Canada's Oil Sands
Third Edition
Oil SandS: QUESTiOnS + anSWERS Third Edition Writer: Robert D. Bott Editor: David M. Carson First Edition Copyright © April 2000, Petroleum Communication Foundation Second Edition Copyright © September 2007, Canadian Centre for Energy Information Third Edition Copyright © September 2009, Canadian Centre for Energy Information All rights reserved. No portion of this publication may be reproduced in any form without the express written permission of the Canadian Centre for Energy Information. Professional elementary, secondary and post-secondary school educators may, however, use and copy portions of this publication for the limited purpose of instruction and study provided that such copies include this copyright notice. Copyright to all photographs and illustrations, except where noted, belongs to the Canadian Centre for Energy Information and unauthorized copying of this publication is prohibited.
Revewers – Thr Eto Bob McMus Alberta Energy
Mke Burt In Situ Oil Sands Alliance
lor amche, Ry dobko, ncoe Spers Alberta Environment
do Thompso Oil Sands Developers Group
Stephe Rorgues Canadian Association of Petroleum Producers
Revewers – Seco Eto Jet aesey Shell Canada Limited
Peter Ker Canadian Natural Resources Limited
R Brrett Oil Sands Environmental Management Division, Alberta Environment
Steve Mcisc Inside Education
Br Beows Suncor Energy Inc.
abert deprtmet of Eergy B Ree Japan Canada Oil Sands Limited
Chrs dwso Petro-Canada Ry dobko Environmental Policy Branch, Alberta Environment Bob dubr Strategy West Inc. de Frkouh Athabasca Regional Issues Working Group
Stephe Rorgues Canadian Association of Petroleum Producers Pus Roheser Imperial Oil Limited Bee Scheck Devon Canada Corporation
Kr Fy Syncrude Canada Ltd.
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Contents seCtion 1: ResoURCes BeYonD BeLieF
5 The continental and global context 6 The nature o the resource 7 Challenges 8 Opportunities seCtion 2: A MAssiVe tAsK
11 Mining 12 Extraction 13 In-situ bitumen 13 Cyclic steam stimulation
Steam-assisted gravity drainage (SAGD) 14 Steam-assisted 14 Generating steam 14 Vapour extraction 15 Fireoods 15 “Cold” production 15 Processing 16 Upgrading 17 Transportation 18 Economics 20 Energy balance 20 Products and uses seCtion 3: toWARDs sUstAinABLe DeVeLoPMent
biodiversity 23 Land and biodiversity 24 Water resources 26 Local and regional air quality 27 Greenhouse gases 28 Quality o lie 29 Regulation and consultation 30 Research 31 The path ahead FoR FURtheR inFoRMAtion
32 Publications 33 Websites iBC Key defnitions
CANADA'S OIL SANDS
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Section 1 Resources Beyond Belie As new sources of conventional crude oil become more difficult and expensive to find and produce, substantial investments are being made to develop the oil sands bitumen resources of Western Canada. Thick and sticky, like like blackstrap molasses, oil sands bitumen is tough to recover recover,, tough to process and tough to transport. Yet Yet the oil sands in northern Alberta have become a major part of North American energy production and are expected to become much more important in the decades ahead.
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As o January 2009, there were 91 active mining and in-situ oil sands projects in Alberta that produce more than all the wells in the state o Texas – more than 1.3 million barrels per day in 2008, which represented about 1.5 per cent o world oil supply – and dozens more projects are proposed or under construction. The National Energy Board estimates that production could exceed 2.8 million barrels per day in 2020 i all the current and proposed projects go ahead. The Alberta government envisions oil sands production as high as three million barrels per day by 2018; that would be equivalent to about 2.5 per cent o the North American daily oil consumption in 2008 (2.3 million barrels in Canada, 19.5 million barrels in the United States and 2.1 million barrels in Mexico). Canada also produced 410,900 barrels o conventional heavy oil per day in 2008. Upgraded and non-upgraded bitumen and heavy oil thus accounted or more than hal o Canada’s crude oil production. Without this production, Canada would have been a net importer o crude oil. With it, Canada had substantial positive energy trade balance o $79.6 billion (including natural gas and coal as well as oil) and was the largest single supplier o crude oil to the United States. Although Canada is a net oil exporter, it imported approximately 1.2 million barrels o crude oil and reined products per day in 2008. Many actors have converged to make the Alberta oil sands such an important resource in the 21st century: •
Experiencega Experiencegainedth inedthrough roughmore morethanac thanacenturyo enturyofrese fresearcha archandfo ndfourdec urdecadeso adesof f
commercial production • Continui Continuingdev ngdevelopm elopmentof entoftechno technologie logiestore storeduce ducecosts costsanden andenviro vironment nmentalimp alimpacts acts •
Highdemand Highdemand,,andtherefo andthereforehigh rehighprice prices, s,forcrudeo forcrudeoiland ilandrefin refinedpetr edpetroleu oleumprod mproducts ucts
•
Taxesa Taxesandro ndroyalti yaltiestha esthataread tareadapted aptedtotheh tothehighcap ighcapitalc italcosts ostsandlo andlonglead ngleadtimes timesofoil ofoil
•
sands development Aninfrast Aninfrastructur ructureofro eofroads ads,,pipelinesand pipelinesandelectri electricalpo calpowerli werlines nes
•
Managerial Managerialtalent talent,t ,techni echnicalex calexpertis pertiseandski eandskilled lledlabou labourr
•
Scientific Scientificresear researchtoa chtoaddres ddressthem sthemanyis anyissues suesarisi arisingfro ngfromdeve mdevelopm lopmentand entandimpro improve ve
development processes • Regulatoryand Regulatoryandconsu consultati ltativepro veprocess cessestof estofacili acilitates tatesustai ustainable nabledevel developmen opmentofbo tofboth th renewable and non-renewable resources resources Oil sands development has created many opportunities: •
Alargenewso Alargenewsource urceofpetr ofpetroleum oleumtomeet tomeetNorthA NorthAmeric mericanand anandgloba globaldema ldemand nd
•
Employmen EmploymentforA tforAlbertan lbertansando sandotherC therCanadi anadians ans
•
Revenuesf Revenuesforener orenergycom gycompanie paniesandgo sandgovernm vernments ents
•
Economic Economicbenefi benefitsfo tsforAbo rAborigin riginalpeop alpeopleando leandotherr therreside esidentso ntsofnorth fnortheaster easternAlbe nAlberta rta
•
Investmentsineducation,training,scientificresearchandtechnologicaldevelop training,scientificresearchandtechnologicaldevelopment ment
But there are also challenges arising rom development: •
Greenhous Greenhousegases egasesandot andotherair herairemis emission sions, s,water wateruseand useandlandd landdistu isturbanc rbance e
•
Consump Consumptiono tionofnatu fnaturalga ralgastoext stoextractan ractandupgr dupgradebi adebitumen tumen
•
Strainonin Strainoninfras frastruct tructureand ureandlabou labourmarke rmarketsdu tsduetorap etorapidgr idgrowth owth
•
Inflation Inflationanddel anddelaysdu aysduetohig etohighdema hdemandfo ndforcruc rcrucialgo ialgoodsan odsandservi dservices ces
•
Effectson EffectsonAbori Aboriginal ginalcomm communiti unitiesand esandtradi tradition tionalland allanduses uses
CANADA'S OIL SANDS
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Oil sands deposits underlie 142,000 square kilometres o Alberta, an area larger than the island o Newoundland or the state o North Carolina. The Athabasca oil sands area, by ar the largest, is the site o all surace mining projects and most in-situ extraction projects. There are also large in-situ projects in the Cold Lake oil sands area. Development has been slowerinthePeaceRiver,WabascaandBuffaloHeadHillsdeposits.TheCarbonateTriangle
is an area where bitumen is trapped in limestone rocks as well as sands or sandstones. Production rom the Carbonate Triangle has not been considered technologically or economically easible to date, but companies recently acquired large leases there and presumably see prospects or uture development. Approximately 8,000 square kilometres o bitumen resources are being evaluated in northwest and east-central Saskatchewan, and there are signiicant bitumen deposits on Melville Island in the Canadian Arctic. Conventional heavy oil deposits in Canada are concentrated around Lloydminster on the Alberta-Saskatchewan border, but heavy oil has also been ound in British Columbia, oshore Newoundland and Labrador, and in the Arctic Islands.
ALBeRtA's oiL sAnDs PRojeCts
Athabasca Deposit
BuffaloHead HillsDeposit
OIL SANDS
CNRL Upgrader
PRODUCING PROJECT
Syncrude Upgrader
Suncor Upgrader Fr McMurray
OIL SANDS AREA SURFACE MINEABLE AREA
Nexen Upgrader
EXISTING PIPELINES
Peace River Deposit
PIPELINES UNDER CONSTRUCTION
Wabasca Deposit
Pac Rvr
UPGRADERS
Cold Lake Deposit
Carba tragl
Cold Lake Scotord Upgrader
edm Llydmr HuskyOil Upgrader
t W Ca ad U.s. mark hardy
CANADA
t ear Caada, U.s. mark ad nwGrad Upgradr a Rga
Calgary
t U.s. mark
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CANADA'S OIL SANDS
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t cal ad glbal cx The Canadian oil sands resource – the total amount o bitumen in the ground – is estimated at 1.7 trillion barrels, o which 170 billion barrels are considered recoverable reserves, based on current economics and technology. O these reser ves, approximately 138 billion barrels can only b e recovered through in-situ processes. Reserves currently under development, through both mining and in-situ methods, total 13.5 billion barrels. The recoverable oil sands reserves in northern Alberta represent a potential supply larger than the conventional crude oil reserves o Iran, Iraq or Kuwait, and are second only to those o Saudi Arabia. Bitumen and heavy oil resources are ound in many other parts o the world, including o Canada’s East Coast and in the Arctic Islands, but none o the known deposits come close to the scale o Alberta’s oil sands and the Orinoco heavy oil region o Venezuela. In addition, there are numerous deposits o oil shales around the world, but extracting hydrocarbons economically rom oil shales has proved very difficult.However,newtechnologiesandprocessesareimprovingtheeconomicalviabilityofthese
resources. Relatively abundant coal resources also can be gasiied or converted into liquid uels, but this poses major economic and environmental challenges. Crude oil plays a central role in the North American and world economies. Nearly all motorized transportation (except electric rail) currently depends on gasoline, diesel, jet and marine uels reined rom crude oil. Transportation uels account or about three-quarters o current crude oil consumption. Many other products, rom asphalt paving and rooing to synthetic rubber, are manuactured economically rom by-products o crude oil. While alternatives such as ethanol and biodiesel can ill some o the mobile uel demand, it would take much o the world’s cropland to supply all the transportation energy now obtained rom crude oil. Conservation, eiciency gains and economic recessions can also reduce consumption, but demand or crude oil is likely to remain high well into the 21st century.
WesteRn CAnADA seDiMentARY BAsin CRoss-seCtion
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t aur f rurc Likeallcrudeoil,Canada’sbitumenresourcesstartedaslivingmaterial.Hundredsof
millions o years ago, the remains o tiny plants and animals, mainly algae, were buried in sea beds. As the organic materials became more deeply buried, they slowly “cooked” at temperatures between 50 and 150 degrees Celsius. Eventually, Eventually, this process converted the materials into liquid hydrocarbons, as well as sulphur compounds, carbon dioxide and water. The liquid hydrocarbons included both “light” compounds – those with only a ew atoms o carbon surrounded by hydrogen atoms – and large “heavy” molecules composed o many more carbon atoms and relatively ewer hydrogen atoms. Light hydrocarbons are similartothosefoundingasoline,dieselandjetfuel.Heavyhydrocarbonsarelikethose
ound in grease and tar. The hydrocarbons then migrated through rocks until they reached the surace or something blocked their progress. Conventional light crude oil is usually trapped in porous rocks under a layer o impermeable (non-porous) rock. In such reservoirs, the oil is not in an underground lake but rather held in the pores and ractures o rock, like water in a sponge. Oil sands are dierent. Geologists believe that about 50 million years ago, huge volumes o oil migrated eastward and upward through more than 100 kilometres o rock until they reached and saturated large areas o sand and sandstones at or near the surace. Bacteria then easted on the hydrocarbons, degrading the simplest hydrocarbons irst, converting them into carbon dioxide and water, and leaving behind the big hydrocarbon molecules and other substances that cannot be digested such as trace metals. The bacteria may also modiy some o the simpler sulphur molecules, leaving complex sulphur compounds. As a result, there are more heavy hydrocarbons, complex sulphur compounds and metals in bitumen than in conventional crude oil. This makes extraction and processing more diicult and expensive. While the Athabasca oil sands are one o world’s largest known hydrocarbon resources, the volume o original crude oil digested by the micro-organisms is believed to have been at least two or three times greater than what now remains as bitumen. While bacteria were the major agent in orming Canada’s oil sands bitumen, crude oil can also be degraded or altered by other actors such as oxidation, evaporation, underground water lows and loss o light hydrocarbons that migrate more easily through pores and ractures in rocks. Various combinations o such actors create the many kinds o bitumen and heavy oil deposits ound around the world. In the Alberta oil sands, each grain o sand is surrounded by a layer o water and a ilm o bitumen. The water layer prevents the bitumen rom being absorbed directly onto the sand surace, which allows or relatively simple extraction. In contrast, in oil shales the hydrocarbon is in direct contact with the mineral making extraction more diicult.
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Water layer Sand particle Bitumen ilm
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Callg The economic, environmental and social challenges o oil sands arise rom the nature o the resource, its location, its vast scale and rapid acceleration o development since the late 1990s. The resource is dierent rom light crude oil and requires dierent methods and acilities to produce transportation uels and other commodities previously obtained rom conventional crude oil. Until recently, the main producing region had a small population and modest inrastructure. The resource is so large that almost everything about its development has occurred on a huge and oten unprecedented scale, although smaller in-situ projects are now becoming more common. Among some stakeholders, the recent pace o development has raised questions about sustainability. Economic challenges include inlation, shortages and delays caused by the high demand or labour, equipment and other key goods and services as multiple projects are under construction. Once production begins, labour requirements and the energy requirements in the production process have been major concerns. Projects need continual maintenance to avoid unscheduled production interruptions. As in other high-growth areas, rapid
Photo cortsy of Shll Canada Inc.
extraction and pgrading facilitis, lik th mins thmslvs, ar on a vry larg scal.
growth has put heavy burdens on inrastructure such as roads and water treatment, and new construction has had trouble keeping pace. Environmental challenges involve both the impacts o individual projects and the cumulative eects o development. Greenhouse gas emissions rom production and upgrading are about 10 per cent higher than rom conventional crude; however, i cogeneration is taken into consideration, oil sands crudes would have a carbon ootprint similar to conventional crudes. There are also emissions o gases that can cause acid deposition and ground-level ozone or smog. Use and disposal o water are signiicant issues. Impacts on soils, vegetation and wildlie o the boreal orest – not just rom mining but also rom wells, plants, roads, pipelines, electric power lines and seismic cutlines – raise questions about how ecosystems can be protected during operations and reclaimed ater production ceases.
Photo cortsy of JnWarrn Pblishing Ltd.
Th impact on cosystms is of primary concrn.
The soaring demand or labour and services to support the projects and the eects on the existing Aboriginal and non-Aboriginal communities are among the social challenges. The population o the Regional Municipality o Wood Bualo, which includes Fort McMurray and most o the Athabasca oil sands region, soared by 108 per cent between 1999 and 2007 to more than 89,100. Traic multiplied on the main highway and through the airport. Local government oicials, Aboriginal communities and non-government organizations sought greater input into decisions aecting them.
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oppru The challenges represent opportunities or those who can ind more eective and sustainable ways to do things. Lessons rom our decades o commercial oil sands operations have already been incorporated into the existing projects and those under development, and new approaches are continually being introduced. As a result, Canadians have become world leaders in unconventional crude oil production, and Canadian expertise is now being applied to other bitumen resources in places such as Caliornia and Egypt. The economic opportunities – employment, regional development, government revenues and export earnings – are numerous. Only about 10 per cent o the Alberta bitumen resource is considered economically recoverable with current technologies, yet those reserves would be suicient to sustain production o three million barrels per day or more than 150 years. New methods could unlock the resources currently beyond reach, including the deposits in the Carbonate Triangle. Innovation could also make existing projects much more costeective, productive and environmentally sustainable, or both existing and new projects. Photo cortsy of Sncor enrgy Inc.
Companis ar also working with scintists, govrnmnt athoritis and forstry companis to rdc cmlativ impacts on soils, vgtation and wildlif.
Creative solutions are being ound to the labour shortages and supply bottlenecks that slowed projects as oil sands development accelerated. Companies have built camps to house construction workers, and some workers ly in rom other provinces and ly home or rest days. With support rom industry and government, community colleges and technical schools have expanded programs to train workers, and companies have stepped up in-house training. Companies have also collaborated in eorts to maximize employment opportunities, minimize competition or labour and ensure an adequate supply o skilled trades throughout construction. Construction schedules have been altered and some work postponed to avoid conlicts with other projects. Wherever possible, assembly and abrication work is done in the Edmonton area or elsewhere outside the oil sands region. Some new upgrading acilities are located in the industrial area near Edmonton, and upgrading capacity has been built at the project sites. New pipelines are planned to carry diluted bitumen rom producing areas to upgraders, and upgraded crude oil to reineries. Meanwhile, work has begun on twinning the main highway between Edmonton and the oil sands project area north o Fort McMurray, and a second highway to the Fort McMurray area was paved in 2006. The provincial government has also stepped up support or other inrastructure, water and wastewater treatment, housing, schools and health acilities in Fort McMurray.
Photo cortsy of Dvon Canada Corporation
In 2006, th Albrta govrnmnt lanchd a pblic consltation procss to considr conomic, social, nvironmntal and First Nations and Métis isss associatd with oil sands dvlopmnt.
While existing projects use natural gas to provide most o the energy or operations as well as the hydrogen or upgrading, companies are developing and implementing technologies that reduce or eliminate the need or natural gas. Upgraders already capture much o the energy used or extraction as waste heat and obtain considerable energy rom bitumen residues during processing, and this is expected to increase. One project obtains substantially all its heat energy rom coke and bitumen combustion and gasiication. Technologies are also being tested to extract bitumen underground without the need or steam heat. Other possible energy sources include Alberta’s large coal resources and nuclear reactors. One project has been proposed to gasiy coal in central Alberta as a source o uel and hydrogen, and there have been preliminary discussions about nuclear power options. To this end, the Alberta government established the Nuclear Power Expert Panel to provide a actual report on the issues pertinent to using nuclear power to supply
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electricity in Alberta. That report is available online at www.energy.gov.ab.ca/Electricity/ pds/NuclearPowerReport.pd. As well, the government conducted public consultation, inormation on which is provided at www.energy.gov.ab.ca/Electricity/pds/AB_Nuclear_ workbook.pd Each project undergoes environmental assessment beore approval, and regulatory authorities also consider the cumulative eects o multiple projects on regional ecosystems. Many research and development projects are underway to reduce environmental impacts. Several methods have been suggested to reduce greenhouse gas emissions. One possibility would be to inject emissions underground, known as carbon capture and storage or carbon sequestration; some o the carbon dioxide might be used to enhance production rom conventional oil ields. On a per-barrel basis, greenhouse gases have been reduced 38 per cent and other emissions have been reduced substantially since the 1990s, but the recent rapid expansion o production has made urther emissions reductions a high priority or companies and government authorities. Water recycling and use o non-potable groundwater already reduce impacts on reshwater resources, and new technologies may reduce the large water requirements or current oil sands production methods. Companies are also working with scientists, government authorities and orestry companies to reduce cumulative impacts on soils, vegetation and wildlie. On a per-barrel basis, most in-situ oil sands operations disturb
Photo cortsy of Sncor enrgy Inc.
Many projct componnts ar fabricatd lswhr and thn transportd by rail or trck to th oil sands ara. Th abov photo is a cokr nit for an pgrading plant.
less land than conventional oil operations. There are opportunities or people across Canada – and internationally – in responsible development o oil sands bitumen resources. Production reduces North America’s dependence on imports o crude oil rom other parts o the world, and it makes more oil available to meet global demand. A avourable trade balance beneits Canadians. According to a study by the Canadian Energy Research Institute, over the next 25 years 9.4 per cent o total GDP impacts and 22.8 per cent o total employment rom oil sands investment and operations in Alberta occurs in provinces outside Alberta. The study also indicates the ederal tax impact on Alberta will be $166 billion compared to $22.4 billion or the other provinces.
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Section 2 A Massive M assive Task Task Conventional crude oil flows naturally or is pumped from the ground, but oil sands bitumen does not flow at room temperature and must be mined or recovered in-situ. Deposits close to the surface are mined; those more than about 75 metres below the surface require in-situ recovery. Current in-situ bitumen production generally comes from deposits more than 400 metres below the surface. Many of the technologies used in oil sands extraction are similar to those in other surface mining and conventional oil and gas operations, but they are deployed on a massive scale and sometimes in unique ways. Industry and government research and development has also led to many entirely new technologies for recovering and upgrading bitumen.
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OIL SANDS QueSTIONS + ANSWeRS
3RD eDITION
Mining shovels dig into sand and load it into huge trucks.
Trucks take oil sands to crushers, where it is prepared or extraction. In some operations, a mobile crusher near the shovel may eliminate the need or trucks.
Hotwaterisaddedtotheoilsands and then ed via hydrotransport to the extraction plant.
Bitumen is extracted rom the oil sands during hydrotransport and in the separation vessels.
The tailings are pumped to the settling basin, where most o the water is recycled.
Mg About 20 per cent o Alberta’s economically recoverable oil sands bitumen reserves are close enough to the surace to make mining easible. These are all located in the Athabasca oil sands area north o Fort McMurray. An advantage o mining is that nearly all o the bitumen is extracted rom the ore, while in-situ methods leave a substantial amount o the resource underground. A disadvantage is that a great deal o earth and ore must be moved, disturbing signiicant areas o landscape. To achieve economies o scale, the projects are very large. Each o the operating mining projects also has an upgrader on site or is connected to an upgrader by pipeline. The ore in the current projects’ lease areas averages about 10 to 12 per cent bitumen by weight. Thus nearly two tonnes o oil sands are dug up, moved and processed to make one 159-litre barrel o upgraded crude oil. The processed sand is then returned to the pit, and the site reclaimed. A big part o the mining operation involves clearing trees and brush rom the site and removing the overburden – the topsoil, muskeg, sand, clay and gravel – that sits atop the oil sands deposit. This can amount to more than two tonnes o additional material that needs to be moved in the course o producing one barrel o upgraded crude oil. The topsoil and muskeg are stockpiled so they can be replaced as sections o the mined-out area are reclaimed. The rest o the overburden is used to reconstruct the landscape. The oil sands are highly abrasive and very hard on machinery. Literally tonnes o steel are worn away rom the equipment each year. Regular maintenance is expensive but vital to a proitable operation. When the Suncor and Syncrude projects were built in the 1960s and 1970s, they used giant excavators called bucketwheels and draglines to dig up the oil sands ore and kilometreslong conveyor belts to move it to bitumen extraction acilities. They used this system because, at that time, the largest mining trucks carried less than 60 tonnes in a load. However,theexcavatorsandconveyorswereexpensivetooperateandsufferedfrequent breakdowns, especially in cold weather. In the mid-1980s, Syncrude started using trucks and power shovels or a portion o its oil sands mining. In 1993, Suncor switched its entire operation to a system that used the world’s largest trucks and power shovels. Each truck by then could carry up to 240 tonnes in a single load. Syncrude began phasing out its draglines and bucketwheels a ew years later and retired the last o its draglines in 2006. By the late 1990s, the trucks in use were carrying as much as 360 tonnes, and the largest trucks today carry about 400 tonnes.
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The truck-and-shovel system has proven much more flexible and energy-efficient than the draglines and bucketwheels of yesteryear. The other big innovation in the 1990s was a system called hydrotransport, which uses pipelines instead of conveyors to carry oil sands to the processing plant. The trucks dump the sand into a machine that breaks up lumps and removes rocks, then mixes the sand with warm water. The resulting slurry of oil sands and hot water is transported by pipeline to the extraction plant. As an added benefit, bitumen begins to separate from sand, water and minerals as it travels from the mine to the plant. In the mid-1990s, Syncrude began lowering extraction process temperatures from the 80°C that was then the customary temperature. The move to hydrotransport facilitated a reduction in process temperature to 40°C, which is currently the norm. As a result, the energy requirement for bitumen extraction has been essentially halved. A new system was tested in 2006 and is expected to make ore transportation even more efficient. A mobile crusher, connected to a slurry pipeline, is located next to the power shovel so that the ore can be dumped in directly. Trucks would still be needed to carry overburden and to reach less accessible parts of the mines, but this system could considerably reduce the trucking requirement and related air emissions.
Exr At the processing plant, the mixture of oil, sand and water goes first to a large separation vessel. Tiny air bubbles, which are trapped in the bitumen as it separates from the sand
Froth
granules, float the bitumen to the surface where it forms a thick froth at the top of the vessel. This froth is skimmed off, mixed with a solvent and spun in a centrifuge to remove remaining solids, water and dissolved salts from the bitumen. The solvent is recycled. The sand and water, known as tailings, fall to the bottom of the separation vessel.
Water
The sand is eventually sent back to the mine site to fill in mined-out areas. Water from the extraction process, containing sand, fine clay particles and traces of bitumen, goes into settling ponds. Some bitumen may be skimmed off the ponds if it floats to the surface. Sand
The sand sinks to the bottom and bacteria digest the remaining bitumen, but the fine clay particles stay suspended for some time before slowly settling. Adding gypsum helps to speed the settling process and produces a slurry called consolidated tailings (CT) for disposal in mined-out areas. Water is recycled back to the extraction plant for use in the separation process. As mining operations move further away from the main upgrading plants, some companies
Frothing If you shak hot watr and oil sands in a tst tub, th bitumn forms a froth at th top, watr collcts in th middl, and sand sttls to th bottom. Th procss is similar to that usd in an old-fashiond buttr churn.
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have started building satellite extraction facilities. The bitumen froth is then sent to the upgrader by pipeline. This reduces the round-trip distance for moving sand between the mine pit and the extraction equipment. REcovERy RatEs RatEs foR vaRious typEs of pRoduction
pr e
Reer re
Conventional light oil
Averages about 30 per cent
Conventional heavy oil
Up to 20 per cent
In-situ oil sands
25 to 50 per cent
Oil sands mining
82+ per cent
CANADA' S OIL SANDS
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i-u bum More than 80 per cent o the economically recoverable oil sands bitumen is buried too deeply or surace mining. Most o this cannot be produced rom a well unless it is heated or diluted. Today’s major commercial in-situ projects use steam to heat and dilute the bitumen, although several other methods are being tested or deployed. Current in-situ production technologies technologies recover between 25 and 50 per cent o the bitumen in the reservoir. This is higher recovery than most conventional light crude oil wells. Research to improve the in-situ recovery rates continues. Excluding the use o diesel as uel or the mining equipment and trucks, mining operations may use less energy and water than in-situ operations on a per barrel basis. In-situ does use substantially less surace area, is reclaimed aster and requires ar less reclamation ater
Cyclic Steam Stimulation
operations cease. Research and pilot operations are currently underway which will dramatically reduce the energy and water consumption or in-situ oil
Stam satrats th oil sands formation, softning and dilting th bitmn so it can flow to th wll dring th prodction phas.
sands development. There are two principal in-situ steam injection methods used in Canada today. The choice between them depends on the characteristics o the reservoir.
Cyclc am mula Cyclic steam stimulation is used at Imperial Oil’s Cold Lake project, Canada’s largest in-situ bitumen producer, and at Canadian Natural Resources Limited’s Wol Lake Primrose project. In this method, high-pressure steam is injected into the oil sands ormation or several weeks. The heat sotens the bitumen, while the water helps to dilute and separate the bitumen rom the sand grains. The pressure also creates channels and cracks through which the bitumen can low to the well. When a portion o the reservoir is thoroughly saturated, the steam injection ceases and the reservoir “soaks” or several weeks. This is ollowed by the production phase, when the bitumen is pumped up the same wells to the surace. When production rates decline, another cycle o steam injection begins. This process uses vertical, deviated and horizontal wells
STAGE 3 PRoDUCtion Heatedoiland water are pumped to the surace. STAGE 2 soAK PhAse Steam and condensed water heat the viscous oil.
and is sometimes called “hu-and-pu” recovery. Shell Canada uses a similar method, with horizontal wells, in the Peace River oil sands area. STAGE 1 steAM injeCtion Steam is injected into the reservoir.
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Oil production
sam-ad gravy draag (sAGD)
Steam injection
Most o the other current in-situ projects, particularly in the Athabasca oil sands area, use steam-assisted gravity drainage (SAGD). In this method, pairs o horizontal wells, one above the other, are drilled into an oil sands ormation, and Reservoir
steam is injected continuously into the upp er well. As the steam heats the oil sands ormation, the bitumen sotens and drains into the lower well.
Steam Chamber
Pumps then bring the bitumen to the surace.
Grag am Existing in-situ projects use natural gas-ired boilers to generate steam, consuming between 1,000 and 1,200 cubic eet o natural gas to produce each barrel o bitumen or about twice as much as the mining-upgrading projects use to produce a barrel o synthetic crude oil. In 2007, natural gas consumed by oil sands producers was 412 Bc, up 17 per cent rom 2006. This represents 13 per cent o total Canadian gas demand. This gas use includes natural gas requiredforelectricitygeneratio requiredforelectricitygeneration.However n.However,in-situdev ,in-situdevelopmentsdo elopmentsdonotrequirethe notrequiretheuse use o diesel uel to run equipment in their operations, like typical mining development and thereore do not have that energy requirement or the associated emissions. Technologies have been developed to use crude bitumen as a uel i needed or steam generation. Additionally, some projects are using by-products o bitumen upgrading, such as asphaltenes and carbon residue or coke. Most o these methods would increase emissions o air contaminants, such as particulates, oxides o sulphur and nitrogen, and greenhouse gases compared to natural gas; however, new technologies are being developed to capture and store carbon dioxide and manage the other air contaminants.
Vapur xrac One technology that could reduce energy requirements is called “vapour extraction” or VAPEX. In this method, pairs o parallel horizontal wells are drilled as in SAGD, but instead o steam, natural gas liquids such as ethane, propane or butane are injected into the upper well to act as solvents so the bitumen or heavy oil can low to the lower well. An industrygovernment consortium is currently evaluating a VAPEX pilot project at the Dover lease northwest o Fort McMurray, and the technology is also being tested by several operators on their own leases. A number o other in-situ production systems, including solvents, electric currents, microwaves and even ultrasound, have been tried on an experimental scale.
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Combustion zone Coke zone
Frfld There has been some production o heavy oil and oil sands bitumen with “ireloods” in which air or oxygen is injected and part o the resource is ignited to heat the reservoir. Petrobank Energy and Resources Ltd. is using a variation on the irelood method near Christina Lake, south o Fort McMurray in the Athabasca oil sands region; the system is called“toe-to-heelairinjection”orTHAI TM .
This process uses no natural gas or production and very little water, thereby substantially reducing the
Production well connected to gathering system
Mobile oil zone
Injection well
Pipe perorated in injection zone
Air F r ro n o nt t a l a l a d dv a v n a nc e c e
Toe
Cold heavy oil
GHGemissionsandoverallenvironmentalfootprint
o in-situ production. Pipe perorated rom toe to heel
Heel
“Cld” prduc Conventional production methods using vertical and horizontal wells have also been used, primarily in the Cold Lake oil sands but also in the Athabasca and Peace River oil sands, where deposits are considered too thin to make steam injection economic. This production
Toe-to-heel Toe-to-heel air injection Air or oxygn is injctd and part of th rsorc is ignitd to hat th rsrvoir.
methodisalsoknownasCHOPS(coldheavyoilproductionwithsand).Technologiessuch
as progressive cavity pumps have improved the eectiveness o these “cold” production methods.
Prcg In-situ bitumen processing involves using water to separate the bitumen rom water and sand. In-situ use o surace water has remained relatively constant, but the total volume o groundwater allocated and used is increasing substantially, doubling between 2002 and 2007, with saline ground water use growing and expected to meet up to 40 per cent o total in-situ water requirements in the uture. Devon’s Jackish project currently uses 100 per cent saline water. In-situ projects that use saline water rom deep ormations also treat the water ater use and then re-inject it into these same ormations, so as to not impact the surace or groundwater systems. Up to 90 per cent o the water is recycled, with the remainder injected underground i it cannot be used in operations. Solids may be landilled, injected underground or used to surace roads. Ater processing, the bitumen is diluted with condensate (pentanes and heavier hydrocarbons obtained rom natural gas processing) and the mixture is shipped by pipeline to an upgrader or reinery.
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Upgradg Compared to conventional light crude oil, bitumen typically contains more sulphur and a much higher proportion o large, carbon-rich hydrocarbon molecules. All operating mines have integral upgraders and 100 per cent o mineable production is upgraded within Alberta. In 2008, about eight per cent o in-situ production was upgraded in Alberta, with most o the rest being upgraded elsewhere in Canada or shipped to the U.S. or upgrading. Currently only a very small portion o bitumen is shipped to Asian markets. Upgrading is the process that converts bitumen into a product with a density and viscosity similar to conventional light crude oil. This is accomplished by using heat to “crack” the big molecules into smaller ragments. Adding high-pressure hydrogen and/or removing carbon can also create smaller hydrocarbon molecules. Most o the energy or upgrading is obtained rom byproducts o the process. Upgrading is usually a two-stage process. In the irst stage, coking, hydro-processing, or both, are used to break up the molecules. Coking removes carbon, while hydro-processing adds hydrogen. In the second stage, a process called hydrotreating is used to stabilize the products and to remove impurities such as sulphur and nitrogen. The hydrogen used or hydro-processing and hydrotreating is produced rom natural gas and steam.
I the upgrading process includes coking, the coke is removed rom the bitumen and used or industrial applications. Another upgrading process adds hydrogen to the bitumen and breaks up the large hydrocarbon molecules – a process called hydrogen-addition or hydrogen-conversion. hydrogen-conversion.
Hydrocarbonsarestabilizedbyadding hydrogen in the presence o catalysts. Ater stabilization, the hydrocarbons are separated into naphtha, kerosene and gas oil.
Utilities plants provide steam, nitrogen, oxygen, potable water and electricity.
Sulphur can be recovered to be used in ertilizer and other products.
A range o products including light sweet and sour crude oils and diesel products are blended and shipped to markets.
Upgrading produces various hydrocarbon products that can be blended together into a custom-made crude oil equivalent, or they can be sold or used separately. The Syncrude and Suncor mining projects use some o their production to uel the diesel engines in trucks and other equipment at their operations. Suncor also ships diesel uel by pipeline to Edmonton or sale in the marketplace. Upgraders in Canada remove most o the sulphur rom bitumen. Since sulphur may be about ive per cent o the raw resource, large volumes o this by-product are produced. Natural Resources Canada expects annual sulphur production rom oil sands projects to rise rom about 1.4 million tonnes in 2008 to about 3.3 million tonnes in 2018. Sulphur is used in the manuacture o ertilizers, pharmaceuticals and other products. Unsold sulphur is stockpiled. Those operations that use coking also market or stockpile the coke, which contains some sulphur as well as carbon.
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Co-generation is the simultaneous production o electricity and heat energy rom a single acility. All o the oil sands mining operations, and several o the larger in-situ projects, include natural gas or synthetic gas-ired co-generation. The electricity is used to meet the projects’ own energy needs, such as operating mine machinery and in-situ well pumps, and any excess power is sold to the provincial power grid. The heat energy is used to separate bitumen rom sand – whether at the extraction plants in the mining operations or by steam injection at the in-situ projects. Co-generation produces ewer air emissions per unit o energy produced compared to other thermal-electric generating acilities. Upgrading can occur at the producing site, adjacent to a reinery or anywhere in between. The choice o location or upgrading depends on several actors: •
Capitaland Capitalandopera operatingc tingcosts ostsofthe oftheupgrad upgraderaton eratoneloca elocation tionrelati relativetoa vetoanother nother
•
Potentia Potentialsyner lsynergieso giesofloc flocating atinganupgr anupgradern aderneartoo eartoorinass rinassocia ociationw tionwithot ithother her
corporate assets such as a reinery • Trans ranspo porta rtati tion onco cost stss •
Photo cortsy of Sncor enrgy Inc.
Prodct tanks stor rfinryrady fdstock and disl fl that is shippd by piplin to cstomrs in commrcial and indstrial markts throghot North Amrica.
Diluentco Diluentcostand standavai availabil lability–cru ity–crudebitu debitumenhas menhastobedi tobediluted lutedtofl toflow ow
through pipelines •
Pumpingc Pumpingcosts osts–dilu –dilutedbi tedbitumen tumenrequi requiresmo resmoreener reenergytopu gytopumptha mpthan n
conventional conventional or upgraded crude • Marke Marketi ting ngco cond ndit itio ions ns
trapra Pipelines are the least expensive and most eicient way to move petroleum products over land. Upgraded synthetic crude oil has a density o about 850 kilograms per cubic metre (about 34 degrees on the America Petroleum Institute gravity scale), similar to the vegetable oil in our kitchens, and is shipped through pipelines just like the conventional light crude oil it resembles. Moving bitumen by pipeline is a challenge due to its high viscosity (resistance to low, or stickiness). Large-diameter pipelines with powerul pumps help, but producers also lower the density and viscosity o the bitumen by diluting it with a light, low-viscosity petroleum
Photo cortsy of Sncor enrgy Inc.
Sand is mind sing shovls with bckts that hold 100 tonns, loading 400 tonn trcks.
product such as condensate, conventional light crude oil or synthetic crude oil. Some bitumen must be diluted by as much as 40 per cent to low through a pipeline. The most common diluents or oil sands bitumen is condensate, a mixture o pentanes and heavier hydrocarbons obtained rom natural gas processing. Supplies o condensate in Western Canada are limited. Some pipeline systems already include return lines to carry condensate back upstream or re-use. A recent alternative uses synthetic crude to dilute bitumen or shipment; the two luids are separated beore processing at the downstream end. Other proposed solutions involve pipelining imported condensate rom the U.S. Midwest or Canada’s West Coast or use as diluent. As bitumen production has increased, there have been periodic shortages o condensate and light oil available or dilution. This is one reason why upgraders in Western Canada increased their processing capacity. Bitumen can also be shipped by truck, but again it must be diluted or heated irst. Trucks are used mainly to carry production rom small or experimental operations to the nearest upgrader or pipeline terminal.
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ecmc Oil sands development depends mainly on two actors: the cost o producing and transporting the products, and the price buyers are willing to pay. Crude oil prices are determined by global supply and demand and change with the weather, politics and other actors. For Western Canadian producers, reining capacity and competition in the midcontinental U.S. and Canadian markets are also key considerations. Operating costs – the labour, natural gas and other goods and services needed to produce a barrel – comprise about hal o the supply cost or producers. In addition, companies have to earn enough to repay the capital they invested in the project, pay royalties and taxes to government, reclaim the sites and set aside unds or research, maintenance and new developments. The developers have invested billions o dollars in the projects, and they must attempt to earn a competitive return on this investment. Judging by the scale o current and proposed activity, companies generally believe that oil sands projects are worthwhile long-term investments. A number o actors aect the proitability o oil sands projects. Major inluences include the exchange rate o the Canadian dollar, iscal terms and operating expenses such as initial capital costs, crude prices and natural gas, material and labour costs. As well, because o unique challenges, dierent projects will have diering operating costs. The operating costs or conventional light oil in Western Canada are considerably lower than or upgraded oil sands bitumen, but conventional producers also have to invest continually in exploration or new reserves, which can add substantially to their costs. Ater a ew years o production, the volume produced rom a conventional well begins to decline and the operating costs start to rise, whereas this is not the case with oil sands mining. Operating costs in the oil sands mining projects are partly dependent on the price o natural gas used to generate steam and electricity and to produce hydrogen in associated upgrading acilities. I ways can be ound to reduce or eliminate natural gas use, then costs could be reduced signiicantly. Wages and salaries are another major component o operating costs or mines and upgraders as they employ large numbers o skilled workers. The operating costs to produce in-situ bitumen vary considerably. In a 2008 study, the Canadian Energy Research Institute estimated plant gate supply costs o about $42 per
Photo cortsy of Syncrd Canada Ltd.
Th high dmand for labor in th oilsands rgion has also allviatd nmploymnt across th contry.
barrel or cyclic steam stimulation projects and $38 per barrel or steam-assisted gravity drainage projects, compared to almost $63 per barrel or mining projects. The amount o natural gas used to generate steam and the recovery rate are the key actors. The availability o condensate and light oil to dilute bitumen can also aect markets or these products. The price o bitumen generally increases in the spring and summer when a lot o road-building and construction activity requiring asphalt is under way. The spread between the price o heavy and light oils is called the dierential. The provincial government, which owns the mineral rights to virtually all o the oil sands resources, has recognized the long-term beneits o development in shaping royalty arrangements or their “owner’s share” o revenues rom oil sands. Alberta established a stable “generic” oil sands royalty system in 1997 ater decades o negotiating project-byproject arrangements. Under the generic system, the province collected one per cent o gross sales revenues on all production and a 25 per cent share o net project revenues ater the operator recovered capital costs to build the project.
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In 2009, the government introduced its New Royalty Framework, consisting o price-sensitive royalty rates linked to the price o West Texas Intermediate crude oil in Canadian dollars. For projects that haven’t recovered capital costs incurred to construct the project, gross royalty rates start at one per cent when oil is priced at $55 per barrel or less, and increase to a maximum o nine per cent when oil is priced at $120 per barrel or more. For projects that have recovered start-up coats, net royalty rates start at 25 per cent when oil is priced at $55 per barrel or less, and increase to a maximum o 40 per cent when oil is priced at $120 or more. The goals o the new Royalty Regime are as ollows: •
Supportsus Supportsustainab tainableecon leeconomic omicdevel developmen opmentthatc tthatcontri ontributes butestoahi toahighqual ghqualityofl ityoflife ife
or all Albertans now and into the uture • Supportafai Supportafair, r,predictable predictableandtr andtranspa ansparentr rentroyal oyaltyregi tyregime me •
AlignAlbert AlignAlberta’ a’sroyaltyre sroyaltyregimew gimewithov ithoverall erallgove governmen rnmentobject tobjectives ives
More inormation is available at http://www.energy.gov.ab.ca/OilSands/808.asp One economic beneit o oil sands development is the ongoing stable employment and signiicant maintenance capital expended throughout the entire lie o the project, in contrast to the ups and downs o conventional oil operations. This was an important consideration cited by the governments when they implemented the generic royalty and tax regimes. Though the economic eects o oil sands development are concentrated in Alberta, they also spread across the country and internationally through purchases o equipment, materials and services. Companies and workers pay taxes to the ederal government, and Alberta is a major contributor to equalization payments that aid poorer provinces. According to a study by the Canadian Energy Research Institute, ederal tax impacts o oil sands investment and operations in Alberta over the next 25 years will total $188.5 billion, o which $166 billion will impact Alberta and $22.4 billion will impact the other provinces. Similarly, the provincial tax impact on Alberta will be $94.7 billion compared to $23.5 billion on the other provinces. The high demand or labour in the oil sands region has also alleviated unemployment across the country. People rom Atlantic Canada, or example, now account or more than one-quarter o the population in Fort McMurray.
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ergy balac The energy balance is simply the ratio between energy inputs and outputs or a given type o energy production. Energy balances are used as indicators o eiciency when comparing energy types and production methods. Based on National Energy Board data or natural gas inputs and petroleum outputs, the energy balance or oil sands mining-upgrading projects is about 1:12 and it is about 1:6 or in-situ bitumen production. In addition, about 14 per cent o the raw bitumen is consumed to produce energy during upgrading or is converted into by-products such as coke and sulphur. As a result i the raw bitumen rom in-situ projects is then upgraded into synthetic crude oil, the energy balance is as low as 1:4. The energy balance or oil sands is roughly comparable to that or ethanol produced rom sugar cane in Brazil – where one unit o energy input produces about eight units o ethanol uel energy – and it is much better than ethanol produced rom corn in North America, where one unit o energy input only produces about 1.3 units o ethanol uel energy. Since the early 1990s, energy use per barrel in oil sands mining and extraction has been reduced about 45 per cent through the use o new technologies such as hydrotransport, which is more eicient than conveyors or truck transport. New, low-temperature extraction processes urther reduce energy use.
Prduc ad u Upgraded synthetic crude oil is a conventional light oil equivalent. The most common products made rom upgraded synthetic crude oil are transportation uels such as gasoline, diesel and jet uel. Others include petrochemicals used in making synthetic rubber and polystyrene. When bitumen is processed in reineries, it also produces transportation uels and some petrochemicals, as well as the asphalt needed or road paving and rooing. Sulphur, which comprises about ive per cent o oil sands bitumen, is a major by-product o
Common prodcts mad from pgradd crd oil, othr than transportation fls, incld ptrochmicals ptrochmicals sd in making synthtic rbbr and plastics. plastics.
oil sands upgrading. The decision to sell or stockpile sulphur or uture sale is dependent on world sulphur markets and the availability o storag e space. Until recently, Syncrude stockpiled most o its sulphur at the upgrader site, but in 2005 Syncrude sold sulphur rom its stockpile or the irst time in 10 years, and the company is now producing ertilizer rom its sulphur. Suncor and other companies have sold most o their sulphur production on international markets despite low prices and high transportation costs or the commodity. Canada is the world’s largest producer and exporter o elemental sulphur, which is also obtained rom sour gas production. By 2018, however, however, upgraders could generate as much as 3.3 million tonnes o sulphur per year. To To address this issue, China and India have been identiied as potential markets since sulphurcanbeusedtomakefertilizer.However,whileChinahasbeenoneofthefastest growing sulphur markets, Canadian supply to the market has declined by 30 per cent in 2008 over 2007. Canada’s share o exports into the China market has dropped, while competitive supplies rom the Middle East have increased. Sulphur is also used in other industries such as pharmaceuticals and synthetic rubber. Some sulphur is currently used in road asphalt and potentially could be used in concrete or other construction materials.
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Section 3 Towards Susta Sustainable inable Development Like many types of resource development, oil sands projects affect land, air and water and the human, plant and animal life they sustain. As ecological knowledge and environmental awareness have grown over the years, companies and government authorities have sought better ways to reduce or eliminate such effects. This helps to ensure the highest possible quality of life for industry’s workers and those who reside near its plants, while also reducing impacts on regional and global ecosystems.
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The Alberta and ederal governments and the petroleum industry generally subscribe to the concept o sustainable development, de ined as “development that meets today’s needs without compromising the ability o uture generations to meet their needs.” As the pace o oil sands development began to accelerate in 1999, the Alberta government announced the Regional Sustainable Development Strategy or the oil sands area o northeastern Alberta. The strategy deined sustainable development this way:
"undr sstainabl dvlopmnt, rnwabl rsorcs ar managd to nsr thir long-trm viability and potntial ftr s. Non-rnwabl rsorcs ar managd to maximiz thir bnfits. Sstainabl dvlopmnt taks into accont th intrdpndnc of trs, minrals, wildlif, watr, fish, rang lands, pblic lands, plants and othr similar rsorcs... It considrs th conomic ffcts of nvironmntal dcisions, and th nvironmntal ffcts of conomic dcisions." To implement the strategy, multi-stakeholder task orces brought together industry, dierent levels o government, non- governmental organizations, Aboriginal communities and local businesses and other interests. They sought co-ordinated approaches to issues such as health care, inrastructure and air quality as well as the cumulative eects rom so much development occurring so rapidly, most o it in one geographical area. In 2006, the Alberta government conducted public consultation through the oil sands Multi-Stakeholder Committee (MSC), to consider economic, social, environmental and First Nations and Métis issues associated with oil sands development. Phase I o the process set out a vision and principles or oil sands development. Phase II sought public input on implementing the vision and principles, and included separate, parallel First Nations and Métis consultation ocusing on potential adverse impacts o oil sands development on constitutionally protected rights and traditional land uses. Inormation gathered by the MSC supplemented previous public and interest-group input that has been ongoing since commercial oil sands operations began. The MSC reached consensus on 96 o 120 recommendations regarding Aboriginal consultation, minimizing the impact o oil sands on biodiversity, improving land reclamation, the need or protected areas, planning and monitoring processes, and retention o a larger share o related, value-added processing. It ailed to reach consensus on the pace o development, water use, targets or greenhouse gas emissions, limiting the amount o land available or oil sands projects, and royalties and taxes. The Multi-Stakeholder Committee Final Report and the Aboriginal Consultation Final Report were published in 2007 and are available at www.oilsandsconsultations.gov.ab.ca Photo cortsy of Syncrd Canada Ltd.
Svral hndrd wood bison graz on th Syncrd sit as part of a long-trm rclamation rclamation projct co-managd with th narby Fort McKay First Nation.
Aboriginal people, who have inhabited the oil sands region or thousands o years, have a special interest in how development proceeds. While they have gained many opportunities through direct employment and the creation o Aboriginal-owned businesses, they have also expressed concern about the impacts o development on their communities, the environment and traditional land uses. In December 2008, the Alberta government released the Land-use Framework, which sets out an approach on how to better manage public and private lands and natural resources in
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light o achieving Alberta’s long-term economic, environmental and social goals. The Lower Athabasca Regional Plan will identiy and set resource and environmental management outcomes or air, land, water and b iodiversity, and guide uture resource decisions while considering social and economic impacts. In February 2009, Alberta released Responsible Actions, a 20-year strategic plan or Alberta’s oil sands, which addresses the economic, social, environmental, research and innovation, and governance needs o Alberta’s oil sands regions. The plan will orm a new provincial and regional approach to managing the oil sands regions. The plan was based on extensive stakeholder consultations described in Investing in our Future: Responding to the Rapid Growth o Oil Sands Development, the Multi-Stakeholder Committee Final Report and the Aboriginal Consultation Final Report. Responsible Actions also builds on existing Alberta government policies, programs and initiatives, particularly the Provincial Energy Strategy and Land-use Framework.
Lad ad bdvry As Canada’s largest mines, the Athabasca oil sands projects aect thousands o hectares o borealforest,wetlands,watershedsandmuskeg.However,onlyfourpercentofCanada’s 310 million hectare boreal orest is underlain by oil sands. Approximately 2.5 per cent o that land, or 0.1 per cent o the boreal orest, is mineable. To the end o 2008, 53,000 hectares had been disturbed. During operations, as well as when mining is completed, the developers are required to restore the mine sites to at least the equivalent o their previous biological productivity. Reclamation is an ongoing process with initial reclamation work commencing as soon as three years ater the land is irst disturbed. This does not mean “tree-by-tree” restoration, but rather that the region as a whole should orm an ecosystem with a productive capacity equal to or greater than that which existed beore development. Howisthisdone?Beforeoperationsbegin,environmentalscientistsrecordexistingsoil
types and plant and animal species in a detailed Environmental Impact Assessment or EIA. Trees that must be harvested are sent to nearby lumber or pulp mills. Muskeg and topsoil are removed and stockpiled. Sand rom the processing acility is returned to mined-out
Photo cortsy of Shll Canada Inc.
Scintific stdis ar ndrway to dtrmin how mch watr can b withdrawn from th Athabasca Rivr withot ngativ ffcts.
areas. Ater an area is mined, topsoil and overburden are replaced, and an annual ground cover such as barley is planted to stabilize the soil. The surace is then replanted with trees, shrubs or grasses. When the area meets the provincial government’s standard or reclamation the land is certiied and it is oicially returned to the Province and is no longer under the control o the oil sands project. Once a certiicate is granted the land reverts back to the crown, would be available or public access and would be unavailable to the oil sands project. Syncrude and Suncor have reclaimed 4,500 and 1,000 hectares respectively and have planted more than 8.5 million trees. Neither company has applied or reclamation certiicates or these areas or a variety o reasons, including that the areas o land remain integral to their operations and the companies want to maintain control over these areas. Several hundred wood bison graze on the Syncrude site as part o a long-term reclamation project co-managed with the nearby Fort McKay First Nation. The bison project is the result o Syncrude’s research eorts into reclamation techniques that will also create productive wildlie habitats. Wood bison were chosen as a ocus because the species was native to the area until their near extinction in the 1800s, and played an important role in the economy and culture o Aboriginal communities.
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OnlySyncrude’s104-hectareparceloflandknownasGatewayHillhasbeenissueda
certiicate by Alberta Environment to date (2009). Research and development to address land issues is continuing. Among the issues or upgraders are the long-term disposal or utilization options or their stockpiles o sulphur and coke. The use o slanted and horizontal wells greatly reduces the land disturbance associated with in-situ bitumen projects. One surace installation, known as a pad, may contain up to Photo cortsy of Sncor enrgy Inc.
Sttling ponds allow clay and silt to sttl ot of th watr sd in th xtraction procss. procss. A nmbr of improvmnts hav bn mad to th dsign and opration of in-sit oil wll casings.
10 well pairs producing rom ormations with a radius o more than a kilometre. Insulated, above-ground pipelines carry steam and bitumen among acilities and well locations at in-situ projects. When production ceases, regulations require that the wells be sealed with cement and the biological productivity o the site be restored. In-situ reclamation is similar in scale and timing to conventional oil reclamation. Mining and in-situ oil sands projects, related seismic programs, roads, pipelines and electrical power lines disturb substantial areas o boreal orest. The “linear disturbances” ragment the landscape and aect wildlie habitat. An approach called Integrated Landscape Management, developed by the Alberta Chamber o Resources in the late 1990s, brings together oil companies and orestry companies to reduce their cumulative impacts on landscapes, orest productivity and wildlie – through measures such as narrower seismic cutlines and co-ordinated planning to reduce the number o roads. “Meandering” cutlines reduce line-o-site corridors or predators, and on-site mulching o wastes speeds reclamation. Research is also underway to improve reorestation o reclaimed sites.
War rurc The National Energy Board estimates that between two and 4.5 barrels o water are needed to produce a barrel o oil sands bitumen in oil sands mining operations. Most o this, up to 90 per cent in some cases, is recycled, and industry is working to reduce water use overall. Some water is also returned to the hydrosphere through evaporation. In-situ development is required by the provincial environmental and energy agencies to use brackish or nonpotable groundwater or production. Most o the water utilized in oil sands mining mining comes rom surace water bodies, typically large adjacent rivers. Scientiic studies were conducted to determine how much water can be withdrawn rom the Athabasca River and other watersheds without negative eects on ish and aquatic lie. The total annual allocation o water rom the Athabasca River or all uses (e.g., municipal, industrial and oil sands) is less than 3.2 per cent o low. This compares to 37 per cent or the North Saskatchewan River (Edmonton), 60 per cent or the Oldman River (Southern Alberta) and 65 per cent or the Bow River (Calgary). Current oil sands mining projects use about one per p er cent o the total annual water low o the Athabasca River. Should all existing, approved and announced oil sands projects proceed, industry would use 2.2 per cent o the Athabasca river low. low. Industry’s withdrawal o water rom the Athabasca River is capped during p eriods o low river low to protect the aquatic ecosystem. The industry-unded, multi-stakeholder Regional Aquatics Monitoring Program (RAMP) has been assessing regional watersheds, ish populations and aquatic ecosystems in the Athabasca oil sands area since 1997. In 2008, RAMP reported that dierences between
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baseline low rates and 2008 low rates at test sites were negligible to low in the Athabasca River in six out o ten tributaries. Similarly, dierences between baseline water quality conditions and 2008 water quality conditions at test sites were negligible to low at 14 out o 16 tributaries. The ederal Fisheries Act requires that developers compensate or loss o ish habitat. The ratio or compensation is at least two-to-one; that is, or each unit o habitat lost, at least two units o equivalent habitat must be created, restored or protected elsewhere in the region. The tailings ponds at oil sands mining projects pose additional challenges. In the extraction process at the mining projects, the water picks up tiny particles o clay. Ponds are used to hold the resulting tailings, a mixture o clay, water and trace amounts o unrecovered bitumen. Oil sands mining developers are using various methods or managing the tailings over the long term. Tailings ponds are not used in in-situ projects. There are two methods o reclaiming tailings ponds, water-capped lakes and solid landscapes. With water-capped lakes, a layer o resh water is placed over the tailings; this water cap could unction as a normal aquatic ecosystem while the clay particles slowly drit to the bottom. Because there is still some debate about whether the settling ponds can become biologically productive ecosystems over the long term, the developers are continuing to study the mat ter. With solid or dry landscapes, gypsum is used to accelerate the settling time and create consolidated tailings. Without the gypsum, the coarse sand raction o the tailings settles out aster than the iner clays, which may take some years to orm mature ine tailings, a mixture o water and 30 per cent solids. In the consolidated tailings process, the tailings stream is hydrocycloned to separate the coarse sand raction rom the ine tailings and water. The sand is then mixed with mature ine tailings and gypsum to orm an un-segregated, stable mixture that consolidates to approximately 80 per cent solids in less than one year. Calcium-rich water released rom the concentrated tailings is added to the ine tailings rom the cyclone process to accelerate settling and produce more consolidated consolidated ine tailings which are in turn mixed with sand and gypsum. In-situ projects have made a continuing eort to reduce water use through increased recycling. Developers are required to use brackish (non-drinkable) water rom underground aquiers to meet part o their water needs. Another issue or in-situ operations is the possibility that casing ailures in steaming operations could contaminate water supplies in underground aquiers. In the Cold Lake area, investigations o the impacts o casing ailures on groundwater quality ound the eects were restricted to the immediate vicinity o a casing ailure. Produced luids released into an aquier rom a casing ailure are recovered by pumping back the released luids. A number o improvements have also been made to the design and operation o in-situ oil well casings. These improvements reduce the number o uture casing ailures and minimize their consequences. For example, by detecting breaks earlier, when they are the size o pinholes, the amount o luid that may be released into a groundwater aquier is
Photo cortsy of enCana
Carbon sqstration not only dispos of C0 2 safly, it rdcs grnhos gas missions. In som convntional oilfilds, th carbon dioxid from oil sands missions cold b sd to nhanc oil rcovry.
signiicantly reduced.
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In the late 1990s, an extensive investigation o groundwater quality around in-situ heavy oil operations was conducted by Komex International Ltd. and Imperial Oil. The study ound that regional groundwater quality had not been aected by in-situ operations. The study also recommended that the monitoring o groundwater quality be enhanced. The enhanced monitoring systems determine groundwater conditions prior to new developments, as well as monitor groundwater quality during the operating lie o the development.
Lcal ad rgal ar qualy Oil sands mining, processing and upgrading produce emissions that aect air quality. New technology and more eicient operations have greatly reduced emissions per barrel o production, but the rapid increase in production has led to increases in some emissions such as oxides o nitrogen (NO x). Alberta authorities have stated that they will be watching closely the cumulative eect o air emissions. Between 1990 and 2006, the annual average NOx concentration increased 7.0 per cent. However,meanannualNOx concentrations in the oil sands regions remain about hal those in Edmonton and Calgary and are well below regulatory limits. NO x emissions contribute to acid deposition and also combine with volatile organic compounds and particulate matter in the presence o sunlight to orm ground-level ozone or smog. According to Environment Canada data, oil sands accounted or 4.5 per cent o Alberta’s total emissions o NO x in 2006. Companies have committed to use “best available technology economically achievable” to reduce NO x emissions. For example, new truck engines emit considerably less NO x and gasired heaters must comply with strict “low-NO x” emission standards. Emissions o sulphur compounds and hydrocarbons also aect local air qualit y. Syncrude and Suncor have reduced these by capturing gases ormerly released into the atmosphere or burned in open lares. The gases are captured in lue gas desulphurization units that produce sulphur or use in making gypsum (Suncor) or ertilizer (Syncrude). Upgraders remove up to 99.8 per cent o the sulphur rom bitumen by converting it into elemental sulphur or retaining it in the coke byproduct, so it is not released with endproduct combustion. The remaining sulphur is released into the atmosphere as sulphur dioxide (SO2). This may combine with water vapour to orm sulphurous acid or sulphuric acid and contribute to acid deposition that aects orests and water resources. According to Environment Canada data, oil sands projects accounted or 30.9 per cent o Alberta’s total sulphur dioxide emissions in 2007. The Wood Bualo Environmental Association monitors air quality in Fort McMurray and the surrounding area. Monitoring includes continuous air quality data and periodic air samples. Air quality in the region generally compares avourably with that o Alberta cities such as Edmonton, Calgary and Fort Saskatchewan. Monitoring results in 2008 showed: •
Theone-houraveragereadings Theone-houraveragereadingsforsulphu forsulphurdioxid rdioxideinFortMcMurra einFortMcMurray, y,FortMcKayand FortMcKayand
Fort Chipewyan were below provincial objectives or ambient air quality • Therewere10exceedencesoftheone-hou Therewere10exceedencesoftheone-hourprovinci rprovincialobjectivesf alobjectivesforsulphur orsulphurdioxide dioxide in areas close to the oil sands acilities • Therewerenoexceedencesoftheone-ho Therewerenoexceedencesoftheone-hourprovinc urprovincialobjectivef ialobjectivefornitrogendio ornitrogendioxide xide • Therewere412exceedencesoftheone-ho Therewere412exceedencesoftheone-houraveragepro uraverageprovincialobje vincialobjectivefor ctivefor hydrogen sulphide
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The Wood Bualo Environmental Association also operates the Terrestrial Environmental Eects Monitoring (TEEM), an ecological monitoring program that samples bogs, ens, lichens and other plant growth to monitor nitrogen and sulphur. The Cumulative Environmental Management Association (CEMA) has developed management rameworks or terrestrial ecosystem, land capability, ozone management, landscape design, acid deposition, ecosystems management, trace metals and nitrogen. In all the oil sands areas, including Cold Lake and Peace River as well as Athabasca, monitoring through 2008 showed that air quality was rated good more than 95 per cent o the time.
Gru ga Oil sands operations also emit large amounts o carbon dioxide and some methane. These are among the heat-trapping greenhouse gases that aect global climate. In 2007, oil sands facilitieswerethesecondlargestsourceofreportedGHGemissionsinAlbertaaccounting for23percentor26.5megatonnesoftotalGHGemissions(carbondioxideequivalent)in
the province. The utilities sector was the largest source o greenhouse gas emissions in Albertawith49.9megatonnesor44percentoftotalreportedGHGemissions. In2007,AlbertabecamethefirstjurisdictioninNorthAmericatolegislateGHGreductions
or large industrial acilities. Any acility, including including oil sands, that emits more than 100,000 tonnesofGHGperyearisrequiredtoreducetheiremissionsintensityby12percentfrom 2003-2005 levels starting in 2007. Facilities that ail to meet this target have the option o buying Alberta-based carbon osets, or paying $15 per tonne over reduction targets into the Climate Change and Emissions Emissions Management Fund. The und supports projects and technologiesaimedatreducingGHGemissionsintheprovince.
As part o the long-term climate change plan Alberta plans to cut projected greenhouse gas emissions by 50 per cent or 200 megatonnes o carbon dioxide equivalents by 2050. It translates to real reductions o 14 per cent below 2005 levels. To date, more eicient use o energy has been the main strategy to reduce greenhouse gas emissions rom oil sands. Research is underway into the possibility o capturing carbon dioxide emissions rom oil sands plants and injecting them underground, which is known as carbon capture and storage (CCS) or carbon sequestration. In some conventional oilields, the carbon dioxide rom oil sands emissions could be used to enhance oil recovery. Alberta is the irst jurisdiction in North America to direct dedicated unding to implement carbon capture and storage across industrial sectors. CCS is orecast to deliver about 70 per cent o the long-term climate change plan’s projected 200 megatonnes carbon dioxide equivalentreduction by 2050, with the majority o those reductions coming rom activities related to oil sands production. Osets are another option to reduce global greenhouse gas emissions. Osets are reductions in emissions that are caused by an activity not directly related to the source creating the emissions. Planting millions o trees to absorb carbon dioxide creates an oset or whoever plants the trees. In an emissions-trading system, carbon dioxide osets can be traded on an emissions market. From a global perspective, what matters is the total amount o greenhouse gases emitted during a product’s “wells to wheels lie cycle” rom extraction to the inal use by a consumer. According to two independent studies commissioned by the Alberta Energy Research Institute released in 2009, greenhouse gas emissions rom the oil sands are
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about 10 per cent higher than direct emissions rom other crudes in the United States. However,ifcogenerationistakeninto However,ifcogenerationistakenintoconsideration consideration,greenhousegasemissio ,greenhousegasemissionsfromoil nsfromoil
sands are similar to those rom the other crudes. The studies, Lif Cycl Assssmnt Comparison of North Amrican and Importd Crd, researched and authored by Jacobs Consultancy Canada Inc. and Comparison of North Amrican and Importd Crd Oil Lifcycl GHG emissions , researched and authored by TIAX LLC, were conducted in 2008. The studies also indicated that greenhouse gas emissions rom conventional crudes are rising because o the increasing reliance upon heavier crudes that are more diicult to produce. Conversely, Conversely, greenhouse gas emissions rom oil sands crudes are decreasing because o technological advances.
Qualy f lf Tens o thousands o new jobs come rom oil sands development. In 2006, Alberta’s unemployment rate was the lowest or any province or state in North America, and the province’s economic growth rate was among the highest in the world. Workers and their amilies have locked to the oil sands region and elsewhere in the province. While this growth has been a boon or these individuals, it puts great pressure on public services, housing and inrastructure. Many businesses have had trouble inding and keeping sta. During consultations in 2006, some Albertans, including the mayor o Fort McMurray, urged Photo cortsy of Shll Canada Ltd.
Oil sands projcts hav cratd nw opportnitis for local bsinsss, inclding many ntrpriss ownd and opratd by Aboriginal popl.
a slowdown in oil sands development so that other sectors could keep pace. In 2008 and 2009, the pace o development did slow due to economic conditions that caused the delay or outright cancellation o some projects. However,oilsandsprojectsalsocreatednewopportunitiesforlocalbusinesses,including
many enterprises owned and operated by Aboriginal people. Splitting contracts into many components makes it possible or smaller companies to bid on them. Oil sands developers use open house events, local media and ongoing consultation to ensure that local people are aware o upcoming business opportunities. The Northeast Alberta Aboriginal Business Association distributes contract inormation among its members, and the Regional Economic Development Link or “Red Link” acilitates opportunities through inormation, communications, promotions, research, networking, and sales. Providing employment and business opportunities is, however, just one o the ways that the industry is transorming the social abric and economic well-being o the oil sands areas. Aboriginal people make up about 10 per cent o the population in the Athabasca oil sands area, and industry has made a concerted eort to provide opportunities or them. Since the 1970s, the government and oil sands companies have established programs to train and recruit Aboriginal people as employees, employees, contractors and suppliers, and the new projects seek Aboriginal involvement involvement wherever possible. About $2.6 billion worth o contracts were awarded to local Aboriginal companies between 1996 and 2007 $606 million in 2007 alone. It is expected that nearly 400,000 jobs will be created in Alberta over the next 10 years, but only 300,000 new workers are expected to enter the labour market. This means the province may ace a shortall that may be as high as 100,000 workers. The Alberta government has released a long-term strategy to combat skill and labour shortages in the province, and is asking Albertans or input.
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Rgula ad cula The Alberta Resources Conservation Board and Alberta Environment are the principal regulators o oil sands operations in the province. Alberta Energy and Alberta Sustainable Resource Development also have direct roles in oil sands regulation. The National Energy Board regulates interprovincial and international aspects such as pipelines and exports. Large projects aecting interprovincial air and water resources, and related issues such as isheries, are typically subject to joint ederal-provincial environmental assessment. Provincial and ederal energy, environment, health and s aety authorities are also involved in many aspects o oil sands regulation. Through the Aboriginal Policy Framework released in 2000, Alberta committed to consult with First Nations when land management and resource development decisions may inringe their existing treaty or other constitutional rights. Beginning in September 2003, Alberta engaged in dialogue with industry and First Nations about consultation and the ocus o consultation policy. The province’s First Nations Consultation Policy on Land
Photo cortsy of Imprial Oil Ltd.
edcation initiativs and consltation fforts hlp dcat srronding commnitis abot Canada's oil sands.
Management and Resource Development was approved on May 16, 2005. It reinorced the commitment or consultation that was identiied in the Aboriginal Policy Framework. The policy outlines the province’s expectations o First Nations and resource companies in striving or increased certainty or all parties with respect to land management and resource development activities. In addition, it outlines the province’s approach to meeting its consultation responsibilities. Following the release o the policy, the province worked with First Nations and industry to develop a Framework or Consultation Guidelines and sector-speciic consultation guidelines. The ramework was released on May 19, 2006 and the guidelines were implemented on September 1, 2006. In addition, the Athabasca Tribal Council began working with the government to develop speciic consultation guidelines or the Athabasca oil sands area where development has been most intense. In 2000, two groups were created to address traditional environmental knowledge in the Athabasca oil sands region. The Cumulative Environmental Management Association ormed a standing committee, the Traditional Environmental Knowledge Committee, to provide guidance on how to incorporate Aboriginal expertise into their knowledge base. The Reclamation Advisory Committee meanwhile created a sub-group to address
Photo cortsy of Imprial Oil Ltd.
Throgh th Aboriginal Policy Framwork Framwork rlasd in 2000, Albrta committd to conslt with First Nations whn land managmnt and rsorc dvlopmnt dvlopmnt may infring thir xisting traty or othr constittional constittional rights.
traditional knowledge. Much o the science and understanding used in reclamation and environmental activities previously were based on Western knowledge. The members o the two bodies were aware o the needs and desires o the people indigenous to the Athabasca area, and wanted to incorporate their knowledge to have a greater understanding o what environmental protection and reclamation should encompass. Traditional ecological knowledge includes inormation rom people with an understanding o how past generations lived o o the land. This includes many First Nations people, Métis and historians o local culture.
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Rarc The National Energy Board estimates that only about 10 per cent o Canada’s oil sands resource can be recovered economically with current technology. The uture o this resource will be decided in the laboratory. Government and industry have invested heavily in oil sands and in-situ research and development or decades, and much more will undoubtedly be spent in the uture to improve the technological, environmental and economic perormance o oil sands developments. In 2007, seven oil and gas companies with major interests in oil sands were among the 100 largest investors in research and development in Canada. These companies’ research and development spending in 2007, much o it ocused on oil sands, totaled $346 million. Several hundred researchers work in industry, university and government laboratories, primarily in the Calgary and Edmonton areas, to ind solutions to the scientiic and technological challenges acing the oil sands industry. Employees and contractors throughout the industry constantly seek more eicient, cost-eective and environmentally sensitive ways to do things. Some o the immediate challenges acing the scientists and technologists include: reducing emissions o oxides o nitrogen and greenhouse gases; reducing water use and natural gas consumption; improving the eiciency o oil sands mining, bitumen extraction and in-situ recovery; obtaining a higher yield o desirable products rom upgrading; reducing equipment maintenance requirements; reducing the need to dilute bitumen or pipeline transportation; and improving tailings management and reclamation methods. Research partners rom industry, the academic community and government co-ordinate their eorts through associations such as the Petroleum Technology Alliance Canada (PTAC), Canadian Oil Sands Network or Research and Development (CONRAD), the Alberta Chamber o Resources’ Oil Sands Task Force, Black Oil Pipeline Network Steering Committee, the CO2 Synergies Research Network, and Co-ordination o University Research or Synergy and Eectiveness (COURSE). The Alberta Energy Research Institute's research priorities with regard to oil sands include improving bitumen upgrading; demonstrating clean carbon/coal is a viable uel or producing electricity; improving oil recovery technologies; developing technologies that reduce greenhouse gas emissions; supporting new technology to reduce resh water use by the energy industry and advancing and adapting technology or alternative energy sources.
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t pa aad North Americans have a huge appetite or oil products. Each Canadian and American uses an average o more than 20 barrels (3,178 litres) worth o petroleum-based products and services per year. Today, Today, it is not possible or historic domestic sources o production to meet this demand. Conventional light crude oil production is declining throughout most oil-producing areas o the United States and Western Canada. The United States already imports more than hal o its oil supplies. Canada has continued to export more oil than it imports. In act, Canada has actually increased oil production thanks to oil sands, heavy oil and oshore oil development. Oshore, Arctic and conventional oil resources can maintain Canadian production and revenues or a while, but the oil sands are the nation's principal petroleum source or the long haul. Humaningenuityhasalreadyaccomplishedagreatdealbymakingtheoilsands
economically competitive with conventional oil. Environmental and social challenges are being engaged. Continuous improvement in science, technology and management are helping to overcome the remaining challenges to meet society’s expectations or sustainable development.
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FoR FURtheR inFoRMAtion Publca Alberta Energy and Natural Resources. enrgy Hritag – Oil Sands and Havy Oils of Albrta . Edmonton: 1982. Alberta Energy Research Institute. Lie Cycle Analysis o North American and Imported Crude Oils. Two studies commissioned and released by AERI: , Lif Cycl Assssmnt Comparison of North Amrican and Importd Crd , researched and authored by Jacobs Consultancy Canada Inc. and Comparison of North Amrican and Importd Crd Oil Lifcycl GHG emissions , researched and authored by TIAX LLC. 2009 AEUB. Crd Bitmn Rsrvs Atlas. Calgary: May 1996. Alberta Oil Sands Technology and Research Authority. AOSTRA – A 15-Yar Portfolio of Achivmnt. Edmonton: 1990. Bryson, Connie, ed. Opportnity Oil Sands. Winnipeg: Fleet Publications Inc., 1996. Bott,Robert.“TrueGrit–HowSyncrudeManagesforSuccess,” Th Glob and Mail Rport on Bsinss Magazin. Toronto: May 1995.
Canadian Association o Petroleum Producers. 2005 CAPP Stwardship Progrss Rport. Calgary: 2006. Canadian Energy Research Institute. economic Impacts of Albrta’s Oil Rsorcs: Sptmbr 2008 updat, Vol. 1 . November 2008 Canadian Energy Research Institute. economic Impacts of th Ptrolm Indstry in Canada . July 2009 Chastko, Paul. Dvloping Albrta’s Oil Sands, From Karl Clark to Kyoto. University o Calgary Press, 2004. Comort, Darlene J. The Abasand Fiasco: T h ris and fall of a brav pionr oil sands xtraction plant. Edmonton: Friesen Printers, 1980. De Bruijn, Theo. Challngs for Low Cost upgrading – A Canadian Prspctiv. Devon, Alberta: National Centre or Upgrading Technology, December 1998. Energy Resources Conservation Board. Albrta’s enrgy Rsrvs 2008 and Spply/Dmand Otlook 2009-2018 . ST982009. Calgary: June 2009 Ferguson, Barry Glen. Athabasca Oil Sands – Northrn Rsorc exploration, 1875-1951 1875-1951.. Regina: Canadian Plains Research Centre, 1985. Fitzgerald, J. Joseph. Black Gold with Grit: Th Albrta Oil Sands. Sidney, British Columbia: Gr ay’s Publishing Ltd., 1978. Ignatie, A. A Canadian Rsarch Hritag : An Historical Accont of 75 Yars of Fdral G ovrnmnt Rsarch and Dvlopmnt in Minrals, Mtals and Fls at th Mins Branch. Ottawa: Energy, Mines and Resources Canada, Canada Centre or Mineral and Energy Technology, 1981. 1981. McCann,T.J.,andPhilMagee.“CrudeOilGreenhouseGasLifeCycleAnalysisHelpsAssignValuesForCO2Emissions Trading,” Th Oil and Gas Jornal . Tulsa, Oklahoma: February 22, 1999.
McKenzie-Brown, Peter; Gordon Jaremko, and David Finch. Th Grat Oil Ag . Calgary: Detselig Publishers, 1993. Mikula, R.J., V.A. Munoz, K.L. Kasperski, O.E. Omotoso, and D. Sheeran. Commrcial Implmntation of a Dry Landscap Oil Sands Tailings Rclamation Option: Consolidatd Tailings. 7thUNITARInternationalConferenceonHeavyCrudeand Tar Sands, paper 1998.096. Mink,Frank,andRichardN.Houlihan.“TarSands,”p.129 Mink,Frank,andRichardN.Houlihan.“TarSands,” p.129,Vol.A26, ,Vol.A26, ullmann’s ullmann’s encyclopdia of Indstrial Chmistry . Weinheim, Germany: 1995.
Mitchell, Robert; Brad Anderson, Marty Kaga, and Stephen Eliot. Albrta’s Oil Sands: updat on th Gnric Royalty Rgim. Edmonton: Alberta Department o Energy, 1998. National Energy Board. Canada’s enrgy Ftr: Scnarios for Spply and Dmand to 2025. Calgary: 2003. National Energy Board. Canada’s Oil Sands: Opportnitis and Challngs to 2015. Calgary: May 2004. National Energy Board. Canada’s Oil Sands – Opportnitis and Challngs to 2015: An updat. Calgary: June 2006. National Oil sands Task Force. A Nw era of Opportnity for Canada’s Oil Sands. Edmonton: Alberta Chamber o Resources, 1996. Oil Sands Ministerial Strategy Committee. I nvsting in Or Ftr – Final Rport. Edmonton: Government o Alberta, 2007.(DownloadedMarch2,2007fromhttp://www.gov.ab.ca/home/index.cfm?page=1551) Prince, J.P., and Govinda Timilsina. Sprading th Walth Arond: Th economic Impacts of Albrta’s Oil Sands Indstry. Calgary: Canadian Energy Research Institute, September 2005. Rolheiser, Pius. “Riddle o the Sands,” Imprial Oil Rviw. Toronto: Summer 1998.
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The Royal Tyrrell Museum o Paleontology. Th Land Bfor us – Th Making of Ancint Albrta. Red Deer, Alberta: Red Deer College Press, 1994. Russell, Loris S. “Abraham Gesner,” Dictionary of Canadian Biography. Toronto: University o Toronto Press, 2000. Sheppard, Mary Clark, ed. Oil Sands Scientist – Th Lttrs of Karl A. Clark, 1920-1949. Edmonton: The University o Alberta Press, 1989. 1989. Woynillowicz, Dan, Chris Severson-Baker and Marlo Raynolds. Oil Sands Fvr: Th environmntal Implications of Canada’s Oil Sands Rsh. Calgary: Pembina Institute, November 2005.
Wb The Canadian Centre or Energy Inormation web portal www.centreorenergy.com provides up-to-date inormation about oil sands and crude oil in Canada. The Centre or Energy’s general introduction to the industry, Or Ptrolm Challng, can be purchased online and provides inormation about drilling, pipelining and processing o crude oil and natural gas as well as a glossary o industry terms. Note: Most U.S. reerences, and some Canadian and international entities, use the American spelling or sulphur and related compounds. When doing searches in libraries or on the Internet, also remember to check or “sulur, sulide, suluric, sulurous, etc.” as well as the Canadian spellings. Alberta Energy www.energy.gov.ab.ca Alberta Energy Research Institute www.aeri.ab.c a Alberta Environment www.environment.gov.ab.ca Alberta Geological Survey www.ags.gov.ab.ca Alberta Utilities Commission www.auc.ab.ca Canadian Association o Petroleum Petroleum Producers Producers www.capp.ca Canadian Energy Research Institute www.ceri.ca CanadianHeavyOilAssociationwww.choa.ab.ca
Clean Air Strategic Alliance www.casahome.org Energy Resources Conservation Board www.ercb.ca Environment Canada www.ec.gc.ca In Situ Oil Sands Alliance www.iosa.ca National Energy Board www.neb- one.gc.ca Natural Resources Canada www.nrcan-r ncan.gc.ca Oil Sands Developers Group www.oilsandsdevelopers.ca Pembina Institute www.pembina.org Regional Aquatics Monitoring Program www.ramp-alber ta.org Regional Economic Development Alliance http: //www.alber tacanada.com/regionaldev/121 tacanada.com/regionaldev/1218.html 8.html Wood Bualo Environmental Association www.wbea.org
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Key eftos Hyrocrbos are compounds of hydrogen and carbon. The simplest hydrocarbon is methane (CH4), composed of one carbon atom and four hydrogen atoms. Methane is the principal component of natural gas. Crue o is a naturally occurring liquid mixture of hydrocarbons. It typically includes complex hydrocarbon molecules – long chains and rings of hydrogen and carbon atoms. The liquid hydrocarbons may be mixed with natural gas, carbon dioxide, saltwater, sulphur compounds and sand. Most of these substances are separated from the liquid hydrocarbons at field processing facilities called batteries. Conventional light crude oil flows easily at room temperature. Upgre crue o is a blend of hydrocarbons similar to light crude oil. It is produced by processing bitumen or heavy oil at a facility called an upgrader. The term synthetic crude oil is sometimes also used for upgraded crude oil. Btume is a thick, sticky form of crude oil. At room temperature, bitumen has the consistency of molasses. It must be heated or diluted before it will flow easily into a well or through a pipeline. Bitumen is sometimes called extra-heavy crude oil. A typical dictionary definition of bitumen is “a tar-like mixture of petroleum hydrocarbons.” A more technical definition in the oil-producing industry is: A naturally occurring, viscous mixture of hydrocarbons that contains sulphur compounds and will not flow in its naturally occurring viscous state. duets are light petroleum liquids used to dilute bitumen and heavy crude oil so it can flow through pipelines. O ss are naturally occurring mixtures of bitumen, water, sand and clay that are found mainly in three areas of Alberta – Athabasca, Peace River and Cold Lake. A typical sample of oil sands might contain about 12 per cent bitumen by weight, although bitumen content can vary widely among specific samples and sites. If the oil sands deposits are close to the surface, bitumen can be recovered from the oil sands by open-pit mining and hot-water processing methods. Deeper deposits require in-situ methods such as steam injection through vertical or horizontal wells. (In-situ means “in-place” in Latin; the oil industry uses this term to indicate the bitumen is separated from the sand underground, in the geological formation where it occurs.) Surface mining is used in the Athabasca oil sands, while in-situ methods are used in all three major oil sands areas. Hevy crue o includes some crude oil that will flow at room temperatures, however slowly, but most heavy oil also requires heat or dilution to flow to a well or through a pipeline. Therefore it is similar to bitumen, although lighter, generally less viscous and usually containing less sulphur. In Canada, the term heavy oil refers to petroleum with a density greater than 900 kilograms per cubic metre (or below 25.7°API on the American Petroleum Institute gravity scale). Petroeum is a general term for all the naturally occurring hydrocarbons – natural gas, natural gas liquids, crude oil and bitumen – although in some usage petroleum refers only to liquid hydrocarbons. ntur gs qus (nGls) are ethane, propane, butane and condensates (pentanes and heavier hydrocarbons) that are often found in natural gas; some of these hydrocarbons are liquid only at low temperatures or under pressure. NGLs can be used as solvents for in-situ in-sit u bitumen b itumen production, and condensates are the most common diluent diluent for shipping bitumen by pipeline. Resources are substances found in nature that are of some use. Bitumen resources, for example, are all the extra-heavy hydrocarbons in the ground in a given area. Reserves are the recoverable portion of resources. Governments generally define reserves as the amounts available for use based on current knowledge, technology and economics. Securities regulators use a narrower definition that also requires a firm development plan with reasonable timelines. As a result, there can be a wide gap between government reserves estimates and the sum of those reported by companies. Brre is a common unit for measuring petroleum. One barrel contains approximately 159 litres. There are about 6.3 barrels in one cubic metre. All costs in this booklet are quoted in Canadian dollars unless otherwise noted.
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