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OIL&GAS March 2013 ~ $6.00

INQUIRER Western Canada's Exploration & Production Authority

Field of Schemes

PM40069240

Heavy oil producers find ways to keep the product flowing

Plus: Tracking oil exploration and development in southern Alberta

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CONTENTS

MARCH.

www.sprung.com/oilgas

in the news

13

Field activity down in 2012

Engineered Fabric Building Solutions

regional news

17

British Columbia

NEB approves third LNG export licence

23

39

Southern Alberta

Gas prices and production should increase

Northeastern Alberta

Cenovus expects big things from new projects

over next five years, says BENTEK

43

Saskatchewan

Renegade spending $80 million in 2013

tech news

47

Central Alberta

Duvernay drilling expected to increase in 2013

Northwestern Alberta

Yoho reports Duvernay success at Kaybob

27

33

CO2 Solutions receives $4.7 million for carbon capture project

features Cover Feature

50 53 57 59 Field of schemes Heavy oil producers find ways to keep the product flowing

New wave Steam, chemical sweeps, push heavy oil growth

Pockets of opportunity Explorers begin to unravel new oil plays in southern Alberta

Back to the well Enhanced recovery creating new reserves in southern Alberta

Short Term Leasing Available

business intelligence Workforce logistics management matters to the bottom line

every issue

10 Stats at a Glance 62 Political Cartoon

On the Cover SAGD is a growing technology in conventional heavy oil plays. Photography by: Joey Podlubny Post-production and design by: Peter Markiw

OIL&GAS March 2013 ~ $6.00

INQUIRER Western Canada's Exploration & Production Authority

Field of Schemes Heavy oil producers find ways to keep the product flowing

PM40069240

61

Plus: Tracking oil exploration and development in southern Alberta

1 800 528.9899 403 601.2292

Direct Dial:

info@sprung.com CALGARY • ALBERTA

OIL & GAS INQUIRER • MARCH 2

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Carbon Steel Stainless Steel Alloys & Duplex

Editor’s Note Vol. 25 No. 2 EDITORIAL EDITOR

Darrell Stonehouse | dstonehouse@junewarren-nickles.com CONTRIBUTING WRITERS

Joseph Caouette, Lynda Harrison, Carter Haydu, Richard Macedo

Is this corporate welfare?

CONTRIBUTING PHOTOGRAPHERS

Aaron Parker, Joey Podlubny

EDITORIAL ASSISTANCE MANAGER

Samantha Sterling | ssterling@junewarren-nickles.com EDITORIAL ASSISTANCE

Laura Blackwood, Tracey Comeau CREATIVE PRINT, PREPRESS & PRODUCTION MANAGER

Michael Gaffney | mgaffney@junewarren-nickles.com CREATIVE SERVICES MANAGER

Tamara Polloway-Webb | tpwebb@junewarren-nickles.com CREATIVE LEAD

Cathlene Ozubko GRAPHIC DESIGNER

Peter Markiw

CREATIVE SERVICES

Christina Borowiecki, Paige Pennifold production@junewarren-nickles.com SALES SALES MANAGER—ADVERTISING

Monte Sumner | msumner@junewarren-nickles.com SENIOR ACCOUNT EXECUTIVE

Diana Signorile SALES

Nick Drinkwater, Sammy Isawode, Mike Ivanik, Nicole Kiefuik, David Ng, Tony Poblete, Sheri Starko For advertising inquiries please contact adrequests@junewarren-nickles.com AD TRAFFIC COORDINATOR—MAGAZINES

Denise MacKay | atc@junewarren-nickles.com DIRECTORS PRESIDENT & CEO

Bill Whitelaw | bwhitelaw@junewarren-nickles.com VICE-PRESIDENT

Rob Pentney | rpentney@junewarren-nickles.com DIRECTOR OF SALES & MARKETING

Maurya Sokolon | msokolon@junewarren-nickles.com DIRECTOR OF EVENTS & CONFERENCES

Ian MacGillivray | imacgillivray@junewarren-nickles.com DIRECTOR OF THE DAILY OIL BULLETIN

Stephen Marsters | smarsters@junewarren-nickles.com DIRECTOR OF DIGITAL STRATEGIES

Gord Lindenberg | glindenberg@junewarren-nickles.com DIRECTOR OF CONTENT

Chaz Osburn | cosburn@junewarren-nickles.com DIRECTOR OF PRODUCTION

Audrey Sprinkle | asprinkle@junewarren-nickles.com DIRECTOR OF FINANCE

Ken Zacharias, CMA | kzacharias@junewarren-nickles.com OFFICES Calgary

nd Flr-  Avenue N.E. | Calgary, Alberta TE Y Tel: .. | Fax: .. Toll-Free: ...

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News that the Canadian Association of Petroleum Producers (CAPP) asked the federal government to rework the tax treatment around capital-cost allowances for the development of liquefied natural gas (LNG) export terminals to save the industry as much as $2 billion over the next seven years comes as no surprise. In the late 1990s, the federal government accelerated the allowance, allowing oilsands operators to write off capital costs faster, resulting in a boom in construction and production that will pay dividends for the next 50 years. So it only makes sense that a similar program could spur LNG export development. Speaking to the standing committee of finance last fall, CAPP president David Collyer said LNG terminals should be treated as manufacturing plants, allowing them to write off 90 per cent of capital costs within seven years of construction. The facilities are currently treated as part of the gas transmission system, meaning costs would be written off over a period of 27 years. Collyer said the reclassification would “positively influence near-term final investment decisions for LNG liquefaction facilities.” CAPP is arguing the change in capitalcost allowance is needed to compete with the United States and Australia in the global LNG export race. Opposition to the request is already taking shape. The Canadian Taxpayers Federation says LNG terminals are not manufacturing and shouldn’t be treated as such. It also argues the lost tax revenue will have to be made up from the people of British

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Telephone: ... Email: circulation@junewarren-nickles.com Online: junewarren–nickles.com GST Registration Number RT. Printed in Canada by PrintWest. ISSN - | ©  JuneWarren-Nickle's Energy Group. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number . Postage paid in Edmonton, Alberta, Canada. If undeliverable, return to: Circulation Department, 80 Valleybrook Dr, North York, ON M3B 2S9 Made in Canada The opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.

Columbia, meaning they will be subsidizing the LNG industry. Labour organizations say the accelerated capital-cost recovery for manufacturers makes sense because manufacturing creates so many jobs, something the LNG export facilities can’t claim. The real problem, of course, is government’s insistence on using the tax code and tax policy as a means to interfere in the free market—usually for political ends. Fair tax policy would treat all industry the same, eliminating the distortions that encourage the misallocation of capital to less-profitable enterprises. Both federal and provincial governments would stick to taking the money they need to run their affairs and quit trying to use the tax code to pick winners and losers, or to encourage the development of one sector of the economy over another. And it goes further than that. By using tax policy as a political tool, governments can also affect public perceptions of private enterprise. LNG developers are already being vilified in the media as corporate welfare cases asking to be “subsidized” by the government. For the record, a subsidy is a handout like what was given to the Ontario auto industry, not a request to keep more of your own money like the LNG industry is asking. Until government stops politicizing the economy, this sort of nonsense will continue, and even if it’s successful in getting its requested change, the oil industry will come out looking bad. Something needs to change. Darrell Stonehouse

Editor dstonehouse@junewarren-nickles.com

N E XT I S S U E April 2013 A look at how the midstream is expanding to account for growing liquids production and in preparation for LNG exports. Plus, a review on instrumentation and automation technologies.

Want to sound off on any content in Oil & Gas Inquirer? Send your emails to dstonehouse@junewarren-nickles.com. Please mark them as ”Letter to the Editor” if you want them published.

OIL & GAS INQUIRER • MARCH 2

9

FAST NUMBERS

,

WCSB wells drilled 2012, down 14 per cent from 2011.

WCSB metres drilled 2012, down 6.7 per cent from 2011.

Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin

M O NTH

OIL

Jan 2012









Feb 2012









GAS

OTHER

T O TA L

MONTH

OIL

GAS

D RY

SERVICE

T O TA L

Jan 2012









655

Feb 2012









1,153 1,275

Mar 2012









Mar 2012









Apr 2012









Apr 2012









988

Jun 2012









Jun 2012







449

Jul 2012









Jul 2012









873

Aug 2012







986

Aug 2012









Sep 2012









Sep 2012







908

Oct 2012









Oct 2012

,







1,269

Nov 2012









Nov 2012









1,250

Dec 2012









Dec 2012









1,054

Jan 2013







Jan 2013





645

Wells Drilled in British Columbia

Saskatchewan Completions

Source: B.C. Oil and Gas Commission

Source: Daily Oil Bulletin

MONTH

WELLS DRILLED

C U M U L AT I V E *

MONTH

OIL

GAS

OTHER

TOTAL

Jan 2012

53

53

Jan 2012





Feb 2012

66

119

Feb 2012







Mar 2012

39

158

Mar 2012







Apr 2012

86

244

Jun 2012

Apr 2012







13

334

Jun 2012







Jul 2012

57

401

Aug 2012

53

454

Sep 2012

11

465

Oct 2012

28

493

Nov 2012

78

571

Dec 2012

65

636

Jan 2013

31

31

*From year-to-date * from year to date

10

. million

MARCH 2013 • OIL & GAS INQUIRER



Jul 2012







Aug 2012





Sep 2012





Oct 2012





 

Nov 2012





Dec 2012







Jan 2013





STATS

AT A

GLANCE

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada, February 13, 2013 Source: Rig Locator

Alberta, February 2013 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

(Per cent of total)

Western Canada Alberta

AC T I V E

OIL WELLS

Alberta

GAS WELLS

Jan 

Jan 

Jan 

Jan 







%

Northwestern Alberta









British Columbia





%

Northeastern Alberta





Manitoba





%

Central Alberta







Saskatchewan







81%

Southern Alberta



31











%

TOTAL









WC TOTALS

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada, February 13, 2013 Source: Rig Locator

Alberta, February 2013 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

(Per cent of total)

Western Canada

Alberta

AC T I V E

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

Alberta

BITUMEN WELLS

Jan 

Jan 

Jan 

Jan 







%

Northwestern Alberta



British Columbia





%

Northeastern Alberta





Manitoba





%

Central Alberta







Saskatchewan





206

79%

Southern Alberta



WC TOTALS







%

TOTAL







OIL & GAS INQUIRER • MARCH 2013

11

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IN THE

Photo: Joey Podlubny

NEWS Issues affecting Canada’s E&P industry

The header for this header Field activity in 2012 the header fordown this header

The header for this header

By XX drilled 11,070 wells across Canada Operators in 2012, off 14 per cent from 12,869 rig releases in the prior year. Last year’s final drill count was the second lowest in the past decade, as the shift to longer horizontal wells and constrained natural gas drilling continued to shape the industry. As a result, overall metres drilled declined by 6.73 per cent to 22.25 million metres, from 23.85 million metres in 2011. In western and northern Canada, the average depth/length per well was a record 2,000 metres last year, up about eight per cent over 2011’s 1,855 metres. The average depth/length of development wells drilled in 2012 (1,951 metres) was more than twice the average 10 years earlier. In 2002, the average length of a development hole was 964 metres. During 2012, operators continued to emphasize development drilling, with

By XX exploratory drilling declined in all four western provinces. Many of the wells drilled last year are still under confidential status, but of those with a reporting status, about 79 per cent were listed as oil or bitumen wells, compared to 69 per cent listed as oil or bitumen wells in 2011. Only 12 per cent of the wells with a reporting status in 2012 were listed as gas wells, down from about 22 per cent the prior year. By province, Alberta rig released 6,792 wells last year, off 16.32 per cent from 8,117 wells drilled in 2011. By metres drilled, the province rig released 14.07 million metres compared to 15.03 million metres the previous year (a decrease of about six per cent). There were 5,039 wells drilled with a target of oil or bitumen (off from 5,239 the prior year), while only 1,097 wells had gas or coalbed methane as an objective (compared to 2,227 the previous year). Operators in Saskatchewan drilled 3,170 wells during 2012, a decrease of 9.2 per cent from 3,491 wells the prior year. Metres drilled slumped 5.26 per cent to 5.17 million metres, from 5.45 million metres in 2011. In British Columbia, fewer than 500 wells were rig released over the course of 2012, with a 25.91 per cent year-overyear decline (466 rig releases last year compared to 629 in 2011). Metres drilled declined to 1.81 million metres from 2.24 million metres. Manitoba operators drilled a record 615 wells last year, up 5.49 per cent from 2011. It was the only province to record a year-over-year increase in rig releases. Metres drilled lifted 8.57 per cent to 1.15 million metres in 2012, from 1.06 million metres the previous year.

19.28 million metres drilled across the country, down from 20.45 million metres in 2011. The biggest growth areas for Petroleum Services Association of Canada zones— ranked by increased metres drilled, excluding test wells—were in northeastern Alberta (up 591,650 metres year-overyear), Manitoba (up 91,018 metres) and eastern Saskatchewan (up 55,600 metres). On a percentage-increase basis, northeastern Alberta led the way with a 40.63 per cent increase to 2.05 million metres, followed by the Foothills (up 25.96 per cent to 57,043 metres) and Manitoba (up 8.57 per cent to 1.15 million metres). O ve r a l l, i ndu st r y d r i l led 1, 245 exploratory wells in Canada last year, off about 19 per cent from 1,543 the prior year and down 25 per cent from 2010, when 1,661 exploratory wells were rig released. On a year-over-year basis,

Calfrac crew working in southern Alberta. Fewer wells drilled means less field activity, despite the growing length of wells.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • MARCH 2013

13

In The News

Growth in U.S. energy production outstrips consumption growth

7.5

million barrels per day

EIA U.S. oil production estimate for 2019

The United States is using less energy and producing more energy, and the trend is expected to continue in the future, according to The Annual Energy Outlook 2013 reference case released in January by the U.S. Energy Information Administration (EIA). The outlook presents updated projections for U.S. energy markets through 2040. These projections include only the effects of policies that have been implemented in law or final regulations. “EIA’s updated reference case shows how evolving consumer preferences, improved technology and economic changes are pushing the nation toward more domestic energy production, greater vehicle efficiency, greater use of clean energy and reduced energy imports,” said EIA administrator Adam Sieminski. In the outlook, crude oil production, particularly from tight oil plays, rises sharply over the next decade. The advent and continuing improvement of advanced crude oil production technologies continues to increase projected domestic supply. Domestic production of crude oil increases sharply in the 2013 outlook, with an annual growth averaging 234,000 barrels per day 14

MARCH 2013 • OIL & GAS INQUIRER

from 2011 through 2019, when production reaches 7.5 million barrels per day. The growth results largely from a significant increase in onshore crude oil production, particularly from shale and other tight formations. After about 2020, production begins declining gradually to 6.1 million barrels per day in 2040 as producers develop sweet spots first and then move to less productive or less profitable drilling areas. Gasoline consumption has declined from last year’s report, reflecting the introduction of more stringent corporate average fuel economy (CAFE) standards. Growth in diesel fuel consumption is moderated by increased use of natural gas in heavy-duty vehicles. The 2013 outlook incorporates the greenhouse gas and CAFE standards for light-duty vehicles through the 2025 model year, which raise the new-vehicle fueleconomy requirement from 32.6 miles per gallon (mpg) in 2011 to 47.3 mpg in 2025. The increase in vehicle efficiency reduces gasoline use in the transportation sector by 0.5 million barrels per day in 2025 and by one million barrels per day in 2035. Furthermore, the improved economics of natural gas results in an increase in the use

of liquefied natural gas (LNG) in heavy-duty vehicles that offsets a portion of diesel fuel consumption. The use of petroleum-based diesel fuel is also reduced by the increased use of diesel produced using gas-to-liquids (GTL) technology. Natural gas use in vehicles reaches 1.7 trillion cubic feet (including GTL) by 2040, displacing 700,000 barrels per day of other motor fuels. Natural gas production increases throughout the projection period, outpacing domestic consumption by 2020 and spurring net exports of natural gas. U.S. exports of LNG from domestic sources rise to approximately 1.6 trillion cubic feet in 2027. The United States becomes a net exporter of LNG in 2016. The Brent spot crude oil price declines from $111 per barrel (in 2011 dollars) in 2011 to $96 per barrel in 2015. After 2015, the Brent price increases, reaching $163 per barrel in 2040, as growing demand leads to the development of more costly resources. World liquids consumption grows from 88 million barrels per day in 2011 to 113 million barrels per day in 2040, driven by demand in China, India, Brazil and other developing economies.

Photo: Joey Podlubny

Refinery at Fort Saskatchewan. Demand for gasoline is expected to decline by 500,000 barrels per day by 2035.

In The News

PSAC sees activity climbing in 2013 In its first update to the 2013 Canadian drilling activity forecast, released in January, the Petroleum Services Association of Canada (PSAC) increased its forecasted number of wells drilled across Canada for 2013 to 11,475 wells. This is an increase of 75 wells from PSAC’s original 2013 forecast, released in early November 2012. The service industry organization said it is basing its updated 2013 forecast on average natural gas prices of C$2.95 per thousand cubic feet at AECO and crude oil prices of US$90 per barrel West Texas Intermediate, and the Canadian dollar on par with its American counterpart. On a provincial basis for 2013, PSAC now estimates 7,165 wells to be drilled in Alberta, representing a two per cent increase from the original forecast. British Columbia is also expected to experience an increase in drilling levels from 385 to 435 wells, a 13 per cent increase. Estimates for Saskatchewan remain steady at 3,199 wells. Manitoba is now forecasted to drill 100 fewer wells at 650 for the year, representing a 13 per cent change. “Due to continued natural gas development in northeastern British Columbia, we’ve adjusted our numbers to reflect that activity,” said Mark Salkeld, president and chief executive officer of PSAC. “At the same time, we are

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11,475

wells

PSAC’s new estimate of 2013 drilling activity

seeing increased activity in northern Alberta with exploratory wells around the oilsands in situ plays. Alternatively, infrastructure bottlenecks in Manitoba, including restricted pipeline capacity, are creating backup and oversupply in the province.” PSAC presents updates to its forecast quarterly, with the mid-year update scheduled to be presented on April 25. “We are optimistic that our forecast update at the mid-year point will show relative stability from our now-updated forecast of 11,475 wells,” Salkeld added. OIL & GAS INQUIRER • MARCH 2013

15

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BRITISH COLUMBIA WELL ACTIVITY JAN/12

JAN/13

Wells licensed





JAN/12

JAN/13

Wells spudded





JAN/12

JAN/13





Rigs released

B.C. British Columbia

Source: Daily Oil Bulletin

NEB approves third LNG export licence By Richard Macedo

Photo: Global Security

The National Energy Board (NEB) gave the green light to an export licence for LNG Canada Development Inc.’s planned project to ship liquefied natural gas (LNG) overseas from a proposed facility near Kitimat, B.C., in late January. This is the third export licence granted by the board. Out of the gate first in getting the nod was Kitimat LNG (KM LNG), which will be led by Chevron Corporation and includes Apache Corporation, each 50/50 partners. The NEB also has approved BC LNG Export Co-operative LLC’s 20-year licence to export LNG from Canada to the Pacific Rim. This would be a smallerscale project near Kitimat. And the board approved LNG Canada’s application for a licence to export LNG from a proposed terminal near Kitimat. T he ter m i na l is c ur rent ly bei ng de veloped under a joint development agreement among Shell Canada Limited, as managing partner of Shell Canada Energy, Diamond LNG Canada Ltd. (an

affi liate of Mitsubishi Corporation), Kogas Canada Ltd. (an affiliate of Korea Gas Corporation) and Phoenix Energy Holdings Limited, which is an affiliate of PetroChina Investment (Hong Kong) Limited. While Shell currently owns 100 per cent of LNG Canada, these parties intend to enter into a shareholding agreement whereby each will own shares in LNG Canada. “Shell welcomes the decision as a key milestone in the LNG Canada project to transport abundant Canadian natural gas to the fast-growing economies of Asia,” said Shell spokesman David Williams. LNG Canada launched in May 2012 and the export licence was filed in July. TransCanada Corporation was selected by Shell and its partners to design, build, own and operate the proposed Coastal GasLink project, an estimated $4-billion pipeline that will transport natural gas from the Montney gas-producing region near Dawson Creek to the LNG Canada export facility.

The Arctic Princess LNG tanker at work. Three LNG export licences have been granted by the NEB.

The next step for the LNG project is for proponents to file a project description, which starts the full regulatory/environmental approval process. Front-end engineering and design work will also be done. A fi nal investment decision is expected by mid-decade, and the project could be on stream by the end of the decade. The export licence will authorize LNG Canada to export 670 million tonnes of LNG (approximately equivalent to 32.95 trillion cubic feet of natural gas) over a 25-year period. The maximum annual quantit y allowed for expor t w ill be 24-million tonnes of LNG (approximately equivalent to 1.18 trillion cubic feet of natural gas, or 3.23 billion cubic feet per day).

33

trillion cubic feet

Amount of gas LNG Canada is licensed to export over 25 years

In approving the application, the board said it has satisfied itself that the quantity of gas to be exported does not exceed the surplus remaining after “due allowance has been made for the reasonably foreseeable requirements for use in Canada, having regard to the trends in the discovery of gas in Canada.” “I think it is good that the NEB has carefully assessed the information, studies and strategies put forth by the proponents, and in my opinion, the NEB has come forward with a very encouraging signal—not only for this LNG export project and the earlier approved two LNG export [licences]; rather, this is a solid forward step for the entire western Canada gas industry,” said Bill Gwozd, senior vice-president of gas services at Ziff Energy Group. Edward Kallio, director, gas consulting, with Ziff Energy Group, noted that LNG OIL & GAS INQUIRER • MARCH 2013

17

3.23

billion cubic feet

Daily gas exports permitted by the NEB

The Fort Nelson gas plant. Fort Nelson First Nations have expressed concerns over the LNG export plans.

Canada is further ahead with respect to downstream arrangements, with partner buyers involved. “They still need pipeline approvals... which KM LNG already have lined up, and that is a significant hurdle,” he said. In terms of aboriginal matters raised during the export application comment period, Fort Nelson First Nation submitted that the application relies on a significant increase in gas production within Fort Nelson First Nation territory, which may have serious impacts on its treaty rights by damaging the environmental integrity of the land. Fort Nelson First Nation further submitted that, before issuing the licence,

the board must be satisfied that the Crown has discharged its duty to consult Fort Nelson First Nation. It stated that, as LNG Canada has not presented evidence regarding the consultation of Fort Nelson First Nation, the board should reject the application. Fort Nelson First Nation requested that the board hold an oral hearing to receive such evidence. Gitga’at Nation expressed concern that LNG exports from the terminal would significantly impact its aboriginal rights and title because of an increase in ship traffic through its territory. Gitga’at First Nation submitted that any approval that would advance LNG Canada’s proposed project ahead of the Crown’s consultation obligations being met is a breach of the Crown’s duty to consult. It further submitted that, until the Crown’s duty of consultation and accommodation is fulfilled, the licence should not be granted. Gitxaala Nation also expressed concer n t hat L NG Canada’s proposal to export LNG by tanker would have serious adverse impacts on its aboriginal rights and title.

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MARCH 2013 • OIL & GAS INQUIRER

Photo: Joey Podlubny

British Columbia

British Columbia

No Plan B if Northern Gateway does not go ahead By Joseph Caouette

The Northern Gateway pipeline is a matter of national priority—but that doesn’t mean there’s a backup plan, according to the executive responsible for the project. “ We don’t have a Pla n B at t he moment,” said Al Monaco, president and chief executive officer of Enbridge Inc., when asked what his company would do if the pipeline proposal did not move forward. He was speaking before a crowd of business and government leaders at a downtown luncheon hosted by the Alberta Enterprise Group in Edmonton. Monaco’s speech touched on the need for new market access to fight the growing gap between Canadian heavy crude prices and the West Texas Intermediate and Brent benchmarks. While there may not be a Plan B, the executive emphasized that the company did have a strong Plan A. This includes a $6-billion Gulf Coast access program, an Eastern access program and a $6-billion

light-oil market access program. The fi nal piece of the puzzle is the Northern Gateway pipeline proposal to provide West Coast access to Asian markets for Alberta oil. During his speech, Monaco acknowledged the strong resistance to the Gateway project from various stakeholders, such as environmental groups, local communities and First Nations. As public opinion towards pipelines has evolved, so, too, must pipeline companies change to meet the increasing scrutiny, he explained. “It’s not just about meeting the regulatory standard—we have to take into account people’s concerns,” he said. In fact, Monaco has welcomed the input, which he believes has improved the project. “ We’ve made nu merous c ha nges to the route, and that’s been based on community input and local expertise,” he said. “They know all the nooks and crannies of what ’s happening in their

environment better than we do, so we’ve taken that advice.” In a question-and-answer session after the speech, Monaco was asked if his company had underestimated the level of opposition that the pipeline would meet. He admitted the company could have been better prepared. “As to what we would have done differently, I can’t stand up here today and say, ‘Boy, we did everything right,’” Monaco told the crowd. “I think maybe we would have started earlier down at the community level, and did a lot more ground work in terms of building trust,” he said. “We need to have the trust, and I think we probably could have spent more time up front building that trust.” In many ways, this is a new challenge for the company. Monaco noted that this controversy is a relatively recent phenomenon for his industry.

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MARCH 2013 • OIL & GAS INQUIRER

“The pipeline business used to be a pretty calm place to be. That’s no longer the case. Projects like Keystone XL and our Northern Gateway project have become the lightning rod for conflict and protest.” — Al Monaco, president and chief executive officer, Enbridge Inc.

“The pipeline business used to be a pretty calm place to be. That’s no longer the case,” he said. “Projects like Keystone XL and our Northern Gateway project have become the lightning rod for conflict and protest.” The reason is that pipelines are the enablers of energy production, making them an attractive target for groups eager to stop oil and gas development. “You stop the pipelines and you stop the energy development,” he said. As a result, pipeline companies are increasingly forced into the role of spokesperson for the entire oil and gas industry—a situation that needs to change, according to Monaco, who notes that “the clock is ticking” on the need for “a more-balanced national discussion.” “Part of that discussion requires that we build effective coalitions on various components of the energy value chain, so it can’t just be the pipeline companies making this case,” he said. “It will need to involve government, service providers, unions and people within communities that we operate in.” Monaco was more circumspect after his speech when asked by reporters what governments could do to become more involved. He praised Alberta Premier Alison Redford’s efforts at reaching out to the entire country on energy issues and lauded the federal government’s changes to the regulatory review system, but declined to suggest what else could be done to address the public resistance to new pipelines. He also avoided comment when asked about the upcoming B.C. election, which will likely be a showdown between the New Democratic and Liberal parties. Neither party has been particularly warm to the Northern Gateway proposal, with Liberal Premier Christy Clark even going so far as to issue a list of five conditions that the project must meet if it is to proceed in the province. The executive said he would work with whoever wins the election and even welcomed Clark’s conditions. “We see it as a pretty good road map, actually,” he said. While questions about the political climate in British Columbia will remain unresolved until the province’s expected May election, the regulatory timeline is at least certain for the company. The public side of the joint review process is expected to wrap up in May, with the National Energy Board’s decision slated for the end of the year. “After that, there is a federal cabinet approval process that I believe needs to be completed by the end of June 2014,” Monaco said.

British Columbia

Word expected this spring on whether Kitimat refinery proposal will fly By Carter Haydu

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Photo: Joey Podlubny

David Black continues pushing plans for a $13-billion refinery at Kitimat.

B.C. businessman David Black says he should know in the next 60 days whether his proposed $13-billion Kitimat oil refinery will proceed. “When will I know if we can do it? I’d say 60 days. A lot of the pieces I’m working on will let us know where they’re going to be. There are a lot of potential stakeholders here and I’ve been talking to them all,” he told reporters following a presentation at Insight Information’s Canadian Oil Sands Summit. In August 2012, the owner of the Black Press Group Ltd. newspaper chain announced that privately held Kitimat Clean Ltd., of which he is chairman, had submitted an environmental assessment application for a world-class oil refinery north of Kitimat. The plan is to construct a 550,000-barrel-per-day refinery to process heavy crude oil transported on Enbridge Inc.’s proposed Northern Gateway pipeline. He believes a modern west coast refinery would be incredibly important to the Alberta oilsands. It would produce 240,000 barrels per day of diesel, 100,000 barrels per day of gasoline and 50,000 barrels per day of aviation fuel. Once Black knows whether the project can proceed, it will take a couple of years to obtain all the necessary permits and environmental assessments followed by five years of construction for a 2020 start-up. “So it’s going to take a while.”

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British Columbia

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Black, whose media chain runs 150 newspapers in Canada and the United States, told those attending the gala dinner that a majority of British Columbians, even those who lean towards the political right, simply are not in favour of pipelines in their province that would move Alberta bitumen to the west coast for shipment abroad. “I can pretty much tell you British Columbia is not in favour of Northern Gateway pipeline—70 per cent against it,” he said, adding that a pipeline doesn’t make sense for the province, as it offers only temporary construction jobs and then little else, aside from the potential for damage to the pristine environment. With such widespread disapproval of the pipeline, Black said, the province’s Liberal government has little choice but to oppose it. “What are you going to do when 70 per cent are against it? Of course the solution is the refi nery, because that turns the population of B.C. around. So that’s what we have to do, and that’s what we’re trying to do.”

“I can pretty much tell you British Columbia is not in favour of Northern Gateway pipeline— 70 per cent against it.” — David Black, owner, Black Press Group Ltd.

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MARCH 2013 • OIL & GAS INQUIRER

According to Black, a world-class refinery provides economic stimulation and a multitude of permanent jobs for his province—3,000 precisely—and gives British Columbia an oilsands buy-in and delivers the social licence necessary for that project to occur. A large-scale refinery also requires a lot of natural gas to operate, which means the Kitimat project would boost British Columbia’s natural gas industry as well. “It would be a fairly sizable consumer of B.C. gas, and God knows, we need some consumers of our natural gas.” For Alberta’s industry, Black said, a refinery that legitimizes pipeline construction gives oilsands products access to foreign markets, helping to resolve the current discount for Alberta crude due to its inaccessibility to markets beyond the United States. Because of Kitimat’s access to tidewater and proximity to natural gas, Black said a large refinery project would be able to offer good-paying jobs and environmental standards not found in a lot of similar facilities around the world, yet at the same time turn a tidy profit and out-compete pretty much any other refinery along the Pacific Rim.

NORTHWESTERN ALBERTA WELL ACTIVITY JAN/12

JAN/13

Wells licensed





JAN/12

JAN/13

Wells spudded





JAN/12

JAN/13





Rigs released

Source: Daily Oil Bulletin

N.W. Northwestern Alberta

Yoho reports Duvernay success at Kaybob

Photo: Joey Podlubny

Yoho Resources Inc. is making progress in commercializing its resource play in the Duvernay shale in the Kaybob play in northwestern Alberta. At Kaybob, Yoho operated the drilling and completion of the fi rst two horizontal Duvernay development wells from a pad site at 15-16-62-21W5. The first well, located at 14-21-6221W5 (75 per cent working interest), was drilled to a measured depth of 4,943 metres. The horizontal lateral was 1,536 metres in length within the Duvernay shale formation. The well was drilled and cased over 33 days at a cost of approximately $4.5 million. Well completion operations started in late December 2012 using a plug-and-perf completion method. The well was fracture stimulated in 15 stages with 51 perf clusters, using 2,217 tonnes of sand and 18,940 cubic metres of completion fluid. Following the fracs, the pumpdown bridge plugs were drilled out with a coiled tubing

Yoho, one of the first Duvernay drillers, is finding lots of liquids at its Kaybob area play.

unit and production tubing was snubbed in. The total estimated cost of the completion is approximately $6.6 million, bringing the total cost to drill, complete and test the well to approximately $11.1 million. During initial cleanup, the 14-21 well flowed at restricted rates of up to 8.5 million cubic feet per day, or approximately 2,508 barrels of oil equivalent per day, including condensate and natural gas liquids. At the end of the 86-hour flow period, the well was producing at a rate of 6.3 million cubic feet per day, or approximately 1,860 barrels of oil equivalent per day, including condensate and liquids. In addition to the natural gas production at the end of the f low period, the well was producing field condensate at a rate of 665 barrels per day, or 106 barrels of field condensate per million cubic feet of raw gas. Additional liquids are anticipated to be recovered at the gas processing facility. Total liquids yield, including both field condensate and plant liquids, is estimated to be 155 barrels per million cubic feet of raw gas. The second well, at 1-16-62-21W5 (75 per cent working interest), was drilled to a measured depth of 4,355 metres. The horizontal lateral was 983 metres in length within the Duvernay shale formation. This well was planned as a substantially shorter lateral due to regulatory spacing regulations. The well was drilled and cased over 32 days at a cost of approximately $4.2 million. Well completion operations also started in late December 2012, using a plug-and-perf completion method. The well was fracture stimulated in 11 stages with 38 perf clusters, using 1,382 tonnes of sand and 13,031 cubic metres of

completion fluid. Following the fracs, the pumpdown bridge plugs were drilled out with a coiled tubing unit and production tubing was snubbed in. The total estimated cost of the completion is approximately $4.8 million, bringing the total cost to drill, complete and test the well to approximately $9 million. During initial cleanup, the 1-16 well flowed at restricted rates of up to 3.5 million cubic feet per day, or 913 barrels of oil equivalent per day, including condensate and liquids. At the end of the 90-hour flow period, the well was producing at a rate of

665

barrels per day of condensate

Flow of first Yoho Duvernay well in 86-hour test

2.3 million cubic feet per day, or 590 barrels of oil equivalent per day, including condensate and liquids. In addition to the natural gas production at the end of the flow period, the well was producing field condensate at a rate of 155 barrels per day, or 67 barrels of field condensate per million cubic feet of raw gas. Additional liquids are anticipated to be recovered at the gas processing facility. Total liquids yield, including both field condensate and plant liquids, is estimated to be 120 barrels per million cubic feet of raw gas. These two wells will be shut-in for one month to obtain pressure information and to allow the completion water to absorb into the formation. This absorption period, or “soak time,” has resulted in higher flow rates and flowing pressures after a period of shut-in time in previous wells drilled to date in the Duvernay formation. — DAILY OIL BULLETIN OIL & GAS INQUIRER • MARCH 2013

23

Northwestern Alberta

Pinecrest Energy pushes forward in Slave Point play

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Pinecrest Energy Inc. continues to successfully develop its Slave Point play at Red Earth using horizontal drilling and multistage fracturing technology. It is also introducing waterfloods to stem decline rates in the play. Pinecrest announced in January that its current production, based on field estimates, is 5,080 barrels per day (99 per cent oil and liquids), and it expects that the wells placed on production in December 2012 will continue to show improvement in production rates through early 2013 as completion fluids are recovered. During 2012, Pinecrest drilled a total of 38 operated Slave Point horizontal oil wells in the Red Earth area. Of these, 15 wells were drilled in the fourth quarter and nine commenced production in December 2012. Three gross wells were drilled in late 2012 and brought on production in January 2013. All of the company’s Slave Point horizontal wells are fracture stimulated using gelled water to place the frac sand in the reservoir. As a result, the company’s experience indicates that each individual well’s peak oil production rate is not observed until it has been on production for approximately two months.

During 2012, Pinecrest drilled a total of 38 operated Slave Point horizontal oil wells in the Red Earth area. Of these, 15 wells were drilled in the fourth quarter and nine commenced production in December 2012.

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MARCH 2013 • OIL & GAS INQUIRER

In 2012, Pinecrest also initiated its first operated waterflood in the play, and has since expanded waterflood efforts. “As a greater proportion of the company’s production base becomes pressure maintained, material positive change is expected to our overall production decline profile,” the company notes. Initial results from the company’s first 100 per cent operated waterflood scheme (Evi-Project #2) have been very encouraging and in accordance with company expectations. Injection commenced on Dec. 20, 2012, and has been on continuous injection since. After 25 days of injection, all of the offsetting producing wells in the scheme are already showing a positive response, each demonstrating an increase in pressure and current production rates up to two times higher than rates prior to injection. Pinecrest has received Energy Resources Conservation Board approval for its second 100 per cent operated waterflood (Loon-Project #1), with injection scheduled for early February 2013 and an initial response expected shortly thereafter. An additional five schemes have been applied for and after approval are scheduled to be phased in throughout the second and third quarters of 2013. The locations of the seven waterflood schemes are dispersed throughout the Red Earth area, encompassing the Evi, Otter, Loon and Red Earth fields. All of the proposed waterflood schemes will utilize existing wells. The expected budgeted capital for the seven operated waterflood projects is approximately $7 million.

Northwestern Alberta

Montney oil play drives RMP RMP Energy Inc. reported record fourth-quarter production as a result of drilling success at Ante Creek, Waskahigan, Grizzly and South Ante Creek, the company reported in January. As a result of RMP’s successful exploration and development drilling program, it delivered record quarterly production for the fourth quarter of 2012 of approximately 6,500 barrels of oil equivalent per day. The company’s core focus is in the Montney oil play, where it has three core areas. To-date, RMP has three 100 per cent working interest lightoil wells drilled at Ante Creek. Production in the area has been restricted to one well as a result of current battery capacity and natural gas–processing constraints. The initial production performance from RMP’s first two Montney horizontal oil wells (4-35-6624W5 and 13-26-66-24W5) has been very significant. In November 2012, the 4-35 well was deliberately shut-in to accommodate the 13-26 well start-up. At that time, the well was producing, without artificial lift, approximately 1,200 barrels per day of light gravity crude oil (37 degree API) and 0.9 million cubic feet per day of associated natural gas. After 87 producing days, the 4-35 well produced 90,000 barrels of light oil and approximately 66 million cubic feet of associated solution gas. Production thus far from RMP’s Ante Creek 13-26 well has demonstrated a very strong production profile. The 13-26 well was brought on stream on Nov. 14, 2012, and in January was flowing, without artificial lift, approximately 1,300 barrels per day of light oil (37 degree API) and 1.1 million cubic feet per day of associated natural gas. After 55 producing days, the 13-26 well has produced an estimated 90,000 barrels of oil and approximately 60 million cubic feet of natural gas. Both of these wells have not demonstrated any material production decline since being on stream and the company has already recovered its drilling and completion capital investment through significant field cash-flow generation from each of these wells. RMP’s third Ante Creek well (1-36-66-24W5) is presently shutin, awaiting the Ante Creek oil battery expansion. The 1-36 well was flow-tested in November 2012 and over the first 40-hour flow back, the well recovered all of the fluid used to fracture the well. During the fi nal 24 hours of a 69-hour new oil production test, it produced approximately 2,421 barrels per day of 37 degree API crude oil and 3.16 million cubic feet of associated solution gas. At Ante Creek, the company holds a 100 per cent working interest in a six-section, contiguous acreage block, on which RMP has identified an additional 21 high-impact, light-oil, horizontaldrilling locations. At Waskahigan, RMP successfully drilled and completed 11 horizontal Montney oil wells in 2012. Initial production of these wells, on average, is tracking the company’s internal expectations, with an estimated ultimate recovery for each well of 160,000 barrels of oil. The 30-day initial production average for nine of the wells drilled in 2012 is approximately 450 barrels per day of light oil. The last two Waskahigan wells drilled in 2012 were recently tied in and brought on stream, and have not yet achieved 30 days of production history.

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25

N.E.

NORTHEASTERN ALBERTA WELL ACTIVITY JAN/12

JAN/13

Wells licensed





JAN/12

JAN/13

Wells spudded





JAN/12

JAN/13





Rigs released

Source: Daily Oil Bulletin

Northeastern Alberta

Cenovus expects big things from new projects By Lynda Harrison

Photo: Joey Podlubny

Cenovus Energy Inc. expects Telephone Lake’s reservoir will be at least as good as its producing Foster Creek and Christina Lake projects in terms of continuity, porosity, permeability and pay thickness, a conference has heard. “Those are all very, very comparable for it,” Brian Ferguson, president and chief executive officer, told the CIBC institutional investor conference. The project will also be at least as large as its predecessors, at more than 300,000 barrels per day, said Ferguson. Telephone Lake is further north in the Fort McMurray area, so there will be a somewhat higher pipeline tariff to get production to market, he noted. Infrastructure also will have to be constructed, but Ferguson believes it will be another cornerstone project. “The thing to me that is really important about Telephone Lake and Grand Rapids is the scope and the scale of those projects. Truly world-class,” he said. Telephone Lake is expected to be built over 72 months in two phases starting

with Phase A in 2014, with an estimated operational life of around 40 years. Timing depends on regulatory approvals, projected for receipt in fourth-quarter 2013, as well as on market conditions and corporate sanction. First steam at Phase A is proposed to start in 2018. Field construction of Phase B is forecasted to begin in 2016, with first steam in 2019. The company’s proposed Grand Rapids oilsands project will have a higher steam to oil ratio (SOR) than its existing projects; however, the project will have commercial advantages such as existing infrastructure, and the SOR will still be lower than the industry average, he said. “It is in the exact vicinity—in fact, it’s a little shallower—above our existing Greater Pelican production from the Wabasca,” he added, noting roads, camps, power and pipelines are already in place. Cenov us’s 100 per cent ow ned, 180,000-barrel-per-day Grand Rapids project in the Greater Pelican Lake area will have a different type of reservoir than the company’s other steam assisted gravity drainage

A worker at Cenovus’s Foster Creek development. The company expects Telephone Lake will perform as well as Foster Creek.

(SAGD) projects (Foster Creek, Christina Lake and Narrows Lake), which are old riverbeds stacked on top of one another. Grand Rapids’ reservoir, on the other hand, is an old shoreline, so it is much more homogeneous, but it is also only 20 metres thick compared to the other projects’ 30- or 40-metre-thick reservoirs, he said. Both Grand Rapids and Telephone Lake are in regulators’ hands, and Cenovus expects approval before the end of the first quarter of 2014. Both have a high-quality reservoir, he said. On an industr y-w ide basis,

300,000

barrels per day Expected production at Telephone Lake

Telephone Lake has a top-decile reservoir while Grand Rapids has a top-quartile one, Ferguson noted. Of its $3.6-billion total capital budget for 2013, Cenovus plans to spend $300 million on the two projects this year. Last year, the company drilled 75 stratigraphic (exploration) wells at Grand Rapids, but it doesn’t plan to drill any this year. It drilled 29 strat wells at Telephone Lake last year and anticipates 28 of them in 2013. Ferguson told the conference Cenovus now has nine phases of SAGD production on stream and has regulatory approval for nine more. Among this year’s highlights will be the start-up of its 10th phase, Christina Lake Phase E and initiation of construction of Narrows Lake Phase A—Cenovus’s third thermal oilsands project, he said. The Narrows Lake project is expected to begin producing in 2016 and Grand Rapids in 2017. OIL & GAS INQUIRER • MARCH 2013

27

Northeastern Alberta

Pengrowth speeds up Lindbergh project

Drilling oilsands core holes. Pengrowth is a year ahead of schedule at Lindbergh.

barrels of bitumen per day for Pengrowth.” The 2013 capital program also includes $470 million for development activities targeting light oil and liquids-rich natural gas production, mainly in the Greater Olds/ Garrington area, Swan Hills and southeastern Saskatchewan. In 2013, Pengrowth will

“ We believe the resource base at Lindbergh will ultimately support production of 50,000 barrels of bitumen per day.” — Derek Evans, president and chief executive offi cer, Pengrowth Energy Corporation

participate in drilling 82 net wells over and above any Lindbergh drilling. An additional $300 million will be spent at Lindbergh in 2013 as Pengrowth positions itself for growth in thermal oil production in 2014 and beyond.

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Pengrowth Energy Corporation has sanctioned Phase 1 of its Lindbergh thermal bitumen project and approved its 2013 capital budget and production guidance. The Phase 1 Lindbergh project is expected to produce 12,500 barrels of bitumen per day when fully operational in mid-2015, which is approximately one year ahead of prior estimates. Capital expenditures for Phase 1 are targeted at $590 million, of which $300 million is budgeted in 2013. This includes an additional $150 million compared to earlier guidance to accelerate the ramp-up and expand the oil-handling capacity of the plant, based on the excellent performance of the Lindbergh pilot operations. “We are excited to proceed with the first phase of Lindbergh, a highly economic, lowdecline project that, once at full capacity, will provide the backbone for a long-term, dividend-paying model,” said Derek Evans, president and chief executive officer. “We believe the resource base at Lindbergh will ultimately support production of 50,000

Northeastern Alberta

Paramount subsidiary Cavalier Energy provides update on Hoole Project Paramount Resources Ltd. reported in January that its wholly owned subsidiary Cavalier Energy Inc. has received an updated independent evaluation of the Grand Rapids formation in its 100 per cent owned in situ oilsands leases in the Hoole area of northeastern Alberta. The evaluation ascribed 93 million barrels of probable reserves with a net present value (discounted at 10 per cent) of $379 million to Cavalier’s initial 10,000barrel-per-day in situ steam assisted gravity drainage oilsands development, covering approximately two sections of the Hoole Lands. Over and above the aforementioned reserves, the evaluation ascribed 719 million barrels of economic contingent resources (best estimate) with a net present value (discounted at 10 per cent) of $1.949 billion to the remaining approximate 54 sections of Cavalier’s Hoole Lands. “The new estimates further emphasize that the Hoole Lands are a significant asset

719

million barrels

Economic contingent resources at Cavalier’s Hoole project

and the recognition of reserves is an important milestone for Cavalier,” stated William Roach, president and chief executive officer of Cavalier. The updated estimates and reclassification of Hoole project volumes from economic contingent resources to probable reserves follows Cavalier’s November 2012 regulatory applications to the Energy Resources Conservation Board and Alberta Environment and Sustainable Resource Development. Subject to receipt of regulatory approvals, the Hoole project schedule currently anticipates first steam in 2015 and the fi rst full year of production in 2016. It is expected that the Hoole Lands could support a project of over 80,000 barrels per day by 2022. “This is another positive step forward for Paramount and the Cavalier team,” said Jim Riddell, president and chief operating officer of Paramount.

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29

Northeastern Alberta

Southern Pacific McKay project builds momentum as oil being shipped by rail south Southern Pacific Resource Corp. reported the wellbores for even temperature conincreasing production from its STP-McKay formance and to allow adequate time for Thermal Project in Alberta in January, the development and growth of the steam along with the arrival of the first shipment assisted gravity drainage (SAGD) chamof diluted bitumen from STP-McKay into bers within the oilsands reservoir. The 12 Mississippi. SAGD well pairs that were initially drilled Bitumen production at the STP-McKay are equipped with comprehensive subsurface measurement of temperature and Thermal Project, located 45 kilometres northwest of Fort McMurray, continues to ramp up. Steady rail shipments of dilbit from STP-McKay have In December 2012, the estimated average bitunow commenced and are being shipped to Natchez. men production rate was 1,200 barrels per day, up 22 per cent from the previous month’s pressure, and have multiple steam delivery average rate. As the company has previously and production recovery points within each stated, it is expected to take 12–18 months well. Southern Pacific is being conservative from first oil production, which occurred in in the initial stages of converting the well mid-October 2012, for total rates to approach pairs from circulation to SAGD, utilizing the the 12,000-barrel-per-day design capacity. downhole technology that was installed to ensure even temperature conformance and The ramp-up period is required to condition

25 Years!

chamber development have occurred along the horizontal length of the wells before the wells are converted to steady-state SAGD. This approach is designed to ensure the longterm integrity of the wellbores and to assist in maximizing the total recovery of bitumen from each well pair over its producing life. To date, seven of the 12 well pairs have been fully converted. The remaining five well pairs are at various stages of circulation and will be converted to full SAGD operation when Southern Pacific’s technical staff deem appropriate. Although the process of circulation and conversion takes time, steady progress is occurring and once the conversion to SAGD operation has been completed, the well pairs will be operating predictably. The surface facilities at McKay continue to perform well despite having been exposed to extended periods of bitterly low temperatures. All systems within the

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Northeastern Alberta

It is expected to take up to 18 months to bring production up to the plant’s 12,000-barrel-perday capacity.

facilities continue to run well and there has been no significant downtime since the plant was commissioned this past summer. Southern Pacific has also commenced an exploration core hole program on its McKay lands. The program will focus on delineating lands to the north of its current project. The program is designed to drill 10–13 core holes and is expected to be completed by the middle of March. Depending upon results, the program could add incremental reserves to justify a further expansion or be integrated into the existing expansions, which include the STP-McKay Phase 1 expansion, which has a design capacity of 6,000 barrels per day, and STP-McKay Phase 2, which has a design capacity of 18,000 barrels per day. These existing expansions are in the application process, with approval anticipated towards the end of 2013. On Dec. 22, 2012, the first shipment of Southern Pacific’s diluted bitumen left the Lynton rail terminal, located just south of Fort McMurray, and landed in Mississippi on Jan. 6, 2013. This first shipment and future shipments will be offloaded at the Genesis

Natchez terminal, where Southern Pacific has exclusive terminal capacity. Steady rail shipments of dilbit from STP-McKay have now commenced and are being shipped to Natchez. Southern Pacific plans to build inventory in Natchez for most of January 2013, with sales expected to commence towards the end of the month. The company has several markets prepared for purchasing its product and expects to receive pricing competitive with other U.S. Gulf Coast heavy oil imports. As a result, Southern Pacific expects to receive a significantly improved netback for its bitumen sales as compared to a sale into local markets based on Western Canadian Select pricing. Southern Pacific has also completed a purchase arrangement to supply its diluent requirements. The diluent will be sourced from the U.S. Gulf Coast and shipped via rail, using Southern Pacific’s returning rail cars, to the Lynton terminal, where it will be transported by truck to the STP-McKay plant site to be used in the bitumen/water separation process. The company expects to realize substantial savings from this source of diluent.

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CENTRAL ALBERTA WELL ACTIVITY JAN/12

JAN/13

Wells licensed





JAN/12

JAN/13

Wells spudded





JAN/12

JAN/13





Rigs released

Source: Daily Oil Bulletin

C.A.B. Central Alberta

Duvernay drilling expected to increase in 2013 By Richard Macedo

Photo: Aaron Parker

The Duvernay should be busier in terms of drilling activity in 2013, with possibly double the number of wells drilled and completed compared to 2012, an energy service and infrastructure conference heard recently. Tom Medvedic, senior vice-president, corporate development, with Calfrac Well

Around 40 to 50 wells were drilled into the Duvernay in 2012.

Services Ltd., told the AltaCorp Capital/ATB Corporate Financial Services conference that last year there were roughly 40 or 50 wells drilled and completed. “O u r e x p ec t at ion for t h i s yea r, based on the incremental capital we’re expecting, certainly from the Encana Corporation JV [joint venture] and some of the larger players making more signifi cant investments in the Duvernay, is that number probably escalates to somewhere between 100 and 120 in 2013,” he noted during a panel session on hydraulic fracturing. “From a service-intensity perspective, the Duvernay would represent—probably second only to the Horn River—the most service-intensive basin that we would operate in. “From a well-profile perspective, clearly further activity is going to have a significant impact on the supply/demand balance or equilibrium in Canada,” Medvedic added. “I think we’re in a reasonably good position to service those 100–120 wells this year. “As far as moving the needle in Canada and being a significant draw on horsepower, we’d probably need to see that well count begin to broach that 200- and 250well range, which I think is quite attainable here in the next year or two; then there would be a significant impact on the requirements for western Canada.” Medvedic said 30 0,0 0 0 –50 0,0 0 0 horsepower would be needed to service the Duvernay in full development mode. “I think the next stage of development, quite frankly, with the Duvernay as we broach into that higher well count is going to be predicated on pad development,” he said. “Clearly, we need to try to get the

well costs down as an industry to sustain this development moving forward.” Well costs have been, on average, $12 million to $14 million. “Through pad development, and the economies of scale or efficiencies that come through that, not only will that significantly increase the overall number of wells being drilled and completed, but clearly the efficiencies and 24-hour operations are going to be key drivers in making this play more economic in the future,” Medvedic said. “That’s when we’ll see that step-change as far as the horsepower requirements are concerned.” After spending billions of dollars on land acquisitions in the Duvernay shale play in Alberta between 2009 and 2012, the industry is now in the early stages of determining the size of the prize. “The Duvernay fracs that we’ve been on lately are using about 40,000–50,000 horsepower on most fracs,” said Brad Fedora, president and chief executive officer of Canyon Services Group Inc. “They are done at very high pressure. “You do have long pumping durations, so it is quite diffi cult on the equipment,” he added. “For every 100 wells drilled in a year, you would keep 200,000 horsepower busy; that can change with 24-hour crews and things like that. “At those pumping rates and pressures, if you left a spread parked in the Duvernay, you would probably cut its life in half.” Michael Baldw in, v ice-president, finance, and chief financial officer with Trican Well Service Ltd., agreed that 100– 120 wells for 2013 in the Duvernay is a fair estimate. “I would say that, if there’s an area in Canada where we see a positive bias upwards, that would probably be it,” he said. “You can see guys doing a few things in the fi rst half of the year that indicates they can move a little bit more to the development side of things.” OIL & GAS INQUIRER • MARCH 2013

33

Central Alberta

Crocotta Energy looks to Edson in 2013 Crocotta Energy Inc. has grown organically from 2,200 barrels of oil equivalent per day in 2010 to over 8,500 barrels of oil equivalent per day exiting 2012 solely by drilling its current Bluesky and Cardium projects at Edson and its Montney project at Dawson. Expect that model to continue in 2013. Crocotta has approved a budget that entails spending approximately $100 million in 2013 with the focus on Cardium oil at Edson, liquids-rich Bluesky gas at Edson and liquids-rich Montney gas at Dawson. The budget will be spent equally between the first and second half of the year.

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MARCH 2013 • OIL & GAS INQUIRER

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Crocotta estimates average 2013 production to be between 9,200 and 9,500 barrels of oil equivalent per day (35 per cent oil and natural gas liquids, and 65 per cent natural gas), with exit-2013 production reaching 10,500 barrels per day. Edson will receive approximately 60 per cent of the overall budget with almost half of the entire year’s budget to be spent on horizontal development of Cardium oil. Crocotta has budgeted to drill 14 net horizontal Cardium oil wells and 2.2 net liquids-rich Bluesky gas wells. Liquids-rich Montney will receive approximately 30 per cent of the budget with its new sweet-gas plant constructed in the first half of the year and four net horizontal wells scheduled to be drilled in the second half of the year. New projects and land will receive the balance of the allocated capital. Crocotta currently has two drilling rigs in operation at Edson, with one drilling Cardium horizontals and one drilling Bluesky horizontals. Crocotta is currently completing one (0.6 net) previously drilled Bluesky well and two (2.0 net) Cardium wells at Edson.

Central Alberta

Angle Energy Inc. drilled and rig released 10 gross (8.3 net) horizontal wells in the fourth quarter of 2012, with six gross (4.3 net) wells targeting Cardium light oil, with a 100 per cent success rate. Currently, Angle has three gross (2.5 net) horizontal wells in completion operations or awaiting completion. A ngle’s 2013 capital expendit ure program focuses on the highest rate of ret ur n projec ts in t he compa ny ’s de velopment portfolio, with emphasis on light oil growth in its Cardium plays. The full-year budget includes $145 million to $160 million in total capital, of which $125 million to $140 million is allocated to drill 43– 47 gross (34 –38 net) wells and related completion, equipping and tie-in activities. Faci lit y capita l of $10 m i l lion is expected to construct the central oil battery, initially sized to process 4,000 barrels of light oil, and related emulsion gathering lines at Harmattan. Drilling, completion, equipping and tie-in capital is expected to be allocated approximately 75–80 per cent to the Cardium light oil projects in Harmattan, Ferrier a nd E dson, a nd 20 –25 p er cent to Mannville liquids-rich gas and light oil in Harmattan and Ferrier. Capital may be allocated towards the Duvernay shale or other high-value projects and is not primarily included in the development budget. Angle expects to drill 17 net wells into the Cardium at a cost of $75 million to $85 million. Expected production volumes resulting from the year’s capital program will be in the range of 11,300–11,700 barrels of oil equivalent per day, with December month-average volumes estimated at 12,000–13,000 barrels of oil equivalent. During the year, the production mixture is expected to average approximately 45 per cent natural gas, 25 per cent natural gas liquids, and 30 per cent light oil and condensate.

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MARCH 2013 • OIL & GAS INQUIRER

Marquee Energy finds growth at Michichi, Lloydminster Marquee Energy Ltd. is growing by the drill bit at its two key oil projects at Michichi and Lloydminster. Following Marquee’s fourth-quarter disposition of its gas-weighted Willesden Green property, Marquee is currently producing greater than 2,300 barrels of oil equivalent per day (62 per cent oil and liquids). Combined production from the Michichi and Lloydminster core areas now represents almost 70 per cent of corporate production. At Michichi, in south-central Alberta, Marquee is the most active driller in this emerging light oil play, having drilled 10 of more than 30 horizontal wells licensed in the Michichi area since July 2011. To-date, Marquee has realized a 100 per cent success rate on the 10 horizontal light oil wells drilled into the Banff and Detrital formations. Eight of these wells are currently on production while the remaining two wells are awaiting completion operations. The first horizontal well of Marquee’s threewell, fourth-quarter program averaged more than 200 barrels of oil equivalent per day over an initial five-day test period and achieved 141 barrels per day, with oil and liquids weighting close to 90 per cent. Marquee continues to optimize drilling and completion techniques, including moving to multi-well drilling pads, in order to improve capital-cost performance. The company has recently tested a new frac design with promising results, and expects the method can increase productivity from new drills compared to conventional multistage fracs as well as reduce completion costs by as much as 40 per cent. Marquee continues to expand its land position and seismic database in the area. Through acquisitions and land sales, Marquee now owns more than 118 net sections of operated Crown lands in the area. Marquee also expanded its seismic database at Michichi to 1,281 line kilometres of 2-D seismic and 104 km2 of 3-D seismic. Analysis of this seismic data in conjunction

Central Alberta

with ongoing detailed geologic evaluations, including extensive review of regional core data, is contributing to the expansion and derisking of the company’s prospect inventory. At Lloydminster, Marquee successfully drilled 10 vertical heavy oil wells in 2012, five of which were drilled and put on production during the fourth quarter. These wells were drilled, completed, equipped with production facilities and placed on production within three weeks of rig release for under $600,000 per well.

PetroBakken high on Cardium PetroBakken Energy Ltd. reported 21,500 barrels of oil equivalent per day coming out of the Cardium at year-end 2012, with big plans to up production in 2013. T he company expects to spend $290 million in the play in 2013, drilling 67 wells. “From a capital-allocation standpoint, we will focus on continuing to grow our production in the Cardium, which, like our Bakken and conventional business units, should become cash-f low positive in 2013,” said company president and chief executive officer John Wright. “The Cardium de velopment program will focus on pad-drilling in Brazeau, Lochend and West Pembina, to shorten on-stream cycle times and reduce capital costs for surface leases, drilling, completions, equipping and tie-ins.” Overall, PetroBakken plans on spending $480 million drilling and completing around 130 wells in 2013. “We will also continue to invest in our cash-flow positive assets in the Bakken a nd sout heast Sask atc hewa n,” sa id Wright. “The Bakken program balances facilities and infrastructure spending with cluster development drilling to maintain strong capital efficiencies and a low operating cost structure. We have also allotted capital for the commercial expansion of our EOR [enhanced oil recovery] pilots to build upon the encouraging results to date. Finally, we will invest in developing our new plays in Alberta that will drive future growth.”

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SOUTHERN ALBERTA WELL ACTIVITY JAN/12

JAN/13

Wells licensed





JAN/12

JAN/13

Wells spudded





JAN/12

JAN/13





Rigs released

Source: Daily Oil Bulletin

S.A.B. Southern Alberta

Gas prices and production should increase over next five years, says BENTEK By Carter Haydu

Photo: Joey Podlubny

While there will be a bit of a slowdown due to weak market prices, drilling efficiencies and associated production as a result of oil and natural gas liquids (NGL) development will sustain North American natural gas production growth into the foreseeable future, says Rick Margolin, west region manager with BENTEK Energy, LLC. “By and large, at BENTEK, we are suspecting these factors are going to combine to keep gas production within the next four- to fi ve-year window at a very substantial pace,” Margolin told the audience at CI Energy Group’s ninth annual Shale Oil & Gas Symposium. For the United States and Canada, Margolin expects production to increase from a current level of about 69 billion cubic feet per day to about 79 billion cubic feet per day in 2017.

In order for producers to specifically seek out and drill for natural gas, Margolin said, producers require a rate of return of about 10–15 per cent. This, he told the audience, necessitates gas prices at about US$4 per thousand cubic feet, and he expects prices will reach that threshold by 2015. However, Margolin said the current number of North American rigs working in shale gas plays is dropping, although total rig counts are actually increasing: “Between January 2010 and today, we’ve got nearly 500 more rigs operating. But they’re not going after gas; they’re going after other commodities.” Despite many rigs switching to drilling oil wells, though, Margolin said gas production is still growing. He attributes this phenomenon to two factors: “One of them is efficiencies in drilling, and I’m sure you’ve all heard the stories of how producers are able to drill deeper wells and go longer with their laterals and get higher

A drilling rig south of Lethbridge, Alta. BENTEK is predicting gas production will increase as improved productivity lowers costs.

initial production rates, and doing all this in a shorter amount of time and all at basically no incremental cost. That is a very big factor in driving the upwards trend for production. “The other big factor, and considerably more influential, is the fact that even if you’re a producer and you’re going after crude or [NGLs], you’re still going to get gas.” Margolin said such associated gas production is a predominant factor in growth within the gas market, and BENTEK estimates three-fifths of the gas currently under production in North America is the result of oil and NGL drilling.

79billion cubic feet per day

Expected North American production by 2017

“So if you make the assumption, which we do, that oil and NGL production will continue to grow in the future, that is going to be a very big driver of gas production.” According to Margolin, another factor that will drive up production of gas in the years ahead is actually due to the oversupply of gas and resulting low cost for it. With a low price, he said, comes a demand for gas in various applications (e.g., power generation, transportation). Over the next 12 months, BENTEK does not expect North American gas prices will rise up past $3.50 per thousand cubic feet even at peak use, and Margolin said another mild winter will only result in increased supply in the market. “But when you get that, that’s what gives those power producers the incentive to go ahead and burn a lot of gas instead of a lot of coal...and that uptake in demand should begin to lift gas prices a little bit.” Within western Canada specifically, Margolin said a big factor driving increased natural gas demand is its use in oilsands OIL & GAS INQUIRER • MARCH 2013

39

Southern Alberta

production. Although, he noted, the current discount to which Alberta crude must sell to international oil rates is impacting the rate of bitumen production growth in the province. Still, he said, BENTEK expects an increase in demand from that sector. “I believe the oilsands consumes about 1.5 billion cubic feet per day of gas right now, and we’re forecasting that to jump to 2.1 billion cubic feet per day by 2017,” he said, adding Alberta and Saskatchewan are also factors in driving gas demand into the foreseeable future, at least in Canada, because those provinces are ripe to switch from coal burning to gas burning for energy needs. With the global recession coming to an end, according to Margolin, industrial demand for natural gas will likely improve as well, as will residential demand, assuming North American winters return to more normal, colder conditions next year. However, he noted, the increase in energy efficiencies in modern homes limits the extent to which residential gas demands can increase. Another source of increased gas demand is Mexico, for as its economy continues to

grow, Margolin said, much of Texas’s natural gas will likely head to support Mexican industry. This will result in California requiring more gas from other sources, which Margolin said could impact, specifically, the demand for gas from Canada. However, the BENTEK west region manager does not foresee natural gas demand increasing throughout every geographical region of the continent. In eastern Canada, for example, even though coal-fired power generation is on the way out, natural gas simply will not be able to compete with nuclear or renewable sources. Margolin said it is unlikely natural gas prices will increase to $5 per thousand cubic feet—which would make the commodity far more enticing for producers— for at least the next few years, until greater capacity for liquefied natural gas exports comes online in North America. “We expect those basis prices to flatten; we expect gas prices to remain relatively low and relatively non-volatile, at least until something structurally changes in the market.”

Encana commissions first liquefied natural gas facility in Alberta Encana Corporation recently announced the commissioning of its Cavalier liquefied natural gas (LNG) facility located approximately 15 kilometres east of the town of Strathmore, Alta. The Cavalier LNG facility will play a key role in providing an alternative fuel to diesel for heavy-duty transportation, including rail and long-haul trucking. It demonstrates Encana’s commitment to lead by example and build the necessary infrastructure to support a transportation future driven by natural gas. “The Cavalier LNG facility represents a milestone, as it will be the first ever in Alberta to offer LNG, a more affordable and cleaner fuel option for the transportation industry,” said Eric Marsh, executive vice-president, Encana

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MARCH 2013 • OIL & GAS INQUIRER

Southern Alberta

Corporation, and senior vice-president, U.S.A. division. “This project further demonstrates how Encana has progressed from the concept of a natural gas–based energy portfolio to a business model of safely and efficiently providing the fuel to new markets. There is a very strong value proposition for natural gas use in the transportation sector, given that the fuel is 20–40 per cent less expensive than gasoline or diesel in many regions. In addition to helping realize significant savings on fuelling costs, the environmental benefits of using natural gas for transportation speak for themselves, with up to 30 per cent less CO2 emissions than oil and 90 per cent less smogcausing particulate matter.” The Cavalier LNG facility receives its feedstock from Encana’s neighbouring Cavalier gas plant. The natural gas is then treated to remove impurities such as water, CO2 and mercaptan, and thereafter directed into a cryogenic heat exchanger where liquid nitrogen (-196°C) cools the methane to a liquid state (-160°C). The LNG is stored in cryogenic tanks on site for truck fuelling or bulk-tanker loading.

The first customers of the Cavalier LNG facility include Calgary-based Ferus Inc., an energy services company specializing in delivering integrated solutions to the energy industry, as well as the Canadian National Railway Company (CN), which last year announced that it is testing two mainline diesel-electric locomotives fuelled principally by natural gas. Encana is providing complete LNG fuelling solutions to CN for this pilot project, including the fuel, transportation and equipment. The CN project is the fi rst of its kind in Canada. The development of the Cavalier LNG facility allows Encana to continue to work closely with CN and other customers to deliver a more environmentally friendly, reliable and cost-effective fuel for their transportation needs. “Natural gas is a viable transportation fuel for the rail sector, and CN’s pilot project demonstrates the transportation industry’s growing awareness of the economic and environmental benefits of natural gas,” said David Hill, Encana’s vice-president, operations, natural gas economy. “There is significant growth

potential for natural gas in the transportation sector when you consider the sheer abundance of this resource that has been unlocked in North America through huge technological advances in unconventional production. Combining the on-road trucking with the rail and oil and gas supply-chain segments represents around 30 per cent, or 22 billion cubic feet per day, of total North American transportation fuel consumption.” As part of Encana’s ongoing efforts to commercially develop natural gas for transportation, the company owns and operates an LNG fuelling station in Louisiana, 10 mobile LNG fuelling stations and seven compressed natural gas stations. In addition, the company is committed to converting its entire fleet of more than 1,300 trucks and passenger vehicles to natural gas. In 2011 alone, the company saved approximately $11 million in fuel costs by using natural gas instead of diesel in company trucks, and has converted close to 40 per cent of its drilling rigs. In December 2012, Encana announced plans to build a 190,000-litre-per-day LNG production facility near Grande Prairie, Alta.

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SASKATCHEWAN WELL ACTIVITY JAN/12

JAN/13

Wells licensed





JAN/12

JAN/13

Wells spudded





JAN/12

JAN/13





Rigs released

Source: Daily Oil Bulletin

S.K. Saskatchewan

Renegade spending $80 million in 2013

Photo: Pipeline News

Renegade Petroleum Ltd. said its board of directors has approved a 2013 capital development budget of $79.6 million. The company’s 2012 budget was first set at $76 million, but eventually was increased to $130 million. Of the $79.6-million 2013 budget, $51.4 million is earmarked for southeastern Saskatchewan and $28.2 for west-central Saskatchewan. The capital program and the expected dividend payment of $46.7 million are forecasted to be funded through the company’s funds flow from operations with an all-in annual payout ratio estimated at 98.4 per cent. Renegade said its successful 2012 drilling program and recent acquisition in southeastern Saskatchewan enabled it to achieve record exit production of about 8,000 barrels of oil equivalent per day. The company believes its assets are ideally suited for an “income plus growth” model for several reasons: its output is 95

per cent light oil with operating netbacks of $50 a barrel; it has a 25 per cent corporate decline rate; 65 per cent of its 2013 production is hedged at C$93.67 for West Texas Intermediate (WTI); 3,000 barrels per day of 2014 output is hedged at C$91.28 WTI; it has a 36 per cent dividend payout ratio (a 98.4 per cent all-in payout ratio); and it has more than 900 light-oil development drilling locations. In the fourth quarter, Renegade began its transition to a dividend-paying corporation, focusing on areas that provide predictable results and strong capital efficiencies. As such, its drilling program concentrated on its core assets in southeastern Saskatchewan and its Viking assets in west-central Saskatchewan. In southeastern Saskatchewan, Renegade drilled six (five net) wells in the fourth quarter, bringing the year-to-date total to 32 (23.8 net) wells. Renegade continued to focus on both the Frobisher and Souris Valley trends, with further drilling plans continuing into 2013.

Drilling in southeastern Saskatchewan. Renegade is spending $51.4 million in the area in 2013.

During the fourth quarter, Renegade drilled and completed two (two net) wells in the Wordsworth and Queensdale areas, targeting the Frobisher formation. In the Wordsworth area, one (one net) horizontal well was drilled, yielding a 30-day initial oil production average of 180 barrels per day. This well offsets the strong results noted in the third quarter. Renegade drilled one (one net) horizontal well in the Queensdale east area that showed promising results during drilling and will be evaluated further in the first quarter of 2013.

8,000

barrels per day

Renegade’s 2012 exit production Renegade drilled one (0.5 net) well in the Crystal Hills area of southeastern Saskatchewan in the fourth quarter, which yielded a 30-day initial unoptimized oil production rate of 200 barrels per day. Renegade has additional plans to continue drilling in this area throughout 2013. In the third quarter, Renegade drilled three (2.5 net) wells in the Redvers/Mair area of southeastern Saskatchewan. The most recent two (1.5 net) wells had an average 30-day initial oil production rate of over 85 barrels per day. In west-central Saskatchewan, Renegade is a strong producer in the Viking play. The company boasts all-in costs of $950,000 per well. Renegade drilled six (six net) wells in west-central Saskatchewan in the fourth quarter. The company has now drilled and brought onto production 14 (14 net) wells based on 40-acre spacing. The production results continue to show a strong correlation to the offset 80-acre spacing well type curves. — DAILY OIL BULLETIN OIL & GAS INQUIRER • MARCH 2013

43

Saskatchewan

Novus extends Dodsland Viking play Novus Energy Inc. has met its corporate exit rate production target of 4,200 barrels per day for 2012. The company reported an estimated average of 4,234 barrels of oil equivalent per day of field-level production during the last week of December, with approximately 78 per cent of volumes comprised of oil and liquids. Based on field estimates, average December production reached 3,925 barrels per day, with average daily volumes of 3,530 barrels per day throughout the entire fourth quarter. Throughout the last three months of 2012, Novus drilled 24 Viking horizontal oil wells in the Greater Dodsland area. Throughout the entire year, Novus drilled a total of 72 Viking horizontal oil wells—completing 68—also all in the Greater Dodsland area. During the last quarter, Novus drilled, completed and placed on production three key successful wells west of its Flaxcombe field. The company believes these wells could validate a substantial amount of its land.

The westernmost well drilled in this extension is situated over 19 kilometres from the Flaxcombe field. So far in 2013, Novus has drilled and cased three additional wells in the region, expecting to bring them on

Novus has 210 net sections of Viking rights in Saskatchewan’s Greater Dodsland area and Alberta’s Greater Provost area.

production before March 31. Novus controls about 14.5 sections of land in the region. Assuming continued development success, the company believes this land block may materially add to its drilling inventory,

which includes 210 net sections of Viking rights in Saskatchewan’s Greater Dodsland area and Alberta’s Greater Provost area. Due to the high quality of its asset base and significant industry interest in recent activities, Novus announced in December that it had retained Cormark Securities Inc., as lead, and FirstEnergy Capital Corp. as its fi nancial advisors to assist the board of directors’ special committee in exploring and evaluating a broad range of options to optimize shareholder value. The data room is now available for interested and qualified parties who have entered into a confidentiality agreement with Novus. The company has not established a defi nitive schedule to complete its review and consideration of shareholdervalue optimization options, and does not intend to disclose process developments unless and until the board of directors has approved a specific transaction or otherwise determines disclosure is appropriate. — DAILY OIL BULLETIN

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MARCH 2013 • OIL & GAS INQUIRER

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Reserves up at Raging River Exceptional organic reserves growth in addition to several accretive acquisitions throughout the year contributed to strong reserves growth in 2012, says Raging River Exploration Inc. Proved-plus-probable reserves grew by 215 per cent to 17.16 million barrels of oil equivalent (95 per cent oil) and proven reserves grew by 201 per cent to 11.54 million barrels (95 per cent oil). Proven reserves represent 67 per cent of provedplus-probable reserves as at Dec. 31, 2012. Finding, development and acquisition (FD&A) costs, including a $167-million change in future development capital, are $26.05 per barrel on a proved-plus-probable basis. FD&A costs, including a $130-million change in future development capital, are $33.81 per barrel on a total proven basis. Reserve additions replaced 2012 production by greater than 12 times on a proven basis and 17 times on a proved-plus-probable basis. Proved-plus-probable reserve additions of 12.38 million barrels included

Raging River’s development drilling inventory has increased to more than 1,300 risked locations. 2.5 million barrels of proved acquisitions and 5.96 million barrels of proved additions/revisions. The reserve-life index is 12 years, based on the December 2012 exit production rate of 4,000 barrels per day. Raging River’s development drilling inventory has increased to more than 1,300 risked locations as at Jan. 1, 2013, of which more than 1,000 are currently unbooked. Based on field estimates, fourth-quarter 2012 average production was 3,100 barrels per day (96 per cent oil). Exit production was more than 4,000 barrels per day, which exceeded previous exit guidance of 3,700 barrels per day by eight per cent.

Raging River is in the midst of an active first quarter, in which it anticipates drilling 30–32 net wells. It has three drilling rigs operating and drilled 20 (17.5 net) wells at 100 per cent success in January. Of those, 13 wells have been completed and placed on production. Despite winter operations that typically marginally increase costs, the average onstream costs in January have been approximately $910,000, equivalent to summer 2012 costs. Raging River said the Kindersley area of Saskatchewan is prone to early spring breakup and operations typically shut down on or before March 15. Plans call for all firstquarter operations to be completed by March 6 and it is on schedule to complete this, the company said. Due to significant snowfall this winter, there is an increased probability of a prolonged breakup, and the company said it has accounted for this in 2013 planning and has factored in no drilling activity between March 7 and June 1, 2013. — DAILY OIL BULLETIN

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Photo: Joey Podlubny

CO2 Solutions receives $4.7 million for carbon capture project

The carbon capture technology uses enzymes to lower capture costs.

CO 2 Solutions Inc., an innovator in the field of enzyme-enabled carbon capture technology, announced in January that the federal government has made a $4.7-million investment through the ecoENERGY Innovation Initiative to support the development of its carbon capture technology in the Alberta oilsands. CO2 Solutions is developing carbon capture technology for use in oilsands production, including in situ methods such as steam assisted gravity drainage (SAGD) and bitumen upgrading. Results from the project will also support the broader application of the company’s technology in other natural gas– combustion sources, such as gas-fired power plants. CO2 Solutions’ management anticipates the overall cost of the project to be $7.5 million. “This project will demonstrate our technology’s ability to cost-effectively address a critical environmental challenge facing the oilsands,” stated Glenn Kelly, president and chief executive officer of CO2 Solutions. “The results from this project will also enable us to apply our technology to other large sources of natural gas–combustion emissions, including the rapidly growing number of natural gas–fired power plants.” Unconventional oil production methods, such as SAGD used in the oilsands, have a somewhat higher carbon footprint than conventional oil production methods. Both industry and government are focused on ways to reduce emissions from the oilsands, with carbon capture being a key option. However, the cost of conventional carbon capture and sequestration systems is high for broad commercial deployment.

7.5 million

The total costs of the demonstration project

CO 2 Solutions’ technolog y lowers the cost barrier by taking advantage of a powerful naturally occurring enzyme, carbonic anhydrase, which regulates CO2 management in all living organisms. The technology can be retrofitted to existing carbon capture systems, as well as installed in new emission sources. Additional funds for this project are being obtained through grants from Alberta’s Climate Change and Emissions Management Corporation (CCEMC), previously announced on Oct. 31, 2012. The balance of the project’s costs will be funded by CO2 Solutions and partnership capital from private entities. CO2 Solutions has built an extensive patent portfolio covering the use of carbonic anhydrase, or analogues thereof, for the efficient post-combustion capture of CO2 with low-energy aqueous solvents. OIL & GAS INQUIRER • MARCH 2013

47

Te c h N e w s

New product provides environmentally progressive, efficient solution for gas-turbine power management ATCO Emissions Management (ATCO) recently announced the addition of heatrecovery steam generators (HRSGs) to its comprehensive line of gas-turbine auxiliary equipment for the power, oil and gas, and cogeneration markets. The new HRSG product, an energy-recovery heat exchanger that recovers heat from a hot-gas stream, will initially serve organizations with gas turbines up to 100 megawatts. “The introduction of HRSGs expands our already extensive offering for gas-fired power generators, adding to the previous success of our patent-pending selective catalytic reduction systems and our other gas-turbine products,” said Harry Wilmot, president and chief operating officer, ATCO Structures & Logistics. By implementing an HRSG system, environmentally progressive companies and those looking to create cost savings can produce heat or power from recovered waste

heat or renewable energy sources. Some companies have also used HRSGs as part of a long-term goal to meet carbon emission targets. The increasingly stringent emission regulations in the United States and Canada

“The adoption of the [heat recovery steam generators] will allow these institutions to be ‘greener’ and energy self-reliant.” — Harry Wong, senior vice-president and general manager, ATCO Emissions Management

are expected to add to the growing demand for HRSGs. “Currently, our HRSGs are designed for use in power plants at hospitals, universities, electricity generation facilities, and at remote oil and gas operations,” said Harry Wong, senior vice-president and general manager,

ATCO. “The adoption of HRSGs will allow these institutions to be ‘greener’ and energy self-reliant.” Integrating the new HRSGs with ATCO’s existing nitrogen oxide and noisereduction technologies will give ATCO the ability to offer the full scope of acoustic, air emissions and heat recovery solutions on gas-turbine projects. Each HRSG is custom-designed in Minneapolis, then fabricated in original equipment manufacturer–approved facilities across the globe. ATCO’s product portfolio for gas-turbine generators also includes combustion air filtration and intake silencing, anti-icing, acoustical enclosures, acoustical buildings, sound barriers, combustion-exhaust silencing systems, catalyst systems for nitrogen oxide and carbon monoxide removal, bypass systems with diverter dampers and exhaust diffusers.

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MARCH 2013 • OIL & GAS INQUIRER

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Field of Schemes Heavy oil producers find ways to keep the product flowing

Photo:Joey Podlubny, Peter Markiw

By Darrell Stonehouse

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MARCH 2013 • OIL & GAS INQUIRER

Cover Feature

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t’s been around 70 years since heavy oil began being produced in the Lloydminster area. Tens of thousands of wells have been drilled and well over a billion barrels have been produced. Yet the heavy oil belt along the border between Alberta and Saskatchewan remains a development hot spot after all these years. And the reason is primary recovery technology keeps improving, making heavy oil a profitable niche in the Canadian oilpatch. “Primary heavy oil provides the highest return of capital projects in our portfolio and generates significant free cash flow,” Canadian Natural Resources Limited president Steve Laut told investors and analysts at Canadian Natural’s 2013 Budget Day presentation in January. Canadian Natural is Canada’s largest primary heavy oil operator, producing around 125,000 barrels per day in 2012. The company has put major efforts into developing its huge heavy oil land holdings the last five years, working to turn its almost 250 million barrels of proven-and-probable reserves into producing assets. It drilled a record 900 cold wells in 2012, raising production by 21 per cent. Laut said he expects Canadian Natural to spend around $1.1 billion drilling around 890 wells and re-completing another 490 wells in 2013. “Our capital spend is the same as 2012, and will deliver an additional 12 per cent growth in production to just over 140,000 barrels a day. We expect that with our inventory, we will be able to grow

lying about an hour north of Pelican Lake, that could greatly add to its heavy oil production. The last available production statistics for the play show Woodenhouse averaged 9,300 barrels per day in October of 2012. Canadian Natural expected the play to exit 2012 at approximately 12,600 barrels per day. Its current plan is to drill around 250 wells on 45 pads at Woodenhouse. Further exploration may add to the play. Like Canadian Natural, Baytex Energy Corp. also uses its base of heavy oil production at Lloydminster to provide cash to grow operations into other plays. Baytex produces around 20,000 barrels per day in the Lloydminster area, and expects that rate to continue well into the future. “Lloydminster is the traditional bread and butter of Baytex,” company chief financial officer Derek Aylesworth recently told an investor conference. “It’s a kind of a cash cow for us. We don’t see that there [are] a lot of growth opportunities, but it’s an area that has the opportunity to stay flat, we think, for the foreseeable future.” Aylesworth described Lloydminster as a multi-stacked heavy oil reservoir with opportunities varying by geographical area. “When you look at technical development of the Lloyd area, Lloyd is a very desperate area. So in some areas we’ll develop with single verticals that intercept multiple pay zones. In some areas we use horizontal wells,” he explained.

“Primary heavy oil provides the highest return of capital projects in our portfolio.” — Steve Laut, president, Canadian Natural Resources Limited

production to roughly 150,000 barrels a day and then see production plateau due to the high-decline nature of primary heavy oil,” he predicted, adding the company will drill 120 horizontal wells in 2013.
Canadian Natural has identified 8,500 drilling locations to keep production stable. It is also testing a number of waterflood pilots on its heavy oil production base to stem declines. The company has a well-established heavy oil recovery plan in place. Vertical wells with progressive cavity pumps are the norm in the heavy oil belt. Canadian Natural continues drilling around 750 of these wells annually, to depths of 350–650 metres. It is using directional, or slant, drilling and multi-well pads, and completing one to three zones per well. Older existing vertical wells are being re-completed to access untapped horizons as production declines in older zones. Canadian Natural began its horizontal program in 2009, drilling two wells to test the technology in heavy oil applications. In 2012, it drilled 100 horizontals. The horizontal wells are being used for two purposes: to access reserves where the oil lies over water, and to access heavy oil in less permeable pools previously discovered but not producible using vertical wells. The company also has a number of enhanced heavy oil recovery schemes in the pilot phases. It has an ongoing waterflood at Salt Lake and pilots underway at Lone Rock, Golden Lake and Epping. It is also testing polymer flooding. Laut said ultimate recovery could double or triple if the enhanced recovery projects are successful. Canadian Natural is also in the process of proving up a new heavy oil play targeting the Wabiskaw formation at Woodenhouse,

Vertical wells are completed in multiple zones, making capital efficiencies very good, he noted. Finding and development costs have been around $12 per barrel. After years of decline, Husky Energy Inc. is enjoying a renaissance in the heavy oil fields surrounding Lloydminster. While much of that is due to thermal projects in Saskatchewan, it also continues growing primary production, Rob Peabody, Husky’s chief operating officer, told shareholders at Husky’s Investor Day presentation. Peabody said Husky still has plenty of opportunity drilling traditional heavy oil wells using cold heavy oil production with sand (CHOPS) technology. “Our focus on CHOPS is to high-grade the remaining locations. We still have an inventory of over 1,000 locations in CHOPS and we keep adding to that inventory every year,” he explained. “And we also have an active program re-completing existing CHOPS wells in new zones that we’ve previously not exploited.” Husky also has a significant horizontal program underway, said Peabody. “With horizontal wells, we’re going after thinner reservoirs that were not previously considered commercial. New technologies have allowed us to grow production to over 8,000 barrels per day in a few years. And we’re in good shape to hit our target of 16,000 barrels per day by 2017. Using pad drilling and multilaterals, not only are we growing production, we’re also improving netbacks. Operating costs for horizontal wells are about $12 per barrel.”

OIL & GAS INQUIRER • MARCH 2013

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Feature

newwave Steam, chemical sweeps, push heavy oil growth By Darrell Stonehouse

Illustration: Kirsty Pargeter/Photos.com

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ecessity is the mother of all invention, goes the old saying. The need to increase production from western Canada’s 30 billion barrels of heavy oil in place in eastern Alberta and western Saskatchewan is driving a lot of inventive schemes in recent years. Operators are using a mix of thermal technologies, polymer floods and even CO2 floods to capture more of the massive heavy oil resource. Husky Energy Inc., which has been operating in the Lloydminster heavy oil fields for 70 years, is leading the charge. Speaking at Husky’s Investor Day, company president and chief executive officer Asim Ghosh said after years of decline in its heavy oil division, Husky is now reversing the trend. Ghosh said much of the credit for this reversal has been the application of steam assisted gravity drainage (SAGD) in its fields around Lloydminster. Thermal recovery of heavy oil is nothing new for Husky. Its first development, Pikes Peak, has been on stream since 1982. Two other developments, Celtic and Bolney, began in 1996. But in the last two years, the company has cranked up production. “Thermal production for us is already big, and it’s getting bigger,” said Ghosh, who explained the company has already surpassed its target set last year to grow thermal production to 35,000 barrels a day by 2016. “We’re running about 38,000 barrels a day, so we’re going to set the bar even higher at 55,000 barrels a day by 2017.” Husky’s two most recent thermal expansions, Pikes Peak South and Paradise Hill, reached full design capacity within two months of first oil and are both exceeding design rates. Ghosh said the use of thermal technologies has added a generation of production to Husky’s Lloydminster land base. “When you look at the overall heavy oil portfolio, we have a very, very large resource in place, and over the past 70 years somewhere of the order of magnitude of 800 million barrels have been extracted from our Lloyd heavy oil complex. And with our new focus, with the technology now in place, we have great confidence that we can recover that amount again in the future,” he said. Husky chief operating officer Robert Peabody said what makes the company’s SAGD heavy oil projects profitable are the low upfront development costs and low operating costs. “The good margins we’re getting are driven by finding and development costs of around $12 a barrel for these thermal projects and operating costs of about $10 a barrel,” Peabody noted.

The effort to grow its thermal production has been building for much of the last decade, Peabody said. The company has shot 3-D seismic over almost all of its two million acres of Lloydminster leases to identify suitable targets. “Through that enhanced technical understanding of how the entire resource is laid down and improvements in 3-D seismic technology, we can really see where we can put these projects now,” he explained. “How the heavy oil is distributed in the subsurface also determines the size of the SAGD projects.” The smaller SAGD projects are easier to execute, as well. Peabody points to the success Husky had at Pikes Peak and Paradise Hill as examples. “Both of the projects were delivered about eight per cent under our budgets, and were delivered with capital efficiencies in the $24,000- to $28,000-a-flowing-barrel range. This delivery was worth about an extra $50 million of net income this year, compared to going on as planned for commissioning these projects.” Peabody says Husky has a robust pipeline of thermal projects to be developed in the next few years. A pilot project at Rush Lake is currently producing, with plans for a 10,000-barrel-per-day commercial project. A smaller, 3,500-barrel-per-day project is under construction at Sandall. Further ahead, the company has identified seven more thermal projects with potential production totalling more than 30,000 barrels per day. A different sort of thermal project is underway in western Saskatchewan at Kerrobert, where Petrobank Energy and Resources Ltd. is testing its toe to heel air injection (THAI) technology. After a rocky start, the project is beginning to build momentum, senior vicepresident and chief operating officer, heavy oil, Chris Bloomer said. Petrobank has 47 million barrels of heavy oil in place on its Saskatchewan lands, with proved-plus-probable THAI reserves of 8.5 million barrels at Kerrobert. The field was placed on production in late 2011. At the end of the third quarter of 2012, production averaged a little over 300 barrels per day. The break-even point for the play is around 1,000 barrels per day. Bloomer says the company believes this rate of production is achievable. “As operations continue to see more air injection and production growth, we do think this project will become an economic project, and that can lead to other projects going forward. So we’re certainly not satisfied with 300 barrels a day and that’s something that we hope to see change in the near term,” he said. OIL & GAS INQUIRER • MARCH 2013

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Feature

Bloomer said the company expects production to climb as it ups air injection and expands the combustion front in the field. “Our target ultimate injection rate per well is about three million cubic feet per day. So with 12 wells that’s 36 million cubic feet of total injection capacity for the whole project. Right now, we are injecting at about 4.5 million cubic feet per day, which is around 12 per cent of the targeted three million cubic feet a day per well, or 36 million cubic feet a day for the whole project,” he said. Heat isn’t the only thing being pumped downhole to drive heavy oil production. Polymer floods are also proliferating in an effort to capture more resources. Pelican Lake is the most advanced polymer flood play, with both Cenovus Energy Inc. and Canadian Natural Resources Limited in the midst of expansion efforts. Canadian Natural is well into total field development at Pelican Lake. “We have over 550 million barrels to develop on our polymer flood,” said Canadian Natural president Steve Laut. “Our plan in 2013 is to continue the development at the polymer flood, with 56 per cent of the pool converting to polymer flood by the end of the year. We’re seeing good production response from our polymer flood, and we’ll see production increase by 19 per cent in 2013.” Cenovus plans on spending as much as $620 million at Pelican Lake in 2013. In 2012, growth slowed in the play as infill drilling resulted in lower field pressure, reported Cenovus executive vicepresident and chief operating officer John Brannan. “We continue to run with four rigs on our infill drilling and polymer flood program,” he added. “Production from the new wells is coming on as expected, and we are slowly seeing production rates

• • • • • • • • • • • • •

returning to normal from the existing wells as operating pressures are restored.” Brannan says that as more and more of the field is polymer flooded, costs are rising at Pelican Lake. The company is beginning construction of a 30,000-barrel-per-day oil battery. Its goal is to raise production to 55,000 barrels per day from the field. Husky is also in the midst of piloting a number of enhanced recovery schemes, using CO2 from its ethanol plant in nearby fields surrounding Lloydminster. The company piloted the technology in two heavy oil reservoirs near Mervin, Sask., with help from the Saskatchewan government. In one pilot, cyclic steam stimulation, or “huff and puff,” technology was used, while more traditional flood injection technology was used in the other reservoir. The effort is the first known use of CO2 in a heavy oil reservoir in the world. Husky has since expanded its pilot program into reservoirs at Tangleflags and Lashburn, both in Saskatchewan. In May, the company announced its carbon capture and liquefaction project at its Lloydminster ethanol plant was complete. In opening the facility, Husky’s Ghosh said the project would recover more oil from existing fields while reducing emissions at its ethanol plant. “This remarkable project gives us two bangs for the same buck,” he said. The facility converts approximately 250 tonnes of CO2 per day into a high-pressure liquid. The liquid is then stored on site in three 900,000-gallon bullets, each holding one day’s worth of production, until it is transferred to the heavy oil fields by tanker trucks. Once there, the CO2 is vaporized and injected into reservoirs. No results have been released from the CO2 floods.

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MARCH 2013 • OIL & GAS INQUIRER

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Feature

Pockets of opportunity

Explorers begin to unravel new oil plays in southern Alberta By Darrell Stonehouse

Photo: Joey Podlubny

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fter years of stagnation caused by the collapse of natural gas prices, the southern Alberta oilpatch is beginning to show signs of life. Driving the resurgence is a patchwork of emerging tight oil plays, along with some enhanced recovery efforts in existing plays. DeeThree Exploration Ltd. is one operator enjoying success south of Lethbridge, Alta., in the Alberta Bakken play. It has 200,000 gross acres in the play and early drilling results have production on the upswing. DeeThree is currently focused on a 100-section area near Ferguson, where it announced a major pool discovery in early 2012. Estimates put contingent resources in place on the play at over 220 million barrels, with another 257 million barrels of prospective resource. The company drilled 17 horizontal wells into the Bakken in 2012 with 100 per cent success. During the third quarter of 2012, DeeThree drilled five wells at Ferguson. The quarter was highlighted by two wells testing 1,025 barrels per day and 743 barrels per day over a 10- and nine-day test, respectively. The company reported that initial production and well declines continue to perform substantially better than the type curve used for internal budgeting purposes: an initial production rate of 300 barrels per day with a 65 per cent first-year decline rate. DeeThree has been drilling mile-long laterals into the Bakken play. The company said its early production results indicate that the longer horizontal legs create higher flow rates, higher initial production and flatter decline curves. Drilling and completion costs have fallen throughout the year, with three of the past four one-mile lateral wells costing about $3 million. After a rough start, Murphy Oil Corporation is also reporting some good news from the Alberta Bakken. Murphy drilled a number of low

production wells in the play in 2011 before refocusing its efforts on the Three Forks zone, which is very prolific in the North Dakota Bakken. “Our initial well, the 15-21, completed in the Three Forks zone, has now been on production for over 300 days and [is] still achieving rates near 200 barrels a day,” said Roger Jenkins, chief operating officer of Murphy Exploration & Production Company. “We have spud another well in this location on October 16. Depending on appraisal success, we plan to drill additional wells there.” Outside the Alberta Bakken play, explorers continue to target the Pekisko play. Pace Oil & Gas Ltd. is building production in the Pekisko on lands it acquired. Pace has a large inventory of oil prospects on more than 310,000 net acres of land in southern Alberta, including 69,000 acres of land at Matziwin. Last summer, Pace drilled two wells into the Pekisko. The first well was completed using a 20-stage slickwater frac with approximately 300 tonnes of sand and 4,000 cubic metres of water. Initial results from the well are very encouraging, with the well flowing approximately 2,000 barrels of oil in 93 hours during cleanup with an average oil cut of 65 per cent. The second well was completed using a 15-stage slickwater frac with approximately 300 tonnes of sand and 4,000 cubic metres of water, and brought on in early August. The company is also targeting the Glauconite, Mannville and Lithic horizons in the play. It has identified 87 low- to medium-risk horizontal locations for future development. Crew Energy Inc. also continued developing its Pekisko play at Princess. It drilled 13 wells into the play in 2012, including a horizontal well that tested at a rate of 800 barrels per day over its first week of production. In 2013, Crew is focusing on managing decline rates at Princess by implementing three to five new waterfloods and drilling 21 new wells into the play. The company already has eight waterfloods working in the Pekisko. Longer term, the company is targeting decline rates in the area to be reduced to the 20–25 per cent range. To the northwest, Legacy Oil + Gas Inc. is working on its Turner Valley oil play, figuring out how to produce the play economically. In its third-quarter 2012 report, Legacy said it continues fine-tuning its drilling and completion strategies by targeting infill locations to optimize both production rate and capital costs. It is testing different OIL & GAS INQUIRER • MARCH 2013

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locations in the Turner Valley field with varying water cut, reservoir pressure, proximity to water injection and three different stratigraphic horizons. Horizontal wells in Turner Valley have typically come on production with a high water cut and as load fluid is recovered, the water cuts decrease and the oil rates increase. This phenomenon has been observed in the 22 previously drilled unfractured horizontal wells and in the wells drilled by Legacy. In turn, the company expects the Turner Valley horizontal wells to produce at stable, low-decline rates based on the production profile demonstrated by both the previously drilled and the Legacy-drilled wells. The Hartell #6 well and Boyd #1 well continue to deliver excellent performance. Hartell #6 has produced nearly 50,000 barrels of oil equivalent (boe) in 11 months of production and Boyd #1 has produced nearly 40,000 barrels in six months of production and has averaged 250 boe per day for the last four months. Both wells did not reach peak rates until considerably after the first production date. Production has continued to trend higher on the remainder of the Turner Valley wells as artificial lift optimization has taken place, production run times have improved and the recovery of load fluid has resumed. Legacy’s most recent horizontal well at Herriman #5 is an example of the progression of positive production results as the Turner Valley completion practices are further refined. The well has increased from 100 barrels per day to peak rates of 400 barrels per day in its first weeks of production, while still producing at approximately 67 per cent water cut and carrying a high fluid level. Offset producers have water cuts between 16 and 45 per cent, and it is anticipated Herriman #5 will continue to trend lower in water cut and higher in oil rate. The company said it’s made great strides in reducing capital costs since the end of 2011 and early 2012. With an ongoing program, refinement of mud programs and bit selection, Legacy continues to improve its drilling performance in Turner Valley, leading to decreased capital costs. The recent dual lateral horizontal wells have cost approximately $6 million for drilling, completion, equip and tiein, driving much-improved capital efficiencies. Legacy believes there is potential for additional capital cost reductions on future wells. The company plans on spending $47 million in the play in 2013. Natural gas giant Encana Corporation is also on the hunt for oil in southern Alberta. In its Clearwater liquids play, located across southcentral and west-central Alberta, Encana has identified a significant inventory of prospective oil opportunities on about 4.6 million net acres of land in southern Alberta. Targeting numerous zones, the company focused on developing 300 high-graded locations in 2012. It drilled around 30 wells. “In Clearwater, Encana has captured 4.6 million acres of land where we have a great advantage in that Encana actually owns the mineral rights to about 78 per cent of those lands where we do not have to pay a Crown royalty,” said Michael McAllister, executive vice-president and acting president of the Canadian division, told shareholders at the company’s Investor Day. “With this fee land advantage, our average royalty rate for the Clearwater business unit is approximately two per cent. The team has mapped out 200 million barrels of petroleum in-place from nine oil-prone formations existing on Encana’s Clearwater lands.” Key zones the company is evaluating include Belly River, Cardium, Viking, Mannville, Pekisko, Wabamun, Camrose, Nisku and Leduc. “The team is identifying a growing well inventory, which currently stands at 300 high-graded locations,” McAllister said.

Feature

Back to

the well Enhanced recovery creating new reserves in southern Alberta By Darrell Stonehouse

Photo: Joey Podlubny

W

hile many operators are focused on finding new oil to grow their production in southern Alberta, others are focused on growing reserves using enhanced recovery technologies. Enerplus Corp. is one such outfit. In November of 2012, the company reported its waterflood production had grown to almost 17,000 barrels per day, a 12 per cent increase over the previous year. Ian Dundas, executive vice-president and chief operating officer for Enerplus, said one area of focus is the Medicine Hat Glauc C project in southern Alberta. During the summer, the company began injecting polymer into the Glauconitic zone at its Medicine Hat area. “And while it’s too early for definitive results, early indications are quite promising,” said Dundas. Polymer is a chemical additive that thickens injected water to improve its sweep efficiency, usually in heavy oil. “As a result of our drilling and enhanced oil recovery [EOR] activities, we expect production will grow this year in this asset by almost 50 per cent,” Dundas said. According to a presentation on Enerplus’s website, the recovery factor in the Medicine Hat Glauc C pool was roughly eight per cent. Original oil in place was estimated at 217 million barrels with an API gravity of 11–18 degrees. Production from the pool rose dramatically after the company stepped up water injection about five years ago. Enerplus believes EOR could more than double remaining reserves. Zargon Oil & Gas Ltd. is also focused on enhanced recovery in southern Alberta. Its Little Bow Alkaline Surfactant Polymer (ASP) project continues to build towards commercialization, the company reported in late 2012. The ASP project entails the injection of a dilute chemical solution into a partially depleted reservoir to recover incremental oil reserves. In its 2011 year-end review, McDaniel & Associates Consultants Ltd. assigned 4.15 million barrels of probable undeveloped oil equivalent reserves to Zargon’s working interest in phases 1 and 2 of the project.

In 2012, Zargon completed the front-end engineering and design studies, finalized the selection of key alkaline and polymer components, obtained scheme approval from the Energy Resources Conservation Board, completed the majority of the detailed design and commenced the procurement of long-lead-time equipment. Zargon has also acquired operatorship and majority ownership of the Travers Gas Plant, which is directly adjacent to its Little Bow oil facilities and is expected to provide solution gas processing facilities for the life of the ASP project. In 2013, Zargon plans to complete well workovers and pipeline upgrades required for the ASP project, which will also benefit existing waterflood operations in the near term. The next step in the development of the project will be the final sanctioning of the project’s construction by mid-March 2013 in order to commence chemical injections by year-end 2013, which in turn is expected to deliver incremental oil production by the second quarter of 2014. The total capital cost of phases 1 and 2 of the Little Bow ASP project is approximately $59 million. The estimated total phase 1 and 2 chemical cost for the 2013-19 chemical injection period will be capitalized and is $50 million. Based on this capital program, phase 1 and 2 peak incremental oil production is estimated at 1,400 barrels of oil per day in 2016-19. Using these rates with an estimated field oil price of $68 per barrel (C$85 per barrel Edmonton par price), a 12 per cent incremental tertiary royalty rate and operating costs of $12 per barrel of incremental oil, the project is forecast to provide a field netback of approximately $48 per barrel of incremental oil production volumes. Follow-on capital expenditures for phases 3 and 4 of the Little Bow ASP project are expected to be completed by 2017, with forecasted total combined phase 1 to 4 project peak production rates expected to occur in 2020. OIL & GAS INQUIRER • MARCH 2013

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Oilfield purchasing technology is changing rapidly Purchasing patterns are changing in Canada’s oil and gas industry, and buyers are using technology to access more and better information. The COSSD, a new database of service and supply companies, is helping them control costs and maximize productivity. In 2012, more than 170,000 people used it. In Canada’s Western Canadian Sedimentary Basin, explorers and producers are changing the way they work. In many plays, their focus is on repeatable, factory-like approaches to drilling, completion and tie-in of new wells, and to the service and operation of existing wells. More and more, they are focused on efficiency and cost control. Website (unique visitors)

and move their head offices or open and close branch locations. Luckily, the Canadian Oilfield Service and Supply Database (COSSD) is constantly updated, so a buyer can count on it to find what they need. They can use the COSSD for free, and it’s available in six ways: website, smartphone, iPad, Garmin GPS, digital edition and print.

Garmin GPS (downloads)

Smartphone (unique visitors)

iPad (downloads)

140,000

Company type

Per cent of total visits

Primary purchasers Exploration & Production Engineering Pipeline Construction Refining & Petrochemicals/ Gas Processing Total—primary purchasers Secondary purchasers Service & Supply Transportation Manufacturing & Fabrication Electrical, Instrumentation & Control Health, Safety & Environmental Total—secondary purchasers Occasional purchasers Legal, Financial & Investment Government, Agencies & Consulates

22

21

Universities, Research Institutions & Public Libraries

120,000 100,000 80,000

Other Total—occasional purchasers

60,000

From a sample of 1,000 companies who visited COSSD.com in Q2-Q3 2012.

40,000 20,000 0 June 30, 2009

June 30, 2010

Engineers, planners, managers and buyers are using new approaches and technologies to make sure they purchase services and supplies at the lowest possible cost. Just as important, they are making sure that services and supplies are delivered when they are needed. Time is money in the oilfield, and they’re focused on saving both. To save time and money, a buyer needs to have more than one option—they need choices in products and vendors. They may have information on some vendors in their accounting, enterprise resource planning and compliance systems. That’s usually not enough—they must extend their search for suppliers, so they need other sources. However, finding what a buyer needs in Canada’s oilfield is a complex process. The service and supply industry is made up of over 3,000 companies, and they are constantly changing. Mergers and acquisitions and company startups and closures happen frequently. Vendors change the products and services they offer,

June 30, 2011

June 30, 2012

December 31, 2012

Whether in an office or in the field, it’s proving to be a buyer’s best source for vendor information—that’s why its usage is growing so rapidly. In 2012, over 53,000 people used its print or digital edition. The fastest growth is in digital usage—in 2012, over 118,000 used it through the website, smartphone, iPad and Garmin GPS. That’s more than 170,000 in total. COSSD is also proving to be a vendor’s best choice for connecting to their customers. Buyers are now using COSSD.com on their web browsers and iPhone, BlackBerry or Android smartphones. They can search a vendor’s company profile, product catalogue, display advertisements, categories of service and locations. They’re also able to use its proximity search features to find a service or product close to a town, city or even their smartphone’s current location. An analysis of 1,000 companies who visited COSSD.com in the second to third quarter

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LefT: Digital usage of the COSSD has grown substantially since 2009. ABOVe: Many of Canada’s leading explorers and producers use COSSD.com—as do many other primary and secondary purchasers of oilfield services and supplies. of 2012 showed that many were primary buyers—explorers and producers such as Encana Corporation or Talisman Energy Inc., and pipeline operators like TransCanada Corporation. Many more are secondary buyers—service and supply companies such as Weatherford Canada Partnership and Halliburton. If you’re a buyer, visit COSSD.com to learn how this database can help you. If you’re a vendor, use the COSSD to ensure 170,000 or more buyers can find you. Become part of this fast-growing buyer/ seller community—email Christopher Kuntz at ckuntz@junewarren-nickles.com or call 403.516.3492.

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Business

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a.m., by the time the people de-board, get their bags and get bused to the work

productivity, maintain controls and contain costs.

site, a half day of work is gone. If you lose a half day off every rotation, that’s

The logistics of getting crews to remote work sites can be staggering, yet workforce transportation is far from the core competence of most mineral and energy industry executives. Hence the reliance on firms that provide com-

10 per cent of your 14/7 crew rotation, even more on a 10/4, wasted. You must integrate the logistics plan with the project schedule.”

plete transportation solutions, from aircraft to crew to all other needs, and to

2) Reliability

wherever they need to go.

While utilizing a contract air carrier saves time since workers do not have to

Encana Corporation holds approximately 1.6 million acres of land in the

contend with traffic queues, parking delays, crowded check-ins or terminal

Greater Sierra oil and gas field, in and around the Fort Nelson area of northeast-

chaos, that time savings can amount to naught if the chartered plane isn’t

ern British Columbia. With a regular crew of skilled workers staffing an energy

ready to go because of mechanical issues.

facility, drawn from all over Canada and the United States, Encana provides a major boost to the local economy. “We need a significant workforce on a regular basis at one of our plants

“Delays can be quite costly,” notes Wallis. “We move crews in and out as close to schedule as possible to stay efficient.”

located near Fort Nelson, British Columbia,” says Terry Wallis, lead, travel and

3) Flexibility

aviation, for Encana. “To attract skilled workers from all over the continent,

A prime benefit of a dedicated charter air partner is responsiveness: does

the best arrangement is to bring them in for two weeks and then take them

the carrier run a scheduled air service in addition to charters (that could take

back home.”

priority over moving workforce contract agreements)? The carrier should

For transporting its workforce, Encana currently contracts with Flair

be able to customize all facets of the operation, from modifying seating lay-

Airlines, a Canadian large-aircraft charter carrier that is backed up by Kelowna

outs to fit anywhere from five dozen business-class seats to 170 economy

Flightcraft, both in Kelowna, B.C.

passenger seats, to departure times and flight routings, to flexibility for

Moving such a quantity of workers in and out of such a small town can create logistical nightmares, particularly when trying to do so cost effectively, rapidly and safely.

customer travel schedules, or even additional baggage capacity.

4) Safety

“The reason transportation is so critical is because you can’t move the group

As charter companies are oftentimes small, their safety can be called into

out that is there until the new force comes in. It is really important to keep that

question. Some very large corporations set up their own standards that the

on schedule,” says Wallis.

air carrier must meet.

Flair Air also worked with Royal Dutch Shell plc when it rotated between 10,000 and 12,000 people a month during construction of its oilsands mine near Fort McMurray. “For its Albian Sands expansion project, Shell also selected Flair for support-

“Any aviation company that we work with has to have been audited and approved to meet our safety standards,” says Wallis.

5) Cost effectiveness

ing its project, which involved 130,000 passenger flights in and out of Albian

Probably the number one reason to utilize a chartered aircraft for workforce

Airport per year from up to 24 different airport locations across the continent,”

logistics is the large amount of expense avoided in purchasing and maintain-

says Yates. “Given the magnitude of such an undertaking, workforce logistics

ing dedicated corporate aircraft for such purposes, which can be limiting in

plays a prime role in productivity.”

terms of flexibility—particularly for peak periods. OIL & GAS INQUIRER • MARCH 2013

61

advertisers' index 3D Drilling Tools Inc . . . . . . . . . . . . . . . . . . . . . . . 28

ClearStream Energy Holdings. . . . . . . . . . . . . . . . 6

Abacus Datagraphics Ltd . . . . . . . . . . . . . . . . . . 38

CRD Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Paramount Hydraulics. . . . . . . . . . . . . . . . . . . . .44

Advantage Valve Maintenance Ltd . . . . . . . . . . . 25

Daemar Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

Pelican Products ULC . . . . . . . . . . . . . . . . . . . . . 28

Allmand Bros Inc . . . . . . . . . . . . . . . . . . . . . . . . . 15

Diversified Glycol Services Inc . . . . . . . . . . . . . . 36

Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Annugas Compression Consulting Ltd . . . . . . . . 55

dmg events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Petroleum Services Association of Canada . . . . 29

Dragon Products . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . . 25

ASAP Heating & Well Servicing Corp . . . . . . . . . 54 Bear Slashing Inc . . . . . . . . . . . . . . . . . . . . . . . . . 15 Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . . 58 Bilton Welding and Manufacturing Ltd . . . . . . . . 36 Brews Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Brother’s Specialized Coating Systems Ltd . . . . 30 Calroc Industries Inc . . . . . . . . . . . . . . . . . . . . . . 49

Ecoquip Rentals & Sales Ltd . . . . . . . . . . . . . . . . 35 Expertec Van Systems Inc. . . . . . . . . . . . . . . . . .48 Foremost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 General Motors of Canada Ltd . . .inside front cover Hughson Trucking Inc. . . . . . . . . . . . . . . . . . . . . .40 Hydro-Fax Resources Ltd . . . . . . . . . . . . . . . . . . 30 Impact Society. . . . . . . . . . . . . . . . . . . . . . . . . . . 20

MRC Global Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Predator Drilling Inc. . . . . . . . . . . . . . . . . . . . . . . 34 Saskatchewan Oil & Gas Show . . . . . . . . . . . . . . 22 Shell-Ryn Machining . . . . . . . . . . . . . . . . . . . . . . 56 Sirius Instrumentation And Controls Inc. . . . . . . 45 Sprung Instant Structures. . . . . . . . . . . . . . . . . . . 7 Strad Energy-Matting . . . . . . . . . inside back cover Tundra Process Solutions Ltd . . . . . . . . . . .42 & 46

Canadian Standards Association . . . . . . . . . . . . .11

Infosat Communications LP . . . . . . . . . . . . . . . . 21

CG Industrial Specialties Ltd. . . . . . . . . . . . . . . . 32

MaXfield Inc. . . . . . . . . . . . . . . .outside back cover

Unified Valve Ltd . . . . . . . . . . . . . . . . . . . . . . . . . 18

Chemineer, Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Maxxam Analytics . . . . . . . . . . . . . . . . . . . . . . . . 37

Vertigo Theatre Society . . . . . . . . . . . . . . . . . . . 24

City of Grande Prairie . . . . . . . . . . . . . . . . . . . . . 52

Meridian Manufacturing . . . . . . . . . . . . . . . . . . . 19

V.J. Pamensky Canada Inc . . . . . . . . . . . . . . . . . . 10

Clean Harbors . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . 58

West Country Oilfield Services & Weed Control . .48

62

MARCH 2013 • OIL & GAS INQUIRER

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Oil & Gas Inquirer March 2013