Oil & Gas Inquirer June 2011

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Global conquest anywhere there’s petroleum, you’ll find canadian knowledGe and technoloGy at work

+

positive pressure

Good news cominG for alberta's pressure vessel manufacturers

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F E A T U R E S

8

JUNE 2011 • OIL & GAS INQUIRER

14

Global conquest

27

Positive pressure

By Darrell Stonehouse

Anywhere there’s petroleum, you’ll find Canadian knowledge and technology at work

By Graham Chandler

Eighteen months ago, Alberta’s pressure vessel manufacturers were hoping for some good news. It seems to have arrived.

Measurement Solutions You Can Count On • Portable Gas Test Measurement Utilizing Vortex Meters and Systech Smart Deadweight R E G I O N A L

33

N E W S

British Columbia

• Ease of Use for Field Operators

71

• LNG export terminal becoming

39

• Bakken waterflood pilot

more likely

success could drive further

By Richard Macedo

tight oil production

Northwestern Alberta • Trilogy reports Duvernay success

45

By Paul Wells

75

nation-building project, says Enbridge CEO

By Paul Wells

Central Alberta

By Elsie Ross

77

• Syngas plant inches forward

Southern Alberta

81

12

International • Five per cent of global gas

By James Mahony

E VE R Y

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production bump

• Contrarian Skope targets shallow gas

I N

East Coast • Newfoundland enjoys

By Lynda Harrison

63

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Saskatchewan

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supply wasted

I S S U E

Statistics at a Glance

85

Tools of the Trade • CJS Coiled Tubing's new hydraulic

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progressive cavity pump

On The Job • Enform’s Ray McKnight

86

Political Cartoon

Visit us at Booth 1732 Gas & Oil Expo in Calgary June 7-9, 2011

#1, 1815 - 27 th Avenue NE Cover illustration: Phillip Vernon

Calgary, AB T2E 7E1

1.888.SYSTECH Ph 403.291.3535 Fx 403.291.3585 www.systechinst.com OIL & GAS INQUIRER • JUNE 2011

9

Editor’s Note Vol. 23 No. 5 President & ceo Bill Whitelaw | bwhitelaw@junewarren-nickles.com Group Publisher Agnes Zalewski | azalewski@junewarren-nickles.com Associate Publisher Chaz Osburn | cosburn@junewarren-nickles.com Editorial director Stephen Marsters | smarsters@junewarren-nickles.com

Darrell Stonehouse | dstonehouse@junewarren-nickles.com

EDITORIAL

The other energy industry

Editor

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Most Canadians’ interaction with the energy industry is limited to paying at the pump and opening their monthly heating and power bills.

So it comes as little surprise energy policy and the idea of a national energy plan was a non-issue in the federal election. But it is also disappointing, because as the new century unfolds meeting global energy demand will be the fundamental driver determining whether the world continues progressing towards greater prosperity as it did in the previous century.

And Canada could play a key role in shaping that future.

Two key shifts in petroleum supplies are positioning the country for leadership going forward. The first is the global barrel of oil is getting heavier. Proof of this lies in the world’s gas tank in the Middle East, which has 970 billion barrels of heavy and extra heavy oil in place.

Saudi Arabia is beginning developing its heavy oil resource, with two fields with 20 billion barrels on production. Oman has a series of thermal recovery schemes ongoing as well.

The second major shift in global petroleum supplies is the tight gas revolution. The U.S. Energy Information Administration (EIA) says the advent of the new technologies for opening up tight rock and shale to commercial production has added 40 per cent to global gas supplies, bringing the total resource to over 22,000 trillion cubic feet.

What does this mean for Canada?

Pretty much all the energy debate in this country has been around developing our own resource and finding new markets for surplus production. This short-sighted view and narrow focus pays the bills for governments and pays dividends to shareholders. But Canada can do better.

The country needs to start looking at our resource base as an endowment that should be conserved. It’s great that there is a 100-year supply of natural gas at current production rates, but what happens after that?

Canada has a wealth of expertise and technology in producing companies and the service and supply community. Simply put, nobody is better than Canadians at getting heavy crude and bitumen out of the ground and turning it into useable products. The country was also an early entrant in the tight gas revolution, giving us a leg up on the competition.

This other energy industry, almost totally hidden from the public eye, could be the foundation of a national energy plan that meets the country’s needs for the long term, while providing needed revenues for government and shareholders as well as we export this knowhow around the world.

But the country isn’t even talking about it. And as time passes us by, others more nimble and focused are positioning themselves for the future.

We need to wake up.

Until next month.

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

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N E X T

I S S U E

Next Issue

If you know an admirable person to profile in On The Job—he or she may be a veteran

In our July/ August edition, Oil & Gas Inquirer

or apprentice, field or shop, wise or a little

travels central Alberta, looking at the revival in

crazy—please give Darrell Stonehouse

conventional oil production across the region,

a call at (403) 265-3700, or email

along with liquids-rich gas in the Deep Basin and

dstonehouse@june­warren-nickles.com.

heavy oil in the Lloydminster area. Also in this

In fact, feel free to sound off about any

issue we look at how central Alberta service

concern at all—that’s a personal invitation.

companies are benefiting from the boom OIL & GAS INQUIRER • JUNE 2011

11

Stats

FAST NUMBERS

78

AT A GLANCE

tcf

The amount of marketable conventional gas

available in the Horn River.

left in Alberta, according to the NEB.

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

May 2010 Jun 2010 Jul 2010

400 126 131

462 117 110

51 41 38

913 284 279

May 2010 Jun 2010 Jul 2010

490 295 193

511 153 9

39 40 16

19 16 4

1,059 504 222

Aug 2010 Sept 2010 Oct 2010

168 357 404

135 638 460

43 59 46

346 1,054 909

Aug 2010 Sept 2010 Oct 2010

452 617 678

156 790 581

40 45 39

15 23 18

663 1,475 1,316

Nov 2010 Dec 2010 Jan 2011

579 676 226

847 403 145

169 294 82

1,595 1,373 413

Nov 2010 Dec 2010 Jan 2011

868 1,061 409

989 559 201

75 78 33

165 238 17

2,097 1,936 660

Feb 2011 Mar 2011 Apr 2011

353 650 419

294 974 472

127 222 112

774 1,846 1,003

Feb 2011 Mar 2011 Apr 2011

723 1,069 618

378 1,081 509

38 64 46

99 164 81

1,238 2,378 1,254

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

May 2010 Jun 2010 Jul 2010

54 42 65

374 416 481

May 2010 Jun 2010 Jul 2010

86 149 220

7 7 7

3 11 0

96 167 227

Aug 2010 Sept 2010 Oct 2010

45 40 42

526 566 608

Aug 2010 Sept 2010 Oct 2010

198 197 201

12 5 12

7 6 11

217 208 224

Nov 2010 Dec 2010 Jan 2011

43 49 62

651 700 62

Nov 2010 Dec 2010 Jan 2011

217 340 136

3 2 4

64 11 3

284 353 143

Feb 2011 Mar 2011 Apr 2011

69 55 41

131 186 172

Feb 2011 Mar 2011 Apr 2011

321 316 183

6 8 11

7 4 11

334 328 205

*From year to date * from year to date

12

78

tcf

The amount of marketable gas the NEB says is

JUNE 2011 • OIL & GAS INQUIRER

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

GAS STOR AGE

Source: Natural Gas Exchange Inc.

Source: U.S. Energy Information Administration

4.00

2.0

$3.66/GJ Total vol.: 957 TJ Transactions: 119

3.65

3.30 Cdn$/GJ

in the United States

1.92 Tcf Year ago: 2.15 Tcf 5-year avg: 1.96 Tcf

1.8

Apr 20

Apr 27

May 4

May 11

1.6

May 18

Source: Natural Gas Exchange Inc.

Tcf

Apr 15

Apr 22

Apr 29

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada May 12, 2011 Source: Rig Locator

Alberta April 2011 Source: Daily Oil Bulletin

ACTIVE

DOWN

TOTAL

ACTIVE (Per cent of total)

Western Canada Alberta

76

495

571

13%

British Columbia

40

48

88

45%

0

11

11

0%

22

111

133

17%

138

665

803

17%

0

0

0

0

Manitoba Saskatchewan WC Totals Northwest Territories

May 6

OIL WELLS

Alberta

GAS WELLS

Mar 11

Mar 10

Mar 11

Mar 10

Northwestern Alberta

145

18

181

91

Northeastern Alberta

44

138

4

125

Central Alberta

201

22

94

77

Southern Alberta

29

20

193

124

TOTAL

419

198

472

417

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada May 12, 2011 Source: Rig Locator

Alberta April 2011 Source: Daily Oil Bulletin

ACTIVE

DOWN

TOTAL

Western Canada Alberta

ACTIVE (Per cent of total)

257

401

658

39%

British Columbia

4

20

24

17%

Manitoba

1

13

14

7%

Saskatchewan

83

106

189

44%

WC Totals

345

540

885

39%

0

1

1

0

Quebec

May 13

Source: U.S. Energy Information Administration

COALBED METHANE

Alberta

BITUMEN WELLS

Mar 11

Mar 10

Mar 11

Mar 10

Northwestern Alberta

10

2

13

0

Northeastern Alberta

0

0

44

127

Central Alberta

46

35

76

7

Southern Alberta

78

21

0

0

134

58

133

134

TOTAL

OIL & GAS INQUIRER • JUNE 2011

13

Feature

Global conquest Anywhere there’s petroleum, you’ll find Canadian knowledge and technology at work

By Darrell Stonehouse

C

anada is t he second-largest market for oilfield service and supply companies in the world, behind only the United States.

In 2010, around $42 billion was invested in an effort to maintain existing production and add new reserves from the country’s resource base. The Canadian Association of Petroleum Producers expects $44 billion to be invested this year.

That’s a big market.

But a Petroleum Services Association of Canada (PSAC) study, completed by Mission Capital Inc., shows the domestic service and supply industry has outgrown 14

JUNE 2011 • OIL & GAS INQUIRER

its geographical boundaries and is now on a global conquest. The Mission Capital study surveyed 36 Canadian service companies in 2009, and found those companies had $12.8 billion in export sales on top of their domestic operations.

In a presentation announcing the results of the Mission study, PSAC past chairman David Yager said Canadian service companies are one of the country’s great success stories when it comes to developing and exporting cutting-edge skills and technology.

“In oil and gas, Canadians have moved well beyond being hewers of wood and

Feature

Illustration: Phillip Vernon

drawers of water,” he explained. “Canada has world-class technology, equipment, procedures and personnel.”

As evidence of the quality of domestic service and supply skills, Yager pointed out that most of the sector’s growth has come in markets like the United States, where there is already a large and mature domestic industry. He said a number of factors have driven Canadian service company’s ability to work successfully in petroleum basins around the world. The country’s explorers and producers have encouraged technological development and creativity, and have

been willing to adapt it into their operations. Backstopping this has been a workforce with tremendous technical depth and a regulatory and economic environment encouraging the testing of new tools to exploit resources. And most importantly, the country’s unique geology, geography and extreme climate have forced innovation on the industry, and those products and ser vices coming out of that innovation are battlehardened and ready for anything the world can throw their way.

“If it will work in Canada, it will work anywhere,” Yager said.

Canadian service companies from all sectors of the industry are proving just how true this is in operations around the world.

Drilling services Ca nadia n d r i l l i ng cont rac tor s a nd related drilling and completions services are no strangers to U.S. and international markets.

Through a series of acquisitions in the 1990s up until 2005, Calgarybased Precision Drilling Corporation built a t r uly global presence w it h r igs work i ng i n pet roleu m ba si n s stretching throughout the Americas and OIL & GAS INQUIRER • JUNE 2011

15

Feature

overseas in the Middle East, North Africa and even Europe. It became the thirdlargest drilling contractor in the world. But that international presence ended in 2005 when it sold its global drilling and services operations to Weatherford International Ltd., pulling back to a Canadian operation with around 30 rigs in the United States.

Precision president and chief executive officer Kevin Neveu told analysts during the company’s first-quarter conference call in late April that unconventional resource plays are driving opportunities for growth in U.S. exports. The market focus over the past year has changed from dry shale gas plays to liquids-rich gas and oil, but

With the drilling rig setting the pace in extended-reach horizontal wells, efficiency is driving the demand for new rigs.

Three years later Precision was back in global growth mode, purchasing U.S.based Grey Wolf Exploration Inc. Today, the company has 203 rigs available in Canada and 151 based in the United States and Mexico. It is also looking at international opportunities to expand its fleet.

• • • • • • • • • • •

demand for high-end equipment capable of drilling the complicated wells needed to unlock tight reservoirs continues shaping the North American market.

“Across North America, approximately 70 per cent of Precision’s rigs working during the first quarter were drilling for oil or liquids-rich natural gas targets

and over 80 per cent were drilling complex horizontal or directional wells,” said Neveu. “In the United States over the past nine months, we have seen the strong oil and liquids-rich natural gas demand for Tier 1 and Tier 2 rigs continue to absorb rigs that have been released as our customers reduce activity in dry gas resource plays. Precision has redeployed approximately 25 rigs from dry gas plays, such as the Barnett and Haynesville shales, to oil- and liquids-rich plays such as the Eagle Ford and Permian Basin.”

The company believes that Canada, the United States and Mexico are all primed for future growth, and it is looking at building new rigs to meet demand.

“We continue to see new build economics in all three regions and are currently in the final stages of negotiating contracts with several customers for multiples of new-build 1,500-horsepower Super Triple rigs,” Neveu said. “If successful, all of these rigs will be deployed in the U.S. later this year.

“In June, we’ll be opening our new Houston technology centre,” he added.

“This facility brings Precision’s full

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16

JUNE 2011 • OIL & GAS INQUIRER

Feature

HIGH FLYERS

Change of scenery for Savanna Energy Services With shallow gas drilling in the doldrums in western Canada, Savanna Energy Services Corp. is expanding internationally, taking its Alberta-built shallow gas drilling expertise to Australia.

In late 2009, the company announced a five-year contract to provide its unique hybrid drilling rigs that can either drill with coiled tubing or using a top drive and drill pipe for developing coal gas fields in the Queensland area. Savanna is also providing workover rigs for the contract. The coal gas development will supply a large liquefied natural gas export terminal. The operators of the development are Australia Pacific LNG Pty Limited (APLNG), a partnership between ConocoPhillips and Origin Energy Limited.

APLNG project director Todd Creeger says the partnership chose Savanna because it could provide drilling and workover rigs to deliver the safest, most efficient and cost-effective wells.

“Importantly, these new rigs reduce the environmental impact on the land, as they require a much smaller footprint for each well,” he adds.

Savanna said the rigs are meant for permanent deployment in Australia, as the country is in the midst of a natural gas boom. The company said it believes its hybrid rig technology is ideally suited for coal gas development. The contract represents the first expansion of Savanna’s hybrid drilling operations beyond North America. Savanna will continue to extend

efforts in expanding its international presence moving forward.

“While domestic North American activity currently remains focused on deeper unconventional plays, there remain substantial international opportunities to deploy Savanna’s hybrid drilling technology in areas where deeper unconventional development is far less pervasive, and local natural gas and oil supply dynamics create a more stable activity and demand base for our equipment,” says Savanna president and chief executive officer Ken Mullen.

The two hybrid drilling rigs are in now in Australia, and the company expects both hybrid rigs to be drilling by the end of third quarter of this year.

OIL & GAS INQUIRER • JUNE 2011

17

Feature

rig maintenance, crew training and rig construction capabilities into play in the United States.”

Ensign Energy Services Inc. is also well advanced in its strategy to become a global drilling contractor. In 2010, Ensign earned more revenue outside of Canada than within its home borders. The United States, where Ensign has 82 drilling rigs and 23 service rigs, accounted for 37 per cent of the company’s revenues last year.

The company has an additional 21 drilling rigs in Mexico and South America, 15 drilling rigs in the Middle East and North Africa, and 16 rigs in Australasia.

International operations accounted for 23 per cent of revenues in 2010.

Ensign, like Precision, says to compete in international markets a company needs to have state-of-the-art equipment.

With the drilling rig setting the pace in extended-reach horizontal wells, efficiency is driving the demand for new rigs. Ensign says it sees well operators demanding rigs that can drill deeper, with longer horizontal legs and therefore more horsepower.

Automation is also important, as it cuts actual drilling times. Operators are paying more attention to non-productive time

between wells, making mobility important.

Ensign also says providing vertically integrated services ranging from directional drilling services to frac flowback units for production testing is also key in growing both at home and internationally.

Well stimulation and completions Canada’s well stimulation and completions specialists are also riding the unconventional resource wave to growth in the United States while at the same time building an international presence in conventional plays.

The use of multistage fracturing in resource plays across the United States has Calfrac Well Services Ltd. in expansion mode. It has equipment in the Lafayette shale play in Arkansas, the Marcellus in the northeastern states and in the Rocky Mountain states. It is now in the process of diversifying operations as the industry switches over to liquidsrich gas and oil plays to take advantage of high prices.

“In the United States, demand for pressure pumping services remains strong,” Calfrac said in its 2011 outlook.

In the Marcellus, Calfrac has two longterm contracts and recently deployed a Photo: Joey Podlubny

The new Enerflex will be a dominant force in the global compression market.

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JUNE 2011 • OIL & GAS INQUIRER

large, newly constructed fracturing spread to the play. It will be adding another spread and crew during the first half of 2011. By mid-2011, Calfrac anticipates that three large fracturing spreads, with a total of approximately 140,000 hydraulic horsepower, will be servicing the Marcellus.

The company has also commenced fracturing operations in the Bakken oil shale play of North Dakota with one large fracturing spread, and it expects to add at least one more fracturing spread during 2011. Calfrac expects high levels of activity to continue in the Fayetteville shale play, keeping its equipment there busy. Fracturing activity levels in the Rocky Mountain region of Colorado are expected to remain relatively high for the remainder of 2011, with the development of the Niobrara oil shale play in northern Colorado providing a significant growth opportunity in this market.

Outside the United States, Calfrac also continues growing. In Russia, it currently has five fracturing spreads and six coiled tubing units and plans to deploy a seventh coiled tubing unit by the end of the second quarter of 2011. Activity levels in Mexico during the early part of 2011 have improved, the company reported. Calfrac is cautiously optimistic that activity in the Chicontepec play will continue to recover as the year progresses.

The company commenced coiled tubing operations in Argentina during the fourth quarter of 2010. This new service line augments its existing cementing and acidizing operations, which are anticipated to be active throughout 2011.

Calfrac is also planning to enter the Colombian pressure pumping market with the commencement of cementing operations during 2011. As Colombian activity is predominately focused on oil, it provides further commodity and geographical diversification and provides another platform for future growth in Latin America.

Trican Well Service Ltd. was also in international expansion mode in 2010.

“U.S. operations gained from higher industry activity levels throughout 2010, as the rig count was up in all of our areas of operation. The growth of horizontal drilling led to steady demand for our services and provided opportunities for pricing increases throughout the year,” it reported in early March. “2010 was also a year of expansion for our U.S. operations, as we added new bases in Oklahoma and Pennsylvania.”

Feature High-tech drilling rigs are in demand Photo: Joey Podlubny

in unconventional oil and gas plays across North America.

OIL & GAS INQUIRER • JUNE 2011

19

Feature

In 2010, revenue in the United States increased by 193 per cent compared to 2009.

With 2011 stacking up to be just a good, the company is investing in new equipment for its North American operations.

“We have increased our 2011 capital budget by $120 million to $493 million.

The boom in resource play drilling in the United States has also presented opportunities for other Canadian drilling service companies. One example is drilling f luids provider Canadian Energy Ser v ices & Technolog y Cor p, (CES) which acquired two U.S.-based f luid

The new Enerflex will have revenues of well over $1 billion annually.

The increase consists of an additional $70 million for our U.S. operations and includes initiating coiled tubing services in the U.S., expanding our acidizing service line, and infrastructure costs for the establishment of new bases to support our Eagle Ford and other geographic expansion,” the company reported.

Internationally, Trican expects its Russian operations to gain incrementally in 2011. It is less certain of its operations in Algeria, where political issues have delayed fieldwork programs.

companies in 2010 to expand into the market. Company president and chief executive officer Tom Simons said the purchases were a great move.

“2010 has been a very successful year for CES,” said Simons. “In particular, our U.S. drilling fluids business saw the largest gains. Through two accretive acquisitions, we acquired roughly three per cent of the U.S. market share and have grown those platforms to roughly seven per cent of the U.S. market share in less than 15 months.”

Production and processing The purchase of Enerflex Ltd. by Toromont Industries Ltd. was the big news in the Canadian natural gas compression and processing sector in 2010. The combination of Enerflex and Toromont’s Energy Ser vices division is now being spun off into its own entity, creating what Toromont president and chief executive officer Robert Ogilvie calls, “a dominant force in the global compression market.”

The new Enerflex will have revenues of well over $1 billion annually, providing natural gas compression, oil and gas processing, refrigeration systems, and power generation equipment, plus in-house engineering and mechanical services around the world.

Enerflex is already flexing its global might, with the largest order in its history coming from Australian coal gas producer QGC. The $193-million contract involves multiple compressor units and process equipment and will run from mid-2011 to 2013.

Toromont vice-president of finance a nd c h ief f i na nc ia l of f icer Pau l Jewer says the QGC project “demonstrates Enerf lex’s leadership in t he Australian market.”

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JUNE 2011 • OIL & GAS INQUIRER

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Feature

HIGH FLYERS Frac fluid storage problem leads Open Range in new direction Canadian tight gas producer Open Range Energy Corp. has turned a frac f luid storage problem at its drill sites into an export opportunity with its creation of its Poseidon Concepts insulated tank system.

The insulated and modular tank features greatly increased storage capacity to accommodate larger fracturing oper-ations, improved portabilit y, a more efficient fluid-heating process and reduced environmental footprint, all of which deliver cost savings versus the traditional approach of using multiple smaller standing tanks or lined pits, says the company.

The Poseidon Concepts system was conceived, designed, tested and rolled out

by Open Range personnel as part of the

company’s continuous efforts to reduce the costs of exploration, development and operations at its core Ansell/Sundance Deep Basin property.

Following successful application of the experimental system on several of its Deep Basin gas wells in early 2010, Open Range formed the Poseidon Concepts business unit to market the system to other producers. Since then, it has taken off.

Open Range reported in March the Poseidon tank fleet has been expanded to 80 rental units. Fleet expansion is ongoing to meet increasing demand, which now includes minimum year-long commitments from 11 major U.S. and Canadian oil and natural gas companies.

The company began its U.S. expedition

in the North Dakota Bakken play, and is now expanding outward.

“Poseidon continues to expand its footprint in the United States, with approximately one-third of the current f leet operating in the U.S. as of early April,” said the company in a news release. “Poseidon has established a presence in four states and expects to deploy multiple units in several other key operating regions over the near term. Expansion is achieving customer and geographical diversification, weighted to the expanding oil- and liquidsrich natural gas shale plays in North America. U.S. expansion is already helping to offset the normal seasonal impact of slower industry activity during spring breakup in western Canada.”

OIL & GAS INQUIRER • JUNE 2011

21

Photo: Joey Podlubny

Feature

High-pressure pumping for fracturing is a growth industry around the world.

He adds that the project is only one of a number of major international projects the company has on the go.

It’s not only large Calgary-based production- and processing-oriented companies that are taking advantage of export opportunities. Montreal-based ProSep Inc. is also riding the natural gas wave growing outside of North America. In February, ProSep announced it had received a $5.5-million contract to provide a gas dehydration system to a global oil and gas producer operating in the South China Sea. This system will be installed on an offshore field being redeveloped using enhanced oil recovery technology to extend its production life. Delivery is scheduled for the first quarter of 2012.

“This contract with a new client represents our largest system sold to date in Southeast Asia. We continue to see strong demand from the region where many natural gas fields are being developed,” said Jacques L. Drouin, ProSep’s president and chief executive officer.

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Feature

easy to operate and are environmentally friendly, making them ideal for offshore installations, says the company.

The announcement of the sale to China was followed by another $4.1-million contract to provide a gas membrane system to a facility in Texas. Delivery is scheduled for the first half of 2012. “ For t he la st t wo yea r s, we ’ ve invested in developing our offering and improving our operations worldwide, said Drouin. “We are now ver y well positioned to benefit from the recovery, higher commodity prices and increasing production challenges.”

Wavefront Technology Solutions Inc. is also seeing global uptake of its enhanced oil recovery product Powerwave. The Powerwave product optimizes fluid injection flows in enhanced oil recovery projects, leading to better production and ultimate recovery.

Early on in its product development, Wavefront provided financial incentives to get producers to test Powerwave. As it has proven itself in the Canadian and U.S. markets, company president and chief executive officer Brett Davidson said those incentives are becoming less necessary.

“Powerwave’s track record of positive results is becoming well known throughout the industry, and we are pleased to see the reduced need for incentives and inducements to entice prospective clients to deploy Powerwave,” said Davidson in announcing the product’s success in a Michigan-area CO2 flood for Core Energy, LLC. “Wavefront will continue to leverage strong Powerwave results generated in multiple locations to advance market penetration with producers who have a focus on maximizing reserves and asset value.”

At the Michigan CO2 flood, Powerwave increased production by 120.6 per cent.

In March, Wavefront announced Powerwave was going international, with a contract for six systems to be installed with Oman’s National Oil Company (NOC).

Installations for this commercial project are slated to commence by July of this year. The NOC is the foremost exploration and production company in the sultanate and accounts for more than 70 per cent of Oman’s crude oil production and nearly all of its nat-ural gas supply. The NOC is 60 per cent owned by the Government of Oman, with the remaining 40 per cent owned by major international oil producers.

HIGH FLYERS

Strata Energy Services strikes Saudi deal Calgary-based underbalanced and managed pressure drilling specialists Strata Energy Services Inc. is moving into the biggest sandbox of them all in Saudi A rabia, the company announced in late April.

Strata signed a joint-venture agreement with the Shoaibi Group to provide integrated performance drilling services in the Kingdom of Saudi Arabia (KSA), and its territorial waters.

The joint-venture company, Strata Energy Services Saudi Arabia Limited (SESSAL), will be headquartered in Al Khobar, Saudi Arabia, and plans to offer fully integrated oilfield services and with a

service giants who enjoy a large market share though out the region, says Paul Cockerill, Shoaibi Group oil and gas services director “SESSA L perfect ly complements existing technologies within the group, which in turn facilitates a long-term strategy of offering integrated services to our customers and allows Shoaibi Group and our partners to compete with conventional service companies,” he says.

Fa i sa l A l Shoa ibi, di rec tor of Shoaibi Group, says the focus of the partnership is on improving recovery from the Kingdom’s

The Saudi Arabian deal is the latest in a series of international deals for Strata, including recent contracts in Indonesia and Kurdistan. special focus on underbalanced drilling and managed pressure drilling. The joint venture will also offer the complete line of patented rotating flow diverters for all drilling applications, surface recovery and separation, light snubbing services, well design and project management, as well as any additional equipment required to perform the same.

The Saudi Arabian deal is the latest in a series of international deals for Strata, including recent contracts in Indonesia and Kurdistan. Strata president and chief executive officer Ken Travis said the partnership with the Shoaibi Group is instrumental in giving his company a foothold in Saudi market.

“In addition to strong market knowledge and relationships, the Shoaibi Group brings a strong portfolio of companies with synergistic value that will help ensure success for all,” he notes.

For Shoaibi, bringing Strata into the fold allows it to compete with global

oilfields. From there, it could expand operations across the Middle East.

“With Strata Energy’s reservoir optimization technologies and skills combined with Shoaibi Group’s regional market expertise, I am confident that SESSAL will capture the fast-growing demand for enhanced oil recovery technologies in KSA, and expand its business in due time across to Bahrain and Algeria,” he comments.

If the price of oil continues to rise, Shoaibi said enhanced oil recovery projects could compete with conventional developments in the region because of their low risk. He notes that with normal decline in producing fields, about 64 million barrels per day will be needed to meet forecast demand by 2030. The company expects that five million barrels per day will be obtained from additional enhanced oil recovery production.

OIL & GAS INQUIRER • JUNE 2011

23

Feature

Canadian companies are also exporting products that solve environmental issues caused by oil and gas exploration and development.

“One of Powerwave’s many strengths is its ability to transform marginal producing fields into highly profitable reservoirs while also adding more booked reserves,” said Davidson in announcing the deal. “The world continues to have an insatiable appetite for oil, and we are very pleased to add this NOC as more and more international oil producers turn to Powerwave to help increase their production and feed that appetite.”

Environmental services Canadian companies are also exporting products that solve environmental issues caused by oil and gas exploration and development. With concerns that fracking water use and pollution in U.S. resource plays could create a $100-billion industry over the next 40 years according to analysts, Calgary-based AquaPure Ventures Inc. is building a strong presence in the United States through its subsidiar y Fountain Quail Water Management, LLC. Aqua-Pure first came on the U.S. market in the Barnett shale play in Texas, recycling flowback water from frac jobs for Devon Energy Corporation beginning

in 2004. So far, the company has recycled more than 500 million gallons of Devon Energy’s waste water, which would otherwise have been injected into disposal wells and permanently removed from the hydrological cycle.

With low gas prices slowing development in the Barnett, Aqua-Pure is now focused on more active exploration basins.

In late 2010, the company got a boost in the Marcellus when new state regulations in Pennsylvania mandated strict water-quality standards for fracking operations. The new regulations enabled Aqua-Pure, which already had t wo of its NOM A D evaporator units working in the area recycling around 200,000 gallons of water a day, to add a new unit. In the Marcellus Aqua-Pure is working in partnership with U.S.-based Eureka Resources Inc. Eureka’s facility now serves several operators, including Range Resources Corporation, XTO Energ y Inc. and Chesapeake Energ y Corporation.

“Our a l l ia nce w it h Eurek a has gone exceedingly well, and we’ve still just scratched the surface in terms

of meeting the growing needs of the companies operating in this area,” said Brent Halldorson, chief operating officer of Fountain Quail Water Management, LLC. Aqua-Pure is recovering an average of 75-80 per cent of pure distilled water from the Marcellus shale waste water it receives, with total dissolved solids measuring well below 150 parts per million, and only trace chlorides. It is the only company currently operating in Pennsylvania that is exceeding the government mandate.

“Just as important as meeting the regulations, we’re providing the most cost-effective solution for operators in Pennsylvania,” said Halldorson. “As a result, we’re adding capacity as quickly as we can.”

Aqua-Pure expects its next expansion in the United States will come in the Fayetteville shale in Arkansas. The company is also building new units in anticipation of continued demand in shale plays across North America.

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Feature

Positive

pressure Eighteen months ago, Alberta’s pressure vessel manufacturers were hoping for some positive news. It seems to have arrived.

By Graham Chandler

I

n an April 2008 benchmarking study commissioned by the Alberta Pressure Vessel Manufacturers’ Association (APVMA) and Alberta Finance and Enterprise, PriceWaterhouseCoopers LLP predicted substantial growth opportunities for APVMA members. Oilsands projects had been booming for three years and the market looked rosy. Then the recession hit, oilsands expansion was put on hold, and the fabricators were instead squeezed.

OIL & GAS INQUIRER • JUNE 2011

27

Feature

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Our largest product is the value that we pass on to our customers.

The oilsands have long been the principal market for the province’s pressure vessel manufacturers and in 2007 and 2008 were swamped with several multibillion dollar projects. When Imperial Oil Limited approved its massive $8-billion Kearl oilsands project a few years ago, Alberta pressure vessel manufacturers were so busy that the company had to source a few hundred of the larger components from a South Korean supplier.

Several of those have been shipped ac ross t he Paci f ic Ocea n, t h rough Vancouver, Washington’s port and up the Columbia and Snake rivers. They are now held up at Lewiston, Idaho, awaiting the outcome of court challenges in Idaho and Montana before being allowed to make the rest of the journey by truck to northeastern Alberta.

Imperial says it shouldn’t jeopardize the project start date but it’s an indication of the effects of ups and downs experienced by Alberta’s pressure vessel manufacturers.

“I have a lot of sympathy for Imperial,” says Bob Saari, manager of the APVMA. “I think that the problem occurred because

Loading a massive pressure vessel for transport during the last boom in 2006-07.

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Feature

there wasn’t enough capacity in Alberta at the time, so they were forced to source externally. But they have real problems now with those big modules sitting in Montana, and some now beginning to be cut up so they can get up here.”

Saari reckons Alberta would have the capacity to build them in today’s business environment. “They were big modules—heat exchangers, pressure vessels,” he says. “And actually some of the components that are on those modules were actually made in Alberta and shipped to Korea. They’re now being shipped back as part of the module.”

Saari says their members still face foreign competition, partly due to the changing ownership in some of the oilsands operators. “ You’ve now got Har vest Energ y [Trust], for example,” he says. “They a re headqua r tered i n Ca lga r y a nd bought out by the Korean National Oil Company. They are looking at a big expansion with up to 63 large modules that they want to bring in from South Korea, so they have been talking to the Idaho government about the possibility

of using the same route that Imperial is using for the Kearl modules.”

But overall, Saari says the threat from Far East competition has softened somewhat. W hereas 18 months ago, Alberta manufacturers were being outbid for pressure vessels and exchangers by 20-30 per cent, today members are much more positive they can be competitive.

There are still the old considerations like the costs associated with adhering to Alberta’s strong health and safety standards that layer additional costs on Alberta products making it difficult often to compete in the international marketplace. And more stringent manufacturing standards and codes compared with some competing jurisdictions cited by the PriceWaterhouseCoopers report, but other concerns such as labour are taking over. With activity on the upswing, “they see other problems starting to creep in: more overtime, looking for more people, etc.,” says Saari.

Tariffs have been a concern, too, says Saari.

“The steel for pressure vessels is a chemistry that’s not available in Canada,

“

so much of it comes from Europe,” he explains. But the Canadian steel industry has still tried to lobby for tariffs. “Three times the Canadian [International] Trade Tribunal has heard cases against Canadian steel mills who wanted to slap a 70 per cent tariff on this steel coming in from Europe even though they can’t make it themselves. We spent $125,000 in legal costs defending the right for Canadian pressure vessel manufacturers to bring in steels that aren’t made here anyway. It’s a real drain on our guys.”

However, nuisances like those are dwarfed by the upbeat oilsands’ 2011 outlook. Unlike their precipitous drop in the recession of 2008, oil prices should remain strong, predicted Martin King, vice-president of institutional research with FirstEnergy Capital Corp. in an early May outlook presentation in Calgary.

A nd according to the prov ince’s Alberta Energy outlook for 2011, three new upgraders are under construction with three others approved or under application. Big-ticket customers for APVMA members, the top four producers are back to sizeable capital expenditures

With the majority Conservative government and Alberta’s good royalty structure things will start streaming in Alberta and then fabricators will pick up.”

— Samy Ibrahim, President, Pressure Vessels Consulting Ltd.

OIL & GAS INQUIRER • JUNE 2011

29

Feature

“

for 2011. Alberta Energy sums up the big spenders’ 2011 programs: Canadian Natural Resources Limited has budgeted up to $2.5 billion in oilsands capital spending; Suncor Energy Inc. has an oilsands capital budget of $4.18 billion, up from 2010’s $3.21 billion; Suncor is also moving forward on its Fort Hills mine, has begun front-end work on MacKay R iver 2 and is expanding Firebag’s in situ facilities; Cenovus Energy Inc. is to spend up to $1 billion…$350 million

to $400 million at each of its Foster Creek and Christina Lake steam assisted gravity drainage projects—and finally Canadian Oilsands Trust, which has the largest interest in Syncrude Canada Ltd., will spend $907 million, up from $511 million. Moreover, Nexen Inc., BP p.l.c., Total E&P Canada and MEG Energy Corp. have also announced large new expenditures in the oilsands.

“Much more positive than a year ago,” says Saari.

A lot of activity, a lot of new projects, others resurrected or coming on stream, so there’s a fair amount of engineering work going on that still has to be done….”

— Bob Saari, Manager, Alberta Pressure Vessel Manufacturers’ Association

Photo: Joey Podlubny

Wages and salaries account for 33 per cent of pressure vessel costs in Alberta

30

JUNE 2011 • OIL & GAS INQUIRER

Another harbinger is the ramping up in demand for large pressure vessel engineering design. “One of my clients has started to turn down requests for quotation,” says Samy Ibrahim, president of Calgary engineering firm Pressure Vessels Consulting Ltd., which specializes in the design of very large pressure vessels.

“This year is much better than last year,” says Ibrahim, who says he was the design engineer for one of Imperial Oil Limited’s large upgrader units, a 500tonne monster for the Kearl project. He sees the recent federal election results as a positive for the industry. “With the majority Conservative government and Alberta’s good royalty structure things will start streaming in Alberta and then fabricators will pick up,” he predicts.

It will be a boost for the optimism that was already rising. “For example we have seen North West Upgrading Inc. refinery northeast of Edmonton, and they are using lots of pressure vessels,” says Ibrahim. But, he adds, foreign fabricators are still in the picture. “So, that competition will still be faced by Alberta pressure vessel fabricators. The Far East uses the same ASME [American Society of Mechanical Engineers, which sets boiler and pressure vessel standards] codes, etc., as does Italy, who specializes in high-temperature, high-pressure steels over five inches thick.”

In a reverse twist, some APVMA member companies are enjoying export success.

“We have a couple of companies selling equipment into Russia and one into Iraq,” says Saari. “Those companies that were exporting didn’t feel the downturn that much. One company that was really feeling the pinch in Alberta started exporting and is now doing quite well at it.”

At the same time, others branched out into pressure vessels needed in the booming fracking industry. “It’s shaping up quite well—a lot of the guys are saying now that most of their work is coming out of northeastern B.C. with the shales.”

Considering the typically long lead times between planning, design and fabrication of large oilsands modules, Saari reckons the industry isn’t yet going full out—but it’s coming.

“A lot of activity, a lot of new projects, others resurrected or coming on stream, so there’s a fair amount of engineering work going on that still has to be done until the shops get fully loaded again. But the hours are starting to create more work and are hiring more people.”

“But full out is a hard one to describe because full out would mean likely two and a half full shifts,” he says. “We are seeing a full shift now and companies that were seeing a three- or four-day work week are now back up to the five, so there are good signs.”

When full out happens, labour may again be a crunch. “The foreign workers that were here [during the last boom] would have been the first to be let go, and my understanding is a lot of them went back home,” says Saari. With wages and salaries averaging 33 per cent of costs and the Alberta pressure vessel industry having the highest labour costs of the eight largest in the world, according to the 2008 PriceWaterhouseCoopers report, fabricators could ill afford to retain them during slow times. So Saari figures a shortfall of workers is looming and foreign labour may well again need to be tapped.

“I think it will happen,” he says. “During the last big spurt in the economy, we were also able to depend on workers out of Saskatchewan, Manitoba, Ontario, Quebec and Newfoundland. But the economies in those provinces have picked up quite a bit, so I don’t think you are going to be able to get those workers back out here this time around.”

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LNG export terminal becoming more likely

Photo: Joey Podlubny

By Richard Macedo

LNG tankers could be moving up and down the west coast by mid-decade, according to analysts.

With two liquefied natural gas (LNG) export licence applications before the National Energy Board (NEB) and plans for another facility coming forward, optimism is growing that Canadian LNG will be sent across Pacific waters by the middle of the decade.

Exports of LNG to the lucrative Asian market will help underpin development of Horn River Basin shale gas that is disadvantaged by its distance to key markets in North America and could get squeezed out by American supplies that are being developed closer to demand centres south of the border.

The most likely first project at this point is t he 700 -million-cubic-feetper-day Kitimat LNG effort proposed by key Horn River operators Apache Corporation, EOG Resources Inc. and Encana Corporation, which recently joined the project.

The approximate cost for phase one is $3 billion. An export licence application was filed with the NEB late last year. It did not include information on gas sales agreements, and proponents have said that establishing an oil-indexed price

and in emerging markets like China.

Demand may increase as a result of the nuclear problems being experienced in Japan following the recent earthquake and tsunami.

Shell Canada Limited, meanwhile, is considering an LNG export plant at Prince Rupert, its Canadian country chair recently said. The NEB has also received a second application seeking approval to export LNG from a point near Kitimat via a smaller-scale facility.

Edward Kallio, director of gas consulting with Ziff Energy Group, said that with the price differential between Asia and North America, it’s no surprise there’s been heavy interest in exports from the B.C. coast.

“When you look at the folks who have land in the Horn River primarily, you can’t make that play work sub-$4 because your full-cycle costs are higher than that. To me, it dares examining finding an alternate outlet for that gas into Asia,” he said.

“But you need that premium.”

According to a report by Scotiabank Group, current LNG prices in Japan are more than US$12, which should yield a netback at Kitimat of about $7 per million British thermal units after deducting

“The challenge for the LNG project at Kitimat will be can they put in all these facilities and have a guaranteed 20-year contract when you don’t have a market signed up for it.”

— Rick DeWolf, Oil and Gas Consultant, R DeWolf Consulting

will be important for the project’s economic viability.

Asia Pacific will be Kitimat’s main market. Demand for LNG in Asia is growing robustly, both in the traditional markets of Japan, South Korea and Taiwan

pipeline tolls, liquefaction and terminal fees, and ocean transportation costs compared with less than around $4 in North American markets.

Scot iaba n k ’s repor t a l so st ated that Shell’s proposed Prince Rupert

APR/10

APR/11

APR/10

APR/11

WELLS SPUDDED

42

39

WELLS DRILLED

46

40

BRITISH COLUMBIA WELL ACTIVITY

APR/10

APR/11

WELL LICENCES

44

78

▲

▼

▼

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • JUNE 2011

33

British Columbia

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plant involves Mitsubishi Corporation, Korea Gas Corporation and PetroChina Company Limited.

Speaking about the Kitimat LNG plant, consultant Rick DeWolf said that it may be problematic getting a long-term export licence from the NEB without a market commitment from buyers.

“When you start looking at long-term contracts or long-term licensing…the NEB tends to want to see some market, some assured supply market contracts,” he said.

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“The challenge for the LNG project at Kitimat will be can they put in all these facilities and have a guaranteed 20-year contract when you don’t have a market signed up for it.”

One expor t facilit y on t he West Coast will likely be more than adequate, DeWolf added.

“If there is one LNG [plant] operational by 2015, and given the decline rates and replacement rates, I do not think there will be adequate gas supplies to support another project for at least a decade,” he said. “It’s like anything, people want to look at this and see if I have a better project than you. Whoever’s first out there and getting permits and gas supply, I think, really always have a substantial head start.”

British Columbia

Quicksilver creating Horn River midstream operation Quicksilver Resources Inc. is creating a separate midstream operation to support the company’s 130,000 net acre shale gas operations in the Horn River Basin.

The midstream operation is targeted to link Quicksilver’s Horn River operations with western U.S. markets through the Spectra Energy Corp. processing and pipeline system and to greater North American

day through a third-party line into the Spectra system. Upon tie-in of the line, the company expects production will be unrestricted.

In Apr il, Quick silver announced an agreement with TransCanada subsidiar y NOVA Gas Transmission Ltd. to start work on a 70-mile Horn River extension and For tune Creek meter​

Toby Darden in announcing its midstream strategy.

Quicksilver has started planning for construction of the initial phase of its Fortune Creek treatment facility to remove CO2 from the natural gas stream.

In its initial phase, the facility will have capacity to deliver 125 million cubic feet per day of natural gas to TransCanada

“These steps will create a midstream business that we believe will be the low-cost solution for gathering, treating and transporting natural gas from the Horn River Basin to multiple markets to achieve the highest possible netbacks.”

— Toby Darden, Chairman, Quicksilver Resources Inc.

ma rket s t h rough t he Tra nsCa nada Corporation system via Alberta.

The first piece of this strategy, the construction of a 20-mile, 20-inch gathering line, is now tied into the Spectra Energy system. The line will initially serve as the spine of Quicksilver’s transportation from its Horn R iver Basin acreage, where the company has completed four gas wells and is at various stages of drilling and completing four additional wells.

The initial four wells can produce more than 30 million cubic feet per day of natural gas but are restricted to approximately 20 million cubic feet per

station to be located within Quicksilver’s acreage. The Horn River extension is expected to be a 36-inch sales gas line connecting TransCanada’s For t u ne C r e e k m e te r s t at ion a nd Quicksilver’s proposed treatment facilit y to TransCanada’s A lberta system from the Cabin area of British Columbia.

Completion of the Horn River extension is expected in mid-2014.

“We have the pieces in place to ensure that our vast resource capture will move out of the Horn River Basin to the west through the Spectra system and to the south through the trans Canadian pipeline system,” said company chairman

and is expected to be operational by mid-2014. The facility is designed to be expandable in 125 million cubic feet per day sales increments to meet the company’s growing production profile for the basin.

“These steps will create a midstream business that we believe will be the low-cost solution for gathering, treating and transporting natural gas from the Horn River Basin to multiple markets to achieve the highest possible netbacks,” Darden said. “This entity will ultimately have its own capital structure and be separately financed.”

— DAILY OIL BULLETIN

Artek reports success at Inga Artek Exploration Ltd. says it has successfully drilled and completed its second horizontal Doig well (60 per cent working interest) in the Inga/Fireweed area of British Columbia.

The well, drilled to 3,100 metres including a 1,200-metre horizontal leg, was completed with a 12-stage fracture stimulation program using GasFrac Energy Services Inc.’s propane frac technology. The final rate was restricted at five million cubic feet per day with approximately 1,400 barrels per day of condensate for a total rate of approximately 2,040 barrels of oil equivalent per day. Further testing inline was planned for the well in early spring.

In the immediate area, Artek holds interests in 16,780 gross (10,094 net) acres or approximately 25 gross (15 net) sections, almost all of which it operates,

horizontal Doig locations on company or farm-in lands. The production volumes are processed at Artek’s operated facility at Inga. The company plans to drill an

At Noel, B.C., Artek has completed an additional uphole zone in its deep Nikanassin exploration well drilled in early 2010 at a rate of approximately 1.2 million cubic feet per day. and has an additional three sections under option through a farm-in commitment.

Based on mapping, management estimates it has another 37 gross (20 net)

additional three horizontal Doig wells at Inga through the remainder of 2011.

In the Sinclair area, the company has decided to delay the completion of its OIL & GAS INQUIRER • JUNE 2011

35

British Columbia

second Montney horizontal well (50 per cent working interest), offsetting its eightmillion-cubic-feet-per-day discovery well drilled in 2010.

The well was drilled to a total measured depth of 4,400 metres and is currently awaiting a 14-stage fracture stimulation.

Due to potential cost overruns as a result of breakup, the completion was postponed until after breakup in late May or early June.

At Noel, B.C., Artek has completed and brought on stream an additional uphole

zone in its deep Nikanassin exploration well drilled in early 2010 at a rate of approximately 1.2 million cubic feet per day. Artek has a 75 per cent working interest in the zone.

Late in the first quarter, Artek spudded a shallow horizontal well (100 per cent working interest) in the Peace River Arch area of Alberta that is targeting light oil and natural gas in the Triassic.

T he well reached a total measured depth of approximately 2,530 metres

with an approximately 1,125-metre lateral. The company said it has several follow-up prospects with the potential for oil in the Triassic that it believes can be accessed through horizontal drilling. In all, Artek has approximately 71 net sections of land in the greater north Peace River Arch area that has seen in excess of $90 million invested by industry at Crown land sales since the beginning of the year.

— DAILY OIL BULLETIN

Sasol/Talisman GTL project driven by oil/gas price differential With oil trading at around 25 times the value of natural gas and Canadian gas searching for market alternatives, the case for a gasto-liquids (GTL) project looks compelling, according to an industry analyst.

South African–based Sasol Limited and Talisman Energy Inc. are studying the feasibility of a commercial GTL facility in western Canada. Talisman would have the option of a 50 per cent stake in the facility.

The companies updated aspects of the planned GTL project during Sasol’s investor day in April, and Ticonderoga Securities LLC analyst John Malone stated in a research note that while the case for the project is compelling, it has the potential to be very costly and is still years away.

Fifty per cent of both Farrell Creek and Cypress A assets in British Columbia can supply a 48,000-barrel-per-day GTL plant, while 100 per cent of both Farrell Creek and Cypress A can supply two plants totalling 96,000 barrels per day, according to Sasol’s presentation.

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one barrel of liquids, so before considering capital spending, a GTL producer needs liquids prices to be at least 10 times that of gas to break even. (The ultra-clean product that GTL plants produce generally sells at a premium to crude.)

In a world with growing demand for clean transport fuels, a price of over $100 per barrel for oil and natural gas under $5

In a world with growing demand for clean transport fuels, a price of over $100 per barrel for oil and natural gas under $5 per thousand cubic feet, GTL “makes eminent sense.”

— Ticonderoga Securities research note

selection of a site is part of the scope of the feasibility study, a company spokesperson later said.

Ticonderoga, meanwhile, noted that what matters most with GTL is the ratio between oil and gas prices, adding that it’s a rule of thumb in GTL that it takes roughly 10,000 cubic feet of gas to produce

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and technical with Sasol, told an investor session in New York. “Canada is short in terms of diesel, naphtha and LPG. We can sell all our products in Canada. This is a unique opportunity for us.”

The naphtha can be used as a diluent for the oilsands.

The site of the GTL facility could either be in Alberta or British Columbia, and

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per thousand cubic feet, GTL “makes eminent sense,” but to justify the high capital expenditure, that disconnect between oil and gas has to be sustained for decades, the Ticonderoga research note stated, adding that “we await more detail on costs and timing.”

— DAILY OIL BULLETIN

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Trilogy reports Duvernay success

The Duvernay play in northwestern Alberta is proving to be liquids-rich, making drilling it profitable.

Trilogy Energy Corp. has reported successful results for its second horizontal well targeting the Duvernay shale in the Kaybob area of northwestern Alberta.

The 3-13 well has been tied in since April 10 in order to reduce flared emissions during the completion and evaluation period. The well was f lowing up seven-inch casing at approx imately 1,250 barrels of oil equivalent per day, consisting of 5.2 million cubic feet per day of sweet natural gas and an estimated 390 barrels per day of natural gas liquids, including 180 barrels per day of 56-degree API condensate and 1,450 barrels per day of water.

C u r r e nt p r o du c t i on r at e s m a y improve when production tubing is run into the well and additional water used to complete the well has been recovered. To date, only 36,300 barrels

(26 per cent) of the completion water has been recovered. The sweet natural gas from the 3-13 well is liquids-rich and is expected to yield total liquids of approximately 75 barrels per million cubic feet of raw gas including free condensate (35 barrels per million cubic feet).

Trilogy managed the drilling and completion operations for the horizontal well under a previously announced joint venture with Celtic Exploration Ltd. and Yoho Resources Inc., pursuant to which each partner has a one-third working interest in 30 gross sections of land.

The 3-13 well was drilled from a surface location at 16-14-60-20W5 to a bottomhole location at 03-13-060-20W5, with a total depth of 4,866 metres. The horizontal lateral was 1,391 metres in length within the Duvernay shale formation. The well was drilled and cased over

50 days at a cost of approximately $6.5 million for the drilling operation.

Completion operations began on March 8 and were concluded in late April. The well was fracture stimulated in 31 perforated intervals in 12 separate stages along the length of the horizontal wellbore. In total, approximately 2,300 tonnes of sand and 138,600 barrels of slick water were used to stimulate the well. The well was completed using a staged “plug-and-perf” horizontal completion technique, incorporating perforation clusters (t wo and three per stage) to stimulate the well. Following the fracture stimulation, the plugs were drilled out to permit the well to be evaluated without obstruction in the horizontal portion of the well.

Production tubing and recorders will be run into the well following completion of the plug removal and logging operations.

Completion costs for the well have totalled approximately $11 million; however, Trilogy expects to see substantial cost savings on subsequent wells targeting this formation, as the 3-13 well was the first to use the “plug-and-perf” completion methodology in the Duvernay.

Once complet ion operat ions a re finalized, production tubing is run into the well and further production data is obtained, Trilogy will review additional drilling locations with its partners. The company said it expects to participate in one more well targeting the Duvernay shale for mation during t he balance of 2011.

It currently ow ns approximately 168,409 gross acres and 138,173 net acres (263 gross sections and 216 net sections) of land with Duvernay rights at Kaybob and surrounding areas.

— DAILY OIL BULLETIN

NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY

APR/10

APR/11

WELL LICENCES

69

90

▲

APR/10

APR/11

WELLS SPUDDED

36

44

▲

APR/10

APR/11

WELLS DRILLED

68

105

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • JUNE 2011

39

Northwestern Alberta/Foothills

Interest in NW Alberta and Exshaw/ Bakken fuels April 6 land sale

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JUNE 2011 • OIL & GAS INQUIRER

Alberta recently kicked off its first land sale of fiscal 2011-12 with a $115.8million land sale, fuelled once again by licences south of Grande Prairie and also several parcels near Lethbridge, which appears to be a continued chase for Exshaw/Alberta Bakken oil.

The sale featured 233,431 hectares exchanging hands at an average price of $496.13 per hectare. After six sales so far this calendar year, $776.6 million has filled the provincial treasury on 1.4 million hectares at an average price of $573.14. To the same point last year, the province had collected $567.1 million in bonus bids for just over a million hectares at an average price of $559.26 per hectare.

Highlights included a sale high bonus bid of $17.9 million by Scott Land & Lease Ltd. for three tracts and several parcels at 61-24W5 and 60-24W5. The broker paid an average of $8,735 per hectare for the 2,048-hectare parcel, also a land sale high. An adjacent nine parcels from 60-26W5 to 60-27W5 combined for total bonus bids of $12.5 million.

Another five parcels around 61-25W5 and 62-23W5 combined for total bids of $8.7 million. Daily Oil Bulletin records show that Copper Creek Petroleum Inc. licensed a horizontal development oil well on March 4 in the Waskahigan area at surface location 01-32-062-24W5 with the Dunvegan formation listed as the total depth zone to a projected depth of 2,400 metres.

Meanwhile, 16 lease parcels in the area around 06-26W4 and 09-24W4 west of Lethbridge combined for total bonus bids of $14.9 million.

Bidding under its own name, Argosy Energy Inc. picked up two leases in the area, each totalling 256 hectares. The company picked up section 16 at 09-24W4 for $1.6 million, which worked out to $6,377 per hactare. Argosy also acquired the rights to section 18, paying a bonus of $1.4 million at an average of $5,377.

Daily Oil Bulletin records show that on March 29, a well was spudded in the Pearce area at surface location 02-20-0924W4. The new pool wildcat horizontal oil

Northwestern Alberta/Foothills

well was licensed under broker Canadian Coastal Resources Ltd. with the Big Valley formation listed as the total depth zone to a planned depth of 3,793 metres.

To t he nor t h , Ne xe n I nc . on March 31 licensed a new pool wildcat in the Claresholm area at surface location 12-1212-25W4 with the Wabamun group listed as the total depth zone with the projected depth set at 3,520 metres. The planned horizontal lists oil as the objective.

The company spudded a horizontal new field wildcat in the Keho area on March 18 at surface location 01-06-1124W4 with a projected depth of 4,100 metres and the Wabamun listed as the total depth zone and oil as the objective.

A total of 59 wells, 32 in Alberta and 27 in Montana, have either been drilled or licensed where the primary target has been the Alberta Bakken petroleum system, according to BMO. “We think it is quite likely a continued chase for the Exshaw/Alberta Bakken play,” said Gordon Tait of BMO Capital Markets. “ T here could be a Second White Specks play in there, but it does sort of, in our view, reaffirm interest in that area.”

A report in April by BMO noted that the Alberta Bakken petroleum system is an emerging unconventional tight oil resource play in southwestern Alberta and northwestern Montana consisting of three potential reservoir zones: Big Valley/ Stettler carbonates, Middle Bakken/ Exshaw dolomitic siltstones and overlying Basal Banff carbonates.

A total of 59 wells, 32 in Alberta and 27 in Montana, have either been drilled or licensed where the primary target has been the Alberta Bakken petroleum system, according to BMO. Companies with large established land positions include Crescent Point Energy Corp., Shell Canada Limited, Murphy Oil Corporation, Bowood Energy Inc./Legacy Oil + Gas Inc., Argosy, Nexen Inc., Rosetta Resources Inc. and Newfield Exploration Company.

— Daily Oil Bulletin

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Northwestern Alberta/Foothills

Paramount buying ProspEx, increases liquids-rich inventory Paramount Resources Ltd. announced in April that it will acquire ProspEx Resources Ltd. and its stable of liquids-rich natural gas assets for approximately $180 million.

Earlier this year, ProspEx announced that it had initiated a review of strategic alternatives and that it had retained Cormark Securities Inc. as its financial advisor to assist a special committee of independent directors that oversaw the process that has culminated with the Paramount offer.

“The deal is the successful result of a comprehensive review of the strategic alternatives available to ProspEx announced in January,” said John Rossall, president and chief executive officer of ProspEx. “The arrangement with Paramount recognizes the significant value in ProspEx’s asset base.”

With the transaction, Paramount said it is acquiring a suite of liquids-rich natural gas assets with significant multizone and horizontal drilling potential in several zones from the Triassic Montney

formations up to the Late Cretaceous Cardium formations, including the Falher C zone in the Kakwa area.

“These assets will increase Paramount’s already significant Deep Basin land holdings in the Kak wa, Elmworth and Wapiti areas of Alberta,” the company said in a press release.

“The transaction also includes considerable assets in the Pembina and Brazeau areas, which have substantial Falher and Notikewin horizontal potential and numerous drilling locations in the Birch area of northeastern British Columbia, a liquids-rich Montney gas opportunity.”

In addition, Paramount said the acquisition includes predictable long life reserves and production from the Ricinus and Harmattan areas of Alberta.

For 2010, ProspEx reported average daily production of 3,056 barrels of oil equivalent per day, cash flow of $17.27 million and a net loss of $2.17 million.

Based on Paramount’s development pla ns for P rospE x ’s proper t ies, t he

company expects to add an additional 2,925 barrels of oil equivalent of production in fiscal 2011 and 3,860 barrels per day in 2012.

Reserves additions include 18.6 million barrels of oil equivalent of provedplus-probable while Paramount also receives 132,300 (104,000 net) acres of undeveloped land and an estimated 47 gross (30 net) risked drilling locations.

Net of undeveloped land at an internally estimated value of approximately $29 million—and based on a purchase price of $2.40 per ProspEx share—the transaction metrics are as follows: 2011 production at $51,900 per barrel of oil equivalent per day, 2012 production at $39,300 per barrel of oil equivalent per day, and proved-plus-probable reserves at $8.17 per barrel of oil equivalent.

Closing is subject to certain conditions, including the receipt of court and other regulatory approvals. Closing of the arrangement was expected in late May. — DAILY OIL BULLETIN

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Northeastern Alberta

Production up at MEG Energy

Photo: MEG Energy

By Paul Wells

MEG Energy's Christina Lake project.

A significant ramp up in production helped MEG Energy Corp. cut its per-barrel costs in the first quarter, leading to increased profitability.

“Our operating and financial performance in the first quarter has given us a very strong start to 2011. It highlights the strong performance of our operations and reservoir engineering teams, the quality of the Christina Lake resource, and our success in developing our assets in a responsible and profitable manner,” said Bill McCaffrey, president and chief executive officer.

MEG, which went public in the second quarter of 2010, reported first-quarter cash flow from operations of $60.9 million, while revenue was $253.9 million for the period.

During the first quarter, MEG said that Christina Lake facilities operated at 99 per cent reliability, contributing to a

reduction in net operating costs to $8.63 per bbl compared with $30.81 per barrel for the first quarter of 2010 and $11.01 in the fourth quarter of 2010. “ T his is somet hing we’re rea lly excited about…. It’s at the low end of the oilsands industry,” McCaffrey said during

MEG’s first two production phases at the Christina Lake project, phases 1 and 2, commenced production in 2008 and 2009, respectively, and have a combined designed production capacity of 25,000 barrels per day. For the three months ended March 31, 2011, bitumen production averaged 27,653 barrels.

The steam to oil ratio (SOR) in the first quarter of 2011 was 2.5, compared with a design SOR of 2.8, and SORs of 3.1 and 2.3 in the first quarter of 2010 and the fourth quarter of 2010, respectively.

“What we anticipate seeing in the next little while is an SOR that would be between 2.2 and 2.6 and that will occur over the next year,” McCaffrey said. “But as the steam chamber grows and sufficient heat is retained in those reservoirs, we plan to drill infill wells and to introduce non-condensable gas to further reduce those SORs down to the low twos.”

The company said the success of the production ramp-up, and improved SOR, have subsequently enabled it to performance-test the integrated Phase 1 and 2 facilities and exceed the original plant design production capacity during the fourth quarter of 2010 and for the first quarter of 2011.

Despite wider light-heavy differentials due to export pipeline restrictions in the first quarter of 2011, cash operating netbacks were strong, at $36.88 per barrel versus $36.56 per barrel in the fourth quarter of 2010. the company’s recent first-quarter conference call.

Despite wider light-heavy differentials due to export pipeline restrictions in the first quarter of 2011, cash operating netbacks were strong, at $36.88 per barrel versus $36.56 per barrel in the fourth quarter of 2010.

Production is expected to average bet ween 25,000 and 27,000 barrels per day in 2011, taking into account a s c h e du le d pl a nt t u r n a r ou n d i n September 2011.

During the three months ended March 31, 2011, the company drilled 83

APR/10

APR/11

APR/10

APR/11

WELLS SPUDDED

50

76

WELLS DRILLED

56

83

NORTHEASTERN ALBERTA WELL ACTIVITY

APR/10

APR/11

WELL LICENCES

62

98

▲

▲

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • JUNE 2011

45

Northeastern Alberta

core holes, four observation wells and one water source well to support Phase 2B horizontal well placement and to further delineate the resource base at Christina Lake.

The Phase 2B horizontal drilling program was initiated in the fourth quarter of 2010 and to date, a total of seven well pairs have been drilled.

Phase 2B construction included ongoing civil activities and commencement of the piling program. Construction progress is at eight per cent overall.

“We have an internal project team in place to manage the construction, and this will give us better cost and schedule controls on the project and it will help us to keep the productivity higher,” McCaffrey said. “So far, we’re on track…for our 2013 start-up.”

Combi ned de sig ned produc t ion capacity at the Christina Lake project is expected to reach 60,000 barrels per day once Phase 2B is complete. Phase 3 contemplates a phased development totalling

an additional 150,000 barrels per day that would bring the company’s total designed production capacity at the Christina Lake project to 210,000 barrels per day.

McCaffrey anticipates receiving regulatory approvals for Phase 3 in 2011.

In addition, the company is currently preparing a regulatory application for a multi-phase development totalling approximately 100,000 barrels per day at Surmont and expects to file a regulatory application in 2011.

Cenovus Christina Lake expansion approved Cenovus Energy Inc. has received Alberta Energy Resources Conservation Board approval to proceed with a major expansion at its Christina Lake oilsands operation, more than doubling the current approved capacity.

The approval covers three expansion phases (E, F and G)—each 40,000 barrels per day—for a total of 120,000 barrels per day. Once complete, the expansions

would increase gross production capacity to 218,000 barrels per day, up from the current approved capacity of 98,000 barrels per day.

Cenovus expects to submit an application for an additional 40,000-barrel-perday expansion, Phase H, at Christina Lake in 2013, increasing the project’s total gross production capacity to 258,000 barrels per day by 2019.

“T he regulator y approval at Christina Lake is a significant step in our plan to increase the company’s net asset value,” Brian Ferguson, Cenovus president and chief executive officer, said in a news release.

“This is a major milestone that allows our expansion plans at Christina Lake to remain on schedule. Additionally, as a result of this approval and the expansion

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JUNE 2011 • OIL & GAS INQUIRER

Northeastern Alberta

of the development plan area, we expect to add substantially to our Christina Lake proved reserves at year-end.”

Christina Lake is a major part of the company’s plan to grow oilsands production fivefold by 2019.

With this approval, Cenovus has oilsands expansions totalling 290,000 barrels per day of gross production capacity either under construction or approved by the regulators. That’s in addition to its current combined gross production capacit y of 138,000 barrels per day at Christina Lake and Foster Creek.

Engineering and equipment fabrication for Christina Lake Phase E is already underway with first production planned for 2014. Phase F is expected to begin production in 2016, and Phase G is expected the following year. Cenovus and ConocoPhillips, its 50 per cent partner, are expected to sanction the first phase of the expansion by the end of this year.

“Cenovus has been able to deliver industry-leading capital efficiencies as it expands its oilsands projects,” said John Brannan, executive vice-president and chief operating officer. The company

is currently building its Christina Lake expansions at a capital efficiency of about $22,500 per flowing barrel, due largely to its manufacturing approach for constructing expansions and the improvements staff are able to identify and implement with each new phase, he said.

Cenovus’s Christina Lake operation is about 20 kilometres from the community of Conklin, Alta., about 120 kilometres south of Fort McMurray. The operation began as a pilot project in 2000 and is currently producing about 18,000 barrels per day (gross) from 19 wells. Christina Lake has more than 700 million barrels of proved-plus-probable reserves and 800 million barrels of best-estimate economic contingent resources. The operation currently has an industry-leading steam to oil ratio (SOR) of less than two, which contributed to low average operating expenses of $16.47 per barrel at Christina Lake in 2010.

Christina Lake currently has two additional phases of 40,000 barrels per day each of gross production capacity under construction. Phase C is almost complete, with final testing and commissioning

adjustments now taking place. The plan is to start injecting steam by the end of this quarter, with first production expected in the third quarter of this year.

Construction is also progressing well on Phase D with more than half of the work complete. Most of the larger pieces of infrastructure are already at the site and the final modules are being completed at the company’s assembly yard in Nisku, Alta. Steam injection at Phase D is expected in the first quarter of 2013, with production starting in the second quarter.

Construction for both phases is on schedule and on budget.

Regulators also are currently reviewing an application for the Narrows Lake project in the Christina Lake region. The project is expected to have gross production capacity of 130,000 barrels per day.

At its Foster Creek operation in the Cold Lake oilsands, Cenovus is moving forward with three approved expansion phases which are expected to increase gross production capacity to 210,000 barrels per day from the current 120,000 barrels per day.

— DAILY OIL BULLETIN

OIL & GAS INQUIRER • JUNE 2011

47

Northeastern Alberta

Some oilsands leases on block in new park plan A draft regional plan for the Lower Athabasca would revoke some existing oilsands land tenures in the creation of what Mel Knight, Alberta minister of sustainable resources development, describes as “significant footprint areas” for conservation.

A total of 10 oilsands leases and 14 mineral leases would be affected in the draft plan, which provides a blueprint for conservation and economic development in northeastern Alberta. Government officials have declined to identify the affected companies.

“We feel we are putting out a plan that has made some choices,” Knight told a news conference as he released the draft plan for consultation. “The choices that are made here are to balance human activity and the protection of Alberta’s landscape.”

The government will not issue any new subsurface dispositions in the new conservation areas, said Knight. “We want to make sure there is clarity to people who are going to invest their

money in Alberta and in Canada and be sure that we honour existing conventional oil and gas; they will have surface access where required.”

However, surface and subsurface approvals could be temporarily on hold in areas the government is proposing to set

Morris Seiferling, stewardship commissioner in the government’s land-use secretariat, told a Canadian Energ y Research Institute oil conference that he does not believe the draft land-use plan will have any impact on existing oilsands projects. New oilsands developments,

The Government of Alberta did the best it could to establish new conservation areas apart from where companies have existing tenure. aside for conservation, he said. The minister urged energy companies to take a look at what the government has done with the conservation areas and what is allowed in certain areas.

“This is not written in stone; this is a consultation,” Knight emphasized. “I would expect them [the industry] to come forward with some very strong views about where we need to go.”

though, might be required to implement some initiatives under air and water frameworks, the conference heard.

The Government of Alberta did the best it could to establish new conservation areas apart from where companies have existing tenure, particularly for oilsands and natural gas, but couldn’t avoid them all, he said.

Oil and gas companies affected by the decision to cancel tenure rights will

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48

JUNE 2011 • OIL & GAS INQUIRER

Northeastern Alberta

be compensated based on the Mines and Minerals Act, which allows for the consistent and appropriate compensation of mineral rights holders whose access to Crown mineral rights are cancelled by the Alberta government, said Alberta Energy spokesman Jay O’Neill.

Environmental groups the Pembina Institute and the Alberta Wilderness Association do not believe the government has gone far enough in the draft plan.

Pembina has called for an independent science panel to review the plan as part of the consultation process to ensure the limits and land-use zones identified in the plan will achieve their stated outcomes.

“Given the history of environmental mismanagement in the region, an independent analysis of the plan would also help to restore the public’s trust in government oversight in the oilsands,” said Jennifer Grant, director of the institute’s oilsands program.

The institute’s early review suggests some elements of the plan are unacceptable, she said. The plan fails to protect habitat for any woodland caribou herds in the Lower Athabasca; allows logging within some conservation areas; and fails to halt water withdrawals from the Athabasca River during low-flow periods, said Grant.

The Alberta Wilderness Association (AWA) was also critical of the draft plan.

“The protected areas do not exclude industry and are not representative in the central and southern boreal, where the most pressures are coming from tar sands, forestry and climate change,” said Carolyn Campbell, AWA conservation specialist.

The Lower Athabasca region covers about 93,260 square kilometres and includes the Regional Municipality of Wood Buffalo, the Municipal District of Bonny ville and the Count y of Lac La Biche.

— Daily Oil Bulletin

Lloyd remains Husky’s anchor Husky Energy Inc. has enough undeveloped resources to maintain production at current rates for another 65 years, shareholders heard in late April.

That was the message chief executive officer Asim Ghosh delivered as he

presided over his first annual meeting as Husky’s chief executive officer.

Ghosh said the production potential of the company’s resource plays adds up to about a 65-year “resource” life index—and this doesn’t include vast bitumen resource

in yet-to-be commercialized carbonate rock at the company’s Saleski property in northern Alberta.

Given its vast holdings of known resources, Husky is unlike a traditional oil and gas company, Ghosh said.

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Northeastern Alberta

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The number one challenge for most exploration and production companies is finding new oil and gas to replace what is being produced.

“Husky does not have that challenge,” he said. “We have a commercialization challenge, not an exploration challenge.”

He cited Lloydminster as an example: “In many ways, you can think of heavy oil as the original resource play— well before the term ‘resource play ’ was invented.”

Describing western Canadian heavy oil as Husky’s foundation, Ghosh said the 800 million barrels Husky produced from the Lloydminister area during past 70 years is only eight per cent of the total oil in place there.

Using existing technologies, the company has the potential to recover another 800 million barrels of heavy oil from the area, which straddles the AlbertaSaskatchewan border, he said.

While western Canadian heavy oil is Husky’s foundation, Ghosh said its three pillars of growth are Southeast Asia, the Alberta oilsands and offshore Newfoundland and Labrador.

As well, he said Husky has 1.3 million acres of potential resource plays in western Canada—about 800,000 acres of gas resource plays and half a million acres of oil resource plays.

“The conventional wisdom—no pun intended—is that conventional western Canada is a declining basin. But in reality, there are massive innovations that are taking place that are rejuvenating the basin as we speak,” Ghosh said.

Husky plans to increase production from its tight oil plays and liquids-rich gas plays to about 30,000 barrels of oil equivalent a day in five years from about 5,000 barrels at present.

The company is chasing tight oil in the Lower Shaunavon and Bakken of southern Saskatchewan and in the Viking of southwestern Saskatchewan and central Alberta, and tight gas in the Alberta Deep Basin.

Husky has 15 billion barrels of bitumen in place on its conventional oilsands leases, excluding the bitumen carbonate resource at Saleski, where the company is doing early evaluation work. Late last year Husky approved construction of the 60,000-barrel-per-day first phase of its Sunrise SAGD project. First oil is slated for late 2014.

— Daily Oil Bulletin

50

JUNE 2011 • OIL & GAS INQUIRER

Northeastern Alberta

In Situ Alliance questions draft conservation plan An association representing in situ oilsands developers has expressed concern about the Alberta government’s proposal to cancel some oilsands leases that will be included in conservation areas in the Lower Athabasca Regional Plan (LARP).

“The potential sterilization of investment in the development of our province’s natural resources because of concerns about lease expropriation or access restrictions does not inspire investor confidence in the petroleum industry and has potential to result in negative economic and social consequences,” the In Situ Oil Sands Alliance (IOSA) said in a news release.

A total of 10 oilsands and 14 mineral leases could be cancelled and the leaseholders compensated, according to the government.

IOSA members strongly advocate the achievement of well-defined conservation goals through consideration of the “temporal nature of mineral leases rather than expropriation of legally purchased

and owned rights,” said the alliance. For example, as oilsands leases are explored, projects developed, completed and land reclaimed, conservation areas could be expanded to include these reclaimed areas, it suggested.

Alliance members will continue to participate in the consultation process to make their views known.

“We expect that the final outcome for LARP will achieve a balance of land-use planning and cumulative effects management while maintaining industry’s ability to operate in the short and long term,” said the IOSA. The alliance noted that in the draft regional plan the government attempted to distinguish between areas where oilsands are under active development and exploitation, and areas where there is generally a low prospect for the commercial development of oilsands. In the IOSA’s opinion, the draft plan appears to be closer to an appropriate balance between regional social, environmental

and economic priorities and the oil and gas industry operating in the Athabasca oilsands fairway.

However, t he proposed increase to conservation areas in the oilsands region is considerably less than the recommendations of First Nations, according to the Athabasca Chipewyan First Nation (ACFN), which holds aboriginal and treaty rights throughout the LARP area. The land set aside in the draft plan is also significantly less than the recommendations from the Regional Advisory Council for an increase of up to 32 per cent in conservation areas, the ACFN said in a news release.

The ACFN said it is “left wondering how they will sustain their traditional livelihood and protect their cultural existence on what amounts to scattered, small parcels of land.”

The Alberta government has a duty and an obligation to ensure that the ACFN has the ability to practice and maintain its rights now and into the future, said Chief Allan Adam.

— DAILY OIL BULLETIN

Total Canada partners with E-T Energy to test electric bitumen recovery technology Privately held E-T Energy Ltd., which is developing its patented electro-thermal (ET-DSP) technology for producing heavy oil and bitumen from oilsands, is getting some support from Total E&P Canada Ltd. Total will provide financial and technical support over the next two steps of field testing as E-T prepares for its proposed 10,000-barrel-per-day Phase 1 commercial development at Poplar Creek.

In consideration for Total’s participation, the agreement provides options for future co-operation in the development of the technology including a global licence of the technology for Total as well as a limited working interest in E-T Energy’s first commercial development. The agreement contains ongoing project milestones and performance criteria.

E-T Energy expected to start production from the current steps 1 and 2 test patterns before the end of April. Step 3 drilling and connecting will commence shortly thereafter.

“We are thrilled to have Total participate with us in our project,” Bruce McGee, E-T’s president and chief executive officer, said in a news release. “The depth of Total’s technical capabilit y and expertise in project development, together with our technology and pilot test experience over the past four years,

looking forward to seeing where this new technology can go and how it can be used on a commercial scale.”

E-T Energy also reported that it has signed its agreement with A lberta’s Climate Change and Emissions Management Corporation (CCEMC), which will provide up to $6.86 million in

“This project is one way that CCEMC is advancing clean technology.”

— Eric Newell, Chair, Climate Change and Emissions Management Corporation

will accelerate the application of ET-DSP in Alberta and globally.”

“Work ing w it h E-T Energ y is an excellent opportunity for Total to help advance innovative extraction methods that continue to build on the development of environmentally sound practices in Canada’s oilsands,” said Jean-Michel Gires, president and chief executive officer of Total E&P Canada. “We are

co-funding for Step 3 and Step 4 field testing of the ET-DSP technology.

“CCEMC is pleased to support field testing for the E-T Energy project,” said Eric Newell, CCEMC chair. “This project is one way that CCEMC is advancing clean technology and exploring the impact that technology can have on reducing greenhouse gas emissions in the oilsands.”

— DAILY OIL BULLETIN OIL & GAS INQUIRER • JUNE 2011

51

Northeastern Alberta

AOSC applies for Hangingstone project Athabasca Oil Sands Corp. (AOSC) has filed an application with the Energy Resources Conser vat ion Boa rd a nd A lberta Env ironment to construct a proposed 12,000-barrel-per-day steam assisted gravity drainage (SAGD) project on its Hangingstone lease.

The company believes its Hangingstone property could peak at more than 70,000 barrels per day by 2020.

In the application filed March 31, AOSC said the project would be located on a portion of its Hangingstone lease in townships 85-86 and range 9-W4.

The entire AOSC Hangingstone lease is located within the Regional Municipality of Wood Buffalo, approximately 20 kilometres south of Fort McMurray, Alta.

The application said the central processing facility (CPF) for the project will be located in sections 19 and 30-8609W4. The project will consist of 25 horizontal well pairs connected to a CPF, where the steam generation and production processing will occur.

52

JUNE 2011 • OIL & GAS INQUIRER

The SAGD production wells will be drilled to a vertical well depth ranging from 180 to 205 metres, placed approximately one to two metres above the base of pay to minimize risk of communication with bottom water.

The injection wells will be drilled approximately five metres above the production well. The horizontal well length are planned to be between 750 and 850 metres. SAGD well pads will be designed to accommodate five well pairs. AOSC said that well pads will be const r uc ted suc h t hat emu lsion from individual production wells will be gathered together at the well pad.

Emulsion will be pumped to the surface by downhole pumps in each production well.

The application said that surface facilities will be required for the project to generate and distribute steam, gather produced fluids, process oil and emulsions, and treat and recycle water.

These facilities can be broken down

into three components: wells and well pads, the CPF and associated facilities, and offsite services.

According to AOSC, the project will recover an estimated 41 million barrels of bitumen over its projected 10-year production life. Production from the project w ill be marketed as a bitumen blend.

AOSC said it anticipates that the regulatory approval process will take 14-18 months. Construction is scheduled to begin in 2012, with first steam anticipated in late 2013. AOSC said that reclamation will begin in approximately 2024 and last for approximately three years.

The application represents the initial segment of a multi-phase development plan in the Hangingstone area.

T he second ph a se of de ve lopme nt is est i mated at 25,0 0 0 ba r rels per day, w it h star t-up possibly as early as 2016. — DAILY OIL BULLETIN

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Confidence builder Backed by major R&D effort, Flexpipe Systems’ tough new FlexCord Linepipe becomes the pipeline choice for severe cyclic pressure pulsating environments Spooled, high-pressure composite pipeline systems have cut both the time and cost in tying in new production and in other field operations, like supplying water for injection wells.

But one challenge composite pipeline systems face is a lack of confidence among engineers that they will perform to full maximum allowable operating pressures (MAOP) in severe cyclic pressure pulsating environments, says Flexpipe Systems manager of product development Mike Yeats. Yeats says in a small number of such applications composite linepipe has broken down or failed before its expected lifespan, resulting in engineers often having to specify higher strength pipe than the application would indicate—and costing them more money.

The big difference between FlexCord and the highly successful FlexPipe Linepipe system is the new linepipe is manufactured with a middle layer of galvanized steel cords instead of glass fibres, giving it the strength to withstand severe pressure pulsations without degrading its reinforcement layer.

“It’s designed to take plenty of abuse,” says Yeats. “It’s specified to 1,500 psi and that means it can simultaneously withstand full 1,500 psi of pressure for 20 years with multiple pulsations per second. And it can withstand 10 full 0 to 1500 psi on-off cycles per day for 20 years. Nothing else in the market can handle that kind of abuse.”

Yeats says FlexCord has found a home in the western Canadian market in tougher pressure pulsation situations like water injection “that are rough on linepipe products.”

Flexpipe Systems, a subsidiary of Shawcor, launched a major research and development effort to understand why this sometimes happens, and to build a product that lives up to its MAOP under severe operating conditions. In mid-2010 it launched the tough new FlexCord Linepipe that is now gaining converts and saving customers money across western Canada and the U.S. as a result of that effort.

“Its main use has been water injection, water transfer, anything with severe pumping applications,” he explains. “Its reception has been very good and the customers that have it have been very happy with it.”

“We dedicated a lot of technical horsepower to understanding what was happening in the field,” says Yeats. “We put sophisticated equipment on the pumps to really understand what was going on.”

Weller says a second key feature of FlexCord is that it is accepted by the ERCB for applications up to 800 parts per million of hydrogen sulfide.

What they discovered was that the often overlooked cyclic pulsations created when using piston pumps, such as duplex or triplex pumps or diaphragm pumps, were the cause of a number of pipeline failures.

Flexpipe’s R&D effort has also spawned some spinoff benefits, adds Weller. A new application tool based on the cyclic performance data generated from the research effort allows the company to look at a client’s specific operating conditions, determine the number of cycles and changes in pressure likely to happen, and predict how the product will perform in that situation.

“Every time a piston moves in a pump, it creates a small pressure spike,” explains Yeats. “It’s something you can’t see looking at a pressure gauge. The gauge doesn’t move. But using more sophisticated equipment we found that many times per second there are small pressure variations, sometimes as high as 100 psi. Over 10, 15 or 20 years the cyclic pulses tended to break down the structural integrity of a composite pipeline system, which was the cause of those products not performing to specifications.

“Once we understood the problem and gained a deep, sophisticated knowledge of what was going on, we set out to design a new linepipe product to counteract the cyclic pulsations. That’s how FlexCord was born,” he adds.

Flexpipe applications engineering manager Blaine Weller agrees.

“It’s an estimating tool based on physical tests of the product,” he explains.

Weller adds the R&D effort leading to FlexCord’s successful launch has provided other benefits as well.

“Companies are impressed with the cyclic performance data we have. It’s unique in the industry. They like to see that we’ve done our homework, and that we’ve done it all up front prior to release,” he notes.

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Central Alberta

Syngas plant inches forward

By Lynda Harrison

APR/10

APR/11

APR/10

APR/11

WELLS SPUDDED

23

91

WELLS DRILLED

24

117

Photo: Swan Hills Synfuels LP

The cost of the gas plant and well pairs is pegged at $600 million, which will be financed separately from the power plant’s estimated cost of about $500 million. That price tag depends on final project component siting and configuration decisions.

T he power plant w ill be in the Whitecourt–Swan Hills region of Alberta, but the company has not yet pinpointed its exact location.

About $70 million has been raised within the organization so far and largely been spent on the demonstration project and first phase of the commercial project, he said. The demonstration project was completed in July 2009 at a cost of about $30 million, of which $8.83 million was provided by the province of Alberta through the Alberta Energy Research Institute.

Shaigec’s company estimates two billion barrels of oil equivalent can be manufactured

from its secured coal resource base using ISCG. The supply cost is less than $3 per gigajoule, he told the conference.

The company’s proposed commercialscale project will manufacture clean fuel for a new 300-megawatt power generation facility near Whitecourt while capturing more than one million tonnes per year of CO2 for sale to nearby enhanced oil recovery customers.

“I can’t give you the exact number of producers who will use the gas, but the interest in the CO2 exceeds the available supply,” he said.

The coal seam is 1,400 metres deep at nearly 2,000 pounds of pressure per square inch and thus is not economical to mine, he said.

The demonstration project has one well pair: one horizontal well that injects oxygen and saline water while the vertical well brings the raw syngas to the surface where a conventional gas plant removes the CO2 resulting in a syngas that can be used as a fuel for power generation or further converted to liquid fuel. The use of saline water virtually eliminates the need for fresh water, said Shaigec.

A series of chemical processes convert the coal to syngas, Shaigec told the conference. The oxygen supports a limited and controlled amount of combustion, raising the temperature of the coal and boiling the water to generate steam. The naturally existing deep underground pressure, along with the elevated coal temperature and the presence of steam, together form the right conditions to gasify the coal. Char and ash, which are remnants of the original coal, remain deep underground.

Although the company is not doing anything differently with its demonstration plant than what’s been done with the technology in its 80-year history worldwide, until that plant was operating skeptics suggested the process would not work, he said.

The syngas process injects oxygen for limited downhole combustion of coal, which gasifies the coal.

A $1.5-billion project designed to use in situ coal gasification (ISCG) to convert non-mineable coal into clean, lowcarbon synthesis gas (syngas) needs further funding but expects to file for regulatory approval sometime this year.

Swan Hills Synfuels L.P. is targeting a construction start in late 2012 or early 2013 for the Swan Hills ISCG/Sagitawah Power project and with an on-stream date late 2015.

The first phase of development will consist of 18-20 well pairs, along with an ISCG facility, power generation, CO2 transportation and sequestration, and a syngas pipeline.

Swan Hills Synfuels is in the process of raising $100 million that will get the project to the start of construction, Douglas Shaigec, president of the Calgary-based company, said on the sidelines of the Canadian Energy Research Institute 2011 Oil Conference in Calgary.

CENTRAL ALBERTA WELL ACTIVITY

APR/10

APR/11

WELL LICENCES

207

142

▼

▲

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • JUNE 2011

55

Central Alberta

Focus on liquids-rich gas stems declines Despite weak levels of natural gas drilling, the decline in production of natural gas liquids (NGLs) in Alberta of the past few years appears to be slowing down as a result of the new industry focus on liquids-rich gas pools.

According to the Energy Resources Conservation Board’s (ERCB’s) tracking of field supply, the decline of NGLs (propane, butanes or pentanes plus, or a combination of them, obtained from the processing of raw gas or condensate) output in Alberta is moderating, having fallen just 1.6 per cent from 88.41 million barrels in 2009 to 86.95 million barrels in 2010. That compares to a decline of 6.48 per cent in 2009 from 2008 when NGL supply totalled 94.53 million barrels.

Drilling for natural gas fell sharply over the past few years as prices plummeted due to weak demand following the credit crisis and burgeoning supplies of shale gas in the United States. Along with that drop in gas drilling, NGL production fell sharply as gas output waned.

More recently, industry drilling programs have been targeting liquids-rich gas

because liquids prices have remained high and make exploitation of some natural gas pools economic despite low prices for that commodity.

Daily Oil Bulletin statistics show that of the 35 producers who reported NGL output in the final quarter of last year, 19 produced more NGLs in the fourth quarter than they did the first three months of the year. Data on reserves show 51 producers who reported NGL reserve performance for 2010 increased proved reserves to 275.3 million barrels at year-end versus 266.2 million barrels at the end of 2009.

And probable reserves climbed from 98.74 million barrels at the end of 2009 to 108.96 million barrels.

Producers reported adding a combined 34.15 million barrels of proved NGLs from drilling activities last year while production of the 51 producers totalled 36.41 million barrels. Drilling activities added a further 16.85 million barrels of probable NGL reserves. On the probable side, the largest year-over-year increases excluding acquisitions came from Canadian

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Both natural gas and liquids production will continue to decline for the near term although perhaps not at the same rate, says Marie-Anne Kirsch, the ERCB’s technical specialist in the market intelligence and regulatory analysis group.

According to Kirsch, Alberta’s volumes of propane, butane, ethane and pentanes plus were down between 2.5 and 5.6 per cent in 2010 compared to 2009.

“Gas production is down, so liquids production appears to have followed suit,” says Kirsch. “For each of the various spec products, I see a decline year over year.”

However, with increased drilling in certain areas, she believes the decline in liquids production could be curbed this year.

“Not like the five per cent decline in the gas production. We might see a two per cent decline, but I can’t see a reversal of that trend just because producers are getting a pretty good cut as it stands

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now,” says Kirsch, referring to recovery efficiency at processing plants.

She is in the process of analyzing data to back up her belief that producers are currently drilling more wells in liquids-rich areas. “We know [the liquidsrich reserves] are there; we have them booked,” says Kirsch.

The definition of liquids-rich gas seems to be changing, due to high prices, says

Steven Paget, an analyst at FirstEnergy Capital Corp. In the past, liquids-rich meant getting 60-100 barrels per million cubic feet and now it seems to mean 15 barrels, he says.

“That’s still a substantial impact,” says Paget. “What used to be insignificant proportions are now more important.”

The biggest issue, says Paget, is the decline in ethane production, off almost

20 per cent compared to 2006. The market for ethane is favourable right now; however, most Alberta ethane is sold under long-term contracts, not at market prices, he says.

According to the ERCB, 35 per cent of the total raw ethane reserves are estimated to remain in the marketable gas stream and could potentially be recovered.

— Daily Oil Bulletin

Conventional oil industry poised for growth, says minister After years of a continuous decline in conventional oil production, Alberta’s energy minister is predicting significant growth in 2011 as producers concentrate their investing overwhelmingly on oil prospects due to high commodity prices and exploitable formations using horizontal drilling and multistage fracturing.

“For the first time in several years, output is projected to increase, and we will now see the industry getting into a growth period,” Ron Liepert says.

According to the Canadian Association of Petroleum Producers (CAPP), the province averaged 459,000 barrels per day of conventional light and heavy oil production last year, with output declining at an average five per cent each year for the past decade. The decline last year was only 1.5 per cent.

According to statistics provided by Alberta’s Department of Energy, output averaged 571,000 barrels per day in 2006, decreasing to 524,000 barrels per day a

year later, 503,000 barrels per day in 2008 and 461,000 barrels per day in 2009.

Liepert declines to put a figure on the expected growth in additional barrels, stating, “Nobody can make an accurate prediction, as a great deal will depend on new technology. Under the royalty changes we made last year, incentives were given for horizontal drilling and multistage fracking, the results of which are now visible.

What was deemed as depleted resources is currently highly prospective, with

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Central Alberta

significant chances of being brought out of the ground.”

In its recent fiscal year budget, the province estimated conventional oil production will rise close to three per cent to 484,000 barrels per day for the year ending March 31, 2012.

BMO Capital Markets analyst Gordon Tait says, “Resurgence is on the way with lots more capital coming into the conventional/tight oil sector. Drilling is on the rise and there is also a lot of competition when auctions are held of Crown oil and gas rights. We also see a great deal of overall investor interest. There is no question that technology has opened up opportunities in those basins that were not there five years ago.”

CAPP’s vice-president for markets and oilsands Greg Stringham notes that early results from the Cardium play point to a reversal of the annual oil production declines experienced for many years.

“Current reserves numbers and production forecasts do not reflect the true potential of the development of the old/ new plays such as the Cardium and Bakken. With the use of new drilling

technology, producers are able to recover more of the oil in place. At present, we only recover 25-30 per cent of the oil in the ground.”

John Zahary, president and chief executive officer of Harvest Operations Corp., says western Canada has a number of formations with significant remaining potential for oil production.

“We have been forecasting the end of the conventional industry since the start of my career.”

— John Zahary, President and Chief Executive Officer, Harvest Operations Corp.

“Many of these formations, such as Cardium, Viking, Dina and Ellerslie have had ongoing oil production going back decades, yet only a fairly small percentage of the resource in place has been recovered. Others such as Slave Point, Bakken, Cardium in certain areas and the oilsands area have generally been known about for a long time, but for the most part have not been developed,” he says.

“We have been forecasting the end of the conventional industry since the start

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of my career. I expect it to continue to be vibrant until at least the end of my children’s career and likely much longer. The future will depend on price and continuing the technical entrepreneurial culture that has created the industry that we have today,” Zahary says.

In a report released last summer, the Energy Resources Conservation Board

(ERCB) estimated the province’s remaining established reserves of conventional crude at 1.44 billion barrels, but that may turn out to be a low estimate, considering the new tight resources being developed with new drilling and completion technologies.

The ERCB report predicted that the number of new oil wells placed on production would increase to 1,500 wells in 2010 and rise again this year to 1,700 wells.

— Ashok Dutta

Central Alberta

Emerge Oil strikes oil at Viking Emerge Oil & Gas Inc. announced last month the results of its first Viking light oil well at Coronation, Alta., along with a new heavy oil pool discovery on its farm-in lands at Primate, Sask.

The company said it has successfully completed and placed on production its first Viking horizontal well (87.5 per cent working interest, operated) in the Coronation area. The well was an 800-metre horizontal and was completed with a 16-stage, 15-ton-per-stage waterbased frac. The well, which is pipelineconnected into an Emerge Oil–owned and operated oil battery in the area, was rig released on February 8 and placed on production on March 15.

The well at 14-36-38-10W4 has produced at a sustained rate of 120 barrels of oil equivalent per day over the last 30 days, comprised of 70 per cent light, sweet 35 degrees API oil and 30 per cent natural gas. Emerge Oil has two (1.9 net) followup locations ready to be surveyed following spring breakup and plans to drill a total of five wells in this area in 2011.

Emerge Oil has four (three net) sections of land with Viking potential in this area for future development.

Emerge Oil is also continuing to develop its drilling program on farmin lands prospective for Viking light oil in the Kirkpatrick Lake area of Alberta, south of the company’s currently owned Coronation lands.

The farm-in agreement, which was announced on Jan. 25, 2011, provides Emerge Oil with access to approximately

30,000 net acres of land, of which 18,000 net acres include Viking petroleum rights.

Emerge Oil has committed to drill five horizontal Viking wells to earn a 70 per cent working interest in 10 sections of land, with a rolling option that allows Emerge Oil to earn the remainder of the farmin lands. The five commitment wells are required to be drilled by Aug. 31, 2011.

Emerge Oil has surveyed 11 wells to date and plans to spud its first well as soon as spring breakup permits.

During the first quarter of 2011, Emerge Oil said it completed the four (3.5 net) commitment wells of its heavy oil

this McLaren heavy oil pool. Emerge Oil earns 100 per cent working interest and is subject to provincial Crown royalty and a 10 per cent non-convertible gross overriding royalty.

Emerge Oil said that all major construction is complete at its Silverdale oil battery, with final electrical tie ins and start-up commissioning now underway.

The facility, which includes an oil sales pipeline, natural gas metering station, emulsion processing, water injection and truck weigh scales, will have the capacity to treat 12,000 barrels a day of oil and inject 60,000 barrels per day of

The company anticipates a $1.50-$2.50 per barrel reduction in corporate operating costs over the second and third quarters of 2011 from the Silverdale battery expansion. farm-in agreement entered into in 2010.

The company said that a farm-in well at 08-19-037-26W3 in the Primate area has produced at a 30-day average rate of 120 barrels a day. This new heavy oil pool discovery is on trend with a heavy oil pool discovered in 2005 that has accumulated more than 1.5 million barrels of oil to date. Emerge Oil has access to 1,920 acres (three sections) with a 100 per cent working interest in the Primate area.

The company has seven follow-up wells surveyed to date with a potential to drill a total of 12 wells to develop

produced water. The facility is expected to be fully operational in early May and is a major component of the company’s operating cost reduction plans for 2011.

The company anticipates a $1.50-$2.50 per barrel reduction in corporate operating costs over the second and third quarters of 2011 from the Silverdale battery expansion.

Emerge Oil has invested approximately $10 million into the construction of this state-of-the-art facility, which will be capable of processing third-party volumes once the facility is fully commissioned.

—DAILY OIL BULLETIN

Open Range reports Wilrich success Open Range Energy Corp. reports continuing success with its Wilrich-focused winter drilling program and has now dr illed, completed and brought on production three horizontal wells of its planned four-well first-half capital program at the company’s core Ansell/ Sundance Deep Basin propert y. The fourth well was planned to be fracture stimulated in April.

The first well of the program came on stream in mid-February. The second and third wells, each drilled to a total

measured depth of over 4,000 metres, recently underwent completion operations using a packer system. They were placed on test in March to clean up fracture fluids, flowing at initial clean-up rates of up to 7.5 million cubic feet per day and 5.5 million cubic feet per day, respectively.

The wells were recently tied in to Open Range’s gathering and processing facilities at initial production rates of 4.2 million cubic feet per day plus natural gas liquids and three million cubic feet per day plus natural gas liquids (NGLs), respectively.

This early data continues to indicate strong per-well reserves and attractive economics at prevailing commodity prices, and demonstrates the repeatability of the Wilrich play over Open Range’s lands, the company said.

Initial 30-day average productivity (IP30) among competitor wells in the greater Ansell/Sundance area is averaging approximately 3.5 million cubic feet per day, ranging from 1.7 million cubic feet per day to 6.6 million cubic feet per day.

Open Range’s initial Wilrich horizontal OIL & GAS INQUIRER • JUNE 2011

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Central Alberta

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well came on stream October 2010 with an IP30 of 4.3 million cubic feet per day. The first well of the winter program came on stream mid-February with an IP30 of 3.9 million cubic feet per day.

These two wells have cumulative production to date of approximately 450 million cubic feet and 230 million cubic feet (plus NGLs), respectively. Open Range says its four wells to date are meeting the company’s expectations and reflect a normal production distribution for the Wilrich play.

Total Wilrich horizontal production in the greater Ansell/Sundance area is now approximately 100 million cubic feet

Within six months of tying in its first Wilrich horizontal well, the company is contributing approximately 10 per cent of the estimated area Wilrich horizontal production.

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per day (plus NGLs) from 39 producing wells, including Open Range’s four net wells.

Within six months of tying in its first Wilrich horizontal well, the company is contributing approximately 10 per cent of the estimated area Wilrich horizontal production.

The fourth well (60 per cent working interest) of the first half program is expected to be brought on stream in late April, weather permitting, which will give the company a total of five (4.6 net) Wilrich horizontal wells.

Given Open Range’s ongoing capital efficiency efforts, the winter program included executing various drilling and completion optimization techniques including the company’s first microseismic program. The data will be used to continue optimizing fracture design and well spacing with the aim to maximize reserve capture without overcapitalizing the asset base. The company has a current inventory of 41 (35 net) Wilrich horizontal locations over 20 net sections.

— DAILY OIL BULLETIN

60

JUNE 2011 • OIL & GAS INQUIRER

Central Alberta

ExxonMobil quiet on Cardium plans Exxon Mobil Corporation and Imperial Oil Limited hold 235,000 net acres in t he Pembina Cardium in A lber ta, a potential light oil play for the company, but the multinational giant isn’t disclosing capital expenditures or drilling plans for 2011.

“That’s not data we typically disclose on a field-by-field basis,” Alan Jeffers, a company spokesman, wrote in an email.

The company disclosed its acreage position in a presentation slide at its analyst meeting last month.

“It’s a combination of ExxonMobil and Imperial Oil acreage. We are planning to evaluate it over the next few years and otherwise haven’t outlined any specific plans for the acreage.”

An Imperial Oil spokesman declined to discuss the company’s Cardium position further.

“Imperial continually evaluates potential opportunities in all basins in which it holds acreage, including the Cardium,” said spokeman Pius Rolheiser.

ExxonMobil has used proprietary, i n novat ive tec h nolog ies to u n loc k resources from tight reservoirs, including multi-zone stimulation technology and just-in-time perforating.

A recent update by Peters & Co. Limited on the unconventional Cardium play stated that since its last update in October 2010, the data set of Cardium oil horizontals with greater than one month of production history has climbed to roughly 430 wells, up from about 200.

With the f ive-year average West Texas Intermediate crude oil strip of US$100 per barrel, t y pe cur ves for Cardium wells in East Pembina, West Pembina and Garrington provide strong economics with a half-c ycle rate of return of 34 per cent, 51 per cent and 43 per cent, respectively.

A r e p or t l ate l a s t y e a r b y T D Newcrest Capital Inc. stated that recent tec h nolog ica l adva ncements in t he development of the Cardium include pad drilling, increased lateral length and frac density, water-based fracs and pump optimization. Different operators are experimenting with some or all of these strategies.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • JUNE 2011

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Southern Alberta

Contrarian Skope targets shallow gas

By James Mahony

APR/10

APR/11

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Photo: Joey Podlubny

At the same time, many junior producers were knee-deep in costly resource plays that need a steady infusion of capital, without, in some cases, returning steady cash flow. In short, there was an ongoing need to generate cash, often from aggressively selling assets, including conventional shallow gas, into a less-thanenthusiastic marketplace.

“You get this restructuring of legacy assets taking place, and when you put that together with the [low] entry costs into shallow gas and conventional production, we saw a real opportunity,” he told the 2011 Energy & Infrastructure Conference sponsored by CIBC World Markets Inc. With current shallow gas production of 4,500 barrels of oil equivalent per day and a reserve life of 8.5 years, Skope hit the ground running after striking a deal to buy an 80 per cent stake in shallow gas assets that Cenovus Energy Inc. was

looking to sell last year. (The remaining stake is owned by privately held Spur Resources Ltd., which operates the assets.)

“We offer quite a bit of exposure to natural gas,” Cohen said. “In fact, we’re probably the most exposed and straightforward vehicle for gas at what we think is the low point in the price cycle. We have a very sustainable production profile, and at current prices, it takes only about 70-90 per cent of cash flow to sustain production and pay our dividend.”

When it comes to horizontal drilling, Cohen acknowledged the technology is most commonly applied to deeper, tighter reservoirs, but said it may yet prove interesting in shallow gas plays. In the near term, however, Skope will maintain production at low costs the old-fashioned way: through vertical drilling, well remediation and recompletions.

Among other advantages, capital spending on conventional, shallow gas plays is done in small steps, and thus is easily controlled, he said. Because Skope’s producing assets are about 40 years old, production declines of roughly 15 per cent are very stable, he said.

As well, thanks to the junior’s hedging, it has some price protection on the downside, yet can meet capital costs and dividend obligations, even at current gas prices.

If and when a recovery in gas prices materializes, the company stands to participate in the upward curve, Cohen said. On the cost side of the ledger, he said the company’s ability to keep general and administrative (G&A) costs down arises from the fact that all of its production is nonoperated, a situation he plans to maintain.

“We end up being one of the lowest-cost companies in the industry. Even though we’re dealing with what’s viewed as the Walmart of the gas business—this really is conventional gas—because our F&D [finding and development] costs are so low, our operating costs and G&A are also low,” he said.

Skope says low entry costs make shallow gas economic.

Despite widespread industry disinterest, at least one junior producer sees gas opportunities in shallow gas, Canadian analysts and investors gathered in Toronto heard recently.

Indeed, the counter-cyclical team at Skope Energy Inc. set out last year to build a producer from just those assets the rest of the industry was rejecting.

Thanks to soaring oil prices, conventional shallow gas has all but fallen off the radar and Skope executives saw an opportunity.

Last summer, as the company was being formed, a confluence of three major cycles occurred, according to Henry Cohen, Skope’s president, chairman and chief executive officer. For one thing, natural gas was trading at below replacement value, and for many western Canadian producers, gas wells were being brought on at high decline rates.

SOUTHERN ALBERTA WELL ACTIVITY

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Source: Daily Oil Bulletin

OIL & GAS INQUIRER • JUNE 2011

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Southern Alberta

AJM more bullish on long-term gas prices Growth in domestic demand, a shift from natural gas to oil focused drilling, and signs of the development of alternative offshore markets for Canadian natural gas have led Calgary-based AJM Petroleum Consultants to raise its price forecast for longer-term Canadian natural gas prices.

In its quarterly domestic oil and gas price forecast released in late March, AJM has maintained its AECO natural gas price forecast at C$4.10 per thousand cubic feet

preferred domestic energy source,” said AJM economist and vice-president Ralph Glass. “Add this to the fact that high oil prices are discouraging natural gas drilling and encouraging oil drilling, and a situation is emerging whereby the balance will shift on the oversupply issue that has been plaguing North American gas prices.”

Based on the prior five-year average numbers for w it hdrawal /injection, by the end of the injection season

“Because natural gas is so cheap to buy right now in North America, it is moving in the direction of being the preferred domestic energy source.”

— Ralph Glass, Economist and Vice-President, AJM Petroleum Consultants

for 2011, but increased its long-term AECO forecast in real dollars to $6.50 per thousand cubic feet by 2016.

“Because natural gas is so cheap to buy right now in North America, it is moving in the direction of being the

in October 2011, storage levels will be below the five-year maximum, the company said.

“As plans move ahead to develop alternative offshore markets for Canada’s natural gas, a new supply paradigm will

emerge so that we will see a return to higher longer-term natural gas prices,” AJM predicted.

While AJM’s March 31, 2011, forecast includes an increase in long-term natural gas prices, it also reflects the current increase in crude oil prices. As early as mid-2008, AJM had predicted that by 2016 the world would see prices of US$100 per barrel for crude oil, but recent world events have caused AJM to shift this forecast so that the West Texas Intermediate (WTI) is now anticipated to linger at US$100 per barrel in real dollars for the balance of 2011 and beyond.

This increase in short-term crude oil price forecasts is based on the unrest in North Africa and the Middle East, along with Japan’s anticipated need for energy to aid its rebuilding process.

While the average WTI spot price will show minor fluctuations due to global events, AJM anticipates it will average at US$100 per barrel in both the mid-term and the long term.

— DAILY OIL BULLETIN

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Shallow rights reversion delayed for a year Alberta will delay implementing shallow rights reversion in the province for one more year, producers heard in mid-April.

“I k now t hat d i sapp oi nt s some people, but it ’s the best decision for

It also hopes it will help keep under-used pipeline assets viable.

Allbright said a shortage of manpower at the Tenure Branch, combined with a few major projects underway including the

Gradeen compared the Stelmach government’s shallow rights policy to the deeper rights reversion policy implemented over 30 years ago by the government of then-premier Peter Lougheed. t he depar tment right now,” Brenda Allbright, head of the tenure branch of Alberta’s department of energy, told about 250 people who attended the Alberta Tenure Information Exchange.

The shallow rights reversion scheme will see non-active formations above currently producing formations revert to the Crown if the current rights holder can’t make the case they deser ve to maintain the rights. The government hopes it will encourage the potential recover y of around 44 trillion cubic feet of gas currently not being targeted.

province’s new Regulatory Enhancement Project geared to boost regulatory efficiency mean they need more time to get the shallow rights reversion program up and running.

“We want to get a few of those things behind us,” she explained.

Allbright said industry is split on the new shallow rights reversion.

Many junior producers favour shallow rights reversion, as it will open up more land for acquisition and development.

“For the most part, I think it is good for the province, for the technology and for

self-sufficiency, and there are a lot of reasons to go ahead with it, on balance,” said Glenn Gradeen, president and chief executive officer of junior Tangle Creek Energy Ltd. “It will give the smaller, more nimble producers an opportunity to access land.”

He also acknowledged shallow rights reversion might also be an opportunity for the province to increase its revenues.

“You’ll get land bonus revenue and I think, ultimately, you’ll increase the royalty revenue,” he said.

Gradeen compared the Stelmach government’s shallow rights policy to the deeper rights reversion policy implemented over 30 years ago by the government of then-premier Peter Lougheed.

“Deeper rights reversion was good for the province and it keeps producers active on existing zones. The companies that own shallow rights now can build their case that they should retain them, but if they can’t, then they go back to the Crown and that provides opportunities for companies like ours,” he said.

— DAILY OIL BULLETIN

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Western Energy buying Stoneham Drilling for $245M Western Energ y Ser vices Corp. and Stoneham Drilling Trust have entered into an agreement to combine to create the sixth-largest contract driller in Canada with 43 rigs available for work.

The value of the deal, if approved b y s h a r e h ol de r s , i s e s t i m at e d at $245 million.

Stoneham has assembled one of the premier deep-capacity drilling rig fleets in the industry. Its rig fleet consists of 19 drilling rigs, all of which are efficient

Stoneham has one of the highest utilization rates in the industry for the three months ended March 31, 2011.

Preliminary Rig Locator records for the first quarter show the company’s Canadian rigs had a 69 per cent utilization rate in the first quarter with 71 wells drilled. Western Energy’s Canadian rigs drilled 136 wells and had a 59 per cent utilization rate.

The average age of Stoneham’s fleet is six years, with approximately 37 per cent of the fleet added in the last four years.

“Stoneham has assembled one of the highest quality, deep-capacity drilling rig fleets in Canada.”

— Dale Tremblay, Chief Executive Officer and Chairman, Western Energy Services Corp.

long-reach ideally suited for deep horizontal drilling in the capital intensive resource plays such as the Cardium, Bakken, Viking, Shaunavon and Montney formations, as well as the Peace River heavy oil area.

A combination with Stoneham would solidify Western Energy as a premier contract driller in the deep horizontal drilling market. Pro forma Western Energy would emerge as having one of the largest deepcapacity modern fleets in Canada at a time

when this type of equipment is in exceptionally high demand, the company noted.

Western Energy continues to focus its efforts in three core business lines encompassing contract drilling through Horizon Drilling Inc., service rigs and rental and production services with an emphasis on businesses engaged in unconventional resource development. Stoneham’s assets, client base, operational personnel, safety and operational performance meet Western Energy’s acquisition criteria perfectly, the company said.

“This transaction represents a significant milestone in Western Energy’s growth achievements,” said Western Energy chief executive officer and chairman Dale Tremblay in a news release. “Stoneham has assembled one of the highest quality, deepcapacity drilling rig fleets in Canada. With one of the top-tier teams in the industry, Stoneham has earned the reputation as a premier contract driller, which is evidenced by its blue chip safety record, high-quality service and top utilization rates.”

— DAILY OIL BULLETIN

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Southern Alberta

Essential targets Technicoil in $187M deal Essential Energy Services Ltd. is acquiring Technicoil Corporation in a $187-million stock and cash deal that will create the predominant coil tubing and nitrogen well service provider in Canada and see the joint entity become the fifth-largest conventional service rig operator in the country.

Garnet Amundson, president and chief executive officer of Essential, said that with the majority of new wells in western Canada being drilled horizontally, and with the expectation that this trend will continue, the company believes the deal is a good fit.

“We believe that [the] announcement is a significant development. With all the new wells that are being done now in Canada horizontally—and certainly I think it’s the majority of wells—we believe the demand for coil tubing services is just going to grow and in fact has material growth ahead of it,” he said in a conference call.

Combined 2010 revenues for the two companies were $261.2 million, with Essential generating $166.6 million and

Technicoil $94.6 million. Amundson said the joint entity will build on that success as the transaction will strengthen Essential’s competitive position with customers across western Canada and

“The size of the company I think will open doors to both organic growth opportunities and the possibility of acquisitions,” Amundson said. “That might be in Canada—perhaps now we can look into

“The size of the company I think will open doors to both organic growth opportunities and the possibility of acquisitions.”

— Garnet Amundson, President and Chief Executive Officer, Essential Energy Services Ltd.

provide continued opportunities for geographic expansion.

“Together with our multistage fracturing system, the combination will strengthen Essential’s position as a key player in the market for completions and workovers on horizontal wells,” he said.

“We are also excited about other growth opportunities within the combined business, including the addition of complementary pumping equipment, the expansion of our downhole tools business and our entry into the growing Colombian oil and gas sector.”

He added that the company’s increased girth also has other material benefits.

At TransGas, great service is a reflex.

the United States and then of course other places internationally.”

Pro forma equipment upon closing of the transaction is as follows: 62 total service rigs (Essential 53, Technicoil, nine); 51 coil tubing rigs (Essential 34, Technicoil 17); 21 nitrogen and f luid pumpers (Essential 16, Technicoil five); and five hybrid drilling rigs (Essential has none, Technicoil five).

According to Daily Oil Bullet in records, Essential was recently running 30 service rigs and Technicoil two. All five of Technicoil’s drilling rigs were down.

— DAILY OIL BULLETIN

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67

Southern Alberta

Next five years look good, says ARC Financial report Outwardly, the financial health of the Canadian oil and gas industry looks positive over the next five years, says Peter Tertzakian, chief energy economist of ARC Financial Corp. in a new report commissioned in part by the Canadian Association of Petroleum Producers (CAPP).

“But aches, pains and vulnerabilities are still to be found beneath the collective veneer of multi-billion dollar financial statements—on the natural gas side of the industry, for example,” Tertzakian said.

“And the potential for economic trauma always looms large in this acutely capitalintense, competitive business.”

ARC’s research focused on analysis of the major trends and changes in capital flow in Canada’s largest industry over the past five years, with implications projected to 2015.

After 150 years of growth, the scale of what’s going on in the Canadian oil and gas industry is impressive by any world standard. From British Columbia to Newfoundland, the upstream oil and gas industry will generate an estimated $115 billion in annual revenue, $20 billion in royalties, land sales and taxes, and $50 billion of investment into infrastructure and jobs in 2011.

ARC’s detailed analysis and findings are published in a new repor t titled, Turmoil and Renewal: The Fiscal P ul se of the Canadian Upst ream Oil and Gas Industr y—A Five-Year Review and Outlook.

“All Canadians are stakeholders in the future of this business,” said Tertzakian, “And whether you are a corporate leader, policy-maker, investor or interested citizen, it is important to develop a broad understanding of the forces affecting Canada’s oil and gas industry.”

The reports says oil and gas companies are expected to generate more than $600 billion in sales over the next five years and that the industry’s revenue stream is becoming “oilier and oilier,” on a path to be 80 per cent reliant on oil by 2015. Only

advocacy— economic growth, energy security and environmental protection.

It recognizes that industry will continue to generate significant revenue and jobs, and highlights the ongoing importance of the industr y ’s contribution to the

“The report provides a broad context for CAPP’s ongoing focus on education, communication and 3E policy advocacy—economic growth, energy security and environmental protection.”

— David Collyer, President, CAPP

five years ago, the oil/gas percentage mix was a more balanced 55/45.

Embracing new technologies, processes and strategies will be paramount for companies seeking insulation from rising costs, environmental pressures and competitive threats, it adds.

The report also says Canada’s oil and gas industry will continues to grow and profits are likely to increase, but growing profits will not always translate into profitability. How well the industry copes with many internal and external challenges to profitability, including volatile commodity prices, will determine whether value will be created and whether an expected $55 billion a year will continue to be invested back into Canada over the course of the decade.

“The report provides a broad context for CAPP’s ongoing focus on education, communication and 3E policy

Canadian economy,” said CAPP president David Collyer.

The report assesses the diversity of businesses—including conventional oil, oilsands and natural gas—that comprise the overall upstream oil and gas sector.

At any given time, some segments of the industry may be more robust, while others may be facing challenges.

“Though the ARC projections suggest a generally positive outlook for the Canadian oil and gas industry, continued success is not assured throughout the forecast period or beyond,” said Collyer. “A strong focus on technology and innovation, a competitive fiscal and regulatory regime, diversification of markets, and continuous improvement in environmental and social performance are among the key success factors for our industry.

Continued growth in the oil and gas sector benefits all Canadians.”

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Saskatchewan

Bakken waterflood pilot success could drive further tight oil production

By Paul Wells

APR/10

APR/11

APR/10

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that recovery factors could materially improve.”

Waterflooding could also help unlock more resource in tighter areas of plays like the Cardium or Viking.

“We are beginning to see some producers test waterflood potential on their Cardium lands. Because the economics for the incremental reserve upside supports testing waterflood we could see producers test the waterflood concept on other oil resource—or tight rock—plays outside of the Cardium, Bakken and Lower Shaunavon,” Wood said.

Wood said that Dundee continues to believe that Crescent Point offers the potential for “significant upside through primary and secondary development” of its Bakken and Lower Shaunavon resource plays in Saskatchewan.

He noted that in a recent report, the firm highlighted the production and

injection response, various completion techniques, lateral length, well spacing and the design (i.e. the number of producer and injector wells) of each pilot.

“We believe Crescent Point currently has 11 waterflood pilots either running or constructed [eight in the Bakken and three in the Lower Shaunavon]. Based on our estimates, there are a total of 17 injectors running on the first five pilots, which keeps them on schedule for 36 by the end of the year,” Wood said.

According to the Dundee report, Crescent Point’s first Bakken pilot, comprised of four horizontal producers and one injector, began injecting water in the fourth quarter of 2006, with production response identified in the third quarter of 2008.

Wood said the first pilot saw a robust production response through the back part of 2008 and into much of 2009.

Since reaching peak production rates of about 550 barrels per day, production has declined about 25 per cent over the past two years.

“The significance of the waterflood program is underscored by the ability to sustainably grow production and improve recovery rates. In our opinion, this is supported by solid daily rates across the four producers [550 barrels per day, up from 50 to 100 barrels per day pre-injection] and cumulative production of about 500,000 barrels,” he said.

“Impressively, production response is also identified on wells outside of the defined pilot, which would further improve daily rates, cumulative volumes and capital efficiencies.”

The company’s second Bakken pilot saw water injection begin in the fourth quarter of 2009 and initial production response identified during the first quarter of 2010. Wood noted that although results do not look as robust as the first pilot,

With development drilling in full swing, Bakken producers are already advancing enhanced recovery schemes to get more oil.

Crescent Point Energy Corp.’s Viewfield Bakken waterflood pilot programs are showing positive initial results and could encourage other producers to attempt secondary recovery on other tight oil plays, says an industry analyst.

The prize is a big one, as many of western Canada’s tighter resource plays oil plays have large in-place volumes but relatively low recover y factors.

Secondary recovery has the potential of boosting the amount of oil recovered from the reservoirs while slowing the high decline rate typically encountered with multistage fracturing of tight oil formations.

Travis Wood, an analyst with Dundee Securities Ltd., says that while Crescent Point’s waterflood program is still in the early stages of development, the firm’s research indicates that “initial results support management ’s expectations SASKATCHEWAN WELL ACTIVITY

APR/10

APR/11

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326

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OIL & GAS INQUIRER • JUNE 2011

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Saskatchewan

they were compromised as the battery was struck by lightning last summer.

Crescent Point’s third Bakken waterflood pilot is also its largest to date and is comprised of six producers and five injector wells. Because water injection only commenced in the third quarter of last year, Wood said it is a bit early to compare production volumes with the earlier pilots.

Crescent Point is also testing waterflood at another of its Saskatchewan tight oil plays.

The company’s first Shaunavon pilot was actually initiated by Wave Energy Ltd. in early 2008 and Wood said it has been a “great source of information” for Crescent Point, which acquired the private company in 2009.

“Although production from this pilot does not appear to be all that exciting

compared with the first Bakken pilot, we do continue to believe that the waterflood will ultimately be a recovery-based story,” Wood said.

The company is still in the early and preliminary stages of Shaunavon waterflood pilots two through four.

Brad Hayes, president of Pet rel Robertson Consulting Ltd., says that all of the new and emerging tight oil plays, including the Cardium “need a good, hard look with respect to waterflooding and other EOR [enhanced oil recovery] techniques.”

“I believe that other producers will be looking at waterflooding as soon as they believe that Crescent Point is actually making economic returns on it,” he said. “If

the water can penetrate the reservoir sufficiently to maintain pressure in the formation, it should improve recovery efficiency.”

That said, Hayes acknowledges that waterflood could be more of an interim step in some tight plays and be used as a precursor to other EOR methods such as CO2 or other miscible flooding agents.

“That is probably the case for many reservoirs, but each one has to be evaluated in terms of its performance. I can see the possibility, for instance, that CO2 or a solvent might be more effective than water, but will it be sufficiently better to justify the greater costs? It all comes down to economics, as usual, and every project has to be assessed from that viewpoint,” he said.

Saskatchewan approves $1.24B carbon-capture project The Government of Saskatchewan has approved construction of the Boundary Dam Integrated Carbon Capture and Storage Demonstration Project—among

the first commercial-scale carbon capture and storage facilities in the world.

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JUNE 2011 • OIL & GAS INQUIRER

Saskatchewan

of taking more than 250,000 vehicles off Saskatchewan roads each year—in addition to capturing CO2 for enhanced oil recovery.

“SaskPower and its private-sector partners are leading the world in the development of a technology that will help to address climate change while ensuring that we can continue to use coal as an energy source for many years to come,” said Rob Norris, minister responsible for SaskPower.

Norris also thanked the federal government for providing $240 million to assist in the development of the project.

“This project will forge an environmentally sustainable path for the production of coal-fired electricity in Saskatchewan,” Norris said. “By proceeding with the carboncapture project at Boundary Dam, while continuing to add wind power and investigating other renewable energy options such as biomass, SaskPower is helping to build a greener future for Saskatchewan.”

SaskPower president Robert Watson noted that the Boundary Dam Integrated Carbon Capture and Storage Demonstration Project will provide a major economic stimulus for the Estevan area, in addition to benefits for the rest of the province.

“This will be one of the largest construction projects in the province’s history, creating hundreds of jobs and substantial business for companies in the province,” Watson said. “In particular, the continued operation of the Boundary Dam and Shand power stations, as well as related businesses servicing the coal industry, will provide long-term benefits to the Estevan region. The petroleum industry will also be a major beneficiary as it will use CO2

Ltd. will supply a state-of-the-art steam turbine—the first in the world designed to fully integrate a coal-fired power plant with carbon-capture technology.

Construction on the project will begin immediately, with operations commencing in 2014.

The new generating unit at Boundary Dam will have the capacity to generate 110 megawatts of electricity. In addition to capturing CO2 for enhanced oil recovery

The Boundary Dam Power Station is SaskPower’s largest generating facility, with six units and a combined generating capacity of 824 megawatts. captured at Boundary Dam to extract oil from mature fields.”

SaskPower has chosen SNC-Lavalin Group Inc., one of the leading engineering and construction companies in the world, to oversee detailed engineering, procurement and construction activities at the Boundary Dam project. Cansolv Technologies Inc., a wholly owned subsidiary of Shell Global Solutions International B.V., will supply the carbon capture process. Hitachi Canada

operations, the Boundary Dam project will also capture sulphur dioxide to be used in the production of sulphuric acid.

The Boundary Dam Power Station is SaskPower’s largest generating facility, with six units and a combined generating capacity of 824 megawatts. The company’s three coal-fired power plants account for approximately 50 per cent of its generating capacity of 3,513 megawatts.

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Northern Gateway a nation-building project, says Enbridge CEO

Photo: Joey Podlubny

By Elsie Ross

Enbridge is meeting fierce opposition to constructing its proposed Northern Gateway pipeline, but the project could add $270 billion to Canada's GDP over its life.

Enbridge Inc.’s proposed Northern Gateway project, which will provide access to Pacific Rim markets for Alberta crude oil, isn’t just another Alberta oil and gas project but a Canadian nation-building energy project, says the company’s top executive.

“A gateway to Pacific markets will have the same advantage for Canada in the 21st century that the St. Lawrence Seaway and key canals had for our country in the 19th and 20th centuries,” Patrick Daniel, president and chief executive officer, said in a speech to the Empire Club of Canada in Toronto. The seaway, he pointed out, “was and remains a massive and multi-generational undertaking that has cemented Canada’s trade connections to the Atlantic nations.”

Canada’s West Coast is the gateway to half the globe’s geography and nearly half of the word’s population, he said. “It is an essential driver of our future economic success.”

While Canada’s geographic position in relation to the United States is a unique advantage, it also makes Canada complacent, a captive supplier and a price taker, he said. “The United States likes—perhaps

even prefers—Canadian oil. It is secure and reliable,” said Daniel. “But they have other options, a world of global energy options. We don’t.”

Northern Gateway will open new markets for Canadian petroleum and will create thousands of construction and supplier jobs—and significant permanent employment right across Canada, said Daniel. “It will generate millions of dollars in benefits for the First Nations and other communities involved and hundreds of billions of dollars for a generation of Canadians.”

But the project will proceed “only if we can rise above the mounting clamour of a coalition of hard-line activists and their political allies committed to saying no to proposed projects and initiatives rather than seeking balanced, sustainable development and supporting continued prosperity for our entire country,” he said. “We say no to nuclear, we say no to coal, we say no to oil, we say no to fracturing wells to recover natural gas, but we say yes to light switches, cooked food, school buses and gas pedals.”

The proposed $5.5-billion project would deliver 525,000 barrels per day of

oilsands production to the port of Kitimat, B.C., where it would be loaded into large crude tankers bound for Asian markets. A parallel pipeline would deliver imported condensate to Alberta for use in the oilsands. The project, though, faces strong opposition from some First Nations and from environmental groups concerned about the risk presented by the tanker traffic through B.C. coastal waters.

In addition to bringing Canadian energy resources to the booming Pacific basin, Northern Gateway will deliver sustainable local and regional prosperity to northern British Columbia and Alberta and national economic advantage for all Canadians, the Toronto audience heard.

Access to premium markets will mean billions of dollars flowing into Canadian hands for decades, said Daniel.

According to independent estimates, over 30 years the project will add $270 billion to Canada’s gross domestic product (GDP)—about one-fifth of Canada’s total economic output in one year, he said. “It is literally a transformative injection of new economic opportunity to Canadians for a generation.”

That increase in GDP will be felt not only in Alberta or British Columbia, but also in Canada’s Industrial Heartland, in the steel mills and manufacturing centres and from heavy industry to high finance for a number of years.

Enbridge filed its regulatory application for Northern Gateway in May 2010.

Over the next 18 months, the Joint Review Panel with representatives appointed by the National Energy Board and the federal environment minister will consult with stakeholders and study the application to determine if the project will cause significant adverse effects on the environment and whether it is in the public interest.

Earlier this year, the Joint Review Panel determined that additional information on the design and risk assessment of the pipelines is required due to the difficult access and unique geographic location of the proposed project. Once the panel has received this information, a hearing order will be issued.

OIL & GAS INQUIRER • JUNE 2011

75

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Newfoundland enjoys production bump

Production was up offshore Newfoundland last year, but exploration success is needed to keep the oil flowing.

The Newfoundland and Labrador government reported higher oil production in 2010 thanks to an increase of over 22 per cent from the Hibernia field.

The province’s three producing offshore fields produced 100.7 million barrels of oil in 2010, 3.1 per cent higher than the previous year mainly as a result of new production from the AA Blocks at Hibernia and the start-up of the North Amethyst field at White Rose. Offshore fields produced an average 277,000 barrels per day, up from 268,000 barrels per day in 2009.

Oil production was originally forecast to decline by around 12 per cent to 86.4 million barrels. Production is expected to decline this year by 14.7 per cent to 85.9 million barrels.

Hibernia, including AA Blocks and the Hibernia South Extension (HSE) unit, is expected to produce 52.2 million barrels in 2011, 4.2 million fewer barrels than in 2010. Terra Nova is forecast to produce 13.8 million barrels, 11.1 million below 2010 due to natural declines and an assumed shutdown. Production for White Rose (including North Amethyst and West White Rose) is forecast at 19.9 million barrels, 500,000 barrels higher than in 2010.

Industry capital expenditures are expected to be about $1.7 billion in calendar 2011, up 34.6 per cent from 2010. Total capital expenditures were approximately $1.3 billion in 2010, up 13.8 per cent from 2009.

The development plan application for the offshore Hebron field is expected by the second quarter, government documents said, noting that preparation work at Bull Arm is expected to start during that period as well.

Hibernia produced 56.3 million barrels of oil in 2010, up 22.9 per cent over 2009.

The province had originally predicted that production at Hibernia would fall by 5.3 million to 40.6 million barrels in 2010.

Average monthly production rose to 4.7 million barrels last year from to 3.8 million barrels in 2009. The higher production was due to a successful drilling program, better-than-expected recoveries in several wells, decreased downtime compared to 2009 and the addition of production from the AA Blocks, the government stated in its budget documents.

First oil from the HSE unit—one of two areas comprising Hibernia South—is expected in the second quarter.

HSE comprises two areas: the A A Bloc k s w it h est imated recoverable reserves of 48 million barrels and the Hibernia HSE unit with estimated recoverable reserves of 167 million barrels. These developments are expected to extend the productive life of Hibernia by five to 10 years. Extraction from the AA Blocks began in late 2009 using direct drilling from the Hibernia production platform.

Turning to other offshore areas, the Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) estimates oil reserves and resources at Terra Nova to be 419 million barrels. This field produced 24.9 million barrels of oil in 2010, a decline of 4.1 million from the previous year. Average monthly production was 2.1 million barrels last year compared to 2.4 million barrels in 2009. Production in 2010 was below 2009 because of natural declines, a scheduled maintenance turnaround in the third quarter and the shutdown of some wells in the fourth quarter to address issues related to hydrogen sulphide, the province said. Production value in 2010 was about $2 billion.

Terra Nova’s operator, Suncor Energy Inc., is planning a 15-week scheduled shutdown of the Terra Nova floating production storage of offloading (FPSO) vessel to replace the injection swivel, budget documents stated. The shutdown may come in July but it could be deferred to 2012.

White Rose (including North Amethyst) produced 19.4 million barrels in 2010, down 3.4 million from 2009. Average monthly production was 1.6 million barrels in 2010 compared to 1.9 million the previous year. Production at White Rose was lower in 2010, reflecting interruptions associated with the North Amethyst tie-in and natural declines in the main field.

The C-NLOPB estimates oil reserves and resources at White Rose to be 373 million barrels. This estimate includes the main South Avalon pool, North Amethyst field, South White Rose extension, West Avalon pool, North Avalon pool and the Hibernia formation. North Amethyst, the first of three satellite areas to be tied back to the SeaRose FPSO, began production in May 2010.

OIL & GAS INQUIRER • JUNE 2011

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East Coast

Pilot well drilling in the West White Rose, the second of three satellite fields, started in August 2010.

Offshore exploration also continued in 2010. In total, 11 wells (exploration, delineation and development) were spudded.

The government listed several offshore exploration efforts in 2010, including: • I n February 2010, the C-NLOPB issued a significant discovery licence (SDL) to Statoil Canada Ltd. related to the Mizzen O-16 discover y well in the Flemish Pass Basin; • Suncor drilled the Ballicatters M-96 exploration well in the Jeanne d’Arc Basin in 2009. Drilling operations were suspended in October 2009 and no results have been announced to date.

Suncor re-entered the well (M-96Z) in November 2010 and is currently conducting sidetrack drilling operations; • Husky Energy Inc. drilled the exploration well Glenwood H-69 in exploration licence (EL) 1090 in March 2010. No results have been announced. During the summer of 2010, Husky completed a 3,005-kilometre 2-D seismic survey in the Sydney Basin and a 5,550-kilometre 2-D

seismic survey off the coast of Labrador in the Hopedale Basin; • Beginning in May 2010, Chevron Canada Limited drilled Lona O-55 exploration well in the Orphan Basin using the drill ship Stena Carron. The well has since been abandoned and no results have been announced. Chevron has submitted a project description to the C-NLOPB for 2-D and 3-D seismic programs in the region of the Orphan Knoll, showing continued interest in the area; • ConocoPhillips Canada and co-venture partner BHP Billiton completed drilling of the East Wolverine G-37 exploration well in the Laurentian Basin in April 2010 using the drill ship Stena Carron.

While no specific data was released, ConocoPhillips announced that the well was dry and has since relinquished five ELs in the area (1081R, 1082R, 1084, 1086R and 1087R) but retained two (1118 and 1119); • I n January 2011, Canadian Imperial Venture Corp. and Shoal Point Energy Inc. started drilling the onshore-to-offshore exploration well 3K-39 to test the hydrocarbon potential of the Green Point shale

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Drilling operations are ongoing; • I n January 2011, NWest Energy Inc. announced that it extended ELs 1097 and 1098 off the province’s west coast to Jan. 15, 2012, by posting a drilling deposit of $500,000 to the C-NLOPB; • In early 2011, Corridor Resources Inc. submitted plans to the C-NLOPB to drill its first offshore exploration well off Cape Anquille (Old Harry) sometime between mid2012 and early 2014, pending regulatory approval. The proposal to drill this well, which is located on the Newfoundland side of the Gulf of St. Lawrence, has triggered an environmental assessment process.

As of Jan. 31, 2011, there were 35 active exploratory licences, 50 SDLs and eight production licences in the province’s offshore area. Currently, there is approximately $995 million in exploration commitments (including new commitments in 2010) to be undertaken by interest owners.

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Photo: Joey Podlubny

Five per cent of global gas supply wasted

Nearly $20 billion in natural gas goes up the flare stack each year.

A new study released by the General Electric Company estimates that five per cent of annual natural gas production is wasted by burning or flaring each year.

T he st udy, Flare G a s Reduct ion: R e c e n t G l o b a l Tr e n d s a n d P o l i c y Considerations, says gas f laring emits 400 million metric tons of CO 2 annua l ly, t he sa me as 77 m i l lion auto mobiles, without producing useful heat or electricity. Worldwide, billions of cubic metres of natural gas are wasted annually, typically as a by-product of oil extraction.

The study finds that the technologies required for a solution exist today.

Depending on region, these may include power generation, gas re-injection, pipeline development and distributed energy solutions. Nearly $20 billion in wasted natural gas could be used to generate reliable, affordable electricity and yield billions of dollars per year in increased global economic output.

“Power generation, gas re-injection and distributed energy solutions are available today and can eliminate the wasteful

practice of burning unused gas. This fuel can be used to generate affordable electricity for the world’s homes and factories,” says Michael Farina, program manager at GE Energy, who wrote the white paper.

“With greater global attention and concerted effort, including partnerships,

world’s largest source of flare gas emissions, as much as 50 billion cubic metres of natural gas produced is wasted annually. If half of this f lare gas was captured and sold at prevailing domestic prices in Russia, the economic opportunity may exceed US$2 billion, says the report.

Although Nigeria has reduced flare gas emissions by 28 per cent from 2000 levels, the country’s oil industry still wastes 15 billion cubic metres of natural gas every year, adds the report.

While nearly half of the population has no access to electricit y, the countr y spends nearly $13 billion per year on diesel-powered generation and perhaps 10 gigawatts of potential electricity is f lared away. Successful capture and f lare gas utilization could potentially triple per capita electricity consumption for this nation of 155 million people.

E lsewhere i n West A f r ica, A ngola, Equatorial Guinea, Gabon, Congo and Cameroon collectively waste about 10 billion cubic metres of natural gas every year. Low natural gas prices and higher costs related to capturing flare gas in the Middle East inadvertently encourage the wasteful burning of unused gas.

“Making better use of vented and flared gas is a tremendous opportunity.

“Making better use of vented and flared gas is a tremendous opportunity. It will help slow global warming while also saving scarce natural resources.”

— David Victor, Director, Laboratory on International Law & Regulation, University of California, San Diego

sound policy and innovative technologies, large-scale gas flaring could be largely eliminated in as little as five years. It’s a win-win outcome.”

T he report prov ides a region-byregion analysis of gas f laring trends.

It points to the Russian Federation as one major offender. Within the Russian Federat ion, by some mea su res t he

It will help slow global warming while also saving scarce natural resources. While this issue has been on the radar screen for some time, many countries still waste massive amounts of gas through flaring and venting,” says David Victor, director of the Laboratory on International Law & Regulation at the University of California, San Diego.

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onthe

JOB Careers in the Oilpatch

Roy McKnight Age: 44 Title: Manager, industry initiatives Company: Enform Location: Calgary Years in Position: Just over 2.5

Education: • Athabasca University Bachelor of General Studies Arts and Sciences • University of Alberta Supervisory Development Citation

• University of Alberta Occupational Health and Safety Certificate • University of Leicester M.Sc. in Health and Safety Management

What do you do as a manager of industry initiatives?

writing at such a high level they can’t understand it, then we’ve missed

Industry initiates a project and brings it to Enform, where it comes

the mark. It has to be quite practical, and organizations have to be able

to my department to ask how we can all work together to solve it.

to take that information and apply it to their particular situations.

Typically, it’s a challenge that’s common across the industry, and we look at it from various angles to find solutions. Once we have a pro-

Do high and low production cycles have different effects on the

ject that needs to be addressed, we call for volunteers from across

industry’s safety culture?

the industry to sit on some form of steering or working committee.

The industry maintains the long view. The difficult part is when we’re going through a really high cycle and we’re hiring too fast.

What led you into occupational health and safety as a profession?

When things are stable, you can take the time to hire the right

In the early 1990s, I was working for a small company as a foreman

people and train them at a pace they can handle. And so when we

with a crew of 25-50 people. We did all kinds of oilfield and forestry

accelerate really, really rapidly, that’s when we have problems.

work. My boss said he needed a health, safety, environment and quality person, and he looked over at me and said, ‘You can do it.’ I

How do you measure if your work is having a positive impact on

had an English Arts degree and he knew I could write—developing

the industry?

practices and procedures is a big part of health and safety. I said,

What I look for are organizations that actually make health and

‘I’ll take the job, but you’ll have to train me.’ He sent me to university

safety activities part of the way they operate. Rather than count the

to take the OHS [Occupational Health and Safety] program at the

number of people injured, let’s look at how well we’re investigating

University of Alberta. So it was kind of by fluke.

our incidents. Are we learning from them? Are we applying corrective action, and are we preventing these incidents from happening

Has your experience in the field influenced how you do your job?

the future? The other way is just engaging with the employees. If

Having the field experience helps me understand how I have to

people are actually making safety part of their decision making

approach a particular challenge if the solution is going to have a fairly

when it comes to doing the work, then you’re really getting some-

broad impact. We always have to keep in mind the field workers. If we’re

where. You’re making an organization that is both safe and produc-

crafting a policy, procedure, document or training course and we’re

tive at the same time.

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TOOLS

OF THE TRADE A LOOK AT NEW TECHNOLOGIES

A component of the FlatPak coiled tubing system.

Installing a new hydraulic PCP system.

The HSPCP wellhead and hydraulic system.

Hydraulic Progressive Cavity Pump System Why did you develop the Hydraulic Progressive Cavity Pump System?

We developed this technology in response to an industry request to eliminate conventional rods and tubing and the surface drive head when functioning a PCP [progressive cavity pump] due to the numerous interventions operators have experienced from the wear and tear associated with this mechanical drive system. With more and more horizontal wells now being drilled both to recover heavy and light crude oil, our system is able to convey the progressive cavity pump “around the corner” in the heel of a horizontal well without the typical mechanical wear while increasing the production rate and amount of recoverable oil from the reservoir by drawing the reservoir pressure down to its minimum.

What’s unique about the system?

This system is unique as it is conveyed via a FlatPak coiled tubing system with the PCP actuated hydraulically. Incorporated in the umbilical used to convey and function our downhole driver are: • Two coiled tubing lines to complete the hydraulic circuit to drive the downhole rotary motor; • One coiled tubing line to receive production fluids to surface; • A capillary to inject chemical or viscosity reducer to help heavy oil flow to surface; • Electric conductors used in conjunction with downhole sensors and surface memory or SCADA to record pump intake and discharge pressures and temperature.

The FlatPak is connected to the hydraulic driver (containing a motor, seal assembly and wiper assembly), which in turn is connected the pump rotor. A short rod string is incorporated to remove any eccentric motion.

Is it field-proven?

We commenced production from two cold heavy oil wells located in Lloydminster on Feb. 25, 2011, and the wells quickly stabilized. Discharge pressures are operating at 1200 and 2000 psi [pounds per square inch], which is not tasking the pump good to 3,000 psi on a continuous basis. We have completed comprehensive testing of our system in our shop offering us data used in concert with the surface flow meter and pressure gauges to calculate torque. We estimate that the two systems currently deployed require under 200 footpounds of torque with the driver capable of delivering about 700 foot-pounds on a continuous basis.

In summary, we are hydraulically moving a typical Lloydminster volume of very heavy oil up a 1.5-inch ID tubular from 85 degrees in the heel of horizontal wells.

We are monitoring pressure and temperature with the digital sensors and surface recorders so that we can optimize production without pump off. We also incorporate a capillary tube into the FlatPak enabling the operator to inject friction reducers, de-waxing, descaling or sand suspension chemicals as he sees fit. We are now designing the second generation of our HSPCP system that will get us into smaller casing environments. In addition, we have designed a thru-tubing solution should the operator find this beneficial.

Answered by Scott Kiser, Business Development, CJS Coiled Tubing Supply Ltd.

OIL & GAS INQUIRER • JUNE 2011

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