Oil & Gas Inquirer - November 2009

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Keeping readers regionally informed

Reshaping CT COLLIN MORRIS: An innovator radically adapts coiled tubing

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Grant Shomody has a CO2 solution for a huge play

Shale victory

Bill Streeper says the Horn River play is already commercial

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Table of Contents

Keeping readers regionally informed

F E A T U R E S

12

Declaring victory

16

Going flat out

20

by James Mahony and Mike Byfield

B.C.’s Horn River Basin shale gas play shapes up as a commercial success

by Mike Byfield

Collin Morris, a former roughneck-turned-inventor, develops a radically different form of coiled tubing

The $6B Montney prospect

by Mike Byfield

Grant Shomody proposes a unique CO 2 supply solution for fracing B.C.’s huge tight gas play

6

NOVEMBER 2009 • OIL & GAS INQUIRER

Table of Contents

Enviro-Tub... first class secondary containment protecting the product environment and primary container

Above Bulkhead Level 500 Gal se of spills inca Eliminating d failure Bulkhea

R E G I O N A L

25

N E W S

British Columbia

47

• Demand for more hydraulic frac sand spawns new mining developments

29

decision to split in two • Oilpatch said to face positive “perfect

Northwestern Alberta/Foothills • ERCB denies Penn West appeal of highrisk enforcement action

35

storm” for recovery in 2011

51

Athabasca oilsands projects for $1.9B

Lower Shaunavon oil play

55

Central Canada • Federal agencies focus on alleged

• StatoilHydro plans to research and pilot

dumping of Chinese tubular goods

new in situ technology

Central Alberta

Saskatchewan • Crescent Point moves into lead on

Northeastern Alberta • PetroChina buys 60 per cent of

41

Southern Alberta • Access to capital clinched EnCana’s

57

• Lower gas prices and bitumen

International • Enerplus commits US$406M to

production reduce Alberta’s revenue

acquire stake in Marcellus shale play

• Culane expects waterflood at Killam to boost oil production

Cover Design: Aaron Parker Cover Photo: Jennifer Jacula

I N

10

E VE R Y

I S S U E

Statistics at a Glance

61

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OIL & GAS INQUIRER • NOVEMBER 2009

7

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Editor’s Note Vol. 21 No. 11 President & ceo Bill Whitelaw | bwhitelaw@junewarren-nickles.com

Mike Byfield | mbyfield@junewarren-nickles.com

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Unconventional thinking

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Collin Morris, the man on the cover of this month’s issue, reminds me of Bob Tessari. Years ago, Tessari invited my publication at the time to profile his revolutionary new tool, a top drive for land-based rigs. In an early test, the prototype’s hydraulic system ruptured, oil spewed everywhere, and the heavy device almost crashed onto the rig floor. But Tessari persevered and Tesco did in fact vastly improve drilling.

Earlier top drives, like earlier multiple conduit coiled tubing (CT) umbilicals, were extremely expensive tools used exclusively in offshore drilling. Will FLATpak CT, a radically reshaped coiled tubing product developed by Morris for land-based equipment, have the same impact? I’m not qualified to make such predictions—read the article “Going flat out” on page 16 and decide for yourself. I can say that the co-founder of CJS Coiled Tubing Supply has the same blend of design originality and testicular fortitude as Tesco’s Tessari.

Grant Shomody is the first person, as far as I know, to delineate the potential scale of the Montney development in terms of capital spending. Six billion bucks is a lot of cash.

During the drilling season, you already have to book months in advance to be sure of a hotel room in Dawson Creek. If the founder of Grantech Engineering International is right, it’s going to get pretty hectic in that corner of northeastern B.C. Like Tessari and Morris, Shomody combines engineering insight with the personal drive needed to bring a concept to reality. Grantech says it can provide new technology capable of generating a constant, affordable supply of CO2 for fracturing horizontal wells.

If so, it’s potentially an important operational breakthrough, since CO2 fracs reportedly work best in the Montney formation.

Bill Streeper, another key figure in this month’s Oil & Gas Inquirer, is an entrepreneur rather than a technology guru. In fact, this former trucker is the first citizen of Fort Nelson, B.C.—its mayor, largest individual taxpayer, and largest industrial land developer. Long before Horn River Basin producers were willing to say the shale play had achieved commercial status, Streeper clearly stated why the odds overwhelmingly favoured its success.

Original thinking is bound to seem unconventional at first, and often a new concept fails to pan out. However, the ideas that do work become the basis of entire economies.

Fortunately, the western oil and gas sector has always been blessed with its share of these frequently stubborn but always amazing individuals.

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N E X T

I S S U E

Conventional oil With West Texas Intermediate crude prices

If you know an admirable person to profile in

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how producers and service companies are

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OIL & GAS INQUIRER • NOVEMBER 2009

9

Stats

FAST NUMBERS

$633

AT A GLANCE

million

Provincial land sales revenue for the first nine months of 2009, the lowest since 1992. The equivalent figure for 2008 was $4.1 billion. Land prices in 2009 averaged $360 per hectare.

$331

million

British Columbia’s share of western Canadian land sales revenue during the first nine months of 2009, averaging $1,281 per hectare. The equivalent figures for 2008 were $2.3 billion and $3,820.

Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin

MONTH

OIL

GAS

OTHER

T O TA L

MONTH

OIL

GAS

D RY

SERVICE

T O TA L

Oct 2008 Nov 2008 Dec 2008

297 273 496

937 1,075 1,793

241 136 200

1,475 1,484 2,489

Oct 2008 Nov 2008 Dec 2008

636 594 917

1,308 1,313 2,380

194 142 173

69 45 137

2,207 2,094 3,607

Jan 2009 Feb 2009 Mar 2009

156 116 321

606 899 979

96 120 317

858 1,135 1,617

Jan 2009 Feb 2009 Mar 2009

248 269 433

813 1,060 1,121

70 113 165

47 36 86

1,178 1,478 1,805

Apr 2009 May 2009 Jun 2009

111 71 36

344 187 143

140 53 42

595 311 221

Apr 2009 May 2009 Jun 2009

111 71 177

342 187 211

61 46 45

12 35 27

526 339 460

Jul 2009 Aug 2009 Sept 2009

79 101 146

178 212 155

77 80 78

334 393 379

July 2009 Aug 2009 Sept 2009

79 250 146

31 267 155

6 36 45

3 37 9

119 590 355

Wells Drilled In British Columbia

Wells Drilled In Saskatchewan

Source: B.C. Oil and Gas Commission

Cumulative to October 2, 2009 Source: Saskatchewan Energy & Resources

MONTH

WELLS DRILLED

C U M U L AT I V E *

Oct 2008 Nov 2008 Dec 2008

66 61 79

779 840 919

Jan 2009 Feb 2009 Mar 2009

125 117 75

125 242 317

Apr 2009 May 2009 Jun 2009

33 26 19

350 376 395

Jul 2009 Aug 2009 Sept 2009

34 36 37

429 465 502

** from fromyear year to to date date

OIL

GAS

OTHER

D RY

T O TA L

289 70 26 38

5 29 174 0

13 8 3 15

7 23 5 25

314 130 208 78

30 13 44 404

0 0 0 0

0 0 0 0

0 0 0 0

30 13 44 404

319 83 70 442

5 29 174 0

13 8 3 15

7 23 5 25

344 143 252 482

Vertical Wells

Lloydminster Kindersley Swift Current Estevan Horizontal Wells

Lloydminster Kindersley Swift Current Estevan Total Wells

Lloydminster Kindersley Swift Current Estevan

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NOVEMBER 2009 • 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 3.75

4.25 4.00

4.35/GJ Total vol.: 1,301 TJ Transactions: 145

3.75

Tcf

Tcf

in the United States

3.716 Tcf Year ago: 3.266 Tcf 5-year avg: 3.242 Tcf

3.50

3.50 Sept 17

Sept 23

Sept 30

Oct 7

3.25

Oct 14

Sept 11

Sept 18

Sept 25

Oct 2

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada October 13, 2009 Source: Rig Locator

Alberta September 2009 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

(Per cent of total)

Western Canada Alberta

AC T I V E

154

433

587

26%

39

73

112

35%

8

2

10

80%

Saskatchewan

60

71

131

46%

WC Totals

261

579

840

31%

0

2

2

0%

British Columbia

Manitoba

Northwest Territories

OIL WELLS

Alberta

GAS WELLS

Sept 09

Sept 08

Sept 09

Sept 08

Northwestern Alberta

15

81

32

364

Northeastern Alberta

23

66

1

75

Central Alberta

90

233

23

185

Southern Alberta

18

34

99

439

146

414

155

699

TOTAL

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada October 13, 2009 Source: Rig Locator

Alberta September 2009 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

AC T I V E

Western Canada 311

573

884

35%

British Columbia

12

29

41

29%

7

1

8

88%

Saskatchewan

122

60

182

67%

WC Totals

452

663

1,115

41%

1

1

2

50%

Manitoba

Northwest Territories

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

Alberta

Alberta

Oct 9

BITUMEN WELLS

Sept 09

Sept 08

Sept 09

Sept 08

Northwestern Alberta

0

1

1

4

Northeastern Alberta

0

0

23

64

Central Alberta

9

34

40

103

Southern Alberta

5

42

0

0

14

77

64

171

TOTAL

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OIL & GAS INQUIRER • NOVEMBER 2009

11

Feature

DECLARING

VICTORY

B.C.’s Horn River Basin shale gas play shapes up as a commercial success

by James Mahony and Mike Byfield

For the past year, major producers in the Horn River Basin stayed coy when asked if the massive shale gas play could be classified yet as a commercial success.

But Bill Streeper, mayor of Fort Nelson and a long-time oilfield entrepreneur in the remote area of northeastern British Columbia, says it’s time to declare victory. “When you see very large, long-term shipping commitments being signed, it’s self-evident that profitability has been established in the minds of the key players,” Streeper says.

“A lot of money is already being invested in new pipeline and processing capacity by Spectra [Energy] and TransCanada [Corporation],” says Streeper. The former oilfield trucker, now an industrial real estate developer, is the second-largest municipal taxpayer in the town of 3,800, after Spectra. The North American natural gas infrastructure company operates a large natural gas processing plant in Fort Nelson.

Spectra also owns an extensive regional 12

NOVEMBER 2009 • OIL & GAS INQUIRER

gathering pipe system plus the mainline trunk line to southern B.C. Last spring, Spectra announced that it had received firm commitments of 760 million cubic feet (MMcf) per day for gathering and processing capacity from seven producers operating in the basin. These commitments support Spectra’s plan to expand gathering and processing capacity in Fort Nelson to accommodate as much as 1.1 billion cubic feet (bcf) per day of additional Horn River gas. Spectra is also working to expand its pipe capacity to the Dawson Creek area (specifically the receipt point at Gordondale, Alta.). From there, the rapidly growing shale gas supply will flow through the TransCanada and Alliance trunk pipeline systems to customers in eastern North America.

Meanwhile, TransCanada Corporation has jumped directly into the northeastern B.C. market for the first time. Last February, the pipeline firm announced that it had received binding commitments

for 378 MMcf per day of Horn River gas. Its $340 million Horn River pipeline system will be about 155 kilometres in length, composed of new pipe up to 36-inch diameter as well as an existing EnCana pipeline in the area. The new system will transport shale gas to a tie-in point on TransCanada’s existing Alberta pipeline network near Rainbow Lake.

Streeper is even more enthused about the proposed contruction of a liquefied natural gas (LNG) plant at Kitimat, which would enable Horn River producers to ship gas via tankers to Asian markets. The West Coast liquefaction plant would be fed gas via the Spectra pipeline system.

“International gas prices are stronger than domestic prices, which could stay soft for years,” the mayor points out.

“What this Kitimat terminal does is it provides a much needed outlet to a strategic market for North American gas producers,” agrees Rosemary Boulton, president of Kitimat LNG Inc.

Feature

Fort Nelson Mayor Bill Streeper says the stars are aligning on Horn River's reserves, production costs, infrastructure, and market access.

This summer, the company signed preliminary supply deals with two Horn River producers, Apache Corporation and EOG Resources Canada. Apache is negotiating a commitment of 200–300 MMcf per day to the proposed plant, whose planned capacity is 700 MMcf per day. Apache also has an option to purchase an ownership stake in the LNG plant. The EOG volume under discussion remains undisclosed.

Although EnCana Corporation has not yet signed on with Kitimat, this pivotal Horn River producer is enthusiastic. “It is a very viable project; we really do love the project,” Mike Graham, EnCana’s executive VP and Foothills division president, told a gas and power conference in New York last month. The shipping distance from B.C. to East Asia is relatively short, and Kitimat has inked deals with Korea Gas Corporation and Gas Natural for its LNG. Ultimately, the Horn River play’s profitability will be defined at the wellhead.

In recent weeks, highly encouraging

estimates and field operational details have been released by EnCana, Nexen Inc., and Quicksilver Resources Inc. “We have done a lot of core work and exchanged a lot of data with Devon and Apache and EOG,” Graham says. “We think there is probably 500 tcf [trillion cubic feet] of original gas in place.”

One EnCana well in the basin came on at 8 MMcf per day and after about a year on production is now producing 4 MMcf per day. That 50 per cent decline rate is “very, very good,” Graham says. “Some of the big shale plays like Haynesville [a U.S. shale play] come off and they come off hard, with declines of 80–90 per cent in one year.” EnCana is also active in that play.

With partner Apache Corporation, EnCana has been extending the length of the horizontal wells to tap into the gas and increasing the number of fractures.

“These are big wells,” said Graham. “They may get 10 to 15 bcf [of reserves—probably twice that of the next shale play in

North America].” EnCana has about 350 net square miles of land in the Horn River basin, all in one big block with an estimated 300 bcf of gas per square mile on its lands.

Beginning with t wo-stage fracs, EnCana has now increased that to 12 and 14. The last few wells with 12 and 14 stage fracs have been coming on at more than 10 MMcf per day and the company expects they will follow the same profile as the others. “We think each frac will recover 1 bcf per frac [a total of 10 bcf per well],” Graham estimates.

At present, EnCana and Apache (in a 50-50 partnership) are drilling 1,600 metre wells but that may be extended to 2,000 metres with perhaps 20 fracs which would work out to about eight-acre spacing. Costs also are coming down. While EnCana at one time spent $1 million per frac, now it costs $750,000.

While EnCana currently has 40 gross wells on the Horn River play, only about 13 are on production. The company has OIL & GAS INQUIRER • NOVEMBER 2009

13

Feature

been completing and in some cases tying Quicksilver reports the completion them in but is waiting for the expected of its first Horn River Basin well, which tested at an initial production rate of 13 stronger gas prices expected this winter to turn them on. The remoteness of the area MMcf per day. The D-50A horizontal well near the Northwest Territories’ border was drilled into the Muskwa shale forpresents a challenge in terms of transmation with roughly 3,500 feet of lateral portation costs, Graham acknowledges. and 10 stages of fracture stimulation. The “To get to the Henry Hub [in Louisiana] it well averaged 10 MMcf per day in the first would probably cost us a buck; if you look month of production. at AECO prices [in southern Alberta] it’s The Texas-based independent says 65 or 70 cents,” he says. initial drilling results confirmed more Nexen’s latest trio of horizontal wells than 500 feet of net shale thickness in the in the basin have been drilled in the Dilly Muskwa and Klua-Evie shale formations Creek area. With five Horn River wells at a vertical depth of about 9,000 feet. The now on stream, the company reports in a company has drilled a second well into the recent news release that it is producing 15 lower Klua-Evie shale, with roughly 4,300 feet of lateral, and expects to begin comto 20 MMcf of gas per day out of the basin.

Most of that gas flows from the three new pleting the well late this year. horizontals, which I n t he w i nte r had a higher fracof 20 07–20 08, ture density than Quicksilver acquired earlier wells.

19 explorator y liI n it s r e c e n t cences on 127,000 drilling program, net contiguous acres the Canadian indein the Horn River pendent took advanBasin, and needs to tage of improved drill 8 more explore qu ipme nt ut i l iatory wells in the zation and longer next 3 years to valiwells, racking up date t he licenses more fracs per well. and convert them The company says it to 10-year develop— Glenn Darden, President and CEO, completed 26 fracs ment leases.

Quicksilver Resources Inc. in 15 days, with a “We anticipate drilling longer lat100 per cent success erals with additional stages of fracture rate on its frac program. Two of the wells were completed with 8 fracs, while a third stimulation which we expect will result was completed with 10 fracs. in even greater production per well,” The Calgary-based independent estiGlenn Darden, Quicksilver president mates that its Dilly Creek lands (which and CEO, stated in a news release. “It is becoming clear from mapping, core total 88,000 acres, wholly owned) could support another 500 to 700 wells. (The analysis, and production results that company holds a further 35,000 acres our acreage…is in a very good part of in the basin.) Although Nexen’s capital the basin and contains the potential for multiple tcf of recoverable natural gas budget has not been finalized, company spokesman Tim Chatten says 8 to 10 horiresources.” zontals will likely be drilled in the Dilly Streeper suggests that no one can Creek area this winter. realistically estimate how large the shale Like other operators, Nexen describes resource may be in the region. “If you the Horn River Basin as one of the most look at the geological maps, details on prolific shale gas plays on the continent. the shale formations all stop at the B.C. The company estimates its own potential border with the Northwest Territories,” recovery at three to six tcf of gas, although the mayor says. “Of course, those forfurther appraisal is required before that mations actually do extend into the territories—they haven’t been properly estimate can be firmed up. Based on the classic ratio that six thousand cubic feet mapped yet. It will be interesting to see of natural gas equals one barrel of crude, what’s there when the infrastructure Nexen is hoping to recover the equivalent matures to the point that we can drill of perhaps one billion barrels. further north.”

“ We anticipate drilling longer laterals with additional stages of fracture stimulation which we expect will result in even greater production per well.”

14

NOVEMBER 2009 • OIL & GAS INQUIRER

Dave Middleton is stuck with a weird wine dilemma.

A toast to B.C. oilmen’s 50th anniversary The 50th anniversary celebration of the Fort St. John Petroleum Association was a swinging, banging, horsepowerful success—except for the awkward matter of the wine.

On August 27, federal Finance Minister Jim Flaherty addressed the association’s kickoff reception. On the 29th, an enormous queue of oilfield vehicles growled through the city, repeating a parade held on the B.C. oilmen’s 25th annversary. For two days, golfers golfed, riverboats raced, and trapshooters shattered clay pigeons. The festivities wound up with a dinner and dance at the Fort St. John Curling Club.

Dave Middleton, a salesman for Raven Oilfield Rentals, managed the 50th anniversary celebration for the association, altogether a two-year assignment. He and other volunteers fermented enough red wine to fill 600 bottles, one per guest at the wrap-up dinner and dance.

“The wine turned out fine but then we couldn’t get a licence,” Middleton laments. The problem?

The vintage had not been provincially inspected.

Middleton had no comment concerning what would become of the wine.

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Feature

Going Flat Collin Morris, a former roughneck-turned-inventor, develops a radically different form of coiled tubing 16

N ovember 2 0 0 9 • O I L & G A S I N Q U I R E R

Feature

I

t’s hard to imagine a better argument for giving engineers a healthy dose of genuine field experience than the technical ingenuity of Collin Morris. Not that Morris is an engineer—his closest approach to higher education is a black belt in karate.

Even so, this summer the president of CJS Coiled Tubing Supply Ltd. addressed a well-attended meeting in Oklahoma City (Society for Petroleum Engineers) and a wellbore deliquification conference in Groningen, Holland. His subject: A revolutionary method for encapsulating multiple conduits and electric wires within a single coiled tubing umbilical.

“CT [coiled tubing] was originally a flexible round pipe used to drill, complete, and produce shallow natural gas and oil wells,” Morris explains. “Of course, a CT rig’s ability to quickly and economically access the wellbore is also attractive for gas production. In that case, though, you often need multiple tubing strings rather than a single conduit.” Well deliquification is a case in point. A hydraulic, submersible downhole pump typically requires two tubing strings to form its hydraulic drive circuit, plus a third string for conveying produced water to the surface. Gas is produced via the casing.

at Maidstone, a half-hour drive east of Lloydminster. As a teenager, Morris aspired to become an air force jet pilot but balked at the low military pay. Instead, the Grade 12 graduate went to work on service rigs right after leaving school, then switched over to CT rigs about a year later.

When he became a CT operator in 1994, the technology was still evolving rapidly. (Coiled tubing applications for the patch were first created in western Canada, during the mid- to late 1980s.)

“You don’t meet too many guys with 15 years’ experience in this business,” the Lloydminster resident says. For years, he worked winters in northern camps.

In 1998, the rig hand took his first step as a future entrepreneur. Scott Kiser, a friend and mentor, launched Caliber Industries, offering CT services in northeastern Alberta. “Scott persuaded Joe [Reck] and me to jump ship [from Canadian Fracmaster] in exchange for some sweat equity,” Morris recounts.

Although oil prices were abnormally low at the time, Caliber fared well due to good service and limited competition in the local CT market.

In 2003, Reck and Morris left the company on a friendly basis to form CJS Coiled

There’s virtually nothing in Morris’ background pointing to him as the man who might adapt that expensive offshore technology to low-cost, land-based operations.

Out

by Mike Byfield

CT umbilicals containing multiple conduits were first developed for offshore producers, whose high-volume wells generate enough cash to pay for high-cost equipment.

“This product is manufactured in Texas, in a plant as big as a football field with giant drums,” Morris says. “Basically, coiled tubing strings are braided and encased within a wrapping. The strings have to be braided to maintain uniform lengths when the tubing is spooled. Otherwise the outer strands would have to be longer than the inner strands. The CT braiding machines are very high with complicated arms—it’s a pretty amazing operation.”

There’s virtually nothing in Morris’ background pointing to him as the man who might adapt that expensive offshore technology to low-cost, land-based operations. His father farmed and welded

Tubing, providing CT parts and supplies to the region. A year later, BlackWatch Energy Services Trust acquired Caliber. Reck is now VP of CJS, while Kiser has joined his former employees as business development advisor. “I’m the main concept guy, Joe gets things done, and Scott brings in the customers,” Morris says. “Without our being competent partners and good friends, CJS could not possibly have enjoyed the success that’s come our way.”

Beyond selling several million dollars’ worth of CT pipe, CJS developed a reputation as a technical coiled tubing problemsolver. “Wells produce a lot of other stuff besides oil and methane—hydrogen sulphide, sulphur dioxide, nitrogen, butane, salt, paraffin, water, and solids, including rocks. Some wells produce two or three of those things; others, all of them—every O I L & G A S I N Q U I R E R • N ovember 2 0 0 9

17

Feature

well has its own personality and you learn to work with it,” Morris says.

“One of the reasons that you find Albertans as oilfield consultants and specialists around the world is the unusually broad range of oil and gas wells that can be found here,” the CJS president comments.

“We’ve got high-pressure deep wells in the foothills, the shallowest wells, supersour gas, very light liquids, the heaviest crudes. One problem we constantly face in low-pressure gas wells—whether they’re coalbed methane [CBM], shale, or shallow conventional—is deliquification. If you don’t remove the produced water, it will build up against that low-pressure until it kills the gas flow.”

the umbilical,” Morris says. Further, he adds, the CT rig’s “skates” (chain clamps), which grip coiled tubing while it’s being fed into or out of the wellbore, do not function nearly as well if the umbilical has an irregular twisted form.

The CJS solution is called FLATpak, a concept that Morris came up with while driving across Montana with a friend.

Multiple conduits sit side by side, encased within a rectangular matrix of thermo plastic. “At first I thought about a square shape, but a rectangle is more adaptable,” the CJS boss recalls. Many configurations of conduit are possible, including various diameters, different electric wire, and more. In terms of manufacturing, FLATpak

a matter of changing one piece in the BOP assembly. That sort of logic carried through downhole tools, fishing equipment, wellhead assemblies, and the rest.”

Last October, CJS began commercializing FLATpak. “Our timing could hardly have been worse,” Morris acknowledges.

“The gas industry was collapsing. However, many producers recognize the urgent need for an innovation that enables them to deploy artificial lift systems in low-rate gas wells. They’re moving to hydraulic and electric submersible pumps and jet pumps, and to rigless operation. CT is especially wellsuited to horizontal wells, including CBM.” The company has installed 30 permanent FLATpak systems in Canada, more

The CJS solution is called FLATpak, a concept that Morris came up with while driving across Montana with a friend. Multiple conduits sit side by side, encased within a rectangular matrix of thermo plastic.

Low-volume gas wells must be managed economically or they’ll lose money.

CT rigs, where they can be applied, are often quicker and therefore cheaper operationally than conventional service rigs. However, deliquification with CT rigs requires submersible pumps, which in turn require CT umbilicals with multiple conduits. The more Morris pondered this challenge, the more he realized that traditional round coiled tubing would not likely provide a solution.

Round pipe is especially difficult to braid if the various conduits are of different sizes and materials—for instance, one strand may be used for fibre optics, not fluids. Even if the CT conduits are of uniform size, the braided umbilical is lumpy rather than smooth, like a thick rope. “The gaps between the twisted strands can allow gas to migrate unpredictably within 18

N ovember 2 0 0 9 • O I L & G A S I N Q U I R E R

is pressure-extruded as a single piece. The rectangular product coils tighter on a CT spool than round pipe, reducing transportation costs.

“I thought the major difficulty would be operational—working with rigs that were designed for traditional CT,” Morris says. “We were almost literally trying to fit a square peg into a round hole. Could we deploy it safely? How hard would it be to adapt the equipment? It seemed really daunting at first.”

At that point, his intimate familiarity with CT proved crucial. “We all dug in and realized that well control systems and running gear are easily modifiable for this product. Much of their sealing is rubber.

And as long as the rectangular form is solid and indexed [rounded at the corners], steel BOP [blowout preventer] rams can be switched easily to the new shape—it’s only

than 10 in the United States, and is adding four or five more per month. “Two service companies in Canada have performed hundreds of well stimulations and clean­ outs using FLATpak with hydraulic submersible and jet pumps. Financially, CJS is doing fine, especially considering that we’re a five-person company caught in a severe activity downturn,” Morris reports.

When engineers see the FLATpak concept, the former rig-hand-turned-inventor says, “they often see new ways to apply it, which is wonderful. For example, people are dusting off old pump prototypes to see if they will operate commercially with this new type of CT.” CJS itself is working to proof its umbilicals for higher pressures and temperatures. “I think there’s offshore potential,” Morris says. “For sure, this development is going to have worldwide significance for our industry.”

413088 Annugas Compres full page 路 fp

Feature

The Montney Grant Shomody proposes a unique CO2 supply solution for fracing B.C.’s huge tight gas play

Next year, Nova Gas Transmission Ltd. hopes to start constructing its Birchcliff pipeline, moving natural gas from British Columbia’s Montney play. Five customers plan to begin shipping about 115 million cubic feet (MMcf) per day in 2010, increasing to 1.13 billion cubic feet by 2014. “A billion cubic feet of daily pipeline capacity typically requires gas processing facilities worth a billion dollars,” says Grant Shomody, president of Grantech 20

N ovember 2 0 0 9 • O I L & G A S I N Q U I R E R

Engineering International. “Processing plants typically represent 15 per cent of total capital investment for a gas development. The rest goes for drilling, infrastructure, and so on. So we’re looking at more than $6 billion being spent in this play over the next five years or so.”

Grantech’s market research indicates that the following producers are planning to construct or expand gas plants in the Montney region of northeastern

B.C.: ARC Energy Trust, AltaGas Income Trust, Crew Energy Inc., Trident Resources Corp. (although this company has filed for Chapter 11 bankruptcy protection), Ramshorn Canada (a Nabors subsidiary), Birchcliff Energy Ltd., Advantage Oil & Gas Ltd., and a midstream producer. Another potential participant is Quicksilver Resources Inc. “Not all of these producers are necessarily committed to construction at this point but

Feature

$6B prospect

by Mike Byfield

Grantech International calculates that $1 billion in proposed capital spending on gas processing plants will generate about $6 billion in total spending.

engineering has begun in Calgary on their projects,” Shomody reports.

The Montney formation consists of tight sandstones, siltstones, and shale sequences. Nova, a subsidiar y of TransCanada, estimates that the Groundbirch drainage area contains 28.5 trillion cubic feet (tcf) of original Montney gas in place, yielding 6.8 tcf of marketable gas based on a 25 per cent recovery factor and four per cent shrinkage. According to

public estimates, there could be up to 318 tcf of original gas in place for the entire Montney formation in northeastern B.C., with estimated marketable volumes of up to 40 tcf.

For Shomody, the Montney prospect combines two professional passions— facility cost evaluation and technological innovation. His Calgary-based company offers an innovative software program that simulates the capital and operating

costs of oil and gas midstream facilities. “O&G Advisor applies sophisticated algorithms to our databases of historical and current costs, enabling us to come up with reliable project estimates within a small fraction of the time needed for traditional estimating methods,” the Grantech founder explains.

Last year, the consulting firm managed EPCM (engineering, procurement, construction, and management) services O I L & G A S I N Q U I R E R • N ovember 2 0 0 9

21

Feature

Photo: Grantech Engineering International

— Grant Shomody, President, Grantech Engineering International

for a major producer for a new gas plant in the Tomslake area—the largest capital project in B.C.’s oil and gas sector in 2008.

The facility has the capacity to process 80 MMcf per day of the area’s tight gas. “The plant came on stream within the client constrained capital budget set out by [O&G Advisor],” Shomody says. “It’s still too soon to determine how close we were on operating costs.”

Grantech also specializes in technical innovations for amine removal of acidic gases such as hydrogen sulphide (H 2S) and CO2, during natural gas processing.

For the Tomslake facility, Grantech’s engineers came up with a refinement of Shell’s SulFerox Process for H2S. But Shomody’s most intense enthusiasm is reserved for amine-related innovations targeting CO2.

At a single stroke, he argues, Montney producers can earn greenhouse credits and significantly reduce the cost of hydraulic fracturing wellbores.

Economic natural gas production from tight rock and shales is only possible through sequential fracturing of the reservoir rock along horizontal wellbores. The injection of fluids or gas under extremely high-pressure cracks open the reservoir formation, enabling gas to flow. In northeastern B.C., producers have experimented extensively with slick-water and CO2 fracs.

Slick-water fracs combine water with a friction-reducing chemical additive, which allows the water to be pumped faster into the formation. But Montney producers operating east of Dawson Creek are encountering technical issues with this 22

N ovember 2 0 0 9 • O I L & G A S I N Q U I R E R

technique, according to Shomody. “The wells decline quickly in pressure, and there may not be enough virgin gas pressure to force the slick-water up a 4,000metre vertical well column. At that point, you’ve killed the well,” he says.

Slick-water fracs generate other problems as well, in his view. “If this play develops as producers hope, the number of wells being drilled would severely tax local water resources. In that case, we can expect a lot of ecologically related criticism. There’s also the problem of disposing of the frac water or treating it for reuse. It’s expensive, and Montney producers have not installed water treatment capability at their plants.”

CO2 fracturing has reportedly yielded better frac results, but its use raises its own hurdles. Grantech says the price per tonne of CO2 has doubled within the past few years, mainly due to oilfield demand. “That price isn’t dropping despite the downturn in drilling activity,” Shomody adds.

Furthermore, the liquefied gas cannot be stored indefinitely because fresher CO2 is considered more effective for fracs, making it more difficult to stockpile.

Then there’s the problem of what to do with the injected CO2 after a hydraulic frac has occurred and the gas is surging out of the wellbore. In a “final well blow down,” Shomody says, “CO2 can make up 12 to 17 per cent of the well’s output for a month.”

TransCanada/Nova will not accept gas into its pipeline system with a CO2 content above two per cent.

“That carbon dioxide is contaminated with other gases so it can’t be simply

vented to atmosphere. Instead, operators mix the CO2 with propane and flare it,” the Grantech president explains. At night, the flaring lights up the area around Tomslake like a giant birthday cake, annoying neighbours. In addition, CO2 is a greenhouse gas, suspected of contributing significantly to man-made global warming. In response to that concern, Shomody says, the B.C. Oil and Gas Commission plans to drastically reduce CO2 flaring by natural gas producers.

Grantech is now pitching Montney producers with new CO2 recovery technology.

It can be implemented through adapting the existing amine systems in gas processing plants. The technology will extract both frac CO2 and the modest quantities of geologically sourced CO2 that flow naturally from the Montney formation. “Our technology will recover about 75 per cent of the frac CO2, which should reduce flaring to the guidelines being worked out by the B.C. Oil and Gas Commission,” Shomody says.

Grantech calculates that its new CO2 technology will achieve payout of capital cost within 12 to 18 months. The Calgarian strongly advocates regional cooperation between producers in the Montney region with respect to CO2. “That way, everyone will have access to a constant, affordable, and fresh supply of this gas for fracturing purposes,” Shomody comments. “The biggest producers could reach most of those goals independently. A regional strategy would yield larger benefits for smaller volume operators, but working together can achieve cost reductions for everyone.”

Photo: Grantech Engineering International

“ Our technology will recover about 75 per cent of the frac CO2 , which should reduce flaring to the guidelines being worked out by the B.C. Oil and Gas Commission.”

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British Columbia

Demand for more hydraulic frac sand spawns new mining developments

Photo: Stikine Gold Corp.

by Richard Macedo

In September, Stikine reported excellent intersections from its Nonda / Ghost Ridge quartzite project.

The drilling shift to more horizontal wells and multi-stage fracturing—a particularly large-scale development in British Columbia’s Horn River Basin—has sparked an urgent search for new sources of frac sand. At the head of the pack in this emerging play is Vancouver-based Stikine Gold Corporation, which has secured title over several silica claims in northeastern B.C. Exceptionally hard sand is used as a proppant to hold fractures open after hydraulic fracturing is applied to a wellbore. Because the Horn River basin is distant from traditional supply sources, it faces exceptionally high transportation costs for frac sand.

Kris Petterson, a completions engineer involved with Horn River operations for EnCana Corporation, says each well requires roughly 3,000 metric tonnes.

“We, along with other operators, have

all looked at self-sourcing,” he adds.

“The mine we’re currently pulling from is actually in…eastern Saskatchewan.

Historically, a lot of proppant comes from the central [United States].”

Petterson estimates that “anywhere in the patch that we use sand, almost

Stikine recently completed an initial field program at a number of its 100 per cent owned quartzite properties in northeastern B.C. to get an early assessment of its 17 properties, now totalling nearly 83,000 hectares of mineral claims covering prospective quartzite zones. The firm reports that several of the properties meet the criteria for raw silica suitable for frac sand.

As resource plays such as Horn River and the Montney to the south continue to develop, more sand will be needed.

Stikine estimates that in 2009, approximately 300,000 tonnes will be required in the Horn River Basin alone and that up to two million tonnes per year will be needed when the field is developed over the coming years. Costs for delivered frac sand have averaged roughly $300 per tonne this year, with an estimated 80 per cent of the current cost associated solely with shipping, handling, and logistics to the area, according to Stikine.

“What really struck us was when we heard about it…was the price that was being paid for frac sand delivered up north,” says Scott Broughton, Stikine’s president and CEO. “We had heard that a year-and-a-half ago, they were paying $450 a tonne delivered—this is to the

" Anywhere in the patch that we use sand, almost two-thirds of the cost of that product is transportation."

— Kris Petterson, Completions Engineer, EnCana Corporation

two-thirds of the cost of that product is transportation. Ideally we’d love…to find one in B.C. Stimulation, I’m going to say, is a solid 50 per cent of the entire well cost. Sand would be in the order of four or five or six per cent of the total well cost.”

well. When you do the math, it’s a massive market and much of it would be dollars just going simply to shipping if it came from…far-away sources.”

Broughton says the size of the market, the value of the material, and the longevity of the gas play “are the magic

BRITISH COLUMBIA WELL ACTIVITY

SEPT/08

SEPT/09

SEPT/08

SEPT/09

SEPT/08

SEPT/09

WELL LICENCES

334

154

WELLS SPUDDED

262

113

WELLS DRILLED

261

92

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • NOVEMBER 2009

25

British Columbia

26

NOVEMBER 2009 • OIL & GAS INQUIRER

Photo: Stikine Gold Corp.

ingredients for making a very profitable and exciting mine.” The focus of field activities for the company in June and July of this year was to locate and define raw quartzite sources near the shale gas fields. Work to date reportedly indicates that its Nonda, Beav, Crow, Pet, and Angus properties represent good opportunities to develop frac sand operations, subject to further tests.

Sampling and mapping at the Nonda property highlighted large-scale potential over an 11,500-metre by 1,000-metre area, Stikine says. Petrographic analysis of samples collected from Nonda indicate the rocks are very pure with up to 98 per cent quartz made up of variably sized grains that fall within the required range for commercial frac sand.

While the in situ quartzite samples from Nonda and Stikine’s other properties have generally angular grains, the company has completed preliminar y laborator y tests that indicate simple crushing, tumbling, and polishing can produce rounded silica sand grains in appropriate fractions, as required for commercial frac sands. Process development and laboratory trials are at an early stage but are continuing.

“What we were really happy to observe was that we can produce sand-sized particles with very little effort and without any black magic,” Broughton says. “We simply crush and go through a process of grinding to help to liberate those particles, those monocrystalline grains. That’s what the industry wants.”

However, it will take at least three years to be able to provide supply in commercial quantities, assuming a quick permitting process, community consultation, and taking into account the seasonal nature of the work. “We really have to be flying now with our exploration and define the resource and doing our…tests to prove up all of these concepts we have to be able to deliver full-scale production in three to four years,” Broughton says.

Rob Cox, VP of Canadian operations for Trican Well Service Limited, says a local source with the right specifications could lower costs. “Freight from mine to location can be a very significant component of the cost, but also the production cost of the mine itself is a big component as well,” he notes.

“The two of them work together. If you had an inexpensive or efficient mine that was close to location, that would be ideal.”

The quartzite outcrop at Stikine's Nonda / Ghost River property offers large-scale frac sand potential.

Trican has fraced for several companies in northeast B.C. While traditionally producers have relied on the suppliers for sand, some producers are now starting to arrange for their own delivery.

Getting sand from a mine to Fort Nelson from sources in Saskatchewan, Iowa, or elsewhere isn’t logistically difficult due to rail access.

“A number of mines produce the sand of the quality and the quantity that’s required up there,” Cox says. “Because it’s being pumped into deep formations, it typically has very high crush resistance.

Just as long as you’ve got the lead time, you can get it to Fort Nelson. Typically you’re looking at 15 days on the rail to get it from mine to Fort Nelson.

“If you’ve got a sizable project…you’d want to start ordering sand four to six weeks before you do a big project,” Cox says. “If it’s a one-off well, it’s going to be easier because there’s going to be typically some storage either in Fort Nelson or some sand already on rail cars en route in speculation that it’s going to be required.”

Victory Nickel Inc. says it has a viable new frac sand source within its proposed Minago open pit nickel project, located 225 kilometres south of Thompson, Manitoba. The Canadian mining firm reports a 15-million tonne “indicated sand resource” of which approximately 84 per cent is marketable frac sand.

This resource could be shipped to locations in Canada or south of the border, depending on economics. “We are right beside the highway and 60 kilometres away from the railroad,” says Victory Nickel spokesman Robin Cook. “Rail goes to the port of Churchill, so in theory, we could ship anywhere from there.”

The demand for high-quality frac sand should continue to expand given the development of unconventional resource plays such as the Montney and Horn River regions, the Barnett and Woodford in the United States, and new emerging plays such as the Marcellus shale in the eastern U.S. This could represent a significant new industry for Manitoba, according to Victory Nickel.

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Anniversary publication, STARS: 25 Years of Care in the Air. I want to invite you to join me in congratulating STARS and wishing stars the best for the next 25 years.

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Northwestern Alberta/Foothills

ERCB denies Penn West appeal of high-risk enforcement action

Following a pipeline crossing leak, the ERCB has moved aggressively to protect Alberta's rivers.

Penn West Petroleum Ltd. has lost its second appeal to the Alberta Energy Resources Conservation Board (ERCB) of High-Risk Enforcement Action 2 taken against it in relation to an April 2008 pipeline failure in the Mitsue area. In a ruling upholding the decision by a board enforcement advisor to deny the appeal, ERCB board member Michael Bruni found that actions and inactions on the part of Penn West contributed to its failure to prevent the pipeline failure that was the subject of the enforcement.

High-R isk Enforcement Action 2 (persistent non-compliance) is initiated against a licensee that has an unacceptable rate, ratio, percentage, or number of non-compliances, either in the same or in different compliance categories.

On Nov. 5, 2008, the board issued the enforcement action for unsatisfactory depth of cover and failure to conduct the

required right-of-way surveillance following an investigation by ERCB staff. After a meeting with Penn West, board staff rescinded the High-Risk Enforcement Action in relation to the right-of-way.

Penn West had acquired operatorship of the pipeline at 10-14-71-4W5 from

On Dec. 2, 2008, Penn West appealed the enforcement action to the ERCB corporate compliance branch, arguing that the depth of cover enforcement was not appropriate because at the time of construction the pipeline met the requirements. The company also said it did not have an opportunity to conduct right-ofway surveillance when the pipeline was not covered in snow. Penn West added that it conducted aerial surveillance of the field immediately after assuming operatorship from Canetic and identified no evidence of exposed pipeline.

In a decision dated March 9, 2009, Kevin Pilger, ERCB enforcement advisor, denied the appeal. He determined that licensees must maintain the minimum earth cover in accordance with CSA (Canadian Standards Association) Z66207 which he found to be a mandatory requirement that must be maintained for the life of the pipeline.

In appealing Pilger’s decision, Penn West submitted that the depth-of-cover requirement was not clearly prescribed.

It also said the enforcement action was unduly harsh in comparison to the June 2008 exposure of a pipeline operated

by Pembina Pipelines when the ERCB did not issue enforcement action as the

According to the ERCB, Penn West contributed to the pipeline failure by wrongly assuming that conducting depth-of-cover inspections within one year of assuming operatorship of the pipeline was adequate.

Canetic Resources Inc. in September 2007.

On April 8, 2008, the pipeline failed and released produced fluids into the Otauwau River as a result of ice in the river breaking up. The company responded to the incident and reported the failure was due to fatigue cracking of the metal adjacent to a girth weld. The pipeline was shut in as a result of the failure.

exposure was determined to be an “act of God.” In further submissions, Penn West argued that it did not have a reasonable opportunity to perform a water-crossing inspection or depth-of-cover survey or to contact a hydrologist, and that there was no indication of a depth-of-cover issue until the failure occurred in April 2008.

NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY

SEPT/08

SEPT/09

SEPT/08

SEPT/09

SEPT/08

SEPT/09

WELL LICENCES

334

154

WELLS SPUDDED

262

113

WELLS DRILLED

261

92

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • NOVEMBER 2009

29

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The ERCB ruled that Penn West's lack of information concerning acquired assets was not a defence.

The company said it had given special consideration to its pipelines in the area by increasing its right-of-way surveillance to weekly from annual patrols. It also asked the board to address the issue of inconsistent application of the regulations in light of its failure to take enforcement action in relation to the Pembina incident.

ERCB staff members responded that Penn West had adequate time in September and October 2007, when water levels normally would be lowest, to conduct watercrossing inspections to confirm depth of cover before the failure occurred. Staff also maintained that depth-of-cover requirements were clearly prescribed, including in the ERCB Directive 66, which outlines requirements and procedures for pipelines.

In his decision, Bruni said that Penn West contributed to the pipeline failure by wrongly assuming that conducting depth-of-cover inspections within one year of assuming operatorship of the pipeline was adequate.

“By its own admission, Penn West had no historical data, baseline, or benchmarking to determine the average snowfall or river characteristics,” he said.

“This strongly suggests it may have been prudent and advisable for Penn West to conduct depth-of-cover inspections much sooner than one year from assuming operatorship of the pipeline from Canetic,” said Bruni. “Any assumptions about the adequacy of inspections of facilities acquired from another operator in the absence of salient information about the pipelines and surrounding terrain were made at Penn West’s own risk.”

In his report, Bruni also dismissed Penn West’s position that the depthof-cover requirements are not clearly

Northwestern Alberta/Foothills

prescribed. “On the contrary, they are explicitly prescribed,” he said.

As for Penn West’s indications it has provided special consideration to the pipelines in the Mitsue field, given the number of pipelines with water crossings and the terrain in the area, “this is exactly what is expected of Penn West in the circumstances, especially where the facilities have been acquired from another operator and Penn West lacked information about the geography and the snow cover in the area,” said Bruni.

T he board member also considered the company’s submission that the enforcement action was unduly harsh given that the ERCB did not take enforcement action against Pembina in relation to its pipeline failure.

“Each incident is reviewed on its own facts and ERCB staff determination of whether enforcement action is warranted is made on a case-by-case basis,” said Bruni. “The failure of Penn West’s pipeline in this instance was reviewed on its facts, and ERCB staff concluded that the enforcement action was appropriate. The board member accepts this conclusion.”

In March of this year, the ERCB issued another High-Risk Enforcement 2 against Penn West, citing poor pipeline construction practices resulting in failure within one year of service/operation for a pipeline at 10-25-067-10W5 in the Municipal District of Big Lakes.

Operations were suspended, and the licensee repaired the pipeline and corrected the improper support of the pipeline.

Penn West provided a plan to address the non-compliance and prevent future occurrences, met with the ERCB to review its action plan, and compliance was achieved.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • NOVEMBER 2009

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PetroChina buys 60 per cent of Athabasca oilsands projects for $1.9B

SEPT/08

SEPT/09

SEPT/08

SEPT/09

WELLS SPUDDED

75

98

WELLS DRILLED

69

110

Photo: Lerindro Internasional

“AOSC therefore decided to look for joint venture partners, and these strategic joint venture arrangements with PetroChina, one of the world’s largest energy companies, can ensure that the MacKay River and Dover projects will be developed in a timely manner, which is excellent news for Alberta and the rest of Canada.”

Gallacher added that AOSC recently visited several of PetroChina’s oil facilities in northeastern China where PetroChina operates a number of heavy oil projects using sophisticated technologies, including various steam assisted gravity drainage (SAGD) processes and firefloods. “Their field developments, operational methods, heavyoil experience, and research facilities are world-class, and as a partner they will bring these very valuable attributes to the MacKay River and Dover projects in Alberta.”

As joint-venture partners, AOSC and PetroChina International intend to use

common in situ methods to develop their oilsands projects. AOSC has filed regulatory applications for approval of two pilot projects within the project areas with Alberta’s Energy Resources Conservation Board and intends to file a regulatory application for the first 35,000 barrel a day phase of the MacKay River commercial project at the end of 2009.

Privately held AOSC said the projects would ultimately see direct investment of $15 billion to $20 billion. Gallacher sa id h i s f i r m had ushered severa l interested parties, representing several countries, through its data rooms before striking a deal with PetroChina.

The state-owned company was chosen because of its financial strength and technical expertise in heav y oil and SAGD technology, he said.

If AOSC had any doubt about the pro­ gress the Chinese have made in oilsands and heavy oil, Gallacher said their doubts were resolved on a recent trip to China.

“We visited several CNPC [China National Petroleum Corp.] oilfields [and] I can tell you unequivocally that they’ve made great strides on their efficiencies and steam-oil ratios. They’ve [also] made great strides in different technologies to enhance SAGD and in situ technologies to further reduce the cost and impact,” he said.

Gallacher said the financing aspect “was a very important part of the deal….

I think it’s safe to say now that we have a fully funded business model, going forward.” Sveinung Svarte, AOSC president and CEO, described MacKay River and Dover as “early stage. We are planning pilot developments on both projects. On MacKay River, which is the first development, we are planning the first-phase commercial application by the end of this year.”

Svarte said the proposed project is very close to Petro-Canada’s MacKay

Athabasca Oil Sands says PetroChina brings sophisticated technology to its MacKay River project.

Athabasca Oil Sands Cor p. (AOSC) has entered into a series of agreements with PetroChina International Investment Company Limited (PetroChina International), a wholly owned sub­sidi­ ary of PetroChina Company Limited ( Pe t r o C h i n a), pu r s u a nt to w h ic h PetroChina will acquire a 60 per cent working interest in AOSC’s MacKay River and Dover oilsands projects for a consideration of $1.9 billion.

The Chinese purchase was announced on Aug. 31. The projects are located in the centre of the Athabasca area in northeastern Alberta and have been independently assessed to contain approximately five billion barrels of best case contingent bitumen resource.

“Oilsands projects are very capitalintensive long-term investments and difficult to fully finance in the traditional equity market,” said AOSC chairman Bill Gallacher.

NORTHEASTERN ALBERTA WELL ACTIVITY

SEPT/08

SEPT/09

WELL LICENCES

53

79

▲

▲

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • NOVEMBER 2009

35

Northeastern Alberta

River SAGD project, and appears to share similar geology. “It seems to be very similar—our rocks—and we can use the same technology and achieve the same kind of production rates. We’re planning a 35,000 barrel a day project there,” he added.

Start-up of commercial production at the project would be 2014, assuming all regulatory approvals, have been achieved by the end of 2011, he said.

Neither executive would discuss possible pipeline links or other means of moving the production when the joint venture project comes on stream. “It’s a bit early to talk about that,” said Svarte. “Obviously, first production will be in 2014, and a lot of things can happen by then. So far, the U.S. market is the base case for everyone. But of course, if there are other export routes opening up, we will look at them all, when we eventually get to that problem. But so far, there is nothing.”

AOSC has been building a position in the oilsands for some time. In October 2008, the company announced it had acquired a 50 per cent stake in a bitumen joint venture with an unnamed company.

That stake was in 750,000 acres on trend with Royal Dutch Shell plc’s holdings in

the western part of the Athabasca oilsands. Shell’s bitumen holdings are in carbonate rock, not the conventional sands from which bitumen is typically produced.

As part of the 2008 acquisition, AOSC gained leases on the bitumen carbonate trend at Dover West, later experiencing “very successful” drilling results, said Svarte. “We found up to 100 metres of very

deal, we probably have more than seven billion barrels recoverable [our share], and we will pursue those assets as if nothing had happened,” he said.

Long before the deal announced yesterday, PetroChina was rumoured to be looking for a bigger stake in Canada’s oilsands industry. Earlier this year, Total E&P Canada Ltd., a unit of French producer

“Even after this deal, we probably have more than seven billion barrels recoverable [our share], and we will pursue those assets as if nothing had happened.”

— Sveinung Svarte, President and CEO, Athabasca Oil Sands Corp.

nice, porous carbonate with bitumen saturation throughout.”

The drilling results galvanized AOSC’s interest in the as-yet uncommercialized carbonate, and the firm began to look for additional bitumen carbonate-bearing lands. “It’s the biggest heavy oil / bitumen carbonate play in the world, and we have basically tied up the remaining part of it,” Svarte said at the time.

In the conference call, Svarte said that aside from the two joint venture assets that make up the PetroChina deal, AOSC has many other assets. “Even after this

Total S.A., sold a 10 per cent stake in the Northern Lights Partnership to SinoCanada Petroleum Corporation, a subsidiary of China Petroleum & Chemical Corporation, also known as Sinopec. Before the deal, Total owned 60 per cent, while Sinopec owned 40 per cent of the project.

Commenting on the deal, Prime Minister Stephen Harper said Canada will apply existing foreign ownership laws to PetroChina’s bid to buy Canadian oilsands assets but will not introduce further barriers to investing in the country.

— DAILY OIL BULLETIN

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StatoilHydro plans to research and pilot new in situ technology through an extensive field testing and StatoilHydro will participate in a new The SOLVE project will include—in accompanying research and developfield research and pilot project to test addition to the field demonstration—a ment program. The expectation is that te c h nolog y t h at c ou ld p ote nt i a l ly research program that will be integrated it will lead to reduced water usage and reduce water usage and carbon dioxide with the demo results to reach clear con(C0 2) emissions at its Leismer in situ C02 emissions compared to conventional clusions about specific factors influencing oilsands project at Leismer in northsteam assisted gravity drainage (SAGD) solvent loss, oil production, energy use, eastern Alberta. technology. and water consumption.

The company believes the piloting of Su s t a i n able Te c h nolog y D e ve lThis is a unique approach to developopment Canada has awarded the SOLVE its steam-solvent co-injection (SCI) pro­ ing a new technology, bringing together ject (SOLVE) technology will demonstrate project $6 million to assist in the devela research consortium through the mana minimum 10 per cent savings on the opment and deployment of this techagement of PTRC. Research partners will steam-to-oil ratio required for extraction, nolog y to lessen the env ironmental include research councils and universities impacts of in situ oilsands extraction. with a potential savings of as much as 25 from both Saskatchewan and Alberta to “The PTRC’s past and current research per cent. help optimize the process for more wide“Reduction in the steam-to-oil ratio into solvent extraction technologies fits spread commercial use. perfectly with StatoilHydro’s innovative Several key milestones in the project has a direct effect on reducing water solvent co-injection at Leismer,” said are anticipated between early 2009 and use and C0 2 emissions since the solvent increases the amount of bitumen late 2011. These include the drilling of Dr. Carolyn Preston, the centre’s execuproduced per barrel of water and fuel tive director. co-injection well pairs at the demo site consumed,” said Åge Kristensen, VP of StatoilHydro’s solvent co-injection (completed in 2009), injecting of steam heavy oil research and development for SAGD process will be piloted at specific in early 2010, and co-injection beginning wells in the Leismer field approximately in the autumn of 2011.

StatoilHydro Canada Ltd. 150 kilometres south of Fort McMurray T h e c o m p a n y ’s p a r t n e r i s t h e Research modelling and simulations Petroleum Technology Research Centre to see if there are reduced environmental are already underway, and data collec(PTRC) in Regina, Sask. It will seek to impacts during extraction, and to optition, monitoring, and measurement will develop, optimize, and commercialmize the process for possible be on-going throughout the project. 8/25/2009 Oilsands, Oilweek, Oil & Gas Inquirer 7.0625w x 4.625h Colorapplication Advt 2009:Half Page Horizontal Advt.qxd i ze St atoi l Hyd ro’s new tec h nolog y to the entire field.

— DAILY OIL BULLETIN

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Alberta Oilsands preparing to file application for pilot project Alberta Oilsands Inc. expects to submit an application for a first phase 2,000 barrel per day pilot project to the Alberta Energy Resources Conservation Board (ERCB) before year-end. Pending successful results from the pilot, AOS expects to submit an expansion application for a 10,000 barrel per day full commercial project.

Two seasons of coring, three-dimensional (3-D) reservoir modelling, extensive cap rock studies, and an updated independent resource assessment suggest Clearwater West will meet the company’s high expectations, the company said in announcing its second quarter results. All indications reportedly confirm a high quality reservoir and a large quantity of bitumen.

During the second quarter of 2009, Alberta Oilsands placed 1 (0.5 net) Slave Point discovery well at Hamburg 13-29095-12W6 in the Ladyfern area on production April 1. The well produced a daily average of 1.4 million cubic feet of natural gas and 37 barrels of natural gas liquids net to the company for the second quarter. The well is eligible for Alberta’s new well royalty incentive program,

which provides for a five per cent royalty rate for gas production volume of up to 500 million cubic feet.

Alberta Oilsands produced an average of 325 barrels of oil equivalent (boe) per day from conventional assets during the second quarter of 2009 compared to 54 boe a day produced in the second quarter of 2008. This average production rate includes a 13-day period during which the Slave Point discovery well was shut in for a pressure build-up test.

Subsequent to the end of the second quarter, Alberta Oilsands announced an increase in the assigned contingent resources at its Clearwater West pro­ ject. The Ryder Scott Company of Canada resource report, effective June 1, 2009, estimated that Alberta Oilsands’ property contains 182.5 million barrels of contingent bitumen resources in a mid or “best estimate” scenario in a National Instrument 51-101 compliant evaluation. This represents an increase of 20.4 per cent over Ryder Scott’s previous assessment.

In the second quarter, the company signed a memorandum of understanding

with the Fort McMurray Regional Airport Commission to help ensure access to three sections of land adjacent to the airport. A definitive agreement was executed subsequent to the end of the quarter on July 8.

Alberta Oilsands believes that the agreement creates a strategic economic relationship of mutual benefit for both the company and the commission. The agreement provides for a two per cent gross overriding royalty to the commission on the oilsands rights held by Alberta Oilsands in sections 21 and 22 of 88-8W4. In addition, the company has agreed to grant the commission four million common share purchase warrants to purchase four million common shares of Alberta Oilsands at a weighted average price of $0.75 per share.

In exchange, the airport authority agreed to grant access to certain airport lands, provided that the company’s operations do not interfere with the safety or proper operation of the airport, and to work with Alberta Oilsands on planning and logistics of any operation on airport lands.

— DAILY OIL BULLETIN

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NOVEMBER 2009 • OIL & GAS INQUIRER

Central Alberta

Lower gas prices and bitumen production reduce Alberta’s revenue

Photo: Government of Alberta

by Richard Macedo

Alberta Finance Minister Iris Evans now projects the provincial deficit at a whopping $6.9 billion.

Alberta’s deficit is expected to grow by $2.2 billion from the original budget expectations thanks largely to weak natural gas prices, the provincial government revealed in its quarterly update. As of late August, the projected deficit rose to $6.9 billion from $4.7 billion predicted when the budget was tabled in April. The fiscal headache is coming from weaker nonrenewable resource revenue, which has fallen to $3.9 billion from the originally budgeted $5.9 billion.

After the budget was tabled in April, Finance Minister Iris Evans publicly mused about the possibility of easing Alberta’s dependence on oil and natural gas revenues with a different tax instrument, but Premier Ed Stelmach quickly quashed the idea of increasing taxes.

Pedro Antunes, director of national and provincial forecast for the Conference Board of Canada, said the question is difficult, but noted economists tend to

like the idea of a sales tax although he acknowledged it’s a tough sell politically.

“Consumer spending is a very stable component of the economy and it tends to be a good source of stable revenue,” he said.

Evans heaped most of the blame on sagging natural gas prices. Alberta’s main source of resource revenue comes from natural gas, but royalties are now forecast to hit $1.9 billion, $1.8 billion lower than the budget estimate and a far cry from 2005–06, a record year that produced $8.4 billion. “That’s most of it. That is really most of what’s different,” she said during a conference call. “What we’ve faced is a darkening on the clouds of the resource revenue.”

Natural gas forecast prices have now been lowered to an average of C$3.75 per gigajoule for the fiscal year that ends next March, a decrease of $1.75 from the budget estimate. The outlook for natural gas prices has deteriorated due to

depressed demand, increased production in the United States, and record inventory levels. The Alberta Reference Price has fallen steadily this year, averaging $3.99 so far during this calendar year to June 30.

Gas prices averaged $3.17 per gigajoule in the first fiscal quarter (April-June).

Total oil royalties are estimated at $1.9 billion, $333 million lower than the budget estimate. Despite the rise in oil prices, royalties from synthetic crude and bitumen have fallen thanks in part to lower production than originally estimated in the budget.

Conventional crude is now pegged at $1.3 billion, roughly $31 million higher than the budget, while the government has lowered its oilsands royalty expectation to $644 million compared to just over $1 billion when the budget was introduced.

Oil prices are currently forecast to average $61 per barrel over the fiscal year, up $5.50 per barrel from the budget estimate.

The impact on royalty revenue from the increase in prices is partially offset by the higher U.S./Canadian dollar exchange rate.

Revenue from bonuses and sales of Crown leases is forecast at $478 million, $153 million lower than budgeted due to lower land sales for conventional oil and gas and slightly lower prices per hectare sold. Drilling stimulus incentives are forecast at $590 million, down $252 million from budget as drilling activity has been slower than expected.

Evans continued to maintain that Alberta is in better shape than other jurisdictions in the country, particularly with the fact that the province is debt-free. “There is a reference that we might be returning to the [former premier Don Getty] years,” she said. “The Getty years dealt with debt.

We’re dealing with deficit and we’re dealing with it with a point of view that we are going to control that deficit.”

— DAILY OIL BULLETIN

CENTRAL ALBERTA WELL ACTIVITY

SEPT/08

SEPT/09

SEPT/08

SEPT/09

SEPT/08

SEPT/09

WELL LICENCES

327

273

WELLS SPUDDED

351

163

WELLS DRILLED

354

161

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • NOVEMBER 2009

41

Central Alberta

Culane expects waterflood at Killam to boost oil production Culane Energy Corp.’s second-quarter revenues plunged by two-thirds to $6.78 million from $21.98 million as production declined 42 per cent and prices received dropped precipitously from the second quarter of 2008. The junior producer hopes to revive its sagging oil production with a waterflood project at its Killam field in central Alberta, where it has invested over $100 million to build up its asset base.

It also plans to add a polymer surfactant to the waterflood to boost oil recovery.

In January, the company began injecting water at its Killam North waterflood pilot project through two injector wells drilled in 2008. The company is currently waiting for regulatory approval to commence its full-field waterflood program and plans to construct full-field waterflood facilities during the third quarter.

Culane’s net debt (bank debt less working capital) at June 30, 2009 was $11.4 million compared to $13.2 million at Dec. 31, 2008 and $18.3 million at June 30, 2008. The company was drawn to $13 million on its primary credit facility of $27 million at June 30, 2009.

During the second quarter of 2009, Culane said it continued its focus on government regulatory issues, reservoir engineering and facilities design for the Killam waterflood project, and debt reduction. On the regulatory front, Culane has been meeting with the regulator and is seeing progress towards attaining approval of four separate waterflood applications submitted earlier this year.

Culane anticipates receiving government approval for its full-field waterflood applications by late third quarter or early fourth quarter. It has commenced development of its water injection facilities as of mid-July. Lease preparation is almost complete, all pipelines have been surveyed, all major equipment has been procured, and the water injection project construction commenced on Aug. 24, including pipeline construction.

This project will involve central injection that will service all Culane lands in the Killam area. As previously announced, the expected completion date of the waterflood injection facilities is by the end of the third quarter and the project is on schedule, Culane said.

With the completion of the water injection facilities and government approval of its applications, Culane intends to increase water injection rates from approximately 1,250 up to 6,000 barrels per day, essentially recharging the reservoir by increasing the reservoir pressure and subsequently reversing the oil production decline that occurred during the primary production phase of the reservoir. This will be achieved through a combination of vertical well injectors and converted horizontal wells.

When Culane has replaced sufficient reservoir voidage and a clear increase in reservoir pressure and well fluid levels is observed, the company said it intends to introduce surfactant polymer to the waterflood. Existing pool analogies indicate that the addition of surfactant polymer has the potential to increase the oil recovery factor to in excess of 40 per cent.

Culane also said it will continue to evaluate strategic oil acquisition opportunities and expects a return to oil exploration drilling in the fourth quarter of 2009.

The company’s gross revenues were $13 million for the first six months of 2009

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42

NOVEMBER 2009 • OIL & GAS INQUIRER

Central Alberta

ERCB approves Petro-Reef downspacing

compared to $37.8 million for the first half of 2008, a 66 per cent decrease. This was due to a 37 per cent decrease in the company’s production for 2009 compared to the first half of 2008, and a 47 per cent decrease in commodity prices received in the two comparative periods.

Production averaged 1,592 barrels of oil equivalent per day for the first half of 2009 compared to 2,525 barrels of oil equivalent a day for the same period in 2008. Culane’s production mix is 72 per cent oil and 28 per cent natural gas.

Cash flow for 2009 was $5.7 million for the six months ended June 30, 2009, down from $21.8 million for the first half of 2008.

With the much reduced cash flow, Culane cut its capital spending to only $3.82 million this year from $35.28 million (including $21.38 million in property acquisitions) a year earlier. The company recorded a loss of $3.2 million for 2009, compared to earnings of $8.3 million in the first half of 2008.

Capital investments were spent on drilling and equipping of four water injection wells and tie-in and equipping of two gas wells at Killam and acquiring additional undeveloped lands in a new area of 94P 5 exploration.

122 19 6 THETLA ANDO A THETLA AN SOUTHDOA

PETITOT

Petro-Reef Resources Ltd. has received Alberta Energy and Resources Conservation Board approval for the downspacing of five sections where it has identified up to 25 development oil wells in its core area of Alexander, Alta. The property sits northwest of Edmonton.

With the downspacing approval, Petro-Reef has begun the approval process for three development oil locations in Alexander, each having additional highimpact natural gas exploration opportunities in other zones that will be tested.

These wells are in addition to the three

“ The approval of Petro-Reef’s downspacing application is a significant milestone for the corporation.”

— Ted Donhuysen, President and CEO, Petro-Reef Resources Ltd.

“ T h e ap p r o v a l of P e t r o - R e e f ’s downspacing application is a significant milestone for the corporation,” Ted Donhuysen, president and CEO of PetroReef, said in a news release. With a typical well producing between 50 and 100 barrels of oil equivalent per day and an average 80 per cent working interest in the lands approved for downspacing, the approval has significant upside, he said.

“Petro-Reef has the potential to triple 22 21 20 19with low-risk development production 18 17 16 15 14 13 12 11 10 9 8 7 6 oil locations.”

exploration locations that Petro-Reef intends to drill targeting a new highimpact on-trend prospect.

The company anticipated drilling its first exploration well by the end of September, with results anticipated by the middle to the end of October. Petro-Reef has an additional downspacing application to allow the drilling of up to 25 additional development oil wells in Alexander and anticipates receipt of approval in the coming weeks.

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Central Alberta

West Energy announces Mannville oil pool discovery West Energy Ltd. reports success with its recent shallow light oil drilling program in the Crossfire area of Alberta. A best estimate value of 8.3 million barrels of discovered petroleum initially in place has been determined by GLJ Petroleum Consultants Ltd. West Energy estimates that three million barrels of oil are recoverable on a primary and secondary basis.

Four 1,800-metre wells were drilled in the company’s Mannville program, resulting in the identification and initial delineation of an undersaturated sweet light oil pool. The pool size has been established by material balance calculations using pressures obtain from the discovery and delineation wells.

This pool size has additionally been confirmed using volumetric calculations.

T he discover y wel l dr i l led last September at 02/11-3-50 - 6W5 targeted bypassed pay identified on logs while drilling a Nisku water injection well at the same location. Since January this Mannville well has produced at a restricted maximum rate limitation of 60 barrels per day of oil with no water and minor associated sweet gas.

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West has applied to t he Energ y Re s ou r c e s C on s e r v at ion B oa r d to increase the discovery well’s maximum allowable production to 125 barrels a day, which is below its estimated capability of 200 barrels per day. Further production increases are expected upon approval of

used as a water source well for the waterflood project.

Three additional Mannville vertical wells will be drilled in the new pool during the next four months. West has extensive 3-D seismic data covering its 148,000 gross acres of land holdings in

Three additional Mannville vertical wells will be drilled in the new pool during the next four months.

a Good Production Practice application and implementation of a waterflood project for the pool.

Recently West Energy drilled three delineation wells to determine the size of the pool. The well at 15-3-50-6W5 tested at 150 barrels per day and is tied in and producing to West’s Crossfire oil battery.

The well at 6-3-50-6W5 was successfully completed in the Mannville zone and may be used as a water injection well.

The fourth well at 7-03-50-6W5 did not encounter the Mannville sand and can be

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the Pembina area. An additional five sections of prospective Mannville lands were acquired along a similar seismic trend.

West Energ y believes part of its Crossfire lands have Cardium oil resource potential and has spudded its first horizontal Cardium oil test well. The economics of the emerging Cardium resource play are enhanced by the company’s Alberta Crown royalty drilling credits. The company plans to drill at least four horizontal Cardium oil wells in the area by year-end.

— DAILY OIL BULLETIN

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Southern Alberta

Access to capital clinched EnCana’s decision to split in two

Photo: EnCana Corporation

by Lynda Harrison

Even after EnCana divides, both new companies will rank among Canada’s top 10 petroleum producers.

Since shelving its plans last fall to divide into two, EnCana Corporation’s debt is now lower, access to capital is better, operations have improved, and the company has received confirmation that the $3.5-billion transaction will not be taxable. On Sept. 11, the company cited these reasons, along with higher oil prices, as key factors in its decision to revive its plans to create two separate companies.

The company announced on Sept. 10 that it plans to split into an EnCana gas company and Cenovus Energy Inc., which will hold its oil and downstream operations plus some gas assets. The division procedure is scheduled to close by Nov. 30.

“Access to debt and availability of debt at a reasonable prices was really the clincher for us,” Randy Eresman, president and CEO, told a telephone conference call. “Without that, we could not have proceeded. It was really the number one item that prevented

us from going forward with the transaction when we stopped it last fall.”

While oil prices have rebounded, gas prices have been challenging. EnCana

long-term NYMEX gas price of $6 to $7, he said.

The two new companies will separately still rank among the top 10 Canadian producers. The new EnCana gas company is expected to have an average 2009 production of 496,000 barrels of oil equivalent per day and Cenovus is forecasted to have an average production of 248,000 barrels of oil equivalent per day.

The new EnCana will have about 3,800 employees with an estimated 2009 operating cash flow of US$6 billion, while Cenovus will have around 2,200 employees and an estimated operating cash flow of US$3.5 billion.

EnCana first announced the proposed corporate reorganization on May 11, 2008, and was advancing plans for the split last fall when the global debt and equity markets experienced unprecedented turmoil and volatility. Given that uncertainty, EnCana decided to delay until clear signs of stability returned to the financial markets.

“While natural gas prices are currently low, we have reduced our near-term commodity price risk by hedging a significant

“ Over the longer term, we believe the current low natural gas prices are not sustainable, and we expect a recovery in prices in 2010.”

— Randy Eresman, President and CEO, EnCana Corporation

believes the market is at the bottom, but it expects to see soft prices through this year and into 2010, said Eresman.

T ha n k s to t he abunda nce of sha le gas, the company is now forecasting a

portion of our expected production for the 2009–10 gas year,” Eresman said. “Over the longer term, we believe the current low natural gas prices are not sustainable, and we expect a recovery in prices in 2010.”

SOUTHERN ALBERTA WELL ACTIVITY

SEPT/08

SEPT/09

SEPT/08

SEPT/09

SEPT/08

SEPT/09

WELL LICENCES

520

246

WELLS SPUDDED

403

130

WELLS DRILLED

391

134

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • N ovember 2 0 0 9

47

Southern Alberta In addition, the financial and operational strength of each company’s asset base has improved during the past year, Eresman said. Additional drilling in the company’s natural gas shale plays has advanced its understanding of its “enormous potential and increased our confidence in our ability to grow these prolific new natural gas supplies from the Montney, Horn River, and Haynesville plays,” said Eresman.

With the start-up of two new phases at Foster Creek and continued production increases from Christina Lake, gross production from these enhanced oil recovery projects now exceeds 100,000 barrels per day, a significant milestone in the longterm oil growth plan for the assets that will be transferred to Cenovus.

Construction of the coker and refinery expansion (CORE) project at the Wood River refinery in the United States is past the midpoint. It is on time and on budget, and is expected to start up expanded capacity in early 2011.

EnCana’s debt at Aug. 31 was about $8.2 billion, down about 19 per cent from when the company first announced its plan to split, Eresman noted.

— DAILY OIL BULLETIN

Oilpatch said to face positive “perfect storm” for recovery in 2011 While this year is a bust for the oil and gas industry, low utilization and low prices are simply putting everything in place for recovery to occur—but not until 2011, an industry audience heard on Sept. 23. The Canadian industry will pick up first, followed by activity in the United States, and finally internationally, Richard Spears, an oilfield market researcher, told a breakfast meeting in Calgary.

“The math is telling us it’s improving, so it’s okay to come out from hiding and go back to work again,” Spears argued.

“We’re setting up for a situation that in 2009 and 2010, throughout North America if you’re an E&P [exploration and production] company it’s almost a perfect storm, in a good way, whereas for the last year it’s been a perfect storm in a bad way.”

Spea r s i s ma nag i ng di rec tor of Spears & Associates, an oilfield market research firm based in Tulsa, Oklahoma. “ T he re w i l l b e ple nt y of c apac it y throughout the industr y, of drilling

contractors and pump trucks and wire line units and well servicing rigs, and a pricing structure which is significantly lower than it has been for quite some time, and you have a commodity price which is beginning to actually improve,” he said. “When you take all those into consideration, incentives to drill become very favourable.”

Capital funding started to flow last spring after nearly a year of limited access and while that has not yet translated into a lot of activity, “the money guys are sitting up and paying attention,” said Spears. Worldwide, oil is already starting to recover, while natural gas drilling will be “not too bad” by next summer, when storage will be “burned off ” and liquefied natural gas will continue to avoid North American shores, Spears said.

The analyst got a mixed response when he asked his audience for its forecast of upcoming winter drilling activity. “We think there will be more oil because that’s

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Southern Alberta what everyone is targeting, but natural gas is going to be down,” said Dan Themig, president of Packers Plus Energy Services Inc., sponsors of the event.

Although drill ships are being built, Spears noted that the land rig construction business has stopped completely and the rig equipment market will continue to fall for several years, said Spears. He’s a director and owner of UniversalPegasus International, a pipeline and offshore engineering company; Varel International, a drill bit manufacturer; and Federal, a supplier of couplings for pipelines and sub-sea applications.

The industry is already seeing indicators of lower costs. Worldwide land drilling, with a huge contribution from Canada and the U.S., was a $25 billion market in 2008, which fell to $16 billion to $17 billion this year, partly due to lower activity but largely because of contract drillers’ price def lation, Spears said.

Pressure pumping, last year a $25 billion market and this year a $16 billion or $17 billion market, will see a return to growth next year, Spears predicted. He noted that Calgar y-based Trican Well Ser vice Ltd. and Calfrac

Well Services Ltd. are now the number four and five pressure-pumping companies in the world, and their management teams are his personal favourites among all pressure pumpers. “I would say that wherever they go they will most likely succeed.”

Spears estimated that 30,000 gas wells were drilled and completed in the U.S. in 2008. This year, 15,000 will be drilled, but only 12,000 will be completed. This “remarkable change” is now “hammering” the completion, fracturing, and wireline industries in Canada and the U.S.; however, it is also creating an inventory of wells that can quickly be brought online, he said.

The completion equipment sector has experienced less price inf lation than others since it’s more of a product than a service and has fared better than other services, said Spears, who began his 30-year career in the upstream oil and gas industry as a field engineer for Halliburton Co. Directional drilling, measurementwhile-drilling, and logging-while-drilling took “a bit of a hiccup” this year, he said.

“But when you start drilling all your wells directionally, it does remarkable things for

that sector.” He’s convinced that 10 years from now, rotary steerable will be the only drilling technology available for directional drilling.

The downhole tools sector is “taking it on the chin” this year, but the hardest hit has been well servicing, whose market has been sliced in two, putting it in a very tough financial situation, said Spears. The rental compression business, a huge market outside Canada, also has seen an incredible drop-off in revenues over the past three or four quarters as a result of what’s happening in the U.S., he said.

Latin America is becoming known for integrated project management, the audience heard. According to Spears, 55 per cent of Schlumberger Ltd.’s revenues this year will come from working for national oil companies and much of that is coming from integrated project management. In contrast, work for U.S. majors has been flat for the past five or six years. “If you’re not paying attention to what’s going on in integrated project management projects in Mexico and all the other international oil companies, you’re missing the boat,” he advised.

— DAILY OIL BULLETIN

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50

N ovember 2 0 0 9 • O I L & G A S I N Q U I R E R

Saskatchewan

Crescent Point moves into lead on Lower Shaunavon oil play

Photo: Brian Zinchuk, Pipeline News

deal, Crescent Point will control a total of 259 net sections in the strategic core of the Lower Shaunavon resource play, including 44 net sections Crescent Point presently manages on behalf of Shelter Bay Energy Inc. The company estimates that this land base contains approximately 1.8 billion barrels of estimated original oil in place.

Crescent Point also announced that it has closed one agreement and entered into a second agreement to acquire producing assets in southeastern and southwestern Saskatchewan for consideration of approximately $258.5 million of cash from Provident Energy Trust. The assets produce approximately 3,750 barrels of oil equivalent (boe) a day, 73 per cent of which is light and medium crude oil, including 450 boe per day in the southeastern Saskatchewan Bakken light oil resource play.

The company also announced a $100 million increase to its 2009 capital spending plans, increasing planned capital expenditures to $325 million. The increase

in planned spending is expected to be directed towards the company’s Bakken and Lower Shaunavon resource plays, including the funding of additional drilling and facilities expansion.

Under the terms of the asset acquisitions, Crescent Point expects to acquire the assets for combined consideration of approximately $258.5 million of cash. The assets produce approximately 3,750 boe a day, comprised of approximately 2,750 boe per day of high-quality, southeastern Saskatchewan production and 1,000 boe per day of high-quality, long-life southwestern Saskatchewan production.

The southeastern Saskatchewan assets are largely adjacent to and contiguous with existing Crescent Point assets in southeastern Saskatchewan, including in the Bakken resource play. The southwestern Saskatchewan assets are largely adjacent to and contiguous with Crescent Point assets in the Lower Shaunavon resource play.

On a combined basis, reserves associated with the asset acquisitions are approximately 11.1 million boe of proved-plus-probable and 7.3 million boe of proved reserves.

Assuming the successful completions of the Wave arrangement and the asset acquisitions and the increase in the company’s planned 2009 spending, Crescent Point said it is increasing its year-end production guidance by 16 per cent to 51,500 boe a day.

In addition, the company announced that it has entered into an agreement, on a bought deal basis, with a syndicate of underwriters for an offering of 5.8 million Crescent Point shares at $34.50 per Crescent Point share to raise gross proceeds of approximately $200 million. Closing of the financing is not subject to the successful completions of the transactions.

“The Lower Shaunavon has rapidly evolved into another world class resource play for Saskatchewan and we are proud to have built the largest land position in

Crescent Point paid $665 million for Wave Energy, acquiring land with a billion-barrel potential.

Crescent Point Energy Corp. has agreed to buy Wave Energy Ltd. for $665 million.

Wave currently has the largest land position in the Lower Shaunavon resource play in southwestern Saskatchewan, with more than 150 net sections of land and access to original oil in place estimated by the company at more than one billion net barrels.

“Wave has done a tremendous job of capturing and developing the premier position in the emerging Lower Shaunavon play,” said Scott Saxberg, president and CEO of Crescent Point. “The Lower Shaunavon today is in the same stage of development as the Bakken was three years ago, when we acquired Mission Oil & Gas Inc. Wave has a first mover advantage in the Lower Shaunavon in the same way that Mission had in the Bakken.”

Under the terms of the arrangement, Wave shareholders will receive 0.21 of a Crescent Point share for each Wave share.

With the successful completion of the Wave SASKATCHEWAN WELL ACTIVITY

SEPT/08

SEPT/09

SEPT/08

SEPT/09

SEPT/08

SEPT/09

WELL LICENCES

502

205

WELLS SPUDDED

561

168

WELLS DRILLED

551

182

Source: Daily Oil Bulletin

O I L & G A S I N Q U I R E R • N ovember 2 0 0 9

51

Saskatchewan the play,” said Wave president Don Rae. “Wave has applied a disciplined approach to production and reser ves growth, aggressively employed emerging drilling and completion technologies, and conservatively managed its balance sheet.”

Daily Oil Bulletin records show Wave, as operator, has drilled 48 wells in Saskatchewan since the beginning of 2008.

Wave has 474 net internally identified lowrisk drilling locations, including 369 net in the Lower Shaunavon play at a drilling density of four wells per section. Its current production is approximately 3,000 boe a day, comprised of 87 per cent high-quality, longlife Lower Shaunavon medium-gravity oil.

It has tax pools estimated at more than $176 million and operating costs of approximately $13.50 per boe. Independent engineers have assigned approximately 17.6 million boe of proved-plus-probable and 8.7 million boe of proved reserves to Wave. Its reserve life index is 16.1 years proved-plusprobable and 7.9 years for proved.

Wave’s land holdings also include approximately 65 net sections of land in the emerging Dodsland Viking light oil play in west-central Saskatchewan and more than 500 sections of undeveloped land in Montana. The arrangement is

subject to Wave shareholder approval, court approval, and other conditions typical of transactions of this nature.

The board of directors of Wave has unanimously approved the arrangement and recommended that holders of Wave shares vote in favour of the transactions.

Holders of Wave shares representing more than 38 per cent of Wave’s issued and outstanding shares have signed hard lockup agreements and have agreed to tender their Wave shares to the arrangement.

Based on the above expectations for the transactions, and after adjusting for estimated land and seismic value of $320 million, the combined estimated acquisition metrics show an acquisition cost of $89,451 per producing boe based on 6,750 boe a day and $21.04 per proved-plusprobable boe ($37.74 per proved boe).

With the successful completions of the transactions, Crescent Point expects to have an extensive low-risk development drilling inventory of more than 4,400 net locations, representing approximately $7 billion of future development projects.

Approximately $42 million of Crescent Point’s $100-million increase in capital expenditures is expected to be directed towards incremental drilling, principally in

the Bakken and Lower Shaunavon resource plays. Crescent Point expects to participate in the drilling of 155 (124.8 net) wells, including 87.5 net horizontal wells in the Bakken resource play and 14.6 net horizontal wells in the Lower Shaunavon play. This represents an increase of 42.5 net wells from the company’s previous capital expenditures budget.

The remainder of the increase in spending, $58 million, is expected to be directed towards facilities infrastructure, land, and seismic. Incremental infrastructure investments are expected to include centralized facilities and gathering systems for the Lower Shaunavon play, and additional batteries and gathering systems for the Bakken play, which will provide capacity for future production growth.

Provident said its proceeds from the asset sale will be reinvested in high-impact growth initiatives in both its upstream and midstream business units. In the short term, the funds will be applied to Provident’s revolving term credit facility.

Provident said it will also continue the disposition process for the remaining heavy oil assets in the Lloydminster operating area as announced on Aug. 13, 2009.

— DAILY OIL BULLETIN

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N ovember 2 0 0 9 • O I L & G A S I N Q U I R E R

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Federal agencies focus on alleged dumping of Chinese tubular goods

by James Mahony

Chinese steel goods importers say a tariff would hike costs for Canadian oil and gas producers.

In a preliminary finding announced in early September, the Canada Border Services Agency (CBSA) found a “reasonable indication” that some oil country tubular goods (OCTG) coming to Canada from China are being dumped, and injuring or threatening to injure Canada’s domestic OCTG producers.

According to company and Statistics Canada figures, China’s state-owned steel producers doubled their share of Canada’s domestic OCTG market between 2006 and 2008, and now account for nearly 70 per cent of Canada’s OCTG imports.

T h ree compa n ies — represent i ng nearly all Canadian-made OCTG—have complained that mainland China’s steel producers were dumping subsidized OCT goods on the Canadian market, hurting Canadian steel-makers in the process. The four complainants are Tenaris Canada, Evraz Inc., NA Canada, and Ontario-based Lakeside Steel Corporation.

Under CBSA rules, selling imported goods in Canada at prices below what they would command in the country of origin is considered dumping. The CBSA’s finding in September was preliminary, but its investigation will continue pending a final

decision on whether Chinese OCTG have been subsidized and dumped in Canada.

The CBSA investigation is one part of a two-track process that also includes the Canadian International Trade Tribunal (CITT). In August, the CITT announced it would conduct a parallel inquiry into allegations against the Chinese companies. Its hearing will review whether and to what extent Chinese OCTG imports are harming Canadian steel producers. If the CITT finds an injury to Canadian producers, it may impose anti-dumping duties in proportion to the harm done.

The CITT has ruled against China before. In March 2008, the agency ruled that certain subsidized and dumped OCT goods from China threatened to cause injury to Canada’s domestic steel industry (although no finding of injury was made).

In that case, the product was seamless, steel well-casing, and the CITT imposed an anti-dumping duty against the Chinese goods in the interim.

In the case currently before the CBSA and the CITT, the Chinese goods in question are different. Instead of seamless well casing, the current case deals with steel tubing, including production tubing

and welded steel well casing with outer dia­meters between 2 3/8 inches and 13 3/8 inches, not including drill pipe.

A ruling against Chinese imports would hurt Canadian distributors of Chinese production tubing and casing. Cantak Corporation is one such company, getting much of its product from abroad. Its president Allan Cheng does not expect a favourable outcome. “Based on the way the tribunal looks at things, they’ll probably rule against them in this case as well,” he said.

Cheng believes imposing duties will boost steel prices for oil and gas produ­ cers. “By artificially increasing the price of steel, you’re hurting Canadian industries and the oilpatch by making them pay more than their counterparts in another country. That may make them less competitive globally,” he said.

Equally important, in his view, new duties could affect the supply of OCTG in Canada. “Last year, when the CITT made its ruling on seamless steel casing, the result was a shortage of product in the Canadian oil and gas market,” Cheng said. “Domestic steel mills could not supply the market. Later, we saw a dramatic increase in the market price for tubulars because the Chinese weren’t as free to come into [Canada].”

The United States and the European Union have also been investigating Chinese steel imports, and in the U.S. especially, the process has gone beyond investigation.

Chinese steel tubing and casing, for example, have been subject to more than one ruling by the U.S. International Trade Commission (ITC), which began investigating in May on grounds that there was a “reasonable indication” that Chinese OCTG imports threatened the U.S. domestic industry.

As in Canada, the U.S. process for imposing anti-dumping duties is twostage, involving the ITC and the U.S. Department of Commerce, each of which will conduct separate investigations.

Recently, Commerce made a preliminary decision that several Chinese makers of certain OCT goods were subsidized. Any anti-dumping duty will require months of further procedures to assess and impose.

— DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • N ovember 2 0 0 9

55

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Photo: Pennsylvania Department of Environmental Protection

Enerplus commits US$406M to acquire stake in Marcellus shale play

Enerplus Resources says the Marcellus play is one of North America’s premier shale gas developments.

Enerplus Resources Fund has entered into agreements with three private natural gas producers—Chief Oil & Gas LLC, Chief Exploration & Development LLC, and a limited partnership managed by Tug Hill, Inc. (collectively “Chief”)—to acquire 30 per cent of their interests in the Marcellus shale natural gas resource play in the northeastern United States.

Total consideration for the acquisition is US$406 million (approximately $3,500 per net acre) comprised of $162.4 million in cash to be paid upon closing and $243.6 million to be paid as a carry of 50 per cent of Chief’s future drilling and completion costs in the Marcellus shale play, which Enerplus expects will be invested over the next four years.

Chief currently owns an average 72 per cent working interest in approximately 540,000 gross acres, the majority of which is located in Pennsylvania within the heart of the Marcellus shale gas play. Upon completion of the acquisition, Enerplus will own an average 21.5 per cent nonoperated working interest in this acreage (approximately 116,000 net acres).

This land is concentrated in the northeastern and southwestern areas of

Pennsylvania, with additional acreage in West Virginia and Maryland. Much of the acreage is contiguous with an average primary lease term of approximately five years. As well, the majority of the leases allow extensions of the primary term for an additional five years.

As part of the transaction, Enerplus will also enter into Area of Mutual Interest (AMI) agreements with Chief that will allow the fund the opportunity to partner on any follow-on acquisitions or swaps in the Marcellus play. These AMIs will provide Enerplus with the opportunity to jointly acquire more land under the current ownership structure, as well as the potential to increase its working interest ownership and possibly operate in certain new areas.

“This transaction is a significant step in high-grading our asset base to provide greater growth potential and further improve our operating performance,” said Gordon Kerr, president and CEO. “Enerplus has gained an entry point into one of the premier shale gas resource plays in North America, consistent with our strategic direction, with an experienced partner who has a proven track record in shale gas development. With the play in the

early stages of development, we believe there is tremendous opportunity for future production, reserves, and value growth.”

In conjunction with the acquisition, Enerplus has agreed to issue 9.25 million trust units through a Canadian bought deal financing at a price of C$21.65 per trust unit for gross proceeds of $200 million. A portion of the net proceeds are expected to be used to pay for the upfront cash portion of the acquisition and the remainder will initially be used to repay bank debt and subsequently used to fund a portion of Enerplus’s ongoing capital expenditures.

The Marcellus shale is the largest unconventional natural gas resource play in North America according to an April 2009 report prepared for the U.S. Department of Energy (USDE). Spanning six states in the northeastern U.S., the play covers an estimated 95,000 square miles. Given the much larger aerial extent of this play compared to the other shale gas plays, according to the USDE report, the Marcellus play has the highest estimate of original gas in place of up to 1,500 trillion cubic feet and approximately 262 trillion cubic feet of technically recoverable resource.

Based upon the current development plans, Enerplus would participate in the drilling of approximately 750 gross wells over the next five years and production volumes are expected to increase to approximately 100 million cubic feet equivalent per day of natural gas to Enerplus before royalties over that period.

Enerplus has conducted an internal evaluation of the leases in accordance with NI 51-101 and has determined a best estimate of contingent resources of approximately 1.4 trillion cubic feet equivalent of natural gas applicable to its working interest effective July 1, 2009. This estimate is based upon a drilling density of four to six wells per 640 acre spacing which would result in over 2,400 gross wells.

A lt hough Ener plus believes t he Marcellus natural gas formation is present over the entire acreage block, its best estimate assumes only 55 per cent of the land is developed.

— DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • N ovember 2 0 0 9

57

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N ovember 2 0 0 9 • O I L & G A S I N Q U I R E R

DW006-Nov 101-F09 OGI (1/3 page) 4.62” x 4.62” Black plus 1 colour White background Material deadline: Oct 06, 2009-NOON Insertion Date: Nov 2009

While some economists have declared the recession over, the painful recovery is expected to drag well into 2010.

JuneWarren-Nickle’s Energy Group’s new Recession to Recovery initiative will help you navigate these uncertain times.

We’re increasing our editorial content with stories and columns focusing on how companies are handling the downturn, preparing for the rebound, and, in some cases, even thriving. They’ll be easy to find. Just look for the special Recession to Recovery logo in each issue of Oil & Gas Inquirer.

On the Job

g a n i look for

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JOB Careers in the Oilpatch

Photo: Aaron Parker

Robert Hinchey Age:

59

When were you laid off?

Training:

CNC machinist, counsellor

About a month ago. Stream-Flo is a fine company but they were forced

Company: Unemployed

to let a lot of employees go—including some highly experienced hands— when the natural gas industry slowed down. It’s really tough out there now in this trade. A lot of Albertans don’t realise how many jobs are dependent

What do you like about being a machinist?

on natural gas in this province. Our economy is not just about oilsands.

I’ve always enjoyed physical operations that proceed in a logical sequence, back to doing summer work as a carpenter and cabinet maker when I was

How do you go about searching for work?

young. Machines are so very different than people. I spent quite a few

Well, as they say, now my job is looking for a job. I keep at it every day.

years as a pro-life counsellor in Toronto—helping women became a voca-

I stay in touch with friends and I contact potential employers. The fed-

tion for me but the unpredictability of counselling can become very stress-

eral and provincial employment offices are a huge help. There you have

ful. The precision and predictability of machining steel appeals to me.

access to a telephone, fax, word processing, seminars in resume writing, online job banks, even retraining programs. Although I’d prefer to stay in

What’s your personal and professional background?

my trade, I’m also willing to consider branching out.

I grew up in New Waterford on Cape Breton Island, where my father was a lawyer. After high school, I earned a bachelor degree in literature and

Psychologically, as a former counsellor and as an older worker, how

psychology at St. Francis Xavier University. Like many Maritimers, I

do you advise coping with the emotional stress of unemployment?

moved to Toronto where I worked as an insurance underwriter. For many

I bear in mind that I’m pretty accomplished for a machinist of my ex-

years, I also counselled for Aid To Women, initially as a volunteer and

perience, that I’m worth hiring. Forty weeks of employment insurance

later for a salary. In 2005 I came to Alberta and received training on

eligibility is important to me, of course. To make up for the loss of family

manual and CNC (computer numerical controlled) lathes at NAIT. For

income, my wife is doing 1.5 jobs—I make a point of doing more household

Weatherford CPS, I operated a Seiki CNC turning centre. Later, at Stream-

chores. Earlier in my life, I experienced fear when I was out of work. Now

Flo Industries, I worked with a Takisawa TC-350 turning centre and fur-

I’ve learned to trust God. That’s not necessarily an easy lesson to learn

thered my education in the trade, including working with programming.

but faith can heal fear.

OIL & GAS INQUIRER • NOVEMBER 2009

59

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WHAT OUR READERS SAY:

57% place their copy of the magazine in a common area for others to read 32% pass it along to a colleague 33% save it for future reference

2008 independent readership survey conducted by Leger Marketing.

60

NOVEMBER 2009 • OIL & GAS INQUIRER

Rig Talk

A LOOK AT NEW DRILLING TECHNOLOGIES

SpiderPlow

What is SpiderPlow Services Inc.?

Founded in 2005, SpiderPlow Services Inc. is a privately owned company headquartered in Calgary, which provides highly specialized pipe installation services across North America. SpiderPlow owns and operates the only North American fleet of German-engineered Fockersperger pipe-plowing equipment.

Describe the SpiderPlow system.

We operate the world’s most advanced technology for installing flexible pipelines, fibre optic cable, or power cable. The system consists of two purpose-built machines. The SpiderPlow itself rips open a narrow channel and continuously lays flexible pipe or cable into that channel. The system’s “muscle” is provided by a winch crawler, a special tracked vehicle designed solely to winch the SpiderPlow forward with massive power.

What are the competitive advantages of this equipment?

The SpiderPlow system is extremely fast, installing up to five kilometres per day. Ground disturbance is minimal. The equipment operates in a wide range of ground conditions and topographies. Pipe diameter can be as large as 20 inches, the cover up to 8.5 feet deep. Reliability and consistency are excellent, thanks to a full fleet and experienced crew. Altogether, the client benefits from excellent installation economics.

What are the market conditions and outlook for SpiderPlow?

Photos: SpiderPlow Services Inc.

Oil and gas has been our primary industry but we’re seeing growth in the water, fibre optics, power and geothermal sectors. In North America, our company has customers in Alberta, Saskatchewan, Manitoba, and Ontario, as well as most eastern and central states. We anticipate further expansion in the continental U.S., and opportunities are currently being assessed in Mexico and Australia.

Answered by Allan Fowler, president and CEO, SpiderPlow Services Inc.

OIL & GAS INQUIRER • NOVEMBER 2009

61

Political Cartoon

Advertisers' Index 1174365 Alberta Ltd . . . . . . . . . . . . . . . . . . . . . . 39 Aggreko LLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 AGI-Envirotank . . . . . . . . . . . . . . . . . . . . . . . . . 39 All Weather Shelters Inc . . . . . . . . . . . . . . . . . . 31 Altronic Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Annugas Compression Consulting Ltd . . . . . . . 19 Bear Slashing Ltd . . . . . . . . . . . . . . . . . . . . . . . 39 Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . 60 Bilton Welding and Manufacturing Ltd . . . . . . . 60 Brews Supply Ltd. . . . . . . . . . . . . . . . . . . . . . . . 23 Brother’s Specialized Coating Systems Ltd . . . 10 Canadian Enviro-Tub Inc . . . . . . . . . . . . . . . . . . . 7 CJS Coiled Tubing Supply . . . . . . . . . . . . . . . . . . 11 Compact Compression Inc . . . . . . . . . . . . . . . . 46 Compass Bending Ltd . . . . . . . . . . . . . . . . . . . . 58 Contain Enviro Services Ltd . . . Inside back cover Crimtech Services Ltd . . . . . . . . . . . . . . . . . . . 52 Crompton Western Canada Inc . . . . . . . . . . . . . 44 Dean’s Pump Service Ltd . . . . . . . . . . . . . . . . . 50 DFI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Dicks Boiler Ltd . . . . . . . . . . . . . . . . . . . . . . . . . 36

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NOVEMBER 2009 • OIL & GAS INQUIRER

Diversified Glycol Services Inc . . . . . . . . . . . . . . . 54 Ecoquip Artificial Lift Ltd . . . . . . . . . . . . . . . . . . . 30 Enform . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58 Enviro Vault Ltd. . . . . . . . . . . . . . . . . . . . . . . . . . . 38 Eveready Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 Falvo Electrical Supply Ltd . . . . . . . . . . . . . . . . . . 58 Global Oil & Pipe Inc . . . . . . . . . . . . . . . . . . . . . . . 56 Infosat Communications . . . . . . . . . . . . . . . . . . . 40 Joule Technical Sales Inc . . . . . . . . . . . . . . . . . . . . 54 Kangabags . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 LJ Welding & Machine . . . . . . . . . . . . . . . . . . . . . . 56 LoTech Manufacturing Inc . . . . . . . . . . . . . . . . . . 40 MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . . 56 Norsteel Buildings Ltd . . . . . . . . . . . . . . . . . . . . . 53 Northstar Energy Services Inc . . . . . . . . . . . . 32-33 Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . . . 53 OilPro Oilfield Production Equipment Ltd . . . . . . 50 Pedestal Supply . . . . . . . . . . . . . . . . . . . . . . . . . . 46 Pembina Controls Inc . . . . . . . . . . . . . . . . . . . . . . 48 Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . . . 48

Platinum Energy Services Corp . . . Inside front cover Platinum Grover Int. Inc . . . . . Outside back cover Propak Systems Ltd. . . . . . . . . . . . . . . . . . . . . . . 3 ProstAid Calgary Society . . . . . . . . . . . . . . . . . 49 Quicksilver Resources Canada Inc . . . . . . . . . . 42 Rick’s Oilfield Hauling . . . . . . . . . . . . . . . . . . . . 46 Rogers Communications . . . . . . . . . . . . . . . . . . 34 SafeHouse Habitats . . . . . . . . . . . . . . . . . . . . . 49 Sage Energy Solutions . . . . . . . . . . . . . . . . . . . 24 Singletouch . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Systech Instrumentation Inc . . . . . . . . . . . . . . 45 T & E Pumps Ltd . . . . . . . . . . . . . . . . . . . . . . . . 54 Tank Gauging Systems . . . . . . . . . . . . . . . . . . . 56 TARM Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54 Trans Peace Construction (1987) Ltd . . . . . . . . 52 TransGas Limited . . . . . . . . . . . . . . . . . . . . . . . 50 Tundra Boiler & Instrumentation Ltd . . . . . . . . 27 Vertigo Theatre Society . . . . . . . . . . . . . . . . . . 53 Westbrier Communications Ltd . . . . . . . . . . . . 28

41/2” to 72” O.D. Pipe .205” to 1” Wall Thk. Cut/Weld to Length Servicing Canada and USA

Platinum Grover “The Piling Connection”