Introduction to Shale Gas Storage

Introduction
to Shale Gas
Storage
Nykky Allen
Andrew Aplin
Mark Thomas
Calgary, June 2009

Nykky.Allen@ncl.ac.uk
Nykky.Allen1@hotmail.co.uk

Outline of presentation
 Research Questions

 Background theory of Gas Storage
1. Basic principles
2. Pores and porosity
3. Key Controls on Gas Storage
4. Basics of Desorption Kinetics

 Methods and Samples
©Shale Gas 2009

 Initial porosity results

 Initial methane sorption results

 Initial desorption kinetics results

Shale Gas consortium

Research Questions 1

 How is gas stored in shales?
1) Adsorbed/absorbed on organics and minerals
2) Free gas
3) Dissolved in formation water

 What effect does the concentration of organic matter
(OM) have on the adsorption capabilities of shales?

What controls sorption capacities of OM: kerogen
©Shale Gas 2009


maturity and type; moisture content?


Research Questions 2

 Controls on porosity, pore size distributions and
thus storage potential and permeability

 Influence of temperature and pressure on sorption
capacity and desorption kinetics

 Differentation of free and sorbed gas

 Desorption kinetics
©Shale Gas 2009


Basic principles of gas sorption

 Gas sorption can occur when a molecule becomes
attached to or interacts with a solid surface

 The adsorption of gas onto a solid surface is
accompanied by the generation of heat (exothermic
process)
©Shale Gas 2009

 The enthalpy (heat) of adsorption is a function of
surface coverage (i.e. the more gas, the more heat
released)


Adsorption principles
A adsorption is the
densification of a fluid at its
interface with a solid
adsorbent

Adsorbent adsorbate adsorptive
surface
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B

0 zA z


Gas Sorption:
Experimental Measurement
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Sorption Isotherms
Gas sorption experiments help determine:

 1) nature of porosity, 2) max. gas storage capacity, 3)
rate of (de)sorption (kinetics)

 An adsorption isotherm is generated by adsorbing gas
onto the shale sample at constant pressure and
temperature, until equilibrium is achieved, and the
mass/volume of gas adsorbed is constant.
16

14

 If this process is
Amount (n)

12
©Shale Gas 2009

10
done at several
-1
n / mmol g

8

6 pressures, then a
4 relative pressure
2
(P/Po) vs amount (n)
0
0.0 0.2 0.4 0.6 0.8 1.0 curve is generated.
Relative Pressure
p/p
0 (P/Po)


Schematic of Kinetic Measurement Technique

Amount
Adsorbed Pressure
(mmol/g)
©Shale Gas 2009

Kinetic
profiles
Time (s)


High-pressure isotherm analysis

• Surface
N, amount adsorbed excess
becomes
important at
very high
Total pressures.
• It is caused
0
Surface Excess by the free
gas having a
©Shale Gas 2009

similar
density to the
Pressure adsorbed gas


Equipment: Intelligent Gravimetric Analyser

•Powdered shale
and kerogen is
subjected to a
vacuum
•High pressure gas
is pumped into the
sample (at constant
temperature)
•The mass change
is accurately
©Shale Gas 2009

measured
•The IGA
microbalance is
accurate to + 0.1 g


Analysis of Isotherm
Data
©Shale Gas 2009


Data Analysis
 The raw isotherm data is analysed using:

1. Langmuir model
P 1 KP 1 P
Ns KN m KN m Nm
2. BET model

p 1 c 1 p
. 0
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n p0 p nm c nm c p
3. D-R model

2 p0
log 10 W log 10 W0 D log 10
p


A combination of these models gives a full
characterisation of the pore structure

 The Langmuir model gives the total pore volume
(i.e. the total capacity available for gas storage)

 The B.E.T. model gives the apparent surface area
available for gas surface adsorption

 The D-R model gives the volume of the tiniest
microporosity (< 2nm) only
©Shale Gas 2009

 Therefore a combination of these models (plus
mercury injection core porosimetry for the larger
pores) allows a full pore size characterisation of
the shales to be obtained


Pores: Definitions
©Shale Gas 2009


Classifications of Pores

• Pores are classified into groups by IUPAC:
– Macropores >50 nm / 500 Å
– Mesopores 2–50 nm
– Micropores < 2 nm / 20 Å – Ultra-micropores < 0.7 nm
– Micropores 0.7 – 1.4 nm
– Super-micropores 1.4 - 2 nm
• Ultra-micropores provide driving force for adsorption at low
©Shale Gas 2009

pressures (but what about under geological pressures?)
• Micropores and super-micropores act as transport porosity
providing access to ultra-microporosity


Mechanism of sorption in pores
 In wide/large pores (> 2 nm/20 Å), high
pressures/low temperatures are required for sorption
because the gas can easily detach off the pore surface

 In microporosity however (< 2nm/20 Å), the micropore
walls are in close proximity, resulting in overlap of
Lennard-Jones potential energy fields

 This overlap of potential energy fields leads to
enhanced adsorption in constrained pore systems
©Shale Gas 2009

 This effect leads to gas adsorbing at low pressures,
thus strongly bonding the molecules to the surface. The
gas condenses (i.e capillary condensation) into a liquid
phase


Micropore Width and Adsorption

• Micropore walls are in close proximity resulting in
overlap of potential energy fields
• Enhanced interactions facilitate adsorption of vapours
at very low pressures i.e. concentrations
Open surface
Potential Energy

W = 1.3 nm
W = 1 nm
©Shale Gas 2009

W = 0.8 nm
W = 0.6 nm
W = 0.5 nm

-0.4 -0.2 0 0.2 0.4
Width (W)
Z / nm


Mechanism of sorption in pores

 Adsorption of gases and vapours in micropores is
characterised by:

 (1) Improved adsorption at low pressure due to enhanced
adsorption potentials caused by the overlap of the force
fields from opposite pore wall
 (2) Activated diffusion effects caused by constrictions in
the microporous network
©Shale Gas 2009

 (3) Molecular size and shape selectivity

 Zsigmondy’s capillary condensation of a vapour to a
liquid can occur below the saturated vapour pressure
(providing the temperature is below the critical point)


Role of pores in gas storage
©Shale Gas 2009


Porosity is involved in storage

 Shale gas can be stored in three ways:
1. Free gas within pore spaces,

2. Adsorbed gas on surfaces of pores

3. Dissolved gas in pore fluid (water/bitumen)

 Therefore, pores are important to shale gas
storage because they contribute to all of the
©Shale Gas 2009

above mechanisms

 The exact details of how shale porosity
determines storage is unclear


Coal Porosity: An analogue of shale?

 Few studies using gas sorption to investigate
porosity in shales and kerogens

 50 years of studies using gas sorption to
investigate porosity in coals

 Coal literature is useful in providing an analogy
for shale and kerogen sorption
©Shale Gas 2009

 Coal may be considered an analogue of the
kerogen in shale?


Porosity of Coal

 Clarkson and Bustin (1996): micropore volume is
the main control on methane adsorption in coal

 Crosdalet et al. (1998): methane adsorption in
coal is related to micropore volume

 Bae and Bhatia (2006): surface areas of coals are
dominated by pores smaller than 10 Å.
©Shale Gas 2009


Porosity in Coal: Bae and Bhatia (2006)
©Shale Gas 2009

 Micropores (< 0.7nm = 7 Å) dominate


Thermal maturity and microporosity of Coals
 Microporosity increases with increasing thermal
maturity (Gan et al., 1972; Clarkson and Bustin, 1996;
Prinz et al., 2004; Prinz and Littke, 2005)

 Crosdale et al. (1998): increasing thermal maturity
increases relative abundance of micropores at the
expense of macropores and mesopores

 Harris and Yust (1976): Transmission Electron
Microscope suggests that vitrinite is mainly micro- and
©Shale Gas 2009

mesoporous, that inertinite is mainly mesoporous, and
liptinite is mainly macroporous


Harris and Yust 1976: TEM of coal pores
©Shale Gas 2009


Mechanism of gas storage

 Shale gas can be stored in three ways:
1. as free gas within pore spaces,
2. as adsorbed gas on surfaces of pores
3. as dissolved gas in pore fluid (water/bitumen)

 The relative importance of the three modes of gas
storage is determined by:
1. Physical properties (e.g. TOC, porosity, pore size
distribution, mineralogy, specific surface area)
2. Geological conditions (depth, temperature, pressure,
©Shale Gas 2009

moisture/water saturation)
3. Gas composition (alkanes, N2, CO, CO2, SO2 etc)

Cluff and Dickerson, 1982; Harris et al., 1978;
Montgomery et al., 2005; Pollastro et al., 2003


Key controls on gas storage: learnings from coal

 Wealth of data on gas storage in coals, a useful
analogy

 Several key controls have been identified:
1. Organic matter type

2. Mineral content

3. Moisture content
©Shale Gas 2009

4. Temperature and thermal maturity


Controls on Gas Storage:
Organic Matter Type
©Shale Gas 2009


Organic Matter Type

 Coal is a complex mixture of heterogeneous
organic and inorganic matters, that introduces
variability into gas sorption studies (Bae and
Bhatia, 2006)

 Vitrinite rich coals have a higher methane
storage capacity than inertinite rich coals
©Shale Gas 2009

(Lamberson and Bustin, 1993; Bustin and Clarkson,
1998; Crosdale et al., 1998; Clarkson and Bustin, 1999;
Laxminarayana and Crosdale, 1999; Mastalerz et al.,
2004; Hildenbrand et al., 2006; Gürdal and Yalçın,
2000).


Organic Matter Type

 Positive correlation between vitrinite content and
methane adsorption capacity (Bustin and Clarkson, 1998).

 The maceral composition has a greater impact on
methane adsorption capacity in higher rank coals
than in lower rank coals (Chalmers and Bustin, 2007)

 Vitrinite is more microporous than inertinite; this
©Shale Gas 2009

is why vitrinite has a higher methane storage
capacity than inertinite (Unsworth et al., 1989;
Lamberson and Bustin, 1993)


Sorption Isotherms for Vitrinite and Inertinite
Rich Coals (Chalmers and Bustin, 2007)

 The difference
in methane
sorption
capacity can be
seen for Bright
(vitrinite-rich)
and Dull
(Inertite-rich)
Coals
©Shale Gas 2009

 Vitrinite-rich
coals store
more methane


Mineral Content
©Shale Gas 2009


Mineral Content
 Mineral content of coals is determined by the
coalification process and the environment of
organic matter deposition (Bae and Bhatia, 2006)

 The inorganic mineral content of a coal has a
negative correlation with methane adsorption
capacity (Crosdale et al., 1998; Laxminarayana and Crosdale, 1999,
Chalmers and Bustin, 2007)

 Crosdale et al. (1998) found that inorganic
mineral matter does not adsorb coal gas, and acts
©Shale Gas 2009

as a diluant to the gas adsorbing organic matter.

 The amount of microporosity decreased with
increasing inorganic mineral matter (Clarkson and
Bustin, 1996)


Effect of Mineral Content on CH4 Sorption in
Coal (Laxminarayana and Crosdale, 1999)
 Methane
sorption
capacity
decreases with
increasing
mineral matter

 It is suggested
that mineral
matter acts as
©Shale Gas 2009

a simple
diluent of shale
kerogen


Moisture Content
©Shale Gas 2009


Moisture Content

 Joubert et al. (1973; 1974) found gas adsorption is a
function of water content in coal seams.

 Moisture in the pores has an effect on gas adsorption
(Bae and Bhatia, 2006)

 Crosdale et al. (2008) found that the moisture content
of coals was a critical determining factor in evaluating
methane storage capacity of coals.

 Bustin and Clarkson (1998) found that moisture
prevents methane from accessing microporosity.
©Shale Gas 2009

 Day et al. (2008) stated that moist coal had a
significantly lower gas adsorption capacity for both CO2
and CH4 than dry coal.


Effect of Moisture Content on CH4 Sorption on
Coal (Crosdale et al., 2008)
Moisture effects on CH4 adsorption on RU1 coal
 The methane
sorption
25.0 isotherms
were
20.0 measured for
the same coal
Adsorption (cm3/g)

sample at
15.0 Moisture = 15% different
Moisture = 52% moisture
10.0 Moisture = 96% contents
©Shale Gas 2009

5.0  It can be seen
that moisture
0.0
reduces
methane
0.0 2.0 4.0 6.0 8.0 10.0
sorption
Pressure (MPa)


Water Plugs Block Pores
 The moisture content effect is attributed to the
water molecules competing with the gas
molecules for adsorption sites (Bustin and Clarkson,
1998; Busch et al., 2007; Crosdale et al., 2008; Hackley et al.,
2007).

 Allardice and Evans (1978): moisture in coal can
be found in the following forms:
 1) Free water in macropores and interstitial spaces
 2) As a meniscus in slit shaped pores due to capillary
condensation effects
©Shale Gas 2009

 3) As mono- and multilayers on pore walls


Temperature and Thermal
Maturity
©Shale Gas 2009


Thermal maturity
 Levy et al. (1997) showed that thermal maturity (rank) of coal
has a strong influence on methane adsorption capacity

 Chalmers and Bustin (2007) suggest that increased thermal
maturity results in enhanced microporosity and thus increased
methane adsorption capacity.

 Clarkson and Bustin (1999) state that coals of lower rank
contain mainly macropores, and that high rank coals contain
©Shale Gas 2009

mainly micropores.

 They found that an anthracite coal sample had the highest
methane sorption capacity with over 23 cm3/g at 6 MPa


Effect of Coal Rank on CH4 Sorption (Chalmers
and Bustin, 2007)

 Thermal
maturity is
determined
using vitrinite
reflectance
(%)
 It can be seen
that maturity
is a strong
factor for
methane
adsorption
©Shale Gas 2009


Effect of Temperature on CH4
Sorption on Coal
• The ambient
CH4 Adsorp on Dietz Coal
temperature is
a strong factor
12.0 for methane
sorption
10.0
Adsorption (cm3/g)

capacity
Temp=10oC
8.0 • In geological
Temp=20oC
6.0 Temp=30oC formations,
high
Temp=40oC
4.0 temperatures
Temp=50oC
would reduce
©Shale Gas 2009

2.0 sorption
0.0
capacity
0.0 5.0 10.0 15.0
Pressure (MPa)

Bustin and Bustin, 2008, AAPG Bulletin, 92(1), 77-86


Desorption Kinetics: How Fast is Gas Released
to Pores?

 Desorption kinetics is required for estimating the
rate of gas production from a geological formation

Amount Pressure
Adsorbed
©Shale Gas 2009

Kinetic profiles Time


Desorption Kinetics: How Fast is Gas Released
to Pores?

 All rates depend on activation energy (Ea)

 Desorption of a gas involves two steps: 1) desorption off the
surface, and 2) diffusion away from the surface into the
porous network

 Diffusion is slow (relative to desorption), and therefore
diffusion through the porous network is the rate determining
step
©Shale Gas 2009

 Rate of diffusion depends on gas size:pore size ratio

 This ratio determines 4 mechanisms: a) gas diffusion; b)
Knudsen diffusion; c) surface diffusion; and d) activated
diffusion.


Size matters: Four diffusion mechanisms

a) Gas diffusion D
D >> MFP

b) Knudsen
Diffusion D ~ MFP
©Shale Gas 2009

c) Surface diffusion
D << MFP
d) Activated diffusion
(Barrier to diffusion)


Samples
 A suite of KCF shale samples will be investigated:

Sample Name depth(m) temp( C) TOC(wt%) Tmax( C) Porosity (%) HI (mgHC/gTOC)
Well=202//3-1A 1600.00 58.00 3.44 417.00 Not Avail 260
Well=205/20-1 1986.00 56.00 2.29 Not Avail Not Avail 500
Well=31/4-10 2007.00 76.00 4.87 423.00 11.0 358
Well=204/27A-1 2043.00 44.00 6.50 425 Not Avail 260
Well=204/28-2 2330.00 60.00 9.98 407.00 Not Avail 406
Well=211/12A-M1 3125.00 97.00 7.52 423.00 14.3 287
Well=25/2-6 3161.00 Proprietary data
100.00 7.70 366.00 Not Avail 316
Well=211/12A-M16 3376.00 102.00 8.71 421.00 Not Avail 138
©Shale Gas 2009

Well=211/12A-M16 3400.00 103.00 8.32 425 Not Avail 121
Well=16/7B-28B 4132.00 106.00 9.63 438.00 8.0 250
Well=6205/3-1R 4450.00 157.00 4.00 477.00 Not Avail 44
Well=3/29-2 4608.00 130.00 6.07 425 6.48 35
Well=3/29A-4 4707.00 141.00 5.11 425 4.3 48
Well=3/29A-4 4781.00 144.00 6.18 425 3.3 65


Experimental Aims and Objectives
 To characterize porous structure of shales and
kerogens using:
1. Carbon dioxide sorption at -78°C (for total porosity)

2. Carbon dioxide sorption at 0°C (for microporosity)

3. Mercury Injection Core Porosimetry (for macroporosity)

 To measure methane sorption isotherm data for
shales and kerogens under conditions which simulate
geological conditions
©Shale Gas 2009

- Using the new high pressure CH4 sorption equipment

 To correlate methane adsorption and porous
structure characteristics with geochemical data and
shale lithological data


Porosity in KCF Shales:
Initial Results
©Shale Gas 2009


KCF Porosity - Depth

% Porosity
0.00 0.05 0.10 0.15 0.20 0.25 0.30
0

1000

2000
Depth (m)

3000
Proprietary data
4000
©Shale Gas 2009

5000

6000

Clay-rich KCF Silt-rich KCF Laminated KCF


KCF: MICP Data

Proprietary data
Proprietary data

Proprietary data
Proprietary data
©Shale Gas 2009

Total Porosity Proprietary data


KCF: MICP Data

Proprietary data Proprietary data
©Shale Gas 2009

Proprietary data Proprietary data

Total Porosity Uncertain


Mercury porosimetry analysis
 Mercury Intrusion Porosimetry (MIP) analysis used to
analyse the pore size distribution (PSD) of pores larger
than ~3nm (in the mesopore range)

211/12A- 211/12A- 211/12A-
Well 16/7B-28B M1 M16 M16 3/29A-4 3/29A-4 3/29-2 31/4-9 31-9-14

Depth (m) 4132.95 3124.7 3375.32 3400.4 4707.7 4780.7 4608.4 2117.8 2978.5
Total
Porosity 0.101 0.233 0.198 0.180 0.086 0.092 0.145 0.232 0.126
Corrected
porosity 0.090 0.227 0.193 0.172 0.062 0.082 0.130 0.194 0.108
Mean pore
radius (nm) 2.100 594.600 608.300 1003.800
Proprietary data 2142.900
1.200 0.600 4.900 3.400
©Shale Gas 2009

90%
percentile
pore radius
(nm) 4.481 780.020 851.520 1435.700 4.165 3.508 8428.000 9.762 7.370
Horizontal
Permeability
(m2) 6.2x10-22 6.9x10-19 6.1x10-19 9.3x10-19 2.3x10-22 1.5x10-22 1.6x10-18 3.4x10-21 1.3x10-21
Vertical
Permeability
(m2) 6.7x10-22 8.7x10-19 7.4x10-19 1.1x10-18 2.4x10-22 1.6x10-22 1.8x10-18 4.2x10-21 1.4x10-21


KCF: Porosity - Permeability
Clay-rich KCF Silt-rich KCF Laminated KCF
0.30

0.25

0.20
% Porosity

0.15
Proprietary data
0.10
©Shale Gas 2009

0.05

0.00
1E-19 1E-20 1E-21 1E-22 1E-23
Permeability (m2)


CO2 isotherm for KCF: 211/12A-M16 at
3375.32m

CO2 at 195K on 211/12A-M16
Blue = 1st replicate
Pink = 2nd replicate
0.6

0.5
Conc (mmol/g)

0.4

0.3 Proprietary data
0.2
©Shale Gas 2009

0.1

0
0 200 400 600 800 1000 1200
pressure (mbar)


Pore Radii in Shale sample 211/12A-M16,
3400 m

Well: 211/12A-M16, 3400 m
12%
200nm to 100nm
10% 100nm to 50nm
50nm to 25nm
45%
25 to 10nm
14% 10 to 3nm
©Shale Gas 2009

19%
In this sample, 45% of the porosity detected by mercury
injection was found in the 3nm to 10nm range.


Adsorption isotherm for KCF: 211/12A-M16 at
3400m

 Using the Langmuir model, the total porosity (i.e.
micro/meso/macropores) is calculated as:
0.01967 cm3/g

 Using the DR model, the microporosity is
calculated to be:
0.01172 cm3/g
©Shale Gas 2009

 This means that 59% of the porosity available for
gas adsorption is 2nm (or less) in this sample


Comparison of N2 and CO2 isotherms on test shale

CO2 at -78oC

Proprietary datao
CO2 at 0 C
©Shale Gas 2009

N2 at -196oC

• The N2 at -196oC isotherm shows significant “activated diffusion”. There is
a kinetic barrier to gas diffusion through the pore network due to low temp.


CH4 Sorption on Illinois #6 Coal: Comparison of Hiden’s
and Newcastle Uni isotherms
1.6

Methane adsorption isotherms on coal Illionis 6 at 303 K
1.4

1.2
-1

1.0
Uptake/ mmol g

0.8

Proprietary data
0.6

0.4
©Shale Gas 2009

Hiden, volumetric measurement
Newcastle, gravimetric measurement
0.2

0.0
0 20 40 60 80 100 120

Pressure/ bar
 Close comparison for Illinois #6 coal at 30oC


Replicate isotherms of a KCF kerogen

0.35 Methane adsorption on kerogen at 303 K • Kerogen was
isolated from
0.30 shale sample:
211/12A-M16 at
0.25 3400m
-1
Uptake/ mmol g

• These replicate
0.20
isotherms were
Proprietary data obtained using
0.15
CH4 at a
1st run, degas at 423 K
constant
0.10
©Shale Gas 2009

2nd run, degas at 473 K temperature of
30 C
0.05
• The max CH4
0.00 capacity =
0 2000 4000 6000 8000 10000
0.33 mmol/g
Pressure/ mbar


Isotherms of KCF kerogen

 The two isotherms are slightly different due to the
degassing pre-treatment used to remove volatile
molecules from the pores

 The final amount of CH4 adsorbed by the kerogen is the
same

 Kerogen sorbs similar amount as the Illinois #6 coal
©Shale Gas 2009


Desorption kinetics: KCF kerogen at 2 bar
• Kerogen was
isolated from
4
1200 shale sample:
2 211/12A-M16 at
Weight Pressure, 2 --- 1 bar
0 3400m
1150
-2
• These kinetic
-4
10 g desorbed after 20 min profiles were

Pressure/ mbar
-6
Weight/ microg.

-8
1100 obtained using
-10 CH4 at a
-12
Proprietary data constant temp
1050
-14 of 30 C
-16
•
©Shale Gas 2009

-18
Shows
-20
1000 desorption from
-22
2 bar to 1 bar
-24
950 • 10 g desorbed
0 10 20 30 40 50 60 70
after 20 min
Time/ minutes


Desorption Kinetics: KCF kerogen at 100 mbar

100 • This low
4
pressure kinetic
2 weight P50 profile shows
90
desorption from
0
100 mbar to 50
mbar

Pressure/ mbar
-2
Weight/ microg.

80
10 g desorbed after 60 min
-4 Proprietary data
70
• 10 g desorbed
-6
after 60 min
-8

• The rate of
©Shale Gas 2009

60
-10

-12
desorption is
50 slower at low
-14
pressures than
0 10 20 30 40 50 60 at high
Time/ minutes pressures


Summary and Conclusions
 Porosity is a significant factor in the sorption capacity
of shale, especially the microporosity

 Organic matter type and maturity, moisture content
and mineral content are significant controls on methane
storage

 Coal gave similar CH4 sorption values as kerogen, so
coal may be considered an analogue of kerogen

 Initial methane sorption results have shown that good
agreement has been obtained for volumetric and
gravimetric adsorption methods for coal which has
©Shale Gas 2009

been used as a model for kerogen

 Results show that desorption kinetics can be measured
and the rates of desorption of methane from coal and
kerogen can be quite slow, but that high pressures
speed desorption up.


Acknowledgements

 I would like to thank:
 Prof Andrew Aplin

 Prof Mark Thomas

 Dr Xuebo Zhao

 Dr Jon Bell

 Mr Phil Green
©Shale Gas 2009


References
 Allardice, D.J., Evans, D.G.,1978. Moisture in coal. In: Karr Jr.,
C. (Ed.), Analytical Methods for Coal and Coal Products, vol. 1.
Academic Press, New York, pp. 247–262.

 Bae J.S. and Bhatia S.K., 2006, High-Pressure Adsorption of
Methane and Carbon Dioxide on Coal, Energy Fuels, 20(6),
2599-2607

 Bustin R.M. and Clarkson C.R, 1998, Geological controls on
coalbed methane reservoir capacity and gas content,
International Journal of Coal Geology, 38, 3–26
©Shale Gas 2009

 Chalmers GLR and Bustin RM, 2007, The organic matter
distribution and methane capacity of the Lower Cretaceous
strata of Northeastern British Columbia, Canada, International
Journal of Coal Geology, 70, 223-239


References

 Clarkson C.R and Bustin R.M, 1996, Variation in micropore
capacity and size distribution with composition in bituminous
coal of the Western Canadian Sedimentary Basin: Implications
for coalbed methane potential, Fuel, 75(13), 1483-1498

 Clarkson C.R and Bustin R.M., 1999, The effect of pore
structure and gas pressure upon the transport properties of
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