Oilsands Review September 2016

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S E P T E M B E R 20 1 6 |

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Saying to the Long Lake SCO dream Photos inside the last decade at Long Lake as Nexen shuts down its once-touted upgrader and considers its oilsands future

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WATER TECHNOLOGIES

CONTENTS VOLUME 11 | NUMBER 4 | S EP TEM B ER | 2 0 1 6

DEPARTMENTS

07

From the editor

18

Insights into oilsands trends

22

MEGAPROJECT FORT MCMURRAY The rebuild of the firedevastated oilsands capital could take a few lessons from industry

TREES COMPANY Reforestation is a cornerstone of Cenovus Energy’s massive new caribou protection effort

R.P. STASTNY

IN REVIEW

CARTER HAYDU

08

News

10

Project news

13

Eyes on the oilsands

16

Rounding up the latest oilsands news

Project status and development progress

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

26

2016 OILSANDS PROJECT ANALYTICS

32

Measuring performance against the yardstick of efficiency

Throwback Oilsands Review’s 10th anniversary series

BETTER THAN THE BEST A new COAA document brings together years of best practices to help build the next generation of oilsands modules DAVE S. CLARK

July 2006: Long Lake could be a game changer

49 52 54

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

Transition Pembina: What a firm emissions limit means for the oilsands

Sector Watch Social license is not democracy—public interest is

TECH_SERIES

36

KEEPING YOUR DISTANCE New positioning technologies allow SAGD wells to be drilled cheaper with less downtime

COVER STORY

44

SAYING GOODBYE TO THE LONG LAKE SCO DREAM Photos inside the last decade as Nexen shuts down its once-touted upgrader and considers its oilsands future DEBORAH JAREMKO

PAT ROCHE

40 SAGD CAVE

Reservior simulation gets a boost from virtual and augmented reality at the U of C LYNDA HARRISON

S E P T E M B E R 2 0 1 6 • J W N E N E R G Y. C O M • 0 5

The world’s premiere showcase for heavy oil knowledge and technology!

September 14-15, 2016

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780.875.6664

EDITORIAL EDITOR

Deborah Jaremko | djaremko@jwnenergy.com

FROM EDITOR THE

INSIGHTS INTO OILSANDS TRENDS

ASSISTANT EDITOR

Joseph Caouette | jcaouette@jwnenergy.com CONTRIBUTING WRITERS

Dave S. Clark, Lynda Harrison, Carter Haydu, Benjamin Israel, Andrew Read, Pat Roche, Elsie Ross, R.P. Stastny EDITORIAL ASSISTANCE MANAGER

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CREATIVE SERVICES

Christina Borowiecki, Genevieve Ongaro, Teagan Zwierink

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OFFICES CALGARY 2nd Flr-816 55 Avenue NE | Calgary, Alberta T2E 6Y4 Tel: 403.209.3500 | Toll-free: 1.800.387.2446

I swear that I can still hear the piles being pounded into the ground.

It was a hot summer day in 2005, and photographer Joey Podlubny and I had turned off Highway 881 south of Fort McMurray into a quiet forest that almost immediately became a major construction zone.

This was going to be Long Lake, and everyone we talked to was very excited about it. It was a leap of faith in oilsands technology.

In 2005, SAGD was very new—the first major wave of large capital projects was just freshly underway. Total Alberta SAGD production at the time averaged just 80,000 bbls/d from seven commercial-scale projects and one pilot (Foster Creek, MacKay River, Firebag, Hangingstone, Cenovus Christina Lake, Joslyn Creek and the Surmont pilot).

In a single 72,000-bbl/d SAGD phase, Long Lake was going to change the SAGD landscape. It was also going to take the technology—which was going to be, but was not yet game changing—to the next level by integrating for full-value synthetic crude oil.

The recruitment messaging said it all: “The sands have shifted. Be there.”

Fast forward three years to October 2008 and we were at the bedazzled grand opening of the Long Lake project.

“It’s time for us to prove that all of the planning and all of the hard work is going to

provide a lot of value,” said Charlie Fischer, Nexen’s chief executive officer at the time.

Over the next six years, Long Lake would be fraught with challenges from the reservoir to the upgrader. Even before this year’s pipeline rupture, fatal upgrader explosion and sweep by wildfire, major issues were evident.

“With $6.1 billion [$6.8 billion in 2016 dollars] of capital deployed in the development of Long Lake, which is now producing at 38 per cent of its design capacity, it is worth noting that implies a cost per daily flowing barrel of $225,925 [$251,851 in 2016 dollars],” wrote columnist Mark McLennan this July on jwnenergy.com.

“Contrast that with the $53,542 per flowing barrel that Suncor just paid for Murphy Oil’s 5 per cent of Syncrude or the approximately $70,000 per flowing barrel that Sunrise cost Husky, one can see just how much of an outlier Long Lake is and the questions about its long-term viability.”

As McLennan noted, “the litany of operational challenges at Long Lake: that decisions made during the planning and development stages of the project were flawed and have proven difficult to overcome.”

I just hope that companies continue to be willing to take risks when it comes to the oilsands, particularly in new technologies that may—or may not—change the game.

DEBORAH JAREMKO

djaremko@jwnenergy.com @JWN_Deborah

EDMONTON 220-9303 34 Avenue NW | Edmonton, Alberta T6E 5W8 Tel: 780.944.9333 | Toll-free: 1.800.563.2946

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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.

NEXT ISSUE

The Supply Chain edition Measuring the success of new strategies designed to reduce risk and cost across the project value chain

Who’s on top?

Nominate your choices for Oilsands Review’s 2016 Producer and Supplier of the Year by emailing Deborah Jaremko at djaremko@jwnenergy.com.

S E P T E M B E R 2 0 1 6 • J W N E N E R G Y. C O M • 0 7

Improving SAGD well pad execution

IN REVIEW

WANTED: A commodity well pad

SEPTEMBER 2016 // ROUNDING UP THE LATEST OILSANDS NEWS

TYPICAL FIELD DEVELOPMENT

P.14

INTEGRATED FIELD DEVELOPMENT

FOUR pipeline right-of-ways

ONE pipeline right-of-way

SIX well pads with SIX access roads

TWO well pads with ONE access road

SEVEN rig moves

THREE rig moves

Nexen is indefinitely shutting down its Long Lake upgrader The upgrader that once drove the characterization of the Long Lake project as an oilsands game changer is being taken offline. The project will now run as SAGD only, Nexen announced this morning.

The decision follows the January explosion that resulted in the death of two Nexen employees. The company says the explosion has resulted in changes to its safety culture.

“Since the explosion of our hydrocracker unit, our upgrader has been operating in idle mode in the hope that a short-term repair solution existed. Following

a comprehensive review of available options, we recognize a short-term repair is not feasible,” Nexen said in a statement.

“As a result, we will begin moving the Long Lake Upgrader into winter preservation [cold stack] mode.

At this time, a planned date to return the upgrader back into full service has not been established.”

Moving to a SAGD-only operation is entirely an economic decision, the company said. It will result in the loss of approximately 350 workers, most of which is expected to be complete by the end of 2016.

The Long Lake project was commissioned in 2008 to great fanfare because of its integrated upgrader, which uses a technology called OrCrude.

It was also the first commercial application of gasification in Canada.

The upgrader has processing capacity of 72,000 bbls/d, but has never been filled.

Flip to page 16 for this month’s Throwback feature from July 2006 to read what people were saying about Long Lake before it got started and to page 44 for photos of the project over the last decade.

Canada’s Federal Court of Appeal has overturned the approval of Enbridge’s Northern Gateway Pipeline, which would carry oil from the Alberta oilsands to a port in northern B.C. for export.

The court ruled in a recent decision that the government had failed in its duty to consult with aboriginal groups on the 1,177-kilometre pipeline project and sent the matter back to Prime Minister Justin Trudeau’s cabinet for a “prompt redetermination.”

Canada’s former Conservative government approved Northern Gateway in 2014, imposing more than 200 conditions on its construction. But the plan has faced fierce opposition from environmentalists, aboriginal groups and communities along the pipeline route, with many investors sceptical it would ever be built.

After its approval, numerous B.C. aboriginal groups, along with environmental groups, filed lawsuits seeking to overturn the decision.

08 • SEPTEMBER 2016 • OILSANDS REVIEW

PHOTOS: JOE Y PODLUBNY/JWN

Canada court overturns federal approval of Enbridge oil pipeline

IN REVIEW

1.5

350

million barrels per day

Approximate level of production lost at the height of the Fort McMurray wildfire through project shut-ins.

128,000

$500K

How much CAPP expects oilsands production to grow each year in 2016-21.

Amount Canadian Natural was penalized for hydrogen sulphide releases in 2010 and 2012.

barrels per day

Workers who will lose their jobs as Nexen indefinitely shuts down its Long Lake upgrader.

Oilsands production returning post-wildfire At the height of the wildfire risk in the Regional Municipality of Wood Buffalo this May, 12 oilsands projects totalling almost 1.5 million bbls/d were taken offline as communities, including the city of Fort McMurray, were evacuated. The fire burned for close to two months, declared “under control” by the Government of Alberta on July 4.

The Insurance Bureau of Canada estimates the Fort McMurray insured property damage at $3.58 billion—more than twice the amount of the 2013 flood in southern Alberta, the previous costliest disaster.

Oilsands producers have not announced any significant damage from the flames, although Horizon North Logistics lost the Blacksand Executive Lodge, a key asset located just north of the city.

Suncor is expected to be hardest hit by the lost production from fire shut-ins, the disruption from which helped push the price of WTI back in the range of $50/bbl. The Conference Board of Canada expects the lost production to cause a nearly $1-billion reduction in the Canadian GDP this year.

At press time, producers had not yet issued their secondquarter results so the full scope of the fire impact is still pending.

AER data shows first look at wildfire production losses This spring’s massive wildfire in Wood Buffalo caused eight in situ oilsands projects together to lose nearly 85 per cent of May production, according to new data from the Alberta Energy Regulator (AER).

The SAGD projects that reported wildfire shutdowns together produced about 378,000 bbls/d in April, but that dropped to about 59,000 bbls/d in May, AER data shows.

The wildfire caused the evacuation of Fort McMurray on May 3, followed by the shutdown of 12 oilsands projects north and south of the city over the subsequent days for an estimated disruption of about 1.5 million bbls/d at the peak of the risk.

Production March 2016 (AER - bbls/d)

Date suspended

Suncor Base

350,000

May 4

Operations restarted May 29

Suncor Firebag

200,000

May 6

Resumed production early week of May 23

Project

Suncor MacKay

Status

35,000

May 6

Resumed production early week of May 23

Syncrude

300,000

May 7

Planning return to operations

Shell Albian

255,000

May 3

Resumed operations May 10

60,000

May 5

Remobilized May 24, restarted June 7

4,000

Not available

Conoco Surmont JACOS Hangingstone ATH Hangingstone

Not available

9,000

May 5

Resumed May 24

20,000

May 4

Not available

Imperial Kearl

215,000

May 9

Restarted limited operations May 19, “normal operations” June 3

Husky Sunrise

20,000

May 7

Restarted week of June 1

Statoil Leismer

20,000

May 9

Not available

Nexen Long Lake

TOTAL

The majority of the production loss came from mining and upgrading facilities, for which AER data is not yet available.

Projects are now resuming production.

The wildfire caught three SAGD projects in the midst of major production rampups, at Surmont, Sunrise and Athabasca Hangingstone. ConocoPhillips achieved first oil at Surmont 2 in September 2015 and is working on ramping up to phase capacity of 118,000 bbls/d. Meanwhile, Husky achieved first oil at its greenfield Sunrise SAGD project in March 2015 and is in the process of ramping up to 60,000 bbls/d.

Athabasca Oil achieved its first barrels at its greenfield Hangingstone project in December 2015, working toward capacity of 12,000 bbls/d.

Here’s the SAGD project-by-project volume drop month-over-month, according to AER records:

1,488,000

Operator - Project

April (bbls/d)

May (bbls/d)

Difference

Suncor Energy - Firebag

201,122

29,749

171,373

CNOOC/Nexen - Long Lake

16,641

0

16,641

ConocoPhillips - Surmont

71,298

7,508

63,790

Suncor Energy - MacKay River

32,788

3,341

29,447

Statoil - Leismer

18,510

11,356

7,154

JACOS - Hangingstone

4,774

525

4,249

Husky Energy - Sunrise

27,204

4,345

22,859

Athabasca Oil - Hangingstone

6,518

1,981

4,537

S E P T E M B E R 2 0 1 6 • J W N E N E R G Y. C O M • 0 9

IN REVIEW MEG says its hatches are battened for low oil prices

Bill McCaffery, Chief executive officer, MEG Energy

MEG Energy says low decline rates and low sustaining capital enable the company to maintain and grow production even with low oil prices.

“We believe we’re now one of the lowest-cost producers in the industry and with sustaining and maintenance costs of just $5/bbl for 2015, we’re well positioned to sustain production levels at current prices for a very long time,” Bill McCaffrey, president, chief executive officer and chair, told the company’s annual general meeting.

Despite having $4.92 billion in outstanding debt, McCaffrey said MEG is in a sound financial position. In addition to low sustaining capital and operating costs, the company has ample financial liquidity, with cash on hand plus US$2.5 billion in an undrawn credit facility, he said.

MEG also has well-structured debt, he said. According MEG, all its debt is “covenant-lite,” meaning the company is free of any financial maintenance covenants and not dependent on nor calculated from crude oil reserves, with earliest maturity in 2020.

A new study shows that dilbit floats, changing cleanup assumptions A study funded by the Canadian government shows that diluted bitumen floats in fresh water, overturning previous assumptions that it would sink like conventional oil. The diluted bitumen only tends to sink when exposed to high temperatures and weathering. This may help remove concerns that a diluted bitumen spill would be more difficult to clean up, according to Bloomberg News.

The study may also affect the government’s decision regarding the Trans Mountain Pipeline, which crosses multiple rivers on its way to the B.C. coast.

PROJECT NEWS

HUSKY ENERGY says it has commenced steam operations its third thermal project to be brought online this year, at Edam West in Saskatchewan. The 10,000-bbl/d Edam East project achieved first oil in April and is now producing above its design rate at approximately 11,000 bbls/d.

Husky says it is leveraging its growing thermal expertise in Saskatchewan at the Tucker SAGD project in the Cold Lake region, which has struggled to reach

nameplate capacity of 30,000 bbls/d since production started in 2006. Husky says Tucker volumes are now approximately 22,000 bbls/d.

IMPERIAL OIL is moving its solvent-assisted SAGD wells at Cold Lake into commercial operations. The company has applied to the Alberta Energy Regulator (AER) to terminate its approval for an experimental solventassisted SAGD pilot, but still operate the wells as part of its 160,000-bbl/d Cold Lake project.

The company’s application says the purpose of the pilot was to evaluate the effectiveness of SA-SAGD in the field, and that evaluation is now complete.

“Based on the outcome of this pilot, Imperial has demonstrated that SA-SAGD results in an increase in bitumen rates and improvement in the oil steam ratio relative to the standard SAGD process,” wrote Imperial’s manager, heavy oil in situ, John Elliott in the AER submission.

VALUE CREATION has filed an amendment application with Alberta Energy

Regulator to add its proprietary clean oil refining units at its approved Heartland Upgrader Project in Strathcona County.

The approval would complete its mission to provide value chain solutions to bitumen producers, said the company. When fully implemented, it is expected to be the best-in-class bitumen refinery. Columba Yeung, chair and chief executive officer, observes, “It is not just refining, it is re-defining the full value chain development of oilsands, sustainably.”

Downhole work is expected to restart at the ENHANCED SOLVENT EXTRACTION INCORPORATING ELECTROMAGNETIC HEATING (ESEIEH) pilot this fall. In mid-2015, a consortium of companies launched the pilot at Suncor’s Dover test site. ESEIEH is expected to eliminate steam requirements for in situ bitumen production, significantly reducing capital costs and greenhouse gas emissions.

The power was turned on at the pilot from June to October of last year, and then the downhole equipment was retrieved in November for troubleshoot-

Oilsands Review provides timely analysis of key project developments and operational performance metrics. For a comprehensive oilsands project status listing and access to deep oilsands data sets, subscribe to the DOB Intelligence Essentials. For more information, please visit dailyoilbulletin.com/about.

10 • SEPTEMBER 2016 • OILSANDS REVIEW

ing, a project rep told the SPE Heavy Oil Technical Conference in June.

The plan was to put everything back downhole this spring, but operations were delayed by nearby wildfires in northeastern Alberta.

He said the group took advantage of the downtime to use what they’ve learned to date to modify the equipment from the original design, which was almost four years old. The pilot is expected to resume operations in November.

MEG ENERGY is seeking regulatory approval to pilot a new solvent-based recovery process at its Christina Lake SAGD operations. The company has applied for a Canadian patent on a process it calls enhanced Modified Vapour Extraction (eMVAPEX).

Instead of steam, hot or cold solvent vapour is injected into the top well to dilute bitumen or heavy oil, which then flows with gravity to a production well drilled lower in the reservoir.

The company applied to the Alberta Energy Regulator for permission to do an eMVAPEX pilot with propane as the solvent.

PHOTO: MEG ENERGY

FIELD UPGRADING recently launched a bitumen upgrading pilot project near Fort Saskatchewan, Alta. The 10-bbl/d pilot facility cost $30 million and produces no direct greenhouse gas emissions. “We take the dirty out of the dirty oil,” says Neil Camarta, president and chief executive officer. The only emissions are expected to be from the electricity used during the sodium sulphide separation process, which uses 50 per cent less energy than conventional upgrading technology. The upgraded oil that comes out of the process is eight to 10 API degrees lighter.

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IN REVIEW New CAPP outlook mutes oilsands growth but anticipates innovation

Over the first five months of 2016, operators have permitted 148 oilsands evaluation wells compared to 120 licences to the end of May last year. Producers licensed 24 oilsands evaluation permits in May, up from zero in May 2015.

Oilsands evaluation wells licensed - Jan. to May 2,000 1,500 1,000 500

2008

2010

2012

2014

2016

SOURCE: ANG US REID

Canadians on Trans Mountain In June, Angus Reid released the results of a new survey asking Canadians what they thought about the National Energy Board recommending approval of the proposed Trans Mountain Pipeline expansion, subject to 157 conditions.

Angus Reid says the results show that the recent scuffle over the pipeline between Calgary mayor Naheed Nenshi and Vancouver mayor Gregor Robertson is “roughly representative of public opinion in the provinces they call home.”

The survey was self-commissioned by Angus Reid and polled about 1,500 people across the country who are members of the Angus Reid Forum.

Do you think the NEB made the right decision or the wrong decision in approving the Trans Mountain Pipeline expansion with conditions?

Right decision

24%

Wrong decision

Not sure

Did the government make the right decision in approving this pipeline with conditions?

63%

58% 41%

38% 40% 22%

BC

18%

34%

24%

AB

Northern Gateway, 2014

28%

25% 9%

BC

AB

Trans Mountain, 2016 SOURCE: ANG US REID

12 • SEPTEMBER 2016 • OILSANDS REVIEW

Total Canada

Oilsands

8 6 4

6.70

6.20 5.00

6.40 5.20

4.80

5.33

4.93 3.95

3.67

2 0

2012

2013

2014

2015

2016

New radio-frequency oilsands tech could drop costs up to 50 per cent

41%

35%

CAPP's growth forecast to 2016

Tim McMillan, president, CAPP

A consortium of oil producers will support new testing of radio-frequency technology to reduce oilsands costs and greenhouse gas emissions, says Calgary-based Acceleware.

The company says it will partner with GE to develop critical power components and complete a pilot test of the system, called RF XL. The technology will be deployed on a typical oilsands well pair in 2017.

“We believe RF XL has the potential to deliver operating cost savings of up to 50 per cent, which is significant when compared to the current industry average operating cost of $14.39 for SAGD,” Acceleware vice-president Mike Tourigny said in a statement.

PHOTO: C APP

0 2006

In 2015, oilsands production totalled almost 2.4 million bbls/d, of which 1.3 million bbls/d were recovered by in situ techniques and one million bbls/d from mining.

From 2016 to 2021, CAPP projects oilsands production to grow by 128,000 bbls/d on average each year, after which the rate of growth slows down to 59,000 bbls/d from 2022 to 2030 of the outlook.

Mining production is forecast to rise to 1.5 million bbls/d by 2030. Most of the future growth is expected from in situ production, which is forecast to reach 2.1 million bbls/d by the end of the outlook period.

CAPP noted that growth in oilsands production could be higher than forecast if long-term crude oil prices return to previous high levels or if in situ operators are able to respond to a lower price environment with greater cost efficiencies.

million bbls/d

Permits increase slightly for oilsands evaluation wells

IN REVIEW

PHOTOS ( LEF T TO RIG HT, TOP TO BOT TOM ): G LOBE AND MAI L; MEG ENERGY; HAIDA NATION; IDE ACIT Y.C A ; Z AYSMITH .COM

“In every [environmental] campaign I’ve ever worked on, once you start working on solutions, supporting policy or working with industry, you are criticized. It’s a lot easier to be on the outside saying no, holding your placard, than to be on the inside crafting solutions.

“Of course, it never feels great to be attacked or called traitor by your own community for meeting with the oil industry, but I don’t see how we get out of this full-out conflict without talking to each other.”

— TZEPORAH BERMAN, co-founder of ForestEthics and former co-director of Greenpeace International’s Global Climate and Energy Program. In July, she was named one of three co-chairs of Alberta’s oilsands greenhouse gas emission advisory panel. The Calgary Herald, July 14.

// EYES on the OILSANDS “Pipelines are the best mode to transport liquids such as bitumen. And pipelines have a good record and I think that if we don’t get our pipelines built, we are not going to be competitive at all in Canada, and our oil will be orphaned.”

— JIM BOUCHER, chief of the Fort McKay First Nation. The Financial Post, June 27.

“As we saw with tight oil producers, when prices collapsed, they focused their activity on the most productive areas.

“We expect a similar experience to play out in the Canadian oilsands. However, given the nature of the long lead times, we expect this will play out over the coming decade.”

— KEVIN BIRN, director with IHS Energy. Global News, June 27.

MEG Energy’s Christina Lake SAGD project.

“At every turn you’re going, you are seeing nails in the coffin of the Enbridge project. “ I don’t think there’s enough room for another nail in the coffin.”

— PETER LANTIN, president of the Council of the Haida Nation, following the Federal Court of Appeal’s decision to overturn the Northern Gateway approval based on inadequate consultation with First Nations by the Canadian government. CBC News, June 30.

Lantin with Canadian environment minister Catherine McKenna.

“[Suncor has] done a hell of a good job taking advantage of the depressed environment to make some very smart purchases. They’ve bought assets closely associated with their own, which helps them lower costs.

They’re going to reap the rewards.”

Steve Williams, chief executive officer, Suncor Energy

— RAFI TAHMAZIAN, Calgary-based portfolio with Canoe Financial, on Suncor’s recent M&A transactions boosting its Syncrude ownership. Financial Post, July 8.

S E P T E M B E R 2 0 1 6 • J W N E N E R G Y. C O M • 1 3

IN REVIEW

Wanted: A commodity well pad Integrated Thermal Solutions displayed its well pad manufacturing solution at this year’s Global Petroleum Show.

o be competitive on a global scale, SAGD producers must be relentless on costs, embrace innovation and do so in such a way that looks for technologies to fix problems unconventionally, says Mark Conacher.

“Look to other industries that have solved something and then see how you can adopt that,” Suncor Energy’s director of well pad development told a recent Oilsands Review speaker series breakfast.

Conacher said that Suncor found its well pad program costs at the Firebag SAGD project were quite high when compared to those of industry peers, but he and his team devised a solution that he believes should move the company closer to best-in-class status over the next couple of years.

“We came up with a very highly modularized layout. We have adopted a twin-row design. Our well spacing and inter-well spacing is the same….

Basically, it makes our facility half the size on the surface—half the piles, half as much insulation. We

moved the module commissioning back into the module yard instead of onsite, and this should construct a lot easier.”

However, Conacher noted that drilling costs are still pretty high on an absolute basis, which industry must address in order to figure out how to develop consistent, sustainable,

repeatable projects. But he also noted that the biggest variable in pad costs is actually for the gathering lines.

“When we step out concentrically from our plants, we are building further and further out. The cost of the pipelines, roads and power lines are variable. If we are close to a development, then that piece is pretty small,

Improving SAGD well pad execution

TYPICAL FIELD DEVELOPMENT

INTEGRATED FIELD DEVELOPMENT

FOUR pipeline right-of-ways

ONE pipeline right-of-way

SIX well pads with SIX access roads

TWO well pads with ONE access road

SEVEN rig moves

THREE rig moves

14 • SEPTEMBER 2016 • OILSANDS REVIEW

Mark Conacher, director of well pad development with Suncor Energy, offered these visuals to illustrate the company’s goals of integrated field development.

PHOTO: DEBOR AH JAREMKO

T

as low as 10–11 per cent of a project.

But with the step-out ones, they could be 30–40 per cent of your overall costs. There is quite a variation.”

As companies look to new technologies to reduce water use and energy requirements at SAGD projects such as solvent or surfactant co-injection, flow control devices and superheaters, well pad programs will also have to adapt, Conacher said.

Ashley Leroux, president and chief executive officer at Integrated Thermal Solutions, told the speaker series that as companies prepare to spend billions of dollars in their SAGD developments, they also have an opportunity to save billions of dollars through fresh thinking and new ideas around pad planning, and through collaboration.

He said, “It is a pretty hot topic about pads and sustainability in our industry.”

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IN REVIEW

// #THROWBACK

JULY 2006

The Long Lake SAGD project could be a step-change

I

n the second issue of Oilsands Review, we profiled the up and coming Long Lake SAGD project, considered by many to be a major jump forward with oilsands technology.

Primarily, the advances were coming in the upgrader, which Nexen has announced is now being shut down. The upgrader has been operating in idle mode since the January explosion that resulted in two fatalities, and a short-term fix is not in the cards, the company says.

2006 would be disappointed. Here’s a piece of the story.

The oilsands industry relies on step-change technologies to further its progress, and many say another leap in efficiency is about to occur. It is peak construction time at the Long Lake site—a project set to change the way the world looks at the oilsands, and the relationship between energy input costs and results.

16 • SEPTEMBER 2016 • OILSANDS REVIEW

“If it works, and I’m sure they will make it work, it will open up a new technology never been used before in the industry,” says Greg Stringham, vice president of markets and fiscal policy with the Can­ adian Association of Petroleum Producers (CAPP).

“It shows you can start looking at other technologies and have confidence going ahead. Not only does it set a new level for technology, it may set a new competitive level for [project] economics as well.”

Long Lake—a 72,000-bbl/d, 50-50 joint venture of OPTI Canada and Nexen—is all about firsts. It is the first ever oilsands project which combines in situ production with upgrading, the first commercial application of gasification in Canada and the first time the OrCrude process will be used on a full scale.

The combination of these technologies, along with the proven method of SAGD, is designed to mitigate what has become one of the most significant challenges facing the oilsands industry today—reliance on costly natural gas. When the two companies started working on Long Lake in 1997, there wasn’t as much concern as there is today relating to this input expense, explains Gary Nieuwenburg, Nexen’s vice president of synthetic oil.

“People didn’t appreciate the relationship between operating costs and the cost of natural gas,” he says, adding that the industry focus was on stand-alone SAGD projects without associated

upgrading capacity. “You can’t make money in SAGD [by itself]. You need to be integrated, and you need to be producing synthetic crude oil.”

First a private company in Canada, OPTI was created to commercialize the OrCrude process where it would be most useful, the company says.

This was determined to be the oilsands.

Originally, OPTI was working with Suncor Energy on the conceptual project, but then in 1997, Nexen got involved. In today’s joint venture, OPTI is in charge of the upgrader, while Nexen is responsible for SAGD operations.

OPTI says that since 2001, an OrCrude pilot plant near Cold Lake has processed more than 250,000 barrels of a variety of Cold Lake and Ath­ abasca crudes. A SAGD pilot has been running at the Long Lake site since 2003. The key to Long Lake is repeatability—it will be developed in phases, eventually taking production to 240,000 bbls/d.

“Our plan is to repeat [the first phase] over and over. It’s the same design and same execution, just repeated,” Nieuwenburg says.

Production rates at Long Lake have struggled to reach capacity since the 2008 start-up. None of the original planned expansions have occurred.

In 2014, Nexen commissioned a 20,000-bbl/d SAGD phase called Kinosis, designed to fill the upgrader. In July 2015, a pipeline running to a Kinosis well pad spilled about 30,000 barrels of bitumen emulsion.

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F E AT U R E

18 • SEPTEMBER 2016 • OILSANDS REVIEW

WILDFIRE REBUILD

The rebuild of the firedevastated oilsands capital could take a few lessons from industry R.P. STASTNY

Development and the former municipality manager of planning.

The fire destroyed about 2,400 structures,

insurance, so now, on that same block of

1,600 of which were residential homes, while

duplexes, instead of having one builder

leaving most of the infrastructure intact.

working according to a systematic approach,

In past years, Fort McMurray built

you have 30 guys working under seven

1,000–2,000 homes a year on a regular basis.

different builders working for 10 different

Houses took five to six months to build,

insurance companies trying to rebuild that

multi-family residences took a year. So in

block,” Dauk says.

theory, using the numerous stock home

In tight neighbourhoods, the issue of

designs builders have on file that just need

builders tripping over each other is com-

y any measure, the rebuild of Fort

a stamp of approval from the municipality,

pounded. In the absence of coordination,

McMurray is a megaproject on the scale

Fort McMurray could be back up and run-

logistics will likely get tangled. A concrete

of an oilsands development. The dev-

ning in as little as one year.

truck pouring a foundation could block

B

astating fire in May has set a new record as

“The last time we were building 1,000–

access to dump trucks or deliveries of

the largest insured loss in Canadian history,

2,000 homes a year in Fort McMurray, [the

roof trusses. Where builders need to place

eclipsing 2013’s $1.7-billion southern Alberta

construction industry in] Edmonton was

materials on vacant sites, this free-for-all

floods. The Insurance Bureau of Canada’s

red­hot, Calgary was red­hot, Cold Lake

scenario of every builder for himself will

most recent estimate has placed the cost of

was red­hot, Red Deer was red­hot. It’s the

cause more problems and further erode con-

insurance claims from the fire at $3.58 billion.

opposite now. There’s plenty of [labour]

struction efficiencies. It would be similar to

Like any megaproject, the rebuild of the

capacity in Edmonton and Calgary that

a SAGD owner contracting with a different

oilsands capital could go well or not so well.

would welcome the opportunity to get back

engineering company and different driller

But if any place understands megaprojects,

to work right now,” Dauk says.

and a different service provider for every

it’s Fort McMurray. There is an opportunity

But theory isn’t practice. In her remarks

new well pad and leaving the scheduling up to each contractor.

to apply some of the industry’s hard­won

upon the return of the first evacuees to Fort

lessons in collaboration, planning and best

McMurray in June, Premier Rachel Notley

practices to the task of rebuilding.

warned that Fort McMurray would “take

to us and say, ‘I love the half duplex I bought

“We’ve even had a couple customers come

years, not weeks” to rebuild. The Conference

from you. Can you rebuild my half of the

construction can begin. The insurance

Board of Canada also estimates that work

house?’ Well, generally we build both sides of

industry, which plays a central role in this

will last till 2019.

the duplex at the same time,” Dauk says.

its own rules and regulations. And some of

Why so long? Construction chaos

a home, Dauk says that builders working

those rules could limit how efficiently build­

“One of the biggest challenges will be build­

around each other may need nine to 12

ers can reconstruct neighbourhoods.

ers tripping over each other if there is no

months to do the same job. This schedule

coordination or logical progress,” Dauk says.

then could bump into cold­weather months

A lot still needs to be sorted out before

project, is a machine that runs according to

Years not weeks

PHOTO: © ISTOCK .COM

“The problem that we have in Fort McMurray is that everybody has their own

In residential development, a handful of

So rather than six months to rebuild

that prevent the pouring of foundations

One of the lessons from other disasters,

builders buy blocks of land and coordinate

or other cement work, further stretching

such as the Slave Lake fire in 2011 and the

construction with each other in order to

timelines.

2013 floods, is that the faster a community

achieve “factory operation” efficiencies,

is rebuilt, the better it is for residents who

Dauk says. Planning and orderly progress

ash and soil testing is being conducted

are less likely to then leave for other places.

through the building stages is essential to

until the end of June to ensure that debris

Initial meetings between the Regional

achieving the lowest construction costs

removal can be done safely. The heaviest

Municipality of Wood Buffalo, builders and

and timely delivery. Everything is planned:

ash and debris deposits are in Waterways,

other stakeholders reflect a community

the placement of excavated basement dirt,

Abasand Heights and Beacon Hill, where

that has pulled together and wants a speedy

where framing materials are placed, the

some removal is already underway.

recovery, says Russell Dauk, vice­president

progression of trades moving through the

of land development with Rohit Land

project and so on.

But before any construction gets going,

“Ash sampling is now complete,” Jessica Lucenko, communications director, Wildfire

S E P T E M B E R 2 0 1 6 • J W N E N E R G Y. C O M • 1 9

WILDFIRE REBUILD

“Building is not hard unless you make it

ment. In this scenario, homeowners would

Oilsands Review on June 23. Analysis of

hard,” Dauk says. “Insurance companies need

swap their debris and ash-covered land for

those samples still continues, but so far no

to realize that if they have half a duplex, they

clean land so as to start building right away,

asbestos or other dangerous contaminants

need to find who has the other half of the du-

saving three to four months and, in some

have been found.

plex and who has all the units on the street,

cases, winter delays.

Recovery Task Force, wrote in an email to

“Debris removal in some areas has

and maybe coordinate the reconstruction.

Again, this is unlikely to happen—unless

begun,” she added. “Coordinated debris re­

“If one company built a row of homes

moval in the three most impacted commu-

before, why not contact the same builder to

are insurance companies that do allow that

nities will begin once sifting is complete.”

rebuild those homes? If you want efficiency

through their insurance policy,” Mack says.

it’s part of the insurance contract. “There

and cost-effectiveness, insurance compan­

“Some insurers have specialty products for

teams that go through the debris for sal-

ies should be getting together, reviewing

exactly that type of situation. But generally,

vageable items such as safes and jewellery.

these things and having serious conver-

unless it’s a decision of the province or the

That could take weeks. And full debris re-

sations with their customers in order to

municipality not to allow some properties

moval and clean up of burn sites is expected

progress logically.”

to be rebuilt, it’s probably unlikely that an

“Sifting” refers to the work of specialized

to take three to four months, according to Alberta Environment and Parks.

“ One of the biggest challenges will be builders tripping over each other if there is no coordination or logical progress.”

— RUSSELL DAUCK, vice-president, Rohit Land Development

Is that happening? No. And it won’t happen,

insurer would agree to a land swap. That’s

according to Heather Mack, director of govern-

because the insurance policy is actually

ment relations, Insurance Bureau of Canada.

a contract between the insurer and the

“Because we would all end up in jail,” she says jokingly. “But the federal Competition Act actually prohibits a lot of that sort of

homeowner, and going outside that contract would be very difficult.”

Amending insurance contracts, how-

coordination. It would be great and would

ever, may become necessary in Fort

probably even be great for the customers,

McMurray’s Athabasca River flood plain.

but they just cannot do that.”

After the 2013 southern Alberta floods,

Even with debris removal and demolition,

the province banned building in flood

each insurance company has to individual-

plains, but exempted Drumheller and Fort

ly contract with a demolition company for

McMurray because of their well-established

each property.

flood plain communities. Now that some

Under Alberta’s insurance act regula-

of Fort McMurray’s flood plain neighbour-

tions, the homeowner also has the right

hoods have been razed by fire, it’s a differ-

to choose vendors. Insurers can suggest a

ent situation.

builder or contractor to help expedite recon-

At the end of June, the Municipality of

struction but, if a homeowner has someone

Wood Buffalo established a committee to

else in mind, it’s his or her decision, which

work through its flood plain and other land

A simple remedy to many of the potential

potentially adds players to an already

issues. No decisions have yet been made,

construction inefficiencies in rebuilding Fort

crowded playing field.

it told Oilsands Review. Flood plain land

Collaborative approach

On the positive side, Mack says that a

swapping will likely not be an easy decision

ingly important concept in the oilsands

number of insurance companies have inde-

to make, considering that it will require the

industry, where project owners, contractors

pendently chosen to hire the same project

involvement of the municipal and provincial

and stakeholders engage early in the pro-

manager, which should help in coordinating

governments, insurance companies and

cess to identify the best way for the project

contractors, “but that’s about as close as you

homeowners.

to progress efficiently. It is recognized by

can get [to working collaboratively].”

McMurray is collaboration. It’s an increas-

groups including the Construction Owners

So while the potential for collaboration and out-of-the-box thinking exists for

Association of Alberta as a key strategy to

Land swaps

improve the competitiveness of the industry

An interesting idea that could speed up the

McMurray reconstruction megaproject,

as it navigates the new oil era.

reconstruction of Fort McMurray is land

many things still need to be sorted out. Even

swaps. The municipality has land that es-

then, builders will likely have to do without

caped fire damage and is ready for develop-

any higher-level planning of their work.

Collaboration will also help an efficient rebuild of the Oilsands City.

20 • SEPTEMBER 2016 • OILSANDS REVIEW

reducing costs and timelines in the Fort

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S U S TA I N A B I L I T Y

Reforestation is a cornerstone of Cenovus Energy’s massive new caribou protection effort

“We expect at least 80 per cent of the trees planted will grow through to maturity based on the results of the pilot project,” says Michael Cody, the company’s senior adviser of land and biodiversity.

“It is the cornerstone on our efforts on caribou,” he adds. “We feel it is quite important because it gets at solving some of the root of the problem, no pun intended.”

CARTER HAYDU

The company announced in June its $32-million, 10-year Caribou aribou thrive in large tracts of undisturbed habitat,

cedented. It includes a unique combination of restoration techniques,

which is problematic when industrial activity, such

such as mounding soil in swampy areas to create drier conditions

as seismic lines, interferes with forest homogeneity

for tree growth, adding woody debris and bent tree stems in dis­

and exposes these large­yet­vulnerable animals to

turbed pathways to discourage caribou and predators from using

predation.

corridors to travel, and planting coniferous tree seedlings such as

Fortunately for the Cold Lake herd, of which only roughly 150 remain, Cenovus Energy is employing a cutting-edge restoration

larch, black spruce and jack pine.

“This is a remarkable development for boreal caribou,” said Aran

strategy that will see the planting of about four million tree seed­

O’Carroll, executive director of the Canadian Boreal Forest Agree­

lings between now and 2026. The company will use proven forestry

ment, in a statement released by Cenovus.

techniques to restore some 3,500 kilometres of old seismic lines,

The company hopes its efforts can serve as a model for the rest

access roads and other linear disturbances within an area of ap­

of industry, as well as the Government of Alberta as it develops an

proximately 3,900 square kilometres.

action and range plan for caribou recovery. As required under the

22 • SEPTEMBER 2016 • OILSANDS REVIEW

PHOTO: © ISTOCK .COM / ARTFO LIOPHOTO

Habitat Restoration project, which it believes to be globally unpre­

S U S TA I N A B I L I T Y

federal Species at Risk Act, provinces must establish plans based

“We did a pilot last fall. The technology has been used in other

on the 2012 recovery strategy for the boreal woodland caribou. In

jurisdictions in the southern United States or in situations such as

accordance with the act, Alberta will release its range plan details

tailings ponds,” Cody says. “This is a different application for exist­

for the Cold Lake herd in 2017.

ing equipment. While it is not common to find such amphibious equipment, it does exist.”

PROVEN TECHNIQUES

Increasing the roughness of land—essentially mimicking the

Cenovus proved its reforestation techniques through the suc­

sort of deadfall one finds in old forest that makes crossing the

cessful Linear Deactivation Pilot project—an innovative voluntary

terrain not worth the animal’s efforts—is key to deterring caribou

restoration initiative to grow forests along older seismic lines near

and predators from accessing planted areas. If woody debris from

projects in northern Alberta. According to Cody, preparing sites for

a cutline’s creation is still present along its edges, crews could re­

reforestation is a mechanized process, involving a track hoe or exca­

distribute that material onto the line, Cody notes. Another method

vator pushing its bucket into the soil and inverting a large mounded

would be to bend stems over with an excavator bucket.

area. After the process is complete, the company waits a season and

“One of the questions we frequently get asked is ‘Isn’t this doing

then sends people down the line to plant saplings into the mounds.

more damage?’ The reality is, though, that within silviculture—if

Because moving heavy equipment onto swampy areas can be a

we think about it not just as a single tree, but a group of trees—it

logistical challenge, the company typically waits until winter when

wouldn’t be uncommon in forestry to remove 30 per cent of stems

crews can move over the ground with greater ease in order to make

in order to benefit the remaining ones,” he says.

the mounds. Cenovus is researching amphibious technology that

“In our case, we take about five per cent of them, at most, that are be­

could allow for such work in non­frozen conditions, thus expanding

side the lines, and so it is only a very small proportion of the stems that

the time frame for preparing soil for reforestation.

are [bent] in order to generate that roughness and result we want.”

S E P T E M B E R 2 0 1 6 • J W N E N E R G Y. C O M • 2 3

S U S TA I N A B I L I T Y

MONITORING PROGRESS

Caribou restoration project area

The company will keep collecting data on vegetation growth and caribou, wolf, moose and bear movements to assess the overall impact of restoration. It monitors not only sites, but also individual animals and the overall population.

Christina Lake plant site

“The technology we would engage at the site level includes things such as these motion­activated cameras that would be at­ tached to a tree alongside the line and would document the number of animals that would use that line or be present there. At the site level, we would also measure vegetation response to treatment— how well the trees survive and grow once they are planted when

Foster Creek plant site

Fort McMurray

compared to control sites, for example, where we did not treat.

“At the individual level, we would use technology such as a collar

Cold Lake

on an animal to send a GPS signal relaying its location. In aggre­ gate, you could understand how that animal moves in the land­

Edmonton

scape and makes habitat choices.

“At the population level, we would use techniques such as the collection of pellets or scat, analyzing that material to actually generate DNA profiles, for example, to see the diet of a wolf or the

Proposed treatment area

relationships between groups of animals genetically. There is quite

Completed treatment area

a powerful area of science in genetics, and the access to that is

Cold Lake caribou herd range

0km

20km

40km

through pellet collection.”

SOURCE: CENOVUS ENERGY

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S U S TA I N A B I L I T Y

He adds, “Lastly, there would be population surveys the

“Fortunately, though, the early results we have at individual and

government does that would involve such things as overflight

site levels are that the behaviour changes are almost immediate with

population counts.”

most of the predator­prey species we are interested in.”

Other wildlife protection measures include specialized animal

All saplings are sourced from local tree species, which is

crossings to help animals get over or under pipelines so they can

important not just because Alberta regulations dictate such

move freely across operations and a tracking app called Wild Watch

practices, but also because certain species grow best in certain

that enables employees to report wildlife sightings at Cenovus

areas, and so the best reforestation results come from matching

operations.

each tree with its ideal condition. “For example, pine grows well on the high and dry ridges, or little eskers. Black spruce grows

EARLY RESULTS

well in the bog and fen areas—the lower areas we move through,”

Environmental specialists developed this restoration project—

Cody says.

encompassing a vast boreal portion of northeastern Alberta

In six­ and seven­year­old pilot projects, some saplings have

largely within the Cold Lake Air Weapons Range—to give young

grown into trees more than two metres high, he notes. While the

trees a chance to grow more quickly in some older corridors dis­

company does not expect every tree to get so big within that time

turbed by industrial development that have been slow to return

frame, Cody believes it is possible for some trees to grow by one

to forest cover.

metre every five years.

“Once [an area] is treated, our hypothesis is it will not be selected

Local First Nations contracting companies conduct much of

in a fashion preferentially anymore,” Cody says. “If we don’t see that

Cenovus’ restoration work, and there will be continuing opportun­

behaviour change, then the result would be to look at how we are

ities for aboriginal businesses to participate in the current 10-year

doing the work and see what we need to change in order to gener­

initiative. Cenovus is also sharing its caribou habitat restoration

ate the target result. In some cases, it might be that we need to wait

approach with industry peers through Canada’s Oil Sands Innov­

until the trees grow.

ation Alliance.

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S E P T E M B E R 2 0 1 6 • J W N E N E R G Y. C O M • 2 5

P R OJ E C T A N A LY T I C S

Thermal oilsands production May 2015-May 2016 (Capacity less than 75,000 bbls/d) SUNCOR ENERGY INC. MacKay River

45,000

CANADIAN NATURAL RESOURCES LIMITED Kirby South

2015 2016

40,000

CONNACHER OIL AND GAS LIMITED Great Divide

35,000

STATOIL Leismer

30,000

OSUM OIL SANDS CORP. Orion JAPAN CANADA OIL SANDS LIMITED Hangingstone ROYAL DUTCH SHELL PLC Peace River/Carmon Creek PENGROWTH ENERGY CORPORATION Lindbergh

bbls/d

HUSKY ENERGY INC. Tucker 25,000

20,000

15,000

10,000

ATHABASCA OIL CORPORATION Hangingstone

5,000

HUSKY ENERGY INC. Sunrise

0

* The Fort McMurray wildfires in spring 2016 dramatically impacted oilsands production in May.

26 • SEPTEMBER 2016 • OILSANDS REVIEW

MAY JUN

JUL

AUG SEP

OCT NOV DEC

JAN

FEB MAR APR MAY*

Four new SAGD projects with capacity less than 75,000 bbls/d started producing bitumen in 2015: Husky Energy Sunrise, Pengrowth Lindbergh, Athabasca Oil Corporation Hangingstone and Sunshine Oilsands West Ells.

Sunshine’s project is not listed here because according to AER data, it has not yet realized average production over 100 bbls/d.

P R OJ E C T A N A LY T I C S

For the most part, it doesn’t matter what the oil price is. Every blink that your eye makes is another moment that the oilsands industry keeps moving. The shovels keep digging, heavy haulers keep rolling, steam keeps injecting and pumps keep pumping. All producers can do is try to do all of it more efficiently to get more product for less investment. The current market environment makes it all the more critical that each task of these processes results in trends that raise the bar.

Here’s the latest data and analysis from the Daily Oil Bulletin, CanOils and

Oilsands Review.

Thermal oilsands production May 2015-May 2016 (Capacity more than 75,000 bbls/d) SUNCOR ENERGY INC. Firebag

225,000

IMPERIAL OIL LIMITED Cold Lake

200,000

CENOVUS ENERGY INC. Christina Lake

175,000

CENOVUS ENERGY INC. Foster Creek

150,000

MEG ENERGY CORP. Christina Lake DEVON CANADA CORPORATION Jackfish CONOCOPHILLIPS CANADA LIMITED Surmont CNOOC LIMITED Long Lake *The Fort McMurray wildfires in spring 2016 dramatically impacted oilsands production in May.

125,000 bbls/d

CANADIAN NATURAL RESOURCES LIMITED Primrose & Wolf Lake

2015 2016

100,000

75,000

50,000

25,000

0 MAY JUN

JUL AUG SEP OCT NOV DEC JAN

FEB MAR APR MAY*

In 2015, Imperial Oil was the producer to start up an expansion to a thermal oilsands project with capacity over 75,000 bbls/d.

Imperial started producing oil at its 40,000-bbl/d Nabiye Cold Lake expansion in Q1.

Suncor Energy achieved first oil from its 23,000-bbl/d Firebag debottleneck project in Q4/2015, and Cenovus Energy completed its 22,000-bbl/d optimization at Christina Lake in Q4/2015.

S E P T E M B E R 2 0 1 6 • J W N E N E R G Y. C O M • 2 7

P R OJ E C T A N A LY T I C S

Quarterly operating costs - in situ projects OPERATOR - PROJECT

Q1/2015

Q2/2015

Q3/2015

Q4/2015

Q1/2016

CENOVUS ENERGY - Christina Lake

$8.22

$8.32

$7.87

$7.80

$7.61

CENOVUS ENERGY - Foster Creek

$14.48

$13.47

$11.37

$11.66

$12.05

SUNCOR ENERGY - Firebag & MacKay River

$14.00

$13.05

$12.55

$11.65

$10.40

CONNACHER OIL & GAS - Great Divide

$16.67

$15.62

$17.57

$17.09

$28.73

MEG ENERGY - Christina Lake

$11.64

$10.72

$9.95

$9.24

$9.35

ATHABASCA OIL CORPORATION - Hangingstone1

--

--

$77.74

$54.14

$29.84

PENGROWTH ENERGY - Lindbergh2

--

$12.66

$9.66

$9.86

$8.81

HUSKY ENERGY - Sunrise2

--

$124.88

$97.22

$56.23

$38.67

HUSKY ENERGY - Tucker

$18.55

$39.02

$13.89

$10.10

$7.41

1

Started producing Q4/2015

2

SAGD producers are in an all-out war to reduce operating costs at their facilities due to the low price environment, some achieving more success than others.

Started producing Q1/2015 SOURCE: CORPOR ATE FINANCIA L RESU LTS

Quarterly netbacks - in situ projects OPERATOR - PROJECT

Q1/2015

Q4/2015

Q1/2016

CENOVUS ENERGY - Christina Lake1

$10.30

$29.76

$13.76

$7.84

-$4.09

CENOVUS ENERGY - Foster Creek1

$5.80

$23.77

$13.28

$4.78

-$8.77

CONNACHER OIL & GAS - Great Divide2

-$8.75

$10.16

-$7.08

-$12.26

-$37.52

MEG ENERGY - Christina Lake3

$8.68

$28.35

$15.56

$8.33

-$4.53

ATHABASCA OIL CORPORATION - Hangingstone4

--

--

-$73.67

-$48.22

-$35.34

PENGROWTH ENERGY - Lindbergh5

--

$31.17

$21.69

$14.09

$3.05

HUSKY ENERGY - Sunrise5

--

-$119.67

-$103.92

-$56.39

-$53.29

HUSKY ENERGY - Tucker

$10.18

$5.89

$17.75

$13.91

$5.28

1

Per barrel of heavy crude

5

Started producing Q1/2015

2

Net of diluent purchased

3

Q2/2015

Does not include power sales

Q3/2015

4

Started producing Q4/2015

SOURCE: CORPOR ATE FINANCIA L RESU LTS

28 • SEPTEMBER 2016 • OILSANDS REVIEW

During the first quarter of 2016, the price of WTI dropped to the lowest point so far in the current rout, approaching $25/bbl. The impact of the depressed prices was clearly evident in first quarter reporting. Secondquarter results are expected to improve with WTI during the period, moving closer to $50/bbl.

P R OJ E C T A N A LY T I C S

Thermal oilsands projects steam to oil ratio (Average May 2015 - May 2016) Ongoing project SOR leaders Cenovus Christina Lake, Devon Jackfish and MEG Christina Lake were joined in the last 12 months by strong performance at the new projects Pengrowth Lindbergh and Canadian Natural Resources Kirby South.

Ongoing ramp-up at Husky Energy Sunrise and initial ramp-up at Athabasca Oil Corporation Hangingstone are evident at the other end of the chart.

1.78

CENOVUS ENERGY INC. - Christina Lake

2.16

PENGROWTH ENERGY CORPORATION - Lindbergh DEVON CANADA CORPORATION - Jackfish

2.39

MEG ENERGY CORP. - Christina Lake

2.39 2.55

CANADIAN NATURAL RESOURCES LIMITED - Kirby South SUNCOR ENERGY INC. - Firebag

2.63

CENOVUS ENERGY INC. - Foster Creek

2.68 2.89

SUNCOR ENERGY INC. - MacKay River

3.16

STATOIL - Leismer

3.84

OSUM OIL SANDS CORP. - Orion

3.93

CNOOC LIMITED - Long Lake

4.11

IMPERIAL OIL LIMITED - Cold Lake

4.22

CONOCOPHILLIPS CANADA LIMITED - Surmont

4.43

CONNACHER OIL AND GAS LIMITED - Great Divide ROYAL DUTCH SHELL PLC - Peace River/Carmon Creek

4.67

HUSKY ENERGY INC. - Tucker

4.69

CANADIAN NATURAL RESOURCES LIMITED - Primrose & Wolf Lake

4.72 4.83

JAPAN CANADA OIL SANDS LIMITED - Hangingstone

7.90

HUSKY ENERGY INC. - Sunrise

39.68

ATHABASCA OIL CORPORATION - Hangingstone

SOURCE: AER

Oilsands mining production by project (March 2015-March 2016) 350,000

SYNCRUDE

The start-up of Imperial Oil’s second phase at Kearl in June 2015 resulted in the combined addition of 220,000 bbls/d of mining production capacity to the oilsands in the last three years.

The last AER data shows this newest oilsands mine is producing above its nameplate capacity.

2015 2016

Aurora North & South 300,000

SYNCRUDE Mildred Lake

250,000

SUNCOR Base operations bbls/d

SHELL Muskeg River

200,000

150,000

SHELL Jackpine CANADIAN NATURAL RESOURCES Horizon IMPERIAL OIL Kearl

100,000

50,000

0 MAR

APR

MAY

JUN

JUL

AUG

SEP

OCT

NOV

DEC

JAN

FEB

MAR

SOURCE: CORPOR ATE FINANCIA L RESU LTS

S E P T E M B E R 2 0 1 6 • J W N E N E R G Y. C O M • 2 9

P R OJ E C T A N A LY T I C S

Oilsands synthetic crude oil production (March 2015–March 2016) 400,000

SYNCRUDE Mildred Lake

300,000 250,000

SHELL Scotford

200,000 150,000 bbls/d

CNOOC Long Lake

2015 2016

350,000

SUNCOR Base operations

CANADIAN NATURAL RESOURCES Horizon

Nexen stopped producing synthetic crude oil from its Long Lake project following a fatal explosion in January 2015 and has since announced the upgrader will be shut down.

100,000 50,000 0 MAR

APR

MAY

JUN

JUL

AUG

SEP

OCT

NOV

DEC

JAN

FEB

MAR

SOURCE: CORPOR ATE FINANCIA L RESU LTS

Quarterly netbacks - upgrading projects OPERATOR - PROJECT

Q1/2015

Q2/2015

Q3/2015

Q4/2015

Q1/2016

SUNCOR ENERGY - Base operations1

$18.82

$31.82

$19.72

$13.30

$5.15

CANADIAN NATURAL RESOURCES - Horizon2

$24.18

$40.83

$30.48

$26.28

$17.88

SYNCRUDE - Mildred Lake

$20.01

$21.64

$18.78

$26.50

$16.14

1

Per barrel of SCO. Includes mining, in situ and upgrading

2

Synthetic crude oil producers have an advantage in price realization to stand-alone bitumen producers as they receive prices closer to WTI, evidenced by continued positive netbacks publicly disclosed through the downturn so far.

Per barrel of SCO. Includes mining and upgrading SOURCE: CORPOR ATE FINANCIA L RESU LTS

Quarterly operating costs - upgrading projects

1

OPERATOR - PROJECT

Q1/2015

Q2/2015

Q3/2015

Q4/2015

Q1/2016

SUNCOR ENERGY - Base operations1

$28.40

$28.00

$27.00

$28.00

$24.25

CANADIAN NATURAL RESOURCES - Horizon

$29.73

$29.25

$27.04

$28.56

$26.55

SYNCRUDE - Mildred Lake

$33.51

$49.83

$38.41

$36.11

$27.75

SHELL - Scotford

$34.78

$78.24

$26.01

$28.25

$28.80

Includes mining, in situ and upgrading operations SOURCE: CORPOR ATE FINANCIA L RESU LTS

30 • SEPTEMBER 2016 • OILSANDS REVIEW

All oilsands mining/upgrading operators that publicly disclose operating costs have been able to realize reductions over the last year, and continue to seek to drive down these expenditures.

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IMAG E: JEREMY SEEMAN

P R OJ E C T D E L I V E RY

32 • SEPTEMBER 2016 • OILSANDS REVIEW

P R OJ E C T D E L I V E R Y

bers of the steel fabrication industry and labour providers developed the document. All sides had to be represented so that the checklists would be fair and balanced for all parties. The committee starting working on the plan early in 2015, and it was presented at COAA’s 2016 Best Practices Conference in May. According to Staples, the docu­ ment was necessary because of the “astronomical growth” of modularization in Alberta over the last few years. He notes the Edmonton region used to have just one or two mod yards in operation, but is now home to around 10. While there are several regions of the world with tidewater access that have become experts in modularization, especially for offshore projects, Alberta is becomtices which have been successful for them,” explains COAA adviser The framework covers many

A new COAA document brings together years of best practices to help build the next generation of oilsands modules DAVE S. CLARK

“In terms of landlocked modularization, Alberta is on

Larry Staples.

M

ing an industry leader as well.

the leading edge. We have more

different aspects of modular

experience than anyone else

construction, including design,

over the past couple of decades,”

contracting, module assembly,

Staples says. “We have the

odularization is crucial

transportation and assembly, but

experi­ence, and we have the

to ensuring large-scale

its overarching theme is safety.

ability to innovate.”

projects in Alberta are

“Safety, of course, is the

safer, more organized and more

foundation of everything. As

LESSONS FROM THE EARLY DAYS

cost effective. A newly released

our current strategic mantra

There are three major benefits to

best practices document by the

highlights, we’ve found that the

modularization when compared

Construction Owners Associ­

same organization practices,

to stick building, and COAA’s

ation of Alberta (COAA) has been

the same project management

best practices document sets

designed with the hopes of push-

disciplines, the same communi-

ways for Alberta’s construction

ing those benefits to the next

cation skills among the project

industry to build upon them. The

level and further strengthening

leaders that lead to projects with

first is efficiency, which comes

the appeal of modularization.

very good safety records, those

from working in a controlled

“Like most of COAA’s best

same management disciplines

environment not subject to

practices, the new modulariza-

and communication skills lead

weather conditions. Modules

tion assembly framework is a

to well organized and productive

are also built in more centrally

distillation of the best thinking

projects,” Staples says. “Working

located areas with a large pool of

of the best people in the business

on safety is job number one, but

workers, like Edmonton, rather

in Alberta. The new modular best

also wins in productivity as well.”

than in more remote areas that

practice is a series of checklists,

A committee made up of

which are a distillation of prac-

owner representatives, mem-

require workers be transported in and housed.

S E P T E M B E R 2 0 1 6 • J W N E N E R G Y. C O M • 3 3

P R OJ E C T D E L I V E RY

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—LARRY STAPLES, adviser, COAA

» Extensive staging area and storage

The second benefit to modu­

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B or the foundation piles were

parallel streams of construction

a metre in the wrong direction.

happening at the same time,

Those lessons from the early

which cuts down on the overall

days have been well learned

build time.

and have been incorporated in

“Rather than starting at the

JWN Consulting

line up with the piping on Unit

larization is the ability to have

the checklists to ensure those

east end of a site and building

kinds of issues are covered off at

steadily westward, you can have

the planning and drawing stage

two or three mod yards working

rather than the jackhammering

on the parts of the plant, and it

stage,” Staples says.

all comes together in a relatively short period of time,” Staples says.

The third benefit is safety.

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34 • SEPTEMBER 2016 • OILSANDS REVIEW

greatly outweigh any down­

upgraders or petrochemical

sides, but the best practices

facilities. Now, the next step

document will help to further

is to concentrate the modules,

eliminate potential shortcom-

increasing their density and

ings to modularization, he says.

add more equipment, piping

“In the early days of modu­

and electrical so they can be set

larization, when the modules

down and operated with minimal

actually showed up at site, there

additional on­site work.

would be a great groan of dismay

Fluor Canada is one of the

when the piping on Unit A didn’t

companies pushing this concept

PHOTO: A ARON PARKER

T: (807) 345-6400

P R OJ E C T D E L I V E R Y

forward. It was recently awarded

Edmonton to Fort McMurray

COAA’s modularization innov­

to examine how a heavier duty

ation award for its work on the

trailer designed to handle the

Shell Quest carbon capture and

increased loads would fare on

storage project. Rather than

the roadways. Rather than the

designing the project and then

standard eight-wheel-wide trail-

trying to determine how it could

er, the pilot used a trailer that

be split into modules, Fluor con-

was 12 wheels wide, which could

ceptualized it from the start as

handle a much heavier load.

being modularly built. This was

Now that the module has been

a subtle but significant shift in

moved safely, COAA is in discus-

thinking about modularization,

sion with Alberta Transportation

according to Staples.

to see how heavier loads could

“That has really changed the way that a highly modularized

be authorized and permitted.

“Heavy modules can have a

project moves from the concep-

very significant improvement

tual stage through the design

on total cost of a project, up to

stage,” he says. “The thinking

sev­eral per cent. On a $5-billion

about earlier and greater mod-

project, that’s pretty important.

ularization has led to a change

It starts to move Alberta back

in thinking about how to do pro­

into the range of being produc-

jects. The equipment needs to be

tive and being able to compete

ordered much earlier if it’s going

for investment dollars. These

to be installed in the mod yards

kinds of improvements in project

rather than on site. The layout

economics are significant in not

of the plant needs to be frozen

just reducing costs to owners, but

much earlier because we need to

improving the investment attrac-

know exactly how the modules

tiveness,” Staples says.

are going to fit together, rather

Being able to make and trans-

than leaving it to be adjusted

port modules more cost effective-

during that stick-building stage.”

ly also makes it more attractive to

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The increased complexity and

overseas, according to Staples.

density of modules does pres-

“As we make these types of

ent a major challenge—how to

modules more attractive to the

transport them to site. Alberta

owners, it gives a competitive

Transportation has set limits on

advantage to local Alberta fab

the maximum width, length and

yards, versus offshore fab yards

height of modules, and those

that now have to fit smaller mod-

limits are based on what can

ules onto ships and be transport-

safely be moved down a two-lane

ed over the Rocky Mountains,”

highway in the province. While

he says. “If we build them here

those units can’t get any larger in

in the Edmonton region or the

size, they can get heavier if more

Industrial Heartland region and

equipment is added to them in

we can transport them safely

the mod yards rather than on site.

and relatively quickly to Fort

In March, COAA participated

McMurray, it’s a way of building

in a pilot project with Mammoet

our own economy, building our

and Suncor that saw the largest

own expertise and high paid jobs

possible module move from

within Alberta.”

Visit www.edmontonexchanger.com for a detailed product and service listing.

S E P T E M B E R 2 0 1 6 • J W N E N E R G Y. C O M • 3 5

TECH_SERIES

Throughout 2016, Oilsands Review is publishing a series of technology-centric stories. Watch for more in our November edition.

KEEPING

As more SAGD wells age, more will need to be re-drilled to sustain production rates.

Doing this effectively—or not—can make a big mark on a producer’s bottom line.

36 • SEPTEMBER 2016 • OILSANDS REVIEW

TECH_SERIES_SUBSURFACE

YOUR

DISTANCE

NEW POSITIONING TECHNOLOGIES ALLOW SAGD WELLS TO BE DRILLED CHEAPER WITH LESS DOWNTIME

The first two values—the inclination and compass direction of the drill string—are obtained using measurement­while­drilling (MWD) tools.

The third value—the measured depth—is easily and accurately calculated from the length of pipe in the hole. These three values are

PAT ROCHE

integrated and used to calculate where the well is in the subsurface.

The problem is that the inclination and azimuth readings, while very accurate, are imperfect. The azimuth, or horizontal direction,

They call it ranging.

may be off by 0.1 degrees. When a well starts drilling, these errors

“obtaining the range of a target by adjustment after firing past it or

are negligible. But with each survey reading, the position error is

short of it.” In SAGD drilling, unlike field artillery, there’s no such

compounded.

luxury as multiple tries. If the horizontal wells miss their target, the

Over two kilometres of drilling, this can add up. Take, for ex­

cost can be millions of dollars—either in bypassed bitumen because

ample, a 2,000­metre wellbore that was designed to be due east. At

wells aren’t in the best resource, or in wasted steam because well

the toe, the estimated compass direction could be out by as much

pairs are too close together.

as 20–25 metres to the north, or 20–25 metres to the south. That’s as

SAGD, which accounted for roughly 850,000 bbls/d of Alberta bitumen production in 2015, was commercialized at the start of

much as 50 metres of total discrepancy.

In the SAGD industry, this error in a well’s position is called the

this century. There are now thousands of SAGD wells on commer­

ellipse of uncertainty. It becomes an issue particularly when one

cial production in Alberta, with the oldest dating back more than a

well in a SAGD well pair fails and needs to be re­drilled.

decade and a half.

It’s no surprise that operators would want a better ranging tool.

As with any equipment, the older a well is, the more likely it is

Halliburton and Scientific Drilling International (SDI) both recently

to fail. As more SAGD wells age, more will need to be re­drilled. The

field­tested new ranging systems, which representatives described

faster these re­drills can be done, and the less production downtime

at the SPE Canada Heavy Oil Technical Conference in Calgary earlier

it involves, the less impact it will have on a producer’s bottom line.

this year.

THE PROBLEM: IMPERFECT SURVEYS

PHOTO: HA LLIBURTON

may be out by as much as one degree and the inclination reading

One definition in the Oxford Dictionary describes ranging as

REDUCING DOWNTIME

Crews drilling horizontal well pairs need to know where the drill bit

For the past few years, Halliburton has been developing a ranging

is relative to reservoir targets, and also relative to other wells. To do

tool that would improve on its widely used magnetic guidance tool

this, they take a survey every time a joint of drill pipe is added to the

(MGT). In SAGD, the lower well—the oil producer—is drilled first.

drill string—roughly every 10 metres.

Then the steam injection well is drilled a few metres above, and

The survey consists of three pieces of information: the inclination,

parallel to, the producer. Halliburton puts its MGT in the first well—

or tilt, of the drill string at that point; the azimuth, or compass direc­

called the target well—to maintain the correct distance while drilling

tion; and the measured depth, which is the length of the wellbore.

the second well.

S E P T E M B E R 2 0 1 6 • J W N E N E R G Y. C O M • 3 7

TECH_SERIES_SUBSURFACE

“we said, ‘what is the limit of the technology?’ then set about exploring that.”

– CLINTON MOSS, president, Marksman Ranging Technologies

The MGT is an electromagnetic solenoid—a coil that acts as a magnet when

ranging technique to address this issue.

than what these construction people have

The so-called gradient discovery tool has

been doing,” says Clinton Moss, president

undergone field trials, and the results are

of SDI’s Calgary­based Marksman Ranging

discussed in an SPE paper by physicist

Technologies division. “We said, ‘What is

Hsu­Hsiang “Mark” Wu, electrical engineer

the limit of the technology?’ So then we set

Akram Ahmadi and mechanical engineer

about exploring that.”

Sean Hinke, all with Halliburton.

With the new method, the ranging tool can simply be attached to the wellhead of the target well; it doesn’t need to be con­

Originally an independent company started by Moss and partners in Edmonton in 2014, Marksman was acquired last year by SDI. The question SDI’s Calgary team set out

veyed into the wellbore. For that reason, a

to answer was, could they create enough

well may have to be taken off production for

magnetic field on the earth’s surface that

only a couple of days rather than a couple of

a meaningful signal could be detected

weeks with the current system.

downhole by an MWD sensor in the drilling

Also, if you don’t need wellbore access,

assembly? The answer is yes, according to

carrying electric current. Run into the well

then you don’t need space to set up a wire­

an SPE paper by Moss and Doug Ridgway, a

to be twinned, the MGT creates a magnetic

line truck by each well pad, so potentially

physicist at SDI.

field that is detected by MWD sensors in the

wellheads could be closer together, says

parallel well that is being drilled.

Hinke. This would reduce upfront facilities

over the path of the planned horizontal well.

costs, which are a significant portion of the

GPS receivers pinpoint the exact location of

target well on the MGT coil and creating

overall spend on a new pad. Tighter well­

the wires on the surface. An electric current

a magnetic field of a known strength and

head spacing means less structural steel,

is sent through those coils of wire, gener­

orientation, the driller of the second well can

shorter pipelines and smaller well pads,

ating a magnetic field. When this magnetic

determine the distance and direction from the

which reduces capital costs and the envir­

field is detected by the MWD sensor, it is

target well. Halliburton says its MGT has been

onmental footprint.

used to calculate the location of the drill bit.

By putting a known current down the

used to drill more than 2,000 injector wells.

In its SPE paper, Halliburton thanked

Coils of wire are laid out on the ground

The current SDI tool is limited to shallow

Cenovus Energy, Canada’s biggest SAGD

horizontal wells, but Moss says the com­

tools is they have to be placed inside the tar-

producer, for supporting the field trials of the

pany is working on increasing the range.

get well. The guidance tool is conveyed into

new ranging technology. However, the com­

the wellbore on either coiled tubing or wire­

pany declined to comment for this article.

operating at 250 metres [true vertical depth]

line tractor, which means a wireline truck or

“It’s too early in the evaluation stage for us to

or less,” says Moss. “350? Stretching it. 450?

coiled-tubing rig has to be brought in.

provide any insights,” explains Reg Curren, a

Currently out of reach.” The deepest SAGD

Cenovus spokesman.

wells in Canada are between 450 and 550

But the downside of the MGT and similar

This is costly and time consuming—the

metres deep.

more personnel and equipment on site, the higher the price tag. And if a well is being

“Right now, we’re quite comfortable

ABSOLUTE CERTAINTY

But at the depths where it works, SDI’s

drilled to replace a failed well on a produc­

Houston­based SDI, a Halliburton competi­

new ranging tool has achieved sub­metre

ing well pad versus on a new well pad, work

tor, took a different approach in building its

accuracy, Moss says. “We actually did as

has to be done to prepare the target well,

new ranging tool.

good as 25 centimetres at a total depth of 125

increasing production downtime.

Instead of magnetizing the wellbore or

metres. So you’re talking about better than one per cent accuracy.”

To get the MGT into a producing well­

wellhead, SDI adapted a technique the con­

bore, the well has to be taken off production

struction industry has used for many years

and the wellhead has to be disconnected

to install underground utilities. Machines

new technique has measurement errors,

from all the flowlines. A service rig may be

such as the ubiquitous Ditch Witch routinely

however small. But unlike conventional

brought in to pull out the completions string,

drill directionally under streams and streets

technologies, SDI’s method doesn’t com­

production tubing and possibly downhole

to install cables and other underground

pound the error as the wellbore is extended.

instrumentation and pumps.

utilities. An electromagnetic signal guides a

What if the driller could determine the distance and direction from an existing well without putting the ranging tool inside the wellbore? Halliburton has devised a new 38 • SEPTEMBER 2016 • OILSANDS REVIEW

Like conventional survey readings, SDI’s

“The most important thing here is...

directional drill underneath a road or river to

there’s no growing uncertainty,” says Moss.

a targeted location on the opposite side.

“It’s for all intents and purposes a very

“So we said, okay, SAGD drilling, particu­ larly north of Fort McMurray, is a lot deeper

accurate measurement that has noncumulative uncertainty.” In other words,

TECH_SERIES_SUBSURFACE

because each survey reading is an absolute position based on the GPS, one measurement doesn’t depend on the previous one.

While Halliburton’s new ranging tool gives the drill bit’s location relative to an existing wellbore, the new SDI ranging tool is designed to provide an absolute position of any shallow horizontal wellbore.

AVOIDING COLLISIONS

As of June, SDI said its new ranging tech­ nique had been used on eight SAGD wells at depths of 100–250 metres for two different operators in northern Alberta. About half of those were for Suncor Energy.

The biggest benefits of the SDI technol­ ogy are collision avoidance and knowing the exact position of the well as it is drilling, says

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Troy Abs, a senior drilling engineer at Suncor.

Because the SDI tool provides an absolute position via the GPS co-ordinates, Abs says the risk of collision with existing wells would be significantly reduced because the ellipse of uncertainty would be largely eliminated.

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He pointed out that collision avoidance is particularly important on thermal oil developments, which are crisscrossed by observa­ tion wells and stratigraphic wells, along with steam injection and oil production wells.

The Suncor drilling engineer says the technology has some limitations, such as the depth restriction. But his overall experi­

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ence with the field trials was positive. “It helped us out a lot—to get better accuracy and avoid collision. You’re certain of where you are, so it gives you a lot of confidence.”

Suncor tested the SDI technology in tan­ dem with conventional magnetic ranging and the results compared well. “At this point, it’s not applicable to everything that we do [in SAGD drilling], but there are areas that it will definitely help,” Abs says.

The other advantage, he says, is that if

S E A R C H | C O M PA R E | C O N N E C T

an existing well has to be sidetracked or re­ drilled, it can be done with more confidence and less hassle. Conventional ranging tools have to be deployed within the target well, which can mean shutting down the well, pulling the tubing and other costly and

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time-consuming preparations.

S E P T E M B E R 2 0 1 6 • J W N E N E R G Y. C O M • 3 9

TECH_SERIES_SUBSURFACE

Researchers at the University of Calgary are using high-tech visualization techniques in pursuit of more efficient and costeffective thermal oilsands production.

SAGD

CAVE

RESERVOIR SIMULATION GETS A BOOST FROM VIRTUAL AND AUGMENTED REALITY AT THE U OF C

PHOTO: U OF C

LYNDA HARRISON

40 • SEPTEMBER 2016 • OILSANDS REVIEW

TECH_SERIES_SUBSURFACE

A

team of researchers at the

Visualization techniques and hardware

Having this flexibility allows the engin­

University of Calgary (U of C) is

in general are advancing rapidly. A lot

eers to research innovative approaches that

using virtual reality (VR), aug­

more is possible on desktops and even

can help analyze complex scenarios.

mented reality and advanced

tablets and phones than was ever possible

visualization techniques to help

in the past.

SAGD producers better manage

“This is even more the case for other

“For example, we are developing tools that can take advantage of [VR] in a variety of platforms including commodity head-

their complex reservoirs to optimize oper­

mediums such as virtual reality and

mounted displays or large-scale collaborative

ations and improve costs.

augmented reality,” he says. “Although the

VR in our advanced visualization facility.”

Their tools are even being used to help

promise of the technology was appreci­

one SAGD operator bring back online wells

ated a decade ago and even earlier, only

that were temporarily shut in during the

now has the hardware, the tools and the

One key issue that needs to be addressed

wildfires this spring.

maturity of interaction design caught up

is the need for better heat-loss modelling.

to the promise.”

The U of C team has developed a stand-

The group is led by Zhangxing (John) Chen, NSERC/AITF/Foundation CMG indus­

The collaboration centre is used to visu-

HEAT-LOSS MODELLING

alone thermal wellbore simulator to handle

trial research chair in reservoir simulation at

alize data for internal and external collab­

several different wellbore configurations

the U of C’s Schulich School of Engineering.

oration, teaching, presentations and outreach.

and completions. It can also be fully coupled

According to Chen, VR is great for sci­

Commercial tools run existing desktop

with the facility’s SAGD simulator.

entific visualization because of the larger

applications in VR applications to show data

variety of interaction possibilities compared

sets; however, there are limitations to these

to model heat loss from tubing walls to the

to a traditional desktop, as well as the com­

tools since they are translating 2­D applica­

surrounding formation, says Chen.

plete immersion and preservation of spatial

tions to a 3­D medium but are not actually

perception.

3­D applications.

For example, research has shown that

For this reason, and to support specif-

The simulator uses a fully implicit method

Instead of implementing the common Ramey method—which has been around since 1962 for heat­loss calculations and has

a specific benefit of VR is that it allows

ic directions, the University of Calgary

been shown to be a source of large errors—

spatial judgments that require careful visual

team has developed its own applications.

Chen’s team’s wellbore simulator runs a

inspection of small objects, he adds.

“Although our applications are prototypes,

series of computational fluid dynamical

we have had positive feedback and hope

(CFD) models for the buoyancy­driven flow

and analyze 3­D data in 3­D, which is more

that as they become more mature they will

for different annulus sizes and lengths and a

straightforward and intuitive.

be used to support our projects,” says Chen.

number of tubings.

Another benefit is the ability to work with

Also, he says there has recently been a lot

The team also has an advanced visual-

Based on these CFD models, correlations

of investigation into improving the analysis

ization facility where members use 2­D and

are derived that can conveniently be used

prior to simulation using heuristics, explora­

3­D technology to analyze complex data sets

for more accurate heat-loss estimation from

tory analysis and proxies, to ensure that valu­

to collaborate and demonstrate projects.

the wellbore to the surrounding formation

able time spent in simulation is more targeted and provides greater value to a project.

“These techniques benefit from collabora­

“By having a facility that can support a variety of visualization mediums, we have maximum flexibility to match the correct

for SAGD injection wells with single or mul­ tiple tubing strings, he explains.

The wellbore simulator can handle

tive interactive methods such as the ones we

visualization need with the appropriate

thermal processes that involve sophisti-

use in our large­scale VR system,” says Chen.

technology,” Chen says.

cated wellbore configurations, complex

S E P T E M B E R 2 0 1 6 • J W N E N E R G Y. C O M • 4 1

TECH_SERIES_SUBSURFACE

fluid flow and heat transfer in the tubing,

“It’s good to have a simulator to give

“It’s good to have a simulator to give you the real-time situation on the ground without spending too much money on measurement.”

annulus, wellbore completion and sur­

you the real-time situation on the ground

rounding formation.

without spending too much money on mea­

– Chao (Charlie) Dong, reservoir engineer, ConocoPhillips Canada

simulator provides real-time information

It can also look at complex but common

surement,” Dong says. “We’re still testing the

wellbore configurations such as multi­parallel

software. It’s quite beta, but we’ve had some

or multi-concentric tubings, says Chen.

successful applications.”

CONOCOPHILLIPS CANADA AND BRION

OPTIMIZATION RUN TIMES DROP

ENERGY GET THE FIRST CRACK

SIGNIFICANTLY

The wellbore simulator is being used by

In another reservoir modelling improve­

industrial sponsors Brion Energy and

ment, the university’s reservoir simulation

ConocoPhillips Canada.

group has developed a parallelization

ConocoPhillips is testing the technology

technology for running a SAGD simulator on

to potentially solve challenges it has with

multiple cores or central processing units

hot spots (steam from a SAGD injector by­

(CPU) on a cluster.

passing directly to a producer) and to help it

The parallel SAGD simulator can be run

bring on wells that were shut in for a month

on thousands of CPUs simultaneously in a

due to the Fort McMurray wildfires in May.

parallel fashion, and it can potentially be

The U of C’s standalone thermal wellbore

thousands of times faster than a serial SAGD simulator on a single CPU.

and connects directly to the reservoir, says

“This means that a simulation run that

ConocoPhillips Canada reservoir engineer

used to take days or even weeks to complete

Chao (Charlie) Dong.

now requires only several minutes.”

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42 • SEPTEMBER 2016 • OILSANDS REVIEW

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C OV E R S TO R Y

Saying

GOODBYE TO THE LONG LAKE SCO DREAM

Photos inside the last decade at Long Lake as Nexen shuts down its once-touted upgrader and considers its oilsands future.

DEBORAH JAREMKO

DECEMBER 2000 50-50 partners Nexen and OPTI Canada file the regulatory application for an integrated 70,000-bbl/d project at Long Lake using SAGD and OPTI’s proprietary OrCrude upgrading technology. The facility would be the first in situ project to have an integrated on-site upgrader, the first commercial use of OrCrude and the first commercial application of gasification in Canada. One of the key drivers for the technology was to reduce natural gas consumption and costs. Suncor was OPTI’s original partner but backed out.

T

he upgrader was the centrepiece of the Long Lake SAGD project when it started operating in fall 2008. Its com­ bined OrCrude and gasification processes were expected to reduce costs by lowering dependence on natural gas. But, largely because the project has been unable to achieve its design capacity and associated economies of scale, the operating costs have been astronomical.

Operating statistics for Long Lake have not been publicly disclosed since the $15.1­billion acquisition of Nexen by CNOOC in late 2012. Nexen’s financial statements for the third quarter of 2012 include a realized price of $80.13/bbl for Long Lake crude, with $77.36 in per barrel operating costs.

The Long Lake SAGD pilot started operating in 2003.

2005

2001 OPTI starts operating a 500-bbl/d OrCrude demonstration plant near Cold Lake, processing a variety of Cold Lake and Athabasca crudes.

BARRELS PER DAY

2004 Long Lake Phase 1 (70,000 bbls/d of SCO capacity) receives corporate sanction; construction and drilling begin. Capital cost is expected to be $3.4 billion.

AUGUST 2003 2003 Nexen and OPTI start operating a SAGD pilot at the Long Lake site.

44 • SEPTEMBER 2016 • OILSANDS REVIEW

Regulatory approval is received for Long Lake Phase 1, consisting of 70,000 bbls/d of bitumen production and 140,000 bbls/d of SCO capacity.

2005

PHOTO: (BOT TOM RIG HT ) PEMBINA INSTITUTE

C OV E R S TO R Y

Nexen chief executive officer Fang Zhi told reporters in July that shutting down the upgrader had been decided in order to maintain the project’s economic viability.

The recommendation had been made by an “oilsands business continuity team” that was established after the explosion to con­ sider the longer-term economic viability of the Long Lake asset, Zhi said.

The project will move to SAGD only “in the interim.”

“CNOOC Limited’s acquisition of Nexen was made with a long­term view to acquire a strong and diverse portfolio of long-term assets. CNOOC Limited remains committed to growing its Canadian production profile and our oilsands assets are an important component of this strategy.”

2008

OPTI Canada CEO Jim Arnold (center left, holding scissors) and Nexen CEO Charlie Fischer (center right, holding scissors) are joined by dignitaries to celebrate the opening of the Long Lake project in fall 2008.

OCTOBER 2008 First oil is achieved at Long Lake Phase 1, followed by start-up of the upgrader.

Capital cost is finalized at $6.1 billion.

According to data from the Alberta Energy Regulator (AER), production reaches 15,000 bbls/d before the end of the year.

Unfortunately, it would be stuck near that level for the next year.

FINAL COST:

$6.1 billion PRODUCTION REACHES:

15,000 BARRELS PER DAY

2007 Construction is completed and first steam is achieved. Nexen operates the SAGD silos while OPTI operates the upgrader. The two companies apply for Long Lake South, a two-phase 70,000-bbl/d bitumen production project designed to fill the upgrader to its approved capacity of 140,000 bbls/d.

2006

SAGD drilling at Long Lake in 2005.

Aerial view of the integrated Long Lake facility as construction continues in 2006.

S E P T E M B E R 2 0 1 6 • J W N E N E R G Y. C O M • 4 5

C OV E R S TO R Y

JANUARY 2009

JUNE 2015

Nexen acquires a further 15 per cent ownership of Long Lake from a financially challenged OPTI and takes over operatorship of the full project.

A pipeline that is part of the Kinosis SAGD expansion ruptures, but goes undiscovered until July due to failure of the automation leak detection system.

2010 Production nears 30,000 bbls/d. Nexen continues a drilling program to add wells and fill the upgrader with bitumen production.

Nexen SVP Ron Bailey displays maps of the June 2015 pipeline spill at Long Lake.

2014 NOVEMBER 2011 CNOOC acquires OPTI for approximately US$2.1 billion, and acquires its 35 per cent ownership of Long Lake.

acquired by CNOOC for US$2.1 billion

In 2014, CNOOC commissioned a 20,000-bbl/d SAGD capacity expansion called Kinosis, designed to fill the upgrader, which had been significantly underused since the 2008 start-up.

2011 2013

2012 In 2011, OPTI Canada CEO Christopher Slubicki sold the company to CNOOC for US$2.1 billion.

46 • SEPTEMBER 2016 • OILSANDS REVIEW

Approval is granted for Long Lake South; Nexen renames the project Kinosis and starts construction on the first 20,000-bbl/d phase, designed to fill the upgrader. CNOOC announces it will acquire Nexen for $15.1 billion, including full ownership of Long Lake. The deal prompts the Government of Canada to adjust its foreign investment rules going forward in order to limit the control state-owned oil companies can have over Canadian oilsands assets.

PHOTOS: ( TOP) THE C ANADIAN PRESS; (MIDDLE ) NE XEN

Production reaches 40,000 bbls/d.

C OV E R S TO R Y

JULY 2015

JANUARY 2016

The pipeline rupture is identified. It is described as one of the largest onshore spills in North American history, spilling about 31,000 barrels of bitumen emulsion.

The AER issues a project suspension order in August following Nexen’s voluntary self-disclosure of pipeline noncompliance.

The AER lifts the suspension order in stages starting in September, and its related investigation continues. In 2015, production reaches 50,000 bbls/d.

An explosion occurs at the Long Lake upgrader’s hydrocracker, killing 52-year-old maintenance worker Drew Foster and critically injuring journeyman millwright Dave Williams. Operations were temporarily shut down. The AER investigation continues.

View of the upgrader unit damaged by the January 2016 explosion that killed two Nexen employees and marked the beginning of the end for the upgrader.

MAY 2016 Massive wildfires around Fort McMurray force the evacuation of 12 oilsands production facilities, including Long Lake. The fire passed right through the facility, Nexen senior vice-president Ron Bailey says, with minimal damage, mainly to a 150-man camp and electrical components.

PHOTOS: NE XEN

JULY 2016 Nexen announces the results of its root-cause investigations for both the pipeline rupture and the hydrocracker explosion. The pipeline rupture is blamed on incompatible pipeline design for the muskeg conditions, which Nexen blames both on itself but also on its contractors and subcontractors. The explosion was “a result of work being performed that was outside of the scope of approved work activities.”

Nexen says the upgrader will be moved into winter preservation, or “cold stack” mode, with no timeline for restart. Long Lake will operate as SAGD only.

A SAGD well pad at Long Lake, with the central processing facility in the background.

Going forward, the project’s production will only come from its SAGD wells.

S E P T E M B E R 2 0 1 6 • J W N E N E R G Y. C O M • 4 7

BREAKING NEWS If your industry news is coming from a live news feed or from content aggregators, it’s probably common knowledge.

The Daily Oil Bulletin (DOB) provides in-depth, original content and energy intelligence that gives you a competitive edge, including:

not all news sources are equal Choose from daily or monthly emails

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Exclusive reports

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INFORMATION THAT GIVES YOU AN EDGE start a trial now on dailyoilbulletin.com/freetrial

Noon-hour Today’s Headlines Monthly LNG Bulletin

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.

APRIL TOTALS

Synthetic crude

Calculated using NetThruPut monthly WCS index 50

2015 2016

40,000

40

35,000

$32.39

39,367,000 BBLS or 61.7% 24,409,300 BBLS or 38.3%

30,000

63,776,300 BBLS total

US$/bbl

Thousand bbls

2015 2016

2015

45,000

25,000 20,000

30

20

2016

15,000 10,000

10

5,000

46,541,400 BBLS or 71.6% 18,439,800 BBLS or 28.4%

0 M

A

M

J

J

A

S

O

N

D

J

F

M

0

64,981,200 BBLS total

A

Natural gas: Spot prices at AECO trading hub in Alberta

J

S

O

N

D

J

F

M

A

M

J

North American carbon steel prices

Monthly averages to July 5, 2016

Hot rolled coil

3.50

A

2015 2016

Structural sections and beams

900

$2.99

3.00

Reinforcing bar

2015 2016

800

$744

700

$707

US$/tonne

C$/GJ

2.50 2.00 1.50

600

1.00

$566

500

0.50 0

400 AUG

SEP

OCT

NOV

DEC

JAN

FEB

MAR

APR

MAY

JUN

JUL

JUL

AUG

SEP

OCT

NOV

DEC

JAN

FEB

MAR

APR

MAY

JUN

Mined oilsands bitumen production Current 3 month avg. (January 2016-February 2016)

BIGGEST MOVER

Previous 3 month avg. (October 2015-December 2015)

Imperial Oil - Kearl

Suncor Energy Inc. - Base operations

-29,303 (from 222,472 to 193,196)

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

TOTAL MINING AVERAGE

Shell Canada - Muskeg River Syncrude Canada - Mildred Lake

Current three months

Previous three months

1,284,109

1,230,872

Shell Canada - Jackpine 0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

Production (bbls/d)

S E P T E M B E R 2 0 1 6 • J W N E N E R G Y. C O M • 4 9

O I L S A N D S DATA

Alberta synthetic crude oil production Current 3 month avg. (January 2016-March 2016)

BIGGEST MOVER

Previous 3 month avg. (October 2015-December 2015)

Syncrude Canada Ltd. - Mildred Lake

Suncor Energy Inc. - Base operations

49,998 (from 259,809 to 309,807)

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

TOTAL CRUDE PRODUCTION AVERAGE

Canadian Natural Resources Limited - Horizon CNOOC Limited - Long Lake 0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

Current three months

Previous three months

1,072,874

977,595

Production (bbls/d)

Top 10 thermal oilsands projects bitumen production Current 3 month avg. (January 2016-March 2016)

BIGGEST MOVERS

Previous 3 month avg. (October 2015-December 2015)

ConocoPhillips Canada Limited Surmont

Suncor Energy Inc. - Firebag

19,616.1

from 34,869.2 to 54,485.3

Imperial Oil Limited - Cold Lake Imperial Oil Limited Cold Lake

Cenovus Energy Inc. - Christina Lake Cenovus Energy Inc. - Foster Creek

Canadian Natural Resources Limited Primrose & Wolf Lake

Devon Canada Corporation - Jackfish Canadian Natural Resources Limited - Primrose & Wolf Lake

10,320.9

from 154,865.9 to 165,186.8

-18,578.6

from 100,137.1 to 81,558.5

MEG Energy Corp. - Christina Lake TOTAL CRUDE PRODUCTION AVERAGE

ConocoPhillips Canada Limited - Surmont Suncor Energy Inc. - Mackay River

Current three months

Previous three months

1,027,185.1

1,017,149.1

Canadian Natural Resources Limited - Kirby South 0

50,000

100,000

150,000

200,000

Production (bbls/d)

Lowest 10 thermal project steam to oil ratios Current 3 month avg. (January 2016-March 2016)

BIGGEST MOVERS

Previous 3 month avg. (October 2015-December 2015)

Andora Energy Corporation Sawn Lake

Cenovus Energy Inc. - Christina Lake

-2.04

from 4.49 to 2.45

Pengrowth Energy Corporation - Lindbergh Pilot Pengrowth Energy Corporation Lindbergh Pilot

MEG Energy Corp. - Christina Lake Devon Canada Corporation - Jackfish Andora Energy Corporation - Sawn Lake

Cenovus Energy Inc. Foster Creek

Canadian Natural Resources Limited - Kirby South

0.18

from 2.08 to 2.26

0.23

from 2.79 to 3.02

Suncor Energy Inc. - Firebag TOP TEN AVERAGE

BlackPearl Resources Inc. - Blackrod Suncor Energy Inc. - Mackay River

Current three months

Previous three months

2.50

2.69

Cenovus Energy Inc. - Foster Creek 0

0.5

1.0

1.5

2.0

2.5

3.0

Steam injected:oil produced

50 • SEPTEMBER 2016 • OILSANDS REVIEW

3.5

4.0

4.5

5.0

O I L S A N D S DATA

FirstEnergy oilsands, integrated and large cap indexes Oilsands

Integrated

Large cap

CHANGE SINCE JULY 7, 2015

Recorded until July 7, 2016

120

INTEGRATED

2015 2016

7.58 7.28 9.82

100

$82.65 80

LARGE CAP

60

$76.79

40

OILSANDS 20

$19.56 0 JUN

JUL

AUG

SEP

OCT

NOV

DEC

JAN

FEB

MAR

APR

MAY

JUN

JUL

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 MONTHLY AVERAGE

Recorded until July 18, 2016

$13.50 15

15

10

10

5

5

0

JUNE 2016 $12.21

20

JULY 2016 $13.28

20

JULY 2015 $15.37

25

2015 2016

JUNE 2015 $8.49

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

25

0 JUN

JUL

AUG

SEP

OCT

NOV

DEC

JAN

FEB

FIRSTENERGY CAPITAL OILSANDS PRICING UPDATE The past few months have seen the Canadian crude oil industry pass through its most trying times on record. It wasn’t driven by the latest round of low and mediocre prices, but by the Fort McMurray wildfires. No single prior naturally occurring event has ever matched this level of disruption and destruction for Canadian oil producers.

Safety concerns and a lack of personnel due to mass evacuations necessitated the shutdown of production at about 10 production sites.

At their height, the shutdowns impacted nearly 1.5 million bbls/d of crude oil production, a mix of synthet-

ic and non-upgraded bitumen, with a cumulative production loss in excess of 40 million barrels by the end of June. As of early July, it appears that all but a small amount of production has returned to full service, but the impacts on the industry are lingering in terms of lost revenue and on the province in terms of lost royalties.

Through it all, crude oil price differentials saw a slight tightening of only a few dollars per barrel. Even though the magnitude of the disruptions was significant, why did prices react so little?

Any price differential impacts from the fires would have been driven

MAR

APR

MAY

JUN

JUL

by numerous factors such as indications of any physical shortages, lack of pipeline availability, poor refinery demand and low inventories.

As it turns out, none of these factors played any major role as the physical supply of crude oil for domestic use and export to the U.S. was maintained at a relatively stable level by tapping into ample inventories of light and heavy crude oil in Edmonton and Hardisty.

The mainline transporting crude oil to the U.S. also remained unaffected by the fires and fully available, while refiners at the receiving end of those barrels were ramping activity up a little less than was expected.

The end result was that the market

JUN

JUL

had sufficient supplies on hand, despite the size of disruption, and prices and price differentials were not significantly impacted.

Where do we go from here? All indications are that oilsands producers are back up and running at normal levels and that oil inventories have begun to rebuild in Alberta.

With ample supplies on hand and refiners already looking toward the fall maintenance season, there is little reason to think that price differentials will be materially impacted beyond their recent ranges as we head into the fall.

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

S E P T E M B E R 2 0 1 6 • J W N E N E R G Y. C O M • 5 1

TRANSITION

C L E A N E N E R G Y C O M M E N TA R Y F R O M T H E P E M B I N A I N S T I T U T E

What a firm emissions limit means for the oilsands ANDREW READ AND BENJAMIN ISRAEL

In November 2015, the Alberta government announced its intention to limit oilsands greenhouse gas (GHG) emissions to 100 million tonnes of CO2 per year, with allowances for upgrading and cogeneration. It will also require facilities to meet the performance level of the top quarter of operators or pay a financial penalty.

While some may interpret this policy as the death knell for the oilsands sector, others are concerned that it allows oilsands emissions to grow at a time when Canada needs to be reducing emissions. What we should remember is that while previous policy approaches failed to address absolute reductions, the emissions limit now provides certainty around the growth of the GHG footprint of the sector, while providing incentive to build towards a higher value, lower impact and more responsibly developed oilsands.

There is no more debate over the need to keep the industry within an appropriate climate budget, even if there is still debate over what the budget should be. Meeting this limit is no small task, but an achievable and necessary step to transition both Alberta and Canada to the low-carbon future.

WHY WE NEED TO CONSTRAIN OILSANDS EMISSIONS In December 2015 at the United Nations climate conference in Paris, countries around the globe committed to reduce global temperature rise to well below 2 degrees Celsius—with the ultimate target being as close to 1.5 degrees Celsius as possible. It’s clear this will require Canada to change the way it produces and consumes en­ergy: as a developed country, this glo­bal target requires immediate domestic action to limit carbon pollution.

To that end, federal, provincial and territorial governments are developing approaches to reduce GHGs. Alberta’s action on climate change is critical to Canada’s climate success—oilsands production continues to be one of the fastest growing sources of GHG emissions, and the oil and gas sector remains the single largest source of GHGs in Canada, at 26 per cent of national emissions.

Prior to the Paris climate conference, the Government of Alberta announced its intention to limit oilsands GHG emissions to 100 Mt of CO2e/year. While the details of this policy are still under development, proper implementation will motivate

How the oilsands industry adapts to global carbon reduction requirements will make or break its future.

52 • SEPTEMBER 2016 • OILSANDS REVIEW

development of only the best, most efficient oilsands projects and help increase the sector’s resilience in the carbon-constrained future.

FIXING LEGACY MISMANAGEMENT The slowdown of the economy following the collapse of oil prices has led to reduced activity in the oilpatch and has postponed or cancelled some less viable oilsands projects. Nevertheless, we estimate that emissions from currently operating projects stand near 63 Mt of CO2/year, excluding projects in construction that could add another eight Mt when they come online.

While on paper there is still room for the sector to grow, this does not consider past project approvals under previous governments that did not respect environmental limits or acknowledge inconsistencies with provincial or federal climate targets.

Approvals do not typically include requirements to construct and operate projects within a specific timeline—­ ultimately approvals can be held as long as 10 years. This is a central issue in oilsands development and planning.

With projects in post-approval limbo and no guarantee of project construction, it is difficult to fully understand the future cumulative impacts of the industry and whether those impacts are likely to exceed environmental thresholds such as the emissions limit.

As a consequence, there remains a backlog of approved projects that

may or may not still be developed under the current policy and economic conditions. In the first quarter of 2016, there was additional approved oilsands production capacity of 2.3 million bbls/d that was not operating or under construction. This excludes projects that are in the application process and those that have been publicly announced, which add another 2.7 million bbls/d.

Without improvements in emissions intensity, if the backlog of approved projects all commenced operation, the oilsands limit would be exceeded by around 20 million tonnes (Figure 1) even before the additional announced projects are considered.

There is a clear opportunity to rethink how oilsands projects are planned, designed and approved.

The increase in production isn’t the only factor in oilsands GHG emissions.

The future saviour for the sector has always been presented as technological improvements to reduce per barrel emissions. However, while claims are consistently made about the improvement in oilsands emissions intensity since 1990, improvements over the last decade have not materialized.

Overall emission intensity of the oilsands has actually increased by 25 per cent between 2004 and 2014 (Figure 2), meaning that the emissions from the sector on a whole have grown faster than oilsands production.

This increase is a major issue for the sector as the world moves toward

TRANSITION

following principles for effective and responsible management of the 100 Mt oilsands limit policy:

GHG estimate of oilsands extraction projects by current status 200

kg CO2e/barrel of bitumen kg CO2e/barrel of bitumen

In-situ

Surface mine

150

GHG estimate of oilsands extraction projects by current status 200 100 In-situ

Surface mine

150 50

100 0

Operating (2.7 mbbl/d)

+In construction (3.1 mbbl/d)

+Approved (5 mbbl/d)

+Application (6.3 mbbl/d)

50

+Announced and Disclosed (7.7 mbbl/d)

GHG estimate of oilsands extraction projects by stage of development based on average Oilsands emissions intensity trends oilsands project intensities as of spring 2016 0 100

Operating (SOURCES: +In construction +Application +Announced OILSANDS REVIEW+Approved , ALBERTA OIL SANDS INDUSTRY QUARTERLY, SPRING 2016) (2.7 mbbl/d) (3.1 mbbl/d) (5 mbbl/d) (6.3 mbbl/d) and Disclosed (7.7 mbbl/d)

80

kg CO2e/barrel of bitumen kg CO2e/barrel of bitumen

Oilsands emissions intensity trends 60 100 40 80 20 60 In-situ 0 40 2004

2005

2006

2007

Mining 2008

2009

Average 2010

2011

2012

2013

2014

2013

2014

20 In-situ 0 2004

2005

2006

2007

Mining 2008

2009

Average 2010

2011

2012

Emissions intensity trends of oilsands production (SOURCES: GREENHOUSE GAS EMISSIONS DATA FROM CANADA’S NATIONAL INVENTORY REPORT 1990-2014, OILSANDS PRODUCTION DATA FROM ALBERTA ENVIRONMENT AND PARKS OIL SANDS INFORMATION PORTAL)

decarbonization, since many estimate current bitumen extraction produces three times the amount of carbon emissions per barrel than conventional crude oil.

If the sector cannot reduce pollution per barrel, the emission limit will act as a constraint on oilsands production, and Alberta may lose market share when high carbon oil is avoided by glo­ bal markets. The emissions limit policy opens a window for industry to demonstrate its commitment to addressing climate change and securing per-barrel improvements in the near term.

FIVE PRINCIPLES TO ALLOW FOR RESPONSIBLE OILSANDS GROWTH IN A CARBONCONSTRAINED ENVIRONMENT The commitment to limiting oilsands emissions to 100 Mt annually has set a new objective for the oilsands industry—to develop only the most efficient and least carbon-intensive projects, rather than maximizing total production.

Implementing the limit will require difficult decisions on how oilsands projects are approved by the Alberta Energy Regulator (AER). In anticipation of this, we have identified the

1. Create an oilsands GHG emissions profile. Develop a cumulative oilsands emissions profile showing total GHG emissions for all approved oilsands projects based on best estimates of project start and end dates; 2. Pause regulatory approvals. Until it can be shown that approved projects will adhere to the 100 Mt emissions limit, the AER should not take on additional liability by considering further oilsands projects; 3. Make some room. Any project that has not commenced construction and reaches its approval expiration date should be considered for cancellation to allow for more efficient projects to be allocated space under the emissions limit; 4. Prioritize most efficient projects. A competitive re-application process for evaluation and prioritization of all operating oilsands projects should be considered to fully optimize production under the oilsands GHG limit. Projects should be evaluated against “top-­­­quar­­tile” performance, and provide enforceable plans to reach this level of performance in a reasonable timeframe; and 5. Consider new projects—as long as limit is not reached. Once it is demonstrated that the remaining approved oilsands projects will not exceed 100 Mt, new oilsands projects may be considered for approval as long as the 100 Mt limit is maintained.

Implementing these principles appropriately places the challenge to reduce emissions firmly in industry’s hands. If industry is able to turn recent trends around and improve performance, as it has long claimed as the path forward, then there may be room for new production under the oilsands limit.

If industry is not able to reduce per barrel GHG emissions, the 100 Mt

limit represents a de facto cap on oilsands. The policies outlined in the Climate Leadership Plan for the oilsands sector provide the necessary market incentives to enable industry to greatly reduce emissions by deploying next generation technologies.

While the Alberta Climate Leadership Plan has defined the oilsands “carbon budget” for the 2015-30 period, this budget must be reduced over time. Alberta’s climate change panel indicated that their proposal, adopted in full, would still not meet the percentage level of reductions required globally to restrict global temperature increases to 2 degrees Celsius, and may simply stabilize Alberta’s emissions by 2030. Alberta is currently the largest provincial emitter in Canada, and therefore Canada’s climate obligations hinge on Alberta reducing emissions.

Canada must outline future carbon budgets across the country and the oilsands sector emissions limit must be harmonized with our national obligations. It is reasonable to assume that the oilsands’ allowable emissions in 2050 will be a fraction of what they are in 2030.

This presents an opportunity to look long term, and make smart decisions about multi-decade fossil fuel extraction projects in a rapidly decarbonizing world. How the sector adapts to these global requirements will make or break the industry.

This policy creates a framework for every oil and gas producing jurisdiction on how to manage emissions. As the world continues to decarbonize, every jurisdiction will have to evaluate the viability of their fossil resources.

Alberta’s approach sets the prece­ dent in how this can be done, and gives Alberta’s industry an advantage over other oil producing jurisdictions.

This leadership is a global example of what is possible when a government takes on the challenge of reducing GHGs head on.

Andrew Read is a senior policy analyst at the Pembina Institute, and Ben Israel is an adviser at the Pembina Institute.

S E P T E M B E R 2 0 1 6 • J W N E N E R G Y. C O M • 5 3

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

Social licence is not democracy— public interest is Former NEB chair Gaétan Caron on making development decisions as a nation ELSIE ROSS

“If you are guided by whether you have approval by the vast majority of citizens in this country, you might as well just shut down everything because you will not get that.”

— GAÉTAN CARON, executive fellow, School of Public Policy, University of Calgary

“Social licence” is not a useful phrase, says the former chair of the National Energy Board (NEB).

“If you are guided by whether you have approval by the vast majority of citizens in this country, you might as well just shut down everything because you will not get that,” Gaétan Caron, an executive fellow at the School of Public Policy at the University of Calgary, said in a round-table discussion at this year’s Global Petroleum Show.

It’s particularly unrealistic, he said, to expect that a 2,000-kilometre-long infrastructure project will obtain universal support.

“Let’s go back to democracy. Let’s define the role of public institutions informed by the laws that people we have elected have passed, and let’s look at the public interest and what is in the public interest when we are taking action by approving or rejecting specific proposals one by one.

“When you make decisions in a democracy, you are meant to earn the support of some people and the disapproval of others; that’s normal,” Caron said. “A decision that is in the public interest sometimes will be contrary to the interests of some people or will inconvenience some people, but the public interest taken

54 • SEPTEMBER 2016 • OILSANDS REVIEW

together for the nation is positive, and therefore, you go there.”

Regulators, he said, face challenges in listening to the public, especially the broad range of views that are sometimes contrary to what companies want to do, and in listening to all these views with sincerity and an open mind.

“It’s hard to do it right in the first place—to listen carefully, intently with an attitude that maybe you are going to learn something and have the other party believe that you are listening to them with sincerity. This is hard work.”

Societal expectations have been informed by a cluster of three major energy sector accidents in 2010, according to Caron. Those are the BP Macondo blowout in the Gulf of Mexico, the Enbridge pipeline rupture in Kalamazoo, Mich., and the PG&E natural gas pipeline explosion in San Bruno, Calif., that killed eight people.

“We have yet to recover from that in terms of credibility and trust in our energy systems and the regulators who are supposed to help prevent those accidents,” he said.

“Unfortunately, these factors obscure the fact that large amounts of energy, including oil products, move uneventfully to supply markets. You obviously don’t get recognition for

that, yet every day we depend on a large amount of these energies.”

However, for all the unrest about energy in all its forms and its transportation, a recent poll found that 68 per cent of Canadians think Canada should be building new pipeline capacity and using its oil resources as well as investing in renewable energy and in ways to reduce emissions, said Caron.

“What this shows is that regulatory agencies are well advised to look at the facts and the figures and the evidence—and this applies to both sides—and make decisions in the end that are in the public interest with regard to the future, which probably means some sort of transition before we have a decarbonized society.”

For Caron personally, the most significant policy shift has been Prime Minister Justin Trudeau’s commitment to making progress toward Canada’s reconciliation with First Nations.

“The sincerity of his commitment to that has been seen by the other side, and I predict he will make progress in terms of reconciliation with indigenous peoples in Canada, and it can only be good, as difficult as it can be and even if it means delays in some infrastructure projects.”

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