Oil & Gas Inquirer | April 2011

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F E A T U R E S

14

Automating manufacturing profits

By Graham Chandler

Flexpipe mechatronics specialist Greg Henry says automation is crucial for controlling costs and quality in energy-related manufacturing

21

8

APRIL 2011 • OIL & GAS INQUIRER

A liquid cure for gas pain

By Elsie Ross

With gas prices low and crude high, Alberta producers are hunting for oil in the Montney formation

R E G I O N A L

25

N E W S

British Columbia

41

• Encana and PetroChina eye Asian LNG

• Service firms run short of skilled

market for Cutbank Ridge gas

drilling and completion workers

By Elsie Ross

29

Northwestern Alberta

By James Mahony

49

• Trilogy’s push for Montney oil at

look strong for 2011

• Strategic updates its plans for Steen

33

Northeastern Alberta

By Richard Macedo

53

By Paul Wells

37

pending regulatory review

55

ferrying crews over rough seas

• Alberta government clinches BRIK deal for North West Upgrading/CNRL

East Coast • Operators end helicopter flights

Central Alberta

By Elsie Ross

Central Canada • Quebec bans new shale gas drilling

• Long Lake project continues to struggle despite Q4 production gains

Saskatchewan • Saskatchewan’s drilling prospects

Kaybob powers Alberta land sale River and Maxhamish

Southern Alberta

By Pat Roche

57

International • DOE says Keystone pipeline can meet Gulf refiners’ crude demand

By Elsie Ross

I N

12

E VE R Y

I S S U E

Statistics at a Glance

61

• Completions data, spot gas prices, gas

Tools of the Trade • Camex Equipment Sales & Rentals Inc.,

storage, drilling activity and more

a veteran manufacturer of customized oilfield vehicles, unveils a scissorneck

59

trailer in its new Low Rider line.

On The Job • As a professional estimator for Vista Projects Limited, Jeff Young specializes

62

Political Cartoon

in coping with unknown factors—like whether field construction crews will work within the specified budget.

Cover design: Aaron Parker

(780) 466-6658

OIL & GAS INQUIRER • APRIL 2011

9

Editor’s Note Vol. 23 No. 3 President & ceo Bill Whitelaw | bwhitelaw@junewarren-nickles.com Publisher Agnes Zalewski | azalewski@junewarren-nickles.com

Mike Byfield | mbyfield@junewarren-nickles.com

Associate Publisher Chaz Osburn | cosburn@junewarren-nickles.com

Technology breeds a new form of ignorance

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

Mike Byfield | mbyfield@junewarren-nickles.com ASSISTANT Editor

Joseph Caouette | jcaouette@junewarren-nickles.com Editorial Assistance

Janis Carlson de Boer, Tracey Comeau, Marisa Kurlovich proofing@junewarren-nickles.com Contributors

Richard Macedo, James Mahoney, Pat Roche, Elsie Ross, Paul Wells Creative Print, Prepress & Production Manager

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Technology not only saves labour, it renders large numbers of people unnecessary to production of basic essentials like food, shelter, clothing and energy. Automation continues to accelerate that trend. While editing this month’s cover article on automation, I found myself wondering yet again what we’re supposed to do with those extra billions of hands.

In medieval Europe, for example, farming occupied 80-90 per cent of the population.

Not a lot of career choices there! Today, thanks to mechanization, fertilization, bioengin­ eering, satellite crop surveying and so on, farmers make up less than one per cent of the North American population. Food is so cheap and abundant that overeating routinely kills even poor Canadians.

It’s the same story in the oilpatch. Shallow wells can be drilled in hours, huge fracs in northeastern British Columbia are managed from Calgary, modern pumpjacks can be monitored and adjusted without stirring from the office, one automation-empowered employee can manufacture more piping, oilfield chemicals and bitumen than ever before.

In previous ages, surplus labour was invested largely in making war or creating religious structures like pyramids and Gothic cathedrals. Today, no major power really wants to fight a rival major power—technology has made warfare itself too dangerous. Nor is any scientifically proficient society willing to invest heavily in architectural works dedicated to a scientifically intangible God. Modern societies address labour surpluses in various ways. Despite its recordshattering industrial expansion, China leaves hundreds of millions on the farm, often in poverty. Western Europe fosters lower workloads per worker through long holidays, early retirement and so on. North America generates personal trainers, grief counsellors, poodle barbers, lap dancers and other less-than-essential occupations. Virtually all wealthy nations pile people into civil services, marketing and ever-increasing periods of schooling—much of which we could do without if necessary.

Frankly, I have no idea what to do with that extra human time/energy, nor do I see anyone else pondering the issue much. As an editor, however, I do see a communication challenge.

Oil and gas is a core industrial product in a society where many folks—including most educators—have little personal experience with any type of core industrial production. More than ever before, the petroleum community must help its neighbours—who are also voters—to understand the operating realities and essential needs of the energy sector.

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Publications Mail Agreement Number 40069240. Postage Paid in Edmonton, Alberta, Canada. If undeliverable, return to: Circulation Department, 800 - 12 Concorde Place, Toronto, ON M3C 4J2 Made in Canada The opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.

N E X T

I S S U E

May Edition

If you know an admirable person to profile

In May, Oil & Gas Inquirer takes a good look

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

at Calgary, which has emerged as a global

or apprentice, field or shop, wise or a little

headquarters for the petroleum service sector

crazy—please give Darrell Stonehouse

over the past generation. Also in this issue, we

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

examine potential opportunities and problems

dstonehouse@june­warren-nickles.com.

with consolidating midstream gas processing

In fact, feel free to sound off about any

along with Rocky Mountain foothills and

concern at all—that’s a personal invitation.

elsewhere in Alberta.

O I L & G A S I N Q U I R E R • april 2 0 1 1

11

Stats

FAST NUMBERS

1

The number of deepwater drilling permits issued for the Gulf since BP’s Macondo well blew out in April 2010. Only in theory has the federal drilling moratorium been lifted.

AT A GLANCE

per cent

The percentage of U.S. domestic oil produced from the Gulf of Mexico, along with 13 per cent of its natural gas.

Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin

MONTH

OIL

GAS

OTHER

TOTAL

MONTH

OIL

GAS

DRY

SERVICE

TOTAL

Mar 2010 Apr 2010 May 2010

264 198 400

579 418 462

198 6 51

1,041 622 913

Mar 2010 Apr 2010 May 2010

548 291 490

681 458 511

109 2 39

20 9 19

1,358 760 1,059

Jun 2010 Jul 2010 Aug 2010

126 131 168

117 110 135

41 38 43

284 279 346

Jun 2010 Jul 2010 Aug 2010

295 193 452

153 9 156

40 16 40

16 4 15

504 222 663

Sept 2010 Oct 2010 Nov 2010

357 404 579

638 460 847

59 46 169

1,054 909 1,595

Sept 2010 Oct 2010 Nov 2010

617 678 868

790 581 989

45 39 75

23 18 165

1,475 1,316 2,097

Dec 2010 Jan 2011 Feb 2011

676 226 353

403 145 294

294 82 127

1,373 413 774

Dec 2010 Jan 2011 Feb 2011

1,061 409 723

559 201 378

78 33 38

238 17 99

1,936 660 1,238

Wells Drilled In British Columbia

Saskatchewan Completions

Source: B.C. Oil and Gas Commission

Source: Daily Oil Bulletin

MONTH

WELLS D R I L L E D

CUMULATIVE *

MONTH

OIL

GAS

OTHER

TOTAL

Mar 2010 Apr 2010 May 2010

98 56 54

264 320 374

Mar 2010 Apr 2010 May 2010

223 92 86

32 10 7

8 3 3

263 105 96

Jun 2010 Jul 2010 Aug 2010

42 65 45

416 481 526

Jun 2010 Jul 2010 Aug 2010

149 220 198

7 7 12

11 0 7

167 227 217

Sept 2010 Oct 2010 Nov 2010

40 42 43

566 608 651

Sept 2010 Oct 2010 Nov 2010

197 201 217

5 12 3

6 11 64

208 224 284

Dec 2010 Jan 2011 Feb 2011

49 62 69

700 62 131

Dec 2010 Jan 2011 Feb 2011

340 136 321

2 4 6

11 3 7

353 143 334

*From year to date

12

30

APRIL 2011 • OIL & GAS INQUIRER

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

GAS STOR AGE

Source: Natural Gas Exchange Inc.

Source: U.S. Energy Information Administration

3.60

2.00

$3.489/GJ Total vol.: 1,142 TJ Transactions: 197

1.62 Tcf Year ago: 1.62 Tcf 5-year avg: 1.59 Tcf

1.75

3.45

3.30 Cdn$/GJ

in the United States

Feb 16

Feb 23

Mar 2

Mar 9

1.50

Mar 16

Source: Natural Gas Exchange Inc.

Tcf

Feb 11

Feb 18

Feb 25

Mar 4

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada March 14, 2011 Source: Rig Locator

Alberta February 2011 Source: Daily Oil Bulletin

ACTIVE

DOWN

TOTAL

Alberta

ACTIVE (Per cent of total)

Western Canada 422

151

573

74

British Columbia

59

30

89

66

Manitoba

13

6

19

68

Saskatchewan

99

19

118

84

WC Totals

593

206

799

74

1

0

1

100

Northwest Territories

OIL WELLS

Alberta

GAS WELLS

Feb 11

Feb 10

Feb 11

Feb 10

Northwestern Alberta

94

46

144

89

Northeastern Alberta

48

8

4

1

Central Alberta

168

68

46

49

43

28

100

166

353

150

294

305

Southern Alberta TOTAL

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada March 14, 2011 Source: Rig Locator

Alberta February 2011 Source: Daily Oil Bulletin

ACTIVE

DOWN

TOTAL

ACTIVE

Western Canada 418

217

635

66

British Columbia

37

7

44

84

Manitoba

15

2

17

88

Saskatchewan

151

43

194

78

WC Totals

621

269

890

70

0

1

1

0

Quebec

COALBED METHANE

Alberta

Alberta

Mar 11

Source: U.S. Energy Information Administration

BITUMEN WELLS

Feb 11

Feb 10

Feb 11

feb 10

Northwestern Alberta

2

1

18

2

Northeastern Alberta

0

0

48

8

Central Alberta

10

27

56

30

Southern Alberta

34

49

0

0

TOTAL

46

77

122

40

OIL & GAS INQUIRER • APRIL 2011

13

Feature

Automating manufacturing Photo: Christina Ryan, Inez Photography

profits

14

APRIL 2011 • OIL & GAS INQUIRER

Feature

From making pipe to blending chemicals to manufacturing synthetic oil, automation is king

By Graham Chandler

A

Greg Henry, process technology manager at Flexpipe Systems, stands by its automated production line. Fibreglass strands from 32 bobbins are wrapped around a central HDPE liner.

few years ago, Greg Henry arrived at Flexpipe Systems as a student intern, straight out of his studies in mechatronics in manufacturing at the University of Calgary. The company would soon ramp up an entirely new production line with extensive automation. Considering that automation is Henry’s passion, he reckons himself pretty lucky. “It was a period of growth and we were doing something relatively high tech,” says the affable, lanky engineer, who’s now Flexpipe’s process technology manager.

Flexpipe Systems, a Calgary-headquartered division of ShawCor Ltd., manufactures spoolable composite pipeline systems used in oil- and gas-gathering systems, water disposal, CO2 injection pipelines and other applications that call for corrosionresistant, high-pressure pipeline. “About a year ago, we knew we were going to require a new line, based on volume forecasts,” Henry says. The energy economy was picking up, marketing teams had done their homework and it was clear a massive increase in output was called for.

Henry and fellow engineer Serge Bourgea, project manager, set out to design the new line in-house. The pair set ambitious goals.

“We would try and make it a 50 per cent higher capacity than our existing line, in the same amount of space,” says Henry. “That was the main corporate goal. Then we had efficiency goals, like five per cent less material used and 20 per cent less energy consumed.”

OIL & GAS INQUIRER • APRIL 2011

15

Feature

The manufacturing process begins with a central highdensity polyethylene (HDPE) liner. Thirty-two bobbins wound with fibreglass are arranged to spin around the liner, applying layers of reinforcement over eight stages. The pipe moves linearly at 15 metres per minute. Further down the line, it’s coated over with an HDPE jacket. Henry points out some automatic features. “Here is a proximity sensor,” he says, pointing to a small device aimed at each strand of reinforcement. “If a strand breaks, the process will automatically stop.”

On each bobbin is a variable brake that controls torque and tension electrically. “We also automatically detect bobbin size variations,” Henry says. Automation is essential, he adds, due to speed. “Some of the things you could do manually become a lot harder when [the manufacturing process] is running fast. You’re limited by people’s ability to change those winders, for example, when they are running extremely fast.”

As well, it’s difficult to eyeball flaws, “so we use things like photo-eyes and lasers to see what’s happening,” Henry says. “The accuracy of an automatic sensor is hundreds or thousands of times better than human perception.” For example, the process that mixes the HDPE to make the liners and jackets automatically weighs input volumes 15 times a second—impossible with the human eye. “For the most part, it’s overkill, but it gives you a lot of confidence,” Henry comments.

High sampling rates generate data, including statistics that are needed for maintenance scheduling and establishing trends for future adjustments. “For example, the dimensions of the extruded

liners, the fibreglass, all these things play a role in what our final dimensions are,” says Henry. Data also allows people to be reassigned to more value-added streams, too. “One person can be used to supervise more of the system,” says the process technology manager.

The industry rebound, coupled to rising oilsands production, prompted Baker Hughes Incorporated. to hike production of its specialty fluids. To complement the company’s Calgary facility, an entire new plant was planned at Leduc, Alta. The facility

“The accuracy of an automatic sensor is hundreds or thousands of times better than human perception.”

16

APRIL 2011 • OIL & GAS INQUIRER

— Greg Henry, Process Technology Manager, Flexpipe Systems

would produce, ship and store chemicals used in water clarification, water treating and demulsification, mainly for oilsands mining and thermal recovery projects. Automation would be essential to all three facets of the new operation: warehousing (shipping and receiving),18-tank storage farm and rail spur, and product blending.

After more than one year of operation, Leduc plant manager Paul Hanson says the automation features have repeatedly proven themselves. “In the warehousing side, automation takes us into the green links: waste minimization, power consumption,

Feature

lighting,” he says. “Everything is tied in to automation—including ventilation and makeup air.” In the processes, the Baker Hughes team deals with over 500 products within their mix from solvent, raw material, intermediates and finished products. “The automation helps us control our quality, our accuracy and our reliability,” Hanson comments. “Automation controls what goes into the vessels so we get proper concentrations that we can mix efficiently.”

Here too, automation enables each worker to be more productive. “We have a person that can man multiple vessels, where traditionally it would be one person, one vessel,” says the plant manager. “Through the automation controls, we can bring products into the vessels, mix them up and manage the entire blend room.” Importantly, automation extends to quality control, too.

“We have our reference points for product quality checks,” Hanson says. “When we sell a product, we have a reference point built right into the automation. From one pail up to a full railcar load, we’ll never overfill a container.”

The quality control (QC) checks are such that if a product is outside a set range, it shuts down the transfer and sends a message to the control room alarm screen, or to a person’s phone. “One of our key QC checks is density of product,” says Hanson. “We can give the automation system a reference point for density. When it comes through the meters, it reads the density. If that’s outside a certain very small percentage, it will shut down the valves and pumps and say, ‘Hey, you’ve got a problem.’”

Quantity measuring and inventory was previously done with weigh scales. Now, that function is automated in part with load cells.

“We have several different inventory controls and measuring devices,” explains Hanson, “and that’s all recorded by the automation system, too.” Baker Hughes’ clients appreciate the comprehensive and reliable data that’s generated by the automated systems, he adds. “If a customer is requesting backup on exactly what we shipped, we have everything down to a scale print ticket that is referenced to a weigh scale, to an inventory control level and a meter printout. That’s three different reference points to ensure product reliability to our customer.”

Most of the Leduc plant’s customers are manufacturers in the Fort McMurray region of Alberta—manufacturers of synthetic oil.

“Producing synthetic oil is a manufacturing process. That is what the oilsands guys call it,” says Grant Wilde, vice-president of oil sands at Spartan Controls. Although not everyone sees crude as a man-made creation like a car or a pharmaceutical, Wilde says the industry certainly has a manufacturing type of mentality. “Processes like these are repeatable. We’re grinding through hundreds of thousands of tonnes of rock that becomes bitumen at the end.”

Again, automation plays a big role. “We’ve got control systems sitting on top of CNRL’s [Canadian Natural Resources Limited’s] Horizon and Suncor’s [Energy Inc.] Firebag [facilities], running their entire oilsands operation,” says Wilde, whose firm is headquartered in Calgary. “The DeltaV system runs extraction, primary and secondary upgrading facilities—those plants where they bring in the oil, add hot water, mix it, separate it, add hydrogen, crack it—that’s the automation layer that we supply.”

The Spartan executive says oilsanders need the same manufacturing innovations at Fort McMurray as any factory where widgets

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17

Feature

Photo: Spartan Controls

take shape from raw steel. “Like the move to reduce labour,” he says.

“How do you do that? You automate. How do you automate? You have more and more complex control systems running the plant or the process. For a lot of businesses, labour is the highest input cost, so you remove one of your cost drivers or you reduce it.”

Labour reduction is financially attractive, Wilde says, but the strategy has its drawbacks. “Part of that trend is you lose some of the craftsmen, the trades, the hands-on expertise that ultimately you still need, but gets weeded out of the system. That’s a risk.”

Spartan's technology helps automate oilsands "manufacturing" plants.

Also, automation can be too costly for some companies, who may be forced to reduce labour cost by moving their operations overseas. “We’ve shut down so many of our core manufacturing facilities because we’ve offshored them,” observes Wilde. “You’re talking about a layer of jobs that may never come back.”

As a global leader in plant and field automation, Spartan Controls points to two prominent trends in the technology. “One is digital communications. That really comes first—it allows us to use computers through digital protocols. Second there’s now more opportunity to have these machines talking to each other

wirelessly,” Wilde explains, adding that the capability extends to portable tablets. “You can see into manufacturing processes on a tablet. You have workers that aren’t stuck to a central desk, they can physically take a view of their process out to the floor.”

Monitoring with automation devices is critical to oilsands operators. “You are controlling a lot of diagnostic, so you understand the health and life cycle status of equipment,” says Wilde.

“Having digital technology allows you to send a whole lot of that information for analysis.” There are important safety gains, he adds. In the event of a breakdown or fire, for example, sensors can enable risk diagnosis before repair personnel enter the affected area.

Automation requires training, which falls in large part to technology schools. “We’re driven by industry,” says Alex Zahavich, SAIT Polytechnic’s director of applied research and innovation services. SAIT recruits an advisory committee for each of its 70 industry-related programs. “With 10 industry reps on each committee, I have a captive audience of 700 industry people coming to my campus twice a year,” Zahavich notes.

SAIT staff and students hone their skills through undertaking real-life automation projects for companies. “If we don’t have an industry partner, we don’t have a project,” Zahavich says. “And unique to SAIT, all of our projects have students involved in them.

If we can’t use students to add value to an industry’s request, we won’t take on a project.”

Introducing automation has its challenges, of course, notably instilling confidence into the existing workforce that the equipment can be trusted. “A lot of people see automation as unreliable or a flaw going completely undetected because no one is there looking at it,” Flexpipe’s Henry comments. “People can be slow on the uptake; they say we must have access to the machine while it’s working. It takes a lot of thought to understand that the automation is not only doing its job, but also that it plays a role in its own troubleshooting, identifying errors in its own logic, etc.”

Wilde agrees that plant operators need time and careful instruction to grasp this sophisticated technology. “You’re taking the very complex and making it simpler [for workers to understand]. If there’s a component failing, automation tells us why we think it’s failing and here are the steps required to fix it,” the Spartan vice-president says. “We now have the capability to embed information that used to be in the old guys’ heads.

That experience lives on because it has been documented inside the system.”

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Feature

A liquid cure for gas pain With gas prices low and crude high, Alberta producers are hunting for oil in the Montney formation

By Elsie Ross

W

hile the silty/sandstone Montney formation has typically been seen as a natural gas play, there is growing interest in Montney oil in Alberta as an opportunity to balance gas-weighted portfolios. Daily Oil Bulletin records show that 110 oil wells with the Montney listed as the total depth zone have been drilled in Alberta since Jan. 1, 2010.

Of those, 24 wells are exploratory wells. On the development side, among the most active players are Venturion Natural Resources Ltd., which has 15 development wells in the Worsley-Hines area, Milestone Exploration Inc. with 10 wells at Tangent and Barrick Energy Inc. with eight wells at Sturgeon Lake.

In a report, Peters & Co. Limited analyst Jeff Martin described the Montney oil formation at Kaybob as a Triassic-aged, clastic wedge that dips from the northeast to the southwest. The Montney sits on the Mississippian Debolt and is overlain by the Jurassic Nordegg, according to the report.

“The Montney formation was deposited on a western-facing shoreline to shelf

environment and thins from west to east, and this regional subcropping is the main trapping mechanism for reservoir development.”

In the Kaybob area, the productive reservoirs are subcropping siltstones and sandstones.

“The sediments also have dolomitic cement, which subdues the porosity logging response over the zone, but partially explains why reservoirs are being continually uncovered,” says Martin in his report.

Montney oil potential was in the spotlight recently with the announcement by Trilogy Energy Corp. that it had paid a total of $26.78 million, or an average of $8,203 per hectare, to acquire 3,264 hectares of Crow n leases at 64-18W5 and 64-19W5 in the Kaybob area where it had drilled its first two successful Montney oil wells.

T he f irst hor izontal well at 16-1-64-18W5 produced an average of 500 barrels per day of crude oil and one million

Photo: ©iStockphoto.com/travismanley

cubic feet per day of natural gas during its first full month of production, while a second horizontal well with a surface location of 06-16-64-18W5 recovered all 3,650 barrels­ of completion fluid and produced 1,600 barrels of oil in its first 24 hours.

Trilogy, which has a 100 per cent working interest in 41 sections of land along the OIL & GAS INQUIRER • APRIL 2011

21

Feature trend, plans to evaluate accelerated development of the play in the second half of 2011. It anticipates drilling further delineation wells and expects that the pool will require four to eight horizontal wells per section to fully exploit the Montney reservoir.

While Kaybob is 18 miles east of the Waskahigan area in which Orleans Energy Ltd. is active, Barry Olson, Orlean’s pres­ ident and chief executive officer, is encouraged by Trilogy’s confidence in the play.

“The whole Montney fairway is fairly large and relatively underdrilled,” he says. “There are not a lot of operators in the Montney, compared to the Viking and the Cardium, so having another player in there come out with an announcement that is that positive is helpful to expand the play.”

About three years ago, Orleans needed and wanted to increase its oil weighting and to find a property that would allow it to be able to focus on improving its commodity balance, he says. “That’s why we settled on Waskahigan.” Orleans began acquiring land in the area, based upon

some of the geological investigation it was doing at the time. It took two years to accumulate its 100 per cent land position at a total cost of $17 million.

“We did it very quietly, only a few sections at a time, and ultimately accumulated 35 sections,” says Olson. Late last year, the company sold its deeper rights (including the Duvernay) for the 35 sections for $32 million. Due to the sale, “we essentially got our [remaining] lands for free,” the Orleans chief executive officer comments.

His company drilled its first Montney horizontal oil discovery well with a bottom­hole location at 04-36-63-23W5 in January 2010 and its second horizontal well at 05-25-63-23W5 came on production in June. So far, Orleans has drilled six Montney wells (five oil and one natural gas) at Waskahigan. While the oil and gas are in close proximity, Orleans considers them to be separate reservoirs.

Average initial production for the 4-36 discovery well was 473 barrels of light (42 degrees API) oil per day with 262 barrels per day after 90 days. The well

“We have been targeting 11-14 stages per horizontal leg and have been experimenting with 10 and increasing [proppant] to 35 tonnes per stage.”

Photo: Environmental Refuelling Systems Inc.

— Barry Olson, President and Chief Executive Officer, Orleans Energy Ltd.

Alberta’s Montney formation is still less explored than the Cardium and Viking plays further south.

22

APRIL 2011 • OIL & GAS INQUIRER

is currently producing about 60 barrels of oil per day. The 5-25 well, which was fractured with twice as much sand, came on at 670 barrels of oil per day with a 90-day rate of 380 barrels per day. “We really like our results so far,” says Olson.

Orleans also gets about 15 barrels per million cubic feet of condensate from the solution gas from the oil. The figure includes eight barrels per million cubic feet of free condensate, which further adds to the economic value of the play.

The true vertical depth to the formation is about 2,250 metres at Waskahigan and the true measured depth is between 3,500 and 3,800 metres, generally with about 1,300 metres to 1,450 metres of hori­zontal leg. The reservoir thickness varies from 25 to 55 metres of overall thickness with net pay eight to 12 metres thick. Operators are drilling horizontal wells with multistage fracture completions. Orleans is still at the experimental phase, says Olson.

“We have been targeting 11-14 stages per horizontal leg and have been experimenting with 10 and increasing [proppant] to 35 tonnes per stage.”

The company plans to drill seven Montney oil wells this year in further delineating the pool, ascertaining the size and scope of the pool with producing wells. “We’re not in the development phase yet,” says Olson. Initial costs per well are between $4.2 million and $4.5 million, but Orleans expects to drive down the cost to below $4 million per well in the development stage. Once the pool is in full development, Orleans expects to apply for downspacing to drill four to eight wells per section, up from the two horizontal wells per section currently permitted.

North of Waskahigan at Ante Creek, which Orleans considers an analog pool, operators have been submitting applications to the Energy Resources Conservation Board seeking approval for up to eight horizontal wells per section. Orleans also has six 100 per cent working interest sections of land immediately to the east of the main Ante Creek field, where it will be drilling a vertical test well in the second half of this year. “We are excited about that; there’s a lot of activity going on immediately offsetting us,” says Olson. “Interest is picking up and land prices are dramatically increasing out there.”

At the February 9 Alberta land sale, Scott Land & Lease Ltd. acquired a 256-hectare lease at 66-18W5 for $217.33

Feature per hectare, while at the January 12 sale Canadian Coastal Resources Ltd. paid $326.37 per hectare for a 1,024-hectare licence at 66-20W5. Among those pursuing Montney oil at Ante Creek is ARC Resources Ltd., which in the fourth quarter of 2010 drilled three oil wells in the area where it recently completed a Montney gas plant.

Daily Oil Bulletin records indicate that since Jan. 1, 2010, operators have licensed 17 wells targeting oil at Ante Creek with the Montney listed as the projected zone. Three exploratory wells have been rig released: two by Canadian Natural Resources Limited and one by Paramount Resources Ltd. Late last year, Harvest Operations Corp. licensed two new pool wildcats in the area.

Galleon Energy Inc. is also pursuing Montney oil in northwestern Alberta, says Dale Orton, vice-president, engineering and corporate development. The company has some exposure to Montney oil on its part of its East Montney play, between 75-19W5 and about 78-21W5, where it plans to drill up to 15 wells in the first phase. “It’s a big trend and there’s some oil on the downdip,” he says.

However, t he company also has accumu­l ated a “fairly significant” land position on another potential Montney oil play where it has drilled only one well, according to Orton. “We are doing some delineation drilling and we are encouraged by what we see.” Daily Oil Bulletin records show Galleon has a vertical new pool wildcat at 05-29-78-23W5 in the Culp area, which was rig released in January of this year. The well has the Precambrian system listed as the projected formation and a projected and total depth of 2,430 metres.

Driven by commodity prices, oper­ ators are increasingly looking for potential new oil plays, and new technologies may bring the lower-permeability Upper Triassic “into the realm of possibility,” Orton says. “I think I see folks looking at not just the Montney, but other members of the Upper Triassic as well, with a little more scrutiny.” While multistage fraccing is a great technology for gas, if a project doesn’t work at $3.50 per thousand cubic feet or $4 per thousand cubic feet gas, “then they have to look for something else,” the Galleon executive says. “That’s not necessarily our situation, but I think that’s what’s driving industry to look more closely at the oil right now.”

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436030 Certified Management Accountants Of Alberta full page 路 fp 1st HALF OF MAG

British Columbia

Encana and PetroChina eye Asian LNG market for Cutbank Ridge gas

By Elsie Ross

Encana thinks it can get an estimated ultimate recovery of up to 15 bcfe per well at Cutbank Ridge.

Encana Corporation is looking to liquefied natural gas (LNG) export markets in Asia in anticipation of a more rapid pace of development at its Cutbank Ridge assets as part of a new joint venture with a China National Petroleum Corporation subsidiary.

“We are, of course, very interested in the expansion of the creation of an LNG export market from North America and we do think it makes a tremendous amount of sense for that market to be linked to the Asian market from a proximity point of view,” Randy Eresman, Encana pres­ ident and chief executive officer, said on February 10. “We look forward to supporting that in any way we can.”

While there are currently multiple import points in North America for LNG, there are no real export points to make a market more fluid and functional, he said. “More specifically, we think there is an opportunity with Asian players who

demand more natural gas in their energy portfolios.”

In addition to its agreement with PetroChina International Investment Company Limited, Encana has a farmout agreement with Korea Gas Corporation (KOGAS) at West Cutbank and in the

supply natural gas to the project, but “we haven’t been in specific discussions for that at this point in time.”

Under the joint venture agreement with Encana, PetroChina will acquire a 50 per cent interest in the Cutbank Ridge assets in British Columbia and Alberta.

The agreement represents a “major step forward” in Encana’s plans to unlock the value in its natural gas resource plays and to double its production per share over the next five years, he said.

It is expected a joint operating agreement, which requires Canadian and Chinese government approvals, will be signed by mid-year, with an effective economic adjustment date of Jan. 1, 2011.

Under the agreement, Encana initially will market the gas for up to the first five years.

Upon closing, the pace of development will be at a rate higher than it otherwise would have been, but it also will be orderly growth as there will be a need for considerable additional infrastructure, Eresman said.

Encana first established a sizable pos­ ition in the Cutbank Ridge area in 2003, acquiring the majority of its land at an average cost of about $700 per acre. The producing zones in the Greater Cutbank area are the Montney, Cadomin and Doig formations

In 2010, independent reserve evaluators estimated proved reserves of about two trillion cubic feet equivalent at Cutbank Ridge.

Horn River Basin. Asked whether Encana would be looking at shipping its gas through the Kitimat LNG export ter­mi­n­al proposed by Apache Canada Ltd. and EOG Resources Canada, Inc., Eresman said there is obviously an opportunity to

with average daily production in January of approximately 510 million cubic feet equivalent (mmcfe). The area is one of the company’s lowest-cost resource plays with a 2010 supply cost of about $3.15 per million British thermal units, said Eresman.

FEB/10

FEB/11

FEB/10

FEB/11

WELLS SPUDDED

82

61

WELLS DRILLED

96

71

BRITISH COLUMBIA WELL ACTIVITY

FEB/10

FEB/11

WELL LICENCES

78

118

▲

▼

▼

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • APRIL 2011

25

British Columbia

Last year in Canada, due mainly to successful drilling, production grew by six per cent to 1.4 billion cubic feet equivalent (bcfe) from 1.32 bcfe in 2009 despite the divestiture of approximately 65 mmcfe per day, said Mike Graham, Encana executive vice-president and president, Canadian division. Including the impact of foreign exchange, operating costs were $1.06 per thousand cubic feet equivalent (mcfe). Operating costs excluding foreign exchange were 96 cents per mcfe last year, approximately 12 per cent below 2009 costs of $1.09 per mcfe due to higher production and improved efficiencies across all resource plays.

In 2010, independent reserve evaluators est imated proved reser ves of about two trillion cubic feet equivalent at Cutbank Ridge, which represent the “very tip of the iceberg” when it comes to what Encana ultimately expects to develop on its existing resource base, said Eresman.

Encana said it plans to focus more on liquids-rich natural gas plays and has established what Graham described as a “large land position” in the Duvernay shale

in Alberta, which has demonstrated “significant liquids potential.” The company has drilled one well, which is currently being tested, and it expects to continue appraisal drilling in 2011.

Graham declined to reveal Encana’s ac reage posit ion i n t he Duver nay, saying only that it is “ver y material to Encana.” He also declined to say how much Encana paid for the lands, although he ack nowledged that last year was “a pretty good year to buy land in Canada” and that the company had added to its land position relatively cheaply. In 2010, Encana bought a total of 500,000 net acres at a cost of about $650 per acre, said Graham. Many of those were liquids-rich plays like the Duvernay, the Montney in some areas and the Dunvegan, Wilrich and Falher formations.

Daily Oil Bulletin records show that on Dec.17, 2010, Encana rig released a vertical well in the Saxon area of Alberta at 11-862-24W5. The well was drilled to a projected and total depth of 3,844 metres with the projected zone listed as the Beaverhill Lake formation. That location was part

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of a 1,536-hectare licence that broker Canadian Coastal Resources Ltd. acquired at the May 19 Alberta Crown land sale for a total bonus of $5.05 million ($3,286.93 per hectare).

Chevron Corporation also recently acquired Duvernay acreage at a “very reasonable entry price,” a company official told a recent Credit Suisse energy summit in Vail, Colo. Gary Luquette, president of Chevron North America Exploration and Production Company, said the company this year plans to evaluate the acreage, which it believes represents an oppor t unit y to build unconventional gas in Canada.

At Horn River, Encana’s production for 2010 averaged 29 mmcfe per day net, lower than the original target of 50 mmcfe per day, primarily due to delays in bringing on production, said Graham. Current production is a bit over 75 mmcfe per day and “the wells are performing wonderfully,” he said. “We really do have a low decline; much lower than most shale plays in North America.” Encana still thinks it can get an estimated ultimate recovery of up to 15 bcfe per well.

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Encana and partner Apache Canada expect to scale back slightly Horn River activity this year with forecast average net production of about 110 mmcfe per day with an exit rate of more than 150 mmcfe per day net. In October, Encana completed frac operations on the 63-K pad where it pumped a total of 316 fracs in 14 wells, the largest frac program ever conducted in the Horn River shale. All 14 wells are on production and after 30

75 per cent to 80 per cent of the daily frac water requirements. This year, the company expects the plant to supply nearly 100 per cent of its frac water requirements, reducing its environmental footprint and reducing water costs.

In the fourth quarter, the company drilled and completed its first Wilrich formation well at Red Rock. The well has flowed at a restricted rate of 9.5 mmcfe for approximately three months, well above

At Bissette, Encana recently completed a Montney well with 24 fracs with initial flow rates of 16 mmcfe per day, its best well to date in the formation and its lowest-cost well at about $300,000 per interval, drilled, completed and tied-in. days had an average production rate of 12 mmcfe per day per well.

The cost of $680,000 per interval was higher than the earlier estimate of $600,000 per interval. Graham attributed the higher costs to pumping difficulties causing lower efficiencies earlier in the operation, as well as a conscious decision to test higher frac volumes per stage in 10 of the wells. Encana expects to reduce costs to the $500,000 per interval range, building on its efficiencies and further using fit-for-purpose technologies.

The Debolt water plant performed exceptionally well through the second half of last year, supplying water for use in the 63-K pad site fracing operations, he said. During the last half of the program, it was supplying approximately

type-curve expectations. Three additional vertical wells drilled into the formation are awaiting completion.

At Bissette, Encana recently completed a Montney well with 24 fracs with initial flow rates of 16 mmcfe per day, its best well to date in the formation and its lowestcost well at about $300,000 per interval, drilled, completed and tied-in.

The company continues to see impressive results from its Falher horizontal drilling program, said Graham. To date, eight Falher wells have been drilled at Kakwa, with seven on production. The wells were completed with an average of 13 frac stages with initial flow rates averaging nine mmcfe per day, considerably exceeding expectations.

Encana also has been moving ahead with refrigeration plants and turbo

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expanders at some of its midstream facilities in the Deep Basin. In the fourth quarter, it signed two deep-cut processing deals, securing 105 mmcfe of firm processing capacit y at Musreau and 90 mmcfe per day of firm capacity at Gordondale. These arrangements will enable the company to strip natural gas liquids out of its gas stream. Over the next few years, it expects to triple NGL production from the Canadian division to about 30,000 barrels per day from current production of about 10,000 barrels per day.

In a farmout agreement with KOGAS, seven wells have been drilled in the Montney formation at West Cutbank with six more planned for this year. The first KOGAS well was brought onstream in October at a restricted rate of about six mmcfe per day and is meeting expectations, said Graham. Improved frac designs in the Montney have lowered completion costs to about $380,000 per frac from $850,000 per frac while initial production rates have increased to 7.1 mmcfe per day from 3.7 mmcfe per day.

In the Horn River Basin, the partners are currently drilling their third main hole on a planned 10-well pad. Encana is pleased with the progression of the farmout agreement and believes there is potential for further expansion of those agreements, he said.

Offshore Nova Scotia, the Deep Panuke project is nearing completion with a final estimated cost of $950 million. The offshore platform is expected to arrive in the third quarter of this year with first gas beginning in the fourth quarter at approxi­ mately 250 million cubic feet per day, close to its firm capacity on Maritimes & Northeast Pipeline.

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Photo: Brian Zinchuk, Pipeline News

Trilogy’s push for Montney oil at Kaybob powers Alberta land sale

Trilogy’s second Kaybob well flowed 1.9 million cubic feet and 3,000 barrels per day of light crude.

Two bids totalling roughly $32.2 million along the Montney trend powered the Alberta land sale on February 9, which brought a total of $68.7 million into the provincial treasury. A total of 91,792 hectares exchanged hands at an average of $748.01 per hectare. The February sale last year generated $106 million on 171,465 hectares at an average of $618.31 per hectare.

After three sales in 2011, $285.5 million has rolled into government coffers for 583,101 hectares at an average of $489.59 per hectare. To the same point last year, the province had collected a total of $211 million on 305,053 hectares, an average of $691.81 per hectare.

Trilogy Energy Corp. had the bonushigh bid of $26.9 million for a single parcel, which also produced the perhectare high. The company paid an average of $8,203 for four tracts covering a lease of 3,264 hectares at 64-18W5 and

64-19W5. An adjacent 3,840-hectare lease was successfully picked up through Scott Land & Lease Ltd. for roughly $5.4 million at an average of $1,400 per hectare. The parcel included five tracts and several sections at 63-17W5 and 64-17W5. Trilogy confirmed to the Daily Oil Bulletin that it had acquired this second parcel.

Trilogy said it successfully applied horizontal drilling and multistage fracturing techniques to exploit a Montney oil pool in the Kaybob area of Alberta. The company issued a news release saying that based on the success of two horizontal Montney oil wells, it acquired the 28 sections along the Montney trend.

With a 100 per cent working interest in 41 sections of land along the trend, Trilogy believes it now holds substantially all of the petroleum and natural gas rights associated with this Montney oil pool and will evaluate accelerating the development of

this play in the second half of 2011. Trilogy anticipates drilling further delineation wells, and that the pool will require four to eight horizontal wells per section to fully exploit the Montney reservoir. Trilogy also stated that this land may prove to be prospective in the Duvernay shale.

In the fourth quarter of 2010, the compa ny completed d r i l l i ng operations on a horizontal Montney oil well at bottom location 16-1-64-18W5 and completed it using a 15-stage fracture stimulation. Following recovery of the completion load f luid, the 16-1 well flowed crude oil at 1,800 barrels per day.

During the first full month of production, this well produced at average rates of 500 barrels per day of crude oil and one million cubic feet per day of natural gas.

Daily Oil Bulletin records show the well was rig released on Oct. 23, 2010, to a total depth of 3,507 metres.

Trilogy followed up on the success of the 16-1 well by drilling a second horizontal Montney oil well to further delineate the oil pool. The second well was drilled as a vertical well at 6-16-64-18W5 to core the Montney formation. It was subsequently plugged back to a kickoff point and drilled horizontally through the Montney to a total depth of 3,120 metres, with a bottomhole location at 03-21-64-18W5.

The lateral portion of the well was 1,158 metres in length and was completed with a 15-stage fracture stimulation.

Trilogy was able to flowback the well immediately prior to a recent land sale, recovering all 3,650 barrels of completion fluid and 1,600 barrels of oil in the first 24 hours of production. The final rate during flowback was 1.9 million cubic feet per day of natural gas and 3,000 barrels per day of crude oil (40 degrees API) at a flowing pressure of 645 pounds per square inch.

— DAILY OIL BULLETIN

NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY

FEB/10

FEB/11

WELL LICENCES

182

218

▲

FEB/10

FEB/11

WELLS SPUDDED

268

280

▲

FEB/10

FEB/11

WELLS DRILLED

287

281

▼

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • APRIL 2011

29

Northwestern Alberta/Foothills

Strategic updates its plans for Steen River and Maxhamish Strategic Oil & Gas Ltd.’s production exceeded 900 barrels of oil equivalent (boe) per day (70 per cent oil) in midFebruary following the completion of repairs to a pipeline break in the Steen River area of northwestern Alberta. The company expects to add another 200 boe per day this month following a successful ongoing workover campaign in the area.

At the Maxhamish light oil play, Strategic said its operations are focused on achieving year-round access to its properties by March with a 2011 drilling campaign of four multi-frac horizontal wells.

Current plans include drilling and completing one well before breakup with three wells following breakup.

With its $14-million purchase late last year of Steen River Oil & Gas Ltd., Strategic acquired a light oilfield producing from the Keg River zone. The property includes 110 sections of undeveloped land, oil and natural gas facilities, and other infrastructure. This acquisition provides Strategic with two large light oil resource plays in western Canada.

• • • • • • • • • • •

Strategic acquired 650 boe per day of production at $22,000 per flowing barrel and 170 sections of land (110 undeveloped). The acquisition also brought facilities with a capacity of 2,000 barrels per day of oil and 35 million cubic feet per day of natural gas.

Prior to the acquisition, a major part of Steen River production was shut-in due to a pipeline break. Repair work began in early December and was completed in the third week of January. These wells have been producing at an average rate in excess of 650 boe per day, increasing Strategic’s overall production to over 900 boe per day.

Strategic’s 2011 capital program includes constructing year-round access, shooting an extensive 3-D seismic program to delineate and develop the existing Keg River oil pools and constructing allyear road access. It also plans to drill up to five additional Keg River oil wells and exploit Keg River, Slave Point and other oil- and gas-bearing zones at Steen River.

Keg River vertical wells typically produce

with initial rates of 200-400 barrels of oil per day per well and provide solid economics with drilling costs of $1.5 million per well.

“We are pleased to be able to complete the low-cost acquisition of Steen and subsequently achieve the start-up of the pipeline within a short time,” said Arn Schoch, Strategic president and chief executive officer.

At Maxhamish, Strategic and its partner have begun the 2011 development program. The program includes building an all-weather road to allow development of the Maxhamish property to occur yearround and constructing an oil battery to remove current production-handling constraints. In addition, up to four horizontal wells will be drilled, then completed with multistage fracs and tied in.

The current road construction project to turn the Maxhamish area into an allyear-round operation is crucial to a future accelerated development program in the area, Schoch added.

— DAILY OIL BULLETIN

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Northeastern Alberta

Long Lake project continues to struggle despite Q4 production gains

Photo: Joey Podlubny

By Paul Wells

Nexen hopes to see improved performance at Long Lake after it steams through water-saturated zones.

Nexen Energy Inc. says fourth-quarter 2010 bitumen volumes at its struggling Long Lake steam assisted gravity drainage (SAGD) project increased 10 per cent to 28,100 barrels per day gross, although January output dropped to 27,000 barrels per day because of steam interruptions and downhole pump failures.

President and chief executive officer Martin Romanow told a conference call on February 10 that the latest setback is a disappointment. “While 2010 production did not meet expectations, we had believed that we had turned the corner. However, despite the record steam, we have not seen bitumen production increase in December and January,” he said.

Nexen owns 65 per cent of Long Lake, with OPTI Canada Inc. holding the remaining 35 per cent stake in the project. In December, the project produced 29,000 barrels per day, matching the project’s previous

monthly high achieved in October. Long Lake also generated positive operating cash flow for the month, marking just the second time that milestone has been achieved.

However, production dropped in January to about 27,000 barrels per day despite having injected the highest steam volumes yet for the project in December and January—172,000 and 156,000 barrels per day, respectively.

Romanow said that while fluid returns have risen, the bitumen production has “not increased proportional” to the steam injection. While some lag between steam increasing and bitumen production increasing is expected, Nexen also believes some of the steam is heating high-water saturation zones, sometimes known as “lean” zones.

Romanow said the issue may mean Long Lake output will not match the promised range of between 38,000 and 45,000 barrels per day of bitumen this year, which is still less than the 72,000 barrels per day it

is designed to produce. He also noted three pilot wells drilled in an area of the Long Lake lease with a higher concentration of these zones also had similar issues and the pilot was temporarily suspended in 2006.

However, with the start-up of the commercial SAGD operation in 2008, Nexen reheated the pilot wells and after steaming through the zone of higher water saturation, two of those wells are now producing in line with the company’s design expectations of 700 barrels per day per well pair of oil at a steam to oil ration (SOR) of 3:1, while the third well is restricted due to mechanical wellbore issues.

Romanow said the company also saw this behaviour on Pad 7N, located on some of its highest-quality reservoir. Once the company steamed through the lean zone, performance improved and now it is, as expected, “our best performing pad with five wells averaging 1,200 barrels per day per well pair at an SOR of 2.3:1. “Once this zone is heated, SORs and bitumen rates improve and this improvement can be dramatic,” Romanow said.

The company said absolute operating costs at Long Lake increased about 10 per cent year-over-year as it added resources to improve operating reliability of the SAGD and upgrader. “During 2010, they have remained relatively constant. We expect them to remain relatively flat as we ramp up to full capacity, with declines in ramp-up related costs offsetting increases in variable costs,” Nexen said. “We expect unit operating costs to be $25-$30 per barrel at full capacity.”

OPTI is struggling with mounting debt and a plummeting stock price. Romanow wouldn’t comment in detail when asked if Nexen would consider buying out its partner’s remaining stake in Long Lake, only saying that the two sides are currently working cooperatively to ensure that future investments required to move the project forward will occur.

— DAILY OIL BULLETIN

NORTHEASTERN ALBERTA WELL ACTIVITY

FEB/10

FEB/11

WELL LICENCES

77

131

▲

FEB/10

FEB/11

WELLS SPUDDED

171

152

▼

FEB/10

FEB/11

WELLS DRILLED

160

166

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • APRIL 2011

33

Northeastern Alberta

MEG exceeds production and SOR ratio expectations The average steam to oil ratio (SOR) at MEG Energy Corp.’s Christina Lake in situ operation averaged 2.3:1 for the fourth quarter of 2010 compared to 4.9:1 for the same quarter a year ago, while bitumen production soared and operating costs fell due to the project’s Phase 2 ramp-up.

During the fourth quarter of 2010 production averaged 27,744 barrels of bitumen per day, approximately 10 per cent above the nominal design capacity of the facilities of 25,000 barrels per day. For the year ended Dec. 31, 2010, the average SOR was 2.5:1 compared to an average SOR of 3.9:1 in 2009. The design SOR is 2.8:1.

The SOR has decreased throughout 2010 as the Phase 2 well pairs have quickly progressed through the circulation phase and entered into normal operations, said the company. The early success of the production ramp-up and improved SOR have enabled it to performance test the integrated Phase 1 and 2 facilities and exceed the plant design production capacity.

MEG now has 34 of the 35 well pairs available steaming right now, Bill

McCaffrey, chairman, president and chief executive officer, told a fourth quarter conference call in February. Currently, 33 are in production and the 34th is in circulation and will be converted to a steam assisted gravity drainage pair shortly.

Phase 2B is progressing on time and on budget, said McCaffrey. Engineering is 40 per cent complete, commitments for 90 per cent of all major equipment are in place, construction is about five per cent complete and MEG has started drilling of horizontal producing wells and five are complete.

On Nov. 30, 2010, the board of directors approved the 35,000-barrel-per-day Phase 2B expansion with a cost estimate of $1.4 billion. Start-up is targeted for 2013.

To date, the company has not seen substantial cost pressures with the exception of a few areas. “One area is copper, but that’s not a very large component of our overall costs,” McCaffrey said.

Operating costs for the three months ended Dec. 31, 2010, were $14.22 per barrel compared to $52.04 per barrel for the same period in 2009. For full-year 2010,

operating costs were $20.86 per barrel compared to $55.80 per barrel in 2009.

MEG also reported that GLJ Petroleum Consultants Ltd. has completed an evaluation of the company’s reserves and recoverable resources effective as of Dec. 31, 2010, and proved bitumen reserves increased to 606 million barrels, an increase of 10 per cent compared with a year ago.

Capital investment during the fourth quarter of 2010 increased by $83.3 million compared to the fourth quarter of 2009 to $147.4 million. This increase is due mainly to increased investment on Christina Lake Phase 2B horizontal drilling and facilities engineering.

Capital investment for the year ended Dec. 31, 2010, increased to $494.63 million from $351.34 million in 2009. The increase is due to increased investment on Christina Lake Phase 2B detailed engineering and commencing the purchase of major equipment, installation of electric submersible pumps, and maintenance and reliability of the Phase 2 facility.

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Central Alberta

Alberta government clinches BRIK deal for North West Upgrading/CNRL

Photo: Government of Alberta

By Elsie Ross

Premier Ed Stelmach praised the two projects as a blend of economic and environmental progress.

The $5-billion first phase of a new 50,000-barrel-per-day bitumen refinery in Alberta’s Industrial Heartland near Redwater is targeted for completion in mid-2014. A partnership between North West Upgrading Inc. and Canadian Natural Resources Limited (CNRL) will construct an upgrader/refinery with feedstock from the province’s Bitumen Royalty in-Kind (BRIK) initiative.

Under the agreement, the Alberta government will provide 37,500 barrels per day of bitumen and will receive three-quarters of any profit after costof-service fees. The upgrader/refinery will be constructed in modules, using expertise and capacity available in the Edmonton area. Depending upon the economics, there could be two more 50,000-barrel-per-day phases.

The deal features two levels of incentive fees. The inclusion of 15 per cent of

the net revenues in the fees is designed to align the interests of the producers with those of the operators to maximize profits.

There also is a sharing of risks between the Crown and Canadian Natural and the equity investors.

Any cost overrun over 30 per cent will be paid by equity owners and will not be included in the tolls. Operating costs also are indexed and any costs over that figure will be excluded from the tolls.

The upgrader/refinery was the first of two projects announced by the Alberta government on February 16. For the second, Enhance Energy Inc. and the province agreed to terms and conditions specific to the first major carbon capture and storage project in the province.

Enhance will receive $495 million from the province to help build a 240-kilometre CO2 pipeline to the Tees oilfield in central Alberta, where the CO2 will be used for enhanced oil recovery.

“This new refinery and CO 2 pipeline will significantly advance Alberta’s capacity for refining bitumen into valueadded products and increase recoveries from Alberta’s conventional oil reserves,” said Premier Ed Stelmach. “ T hese projects underline A lber ta’s

“ This new refinery and CO2 pipeline will significantly advance Alberta’s capacity for refining bitumen into value-added products and increase recoveries from Alberta’s conventional oil reserves.” ­— Premier Ed Stelmach

In addition, if the profit is more than $22 per barrel, there is a sliding scale in which there is a higher percentage of shared profits.

The North West deal is highly leveraged with 80 per cent debt and 20 per cent capital, designed to reduce overall costs and tolls to maximize profitability. The agreement has been structured so that the risks to the lenders are minimized, ensuring the lowest possible costs.

commitment to responsible, cleaner energy production.”

“By processing the province’s barrels of bitumen, we can maximize the resource’s value at a fair price, giving Albertans the biggest bang for the buck. The terms of the processing fee ensure that the province of Alberta always profits as the facility does,” said Ian MacGregor, North West’s chairman. “The BRIK initiative is doing

FEB/10

FEB/11

FEB/10

FEB/11

WELLS SPUDDED

249

246

WELLS DRILLED

239

239

CENTRAL ALBERTA WELL ACTIVITY

FEB/10

FEB/11

WELL LICENCES

265

301

▲

▼

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • APRIL 2011

37

Central Alberta

“ The potential of the enhanced conventional oil recovery ensures ongoing jobs, investment and activity in surrounding communities [in central Alberta].” ­— Alberta Energy Minister Ron Liepert

exactly what it was created to: it’s keeping jobs, taxes and revenues in Alberta and creating opportunities for other petrochemical industries.”

After CNRL equalizes with North West, about $200 million of the total $1 billion in equity will still need to be raised, said MacGregor, who has been working on the project for seven years. “Based on where we have been, that’s going to be the easiest job I have ever had,” he said.

CNRL said that it believes it is important to ensure conversion capacity is available in the mid and long term to support heavy oil demand and to facilitate unlocking the value of the company’s vast heavy oil assets in Alberta.

The bitumen refinery initially will process 37,500 barrels a day of Crown bitumen

38

APRIL 2011 • OIL & GAS INQUIRER

in addition to 12,500 barrels per day of bitumen from CNRL. The refinery will process the Crown’s bitumen for a processing fee, which will result in higher revenues created by the higher-priced refined bitumen products.

The dominant product will be lowsulphur diesel, with production of 36,000 barrels per day of low-sulphur diesel in the first phase. Most of that will be marketed locally to meet a strong local demand. The refinery also will produce 18,000 barrels per day of naphtha and 14,000 barrels per day of diluent.

The refinery will capture more than 3,000 tonnes of CO2 daily. Enhance Energy will then transport the CO2 via the 240kilometre pipeline to conventional oil recovery projects throughout central Alberta.

“Conservatively, we believe the longterm economics of this project are positive,” said Energy Minister Ron Liepert.

“They represent a major step forward in producing value-added products while at the same time reducing greenhouse gas emissions. The potential of the enhanced conventional oil recovery ensures ongoing jobs, investment and activity in surrounding communities.”

Liepert suggested that the agreement with North West and CNRL provides a template for other deals. The government announced its intention in 2008 to collect oilsands bitumen royalty volumes in-kind to encourage upgrading, refining and petrochemical development in Alberta.

— DAILY OIL BULLETIN

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Southern Alberta

Service firms run short of skilled drilling and completion workers

By James Mahony

FEB/10

FEB/11

FEB/10

FEB/11

WELLS SPUDDED

397

196

WELLS DRILLED

402

194

Photo: iStockphoto.com/HazlanAbdulHakim

Ruud, AKITA president and chief executive officer. In particular, he believes labour tightness will affect shallower drilling and oilsands coring projects.

A robust drilling and f racturing market south of the border in the last two to three years is partly behind the labour situation here, Ruud says, noting that, where demand grows, as it has in the United States, men and equipment tend to follow. Closer to home, a lack of experienced workers across the industry is exerting an effect beyond the drilling sector, he believes. “I don’t think it’s just rigs, but the entire spectrum of the service side and drilling. We’re seeing long wait times on all the technical services and a shortage of people.”

Like his colleagues, Ruud knows of industry competitors with rigs ready to go, but no one to man them. Indeed, six of AKITA’s own deep-hole rigs are idle.

Daily Oil Bulletin statistics suggest it’s the province’s largest contractors, not smallor mid-size operators, that are seeing the highest percentage of idle rigs. None of the big contractors contacted by the Daily Oil Bulletin would discuss the issue, however.

Among small contractors, there’s a consensus that more workers would lift the rig count, but differing opinion about just how much difference they would make.

Management at Chinook Drilling, a unit of Total Energy Services Inc., felt the sector is nearing its limits, due in part to factors beyond drilling contractors’ control.

While agreeing that more workers would help the situation, Rod Rundell, Chinook’s general manager, stops short of saying that it would take the active rig count substantially higher. “We’re starting to get maxed out on the service side. Even with another 10 per cent of rigs running, you’d be waiting on cementers, loggers and directional hands,” he says. “To get the last 20 per cent of the rigs running— that’s a big chore.”

As for what’s driving the rig-worker shortage, some suggest it’s the lingering fallout of the last industry downturn, when rig crews were laid off, let go or offered only a few months of work. In response, many found new careers in construction, retail or other sectors, some contractors said. Yet, even here, there’s no consensus.

“Everybody says the crews left the industry and didn’t come back,” says Rundell. “Well, I don’t think so. There are a few that never came back, but a lot went into the [broader] industry. They may not be working on the rig itself, but they’ve moved into other parts of the industry, like MWD [measurement while drilling], directional drillers and the like.” Others note that western Canada’s economy has not fallen as hard as some, meaning job opportunities in Alberta, for example,

Some say former rig hands found stabler jobs in the patch and did not return as drilling heated up.

Although rig utilization has recently averaged 80 per cent, a straw poll conducted

by JuneWarren-Nickle’s Energy Group in February showed some operators believe the rate could rise even higher with more workers. However, other service firms think the shortage of completion specialists might limit drilling activity even if more rig crews were available.

There’s no doubt that rig hands are in tight supply. “Absolutely,” says Bruce Jones, president and chief executive officer of Stoneham Drilling Trust. “We know of a number of cases where, even though a rig is available and on-site, they still haven’t crewed up from Christmas. They’re still waiting for crews.”

Although more nuanced, sentiment at AKITA Drilling Ltd. ran along similar lines. “I don’t know that the [active rig count] would be significantly higher, but it would be somewhat higher,” says Karl SOUTHERN ALBERTA WELL ACTIVITY

FEB/10

FEB/11

WELL LICENCES

178

117

▼

▼

▼

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • APRIL 2011

41

Southern Alberta

are not as scarce as they are elsewhere, providing a ready exit for some workers who used to rely on the rigs for their bread and butter.

According to Stoneham’s Jones, the sheer size and scope of some of Alberta’s non-industry, infrastructure projects mean former rig workers won’t have to go far to switch careers, and when they do, they’ll bring with them the valuable training they got on the drilling floor. “The North American economy is beginning to rumble, and it’s quite easy for [rig crews] to cross the street and get a job [in construction],” he suggests. “Because of the scale of some projects and the consistency of the work they offer, we’ve lost a lot of other people to other industries.”

Jones does not blame the men. “Given the environment we subject our people to, the cyclical nature [of the work] and the level of compensation, there are other options for them to earn a good living.

Perhaps we need to be a bit more competitive when it comes to compensation,” he says.

Another explanation for the rig count is based on demographics. AKITA’s Ruud

spoke of a “missing generation” of rig workers that never materialized simply because it never set foot on the rigs. “If you go back a few years, there were difficult times in the mid-1980s and early 1990s. There was

per rig, with a relief crew resting while two others alternate between day and night shifts. Yet, one source said, a few rigs are running with just two rig crews. In that scenario, with no relief crew, two crews

“ There are a lot of new hires in the industry. Any time you go from 300 to 650 rigs, that’s a lot of [people].”

— Karl Ruud, President and Chief Executive Officer, AKITA Drilling Ltd.

probably a generation that didn’t come into the [drilling] industry. When you talk about supervisory-quality people in their 40s or 50s, there’s a missing generation. That always [means playing] catch-up whenever you go into up-cycles like we’re in right now.”

The result, Ruud concedes, is that drilling rigs are today running with more inexperienced people, on average, than last year or the year before. “There are a lot of new hires in the industry. Any time you go from 300 to 650 rigs, that’s a lot of [people],” he says.

The strain is showing in other ways.

Most drilling contractors run three crews

must work continuously until maximumhour limits under Alberta labour laws are reached or the rig is released, whichever comes first. The practice appears to be in the minority.

Of some half a dozen contractors surveyed, just one says it had no trouble crewing up its 18-rig fleet. According to Randy Hawkings, president and chief executive officer of CanElson Drilling Inc., job applications kept arriving well after the company had recruited everyone it needed.

Two factors have helped the company attract staff, he says. Workers “want efficient rigs, which generally

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42

APRIL 2011 • OIL & GAS INQUIRER

OILWEEK.COM

Southern Alberta

means newer generation. T he average age of our f leet is under t hree years....Secondly, workers want continuous work. You can’t attract a new worker if you’ve only got winter work,” the CanElson president adds.

Wit h 30 yea rs i n t he oi lpatc h, Hawkings recalls the time when many rig workers were fresh off Alberta and Saskatchewan farms. Thanks to their Prairie roots, they were used to adversity and “could fix almost anything mechanical,” making them ideal for the rigs.

Yet, the well may be running dry, he admits. “There are still farm boys coming in, but there are less of them and more mainstream [workers],” he says.

Others told a similar story. At Jomax Drilling (1988) Ltd., company president Tom Levang says young men from A lber ta’s Hut ter ite colonies proved themselves hard workers, with strong mechanical skills, in years past. But he does not always see the same skill set in today’s rig workers, something he blames on modern schooling—“too many computers and games.”

— DAILY OIL BULLETIN

Ziff sees possible gas price recovery after 2011, but urges reforms North American natural gas prices could improve as early as next year, said the head of a leading Calgary-based consultancy. “In terms of recovery, it could be relatively quick to a moderate level.

But it will be slow [beyond that point] because shale gas is not going away,” Paul Ziff, chief executive officer of Ziff Energy Group, said on February 17 following the firm’s annual outlook seminar.

Oilsands production and processing will play a big role in increasing gas consumption, Ziff said, followed by greater demand for power generation in the United States. American electricity demand is driven by the health of the country’s economy, particularly its manufacturing sector. “So, from the U.S. we’re starting to get, in the last couple of months, some positive glimmers. Unemployment is coming down [and] the U.S. dollar is very affordably priced, [which] is helping all of their exporters.”

Ziff doesn’t buy the argument that the North American price of gas—a cyclical commodity—will stay low forever because of rising shale gas output. In his presentation, the veteran gas consultant poked fun at the apocalyptic Biblical-style prediction of one large U.S. consulting firm that in 2010 said gas prices would stay around US$4 per million British thermal units for 40 years.

Ziff Energ y believes several factors will combine to improve gas markets. “However, it does require a North American economic recovery and as [U.S. Federal Reserve chairman Ben] Bernanke is saying, we’re not out of the woods yet,” Ziff said. “So we will get there, but I think we still have another one or two years of some pretty tough times.”

Beyond the short term, however, Ziff Energy believes the pessimistic long-time price forecasts of most pundits are exaggerated. “We’re in a situation that’s similar,

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Southern Alberta

for instance, to the lumber industry when the U.S. went into recession. And some people say, ‘Oh, there’s no hope, ever,’” Ziff said. “We find that markets tend to be too dismal or too optimistic, and the truth is somewhere in between.”

He listed several factors that may ease the current North American gas glut. The cost of some key supplies and services for the shale gas industry, such as fracture stimulations, are rising, and those costs have to be passed on. Also, shale gas activity has been driven by the need to drill to hold land, particularly in plays like the Haynesville. Many of these lease-earning commitments have now been met.

Another factor behind the brisk pace of shale gas activity is foreign capital.

Firms from countries such as China made big investments through deals with companies such as Oklahoma City–based Chesapeake Energy Corporation. “We think those are past the big bulge. There may be some to come, but most of it’s already looked after,” Ziff said.

As well, the energy analyst believes Wall Street has focused too heavily on production growth, even at prices that

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Last spring, Ziff Energy recommended producers shut-in uneconomic gas. “It costs $6; producers are selling it for $3.50.

This is not a good business model. So I think a lot of those factors are playing out

a vanishing breed. About a year ago, Chesapeake and EOG Resources, Inc. each announced plans to become about one-third to one-half oil and liquids weighted. “And it’s a bit ironic that Encana [Corporation] now is musing out loud about oil. And of course they could find it with Cenovus [Energy Inc.],” he added dryly.

More than a year ago, Encana got rid of all its oil production by spinning it off

“ [Gas] costs $6; producers are selling it for $3.50. This is not a good business model. So I think a lot of those factors are playing out through 2011.”

­— Paul Ziff, Founder, Ziff Energy Group

through 2011,” Ziff said. “I’d say last year and this year are probably the worst years.

And [then] we’ll see a recovery, [but] not necessarily a fast recovery.”

Another factor should help bring investment to Alberta. No other jurisdiction in North America has lower royalties than Alberta following last year’s changes to the province’s royalty regime, Ziff said.

He noted one of t he ma nifestations of prolonged low gas prices is that pure-play gas producers have become

with Cenovus, which it created for that purpose. “I guess the moral of the story is that balance is good,” Ziff told his audience of industry executives.

The veteran consultant has never supported the idea of a pure-play gas producer because there’s too much risk. “You have to have a pure balance sheet, which not all producers do. You have to be actively hedging.

And you also have to be lucky,” he said. “And none of those can be assured all the time.”

— DAILY OIL BULLETIN

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Rising producer head counts signal a return to growth Bill Andrew was building up Penn West Petroleum Ltd., now known as Penn West Exploration, he hired many young engineers and geologists fresh out of school. “Fast-forward 10-15 years, and these guys have 10-15 years’ experience,” said Jason Fleury, Penn West’s senior manager of investor relations.

“Bill Andrew really felt young people had good ideas, weren’t scared to try new things,” said Fleury. “And that’s really what was driving his strategy when he hired a lot of these people fresh out of school and gave them room to run. And now that strategy...is paying dividends.”

The oilsands will be a powerful employment generator in the immediate future.

Devon’s thermal oil operations will probably create an average of about 75 net new permanent jobs a year for each of the next three to five years, Beaton estimates. A new SAGD project with a capacity of 35,000 barrels a day requires about 100 permanent employees—about 75 on location and 25 in head office, she said. Subsequent expansions of the same size each require an extra 60-70 net employees.

Devon’s Jackfish 1, Jackfish 2 and Jackfish 3 SAGD projects are each 35,000 barrels a day. Jackfish 1 is successfully operating, Jackfish 2 is to flow first oil this year and construction of Jackfish 3 may be approved this year. No decision has been Photo: Brian Zinchuk, Pipeline News

As oil prices touch US$100 a barrel, activity levels are rising accordingly, and so are producer head counts. Conventional producers are competing for skilled personnel with capital-flush oilsands operators and their bulging project portfolios.

Last year, Encana Corporation hired close to 400 people in Canada, estimates David Urquhart, head of staffing and development.

That includes replacements for an estimated 80-120 people who went to Cenovus Energy Inc.—the spinoff of Encana’s oil assets—and 140 who retired or resigned. The remaining hires were growth related.

At mid-January, Encana had 101 openings. About 40 of those were engineeringrelated jobs and about 20 were for field and plant operators. Cenovus, meanwhile, also hired 400 people last year.

ARC Resources Ltd., a diversified senior producer, brought 53 new employees into its Calgary office last year—roughly half of whom probably filled new positions, said David Carey, ARC’s senior vice-president of capital markets. He estimated the other half of the new hires replaced retirements and resignations. At the start of this year, Carey estimated ARC was recruiting for roughly two dozen positions, and the company expects to continue to grow over the next few years.

“We’ve had a lot of success, [but] it is difficult, no question,” Carey said of ARC’s recruiting efforts. “Everybody, of course, is looking for the best people with experience.” There are plenty of personnel available with zero to five years’ experience, he said, but people with more than 10 years’ experience are scarce enough that ARC tends to use search firms to find them.

“We found, pretty much, the really good people with more than 10 years’ experience are all gainfully employed,” Carey said. “If you want to bring them in, you’re going to have to find somebody who’s at least a little bit unhappy where they currently are and convince him or her that life would be better on your side of the street.” Calgary’s merger-and-acquisition churn also creates headhunting oppor­ tunities, he added. “You often find people who perhaps don’t fit in the new corporate culture and are looking for a change.”

The nice thing about hiring inexperienced people is that ever y year, they gain another year’s experience. As

Skilled oil and gas hands already have jobs, forcing companies to train newcomers.

Cenovus, for example, estimates it will need about 1,200 new employees over the next five years, said spokeswoman Jessica Wilkinson. That’s an increase of about onethird from today’s payroll. The thermal bitumen producer is in the midst of a huge ramp-up of its steam assisted gravity drainage (SAGD) operations.

Devon Canada Corporation hired 289 people last year. Nearly half were in thermal oil and the rest were elsewhere in the field or head office. That includes roughly 120 net new positions, estimated Susanne Beaton, Devon Canada’s talent manager. Entering this year, Devon Canada had 52 job openings, including six student positions.

made on the size of each phase of Devon’s Pike (formerly Kirby) joint venture with BP p.l.c. But, given that the 35,000-barrela-day model worked well for Jackfish 1 and 2, the company is likely to continue to grow at that scale.

The company that may be looking for the most employees had little to offer in specific details. After swallowing senior producer Petro-Canada in August 2009, Suncor Energy Inc. employs more than 12,000 people. In the third quarter of last year, Suncor’s output of 635,500 barrels of oil equivalent a day made it Canada’s largest producer.

The oilsands giant hopes to increase output dramatically to one million OIL & GAS INQUIRER • APRIL 2011

45

Southern Alberta

barrels of oil equivalent a day by 2020, but doesn’t know yet what its labour requirements will be. “We are in the process of finalizing project plans and updating our long-range work force needs. So we are unable to provide an outlook at this time,” Dany Laferriere, a Suncor spokesman, said in an email.

According to its disclosed plans, Suncor laid off about 2,000 employees last year and in 2009. But now it’s in hiring mode.

“While we did not see a significant gain in full-time employees last year, we did aggressively recruit for a number of specialized professionals, such as supply chain management and project controls. So while the past year was not a growth year with significant change to staff levels, in 2011 we have begun to recruit in earnest for a number of professional positions,” wrote Laferriere.

Several newly minted companies hired all their staff in recent years.

Leading the pack in the non-oilsands categor y is new mid-size producer Tourmaline Oil Corp. (23,000 barrels of oil equivalent a day in late December).

Incorporated in July 2008, Tourmaline currently has about 80 staff.

PetroBakken Energy Ltd. hired more than 150 people last year and another 18 this year and still has about 30 vacancies to fill, said Mary Bulmer, vice-president of corporate services. “We’re not having a lot of trouble [finding staff]—PetroBakken is easy to sell,” Bulmer said. PetroBakken’s predecessor companies were producing light, tight oil a few years before it became an industry-wide phenomenon.

But most of the rapidly growing producers are developing oilsands leases.

Just three years ago, Athabasca Oil Sands Corp. (AOSC) had only 23 fulltime employees at its Calgar y head office. Last month, the company had 104 employees and plans to hire another

100-plus technical and operating staff over the next 15 months.

AOSC president Sveinung Svarte said the thermal oil company has had a “very easy” time finding employees and he doesn’t expect that to change. He cites several factors: the company is well financed, so people feel more secure taking a job there; the corporate culture is open and informal; and the pay, which includes stock compensation for all employees, is “very hard to beat.”

Svarte said the September 2008 financial crash created recruiting opportunities just as AOSC was recruiting.

“Everybody’s stock options were under water. That helps a lot...there isn’t much attaching these people to their previous employers,” he said. Also, the AOSC president believes SAGD projects will be partly sheltered from the shortage of operating personnel because production is much less labour intensive than oilsands mining. In SAGD, the bitumen flow is automated right from the reservoir. In mining, every truck and shovel requires a human operator.

Another thermal oil operator, Laricina Energy Ltd., has grown to about 80 fulltime employees from zero in November 2005—including eight new graduates, said its president Glen Schmidt. The company, which has 28 contract and full-time employees in the field, plans to double that number over the next 18 months.

Laricina’s full-time office staff will grow from nearly 70 now to more than 100 in the next two years.

At a time when technical personnel are in short supply, how does a new company manage to recruit 100 per cent of its staff?

Schmidt said such jobs appeal to entrepreneurial types who like to experiment with ideas that often aren’t easily implemented in a larger company. Start-ups like Laricina, he said, give five- to 15-year

Read what our editor has to say.

professionals who are ready to “graduate” from senior producers a chance to advance their careers. “And then, concurrent with that, we’ve had a focus on hiring lessexperienced people to train up.”

There’ll be plenty of competition for professionals such as engineers over the next few years with a slew of bitumen projects under construction. A Daily Oil Bulletin tally found oilsands spending­ (including mining projects) could reach $16 billion this year—and that just includes disclosed budgets.

Hiring of permanent staff can start well before projects come on stream. For example, Husky Energy Inc.’s Sunrise SAGD project, which is expected to flow first oil in four years, will create about 75 engineering and other jobs this year, a spokesman said. Meanwhile, Husky said it hired more than 250 people in its upstream operations last year.

Harvest Operations Corp. is in growth mode with a bitumen project under development and a $1.4-billion capital budget for 2011, including a $525-million acquisition of Hunt Oil Company of Canada assets expected to close early this year. “We probably have 10-15 per cent more people today than we had a year ago,” said Harvest pres-ident John Zahary.

He underscored the importance of hiring and training new graduates to ensure an adequate talent is maintained within the industry. Most producers want recruits with at least 10 years’ experience, but “these highly qualified guys don’t materialize out of thin air when you need them,” said Zahary.

“It’s industry’s responsibility to bring people into the industry to help them develop their careers, to try as much as possible to provide that stability of employment to keep people going during the down periods so they are there during the up periods.”

— DAILY OIL BULLETIN

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APRIL 2011 • OIL & GAS INQUIRER

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The oil and gas industry provided more than 29,000 direct and indirect jobs in Saskatchewan during 2010.

Saskatchewan set a new record for drilling horizontal oil wells in 2010 and producers expect the strong price of crude to keep that momentum going in 2011. Drilling in the province got off to a fast start this year with January showing 151 horizontal wells drilled compared to 103 a year ago, while total well permits issued in the month rose 56 per cent to 424 from 271 licences in January 2010.

The average rig count of 69 in 2010 was over 63 per cent higher than in 2009, according to JuneWarren-Nickle’s E nerg y Group stat ist ics. T he dr i l ling boom is continuing this year as Saskatchewan operators employed 89 rigs in January, 26 per cent more than a year ago.

Last year, the province’s oil and gas industry had roughly $10.5 billion in sales revenues and invested $3.3 billion in exploration and development activity.

The patch provided direct and indirect employment to more than 29,000 people.

Year-end statistics from the Saskatchewan Ministry of Energy and Resources show that 1,531 horizontal oil wells were drilled in 2010, an 88 per cent hike from 2009 and 13 per cent higher than the previous record in 2008.

the 2,360 yearly average for oil wells drilled over the last five years.

Generally, economic growth in the province is expected to be strong, with eight major economic forecasters predicting that Saskatchewan will have the fastest­­-growing economy in Canada in 2011. It’s anticipated to increase by an average of 3.7 per cent, well ahead of the 2.4 per cent forecast for the national average.

Turning to on-the-ground activity this year, a survey of some of the top producers in Saskatchewan show that 2011 will at least equal 2010, or perhaps even surpass it.

Crescent Point Energy Corp., one of the dominant producers in the province, expects to spend approximately 62 per cent of its 2011 budget of $800 million in the Viewfield Bakken area of southeastern Saskatchewan, drilling approximately 200 net wells in the area. Scott Saxberg, president and chief executive officer, said the company’s planned spending in Saskatchewan this year is similar to in 2010.

“We’re spending a little bit more dollars in Alberta than last year with our Alberta Bakken play,” he said. “But it’s a pretty similar breakdown of the program [in Saskatchewan] with the Bakken and Lower Shaunavon. Last year, we had budgeted about $750 million and then

The average rig count of 69 in 2010 was 63 per cent above 2009. The boom is continuing as Saskatchewan operators employed 89 rigs in January, 26 per cent more than 2010.

Horizontal wells, which helped unlock the province’s Bakken-prone lands in the southeast and are now being applied to other areas, accounted for 56 per cent of the 2,730 oil wells drilled in Saskatchewan last year. That total oil well figure is 70 per cent higher than in 2009 and was above

expanded it to $900 million. A good chunk of that, though, was land sales and land acquisitions.”

To accommodate continued growth of the company’s Bakken production, Crescent Point expects to invest up to $45 million on infrastructure projects.

FEB/10

FEB/11

FEB/10

FEB/11

WELLS SPUDDED

238

224

WELLS DRILLED

244

248

SASKATCHEWAN WELL ACTIVITY

FEB/10

FEB/11

WELL LICENCES

295

377

▲

▼

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • APRIL 2011

49

Saskatchewan

As part of its ongoing waterflood implementation project, the company expects to convert up to 23 net horizontal wells into water injection wells, increasing the total number of Bakken water injection wells to approximately 36 by year-end.

In the Shaunavon area of southwestern Saskatchewan, the company plans to spend about 16 per cent of the 2011 budget by drilling 44 net wells that will target both the Lower Shaunavon resource play and the emerging Upper Shaunavon. “It’s very similar to 2010,” Saxberg said. “That program is probably a little bit lighter than what we’d want to do and so I think part way through the year

in [is] more building the infrastructure... and once we get that infrastructure in, then we’ll increase the capital spending in that area.”

The company plans to implement its fourth waterflood pilot in the Lower Shaunavon and to invest up to $27 million in infrastructure projects, including construction of a gas processing plant and a central oil battery, and expansion of the area’s crude oil and natural gas gathering systems.

Trent Yanko, president and chief executive officer of Legacy Oil + Gas Inc., previously helped advance fraccing and horizontal drilling in the Bakken with

Horizontal wells accounted for 56 per cent of the 2,730 oil wells drilled in Saskatchewan last year. The total oil well figure for 2010 is 70 per cent higher than in 2009. we may look to expand our Shaunavon drilling. But at this stage, we’re focused on the Bakken because of the stage of that play. The stage that the Shaunavon play is

Mission Oil & Gas Inc. Yanko said Legacy is still working through its budgeting process. “We see ourselves probably as busy as we were last year, if not more so,” he said.

“We basically drilled around 80-85 gross wells in Saskatchewan in 2010 and we see ourselves probably on that same pace, if not even being a little bit busier than that, again in 2011.”

The company said late last year that its core flooding study of the Torquay at Antler/ Frys was continuing and that it anticipated receiving results of the subsequent reservoir simulation in early 2011. Antler/ Frys is directly adjacent to the successful waterflood project in the Sinclair field in Manitoba. “We are still working on the lab results,” Yanko said. “[We’re] looking to have early data from that in the next month, I’ll say, and that will help us move towards a reservoir simulation, and then from there, probably in the summer sometime, we [will] get a field pilot going once we have done the core flooding work and then also run some reservoir-simulation work.”

Waterflooding, Yanko noted, has historically been important to Saskatchewan’s production, and it will only grow in importance. “That’s just going to write a whole new chapter of enhanced recovery in the province and basically a whole new chapter of future production reserve adds that

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will be coming over the next number of decades,” he said.

PetroBakken Energy Ltd. said recently that in southeastern Saskatchewan it expects to drill 75 net wells (including approximately 55 net bilateral wells) in the Bakken and over 30 net conventional wells. Facilities expenditures of approximately $65 million in this area are expected to further optimize operations and bring on stream Mississippian production that is currently constrained.

The company will continue to invest in enhanced oil recovery pilots to evaluate several injection configurations and fluids, including natural gas. Overall, in southeastern Saskatchewan, PetroBakken plans on spending $325 million, comprised of $250 million in the Bakken and $75 million on conventional Mississippian plays.

Anthony Marino, president and chief executive officer of Baytex Energy Corp., said about 80 gross wells are expected to be drilled in the province this year, although the number could end up being higher. The company has set an overall corporate budget of $325 million, but wouldn’t provide an overall specific figure

for Saskatchewan, only saying spending will be higher this year than in 2010.

Activity in the province will focus on heavy oil and light oil development in the Viking in southwestern Saskatchewan.

“Over the long term, we’ll have a pretty big development project in the Viking light oil, too,” Marino said. “We’re in the early stages of developing it. Our activity will be somewhat higher in Saskatchewan than it was in 2010.”

Ensuring sufficient takeaway cap­ acity to keep up with growing production volumes in the Bakken will be critical for the play’s continued prosperity. To that end, Enbridge Energy Partners, L.P. (EEP) and Enbridge Income Fund Holdings Inc. (ENF) said late last year they were proceeding, subject to regulatory approvals, with a joint project to further expand crude oil pipeline capacity to accommodate growing production from the Bakken and Three Forks formations in Montana, North Dakota, Manitoba and Saskatchewan.

The Bakken expansion program will increase takeaway capacity from the Bakken play by 145,000 barrels per day, which can

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Canadian projects will be carried out by ENF at a cost of about C$190 million.

The expansion program will originate at Beaver Lodge Station near Tioga, N.D., in the heart of the Bakken, and will follow existing EEP and ENF rights-of-way to terminate at and deliver to the Enbridge mainline terminal at Cromer, Man. In addition, EEP has proposed a separate project to expand its pipeline system south of the Missouri River, connecting to Beaver Lodge Station and providing increased access to the expanded North Dakota System.

Once on the Enbridge mainline, Bakken production will have access to the multiple markets accessible from the mainline and connected pipeline systems. The program is a series of pipeline expansion projects that will provide approximately 145,000 barrels per day of incremental capacity from North Dakota into the Enbridge Mainline at Cromer by the first quarter of 2013.

— DAILY OIL BULLETIN

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Quebec bans new shale gas drilling pending regulatory review CAPP supports national energy strategy

— DAILY OIL BULLETIN

— DAILY OIL BULLETIN

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gas development. Additional efforts are also needed to make shale gas development more socially acceptable in the province and that regulations must be improved.

Last fall, the province commissioned BAPE to propose a legislative framework to regulate exploration and development of the resource. On February 28, the review board handed over its report to the Quebec government.

“In the past year, Quebecers have learned that the Saint-Laurent Lowlands may be rich in natural gas,” Premier Jean Charest said in his inaugural address for the current legislative session. “This gas has significant potential for the creation of wealth because every year Quebecers spend nearly $2 billion on natural gas produced outside Quebec.”

Charest noted that natural gas emits less pollution than gasoline and diesel, and it’s also cleaner than the oil used to heat homes and the heavy fuel oil used in fac­ tories. “However, extraction of this shale gas has raised concerns with Quebecers.

We believe that prudence is called for and that the industry must prove its mettle.”

The Canadian Association of Petroleum Producers (CAPP) is “broadly supportive” of a national energy strategy, its president told the Canadian Senate’s standing committee on energy, the environment and natural resources in February. “I do think an energy strategy is an important initiative,” David Collyer said in Ottawa. “However, I don’t think we should underestimate the challenge in getting the common view of some rather difficult issues.”

One of the challenges is Canada’s diversity with very different interests across the country and very different energy production and consumption mixes, senators were told.

“But I think it’s fundamentally important that we find an alliance around something like energy that is so critically important to our future as a country,” said Collyer. “If we get an alliance and bridge some of those internal differences, we can both realize the economic benefit and proceed responsibly around energy develop­ ment and at the same time represent ourselves as a country more effectively in the international debate.”

CAPP is participating in the Energy Policy Institute of Canada’s work on an energy strategy and also is involved in the Think Tank Group, which is working on the issue, he said. An energy strategy could put a lot of these discussions in a broader context and a lot of the individual policy decisions in a broader framework, which is critically important, Collyer suggested.

The federal and provincial energy ministers will be meeting in Alberta this summer and will be discussing energy strategy, added Greg Stringham, CAPP’s vice-president of oilsands and markets.

One of the key elements in which they expressed interest is having strategy foundations in place.

Frac operations in Quebec have triggered concern among landowners, engineers and the public at large.

The government of Quebec has received and accepted the province’s regulatory report on shale gas which calls for a strategic environmental review before allowing development. The province is going to form a committee of experts, government and municipal officials and industry to conduct this strategic review.

The regulator’s report does suggest some shale gas work can proceed during the strategic review but new wells will only be allowed where they serve to increase scientific knowledge necessary for the strategic environmental review. Temporary regulations will be implemented to allow these wells, the province said.

“Quebecers should know that we will not accept any compromise on health, safety and respect for the environment and that we will take the time that is needed to make sure these conditions are fulfilled,” said Pierre Arcand, minister of environment, sustainable development and parks.

The Bureau d’audiences publiques sur l’environnement (BAPE) report said more work must be done to improve government, public and industry knowledge about shale

OIL & GAS INQUIRER • APRIL 2011

53

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Operators end helicopter flights ferrying crews over rough seas

By Pat Roche

Photo: ©istockphoto.com/landbysea

Corridor files application for Old Harry

Choppers will not fly personnel to offshore rigs when waves stand higher than six metres.

Oil and gas operators in Newfoundland and Labrador have established new criteria for offshore helicopter flights in response to a crash investigation recommendation.

In a final report released on the 2009 crash of a helicopter en route to the Hibernia oil platform, the federal Transportation Safety Board recommended offshore helicopters—which are used for crew changes on the drilling rigs and oil production platforms off Newfoundland—not fly when seas are too rough for a successful “ditching,” or emergency landing.

Seventeen people died when the Sikorsky S-92A crashed into the sea due to a serious defect in the design of its gearbox. Only one person survived after the helicopter hit the water hard, sustained severe damage and sank quickly in the frigid Atlantic. It was the worst aviation disaster in the history of Canada’s offshore oil and gas industry.

The province’s offshore oil and gas operators have agreed that the helicopters won’t fly if the seas exceed the ca­pabilities of the flotation equipment on the individual aircraft, said Paul Barnes, Atlantic Canada manager for the Canadian Association of Petroleum Producers.

Offshore oil and gas operators in Newfoundland contract five large helicopters. Barnes said three helicopters that make up the regular passenger fleet are fitted with enhanced flotation equipment to enable them to remain afloat in seas of up to six metres. The other two, which have the manu­ facturer’s standard flotation equipment, can survive in seas of up to four metres.

Under the new operating protocol adopted by the oil and gas operators, the three core helicopters with the enhanced flotation equipment won’t fly when the seas are higher than six metres and the two aircraft with standard f lotation ca­pability won’t fly when seas exceed four metres, Barnes said.

In the past, the helicopters would occasionally fly when sea states exceeded their flotation capabilities. “It will have some impact on operations at this time of year,” Barnes said of the new criteria, noting that the seas happened to be higher than six metres on the day that he spoke. “How much of an impact is not clear at this point.

It will have some impact, but at the end of the day, safety is the top priority.”

— DAILY OIL BULLETIN

Corridor Resources Inc. has submitted to the Canada-Newfoundland and Labrador Offshore Petroleum Board a project description for the drilling of an exploration well on the Old Harry prospect within Exploration Licence 1105, located in the Laurentian Channel of the Gulf of St. Lawrence in the Newfoundland and Labrador offshore area.

The project description, submitted pursuant to the Canadian Environmental Assessment Act, starts the official regulatory process for obtaining the necessary approvals to drill the offshore well between mid-2012 and early 2014.

“We are very excited to commence the approval process for the Old Harry explor­ ation program; this is a prospect that warrants exploration. This well is an essential step in the evaluation of the Old Harry prospect, which offers significant hydrocarbon potential and associated benefits for eastern Canada,” Phillip Knoll, chief executive officer of Corridor Resources, said in a prepared release.

The Old Harry geological structure is approximately 30 kilometres long and 12 kilometres wide. It is one of the largest undrilled geological structures in eastern Canada. Corridor previously completed a work program to identify the proposed well location on the western side of Exploration Licence 1105, which included the collection and interpretation of 2-D seismic data in 1998 and 2002, as well as a geohazard site survey in October 2010.

To date, only 10 offshore wells have been drilled in the Gulf of St. Lawrence.

Knoll noted that studies have indicated that the Gulf of St. Lawrence holds significant potential for hydrocarbon exploration.

Corridor currently has reserves of natural gas at the McCully Field near Sussex, New Brunswick and shale gas resources in the adjacent Elgin sub-basin.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • APRIL 2011

55

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DOE says Keystone pipeline can meet Gulf refiners’ crude demand

Photo: ©istockphoto.com/Stanislav Komogorov

By Elsie Ross

The federal report says Keystone XL will reduce reliance on foreign oil at no net environmental cost.

TransCanada Corporation’s proposed Keystone X L Pipeline project f rom Hardisty, Alta., to the U.S. Gulf Coast represents a high-capacity option that could meet an early, as well as longerterm, demand for crude by Gulf refiners, says a study commissioned by the U.S. Depar tment of Energ y (DOE).

Massachusetts-based EnSys Energy & Systems, Inc. compiled the study.

Modelling results have found there is a short-term (2015-2020) as well as a longerterm market opportunity for pipeline capacity to deliver heavy western Canadian crudes to Gulf Coast refiners to fill a gap created by declining supply from traditional heavy crude suppliers, such as Mexico and Venezuela, according to EnSys. This gap otherwise would be filled by increased imports from other foreign sources, notably from the Middle East, it said.

And, while not specific to the Keystone project, the combination of growing Canadian oilsands imports and U.S. demand reduction has the potential to “very substantially reduce U.S. dependency on non-Canadian foreign oil, including from the Middle East,” the report found.

The EnSys model analysis results showed no significant change in total U.S. refining activity, total crude, and product import volumes and costs, in global refinery CO2 and total lifecycle greenhouse gas emissions, whether or not Keystone XL is built.

Keystone XL is a 2,673-kilometre, 36-inch crude oil pipeline that will begin at Hardisty and extend southeast through Saskatchewan, Montana, South Dakota and Nebraska. The pipeline will then continue on through Oklahoma and Texas to delivery terminals near Port Arthur, Texas, to serve Gulf Coast refineries.

“This study supports what we have been saying for some time—that Keystone XL will improve U.S. energy security and reduce dependence on foreign oil from the Middle East and Venezuela,” Russ Girling, TransCanada’s president and chief executive officer, said in a news release.

“Keystone XL will also create 20,000 highpaying jobs for American families and inject $20 billion into the U.S. economy.”

Keystone XL potentially could add capacity to bring U.S. Bakken crudes to market and/or reduce congestion at Cushing, Okla., by increasing capability

for access to the Gulf Coast for U.S. domestic crudes, EnSys concluded.

TransCanada recently announced it has received sufficient contractual support to proceed with its Cushing Marketlink project, which will have the ability to provide transportation of 150,000 barrels per day of U.S. crude oil production from Cushing to the Gulf Coast. The pipeline firm also concluded a successful open season that obtained firm contracts of 65,000 barrels per day for its Bakken Marketlink from Baker, Mont., to Cushing using capacity on the northern leg of Keystone XL. In general comments, EnSys said that over the next 20 years, the main choice for Western Canadian Sedimentary Basin exporters will be between moving increasing crude oil volumes to the United States or to Asia. “Led by China, which has already bought heavily into oilsands production, Asia constitutes the major region for future petroleum product demand and refining capacity growth and offers Canada diversification of markets,” said the consultant.

In addition, costs for transporting Canadian crudes to major markets in northeast Asia (China, Japan, South Korea and Taiwan) via pipeline and tanker are lower than costs for transporting the same crudes via pipeline to the Gulf Coast, it said.

Projections from the study, supported by third-party information, indicate that Asian markets are attractive and if the access routes are developed, they could access at least one million barrels per day of western Canadian crudes and potentially significantly more, compared to the less than 50,000 barrels per day that move to Asia today.

Meanwhile, TransCanada announced t hat it s Key stone P ipel i ne Sy stem (Keystone XL is a proposed major expansion of the earlier system) has begun oil deliveries through a new extension between Steele City, Neb., and Cushing, Ok la. T he 480 -k ilometre extension includes in an increase in Keystone’s nom­ inal capacity to 591,000 barrels per day.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • APRIL 2011

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JOB Careers in the Oilpatch

Jeff Young Age: 40 Title: Estimation manager Company: Vista Projects Limited Location: Calgary

Photo: Christina Ryan, Inex Photography

Length in position: Three years

How did you get into this profession?

I’m a civil engineer by training. A lot of estimators come up through different routes, and mine happened to be through contracting and construction. I had field experience working on projects and then I started estimating and bidding tenders, winning them, and then going on site to run the job.

What does your field experience bring to your role as

of concrete, you have a problem. You always look back, you check, you

estimation manager?

confirm. Change is going to happen, but it has to be identified early so

My biggest goal is constant improvement. I’m not going to reinvent the

that you can deal with it. There’s nothing worse than getting caught off

wheel, but I hope I can make that wheel spin faster. One of the biggest chal-

guard at the 11th hour. I want to make sure everyone keeps their eye on

lenges I came up against as a young estimator was keeping the big picture

the bigger picture.

in mind in order to be competitive. If you threw in the kitchen sink, you wouldn’t win the job. You have to be willing to take a risk—not a gamble, but

How do you make people aware of the consequences of

a measured approach to what you know and what you don’t know.

their actions?

Basically, it’s about informing and challenging people. You do this

What sort of challenges do you find in bridging the gap between

respectfully, but you need to bring it to their attention. Everyone wants

the designers and the field team?

to do a good job. In the rush for output, the context of the original design

One of the things I’m trying to do is to get the disciplines to recognize

can be forgotten. So you have to ask the team to check their original

the impact they have. If you originally budgeted 400 cubic metres of

quantity versus the current design and have them come to the conclu-

concrete, but now your construction drawings contain 500 cubic metres

sion on their own. It really does open their eyes.

OIL & GAS INQUIRER • APRIL 2011

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TOOLS

OF THE TRADE A LOOK AT NEW TECHNOLOGIES

Camex Low Rider Scissorneck Trailer

This oilfield hauler offers lower deck height and a lower centre of gravity.

Who is Camex Equipment?

The working deck is 8.5 feet wide by 53 feet in length and features two-inch

Camex Equipment Sales & Rentals Inc. started out primarily as a company

oak construction for longer life.

that supplied and designed drilling rig transportation equipment—heavyspec bed trucks, picker trucks, winch trucks, and specialized oilfield and

The trailer has an easy adjust two-position scissorneck complete with a

heavy-haul trailers. This later evolved into the manufacturing of vacuum-

full-width tapered pickup throat and extended length gooseneck with two

related products, such as hydro vacuums, combination wash/steamer

kingpin settings. The deck features a full-width seven-inch non-ratcheting

vacuums, and straight vacuum trucks and trailers. More recently, we have

center lift roll plus a pair of seven-inch pop-up split rolls at the rear of the

been involved with the production of pressure trucks, fuel/lube trucks and

main deck to facilitate and assist the unloading of large, heavy rig compon­

hot oilers.

ents. Winching heavy loads onto the trailer is expedited by a larger 10.75inch full-width tail roll complete with two sets of support rollers for extra

What is the Camex Low Rider Scissorneck Trailer?

strength and durability. Safety features include four swing-out wide load

Drilling rig equipment and components are getting larger and heavier.

lights, dual rear strobe lights, 14 pin pockets and 20 chain pockets. The

Navigating them through road and highway infrastructure is a very chal-

four- and five-axle trailers feature airlift axles for less drag and tire wear

lenging—if not impossible—task. The Camex Low Rider Scissorneck

when pulled empty or with a lighter load.

Trailer addresses this problem for oilfield operators by significantly lowering load heights as well as lowering the centre of gravity for more stability

Where do you see this technology heading in the future?

and safety.

Camex forsees the introduction of Low Rider Extendable Trailers, Oilfield Floats and Fixed Neck Trailers to round out the trailer line in the very near

What are the competitive advantages of this equipment?

future as well as the development of complementary Low Rider Jeeps

With a deck height of 36 inches, the Camex Low Rider Scissorneck Trailer

and Boosters.

boasts the lowest deck height in the industry (compared to the 44-46 inch deck heights of similar trailers)—all without compromising load capacity and features. The trailer comes in tri-axle, four-axle and five-axle config­ urations for 40-ton, 50-ton, 60-ton and 70-ton load capacities, respectively.

Answered by Wally Taschuk, Director of Sales and Marketing, Camex Equipment Sales & Rentals Inc.

OIL & GAS INQUIRER • APRIL 2011

61

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