Alberta’s Oil Sands Resources, Production Growth,Products and Markets

7/27/2019 Albertas Oil Sands Resources, Production Growth,Products and Markets

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Albertas Oil Sands

Resources, Production

Growth,Products and Markets

Duke du Plessis. Senior Advisor

Alberta Economic Development

andAlberta Energy Research Institute

Calgary, Alberta , Canada

October 18, 2004


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Snapshot of Albertas Energy Industry

Alberta has abundant energy resources and a vibrantenergy industry

Worlds 3rd largest natural gas producer

9th largest crude oil producer

Large investments in expanding oil sands production

Maintaining global competitiveness with newtechnologies

Secure and efficient access to markets

Planned pipeline expansions will provide increasedaccess to Asia

Attractive investment opportunities


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Alberta - A major

Energy hub in NorthAmerica


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EdmontonEdmonton

CalgaryCalgary

Peace RiverPeace RiverFortFort

McMurrayMcMurray

AthabascaAthabasca

Peace RiverPeace RiverWabascaWabasca

ColdColdLakeLake

SyncrudeSyncrude

Alberta, Canada

Oil Gas Bitumen Coal

Million m3 Million m3 Million m3 Mill tonnes

Remaining Reserve 291 1211 27,810 34,000Annual Production 43.5 140.7 100.23* 34

Remaining Life 7 9 580 1000

Resources Coal Bed Methane

>3,600 Million m3

Albertas Energy Resources


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Proven World Reserves

0

50

100

150

200

250

300

billion

barrel

SaudiA

rabi

a

Cana

daIra

q

Ven

ezuela

Russia

Mexic

o

Alberta

Sources: Oil and Gas Journal Dec 2002, AEUB

5


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The Oil Sands Resource

174 billion barrels of proven reserves174 bill ion barrels of proven reserves

500 years of supply available at currentof supply available at currentproduction rates (app.. 1 millionproduction rates (app.. 1 million bblsbbls/day)/day)

Production based on currentProduction based on current miningmining andandInIn--situsitu techniquestechniques

Marketed to Canadian and US refineriesMarketed to Canadian and US refineries

(primarily Midwest US)(primarily Midwest US)

$24 billion in investment$24 billion in investment 1996 to 20031996 to 20036

Th N t f th Oil S d R


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The Nature of the Oil Sands Resource- Different technologies required for Mining and in Situ Areas -


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Continuous Innovation Since the 1930s

From Oil SandsFrom Oil Sands To BitumenTo Bitumen To Synthetic crude oilTo Synthetic crude oil

N t f Alb t Bit


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Nature of Alberta Bitumen

Bitumen Characterized by High Density

Substantial Residue Yield

High Viscosity

High Sulphur

for some, High TAN

Bitumen Must Be Blended or Upgraded to Access theMarket

Synthetic Crude Oil

Heavy Crude Oil Blend

Diluent-Bitumen (Dilbit)

SCO-Bitumen (Syn-bit)


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0

100

200

300

400

500

600

700

1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017

(000 M3/D)

0

500

1000

1500

2000

2500

3000

3500

4000

(000 B/D)

Raw Bitumen

Pentanes Plus

Conventional Heavy

Athabasca Synthetic

Conventional Light

Potential

Western Canada Sedimentary Basin

Crude Oil Production Potential

$24 bill (Cdn) under construction or approved $60 bill additional announced

> 66% of Canadas production by 2020

Source: CAPP

Potential


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Whos Playing the Game

- Mining Projects -

Not an all inclusive list

1980 2000 2006+

Suncor Suncor Suncor

Syncrude Syncrude Syncrude

Imperial

Albian/Shell

Synenco

CNRLFort Hills

11Source DOE


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Not an all inclusive list

Whos Playing the Game

- Insitu Projects -1980 2000

Imperial Imperial Imperial Jacos

AEC Encana Deer Creek

Numerous CNRL CNRL OPTI/Nexen

Experimental Shell Shell BlackRock

Projects PanCdn Suncor ConocoPhillips

Numac PetroCanada Husky

Northstar Petrovera Total

Murphy Devon

2006+

12Source DOE

C i l E di


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Capital Expenditures

0

1

2

3

4

5

6

7

8

1996 1997 1998 1999 2000 2001 2002 2003

C$billions

Actuals

Estimated

Since 2000 high capital

investment ($5.9bill/year) has exceededAlbertas engineering

and constructioncapacity resulting in costoverruns

Planned investments for

2004 2020 is $60 billion($3.3 billion/year)

Sustainable if properly

phased

1996-2003:Total Investment > $24 billion ($3.5 bill/year-Sustainable)Average: 2000-2003 = $5.9 bill/year (not sustainable- Cost overruns)

Planned investments for

2003-2020 > $60 billion

($3.5 bill/year)

Not sustainable

Sustainable


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Oil Sands Capital Investment

0

2

4

6

8

10

12

14

199

6

199

8

200

0

200

2

200

4

200

6

200

8

201

0

201

2

201

4

201

6

C$billions

Actuals

Estimated

Announced

Unsustainable

-Cost overruns-

Sustainable

1996-2003:Total Investment > $24 billion

Average for 2000-2003 = $5.9 bill/year

2003- 2020:Total Investment > $60 billion

Sustainable if phased over 17 years ($3.5 bill/year)


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Technology Trends

Surface Mining Truck and shovel

Hydro-transport

In Situ Cyclic Steam Stimulation (CSS)

Cold Heavy Oil Production with Sand(CHOPS-Primary)

Steam Assisted Gravity Drainage (SAGD)

Vapor Extraction (VAPEX)

Upgrading & Value-Added Products Integration/Synergies with existing facilities


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Innovation in Mining Technology

From Draglines to Shovel & Truck Operations

1970 2000


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DraglineDraglineBucketwheelBucketwheel

ConveyorConveyor

DumpDumpPocketPocket

ConveyorConveyorHot WaterHot WaterExtractionExtraction

Warm SlurryWarm Slurry

ExtractionExtraction

Shovel/TruckShovel/TruckFeeder/CrusherFeeder/Crusher

CyclofeederCyclofeeder

PipelinePipeline

Surface Mining and Extraction

400 tonne Ore Trucks


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400 tonne Ore Trucks

C l f d


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Cyclofeeder

Sl H d t t


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Slurry Hydrotransport

Primary Separation Vessel


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Primary Separation Vessel

Technology advances over 20+ years have reduced mined


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Technology advances over 20+ years have reduced minedoil sands production costs from > US$30 to < $10/barrel

Source: Syncrude Ltd.

Mining/Extraction/Upgrading


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Mining/Extraction/Upgrading

Opportunities to Further Reduce Costs Replace coking with critical solvent deasphalting

Replace natural gas with coke or asphaltene gasification Reduce water use: recycling tailings consolidation

Continuous mining & extraction equipment

Improved froth treatment to produce a cleaner bitumen

for upgrading

Improved catalysts

C ti s D l t f I sitContinuous Development of In situ


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Continuous Development of In situ

Technologies

Continuous Development of In situ

TechnologiesThermal Oil Sands Efficiency ImprovementThermal Oil Sands Efficiency ImprovementThermal Oil Sands Efficiency Improvement

8

4

2

Steam/Oil RatioSteam/Oil Ratio

1970 20202000

Carbon intensityCarbon intensity

19901980 2010

First cyclic steam pilotFirst cyclic steam pilot

First SAGD pilotFirst SAGD pilot

*Future potential could include VAPEX, thermal solvent, etc.

0

6

1960

Cyclic steamcommercial projects

SAGD commercialprojects

Futurepotential*

Maturing reservoirMaturing reservoir

Technology pilotsTechnology pilots

1960 1980 1990 2000 2010 2020

I Sit R T h l i


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In Situ Recovery Technologies

Primary Recovery- Cold Heavy Oil Poductionwith Sand (CHOPS)

Thermal Recovery

Cyclic Steam Stimulation (CSS) Steam Assisted Gravity Drainage (SAGD)

Solvent-based recovery processes Vapour Recovery Extraction (VAPEX)

Hybrid thermal/solvent processes Steam Assisted Gas Push (SAGP)

Expanding Solvent SAGD (ES-SAGD)Steam

Low Pressure Solvent SAGD

Tapered Steam Solvent SAGD(TSS-SAGD)


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Cyclic Steam Stimulation Process


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Cyclic Steam Stimulation (CSS)

Current Technology

Developed by Imperial Oilin late 1950s

Steam Cycle:

Steam injection (4-6 weeks)

Soak (4-8 weeks)

Production (3-6 months

Recoveries 20-25% of

original bitumen in place

Current production >120,000 b/d

Successful at Cold Lake

Innovation

CSS less successful for Peace

River Not economical in Athabasca

deposits

CNRL Innovation: Increasesteam injection pressure tofracture pressure

Steam plus solvent process

being tested in a field pilot

In Situ Extraction of Deeper Bitumen Resources


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Development of Steam Assisted Gravity Drainage (SAGD)

1980s 2000Underground Test Facility Horizontal wells drilled from surface

Steam Assisted Gravity Drainage (SAGD) Commercial


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Steam Assisted Gravity Drainage (SAGD) Commercial

after 20 years and some 30 pilot projects

Technology IssuesRequires good vertical permeability

Sub-optimal steam-oil ratios

Natural gas for steam requirements

Water

Energy intensity GHG emissions

Only viable technologyfor 90% of bitumenresources in Athabasca

Significantly reducedland disturbance

Higher recovery thanCSS (up to 50%)

Lower steam-oil ratiosthan CSS

C ti i I ti VAPEX P


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Advantages for:

thin reservoirs

bottom water reservoirs

Minimize water handling/disposal

Reduce greenhouse gas emissions

Low energy consumption

Continuing Innovation-VAPEX Process

Oil sandSolvent mix

Overburden

Underburden

Vapour Chamber

Oil sandSolvent mix

Overburden

Underburden

Vapour Chamber

Oil sand

Solvent mix

Overburden

Underburden

Upgraded Oil , Solvent, Gas

Vapour Chamber

Potential for in situ upgrading

Asphaltene Deposition

Diffusion,

Dispersion

Capillary

Mixing

Solubility

Oil

Drainage

Heavy

Oil

Vapour

Chamber

Swelling

Diffusion,

Dispersion

Capillary

Mixing

Solubility

Oil

Drainage

Heavy

Oil

Vapour

Chamber

Swelling

Continuing Innovation-VAPEX Process


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Continuing Innovation-VAPEX Process Non-thermal:Uses hydrocarbon solvents instead of steam

Vaporized solvent injected into reservoir Reduces water use, energy and CO2 emissions

Solvent is recycled and recovered at the surface

Potential to recover up to 90% of solvent Produced bitumen has higher quality

Potential to reduce costs significantly

Challenges: Solvent recovery Field trials by DOVAP Industry Consortium since 2002

At least 5 years from commercial application

Devon

ChevronImperial

Gibson

PetroCanada

Total

SuncorCNRL

Nexen

JACOS

Continuing Innovation400Production Rates


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Patented steam-solvent hybridprocess

Ongoing research at theAlberta Research Council

Oil rates 68% Energy & water use 45% Reduced GHG emissions

Field tests being conducted bySuncor, CNRL, EnCana,ConocoPhillips, PetroCanada

Continuing Innovation

Hybrid Thermal-Solvent

ProcessES-SAGD Process

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

E

nergyRequirements

(GJ/m3Oil) Steam Energy= 2.8 GJ/m

3steam

SAGD

ES-SAGD

0

50

100

150

200

250

300

350

A

verageOilRate(m3/d)

SAGD

ES-SAGD

45%

68%

Energy Requirements

New Thermal Solvent Reflux Process Concept


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New Thermal Solvent Reflux Process Concept(being developed at the Alberta Research Council)

overburden

vapour

chamber Mobilizedoil

Injector

Refluxedsolvent

Heaters in wells

Oil sand

Producer

underburden

Heaters in injector and

producer wells vaporize

solvent in reservoirSolvent reflux mobilizes

oil

No external recycling &recovery of solvent

Faster start-up

Lower costsIndustry sponsored R&D


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Current Production CostsCost per barrel ($ CDN, 2003)ProductionMethod

Crude

Type Operating Supply

Mining/Upgrading Synthetic 12 to 18 22 to 28

Mining/Extraction Bitumen 6 to 10 12 to 16

SAGD Bitumen 8 to 14 11 to 17

CSS Bitumen 8 to 14 13 to 19

CHOPS Bitumen 6 to 9 12 to 16

Cold Bitumen 4 to 7 10 to 14

Source: NEB 34

Bitumen Supply Cost


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Bitumen Supply Cost

Typical Athabasca SAGD Project

0

2

4

6

8

10

12

14

B

itumenSu

pplyCost(US$/b@P

lant

Gate

Fuel

Royalties

Income Tax

Fixed Capital

Other OperatingCosts

Return on Investment

Source: CERI

Bitumen Supply Cost Sensitivities


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pp y

Typical Athabasca SAGD Project25% Change in

Steam-Oil Ratio

Natural Gas Price

Initial Capital Cost

Discount rate

Operating Cost

10.3 10.7 11.0 11.4 11.8 12.2 12.6 13.0 13.4

Bitumen Supply Cost (US$/barrel @ Plant Gate)

Source: CERI

Both Mining and In Situ Extraction


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g

Processes use large amounts of Natural Gas

Mined

Oil Sands Extraction

Synthetic Crude Oil(SCO)

In situ

ExtractionBitumen

Diluent

PipelineMarkets

Steam

Plant

Warm Water

Distillation,Coking,UpgradingBitumen

Natural Gas for hydrogen and heat

Natural Gas for steam generation

Dilbit


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Increasing Natural Gas Prices reduce the

Profitability of Mined Oil Sands Plants

I i N l G P i d h


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Increasing Natural Gas Prices decrease the

profitability of SAGD Projects even more

Gasification of Coke or Asphaltenes Replaces


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Natural Gas in Mining/Upgrading and in SAGD

Processes and Reduces CO2 emissions

Coke orAsphaltenes

frombitumen

Slag

Oxygen

Acid GasRemoval

Electricity

Gasifier

SulphurBitumen

Upgrading

SAGDHorizontal

Wells

CO2

CO2 Pipeline

H2

SynthesisGas (CO + H2)

Boiler

Separation

Steam

Gasification Replaces Natural Gas


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for hydrogen and heat & produces a higher value synthetic crude

OPTI Nexen Long Lake Process

Gasification

Plant

D i bl f t f Alb t SCO


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Desirable features of Alberta SCO

PipelinableLow SulphurLow Nitrogen

U di T h l 1940 T d


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Upgrading Technology - 1940- Today

Visbreaking Hydrogen Addition Coking

Thermal Cracking

Deasphalting

Gasification

Shell/AlbianOpti-Nexen Husky

SuncorSyncrude

CNRL

Opti-Nexen

Heat H2

Innovation in UpgradingT h l i


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Technologies Solvent deasphalting

Used by Shell and Opti

Supercritical Solvent Deasphalting to improveproduct quality

Replace natural gas as a source of hydrogen andsteam by gasifying coke or asphaltenes

Extract valuable by-products: petrochemicals (and

metals) Integrate Upgrading-Refining-Petrochemicals

Membrane separation and Catalysts

Refined Products and Petrochemicals IncreaseValue and Market Options for Rapidly Growing


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Value and Market Options for Rapidly Growing

Oil Sands Production

2.7

6.9

8.2

8.3

8.6

9.4

9.7

10.9

11.1

16.6

19.7

26.8

0 5 10 15 20 25 3

Bitumen

SCO

Diesel

Natura l Gas

Jet Fuel

Propane

Gasoline

Ethylene

Xylene

Propylene

Ethylene

Styrene

U.S. Cents per Pound. Constant 2003 Dol la rs

Increasing Valueand market options

Adapted from Purvin & Gertz, March 30,2004

Propylene is a component


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of existing process streams

0

20

40

60

80

100

120

140

Suncor

Syncrude

NOVA

Do

w

PCRe

finery

Im

perialR

ef

KTA

Extracted

& produced

by Williams

Energy

Propylene Potential


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py

Kilotonnes/year

Refineries 320

Existing Upgraders 230

Petrochemical Plants 110

Total 660

Other sources

Existing upgrader expansions

BA Energy Upgrader

Opti


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Summary

48

Albertas Oil Sands in 2020


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Offshore Exports

United States Exports

Rest of Canada Exports

Upgrading &Refining

Petrochemical

Development

World Scale Hub for Energy and Refined Products

Alberta Bitumen ProductionAlberta Bitumen Production

3 Million Barrels Per Day3 Million Barrels Per Day

Electricity

Generation

Exports of Crude Oil andExports of Crude Oil andRefined Petroleum ProductsRefined Petroleum Products

Oil Sands Reserves


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O Sa ds ese ves

Capturing the Opportunity

Opportunity

Recoverable

Today0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

Initial In-Place Initial Established

Billion

barrels

Insitu

Mineable

Source: EUB

Alberta Oil Sands Advantage


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Abundant resource and world-class industry

Regulatory stability andcertainty

Competitive fiscal regime

Track record of innovation

Open and competitive markets

Oil sands pictures courtesy of Syncrude Canada. 51


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Alberta- A Good Place to do Business

Vision for the Future


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2000 2010 2020 2030

million barrels per day

6

5

4

3

2

1

3rdOIL

SANDSW

AVE

conventionallightandheavycrude

greenfu

elspetroche

micals

energy/power/H2

bitumen

syntheticcrude

Vision for the Future

Oil sands: a sustainablecompetitive source

of synthetic crude oil,

refined products,petrochemicals and

clean energy

Adapted from Oil Sands Technology Roadmap, Alberta Chamber of Resources, Jan 30, 2004

Documents

Alberta’s Oil Sands Resources, Production Growth,Products and Markets