Oil & Gas Inquirer - September 2009 by JWN | Trusted energy intelligence

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Keeping readers regionally informed

Steaming ahead To heck with the recessionâ&#x20AC;&#x201D;operators continue investing at Cold Lake Nailing tailings: Cleaning up the ponds Beating a bum rap on oilsands emissions Light roads: Minimizing ground disturbance

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Table of Contents

Keeping readers regionally informed

F E A T U R E S

September 2009 • OIL & GAS INQUIRER

Steaming ahead

Nailing tailings

Beating a bum rap

Light roads

by Darrell Stonehouse

To heck with conserving capital—bitumen producers are proceeding with expansions and new projects at Cold Lake

by Lynda Harrison

Researchers close in on innovative ways to speed up reclamation of bitumen mine tailings ponds

by Paul Wells

New research indicates that oilsands generate little more greenhouse gas on a per-barrel basis than other crudes—and emissions are falling

by Graham Chandler

Wood fibre and floating access roads aim at minimal ground disturbance

Table of Contents

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N E W S

British Columbia

• NEB says shale gas will play a larger

• Drilling costs decrease in parallel

role than previously expected

with reduced field activity

• Abu Dhabi’s Taqa North acquires

• Canada’s largest energy

Horn River parcels for $63.3 million

Northwestern Alberta • EnCana outlines its northern drilling

company is born through

its activities over the next year • Baytex buys heavy oil assets

Gage holdings

• Oil prices are up, costs down, but

for $93 million

to GDP over the next 25 years

• Alberta short-lists CCS projects

Central Alberta

Central Canada

On-site break rooms

• CERI says petroleum will add trillions

new upgraders are still stalled for $2 billion in provincial funding

Saskatchewan • Oilsands Quest has funds for

• Pemberton plans to develop its

Northeastern Alberta

Training facilities

Suncor-Petro-Canada merger

plans and operating costs

Southern Alberta

International • BJ Services fares better

• Bonavista buys EnCana assets in central

internationally than in North America

Alberta core area for $694 million

• Savanna enters the Mexican market

• Energy Quest signs agreement with

Manufacturing

with four rigs

Cancen to test upgrader Cover Design: Tina Tomljenovic Cover Photo: Joey Podlubny

I N

E VE R Y

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• Completions data, spot gas prices,

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CALGARY OIL & GAS INQUIRER • September 2009

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Editor’s Note Vol. 21 No. 9 President & ceo Bill Whitelaw | bwhitelaw@junewarren-nickles.com Publisher Agnes Zalewski | azalewski@junewarren-nickles.com Associate Publisher Chaz Osburn | cosburn@junewarren-nickles.com Editorial director Stephen Marsters | smarsters@junewarren-nickles.com EDITORIAL Editor

Mike Byfield | mbyfield@junewarren-nickles.com Editorial Assistance

Samantha Kapler, Marisa Kurlovich proofing@junewarren-nickles.com

Mike Byfield | mbyfield@junewarren-nickles.com

Contributors

Graham Chandler, Lynda Harrison, Richard Macedo, James Mahony, Darrell Stonehouse, Paul Wells Creative Print, Prepress & Production Manager

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DIRECTOR OF SALES

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Cristian Ureta | cureta@junewarren-nickles.com OFFICES Calgary Downtown 300, 999 – 8 Street S.W. | Calgary, Alberta T2R 1N7 Tel: 403.209.3500 | Fax: 403.245.8666 Toll-Free: 1.800.387.2446 Calgary North 300, 5735 – 7 Street N.E. | Calgary, Alberta T2E 8V3 Tel: 403.265.3700 | Fax: 403.265.3706 Toll-Free: 1.888.563.2946 Edmonton 6111 – 91 Street N.W. | Edmonton, Alberta T6E 6V6 Tel: 780.944.9333 | Fax: 780.944.9500 Toll-Free: 1.800.563.2946

Eating oil In my teens, I paddled from La Loche in northern Saskatchewan to Fort Providence, near the point where Great Slave Lake flows into the Mackenzie River. On that trip, just north of a hamlet

called Waterways, I wandered across a nearly empty worksite run by a company with the odd name of Great Canadian Oil Sands (GCOS). All I could see was rebar sticking out of a few concrete footings—the beginnings of what is now the Suncor mine and upgrader hardly looked like the foundation of a future provincial economy. Business is often funny that way. From the sixteenth to the nineteenth centuries, the upper class European males (and often ladies as well) favoured hats made from beaver felt—glossy, supple, capable of holding its shape when wet. A fashion fad, long gone. Yet in search of beaver pelts, men struggled down raging rivers and across inland seas in canoes made of birchbark. Not a material likely to win approval from modern safety regulators. Thanks to those fur traders, Canada exists. Like beavers, Canadians were soon “eating” trees. From Nova Scotia to Ontario, lumber financed nationhood, later joined by the forestry of British Columbia. On the nearly treeless plains, men learned to grow commercial grain crops under conditions as harsh as any in the agricultural world. In our past, Canadians were railway makers, mine diggers, war winners, law enforcers—in short, nation builders. Now most of us listen to whining greens, cringing over one exaggerated ecological fear-fantasy after another. The oilpatch, I’m pleased to report, continues to create in the pioneering tradition. A generation ago, when I wandered across that GCOS site, the concept of deriving gasoline from tarsand struck me as quite a challenge, but still plausible. At that point, hardly anyone even wondered whether the same gumbo could be forced to flow into underground wellbores. Amazingly, as Darrell Stonehouse describes in this issue of Oil & Gas Inquirer, steamdriven bitumen production has become more economically attractive than mining, at least for the moment. Yes, in situ risks are greater—reservoir science and engineering for this sector remain at a fairly early stage—but even so, investment dollars are being committed and oil is being pumped. Our dollar strengthens and weakens in sync with the price of crude, and a great many Canadians now eat thanks to oil. So congratulations to the folks who make that possible. Most of your fellow citizens aren’t particularly grateful for your skill and effort, but we should be.

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Telephone: 1.866.543.7888 Email: circulation@junewarren-nickles.com 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 | © 2009 1062810 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 the Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.

N E X T

I S S U E

Northeastern B.C

If you know an admirable person to profile in

Despite the downturn in North American

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hydrocarbon is fuelling unprecedented

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email mbyfield@junewarren-nickles.com. In fact, feel free to sound off about any concern at all—that’s a personal invitation.

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

Stats

FAST NUMBERS

52 deepwater rigs

AT A GLANCE

121 offshore rigs

The combined rig fleet of jackups , semisubmersibles, and drill ships employed this summer by the three most active private producers. These companies were Royal Dutch Shell (22), Chevron (15), and BP (15). ExxonMobil contracted 10.

The total offshore drilling fleet employed this summer by three large state-owned producers. These companies were Brazil’s Petrobras (46), Mexico’s Pemex (38), and India’s ONGC (37).

Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

MONTH

OIL

GAS

OTHER

T O TA L

MONTH

OIL

GAS

D RY

SERVICE

T O TA L

Aug 2008 Sep 2008 Oct 2008

262 414 297

372 1,084 937

70 200 241

704 1,698 1,475

Aug 2008 Sep 2008 Oct 2008

590 728 636

501 1,250 1,308

71 173 194

19 77 69

1,181 2,228 2,207

Nov 2008 Dec 2008 Jan 2009

273 496 156

1,075 1,793 606

136 200 96

1,484 2,489 858

Nov 2008 Dec 2008 Jan 2009

594 917 248

1,313 2,380 813

142 173 70

45 137 47

2,094 3,607 1,178

Feb 2009 Mar 2009 Apr 2009

116 321 111

899 979 344

120 317 140

1,135 1,617 595

Feb 2009 Mar 2009 Arp 2009

269 433 111

1,060 1,121 342

113 165 61

36 86 12

1,478 1,805 526

May 2009 Jun 2009 Jul 2009

71 36 79

187 143 178

53 42 77

311 221 334

May 2009 Jun 2009 July 2009

71 177 79

187 211 31

46 45 6

35 27 3

339 460 119

Wells Drilled In British Columbia

Wells Drilled In Saskatchewan

Source: B.C. Oil and Gas Commission

Cumulative to July 3, 2009 Source: Saskatchewan Energy & Resources

MONTH

WELLS DRILLED

C U M U L AT I V E *

Aug 2008 Sep 2008 Oct 2008

79 83 66

630 713 779

Nov 2008 Dec 2008 Jan 2009

61 79 125

840 919 125

Feb 2009 Mar 2009 Apr 2009

117 75 33

242 317 350

May 2009 Jun 2009 Jul 2009

26 19 32

376 395 427

* from fromyear year to to date date

OIL

GAS

OTHER

D RY

T O TA L

183 46 23 29

4 28 170 0

8 4 3 11

4 16 3 19

199 94 199 59

23 4 24 282

0 0 0 0

23 4 24 282

206 50 47 311

4 28 170 0

8 4 3 11

4 16 3 19

222 98 223 341

Vertical Wells

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Lloydminster Kindersley Swift Current Estevan Total Wells

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September 2009 • OIL & GAS INQUIRER

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

GAS STOR AGE

Source: Natural Gas Exchange Inc.

Source: U.S. Energy Information Administration 3.5

2.75

Tcf

Cdn$/GJ

3.25

in the United States

$2.91/GJ Total vol.: 1,494 TJ Transactions: 157

2.25 Jul 15

Jul 22

Jul 29

Aug 5

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2.5

Aug 12

Jul 10

Jul 17

Jul 24

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada August 17, 2009 Source: Rig Locator

Alberta July2009 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

AC T I V E

Alberta

113

481

594

19%

British Columbia

113

27%

Manitoba

55%

Saskatchewan

122

34%

190

650

840

23%

33%

WC Totals Northwest Territories

Alberta

GAS WELLS

Jul 09

Jul 08

Jul 09

Jul 08

Northwestern Alberta

129

Northeastern Alberta

Central Alberta

106

144

Southern Alberta

116

265

TOTAL

183

178

543

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada August 17, 2009 Source: Rig Locator

Alberta July 2009 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

AC T I V E

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

Western Canada Alberta

Alberta 290

594

884

33%

British Columbia

34%

Manitoba

83%

Saskatchewan

101

180

56%

WC Totals

415

702

1,117

37%

50%

Northwest Territories

Aug 7

OIL WELLS

(Per cent of total)

Western Canada

Jul 31

BITUMEN WELLS

Jul 09

Jul 08

Jul 09

Jul 08

Northwestern Alberta

Northeastern Alberta

Central Alberta

Southern Alberta

TOTAL

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OIL & GAS INQUIRER • September 2009

To heck with conserving capital—bitumen producers are proceeding with expansions and new projects at Cold Lake by Darrell Stonehouse

With over 200 billion barrels of bitumen in place, the Cold Lake deposit represents an elephant oil resource by any measure. True, it’s usually been overshadowed by the Athabasca oilsands, more than six times larger in volume, that lie immediately to the north. But nearly $100 billion in Athabasca projects remain deferred or cancelled. At Cold Lake, in contrast, new projects are being launched and established producers continue to expand.

September 2009 • OIL & GAS INQUIRER

“The first thing you look for is a quality reservoir, which means the rock. If you get the rock right, you have a good chance at success,” Richard Todd, chairman and CEO of Osum Oil Sands Corp., told an investment symposium sponsored by the Canadian Association of Petroleum Producers (CAPP) in late June. “Cold Lake is the rock-solid foundation for our company. It’s the best of the best in the Canadian in situ oil business. It’s

the region where the most thermal in situ production comes from. Between 10 and 15 per cent of Canadian oil production comes from this area.” Osum’s Taiga thermal project targets bitumen production of 35,000 barrels per day. The private company has shot 20 kilometres of 2-D seismic, 32 square kilometres of 3-D seismic, and drilled 52 core holes on its 29-section prospect. A commercial application is scheduled for this

Feature

year, with first oil expected in 2014. “We are planning on going to full production. We are not a land flipper,” Todd said. The company is high on Cold Lake for a number of reasons. Bitumen is a higher quality than in the Athabasca region, at an average 11°API. The Cold Lake deposit is also closer to market, meaning lower transportation costs. But probably most important is the long experience developers have in thermal in situ production at Cold Lake.

Because of this experience, less upfront experimentation is necessar y before commercial development. “There’s no need to pilot; we are going right to commercial development,” Todd told the CAPP investor meeting. Osum has raised $375 million to finance Taiga. Horizontal wells are planned for both steam assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS). Besides well pads, the project’s components

include a central steam generation plant plus steam delivery and product recovery pipelines. Water treatment and recycling, bitumen treatment, and deep wells for safe disposal of concentrated brackish water will also be installed. Osum is evaluating the possibility of electricity cogeneration to increase overall energy efficiency. Imperial Oil Limited was the original pioneer producer at Cold Lake, first piloting thermal development in the area in

Photo: Joey Podlubny

OIL & GAS INQUIRER • September 2009

Feature Photo: Joey Podlubny

Imperial Oil has designed its new LASER (liquid-assisted steam-enhanced recovery) technology to boost bitumen recovery from older CSS wells.

the 1960s before launching commercial production in 1985. Since then, the company has developed 13 commercial CSS phases. Daily production now averages 150,000 to 160,000 barrels from over 4,000 wells located on approximately 200 pads. Its leases total 190,000 acres. Imperial’s next move at Cold Lake will be the Nabiye bitumen development, with a resource base of 250 million barrels. When completed, Nabiye will produce 30,000 barrels a day. Imperial received regulatory approval for the expansion in 2004, but has since changed its plans in response to new technologies. Those amendments should be filed with provincial authorities later this year. The alterations include a 170-megawatt cogeneration facility and pad layout changes that will reduce the production footprint. Sulphur recovery units have also been added. The original Nabiye plan also calls for the construction of steam generation, bitumen and water processing 14

September 2009 • OIL & GAS INQUIRER

facilities, and other field facilities. When the project was first proposed, Imperial put the cost at around $700 million. No new cost estimate has been released. Imperial president and CEO Bruce March expects the Nabiye expansion to be on stream by 2015. March said the development would follow the pattern established by previous expansions at Cold Lake. “We’ve been steadily able to grow production using the phased development model—the ‘design one, build many’ approach,” he explained. In his view, staging development enables Imperial to better manage costs and “add in new technologies to enhance recovery.” Since 2002, Imperial has also internally developed a process called LASER (liquid-assisted steam-enhanced recovery) that’s expected to increase bitumen recovery by 10 to 15 per cent. LASER is designed for mid- to late-life CSS wells where steam has to travel further before contacting the bitumen. The technology

involves adding diluent to the steam before it ’s being injec ted. Imper ia l has now filed an application with the Energy Resources Conservation Board to deploy LASER for all of its existing Cold Lake wells. E nC a n a C or p. a nd it s pa r t ne r ConocoPhillips are also continuing to develop their leases at Foster Creek on the Cold Lake Air Weapons Range. Phases D and E at Foster Creek were commissioned in the second quarter of 2009, each adding 30,000 barrels per day of new production capacity. The expansion is now ramping up and is on target to exit 2009 at more than 90,000 barrels per day. Also, in the second quarter of this year, a regulatory application was initiated for Foster Creek’s phases F, G, and H. Again, each phase is designed at about 30,000 barrels per day. While the partners have yet to receive regulatory approval or internally sanction the three new phases, EnCana’s executive VP said the project is

Feature Photo: Imperial Oil Limited

Thermal producers continue to develop new well pad configurations.

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September 2009 • OIL & GAS INQUIRER

scheduled to proceed promptly. “We have not slowed down any of our developments like some of the other operators had done when the oil prices slowed down,” said John Brannan, who’s also president of EnCana’s integrated oil division. EnCana reports that the most recent expansions at Foster Creek came in at a cost of around US$15,000 per flowing barrel, as expected. “I think we haven’t seen substantial cost reductions because a lot of the things that we bought, like steam generators and steel and those kind of things, are ordered and bought ahead of time,” Brannan said. “We may see some reductions as we go into these future phases.” The EnCana executive VP added that worker productivity is improving. “We’re not having the turnarounds that we had when we lost crews and stuff to other major projects in the Fort McMurray area and those kind of things,” Brannan said. “We think that we’re cutting some time off of [new projects]. We used to say it’d take, say, 36 months; now we’re saying maybe we can do them in 30 months. So ultimately, when we do these new projects, hopefully we’ll see some improvements if the market conditions stay where they’re at today.” EnCana is also working to increase recovery at existing facilities at Foster Creek through a new technolog y it recently patented called wedge wells. T hese hor izonta l wel ls a re dr i l led between two existing well pairs, tapping the “wedge” of bitumen stranded between them. Canadian Natural Resources Limited (CNRL) also has a long record of success in the Cold Lake oilsands. The company currently has 120,000 barrels per day of capacity from its thermal operations at Primrose, Burnt Lake, and Wolf Lake. In addition, CNRL says it has potential

Feature

incremental thermal capacity of approximately 285,000 barrels per day of incremental thermal production, spread between the Athabasca and Cold Lake deposits. At Cold Lake, its bitumen resource is estimated at 11 billion barrels. CNR L completed its most recent expansion, its Primrose East project, last October. Located about 15 kilometres from its existing Primrose South steam plant and 25 kilometres from its Wolf Lake central processing facilit y, the Primrose East expansion added 40,000 barrels per day of capacity. Steve Laut, president of the Calgary-headquartered firm, described its thermal assets as “the most under-appreciated and misunderstood part of our portfolio. They are clearly a hidden gem.” To reveal the value of that gem, CNRL has plans to add 30,000 to 60,000 barrels per day of in situ production every three years for the next 15 years. According to its original Primrose plans, another 23 well pads will be drilled over the next 25 years to maintain production in the area. Simultaneously, CNRL is now focusing on the southern Athabasca oilsands. “At Kirby, our next 40,000 barrel day of incremental production, we expect to receive regulatory approval this year,” Laut said. “Before we kick off the development, we’ll need this regulatory approval, as well as the completion of the detailed engineering design work.” Pengrowth Trust is in the early stages of developing its Lindbergh assets in the Cold Lake region. The company drilled five vertical core hole wells in the first quarter of 2009 as it moves towards launching a pilot project. Bill Christensen, VP of strategic planning and reservoir exploitation for Pengrowth, said the Calgary-based trust has 1.7 billion barrels of bitumen in place on its leases, and hopes to develop a project producing 10,000 to 20,000 barrels per day.

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OIL & GAS INQUIRER • September 2009

Feature Photo: EnCana Corp.

At Foster Creek, EnCana developed "wedge" technology, consisting of horizontal wells between two existing well pairs to recover stranded bitumen.

The pilot SAGD project is expected to commence in 2012 with commercial production planned for 2016. Christensen said Lindbergh could have a big impact on the future of the trust. If successful, the thermal project could account for an estimated 40 per cent of Pengrowth’s proven-plusprobable reserves.

of 30,000 barrels per day. In 2007, optimization work continued on the original wells and eight new well pairs were drilled. “Tucker is one of the best projects, producing in the range of 3,000 to 5,000 barrels per day,” Husky CEO John Lau told analysts during its second-quarter telephone conference. “We have no intention to push

Husky Energy is convinced that its Cold Lake Tucker in situ bitumen project is on the brink of success. Husky Energy, one of Canada’s most successful oil developers (East Coast, China, and Lloydminster) is convinced that its Cold Lake Tucker in situ project is on the brink of success. Thirty-two well pairs drilled in 2006 failed to meet expectations 18

September 2009 • OIL & GAS INQUIRER

production up yet, because of volatility in the oil price, but we’ll definitely keep our options open.” The company plans on the second project reaching volumes of 5,000 to 6,000 barrels per day by year end.

Shell Canada and Devon Energy are two more powerful players in the Cold Lake play. Shell’s Orion project at Hilda Lake can produce 10,000 barrels per day, but a proposed doubling of that capacity is on hold while the company reworks its oilsands plans. In 2008, Devon drilled 321 wells at its Iron River and Manatokan cold production properties, and plans another 130 in 2009. Budgeting for new thermal in situ projects is beset by uncertainties over crude prices, construction costs, and government levies on greenhouse gas emissions. Calgary-based consultant Bob Dunbar, president of Strategy West Inc., told the Global Energy Conference in June that new SAGD projects will require a stable WTI light oil price of US$70 to US$80 per barrel to yield a 10 per cent return on investment. As this issue of Oil & Gas Inquirer went to press, NYMEX oil futures had risen to $72 to $76 per barrel—but whether the new price level proves stable remains to be seen.

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Nailing tailings Researchers close in on innovative ways to speed up reclamation of bitumen mine tailings ponds by Lynda Harrison

Among the black marks popularly held against the oilsands sector are tailings ponds. This mildly toxic sludge of water, clay, sand, and bitumen is the waste left over from the oilsands mining and upgrading process. Normally, the goo takes decades to settle out, enabling the land to be reclaimed. Recently prodded by a new provincial regulation, however, researchers are intensifying their efforts to speed up the reclamation process.

Directive 74, issued by the Alberta Energy Resources Conservation Board (ERCB) in February, has stirred up a “huge response” among bitumen mine operators, says Randy Mikula, who heads emulsions and tailings research at Natural Resources Canada (NRCan). Technologies under investigation include water capping, centrifugation, composite 20

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

tails, mature fine tails drying, accelerated dewatering, and the use of CO2. Alan Fair chairs the tailings consortium within the Canadian Oil Sands Network for Research and Development (CONRAD). Directive 74, he comments, has intensified tailings research efforts that had already long been underway. CONRAD is a network of companies, universities, and government agencies organized to facilitate collaborative research in science and technology for Alberta’s oilsands. T he E RC B d i r e c t ive, Tai li n gs Performance Criteria and Requirements for Oil Sands Mining Schemes, applies to all minable oilsands operations. It requires the reduction of fluid tailings, their capture in ERCB-approved dedicated disposal areas (DDAs) and their

conversion to trafficable deposits (which means the terrain can bear the weight of heavy equipment). CONRAD has representation from the four existing oilsands operators— Suncor Energy Inc., Syncrude Canada Ltd., Shel l Ca nada L i m ited, a nd Canadian Natural Resources Limited (CNRL)—as well as three companies with proposed projects: Total E&P Canada Ltd., Imperial Oil Limited, and Petro-Canada. Oilsands tailings ponds, which presently total 130 square kilometres, drew worldwide attention in April 2008 when 1,606 ducks died after landing in the muck. Deployment of the air cannons normally used to scare the birds away had been delayed by unusually late winter weather.

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Syncrude Canada scientists conduct fish studies on a pond constructed from fine tailings capped with water.

Photo: Syncrude Canada

O I L & G A S I N Q U I R E R â&#x20AC;˘ S EPTEMBER 2 0 0 9

Photo: Syncrude Canada

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A university student examines a water and sediment sample as part of biodiversity research in Syncrude Canada's reclaimed wetlands.

But the reclamation issue long predates that round of adverse publicity. “None of the existing owners are adverse to the development and implementation of the tailings directive,” Fair says. “I think everyone recognizes and agrees that there’s a need to put more focus on managing the tailings challenges.” Bot h t he ow ners and t he ERCB acknowledge that one of the areas that needs work is in the measurement parameters, Fair says. For example, the directive requires that within one year of the creation of a DDA, the area must measure five kilopascals. (A kilopascal is a unit of strength.) CONRAD fears that goal may be impossible to achieve, depending on the chosen technology. Fair and Mikula agree that the technologies that work best will be projectspecific. While some companies might apply three or four different technologies, Mikula thinks others operators may be able to get by with only one or two, depending on their operation. Syncrude is experimenting with three main methods: water capping, composite tails, and centrifuge. Taking a multipronged approach, the company is also researching other technologies. “We feel that it will take more than one,” says Cheryl Robb, a media relations advisor with the company. 22

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In water capping, a layer of water covers a deposit of fine tails, forming a lake. Syncrude says tests have shown that these lakes will evolve into natural ecosystems and after the final deposition of fine tailings, eventually support healthy plants, animals, and fish. Composite tails combines fine tails with gypsum and sand, causing the tailings to settle faster than they would on their own, thereby speeding up the process of developing landscapes of grass, trees, and wetlands. Syncrude will implement water capping and tails on a commercial scale in the east- and west-end pits within the next five years, according to Robb. Centrifuge, spinning out water from the fine tails, has been piloted twice in the past two years and research is ongoing. It’s fast but costly, says Fair, who also manages Syncrude’s research and development department. Mikula is a big fan of centrifuge technology. “It’s not going to be for everyone, and to be honest, it still needs some work, but that work’s progressing very, very quickly and so far everything looks pretty promising,” he says. Syncrude is taking the lead on that technology and is sharing what it learns with its competition. Mikula thinks the competitive advantage is in the operational experience, not necessarily in the know-how.

The fourth technology that Syncrude is researching—thickened tails, or paste technology—is also promising to speed up the settling process. Before going to the pond, tailings are passed through a product-separating vessel to thicken the mixture. The fine solids settle out rapidly and are pumped out as a viscous fluid with a paste-like consistency. This soft clay will be immediately used for reclamation into a finished landscape. Shell has commissioned a $100million tailings pilot plant at its Muskeg River mine to produce trafficable tailings. The company has demonstrated options such as non-segregating tailings and paste tailings technologies, and has been running the pilot project since 2007. It is gathering information for the design of large-scale facilities and deposits, says spokesman Phil Vircoe. This year, Shell plans to begin placing the first tailings material in mined-out pit areas. At its new Horizon oilsands mine, CNRL injects waste CO2 into the tailings slurry lines before the tailings enter a pond. The CO2 reacts to form carbonic acid. That reaction changes the pH of the tailings mixtures, enabling fines clays, silts, and sand to settle more quickly. The process leaves clearer water, which can be immediately recycled for reuse in the bitumen extraction process.

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Feature

The ERCB’s Directive 74 orders oilsands operators to reduce and recover tailings fluids, and slash the time needed for land reclamation.

CNRL plans to implement another new tailings treatment process during Horizon’s next phase. Cyclones will remove water from the coarse sand, and thickeners will remove the water from the fine clays, silts, and sand. The dewatered streams will then be combined with waste CO2 captured from the Horizon upgrader. The resulting mixture will be deposited in the tailings disposal area where even more water will be released and reused. Additionally, the CO2 will react with the minerals in the tailings to form mineral carbonates. “CNR L is doing something really cool,” Mikula comments. “The beauty of CO2 is it actually gives you a water chemistry that’s beneficial to the extraction process so you don’t have to worry about over-adding your process aid.” CO2 chemically works on the fluid fine tails in the same way that gypsum does to create consolidated or non-segregated tailings, using mature fine tailings in the recipe, the federal scientist adds. Eventually, those bubbles are going to find their way to the surface so CNRL wouln’t be able to get the CO2 sequestration credits from the federal government. Mikula and NRCan are working on that, though. The trick is to get the chemistry and physics of silt and sand particles just right, he says. 24

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Beyond reducing the tailings ponds’ size, CNRL’s new reclamation processes are designed to increase the amount of water available for recycling, thus decreasing the amount of river water needed to process bitumen. The company also expects the process of sequestering CO2 into tailings will eliminate about 219,000 tonnes of CO2 emissions every year. Mikula says Suncor’s efforts with tailings are “ ver y, ver y impressive.” The company, first to mine bitumen, recently planted trees on what will be the first tailings pond reclaimed by the oilsands industry. Ten years ago, Suncor stopped placing tailings into its 40-year-old Pond One. It should be fully reclaimed by 2010. The area, roughly two square kilomet res, is a l ready a l most ready to bear heavy traffic. Suncor moved soft, mature fine tailings and water to ponds that are better suited to their long-term treatment, and added sand from the bitumen extraction process. The surface has been molded into hills and valleys that act as plant and animal habitat. The new landform was then capped with the material that was saved during the original excavation. If all goes well, the final state of the land will be a mixed-wood forest and a

small wetland capable of supporting a variety of plants and wildlife. “Once that is achieved, it will be a major milestone not just for Suncor, but for the industry,” comments company spokeswoman Shawn Davis. Industry researchers also are collaborating on a method of injecting flue gases such as CO2 into tailings ponds to feed the growth of micro-algae, which can then be processed into products like ethanol, bio-diesel, and fertilizer. By Sept. 30, the ERCB expects oilsands operators to submit their plans for meeting the requirements of Directive 74. Annual tailings management plans for the next calendar year must be submitted by Sept. 30 each year thereafter. Requirements will be phased in and adapted, as approved by the provincial board, to take account of particular mining and tailings plans, facilities, and the status of a project. In addition, the mass of fines—mineral solids—must be reported annually and quarterly. Fair acknowledges that no matter what the companies achieve, some environmental lobbyists will remain unsatisfied. “You have to be realistic and, at the end of the day, you do what you can do,” the industry scientist says. This article was adapted from Nickle’s Daily Oil Bulletin.

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is mostly water vapour.

Beating a bum rap New research indicates that oilsands generate little more greenhouse gas on a per-barrel basis than other crudes—and emissions are falling The oilsands have taken an unprecedented public relations pounding in recent months over the allegedly high CO2 emissions generated per barrel of synthetic crude. In the United States, federal and state legislators have moved to ban use of gasoline and other fuels refined from Canadian bitumen. In July, however, a provincially financed report was released that indicates greenhouse gas (GHG) emissions from the oilsands are in the same range as other crudes refined in the U.S. “Imported and domestic U.S. heavy oil crudes have similar emissions to the oilsands pathway,” says Dr. Eddy Isaacs, executive director of the Alberta Energy Research Institute (AERI). “Yes, [oilsands fuel] is somewhat higher than the average barrel, but it’s not higher than California heavy oil. [Furthermore] it can be reduced technologically.” The new findings contradict some previous studies that concluded GHG emissions from oilsands were as much as 40 per cent higher than other sources. According to the AERI report, GHGs generated from oilsands activities are on average about 10 per cent higher than competing U.S. crude imports, and are approximately the same as heavy oil produced in California. Isaacs says the Alberta-coordinated research stands as the first comprehensive comparison of domestic, imported, and 26

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

by Paul Wells

oilsands crude processed in U.S. refineries. The work was funded by the Alberta government through AERI. Its conclusions are drawn from two independent studies conducted by U.S.-based consulting companies Jacobs Consultancy and Tiax LLC. Both firms focused only on emissions released directly during production. Examples of indirect emissions would be GHGs generated due to land use and exploration. Previous studies used a simplified model for calculating direct emissions from different crude oil sources, according to Isaacs. The AERI research incorporates a more comprehensive “well-to-wheels” basis, he argues, including GHGs emitted during production, transportation, and refining. Factors taken into account included location, reservoir depth, oil characteristics, and production technology. “The likelihood of comparable GHGs has been supported intuitively in some studies over the last couple years, but we felt it was critical to ascertain, in an open and transparent manner, if the data supported it,” Isaacs says. “One of the key considerations is that emissions from the oilsands will continue to decline as new technologies continue to be field-tested and commercialized.” In contrast, the AERI executive director notes that GHG emissions from conventional oil are rising. “Over a period of

time, we will see emissions from the production of crude continue to increase due to the global shift to heavier oils and more difficult to produce conventional crudes,” he predicts. In contrast, Isaacs says, “technological advances will further decrease GHG emissions for oilsands crude [on a perbarrel basis]. The oilsands industry, by all accounts, is a very new industry and as it gets to be more efficient, those emissions will start to come down.” But not without effort—and Isaacs insists that oilsands producers should not relax at this stage. “We can go down and should go down,” he says. “This [report] should not be seen as absolving the energy industry in Alberta from doing their utmost to get [GHG emissions] down to the levels as much as possible.” Rachel Bouska, a spokeswoman for Alberta Advanced Education and Technology, says, “Some U.S. policy-makers and lawmakers have considered Alberta´s oilsands dirty oil. We have the facts and the data to support the fact that it’s only about 10 per cent higher—Alberta´s getting a bad rap.” She suggests that Americans should also factor in the reality that Alberta, as a friendly neighbour, is a more secure energy source than many other countries that sell crude to the U.S. This article was adapted from Nickle’s Daily Oil Bulletin.

Photo: Joey Podlubny

That billowing emission

Light Roads Feature

Wood fibre and floating access roads aim at minimal ground disturbance by Graham Chandler

It looks like scrap, but the proper name is drivable wood fibre. Last fall, Devon Canada constructed an access road to a lease just south of Grande Prairie, Alta., using wood chips instead of gravel or access matting. Its contractor was Triple G Construction Ltd., a firm from northwestern Alberta. Another innovative road-making strategy is based on floating mats made from cutting-edge composite materials, developed by Edmontonâ&#x20AC;&#x2122;s ATR Manufacturing Inc. Each access technology has unique advantages, depending on loads and terrain type.

S EPTEMBER 2 0 0 9 â&#x20AC;˘ O I L & G A S I N Q U I R E R

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Photo: ATR Manufacturing

ATR Manufacturing says its ultra-light but costly mats—shown above and on opposite page—are uniquely effective in soft terrain.

“We like doing things with the least amount of impact,” says Mike Head, Devon Canada’s lease construction consultant and supervisor. “We always try to find ways to reduce our footprint.” The Canadian Association of Petroleum Producers, recognizing the company’s commitment to minimizing surface disturbance, presented Devon with the 2009 President’s Award from its Steward of Excellence Program. D e v o n w o r k s w i t h Tr i p l e G Construction Inc., a 29-year-old wood harvesting and oilfield contracting firm based in Grande Prairie and Grande Cache. In the spring of 2008, Gervin Antypowich, its owner and CEO, recognized an opportunity to combine those two operations into a new service—building drivable wood fibre roads. The diversification didn’t even require new equipment. “We could do the mulching and everything—a one-solution company,” Antypowich says. Drivable wood fibre surfaces are just what the name implies. Surplus natural wood products ideally from locally cleared rights of way are mulched into mixed chip sizes and spread over a separation material to create a road surface, staging area, or work site. They’re also called engineered

wood fibre, wood residue, or wood mulch surfaces. Size mix is important: when they are compacted, the fibres mesh with each other and bind together for strength while allowing water to drain through. Antypowich says the necessary compacting or water drainage characteristics won’t be there with, for example, just sawdust. “You need the bigger chips and longer strands,” he says. “We don’t use the screens in our mulchers. Then we get pieces a foot, six inches, or two inches, along with slivers.” In fact, the roads eliminate the need for drainage ditching because they are built above ground level. In order that the mulch doesn’t simply get mixed and mushed into the mud or whatever is under it, the technique is to first lay down a separation layer. Normally, that is GeoTech, a type of cloth used for separating layers on crossings, says Antypowich, to ensure no mixing of soils. Alternatively, GeoGrid—a snow fence– like plastic—can be used. “It’s a grid, with half-, one-, or two-inch holes,” he explains. “That helps spread the load.” He adds that it doesn’t spread loads as effectively as conventional matting, “but each has its application. If you’re dealing

with a lot of water, matting will spread the load a little better.” A major advantage of wood fibre roads over matting is cost, according to Triple G. “We can build you a chip road that costs the same or less than a dirt road,” Antypowich says. “And reclamation costs are down to 10 per cent [of a dirt road]. It can be picked up easily because of the separation layer. And the mulch can be reused.” Where locally cleared wood can be used for the mulch, further trucking costs are saved. Wood fibre roads are best for shorter term access—up to five years. But Head says some of Devon’s routes will hopefully become permanent. “If we have to add some wood to it once in a while to keep it in shape, we’re going into this with the intention of trying to make a road that will last,” he says. Especially in certain conditions, Devon plans to continue with the technique. “I find that where this stuff works best is if you have a little ground base with lots of stumps and you don’t have to disturb the dirt,” Head says. “You basically take that and shave those stumps down flush with the surface and don’t disturb the roots.” Triple G’s Antypowich says mulching machines can process 200 tons per hour, O I L & G A S I N Q U I R E R • S EPTEMBER 2 0 0 9

Feature Photo: Triple G Construction Inc.

Triple G makes wood mulch whose bigger chips and longer strands mesh and bind with each other for strength while allowing water to drain through.

enough to normally accommodate 100 to 150 metres of road. Beyond roads, he tells of a 700 foot by 900 foot work site pad that the firm built for Devon’s Jackfish 2 site near Fort McMurray. “We gave them a 30-inch pad and they topped it with dirt,” he says. “It took 380 truckloads of wood.” Head brought the concept to the attention of the Alberta government. “They’re open to be shown new ideas and to go on field tours and look at some of the things that we’ve got going on,” he says. “I showed them all of our good stuff and all of our bad stuff.” Alberta Sustainable Resource Development subsequently issued Information Letter 2008-06 last September, announcing it was receiving applications for dispositions to use the technique for a five-year trial period, testing for adverse environmental effects like leachate and frost retention. Wood fibre roads aren’t as effective over ground with high water content. “A wood mulch road generally in muskeg conditions doesn’t work very well because there isn’t that support,” says Craig Wronko, president of Edmonton-based ATR Manufacturing. 30

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

“That’s important because in muskeg you want to avoid shearing it. As soon as that happens, you destroy the foundation and it just gets worse.” ATR’s solution is the all-terrain road— mats with a polypropylene honeycomb core bounded by layers of woven fibreglassreinforced epox y resin. Traditional wood, steel, or plastic matting all have drawbacks in muskeg—water retention, load distribution, or deforming. “It [AllTerrain Road] was designed specifically for access to muskeg areas,” says Wronko. The secret? “We’re using aerospace technology. We use a technique that allows us to bond materials that can’t be bonded together. Others have tried, but can’t get the chemical bonding.” T he result is a mat t hat ’s lightweight, easy to install, and can f loat, Wron ko say s. Moreover, AT R mat s remain compliant to shear forces: bending rather than failing, yet rigid enough to support heav y equipment. It ’s the produc t ’s f irst yea r on t he ma rket. To help with application, a computer mo de l i s of fe r e d t h at c a n pr e d ic t

response to specific load conditions and ground properties. Based on independent compression, shear, and bend tests, the computer model enables the user to estimate maximum allowable loads under various ground conditions. “The ground conditions [input] range from wetlands to muskeg, sand, and then to a clay or firmer surface,” explains Wronko. “It will tell you exactly how the mat system will perform or deflect in each particular case. You can give yourself a range, and it’s also dependent upon what’s going on to the mats.” For example, in muskeg under a central load of 22,500 lb, the model predicts vertical mat deflection is 1.65 inches along 14 feet. “Even over a time period in certain muskeg conditions, it will always come back and retain its shape,” says Wronko. “The mats never take a set, never deform. Even with the suction that happens between the ground and the mat, there’s enough force on that system that over time even if it’s compressed or sucked down into the ground, it will always come back.”

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Feature “There are applications where people want to cross an open body of water, let’s say a pond—not a lake or moving water and not so large you’ll get wave action,” says Wronko. ATR recently tested a new fitment system for its floating mats in wetlands. “It was unsupported on water,” the company president says. “We wanted to put a lot of stress onto the joints, so we drove a truck, and I drove my car, out to the end of the mat system, which was just supported on water like a floating dock. The mats didn’t even get water on them. That was with a 7,000 lb load.”

Photo: Triple G Construction Inc.

For track ing pur poses, each ATR mat has its own passive RFID (radio frequency identification) tag for the client to identify his mats, says Wronko. “And secondly, we attach all our information in t hem— all par ts and qualit y control, etc.” Installation is relatively quick. The Edmontonian says that by using two skid-steers, “we can connect and lay a mat every 45 seconds.” So he reckons a truckload, which consists of 92 to 104 mats, can be laid in around two hours.

In fine ecological style, Triple G created this drivable wood road from surplus wood product that was harvested along the local right-of-way.

Off-road transformer No road? No problem. The Swamp Traxx is an 18,000 lb rubber-tracked off-road unit that’s towed down the highway as a trailer. To traverse snow, muskeg, sand, or open water, the two units switch roles. The service truck or other road-worthy vehicle drives aboard the auxiliary-powered trailer, then moves forward. “There’s nothing else on the market like it,” says Terry Laing, VP of sales for R. Pollitt Oilfield Construction Ltd. (located in Leslieville, Alta.). The Swamp Traxx just hit the market. Laing says the towing vehicle can be a service truck (welder, seismic, wireline, and so on) as heavy as 30,000 lb. When the Swamp Traxx is disconnected as a trailer, the truck drives up its self-contained ramps. Its rear tires then engage the drive system of the Swamp Traxx. Steering and speed are controlled from the truck cab using a hydrostatic drive system. A Nodwell or Bombardier self-powered tracked unit can cross the same types of terrain. However, those considerably heavier offroad vehicles must also be transported to the location and don’t normally piggyback vehicles. Laing says that despite its weight, the Swamp Traxx is low-impact. “With 36,000 lb up on top, our ground pressure is still only four and three-quarters psi,” he says, “and with a 10,000 lb truck, we’re way below that.” The manufacturer is now working on a larger model. “We’ve been pretty lucky that everything has worked since we came out of the gate on it,” says Laing, whose sales drive is getting underway in a depressed oilfield market. “There hasn’t been a lot of redesign needed. If it had been in 2006, everyone would have one on their shelf right now.”

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

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British Columbia

NEB says shale gas will play a larger role than previously expected

Photo: Kinder Morgan

by Richard Macedo

Canada’s conventional oil and gas production are both in decline while non-conventional output rises.

The National Energy Board (NEB) sees a continued shift away from conventional to unconventional production for gas in Canada with growth, particularly from shale gas, larger than previously predicted. Depending on prices, Canada’s natural gas production could be as low as 10 billion cubic feet per day (Bcf/d) by 2020 (in the low-price scenario) or as high as 21 Bcf/d (in the high-price scenario). The NEB forecast is part of its 2009 energy supply outlook to 2020, issued by the federal regulator on July 21. The NEB’s median or reference case price scenario calls for 15.8 Bcf/d by 2020. The Canadian Association of Petroleum Producers pegged 2007 production at 16.9 Bcf/d. In the NEB report, natural gas production is projected to decline in 2009 and 2010 due to reduced drilling. Western Canada contains significant unconventional resources, including coalbed

methane (CBM) and shale gas, which comprise an estimated 65 trillion cubic feet or 15 per cent of total estimated remaining natural gas resources. In the NEB outlook, conventional gas production slips from almost two-thirds of total production in 2007 to just one-third by 2020. In the reference case scenario, Canada’s remaining marketable natural gas resource base is estimated at 439 trillion cubic feet. Tight gas is almost a third of the remaining resource base and is expected to be the source of almost 40 per cent of projected Canadian natural gas production through 2020. In a 2007 report, the NEB projected natural gas production to be 13.4 Bcf/d in 2020. The 2007 report also pegged tight gas and shale gas production at 1.5 Bcf/d by 2020. The updated projection now calls for 7.8 Bcf/d from tight and shale reservoirs. These sources currently account for about 5 Bcf/d. The improved unconventional

outlook is largely related to improvements in horizontal drilling and hydraulic fracturing. CBM production in western Canada is projected to rise by almost 50 per cent between 2007 and 2016 in the reference case, reaching nearly 1 Bcf/d. This would include significant development of Mannville CBM to supplement the Horseshoe Canyon production that currently dominates CBM output. Other natural gas resources located north of the 60th parallel or offshore are designated as frontier supply. Frontier resource areas are estimated to contain 225 trillion cubic feet or 53 per cent of Canada’s remaining marketable natural gas resources, but due to the long lead times for frontier projects only minor amounts are likely to be accessible by 2020. Responding to lower prices and an over supplied North American market, natural gas drilling will drop to between 4,500 and 7,500 wells this year, with the reference scenario at 5,900. In the NEB’s reference case scenario, prices in the range of US$7 to US$7.50 per million British thermal unit would prompt a gradual drilling decline in Canada from roughly 12,000 gas wells in 2013 to 9,200 by 2020. Rising shale and tight gas output in Canada would partially offset declines in conventional gas, including 0.4 Bcf/d from Quebec’s shale reservoirs. Production would also be supplemented by frontier gas from northern Canada and off the East Coast later in the projection. Turning to crude oil, the NEB projects a price of US$50 per barrel for West Texas Intermediate, rising to US$90 by 2020. Total oilsands production is projected to be 2.8 million barrels per day in 2020, about 500,000 barrels less than the estimate made in the NEB’s 2007 report. The reduced oilsands production figure was prompted in part by higher capital costs. — DAILY OIL BULLETIN

BRITISH COLUMBIA WELL ACTIVITY

JUL/08

JUL/09

JUL/08

JUL/09

WELL LICENCES

WELLS SPUDDED

WELLS DRILLED

JUL/08

JUL/09

Source: Daily Oil Bulletin

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

British Columbia

B.C. July land sale brings in $38.3M The July land rights sale in British Columbia resulted in $38.3 million in bonus bids, bringing the calendar year-todate total to $284.7 million. The July 15 sale offered 26 parcels covering 58,763 hectares (ha) and the province sold 21 parcels covering 56,804 ha. The average price per hectare was $675.10.

of West of the Liard River. Western Land Services acquired sections 11, 21, 31, 41, 51, 61, 71, 81, and 91 at A-94-N-16; section 1 at H-94-N-16; and sections 12–20, 22–30, 32– 40, 42–50, 52– 60, 62–70, 72–80, 82–90, and 92–100 at D-94-O-13. One drilling licence in the Sundown f ie ld, 35 k i lomet r e s sout hwe st of

One drilling licence in the Sundown field brought in nearly $4.2 million. That’s well off from last year when B.C. took in just over $610 million in bonus bids in the sale on July 16, 2008, covering 132,740 ha, putting the year-to-date total at that time at $1.58 billion. The average price per hectare was $4,595. Key parcels in this year’s July sale included seven drilling licences that totalled nearly $31.3 million. Bids ranged from $233 to $1,106/ha. These parcels are located in the Liard Basin, approximately 110 kilometres northwest of Fort Nelson. The $1,106/ha bid was submitted by Western Land Services Co. Ltd., which recorded the high bonus bid total with the broker putting up $7.2 million for a parcel

Dawson Creek brought in $2,361/ha for a total of nearly $4.2 million. The perhectare figure was a high for the land sale and was submitted by Standard Land Company Inc. The broker acquired the rights to drilling licences at sections 96–100 at I-93-P-7; section 91 at J-93-P-7; sections 6–10, 20, and 30 at A-93-P-10; and sections 1, 11–13, 21–23, 32, 33, 42, and 43 at B-93-P-10. Daily Oil Bulletin records show EnCana Corporation as one of the busiest operators in the field over the past few years. Earlier this year, Murphy Oil Corporation drilled several wells at Sundown targeting the Montney formation.

Abu Dhabi’s Taqa North acquires Horn River parcels for $63.3M Taqa Nor t h pla n s to beg i n d r i l l i ng appraisal wells this fall after acquiring ex plorat ion licences for t wo la rge la nd bloc k s in t he developing Devonian shale gas play in the Horn R iver Basi n of nor t heaster n Br it ish Columbia. The Calgar y-based subsidia r y of Abu Dhabi Nat iona l E nerg y C omp a ny p a id $ 6 3. 27 m i l l ion f or just under 13,000 hec ta res 50 k ilo met res nor t h of For t Nel son i n t he June 17 Crown land sale, said spokesman Leroy McKinnon. The 10 large blocks on offer represented the last substantial blocks of land available in the basin, Taqa North announced on July 6. The acquisition of the Horn River licences will play a significant role in Taqa North’s growth and future production,” said Frederic Lesage, the company’s managing director.

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Northwestern Alberta/Foothills

EnCana outlines its northern drilling plans and operating costs

Photo: TD Drilling Inc.

by Lynda Harrison

EnCana’s Horn River wells have shown daily rates of 9.5 to 11 MMcf after 15 days of initial flow.

EnCana Corp. plans to drill about 60 wells in the Montney formation this year for production of close to 180 million cubic feet per day (MMcf/d). Mike Graham, executive VP of Encana’s Canadian foothills division, also told a second-quarter telephone conference call on July 24 that about 15 rigs are working the play currently, four or five of them drilling for his company. Graham told analysts that costs are continuing to fall in the area. Per interval, he estimated that completion and tie-in can be completed at less than $700,000. Overall, he added, finding and development costs are very attractive. “Things are continuing to progress well in the Montney and we do have a tremendous land position and we’re testing some more areas on the Montney. We’re very encouraged by it,” the EnCana VP added. EnCana’s comparison has found Alberta and B.C.’s royalty structures to

be competitive now, and both provinces are doing a “pretty good job” of providing stimulus programs, Graham said. “We like what’s happening in Alberta; these incentives really help out the Montney and make it very comparable to what we’re doing in British Columbia.” Randy Eresman, EnCana president and CEO, said the Alberta royalty structure is now working in EnCana’s favour, so there are plays that are becoming more competitive compared to the United States. “Generally, wherever you have the most concentrated resources and lowest development/operating costs, those are the ones that are going to be developed first in the future in this kind of a dynamic environment,” he said. The company singled out the Horn River play in British Columbia as holding considerable promise. EnCana said it is not yet ready to go to full commercial scale on

the play yet, as it is still early in the evaluation stage. It doesn’t have a full, long-term development plan for its holdings in the basin because it doesn’t yet know the well characteristics, added Eresman. The company is increasing its drilling plans to about 18 net wells in the Horn River this year, and deferring some completions into 2010. Drilling costs have come down, Graham said, because drilling a well now takes 16 days where it used to take 25. The company expects that with the help of technologies, it will see lowered costs and improved efficiencies. At Horn River, the joint drilling program by EnCana and Apache Corporation at Two Island Lake continues to meet or exceed expectations for both initial well production and expected size of the resource, EnCana said. As a result of the joint venture’s combined activities, to date 32 gross wells have been drilled to evaluate the basin and 10 gross horizontal wells placed on production. Fracture stimulations at Horn River have increased to up to 14 stages per horizontal section. The first wells completed in 2009 were placed on production towards the end of the second quarter. The wells have shown flow rates of 9.5 MMcf per day to 11 MMcf per day after 15 days of initial flow. EnCana also commissioned a new compression and dehydration facility as well as a gas-gathering pipeline that connects the Two Island Lake area with the Spectra pipeline system near the proposed EnCana-operated Cabin gas plant. EnCana currently has about 200 MMcf per day is shut in or curtailed in the U.S. and more than 100 MMcf a day is shut-in in the Canadian Foothills region, in the Deep Basin and the Montney. It takes four to six weeks to bring production back on when wells require swabbing or fracture stimulation, the conference heard. —DAILY OIL BULLETIN

NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY

JUL/08

JUL/09

JUL/08

JUL/09

JUL/08

JUL/09

WELL LICENCES

303

131

WELLS SPUDDED

290

WELLS DRILLED

274

Source: Daily Oil Bulletin

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

Northeastern Alberta

Photo: Joey Podlubny

Oil prices are up, costs down, but new upgraders are still stalled

TD Securities, a veteran oilsands financier, says capital costs have dropped by perhaps 30 per cent.

Higher spot prices for crude oil have sparked hope among bitumen operators that economic recovery will really take hold later this year or in 2010, an investment banker told the PennWell Oilsands and Heavy Oil Technologies Conference in mid-July. But Robert Mason, managing director of TD Securities’ investment banking, global energy, and power, cautioned that many oilsands developers are still in a “pause and evaluate” mode on new upgraders and mines. “The jury is still out as to how long and how deep this recession will be,” Mason told the Calgary conference. “Today, with oil prices coming off like they have, and capital costs still fairly high, certainly on a historic basis, the challenges are fairly significant,” said Mason. TD Securities has led more than $10 billion in financing for new oilsands companies and projects in the past decade. Mason said all future upgrader expansions have recently been delayed and/or

formally deferred, and all nine of the proposed new upgraders in the province have either been deferred indefinitely or have significant financing or sanctioning uncertainty. Imperial Oil Limited’s Kearl mining project is a notable exception to recent pullbacks in capital budgets on the mining side of the industry. Steam assisted gravity drainage bitumen netbacks are currently strong, the investment banker noted. However, he cautioned that those netbacks are relatively volatile and vulnerable to changes in commodity prices. In his view, future oil prices remain uncertain, a crucial factor in major project financing. As an example of falling cost estimates, Mason cited a recent disclosure by UTS Energy Corporation, 20 per cent partner with Petro-Canada (60 per cent) along with Teck Cominco Limited (20 per cent) on the proposed Fort Hills oilsands mine. UTS said the project may be 30 to 45 per cent cheaper

than estimates from September 2008. Imperial’s Kearl estimates are also down by about 30 per cent, he added. Equity and debt financings fell sharply in 2008 and to date in 2009, while the cost of capital has risen drastically for large and small players. Meanwhile, smaller, earlierstage players that two or three years ago had very good access to capital now have very limited access at any price, said Mason. “[Higher oil prices are] definitely making things easier for oilsands developers today. I can tell you that four months ago, when spot prices were down around $40, there wasn’t much talk, if any, of new oilsands project development, and at least now a number of producers are thinking seriously about it,” Mason said. Steel prices, one of the largest input costs for oilsands projects, are down around 71 per cent from their peak in 2008. Alberta’s demand in the next year or two is now expected by the Construction Owners Association of Alberta to be about 25,000 to 30,000 skilled labourers rather than the previously forecasted 40,000 to 44,000 workers. Mason said Canadian bitumen blend differentials are expected to remain lower than they were between 2005 and 2008 when they ranged between US$15 and US$25 per barrel. That expectation is due to increasing access to and demand from the U.S. Gulf Coast. Year to date, the 2009 differential has been US$8.26 per barrel. Alberta condensate prices are still extremely volatile, Mason said. Domestic condensate production is currently limited to about 160,000 barrels per day. Imports of condensate, which is the primary diluent for bitumen blend producers, are about 60,000 barrels per day. Enbridge Inc.’s Southern Lights’ 180,000 barrel per day import line, which is to start in late 2010, is expected to reduce volatility. — DAILY OIL BULLETIN

NORTHEASTERN ALBERTA WELL ACTIVITY

JUL/08

JUL/09

JUL/08

JUL/09

WELL LICENCES

WELLS SPUDDED

▲

JUL/08

JUL/09

WELLS DRILLED

▲

Source: Daily Oil Bulletin

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

Northeastern Alberta

Bitumen operations drive rise in solution gas flaring and venting The economic test currently used to determine if oil facilities in Alberta must conserve solution gas is under review. Flaring and venting of solution gas from crude bitumen batteries rose 31.3 per cent in 2008, outpacing a 19.6 per cent increase in solution gas production, says the Energy Resources Conservation Board (ERCB) in a report released on July 2. In 2008, the total volume of solution gas f lared and vented in Alberta increased to 25.66 billion cubic feet (Bcf ), up 7.6 per cent from 23.85 Bcf in 2007, says the ERCB in its annual upstream f laring and venting report. While flaring of solution gas was down 5.8 per cent, this was offset by a 20.1 per cent increase in venting of solution gas to a total of 14.4 Bcf, up from 12.3 Bcf. Last year was the third straight year in which gas conservation had declined due to the growth in new bitumen wells that produce small volumes of gas from numerous wells. “These volumes are neither sufficient to keep a flare stack lit nor meet the ERCB’s test for conservation,” says the provincial regulatory board.

Between 1996 and 2005, the industry made significant progress in reducing solution gas flaring and venting in Alberta, according to the ERCB. Solution gas flaring has been reduced by 77 per cent since 1996, while venting has been reduced by 41 per cent since 2000. However, while flaring has continued to drop, the trend in venting has been reversed since 2005. “This trend has not been overlooked by the ERCB and is of concern,” says the board. It notes that the Clean Air Strategic Alliance flaring and venting project team is working with stakeholders on a

and vented in A lberta in 2008 with 88.4 per cent of this being vented. Last year, 10.4 Bcf of solution gas was vented f r om c r ude bit u me n bat te r ie s, a n increase of 25.9 per cent over the 8.24 Bcf vented t he prev ious yea r. A not her 1.36 Bcf of gas was f lared in 2008, justly slightly less than the 1.38 Bcf flared in 2006 and nearly double the 2007 volumes of 710 million cubic feet. In its report, the ERCB acknowledges that the oil and gas industry is using a large portion of produced solution gas from crude bitumen operations as fuel

Last year, 10.4 Bcf of solution gas was vented from crude bitumen batteries, an increase of 25.9 per cent over the 8.24 Bcf vented the previous year. number of recommendations for regulatory changes to address solution gas venting in crude bitumen production operations and other facilities—among them is a review of the economic test. Crude bitumen batteries accounted for 45.7 per cent of the solution gas flared

to run pump motors. “Unfortunately, the remaining small volumes of gas will rarely be economically viable to conserve,” it says. “Notwithstanding the fact that gas conservation economics are more difficult respecting bitumen production, this increase continues to concern the ERCB.”

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The board noted that in 2003, the Alberta Energy and Utilities Board implemented a number of conservation measures aimed at reducing the volumes of solution gas vented from crude bitumen operations. As a result of the measures and of greater industry awareness, there was a net decrease in venting from crude bitumen batteries between 2004 and 2007. However, in 2008, that trend reversed and vented gas volumes were up 1.5 per cent over 2003. Conservation of solution gas at both crude oil and crude bitumen batteries continues to decline when adjusted for increases or decreases in production, says the board. While the overall conservation rate for crude oil batteries and crude bitumen batteries declined by 0.7 per cent to 95.8 per cent, the rate for crude bitumen batteries fell by 1.6 per cent to 81.8 per cent from 83.4 per cent in 2007. The conservation rate for crude oil batteries dropped by 0.1 per cent to 97 per cent as production declined by 10.6 per cent. Venting from crude oil batteries was up 9.1 per cent to 4.4 Bcf from 4.1 Bcf the previous year. Flaring from crude oil batteries in 2008 decreased by 12.4 per cent to 9.5 Bcf from 10.8 Bcf in 2007. In 2008, 1.36 Bcf of gas was flared, versus 1.38 Bcf flared in 2006.

O I L & G A S I N Q U I R E R â&#x20AC;˘ S EPTEMBER 2 0 0 9

Northeastern Alberta

Alberta short-lists CCS projects for $2B in provincial funding Two of the three carbon capture and storage (CCS) projects short-listed by the Alberta government to go to the next stage of negotiations are associated with oilsands upgrading projects. Recently, the Stelmach government wound up its evaluation of CCS proposals applying for $2 billion in government funding, paring the field from 10 projects that had made it to the second stage of the competition. The province plans to negotiate letters of intent by the end of July with contracts by the end of this year. The three short-listed projects include: • The Alberta Carbon Trunk LineNor t hwe s t Upg r ade r pr op o s a l advanced by Enhance Energy Inc. and Northwest Upgrading • The Quest CCS project proposed by Shell Canada Energy, Chevron Canada Ltd., and Marathon Oil Sands L.P • The Genesee Integrated Gasification Combined Cycle (IGCC) power generation plant proposed by Epcor Utilities Inc. and Enbridge Inc. In the Enhance-Northwest proposal, Enhance Energy estimates that Phase 1

of the proposed 240-kilometre CO2 trunk line would cost about $600 million to build, while the upgrader-refinery proposed by Northwest Upgrading will cost “significantly less than $4 billion.” The upgrader design capacity would be about 231,000 barrels per day.

power and roughly one million tonnes of CO2 per year under current design specifications. Construction would be expected to take about three years. While the Alberta government said it will work toward signing letters of intent by the end of August, it also said

The Quest carbon capture storage project would be capable of injecting up to 1.1 megatonnes of CO2 per year from Shell’s Scotford upgrader. A spokesman for the Quest CCS project said the proposed, fully integrated CCS project would capture CO2 from the Scotford upgrader and inject it about two kilometres below ground in the Alberta Industrial Heartland area northeast of Edmonton. The project would be capable of injecting up to 1.1 megatonnes of CO2 per year, although the Shell spokesman would not disclose the estimated capital cost or timeline of the project. Steve Buick, spokesman for the proposed Genesee IGCC project, estimated the bill for that project would come to about $2 billion, generating 270 megawatts of

that if that effort fails, it will review its options and may proceed to discussions with other proponents. T he A lberta government has budgeted up to $100 million in the current fiscal year for engineering and design work on the successful projects. The first round of commercial-scale projects is expected to achieve annual CO2 emissions reductions by 2015 equivalent to taking approximately one million conventionally fuelled vehicles, or about one-third of all registered vehicles in the province, off of the road. — DAILY OIL BULLETIN

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Photo: EnCana Corp.

Bonavista buys EnCana assets in central Alberta core area for $694M

Bonavista believes its new central Alberta assets will yield a better return than B.C. shale gas.

Bonavista Energy Trust has agreed to acquire long-life natural gas weighted properties located in its central Alberta core area from EnCana Corp. The acquisition is valued at $694 million. As a result of this transaction, the trust said it may sell up to $100 million worth of properties. Bonavista has been stepping up its acquisition spending after spending relatively little on acquisitions through the boom period between 2005 and 2007. In the past five years, Daily Oil Bulletin records show $972 million invested on acquisitions, of which $590 million were spent in 2004 and $187 million last year. The acquired properties are currently producing approximately 11,400 barrels of oil equivalent (boe) per day, including 53.2 million cubic feet a day of natural gas, 2,150 barrels per day of associated natural gas liquids, and 380 barrels a day of light oil.

EnCana said it will retain a lessor royalty on the majority of the lands. “This sale ref lects our ongoing efforts to high-grade our portfolio of producing assets and it represents a substantial portion of our 2009 divestiture target of between US$500 million and US$1 billion,” said Randy Eresman, EnCana’s president and CEO.

of resource contiguous land, of which approximately 156,000 (136,000 net) acres are undeveloped. Of these lands, 77 per cent are freehold interests with an attractive tenure of a minimum five year term and a favourable royalty structure equating to 80 per cent of Alberta’s New Royalty Framework. The area is characterized as one of the most prolific multi-zone areas in western Canada with over 12 different producing horizons and significant exposure to the recently emerging resource plays occurring in the Glauconite, Rock Creek, Cardium, Viking, and Notikewin formations. Bonavista said it believes that both production and recoverable reserves can potentially be increased by over 50 per cent from these large and scalable under developed reservoirs. The trust said its primary development program will initially consist of drilling horizontal wells within the Glauconite and Rock Creek formations using multi-stage fracture techniques paralleling Bonavista’s success in the area over the past year. The trust has initially identified 165 horizontal drilling locations on the acquired properties in a development program anticipated to generate attractive

In the past five years, Bonavista invested $972 million in acquisitions, including $590 million in 2004 and $187 million last year. T he acquired proper ties complement Bonavista’s emerging initiatives involving the use of leading technologies to access underdeveloped reservoirs in its central Alberta core area. The properties are situated on approximately 492,000 (409,000 net) acres

future development efficiencies with f i nd i ng a nd deve lopme nt cost s of approximately $10 per boe and onstream costs of approximately $10,000 per boe per day. About 89 per cent of the production is operated resulting in attractive operating

CENTRAL ALBERTA WELL ACTIVITY

JUL/08

JUL/09

JUL/08

JUL/09

JUL/08

JUL/09

WELL LICENCES

326

152

WELLS SPUDDED

417

118

WELLS DRILLED

416

115

Source: Daily Oil Bulletin

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

Central Alberta

Energy Quest signs agreement with Cancen to test upgrader

costs of $6.40 per boe. The acquired properties include extensive gathering and processing infrastructure to accommodate production additions efficiently. The acquisition increases Bonavista’s Energy Quest, Inc. has signed an agreecurrent production by 22 per cent to approxment with Cancen Oil Canada Corp. to imately 63,000 boe per day (60 per cent provide testing facilities and feedstock natural gas weighting) and boosts its for the testing phase of the construction proved-plus-probable reserves by 29 per cent of a 1,000 barrels per day heavy crude oil to 247 million boe. upgrader. The upgrader will convert heavy It i mpr ove s B on av i s t a’s pr ove d crude oil feedstock to 32°API and above light oil. reser ve life index by approximately 5 per cent to 7.8 years, and proved-plus“We feel this is a major breakthrough probable reserve life index by approxiin the petroleum industry,” said Keith Talbot, president of Cancen Oil Canada. mately 9 per cent to 10.2 years using current production rates. In addition, any start-up problems will be Bonavista’s undeveloped land posiresolved at the company’s New Sarepta tion will rise by 12 per cent to approxlocation. This will assist Energy Quest in i m ate ly 1. 3 m i l l ion net ac r e s a nd providing start-up for the 5,000 barrel includes a seismic position overlaying per day plant, which was previously announced. t hese lands of approx imately 3,400 The upgrader technology uses an electromiles of 2-D and 160 square miles of 3-D data. magnetic field to align long-chain hydrocarThe acquisition brings control of strabon molecule chains, which are then subjected tegic infrastructure including 610 miles to ultrasonic energy waves. The process creof pipelines, 35,000 horsepower of ates cavitation bubbles within crude oil, heavy compression facilities, and 52 per cent oil, tank bottoms, or bitumen. ownership of a key 33 million cubic feet With Energy Quest upgrader technolaCA_EnergyAd_Oil&Gas_J31 day gas plant. ogy,AM the bubbles 7/31/09 7:11 Page 1collapse at great tempera— DAILY OIL BULLETIN ture and pressure. The collapse of these

bubbles causes the breaking of the longchain hydrocarbon molecules without the need for external sources of heat and pressure used in current conventional processes, Energy Quest said in a news release. The overall process operates at lower temperatures and pressures, which means that energy consumption is nominal and operating costs and maintenance costs are reduced, the company said. Energy Quest said its hydrogen generation technology, referred to as the PyStR process, will be combined with the EQI Upgrader. The PyStR process can directly produce separate streams of high purityhydrogen and CO2 from biomass, heavy crude, oilsands, coal, and petroleum coke. Hydrogen will be used in the upgrading process and CO2 for enhanced oil recovery. Energy Quest will also use Cancen’s fluid bed gasification unit to provide power for the project. Energy Quest will provide the proprietary technologies, equipment, and project management for the complete gasification plant and upgrader. — DAILY OIL BULLETIN

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NRCB approves sulphur-forming plant in Lamont County Photo: Joey Podlubny

A pa nel of t he Nat ura l Resources Conservation Board (NRCB) has determined that Alberta Sulphur Terminals’ proposed $30-million sulphur-forming plant is in the public interest, and is not likely to result in significant adverse social or environmental effects. The plant will be located in the Industrial Heartland region of Lamont County, near Bruderheim. The key concern related to the project is the release of sulphur dioxide gas in the unlikely event of a large fire. The NRCB panel gave close attention to the application’s safety measures for mitigating hazards and the facility’s emergency response capabilities. The plant will produce 3,000 tonnes per day of sulphur pastilles, with shortterm on-site storage. Sulphur is primarily used in the production of agricultural fertilizers. The facility will potentially provide service for oil and gas production and refining operations from Fort Saskatchewan, Fort McMurray, and Lloydminster, taking the by-product of oil and gas upgrading and refining, and processing it into sulphur pastilles for export.

Alberta Sulphur Terminals’ new pastille plant is an alternative to block-style storage shown here.

The NRCB panel concluded that the plant will provide a useful alternative to the long-term above-ground block storage currently used for a significant amount of byproduct sulphur generated from upgrader and refinery operations in Alberta. The panel concluded that the plant will be an economic benefit to the region and a useful response to by-product sulphur

generated from upgrader and refinery operations. The project will provide an alternative to the significant amount of sulphur generated by upgraders in Alberta that is block-formed and placed in long-term above-ground storage. The primar y markets for formed sulphur are the United States, Asia Pacific, and North Africa.

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

Southern Alberta

Photo: Joey Podlubny

Drilling costs decrease in parallel with reduced field activity

PSAC says operator costs are dropping due to lower service rates and better provincial incentives.

Canada’s drilling contractors booked fewer than 7,000 operating days in the second quarter of 2009, yielding a dismal rig utilization rate of about 9 per cent for the three-month period. However, a new study released by the Petroleum Services Association of Canada (PSAC) indicates that service costs have decreased by 13 per cent, which the association hopes will help buoy up activity levels later this year. In late July, PSAC updated to its 2009 drilling activity forecast for the third quarter, predicting a total of 9,500 wells drilled (rig released) across Canada. That figure was down only slightly from the 10,000 wells forecasted in April. “Our well cost study indicates a reduction of well costs in Alberta averaging 13 per cent. The decreases range from a low of 8 per cent to a high of 17 per cent based on the region of activity. The largest percentage decrease came from steel casing

and tubing along with drilling rig and fuel charges,” said PSAC president Roger Soucy. The association believes that lower service costs, combined with the Alberta royalty credit and new well incentive programs, bodes for somewhat better drilling economics. “We believe the decrease in costs will be enough to sustain a certain degree of activity, even in the face of continuing low natural gas prices,” Soucy commented.

to 690 wells, and Saskatchewan will see a 45 per cent drop to 2,275 wells. Only four small contractors (Saxon Drilling Canada LP, Horizon Drilling Inc., Bonanza Drilling Inc., and Impact Drilling) had more operating days this year than last year. Over the first half of 2009, operating days for members of the Canadian Association of Oilwell Drilling Contractors fell 33 per cent to about 28,400 days from 42,500 days the previous year. About the only good news for drilling contractors is that average days to drill a well in Canada continue to climb with longer reach horizontal wellbores, although the decline in shallow wells is also contributing to rising average day counts. Rig Locator records show it took on average 10.7 days to drill a well in western Canada to the end of June this year, up 13 per cent from last year. The 10.7 days is the most days per well since 1991 and is up 71 per cent from its low point of 6.24 days in 2004. Average days per well climbed in A lberta, Saskatchewan, and British Columbia, but it is the latter province that showed the biggest swing at an average of more than 27 days per well, an increase of seven days from a year earlier. Including test or oilsands evaluation wells, Ensign Energy Services Inc. drilled the most wells (1,049) in the first six months of 2009, while Precision

PSAC's study indicates a reduction of well costs in Alberta averaging 13 per cent, within a range of 8 to 17 per cent, depending on the region. Even so, PSAC is still now forecasting a near 45 per cent decrease over drilling activity levels in 2008. On a provincial basis for 2009, PSAC estimates 6,265 wells drilled in Alberta, which is a 46 per cent decline from 2008 drilling levels. British Columbia will see an 18 per cent decrease

Drilling Trust drilled the most metres (1.46 million). However, both contractors had large declines in operating days with Ensign off 42 per cent to 4,457 days and Precision down 27 per cent to 7,508 days, according to Rig Locator and Daily Oil Bulletin records.

SOUTHERN ALBERTA WELL ACTIVITY

JUL/08

JUL/09

JUL/08

JUL/09

JUL/08

JUL/09

WELL LICENCES

375

128

WELLS SPUDDED

462

137

WELLS DRILLED

460

129

Source: Daily Oil Bulletin

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

Southern Alberta Sava n na Energ y Ser v ices Cor p. ranked third on the top contractor list with 881 wells drilled and 755,370 metres of hole finished. Trinidad Drilling Ltd. was fourth overall with 250 wells and 510,262 metres. Precision was the dominant contractor in Alberta with 1.1 million metres of hole and while Ensign was the leader in Saskatchewan (229,704 metres) and British Columbia (205,121 metres). Trinidad was the busiest contractor in Manitoba with 86,435 metres drilled, all for Tundra Oil & Gas Partnership. On an average wells per rig basis, Tec h n icoi l Cor porat ion topped t he list in the first half of 2009 with 18.7 wells drilled on average by its five rigs. BlackWatch Energy Services Corp. was second with 16.3 wells per rig. Panther Drilling Corp. ranked first on an average metres per rig basis at 21,666 metres on average for its two rigs. Bronco Drilling Services Ltd. topped the list for rig utilization at 72 per cent for its two rigs in a first half, which saw a rig utilization rate of only 18 per cent (using operating days as a percentage of total days available). — DAILY OIL BULLETIN

Canada’s largest energy company is born through Suncor-Petro-Canada merger Suncor Energy Inc. completed its merger with Petro-Canada on Aug. 1. Suncor Energy is Canada’s largest energy company and the fifth largest North American–based energy company by market value. The combined company’s current upstream production is approximately 710,000 barrels of oil equivalent per day, slightly below EnCana Corporation’s production. Existing upstream production is supported by 7.5 billion barrels of provedplus-probable reserves, and an additional 19 billion barrels of contingent resources. Efficiencies resulting from the merger are expected to contribute annual reductions of $1 billion in capital spending, in addition to expected annual savings of $300 million in operational expenditures. “This is an important milestone for Suncor and for Canada,” said Rick George, president and CEO of the combined operation. “Bringing together these two great success stories creates the premier Canadian energy company with the assets, people, and financial strength to take on the global competition. This is the start of an exciting journey.

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Southern Alberta

Few oil and gas operators were more active during the first half of 2009 along with Shelter Bay Energy Inc. (up 12 wells) and StatoilHydro Canada Ltd. (plus 12 wells) having the largest increases in operated wells. Overall, Canada’s busiest operators of the first six months of the year were no surprise. EnCana Corporation led the way with 962 wells and 1.11 million metres of hole, while Canadian Natural

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Resou rces L i m ited (C N R L) ra n ked second thank s to its 266 wells and 361,159 metres drilled. EnCana drilled 374 fewer wells than in the first half of 2008, while CNRL chopped its program by 179 wells. ConocoPh i l l ips Ca nada L i m ited ranked third by metres drilled (272,433) although its 121 well count was below

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Southern Alberta Husky Energy Inc.’s 212 wells, putting Husky third by wells drilled and fourth by metres drilled. Despite its high ranking, Husky drilled 272 fewer wells in the six months ended June 30, 2009 than a year earlier. Of the 100 operators that increased their well count in the first half of 2009, ARC Energy Trust had the biggest increase with 30 additional wells (to a total of 76), followed by Taqa North Ltd. (plus 24 wells), Progress Energy Resources Corp. (an additional 23 wells), and StatoilHydro (plus 21 wells). On the downside, the largest declines ca me f rom E nCa na, Husk y, CN R L , Enerplus Resources Fund, Devon Canada Corporation, and Compton Petroleum Corporation.

ARC Energy Trust had the biggest increase with 30 additional wells, followed by Taqa North Ltd. (24 wells), Progress Energy (23 wells), and StatoilHydro (21 wells).

Ranked by metres drilled, the most active explorers in a first half that saw little exploration were EnCana (86,537 metres), CNRL (78,564 metres), and ConocoPhillips (73,223 metres). The lion’s share of EnCana’s exploration was in British Columbia, where it drilled more exploratory metres (57,422) than any other operator. Devon Canada ranked second with 34,603 metres. In Saskatchewan, TriStar Oil & Gas Ltd. with 25,811 metres drilled and Crescent Point Energy Trust with 20,915 metres were the most active explorers. CNRL and ConocoPhillips drilled the most exploratory metres in Alberta. Ranked by wells drilled, EnCana (898 wells) and CNRL (235 wells) drilled the most wells in Alberta during the first half of 2009, while Saskatchewan’s busiest operators were Husky (96 wells) and Enerplus (61 wells). In British Columbia, EnCana’s 60 wells led the way, followed by Harvest Energy Trust’s 39 wells. Tundra Oil & Gas Partnership as usual led the way in Manitoba with 38 wells drilled to the end of June with EOG Resources Canada Inc. in second place with 16 wells drilled. — DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • S EPTEMBER 2 0 0 9

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Saskatchewan

Oilsands Quest has funds for its activities over the next year

Photo: Oilsands Quest Inc.

Baytex buys heavy oil assets for $93M

Oilsands Quest continues to aggressively evaluate its massive bitumen-prone lands in Saskatchewan.

S a s k atc he w a n oi l s a nd s de v e lop e r Oilsands Quest Inc. says it has sufficient funds to carry out its planned activities at Axe Lake and elsewhere through to April 2010. If sufficient funding is not available, the junior producer said it can adjust its expenditure plans based on available cash. The company, whose large-scale properties in northwestern Saskatchewan are still in a preliminary stage of development, reported a net loss of $90.5 million for the year ended April 30, 2009, compared to a loss of $91 million for the same period last year. At its test site 1, Oilsands Quest plans to commission and start up its vertical well test program during the remainder of 2009. Detailed planning of the test is ongoing, including incorporating the testing results generated from test site 3. Operations at test site 1 are scheduled to

begin later this summer subject to regulatory and other approvals. Water and steam will be injected into the reservoir to mobilize the bitumen at the bottom of the McMurray formation using the vertical test holes. Management expects to drill and complete relevant surrounding observation wells and to design, construct, and commission the necessary surface facilities at the wellsite. Water and steam injection into the horizontal wells are planned to begin following the completion of the surface facilities associated with the horizontal test holes. For the comprehensive reservoir monitoring program, six vertical observation wells for cross-well seismic monitoring and four shallow vertical wells for micro-seismic monitoring will be drilled and completed prior to commencement of vertical well operations. — DAILY OIL BULLETIN

In an effort to cut debt, True Energy Trust has agreed to sell nearly $100 million worth of assets, including heavy oil properties in the Kerrobert and Coleville a rea s of sout hwest Sa sk atc hewa n. Baytex Energy Trust will pay $93 million for about 3,000 barrels of oil equivalent per day, three-quarters of which are heavy oil and one-quarter of which are natural gas properties. Baytex said the deal, which should boost its average daily production to 43,000 barrels of oil equivalent per day. Baytex plans to spend about $10 million on the acquired assets in the second half of 2009, although management also said the trust is in the process of evaluating its spending for that period. Baytex said a pilot project using toeto-heel air injection in horizontal wells is planned for the Kerrobert area in this year’s second half. As well, the company added that the Kerrobert area has the potential for light oil development in the Viking formation, using horizontal wells with multi-stage hydraulic fractures.

Provident plans sale Provident Energy Trust plans to sell up to 6,320 barrels of oil equivalent (boe) per day of assets, primarily in Saskatchewan. During the second quarter of 2009, production from the these assets consisted of approximately 84 per cent crude oil and 16 per cent natural gas. Provedplus-probable oil a nd gas reser ves totalled 15 million boe.

SASKATCHEWAN WELL ACTIVITY

JUL/08

JUL/09

JUL/08

JUL/09

JUL/08

JUL/09

WELL LICENCES

608

164

WELLS SPUDDED

484

184

WELLS DRILLED

477

192

Source: Daily Oil Bulletin

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Central Canada

CERI says petroleum will add trillions to GDP over the next 25 years

Photo: Joey Podlubny

by James Mahony

Alberta’s natural gas royalties could be 30 times higher than conventional oil over the next 25 years.

The Canadian Energy Research Institute (CERI) forecasts that the petroleum industry could impact Canada’s GDP (gross domestic product) by $3.6 trillion over the next 25 years, based on investment exceeding $1 trillion. The Calgary-based think tank had discussed its preliminary findings in its latest report earlier this summer. The study estimates that $218 billion will be invested in new oilsands capacity over the next 25 years. CERI considers its figures realistic, noting that Mexico plans to invest US$240 billion over the next 14 years to stimulate its lagging oil industry. Canadian oilsands investment, coupled with the increased production, is expected to produce $1.7 trillion in incremental GDP growth for Canada—including $78.1 billion for Ontario and Quebec. Over 456,000 jobs are expected to be created in Canada, and total additional tax revenue of over $306 billion. When the total petroleum industry is factored in, it will contribute an incremental increase in Canada’s GDP of $3.6 trillion—$144 billion in Ontario alone—and will create roughly 980,000 new jobs. The associated royalty revenues are estimated to be in the area of $429 billion in Canada.

According to CER I, the next t wo years will see limited growth in new oilsands capacity as the industry slowly starts to ramp up. Production is forecast to reach 4.3 million barrels per day by 2030. This figure is well below earlier projections, due to the current economic slowdown and the lasting impacts it will have on the economy. B e side s t he we s te r n C a n ad i a n upstream oil and gas industry, the report identified several other capital projects that will also contribute to the Canadian economy. Exaimined in detail by CERI’s researchers were Enbridge Inc.’s Gateway pipeline project, the Kitimat LNG liquefaction pro-ject, a Quebec LNG regasification terminal, the Mackenzie Valley pipeline project, and Nova Scotia’s Deep Panuke offshore pro-ject. These projects will require investment of $23.5 billion, which will result in incremental growth for the Canadian economy of $60 billion. The largest tax effect, on a federal basis, comes from Alberta. All oil and gas projected investments in the province will have a total estimated federal tax impact of $311 billion, or nearly two-thirds of the

Canadian total. This is followed by B.C. and Saskatchewan at $58 and $32 billion, respectively. With respect to royalties, Alberta will collect an estimated $100 billion from conventional gas over the next 25 years, averaging about $4 billion annually. Conventional oil is strikingly lower, producing $3.45 billion over the period, or roughly $138 million per year. With regard to Alberta coalbed methane from the Horseshoe Canyon and Mannville formations over the next 25 years, royalties will be $5.56 billion and $1.59 billion, respectively. On average, this is pegged at about $286 million per year. Royalties payable to Alberta for the oilsands over the next 25 years will be $184.61 billion. On average, this equals about $7.4 billion per year. Royalties with regard to in situ and mining will be $94.29 billion and $90.31 billion, respectively. In B.C., natural gas royalties are estimated at about $21 billion for the next quarter-century, or $840 million per year. For shale/tight gas from Horn River and Montney, royalties are pegged at $35.9 billion and $32 billion respectively, for a total of $2.7 billion per year. Drilling investment in the Horn River play is pegged at $24.6 billion for the period, with wells totalling 3,684 and infrastructure costs estimated at $1.7 billion. Montney drilling costs are estimated at $20.9 billion with infrastructure costs of $2.9 billion and 6,269 wells drilled. GDP impacts as a result of shale/tight gas developments in B.C. over the next 25 years (construction and operation) total $263 billion for all of Canada. Of this, 91 per cent or $240 billion will directly affect B.C. Royalties payable to Saskatchewan in regard to conventional oil over the next 25 years are forecast at $39.8 billion, averaging $1.6 billion per year. Upstream oil and gas activities in Saskatchewan over the period should create a $14-billion impact on Alberta, while B.C.’s development will contribute $13 billion to its eastern neighbour. — DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • S EPTEMBER 2 0 0 9

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International

BJ Services fares better globally than in North America Savanna enters the Mexican market

BJ said its service pricing was down about 35 per cent in the U.S., year over year, while Canadian pricing, though still under pressure, had fallen roughly “in the 15 per cent range” in the same period. “The pricing pressures we have seen internationally are nowhere near as [great] as in North America,” a senior BJ executive said. In Canada, BJ’s pressure pumping services business saw revenue in the quarter plunge to US$23.3 million, down 76 per cent from the quarter ending March 31, with average drilling rig activity down 72 per cent, mainly due to spring breakup, management said. Year-over-year, revenue from Canadian pressure pumping fell 52 per cent, while average drilling activity was down 46 per cent primarily due to decreased cementing and fracturing, and lower pricing. Stewart said BJ might be looking for an acquisition internationally, if the conditions are right. “A nice add-on acquisition, whether it be a North American or international company, will be something we will pursue, if it’s a good fit and if the price is right,” he told analysts and investors.

Sav a n n a E ne r g y Se r v ice s C or p. h a s contracted to move four drilling rigs into Mexico. In early July, the company announced that it has entered into a contract with a large U.S.-based multi-ser v ice provider to deploy four existing rigs from its Canadian/U.S. fleet into the Chicontepec region in central-eastern Mexico. The Mexican venture represents the first extension of Savanna’s drilling operations beyond Canada and the United States. The company anticipates that it will continue to expand internationally. The rigs are contracted to work at a utilization rate of 100 per cent for an initial term of 18 months, with an extension option. The rigs to be supplied under this agreement are mid-depth telescoping double drilling rigs, representing the core conventional platform within Savanna. The drilling contractor said its rigs will require minor modifications and equipment to allow them to work effectively in the Chicontepec region, with an estimated cost under $6 million. The rigs were scheduled to be operational in Mexico by mid-August. All costs relating to mobilization of the rigs into Mexico from the U.S./Mexico border will be borne by the operator, according to Savanna. Similarly, demobilization of the rigs, if any, will result in delivery of the rigs to the U.S. as well. Savanna said that operational flexibility will facilitate its intention to expand both its U.S. and international operations. Of the four rigs that are mobilizing to Mexico, two will be relocated from the current U.S. fleet, and two will be delivered from Savanna’s previously announced four rig new-build program. With the execution of this contract, Savanna now operates four rigs in Mexico, 14 in the U.S., and 87 in Canada. It will be accepting delivery of two additional new builds by the third quarter of this year for a total fleet of 107 drilling rigs.

— DAILY OIL BULLETIN

BJ Services says its international pricing faces far less downward pressure than the U.S. and Canada.

The lingering effects of spring breakup a nd low nat ura l gas pr ices da mp ened Canadian results for BJ Services Company in the second quarter—the third of its fiscal year—as Canadian consolidated revenue fell 40 per cent from last year’s comparable figure. Measured against the previous quarter, Canadian revenue was down 63 per cent. In the three months ended June 30, Houston-based BJ posted a net loss of US$32.34 million, down sharply from earnings of US$141.78 million in the comparable 2008 quar ter. Revenue in the quarter dropped 25 per cent to US$786.92 million from US$1.33 billion in the earlier period. BJ has cut its global workforce by about 20 per cent since last November. In a conference call with analysts on July 22, BJ chairman and CEO Bill Stewart said the active drilling rig count in the United States declined 29 per cent from the previous quarter and 50 per cent from last year’s quarter. In contrast, average rig counts outside of North America dropped just five per cent from the previous quarter and 13 per cent year-over-year.

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

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with its material and finish. Those insights enable us to spray coat so the part

Endeavor Machining Solutions

will have the optimum precision and tolerances. When did you start Endeavor? October 2007, not long before the downturn in activity started to hit the oil and gas industry. It’s been a struggle. I’ve spent a lot of time on the road, identifying additional applications for our technology and persuading customers to give us a try. I enjoy dealing with people, but we’ve really had to bust our butts getting up the learning curve. What are your own qualifications and training? I grew up in Saskatoon, then got into the oilpatch with Waterflood Sales & Service and earned my journeyman machinist ticket. Later L.O.P. Inc. hired me as a machine manager, then made manufacturing manager with responsibility for 60 people. In starting my own company, my biggest advantage is having worked my way up from the bottom. What do you see as the keys to Endeavor’s success so far? With skilled trades in short supply, that’s a critical factor. So is honesty and, of course, you have to work hard. I’m usually the first to arrive in the morning, the last to leave at night. Teamwork is a big thing for me—I like to be involved in every aspect of a job, and my employees know my door is always open. As the old saying goes, I remember the ways I’ve been treated and what worked. And I stick to the truth with everyone. If we haven’t been able to get a job started, I won’t BS a customer that it’s half done. I just explain what’s happening. I’ve made mistakes, but so far we’ve never lost a customer. Frankly, your work pattern sounds like a recipe for a future divorce.

Photo: Jennifer Jacula

Not if I can help it—Tracy and I just had our fourth child, a boy, a few weeks ago. Living in Lloyd is a huge help. Five minutes and I’m home for lunch and supper every day when I’m in town. If necessary, I go back to work after the kids are in bed. I’ll leave in the middle of the day for a couple of hours to watch my daughter graduate from kindergarten. Only one of our employees has children at this point, but this company believes in helping everyone strike the right balance between work and home. O I L & G A S I N Q U I R E R • S EPTEMBER 2 0 0 9

Diversified Glycol Services Inc. USED GLYCOL PROCESS FEE

Industrial Storage For Lease Drill Pipe • Tractors • Trailers Farming Equipment • Tanks Lumber • Etc. Priced under market value 1 to 20 acre parcels Partly serviced

Reducing G-House emissions

diversifiedglycol@yahoo.ca 403-343-9555 Red Deer, AB

For all inquiries phone: Red Deer (403) 346-7111 Calgary (403) 254-9300 or (403) 690-0919 Email: multiconltd@gmail.com

Ask about our “trade-in” option on replacement glycols!

T&E Pumps Ltd. Crude Oil • Water • Acid • Condensate Fluid Transfer • Recycle Pumps • Skim Pumps

Custom solutions…

Call us in Consort

for the dealer nearest you:

(403) 577-3825 or visit our website at

www.tepumps.com Bonnyville, Brooks, Drayton Valley, Edmonton, Edson, Grande Prairie, High Prairie, Hinton, Lloydminster, Medicine Hat, Peace River, Spruce Grove, Strathmore, Swift Current, Taber and Westlock E-mail: tyler@tepumps.com Fax: (403) 577-3813 “The Environmentally Friendly Solution”

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

From a custom manufacturer. 1-888-227-4923 Phone: (403) 227-7799 Fax: (403) 227 -7796 E -Mail: sales@bilton.ca W ebsite: www.bilton.ca

Rig Talk

A LOOK AT NEW DRILLING TECHNOLOGIES

Rollgliss R500 Rescue and Escape Device Who is Capital Safety? Capital Safety has been in the fall protection and rescue business for more than 50 years, and is home of the Dbi-Sala and Protecta brands. Unlike most other safety-related companies, we only design and manufacture fall protection and rescue equipment. That focus has made us the leading innovator in our industry, with 11 operating sites worldwide. We engineer and rigorously test our safety systems, which include fall arrest and prevention systems, to exceed industry standards set by the OSHA, ANSI, CSA, and CE. What is the Rollgliss R500 Rescue and Escape Device? It is a fully automatic, controlled-descent device that excels in fast and safe rescue. The Rollgliss R500 offers self-rescue, emergency evacuation, and assisted rescue with lifting capabilities. The system comes complete in a carrying bag that includes the descent device, desired length of rope, rope grab, carabiners, pulley, anchoring straps, and edge protection. How does it work? The device is bi-directional. Once anchored, the evacuee or victim hooks up to one end of the line and is automatically lowered to the ground or next structure. While being lowered, the other end of the rope ascends up to the next evacuee or victim. The device can also be used to rescue a victim by disengaging them from their primary fall protection system by using the rescue hub that is included in some models. During assisted rescue, a fallen worker can be attached to the R500 device, raised to a point that allows their fall arrest device to be removed, then lowered safely to the ground or next level. What are the competitive advantages of this equipment? The Rollgliss R500’s ladder bracket is spring-loaded, so installation to the ladder rungs is much easier and requires fewer steps. Because the R500’s rescue hub is solid where others are open or slotted, there is no danger of objects being lodged into the hub, thus stopping the descent or rescue. The Rollgliss R500 comes complete with Dbi-Sala patented snap hooks, which are compatible with the Dbi-Sala First-Man-Up Pole. The First-Man-Up Pole can be used in conjunction with the Rollgliss R500 and assist in rescues remotely or from safe work areas and not subject the rescuer to the fall situation. Finally, the Rollglis R500’s rope sheave is on the outside of the device versus the inside of the device. The benefit here is heat dissipation. Running hundreds of feet of rope through a device like this can create high temperatures. With the competitive models, the rope actually goes in and out of the device where the high heat is, which could cause premature wear and degradation to the rope. The Rollgliss R500’s rope does not enter the device, so it is not subject to high temperatures. Answered by Charley Bryant, product manager for hard

Capital Safety's Rollgliss R500 device, shown at left, is used in locations where life and death are always on the line.

goods with Capital Safety.

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

Political Cartoon

Advertisers' Index 1174365 Alberta Ltd . . . . . . . . . . . . . . . . . . . 64 Aggreko LLC . . . . . . . . . . . . . . . . . . . . . . . . . .5 AGI-Envirotank . . . . . . . . . . . . . . . . . . . . . . 64 Allan R. Nelson Engineering (1997) Inc . . . . . 66 All Weather Shelters Inc . . . . . . . . . . . . . . . 59 Annugas Compression Consulting Ltd . . . . . 27 ATCO Structures Inc . . . . . . . . . . . . . . . . . . . 60 Bear Slashing Ltd . . . . . . . . . . . . . . . . . . . . . 43 Belzona Western Ltd . . . . . . . . . . . . . . . . . . 48 Bilton Welding and Manufacturing Ltd . . . . 68 Brother’s Specialized Coating Systems Ltd . . 10 Canaccord Adams . . . . . . . . . . . . . . . . . . . . 50 Canaccord Capital Corp . . . . . . . . . . . . . . . . 62 Canadian Enviro-Tub Inc . . . . . . . . . . . . . . . . 53 CJS Coiled Tubing Supply . . . . . . . . . . . . . . . 64 Compact Compression Inc . . . . . . . . . . . . . . 38 Compass Bending Ltd . . . . . . . . . . . . . . . . . 60 Contain Enviro Services Ltd . Inside Back Cover Cover-All Alberta . . . . . . . . . . . . . . . . . . . . . 54 D’Arcy & Deacon LLP . . . . . . . . . . . . . . . . . . 66 Dean’s Pump Service Ltd . . . . . . . . . . . . . . . 48 Delta Industrial Valves Inc . . . . . . . . . . . . . . 40 DFI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Dicks Boiler Ltd . . . . . . . . . . . . . . . . . . . . . . 33

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

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