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CONTENTS VOLUME 11 | NUMBER 3 | Q2 | 2016
DEPARTMENTS
07
From the editor Insights into oilsands trends
24
WORKING THE COASTS Cenovus hires 30-year marine veteran Claus Thornberg to manoeuvre midstream and get more crude overseas
29
WHO’S THE BOSS? Why it may be a matter of when, not if, Suncor will take over as operator of Syncrude DAVE S. CLARK
R.P. STASTNY
IN REVIEW
08 14 19
News
21
Throwback
Rounding up the latest oilsands news
Project news Project status and development progress
Eyes on the oilsands What people are saying about the industry in the media and around the world
Oilsands Review’s 10th anniversary series June 2006: Syncrude UE-1
53
Statistics
56
Transition
Taking a close look at the inputs and outputs of the oilsands industry
Pembina: A more environmentally responsible oilsands will be more competitive
59
Guest Column
62
Sector Watch
Watson: Being competitive means changing the way we work
Temporarily shutting in thermal wells may not be as harmful as you think
32 BUILT SO NICE, WE DID IT TWICE SAGD producers are looking to tackle costs with standardized designs for sustaining capital projects—but is it really possible? MELANIE COLLISON
38 A TASTE FOR MEDIUM Partial upgrading could add value to Alberta bitumen at a lower cost, but commercialization still has a long way to go R.P. STASTNY
TECH_SERIES : WATER
44 46 47 50
Improving mining water and land use through integrated, innovative systems The tailings technology enhancements that are already delivering results Pushing the limits of SAGD water treatment A new combustion technology may be able to low-cost retrofit oilsands steam generators to reduce GHGs
Q 2 2 0 1 6 • J W N E N E R G Y. C O M • 0 5
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, Melanie Collison, Simon Dyer, Carter Haydu, Pat Roche, Cal Watson, R.P. Stastny EDITORIAL ASSISTANCE MANAGER
Tracey Comeau | tcomeau@jwnenergy.com EDITORIAL ASSISTANCE
Laura Blackwood, Sarah Miller
CREATIVE CREATIVE SERVICES MANAGER
Tamara Polloway-Webb | tpwebb@jwnenergy.com CREATIVE LEAD
Cathlene Ozubko PRINT COORDINATOR
Janelle Johnson
GRAPHIC DESIGNER
Jeremy Seeman
CREATIVE SERVICES
Celia Hui, Teagan Zwierink
SALES SENIOR ACCOUNT EXECUTIVE
Diana Signorile SALES
Gerry Mayer, Paul Sheane, Blair Van Camp, Patrick Yee For advertising inquiries please contact adrequests@jwnenergy.com AD TRAFFIC COORDINATOR, MAGAZINES
Lorraine Ostapovich | atc@jwnenergy.com
CIRCULATION AND DISTRIBUTION MANAGER, PRODUCT DISTRIBUTION
Jackie Dupuis | jdupuis@jwnenergy.com
DIRECTORS PRESIDENT & CEO
Bill Whitelaw | bwhitelaw@jwnenergy.com SENIOR VICE-PRESIDENT, ENERGY INTELLIGENCE
Bemal Mehta | bmehta@jwnenergy.com VICE-PRESIDENT, SALES OPERATIONS
Donovan Volk | dvolk@jwnenergy.com VICE-PRESIDENT, GLACIER BUSINESS DEVELOPMENT & EVENTS
Ian MacGillivray | imacgillivray@jwnenergy.com VICE-PRESIDENT, DIGITAL STRATEGIES
Gord Lindenberg | glindenberg@jwnenergy.com DIRECTOR, THE DAILY OIL BULLETIN & EDITORIAL PRODUCTS
Stephen Marsters | smarsters@jwnenergy.com
DIRECTOR, GOVERNMENT & STAKEHOLDER RELATIONS
Chaz Osburn | cosburn@jwnenergy.com DIRECTOR, PRODUCTION
Audrey Sprinkle | asprinkle@jwnenergy.com
OFFICES CALGARY 2nd Flr-816 55 Avenue NE | Calgary, Alberta T2E 6Y4 Tel: 403.209.3500 | Toll-free: 1.800.387.2446 EDMONTON 220-9303 34 Avenue NW | Edmonton, Alberta T6E 5W8 Tel: 780.944.9333 | Toll-free: 1.800.563.2946
I was going to use this space to talk about the tenth anniversary of Oilsands Review, which I am proud to say this issue marks, but as I sit listening to ongoing coverage of the third day of one of the largest evacuations in Canadian history, I find it hard to concentrate on anything else. In the worst-case scenario, officials say that the entire community could be destroyed. I could not pray any more deeply that as you read this about two weeks from now, the worst-case scenario did not come true. Our magazine’s 10 years is half a blink in the lifespan of the amazing Fort McMurray community and the wonder of human innovation and continuous progress that is the oilsands industry. I will forever be happily humbled in its presence. Watching from 750 kilometres away as families drive through hellfire to get away from the oilsands forest has been terrifying and heartbreaking. The incredibly good news is that everyone has made it out safely, with the exception of two fatalities from a multi-vehicle crash south of the city during the evacuation. This is a testament to the courageous and dedicated work of the first responders. Thankfully, this is not a tragedy of human life— it looks like the road ahead for the Fort McMurray community will be difficult beyond words, but they have their lives and their families. What they have less and less of as the hours pass is the critical infrastructure required to have a comfortable home and successful community. As it stands, over 1,600 homes and
businesses have been destroyed. A new school has been lost and structures at the old airport have burned. This is a tragedy of loss of infrastructure, and there couldn’t be a worse place in Alberta for that to happen. For more than a decade, Wood Buffalo has been playing catch-up to put in place the essentials to provide not just a place to live but a comfortable home and community. They were starting to get ahead in the last couple of years, with the twinning of the highway, new neighbourhoods, roads, bridges, a new water treatment facility, the massive new multiplex and football/ baseball stadiums, and of course the brand new international airport. Right now, it’s still unclear how much of this infrastructure, if any, will survive. I heard an analyst on the news say that as long as the oilsands production facilities themselves aren’t damaged, this ferocious wildfire will not impact their long-term viability. I think that answer is too easy—even with the damage seen so far, the industry is going to have a hard time coming back from this. Ultimately, the oilsands comes down to people—houses and roads and blankets and families. If they don’t have a place to live, you don’t have an industry. Albertans, and Fort McMurrayites in particular, are tough and because of that this industry is strong. We will rebuild, even if we have to start from one giant pile of rubble, but it is going to hurt a lot along the way. DEBORAH JAREMKO
djaremko@jwnenergy.com @oilsandseditor
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MEMBERSHIP INQUIRIES Telephone: 1.800.387.2446 Email: circulation@jwnenergy.com Online: jwnenergy.com ISSN 1912-5305 | © 2016 JWN. All rights reserved. Reproduction in whole or in part is strictly prohibited without prior consent from the publisher. Publications Mail Agreement Number 40069240. If undeliverable, return to: Circulation Department, 2nd Flr-816 55 Avenue NE, Calgary, Alberta T2E 6Y4. Made in Canada. 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.
PROJECT ANALYTICS Benchmarking efficiency performance project-by-project
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Q 2 2 0 1 6 • J W N E N E R G Y. C O M • 0 7
New CanOils study shows SAGD is improving but LTO is still on top
Q 2 2 0 1 6 / / R O U N D I N G U P T H E L AT E S T O I L S A N D S N E W S
MEG ENERGY LAUNCHES REGULATORY PROCESS FOR NEW 160,000-BBL/D SAGD PROJECT In mid-April, MEG launched the regulatory process for a new phased 160,000-bbl/d SAGD project at May River near Conklin, south of Fort McMurray, by filing its proposed terms of reference with Alberta Environment and Parks. The first two phases would be 40,000 bbls/d each, followed by a third 80,000-bbl/d phase. Expected capital costs have not been disclosed. As an intermediate oilsands producer, it could be surprising that MEG would take this step in a sub-$50 WTI market. But it is evidence of what can be achieved in the oilsands with the right resource and strategy—MEG is in the unique position of not only successfully achieving production and maintaining ownership of a SAGD facility as a junior producer, it has also been very successful in improving performance and reducing costs. In the fourth quarter of 2015, MEG achieved record production of 83,500 bbls/d at its Christina Lake SAGD project (nameplate capacity is 60,000 bbls/d), as well as record low net operating costs of $8.52/bbl. That’s compared to an industry average of about $13/bbl. “Our operating performance throughout 2015 met or exceeded our targets,” MEG president and chief executive officer Bill McCaffrey said in announcing the company’s fourth-quarter results. “Our low cost structure is enabling MEG to weather the low commodity price environment seen over the past year.” Right now that low cost structure is largely attributable to MEG’s RISER program, which incorporates debottlenecking and brownfield expansion at the plant as well as infill drilling
and non-condensable gas co-injection in the reservoir. With results like that, it’s easy to see how MEG could be confident in its future in the oilsands. MEG spokesman Brad Bellows says about May River that, “We are several years out, but when I look at what we have accomplished at Christina Lake, we have learned a lot and refined our technologies, improving our efficiencies as we go, and we expect that process is going to be ongoing and that we can bring that knowledge and expertise to any new development.” The project life of the proposed May River project is approximately 25 years. A commercial project application is planned to be submitted to the Alberta Energy Regulator for review in late 2016. Construction is expected to start in 2019, followed by first steam in 2023. MEG says the project design includes steam generation, cogeneration, water treatment and recycling, bitumen treatment, sulphur recovery, multi-well production pads, steam delivery pipelines, product recovery pipelines, water source wells, waste-water disposal, construction and operations camp, and other secondary infrastructure.
08 • Q2 2016 • OILSANDS REVIEW
P.17
MAY RIVER PROJECT
63
CONKLIN
881
FORT McMURRAY
EDMONTON
CALGARY
PHOTO: MEG ENERGY
IN REVIEW
Supply costs: SAGD vs. the Permian Basin
IN REVIEW
4/10 60 over
Barrels of crude the U.S. imported in 2015 that were from Canada
%
Recovery now expected from most SAGD well pads
$1.7 billion
Oilsands evaluation well permitting drops to decade low
Amount Husky will receive for the sale of a 65 per cent interest in certain heavy oil midstream infrastructure
Canada needs “urgent action” amidst largest capex drop on record
According to data collected by the Daily Oil Bulletin, a total of 58 oilsands evaluation wells were licensed during the first quarter of 2016, down from 117 permits over the first three months of 2015.
Q1 2015
Q1 2016
PHOTO: BP
CAPP is projecting a 62 per cent drop in overall Canadian oil and gas capital spending in 2016 compared to 2014. New data from the Canadian Association of Petroleum Producers (CAPP) forecasts that capital spending in 2016 will decline by $50 billion, or 62 per cent, compared to 2014. CAPP says this is the largest two-year decline since it and its predecessor organizations started tracking this data in 1947. Total capital investment in the oil and natural gas sector is forecast to decline to $31 billion in 2016, down from a record $81 billion in 2014.
“Canada needs urgent action to remain an attractive market for oil and gas investment and to be competitive relative to other oil and natural gas producing jurisdictions,” says Tim McMillan, CAPP president and chief executive officer. CAPP says that this action includes the timely expansion of Canada’s pipeline network to deliver to more markets at home and abroad, along with the development of liquefied natural gas export facilities.
“Doing so would allow Canadians to earn full value for their resources and create economic activity that would otherwise be lost.” McMillan says, “The United States, our only customer and number one competitor, is certainly not standing still.... We as a country need a common effort to have a level playing field in North America. Doing so will help ensure Canada is not at a competitive disadvantage relative to the U.S.”
Q 2 2 0 1 6 • J W N E N E R G Y. C O M • 0 9
IN REVIEW
Suncor says that it will provide enhanced disclosure around carbon risk and its lobbying activities in its upcoming 2016 Report on Sustainability, to be issued in July. The move follows an announcement by sumofus.org that a resolution would be raised at Suncor’s annual general meeting to demand greater transparency around the company’s lobbying activities. The resolution asks Suncor to disclose payments it makes to lobbyists, trade associations, and grassroots campaigns to influence public policy. The company says that “regarding lobbying practices, Suncor will expand its disclosure by publishing its policy on lobbying and political donations, and list trade associations that lobby government to which Suncor pays membership dues of greater than $50,000 and $100,000 per year. Suncor will continue to disclose its political donations as has been done in the past.” The “enhanced disclosure” will also include further information about how the company is expected to succeed in a low-carbon future. “Suncor has a demonstrated track record of transparent reporting as evidenced by the disclosure we provide in our Report on Sustainability, and our recognition by the Carbon Disclosure Project [CDP] and the Dow Jones Sustainability Index,” says Steve Williams, Suncor’s president and chief executive officer. “We believe additional disclosure about the resilience of our business strategy in a transition to a low-carbon future benefits shareholders and stakeholders.” In a statement, Tim Smith of Walden Asset Management said that, “Global institutional investors concerned about climate change are increasingly urging oil and gas companies to review and disclose their lobbying aimed at influencing public policy on climate and the environment. Companies can play a positive role calling for legislation and regulation to address climate change, but often directly or through trade associations a company may be using its voice and funds to oppose climate action.”
10 • Q2 2016 • OILSANDS REVIEW
Scientist: It’s a mistake to blame Athabasca River pollution on the oilsands
The Athabasca River flows into Lake Athabasca, shown here from the shores of Fort Chipewyan, where residents have long been concerned about water pollution. The general public has a “skewed perspective” of the level of disturbance that the oilsands industry is causing to the Athabasca River, says Jon Fennell, vice-president of geosciences and water security at Integrated Sustainability Consultants. “Contributions of natural constituents to the Athabasca River are not well understood, and arguably are not very well quantified either. Just because you measure something does not mean it has any significance or relevance. You need to know what the flux is and its quantity,” Fennell told
Canada’s Oil Sands Innovation Alliance (COSIA) water conference in April. “The Athabasca River has literally carved all the way through the oilsands deposits, down into the Devonian carbonates underneath. All of that oilsand that was once there has been removed, eroded and reported downstream and deposited in the Peace-Athabasca delta. There is no surprise that you are picking up hydrocarbons and other trace elements in the delta, because it is deposited from erosion of the oilsands, and that is still going on today.”
He says that river pollution can be explained by many sources other than oilsands development. Municipal golf courses, storm-water drainage and other municipal sources impact the river system, he added, as can other industries. “There is forestry and some of the issues around the suspended sediment flows that can potentially report to the tributaries and river, as well as aggregate mining. You can see that this is a very busy area with respect to development, and looking at only one aspect of it will lead you to a skewed perspective.”
PHOTO: JOE Y PODLUBNY
Suncor to expand lobbying and carbon disclosure following shareholder activism
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26M042016H
IN REVIEW
EXPECT MODULES, PAY LESS ENGIE Fabricom goes bargain shopping to keep costs down as it assembles modules for Fort Hills JOSEPH CAOUETTE
•
PHOTOS BY AARON PARKER
Anyone looking for signs of the oilsands industry’s financial woes will be disappointed when setting foot on ENGIE Fabricom’s module yard in Fort Saskatchewan, Alta. Opened last year, the 35-acre location is a hub of activity as the site works through its first contract: 80 modules for Suncor Energy’s Fort Hills oilsands mine. Still, the company is acutely aware of the need to keep costs down as the industry strives to remain competitive in a world of lower oil prices. In this
environment, no potential bargain can be missed or detail overlooked. Even the shelves in the warehouse were an occasion for cost savings: the company purchased them for bargain-basement prices at Target Canada’s closing sale. There are 65 trade workers and subcontractors on site and another 25 staffers divided between the company’s Fort Saskatchewan and Calgary locations. Chief executive officer Didier Lhuillier explains that
12 • Q2 2016 • OILSANDS REVIEW
the company deliberately sought out a diverse crew when hiring, which is why 15 per cent of the company’s trade workers are aboriginal. More than a matter of equal opportunity, this is about encouraging diverse perspectives to help the company avoid the familiar productivity pitfalls that have plagued the Alberta market for years, he says. That’s also why there is a whiteboard in the lunchroom where workers can write their ideas. With a monthly theme posted—March was all about tools—the board is filled with a variety of comments, including a request for more garbage cans near the modules and a suggestion to use sleds to move material skids more easily on the soft spring ground. In the past two weeks, Lhuillier has received 17 ideas—and 15 of those were from the trades, he says.
IN REVIEW
LEFT: Workers at the ENGIE Fabricom site in Fort Saskatchewan, Alta., assemble a module destined for Suncor Energy’s Fort Hills project. CENTRE: Chief executive officer Didier Lhuillier shows off a whiteboard where ENGIE Fabricom workers write down ideas for potential innovations. RIGHT: Material skids from South Korea wait to be assembled into finished modules. Every individual piece of steel in the skid is bar coded and scanned upon entering the site. BOTTOM: With heat tracing completed, the pipes must now be insulated before this module can be shipped north. CUT-OUT: Mobile toolboxes, stationed around the yard, are stocked by crew foremen to make sure workers have what they need close at hand.
IN REVIEW
As more SAGD well pads start reaching what was expected to be the end of their productive lives, recovery rates are achieving unexpected levels. Rudy Strobl, geological adviser at Nexen, says that SAGD producers are benefiting from wide areas of mobilized bitumen because of pad development as well as infill drilling and conductive heating (sometimes through non-condensable gas co-injection). These mechanisms are leading to recovery factors exceeding 60 per cent and economic production continuing several years longer than originally predicted. “What we do know about SAGD and thermal recovery is that we are producing more bitumen than we are supposed to. Every time when we do the reserves calculation at the end of every
year, it is supposed to be declining and it goes steady. Every year that we’re supposed to be going to wind-down or shutting down the well pad, it keeps going, and going, and going. These are pads that refuse to die,” says Strobl, who recently co-authored the paper Steam Assisted Gravity Drainage – New Perspective on Recovery Mechanisms and Production, presented at GeoConvention 2016.
The collapse in the price of oil makes the findings all the more relevant to today’s producers, Strobl says. “Once we understand how our 1,700 well pairs actually work, the mechanism that actually produces that oil, then we can make the 1,700 well pairs more efficient, be more economic and be that competitive edge that we need.”
Many SAGD well pads are now exceeding 60 per cent recovery. Suncor’s MacKay River project is seen here.
PROJECT NEWS BRION ENERGY says the first phase of its McKay River SAGD project is “very near mechanical completion” with the goal of a fall start-up, pending a go-ahead from parent company PetroChina. “We are completing construction on it. We’re still awaiting a final decision from headquarters on actual start-up,” says Bob Shepherd, executive vice-president. McKay River construction began in early 2012. The company expects that ramp-up to design capacity of 35,000 bbls/d will take about 18–24 months once
initiated. Meanwhile, Brion says its Dover SAGD project, which received regulatory approval in 2014, has been put on hold. STRATA OIL & GAS says it has entered into an agreement to acquire the rights to 115 sections or 73,600 acres of oilsands leases in the Peace River oilsands region of Alberta, increasing the size of its oilsands holdings in the area to more than 230 sections. The lands are contiguous to Baytex Energy’s Reno project lease block in the southern portion of the Peace River oilsands region, an area with extensive primary production. Strata says the new lease area is complementary to its existing Cadotte project, adjacent to Shell’s 12,000-bbl/d Peace River thermal project, which has been in operation for 30 years. Strata says it considers that the new lands offer strong development opportunities. CANADIAN NATURAL RESOURCES has submitted an application to the Alberta Energy Regulator (AER) for a
new cold heavy oil production with sand (CHOPS) development in the Cold Lake oilsands region. The company applied for approval to construct, drill, complete and operate up to 47 wells on six multi-well pads and one single-well pad; to construct and operate seven associated bitumen batteries and access roads; and to construct and operate associated gas pipelines for on-site fuel use and transport and sale of excess gas. Canadian Natural also applied for a temporary workspace for construction and storage and requested an extended approval term of five years to complete construction. IMPERIAL OIL has applied to the AER for approval to build a solvent-assisted SAGD (SA-SAGD) project on its Cold Lake lands. The project would produce about 50,000 bbls/d of bitumen from the Grand Rapids Formation. Construction could start as early as 2019, with production starting as early as 2022, pending regulatory and internal approvals, Imperial said.
Imperial has piloted SA-SAGD at Cold Lake since 2010. Based on research and pilot results, the company expects the technology to reduce greenhouse gas intensity by 25 per cent compared to conventional SAGD because of lower energy input per barrel of bitumen recovered. PENGROWTH ENERGY says it has entered into a sale and leaseback of the cogeneration facilities at its Lindbergh SAGD project with Frog Lake Energy Resources. The project is located in the Cold Lake oilsands region; it started commercial production in mid-2015 following a successful three-year SAGD pilot. Frog Lake, which is owned by the members of the nearby Frog Lake First Nation, has invested $35 million to purchase the cogeneration facilities and leaseback to Pengrowth. The agreement is for a period of 20 years. Pengrowth says it will provide Frog Lake with long-term returns as well as the opportunity to directly participate in the operation of a successful thermal oil project.
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 DOB Intelligence Essentials. For more information, please visit dailyoilbulletin.com/about.
14 • Q2 2016 • OILSANDS REVIEW
PHOTO: JOE Y PODLUBNY
SAGD well pads are overachieving and “refuse to die”
JUMP ON OPPORTUNITIES FROM THE ASSET LEVEL UP The CanOils Assets Module gives you insight on all oil and gas wells in western Canada, including working interest production and land data. Learn more at canoils.com
IN REVIEW Q1
INSIDE THE MIND OF THE EPCM
PROFIT/LOSS OUTLOOK Nearly half of respondents (48.4 per cent) expect to see a loss of profits in 2016, while the other half (51.6 per cent) believe there will be flat to some growth. EPCMs with diversified services and presence in
Survey results indicate expectations for 2016 and strategies for success
What is your outlook for your organization’s profits in 2016?
PRICING CHANGES Almost half of respondents (46.3 per cent) believe there will be some pricing decreases in 2016. However, one quarter of respondents expect prices to remain flat. Considering their profit expectations, this would indicate that increasing the bottom line remains about aggressive cost control. With 44 per cent of respondents expecting to see price increases of up to 5 per cent, it signals that EPCMs are leery about getting into a price war game that could have lasting effects even if market activity picks up.
20.3%
18.8%
JWN and partner Grant Thornton recently released a detailed review of the oilfield service and supply market following a survey of service and supply company leaders. The study included over 545 survey responses, 100 workshop attendees and 38 interviews—we’ve extracted the results from the engineering, procurement and construction management (EPCM) participants.
Q2
counter-cycle sectors such as refining may believe that if any part of the industry picks up, they will be able to capitalize on that growth. This could also be indicative of synergies being realized from firms merging and consolidating to become more cost competitive.
12.5%
10.9%
10.9%
10.9%
6.3%
6.3% 3.1%
-21% and less
-11% to -20%
-6% to -10%
-1% to -5%
0%
1% to 5%
6% to 10%
11% to 20%
21% and more
What is your organization’s outlook on pricing changes for products/services in 2016 versus 2015? 25.9%
18.5%
11.1%
13.0%
13.0%
9.3%
7.4% 1.9%
-21% and less
-11% to -20%
Q3
COST CONTROL PRIORITIES As the largest contributor to overhead and one of the easiest variables to manage in an immediate way—particularly for companies focused on project/ contract work—staff reductions continue to be the top cost-cutting priority. However, EPCMs also realize the difficulty in attracting and retaining top talent during market upswings. The large percentage of respondents highlights compensation reductions for cost control signals that EPCMs are doing whatever they can to maintain their workforce for what they feel will be a rapid upswing when demand rises. The low-hanging cost reduction fruit has been picked and longer-term, potentially higher-cost saving initiatives are being undertaken, as indicated by the fourth highest priority (12.2 per cent of respondents) of implementing new technologies.
-6% to -10%
-1% to -5%
1% to 5%
0%
6% to 10%
11% to 20%
0.0% -21% and more
Q4
NEW INDUSTRY OPPORTUNITIES With stable cash flows and ongoing oil production that needs to be processed and transported, midstream companies have the resources for capital projects, so it is no surprise that EPCMs view this as the industry vertical to focus on in the near term as oilsands projects are delayed and cancelled.
Oilsands
Midstream 13.9%
33.3%
Layoffs/staff reductions
23.0%
Conventional Gas
Reductions in compensation
13.9%
17.3%
Rationalization of services/products
15.1%
Implementing new technologies
12.2% 18.1%
Asking existing suppliers to cut their costs
9.4%
New suppliers
9.4%
Consolidating offices
9.4%
Outsourcing
4.3%
16 • Q2 2016 • OILSANDS REVIEW
20.8%
Conventional Oil
Refining
IN REVIEW
Q5
BUSINESS DEVELOPMENT OPPORTUNITIES BY GEOGRAPHY Respondents are hesitant to diversify out of Alberta or even Canada with 22.2 per cent indicating their focus in 2016 will remain in the province and 30.4 per cent indicating they would look elsewhere in the country for opportunities. The belief could be that as energy producers in all major non-OPEC countries are struggling, EPCMs would be better served trying to win over more of the existing market share, including through consolidation.
Other Canadian locations (outside Alberta)
30.4%
Within Alberta only
22.2%
Northern/central U.S.
9.6%
Other locations in the U.S.
8.1%
Southern U.S. Middle East
7.4% 6.7%
Asia
5.2%
Europe
5.2%
Africa South America
Oilsands SAGD versus the Permian Basin Supply cost study shows SAGD is improving but light tight oil is still on top In a new study released by CanOils, the full supply costs of SAGD production in 2014-15 are benchmarked against the 2014-15 supply costs of light tight oil production in the massive Permian Basin play in the U.S. CanOils says that in order to provide an apples-to-apples comparison of the two plays, the net diluent cost for oilsands production has been excluded. The analysts note that SAGD producers generally spend about $2–$3/bbl on diluent, while mining producers covered by the study would have minimal diluent expense due to the end product transport of upgraded oil. 2014
3.0%
1. FULL CYCLE SUPPLY COST PER BOE
2.2%
$37.52
Permian
Q6
$31.00 $34.42
BUSINESS DEVELOPMENT OPPORTUNITIES BY ACTIVITY Despite a lack of new oilsands projects being sanctioned, those in flight before the downturn are expected to be completed, resulting in production growth through the end of the decade. This, combined with the significant installed base of production capacity, results in increased producer outlay on maintenance, operations and sustaining capital. EPCMs are shifting accordingly.
Oilsands (SAGD)
What areas do you see as having the most potential for future growth? (Select your top three)
2. OPEX PER BOE
Second
Third
Response count
Permian
Maintenance and repair
18
8
6
76
Oilsands (SAGD)
8
9
5
47
10
16
8
70
Large capital projects
9
3
11
44
Exploration and development
0
2
7
11
Turnarounds
2
8
5
27
Sustainment capital
6
5
6
34
Q7
BUSINESS DIFFERENTIATORS Service, innovation and quality rank as the top three key differentiators that EPCMs want to focus on. This is in line with the EPCM strategy to become tactical advisers to clients, offering cost savings and other efficiencies by being able to provide several integrated services. 22.1%
20.4%
19.9%
Quality
$20
$30
$40
$50
$60
$11.84 $9.77 $13.58 $10.36 $34.50
Oilsands (Mining)
$28.01 $0
$10
$20
$30
$40
3. TRANSPORT PER BOE $2.80
Permian
$3.63 $2.30
Oilsands (SAGD)
$5.98 $1.81
Oilsands (Mining)
$1.85 $0
$1
$2
$3
$4
$5
$6
Time/speed
$16.73
Permian 9.4%
8.8% 4.4%
Innovation
$10
4. F&D PER BOE
11.0%
Service
$51.58 $46.81 $0
First
Operations
$36.06
Oilsands (Mining)
Industry type
Small capital projects
2015
Price
Safety
3.9%
Product Environmental catalogue stewardship
$13.42 $10.37
Oilsands (SAGD)
$11.41 $13.13
Oilsands (Mining)
$14.65 $0
$3
$6
$9
$12
$15
$18
Q 2 2 0 1 6 • J W N E N E R G Y. C O M • 1 7
IN REVIEW
the Clearwater shale, by flowing through induced vertical fractures, or by flowing through natural fractures or faults. In other words, the AER investigation gave more weight to geology and steaming strategy. This has more impact on the project’s future operating strategy than if inactive wellbores were the sole cause, since the latter could be remediated, which presumably would have allowed operations to continue at high injection pressures. In 2013, after bitumen was found leaking to surface at four locations, the AER ordered steam injection suspended at 228 Primrose wells. In 2014, the regulator allowed steaming to resume after it was converted to a low-pressure steamflood from the original high-pressure cyclic steam stimulation. Canadian Natural says that with some minor adjustments, the company will be able to comply with AER requirements outlined in the new report.
Although total U.S. crude oil imports in 2015 continued to be lower than levels reached during the mid-2000s, imports from the U.S.’s top foreign oil supplier—Canada—were the highest on record, according to annual trade data from the Energy Information Administration (EIA). Canada provided four out of every 10 barrels of oil imported into the U.S. in 2015. Canada generally produces heavy, sour crude oil that is well matched to processing capacity in the United States, the EIA says, where many refineries have the equipment needed to process such oil. “Canada has few alternative outlets for the heavy crude produced in Alberta, where most of Canada’s proved oil reserves are located,” the EIA stated. “Canada is expected to continue to provide a large share of
U.S. oil imports for the foreseeable future, especially given the expansion of pipeline and rail shipping capacities to transport Canadian oil.” U.S. gross crude oil imports from all sources averaged 7.4 million bbls/d in 2015, down 27 per cent since the 2005 high of 10.1 million bbls/d. As gross crude oil imports decline, a growing share of remaining imports are being sourced from four top suppliers: Canada, Saudi Arabia, Venezuela and Mexico. Canada sent a record-high 3.2 million bbls/d per day of gross crude oil exports to the U.S. in 2015, up 10 per cent from the year before, accounting for a record 43 per cent of total U.S. crude oil imports. Canada also receives nearly all U.S. crude oil exports, making up 422,000 bbls/d per day, or 92 per cent, of the 458,000 bbls/d per day of crude oil exported from the U.S. in 2015.
Gross imports of crude oil to the U.S. by country 12 10 8 6 4 2 0 1985
Canada
1990
1995
2000
2005
2015
43% 14%
11%
Rest of the world
2010
23%
Saudi Arabia
Venezuela
9%
Mexico 18 • Q2 2016 • OILSANDS REVIEW
PHOTO: JOE Y PODLUBNY
The AER has released its final report following the investigation of bitumen surface leaks in 2009 and 2013 at Canadian Natural Resources’ Primrose thermal project, but the regulator and the company disagree on the cause. Specifically, about the extent to which inactive wellbores contributed to the problem. The AER concluded the leaks were caused by excessive steam volumes, along with open conduits such as wellbores, natural fractures and faults and hydraul ically induced fractures. “This is one of the most complex investigations we’ve ever undertaken,” said Kirk Bailey, the AER’s executive vice-president of operations. Canadian Natural believes that inactive or abandoned non-thermal wellbores provided the most likely pathways for bitumen emulsion to reach the surface. The AER, in all cases but one, believes bitumen escaped either by breaching
Canada provided record-high U.S. oil imports in 2015
million bbls/d
AER finalizes report on Primrose bitumen surface leaks
IN REVIEW
// EYES on the OILSANDS “There is no climate-change-denying, science-muzzling, regressive Tory government here anymore. It is time to start thinking more charitably about Alberta and the 4.4 million fellow Canadians who live here.”
PHOTOS (CLOCK WISE FROM TOP LEF T ): ENERGY.G OV; ENERGY.G OV; O.C ANADA .COM; JOE Y PODLUBNY
— Alberta Premier RACHEL NOTLEY, speaking to the federal NDP convention in Edmonton in April following the defeat of leader Tom Mulcair and the debate over the Leap Manifesto. Post Media, April 9.
“UNLIKE THE PAST, THIS VERY STEEP, RAPID DROP IN CRUDE OIL PRICES HAS NOT BEEN FOLLOWED BY A QUICK TURNAROUND…. “WE’RE STARTING TO THINK THE ENVIRONMENT WE’RE IN TODAY IS THE NEW NORMAL. IT’S NOT A SHORT-TERM ABERRATION.” — MARK WARD, president and chief executive officer of Syncrude, speaking to a luncheon of local business leaders. Fort McMurray Today, April 18.
We are excited about the oilsands, but it doesn’t enjoy a particular strategic advantage…. It’s got to compete with the other opportunities we have. — BOB SHEPHERD, executive vice-president of PetroChina’s Brion Energy. Financial Post, April 13.
“THE [OILSANDS] ISSUE IS NOT SO BLACK AND WHITE. THE QUESTION IS HOW YOU EXPLOIT [IT]…. YOU CAN ACTUALLY HAVE A NEGATIVE BARREL OF OIL IN TERMS OF ITS GREENHOUSE GAS EMISSIONS IF YOU COLLECT MORE CARBON DIOXIDE FROM THE ATMOSPHERE THAN IS EMITTED BY THAT BARREL. “SUPPOSING YOU DID THAT, WOULD YOU THINK OF THE OILSANDS IN THE SAME WAY AS IF THERE WAS NO MITIGATION AND ONLY A POLLUTANT CONSEQUENCE?” — U.S. climate envoy JONATHAN PERSHING. CBC, April 15.
“There is a growing risk that, due to protracted delays, mounting opposition, escalating costs and the lack of distinct political support, essential pipeline projects may die stillborn— just like the ill-fated Mackenzie Pipeline—with severe damage to a vital sector of the economy that is already reeling from depressed prices.” — Former Canadian prime minister BRIAN MULRONEY. National Post, April 19.
Q 2 2 0 1 6 • J W N E N E R G Y. C O M • 1 9
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IN REVIEW
JUNE 2006 BARRELS ON THE MOVE
Syncrude Canada commissions massive UE1 upgrader expansion
// #THROWBACK
In 2006, Syncrude Canada hit a major milestone in its development with the completion of the upgrader expansion one (UE1) project. But signs of what would soon become major headaches for the industry darkened the celebratory mood. A labour shortage was on the horizon, and the project’s hefty price tag—over twice the original estimate—was part of a decade-long struggle with cost overruns in the oilsands. In an excerpt from Oilsands Review’s first issue, editor Deborah Jaremko profiles the historic project.
DEBORAH JAREMKO
PHOTO: JEREMY SEEMAN
INTRODUCING THE OILSANDS The most significant expansion in Syncrude’s history—an approximately 100,000-bbl/d capacity increase—is now complete, and the joint venture is now capable of producing 350,000 bbls/d. Officially commissioned on May 6, 2006, UE1 not only provides more barrels to the market, but also
incorporates environmental mitigation measures and results in a new, higher value crude from the entire production stream. “It’s a step change,” says Mike Glennon, executive director of the Athabasca Regional Issues Working Group. “It puts Syncrude back in front in terms of volume of production.” Glennon says that although the oilsands is now perceived globally as an important resource, still not everyone believes in the commitment of producers and the reality of its potential. “We are not necessarily as well recognized as we think. People still have a little doubt or reservation until the oil comes out the back door,” he explains. “Every time something like this comes to fruition, it adds to the stability of the industry. These companies are serious about it and we really are going to see these barrels.”
MEGATEAM FOR MEGAPROJECT It required a myriad of contractors and subcontractors to complete UE1. A joint venture of Fluor Daniel and SNC-Lavalin executed the engineering and procurement, while Kellogg Brown and Root (KBR) was in charge of construction management. Many local contractors were involved, but the magnitude of the project demanded the company look to the broader community in Canada and around the world, according to Charles Ruigrok, Syncrude chief executive officer. “Projects of this size you cannot do purely with the capacity available in the local community,” he says. In total, the construction phase of the UE1 project required the work of 31,000 people. At peak periods, up to 8,000 people were on site working on the project, in addition to permanent operational staff.
Q 2 2 0 1 6 • J W N E N E R G Y. C O M • 2 1
I N R E V I E W • T H R OW B AC K
“[Oilsands producers] are not necessarily as well recognized as we think. People still have a little doubt or reservation until the oil comes out the back door.”
Where are they now?
CHARLES RUIGROK Ruigrok’s tenure at the top of Syncrude ended in 2007. In 2011, he began a year-long stint as interim president and chief executive officer of Enmax Corporation, where he continues to sit on the board of directors today.
— MIKE GLENNON, executive director of the Athabasca Regional Issues Working Group, May 2006
LOOMING LABOUR CRUNCH Syncrude began to see the early impacts of the looming labour crunch during the project, says co-owner Canadian Oil Sands Trust. Construction of new oilsands operations and expansions of existing plants, combined with the potential development of the Mackenzie Gas Project, have forecasters pointing to the 2007-09 period for peak labour demand. From this standpoint, Canadian Oil Sands says the timing of the UE1 was somewhat lucky. “We are fortunate that our stage three expansion is expected to be completed before the major crunch and the associated risk should be largely behind us,” the company reported in a recent investor presentation. The company says future plans also fit well with the labour market situation. “Our more modest and perhaps more flexible stage three debottleneck is an ideal expansion to be conducting during the upcoming period of heated activity in the region, while our stage four major expansion is not scheduled to occur until the next decade,” reads a recent investor presentation.
DILUENT SUPPLY Canadian Oil Sands has indicated the joint venture is considering marketing some of the production stream as a light, sour diluent for transportation of bitumen and heavy oil. The company says operating costs of producing diluent would be lower than Syncrude Sweet Premium because it does not require hydrotreating, which requires natural gas. And there is a market for the product—conventional diluents such as naphtha are in tight supply, which presents a
2 2 • Q 2 2 0 1 6 • J W N E N E R G Y. C O M
growing concern for industry in general as production gets heavier and heavier. “This will help alleviate that,” says Greg Stringham, vice-president of markets and fiscal policy with the Canadian Association of Petroleum Producers. “It really does continue the value-added stream that’s going on in the province.”
CANADIAN OIL SANDS The largest shareholder in the Syncrude project was swallowed up by Suncor Energy earlier this year after months of heated back and forth between the two companies. With the acquisition of COS and the buyout of Murphy Oil’s five per cent stake, Suncor is left as the majority owner of Syncrude, at 54 per cent.
COSTLY EXPERIENCE The final tab for the UE1 came in at about $8.4 billion—more than double the original estimate of $4.1 billion. This cost overrun, and similar price escalations for recent projects at Suncor and the Athabasca Oil Sands Project, has been attributed to general industry experience with the challenges associated with building a megaproject. “There have been a lot of negative and derogatory comments about [the cost and schedule],” says KBR representative Alan Tarasuk. “When it’s all said and done, what they built was a huge, huge project, and they should be proud of themselves.” The next phase for Syncrude is the stage three debottleneck, which will be followed by stage four—a major expansion envisioned to be similar to stage three in scope, opening up Aurora South and adding about 100,000 bbls/d of upgrading capacity. Both phases still require approval by the joint venture owners. For now, if just for a moment, Syncrude can take a breath as production from its new facilities ramps up. “This is a culmination of years worth of effort on the part of many,” Ruigrok says. “I was elated.”
ATHABASCA REGIONAL ISSUES WORKING GROUP In 2013, the organization relaunched itself as the Oil Sands Community Alliance. It continues to work with stakeholders to address the socio-economic impacts of oilsands development.
GREG STRINGHAM After serving for many years as one of the highest profile voices for the oilpatch in the media, Stringham retired from the Canadian Association of Petroleum Producers earlier this year.
BROUGHT TO YOU BY FLUOR
SUSTAINING CAPITAL solutions
Fluor pushes the envelope on modularization for a unique oilsands mine revamp BY DEBORAH JAREMKO While oilsands spending on new growth capital projects has effectively ground to a halt in the current low price environment, producers continue to invest in work that improves efficiency and optimizes their existing assets. As Fluor learned on a recent project, sustaining capital work can present unique challenges, but overcoming these challenges could help the oilsands industry become more competitive in a lower-cost world. “It is quite refreshing to work on a sustaining capital job because it drives you to find solutions that are very unique,” says Fluor project manager Sean Mulholland. “When we ultimately come out of the downturn and into the next major project cycle, I think that we’re going to be better positioned as an industry because we’re going to be a lot more fit for purpose and safer. We’re going to have these solutions that have been developed from this sustaining capital mentality and build them into our capital projects.” Fluor is nearing completion of a major revamp project of extraction facilities at an operating oilsands mine that demanded
innovative thinking and a change of processes from the beginning. “Basically we had to increase the temperature of the extraction water in order to help the client increase their bitumen recovery,” Mulholland explains. “In order to accomplish that we looked at various options and what we landed on was two additional boilers, expanding their water treatment capacity and being able to cool the solvent in the froth treatment area.” The hardest part: production needed to continue during the entire process. There also wasn’t much room to work in. “Our objective was to minimize site work and be in and out as quick as we could,” Mulholland says. “There was no space within the existing building that housed water treatment and we needed to add additional capacity, so we needed to wrap our facilities around the existing building in the shape of an L. We ended up having to deal with millimetres of difference between the outside of our new building with the existing building, and millimetres between our building and the access road, so we really had no room to spare.”
Fluor was able to work with the owner, as well as its vendors and construction contractors, to successfully execute the project using its 3rd Gen Modular ExecutionSM approach. “We had to amend our whole work process and the work processes and packages of our vendors in order to be able to fit into the constrained space. It forces everybody to be very open and to show every card that they have before they play them,” Mulholland says. “It’s a very different approach but it’s one that we have to take as we move into a heavily modularized design. 3rd Gen Modular Execution really pushes everything into a module including the majority of the electrical, the majority of the piping and equipment.” On the revamp project, which was comprised of 50 Fluor modules, the company was able to move about 600,000 man-hours from the field to module fabrication yards. Taking the innovative approach was a challenge, but Mulholland says it was worth it. “I believe that taking a conventional approach to project execution would’ve led to a significantly more expensive design, increase our exposure hours at site, and also would have led us to expand the outages that the client actually had.”
PROFILE
Working Coasts A crude export tanker docked at the Westridge Terminal operated by Kinder Morgan Canada, the end of its Trans Mountain Pipeline, which has been operating since 1956. Cenovus is a contract shipper on the system but is taking tighter control over what happens to its barrels once they hit the waves.
24 • Q2 2016 • OILSANDS REVIEW
PROFILE
Cenovus hires 30-year marine veteran Claus Thornberg to manoeuvre midstream and get more crude overseas R.P. STASTNY
P
ipeline constraints have hobbled bitu-
Cenovus also appointed a former executive of a
men market access for close to a decade
private U.S. rail logistics company. With North
now, squeezing producer margins with
American logistics in good hands, Cenovus set
wide swings in the heavy-light oil
it sights offshore and, last year, hired Thornberg
price differential. In the absence of major arteries such as Keystone XL to the U.S. Gulf Coast,
as vice-president of marine. Thornberg is tasked with opening new op-
one of two proposed pipelines to the west coast,
tions for overseas crude shipments at the Port
or Energy East to the east, a patchwork of pipes
of Vancouver, where Cenovus currently sends
and bitumen-on-rail options have sprouted to
about 11,500 bbls/d through the TransMountain
deal with growing oilsands output. The key to
Pipeline. With the repeal of the U.S. crude oil
getting the best value from this transportation
export ban that had been in place since the
network is knowing how to work it.
height of the Arab oil embargo in 1975, the U.S.
At least that’s what Cenovus Energy believes, as it continues to expand its midstream
Gulf Coast is another sandbox of opportunity. This February, his team set up a branch
resources and expertise. Its latest addition is
office in Houston to better manage Cenovus’s
marine logistics expert Claus Thornberg. The
50,000 bbls/d of available capacity on Enbridge’s
former tanker captain brings 30 years of mar-
Flanagan South Pipeline to the U.S. Gulf Coast.
ine shipping experience and some colourful
That capacity will climb to 75,000 bbls/d by
stories to boot.
2018. By then, oil prices will almost certainly be stronger and bitumen-by-rail shipments to
DIVERSIFICATION
the U.S. Gulf Coast should also be in full swing,
When oil prices are strong, producers con-
potentially bringing more volumes for export.
sider midstream and downstream operations
“With our marine and other groups, Cenovus
a low-margin drag on their business. In the
has decided to take a very active role in
current market, when there’s no money in ex-
working on the coasts as well as engaging in
traction, refining margins that leverage cheap
dialogue at various levels, including the polit-
crude prices start to look pretty good. To its
ical level, to be a visible player in defining the
credit, Cenovus has a foot in downstream with
standards of what is a world-class standard in
a 50 per cent stake in two U.S. Phillips 66 refin
shipping,” Thornberg says.
eries with a capacity of 255,000 bbls/d as part of an upstream-downstream asset partnership.
PHOTO: KINDER MORGAN CANADA
In mid-2015, Cenovus stepped up its
PIRATES OF SOMALIA Thornberg’s career started at A.P. Moller-
midstream presence with the acquisition of a
Maersk, an iconic company for Danish men
railloading terminal from Canexus. The op
with passion for the sea. But he quickly left
portune $75-million acquisition in Bruderheim,
his peers behind. By age 28, he was a tanker
Alta., added what cost Canexus $360 million to
captain. He gave up life at sea for a shorebased
build before the crude-by-rail market collapsed
career and became managing director with
along with global oil prices.
Camillo Eitzen & Co. He advanced to the buying
To achieve the highest safety standards and the best netbacks from its rail interests,
and selling of companies as a project director and attained chief executive officer of Nordic
Q 2 2 0 1 6 • J W N E N E R G Y. C O M • 2 5
PROFILE
Tankers when it was a sizable concern of
plane circled in order for him to verify the
decided on a new management team,
about 100 ships.
identities of the 12 men, then Thornberg gave
Thornberg found himself in New York being
permission to drop the money.
interviewed for a leadership position with a
But it was as vice-president of Copenhagenbased Clipper Group in 2008 that he experi-
Everything went according to plan: the ship
dry cargo shipping company. It wasn’t a good
enced his career’s most dramatic moments. The
was released; the crew, which was predomin-
fit, so his friends in the executive search firm
company had one of its ships taken hostage by
antly Russian, was met by a Russian warship;
challenged him to widen his horizons.
Somali pirates, putting into play an 80-day
and Thornberg went off to a much-needed
negotiating marathon for Thornberg that taxed
vacation with his family. Except that, instead
off the phone with Bob Pease, the president of
all of his resources and ended with a broken leg.
of sleeping for two days, he hit the ski slopes
downstream here. The opportunity sounded
and broke his leg quite badly.
interesting to me,” Thornberg says.
“I had to change from being frustrated and angry and pissed with the Somali pirates, and treat the situation as a business situation to
“I spent the next eight days in a French hospital,” he says.
“Cenovus came up. They just literally got
It took some months to finalize Thornberg’s hire because Cenovus wasn’t entirely clear
It would be a great story if Cenovus set out to hire Claus Thornberg after seeing the documentary film where he negotiated with Somali pirates and liberated his company’s ship, recognizing the parallel between it and Canada’s situation, where anti-pipeline activists are holding bitumen production hostage. But that’s not how it played out.
negotiate a ransom and figure out how to pay
The hostage-taking got a lot of internation-
what it wanted in a marine person. Was it
al attention at the time. The entire negotiation
looking for a charterer who could arrange
and liberation process was filmed, starting at
shipments on a day-to-day basis? Or was it
ransom agreement for the release of the
hour 20, and made into a documentary.
looking for someone who could bring a stra-
ship and her crew, provided that all the crew
Thornberg was later often asked to speak
tegic view to its marine strategy?
members were alive and accounted for. Before
to various groups about his experience. The
picking up the cash from a local bank in
company’s work with the FBI and other intel-
on the latter,” Thornberg says. “Today, we work
Copenhagen, he recalls having to call and ask
ligence agencies eventually led to the arrest of
extremely well together in executing the down-
how many bags he would need for $2 million.
two of the pirates on U.S. soil.
stream strategy, which is ultimately creating
that,” Thornberg recalls. He reached an approximately $2million
“I was told it would probably fit in one big sports bag, but better bring two. So I picked up
“They are now in U.S. prisons,” Thornberg says.
the money with an armed guard and we took
“Fortunately for me, they ended up deciding
maximum value for each barrel of bitumen that Cenovus produces and ensuring that each drop of oil arrives at the customer’s location without
it to the local airport where we had a com-
FROM OCEAN TANKERS TO SAGD
pany jet,” he says. “I had an employee with a
MARKET ACCESS
background in the British SAF [Special Armed
It would be a great story if Cenovus had seen
VALUE OF EXPERTISE
Forces]. His knowledge came in handy over
the documentary film about the hostagetaking,
“When you look at [Port of Vancouver] statis-
those 80 days. He travelled with me all the way
recognized the parallel between it and Canada’s
tics, in the 60 years that the TransMountain
to Mogadishu [Somalia], where the money was
situation, where anti-pipeline activists and
[Pipeline] has been there, and in 100 years that
put into a special canister with a parachute
the U.S. President’s Office are holding bitumen
others have been transporting oil in and out
and loaded into a drop plane.”
production hostage, and said, “We need to hire
of Vancouver, there has never been a single
this man Thornberg!”
incident involving a tanker,” Thornberg says.
Then Thornberg’s righthand man flew
incident. Safety is paramount.”
with the money to the ship, where the crew
But that’s not how it played out. After
“It’s quite astonishing, but it reflects global sta
was lined up on deck for identification. The
the private equity owner of Nordic Tankers
tistics on safety around tanker transportation.”
26 • Q2 2016 • OILSANDS REVIEW
PROFILE
Claus Thornberg is changing how Cenovus manages its tidewater shipments, both from Vancouver and the U.S. Gulf Coast.
improves your overall CO2 emission footprint.
negotiate with the ship owners on charter
for the port city as well as for the oil industry
Any spill in Vancouver would be disastrous
With the new federal and Alberta governments,
deals,” Thornberg says. “In Calgary, other than
and its prospects for future exports anywhere
carbon emissions matter more and more.”
myself, I have a project manager who sup-
along British Columbia’s coast. Until now, OPPORTUNITIES
on market access project things. It’s a small
on board (FOB) at Vancouver because it didn’t
So safety is paramount. Shipping profits are
team, but it’s a team with the right compe-
have the marine expertise to sell it delivered
nice. But the overarching purpose for Cenovus’s
tences to be able to execute a marine strategy
to final destination. Selling FOB means that
marine group is to sell into international
in a safe and efficient manner.”
the ownership of the cargo changes hands in
markets in Asia and Europe. The company’s
Vancouver and becomes the responsibility of
long-term vision is that this capability will
president of downstream that by Q1 2016
the buyer, who then arranges the ship. In this
narrow the heavy-light oil differential in
he would be ready to charter and sell cargo
way, FOB cedes control over the critical ship
North America.
delivered rather than FOB. He achieved that
selection and vetting process, which has safety
PHOTO: CENOVUS ENERGY
ports the team down there and supports me
Cenovus has been selling its production free
Its Houston office is central to this inter
Last year, Thornberg committed to his
goal. The incremental lift in the value of a
implications for the Port of Vancouver. By sell-
national push. Thornberg’s small team of
barrel of crude can be as much as five dollars
ing through to destination, Cenovus controls
marketers, traders and logistics experts work to
when shipping to markets such as India or
the complicated and expensive vetting process
achieve the best terms for Cenovus’ crude and
China, Thornberg says.
and ensures the highest safety standards while
diluent movements and its refining require
capturing the profits in the shipping leg.
ments, all while strengthening its presence in
might find another [favourable] market,” he
“In the vetting process, you also are able
“Over time that may level out, but then you
the important PADD III area. Houston is also a
says. “I’m not suggesting that we’ll always be
to assess things like fuel line consumption,”
hub for ship owners, brokers and everyone else
able to generate [an incremental] five dollars
Thornberg adds. “Is it a modern vessel? Does
who has a hand in international market access.
a barrel, but if we are able to generate a dollar
it get good fuel economy? Not only does this improve your overall margins, but it also
“My team is four people. Two are now in Houston. They’re the charterers, so they
per barrel just by having the ability to sell internationally, that is significant.”
Q 2 2 0 1 6 • J W N E N E R G Y. C O M • 2 7
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S Y N C R U D E OW N E R S H I P
Why it may be a matter of when, not if, Suncor will take over as operator of Syncrude
PHOTO: ©ISTOCK .COM/ YSBR AND COSIJN
DAVE S. CLARK
For almost four decades, the Suncor and Syncrude oilsands plants have operated across the highway from each other north of Fort McMurray in a competitive but collegial atmosphere. For 25 years, these two producers were essentially the only game on
Q 2 2 0 1 6 • J W N E N E R G Y. C O M • 2 9
S Y N C R U D E OW N E R S H I P
the go in the Athabasca oilsands. The idea
benefited from secondments from its
of Suncor now owning 54 per cent were not
of Suncor taking over Syncrude is nothing
multiple owners. Currently, it is working
answered by the company before press time.
short of pivotal, historically. But even as the
under a management services agree-
joint venture’s new majority owner, Suncor
ment signed in 2006 with Imperial Oil
of oil and gas equity research for BMO
says that’s not happening anytime soon.
(and ExxonMobil), its 25 per cent owner.
Capital Markets, says that although Suncor
That agreement gives Syncrude access
has stated there are no plans to take over
seat of the Syncrude project, following its
to certain management systems and has
operatorship, he believes it will happen in
$6.6-billion takeover of Canadian Oil Sands
brought Imperial employees into senior
the future.
and its $973-million buyout of Murphy Oil’s
management positions, but spokesman
ownership share. At 54 per cent ownership,
Will Gibson says that Syncrude itself still
with the other partners and Exxon, then
Suncor says it has already started sharing
operates independently.
give notice and take over operatorship.
its expertise with Syncrude and operator
“Syncrude has operated on behalf of
“They’ll have to have that discussion
That will take a little bit of time, but I do
Imperial Oil, but maintains it has no plans to
different owners throughout its history.
100 per cent believe Suncor plans to take
take over control of the project’s operations.
So we continue just to work at producing
over operatorship. Once they do, we expect
oil responsibly for the people that own us.
them to look to improve reliability and
do plan to do, however, is work cooperative-
That’s our commitment and that’s what
reduce costs,” he says.
ly with Imperial/Exxon and Syncrude to
we’ve done before this change of ownership
improve reliability and reduce costs,” says
and that’s what we’re going to continue to
greatly from Suncor’s involvement, and
Suncor spokeswoman Sneh Seetal. “Our
do,” says Gibson.
the management services agreement with
“That is not our present plan. What we
Ollenberger says Syncrude will benefit
According to Seetal, the management
Imperial/Exxon won’t have an impact on
reliability with the Syncrude team. We are
services agreement with Imperial is a 10-
that since Syncrude operates as a stand-
looking at working together to improve
year deal, set to expire in November 2016.
alone company.
the operational performance, and some
However, the contract will automatically
discussions on the reliability front have
roll over year-to-year unless either owner-
Exxon really only has a handful of indi-
already begun between Suncor, Syncrude
ship or the operator requests changes. She
viduals that are essentially seconded to
and Imperial.”
said there is a twoyear notification period
that operating company. Over time, I would
required before any changes to the operator
expect Suncor to probably try to bring
four and as many as 10 owners at any one
could take place, and three owners making
Syncrude’s operations more and more
time in its 50-year history, Syncrude has
up 51 per cent of ownership would need to
under the umbrella of Suncor. Over time, I
operated independently but has always
agree for that to happen. The implications
suspect they will try to achieve additional
plan is to share what we’ve learned about
A joint venture that has had as few as
30 • Q2 2016 • OILSANDS REVIEW
“When we say Exxon operates Syncrude,
PHOTO: JOE Y PODLUBNY
Suncor is now firmly in the majority
Randy Ollenberger, managing director
S Y N C R U D E OW N E R S H I P
“I think if the other owners of Syncrude embrace the opportunity that is presented with Suncor having more ownership, it can be a positive thing for everybody.” — JIM CARTER, Former Syncrude president and chief operating officer
efficiencies and reliabilities by fully inte
investors alike, watching Syncrude kind of
develop between those two facilities over
grating the operation,” says Ollenberger.
struggle along here over the last few years,
time. Instead of operating them as two
almost since Imperial took over the man-
completely independent projects, it would
operating officer Jim Carter says the
agement services agreement in November
make sense perhaps to integrate some of
company he used to manage will directly
2006. With Suncor now nearly a 50 per cent
the infrastructure and utilities. That’s all
benefit from Suncor’s increased ownership.
owner, there’s a big incentive for them to
with the intent of lowering operating costs
“I think if the other owners of Syncrude
take a very active role in improving that
and improving reliability.”
Former Syncrude president and chief
embrace the opportunity that is presented
operation, increasing reliability and getting
with Suncor having more ownership, it can
the facility to run closer to nameplate
looking at efficiencies between the two
be a positive thing for everybody,” says Carter.
capacity, whether or not Suncor takes over
projects, but it’s too early to have any de-
the management services agreement from
tails on what future plans may be.
“I suspect that [the new ownership stake] will enable Suncor to dedicate more resources to helping the operation to move
Imperial,” says Bouchard.
Seetal says Suncor has already started
Although Suncor has the most experi-
One simply has to look back at the im-
ence in the oilsands business and is well
forward and to realize its full potential.
provements in reliability that Suncor has
suited to help Syncrude, Ollenberger says
Suncor has been in the business for a long
made to its own facilities in the past five
he doesn’t think Syncrude will ever be as
time. The strength they would have would
years to see what it could do at Syncrude,
reliable as other facilities.
be that they’ve got a lot of experienced em-
according to Bouchard. “They’ve actually
ployees who have been around for 20-plus
made some pretty dramatic changes to the
Suncor had from their process that they
years. In the last 10–12 years, Suncor has
reliability of their mining operations. If
can apply to Syncrude to help improve
done a lot to develop their people and bring
you extrapolate and take whatever they’ve
reliability there. But I don’t expect them
the best out of their folks. I think they would
done there and apply it to Syncrude, it’s
to ever achieve the same sort of reli-
certainly bring that to Syncrude as well.”
going to be better than what we’ve seen,”
ability that Suncor or Canadian Natural
he says.
Resources achieves with their delayed
Analyst Justin Bouchard, who covers both companies for Desjardins Capital Markets,
Bouchard also believes Suncor and
“I think there are lots of learnings
cokers. I think the fluidized bit cokers
says Suncor now has a big incentive to
Syncrude’s proximity to each other will lead
that Syncrude operates are inherently less
work closely with Syncrude, whether it is
to more efficiencies in the future. “Longer
reliable,” he says.
as its operator or in the advisory role it has
term, if you look at where the facilities are,
already started to take on.
Syncrude and Suncor’s mining projects
like Syncrude’s have complications and
are right beside one another, and you’re
can be tricky to run, but said they can also
probably going to see some more synergies
be operated very successfully.
“Suncor has been watching patiently from the sidelines, as everyone has,
Carter says he agrees that fluid cokers
Q 2 2 0 1 6 • J W N E N E R G Y. C O M • 3 1
S U S TA I N I N G C A P I TA L
SAGD producers are looking to tackle costs with standardized designs for sustaining capital projects—but is it really possible? MELANIE COLLISON
f nothing else, this unwelcome
Energy Studies, points out companies are
downturn is breaking down the
increasingly treating SAGD like a manufac-
oilsands sector’s complacency. The
turing operation. Beyond modularizing plant
protracted low price environment
components, producers are also standardiz-
is forcing companies to flex their
ing wells and pads to improve cost efficiencies.
creative muscles and reinvent
Yet full standardization remains beyond the
themselves.
grasp of industry—for now, at least.
“Complacency in the long run will result
“Processes that are dependent on the
in failure,” says Allan To, president of the
local geology, such as optimizing steam to oil
Supply Chain Management Association of
ratios in SAGD, are more difficult to replicate
Alberta and senior commercial manager,
at scale, and true ‘manufacturing’ SAGD
category management, at Suncor Energy.
processes remain aspirational at this point,”
“This sector has experienced signifi
the report reads. “Survival is a compelling
cant changes, and it has shown itself to be
motivator, however, and producers do realize
extremely resilient historically,” he says.
that they need to rapidly improve operat-
“Looking out there to our supply community
ing practices or remain uncompetitive for
and the owner-producers, I see a lot of en-
investment.”
ergy around people finding ways to survive,
As SAGD moves from infancy to maturity,
finding ways to reinvent themselves and
companies are embracing the principles
finding ways to be successful. That’s what
of mass production to achieve economies
achieves greatness.”
of scale. As with cars or computers, the
Resilient people—or industries—see
technology was engineered very specifically
change as an opportunity and capitalize on
every time it was applied in the early days.
it. Case in point: the movement to reimagine
“Now that we’ve run that many, many years
SAGD design as a standardized commodity,
over, some of that engineering has already
which greatly reduces the need for detailed
been done. Let’s take some of that engin-
engineering, thus boosting capital efficiency.
eering away and standardize some of that
This is particularly important for the on-
design. That’s where things are going right
going investment needed to sustain opera-
now,” To says.
tions, including the drilling and construction of new SAGD well pads.
“The rate of adoption is a function of the imperative to change,” he continues. “Given
The Future of the Canadian Oil Sands, a
that we are in an extremely low oil [price]
report produced by the Oxford Institute for
environment and what we’re all seeing is
32 • Q2 2016 • OILSANDS REVIEW
S U S TA I N I N G C A P I TA L
Q 2 2 0 1 6 • J W N E N E R G Y. C O M • 3 3
S U S TA I N I N G C A P I TA L
SAGD well pad at Suncor’s Firebag SAGD project
lower and not only longer, but much longer,
incorporating lessons learned to improve
says. “In the hands of a producer that
the imperative to change is that much
efficiency and drive down capital costs.
understands its resource and has carefully
Chad Hadler, director of technical
thought through its facility requirements, a
these tough environments are in the best
services for modularized well pad provider
highly standardized well pad design should
position to ride it out and be successful.”
Integrated Thermal Solutions, says deep
require minimal engineering effort and a
industry experience has to inform a stan-
lot less time to execute.”
STANDARDS AND PRACTICES
dardized product. He notes that employees
Cost now trumps the desire of clients to
at his company have seen over eight gener-
ENGINEERING SHAKE-UP
impose their own standards and specifi
ations of well pads, and they have learned
Simon Nottingham, general manager of
cations on each project. The term “repli-
to integrate engineering, fabrication and
Fluor Canada, says the engineering per-
cation” is also used by some to describe
field construction into a turnkey product.
centage of a project budget would typically
this approach, but it’s misleading, says Rob
Each model is designed to fit a large spec
range in the mid-teens, depending on the
McNeill, principal of Drifter Projects, a pro-
trum of situations.
development. Reducing engineering to just
ject management consultant that shepherds SAGD projects for mid-sized producers. “Replication implies you rubber stamp
“We’re selling a solution and a prod-
adding updates to a standard design could
uct; we’re not selling a service,” he says.
drive that figure down to three or four per
“They’re two different business models—
cent, he believes.
something; you’re producing the same
the detailed engineering and separate
That might not be healthy for a pure
thing over and over, like a manufacturing
teams managing installation, and sep-
engineering company, but for an engineer-
process that would produce cars,” McNeill
arate teams managing the fabrication
ing, procurement and construction (EPC)
says. “It can never be like that when you’re
contracts. All of those jobs are typically
company like Fluor that has access to the
dealing with resource extraction, because
reimbursable cost-plus jobs, which in my
global reach of its multinational parent,
each resource is different and it requires
opinion was [the industry’s] big down-
engineers will simply be redeployed to the
you to think through what you’re trying to
fall and how Alberta’s cost per barrel for
next growth area, he says.
accomplish.”
installation went up so high.”
But he believes a high degree of stan-
In the perennial tug of war between lump
In the bigger industry picture, McNeill anticipates engineering firms will repli
dardization is still possible. “In well pairs
sum and cost-plus contracting models,
cate the cycle of acquisitions, mergers and
and how the pads are constructed, that’s
pruning out detailed engineering could give
divestments that has long characterized
a very easy place to standardize. So then
the former an advantage.
Alberta’s oil industry.
you’re using a similar design every time out
“Logistics will be streamlined. There’ll
“We’ve gone through a cycle here where
and you save money,” he says. Other parts
be fewer billable hours, but a more efficient
the big engineering firms swallowed up a
of the SAGD process call for continually
product and outcome, for sure,” McNeill
bunch of the medium sized engineering
34 • Q2 2016 • OILSANDS REVIEW
PHOTO: DEBOR AH JAREMKO/JWN
greater. Those companies that can adapt in
S U S TA I N I N G C A P I TA L
firms, and unfortunately, that doesn’t im prove efficiency,” McNeill says. In some cases, an engineering firm may actually dwarf the resource company that hires it. For a relatively nimble and
The case for a united front on project design
decisive company with a few hundred employees, it can be difficult turning over responsibility for the design, construction and commissioning of a project to an organization five or six times its size. The inherent bureaucracy of the larger company just doesn’t match well with the smaller one. “You really lose a lot of effi ciency trying to make the cultures mesh,” he says.
REDUCING BUREAUCRACY Chester Nagy, who founded Plains Fabrication & Supply in 1988, has dealt with that shad-
Operators at Statoil’s Leismer SAGD
owing and the bureaucratic hurdles from his side of the blueprints, too. Nagy is active in PAAD (Productivity Alignment and Delivery), the partnership of owners, EPCs and suppliers collaborating to improve industry productivity, and he’s on the Alberta board of directors of Canadian Manufacturers and Exporters. One bad apple eroded trust broadly within the industry about 15 years ago, and a handshake was no longer enough to seal a deal, Nagy says. That opened the door for EPCs to add layers of bureaucracy in the execution of a project. The industry got pushed into adding inspectors and paperwork, which he says is frustrating because fabricators used to be able to do the same job to the same standard of quality 20–25 per cent faster. The extra inspections and X-rays slow everything down. PHOTO: JOE Y PODLUBNY
“You’ll have five people looking at a dial that’s not moving for an hour,” Nagy says, “but if I don’t do [every extra inspection] one single time, I lose my licence. They created a redundancy of mistrust. It’s ingrained now; it’s hard to undo.”
Oilsands producers could overcome their existential threat if they could only come together on common specs and standards JOSEPH CAOUETTE
H
ow difficult is it to build in Alberta? Consider the following scenario: a company goes looking for a compressor skid. Like any good service provider, the vendour feverishly worked to incorporate the owner company’s in-house standards into the design. As a result, there were nearly 200 spec deviations that ultimately took two months to resolve. In some cases, the two companies were disagreeing over insulation thicknesses that could be measured in millimetres. “Was it worth spending three months of everybody’s time on a customized compressor skid that is really just worth $5 million?” asks Anirudh Kumar, a construction engineer and project manager at Swift Resources. “If we can see this on a $5-million compressor skid, just imagine what’s going to happen on a $5-billion project.” Kumar has worked on a number of major oilsands projects, including Canadian Natural
Resources’ Horizon mine, Suncor Energy’s Fort Hills mine, and Cenovus Energy’s Foster Creek and Christina Lake developments. What he found was that each organization had its own set of in-house standards and specifications, developed over the years through ingrained habits and ad hoc additions. There is the Suncor way and the Cenovus way, and never the twain shall meet. But one approach is not necessarily better than the other—it’s just different, that’s all. Speaking at Calgary’s Modular Construction and Prefabrication Summit Canada 2016 in March, Kumar made a case for standardization as the next great shift in how the oilsands approaches modular fabrication. The audience, while receptive to his message, was skeptical that such a goal could ever actually be realized. “We’ve got owner companies clustered very close to each other north of Fort McMurray, and we can’t even get them to share an airport,” one attendee asked. “How are you going to get them to share standards?” Actually, forget about the challenges of developing common standards across multiple organizations: what about simply developing unified specs within a single company? The same audience member explained that his employer couldn’t even manage a unified approach across its own business silos, which include
Q 2 2 0 1 6 • J W N E N E R G Y. C O M • 3 5
S U S TA I N I N G C A P I TA L
— Audience question at Modular Construction and Fabrication Summit Canada 2016
36 • Q2 2016 • OILSANDS REVIEW
heavy oil, oilsands, and conventional oil and gas. Companies will need to start sorting out their own tangled web of standards before they can begin to look at industry-wide changes. Kumar acknowledges this change will be difficult, but he is seeing companies starting to look at streamlining their own internal specs and standards. In fact, he’s working on tackling that very challenge right now with a petrochemical company. Still, even with leadership buy-in, the process will likely take 12–14 months, he says. In an interview with Oilsands Review, Kumar puts much of the blame on overdesign. He recalls a project where the team had planned to add a closed hydrocarbon trench to help drain vessels during turnarounds, which opened up a wealth of new engineering issues. More valves were needed. Drains had to be placed underground, which increased construction costs. Maintenance costs would rise. The system would need to be monitored to ensure no hydrocarbons leaked. Or you could just bring in a hydrovac to clean out the vessels whenever necessary and avoid all of the extra design and construction work. “We don’t realize that when we customize too much, we’re not letting the operations crew manage the operations,” he says. “Let’s design it one way and let operations come up with their own procedures. Have faith in the ability of those guys to do it safely and efficiently, so we don’t have to incorporate these things into the design.” The company ultimately dropped the trench idea, but more because of the 2008-09 financial
SAGD well pad at Cenovus Energy’s Christina Lake project crash than any special epiphany about the dangers of overdesign. However, cost reductions are just as important today as the oilsands industry faces an “existential threat” from low prices, Kumar says. Because of the massive scale of oilsands developments, the industry has considerable bargaining power with suppliers—but only if it can start pushing more unified standards, he says. The market becomes much more attractive for vendors if it is possible to offer the same product to multiple companies, rather than having to customize and redesign right down to the level of valves and gauges for each client. Kumar believes standardization could translate into cost savings ranging between 15 and 20 per cent. The most significant hurdle may simply be encouraging the owner companies to relinquish some of the internal standards that have developed over the years. There is a wealth of expertise in the industry, but the ability to apply continuous learning from previous projects will continue to be thwarted as long as engineers, fabricators and builders are forced to adapt new solutions to the same old problems with each client. “On one of the projects I’m doing, I’m supervising our construction contractors, and they’re all good at what they do,” Kumar says. “The problem is they have to retrain themselves. We have amazing talent, but we’re not utilizing it because they’re constantly relearning.”
PHOTO: CENOVUS ENERGY
“We’ve got owner companies clustered very close to each other north of Fort McMurray, and we can’t even get them to share an airport. How are you going to get them to share standards?”
Inform. Connect. Grow. The industry is changing and so are we. For over 75 years, JWN has provided the most trusted intelligence and insight on Canada’s energy industry through products such as the Daily Oil Bulletin, Oilweek, Oilsands Review, CanOils and Evaluate Energy. We are pleased to introduce jwnenergy.com , the newest addition to our portfolio of products and your resource for the latest oil and gas news, research reports, data and event information— updated daily. Visit jwnenergy.com to sign up for your free daily energy e-news alert today.
F E AT U R E
38 • Q2 2016 • OILSANDS REVIEW
PA R T I A L U P G R A D I N G
PARTIAL UPGRADING COULD ADD VALUE TO ALBERTA BITUMEN AT A LOWER COST, BUT COMMERCIALIZATION STILL HAS A LONG WAY TO GO R.P. STASTNY
erald Bruce, like most people associated with the upgrading of bitumen, is encouraged by the Alberta government’s recent endorsement of partial upgrading. Against the backdrop of sub-$50 WTI and a barrel of bitumen selling at even less, partial upgrading is a compelling proposition because it has the potential to narrow the light-heavy oil differential, reduce or eliminate the cost of diluent in piping bitumen (which also effectively increases the capacity of the existing pipeline network for bitumen), reduce the overall carbon intensity of bitumen refining and provide better netbacks to oilsands producers. But oilsands producers won’t see any of these benefits through this downturn because commercial partial upgrading is still years away. Also, the government’s $300 million of incentives—the details of which are still pending—may not seem like much to an industry more accustomed to thinking in billions. Bruce, who is the president of GWB Process Consulting, makes the point that to get to a place where the industry can spend billions on commercial partial upgrading, it will need to first spend millions in the development stage. “So in this sense, [the incentives are] pretty important,” he says.
PHOTO: JOHN ASPDEN
WHAT COUNTS AS PARTIAL UPGRADING? In most discussions, the timeline for commercialization of partial upgrading technology is anywhere from 10 to 15 years.
Q 2 2 0 1 6 • J W N E N E R G Y. C O M • 3 9
PA R T I A L U P G R A D I N G
In addition to the Alberta government’s $300 million of incentives for partial upgrading, AI-EES also has a collaborative federal/provincial/industry National Partial Upgrading Program to accelerate technical and economic innovation in partial upgrading. Six unnamed oilsands producers make up the industry component.
1 2 3 4 5 6
Government funding for the program:
Muse Stancil forecasts two cases for partially upgraded bitumen market penetration: The high case:
1.26 million bbls/d by 2035
The moderate case:
$1.6 MILLION
per year for the first three years
$3.2 MILLION
as worthy projects are identified
When asked why nobody talks about Imperial Oil’s paraffinic froth
633,000 bbls/d by 2035
dle PUBs. European and Gulf Coast high-conversion and heavy-cok-
treatment at Kearl as an example of commercial partial upgrading
ing refiners, for example, could readily accept medium quality PUBs.
that’s already in use, Duke du Plessis, senior adviser, energy technol-
Slightly higher quality PUBs, however, could find considerable
ogies with Alberta Innovates – Energy and Environment Solutions
uptake in medium conversion and coking refineries in China as well
(AI-EES), explains that it doesn’t fully measure up to the criteria set
as in the U.S. Gulf Coast and Upper Midwest.
out by AI-EES for partial upgrading because it still requires diluent and it doesn’t increase the value of the bitumen. The objective of partial upgrading is twofold. “You aim at reducing
All this is good to know but somewhat academic until pipelines connect Alberta to tidewater. So last year, AI-EES commissioned a study of the potential of PUBs in nine Eastern Canadian and Sas-
or eliminating diluent. The second thing is you improve the quality
katchewan refineries. Those results are still pending but, as with
and market value of that crude. So if you get something like the deas-
other refining regions, PUBs could improve the economics and com-
phalted product in paraffinic deasphalting, it still has properties that
petitiveness of Alberta’s oilsands producers.
aren’t valued by the client.”
“The gross netback of partially upgraded products is substantial,” du Plessis says. “We found that the netbacks were tied more to the
MARKETS FOR PARTIALLY UPGRADED BITUMEN
light-heavy differential and were less sensitive to the absolute value of
As the research arm of the Alberta government, AI-EES started look-
the crude oil [pricing].... The value uplift derives almost 50/50 from the
ing at full upgrading in 2004. When its research showed that more
reduction of diluent and the added value of the bitumen component.”
upgraders weren’t likely to be built in western Canada, it turned its
Achieving the best economics, according to AI-EES, will require
attention to partial upgrading and, in 2012, published a competitive-
striking the right balance between oil quality—on a spectrum that
ness study that models the potential of partially upgraded bitumen
starts with relatively low-cost solvent deasphalting and moves
crudes (PUBs) in the PADD II U.S. refining market—where most
through to hydrotreating and hydrocracking—and minimal capital
Canadian oil ends up.
investment needed for this conversion.
In 2015, AI-EES commissioned a Muse Stancil study of six global
“If you go past that peak, you’re spending money on a plant that
refining regions—Japan, India, China, Europe, Korea and the U.S. Gulf
you’re not getting value from,” du Plessis says. “How much capital
Coast—that shows these regions vary widely in their abilities to han-
a company can afford to invest to realize an increased netback will
40 • Q2 2016 • OILSANDS REVIEW
PA R T I A L U P G R A D I N G
be a function of a producer’s capex intensity and its internal rates of return.”
TECHNOLOGIES THAT TAKE BITUMEN TO END PRODUCTS If Imperial Oil’s deasphalting process is at one end of the spectrum that doesn’t quite reach into the “partial upgrading” category, there are also number of proponents that overshoot the category on the other end. These include Value Creation, Field Upgrading and Bayshore Petroleum. All of these are now aiming at refined end products. Bayshore has teamed up with E-T Energy to deploy Bayshore’s chemical catalytic conversion technology for in situ bitumen extraction at E-T’s Poplar Creek oilsands property. Bayshore, however, also claims its catalyst technology can convert bitumen straight to diesel—and at an astonishingly low cost of $8,000 per flowing barrel, compared to an estimated $160,000 per flowing barrel at the Sturgeon Refinery Project being built by the North West Redwater Partnership. Value Creation initially said it wanted to produce a “cleaned” sour synthetic crude that is more easily refined but has since moved up the ladder to a “clean oil refinery [model] that can produce—most cost effectively—very high quality light fuel products as well as premium medium crudes that not only fit the majority of refineries in North America, and eventually globally, but also enhance their refinery margins,” says Columba Yeung, chair and chief executive officer of Value Creation. Another company lumped in as a partial upgrader is Field Upgrading. Its technology is a step out from the usual deasphalting and thermal cracking approaches. It uses molten sodium to upgrade
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PARTIAL UPGRADING SYSTEMS MEG Energy’s HI-Q process, Ivanhoe Energy’s HTL technology (the company is now bankrupt), ETX Systems’ IYQ process, and the
Q 2 2 0 1 6 • J W N E N E R G Y. C O M • 4 1
PA R T I A L U P G R A D I N G
“The technology that will prevail is going to be the one that is
USEFUL AT THE LOWEST ENERGY INTENSITY/CARBON FOOTPRINT.... There isn’t one answer here but multiple answers.” — GERALD BRUCE, president of GWB Process Consulting
approaches of Fractal Systems and Petrosonic Energy are some of
50 per cent by heating diluted bitumen just below thermal cracking
the partial upgrading approaches vying for commerciality
temperatures and pumping it through proprietary jet-nozzles where
in Alberta.
cavitation and mechanical shearing occurs. The company says that
ETX Systems’ technology is an example of “almost the highest quality [PUB],” says chief executive officer Gerard Monaghan. “We believe that finding the most accretive mix is full coking of
between April 2014 and April 2015, it processed over 100,000 barrels of diluted bitumen, successfully proving the base technology. Fractal director Joe Gasca says the technology is primarily
the bottom of the barrel, but without the addition of any hydrogen.
focused on diluent reduction but the process also results in some
Refiners are much better positioned in terms of infrastructure and
partial upgrading. He says Fractal is working to get in front of Alberta
proximity to end markets to provide the hydrogen piece of the up-
government representatives to better understand the partial upgrad-
grading puzzle.”
ing incentive opportunity. Meanwhile, Gasca says the company is
Interestingly, Monaghan envisions a significant role for rail in the
nearing completion of a retrofit at its Provost facility and that for the
transport of PUBs because the olefins produced in partial upgrading
remainder of this year will pilot a new configuration called Enhanced
can make it difficult to meet pipeline specifications. He says that
JetShear. Also being piloted is their Acid Reduction Process, another
rail facilities could be repurposed to serve intermediate partially up-
technology system designed to specifically address high-TAN crudes.
graded bitumen. “With rail, you are naturally segregated, so I see that as a growing
Bruce believes the best partial upgrading options target wide-spectrum crude refineries, such as those found in Eastern Can-
and enabling potential for rail…[because] partially upgraded products
ada and the U.S. Midwest. This approach has the potential to strike
like ours have no flashpoint concerns and will float on water,” he
the right balance between crude quality improvement and minimal
says, referring to the tragedy at Lac-Mégantic, Que., and the concerns
investment, while avoiding competition with Bakken light oil for
over bitumen sinking in ocean and waterway spills.
refining capacity.
Monaghan says ETX’s technology has good traction with some
“The technology that will prevail is going to be the one that is
midstream partners and plans are being made for a 14,000-bbl/d
best suited to make products that are useful at the lowest energy
demonstration project.
intensity/carbon footprint,” Bruce says. “It’s a long-term process, but
“I’m cautiously optimistic that we will be able to access the funding we need to move forward in the next couple of months,” he adds. Fractal Systems has been piloting its JetShear technology in the
it’s strategic as well. You’ve got another 800,000 or 900,000 barrels of production coming on over the next two years. How you respond to this can be through partial upgrading, which gets you in the right
field since 2009, first with a 300 bbl/d facility near Consort, Alta.,
direction, but you might want to also consider conversion to finished
followed by a 1,000 bbl/d commercial scale demonstration near
products and putting those on rail cars to get to market. So there isn’t
Provost. It is designed to reduce diluent requirements as much as
one answer here but multiple answers.”
42 • Q2 2016 • OILSANDS REVIEW
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TECH_SERIES
THE
Throughout 2016, Oilsands Review is publishing a series of technology-centric stories. Watch for more in our September edition.
NEXT GENERATION OF OILSANDS
IMPROVING MINING WATER AND LAND USE THROUGH INTEGRATED, INNOVATIVE SYSTEMS
in oilsands tailings water treatment with the Natural Sciences and Engineering Research Council of Canada (NSERC). “We are working on [a] few treatment
CARTER HAYDU
processes I cannot disclose at this time, but basically we are looking at some combinations “Part of the reason for that is because the
of physical and chemical treatments together
mining sector of integrated water management
temperature in the reservoir with in situ is
to accelerate the treatments, and we are also
is when tailings water is disposed of through
much, much hotter. It is over 150 [degrees
looking at some biological and physical pro-
reuse as the supply for steam generation to
Celsius]; you are solubilizing some of the silica
cesses together to make the treatments more
produce bitumen at an in situ facility, says Kim
in the reservoir; it comes up through the water,
cost effective and less greenhousegas (GHG)
Westcott, senior surface water policy specialist
and that presents some interesting treatment
intensive.”
with Alberta Environment and Parks.
challenges when you go to make more steam.”
“We believe that there is opportunity for
For mining, operators are really only using
GETTING READY FOR TMF Last year, the Government of Alberta released
future integration and future improvements of
water when mixing it-at around 56 degrees
water use intensity,” she told the 2016 COSIA
Celsius-with the ore, he notes. “As a result you
its Tailings Management Framework for
AI-EES Water Conference. As technologies ac-
don’t solubilize any silica, but there are a whole
Minable Athabasca Oilsands, which focuses on
celerate tailings treatment in accordance with
bunch of other challenges with mining trying to
getting tailings ponds remediated faster and
the province’s new tailings management frame-
separate the bitumen from the water and clay.”
slowing tailings pond growth. Westcott told
work (TMF), Westcott adds, government and in-
While there currently are no regulations for
the water conference the province’s frame-
dustry must explore management solutions for
oilsands tailings release in the province, re-
work recognizes future water use integration
optimizing outcomes and reducing liabilities
search at the University of Alberta will help in
may in some instances compromise environ-
associated with process-affected waters.
the eventual development of such regulations.
mental outcomes, in which cases the release
Although substantial in either case, the wat-
“Regulations are based on [the] best
of treated tailings water could be an option. “The environmental risk assessment will
er challenges that innovation must tackle differ
available technologies and also making sure
significantly depending on whether for in situ
the treated water when released is going to
be comprehensive. We will require that all pro-
or mining, says John Brogly, water director at
be safe for the environment,” says Mohamed
ponents look at the net effects associated with
Canada’s Oil Sands Innovation Alliance (COSIA).
Gamal El-Din, senior industrial research chair
reusing, recycling and releasing, and in cases
44 • Q2 2016 • OILSANDS REVIEW
PHOTO: JOE Y PODLUBNY
Probably the best example in the oilsands
TECH_SERIES_WATER
TAILINGS TECHNOLOGIES where the net effects of reusing or recycling
plans would also report out on water manage-
the work it is doing and how to proceed with
that stream are greater than releasing, then we
ment performance and provide water demand
TMF implementation. Westcott says: “We will
will consider release to the environment.”
and water use and water supply forecasts.”
continue to work closely with the AER and
Westcott adds: “These applications will be
The second project involves developing the
Water Management Working Group for the
subjected to the existing and supplemental
regulatory process for managing new waste-
rest of this year, and our intent is to develop
requirements that we are in the process of de-
water releases, which connects directly to the
a prioritized project plan for this initiative by
veloping to essentially perform a sitespecific
TMF. “This project also includes developing
the end of this year.”
environmental risk assessment to determine
those supplementary requirements that are
and minimize the impacts of this release on
intended to support existing processes.”
the aquatic environment and on human uses.”
The third project essentially reviews what
She adds: “We know that the oilsands mining sector is growing, and consequentially production is increasing. Therefore, more
CEP initiatives are already happening in
water may need to be brought on site for
mine-site water be managed as part of an
Alberta in order to determine whether those
extraction purposes. Again, it looks like the
integrated system to minimize environmental
initiatives are sufficient to meet the province’s
water footprint will increase.”
impacts, that water conservation efficiency
objectives. The fourth project concerns water
and productivity (CEP) improve throughout
release regional management, which Westcott
all phases of mining, and that excess water
says involves developing a regional waste-load
inventories are reduced and on-site water
allocation for the Athabasca River to deter-
The key to effective and affordable tailings
quality improves through all mining and rec-
mine the best substance release strategy.
treatment involves a blend of methods
Initiative outcomes include that oilsands
lamation phases. The fourth outcome relates
“Most of the core projects are currently in a
TAILORING THE RIGHT TREATMENT PROCESS
tailored for the specific, problematic oil
to ambient water quantity and quality for the
scoping phase. We have started some work in
sands process-affected waters (OSPWs), says
regional ecosystems.
a few of the key areas. We are working closely
NSERC’s Gamal El-Din.
“We have developed several core projects to
with the Alberta Energy Regulator (AER) to
“You need to use a combination of differ-
support these outcomes,” Westcott says. The first
finalize the project roles and responsibilities.
ent treatment processes, because you cannot
project enhances water management planning
All of the four projects will either have an
just go for the ones that are going to be super
performance systems. “Essentially, this project
Environment and Parks lead or an [AER] lead.”
expensive—they are going to require a lot of
is about developing a process in which oilsands
In January, the ministry launched a
energy and are associated with [GHG] emis
mining operators would develop integrated water
multi-stakeholder technical working group to
sions. Therefore, we have to look at the whole
management plans on a regular basis, and these
provide the province with technical advice on
thing from a holistic viewpoint. Q 2 2 0 1 6 • J W N E N E R G Y. C O M • 4 5
TECH_SERIES_WATER
Up and running: Tailings technology enhancements start delivering results In the past, Suncor Energy’s solution to managing its increasing volumes of mined oilsands tailings was to just build more tailings ponds. That was before the company implemented Tailings Reduction Operations (TRO) technology, says Mark Little, Suncor’s executive vice-president, upstream. “It is really about accelerating the pace at which we can recycle the water,” he told the company’s recent annual general meeting. “The huge advantage of that is that we can shrink our footprint and not have nearly as many tailings ponds, and so we stopped building tailings ponds.” Suncor began piloting TRO in 2008 and received regulatory approval to deploy it commercially across its operations in 2010. The process involves the mixture of mature fine tailings with a polymer flocculent, which is then deposited in thin layers over shallow-slope sandbanks, resulting in a dry material suitable for reclamation purposes. Drying occurs
over a shorter time frame (weeks versus centuries, Suncor has said), allowing for faster reclamation. “Now we have started putting the sand right back into the pit, and managing the water recycling and such on a faster basis. This is all about reducing the footprint of technology.” According to Little, TRO is enabling Suncor to update its tailings plans, reducing risk and exposure, driving down water volumes used and increasing recycling. “There has been enormous progress in tailings, but now we still have to reclaim our ponds that we have had historically. We do have a number of ponds that we are working on, and we are in varying degrees of capping those off and getting them ready for reclamation.” Syncrude has also taken big steps on the tailings management front in recent years, including working with Newalta to integrate centrifuge technology. Last year, Syncrude completed construction
“Different scenarios of treatment will be
of a $1.9-billion commercial-scale tailings centrifuge plant, which includes 18 centrifuges measuring nine metres long by two metres high. These spin out the water from fluid fine tailings (FFTs). Heavy haulers then move the resulting “cake”—which is a mud-like substance—to areas in Syncrude’s north mine, where after a freeze-thaw cycle it is considered solid enough to be trafficable. “This is something that we are actually going to be using to start reclaiming. These FFTs treated by centrifuge are what we are using to fill back our north mine,” Gibson says. “After one year, it will become strong enough to support reclamation material and landscapes, whether we are putting grass or trees up in forests, or wetlands over top of them.” Canadian Natural Resources implemented non-segregating tailings (NST) production in 2015 at its Horizon project using cyclones, thickeners and CO2 addition. Management expects NST production to increase the capture of fines, resulting in a smaller tailings footprint and shorter reclamation time frame. According to public affairs adviser Julie Woo, Canadian Natural has been adding CO2 to tailings since 2009 to enhance the solids settling rate and
According to Gamal El-Din, notable
reduce the size of tailing ponds by about half, sequestering carbon in the process. To monitor NST effectiveness and to continually enhance tailings performance, the company created the Applied Process Innovation Centre (APIC) in 2015, a research facility built at Horizon. APIC facilitates collaboration on research projects with industry, academia and government, Woo notes. Currently, work at the facility is focused on tailings management, but Canada’s Oil Sands Innovation Alliance says it could be expanded to other process enhancements in the future. Shell Canada’s new tailings technology is called Atmospheric Fines Drying (AFD), which is also designed to speed tailings treatment and create a dry material that allows for faster reclamation. Shell started commercial-scale operations of an AFD plant at its Muskeg River Mine in 2010, but could not be reached to provide a status update on the technology for this story. At Kearl, the industry’s newest mining operation, tailings reclamation is in its early stages. Kearl produced its first oil in 2013, and according to its tailings management plan filed with the Alberta Energy Regulator, fines capture will start in 2018 using a thin lift drying system.
He adds: “Different absorbents have
dictated by the different requirements for
processes include advanced oxidation. While
been used, ranging from petroleum coke all
treatment, the impact on the environment,
ozone treatment is quite fast and efficient,
the way to other very highly active or very
the available footprint, the timescale people
it is costly compared to biological treatment
highly efficient absorbents. Every scen-
are looking at achieving their reclamation,
methods. Biological treatments are slower
ario is different, and every treatment is
and so forth.”
and require a larger environmental footprint.
different—cost-wise, in terms of the capital
The U of A environmental engineering
Some methods, such as using bioreactors,
cost, operationally, maintenance-wise, and
professor’s 35-person laboratory crew studies
have the potential of a smaller physical foot-
so on.”
a variety of tailings treatment process op-
print as well as reduced water impacts.
portunities, which could be scaled up to an
Other treatments use biologically active
Gamal El-Din’s research chair is funded by oilsands producers, water treatment
applied research phase using the application
filters to treat the OSPW under gravity, work
providers, and the provincial and federal
of various processes and technologies.
ing as a physical and biological combination
governments. Prior to his current oilsands
He says: “If it proves efficient, then it is
treatment, which definitely implies a larger
tailings work, he conducted municipal
up to oilsands companies as to whether they
environmental footprint, says Gamal El-Din.
water and wastewater research. He says
will use it or not. My role is to come up with
“We have other approaches such as
as many solutions as possible for different
absorption methods, where purely phys-
potential shared research benefits between
scenarios of treatment and different types
ical absorption or treatment processes can
the two sectors.
of water that need to be treated. It then
use some absorbing material to remove the
becomes available for solutions with…future
organic matter from the OSPW. It seems to be
water we can use in other areas, such as
reclamation and treatment.”
efficient as well.”
municipal applications.”
46 • Q2 2016 • OILSANDS REVIEW
there is a fair amount of crossover and
“Some of the work we do for the process
TECH_SERIES_WATER
OILSANDS RESEARCHERS TACKLE TECHNOLOGY TO ADDRESS THE COSTS OF MANAGING THEIR MOST VALUABLE LIFELINE
consumption in oilsands operations will also have an impact on a project’s GHG intensity. The push for better environmental practices continues through difficult economic times for the industry, he suggests, because reducing GHG
CARTER HAYDU
intensity and water use on site will positively As in situ oilsands producers aim to reduce
modern user interface to define process
emissions and improve water treatment effi
models, provide input parameters and vis-
ciency, the issue is not so much a shortage of
ualize results. The software quickly evalu-
is that collaboration and innovation is just
technology as it is the need for an integrated
ates technologies, using a reduced amount
as—if not more—important now than it was
approach to understanding the nexus between
of simulation to identify the most promis-
in a higher price environment. But the strong,
GHG emissions, water and operating costs.
ing options.
strong caveat is that this price environment is
That’s the view of Maryam Mahmoudkhani,
the tool’s integrated, holistic approach and
tems at ConocoPhillips Canada.
methodology has been contributed for sharing
“We need to have the tools in terms of a good approach for combining analysis for both water and greenhouse gas emissions PHOTO: CENOVUS
While specifically developed for Surmont,
GHG emissions technical lead in SAGD sys
between the members of Canada’s Oil Sands Innovation Alliance (COSIA). “Because all the thinking around it and
impact the bottom line for oilsands companies. “I would say that all the evidence to date
extremely challenging for these companies.” A SAGD SOLUTION THROUGH HYBRID MEMBRANES In SAGD, water reclamation and reuse is vital to operations, with about 60–70 per
reductions—both are tightly incorporated in
developing the framework is already there, I
cent of total operation costs related to steam
operating costs,” Mahmoudkhani says.
would assume [making it a generic tool] would
generation, according to Mohtada Sadrza-
not be very much work,” she says.
deh, assistant professor in the University of
At ConocoPhillips’ Surmont SAGD project, for example, she says custom software with
For COSIA chief executive Dan Wicklum,
in-house algorithms provides a fully flexible,
almost any solution proposed to decrease water
Alberta’s (U of A’s) department of mechanical engineering. Q 2 2 0 1 6 • J W N E N E R G Y. C O M • 4 7
TECH_SERIES_WATER
“You can see that water limits the growth of the oilsands industry, and this is indeed the lifeline…. The solution to this [cost] problem is to have continuous improvement of the water treatment process.” He adds, “We at the advanced water re search lab at the U of A are working on membranes to decrease the costs of the current water treatment scheme.” Under the current process, bitumen is first recovered from produced water. After separation of trace amounts of oil and gas hydrocarbons, the de-oiled produced water mixes with make-up water and recycled boiler blowdown. It is sent to the conventional water treatment scheme that includes warm-lime softener to remove silica and ion exchangers to removed divalent ions. Finally, the so-called “boiler feedwater” returns to
for water treatment. The technology, which
contemporary polymeric membranes cannot
the steam generator.
was collaboratively piloted by five oilsands
resist temperatures above 45 degrees Celsius
producers, is expected to reduce water use and
for long-term operations.
od is it does not provide any treatment for the dissolved organic matter, and the salt concen-
GHGs while improving plant reliability. Researchers at the U of A are now working
Therefore, U of A researchers are developing mixed-matrix membranes, adding
tration even increases during the process,”
to infuse the thermal stability of inorganic
nanoparticles to polymeric membranes to
Sadrzadeh says. “In addition, only 90 per cent
membranes with the separation ability, large
increase thermal tolerance while maintaining
of the dissolved silica is removed. The organic
surface area and affordable price of organic
high separation performance. The synthesis
matter and the [remaining] silica causes
ones—the best of both worlds.
of robust and defect-free hybrid membranes
fouling of the steam generator, and it increases operation costs.” Membrane technology is expected to offer step-changes in water treatment. “If you use our membrane process after conventional techniques, we can remove almost
“The main concept is to actually incorporate functional nanoparticles into the polymer membranes in order to increase the thermal
is still in the laboratory phase of development, notes Sadrzadeh. “We are hopeful that in the next stage of
stability and also improve the anti-fouling
continuing that work we are moving toward
properties,” says Sadrzadeh.
the larger scale,” he says, adding this technol-
Inorganic ceramic, metallic and zeolite
ogy should reach a piloting phase within the
all the silica, divalent ions and organic matter,”
membranes might be better at handling the
next three years. If piloting goes well, then
Sadrzadeh says. “So we are just increasing the
high temperatures at which SAGD process-
these hybrid membranes could reach commer-
lifetime of the steam generator tubes and im-
affected water arrives to the treatment stage,
cial scale within five years.
proving the plant’s operating performance.”
but they are also unable to deal with irrevers-
Membrane technology could theoretically
Heat exchangers must reduce water tem
ible fouling and must be changed regularly,
perature prior to membrane treatment, after
go one step further and replace the conven-
he notes, and they are expensive, too. These
which the water is reheated into steam, which
tional technique altogether. However, SAGD
are important considerations for oilsands
he notes is a costly step.
produced water has high concentrations of
producers, as they are particularly sensitive to
salt. Organic matter poses a fouling risk and
operating and capital costs.
produced water’s high temperature is incom-
On the organic side, polymeric membranes
“From the viewpoint of energy saving, in order to improve heat integration in SAGD plants, it is better to operate at higher
patible with the long-term use of a typical
are cheaper than their inorganic counter-
temperatures. Because of that, we are actually
polymeric membrane, according to Sadrzadeh.
parts. Due to their high flexibility, they can
going to make high temperature–resistant
be modularized to maximize surface area. In
polymeric membranes to reduce boiler feed-
last year, it became the first SAGD project to
addition, they can provide higher contami-
water heating requirements and greenhouse
incorporate ceramic (inorganic) membranes
nant rejection. Unfortunately, Sadrzadeh says,
gas production.”
When Surmont Phase 2 started operations
48 • Q2 2016 • OILSANDS REVIEW
PHOTO: CENOVUS
“The problem with the conventional meth-
TECH_SERIES_WATER
Important WTDC fixed equipment will include its test separator, which will work in conjunction with bringing in process streams from the emulsion header and allow for chemical testing, level interface testing and diluent optimization work. A flotation cell will bring in oily produced water for chemical optimization trials. Perdicakis notes the test produced-water cooler will enable analysis of fouling mitigation and chemical treatment strategies, cleaning protocols, and different coatings— all aimed at either extending the runtime of produced-water coolers, or minimizing produced-water cooler cleaning costs. A test OTSG will handle about 3.4 cubic metres per hour of boiler feedwater. “It is meant to look at pushing the limits COSIA PARTNERS REMAIN COMMITTED
the WTDC is similar to undergoing a turn-
of what once-through steam generators are
TO DELAYED WATER TECHNOLOGY
around every year.”
capable of, looking at 90 per cent steam qual-
Along with capital and operating costs,
ity trials, looking at proved ways of measur-
When COSIA’s Water Technology Development
project participants equally own and share all
ing steam quality and really exploring what
Centre (WTDC) reaches full swing in 2019,
WTDC results, data and intellectual property,
are the technical operating envelope limits of
companies will be able to simultaneously pilot
says Perdicakis. A combination of Suncor
the OTSG.”
test a plethora of new technologies. Until then,
staff, secondi from the other participating
industry participants continue collaborating
producers and technology suppliers will con-
water, oily produced water, boiler feedwater
on development activities and the search for
duct WTDCrelated tests. He told the recent
and analyzers. Crews will be able to artifi
new ways to lower overall project expenses.
water conference: “All the participants re-
cially increase flow rates with a recirculation
mained committed to completing the project
pump. Further, according to Perdicakis, an
operations in 2017, but it has been delayed due
and collaborating on the subsequent annual
outdoor evaporator pad area will allow for
to challenging market conditions.
test plans.”
testing oversized equipment—evaporation
DEVELOPMENT CENTRE
The project was initially expected to start
The initial construction phase will cost
Potential WTDC benefits include constant
An instrument test loop will test produced
technologies, alternative steam generation
$165 million, says Basil Perdicakis, senior
access to live, realtime process fluids, which
technologies and anything else that cannot
research engineer and WTDC lead, oilsands
proponents believe is necessary to truly test
fit in the main building.
technical and upstream services with Suncor
new technologies’ performance. The WTDC
“We have done a lot of excellent work
Energy. Located at the company’s Firebag
is designed to also provide space, resources,
over the past year in developing a rigorous
SAGD project, Suncor will own and operate the
infrastructure, utilities and associated ex-
method to rank and prioritize the technol-
facility with five COSIA partners: Canadian
pertise required to meet associated oilsands
ogies that we plan to test at the WTDC,” he
Natural Resources, Devon Canada, Husky
innovations’ pilot-testing objectives.
says. “I think people can appreciate that this
Energy, Nexen and Shell Canada. “The WTDC participants are committed
The facility will accommodate five to eight
is a challenge to accomplish within one com-
medium sized pilots at a capacity of roughly
pany. Trying to get six companies to land on
to a fiveyear test program, and the intent
2.3 cubic metres per hour or one large pilot
how this was done was an interesting chal-
is that every year a set of pilots—whether
with a 23-cubic-metre-per-hour capacity. The
lenge, but one that we have worked through
the five to eight medium sized pilots or one
facility will import almost any processed fluid
this past year.”
large pilot—[is] commissioned, operated and
from the beginning of the central processing
decommissioned, and then the next-year set
facility through to the outlet—everything
this area, and it will really enable us to pri-
of pilots comes into the facility, and then that
from emulsion feeding the plant to the once-
oritize the technologies that we want to test
process keeps repeating itself. Operation of
through steam generator (OTSG) blowdown.
going forward.”
He adds: “We have made great strides in
Q 2 2 0 1 6 • J W N E N E R G Y. C O M • 4 9
TECH_SERIES_WATER
A NEW COMBUSTION TECHNOLOGY MAY BE ABLE TO RETROFIT OILSANDS STEAM GENERATORS TO LOW EMISSIONS AT A LOW COST DEBORAH JAREMKO
A Seattle-based combustion company says it has signed a deal with a large oilsands producer to design and engineer its technology for potential retrofit at 40 oncethrough steam generators (OTSGs). ClearSign Combustion Corporation chief executive officer Stephen Pirnat says the tech nology, called Duplex, can lower greenhouse gas (GHG) emissions at a nonprohibitive cost. “We’ve now determined that the paradigm that you have to pay a significant economic penalty for having clean air is really not true anymore,” Pirnat tells Oilsands Review. He says that Duplex technology allows people in the enhanced oil recovery market to get sub5 ppm NOX low CO and retrofit exist ing low-NOX burner technology at a fraction of the cost of, for example, selected catalytic reduction systems. “The industry themselves and this particular client in western Canada is very excited about the fact that they can meet their forward-leaning approach to environmental stewardship [and] do it at a cost that is reasonable for their shareholders.” Pirnat was not at liberty to disclose the name of the producer, but indicated that there are fewer than five companies operating OTSGs in western Canada with a fleet this sig is validated, the two companies will jointly release a statement. “What’s really good for us is that the operators in western Canada are significant, 50 • Q2 2016 • OILSANDS REVIEW
PHOTO: CENOVUS
nificant. He expects that after the technology
TECH_SERIES_WATER
well-funded, sophisticated companies, and we see a relationship with one of those companies as an opportunity to convert a large number of once-through steam generators in western Canada. We think the number of additional once-through steam generators in western Canada is several hundred, and that would give us an opportunity to really impact that entire market.” In the ClearSign system, fuel and air are mixed pre-combustion and then combusted in a Duplex tile. “A Duplex tile has a series of very small channels in it that allow the combustion to take place in a very precise way,” Pirnat says. “That combustion in those small channels allows better mixing and better heat transfer, and reduces the formation of NOX and CO and CO2. It has produced results that are phenomenal….
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Canada’s Oil Sands Innovation Alliance has an active challenge out to external stakeholders and solutions providers to create a new highefficiency boiler for thermal operations. Pirnat says there is a “high probability of that
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» Liebherr LHM 320 mobile harbour crane
measure the proved economic performance— meaning efficiency and fuel savings—associated with our technology. They are going to try to
» Direct rail access by CN and CP to/from Western Canada
replicate and capture the savings [of] the more efficient heat transfer,” he says. “Even though this market is somewhat
» Minimize handling, time and cost
depressed, we’ve also had discussions with manufacturers of once-through steam generators who, in simple terms, are saying, ‘well, if we can take advantage of this unique heat transfer, we could make the radiant section
Thunder Bay Port Authority T: (807) 345-6400 E: tbport@tbaytel.net W: portofthunderbay.ca
» Extensive staging area and storage
bigger and the convective section smaller, and we could make more efficient, smaller and less costly once-through steam generators.’” Q 2 2 0 1 6 • J W N E N E R G Y. C O M • 5 1
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OILSANDS DATA O P E R AT I O N S BY T H E N U M B E R S
Alberta crude bitumen and synthetic crude production Crude bitumen 50,000
Bitumen royalty valuation at Hardisty, Alta.
JANUARY TOTALS
Synthetic crude
Calculated using NetThruPut monthly WCS index
2014 2015
$60
2015 2016
45,000
$50
40,000 40,638,300 BBLS or 54.4%
35,000
$40
34,058,300 BBLS or 45.6% 74,696,600 BBLS total
30,000
US$/bbl
Thousand bbls
2015 2016
2015
25,000
$30
20,000 $20
2016
15,000 10,000
$16.37
$10 46,428,700 BBLS or 58.7%
5,000
32,704,300 BBLS or 41.3%
0
$0
79,133,000 BBLS total D
J
F
M
A
M
J
J
A
S
O
N
D
J
A
Natural Gas: Spot prices at AECO trading hub in Alberta
J
J
A
S
O
N
D
Hot rolled coil
Structural sections and beams
$900
2015 2016
$3.00
F
M
Reinforcing bar 2015 2016
$800
US$/tonne
$2.50
C$/GJ
J
North American carbon steel prices
Monthly averages to Apr. 18, 2016 $3.50
M
$2.00 $1.50
$674
$700
$600
$514
$1.00
$1.02
$500
$0.50
$497
$0
$400
MAY
JUN
JUL
AUG
SEP
OCT
NOV
DEC
JAN
FEB
MAR
APR
APR
MAY
JUN
JUL
AUG
SEP
OCT
NOV
DEC
JAN
FEB
MAR
Mined oilsands bitumen production Current 3 month avg. (October 2015-December 2015)
Previous 3 month avg. (July 2015-September 2015)
BIGGEST MOVER Syncrude Canada - Aurora North & South
Suncor Energy Inc. - Base operations Imperial Oil - Kearl
-29,965 (From 221,831 to 191,866)
Syncrude Canada - Aurora North & South Canadian Natural Resources Limited - Horizon
TOTAL MINING AVERAGE
Shell Canada - Muskeg River
Current three months
Previous three months
Syncrude Canada - Mildred Lake 1,230,872.0
Shell Canada - Jackpine 0
50,000
100,000
150,000
200,000
250,000
300,000
1,274,373.0
350,000
Production (bbls/d)
Q 2 2 0 1 6 • J W N E N E R G Y. C O M • 5 3
Alberta synthetic crude oil production
BIGGEST MOVER
Current 3 month avg. (October 2015-December 2015)
Previous 3 month avg. (July 2015-September 2015)
Shell Albian Sands Scotford Upgrader
Suncor Energy Inc. - Base operations
-25,691 (From 286,918 to 216,227)
Shell Albian Sands - Scotford Upgrader TOTAL MINING AVERAGE
Syncrude Canada Ltd. - Mildred Lake
Current three months
Canadian Natural Resources Limited - Horizon
977,595.0
CNOOC Limited - Long Lake 0
50,000
100,000
150,000
200,000
250,000
300,000
Previous three months
1,019,530.0
350,000
Production (bbls/d)
Top 10 thermal oilsands projects bitumen production Current 2* month avg. (January 2016-February 2016)
Previous 3 month avg. (October 2015-December 2015)
BIGGEST MOVERS ConocoPhillips Canada Limited Surmont
Suncor Energy Inc. - Firebag Imperial Oil Limited - Cold Lake
Canadian Natural Resources Limited Primrose & Wolf Lake
Cenovus Energy Inc. - Christina Lake Cenovus Energy Inc. - Foster Creek Devon Canada Corporation - Jackfish
Imperial Oil Limited Cold Lake
Canadian Natural Resources Limited - Primrose & Wolf Lake MEG Energy Corporation - Christina Lake
16,133.27
from 34,869.2 to 51,002.5
-12,475.08
from 100,137.1 to 87,662.05
10,683.8
from 154,865.9 to 165,549.7
TOTAL MINING AVERAGE
ConocoPhillips Canada Limited - Surmont
Current three months
Previous three months
Suncor Energy Inc. - Mackay River 1,028,575.95
Canadian Natural Resources Limited - Kirby South 0
50,000
100,000
*Data for March 2016 not available at press time
150,000
1,017,149.20
200,000
Production (bbls/d)
Lowest 10 thermal project steam to oil ratios Current 2* month avg. (January 2016-February 2016)
Previous 3 month avg. (October 2015-December 2015)
BIGGEST MOVERS
Cenovus Energy Inc. - Christina Lake
Andora Energy Corporation Sawn Lake
Andora Energy Corporation - Sawn Lake Pengrowth Energy Corporation - Lindbergh Pilot
Cenovus Energy Inc. Foster Creek
MEG Energy Corporation - Christina Lake
Pengrowth Energy Corporation Lindbergh Pilot
Devon Canada Corporation - Jackfish Canadian Natural Resources Limited - Kirby South Suncor Energy Inc. - Firebag
-2.35
from 4.49 to 2.21
0.22
from 2.79 to 3.01
0.2
from 2.08 to 2.2.8
TOP TEN AVERAGE
BlackPearl Resources Inc. - Blackrod
Current three months
Previous three months
Suncor Energy Inc. - MacKay River 1,234,567
Cenovus Energy Inc. - Foster Creek 0
*Data for March 2016 not available at press time
54 • Q2 2016 • OILSANDS REVIEW
0.5
1.0
1.5
2.0
2.5
3.0
Steam injected:oil produced
3.5
4.0
4.5
5.0
1,234,567
O I L S A N D S DATA
FirstEnergy oilsands, integrated and large cap indexes Oilsands
Integrated
Large cap
CHANGE SINCE APR. 21, 2015
Recorded until Apr. 21, 2016
120
INTEGRATED
19.72 11.44 13.91
2015 2016
100
$77.24 80
LARGE CAP
60
$77.90
40
OILSANDS 20
$19.58 0 MAR
APR
MAY
JUN
JUL
AUG
SEP
OCT
NOV
DEC
JAN
FEB
MAR
APR
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
$13.80 15
15
10
10
5
5
APRIL 2016 $14.36
20
20
APRIL 2015 $10.41
25
2015 2016
MARCH 2016 $12.24
25
MARCH 2015 $13.49
Differential: West Texas Intermediate to Western Canadian Select (US$/bbl)
Recorded until Apr. 21, 2016
0
0 MAR
APR
MAY
JUN
JUL
AUG
SEP
OCT
NOV
FIRSTENERGY CAPITAL OILSANDS MARKETS UPDATE Is it possible for crude oil price differentials to actually become boring? Although the topic can be dry at times, the data itself is often a source of great stress and hand-wringing, especially for heavy crude oil producers. Volatility and seemingly random moves have often characterized this particular pricing component since the early 2000s. That behaviour finally seems to be going away, which is consistent with the kind of price stability that we have been preaching since early 2015. Since September 2015, the light-heavy crude oil price spread has been well contained in a range from US$10/bbl to US$20/bbl, and recent months have seen this spread
hold even tighter between US$10/ bbl and US$15/bbl. Far from being an aberration, we think this is the new normal for the industry, and it could very well persist in the current price range with low volatility for the next several years. The reasons for this tighter price range and lower volatility are now becoming better known and, as we have stated many times before, are related to the abundance of capacity to move crude oil to market by pipeline and rail. That second part of capacity, rail, has been vitally important in helping to cap the price spread as the approximate marginal cost of moving crude oil by rail from Alberta to many destinations in the U.S. will
DEC
JAN
FEB
MAR
APR
MAR
rarely exceed US$15/bbl. We won’t belabour this point here, but suffice to say that rail transportation costs are acting as a rough ceiling on the price spread and should remain that way until much tighter capacity conditions arise later this decade, and perhaps not even before 2020. In the here and now, there has also been a substantial amount of field maintenance occurring, which has impacted between 150,000 and 300,000 bbls/d of heavy oil and bitumen production, further preventing too much supply from reaching market and keeping price differentials tight at a time of low seasonal refinery demand. As this maintenance period comes to a close, it will coincide with the seasonal uptick in U.S. refinery demand and should prevent any
APR
negative pressures from arising on the price spread. All of this is fairly self-explanatory, but what is vital to keep in mind is that with U.S. domestic supplies declining, the gates are opening further for Canadian crude to penetrate the U.S. market. This should bode well for Canadian heavy oil prices as refiners increase activity into the summer, demand for refined products looks to be increasing further, and Canada’s two main foreign competitors, Mexico and Venezuela, are facing production decline issues of their own. More stability, and perhaps even tighter differentials, should be on order for the balance of summer 2016. 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
Q 2 2 0 1 6 • J W N E N E R G Y. C O M • 5 5
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
A more environmentally responsible oilsands sector is a more competitive sector
The climate leadership plan breaks the logjam and for the first time, positions Alberta and the oilsands sector as constructive participants in this dialogue.
As the dust settles on Alberta’s game-changing climate announcement of 2015, it is worth remembering that not long ago it would have seemed unfathomable for Alberta to be getting recognition for phasing out coal, pricing carbon, limiting oilsands emissions and reducing fugitive methane emissions. Alberta was locked in an outdated way of thinking: that action on climate change was inconsistent with economic prosperity. By ignoring the climate concerns of our customers and our neighbours, Alberta was undermining the very industry it was seeking to promote. Now, through a change of political will and economic reality, we find ourselves discussing what needs to be done to ensure future prosperity and well-being. Industry leaders recognize a more prosperous economy and acting on climate change are two sides of the same coin. As high-cost producers in a low-price world that is becoming increasingly carbon constrained, the oilsands sector stands to benefit from policy signals that can drive innovation and reduce costs. The Government of Alberta’s climate leadership plan is comprehensive and covers a broad range of sectors: it will bend Alberta’s emissions curve while putting the province on a path toward a more resilient economy. It sends the right set of signals that
56 • Q2 2016 • OILSANDS REVIEW
can help Alberta advance toward a more responsible and competitive oilsands sector, improving the sector’s social licence, and it will create highskilled jobs right here in Alberta.
ALBERTA’S CLIMATE PLAN AND THE OILSANDS The Alberta climate plan includes three key elements for the oilsands sector: reducing emissions intensity to the level of best-performing facility, putting an economy-wide price on carbon and setting a sector-wide emissions limit. In developing regulations, the government needs a transparent process with effective stakeholder consultation resulting in optimal environmental and economic outcomes. Under the Specified Gas Emitters Regulation (SGER), each oilsands facility was required to improve its emissions intensity based on its historical emissions. So, while there are better performing operators, the higher-emitting facilities undermine the average intensity of the entire sector. The new approach will require facilities to improve their emissions to the level of the best performers or pay a price on carbon for any emissions over that benchmark. This means high-emitting facilities have a greater incentive to reduce emissions. Furthermore, the government can provide longer-term regulatory certainty by outlining the schedule
of emission intensity improvements that will be required over time. This vision can drive innovation and deployment of emissions reduction technologies. The plan also includes the application of a $30/tonne economy-wide price on carbon pollution. The previous government’s approach focused on industrial emissions sources while ignoring end-use emissions. Extending the coverage and setting a more effective price on carbon pollution allows for most cost-effective emissions reduction measures to be pursued. The onus is now on the federal government to extend the coverage of carbon pricing policy across the country, with an incrementally increasing schedule that can help Canada reach its climate goals. With Alberta’s climate plan, the province is one of North America’s leading jurisdictions and stands to benefit by being ahead of the regulatory curve. Finally, the government set a 100-megatonne (Mt) oilsands emissions limit that spares Alberta and Canada from a long-standing criticism of unmanaged oilsands growth. Current oilsands projects emit around 70 Mt per year. The limit allows current under-construction projects to proceed with some additional room for growth. If oil prices rebound to sufficient levels, approved but not yet under construction projects could
PHOTO: JOE Y PODLUBNY
SIMON DYER
TRANSITION
GREENHOUSE GAS EMISSIONS
(MT)
140
will reach their limit by 2025, and without further action exceed the limit by 10 Mt in 2030. To ensure there is room for the oilsands to grow over the longer term, the sector must innovate and reduce its emissions.
A CLIMATE PLAN DESIGNED TO BUILD A MORE RESILIENT SECTOR AND ECONOMY
120
100
80
60
40
20 OPERATING
+CONSTRUCTION
+APPROVED
IN SITU SURFACE MINES
ECCC greenhouse gas emissions estimate of oilsands extraction projects by stage of development based on average oilsands project intensities (excludes upgraders) as of February 2016.
quickly raise the sector’s emissions to over 130 Mt. Adjusting for the latest economic outlook, Environment and Climate Change Canada (ECCC) forecasts suggest oilsands emissions
One change the climate plan may instigate is a focus on ensuring the very best projects proceed. This will optimize benefits to Albertans and lower environmental impacts. Governments should ensure the best resources are developed by the most efficient projects and through the most efficient processes. Past policies focused on maximizing recovery of even some of the most marginal deposits, resulting in activity with a lower priority placed on optimal environmental or economic outcomes. Exponential growth of the oilsands sector resulted in escalating labour and capital costs, while the cumulative environmental impacts either exceeded thresholds—in the case of woodland caribou—or were put on track to exceed environmental limits. This exposed the sector to growing domestic and international criticism, shrunk profit margins hedged against long-term high oil price assumptions and passed on growing liabilities to taxpayers. While the climate plan does not address other non-climate issues, it does help to put the sector on the path to becoming more resilient and competitive. A principal outcome of the three pillars of the climate plan for oilsands is innovation. Nearly 90 per cent of oilsands emissions are from stationary combustion sources, the energy the sector burns in order to extract and process bitumen. By improving efficiencies and switching to low-carbon energy sources, the energy demand, operating costs and emissions intensities improve in tandem. This is a positive outcome for the environment and it also helps the oilsands sector become more cost competitive.
The provincial climate plan creates opportunities and can set Alberta on a path toward building a cutting-edge clean economy. To reduce oilsands emissions intensity, highly skilled jobs will be required not only in ongoing technology research and development, but also in the field deployment of such technologies. Alberta’s young and highly educated population is well positioned to take part in these opportunities, which will pave the path to the jobs of the future. The evidence of market acceptance of the climate plan is abundant. At the UN climate conference in Paris, instead of being targeted for derision and positioned on the sidelines, Alberta and Canada played a role in shaping a new agreement that can have a significant impact on protecting our environment. The temperature has been lowered on discussions surrounding the approval of pipelines. While it’s fair to say the level of opposition will not dissipate overnight and local issues remain, the conversation has changed. If the federal government can now demonstrate how it will build on Alberta’s commitments to develop a national plan to meet its emissions reduction obligations, all sectors of Canada’s economy will benefit from the certainty provided. There is still a lot of hard work to do on implementation of the climate plan and the regulatory details. How will the revenue from carbon pricing be returned to Albertans? How does Alberta’s plan fit with Canada’s need for a plan to reduce emissions? How will the 100 Mt limit be enforced or new projects considered? But this is the start of that journey. The climate leadership plan breaks a logjam and for the first time, positions Alberta and the oilsands sector as constructive participants in this dialogue.
Simon Dyer is the Alberta director of the Pembina Institute and former director of the Institute’s oilsands program.
Q 2 2 0 1 6 • J W N E N E R G Y. C O M • 5 7
2016 and beyond: What’s next for service and supply?
Download the complete report at reports.jwnenergy.com.
After five years of over-investment in the global oil and gas industry, supply
HERE’S WHAT THE REPORT OFFERS:
outstripped demand in late 2014, leading to an almost 50 per cent decline
• Insight into the challenges being faced
in 2015. The service and supply sector has been hit hard as operators try to bring costs in line with current prices. JWN and partner Grant Thornton conducted a detailed review of the oilfield service and supply market and an exhaustive survey of service and supply company leaders that concluded in mid-January. The study included over 545 survey responses, 100 workshop attendees and 38 interviews, capturing the most comprehensive data on the health of the service industry, both in western Canada and on a global scale.
by the sector in today’s lower-for-longer commodity price environment and what opportunities still exist
• Information on how the industry is responding to cuts in field activity and pricing, survival plans currently in place and how the industry is preparing for an uncertain future
• Industry forecast: What 2016 and beyond has in store for the sector
Trusted energy intelligence.
GUEST COLUMN INSIGHTS FOR A BETTER INDUSTRY
CHANGING THE WAY WE WORK Being competitive means the oilsands needs to move from “as good as” to “better than” CAL WATSON
Most companies are reaching the limit of what they can cut in terms of capital and activity without significantly undermining their medium-term viability.
The oilsands industry competes on a global scale for investment capital and must sell its product into a global market. Long term, there are a number of structural challenges facing the industry as compared with other global hydrocarbon investment options, particularly U.S. tight oil. These include lower product price, higher transport costs, high operating costs, higher royalties and more stringent environmental requirements. All of these long-term capital investment challenges exacerbate the current challenges of the low oil price. It’s not enough for our industry to become “as good as” producers in other jurisdictions. We must become “better than” to overcome structural challenges and compete
for investment capital against other global opportunities. The challenge for Alberta producers is to find a “no regrets” path that delivers real cash benefits to ride out the near-term price-induced threat while also changing the way companies work to enable product and investment competitiveness in the medium and long term, when dollars become available for future exploration and production (E&P) investment. So far, to deal with the near-term challenges, the focus of Alberta producers, as with the global E&P community, has been to drastically cut opex and capex by reducing staffing and activity levels. With a lower-for-longer industry outlook in 2016, many companies are now focusing on two challenges, one near term and one longer term. The nearterm challenge is cash flow. Producers are seeking improvements that can yield a near-term cash position to maintain dividends and the integrity of the balance sheet. The longer-term challenge is changing how they work. There has been a great deal of reduction in activity and cost-cutting, but there has been little significant effort to transform work to be sustainably leaner with increased efficiency and productivity into the future. How do you work on both of these challenges together? This is the “no regrets” path that Alberta producers must chart. Most companies are reaching the limit of what they can cut in terms of
capital and activity without significantly undermining their medium-term viability. To avoid a significant rundown scenario, reserves have to be replaced and critical maintenance must be done. Many companies may be contemplating further layoffs, but the immediate cash flow benefits of that are limited, and it might actually take more cash in the short term. There are real limits to cost-cutting without transforming the underlying approach to work. You can’t simply cut your way to more efficient work execution or surveillance—you actually have to change the workflow processes, use data and key performance indicators (KPIs) to create business efficiencies, and enhance staff effectiveness. Productivity is key. Options to overcome these challenges include reliability, asset management, project cycle time, and leadership and culture.
RELIABILITY The biggest lever many companies have to pull from a cash perspective may be on the revenue side: improving reliability and uptime, decreasing production declines and increasing throughput. Even at historic low oil prices, the cash benefits of organic production growth may dwarf cost-cutting. You may be able to cut costs by another $1–$2/bbl, but even with current netbacks, each marginal barrel of production is worth potentially $4–$6/bbl. There are many things that go into reliability, including
clear process parameters, shift-toshift consistency, clarity of workflow and decision making, rigorous loss reporting and root cause analysis. In my experience the right focus on reliability—one that treats it as a human system, not just a technical system—can get plants to achieve consistent performance well beyond nameplate or best demonstrated. That is a strong argument for real cash today and a strong return on capital into the future. Higher reliability and more barrels of production also have a direct impact on driving down fixed and variable costs. At my previous producer, on the first thermal SAGD project, the operational excellence program we created working with Evolve Partners helped establish most of these reliability systems, which allowed our teams to reach 42,000 bbls/d (versus nameplate capacity of 35,000 bbls/d). These same systems were maintained and implemented at both the second and the third thermal projects, which accelerated their ramp-up and achieved world-class uptime and availability of 97.9 per cent and 98.5 per cent. Figure 1 illustrates the high degree of production variability, reduced uptime and subpar reliability in the initial years. Implementation of an operations excellence program created a learning environment with our field and technical staff which led to consistently high performance and yielded tens of millions in incremental value.
Q 2 2 0 1 6 • J W N E N E R G Y. C O M • 5 9
G U E S T C O LU M N
Reduced variability through operations excellence (figure 1) 40,000
1. Ramping up production
2. Learning the system
3. Troubleshooting to steady state
4. Stabilizing production
5. Shift to operations excellence
2011
2012
35,000
30,000
bbls/d
25,000
20,000
15,000
TURNAROUNDS
10,000
5,000
0
-5,000 2008
ASSET MANAGEMENT Reliability and asset management are obviously intertwined: the steadier you run, the fewer unplanned events and the less wear and tear you create. Effective, proactive asset management is a central pillar for reliability, including preventive maintenance, less break-in work, failure mode and effects analysis, and higher efficiency, consisting of robust planning and scheduling, plan loading and materials management. There are likely some significant near-term cash benefits to be found in the more judicious use of contract labour, effective material and resource loading, and wrench time enhancements. Again, a thorough, proactive asset management program can yield significant incremental cost savings and reliability benefits while making the plant a safer workplace. All this is made possible through better planning and scheduling, culminating in fewer scope changes. For the thermal SAGD projects I worked on, improved asset management resulted in annual turnarounds
2009
moving to a two-year and eventually a three-year cycle. Millions of dollars were saved with fewer and shorter turnarounds, but more importantly, tens of millions of additional revenue and annualized production was realized.
PROJECT EXECUTION Another opportunity for changing the way you work resides in project execution. Despite reductions in capital budgets, there is still a need for sustaining capital programs for wells and pad facilities. Leaning out the execution process to reduce cycle time and increase standardization of design can yield a double benefit of production and cost savings. A more rigorous, value-based approach to project selection can also help companies choose the right projects—and avoid the wrong ones. Even small plant projects primarily focused on safety, improved operability and higher reliability cross many internal disciplines (field operations, process engineering, facilities engin eering, procurement) that report to different leadership with different
60 • Q2 2016 • OILSANDS REVIEW
2010
processes. As much as they work in teams, these different disciplines are siloed, which negatively impacts communication, planning, scope changes and collaboration. These issues create engineering rework between 20 per cent and 40 per cent, scope creep, schedule loss, quality assurance/quality control and incremental cost.
LEADERSHIP AND CULTURE You will need to motivate the people who have stayed on and are potentially doing the job of more than one person. Remember that the company has taken many people out of the organization but hasn’t actually changed “how” they work. In this constrained environment, fear will cause your people to be less innovative, with many just keeping their heads down and trying not to stand out or create any ripples in the organization. However, this is a time when you need to really maximize innovation and new ideas. To enable real change, you will need to find ways to take the fear out of the organization and create the right environment for real innovation.
This also creates longer-term benefits by getting your people to figure out how to do more with less, grow their skills and create an approach for ongoing productivity and continuous improvement. They will change the way they work by increasing collaboration, reducing cycle time, changing spans of control and creating improved efficiencies. In the early days of my first thermal project, as we were growing rapidly, we experienced too many levels of our organization focused on the day-to-day activities. Although these individuals were engaged and had a high level of ownership, most thought they needed to be connected to all daily happenings or needed information in case a superior asked. However, we found that implementation of a good production loss reporting system and exception reporting allowed senior field and senior technical staff to turn their focus to longer-term, strategic issues while still having confidence that significant performance exceptions would be elevated appropriately.
G U E S T C O LU M N
Reduced variability through operations excellence (figure 2) 40,000
Project 1
Project 2
Project 3
35,000
30,000
bbls/d
25,000
20,000
15,000
10,000
5,000
0 0
12
24
36
48
Normalized months
Responsibility for daily and near-term activities was driven down to the right level in the organization to those who were closest and best able to maximize results. It is paramount that our industry adopts a culture of increased collaboration, both internal and external, to increase productivity, efficiency and net asset value. In 2009, as thermal SAGD production increased and a greater load was placed on the electrical power system, we incurred 17 power outages. This negatively impacted well health and plant stability and resulted in a production loss of tens of millions of dollars. Working together with two utility companies on joint reliability, system backup and new design planning, our outage time went from 3,600 minutes in 2009 to 600 minutes in 2010 and 3.5 minutes in 2011. Figure 2 shows all three SAGD projects normalized to the date of initial start-up, which allows us to compare production ramp-ups.
While reservoir heterogeneity limited Project 2’s peak production capability and differences in pad capital timing for the number of wells available per project at initial startup, the differences in project ramp-ups are undeniable. Creation of a learning organization was sustained across several years of multiple project timelines. Clear roles and responsibilities, accurate KPIs and production loss reporting to drive accountability, high reliability and maximizing value was achieved. It is possible that we could have achieved close to the same results eventually but I have to ask, can our industry afford to undertake a slow transformation and miss millions of revenue dollars? In my opinion, “changing the way we work” starts with leadership and culture.
Cal Watson is the retired vice-president of production with Devon Energy. He is currently an adviser to Evolve Partners, LLC.
SAGD asset planning and enhanced well pad development
TUESDAY, JUNE 21, 2016 THE CALGARY PETROLEUM CLUB
SAGD projects operate for decades, requiring ongoing investment in well pad drilling and construction in order to sustain production rates. This panel discussion will examine producer strategies to optimize project development planning, including the effectiveness of their efforts to drive down costs.
REGISTRATION & BREAKFAST 7:30 a.m.–8:00 a.m. PROGRAM 8:00 a.m.–9:15 a.m.
Register online at: jwnenergy.com/events For inquiries: regsupport@jwnenergy.com or call 1.866.671.2778
TICKET PRICES: $40 PER SINGLE TICKET $300 FOR A TABLE OF EIGHT
EXCLUSIVE EVENT SPONSOR:
Q 2 2 0 1 6 • J W N E N E R G Y. C O M • 6 1
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
LL WE LL R E WE UC R D O O PR NJECT I
Temporarily shutting in thermal wells might not be as harmful as you think
ERS
ED VER O C E UNR Y OIL V A HE
CAPRO
CK
STEAM
STEAM
RISES A
AM
STE
MB CHA
ND HEA TS BITU
MEN
OIL & W ATER
PAT ROCHE
can say is there is not a lot of wells that have been shut in and reactivated—and certainly not enough to make a statistically meaningful study,” Carey told the CHOA conference. “But that isn’t the intent. The intent here for me was to examine trends and behaviour to see if they’re consistent with what you would expect from engineering judgment, and to see if anything big stands out.” He also noted the metrics can easily differ from project to project, depending on factors such as reservoir characteristics, why a well went down, whether the steam chambers are connected and whether the operator did anything to the well while it was down. Carey cited two specific SAGD examples: a well from Devon Canada’s Jackfish project and three wells from Suncor Energy’s MacKay River project. In the case of Jackfish, a well pair was shut in for 18 months after sand abrasion at the wellhead caused an oil spill in 2010. Adjacent well pairs were shut down for three months, then reactivated. Comparing oil production and steam to oil ratio (SOR) before and
62 • Q2 2016 • OILSANDS REVIEW
after the 18-month shut-in, Carey found “no impact whatsoever. In fact, this well pair went on to be an excellent performer with good [oil production] rates and a low SOR.” However, it wasn’t entirely clear whether this well might have been getting thermal support from the neighbouring wells that were reactivated after three months. At MacKay River, three SAGD wells were taken down for repairs and ended up being shut in for extended periods. “[The] wells came back on pretty well the way that they left off in terms of rates and SORs,” Carey said. “The first two wells continued to show operational and inflow issues in the longer term. But the fact remains that they came back on with little change, and the subsequent problems were not a result of the shut-ins.” Not all of the wells in Carey’s study had the same drop-off in oil production rates, but “all ended up doing not too badly” two years after reactivation. Also, while the initial SORs were much higher immediately after reactivation, the SOR two years later “was not unreasonably higher than” before the wells were shut in.
“The [shut-in] wells came back on pretty well the way that they left off in terms of rates and SORs.” — BRUCE CAREY, engineering adviser, Peters & Co.
BA SE I LLUSTR ATION: CENOVUS ENERGY
Investors have been asking Peters & Co. about the potential risks and rewards of shutting in thermal wells during the oil price downturn, so engineering adviser Bruce Carey did the research. While he stresses that the data he came back with is not sufficient to be “statistically meaningful,” it does indicate a surprisingly positive trend. He presented his findings at the Canadian Heavy Oil Association’s Slugging It Out conference in April. Carey began with a geoSCOUT search of thermal well shut-ins, using three screening criteria. First, the wells had to be produced for about two years to provide a good base for assessing any performance changes. Second, the wells had to be shut in for at least six months to increase the likelihood of seeing a response. And third, the well had to be put back on production for at least six months to provide a reasonably stable baseline to compare with previous performance. More than 1,700 well pairs survived the first screening criterion, but only 44 satisfied all three criteria. “With only 44 wells, the most statistically quantitative thing that I
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