Introduction to Shale Gas Storage

Introduction to Shale Gas

Storage

Nykky Allen

Andrew Aplin

Mark Thomas

[email protected] [email protected]

Calgary, June 2009

http://en.wikipedia.org/wiki/File:Lundin_Petroleum.svg

Shale Gas consortium

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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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Research Questions


1. Basic principles




Methods and Samples





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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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Research Questions


1. Basic principles




Methods and Samples





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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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Research Questions


1. Basic principles




Methods and Samples





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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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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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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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Research Questions


1. Basic principles




Methods and Samples





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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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Research Questions


1. Basic principles




Methods and Samples





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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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Research Questions


1. Basic principles




Methods and Samples





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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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Research Questions


1. Basic principles




Methods and Samples





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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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Research Questions


1. Basic principles




Methods and Samples





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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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Introduction to Shale Gas Storage