Oil & Gas Inquirer - November 2010

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Renaissance

Emerging smaller oil plays are energizing the Western Canadian Sedimentary Basin

Rebirth

Chetwynd, B.C., booms on gas, coal, wind and forestry

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F E A T U R E S

2010 2010 NOVEMBER NOVEMBER

BUILDING BUILDING

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22

Conventional recovery

by Pat Roche

Emerging smaller oil plays are energizing the Western Canadian Sedimentary Basin

by Graham Chandler

Service companies race to improve their horizontal multi-frac completion tools and techniques

by Graham Chandler

New frac technologies plus better royalty rates revive oil-related activity in Alberta

Building B.C.

IA MBIA LUMB COLU SHCO BR ITISH BRITI

rus Brian Sure a started with he’s shovel – now ’s ince the prov line pipe biggest contractor

12

Unexpected renaissance

NOVEMBER 2010 • OIL & GAS INQUIRER

British Columbia's northeast region comes of age, with business and political leaders laying foundations for a strong future.

Inserted after page 32

R E G I O N A L

25

N E W S

British Columbia

45

• Chetwynd booms, thanks to gas, coal, wind and forestry

year as activity levels rise

• Imperial Oil is pleased with test rates

• Crescent Point acquires more than one

from Horn River well

29

Northwestern Alberta

million acres in southern Alberta

51

• Duvernay’s former CEO builds a new

conventional oil and gas land sales

37

continues to generate investment

53

oilsands’ original tailings pond

crude production and profits

55

stream by Q3 2011

violation charges related to a fatality

Central Alberta • Enbridge unveils pipeline and terminal

East Coast • Deep Panuke is scheduled to come on

• CNRL and a contractor face safety

41

Central Canada • Conference Board forecasts a rise in

Northeastern Alberta • Suncor celebrates reclamation of the

Saskatchewan • Canada’s original tight oil play

company in the Deep Basin • Alberta reports record revenue for

Southern Alberta • Service companies invest more this

• Anticosti wells come up dry

57

International • IHS-CERA report says oilsands GHG

expansions totalling $920M

emissions are just above average

• Phoenix Oilfield reports a

• Enbridge invests US$34M in Idaho

reduced loss for Q2

geothermal project

I N

10

E VE R Y

I S S U E

Statistics at a Glance

61

• Completions data, spot gas prices, gas

• Deep wells, gassy oil wells and

storage, drilling activity and more

59

low-gas/high-liquid wells are typically not thought of as plunger lift

On The Job

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Political Cartoon

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Editor’s Note Vol. 22 No. 9 President & ceo Bill Whitelaw | bwhitelaw@junewarren-nickles.com Publisher Agnes Zalewski | azalewski@junewarren-nickles.com Associate Publisher Chaz Osburn | cosburn@junewarren-nickles.com Editorial director Stephen Marsters | smarsters@junewarren-nickles.com

Mike Byfield | mbyfield@junewarren-nickles.com

EDITORIAL

Greedheads

Editor

Mike Byfield | mbyfield@junewarren-nickles.com Editorial Assistance

Laura Blackwood, Janis Carlson de Boer, Marisa Kurlovich proofing@junewarren-nickles.com Contributors

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As editor of Oil & Gas Inquirer, I constantly see the petroleum industry from two starkly different perspectives. The contrast between the two pictures is almost hallucinatory.

Day by day, my information comes from individuals — some highly educated, others who’ve developed their smarts on the job — who create and use the energy technology that keeps us all warm and mobile. This month, Oil & Gas Inquirer portrays people of that calibre. These specialists are producing conventional oil and unconventional gas from what was barren rock just a few years ago.

Like anyone else, I also read magazines and blogs, watch movies and so forth. In both news and fiction, beyond the business pages, I typically see oil and gas professionals being depicted as greedy, criminal and sometimes murderous.

For the oilpatch, there’s virtually no connection between reality and popular mythmaking. Which brings us to James Cameron, the director of Avatar and Titanic widely publicized as the world’s most powerful filmmaker. For a humourous glance at his recent visit to the “tar sands,” check out Fred Curatolo’s cartoon on the back page of this issue.

Avatar involves a mining company whose mechanized, death-spewing troopers overrun a tribe of graceful blue aboriginals on another planet. Just in case anyone missed the parallel to the oilsands, Cameron announced in Alberta that he will back aboriginal attempts to legally hinder oilsands development.

Moviemakers don’t portray the energy sector in its true light — or at least with some resemblance to reality — because it’s much, much easier to make money by reducing our industry to villains versus enviro-saints. The real greedheads in this scenario are James Cameron and his colleagues in Hollywood.

Elizabeth McLean | atc@junewarren-nickles.com Marketing Marketing MANAGER

Sonia Taylor Crichton | scrichton@junewarren-nickles.com Marketing AND TRADESHOW COORDINATOR

Jeannine Dryden | jdryden@junewarren-nickles.com OFFICES Calgary

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N E X T

I S S U E

Upcoming edition:

If you know an admirable person to profile in

In December, Oil & Gas Inquirer will examine

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

the powerful trend toward drilling multiple wells

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

from a single pad, a technique that’s having a big

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

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email mbyfield@junewarren-nickles.com.

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In fact, feel free to sound off about any

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concern at all — that’s a personal invitation.

2010 Technology Stars program.

OIL & GAS INQUIRER • NOVEMBER 2010

9

Stats

FAST NUMBERS

$50

AT A GLANCE

The International Energy Agency estimates that China now accounts for half of new oil demand globally.

The International Energy Agency says China has overtaken the United States as the world’s largest energy-consuming nation.

Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin

MONTH

OIL

GAS

OTHER

TOTAL

MONTH

OIL

GAS

DRY

SERVICE

TOTAL

Oct 2009 Nov 2009 Dec 2009

132 169 121

160 212 127

77 116 35

369 497 283

Oct 2009 Nov 2009 Dec 2009

331 382 283

196 244 138

32 68 34

12 10 13

571 704 468

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

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

Oct 2009 Nov 2009 Dec 2009

29 39 45

532 571 616

Oct 2009 Nov 2009 Dec 2009

157 171 139

5 11 11

7 10 9

169 192 159

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 31

480 523 554

Jul 2010 Aug 2010 Sept 2010

220 198 197

7 12 5

0 7 6

227 217 208

*From year to date

10

NUMBER ONE

per cent

NOVEMBER 2010 • OIL & GAS INQUIRER

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

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

Source: Natural Gas Exchange Inc.

Source: U.S. Energy Information Administration 3.70

3.75 $3.16/GJ Total vol.: 1,623TJ Transactions: 224

3.35

3.25

2.75

Sep 15

Cdn$/GJ

Sep 22

Sep 29

Oct 6

3.00

Oct 13

3.59 Tcf Year ago: 3.71 Tcf 5-year avg: 3.34 Tcf

Sep 10

Sep 17

Sep 24

Oct 1

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada October 13, 2010 Source: Rig Locator

Alberta September 2010 Source: Daily Oil Bulletin

ACTIVE

DOWN

TOTAL

Alberta

ACTIVE (Per cent of total)

Western Canada 293

263

556

53%

British Columbia

45

48

93

48%

Manitoba

17

4

21

81%

Saskatchewan

84

46

130

65%

WC Totals

439

361

800

55%

0

1

1

0%

Northwest Territories

OIL WELLS

Alberta

GAS WELLS

Sept 10

Sept 09

Sept 10

Sept 09

Northwestern Alberta

86

16

257

32

Northeastern Alberta

34

24

35

1

Central Alberta

193

90

125

23

Southern Alberta

44

19

221

99

TOTAL

357

149

638

155

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada October 13, 2010 Source: Rig Locator

Alberta September 2010 Source: Daily Oil Bulletin

ACTIVE

DOWN

TOTAL

ACTIVE

Western Canada Alberta

281

660

57%

British Columbia

13

17

30

43%

Manitoba

10

2

12

83%

Saskatchewan

133

56

189

70%

WC Totals

535

356

891

60%

0

2

2

0%

Quebec

COALBED METHANE

Alberta 379

Oct 8

Source: U.S. Energy Information Administration

Tcf

Source: Natural Gas Exchange Inc.

BITUMEN WELLS

Sept 10

Sept 09

Sept 10

Sept 09

Northwestern Alberta

10

0

5

1

Northeastern Alberta

0

0

34

24

Central Alberta

11

10

51

40

Southern Alberta

18

6

1

0

TOTAL

39

16

91

65

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OIL & GAS INQUIRER • NOVEMBER 2010

11

Unexpected Emerging smaller oil plays are energizing the Western Canadian Sedimentary Basin

by Pat Roche The application of hydraulic fracturing to horizontal wellbores has generated much-trumpeted oil plays in the Bak ken, Shaunavon and Vik ing formations of Saskatchewan, along with Alberta’s Cardium formation. Now the same technolog y is being applied to other geological formations where traditional vertical well production proved marginal or uneconomic. In fact, some of these plays do not even require fracturing, an extraordinary development 12

NOVEMBER 2010 • OIL & GAS INQUIRER

in a region where conventional oil prospects have attracted little attention for many years.

Of these emerging conventional oil plays, the Pekisko is probably the best known. Discovered in 1962, this Mississippian carbonate reservoir consists of many pools created by stratigraphic traps scattered from southeastern Saskatchewan to northeastern British Columbia. Production peaked at about 12,500 barrels per day (bbl/d) in 1995,

according to a report on emerging oil plays released earlier this year by Macquarie Capital Markets Canada Ltd. More recently, horizontal technology and excellent crude prices have relaunched the Pekisko. “Early indications are that the economics of the [Pekisko] play are superior to those of other oil plays in western Canada,” Macquarie said in its report. Its authors referred to “the Sleeping Beauty at Princess” — a reference to the southeastern Alberta area where Crew

Photo: Mostar Directional Technologies Inc.

New light crude plays are popping up from southeastern Saskatchewan to northern British Columbia.

Renaissance Energy Inc. led the horizontal development of the play.

Second Wave Petroleum Inc. is pursuing Pekisko prospects at Judy Creek in central Alberta. But the big story to date is unfolding at Princess. There, Crew has boosted output to 5,000 bbl/d, up from 2,200 bbl/d when the company bought the property in 2008. With 14 tested wells yet to be tied in, the company believes its capacity at Princess exceeds 6, 20 0 bbl /d. C rew pre sident Da le

Shwed has cited Princess Pekisko wells with cumulative production as high as 147,000 barrels of oil equivalent (boe) in less than a year.

Shwed notes that some of these wells are only a mile or two from existing production. These stellar results were achieved without any fracture stimulation. When the poorer wells are included, the average is still about 200 bbl/d. Crew estimates it has more than two billion barrels (Bbbl) of oil in place at Princess.

Crew is now building two eight-inch pipelines, drilling water disposal wells and adding other infrastructure. This investment is expected to cut operating costs to about $10/bbl from $16.50 in 2008. Based on drilling in recent months, the producer recently increased its inventory of future horizontal well locations in the Pekisko to more than 700 from 600.

Secondary recovery through waterflood has been started, which is forecast to increase recovery rates from 13 per cent OIL & GAS INQUIRER • NOVEMBER 2010

13

“Transitioning to an E&P [exploration and production] company, you need land. And you don’t just need land in existing production areas, you need land in new plays and emerging plays.”

Photo: Mostar Directional Technologies Inc.

— Jason Fleury, Manager of Investor Relations, Penn West

In new plays where light oil can be tapped horizontally without expensive fracs, operators can achieve payout far more quickly.

14

NOVEMBER 2010 • OIL & GAS INQUIRER

from unstimulated horizontal wells to upwards of 30 per cent.

I n we s t ce nt r a l Sa sk atc he w a n , the Birdbear play is also f lying on the strength of unfractured horizontal wells.

NuVista Energy Ltd. has discovered an estimated 20 million barrels (MMbbl) of oil in place in this Devonian dolomite formation. The Birdbear has long been k nown as an oil-bearing formation.

“There were some scattered oil shows and some ver y poor vertical producers,” says Kevin Christie, NuVista’s VP of exploration. “Technology has made some of these into commercial plays.”

Since December 2007, the company has drilled 18 horizontal Birdbear wells.

Christie says the wells come on at about 150 bbl/d, then decline steeply by about 50 per cent in the first year. However, NuVista expects to recover up to 100,000 bbl of oil per well. On a multi-well program, the horizontal Birdbear wells cost between $1 million and $1.1 million to drill, complete and tie in. NuVista does an acid squeeze or an acid wash bur refrains from fracturing and thus keeps its costs down.

“It is a conventional play,” Christie says. “It might evolve into something different later maybe, but we’re pursuing it as a conventional play.” This formation has also caught the attention of a couple of senior producers. Talisman Energy Inc. and Husky Energy Inc. each drilled a few oil-directed horizontal wells into the Birdbear this year.

Zargon Energy Trust is using horizontal wells — and in many cases, waterfloods — to boost oil recovery factors in its Mississippian carbonate reservoirs in the Williston Basin of southeastern Saskatchewan. Discovered in the 1960s, the Steelman field went through waves of development as technology and high oil prices uncovered opportunities. Output rose sharply in the ’80s as new formations were tapped, and again in the ‘90s with waterflooding.

Now, after almost 50 years of production, Steelman is potentially poised for another output boost. “In the last two years, we’ve had very good success with the drilling of 12 horizontal Frobisher Huntoon wells on several structural ridges at Steelman. We’re planning on drilling five more this year, and six next year,” Zargon president Craig Hansen says.

Oil output from the 17 horizontal wells Zargon drilled in the Williston Basin (at Steelman, Manor, Elswick and Fertile) in

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the past 15 months averaged 149 bbl/d in the first month, 71 bbl/d in the first six months and 46 bbl/d in the first year. The initial oil cut was 70 per cent and estimated ultimate oil recovery is 100,000 bbl per well. Hansen says the average cost of drilling, completing and equipping the 17 wells averaged $1.1 million — and $1.4 million if facility costs are included.

Zargon, a producer capable of 10,000 boe/d, is targeting conventional Williston Basin pools with 5 MMbbl to 15 MMbbl of oil in place. “That’s a reservoir size large enough to make a difference for us, but small enough to reduce the competition from our larger competitors who may be focused on larger resource-type opportunities,” comments Hansen, adding that the prospect inolves plenty of work but the trust can double its money as a return.

In northern Alberta, Penn West Energy Trust was aggressive in a land sale early last year, picking up parcels in Sawn Lake, Otter, Slave and Red Earth. The trust is in the process of becoming an exploration and development company. “Transitioning to an E&P [exploration and production] company, you need land. And you don’t just need land in existing production areas, you need land in new plays and emerging plays,” says Jason Fleury, Penn West’s manager of investor relations.

T he t r ust was bet t i ng ha rd on Devonian carbonates in the Slave Point and Swan Hills formations in northern Alberta. This region has long been known for its prolific reef structures, which were successfully tapped with vertical wells at areas such as South Swan Hills, Virginia Hills, Kaybob and Red Earth. Penn West is drilling past the reefs into the underlying carbonate platforms.

The trust has drilled about 10 horizontals into the play so far this year, and will probably drill another 8–10 by year’s end. Fleury says the wells are producing roughly 200–300 bbl/d in the first month, 180–200 bbl/d in the first three months, and the first-year average is probably in the 140–160 bbl/d range. “It is indeed early days, but we are encouraged by what we see,” he comments.

These horizontals are deep (2,500– 3,000 metres) and expensive ($3.5 million–$3.8 million) to drill, complete, tie in and equip. But per-well costs will fall if Penn West moves beyond the appraisal phase and into pad drilling. Also, these deep, multi-frac horizontals will benefit greatly from the royalty incentives

3 403.293.7333 www.HeX-Hut.com OIL & GAS INQUIRER • NOVEMBER 2010

15

16

NOVEMBER 2010 • OIL & GAS INQUIRER

Photo: Mostar Directional Technologies Inc.

Alberta announced in June. “I can tell you we would have not as much activity up there now without these [royalty incentives],” Fleury says.

Pengrowth Energy Trust is also chasing tight oil at Swan Hills, Deer Mountain, House Mountain and Judy Creek. The Swan Hills trend was discovered in the 1950s, when oil was $2 or $3/bbl, and has about 5.4 Bbbl of oil in place. “A one [percentage point] increase in recovery factor will give you approximately 54 MMbbl of oil. So it doesn’t take much of a technological change or much more attention being paid to an asset to [derive] some value,” notes Derek Evans, Pengrowth’s president.

The trust controls about 2.3 Bbbl of oil in place on this trend. “We have eight proof-of-concept plays that are in various stages that we’re working on,” Evans says.

“We believe that ultimately at the end of the day we’re spending somewhere in the neighbourhood of $90 million on that whole trend this year.” Although the play is in its “very early” stages, the president adds, “I’m convinced a couple of percentage [points of] increase in recovery factor will pay us very well as we figure out ways to get oil out of some of the tighter parts of the reservoir.”

In northeastern British Columbia, Legacy Oil + Gas Inc. and Strategic Oil & Gas Ltd. have partnered in two horizontal oil wells just west of the Maxhamish gas field. Strategic says the wells confirmed the presence of the Chinkeh formation at 1,600 metres. The Lower Cretaceous Chinkeh sands are prospective for light sweet oil. Legacy, as operator, drilled and fraced the two horizontal oil wells and did workovers on three of the existing vertical oil producers. Results are being assessed.

While the Montney is best known as a prolific tight gas formation, it is also being successfully drilled for oil. Orleans Energy Ltd., for example, recently increased its 2010 budget to $51 million from $41 million, reallocating capital to its emerging Montney light oil play at Waskahigan in west-central Alberta. The producer recently tested its second horizontal Montney oil well, which flowed 1,100 bbl of light per day after an 86-hour test.

The well was drilled to a total measured depth of 3,510 metres with a horizontal section of 1,183 metres in the Montney, then completed with a 13-stage, 230-tonne frac. It was well was a followup to Orleans’ 4-36 Montney oil discovery at Waskahigan, brought on stream June 4.

Pengrowth Energy Trust is chasing tight oil at Swan Hills, Deer Mountain, House Mountain and Judy Creek.

It was producing 150 bbl/d of light sweet crude in early September.

Surge Energy Inc. is pursuing an oil accumulation in the Mannville Group in west-central Alberta. The company says the pool has 55 MMbbl (39 MMbbl net) of light oil in place, of which less than 1 MMbbl has been recovered. This play is different from the Cardium and the Viking because there has never been significant production, even though it was drilled with conventional vertical wells, according to Surge chief operating officer Dan Brown.

The company still has some “running room” in the area, Brown adds, so it hasn’t yet identified the specific zone. Surge’s first horizontal test — which had only six effective fracs — has been on production four months and is still producing 100 boe/d (75 per cent oil). The company plans to drill four more horizontals into that pool this year.

As more producers successfully use horizontal technology to tap reservoirs that were uneconomic with vertical wells, the question is whether the increased production will be enough to reverse the long-term slide in western Canada’s light oil output. At this point, it’s too soon to plot a trend, but it certainly appears to be breathing new life back into the basin.

The emerging oil plays are providing prospects for companies too small to pursue costly shale gas plays. The emergence of opportunities in conventional oil also coincides nicely with the creation of a new class of mid-size Canadian explorers as trusts convert back into corporations.

(Energy trusts, originally designed to produce rather than explore, will become liable for federal corporate income tax in 2011.) “I think the resource potential is magnitudes greater than what anybody perceived five years ago,” says NuVista’s Christie. “It’s almost mind-boggling.”

“ Through innovaTion, we’ve achieved a huge reducTion in fresh waTer use. More soluTions are wiThin reach.”

Back in the 1980’s, it was common to use a lot of fresh water to produce oil from the oil sands.

Today, we conserve fresh water by sourcing brackish water – the unusable water far below the fresh water table. By 2013, fresh water will account for less than 3% of all water used at our Primrose facility here in northeastern Alberta.

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

Get the real story at capp.ca/oilsands

John Parr Canadian Natural

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

Innovation pressure

Service companies race to improve their horizontal multi-frac completion tools and techniques

il and gas wells in western Canada are getting longer, and there’s a greater emphasis on development over exploration drilling. Field data for the first eight months of this year indicates that average well length/depth increased by 26 per cent over the same period in 2009. In 2005, one in four wells was exploration; that’s now down to 18.3 per cent. Driving these trends is multi-stage fracturing of horizontal wellbores. This technique works well in natural gas reservoirs that were identified long ago, but whose reservoir rock was too tight to produce with earlier technologies. In response to this opportunity, service providers are racing to come up with better frac tools, capable of lowering finding and development costs in a period of low gas prices.

“The biggest pressure today focuses on the very efficient completion technologies and logistics that are required to complete these long, multiple stage wells,” says Brad Rieb, regional technology manager for BJ Services Company, now part of Baker Hughes. “That’s stating the obvious. Still, consider that we used to start with four to maybe seven stages, and this is now pushing to 30 to 35 stages. In the short term, [a well’s] production rate is initially driven by the number of stages that can be successfully completed. High initial rates of production contribute to high rates of return.”

BJ Services has responded with a menu of innovations. “First and foremost would be the use of coiled tubing technology for annular fracing in cased-hole horizontal wells,” Rieb says. “We can complete any number of completion intervals by the use of coiled tubing that’s run in the hole, used to perforate and isolate intervals, and 18

NOVEMBER 2010 • OIL & GAS INQUIRER

by Graham Chandler

Trican's burst port system (BPS) features integrated casing collars and pre-milled ports in the horizontal casing or liner string.

then we hydraulically fracture down the annulus. We move sequentially from the toe to the heel.” The technology enables operators to complete with closer spacing, the BJ Services manager comments. He distinguishes between open-hole completions, “which is the packer and drop-ball completion technology” versus cased-hole completions “where we put pipe to the end, cement it in, get isolation and then perforate it from toe to heel.”

BJ Services has developed frac sleeves which form an integral part of the casing string. “They’re run as part of the casing string,” Rieb says. “We run in with coil, we pressure up on them, and they slide open. We frac through these casing ports.

We can place them in any numbers up the wellbore. It’s extremely fast, extremely efficient and you get the added benefit of a cemented wellbore, a full-diameter wellbore, whereby in the future remedial workovers can be completed. You can work over different zones that you have open to you. Previously, with the openhole packers-and-ball-drop technologies, you have all these restrictions which are prohibitive.”

B J Se r v ice s ha nd led tec h n ic a l development of its frac sleeve through its coiled tubing research and engineering department in Calgary and manufactures locally. The new technology is now well into commercial operations. “The success rate is now well above 90 per cent,” says Rieb, expressing gratitude to producers who helped test the innovation in the field.

“We can’t keep up with demand — the manufacturing capacity is our choke point.”

David Browne, corporate director of technology for Trican Well Service Ltd.,

outlines the reservoir realities faced by producers. “In shale gas, the zones are thick and the rock is brittle, so you want to stimulate as much of the reservoir as possible,” he says. “To do this, you pump at a very high rate to be able to create as many fractures as possible, extending in three dimensions from the horizontal well.”

Trican favours pumping through casing in order to create an unobstructed conduit.

This approach reduces friction, enabling the operator to pump at a high enough rate to create complex fractures in the rock that resemble shattering glass.

Trican’s new burst port system (BPS) is designed for selectively fracturing.

Integrated casing collars that contain premilled ports are placed into the horizontal well casing or liner string. These ports, Browne explains, are subsequently straddled by the company’s selective fracturing cup tool (dubbed the C2C). Pressure is built up to their designated burst point, leaving an isolated conduit to the formation.

The C2C selective stimulation straddle tool is an innovation in coiled tubing stimulation, designed for deep horizontal or vertical wells. “It allows repeatable, selective isolation of downhole intervals for pinpoint stimulation treatments, Browne says. “Key to the tool’s success in deep applications is C2C’s unique pressure equalization valve. After stimulation treatments are performed in one zone, the pressure in the straddle tool is equalized to that of the annulus, allowing the cups to quickly relax. The straddle tool is moved up or down hole, the next zone is isolated and the treatment is repeated. The pressure equalization valve provides the added benefit of decreasing wear on the cups,

Photo: Trican Well Service Ltd.

increasing their longevity and reducing replacement cost and time.”

Operators are under increasing pressure from regulators to employ ecologically safe frac fluids. BJ Services’ Rieb notes that the fluids must accommodate produced water, recycled water, and recycled oil-based frac systems. “Through chemical innovation, we have to readily accommodate these base fluids,” he says, “so that we can gel, cross link, frac break it chemically on a

t r e at me nt s, pr i m a r i ly i n sh a l low reservoirs. Its more general EcoCleanGSW is a high-performance slick water f ract ur ing f luid t hat ’s desig ned to eliminate contamination risks as well.

Put to the test, the EcoClean products reportedly passed the stringent Microtox standard, meaning they’re considered safe for drinking water, and will meet the criteria set out in most other regulatory examinations.

Trican favours pumping through casing in order to create an unobstructed conduit. This approach reduces friction, enabling the operator to pump at a high enough rate to create complex fractures in the rock that resemble shattering glass. predictive basis and leave the customer with a successful completion.” BJ Services’ Viking PW (produced water) system meets that demand. “It’s very tolerant of iron contaminants, salt and other residual chemical contaminants — such as those that people use to reduce scaling for instance,” its regional technology manager says.

Ideally, a frac fluid inflicts minimal damage on the reservoir formation while transporting proppant further into the fractures. “We also want to reduce the risk to the environment by creating additives that are non-toxic, non-bioaccumulating and biodegradable, and that are mixed in a closed, dustless system,” Trican’s Browne says. Costs are also important, he adds. In particular, frac additives must address the tight gas producer’s need to recycle produced water.

Tr i c a n de s i g n e d it s n o n - t ox i c EcoClea n-LW f luid for exa mple to protect water wells and aquifers during

Proppant consists of hard sand or other particles that prop open the reservoir cracks created by hydraulic fracturing, enabling gas to flow to a wellbore.

Proppant is carried into the cracked rocks by frac fluids. Trican has developed a new transport method with the trade name FlowRider. The surface property of proppant is modified on-the-fly, permitting it to be transported in slick water and travel further into the formation with less settling and banking.

All fracturing technology, of course, is designed to pump fluid into the gas- or oil-bearing reservoir under pressures capable of cracking the rock. “The pressures on the pumping services industry are immense from every angle,” says Rieb.

“For instance, the ambient temperature in Canada is considerably lower than Texas.

So some of the chemicals that we need to operate in remote northern regions have

to be completely unique to Canada. Rather than having to heat water to 20 or 25ºC, we can now facilitate these shale completions in Horn River, for example, with water that’s 3ºC.” Rieb reports that the pump rates and high pressures needed to effectively stimulate shale gas wells “are causing no end of headaches to the operations guys. They’re wearing out equipment prematurely so they are forced to get parts on location; it’s a cost challenge.” In response, technicians would like to come up with plumbing innovations that help limit the amount of turbulent flow, eddies and currents, and erosive activity in the pumping configuration. “That’s a big problem in our world,” the BJ Services regional technology manager says.

Critical to planning a frac job, Rieb suggests, is “doing as much upfront homework as physically possible” before going out on a job. Simulation technology continues to advance. Relevant reservoir characteristics include permeability, gross and net pay, and most importantly, the critical properties of the rocks themselves — their stiffness and reaction to increasing pressure. “We take petrophysical analyses, open-hole logging data on shale-specific characterization; we do that routinely,” the BJ Services manager says. “It starts with the petrophysics. That rock model is then downloaded into our fracture simulator which simulates its behaviour for any number of recipes and pressures, and iterates it down to a usable size.”

No one can ever see how a geological formation cracks thousands of feet below the surface. In place of eyes, specialists are refining microseismic techniques that can “listen” and locate fracing events OIL & GAS INQUIRER • NOVEMBER 2010

19

Photo: Trican Well Service Ltd.

in real time. “The fracing process starts, pushing fluid and sand, getting the rock to break,” explains Darin Silvernagle, VP at CGGVeritas. “We listen for those breaks as they occur.” CGGVeritas, a global seismic services firm, believes that it’s “extremely close” to identifying both a frac’s location in three dimensions and its magnitude.

“And whether it stayed open or resealed,” Silvernagle adds. “That’s very important as an indicator of how much gas that well is going to produce. So microseismic is really catching on.”

Directional drillers are under pressure to come up with more cost-effective tools for horizontal wells. “A whole bunch of things came together,” says Harvie Andre, president and CEO of Wenzel Downhole Tools. “First off, directional drilling is much better than it used to be.

The MWD [measurement while drilling] instrumentation is better and of higher quality. Companies are able to make some economies by having one directional driller in an office in Calgary operating four or five different drilling operations spread all over.”

Andre has a unique background — he holds a PhD in chemistry from the University of Alberta, was an engineering professor at the University of Calgary,

About 50 frac providers compete in North America.

and then a federal Cabinet minister under Prime Minister Brian Mulroney. Since then, he’s played an active role in the Calgary oilpatch. From Wenzel’s angle, Andre says downhole mud motors have become much more reliable. “Ten years ago, drillers were reluctant to keep motors in a well more than 40 hours or so because they had a tendency to break,” the CEO says. “Now, we had a motor with Encana in Louisiana in the shale play there that was in the well for over 400 hours. Big difference.”

Beyond durabi l it y, Wenzel a lso focuses on short radius entry. Its new HB21 reduces the bit-to-bend length down to about 30 inches, which greatly reduces torsional stress. “You can do a shorter radius, and when you rotate to go straight you’re not increasing the diameter as much,” its president explains. “It means you can put more bottomhole pressure, and therefore, faster rates of penetration.”

Also, without that short bit-to-bend, drillers are forced to trip out before moving into the horizontal portion of the well. “Of course, tripping out is expensive,” Andre says. “With the short bit-to-bend, you don’t have to do that.”

Unconventional gas producers are innovation-hungr y to the point that Wenzel “can’t keep up with demand,” the former minister observes. “When gas prices were higher, operators could make money without changing their practices much. Now, in a low price environment, producers need to find efficiencies,” Andre says. “So we too are driven to find a better way of doing things: finding how to reduce costs and improve productivity.

The stronger we make our motor — the more torque we can put out there — the better it is.”

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Photos: Wenzel Downhole Tools

Conventional

recovery F

our years ago, Packers Plus Energy Services Inc. began literally cracking open the Bakken tight oil play in southeastern Saskatchewan. The thensmall firm revolutionized the petroleum industry by efficiently staging hydraulic fractures in series along a horizontal wellbore. From tight oil the new technology swiftly moved toward tight gas (including shales) across North America. This year, horizontal multi-fracs are reviving the moribund conventional oil sector in Alberta.

Why did this technology — a global breakthrough developed by a Calgarybased company and first utilized by Calgary-based producers — take several years before it was deployed on a significant scale in Alberta?

In part, the answer appears to be p ol it ic a l. “ W hat [pro ducer s] were waiting for was a decent fiscal regime [in Alberta] that would interest investors; activity levels were very low under the 22

NOVEMBER 2010 • OIL & GAS INQUIRER

New frac technologies plus better royalty rates revive oil-related activity in Alberta

by Graham Chandler

old royalty regime,” says Don Herring, who recently retired as president of the Canadian Association of Oilwell Drilling Contractors. Those issues, he says, were addressed at the end of May when the Alberta government came forward with revised drilling incentives and other measures that favoured investment.

Since then, the oil industry has moved steadily into higher gear, fuelled by the prospect of drawing more oil out of known conventional oilfields using multi-stage fracs on horizontal wells. “Sixty-two per cent of the wells drilled currently in Canada are oil wells,” says Dave Browne, corporate director of technology for Trican Well Service Ltd. For the most part, the technology is similar whether it’s applied to oil or gas targets.

One major difference between oil and gas is in the way the rock breaks. “Shale gas formations are much less permeable than even tight oil formations. Shale breaks in a complex way more like shattering glass,” Browne says. “Oil formations, being more permeable, require viscous

fluids to create the fracture and place the proppant. These formations break in a more planar [2-D] pattern.” Also, due to the reduced permeability in tight gas reservoirs, the size of the frac treatment is an order of magnitude greater in shale than tight oil formations. “Anywhere from 10–20 tonnes of proppant per stage is used for oil and 100–200 tonnes of proppant for tight gas,” the Trican manager says.

Brad Rieb, regional technology manager for BJ Services Company, notes that the chemicals and proppant almost always vary between gas and oil fracs. Also, oil wells usually produce natural gas and water as well as crude. “All three have to be transported through the frac and in the mechanism that we build,” Rieb says. “Oil wells are more complicated that way. They are three phases — when you’re transporting three phases through a frac path, you have lots of pressure drops. So we have to ensure that we place the right amount of proppant, the right density of proppant, the right size of proppant — and we have to transport it there in the most sophisticated, clean fluid possible.”

Downhole motors developed for horizontal shale gas drilling are also migrating

to unexpected applications. “Because the MWDs [Measurement While Drilling] are so good now, people are using the same techniques for verticals that were developed for horizontals,” says Harvie Andre, president and CEO of Wenzel Downhole Tools. He says the new motors make a straighter hole: “[Vertical wellbores] were never straight. They tended to spiral, and if there were different strata, they tossed and turned.” Now a contractor can drill a more uniformly straight hole, which reduces the frequency of getting stuck, makes it easier to put in casing and helps to achieve a tight cementing job.

The Wenzel president notes one distinction between shale gas and oil fracing.

“Shales frequently have clays in them. You don’t want to have any water contact with the clays because clays tend to expand and you seal off the reservoir,” he explains. For shales, drillers typically use an oil-based drilling mud rather than a water-based mud. “That in turn means that the power sections in our downhole motors, which have rubber liners, don’t tend to last very long,” Andre says. “The rubber tends to expand and absorb some of the oil. It tightens up and you get chunking of the rubber inside the stators. Then you

lose power and torque. It means you have to replace the power section or the stator basically every run, which is clearly expensive.”

Wenzel’s researchers work closely with elastomer manufacturers to come up with rubber compounds that are less susceptible to expansion. “The stators were really developed for high-torque purposes,” says Andre. “But they have even-wall construction. Instead of having just rubber inside the stator, you’ve got a shaped metal with a rubber covering. And because it’s much thinner — less rubber involved — expansion is less of a problem. So these evenwalled power sections that tend to last longer in an oil-based environment.”

Multi-stage fracing is not the only crude oil and gas production enhancement player.

Wavefront Technology Solutions Inc. has developed downhole tools that generate a fluid pulse in the reservoir. That pulsing momentarily expands the pore structure of rock, helping move fluid through the formation much like a heart pumps blood through a human body. As a result, oil that has never moved before can reportedly flow freely.

“Wavefront’s technology is complementary to those techniques [i.e. horizontal multi-stage fracs],” says Brett Davidson,

president and CEO of the Canadian firm.

Remedial work on a single producing well sometimes involves injecting a liquid, he says. “Then the operator can take advantage of our wave technology, especially if they’re injecting diverters or gels.” A gas well is liquid dominant during the stimulation phase, Davidson points out. “If you are looking at remediating near-wellbore damage with acid, here Wavefront has helped,” he says. “We can get the liquids through more nooks and crannies than just the fractures alone.”

Similar factors apply to remedial work or water injection in oil wells, adds the Wavefront founder. “For instance, producers in the Cardium formation [in Alberta] are also looking at horizontal water injectors [to help drive oil to the wellbore],” he says. “Our Powerwave process can play a significant role even if you fractured the injection well.”

For the future, he adds, the company may adapt one of its tools for co-injection of a proppant while generating the liquid pulse.

“Then we could, even during remedial work, create small-scale fractures during the injection process,” Davidson predicts. Successful innovation, in his experience, often leads to more innovation.

OIL & GAS INQUIRER • NOVEMBER 2010

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British Columbia

Chetwynd booms, thanks to gas, coal, wind and forestry

by Mike Byfield

SEP/09

SEP/10

SEP/09

SEP/10

WELLS SPUDDED

45

36

WELLS DRILLED

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Photo: Mike Byfield

Saugstad. Enbridge Inc. is now preparing its initial regulatory application for the $5.6-billion project.

Si m i la rly, Chet w y nd a nd ot her communities in the region could reap advantages from BC Hydro’s proposed Site C power generating station and earthfilled dam on the Peace River. The hydroelectric facility — with construction costs very tentatively estimated at perhaps $6 billion — would be located just upstream from Taylor and Fort St. John. The B.C. government has given the green light for the project, which is proceeding toward environmental review and aboriginal acceptance. The regulatory process is scheduled to take about two years, with construction completion targeted for 2020.

Chetwynd’s burst of prosperity seems a l l t he sweeter, because prev iously ever ything had gone terribly wrong.

A look at its economic foundations

indicates the scale of that calamity for a small community.

Chetwynd has always depended heavily on forestry, with two sawmills (Canfor Corporation and West Fraser Timber Co. Ltd.) and a pulp mill (Tembec Inc.). For the first time ever, Canfor shut down its sawmill in early 2008 due to the global economic downturn. West Fraser and Tembec also laid off the entire payrolls of their mills.

Coal boosted Chetwynd’s growth in the 1980s with the development of major mines southward along Highway 29 around Tumbler Ridge. Private and government investment in road, rail and mines totalled billions. After the turn of the century, however, all of those mines shut down due to low international coal prices.

In 2002, Talisman Energy Inc. made a major natural gas discovery even further south in the Monkman-Sukunka region. Further strikes triggered construction of processing and pipeline facilities, including a sulphur pelletizing plant in Chetwynd. Current low gas prices have temporarily eliminated drilling into these deep targets due to cost.

In 2004, a provincial survey identified Dokie Ridge as the best inland wind power site in British Columbia, prompting Victoria-based EarthFirst Canada Inc. to start installing a $360-million wind farm.

In 2008, EarthFirst went broke.

The forestry shutdowns, which meant unemployment for hundreds of workers, traumatized Chetwynd. “Friends and family members lost their jobs — no one knew when or if the mills would reopen.

Many people who’d put down deep roots here wondered if they’d have to leave forever,” recalls Ellen Calliou, the municipality’s economic development officer (whose husband works in forestry and oil and gas). “The Canfor mill is located right in the middle of the townsite. It was so sad

Sand Source says its new frac sand terminal at Chetwynd is already operating at full capacity.

Every now and then, everything just seems to go right. Chetwynd, just over 100 kilometres west of Dawson Creek, is going through that exhilarating experience right now. Forestry and coal operations are booming around the community of 3,100, a major wind power project is ramping up on a nearby ridge, and Montney-focused natural gas activity has been moving steadily closer to the town.

Slightly further ahead are big construction prospects, mainly because the town’s highway and rail facilities make it the primary transportation hub for the upper Peace River Valley. The proposed Northern Gateway crude oil pipeline from Alberta to the West Coast would pass south of Chet w ynd. “We’re the logical supply staging site for Northern Gateway ’s construction through the Monkman area so we’d get some bene­ fits,” suggests Chetwynd Mayor Evan BRITISH COLUMBIA WELL ACTIVITY

SEP/09

SEP/10

WELL LICENCES

64

69

▲

▼

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • NOVEMBER 2010

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British Columbia to see that huge yard sitting there empty month after month.”

Although Canada’s forestry sector has entered recovery, its consolidation continues to inflict pain. In September alone, Canfor announced that it will permanently close a lumber operation near Prince George, B.C., and Tembec decided to permanently shut down its newsprint mill in Pine Falls, Man. (The newsprint mill, the only major employer in Pine Falls, had operated for more than 80 years.) Chetwynd has fared much better.

Canfor reopened its sawmill this summer, made $20 million in capital investments this year, and is looking for workers. West Fraser and Tembec are also operating full tilt again.

The coal mining recovery has been equally dramatic. In June, Western Coal Corp. reopened its Willow Creek surface mine, located a half hour drive west of Chetwynd. Around Tumbler Ridge, a series of mines have come on stream since 2005, thanks to large-scale investments by Western Coal and Peace River Coal Inc. The region’s coals are high-value anthracite and pulverized coal injection grades, used in steel blast furnaces in Asia and elsewhere.

Plutonic Power Inc. in partnership with GE Energy Financial Services, has revived the Dokie wind farm, scheduled to begin delivering 340,000 megawatt-hours per year of electricity, commencing next March, under a 25-year contract with BC Hydro. The project includes 48 wind turbines, a switchyard and transmission lines at a total project cost of $228 million. The work is on time and on budget, according to Plutonic. On completion, it will be the largest wind farm in the province, and a future expansion phase is under study.

Drilling in the Montney tight gas formation has steadily moved westward since the play began in 2008. Activity now occurs as close as a half hour drive to the east of Chetwynd. “The formation itself extends as far as here but it’s too compressed to yield gas at the margin,” Saugstad says. Besides being mayor, he’s the regional community coordinator for Spectra Energy Inc. and chairs the Northern Development Initiative Trust (the regional economic development agency).

“I don’t see Chetwynd ever having a natural gas industry on the scale of Dawson Creek or Fort St. John, but we’ll

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certainly derive some benefits from geographic proximity,” the mayor says.

Beyond trucking, machining and other gas-related services, the town has an ample local water supply that contains too much barium for human consumption. Tight gas producers in the Montney use huge volumes of water for multi-stage fracing of horizontal wellbores.

This summer, Sand Source Services built and began operating a rail-side storage facility with five employees at Chetwynd. The firm, based in Red Deer, Alta., has specialized in fracturing sand transloading services since 1998. Bill Disher, local manager for Sand Source, says its new silos can store 750 tonnes, with more stockpiled in rail cars when necessary. A range of proppant sand mesh sizes is available. “Business is great. We’re moving the sand out as fast as it comes in,” Disher says.

CE Franklin Ltd. operates a supply and service centre for natural gas and other resource companies in Chetwynd. Chris Johanson, the centre’s manager, says that Montney operators still shop mainly in other communities. “The business we’ve gotten so far from the Montney companies

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British Columbia only makes up for the decline in deep gas drilling,” Johanson reports. “That’s partly because many of the Montney people don’t yet realize that we’re here. I think business will pick up. If the Northern Gateway pipeline gets built, we’re the closest supply point in the region — that would be a huge development for us.”

Curtis Brewster runs Aim Trucking, an 18-year-old family firm that operates 22 heavy trucks. “Our oilfield work is mainly related to production facilities and maintenance turnarounds. We haven’t been able to get much on the exploration side yet. I’m hopeful that will change as the drilling gets closer to us,” says the longtime resident of Chetwynd.

In his experience, gas producers are willing to hire locally but often don’t know what’s available. “To be fair to them, they need to plan ahead, and so they hire their

trucking services before they even get here,” Brewster comments. “From our side, it takes two or three years to get comfortable with a local manager. Then he’s transferred and we’re pretty much back to square one. That’s on the facilities side. For exploration, it’s even harder to develop contacts.”

Even so, the Aim Trucking head look forward to the future with confidence.

“We never did lay anyone off during the bad times around here. In fact, we expanded,” he says. “The company is building a new office and looking for drivers. We’ll do anything from send a picker truck to hauling garbage. Aim has grown by being a one-stop shop for trucking services.”

His father came to Chetwynd from Saskatchewan in 1962. “Growing up, I couldn’t wait to get somewhere else,” Brewster remembers. “Eventually, I

moved to Alberta and opened a hardware store. That was an eye-opener. I really missed Chetwynd and the mountains. Luckily, I was in a position to come back here.” His feelings are understandable. The town’s setting is spectacular, a broad valley lapped by green hills, and its residents pride themselves on being friendly neighbours.

“A good house here can be bought for less than $250,000. A couple with one full-time and one part-time job between them can easily make over $100,000 a year,” Saugstad enthuses. “We lost 500 to 600 jobs locally during the downturn, but that’s all been made up. In fact, Western Coal is now looking for 325 workers.

Anyone who loves the outdoors should come and take a look. For people who’d enjoy living in a community this size, Chetwynd offers a fine quality of life.”

Imperial Oil is pleased with test rates from Horn River well Imperial Oil Limited has successfully ver i f ied t he pre sence of mu lt iple productive reser voir inter vals with average test rates in the range of 500 thousand cubic feet to 1.5 million cubic feet per day from a single-frac stage over a 30-day test at its Horn River shale gas project in northeastern British Columbia.

The company also has modelled recoveries of up to 800 million cubic feet per frac stage, Exxon Mobil Corporation, Imperial’s majority shareholder, said in a presentation at the recent Barclays Capital CEO energy/power conference. “These favourable test rates meet our going-in expectations, and we can expect commercial production rates from our development wells, which will contain multiple individual frac stages,” said the company.

Exxon Mobil/Imperial alone — and also as part of a 50/50 joint venture with EOG Resources Canada Inc. — holds more than 320,000 net acres at Horn River, where the International Energy Association has assessed 760 trillion cubic feet of gas in place in the high-graded portion of the basin with an estimated 130 trillion cubic feet recoverable.

Noting that there is technical uncertainty around the distribution and quality of the different productive reservoir intervals, Exxon Mobil said it is conducting pilot studies and well tests to evaluate the production potential of the basin. “These pilot studies and tests are an important step to mitigate the technical risks and identify the optimal ‘sweet spot’ to begin a phased development,” it said.

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

Imperial and Exxon Mobil are acquiring 3-D seismic data over their acreage and early results from seismic support the identification of areas of higher resource quality, said Exxon Mobil. This data will be used to optimize future development well locations and fracture stimulation design.

Daily Oil Bul let in records show that since Jan. 1, 2009, Imperial has licensed eight wells with the targeted zone t he Ot ter Park member of t he Horn R iver shale, a grey calcareous shale between the Muskwa and the Evie members. The company has licensed an additional 14 wells with the Keg River, an underlying carbonate, listed as the projected zone.

— DAILY OIL BULLETIN

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27

Northwestern Alberta/Foothills

Duvernay’s former CEO builds a new company in the Deep Basin

by Elsie Ross

Mike Rose is focusing Tourmaline on the region where he built Duvernay into a $5.8-billion company.

Mike Rose makes no secret of the fact that he likes the Alberta Deep Basin on the deep western margin of the Western Canadian Sedimentary Basin. To prove the point, the former CEO of Duvernay Oil Corp. and Berkley Petroleum Corp. is back in his old stomping grounds, this time with privately held Tourmaline Oil Corp.

Rose, along with his former Duvernay management team, founded Tourmaline shortly after the sale of Duvernay to Royal Dutch Shell for $5.8 billion in the summer of 2008. “We set out to build two or three large E&P [exploration and production] areas where we control the infrastructure and have very large drilling inventories,” he told a Peters & Co. Limited investment conference on Sept. 15.

“You might wonder why we are so dull that we have to go to the Deep Basin again, again and again — three companies now — but a look at some of the statistics

on a broad perspective sheds some light on that,” the Tourmaline CEO said.

The whole Lower Cretaceous in that area is gas saturated with up to 15 tight sand zones, he said. “It’s one of the largest

producing province,” Rose said. “It’s just a great area, and the technology just keeps making it better.”

Mainly through asset acquisitions and minor Crown sales, Tourmaline has assembled 1,350 gross sections in the Deep Basin with an average 65 per cent working interest. “Realistically, this is at least a 50,000 barrel a day [bbl/d] platform,” said Rose. “The pace we get there will be controlled by the natural gas price.”

Tourmaline has built two core areas: the Deep Basin in Alberta where its focus is on the Lower Cretaceous, and the Peace River High where it focuses on the Triassic Montney. Below the Deep Basin, the company has been assembling a series of Devonian prospects. The company has an inventory of 2,700 vertical wells at 2 wells per section in the Alberta Deep Basin, plus 100 Alberta Montney and 150 B.C. Montney horizontal well locations.

This year’s capital budget is $295 million with a preliminary budget of $425 million for 2011. Tourmaline had drilled about 70 wells over the past 18 months, including 40 gas wells and 3 oil wells this year. It had another 10 wells drilled but

“You might wonder why we are so dull that we have to go to the Deep Basin again, again and again but a look at some of the statistics on a broad perspective sheds some light on that.”

— Mike Rose, CEO, Tourmaline Oil Corp.

gas fields in the world, albeit made up of many small pools.”

A total of 18 trillion cubic feet has already been produced, and drilling out the reserves in the existing wells and adding two wells per section on the remaining lands would add another 12 trillion cubic feet of gas. “You are really not even halfway through the life of this

not completed with an additional 30 wells to be drilled by year-end.

Current production is more than 21,000 barrels of oil equivalent per day (boe/d), including about 16,500 boe/d in the Deep Basin. Another 40 million cubic feet per day (MMcf/d) of gas is tested behind pipe. About half of that is at Minehead and is scheduled to come on

NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY

SEP/09

SEP/10

WELL LICENCES

154

273

▲

SEP/09

SEP/10

WELLS SPUDDED

112

158

▲

SEP/09

SEP/10

WELLS DRILLED

97

169

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • NOVEMBER 2010

29

Northwestern Alberta/Foothills

stream in the first quarter of 2011. Overall production is projected to rise to about 25,000 boe/d in the first half of 2011 and average 30,401 boe/d for the year.

Most of the Deep Basin gas is liquidsrich, averaging 16–20 barrels per million cubic feet (bbl/MMcf) through the majority of the Cretaceous sections with the Cardium providing 40 bbl of natural gas liquids (NGLs) and condensate per MMcf. Tourmaline has been trying some new things on the exploration front with 3-D seismic and has had some extremely high rate wells with strong initial test rates and lots of liquids, said Rose. The Minehead discovery tested 17.5 MMcf/d of natural gas and 500-plus bbl/d of NGLs. That well will end up recovering 5 billion cubic feet (Bcf) to 6 Bcf of gas compared to 2.5–3 Bcf from some other wells, he said.

Daily Oil Bulletin records show new pool wildcats were licensed at 3-2949-20 W5 and 5-10-49-20 W5 with the Poker Chip shale the projected zone and with depths of 3,644 metres and 3,712 metres, respectively.

A number of the producing wells acquired through asset acquisitions are dual- and single-zone producers that were drilled when multi-stage fracing technology in vertical wells didn’t exist. As a result, they present a great opportunity to go back and add the up-hole zones and Tourmaline has a systematic plan in place to do so, said Rose. “It’s a great way to add reserves when gas prices are struggling a little bit.”

Other opportunities are emerging such as intervening shale horizons and certain sand horizons that are likely exploited

horizontally, such as the Wilrich, Second White Specks, some of the Falher sands and, in places, the Nikanassin and the liquidsrich Cardium. Tourmaline’s first horizontal Cardium well tested at 4 MMcf/d of gas and about 37 bbl/MMcf of NGLs and condensate.

The company sees development of four to six vertical wells per section along with one or two horizontals per section, said Rose. It plans to have 12 horizontal wells drilled by next spring breakup to give the company a better sense of the scope and the potential value added by what it calls “embedded resource plays.”

In the Peace River High, Tourmaline’s second core area, the main focus is on the Montney where the company has already

the developing Montney play in Alberta at Elmworth and a large complex at Spirit River where the focus is primarily on an oily property where the company has just drilled two horizontal wells that will be tested as soon as the rig can be moved off the wet lease. The company has an inventory of more than 40 horizontal wells in the area.

Two small corporate acquisitions enabled Tourmaline to get back into the Sunrise/Dawson Montney play where Duvernay was one of the pioneers. “We were able to cobble together a reasonablesized land position and have been doing the E&P program ever since,” said Rose.

The company has drilled 14 horizontal

Tourmaline has been trying some new things on the exploration front with 3-D seismic and has had some extremely high rate wells with strong initial test rates and lots of liquids. drilled 15 horizontal wells. While the industry has been looking at the Montney for a number of years, it was the advent of horizontal wells and multi-stage fracing that unlocked the tight, sweet over-pressured Montney on the Peace River Arch, Rose noted.

A lt hough t he Peace R iver A rc h i s geolog ic a l ly qu ite compl ic ated, Tourmaline’s position is actually quite simple, Rose told analysts. It has three elements: the Dawson/Sunrise Montney play in northeastern British Columbia,

wells so far (10 at Sunrise and four at Dawson) with average test rates of 5.3 MMcf/d of gas and about 35 bbl/MMcf of condensate.

At Elmworth, where the Montney is slightly sour, Tourmaline planned to drill three delineation horizontal wells this fall in advance of a more substantial development next year. Rose said Tourmaline still likes the Paleozoic carbonates at Dawson/ Sunrise, where it has two Wabamun producers and is a non-operating partner in a third well being drilled.

Anglo Canadian fracs its Shane 7-11 well Anglo Canadian Oil Corp. has announced that a multi-stage frac on the “Nordegg Member” has been successfully performed as planned on the Shane 7-11 well. Approximately 600 metres of the 1,240-metre horizontal leg was fractured in six stages. Swabbing operations are ongoing, and it may take up to two weeks or more before initial production numbers are known.

Rigorous analysis of core samples and logs coupled with petrophysical analysis have provided Anglo Canadian with more insight into the potential productive capabilities of the Nordegg. Petro-graphic analysis of a major constituent rock type 30

NOVEMBER 2010 • OIL & GAS INQUIRER

of the Nordegg shows low amounts of ductile clay minerals and abundance of brittle calcite, which management believes will respond well to a fracture stimulation.

Anglo Canadian holds a 100 per cent working interest in 269 sections (172,000 acres) of potential oil-bearing Nordegg oil shale lands in west-central Alberta with a total estimated un-risked resource of 6.47 billion barrels of discovered petroleum initially in place. Its goal is to prove the amount of oil on its lands and to begin commercial production.

An independent laboratory analysis of oil from the 7-11 well, coupled with other

evidence, has reportedly strengthened management’s view that the Nordegg Member may be capable of producing commercially retrievable quantities of oil on Anglo’s 8,064-hectare Shane lease, the company said in September. The Nordegg Member has produced over 600,000 barrels of oil from three vertical wells situated in the Nordegg Member oil-bearing fairway in the Grande Prairie region of west-central Alberta.

Hydrocarbon liquid analysis of the Shane well samples indicate an API of 26.3° at 15°C with 98.26 per cent of the oil’s mass representing carbon chains of

Northwestern Alberta/Foothills

The company owns three gas plants.

It recently started up its third plant at Hinton with a fourth plant at Minehead scheduled to be on stream in the first quarter of 2011. Tourmaline is already planning an expansion next winter for its gas plant at Sunrise, which just came on stream.

“That’s that infrastructure control that lets you get operating costs down to the $6/boe or lower level and also improves the performance of your wells because you can operate the whole system at more appropriate flowing pressures,” the Tourmaline CEO said.

Both the Deep Basin and Montney plays have strong economics even at low gas prices, aided by liquids from the Montney. The company calculated its economics on total well costs (drilling, casing and completing) of $4 million for Alberta Deep Basin vertical wells (including Alberta royalty incentives) and $4 million for B.C. Montney horizontals. However, the last two horizontals have been drilled for less than $2 million, Rose noted.

Year-end 2009 reserves were about 60 million boe, and Tourmaline estimates it has more than doubled those with this year’s E&P program and the acquisition of Talisman Energy Inc.’s Deep Basin assets in the Greater Hinton area, which closed June 1. Tourmaline’s goal is to be the lowest cash cost producer in the basin by 2011, and it is making good strides towards that, he said. Fourth-quarter 2010 operating costs are forecasted at $5.60/boe.

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C7 to C30. A saturates, aromatics, resins and asphaltenes test has been performed and shows an aromatic content of 63.08 per cent by weight. Anglo Canadian said it is encouraged by this value, because high aromatic content — which represents benzene (C6), toluene (C7) and ethylbenzene (C8), among others — may speak to greater oil flowability and a higher oil value.

Anglo Canadian is preparing a vertical frac on the Sturgeon Lake South 5-10 well.

Completion operations on the Shane well and Sturgeon Lake South 5-10 well will continue pending petro-physical and engineering evaluations, as well as equipment availability.

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NOVEMBER 2010 • OIL & GAS INQUIRER

Galleon Energy reports 100 per cent drilling success in Q3 Galleon Energy Inc. drilled and cased 17 wells during the third quarter of 2010 for a success rate of 100 per cent. This drilling was as follows: 8 (8 net) Doig horizontal light oil wells, 1 (0.75 net) horizontal Montney gas well at Kakut, 2 (1.45 net) North Peace River arch wells, 4 (3.93 net) Eastern Montney horizontal gas wells and 2 (2 net) oil wells within the Eastern Montney Business Unit.

Galleon has hedged in excess of one half of its 2011 production at C$5.73 per thousand cubic feet (Mcf ) and $82.90 per barrel of West Texas Intermediate (WTI). Production based on field estimates for the third quarter of 2010 is approximately 13,850 barrels of oil per day (boe/d) — 59.4 million cubic feet per day of natural gas and 3,960 barrels per day (bbl/d) of crude oil and natural gas liquids. Production, net of contemplated minor asset sales, is expected to average over 14,000 boe/d in the second half of 2010.

Current production for the week ended Oct. 2, 2010, is in excess of 14,000 boe/d based on field report estimates. In addition, there are seven wells in the process of being completed, which are expected to be tied in during Q4 2010. 900 boe/d is shut in waiting upon regulatory approvals.

Capital expenditures during the second half of 2010 are allocated 80 per cent towards moving reserves from probable to proven and from proven to proven producing. Currently, there are four rigs drilling.

Year-end production is forecast to range between 14,000 boe/d and 14,500 boe/d, of which 25–30 per cent will be crude oil and natural gas liquids. This forecast excludes approximately 900 boe/d shut in pending regulatory approvals.

Year-end net debt is expected to be approximately $128 million to $143 million, depending upon the size of minor asset sales, with forecasted operating costs in the second half of 2010 to be less than $10/boe.

For the second half of 2010, 14,000 Mcf/d of natural gas is hedged with an average fixed price of $6.13/Mcf, and 3,000 bbl/d of crude oil is hedged with an average fixed price of C$75.40/bbl WTI.

Northwestern Alberta/Foothills

Alberta reports record revenue for conventional oil and gas land sales The Alberta government said it has already reached a calendar-year record of $1.86 billion for petroleum and natural gas land sales, not including oilsands auction revenue, after its Crown auction on Sept. 29. This passes the previous record of $1.83 billion for conventional land sale revenue set in 2005.

The Sept. 29 sale brought in $122.29 million in bonus bids on 245,819 hectares (ha) at an average of $497.48/ha.

This brings the year-to-date total, which includes oilsands parcels, to $1.88 billion ($668.18/ha) for 2.81 million ha. To the same point in 2009, $247.02 million ($188.59/ha) had flowed to provincial coffers on 1.3 million ha.

“Looks like a variety of things, but [the] focus [was] in the west-central plains and adjacent Foothills west of Fox Creek, northwest of Hinton, south of Grande Prairie,” said Brad Hayes, pres­ ident of Petrel Robertson Consulting Ltd. “Probably some Montney activity spurred by recent tight oil successes.”

Highlights of the Sept. 29 sale included a bonus high of $14.68 million successfully submitted by LandSolutions Inc. for a 4,608 ha licence in northwestern Alberta. The broker paid an average of $3,185/ha for several sections at 63-21 W5 and 63-22 W5.

Canadian Coastal Resources Ltd. plunked down $11.89 million for a 2,816 ha licence, paying an average of $4,224/ha. The broker acquired several sections at 58-2 W6.

Six licences between 63-4 W6 and 63-8 W6 attracted combined bonus bids of $14.81 million. Daily Oil Bulletin (DOB) records show that on Sept. 27, Paramount Resources Ltd. spud a development horizontal well in the Kakwa area with gas listed as the objective at surface location 13-5-63-4 W6, with the Falher member as the total depth zone to a projected depth of 4,143 metres.

Three licences between 46-15 W5 and 48-15 W5 generated bonus bids of $18.62 million. One of the parcels attracted a bid of $8.69 million by Scott Land & Lease Ltd., which paid an average of $1,414/ha for the 6,144 ha parcel. The licence

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Northwestern Alberta/Foothills included several sections at 48-15 W5, 47-16 W5 and 48-16 W5.

O&G Resource Group Ltd. produced the land sale per-hectare high of $15,768 for a 256 ha lease, paying a total bonus of just over $4 million. The broker acquired the rights to the southern half and northwestern quarter and the northeastern quarter of section 16 at 50-9 W5.

DOB records show that on Sept. 12, PetroBakken Energy Ltd. rig-released a horizontal well in the Pembina area to a total depth of 2,929 metres at surface location 1-18-50-9 W5. Oil was the objective with the Cardium formation listed as the total depth zone.

Alberta’s auction on Sept. 1 took in $186.63 million in bonus payments, with parcels in the northwest and deep south attracting the highest bids. A total of 303,730 ha were on offer, drawing an average of $614.47/ha.

The high bonus for the sale was from Scott Land & Lease Ltd. with a bid of $23.54 million ($2,873.68/ha) for an 8,192 ha licence in 74-7 W6 in the La Glace area north of Grande Prairie. DOB records show that Capio Exploration Ltd. has licensed a new pool wildcat directional oil well with a surface location of 2-74-7 W6 and the Charlie Lake formation listed as the projected zone. Terra Energy Corp.

Alberta's land sales from January through September broke the previous record for total revenue.

also has licensed a directional Montney natural gas well in the area with a surface location of 1-73-8 W6.

Orleans Energy Ltd. posted the highest per-hectare payment, offering $8,341.89/ha (a total of $4.27 million for two parcels) to acquire all of section 30 in 63-22 W5 and all of section 26 in 63-23 W5 in the Waskahigan area in west-central Alberta.

The licences are for petroleum and natural gas below the base of the Viking formation and for P&G rights, respectively.

In a news release, Orleans said that with the acquisition of the two key sections offsetting its recently completed Montney horizontal light oil well at 5-25-63-23 W5

it has amassed a 33-section (21,120-acre), contiguous land block at Waskahigan, all at 100 per cent working interest. The company said it believes that it has now amassed all of the significant, prospective acreage in this emerging exploration area and intends to undertake a focused drilling delineation strategy.

The area along the Alberta-Montana border continued to attract interest from operators with Standard Land Company Inc. putting up the high lease bid of $5.44 million ($2,657.51/ha) for a 512 ha petroleum and natural gas rights in 1-19 W4 in the Del Bonita area.

— DAILY OIL BULLETIN

Wilbros lands pump station contract for Nipisi heavy crude pipeline Willbros Group, Inc. reports that Pembina Pipeline Corp. has awarded Willbros Canada a project for the construction of six pump stations for the Nipisi Heavy Crude Pipeline Project. The scope of work includes site grading at select sites, piling, pipe rack, process pipe, installation of process pumps, underground drain tanks,

concrete work and site fencing. The project will begin immediately and is scheduled for completion in February of next year. “ We a r e ple a s e d to h ave t h i s opportunity to work for Pembina to expand their heavy oil pipeline transportation capacit y. We have seen signif icant improvement in the Canadian market and

this award further evidences our belief that the oil industry is rebounding. Renewed investment in the region continues to create growth opportunities for all of Willbros Canada units including pipeline construction, maintenance services and fabrication,” said Randy Harl, president and CEO.

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Suncor celebrates reclamation of the oilsands’ original tailings pond

by Deborah Jaremko

SEP/09

SEP/10

SEP/09

SEP/10

WELLS SPUDDED

89

58

WELLS DRILLED

91

58

Photo: Suncor Energy Inc.

natural landscape of the boreal forest,” said Sean Wells, Suncor’s manager of research engineering.

Pond 1 — one of eight tailings ponds that Suncor has created that cover a combined 3,154 ha — was decommissioned in December 2006, after nearly 40 years of operations. Wells said that closure began in earnest in 2007, the most significant aspect of which being the removal of mature fine tailings. MFT is the mixture of sand, silt, clay and residual bitumen left over from the extraction process.

“A lot of the clays settle very, very slowly, and what we end up with is a semifluid layer of what we call MFT,” said Wells. “If we leave the types of deposits that we create to their own devices, how long this stuff would take to actually finally settle out to the bottom of the pond, those time frames are on the order of potentially centuries. No one would really like us to wait that long.”

The biggest challenge facing Suncor and other oilsands mining operators in restoring tailings areas to natural landscapes is creating a solid surface f rom what is essent ia l ly sludge, or what Wells compared to a “giant pool of Jello.”

To help remove the MFT at Pond 1, Suncor backfilled the site with 30 million tonnes of reclaimed tailings sand, pushing the volumes towards an area where a pump out could be enabled.

Much of the MFT from Pond 1 has been moved to another tailings pond that Wells said is “better suited for longterm storage and treatment.”

Over the next two decades, Suncor repor ts it w ill maintain and closely monitor progress on the site. “Ongoing soil, water and vegetation assessments will help ensure the site is on course for return to a sustainable landscape and self-sustaining ecosystem,” the company reported.

“We invested a great deal of time and resources to complete the surface reclamation of Wapisiw Lookout and we’ve also learned a great deal,” said R ick George, Suncor’s president and CEO. One of its technology innovations is called tailings reduction operations (TRO), which Suncor received regulatory approval to put into action earlier this year and plans to spend more than $1 billion on its implementation over the next two years. The company says TRO has the potential to reduce tailings reclamation time by decades, speeding the return to a natural habitat.

Suncor says because of TRO it won’t be building any new tailings ponds. The next tailings pond on Suncor’s target for reclamation is Pond 5, a 440 ha area that started operations in 1997 and was decommissioned in 2009, where TRO is currently underway.

Over time, Suncor says, forest cover will grow on the restored surface of the former tailings pond.

The first tailings pond in the oilsands industry is now officially the first to have a reclaimed surface. On Sept. 23, Suncor Energy Inc. celebrated what it calls an industry milestone, being the first company to achieve this major step in the restoration of a tailings pond to a natural landscape.

Tailings Pond 1, a 220-hectare (ha) area that started operations as part of the first commercial oilsands plant in 1967 — when Suncor was known as Great Canadian Oil Sands and mining was the only way to go about producing bitumen — will now be known as Wapisiw Lookout, a fledgling solid surface that is home to 630,000 shrubs and trees planted earlier this year.

Wapisiw is a Cree word that means “swan,” and its use in this context was inspired by the Cree named Waupisoo, who brought the first samples of oilsands to European explorers in the 1700s.

“Ultimately, it will look very similar to the NORTHEASTERN ALBERTA WELL ACTIVITY

SEP/09

SEP/10

WELL LICENCES

79

57

▼

▼

▼

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • NOVEMBER 2010

37

Northeastern Alberta

CNRL and a contractor face safety violation charges related to a fatality Canadian Natural Resources Limited (CNRL) and a contractor, Clayton Construction of Lloydminster, are facing charges under the Alberta Occupational Health and Safety Act in the death of a Clayton employee in a tailings pond near Fort McMurray two years ago. Rick Boughner died in September 2008 when the floating excavator he was using to clear debris from the pond tipped over and trapped him underneath.

CNRL faces two charges relate to failing to ensure the company it has contracted follows safety rules, said Chris Chodan, a department spokesman. The company was not available for comment.

The charges against Clayton include failing to maintain the health and safety of worker; failing to ensure equipment used in a worksite is maintained in a condition

that it will not comprise the health of safety of a worker using it, failing to ensure that a worker is trained in the safe operation of the equipment he is required to operate, failing to identify existing or potential hazards to workers and taking measures to eliminate or control the hazards, failing to ensure

safety charges in connection with an incident in 2007 at the Horizon oilsands project.

Two temporary foreign workers from China died and two others were seriously injured when the roof of a steel oil storage tank being constructed collapsed. The workers were welding the wall structure inside the

The charges against Clayton include failing to maintain the safety of a worker and its equipment. equipment is operated in accordance with the manufacturer’s specifications and failing to ensure that powered mobile equipment is inspected by a competent (trained) worker for hazardous defects.

CNRL along with two Chinese contractors earlier faced occupational health and

tank when the roof support structure collapsed onto them.

CNRL, Sinopec Shanghai Engineering Company Ltd. and SSEC Canada Ltd. face numerous charges including several counts of failing to ensure the health and safety of the workers.

Chinese investors bring more than cash to the Canadian oilpatch In an industry where cash is king but often in short supply, there’s little doubt that the deep pockets of emerging Asian economies like China and an increased desire by those countries to dig deep and invest in Canada’s oil and gas sector has been a welcomed trend.

“One, for Canadian companies it gives them access to large amounts of patient capital that allow them to accelerate their projects,” said Barry Munro, leader of Ernst & Young Inc.’s national oil and gas practice. “For the Chinese, it offers access to significant reserves in a politically stable environment and access to worldclass management and technologies. This isn’t really a play to bring technology to Canada — this is a capital play.”

Laban Yu, Hong Kong–based oil industry analyst for Macquarie Securities Ltd., agreed that capital is the key driver to deals involving Chinese and Canadian companies, but noted other perks are also beneficial. As an example, he cited PetroChina’s agreement this year to buy a 60 per cent stake in two undeveloped oilsands properties held by Athabasca Oil Sands Corp.

(AOSC). The deal closed in February with a cash payment of $1.9 billion, and there are 38

NOVEMBER 2010 • OIL & GAS INQUIRER

three loan agreements allowing AOSC to draw up to $1.1 billion.

“PetroChina’s major contribution is its deep pockets. However, it is true that it has SAGD [steam assisted gravity drainage] technology and expertise as its Liaoning oilfields — which are some of the most difficult in China — and they are using SAGD successfully,” Yu said. “Low-cost equipment sourcing is also a possibility. There is also evidence that PetroChina uses higher longterm oil price forecasts to make investment decisions, especially overseas. This could provide AOSC a lower hurdle to clear for project approval.”

“PetroChina has sophisticated SAGD operations at its Chinese heavy oil fields,” said Sveinung Svarte, AOSC’s president and CEO. “They also have a very large R&D department working on ways to minimize environmental impacts while maximizing the amount of oil produced. We are privileged to have such a knowledgeable and experienced joint venture partner.”

Earlier this year, Chinese sovereign wealth fund China Investment Corp. agreed to spend $817 million on Penn West Energy Trust’s bitumen properties in the

Peace River region of northwestern Alberta through a new joint venture with the trust.

Bill Andrew, Penn West’s CEO, says the deal is indicative of the new landscape in the Canadian oilpatch as companies are forced to look further abroad for financing and Asian countries, most notably China, are often eager to form joint-venture partnerships.

“We started working on this a couple of years ago. I won’t say we’re any sorts of geniuses when it comes to the future, but it became very apparent that there was going to be struggles for U.S. capital, so we started to look at Asia,” Andrew said, noting that Penn West has since announced a similar deal with Japan’s Mitsubishi Corp., which will provide $850 million under a joint venture to develop shale gas and conventional natural gas in northeastern British Columbia.

“We believe the steps we have taken as a company with China Investment Corp. and Mitsubishi are sort of our first steps,” said the Penn West CEO, adding that the opportunity to share knowledge should not be underestimated, and he believes it will be a key cog as the Canadian oil and gas industry moves forward.

Northeastern Alberta “What else do they bring aside from capital? I think they are very sound business people. They have a tremendous interest in trading of technology...primarily drilling and completion techniques,” Andrew said. “We’re very, very impressed with their reservoir engineering capability, their modelling capability. And I believe they are impressed with some of the things we can do to reduce drilling time and some of the things we do on the completion side as far as completion tools and technology.”

According to the Commercial Service of the U.S. Embassy in Beijing, limited domestic reserves have forced China to exploit more of its heavy crude reserves and to import increasing quantities of heavy crude oil. This type of oil is more difficult to recover from the ground, more difficult to refine and more polluting than light crude — thus requiring advanced technology.

Pete r Te r t za k ia n, c h ie f e ne r g y economist and managing director for ARC Financial Corp. and an author who has written extensively on China’s energy patterns and needs, noted, “I’ve met with some of the Chinese oil and gas officials, and t hey have k nowledge sets and

technologies that we’re not familiar with here that can be quite valuable as well, in terms of the secondary recovery and the recovery of incremental barrels of established reserves. Typically, we produce about 25 per cent of the reserves that are in place and then kind of move on. But in their oilfields, they tell me they have ways of squeezing more out of it in an economic fashion.”

Although he admits that the mutual flow of knowledge has yet to be tested and quantified, Tertzakian believes it will evolve as Canada-China joint ventures mature and both sides gain a better understanding of one another. That said, like the other analysts Tertzakian said the primary benefit of Chinese investment in Canada’s oil and gas industry is the infusion of capital and China’s patient approach to realizing a return on the investment, especially when compared to North America’s quarterly growth mindset.

“They bring a long-term vision and view rather than the quarterly tyranny of performance metrics. They’re business savvy, but at the same time they are also long-term, visionary thinkers. Ten years is a short period of time for them in terms of thinking ahead,” the ARC analyst said.

Greg Stringham, VP of the Canadian Association of Petroleum Producers, said the fact that Chinese entities are investing in oil and gas operations around the globe and gaining associated experience and knowledge will also prove beneficial to Canadian operators.

“They bring a very global perspective.

They are active in many locations around the world and I think we will see more of that global perspective being applied to Canada and, in particular, Alberta’s oilsands as it becomes a much more recognized global factor in the oil market,” Stringham said.

Canada’s oilpatch can expect to see more Chinese investment following federal government signals that Canada is open for business with China, a situation that could greatly benefit the energy sector, says Peter Harder, president of the Canada China Business Council.

“China’s investment in the oilsands and energy sector and mining sector in Canada is about take off even more significantly than it has in the last number of years,” Harder said. “There is no doubt that China needs and wants energy.”

— DAILY OIL BULLETIN

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NOVEMBER 2010 • OIL & GAS INQUIRER

Central Alberta

Photo: Joey Podlubny

Enbridge unveils pipeline and terminal expansions totalling $920M

Enbridge’s projects include a $260-million expansion to its tankage at Edmonton, for service in 2012.

Enbridge Inc. announced on Sept. 29 that its wholly owned subsidiary, Enbridge Pipelines Inc. (EPI), will expand the tankage of its mainline terminal at Edmonton by one million barrels at an estimated cost of approximately $260 million, subject to regulatory approval. The expansion is targeted for completion by late 2012.

The project is required to accommodate growing oilsands production receipts both from Enbridge’s Waupisoo Pipeline and other non-Enbridge pipelines. The expansion, which will be conducted over two phases, will consist of the construction of four tanks in the north terminal and the installation of short segment of pipeline and related infrastructure.

Subject to regulatory approval, construction will begin early in 2011. Phase 1 is expected to be in service in the third quarter of 2012 and Phase 2 in the fourth quarter of 2012. “These additional tanks

will help ensure the necessary infrastructure is in place to accommodate increased oil volumes anticipated in 2012 and will provide improved netbacks for our customers,” said Stephen Wuori, Enbridge’s executive VP of liquids pipelines.

The expansion will be undertaken under the terms of the 2010 Incentive Tolling Settlement between EPI and the Canadian Association of Petroleum Producers (CAPP). Enbridge has received a letter of support from CAPP to undertake the project.

Earlier in September, Enbridge Inc. announced an agreement to provide pipeline and terminalling services to the proposed Husky Energy Inc.–operated Sunrise oilsands project. Enbridge will construct a new originating terminal (Hartley terminal) at the Sunrise project, a 112-k i lomet re, 24 -i nc h- dia meter pipeline from Hartley to Enbridge’s Cheecham ter minal and additional tankage at Cheecham.

The estimated cost of the project is about $475 million with an initial capacit y of 90,000 barrels per day (bbl/d), expandable to 270,000 bbl/d.

The facilities are expected to be in service in the second half of 2013. “This will bring the number of oilsands projects connected to our system to eight by 2013,” said Patrick Daniel, president and CEO of Enbridge. The new project also raises expansions and extensions of Enbridge’s Regional Oil Sands System

“This will bring the number of oilsands projects connected to our system to eight by 2013.”

— Patrick Daniel, President and CEO, Enbridge

Enbridge said it will take steps to minimize potential impacts associated with noise, traffic and dust during construction.

The work will be conducted within the existing Enbridge terminal property, located in an industrial area in Strathcona County.

announced in the last year to a total of approximately $2.3 billion.

Under the terms of the agreement, Enbridge will also provide pipeline transportation services on its existing Regional Oil Sands System for up

SEP/09

SEP/10

SEP/09

SEP/10

WELLS SPUDDED

157

209

WELLS DRILLED

153

209

CENTRAL ALBERTA WELL ACTIVITY

SEP/09

SEP/10

WELL LICENCES

273

247

▼

▲

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • NOVEMBER 2010

41

Central Alberta

to 90,000 bbl/d of diluted bitumen produced from Phase 1 of the Sunrise projec t. A l l of t hese a r ra ngements remain subject to the final sanctioning of the Sunrise project by Husky. The initial term of the pipeline and terminalling agreement is 20 years, w ith Husk y having the right to extend the agreement in successive five-year terms for a total contract life of 45 years.

Also in September, Enbridge said it expand its Athabasca Pipeline to accommodate recent shipping commitments by the Christina Lake oilsands project operated by Cenovus Energy Inc. The estimated cost of the project is approximately $185 million. The Athabasca Pipeline transports crude oil from various oilsands projects to the mainline hub at Hardisty, Alta.

Following this expansion, which is expected to be in ser v ice in the third qua r ter of 2013, t he capacit y of t he At habasca P ipel i ne w i l l be 430,0 0 0 b b l /d o f o i l , d e p e n d i n g o n c r u d e s l at e . Wu o r i n o t e d t h at t h e p ip e line ca n be ex pa nded to as muc h as 570,000 bbl/d if shippers need more capacit y in the future.

— DAILY OIL BULLETIN

Phoenix Oilfield reports a reduced loss for Q2 Phoenix Oilfield Hauling Inc.’s operating costs improved in the second quarter of 2010, which allowed the company to reduce its net loss despite only slightly higher revenues in the traditionally weakest quarter of the year in Canada. Phoenix president Christopher Challis noted that a long spring breakup and a wetter spring than expected resulted in lower costs and a modest earnings before interest, taxes, depreciation and amortization.

T he long brea k up p e r io d compounded by unseasonably wet weather

also extended provincial road restrictions well into the end of the second quarter, which in turn prevented Niskubased Phoenix’s customers from commencing with their projects in early June. Some projects were delayed by as much as six weeks, reducing equipment utilization levels in Canada.

“Although the drilling activity in our market areas in Canada and the United States has begun to rebound, pricing is still lagging in most markets as the industry starts to come out of the bottom

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of the cycle and we expect another quarter or two until pricing returns to more normal levels,” Challis said.

Phoenix booked a net loss of $2.28 million for the three months ended June 30, 2010, on revenues of $5.18 million.

That compares to a net loss of $4 million on revenues of $5.04 million for the same quarter last year. The company had negative cash flow of $1.08 million in the second quarter this year, an improvement over negative cash flow of $2.36 million last year.

Photo: Joey Podlubny

Central Alberta

Phoenix lost $3.96 million in the first half of 2010, down from $15 million in last year’s first half.

For the first half of this year, the company had a net loss of $3.96 million on revenues of $14.93 million, compared to a loss of $2.64 million on revenues of $20.9 million in 2009.

For t u n ate ly, a l l i nd ic at ion s p oi nt toward an active second half and first quarter of 2011 in the company’s direct ma rket s i n Ca nada a nd t he Un ited States, Challis added.

“We are encouraged by industr y forecasts for drilling activity indicating an increase of 42 per cent in the United States and an increase of 53 per cent in Canada in the second half of 2010 compared to the second half of 2009,” he commented. As its initial asset repositioning and corporate restructuring nears completion and start up costs have begun to decline, Phoenix said its new expansion areas have become more established and the company is beginning to see improved contributions from these newer markets.

During the second quarter, Phoenix opened a new base of operations in southwestern Manitoba in June, giving it greater geographical diversity within Canada in oil-producing areas of the country. It also began a wind turbine transportation project in northeastern British Columbia at the end of June.

— DAILY OIL BULLETIN

Husky acquires natural gas properties in west-central Alberta Husky Energy Inc. says it has signed a purchase agreement to acquire natural gas properties in west-central Alberta, which will significantly add to its production and reser ves and extend the optimum utilization of its Ram River gas plant.

The asset acquisition will provide Husky with more than 65 million cubic feet per day of natural gas production or 10,800 barrels of oil equivalent (boe) per day. In addition, the acquisition will contribute 37 million boe of proven reserves and 11.7 million boe of probable reserves. These reserves estimates are as of June 1, 2010.

3

“As part of our heightened focus on growing near-term production, Husky has initiated a strategy to accelerate near-term production opportunities and to leverage our balance sheet capability in order to make acquisitions that fit with our business competence,” said CEO Asim Ghosh.

“This agreement represents an important step in executing that strategy.”

The Ram River gas plant processes a significant portion of the production that is being acquired, and over a fiveyear period, further production from the acquired properties will be integrated into the plant. “This is an important acquisition that adds to our natural gas production

and reserves in an area where we have significant gas gathering and processing infrastructure,” said Ghosh. “The terms of the deal provide an attractive rate of return at today’s natural gas prices and offers Husky significant upside potential.”

The agreement is subject to final closing and regulatory approvals, expected in fall of 2010. The Ram River region in the foothills of central Alberta is a core gas producing area for Husky. The company currently produces 50 million cubic feet per day. The acquisition adds 160,000 acres of land to the company’s holdings, including 122,000 undeveloped acres, doubling Husky’s current land holdings in the region.

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Service companies invest more this year as activity levels rise

Ltd., where capital spending rose to $123.6 million to the end of June this year from only $22.3 million a year ago.

Canadian Energy Services L.P. had the second highest increase from last year, but that was due to its acquisition on June 30 of Fluids Management II Ltd. Daily Oil Bulletin records show that Trican, Calfrac Well Services Ltd. and Canyon Services Group Inc. — all striving to meet increased demand for hydraulic fracturing equipment as producers shift emphasis to horizontal wells with multistage fractures — have set 2010 capital budgets totalling $617 million, up about $495 million from actual capital spending in 2009. These three companies invested nearly $205 million to the end of June this year to expand their equipment and services.

On top of that, new public company Gasfrac Energy Services Inc. plans to

invest $100 million in 2010–11 to expand its fleet of equipment and services.

With a new lower forecast of drilling activity for next year and this year’s expansion of fracturing capacity, Peters & Co. Limited said that western Canadian producers will need between 1 million and 1.1 million of horsepower, a little less than the 1.14 million to 1.18 million that will be available. The biggest fracturing companies in Canada are Calfrac, Trican, BJ Services and Sanjel Corporation.

Peters & Co. is now forecasting that western Canadian drilling will fall next year to 10,500 wells from 11,000 this year and a previous 2011 forecast of 12,500 wells. Operators will limit spending to cash flow levels and cash flow will be reduced by lower natural gas prices, Peters & Co. said, noting the 12-month strip price is around US$4.50 per million British thermal units, a 15 per cent decline since June which limits hedging opportunities for producers.

Total capital spending by all 40 service companies, including acquisitions, amounted to $1.1 billion to the end of June this year, down from $1.19 billion in the same period last year. The biggest yearover-year decline was at Pembina Pipeline Income Fund, where capital spending fell by $300 million this year, mainly due to the $274-million acquisition of the Cutbank Complex in 2009.

Partly helping to fund capital investments, cash flow for the 41 service and supply firms rose to $1.36 billion for the six months ended June 30 from $1.16 billion a year ago (but still far below the firsthalf peak of $2.07 billion in 2006). Almost all of the cash flow increase from last year occurred in the second quarter when funds flow jumped to $504.6 million from $379 million in 2009.

Although drilling levels were better this year than in 2009, cash flow gains

SEP/09

SEP/10

SEP/09

SEP/10

WELLS SPUDDED

116

185

WELLS DRILLED

121

176

Frac pressure companies like Calfrac Well Services Ltd. are racing to build up their fleets.

Led by pressure pumper firms, service and supply companies began to invest more in the second quarter as oilfield activity recovered from last year’s downturn. Excluding acquisitions, 41 public service companies operating in Canada and abroad invested $501.1 million in the three months ended June 30, 2010, up from $415 million a year earlier.

As capital spending was lower in the first quarter this year than in 2009, investment levels for the first six months of 2010 were slightly lower, at $807 million this year versus $918 million to the end of June 2009. Both years represent a large decline from the $1.47 billion invested in the first half of 2008.

Of the 41 companies, 25 increased their capital spending this year while 16 had lower investment levels. The largest increase was at Trican Well Service SOUTHERN ALBERTA WELL ACTIVITY

SEP/09

SEP/10

WELL LICENCES

246

306

▲

▲

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • NOVEMBER 2010

45

Southern Alberta

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for the most part came from pressure pumping and pipeline companies as rates charged by drilling companies for their services remain weak this year.

Trican had the largest year-over-year increase in cash f low for the first six months of this year, with a $107.7 million rise to $105.4 million from negative cash flow of $2.3 million a year earlier. Some of the larger increases from last year were at Inter Pipeline Fund, Pembina Pipeline, Flint Energ y Ser vices Ltd., Calfrac and Canyon.

First half profits rose to $550.9 million from $417.6 million last year. The increase would have been much larger except for the $119 million year-over-year decline in Precision Drilling Corporation’s profits to a small loss of $4.53 million. Precision’s profits were hurt by $52 million in financing charges and a $26-million foreign exchange loss.

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million from negative cash flow of $2.3 million a year earlier.

For the three months ended June 30, 2010, Precision’s net income loss of $66.55 million represented a $124-million decline in profits from the second quarter of 2009 and was the main factor in only a small increase in the combined 41 company profit total of $71.7 million (versus $25.13 million a year earlier).

The biggest year-over-year increase in profitability for the second quarter came at Petrowest Energy Services Trust, which reduced its net loss this year to $5.46 million from a loss of $48.6 million last year. Some of the larger year-over-year improvements were posted by Trican, Inter Pipeline, Pure Energy Services Ltd. and Pason Systems Inc. Precision and Mullen Group Ltd. reported the largest declines in second quarter profits compared to last year.

— DAILY OIL BULLETIN

46

NOVEMBER 2010 • OIL & GAS INQUIRER

Southern Alberta

StatsCan says capital spending fell by 38 per cent in 2009 Capital expenditures by the conventional oil and gas extraction industry fell to $21.9 billion in 2009, down 38.5 per cent from 2008, Statistics Canada said in September. Combined spending in the non-conventional and conventional oil and gas sector totalled $33.13 billion last year, down from $53.7 bill ion i n 20 08, accordi ng to t he fed eral agency.

The non-conventional sector capital expenditures declined 38 per cent to $11.2 billion in 2009, but capital spending in this segment of the industry surpassed $10 billion for the fifth year in a row, the statistical agency said.

Based on estimates of the Canadian Association of Petroleum Producers, capital expenditures in the conventional and non-conventional sectors are expected to reach $42 billion this year.

Operating expenses for t he conventional sector declined 28 per cent from 2008 to $23.7 billion in 2009, the result of lower royalty payments.

Fo r t h e n o n - c o n v e n t i o n a l s e c t o r, operating expenses declined 5.2 per cent from 2008 to $13.9 billion, also largely as a result of lower royalt y payments.

Crude oil and equivalent production decreased 0.5 per cent from 2008 to 158.1 million cubic metres in 2009.

Marketable production of natural gas (- 6.8 per cent) and nat ural gas byproducts (-4.4 per cent) also declined in 2009.

The value of crude oil and equivalent hydrocarbons produced in 2009 totalled $61.6 billion, down 32.9 per cent from the $91.8 billion in 2008. This decline was due to decreases in wellhead prices in 2009.

The value of natural gas marketable production stood at $20.9 billion in 2009, down 53.1 per cent from 2008, as a result of lower wellhead prices in 2009. The value of natural gas byproducts fell 47.9 per cent to $5.8 billion in 2009.

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Southern Alberta

Bowood allies with Blood First Nation for Alberta Bakken play Bowood Energy Inc. has entered into an agreement with Kainaiwa Resources Inc., a corporation wholly-owned by the Blood Tribe First Nation, to acquire through a leasing arrangement an interest in 94.75 contiguous sections (60,640 acres) of land located within the Blood Tribe Reserve in southern Alberta. The lands are located in the emerging southern Alberta Bakken play.

Bowood says the lands are on trend and highly prospective for DevonianMississippian (Bakken equivalent) oil potential and other prospective formations. All of the lands contain the Devonian and Mississippian rights — which include the prospective Bakken, Three Forks and Banff formations — and the majority of the lands include all petroleum and natural gas rights with only a few (single) shallow zone exclusions.

The lease will add to Bowood’s land position in the southern Alberta Bakken fairway, where the company will hold a 100 per cent interest in approximately 104,000 net acres (41,600 net hectares), or 162 sections.

T h e le a s i n g a r r a n g e m e nt w i l l include a joint venture with the Blood Tribe. Bowood’s management team has been working in partnership with the Blood Tribe since 2000 and has successf ully implemented a number of joint ventures to develop resources on the reserve.

• A s part of its strategic joint venture arrangement, the Blood Tribe or its nominee will have the option to elect, in advance of drilling a well, to participate for a 20 per cent working interest in any such well on the lands. If the Blood Tribe or it nominee elects not to participate in such well, the Blood Tribe or its nominee

The company will hold a 100 per cent interest in approximately 104,000 net acres (41,600 net hectares), or 162 sections.

The lease will have a five-year term and is subject to mineral royalties substantially similar to Alberta Crown royalties. In addition, Bowood will commit to: • A total up-front consideration of $14.13 million; • A nnual rent of $5 per hectare, amounting to approximately $122,000 per year; • Drilling one well to a minimum depth of 1,000 metres in each of the first two years of the lease, and two wells in each year thereafter; and,

will be entitled to a 20 per cent working interest in such well once Bowood has recovered 200 per cent of the total capital cost associated with the well.

In addition, Bowood announced it has filed a preliminary short form prospectus in connection with a public offering of 60 million to 80 million subscription receipts, at 25 cents per receipt, for gross proceeds of $15 million to $20 million. The offering is co-led by GMP Securities L.P. and Haywood Securities Inc.

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Southern Alberta

Crescent Point acquires more than one million acres in southern Alberta Crescent Point Energy Corp. has acquired more than one million net acres of explora­ tory land in southern Alberta that it believes is prospective for multi-zone light oil opportunities, including the unconventional Bakken and Three Forks zones.

The company said its land was acquired through Crown land sales, freehold leasing programs and the acquisition of a private company.

“We believe there is signif icant untapped unconvent iona l l ight oi l resource potential in southern Alberta,” said Scott Saxberg, president and CEO of Crescent Point. “These acquisitions provide us with a large, low-cost exposure to this resource potential and a great opportunity to lever off the competitive and technical advantage we have gained through horizontal drilling and multistage fracture stimulation in the Viewfield Bakken and Lower Shaunavon resource plays in Saskatchewan.”

The assets acquired in the private company acquisition include approximately 900 barrels of oil equivalent per day (boe/d) of low-decline conventional production and more than 995,000 net acres of exploratory land in Alberta.

Independent engineers assigned reserves, using NI 51-101 reserve definitions and effective as of July 1, 2010, of approximately 3.6 million boe of proved plus probable and 2 million boe of proved reserves. The reserve life index is 11 years for proved plus probable reserves and 6.1 years for proved reserves.

Total consideration for the acquisition was approximately $95.6 million, comprised of $68.8 million of cash

and assumed debt and about 740,000 Crescent Point shares. The acquisition closed in July.

T he company has drilled and is currently completing its first horizontal exploration well into the play, and expects to drill more than 19 net development and exploration wells on the land by the end of 2011.

Crescent Point said the upside potential of the producing conventional assets acquired in the acquisition decreases the overall land costs and risks associated with pursuing the unconventional light oil exploration play in southern Alberta.

“After adjusting for the value of the

“These land sale acquisitions are in the core producing areas of the Bakken and Lower Shaunavon resource plays and have an immediate impact on our production base and reserves expectations,” said Saxberg.

“These lands recently became available and were proven by our recent drilling activity.”

As a result of the private company acquisition and the Alberta and Saskatchewan land acquisitions, Crescent Point is revising its 2010 capital expenditure plans and guidance. Capital expenditures are expected to increase by $175 million to $925 million, with $140 million of the increase allocated to the land acquisitions and the remainder directed towards increased drilling in the

“After adjusting for the value of the producing conventional assets and their potential upside, we acquired the land from the private [company] at a very low cost relative to recent land sale activity.”

— Scott Saxberg, President and CEO, Crescent Point

producing conventional assets and their potential upside, we acquired the land from the private [company] at a very low cost relative to recent land sale activity in the area,” said Saxberg.

In addition, Crescent Point has acquired more than 100 net sections of undeveloped land in Saskatchewan, including 60 net sections in the company’s core Viewfield Bakken and Lower Shaunavon resource plays through Crown land sales in the last several months. The company has internally identified approximately 200 net low-risk drilling locations at four wells per section on the land. It has already drilled two successful wells on this land.

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Alberta and Saskatchewan Bakken and Lower Shaunavon resource plays.

The company said its main focus for the remainder of 2010 and into 2011 will be capital-efficient projects on its undeveloped land base, further development of its Viewfield Bakken and Lower Shaunavon waterflood projects, and exploration of its emerging resource plays at Flat Lake, Saskatchewan, and in southern Alberta.

Year-end 2010 exit production is expected to increase to more than 71,000 boe/d from 69,500 boe/d, which represents an annual growth rate of more than 10 per cent excluding acquisitions.

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Saskatchewan

Canada’s original tight oil play continues to generate investment

Photo: Brian Zinchuck, Pipeline News

by Pat Roche

Cenovus Energy Inc. has quietly moved into the Bakken tight oil play with a heavyweight budget.

Saskatchewan’s Bakken light oil play continues to thrive. By mid-year, the province had licensed 326 Bakken wells, of which 133 had been drilled, according to Saskatchewan government figures. The dominant players are Crescent Point Energy Corp. (which in 2010 is drilling 191 net Bakken wells and has a total Bakken budget of $750 million) and PetroBakken Energy Ltd. (which plans to drill 100 net wells into the play this year).

The 2010 well count isn’t expected to match the record 714 rig releases in the southeastern Saskatchewan Bakken in 2008 when West Texas Intermediate crude oil rocketed to nearly US$150 per barrel (bbl). Even so, Macquarie Capital Markets Canada Ltd. said in a report earlier this year that the Bakken play in the Viewfield area is arguably one of the fastest-growing light oil plays in North America.

Certainly, production has shot up.

According to the province’s tally, oil output

averaged 61,000 barrels per day (bbl/d) in the first half of this year, up from 54,500 bbl/d in full-year 2009, 41,800 bbl/d in 2008, 13,500 bbl/d in 2007, 5,100 bbl/d in 2006, 1,600 bbl/d in 2005 and 750 bbl/d in 2004.

The province’s statistics show that 1,737 wells have been drilled into the southeastern Saskatchewan Bakken from 2004 to mid2010, and the play continues to show growth potential. While much of the available land has been snapped up in the established Bakken fairway around Viewfield, new areas are emerging. Also, a few big producers are giving the play a serious look, and there have been some significant land acquisitions.

Enerplus Resources Fund is expected to increase activity in the Saskatchewan Bakken following a huge land purchase.

When the fund’s $117-million Bakken development budget was originally set this year, most of it was earmarked for Montana and North Dakota. But the trust

is updating its plans after spending $117 million for 100,000 net acres of Bakkenprospective undeveloped land in Canada and the United States.

NAL Oil & Gas Trust has about 75 sections of Bakken acreage south of Viewfield, and also holds the Bakken rights in 245 sections of undeveloped lands near Hoffer, which is just north of the North Dakota border. The trust, which is Mississippianfocused in Saskatchewan, doesn’t plan to drill any wells in the area south of Viewfield this year, but it will likely drill one or two Bakken wells in the Hoffer area in 2011, said Andrew Wiswell, NAL’s president and CEO. In recent months a much bigger player has quietly made its public debut in the Bakken. Cenovus Energy Inc., the spinoff of Encana Corp.’s oil assets, has been buying Bakken lands west of Viewfield. At its investor conference in June, Cenovus said it has 57 undeveloped sections of land in the Roncott area, where it has drilled two horizontal and three stratigraphic wells.

Cenovus has about 140 more undevel­ oped sections of Bakken lands in the Viewfield and Estevan areas, where it has drilled four horizontal and three stratigraphic wells. The company plans to drill six Bakken wells this year, three of which have already been drilled. About six had been drilled prior to 2010.

At Cenovus’s investor conference, its president Brian Ferguson told reporters that the evaluation of those lands is still in the “very early phases.” He said the company was still evaluating the performance of its existing Bakken wells and had made no decision on additional drilling. “We do have a couple of areas that we have actually farmed out where other companies are drilling wells,” he said. “There’s, for example, a 30-well commitment by one other company...which has a 24-month window for which they’ve got approvals.”

— DAILY OIL BULLETIN

SASKATCHEWAN WELL ACTIVITY

SEP/09

SEP/10

WELL LICENCES

205

239

▲

SEP/09

SEP/10

WELLS SPUDDED

183

210

▲

SEP/09

SEP/10

WELLS DRILLED

179

235

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • NOVEMBER 2010

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• OIL & GAS INQUIRER

Oilweek, Oilsand Review, Oil and Gas

Central Canada

Conference Board forecasts a rise in crude production and profits

Crude oil prices have nearly doubled from their lows in 2009.

Canadian oil companies will fare much better this year and on into 2014 as crude production and profits will continue to trend upward on the back of a revival in global demand and rising prices, says The Conference Board of Canada. In its Canadian Industrial Outlook: Canada’s Oil Extraction Industry — Summer 2010 report released in September, the board said a reversal of fortunes from last year’s downturn is in the cards and a return to profitability will occur.

“Global consumption has rebounded almost to pre-recession levels. As a result, prices have nearly doubled from their lows of 2009, boosting the industry’s profitability,” said Todd Crawford, an economist with the conference board.

After dropping in each of the last two years, the board said Canada’s crude production will reverse course in 2010 and climb to 2.7 million barrels (bbl) per day. Although increased drilling in conventional fields will help, “future capacity increases are expected to be solely the result” of increased investment in non-conventional production.

“The economics of these mega-projects has improved greatly with the higher prices,

and as of last year accounts for the majority of Canadian crude production. Strong investment is expected in this sector throughout the forecast, and the non-conventional industry will drive up its share to account for twothirds of the 3.2 million bbl per day produced in 2014,” Crawford said in his report.

However, the report said declining conventional production “continues to hamper the outlook” for the entire industry. Despite a recent uptick in drilling, production in western Canada is expected to fall again this year as well productivity falls, and new wells drilled will not offset declining production at existing fields.

“On the other hand, the non-conventional side of the industry continues to shine — production this year is expected to climb to 1.5 million bbl per day. And the potential for further expansion is great — more than two million bbl per day of incremental capacity has been announced for the forecast period,” the report said.

The report noted that the conventional side of the industry already faced a long and steady declining production profile. Then the recession struck and production fell by 11.7 per cent in 2009.

As well, drilling fell to near-record lows and put future production at risk.

The board noted that the Petroleum Services Association of Canada concluded in its most recent drilling forecast that oil prices have reached sufficient levels to provide a reasonable rate of return on investment, and that oil well completions will increase significantly in 2010.

“But , accord i ng to t he E ne rg y Resources Conservation Board [Supply and Demand Outlook 2010–2019], production from existing wells will drop by 15.5 per cent per year in Alberta, more than enough to offset the uptick in drilling,” the report said.

“Moreover, having already exploited the best fields, oil companies must now turn to marginal discoveries, or use enhanced recovery techniques. Still, the rate of decline for western Canadian production will slow to 2.4 per cent this year, because of the more favourable economics.”

The conference board is predicting that conventional oil production will fall through the remaining years of the forecast but that several factors will help to slow the rate of decline, including Alberta’s revamped royalty scheme, the potential for increased offshore production and more output from formations such as Saskatchewan’s Bakken field. “Unfortunately, even with these positive developments, conventional production will still drop to 700,000 bbl per day by 2014,” the report said.

The conference board’s short-term expectations of conventional crude output are not shared by the three main oil-producing western Canadian provinces. Government officials in Alberta, Saskatchewan and Manitoba contacted by the Daily Oil Bulletin are all forecasting increased or flat output compared to 2009.

Alberta has raised its 2010 conventional crude forecast to 475,000 bbl/d.

Saskatchewan is expecting production this year to be essentially flat with 2009 output of around 424,110 bbl/d, while Manitoba said production is up about 20 per cent so far this year and it is projecting a strong crude output of 26,200 bbl/d for the full year.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • NOVEMBER 2010

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East Coast

Deep Panuke is scheduled to come on stream by Q3 2011

by James Mahony

Photo: Encana Corporation

Anticosti wells come up dry

Encana says it's still willing to sell a stake in Deep Panuke at the right price.

Although a key component is still in dry dock halfway around the world, Encana Corporation is sticking to a third-quarter 2011 forecast for first gas from its Deep Panuke project in Nova Scotia’s offshore.

When it comes on stream, the project should produce 200–300 million cubic feet per day for at least the next decade, depending on the life of the underlying gas field.

Panuke gas is destined for export to the United States through a link to the Maritimes & Northeast Pipeline (M&NE).

“By the end of [2011], we’ll be producing at maximum capacity...constrained by how much commitment we have on the M&NE Pipeline,” said David Kopperson, Encana’s VP for Atlantic Canada.

Slightly sour (0.18 per cent), and with some carbon dioxide (3.4 per cent), gas from Deep Panuke will be processed offshore before going ashore at Goldboro, N.S., through a 173-kilometre subsea pipeline that is “essentially complete.” Acid gas will be re-injected, while produced water will be treated and discharged overboard.

How profitable Deep Panuke would be at current gas prices is another matter.

Last November, while not actively pursuing sale of the project, Encana president and CEO Randy Eresman said the company would nonetheless consider selling it under the right scenario. This fall, Kopperson said Encana would look at selling a stake, again, if circumstances were opportune.

The project’s main component is the production field centre (PFC). Encana will not own it. Instead, while remaining project operator, the company will lease the PFC from Single Buoy Moorings Inc. Currently in the United Arab Emirates, the PFC will be under construction until some time in the first quarter of 2011, when it will set sail for Nova Scotia.

A s for t he e nt i re D eep Pa nu ke project, Encana estimated in February t he cost had edged up to rough ly $800 million from $760 million when sanctioned. Recent gas prices, which have hovered near or below $4 per thousand cubic feet. While providing no figures, Kopperson said costs at Deep Panuke are “north of $4” per million British thermal units.

— DAILY OIL BULLETIN

Corridor Resources Inc. reports that its 2010 three-well oil exploration program on A nticosti Island in Quebec has been completed. While exploration results were disappointing, the company reported some crude shows and permeable reservoir.

The wells were drilled to evaluate the oil potential of the Trenton / Black River and Mingan formations in the Jupiter, Chaloupe and Saumon prospects located in the east central part of the island.

The Jupiter well encountered live oil shows in the Mingan formation but no significant reservoir potential, and has been abandoned. The Chaloupe well encountered only minor dolomitized carbonates with no apparent reservoir development. The Saumon well was also dry.

Corridor’s drilling also recovered core from the oil-prospective Macasty shale, which is present across virtually the entire island. The company hopes to attract a knowledgeable shale oil player to farm-in on this play.

Corridor also reported that Apache Canada Ltd. is making good progress with respect to its shale gas appraisal program currently under way in the Elgin area of southern New Brunswick.

The Apache/Corridor Green Road B-41 well has been drilled as an offset to the vertical Green Road G-41 well drilled by Corridor in the fall of 2008 and fraced

by Corridor in November, 2009.

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International

IHS-CERA report says oilsands GHG emissions are just above average

by Paul Wells

Photo: Joey Podlubny

Enbridge invests US$34M in Idaho geothermal project

IHS-CERA says its evaluation includes all oilsands sources where earlier studies were less complete.

Well-to-wheels greenhouse gas (GHG) emissions from oilsands crude are lower than commonly perceived and stack up well when compared to other sources of U.S. crude imports, says a new report from Massachusetts-based IHS Cambridge Energy Research Associates (IHS CERA).

According to the report, oilsands products imported to the United States result in GHG emissions that are, on average, six per cent higher than the average crude consumed in the country. “This level places oilsands on par with other sources of U.S. crude imports, including crudes from Nigeria, Venezuela and some domestically produced oil,” the report finds.

The report, Oil Sands, Greenhouse Gases, and U.S. Oil Supply: Getting the Numbers Right, analyzed the complete well-to-wheels life cycle — which includes the extraction, processing, distribution and combustion of the refined fuel — to provide a comprehensive assessment of where oilsands fit in the spectrum of U.S. crude imports.

While numerous other studies compare oilsands to conventional crude, IHS CERA said its analysis uses as a comparison the

emissions from the average barrel of crude actually used in the U.S. in 2005.

Derived from the results of 13 publicly available studies from government, academic and industry sources, the analysis found that the total emissions from refined products wholly derived from oilsands mining operations are five per cent higher while in situ is up to 15 per cent higher than the average crude consumed in the United States.

However, the average for oilsands products processed in the United States is only six per cent because those products are often blends of oilsands and lowercarbon products as opposed to being wholly derived from oilsands.

“Taking into account the complete wellto-wheels life cycle is crucial for making comparisons between sources of crude oil,” said Jim Burkhard, IHS CERA managing director, global oil. “Seventy to 80 per cent of the GHG emissions come from the combustion of the fuel in an engine so the vast majority of emissions remain the same whether the oil comes from West Africa, Latin America or Canada.”

— DAILY OIL BULLETIN

Enbridge Inc. has agreed with U.S. Geot her mal Inc. to par t ner in t he 35-megawatt Neal Hot Springs geothermal project. The Calgary-based company will invest up to US$23.8 million for a 20 per cent interest in the plant. U.S. Geothermal, based in Boise, Idaho, will own the remaining 80 per cent.

The Neal Hot Springs geothermal project, developed by U.S. Geothermal, is located in Malheur County, Oregon. U.S. Geothermal is constructing and will operate the facility. Construction of the project is underway and an in-service date of the second quarter of 2012 is expected. The project will deliver electricity to the Idaho Power grid under a 25-year power purchase agreement.

“Enbridge is already heavily involved in renewable and alternative energy projects through our interests in 810 megawatts of wind, solar, waste heat recovery and fuel cell projects,” said Patrick Daniel, Enbridge president and CEO. Geothermal energy is renewable energy from the heat of the Earth’s interior.

The Neal Hot Springs geothermal project will recover this energy through a binary process that involves pumping hot water from a reservoir in the earth up t hrough production wells. From the production wells, the water will go through closed circuit heat exchangers where it will boil a refrigerant liquid that will be sent through turbines to generate electricity. The hot water will then be injected back into the underground reservoir.

“In 2009, we committed to generating a kilowatt of renewable energy for every kilowatt of energy that our operations consume, and we are making good progress on that objective,” Daniel said.

OIL & GAS INQUIRER • NOVEMBER 2010

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Careers in the Oilpatch

Alex Debogorski

Age: Occupation: Location: Education:

57 Ice road trucker Yellowknife Attended University of Alberta

If you watch the History Channel, chances are you’ve seen Ice Road

What brought you to the Northwest Territories?

Truckers. But what you may not know is that one of the stars of that

I wanted to know where to look for gold. So I go over to the geology

show, Alex Debogorski, who’s done a fair amount of hauling oil equip-

department [at the University of Alberta] and say, “I want to look for

ment in the frigid North, got his start driving coal haulers in Grande

gold. Who do I talk to?” The lady at the desk says, “Go see that guy over

Cache, Alta. Debogorski, on a publicity tour for his new book King of the

there — Professor Staulk.” And he says, “Go to Yellowknife.” He says,

Road, stopped by Oil & Gas Inquirer’s office in Edmonton to talk about life

“You buy a book. Park along the road. Buy an eyeglass, buy a hammer. Go

as an ice road trucker.

no farther in the bush — no farther than you can get back in a day — and break rocks. Look at the book and you’ll find gold.”

Your bio says you live in Yellowknife. Is that where you’re from?

I’m from Berwyn-Grimshaw [Alta]. I was either born in a hospital or a

Now you’re driving a truck, which leads me to believe you didn’t find

cave — one or another, depending on which relative you listen to.

much gold. Fast forward to the 2000s. How did you get on a tv show?

Camera crews from around the world come up there every year.

A cave?

Germany’s a favourite. England. Japan. They do one-hour documentaries,

It sounds pretty good on a resumé.

then they rush off and take it home. The History Channel got a hold of [one documentary], they showed it in the U.S., and the ratings would

How did you become a truck driver — was that your career choice?

go up every time they showed it. Original Productions got a contract

I [originally] came to the University of Alberta. I was going to be a lawyer.

and started looking for characters and every time they’d interview

Then I met my wife and we got married and moved back to the Peace

somebody, they’d say, “You want a character? Talk to Debogorski.”

Country. I had 16 jobs the first year. I was working in a tire shop in Grimshaw and a fellow came in and said, “We’re looking for a truck driver in Grande

You’ve spent a lot ot time in the north. Do you foresee the day

Cache. The truck driver got drunk and quit. Can you drive a truck?” So I said,

when the Mackenzie Gas Project becomes a reality?

“Of course I can drive a truck. I can drive anything. How much you paying?”

It’ll happen. We’re right in the middle of all this BS going on about Arctic

It was three times what I was making, so I said, “I’m with ya.”

waters. The Russians went and put a flag at the bottom of the ocean at the North Pole and the Americans want the line in the Beaufort Sea moved

When was that?

this way. We really have to get serious about sovereignty. We’re [northern

1972.

Canada] probably the most important piece of land in the world.

OIL & GAS INQUIRER • NOVEMBER 2010

59

TANK GAUGING

Visit www.oilpro.ab.ca Equipment catalogue updates every 6 min.

SYSTEMS

TGS - 5012 SOUR (Glycol Filled) • Glycol filled to prevent freezing • Add magnetically activated switches

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0.5 TGS 780-474-2365

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TGS

TGS

TGS - 5010 SOUR PULLEY SYSTEM • Grease sealed pulley • Large indicator & signboard • Add point switch • Tank-in-service installation

DNB ELECTRO MECHANICAL - 4-20MA • Tank-in-service installations • Field calibrated • Sweet and Sour Service • CSA Class 1, Div 1 EX

TGS - 5020 SOUR / 6020 SWEET SERVICE • Coned roof float prevents build-up • Simple installation • Excellent for retrofit applications • Tank internals: Stainless Steel, Teflon Fiberglass • Magnetically Activated Switches • 4-20mA Electronic output (Optional) • Pneumatic output (Optional)

CSA - Class 1, Div 1 Explosion Proof

X 0E S2 TG

Level

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✔ Pumpjacks (sizing

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pressure separators flarestacks

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(boosters: recip. and screw units)

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Looking for good quality surplus equipment OILF

removal downstream of compressors, dehys, amine units, or in transmission lines

I EL D PR O D U C T I O N

EQ UIPM ENT

OilPro Oilfield Production Equipment Ltd. 403·215·3373

Fax:

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Having a Hard time finding replacement parts for your Heat excHangers?

Joule Technical SaleS inc. offers spare parts and complete replacement units for all major brands.

TOLL FREE : 1.800.461.2788 TEL : 403.239.3477 FAX : 403.241.0148

NOVEMBER 2010 • OIL & GAS INQUIRER

✔ Compressors

systems (HotRod, Envirovault, Firetubes, etc.)

PROUDLY SERVING THE OIL & GAS INDUSTRY SINCE 1985

60

sweetening/choke/ mech. refrigeration

✔ Tank heating

Www.tankgaugingsys.com

sales@joule.ca

✔ Gas plants:

50, 100, 210, 400, 750, 1,000 and 1,500

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SWITCHING THE INDUSTRY • TGS20EX Magnetically Activated Electric Switch • PS35 Magnetically Activated Pneumatic Switch • NVM Mechanically Activated Pneumatic Switch • LSX Mechanically Activated Electric Switch Edmonton: 780-474-2365 Calgary: 403-685-8867

storage bullets, 12,000 – 60,000 USWG

help available)

gensets and fuel gas scrubbers/volume bottles

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TOOLS

Ball & Seat (Flow cage)

Seal Element (Packoff)

OF THE TRADE

Resettable Locking Mechanism

A LOOK AT NEW TECHNOLOGIES

Who is Production Control Services (PCS)?

Multi-Stage Tool

Plunger 1

Collar Stop

Illustrations: Production Control Services

The PCS Multi-StageTool

Tubing Casing

Heavy Duty Bumper Spring

PCS has specializing in artificial lift and well optimization for 25 years.

Serving customers from 28 locations in Alberta and the U.S., PCS offers the PCS Plunger Lift System, the PCS Opti-Flow Gas Lift System, Nitro2Go nitrogen generation and SCADA/well automation.

How does the PCS Multi-Stage Tool maximize production?

Deep wells, gassy oil wells and low gas / high liquid wells are typically not thought of as plunger lift candidates, but by employing the PCS Multi-Stage Tool, significant production increases can be achieved. The PCS MultiStage Tool creates multiple plunger lift systems in one well. Acting like an intermediary standing valve between plungers, the tool allows the liquid load to be lifted in stages. The well is then able to utilize its own energy to efficiently remove even large accumulations of liquids or heavy liquids.

The tool is placed roughly 40–70 per cent of the way down the tubing above a plunger lift system. Then a second plunger is set on top of the tool. During the first cycle, the bottom plunger carries fluids up the tubing to the tool.

The liquids travel through the tool and are held above it by gas flow. Upon shut-in, the tool retains these fluids until the top plunger falls from the surface and lands at the tool. Simultaneously, the bottom plunger falls back to the bottom.

During the next cycle, the top plunger picks up the held fluids and delivers them to the surface, while the bottom plunger brings more fluids to the tool. In subsequent cycles, the plungers fall together and rise together.

In this way, the tool allows the liquids to be lifted in smaller, more frequent amounts, enabling the well to remove more liquids and increase productivity.

What results can be expected from the PCS Multi-Stage Tool?

In Alberta Well A, the plunger lift system was unable to remove fluids. A pumpjack was cost-prohibitive given the marginal production. By using the Multi-Stage Tool, the well increased gas production from 0.5 cu. m/d [cubic metres per day] to 2.5 cu. m/d and maintained oil production of 2 cu. m/d.

In Alberta Well B, the well was shut in most of the time because of the amount of fluid, wax and sand it was producing. Use of the PCS Multi-Stage Tool resulted in initial production of 2 cu. m/d and 6 cu. m/d of oil. The well’s production then levelled off to its current rate of 1.2 cu. m/d and 1.4 cu. m/d.

Plunger 2 Bottom Hole Bumber Spring

What are the advantages of the PCS Multi-Stage Tool?

• Unique pack-off design makes it easy to remove or reset the tool.

• I nnovative engineering enables it to perform in wells with even equal amounts of liquid and gas.

• T he seal element and ball check tightly retains fluids above the tool, preventing slippage.

ALBERTA WELL A

Gas Production (cu. m/day)

Oil Production (cu. m/day)

Before Multi-Stage Tool

0.5

2

After Multi-Stage Tool

3.5

2

ALBERTA WELL B

Gas Production (cu. m/day)

Oil Production (cu. m/day)

Before Multi-Stage Tool

0

0

After Multi-Stage Tool

1.2

1.4

Information supplied by Julie Wienen, Director of Marketing, Production Control Services

OIL & GAS INQUIRER • NOVEMBER 2010

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Advertisers' Index 1174365 Alberta Ltd . . . . . . . . . . . . . . . . . . . . . . . 50 1214848 Alberta Ltd . . . . . . . . . . . . . . . . . . . . . . 49 Accuform Welding Ltd . . . . . . . . . . . . . . . . . . . . 56 Allan R. Nelson Engineering (1997) Inc . . . . . . . . 35 Aman Building Corp . . . . . . . . . . . . . . . . . . . . . . . 32 Ansell Healthcare Incorporated . . . . . . . . . . . . . 24 ATCO Structures & Logistics Ltd . . . . . . . . . . . . 54 Bear Slashing Ltd . . . . . . . . . . . . . . . . . . . . . . . . 36 Beijing Zhenwei Exhibition Co.,Ltd. . . . . . . . . . . 28 Bilton Welding and Manufacturing Ltd . . . . . . . . 52 Brother’s Specialized Coating Systems Ltd . . . . 40 Canadian Association of Petroleum Producers . . . 17 Canadian Enviro-Tub Inc . . . . . . . . . . . . . . . . . . . . 11 Canwell Enviro-Industries Ltd . . . . . . . . . . . . . . 36 CARES Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 City of Grande Prairie . . . . . . . . . . . . . . . . . . . . . 21 Compass Bending Ltd . . . . . . . . . . . . . . . . . . . . . 56 Contain Enviro Services Ltd . . . . inside back cover Crimtech Services Ltd . . . . . . . . . . . . . . . . . . . . 46 Dean’s Pump Service Ltd . . . . . . . . . . . . . . . . . . 58 DFI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

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NOVEMBER 2010 • OIL & GAS INQUIRER

Diversified Glycol Services Inc . . . . . . . . . . . . . . 47 dmg world media . . . . . . . . . . . . . . . . . . . . . . . . . 48 Ecoquip Rentals and Sales Ltd . . . . . . . . . . . . . . . 31 EITI Electrical Industry Training Institute . . . . . . 35 Falvo Electrical Supply Ltd . . . . . . . . . . . . . . . . . 52 Gaugetech Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 General Motors of Canada Ltd . . . . . . . . . . . . . . . 5 Hex-Hut Shelter Systems Ltd . . . . . . . . . . . . . . . 15 Joule Technical Sales Inc . . . . . . . . . . . . . . . . . . . 60 K & L Oilfield Holdings Ltd . . . . . . . . . . . . . . . . . . 26 Last Chance Trucking (1995) Ltd . . . . . . . . . . . . . 34 LJ Welding & Machine . . . . . . . . . . . . . . . . . . . . . . 7 Lockhart Oilfield Services Ltd . . . . . . . . . . . . . . 27 LoTech Manufacturing Inc . . . . . . . . . . . . . . . . . . 54 MCI Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 Millennium Directional Service Ltd . . . . . . . . . . 50 MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . 32 NAIT Corporate and International Training . . . . 40 Nexus Exhibits Ltd . . . . . . . . . . . . . . . . . . . . . . . 44 Norseman Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 Northstar Energy Services Inc . . . . . . . . . . . . . . . 4

OilPro Oilfield Production Equipment Ltd . . . . . 60 Oomph Events . . . . . . . . . . . . . . . . . . . . . . . . . . . 56 Pembina Controls Inc . . . . . . . . . . . . . . . . . . . . . 42 Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . . 35 Platinum Energy Services Corp . . outside back cover Platinum Grover Int. Inc . . . . . . . . inside front cover Propak Systems Ltd . . . . . . . . . . . . . . . . . . . . . . . 3 R & M Energy Systems . . . . . . . . . . . . . . . . . . . . 23 Silverado Oilfield Ventures Ltd . . . . . . . . . . . . . . 47 Strad Energy Services Ltd . . . . . . . . . . . . . . . . . 39 Summit Telecom Services . . . . . . . . . . . . . . . . . 44 Suncor Energy Inc . . . . . . . . . . . . . . . . . . . . . . . . 52 Systech Instrumentation Inc . . . . . . . . . . . . . . . 40 Tank Gauging Systems . . . . . . . . . . . . . . . . . . . . 60 TARM Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58 The Motor Company . . . . . . . . . . . . . . . . . . . . . . 33 Trans Peace Construction (1987) Ltd . . . . . . . . . 42 V.J. Pamensky Canada Inc . . . . . . . . . . . . . . . . . . 10

g n i t s! a r b r e l a e e C y 2010

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