Oilsands Review March 2017

THE HE AV Y OIL AUTHORIT Y

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WELL PAD WARS: Competition is tight to get it right as producers target 50 per cent cost reductions

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CONTENTS V O LU M E 1 2 | N U M B E R 1 | M A R C H | 2 0 1 7

DEPARTMENTS COVER STORY

07

From the editor Insights into oilsands trends

IN REVIEW

08 12 15 42 46

News

IN FOR THE WIN

Rounding up the latest oilsands news

Don’t read too much into recent oilsands asset sales–the companies that dominate

Project news

the sandbox are staying and figuring out

Project status and development progress

37

how to get bigger.

PAUL WELLS

Eyes on the oilsands What people are saying about the industry in the media and around the world

PRIORITY 1: PRODUCTIVITY

Statistics

Oilsands producers and

Taking a close look at the inputs and outputs of the oilsands industry

Sector watch Temporarily shutting in thermal wells may not be as harmful as you think

suppliers to continue chasing efficiency as the market stabilizes:

18

2017 OUTLOOK SURVEY

ROAD TO RECLAMATION Oilsands miners look to fine-tune tailings technology under encouraging new regulations LYNDA HARRISON

24

WELL PAD WARS Competition is tight to get it right as SAGD producers target reductions in well pad costs JIM BENTEIN AND DEBORAH JAREMKO

31 M A R C H 2 0 1 7 • J W N E N E R G Y. C O M • 0 5

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FROM EDITOR THE

INSIGHTS INTO OILSANDS TRENDS

EDITORIAL EDITOR

Deborah Jaremko | djaremko@jwnenergy.com CONTRIBUTING WRITERS

Jim Bentein, Lynda Harrison, Paul Wells EDITORIAL ASSISTANCE MANAGER

Tracey Comeau | tcomeau@jwnenergy.com EDITORIAL ASSISTANCE

Laura Blackwood, Jordhana Rempel

CREATIVE CREATIVE SERVICES MANAGER

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Cathlene Ozubko PRINT COORDINATOR

Janelle Johnson

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Jeremy Seeman

CREATIVE SERVICES

Celia Hui, Teagan Zwierink

SALES MANAGER, ENTERPRISE SALES

Kevin Springer | kspringer@jwnenergy.com SENIOR ACCOUNT EXECUTIVES

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MARKETING MANAGER, MARKETING PROGRAM

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CIRCULATION AND DISTRIBUTION MANAGER, PRODUCT DISTRIBUTION

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DIRECTORS PRESIDENT & CEO

Bill Whitelaw | bwhitelaw@jwnenergy.com SENIOR VICE-PRESIDENT, ENERGY INTELLIGENCE

Bemal Mehta | bmehta@jwnenergy.com VICE-PRESIDENT, SALES OPERATIONS

Donovan Volk | dvolk@jwnenergy.com VICE-PRESIDENT, DIGITAL STRATEGIES

Gord Lindenberg | glindenberg@jwnenergy.com DIRECTOR, THE DAILY OIL BULLETIN & EDITORIAL PRODUCTS

Stephen Marsters | smarsters@jwnenergy.com DIRECTOR, PRODUCTION

Audrey Sprinkle | asprinkle@jwnenergy.com DIRECTOR, ADVISORY SERVICES

Anupam Sharma | asharma@jwnenergy.com DIRECTOR, STRATEGIC PARTNERSHIPS

Wendy Ell | well@jwnenergy.com

“The oilsands is likely a dead industry…. A lot of players have left, and other production has been mothballed. The industry is in a holding pattern.”

It is no doubt that oilsands detractors took great smug satisfaction at this statement made by University of Waterloo professor Thomas Homer-Dixon to grist.org in January, but it is just flat-out wrong.

The boom is over and things may never return to the breakneck pace of the past, but to say that the oilsands industry is dead—or even that it is in a holding pattern—is misinformed and incorrect.

We know that oilsands development is a very different proposition in an era of increasing oil abundance than it was when the world was staring down the barrel of peak oil.

We also know that the last two and a half painful years have put a bullseye on what was wrong with the oilsands before prices dropped.

Costs were too high, but they are starting to come down.

Not only will the industry continue to operate its soon-to-be three million bbls/d of bitumen production, it will be able to grow—maybe brownfield today, but also greenfield again tomorrow as new technologies and systems take hold.

The industry already has a line of sight to brand-new growth projects, analysts with CIBC Equity Markets asserted in a report issued this January.

Within five years, greenfield in situ oilsands development will be able to earn a 15 per cent

rate of return in a US$50/bbl WTI world, CIBC said, adding that Alberta’s emissions cap will not hinder further growth.

That’s thanks to new technologies on a spectrum from “simply better ways of doing things with less steel and fewer energy inputs to radically new recovery schemes,” including solvent-assisted extraction, solvent-only extraction and electromagnetic heating, the analysts wrote.

There is a belief that all but the best quality oilsands resources will become stranded, CIBC acknowledged, but that need not be the case.

The people that make up the oilsands industry are leaders in technology development—they have achieved big things in the past and will again in the future.

People are so incredibly wrong to celebrate the idea of shutting down the oilsands.

What we should all celebrate as Canadians is that we have so many people with so much drive and ability to make the oilsands cleaner, more efficient and globally competitive in order to continue contributing and prospering from socially responsible oil in a world that will keeping needing it for decades to come.

DEBORAH JAREMKO

djaremko@jwnenergy.com @JWN_Deborah Sign up for FREE weekly oilsands news at jwnenergy.com

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The opinions expressed by contributors to Oilsands Review 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.

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SPECIAL DOUBLE ISSUE: 2017 Heavy Oil & Oilsands Guidebook The new oilsands growth model

M A R C H 2 0 1 7 • J W N E N E R G Y. C O M • 0 7

IN REVIEW

MARCH 2017 // ROUNDING UP THE LATEST OILSANDS NEWS

Alberta introduces oilsands GHG cap legislation

P.10

Flurry of activity around new Canadian export pipelines It’s good news, bad news and more uncertainty for Canada’s proposed new crude oil export pipelines following a flurry of decisions and announcements in late 2016 and early 2017.

TransCanada accepted U.S. president Donald Trump’s invitation to re-submit the permit application for the proposed 830,000-bbl/d Keystone XL Pipeline on January 27. In his executive orders, Trump also told regulators that their decision should be made on the project within 60 days.

Kinder Morgan received approval from Canada’s federal government and the province of B.C. to proceed with its 590,000-bbl/d Trans Mountain Pipeline expansion, also agreeing to an unprecedented payment to B.C. of up to $1 billion over 20 years.

Subject to a final investment decision, construction could start in September.

The federal government also approved Enbridge’s 370,000-bbl/d Line 3 Replacement Program between Alberta and Wisconsin.

08 • MARCH 2017 • OILSANDS REVIEW

The anticipated in-service date is 2019, pending U.S. regulatory approvals.

Enbridge has removed the Northern Gateway Pipeline application from the B.C. review process following Prime Minister Justin Trudeau’s November announcement that the application would be dismissed.

The National Energy Board (NEB) also announced the regulatory hearing for the proposed 1.1 million-bbl/d Energy East Pipeline from Alberta to the East Coast would start from scratch and the decisions of the previous panel would be voided.

The previous panel stepped down in September 2016 in order to “preserve the integrity” of the NEB process following accusations of bias toward project approval.

A new partnership is working to bring investment back to Alberta by achieving meaningful results in improving the competitiveness of industrial project execution.

The Alberta Projects Improvement Network (APIN) brings together the Construction Owners Association of Alberta (COAA), GO Productivity, the Supply Chain Management Association of Alberta and JWN. APIN works like this: COAA develops the tools to improve performance, GO Productivity implements them through its network of producers and suppliers and JWN communicates the lessons learned to the broader industry.

Advanced work packaging (AWP) is the first best practice being implemented.

AWP, which has been shown to improve productivity by 25 per cent and reduce total installed cost by 10 per cent, is used successfully across North America to extend front-end planning across a project’s life, but it is not yet used in Alberta.

APIN is the result of extensive collaborative work by its partners and leverages each of their strengths to create a powerful tool, the group says.

The initiative has support in high levels of industry, including Mike MacSween, Suncor’s executive vice-president of major projects and a member of GO Productivity’s board of directors.

“The natural resource we’re blessed with, and the industry that has been built up, is a national treasure, and we have an opportunity to build upon that, but it is clear that there is a need for change,” MacSween told Oilsands Review.

“We simply can’t perform at a mediocre level. We should be striving for better, but it takes a holistic approach and takes multiple parties,” he said.

For more information about APIN, visit projectimprovement.ca.

PHOTOS: ( LEF T ) KINDER MORGAN C ANADA ; (RIG HT ) JOE Y PODLUBNY

Alberta Projects Improvement Network launches

IN REVIEW

$50 million per year What Kinder Morgan has agreed to pay B.C. in order to build and operate the Trans Mountain Pipeline expansion over 20 years

At least

10

Number of partial bitumen upgrading technologies that exist today but have yet to be commercialized

Canadian Natural gets maximum APEGA fine in 2007 fatal oilsands tank collapse The Horizon integrated oilsands project.

$582 million

The amount that Athabasca Oil will pay to Statoil to purchase the Leismer SAGD project—plus up to $250 million in payments based on the price of oil to 2020

Nearly 10 years after two contractors were killed at the Horizon oilsands mine construction site, Canadian Natural Resources is being fined $10,000 by the Association of Professional Engineers and Geoscientists of Alberta (APEGA) for unprofessional conduct.

The workers from the Sinopec Shanghai Engineering Company were fatally wounded in April 2007 by a tankroof support structure that collapsed in its early stages of construction. Five others were injured.

APEGA, which initially said it found no evidence that Canadian Natural had done anything wrong, reopened the file in 2016 after Occupational Health and Safety released its own report on the event.

“Canadian Natural Resources Limited freely and voluntarily admitted to unprofessional conduct in the engagement and supervision of project contractors performing engineering work,” APEGA said in a statement.

The tank was to be 56.5 metres in diametre and 19.8 metres high. When the tank-roof support structure collapsed, it was 5.6 metres high, APEGA said.

The fine of $10,000 is the maximum allowed under APEGA’s current legislation. In addition, Canadian Natural has agreed to sanctions including working with APEGA on a new practice standard on outsourcing engineering and geoscience work, and paying up to $150,000 to support a province-wide consultation with APEGA members to develop the practice standard.

PHOTO: C ANADIAN NATUR A L RESOURCES

New rules released for shallow SAGD; four out of five originally impacted companies no longer involved New regulatory requirements have been issued, two years after the Alberta Energy Regulator (AER) deferred decisions on SAGD projects inside an area where bitumen is believed to be too shallow for safe operations of conventional SAGD. The area, which surrounds Fort McMurray but is primarily to the north and includes the surface mineable region is defined by having cap rock that is shallower than 150 metres at its base or caprock that is completely eroded.

The directive was developed in response to a steam release incident at Total E&P Canada’s Joslyn Creek SAGD project on May 18, 2006.

The release, which occurred near the heel of one well pair, caused a surface disturbance area of about 125 metres by 75 metres.

The AER reported that rock projectiles travelled up to 300 metres horizontally from the main crater and a plume of dust about one kilometre long stretched to the southwest of the release point.

When the AER deferred shallow SAGD decisions in 2014, it directly impacted five companies and projects that had filed regulatory applications: • Ivanhoe Energy (Tamarack project)—Ivanhoe declared bankruptcy in 2015.

• SilverWillow Energy (Audet project)—SilverWillow was acquired by Value Creation in 2015.

• Value Creation (Advanced TriStar project)—Alberta Environment and Parks deemed the project’s environmental impact assessment complete in April 2016.

• Grizzly Oil Sands (Thickwood Project)—the application was withdrawn in March 2016.

• Southern Pacific Resource (STP-McKay Phase 2)—Southern Pacific was placed in receivership in June 2015.

The new requirements for SAGD applications concern maximum operating pressure and caprock criteria. The intent is to ensure caprock integrity throughout the lifetime of thermal operations.

Wilbros awarded extension of maintenance agreement, pipeline construction Willbros Group says that its Canadian unit has been awarded US$87 million in new contracts, including a key oilsands maintenance program.

Willbros has formalized a master service agreement that provides for a five-year extension of an oilsands maintenance contract. The company says work will commence under this extension in February 2017.

Willbros has also been awarded construction of a new 48-inch, eight-kilometre pipeline. Construction will begin in January 2017 and is anticipated to be completed during the third quarter of 2017.

ClearStream Energy Services secures two maintenance/ sustaining capital contracts ClearStream Energy Services has announced two new contracts supporting ongoing operations of oilsands projects.

One contract, a five-year agreement through a joint venture with Kentz, is to provide engineering and procurement services for maintenance and sustainment projects to an unnamed integrated producer.

The second contract is a five-year renewal of a maintenance contract with a major oilsands producer.

This contract will be carried out

by ClearWater Energy Services, a subsidiary of ClearStream, and is expected to generate approximately $390 million of revenue over the term of the contract.

M A R C H 2 0 1 7 • J W N E N E R G Y. C O M • 0 9

IN REVIEW It’s up to Alberta to carry partial upgrading technologies across Death Valley: U of C School of Public Policy

Partial upgrading systems that take bitumen to a medium crude versus a full synthetic light have the potential to provide vast benefits for producers, the provincial government and Alberta workers, says a new report from the University of Calgary (U of C) School of Public Policy.

There are more than 10 of these technologies that exist.

However, none of them have been field piloted and remain on the wrong side of technology’s Death Valley, where an investment with likely merit fails to maintain financing and support to reach full market scale.

The report says that a single 100,000-bbl/d partial upgrader could add $10–$15 per bitumen barrel. Meanwhile, there could be an average annual increase to Alberta’s gross domestic product of $505 million, and as many as 179,000 person-years of employment created.

Partial upgrading could also help producers address a number of their current challenges, the report says: add value to bitumen without participating in the increasingly saturated U.S. market for light oil, significantly reduce diluent

requirements, free up pipeline capacity and potentially reduce greenhouse gas emissions.

The U of C report references 10 different partial upgrading technologies, including those owned by MEG Energy, Field Upgrading, ETX Systems, Value Creation Inc. and FluidOil (formerly Ivanhoe Energy).

“The province has stepped in to help technologies cross that ‘Death Valley’ before. The promise of partial upgrading may well justify, as manager and steward of Alberta’s resources, helping bridge that valley again,” the report says, referencing the Underground Test Facility built by the Alberta Oil Sands Technology and Research Authority in the 1980s where SAGD was proven viable—resulting in a game-changing technology shift in the oilsands.

The province announced that it would consider the merits of partial upgrading technologies as part of its Royalty Review Advisory Panel report in January 2016, stating that it understood that “the magnitude of investment required to ‘move the needle’ on partial upgrading technology is approximately $300 million.” Nothing has been announced since.

Alberta environment and parks minister Shannon Phillips has introduced the Oil Sands Emissions Limit Act, the legislation that will cap oilsands greenhouse gas (GHG) emissions to 100 megatonnes per year.

The GHG cap, which was announced in November 2015 with the support of several industry and environmental leaders, will take effect when passed in the legislature, but will not obligate oilsands producers until a regulatory system is designed and implemented, the government says.

“Our support for the oilsands emissions limit and climate policy leadership reflects the ongoing collective support for

responsible development of the oilsands,” read a statement issued by the province from Canadian Natural Resources, Cenovus Energy, ConocoPhillips Canada, MEG Energy, Shell Canada, Statoil Canada and Suncor Energy.

“We believe that by investing in technology and innovation, we can produce oil from the oilsands on a globally carbon competitive basis. The Alberta Climate Leadership Plan emissions limit acts as an incentive to continually improve our performance in a carbon-constrained world. We look forward to providing advice on the effective implementation of the emissions limit.”

10 • MARCH 2017 • OILSANDS REVIEW

Under the cap, a $30-per-tonne carbon price will be applied to oilsands facilities based on results already achieved by high-performing projects, the government says.

PHOTOS: ( TOP) JOE Y PODLUBNY; (BOT TOM ) G OVERNMENT OF C ANADA

Alberta introduces oilsands GHG cap legislation

IN REVIEW

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Pipelines at OSUM’s Orion SAGD project.

PHOTO: DEBOR AH JAREMKO

OSUM looks to reduce SAGD water costs with “rapid deployment” Veolia crystallizer In a move to reduce water treatment costs and recover more water for steam injection at the Orion SAGD project, OSUM Oil Sands has contracted a new system from Veolia Water Technologies.

Located in the Cold Lake oilsands region, Orion was commissioned by Shell Canada in 2007 and purchased by OSUM in 2014. It currently produces about 8,000 bbls/d.

The facility uses a crystallization system in order to minimize evaporator blowdown waste.

Veolia says OSUM is buying its modular bulldozer design crystallizer, which is expected to reduce the project’s operating costs. The system is projected to result in up to 80 per cent less wastewater disposal, six fewer trucks per day on the road and about 560,000 barrels of additional water recycled annually for steam generation.

Veolia says the installation will be executed “several months faster” than conventional systems due to its modular design.

“The philosophy of the modular bulldozer is to minimize fieldwork to the greatest extent possible,” Veolia said in a statement.

“It is designed to be relocatable and can be installed and fully commissioned in approximately four weeks. Welded connections have been eliminated and ship-loose items have been minimized the greatest extent possible. This highly modularized concept is perfect for rapid deployment remediation.”

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M A R C H 2 0 1 7 • J W N E N E R G Y. C O M • 1 1

IN REVIEW

// OILSANDS PROJECT NEWS

​Restarted:

Restarted:

CENOVUS ENERGY CHRISTINA LAKE PHASE G

US OIL SANDS IN UTAH

Cenovus Energy plans to resume work on the phase G expansion at its Christina Lake SAGD project in the first half of 2017, the company announced in December.

Since deferring phase G in late 2014, Cenovus says it has successfully reworked the construction plan and rebid contracts for the project to reduce costs.

“After realizing more than $500 million in project cost savings, the company anticipates the expansion can be completed with go-­ forward capital investment of between $16,000 and $18,000 per flowing barrel. Phase G is about 20 per cent complete and has an approved design capacity of 50,000 bbls/d gross.

First oil from the expansion is expected in the second half of 2019,” Cenovus says.

Cenovus also plans to spend capital to progress engineering work on deferred projects at Foster Creek and Narrows Lake, and says it will provide an update on these projects in the middle of 2017.

Restarted: CANADIAN NATURAL KIRBY NORTH Canadian Natural Resources in November became the first company to restart development of an oilsands growth project that was put on hold during the current downturn.

The company says it will restart work on the 40,000-bbl/d Kirby North SAGD project, an expansion to its 40,000-bbl/d Kirby South facility that started operating in late 2013.

Engineering and procurement commencing will commence in 2017, with a focus on finding opportunities to continue to reduce construction costs to completion, Canadian Natural says.

Kirby North will be targeted to deliver first steam-in in 2019, with first oil targeted in 2020.

“Kirby North project capital spending in 2017 is targeted to be $28 million as the company optimizes its execution strategies in order to continue the reduction in project capital costs,” Canadian Natural says.

“Approximately $700 million of project capital has been invested to-date at Kirby North and the remaining project costs are targeted to be approximately $650 million, more than $100 million less than originally expected.”

12 • MARCH 2017 • OILSANDS REVIEW

With a new US$7.5-million financing in hand, Calgary-based US Oil Sands is ready to restart construction on the Utah project it suspended in early December.

The company says it is now able to rehire the employees and contractors that were temporarily laid off in order to complete and operate the 2,000-bbl/d mining project, called PR Spring.

Project commissioning will resume as employees and contractors are brought back to site in a staged basis to allow for a coordinated and safe return to operations, US Oil Sands says.

First oil is expected early in 2017.

Proceeding: MEG ENERGY EMSAGP ROLL OUT Successful implementation of MEG Energy’s eMSAGP production enhancement system is now going to be further applied at the company’s Christina Lake oilsands project starting this year to the tune of a 20,000-bbl/d production increase, the company says.

About 55 per cent of MEG’s $590 million 2017 capital budget will be directed to eMSAGP growth. The full production increase is expected in early 2019, with 80 per cent of the associated $400 million capital spend to come this year.

Volumes are expected to start coming online in the second half of 2017. eMSAGP involves non-condensable gas co-injection, infill well drilling, new well pairs and facility debottlenecking, which increases production as well as reduces costs and greenhouse gas emissions.

​Planned: NEW SAGD INFILL WELLS AT FIREBAG Suncor Energy is targeting increased production and reduced steam to oil ratios at an existing well pad at its Firebag SAGD project by way of a package of new infill wells.

The company has filed a regulatory application for 14 infill wells at Pad 105 at Firebag. The pad started operations in 2012, the seventh to produce at the project since start-up in 2004.

Suncor started operating its first SAGD infill wells at Firebag in mid-2011. The strategy is designed to take advantage of heat in the reservoir to produce bitumen that isn’t easily accessed by the producer wells.

No pad expansion is required to accommodate the infill wells, Suncor says; however, an additional motor control centre building for infill variable frequency drives and control systems will be needed and constructed on the existing pad.

The incremental recovery factor from the proposed wells is predicted to be about 5.5 per cent.

Planned: JACOS HANGINGSTONE RESTART Japan Canada Oil Sands (JACOS) has filed an application with the Alberta Energy Regulator (AER) to restart the SAGD project it suspended last spring due to market conditions.

The JACOS Hangingstone SAGD pilot is one of the oldest thermal projects in the oilsands, having started up in 1999.

The company suspended operations at the 6,000-bbl/d project in May 2016, a process that was put in motion before the Fort McMurray wildfires but accelerated due to the regional emergency. Hangingstone was expected to be idled for 10–12 months, and JACOS has initiated the process to get it back up and running.

“JACOS requires AER approval such that we are able to react quickly when market conditions support a restart of the demo project,” JACOS regulatory director Enzo Pennacchioli wrote to the AER. The company continued in its submission that bitumen prices have “recovered to the point where restarting the project is being considered. JACOS, and parent company JAPEX, are currently assessing whether or not the economic climate is suitable for approval to restart.” Timing on the restart is uncertain, ­JACOS said, but indicated that it would take about four months following regulatory and corporate approval to return to operations.

Cancelled: MURPHY OIL SEAL PROJECT Murphy Oil has filed a letter with the AER requesting the application for its Seal thermal project, located in the Peace River region, be rescinded.

The company had filed the Seal regulatory application in early 2015. The 12,450-bbl/d project, which would have deployed horizontal cyclic steam extraction technology, was pegged with a capital cost of $624 million.

The Seal lands are part of the $65-million asset package that Baytex Energy announced it was acquiring in November 2016, from a seller later confirmed to be Murphy Oil.

IN REVIEW

“Murphy has confirmed with Baytex that they do not have an interest in continuing with this application,” Murphy said in its December letter to the AER.

Ramp-up update:

Alberta Energy Regulator, between January and October 2016 the highest volume the project achieved was in August, at 266 bbls/d.

Sunshine called the 2,200-bbl/d milestone “very favourable to the project in moving towards its full production capacity in the near term.”

SUNSHINE OILSANDS WEST ELLS Operations are off to a good start in 2017 at the West Ells SAGD project, according to a statement from Sunshine Oilsands.

Production at the 5,000-bbl/d SAGD project north of Fort McMurray has been bumpy since start-up in late 2015, hampered by low oil prices and the Fort McMurray wildfires in spring 2016.

Sunshine says that as of January 3, the project has achieved production of 2,200 bbls/d.

This is a significant jump from previous production rates. According to data from the

Cancelled: KOCH MUSKWA Koch has asked that the Alberta Energy Regulator (AER) rescind approvals for the proposed Muskwa SAGD project, citing economic and regulatory uncertainty for the decision.

The company received regulatory approval for the 10,000-bbl/d project in June 2014.

“Koch Oil Sands Operating ULC does not believe the current nor medium-term

economic environment in Alberta will provide opportunity to generate an adequate return on the required capital for construction of the Muskwa SAGD project,” Koch vice-president Byron Lutes wrote in a letter submitted to the AER. “The longer-term risk of the project is further burdened with regulatory uncertainty around the Climate Leadership Program and its potential impacts on the project, from carbon tax to the emissions cap, both recently legislated by the Alberta government.”

Koch views the costs to maintain the approvals in good standing to be excessive when measured against the risk to the project.

In 2016, Koch also withdrew its application for another proposed SAGD project, a phased 60,000-bbl/d facility called Dunkirk.

Planned: KOCH/PENGROWTH SELINA JV Koch Oil Sands has filed an application with the Alberta Energy Regulator for a new 12,500-bbl/d SAGD project owned jointly with Pengrowth Energy.

The project, called Selina, would be located near Pengrowth’s high-performing Lindbergh SAGD project, south of Bonnyville, within the Elizabeth Metis Settlement.

Koch’s application estimates a $512-million capital cost for the project, which is an investment of about $41,000 per flowing barrel.

The application says that construction is expected to take 12 months, starting in late 2018.

Proceeding:

PHOTO: JOE Y PODLUBNY

LINDBERGH SAGD OPTIMIZATION Pengrowth Energy says it will spend $60 million on optimization work at the Lindbergh SAGD project, which is expected to increase production to 18,000 bbls/d by the end of this year, compared to 15,654 bbls/d at the end of 2016.

This includes drilling seven new well pairs and two infill wells, as well as expanding the associated infrastructure.

The $80 million also includes $10 million at Lindbergh on engineering and design for the 17,500-bbl/d Phase Two expansion. By the end of the year, Pengrowth expects the design work to be approximately 70 per cent complete and to be ready to execute on Phase Two as funds become available.

M A R C H 2 0 1 7 • J W N E N E R G Y. C O M • 1 3

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IN REVIEW

// EYES on the OILSANDS “Frankly, for this reason [low oil

“IT’S LIKE SOMEONE TOOK MY SKIN AND PEELED IT OFF MY BODY OVER A LARGE SURFACE…. IT MADE MY BODY ACHE TO WATCH IT.”

prices], and because of longer-term trends toward cheaper renewables coupled with carbon pricing, the oilsands is likely a dead industry…. A lot of players have left, and other production has been mothballed.”

PHOTOS (CLOCK WISE FROM TOP): THOMA SHOMERDIXON .COM; PHOENIX HELI - FLIG HT; BRIAN JE AN; MACLE ANS.C A ; FLICKR / TRUMPVSTRUDE AU; TORONTO STAR

— THOMAS HOMER-DIXON, chair of global systems at the Balsillie School of International Affairs in Waterloo, Ont. grist.org, Jan. 12.

— Actress and activist JANE FONDA, describing the view she got of oilsands mining from a helicopter tour in January. The Globe and Mail, Jan. 18.

“We can’t shut down the “The bottom line: Alberta’s oilsands tomorrow. We need oil and gas industry and the to phase them out. We need people who work in it are the to manage the transition off of best in the world. And we’re our dependence on fossil fuels. not going anywhere, any That is going to take time…. time soon.”

And, in the meantime, we have — Alberta premier RACHEL to manage that transition.”

NOTELY. The Canadian Press, Jan.13.

— Prime Minister JUSTIN TRUDEAU, speaking at a town hall in Peterborough, Ont. The comment sparked outrage in Alberta. The Canadian Press, Jan.13.

“If Mr. Trudeau wants to shut down Alberta’s oilsands, and my hometown, let him be warned: he’ll have to go through me and four million Albertans first.”

— Alberta Opposition leader BRIAN JEAN, whose constituency includes Fort McMurray. The Canadian Press, Jan.13.

“Sometimes I’ll be asked when we’re going to fly over the destruction they’ve been told about, and I’ll tell them we just did…. That’s when they respond with ‘there’s actually a lot of trees here.’ They had prepared themselves to see the ugliest destruction in the world and didn’t see it.”

— Phoenix Heli-Flight owner PAUL SPRING, on his experience touring celebrities and politicians above the oilsands.

Edmonton Journal, Jan. 13.

M A R C H 2 0 1 7 • J W N E N E R G Y. C O M • 1 5

ADVERTISEMENT

10th Annual Fort McMurray

Photos by Joey Podlubny

Thank You Superintendent Rob McCloy, Wood Buffalo RCMP.

Fire Chief Darby Allen, RMWB Fire Department.

Rex Murphy, Keynote Speaker.

HEROES, HEART AND HOME We thank you “from T the bottom of our hearts ”

he sound of bagpipes marked the official beginning of the 10th Annual Oilsands Banquet, honouring the heroes of the great Fort McMurray wildfires.

First responders from across Alberta paraded into the Shell Place Ballroom, filled to capacity in anticipation of the event that featured messages from political leaders from all levels of government including a personal letter from Prime Minister Justin Trudeau, a video message from Premier Rachel Notley and personal thanks from Mayor Melissa Blake.

Allan Adam, Chief of the Athabasca Chipewyan First Nation, brought greetings on behalf of the Athabasca Tribal Council and delivered a very profound message of unity.

“Our home is your home,” he said.

Presenting sponsor of the event was BMO Financial Group, represented by Susan Brown, Senior VP, Alberta & NWT Division, who announced significant new contributions to the community totalling $1.9 million including half-million-dollar donations to the

~ Fire Chief Darby Allen

Fire Recovery Fund of United Way and Habitat for Humanity’s program to help the uninsured and under-insured, respectively. In their 200 year history, this represents the largest donation after a major disaster.

Rob McCloy, Superintendent, Wood Buffalo RCMP, shared his personal story of being half a world away in Paris on May 3rd, and how his team, led by Inspector Lorna Dicks, went above and beyond to execute one of the largest evacuations in Canadian history.

Fire Chief Darby Allen became the face and voice of the unparalleled battle with the fire that he dubbed “The Beast”. He expressed his gratitude to his incredible team of firefighters, mutual aid partners and so many

other professionals who selflessly joined the effort to save the city.

“We thank you from the bottom of our hearts,” he said.

Rex Murphy, well known Canadian commentator and author, as keynote speaker was pithy and personal in his observations of what happened in Fort McMurray on May 3rd and in the days, weeks and months that followed. He highlighted the role that this community and the oilsands industry have played within the Canadian context and that the fire might have helped elevate the truth about Wood Buffalo.

“What I observed was a genuine kind of heroism,” he said.”There is more to you than what we hear. That you’re here now, within a few short months, not with your heads down, is truly emblematic of your spirit, your heart.

Out of the Beast came the Very Best.”

by Russell Thomas

oilsandsbanquet.com

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GOLD

PLATINUM

presented by

INDUSTRY PARTNER

EVENT ORGANIZER

INDUSTRY PARTNER

PRIORITY 1: PRODUCTIVITY

A

fter more than two years of pain across Canada’s oil and gas industry, the market is starting

to show signs of cautious optimism on the back of stabilized WTI prices just over US$50 and positive indications on new

JWN CONDUCTED ITS ANNUAL OILSANDS OUTLOOK SURVEY IN LATE

market access.

2016, FINDING THAT OILSANDS PRODUCERS AND SUPPLIERS WILL

This includes in the oilsands, where

CONTINUE CHASING EFFICIENCY AS THE MARKET STABILIZES

although producers and suppliers are not looking at a return to major growth,

JWN STAFF

Demographics

1

What is your position within the organization?

What is your area of expertise within your organization?

Field employees/Sales 35%

Capital projects/Exploration and development

100–500 19%

12% 8%

Engineering

Management administration 22%

How many employees (both permanent and contract) does your company currently have?

Less than 100 26%

17%

Sales/Business development

Marketing/ Communications/PR/IR

2

20%

Operations/Production

Executives 11%

Professional technical 15%

22%

Other

Other 6%

Analyst/Adviser/ Consultant 11%

3

500–1,000 18%

18 • MARCH 2017 • OILSANDS REVIEW

Greater than 1,001 37%

4%

Administration

3%

Finance/Accounting

3%

Health and safety

3%

Research and development

3%

IT

2%

Supply chain/Procurement

2%

HR

1%

Legal

1%

2 0 1 7 O I L S A N D S O U T LO O K S U R V E Y

they do see revenues increasing and

growth, with 30 per cent expecting

improvements with 28 per cent of

opportunities to improve efficiencies

improved production efficiency to add

survey respondents saying that would

realizing results.

to top line growth. Only 14 per cent are

be their primary investment focus.

This comes as little surprise to

expecting investments in new capital

Just under half of respondents to

Oilweek’s 2017 Oil and Gas Industry

Gord Lambert, the retired Suncor ex-

projects to add to revenues.

ecutive adviser of sustainability and

Like other sectors, almost half of

Outlook Survey who identify as oilsands operators expect revenues to

oilsands players expect to operate

innovation who served on the Alberta

climb in 2017.

largely on free cash flow. However, the

government’s climate change advi-

sector is much more focused on in-

sory panel. Lambert noted recently

vesting that cash flow in productivity

that without a cost reduction and

Only 20 per cent expect pricing across the sector to drive revenue

Business outlook

4

6

How do you expect your organization’s revenue to change in 2017?

Production efficiency

9%

13%

What is the primary source of your revenue increase?

30%

New business opportunities 17%

21%

Growth capital/ Projects

Significant increase in revenue

Slight decrease in revenue

Unsure

Slight increase in revenue No change

5

How will you be primarily financing your operations in 2017?

46%

Free cash flow

23%

Unsure

Equity

Debt

20%

Increase in pricing

41% Significant decrease in revenue

22%

12%

10%

9%

Proceeds from divestitures

14% 10%

Acquisitions

2%

Divestitures

2%

RESPONDENTS EXPECT TO SEE A SLIGHT INCREASE IN REVENUE THIS YEAR, DRIVEN

BY PRODUCTION EFFICIENCY MORE THAN INCREASES IN PRICING. M A R C H 2 0 1 7 • J W N E N E R G Y. C O M • 1 9

2 0 1 7 O I L S A N D S O U T LO O K S U R V E Y

technological change, the oilsands in-

services and supply companies will be

providers will simply have less to offer

dustry is at risk not of shut-ins, but of

to shift gears from new construction

in the sustaining capital marketplace

entering what he calls a “harvest-type

to sustaining projects.

because of the nature of their products

That shift, however, will be easier

scenario” of no growth.

for some companies than others.

But even in a harvest scenario, a lot

“If you’re a services provider

of money will still be needed to sus-

Those contractors that are already

with something to offer on the MRO

tain existing production—an estimat-

established in maintenance and

[maintenance, repair and operations]

ed $30 billion per year by 2020 based

turnarounds may hold an advan-

spend, you’re going to obviously be

on an output of three million bbls/d.

tage over those trying to break into

better off than if you provide over-

One obvious trajectory for oilsands

the field. Many service and supply

burden removal services to the likes

7

What is your organization’s current primary objective when it comes to spending free cash flow?

Paying dividends

Investing in productivity improvements

10% 28%

15% Unsure 20%

27%

Investing in growth projects

Paying down debt

8

and services.

Aside from depressed commodity prices, what are your organization’s most significant growth constraints for 2017?

Slowdown in industry development

24% 20%

Access to markets 14%

Regulatory concerns

13%

Cost containment 8%

Access to capital

7%

Unsure Resistance to application of new technologies/processes

5%

Skilled labour availability

5%

Productivity

4%

Licensee Liability Rating

1%

20 • MARCH 2017 • OILSANDS REVIEW

9

What are your organization’s most significant opportunities for capital spending in 2017?

Maintenance, repair and operations

23%

15%

New capital projects Technology and process improvement

14%

Plant debottlenecking

9%

Unsure

9%

8%

Enhanced oil recovery Exploration and development Company acquisition

7%

5%

Water treatment and steam generation

3%

Public relations and marketing

3%

Emissions management

2%

Other environmental sustainability initiatives

2%

Crude by rail

1%

2 0 1 7 O I L S A N D S O U T LO O K S U R V E Y

of Suncor or Syncrude,” says Maxim

tailing ponds remediation and

broaden our path in the industry,” says

Sytchev, managing director, research

equipment and labour supply. It

Darren Krill, marketing and commu-

at National Bank Financial.

plans to use its track record in front-

nications manager for the Edmonton-

end project work to secure more

based North American Construction

ongoing work.

Group. “For example, this summer

Edmonton-based North American Energy Partners, for example, is

“The way we’ll approach the future

heavily weighted towards front-end

we went to work out at the Red Chris

oilsands project site development.

is to continue to provide our services

Mine [a 30,000-tonne/d open-pit

It also works in support of ongoing

for all of our clients up in the oil-

copper mine] in northwest British

oilsands operations—mine infra-

sands—we work practically on all of

Columbia—so just breaking out of the

structure development, reclamation,

the sites up there—as well as try to

oilsands mold.”

10

12

What other growth opportunities does your organization plan on pursuing in 2017?

Within industry, horizontal integration 35%

Not pursuing growth Within industry, opportunities vertical integration 19%

14%

12%

11%

If your organization is seeking cost savings in the next year, what will be the main source of those savings?

Production optimization

19%

10% 16%

Layoff/Staff reductions Unsure

11

New industry

Adjacent industry

If your organization has been able to reduce costs in the last year, what was the main source of those savings?

Layoff/Staff reductions 44% Production optimization 17%

15%

Unsure Rationalization of business units

14%

Reduction in compensation

10%

Do not plan on reducing operating costs

9%

7%

Consolidating offices

Reduction in compensation 11% Did not reduce operating costs 6% Rationalization of business units 5%

Outsourcing

Supplier discounts

5%

2%

Supplier discounts 5% Unsure 5% Implementing new technologies 2%

Hedging

1%

New suppliers

1%

Refinancing

1%

Outsourcing 2% Consolidating offices 1%

M A R C H 2 0 1 7 • J W N E N E R G Y. C O M • 2 1

2 0 1 7 O I L S A N D S O U T LO O K S U R V E Y

the two big oilsands construction

company, but we’re definitely looking

other services company that depends

projects—Canadian Natural’s Horizon

to regionally expand, and we want to

heavily on greenfield oilsands con-

and Suncor’s Fort Hills—but it’s also

extend the products and services that

struction. The Edmonton-based steel

preparing for the future.

we offer within our industry.”

Privately held Waiward Steel is an-

Waiward has already been working

“Going into 2017 and 2018, we

fabricator currently derives about 70-plus per cent of its $200 million–­

certainly see challenges as the

in Saskatchewan and B.C. It also plans

$300 million in annual revenues

megaprojects in the oilsands obvious-

to expand its debottlenecking, retrofit-

from the oilsands, supplying steel

ly are dwindling,” says Terry Degner,

ting and maintenance services.

and occasional steel erection work.

Waiward’s president. “We’re looking to

Currently, the company is busy with

diversify our services. We’re an Alberta

13

“We might not be selling $200 million in just structural steel and structural

“GOING INTO 2017 AND 2018, WE CERTAINLY SEE CHALLENGES AS THE MEGAPROJECTS IN THE OILSANDS OBVIOUSLY ARE DWINDLING.”

Where do you see oil prices (US$/bbl) going in 2017?

54%

26% 9%

7%

4%

— TERRY DEGNER, president, Waiward Steel $30–$40

$40–$50

$50–$60

$60–$70

$70–$80

Workforce planning

14

If your organization is planning on a net increase of employees in 2017, would the roles be filled primarily by permanent staff or contractors?

15

What was the primary change your organization made to its compensation structure as a result of the market slowdown?

Decrease in base pay No net increase of employees planned 41% Permanent 11% Unsure 14%

Contractor 34%

24%

No changes Decrease in employer benefits

13%

Decrease in variable compensation

10%

Reduced work schedules

10%

Unsure Variable work schedules

22 • MARCH 2017 • OILSANDS REVIEW

35%

5% 4%

2 0 1 7 O I L S A N D S O U T LO O K S U R V E Y

“If they’ve previously been focused

steel services, but when combined

company that is established in anoth-

with other areas of work and main-

er sector or region could provide ready

on construction, they’re now trying

tenance and shutdown work—and I

access to new markets while delever-

to refocus their services on mainte-

don’t know exactly what that would

aging the company from the oilsands.

nance and operating activities in the oilsands,” Gillies says. “They’re also

GMP FirstEnergy analyst Ian

look like yet—we hope to maintain those revenues by getting a bigger

Gillies says that engineering, procure-

trying to shift their demand over to

piece of a smaller pie,” he says.

ment and construction companies

new markets—that is, a greater focus

and small, private oilsands niche

on the Montney and the Deep Basin

part of Waiward’s diversification

service companies will struggle in the

and some of the more prolific natural

strategy. Merging with a like-minded

coming months.

gas plays.”

Mergers or acquisitions may be

Government

16

What should the main role of government be in the energy industry?

Focusing on increasing market access

25%

Developing cohesive energy strategy

22%

Creating the right fiscal, tax and regulatory regimes

20%

Treating energy on par with other industrial products Strengthening First Nations relations on energy projects Establishing an independent and impartial energy information agency Building public awareness and energy literacy

11% 6% 5% 4%

17

Which clean-tech initiatives does your organization participate in?

19%

Next-generation oilsands extraction Heat and/or water recovery from flue gas

15%

Alternative and/or energy-efficient steam generation

12%

Advanced emissions detection, monitoring and mitigation systems

11% 10%

Energy-efficient technologies Alternative low-carbon heat or power technologies

9% 8%

Does not participate

Diversifying the industry

1%

Cleaner technologies for liquefied natural gas production

Establishing a national climate policy

1%

Methane mitigation process

4%

Unsure

1%

Other

4%

Revitalizing and reforming existing regulatory approval mechanisms

1%

Unsure

None of the above

1%

Advanced technology solutions and/or infrastructure for CO2 capture and conversion

5%

3% 0%

M A R C H 2 0 1 7 • J W N E N E R G Y. C O M • 2 3

S AG D C O S T R E D U C T I O N

24 • MARCH 2017 • OILSANDS REVIEW

S AG D C O S T R E D U C T I O N

Competition is tight to get it right as SAGD producers target 50 per cent reductions in well pad costs JIM BENTEIN AND DEBORAH JAREMKO

n the road to globally competitive new in situ oilsands projects in a market where WTI hovers around US$50/bbl, smaller well pads are a critical incremental step.

Producers are already moving on smaller sustaining well pads and throwing around what’s possible, building the lessons that will help the industry move forward with lower cost greenfield facilities in the future.

“While SAGD is still relatively immature, the industry has made great strides in improving its understanding of reservoir performance. As such, new SAGD project designs will likely be more streamlined and require less ‘bells and whistles,’” CIBC analysts Arthur Grayfer, Mark Zalucky and Trevor Bryan wrote in a research report released in January.

“New developments will have smaller central processing facilities, sustaining pads with less metal, fewer valves, less instrumentation and greater automation, which will all serve to lower costs. These new designs will be relatively low risk and will begin to be implemented on the next phase of greenfield developments, likely later this decade (slimmer sustaining pads have already started to be implemented by industry).”

ZERO-BASED DESIGN Suncor Energy, Cenovus Energy and ConocoPhillips Canada have all made recent statements about the success of their well pad reduction programs.

ConocoPhillips has a line of site to a 50 per cent reduction in well and pad costs through standardized designs, executive vice-president Al Hirshberg

M A R C H 2 0 1 7 • J W N E N E R G Y. C O M • 2 5

S AG D C O S T R E D U C T I O N

told the company’s annual investor day in New York in November 2016.

The most dramatic improvements so

“As we move from the previous de-

Cenovus Energy also refers to its new

sign…to the current design, the footprint

well pair and pad design approach as

and height of the facility have been

“zero-base,” which basically means that

far have been realized in well pad surface

reduced dramatically, driving down the

every line item is fair game for review each

facilities, he said.

amount of structural steel, piping and

time a project is executed.

“We’re using a process called zero-based

electrical components required. This

The first redesigned well pad began

design. We question the need for every

has been amazing progress by our Surmont

construction in the third quarter of 2016,

component in the design, and we get rid

team—but they are not done yet. They

Cenovus says.

of it if we don’t need it for a safe, envi-

still have some more ideas, and they

ronmentally sound or reliable operation,”

are well advanced to drive down costs

proach will result in overall cost savings

Hirshberg said.

even further.”

of 35–50 per cent, including 40–60 per

The company expects the new ap-

cent reductions in materials and a five to 20 per cent drop in well pad surface footprint.

Most well pad cost reductions coming from facilities

Suncor also says its greatest well pad cost reductions have been realized in

Pad facilities

surface facilities.

Drilling Gathering and power lines

9% 2%

Completions

In the company’s third-quarter 2016 in-

11%

5%

vestor presentation, Suncor said that before its new pad design program, facilities

Logistics

accounted for 47 per cent of cost. Using

Commissioning 26%

its new design, which has been developed with Wood Group, Suncor says overall well pad costs are expected to drop by up to 50 per cent.

This includes dramatic reductions in engineering hours, field construction hours and manual valves.

“SAGD is still a fairly new technology, but has now matured to the point that design and specification of its component parts can be effectively

Reduced engineering and construction hours 10,000 Historical pad design

8,000 6,000

Reduced number of manual valves

standardized,” says Dean Piquette, well

250

Calgary office.

“Prior to 2014, a large part of the indus-

200

try still believed that one of the keys to success was in ‘build to suit’ design, with

150 New pad design

4,000

all of the associated costs. Wood Group is 100

2,000

50

0

0

Engineering hours

Field construction hours

pad program director in Wood Group’s

proving that the benefits do not outweigh the costs and that a simpler, standardized design is the key.”

Number of manual valves

SOURCE: SUNCOR ENERGY

Ongoing sustaining well pad development is estimated to account for twothirds of a SAGD project’s overall costs, and Wood Group isn’t the only supplier working to get in on the action.

26 • MARCH 2017 • OILSANDS REVIEW

S AG D C O S T R E D U C T I O N

injection process envelopes in the prov-

cators and SAGD plant operators to develop

ince,” Webber says.

projects that incorporate its approach.

“The design incorporates continuous emulsion metering, which is a unique

INTEGRATED THERMAL SOLUTIONS

attribute as far as BlueSteam is aware,

Ashley Leroux and Chad Hadler of Integrated

We question the need for every component in the [well pad] design, and we get rid of it if we don’t need it for a safe, environmentally sound or reliable operation.”

in the well pad design arena. By doing

Thermal Solutions (iTS), a subsidiary of

so, the test separator and its associated

Tundra Process Solutions, are also vet-

piping can be eliminated.”

erans of the SAGD sector who have been

arator is heated up to 200 degrees Celsius.

in five projects at various stages; planning,

— AL HIRSHBERG, executive vice-president, ConocoPhillips

The resulting stresses in piping and ves-

brownfield and greenfield,” Leroux says.

BlueSteam’s approach, initially developed in 2010 in response to a technologi-

focused on cost reduction.

“We were leading innovation during

cal gap identified by SAIT instructor Russ

the pilot days, at the beginning of the

Ritchie, evolved because Ritchie wanted

SAGD industry,” says Hadler, iTS director

to address the limitations and problems

of technical services.

caused by having a test separator in SAGD well pad design.

Although the use of a test separator is

Both Hadler and iTS chief executive officer Leroux have worked in the sector through its relatively short lifespan,

still the standard in SAGD design, some

stretching back to its earliest projects as

metering alternatives to its use have been

far as 1999.

successfully applied.

When test separators are included, there

While iTS hasn’t yet built a next generation well pad, they say interest in the

is a requirement for significant structural

firm’s “bolt-in-and-bolt-out” manufactured

steel and piping loops to accommodate

model is high.

thermal expansion forces, as the test sep-

sels must be accommodated in the design.

“When the test separator concept is

“We’ve been asked to become involved

The company’s approach is based on the simple premise that “90 per cent of

replaced with continuous emulsion me-

the cost is spent on procurement, fabrica-

BLUESTEAM WELLPAD SOLUTIONS

tering, the job of the piping designer and

tion and construction, so our fabricators

Privately owned BlueSteam WellPad

piping stress engineer requires skillful

and constructors played a large role in the

Solutions is one of the lesser-known players

innovation to enable the main process

design,” Hadler explains, adding that the

in the well pad space, but its eight principles

headers on the well pad to expand and

iTS system results in pads that don’t need

have extensive SAGD design and operations

move independently, without restraint,”

to be redesigned every time, overtime

experience, stretching back to 1998.

Webber says.

costs are not required and engineering

BlueSteam, like its competitors, takes a

When that is achieved, the require-

costs virtually go away.

standardized design approach to well pad

ments for structural steel, piling and

development and is targeting surface fa-

piping are dramatically reduced, which

surface costs through its dual parallel row

cility infrastructure reductions, but with a

leads directly to reduced fabrication

drilling technology.

key difference.

and construction costs, according to

President Tim Webber and civil, struc-

BlueStream.

iTS is also targeting reductions in sub-

“It allows the operators to drill in multiple different directions from the same

“We spend more money on instrumen-

surface location,” says Leroux. “It increas-

the company’s inclusion of continuous

tation, but the amount of money saved on

es the reservoir coverage by 300 per cent.”

emulsion metering in its design helps

pipe, steel foundations and the footprint

distinguish it from the competition.

of the package are each greatly improved,”

hundreds of millions of dollars in costs

Webber says.

can be saved.

tural, architectural lead Dave Vrkljan say

“BlueSteam’s approach has been to create a standardized design that covers the majority of SAGD wellpair production/

The company is working with component providers, service companies, fabri-

With fewer wells needing to be drilled,

“Everyone is focusing on well pad design, but you also need to take a more

M A R C H 2 0 1 7 • J W N E N E R G Y. C O M • 2 7

S AG D C O S T R E D U C T I O N

global approach to drilling and completions and infrastructure that goes with the well pad,” says Leroux.

The approach should stretch the life span of a SAGD well pad, keeping the facilities and infrastructure fully utilized, since it allows for a wider area to be developed.

“They can sweep the reservoir, from existing locations,” says Leroux.

Because a wider area of the reservoir is accessed, the surface facilities don’t need to be as large.

“We can help operators save 60 per cent of the wellhead and infrastructure footprint needed for a project,” Hadler adds.

No dramatic changes are required to adapt to the approach, since iTS designed it as a “bolt-on” technology to work with longer well laterals and flow

This schematic shows the difference between two Wood Group SAGD well pads. The company says the latest design features a a significant reduction of bulk materials and equipment, removes the central spine and places the equipment and instruments on a module near the well head.

control devices.

The idea is to start with a base design that allows for flexibility and then bolt-on

be cost competitive utilizing previous de-

Group approach, that has been reduced to

options, which is why the DPR drilling

signs; they simply won’t be building new

six modules per pad. Piping and instrumen-

technology is also an available option.

pads under the old cost structure.”

tation has been cut substantially as well.

Previously producers might have spent

In the same way that no Ford F-150

as the inclusion of solvent-assisted pro-

$100 million on a large well pad. Wood

model suits all, the company is developing

cesses, is as easy as turning a wrench,”

Group believes it can slash that down to

a next generation well pad for SAGD pro-

Leroux says.

between $25 million and $30 million for a

ducers with slant wells that are inspired

10 well pair pad. And it has found a way to

by the company’s global experience de-

WOOD GROUP

reduce the direct facility module costs of

signing facilities for offshore and subsea.

Wood Group also has extensive SAGD

each well pair to around $1.5 million.

Wood Group, which has built a prototype

One key is that it has reduced the

well pad facility at a site in Calgary, contin-

and in situ oilsands experience, including long relationships with Canadian

footprint of the well pads by substantially

ues to make subtle changes to its design

National Resources, Cenovus Energy and

reducing the module count. By doing that,

and the interaction with the wellhead

Suncor Energy.

significant cost savings are realized as

as part of its continuous improvement

less earthwork needs to be prepared, the

approach. For example, by optimizing the

scribes the company’s standardized well

regulatory process is streamlined and

valves and cable trays, it saved an addition-

pad design approach “industry proven.”

many other costs are stripped away.

al $300,000 from the previous design.

Well pad program director Piquette de-

The 2017 model of the approach,

Piquette says the previous approach

Given the firm’s success in reducing

which has been implemented at Suncor’s

used by owner companies to well pad

costs, one might think orders would

Firebag facility, offers significant cost and

development essentially involved an

be lined up. That’s not quite the case,

operability improvements over previously

“over-engineered” design.

largely because the emphasis has been

installed pad infrastructure, Piquette says.

For instance, previous well pads were

on slashing capital spending to the bone.

designed to operate for 30 or more years

But Rempel said potential customers are

says Scott Rempel, vice-president of

instead of the more common 12–15 year

showing much more interest in the firm’s

business development in Wood Group’s

lifecycle. Previous pad designs required 27

design approach, as freezes on capital

Calgary office. “Owners will struggle to

modules to make a pad, but with the Wood

spending start to thaw.

“It’s vital that the industry do that,”

28 • MARCH 2017 • OILSANDS REVIEW

IMAG E: WOOD G ROUP

“Adding pre-engineered options, such

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Shell Canada Limited Shell Canada Limited has signed a Compliance Agreement with the Commissioner of Canada Elections regarding non-compliance with subsection 132(1) of the Canada Elections Act. The text of the Compliance Agreement is available on the Commissioner’s website at www.cef-cce.gc.ca.

Shell Canada Limited acknowledges that, on October 19, 2015, Shell employees working at Shell Albian Sands (SAS), who were qualified electors, were not provided the legislated time off work for the purpose of casting their vote during the 42nd federal general election. This decision was made based on a mistaken, though good faith, belief that Shell Canada Limited had fulfilled its obligations in the circumstances because these employees, otherwise scheduled to work on polling day, had been provided the opportunity for paid time off and transportation to an advance polling station on October 12, 2015 for the purpose of casting their votes.

Shell Canada Limited acknowledges that while it had a short term leave policy in place for the purpose of allowing employees paid time off to vote during elections, the policy did not specifically state that employees who were qualified electors were entitled to paid time off to allow them to have – during voting hours – three consecutive hours in which to vote during polling day for a federal election. Prior to entering into the Compliance Agreement, Shell Canada Limited adopted a new and more detailed policy with respect to voting rights of its employees to better ensure compliance. Shell Canada Limited’s new policy has been reviewed and approved by the Commissioner of Canada Elections.

Shell Canada Limited acknowledges that the approach taken to employee voting at SAS during the 42nd federal general elections was contrary to subsection 132(1) of the Canada Elections Act and accepts full responsibility for these acts.

Shell Canada Limited undertakes to implement each of the Compliance Agreement’s terms and to comply with the relevant provisions of the Canada Elections Act in the future.

This notice is published in accordance with the above mentioned Compliance Agreement.

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TA I L I N G S M A N AG E M E N T

Oilsands miners look to fine-tune tailings technology under encouraging new regulations LYNDA HARRISON

A

lberta’s new, more flexible rules for how oilsands mines manage their tailings ponds are expected to result in some “cool,” fresh ways to treat water and waste.

“We’re going to see the opportunity to implement a lot of the learnings of the past two or

three decades in some major pilot projects and even some commercial demonstrations that might not have been possible under the old directive,” says Randy Mikula, who has spent more than 30 years researching how to improve oilsands technology. “People were boxed in.”

Meeting a Nov. 1, 2016, deadline, oilsands companies have submitted their tailings management plans to comply with Directive 085: Fluid Tailings Management for Oil Sands Mining Projects, issued last summer by the Alberta Energy Regulator (AER).

The Government of Alberta released the Lower Athabasca Region: Tailings Management Framework for Mineable Athabasca Oil Sands (TMF) in March 2015. As a result, the AER suspended Directive 074: Tailings Performance Criteria and Requirements for Oil Sands Mining Schemes and developed new requirements for tailings management, including the new directive.

M A R C H 2 0 1 7 • J W N E N E R G Y. C O M • 3 1

TA I L I N G S M A N AG E M E N T

Timeline of tailings reclamation (example: terrestrial and wetland ecosystems) Stage 1: Filling the dedicated disposal area with non-segregating tailings. Mature fine tailings spiked non-segregating tailings starts.

Stage 2: Settling and consolidation of non-segretating tailings.

Mature fine tailings spiked non-segregating tailings deposits.

non-segregating tailings line

Capping tailings line

On trajectory to meet ready-to-reclaim stage

60 to 65% solids

Non-segregating tailings deposition occurs in mined out pit and is the final location of the landscape.

Stage 3: Capping with sand or high sand-to-fines ratio non-segregating tailings.

Non-segregated tailings settling and consolidation occurs and is on trajectory for ready-to-reclaim rate.

According to the AER, the major difference between

oilsands extraction and tailings, but

the two directives is that the old one was much more

with a focus on environmentally

prescriptive, measuring operators’ tailings reduction

responsible development of the

performance on only one requirement—the strength of

resource.

Target ≥ 70% solids

Ready-to-reclaim rate is achieved when the non-segregated tailings solids content is greater than or equal to 70 per cent and hydraulic capping can be initiated.

It turns out the Alberta government is doing just that.

“Returning treated tailings into rivers in Alberta would need

the mature fine tailings—while the new directive uses

“It’s always been about water

the overall volume of fluid tailings to track reductions.

management and the old directive

standards. Development of these

didn’t recognize that,” he says. “There

standards is currently under-

was a big disconnect. Now, Directive

way,” says Brent Wittmeier, press

Five oilsands producers operate a total of seven mines and 25 tailings ponds.

to meet stringent water quality

“In terms of their operations and the money they’re

085 is actually linked with what the

secretary to Shannon Phillips,

spending, [the directive] is not necessarily that differ-

industry has to manage, and that is

Minister of Environment and Parks.

ent,” says Mikula.

volumes. In terms of how compa-

“Technology may improve treatment

nies are going to operate, I think it’s

of tailings, but any technique would

effect on industry, he believes the greater impact will

opening up a lot of doors, we’re going

need to be proven, meet the highest

be on society.

to see a lot more innovation than we

environmental standards and miti-

would have under the old directive.”

gate risks on a case-by-case basis.”

cietal impact, it is going to have that kind of impact. We’re

DISCHARGING TREATED TAILINGS WATER

PEMBINA CAUTIOUSLY OPTIMISTIC

going to see—in my view anyway—a lot more cool things

Oilsands tailings water volumes con-

Directive 074 was an ambitious

being implemented in terms of tailings management.”

tinue to accumulate in part because

policy, but its major failure was in

currently there is a zero discharge

enforcement and the industry and

policy back into the Athabasca River.

the regulator being overconfident

Unless the government comes

in technologies, says Jodi McNeill,

While he allows the new directive will have some

“We’re going to see much more positive tailings management initiatives being implemented by the industry, so whether you call that an industry impact or a larger so-

That’s because companies will now concentrate on volume instead of strength. Really, tailings management has always about volumes, says Mikula.

As leader of the oilsands extraction and tailings

up with some kind of criteria that

technical and policy analyst with

group at the Natural Resources Canada (NRCan)

allows the industry to treat and dis-

the Pembina Institute.

research station in Devon, Alta., Mikula was heavily

charge water, Mikula says there is

involved in the development of a variety of novel ex-

no tailings technology on the planet

is in favour of the new directive, it

traction and tailings technologies used in the industry.

that is going to change the volume

continues to have concerns about

situation. “Then we’ll start to see

compliance and enforcement, as

some real progress,” he said.

well as about policy gaps in the rules

He left NRCan in 2011 to found Kalium Research, a start-up company that is continuing research on

32 • MARCH 2017 • OILSANDS REVIEW

She says that while Pembina

TA I L I N G S M A N AG E M E N T

Stage 4 A: Terrestrial reclamation of deposit.

Timeline of water content:

Stage 4 B: Wetland reclamation of deposit.

2020

High

Stage 1

Stage 2

2030 Medium Target ≥ 81% solids

Water quality to support wetlands

2031

Deposit may become a wetland area when solids content reaches greater than or equal to 81 per cent and meets requirements for wetlands reclamation.

2035+

Cover soil

Deposit has achieved ready for reclamation rate with solids content greater than or equal to 81 per cent and meets requirements for terrestrial reclamation.

Stage 3

Low

Stage 4

Source: Canadian Natural Resources

surrounding reclamation timelines,

and it will ensure that those results

three main technologies already in use: composite

which it says range from 10 years to

are clearly reported to the public.

tailings, water capping and centrifuge.

70 years after the end of mine life.

The regulator’s enforcement tools

Meanwhile, the company is researching several

include more frequent and detailed

other technologies that are in various stages. They

enforcement and how the directive

inspections, more stringent planning

include accelerated dewatering, overburden mixing

is being implemented, but essential-

requirements, enforcement orders,

(pilot projects were completed in 2014 and 2015) and a

ly we just want to see the objectives

shutting down operations, adminis-

thickener that uses a cyclone separator. Their results

of the [TMF] met so our concerns

trative penalties and prosecution.

will be shared with other oilsands mining companies

“We do have concerns in terms of

through Canada’s Oil Sands Innovation Alliance.

really relate to that,” says McNeill.

“In theory, we are supportive.”

FINE-TUNING TECHNOLOGIES

“Our goal is to ensure that we have as many differ-

None of the mining companies have

ent suites of technologies as possible,” says Syncrude

to be highly flexible in permitting

proposed radically new technol-

spokesman Will Gibson.

companies to design their own fluid

ogies to comply with 085. Rather,

tailings treatment criteria, Pembina

they are fine-tuning what they have

number of arrows in the quiver, so to speak, when

strongly recommends that the

been doing all along, says Mikula,

they’re looking at ways to manage tailings and ensur-

AER delineate a stringent and rigid

adding some of the technologies

ing that we’re meeting the public expectation on that,

regime for compliance and en-

that were specifically about strength

as well as government regulations.”

forcement “to regain the trust of the

development under the old directive

public following the lack of enforce-

are going to play a smaller role com-

ment of Directive 074.”

pared to the ones that are address-

Since Directive 085 was designed

“We want to see some hard stops [regarding] what the penalties are

ing volume.

“This is going to help our mine planners have a

Syncrude has invested $3 billion to manage its tailings— a large part of it on its $1.9-billion centrifuge plant.

“We’re making significant investments to address public expectations in this area,” Gibson says.

Composite tailings, consolidated

going to be for non-compliance so

tailings, non-segregating tailings—

SUNCOR

that stakeholders and the public can

every company has a different

Suncor Energy is proposing the addition of an in-mine

be watchdogs and make sure that

name for what is essentially the

dedicated disposal area (DDA) to its tailings reduction

enforcement is actually happening

same material, he says.

operations. The in-mine DDA will use similar treat-

this time around,” says McNeill.

The AER says performance-

ment technology as its current DDA and will be water

SYNCRUDE

monitoring requirements will be put

To comply with the directive,

in place to keep industry on track

Syncrude Canada’s plans to use its

capped for closure.

According to Suncor’s application, the main benefits of the proposed plan are that it provides

M A R C H 2 0 1 7 • J W N E N E R G Y. C O M • 3 3

TA I L I N G S M A N AG E M E N T

development, demonstration and

“We’re going to see a lot more cool things being implemented in terms of tailings management.”

— RANDY MIKULA, research scientist with Kalium Research, ASTech Award-winning oilsands tailings researcher

deployment.

It is estimated that all Horizon legacy fine tailings will be treated by the end of 2032. Mining of the last pit at the project is planned to be completed by 2055. By 2065, all new tailings will be treated and the dedicated disposal areas and end pit lakes will be ready to reclaim, as required by Directive 085, says the company’s application.

IMPERIAL OIL Key changes between Imperial Oil’s previously approved tailings management plan, approved in June 2013, and its current one include the addition of a mix box and secondary thickened tailings chemical treatment to the flotation tailings thickeners, as well as replacement of the layered thickened tailings and coarse sand tailings deposition plan with a multi-layer, additional treatment capacity below grade, allows the

a supplemental tailings treatment

deep, ready-to-reclaim deposit

water released from the treated tailings to be collected

technology starting in 2020.

of secondary, chemically treated

The tailings management plan

tailings are treated in a more sustainable manner and

includes two end pit lakes to store

with no additional land disturbance.

residual fluid tailings at the end of

In addition, this plan increases the reliability of fluid tailings treatment by reducing the reliance on

the mine’s life.

The company is currently using

thickened tailings.

PHASE 2 OF THE NEW DIRECTIVE ISSUED The AER is planning to review tail-

weather-dependent processes and allows future flex-

NST technology at its Horizon mine.

ings management plans every five

ibility to add more treatment capacity while allowing

The technologies currently being

years to ensure the tailings profiles

for progressive reclamation, it says.

investigated by Canadian Natural,

and thresholds align with projec-

either as improvement of existing

tions and reflect current technology,

SHELL

technologies or development of new

new knowledge and continuous

Shell Canada says it will use thickened tailings and

technologies, are: the enhancement

improvement.

centrifuged tailings technology for tailings man-

of NST performance, improvement

agement and reclamation plans at its Muskeg River

of mature fine tails spiked NST

winter reviewing tailings manage-

and Jackpine mines, while Muskeg River will also

performance, development of new

ment applications for each oilsands

employ fluid fine tailings drying and atmospheric

mature fine tails treatment technol-

operation, recently posting a revised

fines drying.

ogies (semi in-situ mature fine tails

version of Directive 085 with up-

treatment) and end pit lakes.

dated surveillance and compliance

CANADIAN NATURAL RESOURCES

These technologies are in differ-

The regulator has spent the

processes for stakeholder feedback.

Canadian Natural Resources proposes to use mature

ent stages of maturity and imple-

A finalized version of the directive is

fine tailings spiked non-segregating tailings (NST) as

mentation ranging from discovery,

to follow in the spring.

34 • MARCH 2017 • OILSANDS REVIEW

PHOTO: SYNCRUDE

and recycled in Suncor’s operations and that the fluid

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C OV E R S TO R Y

Don’t read too much into recent oilsands asset

While the oilsands sector is still licking its wounds

sales—the companies that dominate the sandbox

from the fallout of the oil price collapse, the ability of

are staying and FIGURING OUT how to get bigger PAUL WELLS

the industry to confront market challenges head-on by reducing costs, deploying new technologies and streamlining operations has set up 2017 to be a year of stabilization as oil prices stay firm in the US$50/bbl range and large-scale projects sanctioned prior to the downturn near completion.

M A R C H 2 0 1 7 • J W N E N E R G Y. C O M • 3 7

C OV E R S TO R Y

Greg Pardy, the Toronto-based co-head of global energy research for RBC Capital Markets, says that despite some companies

that you’re going to see massive changes

because of the very different period that

coming,” he says.

we’re still in, although it’s not as bad as

Jackie Forrest, vice-president, energy

last year,” Forrest says.

“It’s got nothing to do with the oilsands.

like Norwegian giant Statoil, U.S.-based

research at ARC Financial in Calgary, says

Murphy Oil and French juggernaut Total

industry observers shouldn’t read too

All [producers] are trying to find out how

selling off oilsands assets over the past few

much into companies like Statoil, which

they can reduce their costs and in many

years, the composition of players in the

sold its oilsands assets to Athabasca Oil

cases picking your core areas and getting

sector is unlikely to undergo any massive

Corporation for C$832 million in December,

larger in those areas can reduce your

changes in the near- to mid-term.

exiting the sector.

costs.... It’s really no different than, say,

“I think we’re going into a period of

In fact, she says that deal and others

what’s happening in the Montney. If you’re

relative calm. I think the large players

that have occurred in the oilsands are

going to be the low-cost supplier, scale

will remain the large players. I think the

more reflective of a global trend that is

matters. I think you will see companies

resource now has been spoken for, by and

seeing producers worldwide narrow their

work to get more consolidation in order to

large. So my sense is you will not see a big

investment focus and shed assets that no

get their economies that come from great-

shift. If anything, the larger companies

longer fit their respective portfolios.

er scale,” she says, adding that there could

become bigger at the margin. But I don’t think over the next two or three years

“Globally, we’re seeing companies sort of change the assets that they own

be more consolidation in the oilsands market in order to bring down costs.

PHOTO: DEBOR AH JAREMKO

Future growth in the oilsands is expected to come largely from advances in technology that continue to drive down capital and operating costs at in situ projects.

38 • MARCH 2017 • OILSANDS REVIEW

C OV E R S TO R Y

per cent this year, Forrest says 2017 capital

For his part, Pardy doesn’t expect an uptick in merger and acquisition activity

expenditures in the oilsands are expected

in the oilsands this year.

to decline by about 18 per cent year-over-

“I don’t think so. That’s not to say there won’t be one-off transactions—you never know, with Imperial Oil in particular. The oilsands has almost become the sandbox of the big companies that have big balance sheets and the financial diversity to carry through projects over a relatively

“

the edges.”

I think the industry is going to adapt to this because otherwise it’s hard to see a lot in the way of further growth.”

WHILE INDUSTRY CONDITIONS ARE

— GREG PARDY, co-head of global energy research, RBC Capital Markets

long period of time,” he notes.

“In the oilsands, certainly given the inherent operational risk and the time it takes to bring those barrels on, certainly now is not the kind of pricing environment where I think that a lot of companies are going to take on very large projects.

“The consolidation then comes back to smaller companies selling their assets. I think you might have one-off situations where that can make some sense. But broad consolidation would surprise me.

I think we’re probably going to stay with the status quo, with transactions around

year to about $13 billion. That’s a level she notes is down from a peak spending of around $34 billion in 2013.

“So I think the future for the oilsands this year and over the next few years is going to be quite a bit lower spending and not the $30-billion a year or so that we were used to,” she says.

“There’s always going to be some spending just because the maintenance requirements alone require spending in the range of close to $10 billion just to maintain the existing oilsands facilities. We may [also] see some brownfield expansion­ type spending and some capacity added because of that,” Forrest adds.

“But we don’t see a large wave of the big megaprojects obviously that we saw through 2010 through 2014. It’s going to be a much slower rate of spend.”

Pardy and RBC think producers need about US$60/bbl WTI to lead to new brownfield oilsands expansions.

“What we’ve been seeing in the last few months with budgets, whether it’s

IMPROVED, SPENDING NOT EXPECTED

[Canadian Natural Resources’s] Kirby or

TO RISE While some companies have unloaded

we don’t have any big megaprojects com-

Christina Lake G with Cenovus, is essen-

oilsands assets or put the brakes on future

ing behind them that will fill in the void.”

tially those are very different decisions

expansion projects, others, such as Suncor

A handful of oilsands megaprojects are

because they have had some capital in

Energy, Canadian Natural Resources,

nearing completion. By the end of the year,

those projects and at some point they

Cenovus Energy, Imperial Oil and MEG

Suncor’s 180,000-bbl/d Fort Hills mine

were going to do them,” he says.

Energy have sent strong signals they are all-

should be producing, as well as Canadian

in by either bulking up their holdings or by

Natural’s 80,000-bbl/d Horizon Phase 3

ronment at which they want to see those

announcing shorter-cycle expansion plans.

project, the 50,000-bbl/d Sturgeon Refinery

through to completion. And certainly in

and the 20,000-bbl/d Hangingstone SAGD

the cost environment we’re in right now,

ments from Cenovus, for example, that

expansion owned by Japan Canada Oil

the economics look extremely favourable

they’re doing some projects—re-starting

Sands and Nexen.

to getting that stuff done.”

“There have been some announce-

projects that were partly finished and

“So the oil price now is in the envi-

A number of SAGD projects have also

things like that,” Forrest says. “So we do

recently made their debut and are ramping­

REDUCING BREAK-EVEN COSTS WILL

expect some new projects, but they’re just

up, including Cenovus Energy’s Foster Creek

CONTINUE TO BE A FOCUS IN 2017

not big enough to offset the loss of some of

Phase G (30,000 bbls/d) and Christina Lake

Forrest calls the ability of some oilsands

the big ones like Horizon and Fort Hills.

Phase F (50,000 bbls/d), ConocoPhillips

operators to reduce their break-even costs

Canada’s Surmont Phase 2 (118,000 bbls/d)

over the past two years “incredible.”

“We actually expect spending to decrease this year from the previous year and that’s basically because the big oilsands projects like Fort Hills are wrapping up and

and Husky Energy Sunrise (60,000 bbls/d).

“I wouldn’t say Cenovus is alone, but I

While ARC is projecting non-oilsands

had a quote from the company that said

spending to increase by approximately 40

they are now estimating a 35–50 per cent

M A R C H 2 0 1 7 • J W N E N E R G Y. C O M • 3 9

C OV E R S TO R Y

Inside a once-through steam generator at an oilsands SAGD project.

costs—should be coming down, as well,” Pardy adds.

“I think the industry is going to adapt to this because otherwise it’s hard to see a lot in the way of further growth unless the costs continue to come down. We expect oil prices to move higher as we move into the balance of the decade, but that’s not $100. That’s conceivably moving into the 60s and 70s as we get into 2019 and 2020.” reduction in size and cost of their new

to demand or what service providers are

well pads and that they are now estimat-

going to demand.

“It’s a very, very unique set of circum-

ogy advancement in the oilsands, saying

is $20 below what it was in 2015. That’s

stances that we are in right now and I

new and emerging technologies should

pretty phenomenal,” she says.

don’t think they are going to last. The

ultimately lower the supply cost for in situ

“So from that perspective it’s compa-

costs tend to be pro-cyclical—as prices go

recovery and make oilsands growth more

rable to some of the tight oil economics

higher, costs are going to go higher with a

competitive on a global stage.

that we’re hearing about. But I think the

lag. It’s just a matter of time.”

CIBC says that there is now visibility for economic oilsands growth in a US$50/

challenge is still the style of investment associated with the oilsands—it’s still that

ADVANCING A LOWER-COST FUTURE

longer cycle.”

THROUGH NEW TECHNOLOGY

bbl world.

“The goal for oilsands producers

Pardy notes that the oilsands sector’s

today is to lower supply costs and im-

continued pursuit of technological

prove environmental stewardship while

advancements and operational improve-

supporting oilsands development,” the

people might think. I think the go-forward

ment bode well for the health of the

analysts wrote.

economics with Cenovus’s Christina Lake

industry going forward.

But is the current and improved cost structure sustainable? Pardy isn’t so sure.

“I think it’s probably more fragile than

G was $16,000–$18,000 per flowing barrel

“The other piece is, and what’s key not

“These goals will be achieved by a spectrum of applications, ranging from simply

per day to complete that project. That’s

to lose sight of, is what’s going on with

better ways of doing things with less steel

unheard of, right, for an oilsands project

technology advancements, whether that’s

and fewer energy inputs to radically new

[in the last decade]. But it’s taking advan-

a move into solvent-aided SAGD or what’s

recovery schemes.”

tage of a severe drop in activity and proba-

going on with [MEG Energy’s] Christina

bly not much of an expectation for a lot of

Lake eMSAGP and so on,” he says.

activity in the near term, either,” he says.

“I think that with the next set of proj-

CIBC’s analysis suggests that in the next five years, greenfield oilsands development will be able to earn a 15 per cent

ects, which are probably more towards

rate of return in a US$50/bbl oil world,

and you have two or three projects that

the end of the decade, probably solvents

and that Alberta’s emission cap may not

start to come in. I think that labour market

will figure more highly into those. The gas

“hinder development in the next decade

tightens up faster than what we would

intensity will probably go down, which is

as conventional thinking believes, both of

expect. Not enough to blow the economics

favourable from a CO2 emissions stand-

which point to the belief that oilsands, and

up, but certainly I think it would contrib-

point as well, but more importantly the

not just higher quality oilsands, will not

ute to re-marking of what labour is going

capital intensity—therefore the break-even

necessarily be a stranded resource.”

“All of a sudden you start to staff-up

40 • MARCH 2017 • OILSANDS REVIEW

PHOTO: JOE Y PODLUBNY

ing a $35–$50/bbl WTI break-even, which

In a January research note, CIBC analysts echoed the importance of technol-

Inform.

Connect.

Grow.

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OILSANDS DATA O P E R AT I O N S BY T H E N U M B E R S

Alberta crude bitumen and synthetic crude production Crude bitumen 50,000

Bitumen royalty valuation at Hardisty, Alta.

OCTOBER TOTALS

Synthetic crude

Calculated using NetThruPut monthly WCS index $35

2015 2016

2016

$29.65

2015

45,000

$30

40,000 $25

47,539,200 BBLS or 64% 27,041,600 BBLS or 36%

30,000

74,580,800 BBLS total

US$/bbl

Thousand bbls

35,000

25,000 20,000

2016

15,000

$20 $15 $10

10,000 5,000

$5

47,353,500 BBLS or 58% 34,358,100 BBLS or 42%

0 S

O

N

D

J

F

M

A

M

J

J

A

S

$0

81,711,600 BBLS total

O

Natural Gas: Spot prices at AECO trading hub in Alberta

J

F

M

A

M

J

J

A

S

N

D

North American carbon steel prices

Monthly averages to Jan. 18, 2017

Hot rolled coil

$4.00

$800

2016 2017

Structural sections and beams

Reinforcing bar

2016

$701

$3.50 $700

$3.00

$670 US$/tonne

$3.02

$2.50

C$/GJ

O

$2.00 $1.50 $1.00

$600

$500

$533

$400

$0.50 $300

$0 FEB

MAR

APR

MAY

JUN

JUL

AUG

SEP

OCT

NOV

DEC

JAN

JAN

FEB

MAR

APR

MAY

JUN

JUL

AUG

SEP

OCT

NOV

Mined oilsands bitumen production Current 3 month avg. (July 2016-September 2016)

BIGGEST MOVER

Previous 3 month avg. (April 2016-June 2016)

Suncor Energy - Base Operations

Suncor Energy Inc. - Base operations

227,052 (From 67,479 to 294,531)

Imperial Oil - Kearl Syncrude Canada - Aurora North & South Canadian Natural Resources Limited - Horizon

TOTAL MINING AVERAGE

Shell Canada - Muskeg River Syncrude Canada - Mildred Lake

Current three months

Previous three months

1,236,405

840,721

Shell Canada - Jackpine 0

50,000

100,000

150,000

200,000

Production (bbls/d)

42 • MARCH 2017 • OILSANDS REVIEW

250,000

300,000

350,000

DEC

O I L S A N D S DATA

Alberta synthetic crude oil production Current 3 month avg. (July 2016-September 2016)

BIGGEST MOVER

Previous 3 month avg. (April 2016-June 2016)

Syncrude Canada - Mildred Lake

Suncor Energy Inc. - Base operations

252,000 (From 87,693 to 339,693)

Shell Albian Sands - Scotford Upgrader Syncrude Canada Ltd. - Mildred Lake

TOTAL MINING AVERAGE

Canadian Natural Resources Limited - Horizon CNOOC Limited - Long Lake

SHUT DOWN INDEFINITELY

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

Current three months

Previous three months

1,008,528

517,087

Production (bbls/d)

Top 10 thermal oilsands projects bitumen production Current 2* month avg. (October 2016-November 2016)

BIGGEST MOVERS

Previous 3 month avg. (July 2016-September 2016)

Canadian Natural Resources Limited Primrose & Wolf Lake

Suncor Energy Inc. - Firebag Imperial Oil Limited - Cold Lake

ConocoPhillips Canada Limited Surmont

Cenovus Energy Inc. - Christina Lake Cenovus Energy Inc. - Foster Creek Devon Canada Corporation - Jackfish

Cenovus Energy Foster Creek

Canadian Natural Resources Limited - Primrose & Wolf Lake

23,880.02

from 61,985.03 to 85,865.05

14,001.77

from 84,280.93 to 98,282.70

13,309.13

from 147,710.97 to 161,020.10

MEG Energy Corporation - Christina Lake ConocoPhillips Canada Limited - Surmont

TOTAL MINING AVERAGE

Canadian Natural Resources Limited - Kirby South

Current two months

Previous three months

1,140,101.2

1,073,495.8

Suncor Energy Inc. - Mackay River 0

50,000

100,000

*Data for December 2016 not available at press time

150,000

200,000

250,000

Production (bbls/d)

Lowest 10 thermal project steam to oil ratios Current 2* month avg. (October 2016-November 2016)

BIGGEST MOVERS

Previous 3 month avg. (July 2016-September 2016)

Cenovus Energy Foster Creek

Cenovus Energy Inc. - Christina Lake

-0.25

from 2.61 to 2.36

Devon Canada Corporation - Jackfish ConocoPhillips Canada Limited Surmont

MEG Energy Corporation - Christina Lake Cenovus Energy Inc. - Foster Creek Pengrowth Energy Corporation - Lindbergh Pilot

Devon Canada Jackfish

Canadian Natural Resources Limited - Kirby South

-0.23

from 3.53 to 3.30

-0.08

from 2.26 to 2.18

Statoil - Leismer Demonstration TOTAL MINING AVERAGE

Suncor Energy Inc. - Firebag Suncor Energy Inc. - MacKay River

Current two months

Previous three months

2.55

2.55

ConocoPhillips Canada Limited - Surmont 0

*Data for December 2016 not available at press time

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

Steam injected:oil produced

M A R C H 2 0 1 7 • J W N E N E R G Y. C O M • 4 3

O I L S A N D S DATA

FirstEnergy oilsands, integrated and large cap indexes Oilsands 120

Integrated

Large cap

CHANGE SINCE Jan. 19, 2016

Recorded until Jan. 19, 2017

2015 2016

2016 2017

INTEGRATED

18.47 48.58 9.66

$93.45 100 80

LARGE CAP $84.89

60 40

OILSANDS 20

$24.62

0 DEC

JAN

FEB

MAR

APR

MAY

JUN

JUL

AUG

SEP

OCT

NOV

DEC

JAN

Index launched Jan 1, 2007. FirstEnergy complimentary indexes are available daily on the homepage at firstenergy.com. FirstEnergy Capital Corp. is a member of the Canadian Investor Protection Fund and IIROC.

Crude oil differential: WTI-WCS

25

20

20

$13.60 15

15

10

10

5

5

JANUARY 2017 $14.67

2016 2017

JANUARY 2016 $14.80

2015 2016

DECEMBER 2016 $15.93

Differential: West Texas Intermediate to Western Canadian Select (US$/bbl)

25

DECEMBER 2015 $14.30

MONTHLY AVERAGE

Recorded until Jan. 20, 2017

0

0 DEC

JAN

FEB

MAR

APR

MAY

JUN

JUL

AUG

SEP

OCT

NOV

DEC

JAN

DEC

JAN

FIRSTENERGY CRUDE DIFFERENTIALS UPDATE The Canadian crude oil market began the new year much the way it began the previous year, with rising production and steady price differentials.

In fact, price spreads for all grades of Canadian crude oil have remained remarkably steady for more than 18 months. Going forward, we expect more of the same as the industry continues to have options to move rising supply to market.

We continue to expect the reemergence of crude by rail. We expect the cost of moving barrels from Alberta to the U.S. Midwest or the Gulf Coast— which currently ranges between US$12 and US$15/barrel—will act as a rough ceiling on the price differential, especially for the movement of heavy oil.

Should the differential trend above this cost as supplies begin to build up, more railing capacity will be brought to bear and relieve the backlog, forcing the differential to narrow once again.

As such, railing capacity acts as something of a safety valve for the industry.

With railing capacity from Alberta to other parts of North America in the range of one million bbls/d, there is plenty of room to move some or all of the production increases expected in 2017 to market. This is a fallback position for the industry that it did not have a few years ago, and should prevent any major price blowouts over the next few years.

This is happening as export pipelines from Canada are facing increasing

congestion to the point where apportionment has become more and more common. Other than some modest efficiency gains over the next two years, the next batch of new available pipeline capacity will likely not be ready until late 2019 when both the 590,000-bbl/d TransMountain Pipeline expansion and the 400,000-bbl/d Enbridge Line 3 replacement program are completed.

With both of these projects having received the blessing of the federal government, progress is likely to be initially slow as environmental and legal challenges continue to be undertaken.

The wildcard in this mix will be whether newly minted U.S. President

Donald Trump proceeds with approval of the long-tortured Keystone XL Pipeline. If such an approval is granted, reversing President Obama’s rejection in November 2015, it could be upwards of one year before construction would be able to proceed.

At more than 500,000 bbls/d, Keystone XL might be able to provide access for rising Canadian production sooner than the other two pipelines.

Whether Keystone XL goes ahead or not, Canada will have a great deal of new pipeline capacity available to it by the end of this decade. Until then, there is plenty of room on the rails.

MARTIN KING, vice-president, institutional research, FirstEnergy Capital.

SOURCES: A LBERTA ENERGY REG U L ATOR; ENERGY INFORMATION ADMINISTR ATION; FIRSTENERGY C APITA L CORP; FLINT HI LLS RESOURCES LTD; MEPS INTERNATIONA L; NATUR A L GAS E XCHANG E INC . TOP ANA LYSIS

44 • MARCH 2017 • OILSANDS REVIEW

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SECTOR WATCH Q U I C K- H I T I N S P E C T I O N O F O I L S A N D S I S S U E S

Suncor uses offshore operations approach to bring a remote control room to the Firebag SAGD project

“We had significant cost savings, and reliability actually improved because there’s less distraction at site.”

— RICHARD CHAN, senior reservoir engineer, Suncor Energy

A remote control room in downtown Calgary has helped Suncor Energy reduce costs and increase production at its Firebag SAGD project, says one of the company’s senior reservoir engineers.

The integrated operations centre (IOC) has resulted in a significant drop in on-site staff north of Fort McMurray at the 200,000-bbl/d SAGD project, while contributing to a 35 per cent decrease in per-barrel cash costs and a 34 per cent increase in production rates since 2013, Suncor’s Richard Chan told a recent session hosted by the Canadian Heavy Oil Association.

“We made some changes in terms of where we work, and we adopted the offshore model,” Chan said.

Suncor has production platforms offshore Norway, the east coast of Canada and in the U.K. North Sea. These platforms don’t have much space, he said, so really its only hands-on staff that are located in situ.

“We brought that to Firebag, and we brought a lot of people from site back to Calgary. It was actually a winwin because a lot of these guys were working 12-hour days; they were away from their family. Even just site exposure and travel time—from a safety perspective, they were more at risk.

46 • MARCH 2017 • OILSANDS REVIEW

At the same time we had significant cost savings as a result, and reliability actually improved because there’s less distraction at site.”

Chan said Suncor has been inviting other producers to come check out the IOC. “How it works is we’ve got one room at Firebag at site [and] one room here in Calgary. Inside these rooms you’ve got the cross-functional decision makers, so we’ve got someone from process engineering, from automation, operations managers, production engineering, even reliability. You can actually come up with a decision and execute quickly.

“The control room operators, they are still up at site. What we have moved down is more of the functions that support operations up at site.

“For example, our field production engineers, where we used to have maybe six to eight up there, we only have two now. So there is still some need for face-to-face interaction, but we’ve tried to minimize how many people we have at site.”

Technology has also helped with the success of the IOC, but not in the way one might expect.

“We went to a fancy software company and they had a neat software

where everybody could access the same screen and pull it to their computer to work on it and you could actually share screens and video feeds, and what we found is that was a bit of overkill,” Chan said.

There are two main screens in each room fed by a main computer, and Chan said Suncor is able to use a basic system to achieve its requirements for information sharing.

“We just plugged in four or five wireless mice into the same computer so everyone can access the main screen, so we didn’t need any fancy software to make it work.”

While the on-site staff works on hour-by-hour and day-by-day operations, the IOC works on a two-week optimization time frame—for example, planning for efficient use of steam when certain units are taken down for maintenance. Additionally, Chan said the IOC is working on predictive control and automation.

“What this does is it actually requires less human intervention, so the same number of people can operate more wells, you can do it with more consistency, you can do it with less human error and that is something that we are actively progressing right now.”

PHOTO: JOE Y PODLUBNY

BY DEBORAH JAREMKO

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