Oil & Gas Inquirer September 2012

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FEVER incremenTal improvemenTS in Thermal TechnologieS drive in SiTu oilSandS growTh The oTher SaSkaTchewan oil boom

Production quietly builds in the shaunavon Play in the southwest

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FEATURES

1

21

2

Steam fever

Pushing production

thermal oilsands production booms through uncertainty

thermal oilsands operators expand technological toolbox to drive growth

By Pat Roche and Lynda Harrison

By Darrell Stonehouse

Saskatchewan's other oil boom

Frac sand storage

the Shaunavon play is building momentum

By Darrell Stonehouse

GENERAL NEWS

35 uncertainty plagues drilling expectations

By Paul Wells

REGIONAL NEWS

41 British Columbia

On-site warehousing

57 Central Alberta Duvernay shows promise,

LNG exports needed to make Liard Basin gas viable

say producers

By Richard Macedo

By Richard Macedo

45 Northwestern Alberta

63 Southern Alberta Ziff forecasting further drop in

Celtic invests in NGL infrastructure

gas prices

for Duvernay gas

51 Northeastern Alberta Oilsands operators

By Elsie Ross

69 Saskatchewan

managing differential

Climate change a hot issue in

By Lynda Harrison

Saskatchewan

Dining facilities

TECHNOLOGY NEWS

73 CCeMC announces $46 million for new carbon and clean technology efforts

IN EVERY ISSUE

10 Stats at a Glance 78 Political Cartoon

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Editor’s Note

Vol. 24 No. 7 EDITORIAL eDiTor

Darrell Stonehouse | dstonehouse@junewarren-nickles.com

Darrell Stonehouse | dstonehouse@junewarren-nickles.com ConTriBuTing WriTerS

Tough times for gas producers

Lynda Harrison, Richard Macedo, Pat Roche, Elsie Ross, Paul Wells eDiTorial aSSiSTanCe Manager

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The bad news continues for natural gas producers going into the winter of 2012-13.

Ziff Energy Group is the latest to forecast no end in sight to the current glut of natural gas across North America, and predicts prices will reach a nadir this fall as storage facilities reach capacity.

“The real price in September and October, I think, will be just downright brutal for the producers, and that’s very unfortunate, but you need to be in supply-demand balance,” said Bill Gwozd, vice-president of gas services for Ziff Energy.

Ziff predicts the real price for gas this fall could reach below $1 per thousand cubic feet on some days as supply of gas continues to far outstrip demand across the continent.

The analysts believe up to a quarter of production capacity could be shut-in this winter in response to low prices.

In a report, Ziff says U.S. gas rig counts would have to drop to a level below 400 rigs over the next few years before gas production will come into line with demand.

The problem is the high productivity of shale gas wells. Fewer wells need to be drilled to have a major impact on supply. In western Canada, drilling 1,000 conventional wells will add just over 100 million cubic feet per day of gas production, but in shale plays such as Horn River the same number of wells will add nearly five billion cubic feet per day of production, according to a Ziff analysis.

Gas producers have been targeting liquids rich formations as a means to stay profitable. Ziff says this strategy, while effective in the short term, is not sustainable as there is already downward price pressure on liquids in some markets.

Canadian operators also face the reality that their major export market to the United States is drying up as American supply displaces Canadian production. In the future, U.S. production may also compete for the eastern Canadian market.

It looks like natural gas markets in Canada will remain in the tank until LNG export facilities taking gas from the West Coast to Asia come on stream. And those facilities keep getting pushed further and further into the future. There are rumours the Kitimat LNG terminal won’t be operational until 2017 at the earliest. And it is believed the next major export facility, being constructed by Shell Canada Limited and its partners, won’t be ready until 2019.

Until then the huge supplies of gas in the Horn River and Liard Basin will remain in the ground. And further compounding the supply picture is the Duvernay in Alberta. Early drilling results in the play covering much of central to northwestern Alberta indicate it could be another giant like the Horn River. If it proves out, western Canada could be looking at a gas glut for decades.

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N E X T

I S S U E

October 2012 our annual state-of-the-industry report on the oilfield hauling sector and a review of shale and tight gas plays in northeastern B.C.

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MINI B&W FSC LOGO oil & gaS inQuirer • SEPTEMBER 2012

9

STATS AT A GLANCE

Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin

MONTH

OIL

Jul 2011 Aug 2011 Sep 2011

105 452 1,02

Oct 2011 Nov 2011 Dec 2011

GAS

OIL

Jul 2011 Aug 2011 Sep 2011

29 922 1,44

9 262 445

0  0

Oct 2011 Nov 2011 Dec 2011

1,153 1,10 9

35 50 55

1 1 1

Jan 2012 Feb 2012 Mar 2012

12 3 95

1 2 

Apr 2012 Jun 2012 Jul 2012

T O TA L

43 13 35

9 93 146

2 2 1,1

626 55 56

259 241 300

19 36 2

Jan 2012 Feb 2012 Mar 2012

215 491 515

131 1 14

Apr 2012 Jun 2012 Jul 2012

403 205 34

141 12 46

GAS

D RY

SERVICE

T O TA L

15 2 24

 0 155

498 1,292 2,072

321 331 359

20 2 2

49 42 115

1,543 1,570 1,489

419 46 996

190 244 10

15 21 33

31 52 66

655 1,153 1,275

60 36 660

192 25 92

31 40 16

15  105

988 449 873

Wells Drilled in British Columbia

Saskatchewan Completions

Source: B.C. oil and gas Commission

Source: Daily Oil Bulletin

MONTH

WELLS DRILLED

C U M U L AT I V E *

MONTH

OIL

GAS

OTHER

TOTAL

Jul 2011 Aug 2011 Sep 2011

56 40 92

479 519 611

Jul 2011 Aug 2011 Sep 2011

15 413 352

5 2 4

3 13 29

1 2 

Oct 2011 Nov 2011 Dec 2011

35 92 58

646 738 796

Oct 2011 Nov 2011 Dec 2011

45 524 332

29 4 4

46 32 61

2 0 

Jan 2012 Feb 2012 Mar 2012

53 66 39

53 119 158

Jan 2012 Feb 2012 Mar 2012

142 296 414

10 6 0

 20 40

10 22 

Apr 2012 Jun 2012 Jul 2012

86 13 57

244 334 401

Apr 2012 Jun 2012 Jul 2012

12 144 232

0 0 0

49 10 16

221 1 2

*From year to date * from year to date

10

MONTH

OTHER

SEPTEMBER 2012 • oil & gaS inQuirer

FAST NUMBERS





BakerHughes u.S. Gas rig Count aug. 2012

BakerHughes u.S. Gas rig Count oct. 2011

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada, august 10, 2012 Source: Rig Locator

alberta, august 14, 2012 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

(per cent of total)

Western Canada Alberta

AC T I V E

OIL WELLS

Alberta

July 12

GAS WELLS July 11

July 12

July 11

24

331



43%

Northwestern Alberta

1

23

2

3

British Columbia

35

19



65%

Northeastern Alberta

6

10

0

0

Manitoba

1

9

2

65%

Central Alberta

16

6

5

10

Saskatchewan

3

50

1

62%

Southern Alberta

31

15

4

3

2

0

1

%

TOTAL



115



51

WC TOTALS

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada, august 10, 2012 Source: Rig Locator

alberta, august 14, 2012 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

(per cent of total)

Western Canada Alberta

AC T I V E

C OA L B E D M E T H A N E

Alberta

July 12

July 11

BITUMEN WELLS July 12

July 11

39

33

2

50%

Northwestern Alberta

0

0

14

4

9

1

2

33%

Northeastern Alberta

0

0

6

9

19

2

21

90%

Central Alberta

0

2



2

Saskatchewan

153

50

203

75%

Southern Alberta

1

1

0

0

WC TOTALS

0



1,01

%

TOTAL

0

3

1

40

British Columbia

Manitoba

oil & gaS inQuirer • SEPTEMBER 2012

11

437991 City of Grande Prairie full page 路 fp feature

Feature

Steam

FEVER tHerMaL OILSaNDS PrODuCtION BOOMS tHrOuGH uNCertaINtY By pat roche and lynda Harrison Western Canada’s conventional oil and gas industry is stalling due to uncertainty about commodity prices, but it’s full steam ahead for Alberta’s thermal oil sector.

Even at today’s oil prices, new oilsands projects would be profitable, a panel of producers told the TD Securities Calgary Energy Conference.

The projects Cenovus Energy Inc. is building— Narrows Lake, Grand Rapids, Telephone Lake, and expansions at Foster Creek and Christina Lake—have estimated supply costs of $35–$45 per barrel, said Harbir Chhina, Cenovus’ executive vice-president of oilsands.

oil & gaS inQuirer • SEPTEMBER 2012

13

Feature “So even at these prices or even if they drop, we’re good to go,” said Chhina.

The big concern facing the industry is higher capital costs, said Chhina. The company still expects to see costs escalate this year; however, so far they have only stabilized, he added.

Bart Demosky, chief financial officer of Suncor Energy Inc., said his company’s plans are based on $85 oil. The company tries to use very conservative assumptions around price differentials, and it factors in inflation.

Considering today’s differentials, investment decisions depend on the assets a company has surrounding its bitumen production, said Demosky.

Project costs have not decreased since about the mid-1970s, and Imperial Oil Limited does not expect they will in the future, said Bruce March, chairman, president and chief executive officer.

“We can find ways to optimize, to build it better, to save on infrastructure and things like that, but by and large costs are going to keep continuing to rise,” said March.

Imperial does not count on any margin improvement from any of its downstream assets and every investment decision stands on its own, tested on an upstream basis alone, he said.

His company has the same long-term view Suncor does, he added. “As long as

ConocoPhillips is investing nearly $100 million per year in oilsands technology, conducting research at three laboratory facilities including one in Calgary, he told the conference.

A lthough it keeps a low profile, Canadian Natural Resources Limited (CNRL) is Canada’s biggest oil and gas producer. It is also a major thermal producer. In April, the most recent month for which public figures are available, CNRL’s steam-assisted oil production averaged 89,608 barrels per day. The company plans to add about 40,000 barrels per day of thermal oil capacity every two to three years.

“Without the benefit of either having upgrading assets or some form of downstream integration it could be challenging,” he said. “That’s certainly not our position. We’re virtually 100 per cent integrated, so we’re looking for ward to capturing all of that $30 price differential right now, and we think over the next five to seven years we’ve got a pretty unique and distinct advantage to be able to take advantage of volatility in the markets and have a higher profitability as a result.”

14

SEPTEMBER 2012 • oil & gaS inQuirer

we’ve got a good-quality resource base, can execute a project in a timely nature and it looks like it provides a decent return for shareholders, we’ll go ahead through the business cycle. That’s been our history for some time,” said March.

Oilsands projects last 30–50 years, noted Nicholas Olds, senior vice-president of oilsands at ConocoPhillips Canada.

His company plans to continue investing in Surmont Phase 2, now under construction and aiming for first steam in 2014 and first production in 2015, said Olds.

Construction of the steam plant for CNRL’s Kirby South Phase 1 steam assisted gravity drainage (SAGD) project is to start this summer.

The project is on track to start steaming in 2013 with production ramping up throughout 2014, said vice-chairman John Langille.

The Kirby North Phase 1 that is slated to come on stream in 2016, and the Grouse SAGD development in 2017 will follow that.

In all, CNRL has 500,000 barrels per day of thermal oil developments on its books.

A relative newcomer to the thermal oil business, Devon Canada Corporation

Photo: Joey Podlubny

thermal oilsands projects are being built for the long term, making current pricing only a minor factor in building decisions.

Feature brought its first commercial SAGD project, Jackfish 1, on stream in January 2008.

Jackfi sh 1 has been one of Alberta’s most successful thermal efforts with production averaging 97 per cent of the design capacity of 35,000 barrels per day through last year, said Chris Seasons, president of Devon Canada.

Jackfish 2, which came on stream about a year ago, is currently producing 23,000 barrels per day, and is continuing to ramp up to 35,000 barrels per day, Seasons said.

“Five years ago, we had no thermal heav y oil production. Today we’re at roughly 55,000 barrels a day [before royalties],” he said. Devon Canada expects its Alberta thermal oil output to reach the 150,000–175,000-barrel-per-day range (after royalties) by the end of the decade.

Jac k f i sh 3 received reg u lator y approval last September. Construction started in January and is more than onethird completed, Seasons added.

At Pike, Devon’s 50/50 joint venture with BP Canada Energy Group ULC, a regulatory application was fi led last month for a three-phase, 105,000-barrel-per-day SAGD project. First oil is slated for late 2016 at a cost of $3.8 billion.

In July, Devon applied for Walleye, a 9,000-barrel-per-day SAGD project slated to start producing in 2016.

In the longer term, Devon has one more area to develop at Jackfish, called Jackfi sh East, which is expected to yield 20,000–25,000 barrels per day.

Nexen Inc.’s troubled Long Lake SAGD projec t i s f i na l ly beg i n n i ng to build momentum. Long Lake was designed to produce up to 72,000 barrels of bitumen per day when it came on stream a few years ago, but output has never exceeded about half that level, according to public data. To remedy the situation, Nexen is drilling an extra 60 SAGD well pairs.

“A third of those are already started to ramp up today. For the remaining twothirds, we’re preparing roads and drilling pads for the drilling program that will take place next winter. And then we’ll start to bring them on stream in the latter part of next year and into the early part of 2014,” said Kevin Reinhart, Nexen’s interim president.

Nexen expects to spend $1 billion in additional capital to top up the Long Lake SAGD project’s productive capacity so it can match the upgrader’s design capacity of 72,000 barrels per day of bitumen

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oil & gaS inQuirer • SEPTEMBER 2012

15

With supply costs ranging from $35 to $45 per barrel, SaGD expansion projects are going full steam ahead.

feedstock, which would be converted to 60,000 barrels per day of synthetic crude oil.

Husky Energy Inc. is also ramping up output from Tucker, its SAGD project in the Clearwater formation. Tucker was supposed to ramp up to 30,000 barrels per day over 18–24 months, starting in November 2006. But by November 2007 it was only trickling out 1,100 barrels per day. Today, however, Tucker is producing nearly 10,000 barrels per day thanks to additional capital spending.

Meanwhile, Phase 1 of Husky’s flagship 60,000 -ba r rel-per- day Sun r ise SAGD project is slated to be on stream in 2014.

To date, with a couple of exceptions, the actual operation of commercialscale thermal projects has been left to senior producers. But many small producers are currently developing their own SAGD projects.

In May, BlackPearl Resources Inc. filed a regulatory application for a commercial development at its Blackrod property in the Athabasca oilsands region. Production would be from the lower Grand Rapids formation. The head of BlackPearl is John Festival and the same technical team that

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SEPTEMBER 2012 • oil & gaS inQuirer

www.MeridianMFG.com

Photo: Joey Podlubny

Feature

Feature grew BlackRock Ventures Inc. from zero to 16,000 barrels of oil per day before selling it to Shell for $2.4 billion in 2006.

BlackPearl’s Blackrod pilot is producing more than 400 barrels of oil per day after 10 months of steam injection and the instantaneous steam to oil ratio is less than three, said Festival. The pilot is to be expanded in the next six to eight months with a deeper well pair and more steamand water-handling capacity.

The 80,000-barrel-per-day Blackrod commercial project is to be built in three phases. The first is to be 20,000 barrels per day, followed by two phases of 30,000 barrels per day each. Festival estimated regulatory approval will take 18–24 months, and construction will take 12–18 months.

BlackPearl expects to start steam injection at Blackrod in 2015 and to hit peak production in 2016.

While commercial development will require external financing, BlackPearl’s current activities are funded from cash f low—much of it from Onion Lake in we st- cent ra l Sa sk atc hewa n, where c onve nt ion a l we l l s a r e pr o duc i ng 6,700 barrels a day, or 70 per cent of BlackPearl’s output.

Last year, BlackPearl applied for regulatory approval for a 12,000-barrel-perday SAGD project at Onion Lake.

A relatively new but well-financed small player is Sunshine Oilsands Ltd., headed by John Zahary, former president and chief executive officer of Harvest Operations Corp., which was bought by the Korea National Oil Corporation. Harvest said it would spend $215 million this year on construction of the 10,000-barrelper-day first phase of its BlackGold SAGD project, from which first oil is expected in 2014. Regulatory approval for BlackGold’s 20,000-barrel-per-day second phase is expected this year.

Asian investors own nearly half of Sunshine’s shares. They include Chinese state-owned refiner Sinopec (eight per cent), sovereign wealth fund China Investment Corp. (eight per cent), Bank of China (seven per cent), China Life Insurance (five per cent), Hong Kong private equity firm Cross-Strait Common Development Fund (three per cent) and Orient International Resources (10 per cent).

Thanks to those investors and a successful initial public offering, Sunshine has about $400 million in the bank, Zahary said.

Sunshine’s properties are West Ells, Thickwood and Legend Lake in the Pelican Lake area of northern Alberta.

Zahary said the 10,000-barrel-perday first phase of West Ells is under construction. Detailed engineering is 52 per cent complete, and procurement of the secondary equipment is 78 per cent complete. First production is slated for mid-2013.

In the longer term, he said West Ells has the potential to produce 100,000 barrels per day, while Thickwood and Legend Lake can each produce 50,000 barrels per day.

In the fourth quarter of 2011, Sunshine filed regulatory applications for 10,000 barrels per day fi rst phases at Legend and Thickwood. The company hopes to get regulatory approval in mid-2013.

At its Harper property, Sunshine is doing a pilot that it says has demonstrated oil mobility in response to steam injection in the Grosmont carbonate formation.

Sunshine estimates it has 371 million barrels of recoverable bitumen resource in carbonate rock at Harper, and another 974 million barrels of bitumen in carbonates at other properties.

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Feature

One of the newest thermal oil developers is Cavalier Energy Inc., which was created last December by Paramount Resources Ltd. Cavalier is headed by Will Roach, former head of UTS Energy Corporation. Paris-based Total SA bought most of UTS’s assets for $1.5 billion.

Cavalier has completed delineation for its first SAGD project in the Grand Rapids

lineage from UTS. SilverWillow began operations on April 4 after Canadian mining giant Teck Resources Limited bought SilverBirch Energy Corporation.

Teck said in an April press release it owns 8.7 per cent of SilverWillow. (After Total bought most of UTS, SilverBirch was formed from the remaining assets. Former UTS personnel joined either SilverBirch or

Unlike most small thermal oil developers, Ivanhoe Energy Inc. has its own upgrading technology. The company is also developing its own SAGD project at its Tamarack property. formation at Hoole. A regulatory application for the $450-million, 10,000-barrelper-day first phase is expected to be filed in the fourth quarter. Production would begin in 2016, pending regulatory approval.

The company, which is still wholly owned

by Paramount, plans to raise $450 million to $600 million by 2014 through equity and debt.

An even newer player is SilverWillow Energy Corporation, which also traces its

Cavalier.) Howard Lutley, who was vicepresident of mining and extraction at UTS, heads SilverWillow.

SilverWillow has drilled 72 core holes, conducted mini-frac tests and analyzed core samples to evaluate its property at Audet, which is northeast of existing SAGD developments northeast of Fort McMurray, Alta.

Lutley said this year’s work program includes engineering and design of

processing facilities and preparation of a regulatory application for a 12,000-barrelper-day SAGD project that would be on stream in 2016.

Unlike most small thermal oil developers, Ivanhoe Energy Inc. has its own upgrading technology. The company is also developing its own SAGD project at its Tamarack property near Fort McMurray. It hopes to have the 20,000-barrel-per-day first phase on stream by 2015.

Ivanhoe filed its Tamarack regulatory application with the Alberta Energy Resources Conservation Board (ERCB) in November 2010. The company just responded to the second round of ERCB supplementa l in for mat ion requests (SIRs), said Greg Phaneuf, Ivanhoe’s executive vice-president of corporate development, who believes Tamarack remains on track for regulatory approval by year-end.

“Our focus now—with the SIRs hopefully all...behind us—is to look at the stakeholders in the area and to ensure they are supporting the project,” Phaneuf said. “I’m pleased to say we’ve made some very good progress of late in terms of the stakeholders.”

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PUSHING PRODUCTION Thermal oilsands operators expand technological toolbox to drive growth

Photo: Joey Pudlubny

By Darrell Stonehouse

In 2011, production from Alberta’s oilsands passed the 1.6-millionbarrel-per-day mark. Of that total, 47 per cent, or 752,000 barrels per day, came from in situ operations.

Expect that number to climb in the near future. In situ production is projected to surpass mining as the engine of oilsands growth by 2016, and from there it’s full-steam ahead.

A combination of factors is driving growth in thermal oilsands operations. Producers are applying new technologies to exploit more oil from existing operations, expanding operations, and venturing into new plays in the vast oilsands resources.

Fine-tuning SAGD MEG Energy Corp. is leveraging its existing operations to increase production using a suite of technologies it calls RISER.

The suite of technologies comprising RISER incorporates infill wells, non-condensable gas (NCG) injection to maintain reservoir pressure, and a variety of related proprietary processes.

“These are relatively low-capital, high-return initiatives, which not only support increased production with shorter lead times, but should also help drive our operating costs even lower,” said Bill McCaff rey, MEG’s president and chief executive officer.

MEG is spending an additional $185 million this year on RISER at its in situ oilsands facilities at Christina Lake, while a recent evaluation increases its total proved reserves by 70 per cent over the company’s previous evaluation, to 1.2 billion barrels of bitumen.

RISER boosts the company’s production target from Christina Lake Phases 1, 2 and 2B to approximately 80,000 barrels per day at the end of 2014 or early 2015, from the previous target of 60,000 barrels per day. oil & gaS inQuirer • SEPTEMBER 2012

21

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22

S E P T E M B E R 2 0 1 2 • OIL & GA S IN Q UIRER

Shell is using vertical steam drive technology at its Carmon Creek development in northwestern Alberta. It expects recovery of over 50 per cent of the bitumen.

The Narrows Lake approval included the option to use a combination of SAGD and solvent-aided process, which will be the first large-scale commercial project to use butane as a solvent, Brannan said. Detailed engineering is under way with sanctioning anticipated later this year.

The right technology for the resource Thermal operators are also focused on ensuring they are using the right technology to exploit the resource, given its formation. One example of this is Osum Oil Sands Corp.’s operations in Cold Lake.

Although cyclic steam stimulation (CSS) is the recovery process most often associated with the Clearwater formation in the Cold Lake oilsands region, Osum plans to use both SAGD and cyclic steam.

Alberta’s Energy Resources Conservation Board has started public hearings in Cold Lake to consider Osum’s application to develop its 45,000-barrel-per-day Taiga thermal bitumen extraction project.

Cold Lake has Canada’s longest history of large-scale thermal oil production. Imperial Oil Limited’s Cold Lake project has been on stream for more than 30 years and is currently producing roughly 160,000 barrels of bitumen a day. Osum says all companies in the Cold Lake area are currently producing roughly 340,000 barrels of oil a day, or about 10 per cent of Canada’s oil output.

Imperial’s massive thermal operation has used cyclic steam because shale layers within the portions of the Clearwater sands

Photo: Joey Podlubny

“For 2012, the implementation of these enhancement initiatives will support full-year production at the high end of our guidance of 26,000–28,000 barrels per day,” said McCaffrey.

“With broader deployment of the technology, we’ll be working on opportunities for ‘interphase growth’ between major expansion projects of 10–15 per cent per year, over the next several years.”

With fixed costs spread over higher production volumes, RISER is also expected to help further reduce non-energy operating costs per barrel once the program is fully implemented.

Capital costs for the incremental production growth are expected to range between $15,000 and $20,000 per barrel per day.

The RISER concept has been implemented in MEG’s Phase 1 area, McCaffrey said. NCG was introduced into the three existing well pairs and two infill wells were added.

Production from the pilot pattern increased to 2,900 barrels per day at a steam-oil ratio of 1.3 in the second quarter of this year, compared with production of 2,300 barrels per day at a steam-oil ratio of 2.7 in the second quarter of 2011.

Achieving low steam-oil ratios frees up steam for redeployment into new wells, further supporting higher production levels, McCaffrey noted.

MEG plans to implement RISER in Phases 1 and 2, prior to the start-up of Phase 3A, currently scheduled for 2016.

Over the next two years, MEG plans to drill up to 32 additional infill wells in the Phase 2 area and, subject to regulatory approval, introduce NCG injection on additional steam assisted gravity drainage (SAGD) well pairs.

To support RISER and to advance engineering and procurement for Christina Lake Phase 3A and related infrastructure, MEG plans to increase its 2012 capital budget to a total of $1.75 billion from the previous $1.37 billion.

Of the expanded 2012 capital program, $185 million is related to RISER, including nine new infill wells in the Phase 2 project area, nine additional SAGD well pairs, and engineering and facility modifications to ensure that the central water and oilhandling facilities can reliably accommodate increased volumes.

Cenovus Energy Inc. also has a number of improvements to its SAGD technologies under way.

At Telelphone Lake, Cenovus continues to progress the dewatering and expects to start water production and air injection in the next couple of months, said John Brannan, executive vice-president and chief operating officer. The pilot is designed to test the efficiency of removing the non-potable water sitting on top of the bitumen in the reservoir.

Prior to water removal, Cenovus thinks its steam-oil ratio will be in the range of 2.5, but if it is successful in removing the water, it should be able to further reduce the ratios, said Brannan.

“We are encouraged by what we have seen so far in our strat well drilling program at Telephone Lake, and we will continue to collect data from the pilot and additional wells we plan to drill over the next year,” he said. “Clearly, Telephone Lake will be an industry-leading project, with or without dewatering.”

Cenovus has received regulatory approval for Narrows Lake, which is jointly owned with ConocoPhillips Company. Narrows Lake is expected to have gross production capacity of 130,000 barrels per day and be developed in three phases. Groundwork for the initial phase of 45,000-barrel-per-day gross is expected to begin this fall, with project sanctioning from Cenovus and ConocoPhillips expected by the end of this year with an anticipated 2017 start-up.

Feature Imperial has commercially developed impede vertical permeability. This has prevented Imperial from using SAGD in those zones since SAGD requires effective vertical permeability so steam can rise and bitumen can drain down to production wells.

Two projects that are using SAGD in the Clearwater—Husky Energy Inc.’s Tucker and Royal Dutch Shell plc’s Hilda Lake/Orion— have struggled. According to the most recently available public data, in April Tucker was producing at roughly one-third of its 30,000-barrel-per-day design capacity and Orion, which Shell put on the auction block, was doing about half its 10,000-barrel-per-day capacity. However, all of the Clearwater shouldn’t be tarred with the same brush, according to Osum.

Most of the Clearwater reservoir that Osum plans to produce at Taiga has good vertical permeability and in those areas — and also in the Grand Rapids formation — Osum plans to use SAGD, said Rick Walsh, Osum’s chief operating officer.

CSS will be used on the portions of the Clearwater that have limited permeability, Walsh said during a question-and-answer session at last week’s TD Securities’ energy conference in Calgary.

Most of Osum’s Clearwater acreage “lends itself very well to SAGD because it’s laterally and vertically permeable. There is a portion of the lease that has more limited vertical permeability, and that is where you want to apply cyclic steam stimulation to kind of open up the rock a bit,” Walsh explained.

Osum hopes to get regulatory approval in the fourth quarter and to start construction and the drilling of well pairs for the 23,000-barrel-per-day first phase next year. First oil from Taiga is slated for 2016.

Husky Energy Inc. is taking thermal development into the heavy oil fields surrounding Lloydminster, and has said it made significant progress in the second quarter in repositioning its heavy oil business to more long-life thermal projects such as Pikes Peak South, Paradise Hill and Sandall, while major projects remain on budget and on schedule, during its second quarter report to shareholders.

During the second quarter, first oil was achieved ahead of schedule from Pikes Peak South with 8,000 barrels per day of capacity and Paradise Hill with 3,000 barrels per day of capacity—both expected to reach full volumes by the end of the year. During the quarter, the 3,500-barrel-per-day Sandall thermal development was sanctioned, with commissioning expected in 2014, and the company is in the preliminary stages of examining four additional Sandall projects, Asim Ghosh, president and chief executive officer, told a second-quarter results conference call.

“We’ll be developing these projects with our proven modular approach, which will give us cost and operational efficiencies,” said Ghosh.

The Rush Lake commercial project design, estimated at 8,000 barrels per day, is continuing based on production performance from the single-well-pair pilot.

The initial planning process is ongoing for three additional commercial thermal projects that are in the early stages of reservoir evaluation and concept selection.

Husky also has four solvent enhanced oil recovery pilots in the Lloydminster region.

Grizzly Oil Sands ULC is developing technology to enable it to target smaller oilsands deposits. Grizzly says its Advanced Relocatable Modular Standardized (ARMS) development model requires half as much acreage for a central plant as a conventional SAGD operation. It says ARMS will allow smaller bitumen pools to be produced, and it will cut in half the time it takes to extract all the recoverable bitumen from larger pools.

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23

Feature

The company’s first bitumen production is slated to start next year from its 10,000–12,000-barrel-per-day Algar Lake SAGD project. Construction of this first phase, for which it has budgeted $220 million, is in full swing. Grizzly expects to file a regulatory application in the third quarter of this year for its proposed 10,000-barrel-per-day Thickwood Hills SAGD project.

In the Peace R iver oilsands region, Shell is testing a unique thermal technology at its Carmon Creek play. The company hopes to develop the play in two 40,000-barrel-perday phases.

Carmon Creek will be unique among Alberta’s large-scale thermal projects in that it will use a vertical steam drive (VSD)—not the SAGD and pure CSS processes other thermal producers are using.

Shell had been trying to figure out how to do a large-scale commercial development in the Peace River area since the 1960s.

It opted for vertical steam drive after testing everything but the kitchen sink—including in-situ combustion in 1965.

The prize is a massive bitumen resource trapped in the Bluesky formation, which has proved to be a challenging reservoir. After decades of experimentation, a re-evaluation of the shale baffles within the Bluesky found the shale bedding was much more extensive than previously thought.

24

S E P T E M B E R 2 0 1 2 • OIL & GA S IN Q UIRER

Multiple thin shale baffles greatly reduce effective vertical permeability, impeding the rise of steam and the gravity flow of bitumen, thereby eliminating any recovery technique that relies on gravity drainage.

Each VSD pattern would consist of six vertical production wells in a hexagonal pattern. Each pattern would cover 3.4 hectares within the Bluesky. A dedicated vertical steam injector would be drilled in the centre of the hexagon. The goal is to drive fluid horizontally from the steam injector well to the producer wells—without relying on gravity or vertical flow—and to operate at low pressures.

Production would start with one cyclic steam cycle in which steam would be injected in the six producer wells. Once the producer wells have been steam-soaked for one CSS cycle, the injection well will begin to inject steam continuously, pushing it horizontally towards the producing wells, reducing bitumen viscosity. The single CSS cycle would be repeated about every year or two during the expected 10-year life of each pattern.

Shell expects this alternating of vertical steam drive with CSS will result in a recovery factor of more than 50 per cent.

Unlocking the carbonates The carbonate play in north-central Alberta, with 400 billion barrels in place, is one of the biggest known undeveloped oil

Photo: Joey Podlubny

MEG is using its RISER concept to access bitumen left behind at its existing Christina Lake development.

Feature

resources in the world. But a group of producers is working feverishly to change this situation.

Laricina Energy Ltd. said in July it has made significant progress towards demonstrating that thermal extraction of bitumen from the Grosmont carbonate formation at Saleski is commercially possible. So far, the Saleski pilot has used horizontal SAGD well pairs with steam cycles in both the injector and producer wellbores.

“During the test cycle from our newly drilled well pair at Saleski, we achieved our greatest peak bitumen production rate to date of more than 1,200 barrels per day,” Glen Schmidt, Laricina’s president, said. “This is compared to our previous peak rate of more than 800 barrels per day achieved during the first quarter.”

“Although we are encouraged by these preliminary results, we note that the initial cycle was over a short time-period,” Schmidt cautioned. “Further and extended cycles are required to confi rm production performance as we apply what we have learned from previous cycles, and continue to employ a variety of systems and applications in startup and recovery to fully understand the Grosmont formation.”

As reported in the company’s fi rst-quarter results, the most recent well pair is the fourth to be drilled at the Saleski pilot and is the second targeting the “C” zone, hence it’s labelled “C2.”

The horizontal sections were drilled to only 450 metres to enhance early start-up by reducing the volume of steam needed for testing and to manage the overall steam volume available at the pilot. Laricina said the well pair was drilled to test a balanced pressure mud system and open-hole completion with the goal of enhancing steam-to-reservoir contact.

This is meant to advance the steam chamber development along the wellbore and optimize overall thermal bitumen production performance.

The first steam/production cycle for the C2 well-pair occurred throughout May and June. The company said the initial results from the fi rst cycle confi rm the improved drilling and stimulation techniques minimized drill-cutting losses and near-wellbore impairment that restricted fluid inflow, which was evident in the initial startup in the C1 and D1 well pairs last year where overbalanced drilling and a liner completion were used.

Laricina said C2 also demonstrated enhanced reservoir contact, evidenced by the increased steam volumes the company was able to inject and followed by excellent initial production rates.

“These results support both our confidence in the drilling techniques which we expect to use in the planned 10,700-barrelper-day Phase 1 commercial expansion at Saleski, and our goal to drive down the costs and improve performance of future well pairs,” the company said.

The third cycle for the C1 well pair also began in May of this year. Operational issues related to a water-disposal line break that was detected immediately and contained to the pilot site have affected early results from this cycle. Production for C1 was curtailed for about a week while the leak was investigated, contained and repaired. As a result, fluid production rates, drawdown on the reservoir, and subsequent bitumen production rates have been affected.

The disposal line has since been repaired and is back in service with production operations returned to normal. Laricina is monitoring production performance from C1 and estimates completing this cycle in late July or early August.

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oil & gaS inQuirer • SEPTEMBER 2012

25

Feature

In addition to demonstrating production performance from the C zone, Laricina continues to study the production performance from the D zone, the connectivity between the C and D zones, and the potential to extract bitumen from the C and D as one reservoir.

Additional testing is planned for the third quarter.

Laricina said SAGD production has been established in both the C and D zones demonstrating the high effective permeability in the reservoir.

The Saleski pilot was designed, and has thus far focused on, dual horizontal well SAGD using steam cycles for both the injector and producer wells in an effort to obtain reservoir fluid-flow information and an understanding of the permeability systems within the Grosmont.

“Through our work over the last year we have determined that early life start-up oil rates and steam-oil ratios are significantly improved when the well pairs were operated under an injectionand-production cycling process. Our testing and analysis of this to date shows a strong correlation to commercial single horizontal well cyclic steam stimulation, similar to existing commercial horizontal-well CSS projects,” the company said.

Laricina and its working-interest partner at Saleski believe that CSS is a suitable initial development strategy for the Grosmont and may also be an effective start-up method that supports continuous dual-well SAGD. It will continue to advance field-testing to better understand horizontal well CSS at Saleski.

Based on field performance and analysis, Laricina is evaluating incorporating CSS in its 10,700-barrel-per-day Phase 1 regulatory application. If it decides to do so, it could require an amendment to the regulatory application currently being reviewed which would affect the current schedule for approval and ultimate start-up.

Athabasca Oilsands Corp. is testing a different technology at its Dover West Carbonates play.

Situated 90 kilometres northwest of Fort McMurray, Athabasca’s Leduc carbonate trend—originally formed as a carbonate reef and characterized today by excellent porosity and permeability—lies below the company’s Dover West sands. Based upon GLJ Petroleum Consultant’s April 30, 2012, pro forma assessments, and employing SAGD production technology, Athabasca’s Leduc trend is estimated to contain 16.3 billion barrels of total petroleum initially in place and 2.8 billion barrels of contingent resource (best estimate).

Production from the company’s bitumen-rich Leduc carbonates at Dover West is forecasted to utilize the thermally assisted

gravity drainage (TAGD) production process. A proof-of-concept field test successfully delivered all of its objectives, confi rming that the company could effectively heat the reservoir and mobilize bitumen to a production well, paving the way to initiating the TAGD pilot/demonstration project.

The field test successfully mobilized bitumen at lower temperatures than those utilized in the SAGD production process. The field test also gathered data on the Leduc reservoir permeability and thermal conductivity. Finally, it demonstrated the reliability and performance of the heating cables.

The bitumen was mobilized at 70–90 degrees Celsius and field testing demonstrated that approximately 60–70 per cent of the bitumen, heated to greater than 80 degrees Celsius, was recovered during the production process. The heating cables were fully operational throughout the field test.

Data obtained during the field test has enabled Athabasca to model its proprietary production technology, and to simulate the performance of a commercial TAGD project in the Leduc carbonates.

The Leduc field testing indicates that effective reservoir permeability is considerably higher than previously anticipated.

Reservoir modelling based upon field testing illustrates that commercial scale wells heated to temperatures in the range of 120– 140 degrees Celsius should yield single-well production rates in the order of 1,000–2,000 barrels per day, depending on reservoir thickness.

Because the TAGD process does not require steam generation and water treatment facilities that are essential parts of SAGD projects, total capital exposure is reduced by approximately 50 per cent compared to a SAGD project. Accordingly, expected rates of return for a TAGD project will be in the order of approximately 5–10 per cent higher than for a comparably sized SAGD project.

Athabasca anticipates receiving regulatory approval for the TAGD pilot/demonstration project by year-end. Work continues on design and procurement of the project, and an innovative heater assembly facility is being constructed near Strathmore, Alta.

Pending regulatory approval, Athabasca plans to launch its TAGD pilot/demonstration project in 2013, with an initial two-yearlong drilling, construction and installation phase, followed by a production phase. The company anticipates achieving the objectives of the pilot/demonstration project within two years after start-up.

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Feature

SASKATCHEWAN’S oTHer OIL BOOM The Shaunavon play is building momentum

By Darrell Stonehouse

T

he oilfields surrounding the historic town of Shaunavon in southwest-

ern Saskatchewan have been producing medium-gravity crude oil since 1952.

Targeting the Upper Shaunavon and Roseray formations, by 2010 over 359 million barrels had been pulled out of the ground in the Swift Current area.

Since then, drilling has exploded in the area as the arrival of horizontal drilling and multistage fracturing technology proven in the Bakken play to the east has been adapted to target the tight Lower Shaunavon formation. Vertical well production from the Lower Shaunavon averaged about 10 barrels per day, making the play uneconomic. With horizontal drilling and multistage fracturing, wells have initial production of 100–250 barrels per day and settle in at around 60 barrels per day after the first year.

According to Saskatchewan government figures, Lower Shaunavon production averaged just 257 barrels per day in 2007. Production in mid-2011 had reached over 10,000 barrels per day, and that number is expected to keep growing.

At year-end 2010, there were over 130 discovered oil pools in the Shaunavon play. The National Energy Board (NEB) estimates two billion barrels of discovered oil in place. The NEB believes there is the potential for another 896 undiscovered oil pools and an additional 3.3 billion barrels of crude oil in place. Almost all that potential lies in the Lower Shaunavon. >

oil & gaS inQuirer • SEPTEMBER 2012

29

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Crescent Point Energy Corp. is the largest player in the Shaunavon, with over 800 sections of land in the play. Its combined production for all formations in the Shaunavon area is 18,500 barrels per day.

Company president and chief executive officer Scott Saxberg recently told shareholders the Lower Shaunavon is about three years behind the Bakken in development. But that development is about to pick up speed.

Crescent Point has a five-year plan in place to grow production in the play to 35,000 barrels of oil equivalent per day in the next five years. Longer term, the company has a risked drilling inventory of over 1,800 locations in the Lower Shaunavon. Fully developed, Crescent Point expects Lower Shaunavon production could peak at 126,770 barrels per day. To reach that plateau would require a capital investment of around $3.8 billion.

The company has also identified 250 risked drilling locations in the Upper Shaunavon, with the potential to produce 17,400 barrels per day. A $500-million investment will be required for the play to reach its potential.

As Crescent Point explores its Shaunavon lands, it continues to expand the boundaries of the play. In late 2011, the company 30

SEPTEMBER 2012 • oil & gaS inQuirer

announced it had drilled a series of step-out wells in the northern part of the play and added 150 million barrels in place to its resource tally. In the heart of the Shaunavon, Crescent Point and Cenovus Energy Inc. discovered another 150 million barrels through exploration drilling.

“In the southern part of the field we rediscovered an area of the Upper Shaunavon, a tight oil play drilled vertically in the past,” said Saxberg. “We have been drilling in the pool and believe there are 700 million barrels of oil in place. That’s one billion barrels in total for the three areas. Five or six years ago, this would have been the biggest oilfield discovered in 50 years, so it’s a pretty incredible amount of new oil.”

During fi rst quarter of 2012, the company participated in the drilling of 29 (23.9 net) oil wells in southwestern Saskatchewan, achieving a 100 per cent success rate. Of these wells, 18 (17.5 net) were drilled into the Lower Shaunavon zone, while 11 (6.4 net) were drilled into the Upper Shaunavon zone. The company plans to drill up to 91 net wells in the Shaunavon area in 2012 and to spend approximately $260 million, including approximately $50 million to expand facility infrastructure. Expanded facilities are expected to accommodate increased production in the area.

Photo: Pipeline News

Drilling in late 2011 expanded the oil in place in the upper and Lower Shaunavon plays by around one billion barrels. Crescent Point's Scott Saxberg said five or six years ago that would have been the largest field found in 50 years.

Feature

HORIZONTAL WELL LICENCES Source: The National Energy Board

250

Lower Shaunavon 200

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31

Crescent Point could ultimately spend as much as $4 billion developing the Shaunavon.

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SEPTEMBER 2012 • oil & gaS inQuirer

The company is also advancing its waterflood program. It is currently injecting water into six horizontal injection wells in its original four pressure-maintenance programs in the Lower Shaunavon zone. With the closing of the Wild Stream acquisition, Crescent Point gained a fi fth pressure-maintenance program in the Lower Shaunavon zone, which has been injecting water since October 2011. Crescent Point continues to be encouraged by results to date in all programs. Plans to convert up to four wells in the Upper Shaunavon zone to water injection wells in 2012 are also underway and are expected to bring the total number of injection wells in the play to 10 by year-end 2012.

During the quarter, approximately 110 k ilometres of pipeline were constructed to tie in wells. Plans to design and construct three additional batteries in 2012 to accommodate increased production have begun, and construction is expected to begin during the second and third quarters of 2012, with commissioning anticipated by fourth-quarter 2012. The company’s new gas plant is expected to be operational in second-quarter 2012.

C e nov u s i s a l so a la r ge lea se holde r i n t he L owe r Shaunavon, with 54 sections of land. Cenovus averaged 4,100 barrels of oil per day in the second quarter, almost 1.5 times higher than the same period a year earlier. Cenovus has 87 horizontal wells and one vertical well producing in the Lower Shaunavon.

In 2011, the company spent around $120 million drilling and building facilities in the play. It expects to spend that same amount for the next five years.

Photo: Pipeline News

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General News

Uncertainty plagues drilling expectations

By Paul Wells

Photo: Aaron Parker

Capital expenditure cuts by explorers and production companies have drilling companies worried.

Continued market unrest, lagging natural gas and volatile oil prices, a longer-thanhoped-for spring breakup and another wet spring has the western Canadian oilpatch bracing for uncertainty as 2012 continues to unfold.

A nd with some exploration and production companies already having announced substantial cuts to 2012 spending plans, this year’s industry drilling forecasts may soon be downgraded from previous expectations.

“One thing that we’re watching very closely is we have seen some analysts come out with some very difficult information for the industry to look at— they’ve been talking about depressed prices for the end of 2012 and going into 2013,” said Mark Scholz, president of the Canadian Association of Oilwell Drilling Contractors (CAODC).

Although Scholz says the recent rebound in crude oil prices to in and around the range of $87 per barrel West Texas Intermediate is a good sign, other factors in play could further pinch capital spending and drilling plans going forward.

“There is a tremendous amount of uncertainty in the market right now, and that uncertainty...may or may not affect projects coming into the fourth quarter,” he said.

“We have heard reports of there being up to a 20 per cent reduction in capital expenditures for the fourth quarter, which certainly isn’t good news for drillers and contractors.”

Gary Leach, executive director of the Small Explorers and Producers Association of Canada, agrees that there could be an overall pullback in drilling for the remainder of this year.

“The larger trend to watch will be the extent to which the usual recovery in drilling activity over the summer is moderated due to producers cutting spending as a result of uncertaint y caused by oil price weakness. Western Canadian drilling activ it y responds quickly to changes in the commodity price outlook,” he said.

“A number of junior and intermediate producers have already cut their previously announced capital spending for

this year, and if the uncertainty persists, despite the oil price uptick in the last couple of days, and if larger operators follow suit, then drilling activity will be negatively impacted.”

Leach noted that FirstEnergy Capital Corp.’s recent forecast calls for drilling activity this year that is well below the earlier forecasts issued by the Petroleum Services Association of Canada (PSAC) and CAODC. Mark Salkeld, PSAC president and chief executive officer, said a long spring breakup and wet weather in May and June has already compromised the capital plans of some producers.

“To a certain degree it was like last year, although I don’t think it was wet in some areas. Southern Saskatchewan was pretty severe last year and again this year, which is slowing us down—although we’re not getting the same degree of flooding—but it’s definitely affecting our ability to get on the road and to locations off the main roads,” he said, adding that PSAC would release its updated drilling forecast the following week.

“The Bakken, without a doubt, has been affected. Parts of central Alberta are still too wet to get the rigs out; the Cardium in the Pembina area was also affected, as well as the Duvernay a little bit.”

Having said that, Salkeld noted that there are certain producers who will be less affected as they are using multiwell pads.

“They can get those pads built, get the wells drilled and get the equipment on location to drill and complete, which is extending our season to a certain degree,” he said.

“But that’s not the case with all the producers. You still have a lot of small explorers that have just one-off wells here and there and road bans, and the weather affects them more.”

Leach added that while parts of western Canada have been experiencing an extended period of wet weather this OIL & GA S IN Q UIRER • S E P T E M B E R 2 0 1 2

35

General News

spring, the rig count is “virtually the same as 12 months ago and not entirely unexpected” for this time of year.

“There may be some localized challenges rescheduling rig moves, and some smaller operators may be more impacted by this exercise than larger players as drilling activity climbs higher over the summer,” he said.

CAODC’s Scholz said that overall activity levels are off to a slower start this summer because of rain and the prolonged spring breakup. “ T he la st t i me I looked at t he numbers, we were sit ting at about 37 per cent utilization this week and that, of course, is better than the prior

couple of weeks when we were sitting at the very low 20s and in fact sometimes dipping below that to the 15–18 per cent range,” he said.

“Usually in our industry we can expect to have your typical spring breakup, but the problem is that this one lasted longer than a lot of us would have liked.”

Shippers want pipeline certainty Many oil and gas producers are increasingly looking for certainty when it comes to pipeline transportation or gas processing and are prepared to sign long-term contracts to ensure they can access the service when they need it, an energy conference heard in July.

While shippers once may have seen a pipeline take-or-pay commitment as a liability, now it’s often seen as an opportunity to mitigate the risk associated with being constrained in access to transportation when it is needed,

• • • • • • • • • • • • •

Paul Miller, senior vice-president of oil pipelines for TransCanada Corporation, told the TD Securities Calgary Energy Conference. “There’s nothing worse than having stranded production or a dry refi nery.”

TransCanada is act ually seeing changes in the marketplace where producers and refiners want to sign up for capacity because they want to put all their risk in upstream production and downstream refining, he said. They are prepared to hold that capacity day in and day out and

pay the fi xed toll because it is small relative to the capital investment.

“The fundamental difference that is happening is that our customers are much more confident in the fact that the resource is there, and as a result they are more willing to commit to us long term,” noted Bob Michaleski, Pembina Pipeline Corporation's chief executive officer. His company has deep-cut gas extraction facilities under development at Saturn and Resthaven that are fully contracted for seven and 15 years, respectively.

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SEPTEMBER 2012 • oil & gaS inQuirer

General News

W he n K i nde r Mor g a n C a n ad a recently held an open season for its Trans Mountain expansion, it offered multipleterm contracts, said Ian Anderson, company president. “Every shipper that signed up took the maximum term of 20 years; that spoke loudly,” he said.

For the Trans Mountain shippers that Anderson has talked to, the No. 1 priority is optionality. “What shippers are recognizing is that they can’t assume anymore that the next pipeline to the next market is built easily and in the time frame that they want,” he said. Shippers will get multiple pipeline alternatives to multiple markets and virtually support all of them to some degree so that when production comes on towards the end of this decade, they are going to have access to the markets where they can get the best price, Anderson suggested.

Jeff Marchant, vice-president of transportation for Inter Pipeline Fund, agreed that shippers are primarily interested in optionality and certainty. “Schedule is a big thing, and when we went on the Polaris [diluent] pipeline [to sign up shippers] one of the most attractive features

of that line is that it was already in the ground,” he said.

While Inter Pipeline has cost-ofservice–type contracts on its gathering pipelines, they are somewhat modified.

For example, in the contracts on the Polaris pipeline in the Cold Lake area it also is able to offer firm tolling service over the long term. “Shippers definitely value that,” said Marchant.

As Inter Pipeline works on developing potential expansions, the company is finding that shippers are not necessarily as concerned that they will be making a long-term commitment. “Given pricing fluctuations, they are more concerned about us getting those pipes in the ground on time, and they are going to deal with those things more on the downstream end.”

AltaGas Ltd. has also found that delivering projects on time is critical for its customers, said David Cornhill, the company’s chief executive officer.

Jim Bertram, chief executive officer of Keyera Corp., told the conference he believes there are fundamental changes occurring in the natural gas liquids

business in North America, which could grow by 30–40 per cent in the next four or five years. That could result in “pinch points” all over North America, similar to those today for oil, as well as shortages of storage and possibly fractionation, encouraging producers to enter into long-term relationships with midstream companies.

“I think you are going to have producers go from a period where they can pick and choose a little bit to a period where they are going to start to pick their dance partners for the long term because we are going to have to make major capital expenditures to move this product,” said Bertram.

However, the Alliance pipeline and Aux Sable midstream business can offer producers a unique service for the natural gas liquids in the gas, said Stephen White, president and chief executive officer of Veresen Inc., the owner and operator.

“It’s a different value proposition,” he said. “It means they don’t have to commit to deep cuts in the field; they can transport the liquids on Alliance, extract them at Aux Sable and get Midwest prices

OIL & GA S IN Q UIRER • S E P T E M B E R 2 0 1 2

37

General News

for those liquids.” Generally, producers receive superior netbacks, White noted.

On the oil side, Enbridge Inc. still operates the Canadian mainline as a common carrier and that provides it with a competitive advantage, said Vern Yu, vice-president of liquids pipelines business development.

“When you come on to the Enbridge mainline system, you don’t have to take a take-or-pay commitment for most of the way,” he said. For example, a producer who wants to ship to the U.S. Gulf Coast can take a common carrier pipeline to Flanagan, Ill. Although it

would have to commit to a contract for the remaining distance from Flanagan to Houston or Port Arthur, Texas, the toll would be considerably less than for the full contract on another pipeline, said Yu. — DailY oil BulleTin

Senate wants oil to move to eastern Canada

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its relevance as the natural resource sector becomes increasingly complex, knowledge intensive and service oriented.

“Moreover, energy projects—whether in hydrocarbon extraction, hydro-power, nuclear research or clean-tech development—generate supply-chain and taxrevenue effects which ripple positively throughout the entire national economy,” Conspicuously absent from the committee’s list of 13 energy priorities, however, is the word “oilsands.”

The list of priorities includes natural gas, hydroelectric power, renewable energy and nuclear power—but not Canada’s biggest single source of oil production and one of the world’s largest oil deposits: the Alberta oilsands.

A voicemail message for the committee’s media relations contact to ask about the omission wasn’t immediately returned.

The committee is chaired by Senator David Angus, a Quebec Conservative.

As its first priority, the committee said Canada must strive for “collaborative energy leadership. Federal, provincial, territorial and municipal governments, industry, environmental groups and aboriginal leaders need to come together to chart a course for

A Canadian Senate committee supports construction of increased pipeline capacity to ship more western Canadian oil to eastern Canada to displace imports.

In a report issued titled Now or Never, the Senate committee on energy, the environment and natural resources listed 13 “priorities for action” needed to secure Canada’s energy future.

Canada is a major net exporter of oil, but eastern Canada imports substantial volumes from other countries because it can’t get enough western Canadian crude due to inadequate economic transportation capacity.

“Some have argued that building and enhancing east-west pipeline infrastructure would increase domestic energy security, but others question whether it makes economic sense,” the committee noted. But its report stated, “We believe that now is the time for such infrastructure projects to be undertaken in the spirit of nation building.”

Responding to criticism of the energy sector’s boom-and-bust cycles, and the claim that Canada’s strong petro-dollar hurts the non-energy manufacturing sector, the report said, “The traditional method of dividing the economy into sectors is losing

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SEPTEMBER 2012 • oil & gaS inQuirer

responsible development and marketing of our energy resources.”

The second priority for action is to “advance nation-building through energy infrastructure. Modernize and expand electricity systems and oil and gas pipelines to connect regions, and diversify export markets to further strengthen the national economy.”

The third listed priority, which described natural gas as “a game-changing fuel,” says expanded use of the “reliable, versatile and efficient” fuel should be encouraged.

The report acknowledged gas has become “extremely abundant, which has made it very affordable.” It says there is increasing demand for gas as a transportation fuel in urban fleets, in heavy-duty trucks and even in rail and marine transportation.

The trucking industry is beginning to transition to vehicles powered by liquid natural gas, but this is tempered by high costs, it said.

The report acknowledged that trucking companies are reluctant to invest in gas-powered trucks until there are enough fuelling stations, and gas companies are reluctant to build the refuelling network until there is adequate demand.

— DailY oil BulleTin

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The use of modern camera technology for downhole Sideview of Burst Casing diagnostics and troubleshooting makes the finding and development of petroleum assets a more streamlined, efficient and profitable enterprise.

Just as the tools of modern seismic exploration boost accuracy in targeting pay zones, a camera can pinpoint a downhole problem quickly and accurately, side-stepping the uncertainties of interpretation that are often encountered with conventional diagnostic equipment. “Camera technology is a great application for many companies.

People in our business make a lot of assumptions, but when you run a downhole camera, you see a lot of things you didn’t anticipate and can then plan a course of action based on your present situation,” says Alan Young, a completions consultant.

Cameras were first used on wells for fishing operations to recover lost or stuck equipment in the wellbore. Today, camera technology is streamlining diagnostics on multi-stage horizontal frac jobs. It is also being used to check for pipeline integrity. “We’re seeing a lot more use of cameras. And with video in HD colour, there are many more applications,” Young says.

Jerrom, VP Canada at EV Canada Inc. The company offers camera systems that cover the spectrum of operating environments and situations in the petroleum sector—including drilling services, pipeline pigging, and wellhead inspections.

Mechanical failures as a result of pinched tubing or other obstructions can be a challenge when traditional tools don’t give a clear answer. “You run an impression block or a multi-finger calliper, but neither gives you a complete picture. Instead, looking down and being able to pan 360 degrees using two cameras, each with its own light, and you are able to identify what the real problem is, minimizing downtime,” Jerrom says.

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An operator can also adjust the resolution Half of the camera services are proand frame rates from the surface to zoom vided on a will-call basis, and fishing in on a problem area. situations provide much of the demand “If you can actually see the problem— for that segment of the business. As Jerwhether it’s split casing or a port that rom says, “A camera tells you where in the didn’t open—you can respond faster. hole the fish is located, what exactly it Sometimes the logging data doesn’t make looks like, and its condition.” as much sense as a picture,” says Curtis

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British Columbia

LNG exports needed to make Liard Basin gas viable By richard Macedo

Photo: Joey Podlubny

an LNG export terminal is needed before there is full-scale development of the Liard and Horn river.

While Apache Corporation grabbed headlines across North America in June for its results on a prolific Liard shale validation well, the resource will likely languish in the absence of a gas price revival or the construction of a liquefied natural gas (LNG) plant on British Columbia’s north coast.

Apache’s D-34-K horizontal well had a vertical depth of 12,600 feet, a lateral length of 2,900 feet with six frac stages.

The 30-day initial production rate was 21.3 million cubic feet per day, 3.6 million cubic feet per day per frac and estimated ultimate recovery is 17.9 billion cubic feet.

Apache has said it would not immediately jump into development, but rather drill wells to hold onto the acreage. And therein lies the problem with shale gas plays like the Liard Basin: while the geology may work, the economics do not, based on surging supply south of the border and weaker prices.

“There are competitive issues that western Canadian gas is facing in our traditional markets in the U.S. Northeast with the growth of the Marcellus and also Rockies gas,” Edward Kallio, director, gas consulting, with Ziff Energy Group, said in an interview. “You’ve got this tremendous productive potential in our basin, in the Horn River play and in the Liard now.

“But the gas has no place to go. When producers can’t recover those full-cycle costs, when they can’t replace the gas that they’re producing with new gas, they stop drilling. And that’s what we’re seeing.”

A key will be developing LNG export facilities to send the gas to the B.C. West Coast and overseas to Asia where gas prices are linked to an oil price basket, and are much higher than in North America. Estimated July landed LNG prices in Korea and Japan were US$17.20 per million British thermal

units, according to the Federal Energy Regulatory Commission.

“It’s imperative that we continue to develop these LNG liquefaction proposals,” Kallio said. “But it takes a long time to get these things permitted and built. We’ve heard about delays on Kitimat LNG to 2017 now.

“Royal Dutch Shell [plc] is looking at around 2019 at the earliest on their plan, and there could be some slippage there,” he added. “We’re going to be in a painful environment here in western Canada. That Liard/Horn River gas won’t be coming on stream unless and until we build some...export capacity.”

In addition to Apache, Nexen Inc. has some land in the Liard region, as does Transeuro Energy Corp. South Korean company ST X Energ y acquired t he Maxhamish conventional natural gas field in northeastern British Columbia from Encana Corporation for $152 million, effective Jan. 1, 2010.

Transeuro holds a 100 per cent interest in the Beaver River field covering 35 sections on the existing pipeline, with three wells producing approximately 2.2 million cubic feet per day. The field is about 100 kilometres west of the Horn River in the Liard Basin that contains the same Horn River geology, but at deeper levels. The basin also contains 2,000 metres of shallower Besa River shales that have been publicized recently by Apache, but which have five years of production history at Beaver River.

Transeuro had a 50/50 partnership with Questerre Energy Corporation at the Beaver River property until June of last year when it bought out Questerre. “ We c ha nged t he operat ions to improve compression when the company took over the operatorship,” said Darren Moulds, Transeuro’s chief financial officer. “What we want to do now is just reenter the existing A-5 and A-8 wells

BRITISH COLUMBIA WELL ACTIVITY WeLL LICeNCeS

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Jul/12

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Source: Daily Oil Bulletin

oil & gaS inQuirer • SEPTEMBER 2012

41

British Columbia

and do some acid stimulation and prepare for hydraulic fracs of the same shales that Apache’s testing. But we will use the existing vertical wellbores to reduce costs.

“We’re not drilling new wells as of yet, but going into existing wellbores, keeping costs down and testing shales that we know are there.”

Plans for the Phase 1 program in the summer include acid stimulation of the A-8 well in the Nahanni formation and preparing the A-5 well for hydraulic fracs and also conducting acid stimulation in the Lower Besa River.

However, the Phase 2 program will likely be delayed to winter due to timing constraints. Plans for the program include shale fracs at A-5 in the Lower Besa, fracturing of the A-6 well (Upper Besa River) and fracturing the B-3 well (Upper Besa River).

Apache’s well announcement, meanwhile, does help the company’s cause in the area, Moulds added.

“This does help prove out the potential of the shales” he said. “It also brings a better exposure to what we have up there. It adds credibility to the story that we knew existed.”

According to a note from Peters & Co. Limited, Paramount Resources Ltd. is a major shale gas land owner in the Greater Liard Basin, with approximately 127,000 net acres of land in the area. During the first quarter, Paramount started drilling its first vertical well at Dunedin in the area slightly to the west of Apache’s Liard Basin wells, but drilling operations having been suspended due to breakup.

Paramount’s first vertical well into the play will be completed this upcoming winter while a second vertical well is planned to spud this fall at Patry.

Expansion eyed for Pacific Northern Gas western B.C. system LNG Partners, LLC has agreed to fund the cost of a feasibility study for the expansion of Pacific Northern Gas Ltd.’s (PNG’s) western transmission system to provide an additional 170 million cubic feet per day to 195 million cubic feet per day of firm transportation capacity for LNGP. BC LNG Export Co-Operative LLC, an affiliate of LNG Partners, has a licence from the National Energy Board that allows the export of 250 million cubic feet per day of liquefied natural gas, and LNG Partners plans to expand the capacity of its proposed LNG facility. PNG, a wholly owned subsidiary of AltaGas Ltd., is in the planning stages of the feasibility study and will be consulting with First Nations, nearby communities and other stakeholders during the study.

AltaGas also announced that PNG and LNG Partners have amended their agreement for 80 million cubic feet per day of fi rm gas transportation service on PNG’s

western B.C. system. The amendments include a six-month extension to LNG Partners’ exclusive option on the firm capacity and the lengthening of the term of the transportation service agreement to 30 years. The start date for the service is to be on or before March 31, 2015, if the option is exercised.

“We are pleased to provide the opportunity for LNG Partners to transport its natural gas to its liquefied natural gas export facilities in the Kitimat area,” David Cornhill, chairman and chief executive officer of AltaGas, said in a news release. “AltaGas continues to use its strategically located assets to contribute to the development of northwest B.C. and benefit our utility customers while enhancing shareholder value.”

LNG Partners paid PNG an additional $1-million non-refundable fee to extend the option, which must be exercised on or before Dec. 31, 2012. This payment is the

sixth extension of the option with PNG collecting $7.5 million since first entering into the agreement in 2009. These fees have been credited to PNG’s customers, resulting in lower rates. Further customer benefits will be realized if LNG Partners exercises its option as the PNG pipeline system becomes fully utilized and generates up to $15 million per year of revenues under the agreement.

Headquartered in Vancouver, PNG owns and operates natural gas transmission and distribution systems including a transmission line that extends from a gas transmission system north of Prince George to tidewater at Kitimat and Prince Rupert, and provides service to 12 communities and a number of industrial facilities. In the northeast, PNG’s subsidiary Pacific Northern Gas (N.E.) Ltd. provides gas distribution service in the Dawson Creek, Fort St. John and Tumbler Ridge areas.

— DailY oil BulleTin

B.C. wants share of proposed oil pipeline royalties By elsie ross British Columbia would require a “fair share” of the fi scal and economic benefits of a proposed heavy oil project before it would consider supporting the construction and operation of heavy oil pipelines within its borders, the government said in July.

42

SEPTEMBER 2012 • oil & gaS inQuirer

The money would have to reflect the level, degree and nature of the risk borne by the province, the environment and taxpayers, it said.

“Given that B.C. will shoulder 100 per cent of the marine risk and a significant portion of the land-based risk, we do not feel

the current approach to sharing these benefits is appropriate,” Environment Minister Terry Lake said in a conference call. “A fair share of benefits will be the subject of negotiations, should there be any interest in pursuing a new heavy oil pipeline in British Columbia.”

British Columbia

“We have identified aggressive environmental requirements and principles for First Nations engagement, and we have clearly stated we expect a fair share of the fiscal and economic benefits for our province,” said Premier Christy Clark in a news release.

“Our government is committ ed to economic development that is balanced with environmental protection.”

— Christy Clark

“British Columbians are fair and reasonable. We know we need resource and economic development, but we also expect that risks are managed, environmental protection is uncompromised and that

generations will benefit from the decisions we make today.

“Our government is committed to economic development that is balanced with environmental protection,” said Clark. “In light of the ongoing environmental review by the Joint Review Panel on the Enbridge [Inc. Northern Gateway] pipeline project proposal, our government has identified and developed minimum requirements that must be met before we will consider support for any heavy oil pipeline projects in our province. We need to combine environmental safety with our fair share of fiscal and economic benefits.”

For the B.C. government to consider support for heavy oil pipelines, it also would require: • Successful completion of the environmental review process. In the case

of Enbridge’s proposed pipeline, that would mean a recommendation by the National Energy Board Joint Review Panel that the project proceed; • World-leading marine oil spill response, prevention and recovery systems for British Columbia’s coastline and ocean to manage and mitigate the risks and costs of heavy oil pipelines and shipments; • World-leading practices for land oil spill prevention, response and recovery systems to manage and mitigate the risks and costs of heavy oil pipelines; and • Legal requirements regarding aboriginal and treaty rights are addressed, and First Nations are provided with the opportunities, information and resources necessary to participate in and benefit from a heavy oil project.

— DailY oil BulleTin

Photo: Joey Podlubny

Living Oceans Society condemns B.C. government’s Northern Gateway announcement British Columbia environmental group L iv i ng Ocea n s Soc iet y condem ned the Christy Clark government’s longawaited announcement of its position on the Enbridge Inc. Northern Gateway pipeline and tanker proposal in July. “ World-leadi ng ma r i ne oi l spi l l response and recovery systems will do nothing for us in the event of a spill of tar sands bitumen,” said Karen Wristen, Living Oceans’ executive director. “First, Enbridge needs to establish to the satisfaction of British Columbians that there exists any technology that could clean up such a spill. When diluted bitumen is spilled into water, much of it sinks to the bottom where conventional spill response technology is simply useless.”

Diluted bitumen, or dilbit, contains a much higher propor tion of heav y asphaltenes and resins than conventional oil. These components do not float on water and are highly resistant to dispersant chemicals.

“The rest of the components of dilbit may float for some time, giving off a toxic cloud of benzene, toluene and hydrogen sulphide that would make oil spill response hazardous,” Wristen said.

“By the time people could actually get

close enough to deploy any kind of surface-cleaning technology, any oil remaining on the surface would be widely dispersed by the action of currents, wind and waves.”

Once the heavier components of the dilbit sink to the ocean floor, it is unknown how long they will persist. The bacteria that degrade conventional oils live Concerns about oil spills should be the B.C. government's number one focus, on the surface of the not revenues, says the Living Oceans Society executive director. water. It is expected that the tar-like goo would smother life on the ocean floor it would impact the entire local ecosystem wherever it lands. for decades, perhaps centuries, to come.

“The Kalamazoo River spill in July Living Oceans has been calling for the 2010 gave us clear evidence that the transprovince of British Columbia to withdraw portation of dilbit is a dangerous experifrom the federal Joint Review Panel process ment that we don’t know how to control,” and conduct an assessment of the real risks said Wristen. “If a spill were to happen in for British Columbia, including the risk of sensitive near-shore environments, such increased supertanker traffic in pristine as the Douglas Channel route into Kitimat, and sensitive North Coast regions. oil & gaS inQuirer • SEPTEMBER 2012

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Northwestern Alberta/Foothills

Celtic invests in NGL infrastructure for Duvernay gas

Photo: Joey Podlubny

Celtic is building a shallow-cut gas plant to maximize returns from its Kaybob operations.

Celtic Exploration Ltd. has committed to construct a shallow-cut gas plant near its existing Kaybob compression facility located at 15-07-060-18W5.

The Kaybob plant is expected to have the capacity to process approximately 150 million cubic feet per day of raw gas.

The company expects the cost to construct the Kaybob plant will be approximately $40 million, of which about 40 percent will be incurred in 2012 and the balance will be spent in 2013.

Celtic’s prev iously announced 2012 capital expenditure budget included the anticipated cost in 2012 of constructing the Kaybob plant.

Celtic said its production from the Devonian Duvernay, Triassic Montney and Cretaceous formations at Kaybob that is currently processed at the third-party

operated Kaybob Amalgamated gas plant will be diverted to the company’s Kaybob plant, which is expected to be on stream in the second quarter of 2013.

The company is actively drilling wells at Kaybob targeting the Duvernay formation.

To date, the company has completed vertical operations on six gross wells. In addition, Celtic has drilled eight gross horizontal wells, three of which are on production. The fourth horizontal well has been completed and tested, and is currently being tied in. The fi fth horizontal well is being completed at this time, and the remaining three horizontal wells were expected to be completed by the end of August 2012. A ninth horizontal well was expected to spud recently.

Celtic’s working interest in wells drilled to date range from 33.3 per cent to

100 per cent. The company currently owns 110,034 net acres (172 net sections) of lands with Duvernay rights in the Kaybob area of Alberta.

In addition, Celtic has entered into a 10-year rich-gas premium agreement with Aux Sable Canada LP pursuant to which Celtic will receive additional economic value for the natural gas liquids in its liquids-rich natural gas stream originating from its Kaybob Devonian D u v e r n a y, Tr i a s s i c M o n t n e y a n d Cretaceous development area.

Rich gas from Kaybob will be delivered onto the Alliance Pipeline, obviating the need to build capital intensive deep-cut liquids extraction facilities in the field. The rich gas will be processed at Aux Sable’s large-scale natural gas liquids (NGLs) extraction and fractionation plant near Chicago, in Channahon, Ill., where NGL products will be removed.

Under the agreement, Celtic comm it s to t r a n s p or t r ic h g a s on t he Alliance Pipeline and Aux Sable will prov ide enhanced value for the rich gas that exceeds Celtic’s other gas and NGL market alternatives. Celtic expects to begin delivery under the agreement in the second quarter of 2013, when the construction of the Kaybob plant is completed.

The expected benefits of constructing the Kaybob Plant and entering into the Aux Sable agreement include the following: • Based on the value-sharing arrangement under the Aux Sable agreement and operating and transportation cost savings from the newly constructed Kaybob plant, using forward strip pricing, and assuming the plant operates at approximately 50 per cent of capacity during the first year, Celtic expects that funds from operations for the first 12 months after starting delivery will increase by approximately

NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY WeLL LICeNCeS

Jul/11

Jul/12

254

167

▼

WeLLS SPuDDeD

Jul/11

Jul/12

215

176

▼

WeLLS DrILLeD

Jul/11

Jul/12

159

18

▼

Source: Daily Oil Bulletin

oil & gaS inQuirer • SEPTEMBER 2012

45

Northwestern Alberta/Foothills

$15 million. As Celtic continues to develop its Kaybob Duvernay asset base and brings on additional production, incremental annual funds from operations are expected over the 10-year term of the agreement.

• Pricing under the agreement for ethane, propane, isobutane and normal butane is calculated with reference to the U.S. market, which provides Celtic with access to a larger and more liquid market for these NGLs.

• The Aux Sable agreement eliminates the requirement to incur additional capital expenditures of approximately $75 million to construct deepcut facilities at the Kaybob plant.

— DailY oil BulleTin

the Slave Point formation at red earth is proving fertile ground for Border Petroleum, with shortlength horizontal wells with 10 frac stages having initial IPs of around 160 barrels per day.

Border Petroleum Corp. has reported initial results from its fi rst two Slave Point horizontal exploration wells in the Red Earth area of north-central Alberta.

The wells were drilled to a vertical depth of 1,400 metres with minimum 500metre horizontal legs and fracture stimulated with an average of 10 stages. They were drilled on 18,720 acres of Loon River Cree Nation exploration rights granted under a federal government permit to Border in 2011. The 100 per cent Borderoperated Loon block contains approximately 120 potential locations based on quarter-section spacing, said the company.

T he t wo wel l s, wh ic h sat i sf ied Border’s fi rst-year drilling requirements under the permit, were drilled in proximity to infrastructure and into a gross pay thickness of 18 metres. Gross pay 46

SEPTEMBER 2012 • oil & gaS inQuirer

thicknesses on the Loon block can be up to approximately 30 metres.

To date, based on field reporting, the peak seven days of initial production from these short-leg horizontal wells averaged 159 barrels of oil per day with a single-day peak rate average of 175 barrels of oil per day. After 15 days, average oil production per well was 56 barrels per day (average 27 per cent oil cut) while after 30 days, initial production averaged 102 barrels of oil per day with an average 52 per cent oil cut.

Slave Point horizontal wells in the Red Earth area typically reach their maximum oil rates between 30 and 120 production days after start-up, said Border. During the clean-up period, rates fluctuate as frac is recovered and inflow stabilizes with oil production typically increasing with the oil recovery.

The results have validated its strategy of using short horizontal wells to de-risk the Loon block, said Border. Capital exposure and operational risk were minimized while valuable information was obtained to assist in future development.

Based on the initial results of its first two Slave Point wells, Border is moving forward with its development plan focused exclusively on Slave Point opportunities at Red Earth. After achieving a 30-day initial production rate of 10 barrels of oil per day per frac, Border intends to take advantage of the efficiencies related to drilling long-leg horizontal wells incorporating a minimum of 20 frac stages. It has initiated licensing its fi rst long-leg horizontal well, which it plans to commence in the fall. The well will be funded by cash on hand and funds generated by current assets.

Border a lso engaged Sproule Associates Ltd. to conduct an assessment of its contingent Slave Point oil resources covering 20,000 gross and net acres of the company’s interests in the Greater Red Earth Area eff ective May 31, 2012.

The Sproule report estimated 316 million barrels net to Border of discovered oil initially in place on Border’s Slave Point interests with a best estimate of contingent Slave Point oil resources of 40.4 million barrels.

The Sproule report is based on a development plan that consists of one 1,400-metre-long horizontal well per quarter section using multistage fracture stimulation completions, and does not assign any contingent resources or reser ves for seconda r y recover y schemes or down-spacing of drill spacing units.

— DailY oil BulleTin

Photo: Joey Podlubny

Border reports Red Earth success

Northwestern Alberta/Foothills

Alberta land sale targets Grande Prairie

The A lberta government brought in $41.88 million at its July land sale, highlighted by an auction high bid of $9.39 million south of Grande Prairie, Alta.

A total of 161,860 hectares exchanged hands at an average of $258.76 per hectare. Year-to-date, the government has collected $689.44 million in land sale revenue on 1.61 million hectares at an average of $427.59.

The sale high bid of $9.39 million was successfully submitted by broker Scott Land & Lease Ltd., which paid an average of $4,585.74 for the 2,048-hectare licence at 67-06W6.

“The eight-section licence is located in the Gold Creek/Elmworth area of the Deep Basin,” said Steve Hager, senior exploration analyst w it h Canadian Discovery Ltd. “Six sections, which include

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The area south of Grande Prairie is being targeted for Montney development.

rights below the Spirit River or the basal Cretaceous Bluesky-Bullhead, would be prospective for the Montney, which is being successfully developed in the area.”

Other highlights included two leases in the area around 46-12W5, which combined for $3.1 million and produced identical per-hectare averages of $8,076.62.

B o t h we r e a c q u i r e d b y W i n d f a l l Resources Ltd. “Both include rights to the base of the Cardium and that would be the target,” Hager added.

Windfall also scooped up the rights to a 768-hectare licence at 46-12W5 for $5.17 million, which worked out to an average of $6,729.68 per hectare.

It i nc lude s v a r iou s C ret aceou s and Jurassic rights to the base of the Mississippian Shunda formation, which along with the Cardium would include the Viking, Upper Mannville, Rock Creek and Nordegg, also productive in the Brazeau River field, where these parcels are located, Hager added.

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OIL & GA S IN Q UIRER • S E P T E M B E R 2 0 1 2

47

Northwestern Alberta/Foothills

tourmaline is building infrastructure to process its Deep Basin production.

Tourmaline Oil Corp. more than doubled its liquids production in the second quarter and reported record production, achieving a profit despite a 49 per cent drop in its natural gas price.

Oil and liquids production averaged a record 6,560 barrels per day for the three months ended June 30 compared to 2,991 barrels per day in the comparable 2011 period, an increase of 119 per cent.

Record second-quarter production of 51,022 barrels of oil equivalent per day represented growth of 81 per cent over the 2011 quarterly average of 28,263 barrels per day. Tourmaline is targeting 2012 exit production of between 55,000 barrels equivalent per day and 57,500 barrels per day, including between 9,000 and 10,000 barrels per day of liquids.

Realized natural gas prices in the quarter were $2.23 per thousand cubic feet. The company also reduced per unit operating costs to a record low of $4.83 per barrel equivalent, down 16 per cent from $5 in the second quarter of 2011.

Second-quarter capital spending was $53.88 million compared to $130.08 million during the same period in 2011.

Tourmaline is now anticipating spending 48

SEPTEMBER 2012 • oil & gaS inQuirer

of $410 million for the year as a result of expanded exploration and production programs at Sunrise-Dawson, Musreau, AnsellEdson and Spirit River.

The company currently is planning a preliminary capital program of $525 million in 2013.

Tourmaline now has six rigs drilling and they all are on either their second or third holes and initial results have been very strong, he said.

In the Alberta Deep Basin, four rigs are working with three pursuing horizontal targets and one vertical targeting highrate Wilrich, Falher and Notikewin objectives. Five new gas wells have been drilled thus far in the second half of 2012 and will be completed during the next few weeks.

A total of 25 new horizontals and six verticals, including outside operated wells, are anticipated in the Deep Basin during the second half. The company expects to have between 25 and 30 new horizontal wells on stream through existing owned-and-operated gas plants by the end of the first quarter of 2013.

At the Dawson-Sunrise complex in British Columbia, Tourmaline plans to operate one rig drilling Montney horizontals

in the second half. The program is concentrating on the follow-up to the new high-deliverability liquids-rich Montney turbidite lobes it had uncovered with drilling over the last six to nine months, said Rose. These lobes are producing at initial rates of 15 million cubic fee per day and thus far higher condensate and natural gas liquid (NGL) rates in the range of 40–50 barrels per day. Plans call an additional 15–18 Montney horizontal wells during the next nine months.

Tourmaline’s most recent Montney horizontal well in the complex was drilled in 11 days for a record low cost of $1.67 million.

The company currently has approximately 60 million cubic feet per day behind pipe at Sunrise-Dawson and is planning a new 50-million-cubic-feet-perday gas plant with a late fi rst-quarter 2013 completion target. This will increase total production from the complex to between 125 million and 130 million cubic feet per day with 4,000–5,000 barrels per day of condensate and NGLs. At Spirit River, Alta., current production is approximately 3,200 barrels per day of light oil and 14 million cubic feet per day of associated gas. Ongoing drilling in the Phase 1 development area is expected to bring oil production from the complex to 5,000 barrels of oil per day by the second quarter of 2011.

Tourmaline is employing one rig drilling Triassic Charlie Lake horizontals with the second-half 2012 exploration and production program. Seven of the 10 planned horizontals in the second half will focus on oil pool expansion opportunities to the east and south of the initial large pool.

Two new horizontals in the peripheral areas have already been drilled in the second-half program, with encouraging initial results. The most recent horizontal was drilled in 13.5 days for $1.9 million—a cost record. The most recent horizontal completion was also a record with 18 stages stimulated for $1.6 million total cost.

The infill and pool expansion program will result in approximately 15 new horizontal wells by the end of the fi rst quarter of 2013, with the majority of these wells brought on production by the end of that quarter.

— DailY oil BulleTin

Photo: Joey Podlubny

Tourmaline doubles liquids production

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Northeastern Alberta

Oilsands operators managing differential

By Lynda Harrison

Rogers, MEG Energy Corp.’s vice-president of investor relations.

MEG’s long-term strategy has been to find various routes to move its crude in order to get the highest prices for its end product, Access Western Blend, a bitumen blend that is sold at a discount relative to WTI. The SAGD producer believes the Access pipeline it shares with Devon Canada Corporation and the under-construction Stonefell storage facility offer the company a unique cost and revenue advantage.

Planned additional pumping stations on Access this year will increase blended bitumen capacity to 118,000 barrels per

day and condensate capacity to 76,500 barrels per day (net) from net current capacity of 78,000 and 52,000 barrels per day, respectively.

In addition, Rogers said, the company has taken options on proposed pipelines: Enbridge Inc.’s Northern Gateway project to the West Coast and Asian markets and its Flanagan South and Seaway Pipeline Twin to the U.S. Gulf Coast, expected to be operational in 2014.

In the meantime, the best way MEG has found to manage price differentials is to lower its operating costs and maximize revenues, Rogers said, adding that his company can produce a barrel of oil for less than $8.

According to MEG, its low-cost structure delivers high netbacks. Efficient plant utilization enables it to spread fixed costs over production volumes, which are currently above design capacity. As a result, its nonenergy operating cost per barrel is among the top decile in the industry, it says.

Also, on-site cogeneration generates power revenue that partially offsets its energy operating costs and provides a hedge against natural gas prices. An 85-megawatt facility generates steam and electricity for operations while surplus electricity is sold to the grid.

During the first quarter of 2012, MEG’s differential for oil prices was around 31 per cent and its cash operating netback was $39.20, versus last year when the differential was around 24 per cent and its cash operating netback was around $43, said Rogers.

“So if you take similar oil prices and you change your differential from the mid-20s to 33–35 per cent, you’ll find that it drops your net operating margin by about $5–$6, so it doesn’t have this really dramatic impact that people are thinking that these wide differentials have,” said Rogers.

Harbir Chhina, Cenovus Energy Inc.’s executive vice-president of oilsands, said that in the past couple of years it’s been “a blessing” to have downstream capacity.

JUL/11

JUL/12

JUL/11

JUL/12

WELLS SPUDDED

99

133

WELLS DRILLED

96

139

Photo: Joey Podlubny

The differential between bitumen and WTI averaged as high as 31 per cent in the first quarter of 2012.

Through pipelines, refineries and production methods, oilsands companies have varying ways of coping with differentials, a panel of producers told a recent industry forum.

Some companies are trying to get the best price possible by taking their product to the highest bidders, others are keeping their costs low while others are not affected at all, the TD Securities Calgary Energy Conference heard.

Synthetic crude oil has traded close to West Texas Intermediate (WTI) prices, but volatility has recently increased.

There has been “extreme concern, and rightly so” around differentials, said John NORTHEASTERN ALBERTA WELL ACTIVITY

JUL/11

JUL/12

WELL LICENCES

109

56

▼

▲

▲

Source: Daily Oil Bulletin

OIL & GA S IN Q UIRER • S E P T E M B E R 2 0 1 2

51

Northeastern Alberta

Last year, the company made about $1 billion from its downstream segment and expects to make at least that much this year, especially if crack spreads remain in the $25–$30 range, he said.

In November, Cenovus completed the expansion of new four-drum coker with capacity of 65,000 barrels per day at its shared Wood River refinery in Illinois and that project is running smoothly, he added.

The refinery has a processing capacity of approximately 356,000 barrels per day.

It refines crude oils to produce gasoline, diesel and jet fuel, petrochemical feedstocks and asphalts. Its completion has expanded Cenovus’ heavy oil upgrading capacity and increased the production of clean transportation fuels.

Marcel Coutu, president and chief executive officer of Canadian Oil Sands Limited, which owns the largest share of Syncrude

Canada Ltd., said he believes that differentials will shrink in the coming years.

Differentials between Brent and WTI were as high as $25 per barrels earlier this year, said Coutu. “I think it’s a terrible misfortune for producers both American and Canadian, but that’s quickly being repaired,” he said.

The differential is now $10–$15 per barrel between Cushing and Brent prices and Canadian Oil Sands believes that will be corrected within the next two years as the Seaway pipeline and reversal and expansion come on and the Keystone “pre-build,” as he calls it, gets completed between Cushing, Okla., and the United States Gulf Coast.

“That will be one million to 1.5 million barrels of capacity and should close most of the rest of that gap back to normal levels, which is what I call low-hanging fruit,” said Coutu.

The other differential is synthetic crude oil, he said, adding that will probably take the better part of five years to correct and that will happen with Enbridge’s Northern Gateway pipeline and TransCanada Corporation’s Keystone XL, “which we do expect will go ahead,” he said.

Suncor Energy Inc. is not much affected by differentials, both between light and heavy oil, and between WTI and Brent prices, said Bart Demosky, Suncor’s chief financial officer.

“We capture almost all the Brent price and because of our complex upgrading and refining assets the light-heavy differentials really aren’t affecting us much, so whether we capture that value in the upstream or in the downstream we’re largely indifferent,” said Demosky. “The whole purpose is to capture full value for every barrel that we produce in the upstream part of our business.”

More air-monitoring stations coming The new head of the organization that monitors air quality in the Athabasca oilsands region says her f irst priority is to make sure the Wood Buffalo Env ironmental A ssociation ( W BE A) doesn’t get in over its head.

The independent, community-based, not-for-profit association monitors the air in the Regional Municipality of Wood Buff alo 24 hours a day, 365 days a year and operates a variety of air, land and human monitoring programs.

“What I see going forward, one of the key objectives as we take on more and more monitoring, is that we don’t exceed the capacity of our organization and that we really pay attention so that we can keep doing some of the things that we’re doing really well right now; we can still maintain that as we’re enhancing our network going forward,” Diane Phillips of Syncrude Canada Ltd. said.

Prior to her appointment as president of the WBEA, she was a member of the ambient air technical committee for 10 years and chaired it for five years. Phillips was also a member of the WBE A governance committee for three years.

“Due to my e x per ience work i ng with WBEA since 1997, I am fully aware 52

SEPTEMBER 2012 • oil & gaS inQuirer

of t he ef for t t hat has gone into t he organization by the WBEA committee members, WBE A staff, scientists and WBEA board members to make WBEA a successful organization,” she said. “A priority going forward is to ensure that WBEA is sustainable in the long term f rom a resource perspective and to ensure that we have the infrastructure in place to support the expected continued growth of the organization.”

The WBEA operates 15 continuous stations—10 near oilsands projects and five in communities in Alberta (two in Fort McMurray and one each in Fort MacKay, Fort Chipewyan and Anzac).

It also operates one portable station and one mobile station.

T he a s so c iat ion h a s 22 pa s sive monitors attached to 18-metre towers at remote forests, monitoring the air’s content of ammonia, nitric acid, ozone, nitrous dioxide and sulphur dioxide.

A not her f ive monitors are solarpowered, attached to 30-metre towers in remote forests, recording meteorological data.

T he infor mation collected is sh a r e d w it h s t a ke holde r s a nd t he public on its website, wbea.org, and through reports.

In addition to its monitoring network, the WBEA is studying forest and human health, and one of Phillips’ first tasks as president is to gain more indepth knowledge of these programs.

She said the association is in the fi rst phase of an odour-monitoring program. Currently, the technology used to measure odorous compounds is being assessed to determine the longer-term monitoring strategy.

Also, plans are in place for a new continuous ambient air monitoring station to be installed in the community of Conklin, Alta., and a new continuous ambient air monitoring station is to be installed between the Total E&P Canada Ltd. Joslyn mine, northwest of Fort MacKay, and the community of Fort MacKay, Alta.

Last year the WBEA commissioned a comprehensive scientific and technical evaluation of the WBEA ambient air-quality network that was conducted by respected experts in the fi eld of airquality monitoring, said Phillips.

One of their recommendations was to measure the air quality entering and leaving the air shed, she said, so the WBEA now plans for an ambient air monitoring station to be installed near the Saskatchewan border.

Northeastern Alberta

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The WBEA is stepping up monitoring.

Also last year, operations and maintenance of the ambient air monitoring network contracts were evaluated and the WBEA decided to transition to its own personnel for maintenance of the network from third-party contractors.

It hired a program manager, data validation and reporting personnel, three ambient air qualit y specialists, and one intermediate and four junior field technicians.

Both the federal and provincial governments have identified the need for additional monitoring in this region [the Joint Canada /A lber ta Oilsands Plan 2012], said Phillips, who is also a senior env ironmental scientist for Syncrude Canada Ltd. “The WBEA is already conducting a substantial amount of the monitoring that is recommended in this report,” said Phillips. “In light of this plan and look ing for wa rd, work ing w it h t he member organizations to support anticipated additional monitoring requirements by WBEA will be a priority.”

The association was formed in 1985 as the Air Quality Task Force to address environmental concerns raised by the Fort McKay First Nation.

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53

Northeastern Alberta

Solvent-aided bitumen production growing

Producers are using solvent to cut the energy costs at thermal operations.

It takes about one thousand cubic feet of natural gas to produce a barrel of oil from Alberta’s steam-assisted bitumen projects.

With the province’s thermal oil output now exceeding 700,000 barrels per day, that’s about 700 million cubic feet of gas a day being burned just to make steam.

What if you could replace at least a portion of that steam with a mostly reusable solvent? Researchers have been patenting solvent-aided bitumen extraction processes since at least the 1970s. Until recently, nothing really caught on.

Now projects are springing up across the oilsands regions of northern Alberta.

Two processes are in commercial use—at Cold Lake and Christina Lake—

and a variety of pilot tests are operating or under construction. Most inject solvent with steam; one will use solvent and electric heat; another relies entirely on heated solvent.

This quest to cut gas consumption is occurring even though gas prices are the lowest they’ve been in a decade. Time will tell whether it will significantly reduce the ratio of gas burned to bitumen produced.

According to an estimate Ziff Energy Group prepared last year, Alberta’s thermal oil industry as a whole burns about 1.1 thousand cubic feet (mcf) of gas for every barrel of bitumen produced, said Bill Gwozd, Ziff Energy’s vice-president of gas services.

Gas consumption varies widely by project as well as recovery method. Ziff Energy estimated cyclic steam projects burn roughly two mcf to three mcf of gas per barrel produced, and SAGD projects consume between 0.8 mcf and 1.6 mcf, said Gwozd.

Despite the proliferation of field pilots testing solvent-assisted bitumen extraction processes, Gwozd isn’t expecting a big drop in gas consumption until gas prices rise—the economics are just too compelling while gas remains dirt cheap.

And he’s skeptical that companies are doing it solely for environmental reasons.

Virtually all companies testing solventbased processes point to reductions in greenhouse gas emissions and water consumption, but the technology is also expected to increase bitumen recoveries.

“The main advantages of adding solvent to steam is the observed increase in oil production of about 30 per cent, decrease in steam requirements also of about 30 per cent and concomitant lower water usage,” writes Eddy Isaacs, head of Alberta Innovates – Energy & Environment Solutions, an Alberta government research agency.

“The main disadvantage is the solvent losses in the reservoir and the high costs and availability of solvents,” Isaacs said in a paper presented at the World Petroleum Congress in Doha, Qatar, last December.

With gas prices being so low, and without an incentive to curb carbon emissions, the commercial application of solvents is often not cost effective, he wrote.

Challenges include the relative complexity of the processes compared to straight steam injection, and the cost of the solvent, especially if transported by truck rather than pipeline.

In very rough terms, propane is about the same price as bitumen, or about half the price of West Texas Intermediate (WTI) crude. Condensate is roughly the same price as WTI, but often has the advantage of being pipelined onto the site for use as diluent.

Given the cost of solvents, the amount recycled— or more to the point, the volume lost per barrel of bitumen produced—is crucial to the economics.

“Solvent recovery per se is not a useful economic indicator, because the minimum level is a function of the amount used in the first place. If only small amounts of solvent are used, then the incremental oil may yield positive economics without much, or even any, solvent recovery at all,” said Neil Edmunds, advisory director for Laricina Energy Ltd. and an engineer with many years of experience in thermal recovery.

“So the real indicator,” Edmunds said, “is how much solvent is lost per barrel of oil recovered. On that measure we need to be below about 10 per cent ‘relative retention.’”

As for variations in the technology, he said, “There are more possible solvent processes than atoms in the universe. The basic variables are solvent types, dosage and timing.”

Sunshine Oilsands Ltd. says it has achieved significant growth in its reserves and resources categories in its mid-year report, increasing proved reserves to 80 million barrels, up 78 million barrels from November thanks to the 54

SEPTEMBER 2012 • oil & gaS inQuirer

regulatory approval of its West Ells commercial steam assisted gravity drainage development.

West Ells, approved on January 20, is designed to produce 10,000 barrels per day of bitumen and is now under construction.

The company’s aggregate proved-plusprobable reserves grew by 26 million barrels to 445 million barrels.

The aggregate pre-tax discounted cash f lows for proved reserves (PV10

Photo: Joey Podlubny

Oilsands project boosts Sunshine’s proved reserves

Northeastern Alberta

per cent) is $312 million while proved-plusprobable reserves PV10 per cent value is $918 million.

Sunshine intends to continue with delineation for more recognition of its reserves at West Ells, Legend Lake and Thickwood and will report those results in a timely manner, said John Zahary, president and chief executive officer.

Probable reserves additions were achieved in the Legend area.

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Clastics best-estimate contingent resource recognition increased by 1.2 billion barrels to a total of 3.61 billion barrels primarily due to Harper, Opportunity and Pelican Lake additions.

Carbonates best-estimate contingent resource recognition increased in Sunshine’s Gof fer, Musk wa and Portage operating areas, adding more than 700 million barrels to a total of 1.35 billion barrels.

“We are particularly encouraged to see progression in our carbonate reservoir resource recognition, since we have captured large trends of this resource type and we are progressing our examinat ion of suitable tec h nolog ies for extraction,” said Zahary.

The report also lists 603 million barrels of proved-plus-probable-plus-possible reserves with an aggregate pre-tax PV10 per cent of $1.6 billion.

Sunshine’s reserves and resource reports, effective May 31, 2012, were independently prepared by DeGolyer and MacNaughton Canada Limited and GLJ Petroleum Consultants Ltd. — DailY oil BulleTin

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Central Alberta

Duvernay shows promise, say producers By richard Macedo

Photo: Joey Podlubny

Drilling in the Duvernay is showing as much as 100 barrels of condensate per million cubic feet of gas.

Producers with property in the Duvernay shale play in Alberta are encouraged by what they’re seeing so far, but it’s still in its early stages of development, they caution.

Robert Broen, vice-president of the shale division with Talisman Energy Inc., told the TD Securities Calgary Energy Conference that early industry results have been encouraging. The company has a land position of 360,000 net acres and plans to have six wells drilled by the end of 2012.

Three are planned for the North Duvernay and three in the South Duvernay.

Two wells are currently producing, and the company expects to have four on production by the end of the year.

“We’re very well positioned in the Duvernay,” Broen said. “Most of the industry activity has been focused on the northern part of the play so far.

“We just fi nished reaching total depth on our third well in the northern part of

the play. We’re running one rig in the Duvernay. We’re moving that rig down to the south part of that play immediately.”

“Industr y results have been ver y good,” he added. “We haven’t released our results yet, but we’re very pleased with what we’re seeing in the industry, and we’re very encouraged despite it being early days with this play.”

According to information by BMO Capital Markets, the Duvernay shales have been credited as the source rock for many of the large Devonian oil and gas pools in Alberta. In central Alberta, the Duvernay shale basin spans roughly 50,000 square miles with an estimated 7,500 square miles within the thermally mature or “wet” gas window. BMO estimates that the liquids-rich gas window could contain as much as 750 trillion cubic feet of gas.

BMO noted that the Duvernay in the Kaybob area is predominately within the

thermal gas window of hydrocarbon generation. Thermal maturation increases to the southwest, as does depth, and locations within the Wild River sub-basin may produce drier gas than at Kaybob.

Celtic Exploration Ltd.’s land position in the Kaybob Duvernay includes 138,080 (110,034 net) acres. The reservoir is overpressured at 60 megapascals, and the wet gas leg is rich in liquids at 75–115 barrels per million cubic feet. Drilling potential includes four to eight wells per section.

“We were lucky enough that we had Montney lands here and we actually ended up owning a lot of the Duvernay rights,” said David Wilson, the company’s president and chief executive officer. “We were pretty aggressive early on here drilling these wells because we wanted to make sure that it was a play we wanted to continue to pursue. As a result, we continued to acquire more land on it.”

To date, the company has three producing wells, all horizontals with Celtic, Trilogy Energy Corp. and Yoho Resources Inc. each with 33.3 per cent interest. A fourth well is completed and being tied in.

This horizontal well was expected to come on stream by the end of July. (Celtic has a 50 per cent interest.)

A fifth well is just being completed now at 4-11 (this one is a joint venture with Yoho and Trilogy). The company then has three more wells to complete.

Celtic has 100 per cent interest in two of the horizontal wells, and 50 per cent interest in the third.

And, the company is moving a rig now to drill well number nine.

Wilson added that liquids content will change across the acreage as it gets closer to the oil window.

“So far, we’ve averaged about 100 barrels a million, maybe even a little bit higher than that,” he said. “As we drill closer and closer to the oil line, we expect that liquids

CENTRAL ALBERTA WELL ACTIVITY WeLL LICeNCeS

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Source: Daily Oil Bulletin

oil & gaS inQuirer • SEPTEMBER 2012

57

Central Alberta

yield to go up. Some of these next wells should prove out that theory.”

Michael Kohut, chief fi nancial officer of Trilogy, said that the company has 200 net sections in the Duvernay, 100 in the gas/condensate window and roughly 100 in the “oilier” reservoir.

“Really, all we’re trying to do here is we’re trying to manage our expiries and learn as much as we can about the play as we go on,” he said. “We have informationsharing agreements with most of the major companies that are drilling in this area.

“They’re seeing the wells we drill; we’re seeing the wells they drill,” Kohut added. “We’re trying to fi nd out the best way to drill and complete these wells. It’s an interesting play; it’s got a lot of potential, we think. But it’s early days from our perspective.”

Well service firms meet weather, worker shortage issues

58

SEPTEMBER 2012 • oil & gaS inQuirer

Well service companies are lacking the crews needed to keep equipment running.

house—and living a life—more feasible for the average worker.

For one executive, the service sector’s loss of workers was most keenly felt in the 2008-09 downturn, when a wave of well servicing workers left the industry, including many from Atlantic Canada.

“We’ve always had downturns…and the workers generally came back, but that was such a protracted period…when there was no work that a lot of the workers found

other employment,” said Deb Close, president of production services for Tervita Corporation.

While federal Immigration Minister Jason Kenney ’s announcement that Ottawa will take steps to facilitate the flow of workers to Canada under its Temporary Foreign Worker (TFW) program was hailed as good news, there’s still some debate about which sectors will benefit the most from the coming changes.

Photo: Joey Podlubny

The heavy rain that turned prairie roads to mud in June has also slowed well servicing activity in July, especially in southern Alberta and Saskatchewan. The trouble is not in fi nding rigs, but moving them over roads that could take days or weeks to dry out. “ T he i ssue we’ve had over t he last month or six weeks has been wet weather,” said Duncan Au, president and chief executive offi cer of CWC Well Services Corp. “They’ve had more rain in Lloydminster and Provost than they’ve seen in three years.”

While showing 75 per cent utilization in the week ended July 15, 2012, Au said CWC’s rate came down during the week ended July 22, although he would not be more specific. CWC operates 65 service rigs.

Average utilization for wester n Canada’s roughly 990 service rigs during the first half of 2012 averaged 57.4 per cent or 568 active rigs, ahead of the 54 per cent or average 480 active rigs used in the fi rst six months of last year (fleet of 889 rigs).

Yet the wet weather that slowed activity may be the least of concerns for well servicing contractors as they gear up for winter. Aside from worries that crude oil prices could falter, causing producers to trim spending, contractors are concerned that an already-tight labour market could worsen this winter. Service rig owners who are recruiting are still competing with oilsands employers for a limited pool of workers, and oilsands pay scales are tough to match.

As well, the cyclical, feast-or-famine nature of well servicing has in the past led many workers to abandon the field for lesser-paying work that nonetheless offers regular hours and a steady paycheque, factors that make buying a

Central Alberta

Many believe megaprojects, including oilsands plays already reaping benefits under the TFW regime, will be the real beneficiaries of the recently announced changes.

Even if most temporary foreign workers end up in the oilsands, the net effect would be to take pressure off Alberta’s labour supply, freeing up workers for other jobs, including those in the service sector.

Yet one service contactor believes the attraction of working in Alberta will pale once winter arrives.

“They won’t work up here,” said Dave Malone, referring to the A mericans expected to cross the 49th parallel for temporary jobs in well servicing in the months to come. President of Rezone Well Servicing Ltd., Malone believes Americans who are not acclimatized to Alberta will find winter tough sledding and ultimately leave their jobs for warmer climes.

But for the worker shortage, Malone could add two more service rigs to his 13-rig, Red Deer, Alta.–based fleet. “I’ve ridden this bus quite a few times, with swings in activity levels,” he said, noting the current surplus of inexperienced workers.

“We used to be able to draw from Newfoundland and Saskatchewan, but those are ‘have’ provinces now. We’ll have to get either foreign or young people interested in the industry who’ll give it a try.”

In the near term, he thinks southern Ontario, whose weakened manufact uring sector has been rife w it h layoffs, might prove a good source of workers. As unemployment rates rise and Ontarians get increasingly hungry for work, he believes more will come to Alberta.

If so, other Alberta service contractors aren’t going to wait. Canyon Services Group Inc., for one, continues to recruit in Britain, while other companies are turning to the United States. The latter include Tervita, whose well servicing division, formerly Concord Well Servicing, runs 101 service rigs in western Canada.

“We’re not sold out of equipment.

We’re sold out of crews,” said Tervita’s Close, who believes most well servicing firms are in the same boat. “It takes time— about five years—to build an experienced crew and we’re all trying to build them

right now. It’s not really an equipment— but a manpower—shortage.”

The company ’s strateg y includes a f ly-in program that brings workers from Atlantic Canada. Yet, thanks to Newfoundland’s booming economy, the program has proven less fruitful than in years past. The company is also recruiting internationally. In addition to the United States, it’s looking to Mexico for skilled workers with experience on well servicing rigs, along with core Englishlanguage skills.

She rejected the idea that foreign workers w ill come to Canada f rom warmer countries like Mexico, work a few weeks and then leave the country for good when they feel the bite of a Canadian winter.

“That hasn’t been our experience,” she said. “We didn’t recruit from the U.S. last year, but we did from Mexico, and none of those workers left because of the winter.” Acknowledging that some workers left Canada because well servicing did not meet their expectations, she said the same thing sometimes happens with Canadian workers.

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59

Central Alberta

“It’s a huge opportunity,” Chappell said. “This isn’t just natural gas liquids; this is the basic petrochemicals that others are creating.”

The challenge is getting the owners of the upgraders on board, he said. “Their focus is on making synthetic crude oil, and there’s certainly value in doing this and it pays for the assets...but if they can make another 100,000 barrels a day of synthetic crude and put 20 people working on that, they would rather do that because that’s what they do,” he said. “They are working on it now, but it’s taking a long time to convince them that this works, it makes sense and is economic.”

The Joffre Petrochemical Plant. More oilsands offgases could be used to fuel expansion in the In processing the offgas, Williams also petrochemical industry. takes out much of the sulphur and returns methane, which means that while the The growth of oilsands upgraders in The company currently removes only upgraders are burning the same amount Alberta holds great opportunity for NGLs (propane and butane) and olefins (proof energy, it is a lot cleaner. “We are not Williams Energy Canada and any new rules pylene and butylene) from the Suncor Energy actually manufacturing this, so it is a very on greenhouse gas emissions would further Inc. upgrader offgas in Fort McMurray, but good business model, he said. increase its growth potential, an industry soon also will be processing ethane and An IHS study found that the lowest conference heard in July. ethylene. If Williams were to process all the cash-cost propylene is in the United States Williams is the only company in the offgas and remove all the C2+, it would be where propane hydrogenation is turned world that processes upgrader offgas to looking at five times the volume it currently into propylene. However, because the remove higher-value natural gas liquids handles, and if new and expanded upgraders Canadian fuel price is below the U.S. fuel and olefins, David Chappell told the TD are included, it would be seven times the curprice, “we are by far the lowest cash-cost Securities Calgary Energy Conference. “If rent volumes, said Chappell.

September Expertec for Oil & Gas Inquirerpropylene producer in the world,” accordwe were to process all the offgas in the Fort Existing ad sources of offgas beyond ing to Chappell. Most of the propylene is McMurray region, we would decrease CO2 Williams’ current as the CMYK press res pdf:operations 7.0625”such x 2.25” shipped by rail to the U.S. Gulf Coast, as emissions by one million tonnes a year.”

Syncrude Canada Ltd. facility and Canadian there are limited markets for it in Canada.

Upgrader offgas is 40 per cent natural Natural Resources Limited’s (CNRL’s) There is an additional 1/8” bleed included in the tiff file.

With its 12-inch Boreal NGL pipeline gas liquids (NGLs), 40 per cent methane Horizon upgrader could increase NGL/ you the along tiff file insome your publication, put barrels a 1 ptper blackfrom border aroundAlta., it. to its Redwater Fort McMurray, and 20Ifper centuse hydrogen with olefin volumes toplease nearly 80,000 fractionator now on stream, Williams sulphur. Upgraders traditionally have day beyond current production of approxiis uniquely positioned to open up the removed as much of the sulphur as possible mately 14,000 barrels per day. With ethane NGL market out of the oilsands area. The from the offgas and burned the rest as fuel. extraction, the Voyageur upgrader and the 420-kilometre high-vapour pressure pipe“But they are burning a lot of very valuCNRL upgrader expansion, potential volline has an initial capacity of 43,000 barable products,” said Chappell, president of umes could rise to 200,000 barrels per day rels per day with an ultimate capacity of Williams Energy Canada. in the 2021-25 period.

60

S E P T E M B E R 2 0 1 2 • OIL & GA S IN Q UIRER

Photo: Joey Podlubny

Williams Energy sees potential in oilsands offgases

Central Alberta

125,000 barrels per day with additional pump stations.

In its latest project, Williams has signed a long-term agreement with NOVA Chemicals Corporation under which it will provide the petrochemical company with up to 17,000 barrels per day of ethane and ethylene from upgrader offgas. With 10,000 barrels per day from Suncor, it has room for offgas from one more upgrader and a de-ethanizer is going to be built, he said. The ethane recovery project, which is expected to be in service in mid-2013, has an estimated cost of between $290 million and $340 million.

Responding to a question, Chappell said that a barrier to entry for other companies is the technical know-how that Williams has developed over the years.

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working extremely well.”

— David Chappell, president of Williams Energy Canada.

When the cryogenic liquids extraction plant at the Suncor site originally started up 10 years ago, it didn’t work very well and the company brought in experts from around the world to figure out how to make it work properly, he said.

“We’ve got all the bugs ironed out now and we’ve got it working extremely well and we’ve got the systems in place to get the highest value of these fracs out,” said Chappell. “There’s a lot of learnings there that upgraders want,” he said. “When you think about someone bolting a plant onto the side of your $10 [billion] or $15-billion upgrader, you want to make sure the company that’s doing that knows what they’re doing.”

William also has the advantage of its Redwater olefinic fractionator, which has a number of components designed to extract the highest value of products. Two years ago it brought in a $60-million splitter that takes the butane/butylene mix and turns it into two valuable components. As the company currently is using only about half of the capacity, when it starts working with other upgraders it won’t need to buy another splitter.

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Southern Alberta

Ziff forecasting further drop in gas prices By elsie ross

Photo: Joey Podlubny

Ziff sees real gas prices hitt ing possible lows below $1 per thousand cubic feet this fall.

North American natural gas producers who have not shut in production could be looking at gas prices below $1 per thousand cubic feet on some days this fall as storage levels remain high, a gas consultant is predicting.

“The real price in September and October, I think, will be just downright brutal for the producers, and that’s very unfortunate, but you need to be in supply-demand balance,” said Bill Gwozd, vice-president of gas services for Ziff Energy Group.

For about 25 per cent of Nor th American supply, the price will be zero as the gas will be shut in, he suggested. The remaining 75 per cent will be subject to gas-on-gas competition, he added. “The producers aren’t going to take zero without taking out their sabres and trying to fight on the way down.”

However, with full cycle costs of $5.50 to $6 per thousand cubic feet,

producers will come to recognize the disconnect with gas prices and begin to shut in their gas and cut back on drilling next winter, he said. While some major gas producers such as Encana Corporation and Chesapeake Energ y Cor porat ion have a l ready t r i m med some gas drilling activity, the industry may need to do more. If gas storage fills up before the start of the withdrawal season in November, producers may have no choice but to shut in gas, according to Gwozd.

On the drilling side, Gwozd suggested that assuming a North American gas supply of 80 billion cubic feet per day and a macro decline rate of 20 per cent per year, if there was no drilling for one quarter, supply would fall by about four billion cubic feet per day (fi ve per cent).

“I think that would have an impact on prices,” he said. “Do it for six months

[take out 10 per cent of your supply]; I think you would have a major concern.”

In a report that provides an analysis of selected factors influencing natural gas drilling, author Lev Virine, Ziff ’s manager of gas consulting, forecasts that the gas rig count in the Lower 48 states will fall to below 400 rigs over the next couple of years in order to bring demand and supply back into balance.

While attractive economics for natural gas liquids have driven gas drilling over the last couple of years, that cannot continue indefinitely, cautioned Simon Mauger, Ziff ’s director of gas supply and economics. “We see more downward pressure on liquids prices than anything else at the moment,” he said. There’s been a double whammy with not only increased supply but in falling oil prices on which some NGLs [natural gas liquids] are based.”

In the last month, ethane has attracted a lower incremental value over methane, said Mauger. “It is just being re-injected, and we are finding a lot of hot gas is being burned around the continent.” It’s a similar case for propane.

Although the price of condensate is still holding up at about 80 per cent that of West Texas Intermediate, “there is only so much the oilsands can sop up as diluent, assuming the infrastructure is there to deliver it.”

Eventually, though, markets will grow and supply and demand will come back into balance, but it’s going to take time, he said.

Because of shale gas, which relies on horizontal wells and hydraulic fracturing that can produce more gas from each well, North America is a completely different supply market from three or four years ago, said Mauger. For example, there was virtually no production growth when the number of gas rigs recovered to 1,000 in 2010-11 from a peak of 1,500 rigs in 2008.

However, with the advent of shale gas,

SOUTHERN ALBERTA WELL ACTIVITY WeLL LICeNCeS

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oil & gaS inQuirer • SEPTEMBER 2012

63

Southern Alberta with 1,000 rigs in operation, production has been growing by an average of three to four billion cubic feet per day, he said.

In western Canada, drilling 1,000 conventional wells will add just over 100 million cubic feet per day of gas production, but in shale plays such as Horn River or the Haynesville shale in the United States, the same number of wells will add nearly five billion cubic feet per day of production, according to a Ziff analysis.

“If you drop that rig count by more than half, you’ll get a little bit of production

decline.... It may drop by about 10 per cent,” said Mauger. “After that, maintaining that low level of drilling in there actually grows production again, and we’ve seen that within the Barnett shale.” Although production initially dipped and growth slowed after 50–60 per cent of the rigs were moved out, production is currently flat, he said.

“The industry has stepped off the drilling treadmill of the mid part of the last decade with a focus on high-productivity shale gas wells,” Virine said in a news release. “Producers can ramp up production

rapidly in response to higher gas prices.

Gas production from shale gas plays will not decline significantly, even when rig counts are cut in half.”

According to Virine, in 2008, only onequarter of wells drilled were horizontal and 75 per cent were vertical; by 2015, he expects those numbers to be reversed.

Daily Oil Bulletin records show that in the fi rst five months of this year, 2,812 horizontal wells were drilled in western Canada, accounting for 65 per cent of all wells drilled.

ERCB and independent third party to review Alberta pipeline safety In response to recent high-profile spills and increased public concern over pipeline integrity, the Alberta government will be putting the pipeline sector under the microscope.

Alberta Energy Minister Ken Hughes has requested that the Energy Resources

Conservation Board (ERCB) retain an independent third party to examine elements of the province’s pipeline system.

“The spotlight is on pipelines, and I have challenged the industry that they need to perform,” Hughes said during a press conference at Calgary’s McDougall Centre.

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SEPTEMBER 2012 • oil & gaS inQuirer

“The scrutiny is at a level that we have never seen before. I welcome that scrutiny, and I believe our pipeline companies do as well.”

Hughes said the ERCB, in conjunction with an independent third party to be contracted, will review three specific

Southern Alberta and integral areas of pipeline safety in the province. They will examine how pipeline integrity is managed, how the safety of pipelines crossing waterways is ensured and how responses to pipeline incidents are handled.

“Premier [Alison] Redford said that it is important for us to know that the pipelines crossing our territory are as safe as they possibly can be. This assurance is fundamental if we are to earn and retain our social licence to operate,” Hughes said. “Let me also be clear that I will hold industry accountable.”

The new pipeline safety review will run in conjunction with the current incidentspecific investigations that the ERCB is conducting. The safety review will be broader in scope and will look at existing regulations and industry best practices from Alberta and around the world. At the conclusion of the review, a report will be submitted to Hughes.

According to Alberta Energy, the province has almost 400,000 kilometres of provincially regulated pipeline. The number of incidents has been steadily declining, to 641 in 2011 from 885 in 2007. All incidents, ranging from contact with a pipeline that does not cause a release to a spill, must be reported to the ERCB.

“As leaders in energy production and regulation, our pipeline integrity standards must be among the best in the world. If changes are needed, Albertans can rest assured that we will make them,” Hughes said.

“The energy industry is the economic lifeblood of our province, and at the same time we want to ensure that Albertans have

“The Alberta government’s policy of letting companies monitor and determine their own oil spill cleanup plans is another flaw in the government’s pipeline management,” said Greenpeace Canada climate and energy campaigner and member of the Lubicon Cree First Nation, Melina Laboucan-Massimo.

“ After witnessing what a pipeline spill has done to my home community of Little Buffalo over the last year, it is clear that we need an independent review now.”

— Melina Laboucan-Massimo, energy campaigner clean water, clean land and clean air. Today we are taking significant steps to ensure this will be the case for decades to come.”

At t he sa me t i me t hat Hughes announced the pipeline safety review, Greenpeace Canada released photos of oil contamination as well as water and soil samples that it said call into question the Alberta government’s oversight of oil spill cleanup measures. The photos, which were recently taken from a pond near the site of the April 2011 Plains Midstream Rainbow Pipeline oil spill, were revealed during a press conference on the steps of the Alberta legislature.

“After witnessing what a pipeline spill has done to my home community of Little Buffalo over the last year, it is clear that we need an independent review now.”

In a press release, Greenpeace said Alberta has been hit by three major oil spills in just over a month and suffers over 600 pipeline incidents every year. In a one-week period recently, more than 50 groups called on the premier to establish an independent review that would address gover nment oversight, reg ulations, enforcement, follow-up and Alberta’s pipeline infrastructure itself.

— DAILY OIL BULLETIN

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North West Upgrading building momentum About 1,000 people are working on North West Upgrading Inc.’s Alberta upgrader/ refinery project—about 325 at the company’s own offices and the rest at contractors’ offices, said chairman Ian MacGregor.

So far the company has spent about $600 million, MacGregor told the TD Securities Calgary Energy Conference.

Components with long delivery times have been ordered and engineering and design activities are underway.

“We hope to sanction in about the third quarter of this year,” MacGregor said of the pending fi nal investment decision on whether to proceed with construction of the $5.5-billion upgrader and refinery.

Construction of the 50,000-barrelper-day fi rst phase of the 150,000-barrelper-day project is expected to take about 36 months. North West hopes to have the plant in the Industrial Heartland area near Edmonton on stream by mid-2015.

Alberta government royalty-in-kind bitumen will provide 37,500 barrels per day of the feedstock for Phase 1. The remaining 12,500 barrels per day of bitumen has been committed by Canadian Natural Resources Limited, co-owner of the planned refinery through its 50/50 North West Redwater Partnership with North West.

“If the project had been in operation last year, the Alberta government would have made about $500 million more turning their bitumen into diesel fuel than they made by selling it as diluted bitumen,” MacGregor said.

Upgrading and refining will be provided on a cost-of-service contract similar to a pipeline toll in some ways, he said.

“We earn a 10 per cent equity return on a cost-of-service basis. We keep 15 per cent of the value between product revenue that we generate and the cost of feedstock and the operating cost.” And the owners keep the additional capacity created as the refinery is debottlenecked in the future.

CO2 emissions are to be diverted from the atmosphere into central Alberta oilfields to enhance oil recovery under an agreement with Enhance Energy Inc., which will build and operate a CO2 pipeline for that purpose.

— DailY oil BulleTin

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Climate change a hot issue in Saskatchewan

trusted source for information, but they are confused about the impacts of CO2 on the environment, and don’t know what the risks and benefits of carbon capture and storage are,” said Carmen Dybwad, chief executive officer of IPAC-CO2. “People are overwhelmed by the information that is out there, which is why there needs to be a group like IPAC-CO2 who can communicate about CCS and climate change.”

Responses for the survey were collected from 1,003 Saskatchewan residents between May 30 and June 8 using Insightrix Research Inc.’s proprietary online panel, SaskWatch Research.

“We set specific quotas for demographic variables, such as age, gender, education, region, income and voting, to ensure the sample of respondents mirrored the general population throughout Saskatchewan,” said Briana Brownell, manager of analytics at Insightrix.

Thirty-two per cent of those surveyed believe that CCS could be very or fairly effective in fighting climate change, while 39 per cent think it would not be very effective, or not at all effective.

The remaining 29 per cent are unsure, which is a notable increase from the 2011 research where 20 per cent of those surveyed did not have an opinion whether or not CCS would be effective in fighting climate change.

The majority of Saskatchewan residents (58 per cent) believe that climate change is occurring due to a combination of human activity and natural climate variation. Some (21 per cent) believe that climate change is occurring due to human activity, and even fewer think that climate change is occurring only because of natural variation (16 per cent).

“Compared to 2011, the opinions of Saskatchewan residents on their anticipated level of concern if a CO2 storage site was to be located within five kilometres of their home has shifted,” said Brownell. “ T he pr op or t ion who wou ld b e fairly or ver y worried has decreased (from 49 per cent to 43 per cent), while a higher proportion of residents are unsure (10 per cent versus 16 per cent).”

CCS involves extracting CO2 during the process of power generation or from heavy industrial operations such as steel mills or cement plants, compressing it and storing the CO2 permanently in depleted oil or gas fields or saline aquifers.

IPAC-CO2 Research Inc., the International Performance Assessment Centre for geologic storage of Carbon Dioxide, is an environmental non-government organization created to provide independent risk and performance assessments, develop standards, conduct applied research and engage communities, government and industry leaders on all aspects of CCS.

JUL/11

JUL/12

JUL/11

JUL/12

WELLS SPUDDED

403

268

WELLS DRILLED

350

271

Around 70 per cent of Saskatchewan residents surveyed said they were worried about the impact of

Photo: Joey Podlubny

climate change.

Saskatchewan residents have strong but divided opinions about climate change and carbon capture and storage (CCS) technology, concludes a public opinion survey commissioned by IPAC-CO2 Research Inc. “Almost seven in 10 (68 per cent) residents are concerned about climate change,” said Joe Ralko, director of communications for IPAC-CO2, who managed the survey.

“However, there is no consensus on how to address the problem. That could be because the survey discovered there is no agreement on what residents believe to be the main sources of greenhouse gas emissions. What the people of Saskatchewan are saying is that whatever steps are taken to mitigate climate change must be effective.”

Saskatchewan residents are clear on their trusted sources of information on climate change.

“Our study shows scientists and researchers (73 per cent) are the most SASKATCHEWAN WELL ACTIVITY

JUL/11

JUL/12

WELL LICENCES

325

250

▼

▼

▼

Source: Daily Oil Bulletin

OIL & GA S IN Q UIRER • S E P T E M B E R 2 0 1 2

69

Saskatchewan

Smart Sand, Canadian Pacific Railway building Bakken frac sand facility

the new rail terminal still serves the Bakken tight oil play.

A new frac sand transload facility serving Bakken shale producers in the Williston Basin will be first terminal built under a new partnership agreement between Smart Sand Inc. and Canadian Pacific Railway Limited (CP).

The Makoti, N.D., facility, expected to be the region’s largest, will begin operations next year.

In the strategic long-term partnership announced in July, the two companies will supply and ship premium, Northern White frac sand to the unconventional oil and gas industry in key North America producing regions including the Bakken and Eagle Ford formations and the Utica and Marcellus shales.

“We are excited to partner with transportation leader Canadian Pacific to bring our combined expertise to those companies working in the Bakken Shale formation,” Charles Young, founder, president

and board member of Smart Sand, said in a news release.

Smart Sand offers substantial dry sand capacity and 100-plus years of proven reserves, plus direct rail access for unit trains, he said. “We believe the new North Dakota transload facility offers a unique combination of cost effectiveness, reliability and product flexibility.”

Young said the partners look forward to offering similar services in other producing regions while building strong relationships in the Williston Basin.

“Smart Sand has prime resources and processing capabilities, which align well with CP’s shipping presence in the energy sector,” said Jane O’Hagan, CP’s executive vice-president and chief marketing officer.

“This agreement with Smart Sand demonstrates our commitment to provide our customers with end-to-end

transportation service that is competitive and reliable.”

Smart Sand’s primary facility, which opened in late June 2012 and is located on the CP rail line in Oakdale, Wis., will supply premium Northern White frac sand in a broad range of mesh sizes to the new transload facility.

Based on Smart Sand’s initial processing capacity of more than one million tonnes per year, plus the company’s extensive proven reserves, the facility will be able to quickly fulfill long- and short-term orders while providing direct rail access for unit trains.

CP is the only North American railroad to serve the Bakken formation, the Alberta Industrial Heartland near Edmonton and the Marcellus Shale. In addition, CP is the only Class I railway to connect the energy hubs of the U.S. Midwest, Alberta and Saskatchewan to the northeastern United States.

Through its network to the northeastern United States and through the Kansas City gateway to the U.S. Gulf Coast, CP is able to partner with the energy industry to facilitate growth in moving oil and energy-related materials. Each year, CP moves hundreds of thousands of carloads of energy-related products, including crude oil, sulphur, fuels, diluents and materials key to the energy industry, such as pipe and frac sand.

Smart Sand is one of the leading providers of high-quality proppant and related logistics services to the oil and gas industry in North America. All of its facilities are located near major rail transport lines, ensuring reliable, cost-effective delivery to major shale plays in the United States and Canada.

— DailY oil BulleTin

Pet roBa k ken Energ y Ltd. says wet weather delayed its second-quarter capital program by approximately three weeks, but it expects to catch up before the end of the year.

With average second-quarter production of 38,700 barrels of oil equivalent per 70

SEPTEMBER 2012 • oil & gaS inQuirer

day based on field estimates, the company is on target to meet production and capital guidance for 2012 and is ahead of last year’s second-quarter output of 35,300 barrels per day.

This year, second-quarter production was comprised of more than 14,800 barrels

per day from the Bakken business unit, over 15,600 barrels per day from the Cardium business unit, and the remainder from its Saskatchewan conventional and Alberta/ B.C. business units.

Second-quarter 2012 production levels are after the 3,930 barrels per day of

Photo: Gerald Ford

PetroBakken provides operational update

Saskatchewan

asset dispositions completed recently and reflect additional shut-in production of approximately 2,300 barrels per day due to spring breakup conditions.

In June, estimated average output was 37,500 barrels per day with an 84 per cent liquids weighting.

In the second quarter, PetroBakken drilled 15 (nine net) wells and completed 24 (17 net) wells. Ten (six net) wells were drilled and nine (six net) wells were completed in the Bakken business unit, four (two net) wells were drilled and 13 (10 net) wells were completed in the Cardium business unit, and one well was drilled and two (one net) wells were completed in its Saskatchewan conventional business unit.

Only si x (t hree net) wells were brought on production in June, leaving 23 (15 net) wells in inventory that will be brought on as activity fully resumes after spring breakup.

Persistently wet weather in June caused extended road bans and limited service rig and truck access, which, combined with several plant and battery turnarounds throughout the month, resulted

in additional shut-in production of approximately 2,000 barrels per day. Field conditions are now improving, and the company has 13 drilling rigs operating with extensive well servicing operations underway.

PetroBakken expects to have 15 drilling rigs operating for most of the second half of 2012: seven rigs in the Cardium drilling 57 net wells, six rigs in the Bakken drilling 75 net wells, one rig in southeast-

PetroBakken expects to have six rigs drilling the Bakken and one rig drilling conventional assets in southeastern Saskatchewan for the remainder of the the year.

With approximately 75 per cent of its planned wells for 2012 yet to be drilled, PetroBakken anticipates continued volumes growth during the second half of the year and reiterates its 2012 exit rate production guidance for 2012 of 52,000– 56,000 barrels per day.

Consistent with previous years, the second half of the year will be the company’s period of highest activity and capital intensity.

ern Saskatchewan drilling 27 net wells, and one rig drilling four net wells in its emerging plays in Alberta.

Facility investments continued in the Cardium business unit in the second quarter as PetroBakken brought a new battery online in West Pembina, allowing it to tie in associated gas production and provide central oil processing to reduce trucking costs.

— DailY oil BulleTin

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oil & gaS inQuirer • SEPTEMBER 2012

71

Technology News

CCEMC announces $46 million for new carbon and clean technology efforts

Photo: Joey Podlubny

The Climate Change and Emissions Management Corporation (CCEMC) is providing $46 million in funding to support six new clean technology projects.

The projects have a combined value of more than $327 million.

“The CCEMC is supporting industry efforts to reduce greenhouse gas emissions from fossil fuels while helping to ensure [that] Alberta can continue to be a global energy leader, even as we transition to other sources,” said CCEMC chair Eric Newell.

“By addressing challenges facing Alberta’s large emitters we are funding projects that have tremendous potential to reduce Alberta’s greenhouse gas emissions over the long term.”

The organizations receiving funding from CCEMC are: • Cenovus Energy Inc.—$10 million for a 10-megawatt Chemical Looping Steam Generator pilot at Christina Lake near Fort McMurray • Husky Energy Inc.—$2.9 million for

the Lashburn CO2 capture demonstration project near Lloydminster • Imperial Oil Limited—$10 million for a cyclic solvent process pilot in Cold Lake • Inventys Thermal Technologies Inc.—$3 million for the VeloxoTherm CO2 capture project at Joffre • MEG Energy Corp.—$10 million for heavy crude quality improvement in the Alberta Industrial Heartland Region • N-Solv Corporation—$10 million for the N-Solv BEST pilot plant at Suncor Dover in Fort McMurray “These innovative projects continue to demonstrate how Alberta leads the way in supporting and developing responsible, clean-energy technology,” said Diana McQueen, Alberta Environment and Sustainable Resource Development minister.

“I’m confident that continued innovation by industry will help Alberta demonstrate leadership in environmental management while meeting growing global energy demand.”

Most of the CCEMC investment targets in situ oilsands investments.

CCEMC estimates these six projects will combine to reduce emissions by more than 183,000 tonnes over 10 years, and that does not consider further emissions reductions as technology is commercialized. The potential emissions reductions that could be realized through build out and commercialization of these technologies is estimated at five megatonnes by 2021. For every dollar CCEMC invests in these projects, about another seven dollars are also invested.

The six projects are from the CCEMC’s fourth round of funding that was announced in April 2011. The maximum CCEMC funding per project for this round is $10 million.

With this announcement, CCEMC has shared plans to support 31 projects with a total commitment of more than $156 million. In total, these 31 projects are valued at more than $828 million. Combined, the CCEMC estimates they will reduce emissions by nearly eight megatonnes over 10 years in Alberta. In addition, the organization has also announced support for biological and adaptation projects.

The CCEMC focuses on stimulating transformative change. Enabled through regulation, the CCEMC is an independent not-for-profit organization that provides ongoing, dedicated funds to support the discovery, development and deployment of innovative clean technology.

Funding for CCEMC is collected from industry. Since 2007, Alberta companies that annually produce more than 100,000 tonnes of greenhouse gas emissions over a baseline are legally required to reduce their greenhouse gas intensity by 12 per cent.

Companies have three options to meet their reduction target: improve the efficiency of their operations, buy carbon credits in the Alberta-based offset system, or pay $15 into the Climate Change and Emissions Management Fund for every tonne over the reduction limit.

The CCEMC invests the money collected in clean technology. The CCEMC is now in the fourth year of operations. By the end of the 2011/12 operating year, the CCEMC expects to be involved in close to $1 billion of active projects that reduce emissions and spur innovation in clean technology and help move toward more sustainable practices.

OIL & GA S IN Q UIRER • S E P T E M B E R 2 0 1 2

73

Technology News

Tervita introduces new evaporator technology Tervita Corporation has entered into an agreement to license and market a new technology that will treat evaporator blowdown in a more responsible, sustainable and cost-effective way for steam assisted gravity drainage (SAGD) operators.

The technology, called THi-pHEC ( Treat ment of High-pH Evaporator Concentrate) was developed by Veolia Water Solut ion s a nd Tec h nolog ies Canada Inc., a n inter nat iona l pro vider of water and waste-water management solutions.

“Ter vita is constantly looking for ways to innovate and improve how we protect and clean our earth,” said John Gibson, Ter v ita president and Caption here chief executive officer. “This agreement helps ensure we are in a position to offer our oil and gas customers technologies and solutions that help facilitate sustainable and responsible development.”

Evaporator blowdown is the remaining waste solution after produced water

September 24 – 28, 2012 Calgary, Alberta, Canada

has been treated. Previously, evaporator blowdown was injected into caverns as waste. The new technology will create two waste streams where there was previously one, providing producers with more environmentally appropriate disposal.

Many SAGD operations produce waste-water that contains dissolved silica maintained in a high-pH solution. This waste solution is not suitable for typical deep well injection and is currently disposed of in caverns.

Ter vita’s new treatment will remove silica from the waste-water and create a solution that will meet criteria for Class 1B disposal and a dry solid suitable for Class 2 landfill disposal.

“Tervita and Veolia have a mutual goal to minimize waste from production,” said Jim Brow n, chief executive officer of Veolia Water Solutions and Technologies Industrial Markets in North A merica. “THi-pHEC technology is an ideal fit with the energy solutions and capabilities that Tervita

of fers. T h is col laborat ion helps ensure responsible and sustainable treatment and disposal of waste.”

Ter v ita is currently engineering a pilot plant for this technology and expects construction to be complete

by April 2013, with plans to move to a SAGD operation later in the year.

“This technology is mobile, which will cut costs for producers, save time and transport, and will improve safety by keeping more trucks off the road,” said Dave Tyson, Tervita’s director of onsite environmental solutions.

In addit ion to evaporator blowdow n t r eat me nt , Te r v it a of fe r s a number of on-site ser v ices to SAGD operations, including centrifugation of slop oil production, off-spec production and lime sludge. T he company is currently commissioning two on-site centrifuge pilot plants to demonst rate and quantif y t he value to i n d u s t r y. T h e p i l o t p l a n t s a r e expected to be f ully operational by August 2012.

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74

S E P T E M B E R 2 0 1 2 • OIL & GA S IN Q UIRER

@IPC_Calgary @petroleumshow

Technology News

Victor Group launches Ecoshield fabric for oil and gas clothing The Victor Group Inc. Apparel and Spec ia lt ies Div ision i nt roduced Ecoshield®, the latest addition to Victor Group’s Eco Intelligence® collection of sustainable products last month.

Ecoshield is a new, fire-resistant, environmentally friendly fabric that will be used to make protective clothing for individuals working in hazardous occupations and environments. Created within a closed-loop system, Ecoshield is the fi rst fabric to contain post-consumer recycled aramid fabric waste.

Ecoshield fabrics provide the same protection for the wearer as virgin fabrics, and meet CGSB 155.20–2000 and HRC 2–ATPV 9.6 cal/cm2 standards. In addition to the protection provided by the fabric, wear tests conducted by Victor Group have proven the fabric is more comfortable than virgin aramid products. Furthermore, Ecoshield fabrics can be used to create clothing that features a unique denim-like appearance.

“Ecoshield represents a significant innovation, revolutionizing the industry’s

supply chain with its closed-loop concept,” said Al Britton, director of sales and product development. “We are excited to be able to provide an eco-friendly and safe fabric option for individuals working in hazardous situations.”

“ We are excited to be able to provide an eco-friendly and safe fabric option for individuals working in hazardous situations.”

— Alain Duval, president and chief executive officer of Victor Group

The closed-loop recycling process that is used to create Ecoshield is an innovative manufacturing achievement for Victor Group. Coveralls worn by workers in the target industries are usually destined for the landfill once they have reached the end of their useful life.

Instead, Victor Group will be collecting

these worn coveralls, and using them as the raw material for their Ecoshield fabrics, keeping them out of landfills and giving them a second life.

Once an article of clothing has reached the end of its life, Victor collects the clothing, cleans it, strips the buttons and closures, and cuts and shreds the fabrics to fibre. From the fibre, the company makes new yarn, which is woven into a unique recycled fabric, ready to be manufactured into a brand new coverall with all safety features and wearability of the original item of clothing.

“There are many aspects of Ecoshield that make it an innovative product, but the key feature in my mind is being able to close the loop and maintain the level of protection that a virgin fabric provides,” said Alain Duval, president and chief executive officer of Victor Group. “Personal protection is the primary objective of the clothes. We are extremely proud to be able to offer a closed-loop product that provides exceptional protection for both the consumer and the environment.”

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oil & gaS inQuirer • SEPTEMBER 2012

75

Technology News

Electric heat mobilizes bitumen in carbonates By pat roche Athabasca Oil Corporation says a proofof-concept field test—using electricity instead of steam—heated a bitumen-rich carbonate reservoir at a much lower temperature than steam assisted gravity drainage (SAGD) and produced 100 barrels of oil per day—even though it wasn’t a production test.

“It proved the formation conductivity—how fast heat spreads in the formation—and it proved that we can mobilize oil at lower temperatures,” Ian Atkinson, Athabasca’s vice-president of geoscience, told a conference call.

The process—called thermal assisted gravity drainage (TAGD)—uses electric cables in horizontal wells to heat the reservoir via conduction heating. The field test was done in the bitumen-bearing Leduc carbonates at Athabasca’s Dover West property 90 kilometres northwest of Fort McMurray, Alta.

The conduction-heating technology is meant to mobilize bitumen at low

temperatures, and the field test was designed to determine how low the temperature could be and still mobilize bitumen.

Athabasca said bitumen was mobilized at a temperature of 70–90 degrees Celsius versus well over 200 degrees for SAGD. Athabasca said it recovered 60–70 per cent of the bitumen that had been heated to more than 80 degrees. The heating cables were fully operational throughout the field test.

The goal was to pump the heated bitumen to a producing well until there was no more oil mobilized at that temperature, shut the well back in, heat it and then open it up again for another production stage.

“On our fi rst production segment [of the test], we were pleased to see that we had mobilized enough oil that the pump had to work at full capacity and [was] producing at 100 barrels a day—even though this was not a production test,” Atkinson told analysts.

Who, What, Where of the Canadian Oilpatch

So far, t wo heating and product ion pha se s have been completed.

The production well is currently shut in for heating, preparing for a third production phase slated for October.

In this final phase of the TAGD field test, heating is occurring in a heater/ producer well in addition to in a dedicated heating well.

Atkinson emphasized this was a $30-million field test, not a pilot costing hundreds of millions of dollars.

Athabasca said the test successfully delivered all of its objectives, confirming that it could effectively heat the reser voir and mobilize bitumen to a production well, paving the way a TAGD pilot/demonstration project, pending regulatory approval.

The proof-of-concept field test also gathered data on the Leduc reservoir permeability and thermal conductivity and demonstrated the reliability and performance of the heating cables.

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SEPTEMBER 2012 • oil & gaS inQuirer

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Technology News

Athabasca said field testing indicates effective reservoir permeability is considerably higher than previously anticipated.

Reservoir modelling based on field testing suggests commercial-scale wells heated to 120–140 degrees would yield single-well production rates of 1,000–2,000 barrels per day, depending on reservoir thickness.

Because TAGD doesn’t require steam generation and water treatment, capital costs are about 50 per cent lower than for SAGD, the company said.

Athabasca expects to get regulatory approval for the TAGD pilot/demonstration project by year’s end. Work continues on design and procurement, and the company said an innovative heater assembly facility is being built near Strathmore, Alta.

Pending reg ulator y approva l, Athabasca plans to launch its TAGD pilot/demonstration project in 2013, with a two-year drilling, construction and installation phase, followed by a

production phase. The company hopes to achieve the objectives of the pilot/ demonstration project within two years of start-up.

“This pilot is to confi rm recovery factors, confi rm energy balance and give us more indicative rates of the commercial [scale] because we will heat a full column of reservoir up to target temperature of 125–140 degrees. And in that we will see all of the reservoir drive mechanisms,” said Atkinson.

Flexpipe Systems wins first major Australian pipeline project Flexpipe Systems has been awarded its biggest Australian project to date.

Having worked closely with Australian distributor Energy Process Services and contractor Lean Field Developments Flexpipe has secured the sale of 175 kilometres of combined FlexPipe Linepipe a n d F l e x P i p e H i g h -Te m p e r a t u r e Linepipe.

“This is a historic achievement for Flexpipe Systems,” says David McColl,

vice-president, QHSE and business development. “Over the past two years, our team has diligently been working with Australian energy companies and regulators to ensure all engineering design, safety, quality and environmental requirements are met. A project of this magnitude solidifies the presence of Flexpipe products in the Australian market.”

Flexpipe went through two years of in-depth technical inquiries and testing to

Safe heat when you need it!

complete the AS2885 compliance process, proving the company’s suitability for the project. The area in which the project is based is also env ironmentally sensitive, making FlexPipe L i ne pip e a n e v e n b e t te r s olut ion because of its minimal environmental disturbance.

The pipeline project stretches from the remote Cooper Basin region in South Australia to South East Queensland.

Enhancing Shale Oil & Gas Development Strategies Utilizing Drilling, Completion and Reservoir Engineering Knowledge to Advance Exploration and Diversify Shale Portfolios September 12-13, 2011 | Denver, CO Optimizing shale expansion through growing technology innovations and trends.

We provide: • SRH drilling rig steam heaters • HUH & HHP steam & glycol unit heaters • XEU1 explosion-proof electric air heaters • XDC-01 explosion-proof disconnect switches • TBX1 explosion-proof thermostats • Competitive pricing and quick delivery Tel 403-730-2488 1-866-701-Heat (4328) Info@HazlocHeaters.com www.HazlocHeaters.com Calgary, AB Canada

Quality is… customers that come back, and products that don’t.

Featured Speakers Include: Mark Williams, SVP of Exploration & Development, Whiting Petroleum Bryan Lastrapes, Business Development Manager for North America, Shell Jennifer Leslie-Panek, Ph.D., P. Geoph., Geophysicist- COG, Shale Gas, Nexen Tisha Conoly Schuller, President & CEO, Colorado Oil & Gas Association

Who Should Attend: marcus evans invites Oil & Gas Upstream VP’s, Directors, and Managers with involvement in Shale and responsibilities in: • Reservoir Engineering • Exploration • Resource / Business Development • Geology / Geoscience • Drilling • Production • Completions Please Contact: Michele Westergaard T: 312 540 3000 ext. 6625 E: Michelew@marcusevansch.com

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Dragon products . . . . . . . . . . . . . . . . . . . . . . . . . . 6 ecoquip rentals & Sales ltd . . . . . . . . . . . . . . . . 31 edmonton exchanger & Manufacturing ltd . . . . 15 enform . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75 enTreC Corporation. . . . . . . . . . . . . . . . . . . . . . . 5 eV Canada inc . . . . . . . . . . . . . . . . . . . . . . . . . . . 39 expertec Van Systems inc. . . . . . . . . . . . . . . . . .60 general Motors of Canada ltd . . . . . . . . . . . . . . 27 Hazloc Heaters . . . . . . . . . . . . . . . . . . . . . . . . . . 77 imagewear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 imperial oil. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 jobsite123.ca . . . . . . . . . . . . . . . . . . . . . . . . 23 & 25 Joule Technical Sales inc . . . . . . . . . . . . . . . . . . .68 lloydminster Heavy oil Show . . . . . . . . . . . . . . .40 Marcus evans, inc . . . . . . . . . . . . . . . . . . . . . . . . 77 Maxfield inc. . . . . . . . . . . . . . . .outside back cover Meridian Manufacturing . . . . . . . . . . . . . . . . . . . 16 Mpi-Marmit plastics inc . . . . . . . . . . . . . . . . . . . 71 naiT Corporate and international Training. . . . . 53 neTZSCH Canada inc. . . . . . . . . . . . . . . . . . . . . . 61 nexus exhibits ltd. . . . . . . . . . . . . . . . . . . . . . . . 17 norwesco Canada ltd . . . . . . . . . . . . . . . . . . . . .64

oil lift Technology inc . . . . . . . . . . . . . . . . . . . . . 50 penfabco ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 phoenix fence inc . . . . . . . . . . . . . . . . . . . . . . . . 71 platinum grover int. inc . . . . . . . .inside front cover pTi group inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67 rainmaker global Business Development . . . . . 56 Sirius instrumentation and Controls inc. . . . . . .66 Sprung instant Structures. . . . . . . . . . . . . . . . . . . 7 Systech instrumentation inc . . . . . . . . . . . . . . . . 38 Tank gauging Systems. . . . . . . . . . . . . . . . . . . . . 47 TCa Marketing ltd. . . . . . . . . . . . . . . . . . . . . . . . 65 Trans peace Construction (1987) ltd. . . . . . . . . . 47 Triland international . . . . . . . . . . . . . . . . . . . . . . 55 Vertigo Theatre Society . . . . . . . . . . . . . . . . . . . 76 V.J. pamensky Canada inc . . . . . . . . . . . . . . . . . . .11 Westeel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Yantai Jereh petroleum equipment Technologies Co ltd. . . . . . . . . . . . . . . . . . . . . . . 28 ZCl Composites inc. . . . . . . . . . . . . . . . . . . . . . . 32

420228 Bear Slashing Inc full page 路 fp IBC

TOG E T HE R WE CAN

For over 10 years MaXfield has quietly been gaining the expertise and experience to handle your next project.

From custom vessels to structural steel, piping and modular packaged equipment, MaXfield is now your one-stop shop for industrial fabrication.

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