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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
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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 ?
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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 ?
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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)
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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
LENEF Consulting (1994) Limited 38
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
LENEF Consulting (1994) Limited 47
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)
LENEF Consulting (1994) Limited 54
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
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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 ?
LENEF Consulting (1994) Limited 60
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
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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
LENEF Consulting (1994) Limited 62
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
LENEF Consulting (1994) Limited 63
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
LENEF Consulting (1994) Limited 64
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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 !
LENEF Consulting (1994) Limited 65
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
LENEF Consulting (1994) Limited 66
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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
LENEF Consulting (1994) Limited 67
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
LENEF Consulting (1994) Limited 68
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
LENEF Consulting (1994) Limited 69
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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
LENEF Consulting (1994) Limited 71
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
LENEF Consulting (1994) Limited 72
*
**
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
LENEF Consulting (1994) Limited 73
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
LENEF Consulting (1994) Limited 76
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 !
LENEF Consulting (1994) Limited 77
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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 ?
LENEF Consulting (1994) Limited 78
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
LENEF Consulting (1994) Limited 79
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
LENEF Consulting (1994) Limited 80
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
LENEF Consulting (1994) Limited 81
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LENEF Consulting (1994) Limited 82
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
LENEF Consulting (1994) Limited 83
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
LENEF Consulting (1994) Limited 84
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
LENEF Consulting (1994) Limited 85
*
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
LENEF Consulting (1994) Limited 86
The Great Debatewho gets what ?
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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
LENEF Consulting (1994) Limited 87
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Where to Upgrade
Recent Plans for AlbertaWhats Happening to Change the Picture ?
Canada v. U.S. Refineries
LENEF Consulting (1994) Limited 88
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
LENEF Consulting (1994) Limited 89
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
LENEF Consulting (1994) Limited 90
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
LENEF Consulting (1994) Limited 91
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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
LENEF Consulting (1994) Limited
the environmentfrom air time to prime time !
Oil Sands compared to other crude sources
Greenhouse Gases
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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
LENEF Consulting (1994) Limited 92
Exploring the CO2 issue more closelyover next few overheads
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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
LENEF Consulting (1994) Limited 93
Alternative Fuel: Comparisons of CO2 EmissionsNatural Gas vs. Bitumen-Based Alternatives for Energy & Hydrogen
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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
LENEF Consulting (1994) Limited 94
kg CO2
Some Updated Comparisons of CarbonDioxide Emissions
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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
Coker based ref inery
LENEF Consulting (1994) Limited 95
?
?
Comparison of Carbon Dioxide Emissions
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but what if we change the basis toequal energy outputs?
5,000
4,000
3,000
2,000
kg CO2per m3
35 APIcrudeblend
Coker based ref inery
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
Coker based ref inery
LENEF Consulting (1994) Limited 96
by-productcredits
by-productcredits
Capture-readyimpact
Recent Numbers From AERI Study US ConsultantsRelative, WTW % in US Refineries
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150
100
50
0
% relative toO/S Mining
new technologypotential
LENEF Consulting (1994) Limited 96A
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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
LENEF Consulting (1994) Limited 97
Estimated CO2 from Oil Sands in Alberta
b i t & h d f t l
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150
125
100
75
50
25
0Current ~ 2020
Mega-tonne
/yrCO2
LENEF Consulting (1994) Limited 98
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
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- 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
LENEF Consulting (1994) Limited 99
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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
LENEF Consulting (1994) Limited 100
What about Carbon Taxes?
M i F d l d P i i l
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- 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
LENEF Consulting (1994) Limited 102
it di l di it di l di bit
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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
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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
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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
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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
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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
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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!
LENEF Consulting (1994) Limited 106
Summary of Key Points
Th il d i d t i hi h t f l
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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
LENEF Consulting (1994) Limited 107
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)
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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!
LENEF Consulting (1994) Limited 108
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 !
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Lunch & Questions ?
Added reading
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Oil Sands
Technology RoadmapAlberta Chamber of Resources2004 (www.acr-alberta.com)
Added reading
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