oil & gas inquirer | march 2011

MARCH 2011 $6.00

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Despite low natural gas prices, innovative proDucers anD service companies trigger an economic revival in granDe prairie

Grande

ENGINEERS, FABRICATORS & CONSTRUCTORS FOR OIL & GAS PROCESSING

GAS COMPRESSION / GENERATION / PROCESSING EQUIPMENT FOR SALE / RENT / OR LEASE

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

TURBO-EXPANDER PLANT (USED)

25 MMscf/d EXPANDER C2 OR C3 RECOVERY

POWER GENERATION UNITS (NEW)

G-300-KW-Dual Waukesha F18GL 300 KW Generator

- WG-400-KW Dual aukesha H24GL 400 KW Generator

GAS BOOSTER COMPRESSORS (NEW)

AC200-S20B 200 Caterpillar G3306 T W Sullair PDR20 Gas Booster

C400-S25B 400 Caterpillar G3408 TAW Sullair PDR25 Gas Booster

C400-S25B 400 Caterpillar G3408 TAW Sullair PDR25 Gas Booster

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

C195-JGA-2 195 Caterpillar G3306TA Ariel JGA-2 Throw

W400-JGA-3 400 Waukesha F18CL Ariel JGA-4 Throw

W400-JGA-3 400 Waukesha F18CL Ariel JGA-4 Throw

C630-JGJ-3 630 Caterpillar 3508 TALE Ariel JGJ-4 Throw



C810-JGH-3 810 Caterpillar G3512 TALE Ariel JGH-4 Throw

C810-JGH-3 810 Caterpillar G3512 TALE Ariel JGH-4 Throw

1250W1250-JGK-3 Waukesha 5774 LT Ariel JGK-4 Throw

W1445-HOS-3 1445 Waukesha 5794 LT Dresser HOS-4 Throw

W1445-JGK-3 1445 Waukesha 5794 LT Ariel JGK-4 Throw

W1445-JGK-3 1445 Waukesha 5794 LT Ariel JGK-4 Throw

W1680-JGK-3 1680 Waukesha 7044 Ariel JGK-4 Throw

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

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

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

Propak Compression is a distributor of Dresser-Rand & Ariel compressors. Propak Compression is set up tosell units, service and supply parts for reciprocating and rotary screw gas compressors.

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

Phone Sales: (403) 912-7000 Fax: (403) 912-7011E-mail: [email protected] Web Site: www.propaksystems.com

We are proud of our customer service, on every job, every day. Call us to experience the Copp’s difference.

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6 M A R C H 2 0 1 1 • O I L & G A S I N Q U I R E R

Keeping readers regionally informed

F E A T U R E S

Grande ideasBy Mike ByfieldDespite low natural gas prices, innovative producers and service companies trigger an economic revival in northwestern Alberta

12

21 Avalanche of opportunityBy Mike ByfieldTechnical institutes and colleges are meeting the oil and gas sector’slooming skills crunch with more class than ever

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O I L & G A S I N Q U I R E R • M A R C H 2 0 1 1 7

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

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

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

storage, drilling activity and more

67 On The Job• Erecting complex scaffolding keeps life

interesting for Jonathan Hokanson, a

big and agile entrepreneur who fears

boredom more than heights.

69 Tools of the Trade• BPC Services Group, based in

Lloydminster, uses directional drilling

to drastically reduce the impact of

installing gathering pipeline systems,

with benefits to the environment,

surface owners and producers.

70 Political Cartoon

27 British Columbia• Painted Pony achieves healthy

production growth with the drill bit

• Storm Resources reports a successful

Horn River well

31 Northwestern Alberta• Galleon’s northwest drilling identifies

possible Triassic oil play

• Deep Basin–developed fracture fluid

tank system goes continental

35 Northeastern Alberta• Oilsands investment could reach $16B in

2011, up by $2.5B from 2010

By Elsie Ross

43 Central Alberta• The liquids-rich Hoadley Glauconite play

is generating good returns

By Paul Wells

49 Southern Alberta• Peters boosts drill, case and complete

forecast to $21.9B for 2011

By Pat Roche

57 Saskatchewan• PetroBakken sets 2011 capital budget

at $800M, versus $675M in 2010

• Researchers will study alleged

carbon dioxide leakage into farm near

Weyburn

61 Central Canada• Reef Resources outlines Ontario

enhanced oil recovery program

63 East Coast• Bidding is ramping up this year for

Newfoundland’s Hebron project

By Pat Roche

65 International• ExxonMobil sees natural gas as the

world’s fastest growing fuel to 2020

By Pat Roche

Cover design: Aaron Parker

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N E X T I S S U E

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.

April EditionLook, Ma, no hands! Or fewer hands, anyway. In April, Oil & Gas Inquirer will take a look at automation systems used in manufacturing pipe, drill bits and other oilfield equipment. Also, look for our Northeast British Columbia Profiler, which will provide the latest, most intimate details on the Montney and Horn River Basin plays.

Grande Prairie looks young. Most of its 50,000 residents are first-generation with no ancestral roots in the community. When natural gas prices plunged in 2008 and jobs became scarcer, some newcomers easily drifted away. Even architecturally, northwest-ern Alberta’s largest urban centre appears uniformly modern, with no large heritage buildings at all.

Look a little deeper, though, and you’ll discover that the Peace River Valley has its own human spirit and historical character in abundance.

For starters, this is a big country—far larger than many southerners realize. The Peace drainage basin totals about 300,000 square kilometres across northern Alberta and British Columbia, five times as big as Nova Scotia and double the size of Great Britain. The majes-tic river itself is almost 2,000 kilometres long. The Peace Valley, with its rich agricultural soil and other natural resources, might well have become a province in its own right if settlement had occurred earlier.

As far back as 1927, according to a report from the National Research Council, the Peace district of Alberta generated more patent applications per capita than anywhere else in Canada. That record is all the more remarkable given the region’s geographic isolation until quite recently. The Peace was the last major agricultural belt to be settled in North America, with homesteading continuing into the 1950s.

As the cover story of this issue of Oil & Gas Inquirer proves, that pioneering techno-logical spirit is alive and kicking in the oilpatch. For instance, David Forseth’s grand father walked from the Peace country to Edmonton—about 500 kilometres—to register his homestead in the provincial capital. Then he walked back to his new home. Maybe it’s not just a coincidence that Forseth himself has stubbornly stuck with developing his innova-tive remote-site catalytic heating system through six long years.

Speaking of spirit, read this month’s article about three technical colleges whose students graduate to the energy sector. Germany, Japan, France, even little Belgium and Switzerland all built themselves into industrial champions on the strength of their workers’ skills as much as their professional engineering. If North America hopes to con-tinue being blessed with prosperity, we must invest respect as well as cash in our techni-cal schools. So it’s deeply good that SAIT Polytechnic graduates are donating large sums toward developing their college for generations to come.

Vol. 23 No. 2President & ceoBill Whitelaw | [email protected]

PublisherAgnes Zalewski | [email protected]

AssociAte PublisherChaz Osburn | [email protected]

editoriAl director Stephen Marsters | [email protected]

editoriAlEDITORMike Byfield | [email protected] ASSISTANCE Janis Carlson de Boer, Marisa Kurlovich, Kyle Thompson [email protected] Pat Roche, Elsie Ross, Paul WellscreAtivePRINT, PREPRESS & PRODUCTION MANAGER Michael Gaffney | [email protected] PUBLICATIONS MANAGER Audrey Sprinkle | [email protected] MANAGER Rianne Stewart | [email protected] DIRECTORKen Bessie | [email protected] SERVICES MANAGER Tamara Polloway-Webb | [email protected] DESIGNER Aaron Parker | [email protected] SERVICES | [email protected] Johnson, Cath OzubkosAlesDIRECTOR OF SALES Rob Pentney | [email protected] MANAGER, MAGAZINES Maurya Sokolon | [email protected] ACCOUNT EXECUTIVE Diana SignorileSALES Jerry Chrunik, Nick Drinkwater, Ellen Fraser, Michael Goodwin, Rhonda Helmeczi, Nicole Kiefuik, David NgFor advertising inquiries please contact [email protected] TRAFFIC COORDINATOR—MAGAZINESElizabeth McLean | [email protected]

MArketingMARkETING AND TRADESHOW COORDINATOR Jeannine Dryden | [email protected]

oFFicesCalgary 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

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Subscription Inquiries Telephone: 1.866.543.7888 Email: [email protected] Online: junewarren-nickles.com

Oil & 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 | © 2011 1080554 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 Canada

The opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.

Editor’s Note

The Mighty PeaceMike byfield | [email protected]


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StatsAT A GLANCE

F A S T N U M B E R S

Price paid for British firm John Wood Group by General Electric, which is expanding its role in oil and gas services.

Estimated capital spending by 73 western Canadian producers for 2011, $3.9 billion more than those companies spent in 2010.

US $2.8B$49.1B

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

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

May 2010 490 511 39 19 1,059Jun 2010 295 153 40 16 504Jul 2010 193 9 16 4 222

Aug 2010 452 156 40 15 663Sept 2010 617 790 45 23 1475Oct 2010 678 581 39 18 1316

Nov 2010 868 989 75 165 2097Dec 2010 1061 559 78 238 1936Jan 2011 409 201 33 17 660

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 *

Feb 2010 101 166Mar 2010 98 264Apr 2010 56 320

May 2010 54 374Jun 2010 41 415Jul 2010 65 480

Aug 2010 43 523Sept 2010 39 562Oct 2010 42 604

Nov 2010 43 647Dec 2010 49 696Jan 2011 59 59

*From year to date

M O N T H OIL GA S OTHER TOTA L

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

May 2010 86 7 3 96Jun 2010 149 7 11 167Jul 2010 220 7 0 227

Aug 2010 198 12 7 217Sept 2010 197 5 6 208Oct 2010 201 12 11 224

Nov 2010 217 3 64 284Dec 2010 340 2 11 353Jan 2011 136 4 3 143

M O N T H OIL GA S OTHER TOTA L

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

May 2010 400 462 51 913Jun 2010 126 117 41 284Jul 2010 131 110 38 279

Aug 2010 168 135 43 346Sept 2010 357 638 59 1054Oct 2010 404 460 46 909

Nov 2010 579 847 169 1595Dec 2010 676 403 294 1373Jan 2011 226 145 82 413


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 February 15, 2011 Source: Rig Locator

Drilling Activity: Oil & GasAlberta January 2011 Source: Daily Oil Bulletin

OIL W ELLS GA S W ELLS

Alberta Jan 11 Jan 10 Jan 11 Jan 10

Northwestern Alberta 56 53 72 77

Northeastern Alberta 10 27 0 1

Central Alberta 130 141 27 69

Southern Alberta 30 32 46 178

TOTAL 226 253 145 325

Service Rig Count by Province/TerritoryWestern Canada February 15, 2011 Source: Rig Locator

COA LBED M ETH A NE BITU M EN W ELLS

Alberta Jan 11 Jan 10 Jan 11 Jan 10

Northwestern Alberta 0 1 6 7

Northeastern Alberta 0 0 10 27

Central Alberta 9 19 61 84

Southern Alberta 1 74 1 0

TOTAL 10 94 78 118

AC TIV E DOW N TOTA L AC TIV E

Western Canada

Alberta 438 217 655 67

British Columbia 30 7 37 81

Manitoba 13 2 15 87

Saskatchewan 147 36 183 80

WC Totals 628 262 890 71

Quebec 1 0 1 100

AC TIV E DOW N TOTA L AC TIV E

Western Canada (Per cent of total)

Alberta 467 114 581 80

British Columbia 66 27 93 71

Manitoba 20 1 21 95

Saskatchewan 88 15 103 85

WC Totals 641 157 798 80

Northwest Territories 2 0 2 100

Drilling Activity: CBM & BitumenAlberta January 2011 Source: Daily Oil Bulletin

3.25

3.75

4.25

Feb 16Feb 9Feb 2Jan 26Jan 19

Cdn$/GJ

$3.395/GJ Total vol.: 1,648 TJ Transactions: 210

Source: Natural Gas Exchange Inc.

1.8

2.3

2.8

Feb 11Feb 4Jan 28Jan 21Jan 14

Tcf

1.91 Tcf Year ago: 2.05 Tcf5-year avg: 2.04 Tcf

Source: U.S. Energy Information Administration

BLANK PAGEFOR DUPLEXING


DESPITE low nAturAl gAs Prices, INNOVATIVE PRODUCERS AND SERVICE COMPANIES TRIGGER AN econoMic revivAl IN GRANDE PRAIRIEBy Mike Byfield

espite natural gas prices that continue to wallow dismally at about $4 per thousand cubic feet (mcf), Grande Prairie’s energy sector is battling successfully to survive and thrive. Field crews have been busy this winter and the future looks promising. Innovative pro-ducers, including juniors, are probing the traditionally gas-prone

region’s complex geological formations for liquid hydrocarbons. Meanwhile, locally based service companies are developing technologies with potential customers far beyond northwestern Alberta.

The region has a gift for technical innovation. Currently, Alberta typi-cally ranks third among provinces in total patent applications per annum (after Ontario and Quebec) but first on a per capita basis. Although the Mighty Peace has only five per cent of the provincial population, it accounts for as much as 40 per cent of the province’s patent applications. Companies based in Grande Prairie—for instance Risley Equipment Inc. and DAVCO Manufacturing Ltd.—make patented forestry tools that are sold across North America, Australia and elsewhere.

“At the moment, my client list of innovators has 59 people on it, many of them from the energy sector. We’ve got some excellent technology in the works,” says Jim Letersky, an adjunct staff member with the Centre for

Research and Innovation (CRI). Sponsored by the Peace Region Economic Development Alliance and Grande Prairie Regional College, the CRI was launched in 2007 with a $3.4 million grant from the provincial government’s Rural Alberta Development Fund.

Letersky is a veteran specialist in economic and community develop-ment who grew up in the region near Spirit River. “I remember when Grande Prairie had 3,000 people and still had a hitching post [for horses] down-town,” he says. (The city’s current population is 50,000, servicing a market area totalling nearly 250,000.) “We were isolated for a long time, so people learned to make their own replacement parts for farm implements and other machinery,” the CRI coordinator says. “That self-sufficiency naturally evolved toward technical innovation.”

Every month, the CRI brings a patent lawyer to town, providing one-hour consultations to would-be inventors. “He’s seen more than 200 people so far and we’re still going strong,” Letersky says. Besides helping with the patent-ing process, the institute guides developers through the funding maze of research councils and government agencies. The CRI also offers practical advice on technical drawings, prototypes, attracting investors and lenders, and manufacturing start-up.

FEAtUrE

ideasGrande


“I only wish that I’d run into CRI earlier. They’re

a tremendous ally,” says David Forseth, president of Cataflow Technologies Inc. Farm-raised north of Dawson Creek, his oilpatch experience includes work with steam trucks. “Production equipment and lines kept freezing off, and thawing them out obviously made less sense than preventing the freeze-up in the first place. So I got to figuring out a better solution,” explains the 44-year-old inventor.

His start-up firm is now manufacturing its first 60 flameless, self-powered hydronic heating systems, designed to operate away from the power grid. Hydronic technology uses circulating liquid for heating purposes. Depending on size, the Cataflow units can sup-port up to 800 feet of heat trace (tubing used to wrap around equipment and lines) with a 12-inch by 24-inch heater. Besides heat, the patent-pending technology generates enough electricity to operate a pump that moves warm glycol through the heat trace. Very modest amounts of water and CO2 are emitted, mini-mizing the environmental footprint.

Cataf low’s systems can be fuelled by raw gas from a wellhead or any

other hydrocarbon gas. Three litres of bottled propane will supply 400 feet of heat trace for 24 hours with the smaller system. The only external power source required is a 12-volt battery for about 10 minutes. The battery initiates genera-tion of infrared energy from a catalytic heater. “My system absorbs the infrared energy and transforms it into a heated f luid [glycol] and electricity,” Forseth explains. Catalytic heaters are popular in the patch because they are f lame-less, a major plus wherever hydrocarbon vapours may be present.

The catalytic heater element con-tains platinum material, which reacts with oxygen and gas to create infrared energy. The catalytic process is self- sustaining as long as the heater doesn’t fall below 200 degrees Celsius. “A major producer is now in the second year of using our prototype units in the field and their guys love this technology. Our equipment will run for years with vir-tually no maintenance. The pump is magnetically driven; there are no seals or shafts,” says Forseth, who’s been in the development process for six years.

Financially, a key f igure behind Cat a f low i s Hou ston-ba sed Ma rk A d a m s o n , w h o r u n s Te c h - S e a l International Inc. “Mark makes a lot of oil-field equipment. Getting his attention was very difficult, but he immediately agreed to invest once he came here and saw what we have,” Forseth reports. Another investor is Dan Vezina of SunStroke Solar Ltd., an Alberta-based developer of solar- powered pumps. While Cataflow’s initial goal was supplying heat at remote sites, an off-grid, inexpensive, low-emission source of electricity could well have even more market potential. Forseth acknowledges that his company is working on boosting power output from his catalytic technol-ogy but won’t yet discuss details.

FEAtUrE

Cataflow's self-powered hydronic heater.

Photo: Aaron Parker

Grande

cAtAFlow PUtS thE hEAt ON At rEMOtE lOCAtiONS

WhEN thE GOiNG GOt tOUGh, rhinokore GOt GOiNG

R h i nokore ma kes insulated frac tanks, based on a proprietary polyurethane panel

with an extraordinary strength-to-weight ratio. “One of our 1,200-cubic metre tanks can be transported on a single truck and erected in a day or two,” says Rhinokore founder Paul Dagesse. “It replaces 20 tanks [400 barrels apiece] and 20 truckloads. Our frac tank’s insulation value is as high as R40, which saves big on heating cost, as does the

floating-type lid. And completing a big shale gas well with one rectangular tank on the corner of the lease is a lot easier than hooking up 20 round tanks to the wellhead.”

Rhinokore, a subsidiary of Grande Prairie’s Trans Peace Construction, also manufactures portable bridges, rig mats and other products from its unique panels. To make them, the company injects a low-density polyurethane foam into a honey-comb structure. Where other core-type technologies break at their stress point,

Rhinokore’s foam-stabilized cells distribute that energy across the structure, providing its panels with a powerful combination of stiffness and flexibility.

Dagesse, raised on a dairy farm in Manitoba, apprenticed as a carpenter with Trans Peace when he came west. In 1987, he and a partner bought out the previous owner. The company specializes in con-struction of self-framing metal buildings, utilidor structures, pipe insulation and similar oilfield tasks. Trans Peace also

Photo: Rhinokore


R a n d y G a l b r e a t h , president of St rat us P ipel i nes Ltd., used

to have shouting matches in the field with Doug Kulba, an inspector with Alberta Environment. “After a while, we decided that it would make more sense to work together,” comments Galbreath, a pipeline contractor based in Grande Prairie. The resulting cooperation has

worked out better than either man could have expected.

In June, Kulba and Galbreath were cited along with Devon Canada Corp. by the Alberta Emerald Foundation for the Emerald Certified Shared Footprints Award. They were the inaugural recipients of this honour, newly created by Alberta’s Department of Sustainable Resource Development. Their achievement: creating innovative

techniques and tools for resolving the expensive annoyance of soil settling above pipeline installations and mixing of soils.

In 2007 or so, Devon noticed that sunken “ditch lines” were appearing over pipelines installed five to 15 years ear-lier. If that ditch spanned a quarter sec-tion, it could be traversed as often as 800 times a year by a farmer while he circled his field to harrow, seed, spray, swath,

FEAtUrE

strAtus PiPEliNES SqUEEzES SOil SEttliNG WOES

Photo: Rhinokore

manufactured conventional polyurethane panels, which prompted its president’s interest in composite materials.

A composite material consists of two or more chemically different materials that maintain their distinction within the bonded product. A simple example would be early bricks made with mud and straw. A com-posite always includes at least one matrix (polyurethane, in the case of Rhinokore) and a reinforcement. Rhinokore, launched three years ago, has not revealed what material is used to form its honeycomb, although Dagesse does say it’s neither the traditional paper nor polypropylene.

Also confidential is the manufacturing process used to fill the honeycomb with polyurethane so that it’s completely free of voids. (Air pockets would weaken the panel.) “That process is not as easy as you might think, and we have a patent,” Dagesse says with a smile. The polyurethane- impregnated honeycomb is then wrapped in a tough resin covering.

Rhinokore’s first products were rig mats. “These panels will not warp or crack in extreme heat and cold. They’re splinter-proof, waterproof and chemical-proof, and the non-skid surfaces are easy to clean,” Dagesse says. “Our heavy-duty mat has a compression strength of over 85,000 pounds per square foot. Our standard mat only weighs 600 pounds, which can save as much as 75-80 per cent in transportation costs compared to wood mats. Even the toughest traditional mats will break down after half a dozen uses. Ours will not.”

R hinokore’s panels, being non- metallic, do not interfere with pipeline locations equipment, making them suitable for pipeline crossings. “Our panels can be installed on screw piles, so they’re well-suited for floating and industrial docks, elevated roadways and small creek cross-ings. They’ll work well as insulation in per-mafrost applications, too,” Dagesse says.

Because drilling activity collapsed just as the innovative rig mats were

introduced, a ballooning surplus of wood mats impeded sales. Fortunately, pro-ducers were simultaneously gearing up to mount massive frac operations in the Horn River Basin and Montney plays, creating a new market for frac tanks of unprecedented size. Meanwhile, high gasoline prices had decimated sales of recreational vehicles. Rhinokore was able to lease a former RV manufactur-ing facility in Armstrong, B.C., which came complete with a highly experienced workforce.

Dagesse is intrigued by the possibil-ity of combining Rhinokore panels with Cataflow’s remote-site catalytic heating technology. “We could provide a customer with an 8,000-square-foot heated floor, transported on one truck to a remote site and installed in a day. The customer could erect any kind of structure over that floor, [such as fabric buildings, another west-ern Canadian specialty],” the Trans Peace president enthuses.

rhinokore's frac tank (left) sits in front of multiple round steel tanks, while its manifold (right) is conveniently simple.

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combine and more. “Every time a farmer hits a ditch line, the jolt feels like driving your car over a speed bump in a parking lot at 20 kilometres per hour,” Galbreath says. Devon found itself paying for agricul-tural machinery and, more importantly, forfeiting the good will of landowners.

When trenching occurs along a pipe-line right-of-way, the liberated clay expands in volume by up to 45 per cent, making it difficult to replace after the pipe is laid. Current approved pipeline prac-tices allow for the spreading or “feather-ing” of excess clay across the right-of-way. Gradually, however, the replaced soil resettles and a ditch is born. Spring runoff

water can deepen the fault line. Back when farmers routinely ploughed up fields, their yearly shifting of soil tended to even out land surfaces. In recent times, how-ever, agricultural operators have largely switched to “no-till” methods that elimi-nate the need to plough annually.

To prevent ditch line settlement, Galbreath and Kulba hatched a solution based on careful preoperational plan-ning that they named the “Low Impact Pipeline System.” Firstly, this approach calls for digging up less soil by narrow-ing the trench. Secondly, valuable top-soil is segregated from the underlying infertile clay more accurately. Finally, nearly all of the soil is replaced after the pipe is laid through improved clay com-paction methods.

To implement their strategy, Galbreath and Kulba had to invest in creating suit-able equipment. Stripping frozen topsoil

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Photo: Rhinokore

“Every time a farmer hits a ditch line, the jolt feels like driving your car over a speed bump in a parking lot at 20 kilometres per hour.”

— Randy Galbreath, President, Stratus Pipelines Ltd.


StACkEd liqUid PrOSPECtS drAW tAngle creek tO NOrthWESt AlBErtA

Ta n g l e C r e e k Energy Ltd. is a n e w l y f or m e d

junior with over $100 million to invest. “We are focused on oil in tighter res-ervoir rock. To establish our core oper-ating areas, we’re now evaluating several prospects across the western Canadian Sedimentary Basin,” says Alison Essery, exploration vice-president for the private company. “Tangle Creek is interested in a number of areas but the Peace River Arch [PRA] is certainly attractive, especially for a start-up such as ourselves. Land sales activity began to pick up there about a year ago, and traffic is still increasing. I think the arch is about to bust wide open.”

The Peace River Arch lies deepest in the Alberta-B.C. border region west of Grande Prairie. From there, the geo-logical trend (a high uplift in Devonian and a low basin during younger times) sprawls eastward and slightly north for

750 kilometres, gradually rising toward the surface. The PRA’s prime attraction, according to Essery, is gas liquids and oil, with large additional exploration and exploitation potential in Devonian, Triassic and Cretaceous formations.

“ E ve n t houg h we a r e t a r get-ing previously discovered—but non- commercial—accumulations, the exploit-ation component of our business is really applying some of the newer drilling and completions technologies that have been really successful in central Alberta. Exploration usually involves a degree of luck,” Essery says. “So we prefer to work in areas with stacked targets that offer mul-tiple possibilities for success.”

The Triassic specialist spent 29 years with Shell Canada, including eight years working on the PRA (with four years as team lead) and a further eight years in the Rocky Mountain foothills. In 1999, Shell sold its PRA lands to Apache Canada Ltd.

In fact, global heavyweights like Exxon Mobil Corporation and BP p.l.c. are almost entirely absent from this massive swathe of terrain, leaving plenty of room for inde-pendent producers and juniors.

Essery says it ’s now nearly impos-sible to buy good prospective land in the Pembina area for less than $5,000 per hectare ($2,000 per acre). “Land prices in the better understood portions of the Cardium play [of west-central Alberta] have become too steep for most juniors,” she says. In contrast, the PRA remains relatively affordable. At the Alberta Crown auction on Jan. 26, Galleon Energy Inc. submitted the high bonus of the sale: $7.26 million for 6,400 hectares ($1,135 per hectare) in its North Peace core oper-ating area. Most bids for PRA acreage are much lower.

“On the [Peace Rive] Arch, carbonates often occur within the sandstone systems, which isn’t always the case elsewhere.

is no simple task. “Until now, there were two choices. You could put a megamulcher head on a D6 Cat, which means using equipment worth $800,000 to $1 million,” Galbreath says. “Alternatively, a D8 could haul a soil-breaking tool, which came out to nearly as much in terms of equipment value.” Because this heavy machinery is wide, pipeline rights-of-way had to be wide as well.

Stratus has developed a patented top-soil stripper that is now available for sale or rent. The tool costs around $35,000 and it can be fitted as an attachment to the excavators that are present on any pipeline construction site. Adjustable front and back knives slice the topsoil, which is then care-fully scooped up by the bucket. “As well, we worked with an inventor to develop a narrow bucket for large excavators. It’s sur-prising how much soil can be handled even by the smaller bucket,” Galbreath says. “It took a lot of time to achieve a clean dump and an even trench bottom.”

His company has invested $1.5 mil-lion in developing its topsoil stripper,

narrow buckets, packing wheels and the Low Impact Pipeline System. Packing wheels can also be attached to existing equipment, and these wheels come in various widths. “In the cases where we can’t replace the topsoil due to frost, clay will still be 90-95 per cent returned,” Galbreath says. “This approach allows us to return in early May to tidy up the ditch line and replace the topsoil. Landowners can then commence s p r i n g a c t i v i t ie s . Traditional methods tend to prevent clean up from starting until July or August, mean-ing an entire crop year is lost.”

Stratus says its Low Impact Pipeline System reduces right-of-way width by 20-40 p er cent . Topsoi l st r ippi ng requi re-ments drop by as much as 60 per cent.

“We can reduce the ditch width by about 60 per cent, down to as little as 11 inches, considerably minimizing the amount of subsoil demolition,” Galbreath adds. “Initial expense of laying a pipeline with our methods is typically a little higher, but total project cost will be less over time.” The pioneering pipeliner is hopeful that more companies will follow Devon Canada’s lead in harnessing this new technology.

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Photo: Aaron Parker

Stratus's low impact Pipeline System toolkit includes specialized buckets.

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There’s been a lot of [water] leaching, and the resulting carbonate dissolution gener-ates sweet spots with better porosity and permeability [P&P] in tight sandstone formations,” Essery says. “Even today, some vertical wells can be good produc-ers. Overall, there is a lot of potential for hybrid resource plays, with less P&P than a typical conventional prospect but better than, for example, the Horn River Basin. Only the major or exceptionally well- capitalized companies can afford the huge numbers of heavily fracced wells needed to develop economic production in a true resource play like Horn River. The arch is a good prospective place for a technically sophisticated but smaller company like Tangle Creek.”

Triassic targets with hydrocarbon potential in the PRA include the Montney, Doig, Halfway and Charlie Lake. Slightly higher sits the Nordegg. Prospective Devonian-period formations, roughly 130 million years older than the Triassic, include the Duvernay section, another PRA resource play that ’s heating up. “Fundamentally, the arch involves thick layered reservoir packages sandwiched between good source rocks,” Essery says.

“However, the geology is complex, with very mixed reservoirs that can be broken by faults in polygonal patterns.”

Among the explorers active in north-western Alberta is Mike Rose, a former Shell Canada explorer and now the pres-ident of Tourmaline Oil Corp. The private

company expects to spend between $350 million and $425 million on explora-tion and production capital projects in 2011, principally on prospects in the Deep Basin and Peace River Arch. Other PRA drillers include Canadian Forest Oil Corp., Canadian Natural Resources Limited, Daylight Energy Ltd., Pace Oil & Gas Ltd., Dejour Enterprises Ltd., TAQA North and Birchcliff Energy Ltd. Bonavista Energy Corp. and Paramount

Resources Ltd. have also been active at recent land sales.

An unfashionable but still prime attrac-tion in northwestern Alberta is natural gas, according to Essery. “On the arch, the odds are good for finding significant gas vol-umes. The gas becomes a really attractive

bonus if it’s liquids-rich gas,” the veteran geologist says. “I think that many shale gas producers are going to find that they’ve been over-optimistic about their produc-tion potential in North America. Not every-one is going to have success. If I’m right, gas prices will come back sooner than many analysts expect. If I’m wrong, gas prices will still recover, but it may just take longer for companies to realize the benefit of the gas they find while looking for oil.”

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“I think that many shale gas producers are going to find that they’ve been over-optimistic about their production potential in North America.”

— Alison Essery, Exploration Vice-president, Tangle Creek Energy Ltd.

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T H E OIL AN D GA S E xP LOR ATION , production and pipeline sectors will lose at least 30 per cent of their combined core workforce within 10 years due to retirement, according to a report released in December by the Petroleum Human Resources Council of Canada (PHRC). The government-industry agency con-ducted four short-term labour market surveys over 2009-10. Chronic shortages of crucial skills—power engineers and plant operators, frac crews and other field specialists, production accountants and more—dogged the patch even during a period of mass upstream layoffs.

“Between 2007 and 2009, the services sector lost approximately 13,000 seismic, drilling, oilfield construction and main-tenance, and well servicing workers,” the PHRC report states. In fact, even more energy service workers were likely laid off between 2007 and early 2009, the council says, but some were recalled during the latter part of 2009 when activity began picking up. As that recovery continues, the report notes, “material and skills short-ages are expected to re-emerge in the

opportunityavalanche of

TECHNICAL INSTITUTES AND COLLEGES

ARE MEETING THE OIL AND GAS SECTOR’S

LOOMING SkILLS CRUNCH WITH

MORE CLASS THAN EVER By Mike Byfield

An artist's rendering of the trades and

technology Complex at SAit Polytechnic.

Illustration: SAIT Polytechnic


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short-term [2012] and the industry will once again be challenged to keep costs under control, while competing for talent.”

We s te r n te c h nolog y i n s t it ute s and colleges are responding aggres-sively to the looming oilf ield skills squeeze. In Calgary, SAIT Polytechnic is

mid-way through construction of its Trades and Technology Complex (TTC). Upon completion in 2012, the Calgary facility will provide 740,000 square feet of new space on campus, designed for training specialists in energy, construc-tion, and manufacturing and automa-tion. The TTC will deliver 3,600 more student spaces, allowing as many as 8,100 more students every year.

An impressive chunk of the Calgary project’s funding is coming from SAIT graduates and former tradespeople. For instance, the largest of the three TTC buildings will be named the Aldred Centre in recognition of a $15-million contri-bution from John and Cheryl Aldred.

A n i m m ig r a nt f r om Britain who arrived in 1967, John Aldred first worked as a heavy-duty mechanic in the oilpatch. Going into business for himself, he trans-formed Enerf lex Systems Ltd. from a one-man start-up into a 3,000-employee global manufacturer of natural gas com-pression and processing equipment. In 2010, Toromont Industries Ltd. acquired Enerflex for $670 million.

The west wing of the TTC will be named the Johnson-Cobbe Energy Centre, honour-ing a pair of $5-million gifts from two SAIT graduates. Murray Cobbe and David Johnson both earned petroleum technology diplomas in the 1970s. Today, Cobbe is the executive chairman of Trican Well Service Ltd. while Johnson holds the same position at Progress Energy Resources Corp. The TTC initiative was launched in part thanks to an earlier $10-million gift from fellow SAIT alumnus Keith MacPhail, chairman and chief execu-tive officer of Bonavista Energy Corp.

Building Three [of the TTC] will house a “live laboratory” where aspiring power engineers, instrumentation mechanics, process operators and other students will acquire skills in replica industrial facilities rather than classrooms. For example, SAIT will duplicate a steam assisted gravity drainage (SAGD) installation. “We depend on our graduates and other industry spe-cialists to keep our programs and equip-ment focused on the current needs of the oil and gas sector,” says Mary MacDonald, dean of the MacPhail School of Energy at SAIT Polytechnic.

MacDonald places the highest priority on maintaining tight linkages with indus-try. Her energy school has 10 industry advisory committees that meet at least once annually. The Northern Alberta Institute of Technology operates a simi-lar industry-academic advisory system. To help coordinate technology train-ing on a province-wide basis, NAIT and SAIT academic department chairs attend each other’s advisory committee meet-

i ng s . B e s ide s h e r c o m m i t -tee work, t he MacPhail dean s a y s , “ I a l s o meet one - on-one with four industry leaders each month.”

Her staffers develop a great

deal of energy-related curriculum mat-erial for their students. “No one publishes a standard textbook that includes instruc-tions for operating an H2S [hydrogen sul-phide] gas plant at 40 below,” MacDonald comments. SAIT’s academic strength continues to deepen, with full bachelor’s degrees now available in applied petro-leum technology. “Quite a few students fail to graduate because they’re offered jobs before they’ve completed the pro-gram,” the energy dean notes with a touch of frustration.

SAIT provides custom-tailored tech-nical training programs for companies and governments around the world. “The [Alberta] government only funds half of our overall budget,” MacDonald explains. “We’ve been able to generate significant additional revenue through competing in the global market. For instance, we’ve got 92 Angolans here right now training for jobs in their own country. Beyond the immediate revenue for SAIT, international

Construction of SAit's 740,000–square foot trades and technology Centre is scheduled for completion next year.

Photo: SAIT Polytechnic

Photo: SAIT Polytechnic

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initiatives create another valuable bene-fit: our graduates become familiar with Canadian energy technology and they rep-resent future potential customers for our suppliers as their careers progress.”

Flexible delivery and transferability between industries are strong points for Northern Lights College, whose five cam-puses in northeastern British Columbia handle about 1,100 trades and technology students annually. Besides its headquar-ters in Dawson Creek, “B.C.’s energy col-lege” has locations in Fort St. John, Fort Nelson, Chetwynd and Tumbler Ridge. “We’re definitely not mired in academe and bureaucracy,” says Jeff Lekstrom, dean of trades and technology. “We deliver on a very timely basis, adjusting to chang-ing circumstances in the petroleum, for-estry and mining industries.”

In 2008, Canfor Ltd. closed an oriented strand board mill and plywood plant at Fort Nelson, triggering 625 direct job losses. “Luckily, the Horn River Basin shale gas play was expanding at that time. Most of those forestry workers transitioned quickly into the natural gas sector, with help from

our trades and apprenticeship coordinator,” Lekstrom says. “We provided the necessary programs for upgrading tickets and spe-cialized needs like H2S safety and confined space entry training.”

In 2009, the Horn River Basin Producers Group (which includes 11 member com-panies) informed Northern Lights that field operators would be needed in the near future. “I made a presentation to the group in Calgary in the morning and learned that our proposal was officially accepted when I got off the plane back home at 2 p.m.,” Lekstrom recalls. In January 2010, an ini-tial intake of 46 students graduated as qualified operators.

To train power engineers at Fort Nelson, the college is now setting up a 10-month program in partnership with Spectra Energy, Encana Corp. and the Northeast Aboriginal Skills Employment Project. Course material covers fourth-class power engineering and all four levels of gas processing operations. Nine months of the program will be offered in Fort Nelson, with another month at the Fort St. John campus, plus practicum time

at local Spectra Energy and Encana facil-ities. Mandatory upgrading has already begun, with the program itself scheduled to launch in June.

Northern Lights prides itself on its well-qualified veteran instructors, all with operational experience in the region’s rig-orous winter climate. Another mainstay is modern equipment. In 2008, the college opened its $12-million Oil and Gas Centre of Excellence on the Fort St. John campus, with half of its capital budget paid by

The west wing of the TTC will be named the Johnson-Cobbe Energy Centre, honouring a pair of $5-million gifts from two SAIT graduates.

SAit's new technology centre will provide state-of-the-art facilities for foreign students as well as Canadians.

Illus

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SA

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corporate and private donors. The facil-ity includes a simulated well production site, complete with two wellheads, a com-pressor, and flare and pigging capabilities within a closed-loop system. “We empha-size hands-on training, and industry has been hugely supportive in providing our

students with great tools for that purpose,” Lekstrom says.

Anyone who’s looking for a well-paid, virtually guaranteed job after one year of study might consider applying to the heavy oil operations technician (HOOT) program at Lakeland College in

Lloydminster. The thriv-ing heavy oil and in situ bitumen sector in Alberta a nd Sa sk atc hewa n i s e x pec ted to generate demand for many hun-dreds of operators in t he nea r f ut ure. Ber t Samuelson, Lakeland’s dean of the trades and technology school, says a survey of last spring’s graduates indicates 96 p e r ce nt s at i s f ac t ion with HOOT.

S a m u e l s o n s a y s t he HO OT lab need s upgrading and possibly an addition. In particu-lar, the dean dreams of adding a second year of study, which would train

students as third-class power engineers (HOOT now prepares its grads to chal-lenge the fourth-class exam), SAGD operations, firefighting, more intense training in information technology and more. “We’d configure the program for f lexibility,” he says. For example, an operator could graduate from the first year, work for a while in industry if he chooses, and then return to school later for the second year.

Other western schools that offer petroleum-specific training (exclud-ing engineering and other disciplines at major universit ies) are NA IT in Edmonton, Fort McMurray ’s Keyano College, Red Deer and Medicine Hat colleges (primarily through the r ig technician apprenticeship program) and Saskatchewan Southeast Regional College. SAIT’s MacDonald predicts that all available training capacity will be stretched by the oilpatch’s need for skills. “Institutes and colleges themselves will soon be challenged in recruiting instruc-tors for energy-related courses, the situ-ation is that intense,” the MacPhail dean comments. “We’re facing an avalanche of opportunity.”

Northern lights College handles about 1,100 trades and technology students per year.

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BRITISH COLUMBIA WELL ACTIVITY

British Columbia

JAN/10 JAN/11

WEll liCENCES 101 76 ▼

JAN/10 JAN/11

WEllS SPUddEd 97 76 ▼

JAN/10 JAN/11

WEllS drillEd 57 55 ▼

Source: Daily Oil Bulletin

With veteran geologist Patrick Ward as CEO, Painted Pony has grown quickly since its launch in 2007.

Painted Pony achieves healthy production growth with the drill bit

Painted Pony Petroleum Ltd. says its pro-duction has continued to grow to record levels despite weather-related oper-ational delays and pipeline apportion-ment, with field-estimated December 2010 production averaging 3,950 bar-rels of oil equivalent (boe) per day (52 per cent oil and liquids, 48 per cent gas). Based on field estimates, production for the fourth quarter of 2010 was 3,360 boe a day (54 per cent oil and liquids, 46 per cent gas).

Painted Pony planned to drill a total of five (2.9 net) Montney wells during the first quarter of 2011. The Montney zone across the entire area contains sweet, low-CO2 gas, with high heat con-tent and an estimated liquids-to-gas ratio of over 20 barrels per million cubic feet (mmcf).

Following a five-day cleanup, Painted Pony said in mid-January that its Lower

Montney horizontal well Gundy D-B67-J/94-B-9 (20 per cent working interest) flowed in-line for 19 days at an average rate of 11.6 mmcf per day with a peak rate of 13.1 mmcf a day. The average pressure during the 19-day test was over

2,900 pounds per square inch (psi). Current production is 11.5 mmcf per day and the well has produced 0.3 billion cubic feet (bcf) in less than one month.

Daily Oil Bullet in records show Progress Energy Resources Corp. as the operator of the well. On the same pad,

the horizontal well Gundy C-67-J/94-B-9 (20 per cent working interest to Painted Pony) was brought on stream in December 2010. The well was drilled and completed during the summer of 2010, though it was not tied in until the Gundy compressor facility was completed. The well is cur-rently producing 6.1 mmcf a day at over 1,400 psi, after one month on production.

Approximately four miles away on the same contiguous block of land, the hori-zontal well Kobes A-B10-J/94-B-9 (20 per cent working interest) has been on pro-duction since last August. Initial produc-tion was 9.8 mmcf a day, and the average production rate during the first 30 days following cleanup was 8.5 mmcf per day at an average pressure of over 2,900 psi. The well has produced 0.85 bcf in approxi-mately four months.

The Middle Montney horizontal well Kobes A-A10-J/94-B-9 (20 per cent work-ing interest) has been on production since October 2010. The average production rate during the first 30 days following cleanup was 6.6 mmcf a day at an aver-age pressure of 1,000 psi. The well has produced over 0.5 bcf in less than three months and is currently producing at 5.9 mmcf per day.

In addition to these wells in the lower and middle Montney, Painted Pony now has three upper Montney hori-zontal wells on production. Production from the first two wells, which were brought on stream at Blair approxi-mately eight months ago, has exceeded

Painted Pony planned to drill a total of five (2.9 net) Montney wells during the first quarter of 2011.

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British Columbia

original expectations significantly, the company said. The third upper Montney well (20 per cent working interest), Gundy D-A67-J/94-B-9 is currently pro-ducing at 2.3 mmcf a day after 29 days on production.

Painted Pony said it continues to actively delineate all three Montney

intervals on its significant land pos-ition in northeastern British Columbia. The company holds approximately 118 net sections with Montney rights in this area. On the Cameron/Kobes block, all three intervals in the Montney have been proven commercially productive with horizontal wells.

On the Blair/Town block (85 net sections), the upper Montney has been proved com-mercially productive with horizontal wells, and the lower and middle Montney have been tested successfully using vertical wells. Additional horizontal piloting is planned for all three intervals at Blair/Town in 2011.

— DAILY OIL BULLETIN

Storm Resources Ltd. and its partner, Storm Gas Resource Corp. (SGR), have announced initial gas flow rates from the first horizontal well drilled in the Muskwa and Otter Park gas

shales on their joint lands in the Horn River Basin in northeastern British Columbia.

In October 2010, the first horizontal well at D-9-D/94-P-12 (60 per cent SGR, 40 per cent Storm) was drilled to a total depth of

4,300 metres with a 1,750-metre horizon-tal section in the Muskwa and Otter Park shales. Completion of the well commenced in early December 2010 and consisted of

12 fracture treatments with each being approximately 300 tonnes of sand and 2,900 cubic metres of water (total sand pumped was 3,500 tonnes and total water pumped was 35,000 cubic metres or 220,000 barrels).

Total cost of the completion is expected to end up at $9 million to $9.5 million. The well has now flowed for 76 hours on cleanup with results as follows:• Gas rate has been restricted and has aver-

aged 8.8 million cubic feet (mmcf) per day during the cleanup period (cumulative gas production 28 mmcf).

• The most recent gas rate was 9.1 mmcf per day at a flowing casing pressure of 8,000 kilopascals.

• The water used in the fracture treatments is being recovered at a rate of 1,600 bar-rels per day or 255 cubic metres per day,

Storm Resources reports a successful Horn River well

Gas rate has been restricted and has averaged 8.8 million cubic feet (mmcf) per day during the cleanup period.

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Read what our editor has to say.


British Columbia

Artek Exploration Ltd. says it has success-fully drilled its first horizontal Doig well (60 per cent working interest) in the Inga/Fireweed area of British Columbia to a total measured depth of approximately 2,900 metres (including approximately a 1,100-metre horizontal lateral).

The well was successfully completed with a seven-stage fracture stimulation program. After a five-day cleanup, the well flowed on an in-line test over a 64 hour test period at an average restricted rate of approximately 4.7 million cubic feet (mmcf) a day and 1,100 barrels a day of condensate or 1,895 barrels of oil equivalent (boe) per day at an average flow-ing tubing pressure of 1,156 pounds per square inch (7,965 kilopascals).

The company said it is satisfied with the positive results from the initial seven stages of the planned 11-stage fracture stimulation program, although it may elect to stimulate additional stages in the future.

At a liquids ratio of over 200 barrels of condensate per mmcf of natural gas and an assumed oil price of $83 per barrel at the wellhead and a natural gas price of

$3.85 per gigajoule (AECO price), Artek said it anticipates operating netbacks from the well of up to $41 per boe.

Daily Oil Bulletin records show an Artek-operated well licensed at 05-11-88-23W6.

In the immediate area, Artek holds interests in 16,780 gross acres (10,094 net) or approximately 25 gross sections (15 net)

and has an additional three sections tied up through a farm-in commitment.

The test results from this well, in com-bination with its five vertical Doig produc-ers, provides validation to the company’s geotechnical model and Artek said it plans to drill an additional two Doig wells after breakup. The volumes are being processed at its operated facility at Inga. The oper-ational success at Inga establishes a new core area for the company that has scale and repeatability and where it has control

of facilities and development, according to the company.

Additionally, Artek said it has successfully drilled and cased a horizontal re-entry (85 per cent working interest) into a Paleozoic carbonate formation in the Peace River Arch area that is prospective for natural gas and liquids. The company plans to complete the

well using a five-stage fracture stimulation program when services are available.

On the Alberta/B.C. border, Artek has spud its second Montney horizontal well (50 per cent working interest) in the Sinclair area, where in late 2010 its first Montney well tested in excess of eight mmcf a day. The well is anticipated to reach a total measured depth of approximately 4,300 metres and plans are for a 12-16 stage frac-ture stimulation prior to spring breakup.


with cumulative water recovery to date being 1,050 cubic metres, representing three per cent of the water pumped in the fracture treatments.

• Tubing is now being installed in the wellbore and the well will be f low tested for an additional seven to 10 days in order to gain additional infor-mation regarding the gas rate and flowing pressures.

Once testing has been completed and assuming results are as expected,

construction of the associated facility and pipelines will begin and first gas sales may occur as early as April 2011.

Although the initial flow rate is very encouraging, Storm said in January that it expects at least three to six months of production history will be required before a reserve estimate can be provided and before longer-term production perfor-mance can be predicted.

A second horizontal well was drilled in December at C-29-D/94-P-12 (60 per cent

SGR, 40 per cent Storm) to a total depth of 4,400 metres, which includes a 1,900-metre horizontal section.

SGR and Storm are 60:40 working interest partners and jointly control over 95 gross sections in the Horn River Basin, of which 19 gross sections have been identified as a core project area. In addition to its direct working inter-est, Storm holds a 22 per cent ownership position in SGR.


Artek scores with Doig horizontal at Inga/Fireweed

The operational success at Inga establishes a new core area for the company that has scale and repeatability and where it has control of facilities and development, according to the company.


NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY

Northwestern Alberta/Foothills

JAN/10 JAN/11

WEll liCENCES 251 278 ▲

JAN/10 JAN/11


JAN/10 JAN/11



Galleon’s northwest drilling identifies possible Triassic oil play

A veteran player on the Peace river Arch, Galleon estimates its 2011 production at 14,500 boe per day.

Galleon Energy Inc. said its successful fourth-quarter drilling program resulted in the identification of a potential Montney oil play and provided further support for a possible Triassic crude program. At its Eastern Montney business unit, Galleon said it plans to further develop an oil-prone Montney fairway in 2011.

“Although it is still early in the development of this oil fairway, the poten-tial of this oil play has been defined as significant,” the company said in a press release. Four horizontal wells (96 per cent interest) have been drilled to date having initial one-month production averaging 107 barrels of oil equivalent (boe) per day, with 76 per cent oil. Galleon said that the average cost to drill, complete and tie in each well is approximately $1.3 million.

In the fourth quarter at the company’s North Peace River Arch business unit, Galleon successfully drilled one vertical

Montney natural gas well. In addition, two new Triassic oil projects were identified. An additional three horizontal wells were planned to be drilled in the first quarter to further prove up productivity from this new Montney oil fairway.

One vertical well in the first Triassic oil project was recompleted in the fourth

quarter of 2010 with what the com-pany called “encouraging results.” “This recompletion, along with vertical well control and seismic, provides support for an emerging Triassic oil play. This play has considerable aerial extent and thick hydrocarbon charge,” Galleon said.

The company plans to follow up with two horizontal wells in the current quar-ter. In the second Triassic oil project, Galleon said that after comprehensive geological and geophysical analysis, one vertical well test was planned in the first quarter. At its Kakut Montney project, Galleon said that new production and pressure data has confirmed the existence of two separate Montney pools. The south-ern pool is primarily natural gas whereas the northern pool has an oil leg.

Recent production from the north-ern pool has seen a transition toward oil. Galleon has a plan to develop this oil resource during 2011. One well is currently on stream and three other standing wells are scheduled to be tied in and brought on stream late in the first quarter of 2011.

Galleon said it plans to further maxi-mize oil production in 2011 by drilling at least one Montney horizontal well in the oil portion of the pool. Producing pre-dominantly oil from this pool will result in increased cash flow due to high crude oil prices.

The company said its Kakut Doig gassy light oil project in Alberta contin-ues to deliver economic wells. This Doig reservoir is defined by a large number of vertical control points. Galleon said it continues to accumulate data and

history within this project, and as such, continues to increase its understanding of the reservoir. “In addition, work is on-going to determine the appropriate com-pletion and drilling methods, with the goal of optimizing well productivity and cost efficiency,” the company said.

“Although it is still early in the development of this oil fairway, the potential of this oil play has been defined as significant.”

— Galleon Energy Inc.

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Galleon plans to complete a Kakut Doig horizontal well in the first quar-ter with a cemented liner system using a higher fracture density than previously deployed.

Based on field estimates, Galleon said that fourth quarter 2010 production aver-aged 13,525 boe per day. For the same period a year prior, the company averaged 14,688 boe per day.

Galleon said production was affected as it experienced delays in obtaining frac-ture crews and equipment. This resulted in certain newly drilled wells being completed and brought on stream up to

three to four weeks later than initially forecasted. In January 2011, the com-pany entered into a strategic agreement to contract equipment and crews for the majority of its currently planned comple-tion activities through to the end of third quarter 2011.

Currently, the company has three drill-ing rigs working and plans to drill up to 19 wells in the first quarter. Estimated capital expenditures of approximately $33 mil-lion have been allocated to the drilling program for the period. These expendi-tures are expected to be funded by work-ing capital and cash flow.

During the three months ended Dec. 31, 2010, 14 (12.75 net) wells were drilled and cased for production result-ing in five (five net) natural gas and nine (7.75 net) oil wells, for a success rate of 100 per cent.

As previously announced, Galleon will spend $131 million this year with 70 per cent of that directed to oil projects. The focus of its first quarter 2011 capital program will be on the continued develop-ment of its light oil and natural gas pro-jects in the Kakut, Eastern Montney and North Peace River business units.


Open Range Energy Corp. says Poseidon Concepts (a wholly owned business unit) is deploying its innovative fracturing fluid-handling system in the United States after achieving success among customers in

western Canada. Open Range is a Calgary-based junior producer that has ventured into the service sector.

Poseidon designs, manufactures and operates a patent-pending modular, insulated

tank system that was tested and rolled out by Open Range personnel at its core Ansell/Sundance Deep Basin property. The experi-mental system was deployed on several liquids-rich natural gas wells in early 2010.

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Poseidon Concepts was subsequently formed under the operating direction of Cliff Wiebe, who has been Open Range’s completions superintendent for the past three years. Wiebe has over 25 years of industry experience primarily focused on completion operations and related energy services.

The insulated and modular tank sys-tem’s advantages reportedly include greatly increased storage capacity to accommodate larger fracturing oper-ations, improved portability, more effi-cient fluid-heating process and reduced environmental footprint, all of which deliver cost savings versus the traditional approach of using multiple smaller stand-ing tanks or lined pits.

Poseidon provides systems on a rental basis to oil and natural gas producers across western Canada. The first revenue- generating job was performed in June and initial rentals focused on Alberta’s Deep Basin. Fabrication of tank systems for western Canadian operations is continuing through an Alberta-based third-party manufacturer and was scaled up in the fourth quarter of last year to meet increasing industry demand.

Late in the fourth quarter of last year, Poseidon expanded into North Dakota as its initial step towards ser-vicing the multiple oil and natural gas basins in the U.S. Open Range com-mented that growing industry activity in North Dakota made this the logical entry point, gaining exposure to mul-tiple intermediate to senior U.S. pro-ducers while remaining in relat ive proximity to its Canadian base.

Fabrication of tank systems for the U.S. operations is now underway using a large third-party manufacturer based in the U.S. The first U.S.-built system was recently field-deployed in North Dakota. Poseidon’s U.S. operations recently received a one-year minimum commit-ment for the provision of multiple fluid handling systems to a major American oil and natural gas company operating in North Dakota.

Poseidon’s revenue per job has aver-aged approximately $86,000 during this period. With demand for fractur-ing services and related equipment in Canada and the U.S. remaining strong, particularly for unconventional oil and

liquids-rich natural gas reservoirs being developed with horizontal wells and larger fracturing operations, Open Range said it anticipates continued growth of the tank fleet.

Poseidon currently has 45 f luid- handling systems in the f ield, with approx i mately 20 per cent of t he expanding f leet expected to be servic-ing U.S. operations by mid-February. The majority of the f leet is deployed at unconventional oil and liquids-rich natural gas plays. The strong operating environment is driving a high utilization rate and solid operating margins.

For the f irst half of 2011, Open Range forecasts $8.5 million in business unit cash flow from operations and earn-ings before interest, taxes, depreciation and amortization. Poseidon’s capital expansion requirements are expected to be fully financed using a portion of the business unit’s cash flow from oper-ations, with the balance of the business unit ’s cash f low contributing to Open Range’s continuing exploration and development program.


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NORTHEASTERN ALBERTA WELL ACTIVITY

Northeastern Alberta

JAN/10 JAN/11


JAN/10 JAN/11

WEllS SPUddEd 134 209 ▲

JAN/10 JAN/11

WEllS drillEd 131 206 ▲


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don thompson, head of the Oil Sands developers Group, has “no doubt” that 2011 will be a good year.

Oilsands investment could reach $16B in 2011, up by $2.5B from 2010By Elsie Ross

once the front-end engineering design is updated this year.

The company has an oilsands capital budget of $4.18 billion this year, up from $3.21 billion in 2010, as it also moves forward on the proposed Fort Hills mine, begins front-end work on MacKay River 2 and expands Firebag in situ facilities. The figure includes $250 million as its share of Syncrude operations.

Although Imperial does not release forecast capital spending, in the third quarter of 2010 it reported capital and exploration expenditures of $1.2 bil-lion, directed primarily to Kearl. The company also indicated it planned total capital spending of $3.2 billion last year but expected to exceed that. This year, its share of Syncrude will be $621 million.

At Cold Lake, plant site clearing, grad-ing and road construction was underway in the third quarter in preparation for the Nabiye expansion project, which will add about 30,000 barrels (bbls) a day of produc-tion. Amendments to the original scheme recently approved by Alberta’s Energy Resources Conservation Board (ERCB) include a sulphur-recovery plant, cogenera-tion and a reduction in the number of pro-ducing well pads to nine from 22.

Canadian Natural Resources Limited has budgeted up to $2.5 billion in capital spending on oilsands projects this year. The figure includes $1.35 billion for ther-mal in situ oilsands projects, including its recently acquired Kirby assets. Another $800 million to $1.2 billion will be spent on the Horizon oilsands mine along with $130 million on tailings management as required by the ERCB.

Cenovus Energy Inc. could spend up to $1 billion this year with capital expendi-tures of $350 million to $400 million each at its Foster Creek and Christina Lake SAGD projects which it shares 50/50 with ConocoPhillips, with whom it also has

Oilsands activity appears to be set for a resurgence this year with continued strength in oil prices and a stronger global economy contributing to renewed confi-dence that could boost capital spending to an estimated $16 billion, up from just under $13.5 billion in 2010.

Suncor Energy Inc. will be one of the most active players as it increases oilsands spending by 30 per cent, while Imperial Oil Limited will continue construction of its Kearl oilsands mining project and begin work on its Cold Lake Nabiye cyclic steam stimulation (CSS) expansion. In addition, Syncrude Canada Ltd. will add two new mining trains, and several new steam assisted gravity drainage (SAGD) projects are expected to break ground.

“I have no doubt it’s going to be a good year for oilsands, subject to crude prices continuing to be supportive,” said Don Thompson, president of the Oil Sands

Developers Group which represents oil-sands mine operators. “We’ve had one major announcement and large amounts of projects move through the regulatory pro-cess and into construction, particularly in the in situ region.”

In December, Suncor and Total E&P Canada Ltd. signed several agreements to form a strategic oilsands alliance encompassing the Suncor-operated Fort Hills mining project, the Total-operated Joslyn mining project and the Suncor-operated Voyageur upgrader project. Under the al l iance, the companies agreed to pool their combined interests in these projects, with the respective operator holding 51 per cent and the other partner 49 per cent.

Suncor suspended Voyageur construc-tion in 2008 as high levels of activity drove up costs in the oilsands while world mar-kets were in turmoil, but work will resume



50 per cent ownership in two U.S. refin-eries. Cenovus also has allocated up to $200 million for emerging oilsands assets such as Narrows Lake, Grand Rapids and Telephone Lake.

Canadian Oilsands Trust, which has the largest interest in Syncrude at 34.6 per cent, will spend $907 mil-lion including $176 million on tailings management, up from expected capital spending this year of about $511 million. Syncrude’s total estimated budget for this year is $2.8 billion.

About $332 million of Canadian Oilsands’ capital budget has been allo-cated to relocating or replacing four out of Syncrude’s five mining trains to build a stable, more efficient foundation for future bitumen production. Once completed, these mine trains should remain in oper-ation for 10-20 years.

Another $114 million will be spent to complete the Syncrude Emissions Reduction project. Expected to be com-pleted this year at a total cost of $1.6 bil-lion to Syncrude, the project is expected to bring a 60 per cent reduction in sul-phur compound emissions from current approved levels once fully operational.

At Christina Lake, MEG Energy Corp. plans to invest about $900 million this year when it starts facilities construc-tion for the second phase of its $1.4 bil-lion SAGD project. The budget includes $80 million to $90 million for core drilling and seismic programs at Christina Lake, Surmont and growth properties on MEG’s 800 square miles of 100 per cent–owned oilsands leases.

Nexen Energy Inc., which has been struggling with production at its Long Lake SAGD project, has budgeted a total of $575 million, of which $425 million has been allocated for in situ projects (mainly Long Lake) and $150 million for its share of Syncrude expenditures. At Long Lake, the focus will be on improv-ing the strength and reliability of plants and infrastructure with two new pads and additional steam generating capacity.

The company plans to be sanction-ready in 2012 on the first of its two 40,000 bbl per day SAGD projects at Kenosis and is moving forward with its non-operated SAGD pro-ject at Hangingstone.

BP will spend $416 million this year as its share of the first $2.5 billion of Husky Energy Inc.’s Sunrise oilsands mining project. Husky will spend an

equal amount on the expansion of BP’s refinery in Toledo, Ohio, to enable it to process crude from Sunrise.

Harvest Operations Corp., owned by Korea National Oil Corporation, has bud-geted $240 million for its BlackGold SAGD project for which facility construction and production-well drilling is scheduled to begin this year. About $190 million will be spent on construction and design of the facility while approximately $50 mil-lion will be spent on drilling 10 production well pairs and 12 observation wells, as well as other growth capital opportunities.

Total’s share of this year’s expendi-tures for Fort Hills and Voyageur as

part of its new agreement with Suncor is $314 million. Pending regulatory approval, expected in the first quarter, construction could begin in 2011 on Total’s 100,000 bbl per day North Joslyn mine about 70 kilometres north of Fort McMurray, Alta., in which Suncor will have a 49 per cent interest.

Athabasca Oil Sands Corp., which is part of a joint venture with PetroChina International Investment Company Limited, has a $302-million capital budget for its own as well as its joint-venture projects. Spending will include purchasing certain long-lead items for the Hangingstone SAGD project; thermal assisted gravity drainage and SAGD test-ing of the Dover West carbonates; drilling up to 140 wells; acquiring up to 60 square kilometres of 3-D seismic; and acquiring up to 130 kilometres of 2-D seismic.

Athabasca Oil Sands and Cretaceous Oil Sands Holdings Limited, a wholly owned subsidiary of PetroChina, formed Dover Operating Corp. to develop and manage both the MacKay River and Dover commercial SAGD projects. Athabasca Oil Sands owns 40 per cent and PetroChina 60 per cent of both projects. In late January, Dover submitted an application to the ERCB for the Dover commercial project north of Fort McMurray.

OPTI Canada Inc.’s largest expenditure this year will be $122 million as its share of the budgeted costs for Nexen’s Long Lake

project. It also will invest approximately $22 million in advancing engineering and detailed execution plans for the Kinosis project to the end of March. The OPTI board may consider further 2011 capital spending on Kinosis this year. Apart from its Nexen partnership, OPTI will invest approximately $6 million for development of its Leismer and Cottonwood assets.

With its Algar SAGD project now com-mercial, Connacher Oil and Gas Limited has reduced spending this year to a total of $72 million, down from $230 million in 2010. This year’s budget consists of $39 million for oilsands operations, $25 million for exploration and $8 million for

an environmental impact assessment and Algar expansion engineering.

Also contributing to oilsands spend-ing this year will be new in situ projects to be developed by new oilsands operators. While it waits for regulatory approval for its 11,300 bbl per day SAGD oilsands pro-ject at Algar Lake, Grizzly Oil Sands ULC expects to spend between $60 million and $70 million this year on core hole drilling programs at Algar and at its Firebag lease, east of Suncor’s existing Firebag project.

BlackPearl Resources Inc. plans to spend $22 million this year on its Blackrod single well pair SAGD in the Athabasca oil-sands at 77-17-W4 where it expects to start steam injection in March.

With the recent regulatory approval for its 12,000 bbl per day project at McKay, Southern Pacific Resource Corp. is now raising the $425 million required to con-struct the STP-McKay thermal bitumen project. Construction could begin later this year.

Privately held Laricina Energy Ltd., which last year raised $50 million in a private placement to a wholly owned sub-sidiary of Korea Investment Corporation, recently began injecting steam into the Grosmont carbonate formation at its pilot project at Saleski in northern Alberta. The pilot has an approved capacity of up to 1,800 bbl per day.

Another new player, Osum Oil Sands Corp., expects to receive regulatory

OPTI Canada Inc.’s largest expenditure this year will be $122 million as its share of the budgeted costs for Nexen’s Long Lake project.



approval by mid-2011 for its proposed 35,000 bbl per day Taiga SAGD project at Cold Lake. First oil from the pro-ject is anticipated in early 2014. Osum raised gross proceeds of approximately $100 million in a private placement sub-scribed to by a wholly-owned subsid-iary of Korea Investment Corporation. The proceeds from the financing along with Osum’s existing working capital will be invested directly in the company’s in situ projects and general corporate purposes.

Peters & Co. Limited is forecasting total risked oilsands capital expenditures of $180 billion over the next 10 years, peaking at about $22 billion in 2014. That figure is about 20 per cent higher than the last oilsands spending cycle peak during 2007 and 2008 and will be difficult to fully execute, the investment dealer points out in a recent research report.

Additional factors that add some uncertainty to oilsands development include carbon costs and the associated legislation that could eventually unfold,

water usage and the costs associated with other potential environmental impacts such as tailings remediation, according to Peters.

Stabilized oil prices of between US$75 per bbl and $90 per bbl provide for a strong investment opportunity for SAGD operators, says Peters. It estimates that for most producers a long-term oil price of approximately $50 per bbl is required for a new SAGD project to be economic, a cal-culated break-even price at a 10 per cent after-tax discount rate.

The required price rises to approxi-mately $60 per bbl for a mining (no upgrading) project and to more than $100 per bbl for an integrated mining project, due mainly to the high costs asso-ciated with the upgrader and the mini-mal economic lift based on the current narrow light-heavy differentials, says Peters. These required break-even prices are highly sensitive to the different input variables, most importantly the quality of the resource.


A joint review panel has granted condi-tional approval to Total E&P Joslyn Ltd.’s proposed 100,000 barrel (bbl) per day Joslyn North oilsands mining project in northeastern Alberta, finding that it is in the public interest.

In a 138-page decision released on Jan. 27 following a public hearing last year, the joint panel concluded that in meeting the conditions and recommen-dations imposed the project would have “no significant adverse effect” on species at risk and valued wildlife species nor a significant adverse environmental effect on water quality. The joint panel also found the mine project would meet the Energy and Resources Conservation Board’s (ERCB) more stringent new requirements for tailings management.

The joint ERCB-Canadian Environ-mental Assessment Agency panel imposed 20 conditions related to environmen-tal and technical aspects of the project, including tailings and reclamation man-agement. In addition, the panel made a

total of 17 recommendations to the gov-ernments of Alberta and Canada and to the ERCB.

“This recommendation by the Joint Review Panel is a very positive first step for Total in receiving our permit to develop the Joslyn North Mine Project,” Jean-Michel Gires, president and chief executive officer of Total E&P Canada Ltd., said in a news release. “This affirms our commitment to developing a responsible project and improving en-vironmental and social performance of Canada’s oilsands. We are pleased that the panel finds this project to be in the public interest.”

Total obtained the withdrawal of objections concerning the project from the Fort McKay, Athabasca Chipewyan and Mikisew Cree First Nations and the Regional Municipality of Wood Buffalo, entering into agreements with them.

The Joslyn North mine would be built in two phases, each 50,000 bbls per day, at an estimated cost of between $7 billion

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and $9 billion. Total’s Joslyn lease about 70 kilometres north of Fort McMurray will support mining activities for 20 years (2017-2037).

T he development, west of t he Athabasca River and directly south of Canadian Natural Resources Limited’s Horizon mine, would increase Alberta’s approved minable project area by about seven per cent.

Total’s plans call for final regulatory approvals in the fourth quarter of this year. Detailed engineering, procure-ment and construction would take place between the third quarter of 2011 and the third quarter of 2016. Commissioning and start-up would occur in the fourth quarter of 2016 with initial operation and ramp up in 2017.

The project includes the design, con-struction and operation of a truck and shovel mining technology for the development of one mine pit to support a pro-duction rate of about 100,000 bbls per day of partially deasphalted bitumen. There also will be on-site energy genera-tion infrastructure to generate electricity and steam.

Total also has ERCB approval for an upgrader near Fort Saskatchewan but will not be proceeding with it. Instead, the bitumen will be upgraded at the $11.6-billion Voyageur upgrader near Fort McMurray in a joint venture with Suncor Energy Inc., which is acquir-ing 36.75 per cent of Total’s interest in

Joslyn. Total, as operator, will retain a 38.25 per cent interest in Joslyn North, with Occidental Petroleum Corporation (15 per cent) and Inpex Corporation (10 per cent) holding the remaining 25 per cent.

A t t he he a r i n g, t he O i l s a nd s Environmental Coalition comprised of the Pembina Institute, the Fort McMurray Environmental Association and the Toxics Watch Society of Alberta, urged that the project be denied on the grounds

that it would not be in the public inter-est and would cause significant adverse effects. The group cited concerns about the adequacy of Total’s environmental assessment and questioned the adequacy and costs of reclamation and the meth-odologies used to determine the project’s effects on water quality.

To meet the requirements of the ERCB’s tailings Directive 74, Total plans to apply technologies such as thickened tailings, centrifuged tailings and sand spiking (adding fluid fine tailings to the coarse sand tailings stream to increase fines capture in the sand beach areas). The thickened tailings would be depos-ited in two dedicated disposal areas at annual deposition rates of four to six metres in one area and six to eight metres in a second area.

The development, west of the Athabasca River and directly south of Canadian Natural Resources Limited’s Horizon mine, would increase Alberta’s approved minable project area by about seven per cent.

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Thermal bitumen production in Alberta climbed to 549,024 barrels (bbls) a day in October, up from 434,096 bbls a day in October 2009 and 407,558 bbls a day in October 2008. The October 2010 num-bers, based on Alberta Energy Resources Conservation Board (ERCB) data and pub-lished on the Oilsands Review website, are the most recent available.

New and expanded steam assisted g rav it y drainage (SAGD) projec ts accounted for most of the increase. Alberta SAGD output in October averaged 316,508 bbls of bitumen a day, up from 255,409 bbls a day in October 2009 and 202,692 bbls a day in October 2008.

In its recently released in situ oil-sands overview, Peters & Co. Limited said SAGD production has the potential to rise to nearly two million bbls a day by 2020, based on planned projects.

However, Peters added this caveat: “While such an increase would obviously result in many different beneficiaries, it

is important to recognize that, based on the number and scale of planned pro-jects, there will most likely be timing delays and bottlenecks in the proposed development.”

The two million bbls a day total for SAGD output in 2020 is modest compared to the sum of what project proponents were proposing a few years ago. For exam-ple, a 2007 tally of planned SAGD projects found SAGD production would reach a peak of 4.32 million bbls a day by 2020 if everything proceeded.

In its in situ overview, Peters sum-marized key features of SAGD projects that are notable (both for positive and negative reasons):• Cenovus Energy Inc.’s Christina Lake

and Foster Creek are among the most energy efficient projects with cumulative steam to oil ratios (SORs) of 2.3 and 2.5, respectively.

• Connacher Oil and Gas Limited’s Pod One production has averaged 6,600 bbls a day,

SAGD output continues to climb despite challenges

The company said that its thickened tailings technology would meet 55 per cent of the total mass of fines in the oil-sands feed (compared to the required 50 per cent) and would meet the five-kilopascal strength requirement one year after deposition.

The panel found that the proposed tailings plan is reasonable based on cur-rently available technology and that it can manage any unforeseen shortfalls because it uses a suite of technologies and it exceeds the directive requirements. However, the panel said it was concerned that industry has not commercially dem-onstrated that thickened tailings with an annual deposition of six to eight metres can meet the strength requirement.

As a condition of approval for the project, Total will be required to provide Alberta Environment with a wildlife miti-gation plan for approval prior to clearing any vegetation. “The plan must achieve no net significant adverse effect on species at risk and deal with mitigating impacts not only to species at risk but also valued wild-life,” said the panel.


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which represents a reliability factor of less than 70 per cent. Peters noted output rose recently, but believes production will remained constrained by steam-generating capacity.• Devon Canada Corporation ramped up

production at its Jackfish 1 project to 90 per cent of its 35,000 bbl a day capacity in 2010 while maintaining well-pair productivity of about 1,100 barrels a day and an SOR of 2.4—both ahead of industry averages.

• MEG Energy Corp. is in the enviable position of having exceeded the target design capacity of 25,000 bbls a day at its Christina Lake project in recent months. The design was based on an SOR of 2.8, but the star project has actually oper-ated at a lower SOR—which allowed volumes to exceed expected capacity. Average well pair output recently topped 800 bbls a day.

• Minimal progress has been made to increase production at Husky Energy Inc.’s troubled Tucker project. The company hopes to increase output to 10,000 barrels a day by mid-2011 from about 4,000 barrels a day now. The cumulative SOR is 10 and

the instantaneous SOR is above six. Design capacity was about 30,000 barrels a day.

• Output at the troubled Nexen Inc.– operated Long Lake project reached about 29,000 bbls a day last year but remains far below its design rate of 72,000 bbls of bitumen a day. Steam injection rates continue to be much

lower than planned. Peters noted produc-tion from a new pad in the northwestern corner of the project began in May “with minimal production contribution thus far.” Peters estimates an additional $600 million will have to be spent to get the project operating near its design rate.

• Suncor Energy Inc.’s Firebag project has consistently had the highest well pair productivity (recently about 1,400 bbls

a day) thanks to higher operating pres-sures. However, Firebag’s cumulative SOR of 3.2 is above the 2.7 SOR design capacity. “And without an improvement in the SOR, additional steam genera-tion will be required before the project can ramp up to full-scale production,” Peters said.

In an in situ project performance update last October, Peters listed Suncor’s Firebag utilization rate at only 63 per cent, based on August 2010 production of 56,300 bbls a day.

According the ERCB data on the Oilsands Review website, Firebag’s output in October—the most recent month avail-able—averaged 49,532 bbls a day.

—DAILY OIL BULLETIN

In an in situ project performance update last October, Peters listed Suncor’s Firebag utilization rate at only 63 per cent, based on August 2010 production of 56,300 bbls a day.


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CENTRAL ALBERTA WELL ACTIVITY

Central Alberta

JAN/10 JAN/11


JAN/10 JAN/11


JAN/10 JAN/11



The liquids-rich Hoadley Glauconite play is generating good returnsBy Paul Wells

Phot

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the Glauconite formation has recently yielded 65 barrels of liquids per million cubic feet of gas.

With its high liquids content, strong eco-nomics and proximity to infrastructure including a deep cut gas plant at Rimby, the Hoadley Glauconite play is prov-ing to be an attractive target. Haywood Securities Inc. analyst Geoff Ready says participants include Bonavista Energy Corporation, Yangarra Resources Ltd. and Waldron Energy Corp.

“Like most other plays in west-central Alberta, the Glauconite is being exploited using horizontal multistage fracturing technology. Driving the strong econom-ics is the fact the gas is extremely liquids-rich with yields exceeding 65 barrels [bbls] per mmcf [million cubic feet],” Ready said, noting that Bonavista is the most active operator in the play “achiev-ing first month average rates of 460 boe [barrels of oil equivalent] per day at a total half-cycle capital cost of $2.5 mil-lion per well.”

“The play is in an established area with lots of infrastructure and lots of run-ning room. And it’s just a thick, continu-ous trend so it’s got a lot of legs,” Ready added. “Bonavista is a well-respected com-pany with a great history and this is their flagship play. They talk about it but until

recently, nobody else seems to. Yangarra’s talking about it now and it’s starting to get a little more exposure but it’s kind of flown under the radar.”

B o n a v i s t a c a l l s t h e H o a d l e y Glauconite “one of the cornerstones of growth” for the company. To date, the

company has drilled more than 50 wells into the trend since initiating its program in 2008 and plans to spend between $75 million and $80 million to drill 40-45 wells there in 2011. With greater than five years of drilling inventory in the play, Bonavista expects to spend $800 million over the life of the program.

“We’re not the discoverer of this play in any sense of the word, but rather we’re leading the charge on redeveloping it, if you will,” said Cam Deller, Bonavista’s manager of investor relations. “It’s not unlike the Pembina Cardium that’s now being developed in the areas where it doesn’t have the good quality rocks to develop it vertically.”

In the third quarter of 2010, Bonavista drilled seven horizontal wells and par-ticipated in four non-operated horizontal wells on the Hoadley Glauconite trend in its western core region. Deller said the liquids-rich natural gas development pro-gram continues to impress with its “con-sistency and ability to deliver meaningful economics even in today’s low natural gas price environment.”

Bonavista has now drilled 55 horizon-tal Glauconite wells successfully testing the resource across 60 miles of the Hoadley trend. “The production profile of the

producing wells to date continues to meet or exceed our expectations with initial one-month production rates of 500-600 boe per day, which includes a highly valuable liq-uids stream of 150-180 barrels per day of natural gas liquids,” the company said in its third-quarter press release.

“The play is in an established area with lots of infrastructure and lots of running room. And it’s just a thick, continuous trend so it’s got a lot of legs.”

— Geoff Ready, Analyst, Haywood Securities Inc.


Central Alberta

Since closing a strategic Hoadley acquisition in August 2009, Bonavista has increased its exposure to the play by approximately 50 per cent through suc-cessful step out development and land consolidation activities. Deller said the company’s remaining inventory of 275 horizontal drilling prospects on the Hoadley trend will result in an attractive multi-year development program with on-stream capital efficiencies of approxi-mately $6,000 per boe per day.

“Bonavista believes that our Glauconite horizontal development program is one of the most profitable liquids-rich natural gas resource developments in North America with economics that outperform many oil projects being developed today,” he said. “Single well economics are exceptionally attractive and provide abundant capital spending flexibility with half-cycle break-even economics of approximately $2 per mcf [thousand cubic feet].”

According to an Alberta Association of Petroleum Geologist (AAPG) report issued in 1984, the Hoadley trend is a giant gas condensate accumulation discov-ered in November 1977 by Sundance Oil Company. The field covers approximately 3,900 square kilometres in south-central Alberta. The producing zone in the Lower Cretaceous Glauconitic formation com-prises 7.6-24.4 metres of sandstone pay.

The sand was deposited as an exten-sive marine barrier bar complex with an approximate width of 24 kilometres and length of more than 200 kilometres, trending southwest-northeast. The middle and southwestern portion of the barrier bar, which is approximately 160 kilo-metres long, is entirely saturated with gas and natural gas liquids, trapped laterally by impermeable shale and updip by shale-filled tidal channels.

The A A PG report said the f ield is estimated to contain an ultimate potential recoverable reserve of six to seven trillion cubic feet (tcf) of gas and 350 million to 400 million bbls of associ-ated natural gas liquids.

Dave Russum, a petroleum geolo-gist who is vice-president of geoscience for AJM Petroleum Consultants, says it’s likely those numbers could go higher once the impact of new technology and its abil-ity to exploit targets that were previously considered uneconomic are factored in.

“I would think they would increase. It was a pretty big number at that time, but

I would think it’s highly likely that when those numbers were done the focus was on the higher quality rock that could be drilled vertically. Just like in the Cardium and other plays, the lesser quality rock was likely largely ignored for the calcula-tions of gas in place,” Russum said.

While he agrees that plays like the Hoadley Glauconite have great poten-tial, Russum was quick to caution that estimated ultimate recovery volumes should not be overestimated by industry players. “Even with the best technology, we shouldn’t assume that we’re going

to get out 50 per cent or 80 per cent of the product from those kinds of rocks,” he said. “It doesn’t seem realistic to me, anyway.”

According to Deller, it’s not just the fact that the play is liquids-rich that caught the company’s attention—it’s the quality of the liquids themselves that sets the Hoadley Glauconite apart from many other liquid-rich plays.

“About 30 per cent of the reserves are liquids, so that’s about 60 barrels per mmcf. Then it ’s about one-third, one-third, one-third of condensate, propane and butane. Obviously, propane and butane have had their ups and downs over the last couple of years but con-densate has had a nice run. Actually, it’s essentially getting equivalent to West Texas Intermediate prices.”

So, if Bonavista brings a well on at 550 bbls of oil equivalent per day and 30 per cent of that is liquids, that equates to about “165 barrels of oil per well per day essentially,” on top of the natural gas production. “That’s the real driver of the economics. That and the cost reduc-tions that we’re achieving,” Deller said.

Deller said that when Bonavista initi-ated its three-well pilot program in the

Hoadley Glauconite trend in the fall of 2008, well costs were about $3.6 million all-in. But as the company gained exper-tise in the play, those costs have come down substantially. “We’re doing that now for about $2.5 million. That’s just a func-tion of it being a repeatable program—we’re drilling off pads, that sort of stuff. We’re drilling two, sometimes three wells off a pad,” he said.

Jim Evaskevich, Yangarra’s pres-ident and chief executive officer, counts the Hoadley Glauconite as one of his company’s pillars for growth, especially

in the current low natural gas price environment. “This is going to be a hot, hot play. The rate of return on the Glauc is just amazing,” he said. “Now, all the Hoadley blocks are not created equal. One of the things that people need to recognize is there is a lot of really good locations but there are also a lot of loca-tions that are not going to cut it. The bulk of the action will be in the defined Hoadley trend.”

The company drilled two wells into the formation in 2010 and Evaskevich said the results were encouraging—the first well had initial production (IP) over the first 30 days of 602 boe per day while the second well’s IP-30 was 761 boe per day.

“We’re into a bit of an oilier leg, so we’re actually running about 125 bar-rels per mmcf of liquids,” he said. “So it’s huge liquids. Now we don’t expect all of our Glauc wells to be that way, quite frankly. But what I think is key about the Glauc is the big liquids. I think Bonavista is advertising something in the order of 60 barrels [per mmcf]. There’s going to be places where it ’s oilier, like some of our land.”

Evaskevich said Yangarra started its 2011 drilling program during the

“Bonavista believes that our Glauconite horizontal development program is one of the most profitable liquids-rich natural gas resource developments in North America .”

— Cam Deller, Manager of Investor Relations, Bonavista Energy Corporation

1-888-227-4923

Phone: (403) 227-7799 Fax: (403) 227-7796E-Mail: [email protected] Website: www.bilton.ca


Central Alberta

first week of January and will run one rig which will drill both Glauconite and Cardium wells.

“Because the area is so active geo-logically, we’re doing a bunch of Cardium wells as well. While we really like the Glauc, we’ve had some great success with our Cardium wells,” he said. “We’re only running one rig so we’re more or less alternating back and forth between Cardiums and Glaucs. Our current [2011] budget indicates 17 gross wells for 2011, split up between the two plays.”

Ernie Sapieha, president and chief executive officer of Waldron Energy Corp. declined to comment on the company’s activities, citing “competitive reasons.” However, in a recent report on Waldron, Ready and Haywood Securities said the company is pursuing the Glauconite play at Ferrybank (near Red Deer) and “has identified 10 locations over six sections of land [87 per cent working interest].”

“In Ferr ybank, current produc-tion is approximately 800 boe per day with resource plays to be developed in Glauconite liquids-rich natural gas and Belly River oil,” Ready said in a Jan. 4 note. “The near-term focus is on drilling Glauconite horizontal wells and vertical and horizontal Belly River oil wells.”

The mid-stream sector is also acknow-ledging the growing activity in the Hoadley Glauconite and its long-term viability. In mid-December, Keyera Facilities Income Fund announced it will build the Carlos pipeline south west from the Keyera Rimbey gas plant into the Hoadley region of central Alberta.

The pipeline will allow producers in the area to deliver liquids-rich gas to the Rimbey natural gas plant. The initiative will be a boon to produc-ers active in the Hoadley trend as the Rimbey plant is able to extract a “deep cut” of natural gas liquids (NGLs), frac-tionate them into specification ethane, propane, butane and condensate, and deliver these products directly into the Edmonton/For t Saskatchewan NGL energy hub.

T he $30 -mil l ion, 45-k i lometre, 12-inch raw gas-gathering pipeline is expected to be in service in the second quarter of 2011. To support this project, Keyera has secured a long-term, fee-for-service transportation and processing agreement with Bonavista.


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This year should be a busy drilling year for the Cardium formation in Alberta. Two of the largest players in the legacy field, Penn West Exploration and PetroBakken Energy Ltd., are each planning to spend over $300 million in the region during 2011.

The field, reinvigorated by strong oil prices and new technology, was the source of strong land sale interest over the past year. Penn West, fresh off its conversion from a trust, is already at an advantageous position corporately because it has plenty of lands which are oil-prone, noted Murray Nunns, pres-ident and chief operating officer, who presented at the BMO Capital Markets unconventional resource conference in New York on Jan. 11.

The company continues to focus its capital investments on resource plays in the Cardium trend in Alberta, the Viking trend in Alberta and Saskatchewan, the Amaranth in Manitoba and the carbon-ates in northern Alberta. Its 2011 forecast expenditure budget is between $1 billion to $1.2 billion with estimated production

of 172,000-177,000 barrels of oil equiva-lent per day, 65 per cent of that oil. In 2010 the company spent around $900 million to $1 billion and averaged 164,000-172,000 boe per day.

“We are the single largest land holder in the Cardium asset base by a good margin,” Nunns said. “It is one of the

single largest oilfields in North America. It also has one of the lowest recovery rates for any field this large and that’s critical to the go-forward.”

A 2010 operational update in the presentation noted that in the Willesden Green area, the company’s f irst f ive wells were producing 280 boe per day

per well after three months. In the West Pembina drilling area, the first four wells average 125 boe per day per well after three months.

In the Cardium this year, Penn West has capital spending plans of between $300 million and $325 million with a total of 100-110 wells and it has seven

rigs currently operating. “Completions [are] ongoing as well on last year’s wells,” Nunns said. “[Willesden Green] and West Pembina will be the guts of it. We’re also opening up into the Buck Lake and East Pembina areas.”

PetroBakken, meanwhile, announced plans yesterday to invest $800 million on

Large Cardium players will have a busy year in the field

“It is one of the single largest oilfields in North America. It also has one of the lowest recovery rates for any field this large and that’s critical to the go-forward.”

— Murray Nunns, President and Chief Operating Officer, Penn West Exploration

Central Alberta

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capital projects this year. “Our growth profile will, again, be in light oil as we continue to develop in the Bakken and the Cardium,” Gregg Smith, pres-ident and chief operating officer, told the conference.

The company plans to drill 95 net wells in the Cardium this year with cap-ital spending of $345 million. Its position now includes over 320 (240 net) sections

of land in the Cardium trend with over 650 net locations. “It was a natural for us to move into and piggyback off our experience with the Bakken,” Smith said. Experimentation has led the company to use monobore drilling (a single lateral well) and slick water frac completions in the Cardium.

“In the Cardium, it ’s been a little tighter for frac crews, so we’ve done a

two-year deal to ensure service with one frac crew from [Calfrac Well Services Ltd.] and we’ve negotiated windows with other companies to fill in that service,” Smith noted. “One frac crew can keep up with seven, maybe eight, drill crews so that one frac crew can probably provide most of what we need in the Cardium with just the odd window from other players.”


Central Alberta

Sure Energy Inc. has reported production test results of its 11-2 Redwater North hori-zontal well. The Viking formation was tested for 50 hours and flowed a total of 569 bar-rels (bbls) of clean light oil and 442 thou-sand cubic feet of solution gas. Rates were restricted through a 3/8-inch choke with drawdown estimated at 50 per cent.

Sure said it expects the well to pro-duce in excess of 200 bbls of oil per day initially while flowing and to stabilize at 120-150 bbls of oil per day when placed

on pump. The company’s two offsetting producers f lowed for approximately a month. The well is 100 per cent owned by the company and will qualify for the Alberta government’s Horizontal Oil New Well Royalty Rate of five per cent for 18 months, to a maximum of 50,000 bbls.

The well will be placed on production following the drilling and completion of a follow-up well at 12-2, which will be drilled from the same surface lease. This well will be the seventh and last well planned for

North Redwater in the current program. Including the 11-2 well, Sure Energy said it has experienced a 100 per cent success rate with its North Redwater horizontal drilling program to date. The company owns 7.75 sections of 100 per cent working interest lands in the Redwater North Viking play.

These lands have regulatory approved holdings allowing up to four wells per quarter section. In total, Sure Energy has 7,495 acres of net undeveloped land on the Redwater Viking oil trend.

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SOUTHERN ALBERTA WELL ACTIVITY

Southern Alberta

JAN/10 JAN/11

WEll liCENCES 242 203 ▼

JAN/10 JAN/11


JAN/10 JAN/11



Well type, not just a simple well count, has become essential for measuring oilfield activity.

Phot

o: A

aron

Par

ker

Peters boosts drill, case and complete forecast to $21.9B for 2011By Pat Roche

Drill, case and complete spending in the Western Canada Sedimentary Basin (WCSB) this year will total about $21.9 billion, predicts Peters & Co. Limited. That’s up significantly from Peters’ fore-cast in its Fall 2010 North American Energy Overview which projected 2011 spending of about $17.2 billion in the WCSB for drill, case and complete.

At the time, Peters was forecasting 10,500 wells would be drilled in the basin in 2011.

Peters now forecasts about 11,500 wells will be drilled in the WCSB this year, about 70 per cent targeting oil (including bitumen). It expects the aver-age well cost will be about $1.9 million. The investment firm also released its 2012 forecast for drill, case and complete expenditures. It expects the figure will total $23.2 billion as 12,000 wells are drilled next year.

“We continue to forecast an increase in horizontal multi-frac wells, thereby benefiting those service companies with equipment leveraged towards these types of wells,” Peters said in the oilfield services chapter of its Winter 2011 North American Energy Overview.

T he report emphasizes the wel l count is less important than the type of wells drilled.

For example, about 18,500 wells drilled in 2007 required a total of about 123,600 drilling days. In contrast, only about 12,200 wells drilled last year resulted in 124,800 drilling days, Peters says.

“Additionally, operators continue to drill wells deeper, which will result in an increase in drilling days, thereby resulting in improving equipment utilization levels for deep drilling contractors and direc-tional drilling providers,” the report notes. “Also, given the increasing well depth,

the number of fracturing stages per well will rise, thereby resulting in continuing strong demand for fracturing equipment.”

Peters says pressure pumping com-panies recently signed fracturing equip-ment to take-or-pay contracts.

The investment firm’s 2011 and 2012 forecasts include about 975 and 1,000 horizontal gas wells, respectively—or about 30 per cent of its total 2011 and 2012 gas well forecasts, up from only about seven per cent in 2009.

The evolving WCSB well profile con-tinues to benefit directional drillers, pres-sure pumpers and drilling rig contractors with deep rig fleets—particularly those with expertise in northeastern British Columbia, west-central Alberta and south-eastern Saskatchewan, the report says.

“Our 2011 forecast includes 11.1 drill-ing days per well, as well as a 44 per cent WCSB drilling rig utilization level, while our 2012 forecast calls for 11.2 drilling days per well and a 46 per cent drilling rig utilization level,” Peters says.

Due to the expected oilsands spending boom, Peters foresees significant increases in demand for coring, infrastructure con-struction, remote accommodations, tail-ings pond reclamation and maintenance services. Peters points out most new siz-able oilsands projects are controlled by majors with less financing risk and lower cost of capital than juniors.

The investment firm expects that by March 31, outstanding tenders for ConocoPhillips Company’s Surmont, MEG Energy Corp.’s Christina Lake and Suncor Energy Inc.’s Firebag 3 and 4 projects will be awarded—resulting in an estimated $850 million in 2011 construction revenues.

That includes about $250 million for Surmont, $100 million for Firebag 3, $250 million for Firebag 4 and $250 million for MEG’s Christina Lake.



Southern Alberta

While the outlook for new pipeline construction in western Canada has improved, contractors say a revival in mainline construction might not occur until 2012 or beyond as some major pro-jects get approved.

The Daily Oil Bulletin spoke to sev-eral firms, from mainline contractors to smaller contractors that build shorter pipelines and gathering systems, as well as engineering, procurement and construc-tion (EPC) firms.

Techint E&C Inc., an EPC firm, said small-inch projects—many tied to local capital expansions or debottlenecking projects—have shown the highest increase in activity this year. Techint added that mainline bid activity has not returned to pre-recession levels and will not likely do so for a few years, at least not until the next major projects, including some in the regulatory or planning stage, are put out for tender.

An executive at Parkland Pipeline Contractors Ltd., a contractor that builds pipelines in two- to 24-inch diameters, also sensed a positive change in the market. “Compared to 2010, activity levels should be a little bit better [this year] than they were,” said Mark Breakell, Parkland’s vice-president of marketing. “It ’s still pretty early to tell, and [companies] are hanging on to their wallets pretty tightly, but if you look at $90 oil, we’re oilsands specialty guys, and we’ve got work to go to in the oilsands.”

Indeed, most of Parkland’s work this year is oilsands-related, a trend other contractors confirmed. Wes Waschuk, president of Red Deer–based Waschuk Pipe Line Construction Ltd., estimated 85 per cent of his firm’s market is oilsands-driven. “Right now, the [work] is from Fort McMurray, trying to get [product] down to the Edmonton area,” he said. “In the last few years, they’ve been taking more [product] down from Edmonton to the U.S. market.”

Within Alberta, Parkland is cur-rently building a 24-inch pipeline, sev-eral shorter lines and a 50-kilometre pipeline that connects oilsands facilities for Suncor Energy Inc. Roughly 75 per cent of Parkland’s current pipeline work serves steam assisted gravity drainage

(SAGD) projects. Last year, Parkland built nearly 450 kilometres of pipe, Breakell said.

At Flint Energy Services Ltd., bid activity is up five per cent over last year on construction of smaller-gauge pipe-line (up to 24 inches). In another Flint division that builds tie-ins, gathering lines and laterals, activity is expected to be flat this year with 2010, which was up from 2009 levels, according to Guy Cocquyt, investor relations director. Pipeline and facilities construction make up 25-30 per cent of Flint’s production services revenue.

A focus on oilsands was evident in the new budget of pipeline carrier Inter Pipeline Fund, which plans to invest $223 million this year, two-thirds of it in its oilsands transportation unit. In all, about

$143 million will be spent on the Corridor, Cold Lake and Polaris pipeline systems. Most of the capital is allocated to build-ing the Polaris pipeline, which will move diluent to the Kearl and later the Sunrise oilsands projects.

Included in the $143 million is about $25 million that Inter Pipeline will spend on the Cold Lake pipeline system, while the company will invest just $5 million on conventional pipeline work this year.

According to Techint, ongoing oil-sands development is the main driver for many of western Canada’s pipelines, whether taking product out of the Fort McMurray area or bringing natural gas to its plants and upgraders. Exceptions to the rule include the proposed CO2 trunk line and others designed to move Canada’s natural gas to Asian markets, the firm said.

Waschuk estimated mainline bid activ-ity this year is up 25 per cent from last year. “In our market, things are definitely starting to pick up,” said Waschuk.

“There’s really not much out there on the market at the present,” said Rod Ruston, president and chief executive officer of North American Construction Group, a mainline contractor with con-struction divisions in other sectors, but he does see improvement coming.

After a “very significant” drop in demand for mainline construction in Canada last year, the market is on the point of turning, he said. “We’re just seeing the turn now. You probably won’t see too much in 2011, but I think in 2012, there will be a lot of pipeline con-struction activity.”

Among mainline contractors, some have noticed a narrowing of the field as competitors have dropped out of the business. “We’re in the very early stages where we’re seeing the number of bidders

is fewer,” said North American’s Ruston. “The demand for better process and safety in operations has grown. In 2009-10, [cli-ents] just said, ‘build our pipe.’ But public and government pressure on being safer, executing better and being environment-ally sensitive has resulted in probably a few of the smaller [contractors] getting out of the business.”

Other executives agreed the number of contractors has narrowed, but differed over the reasons why. “Some [contrac-tors] did not survive lean times in the early 2000s,” said Waschuk. “They maybe weren’t efficient and a few big players were knocked out. In the 1990s, it was the same thing.”

He underscored the stiff barriers to entry in mainline construction, noting the heavy capital investment required of anyone build-ing national oil and gas pipelines. Others said Canada’s stiffer environmental and regula-tory requirements are here to stay, and the current rules affecting mainline construc-tion will only grow, not diminish, over time.

Pipeline construction outlook improves but not for big-inch projects

“In 2009-10, [clients] just said, ‘build our pipe.’ But public and government pressure on being safer, executing better and being environmentally sensitive has resulted in probably a few of the smaller [contractors] getting out of the business.”

— Rod Ruston, President and Chief Executive Officer, North American Construction Group

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Southern Alberta

Oil and gas deals in the exploration and production sector reached US$73 billion in the fourth quarter of 2010 with deals for the year totalling $238 billion, up from $151 billion in 2009, according to Evaluate Energy’s database of transactions. The total deal value in the third and fourth quarters of 2010 even outscored the fourth quarter of 2009—a three-month period that included ExxonMobil Corporation’s $41-billion acquisition of XTO Energy Inc.

At least four key trends emerge from the pattern of oil and gas deals in 2010, according to Evaluate Energy:• A marked shift in Chinese activity away

from Africa towards the Americas.• A growing interest in shale plays con-

taining liquids and some interesting new innovative approaches to monetizing shale resources, prompted by the widen-ing gap between gas and oil prices.

• A trend towards taking companies private.• The nearing completion of a dramatic

series of divestitures by BP.

Following a quarter of inactivity in the third quarter, Chinese state companies satisfied their appetite for foreign assets with a flurry of deals in the fourth quar-ter of 2010, ending the year with a total of $31 billion in exploration and production (E&P) acquisitions. This compares with a total of $19 billion spent by Chinese com-panies on E&P assets in 2009.

In this time, the Chinese government has been broad-based towards the loca-tion of their acquisitions, with major deals being conducted across 14 different coun-tries, Evaluate Energy said. While Africa was the main focus of acquisitions in 2009, Canada and South America dominated China’s deals in 2010, accounting for eight of the top 10 deals by Chinese companies during the year.

Among the key drivers of deal value during the fourth quarter was the spending by Chinese companies in Latin America. The largest deal of the quarter came from Sinopec acquiring a 40 per cent

Oilpatch asset transaction activity jumped during 2010

Despite t he st rong out look for oilsands-driven pipelines, not every contractor is relying on bitumen and syn-thetic crude. Ruston, for one, acknowl-edged that the lion’s share of current Canadian pipeline work is oil-focused, but bel ieves nat u ra l gas pipel i ne de velopment will eventually resurface.

“Gas will still be a player,” Ruston said. “Even though [it’s] down on its bum, ulti-mately, the Horn River Basin will be built, and gas will be extracted from it,” he said. “It’s started now and will build up over time. There are multiple players and con-tracts up there, and there will [also] be multiple pipelines,” he said.

While mainline projects have seen a narrowing of the f ield of bidders, the same is not true on smaller pipe-lines and gathering systems. “There are bigger barriers to entry in big-inch pipelines and almost zero in small-inch pipe,” said Ruston. “It’s dead easy for a [big pipe contractor]...to bid on gather-ing systems, [but] almost impossible for a mom-and-pop [contractor] to bid on 30-40 inch pipeline.”


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Southern Alberta

stake in Repsol Brasil for $7.1 billion and gaining a foothold in the increasingly popu-lar Brazilian offshore pre-salt reserves. This sector is about to undergo major develop-ment with the massive $43-billion deal by Petrobras and consequent financing paving the way for a development charge.

The second largest deal of the quarter came from the acquisition by Bridas Corp. (50 per cent owned by the China National Offshore Oil Corp., or CNOOC) of BP’s 60 per cent stake in Pan American Energy, the second largest oil and gas producer in Argentina for $7 billion. Sinopec added further to China’s Argentinean assets by acquiring Occidental Corp.’s Argentinean E&P portfolio for $2.5 billion.

The final major deal by a Chinese company came from CNOOC farming into a 33 per cent stake in Chesapeake Energy Corp.’s liquids rich Eagle Ford shale assets. The deal marks the first major Chinese acquisition in the U.S. since CNOOC’s failed attempt to acquire Unocal Corporation in 2005.

In an effort to secure energy supplies to China’s booming economy, the gov-ernment has also entered into various

loans for oil agreements. This strategy capitalized on the disparity of economic performance between China and the majority of the rest of the world, without the risk of potential hostility from another

Chinese asset grab. Agreements are now in place with Brazil, Russia, Kazakhstan, Ecuador and Venezuela, with the latter receiving a loan of $20 billion.

While shale gas emerged as a key driver of U.S. mergers and acquisitions in early 2010, shale oil has now started to take a more prominent posit ion among the shale-focused deals, with the Eagle Ford shale play in particular attracting a lot of interest during the quarter. There were 10 deals during the quarter involving the liquids-rich por-tion of the Eagle Ford shale play, with a total value of $4.5 billion. The switch from gas-bearing shale to liquids-rich

shale is due to the large difference in realizations from oil and gas in the United States.

Talisman Energ y Inc. has taken another route to attracting increased

realizations from one of its shale proper-ties. Talisman accepted a $1-billion farm-in from the South African integrated company Sasol Ltd. in its Montney shale play in Canada. The key reason Sasol was taken on as a partner is due to the com-pany being among the global leaders in gas-to-liquids technology. The companies will be conducting a feasibility study for the construction of a gas-to-liquids plant and the case for the construction will gain strength should the gas prices remain low relative to liquids realizations.

Shale gas deals still took the majority of the value amongst shale deals in the fourth quarter however with $7.4 billion

While shale gas emerged as a key driver of U.S. mergers and acquisitions in early 2010, shale oil has now started to take a more prominent position among the shale-focused deals.

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worth of deals. The value was considerably boosted by the $4.3 billion acquisition by Chevron Corporation of Atlas Energy Inc., a company with holdings in the Marcellus and Utica shale plays.

BP continued its asset divestiture program with $10 billion of asset sales in various countries during the quarter. The most significant sales by BP include

the $7-billion sale of the company’s 60 per cent stake in Pan American Energy to Bridas, the $1.8-billion sale of the com pany’s Venezuelan and Vietnamese assets to TNK-BP, the $775-million sale of the company’s Pakistan assets to United Energy Group and the $650-million sale of certain Gulf of Mexico assets to Marubeni Corporation.

Since BP’s Macondo oil spill in April 2010, which prompted a $30-billion provi-sion to be made by the company, $21 billion worth of divestitures have now been con-ducted by BP. In July, BP reported that it is aiming for $30 billion of asset sales, which coupled with the company’s dividend freeze is aimed at fully satisfying the oil spill costs.


The shift in operator focus to oil and the application of horizontal, multi-stage frac technology to known reservoirs previously labelled uneconomic helped boost activity levels in Western Canada and put wind in the sails of service sector share prices in 2010.

Peters & Co. Limited’s Peters Energy 100 oilfield services sub-index posted a gain of 27 per cent in 2010, led by Canyon Services Group Inc. (up 361 per cent) and Pure Energy Services Ltd. (up 182 per cent). The worst performer on the index was Calmena Energy Services Inc., down

29 per cent. Pressure pumpers Calfrac Well Services Ltd. and Trican Well Service Ltd. finished up 65 per cent and 44 per cent, respectively, on the Peters Energy 100 oilfield services index.

John Tasdemir, an analyst with Canaccord Genuity, noted that the focus on complex reservoirs in western Canada will continue to benefit the pres-sure pumpers. “Those guys generally led the way [last year],” he said. “The com-panies that kind of underperformed were generally more the traditional drilling

companies just because we generally have plenty of drilling rig capacity in Canada, particularly for the shallower drilling.”

Activity in the oil-focused plays in the basin should remain strong in 2011, but Tasdemir noted the stocks “get a little more tricky. We’ve seen a pretty big run-up in sev-eral already. That’s going to make it a little more interesting to pick stocks in 2011.”

“Obviously the big winners in 2010 were the pressure pumpers, with [Calfrac] and [Trican] being up over 40 per cent each,” added Scott Treadwell, a research analyst

Service sector companies post share value gains in 2010

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Southern Alberta

with Macquarie Securities. “Canyon’s share price appreciated by 360 per cent in 2010, on top of 200 per cent in 2009, as the company shifted to mainstream pressure pumping and growth. Precision led the drillers group with 26 per cent growth in 2010, driven in large part by the horrible 2009 they had and is a testament to the focus shown by the team to right the ship and get back to leading the pack.”

Total Energy Services Inc., which saw over a 100 per cent share price increase, stands out as its drilling and compres-sion arms recovered from the downturn in 2009 and it acquired and integrated DC Energy Services Inc. into its rental arm, Treadwell added.

On the losing side, he noted that Trinidad Drilling Ltd. was one of the few names with a loss in share price in 2010, driven largely by the impact of its Mexican operations and concerns about its ability to retire debt. “With its recent debt issue, it looks like the balance sheet concerns have been resolved,” he said.

Over the last two years, which starts in some of the darkest days of the down-turn (January 2009), Trinidad is the best

performing driller at 40 per cent gain, while Calfrac has outpaced Trican 194 per cent to 153 per cent. Flint Energy Services Ltd. is up over 150 per cent, while ShawCor Ltd. is up almost 80 per cent, Treadwell said.

For the past 18 months, oil service activity has ramped up significantly largely due to North America, but a Canaccord report stated there’s upside left globally. Service intensity in North

America should remain elevated due to further growth in unconventional activ-ity and the long awaited acceleration in international exploration and production spending will finally start to more mean-ingfully contribute to the service sector.

The capital equipment cycle has also started its recovery with equipment builds in North America (rigs and completion equipment) and in the offshore markets for both deepwater and jack-up rigs. This sets the stage for outperformance for

multinational Halliburton, equipment manufacturer National Oilwell Varco and small-cap directional driller Phoenix Technology Income Fund, the Canaccord report said.

In North America, the firm expects a “range-bound” rig count environment during 2011 as growth in oil-directed drilling offsets a decline in gas activity. There should be continued growth in

directional drilling, completion services and purpose-built drilling rigs.

Oil and liquids–rich directed activity is expected to remain strong, led by con-tinued development in the Bakken, Eagle Ford, and Permian in the U.S. and Cardium, Viking and Bakken plays in Canada. As for the drillers, the Canadian winter drill-ing season was off to a strong start, and Canaccord expects to see the first big push on rig day rates in the last three years.


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Current North American natural gas over-supply issues and the strong Canadian dollar have led Calgary-based A JM Petroleum Consultants to lower its price forecast for Canadian natural gas prices. In its quarterly domestic oil and gas price fore-cast dated Dec. 31, 2010, AJM has main-tained its AECO natural gas price forecast at $4.10 per thousand cubic feet (mcf) for 2011, but has lowered its prediction for 2012 to $4.50 per mcf from the $4.70 per mcf anticipated in its prior forecast.

“For Canadian natural gas to remain competitive with U.S. natural gas, our prices have to be lower than the American prices,” said AJM economist and vice-president Ralph Glass. “A high Canadian dollar, and an increased supply of nat-ural gas from American shale plays, combined with the U.S. economic recov-ery strategy to ‘keep America working,’ is pushing Canadian natural gas out of the U.S. markets. We have to maintain

bargain basement prices to keep natural gas moving until we develop viable alter-native markets. That will mean a tough year for Canadian natural gas producers.”

With the goal of developing alternative gas markets, Apache Canada Ltd. and EOG Resources Canada Inc. submitted a joint application to the National Energy Board (NEB) to export natural gas volumes out of Kitimat, B.C., on Canada’s West Coast.

On the crude oil side, Enbridge has filed its own application with the NEB to construct a pipeline from Alberta to Kitimat.

Glass notes that these pipeline appli-cations are critical to the development of alternative markets for western Canadian hydrocarbons, and while they may even-tually change the Canadian natural gas market, this change is not happening fast enough to correct current imbalances.

“Despite marked price increases for both crude oil and natural gas in the

final weeks of 2010,” said Glass, “we anticipate the 2011 yearly averages for both commodities will remain relatively unchanged from 2010 actual prices. The continued weakness of the U.S. dollar is prompting commodity traders to turn to crude oil in particular. But with the U.S. economy showing early signs of recovery, the U.S. dollar should strengthen and reduce the speculation that is driving cur-rent price premiums.”

Outside the decrease on AECO nat-ural gas pricing, AJM’s Dec. 31, 2010 oil and gas price forecast remains consistent with its Sept. 30 forecast: NYMEX natural gas is predicted to be US$4.50 per mcf in 2011, with long-term NYMEX price rising to $6.75 by 2022. In the near future, AJM anticipates West Texas Intermediate crude oil prices will average US$85 per barrel for 2011, $87.50 per barrel for 2012 and $88 per barrel in 2013.


Canadian gas prices are unlikely to recover in 2011, AJM forecasts

The United States could “easily” become self-sufficient in natural gas, eliminat-ing the need for Canadian imports, but growing consumption in the oilsands and power generation sectors will pro-vide new demand for Canadian gas, says a gas analyst.

“The shale gas tsunami really is...going to require new pipelines. It’s going to require storage facilities—all of which are going to turn the way the industry has been doing business on its head,” Simon Mauger, director of gas services at Ziff

Energy Group, told a Canadian Institute conference in January.

But the good news for Canadian gas exporters is that gas demand for oilsands production and processing will grow by two billion cubic feet (bcf) a day by the end of the decade—just from known projects. “We have [oilsands gas demand] growth going out far beyond that as well. So it could grow to six or seven bcf a day and essentially replace all of the exports on TransCanada or some of the other pipelines,” Mauger said.

He cited t wo developments that will push outward-bound gas back into Alberta. One is the Bison pipeline in North Dakota, which just went on stream and feeds into the Northern Border pipeline, pushing out Canadian gas. Later this year, the Ruby pipeline in the U.S. Northwest will push gas back into Alberta as well.

Mauger expects North American gas production to grow by about 10 bcf a day over the next decade.


Ziff says rising oilsands demand for gas will offset weaker exports

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Saskatchewan

SASKATCHEWAN WELL ACTIVITY

JAN/10 JAN/11


JAN/10 JAN/11

WEllS SPUddEd 242 272 ▲

JAN/10 JAN/11

WEllS drillEd 206 280 ▲


PetroBakken Energy plans to spend $325 million this year in southeastern Saskatchewan.

PetroBakken sets 2011 capital budget at $800M, versus $675M in 2010

PetroBakken Energy Ltd. plans to invest $800 million on capital projects this year, up from $675 million in 2010. Current plans anticipate capital develop-ment expenditures of $680 mill ion focused predominantly on horizontal drilling and completions in the Bakken and Cardium light oil plays. The com-pany also plans to spend $120 million on land, seismic, well recompletions and direct administration expenses.

“We expect that this drilling-focused capital plan will generate a 2011 exit pro-duction rate between 46,000 and 49,000 barrels of oil equivalent [boe] per day. Our funds flow from operations and our $1.2-billion credit facility are expected to fund this activity and maintain our $0.96 per share per annum dividend,” PetroBakken said in a news release.

Capital plans for 2011 will focus pri-marily on light oil resource plays in central

Alberta for the Cardium and in southeast-ern Saskatchewan for the Bakken as well as Mississippian conventional light oil plays. The majority of 2011 capital spending will be used to to drill, complete and equip over 200 net wells (due to bilateral wells this

represents over 255 net horizontal well-bores) for approximately $590 million.

The plan also includes faci l it ies investments of $70 million, primarily in southeastern Saskatchewan, to handle new production as well as improve

ex ist ing product ion ef f ic iencies. A further $20 million will be spent on enhanced oil recovery (EOR) pilots within the Bakken.

I n sout hea ster n Sa sk atc hewa n, PetroBakken expects to dril l 75 net wells (including approximately 55 net bilateral wells) in the Bakken and over 30 net conventional wells. Facilities expenditures of approximately $65 mil-lion in this area are expected to further optimize operations and bring currently constrained Mississippian production on stream.

T he compa ny w i l l cont i nue to invest in EOR pilots to evaluate several injection configurations and f luids, including natural gas. Overall, in south-eastern Saskatchewan, PetroBakken plans on spending $325 million, com-prised of $250 million in the Bakken and $75 m i l l ion on t he conve nt ion a l Mississippian plays.

In central Alberta, the company plans on spending approximately $350 million to drill 95 net wells. Consistent with its acreage position, approximately 65 per cent of the wells will be drilled in western Pembina, 25 per cent in eastern Pembina and the balance at Garrington and

Lochend. The majority of drilling will be limited to one well per section as the company proves up its extensive acreage position. In addition, first quarter 2011 spending will include carry-over activ-ity as PetroBakken completes and adds

“We expect that this drilling-focused capital plan will generate a 2011 exit production rate between 46,000 and 49,000 barrels of oil equivalent [boe] per day.”

— PetroBakken news release


Saskatchewan

production from wells that were drilled in the fourth quarter of 2010.

The remainder of the 2011 program is more explorator y in nature, and PetroBakken expects to drill between four and seven net wells. Two net wells will be drilled in northeastern British Columbia at Monias to preserve acre-age, while the remaining wells will be drilled in other areas. The majority of the planned $45 million of capital spending for this program is for drilling

and completions, with approximately 10 per cent allocated to facility costs in northeastern British Columbia. These capital investments are planned to enhance the long-term value of the com-pany’s drilling inventory by preserving its extensive natural gas options in north-eastern British Columbia and evaluating new resource plays.

Exit production for 2011 is expected to be between 46,000 and 49,000 boe a day, up from 42,500 boe a day for

year-end 2010 (based on f ield esti-mates), including replacing 2011 base production decline of approximately 40 per cent. Most of the production growth is expected to come from the Cardium area in central Alberta while the company ’s more mature assets in sout heaster n Saskatchewan are expected to remain relat ively f lat. Approximately 85 per cent of production is light oil and natural gas liquids.


T h e I n t e r n a t i o n a l P e r f o r m a n c e Assessment Centre for Geological Storage of CO2 (IPAC-CO2) is assembling a team of international experts to conduct an inde-pendent performance assessment of proto-cols and practices in the Weyburn carbon capture and storage (CCS) project fol-lowing complaints from a Saskatchewan family about the possibility of CO2 leaks at their farm.

The report, Geochemical Soil Gas Survey, was conducted by Paul Lafleur of Petro-Find Geochem, Ltd., and sub-mitted to Cameron and Jane Kerr. That report is currently under review by Saskatchewan’s Petroleum Technology Research Centre. A response to this report will be provided once it has been thoroughly reviewed.

IPAC- CO2 is an env ironmenta l, non-government organization created in 2009 to gain public and regulator confidence in the geological storage of CO2 as a sustainable energy and environ-mental option by providing independent performance assessments of the projects.

“This will be a fact-based review,” said Carmen Dybwad, IPAC-CO2’s chief executive officer. “The object is not to determine fault or point fingers. It is simply an analysis of whether there is leakage and, if so, to discover its root cause. Results of this independent study will help establish the ‘best practices’ for future CCS projects that include an enhanced oil recovery component.”

A detailed list of the team members will be released once all of the experts have been conf irmed. Part icipants

in the project, so far, include experts from the Gulf Coast Carbon Center at the University of Texas and Carbon Management Canada Ltd., a network of 22 Canadian universities researching large-scale ways to reduce carbon emis-sions in the fossil fuel industry. To par-ticipate in the independent review, each expert must not have had any previous association with the Weyburn project, Dybwad said.

“We will apply the nine-step protocol for site assessment we developed while working with the Canadian Standards Association to draft the world’s first standard for geologic storage of carbon dioxide,” Dybwad said.

The draft, which establishes a bi-national standard, is being reviewed by a technical committee of almost three dozen experts from Canada and the United States. The new standard will also be used as a basis for international standards through the International Organization for Standardization.

Cameron and Jane Kerr held a news conference on Jan. 11, 2011, in Regina demanding a full public investigation of problems at their farm located near the Cenovus Energy Inc. CCS site. The Kerrs said they had first noticed changes in sur-face water and well water on their prop-erty in 2004, one year after CO2 injection in the area had begun.

About 17 million tonnes of CO2 have been injected into the Weyburn oilfield over the past decade. It is recognized as the largest, commercial-scale CCS project in the world.

The International Energy Agency’s Greenhouse Gas Weyburn Midale CO2 Monitoring and Storage Project has been involved in measuring and monitor-ing injection of CO2 into the Weyburn and Midale oilfields in southeastern Saskatchewan since the year 2000.

As part of this research, an extensive program of sampling soil gases and shal-low water wells across the CO2 injection area has been undertaken for almost 10 years. Baselines for CO2 in the soils and wells were taken in multiple loca-tions starting in July, 2001, prior to any injection, and several surveys have been repeated periodically since injection began.

The soil gas surveys were conducted by independent research organizations including the British Geological Survey, the French Geological Survey and the Italian Geological Survey. These tests all have indicated that soil gases sam-pled are in the normal range for these soil types given variations in organic matter content, moisture, temperature and seasonal variations.

No evidence of CO2 originating from the 1.5-kilometre deep Midale reser-voir (the geological unit at the Weyburn f ield) has been obser ved in any of these sur veys undertaken by these international scientific organizations. Similarly shallow well water samples taken repeatedly throughout this study over 10 years have not indicated any evidence of CO2 from the deep geologi-cal reservoir.


Researchers will study alleged carbon dioxide leakage into farm near Weyburn

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Saskatchewan

CanElson Drilling Inc. has entered into an agreement to acquire Eagle Drilling Services Ltd., a private corporation that owns eight telescopic double drilling rigs in the Bakken area of southeastern Saskatchewan. CanElson has agreed to make an offer to acquire all of Eagle’s out-standing common shares for $61 million (plus the assumption of debt of approxi-mately $17.1 million).

The pre-acquisition agreement pro-vides for a break fee of $2.5 million pay-able by Eagle to CanElson under certain circumstances. CanElson will acquire eight fully crewed, modern, heav y-duty, telescopic double rigs (ratings of 3,500 metres vertically, 4,300 metres horizontally); positive working capital estimated at $6 million; land and build-ings with an estimated value of $3.5 mil-lion; and rental and ancillary equipment with an estimated value of $3.5 million, which equates to a purchase price per rig of approximately $8.1 million.

The company expects that key employ-ees and management of Eagle will be

retained and continue with CanElson. Daily Oil Bulletin records show Eagle drilled 152 wells last year while CanElson drilled 105 wells in Canada. Eagle’s key customers were Crescent Point Energy Corp. (57 wells) and PetroBakken Energy Ltd. (35 wells).

By the end of the first quarter of 2011, and including the closing of the acquisi-tion, CanElson will operate a combined rig fleet of 27 (net 23) rigs which includes 18 drilling rigs in western Canada, five (net four) drilling rigs in the Permian Basin west Texas, two (net one) subcon-tracted drilling rigs in Mexico and two (net one) service rigs in Mexico. 100 per

cent of CanElson’s owned drilling rig fleet is deep, small footprint telescopic double drilling rigs rated greater than 3,500 metres with an average age of less than three years designed for horizontal and resource play drilling.

“Eagle is one of the most respected contract drilling providers operating in southeast Saskatchewan and southwest Manitoba that has consistently realized higher-than-industry utilization levels and also has a reputation as an effi-cient and safe drilling contractor,” said CanElson president and chief executive officer Randy Hawkings.

CanElson buys Eagle Drilling for $78M

“Eagle is one of the most respected contract drilling providers operating in southeast Saskatchewan and southwest Manitoba that has consistently realized higher-than-industry utilization levels and also has a reputation as an efficient and safe drilling contractor.”

— Randy Hawkins, President and Chief Executive Officer, CanElson Drilling Inc.

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reef plans to use recycled natural gas for enhanced oil recovery in a pinnacle reef formation.

Reef Resources Ltd. says its corporate objectives for 2011 include drilling a new Ausable No. 5 oil well in Ontario this winter. The well will increase over-all production and will provide valuable geological data for future gas storage, the company said. Reef also plans to fish frac tools that have impeded production from the Ausable No. 2 using the drilling rig available after Ausable No. 5 is drilled.

The company said it achieved produc-tion of oil and natural gas condensates in 2010 by executing a gas recycling and enhanced oil recovery (EOR) program on its Ontario property.

The EOR and gas-recycling program initiated in October has so far produced 20-40 barrels (bbls) per day of oil and petroleum condensate since start-up. The company will be optimizing its down-hole pumping configuration in the near future to increase production including the installation of a hydraulic pump in Ausable No. 1 on a trial basis.

The current EOR program confirms the company ’s assessment that the Ausable pinnacle reef will produce con-siderably more oil and natural gas liquids

by re-pressurizing and recycling natural gas through the reservoir, Reef said.

The proposed EOR program involves purchasing low-cost natural gas to pres-surize the reef and increase recycle vol-umes, thereby increasing production; drilling four new horizontal wells; and installing a refrigeration plant to strip natural gas liquids.

It is anticipated that up to five mmcf a day of natural gas will be injected and recycled through the reef using two of the four new horizontal wells. The goal is to produce significant levels of oil and natural gas liquids (propane, butane and condensate) from the other two new hori-zontal production wells in addition to the existing four wells. The recycled nat-ural gas will be processed using a minus 40 degrees Celsius refrigeration plant to recover propane, butane and condensate.

Reef’s goal is to have the four horizontal wells and associated on-site infrastructure in operation by summer 2011. The com-pany said it has identified three additional Silurian pinnacle reefs within its 23,000-acre 3-D seismic database.


Reef Resources outlines Ontario enhanced oil recovery program

Newsman Peter Kent named federal environment minister A former television journalist is Canada’s new environment minister. MP Peter Kent, who represents Thornhill near Toronto, replaces Calgar y MP Jim Prent ice who lef t t he gover nment late last year for a job in the private sector. Prime Minister Stephen Harper announced the appointment as part of a cabinet shuffle in January.

Prior to his election in 2008, Kent was a broadcast journalist, spending more than 40 years working as a writer, reporter, producer, anchor and senior executive in Canada, the United States and around the world after beginning his career in Calgary.

Calgary MP Diane Ablonczy will replace Kent as minister of state of foreign affairs (Americas and consular affairs). In that role she will further promote Canada’s political and trade interests in the Americas and help protect Canadians travelling and working outside the country.

As minister, Kent will be in charge of his government’s efforts to improve Alberta oil-sands water monitoring systems as Canada comes under increased global scrutiny for its environmental regulation of the oilsands. Late last year, John Baird, acting environ-ment minister, announced he has directed senior department officials to work together to design a water monitoring system by the end of March. The government will then consult with a group of independent scien-tists to ensure that the proposed design is appropriate and then move immediately to implementation, he said.

The announcement followed the release of a report by a Prentice-appointed panel that was critical of the existing monitoring efforts by provincial and fed-eral governments and other stakeholder groups, including industry.

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Bidding is ramping up this year for Newfoundland’s Hebron projectBy Pat Roche

Bidding is expected to ramp up this year for most of the contracts for the biggest construction project in Newfoundland-Labrador since Hibernia was developed in the 1990s. The Hebron offshore project will be the province’s fourth standalone oil development after Hibernia, Terra Nova and White Rose.

Like Hibernia, Hebron will be produced from a concrete gravity-based structure (GBS) sitting on the seabed. Capable of stor-ing about 1.13 million to 1.45 million barrels (bbls) of oil, the Hebron GBS will be 120 metres tall—about the height of a 40-storey building. Construction of the GBS is sched-uled to start in the second quarter of 2012.

From a logistical standpoint, the deci-sion to develop Hebron with a GBS makes it impossible to build the main structure overseas. The structure—the equivalent of a high-rise office building—has to be built as close as possible to the oilfield it will produce because near-perfect sea and weather conditions are needed for the slow and painstaking operation of towing it to the desired location.

In addition to building the towering gravity base in Newfoundland, operator

ExxonMobil Canada Properties, a unit of Exxon Mobil Corporation, has said it will also build most of the steel topsides com-ponents in the province if capacity exists. The exception is the utilities and processing module, which will be bid internationally.

Hebron topsides components will include a drilling rig, production equip-ment, a control centre, a f lare boom, utilities, a helicopter landing pad, living quarters and lifeboat stations.

It is unclear whether the province has sufficient spare capacity to absorb a $4- billion to $6-billion megaproject—espe-cially since the St. John’s area is already in the midst of a construction boom.

The Hebron field was discovered in 1981, but the total project will tap three oilfields—Hebron, Ben Nevis and West Ben Nevis. The project is expected to recover 566 million bbls of oil over about 30 years, starting in 2017. Most of the oil is about 20 degrees API gravity. Oil pro-duction is expected to be in the 120,000-175,000 bbls a day range.

Owners are: ExxonMobil (36 per cent); Chevron Canada Limited (26.7 per cent); Petro-Canada Hebron Partnership,

now owned by Suncor Energy Inc. (22.7 per cent); Statoil Canada Ltd., a unit of Norway’s Statoil ASA (9.7 per cent); and Nalcor Energy—Oil and Gas Inc., which is owned by the Newfoundland government (4.9 per cent).

Hebron’s main construction site will be the currently idle Bull Arm onshore and near-shore fabrication complex in Trinity Bay, 150 kilometres northwest of St. John’s. According to regulatory filings, initial work—slated to start in the second quarter of this year—will prepare Bull Arm and re-establish the temporary dry-dock that was originally built for Hibernia GBS construction in the 1990s.

Early activities include blasting, dredging and drydock construction. A row of sheet piles will be pounded into the seabed to create a rock-fill dyke, or “bund wall.” This will dam off the inner portion of a cove, which will be then be dewatered for use as a drydock. The GBS drydock area is about 16.5 metres deep and 180 metres in diameter.

Topsides fabrication is expected to take about 30 months at several sites. Final assembly and integration of all topsides modules will occur on the top-sides pier at Bull Arm. A partly finished GBS will be f loated out of the drydock and towed to Bull Arm’s nearby “deep-water” site. Here the concrete base will be moored in 180 metres of water for final construction and mating with the steel topsides modules.

The massive structure will be towed to the Hebron field, 340 kilometres east of St. John’s, where it will be weighted with bal-last until it rests on the sea floor in about 100 metres of water. The intended loca-tion isn’t far from the Hibernia platform, Canada’s first and only GBS.

Most of the Hebron contracts are expected to be awarded this year once the front-end engineering and design (FEED) has been completed. A few years ago the Hebron price tag was estimated at $4 bil-lion and $6 billion, but the FEED will narrow that range. Both FEED contracts were awarded last year.


if all goes well, the hebron initiative will become Newfoundland's fourth offshore oil operation.

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ExxonMobil expects natural gas to fuel more than a quarter of global electricity generation by 2030.

ExxonMobil sees natural gas as the world’s fastest growing fuel to 2020By Pat Roche

Natural gas will be the world’s fast-est growing major energy source in the next two decades, overtaking coal as the second-largest global energy source behind oil, says energy giant ExxonMobil Corporation. The company made the pre-diction on Jan. 27 in releasing the 2011 edition of its Outlook for Energy: A View to 2030.

Asia is forecast to have the larg-est growth with gas demand almost tripling by 2030. Substantial growth is also expected in Europe and North America. “The forecasts...show a shift toward natural gas as businesses and gov-ernments look for reliable, affordable and cleaner ways to meet energy needs,” said Rex Tillerson, ExxonMobil’s chairman and chief executive officer. “Newly unlocked supplies of shale gas and other unconven-tional energy sources will be vital in meet-ing this demand.”

U.S. President Barack Obama’s new plan to double U.S. clean power output is expected to help boost gas usage. U.S. Energy Secretary Steven Chu said the plan represents roughly a doubling of electricity generation from cleaner power

sources in less than 25 years. The plan, introduced by Obama in his State of the Union speech on Jan. 25, would require power plants to generate 80 per cent clean electricity by 2035.

ExxonMobil expects total global energy demand to be about 35 per cent higher in 2030 than in 2005 and energy demand in the developing nations to rise more than 70 per cent. However, global growth would be far higher without pro-jected efficiency improvements, the fore-cast says.

Efforts to ensure reliable, affordable energy—while also limiting greenhouse gas emissions—will lead to policies in many countries that put a cost on CO2 emissions, the report predicts. As a result, gas will become increasingly competitive as an economic fuel for electricity genera-tion as its use results in up to 60 per cent less CO2 emissions than coal in generat-ing electricity.

Demand for gas for power generation is expected to rise by about 85 per cent from 2005 to 2030 when gas will provide more than a quarter of the world’s electric-ity needs. Gas demand is rising in every

region of the world and is strongest in developing countries, particularly China, where demand in 2030 will be about six times what it was in 2005.

ExxonMobil said its outlook is based on a detailed analysis of about 100 coun-tries, 15 demand sectors and 20 fuel types, and it is underpinned by economic and population projections and expectations of significant energy efficiency improve-ments and technology advancements.

Rising electricity demand—and the choice of fuels used to generate that elec-tricity—represent a key focus area, which will have a major impact on the global energy picture over the next 20 years, the company says. ExxonMobil expects the number of cars and trucks on the road to increase by 400 million vehicles by 2030—and oil will remain the main trans-portation fuel source.

“No technology has been able to out-perform gasoline and diesel as con venient and economic fuels for consumers,” said Bill Colton, ExxonMobil’s vice- president of corporate strategic plan-ning. “The weight of a fuel is critical for transportation.... Even for cars, it’s hard to beat the high energy density of gaso-line. A typical car gas tank contains...only 100 pounds of gasoline, yet it can motor a 3,000-pound car for 400 miles at 60 miles an hour,” he said.

Nuclear also shows strong growth. “We believe nuclear is an attractive alter-native, yet we acknowledge there’ll be practical limits as to how fast new nuclear plants can be sited and built,” Colton said. And while solar and biofuels will be the fastest-growing fuel sources—almost 10 per cent growth—by 2030 they’ll still account for only 2.5 per cent of the global energy demand, ExxonMobil predicts.

CO2 emissions are expected to increase by about 25 per cent by 2030, signifi-cantly less than overall energy demand increases. Efficiency gains across all sec-tors of economies worldwide should curb energy demand growth through 2030 (compared to historical trends) by an esti-mated 65 per cent.


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CAREERS IN ThE OILPATCh

have you been in the scaffolding business your whole life?My first job was in 1989. I was hired by Rick Moran at U-Max (now it’s Aluma Systems). I started quite young, but it took me several years to finish my apprenticeship, because I kept on going and doing other things. I went to university for three semesters and just decided that wasn’t for me. Scaffolding appealed to me on an adrenalin basis—work hard and get up high in the air, travel around a fair bit because you’re usually not in one place for too long.

so is the appeal that you like working with heights?It’s not that I like them. I enjoy the focus that hard work at heights brings, because you have to concentrate or you’re going to get hurt—or hurt somebody else, even worse. I found two things: I was well equipped for it personally in that I’m a pretty big, strong guy, and I’m pretty nimble. So I could get around, get things done comfortably. I don’t have a lack of fear of heights; I don’t have a serious fear of heights. Certainly, I’ve always been respectful of them. That being said, I can move a lot of gear.

do you find it rewarding to have your own company?I just love it. My whole life has been a challenge to fight bore-dom. I used to read books under my desk—just hold them under my desk—because whatever was going on at the front of the classroom was boring, and I could find a book that was more interesting. It’s been a theme through my whole life. I’ve always played fast moving sports—rugby, football, squash—because the focus required to do those things is pleasurable. And I’ve got to say the focus required to oper-ate a business...I mean, it’s the most difficult thing I’ve ever done, but I’m not bored, and I’m grateful for that.

what’s the biggest challenge you’ve faced with this job?The biggest challenge I find is that I’m wearing so many hats. I’m trying to track so many things. It’s a job probably best suited to a woman who has raised several children. My goal in life these days is to take off a hat and give it to someone—I don’t care which one it is. I’m my own project manager/super-intendent/sales and marketing guy, and it all goes through me. And I’m acutely aware that if we’re going to grow this business, I’m going to have to delegate these things. But of course you have to be confident you can make enough money in the next 12 months that you can bring someone in to do that. It’s a tricky equation.

JonathanHokansonAge: 40title: Ownercompany: Standard Scaffold incorporatedlocation: Sherwood Park, Alta.


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A LOOK AT NEW TEChNOLOGIES

TOOLSOF ThE TRADE

information supplied by: Martin campbell, Manager, bPc trenchless Pipeline systems

BPC Trenchless Pipeline System

who is bPc services group?BPC provides pipeline integrity and construction services to midstream pipe-line companies and pipeline services to upstream producers. Our service area includes Alberta, Saskatchewan and Manitoba.

what is the bPc trenchless system?Smaller pipelines—less than 1,000 metres in length—have traditionally required the same ground disturbance as larger projects in terms of topsoil removal, trenching and reclaiming the pipeline right-of-way to its original condition. BPC has developed a system to install these lines with far less dis-ruption to the environment and property stakeholders. We utilize horizontal directional boring along with state-of-the-art mapping and product-coating integrity surveys after pipe placement, ensuring the pipeline is fully compliant with all regulations and customer requirements.

what are the competitive advantages of trenchless installation?Installation through directional drilling greatly reduces disturbance to the en vironment as well as lease pads, containment barriers, roads, canals, irriga-tion equipment and other infrastructure that may be encountered along a pipe-line route. The minimal disturbance to the environment allows for construction within delicate ecosystems such as native prairie and forested areas.As an example, BPC recently completed an 800-metre pipeline from an oper-ating multi-oilwell production pad to a compressor station. The right-of-way traversed arable farmland, forested areas and an existing highway complete with overhead power lines, underground telephone and fibre optic lines. The forestry owner expressed great concern over the removal of large trees along the route. When the petroleum producer offered to install the pipe using BPC’s trenchless techniques, this land owner agreed to approve construction without further delay. The pipeline was then installed in one continuous pass from loca-tion to location. No disruption whatever occurred beyond the boundaries of the existing leases, and this project was completed at a cost equivalent to open cut pipeline construction methods. The line is now in service, with no future right-of-way concerns such as soil settling and revegetation.Thanks to reduced ground disturbance, our clients typically report many sav-ings such as frost ripping, topsoil conservation and reseeding right-of-ways and contouring. The construction window for BPC’s form of construction is also seasonally extended, enabling producers to achieve cash flow more quickly.

what future development path do you see for trenchless pipelining?Responsible operators in the oil and gas industry are continually striving to reduce their environmental footprint. For that reason, our customers are very receptive to trenchless installation. In fact, BPC believes that its trenchless techniques will become an industry standard for short infield tie-ins and longer projects in sensitive areas.

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look, Ma, no trench: BPC drilled horizontally between the two sites above.


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building local partnerships for success

www.bakerhughes.com/canada

As a leading provider of oilfield services around the world, Baker Hughes

is committed to supporting the communities where we operate. From

Fort St. John, British Columbia to St. John’s, Newfoundland, our people

make valuable contributions in these communities everyday – coaching

youth sports teams, sponsoring and hosting community events, and leading

the charge in many ways that improve our neighborhoods.

Baker Hughes continues to invest in both the infrastructure and our people

across Canada with growing operations in key locations including Grande

Prairie. As we further develop our business in the area, employment

opportunities and community involvement will persist.

To find out how our global experience,

well-trained local workforce, and

unmatched technology portfolio can

improve your recovery, contact your

local Baker Hughes representative or

visit us online.

oil & gas inquirer | march 2011

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