Introduction to Shale Gas
Storage
Nykky Allen
Andrew Aplin
Mark Thomas
[email protected] [email protected]
Calgary, June 2009
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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
Initial porosity results
Initial methane sorption results
Initial desorption kinetics results
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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 maturity and type; moisture content?
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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
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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
Initial porosity results
Initial methane sorption results
Initial desorption kinetics results
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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)
The enthalpy (heat) of adsorption is a function of surface coverage (i.e. the more gas, the more heat released)
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adsorption is the
densification of a fluid at its
interface with a solid
adsorbent
A
z
adsorbate adsorptive
zA 0
Adsorbent
surface
B
Adsorption principles
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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.
0.0 0.2 0.4 0.6 0.8 1.0
0
2
4
6
8
10
12
14
16
n /
mm
ol
g-1
p/p0
If this process is
done at several
pressures, then a
relative pressure
(P/Po) vs amount (n)
curve is generated.
Relative Pressure (P/Po)
Am
ount (n
)
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Schematic of Kinetic Measurement Technique
Pressure
Amount
Adsorbed (mmol/g)
Kinetic
profiles
Time (s)
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High-pressure isotherm analysis
N, amount adsorbed
Pressure
0
Total
Surface Excess
• Surface excess becomes important at very high pressures.
• It is caused by the free gas having a similar density to the adsorbed gas
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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 measured
•The IGA microbalance is accurate to + 0.1 g
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Analysis of Isotherm Data
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Data Analysis
The raw isotherm data is analysed using:
1. Langmuir model
2. BET model
3. D-R model
00.
11
p
p
cn
c
cnppn
p
mm
mmms N
P
KNKN
KP
N
P 11
p
pDWW
02
1001010 logloglog
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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
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
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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
Initial porosity results
Initial methane sorption results
Initial desorption kinetics results
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Pores: Definitions
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Classifications of Pores
– Ultra-micropores < 0.7 nm
– Micropores 0.7 – 1.4 nm
– Super-micropores 1.4 - 2 nm
– Macropores >50 nm / 500 Å
– Mesopores 2–50 nm
– Micropores < 2 nm / 20 Å
•Ultra-micropores provide driving force for adsorption at low
pressures (but what about under geological pressures?)
•Micropores and super-micropores act as transport porosity
providing access to ultra-microporosity
• Pores are classified into groups by IUPAC:
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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
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
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• 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
W = 0.5 nm
W = 1.3 nm W = 1 nm
W = 0.8 nm
W = 0.6 nm
0 -0.2 -0.4 0.2 0.4
Z / nm Width (W)
Micropore Width and Adsorption
Open surface
Pote
ntial E
nerg
y
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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
(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)
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Role of pores in gas storage
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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 above mechanisms
The exact details of how shale porosity determines storage is unclear
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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
Coal may be considered an analogue of the kerogen in shale?
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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.
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Porosity in Coal: Bae and Bhatia (2006)
Micropores (< 0.7nm = 7 Å) dominate
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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 mesoporous, that inertinite is mainly mesoporous, and liptinite is mainly macroporous
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Harris and Yust 1976: TEM of coal pores
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Harris and Yust 1976: TEM of coal pores
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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
Initial porosity results
Initial methane sorption results
Initial desorption kinetics results
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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, 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
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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
4. Temperature and thermal maturity
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Controls on Gas Storage: Organic Matter Type
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Controls on Gas Storage: 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
(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).
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Controls on Gas Storage: 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 is why vitrinite has a higher methane storage capacity than inertinite (Unsworth et al., 1989;
Lamberson and Bustin, 1993)
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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
Vitrinite-rich coals store more methane
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Controls on Gas Storage: Mineral Content
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Controls on Gas Storage: 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 as a diluant to the gas adsorbing organic matter.
The amount of microporosity decreased with increasing inorganic mineral matter (Clarkson and Bustin, 1996)
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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 a simple diluent of shale kerogen
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Controls on Gas Storage: Moisture Content
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Controls on Gas Storage: 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.
Day et al. (2008) stated that moist coal had a
significantly lower gas adsorption capacity for both CO2 and CH4 than dry coal.
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Effect of Moisture Content on CH4 Sorption on Coal (Crosdale et al., 2008)
The methane sorption isotherms were measured for the same coal sample at different moisture contents
It can be seen that moisture reduces methane sorption
Moisture effects on CH4 adsorption on RU1 coal
0.0
5.0
10.0
15.0
20.0
25.0
0.0 2.0 4.0 6.0 8.0 10.0
Pressure (MPa)
Ad
so
rpti
on
(c
m3
/g)
Moisture = 15%
Moisture = 52%
Moisture = 96%
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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
3) As mono- and multilayers on pore walls
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Controls on Gas Storage:
Temperature and Thermal Maturity
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Controls on Gas Storage: 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 mainly micropores.
They found that an anthracite coal sample had the highest methane sorption capacity with over 23 cm3/g at 6 MPa
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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
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Effect of Temperature on CH4
Sorption on Coal
CH4 Adsorp on Dietz Coal
0.0
2.0
4.0
6.0
8.0
10.0
12.0
0.0 5.0 10.0 15.0
Pressure (MPa)
Ad
so
rpti
on
(c
m3
/g)
Temp=10oC
Temp=20oC
Temp=30oC
Temp=40oC
Temp=50oC
• The ambient temperature is a strong factor for methane sorption capacity
• In geological formations, high temperatures would reduce sorption capacity
Bustin and Bustin, 2008, AAPG Bulletin, 92(1), 77-86
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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
Initial porosity results
Initial methane sorption results
Initial desorption kinetics results
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Desorption Kinetics: How Fast is Gas Released to Pores?
Desorption kinetics is required for estimating the rate of gas production from a geological formation
Pressure Amount
Adsorbed
Kinetic profiles Time
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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
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.
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Size matters: Four diffusion mechanisms
Da) Gas diffusion
D >> MFP
b) Knudsen
Diffusion D ~ MFP
c) Surface diffusion
D << MFP
d) Activated diffusion
(Barrier to diffusion)
DDa) Gas diffusion
D >> MFP
b) Knudsen
Diffusion D ~ MFP
c) Surface diffusion
D << MFP
d) Activated diffusion
(Barrier to diffusion)
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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
Initial porosity results
Initial methane sorption results
Initial desorption kinetics results
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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 3161.00 100.00 7.70 366.00 Not Avail 316
Well=211/12A-M16 3376.00 102.00 8.71 421.00 Not Avail 138
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
Proprietary data
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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
- Using the new high pressure CH4 sorption equipment
To correlate methane adsorption and porous structure characteristics with geochemical data and shale lithological data
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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
Initial porosity results
Initial methane sorption results
Initial desorption kinetics results
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Porosity in KCF Shales:
Initial Results
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KCF Porosity - Depth
0
1000
2000
3000
4000
5000
6000
0.00 0.05 0.10 0.15 0.20 0.25 0.30
% PorosityD
ep
th (
m)
Clay-rich KCF Silt-rich KCF Laminated KCF
Proprietary data
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KCF: MICP Data
Total Porosity
Proprietary data
Proprietary data
Proprietary data
Proprietary data
Proprietary data
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KCF: MICP Data
Total Porosity Uncertain
Proprietary data Proprietary data
Proprietary data Proprietary data
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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)
Well 16/7B-28B
211/12A-
M1
211/12A-
M16
211/12A-
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 1.200 0.600 2142.900 4.900 3.400
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
Proprietary data
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KCF: Porosity - Permeability
0.00
0.05
0.10
0.15
0.20
0.25
0.30
1E-231E-221E-211E-201E-19
Permeability (m2)
% P
oro
sit
y
Clay-rich KCF Silt-rich KCF Laminated KCF
Proprietary data
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Po
ros
ity
Shale and KCF Poroperm
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CO2 isotherm for KCF: 211/12A-M16 at 3375.32m
CO2 at 195K on 211/12A-M16
0
0.1
0.2
0.3
0.4
0.5
0.6
0 200 400 600 800 1000 1200
pressure (mbar)
Con
c (m
mol
/g)
Blue = 1st replicate
Pink = 2nd replicate
Proprietary data
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Pore Radii in Shale sample 211/12A-M16, 3400 m
Well: 211/12A-M16, 3400 m12%
10%
14%
19%
45%
200nm to 100nm
100nm to 50nm
50nm to 25nm
25 to 10nm
10 to 3nm
In this sample, 45% of the porosity detected by mercury injection was found in the 3nm to 10nm range.
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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
This means that 59% of the porosity available for gas adsorption is 2nm (or less) in this sample
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Comparison of N2 and CO2 isotherms on test shale
CO2 at -78oC
CO2 at 0oC
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.
Proprietary data
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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
Initial porosity results
Initial methane sorption results
Initial desorption kinetics results
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Methane Sorption in KCF shales: Initial Results
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CH4 Sorption on Illinois #6 Coal: Comparison of Hiden’s and Newcastle Uni isotherms
Close comparison for Illinois #6 coal at 30oC
0 20 40 60 80 100 120
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
Up
tak
e/ m
mo
l g
-1
Pressure/ bar
Hiden, volumetric measurement
Newcastle, gravimetric measurement
Methane adsorption isotherms on coal Illionis 6 at 303 K
Proprietary data
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Replicate isotherms of a KCF kerogen
0 2000 4000 6000 8000 10000
0.00
0.05
0.10
0.15
0.20
0.25
0.30
0.35
Up
take
/ m
mo
l g
-1
Pressure/ mbar
1st run, degas at 423 K
2nd run, degas at 473 K
Methane adsorption on kerogen at 303 K • Kerogen was isolated from shale sample: 211/12A-M16 at 3400m
• These replicate isotherms were obtained using CH4 at a constant temperature of 30 C
• The max CH4 capacity =
0.33 mmol/g
Proprietary data
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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
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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
Initial porosity results
Initial methane sorption results
Initial desorption kinetics results
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Desorption Kinetics: Initial Results
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Desorption kinetics: KCF kerogen at 2 bar
• Kerogen was isolated from shale sample: 211/12A-M16 at 3400m
• These kinetic profiles were obtained using CH4 at a constant temp of 30 C
• Shows desorption from 2 bar to 1 bar
• 10 g desorbed after 20 min 0 10 20 30 40 50 60 70
-24
-22
-20
-18
-16
-14
-12
-10
-8
-6
-4
-2
0
2
4
950
1000
1050
1100
1150
1200
We
igh
t/ m
icro
g.
Time/ minutes
Weight Pressure, 2 --- 1 bar
Pre
ssu
re/
mb
ar10 g desorbed after 20 min
Proprietary data
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Desorption Kinetics: KCF kerogen at 100 mbar
• This low pressure kinetic profile shows desorption from 100 mbar to 50 mbar
• 10 g desorbed
after 60 min
• The rate of desorption is slower at low pressures than at high pressures
0 10 20 30 40 50 60
-14
-12
-10
-8
-6
-4
-2
0
2
4
50
60
70
80
90
100
We
igh
t/ m
icro
g.
Time/ minutes
weight
Pre
ssu
re/
mb
ar
P50
10 g desorbed after 60 min
Proprietary data
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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 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.
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The End
Thank you for listening
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Acknowledgements
I would like to thank:
Prof Andrew Aplin
Prof Mark Thomas
Dr Xuebo Zhao
Dr Jon Bell
Mr Phil Green
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