17 per cent increase in revenues for the same period ($12.8 billion versus $10.9 billion). Cameron International Corporation saw its revenues rise 15 per cent during the period ($4.3 billion versus $3.7 billion in 2009). Of the six leading companies covered in the sector, only National Oilwell Varco, Inc. posted a revenue decline (six per cent or $8.9 billion in 2010 versus $9.5 billion

in 2009), but its earnings advanced 14 per cent to $1.4 billion. Shifting resources to meet strong demand for U.S. onshore drilling and other international projects helped many service companies turn the earnings tide back to a more positive flow, IHS Herold said. It noted that Baker Hughes reported that an improving North American fracture market and rising frac prices led to a strong backlog for pressure pumping in the third quarter, with wait times of 90-180 days. IHS Herold said Halliburton reported the North America shift into oil and liquidrich plays will lead to continued growth in overall activity for its U.S. land business and better prices and utilization rates. Multi-service providers fared better than offshore drillers, who either saw declines in revenue or marginal revenue growth. Oceaneering International was the only company in the segment to post positive revenue and earnings growth of three per cent and eight per cent, respectively. According to the IHS CERA Upstream Capital Cost Index (UCCI), upstream construction costs rose three per cent in the past six months after bottoming out during the previous six-month tracking period—an increase the report attributed to oil and gas activities worldwide. In the deepwater, six rigs left the Gulf for projects elsewhere, but the remainder stayed under contract and sat idle while waiting out the moratorium. Service providers to the rigs were also hard hit. “Even in shallow water where the moratorium was not enacted, the number of new wells drilled has been sharply lower,” said IHS CERA. “The subsequent lifting of the moratorium does not mean a return to business as usual, however. The return to drilling will be slow as operators and rig owners move to meet newly enacted certification processes.” IHS said its CERA UCCI report and its Herold oilfield service sector review both noted that idle rigs and a backlog of new rigs leaving the construction fields will lead to a softening of the rig market for the time being. — DAILY OIL BULLETIN

O I L & G A S I N Q U I R E R • J A N U A R Y / F e b ruary 2 0 1 1

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JOB Careers in the Oilpatch

Marlon Ellerby Age: 47 Title: President Company: Energy Auctions Inc. Education: High school diploma

What does your company do? Energy Auctions Inc. is the only auctioneering company that handles exclusively oil and gas equipment and operates exclusively online. Our larger competitors serve a variety of industries and their online selling is usually a sideline to holding live auctions in physical locations. How did you get into the auction business? My father Albert was the founder of Veteran Auction Market in the Coronation area of east-central Alberta, and I worked with him as a boy. It could be hard work—30 or 40 below, running spooked cattle

How can an online buyer be sure of what he’s

up and down the alley between the corrals, finishing some days at 4 a.m.

getting for his money?

Later, I did some seismic fieldwork and worked as an auto parts-

Evaluating the goods is a big concern whether the sale is taking place

man, but this business gets in your blood. In 2005, I became a part-

online or at a yard. If you’re looking for an oil and gas separator, a

ner in Highwood Livestock Auction and we also started the Direct

dehy unit, a compressor or a comparable piece of equipment, there

Livestock Marketing System. Operating 100 per cent online, we had

are many considerations—pressure capacity, valves, meter runs,

29 agents across western Canada and sold cattle throughout North

whether it meets regulatory criteria in your jurisdiction and so on.

America. After a much larger company bought us out, my wife [Janet]

Even at a big group sale, there likely won’t be more than one or two

and I started Energy Auctions Inc. in 2009.

suitable units. It’s easier to narrow your search online, then inspect the equipment either in person or through a professional agent.

What would you say is the key competitive advantage of an online auction versus selling through a yard?

Who are your customers?

Online, the customer can sell his equipment or goods where the

On the sell side, we’re working for some of the biggest producers as

items are currently located rather than paying freight charges to

well as other vendors. Our buyers include producers, service com-

move it. Most oilfield gear is heavy and bulky so the transporta-

panies and brokers who will resell the equipment. We get calls con-

tion saving is often significant. In fact, in some situations the online

stantly from CEOs and engineers. For us, the key is our email list of

alternative is the only way for the vendor to make a profit rather

buyers. At present, we send sale information notices to 5,500 quali-

than take a net loss on the sale.

fied oil and gas managers who have procurement authority.

O I L & G A S I N Q U I R E R • J anuary / F e b ruary 2 0 1 1

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Fluid Life Who is Fluid Life? Fluid Life has been a leading competitor in the North American fluid analysis industry for over 30 years, serving operators in oil and gas, mining, power generation, aviation, transportation forestry, construction and manufacturing. We focus on helping every customer achieve consistent payback from its oil analysis program. Our clients range in size from owner-operators to multinational, multi-site entities with several hundred pieces of equipment. Fluid Life is headquartered in Edmonton, with a branch location in Brantford, Ont., and most recently a facility in Minneapolis, Minnesota. What services do you provide? Our customers are striving for top-tier equipment reliability and lower lubrication costs. In support of those objectives, Fluid Life’s state-of-the-art testing facilities deliver quality analysis of in-service lubricants, coolants, fuels, filters and specialty fluids. That information is put into a usable format through our ‘best-of-breed’ data analysis tools designed for aggregating fleet, equipment and sample information. Our software includes a comprehensive report writer as well as integration options with CMMS [computerized maintenance management systems]. Fluid Life also provides comprehensive training and fluid-analysis program design as well as ongoing analysis program support and monitoring. These educational, customer value–focused initiatives are delivered by certified lubrication specialists.

Photos: Aaron Parker

Fluid Life president David Hunt in the company's Edmonton testing facility.

What are the key technical factors in fluid analysis? Our procedures enable maintenance supervisors to detect problem areas before they lead to more costly failures or costly delays. To achieve that result, we deliver the right fluid analysis, accurately and on time. Each testing procedure in our tool kit provides repeatable, reproducible results on every sample. We have an industry-leading reputation for accuracy and timely result turnaround, along with strong data integrity and a commitment to continuous improvement. Essentially, our service allows the customer to control its equipment, not have the equipment control them. Where do you see fluid analysis heading in the future? Any condition-monitoring program—including in-service fluid analysis—relies on the creation of a pool of maintenance-related information. Data collection must be consistent and thorough. By employing a disciplined approach to building data, the maintenance professional can not only identify trends and problem areas, but he can trust his data to truly help him extend the useful life of his equipment. In addition to building a foundation of good data, increasing the value of fluid analysis largely depends on greater integration with existing maintenance programs as well as the increased use of technology such as barcoding, smartphones and cloud-based computing. By making data input easier, data integrity will increase, thereby allowing condition monitoring to be used to its full potential.

Information provided by David Hunt, President, Fluid Life

O I L & G A S I N Q U I R E R • J anuary / F e b ruary 2 0 1 1

CARTOON GOES HERE

Advertisers' Index 1214848 Alberta Ltd.................................................................................63 Accuform Welding Ltd.............................................................................76 Aggreko LLC.................................................................................................. 25 Allan R. Nelson Engineering (1997) Inc...........................................47 Annugas Compression Consulting Ltd..........................................22 Baker Hughes Canada Company......................................................... 5 Bear Slashing Ltd...................................................................................... 42 Beaver Plastics Ltd..................................................................................49 Beijing Zhenwei Exhibition Co, Ltd.................................................. 18 Belzona Western Ltd................................................................................76 Bilton Welding and Manufacturing Ltd............................................7 Black Sivalls & Bryson (Canada) Ltd.............................................. 54 Brews Supply Ltd...................................................................................... 65 Brother’s Specialized Coating Systems Ltd..............................52 Brownlee LLP................................................................................................72 CADE-Canadian Association of Drilling Engineers..................................................................................64 Compass Bending Ltd..............................................................................72 Contain Enviro Services Ltd..............................Inside back cover Copp’s Pile Driving......................................................................................17 CPTDC (China Petroleum Technology & Development Corporation).............................................................. 21 CSPG................................................................................................................. 42

Daqing Petroleum Equipment Group.............................................57 Dean's Pump Service Ltd......................................................................69 DFI..........................................................................................................................8 Diamond Realty...........................................................................................25 Diversified Glycol Services Inc..........................................................72 EITI Electrical Industry Training Institute Engineers............................................................................... 50 Enform.............................................................................................................48 FalCan Industries Ltd..............................................................................49 Falvo Electrical Supply Ltd...................................................................52 Fluid Life......................................................................................................... 38 Gaugetech Inc.............................................................................................. 56 General Motors of Canada Ltd........................................................... 51 Hobblestone Enterprises Inc..............................................................57 Iron Brothers Construction................................................................. 10 Kelro Pump & Mechanical Ltd.............................................................72 Ketek Industries........................................................................................ 58 LJ Welding & Machine..............................................................................25 Lockhart Oilfield Services Ltd...........................................................37 LoTech Manufacturing Inc....................................................................57 Marv Holland Apparel Ltd....................................................................46 MCI Solutions.............................................................................................. 34 Millennium Directional Service Ltd............................................... 29

J anuary / F e b ruary 2 0 1 1 • O I L & G A S I N Q U I R E R

MPI-Marmit Plastics Inc........................................................................ 41 NAIT Corporate and International Training.............................. 58 Norseman Inc............................................................................................... 28 Northgate Industries Ltd......................................................................57 Northstar..........................................................................................................4 Norwesco Canada Ltd.............................................................................55 Oil Lift Technology IncEngineers.....................................................60 Pembina Controls Inc...............................................................................55 Penfabco LtdGroup..................................................................................52 Petroleum Services Association of Canada..............................70 Phoenix Fence Inc..................................................................................... 42 Platinum Energy Services Corp.....................Inside front cover Platinum Grover Int. Inc................................... Outside back cover Propak Systems Ltd................................................................................... 3 Quik Pick Waste Disposal..................................................................... 3 4 Systech Instrumentation Inc.............................................................68 Tank Gauging Systems............................................................................76 TARM Inc.......................................................................................................... 41 The Weyburn Review #414 - Oil ShowEngineers..................... 61 Trans Peace Construction (1987) Ltd............................................ 34 Vertigo Theatre Society....................................................................... 58 V.J. Pamensky Canada Inc...................................................................... 11 Waydex Services LP................................................................................. 16