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Australian Coal Bed Methane:

Principles and Development Challenges

Martin T K Soh

Reservoir Modelling and Monitoring Consultant

Source: APLNG FID Jul 2011

Significant Australian CBM resource potential

In comparison (2P): NWSV – 30 Tscf, Pluto – 6 Tscf, Browse – 15

Tscf, Gorgon foundation – 20 Tscf

30 Tscf CBM 2P resource available in Queensland, and it is

growing

1 PJ ~ 1 Bscf

Growing CBM resource base

Source: Origin Jun 2009 Source: GLNG FID Jan 2011

Coal Bed Methane (CBM) / Coal Seal Gas (CSG) principles

Australian CBM landscape

Challenges and Lessons

Australian CBM Principles and Development

Challenges

Naturally fractured reservoir, productivity dependent on the quality

and quantity of fractures

Coalbeds are naturally fractured

Heating value determines coal value and increases with coal

maturity (bituminous)

CBM coals are typically sub bituminous (related to fracture quality

and quantity)

Coals are created through a process called

coalification

Peat

Kerogens Parafins

Coalification process

Burial, Compaction, Heating

Gas liberated

Coal rank (increasing maturity)

Peat, lignite, sub bituminous,

bituminous, anthracite

Isotherms used to model gas storage capacity

Gas storage capacity increases with coal maturity

Possible Gas storage capacity > Gas Content (undersaturation)

Gas liberated during coalification can be sorbed into

coal matrix

Economic consequences:

Rate of ramp up to peak gas (payback)

Peak gas rate (marginal revenue, marginal cost)

Rate of decline post peak gas (NPV)

Coal saturation affects CBM productivity

Water is the main phase (reduce

reservoir pressure)

Artificial lift is required (normally

pressured, opex)

Low pressure system

(compression required at start)

Stimulation (hydrofrac) may be

required for tight coals

Horizontal wells drilled to

improve reservoir contact in

seam

CBM production well configuration

Fracture permeability affects peak gas rate and decline, and time

required to get payback on upfront costs

30 year production life of CBM development well

CBM Development scale

25 km

Source: Santos UK Investor Roadshow Mar 2012

Source: Origin Asset Visit Sep 2011

Source: Origin Investor Visit Upstream Jun 2009

Reservoir property variability

Technical – sweetspot identification

Gas content (higher GIIP)

Saturation (quick ramp up)

Gas density (e.g. Bscf/acre)

Permeability (fractures to flow)

Non technical – surface risk mitigation

Cost

Access to land (landholder negotiations)

Surface footprint (community amenity and lifestyle)

Water (sharing aquifers)

What is required for CBM to work

Source: Santos Investor Seminar – Nov 2011

Source: Santos Investor Seminar – Nov 2011

What could happen if surface risks are not as well

managed…

CBM characteristics

Higher surface footprint, well and gathering system requirements

Higher lifting cost

CBM development success factors

Cost control and reduction

Well ultimate recovery and drainage area

Appraisal (capture uncertainty vs minimising uncertainty)

Pilot production (commercial rates, FDP)

Early monetisation (cashflow, learning, technology, capability)

Success factors for CBM development

Source: Santos investor presentation Nov 2011

Gas price has been the monetisation enabler for

CBM in Australia

Industry consolidation: CBM company acquisition valuations

based on upside of LNG pricing

Historical Reserves Multiples paid by multinationals

to enter the Australian CBM business

Reserves is hydrocarbon that can be

commercially produced

Technically mature

Commercially mature

Commitment to produce (FID)

1P, 2P and 3P classes indicate

confidence/certainty in the estimate

Lower confidence/certainty further away

from data

In order for undeveloped reserves to be

booked, future well locations must be

defined

Linked to commerciality and commitment

to produce

Reserves estimation using the offset method

Reservoir

3.4 Bscf over 750x750 m2

Revenue and cost

Price = $6/Mscf

Royalty = 10% revenue

Well cost = $1 million

Lifting cost = $2/Mscf

Minimum gas rate (MC) = 1

Msm3/d = 35 Mscf/d

Breakeven well UR = 0.3 Bscf

(undiscounted)

Dynamic simulation to evaluate economic

sensitivities

High permeability leads to accelerated production and payback =

better NPV

Lower permeability reservoirs are more marginal because of lower

peak rates and slower decline from peak

Sensitivity on fracture permeability

Hydraulic fractures are a high permeability conduit into the

wellbore

Fractures created by tensile failure

Depending on the stress regime, transverse or pancake fractures

are created

Hydraulic fractures to improve reservoir contact for

low permeability reservoirs

Transverse ‘Pancake’

Cost of hydraulic fracture not included

NPV10 negative assuming $1 million job

cost

Cost control and reduction is critical to make

this work

Sensitivity for transverse hydraulic fractures

Return permeability impairment:

Be careful what you inject into the reservoir

CBM characteristics

Higher surface footprint, well and gathering system requirements

Higher lifting cost

CBM development success factors

Cost control and reduction

Well ultimate recovery and drainage area

Appraisal (capture uncertainty vs minimising uncertainty)

Pilot production (commercial rates, FDP)

Early monetisation (cashflow, learning, technology, capability)

Success factors for CBM development

CBM development critical success factors

Australian CBM Development Challenges

CSF Challenges

Cost control & reduction Multiple concurrent LNG developments,

$5 Billion cost blowout QCLNG, labour

shortages

Well UR and drainage area Sweetspots in production, stepping out to

less favourable areas

Appraisal (uncertainty) Most data available from sweetspots; is it

geostationary (extrapolatable)?

Pilot production Pilot production area chosen to maximise

commercial gas flowrates

Early monetisation Expansion scale brings additional risks

(LNG supply security, organisation

capability)