Oil & Gas Inquirer - June 2010

JUNE 2010 $6.00

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Carbonate trailblazer Laricina mounts the first SAGD pilot projects in

Alberta’s vast bitumen-rich carbonate reservoirs

Canadian teams—from large-scale ZCL to tiny Bruin Instruments— supply energy goods and services around the world

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DEHYDRATORS (NEW)Tower Size Design Pressure12” to 36” Sweet & Sour 1,310 - 1,480 psig

HEATERS (NEW)2 MMBtu/hr Heat Duty, 1500# Preheat Coil

AMINE SWEETENING PLANTS (NEW)Plant Size Amine Circulation Rate15 MMscf/d AMINE 45 USGPM of AMINE

SEPARATOR SKIDS (NEW)Separator Size Design Pressure16” & 24” Sweet 1,440 psig

LPG RECOVERY PLANTS (NEW)Plant Size Refrigeration Compressor6-10 MMscf/d GAS 100 hp Mycom8-12 MMscf/d GAS 150 hp Mycom10-15 MMscf/d LEAN GAS 200 hp Mycom20-30 MMscf/d RICH GAS 450 hp Mycom

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C400-S25B 400 Caterpillar G3408 TAW Sullair PDR25 Gas Booster

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C630-A282 630 Caterpillar G3508 TALE Ariel RG282 Gas Booster

C1265-A357 1265 Caterpillar G3516 TAW Ariel RG357 Gas Booster

C145-JG-2 145 Caterpillar G3306NA Ariel JG-2 Throw

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C1775-JGC-3 1775 Caterpillar G3606 TAW Ariel JGC-4 Throw

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GAS COMPRESSORS (NEW)Model # hp Engine Compressor Model # hp Engine Compressor

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See our Web Site for detailed specifications for thestock production equipment.

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Imperial Oil is a trademark of Imperial Oil Limited, Imperial Oil, licensee. Mobil and the Pegasus are trademarks of Exxon Mobil Corporation or one of its subsidiaries, Imperial Oil Licensee.

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

Table of Contents

F E A T U R E S

14 Tank driveZCL takes its composite tank technology worldwide

21 Brain, not brawnTiny Bruin Instruments relies on innovation to win a global niche for its chemical pumps

27 Exporting expertisePajak Engineering sends its oilfield consultants to the farthest corners of the global patch

Keeping readers regionally informed

32 Carbonate trailblazerby Mike ByfieldLaricina president Glen Schmidt mounts the first SAGD pilot projects inAlberta’s vast bitumen-rich carbonate reservoirs

GLOBAL VISIONA western Canadian energy service company, large or small, can target international markets. In our cover feature, Oil & Gas Inquirer profiles three companies that have taken on the world.

by Mike Byfield14

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O I L & G A S I N Q U I R E R • J U N E 2 0 1 0 9

R E G I O N A L N E W S

I N E V E R Y I S S U E

63 Southern Alberta• Western Canadian light- and medium-

crude production shows new life

• PSAC revised forecast calls for

11,250 wells in 2010

69 Saskatchewan• Saskatchewan’s $190.1M land sale

is dominated by Bakken interest

• Stealth signs a joint-venture deal

for the Colorado Shales

75 Northern Frontier• Deepwater Horizon blowout will

impact Beaufort Sea drilling review

77 Central Canada• Quebec gets ready to produce

"gaz naturel"

79 East Coast• ExxonMobil and Encana trigger

offshore optimism in Nova Scotia

81 International• Controversial geologist pans U.S.

shale gas plays as likely losers

41 British Columbia• Apache completes Horn River wells

and prepares Kitimat LNG contract

• Dawson Creek and Shell negotiate

sewage treatment deal

49 Northwestern Alberta• North Peace focuses on completing

Peace River bitumen pilot project

• Seaview cases first horizontal

Cardium well at Wapiti

53 Northeastern Alberta• Stelmach vows end to tailings ponds

as ERCB approves more

• Connacher completes Algar

construction ahead of schedule

59 Central Alberta• Daylight calls its latest Cardium

horizontal results “exceptional”

• Triton reports a liquids-rich

Rich Ellerslie gas discovery

85 Tools of the Trade• PatchMap is a set of digital maps

containing all of the oil and gas field

locations ever applied for, along with

the most complete road dataset

available

86 Political Cartoon

12 Statistics at a Glance• Completions data, spot gas prices,

gas storage, drilling activity, and more

83 On The Job• Dale Terry supervises construction of

fabric-covered buildings, stating that

well-engineered structures are safe

despite the catastrophic collapse of

a competitor’s product Cover Design: Aaron Parker

Table of Contents

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Editor’s Note

N E X T I S S U E

Mike Byfield | [email protected]

If you know an admirable person to profile in On The Job—he or she may be a veteran or apprentice, field or shop, wise or a little crazy—please give me a call at (780) 784-4251, or email [email protected]. In fact, feel free to sound off about any concern at all—that’s a personal invitation.

Vol. 22 No. 6President & ceoBill Whitelaw | [email protected] Zalewski | [email protected] PuBlisherChaz Osburn | [email protected] director Stephen Marsters | [email protected] editoriAlEDITORMike Byfield | [email protected] ASSISTANCE Laura Blackwood, Janis Carlson de Boer, Samantha Kapler, Marisa Kurlovich [email protected] Jim Bentein, Lynda Harrison, Richard Macedo, Jim Mahony, Pat Roche, Elsie Ross, Paul WellscreAtivePRiNT, PREPRESS & PRoDUCTioN MANAgER Michael Gaffney | [email protected] MANAgER Audrey Sprinkle | [email protected] SUPERvISOR Rianne Stewart | [email protected] DIRECTORKen Bessie | [email protected] SERvICES SUPERvISOR Tamara Polloway-Webb | [email protected] DESigNER Aaron Parker | [email protected] SERvICES | [email protected] Dash-Williams, Janelle Johnson, Alanna StaversAlesDIRECTOR OF SALES Rob Pentney | [email protected] MANAgER, MAgAZiNES Maurya Sokolon | [email protected] ACCoUNT MANAgER Diana Signorile | [email protected] MANAgERS Jerry Chrunik | [email protected] Kiefuik | [email protected] Ng | [email protected] TRAFFIC COORDINATOR—MAgAZiNESElizabeth McLean | [email protected] advertising inquiries please contact [email protected] / TRADE SHoW CooRDiNAToR Ryan Mischiek | [email protected] DESigNER Cristian Ureta | [email protected] 2nd Floor, 816 – 55 Avenue N.E. | Calgary, Alberta T2E 6Y4Tel: 403.209.3500 | Fax: 403.245.8666 Toll-Free: 1.800.387.2446Edmonton 6111 – 91 Street N.W. | Edmonton, Alberta T6E 6v6Tel: 780.944.9333 | Fax: 780.944.9500Toll-Free: 1.800.563.2946

suBscriPtionsSubscription Rate In Canada, 1 year $49 plus GST, 2 years $69 plus GST Outside Canada, 1 year $99

Subscription Inquiries Telephone: 1.866.543.7888 Email: [email protected] Online: junewarren–nickles.comOil & Gas Inquirer is owned by JuneWarren-Nickle’s Energy Group and is published monthly.

GST Registration Number 826256554RT. Printed in Canada by PrintWest. ISSN 1204-4741 | © 2010 1072125 glacier Media Inc. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number 40069240. Postage Paid in Edmonton, Alberta, Canada. If undeliverable, return to: Circulation Department, 800 - 12 Concorde Place, Toronto, oN M3C 4J2

Made in CanadaThe opinions expressed by contributors to oil & gas inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.

Grande Prairie bounces back

Summer edition:This summer, Oil & Gas Inquirer will publish a single edition for July and August. (Subscribers will still receive the same number of issues through an extension of one month.) our next issue will feature a look at green hands, electrical contracting, notable natural gas processing plants, and more.

Tom Shields, an industrial realtor in Grande Prairie, Alta., says the economic downturn of the past two years could have been much worse. “If interest rates hadn’t been so low, we would have gone through a real bloodbath,” Shields comments. “Now business is picking up. I’ve handled more leases in the past six weeks than all of 2009. The big service companies have Help Wanted signs out again.”

“This downturn hasn’t been as bad as the NEP,” says Shields, referring to oilpatch miseries triggered by the federal National Energy Program and record-high interest rates in 1980–1982. He thinks northwestern Albertans tend to be optimistic by nature, confident in the long-term future of their region’s natural gas, oil, forestry, and agricultural resources.

Among those northern resources is bitumen, billions of barrels locked in both sandstone and carbonate reservoirs. This issue of Oil & Gas Inquirer outlines how bitumen development is now struggling westward from the Fort McMurray area toward Peace River, Alta. While the potential scale is truly global, plenty of the eventual benefits will be local, boosting businesses from Slave Lake to Grande Prairie.

Meanwhile, the natural gas–prone Northwest continues to feel the effects of the gas price slump that began in the summer of 2008. At that time, Shields says, an acre of serviced industrial land in a prime location around Grande Prairie would have fetched $300,000. Today, the same parcel would be worth about $135,000 per acre. Vacancy rates in older buildings continue to depress the value of newly constructed facilities.

Natural gas prices, which have recently been about US$4.50/Mcf (NYMEX), appear likely to stay soft for months, maybe years. “We need [US$6-$7/Mcf] to really spark activity in northwestern Alberta,” says Rob Petrone, president of the Grande Prairie Petroleum Association and district superintendent with Devon Canada. “The strength of the Canadian dollar [versus the U.S. dollar] also has a really brutal impact on producers [because much of Canada’s gas is exported south of the border].”

Grande Prairie’s energy sector has suffered layoffs and corporate amalgamations, Petrone reports, along with a few outright bankruptcies. Even so, he agrees that “there’s definitely optimism in the air here. The service companies are smaller but they’re quite busy. A lot of people and equipment are at work in the Montney and Horn River [tight gas] plays [in northeastern British Columbia].”

In Petrone’s view, the royalty policy changes now being worked out in detail by the provincial government will be critical to the energy sector of northwestern Alberta. “Other jurisdictions in North America became more attractive for upstream investment,” the veteran field operations manager says. “It’s important that Alberta becomes competitive again and hopefully we’ll see that happen soon.”


F A S T N U M B E R SStatsAT A GLANCE The Canadian Society for Unconventional Gas (CSUG)

now estimates Canada’s natural gas in place at almost 4,000 trillion cubic feet.

CSUG’s estimate for marketable natural gas in Canada, depending on gas prices. In 2006, CSUG estimated marketable gas at 367 trillion cubic feet.

700–1,300 Tcf4,000Tcf

Saskatchewan CompletionsSource: Daily Oil Bulletin

Alberta CompletionsSource: Daily Oil Bulletin

WCSB Oil & Gas CompletionsSource: Daily Oil Bulletin

M O N T H OIL GA S DRY SERV ICE TOTA L

May 2009 71 187 46 35 339Jun 2009 177 211 45 27 460July 2009 79 31 6 3 119

Aug 2009 250 267 36 37 590Sept 2009 146 155 45 9 355Oct 2009 331 196 32 12 571

Nov 2009 382 244 68 10 704Dec 2009 283 138 34 13 468Jan 2010 429 343 55 13 840

Feb 2010 147 143 20 5 315Mar 2010 548 681 109 20 1,358Apr 2010 291 458 2 9 760

Wells Drilled In British ColumbiaSource: B.C. Oil and Gas Commission

M O N T H W ELLS D R I L L E D CU M U L ATIV E *

May 2009 26 376Jun 2009 19 395Jul 2009 34 429

Aug 2009 36 465Sept 2009 38 503Oct 2009 29 532

Nov 2009 39 571Dec 2009 45 616Jan 2010 65 65

Feb 2010 98 163Mar 2010 95 258Apr 2010 47 305

*From year to date

M O N T H OIL GA S OTHER TOTA L

May 2009 16 4 3 23Jun 2009 107 10 10 127Jul 2009 124 27 1 152

Aug 2009 116 3 6 125Sept 2009 194 7 3 204Oct 2009 157 5 7 169

Nov 2009 171 11 10 192Dec 2009 139 11 9 159Jan 2010 153 18 6 177

Feb 2010 169 58 4 231Mar 2010 223 32 8 263Apr 2010 92 10 3 105

M O N T H OIL GA S OTHER TOTA L

May 2009 71 187 53 311Jun 2009 36 143 42 221Jul 2009 79 178 77 334

Aug 2009 101 212 80 393Sept 2009 146 155 78 379Oct 2009 132 160 77 369

Nov 2009 169 212 116 497Dec 2009 121 127 35 283Jan 2010 253 324 62 639

Feb 2010 144 308 114 566Mar 2010 264 579 198 1,041Apr 2010 198 418 6 622

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

Source: Natural Gas Exchange Inc.

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

Source: U.S. Energy Information Administration

Drilling Rig Count by Province/TerritoryWestern Canada May 17, 2010 Source: Rig Locator

Drilling Activity: Oil & GasAlberta April 2010 Source: Daily Oil Bulletin

OIL W ELLS GA S W ELLS

Alberta Apr 10 Apr 09 Apr 10 Apr 09

Northwestern Alberta 18 29 91 107

Northeastern Alberta 138 4 125 15

Central Alberta 22 56 78 77

Southern Alberta 20 22 124 140

TOTAL 198 111 418 339

Service Rig Count by Province/TerritoryWestern Canada May 17, 2010 Source: Rig Locator

COA LBED M ETH A NE BITU M EN W ELLS

Alberta Apr 10 Apr 09 Apr 10 Apr 09

Northwestern Alberta 2 1 0 9

Northeastern Alberta 0 0 127 4

Central Alberta 35 49 7 23

Southern Alberta 21 65 0 0

TOTAL 58 115 134 36

AC TIV E DOW N TOTA L AC TIV E

Western Canada

Alberta 250 420 670 37%

British Columbia 4 27 31 13%

Manitoba 5 4 9 56%

Saskatchewan 117 75 192 61%

WC Totals 376 526 902 42%

Quebec 1 1 2 50%

AC TIV E DOW N TOTA L AC TIV E

Western Canada (Per cent of total)

Alberta 73 473 546 13%

British Columbia 43 66 109 39%

Manitoba 0 10 10 0%

Saskatchewan 68 68 136 50%

WC Totals 184 617 801 23%

Northwest Territories 0 1 1 0%

Drilling Activity: CBM & BitumenAlberta April 2010 Source: Daily Oil Bulletin

3.0

3.5

4.0

May 19May 12May 5Apr 28Apr 21

Cdn$/GJ

$3.73/GJ Total vol.: 1,486 TJ Transactions: 157

Source: Natural Gas Exchange Inc.

1.75

2.00

2.25

May 14May 7Apr 30Apr 23Apr 16

Tcf

2.16 Tcf Year ago: 2.09 Tcf5-year avg: 1.86 Tcf

Source: U.S. Energy Information Administration


In 1989, ZCL Composites Inc. began making fibreglass under-ground tanks for gasoline retail stations in 1989. Today, the Edmonton-headquartered firm has more than 900 employees, 14 plants across Canada and the United States, one in Europe, and it’s quickly expanding globally through licensees and joint ventures. “We are North America’s largest manufacturer and supplier of FRP [fibreglass-reinforced plastic] underground storage tanks,” says Ron Fink, executive VP of ZCL. “Our goal is to be the world’s lead-ing supplier of environmentally friendly liquid storage solutions.”

ZCL’s competitive strategy is based on an ever-expanding prod-uct range and its exhaustive quality controls for both manufacturing and installation. In western Canada, the company has aggressively targeted emerging markets in the oilsands, shale gas development, and other upstream petroleum activities. “Multinational oil and gas producers who buy our tanks domestically also see us as a reliable

provider overseas. That good will is an important factor in our inter-national expansion,” Fink says.

Beyond the oil patch, the manufacturer targets water and sewage customers who have traditionally relied on concrete products. Also, customized corrosion solutions are sold across a variety of industries—for example, composite liners for the scrubbing stacks of coal-fired generating plants. ZCL even makes FRP tanks for homeowners across Canada and in the northeast-ern U.S. where oil-fired heating is common. For applications where composites are unsuitable, the company manufactures its own steel tanks.

Venence Côté, ZCL’s president, worked for CAE Industries Ltd. in the aerospace sector before founding the present composites company. The aviation connection is not coincidental. “Seventy per cent of a modern aircraft is made up of composites,” says

tank driveZCL takes its composite tank technology worldwideby Mike Byfield


Feature

ZCL executive VP Ron Fink

Photo: A

aron Parker

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Feature

the Quebec-born engineering technologist, referring to wings, fuselages, propellers, heat shields, and more. “The international space station [operated by NASA] is mostly constructed from composite materials.”

Conceptually, an engineered composite can be any product that incorporates two or more materials whose properties com-bine usefully. An ancient example would be bricks, originally made from straw and mud. High-tech composites typically include resins and a reinforcing substrate. Fibreglass, for instance, com-monly consists of finely spun glass matting soaked in polymer and styrene resins. FRP composites, although typically more expen-sive on a per-pound basis than steel, are much lighter as well as corrosion-proof against water and most other liquids.

In the ZCL’s earliest days, Côté secured the Canadian rights to an FRP tank manufacturing process developed by Minnesota-based Xerxes Corp. Composite tanks had tradition-ally been made by “winding” glass fibre and resins around a steel mould. The Xerxes system turned that process outside in, spraying a mixture of chopped glass fibre and resin onto the interior surface of a large mould. ZCL markets its FRP tanks under the trade names Prezerver and Greentank. In 2007, the company acquired Xerxes outright.

Côté scored his first big success in the downstream sector. During the 1980s, regulators realized that the steel tanks used to store gasoline and diesel fuel at retail outlets were attacked by corrosion and became leak-prone over time. In response, the Canadian Environmental Protection Act imposed new rules requiring cathodic protection for steel tanks, leak detection, and secondary containment, which initiated an opportunity for com-posite tanks. To meet that demand, ZCL impressed operators with

the first double-walled FRP tanks made in Canada, and today are capable of storage in excess of 100,000 litres.

Côté achieved that technical coup thanks to Parabeam, a 3-D glass fabric made in the Netherlands. ZCL uses Parabeam as a reinforcing linkage between the two walls of its tanks. The high-tech material also allows for liquid transfer along the length of the tank, permitting detection and containment when needed. Due to their double walls and integrated ribbing, these vessels

ZCL accepts that steel tanks have a place—the company makes this model.

Photo: Aaron Parker


Feature

have the strength required for applications across the petroleum industry. In 2002, ZCL bought Parabeam Industries BV, leaving its highly skilled Dutch team in place rather than shifting the operation to Canada.

To meet the needs of eastern Canada, ZCL opened a manu-facturing plant near Montreal. Côté estimates that his outfit currently supplies upwards of 90 per cent of the new tanks installed by gasoline retailers in Canada and 40 per cent in the United States. South of the border, future growth is expected to be strong, as more than 500,000 tanks will likely need to be replaced over the next 20 years.

Green rules boosted ZCL’s fortunes in the upstream sector as well. Western Canadian petroleum producers often flared solu-tion gas and other by-products at the wellhead. During the 1990s, however, Alberta regulators insisted on the installation of liquid waste storage and disposal systems. “At that point, the standard underground tanks used in the oilpatch were steel,” Fink says. ZCL muscled into the upstream market on the strength of FRP tanks that offered superior reliability and lower full-cycle costs.

According to Fink, steel fabricators responded to the FRP competition by promoting above-ground field storage tanks. Undeterred, ZCL designed a line of its own above-ground FRP tanks. “Why replace a steel tank every five years if a composite alternative will last indefinitely?” the executive VP queries. Because American regulators have also toughened their oilfield regulations, ZCL’s FRP tanks are selling in states with strong natural gas exploration and development.

The company’s operations now total more than 100,000 square feet of plant floor space in Edmonton alone. Its engineers have designed equipment to make thick-walled pressure vessels, Ron Fink stands beside an above ground fibreglass oilfield service tank.

Photo: Aaron Parker

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heated knockout tanks, custom vessel inlets and outlets, and other specialized products. Beyond vessels, ZCL also designs and manu-factures a range of pipes, concrete tank anchors, and even ladders. “We aim to be a one-stop shop. We’re very flexible when it comes to meeting a customer’s specific needs,” Fink says.

Among the executive VP’s showpieces is a circle of corroded steel bonded to a thick layer of FRP, a real-life example of ZCL’s proprietary tank relining technology. “This steel came from the floor of a tank that we refurbished,” Fink says. “Water will get into virtually any oil-containing vessel. Even if there’s no external source, condensation will occur. The water sinks below the hydro-carbon. Although corrosion can occur anywhere in a steel tank, it’s usually most vulnerable along the bottom or the floor.”

To salvage corroded tanks, ZCL’s engineering team came up with the Phoenix System. After being thoroughly cleaned, an underground single-wall tank (steel or fibreglass) can be trans-formed into a secondarily contained system without digging it out. In 2006, the technology received certification by underwrit-ing authorities in the United States and Canada. Since then, the company has been deploying Phoenix in North America, Europe, and Asia.

ZCL went public in 1995. Its share price peaked at nearly $16 in mid-2007 and now sits above $4. Annual revenue presents a brighter picture, rising from $55.1 million in 2006 to $128 mil-lion in 2008, then subsiding marginally to $110 million last year due to the global economic downturn. Net income remained in the black last year, at $2.2 million, down from $11.4 million the pre-vious year. The company’s balance sheet as of 2009 was notably strong—assets totalled $103 million while long-term debt stood at $5.3 million.

In January, ZCL made a major move, acquiring Dualam Plastics Inc. for about $22 million in a half-cash, half-equity deal. The Montreal-based firm custom engineers FRP and dual-laminate composite products for use in corrosion-resistant applications. Its major customers are in the power generation, chemical, and pulp and paper sectors. In 2009, Dualam had rev-enues of nearly $60 million. Besides extending ZCL’s reach into new industries, its executive VP says his company can now offer individually designed solutions within the patch, particularly the oilsands.

The Edmonton firm is now focusing its reinforced strength on the international arena. Jizhou Zhong Yi FRP Co., a tank manu-facturer in northeastern China, signed a licence agreement for tank manufacturing and relining technology, and some personnel training has occurred in both countries. France’s Socomex SARL licensed the Phoenix System. ZCL will continue to aggressively pursue growth, according to its executive VP. “Canada is big and North America is bigger,” Fink says. “But the world is the biggest of all, and that’s where we’re heading.”

ZCL has designed its own equipment to manufacture thick-walled pressure vessels.

Feature

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Not many hockey fans can match the drive of Darren Preece, who’s cheered for the Boston Bruins since he was a kid, perched on his dad’s knee in front of the family television. “Our company is named after the team,” says the president of Bruin Instruments Corp. With a staff of about two dozen, Bruin itself is no larger than a hockey team. Despite its small size, though, the chemical injection pump man-ufacturer is moving aggressively to sell its equipment across the United States and around the world.

Its 12,500-square-foot facility is located in Sherwood Park, Alta., where Preece grew up. “In western Canada, we’ve competed through making constant improvements to our pumps, and now we’re applying that same capability to

other markets,” the 49-year-old entrepre-neur says. “We were the first guys out with a low-pressure pump that’s specifically designed for shale gas. Existing pumps required operating pressures higher than the low-pressure shale fields can provide. This model works at as low as two psi: without sacrificing durability.

Bruin has also innovated with respect to low-volume chemical injection. “Many pumps are hard to adjust for really low volumes,” Preece explains. “Chemicals are very expensive and a pump in the field operates 24 hours a day.” His company met that need with a pump that offers extremely low-volume field adjustability, reducing the injection of chemicals where possible to as little as cubic centimetres per day.

Beyond entirely new products, Bruin takes pride in making dozens of small but cumulatively significant improvements. For instance, nitriting main rods improve their durability. A priming valve can be shaped so it won’t inadvertently catch on the coveralls of a passing worker. Or suppose a pump diaphragm breaches—natural gas will then leak into the structure housing the pump. In response, Bruin provides a connection that permits the operator to easily attach an exterior venting tube to the pump.

Then there’s the plastic lid. “We found that operators would remove the steel lid over a chemical pump’s mechanism to see what was happening in there. Then the lid would often be left off because screw-ing and unscrewing it is a nuisance,” the

Brain, not brawnTiny Bruin Instruments relies on innovation to win a global niche for its chemical pumpsby Mike Byfield

Bruin Instruments president Darren Preece

Photo: A

aron Parker

Feature

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Feature

company president says. “Of course, it’s better to leave the lid on. So our pumps feature a clear plastic lid—the operator can see the mechanism and liquid flow without removing the lid.”

Looking to the future, Preece says, “The big trend is solar. Any pump that burns wellhead gases will release emis-sions, so producers are turning to solar power as an environmentally superior alternative.” In response, Bruin has nearly completed a “cool little controller” that combines the control and regulation func-tions in a single device. Its features include simplicity, ruggedness, lower cost, and finely tuned electricity flow from solar panel to pump batteries.

Well-established in the West, Preece thinks his firm is ready to take on dozens of competitors in the international arena. Teamwork is a passion for this hockey enthusiast. On display at the Bruin plant are a Boston hockey jersey and other paraphernalia signed by the best-known Bruin of all time, defenceman Bobby Orr. “As a teenager, I got a try out with the Victoria Cougars, which made me real-ize that professional hockey wasn’t for me,” he says. “I heard the oilpatch paid the best money around here, so I got a job driving a truck for a local oil and gas industrial supply store.”

The young contender had found his game. Working for Bishop, Turbo, and Vonco in oilfield distribution, Preece quickly rose to manager, opening a store in Bonnyville, Alta. Ironically, his most educational experience in service and supply came from working for an actual producer. “BP hired me as an operator at its cyclic steam bitumen project [near Cold Lake, Alta.]. I read gauges, I twisted wrenches, but most of all I learned how

Photo: Aaron Parker

This Bruin chemical injection pump has the company's see-through lid.


Feature

buying power is distributed from the field to head office,” the Bruin CEO says. “Until then, I’d focused on purchasing agents. BP was a huge eye opener.”

In 1990, not yet 30 years old, Preece launched Bruin, selling his home to raise capital. The fledgling firm repaired valves, switches, various types of pumps, and more. “There’s a vast amount of instrumentation products, and we went for pretty much all of it,” the entrepre-neur says. “Gas prices were very low at that time and everyone was grinding each other down on price. Margins were ter-rible. I was on the road myself for five or six years, almost to the point of burning out, but we survived.”

As times got better, Bruin persistently accumulated cash reserves. “Getting started in a downturn made us careful, which turned out to be a good thing,” Preece says. Due to its strong balance sheet, the company coped well with the energy sector slowdown of the last couple of years. Meanwhile, several competitors in western Canada have shut their doors. “Those companies began when making money was easy and the owners bought the big fancy trucks and so on,” the Bruin founder says. “Everyone learns sooner or later that this industry is cyclical.”

Years of repair experience taught Bruin the limitations of existing pumps and sparked ideas for improvements. Preece persuaded an American-based manufacturer to make a raw gas-fuelled, CSA-approved “trash” pump capable of dealing with solids-contaminated liquids. “We got the western Canadian sales rights, which was fine as far as it went,” he says. “But the real money was made by the man-ufacturer, who still sells that model inter-nationally.”

To get into manufacturing, the Alberta company needed more bench strength. Two executives were recruited from a far larger competitor, using the classic lures of partnership and promotion. Since 1998, Darrell Hughes has handled Bruin’s marketing, while Ken Shapka came on board in 2000 as a design-oriented engineer. “Our manufacturing and repair operations now account for about 80 per cent of our revenue. We also sell American pumps that complement our own models,” Preece says.

International sales presently generate nearly 15 per cent of revenue, a figure that has grown annually for the past five years. To boost its foreign income further, the

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company naturally looks south of the border. Its full line of pumps will soon be carried by an oilfield supply house with 14 stores that serve oil and gas producing regions in the United States “We’re now training their people on sales and repair, which takes time,” Preece says.

Hughes, who heads Bruin’s overseas marketing push, says it usually takes two to five years to develop a new foreign market. “You need plenty of time to train a good agent or representative and get your name known,” says the Bruin sales manager. Besides coming up with custom-ers, a good agent will help create effective sales materials, provide reliable after-sales service, and make valuable sugges-tions on how to adapt a pump design for his market.

Independent producers, including Canadian operators, are increasing their activities in many foreign oilpatches, as are oil and gas service providers. (The independents generally follow in the wake of multinationals like Exxon and Shell, who leave a region once its potential for elephant oil and gas discoveries has been exhausted.) “North American companies know our products are reliable and that’s a big help for us overseas,” Hughes says. “But these companies are demanding. In many markets, delivery times have shrunk from many months to a few weeks.”

Some of Bruin’s competitors have laid off the engineering and marketing spe-cialists who previously handled export business. “The economic downturn of the last couple of years has led to cut backs, which provides us with opportunities,” Hughes comments. “We’ve made a long-term commitment to our international business.” Foreign cash flow, although difficult to get started, tends to be stable, precisely because lining up a new supplier takes so much time and expense. Equally attractive, foreign oil and gas activity is often less violently cyclical than the North American petroleum sector.

When it comes to foreign markets, Preece says he’s not especially concerned about his company’s lack of size. Sheer quantity, in his view, counts for much less than having motivated, well-trained people who know how to identify and exploit opportunities. “Can your team deliver leading-edge products at a competitive price?” queries the Bruin CEO. “If the answer is yes, you can find your niches. Wherever oil and gas are produced, the door is open.”

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Three years ago, Chad was invaded by rebel forces with military backing from neighbouring Sudan. Hundreds of civil-ians have been killed in fighting between these two African nations, and on this occasion the invaders penetrated to N’Djamena, the Chadian capital. Caught by the incursion were field crews belong-ing to China National Petroleum Company (CNPC) and a Canadian petroleum con-sultant. “It wasn’t just a question of getting our own people [five] out of there—we also had to help evacuate 115 Chinese oilfield personnel,” says George Myette,

business development manager for Pajak Engineering Ltd.

Pajak supplies wellsite supervisors, professional engineers, and certified en-gineering technologists to clients around the world. Last winter, its personnel roster totalled about 250, with more than 25 per cent working outside of Canada. “We have expertise in all phases of the oil and gas exploitation cycle, from initial permitting to final abandonment. And if a client hap-pens to need an emergency evacuation, we’ll provide assistance for that as well,” Myette says with a smile.

The Chad contract was originally signed with Encana, and Pajak continued working there after the assets were sold to CNPC. When warfare erupted in 2008, the Chinese producer initially wished to leave its crews in place. “The fighting was several hundred kilometres away from our locations,” Myette says. “Even so, the situation was not tenable. The incursion had cut off supplies and our advice was to withdraw our people promptly.” Beyond the invasion itself was the risk of wide-scale looting, which did in fact break out in the national capital.

exporting expertisePajak Engineering sends its oilfield consultants to the farthest corners of the global patchby Mike Byfield

Pajak Engineering business development manager George Myette

Photo: C

hristina Ryan, inez P

hotography


Feature

Leaving Chad, a landlocked country with minimal modern infrastructure, was easier said than done. The Chinese didn’t have passports—their papers had been held at CNPC’s office in N’Djamena and were unavailable. Fortunately, Joe Horvath—the Pajak Logistics consultant on the spot—persuaded immigration officials in Cameroon to let the Chinese enter without conventional documents. On short notice, Twin Otters ferried the oilfield crews from Chad to Cameroon in a series of flights. To keep refuelling the Canadian-made bush aircraft, the consult-ant had enough funds at hand to pay cash on the barrelhead.

Pajak veterans like to say that all of its assets wear boots, and always have. The firm was founded in 1966 by drilling en-gineer Lou Pajak, a close friend and busi-ness associate of Vern “Dry Hole” Hunter. (After a long string of drilling dusters for Imperial Oil, Hunter was the rig man-ager on Leduc No. 1, the famed well that launched Alberta’s modern oil industry in 1947.) Pajak initiated Canada’s first well

control course, called Drilling For Kicks. He also constructed an early drilling rig control simulator for training purposes.

From providing wellsite supervision on a contract basis, Pajak branched into engineering services and project manage-ment. “The Western Canadian Sedimentary Basin has a challenging slate of hydrocar-bons, everything from bitumen to sour gas under high pressure,” Myette comments. “The operating environment here is also very expensive due to weather, physical isolation, and other factors. As a result of our resources and geography, drilling man-agement skills are widely recognized as a Canadian specialty.”

Myette’s own background blends oilfield experience, an entrepreneurial streak, and social work. At age 16, the Saskatchewan-born, Wainwright-raised youth began roughnecking on a service rig as a summer job. A job on Kenting’s Rig 12 after high school took him to Britain in 1972, drilling onshore. Changing course, the Calgarian earned a diploma in applied social sciences from Mount Royal

University in 1975, then helped develop halfway houses and industry training for released prisoners. (He now sits on the national board of the Seventh Step Society, whose rehabilitation program is designed to help repeat offenders.)

In 1982, Myette moved back into oil and gas, marketing for Schlumberger-owned Johnston Testers and working as far afield as Venezuela. Later he joined Flextube and became a partner in that pioneering coiled-tubing technology firm. “Canadian Fracmaster bought Flextube in 1997 and I stayed with them for two years, developing CT-related business. After Fracmaster went broke, Pajak brought me on board,” the business development man-ager says.

“At that time, the company had about 100 consultants, including a group work-ing for ARCO in Indonesia. We set about deploying more personnel internation-ally where the business tends to be less cyclical than it is in Canada,” Myette says. By 2008, Pajak’s total consultant payroll had reached 300, and the com-pany had a blue ribbon client roster of overseas operators that includes Talisman, Encana, Suncor, BP, Murphy, Husky, Niko, and others. Some of that work is offshore, taking the firm well beyond its western Canadian roots.

Marketing Pajak’s portfolio of energy expertise requires plenty of travel. Last year alone, Myette visited South Africa, Syria (twice), Qatar (twice), China, Libya, and Britain. “Canadians in our industry are known for having a good work ethic,” he says. “Producers recognize that our guys will push hard toward a set of goals. But that drive is balanced with common sense. Our consultants operate responsi-bly. To our customers, common sense is just as important as the determination to push forward.”

High standards have been crucial to Pajak’s success, according to Myette. “We maintain professional ethics,” the 56-year-old manager says. “We avoid questionable operational shortcuts. Our consultants are under instruction not to jeopardize any-one’s health or safety. And if one of our consultants does shut down a job because it’s not in compliance with good prac-tices, this company will back him up. Occasionally, a client will question a deci-sion that costs money and we have probably lost some business as a result. Overall, however, insisting on quality has benefited us among the higher-calibre producers.”

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spooled, high pressure, corrosion-less pipeline systemwith the strength and cyclic durability of steel. FlexpipeSystems’ newest product line can handle applications

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Flexpipe Systems is deeply committed to innovation and continuous improvement and is poised to launch a new product line to the oil and gas industry. FlexCord Linepipe, which has been designed for pipeline applications with severe pressure cycling, will be released in the coming months.Offering all of the advantages of spooled pipe, FlexCord was developed in response to feedback from customers who asked Flexpipe Systems to cover a broader range of applications.“It’s market-driven demand. FlexCord is a true reflection of Flexpipe Systems as an innovative leader utilizing market demand for product creation,” says Flexpipe Systems Sales and Operations Vice President, Dean Zipse. “As clients ask, we deliver.”Flexpipe Systems, a division of ShawCor Limited, is the market leader in continuous pipeline technology, providing complete engineering and application resources to its customers. Flexpipe’s

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or rehabilitation of corroded steel lines,” Zipse says. “The addition of FlexCord to our product offering will broaden the application parameters into which our composite pipeline technology will fit.”The primary difference between FlexCord and FlexPipe is that FlexCord’s middle layer is constructed from galvanized steel cords instead of glass fibres. This allows FlexCord to withstand severe pressure pulsations without degradation of the reinforcement layer. The use of galvanized steel cords also provides better corrosion resistance than the bare steel used in other composite technology.“Even with best efforts, actual production operating parameters can have severe pressure fluctuations,” explains Jeff Conley, Senior Product Engineer at Flexpipe Systems. “It’s the demands of these pressure spikes that FlexCord is designed to handle.”FlexCord Linepipe will initially

be available

in three-inch and four-inch internal diameters, with a maximum

allowable operating pressure of 10,342 kPa (1,500 psi), and a maximum allowable operating temperature of 60°C. This allows FlexCord to meet the needs of a wide variety of oilpatch applications, including many oilfield water transfer and injection/disposal applications. “FlexCord can be used in challenging operating conditions, wherever that cyclic robustness is required,” Zipse says.In today’s world of volatile commodity pricing, the requirement to get wells online in a timely fashion warrants spoolable technology. Operators with a backlog of wells that have been drilled but not tied in can get their wells tied in faster and more cheaply with this type of product.

FlexCord maintains all of the key benefits of FlexPipe, including the same durable, proven joining system. Other benefits include:

• FlexCord’s excellent installation economics—Using FlexCord will save clients money. FlexCord can be installed in a fraction of the

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• FlexCord is environmentally viable—FlexCord causes less ground disturbance and requires a smaller right-of-way, resulting in better relationships with landowners.

• FlexCord is a corrosion-less system—FlexCord’s corrosion resistance and operational effectiveness reduce the cost of ownership of a pipeline. Like FlexPipe, the pipeline system requires no chemical inhibition programs.

Flexpipe Systems’ continuous, high-pressure, corrosion-resistant pipeline products, FlexPipe Linepipe and FlexCord Linepipe, are cost-competitive, environmentally sound solutions, aimed at decreasing the overall cost of pipelining projects. It pays to be FLEXIBLE.

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It Pays To Be Flexible

spooled, high pressure, corrosion-less pipeline systemwith the strength and cyclic durability of steel. FlexpipeSystems’ newest product line can handle applications

subject to the most severe of cyclic conditions.

Go to:

Flexpipe Systems is deeply committed to innovation and continuous improvement and is poised to launch a new product line to the oil and gas industry. FlexCord Linepipe, which has been designed for pipeline applications with severe pressure cycling, will be released in the coming months.Offering all of the advantages of spooled pipe, FlexCord was developed in response to feedback from customers who asked Flexpipe Systems to cover a broader range of applications.“It’s market-driven demand. FlexCord is a true reflection of Flexpipe Systems as an innovative leader utilizing market demand for product creation,” says Flexpipe Systems Sales and Operations Vice President, Dean Zipse. “As clients ask, we deliver.”Flexpipe Systems, a division of ShawCor Limited, is the market leader in continuous pipeline technology, providing complete engineering and application resources to its customers. Flexpipe’s

existing product line, FlexPipe Linepipe,

has been used by a long list of energy producers in North

America. “Over the last seven years, Flexpipe Systems has provided

composite pipeline solutions for many tier 1 E&P companies as well as hundreds of junior oil and gas producers. Our marquis product line has helped our clients lower the cost of their pipeline projects, has reduced the environmental impact caused by pipelining and has helped companies increase their production rates through quick installation of new lines

or rehabilitation of corroded steel lines,” Zipse says. “The addition of FlexCord to our product offering will broaden the application parameters into which our composite pipeline technology will fit.”The primary difference between FlexCord and FlexPipe is that FlexCord’s middle layer is constructed from galvanized steel cords instead of glass fibres. This allows FlexCord to withstand severe pressure pulsations without degradation of the reinforcement layer. The use of galvanized steel cords also provides better corrosion resistance than the bare steel used in other composite technology.“Even with best efforts, actual production operating parameters can have severe pressure fluctuations,” explains Jeff Conley, Senior Product Engineer at Flexpipe Systems. “It’s the demands of these pressure spikes that FlexCord is designed to handle.”FlexCord Linepipe will initially

be available

in three-inch and four-inch internal diameters, with a maximum

allowable operating pressure of 10,342 kPa (1,500 psi), and a maximum allowable operating temperature of 60°C. This allows FlexCord to meet the needs of a wide variety of oilpatch applications, including many oilfield water transfer and injection/disposal applications. “FlexCord can be used in challenging operating conditions, wherever that cyclic robustness is required,” Zipse says.In today’s world of volatile commodity pricing, the requirement to get wells online in a timely fashion warrants spoolable technology. Operators with a backlog of wells that have been drilled but not tied in can get their wells tied in faster and more cheaply with this type of product.

FlexCord maintains all of the key benefits of FlexPipe, including the same durable, proven joining system. Other benefits include:

• FlexCord’s excellent installation economics—Using FlexCord will save clients money. FlexCord can be installed in a fraction of the

time it takes to

install a steel pipeline and also

requires less equipment and smaller construction crews.

• FlexCord is environmentally viable—FlexCord causes less ground disturbance and requires a smaller right-of-way, resulting in better relationships with landowners.

• FlexCord is a corrosion-less system—FlexCord’s corrosion resistance and operational effectiveness reduce the cost of ownership of a pipeline. Like FlexPipe, the pipeline system requires no chemical inhibition programs.

Flexpipe Systems’ continuous, high-pressure, corrosion-resistant pipeline products, FlexPipe Linepipe and FlexCord Linepipe, are cost-competitive, environmentally sound solutions, aimed at decreasing the overall cost of pipelining projects. It pays to be FLEXIBLE.


FlexCord Can Handle the Pressure! Innovative Developments at Flexpipe Systems

Please contact

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A lberta’s Grosmont formation is by far the world’s largest heavy oil car-bonate reservoir, with estimated

original bitumen in place (OBIP) of 320 billion barrels (Bbbl). A generation ago, several producers tackled this huge pros-pect with several pilot production initia-tives that failed financially. Now Laricina Energy Ltd. is advancing the first attempt to tap into the Grosmont with steam assisted gravity drainage (SAGD) technology. If the 1,800-barrel-per-day (bbl/d) Saleski pilot project goes well, the north central region of the province—traditionally serviced out of Slave Lake and Wabasca—can look for-ward to large-scale economic development within the forseeable future.

At Saleski, Laricina hopes to ramp up production in stages of 20,000 to 60,000 bbl/d. Ultimate output would be 270,000 bbl/d over an estimated 25 years of reserve life. While Saleski is a pure car-bonate play, Laricina’s nearby Germain project will draw bitumen from an oilsand formation (Grand Rapids) and the deeper

Winterburn, a carbonate reservoir. At Germain, the company plans a $250-mil-lion demonstration phase followed by staging production up over 10 years to 180,000 bbl/d.

“The development of two projects within one operating area significantly improves the economics of each,” com-ments Laricina president Glen Schmidt. To date, the five-year-old company has raised approximately $450 million. As Saleski’s operator, it owns 60 per cent of the pro-ject. Its partner, Osum Oil Sands Corp., is another Calgary junior that specializes in bitumen. Saleski has an estimated 4.1 billion OBIP, which would yield 1.6 Bbbl at a recovery rate of 39 per cent. Germain (96 per cent owned by Laricina) is also expected to produce at least 1.6 Bbbl of bitumen.

The Laricina CEO holds chemical engineering and MBA degrees from the University of Calgary. His professional pedigree includes Torex Gold Resources Inc. and Pioneer Natural Resources

Canada (both as president) along with vice-presidential posts at Chauvco and Mark Resources. From 2001 to 2005, he headed Deer Creek Energy Limited, which generated the Joslyn oilsands SAGD and mining project. After French multi-national Total acquired Deer Creek for $1.35 billion, Schmidt turned his attention to in situ and bitumen-bearing carbonates.

“People tend to look backward, which is fine as far as it goes, but the real value gets created when someone applies the les-sons of the past creatively to new opportu-nities,” says the entrepreneurial engineer. “For instance, Texaco once held most of the Deep Basin [a tight gas formation in northwestern Alberta and northeastern British Columbia]. But it took John Masters and Jim Gray of Canadian Hunter to rec-ognize that the Deep Basin had immense potential—Texaco just saw poor reservoir rock and farmed out.”

When Alberta’s bitumen industry got underway, Suncor and later Syncrude Canada developed their strip mines

Carbonate trailblazer

by Mike byfield


Laricina president Glen Schmidt mounts the first SAGD pilot projects in Alberta’s vast bitumen-rich carbonate reservoirs

Feature

“ People tend to look backward, which is fine as far as it goes, but the real value gets created when someone applies the lessons of the past creatively to new opportunities.”

– Glen Schmidt, President, Laricina Energy Ltd.


Photo: C

hristina Ryan, inez P

hotography


Feature

where the McMurray oilsand formation outcropped to the surface. By a fortunate coincidence, those surface deposits were close to established transportation cor-ridors. “Accessibility and infrastructure pushed the first projects to the north-east,” Schmidt says. Over time, produ-cers experimented with steam injection to exploit deeper oilsand bitumen deposits, but they mostly confined their projects to the McMurray sands.

The Grosmont carbonate and its Winterburn counterpart (upwards of 60 billion OBIP), form a north-south corri-dor to the west of the McMurray oilsand fairway. Sandstones and carbonates have very different origins. Sand is essen-tially inorganic. In contrast, carbonates (common examples are limestones and dolomite) consist of marine organic ma-terial, like plankton and coral. These rocks can be super-productive. Saudi Arabia’s Ghawar, the world’s largest oil-field, and Kirkuk in Iraq, one of the most prolific, are carbonate reservoirs. In Schmidt’s view, they are also good geo-logical analogues to the Grosmont.

Producers did recognize the poten-t ia l of the geographical ly isolated Grosmont. Several in situ pilot tests

were conducted in its central portion of this area in the 1970s and ’80s, applying steam and underground combustion pro-cesses. Among these players were Union Oil, Unocal, Chevron, and Canadian Superior, along with the provincially funded Alberta Oil Sands Research & Technology Authority (AOSTRA), which later evolved into the Alberta Energy Research Institute.

The carbonate geology that confronted these early explorers proved to be daunt-ingly complex, The Grosmont’s average depth is just over 1,000 feet, including up to 250 feet of bitumen-soaked pay zone. The formation features several types of porosity/permeability:• There’s low-permeability, fine-grained

matrix, through which tarry bitumen cannot flow without treatment.

• Long fractures create routes through which steam can rise and crude can drain, both rapidly. Speed is of the essence in thermal recovery, because of continuous heat losses to the surrounding rock.

• In addition are vugs and karsts—cavi-ties of various sizes formed by f low-ing water that later filled up with rock debris and bitumen. A drill bit can plunge several feet through a vug.

Although the hollows can boost bitu-men flow, they’re potentially bottom-less pits for drilling mud.Unocal and partner AOSTRA had some

technical success—one vertical well gener-ated 550 bbl/d. In fact, the performance of this well, the only one to ever receive more than three small steam slugs, was greatly superior to anything realized by that time in the McMurray. Three things intervened: the oil price crash in the mid ’80s, geographic isolation, and AOSTRA’s mandate to unlock the McMurray first. “The industry’s focus was on what it knew. As long as there was McMurray oilsands acreage available, the industry deferred the development of the Grosmont carbonate,” Schmidt says.

Today, the promising oilsands pros-pects are locked up. SAGD has emerged as a viable technology, developed entirely in the McMurray and other Cretaceous sands. To the west, the Grosmont fairway has been opened up with roads and other infrastructure, constructed by natural gas, the Pelican Lake conventional heavy crude play, and forestry producers. The changed circumstances attracted attention from a pair of international operators. In early 2006, Royal Dutch Shell startled the oil-patch by bidding $465 million for Crown

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leases totalling 88,600 hectares in the Grosmont. Husky Energy, another heavy-weight, also picked up extensive acreage.

Major producers, when tackling low-grade resource prospects like shale gas or oilsands, often buy extensive acreage at

relatively low prices per acre. Their teams can then take time to high-grade the best prospects within those holdings. As a junior, however, Laricina couldn’t afford that strategy. Instead, the company has drilled delineation wells and evaluated

legacy records (310 wells altogether) over all its projects. Dozens of laboratory, simulation, and physical reservoir tests were performed. Based on that expand-ing knowledge base, the company cherry-picked specific lands for acquisition.

Schmidt has few concerns about res-ervoir permeability at the Saleski and Germain prospects. “We will not need to frac our wells as needs to be done in the tight oil and gas plays,” he says. “These are high-quality reservoirs. Our approach was to do everything possible at the mod-elling and simulation level, then to test ideas in the field—all before moving to the more cost-intensive phase of pilot-scale operations.” Thorough evaluation helped encourage provincial support for the pilot. As a small company, this incremental capi-tal investment is helpful.

With that initial work largely com-plete, field construction is now proceeding. This winter, Laricina drilled the four well pairs at Saleski. (An evaluation well pair had been drilled in 2008.) A peak labour force of 350 constructed an all-weather, 32-kilometre gravel access road to the project, drilled service wells, prepared the 12-hectare plant site, and placed the initial SAGD facility’s components on the site.

Feature

Laricina plans to begin steam injection at its Saleski carbonate pilot project late this year.

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Feature

Water source and disposal wells are in place. The pilot plant’s construction is scheduled for completion by this fall, with steam injec-tion beginning in the fourth quarter.

At Germain, Laricina recently received a green light from the Energy Resources Conservation Board for a 1,800 bbl/d pilot plant but the company’s evaluation work prompted an expansion to 5,000 bbl/d as a commercial demonstration project. This amendment is pending approval and expected later in 2010. The revised demonstration project will incorporate a hydrocarbon-assisted recovery process known as solvent-cyclic SAGD (SC-SAGD). Construction is scheduled to begin next year, start-up should occur in the second half of 2012, and commercial expansion to 30,000 bbl/d is slated for 2015.

The Germain project will have a 66-hectare footprint, accessed by a 21-kilometre al l-weather road con-structed in 2007–08. Its main compo-nents will include a central processing facility, 10 well pairs drilled from one pad, and offsite pipelines and services. Also planned are an operations camp, waste water and sludge disposal system, and a natural gas pipeline.

The SAGD process consists of drill-ing two horizontal wells in parallel, one above the other. Steam is injected into the upper well, enabling the softened bitumen to drool downward into the col-lector well. Schmidt emphasizes that the project would be economically viable with straight steam. “Adding solvent to the steam will be the value multiplier. It sub-stantially reduces the quantity of energy needed to recover each barrel of bitumen,” he says.

At Germain, the primary SC-SAGD target is the Grand Rapids oilsand. Laricina’s injection will begin with steam and condensate, then shift to propane and steam. The solvents should move ahead of the steam, pre-treating the bitumen and initiating gravity drainage. The advanc-ing steam front should then empty the expanding underground “chamber” of bitumen while much of the solvent recir-culates through convection for eventual recovery. The company hopes that using solvent will reduce the all-important steam to oil ratio from three to one to as little as 1.8 to 1.

Sc h m idt compa res Sa lesk i a nd Ger ma i n to t he Foster Creek a nd

Christ ina Lake SAGD bitumen projects developed by Encana Corp. “Those are the crown jewels of Cenovus [the oi l-focused company spun of f last September by Encana]. In terms of scale and profitability, our projects are very comparable,” he comments. Cenovus is also experimenting with solvent-SAGD at its thermal production sites. Further down the road, Laricina plans to exploit three smaller core properties (two oil-sands, one carbonate). “As the infra-structure matures in our region, those properties will advance,” the company president explains.

West of the Grosmont platform sit the Peace River bitumen deposits. Again, the thick crude sits in both sand and carbon-ate reservoirs. Shell Canada has long oper-ated a limited SAGD oilsands project in this area, and North Peace Energy Corp. is now launching an oilsand pilot there. (See article on page 49.) In general, though, Schmidt sees Peace River bitumen as less economically attractive at this stage. “Their turn will come,” he predicts. “As our exploitation technology continues to improve, resources that are now marginal will be profitably produced.”

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The unique demands of oil and gas production require a one-of-a-kind solution that saves both time

and money. That solution is now available.Canadian-based One 4 Haul Trans4mer Ltd. has

developed the Trans4mer Garage/Wash Bay—a combined garage and wash bay. This innovation is a versatile portable

building with many applications, ranging from a temperature-controlled working area to an environmentally friendly wash bay. There is no hydraulic system—it’s all electrical and air. The indoor facility is also the world’s first portable building with a four-ton overhead crane.

“It’s mobile, it’s fast-opening, and it’s easy to close,” says Jay Haché, head of Sales and Marketing at One 4 Haul Trans4mer Ltd. And with ever increasing interest from industry, the production schedule is filling up fast.

The Trans4mer Garage/Wash Bay is transported by truck and spans 30 feet wide, 40 feet long, and 20 feet high when opened. Set-up and removal is easy: one truck, one person, one hour. Customers will benefit from the unique design of the floor as a tank, as well as the unit’s rigidity and robustness. The Trans4mer Garage/Wash Bay comes with a floor that can support 90,000 pounds, a four-ton overhead crane, and an insulated, heated facility with a generator that makes the building self-sufficient.

Born from close study of the needs of potential oil and gas industry clients, the Trans4mer Garage/Wash Bay seeks to help businesses operate more efficiently and thrive in harsh environments, while at the same time protect the environment and prevent cross-contamination challenges. Clients can also ensure productivity in the worst conditions. During winter, mechanics working without the benefit of the Trans4mer Garage/Wash Bay can spend as much as 30 minutes out of an hour simply warming up.

The Trans4mer Garage/Wash Bay has also responded to another dilemma faced by clients: stricter government enforcement of mandatory spotless wash regulations. Haché recalls a client that had to haul heavy equipment 250 kilometres from one site to head office to be cleaned, before transporting the equipment to a different work location, only 50 kilometres away from the original site. “By combining the garage and wash bay as a unit, companies will now be able not only to do mechanical work and/or welding, but they will also have the option of cleaning their equipment right on site,” Haché says.

For more information, please contact:One 4 Haul Trans4mer Ltd.

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Visit us at booth 5415 during the Global Petroleum Show on June 8–10. To receive a personalized invitation to visit the Trans4mer Garage/Wash Bay in the Calgary and

Fort McMurray areas, contact Jay at [email protected] or go to www.one4haul.com/ogminvitation.

• Rapid and easy mounting/dismounting—one truck, one person, one hour;

• A wash bay to keep equipment clean and prevent costly cross-contamination problems;

• Insulated walls, for a more comfortable working area;

• An environmentally friendly design with a tank built as a floor, to capture any liquid spills that would otherwise damage the environment;

• Two 14-foot by 16-foot overhead doors (one at each end);

• Optional items, available at extra cost, including attached tool boxes, attached work tables, welding equipment, and much more;

• A standard air compressor system (at no extra cost);

• An optional security camera system;

• A diesel generator (50 kW, 3 phase) included to power the facility;

• A structure whose high-quality design makes it versatile, durable, and portable

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• Greatly reduced equipment downtime, by having mechanics and equipment readily available;

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• Increased staff morale and productivity, with a working environment that can be adjusted to provide relief from outdoor conditions.

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“This garage will bring

great cost savings, and will

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profitable, more effective

way of doing business.”

It’s no surprise that interest in the Trans4mer Garage/Wash Bay is growing rapidly. Customer responses have ranged from, ‘‘Where have you been?” to “We should have gotten this 10 years ago.”

One customer even described it as “the most innovative product in the heavy equipment industry for the past 5 to 10 years.”


BRITISH COLUMBIA WELL ACTIVITY

British Columbia

APR/09 APR/10

WELL LICENCES 30 44 ▲

APR/09 APR/10

WELLS SPUDDED 17 37 ▲

APR/09 APR/10

WELLS DRILLED 27 44 ▲

Source: Daily Oil Bulletin

Apache completes Horn River wells and prepares Kitimat LNG contract

Apache Corp. expects to award front-end engineering and design proposals for the Kitimat LNG Inc. export facility within the next two months, a company official said on April 29. John Crum, co-COO and pres-ident of North America, said his company is currently evaluating proposals from four parties.

Apache, the operator of the liquefied natural gas (LNG) facility, plans to export natural gas from its Horn River shale gas play in northeastern British Columbia. “LNG is a big step forward for Apache,” added Steven Farris, chairman and CEO. “It allows us to monetize very large gas resources at LNG prices, which are gener-ally linked to crude.”

Horn River activity continues to domi-nate Apache’s Canadian operations with seven horizontal wells drilled in the Two Island Lake development area during the quarter. Those wells include four on the

Apache-operated 52-L pad and three on Encana Corp.-operated 63-K pad. In addi-tion, Apache drilled three horizontal wells in its Dilly area to hold expiring acreage.

Drilling efficiencies and resulting cost performances continue to improve with the average drill time now 19 days from spud to rig release, with an average drill cost of US$3.7 million per well for a 7,200-foot horizontal section, analysts heard during a telephone conference call focused on the company’s fourth-quarter results in 2009.

Although Apache hasn’t yet brought the wells on, it still believes it will be able to recover more than 10 billion cubic feet (Bcf) per well, said Crum. Completion operations on the 16-well, 70-K pad, which was drilled in 2009, began in January. In late April, Apache finished the mammoth fracture stimulation project associated with these wells.

In that time, the company has com-pleted 274 frac stimulations on those 16 wells, which works out to just over 17 fracs per well, with up to 22 stages on individual wells. It also pumped more than five mil-lion barrels of water and more than 100 million pounds of sand.

The project also involved conducting a huge micro-seismic acquisition program with 82 individual frac stages and more than 19,000 individual microseismic events mapped. The data will be used to optimize frac design and spacing, and well spacing on future pads. The first of the 70-K pad wells came on stream March 29 to start recovering frac water, and current produc-tion from the pad is now about 25 million cubic feet per day, said Crum. Ramp-up, though, has been severely limited by space restrictions while the frac spread remained on location. The frac equipment is currently being demobilized and all 16 wells should be on production by early July, he said.

In its conventional business units, Apache drilled a total of 42 development wells result-ing in 38 producers in the first quarter. Natural gas activity included successful com-pletions at Zama, Kaybob, and Nevis.

Oil drilling activity was focused on House Mountain in northwestern Alberta where six new horizontal wells are produc-ing more than 1,100 barrels per day. An 18-well program in the Provost area also has delivered good results, including one well which tested at more than 500 bar-rels of oil per day in Apache’s proposed enhanced oil recovery project area.

In the first quarter, Apache posted its strongest earnings and cash flow since 2008, despite the weak market for North American gas, said Farris. The company reported net income of $705 million for the three months ended March 31, 2010, com-pared to a loss of $1.76 million in the first quarter of last year.

— DAILY OIL BULLETIN

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Apache drilled seven horizontal wells in the Two Island Lake development area in the first quarter.

Visit us at theGlobal Petroleum Show June 8th -10th, 2010Calgary, Stampede Park Booth #: 3750 (Outdoor)


British Columbia

Residents of Dawson Creek, B.C., could soon be cooperating with the oil and gas industry every time that a toilet is flushed. The city in northeastern British Columbia currently sells 20 per cent of its potable water for use in natural gas production. That practice would end if Shell Canada and the community agree to upgrade sewage effluent to industrial usage stan-dards.

“This effluent reuse plan will be the first of its kind in North America,” said Dawson Creek Mayor Mike Bernier. The city recently took requests for proposals for the project. Shell offered $9.7 million that would be used to pay for waste water treatment upgrades in exchange for 3,400 cubic metres (cu. m) of treated effluent per day.

“Shell has offered in their [request for proposal] to pay for that whole pump sta-tion to help get the oil and gas industry off of our clean, potable water,” Bernier said. ‘It’s a feather in their cap for sure, show-ing they want to be part of the region and making a difference in the environment in a positive way as well.”

The city’s eff luent currently under-goes treatment before being dumped into the Dawson Creek. A city recently came up with a plan to reuse this water to supply the oil and gas industry, but council decided it couldn’t make the $10-million investment needed to com-plete the project.

“Even though we know it’s a great idea, it wasn’t unfeasible,” Bernier said. “For them [Shell] to come forward and say they’ll help pay for it in order to make it happen, it’s a win-win for us.” Shell also proposed to construct a pipeline from the treatment facility to its Groundbirch field. The company estimates that will eliminate 85 trucks from the roads every day.

The company’s proposal also said the city could market and sell any of the daily 3,400 cu. m of treated effluent water it doesn’t use. It’s estimated that 600 cu. m per day could generate revenue in excess of $500,000 per year.

The city has budgeted $250,000 in the 2010 financial plan for design, devel-opment, and engineering of the project. It also committed to provide land for the

project and $150,000 a year for the facil-ity’s operating costs. Details on the project are still in development and a finalized contract was expected within two weeks, Bernier said in early April.

— CANADIAN PRESS

Dawson Creek and Shell negotiate sewage treatment deal

The city named for pioneering surveyor George Dawson has made a forward-looking water sale.

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British Columbia

Monterey Exploration Ltd. has announced a significant increase in reserves from year-end 2009, a $19.2-million Crown land acquisit ion at Groundbirch in northeastern British Columbia, and an agreement with AltaGas Income Trust to fund the construction of its Groundbirch natural gas plant.

At the April 21 Crown land sale, Monterey was successful in acquiring a six-section (100 per cent net to Monterey) contiguous land block located three miles south of its existing Groundbirch lands for $19.2 million. With this recent land acqui-sition, the corporation’s Groundbirch land-holdings now stand at 21 (19 net) sections, with a current drilling inventory of 105 (95 net) locations in the upper Montney alone.

GLJ Petroleum Consultants Ltd. pre-pared an independent resource assess-ment dated effective April 21, 2010, of all 21 (19 net) sections of Montney landhold-ings in the Groundbirch area. The best estimate of Discovered Petroleum initially in place net to Monterey in the upper Montney formation increased to 2.46 tril-lion cubic feet (Tcf), up 45 per cent from

the 1.7 Tcf best estimate provided in GLJ’s previous resource assessment dated effec-tive Feb. 28, 2010.

Reser ves at Grou ndbi rc h have increased to 101.4 billion cubic feet of gas equivalent (Bcfe) on a proved-plus-proba-ble basis, up 141 per cent from 42.1 Bcfe at Dec. 31, 2009. The current total includes 100.14 Bcf of gas and 211,000 barrels (bbl) of natural gas liquids.

Proved reserves at Groundbirch have increased to 45.9 Bcfe, up 156 per cent from 17.9 Bcfe at the end of 2009.

Total corporate reserves are now estimated at 142.5 Bcfe on a proved-plus-probable basis, up 63 per cent from year-end 2009. Proved reserves are now estimated at 67.1 Bcfe, up 59 per cent from year-end 2009.

Monterey has entered into an agree-ment with AltaGas whereby the trust will fund the construction cost of Monterey’s 28 million cubic feet per day (MMcf/d) Groundbirch natural gas plant at 6-19-80-20W6 estimated at $28 million. The 6-19 Groundbirch gas plant has all required regulatory approvals in place,

site clearing and surface preparation has been completed, and field construc-tion is expected to start in August. While Monterey’s Montney gas is sweet, the 6-19 Groundbirch gas plant is being con-structed to process sour gas, which is commonly found in this area in other pro-spective formations such as the Doig.

Monterey said next year’s average daily corporate production with the 6-19 Groundbirch gas plant on stream prior to the end of the fourth quarter of 2010 is estimated to range between 4,500 to 5,500 barrels of oil equivalent per day (boe/d), with associated operating costs of approximately $6 to $6.50/boe and a capital expenditure program of between $25 million to $35 million.

To date, Monterey said it has success-fully drilled and completed three horizon-tal wells at Groundbirch:• The 4-30-80-20W6 well (100 per cent

net to Monterey) tested at approxi-mately 9 MMcf/d, with a flowing well-head pressure of 1,000 psi after 48 hours of continuous production testing in November 2009.

Monterey increases reserves at Groundbirch and acquires more land


British Columbia

• The 2-21-80-21W6 well (100 per cent net to Monterey) tested at approximately 7 MMcf/d, with a flowing wellhead pres-sure of 520 psi and 60 bbl per hour of frac fluid after 34 hours of continuous production testing in March 2010.

• The 13-27-80-21W6 well (75 per cent net to Monterey) tested at approximately 6 MMcf/d, with a flowing wellhead pres-sure of 450 psi and 50 bbl per hour of frac fluid after 48 hours of continuous production testing in March 2010.

In addition to the three horizontal wells drilled at Groundbirch, Monterey has drilled two vertical stratigraphic test wells. The 3-25-80-20W6 well (100 per cent net to Monterey) was drilled in February 2009 and the 16-31-80-21W6 well (75 per cent net to Monterey) was drilled in February 2010. These strati-graphic wells were not completed in the Montney formation and there are no reserves assigned to these wells; however, the data from these wells was used by GLJ in its resource assessment.

Reserves booked to Groundbirch are based on the drilling and completion of a total of 20 (17.5 net) wells, consisting of 16 (14.75 net) horizontal Montney wells, inclusive of the 3 (2.75 net) horizontal wells previously drilled and completed by Monterey, and 4 (3 net) vertical Doig wells.

At April 1, 2010 the future devel-opment capital for such reserves is $74 million, which now excludes the con-struction cost of the 6-19 Groundbirch gas plant. Monterey’s board of directors has approved a 2010 capital expenditure program totalling $35 million, net of the $10-million non-core asset disposition of which 100 per cent of the approved expenditure program will be allocated towards exploration and development activities at Groundbirch. The corpora-tion’s base production is expected to decline modestly and average 1,600 boe/d for 2010.


Monterey has a current inventory of 105 drilling locations in the upper Montney alone

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British Columbia

Progress Energy Resources Corp. has increased its Montney production from approximately eight million cubic feet per day (MMcf/d) of natural gas at the beginning of the year, to approximately 30 MMcf/d, with over 20 MMcf/d targeted to flow through its recently commissioned facility at Town South in British Columbia.

Production at the Town South develop-ment project was successfully brought on stream in late March. The company drilled and brought on stream four additional horizontal wells in the first quarter in the Town South area with five-day sustained test rates ranging between 4 MMcf/d and 7 MMcf/d each.

Progress constructed and commissioned a 25 MMcf/d compression and dehydration facility and a central distribution system for frac fluids at a cost of $8.5 million.

Based on the success of the first phase of development, Progress expects to com-mence the expansion of its recently com-missioned Town South facility in the third quarter. The expansion includes the installation of two additional compressors to double the capacity of the plant to 50 MMcf/d at an estimated cost of $5 million.

Progress estimates the internal risked rate of return on its Montney project to be approximately 40 per cent at a natural gas price of $5 per gigajoule and assuming 4 MMcf/d 30-day initial production rate and four billion cubic feet recoverable at a per-well cost of $6.5 million.

The horizontal wells were drilled a nd completed for approx i mately $6.5 million per well in the Town South area. Multiple opportunities have been identified to reduce costs to $6 million per well, Progress said.

The company has made headway in reducing drilling times for the horizontal wells to less than 30 days with one well being drilled in a record 26 days for a Montney well in this area. The horizontal wells were completed consistently using slick water fracture stimulations with six to nine fracs per horizontal leg. Eight to ten additional horizontals are expected to be drilled in the greater Town South area prior to year-end, Progress said.


Progress rapidly builds up its Montney production

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Increased production and higher crude oil prices sent ARC Energy Trust’s first-quarter earnings soaring to $139.4 million from $22.5 million a year earlier, while cash flow and revenues were also vastly improved year over year. Production vol-umes for the quarter averaged 67,209 bar-rels of oil equivalent per day (boe/d), an increase of four per cent compared to the first quarter of 2009.

The trust said the majority of the increase in production was a result of an acquisition that closed late in 2009, with the remainder attributed to increased output from the greater Dawson area. ARC continues to expect full-year average production between 70,500 and 72,500 boe/d, with the planned start-up of a trust-operated gas plant at Dawson in the second quarter.

Cash flow from operating activities increased by 28 per cent in the first quarter of 2010 to $158.7 million from $124.3 mil-lion in the first quarter of 2009. Increases in Crown royalties and a decrease in cash gain on risk-management contracts were more than offset by the 35 per cent ($13.45/boe) increase in commodity prices and a four per cent increase in production relative to the first quarter of 2009.

Capital expenditures, excluding acquisitions and dispositions, totalled $128.3 million in the first quarter of 2010, compared to $97.2 million in the same period of 2009. This amount was incurred on drilling and completions, geological, geophysical, and facilities expenditures.

Of the total amount spent in the first quarter, $59.7 million was spent on ARC’s resource plays, including $41.4 million for the Montney resource play in northeastern British Columbia and $14.9 million for the Cardium resource play in Alberta.

A total of $53.6 million was spent on ARC’s conventional oil and gas properties, $4.1 million on enhanced oil recovery (EOR) initiatives, and the balance of $10.9 million was spent on leasehold improvements for the trust’s new office space in downtown Calgary. Total capital expenditures are fore-cast to be $610 million in 2010.

The trust’s activities in the Dawson-area Montney play included drilling 14 horizontal wells and 3 vertical wells. Four horizontal wells were completed during the quarter. ARC also incurred $3.9 million of capital expenditures on the construction of its Dawson Phase 1 gas plant during the first quarter.

From inception to March 31, 2010, the trust has spent $61.5 million on the gas plant. Subsequent to quarter-end, con-struction and commissioning of the gas plant was completed with start-up proce-dures now underway. Sales gas was antici-pated to be flowing through the plant by the middle of May. ARC said it currently has enough wells awaiting tie in to the gas plant to fill it to its 60 million cubic feet per day (MMcf/d) per day capacity within two weeks of plant start-up.

During April 2010, ARC submitted an application for the Phase 2 portion of the Dawson gas plant to the British Columbia Oil and Gas Commission. Phase 2 consists

of the construction of a second 60 MMcf/d train at the Dawson gas plant and, if approved, is anticipated to increase the plant processing capacity from 60 MMcf/d to 120 MMcf/d. Phase 2 is expected to be completed in the first quarter of 2011.

ARC spent $14.9 million during the first quarter at the Pembina Cardium field, principally on the drilling of five horizon-tal wells and two vertical wells. Two of the horizontal wells and both of the vertical wells were in the early stages of comple-tion at quarter end, with early indications suggesting that these will be average hori-zontal wells for the area.

The trust also drilled one horizontal Cardium well and completed two horizon-tal wells drilled in the fourth quarter of 2009 in the Garrington area. Thirty-day initial production rates for the completed wells averaged just over 100 boe/d.

ARC expects to spend at least another $40 million during the remainder of the year to further outline potential for the recovery of significant incremental oil vol-umes through the application of horizontal drilling and completion technology.

The trust also spent $4.1 million on EOR initiatives. Work on the Redwater CO2 pilot project continues and both the CO2 injection and oil production facilities are operating. Results to date are encouraging, but ARC anticipates that it will take until later in 2010 to determine to what extent the pilot has been successful in mobilizing incremental volumes of oil.

While the pilot project may indicate enhanced recovery, the outlook for crude oil prices and the cost and availability of CO2 will be determining factors in ARC’s ability to achieve commercial viability for a full-scale EOR scheme at Redwater.


Production boost and higher prices increase ARC’s earnings

ARC spent $61.5 million to build its Dawson gas plant, which is now in operation.

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NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY

Northwestern Alberta/Foothills

APR/09 APR/10


APR/09 APR/10


APR/09 APR/10



At the cyclic steam-stimulation bitumen pilot, the second cycle of the L1 well is being produced.

North Peace focuses on completing Peace River bitumen pilot project

North Peace Energ y Corp. invested $13.9 million during 2009, focused on the completion of pilot construction and pilot operations on Peace River bitumen acreage and drilling programs.

The company reported a net loss for the year of $2.76 million on minimal rev-enues. Production for 2009 averaged 44 barrels per day (bbl/d).

“During 2009, we made very sig-nificant strides in the development of our project. We completed construction of the pilot facilities, initiated opera-tions, and achieved the very signifi-cant milestone of first oil in May. Most importantly, we have advanced our understanding of the resource and mod-ified our steaming strategy to the point where we have already achieved a com-mercial SOR [steam-to-oil ratio] on our L1 well,” said Louis Dufresne, president of North Peace, in a news release.

At the cyclic steam-stimulation bitu-men pilot, the second cycle of the L1 well has now been on production for 21 weeks.

The cycle’s SOR, which continues to decrease as production is maintained, is now approximately 4.4, which repre-sents a 45% improvement over the ini-tial cycle.

For comparison purposes, the com-pany said its SOR, when adjusted for heat content of injected steam, equates to a steam assisted gravity drainage (SAGD) SOR of 3.7, which is equivalent to the current industry average of 3.7 for existing SAGD projects in commer-cial operations.

T he product ion rate to date for the cycle is 29 bbl/d over a period of 26 weeks, which includes both steam injection time and production time.

The revised steam injection strategy on the L1 well is accessing the resource

more eff iciently and is result ing in significantly improved SORs, the com-pany said. The next cycle will use the same strateg y w it h a larger steam slug. The purpose of this next cycle is to demonstrate repeatability, but also has the potential for further improved SORs and increased daily oil rates.

The L2 well was on production for six months and is now shut-in for a pump change. Prior to the pump change the well will be converted to steam cir-culation to gather additional injection and production data which will help to determine the steaming strategy for the well’s second cycle.

During 2009, Nor th Peace com-pleted pilot construction in the f irst quarter, initiated first steam on the L1 well in January and achieved first oil production from the pilot in May.

It produced 16,000 barrels (bbls) from the L1 and L2 wells during the year.

The company also completed its winter drilling program at Red Earth, which consisted of an additional 10 delineation wells to bring the total well count to 27 delineation wells.

North Peace said it also drilled five conventional exploration wells outside the Red Earth area.

Three wells (1.6 wells net to North Peace) of t he explorat ion prog ram were successful, resulting in 177,800 bbls of proved-plus-probable reserves and a net-present value before tax of $3.7 million.

The company said its current work-ing capital is approximately $4 million.

N o r t h P e a c e c o m p l e t e d a n $11.6-million financing on June 23, 2009, issuing 21.1 million common shares.

The company has announced a stra-tegic review and has entered into an agreement to sell a portion of its drill-ing royalty credits.

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Seaview Energy Inc. has successfully drilled and cased its first horizontal well in Wapiti, targeting an early-stage light oil resource play in the Cardium formation.

The horizontal well has been com-pleted with a 10-stage multi-fracture completion and is currently flowing on cleanup, said the junior in releasing its fourth quarter 2009 results. Seaview has assembled a sizable land position offset-ting the horizontal well with exposure to 11.5 (6.5 net) sections of land on the new exploration play. The Cardium formation in Wapiti is known to produce both oil and natural gas regionally, but to date has not been developed using horizontal wells with multi-frac completion technology, according to Seaview.

Cash f low and revenues were up sharply in both the 3 and 12 months ended Dec. 31, 2009, but so were the losses, as Seaview recorded a net loss of $2.37 million (four cents per share) for the fourth quarter and a loss of $9.61 million (16 cents per share) for the year (see tables).

Despite the challenges of volatile commodity prices and weak capital mar-kets due to the global economic crisis, the company achieved record production levels of 2,729 barrels of oil equivalent per day (boe/d) in the fourth quarter, its ninth consecutive quarter of growth since inception in the fourth quarter of 2007. Production for the year of 2,321 boe/d was more than double the 2008 average of 1,077 boe/d.

The company is forecasting aver-age daily production of more than 3,200 boe/d for 2010 and has a hedging pro-gram in place that provides for downside

protection on 48 per cent of forecast aver-age production this year.

Seaview’s management team contin-ues to focus on consolidating high-quality assets within its core areas with significant exploration and development opportuni-ties. In 2009, it successfully closed five property acquisitions, further consolidating core assets in the Peace River Arch. In the fourth quarter, Seaview purchased assets in four separate acquisitions for a total of $3.8 million. Each of the minor property acquisitions added high working-interest follow-up drilling locations based on the successful third-quarter drilling program.

Seaview drilled 11 (nine net) wells in 2009 at a 73 per cent success rate. In the Peace River Arch, it drilled seven (6.6 net) wells with a 71 per cent success rate. Results of the 2009 drilling program yielded four (3.6 net) producing gas wells, one net potential gas well, and two net abandoned wells. One of the abandoned wells encountered the target reservoir but was abandoned due to operational prob-lems and was subsequently successfully re-drilled in the first quarter of 2010.

The forecast capital budget for 2010 is $11.5 million. Activity for the winter program to date in 2010 included drill-ing five (four net) wells at an 80 per cent success rate. At Clayhurst in the Peace River Arch, the company re-drilled one net Montney well which has been success-fully completed and tied in with initial rates expected to add more than 80 boe/d net in the second quarter. The company also drilled one net unsuccessful well at Boundary Lake.

At Wapit i, Seav iew dri l led t wo (one net) wells as part of the ongoing

explorat ion program targeting the Cardium formation. One (0.32 net) ver-tical gas well was drilled and completed testing Cardium gas similar to the verti-cal exploration well drilled in late 2009. Seaview has now completed the earning phase on the gas exploration portion of the program, earning 32 per cent in three sections of land on the Cardium natural gas resource play.

Seaview estimates current behind pipe volumes of more than 850 boe/d from seven (4.8 net) wells. It is anticipated that five (3.1 net) wells will be brought onstream during the second quarter, adding more than 250 boe/d net of new production. The remaining two (1.8 net) wells to be tied in have initial production of more than 600 boe/d, which may be tied in before year-end contingent on facil-ity access and improved gas prices.

Due in large part to its 2009 acquisi-tions, the company earlier reported a 49 per cent increase in total proven reserves to 7.14 million boe effective Dec. 31, 2009, as evaluated by Sproule and Associates using National Instrument 51–101 reserve definitions (Daily Oil Bulletin, Mar. 8, 2010). Total proved-plus-probable reserves grew to 11.07 million boe from 7.26 million boe. Seaview has a reserve-life index of 11.1 years based on total proved-plus-probable reserves and fourth-quarter production of 2,729 boe/d.

In 2009, Seav iew expanded its credit facility by 53 per cent to $52 mil-lion. Based on net debt of approximately $40 million at the end of the fourth quar-ter, the company has $12 million of avail-able credit capacity with which to pursue strategic acquisitions.

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NORTHEASTERN ALBERTA WELL ACTIVITY

Northeastern Alberta

APR/09 APR/10


APR/09 APR/10


APR/09 APR/10



Stelmach vows end to tailings ponds as ERCB approves more

Phot

o: Jo

ey P

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bny

Premier Ed Stelmach says technology exists to eliminate tailings ponds but deployment will take time.

one, but I know that within a matter of a few years we should be able to get there.”

As for the newly approved tailings ponds, Fort Hills plans to operate one tail-ings pond with a tailings storage capacity of 322 million cubic metres, which will operate for approximately 22 years, with a plan to dry tailings to a trafficable sur-face in compliance with the directive, the board said.

The ERCB has imposed two conditions focusing on technology testing and tail-ings management in its approval of the Fort Hills tailings plan. Suncor Energy Ltd., UTS Energy Corporation, and Teck Limited are partners in the Fort Hills project.

The ERCB has placed six conditions on its approval for Syncrude’s Mildred Lake site, located about 40 kilometres north-west of Fort McMurray, Alta. The site currently deposits tailings in five tailings areas. These areas have a fluid fine tailings inventory of 430 million cubic metres and are scheduled to be returned to a traffic-able surface in 2016, 2020, and 2023, with the Mildred Lake Settling Basin scheduled for return to a trafficable surface in 2060.

The board has placed six conditions on its approval for Syncrude’s Aurora North site, located about 80 kilometres north-east of Fort McMurray. The site currently operates a single tailings pond with a cur-rent fluid fine tailings inventory of 75 mil-lion cubic metres, which is scheduled to be returned to a trafficable surface in 2037. Syncrude is in the design stage of a com-posite tailings plant at Aurora and plans to have this plant operational and in compli-ance with the directive in 2014.

The Syncrude plans as filed on Sept. 30, 2009, did not fully meet ERCB require-ments, the board said, adding that consul-tations between Syncrude and the ERCB have seen significant improvements to the company’s plans.


A day after Premier Ed Stelmach said wet tailings ponds should be eliminated, the Alberta Energy Resources Conservation Board (ERCB) gave conditional approval for plans by the Fort Hills Oil Sands Project and Syncrude Canada Ltd. with dates for construction, use, and closure of fluid tailings ponds.

The tailings plans are the first of those submitted to the ERCB by six oil-sands operators in September 2009. Under directive 074, operators are required to prepare tailings plans and report on tailings ponds annually, reduce fluid tailings through fines captured in dedicated disposal areas, and convert fines into trafficable deposits which are ready for reclamation five years after deposits have ceased.

During a media scrum on April 22, the Alberta premier said he’s aiming to ensure tailings ponds are eliminated. He

also said that Hollywood director James Cameron should come to see the develop-ment in northeastern Alberta. Cameron, who directed the movie Avatar, has pub-licly criticized the oilsands. “He, unfor-tunately, perhaps was led to a conclusion without all of the information being pre-sented,” the premier said.

“Our goal is to ensure that we elimi-nate tailings ponds. That’s what people are focusing on and that’s the direction we’re taking,” Stelmach said. “It can’t be done overnight, but we know that the technology is there to start that process and we’ll be doing that. We’re going to have to force, and when I say force, we’re going to get more aggressive in working with companies in…open-pit mining to move to either dry tailings or develop that resource without wet tailings ponds.”

When pressed again for a timeline, the premier replied, “I can’t give you a definite



Mullen Group Ltd. says its wholly owned operating subsidiary Canadian Dewatering L.P. has been awarded a major contract by Suncor Energy Inc. as part of the company’s new approach to tailings management at its oilsands mining operations. Work is scheduled to begin in mid-2010.

“This is an important new piece of business for our organization, one that expands the service offerings Canadian

Dewatering provides to one of our larg-est customers. Being chosen by Suncor to manage the design, build, and com-missioning of a state-of-the-art Thin Fine Tailing Barge System specifically to support Suncor’s initiatives related to their tailings reduction operations has our entire organization excited and engaged,” said Dale Marchand, president of Canadian Dewatering.

Mullen Group first invested in the pumping, water management, and dewatering business in 2004 with the acquisition of Northern Underwater Systems Ltd. In 2006, Mullen Group acquired Canadian Dewatering based out of British Columbia, which was one of the largest providers of pumping and water management services in western Canada.


Mullen Group subsidiary wins Suncor tailings contract

Connacher Oil and Gas Limited has com-pleted construction of its second steam assisted gravity drainage oilsands project at Great Divide in northeastern Alberta. Algar has a design steam generation capacity of 30,000 barrels per day (bbl/d), which at its long-term target peak operat-ing steam to oil ratio of 3 to 0, is antici-pated to facilitate production of 10,000 bbl/d of bitumen over a project life of more than 25 years.

The project was designed to allow for expansion to 34,000 bbl/d of bitumen pro-duction in subsequent years.

Major civil work at Algar, including construction of the plant site, access road and well pads, was completed in February 2009. Project field construction and fab-rication commenced on July 7, 2009. Drilling of the 17 steam assisted gravity drainage (SAGD) well pairs at Algar and concurrent construction of the steam gen-eration facility and oil processing plant were reportedly completed in 273 work-ing days, less than the 275 working-days target set out by the company.

Capital expenses are still being accu-mulated and won’t be final until after commissioning of the project. Connacher anticipates the total construction costs of Algar will be under its announced $375-million budget.

A total of 390 standard loads and an additional 175 large loads of material, skids, and component parts were trucked to the Algar site during construction. The project incorporated 1,900,000 kilograms of structural steel and 280,000 inches of welding on 8,800 spools. Overall, the project reportedly had an extremely low spool revision rate of approximately one per cent.

The project also incorporated 36 ves-sels, 84 heat exchangers, 52 tanks, and 190 pumps. Over 700,000 field and shop man-hours of employment were created during Algar’s construction, primarily in Canada. At peak construction, 400 work-ers were employed on site.

Connacher also announced that com-missioning of the Algar plant will com-mence immediately. It is anticipated that the commissioning process will take up to 30 days and will include tie-in of the three SAGD well pads to the steam-generation facility and oil processing plant. Also, the evaporators and all vessels will be tested along with the treating, instrumentation, and electrical systems. Commissioning of

the steam pipelines and SAGD well pads will follow.

The next step will then be the com-mencement of sequential injection of steam into Algar’s 17 SAGD well pairs. Connacher plans to steam the well pairs for approximately 90 days prior to the ini-tial production of bitumen. The process will be closely monitored to determine the optimum production startup date, based on individual well response.

As all wells will not be brought on stream simultaneously, the company anticipates ramping up bitumen produc-tion towards design capacity of 10,000 bbl/d by the second half of 2011.


Connacher completes Algar construction ahead of schedule

Phot

o: JJ

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Podl

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Connacher chairman Dick Gusella says Algar should reach 10,000 bbls/d by the second half of 2011.



While the differential between Canadian light and heavy crudes has widened in recent weeks, Peters and Co. Limited is forecasting narrower-than-historic levels in the longer term. “Aside from periodic fluctuations in the light-heavy differential, we believe that a narrow long-term differ-ential will prevail,” the investment banker says in an energy update.

“The narrower light-heavy differen-tial we experienced through 2009 and into early 2010 represents a long-term structural change in the Canadian heavy oil markets through 2015,” Peters pre-dicted. The investment banker attributes the recent widening in the differential to about 20 per cent due largely to a number of temporary market conditions.

In 2009, the Edmonton Par-Western Canadian Select differential averaged 12 per cent, down from 19 per cent in 2008 and historic levels of 30 per cent.

So far this year, the light-heavy dif-ferential has averaged approximately 10 per cent, reflecting the strong demand for Canadian heavy crude in the U.S. Midwest (PADD II) and the Gulf Coast (PADD III), where additional pipeline capacity has enabled increased exports into those markets.

In the longer term, Peters believes that the significant takeaway capacity and coking capacities available for Canadian heavy crudes will support a narrow differ-ential compared to its historic level. It con-tinues to forecast a 2010 differential of 15 per cent, rising to 20 per cent between 2011 and 2015.

Two new export pipelines, TransCanada Corp.’s 435,000 bbl/d Keystone and Enbridge Inc.’s 450,000 bbl/d Alberta Clipper, both into the U.S. Midwest, are expected to be in service by later this year. Pipeline fill is now under way after some delays that Peters suggests may have con-tributed to the slightly wider differential. Keystone will add another 155,000 bbl/d with an extension to Cushing, Oklahoma, next year.

Based on its updated oilsands produc-tion outlook, this capacity should be ade-quate to 2015, says Peters. In addition to the current excess pipeline capacity into the Midwest, proposed projects would significantly increase access to the Gulf Coast. TransCanada’s Keystone XL pipeline currently awaiting U.S. regulatory per-mits would transport 700,000 bbl/d from Hardisty to the Cushing area with 500,000 bbl/d to the Gulf Coast.

Also proposed are a 30,000 bbl/d expansion of the ExxonMobil Pegasus pipeline, the 150,000 bbl/d BP/Enbridge Gulf Access l ine, and the 400,000 bbl/d ExxonMobil/Enbridge Patoka to Beaumont, Texas, extension.

In its report, Peters attributed the wid-ening differential to increased oilsands production offset by a reduced demand for heavy feedstocks, as a number of Canadian and U.S. refineries have been going through seasonal planned turnarounds and in some cases, unplanned turnaround activity.

Continued weak refining margins continue to drive demand for the heavier feedstocks, according to Peters. Lloydminster coking margins continue to provide refiners with the greatest profitability compared to other feedstocks in the U.S. mid-continent region, providing refiners with the coking capacity relatively stronger margins in a weak refined product environment.

“Should demand for refined products increase significantly, refiners may elect to utilize light crude runs but, overall, the heavier barrels will provide these refin-ers with greater product yields and higher margins,” said the investment banker.


Peters and Co. forecasts a narrow heavy-light crude price gap

A Chinese energy giant is buying ConocoPhillips’s minority stake in the world’s largest oilsands venture for US$4.65 billion, as the Asian country seeks to quench its burgeoning econo-my’s thirst for resources. On April 12, ConocoPhillips said it had agreed to sell its nine per cent interest in the Syncrude Canada Ltd. partnership to subsidiar-ies of Sinopec International Petroleum Exploration and Production Co.

The deal should close in the third quarter of this year, pending approvals by the Chinese and Canadian governments, ConocoPhillips said. “We are pleased that [Sinopec] has recognized the value of this quality asset,” company chairman and CEO Jim Mulva said in a statement.

Sinopec had already grabbed a foothold in the oilsands through its 50 per cent stake in Total E&P Canada’s Northern Lights project. But the deal

with ConocoPhillips is China’s biggest move in the oilsands so far. It makes sense that Sinopec would want in on the Syncrude joint venture, said portfolio manager John Stephenson at First Asset Investment Management. “The big mar-kets are shifting east, rather than west. The West is in decline, the East is surging higher,” he said.

Some observers had pegged the most likely buyer of ConocoPhillips’s interest to be Canadian Oil Sands Trust, already the majority partner in Syncrude with a 37 per cent stake. “But I think every-body would have had to consider the Chinese as being interested parties as well,” said Lanny Pendill, an analyst with the Edward Jones brokerage in St. Louis. “They’ve made it very clear that they view the Canadian environment very positively from a political stability standpoint. We all know they’re trying

to lock up future supply of oil. It ’s not surprising.”

Syncrude, an oilsands mining opera-tion north of Fort McMurray, Alta., has a capacity of up to 350,000 barrels of oil per day. Imperial has a 25 per cent stake, Suncor has a 12 per cent stake, Nexen has a 7 per cent stake and Murphy Oil Co. and Mocal Energy each have a 5 per cent interest.

Another state-owned energy firm, PetroChina, said in August it would invest nearly $2 billion for a majority stake in projects controlled by Athabasca Oil Sands Corp. Edward Jones’s Pendill said he sees China continuing to invest in the oilsands through joint-venture arrange-ments like the Syncrude, Northern Lights, and Athabasca projects. “There’s going to be plenty of opportunities to be doing more of that going forward,” he said.

— CANADIAN PRESS

China’s Sinopec buys ConocoPhillips’s stake in Syncrude for $4.65B

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Husky Energy Inc. plans to increase capital spending on heavy oil. “We just acquired more reserves from Penn West [Energy Trust] on heavy oil,” said com-pany president John Lau. “We are looking at other M&A [merger and acquisition] activities for the heavy oil side. How much the company will spend on heavy oil this year hasn’t been decided yet and will depend on opportunities that arise, Lau said at the company’s annual meeting on April 20.

Current plans call for the drilling of 445 heavy oil wells this year. When Lau became Husky’s CEO in 1993, its heavy oil output was about 12,000 barrels per day (bbl/d). Today, it’s close to 100,000 bbl/d. Husky is the largest holder of proved reserves of Canadian heavy oil with 120 million barrels booked at the end of 2009.

“Something people ignore or forget about is heavy oil,” Lau said. In the fourth quarter of 2009, Husky’s heavy oil operating netback was $37.16 com-pared with $19.55 in the corresponding 2008 period. “For the year 2010, we will

be more focused on heavy oil, but more or less on the Saskatchewan side,” the Husky CEO added.

While the Calgary-based producer is reaping the benefits of strong heavy oil prices, profits at its Lloydminster heavy oil upgrader are being squeezed by narrow heavy oil differentials. Upgraders make money on the spread between the price of heavy feedstock and the price of their synthetic crude product.

L ast yea r, t he spread bet ween Lloydminster crude blend and West Texas Intermediate crude oil averaged only US$9.93/bbl—down by more than half from $20.30 in 2008 and $23.81 in 2007. Net earnings from Husky’s upgrad-ing segment plunged to $54 million last year from $246 million in 2008 and $268 million in 2007. The company cited the reduction in the upgrading differen-tial, which resulted from narrow heavy oil differentials last year.

However, Husk y ’s appet ite for upgrading isn’t diminished. Lau noted that even today’s differential of $11 or $12—although poor compared to recent

years—is much better than the $4 to $5 expected when Husky began operating the upgrader. “So it generated a lot of cash flow for us,” he said. Husky plans to expand the upgrader, which has a pro-cessing capacity of 82,000 bbl/d, in the medium or long term.

On a much larger scale, Husky is seek-ing a big partner for a joint venture to develop technology to realize the com-pany’s vast bitumen resource trapped in carbonate rock. Cracking the code for commercial bitumen production from the carbonates depends on technology devel-opment, and Husky, which “is very finan-cially prudent,” is looking for a major international company to share the risk, the reward, and technological expertise, Lau said.

At Sunrise, Husky has a 50-50 part-nership with BP plc for a planned thermal bitumen project in northeastern Alberta. Lau said that Husky and BP are still on track with their plan to decide by the end of the year whether to proceed with con-struction of the Sunrise megaproject.


Husky Energy plans to boost its heavy oil spending

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Oilweek, Oilsand Review, Oil and Gas7.0625” x 4.625”4-color



For the next decade, oilsands producers anticipate relatively narrow differentials and high bitumen prices. First, there is ample pipeline capacity from western Canada into the United States. Second, higher demand for heavier slates of crude is coming in the short term from U.S. Midwest refinery expansions and later on from Gulf of Mexico refineries.

Transportation availability stems in the short term from the more moderate pace of oilsands development. By 2013, significant volumes could potentially be heading as far as the Gulf of Mexico, where heavy crude markets already used to handling heavy crudes are eager for an additional source of supply to replace the declining volumes of Venezuelan and Mexican crudes.

Both TransCanada Corporation’s 435,000-barrel-per-day (bbl/d) Keystone Pipeline from Hardisty to Wood River/Patoka, Illinois, and Enbridge Inc.’s 450,000 bbl/d Alberta Clipper pipeline from Hardisty to Superior, Wisconsin, are expected to be in operation by the end of this year.

Combined with the existing Enbridge mainline, Express Pipeline and Kinder Morgan Canada Inc.’s TransMountain pipeline to the West Coast, producers will have access to 3.35 million barrels per day (MMbbl/d) out of western Canada, far more than production capacity.

In 2011, the Keystone extension will add another 155,000 bbl/d from Steele City, Nebraska, to Cushing, Oklahoma, extending its reach into southern PADD II, while Keystone XL, which would transport 700,000 bbl/d of Canadian crude from Hardisty to the Gulf Coast by 2013, already has National Energy Board approval in Canada and is waiting for U.S. approvals.

In the short term, the U.S. Midwest, the traditional market for Canadian bitu-men, will offer additional opportunities as several large-scale refinery conversions and expansions are underway to accom-modate heavier Canadian crudes. “There’s a good chance that when they start up, there actually will be a shortage of crude in the Midwest,” said Tom Wise, VP in the Calgary office of consultants Purvin & Gertz, Inc. “It was like that in the 1990s,

when the Midwest was importing heavy crudes from the Gulf Coast.”

This time, though, U.S. Midwest refin-eries likely will find it difficult to bring in crude from the Gulf because that area also will be short, Wise said. “There just won’t be enough to go around, and that bodes well for the heavy producer here at least for that period.”

“The U.S. Gulf Coast is the deepest heavy crude market in the world; it is the most liquid,” Harold “Skip” York, VP down-stream consulting—Americas, for Wood Mackenzie, said in an interview. “As long as Mexican and Venezuelan production continues to decline, it makes room for Brazil and Canadian barrels, plus we are going to have expansions [on the Gulf].”

Last year, the Canadian Association of Petroleum Producers’ forecast that total oilsands and upgrader production under a moderate growth scenario would grow to 2.57 MMbbl/d in 2015 and 3.33 MMbbl/d by 2020. The association will be coming out with a new forecast shortly, but early indica-tions are that it will be similar to last year.


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CENTRAL ALBERTA WELL ACTIVITY

Central Alberta

APR/09 APR/10


APR/09 APR/10


APR/09 APR/10



Daylight has reallocated capital from its natural gas program to its Pembina Cardium oil program.

Daylight calls its latest Cardium horizontal results “exceptional”

Daylight Resources Trust has announced what it calls “exceptional” results from the first series of nine (8.4 net) Pembina Cardium horizontal oil wells. The first well drilled at Tomahawk in the north Pembina area came on production during March at over 2,100 barrels of oil equiva-lent per day (boe/d) at 100 per cent work-ing interest (WI).

During its first month of production, this well produced over 31,000 barrels (bbls) of new oil resulting in an average calendar day producing rate of over 1,000 boe/d. With the recent installation of arti-ficial lift, this well is currently producing in excess of 1,200 boe/d.

The second Tomahawk well came on production during March and produced at an average initial rate of 290 boe/d (100 per cent WI). Two (1.7 net) additional wells drilled in Tomahawk have recently finished unloading their completion fluid

and are producing new oil at rates of 460 boe/d and 160 boe/d respectively.

Based on these initial results, Daylight believes that the north Pembina area of Tomahawk may well be one of the more highly prospective areas for the emerging

Cardium oil development, complementing the trust’s significant position at Brazeau on the southwest edge of the Pembina Cardium pool.

At Brazeau, Daylight has recently com-pleted its first series of horizontal Cardium oil wells, including the first well (100 per cent WI) which came on production at a rate of 470 boe/d. One (100 per cent WI)

further well has been completed and has flowed back 80 per cent of its load fluid at a rate similar to the initial Brazeau well. Three (2.8 net) additional wells have been drilled with completion operations cur-rently in progress.

In addition to the above wells, Daylight also has seven (3.8 net) additional Cardium horizontal wells in various stages of completion, tie-in, and production at Pine Creek. These wells have all encoun-tered the Cardium zone with expected geological results. The first Pine Creek well (13.5 per cent WI non-operated) has come on production with a very strong initial production rate of 350 boe/d. One additional well (27.1 per cent WI non-operated) is cleaning up its load fluid with the two remaining non-operated wells waiting on completion.

Daylight has commenced its operated program at Pine Creek with the drilling of three (three net) Cardium wells, all of which are finished drilling and are await-ing completion.

The trust said it continues to advance its knowledge and experience with the application of new horizontal drilling and completion technologies. It has increased the length and number of fracs applied to

Cardium horizontal oil wells as it pursues optimization of wellbore design.

Daylight has reallocated capital from its natural gas program to its Pembina Cardium oil program based on highly successful Pembina results to date and the current commodity price strength of oil versus natural gas. The trust has also elected to defer the on-stream timing of

Daylight believes the north Pembina area of Tomahawk may be one of the more highly prospective areas for the emerging Cardium oil development.


Central Alberta

Triton Energy Corp. has announced an Ellerslie liquids-rich natural gas discovery well in its Strachan/Ricinus core area of west-central Alberta and the acquisition of 15 sections of Crown land directly on the Ellerslie trend. The well was fracture stimulated on March 27 and is currently flowing 3 MMcf/d with 2 bbls/hr of frac fluid on fracture clean-up. The well is tied in and will be tested in-line once the final tubing string is snubbed into place.

The company said it confirmed its exploration concepts in its Strachan/Ricinus core area by deepening a sus-pended well 55 metres at 6-30-37-8W5.

A six-metre Ellerslie channel sand was dis-covered at 3,120 metres. Triton’s mapping indicates this Ellerslie discovery to be sig-nificant, as it is an extension of the highly productive Ferrier Ellerslie F pool located six miles to the northeast.

The 6-30 well is expected to be placed on production at 2 MMcf/d of raw gas plus 50 bbls/MMcf of natural gas liquids (approx. 365 boe/d of sales). Triton has an 83 per cent working interest in the well.

Triton said it is immediately com-mencing a second deepening opera-tion at the adjacent 14-29-37-8W5 well.

The 14-29 well is 100 per cent owned and is expected to encounter a thicker sand sequence based on 3-D seismic interpreta-tion. Additionally, Triton’s third explora-tion prospect on this channel sand system is licensed as a 100 per cent working inter-est 3,500-metre test well located ten miles south at Triton Ricinus 15-10-36-9W5 and is planned to spud in the second quarter of 2010.

At a highly competitive Crown land sale on March 24, Triton acquired 100 per cent working interests in 15 key sections of lands that it posted. Triton now has 20-net sections of land directly on-trend with the Ellerslie channel discovery. The Strachan/Ricinus Ellerslie lands with a large amount of gas in place per section are approved to be drilled at up to four wells per section on select lands.

The analogous Ferrier Ellerslie F pool has produced 70 Bcf to date from this Ellerslie channel with ultimate gas recovery forecasted to average 4.6 Bbcf per well. Triton noted its management team has considerable experience target-ing Lower Cretaceous deep-basin channel sands through a combination of geological and geophysical models.

The wells are expected to generate a risked 20 per cent rate of return at gas prices of approximately $3.50 per Mcf. Additionally, recent proposed changes to the Alberta Crown royalty regime are expected to enhance liquids-rich natural gas well economics. Other prospective zones in Triton’s Strachan/Ricinus core area include the Cardium, Viking, Glauconite, and Rock Creek.


Triton reports a liquids-rich Rich Ellerslie gas discovery

certain natural gas volumes from its first-quarter drilling program due to recent weakness in natural gas prices.

In addition to the Cardium activity, Daylight said it has been active in its natural gas resource play developments. Its first horizontal Nikanassin well was successfully drilled, with clean-up test rates from an eight-frac, 700-metre horizontal completion of greater than 7 MMcf/d. The well is tied in and is expected to come on production later in 2010 when natural gas prices are anticipated to be stronger.

Daylight plans to increase the length and number of fracs in future horizontal

Nikanassin wells as it optimizes the well-bore design based on this successful “proof of concept” for horizontal Nikanassin potential.

At Elmworth, Daylight continued its successful development of the Cadomin natural gas resource play. During the first quarter, the trust’s latest horizontal well (45 per cent WI) attained a first week calendar day initial production rate of 13 MMcf/d. Due to the strong production inflow from this well, the up-hole Cretaceous zones have not yet been completed.

Continuing with Daylight’s long-term strategy of counter-cyclical acquisition of

growth opportunities, the trust announced the acquisition of 40 sections of 100 per cent WI lands in its Elmworth area. These lands were acquired at recent Alberta land sales for $5.5 million and are on trend with several successful wells.

Daylight considers these lands highly prospective for both the Cadomin and the Nikanassin, increasing its land hold-ings in this key natural gas Deep Basin resource play area to over 400-gross (265 net) sections, with over 200-net prospec-tive sections in each of the Cadomin and Nikanassin resource plays.


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Following up its 6-30 liquids-rich well, Triton immediately began an adjacent deepening operation.

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Central Alberta

Flint Energy Services Ltd. has acquired all of the issued shares of PES Surface Inc. (PSI), a subsidiary of Paintearth Energy Services Inc., for approximately $7.3 million in cash and the assumption of $610,000 debt, subsequent to closing adjustments. PSI is a production-equip-ment fabrication company with a facility located in central Alberta.

PSI will provide the platform for Flint to add engineering and design solutions

for production equipment to Flint’s cus-tomers in western Canada. This wider range of services will include gas dehy-dration, dewpoint control, gas filtration, BTEX removal and incineration, oil dehy-dration, and process equipment design to match the production specifications of the field and formation it is designed for.

Flint has been a leader in the design and manufacturing of oil and gas produc-tion equipment across the United States

for a number of years. This facility and workforce will allow Flint to expand its production-equipment manufacturing ser-vices into Canada.

Flint said its extensive geographic foot-print and business-development team will be used to expand the sales and grow the busi-ness. The close tie to Production Services will allow for the design manufacturing and field installation of equipment, providing production solutions to customers.

Flint announces its acquisition of PES Surface

Alberta is continuing its run of solid land sale results as the crown auction on April 7 generated a bonus of $112.68 million, the third highest after six sales so far in 2010. The sale, the first of the provincial govern-ment’s 2010–2011 fiscal year, produced an average of $974.37 for 115,645 hectares. The same sale last year brought in just $6.25 million on 30,900 hectares, which worked out to an average of $202.28.

For t he f i rst s i x sa les of t h is calendar year, total bonus revenue rose dramatically to $567.07 million for 1.01 million hectares at an average of $559.26. To the same point in 2009, $62.14 million had rolled into government coffers at an average of $124.39 for 499,639 hectares.

The top bonus and per-hectare aver-ages were paid at 50-10W5 in the Pembina area as industry has been focusing on re-entering areas that have been heavily drilled but are being unlocked to a greater extent with new technology.

Nine lease parcels at 50-10W5 com-bined for a total bonus of $21.8 million, and featured the highest per-hectare aver-ages. Scott Land & Lease Ltd. plunked

down $5.03 million for the southern half and northeast quarter of section 21 at 50-10W5 for petroleum and natural gas below the base of the Belly River Group. The 192-hectare lease went for an average of $26,232, which tied with two other par-cels in the area for the land-sale high.

Scott also tendered the bonus high, paying $9.31 million for a 512-hectare licence parcel. The broker paid an average

of $18,193 for sections 22 and 27 at 50-10W5 for petroleum and natural gas below the base of the Belly River Group. Daily Oil Bulletin records show that Baytex Energy Ltd. rig released a well on March 16 in the Pembina area at surface location 16-2-50-10W5 with the Nordegg member listed as the terminating zone and gas as the objective.


Alberta land sale produces $112.7M in bonus revenue

The Pembina area is generating good revenue on the strength of Cardium re-entry prospects.

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Southern Alberta

APR/09 APR/10


APR/09 APR/10


APR/09 APR/10



SOUTHERN ALBERTA WELL ACTIVITY

Western Canadian light- and medium- crude production shows new lifeby Paul Wells

Average oil well output in Canada has jumped to 86 bbl/d from 60 bbl/d.

Canadian conventional light- and medium- crude oil production appears to be reversing its decline and individual well deliverability is on the upswing as exploita-tion of oil from low-permeability reservoirs like the Bakken and the Cardium ramps up, says a veteran petroleum consultant.

Robin Mann, chairman and CEO of AJM Petroleum Consultants Ltd., told the Dufour Energy Commodities seminar on April 14 that after being on the downward slide since the early 1970s, conventional crude oil output is holding steady and could even increase slightly.

“From about 1973–74 within Canada, we’ve been on a decline of conventional oil with the major increases in oil produc-tion and reserves in western Canada being heavy oil,” Mann said. “But from about 2006 to 2007, there’s been a definite flat-tening and maybe even an uptick with respect to conventional oil, and this is due

to a number of companies going out and starting some horizontal drilling in some tight, oily reservoirs.”

The Canadian Association of Petroleum Producers’ (CAPP) April crude report fore-casts 2010 conventional light and heavy crude production at 564,000 barrels per day (bbl/d), much the same as last year’s output level. This flattening halts a slide that saw conventional oil production drop to 564,000 bbl/d last year from about 593,000 bbl/d in 2008.

“The 2008 to 2009 decline is due to the natural reservoir decline. The increase from 2007 to 2008 is primarily from the Bakken,” said the CAPP VP of markets and oil sands Greg Stringham. “The 2010 [numbers] are very early in the year, so don’t represent the full year. However, given the level of oil drilling we’ve seen so far this year would suggest that oil will indeed recover.”

In March, the National Energy Board said it expects overall Canadian crude output to total 2.81 million barrels per day (MMbbl/d) this year, up from 2009 produc-tion of 2.73 MMbbl/d. However, the federal regulator expects output of conventional crude oil to decline about 0.4 per cent, to about 781,000 bbl/d. By contrast, pro-duction of synthetic crude from oilsands projects in Alberta will rise 11 per cent to 854,369 bbl/d.

Mann also noted that individual well deliverability for light and medium oil is benefitting from horizontal drilling and multi-stage fracturing and has shown a “sig-nificant increase” over the past two years. He said that from 1999 to 2008, well deliv-erability has fallen from an average first 12-month production rate of about 80 bbl/d to about 60 bbl/d, but is now bouncing back.

“Over the last couple of years, that average has gone up…mainly due to the increase in horizontal drilling in western Canada,” Mann said. “For 2009 the number actually is 86 bbl/d from a low of a little below 60 a couple of years ago.” Further, Mann said when he breaks 2009 light and medium crude well deliverability to output from vertical and horizontal wells, the impact of the newer technology becomes even more profound.

“That average 86 bbl per day is made up of an average vertical production of 45 bbl per day and average horizontal produc-tion of 121 bbl/d,” he said. “Remember, this is 12-month averages. This isn’t just initial production that comes on for three hours that some companies report—this is what our analysis is for a 12-month average.”

Mann noted that what has transpired in the light- and medium-crude space in west-ern Canada the past few years is mimicking the game changer that has been witnessed on the natural gas side with the explosion in shale gas production.


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Southern Alberta

For the second time this year, the Petroleum Services Association of Canada (PSAC) has raised its forecast for drill-ing activity. In a revised forecast issued on April 29, PSAC forecasts that opera-tors will drill (rig release) 11,250 wells in Canada this year, a 35 per cent increase over the final total of 8,350 wells drilled in 2009.

The number is up from PSAC’s initial forecast in November 2009 that 8,000 wells would be drilled in Canada this year and its January 2010 first-quarter update when it forecasted 9,000 wells. The latest forecast is based on average natural gas prices of $4.25 per thousand cubic feet at AECO and crude oil prices of US$82/bbl West Texas Intermediate

PSAC attributed its more optimistic forecast to three main factors, including the increase in the price of oil, the antici-pated royalty changes in Alberta, and the general boost in economic activity as the economy emerges from the global reces-sion. “At worst, downsizing has flattened out for petroleum service and supply com-panies,” said PSAC president Roger Soucy.

“And in pockets, companies are hiring people; pockets like pumping services and services related to shale development.”

PSAC is forecasting that 7,590 wells will be drilled in Alberta, a 31 per cent increase over final 2009 drilling levels. British Columbia is pegged at 560 wells, a two per cent decrease in drilling from 2009, while in Saskatchewan the number of wells will soar to 2,580 wells drilled, a 47 per cent increase over the 1,750 wells

drilled in 2009. Manitoba activity is esti-mated at 475 wells, more than double the 230 wells drilled in 2009.

However, Mike Mazar, a BMO Capital Markets service sector analyst, told PSAC’s mid-year update event that he’s less bull-ish. He told the industry crowd that although BMO is expecting total 2010 well completions in western Canada to increase from last year, depressed natural gas prices will continue to suppress drilling for

that commodity while reinvigorated crude oil drilling activity will not entirely make up for the shortfall.

“We’ve kept our [forecast] kind of around that 10,100 [wells completed] range, and a lot of that is because of our bearish-ness on natural gas,” Mazar said. “Sure, we understand and are cognizant of the fact that crude activity has been driving activity, but we’re just a little skeptical about what the visibility is going forward post-breakup.”

Mazar is less enthusiastic about 2010 activity levels than PSAC and some other analysts, but admitted to a pessimistic per-sonal streak. “I’m the guy who reads the last chapter of a new book I just bought first, so that in case I die and don’t get to the end, at least I can figure out how it ends,” the ana-lyst said. In his view, crude oil is reasonably valued in its current price range, but further increases upward are not in the cards.


Revised PSAC forecast calls for 11,250 wells during 2010

The association forecasts 7,590 wells for Alberta this year.

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Interest in the Del Bonita area along the Canada/U.S. border helped drive Alberta’s land sale on April 21, which drew total bonus revenue of $55.08 mil-lion at $790 per hectare (ha) on 69,718 ha. Thirteen lease parcels between 1-20W4 and 2-22W4 in the extreme southern part of the province drew over $18 million. O & G Resource Group Ltd. plunked down $2.84 million for a 2,560 ha lease parcel, which included several sections, at 1-21W4 at an average price of $1,110/ha.

Daily Oil Bulletin records show that Connaught Oil & Gas Ltd. licensed a well in March in the Del Bonita area at surface location 14-7-1-21W4, with the Livingstone formation listed as the terminating zone and oil as the objective.

C h r i s T he a l , a n a n a ly s t w it h Macquarie Capital Markets Canada, said the interest in this area stems from drilling activity in Montana. “[Rosetta Resources Inc., Newfield Exploration Company, and Quicksilver Resources Inc.] are chasing what’s being called the Alberta Basin Bakken shale,” he said. “Rosetta’s got a few wells into it. One

of the wells is only two miles from the Canadian border.”

According to Canadian Discovery Ltd., a geoscience information company, the his-torical exploration effort at Del Bonita has focused on oil in the Rundle Group and gas

in the Bow Island and Fish Scales sandstones associated with Sweetgrass Arch tecton-ics. None of these plays have generated the momentum necessary to sustain an explo-ration effort, a report said. Recent drilling south of the border has, however, re-ener-gized this area.

Operators on the Blackfeet Reservation in Montana have been developing a play analo-gous to the Bakken in North Dakota. Initial indications point to “significant discover-ies.” These postings appear to be the begin-ning of a northwards extension of this play. Canadian Discovery added that it appears the Del Bonita postings are primarily focused

on the Exshaw/Bakken formation and that there are indications of secondary resource play potential.

Meanwhile, the land sale bonus high of $4.52 million was tendered by Plunkett Resources Ltd., which paid an average of

$2,211 for a 2,048 ha licence at 46-15W5. Standard Land Company Inc. produced the per-hectare high of $5,178 for two separate, 256 ha lease parcels. Each also generated identical bonuses of $1.33 million at 35-7W5 at sections 28 and 29. It included petro-leum and natural gas below the base of the Cardium formation.

Alberta’s land sale revenue has now climbed to $622.16 million in 2010 on 1.08 million hectares at an average of $574.11/ha. To the same point last year, the province had attracted just $73.22 million in bonus bids for 585,353 ha, which worked out to $125.10/ha.


Del Bonita oil play in southern Alberta gets compared to the Bakken

Southern Alberta

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All but three drilling contractors in Canada had more operating days in the first quarter of 2010 than a year ago when drilling was in a major slump due to low commodity prices and weak capital mar-kets. Overall, Rig Locator records show 28,613 operating days booked by Canada’s drilling contractors for the three months ended March 31, 2010, up 38 per cent from 20,668 operating days for the same three months last year. The increase will partially offset the lower prices for drilling services in effect this year.

Canada’s two largest contractors—Precision Drilling Trust and Ensign Energy Services Inc.—not surprisingly showed the largest increases in operating days. Precision surged by 1,927 days or 36 per cent to 7,346 days, while Ensign rose 39 per cent or 1,350 days to 4,778.

After two years of increases due to a drop in shallow drilling and higher percent-ages of wells being horizontal, the number of days on average it took to drill a well in Canada declined in the first quarter to 9.34 days from 10.78 days a year earlier. The drop occurred only in Alberta and was most prominent west of the Fifth Meridian areas.

In Saskatchewan, it took on average 8.92 days to drill a well, up from 8.16 last year, while in British Columbia the drilling day count rose to 23.97 days per well from 22.42 days per well.

The top-three drilling contractors for the first quarter of 2010 were the same three that have dominated for the past few years: Precision Drilling Trust with 1,053 wells

and 1.58 million metres, Ensign Drilling Inc. with 909 wells and 1.08 million metres, and Savanna Energy Services Corp. with 723 wells and 766,232 metres of hole.

Precision was far ahead of any other contractor in Alberta, with 1.14 million metres drilled and was slightly ahead of Ensign in Saskatchewan at 241,733 metres (m) versus Ensign’s 236,796 m. Nabors Drilling finished the most metres in British Columbia (157,941 m, much of them for Shell Canada Ltd.). Trinidad Drilling Ltd. was busiest in Manitoba, where it was

employed by Tundra Oil & Gas Partnership and finished 68,654 m of hole.

Including 1,370 oilsands evalua-tion and test wells, Canada’s contractors drilled 5,004 wells and 6.5 million metres of hole in the first three months of 2010. Excluding oilsands evaluation and test wells, the well count was 3,634 wells and metres totalled 5.9 million.

Fleet util ization was highest at Crusader Drilling Corp. (nearly 79 per cent on its single rig), Fox Drilling Inc. (77 per cent utilization), and Eagle Drilling Services Ltd. (76 per cent for its six rigs). As measured by average metres drilled per rig owned, Technicoil Corporation topped the list in the first quarter with 18,217 m drilled on average by its five rigs in Canada. Crusader and Eagle Drilling ranked second and third. Savanna rig #412 drilled the most wells (44) during the first quarter.


Contractor operating days increase by 38 per cent in Q1

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Precision was far ahead of any other contractor in Alberta with 1.14 million metres drilled during the first quarter.

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Saskatchewan’s $190.1M land sale is dominated by Bakken interest

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Saskatchewan’s land sale revenue has rebounded this year with $229.58 million after two sales.

The Bakken light oil play continues to spark interest in Saskatchewan, helping the province take in $190.1 million in its April land sale. It was the second-highest total for an April land sale and interest in the southeastern part of the province was responsible for driving bonus revenue.

Saskatchewan Energy and Resources Minister Bill Boyd said the auction “dem-onstrates increased interest and activity in our oilpatch in 2010 after a somewhat slower year in 2009.” Daily Oil Bulletin records show 656 wells drilled in the province to the end of March, up 64 per cent from only 303 wells one year earlier.

T he auc t ion fe at u r e d 116,676 hectares (ha), which sold for an average of $1,629/ha. Last year ’s April sale attracted $11.68 mill ion on 34,155 ha, an average price of $342.20/ha. While the province expects industry interest to remain strong throughout

2010, revenues from upcoming sales are expected to be lower.

Saskatchewan’s land sale revenue has rebounded this year with $229.58 million paid for rights to 212,836 ha after two sales, an average of $1,078. To the same point last year, the province had generated $17.94 million on 67,104 ha at an average of $267.39. “We don’t expect the interest to be as high as this in upcoming land sales, but with a rebounding industry and the other spinoffs from its exploration work, we are looking at a very exciting year ahead for our oilpatch,” Boyd said.

The sale included 26 exploration licences that sold for $142.4 million and 286 lease parcels that attracted $47.7 mil-lion in bonus bids. The Weyburn-Estevan area received the most bids, drawing a bonus of $139 million. The highest price for a single parcel was $23.5 million, paid by Scott Land & Lease Ltd. for a 4,209

ha exploration licence near Oungre at 2-13 and 2-14W2, drawing an average of $5,584/ha. Neighbouring this, Windfall Resources Ltd. tendered a bonus of $16.23 million for a 3,083 ha licence at 2-14 and 2-15W2, which worked out to $5,267/ha.

Bulletin records show that Crescent Point Energy Corp., an active Bakken pro-ducer, licensed two wells in the last few months in the Oungre area, both with the Bakken as the terminating zone. One is at surface location 4-2-2-13W2, the second at 1-3-2-13W2.

The Kindersley-Kerrobert area pro-duced the second-most bonus revenue at $25 million. The province is seeing greater interest on the west side of the province in the Viking formation. Top price paid for a single lease was $3.95 million by Windfall for a 647 ha parcel situated partially within the Avon Hill Viking Sand oil pool six kilometres northeast of Kindersley. The parcel included sections four, nine and the southern half of section 16 at 30-2W3. The broker paid an average of $6,103/hectare for the parcel.

In the Swift Current area, the gov-ernment took in $23.2 million. The top bonus for a single licence in this area was $12.31 million by Scott Land & Lease for a 2,851 ha block two kilometres south of the Rapdan South Upper Shaunavon oil pool, two kilometres southwest of Frontier. The parcel includes several sections at 3-19 W3 and 3-20W3. The licence produced a per-hectare average of $4,321. The Lloydminster area, meanwhile, brought in $2.9 million in bonus bids.

The highest price on a per-hectare basis was $15,600. Canadian Coastal Resources Ltd. plunked down just over $1 million for the northwestern quarter of section 28 at 6-31W1, a 65 ha lease parcel near Redvers.


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Stealth Ventures Ltd. says it has signed a joint venture with MOI Resources Ltd., a Saskatchewan-based, private oil and gas company looking to expand into the Colorado Group of Shales resource play. “We’re excited to be entering into a partnership with Stealth and see a lot of potential in the Colorado. It’s a good time to be entering into the gas markets, as we probably wouldn’t have had this chance if gas was $10 per Mcf [thousand cubic feet],” said MOI Resources CEO Kerwin Mondor.

The Cretaceous Colorado group in the Western Canadian Sedimentary Basin is represented almost continuously in a 1,000 kilometres east-west profile. Of the over 250,000 wellbores that penetrate the Colorado, most have been drilled to target deeper horizons. Derek Krivak, president and CEO of Stealth, said there is more potential than his company would ever be able to manage on its own, “so we’re excited to be expanding our efforts with MOI.”

Further to Stealth’s initial downspacing approval by the Alberta Energy Resources

Conservation Board to proceed with eight wells per section on two sections of land in the Wildmere area, the company has added an additional 17 sections, bringing the total sections to 19, which are available for eight wells per section drainage on Stealth lands.

Fekete Associates Inc. completed extensive rate transient analysis on location 15-10-50-06W4, which had over two years of production data and showed ultimate well density will approach 18

wells per section (36 acre spacing) to ultimately drain the resource before interference is found. An additional 11 sections are currently awaiting decision by the board with the remaining Stealth acreage (more than 80 gross sections) in process with Fekete. With full-spacing approval, Stealth will have hundreds of locations available to the company for development.

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Ryland Oil Corporation advises that its wholly owned subsidiary, Pebble Petroleum Inc., has entered into a new farmout agree-ment with Crescent Point Energy Corp. Under the agreement, Crescent Point has agreed to spud a test well by June 30, sub-ject to rig availability, surface access, and regulatory approval, at a location of its choice on a three-section lease in the Flat Lake area of southeastern Saskatchewan acquired by Pebble in November 2009.

The test well, which has been licensed, will be a horizontal well which will test the Bakken formation. Crescent Point must pay 100 per cent of the costs to drill, complete and equip or abandon the test well to earn a 50 per cent working interest in the three sections comprising the lease as well as an additional 11 net sections of Ryland leasehold acreage.

If any wells are subsequently drilled on acreage in which Crescent Point has earned its 50 per cent working interest, each of Pebble and Crescent Point will be responsible for payment of 50 per cent of the costs of such wells and hold a 50 per cent working interest, subject to the provi-

sions of the operating agreement between the parties. Crescent Point will be the operator of the test well and the initial operator of all post-earning wells.

This is the fourth farmout agreement between Ryland/Pebble and Crescent Point, the first three having been entered by Pebble with TriAxon Resources prior to TriAxon’s acquisition by Crescent Point. Under the other agreements, Crescent Point has the right to earn a 50 per cent working interest in and to a total of approximately 81 sec-tions of Pebble acreage in the Flat Lake area by drilling a total of eight wells. The earn-in under those agreements is limited to the Bakken formation only. Drilling is ongoing.

Vancouver-based Ryland owns Crown leases and licences in southeastern Saskatchewan covering approximately 300,000 net acres along an 85-mile trend extending into the northwestern U.S., where the company owns an additional 12,184 net acres (20,647 gross acres). The Saskatchewan properties are held by Ryland's Canadian subsidiary, Pebble Petroleum.


Ryland announces a new farmout deal with Crescent Point

Ryland now has four farmouts with Crescent Point.

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Saskatchewan

Renegade Petroleum Ltd plans to spend $42 million to $44 million focused on development drilling, land sales, facili-ties expansion, and seismic work this year. About 75 per cent of that spending will be in southeastern Saskatchewan, predomi-nantly on the Bakken play. The remain-der of the capital expenditure program is anticipated to target the Viking play in the Dodsland pool in western Saskatchewan.

Renegade said its program is expected to result in 2010 exit production of 1,800 to 1,900 barrels of oil equivalent per day (boe/d) that will be weighted approxi-mately 95 per cent to light crude oil. Average output for the year is forecasted to generate approximately $19 million to $20 million of funds from operations using estimated prices for crude oil of $75 per

barrel West Texas Intermediate and $4 per gigajoule at AECO for natural gas.

During the first quarter of 2010, Renegade participated in four gross (two net) Viking wells in the Dodsland pool and drilled two gross (1.5 net) wells in its Hastings/Alameda core area in southeastern Saskatchewan, all with 100 per cent success.

In March 2010, Renegade (formerly Colonia Energy Corp.) completed an acqui-sition of a private company with assets based in the heart of the Dodsland Viking pool, which established an additional high-growth core area in Saskatchewan for the company.

Production fell a bit last year, to 145 boe/d from 161 boe/d in 2008, while profit sank. The company reorganized itself in the fourth quarter of 2009. As a result of

the acquisition of Duce Oil Ltd. and its working interest partners for approxi-mately $35 million as well as raising more than $46 million in equity, Renegade has positioned itself as a high-growth, light oil, Saskatchewan-based producer.

As of Dec. 31, 2009, Renegade’s gross proved-plus-probable reser ves base was 371,000 boe. Light and medium oil accounted for 76 per cent of the proved-plus-probable reserves base. Renegade’s gross proved reserves base was 194,000 boe. Proved reserves represent 53 per cent of the total proved-plus-probable reserves. Proved producing reserves represent 38 per cent of the total proved reserves base. Light and medium oil accounted for 95 per cent of the total proved reserves base.


Renegade repositions for Saskatchewan growth

W. Claire Energy Corp. has signed a letter of intent with PetroBakken to implement a field demonstration of the privately held company’s proprietary process for the cap-ture and monetization of the liquids-rich gas. W. Claire will provide the equipment and PetroBakken will provide access to the wellsite.

With operation scheduled to begin this summer, W. Claire plans to capture and compress solution gas that PetroBakken Energy Ltd. is currently flaring at one of its light oil wellsites in the Estevan area of southeastern Saskatchewan. Typically, the solution produced at oil wells and oil bat-teries is not tied into gathering systems. While the oil is being trucked to market, there is no way to handle the gas.

“We are compressing the gas, dehy-drating it, and putting it into a container, where it can be transported from the well-site to one of PetroBakken’s compressor stations where we will unload the con-tainer downstream of the compressor,” said Greg Loewen, president and CEO of W. Claire. “It’s just like trucking oil.” The container will hold about 150,000 cubic feet of gas, about a day’s production of solution gas from the well, he said.

Once the project is operational, pro-ducers will be charged a fee that will con-sist of a monthly flat fee in addition to a charge based on the volume of gas trans-ported. The fees will enable W. Claire to

achieve a reasonable rate of return, while also providing an opportunity for the pro-ducer to generate revenue for themselves. “They are essentially getting nothing for the gas now, so what we are trying to do is generate a new revenue stream for them,” Loewen said.

The solution gas will generate a signifi-cant revenue stream even with low natural gas prices because of the heavier hydro-carbons including propane, butane, and pentane. “That’s what’s really driving the economics of trying to conserve solution gas, especially in southeast Saskatchewan because of the high liquids content,” said

Loewen. “This wouldn’t work as well or maybe wouldn’t even be economic in the Lloydminster [heavy oil] area.”

While there are other areas of Alberta where capturing solution gas might work, W. Claire initially targeted southeastern Saskatchewan because of the high level of oil activity, he said. The company has been working on its solution gas capture project for the past 18 months, and with PetroBakken for the past two months.

Calgary-based Big Gas Compression will supply the compression for the

demonstration project, enabling W. Claire to provide a total well-optimization solution, said Loewen. Through Big Gas, it also has access to local technical staff who will service and maintain its equipment.

Once the final agreement is in place and the design is finalized, the actual start-up date will depend on order lead times for the equipment, he said. The company cur-rently is in the middle of financing to raise money for the project and once it has the money, it will order the equipment.

W. Claire also has been trying to imple-ment its technology overseas and has had a fair amount of interest but believed it was

important to get a project up and running in Canada. “It’s easier for people to see and it’s easier for the investors to get their heads wrapped around it,” Loewen said.

W. Claire estimates that 15 billion cubic feet of solution gas from oil wells is being burned every day around the world.The company says that its technology will allow producers to conserve solution gas from new oil wells from early on in the production cycle, while reducing the greenhouse gas effect of flared gas.


W. Claire signs letter of intent for solution gas project

W. Claire plans to capture and compress solution gas that PetroBakken Energy Ltd. is currently flaring at a light oil wellsite near Estevan.

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The requirement that Beaufort explorers be able to drill a timely relief well was revived in 2009.

Deepwater Horizon blowout will impact Beaufort Sea drilling reviewby James Mahony

In its scheduled review of drilling regu-lations in the Beaufort Sea, the National Energy Board (NEB) will take into account any lessons learned from the disastrous loss of a semi-submersible drilling rig in the Gulf of Mexico and the ensuing crude spill loss. Bruce March, CEO of Imperial Oil Limited, stressed at his company’s annual meeting that the Beaufort and Gulf are very different operating arenas.

On April 20, the Deepwater Horizon rig operated by Transocean Ltd. ignited and sank, killing 11 and creating a wild well that released an estimated 5,000 bar-rels per day of crude oil. In a letter dated April 28, the NEB gave notice to all inter-ested parties in the Beaufort that it plans to question the parties about that incident.

“In the Beaufort Sea, drilling condi-tions as well as the timeframe available [for a relief well] to be drilled are quite different,” March said after the company’s annual meeting in Calgary on April 29. “We’re not looking at year-round activity in the Beaufort. We’re looking at two to three months. There has been discussion about same-season relief well capability ever since Beaufort exploration started

in the 1970s and ’80s. There’s no written policy on that today.”

The requirement that companies drilling in the Beaufort be able to drill a timely relief well was revived in October 2009, when Imperial asked the NEB for an advance ruling on the company’s approach to same-season relief well capability. At that point, the NEB decided to formally review its policy in a written hearing.

March said Imperial and others could benefit from the findings of the current U.S. investigation into the Gulf of Mexico incident. “We think it would be the kind of thing we should [include in] the lessons learned from that, and then sit down with the NEB in terms of what the policy would be up in the Beaufort,” he told reporters.

Other producers active in the region have also asked to participate in the NEB hearing. The list includes Chevron Canada Limited, BP Exploration Operating Company, ConocoPhillips Canada Resources Corp., and MGM Energy Corp. The hear-ing has also attracted interest from those living in the Beaufort region, including the Inuvialuit Game Council, the Inuvialuit Land Administration (ILA), and the Tuktoyaktuk

Hunters and Trappers Committee, all of which have filed documents with the board.

In its filings, the ILA has suggested the NEB’s review of same-season relief well policy should examine not only that issue, but the broader question of preventing and remediating any uncontrolled release of hydrocarbons in the Beaufort. Like other aboriginal groups that have filed letters, the ILA underscored the importance of hunting and fishing for Beaufort-area residents. The Northwest Territories government will also participate in the board’s policy review.

The only non-Canadian participant will be the U.S. Minerals Management Service (Alaska region), a branch of the U.S. federal government that has asked to participate. (The U.S. and Canadian gov-ernments differ about where the border lies in the Beaufort Sea.)

At its annual meeting, Imperial broadly outlined plans to spend some $20 billion in Canada over the next five years. March said any funds allocated to the Mackenzie Valley Gas pipeline project would be “very modest.” Regulatory approval of that project has been delayed repeatedly since the 1970s.

The $20-billion program includes both phases of Imperial’s Kearl oilsands project, currently about 25 per cent complete, and further capital for Nabiye, the expansion of its Cold Lake heavy oil facility. The figure also includes “significant” sustaining capital for Syncrude Canada Ltd., including the opening of the facility’s south mine, March said.

“We’ve heard some expressions of con-tractor-manpower tightening [in the oil-sands], but we’re a long ways from where this industry was two or three years ago. We’re not even close,” March said. “When Shell Canada finishes their work this year, Kearl will be the only big project going in the oilsands.”

In northeastern British Columbia, Imperial has been active in the Horn River Basin, and March voiced satisfaction over the company’s recently completed winter drilling program, which saw 11 wells drilled, including two horizontal. “We’re still testing [the wells], but early returns are very, very promising,” he said.


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A hopeful Quebec gets ready to produce "gaz naturel"by lynda Harrison

The stars appear to be aligning nicely for a natural gas industry in Quebec, accord-ing to the president of the Quebec Oil and Gas Association (QOGA). André Caillé has previously headed up both the Crown power utility Hydro-Quebec and Gaz Metropolitain, the province’s natural gas distribution utility. “Quebec is changing. It’s going to be a fossil fuel producer now,” Caillé says.

The breakthrough well that excites Caillé was St. Edouard #1A, drilled in February by Talisman Energy Inc. in the Utica shale gas play. The well, which pro-duced more than 12 million cubic feet (Mcf) per day, was the fourth and final one under a farm-in by Talisman on lands owned by Questerre Energy Corporation.

“The well is commercial. Not at this week’s price, but at $4 or $5 we can pro-duce commercial gas. We are very, very much encouraged by the fact the gas is there,” Caillé says. “There’s no doubt about that.” He thinks the province can produce gas commercially when the commodity price is $4 at the Alberta border. “Before the gas gets out of the ground here, it’s already worth $1 an Mcf because there’s

no transportation cost associated with it from Empress to Montreal.”

The QOGA, formed in April 2009 with about 30 member companies, held its first conference last fall. Attendance of nearly 300 people was higher and from further afield—as far away as Europe and Australia—than expected. A second meeting is planned for October 2010. The Quebec government expects to table specific legislation for oil and gas, cur-rently covered in mining legislation, in the National Assembly in September.

Recently, the association successfully lobbied the provincial government to keep royalty rates at 10 per cent to 12.5 per cent, possibly the lowest in North America. A task force is working on “one-window shopping” for regulatory permitting, in the hopes that a prompt regulatory process will enable the province to compete with Alberta and British Columbia for investment.

Increased investment will encourage more drilling, which currently stands at about 10 wells per year with costs as much as $10 million per well. The QOGA is working to reduce that to $5 million per well. Another QOGA objective is to see

service companies develop in Quebec, but for the short term Caillé and other indus-try players expect to get rigs from western Canada and Pennsylvania, incurring large mobilization costs.

Quebec currently consumes about 200 billion cubic feet of gas per year, account-ing for 12 per cent of its overall energy demand. GazMet says when producers are ready, it will be ready. Marie-Noelle Cano, a GazMet spokeswoman, says increased sales will come from new residential con-struction, with one in five homes being equipped with gas-fired heating.

Caillé estimates that increased gas consumption at the expense of compet-ing fuels will lower carbon dioxide emis-sions by five or six per cent. Quebecers also know that gas’s environmental footprint is smaller than any other fuel sources, he notes. “A wellhead is nothing compared to an electrical [dam],” he says.

The province has no shortage of will-ing workers. “I cannot remember another industry that has proposed to create as many jobs in the region between Quebec City and Montreal,” says Caillé. “These are electricians, pipefitters, people that are looking for jobs now, and by Quebec stan-dards these are well-paid jobs. Many young people will be able to earn their living in the village where they were born.”

QOGA is working with a local college, Cégep de Thetford, to provide a training program for potential rig workers that could start as early as next year. “We need these people tomorrow,” said Caillé.

The province could certainly use the influx of cash a gas industry would supply. Le Soleil newspaper columnist Pierre Couture estimated gas royalties collected by Quebec could some day exceed $1 billion per year. According to Couture, the government is “desper-ately” seeking new revenue to balance its budget and to do that, the province will need an additional $5 billion in the next three years. “The discovery of a signifi-cant natural gas deposit in Quebec will forever change the face of public finances in the province,” wrote the newspaper.


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These ships are transporting elements of Encana’s Deep Panuke gas project offshore Nova Scotia.

ExxonMobil and Encana trigger offshore optimism in Nova Scotiaby Pat Roche

Only a few years ago, Nova Scotia’s off-shore faced a bleak future. Output from the Sable natural gas project was declin-ing and the only other discovery slated for development—the Deep Panuke gas project—was on hold. Now the outlook is decidedly brighter, largely thanks to a new evaluation by ExxonMobil Canada of old discoveries near its Sable Island project.

Construction of the Deep Panuke production facilities is to be completed this year and the roughly $800-million project is expected to be onstream in the first half of 2011. The operator, Encana Corporation, has drilled a disposal well and is currently re-completing the first of four production wells. The project has a design capacity of 300 million cubic feet (MMcf) a day, but the start-up rate from the four initial production wells will be roughly 200 MMcf/d, the company said.

Work is under way at Goldboro, N.S., to install three kilometres of onshore pipeline to connect the offshore pipeline installed last year with the Maritimes & Northeast Pipeline system.

Meanwhile, Ex xonMobil Canada has been evaluating unspecified old

discoveries near the Sable Island project for more than a year to determine if one or more of the offshore prospects may be economic to develop. The Sable Offshore Energy Project now includes six gas fields—Thebaud, Venture, North Triumph, South Venture, Alma, and Glenelg—near Sable Island.

Partners in the Sable project are ExxonMobil, Imperial Oil Resources, Shell Canada Energy, Pengrowth Corporation, and Mosbacher Operating Ltd. Ownership percentages vary with each licence. The eastern Sable Island Bank area includes undeveloped gas discoveries which are under various ownership arrangements.

ExxonMobil and its partners are “con-sidering the feasibility of bringing in addi-tional gas supplies to the [Sable project] from some undeveloped fields—including Glenelg and Citnalta—and potentially from additional prospects in the same general vicinity as these fields and flowline route corridors,” the company said in an environ-mental filing for a planned seabed survey.

The seabed survey would help identify hazards at potential wellsite locations and pipeline routes. Hazards could include

shallow gas, steep or unstable substrates, and seabed obstructions. Activities would include sonar scans, underwater videog-raphy, sediment sampling, and core sam-pling at each potential wellsite and along potential flowline routes.

Two-dimensional seismic data will be acquired within areas of roughly one square kilometre at each wellsite as part of the seabed survey. The entire survey, including the small seismic acquisition, is expected to take one to two months, and ExxonMobil hopes to complete the work this year.

Other details haven’t been disclosed, such as the full list of discoveries being evaluated and the number and location of potential wellsites and flowline routes. “We have said we are evaluating ‘sev-eral’ SDLs [significant discovery licences] to determine whether one or more may be economic to develop,” said Merle MacIsaac, an ExxonMobil spokesman in Halifax. “We haven’t quantified the size of any potential SDL development, nor have we quantified the resources we are dedi-cating to the evaluation.”

Recent Sable production, which has f luctuated with downtime for mainte-nance and enhancements, such as com-pression addition, typically has been in the 350–400 MMcf/d range. ExxonMobil Canada, as the operator, isn’t saying when the 10-year-old project would shut down if no additional gas comes onstream.

ExxonMobil is “looking at ways and technologies that could make the SDLs economic,” Glenn Scott, president of ExxonMobil Canada, said in a speech to a Nova Scotia oil and gas group in Halifax last year. But he cautioned: “It remains to be seen if SDL development is warranted.” Operations and maintenance spending on the Sable project exceeds $150 million in a typical year.

Still, just the fact that the operator is looking at extending the life of Nova Scotia’s only producing offshore project is reason for optimism. Nova Scotia waters hosted Canada’s first offshore oil project, Cohasset-Panuke, which produced from 1992 through 1999.


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International

Arthur Berman says shale plays are economically vulnerable to rapid decline rates and low gas prices.

Controversial geologist pans U.S. shale gas plays as likely losersby Pat Roche

Consultant Arthur Berman, a former Amoco geologist and an associate editor of the American Association of Petroleum Geologists Bulletin, has controversial views on the likely rate of production decline in shale gas wells. Last November, for exam-ple, World Oil refused to run one of his col-umns. On April 13, Berman was in Calgary, speaking to a large meeting sponsored by Packers Plus Energy Services Inc.

His Calgary presentation dealt strictly with U.S. shales. Berman says American reserve estimates are overstated by at least 25 per cent, while costs are grossly under-stated. “Unfortunately, based on what I’ve seen so far, they require peak market conditions to be commercial. Those peak market conditions have only existed for 18 months out of the last 15 years,” Berman states. “Companies that bet everything on shale plays…are going to have a signifi-cant competitive disadvantage throughout 80 per cent of the price cycle.”

Even so, in his judgement, shale gas plays are working for producers that are approaching them correctly. “And so I’m not against the plays,” Berman stresses. “What I am against is the sort

of one-size-fits-all approach to choos-ing locations, to deciding where to buy land, how to drill, and particularly how to drill and complete these wells.”

He believes shale gas plays are fraught with risk because no one knows how the wells will perform over many years. “We know very, very little about these plays that we’re spending so much time, energy, and money on.” Berman says. “We make some assumptions, mostly about decline rates…and that’s the basis for our enthusiasm.”

Beyond its implications for industry, this is important because public policy issues are being decided in the United States, Canada, and even Europe based on the assumption that there is maybe a 100-year supply of cheap gas, Berman says. “If that’s not true, then we have a problem.”

In the United States, companies often acquired hundreds of thousands of acres on very short-term exploration leases. “We get the leases and we announce success. We haven’t drilled any wells, but we know that the Barnett is supposed to have 30 [trillion cubic feet] of gas and my company has X per cent, and therefore, we publish

these resources,” Berman charges, refer-ring to much of the industry.

Because of looming lease expiries, companies were initially drilling to hold land, not where their scientists told them to drill. “And in the Barnett [a Texas shale play]—12,000 wells later and probably $35 [billion] or $40 billion—we find the sweet spot by the Braille method,” Berman says.

In the Barnett, on average, the geolo-gist estimates that 75 per cent of the estimated ultimate recovery (EUR) is achieved in the first five years. He focuses heavily on the Barnett because it is the only shale play with hundreds of wells that have produced for five or six years. “We’ve looked at about 2,000 wells and we see about 1.25 Bcf [of EUR per Barnett well] as being the most likely case. You need about 1.5 Bcf to break even [even if gas prices were almost double current levels],” Berman claims.

That analysis is criticized because much of Berman’s production assess-ment comes from older wells, and newer wells are potentially more productive because technology constantly improves. “I believe that we are getting better in certain areas of the play,” the consultant says, but overall “the second half of 2008 was the worst…for EURs in the Barnett shale, ever.”

Berman calculates that the Fayetteville and Haynesville shale plays appear to suffer from similar difficulties as the Barnett. “Twelve per cent of the wells that I’ve looked at [in the Haynesville play] will reach that economic threshold,” he says. “So this is kind of a development scenario where your failure rate is 90 per cent.”

The consultant feels shale gas plays in the United States are being approached with a gold-rush mentality that “almost ensures the victory of expediency over any kind of science, technology, or portfo-lio management. These plays make abso-lutely no sense at current gas prices. And the way that operators are drilling like mad—at least in the U.S.—ensures that the prices are going to stay low and we’re going to destroy more capital.”



On the Job

JOBonthe

CArEErS iN ThE OiLPATCh

What do you do?My background is in carpentr y, par ticularly concrete forming and scaf folding . For the past seven years, I ’ ve wor ked for Norseman’s Por table Building division, f irst as a field crew leader and then as a construction superintendent. Eight months ago, I took over managing all of the construction operations.

how is business these days?The pace is really picking up. Especially here in Alber ta and Saskatchewan, there’s activit y at pret t y much all of the big oilsands sites. Last year, our division was a little slower, with many companies putting a hold on their new development plans. it was nice to be able to spend a little more time at home. We’re busier now, but we are still selective in hiring competent, hard workers.

What are the most challenging aspects of your job?In the field, it ’s weather—working outside, par ticularly when it ’s minus 30 or colder. Sometimes it gets so windy we can’t use the trucks to pull the fabric covers over the steel framework. Psychologically, it can be hard to spend so much time away from home. We have four kids—seven straight years of diapers and now they’re all in sports. Fortunately, my wife Jenna is amazing , and my present position allows me to spend more time at home.

What are some key indicators of quality for this type of product?One indicator is the use of steel in the building. Our structures have almost t wice as many steel tr usses as many of our competitors. We’re also one of the very few membrane-structure companies in Canada that control the entire process, from design and fabrication (we make our own steel frames and membrane covers ourselves) to installation and after-sale service.

in March of this year, one of your competitors filed for bankruptcy protection. reportedly, there have been problems with engineering and consequent liabilities for repairs. how do the difficulties facing that company affect norseman?Customers, both our own and others, have been calling us about it and that ’s natural under the circumstances. For tunately, N o r s e m a n h a s t h e b e s t s a fe t y r e co r d i n t h e m e m b r a n e -structure industry. Our products have always been engineered to meet the strict standards of the National Building Code of Canada and even beyond. Not one of our engineered buildings has ever collapsed. And our focus on safet y ex tends to our own people. Field erection of our structures has always been handled by Norseman-trained personnel, and we’ve never had a major accident during installation.

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Tools of the Trade

A LOOK AT NEW TEChNOLOGiES

TOOLSOF ThE TrADE PatchMap

information supplied by: robert coutts, President of skyBase geomatic solutions inc.

Who is skyBase Mapping?SkyBase Mapping [SkyBase Geomatic Solutions inc.] morphed from a contract oilfield-survey company into a digital- and paper-mapping company that primarily creates mapping for Garmin software and GPS units. For the oil and gas sector ‘patch,’ we produce PatchMap. For weekend ‘bush warriors’, there’s BushMap, a less expensive product. Then came AgMap for anyone servicing the farm sector across the Prairies, and also a web-map service for automated vehicle location companies.

What is PatchMap?PatchMap is a set of digital maps containing all of the oil and gas field locations ever applied for, along with the most complete road dataset available. PatchMap presently covers all of Saskatchewan, Alberta, and northeastern British Columbia. The maps can be used in Garmin GPS units, desktop computers, and notebooks for anything from normal search and navigation, to job bidding and crew dispatching. Small views of the map are increasingly being seen in field reports. The ‘moving map’ personal computer [PC] version [utilizing nroute] allows for the most complete usage, but most people are just interested in ‘getting there,’ so they gravitate to the GPS version. We have about 1,000 PC customers, and between two and three times that for GPS.

What are the competitive advantages of PatchMap?No other product is even close to being as detailed and complete as PatchMap. The SkyBase dataset has an additional 88,000 kilometres of roads, with more being constantly acquired. Our mapset gets updated about four times each year. Every oilfield location point has additional information, such as name and operator, license date and number, and strike zone [oilfield] and surface location. Following the practice of the Energy resources Conservation Board, all directionally drilled wells are named by their bottomhole. Whether the surface or the bottomhole is used, crews will get to the correct location. So far, our customers are primarily companies and individuals located in these areas. in the future, we expect major producers to recognize the savings in time and money that PatchMap can bring to all of their field operations.

Where do you see PatchMap heading next?On certain GPS units, a verbal safety warning advises if you get too close to a sour wellsite. Both sour and abandoned locations are already visually indicated on our maps. As a pilot project regarding road hazards, we have built-in verbal warnings for narrow bridges, approved chain-up areas, blind-approach corners, steep hills, railway crossings, etc. Through JuneWarren-Nickle’s Energy Group, we have implanted certain listings from COSSD [Canadian Oilfield Service & Supply Directory] that can be called with a single-button push and will soon add rig Locator search capabilities. We are also looking at a Citrix-based PC deployment, which will be favoured by the big companies. There are many more trucker-related issues being evaluated for future solutions, so don’t let us out of your sight.


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Advertisers' Index1174365 Alberta ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 521214848 Alberta Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 & 66Abacus Datagraphics Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67Allan R. Nelson Engineering (1997) inc . . . . . . . . . . . . . . . . . . . 52All Weather Shelters inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44Annugas Compression Consulting Ltd. . . . . . Inside Back CoverASAP Heating & Well Servicing Corp. . . . . . . . . . . . . . . . . . . .36ATCO Structures & Logistics Ltd . . . . . . . . . . . . . . . . . . . . . . .65Bear Slashing Ltd . . . . . . . . . . . . . . . . . . . . .Outside Back Coverbelzona Western ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70bidell Equipment lP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .43bilton Welding and Manufacturing ltd . . . . . . . . . . . . . . . . . . 74black Sivalls & bryson (Canada) ltd. . . . . . . . . . . . . . . . . . . . .58brother’s Specialized Coating Systems ltd . . . . . . . . . . . . . .58Brownlee LLP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48Calgary Health Trust . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73Canadian Association of Petroleum Producers (CAPP) . . . . . .6Canadian Enviro-Tub Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13CARES Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68Caush Xhufi (Professional geophysicist) . . . . . . . . . . . . . . . .24Christina Lake Lodge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51City of Grande Prairie. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40CJS Coiled Tubing Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . .50Continental Electric Motor Services ltd . . . . . . . . . . . . . . . . .26County of Grande Prairie No. 1 . . . . . . . . . . . . . . . . . . . . . . . . .34Crompton Western Canada inc . . . . . . . . . . . . . . . . . . . . . . . . 16Dean’s Pump Service Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . .58DFI. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Diversified Glycol Services Inc. . . . . . . . . . . . . . . . . . . . . . . . .58Eagle Drilling Services Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Edmonton Exchanger & Manufacturing ltd . . . . . . . . . . . . . . 22Falvo Electrical Supply Ltd. . . . . . . . . . . . . . . . . . . . . . . . . . . 64Flexpipe Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30-31Gaugetech Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66Grande Prairie Regional College . . . . . . . . . . . . . . . . . . . . . . .56Imperial Oil Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5iTT Water & Wastewater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47Joule Technical Sales Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71Kubota Canada Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7lJ Welding & Machine. . . . . . . . . . . . . . . . . . . Inside Front Coverlloydminster Heavy oil Show . . . . . . . . . . . . . . . . . . . . . . . . .82Lockhart Oilfield Services Ltd . . . . . . . . . . . . . . . . . . . . . . . . 46loTech Manufacturing inc . . . . . . . . . . . . . . . . . . . . . . . . . . . .65 MaXfield inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .45Maxon . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .56MCi Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80Mechanix Wear Canada . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .29Meridian Mfg group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .42MPi-Marmit Plastics inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48NAIT Corporate and International Training . . . . . . . . . . . . . . .62Northern Mat & bridge ltd . . . . . . . . . . . . . . . . . . . . . . . . . . 48Northgate Industries Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64Northstar Energy Services Inc. . . . . . . . . . . . . . . . . . . . . . . . . .4Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .62oil lift Technology inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52oilPro oilfield Production Equipment ltd . . . . . . . . . . . . . . . . 70

oil Sands and Heavy oil Technologies . . . . . . . . . . . . . . . . . . 84one 4 Haul. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38-39Opsco Energy Industries Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . 78Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74Phoenix Fence inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .62Platinum Energy Services Corp . . . . . . . . . . . . . . . . . . . . . . . . 25Platinum Grover Int. Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19PrintWest Communications. . . . . . . . . . . . . . . . . . . . . . . . . . . 78Production Control Services . . . . . . . . . . . . . . . . . . . . . . . . . .20Propak Systems Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3Prostate Cancer Canada Network . . . . . . . . . . . . . . . . . . . . . . 76Radafab Oilfield & Industrial Supply Inc . . . . . . . . . . . . . . . . 66RTS Services Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18Strad Energy Services Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71Suncor Energy Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57Systech Instrumentation Inc . . . . . . . . . . . . . . . . . . . . . . . . . . .9Tank Gauging Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74TCA Marketing ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68T & E Pumps Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74Titan logix Corp . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68Tomco Production Services Ltd. . . . . . . . . . . . . . . . . . . . . . . . 23vector Communications Ltd . . . . . . . . . . . . . . . . . . . . . . . . . .24vertigo Theatre Society . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76v.J. Pamensky Canada Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Waydex Services lP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37Westeel. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35World Energy Congress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

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Oil & Gas Inquirer - June 2010

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