penwell july14-09 oil sands workshop-final-adobe copy

7/25/2019 Penwell July14-09 Oil Sands Workshop-FINAL-Adobe Copy

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An Introduction to Oil Sands and Heavy Oil

Industry, Technology & Economics

The Oil Sands and Heavy Oil Technology Conference & ExhibitionJuly 14-16, 2009

Calgary, Alberta, Canada.

Owned and Produced by

Presented by: Len Flint, Ph.D, P.Eng.(403) 238-0484 / [email protected]


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Introductory Remarks

on Agenda& Terminology

LENEF Consulting (1994) Limited 1


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The material presented in this workshop coversthe technology, economics and environmentalchallenges to oil sands development

Over the last year, two very important developmentshave occurred:

1) Crude prices are a pale shadow of their levelsthis time last year

2) The environmental and sometimes political lobby,especially in the US, has placed additional issuesbefore the industrywe are labelled Dirty Oil

To the extent possible, some of our discussion willaddress the implications and the reality



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The Changing Challenges

2006 to PRE -2008 CRASH

- capital costs in Alberta- impact of the new Royalties in 2009

- environmental challenges getting air time

POST CRASH

- Oil prices less certain

- New President / Carbon management- dirty oil label begins to stick- Land reclamation & water use priority issues



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Section Section Topics min

1 Introduction What we will coverTerminology HC -101 10

2 What is Bitumen ? Location of Main DepositsQuality v. Conventional crudes

History of Development LandmarksProduction ProjectionsMarkets

15

3 Bitumen Recovery MiningExtraction & Froth TreatmentTailings ManagementWater useCosts

AlternativesIn SituRecoveryThermal Methods and CostsReasons and Alternatives to SAGDNew Technologies

40

4 Why Upgrade ? Field Upgrading: moving to marketsFull Synthetic Products 20

5 Upgrading Coker-based Upgraders/Crude QualityHydro-Conversion AlternativesNatural Gas use and impactNew Approaches to Upgrading / QualityHydrogen ManagementUpgrader By-Products

40

Break 30



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Section Section Topics min

6 Oil Sands IndustryEconomics

LightHeavy Oil DifferentialsRecovery & Upgrading

Cash Flows/Investment ReturnsImpact of New Royalty ProposalsGovernment & Industry: Who gets what ?

30

7 Where to Upgrade Recent Plans in Alberta / Shifting Sands ?Canada v. U.S. RefineriesCurrent Plans both sides of the border

15

8 EnvironmentalChallenges

elephant in the room

Greenhouse Gas IntensityWater Use & ManagementLand Management

30

Lunch 30

9 Summary Overview of Key Points 15

10 Q & A 30



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Hydrocarbons 101 Basic Terminology

Naphtha Gasoline boiling range

Distillates Jet/Diesel boiling range

Heavy Gas OilNeeds to be cracked/convertedto naphtha/distillates

Residueneeds to be cracked/converted

- to naphtha/distillates

- orasphalt- orblended to Very Heavy Fuel Oil

Major Crude Properties: oAPI Gravity % w S~ 40 for light crudes < 0.5~ 20-38 for Conv.Hvy. 2 to 3 %

~ 8-12 for Bitumens 4 to 5 %

Downstream Refining

(not covered in this workshop)

Heavy Products

Light Products

GasolineJet FuelDiesel



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What Is Bitumen ?

Location of the main deposits

Quality (f ract ions) v. Conventional CrudesHistory of Development LandmarksProduction ProjectionsMarkets



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What is Oil Sand?

What is Bitumen ?

8


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Oil sand deposits in Alberta

Albian Bitumen1,600 billion bbl

in place

Saudi

270 175

AB-CanRecoverable

4 billionproducedto date

9

~ 2% of reserves mineable


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Comparative Boiling Ranges

2

4

6

8

1

B

i

t

u

m

en

r

a

b

H

e

a

vy

M

a

ya

Naphtha

Distillate

Gasoil

Residue

10


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Oil Sands Historical Productionall products

1960 1980 2000 2020 2040

Million barrel per day

5

4

3

2

1

actual planned

2030



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2000 2010 2020 2030

5

4

3

2

1

million

barrelsper day

Hows that Vision coming along ?

unfactoredannouncementsall Bi tum en recovery

Athabasca Mining

Peace River In Situ



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PRODUCTIONOR

RECOVERY

REFININGMARKETS

The Oil Sands Bitumen Value Chain

UPGRADETO

SYNTHETICS

DILUENT

DILBIT/SYNBIT/Variants

PARTIALFIELD

UPGRADE ?


in situ or above ground

may still need some


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2000 2010 2020 2030

5

4

3

2

1

million

barrelsper day

Upgraded vs. Dilute Bitumenunfactoredannouncements

Alberta Upgraders

but will partialupgrading bepart of this ?


will moremove to US ?(see later)


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Source: CAPP-2008 15


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Current and Future markets

Fort McMurray

existingpipelines

Canadiansupplied today

Courtesy Enbridge

PADD II

PADD III

PADD I

PADD IV

PADD V

Mexico

Edmonton

Pacific rim

new markets

16


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Bitumen is too heavy and viscous to transport in longdistance, common carrier pipelines without dilution

C5+ Gas Condensate (naphtha)Dil-bits

Dilution agent Potential Issues

- Refinery capacity for light naphtha- Back shipping costs- Periodic shortagesbut can now

import off west coast

Light synthetic crude (SCO)mixtures of SCO/CondensateSyn-bits or Syn-dil-bits

- Refinery capacity forsometimes qualitychallenged SCO

- Sell at discount

IF ISSUES A PERSISTENT PROBLEM

will some form of water-based emulsion be used long term?



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Does railing bitumen make sense?

In the last year there has been a move by CNand the Altex pipeline project (Edmonton to the USGC)to suggest a pipeline on rails as an economicalintermediate step during buildup of bitumen shipmentsto that location, towards an eventual pipeline.

Presentation to CHOA, April 30, 2009

might it also work as an interim step for the AB to

West Coast pipeline (Gateway) ?



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Bitumen Recovery

MiningThermal in situ

and each may see new developments



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Mining Based Recovery(less th an 50-100 m overburden)

Warm Water Extraction to FrothFroth TreatmentTailings ManagementTracking Water UseRecovery Costs



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slurry

crusher & cyclofeeder

tailings

sandstorage

tailings settlingbasin

water recycling

tailings oilrecovery

bitumenfroth totreatment

EXTRACTION

overburden

tree clearing

MFT & CTcontainment

MINING

Courtesy Syncrude

TAILINGS MANAGEMENT

truck & shovel

21


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slurry

crusher & cyclofeeder

tailings

sand

storage

tailings settling

basin

water recycling

tailings oilrecovery

bitumenfroth totreatment

overburden

tree clearing

MFT & CTcontainment

MINING

Courtesy Syncrude

TAILINGS MANAGEMENT

truck & shovel

EXTRACTIONEXTRACTION:

- Primary produces froth- Froth Treatment

22


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Tailings

NaphthaInclined PlateSettler

ScrollCentrifuge

SecondStageFeed Drum

Cuno Filter

DiscCentrifuge

Froth Tank

99-98% Bitumen Recovery

60% B30% W10% S

NaphthaRecoveryUnit (NRU)

to addedcentrifuging(plant 67)and DiluentRecoveryUnit (DRU)

FROTH TREATMENT(Syncrude & Suncor)

23


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Extraction and TailingsPrimary

SeparationCell Deaerator

Screen

Primary Flotation

SecondaryFlotation

ThickenerCyclones

TailingsPond

Warm

WaterTank

ConditionedSlurry PSC Froth

Bitumen toFroth

Treatment

Primary FlotationTailings

Froth

Middlings

Froth

Sec Flot

Tailings

Underflow

Overflow

Steam

Froth Feed

Tanks

RecycleWater Pond

Froth Screen

Courtesy: Shell Canada Limited

PRIMARY TREATMENT(Shell et al)

24


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Comparing Froth Treatment Methods

SimilarFroth

Syncrude/Suncor

Shell

Gravity sepn.solvent recovery

Paraffinicsolvent

Gravity sepn.solvent recovery

Naphthenic

solvent

~98% bitumen recoveryfrom froth

but 1-2 %solids/water

~90% lighter bitumenrecovery

but solids/water free

+ heavy asphaltenes(like coffee grounds)

LENEF Consulting (1994) Limited 24a


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Source: Syncrude

& others

Bitumen Lossesas % of Bitumen on Mined Sand

Primary Extraction 8-10%

Mining 2-3%Froth Treatment

2 %



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cycloned total

tailings

tailings sandstorage

tailings settlingbasin (waterMFT & inventory)

water recycling

CT storage

Courtesy Syncrude

beachedtotal tailings

beachedtotal tailings

MFT &

gypsum

water recycling

MFT to make CT

beach runoff

fromplant

26

TAILINGS MANAGEMENT


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consolidatedsand, trappedfines & trappedinterstitialwater

recycle water

make up waterex. Upgrader

sand& clay

bitumen

2.6

7.1

1.1

~ 5

1) all figures approximate & will varywith ore quality and o ther factors

2) solid volumes include interstices3) overburden / bitumen losses / mine

rejects & diluent not included

1.0

bitumen product(water /solid traces not incl.)

water in MFT30+% w solids

4.9

tailings streams

0.30.1

9.4

0.8

0.63

1.4

recyclewater frompond settling

water trapped

in pond1.7

feed ore

combinedwater

sand

storage

tail

ings

pond

4.7

Froth

Treatment

7.1

recyclewater fromsand runoff

sand storage &tailings pond

solidsin MFT

all figures in m3 Key: SolidsWater

Hydrotransport& PSV

0.5

water & bitumen trappedin sand matrix

froth

water

all figures are VOLUME based

TRACKING WATER, SOLIDS & BITUMEN IN MINING-BASED WARM WATER EXTRACTION



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Alternatives to Mining and/or

Water Based Extraction

Old- Taciuk kiln (1970s)

- Solvent extraction (Shell1960s)

New- At Face Mining (Suncor patents)

- Tar Sands Combine (TSC) (Google it! )- Kruyer Oleophilic Sieve (US Pat .4730311)



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In SituRecovery

Why?: too mu ch overburden for min ing

- Thermal Methods (with Natural Gas) & Costs- Reasons for Alternatives to SAGD- New Technologies



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Cyclic Steam Stimulation

31


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EAST

- .

Steam Chamber

Steam Injector

Steam Flow

Oil Flow

Slots

Oil Producer

SAGD Facility

Oil Sand Formation

Steam Assisted Gravity Drainage

32


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WATERTREATMENT

diluent

producedwater

Dilbitproduct

STEAMBOILERS

brine todisposal well

make up

water

sand todisposal

producedfluids

naturalgas

tanks,pumps

etc. not shown

produced gas

steam toSAGD

chemicals

Bitumen Cleanup



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Capital 3.00

drilling

Source: LENEF/various

Operating Costsestimated $ Cdn (2007)/ WTI=$90

energy port ion

appro x. $ 11

reservoirstimulation 10.00

oil separation3.50

water treatmentmiscellaneous

total $ 16.00

1.00 0.600.90

Note: ini t ial capital cost recovery NOT includ ed



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PRODUCTION

ORRECOVERY

REFININGMARKETS

The Oil Sands Bitumen Value Chain

UPGRADETO

SYNTHETICS

DILUENT

DILBIT or SYNBIT

PARTIALFIELD

UPGRADE

2 major cost elements

- Recovery Energy- Diluent for Transport

106

35recoveryenergy diluent for

transport @ $90 WTI

other recovery cost net loss on diluent5



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Below Groundreminder

EAST

: ac a - .cd

Steam Chamber

Steam Injector

Steam Flow

Oil Flow

Slots

Oil Producer

SAGD Facility

Oil Sand Formation


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Below Ground(Alternative Recovery Options)

Solvent Assisted

- solvent co-injected with reduced steam- solvent alone (no steam addition) - VAPEX- solvent assists the mobilization of the bitumen- solvent potentially enhances heat transfer to bitumen

- all still at pilot stage- recovery of solvent and obvious economic issue- no breakthroughs reported



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Below Ground(partial Combustion/Gasification)

airproduced

fluids

Old - advancing firefront mobilizes bitumen

- premature air breakthrough an issue

~ 500 m

X

New

producedfluidsair

- lower path length to producer- initial pilot results promising

Hz well


THAITM PROCESSTHAITM PROCESS


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THAITM PROCESSTHAITM PROCESSmobilized oil and hot

gases co-produced

Coke is deposited on the sand

and is fuel for the processHorizontal well is low

pressure region

Air injected in

near vertical

combustionfront

Hot gases heat oil

in front of

combustion zone

FRONTAL ADVANCE

OF MOBILE OIL

COLD HEAVY OIL

HEELTOE

Courtes Petrobank 39


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Capital 3.00

drilling

Source: LENEF/various

Operating Costsestimated $ Cdn (2007)/ WTI=$90

energy port ion

approx. $ 11

reservoirstimulation 10.00

oil separation3.50

water treatmentmiscellaneous

total $ 16.00

1.00 0.600.90

THAI wouldeliminate ~ 80-90% ofthe direct energy cost



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Reduced Bitumen Residuesfor recovery energy

Atmospheric/Vacuumdistillation and/or

Solvent DeasphaltingBitumen

lighterproduct

less diluent

Residue

direct combustioncould be gasification?

emulsion combustion

Issues:- cost vs. benefits- flue gas desulphurization- increased CO2 emissions



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Bitumen & Heavy Oil Upgrading

Why Upgrade?

too much bitumen

not enough refinery conversion capacity

Field Upgrading: moving bitumen to markets

Full Synthetic Products



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Field Upgrading: moving to markets

Objectives: - lower viscosity less/no diluent for long distance transport- residue reduction/destruction (partial upgrade)- energy by product for SAGD recovery- economic at smaller scale (15 to 30,000 b/day)

Other Features:

- Go beyond simple physical processes distillation & deasphalting- Include thermally bases residue reduction

Two recent offerings targetting this market

Ivanhoe HTP

ETX Systems



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Ivanhoe Energy Heavy-To-Light (HTL) Process

45


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As we are beginning to see

UPGRADING IS A CONTINUUM

the objective is to get bitumen to markets andeventually to finished transportation fuels

it can occur underground (solvent assisted SAGD, THAI) it can occur above ground at the production site more extensive upgrading at central upgraders

it can be achieved in specially equipped refineries


The Target for Full Upgrading


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% volume

100

80

60

40

20

0

Conventional 32-35o API

Light / Heavy Sweet SCOcrude blend

11. 9

24

50

15

35

11. 3

poor quality

distillates limit

many refiners

to 10% or less

of crude diet

high volumeof low quality

feedstock for

cat cracking

refineries

some questions

on hydrocarbon

mixJet Fuel

smoke point> 21

DieselCetane

> 45

Gas Oil to

conversionunits

UOPk> 11.75

residue

some idealproperties naphtha

Typicalbitumen

g pg gremind er of how far we have to go

low volumelow quality30-35

~ 11.3 high volumelow quality

high volumehigh metalshigh coke

precursors

residue



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Full Upgrading

Original Coker Based UpgradersEbullated Bed upgrading

Natural Gas use and impactNew Approaches to UpgradingChanging View of SCO TargetsHydrogen ManagementUpgrader By-Products



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gas treatment

syntheticcrude oil

coker

hydrogen

hydroprocessingunits

ebullated bedhydroprocess

bitumen

natural gas

coke

residue

original

PRIMARY UPGRADE SECONDARY UPGRADE

bitumen

users: Syncrude, Suncor, CNRL LENEF Consulting (1994) Limited 50


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250-300 kPafractionator

Gas oilstripper

Unstabilized

Naphtha

Light gases

& LPGs

steam

FR Coker

Gas oil

steam

coke coke

950oF

feed

Delayed Coking(several l icensors)



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reactor productsto fractionator

scrubber

reactor burner

steam

coke

flue gas to CO boilerand cleanup

feed

steam

air

Exxon-Mobil Fluid Coking LENEF Consulting (1994) Limited 52


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Hydrotreater

Courtesy UOP - Unionfining

53

Hydrogen production a natural gas addict !


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CO2

CO

SMR

PressureSwing

Absorberunit

steam

naturalgas

steamgeneration

tracesulphurremoval

fuel gas

HTShift

hydrogen

Hydrogen production a natural gas addict !

SteamMethaneReforming(SMR)


Typical Offering from Coker-HT Upgraders!


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% volume

100

80

60

40

20

0

Conventional 32-35o APILight / Heavy Sweet SCOcrude blend

11. 9

24

50

15

35

11. 3

poor quality

distillates limit

many refiners

to 10% or less

of crude diet

high volumeof low quality

feedstock for

cat cracking

refineries

some questions

on hydrocarbon

mixJet Fuel

smoke point> 21

DieselCetane

> 45

Gas Oil toconversionunitsUOPk> 11.75

residue

some idealproperties naphtha

Typical Offering from Coker-HT Upgraders!(w i thou t fur ther processing)



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gas treatment

syntheticcrude oil

coker

hydrogen

hydroprocessingunits

ebullated bedhydroprocess

bitumen

natural gas

coke

residue

Second generation

PRIMARY UPGRADE SECONDARY UPGRADE

bitumen

users: (Syncrude), Shell, Husky LENEF Consulting (1994) Limited 56

Ebullated Bed Process


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Main commercial offerings: Axens H-Oil (Husky Lloyd Upgrader)Chevron-Texaco LC Fining(Syncrude, Shell, Husky,North West Upgrading)

Ebullated Bed Processgives somewhat better quality SCO than Coking/HT

Courtesy: Axens

Conversion limited by feedstock qualitybut working on it !



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Slurry Hydroconversiona new breed of hydroconversion

Similar to Ebullated bed, but replaces solid catalyst with fineparticles/emulsified liquid carried by process streams

Achieves higher conversion with stable residue

Licensor Offerings

H-CAT (Headwaters Inc.) UOP SRC-Uniflex (sub-licensing NRCan Canmet Technology) ESP (Enichem, Italy)

HRH (Mobis Energy Inc.) Micro-Cat RC (Exxon-Mobil) CASH (Chevron)

None yet commercialized as full units !



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reduction/freedom from Natural Gas use

eliminate the coke by-product higher synthetic crude quality

Drivers for Change in Central Upgraders


where does the oil sands industry use Natural


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In Situ 1250

varies!

upgrader fuel

(no coke burning)

Source: OSTRM / various

Mining 300addedqual i ty

syntheticqualitytoday

Stan dar d cub ic feet NG / b arr el

Bitumen Reco very & Upgradingall figures are estimates, and will vary

80

250

400

RecoveryUpgrading

Hydrogen

production

where does the oil sands industry use NaturalGas in Production & Upgrading ?


N t l G U S l ( )


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0

1

2

34

5

6

7

8

2000 2005 2010 2015 2020 2025 2030

WCSB

Source: NEB / OSTRM

CBM

MacKenzie

Trillion cubic feet per year

Natural Gas Use .v. Supply (west)

Oil Sands demandbusiness as usual


Improving Synthetic Quality


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Improving Synthetic Quality

C5 - naphthene content

Aromatics .v. CRU hydrogen make

Kero Smoke Point & Aromatics = WTI or betterCetane = WTI or betterS & N handled by conventional HTs or better

gas oils with UOP/Watsonk = 11.8 or better

Asphalt qualityseasonal

DAO for FCCU feed


Energy & Hydrogen Self- Sufficiency Options


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Metals &Asphaltenes

% volume oforiginal bitumen0 20 40 60 80 100

noncoking thermalor deasphalting

combinations

residue hydroconversion(or maybe coking)

likely best option

SAGD+ Upgrading

Upgrading

residue needed for energyand hydrogen is in this range

physical separation alone

coking

ebullated bed hydroconversion

slurry hydroconversion

more severe processesto provide zerometals/asphaltenesin tops products


Hydrogen Production Economics


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Basis: 200 million scf/day - stand-alone facility

cost /000 scf

$ US

SMR

NG$8/mmbtu

SDA ResidueGasification

$15-20/ barrelSMR equivalent

CokeGasification

$ 5-8 / tonneSMR equivalent

4

3

2

1 feedstock

capex

otheropex

directional trend

not including up grader capex / opex benef i ts



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Serendipity supply concerns for natural gas willhelp us in the long run

replace natural gas with heaviest residues

need for less severe primary conversion

now need higher secondary conversion(e.g. hydrocracking)

higher quality now easier to accomplish !


energy self-sufficiency is already changing


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gy y y g gthe face of fu l lupgrading

COKINGOR

H +RESIDUECONVERSION

HYDROTREAT

HYDROGENPLANT

Synthetic

CrudeOK quality

Natural Gas

Bitumen

coke

ORIGINAL

NEWERNG-FREEAPPROACHES

HYDROCONVERSIONSDA &/OR

MILD THERMALBitumen

GASIFIER

HYDROCRACK

Synthetic

CrudeHigher Quality

Hydrogen

Hydrogen



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Atmosphericdistillation

fuelgas

Vac

column

product

or blend

streams

PrimaryUpgading

Hydrotreater

Frac

Vac

AGO

VGO

only main oil flows shown

Hydrocracker

to gasifier

VGO

bleed

hot

HPS

VGOs

& lighter

to gasifier

growing trend


Bitumen

an example of milder thermal conversion (non-coking)


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Visbreaking

Unstabilized

FR Naphtha

Light gases& LPGs

steamVisbreakerTar to fuel ,

Gasifer, or

DA Unit

steam

steam

Visbreaker

LGO

Visbreaker

VGO

Soaker

drum

steam

AtmosphericDistillation

VacuumFlasher

feed


D h lti


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Deasphalting

Pitch

stripper

DAO

stripper

Extractor

DAO

Pitch

DAO

separator

Not all stripper &

Separator details shown

solvent

circulation

Feed

make upsolvent

0 20 40 60 80 100

% deasphalted oil yield

%o

fcontaminant

100

80

60

40

20

0

sulphu

r

Nicke

l

CCR

Vana

dium

Solvent selection controls yield &quality of DAO



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1 /

Courtesy: GE 70

Does integrated gasification/H2 make economic sense?


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2 cases: Coking + SMR to SCOThermal/DAU + Gasification to SCO (plus added hydrogen)

Coking/SMR Thermal/DAU +Hydrogencash flow$ million/yr

5,000

4,000

3,000

2,000

1,000

0

150 kb/day, $ 90 WTI / 25 year project /2% inflation/30% tax rate/10% DCF

revenues

Capex@ 12% IRR

opcosts

margin380

CapexIRRNPV10

$ 7,800 mil.16%

$ 4,200 mil

555 margin

$ 7,000 mil.15%

$ 3,100 mil


How are projects responding ?


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Operators PrimaryConversion

SecondaryProcessing

Hydrogen

ExistingSuncor Delayed Coking Hydrotreating SMRSyncrude Fluid Coking/Ebullated Bed H+ Hydrotreating SMR

Husky, Lloydminster E-B H+/ Delayed Coking Hydrotreating SMR

AOSP (Shell) E-B H+ Hydrotreating SMR + 3rd party

New Projects (engineered, but not yet operating)

Thermal Cracking/De-asph. HYDROCRACKING Resid gasification

CNRL (S/U now) Delayed Coking Hydrotreating SMR

New Projects Planned (excl. expansions of existing plants)

BA Energy De-asphalting/Pyrolysis none none

North West E-B H+ HYDROCRACKING Resid gasification

Petro-Can/UTS Delayed Coking Hydrotreating SMR

all full upgrader projects have signalled intent to consider gasification in later expansions

Total / Fort Hil ls/NWU & BA all delayed pendin g better times/next stage of fun ding

**

Total

Statoil

detai ls no t yet declared

detai ls no t yet declared*

OPTI/Nexen


*

**

Hydrogen management


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Hydrogen in bitumen feed

ammonia

80%

20%

54%

total hydrogenin system

distributionof addedhydrogento products

C5+ product

butaneto SCO

hydrogensulphide

netbutane

fuel gases propane

1017

102

7

addedhydrogen


the convention-breaking upgrader !


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g pg

Courtesy: BA Energy 74


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1. The Pet Coke Market Today and to 2015


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metric-t/day

Present 2015Fort McMurray

Suncor (some used for energy)Syncrude **(some converted to energy)CNRL

Alberta Industrial HeartlandPetroCanada (refinery)

BA Energy (solid asphaltenes)Statoil (previously NAOSC)PetroCanada/Fort Hills

Other expansions (coke/asphaltenes)

SaskatchewanHusky LloydminsterNewgrade/Coop Refinery

2012

8,2008,200

_______

16,400

400

_____400

800400

16,00016,0008,500

40,500

800 ?

?

800

800400

16,00016,000

8,50040,500

800 ?

4,200 ?3,200 ?8,200 ?

?

16,400

800400

putting in perspective 40,000 tpd would produce 4,500 MW of power

about 35-40% of current Alberta production


2. Sulphur Business


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p

World Production:Canadian Production:

Est. by 2030:Canada Seaborne exports:

75 million tonnes per year~ 8 to 9 million tonnes per year~13 to 20 million tonnes per year (added Oil sands)~ 6 to 7 million tonnes per year (#1!)

Big Challenge .fluctuating priceshistorically $30 to $60 /t FOB Van.(currently above $ 600..but how long?)

- World supply/demand now back to short supply (thank you, India & China!)- but Oil Sands will probably put it back into surplus within 5-10 years

is injection of Acid Gas into deep formations a solution ?much smaller volumes than the CO2problem !



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Oil Sands Industry Economics

Heavy-Light Oil Differentials

Production & Upgrading- Cash Flows and Investment Returns

Impact of New Royalty ProposalsGovernment & Industry: Who gets what ?


Current and Future markets


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Fort McMurray

existingpipelines

Canadiansupplied today

Courtesy Enbridge

PADD II

PADD III

PADD I

PADD IV

PADD V

Mexico

Edmonton

Pacific rim

new markets


WTI (Cushing, OK) vs. Lloyd Bitumen Blend (Hardisty, AB)


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2000 2001 2002 2003 2004 2005 2006 2007 2008

100

80

60

40

% WTI

Source: Sproule


today

Bitumen has Two Kinds of Marketed Products


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Bitumen has Two Kinds of Marketed Productseach with variants

Diluted Bitumen Blends (~19-22 oAPI)- Dilbit 20-30% Condensate (seasonal adjust)- SynBit ~ 50% Synthetic Crude

- SynDilBit ~25/15/60(e.g. Western Canada Select)

lighter blending components needed for pipeline transport

Light Sweet Synthetic Crude

- Original Coker Based ~ 33-35 oAPI- Newer targets ~ 38-40 oAPI



86/119


This section introduces the term Capital Charge in some slides.

This is the income per barrel required to pay out investment with

a 12 % Internal Rate of Return.

So, Capital charge is a useful way to relate capital costs ona per barrel basis for considering/comparing margins from arecovery or upgrading project.

All IRR calculations are based on 2 year construction period forrecovery projects and 4 years for upgrading, and a 25 yearoperating life for all projects. Other economic factors are:2% inflation, 10% discount rate, 30% tax rate, and 20% decliningbalance Capital cost allowance.

Project capital (Capex) in Alberta at this time is declining fromrelatively recent unsustainable levels. But this does vary a lotdepending on reserve quality or on upgrader scale.

1.

2.

Tracking Bitumen Value and Margins to Production Site


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WTI = $ 90, Dilbit Blend* = 67.5% WTI @ Hardisty

* Blend = 72% Bitumen / 28% Naphtha

All figures based on bi tum en barrel$ (US or Cdn )

Value of blend * 84.40Less:Shipping to Hardisty ( 1.50)

Cost of Diluent ( 36.65)

Value of Bitumen at Production site 46.35 (51.5% of WTI)

Cost of Production (@ 30,000 b/day) (excl. capex)

Recovery Energy ( 10.00)Other opcosts (not incl. sustaining capex) ( 6.00)

Pre-Royalty Margin at Production Site 30.35

Greenfield site


Royalty Changes 2009


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Pre Payout *

* typically 4-6 years / based on % of gross margin

** on typical 30 kb/day SAGD, based on % of net margin

Post Payout **

60 90 120 60 90 120light crude, $ /barrel light crude, $ /barrel

6

5

4

3

2

1

0

20

10

0

$/barrel

current

Example @ $ 90 Light Crude/WTIPrevious Royalty New Royalty

pre-payout post-payout pre-payout post-payoutPre-Royalty Margin 30.35 30.35 30.35 30.35Royalty ( 0.45) ( 7.10) ( 2.40) ( 9.45)Post Royalty Margins 29.90 23.25 27.95 20.90

$/barrel


Tracking Costs and Netbacks for SCO Production


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WTI=$90, Nat. Gas = 50% of light crude energy equivalent ($7.50/GJ)

Upgrading to Light Sweet SCO *

all $/barrel of bitumen feed

Value of Products (95% vol. yield/105% WTI) 89.75

Less shipping to markets ( 1.00)Cost of feedstock (SAGD market value) (46.45)Operating costs ( 9.00)

Operating Margin 33.30

* new type of upgrader with integrated gasification / Greenfield

The impact of Capital cost escalation:

Capital charge @ $12% IRR (2004/05) 12.00Margin over 12% IRR 21.30

Capital charge @ $12% IRR (mid 2007) 24.00Margin over 12% IRR 9.70

the capexissue in anutshell


*

IRR % *

Unleveraged Economic Returns


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40

30

20

10

0

IRR,% *

60 80 100 120

Light Crude, $ US/barrel

Based on Alberta Capital Costs (2007)Greenfield Developments

* unleveraged

** SAGD @ 30,000 b/day ; Upgrading @ 150,000 b/day

12% IRR


The Great Debatewho gets what ?


91/119

New After-Royalty Margins

SAGD

After-Royalty & Various Taxesfrom the Commercial Development

SAGD+ UG

$ / barrel bitumenWTI= $90/35 year life/estimated royalties/taxes averaged/no inflation

capex recovery charge @ 8% included

Alberta Gov.only Alberta/Federal GovIndustry

10.40 8.00

15.70

24.60

8.0027.50

15.006.00

includesroyalty



92/119

Where to Upgrade

Recent Plans for AlbertaWhats Happening to Change the Picture ?

Canada v. U.S. Refineries


2004-06 Announced Upgrader Plans for Albertain period 2015-2020


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p

millionbarrels

/day

3.5

3.0

2.5

2.0

1.5

1.0

0.5

0

2015-2020Projections

Current or close to startup

Other projects proposed

Suncor

Syncrude

Husky

Shell et al

Nexen-OPTI

CNRLB A Energy

Statoil (NAOSC)

NWU

Total / Synenco

Petro-Canada et al

status not very encouraging !

Will likely proceed but delayed

Likely at some stageLikely at some stage

First phase delayed pending partner

First phase delayed indefinitelyExpansions will likely proceed

First phase now operating

Some future exp. may move East/SouthMarathon may move their share to U.S.

Expansion likely to move to U.S. refinery

Expansions will proceed

Expansions will proceed but delayed


Looking at it another way.

other pre-crash plans


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Current Bitumen Prod. Upgrading

2015-2020 projections

5

4

3

2

1

0

millions of barrel per day

CAPPProjections

announcedintentionsby U.S. refinersrisked

additionalpotential

upgraded inAlberta

Bitumenlargely shipped

to US

but always remember2nd and 3rd phasesare less costly


some may

never get built

p p

fairly solid for Alberta

?


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Environmental Challenges

the elephant in the room

Greenhouse Gas IntensityWater Use & ManagementFootprint & Land Reclamation



96/119

The Changing Challenges

2006 to PRE -2008 CRASH

- capital costs in Alberta- impact of the new Royalties in 2009- environmental challenges getting air time

POST CRASH

- oil prices less certain- new President / carbon management

- dirty oil label begins to stick- land reclamation & water use priority issues

LENEF Consulting (1994) Limited

the environmentfrom air time to prime time !

Oil Sands compared to other crude sources

Greenhouse Gases


97/119

2000

2500

3000

3500

4000

kg CO2E per cubic meter crude

Canadian Mexico SCO Bitumen Venezuelan

Light Heavy Blend Upgraded

production

transport

refining

by-product

combustion

end use

Source: T.J.McCann & Associates

0

Oil Sands compared to other crude sources


Exploring the CO2 issue more closelyover next few overheads


98/119

In Situ 1250

varies!

upgrader fuel

(no coke burning)

Source: OSTRM / various

Mining 300addedqual i ty

synthet icqualitytoday

Standard cub ic feet NG / barrel

Bi tumen Recovery & Upgradingall figures are estimates, and will vary

80

250

400

RecoveryUpgrading

Hydrogenproduction

Upgrader fuel equivalent adjusted to 300 scf/barrelto account for internally generated energy used in upgraders,and which converts to more CO2

now lets take alook at the CO2impact alternativeenergy sources

a reminder on main energy inputs based on

equivalent natural gas


Alternative Fuel: Comparisons of CO2 EmissionsNatural Gas vs. Bitumen-Based Alternatives for Energy & Hydrogen


99/119

Basis: 1000 scf NG / Residue & Pet Coke comparisons to match Energy and Hydrogen

Energy (0.95 GJ HHV) Hydrogen (2,400 scf)

100

50

0

kg CO2

100

50

0

data sources: Jacobs/SFA Pacific/NETL / LF

53

79

9820

33

80

5

104

5

NG Bitumen Pet Coke

Residue

NG Bitumen Pet Coke

Residue

Note:- Expected increase in CO2

Note:- Expected increase in total CO2- Res./Pet coke have lower dilute CO2

CO2 dilute

CO2 capture ready


kg CO2

Some Updated Comparisons of CarbonDioxide Emissions


100/119

kg CO2/ cubic meter transportation fuel

6,000

5,000

4,000

3,000

2,000

kg CO2per m3

35 APIcrudeblend

22 APIcrude

Coker based ref inery

Bitumen RecoveryUpgrading and Refining

l ow high

Trans.Fuelend use

Production

RefiningBy-Products

Dilute CO2

Captureready CO2

Sources: T.J.McCann & Associates, LENEF Consulting, NETL, SAE/Argonne Lab

Dioxide Emissions

CO2 only. other CO2E not included



?

?

Comparison of Carbon Dioxide Emissions


101/119

but what if we change the basis toequal energy outputs?

5,000

4,000

3,000

2,000

kg CO2per m3

35 APIcrudeblend


Bitumen RecoveryUpgrading and Refining

worst case

Trans.FuelEnd use

Production

RefiningBy-Products

Dilute CO2

Captureready CO2

Sources: T.J.McCann & Associates, LENEF Consulting, NETL, SAE/Argonne Lab

p



by-productcredits

by-productcredits

Capture-readyimpact

Recent Numbers From AERI Study US ConsultantsRelative, WTW % in US Refineries


102/119

150

100

50

0

% relative toO/S Mining

new technologypotential

LENEF Consulting (1994) Limited 96A


103/119

now lets switch to a review ofthe potential for Carbon Capture and Storage

Carbon Dioxide Canada: 700 mega-t/yearAlb t 220 t/


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Alberta: 220 mega-t/year

- Oil Sands (Alberta) 55 mega-t/year.

Projected Production ~ 2020

Fort McMurray Area(lower quality SCO will improve/SMR Hydrogen)

Edmonton- Alberta Ind. Heartland(av.quality higher-more gasification / more H2)

Other Locations (Long Lake, Lloyd)(av.quality higher-more gasification / more H2)

current ~2020

000,000 barrels/day

4

3

2

1

0


Estimated CO2 from Oil Sands in Alberta

b i t & h d f t l


105/119

150

125

100

75

50

25

0Current ~ 2020

Mega-tonne

/yrCO2


total

est. capture-ready

basis: net energy & hydrogen from natural gasadd approximately 50-60% for complete NG substitution by residues

Carbon Dioxide Use / Capture Potential


106/119

- producers and potential EOR users are making plans- but EOR may not be a large sink- CBM industry has yet to develop opportunity

Coal BedMethane

capacity, Mega-tonnes CO2

Source: CERI / T.J.McCann & Associates

gas & oilpools

9,000

15,00010,000

aquifers

2,000 EOR

storage @ 100 M-t/year = 360 years

for Alberta Provincial Government, carbon captureis the favoured solutionthe train has left the station !

potential

value-addedopportunities



107/119

top 240 oil pools

low value sequestration capacity, Mega-tonne CO2

Source: CERI-2003

top 350 gas pools6,440

2,580

0 50 100 M-t/year

$

/tonne

150

100

50

cost to sequester

10,000

saline aquifers

Dated, but recent $ figures are about the same


What about Carbon Taxes?

M i F d l d P i i l


108/119

- Many suggestionsFederal and Provincial- Few details on the rules- Lets look at Alberta & Federal proposals

- Based on emission intensi ty/ Cap & Trade

Take the average Recovery/Upgrader Combination

Current (and assumed Baseline) emissions: 120 kg CO2 per barrel

120 kg/b

6 years

106 kg/b

Assume total failure to deliverNeed to purchase credits @ $20/tonne

Canada cont in ues to move slowly;l i t t le Federal/Provin cial consensu s as yet

ALBERTA: 2% redn. per year from baseOver 6 years

Cost in year one : $ 2 cents/barrelCost in year six+: $ 12 cents/barrel

FEDERAL: 6% redn. per year from baseover 3 years; 2% per year thereafter

Cost in year one: $ 6 cents/barrelCost in year six: $ 59 cents/barrel

98 kg/b91 kg/b


it di l di it di l di bit


109/119

unit di volume di acqua per unit di volume di bitume

SAGD Mining Upgrading

10

5

4

3

2

1

0

Fabbisogno totale

Fabbisogno ricircolato

Fabbisogno netto

Water Use DataRecent Numbers From Study for U.S. DOE


110/119

Production through Refining (1.5 of total)

8

6

4

2

0

Net Water Use

per unit volumeof Crude

LENEF Consulting (1994) Limited 103A

Water Use & Management.continued


111/119

Investment Costs for Pre-Competitive Extraction R&D

0

2

4

6

8

10

12

14

Extr Support Total

Universities

Govt.Labs

Totals

Extraction Support TotalTechnology Technology

$ million / year

. industry internal R&D not included !NRCan report - 2005

104

Land Management . The Challenge


112/119

Satellite Photo Of Mining Plants (2003)

SuncorSyncrude

Albian Sands

Athabasca

River

settling basin

5 km

Courtesy Syncrude & Alberta Chamber of Resources

105

Land Management . continued

Investment Costs for Pre-Competitive


113/119

pTailings and Land Reclamation R&D

0

2

4

6

8

10

12

14

16

Tailings LR Total

UniversitiesGovt.Labs

Industry Totals

Totals

Tailings Land TotalReclamation

$ million / year

NRCan report - 2005. industry internal R&D not included !

106


114/119

The largest threat to freedom, democracy, the

market economy and prosperity, is no longer socialism.It is instead the arrogant, unscrupulous ideologyof environmentalism

Vaclav Klaus,

President of Czechoslovakia

You be the judge!


Summary of Key Points

Th il d i d t i hi h t f l


115/119

The oil sands industry remains a high cost source of supply

Secure supply for N.A. is an important consideration, but will

current NA environmental negativity also hastenmarket diversification ?

Capital cost concerns recognized eating up crude price increases

Upgrading in established U.S. refineries will at this timebe more cost-effective, especially for new entrants


12% IRR projects in 2007- 08 required around $45-50 for bitumen

production and $ 80 for full upgrading (Greenfield) in Alberta

The recent economic crash accelerated an already evident

decline / delay in appetite for Alberta investments

The drive to freedom from Natural Gas use will impactboth production and upgrading economics positively

Summary of Key Points (2)


116/119

Water and mining-based land reclamation are the next (and present !)environmental frontiers to challenge the industry in Alberta

Economics and regulations, as well as infrastructure limitationsmay clip the Golden Gooses wings but not kill it!


GHG emissions will be taxed, but at this stage it is likelyto be at a cents/b rate; below Carbon Capture & Storage costs

Carbon Capture & Storage (CCS) will accelerate, and the costswill in the long run be borne by the consumer

Environmental issues and solutions will command more public

attention and scrutinybut the worlds current addiction to

hydrocarbon fuels, and the heavier barrel generally will modifythe impact real ism conf ronts ideal ism !


117/119

Lunch & Questions ?

Added reading


118/119

Oil Sands

Technology RoadmapAlberta Chamber of Resources2004 (www.acr-alberta.com)

Added reading


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penwell july14-09 oil sands workshop-final-adobe copy

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