Strategies for Cheaper Bitumen

Peters & Co. - Lake Louise

January 25, 2008

January 2008

2Strategies for Cheaper Bitumen

1.Cheap Steam

2.Less Steam

3.No Steam

January 2008

3The Asphaltene Opportunity

1.060.200.14-Burn

Asphaltene

1.340.34-1.25Gas Fired

Blend/SCO(bbl)

C5+

(bbl)Asphaltene

(bbl)Gas(GJ)

Consumption/Production perProduced Bbl.

•remove & burn the

bottom ends (+/- 15%)

•no gas purchased

•significant reduction

in diluent required to

meet P/L spec.

•reduction in sales

volume

January 2008

4Asphaltene Challenges

• 8% Sulphur

• 1% Ash (Vanadium, Nickel)

• Volume loss (bottoms are not

completely worthless)

January 2008

5Wet Combustion

TreaterSkim

Tank

DeAsph

0.14 bbl Asphaltene

Reactor

O2 Plant

1 bbl

Bitumen

Production

Water

0.86 bbl

DAO

Steam

+ CO2

+ SO2

Sludge

CO2 (+SO2)

Sequester

Blending0.21 bbl

C5+

1.07 bbl

CLB

Deoil Soften

2.5 bbl

Steam

January 2008

6Strategies for Cheaper Bitumen

1.Cheap Steam

2.Less Steam

3.No Steam

January 2008

7Turning Down the Heat

• under steady or cyclic operation,

the rate of oil recovery is a function

of the (time averaged) reservoir

temperature

• in conventional SAGD, supply cost

components of steam vs. wells is

typically 3:1 or more

• lower temperature → lower SOR

but less productive wells (same

recovery, just slower)

• “save a lot on steam by spending a

little more on wells”

optimumrange

typical range

Recovery Costs vs. Drainage Temp

$0

$5

$10

$15

$20

$25

100 150 200 250

Temperature, C

$/b

blr

ela

tive

unit

cost

0

1000

2000

3000

4000

5000

Ste

am

Pre

ssure

,kP

a(a

bs)

Wells

Steam

Wells + Steam

Steam Pressure

January 2008

8Cyclic, Horizontal Steam Stimulation

Primrose 2A18 HCSS

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

0 1 2 3 4 5 6 7 8 9

Years After First Steam

CS

OR

0

25

50

75

100

125

150

175

Matc

hin

gS

team

Pre

ssu

re,

kP

aa

Field CSOR

Model CSOR @ 200 kPaa/119C

Temperature to match vs. time

January 2008

9The Gravity Conspiracy Theory

• CSS– Unocal history provides

grounding for reservoir values(match & extrapolation)

• SAGD– Horizontals recover ~2.5x

more oil from same heatedarea

– Lower pressure more gentleprocess

– Controlled distribution

– Better SOR

Vertical CSS (i.e. radial, cyclic SAGD):● 1/3 sweep @ 10 years (typ.)● 1/3 * (.85-.15) = 23% recovery

(Horizontal) SAGD:● 85% sweep @ 10 years (typ.)● .85 * (.85-.15) = 60% recovery

January 2008

10Grand Rapids – CSS @3000 kPa IP

Generic Grand Rapids Model, CSOR v % Recovery Case Comparison(250 - 1500 Cases, 3000 kPaa injection over initial 6 months)

0.0

1.0

2.0

3.0

4.0

5.0

6.0

0 10 20 30 40 50 60 70 80

% Recovery

Cu

mu

lati

ve

Ste

am

/Oil

Rati

o(m

3/m

3)

250 kPaa Inj

500

750

1000

1500

2000

2500

3000

3500

4000

2000 UI

2500 UI

3000 UI

3500 UI

4000 UI

3 Cycle CSS

January 2008

11Strategies for Cheaper Bitumen

1.Cheap Steam

2.Less Steam

3.No Steam

January 2008

12Bitumen in Carbonates

Alberta Energy and Utilities Board, 1990

6-12m

12-18m

18-24m

24-30m

Fif

thM

eri

dia

n

T90

T80

T70

T100

Net BitumenPay

Saleski

January 2008

13McMurray vs. Grosmont

10585ROIP, mmbbl/sec

6.55.3ROIP*, m

‘extreme’5kh , D

>5-1005kv, D

5025h, m

.2x(.9-.25) = .13.3x(.85-.15) = .21•So

GrosmontMcMurray

*Recoverable OIP, assuming 100%volumetric sweep

January 2008

14Extreme Permeability

• Evidence– drilling fluid losses

– Buffalo Creek steam injectivity

– bitumen drains from core

– Buffalo Creek history match (BH Temp.)

• Origins– Permeability of rock goes as (pore size)2

– e.g. (1cm / 25 m)2 = 160,000 : 1

– e.g. 5% , 1 cm tubes → 156,000 D

January 2008

15Enhanced porosity and permeability

(TIPM Labs – Apostolos Kantzas)

CT Scan Core X-Sections

January 2008

16High bitumen saturations

Bitumen Covered Core Barrel (Saleski 10-27-85-19W4)Encountered 3m cavern; recovered only bitumen no rock

Typical Saleski Core Sample

• Bitumen saturations exceeding 85%at Saleski

January 2008

17

D Mega Ф Zones

C Mega Ф Zone

10-35 10-26 7-26 10-23 10-14-85-19W4

Regional Constituency

January 2008

18Solvent Recovery from Carbonates

• versus thermal:

– porosity is not critical: rock doesn’t absorb solvent

– thickness is not critical: solvent is not lost to confining

strata

• high permeability key to minimizing solvent

requirement

• fractures & vugs provide ‘fractal’ access to reservoir

volume (convection beats diffusion)

• heat+solvent spectrum – use genetics to explore

and optimize

January 2008

19Saleski Cold Solvent soak experiment

• performed by U of C-TIPM atinitial reservoir temperatureand pressure

• zero pressure gradient(recovery by gravity drainage& oil phase swelling)

• recovery was > 50% in < 2weeks

• Laricina is currently preparinga single-well cold solvent fieldtest

January 2008

20100˚C: The Thermal Divide

• Thermal facilities, field piping, and well tubularsare all subject to significant thermal expansion atsteam temperatures

• e.g. flowlines must accommodate the strain,hence on piles above ground, hence insulatedand drainable or traced

• below about 100˚, lines can be plowed in andpiping standards relaxed;

• a cold (or warm) solvent process is expected tohave field development costs more akin toconventional production, i.e. about half of SAGD

January 2008

21

Effect of cost intensity on Project NPV& optimum project life

[All Projects have same 1.15b bbl OIP]

$-

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

$1,800

$2,000

0 5 10 15 20 25 30

Project Life, years

Pro

jec

tN

PV

,$

mm

SAGD, 65% Rec

1/2 SAGD Costs,32.5% Rec

1/2 SAGD Costs,43% Rec

January 2008

22Conclusions

• There is a lot of room for improvement in bitumen recovery

technology and cost

• Asphaltene burning appears to justify the req’d environmental

investment; reduced diluent usage is a major benefit

• The thermal intensity of SAGD can be optimized (lowered) by

cyclic steaming strategies

• The Grosmont carbonates are an emerging resource with

attractive qualities for thermal recovery

• Highly developed secondary porosity may enable a low-cost,

cold solvent recovery process

January 2008

23Forward-Looking Statement Disclaimer

Certain statements contained in this document are“forward-looking statements”. The projections,estimates and beliefs contained in such forward-looking statements involve known and unknownrisks, uncertainties and other factors which maycause actual results or events to differ materiallyfrom those anticipated in any forward-lookingstatements.

It is believed that expectations reflected in thoseforward-looking statements are reasonable,however assurance cannot be provided that theseexpectations will prove to be correct.