Heavy Oil & Oilsands Guidebook Volume 7 2012

VOLUME 7 | 2012 | $20 PRODUCTION ENVIRONMENT

BROUGHT TO YOU BY THE PUBLISHERS OF

IN PARTNERSHIP WITH

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EDITOR’S EDITOR’S editorial editorial Editor

EditorS

LETTER LETTER

| djaremko@junewarren-nickles.com DeborahDeborah JaremkoJaremko | djaremko@junewarren-nickles.com ChazwritErS Osburn | cosburn@junewarren-nickles.com Contributing Contributing Jim Bentein, Godfrey writErS Budd, Graham Chandler, Melanie Collison, Lynda Harrison, Richard Macedo,Klingbeil, Neil Levine, Ashok Dutta, Gordon Jaremko, Annalise Pat Roche, Dustin Sundby James Mahony, Peter McKenzie-Brown, R.P. Stastny Editorial aSSiStanCEJoey ManagEr Contributing PhotograPhEr: Podlubny Samantha Kapler | skapler@junewarren-nickles.com Contributing illuStrator: Nickelas Johnson Editorial aSSiStanCE Contribuitng Editor: Joseph Caouette Laura Blackwood, Brandi Haugen Editorial aSSiStanCE ManagEr

Samantha Kapler | skapler@junewarren-nickles.com Creative PrEPrESS & ProduCtion ManagEr Editorial Print, aSSiStanCE

Michael Gaffney | mgaffney@junewarren-nickles.com Kate Austin, Laura Blackwood, Tracey Comeau, Alison Dotinga, Brandi Haugen, CrEatiVEMarisa SErViCESKurlovich ManagEr Tamara Polloway-Webb | tpwebb@junewarren-nickles.com Creative CrEatiVE lEad Print, PrEPrESS & ProduCtion ManagEr

Cathlene| mgaffney@junewarren-nickles.com Ozubko Michael Gaffney graPhiC dESignErS CrEatiVE SErViCES ManagEr

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Ian MacGillivray | imacgillivray@junewarren-nickles.com Bill Whitelaw | bwhitelaw@junewarren-nickles.com dirECtor oF thE oF daily oil bullEtin ViCE-PrESidEnt & dirECtor SalES

Stephen Marsters | smarsters@junewarren-nickles.com Rob Pentney | rpentney@junewarren-nickles.com dirECtor digital StratEgiES dirECtor oF EVEntSoF & ConFErEnCES

Gord Lindenberg | glindenberg@junewarren-nickles.com Ian MacGillivray | imacgillivray@junewarren-nickles.com dirECtor oF oil ContEnt dirECtor oF thE daily bullEtin

Osburn | cosburn@junewarren-nickles.com Stephen Chaz Marsters | smarsters@junewarren-nickles.com dirECtor ProduCtion dirECtor oF digitaloF StratEgiES

Audrey Sprinkle | asprinkle@junewarren-nickles.com Gord Lindenberg | glindenberg@junewarren-nickles.com dirECtor oF MarkEting dirECtor oF ContEnt

Kim Walker | kwalker@junewarren-nickles.com Chaz Osburn | cosburn@junewarren-nickles.com dirECtor oF FinanCE dirECtor oF ProduCtion

Ken Zacharias, CMA | kzacharias@junewarren-nickles.com Audrey Sprinkle | asprinkle@junewarren-nickles.com dirECtor oF MarkEtingBoard adviSory

Christine Bovaird, IHS Energy Kim Walker | kwalker@junewarren-nickles.com Walter Dale, GE Infrastructure dirECtor oF FinanCE Tracy Grills Technologies, Canadian Heavy Oil Ken Zacharias, CMA,|Pinnacle kzacharias@junewarren-nickles.com Association

adviSory TimBoard Hazlett, Government of Alberta Gerald Bruce , Canadian Heavy Oil Association Deborah Jaremko , JuneWarren-Nickle’s Energy Group MarkCanadian Lowey, ISEEE Karri Viccars, Association of Petroleum Producers Bill MacFarlane , Nexen, Bob Dunbar, Strategy West Inc. Canadian Heavy Oil Association Stephen , JuneWarren-Nickle’s Energy Group Bob Taylor, EnergyMarsters Futures Network Chaz JuneWarren-Nickle’s Osburn, JuneWarren-Nickle’s Energy Group Chaz Osburn, Energy Group Rob Pentney , JuneWarren-Nickle’s Energy Group Rob Pentney, JuneWarren-Nickle’s Energy Group DeborahoFFiCeS Jaremko, JuneWarren-Nickle’s Energy Group oFFiCeSCalgary Calgary 2nd Floor, 816 – 55 Avenue N.E. | Calgary, Alberta T2E 6Y4 Fax:|403.245.8666 | Toll-Free: 2nd Floor,Tel: 816403.209.3500 – 55 Avenue |N.E. Calgary, Alberta T2E 6Y41.800.387.2446 Edmonton Tel: 403.209.3500 | Fax: 403.245.8666 | Toll-Free: 1.800.387.2446 6111 – 91 Street N.W. | Edmonton, Alberta T6E 6V6 Edmonton 780.944.9333 | Fax: 780.944.9500 | Toll-Free: 1.800.563.2946 6111 – 91 Tel: Street N.W. | Edmonton, Alberta T6E 6V6 SUBSCriPtioN iNqUirieS Tel: 780.944.9333 | Fax: 780.944.9500 | Toll-Free: 1.800.563.2946 Tel: 1.866.543.7888 SUBSCriPtioN iNqUirieS Email: circulation@junewarren-nickles.com Tel: 1.866.543.7888 Heavy Oil & Oilsands Guidebook & Directory is owned by JuneWarrenEmail: circulation@junewarren-nickles.com Nickle’s Energy Group and is published yearly.

When our editorial team met with the Heavy Oil & Oilsands Guidebook advisory committee in late 2011 to determine the direction of the seventh edition of this publication, the conversation kept drifting back to a central theme for this sector: the future is now. This industry is headed to a very different place than it used to occupy, the characteristics of which retiring Suncor Energy Inc. president and chief executive officer Rick George recently hinted at. “The technology changes that you’re going to see in this industry in the next 10 years on the mining side and the in situ side and the land reclamation side are going to be off-the-charts good,” he said. “The next 20 [years are] going to be about technology and how quickly we go up this technology curve.” What is truly exciting is that important advances along the curve George talked about have already been achieved. For example, I remember the World Heavy Oil Congress held in Edmonton in 2008, when he took the stage and made the bold prediction that dry tailings would be a reality within two years. It was an unexpected statement, but he was right. In fall 2010, Suncor celebrated the reclamation to a solid surface of the first tailings pond in the oilsands industry, and the commercial deployment across the company’s operations of a tailings treatment technology called TRO; it not only prepares this waste stream for reclamation in a matter of weeks rather than decades, but also means that—in support of Suncor’s existing operations— another new tailings pond will never be created. Suncor is not alone—all the oilsands mining firms have similar technologies and have agreed to collaborate on their commercialization. That’s just one example among many of what the future of this industry looks like. It’s all part of growing up, and this sector has certainly come of age, but unlike the humans who created it, coming of age for the oilsands industry is not going to be accompanied by a slow and steady decline to death; instead, the future holds nothing but promise. The road will be difficult, but the light trained on bitumen and its benefits far outshines the shadows along its fringes. You will find the details illuminated in these pages. Enjoy!

Deborah Jaremko | Editor

Heavy Oil &GST Oilsands Guidebook & Directory is owned by Registration Number 826256554RT JuneWarren-Nickle’s and is published yearly. Printed in Energy CanadaGroup by PrintWest GST Registration Number 826256554RT ISSN 1207-7333 Printed in Canada by PrintWest ©2011 1080557 Glacier Media Inc. ISSN 1207-7333 Publications Mail Agreement Number 40069240 ©2012 JuneWarren-Nickle’s Energy Group Postage paid in Edmonton, Alberta, Canada Publications Mail Agreement Number If undeliverable, return to: 40069240 Postage paid in Edmonton, Alberta, Canada Circulation Department, 800-12 Concorde Place, Toronto ON,to: M3C 4J2 If undeliverable, return in Canada. CirculationMade Department, 80 Valleybrook Dr, North York ON, M3B 2S9 Made in Canada.

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Pengrowth Optimizes Well Design and Placement for Maximum Heavy Oil Recovery ECLIPSE Thermal simulator aids sensitivity analysis and SAGD optimization at Lindbergh field, Alberta CHALLENGE

Analyze initial well design and determine well placement for maximum recovery and optimized steam-oil ratio (SOR) in a steam-assisted gravity drainage (SAGD) pilot operation.

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SOLUTION

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RESULTS

Produced thermal simulation model, enabled sensitivity analysis of SAGD process, and achieved confidence in pilot design; modified design to maximize oil recovery while reducing SOR; cut time to run simulations using parallel computing.

Examine potential SAGD success in pilot area Pengrowth used ECLIPSE Thermal Reservoir Simulation software and its Multisegmented Well (MSW) option to build a model representing field conditions and to evaluate the potential success of SAGD in the Lindbergh pilot area. Due to the reservoir’s relative homogeneity, a layered model was created with the vertical variation in porosity and permeability derived from core data. The ECLIPSE Thermal simulator with MSW option enabled accurate representation of pressure drops and heat transfer effects along the wellbore. Reservoir simulation helped optimize completion design and well placement to ensure maximum economic oil recovery. Industry-leading approach to modeling. The pilot design was modeled using eight SAGD well pairs with multisegmented well models to test

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effects of viscosity variation spatial distance between the eight well pairs vertical separation between the injector and producer for each well pair vertical separation of the producer from the bottom water (i.e., how high or low the producer can be with respect to the bottom water to optimize SAGD) the multipoint injection scheme within each injector.

Existing pipelines and facilities, horizontal well lengths and interwell spacing, and observation wells were also taken into account. A computing cluster with 32 cores was used for the modeling process. Each simulation was run 16-way parallel, effectively running two simulations at the same time. The run times for each eight-well-pair model with MSW were reduced from several days to an average of 18 hours. The simulation runs covered 11 years of SAGD production, with an additional 3 months for preheating via steam circulation. This industry-leading approach was more comprehensive than single-wellpair modeling, and the testing helped avoid steam chamber quenching while maximizing recovery. Pilot design modifications to maximize recovery. Five development scenarios were modeled to analyze the Lindbergh pilot design. Sensitivity analysis results were extremely useful in optimizing the design. Subsequent modification further maximized recovery while reducing SOR. The best case of each scenario was taken to run the remaining sensitivities. The right horizontal spacing is essential for maximizing oil recovery and balancing SOR. Inter-pair horizontal spacing was evaluated at increments of 80 m, 100 m, and 120 m—resulting in an optimal interval of 100 m, with eight well pairs generating

Steam fraction showing the vertical chamber growth in a plane perpendicular to the wells 1 year into the SAGD process (optimized case).

the most economically viable operation. Testing injector and producer vertical well spacing allowed Pengrowth to determine the best spacing for ultimate recovery. Spacing was tested using separation increments of 3 m, 4 m, 6 m, and 7 m. The greater the vertical separation between the injector and the producer wells, the higher the overall recovery, but the lower the initial production rates. The increase in reserves was incremental, and the original design of 5 m separation was within the acceptable range. The number of injection points required to maximize recovery and minimize SOR was also investigated. The final simulation cases used several injection points, one point at the heel and five points spaced out in 25% increments along the horizontal length. Two injection points—at heel and toe—provided maximum recovery.

Maximized recovery and minimized SOR This study shows that additional sensitivity analyses and uncertainty quantification are required to optimize the SAGD process under varying reservoir conditions. Geology plays a key role in dictating SAGD performance and must be adequately reflected in the simulation model. A detailed wellbore model is critical in understanding pressure and heat transfer effects on steam chamber formation. The ECLIPSE Thermal simulator and Multisegmented Well option provided the rigor to determine the best operational parameters, maximizing recovery and minimizing SOR. Pengrowth plans to introduce detailed heterogeneity into the model for further studies.

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VOLUME 7 | 2012

TABLE OF CONTENTS 1 9

Editor’s note

Welcome From the Canadian Heavy Oil Association

10 BROUGHT TO YOU BY THE PUBLISHERS OF

From the Government of Alberta

Welcome From the Government of Saskatchewan

IN PARTNERSHIP WITH

184

Industry statistics

185

Environment statistics

186

Glossary

IntroductIon

Reflections on 2011 and forecast for 2012

departments

dIrectory

192

Networking

198

Producers

202

Service & Supply

ENVIRONMENT

GUIDEBOOK

Welcome

by deborah Jaremko

History: Heavy oil and oilsands come of age by gordon Jaremko

PRODUCTION PRODUCTION 30

A new boom Oilsands investment projected to reach record levels in 2012

by deborah Jaremko

Operating project profiles

PhotoS (FroM toP): JoEy Podlubny, JoEy Podlubny, Marathon oil CorPoration, MEg EnErgy CorP., north wESt uPgrading, JoEy Podlubny.

ENVIRONMENT ENVIRONMENT 32 Mining

Project status listing

Inflation headwind Oilsands owners face a new period of difficult cost control as a boom begins anew

38 In situ 59 Experimental

68 71

by neil levine

Operational data reference

PRODUCTION PRODUCTION

Oilsands projects under construction

UPGRADING + REFINING UPGRADING + REFINING

Emerging producers On the rise in the oilsands sector

An international arrangement Foreign oilsands investment surge is likely to continue, but in increments and not flagship deals

by James Mahony

ENVIRONMENT ENVIRONMENT 88

Eye on the environment

Industry uses collaboration and technology to manage air, water and PEOPLE PEOPLE land issues by annalise klingbeil

Catalyzing creativity Oilsands producers $66.9 UPGRADING + REFINING UPGRADING +contribute REFINING

by deborah Jaremko

105

by Joseph Caouette

Carbon clash in the Golden State MARKETS MARKETS The legal fight over California’s lowcarbon fuel standard could have big implications for Canada’s oilsands industry

by r.P. Stastny PEOPLE PEOPLE

Top watchdog A new federal-provincial oilsands monitoring plan will bring together existing programs into one coordinated effort

million to clean technology fund

The tailings technology suite Oilsands miners drop the barriers of cost and intellectual property for the greater good

by Jim bentein

110

Oilsands allies Inside a growing trend toward industry collaboration in support of environmental performance improvement by Peter Mckenzie-brown

RESEARCH + DEVELOPMENT RESEARCH + DEVELOPMENT

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PRODUCTION ENVIRONMENT CONTENTS PRODUCTION TABLE OF ENVIRONMENT

VOLUME 7 | 2012

GUIDEBOOK BROUGHT TO YOU BY THE PUBLISHERS OF

UPGRADING + REFINING UPGRADING + REFINING 116 ENVIRONMENT Upgrading in Alberta: two steps forward ENVIRONMENT PRODUCTION

PRODUCTION by neil levine

+ REFINING UPGRADING + REFINING 118 UPGRADING An incremental game changer

120

Operating oilsands upgrader profiles

126

In play: new upgrading projects to watch

142

Bill McKibben Environmental Activist

144

Les Little Alberta Innovates– Energy and Environment Solutions

146

Dana Woodworth Alberta Energy

148

Lei Jianzhong People’s Republic of China

166

Spill stresses

High-temperature paraffinic froth treatment promises better efficiencies and ready access to refineries

PEOPLE PEOPLE by r.P. Stastny ENVIRONMENT ENVIRONMENT UPGRADING + REFINING UPGRADING + REFINING PEOPLE PEOPLE 130

Dave Harper Ledcor Group of Companies

MARKETS 132 MARKETS Alan Fair Oil Sands Tailings Consortium 134

Bill McCaffrey MEG Energy Corp.

UPGRADING + REFINING UPGRADING + REFINING PEOPLE 136 PEOPLE Steve Williams Suncor Energy Inc. MARKETS 138 MARKETS Andrew Leach University of Alberta

140

Janet Holder Enbridge Inc.

RESEARCH + DEVELOPMENT RESEARCH + DEVELOPMENT MARKETS MARKETS PEOPLE PEOPLE 152

From feeding the beast to feeding the dragon RESEARCH + DEVELOPMENT RESEARCH + DEVELOPMENT

With new pipeline projects under scrutiny, industry goes on the offensive over safety

Why Canada’s oil can no longer rely on one market—the U.S. Midwest

by ashok dutta

155 MARKETS New market access: project profiles MARKETS

169

A collective of newcomers Fort McMurray leaders work to build a community amid the challenges of rapid oilsands development and a skyrocketing population

+ DEVELOPMENT RESEARCH + DEVELOPMENT 163 RESEARCH Asia opportunities Where Canadian crude could fit into a growing, evolving, new refining market

by Jim bentein

by ashok dutta

RESEARCH + DEVELOPMENT RESEARCH + DEVELOPMENT 176

The oil that technology made

180

Technological challenges have always shaped the recovery of bitumen resources

Advancing the frontier Barely 10 years have passed since the first commercial SAGD programs and producers are steadily pushing ahead with new extraction technologies

by graham Chandler

178

Tidier tailings and waterless extraction Scientists sink their teeth into the challenges of cleaning up oilsands mining by graham Chandler

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182

Fine-tuning SAGD Operators adding hydrocarbon solvents to boost productivity and lower costs by godfrey budd

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WELCOME

LETTERS

MESSAGE FrOM

The Canadian Heavy Oil Association

Welcome to the seventh edition of the Heavy Oil & Oilsands Guidebook. These are exciting times in the industry, which is receiving more than its share of attention as the scope and scale of development becomes a topic of discussion on the world stage. This guidebook will provide you with understanding and insight into the game, the drivers, the people, successes, challenges and future initiatives. The fundamentals of getting the bitumen out of the ground, through both mining and in situ production, are profiled with key metrics on operating facilities. Developmental and experimental pilots provide a view on where the industry is heading, through applied technology and innovation. A comprehensive project status listing provides a good understanding of who the key players are, and the emerging companies that provide insight into the future of the industry. Included in this guidebook is perspective on: the people behind the scenes; decision makers and innovators; the markets, infrastructure and politics; the role that upgrading and refining has in the future of the industry; sustainability measures related to the impact on air, water and land; and the research and development initiatives that hold great promise for the future of the industry. We have reflections on the achievements of 2011 with predictions for 2012, a commentary on project costs, a profile of the current status of community building efforts in the oilsands heartland of Fort McMurray, Alta., and a historical look back at how heavy oil and oilsands have come of age. The publication also looks at important trends in the sector, such as the increasing push towards collaboration between companies on environmental issues, and strategies to control project costs. I trust you will develop an appreciation of how the heavy oil and oilsands industry is positioning for a very interesting future.

Gerald Bruce President, Canadian Heavy Oil Association 2011-2012

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WELCOME

LETTERS

MESSAGE FrOM

The Government of Alberta

As a passionate Albertan, and former minister of both sustainable resource development and finance, I know how important the energy portfolio is to Alberta. This past year, many economies around the world remained fragile. In Alberta, however, we’re gearing up for what could be another unprecedented period of growth. Alberta is leading Canada’s economic recovery. When it comes to the oilsands, Alberta has a strong story to tell. Responsible development has always been important to me and will only become more critical in support of Alberta’s interests, nationally and internationally. This includes telling a more complete story of Alberta’s responsible development of the oilsands. Our oilsands have garnered interest from Norway, France, China, Japan, Korea and Thailand. It is in the emerging economics of Asia that demand is forecast to grow most significantly over the next two decades. Alberta is energy-rich and innovative, with a skilled workforce. Our fiscal regime is competitive, recognizing and rewarding risk while embracing change. Regulatory enhancement is also critical to Alberta’s competitiveness. Clarity, predictability and timely processes in a regulatory system are key goals of the Regulatory Enhancement Project. The premier and I are fully committed to this project and to maintaining momentum in implementing fundamental change in the system. Developing legislation to implement a single regulator remains a top priority. The success of this project will result, in part, from our positive working relationship with industry. Moving forward must both enhance Alberta’s position as a sound place to invest and build on our strong regulatory framework. We also continue to move forward with our carbon capture and storage development program. Clean energy production is a science that is constantly evolving and, here in Alberta, we’re striving to be on the cutting edge. This program, in partnership with industry, will fund projects that will reduce Alberta’s greenhouse gas emissions by five million tonnes annually, beginning in 2015. I look forward to building on a truly positive and collaborative relationship between government and industry. Together, there is much we can accomplish for the benefit of Albertans and Canadians across this land.

Ted Morton Alberta Minister of Energy

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WELCOME

LETTERS

MESSAGE FrOM

The Government of Saskatchewan Saskatchewan is taking its rightful place on the global stage—we have what the world needs. The province accounts for over a quarter of Canada’s primary energy production, including coal, oil, natural gas, hydro, uranium, wind and biofuels. Saskatchewan is the second-largest producer of crude oil in Canada, accounting for approximately 17 per cent of total Canadian production. Our province is the sixth-largest oil producer among all American states and Canadian provinces. In any given year, 65–70 per cent of our oil is exported to the United States. While we do not have oilsands production to date, we do have exploration and development underway in the northwestern part of our province. Scientists estimate there are 27,000 square kilometres with some degree of oilsands potential. There is also excellent oil shale opportunity in east-central Saskatchewan. We have the business environment that draws investors to our province to help develop those resources. For example, our province was recognized by the Fraser Institute last year in its annual Global Petroleum Survey. The institute assessed 136 different provinces, states and countries in terms of their investment climates—as seen by the oil and gas companies—and ranked Saskatchewan best in Canada. That brought our standing up from second place in 2010. On the international stage, Saskatchewan ranked 11th best in the world, up from 17th the year before. Saskatchewan’s oil and gas industry recorded an estimated $11.7 billion in sales last year and invested roughly $4.2 billion in exploration and development activity. The oil and gas industry provided approximately $1.7 billion in revenue back to the provincial government in 2010-11 and was one of the largest contributors to the provincial economy. We have more than 300 different oil and gas companies operating in the province and over 32,000 people employed directly and indirectly in the oil and gas industry. The 2011 calendar year was our second-best for drilling oil wells and we broke a horizontal well drilling record that was only a year old. In total, 3,528 oil wells were drilled in 2011, a 29 per cent increase over the figure for 2010 and just short of the record figure we set in 1997. All that activity contributed to the new record for horizontal oil wells drilled last year—1,992—a 30 per cent increase over 2010’s previous record. Four oil plays have been getting a lot of attention in our province lately: the Viking light oil play in the west-central area; the Shaunavon medium oil play located in the southwestern corner; the Bakken in the southeast and the rejuvenated Birdbear heavy oil play located in the Lloydminster heavy oil belt. These may be the “hottest” plays, but they are not the only active plays in the province. Heavy oil accounts for over half of our annual provincial oil production. We have over 40 billion barrels of conventional oil in place, and about 22 billion barrels of that is heavy oil. With our current technology, we can only expect to recover a small percentage of our heavy oil resources, but that will change as new techniques in enhanced oil recovery are developed. We have the resources and the business climate to continue to excel on the world stage. That’s our Saskatchewan Advantage, and we’re making the most of it on behalf of the people of our province.

Bill Boyd Minister of Energy and Resources Government of Saskatchewan

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POISED FOR

A BOOM rEFlECTIONS

2011 on

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NEW LAND-uSE PLANNING FOR ALBERTA’S MAIN OILSANDS REGION The Government of Alberta announced a new plan for regionally focused regulation in the Athabasca oilsands region in April 2011, which among other changes would result in the cancellation of 10 oilsands and 14 mineral leases in order to create conservation areas. The Lower Athabasca Regional Plan (LARP) is expected to become law in the near future, and represents a significant shift in industry regulation, according to Dufferin Harper, an environmental lawyer with Blake, Cassels & Graydon LLP. “LARP will be a bit of game changer for everybody in the oilsands industry. [It] increases the importance of looking at your operation in the context of other operations in your area. You can no longer look at your [project] in isolation. Today, you have to look at it in concert with others in your region,” he said in early 2012.

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ES CANADA DROPS TO THIRD IN GLOBAL CRuDE RESERvES As of March 2011, the Canadian Association of Petroleum Producers (CAPP) and the Alberta government stopped reporting that Canada has the second largest reserve of crude oil in the world, second only to Saudi Arabia. The issue: while Canada’s reserves are holding steady at approximately 175 billion barrels (170 billion of which are oilsands), Venezuela’s estimate has jumped significantly, from 99 billion barrels previously to 211 billion barrels today. This stacks Venezuela as number two, flanked by Saudia Arabia (260 billion barrels) on one end and Canada on the other. CAPP spokesman Travis Davies explains that the change in its reporting is a direct result of a recent reserves estimate update by the Oil and Gas Journal, the source upon which CAPP bases its own global reserves data. The estimate increase of 112 billion barrels is most likely in response to a January 2010 reserves update for Venezuela made by the U.S. Geological Survey. “It’s important to note that the [Oil and Gas Journal] numbers are based on a survey of government agencies. In Canada, it’s CAPP,” says Davies, adding that the drop from second to third place doesn’t have significant implications for Canada’s unconventional oil industry. “The most important thing to bear in mind is that unlike the Canadian oilsands, Venezuelan reserves are not open to free market investment. Fifty-two per cent of reserves available to capital in the world are in the Canadian oilsands. That fact remains the same.” ALBERTA GOvERNMENT CLINCHES REFINERy FEEDSTOCK DEAL The first $5-billion phase of a new 50,000-barrel-per-day bitumen refinery in the Industrial Heartland near Redwater, Alta., that will process Bitumen Royalty in-Kind for the Alberta government is now targeted for completion in mid-2014. The Alberta government announced in February 2011 that it had successfully negotiated contracts that will encourage upgrading and refining of bitumen in Alberta, increase supplies of diesel fuel and provide a source of pure CO2 for enhanced oil recovery from existing conventional oilfields. Depending upon the economics, there could be two more 50,000-barrel-per-day phases. The deal, a joint venture between North West Upgrading Inc. and Canadian Natural Resources Limited, will lead to construction of the refinery as part of the government’s Bitumen Royalty inKind initiative. The bitumen refinery initially will process 37,500 barrels per day of Crown bitumen in addition to 12,500 barrels per day of bitumen from Canadian Natural. The refinery will process the Crown’s bitumen for a processing fee, which will result in higher revenues created by the higher-priced refined bitumen products.

OILSANDS SECTOR IN IMPROvED POSITION TO CONTROL COSTS In June 2011, senior executives from major oilsands companies agreed that while inflation is still a risk, the current round of construction is different from during the previous boom when bloated costs led to huge cost overruns. Contracts, labour availability, natural gas prices and fewer new upgraders make the current situation more manageable, they told the RBC Capital Markets’ Global Energy and Power Conference in New York City. “I’m seeing better balance,” said Bart Demosky, chief financial officer for Suncor Energy Inc. “[There is] some risk on the horizon probably two or three years out, and in the interim we’ve got the EPC [engineering, procurement and construction] firms calling us and saying they’re not full on work, and I haven’t heard that for quite some time.”

PILOTS FIRED uP IN CARBONATES AND GRAND RAPIDS RESERvOIRS Producers moved ahead on the next geological frontiers for in situ bitumen recovery in late 2010 and 2011, starting up a number of pilot facilities targeting both the bitumen carbonates and the application of steam assisted gravity drainage (SAGD), in the Grand Rapids formation. In late 2010, Laricina Energy Ltd. and partner Osum Oil Sands Corp. started up the Saleski carbonate SAGD pilot, reporting first oil in March 2011. During the first quarter of 2011, Sunshine Oilsands Ltd. conducted one cycle of cyclic steam stimulation on its carbonate leases at Harper, planning a second cycle for early 2012. Athabasca Oil Sands Corp. initiated a pilot of thermal assisted gravity drainage in the Leduc bitumen carbonates in 2011, anticipating full results in early 2012. There is estimated to be more bitumen resource present in the carbonates than in the currently commercialized clastics. Another resource yet to be fully tapped is the Grand Rapids formation, and in late 2010 and 2011 both Cenovus Energy Inc. and BlackPearl Resources Inc. moved ahead with Grand Rapids SAGD pilots. Cenovus started operations at its pilot, located on the same leases as its Pelican enhanced oil recovery operations, in late 2010, while BlackPearl fired up the Blackrod SAGD pilot in 2011. Currently, the only commercial SAGD operation in the Grand Rapids formation is owned by Canadian Natural at Wolf Lake.

THE FuTuRE OF OILSANDS ExPORT PIPELINES GETS MuRKy Opposition to new Canadian crude oil export pipelines escalated in 2011, ultimately forcing the U.S. State Department rejection of the proposed Keystone XL system to the U.S. Gulf Coast in its original route. Actions included thousands of protestors lining up at the White House in November with the message to stop Keystone XL due to environmental concerns both upstream in the oilsands and along the system’s path. To the West Coast, the proposed Northern Gateway pipeline is facing at least as much opposition in Canada from First Nations and environmental groups. In November, the joint review panel tasked with assessing the project released details on public hearings to be held in 2012, at which about 4,000 people are expected to speak. In early 2012, protests in British Columbia had already begun.

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CHINA CONTINuES TO BuILD OILSANDS PRESENCE In another Chinese foray into the Canadian oilpatch, in summer 2011 China National Offshore Oil Corp. (CNOOC) agreed to take over troubled oilsands developer OPTI Canada Inc. in a US$2.1-billion deal. The announced investment came a week after OPTI, which is a 35 per cent working interest partner in Nexen Inc.’s Long Lake SAGD project, filed for creditor protection to ease the burden of its crushing debt. The OPTI board voted unanimously in favour of the deal, which closed in November. In early 2012, PetroChina Company Ltd. became the first Chinese energy company to secure operatorship of an oilsands project, purchasing the remaining interest in the proposed MacKay River SAGD project from former partner Athabasca Oil Sands for $680 million.

FEDERAL COMMISSION SAyS OILSANDS MONITORING IS INADEquATE Incomplete environmental baselines and environmental data-monitoring systems needed to understand changing environmental conditions in northern Alberta have hampered federal agencies’ ability to properly judge the cumulative environmental effects of oilsands projects in that region, said an October 2011 report from the office of the auditor general of Canada. The report also noted that the federal government has not tracked the cumulative environmental effects of multiple-development projects over time. As a consequence, decisions about oilsands projects have been based on incomplete, poor or nonexistent environmental information, according to Scott Vaughan, commissioner of the environment and sustainable development, creator of the report. That, in turn, has “led to poorly informed decisions.” PRODuCERS REALIZE vOLuMES FROM MAJOR ExPANSIONS In 2011, a number of oilsands producers began to reap the benefits of multi-year construction projects expanding capacity at their bitumen production and processing facilities. Most significantly, in June Shell Canada Limited commissioned the only recent significant increase to upgrading capacity in Alberta, celebrating a 100,000-barrel-perday expansion to both its mining operations and to the associated Scotford Upgrader. Also in June, Devon Canada Corp. achieved first oil from the 35,000-barrel-per-day Jackfish 2 project, the company’s second phase of SAGD in the oilsands. In July, Suncor Energy reported first oil from the 62,500-barrel-per-day Stage 3 expansion at its Firebag SAGD project, followed by commissioning of Cenovus Energy’s 40,000-barrel-per-day Phase C at its Christina Lake SAGD project in August. Production volumes from these projects continued ramp-up through 2011.

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A TOUGH BUT WORTHWHILE

CLIMB WHAT TO WATCH

2012 in

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LEARNINGS FROM OTHER SECTORS HELP THE OILSANDS MOvE INTO THE FuTuRE According to Deloitte & Touche LLP there are early signs that the oilsands industry is moving away from legacy “staunchly independent or even adversarial” oil and gas attitudes, and toward strategies that borrow models from other sectors in order to address complex issues such as new technology development, and environmental and social sustainability. Deloitte argues that by using ideas from the automobile, high-tech and other sectors, oilsands producers can take advantage of contemporary manufacturing approaches. “These can reduce cycle times, reduce operational costs and eliminate non-productive activity.”

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RECORD OILSANDS INvESTMENT ON THE BOOKS At least $20 billion will be spent on new capital projects in the oilsands sector in 2012, according to CAPP. Construction is already underway on over 900,000 barrels per day of production capacity, largely from SAGD projects, and engineering and early-stage procurement continues on the next wave. “We think it’s going to be very, very busy in 2013 and we expect it will be very close to what we expect the peak to be,” said Guy Cocquyt, director of investor relations with Flint Energy Services Ltd., which in early 2012 announced it would be acquired by URS Corporation for $1.25 billion.

COLLABORATION GROWS AS KEy TO MANAGING ENvIRONMENTAL ISSuES In a recent interview, Suncor president and chief executive officer Rick George said the oilsands industry should “share anything to do with safety, the environment, environmental improvement, anything on reducing our air, land and water footprint.” Given that perspective, it isn’t surprising that Suncor is one of the founding members of the Oil Sands Leadership Initiative—a group of major producers that has agreed to share technologies and best practices in these important areas. According to CAPP’s Greg Stringham, vice-president of oilsands and markets, “Collaboration is the big topic for improving environmental issues. It is a growing initiative. Environmental issues are not a competitive issue, but something that needs to be worked on collaboratively. The leading edge is the Oil Sands Tailings Consortium.” Deloitte’s report notes that “the associations being forged now will set in motion the expectations and rules of engagement that will carry forward when addressing even bigger-picture issues requiring even greater universality and solidarity.” For this to happen, says the firm, the industry will need “a wider representation of both large and small operators…to truly push ahead.”

HuMAN RESOuRCES: THE COST OF A LABOuR SHORTAGE GROWS HIGHER The oilsands sector is moving into a full-blown labour shortage, and the associated cost implications for new projects will be on the rise in 2012. “A number of indicators demonstrate that the labour market in Alberta is already tight,” says Chris Lee, a partner with Deloitte whose group recently prepared the report Gaining ground in the sands 2012: A deeper look at major trends and opportunities in the oil sands sector. “Last time around [in 2007-08], this resulted in a labour shortage, with certain trades hit especially hard, and there was a significant switch of the risk to getting labour from engineering, procurement and construction to the owners. Oilsands projects will continue to be a talent drain.” According to the Petroleum Human Resources Council of Canada, the oilsands sector—which it estimates will have to hire up to 15,000 new workers between now and 2020—has challenges attracting qualified people because of its remote location, the competition for skilled labour when several large projects start at the same time, and the industry’s negative public image. SOLvENTS CONTINuE TO BE ALL THE RAGE FOR IN SITu PRODuCERS More and more in situ producers are piloting solvent-assisted SAGD projects. “Solvents are the next big thing in situ development,” says CAPP’s Stringham. “Almost every company is experimenting with it now.” Companies using solvents include Connacher Oil and Gas Ltd., Cenovus Energy, Japan Canada Oil Sands Ltd., Imperial Oil Limited and Suncor Energy. “Not only is it an effective tool for production, it’s also more environmentally responsible” since it reduces the amount of heat needed to mobilize the bitumen. Fortunately for the companies wanting to use solvents, a lot of natural gas exploration is being directed toward liquids-rich gas—especially in shale gas development—because those liquids are much more valuable than dry natural gas. Also, the design for in situ oilsands projects adding solvents is to recover as much as possible for reuse. “For the most part, once a company has its solvents, there isn’t much need for more of the stuff,” says Stringham. “There is an initial demand upfront and a certain need for makeup demand.”

NON-LABOuR COST INFLATION WILL STAy RELATIvELy LOW Labour may be the highest piece of oilsands project costs, but there are other inputs that can significantly alter the bottom line. CAPP’s Stringham notes three of the major the indicators that forecast nonlabour inf lation in the oilsands: the price of steel, the price of natural gas, and the cost and availability of capital. Each of those three now reads better than it did before the global crash. Steel is a globally priced commodity, and prices could spike rapidly (as they did in 2008) if there were sudden growth in some of the larger developing countries. At the moment, however, its price is roughly the same (US$600 per tonne) as it was in 2007. Natural gas, of course, is important as a fuel source. In 2007, natural gas was averaging between $5 –$7 per gigajoule, but according to the Natural Gas Exchange, has averaged approximately $3 per gigajoule since January 2010. The price has dropped and it’s stable.

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ALBERTA AND OTTAWA PLAN NEW ENvIRONMENTAL MONITORING The federal and Alberta governments announced in February 2012 new measures to improve environmental monitoring in oilsands areas. The three-year implementation plan begins this spring with increased sampling frequency, parameters and locations. It will also integrate relevant parts of existing monitoring efforts, and will give government and industry the scientific foundation necessary to continue to promote the environmentally sustainable development of the oilsands. The implementation plan ref lects the Integrated Oil Sands Environmental Monitoring Plan released by Environment Canada in 2011, and will be consistent with the Government of Alberta’s plans for a province-wide environmental monitoring system.

ALBERTA’S FIRST BRIK REFINERy LIKELy TO BE SANCTIONED After being delayed in 2008 due to strained economics, it looks like 2012 will be the year that North West Upgrading’s Redwater bitumen refinery will be sanctioned, processing volumes both from partner Canadian Natural as well as the Alberta government through its Bitumen Royalty in-Kind (BRIK) program. Detailed engineering for the first 50,000-barrel-per-day phase of the project began in the first quarter of 2011. Canadian Natural says, “Project development is dependent upon completion of detailed engineering and final project sanction by the partnership and approval of the final resulting tolls. Board sanction is currently targeted for 2012.” The $5-billion project would then be up and running by 2014, and although it is a new step for the province in deploying BRIK, it does not necessarily signal more Albertafed upgrading in the province. THREATS BuILD ON THE WAy TO THE B.C. COAST University of Alberta economist Andrew Leach says the biggest threats to the oilsands sector right now are not in its carbon footprint. Rather, he zeroes in on two problems closer to home: issues from First Nations communities and Canada’s endangered species legislation. Leach acknowledges that oilsands development has created a surge of employment in First Nations communities in the oilsands areas. However, there is a great deal of hostility towards the industry in aboriginal communities where there are no obvious economic benefits, for example along the proposed Gateway Pipeline right-of-way. (Another hot-button issue, of course, is the tanker traffic shipping “dirty oil” along the B.C. coast.) Those issues could stop the line, the regulatory review of which is currently under public comment.

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Plans for the Syncrude project, here under construction in 1977, were more than once in jeopardy before commercialization was realized in 1978.

FroM obSCurE TO ESSENTIAL heavy oil and oilsands come of age by gordon Jaremko

fter a long history of hard labour as the Cinderella in the bargain basement of the petroleum industry, heavy oil rules today. It eclipses the former darlings of the fossil fuel family, light crude and natural gas, as the engine of growth in the 2011 edition of a 25-year forecast done periodically by the National Energy Board (NEB), Canada’s Energy Future: Energy Supply and Demand Projections to 2035. The “reference case,” or scenario rated as most likely to come true, is a paint-by-numbers portrait of the greatest investordriven oil production prospect outside the Organization of the Petroleum Exporting Countries. The picture draws on business intentions and immensely detailed annual reserves reports by Alberta’s Energy Resources Conservation Board (ERCB). Canadian output is expected to double, reaching six million barrels per day as of 2035. In all its forms—from wells with pumps that strain to pull up molasses-like flows to bitumen mine and upgrader complexes that manufacture premium synthetic crude—heavy oil is forecast to grow to 5.4 million barrels per day or nine-tenths of the national total from the current two million barrels per day or two-thirds. Alberta’s 140,200 square kilometres of oilsands resources are the growth mainstay. Even after making allowances for project delays or cancellations, production is expected to more than triple to five million barrels per day as of 2035 from the current 1.6 million barrels per day. Within the heavy oil product line, the premium-value top item, upgraded synthetic crude, is forecast

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to grow, but at a slower pace that lags the overall total expansion due to less-favourable cost and price trends than the outlook for raw bitumen. Upgraded output is expected to about double to 1.9 million barrels daily in 2035 from the current 887,000 barrels per day. Heavy oil is no overnight success. No Alberta resource has a longer pedigree or more checkered record of striving to grow up into a product. The fur trade was at its height and the Victorian-era British princess that Alberta was eventually named after had not even been born yet at the time of the first recorded sighting of the oilsands. A Cree rover called Wa-Pa-Sun carried a bitumen sample east to the York Factory outpost of the Hudson’s Bay Company, where agent Henry Kelsey made a note of it in his official journal. More mentions occurred in the diaries of 18th-century northern explorers Peter Pond and Alexander Mackenzie. As a trade item, bitumen has a history dating back to the ancient Egyptian pharaohs, with uses ranging from preserving the dead as mummies to folk medicine and waterproofing boats and canoes. The first description of the oilsands by a scientist—chemist John Richardson, a member of an 1848 overland search party seeking the lost polar expedition of Sir John Franklin— included an observation of the resource’s potential to be a hazard. While crossing the future bitumen-mining district north of Fort McMurray, Alta., Richardson recorded in his diary that “a copious spring of mineral pitch issues from a crevice in a cliff composed of sand and bitumen. It lies a few hundred yards back

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ignited an exploration campaign that spread across the Albertafrom the river in the middle of a thick wood. Several small birds Saskatchewan borderlands, with numerous discoveries inspiring were found suffocated in the pitch.” Like every other aspect of homegrown companies to keep the drilling going through the the oilsands, from microscopic clay “fines” in geological water Great Depression of the 1930s. associated with the ore to sandpaper-like abrasive action of its By 1934, Lloydminster had natural gas service. The disknife-edged quartz grains on steel industrial hardware, the trict sprouted two oil refineries: Excelsior in the town and environmental peril noted by Richardson spawned generations Dina, about 40 kilometres to the south, near Wainwright, Alta. of technology development. Lloydminster had one of the first main drags paved with asphalt Only 10 years after Richardson’s observation, the first comin western Canada. Black smoke rose over the town from a mercial oil well in North America launched the Canadian refinery waste incineration pit every day except Monday, which industry near Sarnia, in southwestern Ontario. By the time the plant voluntarily recognized as Wash Day by stopping the Alberta became a province at the dawn of the 20th century, oil burning long enough to let households dry their laundry clean had its modern image as black gold and inspired feats of techon outdoor clotheslines. Farmers in the district built fences nical and economic daring. with discarded drill pipe. Stores posted entrance signs at their A monument to the exploration era—and especially the magentrances saying “Please remove oily footwear.” netic attraction of Alberta’s northern heavy oil regions—greets Large-scale development began in 1946 with the arrival of visitors at an outdoor shrine to industry pioneers in a secluded Husky Oil Ltd., then an American-owned production and refinsouthwestern Edmonton ravine. A wooden derrick marks the ing empire based in Cody, Wyo. The company led a mini-boom entrance to the Edmonton Oilfield Technical Society’s nine-acre in supplying the railways with heavy crude, barely refined into private OTS Park. thick bunker oil akin to steamship fuel. The stuff only had to The structure is a reconstructed cable-tool drilling rig that heat boilers and not work as an instant explosive mist when entrepreneur A.F.A. Coyne and his Northern Production Co. Ltd. mixed with air to drive the rapidly moving pistons of interimported from Pennsylvania, then hauled in pieces 400 kilonal combustion engines. Bunker oil was a technical advance metres north to the Fort McMurray area. The enterprise took from 1915 through 1918 to assemble the rig beside the Athabasca at first, as a cleaner and more efficient replacement for coal in steam locomotives. The gravy train lasted until the railways conRiver and pound a well into the ground with the cable-tool verted to diesel engines in the late 1950s, enlarging demand for machinery, which worked like a piledriver. The epic effort was fuelled by a common theory of the pioneer era that black gold lay the higher-value light oil discovered south of Calgary at Turner in pools beneath the bitumen ore at a depth of about 190 metres. Valley, Alta., in 1936 and southwest of Edmonton at Leduc, Alta., in 1947. Husky and other heavy oil producers devised Only a puddle of such “free oil” was found. The firm went broke. blends and opened up niche markets that kept their specialty The deserted rig collapsed and bush grew over it until indusalive while it was eclipsed by abundant light crude through the try veterans Stan Kondratiuk and Fin Lineham retrieved it in the 1950s, ’60s and ’70s. 1970s using a metal detector, trucks, helicopters, and cash and services donated by numerous companies. The sight teaches heavy oil is no overnight success. no alberta resource has a longer a lesson about oil, OTS Park director Barry Moore said in an pedigree or more checkered record of striving to grow up into a product. interview: “It doesn’t come easy or cheap.” Construction of two plants in the late 1980s, Husky’s Variations on the same theme are taught by exhibits and oral Biprovincial Upgrader at Lloydminster and the Co-op Upgrader history memoirs preserved by the Heavy Oil Science Centre at Regina, set off the modern wave of conventional heavy oil in Lloydminster. The city, east of Edmonton on the Albertadevelopment. As in the pioneer discoveries, technology was not Saskatchewan boundary, has been the capital of conventional the only force at play in creating a new market by building capacheavy crude drilling in both provinces for almost a century. ity to manufacture heavy crude into a suitable product for fuel Among the lessons taught by the centre is that primitive technoland lubricant refineries. Both upgrading projects were deemed ogy and rudimentary earth sciences did not invariably end in failure. to be matters of high public interest in fostering resource and Lady luck played a big role in the pioneer era of the energy industry. regional economic development. The Saskatchewan government In the absence of seismic surveys and computer simulapaid half the price of the $700-million Regina plant by taking on tions of geological formations, fussy cattle sniffed out the path 50 per cent ownership. The federal, Alberta and Saskatchewan to the discovery that launched conventional heavy oil developgovernments shared majority ownership of the Lloydminster ment with flowing wells and rocking-horse pumpjacks. When project and poured in $1.2 billion or 75 per cent of its costs. In his livestock turned up their noses and refused to drink from a both cases, the governments sold their interests to industry after well that Charles Marren dug to a depth of 48 metres on his farm construction was completed and early operations worked bugs 16 kilometres south of Lloydminster in 1926, he and his neighout of their systems. bours sent the water to chemists at the University of Alberta for The ensuing wave of drilling and production growth analysis. After laboratory tests showed the well had accidentally spawned technology that gave the heavy oil region a new landrun into oil, the farmer and his friends created the Marrenmark: spinning tops of a potent extraction device known as the Lloydminster Oil and Gas Company Ltd., raised $100,000 and

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as of 2015, the nEb predicts in situ methods of tapping the four-fifths of the oilsands that are too deep to mine will emerge as a growing majority of production. progressing cavity pump. The hardware replaced pumpjacks and sucker rods with steel poles that resemble corkscrews, but use a more sophisticated method than mechanical lifting on augerlike circular ramps. The devices work like super vacuum cleaners with suction that overcomes gravity by rotating precisionengineered shapes. The force lifts sand out of the ground with the crude, in turn spawning innovations and growth businesses in separating and disposing of oily waste in environmentally acceptable ways. At its peak in 2003, conventional heavy oil production hit 917,700 barrels per day, NEB records show. Despite gradual depletion of wells as they age, output is projected to continue for the next quarter-century and still be 530,100 barrels daily in 2035. On the growth side of the heavy crude spectrum, the oilsands, the vigour foreseen by the NEB and ERCB fulfills a prophecy by the Edmonton scientist who invented the original process for bitumen extraction using hot water. Karl Clark predicted a giant future for the biggest but crudest item in Alberta’s resource endowment at the time that it most seemed to be doomed by better luck elsewhere. He had his vision when the Leduc discovery of the most valuable naturally occurring fossil fuel, freely flowing light oil, was less than three years old. “Many people consider that the finding of oilfields in the province eliminates any chance of bituminous sand development in the foreseeable future,” Clark acknowledged in correspondence dated Jan. 20, 1950. “I do not think this is so. In fact, I figure that it is quite otherwise,” he wrote. The document is preserved by his daughter Mary Clark Sheppard in her book Athabasca Oil Sands: From Laboratory to Production: The Letters of Karl A. Clark, 1950-66. His patent on the production process was 11 years old. The beginning of operations by the first commercial plant was still 17 years off. But Clark saw a wide road ahead into a colossal future for the northern Alberta bitumen belt, with conventional black gold paving the way. He predicted: “Great volumes of oil will be produced. This will have to get to more than a local market. Bituminous sands development depends on pipelines to outside marketing areas. If there had been no oil discoveries and a bituminous sand development had to shoulder the construction of pipelines as well as its own mining and extracting job, I think the development would be in the distant future. But the oilfields are presenting the bituminous sands with a pipeline system to make use of. Any time that the cost of producing oil from the bituminous sands is such as to show a profit, the stage is now or soon will be set for the development to start.” Oilsands schemes rolled up to the industrial starting gate while Alberta still had more conventional black gold than the pipelines could take. Projects had to fight for delivery capacity that was divvied up by an ERCB market-sharing regime, “prorationing.”

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

The first commercial mining and upgrading complex, Great Canadian Oil Sands Limited, only made it into production in 1967 by limiting its size to a ceiling that the premier, Ernest Manning, set after long regulatory and political duels: five per cent of total Alberta output, or 45,000 barrels per day. The Syncrude Canada Ltd. project was older, but had to settle for second place in the development lineup because it sought elbow room for 100,000 barrels per day. After waiting for ERCB approval until 1969, Syncrude also had to delay construction in order to fit into provincial oil supply and demand forecasts. The ruling included a rare board split. The majority under chairman George Govier set a three-year postponement, while future chairman Vern Millard dissented by interpreting the economic projections as requiring a longer wait. Skeptical companies in the industry majority held back from replacing a partner that dropped out while Syncrude was under construction in 1974. The Alberta, federal and Ontario governments filled the gap by taking on part ownership and providing loans and grants. By the time production started in 1978, rising costs, adverse energy policies and unpredictable upheavals on the global oil market discouraged any further new developments. Activity focused on making the first two complexes economical. They gradually raised output to spread costs thinner. They made technical advances on a large scale from increasingly computerized control systems to replacing imported mine bucket-wheels, draglines and conveyor belts with rugged, simpler trucks and shovels more suited to the ore and northern conditions. It took a quarter-century for the Athabasca Oil Sands Project (AOSP) to start up the third Fort McMurray mine in 2003 and another five years for Horizon to become the fourth. Innovations ranged from cost- and emissions-cutting reductions in the operating temperature of the production process to building the AOSP synthetic crude upgrading plant near Edmonton, in a more economical location than the subarctic climate and muskeg swamps of northeastern Alberta. The lone exception to the long oilsands project lull pioneered a new business strategy as well as technology. The Cold Lake development went into action in the mid-1980s after a ’70s megaproject version was divided into less-costly stages. By gradually growing in profitable phases through the ’80s, ’90s and early 2000s, Cold Lake established reliability and economic respectability for “in situ” or underground bitumen extraction with steam pumped into the ore. As of 2015, the NEB predicts in situ methods of tapping the four-fifths of the oilsands that are too deep to mine will emerge as a growing majority of production. This article was originally published in the commemorative volume celebrating the 25th anniversary of the Canadian Heavy Oil Association in 2011.

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productIon

Photo: JoEy Podlubny

production

INTrODuCTION A new boom

MINING

IN SITu

ExPErIMENTAl

OPErATING DATA

uNDEr CONSTruCTION

EMErGING PrODuCErS

PrOJECT STATuS

PrOJECT COSTS

INTErNATIONAl INVESTMENT

I N T R O d u C T I O N

boom A new

oilsands investment projected to reach record levels in 2012 by deborah Jaremko Order

Operator

Project

Operating cOmmercial Oilsands prOjects—mining 1 Suncor Energy Inc. Base Operations 2/3 Syncrude Canada Ltd. Mildred Lake/Aurora North 4/5 Shell Albian Sands Muskeg River/Jackpine 6 Canadian Natural Resources Limited Horizon Operating cOmmercial Oilsands prOjects—in situ 8 Canadian Natural Resources Limited Primrose/Wolf Lake 9/10 Cenovus Energy Inc. Christina Lake/Foster Creek 11/12 Connacher Oil And Gas Limited Great Divide/Algar 13 ConocoPhillips Canada Limited Surmont 14/15 Devon Canada Corporation Jackfish 1/Jackfish 2 16 Husky Energy Inc. Tucker 17 Imperial Oil Limited Cold Lake 18 Japan Canada Oil Sands Limited Hangingstone 19 MEG Energy Corp. Christina Lake 20 Nexen Inc. Long Lake 21/22 Royal Dutch Shell plc Orion/Peace River 23 Statoil Canada Ltd. Leismer 24/25 Suncor Energy Inc. Firebag/MacKay River Operating Oilsands upgraders—athabasca regiOn 26 Suncor Energy Inc. Base Operations 27 Syncrude Canada Ltd. Mildred Lake 28 Canadian Natural Resources Limited Horizon 29 Nexen Inc. Long Lake Operating Oilsands upgraders—industrial heartland regiOn 30 Shell Canada Limited Scotford Operating experimental Oilsands prOjects—in situ 7 BlackPearl Resources Inc. Blackrod 31 Athabasca Oil Sands Corp. Dover West Leduc Carbonates 32 Cenovus Energy Inc. Pelican Lake Grand Rapids 33 E-T Energy Ltd. Poplar Creek 34 Laricina Energy Ltd. Saleski 35 Sunshine Oilsands Ltd. Harper 36 Pengrowth Corporation Lindbergh SAGD 37 Baytex Energy Corp. Cliffdale/Harmon Valley 38 Southern Pacific Resource Corp. Red Earth Editor’S notE: because december 2011 data was unavailable at press time, January-november production is shown for comparative purposes for mining projects beginning on page 32, in situ projects beginning on page 38 and upgrader projects beginning on page 120.

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

anada’s oilsands sector—and indeed, the country’s entire oil and gas industry—is headed for record capital investment in 2012, according to the Canadian Association of Petroleum Producers (CAPP) and data collected by JuneWarrenNickle’s Energy Group. But the oilsands specifically is nearing the limits of comfortable development without high inflationary pressures, says Martyn Griggs, CAPP’s manager, oilsands. CAPP is forecasting approximately $20 billion in new oilsands capital investment this year, and Griggs says that while the spend could be greater, increases will come with additional challenges, particularly around labour. “I think $20 billion is now a record. It certainly has been climbing since we had the financial downturn in 2007 and 2008,” he says. “The maximum I ever got to for all of oil and gas, including oilsands, was $50 billion, and for 2012 I’m now showing that number to be $55 billion.” CAPP forecasts capital expenditures through tracking of company disclosures and surveys of its membership, as well as analysis of government-run statistics such as Statistics Canada’s summaries of past spend rates. “We don’t go project by project or company by company. We tend to say, ‘Look, what does the market bear? What’s the availability of labour out there….’ We’ve been spending $17 [billion] or $18 billion in prior years, and it was $19 billion in 2011. Where do we see the run rates going in the future—is it going to be significantly more or something similar? Right now we see the burn rate to be very similar to prior years, maybe with a slight increase,” Griggs says. “If you add up all the [plans of] individual companies, you’ll probably come to a number quite significantly bigger,

I N T R O d u C T I O N

productIon

position in the next year or two,” says Griggs. “Are we at the limit of capacity? The oil and gas industry and oilsands in particular will find a way of getting the people it needs, so if the burn rate was to, say, exceed $20 billion, let’s say to $21 billion, that’s a five per cent increase. You’ve got to get the people and the materials from somewhere, so you’ll probably start looking outside of Alberta. And that’s when the inflationary issues will start coming into play because you’re trying to bring people in, whether it’s from the U.S. or even further afield. I wouldn’t say that you’ve hit a ceiling. There is no ceiling, but it becomes that much more difficult to spend over and above $20 [billion] to $21 billion in the short term, i.e., the next 10–12 months, without causing disruption to the broader economy.”

because each company has its blinker view of the world, of what they’re going to achieve. In reality, the market probably can’t build $30 billion a year because there simply aren’t the resources out there to do it. The ones that have their contracts in place are more likely to go ahead.” The unemployment rate in Alberta is currently about 4.9 per cent, which equates to near-full employment, he points out, adding that the oilsands industry is already stretched in some areas such as engineering and trade skills. However, other sectors in the province, such as hospitality and agriculture, are not yet experiencing the major challenges they did during the last energy boom in 2005-06. “If the [capital spend] rate increases significantly, then we could end up being in that same

Operating oilsands projects 6

28 2

5 27

FORT MCMURRAY

22 37 32

PEACE RIVER

ALBERTA

23 19

CONKLIN

Oilsands Deposit Inferred Oilsands Deposit

SASKATCHEWAN

15 10

Heavy Oil Deposit Grosmont Carbonate Triangle

LAC LA BICHE

First Nations

Metis Settlement National Park

Provincial Park

BONNYVILLE 30

COLD LAKE

EDMONTON LLOYDMINSTER

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

M I N I N g

Photo: JoEy Podlubny

SunCOr

MAP REFERENCE

Project

Suncorâ&#x20AC;&#x201D;Base and Millennium

Location

North Athabasca

Ownership

Suncor Energy Inc. 100%

Production start

1967

Average total volume to bitumen in place

8.1:1

Average ore grade (weight %)

11.61

Average strip ratio

1.3:1

Current production capacity

321,000

Average daily bitumen production Jan.-Nov. 2011 (bbl/d)

261,604

Average daily bitumen production Jan.-Nov. 2010 (bbl/d)

239,448

Year-to-date barrels mined (Jan.-Nov. 2011)

1,071,960,794

Year-to-date barrels mined (Jan.-Dec. 2010)

941,114,826

200,000 150,000

Monthly average mined ore grade (weight % Jan.-Nov. 2011)

11.42

100,000

Monthly average mined ore grade (weight % Jan.-Nov. 2010)

11.91

50,000

2011 average realized price per bbl

See stats for Suncor upgrader

2010 average realized price per bbl

See stats for Suncor upgrader

Suncor is currently implementing a new tailings management technology across its operations. Known as tailings reduction operations, the technique allows for tailings to dry and be ready for reclamation over a span of weeks rather than decades.

PRODUCTION

2009

2010

2011

450,000 400,000 350,000 300,000

(bbls/d)

250,000

Jan

Feb

Mar

Apr

May

SourCE: EnErgy rESourCES ConSErVation board

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

Jun

Jul

Aug

Sep

Oct

Nov

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M I N I N g

Photo: JoEy Podlubny

MAP REFERENCE

MILDRED LAkE

SynCrude

MAP REFERENCE

Syncrude is budgeting $4.5 billion for the replacement and relocation of four of its five mine trains in order to start reclaiming the mine pits in which this equipment sits. The project is expected to be complete in 2014.

Au R O R A N O R t h

Project

Syncrude

Location

North Athabasca

Ownership

Canadian Oil Sands Limited (36.74%), Imperial Oil Resources Limited (25%), Suncor Energy Inc. (12%), Sinopec Oil Sands Partnership (9.03%), Nexen Oil Sands Partnership (7.23%), Mocal Energy Limited (5%), Murphy Oil Ltd. (5%).

Production start PRODUCTION

2009

2010

2011

450,000 400,000

1978

Average total volume to bitumen in place

North Mine: 7.2, Aurora North: 7.2, Aurora South: 8

Average ore grade (weight %)

North Mine: 11, Aurora North: 11.4, Aurora South: 11

Average strip ratio

North mine: 1.5, Aurora North: 0.8, Aurora South: 0.9

350,000

Current production capacity (bbl/d)

407,000

300,000

Average daily production Jan.-Nov. 2011 (bbl/d)

317,548

Average daily production Jan.-Nov. 2010 (bbl/d)

318,071

250,000

Year-to-date barrels mined (Jan.-Nov. 2011)

1,366,470,262

200,000

Year-to-date barrels mined (Jan.-Nov. 2010)

1,373,089,281

150,000

Monthly average mined ore grade (weight % Jan.-Nov. 2011)

Mildred Lake 10, Aurora 11.01

Monthly average mined ore grade (weight % Jan.-Nov. 2010)

Mildred Lake 10.52, Aurora 11.02

2011 average realized price per bbl

See stats for Syncrude upgrader

2010 average realized price per bbl

See stats for Syncrude upgrader

100,000

(bbls/d)

50,000 0

Jan

Feb

Mar

Apr

May

SourCE: EnErgy rESourCES ConSErVation board

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

Jun

Jul

Aug

Sep

Oct

Nov

M I N I N g

Photo: JoEy Podlubny

productIon

MAP REFERENCE

MuSk E g R I v ER

AthAbASCA Oil SAndS PrOjeCt Project

Athabasca Oil Sands Project

Location

North Athabasca

Ownership

Shell Canada Limited 60%, Chevron Corporation 20%, Marathon Oil Corporation 20%

Production start

2002

Average total volume to bitumen in place

Muskeg River 7:1, Jackpine 7.2:1

Average ore grade (weight %)

Muskeg River 11.4, Jackpine 10.4

Average strip ratio

Muskeg River 0.7:1, Jackpine 0.6:1

Current production capacity

255,000

Average daily bitumen production Jan.-Nov. 2011 (bbl/d)

192,112

Average daily bitumen production Jan.-Nov. 2010 (bbl/d)

118,205

Year-to-date barrels mined (Jan.-Nov. 2011)

849,764,019

Year-to-date barrels mined (Jan.-Nov. 2010)

566,908,672

Monthly average ore grade (weight % Jan.-Nov. 2011)

Muskeg River 10.56, Jackpine 12.56

Monthly average ore grade (weight % Jan.-Nov. 2010)

Muskeg River 11.45, Jackpine 13.07

2011 average realized price per bbl

See stats for Scotford upgrader

2010 average realized price per bbl

See stats for Scotford upgrader

MAP REFERENCE

Shell commissioned a 100,000-barrel-per-day expansion of its Albian Sands operations at the new Jackpine mine in fall 2010 and is now ramping up to full capacity.

JAC k PI N E

PRODUCTION

2009

2010

2011

250,000 225,000 200,000 175,000 150,000 125,000 100,000 75,000 50,000 (bbls/d)

25,000 0

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

SourCE: EnErgy rESourCES ConSErVation board

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

M I N I N g

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

hOrizOn

Photo: JoEy Podlubny

MAP REFERENCE

M I N I N g

productIon

A major fire at the Horizon upgrader in January 2011 resulted in zero bitumen and synthetic oil production between February and August. Canadian Natural reported a return to full production rates in September.

Project

horizon

Location

North Athabasca

Ownership

Canadian Natural Resources Limited 100%

Production start

2008

Average total volume to bitumen in place

10.3:1

Average ore grade (weight %)

10.8

Average strip ratio

1.2:1

Current production capacity

135,000

Average daily bitumen production Jan.-Nov. 2011 (bbl/d)

37,579

Average daily bitumen production Jan.-Nov. 2010 (bbl/d)

99,960

Year-to-date barrels mined (Jan.-Nov. 2011)

168,841,668

Year-to-date barrels mined (Jan.-Nov. 2010)

420,124,975

Monthly average ore grade (weight % Jan.-Nov. 2011)

11.15

Monthly average ore grade (weight % Jan.-Nov. 2010)

10.34

40,000

2011 average realized price per bbl

See stats for horizon upgrader

20,000

2010 average realized price per bbl

See stats for horizon upgrader

PRODUCTION

2009

2010

2011

180,000 160,000 140,000 120,000 100,000 80,000

(bbls/d)

60,000

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

SourCE: EnErgy rESourCES ConSErVation board

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h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

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Photo: JoEy Podlubny

COld lAKe

17 MAP REFERENCE

The Cold Lake project achieved record average production rates in 2011 due to contributions from new wells steamed in 2010 and 2011, technology application and the projectâ&#x20AC;&#x2122;s cyclic nature.

PRODUCTION

2009

2010

2011

180,000 160,000 140,000 120,000 100,000 80,000 60,000 40,000

(bbls/d)

20,000 0

Jan

Feb

Mar

Apr

May

SourCE: EnErgy rESourCES ConSErVation board

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

Jun

Jul

Aug

Sep

Oct

Nov

Project

Cold Lake

Location

Cold Lake

Ownership

Imperial Oil Limited 100%

Production start

1985

Formation/pool

Clearwater

Average reservoir depth

400 m

technology

Cyclic steam stimulation

Current production capacity (bbl/d)

140,000

Average daily production Jan.-Nov. 2011 (bbl/d)

159,706

Average daily production Jan.-Nov. 2010 (bbl/d)

144,000

Average water production per calendar day Jan.-Nov. 2011 (bbl/d)

549,956

Average water production per calendar day Jan.-Nov. 2010 (bbl/d)

489,321

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2011)

3,270/4,461

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2010)

3,181/4,454

Monthly average steam to oil ratio Jan.-Nov. 2011

3.42:1

Monthly average steam to oil ratio Jan.-Nov. 2010

3.63:1

2011 average realized price per bbl

$105

2010 average realized price per bbl

$59

I N

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Photo: JoEy Podlubny

productIon

PriMrOSe/WOlF lAKe Project

Primrose/Wolf Lake

Location

South Athabasca, Cold Lake

Ownership

Canadian Natural Resources Limited 100%

Production start

1985

Formation/pool

Clearwater, upper grand Rapids

Average reservoir depth

450 m

technology

Cyclic steam stimulation

Current production capacity (bbl/d)

120,000

Average daily production Jan.-Nov. 2011 (bbl/d)

97,880

Average daily production Jan.-Nov. 2010 (bbl/d)

84,229

Average water production per calendar day Jan.-Nov. 2011 (bbl/d)

266,445.2

Average water production per calendar day Jan.-Nov. 2010 (bbl/d)

250,212

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2011)

807/958

80,000

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2010)

743/912

60,000

Monthly average steam to oil ratio Jan.-Nov. 2011

3.95:1

Monthly average steam to oil ratio Jan.-Nov. 2010

4.22:1

2011 average realized price per bbl

n/q

2010 average realized price per bbl

n/q

MAP REFERENCE

Canadian Natural says that Primrose achieved record quarterly production of approximately 110,000 barrels per day in the fall of 2011, due to continued pad additions, excellent overall performance in the quarter, and the nature of the steaming and production cycles. PRODUCTION

2009

2010

2011

180,000 160,000 140,000 120,000 100,000

40,000

(bbls/d)

20,000 0

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

SourCE: EnErgy rESourCES ConSErVation board

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

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Photo: JoEy Podlubny

PeACe riVer

MAP REFERENCE

Shell has long planned an expansion of the Peace River in situ project, called Carmon Creek. The company recently re-submitted an adjusted application, and in late 2011 the environmental impact assessment for Carmon Creek was deemed completeâ&#x20AC;&#x201D;an important step in the regulatory process.

PRODUCTION

2009

2010

2011

9,000

Location

Peace River

Ownership

Shell Canada Limited 100%

Production start

1986

Formation/pool

Bluesky-gething

Average reservoir depth

550 m

technology

Cyclic steam stimulation

Current production capacity (bbl/d)

12,500

Average daily production Jan.-Nov. 2011 (bbl/d)

4,489

Average daily production Jan.-Nov. 2010 (bbl/d)

7,075

7,000

Average water production per calendar day Jan.-Nov. 2011 (bbl/d)

20,002

Average water production per calendar day Jan.-Nov. 2010 (bbl/d)

23,835

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2011)

77/115

4,000 3,000

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2010)

80/115

2,000

Monthly average steam to oil ratio Jan.-Nov. 2011

7.16:1

Monthly average steam to oil ratio Jan.-Nov. 2010

4.54:1

2011 average realized price per bbl

n/q

2010 average realized price per bbl

n/q

5,000

(bbls/d)

Peace River

8,000

6,000

1,000 0

Jan

Feb

Mar

Apr

May

SourCE: EnErgy rESourCES ConSErVation board

Project

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

Jun

Jul

Aug

Sep

Oct

Nov

We seek opportunities to learn, share, and contribute toward creative solutions ThereÂ´s never been a better time for good ideas.

I N

S I T u

Photo: JaPan Canada oil SandS

hAnGinGStOne

18 MAP REFERENCE

Reports indicate that JACOS owner Japan Petroleum Exploration is delaying an investment decision on a proposed 35,000-barrel-per-day expansion at Hangingstone (owned 75 per cent by JACOS and 25 per cent by Nexen Inc.) until mid-2012 due to a delay in regulatory approval.

PRODUCTION

2009

2010

2011

Project

hangingstone

Location

South Athabasca

Ownership

Japan Canada Oil Sands Limited (JACOS) 100%

Production start

1999

Formation/pool

Wabiskaw-McMurray

Average reservoir depth

280â&#x20AC;&#x201C;310 m

technology

Steam assisted gravity drainage

9,000

Current production capacity (bbl/d)

10,000

8,000

Average daily production Jan.-Nov. 2011 (bbl/d)

6,555

7,000

Average daily production Jan.-Nov. 2010 (bbl/d)

7,045

6,000

Average water production per calendar day Jan.-Nov. 2011 (bbl/d)

25,919

5,000

Average water production per calendar day Jan.-Nov. 2010 (bbl/d)

26,700

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2011)

40/44

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2010)

38/41

Monthly average steam to oil ratio Jan.-Nov. 2011

4.23:1

Monthly average steam to oil ratio Jan.-Nov. 2010

3.99:1

2011 average realized price per bbl

n/q

2010 average realized price per bbl

n/q

4,000 3,000

(bbls/d)

2,000 1,000 0

Jan

Feb

Mar

Apr

May

SourCE: EnErgy rESourCES ConSErVation board

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

Jun

Jul

Aug

Sep

Oct

Nov

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Photo: CEnoVuS EnErgy

productIon

FOSter CreeK Project

Foster Creek

Location

South Athabasca

Ownership

Cenovus Energy Inc. 50%, ConocoPhillips Canada 50%

Production start

2001

Formation/pool

Wabiskaw-McMurray

Average reservoir depth

450 m

technology

Steam assisted gravity drainage

10 MAP REFERENCE

As of the end of 2011, about 11 per cent of production at Foster Creek was coming from Cenovus’ “wedge well” technology, essentially infill wells between SAGD steam chambers that access stranded but mobilized oil. The technology is designed to increase production without adding steam. PRODUCTION

2010

2009

2011

180,000

Current production capacity (bbl/d)

120,000

Average daily production Jan.-Nov. 2011 (bbl/d)

109,719

160,000

Average daily production Jan.-Nov. 2010 (bbl/d)

101,660

140,000

Average water production per calendar day Jan.-Nov. 2011 (bbl/d)

249,654

Average water production per calendar day Jan.-Nov. 2010 (bbl/d)

222,258

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2011)

337/378

80,000

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2010)

308/337

60,000

Monthly average steam to oil ratio Jan.-Nov. 2011

2.15:1

Monthly average steam to oil ratio Jan.-Nov. 2010

2.26:1

2011 average realized price per bbl

n/q

2010 average realized price per bbl

n/q

120,000 100,000

40,000

(bbls/d)

20,000 0

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

SourCE: EnErgy rESourCES ConSErVation board

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

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Photo: JoEy Podlubny

MACKAy riVer

25 MAP REFERENCE

Project

Mackay River

Location

North Athabasca

Ownership

Suncor Energy Inc. 100%

Production start

2002

Formation/pool

Wabiskaw-McMurray

Average reservoir depth

150 m

technology

Steam assisted gravity drainage

Current production capacity (bbl/d)

33,000

Average daily production Jan.-Nov. 2011 (bbl/d)

29,871

40,000

Average daily production Jan.-Nov. 2010 (bbl/d)

31,323

35,000

Average water production per calendar day Jan.-Nov. 2011 (bbl/d)

66,133

30,000

Average water production per calendar day Jan.-Nov. 2010 (bbl/d)

72,461

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2011)

112/121

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2010)

114/116

Monthly average steam to oil ratio Jan.-Nov. 2011

2.16:1

Monthly average steam to oil ratio Jan.-Nov. 2010

2.41:1

2011 average realized price per bbl

See stats for Suncor upgrader

2010 average realized price per bbl

See stats for Suncor upgrader

Late in 2011, Suncor says it commenced production from a new phase of six wells at MacKay River and initiated steam injection into additional wells. The company says that future production from these new wells, combined with ongoing well workovers, is expected to offset natural production declines.

PRODUCTION

2009

2010

2011

45,000

25,000 20,000 15,000

(bbls/d)

10,000 5,000 0

Jan

Feb

Mar

Apr

May

SourCE: EnErgy rESourCES ConSErVation board

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

Jun

Jul

Aug

Sep

Oct

Nov

Driven by PeoPle… You’ll see our drive and commitment across the prairies, from start to finish and every point in-between.

Bonnyville 780.826.4565 Calgary 403.777.1644 Fort McMurray 780.790.0279 lloydMinster 780.808.9123 spruCe grove 780.962.1600

Fuelled by integrity… Powered by commitment. ENTREC has a strong track record in the safe transportation (over the road and on-site), loading, off-loading, setting and rigging of overweight and oversized cargo for western Canada’s oil and gas industry. We are committed to providing exceptional customer service with a renewed focus on operational excellence while providing the most cost-effective and safe transportation solutions for each and every client. With branches strategically located in western Canada, ENTREC is well-positioned to meet your most challenging heavy haul needs.

safety and service people and communities respect and integrity

For more information visit our website at entrec.com or email to info@entrec.com. ENTREC is publically traded on the TSX-V:ENT.

I N

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Photo: CEnoVuS EnErgy

ChriStinA lAKe/CenOVuS enerGy

MAP REFERENCE

Cenovus Energy achieved first oil from its 40,000-barrel-per-day Phase C expansion at Christina Lake in the third quarter of 2011, ahead of its original schedule.

Christina Lake

Location

South Athabasca

Ownership

Cenovus Energy Inc. 50%, ConocoPhillips Canada 50%

Production start

2003

Formation/pool

Wabiskaw-McMurray

Average reservoir depth

400 m

technology

Steam assisted gravity drainage

Current production capacity (bbl/d)

58,800

Average daily production Jan.-Nov. 2011 (bbl/d)

20,284

Average daily production Jan.-Nov. 2010 (bbl/d)

14,654 47,487

30,000

Average water production per calendar day Jan.-Nov. 2011 (bbl/d)

25,000

Average water production per calendar day Jan.-Nov. 2010 (bbl/d)

32,473

20,000

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2011)

45/47

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2010)

31/31

Monthly average steam to oil ratio Jan.-Nov. 2011

2.3:1

Monthly average steam to oil ratio Jan.-Nov. 2010

2.08:1

2011 average realized price per bbl

$61.86

2010 average realized price per bbl

$57.96

PRODUCTION

2009

2010

2011

45,000 40,000 35,000

15,000

(bbls/d)

10,000 5,000 0

Jan

Feb

Mar

Apr

May

SourCE: EnErgy rESourCES ConSErVation board

Project

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

Jun

Jul

Aug

Sep

Oct

Nov

I N

S I T u

Photo: JoEy Podlubny

productIon

ChriStinA lAKe/MeG enerGy Project

Christina Lake

Location

South Athabasca

Ownership

MEg Energy Corp. 100%

Production start

2003

Formation/pool

Wabiskaw-McMurray

Average reservoir depth

350 m

technology

Steam assisted gravity drainage

Current production capacity (bbl/d)

25,000

45,000

Average daily production Jan.-Nov. 2011 (bbl/d)

26,043

40,000

Average daily production Jan.-Nov. 2010 (bbl/d)

20,417

Average water production per calendar day Jan.-Nov. 2011 (bbl/d)

66,133

Average water production per calendar day Jan.-Nov. 2010 (bbl/d)

45,944

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2011)

69/71

20,000

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2010)

60/68

15,000

Monthly average steam to oil ratio Jan.-Nov. 2011

2.48:1

Monthly average steam to oil ratio Jan.-Nov. 2010

2.68:1

2011 average realized price per bbl

$67

2010 average realized price per bbl

$51

19 MAP REFERENCE

Construction continues on MEGâ&#x20AC;&#x2122;s 35,000-barrel-per-day Phase 2B at Christina Lake. In late 2011, Alberta regulators also issued approval for Phase 3, a 150,000-barrel-per-day multistage expansion.

PRODUCTION

2009

2010

2011

35,000 30,000 25,000

(bbls/d)

10,000 5,000 0

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

SourCE: EnErgy rESourCES ConSErVation board

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

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Photo: SunCor EnErgy

FirebAG

24 MAP REFERENCE

Suncor achieved first production from the 62,500-barrel-per-day Stage 3 expansion in early July 2011. Volumes are expected to ramp up through 2012.

PRODUCTION

2009

2010

2011

90,000

Firebag

Location

North Athabasca

Ownership

Suncor Energy Inc. 100%

Production start

2004

Formation/pool

Wabiskaw-McMurray

Average reservoir depth

320 m

technology

Steam assisted gravity drainage

Current production capacity (bbl/d)

157,500

Average daily production Jan.-Nov. 2011 (bbl/d)

57,858.5

80,000

Average daily production Jan.-Nov. 2010 (bbl/d)

53,406

70,000

Average water production per calendar day Jan.-Nov. 2011 (bbl/d)

199,772.7

60,000

Average water production per calendar day Jan.-Nov. 2010 (bbl/d)

165,392

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2011)

99/105

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2010)

79/81

Monthly average steam to oil ratio Jan.-Nov. 2011

3.56:1

Monthly average steam to oil ratio Jan.-Nov. 2010

3.19:1

2011 average realized price per bbl

See stats for Suncor upgrader

2010 average realized price per bbl

See stats for Suncor upgrader

50,000 40,000 30,000 20,000

(bbls/d)

10,000 0

Jan

Feb

Mar

Apr

May

SourCE: EnErgy rESourCES ConSErVation board

Project

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

Jun

Jul

Aug

Sep

Oct

Nov

. .. . .... . . . . .... .... Heavy Civil Construction Plant Sites and Leases Site Reclamation Roads and Highways Tank Farms Pipelines Above and Below Ground

1-855-GOT-SITE 1-855-408-7483 W W

W W

. .

S S

I I

T T

E E

N N

E E

R R

G G

Y Y

. .

C C

O O

M M

I N

S I T u

Photo: JoEy Podlubny

tuCKer

16 MAP REFERENCE

Project

tucker

Location

Cold Lake

Ownership

husky Energy Inc. 100%

Production start

2006

Formation/pool

Clearwater

Average reservoir depth

400 m

technology

Steam assisted gravity drainage

18,000

Current production capacity (bbl/d)

30,000

16,000

Average daily production Jan.-Nov. 2011 (bbl/d)

7,128

Average daily production Jan.-Nov. 2010 (bbl/d)

3,825

Average water production per calendar day Jan.-Nov. 2011 (bbl/d)

47,209

Average water production per calendar day Jan.-Nov. 2010 (bbl/d)

29,012

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2011)

82/106

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2010)

65/80

Monthly average steam to oil ratio Jan.-Nov. 2011

6.16:1

Monthly average steam to oil ratio Jan.-Nov. 2010

8.05:1

2011 average realized price per bbl

n/q

2010 average realized price per bbl

n/q

Husky Energy has been making headway against the production challenges it has faced at Tucker since start up, reportedly by remediating older wells with new completion and stimulation techniques, drilling new wells and initiating revised start-up procedures.

PRODUCTION

2009

2010

2011

14,000 12,000 10,000 8,000 6,000

(bbls/d)

4,000 2,000 0

Jan

Feb

Mar

Apr

May

SourCE: EnErgy rESourCES ConSErVation board

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

Jun

Jul

Aug

Sep

Oct

Nov

I N

S I T u

Photo: JEFFEry borChErt

productIon

MAP REFERENCE

11 g R E At D I v I D E

GreAt diVide/AlGAr great Divide/Algar

Location Ownership

South Athabasca Connacher Oil and gas Limited 100%

Production start Formation/pool Average reservoir depth

2007 Wabiskaw-McMurray great Divide 200 m, Algar 450 m

technology

Steam assisted gravity drainage

Current production capacity (bbl/d)

great Divide 10,000, Algar 10,000 great Divide 6,752, Algar 3,080 great Divide 6,627, Algar 6,778

Monthly average daily production Jan.-Nov. 2011 (bbl/d) Monthly average daily production Jan.-Nov. 2010 (bbl/d) Average water production per calendar day Jan.-Nov. 2011 (bbl/d) Average water production per calendar day Jan.-Nov. 2010 (bbl/d) Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2011) Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2010) Monthly average steam to oil ratio Jan.-Nov. 2011

great Divide 25,618, Algar 24,812 great Divide 25,099, Algar 13,637 great Divide 38/38, Algar 34/34 great Divide 36/36, Algar 22/34 great Divide 4.02:1, Algar 3.88:1

Monthly average steam to oil ratio Jan.-Nov. 2010

great Divide 3.73:1, Algar 13.01:1

2011 average realized price per bbl

n/q

2010 average realized price per bbl

n/q

MAP REFERENCE

In early 2012, Connacher went A Lg AR through significant management changes including the resignation of chairman, president and chief executive officer Dick Gusella. The company has launched a process to review its business plan and to identify, examine and consider all strategies available in order to prudently determine its optimal future course of action.

PRODUCTION

2010

2009

2011

18,000 16,000 14,000 12,000 10,000 8,000 6,000 4,000

(bbls/d)

Project

2,000 0

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

SourCE: EnErgy rESourCES ConSErVation board

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

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Photo: dEVon Canada

MAP REFERENCE

14 JAC k FISh 1

jACKFiSh

MAP REFERENCE

Devon achieved first oil from the 35,000-barrel-per-day Jackfish 2 project in June 2011. The company has also sanctioned another 35,000-barrel-per-day stage in Jackfish 3, and is progressing the Pike project, another 35,000-barrelper-day project shared with BP p.l.c.

15 JAC k FISh 2

PRODUCTION

2009

2010

Project

Jackfish

Location

South Athabasca

Ownership

Devon Energy Corporation 100%

Production start

Jackfish 1: 2007, Jackfish 2: 2011

Formation/pool

Wabiskaw-McMurray

Average reservoir depth

415 m

technology

Steam assisted gravity drainage

Current production capacity (bbl/d)

70,000

2011

45,000

Average daily production Jan.-Nov. 2011 (bbl/d)

40,000

Jackfish 1: 33,468; Jackfish 2: 4,458

Average daily production Jan.-Nov. 2010 (bbl/d) 35,000 30,000

Average water production per calendar day Jan.-Nov. 2011 (bbl/d)

Average water production per calendar day Jan.-Nov. 2010 (bbl/d)

63,502

25,000

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2011)

66/76

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2010)

52/56

Monthly average steam to oil ratio Jan.-Nov. 2011

2.57:1

Monthly average steam to oil ratio Jan.-Nov. 2010

2.5:1

2011 average realized price per bbl

n/q

2010 average realized price per bbl

n/q

20,000 15,000

(bbls/d)

10,000 5,000 0

Jan

Feb

Mar

Apr

May

SourCE: EnErgy rESourCES ConSErVation board

25,507

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

Jun

Jul

Aug

Sep

Oct

Nov

Jackfish 1: 79,175; Jackfish 2: 27,386

RE-THINK YOUR TOOL SELECTION.

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WE DON’T INVEST IN TECHNOLOGY – WE INVENT IT!

ARE YOU USING THE RIGHT TOOLS? visit us at

www.regentenergygroup.com

Nisku • Calgary • Sultanate of Oman • Villahermosa • Tampico • France

I N

S I T u

Photo: nEXEn

lOnG lAKe

20 MAP REFERENCE

In November 2011, Nexen’s previous Long Lake venture partner, OPTI Canada Inc., annouced it would be acquired by China National Offshore Oil Corporation for $2.1 billion. OPTI had declared bankruptcy earlier in the year.

Long Lake

Location

South Athabasca

Ownership

Nexen Inc. 65%, China National Offshore Oil Corporation 35%

Production start

2007

Formation/pool

Wabiskaw-McMurray

Average reservoir depth

200–250 m

technology

Steam assisted gravity drainage

45,000

Current production capacity (bbl/d)

72,000

40,000

Average daily production Jan.-Nov. 2011 (bbl/d)

28,211

Average daily production Jan.-Nov. 2010 (bbl/d)

23,902

Average water production per calendar day Jan.-Nov. 2011 (bbl/d)

145,884

Average water production per calendar day Jan.-Nov. 2010 (bbl/d)

123,910

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2011)

168/181

15,000

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2010)

161/182

10,000

Monthly average steam to oil ratio Jan.-Nov. 2011

5.23:1

5,000

Monthly average steam to oil ratio Jan.-Nov. 2010

5.59:1

PRODUCTION

2009

2010

2011

35,000 30,000 25,000

(bbls/d)

20,000

Jan

Feb

Mar

Apr

May

SourCE: EnErgy rESourCES ConSErVation board

Project

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

Jun

Jul

Aug

Sep

Oct

Nov

2011 average realized price per bbl

See stats for Long Lake upgrader

2010 average realized price per bbl

See stats for Long Lake upgrader

I N

S I T u

Photo: ShEll Canada

productIon

OriOn Project

Orion

Location

Cold Lake

Ownership

Shell Canada Limited 100%

Production start

2007

Formation/pool

Clearwater

Average reservoir depth

400 m

technology

Steam assisted gravity drainage

Current production capacity (bbl/d)

10,000

5,000

Average daily production Jan.-Nov. 2011 (bbl/d)

4,015

4,500

Average daily production Jan.-Nov. 2010 (bbl/d)

3,261

Average water production per calendar day Jan.-Nov. 2011 (bbl/d)

19,236

Average water production per calendar day Jan.-Nov. 2010 (bbl/d)

18,021

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2011)

43/44

2,500

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2010)

42/42

2,000

Monthly average steam to oil ratio Jan.-Nov. 2011

4.89:1

Monthly average steam to oil ratio Jan.-Nov. 2010

5.45:1

2011 average realized price per bbl

n/q

2010 average realized price per bbl

n/q

21 MAP REFERENCE

Shell says it has experienced challenges at Orion partly due to the reservoir being more heterogeneous than originally expected and steam shortages in the first two years of operations. The company says it is now seeing success in applying tailored operating strategies on different wells. PRODUCTION

2009

2010

2011

4,000 3,500 3,000

(bbls/d)

1,500 1,000 0 500

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

SourCE: EnErgy rESourCES ConSErVation board

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

I N

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Photo: ConoCoPhilliPS Canada

SurMOnt

13 MAP REFERENCE

Project

Surmont

Location

South Athabasca

Ownership

ConocoPhillips 50%, total E&P Canada Ltd. 50%

Production start

2007

Formation/pool

Wabiskaw-McMurray

Average reservoir depth

400 m

technology

Steam assisted gravity drainage

Current production capacity (bbl/d)

27,000

Average daily production Jan.-Nov. 2011 (bbl/d)

20,700

Average daily production Jan.-Nov. 2010 (bbl/d)

20,013

Average water production per calendar day Jan.-Nov. 2011 (bbl/d)

50,051

Average water production per calendar day Jan.-Nov. 2010 (bbl/d)

47,130

20,000

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2011)

55/61

15,000

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2010)

51/56

Monthly average steam to oil ratio Jan.-Nov. 2011

2.37:1

Monthly average steam to oil ratio Jan.-Nov. 2010

2.57:1

2011 average realized price per bbl

n/q

2010 average realized price per bbl

n/q

ConocoPhillips Canada is currently building the largest single phase of a SAGD project ever constructed, a 110,000-barrelper-day expansion to Surmont.

PRODUCTION

2009

2010

2011

45,000 40,000 35,000 30,000 25,000

(bbls/d)

10,000 5,000 0

Jan

Feb

Mar

Apr

May

SourCE: EnErgy rESourCES ConSErVation board

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

Jun

Jul

Aug

Sep

Oct

Nov

I N

S I T u

Photo: JoEy Podlubny

productIon

leiSMer Project

Leismer

Location

South Athabasca

Ownership

Statoil Canada Ltd. 60%, Ptt Exploration and Production 40%

Production start

2010

Formation/pool

Wabiskaw-McMurray

Average reservoir depth

400 m

technology

Steam assisted gravity drainage

23 MAP REFERENCE

Statoilâ&#x20AC;&#x2122;s next phase of in situ oilsands growth is a 40,000-barrelper-day project near Leismer called Corner. This project already has regulatory approval, and construction is expected to start in the first quarter of 2013.

PRODUCTION

2009

2010

2011

18,000

Current production capacity (bbl/d)

10,000

Average daily production Jan.-Nov. 2011 (bbl/d)

9,649

Average daily production Jan.-Nov. 2010 (bbl/d)

472

Average water production per calendar day Jan.Nov. 2011 (bbl/d)

24,624

Average water production per calendar day Jan.Nov. 2010 (bbl/d)

8,215

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2011)

41/41

8,000

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2010)

16/16

6,000

Monthly average steam to oil ratio Jan.-Nov. 2011

3.13:1

Monthly average steam to oil ratio Jan.-Nov. 2010

4.98:1

2011 average realized price per bbl

n/q

2010 average realized price per bbl

n/q

16,000 14,000 12,000 10,000

(bbls/d)

4,000 2,000 0

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

SourCE: EnErgy rESourCES ConSErVation board

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

GET YOUR PUMP RUNNING IN

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Calgary Manufacturing Industry’s Best Employer for Medium Sized Manufacturers.

Bringing Solutions to Surface

E x p E R I M E N Ta L

Photo: JoEy Podlubny

33 MAP REFERENCE

Project

Poplar Creek

Location

North Athabasca

Ownership

E-t Energy Ltd. 100%

Operations start

2006

Formation/pool

McMurray

Average reservoir depth

51 m

technology

Electro-thermal dynamic stripping

Current production capacity (bbl/d)

up to 1,000

Electro-thermal dynamic stripping is a commercial method for remediation of contaminated soils in the environmental industry. Essentially, it uses an electro-thermal process to heat the reservoir, in the case of the oilsands, mobilizing viscous bitumen. E-T Energy is working on what it calls Step 3 of its pilot process, a 250-barrelper-day “pre-commercial” test “fine tuning” production rates, energy intensity, total recovery and costs. This phase, funded in part by Total E&P Canada Ltd., began in January 2012 and is expected to proceed for about a year. (The technology reportedly extracts oil faster than other in situ methods.) The next step for E-T is a 10,000-barrel-per-day commercial pilot—the regulatory application has been filed and the company anticipates approval early in 2012. It also plans an initial public offering in 2012 to raise funds.

Game changers.

Big things in store for 2012. See what awaits online at www.advantageproductsinc.com

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

productIon

POPlAr CreeK

E x p E R I M E N Ta L

Photo: north PEaCE EnErgy

red eArth

38 MAP REFERENCE

Cyclic steam stimulation operates in phases of steam injection, steam soak and bitumen production. It has been used in the Peace River region by Shell Canada Limited since the 1980s. Southern Pacific Resource purchased the Red Earth asset from North Peace Energy Corp. in 2010. Southern Pacific has continued testing of CSS on its Red Earth leases. Over the last half of 2011, Southern Pacific used these wellbores to test three different configurations of CSS. The results of this initial pilot testing program were being analyzed and modelled in early 2012. The company expects to finalize its future development plans for Red Earth in the second quarter of 2012.

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

Project

Red Earth

Location

Peace River

Ownership

Southern Pacific Resource Corp.

Operations start

2009

Formation/pool

Bluesky-gething

Average reservoir depth

350â&#x20AC;&#x201C;375 m

technology

Cyclic steam stimulation (CSS)

Current production capacity (bbl/d)

1,000

E x p E R I M E N Ta L

Photo: lariCina EnErgy

34 MAP REFERENCE

Project

Saleski

Location

South Athabasca

Ownership

Laricina Energy Ltd. 60%, Osum Oil Sands Corp. 40%

Operations start

2010

Formation/pool

grosmont carbonates

Average reservoir depth

360 m

technology

Solvent-cyclic steam assisted gravity drainage

Current production capacity (bbl/d)

1,800

Solvent-cyclic steam assisted gravity drainage incorporates the addition of solvents into the commercial steam assisted gravity drainage (SAGD) process. Saleski is the first application of SAGD in the massive carbonate bitumen resources of Alberta. Steam injection began in December 2010. Laricina reported first oil from the Saleski project in March 2011, and by September 30 sales of bitumen production had surpassed 26,000 barrels gross. The company says it is encouraged with the results, but cautions that achieving the goal of evaluating SAGD and solvent-cyclic SAGD bitumen extraction in the carbonates involves successive cycles of testing, observation, gaining knowledge, marketing of initial production, adaptation, application of solvents, adjustment and further observation that will last up to two to three years of pilot operations.

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

productIon

SAleSKi

E x p E R I M E N Ta L

Photo: CEnoVuS EnErgy

GrAnd rAPidS

32 MAP REFERENCE

Grand Rapids: Although SAGD has been commercial in the WabiskawMcMurray and Clearwater formations for over a decade, the technology has not been widely proven in the Grand Rapids formation. Reportedly, Canadian Natural Resource Limited’s Wolf Lake SAGD project in the Grand Rapids is the only commercial installation of its kind.

Project

grand Rapids

Location

South Athabasca

Ownership

Cenovus Energy Inc. 100%

Operations start

2010

Cenovus Energy’s Grand Rapids SAGD pilot is located on its Pelican enhanced oil recovery leases in the South Athabasca region. The company plans to file an application for a phased commercial 180,000-barrel-per-day project at Grand Rapids in the near future.

Formation/pool

grand Rapids

Average reservoir depth

250 m

technology

Steam assisted gravity drainage (SAgD)

Current production capacity (bbl/d)

600

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E N E RGY, 62

I N D U ST R I A L

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E N V I RO N M E N TA L

S E RV I C E S

E x p E R I M E N Ta L

Photo: blaCkPEarl rESourCES

MAP REFERENCE

Project

Blackrod

Location

South Athabasca

Ownership

BlackPearl Resources Inc. 100%

Operations start

2011

Formation/pool

grand Rapids

Average reservoir depth

300 m

technology

Steam assisted gravity drainage (SAgD)

Current production capacity (bbl/d)

500

As of January 2012, BlackPearl Resources was reporting that production at its Grand Rapids SAGD pilot was over 250 barrels per day with a steam to oil ratio of 3:1. The company plans to file an application for a phased commercial 80,000-barrel-per-day project at Blackrod during the first half of 2012.

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MAP REFERENCE

C L I FFDA L E

h A R M O N vA L L E Y

Photo: baytEX EnErgy CorP.

CliFFdAle/hArMOn VAlley n/a

Cyclic steam stimulation operates in phases of steam injection, steam soak and bitumen production. It has been used in the Peace River region by Shell Canada Limited since the 1980s. Baytex says it has conducted two successful CSS tests in the Peace River/Seal region, including steam to oil ratios of 2.7:1 and 1.9:1, respectively. Based on that success, the company is advancing a permanent steam injection project. It has received regulatory approvals to install oil- and water-handling facilities and steam distribution piping at Cliffdale. Construction has commenced and steam injection was expected to commence before the end of 2011.

Project

Cliffdale and harmon valley

Location

Peace River

Ownership

Baytex Energy Corp.

Operations start

2008 and 2010

Formation/pool

Bluesky-gething

Average reservoir depth

350–375 m

technology

Cyclic steam stimulation (CSS)

Current production capacity (bbl/d)

1,000

“Performance Under Pressure”

Oil and Gas – pOwer GeneratiOn – pulp and paper new COnstruCtiOn – MaintenanCe – turnarOunds SAGD FAcilitieS contrActor SteAm GenerAtion & coGen DeSiGn/BuilD Well PAD & moDule inStAllAtion nAtionWiDe Boiler rentAl AGent For WeStern cAnADA

w w w. t h e r M a l e n e r G y. C a 1-800-490-7192 12 derrick drive, devon, alberta t9G2a1 64

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E x p E R I M E N Ta L

MaP: diVEStCo

35 MAP REFERENCE

Project

harper

Location

Northwest Athabasca

Ownership

Sunshine Oilsands Ltd.

Operations start

2011

Formation/pool

grosmont carbonates

Average reservoir depth

540 m

technology

Cyclic steam stimulation (CSS)

Current production capacity (bbl/d)

1,000

Like other thermal methods, CSS has not been proven in the vast bitumen carbonate reservoirs of northern Alberta. Sunshine Oilsands is testing the technique on its Harper leases. Sunshine Oilsands conducted one CSS cycle in the first quarter of 2011, reporting that it has been successful in mobilizing and producing bitumen. The company is now mobilizing for a second CSS cycle with a number of production improvements to better understand and operate the scheme.

Stuart Torr Director of Technology

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hArPer

E x p E R I M E N Ta L

Photo: athabaSCa oil SandS

dOVer WeSt

31 MAP REFERENCE

Thermal assisted gravity drainage employs conduction heating using mineral insulated (MI) cables along horizontal wellbores. Simply put, MI cable is a wire surrounded by mineral insulation to prevent short circuiting. Like the elements on an electric stove, the wire turns red hot as the power is cranked up.

Project

Dover West—Leduc carbonates

Location

North Athabasca

Ownership

Athabasca Oil Sands Corp.

Operations start

2011

Athabasca Oil Sands is operating a two-well TAGD test on its Dover West leases. The primary objective of the test is to evaluate the process recovery factor, which is expected to be 50–60 per cent or higher, similar to SAGD. The company says the heater cable performance is exceeding expectations, and heat transfer to the reservoir is better than predicted. Full results of the test are expected at the end of the first quarter of 2012. In October 2011, the company filed an application for a 6,000-barrel-perday TAGD demonstration project.

Formation/pool

Leduc carbonates

Average reservoir depth

300 m

technology

thermal assisted gravity drainage (tAgD)

Current production capacity (bbl/d)

1,000

Saskatchewan is full of energy opportunity. We have over 40 billion barrels of conventional oil in place and exciting potential in the Bakken Formation, heavy oil, oil sands and shale gas. We’re also on the leading edge of new research into enhanced oil recovery and carbon dioxide capture and storage. Explore investment opportunities in your next energy destination, Saskatchewan. Visit www.er.gov.sk.ca

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

E x p E R I M E N Ta L

MaP: diVEStCo

36 MAP REFERENCE

Project

Lindbergh

Location

Cold Lake

Ownership

Pengrowth Energy Corporation

Operations start

2012

Formation/pool

McMurray

Average reservoir depth

500 m

technology

Steam assisted gravity drainage (SAgD)

Current production capacity (bbl/d)

1,200

There is a long history of thermal bitumen production pilots in the Lindbergh field, dating back as far as the 1970s using CSS (Murphy Oil Corporation). In 2004, Pengrowth Energy Corporation purchased the property from Murphy Oil. The field is the deepest to use SAGD. Pengrowth built its SAGD pilot at Lindbergh after receiving regulatory approval in spring 2011. The company announced first steam in February 2012. The company says the project is expected to provide Pengrowth with the potential to develop a 30,000-barrel-per-day commercial project of low cost, low decline, stable oil production, with a 25-year reserve life. Pengrowth says it plans to sanction the first commercial phase at Lindbergh, subject to the pilotâ&#x20AC;&#x2122;s performance, in the first quarter of 2013.

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productIon

lindberGh

O p E R aT I N g

d aTa

OPerAtinG COMMerCiAl in Situ OilSAndS PrOjeCtS Primrose/ Foster Creek Wolf lake South Athabasca, South Athabasca Cold Lake

Project

Cold lake

Location

Cold Lake

Ownership

Imperial Oil 100%

Cenovus Canadian Natural Energy 50%, Resources 100% ConocoPhillips Canada 50%

Suncor Energy 100%

Nexen 65%, China Cenovus Energy National Offshore Devon Energy 50%, ConocoPhillips Oil Corporation 100% Canada 50% 35%

Production start

1985

2004

2007

2003

2007

Formation/pool

Clearwater

Clearwater, upper Wabiskawgrand Rapids McMurray

WabiskawMcMurray

Average reservoir depth

400 m

450 m

320 m

200â&#x20AC;&#x201C;250 m

400 m

415 m

technology

CSS

SAgD

Current production capacity (bbl/d)

140,000

120,000

157,500

72,000

58,800

70,000

Average daily production Jan.-Nov. 2011 (bbl/d)

159,706

97,880

109,719

57,858

28,211

20,284

Jackfish 1: 33,468 Jackfish 2: 4,458

Average daily production Jan.-Nov. 2010 (bbl/d)

141,000

84,229

101,660

53,406

23,902

14,654

25,507

Average water production per calendar day Jan.-Nov. 2011

549,956

266,445

249,654

199,772

145,884

47,487

Jackfish 1: 79,175 Jackfish 2: 27,386

Average water production per calendar day Jan.-Nov. 2010

489,321

250,212

222,258

165,392

123,910

32,473

63,502

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2011)

3,270/4,461

807/958

337/378

99/105

168/181

45/47

66/76

Wells producing or injecting/capable of producing or injecting (monthly avg. Jan.-Nov. 2010)

3,181/4,454

743/912

308/337

79/81

161/182

31/31

52/56

Monthly average steam to oil ratio Jan.-Nov. 2011

3.42:1

3.95:1

2.15:1

3.56:1

5.23:1

2.3:1

2.57:1

Monthly average steam to oil ratio Jan.-Nov. 2010

3.63:1

4.22:1

2.26:1

3.19:1

5.59:1

2.08:1

2.5:1

2011 average realized price per bbl

$105

n/q

2010 average realized price per bbl

$59

n/q

$58.80

See stats for Suncor upgrader

n/q See stats for Long Lake upgrader n/q

2001

Firebag

long lake

North Athabasca South Athabasca

Christina lake

jackfish

South Athabasca

n/q n/q

OPerAtinG COMMerCiAl OilSAndS MininG PrOjeCtS Project

Syncrude Mildred lake and Aurora

Location

North Athabasca

Ownership

Canadian Oil Sands Limited (36.74%), Imperial Oil Resources (25%), Suncor Energy (12%), Sinopec Oil Sands Partnership (9.03%), Nexen Oil Sands Partnership (7.23%), Mocal Energy (5%), Murphy Oil (5%)

Production start

1978

Average total volume to bitumen in place

North Mine: 7.2, Aurora North: 7.2, Aurora South: 8

Average ore grade (weight %)

North Mine: 11, Aurora North: 11.4, Aurora South: 11

Average strip ratio

North Mine: 1.5, Aurora North: 0.8, Aurora South: 0.9

Current production capacity

407,000

Average daily bitumen production Jan.-Nov. 2011 (bbl/d)

317,548

Average daily bitumen production Jan.-Nov. 2010 (bbl/d)

318,071

Year-to-date barrels mined (Jan.-Nov. 2011)

1,366,470,262

Year-to-date barrels mined (Jan.-Dec. 2010)

1,373,089,281

Monthly average mined ore grade (weight %, Jan.-Nov. 2011)

Mildred Lake 10.5, Aurora 11.01

Monthly average mined ore grade (weight %, Jan.-Nov. 2010)

Mildred Lake 10.52, Aurora 11.02

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

O p E R aT I N g

tucker

Surmont

Christina lake

Peace river

Great divide/Algar

hangingstone

leismer

Orion

North Athabasca Cold Lake

South Athabasca

South Athabasca Peace River

South Athabasca

Cold Lake

Suncor Energy 100%

husky Energy 100%

ConocoPhillips 50%, Japan Canada Oil Connacher Oil and gas total E&P Canada MEg Energy 100% Shell Canada 100% Sands Limited 100% 50% 100%

Statoil Canada 60%., Shell Canada Ptt Exploration and 100% Production 40%

2002

2006

2007

2003

1986

2007/2010

1999

2010

2007

WabiskawMcMurray

Clearwater

WabiskawMcMurray

Blueskygething

WabiskawMcMurray

Clearwater

150 m

400 m

350 m

550 m

great Divide 200 m, Algar 450 m

280–310 m

400 m

SAgD

33,000

30,000

27,000

25,000

12,500

great Divide 10,000, Algar 10,000

10,000

29,871

7,128

20,700

26,043

4,489

great Divide 6,752, Algar 3,080

6,555

9,649

4,015

31,323

3,825

20,013

20,417

7,075

great Divide 6,627, Algar 6,778

7,045

472

3,261

66,133

47,209

50,051

66,133

20,002

great Divide 25,618, Algar 24,812

25,919

24,624

19,236

72,461

489,321

47,130

45,944

23,835

great Divide 25,099, Algar 13,637

26,700

8,215

18,021

112/121

82/106

55/61

69/71

77/115

great Divide 38/38, Algar 34/34

40/44

41/41

43/44

114/116

3,181/4,454

51/56

60/68

80/115

great Divide 36/36, Algar 22/34

38/41

16/16

42/42

2.16:1

6.16:1

2.37:1

2.48:1

7.16:1

great Divide 4.02:1, Algar 3.88:1

4.23:1

3.13:1

4.89:1

2.41:1

8.05:1

2.57:1

2.68:1

4.54:1

great Divide 3.73:1, Algar 13.01:1

3.99:1

4.98:1

5.45:1

See stats for Suncor upgrader

$60.42

n/q

$67.99

n/q

$55.56

n/q

$51.10

n/q

$45.08

n/q

Shell Albian Sands – Muskeg river and jackpine

horizon

North Athabasca

Suncor Energy 100%

Shell Canada 60%, Chevron 20%, Marathon Oil 20%

Canadian Natural Resources 100%

1967

2002

2008

8.1:1

Muskeg River 7:1, Jackpine 7.2:1

10.3:1

11.61

Muskeg River 11.4, Jackpine 10.4

10.8

1.3:1

Muskeg River 0.7:1, Jackpine 0.6:1

1.2:1

321,000

255,000

135,000

261,604

192,112

37,579

239,448

118,205

99,960

1,071,960,794

849,764,019

168,841,668

941,114,826

566,908,672

420,124,975

11.42%

Muskeg River 10.56%, Jackpine 12.56%

11.15%

11.91%

Muskeg River 11.45%, Jackpine 13.07%

10.34%

Photo: athabaSCa oil SandS

Suncor – base and Millennium

productIon

MacKay river

d aTa

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

KEYA N O CO LLEGE explore the O P P O R T U N I T I E S and discover the P O S S I B I L I T I E S

KEYANO COLLEGE located in the heart of the Athabasca oil sands is constructing the Oilsands Power and Process Engineering Lab in Fort McMurray, Alberta. Your participation in our capital campaign will ensure a steady flow of locally trained employees to maintain and operate the vital functions of your SAGD or mine operations.

www.keyano.ca

Significant recognition is available.

Call Angele Dobie, Fund Development Manager for further information at 780-588-4777 or email: Angele.Dobie@keyano.ca

u N d E R

C O N S T R u C T I O N

productIon

Photo: SouthErn PaCiFiC rESourCE CorP.

Construction on Southern Pacific resource Corp.â&#x20AC;&#x2122;s STP-McKay SAGD project is expected to be complete in the second quarter of 2012, with production to commence three to four months later.

OilSAndS PrOjeCtS under COnStruCtiOn Operator name

Project name

Phase name

Capacity (bbl/d)

budget (million $)

Start-up

Canadian Natural Resources Limited

kirby (South)

Phase 1

45,000

1,254

2013

Cenovus Energy Inc.

Christina Lake

Phase D

40,000

n/q

2012

Cenovus Energy Inc.

Foster Creek

Phase F

45,000

2,000

2014

ConocoPhillips Canada

Surmont

Phase 2

109,000

2,490

2015

Devon Canada Corporation

Jackfish

Phase 3

35,000

1,200

2015

grizzly Oil Sands uLC

Algar Lake

Phase 1

5,650

220

2013

harvest Operations Corp.

Blackgold

Phase 1

10,000

500

2014

husky Energy Inc.

McMullen

Air injection pilot

755

2012

husky Energy Inc.

Sunrise

Phase 1

60,000

2,500

2014

Imperial Oil Limited

Cold Lake

Nabiye expansion

40,000

1,300

2015

Imperial Oil Limited

kearl (mine)

Phase 1

110,000

10,900

2012

Imperial Oil Limited

kearl (mine)

Phase 2

110,000

8,900

2015

Laricina Energy Ltd.

germain

Commercial demonstration

5,000

435

2013

MEg Energy Corp.

Christina Lake

Phase 2B

35,000

1,400

2013

Petrobank Energy and Resources Ltd.

Dawson

thAI pilot

n/q

2012

Southern Pacific Resource Corp.

StP-Mckay

Phase 1

12,000

440

2012

Suncor Energy Inc.

Base Operations

North Steepbank extension

180,000

400

2012

Suncor Energy Inc.

Firebag

Stage 4

62,500

2,000

2013

total capacity under construction (bbl/d)

904,905

total budget under construction (million $)

35,954

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

E M E R g I N g

p R O d u C E R S

eMerGinG PrOduCerS: On the rise in the oilsands sector by deborah Jaremko

ALBERTA OILSANDS INC. alberta oilsands inc. (aoS) is advancing a number of in situ oilsands projects, but the furthest along is the proposed 4,350-barrel-per-day first phase of the Clearwater project, located immediately to the southeast of the Fort McMurray regional airport. aoS applied for the project in 2010 and in december 2011 responded to the second round of information requests from the regulator.

ANDORA ENERGy CORPORATION andora Energy Corporation, controlled by Calgarybased Pan orient Energy Corp., has a main asset at Sawn lake, alta., in the Peace river oilsands region. the company has approval for a 1,400-barrel-per-day steam assisted gravity drainage (Sagd) pilot. in 2010, Pan orient announced andora had initiated a strategic review process that could include a merger or sale, and as of november 2011 had received no bids.

ATHABASCA OIL SANDS CORP. one of the largest bitumen leaseholders in the athabasca oilsands region, athabasca oil Sands Corp. (aoSC) has five assets advancing. as it continues pilot testing on bitumen carbonates at dover west, the most likely project to be commercialized for aoSC is at hangingstone. the regulatory application for a 12,000-barrel-per-day project is “proceeding as planned,” and construction is expected to begin in 2012.

BLACKPEARL RESOuRCES INC. in 2011, junior heavy oil producer blackPearl resources inc. started operations at its blackrod Sagd pilot, a test of the technology in the grand rapids formation, which has seen exponentially less commercial Sagd than the McMurray formation. the company says blackrod is exceeding model expectations, and it plans to file an application for a phased commercial 80,000-barrel-per-day project during the first half of 2012.

E-T ENERGy LTD. E-t Energy ltd. president and chief executive officer trevor roberts says the company is in about the seventh year of a 10-year process to commercialize its in situ oilsands technology, which is already used to remediate soils in the united States. in 2012, E-t—with the support of government funding and partner total E&P Canada ltd.—will progress the next phase of testing, which roberts categorizes as largely “fine tuning.” E-t will also likely look to access public markets with an initial public offering this year.

GRIZZLy OIL SANDS uLC Construction is underway on grizzly oil Sands ulC’s first-phase Sagd installation at algar lake. this 5,000-barrelper-day project is the company’s first execution of an oilsands construction and operations approach it calls the advanced, relocatable, modular, standardized (arMS) development model. First production at algar lake is expected in 2013. in 72

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

early 2012, grizzly made a bold step forward with the acquisition of Petrobank Energy and resources’ May river oilsands asset, which the company says will also be developed using the arMS model.

HARvEST OPERATIONS CORP. harvest operations Corp., an integrated oil and gas company that was purchased by korea national oil Corporation in 2009, is currently building its first 10,000-barrel-per-day phase of Sagd in the oilsands. the project, called blackgold, is expected to be operational in 2014. harvest has applied for a further 20,000-barrel-per-day phase at blackgold and anticipates regulatory approval in 2012.

IvANHOE ENERGy INC. ivanhoe Energy inc., which operates in the united States, Ecuador, China and Mongolia, is working towards commercialization in Canada of its in situ oilsands assets and, eventually, its proprietary field upgrading technology it calls htl. ivanhoe filed a regulatory application for a phased, integrated 40,000-barrel-perday project called tamarack in late 2010, and recently responded to the regulator’s first round of information requests.

KOCH ExPLORATION CANADA LP one of a number of Canadian subsidiaries of massive private american firm koch industries, inc., koch Exploration Canada lP has put together plans for a 1,200-barrel-per-day Sagd pilot in the Cold lake region called gemini, which would be followed by a commercial 10,000-barrel-per-day installation. the regulatory application for both phases has been filed, and a public hearing is scheduled regarding the project in early 2012.

LARICINA ENERGy LTD. in 2010, laricina Energy ltd. became the first company to ever pilot Sagd in the potentially vastly prolific grosmont carbonates. the company reported first oil in March 2011, and by September 30 sales of bitumen production had surpassed 26,000 barrels gross. laricina says it is encouraged with the results, but cautions that achieving the pilot goals will require up to two or three years of operations.

NORTH WEST uPGRADING INC. this year could prove to be pivotal for north west upgrading inc., as long-awaited sanction is anticipated for its redwater upgrader project. north west shares the project with Canadian natural resources limited, and uniquely has the support of the alberta government, which has agreed to supply it with feedstock through the bitumen royalty in-kind program. the first 50,000-barrel-per-day phase of the project is anticipated to be operational in 2014.

NORTHERN ALBERTA OIL LTD. northern alberta oil ltd. is a subsidiary of deep well oil & gas inc., which has pre-production assets in the Peace river

E M E R g I N g

OAK POINT ENERGy LTD. oak Point Energy ltd. is a recently established junior firm looking to leverage a different design approach to Sagd into cost savings and reduced labour requirements. the company, which recently acquired modular Sagd design company kemeX ltd., has filed an application for a 1,720-barrel-per-day pilot project at lewis, with production planned to start in 2014.

OSuM OIL SANDS CORP. osum oil Sands Corp. is steadily building land position as one of the largest leaseholders of assets in the bitumen carbonates. the company currently shares a Sagd carbonate pilot with partner and operator laricina Energy, but also plans its own operated installations in the future. osum has also filed a regulatory application for a phased 45,000-barrel-per-day Sagd/CSS pilot called taiga, in the Cold lake region. the company anticipates regulatory approval in 2012.

PENGROWTH ENERGy CORPORATION intermediate oil and gas producer Pengrowth Energy Corporation is making its first foray into the oilsands sector with the lindbergh project, a Sagd pilot in the Cold lake region. the company achieved first steam at the 1,200-barrelper-day facility in February 2012. Pengrowth plans to file regulatory applications for a phased 30,000-barrel-per-day commercial project.

PETROCHINA COMPANy LIMITED in early 2012, PetroChina Company limited became the first Chinese company to go beyond taking an interest stake in an oilsands project and into the larger-scope realm of 100 per cent ownership and operatorship. PetroChina purchased the remaining 40 per cent interest in the proposed Mackay river Sagd project from former partner athabasca oil Sands. regulatory approval is in place for up to 150,000 barrels per day at Mackay. Construction of the first 35,000-barrel-per-day phase is expected to start this year.

PIxAR PETROLEuM CORP. Established oil and gas producer Paramount resources ltd. announced in november 2011 that it would spin off its oilsands assets into a new subsidiary called Pixar Petroleum Corp. the near-term focus at Pixar will be on the hoole project, a proposed Sagd installation targeting the grand rapids formation. Paramount had previously announced plans for a 35,000-barrel-per-day project at hoole. the company will also have cold bitumen production and significant assets in the grosmont carbonates.

productIon

oilsands region. northern alberta oil has regulatory approval for a 700-barrel-per-day cyclic steam stimulation (CSS) pilot at Sawn lake, and deep well reports that it is preparing a pilot plan and considering options for capitalization.

p R O d u C E R S

SILvERWILLOW ENERGy CORPORATION in January 2012, conventional mining major teck resources limited purchased oilsands project partner Silverbirch Energy Corporation, in turn gaining full ownership of the proposed Frontier oilsands mine. Silverbirch’s in situ oilsands assets—primarily a prospective project called audet—were spun off into a new company called Silverwillow Energy Corporation.

SOuTHERN PACIFIC RESOuRCE CORP. Construction is nearing completion on Southern Pacific resource Corp.’s 12,000-barrel-per-day StP-Mckay Sagd project, with first steam reportedly on track for the second quarter of 2012. this is the first Sagd project for Southern Pacific to build and operate, although a few years ago it acquired the long-running Senlac Sagd project in Saskatchewan. in november 2011, Southern Pacific filed a regulatory application for a phased 24,000-barrel-per-day expansion at Mckay.

SuNSHINE OILSANDS LTD. Sunshine oilsands ltd., which is launching an initial public offering on the hong kong Stock Exchange, has a number of oilsands projects in the early stages of development. this includes an ongoing test of CSS in the bitumen carbonates. likely the first Sunshine project to achieve commercialization will be at west Ells, where it received approval for a phased 10,000-barrel-per-day Sagd project in early 2012.

SuRMONT ENERGy LTD. incorporated in october 2011, Surmont Energy ltd. is on a fast track to commercialization of its in situ oilsands assets. by summer 2012, the company plans to submit a regulatory application for a 10,000–12,000-barrel-per-day Sagd project in the Surmont region of the athabasca oilsands.

TECK RESOuRCES LIMITED a long-time interest holder in a number of planned oilsands mining projects, conventional miner teck resources limited took a step forward in the bitumen sector in January 2012 with the purchase of Silverbirch Energy and the subsequent 100 per cent ownership of the proposed Frontier oilsands mine. teck says it now has the opportunity to pursue new partnerships to see the project to commercialization. it also owns 20 per cent of Suncor Energy inc.’s proposed Fort hills project.

vALuE CREATION GROuP Private oilsands firm Value Creation group announced in 2010 that it had entered into a development partnership with bP p.l.c. the company has three oilsands projects, including two small-scale upgraders in the plans, with regulatory approval in place for a Sagd pilot at terre de grace and an application filed for an integrated project called triStar. h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

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p R O j E C T

productIon

PROJECT StatuS

S TaT u S

NORTH ATHABASCA REGION Athabasca Region

SOuTH ATHABASCA REGION

Industrial Heartland Region

COLD LAKE REGION

Cold Lake Region

Sourced from company releases, the Energy resources Conservation Board and the Daily Oil Bulletin, with files from Strategy West.

Peace River Region

PEACE RIvER REGION SASKATCHEWAN REGION

Northwestern Saskatchewan

This listing is updated on a monthly basis in Oilsands Review magazine and is available in even greater detail at www.oilsandsreview.com.

INDuSTRIAL HEARTLAND REGION

ProJECt uPdatES aS oF FEbruary 2012 CurrENT PrOJECT

CAPACITY

STArT-uP

rEGulATOrY STATuS

NORTH ATHABASCA REGION — MINING

Debottleneck

Canadian Natural says that reliability projects are on track with costs running below budget, a third ore preparation plant is being commissioned, there has been a six-month schedule slip in its Phase 2A plans for a coker expansion, in part due to coker fire rebuild, lump sum contracts have been awarded for its Phase 2B and engineering is on track for Phase 3. 135,000

2008

Operating

Phase 2A

10,000

2014

Approved

Phase 2B

45,000

TBD

Approved

Phase 3

80,000

TBD

Approved

Imperial Oil Limited Kearl Imperial Oil says that Kearl Phase 1 is approximately 80 per cent complete. The company has sanctioned Kearl Phase 2. Phase 1

110,000

2012

Construction

Phase 2

110,000

2015

Construction

70,000

2020

Approved

rEGulATOrY STATuS

Phase 1

25,000

TBD

Approved

165,000

2016

Approved

120,000

TBD

Application

voyageur South Phase 1 Syncrude Canada Ltd. Mildred Lake/Aurora North & South Canadian Oil Sands limited reports that front-end engineering and design is now complete for its $4.6-billion Mildred lake mine train replacements. The target in-service date for the $1.6-billion Syncrude Emissions reduction Project has now been extended into Q1 of 2012. Aurora South Train 1

100,000

2016

Approved

Aurora South Train 2

100,000

2018

Approved

Base Mine Stage 1 & 2 Expansion

290,700

1978

Operating

Stage 3 Expansion

116,300

2006

Operating

Total E&P Canada Ltd.

Shell Albian Sands

Joslyn North Mine

Jackpine The Canadian Environmental Assessment Agency recently invited public comment on a revised draft agreement to establish a joint panel for review of the Pierre river Mine project, as well as revisions to the existing joint panel agreement for the review of the Jackpine Mine expansion project. Expansion

STArT-uP

Current capital expenditures for Fort Hills are around design base memorandum engineering.

Horizon

Phase 3 Debottleneck

CAPACITY

Fort Hills

Canadian Natural Resources Limited

Phase 1

CurrENT PrOJECT

100,000

2017

Approved

Phase 1A

100,000

2010

Operating

Phase 1B

100,000

TBD

Approved

Project partner Suncor Energy says that current capital expenditures are around geological, engineering, regulatory and environmental studies. Phase 1

100,000

2018

Approved

100,000

TBD

Announced

Joslyn South Mine Phase 1 Northern Lights Mine

Muskeg River Commercial

155,000

2002

Operating

Phase 1

57,250

TBD

On Hold

Expansion & Debottlenecking

115,000

TBD

Approved

Phase 2

57,250

TBD

On Hold

Phase 1

100,000

2018

Application

Phase 2

100,000

TBD

Application

12,000

TBD

Announced

Pierre River

NORTH ATHABASCA REGION — IN SITu

SilverBirch Energy Corporation

Athabasca Oil Sands Corp. Birch Phase 1

Frontier Teck resources limited will acquire SilverBirch Energy Corporation and a new company will be spun out (SilverWillow Energy Corporation) with the former company’s in situ assets. Teck gains SilverBirch’s 50 per cent interest in Frontier.

Dover West Clastics Application for the 12,000-barrel-per-day Phase 1 was filed in December 2011.

Phase 1

75,000

2021

Application

Phase 1

12,000

2015

Application

Phase 2

80,000

2024

Application

Phase 2

35,000

TBD

Announced

Phase 3

80,000

2027

Application

Phase 3

35,000

TBD

Announced

Phase 4 Equinox

40,000

2030

Application

Suncor Energy Inc. Base Operations In Q4 of 2011, Suncor began to mine ore from the North Steepbank extension. Additionally, at the upgrader, the Millennium Naphtha unit is now producing hydrogen and is expected to reach full design rates in early 2012. Millennium Debottlenecking

Dover West Leduc Carbonates AOSC says that TAGD piloting will continue through the end of Q1 of 2012. Phase 1 Demonstration

6,000

2014

Application

Phase 2 Demonstration

6,000

TBD

Application

Canadian Natural Resources Limited

23,000

2008

Operating

Millennium Mine

294,000

1967

Operating

North Steepbank Extension

180,000

2012

Construction

Phase 1

60,000

2022

Announced

4,000

2007

Operating

Phase 2

60,000

2026

Announced

Steepbank Debottleneck Phase 3

Birch Mountain

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

p R O j E C T

S TaT u S

CurrENT PrOJECT

CAPACITY

STArT-uP

rEGulATOrY STATuS

Cenovus Energy Inc.

STArT-uP

rEGulATOrY STATuS

Firebag

Cenovus has filed the environmental impact assessment for a 90,000-barrel-per-day phase commercial project at Telephone lake. Phase A

45,000

TBD

Application

Phase B

45,000

TBD

Application

Dover Operating Corp. Dover

Subsequent Phases

CAPACITY

Suncor Energy Inc.

Telephone Lake Borealis

Phase 1

CurrENT PrOJECT

Suncor says that, exiting 2011, bitumen production from its in situ assets increased approximately 30 per cent over 2010, primarily due to the ramp-up of operations from Firebag Stage 3 and new infill wells at the Firebag project. Cogeneration and Expansion

25,000

2007

Operating

Stage 1

35,000

2004

Operating

Stage 2

35,000

2006

Operating

62,500

2011

Operating

50,000

2015

Application

Stage 3

200,000

TBD

Application

Stage 3-6 Debottleneck

23,000

TBD

Application

Stage 4

62,500

2013

Construction

Stage 5

62,500

2018

Approved

Stage 6

62,500

2019

Approved

Mackay River PetroChina Company limited has exercised its right to purchase the remaining 40 per cent of the MacKay river project from former partner Athabasca Oil Sands, marking the first time PetroChina will act as project operator in the oilsands. ErCB project approval granted January 2012. Phase 1

35,000

2014

Approved

Lewis

Phase 2

40,000

2017

Approved

Phase 1

40,000

TBD

Application

Phase 3

40,000

2019

Approved

Phase 2

40,000

TBD

Application

Phase 4

35,000

TBD

Approved

MacKay River

E-T Energy Ltd.

Suncor has commenced production from a new phase of six wells at MacKay river and initiated steam injection into additional wells. Production from these developments is expected to offset natural declines in the future.

Poplar Creek E-T is now working on what it calls Step 3 of its pilot, intended to look at equipment reliability and fine tuning of its well patterns. The next step will be a commercial 10,000-barrel-per-day project. E-T plans to access the IPO market in 2012. Phase 1

10,000

2014

Application

Phase 2

40,000

2016

Announced

1,000

2007

Operating

Pilot Husky Energy Inc.

Mr2

40,000

2016

Application

Phase 1

33,000

2002

Operating

Sunshine Oilsands Ltd. Harper Sunshine Oilsands is mobilizing for a second cyclic steam stimulation cycle at its Harper pilot, reportedly with a number of production improvements to better understand and operate the scheme. Carbonate Pilot

Sunrise Husky says Phase 1 construction remains on schedule for first production in 2014. More than half of the 49 SAGD well pairs are complete and Husky says drilling costs are trending on budget. Installation of foundations for the main plant and delivery of first major equipment began in January.

1,000

2011

Operating

Legend Lake Sunshine Oilsands has filed its application for the legend lake SAGD project.

Phase 1

60,000

2014

Construction

Phase 1

10,000

2016

Application

Phase 2

50,000

2016

Approved

Phase 2

10,000

TBD

Announced

Phase 3

50,000

TBD

Approved

Phase 2 Expansion

10,000

TBD

Announced

Phase 4

50,000

TBD

Approved

Phase 3

20,000

TBD

Announced

Phase 3 Expansion

10,000

TBD

Announced

Ivanhoe Energy Inc. Tamarack

Thickwood

Ivanhoe says it delivered the responses to the ErCBâ&#x20AC;&#x2122;s first round of supplemental information requests relating to its application in November 2011.

Sunshine Oilsands has submitted the regulatory application for its Thickwood SAGD project, anticipating project start-up in 2015.

Phase 1

20,000

2013

Application

Phase 1

10,000

2015

Application

Phase 2

20,000

TBD

Application

Phase 2

20,000

2017

Announced

Phase 2 Expansion

20,000

2020

Announced

Marathon Oil Corporation Birchwood Pilot

West Ells 12,000

2016

Announced

Oak Point Energy Ltd.

Sunshine has received regulatory approval to proceed with a 10,000-barrel-per-day SAGD project at West Ells. Former Harvest Operations Corp. John Zahary has been appointed president and CEO. Phase 1

Lewis Oak Point Energy reports that engineering and procurement is ongoing. Pilot

1,720

2013

Application

Southern Pacific Resource Corp. STP-McKay

5,000

2012

Approved

Phase 2

5,000

2013

Approved

Phase 3

40,000

2018

Announced

Phase 4

40,000

2024

Announced

value Creation Inc.

Southern Pacific says construction is nearing completion and it remains on track for first steam near the end of Q2 of 2012, with production to commence three to four months from first steam date.

Terre de Grace

Phase 1

12,000

2012

Construction

Phase 1

40,000

TBD

Announced

Phase 2A

12,000

2015

Application

Phase 2

40,000

TBD

Announced

Phase 2B

12,000

TBD

Application

Pilot

10,000

TBD

Approved

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

p R O j E C T

CAPACITY

STArT-uP

rEGulATOrY STATuS

SOuTH ATHABASCA REGION â&#x20AC;&#x201D; IN SITu

rEGulATOrY STATuS

24,000

2001

Operating

6,000

2003

Operating

Phase C Stage 1

10,000

2005

Operating

Phase C Stage 2

20,000

2007

Operating

Phase D

30,000

2009

Operating

Phase E

30,000

2009

Operating

Phase F

45,000

2014

Construction

Phase G

40,000

2015

Approved

Application

Phase H

40,000

2016

Approved

45,000

2017

Announced

Alberta Oilsands anticipates approval for the Clearwater West pilot in 2012, with construction to follow. Shabir Premji has retired as chairman and CEO, replaced by interim CEO Michael lee and chairman Jack Crawford. 25,000 4,350

2016 2012

Announced Application

Athabasca Oil Sands Corp. Hangingstone AOSC says the engineering design basis memorandum is complete, and certain long-lead items have been procured, such as evaporators and boilers. Construction is targeted to start in late 2012. Phase 1

STArT-uP

Ground preparation is now complete for Phases F-H. At Phase F, site preparation and the installation of pipe racks continues to progress on schedule.

Clearwater West

Pilot

CAPACITY

Foster Creek

Alberta Oilsands Inc.

Phase 2

CurrENT PrOJECT

12,000

2014

Phase A Phase B Debottleneck

Phase 2

35,000

2017

Announced

Phase I

Phase 3

35,000

2019

Announced

Narrows Lake

BlackPearl Resources Inc.

Alberta Environment has deemed complete the environmental impact assessment for the Narrows lake project.

Blackrod Alberta Environment and Water is preparing the final terms of reference for the commercial project phases. BlackPearl says production at the pilot is now over 300 barrels per day with an instantaneous SOr of less than 3:1, exceeding model expectations. The application for the 80,000-barrel-per-day commercial project is nearing completion, and will be submitted to the regulator in Q2 of 2012.

Phase 1

43,333

2017

Application

Phase 2

43,333

TBD

Application

Phase 3

43,334

TBD

Application

Phase 1

20,000

2016

Announced

Phase 2

30,000

TBD

Announced

Phase 3

30,000

TBD

Announced

Phase A

60,000

2017

Application

2011

Operating

Phase B

60,000

TBD

Application

Phase C

60,000

TBD

Application

2011

Operating

Pilot

TBD

Canadian Natural Resources Limited Gregoire Lake Phase 1

Pelican Lake Grand Rapids Cenovus has filed the environmental impact assessment for a commercial project at Pelican Grand rapids.

Pilot 60,000

2024

Announced

600

Connacher Oil And Gas Limited Great Divide

Grouse regulatory application is targeted for early 2012. Alberta Environment has issued its final terms of reference for the Grouse environmental impact assessment. Commercial

40,000

2017

Announced

Kirby (North) CNrl has submitted the environmental impact assessment for all phases at Kirby North and South. Phase 1

50,000

2016

Application

Phase 2

30,000

2019

Application

Kirby (South) Canadian Natural says construction remains on track and on budget. The company has submitted the environmental impact assessment for all phases of expansion at Kirby North and South. Phase 1

45,000

2013

Construction

Phase 2

15,000

2020

Application

Cenovus Energy Inc.

Connacher chairman and CEO Dick Gusella has relinquished his post. The companyâ&#x20AC;&#x2122;s board has announced the initiation of a process to examine all potential strategies for the company going forward. Algar Pod 2

10,000

2010

Operating

Expansion

24,000

2014

Application

Pod 1

10,000

2007

Operating

ConocoPhillips Canada Limited Surmont ConocoPhillips says it has received regulatory approval to increase production capacity of Phase 2 to 109,000 barrels per day, up from the previously approved 83,000 barrels per day. Phase 1

27,000

2007

Operating

Phase 2

109,000

2015

Construction

1,200

1997

Operating

Pilot Devon Canada Corporation

Christina Lake

Jackfish

Construction of Phase D is more than 70 per cent complete and production is expected in Q4. Construction of Phase E is more than 30 per cent complete, with initial production expected in Q4 of 2013. Ground preparation continues for Phase F. Production capacity for both Phases F and G has been increased by 10,000 barrels per day to 50,000 barrels per day each.

Devon reports that Jackfish 3 construction is now underway, and that Jackfish 2 volumes are ramping up ahead of plan and on target to reach capacity of 35,000 barrels per day by late 2012. Phase 1

35,000

2007

Operating

35,000

2011

Operating

35,000

2015

Construction

10,000

2002

Operating

Phase 2

Phase 1B

8,800

2008

Operating

Phase 3

Phase C

40,000

2011

Operating

Pike

Phase D

40,000

2012

Construction

Phase E

40,000

2013

Approved

Phase F

50,000

2016

Approved

35,000

2016

Announced

Phase G

50,000

2017

Approved

35,000

2017

Announced

Phase H

40,000

2019

Announced

35,000

2017

Announced

Phase 1A

productIon

CurrENT PrOJECT

S TaT u S

Devon is currently drilling appraisal wells and acquiring seismic on its Pike oilsands leases in order to determine the optimal development plan. Alberta Environment has issued its final terms of reference for the project.

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

p R O j E C T

S TaT u S

CurrENT PrOJECT

CAPACITY

STArT-uP

rEGulATOrY STATuS

Grizzly Oil Sands ulc

CurrENT PrOJECT

CAPACITY

STArT-uP

rEGulATOrY STATuS

Surmont

Algar Lake

regulatory application to be filed for 100,000-barrel-per-day project in Q2 of 2011.

Partial owner Gulfport Energy says Grizzlyâ&#x20AC;&#x2122;s construction is on track for commissioning in Q4 with first production in mid-2013. Grizzly will also likely soon file a regulatory application for a SAGD project at Thickwood. Phase 1

5,650

2013

Construction

Phase 2

5,650

2014

Approved

Harvest Operations Corp.

Phase 1

50,000

2018

Announced

Phase 2

50,000

TBD

Announced

N-SOLv Corporation Dover N-Solv and partner Suncor Energy have been granted funding from the Government of Canada under Sustainable Development Technology Canada to develop the N-Solv pilot.

BlackGold Harvest president and CEO John Zahary has stepped down and will be replaced by Myunghuhn Yi as part of the transition of ownership to Korea National Oil Corporation. Phase 1

10,000

2014

Construction

Phase 2

20,000

2015

Application

Demonstration Plant

500

2012

Announced

Nexen Inc. Long Lake Nexen says its focus at long lake continues to be to fill unused capacity at the upgrader. The company is currently advancing 60 additional wells to achieve this task.

Husky Energy Inc. McMullen Husky says that steam injection commenced in September 2011, followed by first air injection successfully initiated in December 2011. Air Injection Pilot-Experimental

755

2012

Construction

long lake South (Kinosis) Phase 1

40,000

TBD

Approved

long lake South (Kinosis) Phase 2

40,000

TBD

Approved

Phase 1

72,000

2008

Operating

Phase 2

72,000

TBD

Approved

Phase 3

72,000

TBD

Application

Phase 4

72,000

TBD

Announced

Japan Canada Oil Sands Limited Hangingstone JACOS owner Japan Petroleum Exploration is delaying a decision on an expansion at Hangingstone until mid-2012 due to a delay in regulatory approval. Expansion

35,000

2015

Application

Hangingstone Pilot

Hoole

JACOS owner JAPEx says regulatory approval for expansion is anticipated this fall, and an investment decision will follow. Pilot

11,000

1999

Operating

Laricina Energy Ltd.

Civil site construction is complete. Well pair drilling has commenced. Procurement, engineering and module fabrication continues. laricina has commenced an expansion of its camp to support project construction. laricina has submitted the environmental impact assessment for its 150,000-barrel-perday expansion at Germain. 5,000

TBD

Construction

Phase 2

30,000

2015

Application

Phase 3

60,000

TBD

Application

Phase 4

60,000

TBD

Application

Saleski laricina says the Saleski pilot sold 26,300 barrels of bitumen as of the end of Q3 of 2011. Pilot testing continues with an additional steam cycle added to each operating pair. The company has received regulator approval for the addition of a second steam generator. The Phase 1 application continues to move through the regulatory process, and now first steam is targeted for early 2014 rather than late 2013. Phase 1 Pilot

Announced

Expansion

1,900

TBD

On Hold

Pilot

1,900

2006

Suspended

Petrobank Energy And Resources Ltd. Conklin (Whitesands)

May River Petrobank has closed the sale of its May river asset to Grizzly Oil Sands, which plans to develop the leases using SAGD technology. Phase 1

10,000

2013

Application

Subsequent Phases

90,000

TBD

Disclosed

Statoil

Application

Kai Kos Dehseh

1,800

2011

Operating

Corner

40,000

2015

Approved

Corner Expansion

40,000

TBD

Application

Hangingstone

20,000

TBD

Application

leismer Commercial

10,000

TBD

Approved

leismer Demonstration

10,000

2010

Operating

leismer Expansion

20,000

TBD

Approved

leismer Northwest

20,000

TBD

Application

leismer South

20,000

TBD

Application

Thornbury

40,000

TBD

Application

Thornbury Expansion

20,000

TBD

Application

MEG says that detailed engineering on Phase 2B is 93 per cent complete. All materials and project modules have been ordered, with delivery and on-site construction scheduled to continue through 2012 with completion scheduled for 2013. The company has received regulatory approval for the multistage Phase 3. 3,000

2008

Operating

Phase 2A

22,000

2009

Operating

Phase 2B

35,000

2013

Construction

Phase 3A

50,000

2016

Approved

Phase 3B

50,000

2018

Approved

Phase 3C

50,000

2020

Approved

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

2015

2014

Christina Lake

35,000

10,700

MEG Energy Corporation

Phase 1 Pilot

Paramount is spinning off its oilsands assets including Hoole and carbonate leases into a new firm called Pixar Petroleum Corp. The company says the majority of work necessary for the Hoole regulatory application has been completed, together with preliminary front-end engineering and design, reservoir modelling and simulation. Commercial

Germain

Phase 1 Commercial Demonstration

Paramount Resources Ltd.

p R O j E C T

CAPACITY

STArT-uP

rEGulATOrY STATuS

Suncor Energy Inc.

Phase 2

STArT-uP

rEGulATOrY STATuS

Lindbergh 40,000

TBD

Announced

Meadow Creek Phase 1

CAPACITY

Pengrowth Energy Corporation

Chard Phase 1

CurrENT PrOJECT

productIon

CurrENT PrOJECT

S TaT u S

40,000 40,000

TBD TBD

Approved Approved

Pengrowth achieved first steam at the lindbergh pilot in February. Phase 1 Commercial

12,500

2014

Application

Phase 2 Commercial

17,500

2016

Announced

1,200

2012

Operating

Phase 1

10,000

2007

Operating

Phase 2

10,000

TBD

Approved

Pilot Royal Dutch Shell plc

value Creation Inc.

Orion

TriStar Value Creation is providing the ErCB with additional information supporting its application. Pilot

1,000

2012

Application

COLD LAKE REGION — IN SITu

Andora Energy Corporation

Canadian Natural Resources Limited

Sawn Lake

Primrose/Wolf Lake Canadian Natural plans five new pads at Primrose East and three new pads at Primrose South in 2012. Primrose East

32,000

2008

Operating

Primrose North

30,000

2006

Operating

Primrose South

45,000

1985

Operating

Wolf lake

13,000

1985

Operating

Husky Energy Inc. Caribou Demonstration

Andora Energy majority owner PanOrient Energy Corp. says the previously announced strategic review continues, but no bids have been received either to purchase the company or farm into the asset. The process continues. SAGD Demonstration

10,000

TBD

Approved

1,400

TBD

Approved

Northern Alberta Oil Ltd. Sawn Lake Company owner Deep Well Oil & Gas Inc. says DeGolyer & MacNaughton Canada limited has completed its reservoir modelling for a proposed horizontal cyclic steam stimulation pilot at Sawn lake, concluding the project would yield commercially viable extraction. Deep Well is currently preparing a pilot plan and options for capitalization. CSS Pilot

700

TBD

Approved

Petrobank Energy And Resources Ltd. Dawson

Tucker Production at Tucker has increased significantly, exiting 2011 at over 9,000 barrels per day versus 4,000 barrels per day the previous year. Husky says it has addressed subsurface challenges by remediating older wells with new completion and stimulation techniques and initiating revised start-up procedures. Phase 1

PEACE RIvER REGION — IN SITu

30,000

2006

Operating

Petrobank says the Dawson THAI pilot is 75 per cent complete and will be complete in Q2. Full field development is being considered, targeting regulatory filing in Q3. Phase 2 THAI Demonstration-Experimental

10,000

TBD

Announced

TBD

Construction

Royal Dutch Shell plc Imperial Oil Limited

Peace River

Cold Lake Cold lake achieved production record of 162,000 barrels per day in Q3 of 2011, due to contributions from new wells steamed in 2010 and 2011. Imperial continues to progress its cyclic solvent process technology. A three-horizontal well pair pilot has been sanctioned and is expected to start up in late 2013. Phase 1-10

110,000

1985

Operating

Phase 11-13

30,000

2002

Operating

Alberta’s environmental assessment director has deemed complete Shell Canada limited’s environmental impact assessment report for the Carmon Creek expansion. Cadotte lake

12,500

1986

Operating

Carmon Creek - Phase 1

40,000

2015

Application

Carmon Creek - Phase 2

40,000

TBD

Application

Southern Pacific Resource Corp. Phase 14-16

40,000

2014

Construction

Koch Exploration Canada Corporation Gemini The ErCB held a public hearing on the proposed Gemini project in Cold lake, Alta., on Feb. 22, 2011. Commercial Pilot

Red Earth Southern Pacific is analyzing results from its latest CSS test at red Earth. The company says it will finalize future development plans in Q2.

10,000

TBD

Application

1,200

TBD

Application

Commercial

10,000

TBD

Announced

Pilot

1,000

2009

Operating

Pilot Expansion

3,000

TBD

Announced

SASKATCHEWAN REGION — IN SITu Oilsands quest Inc.

Osum Oil Sands Corp.

Axe Lake

Taiga Osum has completed a $500-million private placement. The company has raised in excess of $1 billion in private equity since inception. Phase 1

17,500

2014

Application

Phase 2

17,500

2016

Application

Oilsands Quest has entered into a solicitation process looking for offers to acquire or restructure the company. Commercial

30,000

TBD

On Hold

reservoir Test

600

2008

On Hold

SAGD Pilot

TBD

On Hold

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

p R O j E C T

S TaT u S

CurrENT PrOJECT

CAPACITY

STArT-uP

rEGulATOrY STATuS

NORTH ATHABASCA REGION — uPGRADER

CAPACITY

STArT-uP

rEGulATOrY STATuS

value Creation Inc. TriStar

Canadian Natural Resources Limited Horizon

Value Creation is providing the ErCB with additional information supporting its application.

CurrENT PrOJECT

114,000

2009

Operating

Phase 2A

10,000

2014

Approved

Phase 2B

45,000

TBD

Approved

Phase 3

80,000

TBD

Approved

Ivanhoe Energy Inc.

Pilot

840

TBD

Application

INDuSTRIAL HEARTLAND REGION — uPGRADER North West upgrading Inc. Redwater upgrader Final sanction is anticipated in 2012. Phase 1

77,000

TBD

Approved

Phase 2

77,000

TBD

Approved

Phase 3

77,000

TBD

Approved

Tamarack Ivanhoe says it delivered the responses to the ErCB’s first round of supplemental information requests relating to its application in November 2011. Phase 1

34,784

2014

Application

Shell Albian Sands Scotford upgrader 1 Shell says the focus at Scotford will now be on improving operating efficiencies and adding capacity through debottlenecking. Alberta’s environmental impact assessment director has deemed complete the environmental impact assessment report for Shell Canada’s Quest carbon capture and storage project from the Scotford upgrader. Commercial

Millennium Coker unit

97,000

2008

Operating

Expansion

Millennium Vacuum unit

35,000

2005

Operating

Scotford upgrader 2

225,000

1967

Operating

u1 and u2 Fort Hills

158,000

2003

Operating

91,000

2011

Operating

Shell withdrew its application for all phases of Scotford upgrader 2 in fall 2010. Phase 1

97,750

TBD

Cancelled

Phase 2

97,750

TBD

Cancelled

Phase 3

97,750

TBD

Cancelled

Phase 4

97,750

TBD

Cancelled

Phase 1

65,000

TBD

Cancelled

Phase 2

152,000

TBD

Cancelled

Current capital expenditures for Fort Hills are around design base memorandum engineering. Phase 1

145,000

TBD

On Hold

Phase 2 & 3

145,000

TBD

On Hold

voyageur upgrader 3 Current capital expenditures are around remobilizing the workforce, confirmation of current design and modification of project execution plans. Phase 1

127,000

2017

Approved

Phase 2

63,000

TBD

Approved

Syncrude Canada Ltd. Mildred Lake/Aurora North & South Canadian Oil Sands reports that front-end engineering and design is now complete for its $4.6-billion Mildred lake mine train replacements. The target in-service date for the $1.6-billion Syncrude Emissions reduction Project has now been extended into Q1 of 2012. Base Plant Stage 1 & 2 Debottleneck Stage 3 Debottleneck Stage 3 Expansion (uE-1)

250,000

1978

Operating

75,000

TBD

Announced

100,000

2006

Operating

value Creation Inc. Terre de Grace 33,600

TBD

Announced

Phase 2

33,600

TBD

Announced

8,400

TBD

Approved

Pilot

SOuTH ATHABASCA REGION — uPGRADER Nexen Inc.

Application withdrawn in December 2008.

Total E&P Canada Ltd. Northern Lights Previous project owner Synenco Energy Inc. withdrew the Northern lights upgrader application in June 2008. Total purchased Synenco in August 2008. Phase 1

50,600

TBD

Cancelled

Phase 2

50,600

TBD

Cancelled

46,000

TBD

Cancelled

Phase 1

138,000

TBD

Cancelled

Phase 2

87,000

TBD

Cancelled

Phase 1

46,300

TBD

On Hold

Phase 2

46,300

TBD

Approved

Phase 3

46,300

TBD

Approved

Total says it will not proceed with its Strathcona upgrader. Debottlenecking

value Creation Inc.

Long Lake Nexen says its focus at long lake continues to be to fill unused capacity at the upgrader. The company is currently advancing 60 additional wells to achieve this task. Phase 1

58,500

2008

Operating

Phase 2

58,500

TBD

Approved

Phase 3

58,500

TBD

Announced

Phase 4

58,500

TBD

Announced

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

Strathcona

Phase 1

Statoil

Heartland Construction was suspended in September 2008.

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p R O j E C T

C O S T S

Inflation headwind oilsands owners face a new period of difficult cost control as a boom begins anew by neil levine

illuStration: JErEMy SEEMan

t’s not yet a return to the height of the oilsands construction boom in 2007-08—although development is expected to surpass the last peak in the near term—and project costs will continue to escalate despite the best efforts of owners and service providers to manage them. The Canadian Association of Petroleum Producers is forecasting record capital spending in the Canadian energy industry this year of $55 billion, of which $20 billion in spending will be focused on the oilsands, up from $19 billion the previous year and $17 billion in 2010. These are giant numbers, and they could go up. Nobody knows by how much, but cost inflation will

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

become an increasingly important and difficult issue for oilsands developers to manage. A recent report by Raymond James analyst Justin Bouchard says that labour shortages will be the most significant factor that will lead to cost inflation. Bouchard points out that the industry is already above peak employment levels experienced during the boom of 2005-08. That view is echoed by project proponents small and large. Glen Schmidt, president and chief executive officer of junior Laricina Energy Ltd., says that less-competitive projects will not be viable. “People will need to be creative and manage costs,” he says. Laricina has its own engineering team

p R O j E C T

productIon

and has looked outside Alberta for the procurement and fabrication of equipment for its Germain and Saleski projects in the southwestern Athabasca region. Larger oilsands operators are also keenly aware they need to manage costs in an increasingly heated environment. Cenovus Energy Inc. co-owns two major producing projects with partner ConocoPhillips Canada, steam assisted gravity drainage (SAGD) facilities at Foster Creek (current capacity is 120,000 barrels per day) and Christina Lake (capacity is 58,000 barrels per day). Cenovus is on an aggressive growth path and has taken a number of steps to control project costs: outside fabrication of modules in a module yard in Nisku (north of Edmonton), the use of smaller “mom-and-pop” contractors consisting of 30–40 people near the project sites and having its own construction management team oversee activity. The recent Raymond James report actually lists Cenovus as “the bestpositioned company to work through the looming inflationary environment.” Phased development of these SAGD projects is particularly effective at controlling costs and timelines, notes Susan Grey, Cenovus’s director of investor relations. “This worked well for us in 2008, when we maintained our expansion phases that had been previously announced despite the downturn,” she says. Grey also cites the work with smaller contractors as building loyalty and continuity for future work. “We can bring in someone who can build their business with us.” The Alberta Chamber of Resources (ACR) and Construction Owners Association of Alberta (COAA) have been working with other organizations and companies to try to learn from the previous boom and come up with new ways to help construction companies, contractors and project proponents deal with cost escalation. “We’re entering an era of increased activity,” says Brad Anderson, executive director of both the ACR and COAA. “No two booms or busts are ever the same. It’s hard to guess.” Anderson points to a number of methods and best practices that COA A members—representing heavy construction projects in the province—are using to rein in costs. A primary technique, and quite likely a large piece of the reasoning behind Cenovus’ position in the mind of Raymond James, is modularization, or the use of offsite

C O S T S

fabrication and construction. Anderson says workforce planning and training are also key elements of cost control. “The solution isn’t just to add more people. In the last 10 years, we’ve become more sophisticated in looking at the science behind construction.” The organization and its members have worked with a number of experts at the University of Alberta, the University of Calgary and the University of Texas at Austin researching benchmarking. This involves measuring, tracking and comparing items such as construction costs and data and then learning to better manage these variables. The Raymond James researchers also point to workforce management as an important piece of the cost-inflation puzzle. “Our primary concern with regard to the supply of labour relates to the productivity of the labour force within the oilsands industry,” wrote Bouchard and associate Christopher Cox. “Looking back to the last boom in the oilsands, productivity was often cited as one of the leading factors contributing to the rise in costs.” The researchers predict the following developments to occur in the looming higher-cost environment: • In situ projects will get priority over mining projects • Top-tier in situ projects will still generate compelling economic returns and will make up the majority of future growth over the next five to seven years • Upgrading projects will be deferred indefinitely (as long as light-heavy differentials stay below 28 per cent and without government intervention) • Growth will come predominantly from brownfield expansions versus greenfield developments • Smaller companies will be challenged to grow On the last note, they add, “There are numerous industry participants vying to grow their oilsands presence, all of whom would not easily ‘drop out of the race’ so to speak. What that implies is that costs are expected to march forward until some of the balance can be achieved. But with companies like BP, Shell, ExxonMobil, Statoil, PetroChina, Suncor, Canadian Natural, Husky, ConocoPhillips, Devon, and Sinopec participating in the race, we could easily envisage a scenario where costs increase to levels well past what would be expected from a purely rateof-return analysis.”

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

I N T E R N aT I O N a L

I N v E S T M E N T

An international

arrangement

Foreign oilsands investment surge is likely to continue, but in increments and not flagship deals By James Mahony

FOREIGN OILSANDS INvESTMENT TRANSACTIONS 2004-12 Year 2012

2011

2010

2009

2008

2007

2006

Buyer

Seller

Description

esources limited teck resources

Silverbirch Energy Corporation

50% Frontier

$435

PetroChina Company limited

athabasca oil Sands Corp. (aoSC)

Mackay river

$680

China national ational offshore oil Corporation

oPti Canada inc.

nexen/oPti long lake Sagd

PetroChina Company limited

dover operating Corp.

Joint venture projects

total otal E&P Canada

Suncor Energy inc.

Strategic alliance—Joslyn/Voyageur/Fort hills inPEX (indonesia) has 10% interest in Joslyn

imited teck resources limited

utS Energy Corp.

50% lease 14

Ptt Exploration and Production

Statoil Canada ltd.

40% interest in kai kos dehseh project from Statoil

$2,225

total Sa

utSS Energy Corp.

utS Energy Corp.

$1,145

China investment Corporation

Penn west Exploration

45% interest in joint venture to develop resources

Sinopec Corp.

ConocoPhillips Company

9.03% interest in Syncrude Canada ltd.

devon Energy Corporation

bP p.l.c.

50% interest in Pike oilsands leases from bP; form joint venture with bP for Pike

$634

Exxon Mobil Corporation

utSS Energy Corp.

acquisition cquisition with imperial oil limited—50% of utS oilsands lease 421

$125

PetroChina international Company ltd.

athabasca oil Sands Corp.

60% interest in aoSC’s Mac Mackay river and dover oilsands projects

occidental Petroleum Corporation

Enerplus Corp.

acquisition of Enerplus’ 15% working interest in Joslyn oilsands

$489

total Sa

nc. Synenco Energy inc.

Synenco Energy iinc.

$541

Marathon oil Corporation

nc. western oil Sands, inc.

western oil Sands, inc.

$6,495

Statoil aSa

north american oilil Sands Corporation

north american oil Sands Corporation

$1,951

Surge global Energy inc.

Peace oil Corporation

ConocoPhillips Company

Encana Corporation

Joint venture to develop integrated north american heavy oil business

$2,635

royal dutch Shell PlC

alberta public offering

acquisition of five parcels of oilsands land

$101

korea national oil Corporation

harvest Energy trust

$264

alberta public offering

acquisition of one parcel of oilsands land from public offering

$465

royal dutch Shell PlC

2005

$2,100 $83 $1,750 $177

$817 $4,538

$1,900

total Sa

deer Creek Energy limited

Sinopec Corp.

northern lights Partnership

40% joint venture interest

$149

China national offshore oil Corporation

MEg Energy Corp.

acquisition of 16.69% shares

$119

Canada oil Sands Co., ltd.

acquisition of 3.1% of company

2004 inPEX Corporation

Cost (million $)

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

$1,674

I N T E R N aT I O N a L

productIon

hina’s rising investment in Canada’s oilsands sector will not likely be challenged unless one of its stateowned firms makes a bid for one of Canada’s flagship producers, say industry observers. “The real test would be if there was a [target] company of stra strategic importance to the Canadian economy, where you could argue it was so central to that industry that the loss of Canadian ownership would be a serious issue,” says Roger Gibbins, president of the Canada West Foundation. In particular, bids for such oilsands players as Suncor Energy Inc. or Cenovus Energy Inc. could spark formal reviews by Ottawa, likely under the Investment Canada Act, he says. Such a review would consider whether or not a foreign investment that meets a minimum threshold—$330 million this year—would represent a net benefit to Canada. Calgary academic Bob Schulz takes much the same view as Gibbins, but offers a longer list of iconic Canadian producers whose takeover could spark a review. His list includes Suncor and Cenovus, but also Canadian Natural Resources Limited and Petrobank Energy and Resources Ltd. “If there were a play for the whole company, I think Investment Canada would say, ‘No, I don’t think you want to do that,’ particularly if you look at Suncor and Cenovus, because those would be top-of-the-line Canadian companies,” says Schulz, who teaches at the Haskayne School of Business at the University of Calgary. Among Canadian oilsands players that might be targeted, he differentiated between those with existing production and those with oilsands projects not yet built. Investments in the latter, he suggested, would more likely pass muster, since the Chinese buyer is in effect offering to make the investment needed to turn reserves into production. In the past few years, China’s state-owned producers have invested about $10 billion in Canada’s oil and gas industry, much of it in the oilsands. In early 2012, Athabasca Oil Sands Corp. announced it had sold its remaining 40 per cent stake in the MacKay River oilsands project to a unit of PetroChina International Investment Limited, giving the latter full ownership. Last year, China’s investment in Canada included Sinopec International Petroleum Exploration and Production Corporation’s $2.2-billion acquisition of non-oilsands developer Daylight Energy Ltd., and CNOOC Limited’s US$2.1-billion takeover of troubled oilsands developer OPTI Canada Inc. If anything, the scale of deals appears to be on the rise. At Vancouver’s Asia Pacific Foundation, the view was also that any attempt by a foreigner—Chinese or not—to take control of a prominent Canadian oilsands producer would prompt soulsearching in this country, “but we’re not at that stage yet,” says Yuen Pau Woo, foundation president and chief executive officer. He conceded that a bid for ownership of a major oilsands player is still a possibility. “Whether the Chinese will be so emboldened is another question. My sense is they’ll continue with an incremental,

I N v E S T M E N T

cautious approach and not seek to ruffle any feathers. They are increasingly criticized and will try to stay away from any deals that would cause a backlash,” he says. Given the increasing scale of Chinese investment in oil and gas worldwide, Woo is surprised that more of China’s money has not come to Canada. “It hasn’t been as large as it could have been, even five years ago. When you consider the pace and volume of Chinese oil and gas investment in Africa, Latin America and Asia, what has come to Canada is still a relatively small share.” When it comes to Canada as a place to invest, a University of Alberta expert on China-Canada relations says the Chinese perception is that much of the world is risky, but Canada is safer. Associate professor Wenran Jiang also says the Chinese feel Canada’s federal government has consistently welcomed Chinese investment, as have the western provinces. Whether or not state-owned firms will aim for bigger fish in the oilsands sector is another matter. “The Chinese are getting bolder and more confident, yet are still moving very cautiously forward,” he says. “They would not have moved as they did with Daylight or Athabasca without some kind of signal or assurance from [Canada’s] governments that Chinese investment is more welcome than before.” Gibbins notes that Asian money comes from China, but also from Japan, Korea, Thailand and Malaysia. He cited a Canadian opinion survey that brought out another difference. investWhile Canadians were generally enthusiastic about Asian invest ment, the feeling “paled a bit” for survey respondents if the word “Asian” was replaced by “Chinese.” “There’s no question that China, as a corporate player, propro vokes some wariness among Canadians, but I think that’s different from a feeling that we would be losing control of the oilsands or that foreign investment is too pronounced,” he says. “The reality is that foreign investment, whether from Norway, France, the U.S. or elsewhere, is driving [Canada’s] oilsands development.” Others also said those who fear China’s continued investinvest ment in the sector need only look around to see a host of foreign participants, starting with Royal Dutch Shell PLC, Exxon Mobil Corporation, Statoil ASA, Total SA and others. “You’ve got a lot of international buyers there, already,” says Schulz. “Shell and ExxonMobil are multinationals, Statoil is Norwegian and Total is French. People are saying ‘the Chinese are coming’ when foreign companies have been at the table for decades. To me, it’s not that much different.” In recent months, as China’s investment in the sector has oilincreased, some Canadian politicians have described the oil sands as a “strategic” resource for Canada, while others term it a “national resource.” While that kind of language annoys some people, it doesn’t bother Gibbins. “I welcome it because it shows that the oilsands are being secrolled into a broader understanding of the role of the energy sec tor in the Canadian economy.” straAs for describing bitumen as a national resource that’s of stra tegic importance, he says it’s “all [for] the good.”

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

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EYE ON THE ENVIrONMENT

CArBON MANAGEMENT 91 Catalyzing creativity 95 Carbon clash in the Golden State

ENVIrONMENT DATA

TAIlINGS The tailings technology suite

105

MONITOrING Top watchdog

110

COllABOrATION Oilsands allies

envIronment

environment

E y E

O N

T h E

E N v I R O N M E N T

EYE ON THE EnVironMEnt

industry uses collaboration and technology to manage air, water and land issues by annalise klingbeil

PhotoS: tar SandS aCtion nEtwork

Protests in Canada and the united States have recently focused on proposed export pipeline projects such as Keystone xl and Gateway, and have featured celebrities such as actress Daryl Hannah (far right).

aving the world’s third-largest proven oil reserve is an economic dream that comes with significant environmental challenges. as oilsands production drives rapid economic growth, there is increasing concern about environmental harm. but industry heavyweights are collaborating with the aim to tackle highly complex technical issues, and ultimately improve the sector’s environmental performance. in december 2011, the Canadian association of Petroleum Producers (CaPP) released its second annual responsible Canadian Energy progress report. the report contains 2010 data and documents the industry’s performance in the categories of people, land, air and water. “[the program is] focused more on national performance metrics— being able to measure them, being able to validate them and being able to be transparent in the areas Canadians want us to be,” says CaPP spokesman travis davies. “it’s showing us areas where we’ve done well, [and] it’s showing us areas where we need to do better.” he says it’s tough to narrow down the industry’s environmental challenges to just one main issue. “you’re looking at land or air, or water. ghgs on a more global basis, or local air quality on a more regional basis…. they’re all important to different groups.”

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

there is room for improvement, according to the 2010 data, in areas such as greenhouse gas (ghg) emissions. overall, ghg emissions intensity (ghg emissions per barrel equivalent of production) increased about three per cent from 2009 to 2010 and, over the past five years, increased by about 19 per cent. it’s not all bad news though. according to CaPP, since 1990, the ghg emissions created to produce one barrel of oil have been reduced by an average of 29 per cent. in a december 2011 report titled Responsible Action?, the Pembina institute assessed alberta’s ghg policies, concluding that “alberta’s current approach will deliver less than one-third of the ghg reductions the government of alberta has committed to.” the report contains six recommendations to strengthen current climate policies. while ghg emissions are a major issue, Jennifer grant, director of Pembina’s oilsands program, says there is a tie for the number-one environmental challenge facing the industry. “its pace and scale and the absence of environmental limits, as well as greenhouse gas implications of development,” grant says. there are also are ongoing concerns around water monitoring and impacts to surface water quality and quantity. grant says it’s useful to refer back to the 1990s when the national oil Sands task Force was formed. “their goal of having one million barrels

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O N

T h E

E N v I R O N M E N T

to address them: “oSli was started by like-minded companies that had a laser focus on performance and improving our activities with an impact on environmental, social and technical issues.” oSli is involved in numerous projects that are geared towards addressing specific environmental challenges. “i think the challenges are around minimizing our footprint and that involves energy use, that involves tailings, that involves water, that involves land management and impacts on biodiversity,” Saubestre says. he points out that tailings is the one challenge outside of oSli’s specialty as it’s handled by the oStC. through collaboration and a focus on technology, oSli is attempting to solve the industry’s environmental challenges. “i think if you were to tell people in the industry that six companies have gotten together and in two years have structured 50 joint industry projects that they’re collaborating on, you’d probably raise some eyebrows and have questions revert to ‘how

the focus on tailings ponds as a major industry environmental challenge. in 2010, oStC member companies agreed to remove monetary and intellectual property barriers with regard to tailings research and development. they share tailings knowledge, research and technology in a bid to advance tailings management. the oStC member companies dedicated $90 million to support tailings research conducted through the oStC in 2011. the oStC isn’t the only group of like-minded industry heavyweights that has made a pact to collaborate on environmental improvements. the oil Sands leadership initiative (oSli) represents six companies that decided working together made sense. they’ve come together to improve the oilsands industry’s reputation by demonstrating and communicating environmental, social and economic performance, and technological advancements. the group started as a collaborative network between ConocoPhillips Canada, nexen inc., Statoil Canada ltd., Suncor Energy inc. and total E&P Canada ltd., with Shell Canada limited joining later. today, oSli is a multi-million dollar undertaking involved in dozens of projects that address industry challenges. oSli’s budget grew from $9 million in 2010 to $23 million in 2011. Executive director Vincent Saubestre says oSli has identified industry challenges and is working

did you do that?’” Saubestre says. while it’s a significant achievement that’s been achieved quite rapidly, Saubestre knows there is still more work. “i think there is work ahead and it means finding new projects that we need to embrace collectively to address the environmental challenges.” grant is encouraged by the industry’s small steps taken in addressing environmental challenges. “we certainly look forward to working with the federal and provincial government and industry to try to ensure this resource is developed responsibly,” she says. there is a huge economic opportunity represented by the oilsands industry, but grant believes recent events such as the denial of the keystone Xl pipeline project provide evidence that more must be done to address the impacts of developing and transporting the resource. if environmental challenges are not properly addressed, grant says Canada will continue to be criticized internationally for not having an adequate environmental management system in place. “Canada’s reputation worldwide is at risk if we aren’t taking the development of this resource more seriously and doing things more slowly so that we can actually put in place a monitoring system that’s credible, a regional plan that actually helps manage the growth of the industry, those kinds of things.”

h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

envIronment

per day coming out of the oilsands by 2020 was actually achieved 16 years ahead of schedule in 2004.” as a result, she says the industry is playing catchup today. “are we able to actually manage this resource responsibly and ensure development isn’t exceeding time-space limits going forward? that’s a key concern for us.” in a technology-intensive industry, solving environmental challenges is dependent on innovation. the oil Sands tailings Consortium (oStC) is as an example of like-minded operators sharing resources. the oStC was founded in december 2010 when the seven major mining players came together to more quickly deploy technology solutions. tailings contain small amounts of unrecovered bitumen, which can create oil patches and be dangerous for birds and other animals. when 1,600 ducks died at one of Syncrude Canada ltd.’s tailings pond in april 2008, the event was publicized around the world and increased

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Catalyzing creativity envIronment

oilsands producers contribute $66.9 million to clean technology fund by Joseph Caouette

lberta’s oilsands industry has become notorious on the global stage in recent years, in large part because of concerns over greenhouse gas (ghg) emissions. less known—and perhaps even more surprising than anything happening in the oilsands—is the fact that the province was one of the first jurisdictions in north america to place a price on carbon emissions. Since mid-2007, any large emitter that produces over 100,000 tonnes of greenhouse gases annually must reduce its emissions intensity by 12 per cent each year. when emissions fall outside of that target range, companies have the option of paying $15 per excess tonne into a technology development fund. by the end of 2010, the fund had swelled to $254.5 million, with the oilsands sector contributing $66.9 million. administered by

the Climate Change and Emissions Management Corporation (CCEMC), the money is being used to support new technologies that reduce greenhouse gas emissions or help the province adapt to climate change. “we’re trying to be a catalyst for good ideas,” explains Eric newell, former chairman and chief executive officer of Syncrude Canada ltd., retired chancellor of the university of alberta and current chair of the CCEMC. “we want to fund projects that would otherwise not proceed but have good promise.” Since the corporation’s inception in 2009, it has pledged a combined total of over $120 million in funding to 26 projects. the following 10, focused on energy efficiency and renewable energy, represent the CCEMC’s 2011 selections.

Organization: biorefinex Canada inc. Project: lacombe biorefinery location: lacombe, alta. CCEMC funding: $10 million Total project value: $31.8 million Estimated GHG reductions: 364,149 tonnes of Co2 equivalent over 10 years Summary: when organic waste is sent to the landfill, it typically releases methane—a greenhouse gas considerably more potent than Co2. biorefinex Canada plans to reduce emissions by diverting organic waste and animal by-products from landfills and incinerators and into energy and fertilizer production. using thermal hydrolysis technology, the biomass plant will tap into feedstock from lacombe’s sewage treatment lagoon and a local meat-packing plant, both located adjacent to the facility. the process used to break down the waste—involving superheated steam and high pressure—destroys any pathogens in the material, ensuring sanitary disposal. Status: Contribution agreement not yet finalized Organization: Cenovus Energy inc. Project: Engine and compressor emissions control project location: Various facilities CCEMC funding: $3.6 million Total project value: $10.7 million Estimated GHG reductions: 19,980 tonnes per year Summary: Cenovus is hoping to improve efficiency at its natural gas facilities by combining fuel-optimization technology with captured vent gases. the first half of the project involves installing air/fuel ratio controllers on 37 different natural gas compressor engines across alberta. in addition, Cenovus will install a vent-gas capturing system at the sites, with the intention of using waste methane to help fuel the engines. while initial emissions reductions appear modest, the company is confident the technology could have big benefits if widely applied. “we estimate that industry-wide implementation of the fuel optimization technology alone could reduce Co2-equivalent emissions by almost half a million tonnes per year,” says dave hassan, team lead for Cenovus environmental technical investments. Status: less than 10 per cent complete

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Organization: Coastal hydropower Corporation Project: Carseland very low head (Vlh) small hydro project location: Carseland, alta. CCEMC funding: $2.65 million Total project value: $5.38 million Estimated GHG reductions: 42,510 tonnes of Co2 equivalent over 10 years Summary: “if we can get a technology that has never been applied in alberta or Canada, we like to be a catalyst for that sort of technology,” newell says of the CCEMC’s criteria when looking at potential projects. Coastal hydropower’s small-scale hydro project is a prime example of that philosophy in action. the Vlh turbine technology is currently used in France, but Coastal hydropower is working on adapting it to Canada’s colder climate. the turbines install onto existing low-head structures under five metres in height—such as smaller dams, weirs and irrigation canals—where larger hydropower projects could not be developed. two retrofitted 390-kilowatt turbines will be set up at the Carseland weir on the bow river in southern alberta for the demonstration project, which is expected to span two years. Status: Contribution agreement not yet finalized Organization: ConocoPhillips Canada Project: Energy efficiency projects at upstream conventional oil and gas facilities location: Various facilities CCEMC funding: $7 million Total project value: $14.1 million Estimated GHG reductions: 48,540 tonnes per year Summary: rather than relying on a single large-scale technology, ConocoPhillips is going small with the hopes of bringing energy efficiency to a wider range of oil and gas operations. the project will involve 10 different technologies employed at 400 different conventional oil and gas facilities across alberta, including wellsites, gas plants and compressor stations. the technologies will increase energy efficiency in one of two ways. Some will be focused on saving fuel gas, which could involve anything from improved engine controls to recycling heat from exhaust stacks. other projects will be focused on reducing vent-gas emissions, and will include capturing vented methane at wellsites to help heat buildings. in 2013, after the project has finished its initial two-year run, ConocoPhillips plans to hold a knowledge-sharing workshop on the results to encourage more widespread use of the technologies across the oil and gas industry. Status: less than 10 per cent complete Organization: Encana Corporation Project: Vent-gas capture for engine-fuel use location: Various facilities CCEMC funding: $2.4 million Total project value: $5.5 million Estimated GHG reductions: 61,160 tonnes per year Summary: Much like Cenovus, Encana is pinning its energy-efficiency plans on capturing methane that would otherwise be released into the atmosphere. the company will set up the gas-capturing technology at 52 different compressor stations in southern alberta, where the system will re-inject the methane into the compressor engines as fuel. and with excess greenhouse gas emissions costing companies $15 per tonne in alberta, Encana sees a lot of potential for cost savings in the technology—and a great incentive to apply it more widely should it prove successful. “we have several more sites that we can commit to this as well, so we’re looking at the broader scope,” says Vince Elenko, an energy analyst with Encana’s corporate environment division. Status: Contribution agreement not yet finalized Organization: growing Power hairy hill lP Project: gPhh integrated biorefinery location: hairy hill, alta. CCEMC funding: $5 million Total project value: $60 million Estimated GHG reductions: 932,078 tonnes of Co2 equivalent over 10 years Summary: taking advantage of a nearby feedlot, growing Power’s hairy hill biofuel plant will achieve net-zero status by running on manure from the very same cattle it will help feed. the plant will use wheat to produce 40 million litres of ethanol each year, but the process will be powered by biogas generated from cattle manure. in addition, the ethanol process leaves a residual substance known as distillers grains, which can be used as cattle feed. according to the company, the biofuel produced by the plant should have a higher energy balance of 7:1—meaning seven units of energy are provided for every unit put into producing the fuel—compared to 1.4:1 for conventional ethanol or 0.8:1 for gasoline. Status: Contribution agreement not yet finalized 92

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Organization: nrgreen Power limited Project: whitecourt energy-efficiency project location: whitecourt, alta. CCEMC funding: $7 million Total project value: $54.4 million Estimated GHG reductions: 67,650 tonnes per year Summary: a major part of the CCEMC’s mandate is finding new technologies that can be used to help alberta meet its greenhouse gas targets. “the only criteria on projects we’ll fund is that ultimately the technology can be applied in alberta,” explains newell. on that basis, a successful energy-efficiency project developed on Saskatchewan’s pipeline system is a prime candidate for use in pipeline-rich alberta. after installing four waste-heat units at pipeline compressors in Saskatchewan, nrgreen Power will be installing the technology at a compressor station owned by alliance Pipeline l.P. near whitecourt. the unit works by capturing exhaust from natural gas turbines and then converting that waste heat into electricity, producing up to 14 megawatts of power. Status: 30 per cent complete Organization: Quantiam technologies inc. Project: Catalyzed-assisted manufacture of olefins (CaMol) generation two for energy and ghg emissions reductions in higher-severity ethane crackers location: Edmonton CCEMC funding: $2.2 million Total project value: $4.5 million Estimated GHG reductions: 22,080 tonnes per year Summary: the production of olefins like ethylene is among the most energy-intensive processes found in the petrochemical industry. Every year, olefin production requires three billion gigajoules of energy, resulting in over 125 million tonnes of Co2 emissions around the globe. by adding a catalytic surfacing coating inside the olefin furnace, the CaMol technology decreases carbon buildup and allows the furnaces to operate at a lower temperature, reducing energy use and decreasing maintenance time. So far, the first generation of the technology has been successfully applied in Europe, where it proved effective in reducing energy consumption in olefin production by six to 10 per cent. aided by the CCEMC’s funding, Quantiam will be bringing CaMol to alberta’s own petrochemical industry in order to test the second generation of the technology. Status: Contribution agreement not yet finalized Organization: west Fraser timber Co. ltd. Project: Slave lake pulp bio-methanation project location: Slave lake, alta. CCEMC funding: $5 million Total project value: $25 million Estimated GHG reductions: 470,540 tonnes of Co2 equivalent over 10 years Summary: waste disposal has always been a significant challenge for the pulp and paper industry, but companies in recent years have been discovering the energy-producing potential of pulp by-products. Chief among these is waste-activated sludge, which is traditionally incinerated or disposed of in landfills. west Fraser timber is looking to harness this waste material to help power its Slave lake pulp mill. by integrating an anaerobic digestion system into the mill’s current waste-water treatment system, the company will be able to convert the sludge into a methane-rich biogas. the gas will then be used to help power the pulping process by generating heat and electricity. Status: Contribution agreement not yet finalized Organization: weyerhaeuser Company limited Project: weyerhaeuser grande Prairie evaporator project location: grande Prairie, alta. CCEMC funding: $5 million Total project value: $72.5 million Estimated GHG reductions: 103,780 tonnes per year Summary: nearly 40 years old, weyerhaeuser’s grande Prairie pulp mill is in the midst of a massive efficiency overhaul. the new evaporator will serve as the centrepiece for the revamped mill, and it promises to capture an extra 100,000 pounds of steam per hour—the amount currently lost during operations. using that steam, the evaporator will produce 23 megawatts of electricity. with the already completed portions of the efficiency upgrades—including a new recovery boiler and turbine—the mill will be capable of generating up to 27 megawatts of power. Status: 30 per cent complete h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

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IN THE

the legal fight over California’s low-carbon fuel standard could have big implications for Canada’s oilsands industry by r.P. Stastny

alifornia’s implementation of its low-Carbon Fuel Standard (lCFS) was stopped in its tracks on december 29 when a u.S. federal district court determined that it violates the country’s constitution by unfairly discriminating against out-of-state energy. originally approved in 2009 as a way to lower California’s dependence on petroleum by 20 per cent and cut one-tenth of its transportation fuel greenhouse gas (ghg) emissions by 2020, the lCFS has ruffled more than a few industry feathers, especially of carbon-intensive fuel interests, such as u.S. Midwestern ethanol and Canadian oilsands producers, who fear they will not be able to compete in the golden State. across the atlantic, a similar initiative, the European union’s (Eu’s) Fuel Quality directive, is also moving to implementation, but still needs the approval of its member states. the Eu’s directive commits fuel suppliers to reducing carbon emissions from fuel production by six per cent between 2010 and 2020. like the California lCFS, the Eu directive assigns carbon values to fuels based on their greenhouse gas emissions intensity. under the Eu

directive, oilsands crude is assigned a 23 per cent–higher value than conventional oil, posing a deterrent to its use by refineries—at least in theory. “Fuel standards in places like California and the Eu—even though we’re not currently trading into those markets—are precedence-setting issues,” says Canadian association of Petroleum Producers (CaPP) spokesman travis davies. “People watch those jurisdictions.” California often leads the rest of north america in environmental legislation, so this case is of crucial interest and could have implications for future cap-and-trade greenhouse gas emissions legislation in north america and abroad. Similarly, the Eu’s fuel standards will influence other countries that could become markets for oilsands products in the future. beyond issues of precedents, California is potentially a significant market for oilsands crude, even though the state currently imports only a trickle of Canada’s total production. in 2010, California brought in about 52,000 barrels a day of Canadian oil by tanker shipments, and only a fraction of that was oilsands production, according to CaPP.

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Canadian crude won’t be labelled “dirty” in Europe, for now it appears as though the European union is not ready to label Canadian oilsands crude as being more harmful to the environment than other sources. a February 2012 vote on the Eu’s proposed Fuel Quality directive, which would have done just that, ended in deadlock. the 27 member nations—assigned votes based on population—voted “neither for nor against” the directive. a pass would have required 255 votes, but the actual result was 89 for, 128 against and 128 abstentions. while Canada exports very little in energy products to Europe (reportedly only a small amount of diesel fuel), the label is seen as a potential precedent that could cause problems in other markets in the future. Far from a dead issue, some form of the Eu Fuel Quality directive is expected to resurface.

CRuDE IS CRuDE? at the centre of the low-carbon fuel tussle is carbon intensity calculations and geographic discrimination. “we never take issue with any effort trying to achieve carbon reduction,” davies says. “but our point is, ‘let us compete and don’t discriminate against us.’” when California first brought in its lCFS in 2009, the rules assigned a baseline carbon intensity to a basket of crude oils for which California refineries wouldn’t require carbon offsets. Canadian oilsands crude was excluded from this basket. absurdly, California heavy oil was included in it, even though studies have shown it to be more carbon intensive than oilsands production, in some cases. the California air resources board (arb), the regulator overseeing the fuel standard, seemed to concede this point last december 19 by “levelling the playing field” with a revision to the rules. all refinery feedstocks were now subject to the same scrutiny regardless of origin. alberta’s oilsands producers saw the revision as a step in the right direction, but it still fell short of their ideal: one carbon-intensity value assigned to all crude oil sources. Producers argue that the world’s oil supply is getting heavier, and while alberta requires its producers to rigorously track greenhouse gas emissions, can the same be said of places like nigeria, Venezuela or Saudi arabia? university of Calgary assistant professor Joule bergerson, a researcher of life-cycle assessments of oilsands ghg emissions, emphasizes that carbonintensity numbers are always just estimates. “life-cycle assessment methods are highly uncertain,” she says. “So for [California’s regulators] to come up with estimates for these sorts of pathways [various sources of energy] and reporting them to four significant figures implies more accuracy than they are capable of.”

CONSTITuTIONAL vIOLATION in the december 29 court decision, Judge lawrence o’neill sided with a coalition of out-of-state farmers and ethanol producers, ruling that the lCFS violates the Commerce Clause of the u.S. Constitution. 96

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Midwestern ethanol, under the lCFS rules, takes a higher carbon value than California-produced ethanol, largely due to transportation emissions and higher carbon inputs, such as the coal-fired electricity used during processing. Judge o’neill concluded that California’s goal of combatting global warming “cannot be achieved by the illegitimate means of isolating the State from the national economy.” he said the lCFS “explicitly discriminate[s] among ethanol pathways based on origin and activities inextricably intertwined with origin.” California argues this logic is flawed. the fuel standard discriminates on the basis of carbon intensity—which is exactly its purpose—not location per se. with his decision, Judge o’neill authorized an immediate appeal of the ruling, which saves the arb a year or more in challenging this ruling. as for a definitive ruling, richard Frank, director, California Environmental law and Policy Center, says, “once an appeal is filed, it is up to the ninth Circuit Court of appeals how quickly or how slowly it will actually decide the matter. it could be a matter of six months or it could be a matter of three years.” the ninth Circuit Court can also lift Judge o’neill’s injunction while it decides the appeal, which would allow the arb to go forward with implementing the standard. that issue will likely be a preliminary skirmish in the case. once the ninth Circuit makes a decision, there is still the possibility of one final review in the u.S. Supreme Court. the Supreme Court, however, is not obligated to hear any appeal from the ninth Circuit and it hears only a very small number of cases every year. “it’s statistically unlikely that the Supreme Court would decide to hear an appeal [of this case],” Frank says. “in all likelihood, the ninth Circuit decision will be the final one in this dispute.... “but it is a cutting-edge issue with a lot of public importance, so it’s conceivable that the Supreme Court could take an interest in this case, which would delay the results by a further year or two.”

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d aTa

2010 Canadian Association of Petroleum Producers Responsible Canadian Energy Aggregated Data — Oilsands Data source

Metric

2006

2007

2008

2009*

2010

Air and energy management Air emissions

Greenhouse gas (GHG) emissions

CAPP

SO2 emissions (tonnes/yr)

CAPP

SO2 intensity (tonnes per 103m3 OE of bitumen production)

CAPP

NO x emissions** (tonnes/yr)

CAPP

NOx intensity (tonnes per 103m3 OE of bitumen production)

CAPP

Total CO2 -equivalent emissions (tonnes/yr)

CAPP

Tonnes GHG emitted per m3 OE of bitumen production

Ambient air quality

119,520

124,942

116,405

131,655

1.73

1.69

1.64

1.6

113,525 1.23

45,953

54,591

58,255

69,307

72,157

0.65

0.74

0.83

0.84

0.78

33,591,392

34,465,421

37,332,657

40,482,998

46,253,129

0.48

0.47

0.52

0.49

0.5

Discussed in report using ambient air graphs and case studies

Water management Freshwater withdrawal Fresh water as a percentage of total water withdrawal Freshwater withdrawal per barrel of production Per cent water reuse (shale gas, tight oil and gas)

Government***

Freshwater withdrawal for in situ operations (million m3/yr)

14.5

15.8

18.5

16.6

17.5

Government***

Freshwater withdrawal for mining operations (million m3/yr)

121.2

125.6

184.3

162.4

152.4 49%

Government***

Fresh water as a percentage of total water withdrawal for oilsands in situ operations

52%

51%

56%

50%

Government***

Freshwater withdrawal per barrel of production for oilsands in situ operations (m3/m3)

0.51

0.55

0.43

0.4

Government***

Freshwater withdrawal per barrel of production for oilsands mining operations (m3/m3)

2.71

2.76

4.39

3.39

3.07

n/a

Water quality

n/a Qualitative indicator—discussed in report

Land management Active wells and inactive wells Annual well abandonments Status of abandoned wells in reclamation Annual certifications or releases received

Government***

Active wells

8,585

8,894

9,514

9,405

10,229

Government***

Inactive wells

5,717

6,518

7,010

7,863

8,030

Government***

Annual abandonments—Alberta conventional and oilsands wells

5,619

4,924

5,903

4,314

4,574

617

853

404

1,363 4,019

CAPP

Abandoned wells in active reclamation/remediation

463

CAPP

Abandoned wells in monitoring/assessment or application

100

1,128

CAPP

Annual certification or releases received

115

Total active footprint (oilsands mining)

Government***

Total active footprint—oilsands mining (hectares)

First reported in 2009

67,613

71,497

Total area cleared or disturbed (oilsands mining)

Government***

Total area cleared or disturbed—oilsands mining (hectares)

First reported in 2009

60,096

63,954

Government***

Total area in active reclamation or reclaimed and not certified—oilsands mining (hectares)

First reported in 2009

7,517

7,543

Total area in active reclamation or reclaimed and not certified (oilsands mining)

Data may be impacted by fluctuations in CAPP membership year-over-year. *The 2009 CAPP-collected data has been updated to reflect 2009 data that was not available to CAPP until 2011. **In 2007, there was a methodology change to include NOx from non-stationary oilsands sources. Also, 2009 was the first year the metric was mandatory. ***Data source: Government of Alberta

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SourCE: goVErnMEnt oF albErta

Key performance indicator

Ta I L I N g S

THE TAILINGS by deborah Jaremko Photos by Joey Podlubny

ilsands miners have entered a potentially groundbreaking period in tailings management where not only have the largest operators joined together to dissolve the walls of intellectual property and costs to share their ideas for solutions, but the solutions have gotten to the point where they appear to actually be solving the problem. The problem currently occupies about 170 square kilometres of northern Alberta. The four current oilsands mining projects have generated approximately 20 tailings ponds or settling basins that, although considered essential process vessels for water-based bitumen extraction, are far too big and far too many. And it’s not just their scale—because the ponds contain small amounts of leftover bitumen and asphaltenes, they present a hazard to local wildlife. To say that tailings are a major challenge for the oilsands industry is a significant understatement. But there is palpable enthusiasm among the members of the Oil Sands Tailings Consortium (OSTC), the group established in late 2010 by all the major mining players: Canadian Natural Resources Limited, Imperial Oil Limited, Shell Canada Limited, Suncor Energy Inc., Syncrude Canada Ltd. and Total E&P Canada Ltd. The firms committed to spend $90 million on OSTC research in 2011, as well as to share existing research and technology with no financial conditions. “We’re really looking to reclaim our tailings areas much faster than we have done

to date. We’re not going to get rid of them completely, but we are going to reduce their number and their size,” says Alan Fair, who in May was appointed executive director of the OSTC after a 32-year career at Syncrude, including the design and construction of the joint venture’s first tailings pond in 1979. Fair says he has been promoting collaboration in the oilsands industry for years. “We compete in terms of our lease positions, but not in terms of technology.” The tailings consortium has existed in some form since 1997, says Joy Romero, vice-president of technology development for Canadian Natural Resources. “We stepped it up a notch to the open [intellectual property] and to make sure that money didn’t get in the way,” she explains. “We know [collaboration] is a good recipe…. We see our solutions as regional solutions. We get that we need to get this right.” Each company has been working on different tailings management technologies for years, although often duplicating efforts. And there will be no single solution because each project is at a different stage and processes a different quality of resource. “It’s not a one-size-fits-all [solution],” says John Broadhurst, vice-president, development for heavy oil with Shell Canada and chair of the OSTC. “A suite of technologies will be used.” In addition to continued work at their individual sites, the OSTC is working on a $1.4-million tailings road map study, which is scheduled to be complete this year.

SHELL MUSKEG RIVER MINE

MaP: oil SandS tailingS ConSortiuM

Oilsands miners drop the barriers of cost and intellectual property for the greater good

CANADIAN NATURAL HORIZON

SYNCRUDE AURORA NORTH SHELL JACKPINE MINE

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OILSANDS TAILINGS PONDS

SYNCRUDE MILDRED LAKE SUNCOR

Fort McMurray

The “fines issue” the principal challenge that all oilsands operators face is called mature fine tailings (MFt), or fluid fine tailings. once the bitumen has been extracted from its matrix of sand, silt, water and clay using warm water, everything from the process, excluding the majority of the bitumen, is deposited into a settling basin or tailings pond. here, most of the water flows to the top and is recycled back into the process while the sand and clay settle to the bottom. MFt becomes a fine layer in the middle where clay and water will not separate for decades if left on their own. MFt is the reason why historically it has taken so long for a tailings pond to be reclaimed to a solid surface, and further to productive landscapes.

[Top] Oilsands tailings ponds, which are located in relatively close proximity to each other, currently occupy about 170 square kilometres of northern Alberta.

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Suncor Energy TRO in 2008, Suncor Energy began field testing a technology that would end up drastically changing the surface footprint of its mine plan. the technique, originally called tailings reduction operations but since shortened to the simpler tro, creates a mixture of polymer and MFt (the real problem child of the tailings process, which takes decades to dry out on its own). adding the polymer and laying the mixture over sloped banks for drying allows for the creation of a solid surface within weeks, Suncor says. Since receiving regulatory approval to use tro commercially across its operations in 2010, Suncor has changed its mine plan to the extent that no new tailings ponds will be built over its main project’s life (not including new projects such as Fort hills and Joslyn). “we had five more tailings ponds planned in our mine plan. now none of those will get built,” says bradley wamboldt, Suncor’s tro director. “we are very much in the commercial application of this technology.”

[Top left] One of a number of sites on Suncor’s mining leases where it is drying tailings treated with its TrO technology. [Top right] Tailings treated with TrO release water much more quickly than tailings treated with previous methods. [Bottom] Pipes carrying mature fine tailings and the substance that makes TrO what it is—polymer—for treatment.

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Syncrude Centrifuges, water capping and composite tailings

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Canada’s largest oilsands joint venture is working on three main technologies to manage its existing inventory of tailings, as well as new tailings from ongoing operations. one of these techniques is the use of centrifuges to remove the water from MFt, which Syncrude Canada says it has successfully piloted. “this technology produces a soft clay-rich soil that can be used as a landform foundation in oilsands reclamation areas,” the company says. Plans are in place for a commercial-scale demonstration in 2012, followed by development of a commercial plant and then an increase in MFt conversion capacity. the second technique Syncrude is working on is composite tailings technology, where fine tailings are combined with coarse tailings and gypsum before being sent to settle. the technique is currently being used to reclaim the former East Mine, a process that will include the first recreated fen in the industry. the final piece of the Syncrude tailings technology suite is water capping, which it has been demonstrating on a pilot scale for over 20 years. it has 11 test ponds and is planning to commission the industry’s first commercial-scale water-capped lake starting in 2012.

[Top] One of Syncrude’s 11 test ponds of water-capped tailings. The company has been studying this technique for more than 20 years and plans to open its first commercial-scale lake in 2012. [Middle] Early reclamation underway on Syncrude’s East Mine, formerly a tailings pond. [Bottom] Ducks swim about in one of Syncrude’s water-capped tailings ponds.

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Shell Canada

Atmospheric fines drying and thickened tailings Shell Canada describes its approach to tailings technology as to develop and advance a number of techniques that can work in concert to help accelerate the pace of reclamation and minimize the size of ponds and the need for new ones. two of these techniques are atmospheric fines drying (aFd) and thickened tailings. Similar to Suncor’s tailings reduction operations process, aFd involves the mixture of a chemical agent with MFt and placement of the combined materials on a sloped surface to dry out. Shell started its aFd testing in the summer of 2010. the company says it started as a test at its tailings pilot facility and that a commercial demonstration is now underway. Shell’s two mining sites are reportedly the ones in the oilsands industry to be using tailings thickeners to recover warm water from the tailings before they are sent to the settling basins. the process starts with hydrocyclones to separate the coarse and fine tailings. Shell says the MFt is then dewatered using a chemical agent, followed by gravity settling in a thickener. the overflow water is recycled back into the process. the thickened tailings technology was tested at Shell’s Muskeg river tailings pilot plant and is now being commercially deployed at the new Jackpine mine.

[Top] At Shell’s brand new Jackpine extraction facility, it is using tailings thickeners to recover more water before the tailings are sent to settling basins. [Middle] Machinery aerates drying tailings treated with Shell’s AFD technology. [Bottom left] Demonstrating the application of AFD at Shell’s Muskeg river mine. [Bottom right] Dried tailings from the AFD process.

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Canadian Natural Resources Send in the CO2

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Canada’s newest oilsands miner has in part taken a different approach to tailings management than its predecessors. Since 2009, after plant start-up in late 2008, Canadian natural resources has been adding waste Co2 to its tailings streams before they are sent to the settling basin. the company says this creates a reaction where the solids settle more quickly, particularly those pesky fines. as well, Canadian natural says the process increases the clarity of the water for recycling back into the process, enabling the reduction of fresh water use and the size of the horizon project’s pond. Currently, the company is using purchased waste Co2, but the opportunity also exists for it to reduce its own emissions using this process in the future. Joy romero, Canadian natural’s vice-president of technology development, says this choice was made early on. “we did the analysis in 2002 and decided that this was part of our process in 2003,” she says. Starting in 2015, Canadian natural plans to implement two other tailings technologies that are currently being demonstrated: MFt dewatering, where MFt is treated with a reagent, and non-segregating tailings used in the extraction plant. the company says this will incorporate thickeners and cyclones to recover and recycle hot water, producing respectively dewatered tailings.

[Top left] Dried tailings treated with purchased waste CO2 at Canadian Natural resources’ Horizon mine. [Top right and bottom] Tailings and CO2 infrastructure enabling Canadian Natural’s take on tailings reduction technology.

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Delivering engineering solutions to the heavy oil and oil sands industry.

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A NEW FEDERAL-PROvINCIAL OILSANDS MONITORING PLAN WILL BRING TOGETHER ExISTING PROGRAMS INTO ONE COORDINATED EFFORT

by Jim bentein

illuStration: JEnna o’FlahErty

arly in February, the Alberta and federal governments unveiled details of a new environmental monitoring program for the oilsands industry. The news was welcomed in many quarters as a long-overdue response to criticisms of oilsands oversight, but it does beg one question: What about all of the old environmental monitoring programs? Jessica Potter, a spokeswoman for Alberta Environment and Water, which will oversee the implementation of the monitoring program along with Environment Canada, says existing monitoring organizations will be a part of the plan—at least in the short term. “The intent is to integrate the work of all of these agencies under the direction of a single plan,” she says. “We don’t want to eliminate—we want to enhance and integrate. We want to be sure the [monitoring] activities are coordinated under one

program. That way we can ensure they are scientifically credible, and the results are open [and] transparent.” The two governments announced the plan for the joint monitoring program last summer after a torrent of criticism aimed at the existing industry-government monitoring organization—particularly the Regional Aquatics Monitoring Program (RAMP), which is responsible for surface water monitoring in the Athabasca oilsands region. Many of the other monitoring organizations, such as the Wood Buffalo Environmental Association (WBEA) and the Cumulative Environmental Management Association (CEMA), got off more lightly. According to Potter, CEMA, WBEA, RAMP and the Lakeland Industry and Community Association (a communitybased group in the Cold Lake, Alta., area that monitors local environmental impacts), “will continue to exist in the short term.

“The long-term decision regarding monitoring will be determined by the governments, and their positions are still ongoing,” she says. There will be a three-year implementation plan, starting this spring with increased sampling frequency, parameters and locations. That is when the integration of “relevant parts of existing monitoring efforts” will be rolled into the new program, the governments said in a press release. Finding Funds One of the major criticisms of RAMP is that its monitoring efforts have been affected by a lack of adequate funding. The completely industry-funded organization has also been plagued by concerns over its lack of permanent staff and reliance on volunteers linked with industry. By contrast, WBEA has significant industry and government funding, and is run by a permanent bureaucracy headed by Kevin Percy, a respected environmental

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scientist. CEMA is also headed by a full-time management team and has appeared well funded in the past, although it faces a budget shortfall this year. But it seems certain industry will be asked by the federal and provincial governments to provide more dollars for environmental monitoring in the future. Federal Environment Minister Peter Kent says he is confident the energy industry will provide the increased funding for the expanded program, pegging the total cost at $50 million a year. The governments say that by the time the three-year plan is fully implemented in 2015, the number of sampling sites will increase and include a larger area, the number and types of parameters being sampled will rise, samples will be taken more often, monitoring methodologies for both air and water will improve, and an integrated, open data management program will be created. There is also the promise that the monitoring program will undergo external expert peer review after the third year and at five-year intervals thereafter to ensure that scientific integrity is maintained. An annual report on the status of implementation

will be made public and data from the monitoring program, along with the methodology used to produce it, will be made public on a continuous basis. The water-monitoring components of the program will include: • Improved coordination of sampling to gauge cumulative effects. • New sediment monitoring throughout the mainstream and key tributaries of the Athabasca River to establish baseline and downstream conditions of potential contaminants throughout the system. • New systematic sampling of snow and rainfall to assess the relationship between airborne processes and surface water runoff entering tributaries and moving downstream. • New and improved monitoring techniques for measuring contaminants in ice and the impact of freeze-up and breakup. • New intensive monitoring of sources of potential near-surface groundwater contaminants and pathways. Air-monitoring improvements will include: • New air monitoring in upwind locations (to understand the quality of air moving into the region) and in downwind

IndustrIal aIr pollutants remaIn focus of wBea monItorIng plans

ith both the federal and Alberta governments having pledged to increase the monitoring of the environmental impacts of oilsands development, it seems almost certain Kevin Percy will play a role in any approach aimed at monitoring air emissions in the Wood Buffalo region, where development is concentrated. That’s because Percy is the executive director of the Wood Buffalo Environmental Association (WBEA), recognized last year by Environment Canada as having adopted “a sound, transparent science approach that permeated all of its activities.” Since 2007, the association’s funding has increased from $2.7 million a year to the current level of $10.6 million a year. This funding, almost all from industry, “has allowed us to build a team that consists of 38 internationally respected 10 6

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scientists,” says Percy, who joined the WBEA as lead scientist in 2009 before becoming executive director in 2011. The WBEA’s 15 air-monitoring stations and 27 passive-monitoring stations—located throughout the prime oilsands-mining area—measure what are called “industrial pollutants,” including sulphur dioxide, nitrogen oxides, ozone, carbon monoxide and particulates, as well as odour-related hydrogen sulphide. The WBEA, which is a collaboration of industry, communities, environmental groups, government and aboriginal groups, reports continuous ambient air-quality data in real time. Percy says at this point the association isn’t heavily involved in measuring CO2, but that might change (individual plant operators gather most of the data now). “Our focus is primarily on industrial air pollutants,” he says. “We can measure

CO2 at two of our four tower sites, but if the plan [for future monitoring] calls for us to be more involved in measuring CO2, we certainly could do so.” The WBEA’s monitoring up to now has produced results that wouldn’t be surprising to those who have been to the Wood Buffalo area and seen the extent of oilsands development there. “We have seen elevated concentrations of air pollutants and a related impact on terrestrial plants within 15–20 kilometres from the source,” Percy says. “However, concentrations decline sharply when you get 20–25 kilometres away from the source.” Other work showed “changes in air quality in communities in the region was either small or not obser vable,” he says, with the exception of Fort MacKay, Alta., where increases in nitrous oxides were obser ved.

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cover the entire oilsands region. Finally, the program will use improved high-resolution imagery to better understand and predict biodiversity patterns. The Pembina Institute, an Alberta-based environmental group, reacted positively to the announcement of the new plan. “The need to improve monitoring of the environmental impacts of oilsands production has been widely recognized, and it’s promising to see that this plan commits to transparency and accessibility and is based on technically sound information,” says Jennifer Grant, director of the organization’s oilsands program. “A scientifically credible monitoring plan provides a strong foundation for improved environmental management of oilsands development.” However, she says better monitoring “is only one piece of the puzzle,” adding that government’s ability to manage environmental impacts “continues to lag behind the pace and scale of new oilsands development, and new projects continue to be approved even though we don’t have enough information to understand the impacts.”

cema faces fundIng shortfall and uncertaIn future

he head of an organization created to advise the federal and provincial governments on the cumulative environmental impacts of oilsands development says it has the power to tell governments when it’s time to slow down expansion. “We can do that to a degree,” says Glen Semenchuk, executive director of the Cumulative Environmental Management Association (CEMA). “We can set a tipping point. When it gets to a certain point that the monitoring agencies say we can accommodate one more plant, we can say if we go beyond this point there will be dire consequences.” However, it’s not certain CEMA will exist long enough to make that pronouncement. In mid-December, CEMA announced it was facing a funding shortfall due to a 15 per cent reduction in funding from the Oil Sands Developers Group (OSDG).

That group, which represents most of the companies involved in the oilsands, announced it will provide $5 million towards CEMA’s budgeted $9.6-million work plan this year. In the past, Alberta Environment and Water has contributed the balance of CEMA’s funding, but it is not likely to boost its funding to fill the gap created by OSDG’s reduction. “CEMA is now facing a significant budget shortfall for its 2012 operations,” Semenchuk said in December, adding that it would mount an “aggressive campaign” to fill the funding gap. The association’s mandate was established in 2000 by Alberta Environment, which identified 72 issues it wanted to see addressed in the oilsands, with CEMA being tasked with 38. One of those issues, the critical load of nitrogen in the air in the Regional Municipality of Wood

Buffalo, will require long-term research. Semenchuk says CEMA has only completed the first year of research. However, he believes the organization’s work should continue well into the future. “We’ve only scratched the surface now [of oilsands development in the Athabasca region],” Semenchuk says. “We’re at five to 10 per cent of the land surface having been developed. What happens when we get to 50 per cent?” Over the next several months, he and others at CEMA will learn if they, another agency on its own, or CEMA in combination with another agency will carry out its mandate in the future.

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locations (to monitor the quality of air moving out of the oilsands area). • Improved monitoring of potential sources of air contaminants to improve understanding of the levels of contaminants that are being emitted to the air from all oilsands-related sources. • Improved monitoring to understand contaminant pathways, as well as how they move in the air and where they are deposited. • Improved monitoring methodologies that use remote imagery, mobile monitoring systems and refined monitoring networks based on the results of special studies designed to identify locations that may experience impacts. The program will also include habitat monitoring. This will involve core biodiversity monitoring extending beyond the Lower Athabasca region to include all current and potential oilsands-producing areas and new cause-effect monitoring throughout the oilsands areas to better understand different land disturbances. It will also include a new, continuously updated “wall-to-wall” human-disturbance map developed to

Photo: JoEy Podlubny

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reclaimed land outside the Syncrude main plant north of Fort McMurray, Alta.

ramp soldIers on despIte heavy crItIcIsm of oIlsands water-monItorIng efforts

t hasn’t exactly been smooth sailing recently for those involved in the organization responsible for surface water monitoring in the oilsands region of northeastern Alberta. In fact, it’s been more like Chinese water torture. Four different assessments of environmental monitoring in the region over the last two years—including federal and prov incial panels and the Royal Society of Canada—have saved much of their criticism for the Regional Aquatics Monitoring Program (RAMP). “Although we are confident it was conceived and currently implemented by people with the best of intentions, it is not designed to be systemic, holistic or adaptive,” the federally appointed Oil Sands Advisory Panel wrote. It got worse. “[T]he program suffers from a lack of scientific leadership…. It is not

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producing world-class scientific output in a transparent, peer-reviewed format and it is not adequately communicating its results to the scientific community or the public,” the report continued. “There is a perception that RAMP is designed to fulfill permit requirements but is not adequate for quantifying ecosystem change as a result of oilsands development.” Despite the criticisms, one of R AMP’s former founding managers believes it can and should play a role in ongoing monitoring. Chris Fordham, now working as the manager of sustainability strategy for Suncor Energy Inc., disputes criticism that the program had not been transparent enough with its information, pointing to its website (ramp-alberta.org), where data is available on an ongoing basis. However, he acknowledges that funding for RAMP—all from industry—should

have been larger. It has grown from about $2 million to $5 million this year. RAMP monitors the Lower Athabasca region, which extends from the AlbertaSaskatchewan border to Wood Buffalo National Park, and includes the Athabasca River and the Peace-Athabasca delta, as well as its tributaries, associated wetlands and numerous lakes. Its monitoring program is aimed at measuring climate and hydrology, benthic invertebrate communities, water and sediment quality, fish populations and acid-sensitive lakes. Fordham says he has “heard rumblings” that RAMP may be replaced entirely as part of a regional watermon itoring program, but he says the program could also be broadened, with more funding and paid staff (it operates completely on a volunteer basis). “Whatever happens, aquatic monitoring will always be a part of overall monitoring in the region,” he says.

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BIodIversIty Is more challenged In alBerta outsIde of the oIlsands: aBmI

ntensive agricultural development in southern Alberta is more ecologically destructive than oilsands development in northeastern Alberta, according to studies recently completed by a government- and industry-supported agency that measures the biodiversity in different areas of the province. It’s an irony not lost on Kirk Andries, executive director of the Alberta Biodiversity Monitoring Institute (ABMI). “Despite all of the attention being paid to oilsands development in northeastern Alberta, our work shows there has been more destruction of the biodiversity in southern Alberta, mostly because of intensive agricultural development, than in northeastern Alberta,” he says. “Where there is intensive cereal crop production, biodiversity is very low, with it becoming less so in grazing areas. The biodiversity of southern Alberta has been severely compromised.”

The ABMI monitors the state of water, land and living resources across the province, relying on scientifically credible indicators of environmental health. Established five years ago, it has an annual budget of $9 million and has a board that includes academics, representatives of environmental groups and senior government officials. Andries says the ABMI will be producing a wide-ranging report this June on the state of biodiversity in the Lower Athabasca region, which will include the status of lichens, mosses, soil arthropods, fungi, wetland invertebrates, habitat quality and other measures. In time, it plans to produce similar reports for all of Alberta. This data will create a baseline of information that will be a critical part of the Lower Athabasca Regional Plan now being finalized, and in land-use plans province-wide.

“The ABMI will be a part of any new [monitoring] model, regardless of what it looks like.” — kirk andries, executive director, alberta biodiversity Monitoring institute

“The work the ABMI is doing sets the benchmark for the environmental health of Alberta today and will play a significant role as the province implements a cumulative-effects approach to managing the environment and ecosystem,” Andries says. He believes the research-based organization, which is housed at the University of Alberta, will be a part of any future joint Alberta-federal government approach to managing the impacts of oilsands development. “The ABMI will be a part of any new model, regardless of what it looks like,” he says. h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

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oilsands allies inside a growing trend toward industry collaboration in support of environmental performance improvement by Peter Mckenzie-brown

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Beyond the OSTC and OSLI, many technical organizations help contribute to industry innovation, including the Canadian Oil Sands Network for Research and Development (CONRAD) and Petroleum Technology Alliance Canada (PTAC). OSLI members support both PTAC and CONRAD, but the newer groups are designed to have a wider scope and faster uptake. Environmental consortia like OSLI and the OSTC are focused on the idea that the industry should share its resources in those technical areas in which everybody can benefit from shared innovations. The OSTC includes all the major oilsands mining companies: Canadian Natural Resources Limited, Imperial Oil Limited, Shell Canada Limited, Suncor Energy Inc., Syncrude Canada Ltd., Teck Resources Limited and Total E&P Canada Ltd. Stringham says that the group “brings together all of the stakeholders that are involved in tailings through collaboration, breaks down the corporate barriers and enables companies to work together to find solutions” to a difficult environmental problem.

Similarly, OSLI is based on the assertion that the industry should only compete in areas where it makes economic sense to compete. As a collaborative network that includes ConocoPhillips Canada, Nexen Inc., Shell, Statoil Canada, Suncor and Total, OSLI has four main areas of focus: water management, technology breakthroughs, sustainable communities and land stewardship. The ultimate beneficiaries of the approach are local communities and the air, water and land affected by oilsands development and production. One of the key elements of OSLI is that it is designed to reduce cycle times and paperwork. For example, companies can share research without first signing joint-venture agreements. Also, it reportedly not only honours each company’s intellectual property, but honours rules about non-competitive behaviour. THE PuBLIC RELATIONS FACTOR It’s important to distinguish these new collaborative organizations from the

omentum is building in Canada’s heavy oil and oilsands sector towards a new reality where project owners are able to work together to achieve successes they couldn’t have alone, either as quickly or as completely. Make no mistake: competition in the sector is fierce, but not in all areas of development—companies are finding that, in many cases, it makes more sense to collaborate than to fight. “The idea has really caught fire,” says Greg Stringham, vice-president of oilsands and markets with the Canadian Association of Petroleum Producers (CAPP). “This is the first time [industry has] come together in such a collaborative manner.” Canada’s petroleum industry has long been an alphabet soup of industry associations and other forms of joint ventures, but new developments—such as the 2010 creation of both the Oil Sands Tailings Consortium (OSTC) and the Oil Sands Leadership Initiative (OSLI)—may represent the beginning of an unstoppable trend.

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many others that exist. For example, the In Situ Oil Sands Alliance describes itself as having been formed in 2007 to address “geopolitical, economic, ecological, infrastructure and social realities” facing in situ oilsands producers. Largely, the responsibility rests on CAPP’s shoulders to manage oilsands communications. By contrast, OSTC executive director Alan Fair says his organization and OSLI do very little in terms of communication with the public. “It is quite important to keep [technical] organizations separate from the ones that have communication as their focus. [Our] purpose is to raise the environmental bar for the industry.” From his perspective at CAPP, Stringham recognizes the importance of both functions. “We understand how foundational environmental performance is. It isn’t only about perception; it’s also about the performance aspects of the development of the oilsands.” For its part, CAPP launched a program in 2010 called Responsible Canadian Energy based on transparent

communication of performance data from energy production operations across the country. Stringham says that the issue isn’t really about collaboration or competition; the industry needs both. “In downhole and extraction technologies and everything else that’s involved with taking oil out of the ground, the competition is intense. However, in the environment, we don’t compete. By working together we can make sure that everybody is using the latest and the best environmental technologies…. Environmental issues are not a competitive concern, but something that needs to be worked on collaboratively.” For example, as Fair points out, there really aren’t any serious issues around land ownership in the oilsands sector anymore. For the most part, land ownership has already been established; properties don’t often change hands. “Now the public has an expectation that the companies will work together to meet some of these environmental challenges. From a business perspective, any time you can get a group of companies

to work together, you eliminate duplication of effort and the industry as a whole becomes much more efficient.” This is particularly important for an industry that faces not only a volatile market environment and uncertain global outlook, but also an increasing level of hyper-scrutiny from environmental groups. ROLE REvERSALS In a very real sense, the industry’s use of these technical consortia is a leveraging of one of the great traditions of the oilsands sector. The leading edge of good oilsands development has always been science, and some of the most significant developments have been the result of collaborative groups. One of the first important investigators of the oilsands industry, about 100 years ago, was a scientist employed by the Geological Survey of Canada named Sidney Ells. The Alberta Research Council’s Karl Clark came in the 1920s, and his hot-water extraction process fundamentally transformed the sector. h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

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The continual presence of provincial funding for basic oilsands research— even during the Great Depression, when Alberta defaulted on its debt—has played a vital role in helping make the industry viable. After the Geological Survey came the Alberta Research Council, which was followed 50 years later by the Alberta Oil Sands Technology and Research Authority (AOSTRA). AOSTRA used government funding to encourage the industry to invest in the oilsands. According to industry consultant Bob Taylor, it “was the major catalyst in leapfrogging oilsands development forward.” AOSTRA’s main focus was to make in situ resources both technically and economically recoverable. More than $1 billion of spending in field pilots resulted, and AOSTRA activity led directly to the definitive proof of steam assisted gravity drainage (SAGD). Fast forward to the present. One of the current iterations of public investment in the industry is Alberta Innovates – Technology Futures. This Crown corporation trend incorporates the 90-year-old Alberta Research Council and plays an important role in moving technologies along the development path. There is also Alberta Innovates – Energy and Environmental Solutions, another highly respected Crown corporation led by chief executive officer Eddy Isaacs. It’s an important source of expertise for the sector, with a tremendous reservoir of expertise and experience—for example, senior advisor Duke du Plessis began research on the oilsands more than 50 years ago. But as it applies to energy, the Alberta Innovates initiatives are relatively small. This raises the question of whether the province—the owner of the resource—is doing enough to encourage the development of new oilsands technologies. Put another way, in recent years there has been no AOSTRA-like leadership in advancing oilsands-related technological innovation in the province. 112

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AOSTRA 2 AND NASA II? Last May, the Premier’s Council for Economic Strategy recognized this issue, identifying it in a report titled Shaping Alberta’s Future. The group proposed creating the Global Centre for Energy, which would “require collaboration among industry, researchers and government,” the report proclaims, adding that “to ensure Alberta realizes the full potential of its energy resources over the decades to come, it is time to launch another large-scale collaborative effort like AOSTRA and make it a strategic priority for the province.” The authors suggested a program that is “a crucible for accelerating innovation to transform environmental and operational performance. Design it to be a catalyst and funder of collaborative research, a meeting place of diverse interests, and a showcase of achievement. Make Alberta internationally respected for pioneering research, with authoritative evidence and industrialstrength solutions.” Unfortunately, the Premier’s Council on Economic Strategy now reports to the Cabinet Office rather than the Premier’s Office. Perhaps this explains why there are no bold initiatives in sight. Doug James and Bob Taylor—the main forces behind the Energy Futures Network, a think tank—have put forward to both government and industry the notion that the province needs to bring more resources to bear on the oilsands. In a paper titled AOSTRA 2, they make a strong case for a new collaborative industry/government research and development program. “This must be a private-public initiative from the beginning,” they argue, “but it would be best if it were industry led.” The paper is full of ideas and principles, but the authors’ main concern is that “multiple technologies needed to be developed in parallel, both to share cost and risk and to move more quickly.” They propose an organization that sets the goal, but doesn’t predetermine how—a bit like NASA’s approach to landing on the moon. On the issue of NASA, perhaps it’s best to leave the last word to Preston

Manning—head of the Manning Foundation for Building Democracy. In a recent presentation to an OSLI “Big Ideas” forum, Manning proposed the notion of collaboration on a continental scale. “Today, both Canada and the U.S. have a somewhat different security concern: the need to reduce North American dependence on offshore petroleum resources and increase the availability and delivery of North American sources [of ] energy. So why not agree on sustainable continental energy security as a mutual goal and establish a similar organization to NASA—NASA II, where NASA stands for the North America Sustainability Agency—to bring largescale public and private resources and scientific expertise in both our countries to bear on the goal of sustainable continental energy security?” THE NExT STEP A new collaborative group is set to emerge from the collaborative foundations in the oilsands sector, reportedly a consortium that will take this approach to the next level. Although the details were still pending at press time, the group—called Canada’s Oil Sands Innovation Alliance—is understood to become a forum for the 13 largest oilsands companies to share intellectual property related to land, water, greenhouse gases and tailings. This could be another important step, but it also represents a new challenge that Deloitte & Touche LLP outlined in the recent research paper Gaining ground in the sands 2012. Deloitte points to increased collaboration in the industry as a key piece of its future success, but warns that “a problem for broader oil and gas industry associations in 2012 could suddenly and paradoxically be one of an embarrassment of riches—that is, a risk of redundancy and miscommunication between the growing roster of associations, none of which represents all of the oilsands industry or all of the oilsands industry exclusively.”

Isn’t it time your career picked up a little steam? Thermal Heavy Oil is an exciting growth area for Devon. It is part of our future and we’re working hard to significantly grow production over the next decade. With a significant acreage position in the southern Athabasca oil sands, demonstrated technical expertise and positive stakeholder relationships, Devon has earned the reputation of an industry leader. In addition to the award winning Jackfish facility and its two look alike projects, Devon is in the early stages of multiple development phases of a new program called Pike. In order to help us reach our goal, we need more great employees. If you’re interested in joining our growing team, please visit jobs.dvn.com.

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Upgrading in Alberta:

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by neil levine

illuStration: angiE CaStaldi

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“At some point in the future there may be other situations where the [Alberta] government would see a need or opportunity to play a role in encouraging [upgrading] here. But any situation would need to have a credible business case for Albertans.” — Mike Ekelund, assistant deputy minister, strategic initiatives, alberta Energy

is essentially all of mined production and 11 per cent of in situ volumes. The NEB predicts that upgraded bitumen volumes will roughly double to 1.9 million barrels per day by 2035, but will not keep pace with overall increases in bitumen production. “The portion of total bitumen production that is upgraded declines from 49 per cent in 2010 to 37 per cent in 2035.” The Government of Alberta’s Hydrocarbon Upgrading Task Force recommended in 2007 a goal of onethird bitumen sales, one-third synthetic crude oil sales, and one-third finished products and petrochemicals, but this remains an “aspirational goal” rather than an achievable result. THE PROJECTS IN PLAy Suncor Energy Inc.’s 200,000-barrelper-day Voyageur upgrader (its third) was originally announced in 2001, but shelved during construction in January 2009 due to shaky financial markets as a result of the global financial crisis. Voyageur is a key piece of Suncor’s $1.75-billion joint venture with Total E&P Canada Ltd., which was announced in late 2010. The project is now scheduled to begin operations in 2016, but the restart of construction has not yet been approved by Suncor’s board. Total had planned its own upgrader near Edmonton, but cancelled the project in favour of the venture with Suncor.

The second upgrader moving forward in Alberta is the North West Redwater Partnership, a joint venture between North West Upgrading Inc. and Canadian Natural Resources Limited, located north of Edmonton. The project will use bitumen feedstock contracted from the Government of Alberta’s Bitumen Royalty in-Kind program as well as volumes from Canadian Natural to produce ultra-low-sulphur diesel fuel. The first 50,000-barrel-per-day phase also incorporates a carbon management component. With all regulatory approvals in place and board approval pending, the Redwater project is expected to put shovels in the ground by the summer of 2012, and have its first phase on stream in late 2014. The expected cost is $5 billion for the first phase, with the possibility of three additional 50,000-barrel-per-day phases. The Government of Alberta has said, however, that it has no plans to incent other upgrading projects at this time. “At some point in the future there may be other situations where the government would see a need or opportunity to play a role in encouraging processing here,” says Mike Ekelund, assistant deputy minister, strategic initiatives, at Alberta Energy. “But any situation would need to have a credible business case for Albertans.”

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espite two important new projects progressing towards realization, the future of bitumen upgrading in Alberta remains a shadow of what it was just a few short years ago. Before fall 2008, as many as seven new projects promising more than 1.5 million barrels per day of new capacity were on the advance, but that all fell apart. The global recession of 2008 provided the final blow to the market for new upgrading installations in Alberta, already damaged by industrial construction costs that had spiralled out of control. Upgrading projects dropped off the development queue, with the exception of the 100,000-barrel-per-day integrated mining/upgrading capacity boost to the Athabasca Oil Sands Project, which was commissioned in spring 2011. The slowdown in oilsands development has been over for more than a year for upstream production projects. The key measure of economics for new upgrading projects—the price spread between light and heavy crude— remains unsupportive. “Over the period [of] 2008-10 the differential between light and heavy crude prices has been relatively narrow, and is projected to remain narrow for the near to medium term,” wrote National Energy Board (NEB) researchers in the November 2011 report Canada’s Energy Future: Energy Supply and Demand Projections to 2035. “This, combined with the very high Capital costs of constructing upgraders, is not supportive of building greenfield upgrading facilities.” There are currently five bitumen upgrading facilities in Alberta. The Energy Resources Conser vation Board reports that in 2010 those installations produced just over 790,000 barrels per day of synthetic crude oil, or about 49 per cent of total production. This

p a R a F F I N I C

F R O T h

T R E aT M E N T

Photo: iMPErial oil liMitEd

Imperial Oil’s Kearl mining project, two phases of which are currently under construction, will incorporate paraffinic froth treatment. This will result in a higher-value crude without incorporating an upgrader in the project.

an incremental game changer high-temperature paraffinic froth treatment promises better efficiencies and ready access to refineries by r.P. Stastny

he pace of oilsands innovation is often described as “incremental,” largely because the sheer size of the capital investment in oilsands facilities doesn’t encourage straying far from the tried and true. Those who roll the dice often pay a hefty toll. Despite this conservative mindset, the industry has made real strides in reducing water consumption and improving thermal efficiencies through cogeneration. But more is needed. Producers recognize that in the face of mounting social and environmental pressure to clean up oilsands production, they have to take on more risk and accelerated innovation directed at reducing their environmental footprint. One technology stepping up to bat— and resulting in a higher-grade product prior to upgrading—is paraffinic froth treatment. The technology is already in service at Royal Dutch Shell PLC’s oilsands 11 8

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mine, and variations of the process are planned for Imperial Oil Limited at Kearl, Total E&P Canada Ltd. at Joslyn, Suncor Energy Inc. at Fort Hills and Teck Resources Limited at Frontier. Paraffinic froth treatment is an important base hit for the environment. Shell claims the technology improves the overall energy efficiency of processing bitumen to refined products such as diesel, gasoline and jet fuel by 10 per cent while reducing greenhouse gas emissions. This technology also reduces the physical footprint of a mine’s facility equipment by 35 per cent and requires 10 per cent less water. The benefits of the technology are realized by eliminating the need for bitumen upgrading, which is why some industry observers are calling paraffinic froth treatment a game changer. While conventional froth treatment creates only an intermediate product that has to be upgraded before it can go to a refinery,

paraffinic processing actually creates a marketable product in itself. This technology creates a bitumen stream that is light and clean enough to dilute and ship via third-party pipelines directly to refineries for processing, provided they have the capability to handle heavy sour crude—which most Chicago and Gulf Coast refiners do. RAINING HEAvy BOTTOMS Typical commercial oilsands mining operations involve mining the ore, crushing it, mixing it with hot water to create slurry, then piping it to a froth treatment facility and, finally, to upgrading. To promote the attachment of bitumen to air bubbles, the hot-water/bitumen slurry is aerated, either by hydrotransport or in steam tumblers, creating a lowerdensity froth. Froth treatment removes the water and fine solids in preparation for upgrading.

p a R a F F I N I C

Froth treatment is either a naphthenicor paraffinic-based process in the oilsands. The more common is the naphtha-based process. Shell, however, has traditionally used low-temperature froth treatment. In cooperation with the energy technology arm of the federal government, CANMET, Shell developed what it calls “Shell Enhance,” a higher-temperature, higherpressure variation of froth treatment. By using higher temperatures, higher pressures and a lighter solvent than naphtha—a paraffin—fine clays and water are more effectively removed while precipitating the heaviest hydrocarbon

components—the asphaltenes—out of the bitumen stream. The resulting bitumen product is lighter and cleaner, but it’s still much heavier than upgraded bitumen, a process that completely changes the characteristics of the bitumen by breaking up the long hydrocarbons into lighter oil. The paraffinic process, in other words, doesn’t physically alter the bitumen. It’s just more effective in removing the contaminants and it precipitates some of the heavy hydrocarbon bottoms, which is why it also yields about eight to 10 per cent less bitumen volume

— Pius rolheiser, spokesman, imperial oil limited

T R E aT M E N T

compared to traditional froth treatment processes, according to industry experts. GROWING INTEREST Imperial Oil developed a variation of Shell’s higher-temperature, higherpressure froth treatment for its Kearl oilsands mine. “Paraffinic froth treatment is not upgrading,” says Imperial spokesman Pius Rolheiser. “It’s a different process, which yields a lighter grade of bitumen.” Imperial expects similar reductions in energy usage, facility footprint requirements and water consumption as Shell in going to this technology. But one of Imperial Oil’s key environmental benefits is the ability to reduce greenhouse gas emissions. “The extracted bitumen will only need to be processed once rather than twice,” Rolheiser says. “Therein lies the significant reduction in greenhouse gas emissions. With paraffinic froth treatment, we estimate greenhouse gas emissions associated with each barrel of bitumen will become comparable to conventional crudes.”

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upgradIng + refInIng

“Paraffinic froth treatment is not upgrading. It’s a different process, which yields a lighter grade of bitumen.... The extracted bitumen will only need to be processed once rather than twice.”

F R O T h

O I L S a N d S

u p g R a d E R S

Photo: JoEy Podlubny

SunCOr

26 MAP REFERENCE

Project

Suncor Base and Millennium

Location

North Athabasca

Ownership

Suncor Energy Inc. 100%

Production start

1967

Current upgrading capacity (bbl/d)

357,000

Average daily synthetic crude oil production Jan.-Nov. 2011 (bbl/d)

260,441

Average daily synthetic crude oil production Jan.-Nov. 2011 (bbl/d)

231,669

Plant natural gas purchased 2011 (103M3 Jan.-Nov.)*

1,169,790

Plant natural gas purchased 2010 (103M3 Jan.-Nov.)*

834,326

Plant natural gas generated 2011 (103M3 Jan.-Nov.)*

Plant natural gas generated 2010 (103M3 Jan.-Nov.)*

25,000

Plant electricity purchased 2011 (MWh Jan.-Nov.)*

223,566

20,000

Plant electricity purchased 2010 (MWh Jan.-Nov.)*

240,093

15,000

Plant electricity generated 2011 (MWh Jan.-Nov.)*

2,411,943

10,000

Plant electricity generated 2010 (MWh Jan.-Nov.)*

2,597,289

Average price realization per barrel 2011

$88.74

Average price realization per barrel 2010

$69.58

In 2011, Suncor completed the largest-ever turnaround at the companyâ&#x20AC;&#x2122;s second upgrader, followed by its two highest quarters on record for oilsands production.

PRODUCTION

2009

2010

2011

45,000 40,000 35,000

(bbls/d)

30,000

5,000 0

Jan

Feb

Mar

Apr

May

SourCE: EnErgy rESourCES ConSErVation board

12 0

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Jun

Jul

Aug

Sep

Oct

Nov

*Natural gas and electricity may include operations beyond upgrading.

u p g R a d E R S

Photo: JoEy Podlubny

O I L S a N d S

Project

Syncrude Mildred Lake

Location

North Athabasca

Ownership

27 MAP REFERENCE

Canadian Oil Sands says that Syncrude production in 2011 was affected by the outage of the projectâ&#x20AC;&#x2122;s largest hydrogen unit, which reduced production by millions of barrels in the fourth quarter. As a result, the annual production target was missed. The company says this exemplifies the value of the effort underway to target unplanned capacity losses, expecting this to gradually result in increased capacity rates.

Production start

1978

Current upgrading capacity (bbl/d)

350,000

Average daily synthetic crude oil production Jan.-Nov. 2011 (bbl/d)

267,222

Average daily synthetic crude oil production Jan.-Nov. 2011 (bbl/d)

268,465

Plant natural gas purchased 2011 (103M3 Jan.-Nov.)*

2,122,785

Plant natural gas purchased 2010 (103M3 Jan.-Nov.)*

2,065,730

Plant natural gas generated 2011 (103M3 Jan.-Nov.)*

Plant natural gas generated 2010 (103M3 Jan.-Nov.)*

250,000

Plant electricity purchased 2011 (MWh Jan.-Nov.)*

679,688

200,000

Plant electricity purchased 2010 (MWh Jan.-Nov.)*

673,759

150,000

Plant electricity generated 2011 (MWh Jan.-Nov.)*

2,944,969

Plant electricity generated 2010 (MWh Jan.-Nov.)*

2,975,296

Average price realization per barrel 2011

$104.78

Average price realization per barrel 2010

$83.97

*Natural gas and electricity may include operations beyond upgrading.

upgradIng + refInIng

SynCrude

PRODUCTION

2009

2010

2011

450,000 400,000 350,000 300,000

100,000

(bbls/d)

50,000 0

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

SourCE: EnErgy rESourCES ConSErVation board

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O I L S a N d S

u p g R a d E R S

Photo: JoEy Podlubny

SCOtFOrd

MAP REFERENCE

Shell and its partners in the Athabasca Oil Sands Project celebrated the commissioning of a 100,000-barrel-per-day expansion to the Scotford upgrader on June 24, 2011. The project is the only major new upgrading capacity initiative to be completed in Alberta since the Long Lake facility was commissioned in 2008.

PRODUCTION

2009

2010

2011

450,000 400,000 350,000 300,000 250,000

Project

Scotford upgrader

Location Ownership

Industrial heartland Shell Canada Limited 60%, Chevron Corporation 20%, Marathon Oil Corporation 20%

Production start

2003

Current upgrading capacity (bbl/d)

249,000

Average daily synthetic crude oil production Jan.-Nov. 2011 (bbl/d)

195,447

Average daily synthetic crude oil production Jan.-Nov. 2011 (bbl/d)

110,326

Plant natural gas purchased 2011 (103M3 Jan.-Nov.)*

353,379

Plant natural gas purchased 2010 (103M3 Jan.-Nov.)*

343,975

Plant natural gas generated 2011 (103M3 Jan.-Nov.)*

Plant natural gas generated 2010 (103M3 Jan.-Nov.)*

Plant electricity purchased 2011 (MWh Jan.-Nov.)*

71,926

200,000

Plant electricity purchased 2010 (MWh Jan.-Nov.)*

110,005

150,000

Plant electricity generated 2011 (MWh Jan.-Nov.)*

995,097

100,000

Plant electricity generated 2010 (MWh Jan.-Nov.)*

722,252

Average price realization per barrel 2011

$93.81

Average price realization per barrel 2010

$74.96

(bbls/d)

50,000 0

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov *Natural gas and electricity may include operations beyond upgrading.

SourCE: EnErgy rESourCES ConSErVation board

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u p g R a d E R S

Photo: nEXEn inC.

O I L S a N d S

Project

Long Lake

Location

South Athabasca

Ownership

Nexen Inc. 65%, China National Offshore Oil Corporation 35%

upgradIng + refInIng

lOnG lAKe

29 MAP REFERENCE

Nexen is working on filling capacity at the Long Lake upgrader, reportedly focused on the continued drilling of high-quality resource at Long Lake and the advancement of development of a portion of the Kinosis lease. Nexen says the action plan is expected to provide an attractive return on capital as each incremental barrel of production contributes significantly to cash flow and profitability given the primarily fixed costs of the operation.

Production start

2008

Current upgrading capacity (bbl/d)

58,500

Average daily synthetic crude oil production Jan.-Nov. 2011 (bbl/d)

26,810

Average daily synthetic crude oil production Jan.-Nov. 2011 (bbl/d)

18,949

Plant natural gas purchased 2011 (103M3 Jan.-Nov.)**

195,805

Plant natural gas purchased 2010 (103M3 Jan.-Nov.)**

170,486

Plant natural gas generated 2011 (103M3 Jan.-Nov.)**

Plant natural gas generated 2010 (103M3 Jan.-Nov.)**

Plant electricity purchased 2011 (MWh Jan.-Nov.)**

625,630

Plant electricity purchased 2010 (MWh Jan.-Nov.)**

544,635

Plant electricity generated 2011 (MWh Jan.-Nov.)**

15,351

15,000

Plant electricity generated 2010 (MWh Jan.-Nov.)**

14,119

10,000

Average price realization per barrel 2011*

$96

Average price realization per barrel 2010

$85

PRODUCTION

2009

2010

2011

45,000 40,000 35,000 30,000 25,000

(bbls/d)

20,000

5,000 0

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

* Premium sweet crude to September 30 **Natural gas and electricity may include operations beyond upgrading. SourCE: EnErgy rESourCES ConSErVation board

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O I L S a N d S

u p g R a d E R S

Photo: JoEy Podlubny

hOrizOn

28 MAP REFERENCE

PRODUCTION

2009

2010

2011

45,000 40,000 35,000 30,000 25,000

Project

horizon

Location

North Athabasca

Ownership

Canadian Natural Resources Limited 100%

Production start

2008

Current upgrading capacity (bbl/d)

114,000

Average daily synthetic crude oil production Jan.-Nov. 2011 (bbl/d)

31,896

Average daily synthetic crude oil production Jan.-Nov. 2011 (bbl/d)

84,815

Plant natural gas purchased 2011 (103M3 Jan.-Nov.)**

396,396

Plant natural gas purchased 2010 (103M3 Jan.-Nov.)**

723,068

Plant natural gas generated 2011 (103M3 Jan.-Nov.)**

Plant natural gas generated 2010 (103M3 Jan.-Nov.)**

0 150,865

Plant electricity purchased 2010 (MWh Jan.-Nov.)**

68,204

15,000

Plant electricity generated 2011 (MWh Jan.-Nov.)**

482,725

10,000

Plant electricity generated 2010 (MWh Jan.-Nov.)**

752,073

Average realized price per barrel 2011*

$96.19

Average realized price per barrel 2010

$81.51

(bbls/d)

Plant electricity purchased 2011 (MWh Jan.-Nov.)**

20,000

5,000 0

Jan

Feb

Mar

Apr

May

SourCE: EnErgy rESourCES ConSErVation board

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h E aV y o i l & o i l S a n d S g u i d E b o o k V i i

Jun

Jul

Aug

Sep

Oct

Nov *To September 30. **Natural gas and electricity may include operations beyond upgrading.

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N E w

u p g R a d E R S

The Redwater Upgrader will be the first facility to process Bitumen Royalty in-Kind volumes on behalf of the Government of Alberta, in addition to merchant volumes including those from project partner Canadian Natural Resources. Project sanction on the first 50,000-barrel-per-day phase is expected in 2012, with approximately 30 months of construction to follow.

PLAY

Project

Redwater upgrader

Location

Industrial heartland

Ownership

North West upgrading Inc. 50%, Canadian Natural Resources Limited 50%

Capacity (three-phase total, bbl/d)

150,000

Planned start-up

2015

Projected cost

$5 billion

Wellpad Specialists

DALLAS: 214.368.6391 CALGARY: 403.266.8680

• •

HOUSTON: 713.273.8300 MOSCOW: 7095.937.8374

COMPLETE EVALUATION OF ALBERTA OIL SAND DEPOSITS Geological mapping and modelling of ore bodies and depositional environments Mining reserves/resources determination using NI 51-101 criteria Steam Assisted Gravity Drainage studies (SAGD) Cyclic Steam Simulation (CSS) Compositional modelling Sensitivity analysis Development planning Water use forecasting Transportation and marketing analysis Application to regulatory agencies Pilot project design assistance

DeGolyer and MacNaughton Canada Limited 1430, 311 - 6 Avenue SW Calgary, AB Canada T2P 3H2

www.projex.ca

Tel: 403.266.8680 Fax: 403.266.1887 degolyercal@demac.com

www.demac.com

12 6

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WORLDWIDE PETROLEUM CONSULTING IN OVER ONE HUNDRED COUNTRIES

Photo: north wESt uPgrading inC.

redWAter

N E w

u p g R a d E R S

Photo: JoEy Podlubny

VOyAGeur Suncor suspended construction on Voyageur—its third upgrader—in January 2009, citing market conditions for limiting growth. Things started to look up for Voyageur in late 2010, when Suncor and Total announced a $1.75-billion deal to join forces on three projects, including the Voyageur upgrader. Suncor’s near-term focus for Voyageur is around remobilizing the workforce, confirmation of current design and modification of project execution plans.

voyageur

Location

North Athabasca

Ownership

Suncor Energy Inc. 51%, total E&P Canada Ltd. 49%

Capacity (three-phase total, bbl/d)

190,000

Planned start-up

2016

Projected cost

$11.6 billion

upgradIng + refInIng

Project

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people

130

DAVE HArPEr Ledcor Group of Companies

132

AlAN FAIr Oil Sands Tailings Consortium

134

BIll MCCAFFrEY MEG Energy Corp.

136

STEVE WIllIAMS Suncor Energy Inc.

138

ANDrEW lEACH University of Alberta

140

JANET HOlDEr Enbridge Inc.

142

BIll MCKIBBEN Environmental Activist

144

lES lITTlE Alberta Innovates - Energy and Environment Solutions

146

DANA WOODWOrTH Alberta Energy

148

lEI JIANZHONG People’s Republic of China

people

Photo: MEg EnErgy

TEN PEOPLE AT THE FOREFRONT OF CANADIAN OILSANDS ISSUES

p R O F I L E S

“Ledcor was one of the first construction companies in Alberta to utilize temporary foreign workers to assist in the construction of an oilsands project. Our first LMO [Labour Market Opinion] was approved by the federal government in 2005. We have recently applied for an LMO for our current backlog of projects.” Photo: lEdCor

Dave Harper

vice-president, operations, fabrication and module assembly, Ledcor Group of Companies

ilsands production and upgrading projects offer a perfect storm of challenges for the companies that build them—large, complex facilities located in a remote, cold-weather region with limited available labour. In order to maximize returns on investment, control project schedules and optimize worker safety and comfort, oilsands builders have turned to a module-based construction approach. Manufacturing and fabricating the pieces off-site based on the design concept of building blocks minimizes the amount of work done in the field and can equate to more cost-effective and higher-quality execution. Ledcor is on the leading edge of modular fabrication and assembly for oilsands projects, a segment currently led by Dave Harper.

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p R O F I L E S

Why has modular construction become such an important approach for oilsands projects? There are numerous benefits to modularization, but cost and efficiency are the primary factors. It is more efficient and cost effective to modularize components versus stick building in the field [installing components in the field]. It allows for an efficient construction sequence and allows field civil programs to run concurrently with module assembly programs, making module erection in the field very rapid and efficient. Civil scope would include site clearing, rough and final grading, piling, concrete foundations and paving. While this strategy is growing, it is not new. What is different about module fabrication, transportation and field assembly today versus 20 years ago? In Alberta there is a limitation on the size of modules that can be shipped on the heavy-load corridor. The difference is engineers and contractors are exploring ways to maximize the modularization of the plants, i.e. a building module erected at site consisting of two, three or four modules. What do you see as the biggest challenge facing Alberta’s module fabricators? The largest challenge facing the industry will be qualified labour to fabricate modules. We are looking for people in all kinds of construction trades—carpenters, pipefitters, welders and

“The largest challenge facing the industry will be qualified labour to fabricate modules. We are looking for people in all kinds of construction trades—carpenters, pipefitters, welders and electricians, etc.” electricians, etc. In addition, there are engineering, scheduling and project management positions that need to be filled. Ledcor was one of the first construction companies in Alberta to utilize temporary foreign workers to assist in the construction of an oilsands project. Our first LMO [Labour Market Opinion] was approved by the federal government in 2005. We have recently applied for an LMO for our current backlog of projects. As the market heats up, there will likely be new programs developed and introduced to attract and retain labour. In the past, there have been programs that pay anywhere from $1–$3 per hour on top of workers’ regular wages, based on a set of criteria.

people

Alberta-based ATCO Group, with more than 8,800 employees and assets of approximately $12 billion, delivers service excellence and innovative business solutions worldwide with leading companies engaged in Structures & Logistics, Utilities, Energy and Technologies.

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p R O F I L E S

â&#x20AC;&#x153;Our stakeholders expect collaboration. They want to see the [oilsands] industry work together to develop solutions to environmental challenges.â&#x20AC;?

Photo: JoEy Podlubny

Alan Fair

isually, tailings ponds are the oilsands industry at its worst. Although these large settling basins where water slowly separates from the by-products of bitumen extraction are a necessary piece of the operational process, they currently occupy about 170 square kilometres and are a hazard to wildlife. They are too big, and there are too many of them. Industry has been aware of its tailings challenge for decades, but its action to address the problem has been accelerated, largely due to new regulations by the Alberta Energy Resources Conservation Board (ERCB). In 2010, all seven major oilsands mining firms formally joined together to drop the barriers of intellectual property in order to advance and commercialize tailings solutions. It is the job of Alan Fair, former manager of research and development at Syncrude Canada Ltd., to guide this process.

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Executive director, Oil Sands Tailings Consortium

Collaboration seems to be a growing theme in the heavy oil and oilsands sector. Why do you think this is and what do you expect the results will be? Our stakeholders expect collaboration. They want to see the industry work together to develop solutions to environmental challenges. Collaboration has been underway since back in the early 1990s, but the urgency has increased. Where [companies] want to compete is on operational excellence and on lease position. Recognizing the value of collaboration on oilsands research and development [R&D], industry is now taking another significant step. Months of planning went into the creation of the group announced in February, the Canadian Oil Sands Innovation Association [COSIA], [designed] to work together on land reclamation, revegetation, treatment of water and water quality, and greenhouse gases.

p R O F I L E S

Based on the OSTC [Oil Sands Tailings Consortium], COSIA encompasses the Oil Sands Leadership Initiative and the Canadian Oil Sands Network for Research and Development, and will be supported by most of the surface mining companies and many of the in situ companies. Specifically regarding the OSTC, what impact has the ERCB’s Directive 74 had on the development of tailings technology solutions? It defines the regulatory expectations for all of the operators. In the 2012 reporting year, 50 per cent of the fines in the feed being mined have to be captured in defined disposal areas [DDAs]. This is the first year the shear strength [cohesiveness of the tailings deposit] has to be reported. The requirement is that five years after the last layer is added to a DDA, the deposit has to have sufficient shear strength that you can cap it and reclaim the area. OSTC is working with the ERCB to develop measurement protocols for tailings shear strength, so there is consistency of measurement among companies despite differences between their tailings treatment methods. The directive is better suited to some kinds of tailings deposits than others, so we’re working with the ERCB to broaden the directive.

What has the OSTC achieved to date and what are the group’s near-term goals? OSTC spent its first six months addressing the immediate requirements of Directive 74. We held workshops and a retreat to share information and coordinate fieldwork, given that several field programs were underway to advance the development of various tailings technologies. We committed $90 million to tailings R&D in 2011 and agreed to fund the Oil Sands Tailing Research Test Facility at the University of Alberta for another five years. We’re now creating a framework for the future. Working with a number of provincial and federal government departments, we’ve put together our first tailings road-map study to define a game plan. We developed environment, society, economic and technical evaluation criteria aimed at assessing the current status of tailings technologies and determining what is required for commercial implementation. Through the spring, the steering committee is determining its long-term strategy and the technical committee is planning how it will respond to those strategic requirements. We’re looking towards the timely deployment of technologies, supporting R&D of next-generation technologies, information sharing and technology transfer, and developing a performancebased framework for adherence to commitments.

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“I think the success we’ve achieved so far comes from the approach to innovation that’s in MEG’s corporate DNA. We’re always challenging ourselves to learn from what we’ve done, to drive new ideas and to try to think about different opportunities as we develop our strategies.” Photo: MEg EnErgy

Bill McCaffrey

President and chief executive officer, MEG Energy Corp.

n just over 10 years, junior MEG Energy Corp. has grown from an idea in a basement to a major and growing player on the oilsands landscape, consistently achieving success in business strategy and production efficiency. MEG’s in situ project at Christina Lake not only has production rates that are regularly above capacity with industry-leading steam to oil ratios, but it is also uniquely connected to market through MEG’s 50 per cent stake in the Access Pipeline. The company is also building a large storage terminal near Edmonton to further support its midstream initiatives. The strategy behind the decisions that have delivered these results, among many others, have been guided by MEG founder Bill McCaffrey.

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p R O F I L E S

MEG is quickly building a reputation as an oilsands leader in production performance and strategy innovation. To what do you attribute this success? Given the strong track records of many of our peers, it’s very flattering to be called a leader. I think the success we’ve achieved so far comes from the approach to innovation that’s in MEG’s corporate DNA. We’re always challenging ourselves to learn from what we’ve done, to drive new ideas and to try to think about different opportunities as we develop our strategies. That can mean focusing on where the barrels go, like our “huband-spoke” approach, to marketing with proprietary pipeline capacity and storage terminals. And it can also mean taking a hard look inside our existing operations to see how we can create new value by leveraging technology and the wealth of experience of our people to drive efficiency. What is MEG’s view of “value-added” processing in Alberta versus shipping raw product to other markets? To realize the maximum value from our resources, we need both diverse products and diverse markets. Car manufacturers and smartphone makers don’t focus on one single product and one single market—they take a more flexible portfolio approach. The same is true for Canada’s energy industry. We already have a globally important resource base and a range of products— and we should be taking a global view of demand and reaching

“We may never be the biggest volume producer in the oilsands business—and that’s okay. But I would like to see MEG continue to focus on striving to be the best at everything we do.” out to new markets. We need to look at the whole spectrum of options in our portfolio and determine where the best value is for the industry and for all of Canada. What would you say is MEG’s long-term goal in this sector? We may never be the biggest volume producer in the oilsands business—and that’s okay. But I would like to see MEG continue to focus on striving to be the best at everything we do: to have one of the highest returns on investment and to be a company that communities and other companies want to do business with. That goal goes hand in hand with being viewed as an in novator and, hopefully, being known as one of the best places in the industry to work creatively, have fun and develop a career.

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“Suncor has an exciting future and growth plan[s]. We have the resource, the experience and the knowledge. We have always been recognized as a company that develops this great [oilsands] resource responsibly; this will continue regardless of any business environment changes.” Photo: SunCor EnErgy

Steve Williams

n late 2011, long-time Suncor president and chief executive officer Rick George announced his retirement, slated for spring 2012. Chief operating officer Steve Williams will take over the helm of the oilsands mogul in a succession plan that has been under development for over five years. George says that Suncor is a 50–100-year company, and this is its next leg in the journey. Williams says, among other things, that his job is to increase its market capitalization from $50 billion to $100 billion.

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Incoming president and chief executive officer, Suncor Energy Inc.

Suncor is embarking on a period of major growth in its oilsands operations, and although these will be major projects, this is not the first time the company has moved forward with such significant growth. What has changed about the business environment? In December 2010, Suncor launched a decade-long growth plan, one that is expected to boost our total production to one million barrels of oil equivalent per day by 2020. This growth period not only looks different because of external factors such as escalating oil prices and the labour market, it also feels different because of how we’re approaching it internally. Today we have a very disciplined capital program and an increased focus on operational excellence. That discipline and operational excellence means we’ll follow world-class processes, complete the engineering and procurement prior

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to mobilizing construction and keep workforces to a manageable size to facilitate measuring productivity. We’ll award smaller, bite-sized contracts to contractors we’ve worked with for many years that have proven track records in our industry, and we will continue to apply lessons learned across all projects. Growth projects will be focused on quality and cost and not driven by schedule. It is important for us to manage costs so we can deliver a quality project and more long-term value for our shareholders. Another significant difference this time ‘round is the appetite for collaboration in our industry. We know it is necessary to improve our social and environmental performance, and Suncor will be instrumental in leading and driving this industry collaboration. Suncor has an exciting future and growth plan[s]. We have the resource, the experience and the knowledge. We have always been recognized as a company that develops this great resource responsibly; this will continue regardless of any business environment changes. What are Suncor’s key areas of focus in the next year? Suncor will diligently pursue its continued focus on operational excellence. A key element of operational excellence is safety. We want everyone to go home to their loved ones every night—no business result takes precedence over this.

Over the years, we have steadily improved our safety and environmental results. These results have laid the groundwork for the strong operational performance across the business that we are now seeing. We will maintain this continued focus on safe, reliable, environmentally responsible operations. We’ll be focused on project execution on all of our projects: the ramp-up of Firebag 3 and continued work to bring Firebag 4 to near completion, and also the implementation of our joint venture with Total E&P Canada. Suncor has taken a leadership position in collaboration within the oilsands sector. Why? We believe we have a responsibility to do so. Solving the environmental challenges that face our industry should not be seen as a competitive advantage. [For example] our tailings management technology will help solve a problem that challenges the whole industry. As an industry, we’re stronger when we work together; when we team our high-calibre scientists and biologists and engineers up with those in other companies/organizations, we’ll achieve results more quickly, more cost effectively and with a better environmental outcome. We have reason to be optimistic through our involvement in the Oil Sands Leadership Initiative and the Oil Sands Tailings Consortium; we’re seeing the sharing of ideas and technologies that are helping to drive forward solutions and move us forward on the environmental front.

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“The oilsands industry needs to show it can exist under policies that meet national and international environmental goals—not that it should be exempt because the world needs oil.”

Photo: JoEy Podlubny

Andrew Leach

niversity of Alberta economist Andrew Leach has emerged recently as a constructive and balanced voice, offering realist analysis of issues facing the oilsands sector and how those issues entwine with the Canadian—and North American—economies. His blog at andrewleach.ca, Rescuing the Frog, and Twitter feed have become “mustfollows” for those interested in the larger trends and challenges for Canada’s unconventional oil.

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Associate professor, marketing, business, economics and law, university of Alberta

What are the biggest challenges facing the oilsands industry? I see three: managing local cost inflation, market access and social licence. Operating costs are expected to increase five to 10 per cent per year; labour costs have risen on average seven per cent per year for a decade. Looming labour shortages make more-rapid cost increases likely. This inflation has been both caused by and compensated for by oil prices far outstripping forecasts. Cost escalation makes investment look more risky than it should and

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disperses the value of the oilsands far beyond Alberta’s borders. We’re used to break-even as being $20 per barrel under current oil prices. Let’s not lose sight of how prices have increased and the impact if we retreat to $40 or $50 per barrel. Market access is a growing risk, one ignored for too long. If new pipelines are not built by 2020, we will see an Alberta discount as shippers turn to more expensive, less secure means of transport. New projects will see less upside potential as new production would add to the discount and erode returns. This is in no way akin to staged development to ease the overheated oilsands economy. The value in oilsands would be eroded. Finally, social licence. The small fraction of oilsands reserves currently under development has a value greater than our coal, conventional oil and natural gas combined—$35,000 per Canadian. Mainly because of the environmental risks and uneven distribution of benefits, some Canadians oppose development. The vast majority support it if—of crucial importance—environmental controls are appropriate, and development fits Canadian values. That support is essential to expansion. What do you think are the most significant things this sector has working in its favour? The chance to change public opinion. If the industry can look at improved performance in the same way it does

market access, in dollar-per-barrel terms, and see the strategic value of improving environmental performance plus communicating effectively—not either one alone—the future looks much brighter. How would you characterize your view of this industry’s future? Risky. It’s disappointing to use that word, but 2011 saw significant changes. The Keystone XL debate in the United States, regulations discriminating against oilsands-derived fuels in California and the European Union, and opposition to Northern Gateway in Canada have made it clear that projected export growth is not guaranteed. Locally, project cost inflation has again reared its head and, as in 2008, companies are starting to question new projects. Perhaps most importantly, the industry has become a lightning rod for environmental concerns related to both climate change and water use. With any environmental issue, the easiest response is to eliminate the new and growing sources of damage, even though it’s seldom the optimal response. The oilsands industry needs to show it can exist under policies that meet national and international environmental goals— not that it should be exempt because the world needs oil. If it can’t demonstrate this, and soon, risks to the industry as a whole will keep rising.

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“[The Northern Gateway pipeline] represents an opportunity for Canada, and the clock is ticking.”

Photo: EnbridgE

Janet Holder

rossing the province of British Columbia has never looked so challenging as it does right now for Enbridge Inc., facing an uphill battle in its quest to secure approval for the Northern Gateway pipeline project. The $6.6-billion piece of energy infrastructure would run from Redwater, Alta., to Kitimat, B.C., opening up a tidewater export market for oilsands crude— now a trickle—into a gusher, vastly opening up opportunities for oilsands producers to sell crude on the Asian market.

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Executive vice-president, western access, Enbridge Inc.

Northern Gateway is seen as an opportunity for Canada to diversify and secure greater value for its oil, but the project is facing serious opposition from those who worry about pipeline and tanker safety, and the upstream impacts of the oilsands sector. In late 2011, B.C native Janet Holder set up shop along the pipeline route, assuming the role of Enbridge’s executive vicepresident, northern access. She’s now in charge of making sure the Northern Gateway project goes ahead.

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How does it feel to take charge of the Northern Gateway project as it moves into the important stage of public hearings? It feels very good indeed. I believe we have momentum in terms of increasing public support and support from aboriginal communities, as demonstrated by recent opinion polls and the fact that about half the aboriginal communities along the proposed Northern Gateway right-of-way have signed agreements to become equity partners. I took the opportunity to return to my home province of British Columbia to lead this project for Enbridge because I believe very strongly in the strategic benefits for Canada that would flow from increased market diversity and access to the growing economies of the Pacific Rim. There are challenges, to be sure, but I believe that the more people hear about the project over the coming months of public hearings, the more they will understand the enormous amount of work we have put into our application and our commitment to building and operating Northern Gateway safely. What is Enbridge doing to garner the support of local communities along the route of the project? Is this strategy changing? No, our strategy is not changing. We have been talking to residents of northern British Columbia and Alberta for almost a decade, and we have had a very extensive process of consultation with communities along the proposed right-of-way—and

that’s before the federal review of Northern Gateway. To date, we have been involved in close to 17,000 separate consultations with groups and individuals over a number of years. We have supported the creation of five regional community advisory boards that have been keenly involved in the consultation process. I do not believe there has ever been a public consultation process of this scope and intensity before about a pipeline proposal. What would you say to the concern that Northern Gateway could be the oilsands industry’s version of the Mackenzie Gas Project, which took decades to go through the regulatory process and remains uncertain? I would not want to compare Northern Gateway with any other project because in so many ways it is unique. We are committed to seeing this through the regulatory process and we support a rigorous, open review of our application—because we believe we have solid answers to the concerns that have been expressed. We have always believed that the more people know and understand about the engineering and environmental work that has gone into the planning of Northern Gateway, the more comfortable they will be with the project. Having said that, we do believe a timely review is necessary. Gateway represents an opportunity for Canada, and the clock is ticking.

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“Even without the tar sands, we’re overloading the atmosphere with carbon, so we surely can’t afford a vast new source. Just as Brazil needs to refrain from cutting down the rainforest for reasons of planetary protection, Canada needs to keep the tar sands in the ground.” Photo: bill MCkibbEn

Bill McKibben

u.S. environmental activist and author

ill McKibben is a well-known environmentalist and author in the United States, perhaps best known for his coordination of the “350” movement in October 2009. This action featured more than 5,000 protests in 181 countries meant to raise awareness about human-induced climate change. McKibben, who is a Schumann Distinguished Scholar at Middlebury College in Vermont and whose writing has been excerpted in Scientific American, focused in on the oilsands sector in 2011, becoming the lead environmentalist championing protest actions against the proposed Keystone XL pipeline expansion from Alberta to the U.S. Gulf Coast. Those protests almost certainly contributed to the fall 2011 decision by the State Department to deny approval of Keystone Xl, although welcoming a new, re-routed application.

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Canada and the united States have a long history and deeply entwined network of crude oil supply and demand. Why do you feel now is the time to break those bonds?

I think we need to reduce our imports because we need to use less fossil fuel in general. So far the planet has warmed one degree as a result of fossil fuel combustion, and the scientific consensus is that we’re looking at three to five degrees unless we stop burning fossil fuels very soon. Wherever we’re accessing coal, gas and oil, we need to start weaning ourselves.

“I’m not interested in inducing fear.”

Canada’s oilsands industry represents less than one-tenth of one per cent of global CO 2 emissions. Why focus your efforts on this industry rather than on the worst offenders?

The theme of your book Eaarth: Making a Life on a Tough New Planet is that human beings have irreversibly damaged the planet and it will soon be inhospitable, although we’ll continue to exist. How do you respond to the assertion that such an approach is based on spreading fear rather than moving towards solutions through constructive dialogue?

Because the tar sands are the second-largest pool of carbon on earth. So far, they haven’t been heavily developed. Only about three per cent of their oil has been tapped. But as the planet’s foremost climatologist, NASA scientist James Hansen, explained in the spring of 2011, if they are heavily exploited, it will be “game over for the climate.” We can end that game in other ways, too. Even without the tar sands, we’re overloading the atmosphere with carbon, so we surely can’t afford a vast new source. Just as Brazil needs to refrain from cutting down the rainforest for reasons of planetar y protection, Canada needs to keep the tar sands in the ground.

The book actually talks about the ways that we can keep the heating from getting worse than it already is—by getting off fossil fuel—and how to cope with the climate change we can no longer prevent—principally by emphasizing local economies with fewer too-big-to-fail sectors, be they banking, energy or agriculture. I’m not interested in inducing fear; my job as both a writer and as an activist is about spreading the information we now know about the planet. That’s why our big global campaign, 350.org, took its moniker from a wonky scientific data point: the amount of carbon (in parts per million) that scientists say is the most we can safely have in the atmosphere.

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“Less than 10 per cent [of new technologies] make it from idea to commercial use. Some would say one per cent go the whole distance through an evolution Photo: albErta innoVatES - EnErgy and EnVironMEnt SolutionS

that can take 25 years.”

Les Little

esearch and development is at the very heart of the heavy oil and oilsands industry—by their nature, bitumen resources are difficult to produce, process and add value to. Production companies have barely scratched the surface of what is potentially available with existing mining and in situ recovery technologies. Vast opportunities exist to improve current methods, but also to create new solutions for the next several generations of development. Alberta Innovates - Energy and Environment Solutions (AI-EES) is the provincial government’s lead agency in this area, and Les Little is at its helm.

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Executive director, energy technologies, Alberta Innovates – Energy and Environment Solutions

What are the main technology developments AI-EES is working on in support of the heavy oil and oilsands industry? The further out we’re targeting, the more substantial the improvement has to be over what we’re trying to replace. For in situ bitumen production, industry mostly takes care of improved efficiency on current processes, for example introducing solvents. We’re looking at the next generation, the removal of steam and the use of water altogether, which could mean using just heated solvents. Or using a different method of introducing energy into the reservoir, such as electrical-based radiation. You need the right frequency of electro-magnetic field to excite the molecules, the right specific technology and applications to make a process efficient and commercial, perhaps heat transfer or running an

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electrical current to transfer energy waves. The next generation could be using part of the resource in situ without adding anything from the surface. How often do these technologies move from lab testing to commercial use? Less than 10 per cent make it from idea to commercial use. Some would say one per cent go the whole distance through an evolution that can take 25 years. You have an idea and start down a path of investigation for your research. You have fundamental research and development in your investigation process to see if it’s physically possible, scientifically possible. But when you start with a good question, the answer is not linear and your discoveries may apply to other technology areas, or other developments can assist you in achieving commercialization somewhere else. There’s an S-curve of development, quick innovation followed by periods of stability that support a continual improvement process until a technology reaches its upper limit, after which a new paradigm of technology may surpass it. Your idea may become a stepping stone to development and be commercialized somewhere entirely different than you’d originally pictured. Similarly, you can reduce time to commercialization by adapting ideas from other fields. It’s hard to measure because you keep modifying and adapting your idea, but the earlier you start the earlier you can get there.

“We’re in it together. Some people forget that from time to time.”

There appears to be a growing movement towards collaboration in the oilsands sector. Is there potential for a greater role for AI-EES in this strategy? Collaboration is one of our strengths. As the technology arm of government, we have a different mandate than a lot of our partners, particularly industry. We’re focused on a strategic future. Since our inception as an organization, that’s been our mandate. We collaborate to develop the next wave of technology, to bring the strongest minds in different areas of expertise to bear on a problem. Without collaboration there’s less opportunity for adaptation or uptake by people who are going to commercialize a given project. The more collaboration, the better. It reduces the risk and spreads it among a group of stakeholders who, despite competitive aspects, share the same goal—to sustainably produce Alberta’s energy resources. We’re in it together. Some people forget that from time to time.

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“The nature of the risks here is different [compared to the military]. They’ve changed from human life to financial, environmental and social licence. That said, the challenges are similar in being complex and highly dynamic.”

Photo: JoEy Podlubny

Dana Woodworth

anaging the complexities of the oilsands industry and where it fits into the overall strategy of the Government of Alberta is a deeply involved and continually evolving exercise. Late last year, a new lead was appointed to the top job. Dana Woodworth, who served for nearly 30 years in the Canadian Armed Forces as a military engineering officer—including deployment as the commanding officer of the Kandahar Provincial Reconstruction Team in Afghanistan— is now applying his skills not to issues around human life, but instead around economics and the environment. But the risks are still complex and highly dynamic.

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Chief, oilsands strategy and operations, Alberta Energy

What does your role entail directing oilsands strategy and operations for the Alberta government? The oilsands are a massive resource of extreme significance to Alberta and arguably the major Canadian geopolitical issue at the moment. The oilsands support economic prosperity through royalty revenue, jobs, and numerous direct and indirect effects. They also raise an environmental question, arise in cross-border politics and diplomacy, and play a key role in Alberta and Canada’s future. The division I lead carries a number of responsibil ities. The operations branch deals with royalty and tenure on a day-to-day basis—collecting royalty revenues, administering

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land sales, monitoring royalty ring-fencing areas, providing assurance, and implementing royalty and tenure regulations. The business design and evaluations branch works on operational policies, including amendments to royalty and tenure regulations. Our value-added and strategic integration branch looks decades into the future to drive oilsands strategy by working within the department, across the provincial government and with significant stakeholders, including industry. This group also analyzes value-chain opportunities to maximize economic benefits from Alberta’s energy resources through such initiatives as incentivizing upgrading and petrochemical feedstock production. Finally, the external relations and advocacy branch serves the entire department of energy through trade policy, missions and advocacy. What are your current priority areas? My principal focus is to identify, understand and engage with those stakeholders who will drive the desired outcomes for Alberta’s provincial energy strategy. One specific item my team is working on is a fundamental review of the oilsands tenure system. This review will involve consultation with industry stakeholders and will tie back to a set of principles to guide our actions. The dynamic nature of government policies and industry progress producing the resource over time implies a need to willingly review and adjust our position.

On the more strategic side, I am working on developing a deeper understanding of the system in which the department of energy operates to help situate the oilsands strategy and operations division within an overall energy system. This will engender clarity of purpose within government and drive a strategy that is adaptable because it is linked to the broader picture. How do the skills you have developed through 30 years in leadership in various capacities compare with what’s needed in your new mandate? Over many years within the Canadian Army, I had the opportunity to lead in high-risk, complex environments that demanded intellectual agility and critical-thinking skills. The nature of the risks here is different. They’ve changed from human life to financial, environmental and social licence. That said, the challenges are similar in being complex and highly dynamic. As a proponent of applied-systems thinking, I believe in characterizing the system and understanding its key interactions and linkages. The beauty of applied-systems thinking for me is that it combines analysis, which increases knowledge, and synthesis, which builds understanding. My concept of leadership goes beyond providing clarity, resources and inspiration for those within the division to understanding and influencing the context—what is typically perceived as beyond one’s control.

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“During the next five years and thereafter, green, energysaving and environmentally friendly industries will be the key fields focused on by the government [of China] for development and to attract foreign investment. They will ultimately create a huge market and great investment opportunities.” Photo: JoEy Podlubny

Lei Jianzhong

Science and technology consul general, People’s Republic of China

n the last three years, Chinese energy companies have invested a massive $9 billion in Canada’s oilsands sector, primarily through minority stakes in operating or proposed projects. But that all changed in early 2012 when PetroChina Company Limited bought out the remaining share of partner Athabasca Oil Sands Corp.’s upcoming MacKay in situ project, marking the first time a Chinese firm will act as project operator. Clearly, the momentum behind these investments is far from slowing.

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p R O F I L E S

In the last few years, Chinese companies have significantly increased their position in the Canadian oilsands, primarily through minority ownership in projects or companies. Can we expect this trend to continue in the future? Chinese oil companies are new players compared to others in the global context. They are profit-oriented as well. They take any possible and available investment opportunities that could generate profits for their shareholders. A stable and fair environment is the most favourable market. Canada is one possible investment destination on the list of choices. The growing bilateral relationship between China and Canada also helps promote the increase of two-way trade and investment. Therefore, I would say there would be more investment from China coming into Canada. What are the key areas of focus or interest for Chinese companies investing in the oilsands sector? Currently their focus area is targeted at oil production—the upstream [component]—which they can handle better. Any areas of expansion in the future would depend on their business development situation and the investment climate in Canada. Canada’s oilsands sector is controversial in some countries. How is it viewed in China? There is no resistance in China to oilsands development, partly because China has only conventional sources of petroleum and the term is not well known. I understand the

controversy is generated because of the greenhouse gas [GHG] emissions from oilsands development. GHG emissions are of concern worldwide. The Chinese government has been working hard and has achieved great progress in reducing the country’s GHG emissions by developing green and renewable energy sources. During the next five years and thereafter, green, energysaving and environmentally friendly industries will be the key fields focused on by the government for development and to attract foreign investment. They will ultimately create a huge market and great investment opportunities. At the same time, all parties involved in oilsands production, such as the government, the industry, scientists, etc., should make as much effort as possible to reduce the environmental damage by oilsands development.

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New market access From feeding the beast to feeding the dragon

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Photo: Marathon oil CorPoration

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Why Canada’s oil can no longer rely on one market—the U.S. Midwest By ashok Dutta

statement often repeated in heavy oil and oilsands industry forums is that with Canada projected to reach crude oil production of nearly three million barrels per day by 2020, its output will be greater than some small and medium members of the Organization of the Petroleum Exporting Countries (OPEC). Yet, unlike the member states of the Vienna-based cartel that sells crude oil to buyers across a geographical spread, Canada relies on a single market—the United States—for nearly 90 per cent of its exports. Some see this scenario as a perfect recipe for disaster while others stress the inevitability and benefits of the existing arrangement, pointing out there is little that Ottawa can do quickly to change the energy partnership. After all, as the world’s single-largest energy consumer, the United States has been a hearty market for Alberta’s bitumen and synthetic crude oil and will continue to be so in the shortto medium-term. “In our long history, we have sold into a growth market [the United States], but now there is a growing threat of that market

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shrinking,” says Peter Tertzakian, chief energy economist and managing director of ARC Financial Corp. “With major global investments coming into the province, we are now at a size and significance of becoming a global player, and it is time we emerge as one.” In the world of commodities, history has proved that politics, product pricing, the gap between supply and demand, and economics have been key factors affecting major policy decisions. As vice-president of oilsands and markets at the Canadian Association of Petroleum Producers, Greg Stringham understands the nuances only too well. “Part of Canada’s wealth generation comes from exporting both oil and natural gas,” he says. “We have been doing so successfully to the U.S. However, there is also a need to develop new markets for us to move ahead. It is not only oilsands output that Alberta will be talking about, but we also see a major resurgence in the conventional and tight oil sectors.” Stringham continues, “Since 2006, oil companies from Europe and the U.S. have been investing in Alberta, and that is now being manifested in hopes of being pinned on oilsands as a major supplier of energy resources. From early 2009, huge investments have

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Photo: Marathon oil CorPoration

currently, canada’s major market for oilsands crude is the u.s. midcontinent, particularly the midwest, where facilities are being flooded with oilsands crude that needs new markets.

t he implicat ions of a “no” on Keyst one Xl Few will deny the potential and promise that Alberta holds as a global supplier of crude oil. But these hopes took a hit in November 2011, when the U.S. State Department denied approval of the proposed TransCanadabacked Keystone XL pipeline expansion planned to transport over 1.1 million barrels per day of Alberta crude from Hardisty, Alta., (near Edmonton) to refineries on the U.S. Gulf Coast. The company is, however, welcome to reapply with a modified plan. A prime reason for the denial was the threat of contaminating the Ogallala reservoir in the event of a pipeline leak. Spread over eight states, 27 per cent of irrigated land in the United States

overlies the Ogallala aquifer system, which yields about 30 per cent of the nation’s groundwater used for irrigation. Besides, it also provides drinking water to 82 per cent of the people who live within the aquifer boundary. The final curtain has not yet been drawn on the Keystone XL proposal, and TransCanada is still pursuing efforts to win approval by proposing a rerouting of the pipeline. However, attention in the meantime should be focused on the growing influence of the environmental lobby in the United States. Recently, B.C.–based blogger Vivian Krause—who has sifted through U.S. tax records—reported that American foundations have funnelled US$300 million into Canada’s environmental movement in the past decade. She said that a prime driver behind the stand being adopted by U.S.–based environmental groups that the Enbridge-backed Northern Gateway pipeline—designed to open an Asian market for Alberta’s crude oil, with a throughput of 525,000 barrels per day—is not in Canada’s national interest is to keep Alberta’s oil landlocked, to eventually ensure economic benefits for the United States.

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been made by Asian oil and gas companies, and it is imperative we look at China, Korea, Japan and India for exports.” Ralph Glass, director of energy valuations and operations with AJM Deloitte, also supports the opening up of a new market. “In the longer term, reaching out to a new market would mean more royalties for the province, and this could eventually translate into more jobs for rural Albertans,” he says.

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“Canada’s sole customer will be the U.S.,” Krause says. “No oil tanker traffic means that the U.S. gets a continued monopoly…all in the name of protecting the environment.” t he promise of higher prices A major benefit of exporting to an international market would be a higher price that Canadian oil producers could receive compared to what they are stuck with delivering only to the United States. A recent University of Calgary report, titled Catching the Brass Ring: Oil Market Diversification Potential for Canada, commented that success in finding a footing in a new market could result in “incredible” economic advantages. “The near-term benefits for increased access to the U.S. Gulf Coast after mid-continent bottlenecks are removed will be significant and represent [a difference of] nearly US$10 per barrel for Canadian producers,” the report said. “On the Pacific Coast, the world market is represented by growing capacity for heavy crude products in emerging Asian markets, including Japan, Korea and China, and existing heavy crude facilities in California and the U.S. west coast.” The researchers said that the true benefits will emerge from 2020 onwards, when the differential value range in California will be US$7.20 per barrel, escalating to US$8.77 per barrel a decade later. For Asia, the benefit range in the same period will grow from US$11.15 per barrel to US$13.60 per barrel. “Those higher prices for Canadian crude would translate into significant increases in profits, jobs and government revenues. With

w w w. H O C S .C a

better access and new pipeline capacity, producers will see more efficient flow to international markets, which can add up to $131 billion to Canada’s GDP [gross domestic product] between 2016 and 2030. This amounts to over $27 billion in federal, provincial and municipal tax receipts along with an estimated 649,000 person-years of employment.” The benefits of expanding markets are too lucrative to ignore and oilsands producers are not sparing any efforts to advance proposed projects. A case in point is the weight thrown behind the Northern Gateway pipeline by five international and Canadian producers—Total SA, Cenovus Energy Inc., Nexen Inc., Suncor Energy Inc. and MEG Energy Corp.—all of whom have signed up as potential shippers on the line. It also has backing of China-based Sinopec. The National Energy Board has started public hearings on the Northern Gateway project, with nearly 4,500 respondents filing certificates of objection and clarification requests. Realistically, it will be years before substantial volumes of Alberta extra-heavy oil is sold to Asian buyers, but in the meantime, the United States will continue to be a hefty customer. “We will certainly be selling to Asia, but demand from the U.S. will always be there,” says Stringham. “After all, of the total [U.S.] refining capacity of nine million barrels per day, five million is for heavy oil. With Mexican production in decline and Venezuela moving away from exporting to the U.S., there will still be a great prospect for Alberta crude.”

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p r o j e c t s

New market access: proposed project profiles

Keystone Xl owner: transcanada corporation

end/access point: Keystone XL would ultimately offer access to over 1.1 million barrels per day of Alberta extra-heavy crude to refineries on the U.S. Gulf Coast.

challenges: In January, the U.S. State Department issued its decision that the application to build Keystone XL was denied, although TransCanada is welcome to submit a new application with a revised route. A prime reason cited was worries about the pipeline’s potential environmental impact, especially in Nebraska. The disputed route runs through six states in the United States, and a major concern was the threat it posed to contaminating the Ogallala reservoir in the event of a pipeline leak. Also, opposition has been growing from several groups in the United States opposed to importing Alberta’s “dirty” oil. Pressure has mounted on the U.S. government from not only the

Edmonton

Hardisty Calgary Regina Winnipeg

Helena Bismarck Pierre

Chicago Lincoln

Steele City

Springﬁeld

Topeka

Oklahoma City

St. Louis

Patoka Wood River

Cushing

Keystone Pipeline Keystone Pipeline Expansion

Austin

Houston

Port Arthur

transcanada recently announced it will construct the pipeline segment from cushing to the u.s. Gulf coast as a stand-alone project.

environment lobby, but also locals along the pipeline route, film personalities and even Nobel laureates. status: TransCanada announced in February that it has sent a letter to the U.S. Department of State stating it will, in the near future, file a new presidential permit application for the Keystone XL Project from the U.S./Canada border in Montana to Steele City, Neb. The company said it will supplement that application with an alternative route in Nebraska as soon as that route is selected. Additionally, TransCanada now feels that what had been the Cushing–U.S. Gulf Coast portion of the project has its own independent value and will be constructed as a stand-alone project and not part of the presidential permit process. “The approximate cost is US$2.3 billion and, subject to regulatory approvals, we anticipate the Gulf Coast Project to be in service in mid- to late 2013,” TransCanada says.

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Benefits: The pipeline is of strategic importance to Canada and the United States for various reasons. From an energy security perspective, it would ensure uninterrupted supply of feedstock crude oil for its main refining in the Port Arthur area. From a geopolitical standpoint, with supplies from traditional sources—Mexico and Venezuela—declining, Canadian crude is the most viable option. The project would also result in a windfall of economic opportunities in the U.S., putting as many as 13,000 Americans to work, including pipefitters, welders, mechanics, electricians and heavy-equipment operators, in addition to 7,000 manufacturing jobs that would be created across the country. Local businesses along the pipeline route would also benefit from an estimated 118,000 spinoff jobs through increased business for local goods and service providers.

MaP: tranSCanaDa CorPoration

characteristics: Estimated to cost $7 billion, the Keystone Gulf Coast Expansion Project is a nearly 2,673-kilometre (1,661mile), 36-inch-diameter crude oil system that would begin at Hardisty, Alta., and extend southeast through Saskatchewan, Montana, South Dakota and Nebraska. It would incorporate a portion of the existing Keystone pipeline (Phase 2) through Nebraska and Kansas to serve markets at Cushing, Okla., before continuing through Oklahoma to a delivery point near existing terminals in Nederland, Texas, to serve the marketplace in Port Arthur, Texas. The original route through Nebraska is expected to change in TransCanada’s planned new application to the U.S. State Department to avoid the environmentally sensitive Sandhills after the project’s denial in late 2011.

p r o j e c t s

Northern gateway owner: enbridge inc.

characteristics: Estimated to cost $6.6 billion, the proposed Northern Gateway project is a dual pipeline system to run from Bruderheim, Alta., (near Edmonton) to Kitimat, B.C. One: a 1,177-kilometre, 36-inch-diameter pipeline with capacity of 525,000 barrels per day of Alberta heavy crude for export. Two: a 20-inch-diameter pipeline of similar length that would import 193,000 barrels per day of condensate to be used as diluent by oilsands producers.

Primarily due to a glut of heavy oil at Cushing, Okla., price differentials are currently against the favour of Canadian producers, further highlighting the need to find footing in a new market. In terms of economic benefits, Alberta and British Columbia would earn tax revenues of $114 million and $166 million respectively during the construction phase, and $462 million and $1.2 billion respectively when the pipeline is functional. About 62,700 person-years of construction employment would be created, while 1,150 long-term jobs would be created.

end/access point: Gateway would offer 525,000 barrels per day of Alberta diluted bitumen for export to markets in Asia through supertankers operating on the Pacific Ocean. At Kitimat, two export berths and 14 storage tanks would be built for crude oil and condensate. All vessels calling at the Kitimat terminal would be modern, double-hulled and vetted by independent, third-party agencies and also meet Canadian and international standards. It is estimated that 220 supertankers would use the terminal each year.

challenges: Gateway is facing both domestic and international opposition. On the Canadian front, many aboriginal groups along the route are standing staunchly against the project, citing environmental threats such as pipeline leaks and damage to marine life, as well as issues relating to land claims. The case is also being made internationally that Gateway would encourage expansions of oilsands production, and that development of the resource should be stopped, primarily because of its perceived relation to climate change.

Benefits: The pipeline is of strategic importance to oilsands producers in Alberta as well as the Canadian government, as it would open up the much-touted Asian market. Currently, over 90 per cent of Alberta’s bitumen production is exported to America. Asian market access has assumed even more significance since the U.S. government denied the initial application for the TransCanada-backed Keystone XL pipeline system that would transport over 1.1 million barrels per day of Alberta crude to refineries on the U.S. Gulf Coast.

status: Public hearings into the Gateway pipeline are being held through 2012 and early 2013 along the proposed route. More than 4,000 people have registered to voice their opinions through a 10-minute submission/presentation.

MaP: EnBriDGE

Fort St. John

New Aiyansh

BRITISH COLUMBIA Hazelton

Prince Rupert

KP 1172.19

Houston

KP 1100 61 60 59

56 55 54 53 52 51

KP 1000

KP 900

Burns Lake

Tumbler Ridge KP 600

Fort St. James

Terrace 63 62

ALBERTA

Chetwynd

Mackenzie Burns Lake

Masset

Dawson Creek

Hudson’s Hope

ALASKA

50 49

Fort St. James

47 46

45 44

KP 800

Vanderhoof

42 43

Bear Lake 41

38 39

Grande Prairie

KP 500 33 32

29 28

KP 700

Prince George

KP 400

21 20

19 18

KP 300

Fox Creek KP 15 200 13

Whitecourt

Grande Cache

Mayerthorpe

02 06 05 04 03 09 08 07

KP Morinville 100

KP 0 01 Bruderheim Fort Saskatchewan

Edmonton

Cottonwood Camrose

Northern Gateway Pipeline KP City Town Northern Gateway Pipeline Route

the National energy Board’s joint review panel into the proposed Northern Gateway pipeline began public hearings in early 2012, to be held through to early 2013 along the proposed route. 15 6

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50 Kilometres

100

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t rans mountain expansion owner: kinder morgan canada

characteristics: Estimated to cost $4 billion, the Trans Mountain Expansion (TMX) is an expansion of the only existing West Coast export pipeline for Alberta crude—a 300,000-barrel-per-day, 1,150-kilometre line that has diameters varying from 24 to 36 inches. Built in 1953, it runs from Edmonton to marketing terminals and refineries in the central B.C. region, the Greater Vancouver area and the Puget Sound area in Washington state, as well as to other markets such as California, the U.S. Gulf Coast and overseas through the Westridge marine terminal at Burnaby, B.C. TMX is a phased project aimed at increasing capacity by 400,000 barrels per day. The first stage would add 80,000 barrels per day of additional throughput, followed by two phases each of 160,000 barrels per day. The expansion plan is comprised of facilities that will complete the looping of the pipeline in Alberta and British Columbia, pumping stations, tanks in Edmonton and Burnaby, and expansion of the Westridge Marine Terminal. Kinder Morgan is looking to replace the existing pipeline with facilities of larger diameter in areas where bottlenecks currently occur. It also has an option to construct a second berth to expand capacity with increased docking capacity to accommodate one- million-barrel-capacity Suezmax tankers.

MaP: KinDEr MorGan CanaDa

end/access point: The expansion is proposed primarily to serve future export requirements for Alberta crude through

Canada’s west coast to either the U.S. west coast, Asia or both. Currently, 90 per cent of the crude moving through the Trans Mountain pipeline is exported through the Westridge dock to California, with remaining volumes going to the U.S. Gulf Coast and China. Benefits: In light of the recent U.S. State Department decision to reject the Keystone XL pipeline, TMX assumes even greater significance. From a commercial viewpoint, oilsands producers and the governments of both Canada and Alberta have expressed great support for increased Asia-Pacific exports of oilsands crude. challenges: Very little opposition currently exists to the TMX project. However, finding shippers will be a key issue. Kinder Morgan has said that the outcome of an open season will provide market indications and help the company determine precisely in how many phases the expansion will be implemented. status: An open season for binding 15- and 20-year agreements for all pipeline transportation services between Alberta and British Columbia started on Oct. 20, 2011, and was completed on Jan. 19, 2012. Kinder Morgan reports that it has sufficient shipper commitments established to make an investment decision, but none had been made as of press.

BRITISH COLUMBIA Edmonton

ALBERTA markets

Kamloops

Calgary

Vancouver Burnaby/Westridge Anacortes/Ferndale

Existing Pipe

WASHINGTON

MONTANA

Expansion Pipe

kinder morgan canada’s trans mountain pipeline is the only existing crude oil export system to the west coast.

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rail owner: canadian National railway (cN)/canadian Pacific railway (cP)

characteristics: Both of Canada’s main rail carriers offer a significant opportunity to oil producers—in the oilsands and in other regions— to expand market access without new pipelines, or until new pipeline infrastructure is built. CN and CP are both reporting that they have commenced shipping crude oil volumes on a regular basis. The concept, which hinges on flexibility, is reportedly not intended to replace pipeline transport, but to supplement it as an option where it makes sense. end/access point: CN operates approximately 20,000 routemiles of track in North America, serving ports on the Atlantic, Pacific and Gulf Coasts. The tracks move through eight Canadian provinces and 16 U.S. states. CP’s North American system exists on approximately 14,800 route-miles, moving through six provinces and 13 U.S. states. The rail line connects to eight ports including Montreal and Vancouver.

Photo: Cn/CP/Oilsands Review

Benefits: With uncertainty prevailing over the fate of new Canadian crude export pipelines—such as TransCanada Corporation’s Keystone XL system to the U.S. Gulf Coast and the proposed Enbridge Inc. Northern Gateway pipeline to Kitimat, B.C.—oilsands producers are looking at shipping crude by

Fairbanks Anchorage Whittier

pipeline as a viable incremental alternative. Rail systems can connect crude oil products with markets within Canada as well as to the U.S. Midwest, the U.S. Gulf Coast and other export opportunities, although this option is generally seen as more expensive than using pipelines. There is potential cost savings, however, in that shipping bitumen by rail would mean significantly reduced need for condensate addition to liquefy the crude to pipeline quality specifications, Alberta’s oilsands producers have relied almost entirely on pipelines to export diluted bitumen/ synthetic crude oil. There may also be a challenge in offloading capabilities not being readily available to transfer bitumen in rail cars to its final destination at refineries or export terminals. Additionally, according to Altex Energy Ltd. president and chief executive officer Glen Perry, the idea faces a logistical challenge in order to achieve the cost-saving benefits of removing diluent from the process. (Altex is working with CN in support of its “pipeline on rails” concept.) Perry has described the condensate issue as a “chicken and egg” problem: “Condensate is introduced early in the water-removal process and left in because that is the transport mechanism to reduce viscosity. Producers won’t stop using condensate diluent in the short term if no CP lines transport alternative exists.” CN lines Ports served by CN

Hay River

Fort Nelson Prince Rupert

Fort McMurray

Kitimat Prince George Kamloops Calgary

Edmonton Saskatoon

Vancouver

Winnipeg

Regina

Thunder Bay

Duluth

Rapid City

prince george

Hearst

Sault Montreal Ste. Marie Sudbury

Steven Point

Green Bay

Minneapolis/St. Paul Fond du Lac Sioux City Omaha Lincoln Topeka

East Peoria

Sept-Îles Baie Comeau Matane Moncton Quebec City

Detroit Chicago

Saint John

Toronto Sarnia Buffalo Albany Connaout Pittsburgh

Halifax

Auburn New London

New York

Philadelphia

St. Kansas City Louis Memphis

Mexicali

Alliance

El Paso

Topolobampa

Counce Birmingham

Shreveport

Jackson Mobile Baton Rouge Beaumont Pascagouia Houston New Gulfport Laredo Orleans Corpus Christi Matamoros Tampico

Guadalajara

Veracruz

Manzanilla Lázaro Cárdenas

Mexico City

Coatzacoalcos

Both cN and cP have announced regular shipments of crude oil from western canada along their tracks, sourced from the heavy oil and oilsands regions of alberta and saskatchewan as well as from the latter province’s Bakken play.

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status: CN reports it is already shipping bitumen and heavy crude oil from the oilsands in Alberta, as well as light Bakken crude from Saskatchewan to Calfornia and the U.S. Midwest. CP also says it is shipping crude oil from Canada to the United States via rail, particu larly Bakken volumes. The company has also secured a contract with Cenovus Energy Inc. to ship bitumen from the same Bakken facility in Saskatchewan, as well as a deal with NuStar Energy L.P. to build a new transload facility near Lloydminster, Sask., from which to ship undiluted heavy crude.

p r o j e c t s

seaway owners: enbridge inc., enterprise Products Partners l.P.

status: Enbridge has commenced purging the line to prepare for reversal and says it is on track for first operations on June 1. The company plans to have light service of 150,000 barrels per day in the second quarter of 2012, expanded to light service of 400,000 barrels per day in the fourth quarter of 2012, and 500,000-barrelper-day light service/400,000-barrel-per-day mixed service in the first quarter of 2013.

DECISIONS

MaP: EnBriDGE

characteristics: Operating since 1976, Seaway is an 800- k ilometre, 30-inch-diameter pipeline that runs from the U.S. Gulf Coast (in the Texas City area to the U.S. Midwest at Cushing, Okla.) Enbridge Inc. acquired 50 per cent interest in the system from ConocoPhillips Company in November 2011 for $1.15 billion. The plan is to reverse the pipeline so that it no longer ships crude from the Gulf Coast to the Midwest, instead reducing the existing bottleneck of overcapacity at Cushing by redirecting crude to the Texas City area. end/access point: The Seaway reversal is designed to help solve the problem of a glut of crude oil at Cushing, moving volumes instead to where surplus refining capacity exists (on the U.S. Gulf Coast). The pipeline will eventually have capacity to transport a mix of light and heavy-grade crudes.

TULSA

CUSHING Lincoln Pottawatomie

Seminole

OKLAHOMA

Pontotoc Johnston Bryan Grayson Collin Rockwall

DALLAS

Kaufman Henderson

Navarro

TEXAS

Freestone Leon Madison

prince george

Giles Waller

HOUSTON Fort Bend

LEGEND PHASE 1 | CUSHING TO ECHO TERMINAL PHASE 2 | ECHO TERMINAL TO PORT ARTHUR

Harris

PORT ARTHUR Chambers Jefferson

ECHO TERMINAL

enbridge expects to be in-service transporting 150,000 barrels per day of light crude from cushing to the u.s. Gulf coast in the second quarter of 2012.

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line 9 reversal owner: enbridge inc.

Benefits: The Enbridge application came as a response to a request from its customer, Imperial Oil Limited. Imperial says it requested a change in service to its Nanticoke Refinery near Port Dover, Ont. “Imperial presently utilizes offshore imported light crude oil for some of Nanticoke Refinery’s needs,” the company says. “Prompted by market conditions and available light crude oil supplies, Imperial’s objective is to replace these supplies, in kind, with light crude oil sourced from within Canada and the United States.”

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North Westover Station

Lake Huron N

prince george

Line 9 reversal phase1

Line 9

MaP: EnBriDGE

characteristics: Built in the 1970s, Enbridge Inc.’s 240,000-barrelper-day Line 9 pipeline runs between Montreal, Que., and Sarnia, Ont. Enbridge says it was originally constructed to secure the supply of oil in Quebec—which was then dependent on offshore crude—but in the late 1990s the flow was reversed to accommodate changing market conditions. In August 2011, Enbridge applied to the National Energy Board (NEB) to reverse a section of Line 9 from Sarnia to Westover, Ont., so it would transport crude from west to east rather than east to west (its original configuration). The Line 9 reversal was proposed in 2008 as part of a multicomponent project called Trailbreaker. Enbridge says that project was put on hold in 2009 due to lack of commercial support and is no longer being pursued.

Westover Terminal Hamilton

Sarnia London

Sarnia Terminal

Lake Erie Line 9 reversal phase 1

Line 9

Existing Enbridge Facility

City/Town

the reversal of line 9 is currently intended for light crude, but it would help alleviate bottlenecks for oilsands volumes.

status: The Line 9 reversal was expected to go through a fairly easy regulatory approval process, but concerns raised around whether the system was being reversed to supply eastern Canada with “dirty” oilsands crude helped to prompt an NEB public hearing process. Enbridge says that will delay the project “further into 2012” than anticipated.

p r o j e c t s

exports through alaska owner: G seven Generations ltd. (G7G)

Alyeska Pipeline (TAPS)

Fairbanks Delta Junction

Doyon

end/access point: A major aim of this project is to avoid highdensity tanker traffic along the coast of British Columbia, circumventing opposition from aboriginal groups and environmental lobbies. The existing Valdez terminal is facing declining supplies from Alaska’s North Slope, creating spare capacity that could be utilized by Alberta’s oilsands producers. challenges: The primary challenge facing the project is the need to ensure its commercial viability. Additionally, it is not the only railway option being proposed to transport Alberta crude to new markets. status: Over the coming months, G7G will be working to complete a feasibility study, business plan and First Nations consultations. The link has reportedly already been endorsed by First Nations in British Columbia, the Yukon and Alaska. Meetings are also taking place with government agencies in Canada and Alaska, and with national and international aboriginal organizations.

MaP: G7G

characteristics: Estimated to cost $12 billion, the proposed project is an over-2,000-kilometre railway link from Alberta to Alaska to export oilsands crude through the Valdez marine terminal to markets in Asia. The route would run northwest from Fort McMurray, Alta., to join Alberta to the Alyeska pipeline (part of the TransAlaska Pipeline System) at the Delta junction in Alaska.

Chugach

United Yukon FNs

Kaska

Valdez

Watson Lake Dene Tha’ Tahltan

Oilsands to MARKET

Asia

Europe

Fort Nelson

Gitanyow Gitxsan

The United States of America

Treaty 8

Fort McMurray

Kitwanga Gitwangak Edmonton

Kitimat 4

the seven Generations project would use both rail and pipeline infrastructure to connect oilsands crude with tidewater.

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The Port of Thunder Bay “Industry Leading Quality & Service Since 1987” Specialists in internal & external coating applications

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asia

a s i a

opportunities Where Canadian crude could fit into a growing, evolving, new refining market By ashok Dutta

consumption levels in Europe,” Jean-Jacques Mosconi, senior vice-president of strategic planning for French energy giant Total SA, said recently at an industry conference in Abu Dhabi, United Arab Emirates. “European refiners will also be suffering from Phase 3 of the C02-emission trading system, and by 2013 they could end up paying for an average 20 per cent of their total emissions.” ent er asia With demand for refined products growing significantly in Asia since 2002, there never was any doubt of a refining base mushrooming sooner than later. h E aV Y o i l & o i l S a n D S G U i D E B o o K V i i

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n the world of crude oil refining, until recently the United States and Europe held special status for three major reasons: highest consumption levels, strict adherence to refined product specifications and price sensitivity. But those positions seem to be changing rapidly in post-global economic meltdown times. With demand destruction prevalent in the United States and Europe, Asia—led by China and India—is now the emerging heavyweight. Commercial issues are also bringing about major changes in Europe’s downstream sector and, by default rather than design, shifting the centre of gravity towards Asia. Here lies a giant opportunity, and Canada’s oilsands producers are eager to meet the growing demand. “Stringent efficiency measures and the introduction of biofuels into the energy mix is putting pressure on

a s i a

— University of Calgary report, Catching the Brass Ring: Oil Market diversification Potential for Canada

a sinopec oil refining facility in china.

According to the U.S. Energy Information Administration, China may increase refining capacity by one-third to more than 12 million barrels per day by 2015 to feed economic growth. A recent University of Calgary report entitled Catching the Brass Ring: Oil Market Diversification Potential for Canada asserts that over the 10-year period (starting in 2000) China’s net growth in demand for crude oil was at 91 per cent—the highest globally—while the United States and Europe registered negative growth rates of three per cent and four per cent, respectively. For refined products, China’s maximum demand was for jet fuel, heating oil, diesel and kerosene at 39.5 per cent, followed by motor and aviation gasoline at 27 per cent. In Japan, motor gasoline was the most sought-after product at 39 per cent, followed by jet fuel at 31 per cent. “The Asian states were in a catch-22 situation, as they desperately wanted to reduce soaring import bills of refined products and also seek investments into their domestic refining sectors,” Mosconi says. As the world’s largest crude oil producer and with ambitions of building global refining capacity, Saudi Aramco was the first to seize this opportunity. In 2007, it put pen to paper with Sinopec Corp. and Exxon Mobil Corporation on a deal to triple the capacity of the Fujian refinery in southern China to 240,000 barrels per day, as well as integrate the facility with a petrochemical unit. Aramco has not looked back since, and last year signed an agreement with PetroChina to build a 200,000-barrel-per-day facility in Yunnan province. 16 4

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Aramco’s success was replicated by Kuwait Petroleum Corporation (KPC) in March 2011. The company set up a joint venture with Sinopec to build a 300,000-barrel-per-day refinery and petrochemical complex in southern China. Located on Donghai Island in the Guangdong province, the new refinery is expected to be operational in 2014-15, and will carry a price tag of US$9 billion. The refinery products will be marketed locally to meet the fast-growing demand in Guangdong province and across the rest of China. Last fall, Aramco and South Korea’s S-Oil Corporation jointly announced the completion of the Onsan refinery expansion project, while KPC is now aiming to award the engineering, procurement and construction contract for a 200,000-barrel-per-day refinery it plans to build in partnership with PetroVietnam in the northern province of Thanh Hoa, some 180 kilometres south of Hanoi. Recently, in an attempt to increase energy security as well as diversify supply, China signed a series of co operation agreements with Qatar Petroleum (QP) that will see the establishment of a 400,000-barrel-per-day refinery in eastern Zheijang province. All the planned refinery ventures in China have a common element: feedstock crude will be supplied under long-term deals by Aramco, KPC and QP. “Gulf producers are looking closely at demand dynamics and participating in refinery projects in Asia to improve access to markets there amid the region’s increasing consumption of fuel and crude,” John Sfakianakis, chief economist at Banque

Photo: SinoPEC

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Saudi Fransi in Riyadh, said in a research note. “Asia, including China, is a very strategic and important demand driver. Aramco is aware that China and Asia are the markets that drive demand given the macro fundamentals.” fit t ing in alBert a crude Canadian crude has yet to find a footing in Asia because Alberta, the heart of oil production, is landlocked, and nearly 90 per cent of the province’s diluted bitumen and synthetic crude oil is currently exported to the United States. Approximately 10,000 barrels per day of Alberta crude finds its way to refineries in Asia through Kinder Morgan Canada’s Trans Mountain pipeline, but the province has a Herculean task ahead to increase that flow, even as oilsands production is projected to ramp up to three million barrels per day by 2020. “It is not automatic that we will be able to export to Asia,” says Gordon Houlden, director of the China Institute at the University of Alberta. “If Alberta wants to become a credible primary oil supplier to China, provincial and federal governments need to act now and form a long-term, targeted strategy. The most critical issue will be building a pipeline to the west coast.” But it is not all gloom and doom for Canada, if some recent domestic changes in Asia are an indication. Oil production global ly is getting heavier, and that means refineries are retooling to process lower-quality crude that resembles oilsands bitumen.

“There has been considerable interest and investment in expanding heavy crude processing capacity outside the U.S., primarily in China, including coking, fluid catalytic cracking and hydrocracking capability,” wrote the University of Calgary researchers, adding that “In Asia, generally, heavy crude processing capacity is expected to increase, although the time periods are uncertain. As these upgrading and new refinery projects are completed, crude slates worldwide are expected to shift dramatically toward heavy sour crude.” Demand is also rising in India, making the Asian state look at new options for securing crude oil. “Iran, Saudi Arabia and Kuwait supply over 70 per cent of our demand, but we are looking elsewhere too,” says Dependra Pathak, exploration director at New Delhi’s Ministry of Petroleum and Natural Gas. “A deal has been signed with Brunei, but with a plan in place to upgrade our facilities by installing cokers and initiating a secondary refining process. Taking crude from Canada is a target area for us. We will be working on this over the coming few years.” The verdict will be much awaited in Alberta. In the meantime, under its coastal refinery development program, Sinopec plans to build two facilities of total capacity of 600,000 barrels per day in the eastern provinces of Hefei and Guangxi that could potentially utilize oilsands crude as feedstock.

Oil Sands

& Heavy Oil

markets

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spill stresses With new pipeline projects under scrutiny, industry goes on the offensive over safety By ashok Dutta

anada’s multi-billion dollar crude oil pipeline industry is set for a roller-coaster ride in 2012—and probably further beyond—with an undertone of uncertainty. Resistance to new export pipeline projects is not just about perceived problems with the upstream oper ations in the oilsands industry that provide their feedstock, but also about concerns over pipeline safety. Arguably, the most significant reason why opposition to the Keystone XL pipeline expansion to the U.S. Gulf Coast has so far been successful was the effectiveness of raising these concerns. “There are unique challenges and risks associated with transporting diluted bitumen compared to conventional oil,” reads a recent report from the Natural Resources Defense Council, Pembina Institute and Living Oceans. “Diluted bitumen may weaken pipelines at a faster rate than conventional oil due to its acidic, sulphuric, abrasive and viscous nature. When tar sands pipelines spill, the spills are especially hazardous due to the explosive properties of diluted bitumen and the concentration of toxins found in bitumen, like benzene and polycyclic aromatic hydrocarbons.” The Canadian Energy Pipeline Association (CEPA) categorically disagrees with this and other reports making the same point. In November 2011, CEPA pointed to an Alberta Innovates study stating that “the characteristics of [diluted bitumen] are not unique and are comparable to conventional crude oils 16 6

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during pipeline flow. Analysis of historic data shows that the internal corrosion related pipeline failure rate of dilbit is statistically comparable to the conventional oil in the U.S.” CEPA also pointed to an assertion from the Alberta Energy Resources Conservation Board that “there is no indication that the types of pipelines transporting blended crude bitumen, crude oil or synthetic crude oil have an increased risk of internal corrosion issues.” Canada’s commissioner for the environment and sustainable development, Scott Vaughan, added to the debate in December 2011. In a report to Parliament, Commissioner Vaughan said failure of the National Energy Board (NEB) and Transport Canada to identify and fix problems associated with the transport of dangerous goods is increasingly putting the public safety of Canadians at risk. “There are some pretty big gaps and some serious problems that require action to protect Canadians from exposure to hazardous materials,” he said, adding there is an average of two incidents involving the transport of dangerous products and one pipeline incident every week (ranging from a minor leak to a major break or an explosion). Vaughan continued that the NEB is “overstretched” with 65 employees responsible for a pipeline network covering some 72,000 kilometres, with about one-third of the pipelines built 30–50 years ago. CEPA was quick to respond.

p i p e l i n e

s a f e t y

Photo: EnBriDGE inC.

a 2010 leak from an enbridge pipeline in michigan’s kalamazoo river contributed to heightened concerns about crude oil pipeline safety. Here, workers use booms and such equipment to clean oil from the river.

“there is no indication that the types of pipelines transporting blended crude bitumen, crude oil or synthetic crude oil have an increased risk of internal corrosion issues.” — alberta Energy resources Conservation Board

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“We are very concerned when reports fail to provide context to their stories and create unnecessary public fears when the facts clearly show that the opposite is true. Commitment to safety is our industry’s number one priority. It is in our best interest and that of the public to operate a safe and reliable system. As a result of that commitment, we transport oil and gas products 365 days a year with a reliability factor of 99.98 per cent. We assess and adopt new technologies, and share best practices continuously.” CEPA president and chief executive officer Brenda Kenny says that stringent reporting has resulted in even a “little smudge of oil on a valve” getting detailed. “Few spills of eight cubic metres, the benchmark for a ser ious one, actually occur in a year,” she says. “Pipeline

companies know they need to comply with regulations because they simply cannot afford to be lax about them.” Adhering to regulations does not lie on the NEB’s shoulders alone. The Canadian Environmental Assessment Agency (CEAA) is also part of the equation. Nathan Lemphers, a policy analyst with the Pembina Institute, says the CEA A lacks a sufficient number of inspectors to oversee pipeline inspections. This is a concern for existing pipelines, as well as the new ones that will eventually have to be checked once they are built, commissioned and operating. “Canadians should expect better from their government,” he says. “It is a clear case of wanting the moon, but resourcing them much lower than that. You have more pipelines [and an] increasing age of pipelines, so there are going to be more problems, yet you have fewer inspectors looking at those pipelines and budget cuts on top of all this.” CEPA disagrees with the assertion that aging pipelines are more dangerous than new ones. “Similar to a home, a 50-yearold home can be as safe and liveable as a five-year-old home if you adopt proper maintenance procedures. As an industry that has built a vast network of energy highways for the past 60 years that has allowed Canadians to enjoy affordable, reliable and safe use of energy, we are proud of our record and responsibilities to the public we serve.”

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f o r t

m c m u r r ay

collective of

newcomers

Photo: JoEY PoDlUBnY

Fort McMurray leaders work to build a community amid the challenges of rapid oilsands development and a skyrocketing population By Jim Bentein

the highly multicultural nature of the fort mcmurray community was clear on canada Day in 2011.

including New Orleans, Toronto, Hamilton and Calgary. He and his wife were immediately impressed by how easy it is to sample all of what Fort McMurray has to offer with just a short drive. “We moved here one year ago from Calgary,” he says. “I have this thing I tell people about, what I call a natural domain. When you live in Calgary, a city of over one million people, you actually only live in one part of the city [because of difficulties travelling from one part to another]. I find that I can do 85 per cent to 90 per cent of what I did there in Fort McMurray. “We’ve found the transition to be very easy.” However, despite all of the progress that has been made in building a more livable community, Little still gets asked by friends and others how he ended up in Fort McMurray—with the implication being that it was not by choice. It was, and he says the negative image many have of the oilsands city “is very dated.” But Suncor has to contend with that outdated image as it recruits new workers to its operations in the area. For that reason, the company launched its Go Ahead campaign, which augments job fairs, networking and employee referrals with an online network for potential candidates. The site

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s the collection of communities at the heart of the oilsands, the Regional Municipality of Wood Buffalo has seen unprecedented growth and change in recent times—and as the industry ramps up for a new boom, the challenges of the past are building once again. According to the Statistics Canada, Fort McMurray, Alta., the region’s major residential centre, saw a 29 per cent spike in population between 2006 and 2011, from 47,705 to 61,374. Municipal figures for the whole region put the total population at nearly 105,000. This makes Fort McMurray largely a city of newcomers, flooded with a mixture of temporary workers and permanent residents, new families looking to make a home and new employees looking to make a buck. For the city’s political, industrial and cultural leaders—many of who are new to the area themselves—the challenge is to foster a sense of community between all these disparate groups while fighting the old stereotypes of the frontier boom town. Those preconceptions usually fall apart when confronted by the reality of the city, as Mark Little discovered. Like many who have moved to the community, the executive vice-president of oilsands at Suncor Energy Inc. has lived in many other cities,

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(goaheadfortmac.ca) explores the lifestyle and amenities of the area, including its multicultural population and nearby natural attractions (like lakes and cross-country ski trails). “Expect great,” potential recruits are told, with the site including profiles of Suncor employees who tell their personal stories. Beyond the company’s multi-hundred-million dollar annual payroll in the community and local spending on goods and ma- ter ials, the Suncor Energy Foundation has contributed $34 million to community facilities and activities since 2000, says Little. As someone who travelled widely in previous jobs (he was responsible for Suncor’s North Sea and East Coast Canada operations, and has worked in Latin America, North Africa and the Near East), Little says he has found the multicultural, sophisticated nature of the community to be one of its most compelling characteristics. It’s a trait he believes should assist with the recruitment of workers from throughout the world. “I think it’s the most multicultural city we’ve ever lived in,” he says. “You have very rich experiences here.” coping wit h growt h In just 20 years, Fort McMurray has transformed from an isolated frontier outpost to a modern city, filled with recreational, social and other amenities. Much of the credit for coping with that rapid growth is due to younger community leaders like Mayor Melissa Blake, 41, who has spent 13 years on the municipality’s council and has been mayor since 2004. “I can’t imagine a better place to raise a family,” says Blake, who has two children, ages two and eight, and a husband who is the director of process engineering at the nearby Suncor Energy oilsands mining operation. “The average family income is $177,000 a year. Our real estate is very expensive [single-family homes average $730,000 and multi-family dwellings average $441,000], but we have excellent child care and outstanding recreation.” But growth poses numerous challenges for the municipality, which is expected to see its population at least double in the next 20 years. Not only is it an economic dynamo, but it has also become a crucible for planning exercises aimed at taking the rough edges off Canada’s most-watched boom town, and a target for environmentalists who claim the nearby oilsands plants make Alberta a symbol of oil development gone amok. Blake, who moved to Fort McMurray in her teens, is unabashed in her enthusiasm for her adopted home. She seems more a career booster for the region than someone who has spent much of her adult life in politics. “I didn’t plan for a life of politics,” she says, adding she has no plans to move to provincial or federal politics. “For me, there’s nothing that has been more meaningful than serving my community.” There continue to be challenges. There is not enough moderately priced housing nor is there enough commercial and industrial land. There aren’t enough doctors, nurses, teachers and other professionals. And although amalgamation between Fort McMurray and the surrounding districts and hamlets 16 years ago brought hundreds of millions in industrial tax revenues into the municipal coffers, those revenues remain lopsided, with 90 per cent coming from industrial taxes and 10 per cent from residential taxpayers. (A healthy balance is considered to be roughly half and half.)

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“But there’s a time lapse,” Blake says, commenting on newer oilsands-related growth. “The people come before the companies start to contribute to our tax base. At this point, I have confidence we can keep up.” Coping with rapid growth is one thing, but coping with the negative image of the community she loves is another. “I have concerns about views people outside the area have about the ‘tar sands,’” she says. “The reality is the experience of living here is very difficult than what is portrayed. You see people here being tarnished, but these are people who have the same values as other Canadians.” Blake, who has a master’s degree in administration from the area’s Keyano College, says more Canadians should realize the “tremendous impact” oilsands development is having on Canada’s economy, playing a large role in helping it skirt the worst of the 2008 recession, for instance. no place for t heory Kevin Nagel certainly knows about that contribution, which is why he decided to become a large part of it last April, when he became president and chief executive officer of Keyano. “This will probably be one of the most important places in North America over the next decade,” says Nagel, who is in his 50s. While the chance to be a part of the area’s dynamic economy was an attraction, Nagel sees Keyano as a living, breathing part of the area. “The community is part of the college and the college is part of the community,” he says. He was also attracted to the institution because of its pragmatic role in the community, where it is the antithesis of the “hallowed halls of ivy” like universities of old. “This is definitely not the place for theory to live,” he says, after noting that area oilsands operators and other businesses can never find enough employees. “This is where you want to create appliedtype programs, where businesses need more than heavy-haul truck drivers [even though they also need plenty of them]. “This is an incredibly fulfilling job,” he says. “People are always attracted to being needed, and this college is needed, since this is one of the fastest-growing areas in North America. We’re talking about development on the same scale as is occurring in China.” Nagel plans to remain in the area for many years. “The community has been good to me, and we’re going to have to make sure we do the right things for it.” leisure t ime But all study and work and no play makes for a dull life—and Tim Reid is committed to making the leisure hours of area residents as fulfilling as the hours they spend churning out bitumen or studying fluid mechanics at Keyano. Reid is chief operating officer of MacDonald Island Park, the hub of recreational activity in the area, which includes the Suncor Community Leisure Centre (at 440,000 square feet it’s the largest recreation centre in Canada), the 18-hole Miskanaw Golf Course, four baseball diamonds and two soccer pitches. Opened in 2009, the $181-million facility also includes a 100,000-square-foot aquatic centre (also the largest in the country), an NHL-sized hockey rink, a second rink and a children’s

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Photo: JoEY PoDlUBnY

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“the reality is Fort McMurray, for the last 10 or 15 years, has been constantly running to get to the starting line. it has been playing catch-up because every population projection has been exceeded.” — Ken Chapman, executive director, oil Sands Developers Group

Photo: JoEY PoDlUBnY

left: fort mcmurray traffic is well known for its near-constant congestion, but infrastructure projects are underway to ease the strain.

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above: People come from all over the world to fort mcmurray to capitalize on the opportunities the oilsands industry presents, but the rapid growth in population continues to cause lapses in development of local infrastructure.

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arena, an indoor track, a curling rink (soon to open), an 8,000-square-foot field house, a child-care centre and indoor playground, banquet and meeting rooms, and other amenities. “When I moved to Fort McMurray [in 2009, along with his wife, who is a teacher], MacDonald Island Park had 26 employees and now it has 327,” he says. “This was a fabulous opportunity.” At first, his wife was adamant about not wanting to move to Fort McMurray, which he attributes to the “negative image” of the boom town. However, that perception changed after he and his wife took a trip to the area to participate in a fundraising event. They were both so impressed with the look of the city and with the people they met there that he took the job offer. It probably helped that the chance to manage Canada’s largest indoor recreational facility, especially at his age (Reid is 33), was too good to pass up. It has truly become a commun ity hub, he says. “Last year, 1.8 million people went through its doors,” he says. He and his wife had their first child last fall and they both look forward to raising him in the area. “Growing up in a military home, I found there are good people everywhere, but this is a great place to raise a family,” he says.

“nobody is really from here so this isn’t home, which is why we all need each other.”

Photo: JoEY PoDlUBnY

— tim reid, chief operating officer, MacDonald island Park

construction is currently underway on a new, multi-apron terminal at the fort mcmurray regional airport.

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“Nobody is really from here so this isn’t home, which is why we all need each other.” He still gets offers to manage recreational facilities in larger cities in Canada, but Reid isn’t budging. “I do more in a month than I would do in a year in most of those facilities,” he says, adding that with revenue of $55 million a year being generated by the recreation complex, it qualifies as a major economic player in the community. And, like many community leaders in the area, he says he can’t stand on past laurels, especially in an area where the population will more than double in the next 20 years or so. While acknowledging that Fort McMurray still has a negative image, he believes interaction with others from across Alberta and Canada through sporting and cultural events offers one of the best ways to change perceptions of the municipality. For instance, the area will host the Western Canada Summer Games in 2015, which will give many outsiders a chance to see it for the first time. “The best way to change our image and challenge our stereotype is to give visitors an outstanding experience,” he says. “more t han a company t own” Ken Chapman struggles against the negative stereotype every day as executive director of the Oil Sands Developers Group (OSDG), which represents 30 of the major oilsands operators. He says what most outsiders miss seeing is that Fort McMurray “is becoming much more than just a company town.” Chapman, who practised law in Edmonton for 35 years before becoming involved as a consultant in public policy, is an unabashed defender of oilsands development. “I’m a big fan of the oilsands,” he says. “We have amazing potential, but we have to do it right.” While he continues to maintain a home in Edmonton, Chapman spends much of his time living in an apartment in the oilsands city. After six months in Fort McMurray—he moved into his position at OSDG this past June—he has been intrigued by what he has observed. “Wood Buffalo is a fascinating place, in terms of its social and cultural diversity,” he says. “At one of the elementary schools there are 69 different languages spoken.” He is optimistic that the region’s social, environmental and other problems are being dealt with. “The reality is Fort McMurray, for the last 10 or 15 years, has been constantly running to get to the starting line,” he says. “It has been playing catch-up because every population projection has been exceeded.” While the community leaders in the past have mostly come from an oilsands industry background, Chapman says he’s finding many now come from other backgrounds, which he attributes to the maturity of the area. At 65 years of age, he says the new position “is the best gig I’ve ever had,” despite the long hours of work and heavy responsibilities of the job, since the OSDG, with an annual budget of $1.5 million, is the face of the oilsands industry. It’s a face that is not always clearly seen by many observers. “The whole world is watching, but they’re all using different lenses,” he says. “Depending on what lens they use, they don’t get the full picture of what’s going on.”

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tecHNoloGy ProGressioN The oil that technology made

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miNiNG r&D Tidier tailings and waterless extraction

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iN situ r&D Advancing the frontier

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t echnological challenges have always shaped the recovery of bitumen resources By Graham Chandler

illUStration: JErEMY SEEMan

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t e c h n o l o g y

high-quality bitumen reservoirs Imperial secured in that area. It hasn’t really found much application in large projects beyond the [Imperial Oil] Cold Lake project, which was developed in the early 1980s.” It was another technological breakthrough from this period that proved to be most significant, says McKenzie-Brown. “The big kahuna in oilsands technologies was the development of steam assisted gravity drainage [SAGD] in the 1980s and 1990s. It was certainly the most important development since Karl Clark’s work on hot-water separation.” Roger Butler, a petroleum engineer who immigrated to Canada from England in the 1950s, developed SAGD. He believed the injection of pressurized warm vapours into an oilsand deposit would create a “steam chamber,” allowing gravity to draw the oil to the chamber’s base. Butler discovered that within vertical wells, the chambers are full of sand, thereby preventing gravity from moving the oil to the bottom. His answer came with the newly perfected horizontal well technique. He would use horizontal well pairs—steam injected above and oil collected below. The invention revolutionized the industry, paving the way for the scores of in situ projects currently working that now account for nearly half of all oilsands production. “SAGD was first employed on a pilot basis only about 14 years ago. We are now approaching the million-barrel-per-day mark of SAGD production. And that’s in just a decade and a half,” says Mark Bilozir, team leader, technology development, at Cenovus Energy Inc. “That means we’ve still got lots of things to learn. There is so much resource out there to go after, so much opportunity. “With continuous improvement and changes, it will be exciting times.” Future changes will include ongoing improvements to SAGD, better environmental practices and revolutionary new oilsands extraction techniques that will allow new bitumen areas like carbonates to be opened for exploitation. “The next frontier will be the development of bitumen from carbonate reservoirs,” says Bruce Roberts, chief reservoir engineer at Athabasca Oil Sands Corp. “The target is huge—it is estimated there are 450 billion barrels of bitumen contained in carbonate reservoirs. The production from carbonates containing light oil, for example from the highly prolific Leduc reefs, kick-started the industry in the 1940s. Given the application of new technology, production of bitumen from carbonate reservoirs may have a similar impact on the [oilsands] industry.”

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n 1788, when Sir Alexander Mackenzie wrote in his diary about the discovery of bitumen in the Athabasca region, he noted, “The bitumen is in a fluid state, and when mixed with gum or the resinous substance collected from the spruce fir, serves to gum the canoes.” It was the first recorded use of bitumen in North America. But it wouldn’t be until 1913 that efforts were made to develop bitumen and heavy oil commercially when Sidney Ells, a young engineer working for the federal department of mines, began experimenting with hot-water flotation. Ells continued his experiments until 1945, but it took another scientist at the Alberta Research Council, Karl Clark, to refine Ells’s methods by mixing sands with hot water and aerating the resultant slurry. This separated into a floating froth of bitumen and a clean layer of sand, which settled to the bottom. “Clark was the single-most influential person in early oilsands development,” says Peter McKenzieBrown, a writer and an active researcher into oilsands history. “In the 1920s, Karl Clark developed the hot-water separation process, which made future oilsands companies possible.” Others also explored economic recovery. In the 1920s, entrepreneur R.C. Fitzsimmons set up a plant 80 kilometres from Fort McMurray, Alta., to use the hot-water flotation process to produce bitumen for roofing and road surfacing. His efforts were economically unsuccessful. However, in 1948, the Alberta government acquired his plant to research extraction methods using large equipment. The following year, over 450 tonnes of oilsand per day were processed, after which the government, uninterested in getting into commercial production, closed the operation. The oilsands could be profitable, though, the government reckoned in a report published in the 1950s. The first major company to begin developing an oilsands project was Great Canadian Oil Sands (now known as Suncor Energy Inc.). Suncor’s project came on stream in 1967, making it the world’s first oilsands operation. The Syncrude Canada Ltd. plant followed it in 1978. Both used the water flotation process developed by Ells, Fitzsimmons and Clark to process raw material gathered through surface mining. As the largest percentage of oilsand lies too deep for mining, other technologies were being developed for in situ mining. “In the ’60s and ’70s, Imperial Oil developed cyclic steam stimulation in three experimental projects at Cold Lake,” says McKenzie-Brown. “This approach is particularly well-suited to the vast,

p r o g r e s s i o n

m i n i n g

r + d

illUStration: JErEMY SEEMan

ho would have thought there was a relationship between dental plaque and making tailings pond water clean enough to return to the environment? Both involve natural bacteria communities called biofilms, which are the focus of a study by Canadian university scientists actively experimenting to solve some of the environmental impacts of oilsands mining, and to make extraction more efficient. Properly controlled, biofilms can be used to completely detoxify tailings water. Susanne Golby, a University of Calgary master’s graduate, got interested in the concept just after she completed her undergraduate degree. “I started working with Golder Associates doing bio logical treatment studies for contaminated soils,” she says. For her graduate thesis she obtained samples of tailings sludge, which contains natural biofilms, and placed them into a bioreactor. “By altering the growth conditions, and exposing the biofilms to different stressors, we could select for or against certain species,

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and we began to learn how we could manipulate the biofilms to get the metabolic activities and characteristics we were looking for,” she said in a news release. Currently, no detoxification is done. But, “if they can decontaminate before they put them into the pond, they won’t need the pond,” Golby says. “Ideally, that would be an objective. It’s the same as waste-water treatment—our waste is treated and dumped back into the river. We’d like to eventually meet Environment Canada discharge regulations.” The biofilms are all natural, says Howard Ceri, chairman of the Biofilm Research Group and professor of biological sciences at the University of Calgary, as well as Golby’s former graduate supervisor. “Basically, the concept was to take an already existing biological process—they’ve been degrading bitumen and breaking it down for millions of years—and using lots of food and oxygen to allow them to grow very quickly,” he explains. Using the Calgary biofilm device, the researchers create large numbers of mini-bioreactors to try

m i n i n g

r + d

“in my opinion, [in the future] the industry will be using smaller, perhaps modular, processes that can process more solids with less water and/or solvent, with almost complete recycle of water and solvent. these modular extraction plants will be placed closer to the mining site to minimize transport of solids, water and solvent.” — Edgar acosta, associate professor, department of chemical engineering and applied chemistry, University of toronto

various combinations of conditions, “and then select those biofilms that can enhance the breakdown of the products that we want.” Ceri is careful to note this is not genetic manipulation. “We’re not making a superbug—we are just taking the bugs that are there and picking the ones who work best together,” he says. The biofilms don’t actually ”eat” the toxins, but rather provide a process whereby the toxins precipitate from the tailings water. The next phase is to take these isolated bacterial populations and upscale the bioreactors so that they become equivalent to what’s done with city waste water. “We can pass [the sludge] through at a very high speed and, in the end, release the water into the waterway,” he says. Ceri reckons the process shouldn’t be overly costly. “I don’t see this as being a huge capital investment,” he says, while also suggesting the industry will be motivated by the bad press that has surrounded tailings ponds. “They certainly stand out as the lightning rod, and if we can get this working to the scale needed, I don’t imagine the cost will be an issue.” The final process may have another bonus: selling the extracted metals. Ceri envisions “a self-paying process where we can extract silver, and all the other metals that have value, out of these crystals and perhaps pay for the cost of the remediation.” Concentrations aren’t yet known, “but we know that we can precipitate the metals.”

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dry cleaning t he oilsands While decontamination remains important, waterless, or nonaqueous, bitumen extraction has become an equally significant prize for oilsands researchers. Tony Yeung, professor in the University of Alberta’s chemical engineering department and also a Centre for Oil Sands Innovation (COSI) researcher, is studying just that. He offers a novel illustration of current inefficiencies. “Think of the sand grains as dirty dishes: you wash them off with a lot of water and get the oil out, then you throw away the plates,” he says. The flip side is more like dry cleaning, explains Yeung, who holds a National Sciences and Engineering Research Council Industrial Research Chair in non-aqueous bitumen extraction. “Instead of using water you use an organic solvent to wash

the sand,” he says, noting that experiments involve different mixtures of aromatic and other solvents. “By mixing different amounts, you can have a whole range of aromatic content.” There are still big challenges ahead, like dealing with massive amounts of sand containing solvent traces (each barrel of oil produces about a cubic metre of sand). And the solvent, more pricey than bitumen or water, would have to be recovered. “Nor do you want all that solvent exposed to the atmosphere,” he says. One option currently being tested is vaporization, but another alternative is to replace solvents with surfactants, which would use minimal amounts of water. “Think of [surfactants] as cleaning your dishes again,” Yeung explains. “If you just wash them under tap water, it’s not doing a very good job, but if you add a detergent, it works.” A researcher looking at how to separate bitumen from even smaller particles—tailings clays—is Edgar Acosta, associate professor in the department of chemical engineering and applied chemistry at the University of Toronto. He’s studying how a process might include removal of residual solvents in these nano-particles after bitumen extraction. The researcher explains that the work on nano-particles tries to take advantage of the best features of solvent-based extraction, such as rapid and efficient oil recovery, and aqueous- based extraction, like minimizing the residual solvent left on particles. “We have had success with this combined technology with sand particles, and work is underway with oilcontaining clays,” he says. Acosta, who also works with COSI, says collection of nanoparticles into bigger particles that can be safely disposed of in aqueous extraction is a major challenge. Others include minimization of the volume of solvent and/or water required in the process, and optimizing the condition for maximum reuse of water, solvents and any other additives. He envisions the ideal future for oilsands mining: “In my opinion, the industry will be using smaller, perhaps modular, processes that can process more solids with less water and/or solvent, with almost complete recycle of water and solvent. These modular extraction plants will be placed closer to the mining site to minimize transport of solids, water and solvent.”

i n

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Production well

Injection well

The heat from the steam reduces the viscosity of the heavy crude oil or bitumen, which allows it to flow down into the lower wellbore.

Gravity allows for crude oil or bitumen and water to collect around the lower wellbore, which allows it to be pumped out to be refined.

steam assisted gravity drainage has made it possible to produce billions of barrels of resource that would have been impossible without the technology. Now r&D focuses on improving the technique and solving the challenges of the future.

Barely 10 years have passed since the first commercial SAGD programs and producers are steadily pushing ahead with new in situ extraction technologies By Graham Chandler

tandard in situ bitumen production is energy- and water-intensive. But what if energy consumption could be reduced, and water needs virtually eliminated? and what if bitumen could be produced from the potentially vastly prolific, currently untapped carbonate formations too? a number of producers are working on solutions to these challenges, including athabasca oil Sands Corp., in its vast holdings at Dover West and the leduc carbonates. “although a steam-based process would work very well in these, we thought that it also provided an opportunity to look at electrical heating,” says Bruce roberts, athabasca’s chief reservoir engineer. What he’s talking about is taGD—thermal assisted gravity drainage. “the idea is that steam may preferentially flow to some of the fractures

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and some of the more vuggy areas, and so bypass some of the bitumen,” he explains. “With taGD, the heating will be much more uniform and predictable.” taGD well pairs are similar to steam assisted gravity drainage (SaGD) arrangements. But instead of steam, taGD uses an array of electrical elements to heat the bitumen. “the heater cables are like your kitchen stove coil,” roberts says. While typical SaGD temperatures can exceed 200 degrees Celsius, taGD runs 120–160 degrees. “and by using conductive heating we’re able to better control the temperature; we can place heaters just where we need heat. in a steam base, you’re relying on the steam to flow and spread out.” Moreover, taGD virtually eliminates water need and extends further than SaGD. Commercial

taGD wells, says roberts, would be around 1,200 metres—twice as long as SaGD applications. Part of the taGD advantage is that reservoir pressures are maintained naturally from the gas coming out of the oil and vaporization of some of the natural reservoir water. roberts says that means “taGD would work better [than SaGD] in oilsands where pressures are low in shallow deposits, for example—too deep to mine, but too shallow for SaGD.” athabasca’s current two-well taGD trial started up in april 2011 and the company has been testing “to establish how much heat we can [safely] inject,” roberts says. “We already found we could inject more than we planned—the reservoir is taking the heat well.” he calls the project a success, with bitumen produced last october. the next step planned

illUStration: JErEMY SEEMan

STEAM ASSISTED GRAVITY DRAINAGE

i n

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Photo: lariCina EnErGY

is a new pilot to start in 2014-15, followed by commercial production in 2015-16. that would open up the field. “the leduc contains about 19 billion barrels of bitumen,” roberts says. “and we also have a large holding in the Grosmont we haven’t looked at for taGD yet.”

list en t o your reservoir

at saleski, laricina energy is testing the application of saGD to a new and potentially vastly prolific reservoir in the bitumen carbonates. Photo: CEnoVUS EnErGY

cenovus energy inc. has successfully deployed a new saGD-improving technology called wedge wells at its christina lake and foster creek projects. single wells are drilled between existing well pairs to capture stranded oil.

upside-down pyramid next to upside-down pyramid, and eventually they will grow into each other. that means that in-between those pairs you’ve got this wedge of oil kind of in the no-man’s land. We put a horizontal well at the bottom of the bank between those two wells.” and the beauty of that is there’s no additional steam needed to produce that oil. “So you end up recovering more of it—the wedge wells increase our recovery by about 10 per cent.” Bilozir reckons the wells can reduce costs by $10–$15 per barrel, while also cutting emissions, because steam to oil ratios drop by at least five per cent. that doesn’t mean wedge wells don’t have their challenges. “the hardest steps are convincing yourself that you need another well,” says Bilozir. “these wells aren’t cheap—they cost a million plus.”

Drilling can also be tricky because it involves hot oil and is next to active SaGD patterns. “it took us a few years to understand the riskreward,” he says. But so far it seems to be paying off for the company. according to Bilozir, Cenovus had about 60 wedge wells drilled at its Foster Creek operations and four at Christina lake by the end of 2011, all producing. Sometimes innovations can be victims of their own success. “now these wedge wells are producing so much oil that maybe our spacing can be changed such that we would no longer need wedge wells,” Bilozir says. “Maybe if we started to make the pairs closer together we wouldn’t need the wedge well.” as always with innovations, that’s a whole other round of modelling, he says.

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another company barrelling ahead with carbonate technology testing is laricina Energy ltd., which is calling its pilot project Saleski. laricina is looking at combining SaGD with solvent injection. Pilot recovery programs had been employed in decades past for oilsands carbonates (none used SaGD), and those studies were laricina’s starting point, to first define the reservoir characteristics. “We went back to the geology and the seismic, we went back to the pilots, [and] we studied what we could,” says president and chief executive officer Glen Schmidt. that was followed up with more seismic, drilling and lab simulations to characterize this high-permeability rock and how it might perform using solvent-steam injection. “We injected propane and Co2 one winter and propane and nitrogen another winter, and ‘listened’ to the reservoir,” he says. the addition of solvent to steam increases recovery, explains Schmidt. “it increases the oil rate per well and decreases the steam-oil ratio.” What’s critical is the timing and character of the solvent used because each reservoir is unique and behaves differently as steam is applied. Shared research data comes from the SharP (solvent heat assisted recovery processes) research consortium at the University of Calgary, which has 16 corporate members. the Saleski pilot has been successful, with oil produced and sold. “We are now measuring the subtleties of how the wells perform, and testing them so we get the maximum amount of information for a commercial project,” Schmidt says. “We filed for the expansion in December 2010.” Even standard SaGD recoveries can be improved without electrical heating or the addition of solvents. recent years have seen Cenovus Energy inc. perfect its patented wedge wells— a solution for recovering bitumen stranded between SaGD well pairs. Mark Bilozir, Cenovus technology development team leader, explains: “When you’re injecting the steam, it mobilizes the oil preferentially at the top, so a chamber looks like an upside-down pyramid. When you have five or seven well pairs drilled to one pad, you’ll have

s o lv e n t s

Butane is a light hydrocarbon that is being tested as an in situ oilsands solvent.

fine-tuning sagd operators adding hydrocarbon solvents to boost productivity and lower costs By Godfrey Budd

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pilot tested solvent injection are widely viewed as almost certain to do so within the next few years. “the lab work and the pilots have prompted industry to take an interest in advancing towards commercialization,” says haibo huang, a principal researcher with the heavy oil and oilsands business unit with alberta innovates technology Futures. “there are opportunities for SaGD if the reservoir is not deep and steam injection pressure has to be low.” in addition to potential SaGD benefits where the pay zone is relatively close to the surface and the caprock might not be able to handle higher pressures, solvent co-injection can improve

steam to oil ratios (Sor), cutting natural gas requirements and Co2 emissions. “the mixing of oil and solvent in the reservoir is a key to the process of using less steam,” says huang. lab results—and most pilot tests done in the last 10 years—also suggest that steam-solvent technology can boost productivity. huang notes, “the lab parametric experiments and study of [solvent co-injection] demonstrated that the addition of solvent to steam accelerated oil depletion compared to steam only.” Expanding solvent (ES) SaGD is one coinjection method being tested. huang says

illUStration: JErEMY SEEMan

bout a decade’s worth of lab research and a sprinkling of pilot projects to investigate the potential benefits of adding hydrocarbon solvent injection to steam assisted gravity drainage (SaGD) operations appears to be paying off. Multiple in situ oilsands operators have announced plans to pilot test solvent coinjection, while others have requested the option to use solvent injection on commercial projects in their regulatory filings with the alberta Energy resources Conservation Board (ErCB). Most of the companies that have not yet

s o lv e n t s

For this type of scheme, we feel over 80 per cent is success. We got [solvent recovery] in the 85–90 per cent range.” another benefit of solvent-steam can be a slightly lighter oil. “When you inject a light hydrocarbon, some of the asphaltenes separate out,” says Subodh Gupta, chief of technology development at Cenovus. the company has been testing its proprietary solvent-aided process for a number of years. Gupta says that a pilot in 2004-05 showed a production increase of about 30 per cent and lowered Sor by about 25 per cent. it also produced oil that was lighter by about one degree aPi. Since 2009, the company has been doing further solvent testing on another pair of wells at Christina lake to investigate wider spacing, which, if successful, would result in fewer pairs, reducing both costs and footprint. “We are seeing encouraging results, slowly decreasing Sor and increasing production.” Field testing for the company’s steamsolvent narrows lake commercial project is continuing. an application has been filed for Phase 1, which has a projected production start in 2016 and 40,000-barrel-per-day capacity. the company hopes to receive a permit this year. tests have shown promise. “So far, field testing results have been very much congruent with lab testing and simulations, not exactly matching, but sufficiently close to give us confidence to move further,” says Gupta. laricina Energy ltd. is developing two solvent-steam projects at Saleski and Germain. Germain is under construction, while Saleski has been operating since 2010. the process laricina is developing is called solvent-cyclic SaGD, which involves alternating injection cycles of steam and hydrocarbons. “the purpose of the pilot is to optimize design for commercial recovery, so solvent is to be injected at the suitable point,” says Glen Schmidt, laricina’s president and chief executive officer. although some petroleum engineers say further research on reservoir impact and phase behaviour of some of the light hydrocarbons applicable to solvent-steam SaGD could be useful, industry is showing considerable faith in the technology’s overall potential. But, as noted in one operator’s announcements, these projects require timely availability of solvent in sufficient quantities to justify the increased capital cost required for solvent injection—around 10–15 per cent, on average.

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that it is important that the injected steam and hydrocarbon are in the same phase in order to ensure an even sweep of the reservoir and optimize solvent recovery. Pressure is another critical factor, and is affected by the depth of the target formation. Pressure, in turn, affects the behaviour of water/steam and hydrocarbon solvents/ gases, and the point at which they move from one phase to another—for example, from water to steam or vice versa. the variability of formation depth, pressure and other factors of in situ production that affect phase behaviour means that one type of

solvent may work better in a particular formation than another. “ES-SaGD uses a range of solvents so that a range of different types of reservoir can be candidates for this implement,” says huang. Unfortunately, because the research on solvent SaGD at alberta innovates is being paid for by a consortium of oil companies, huang can’t divulge lab results or quantify how they might translate to field operations. the available information, however, indicates that results from pilot solvent-steam programs have been promising. Claes Palmgren, vicepresident of engineering at alberta oilsands inc. (aoS), points to numbers he gleaned from ErCB data and technical papers on the subject, offering that a Cenovus Energy inc. pilot at the Senlac SaGD installation in Saskatchewan saw a production-rate improvement of over 50 per cent with a solvent recovery of over 70 per cent. an early Cenovus pilot in 2001 at Christina lake saw a productivity spike of 60 per cent. imperial oil limited ran a solvent injection pilot at its cyclic steam stimulation facility at Cold lake and production almost doubled, with over 80 per cent solvent recovery. aoS has filed for regulatory approval on a pilot using solvent in a process called SlP-SaGD at its Clearwater asset. (SlP stands for supported liquid phase.) “Why SlP? to maintain caprock integrity, as the pay zone is about 60 metres from the surface,” says Palmgren. Clearwater is quite shallow compared to other SaGD operations, many of which are at depths of 300–600 metres below ground. “We hope to demonstrate we can safely operate a shallow SaGD project,” says Palmgren. “the economics are partly determined by solvent recovery ratios.” Connacher oil and Gas limited is operating a solvent-steam pilot at algar, which, at 500 metres down, is much deeper. the company began solvent injection in summer 2011. the main drivers for using solvent on this SaGD project are production increase and capital cost. “on capital cost, we have an advantage in that in that we are using a solvent that could be sold as part of our dilbit stream,” says Merle Johnson, Connacher’s vice-president of engineering. Johnson says the field data has shown good matches with lab results and computer-based simulations. “We’re very pleased. We’re confident of a production increase. the big issue was recovery of solvent. it beat expectations.

s tat i s t i c s

production of Bitumen 7 in alberta, 2010 (103 m3/day)

canadian oilsands and conventional oil production outlook

7 Wood Buffalo National Park

136.2

Athabasca

59.1

6.4

In Situ

6.4

54.6

Grande Prairie

Mined

5,000

54.6

Edmonton

Calgary

4 3

1 2

102

u Sa

ab Ar

n Ve

Ira

n Ca

Ira

Other (44%)

92 60

Canada’s Oilsands (56%)

Open to private sector

137 115

t ai a w Dh Ku u Ab

ya Lib

ria

a at

te ni

es at St

Venezuela

Mexico

0 2005

2006

2007

2008

2009

2010

alberta mined Bitumen production and synthetic crude oil production and price, 1968-2010

2021

2023

2025

Iran Canada 2010 Mexico UAE Kuwait Million barrels per day

3,776

500

3,146

400

2,517

300

1,888

200

1,259

100

629

2000

616

120

528

100

440

352

264

176

88 0

1968 1971 1974 1977 1980 1983 1986 1989 1992 1995 1998 2001 2004 2007 2010

2004

2006

2008

2010

2012

2014

In Situ Production

Production (103 m3/day)

140

2002

2016

2018

2020

Bitumen Price

140

594

120

509

100

424

340

255

170

1968 1971 1974 1977 1980 1983 1986 1989 1992 1995 1998 2001 2004 2007 2010

SoUrCE: ErCB

704

In Situ

600

SCO Price

Price (Cdn$/m3)

SCO Production

160

h E aV Y o i l & o i l S a n D S G U i D E B o o K V i i

2025

Nigeria

alberta in situ Bitumen production and price, 1968-2010

SoUrCE: ErCB

Production (103 m3/day)

Mined Bitumen

18 4

2019

China

Production (103 m3/day)

Per cent

2017

SoUrCE: ErCB

SoUrCE: U.S. Eia 2011

2004

2015

Surface Mining

2003

2013

Saudi Arabia

16%

2002

2011

USA

2001

2009

Saudi Arabia

21%

2000

2007

alberta crude Bitumen production

15%

1,000

canada’s share of u.s. imports Canada

1,500

U.S. DEPt. oF Eia, anD CaPP

Billion barrels

Restricted (79%)

175

100

2,000

500

SoUrCE: oil anD GaS JoUrnal/CaPP

211

150

2,500

Russia

250 200

3,000

World Oil Reserves

Includes 170 billion barrels of oilsands reserves

260

3,500

global crude oil production 2010

1 2 global crude oil reserves by country 300

Forecast

4,000

SoUrCE: Eia

SoUrCE: ErCB

Actual

4,500

Cold Lake

Conventional Heavy Conventional Light Pentanes/Condensate

Production (103 bbl/d)

In Situ

Atlantic Canada In Situ Mining

Fort McMurray

Peace River

59.1

Price (Cdn$/m3)

Mined

Thousand barrels per day

i n d u s t r y

e n v i r o n m e n t

SoUrCE: U.S. DEPt. oF EnErGY/Eia, EnVironMEnt CanaDa

land use and reclamation

north american ghg emissions–2009

for coal-fired and Power oilsands 100 megatonnes 50 megatonnes

Canada’s boreal forest (3,200,000 km2)

Canadian oilsands Canadian coal-fired power generating plants

Land that could be impacted by mining (4,802 km2) Land mined over the last 40 years (602 km2) 11% of land mined has been reclaimed

U.S. coal-fired power generating plants

How big is 602 km2? Greater Metropolitan

684

9,418

toronto, Ontario

630

7,125

Chicago, illinois

606

28,164

Oslo, Norway

454

8,900

Area (km2)

SoUrCE: CaPP

City proper

edmonton, Alberta

Global Emissions

Canada’s 2%

Non-OECD Europe & Eurasia 9%

Industrial Processes & Waste 9.9% Agriculture & Forestry 8.4%

Transport 27.5%

Japan 4% China 24%

fish populations: human health risk from mercury in fish t issue (athabasca region)

India 5% Residential 5.9% Australia/New Zealand 2% Other 19%

Manufacturing, Commercial & Construction 11.5%

Other Fossil Fuel 16.1%

Brutus Lake

Keith Lake

Net Lake

Electricity & Heat Generation 14.2%

GHG emissions • Just over 1/1000th of global GHG emissions from oilsands: • 6.5% of Canada’s GHG emissions

Subsistence fishers

General consumers

Lake Whitefish

Walleye

Northern Pike

Lake Whitefish

Northern Pike

Lake Whitefish

Walleye

Northern Pike

1 negligible-low change

LEgEND:

• 29% reduction in intensity from 1990

Difference from baseline 2010

Species

Oilsands 6.5%

Canada

United States 18%

Region

2 moderate change

3 high change

local air Quality t rends in the regional municipality of wood Buffalo

2010 summary of regional acquatics monitoring program results

average annual ambient air concentrations (2010)

Differences between tests and baseline conditions

Sulphur Nitrogen Ozone dioxide dioxide (ppb) (ppb) (ppb)

Particulate Total reduced Total hydrocarbon matter sulphur and (ppb) hydrogen sulphide (ppb)

Watershed/Region

SoUrCE: rEGional aqUatiCS MonitorinG ProGraM

OECD Europe 17%

SoUrCE: JaCoBS ConSUltanCY

15 megatonnes

Land covering the oilsands (142,200 km2)

global energy related emissions

Hydrology

Water quality

Benthic invertebrate communities

Sediment quality

2009

2010

2009

2010

2009

2010

2009

INDUSTRY STATIONS

Athabasca Delta

1/3

Mannix

2.33

1.24

2.12

Muskeg River

1/2

Mildred Lake

1.85

1.31

2.33

Steepbank River

Tar River

MacKay River

1/2

Albian Muskeg River

1.69

30-40

12.91

n/q

9.20

2.26

Lower camp

1.51

1.09

2.23

Calumet River

Syncrude UE1

1.20

6.16

18.66

4.76

0.19

2.35

Firebag River

Buffalo viewpoint

1.03

0.35

2.16

Ells River

Canadian Natural Horizon

0.98

5.46

7.47

0.47

2.12

Christina River

Millennium mine

0.97

16.67

9.83

1.26

2.55

Clearwater River

Beaver River

McLean Creek

Mills Creek

Poplar Creek

Fort Creek COMMUNITY STATIONS Fort McKay

1.34

7.01

20.31

4.69

0.74

2.11

Patricia McInnes

0.98

5.93

22.95

4.17

0.26

2.08

Athabasca Valley

0.71

10.96

17.84

4.69

0.52

2.17

Anzac

0.53

2.73

25.85

3.85

0.35

2.08

Fort Chipewyan

0.37

1.10

27.39

3.72

leGeND:

1 negligible-low change

nc not completed

2 moderate change

nm not monitored

3 high change

na no baseline

h E aV Y o i l & o i l S a n D S G U i D E B o o K V i i

SoUrCE: rEGional aqUatiCS MonitorinG ProGraM

2010 Athabasca River

Objective

SoUrCE: WooD BUFFalo EnVironMEntal aSSoCiation

s tat i s t i c s

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Glossary api an american Petroleum institute measure of liquid gravity. Water is 10 degrees aPi, and a typical light crude is from 35 to 40. Bitumen is 7.5–8.5 aPi. Barrel the traditional measurement for crude oil volumes. one barrel equals 42 U.S. gallons (159 litres). there are 6.29 barrels in one cubic metre of oil. Bitumen naturally occurring, viscous mixture of hydrocarbons that contains high levels of sulphur and nitrogen compounds. in its natural state, it is not recoverable at a commercial rate through a well because it is too thick to flow. Bitumen typically makes up about 10 per cent by weight of oilsand, but saturation varies. condensate Mixture of extremely light hydrocarbons recoverable from gas reservoirs. Condensate is also referred to as a natural gas liquid, and is used as a diluent to reduce bitumen viscosity for pipeline transportation. cyclic steam stimulation (css) For several weeks, high-pressure steam is injected into the formation to soften the oilsand before being pumped to the surface for separation. the pressure created in the underground environment causes formation cracks that help move the bitumen to producing wells. after a portion of the reservoir has been saturated, the steam is turned off and the reservoir is allowed to soak for several weeks. then the production phase brings the bitumen to the surface. density the heaviness of crude oil, indicating the proportion of large, carbon-rich molecules, generally measured in kilograms per cubic

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metre (kg/m3) or degrees on the american Petroleum institute (aPi) gravity scale. in western Canada, oil up to 900 kg/m3 is considered light to medium crude—oil above this density is deemed as heavy oil or bitumen. diluent See Condensate. established recoverable reserves reserves recoverable under current technology and present and anticipated economic conditions, plus that portion of recoverable reserves that is interpreted to exist, based on geological, geophysical or similar information, with reasonable certainty. established reserves reserves recoverable with current technology and present and anticipated economic conditions specifically proved by drilling, testing or production, plus the portion of contiguous recoverable reserves that are interpreted to exist from geological, geophysical or similar information with reasonable certainty. extraction a process, unique to the oilsands industry, which separates the bitumen from the oilsand using hot water, steam and caustic soda. froth treatment the means to recover bitumen from the mixture of water, bitumen and solids “froth” produced in hot-water extraction (in miningbased recovery). gasification a process to partially oxidize any hydrocarbon, typically heavy residues, to a mixture of hydrogen and carbon monoxide. Can be used to produce hydrogen and various energy by-products.

Photo: JoEY PoDlUBnY

g l o s s a r y

tailings treatment cells at the athabasca oil sands Project.

greenhouse gases Gases commonly believed to be connected to climate change and global warming. Co2 is the most common, but greenhouse gases also include other light hydrocarbons (such as methane) and nitrous oxide. in situ latin for “in place.” in situ recovery refers to various methods used to recover deeply buried bitumen deposits. in situ combustion a displacement enhanced oil recovery method. it works by generating combustion gases (primarily Co and Co2) downhole, which then “pushes” the oil towards the recovery well. initial established reserves Established reserves prior to the deduction of any production. initial volume in place the volume calculated or interpreted to exist in a reservoir before any volume has been produced. lease a legal document from the Province of alberta giving an operator the right to extract bitumen from the oilsand existing within the specified lease area. the land must be reclaimed and returned to the Crown at the end of operations. muskeg a water-soaked layer of decaying plant material, one to three metres thick, found on top of the overburden. oilsands Bitumen-soaked sand, located in four geographic regions of alberta: athabasca, Wabasca, Cold lake and Peace river. the athabasca

deposit is the largest, encompassing more than 42,340 square kilometres. total deposits of bitumen in alberta are estimated at 1.7 trillion to 2.5 trillion barrels. overburden a layer of sand, gravel and shale between the surface and the underlying oilsand. Must be removed before oilsands can be mined. overburden underlies muskeg in many places. pilot plant Small model plant for testing processes under actual production conditions. proven recoverable reserves reserves that have been proven through production or testing to be recoverable with existing technology and under present economic conditions. reclamation returning disturbed land to a stable, biologically productive state. reclaimed property is returned to the Province of alberta at the end of operations. remaining established reserves initial reserves less cumulative production. royalty the Crown’s share of production or revenue. about three-quarters of Canadian crude oil is produced from lands, including the oilsands, on which the Crown holds mineral rights. the lease or permit between the developer and the Crown sets out the arrangements for sharing the risks and rewards.

h E aV Y o i l & o i l S a n D S G U i D E B o o K V i i

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steam assisted gravity drainage (sagd) an in situ production process using two closely spaced horizontal wells: one for steam injection and the other for production of the bitumen/water emulsion. synthetic crude oil a manufactured crude oil comprised of naphtha, distillate and gas oil-boiling range material. Can range from high-quality, light sweet bottomless crude to heavy, sour blends. t ailings a combination of water, sand, silt and fine clay particles that is a by-product of removing the bitumen from the oilsand. t ailings settling basin the primary purpose of the tailings settling basin is to serve as a process vessel allowing time for tailings water to clarify and silt and clay particles to settle, so that the water can be reused in extraction. the settling basin also acts as a thickener, preparing mature fine tailings for final reclamation.

t ruck-and-shovel mining large electric or hydraulic shovels are used to remove the oilsand and load very large trucks. the trucks haul the oilsand to dump pockets where it is conveyed or pipelined to the extraction plant. trucks and shovels are more economic to operate than the bucketwheel reclaimers and draglines they have replaced at oilsands mines. upgrading the process of converting heavy oil or bitumen into synthetic crude, either through the removal of carbon (coking) or the addition of hydrogen (hydroconversion). viscosity the ability of a liquid to flow. the lower the viscosity, the more easily the liquid will flow.

Location 56.999592, -111.612972 Photo: Fort McMurray Tourism

t hermal recovery any process by which heat energy is used to reduce the viscosity of bitumen in situ to facilitate recovery.

t oe to heel air injection (t hai) an in situ combustion method for producing heavy oil and oilsand. in this technique, combustion starts from a vertical well, while the oil is produced from a horizontal well having its toe in close proximity to the vertical air-injection well. this production method is a modification of conventional fire flooding techniques in which the flame front from a vertical well pushes the oil to be produced from another vertical well.

CLEAN

IS ESSENTIAL.

Innovation makes a measurable difference. New equipment we have been installing at our Mildred Lake facility will help reduce total emissions of sulphur compounds by over 50%. And we’re always looking for new ways to improve air quality.

Diane Phillips, Syncrude Canada Ltd.

oilsandstoday.ca A message from Canada’s Oil Sands Producers. The Canadian Association of Petroleum Producers (CAPP) represents member companies that produce over 90 per cent of Canada’s natural gas and crude oil, including Canada’s Oil Sands Producers.

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a d v e r t i s e r s ’

i n d e x

ADVERTISERS’ INDEX

Photo: JoEY PoDlUBnY

acklands-Grainger inc ...................................................................................................................... 81 advantage Products inc .................................................................................................................. 59 aker Solutions ........................................................................................................................................ 94 aluma Systems Canada inc ......................................................................................................... 114 aMEC americas limited ................................................................................................................ 119 applied rigaku technologies, inc ........................................................................................... 143 atCo Group ........................................................................................................................................... 131 Baker hughes Canada Company ............................................................................................... 19 Bantrel Co ................................................................................................................................................ 135 Brother’s Specialized Coating Systems ltd ....................................................................... 162 Canadian association of Petroleum Producers (CaPP)................................................188 Canadian heavy oil association ................................................................................................ 22 Canwell Enviro-industries ltd ................................................................................................... 149 CCS Corporation ........................................................................................................................ 14 & 15 CEDa international .............................................................................................................................. 36 CiDra oilsands ltd ........................................................................................................................... 139 Clean harbors ......................................................................................................................................... 62 ClearStream Energy Services ........................................................................................................ 28 Connacher oil & Gas ltd ................................................................................................................ 133 DeGolyer and Macnaughton Canada limited ............................................................... 126 Deran oilfield Services ltd .............................................................................................................143 Devon Canada Corporation ........................................................................................................ 113 dmg events .............................................................................................................................................. 27 Edmonton Destination hotels – South Side .................................................................... 159 Edmonton Exchanger & Manufacturing ltd ...................................................................... 23 Enform ..................................................................................................................................................... 149 EntrEC transportation Services ltd ....................................................................................... 45 EPCor alberta ........................................................................................................................................ 74 Express integrated technologies Canada ............................................................................ 13 Flint Energy Services ltd ................................................................................................................. 11 Focus Corporation ........................................................................................................................... 104 Fourquest Energy inc ....................................................................................................................... 86 Fugro Canada ....................................................................................................................................... 145 G.l.M. industries lP ................................................................................................................................ 8 G & l Slotco oil Field Services ...................................................................................................... 33 halliburton .................................................................................................................................................. 4 hoCS Projects ..................................................................................................................................... 154

hunting Energy Services (Canada) ltd ............................................. outside back cover imperial oil ............................................................................................................ inside front cover iMV Projects inc ..................................................................................................................................... 65 industrial training Consultants, inc ....................................................................................... 162 iracore international ......................................................................................................................... 137 Kenwood Electronics Canada inc ........................................................................................... 125 Keyano College ..................................................................................................................................... 70 Kudu industries inc ............................................................................................................................. 58 MaXfield inc ............................................................................................................................................. 90 Mine Safety appliances Company .......................................................................................... 141 Ministry Energy and resources ................................................................................................... 66 nexen inc ................................................................................................................................................. 173 nGC Product Solutions ....................................................................................................................... 7 norseman Structures ........................................................................................................................ 63 northgate industries ltd .............................................................................................................. 168 norwest Corporation ..................................................................................................................... 165 Phoenix Fence inc ............................................................................................................................... 18 ProJEX ...................................................................................................................................................... 126 raE Engineering & inspection ltd ............................................................................................ 67 regent Energy Group ....................................................................................................................... 53 rockwell Servicing ............................................................................................................................ 161 Schlumberger Canada limited ..................................................................................... 2, 3 & 97 SitE Energy Services ltd .................................................................................................................. 49 SnC-lavalin inc .................................................................................................... inside back cover Statoil Canada ltd ................................................................................................................................ 41 Strad Energy Services ...................................................................................................................... 127 Sulzer Management ltd ................................................................................................................ 127 Suncor Energy inc ................................................................................................................................ 98 tenaris ........................................................................................................................................... gatefold thermal Energy Services inc ......................................................................................................... 64 thunder Bay Port authority ....................................................................................................... 162 Veolia Water Solutions & technologies ............................................................................... 147 Volant Products inc ............................................................................................................................ 173 West-Can Seal Coating inc .......................................................................................................... 168 Workers’ Compensation Board – alberta .......................................................................... 160 WorleyParsons Canada ..................................................................................................................... 37 ZCl Composites inc ................................................................................................................. 60 & 61

flying into the oilsands: landing at one of a number of private airstrips around fort mcmurray.

h E aV Y o i l & o i l S a n D S G U i D E B o o K V i i

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