Introduction to Shale Gas Storage

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An introduction to the chemistry of gas storage in shales

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Introduction to Shale Gas Storage

  1. 1. Introductionto Shale Gas Storage Nykky Allen Andrew Aplin Mark Thomas Calgary, June 2009 Nykky.Allen@ncl.ac.uk Nykky.Allen1@hotmail.co.uk
  2. 2. 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
  3. 3. 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? Shale Gas consortium
  4. 4. 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 Shale Gas consortium
  5. 5. 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
  6. 6. 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) Shale Gas consortium
  7. 7. Adsorption principles A adsorption is the densification of a fluid at its interface with a solid adsorbent Adsorbent adsorbate adsorptive surface©Shale Gas 2009 B 0 zA z Shale Gas consortium
  8. 8. Gas Sorption: Experimental Measurement©Shale Gas 2009 Shale Gas consortium
  9. 9. 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) Shale Gas consortium
  10. 10. Schematic of Kinetic Measurement Technique Amount Adsorbed Pressure (mmol/g)©Shale Gas 2009 Kinetic profiles Time (s) Shale Gas consortium
  11. 11. 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 Shale Gas consortium
  12. 12. 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 Shale Gas consortium
  13. 13. Analysis of Isotherm Data©Shale Gas 2009 Shale Gas consortium
  14. 14. 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©Shale Gas 2009 n p0 p nm c nm c p 3. D-R model 2 p0 log 10 W log 10 W0 D log 10 p Shale Gas consortium
  15. 15. 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 Shale Gas consortium
  16. 16. 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
  17. 17. Pores: Definitions©Shale Gas 2009 Shale Gas consortium
  18. 18. 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 Shale Gas consortium
  19. 19. 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 Shale Gas consortium
  20. 20. 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 Shale Gas consortium
  21. 21. 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) Shale Gas consortium
  22. 22. Role of pores in gas storage©Shale Gas 2009 Shale Gas consortium
  23. 23. 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 Shale Gas consortium
  24. 24. 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? Shale Gas consortium
  25. 25. 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 Shale Gas consortium
  26. 26. Porosity in Coal: Bae and Bhatia (2006)©Shale Gas 2009  Micropores (< 0.7nm = 7 Å) dominate Shale Gas consortium
  27. 27. 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 Shale Gas consortium
  28. 28. Harris and Yust 1976: TEM of coal pores©Shale Gas 2009 Shale Gas consortium
  29. 29. Harris and Yust 1976: TEM of coal pores©Shale Gas 2009 Shale Gas consortium
  30. 30. 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
  31. 31. 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 Shale Gas consortium
  32. 32. 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 Shale Gas consortium
  33. 33. Controls on Gas Storage: Organic Matter Type©Shale Gas 2009 Shale Gas consortium
  34. 34. 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©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). Shale Gas consortium
  35. 35. 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©Shale Gas 2009 is why vitrinite has a higher methane storage capacity than inertinite (Unsworth et al., 1989; Lamberson and Bustin, 1993) Shale Gas consortium
  36. 36. 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 Shale Gas consortium
  37. 37. Controls on Gas Storage: Mineral Content©Shale Gas 2009 Shale Gas consortium
  38. 38. 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©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) Shale Gas consortium
  39. 39. 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 Shale Gas consortium
  40. 40. Controls on Gas Storage: Moisture Content©Shale Gas 2009 Shale Gas consortium
  41. 41. 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.©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. Shale Gas consortium
  42. 42. 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) Shale Gas consortium
  43. 43. 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 Shale Gas consortium
  44. 44. Controls on Gas Storage: Temperature and Thermal Maturity©Shale Gas 2009 Shale Gas consortium
  45. 45. 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©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 Shale Gas consortium
  46. 46. 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 Shale Gas consortium
  47. 47. 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 Shale Gas consortium
  48. 48. 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
  49. 49. 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 Shale Gas consortium
  50. 50. 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. Shale Gas consortium
  51. 51. 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) Shale Gas consortium
  52. 52. 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
  53. 53. 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 Shale Gas consortium
  54. 54. 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 Shale Gas consortium
  55. 55. 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
  56. 56. Porosity in KCF Shales: Initial Results©Shale Gas 2009 Shale Gas consortium
  57. 57. 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 Shale Gas consortium
  58. 58. KCF: MICP Data Proprietary data Proprietary data Proprietary data Proprietary data©Shale Gas 2009 Total Porosity Proprietary data Shale Gas consortium
  59. 59. KCF: MICP Data Proprietary data Proprietary data©Shale Gas 2009 Proprietary data Proprietary data Total Porosity Uncertain Shale Gas consortium
  60. 60. 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 Shale Gas consortium
  61. 61. 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) Shale Gas consortium
  62. 62. Shale and KCF Poroperm Porosity©Shale Gas 2009 Shale Gas consortium
  63. 63. 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) Shale Gas consortium
  64. 64. 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. Shale Gas consortium
  65. 65. 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 Shale Gas consortium
  66. 66. 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. Shale Gas consortium
  67. 67. 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
  68. 68. Methane Sorption in KCF shales: Initial Results©Shale Gas 2009 Shale Gas consortium
  69. 69. 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 Shale Gas consortium
  70. 70. 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 Shale Gas consortium
  71. 71. 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 Shale Gas consortium
  72. 72. 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
  73. 73. Desorption Kinetics: Initial Results©Shale Gas 2009 Shale Gas consortium
  74. 74. 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 Shale Gas consortium
  75. 75. 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 Shale Gas consortium
  76. 76. 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. Shale Gas consortium
  77. 77. The End Thank you for listening©Shale Gas 2009 Shale Gas consortium
  78. 78. Acknowledgements  I would like to thank:  Prof Andrew Aplin  Prof Mark Thomas  Dr Xuebo Zhao  Dr Jon Bell  Mr Phil Green©Shale Gas 2009 Shale Gas consortium
  79. 79. 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 Shale Gas consortium
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  84. 84. References  Okiongbo et al., 2005, Energy and Fuels, 19, 2495-2499  Pollastro, R. M., R. J. Hill, D. M. Jarvie, and M. E. Henry, 2003, Assessing Undiscovered Resources of the Barnett-Paleozoic Total Petroleum System, Bend Arch–Fort Worth Basin Province, Texas: Search and Discovery Article #10034.  Prinz D., Pyckhout-Hintzen W., Littke R., 2004, Development of the meso- and macroporous structure of coals with rank as analysed with small angle neutron scattering and adsorption experiments, Fuel, 83, 547-556  Prinz D. and Littke R., 2005, Development of the micro- and ultramicroporous structure of coals with rank as deduced from©Shale Gas 2009 the accessibility to water, Fuel, 84, 1645-1652  Ross, D. J. K., and R. M. Bustin, 2008, Characterizing the shale gas resource potential of Devonian-Mississippian strata in the Western Canada sedimentary basin: Application of an integrated formation evaluation, AAPG Bulletin, 92, 87-125.  Unsworth J.F., Fowler C.S., Jones L.F., 1989, Moisture in Coal: 2 Maceral effects on Pore structure, Fuel, 68, 18-26 Shale Gas consortium

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