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
1 PJ ~ 1 Bscf
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
Growing CBM resource base
Source: Origin Jun 2009
Source: GLNG FID Jan 2011
Australian CBM Principles and Development
Challenges
Coal Bed Methane (CBM) / Coal Seal Gas (CSG) principles
Australian CBM landscape
Challenges and Lessons
Coalbeds are naturally fractured
Naturally fractured reservoir, productivity dependent on the quality
and quantity of fractures
Coals are created through a process called
coalification
Coalification process
Burial, Compaction,
Heating
Gas liberated
Peat
Kerogens
Parafins
Coal rank (increasing maturity)
Peat, lignite, sub bituminous,
bituminous, anthracite
Heating value determines coal value and increases with coal
maturity (bituminous)
CBM coals are typically sub bituminous (related to fracture quality
and quantity)
Gas liberated during coalification can be sorbed into
coal matrix
Isotherms used to model gas storage capacity
Gas storage capacity increases with coal maturity
Possible Gas storage capacity > Gas Content (undersaturation)
Coal saturation affects CBM productivity
Economic consequences:
Rate of ramp up to peak gas (payback)
Peak gas rate (marginal revenue, marginal cost)
Rate of decline post peak gas (NPV)
CBM production well configuration
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
30 year production life of CBM development well
Fracture permeability affects peak gas rate and decline, and time
required to get payback on upfront costs
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
What is required for CBM to work
Technical sweetspot identification
Gas
content (higher GIIP)
Saturation
Gas
(quick ramp up)
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)
Source: Santos Investor Seminar Nov 2011
Source: Santos Investor Seminar Nov 2011
What could happen if surface risks are not as well
managed
Success factors for CBM development
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)
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 estimation using the offset method
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
Dynamic simulation to evaluate economic
sensitivities
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)
Sensitivity on fracture permeability
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
Hydraulic fractures to improve reservoir contact for
low permeability reservoirs
Transverse
Pancake
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
Sensitivity for transverse hydraulic fractures
Cost of hydraulic fracture not included
NPV10 negative assuming $1 million job
cost
Cost control and reduction is critical to make
this work
Return permeability impairment:
Be careful what you inject into the reservoir
Success factors for CBM development
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)
Australian CBM Development Challenges
CBM development critical success factors
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)
