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Geological controls on gas sorption capacities and regional gas shale potential of the Lower Cretaceous… Chalmers, Gareth Raymond 2007

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G E O L O G I C A L CONTROLS O N G A S SORPTION CAPACITIES A N D R E G I O N A L GAS S H A L E POTENTIAL OF T H E L O W E R C R E T A C E O U S B U C K I N G H O R S E F O R M A T I O N , N O R T H E A S T E R N BRITISH C O L U M B I A , C A N A D A . by GARETH RAYMOND CHALMERS B.Sc. (HONS), The University of Newcastle, Australia, 1997 M.Sc. The University of Newcastle, Australia, 2001  A THESIS SUBMITTED IN P A R T I A L F U L F I L L M E N T OF T H E REQUIREMENTS FOR T H E D E G R E E OF DOCTOR OF PHILOSOPHY  in  THE F A C U L T Y OF G R A D U A T E STUDIES  (Geological Sciences)  T H E UNIVERSITY OF BRITISH C O L U M B I A  June, 2007  © Gareth Raymond Chalmers, 2007  ABSTRACT  The geological controls on methane sorption capacity and the regional gas shale potential have been investigated for the Lower Cretaceous Buckinghorse Formation in Northeastern British Columbia. Geological controls investigated include: 1) total organic carbon (TOC) content; 2) kerogen types; 3) maturity; 4) mineralogy; and 5) moisture content. No published research has evaluated the geological controls on methane capacity of shales. The influence of petrographic composition on methane capacity of coal, particularly liptinite, is still not well understood but is relevant to kerogen types of gas shales.  Methane sorption capacity of moisture-equilibrated samples were obtained by using a high pressure, volumetric, gas sorption apparatus. Rock-Eval analysis provided TOC content, kerogen types and maturity data and telovitrinite reflectance and petrographic analyses were performed on coals. Micropore volumes were measured by CO2 at 0°C and mesopores by N2 at -196°C on a surface area analyser. Mesopore to macropore volumes were obtained from a mercury porosimeter. Total porosity was determined by helium pycnometry and mercury immersion. Shale mineralogy was determined by X-ray diffraction.  TOC content is the primary control on methane sorption capacities for these shales. High maturity samples that are dominated by Type III kerogen have greater methane capacity per unit TOC volume because they contain greater volume of micropores. Liptinite-rich  ii  coals store gas in solution while liptinite-poor coals store gas in micropores by physical sorption. Overall rank is the primary influence in methane capacity of coal. Illite is the only mineralogical control because both micro- and mesoporosity increase and illite content also increases with maturity. Moisture has a negative effect on methane capacity of a shale but there is no correlation between methane capacity and equilibrium moisture.  In northeastern British Columbia, areas of high gas-in place (GIP) estimates are either high in TOC content (map section 94-P) or reservoir pressure (Liard Basin and 94-1). For the Garbutt-Moosebar-Wilrich formations, the Liard Basin has the greatest GIP due to greater strata thickness. The regional TOC distribution is controlled by clastic input with low TOC at the deformational front and a basinward increase to the northeast.  iii  T A B L E OF CONTENTS  Abstract  ii  Table of Contents  iv  List of Tables  viii  List of Figures  ix  List of Acronyms  xvi  Acknowledgements  xvii  Dedication  xviii  Co-Authorship Statement C H A P T E R ONE  Introduction  xix 1  1.1 Introductory Statements  1  1.2 1.3 1.4 1.5  2 5 6 7  Research Background Statement of Problem and Objectives Thesis Structures References  C H A P T E R TWO  On the effects of petrographic composition of coalbed methane  sorption  11  2.1 Introduction  11  2.2 Analytical Methods 2.3 Results 2.3.1 Maceral Analysis 2.3.2 Methane Sorption Capacities 2.3.3 Surface Area and Micropore Volumes 2.3.4 Whole Coal Reflectograms 2.4 Discussion 2.4.1 Subbituminous Coals 2.4.2 Bituminous Coals 2.4.3 Higher Rank 2.4.4 Liptinite-rich Samples 2.4.5 Full Coal Reflectograms 2.5 Conclusions  15 17 17 18 18 19 19 20 21 22 24 27 27 iv  2.6 References  CHAPTER THREE  52  The organic matter distribution and methane capacity of the Lower  Cretaceous strata of Northeastern British Columbia, Canada 3.1 Introduction  53 53  3.2 Lithology and Depositional Environments of Formations 56 3.3 Analytical Methods 59 3.4 Results 61 3.4.1 Organic Matter Petrology and Methane Sorption Capacity 61 3.4.2 Moisture Content, Organic Matter Content and Methane Capacity.64 3.4.3 Surface Area and Microporosity 65 3.4.4 Total Gas Capacity and Porosity 66 3.5 Discussion 67 3.5.1 Organic Petrology 67 3.5.2 Controls on Methane Sorption Capacity 69 3.6 Conclusions 72 3.7 References 92  C H A P T E R FOUR  Lower Cretaceous Gas Shales in Northeastern British Columbia,  Part I: Geological Controls on Methane Sorption Capacity 4.1 Introduction 4.2 Methods 4.2.1 Organic Geochemistry 4.2.2 High-Pressure methane Sorption Analysis 4.2.3 Shale Mineralogy 4.2.4 Pore Size Distribution 4.2.5 Total Porosity Measurements 4.3 Results and Discussion 4.3.1 Organic Geochemistry and Methane Capacity 4.3.2 Shale Mineralogy 4.3.3 Pore Size Distribution and Methane Capacity 4.3.4 Moisture Content 4.4 Summary and Conclusions 4.5 References  96 96 99 99 100 101 101 102 103 104 105 107 Ill 112 133  C H A P T E R FIVE Lower Cretaceous Gas Shales in Northeastern British Columbia, Part II: Evaluation of Regional Potential Gas Resources 5.1 Introduction 5.2 Geological Background 5.2.1 Lithological Distribution 5.2.2 Depositional Environments 5.2.3 Basin Evolution and Structural Controls 5.2.4 Palaeogeography 5.3 Methods 5.3.1 Stratigraphic Cross-sections, Isopach and Structure Maps 5.3.2 Organic Geochemistry 5.3.3 High-Pressure Methane Sorption Analysis 5.3.4 Porosity and Total Gas Capacity 5.3.5 Permeability 5.3.6 Mineralogy 5.4 Results and Discussion 5.4.1 Structure and Stratigraphy 5.4.2 Isopach 5.4.3 Stratigraphic Cross-sections 5.4.4 Organic Geochemistry 5.4.4.1 Total Organic Carbon Content 5.4.4.2 Kerogen Types 5.4.4.3 Maturity 5.4.5 Shale Mineralogy 5.4.6 Methane Sorption Capacities 5.4.7 Total Gas Capacities 5.4.8 Gas-In-Place (GIP) Estimates 5.4.9 Producibility Considerations 5.5 Exploration Considerations 5.6 Conclusions 5.7 References  C H A P T E R SIX Conclusion and Recommendations for Future Work 6.1 6.2 6.3 6.4  General Conclusions Significance of Work and Applicability of Research Future research and recommendations References  137 137 139 139 140 141 142 143 143 144 145 145 146 147 147 147 148 149 151 151 153 153 154 155 156 156 158 159 160 184  188 188 191 192 193  APPENDICES  A P P E N D I X A Data table for 216 samples - analyses include methane sorption capacity, total gas capacity, porosity, equilibrium moisture content, and total organic carbon content, kerogen type and maturity, t Methane capacities are an arbitrary pressure of 6 MPa and volumes reported in cm /g  195  3  A P P E N D I X B Reservoir (hydrostatic) pressure, sorbed and total gas capacity, permeability and depth to samples. * permeability is measured from the porosimeter data and using equations by Swanson (1981). $ Sample depth is total vertical depth and from the surface, f measured in cm /g at reservoir pressure. GIP = gas in place  200  A P P E N D I X C Stratigraphic Cross-section C - C  205  A P P E N D I X D Stratigraphic Cross-section D - D '  206  A P P E N D I X E Stratigraphic Cross-section E - E '  207  A P P E N D I X F Stratigraphic Cross-section F-F'  208  A P P E N D I X G Core log description for all cores within this study  C D (insert)  vii  LIST OF TABLES  Table 2.1 Properties of the coal and organic-rich shale samples  44  Table 2.2 Maceral Group Composition of samples (minerals included)  45  Table 2.3 The volume percentage of maceral composition of subbituminous samples on a mineral matter free basis 46 Table 2.4.The volume percentage of maceral composition of bituminous and higher rank samples on a mineral matter free 46 Table 2.5 The volume percentage of maceral composition of liptinite-rich samples on a mineral matter free basis 47 Table 2.6 Methane capacities of all samples at 6 MPa, the capacity differences between the bright and dull samples of the subbituminous and bituminous coal suites (negative number indicates greater capacity for dull sample), and the percentage of reactive macerals (vitrinite+liptinite+reactive inertinite) in dull samples 48 Table 2.7  Surface area and microporosity of coals and organic-rich samples  Table 3.1 Maceral group percent by volume for the four formations of 6-30-80-13W6M  49  89  Table 3.2 Maceral analysis of the four formations in well # 6-30-80-13W6M. All volumes are reported in percent with minerals included 90 Table 3.3 Reservoir characteristic of the samples analysed for methane capacities, averages are shown in italics (* denote pressures at 6 MPa)  91  Table 3.4 Surface area and micropore volume of all methane sorption samples  92  Table 4.1 Mineralogy of the sample suite that were also analysed for pore size distribution. Mineral contents are in volume percent  130  Table 4.2 The mesoporous and microporous surface area with various TOC contents and methane sorption capacities 132 Table 5.1 Mineralogy of shale samples subdivided by their location with respect to the map sections 182  viii  LIST OF FIGURES Figure 2.1 Methane sorption capacity for bright and dull pairs for subbituminous coals, on an ash free and dry basis. Open shapes are dull samples and filled shapes are bright samples 29 Figure 2.2 Methane sorption capacity for the bituminous rank coals on ash free, dry basis. Open shapes are dull samples and filled shapes are bright samples. Note the large difference between the low volatile bituminous Canmore coals and the other bituminous coals 30 Figure 2.3 Methane sorption isotherms for the anthracite and natural coke samples on a dry and ash free basis. Note the Y-axis has been changed to log scale 31 Figure 2.4 Methane sorption capacity for liptinite-rich coals and shales. On a dry, ash free basis. Note alginite-rich coals have similar methane capacities and same for the exsudatinite -rich samples and also the two mineral-rich samples 32 Figure 2.5 A negative relationship exists between the micropore volume and mesoporous surface area of a sample. Liptinite-rich samples do not have high surface area nor microporosity with the exception of the high surface area in the rhythmite because of the high ash content 33 Figure 2.6 Reflectogram of the dull portions of subbituminous coals to coke showing the reactive inertinite cutoffs 34 Figure 2.7 The negative relationship between micropore volume, methane sorption capacity and the percentage of non-reactive inertinite in the dull subbituminous and bituminous coals, excluding Canmore Coal due to reflectance cut-off equations not being suitable for coals above the rank of medium volatile bituminous 35 Figure 2.8 The strong positive relationship between rank and methane sorption capacity for samples except liptinite-rich samples. Mean random reflectance (%Rrt) of telovitrinite was used to determine the rank of each sample. The effect rank has on methane sorption can be easily seen. Note the logarithmic scale for rank. N = 15 36 Figure 2.9 There is a weak positive relationship that exists between the vitrinite or telovitrinite contents and methane sorption capacity of the subbituminous samples  37  Figure 2.10 Comparison between micropore volume, mesoporous surface area and methane capacity for both bright and dull samples of the subbituminous coal suite. Rank increases from the left to the right. Both Genesee samples have the highest methane capacity due to their high micropore volumes 38  ix  Figure 2.11 Comparison between the micropore volume, mesoporous surface area and methane capacity for the bituminous coals, anthracite and coke samples. A l l bright samples have a greater micropore volume and methane capacity than their dull pairs. The high volatile and medium volatile bituminous coals have similar capacities when compared to the low volatile bituminous Canmore coals and anthracite samples 39 Figure 2.12 A positive relationship exists between both vitrinite and telovitrinite with the methane sorption capacity, the lower data points are from the high and medium volatile coals and the higher data points are the low volatile bituminous Canmore coals and anthracite samples 40 Figure 2.13 Increase in the differential pressure during void volume calculation of the coke through helium expansion analysis. The coke indicates that more helium is diffusing into the sample with higher pressures, however, the microporosity is too small for the methane to access as indicated by the methane sorption capacity of only 0.5 cm /g. The differential cell pressure is the measurement of the pressure differences between the reference and sample cell. Therefore, an increase in differential pressure, indicates there is a drop in pressure within the sample cell 41 3  Figure 2.14 There is a broad positive relationship between micropore volume, methane capacity and vitrinite content subbituminous coals to coke samples. By increasing the vitrinite content of a sample, the microporosity and surface area of the coal increases which provides more sorption site for methane to be stored on. Note the large difference in methane capacity for the Canmore coals and the anthracite sample due to rank 42 Figure 2.15 Broad positive relationship exists between micropore volume and methane sorption capacity. Liptinite-rich samples show high methane capacities but low micropore volumes which are attributable to the gas being held in solution 43 Figure 3.1 Location of study area is centred at Fort St John and the location of the well is along the Alberta/British Columbia border, shown by filled diamond. Inset is the location of the study area within British Columbia, Canada. The filled circles are location of towns/cities 75 Figure 3.2 Stratigraphic table for the Lower Cretaceous strata of northeastern British Columbia. Light grey shaded formations are sandstone dominated and medium grey shaded formations are shale dominated 76 Figure 3.3 Lithological graphic log showing the four formations of well # 6-30-8013W6M and the O M distribution. Sample numbers and their locations are also shown .77 Figure 3.4 (A) illustrates the alternation between organic-rich siltstones and shale with fine-grained sandstone, Bluesky Formation; (B) parallel cross-laminated fine sandstone with organic-rich laminations, Bluesky Formation; (C) a Teichichnus-type burrow originating from OM-rich siltstone and penetrating into cross-laminated sandstone, Bluesky Formation; (D) illustrates the cleaner coal in the middle of the seam and the  increase in mineral matter towards both the upper and lower contacts, Chamberlain Member; Canadian penny for scale  78  Figure 3.5 Moosebar Formation containing a 3-cm sulphur-rich claystone, the claystone is a bentonite band, one of several found within the Moosebar Formation (A); interbedded massive medium to coarse sandstone with organic-rich siltstone and shale, Gates Formation (B); heavily bioturbated sandstone, siltstone and shale, similar to the Bluesky Formation, giving a mottled texture (C), Gates Formation; the shale of the Hulcross Formation (D) is fissile and sulphur-rich. Canadian penny for scale 79 Figure 3.6 Methane sorption isotherms for the Bluesky, Moosebar, Gates and Hul cross Formations. The percentage of O M content of samples are also shown 80 Figure 3.7 The relationship between the O M content, moisture content and methane sorption capacity. Graph excludes the coal sample S8 due to underestimation of O M content  81  Figure 3.8 Photomicrographs of macerals in well 6-30-80-13W6M. (A) Large, poorlysorted inertinite grains too large to be classified as inertodetrinite with smaller vitrodetrinite particles, note the large variation in reflectance levels, Sample S7; (B) Telovitrinite rootlet showing bifurcation within mineral matter, Sample S10; (C) Telovitrinite from the Chamberlain coal with well preserved resin ducts, Sample S8; (D) Liptodetrinite-rich Moosebar Formation with the majority consisting of fragmented alginite, Sample SI2; (E) High-reflecting inertodetrinite from a Moosebar Formation, Sample SI5; (F) Low-fluorescing bituminite-rich matrix shale from the Hulcross Formation with scattered liptodetrinite, Sample S22. A l l photomicrographs are in white light except (D) and (F) which are in blue light, oil immersion, 40x objective. Scale bar is 20 jim 82 Figure 3.9 The positive relationship between the O M content, the micropore volume and the methane sorption capacity of the OM-rich shales. Note, the Chamberlain coal sample was excluded due to scaling effects 83 Figure 3.10 The positive relationship between moisture, micropore volume and O M content of the OM-rich shales. Note the Chamberlain Coal is excluded due to scaling effects  84  Figure 3.11 A negative relationship exists between the surface area measured by N2 adsorption and the moisture content of a sample. The moisture, in fact, is associated with the microporosity of the O M , illustrated by the positive relationship between moisture and micropore volume 85 Figure 3.12 The relationship between porosity, micropore volume and surface area measured by N2 adsorption. Porosity, measured by the difference between bulk (mercury immersion) and skeletal (helium pycnometry) densities, is shown to be derived from the microporosity of the sample and the mesoporosity does not have any influence 86 xi  Figure 3.13 Sample S15 from the Moosebar Formation illustrating the difference between sorbed gas capacity and total gas capacity. Total gas capacity is calculated using the porosity of the sample and assuming there is no water saturation 87 Figure 3.14 Total (free + sorbed) gas capacities of the four formations. Free gas is calculated using porosity of the sample. Porosity values (percent) are shown for each sample's isotherm  88  Figure 4.1 Location of study area and sampled wells. Symbols are keyed to the name of the formation that was analysed 115 Figure 4.2 Stratigraphy for Lower Cretaceous strata (Modified after Jowett and Schroeder-Adams, 2005). Predominately shale units are in dark grey and sandstone units are in light grey. F S M B = Fish Scale Marker Bed 116 Figure 4.3 A selection of isotherms with varying TOC contents, see Appendix A for more information on these samples 117 Figure 4.4 A positive correlation exists between TOC content and methane capacity. The data have been subdivided into kerogen types 118 Figure 4.5 The relationship between TOC content, maturity and methane capacity grouped into kerogen types  119  Figure 4.6 Relationship between HI and methane capacity is due to the association of high HI with high TOC content (A) as the relationship becomes a negative trend between HI and methane capacity when the methane capacity is normalized to TOC content (B) 120 Figure 4.7 The relationship between methane capacity normalized to TOC with the total clay (A) and illite contents (B). The relationship between methane capacity normalized to TOC on a dried basis with the total clay (C) and illite contents (D) 119 Figure 4.8 Plot of illite content as a percentage of the total clay content and maturity 120 Figure 4.9 Relationship between mesoporous and microporous surface areas with methane capacity (A) and with the TOC content (B)  123  Figure 4.10 The relationship between mesoporous and microporous surface area with maturity (A) and with total clay content (B) 124 Figure 4.11 The micropore distribution of samples with varying maturity (A) and when the micropore volume is normalized to TOC content (B) 125  xii  Figure 4.12 The relationship between microporous surface area and maturity (A) and microporous surface area normalized to TOC content (B). Kerogen types can be separated into to groups with Types I and II grouped A (dashed lines) and Types II/III and III group B (dash-dot line) 126 Figure 4.13 Pore size distribution of selected samples with varying quartz contents by mercury porosimeter (A) and also determined by N2 and CO2 adsorption analyses (B) 127 Figure 4.14 Relationship between moisture content and maturity (A) and when the moisture content normalized to TOC content (B)  128  Figure 4.15 The relationship between the moisture content and TOC (A), total clay content (B), methane capacity (C) and the meso- and microporous surface area (D) .... 129 Figure 5.1 Study area in northeastern British Columbia and structures that have influenced sedimentation of the Lower Cretaceous strata; the Peace River Arch (Wright et al., 1994), Deep Bain (Masters, 1984), Keg River Palaeohigh (Smith, 1994) and Bovie Structure (Price, 1994). The eastern margin of the study area is the border between British Columbia and Alberta and the western margin is the deformation front 162 Figure 5.2 Stratigraphic table of the Lower Cretaceous strata for northeastern British Columbia and northwestern Alberta. A geophysical-log example through the relevant formations is inset. Location of the Liard Basin, Sikanni Chief River and Moberly Lake sections are shown in Fig. 5.1 163 Figure 5.3 Index map for the three cross-sections and the well control for the analysed wells (full circles) and for the wells used for isopach maps (crosses). Cross-sections CC , D - D ' , E - E ' and F-F' are found in Appendix A , B , C and D, respectively 164 Figure 5.4 The structural map on the base of the Buckinghorse Formation. Short dashed lines are the boundaries of the Peace River Arch (PRA) and the long dashed line is the margin of the Deep Basin (DB). Unbroken line is approximation of the Bovie Structure (BS). Crosses indicate well locations 165 Figure 5.5 Isopach map for the total thickness of the Buckinghorse Formation. Crosses indicate location of wells used for all isopach maps 166 Figure 5.6 Isopach maps of the organic-rich basal (ORB) layer (A) and the Moosebar and equivalent formations (B). Well control shown in Fig. 5 167 Figure 5.7 Stratigraphic cross-section A - A ' . Cross-section shows the Buckinghorse Formation and its equivalents. The Sikanni Formation lies on top of the Buckinghorse Formation. Refer to Figure 3 for location of cross-sections. Location of P R A is identified by the erosion of the Sikanni and part of the Lepine formations. Black boxes indicate the sampled intervals and FS 2 is the datum 168  xiii  Figure 5.8 Stratigraphic cross-section A ' - A " . A thinning of the strata highlighted by the coalescence of flooding surfaces occurs towards the north (cross-section A - A ' - A " ) . Black boxes indicate the sampled intervals and FS 2 is the datum 169 Figure 5.9 Stratigraphic cross-section B - B ' . The B ' end connects with A " and is the westward extension of A - A ' - A " cross-sections. The abrupt thickening in this crosssection is due to the syndepositional faulting of the Bovie Structure which defines the eastern margin of the Liard Basin (between wells B-59-I-04-O-11 and B-66-D-94-0-13). Black boxes indicate the sampled intervals and FS 2 is the datum 170 Figure 5.10 The regional distribution for the TOC content (A), kerogen types (B), kerogen maturity by T (°C) and oil, wet gas and dry gas windows (D). A l l data are well averages and black crosses indicate location of wells 171 m a x  Figure 5.11 Modified van Krevelen diagram illustrating the kerogen types by their geographic location in map sections  172  Figure 5.12 The regional distribution of the illite (A) and quartz (B) contents. Values are averaged per well and crosses in (B) are location of wells with shale mineralogy analysed 173 Figure 5.13 Five graphic logs of cores from across the basin. Sections include part of the Gething/Bluesky formations and the basal section of the Buckinghorse Formation. Depths are from sea level 174 Figure 5.14 The distribution of methane sorption capacity on an average per well basis (A). Gas capacities are measured in cm /g, at hydrostatic pressure and at 30°C. Crosses show location of analysed wells 175 3  Figure 5.15 Average porosity (%) per well (A) and the total gas capacity (cm /g) (B). Crosses show location of analysed wells 176 3  Figure 5.16 GIP estimates for the ORB layer (A) and the Garbutt-Moosebar-Wilrich formations and the equivalents (B) 177 Figure 5.17 Reservoir temperature for bottom-hole temperature from analysed wells 175 Figure 5.18 The relationship between methane sorption capacity and temperature on four samples with varying TOC contents 179 Figure 5.19 The variation in matrix permeability of the Lower Cretaceous shale at different depths  180  Figure 5.20 Natural fracturing and facies changes are present within the Buckinghorse Formation. A vertical, straight, bitumen-filled fracture (A) core width is 4 inches, and calcite-filled fractures are commonly found within the more competent ironstone or xiv  siderite bands and lenses (B). Facies changes from shale to very fine-grained to finegrained sandstone occurs as volcanic ash deposits (C) Canadian Penny for scale, or as tempesites (D) 181  xv  LIST OF ACRONYMS  ASTM  American Society for Testing and Materials  BET  Brunauer Emmett and Teller  BJH  Barrett, Johner, Helenda  BS  Bovie Structure  CBM  Coalbed methane  CNS  Carbon Nitrogen Sulphur  DB  Deep Basin  D-R  Dubinin-Radushkevich  GIP  Gas in place  HI  Hydrogen Index  IUPAC  International Union of Pure and Applied Chemistry  md  millidarcies  NE BC  Northeastern British Columbia  OM  Organic matter  OI  Oxygen Index  ORB  Organic rich basal  PRA  Peace River Arch  R  Reflectance cut-off  Rr  jt  Mean random reflectance of telovitrinite  STP  Standard temperature and pressure  S  Water saturation  w  TOC  Total organic carbon  T  Thermal Maturation by Rock-Eval  m a x  WCSB  Western Canadian sedimentary basin  xvi  ACKNOWLEDGEMENTS  I wish to gratefully acknowledge my supervisor Dr R. Marc Bustin for his assistance and guidance throughout the course of this PhD candidacy. His persistence in editing my manuscripts has improved my writing ability as well as he has taught me to self evaluate my writing style and scientific content. I would also like to acknowledge my supervisory committee, Dr Paul Smith and Dr Kurt Grimm for their academic support and editorial assistance for the past four and half years. Editorial assistance and comments are gratefully acknowledged from the university examiners, Dr. Lori Kennedy and Dr. Scott Dunbar.  I would like to express my gratitude to N S E R C and the Encana Corporation for financial assistance in this project. I would also like to thank for assistance and entertainment, the staff at the Ministry of Energy, Mines and Petroleum Resources, Core Facility at Charlie Lake, British Columbia.  Appreciation is expressed to all the faculty, staff and students of Earth and Ocean Sciences for their support and friendships throughout the course of this PhD project. There have been many students, both faculty, graduate and undergraduate levels, that have passed through this department from a large variety of countries and backgrounds. I thank these people as they have given me different scientific and personal points of view.  xvii  This thesis is dedicated to Rachmaninov, Piano Concerto No. 1: Rhapsody on a Theme of Paganini and my Fisher Space Pen; no edit would have been complete.  xviii  CO-AUTHORSHIP STATEMENT  The research theme of the thesis is an original concept by Dr R . M . Bustin. The Lower Cretaceous stratigraphy of Northeastern British Columbia was selected by G.R.L. Chalmers to evaluate the influence of sea-level fluctuations have on the organic matter distribution and how this distribution effects the potential gas shale.  Both the high pressure methane sorption and helium pycnometry apparatuses were designed and constructed by Dr R . M . Bustin at the Earth and Ocean Sciences, University of British Columbia. Apart from the Rock-Eval analysis that was conducted at the Geological Survey of Canada in Calgary and the CNS analysis was carried out by M . Soon in Earth and Ocean Sciences, all analyses were performed or laboratory assistants were supervised by G.R.L. Chalmers at the Earth and Ocean Sciences, University of British Columbia. Troubleshooting of analytical apparatuses were performed with the assistance of Dr R . M . Bustin, D. Ross and Dr. L. Chikatamarla.  Analyses and interpretation of collected data have been performed by G.R.L. Chalmers. Raw data from the high pressure methane sorption analysis and helium pycnometry were modified by calculations designed and implemented by Dr R . M . Bustin.  The preparation of the four manuscripts within this thesis were designed and written by G.R.L Chalmers with conceptual, editorial and scientific guidance by Dr R . M . Bustin and will further editorial assistance by D. Ross.  xix  CHAPTER ONE  INTRODUCTION  1.1 INTRODUCTORY STATEMENTS  Demand for natural gas in North America is expected to grow from the present consumption of 22 trillion cubic feet (Tcf) per year to 26 Tcf per year by 2030 (Energy Information Administration, website). Supply from conventional reservoirs is declining with the projection of current production being exhausted by the year 2085. With the increase in demand and decrease in conventional production, there is a need to identify and produce from unconventional gas resources like gas shales. The western Canadian sedimentary basin (WCSB) contains a massive untapped gas shale resource with estimates of greater than 86 Tcf of gas in place (Faraj et al., 2004). The rock volume of the Lower Cretaceous, organic-rich shales within the W C S B in northeastern British Columbia is estimated to be 130, 000 k m (Leckie et al., 1988). This large volume of 3  shale has the potential of becoming a major supplier to the North American gas market.  Gas shales are a continuous, non-buoyancy driven resource with methane found in a sorbed state on internal surfaces of clay and organic matter and in the free state compressed within the matrix porosity and microfractures. Gas is retained within the shale because of low matrix permeability and the methane molecule's attraction to  internal surfaces. Zones of economic interest are not concentrated within structural or stratigraphic traps like conventional reservoirs hence other methods are needed to identify the pay zones within these continuous reservoirs. These zones are controlled by the total organic carbon (TOC) content, kerogen types, thermal maturation, mineralogy and the pore size distribution. Methane generation is dependent on the TOC content, type and maturity while gas storage is related to the pore size distribution (i.e. surface area). To date no research has focused on the evaluation of these geological controls on methane capacity of gas shales. The purpose of this research thesis is to outline the possible controls on, and location of, pay zones within the Lower Cretaceous shale of northeastern British Columbia. Once the relative importance of each geological control is established, the task of identifying pay zones within a gas shale reservoir will become more successful. The conclusions of this research will provide information that can be readily applied towards other potential gas shale basins.  1.2 RESEARCH BACKGROUND  Shales are heterogeneous because they form and evolve under a variety of geological conditions that determine their mineralogy, kerogen characteristics and degree of diagenesis. This heterogeneity results in gas shales comprising a very diverse set of rocks and reservoir properties. Hill and Nelson (2000) observed that the five currently producing gas plays in the United States have their own set of unique characteristics and concluded these plays need to be assessed on an individual basis. Limited research has  2  summarized reservoir characteristics of the Barnett Shale (Montgomery et al., 2006) but has not identified how the distribution of the characteristics is controlled across the basin.  Gas shales are, in part, analogous to coalbed methane in that a component of gas storage is in the sorbed state. They are also similar to tight sands with low permeability and porosity. Consequently, geological controls on methane capacity for organic-rich shales should be similar to coals and tight sands.  The geological controls on methane capacity of coals include rank, mineral matter, petrographic composition and moisture content. Mineral matter and rank are the two dominant controls. Mineral matter acts as a dilutant for sorbed coal capacity (Faiz et al., 1992; Yee et al., 1993; Crosdale et al., 1998; Laxminarayana and Crosdale, 1999) because it reduces the volume of sorption sites which are a function surface area most of which is associated with the organic matter fraction. A positive relationship exists between rank and methane capacity (Gan et al., 1972; Unsworth et a l , 1989; Lamberson and Bustin, 1993; Yee et al., 1993; Beamish and Crosdale, 1995; Clarkson and Bustin, 1996; Levy et al., 1997; Prinz et al., 2004; Prinz and Littke, 2005). The effects of petrographic composition on sorption capacity are not clear because rank is a strong control and few studies are based on iso-rank samples. The few examples of iso-rank studies indicate a positive relationship between vitrinite content and methane capacity (Crosdale and Beamish, 1993; 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). This correlation is attributed to vitrinite  3  being more microporous than inertinite and the difference becomes relatively more pronounced with increasing rank (Unsworth et al., 1989; Lamberson and Bustin, 1993; Beamish and Crosdale, 1995). Other research has found no relationship between petrographic composition and methane capacity (Carroll and Pashin, 2003; Faiz et al., 1992; Faiz et al., in press). Studies on the affects of petrographic composition have neglected the liptinite maceral group which is more important in gas shales because majority are marine and liptinite-rich. Moisture content has a negative relationship with methane capacity of coals because the water molecules reduce the volume of sorption sites for methane (Joubert et al., 1974; Levy et al., 1997; Mavor et al., 1990; Yalcin and Durucan, 1991; Yee et al., 1993). With increase in moisture content, a maximum reduction in the methane capacity (critical value) is reached, after which any further increase has no effect (Joubert, 1974).  Tight sands or tight gas characterized by low permeability (< 0.1 md) sandstones form unconventional petroleum systems. Tight gas plays are continuous and regionally pervasive because the accumulations are non-buoyancy driven and do not rely on structural or stratigraphic traps (Law and Curtis, 2002). Gas shales have low permeability characteristics similar to tight sands and also show continuous, regionally pervasive gas accumulation.  The most studied gas shale is the Mississippian Barnett Shale (Montgomery et al., 2005) which is used as an analogy for this study. The gas potential of the Barnett Shale was evaluated by mapping the stratal thickness, organic richness, thermal maturity, gas  4  content, and lithology of the reservoir. Montgomery et al. (2005) concluded that areas with the greatest gas shale potential contains upper and lower fracture barriers, greater thickness, higher TOC content and higher maturity ( T  max  values above 450°C) compared  to the rest of the Fort Worth Basin (Montgomery et al., 2005). A similar approach has been implemented for the regional evaluation within this study.  1.3 STATEMENT OF PROBLEM AND OBJECTIVES  The heterogeneous nature of shale from the scale of local internal stratigraphy to differences from basin to basin creates a complex task of characterizing gas shale reservoirs. Studies characterizing gas shales have not evaluated the geological controls on methane capacity with the exception of Lu et al., (1995) and Ramos (2005), who found a positive relationship between TOC and methane capacity. There are no published results on the effects that kerogen type, maturity, mineralogy or moisture content have on methane capacities of shale. In this study, a suite of samples was selected from the Lower Cretaceous shales of northeastern British Columbia in order to determine what influences the methane capacity. This research project is subdivided into two parts: 1) the evaluation of the geological controls on methane capacity of gas shales; and 2) the regional evaluation of gas shale resources for the Lower Cretaceous shales in northeastern British Columbia. There is limited published research describing producing gas shales (e.g. Montgomery et al., 2005) or on the evaluation of the geological controls on the methane sorption capacity of potential or producing gas shales. Researchers commonly list shale  5  properties when describing gas shale characteristics (e.g. Hill and Nelson, 2000), however, the relative importance of each characteristic with respect to methane capacity has not been evaluated.  A n additional suite of coals and organic-rich shales has been selected to examine the effects of petrographic (kerogen type) composition on methane capacity because the Lower Cretaceous shales are relatively organic lean in comparison which could make results more ambiguous. The effect petrographic composition has on coalbed methane capacity is not clear because rank is the dominating control. Some studies have shown vitrinite to have a higher methane capacity than inertinite in iso-ranked samples while others have observed no trends. Liptinite is more common in marine shales than in coals and therefore needs to be assessed as a control in gas shales. Previous research has also neglected to distinguish between non-reactive and reactive inertinite. Coking coal research indicates that reactive inertinite has similar properties and chemical structure to vitrinite. Reactive inertinite could have a similar ability to sorb gas as vitrinite and may be part of the reason that a complex relationship exists between petrographic composition and methane capacity of organic-rich rocks.  1.4 THESIS STRUCTURE  This thesis consists of four published or submitted research papers. The papers are in the following order:  6  Chapter 2: Chalmers, G.R.L. and Bustin, R . M . , 2007. On the effects of petrographic composition on coalbed methane sorption. Int. J. Coal Geol., vol. 69, p. 228-304.  Chapter 3: Chalmers, G.R.L. and Bustin, R . M . , 2007. The organic matter distribution and methane capacity of the Lower Cretaceous strata of Northeastern British Columbia, Canada. Int. J. Coal Geol., vol. 70, p. 223-239.  Chapter 4: Chalmers, G.R.L. and Bustin, R . M . , submitted. Lower Cretaceous gas shales in northeastern British Columbia, Part I: Geological controls on methane sorption capacity. CSPG Bulletin.  Chapter 5: Chalmers, G.R.L. and Bustin, R . M . , submitted. Lower Cretaceous gas shales in northeastern British Columbia, Part II: Evaluation of regional potential gas resources. CSPG Bulletin.  1.5 REFERENCES  Beamish, B.B. and Crosdale, P. J., 1995. The influence of maceral content on the sorption of gases by coal and the association with outbursting. Int. Symp. Cum Workshop on Management and Control of High Gas Emission and Outbursts, Wollongong, 20-24 March, 1995. Wollongong, Australia. Bustin, R . M . and Clarkson, C.R., 1998. Geological controls on coalbed methane reservoir capacity and gas content. Int. J. Coal Geol. 38, 3-26. Bustin, R . M . 2005. Gas shale tapped for big play. A A P G Explorer, February, 2005.  7  Carroll, R.E. and Pashin, J.C., 2003. Relationship of sorption capacity to coal quality: CO2 sequestration potential of coalbed methane reservoirs in the Black Warrior Basin. International Coalbed Methane Symposium, proceedings, paper 0317. Tuscaloosa, Alabama, U S A . 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, Vol. 75 (13), pp. 1483-1498. Clarkson, C R . and Bustin, R . M . , 1999. The effect of pore structure and gas pressure upon the transport properties of coal: a laboratory and modeling study. 1. Isotherms and pore volume distributions. Fuel 78, 1333-1344. Crosdale, P.J. and Beamish, B.B., Valix, M . , 1998. Coalbed methane sorption related to coal composition. Int. J. Coal Geol. 35, 147-158. Energy Information Administration's Annual Energy Outlook 2007. Website: http://www.eia.doe.gov/oiaf/aeo/gas.html Faiz, M . M . , Aziz, N.I., Hutton, A . C and Jones, B.G., 1992. Porosity and gas sorption capacity of some eastern Australian coals in relation to coal rank and composition. Coalbed Methane Symposium, Townsville, 19-21 November, 1992. Townsville, Australia. Faiz, M . , Saghafi, A., Sherwood, N . , Wang, I. in press. The influence of petrographic properties and burial history on coal seam methane reservoir characterisation, Sydney Basin, Australia. Int. J. Coal Geol. Faraj, B., Williams, H., Addison, G. McKinstry, B. 2004. Gas potential of selected shale formations in the western Canadian sedimentary basin. Houston, Hart Publications, Gas TIPS, vol 10 (1), p 21-25. Gan, H., Nandi, S.P. and Walker Jr., P.L., 1972. Nature of porosity in American Coals. Fuel 51, 272-277. Hildenbrand, A., Krooss, B . M . , Busch, A . and Gashnitz, R., 2006. Evolution of methane sorption capacity of coal seams as a function of burial history - a case study from the Campine Basin, N E Belgium. International Journal Coal Geology 66, 179203. Hill, D.G. and Nelson, C R . 2000. Gas productive fractured shales: A n overview and update. Gas TIPS, Vol 7 (2),. p 11 -16. Joubert, J.I., Grein, C.T. and Bienstock, D., 1974. Effect of moisture on the methane capacity of American coals. Fuel 53, 186-191. 8  Lamberson, M . N . and Bustin, R . M . , 1993. Coalbed Methane Characteristics of Gates formation Coals, Northeastern British Columbia: Effect of Maceral Composition. A A P G 77(12), 2062-2072. Law, B.E. and Curtis, J.B. 2002. Introduction to unconventional petroleum systems. A A P G 86 (11), p 1851-1852. Laxminarayana, C. and Crosdale, P.J., 1999. Role of coal type and rank on methane sorption characteristics of Bowen Basin, Australia coals. Int. J. Coal Geol. 40, 309-325. Leckie, D.A., Kalkreuth, W.D., Snowdon, L.R., 1988. Source rock potential and thermal maturity of Lower Cretaceous Strata: Monkman Pass Area, British Columbia. A A P G , 72, p 820-838. Levy, J.H., Day, S.J. and Killingly, J.S., 1997. Methane capacities of Bowen Basin coals related to coal properties. Fuel 76, 813-819. Lu, X . C . , L i , F.C. and Watson, A.T. 1995. Adsorption measurements in Devonian shales. Fuel, Vol. 74, 4, pp 599-603. Mahajan, O.P. and Walker, Jr., P.L., 1971. Water adsorption on coals. Fuel 50, 308-317. Mastalerz, M . , Gluskoter, H . and Rupp, J., 2004. Carbon dioxide and methane sorption in high volatile bituminous coals from Indiana, U S A . Int. J. Coal Geol. 60, 43-55. Mavor, M.J., Owen, L.B. and Pratt, T.J., 1990. Measurement and Evaluation of Coal Sorption Isotherm Data. Society of Petroleum Engineers, SPE 20728. 157-170. Montgomery, S.L., Jarvie, D . M . , Bowker, K . A . and Pollastro, R . M . 2005. Mississippian Barnett Shale, Fort Worth basin, north-central Texas: Gas-shale play with multitrillion cubic foot potential. A A P G Vol. 89 (2), p 155-175. Nishino, J., 2001. Adsorption of water vapour and carbon dioxide at carboxylic functional groups on the surface of coal. Fuel 80, 757-764. Prinz, D. and Littke, R., 2005. Development of the micro- and ultramicroporous structure of coals with rank as deduced from the accessibility to water. Fuel 84, 1645-1652. Prinz, D, Pyckhout-Hintzen, W. and 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. Ramos, S. 2004. The effect of shale composition of the gas sorption potential of organicrich mudrocks in the western Canadian sedimentary basin. M.Sc. Thesis. Department of Earth and Ocean Sciences, University of British Columbia. 192 p. 9  Unsworth, J.F., Fowler, C.S. and Jones, L.F. 1989. Moisture in coal. 2. Maceral effects on pore structure. Fuel 68, 18-26. Yalcin, E. and Durucan, S., 1991. Methane Capacities of Zonguldak coals and the factors affecting methane adsorption. Mining Science and Technology 13, 215-222. Yee, D., Seidle, J.P. and Hanson, W.B., 1993. Gas sorption on coal and measurement of gas content, in: Law, B.E., Rice, D.D. (Eds.), Hydrocarbons from coal. A A P G Studies in Geology, Chapter 9, A A P G , Tulsa, Oklahoma, 74101 USA, 203-218.  10  CHAPTER TWO  ON T H E EFFECTS OF PETROGRAPHIC COMPOSITION ON COALBED M E T H A N E SORPTION  2.1 INTRODUCTION  Coalbed methane reservoir characterisation is complex due to the high degree of heterogeneity and spatial variation in maceral composition (Bend, 1992). The ash content of a coal has a negative relationship with methane sorption capacity (Faiz et al., 1992; Yee et al, 1993; Crosdale et al, 1998; Laxminarayana and Crosdale, 1999) which implies that the organic matter is a key component in the ability to store methane in coalbed methane resources (CBM). However, the influence of petrographic composition of coal on the methane sorption capacity is not well understood. To complicate matters, coal rank has a strong influence on methane capacity and may mask the effects of the maceral composition (Yee et al., 1993; Levy et al, 1997). Excellent reviews on defining the maceral composition of coals can be found in Diessel (1992) and Taylor et al. (1998).  Research into the effect that petrographic composition has on methane capacity indicates that bright, vitrinite-rich coals have a higher capacity than dull, inertinite-rich coals at the same rank (Crosdale and Beamish, 1993; Lamberson and Bustin, 1993; Bustin and Clarkson, 1998; Crosdale et al, 1998; Clarkson and Bustin, 1999; Laxminarayana and A version of this chapter has been published/accepted for publication. Chalmers, G.R.L. and Bustin R . M . (2007) On the effects of petrographic composition on coalbed methane sorption. International Journal of Coal Geology, Vol 69: 299-304. 11  Crosdale, 1999; Mastalerz et al, 2004; Hildenbrand et al, 2006). Other workers have found no relationship or trends (Faiz et al, 1992; Carroll and Pashin, 2003). Due to a generally low liptinite content in coal, the effect of liptinite on methane capacity has not been fully examined. Surface area is inherently linked to the pore size distribution of a sample whereby the surface area progressively increases with declining pore size for a given pore volume. The reason vitrinite can store more methane than inertinite is because vitrinite is more microporous (Unsworth et al, 1989; Lamberson and Bustin, 1993; Beamish and Crosdale, 1995) and therefore has a higher surface area.  Low pressure gas adsorption analysis is used to measure the surface area and pore size distribution of coals and shales. Due to the low temperature, the five-point Brunauer, Emmett and Teller (BET) method (Brunauer et al., 1938) for N2 adsorption has been found only to measure the surface area of mesopores and some macropores (2 to 100 nm; Unsworth et al, 1989) in coals because the molecular thermal energy is too low to overcome the energy barriers within the micropore (< 2nm) (Marsh, 1989). Microporosity can be measured by CO2 adsorption even though the CO2 molecule is larger than the N2, because at higher temperatures (i.e. 273K) the CO2 molecule has greater thermal energy and can penetrate and adsorb onto surfaces located within the micropores of the coal. Microporosity is found to increase with rank (Gan et al, 1972; Clarkson and Bustin, 1996; Prinz and Littke, 2005; Prinz et al, 2004) and this is the reason why methane capacity increases with rank. Therefore, higher sorption capacities will be found in high-rank vitrinite-rich coals.  12  Research into coking properties of coals has revealed that not all inertinite is chemically inert but is a mixture of reactive, semi-reactive and non-reactive macerals (Diessel, 1983; Kruszewska, 1989; Taylor et al, 1998). The complex relationship between the petrographic composition of coal and methane sorption capacity could be related to the reactive semifusinite content. From mass balance calculations, the equations below (Eq. 1 and Eq. 2) have been created to determine the reactive, semi-reactive and the nonreactive portions of a coal (Taylor et al, 1998). Reflectance cutoff (R) between reactive and semi-reactive is determined by:  R = -0.62 + 2.92/?,., -0.91/?,.,  2  (1)  The reflectance boundary between semi-reactive and non-reactive is:  R = 0.10 + 2.28/?,.,-0.71/? ,  2  r  (2)  Where R is the random reflectance of telovitrinite. The difference between these three r?t  domains is due to the chemical structure of the macerals. Non-reactive macerals tend to have stronger cross-links between aromatics which do not break during heating and therefore do not react (Diessel, 1983). Mastalerz and Bustin (1997) found that semifusinite with low reflectances have comparable structures to vitrinite with respect to aliphatic side chain lengths and suggest that these are reactive semifusinite. Microporosity of coal is reported to be the low electron-density space between crosslinked macromolecular structures (Marsh, 1989). Therefore, i f the reactive semifusinite is 13  structurally (chemical) similar to vitrinite, then the microporosity should also be similar at a given rank. The boundaries between non-reactive and reactive macerals can be determined by applying the above equations to the whole-coal reflectogram of a sample. Whole coal reflectograms illustrate the reflectance distribution of macerals within a sample and typically have a peak at mean random reflectance of telovitrinite with a positive skewness of high reflectance for inertinites. The reflectance cut-off equations are derived from the positive correlation between mean random reflectance of telovitrinite and the thermoplastic properties of the coal (Taylor et al., 1998). However at the rank of medium volatile bituminous, the relationship diverges as the thermoplastic properties decline with increasing rank. For this reason, the non-reactive/reactive reflectance cut-off is not applicable to coals that are higher rank than medium volatile bituminous.  The purpose of this paper is to compare vitrinite- (vitrain) and inertinite-rich (durain) samples obtained from a suite of coals to compare their methane capacities. Location of coal samples are not relevant to this study as the composition of the coal is being evaluated, not a potential C B M resource. Rank is the dominant control of methane capacity and samples are sub-divided into three groups - sub-bituminous, bituminous and higher rank. We postulate that in low-rank coal there is no difference in sorption capacity between bright and dull samples and with increasing rank, the bright coals will have a greater methane capacity than dull coals. A variety of naturally concentrated liptinite-rich coals and shales have also been selected to understand the role of liptinite in methane sorption capacities and will be examined here separately. This paper will also examine the difference in methane sorption capacity between dull coal samples and i f there is any  14  relationship between reactivity of inertinite and sorption capacity. We postulate that a reactive inertinite is more microporous than non-reactive inertinite and therefore dull samples that contain a higher portion of reactive inertinite will have higher gas capacities.  2.2. ANALYTICAL METHODS  Coals and organic-rich shales used in this study are from locations within North America. Methane sorption capacities were determined for 23 samples with seven coals separated into bright and dull components by hand picking lithotypes. The rank of these seven coals ranges between subbituminous C through to meta-anthracite. To understand methane sorption capacity of liptinite-rich coals, samples were taken of alginite-rich boghead coal, gilsonite, oil shale, rhythmite (diatomite) and bitumen (solid). The ash, moisture and rank of these samples are presented in Table 2.1. Samples are subdivided into four groups, separated into liptinite-rich and liptinite-poor samples with the latter being further subdivided into sub-bituminous, bituminous and higher rank samples.  Methane capacity of moisture-equilibrated samples was determined by a high pressure (0 to 9MPa) volumetric sorption apparatus. A l l analyses were performed under isothermal conditions at 30°C ± 0.1 °C. Gas volumes are measured in cubic centimeters per gram of rock (cm /g). Samples were stage ground in a ring mill to pass through a 60 mesh sieve 3  and placed in an atmosphere over a saturated solution of potassium sulphate at 30°C to obtain equilibrium moisture ( A S T M D1412-04). Samples are in equilibrium with the atmosphere when the weight of the sample becomes constant. Moisture was measured by  15  oven-drying weight-loss calculations. Analyses of ash contents of samples were performed in accordance with A S T M D3174-04. To compare and contrast the petrographic composition with methane capacity, all samples are dry and ash-free basis.  Maceral analysis was performed in accordance with AS 2856.2-1998 based on a total of 500 points counted for each sample and reported as a volume percent. Mean random reflectance of telovitrinite (50 points) was performed by the procedure set in A S T M D2798-99 standard. Whole-coal reflectograms were performed on dull coal samples using the standards for maceral analysis and random reflectance. A total of 300 reflectance measurements were made on each sample.  The mesoporous surface area of each sample was determined by Micromeritics A S A P 2010 using N2 gas adsorption at low temperature and pressure (77K and < 127 kPa) and the five-point BET method (Unsworth et al., 1989; Marsh, 1989). CO2 adsorption was also performed to determine the micropore volume using the cross-sectional area of the CO2 molecule of 0.253 nm and at a temperature of 273K. The micropore volume is an 2  equivalent measurement of the surface area of both mesopores and micropores by CO2 adsorption. Samples were degassed at 105°C with the exception of the gilsonite and bitumen which were degassed at 40°C for a period between 12 hours and two days depending on the volatility of the sample. Repetitive helium dosing and evacuation were performed on samples that outgassed for periods longer than 12 hours. The repetitive dosing accelerates the outgassing of volatiles within the microporous structure of the sample.  16  2.3. RESULTS  2.3.1 Maceral Analysis  The results of the maceral analyses are shown in Tables 2.2 to 2.5. Mineral content is determined by petrographic analysis. Separating coals into bright and dull samples was successful for most coals except for the Coalmont coal. The Coalmont dull sample has a higher detrovitrinite content compared to the bright sample (Table 2.4). For the bright samples, the vitrinite content ranges between 80 vol.% and 97.4 vol.% while the dull samples contain inertinite concentrations between 35.2 vol.% and 73.8 vol.%. The liptinite-rich samples have liptinite contents ranging between 66.6 and 100 vol.%. The gilsonite and bituminite samples are regarded as 100% exsudatinite (Table 2.5) as described and defined by Taylor et al. (1998). The oil shale and rhythmite samples contain significant portions of matrix bituminite (86.7 and 99.8 vol.%) while the two boghead coals have alginite contents of 63.1 and 91.6 vol.%. A higher detrovitrinite content is the reason for the lower alginite content in sample TY-29 (Table 2.5). Telovitrinite is a significant maceral in all bright coal samples with contents greater than 42 vol.% (Table 2.3 and 4). 2.3.2 Methane Sorption Capacities  17  The methane sorption isotherms of the four sample groups are shown in Figures 2.1 to 2.4. For comparison, the methane sorption capacity at a pressure of 6 MPa for each sample is shown in Table 2.6. The amount of methane sorbed ranges between 0.5 and 23.9 cm /g. The higher-rank coals, designated Canmore Bright, Dull, and anthracite, have 3  the highest methane capacities. Among the liptinite-rich coals and shales the two alginiterich bogheads coals have the highest methane sorption capacities.  2.3.3 Surface Area and Micropore Volumes  The micropore volumes from CO2 adsorption and mesoporous surface area from N2 adsorption are shown in Table 2.7. The mesoporous surface area ranges between 0.01 and 7.9 m /g with the micropore volumes between 0.46 and 15.6 cm /100 g. A plot of the 2  3  surface area derived from N2 adsorption and micropore volume (Fig. 2.5) illustrates that with higher micropore volume there is a decrease in the surface area measured within the mesopore size range, as expected.  18  2.3.4 Whole Coal Reflectograms  Whole coal reflectograms for the subbituminous and bituminous dull coals are illustrated in Figures 2.6A to C, with the exception of the Canmore coal as this coal's rank is above medium volatile bituminous. The dull samples of the subbituminous coals show typical reflectogram profiles (Fig. 2.6A and B). The Luscar, X24 and P63 coals have the highest portion of non-reactive inertinite (their reflectograms have the largest positive skewness). The Coalmont coal contains low-reflecting vitrinite and inertinite illustrated by its leptokurtic distribution and has no non-reactive inertinite according to its cut-off value. Both the Genesee and F82 coals have lower non-reactive inertinite contents and the Gething coal has an intermediate reactive content. For each reflectogram, the boundary for reactive and non-reactive inertinites where the percentage of reactive macerals has been calculated using Eq. 2 (Table 2.6). A negative trends exist between the non-reactive inertinite content with methane sorption capacity and micropore volume (Fig. 2.7).  2.4. DISCUSSION  Since rank is a dominating control on methane capacity illustrated by the strong positive relationship between sorption capacity and rank (Fig. 2.8), samples are compared here within subbituminous, bituminous and higher-rank groups in an attempt to eliminate effects of rank. Liptinite-rich samples are also discussed separately due to their contrasting petrographic composition compared to the liptinite-poor coals.  19  2.4.1 Subbituminous Coals  There are no significant trends found with the subbituminous coals when comparing methane sorption capacity with rank, ash content, mesoporous surface area or micropore volume. There is a weak positive relationship between vitrinite and telovitrinite with methane capacity except for the Luscar Bright sample (Fig. 2.9). The relationship is poor due to both bright and dull samples having similar methane sorption capacities (Fig. 2.1; Table 2.6). There is no difference in methane capacity between coals that contain 50-60 vol.% vitrinite compared to coals that contain over 90 vol.% vitrinite (Fig. 2.9). The Genesee and F82 coals have the highest gas capacities of the subbituminous coal suite, with their bright samples having slightly higher capacities than their dull counterparts. The dull samples of X24 and Luscar coals have higher gas capacities than their bright samples. The Luscar bright and dull samples have the lowest capacities and also the biggest difference between coal pairs. Telovitrinite content has a weak positive relationship with methane capacity with the exception of the Luscar bright sample but there are dull samples that have high methane capacities and low telovitrinite contents (i.e. Genesee and F82). Micropore volumes are greater for bright samples in comparison to their dull counterparts, however, the micropore volume or methane capacity do not increase with rank (Fig. 2.10). The larger micropore volumes for the Genesee samples results in greater methane capacities (Fig. 2.10) even though it has the lowest rank. The botanical origins of the precursors to vitrinite or the depositional conditions could control the microporosity of low rank coals.  20  2.4.2 Bituminous Coals  For the bituminous coal suite, all bright samples have higher methane capacities and micropore volumes compared to their dull sample counterparts (Fig. 2.11). The difference between the three bituminous pairs is greater than the difference between bright and dull samples in the subbituminous coal suite (Table 2.6). A positive relationship exists between vitrinite and telovitrinite contents with methane capacity of the bituminous coal samples, however, there is a pronounced difference between high to medium volatile coals and low volatile bituminous to anthracite coals (Figs 2.11 and 2.12). There is little variation between the methane sorption capacities of the bituminous coals with respect to the vitrinite and telovitrinite contents which suggests that petrographic composition is not the most significant influence on methane capacity. Rank appears to be the strongest influence in the bituminous suite of coals. The Coalmont Bright and Dull samples differ significantly in the amount of telovitrinite and detrovitrinite (Table 2.2) and the higher methane capacity of the bright sample could be explained by the higher telovitrinite content and lower semifusinite and detrovitrinite contents (Table 2.4). The difference in the pore size distribution illustrates the reason the Coalmont Bright sorbs more methane than the dull counterpart. Higher micropore volume and lower mesoporous surface area for the Coalmont Bright sample compared to the Coalmont Dull sample is due to the higher telovitrinite content (Table 2.7). Mastalerz et al. (2004) observed samples with high carbon dioxide capacities have higher telovitrinite contents but methane capacities were found to have no relationship.  21  Compared to the anthracite sample, the Canmore coal samples have similar methane capacities but lower than expected micropore volumes (Fig. 2.11). The micropore volumes are similar to other bituminous samples which sorb less than half the volume than the Canmore coals. Pore geometry may influence the measurement of pore size distribution where gases at low pressure (CO2 and N2 adsorption analyses) cannot access micropores with narrow tortuous pore throats but are accessible to gas under higher pressures (methane adsorption analyses, < 9 MPa).  2.4.3 Higher Rank  The anthracite sample has the second highest methane sorption capacity with over 23 cm /g at 6 MPa (Fig. 2.3 and Table 2.6) while the natural coke has a capacity of 0.5 3  cm /g. The difference between these two samples is illustrated in Fig. 2.3. The anthracite sample has the highest micropore volume which explains the high methane capacity of the sample.  To calculate the volume of methane sorbed (sorption capacity) the volume of the sample canister is reduced by the void volume which includes the headspace, intergranular spaces and the total porosity of the sample as well as space occupied by sorbed gas. By eliminating the void volume, the change in pressure over time is a result of the volume of methane that is sorbing onto the coal. During void volume measurements for the coke sample, using the helium expansion technique, an increasing trend between differential  22  pressure and cell pressure was identified (Fig. 2.13). The differential pressure is the difference between the individual pressures of the reference cell and the sample cell. The trend in Fig. 2.13 is caused by a pressure drop in the sample cell with respect to the reference cell. The pressure reduction indicates the helium is more effectively accessing the restricted pores with tortuous pathways as the cell pressure increases. This trend resulted in an overestimation of the void volume and a negative calculation would occur for methane sorption capacity because the void volume includes space that was not available to methane.  Comparing the surface area analysis of the coke to other samples, the high mesoporous surface area and low micropore volume (Fig. 2.11) illustrates there is a development of meso- and macropores during the thermal alteration of the coal and the microporosity of the coke is too small to be measured by CO2 at low pressures. From the helium expansion trends observed, it appears the pore structure of the coke acts as a molecular sieve that allows helium through but not larger molecules such as CH4, N2 or CO2 and therefore the pore diameter must be smaller than 0.37 nm (kinetic diameter of CH4 and N2) but greater that 0.26 nm (diameter of He). Other cokes are known to have high gas capacities and this may be related to their textures and microporosity.  For subbituminous to coke samples, there is a positive relationship between the vitrinite content and the micropore volume (Fig. 2.14) and a concomitant increase in the methane capacity. The positive relationship between methane capacity and the other two parameters is weaker compared to relationship between the vitrinite content which is due  23  other factors like rank having a larger influence. The significant difference in methane capacity between the Canmore coals and the anthracite sample is due to their higher rank.  2.4.4 Liptinite-rich Samples  To gain an understanding of how methane is stored in liptinite-rich samples, the micropore volumes are determined for comparison with the mesoporous surface area determined by N2 adsorption and also with pore size data of the other coal suites. There is a positive relationship between the micropore volume and methane capacities of the liptinite-rich samples (Tables 6 and 7), however the low micropore volumes but high methane sorption capacities of liptinite-rich samples, as compared to the other coal suites discussed earlier, indicate that the methane is in solution. Both low values for N2 (mesopores) and CO2 (micropores) adsorption at low pressures indicates liptinite does not have high surface areas. Hence, it is postulated that methane is forced into solution under higher pressures during methane sorption experiments (i.e. < 9 MPa). Figure 2.9 illustrates the low microporosity of the liptinite-rich samples compared the other coal suites with respect to their ability to sorb methane under pressure. Henry's Law identifies the positive relationship between concentration of gas dissolved in solution with pressure and the gas's solubility coefficient. Studies have reported the solubility of hydrogen (Lai et al, 1999; Cai et al, 2001) and methane (Svrcek and Mehrotra, 1982; Upreti, 2000) within liquid to semi-solid bitumen increase with pressure. This process is an analogue to the methane dissolving into the liptinite-rich samples. The near linear shape of the  24  isotherm compared to the other coal suites also illustrates the solution process in the liptinite-rich samples and appears to follow Henry's Law of increasing dissolved gas content with increasing pressure. This is not diagnostic observation for the process of gas into solution as similar isotherms are seen for liptinite-poor shale samples, but is reflecting the complex pore size distribution. Classic Type I isotherms show a decrease in the amount of gas adsorbed at higher pressures as all available adsorption sites become occupied and results in initial sharp linear rise and plateaus. The liptinite-rich sample isotherms do not plateau within the higher pressures (i.e. 8 MPa) which indicates the gas molecules are not sorbing to surfaces but is in solution.  Similar methane sorption isotherms (Fig. 2.1) and micropore volumes (Table 2.7) occur between the pairs of alginite-rich coals, the exsudatinite-rich samples, and the ash-rich samples. The two alginite-rich coals (boghead coals), along with the gilsonite and bitumen samples, show the highest capacities whereas the oil shale and rhythmite samples have the lowest sorption volumes. From the maceral analyses, the two boghead coal samples vary in the amount of liptinite, with sample TY-2663 having less liptinite (66.6 vol.%) due to a higher content of vitrinite and inertinite compared to sample TY-29 (95.6 vol.%o), however their methane capacities and micropore volumes are very similar. The higher contents of vitrinite and inertinite in TY-2663 has not reduced its ability to sorb methane but there is an increase in mesoporosity which could be contributed by the inertinite content. The boghead coals illustrate that mesoporosity is not important when gas is absorbing into a sorbent (i.e. gas dissolving into a solution).  25  The oil shale and rhythmite samples are ash-rich even though the maceral analyses show high liptinite contents (Table 2.2) in the form of matrix bituminite (Table 2.1). Matrix bituminite results from adsorption of bituminous substances onto the clay mineral surfaces (Taylor et al, 1998) and can be difficult to distinguish from mineral matter under reflected light. Even on an ash-free basis, the oil shale and rhythmite samples have the lowest methane capacities illustrating matrix bituminite cannot store as much methane as alginite or exsudatinite. The rhythmite has a higher mesoporous surface area compared to the oil shale which indicates the matrix bituminite has not reduced the surface area of the mineral matter as found for the oil shale and the sorption sites are still available in the mesopores. Figure 2.15 shows the ash-rich samples have lower microporosity compared to the other liptinite-rich samples. The mesoporosity is also higher in the ash-rich samples and also in the boghead sample TY-2663 compared to the other liptinite-rich samples.  2.4.5 Full Coal Reflectograms  Mesoporous to macroporous material contains less surface area than microporous material. The negative relationship between non-reactive inertinite content and methane sorption capacity is due to the positive relationship between inertinite and macroporosity. By increasing the non-reactive inertinite, there is a decrease in microporosity and relative increase in meso- and macroporosity of the coal which reduces the surface area for sorption (Fig. 2.7). Reactive inertinite are chemically and structurally similar to vitrinite  26  and are more microporous than non-reactive inertinite resulting in an increase in the methane sorption capacity of the dull coal. Reactivity of inertinite, especially semifusinite, should be considered when assessing C B M potential of dull coals and also when comparing petrographic composition of coals and its affects on methane capacity.  2.5. CONCLUSIONS  • The highest rank coals have the greatest methane capacity (Canmore coals and the anthracite) with more than 20 cm /g on a dry, ash free basis. The alginite-rich coals 3  have the next highest sorption capacities and are higher than bituminous-rank coals due to methane in solution. Coke is meso- to macroporous and contains micropores too small to be accessed by methane.  •  Contrasting methane sorption processes occur between liptinite-rich samples  (solution gas) and liptinite-poor coals (physical sorption) and therefore liptinite-rich samples need to be independently assessed for C B M potential.  •  Dull samples can have higher gas capacities than bright samples at lower rank  levels and all bright samples have a higher gas capacity than dull samples at higher rank. The difference in methane capacity between bright and dull pairs increases with rank.  27  • The maceral composition is more important in high rank coals because even the vitrinite is macroporous in low rank coals.  • Methane sorption shows a moderate positive relationship with microporosity and both increase with rank. Rank is a more significant factor. Microporosity positively correlated with vitrinite content, in particular, the telovitrinite (structured vitrinite) content.  • Between subbituminous and medium volatile bituminous rank, dull coals with lower non-reactive inertinite contents have a greater gas capacity because of higher micropore volumes. Reactive inertinite should be considered when assessing dull coals as a C B M resource.  28  10  •  G e n e s e e Bright G e n e s e e Dull Luscar Bright Luscar Dull X24 Bright X 2 4 Dull F82 Bright F82 Dull  o T  8^  V  • •  CTJ X3  b> 6H  • O  T3  • i  CD  o  O CO  o •  <D  c  2 J.  v  •  V V  V  ft  2  4  6  Cell Equilibrium Pressure (MPa) Fig. 2.1: Methane sorption capacity for bright and dull pairs for subbituminous coals, on an ash free and dry basis. Open shapes are dull samples and filled shapes are bright samples.  29  30  25  • o T V  •  •  CO  b) 20 o o  O  Canmore Bright Canmore Dull Coalmont Bright Coalmont Dull P63 Bright P63 Dull Gething Dull  o  T3  CD .O i_  o  o  15 A  o  o  CO  cu co 10  o o  0 0" 0  2  4  6  8  Cell Equilibrium Pressure (MPa) Fig. 2.2: Methane sorption capacity for the bituminous rank coals on ash free, dry basis. Open shapes are dull samples and filled shapes are bright samples. Note the large difference between the low volatile bituminous Canmore coals and the other bituminous coals.  30  100  CD "O  10 H  0> O T3  O  i_ O CO 0) c CO  "25  0.1  • o  Anthracite Coke  0.01 2  4  6  Equilibrium Cell Pressure (MPa) Fig. 2.3: Methane sorption isotherms for the anthracite and natural coke samples on a dry and ash free basis. Note the Y-axis has been changed to log scale.  31  14  12 03 "O  10  CO  • o • V  • •  Gilsonite Boghead T Y - 2 9 Oil Shale Rhythmite Boghead TY-2663 Ground Bitumen  o  •  84 o  "O  a> jQ  o  CO (D c CD  «  6  4  • o  s  o  •  V  o o  ~1  6  Cell Equilibrium Pressure (MPa) Fig. 2.4: Methane sorption capacity for liptinite-rich coals and shales. On a dry, ash free basis. Note alginite-rich coals have similar methane capacities and same for the exsudatinite -rich samples and also the two mineral-rich samples.  32  8H • O T  S. CO <D  6  Liptinite-rich samples Sub-bituminous coals Bituminous to coke samples  •!  CD O  •g CO  h-  UJ CO  O  4  6  o  8  10  12  14  16  Micropore Volume (cc/ 100g) Fig. 2.5: A negative relationship exists between the micropore volume and mesoporous surface area of a sample. Liptinite-rich samples do not have high surface area nor microporosity with the exception of the high surface area in the rhythmite because of the high ash content.  33  Reflectograms of Genesee and Luscar Dull Coals  «V  s\tf>  1?  \ * V\f  Random Reflectance (%)  A  Reflectograms of F82 and X24 Dull Coals  <V'«f  T?»*  ^ J "  ^  Random Reflectance (%)  B Reflectograms of Coalmont, P63 & Gethlng Dull Coals 35.0 30.0 —  25.0  M  3?  Gething Dull P63 Dull Coalmont Dull  Coalmont cut-off at 1.37%  * 20.0 y  Gething cut-off at 1.83%  ci  5 15.0  P63 cut-off at 1.34%  i  it 10.0 5.0 1  «V *V «V  V -vV vV v*  Random Reflectance (%)  Fig. 2.6: Reflectogram of the dull portions of subbituminous coals to coke showing the reactive inertinite cutoffs.  Fig. 2.7: The negative relationship between micropore volume, methane sorption capacity and the percentage of non-reactive inertinite in the dull subbituminous and bituminous coals, excluding Canmore Coal due to reflectance cut-off equations not being suitable for coals above the rank of medium volatile bituminous.  35  25  CD  73 cn 20 H  • O  Sub-bituminous coals bituminous coals to coke  E o CD D_  15 H  CD CD C  £o  Q.  10 A  i_  O CD  O CO CD c CD  • •°  O  F  I  I  1  I  1  -  10  0.1  Rank (%R ) rt  Fig. 2.8: The strong positive relationship between rank and methane sorption capacity for samples except liptinite-rich samples. Mean random reflectance (%Rrt) of telovitrinite was used to determine the rank of each sample. The effect rank has on methane sorption can be easily seen. Note the logarithmic scale for rank. N = 15.  36  7.5  • •  7.0 CO 6.5 03 Q_  CD  6.0 -  •  •  CO o  03 CL  s CD C CO JO  •  •  5.5 -  •  •  5.0 -  •  •  Vitrinite Telovitinite  4.5 4.0 H 3.5  —i—  20  40  60  80  100  Maceral Content (vol.%) Fig. 2.9: There is a weak positive relationship that exists between the vitrinite or telovitrinite contents and methane sorption capacity of the subbituminous samples.  37  14 • • i 12  Methane C a p a c i t y (cc/g) I Micropore V o l u m e (cc/100g)  • H  M e s o p o r o u s S u r f a c e A r e a (m /g) 2  10 Rank —  •  6 A  ,  n  4 A  24 •  y  I  of  1 1  •  i  i  4?  Fig. 2.10: Comparison between micropore volume, mesoporous surface area and methane capacity for both bright and dull samples of the subbituminous coal suite. Rank increases from the left to the right. Both Genesee samples have the highest methane capacity due to their high micropore volumes.  38  25  Rank  Methane Capacity (cc/g) 20  Microporosity V o l u m e (cc/1 OOg) M e s o p o r o u s Surface A r e a (m /g) 2  15 4  10 A  «F*  «.<°  <F  tP  <?£  jf ^ J°  <z  Fig. 2.11: Comparison between the micropore volume, mesoporous surface area and methane capacity for the bituminous coals, anthracite and coke samples. A l l bright samples have a greater micropore volume and methane capacity than their dull pairs. The high volatile and medium volatile bituminous coals have similar capacities when compared to the low volatile bituminous Canmore coals and anthracite samples.  39  26 _  24  •  O  o  CO  •  22  a. 2  co >>  20  • •  Vitrinite Telovitrinite  V / A  Q. CO  O c  10  A  •  o "5. i o  CO  CD  •  c  CO  •  •  • —i—  i  0  20  40  60  80  100  120  Maceral Content (vol.%) Fig. 2.12: A positive relationship exists between both vitrinite and telovitrinite with the methane sorption capacity, the lower data points are from the high and medium volatile coals and the higher data points are the low volatile bituminous Canmore coals and anthracite samples.  40  0.542  0.522  Equilibrium Cell Pressure (MPa)  Fig. 2.13: Increase in the differential pressure during void volume calculation of the coke through helium expansion analysis. The coke indicates that more helium is diffusing into the sample with higher pressures, however, the microporosity is too small for the methane to access as indicated by the methane sorption capacity of only 0.5 cm /g. The differential cell pressure is the measurement of the pressure differences between the reference and sample cell. Therefore, an increase in differential pressure, indicates there is a drop in pressure within the sample cell.  41  Fig. 2.14: There is a broad positive relationship between micropore volume, methane capacity and vitrinite content subbituminous coals to coke samples. By increasing the vitrinite content of a sample, the microporosity and surface area of the coal increases which provides more sorption site for methane to be stored on. Note the large difference in methane capacity for the Canmore coals and the anthracite sample due to rank.  42  25 E  «T 20 H  D_ CD  • O T  03  >,  15 H  o CD Q_ CD  O c o  10  T  • o CO  Liptinite-rich samples Sub-bituminous Coals Bituminous coals and higher rank  O  O  O  CD  c CD JC -*—' CD  10  12  14  16  18  Micropore Volume (cm /100 g) Fig. 2.15: A broad positive relationship exists between micropore volume and methane sorption capacity. Liptinite-rich samples show high methane capacities but low micropore volumes which are attributable to the gas being held in solution.  43  Table 2.1: Properties of the coal and organic-rich shale samples. S  a  m  P  l  e  1  0  Rank  %R  r t  M S r e ^ o  A  s  h  w  t  Liptinite-rich coals and shales Gilsonite Bitumen Oil Shale Rhythmite Boghead TY-2663 subB Boghead TY-29 -  0.382 0.447 -  1.5 0.9 8.3 5.4 1.6 1.3  60.2 75.0 10.4 7.0  Subbituminous coals G e n e s e e Bright G e n e s e e Dull Luscar Bright Luscar Dull F82 Bright F82Dull X24 Bright X24Dull  subC subB sub A subA -  0.406 0.432 0.540 0.585 -  11.9 11.5 14.5 13.9 10.0 9.1 9.7 9.0  3.7 7.3 7.2 9.9 10.5 20.1 6.8 15.3  Bituminous coals P63 Bright P63Dull Coalmont Bright Coalmont Dull Gething Dull Canmore Bright Canmore Dull  hvCb hvBb mvb Ivb -  0.696 0.721 1.224 1.890 -  4.3 3.3 6.7 6.7 3.5 3.1 2.8  5.1 19.0 2.1 4.9 19.0 2.3 8.7  %  0.5  Higher rank and altered coals Anthracite an 4.558 5.2 5.3 Coke rria 6.560 24 7.0 Note: subB = subbituminous B; subC = subbituminous C; subA = subbituminous A; hvCb = high volatile bituminous C; hvBb = high volatile bituminous B; mvb = medium volatile bituminous; lvb = low volatile bituminous; an = anthracite; and ma = meta-anthracite.  44  Table 2.2: Maceral Group Composition of samples (minerals included). Sample ID  Vitrinite (vol.%)  '"Jjj^j  8  Liptinite (vol.%  Minerals (vol.%)  Liptinite-rich coals and shales Gilsonite Bitumen Oil Shale Rhythmite 0.4 Boghead TY-2663 21.6 Boghead TY-29 3.8  0.2 11.0 0.6  100.0 100.0 98.6 71.4 66.6 95.6  Subbituminous coals G e n e s e e Bright G e n e s e e Dull Luscar Bright Luscar Dull F82 Bright F82Dull X24 Bright X24Dull  94.6 56.6 90.6 24.4 89.2 47.6 80.0 30.6  2.8 35.2 5.0 67.8 8.8 38.6 12.6 62.0  1.8 7.0 3.4 4.2 0.2 3.6 3.8 2.2  0.6 1.0 0.8 2.0 1.8 10.2 3.6 5.2  Bituminous coals P63 Bright P63Dull Coalmont Bright Coalmont Dull Gething Dull Canmore Bright Canmore Dull  81.6 29.4 97.4 91.4 14.6 95.8 43.2  14.2 58.6 0.6 3.8 73.8 3.8 55.2  2.0 4.2 1.2 4.0 -  2.0 7.6 0.8 0.4 11.6 0.4 1.0  9.4 n/a  n/a  1.4 n/a  Higher rank and altered coals Anthracite 98.2 Coke n/a  1.4 28.0 0.8  45  Table 2.3: The volume percentage of maceral composition of subbituminous samples on a mineral matter free basis Mac Mic SF. Fusinite Inertod. Sample ID TV. DV. Sporinite Resinite Other liptinite. 0.2 1.4 1.2 0.2 1.0 Genesse Bright 87.1 8.0 0.8 5.5 10.1 36.2 0.8 0.2 20.0 Genesse Dull 21.0 6.3 0.6 2.6 2.6 0.2 1.8 Luscar Bright 84.7 6.7 0.8 0.4 1.2 6.1 4.3 Luscar Dull 19.2 4.1 0.2 58.8 5.7 1.6 6.7 0.6 F82 Bright 79.2 11.6 0.2 0.4 8.0 31.8 2.0 F82 Dull 20.7 32.3 3.3 0.7 0.4 0.2 1.0 2.9 1.5 8.5 X24 Bright 56.8 26.1 2.5 1.5 6.5 8.0 2.1 0.2 48.8 X24 Dull 16.5 15.8 TV. = telovitrinite; D V . = detrovitrinite; Other Lipt = other liptinites; SF. = semifusinite; Inertod. = inertodetrinite; Mac = macrinite; Mic = micrinite.  Table 2.4: The volume percentage of maceral composition of bituminous and higher rank samples on a mineral matter free basis Mic Mac SF. Fusinite Inertod. TV. DV. Sample ID Sporinite Resinite Other liptinite. 1.0 2.7 0.4 0.2 10.2 0.6 P63 Bright 42.0 41.2 1.6 0.9 0.9 20.3 2.2 0.2 41.3 P63 Dull 6.7 25.1 2.4 0.6 91.7 6.5 0.4 Coalmont Bright 0.8 0.2 3.8 Coalmont Dull 34.7 57.0 1.4 2.6 1.1 0.9 1.6 30.5 3.2 0.4 49.8 Gething Dull 13.3 1.0 1.8 1.0 72.9 23.3 Canmore Bright 16.4 0.6 2.4 37.0 Canmore Dull 6.9 36.8 2.4 0.2 6.9 Anthracite 64.9 25.6 Natural coke TV. = telovitrinite; D V . = detrovitrinite; Other Lipt = other liptinites; SF. = semifusinite; Inertod. = inertodetrinite; Mac = macrinite; Mic = micrinite. ON  Table 2.5: The volume percentage of maceral composition of liptinite-rich samples on a mineral matter free basis. Sample ID TV. DV. Alginite M B . Exsud. Resinite Other SF. Fusinite Inertod. Other Lipt. Inert. Gilsonite . . . . 100 Bitumen . . . . 100 Oil shale 0.2 99.8 . . . . . . . Rhythmite 0.6 86.7 9.4 3.1 0.3 Boghead T Y 2663 1.8 20.0 63.1 0.2 3.9 4.9 1.2 3.3 1.6 Boghead T Y 29 2.2 1.6 91.6 3.0 1.0 0.4 02 -_ TV. = telovitrinite; DV. = detrovitrinite; M B . = matrix bituminite; Exsud. = exsudatinite; Other Lipt = other liptinites; SF. = semifusinite; Inertod. = inertodetrinite; Other Inert. = Other Inertinites.  Table 2.6: Methane capacities of all samples at 6 MPa, the capacity differences between the bright and dull samples of the subbituminous and bituminous coal suites (negative number indicates greater capacity for dull sample), and the percentage of reactive macerals (vitrinite+liptinite+reactive inertinite) in dull samples. C H sorbed at 6MPa, dry & ash free (cm /g) 4  Sample ID  3  Difference between Bright and Dull Pairs (%)  Non-reactive Macerals (%)  4.0  17.4  -24.4  33.7  0.8  19.6  1.5  31.3  10.0  32.4  15.0 n/a  0 25.4  Liptinite-rich samples Gilsonite Bitumen Oil Shale Rhythmite Boghead TY-2663 Boghead TY-29  8.97 9.57 3.82 5.58 11.69 11.43  Subbituminous coals Genesee Bright Genesee Dull Luscar Bright Luscar Dull F82 Bright F82Dull X24 Bright X24Dull  7.20 6.91 3.83 4.77 7.10 7.05 5.80 5.89  Bituminous coals P63 Bright P63Dull Coalmont Bright Coalmont Dull Gething Dull Canmore Bright  8.07 7.26 9.43 8.02 7.50 23.88  Canmore Dull  21.71  9.1  n/a  Higher rank Anthracite Coke  23.79 0.50  -  n/a n/a  48  Table 2.7: Surface area and microporosity of coals and organic-rich samples. Micropore Voh BET Mesoporous Surface Area Sample ID (cm /100g) by N2 adsorption (m /g) Liptinite-rich samples 1.02 Gilsonite 0.07 1.16 Bitumen 0.01 0.46 Oil Shale 0.63 0.57 Rhythmite 5.34 1.83 0.94 Boghead TY-2663 Boghead TY-29 0.02 1.63 2  3  Subbituminous coals Genesee Bright Genesee Dull Luscar Bright Luscar Dull X24 Bright X24 Dull F82 Bright F82 Dull  0.27 2.00 1.05 1.07 0.49 0.13 1.56 3.03  11.62 8.19 6.96 6.18 7.20 5.65 9.40 5.39  Bituminous coals P63 Bright P63 Dull Coalmont Bright Coalmont Dull Gething Dull Canmore Bright Canmore Dull  0.08 0.90 1.33 3.16 2.63 0.03 0.02  5.69 2.78 8.23 7.08 4.98 9.12 7.42  Higher rank Anthracite Coke  0.03 7.90  15.56 1.12  2.6 REFERENCES  A S 2856.2-1998. 1998. Australian Standard 2486.2. Coal petrography, Part 2: Maceral Analysis. Standards Association of Australia, North Sydney, NSW, Australia A S T M D l 412-04, 2004. Test for equilibrium moisture of coal at 96 to 97% relative humidity and 30°C.  49  A S T M D2799-05, 2005. 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The use of reflectance to determine maceral composition and the reactive-inert ratio of coal components. Fuel 68, 753-757. Lamberson, M . N . , Bustin, R . M . , 1993. Coalbed Methane Characteristics of Gates Formation Coals, Northeastern British Columbia: Effect of Maceral Composition. A A P G Bulletin 77, 2062-2072. Lai, D., Otto, F.D., Mather, A . E . 1999. Solubility of hydrogen in Athabasca bitumen. Fuel 78, 1437-1441. Laxminarayana, C , Crosdale, P. J., 1999. Role of coal type and rank on methane sorption characteristics of Bowen Basin, Australia coals. International Journal of Coal Geology 40, 309-325. Levy, J.H., Day, S.J., Killingly, J.S., 1997. Methane capacities of Bowen Basin coals related to coal properties. Fuel 76, 813-819. Mastalerz, M . , Bustin, R . M . , 1997. Variation in the chemistry of macerals in coals of the Mist Mountain Formation, Elf Valley coalfield, British Columbia, Canada. International Journal of Coal Geology 33, 43-59. Marsh, H., 1989. Adsorption methods to study microporosity in coals and carbons - A critique. Carbon 25, 49-58. Prinz, D., Littke, R., 2005. Development of the micro- and ultramicroporous structure of coals with rank as deduced from the accessibility to water. Fuel 84, 1645-1652. 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.  51  Robert, P., 1985. Organic Metamorphism and Geothermal History; Microscopic study of organic matter and thermal evolution of sedimentary basins. Sedimentology and Petroleum Geology. Elf-Aquitaine and D. Reidel Publishing Company, Dordrecht, Boston, Lancaster, Tokyo. Svrcek, W.Y., Mehrotra, A . K . , 1982. Gas solubility, viscosity and density measurements for Athabasca bitumen. Journal of Canadian Petroleum Technology 21 (4) 31-38. Taylor, G.H., Teichmuller, M . , Davis, A . , Diessel, C.F.K., Littke, R., Robert, P., 1998. Organic Petrology. A new handbook incorporating some revised parts of Stach's Textbook of Coal Petrology. Gebruder Borntraeger, Berlin, Stuttgart. 704 pages. Unsworth, J.F., Fowler, C.S., Jones, L.F., 1989. Moisture in coal. 2. Maceral effects on pore structure. Fuel 68, 18-26. Upreti, S.R., 2000. Experimental measurement of gas diffusivity in bitumen: Results for CO2, CH4, C2H6 and N2. Ph.D. Dissertation University of Calgary, Alberta, Canada. Yee, D., Seidle, J.P., Hanson, W.B., 1993. Gas sorption on coal and measurement of gas content. In: B.E. Law and D.D. Rice (Eds.), Hydrocarbons from coal. A A P G Studies in Geology, Chapter 9, A A P G , Tulsa, Oklahoma, 74101 USA, 203-218.  52  CHAPTER THREE  T H E ORGANIC M A T T E R DISTRIBUTION AND METHANE CAPACITY OF T H E LOWER CRETACEOUS STRATA OF NORTHEASTERN BRITISH COLUMBIA, CANADA.  3.1 INTRODUCTION  Gas shales are unconventional gas systems when the shale is both the source and reservoir for methane. The methane is sourced from the organic matter (OM) through biogenic and/or thermogenic processes and stored in a sorbed state on O M and clay particles or in the free state in intergranular porosity and natural fractures.  To date, there is no published data on the geological controls of gas capacity in shales, other than Lu et al. (1995) who showed a positive correlation between O M content and gas capacity for Devonian shales of the United States. The approach and methods that identify the controls on gas capacity in coalbed methane (CBM) studies are also used in this study as the gas storage mechanisms are the same. In comparison to coal seams, gas shales are organic lean and have lower porosities. The larger stratal geometries increase the potential of gas shales as a methane resource. The dominating controls on gas capacity in C B M resources are rank, composition (maceral and ash content), and A version of this chapter has been published/accepted for publication. Chalmers, G.R.L. and Bustin R . M . (2007) The organic matter distribution and methane capacity of the Lower Cretaceous strata of Northeastern British Columbia, Canada. International Journal of Coal Geology, Vol. 70:223-239. 53  moisture content. A positive relationship exists between rank and gas capacity (Levy et al., 1997; Yee et al., 1993). Rank of a coal appears to be the most significant control on methane capacity to the point that it complicates the relationship between maceral composition and gas capacity. Research in C B M has found a negative relationship between ash content and methane capacity (Crosdale et al., 1998; Faiz et al., 1992; Laxminarayana and Crosdale, 1999; Yee et al, 1993), implying that O M content controls gas capacity. At high ranks, bright coals that are vitrinite-rich show higher gas capacities than dull, inertinite-rich coals (Bustin and Clarkson, 1998; Crosdale and Beamish, 1993; Crosdale et al. 1998; Clarkson and Bustin, 1999; Lamberson and Bustin, 1993; Laxminarayana and Crosdale, 1999; Mastalerz et al, 2004). Other workers have found no relationship or trends between O M contents and methane capacity (Carroll and Pashin, 2003; Faiz et al., 1992). The reason bright coal has higher gas capacity is because vitrinite is more microporous with higher surface areas than inertinite (Lamberson and Bustin, 1993; Beamish and Crosdale, 1995; Unsworth etal, 1989). Microporosity of vitrinite increases with rank (Clarkson and Bustin, 1996; Gan et al., 1972) which is the reason gas capacity of coal increases with rank.  Moisture content of a coal has been shown to have a negative impact on the methane sorption capacity of coals (Joubert et al, 1974; Levy et al., 1997; Mavor et al, 1990; Yalcin and Durucan, 1991; Yee et al, 1993). Joubert et al. (1974) found that coals reach a unique critical value for moisture content where further increases did not reduce the amount of methane sorbed. Studies show moisture content increases with the oxygen content of the coal, suggesting moisture is attracted to carboxylic functional groups on  54  the surfaces of the coal (Mahajan and Walker, 1971; Nishino, 2001). It appears that the water molecules reduce the volume of sorption sites available to methane but there are sites still available for methane to sorb even if the coal is water saturated.  In this study I investigate the geological controls on the gas capacity of shales from the Lower Cretaceous strata of Northeastern British Columbia (NE BC), Canada (Fig. 3.1). Samples were collected from the Bluesky, Moosebar, Gates and Hulcross formations and the Chamberlain Member of the Albian Fort St John Group (Fig. 3.2) from a 180 m length of core in well # 6-30-80-13W6; the location of which is shown in Figure 3.1. The objectives of this study are to: 1) determine the methane gas capacity of the Lower Cretaceous strata in N E B C ; 2) identify the link between methane capacity and O M distribution and lithology; and 3) identify the macerals and their relationship to methane capacity. Two hypotheses are considered for this paper: a) methane capacity will increase with the O M content because O M contains the highest volume of sorption sites due to their high internal surface area and microporosity; and b) under the depositional conditions and palaeogeography in the Early Cretaceous in Northeastern British Columbia, the increases in O M are a result of shoreline progradation and increased input of land-derived plant material, in particular, inertodetrinite and other larger transported land-derived macerals.  55  3.2 LITHOLOGY AND DEPOSITIONAL ENVIRONMENTS OF FORMATIONS  Lower Cretaceous strata of N E B C were deposited within the retro-arc western Canadian sedimentary basin (WCSB). Sources of sediment were to the west and southwest from the rising thrust belts (Leckie 1986a; Smith et al, 1984; Stott, 1984). The Albian Fort St John Group (Fig. 3.2) is composed of fluvial, deltaic, littorial and marine sediments. Leckie (1986b) interprets the boundary between the terrestrial and marine conditions to have oscillated in a north/south direction, centred within the Bullmoose Mountain area (Fig. 3.1) through the Albian.  At the base of the 6-30-80-13W6 core, the Bluesky Formation is a 96 m coarseningupward package of very fine to coarse-grained sandstone interbedded with organic-rich siltstone and shale (Figs. 3.3 and 3.4A to C). Sandstones within the sequence are either fine-grained and bioturbated or are medium to coarse-grained and low-angle cross laminated. Lithological boundaries are abrupt and distinctive. Composition of the sandstone is described as a glauconitic-sublithic arenite. Bioturbation is concentrated within the organic-rich siltstones and shale sections. The depositional environment has been interpreted as either deltaic (Oppelt, 1988) or as a beach barrier with detachedoffshore-marine-bar system (Smith et al, 1984). The Bluesky Formation resulted from the initial transgression of the Boreal Sea that overlies the continental Gething Formation (Oppelt, 1988). However, sediment supply at this time exceeded sea-level rise and resulted in a coarsening-upward trend. The Bluesky Formation is relatively thin and has a  56  maximum reported thickness of 30 m due to localised thickening of the offshore marine bars (Smith et al., 1984).  The continental Chamberlain Member consists of fine- to coarse-grained sandstones, conglomerates, shale and thin to thick coal seams (Gibson, 1992). The Chamberlain Member in the 6-30-80-13W6 well consists of 1.6 m of interbedded coal and shale (Fig. 3.4D). The basal contact is gradational and is a continuation of the fining-upward trend in the upper section of the Bluesky Formation (Fig. 3.3). The interval contains a total of four coal seams ranging in thickness from 10 to 27 cm. The coals are dull, mineral-rich, argillaceous coal, and grade to carbonaceous shale at their contacts. The upper contact with the Moosebar Formation is missing due to core loss of 4.2 m. The Chamberlain Member caps the coarsening-upward Bluesky Formation and is interpreted as deltaic plain (Oppelt, 1988) or lagoonal and bay sediments (Smith et al., 1984). It is 100-m thick at the type-section south of Bullmoose Mountain (Fig. 3.1) and tapers to the east and northeast to 10 m at the Alberta/British Columbia border. Both the Bluesky Formation and Chamberlain Member were deposited in a regressive pulse of the overall transgression of the Boreal Sea in the W C S B (Smith et al., 1984).  The cored Moosebar Formation is 25 m of pyritic dark-grey to black shale (Figs. 3 and 5A). The shale also contains siderite and pyrite nodules, plant fragments and six bentonite claystone beds. A 1-cm thick granule conglomerate with an erosive base denotes the upper contact with the Gates Formation. The shale was deposited during the maximum lateral extent of the Boreal Sea. Depositional environments range from wave-  57  dominated, prograding-shoreface setting (Taylor and Walker, 1984) to prodeltaic to offshore-transitional-shoreface setting (Karst, 1981; Leckie et al, 1988). The thickness decreases from 300 m at its type locality near Hudson Hope (Fig. 3.1) to 30 m towards the southeast into western Alberta (Stott, 1982). Overall, the shale coarsens upwards into siltstone and eventually into fine sandstone of the Gates Formation.  In this study area, the Gates Formation consists of 48 m of interbedded fine to mediumgrained sandstones and siltstones, with minor shale partings. The Gates Formation is a coarsening-upward package (Fig. 3.3; Fig. 3.5B and C) with the basal 20 m consisting of interbedded organic-rich siltstones and fine sandstones. At the type locality, near Hudson Hope, the Gates Formation is a massive to thick-bedded fine-grained, well-sorted sandstone. The Gates Formation was deposited as a regressive phase and is interpreted to have been the deposits of a prograding shoreline from the south (Smith et al, 1984). At the type locality near Hudson's Hope, the thickness is only 18 metres but thickens to the south to over 260 metres (Stott, 1982).  Within the 6-30-80-13W6 well, the Hulcross Formation consists of 15 m of pyritic, darkgrey to black argillaceous to silty shale (Figs. 3 and 5D). There are minor sandstone and siltstones present. Similar to the Moosebar Formation, plant fragments are either pyritised and/or carbonaceous. Not all the Hulcross Formation was cored and the upper contact is missing. The transgression that deposited the Hulcross Formation was not as widespread in comparison to the transgression of the Moosebar Formation (Stott, 1982). The Hulcross Formation is interpreted to have been deposited in an offshore transitional to  58  offshore environment. Maximum thickness observed is 136 m in the Peace River canyon area and thins to the south where it grades into sandstone (Stott, 1982).  3.3 ANALYTICAL METHODS  To determine the O M distribution in 6-30-80-13W6M (Figs. 1 and 3), 150 samples were collected with an additional 15 samples taken for methane sorption capacity, surface area, maceral and random reflectance analyses. A l l samples were crushed to pass through a 60 mesh (250 um) sieve.  For shale samples, the inorganic carbon content was measured by coulometric analysis using a C M 5014 CO2 coulometer. A Carlo Erba ® N A 1500 CNS analyser determined the total carbon content. O M content was determined by subtracting the inorganic carbon content from the total carbon content. A l l O M values are reported as weight percent. Ash measurement for the coal sample was performed in accordance with the A S T M standard D3174-04 (2004) on a dried coal basis.  Methane capacity of samples was determined by a high pressure volumetric sorption apparatus. Samples were stage ground in a ring mill and placed in a water bath to obtain equilibrium moisture ( A S T M D 1412-04, 2004). A l l analyses were performed under isothermal conditions at 30°C ± 0.1 °C. Moisture content was measured by oven-drying  59  weight-loss calculations. Gas volumes are reported in cubic centimeters per gram of rock (cm /g) at 30°C and 6 MPa. 3  Maceral analyses of samples were performed in accordance with AS 2856.2-1998 (1998) and a total of 500 points were counted on each sample. The mean random reflectance of telovitrinite or vitrinite (50 points) was performed on samples from each formation to ascertain their maturity using the standard A S T M D 2798-99 (2004).  Porosity was calculated by subtracting the skeletal density from the bulk density. Mercury immersion and Archimedes' Principle of Displacement determined the bulk density of a sample. Skeletal density was obtained by helium pycnometry.  The surface area and the microporosity were determined by low-pressure (<127kPa) adsorption analyses using a Micromeritics A S A P 2010 apparatus. The surface area of the samples by nitrogen adsorption was determined at 77K using the five-point Brunauer, Emmett and Teller (BET) method (Brunauer et al., 1938). Micropore volume and "equivalent" surface area were determined by carbon dioxide adsorption using the Dubinin-Radushkevich (D-R) equation at 273K. Repeatability of analysis on this apparatus is ±6%. Between 1 and 2 g of sample was degassed at 150°C for 12 hours prior to analysis. In some cases, the sample had to be repeatedly dosed with helium and reevacuated for several days to purge residual volatiles.  60  3.4. RESULTS  3.4.1 Organic matter petrology and methane sorption capacity  The average O M content for the all formations is 2.3 wt% with a minimum of 0.6 wt% and a maximum of 10.1 wt% (Fig. 3.3). Methane sorption analyses were performed on 15 samples (Fig. 3.6A to D) and the sample with the highest O M content from each formation had the highest methane capacity. There is a positive correlation between O M content and methane sorption capacity (R is 0.60) (Fig. 3.7). The Chamberlain coal 2  sample S8 was excluded due to the underestimation of the O M content.  The Bluesky Formation has an average O M content of 1.9 wt% and ranges between 0.6 and 7.1 wt%. There is general upward increase in O M ; however, in the basal 40 m there is a high frequency oscillation between high and low values (Fig. 3.3). The oscillation reflects the interbedding of organic-rich siltstone with organic-lean sandstone. In the upper half of the formation, two major peaks occur within the increasing O M content. Samples S5 and S4d show the lower O M peak mainly consists of inertinite (Table 3.1) with the majority of this being inertodetrinite (Table 3.2). Sample S7 reveals that the second O M peak also contains a high proportion of inertodetrinite which shows a wide range of reflectance levels (Fig. 3.8 A). Inertodetrinite, vitrinite and sporinite contents increase towards the top of the formation (Table 3.2), illustrating the increase in terrestrial O M into the marine system. The Bluesky Formation has an average methane  61  sorption capacity of 0.55 cm /g (Table 3.3). Sample S7 has both the highest O M content 3  and methane sorption capacity of 0.97 cm /g. There is a general trend of increasing O M 3  content and methane sorption capacity in the Bluesky samples (Fig. 3.6A).  The Chamberlain Member is a coal-bearing unit with an expected higher average O M content (5.1 wt%) compared to the other formations. The O M content ranges between 1.7 and 10.1 wt% for shale samples. The shale beds within the Chamberlain Member contain bifurcating telovitrinite rootlets that penetrate from the overlying coal seam (Fig. 3.8B). The coal seams contain telovitrinite bands with preserved resin ducts (Fig. 3.8C), inertodetrinite, detrovitrinite, framboidal pyrite and alginite. The coal sample, S8, from the Chamberlain Member (Fig. 3.6A and Table 3.3) has the highest methane capacity in this study with 2.74 cm /g. Sample S8 is a argillaceous coal and has the highest vitrinite 3  content of 76 vol.% in the suite of samples. The underestimation of the O M content is confirmed by the maceral analysis and also the ash content of 32.7 wt%. Bostick and Daws (1994) found total organic carbon analysis was underestimated because of incomplete oxidation of the coal due to the large amount of organic matter in the crucible. The coal sample is excluded from correlations in this study.  The Moosebar Formation has an average O M content of 2.3 wt% with a range between 0.7 and 3.6 wt% and an average methane capacity of 0.57 cm /g (Fig. 3.6B and Table 3  3.3). As the O M content is very similar between samples there are no clear relationships with sorption capacity. The most OM-rich shale does have the highest methane capacity. The Moosebar Formation is relatively enriched in alginite in comparison to inertinite and  62  vitrinite (Tables 1 and 2). A high proportion of the liptodetrinite is composed of fragmented alginite as indicated by the fluorescence colour and intensity (Fig. 3.8D). Inertodetrinite particles are rare in the Moosebar Formation and are generally smaller and higher reflecting in comparison to the particles in the Bluesky Formation (Fig. 3.8E).  The Gates Formation has an average O M content of 1.8 wt% and ranges between 1 and 3 wt%. A n increase in the inertodetrinite content from 2.2 to 7.6 vol.% in the basal 10 m of the Gates Formation is reflected in the O M distribution (Fig. 3.3) with a peak of 2.9 wt%. The remainder of the formation shows O M contents between 1 and 2 wt% with a decreasing inertodetrinite content towards the top and a relative increase in the liptinite content. The liptinite increase is a result of an increase in sporinite, alginite and liptodetrinite. Even though the Gates Formation has a similar lithological character to the Bluesky (i.e. interbedded sandstones with organic siltstones), the O M content does not show the same high-frequency oscillation. The Gates Formation has the lowest average methane capacity of 0.4 cm /g and the lowest average O M content of the four formations. 3  Figure 3.6C shows the difference between the two Gates samples with the more organicrich sample sorbing more methane. There is more than a 3-fold increase in methane sorption when O M increases from 1.0 wt% to 1.7 wt% (Table 3.3).  The Hulcross Formation has an average O M content of 2.7 wt% and ranges between 2.1 and 4.1 wt% (Fig. 3.3). The maceral composition is characterised by very low (0.2 vol.%) to no vitrinite and a relative enrichment of liptinite (Table 3.2). Liptinite consists of liptodetrinite and matrix bituminite (Fig. 3.8F). The shale contains O M within the  63  mineral matrix that is too small to be observed by microscope illustrated by a low maceral content compared to the O M content. Although the Hulcross has the highest average O M content, the average sorption capacity of 0.5 cm /g is not the highest of the 3  four formations (Fig. 3.6D). Similar to the other formations, the Hulcross sample with the highest O M content does have the highest methane sorption capacity.  Using the average for each formation, the vitrinite reflectance increases with depth, from 0.79% for the Hulcross to 0.90% for the Bluesky Formation (Table 3.3). The reflectance values have a wide range, from 0.68% to 1.08%) and vary significantly between samples within formations. The reflectance values place the samples in the high volatile B to A bituminous coal rank or in the oil generation zone for source rocks (Taylor et al, 1998). There is no clear relationship between vitrinite reflectance and methane capacity in this study and no conclusions can be drawn.  3.4.2 Moisture Content, O M content and Methane Capacity  Equilibrium moisture contents range between 3.1 and 9.0 wt% with the Hulcross Formation having the highest average of 8.7 wt% and the Gates Formation with the lowest at 4.2 wt% (Table 3.3). The relationship between the moisture content and the methane sorption capacity shows a general increasing trend with higher moisture contents (Fig. 3.7). There is a similar positive trend between the O M and moisture contents.  64  3.4.3 Surface area and Microporosity  The N2 BET surface area, CO2 D-R "equivalent" surface area and the micropore volume are shown in Table 3.4. The N2 BET surface area is a measure of mesoporosity and some macroporosity (2-100 nm) while the CO2 D-R method measures surface area of the microporosity and mesoporosity (Unsworth et al, 1989). In all cases the "equivalent" surface area is larger than the surface area from BET method which is an indication that these shales contain microporosity. The Chamberlain coal (S8) has the largest micropore volume (1.7 cm /100 g) and CO2 surface area. Two Hulcross samples, S19 and S22, have large micropore volumes as well. The inertodetrinite-rich sample S7 of the Bluesky Formation has a relatively large micropore volume as well as a large surface area determined from N2 adsorption. The rest of the suite of samples have micropore volumes ranging between 0.4 and 0.7 cm /100 g. There is strong positive relationship between 3  micropore volume, methane sorption capacity and O M content (Fig. 3.9). A strong positive relationship also exists between the moisture content, methane sorption capacity and micropore volume (Fig. 3.10) which validates the positive relationship between moisture content and methane capacity in Figure 3.7. The negative relationship between moisture and surface area derived from N2 adsorption (Fig. 3.11) indicates the inherent moisture is located within the microporosity and therefore within the O M which explains the reason that moisture and methane capacity have a positive relationship. The total porosity (i.e. difference between bulk and skeletal densities) appears to be controlled by the micropore volume and not by the mesopores as illustrated by Fig. 3.12.  65  3.4.4 Total Gas Capacity and Porosity  Total gas capacity is the amount of gas stored in solution and the sorbed and free states. To calculate the total gas capacity the total porosity is determined and the volume of the total porosity occupied by sorbed gas is subtracted to yield the porosity available to free gas. This calculation assumes that all pores (accessible to helium) are accessible to methane and the water saturation is zero ( S = 0) or the sample is analysed at reservoir w  S . Solution gas although locally important is not considered here. These assumptions w  then describe the maximum gas capacities for these samples. The porosity of the samples and their total gas capacities at 6 MPa are shown in Table 3.3. The difference between sorbed gas capacity and total gas capacity is illustrated by the Moosebar Formation sample SI 5 in Figure 3.13. The sorption isotherms of all samples are shown in Figure 3.14 recalculated to total gas capacity. The Chamberlain Member sample S8 has the highest total gas capacity (16.6 cm /g). The Hulcross Formation sample S21 has the 3  second highest capacity with 15.2 cm /g because of its high porosity of 22.5%. Sample 3  S7 from the Bluesky Formation which has the second highest sorbed capacity has the third highest total gas capacity of 11.7 cm /g. The remainder of the samples have 3  significant total gas capacities ranging between 2.2 and 8.5 cm /g.  66  3.5. DISCUSSION  3.5.1 Organic Petrology  The relationship between the lithological changes, O M distribution and relative sea-level changes are explored within this section. The trend of decreasing alginite towards the top of the Bluesky Formation, increasing terrestrially-derived inertodetrinite and sporinite coupled with the increase in grain size is an indication that the coastal plain is becoming more proximal to the study area. Oppelt (1988) suggests the shoreline was advancing during the deposition of the Bluesky Formation as sediment supply exceeded the rise in sea level. The advancement of the shoreline would increase the amount of terrestrial O M into the study area. There is an inverse relationship between O M content and grain size, illustrated by the lower O M content in the coarser sediments and higher O M content in the finer, argillaceous sediments in the Bluesky Formation. This relationship is caused by the changes to the depositional energy and has resulted in the high frequency oscillation within the O M distribution illustrated in Figure 3.3.  As the shoreline continued to advance, the sediment character changed from nearshore to terrestrial with deposition of coal in the Chamberlain Member. The presence of telovitrinite and detrovitrinite bands within the coal seams and also the identification of rootlets within the shale partings indicate the coal had developed as an autochthonous mire, capping the coarsening-upward trend of the Bluesky Formation. The shale partings  67  in the Chamberlain Member contain alginite and framboidal pyrite that suggests the mire was in a paralic setting which experienced periodic marine incursions during peat accumulation.  A marine transgression resulted in the deposition of the Moosebar Formation as the O M enriched basal section consists mainly of alginite and alginite-derived liptodetrinite. The transgression may have been accelerating which increased water depth and reduced ocean circulation to create anoxic conditions, enhancing the preservation of O M . Bohacs (1998) suggests that shale is most OM-rich in the upper transgression to lower highstand in a sequence stratigraphic model as the water depths are at their greatest and ocean circulation and clastic input are minimal. The inertodetrinite within the Moosebar Formation differs from the Bluesky Formation by being smaller, more angular and all exhibiting very high reflectance. We interpret the inertodetrinite as being derived from natural airborne particulates resulting from forest fires. We further suggest that the marine transgression of the Moosebar Formation trapped waterborne terrestrial O M in the nearshore environment (estuarine) which resulted in the relative increase in the alginite and the airborne particulate contents.  The O M content of the Gates Formation does not increase towards the top of the formation as would be expected for deposits of a prograding shoreline. A subtle increase in the vitrinite and sporinite contents towards the top of the formation indicates an increase in terrestrial O M input; however, there is no increase in the inertodetrinite content that was observed in the Bluesky Formation. The reason that the total O M  68  content does not increase upwards is due to the depositional energy being too high for the accumulation of O M and a high sediment supply diluted the O M concentration.  The Hulcross Formation was deposited during another transgressive event which is reflected in the sharp rise in the O M content. Similar to the Moosebar Formation, the increase in O M content is due to the creation of anoxic conditions. The initial stages of the transgression created anoxic bottom water conditions and increased the preservation potential. The second O M peak at the top of the core may be a flooding surface or acceleration in sea-level rise. Generally, the alginite and matrix bituminite contents are relatively higher than the Gates Formation and indicate anoxic marine bottom waters and anaerobic bacterial degradation (Taylor et al., 1998). The Hulcross shale has a relatively low terrestrial-derived O M content which is similar to the Moosebar Formation. The transgression reduced the influx of terrestrial O M to the study area.  3.5.2 Controls on Methane Sorption Capacity  The changes in lithology and O M distribution in each formation are controlled by the depositional environment and to gain an understanding of the geological controls on methane capacity, these changes are compared to their methane capacities. The strong positive relationship that exists between the O M concentration and methane sorption capacity of the sample (Fig. 3.7) is due to the high microporosity and surface area of O M (Fig. 3.9). The high surface area of the O M provides the large volume of sorption sites  69  for methane. Therefore a small increase in O M has a large impact on the total surface area of the sample and its ability to store methane. Samples that have O M contents greater than 4 wt% show a strong relationship with the ability to sorb methane while samples with lower O M contents have weaker relationship. The poorer relationship is indicating that there are other factors contributing to the methane capacities of samples and this could include the moisture content (previously correlated with OM) and the clay content and composition.  Samples that have either high vitrinite or inertodetrinite contents have the highest methane sorption capacities (i.e. Samples S7 and S8). The highest capacity is from the Chamberlain Member (S8) which has a total vitrinite content of 76 vol.%. Vitrinite has been shown to have the highest microporosity and surface area and therefore samples enriched in vitrinite sorb more gas (Beamish and Crosdale, 1995; Clarkson and Bustin, 1996; Gan et al, 1972; Lamberson and Bustin, 1993; Unsworth et al, 1989). The S8 coal sample has the highest micropore volume (1.7 cm /l OOg) and equivalent surface area by 3  CO2 adsorption (63 m /g). The total maceral content of sample S7 from the Bluesky Formation is 16.6 vol.% with 9.2 vol.% consisting of inertodetrinite which is a mixture of both high and low reflectance level macerals (Fig. 3.8A). The lower reflectance level macerals are vitrodetrinite and their microporous structure has increased the total surface area (32 m /g; Table 3.4) of the sample and its ability to sorb methane. Sample S5 has a 2  higher inertodetrinite content (12.6 vol.%) than Sample S7 but the second lowest methane capacity in the suite of samples. The inertodetrinite within sample S5 consists of highly oxidized inertinite macerals and is therefore more mesoporous than sample S7 as  70  indicated by the lower micropore volume and surface area (21m /g). Inertinite has less surface area than vitrinite because it is mesoporous not microporous (Clarkson and Bustin, 1999). It appears that not only the O M concentration but the maceral composition is important when assessing the methane capacity of a sample. Therefore the depositional environment and botanical origins of the O M also has a bearing on the quality of the O M and its ability to store methane.  Results from this study show a positive relationship exists between the O M content, moisture content and the ability to sorb methane (Fig. 3.7). The positive affect appears contradictory to C B M studies which have shown that inherent moisture has a negative impact on the sorption capacities. The increase in sorption capacity with increases in both moisture and O M contents suggests that the water molecule is sorbing to specific hydrophilic sites (e.g. negative-charged clay surfaces) and the other available sorption sites are taken by the methane molecule. Sites available increase with O M content and this is shown by sample S7 with the O M content of 7.2 wt%. The Hulcross samples show higher moisture contents, surface areas and micropore volumes than sample S7 but have lower methane capacities because moisture is blocking access or is competing for sorption sites. The negative relationship between moisture and the surface area determined by N2 adsorption and the positive relationship moisture has with micropore volume indicates that the inherent moisture is located in the microporosity of the O M . This relationship is contradictory to C B M studies because increases in O M are more significant in shales because they are organic lean compared to coals and this increase in O M directly increases the available sites to moisture.  71  3.6. CONCLUSIONS  1) O M characteristics differ between formations with the Bluesky and Gates Formations and Chamberlain Member containing more terrestrially-sourced O M compared to the Moosebar and Hulcross Formations. Both the Bluesky and Gates Formations have terrestrial O M contents increasing upwards. Progradation of the shoreline increased both the coarseness of the inorganic component and the terrestrial O M content for the Bluesky and Gates Formation. The source of the terrestrial O M was the coastal plains located to the south of the study area. The Chamberlain Member is evidence that the coastal plain had reached the study area during the progradation that deposited the Bluesky Formation.  2) The OM-rich basal sections of the Moosebar and Hulcross formations were deposited during accelerating relative rise in sea level. The second peak in the Hulcross Formation may be a flooding surface after the initial rise in sea level that produces the OM-rich base.  3) A n inverse relationship exists between the O M and clastic grain size. The abrupt high-frequency changes in the O M content in the Bluesky Formation reflects the thin interbedded nature of the unit. Both the shale formations contain higher O M averages and show less change than the coarser-grained units.  72  4)  The relative increase in high-reflectance inertodetrinite and the reduction in terrestrial O M in the shale formations is an indication that water-transported O M was not delivered to the study area during transgression, but trapped in nearshore environments. The relative increase in high-reflecting inertodetrinite could be sourced from air-borne particulates from forest fires.  5) The concentration of O M in a sample has a direct influence on the volume of sorbed methane. The microporous nature and high internal surface area of O M , particularly vitrinite, provide the sorption sites for methane. The samples that have the highest sorbed gas capacities have the highest O M contents and are either vitrinite or inertodetrinite rich. The inertodetrinite-rich sample does contain a significant portion of particles that have low reflectance levels and are considered vitrodetrinite.  6) There is a positive relationship between moisture content, O M content and methane sorption capacity. The water molecule is only sorbing to specific hydrophilic sites and other sorption sites are still available for methane. Both the hydrophilic and hydrophobic sites increase with the increase in O M content.  7) Surface area and micropore volume analyses indicate that the moisture and methane capacity are associated with the microporosity of O M . This is the reason why a positive relationship exists between the moisture content and methane  73  sorption capacity. The microporosity also has a strong influence on the total porosity of the sample.  8) Using the porosity measurements, the total gas capacity of the four formations ranges between 2.2 cm /g to 16.6 cm /g at 6 MPa with the Chamberlain Member 3  3  coal having the highest capacity. The porosity has a significant bearing on the total volume that can be stored and is an important component when assessing gas shale resources.  74  Fig. 3.1. Location of study area is centred at Fort St John and the location of the well is along the Alberta/British Columbia border, shown by filled diamond. Inset is the location of the study area within British Columbia, Canada. The filled circles are location of towns/cities.  75  Fig. 3.2. Stratigraphic table for the Lower Cretaceous strata of northeastern British Columbia. Light grey shaded formations are sandstone dominated and medium grey shaded formations are shale dominated.  76  Fig. 3.3. Lithological graphic log showing the four formations of well # 6-30-80-13W6M and the O M distribution. Sample numbers and their locations are also shown.  77  Fig. 3.4. (A) illustrates the alternation between organic-rich siltstones and shale with finegrained sandstone, Bluesky Formation; (B) parallel cross-laminated fine sandstone with organic-rich laminations, Bluesky Formation; (C) a Teichichnus-type burrow originating from OM-rich siltstone and penetrating into cross-laminated sandstone, Bluesky Formation; (D) illustrates the cleaner coal in the middle of the seam and the increase in mineral matter towards both the upper and lower contacts, Chamberlain Member; Canadian penny for scale. 78  Fig. 3.5. Moosebar Formation containing a 3-cm sulphur-rich clay stone, the claystone is a bentonite band, one of several found within the Moosebar Formation (A); interbedded massive medium to coarse sandstone with organic-rich siltstone and shale, Gates Formation (B); heavily bioturbated sandstone, siltstone and shale, similar to the Bluesky Formation, giving a mottled texture (C), Gates Formation; the shale of the Hulcross Formation (D) is fissile and sulphur-rich. Canadian penny for scale.  79  Isotherms of the Chamberlain and Bluesky Formations  •  0  V  •  f>2.0  •  S8 S7 S3 S4 S3 S2 S1  cool black storm ftno oantJslono black siltslone darK gray srial* dart; gray tMn\t black alilsiono  ^  Equilibrium Cell Pressure (MPa)  Isotherms of the Gales Formations  • O  Isotherms of the Moosebar Formations  1.30  Equilibrium Cell Pressure (MPa)  Isotherms of the Hulcross Formations  S17 - black smtlono S16-black aiftslooe  Equilibrium Cell Pressure (MPa) Equilibrium Cell Pressure (MPa)  Fig. 3.6. Methane sorption isotherms for the Bluesky, Moosebar, Gates and Hulcross Formations. The percentage of O M content of samples are also shown.  80  Fig. 3.7. The relationship between the O M content, moisture content and methane sorption capacity. Graph excludes the coal sample S8 due to underestimation of O M content.  81  Telovitrinite  \ Resitiite  -  •  Inertodetrinite Mineral Matter  Liptodetrinite  s \  Matrix Bituminite  /  I  Liptodetrinite \  E  , ,,I,,,,ni„  p  Fig. 3.8. Photomicrographs of macerals in well 6-30-80-13W6M. (A) Large, poorly-sorted inertinite grains too large to be classified as inertodetrinite with smaller vitrodetrinite particles, note the large variation in reflectance levels, Sample S7; (B) Telovitrinite rootlet showing bifurcation within mineral matter, Sample S10; (C) Telovitrinite from the Chamberlain coal with well preserved resin ducts, Sample S8; (D) Liptodetrinite-rich Moosebar Formation with the majority consisting of fragmented alginite, Sample SI2; (E) High-reflecting inertodetrinite from a Moosebar Formation, Sample SI5; (F) Low-fluorescing bituminite-rich matrix shale from the Hulcross Formation with scattered liptodetrinite, Sample S22. A l l photomicrographs are in white light except (D) and (F) which are in blue light, oil immersion, 40x objective. Scale bar is 20 um.  82  Fig. 3.9. The positive relationship between the O M content, the micropore volume and the methane sorption capacity of the OM-rich shales. Note, the Chamberlain coal sample was excluded due to scaling effects.  Fig. 3.10. The positive relationship between moisture, micropore volume and O M content of the OM-rich shales. Note the Chamberlain Coal is excluded due to scaling effects.  84  Fig. 3.11. A negative relationship exists between the surface area measured by N  2  adsorption and the moisture content of a sample. The moisture, in fact, is associated with the microporosity of the O M , illustrated by the positive relationship between moisture and micropore volume.  85  Fig. 3.12. The relationship between porosity, micropore volume and surface area measured by N2 adsorption. Porosity, measured by the difference between bulk (mercury immersion) and skeletal (helium pycnometry) densities, is shown to be derived from the microporosity of the sample and the mesoporosity does not have any influence.  86  Total vs Sorbed Methane for Moosebar Formation Sample S15 12  0_ r- 10 H  • O  S 1 5 - S o r b e d Methane S 1 5 - T o t a l Methane  O  co  o TOC (2.37%) + Porosity (10.9%) CD "CD "O CD -Q i— o CO  6H Sorbed + Free Gas  4 4.  1  o  TO O  1/  TOC = 2.37%  2  4  6  Equilibrium Cell Pressure (MPa) Fig. 3.13. Sample S15 from the Moosebar Formation illustrating the difference between sorbed gas capacity and total gas capacity. Total gas capacity is calculated using the porosity of the sample and assuming there is no water saturation.  87  Total Gas Content for Moosebar Formation  Total Gas for Chamberlain and Bluesky Formations  12  25  5  •o  S8 S7 T S5 V S4 • S3  20  <§)  O) g 15  •  S2  S1  •  5COa>  coal black snaie tine sandstone  . 16.8  black sillstOfiG dafk arev shale dark grey shale  — f cn  block siltstone  o 14.4  n  9  +  <K 5  a  w  ST 4  • V  S15 S13 S12 S11  oork grey shale  • 10.9  black shale btock shato  •  black shale  4  9.1 9.4 6.8 •II  6  O  n  |  4 '4.1 5.7  (U ^  2 0  2  4  6  Equilibrium Cell Pressure (MPa)  Equilibrium Cell Pressure (MPa)  Total Gas for Gates Formation  Total Gas for Hulcross Formation  •  S17-  O  S16-black sftistone  o 5.6  I rj  2  •o  ® 8  10  |  _ 10 x  . 7.6  Wack slttstono  ®  3.2  1 3 CD  O T3  •e  z  o + CD  £ 1 0  6°2  4 Equilibrium Cell Pressure (MPa)  6  2  4  6  Equilibrium Cell Pressure (MPa)  Fig. 3.14. Total (free + sorbed) gas capacities of the four formations. Free gas is calculated using porosity of the sample. Porosity values (percent) are shown for each sample's isotherm.  88  Table 3.1: Maceral group percent by volume for the four formations of 6-30-80-13W6M Sample ID Depth Hulcross Formation S22 640 S21 646 S20 647 S19 652 Gates Formation S18b 659 S18 667.8 S17c 676.5 S17b 683.8 S17 688.6 S16 698.5 Moosebar Formation S15 704.2 S13 711.6 S12 714.6 S11 722.9 Chamberlain Member S10 728.5 S9 729 S8 729.1 Bluesky Formation S7 736.7 S6 746.7 S5 752.5 S4d 756.5 S4c 767.5 S4b 770.6 S4 777.5 S3 779.9 S2 789.2 S1 804.45  Vitrinite vol.%  Liptinite vol.%  Inertinite vol.%  Mineral Matter vol.%  -  2  3 6 4 3  95 94 94 95  2 2  -  -  -  2  4 1 1 1 1  4 4 2 8 3  100 90 95 96 92 96  1  1 1 3 5  7 4 5 6  91 94 92 88  4 1 76  1 9 3  5 18 1  90 72 20  1 3 1 1 1  6 3 0 1  -  1  1 2 1 2  -  -  10 6 13 10 4 7 6 7 4 2  83 88 86 88 95 92 91 92 93 98  1  1  -  2  -  -  89  Table 3.2: Maceral analysis of the four formations in well # 6-30-80-13W6M. All volumes are reported in percent with minerals included. Sample ID S22 S21 S20 S19 S18b S18 S17c S17b S17 S16 S15 S13 S12 S11 S10 S9 S8 S7 S6 S5 S4d S4c S4b S4 S3 S2 S1  o  Telovitrinite  0.2 0.2  2.0 0.2 0.6  0.4 0.8 0.4 0.2 0.6 4.0 0.6 66.2 1.2 2.4 1 0.6 0.6 0.4 1.8 0.2 0.6  -  Detrovitrinite  -  Sporinite  0.2 0.2  -  1.2 0.2 0.2  -  -  0.4  0.4  -  -  0.2 0.4 1.2 0.2 0.6 0.6 1.0 0.6  0.4  0.4 5.8 0.4  -  2.0 0.4  -  -  1.0 0.4 0.2 0.2  0.4 0.2 9.8 0.6  Alginite 0.4 0.2 0.6  0.2  -  -  0.2  0.2 0.2 0.2 0.8  -  -  Resinite  Liptodetrinite  -  0.8 0.6 2.4 4.2 0.6 3.0  2.4  -  1.0 0.2 1.0 1.6  1.6 0.2 0.2 0.4 0.4  Semifusinite  -  Fusinite 0.4  0.2  -  -  0.2  0.4  -  0.2  -  -  0.2 0.2  2.2  0.6  -  -  3.0 1.6  0.2 0.4 0.2 0.6 0.2 0.6  -  1.0 0.2 0.6 1.4 0.8 0.6 0.4  -  -  0.2  0.2 0.4 0.2 0.2  -  Inertodetrinite 2.8 5.8 4.2 2.8 0.4 4.0 3.6 2.4 7.6 2.2 7.2 4.2 5 5.6 4.6 15.0 0.6 9.2 6.0 12.4 8.8 3.4 5.6 5.4 6.2 4.2 1.8  Detrital Minerals 93.4 90.4 81.2 92.8 99.4 81.2 94.4 92.4 90.4 95.0 85.2 79.2 89.2 82.8 89.6 65.4 18.6 74.0 87.2 86.4 87.6 95.4 92.4 90.6 90.6 84.6 97.8  Pyrite 2.0 3.2 12.6 2.6 0.2 9.0 0.6 4.0 1.4 1.4 5.4 15.2 2.2 5.4 0.2 6.6 1.4 9.4 0.8  1.2  0.2 1.8 8.8  -  Table 3.3: Reservoir characteristic of the samples analysed for methane capacities, averages are shown in italics (* denote pressures at 6 MPa).  Sample ID Hulcross S22 S21 S19 average Gates S17 S16 average Moosebar S15 S13 S12 S11 average Chamberl ain S8 Bluesky S7 S5 S4 S3 S2 S1 average  Standard Deviation  Equilibrium Moisture wt%  Porosity %  Methane Sorption Capacity (cm /g)  n/a 0.83 0.74 0.79  n/a 0.209 0.188  8.4 8.7 9.0 8.7  9.2 22.5 11.6 14.5  0.61 0.56 0.32 0.50  3.0 15.2 7.0 8.4  1.00 1.70 1.35  1.02 0.81 0.79  0.134 0.268  3.1 5.2 4.2  7.6 3.2 5.4  0.19 0.61 0.40  3.6 2.7 3.2  2.37 1.92 2.19 2.21 2.17  0.76 n/a 0.72 0.84 0.72  0.168 n/a 0.178 0.197  -  6.5 4.7 5.1 4.5 5.2  10.9 5.6 4.1 5.7 6.6  0.82 0.56 0.44 0.44 0.57  8.5 7.3 2.8 2.2 5.2  20.02  0.83  0.056  6.0  16.8  2.74  16.6  7.07 1.30 1.37 1.84 2.18 1.16 2.49  1.08 n/a 0.96 n/a 0.68 0.84 0.90  0.229 n/a 0.321 n/a 0.242 0.117  5.9 4.7 4.8 4.9 5.1 3.6 4.8  14.4 6.2 9.4 4.5 6.8 9.1 8.4  0.97 0.29 0.52 0.51 0.67 0.36 0.55  11.7 4.0 6.1 3.8 5.2 6.5 6.2  TOC wt%  %Rrt  4.07 2.45 3.17 3.23  -  -  -  3  Total Methane Capacity (cm /g) 3  91  Table 3.4: Surface area and micropore volume of all methane sorption samples. N - BET Surface C 0 - D-R Surface Micropore Volume Area (m /g) Area (m /g) (cm /100g) Sample ID 2  2  2  2  3  Hulcross S22 S21 S19  4.1 4.4 2.5  37.9 33.3 37.3  1.02 0.90 1.00  9.7 12.8  16.1 21.8  0.43 0.59  9.3 19.2 17.3 5.0  27.3 26.8 26.9 21.3  0.74 0.72 0.73 0.57  5.7  62.9  1.69  14.0 14.7 15.9 19.4 5.0 .14.1  31.6 21.0 20.2 27.2 21.4 18.1  0.85 0.57 0.54 0.73 0.58 0.48  Gates S17 S16 Moosebar S15 S13 S12 S11 Chamberlain S8 Bluesky S7 S5 S4 S3 S2 S1  ;  3.7 REFERENCES  AS 2856.2-1998. 1998. Australian Standard 2486.2. Coal petrography, Part 2: Maceral Analysis. Standards Association of Australia, North Sydney, NSW, Australia A S T M D l 412-04, 2004. Test for equilibrium moisture of coal at 96 to 97% relative humidity and 30°C. A S T M D2799-05, 2005. Microscopical determination of volume percent of physical components of coal. A S T M D3174-04, 2004. Ash in the analysis sample of coal and coke.  92  Beamish, B.B., Crosdale, P. J., 1995. 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Methane Capacities of Zonguldak coals and the factors affecting methane adsorption. Mining Science and Technology 13,215-222. Yee, D., Seidle, J.P., Hanson, W.B., 1993. Gas sorption on coal and measurement of gas content, in: Law, B.E., Rice, D.D. (Eds.), Hydrocarbons from coal. A A P G Studies in Geology, Chapter 9, A A P G , Tulsa, Oklahoma, 74101 USA, 203-218.  95  CHAPTER FOUR  LOWER CRETACEOUS GAS SHALES IN NORTHEASTERN BRITISH COLUMBIA, PART I: GEOLOGICAL CONTROLS ON M E T H A N E SORPTION CAPACITY  4.1 INTRODUCTION  Understanding of the geological controls on methane sorption capacity of shales is critical to the design and implementation of an exploration strategy for gas shales, particularly in frontier areas. The geological controls include total organic carbon (TOC) content, kerogen types, maturity, mineralogy, moisture content and pore size distribution. TOC content shows a positive correlation with gas capacity of a shale (Lu et al., 1995; Chalmers and Bustin, 2007b), however scatter within the correlations indicate other controls are present which require investigation. Gas shales are in part analogous to coalbed methane in that a component of gas storage is in the sorbed state. Similar geological controls on methane sorption capacity, as found for coals, are expected for organic-rich shales.  The objective of this paper is to elucidate the major geological controls on methane sorption capacities by using as an example from the basal interval of the Lower Cretaceous Buckinghorse Formation and equivalent strata in northeastern British A version of this chapter has been submitted for publication. Chalmers, G.R.L. and Bustin R . M . Lower Cretaceous gas shales in northeastern British Columbia, Part I: Geological controls on methane sorption capacity. CSPG Bulletin.  Columbia (Figs 4.1 and 4.2). This paper investigates the following relationships between the methane sorption capacity and: a) the TOC content; b) kerogen type; c) maturity; d) mineralogy; e) moisture content; and f) pore size distribution. This paper also investigates the relationships between pore size distribution and: g) TOC content; h) mineralogy; and i) moisture content. The term methane capacity will be used throughout this paper and is synonymous with methane sorption capacity. Total gas capacities (sorbed, free and solution gas) of this sample suite are dealt within a companion paper: Evaluation of regional potential gas resources (Chalmers and Bustin, submitted)  There is no previous work on the geological controls on methane capacity of gas shales apart from anecdotal evidence. However, research on the controls of methane capacity for coal will provide insight into the possible influences for gas shales. Mineral matter and rank are the two dominant controls on methane capacity in coal. Mineral matter which has a comparably low surface area acts as a diluent for sorbed coal capacity (Faiz et al., 1992; Yee et al., 1993; Crosdale et a l , 1998; Laxminarayana and Crosdale, 1999) because mineral matter reduces the volume of sorption sites. A positive relationship exists between coal rank and methane capacity (Gan et al., 1972; Unsworth et al., 1989; Lamberson and Bustin, 1993; Yee et a l , 1993; Beamish and Crosdale, 1995; Clarkson and Bustin, 1996; Levy et al., 1997; Prinz et al., 2004; Prinz and Littke, 2005; Chalmers and Bustin, 2007a).  The effect petrographic composition has on sorption capacity is not clear because rank is a strong control and masks the effects of the petrographic composition. From iso-rank  97  studies, a positive relationship exists between vitrinite content and methane capacity (Crosdale and Beamish, 1993; 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). This correlation is attributed to vitrinite being more microporous than inertinite and becomes relatively more pronounced with increasing rank (Unsworth et al., 1989; Lamberson and Bustin, 1993; Beamish and Crosdale, 1995; Chalmers and Bustin, 2007a). Other research has found no relationship between petrographic composition and methane capacity (Carroll and Pashin, 2003; Faiz et al., 1992; Faiz et al., in press). Liptinite-rich coals can have comparable methane capacities to high rank, vitrinite-rich coals (Chalmers and Bustin, 2007a) because gas is in solution. Although liptinite-rich coals are a rare coal type, liptinite is more common in gas shales because the majority of these shales are marine in origin.  Moisture content has a negative relationship with methane capacity of coals as the water molecule reduces the volume of sorption sites for methane (Joubert et al., 1974; Levy et al., 1997; Mavor et al., 1990; Yalcin and Durucan, 1991; Yee et al., 1993). Moisture content of coal decreases with increasing rank due to the loss of carboxylic functional groups which attract water molecules (Mahajan and Walker, 1971; Nishino, 2001). With increase in moisture content, a maximum reduction in the methane capacity is reached (critical value), after which any further increases in the moisture content does not effect the methane capacity (Joubert, 1974). Chalmers and Bustin (2007b) observed both moisture content and methane capacity increase with the TOC content of Lower  98  Cretaceous shales and concluded that both hydrophobic and hydrophilic sorption sites concomitantly increase and allow sorption of both methane and water molecules.  4.2 METHODS  Samples from the basal section of the Buckinghorse Formation and its equivalent strata (Moosebar-Wilrich-Garbutt formations; Fig. 4.2) were ground in a ring mill to pass a 60 mesh (250 urn) sieve. Ground samples were used for high-pressure methane sorption analysis, X-ray diffraction, Rock-Eval and surface area analyses. Whole rock samples were used for helium pycnometry, mercury immersion and mercury intrusion porosimetry.  4.2.1 Organic Geochemistry  Two methods were used to determine the TOC content. One method measures the inorganic carbon content by coulometric analysis using a C M 5014 CO2 coulometer. A Carlo Erba ® N A 1500 CNS analyser determined the total carbon content. TOC content (wt. %) was determined by subtracting the inorganic carbon content from the total carbon content. The other method for determining the TOC content was using Rock-Eval 6 pyrolysis fitted with a TOC module. TOC is calculated from the amount of CO2 evolved during hydrocarbon generation and also during oxidation at 650°C (Stasiuk et al., 2006).  99  Maturity of the samples was determined from T  m a x  values in degrees Celsius which is  determined from the temperature at the peak of S2. The S2 peak results from the cracking of kerogen and represents the total amount of oil and gas that can be produced from the source rock. A modified van Krevelen diagram is used to plot the hydrogen index (HI=[S2/TOC]/100) and oxygen index (OI=[mgC0 /gm sample/TOC) and provides 2  information of the kerogen types within the shale samples.  4.2.2 High-Pressure Methane Sorption Analysis  Methane capacity of samples was determined by a high pressure volumetric sorption apparatus. Ground samples were placed in an atmosphere over saturated solution of KC1 at 30°C to obtain equilibrium moisture ( A S T M D 1412-04, 2004). A l l analyses reported here were performed under isothermal conditions at 30°C ± 0.1 °C to facilitate sample comparison. Moisture content was measured by oven-drying, weight-loss calculations. Gas volumes are reported in cubic centimeters per gram of rock (cm /g) at an arbitrary 3  pressure of 6 MPa which corresponds to the average reservoir pressure in the study area. This pressure is average of the calculated hydrostatic pressure in the study area. Repeatability of the volumetric sorption analysis is less than ±4% difference in the gas volumes calculated.  100  4.2.3 Shale Mineralogy  Crushed samples were mixed with ethanol, hand ground and then smear mounted on glass slides for X-ray diffraction analysis. A normal-focus Cu X-ray tube was used on a Siemens Diffraktometer D5000 at 40 k V and 40 mA. Relative mineral percentage were calculated using area under the curve for the major intensity peak of each mineral with correction for Lorentz Polarization (Pecharsky and Zavalij, 2003).  4.2.4 Pore Size Distribution  Conventional reservoir evaluation methods investigate porosity on the micrometre scale, however in gas shales, pore sizes range in the micrometre to nanometre scale . The 1  mesoporous surface area of each sample was determined by Micromeritics A S A P 2010 ™ using N2 gas adsorption at low temperature and pressure (-196°C and < 127 kPa) and the five-point Brunauer, Emmett and Teller (BET) method (Brunauer et al., 1938). The pore size distribution in the mesopore and macropore ranges (2-200 nm) were determined between the relative pressures of 0.06 and 0.99 and using the Barrett, Johner and Halenda (BJH) method for adsorption (Barrett et al., 1951). The surface area of micropores were determined by CO2 adsorption using the Dubinin-Radushkevich (D-R) equation at 0°C and using the cross-sectional area of CO2 molecule of 0.253 nm (Clarkson and Bustin, 2  The term microporosity is used for pore sizes that are less than 2 nm, mesopores describe pore sizes of 2-50 nm and macropores are greater than 50 nm (JUPAC, 1997). 1  101  1996). Between 1 and 2 g of sample was degassed at 150°C for 12 hours prior to analysis. Some samples had to be repeatedly dosed with helium and re-evacuated for several days to purge residual volatiles. Repeatability of analysis on this apparatus is ±6%.  The pore size distribution (3-100,000 nm) was also determined by the mercury intrusion technique using a Micromeritics Autopore IV ™ porosimeter. Between 5 and 10 g of whole rock sample were oven dried at 115°C for at least 2 hours. The samples were degassed as preparation to the low pressure intrusion. The high pressure analysis measures the volume of intruded mercury up to the pressure of 414 MPa (60, 000 PSIA). Repeatability of analysis is ±9%.  4.2.5 Total Porosity Measurements  Porosity was calculated by subtracting the skeletal density from the bulk density. Mercury immersion and Archimedes' principle of displacement determined bulk density with an accuracy of less than ± 1 % volume difference and repeatability of analysis is less than ±0.3%. Skeletal density was obtained by helium pycnometry with an accuracy of ±2% of the total volume and repeatability of analysis is less than ±0.3%.  102  4.3 RESULTS AND DISCUSSION  Methane capacity of a total database of 215 samples varies between 0.04 to 1.89 cm /g at 6 MPa (3.2 to 60.4 scf/ton at 870 PSI) (Appendix A). Moisture contents range between 1.5 and 11.0 wt% and the TOC content of the sample suite ranges between 0.53 and 17.0 wt%. The maturity determined by the T  m a x  values, ranges between 416 to 476°C. Total  porosity by helium pycnometry is from 0.84% to 22.1%. Mineralogy is dominated by quartz and illite (Table 4.1). Surface area of micropores, mesopores and combination of both are shown in Table 4.2. Figure 4.3 shows examples of isotherms with various TOC contents and moisture values (Appendix A).  There is a strong correlation between TOC and methane capacity, however there is still a large variation between samples. In the following sections the TOC is shown to be a significant influence in the methane capacity of these shales and by normalization of the data to TOC, the secondary influences on gas capacity are evaluated. Normalization of methane capacity to TOC are calculated by dividing the methane capacity of each sample by its TOC which results in a methane capacity on a per unit TOC volume basis. As TOC is measured on a weight percent basis, then the assumption is made that the density of the kerogen is constant. The assumption although not strictly correct, does not affect on the interpretations in this study, since the TOC varies over a very narrow range.  103  4.3.1 Organic Geochemistry and Methane Capacity  Complex relationships exist between methane capacity and TOC, kerogen types, hydrogen index (HI) and maturity of the organic matter because these properties are strongly interdependent. Kerogen type, hydrogen index (HI) and maturity are interrelated because the HI content is dependant on both the origins of the kerogen type and the maturity; with increasing maturity, both the HI and TOC contents decrease as hydrocarbons are generated.  TOC is the dominating control on methane capacity of these Lower Cretaceous shales. A broad positive correlation exists between TOC and methane capacity (Fig. 4.4). The broad trend indicates that other secondary factors are contributing to the methane capacity of these shales other than TOC. With increasing maturity, there is a decrease in the TOC and a concomitant decrease in the methane capacity (Fig. 4.5). In contrast, methane capacity of coal increases with rank (Gan et al., 1972; Unsworth et al., 1989; Lamberson and Bustin, 1993; Yee et al., 1993; Beamish and Crosdale, 1995; Clarkson and Bustin, 1996; Levy et al., 1997; Prinz et al., 2004; Prinz and Littke, 2005; Chalmers and Bustin, 2007a). The difference in trends between coals and these shales is because with increasing maturity there is a decline in TOC within the shales. Maturity of the organic matter is an artifact of the TOC. The kerogen type is also a consequence of the TOC. Samples that contain Type I and II kerogen have higher methane capacity because they have a greater TOC compared to samples dominated by Type II/III and III (Fig. 4.5). The relationship TOC has with maturity and kerogen type is due to two reason: 1) the  104  loss of TOC through hydrocarbon generation; and 2) the association between increasing mineral matter and maturity towards the deformation front. The increase in the sedimentation rate approaching the deformation front dilutes the concentration of TOC (discussed in detail in the companion paper: Evaluation of regional potential gas resources). The kerogen type also changes from Types I and II to Types II/III and III towards the deformation front. For this reason, samples dominated by Types II/III and III have low TOC contents and low methane capacities compared to Types I and II rich samples.  A broad positive relationship exists between HI and methane capacity (Fig 6A) with kerogen Types I and II (high HI) having a greater methane capacity than Types II/III and III (low HI). A negative relationship exists between HI and methane capacity when the methane capacity is normalized to TOC (Fig. 4.6B) because the methane capacity is controlled by TOC. This observation indicates samples with lower HI contents (Types II/III and III) have a higher methane capacity on a per unit TOC volume basis compared to higher HI (Type I and II) samples.  4.3.2 Shale Mineralogy  The mineralogy of the Buckinghorse Formation and equivalent strata is mainly quartz, illite, kaolinite and to a lesser extent pyrite, dolomite, chlorite, albite, siderite, calcite and gypsum (Table 1). The illite X-ray diffraction peaks are broad and low which sharpened  105  when saturated with KC1 solution indicating that they are degraded due to leaching of potassium cations (Grim, 1968; McConchie and Lewis, 1980). The iron sulphate minerals szomolnokite and rosenite occur within three samples. These minerals are a product of oxidation of sulphides during core storage and therefore they are not included within the discussion on mineralogy.  There are no trends between TOC and the contents of total clay nor quartz. A positive correlation between TOC and clay content is expected due to adsorption of organic matter onto clay during sedimentation (Adams and Bustin, 2001; Toth and Rimmer, 2004). The lack of trends between mineralogy and organic content could be related to the type of organic mater and diagenesis of the shale, as the degree of diagenesis will effect the TOC and illite contents.  To determine whether mineralogy of these shales contributes to the methane capacity, the total clay content and clays separated into types are plotted against the methane capacity on moisture-equilibrated and dried samples. There are no trends between methane capacity on moisture-equilibrated samples with total clay content (Fig. 4.7A) nor with the illite content (Fig. 4.7B). Positive trends exist between methane capacity on a dried basis and normalized to TOC with total clay content (Fig. 4.7C) and illite content (Fig. 4.7D). It has been suggested that illite can sorb methane at high pressures (Lu et al., 1995). There is no correlation between kaolinite or chlorite with methane capacity. Although clay particles sorb methane on a dried basis, the above observations illustrate that for  106  moisture-equilibrated samples, the clay component of a gas shale has mostly lost its ability to contribute to the methane capacity.  The illite content, as a percentage of the total clay content, increases with maturity (Fig. 4.8) which is interpreted to be due to the illitization of kaolinite and smectite. Illitization occurs at temperatures between 80 and 120°C (Potter et al., 2005). Samples in this study have been subjected to temperatures of 50 to ~130°C indicating samples are at different stages of illitization as shown by the range of illite contents, particularly at lower temperatures (Fig. 4.8). Variations in illite contents could also be due to the depositional setting and provenance.  4.3.3 Pore Size Distribution and Methane Capacity  A positive relationship exists between the surface area and methane capacity. The pore structure of a shale is the most important property with respect to the methane capacity as the surface area progressively increases with decreasing pore size for a given pore volume. The pore size distribution controls the methane capacity as shown in coalbed methane studies (Gan et al., 1972; Unsworth et al., 1989; Lamberson and Bustin, 1993; Yee et al., 1993; Beamish and Crosdale, 1995; Clarkson and Bustin, 1996; Levy et al., 1997; Prinz et al., 2004; Prinz and Littke, 2005; Chalmers and Bustin, 2007a). To gain a better understanding on how the TOC, kerogen types, maturity, and mineralogy control the methane capacity, the influence these controls have on pore structure are evaluated  107  here. In the studied shales, microporous surface area correlates more closely with methane capacity than mesoporous surface area (Fig. 4.9A). Micropore surface area is primarily associated with the kerogen as illustrated by high TOC contents containing higher microporous surface area (Fig 9B). The relationship between microporosity, TOC and methane capacity shown by Figures 4.9 A and B illustrate the importance of the TOC content as a control on methane capacity.  Illite is the major contributor to the micropore and mesopore structure of the shales other than TOC content (Fig. 4.1 OA). No correlation exists between mesoporous and microporous surface areas with chlorite and kaolinite.  Microporosity and mesoporosity increase with maturity (Fig. 4.1 OB) which is a reflection of the relationships with TOC and illite content. Low maturity samples have high microporous surface area in comparison to mesoporous surface area because these samples contain high TOC contents (Fig. 4.5 illustrates the association between low maturity and high TOC). Microporous surface area does not increase as significantly as the mesoporous surface area with maturity because 1) TOC is lost with hydrocarbon generation reducing the amount of micropores and 2) the illite content increases which produces more mesoporous surface area than microporous surface area as shown in Fig. 4.1 OA.  Illite has a stronger relationship with the micro- and mesoporous surface areas compared to methane capacity. Similar relationships are expected because the methane capacity  108  increases with increasing surface area. The difference in relationships is because the surface area analysis is on dried samples while the methane sorption analysis is on moisture-equilibrated samples. The moisture content of the sample invariably reduces the methane capacity of samples.  There is a complex interrelationship between TOC, kerogen types, maturity and microporosity. Plotting the micropore volumes for a selection of samples of varying maturity ( T  max  = 420-459°C) illustrates that TOC content is a stronger positive  relationship on micropore volume than the maturity of the sample (Fig. 4.11 A). From previous studies, the micropore volume is expected to increase with maturity (Gan et al., 1972; Unsworth et a l , 1989; Lamberson and Bustin, 1993; Yee et al., 1993; Beamish and Crosdale, 1995; Clarkson and Bustin, 1996; Levy et al., 1997; Prinz et a l , 2004; Prinz and Littke, 2005; Chalmers and Bustin, 2007a). The reason for the opposite trend of decreasing micropore volume with maturity in Figure 4.11A is because TOC also decreases with maturity. A n inverse trend exists when the micropore volume is normalized to TOC with the micropore volume increasing with maturity (Fig. 4.1 IB). In comparison to coals (Chalmers and Bustin, 2007a), these shales show an opposite trend of Type I having a higher micropore surface area compared to Type III (Fig. 4.11 A). Since shales are organic lean in comparison to coal, the difference in micropore volumes more closely reflects the TOC content and not the kerogen type (i.e. macerals). The strong influence of TOC content is also illustrated in Figure 4.12, where Group A (Type I and II kerogens) have high microporous surface areas compared to Group B (Type II/III and III) in Figure 4.12A and when microporous surface area is normalized to TOC, the  109  trend is reversed with Group B have a higher surface area per unit TOC volume, compared to Group A (Fig. 4.12B).  The pore size distribution of the Lower Cretaceous shale is controlled by the TOC content and mineralogy of the shale (Fig. 4.13). A positive relationship exists between the clay content and the volume of mesopores and micropores (Fig. 4.13 A and B). Sample B 95-J-8iso has the lowest clay and the highest quartz contents (Table 4.1) and has the lowest volume of mesopores and micropores (Table 4.2; Figs 4.13 A and B) due to the mineralogy dominated by kaolinite and quartz. Kaolinite has lower sorption capacity compared to other clays (see mineralogy section 4.3.2) due to lower surface areas and quartz contains no internal surface area. There is a general trend of increasing macropore volumes with decreasing clay content within the sample suite, particularly in the 10, 000 to 100, 000 nm range (Fig. 4.13 A) which reflects the increasing volume of quartz (Table 4.1). A greater increase from mesopore to micropore volumes for samples A-30-H-2iso and D-55-H-4iso compared to the other samples show the strong influence of high TOC contents on the micropore volumes (Fig. 4.13B). The analytical temperature can affect the limits of measurable pore sizes. The mesopore volume reaches zero around 6 nm for B-95-J-6iso (Fig 4.13B) which indicates that pores below 6 nm were not detected at a temperature of -196°C (N2 adsorption analysis). However, CO2 adsorption analysis shows that micropores exist within this sample and are detectable at a higher analytical temperature of 0°C.  110  4.3.4 Moisture Content  Moisture content has a negative impact on methane capacity when the moisture is increased within a sample. Moisture content of a shale depends on the TOC as the water molecules are attracted to functional groups of the organic matter (Joubert et al. 1974; Unsworth et al., 1989). A broad negative trend exists between equilibrium moisture and maturity (Fig. 4.14A) because of the loss of TOC and functional groups within the kerogen during maturation. The loss of functional groups in the organic matter results in a decreasing moisture content with increasing coal rank (Mahajan and Walker, 1971). The reduction of the TOC content with maturity also reduces microporosity and the number of sorption sites for water. Kerogen types also effect the moisture content of these shales. The moisture content is higher in the Type II/III and III kerogens when the moisture content is normalized to TOC (Fig. 4.14B) and the higher moisture content is because of the greater amount of micropores found within Types II/III and III compared to Types I and II kerogen (i.e. Fig. 4.1 IB).  The lack of a relationship between TOC and moisture content (Fig. 4.15 A). There is also no relationship between moisture content and total clay content (Fig. 4.15B). The lack of trends between moisture content with clay and TOC contents indicates a complex relationship between these three variables. No trend occurs between the moisture content and the methane capacity (Fig. 4.15C). Since equilibrium moisture is established prior to running methane sorption analysis and methane still sorbs, sorption (hydrophobic) sites are still available to the methane molecule regardless of the moisture content. A broad  111  positive relationship exists between moisture and the sum of the mesoporosity and microporosity (Fig. 4.15D) which illustrates that the surface area of both the clays and TOC contribute to the moisture content. Further investigation is needed into what controls the moisture content.  4.4 SUMMARY AND CONCLUSIONS  The relationships between the geological controls on methane capacity are complex. T O C content is the dominating control on methane capacity of these Lower Cretaceous shales but the trend is broad which indicates other secondary influences are present. The TOC content masks the effects of the other geological controls. Samples that have higher methane capacities are dominated by Type I or II kerogen but these samples have a high gas capacities because of high TOC contents and not because of their kerogen type. If the methane capacity is normalized to TOC, then Type II/III and III kerogens have a greater methane capacity than Types I or II. The Type II/III and III kerogens show greater capacity because they have greater microporosity (on a per unit TOC volume basis) compared to Type I and II kerogens.  TOC content affects the relationship between maturity and methane capacity. The negative relationship between maturity and methane capacity is due to decreasing TOC with maturity. The association between higher maturity and lower TOC is due to  112  hydrocarbon generation and dilution by mineral matter compared to lower maturity samples.  The pore size distribution governs the methane capacity of Lower Cretaceous shales. Microporosity is a strong influence on the methane capacity and from this study both the TOC and illite contents contribute to microporosity. With the increase in illite content with maturity due to illitization (or depositional setting and provenance), there is a greater increase in the mesoporosity compared to the microporosity. The greater increase in mesoporosity is because the illite contains more mesopores than micropores. On a relative scale, the reduction in TOC with maturity has decreased the microporosity and increased the mesoporosity. Both the total clay and illite contents show positive relationships with methane capacity when normalized to TOC and on a dried basis but show no relationships with methane capacity when samples are moisture equilibrated. These observations suggest moisture occupies all the sorption sites within the clay component of the shale when moisture equilibrated.  No correlation exists between moisture and methane capacity. Water and methane molecules must sorb at different sorption sites as a shale can have both a high moisture content and methane capacity. The range in moisture contents decreases with increasing maturity as there is a concomitant decrease in the TOC content. A loss of functional groups within the kerogen with maturity also reduces the moisture content of the shale. Higher moisture content is associated with Type II/III and III kerogens on a per unit TOC  113  volume basis compared to Type I and II. This relationship is due to the greater micropore volume in Type II/III and III kerogen.  114  Figure 4.1: Location of study area and sampled wells. Symbols are keyed to the name of the formation that was analysed.  115  Sikanni Chiefl River, B.C.  Liard Basin  Peace River Northwestern Foothills Moberly Lake Alberta Plains  Central Plains  IpMHMHIMlgrim •  M l  ,  1ESMB  Sully Fm  Sully Fm  Bougie m b  I  Goodrich  Fm  Fm  '\  O, O  Paddy Mb  | Lower Boulder Creek  8-y  Hulcross  Fm  Gates Fm Moosebar  Fm  ~ o  Cadotte  Viking F m  , |  o  Lower Hosier Fm  Tussock M b l ^  Westgate Fm  2  Upper Hosier Fm  "Viking" marker bed "Viking" marker bed Lepine  Fish Scales Fm  a. o O Shaftesbury FmLjl o  Cruiser Fm  Sikanni Fm Sikanni Fm Bougie m b  ,  Belle Fouche Fm  Mb  Harmon Mb FalherMb W i l r i C h Mb Bluesky Fm  I B  ClearwaterFm Glauconitic  I  Figure 4.2: Stratigraphy for Lower Cretaceous strata (Modified after Jowett and Schroeder-Adams, 2005). Predominately shale units are in dark grey and sandstone units are in light grey. F S M B = Fish Scale Marker Bed.  116  Sample ID & T O C Content 2.5  CO  E o  2.0  D-55-H-3iso - 10.2% o • B-95-J-4iso • 6.1% — • — A-30-H-2iso - 7.2% 6-30-80-11iso - 2 . 3 % —v • B-17-H-5iso - 5.2% —••• — # -  •  C-26-A-3iso - 6.8% C-74-J-3iso - 1.6% A-77-D-3iso - 0.8%  o CO  Cl CO  o  c: o o  CO CD  c:  CO  sz 0  4  5  6  Cell Equilibrium P r e s s u r e (MPa)  Figure 4.3: A selection of isotherms with varying TOC contents, see Appendix A for more information on these samples.  117  2.0  n  n  J  0.0 H  0  _ J  1  2  1  4  1  6  1  8  1  10  1  12  1  14  1  16  1  18  TOC (Wt%) Figure 4.4: A positive correlation exists between TOC content and methane capacity. The data have been subdivided into kerogen types.  118  119  2.0  0  100  200  300  400  500  600  500  600  Hydrogen Index (HI) 1.2  0  100  200  300  400  Hydrogen Index (HI)  Figure 4.6: Relationship between HI and methane capacity is due to the association of high HI with high TOC content (A) as the relationship becomes a negative trend between HI and methane capacity when the methane capacity is normalized to TOC content (B).  120  Total Clay Content (%)  Illite Content (%)  Figure 4.7: The relationship between methane capacity normalized to TOC with the total clay (A) and illite contents (B). The relationship between methane capacity normalized to TOC on a dried basis with the total clay (C) and illite contents (D).  121  100  to  80  O  "co 2  60  g  40  c o O CD  £  20  T  420  430  440  450  Maturity ( T  max  460  470  480  ; °C)  Figure 4.8: Plot of illite content as a percentage of the total clay content and maturity.  122  Figure 4.9: Relationship between mesoporous and microporous surface areas with methane capacity (A) and with the TOC content (B).  123  Figure 4.10: The relationship between mesoporous and microporous surface area with maturity (A) and with total clay content (B).  124  - • -  m»x = 420; TOC = 8.0%  T  ' • • ' m » = 428; TOC = 7.2% T  0.0028  - V " max = 436; TOC = 1.2% T  -V-  T „=441;TOC=1.1') m  0.0026 0.0024 O) 0.0022 -| I,  0.0020  CD  E  0.0018 -|  o >  0.0016 -|  C?  0.0014  0  0.0012 Type II/III 0.0010  Type III  ^  Type III  0.0008 1.30  1.35  1.40  1.45  1.50  1.55  1.60  1.65  1.55  1.60  1.65  P o r e W i d t h (nm) 0.018 0.016 H ~  B  0.014 -\  £ o  0.012 H  O  0.010  o o  fc: CD  E _D O > O o 0-  0.008 0.006 0.004 0.002 0.000 1.30  1.35  1.40  1.45  1.50  P o r e W i d t h (nm)  Figure 4.11: The micropore distribution of samples with varying maturity (A) and when the micropore volume is normalized to TOC content (B).  125  80 _^ C5>  A  70  .  •  CO  a)  <  8  CO  t  T y p e II  •  T y p e II/III  V  T y p e III  Group A so  <»  40  8. p  30  CO 2  Type I  O  l o g *«°( I i  •'••Q  o°  T  •*  v  x  o.i . / '  V  T  Group B  T  \ v'»  20 10  420  430  440  450  460  Maturity (T ;°C) X  50  c a> c o  O O O  t to a) < o CO  t CO (0 S o  Q. O  B .'V s  40  i  \  / [  30  \  ..Group B •  20  v--  Group A  10  Cm  V J  . 420  ..y  o 6 " \  %oo8°o°...?. . 430  X . 440  450  460  Maturity (T ;°C) max  Figure 4.12: The relationship between microporous surface area and maturity (A) and microporous surface area normalized to TOC content (B). Kerogen types can be separated into to groups with Types I and II grouped A (dashed lines) and Types II/III and III group B (dash-dot line).  126  0.014  Mesopores -  Macropores  0.012 Sample ID with Total Clay & TOC Contents  • — B - 9 5 - J - 8 i s o - 14%; 5.3% A-30-H-2iso - 57%; 7.2% <w— D-55-H-4iso - 68%; 8.9% A-30-H-4iso - 88%; 2 . 3 %  100  1000  10000  100000  100000CM  Pore Diameter (nm) 0.12 w  <D  Mesopores-  - Macropores-  s  0.10  o Q. O  1  0.08  E o CD  E  0.06  o > CD  O Q.  0.04  0.02  0.00  B  Pore Diameter (nm)  Figure 4.13: Pore size distribution of selected samples with varying quartz contents by mercury porosimeter (A) and also determined by N and CO2 adsorption analyses (B). 2  127  12 • O • V  O  10  o  CD C  -1oK?  o O  -  o o  O  CD  w w o  Type I Type II Type II/III Type III  4  o  410  420  CP  430  440 Maturity (T  450  460  470  480  ; °C)  Figure 4.14: Relationship between moisture content and maturity (A) and when the moisture content normalized to TOC content (B).  B  Type I Type II •  Type II/III  T  \  Type III  •  S_- 8 • c  CD C  O  o  R 6  Q>  1  4  s  •  '3$g'V °  JSf  • • • •  sP°°  4  6  8  10  12  14  16  20  18  40  80  60  100  Total Clay Content (%)  TOC Content (wt%)  D 5 1.5 "E & o S. i.o  3 {/>  o  2  4  6 Moisture Content (%)  8  10  12  4  20  40  60  80  100  Meso + Microporous Surface Area (m /g) 2  Figure 4.15: The relationship between the moisture content and TOC (A), total clay content (B), methane capacity (C) and the meso- and microporous surface area (D).  129  Table 4.1: Mineralogy of the sample suite that were also analysed for pore size distribution. Mineral contents are in volume percent. Sample ID 14-20-77-23W6-2iso 3-21-81 22W6-4iso 4-21-83-17W6-5iso 6-29-81-15W6-4iso 6-30-80-13W6-11iso 6-30-80-12iso 6-30-80-14iso 7-30-80-14W6-3iso 7-30-80-4iso a-1-l-94-H-12-3iso a-30-h-94-l-9-2iso a-30-h-4iso a-32-a-94-H-5-2iso a-5-d-94-H-9-3iso a-65-k-94-P-7-2iso a-65-k-3iso a-77-d-94-0-11-3iso a-77-k-94-P-7-10iso a-77-k-11 iso a-77-k-16iso a-77-k-2iso a-77-k-3iso b-17-h-94-l-9-2iso b-17-h-3iso b-55-e-94-0-13-4iso b-56-e-94-l-10-5iso b-66-d-94-0-15-6iso b-95-j-94-P-12-6iso b-95-j-7iso b-95-j-8iso c-26-a-94-P-11-4iso c-30-k-94-P-6-3iso c-35-b-94-A-14-4iso c-63-d-94-P-1-1iso  total clay 46 48 58 55 35 71 35 47 70 56 57 88 35 45 32 20 49 24 19 59 67 38 67 57 21 54 77 59 36 14 33 46 46 59  chlorite 3 0 0 0 0 7 0 10 9 0 0 2 0 0 0 0 0 0 9 0 2 0 7 10 0 0 10 0 0 0 0 0 0 0  illite 38 32 36 47 30 58 27 20 55 56 53 82 34 39 11 5 29 4 1 51 27 18 58 37 13 51 46 57 33 0 15 33 28 53  gypsum 0 0 0 0 15 0 0 0 0 0 3 0 0 0 0 0 0 0 3 0 0 0 0 0 0 9 0 3 0 0 0 0 0 0  kaolinite 5 16 22 8 5 6 7 18 7 0 4 4 2 5 20 15 20 20 8 8 38 21 3 9 8 3 21 2 4 14 18 13 18 6  quartz 51 51 41 42 49 28 63 46 28 43 39 12 43 54 66 79 51 76 72 40 33 55 32 40 79 36 23 38 63 80 66 53 48 39  pyrite 0 0 1 1 0 0 1 2 0 0 1 0 0 0 2 1 0 1 1 1 0 1 0 2 0 1 0 0 0 3 1 0 0 1  calcite 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1 0 0  dolomite 1 1 0 1 0 0 0 0 0 0 0 0 0 0 1 0 0 0 0 0 0 6 0 0 0 0 0 0 0 0 0 0 1 0  albite 2 0 0 1 1 0 1 6 1 1 0 0 0 1 0 0 0 0 0 0 0 0 0 1 0 0 0 0 0 0 0 0 0 0  siderite 0 0 0 0 0 0 0 0 0 0 0 0 22 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 3 0 0 0 0  Table 4.1: Continued. Sample ID c-8-i-94-H-5-4iso d-55-f-94-P-6-4iso d-55-h-94-P-12-3iso d-55-h-4iso d-57-L-94-H-8-4iso d-65-d-94-P-12-10iso d-65-d-1iso d-65-d-5iso d-66-i-94-G-1-3iso d-71-g-94-l-1-2iso d-75-e-94-N-8-6iso  total clay 59 73 37 68 34 29 35 37 50 74 75  chlorite 5 8 0 3 0 0 0 0 0 12 0  illite 50 39 26 62 25 26 22 21 45 57 72  gypsum 0 0 0 0 0 0 7 9 0 0 0  kaolinite 4 26 12 3 9 3 13 16 6 5 3  quartz 41 26 60 31 65 70 51 52 49 25 24  pyrite 0 0 1 1 0 1 5 2 0 0 0  calcite 0 0 2 0 0 0 2 0 0 0 0  dolomite 0 0 0 0 0 0 0 0 0 0 0  albite 0 0 0 0 1 0 0 0 1 0 1  siderite 0 0 0 0 0 0 0 0 0 0 0  Table 4.2: The mesoporous and microporous surface area with various TOC contents and methane sorption capacities. Sample ID 6-30-80-13W6-11iso 6-30-80-12iso 6-30-80-13iso 6-30-80-14iso2 7-30-80-14W6-4iso a-30-h-94-l-9-2iso a-30-h-4iso a-32-a-94-H-5-2iso a-65-k-94-P-7-2iso a-65-k-3iso2 a-77-d-94-0-11-3iso a-77-k-94-P-7-10iso a-77-k-11 iso a-77-k-2iso a-77-k-3iso b-17-h-94-l-9-2iso b-17-h-3iso b-55-e-94-0-13-4iso b-56-e-94-0-13-5iso b-66-d-94-0-15-6iso b-95-j-94-P-12-6iso b-95-j-7iso b-95-j-8iso c-26-a-94-P-11-4iso c-30-k-94-P-6-3iso c-63-d-94-P-1-1iso c-84-f-94-l-3-2iso c-8-i-94-H-5-4iso d-55-f-94-P-6-4iso d-55-h-94-P-12-3iso d-55-h-4iso d-65-d-94-P-1210iso d-65-d-94-P-7-1iso d-65-d-5iso  Mesoporous Surface Area B E T - N (m /g) 9.3 19.2 17.3 5.0 21.2 13.5 53.0 15.8 1.5 21.5 13.5 7.7 2.0 16.5 18.9 23.3 22.3 20.7 5.2 23.2 38.2 39.4 1.8 26.1 11.4 29.4 32.3 20.8 35.2 15.9 19.2  D-R Equivalent Microporous Surface Area - C 0 (m /g) 27.3 26.8 26.9 21.3 31.1 42.7 50.6 29.3 44.5 52.6 21.2 31.8 47.7 45.0 45.1 31.1 47.6 24.0 28.3 32.7 45.1 39.6 18.6 41.7 43.3 45.4 40.2 32.6 52.4 40.0 46.1  28.1 3.2 17.3  41.0 70.3 49.2  2  2  2  2  Mesoporous & Microporous Surfs Area (m /g) 36.7 46.0 44.2 26.2 52.3 56.2 103.7 45.1 46.0 74.1 34.8 39.5 49.7 61.5 64.0 54.4 69.8 44.6 33.5 55.9 83.3 79.0 20.4 67.9 54.7 74.8 72.5 53.5 87.6 56.0 65.2 2  69.1 73.5 66.5  132  4.5 REFERENCES  Adams, R.S. and Bustin, R . 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A A P G Studies in Geology, Chapter 9, A A P G , Tulsa, Oklahoma, 74101 U S A , p. 203-218.  136  CHAPTER FIVE  LOWER CRETACEOUS GAS SHALES IN NORTHEASTERN BRITISH COLUMBIA, PART II: EVALUATION OF REGIONAL POTENTIAL GAS RESOURCES  5.1 INTRODUCTION  Thick, organic-rich, Lower Cretaceous shales in northeastern British Columbia are a promising exploration target due to their lateral extent, thickness, maturity and organic richness. Additionally, these shales have potential in areas of existing infrastructure and are behind pipe (within existing wells) in a field that has declining gas resources.  At a reservoir scale, gas shale potential is primarily evaluated by measuring the methane capacity at reservoir pressure. To calculate the gas shale potential, the measurements for methane sorption capacity are expanded to include both the free gas component (total gas content) and the thickness of the play. Gas shale capacity is controlled by the TOC content, kerogen types, maturity, moisture content, pore size distribution, mineralogy, stratal thickness, depth of burial and reservoir pressure and temperature. In order to understand the regional distribution of the methane capacity of a gas shale, there is a need to identify spatial relationships between these various geological controls. The evolution of the sedimentary basin influences the distribution of the geological controls of methane A version of this chapter has been submitted for publication. Chalmers, G.R.L. and Bustin R . M . Lower Cretaceous gas shales in northeastern British Columbia, Part II: Evaluation of regional potential gas resources. CSPG Bulletin.  137  capacity because basin evolution dictates the stratal thickness, geometry, basin structure and the sedimentation and subsidence rates.  Previous work on gas shales have only superficially considered the characteristics of producing shales within the eastern and southern United States of America (Hill and Nelson, 2000; Montgomery et al., 2005). The problem, in part, is that each play has a set of unique characteristics and the geological controls are not identical between stratigraphic levels or basins, indicating the need for the individual assessment on controls of methane capacity. The Lower Cretaceous shales in northeastern British Columbia provide an unique opportunity to systematically investigate the geological controls and their effect on the regional distribution of gas shale capacity (Figs 5.1 and 5.2).  Objectives of this paper are to identify: 1) the lithological distribution of the Lower Cretaceous strata in northeastern British Columbia, particularly the organic-rich basal (ORB) layer; 2) the distribution of the kerogen concentration, types and maturity; 3) the distribution of the total porosity; 4) areas that contain high gas sorption capacities and total gas capacities; 5) reservoir pressure and temperature; 6) the controls on permeability; and 6) the mineralogical changes across the study area.  This paper is divided into two sections. The first section identifies the geometry of the potential play of the Buckinghorse Formation. The first section also highlights the spatial relationships between the geological controls on methane capacity with respect to the  138  evolution of the W C S B and palaeogeographic setting. The second section evaluates the resource by illustrating the distributions of the sorbed gas, total gas and gas-in-place (GIP) estimates and identifies the geological controls on these distributions. Matrix permeability, natural fractures and facies changes are also considered as they are important controls on producibility.  5.2 GEOLOGICAL BACKGROUND  5.2.1 Lithological Distribution  Relative sea level and palaeotopography controlled the timing of the deposition of the Buckinghorse Formation and it equivalents. The Lower Cretaceous shales in northeastern British Columbia have been given a variety of names which includes the Buckinghorse, Moosebar, Garbutt and Wilrich formations. The Buckinghorse Formation is a dark grey shale with a thickness estimated to be 1000 m (Hage, 1944) (Fig. 5.2). The basal contact is transitional with the underlying sandstone of the Gething Formation. The shale coarsens upwards into siltstone and thin sandstone beds grading into the first sandstone member of the Sikanni Formation (Hage, 1944; Stott, 1982). The Moosebar Formation is the stratigraphic equivalent of the Buckinghorse Formation (Fig. 5.2) and decreases from 300 m thick at its type locality near Hudson Hope (Fig. 5.1) to 30 m towards the southeast into western Alberta (Stott, 1982; McLean and Wall, 1981). Overall, the  139  Moosebar shale coarsens upwards into siltstone and eventually into fine sandstone of the Gates Formation. The Garbutt Formation is the northern stratigraphic equivalent of the Moosebar Formation (Fig. 5.2). The Garbutt Formation is a black silty shale which gradually coarsens upwards into the sandstone of the Scatter Formation (Leckie and Potocki, 1998). The thickness varies from 379 m in the southern part of Liard Basin (Fig. 5.1) to 82 m in the northeast of the basin (Leckie and Potocki, 1998). The base of the unit contains a 10 to 20 m radioactive bed which represents a condensed section (Leckie and Potocki, 1998). A regionally extensive, sharp contact between the Scatter Formation and the overlying shales of the Lepine Formation is referred to as the "Scatter marker" (Jowett and Schroeder-Adams, 2005). Lithological correlation, sedimentology and palaeogeography of the Lower Cretaceous strata in the map sections 93-P and 94-A (Fig. 5.1) are extensively documented (e.g. Stott, 1982; Taylor and Walker, 1984; Leckie, 1986). Recently, correlation of Lower Cretaceous strata into the northern sections of the basin have been completed by using key flooding surfaces and biostratigraphy which illustrate the changes in stratal geometry (Schroeder-Adams and Peterson, 2003; Webb et al., 2005; Jowett and Schroder-Adams, 2005).  5.2.2 Depositional Environments  The depositional environment of the Buckinghorse Formation is considered by Hayes et al. (1994) to be open marine mid-basin to shallow seas. The basal section of the shale is pyrite and organic rich, homogenous and massive suggesting the bottom waters were  140  depleted of oxygen (Stott, 1982). Foraminifera indicate normal salinity, but with restricted circulation and water depths of 30 m in the south to 180 m in the north (Stott, 1982). Depositional environments for the Moosebar Formation have been described as wave-dominated, prograding-shoreface setting (Taylor and Walker, 1984) or prodeltaic to offshore-transitional-shoreface setting (Karst, 1981; Leckie et al, 1988). The depositional environment of the Garbutt Formation is described as wave-dominated shelf conditions (Leckie and Potocki, 1998).  5.2.3 Basin Evolution and Structural Controls  Basin evolution during the Early Cretaceous was initiated by allochthonous terrane accretion which created renewed subsidence of the foreland trough with the maximum subsidence occurring adjacent to the deformation front (Smith, 1994). Sediments were shed off the tectonically active highlands into the foreland trough to the east (Leckie and Smith, 1992). Both subsidence and sedimentation rates decreased from the deformation front towards the east to the stable eastern platform (Leckie and Smith, 1992).  Major structures within the study area that have affected the accommodation space and accumulation of sediment are; the Cordilleran deformation front, the Bovie Structure, extensional tectonics in the Pink Mountain area and the Peace River Arch (Fig. 5.1). During the Cretaceous, the deformation front and the Bovie Structure both increased the accommodation space along the western margin of the basin. The Bovie Structure had a  141  significant influence on accommodation space in the Liard Basin (Fig. 5.1). During the Jurassic to Cretaceous periods, the Pink Mountain area (Fig. 5.1) experienced extensional tectonics which created a negative feature within the Early Cretaceous palaeosurface (Hinds, 2002; Hinds and Spratt, 2005) and led to increased thickening of the Cretaceous strata. Erosion of the Upper and some of the Lower Cretaceous strata occurred over the Peace River Arch (PRA) and has reduced the depth of the Moosebar (Wilrich) Formation (Leckie et al., 1990).  5.2.4 Palaeogeography  Although the Garbutt Formation is the northern lithostratigraphic equivalent of the Moosebar-Wilrich Formations, these formations are diachronous as illustrated by the palaeogeography in Smith (1994). Deposition of the Garbutt Formation began simultaneously with the deposition of the Cadomin and Gething/Bluesky formations to the south. The Keg River palaeohigh (Fig. 5.1) acted as a barrier to the prograding sediments from the south and southwest which starved the shallow shelf of sediments (Smith, 1994) and created a condensed section in the northeast of the study area (map section 94-P) (Leckie and Potocki, 1998). As relative sea-level increase submerged the palaeohighs, shale deposition moved to the south into the Deep Basin area (Fig. 5.1) and deposited the Moosebar (Wilrich) Formation. Simultaneously, the Scatter Formation was deposited in and to the east of the Liard Basin with sediment being sourced from the active deformation front to the west (Leckie and Potocki, 1998).  142  5.3 METHODS  A total of 215 samples were analysed for methane sorption capacity from 87 wells across northeastern British Columbia (Fig. 5.3). From these samples, moisture content and total porosity were measured. Rock-Eval analyses were performed on at least one sample from each well and suite of samples with a variation in TOC content, mineralogy and porosity were then analysed for permeability.  5.3.1 Stratigraphic Cross-sections, Isopach and Structure Maps  Seven cross-sections with a combined length of 1285 km and an average well spacing of 20 km were constructed to tie analysed wells within the study area (Fig. 5.3). Correlations were based on flooding surfaces within the distal portions of the basin and lithological changes within the southern portion of the basin where the Falher/Gates/Notikewin shoreface sandstones developed. Gamma ray and resistivity logs were used with sonic or density being substituted when the latter were not available. Spontaneous potential logs were used if gamma-ray logs were unavailable or did not cover the whole formation.  Isopach maps were constructed by identification of formation tops in wire-line logs for the entire study area (Fig. 5.3). The focus of this study is on an organic-rich basal (ORB) layer in the Buckinghorse Formation and sampling was focused within this/interval. The separation of the ORB layer of the Buckinghorse Formation includes the radioactive  143  marker that was described by Leckie and Potocki (1998). Stratal thicknesses were calculated for the both O R B layer and for the Moosebar-Garbutt-Wilrich formations and stratigraphic equivalent in the Buckinghorse Formation which included the ORB layer and the coarsening-upward siltstone to the first sandstone unit of the Gates-Scatter Formations. Isopach maps have been constructed for: 1) the ORB layer; 2) MoosebarGarbutt-Wilrich formations; and 3) the total Buckinghorse Formation.  5.3.2 Organic Geochemistry  Two methods were used to determine the TOC content. One method measures the inorganic carbon content by coulometric analysis using a C M 5014 CO2 coulometer. A Carlo Erba ® N A 1500 CNS analyser determined the total carbon content. TOC content (wt. %) was determined by subtracting the inorganic carbon content from the total carbon content. The other method for determining the TOC content was using Rock-Eval 6 pyrolysis fitted with a TOC module. TOC is calculated from the amount of CO2 evolved during hydrocarbon generation and also during oxidation at 650°C (Stasiuk et al., 2006). Maturity of the samples was determined from T  r a a x  values in degrees Celsius which is  determined from the temperature at the peak of S2. The S2 peak results from the cracking of kerogen and represents the total amount of oil and gas that can be produced from the source rock. A modified van Krevelen diagram is used to plot the hydrogen index (HI=[S2/TOC]/100) and oxygen index (OI=[mgC0 /gm sample/TOC) and provides 2  information of the kerogen types within the shale samples.  144  5.3.3 High-Pressure Methane Sorption Analysis  Methane capacity of samples was determined by a high pressure volumetric sorption apparatus. Ground samples were placed in an atmosphere over saturated solution of KC1 at 30°C to obtain equilibrium moisture ( A S T M D 1412-04, 2004). A l l analyses reported here were performed under the same isothermal conditions at 30°C ± 0.1 °C in order to compare samples. Moisture content was measured by oven-drying, weight-loss calculations. Gas volumes are reported at standard temperature and pressure (STP) in cubic centimeters per gram of rock (cm /g) at hydrostatic pressure. Repeatability of 3  analysis is less than ±4% difference in the gas volumes calculated.  5.3.4 Porosity and Total Gas Capacity  Porosity was calculated by subtracting the skeletal density from the bulk density. Mercury immersion and Archimedes' principle of displacement determined bulk density with an accuracy of less than ± 1 % volume difference and repeatability of analysis is less than ±0.3%. Skeletal density was obtained by helium pycnometry with an accuracy of ±2% of the total volume and repeatability of analysis is less than ±0.3%.  The total gas capacity is the measurement of the maximum volume of sorbed, free and solution gas within the shale. To calculate the total gas capacity, the volume occupied by  145  sorbed gas is subtracted from the total porosity to yield the porosity available to free gas. This calculation assumes that all pores (accessible to helium) are accessible to methane and the water saturation is zero (S = 0) as the porosity of these samples was analysed on w  a dried basis because no fresh core was available.  5.3.5 Permeability  Intrusion data from a high pressure mercury (Micromeritics ™ Autopore IV) porosimeter was utilised by applying the equations of Swanson (1981). Permeability data presented here is the equivalent brine permeability at a confining pressure of 6.9 MPa. Although sample depth and confining pressure vary, the data serve to compare and contrast within the data set and do not necessarily represent in-situ values. Between 5 and 10 g of whole rock samples were oven dried at 115°C for at least 2 hours and evacuated in preparation for the low pressure intrusion. Low pressure intrusion is between the pressures of < 50 um Hg to atmospheric pressure. The high pressure analysis measures the volume of intruded mercury from atmospheric pressure to 414 MPa (60,000 PSIA). This allows measurement of pore sizes in the range of 100 um to 3 nm which includes the macro- and mesopore size ranges (IUPAC, 1997). The porosimeter is programmed to allow the mercury and sample to equilibrate at each pressure step.  146  5.3.6 Mineralogy  Crushed samples were mixed with ethanol, hand ground and then smear mounted on glass slides for X-ray diffraction analysis. A normal-focus Cu X-ray tube was used on a Siemens Diffraktometer D5000 at 40 k V and 40 mA. Relative mineral percentages were calculated using area under the curve for the major intensity peak of each mineral with correction for Lorentz Polarization (Pecharsky and Zavalij, 2003).  5.4 RESULTS & DISCUSSION  5.4.1 Structure and Stratigraphy  The total vertical depth to the base of the Buckinghorse Formation ranges between 400 and 1800 m. Majority of sampling is concentrated at the base of the Buckinghorse Formation. The structure map to the base of the Buckinghorse Formation highlights the Liard Basin in the northwest of the study area with the Bovie Structure (BS) as the eastern margin of the basin (Fig. 5.4). The depositional dip of the basin is to the west and the regional dip steepens to the south (93-P) where the study area borders the northern margin of the Deep Basin (Fig. 5.4). The shallowing that occurs within 94-A is associated with the regional structure of the P R A (Fig. 5.4).  147  5.4.2 Isopach  The total thickness of the Buckinghorse Formation ranges between 260 and 1636 m (Fig. 5.5). The thickest section occurs on the west side of the Bovie Structure (Fig. 5.1) within the Liard Basin (see Figs 5.1 and 5.5).  The major depocentres within the study area (Fig. 5.5) are: a) the Liard Basin (94-N/94-0 section); b) central 94-J section; c) Trutch area (94-G section); and d) the Deep Basin (93-P). These depocentres are proximal to the deformational front where subsidence and sedimentation rates were high. There are two depocentres within the Liard Basin (94-N and 94-0) that are highlighted by the ORB layer isopach map (Fig. 5.6A). A similar pattern was observed by Leckie and Potocki (1998) for the overlying Scatter Formation. From the isopach map (Fig. 5.6A), we interpret the localized thinning of the ORB layer as a reflection of the topography prior to the transgression of the Moosebar Sea. Thinning occurs on positive features that were produced by river deposits of the Gething Formation (southern 94-H section) and the alluvial fans of the Cadomin Formation (adjacent to deformation front) (e.g. Smith, 1994). Swamps and lakes would develop adjacent to the channels which became depressions during a transgression. The ORB layer thickens across the boundary of map sections 94-1 and 94-H which results in the thickening of the ORB layer as these depressions infill. This is conceptually similar to the "Puddle Model" (Wignall, 1994) in that the importance of topography on the development of black shales during the initial stages of transgression. Depressions act as small basins where water circulation is restricted and the stagnation preserves more organic matter within the basal  148  transgressive black shale than areas of higher elevation. The ORB layer thins towards the northeast into map section 94-P to only 10 to 30 m thick which follows the regional structure and thinning of the Buckinghorse Formation to less than 300 m (Fig. 5.5). This thinning is a reflection of the lower sedimentation and subsidence rates in map section 94-P.  The Moosebar-Wilrich-Garbutt formations are thickest along the deformation front (Fig. 5.6B) where subsidence and sedimentation rates were higher. The thickening of the Moosebar-Garbutt-Wilrich formations along the boundary of 94-G and 94-H (Fig. 5.6B) could be related to the extensional tectonics that were active in the Pink Mountain area during the Cretaceous (Hinds, 2002; Hinds and Spratt, 2005).  5.4.3 Stratigraphic Cross-sections  Three stratigraphic cross-sections (Figs 5.7 to 5.9) illustrate the stratal thickness and geometry of the clean sandstones (light grey), organic-rich shales (dark grey) and the siltstones/organic-lean shales (medium grey). Four additional stratigraphic cross-sections are located in Appendices A to D.  Flooding surfaces result from a rapid increase in accommodation which leads to a sharp contact between a coarser-grained unit and an overlying finer-grained unit, typically a marine shale. Five flooding surfaces (FS 1, 2, 3, 4 and 5) are identified within the cross-  149  sections by an abrupt increase in gamma ray response because of a rise in the clay and/or organic matter contents. The first three surfaces can be identified throughout the study area with a fourth (FS 4) occurring within the map section 94-H, and a fifth (FS 5) in map section 94-G at the top of the Buckinghorse Formation in cross-section A - A ' (Fig. 5.7). Towards the northern end of cross-section A ' - A " (Fig. 5.8) and the western end of crosssection B - B ' (Fig. 5.9) the three upper flooding surface (FS 2, 3 and 4) coalesce into one flooding surface between wells # C-85-J-94-P-12 and A-65-K-94-P-7. The amalgamation of the three flooding surfaces is interpreted as a second condensed section, above the condensed section that Leckie and Potocki (1998) identified at the base of the Garbutt Formation. The second condensed section is part of the "Scatter Marker". The "Scatter Marker" is FS 2 (used as a datum in all cross-sections) and is equivalent to the basal section of the Hulcross Formation in the south of the study area (Fig. 5.7). The distance between the "Scatter Marker" and the ORB layer becomes thinner, separated by a thin Scatter Formation at the north end of cross-section A ' - A " illustrating the decrease in stratal thickness towards the northeast. The appearance of the Scatter Formation within the map section 94-H (south end of cross-section A " - A ' ) and its increase in thickness towards the north occurs as the thickness of the shale thins within the Buckinghorse Formation. Low sedimentation and subsidence rates in map sections 94-P, 94-1 and 94-H area have produced the two condensed sections and the shale units are also thinner in comparison to the southern portion of the study area (Fig. 5.6A). A n increase in the sediment supply and/or a decrease in subsidence during the deposition of the Scatter and Lepine formations, produced thicker sandstone units in the low accommodation areas of map sections 94-1 and 94-P.  150  The Buckinghorse Formation is the thickest in the Deep Basin area and in maps sections 94-G and 94-B (Fig. 5.7). Extensional tectonics occurred within map section 94-G during the Early Cretaceous (Hinds, 2002; Hinds and Spratt, 2005) and accommodation space was high in the Deep Basin area (Jackson, 1984). The Buckinghorse Formation becomes thicker towards the western end of cross-section B - B ' (Fig. 5.9) because the Bovie Structure was active during deposition and increased accommodation space (Leckie et al. 1991; Leckie and Potocki, 1998). The ORB layer is also the thickest within areas that contain thicker Buckinghorse Formation. The Buckinghorse Formation thins between wells A-1-J-94-B-9 and 6-01-80-23W6 where the Sikanni and part of the Boulder Creek formations have been eroded (Fig. 5.7). This thinning has occurred in the area that contains the P R A (Wright et al., 1994). The P R A is also highlighted by the thinning of strata in the isopach of the Buckinghorse Formation in 94-A (Fig. 5.5). Erosion of the Cadotte Member, equivalent (in part) to the Lepine Formation, has also been reported in the P R A area by Leckie et al. (1990).  5.4.4 Organic Geochemistry  5.4.4.X Total Organic Carbon Content  For the entire region, the TOC ranges between 0.2 to 16.99 wt % with an average of 2.52 wt % (Fig. 5.1 OA; Appendix E). The TOC concentration is highest (> 3 wt%) in the  151  northeast section of the study area (94-P and 94-1) and the lowest concentrations (< 1 wt%) occur along the deformation front.  The regional distribution of TOC within the study area is controlled by the inorganic sedimentation rate and the level of maturity. Sedimentation and subsidence rates control the stratal thickness and depth of burial. The depth of burial influences the maturity and the degree of hydrocarbon generation as an inverse relationship exists between TOC and maturity. The sedimentation rate also directly influences the TOC content as an increase in the sedimentation rate dilutes the TOC concentration. This is assuming the TOC rate is relatively constant, in comparison to the changes in sedimentation rates across the basin. For example, the clastic input was higher along the deformation front as illustrated by the isopach maps (Figs 5.5 and 5.6) and cross-sections (Figs 5.7 to 5.9) and these areas have the lowest TOC concentrations (Fig. 5.1 OA). Although kerogen additional to that formed in-situ was being transported into the basin from the coastal areas and deposited proximal to the defoimational front, this is relatively low in comparison to the increase in clastic sediments. Oxygen-laden waters reduced the organic matter content by decomposition and also promoted bioturbation of the sediment further reducing the TOC content along the deformation front. The observation of an inverse relationship between stratal thickness and TOC concentration is the result of high sedimentation and subsidence rate that increases maturity and dilution of the TOC content. During the development of the condensed section in the Lower Cretaceous shale in the map section 94-P (Leckie and Potocki, 1998), the Keg River palaeohigh further reduced the clastic input from the  152  coastal plain to the south (Smith, 1992) which starved this area from sediments and resulted in a relative increase in the TOC content.  5.4.4.2 Kerogen Types  Majority of the samples contains a mixture of Type II and III kerogen (Figs 5.1 OB and 5.11; Appendix E). A number of samples, mostly from the map sections 94-P and 94-1 contain Type I to Type II kerogen (Fig. 5.11). From the deformation front to the northeast of the study area (94-P), the kerogen types change from Type III to a mixture of Types II/III to Types I and II. Type III kerogen occurring proximal to the deformation front is consistent with kerogen being terrestrially-sourced from the coastal areas. Large terrestrial wood fragments (e.g. branch and fern impression) occur within the shale in 94P and northern part of 94-1 even though kerogen types are dominated by I and II. The Keg River palaeohigh (Fig. 5.1) was emergent and vegetated during the initial stages of the deposition of the Garbutt Formation and supplied terrestrial plant fragments to these areas.  5.4.4.3 Maturity  Maturity as measured from Rock-Eval, ranges between the T  m a x  of 407 and 476°C  (Appendix E). Regional maturity (Fig. 5.10C) shows a general trend similar to the  153  regional structure (Figure 5.4). Higher temperatures were experienced within the Deep Basin, the Liard Basin and 94-H due to the greater depths of burial and/or higher heat flow.  The majority of the study area is in the wet to dry gas window while map sections 94-P and the eastern portion of 94-1 are in the oil window (Fig. 5.10D; Appendix E). The dry gas window parallels the deformation front as the close proximity has: 1) delivered terrestrially-derived (Type III) kerogen which are more prone to generate gas; and 2) experienced greater burial and maturity. The greater depth of burial and/or higher heat flow with high TOC contents in the western portion of map section 94-H have also increased the potential for dry gas generation (Fig. 5.10D).  5.4.5 Shale Mineralogy  Samples are dominated by quartz (12-80%) and illite (0-82%) with up to 38% kaolinite and 12% chlorite (Table 1). Siderite (0-22%) and gypsum (0-15%) are abundant in some samples. Minor contents of pyrite, calcite, dolomite, and albite occur. The majority of the illite is degraded. Mineralogy of these shales is mainly detrital but the illite abundance also reflects diagenesis of the shale. Areas that have high illite content occur along the deformation front in map sections 93-P, 94-G, 94-N and also in 94-1 section (Fig. 5.12A). Apart from the depositional setting and provenance, the degree of maturity has influenced the distribution of illite across the study area. Higher maturity occurs within map areas  154  that contain high illite contents (93-P, 94-G and 94-N). Chalmers and Bustin (submitted) showed the illite content increases with maturity through the process of illitization of kaolinite and smectite.  Cores from the map area 94-P and 94-1 include thin-bedded siltstones and fine sandstones that are interpreted as turbidites (Fig. 5.13). High detrital quartz content is found within the 94-P section which is derived from the Keg River palaeohigh to the south (Fig. 5.1). The detrital quartz was episodically being transported into the sediment-starved area as thin turbidite beds. Well A-77-K-94-P-7 contains a conglomeratic bed within the shale sequence (Fig. 5.13) which contains up to cobble-sized, subrounded-chert clasts. These chert clasts are most probably derived from the Permian Belloy Formation or Devonian to Triassic conglomeratic beds that were exposed in the Keg River Palaeohigh (Smith, 1994).  5.4.6 Methane Sorption Capacities  At reservoir pressures (Appendix B), sorption capacities range between 0.03 (0.96 scf/ton) and 1.86 cm /g (59.5 scf/ton) with an average of 0.54 cm /g (17.3 scf/ton) 3  3  (Appendix F). Average hydrostatic pressure across the study area is 8.8 MPa with pressure varying from 2.9 to 17.8 MPa. The highest methane sorption capacities are found in map sections 94-P, 94-1, 94-H, 94-N and 94-0 (Fig. 5.14). High capacities in 94-  2  For this study, reservoir pressures are assumed to be equal to the hydrostatic pressure.  155  P and 94-1 reflect high TOC contents while the high capacities in 94-H, 94-N and 94-0 are because of higher reservoir pressures.  5.4.7 Total Gas Capacities  Total porosity of the shale ranges between 0.7 and 16%, with an average of 6.5% (Fig. 5.15A; Appendix F). At reservoir pressure, total (free + sorbed) gas capacity ranges between 1.49 and 14.5 cm /g, with an average of 5.7 cm /g (Appendix A). In Figure 3  3  5.15B, the highest total gas capacities are found within map section 94-N because of the high reservoir (hydrostatic) pressures and lowest in 94-A because of lower reservoir pressures. Erosion of the Sikanni and part of the Lepine formations has reduced the depth to the sampled interval which resulted in lower reservoir pressures. Total gas is relatively high in map sections 94-1 and 94-H because of the higher porosity and higher pressures than adjacent areas (Fig. 5.15A).  5.4.8 Gas-In-Place (GIP) Estimates  Regional gas-in-place (GIP) estimates have been calculated for the ORB layer (Fig. 5.16A) and also for the Garbutt-Moosebar-Wilrich formations (Fig. 5.16B) at reservoir pressure (Appendix F). GIP estimates have been made at constant (analytical) temperature (30°C) and have not been calculated to reflect the changes in reservoir  156  temperature across the basin. The reservoir temperature (defined from bottom-hole temperatures) for the analysed wells range between 8.8 and 63.4°C with an average of 30.2°C (Fig. 5.17). A negative, exponential relationship exists between methane capacity and temperature (Fig. 5.18). The capacity decreases rapidly from 10 to 30°C and then plateaus above 30°C. The four plotted sampled in Figure 5.18 have TOC ranging between 1.0 and 17.0 wt%. There is less variation in methane capacity with temperature for samples that have low TOC contents (e.g. 1.0 and 3.2 wt%) compared to the high TOC samples (8 and 17 wt%). Samples that are at reservoir temperatures less than 30°C and have high TOC values have slightly higher methane capacities than those presented in this paper. Methane capacities would therefore be higher within the northeast of the study area (94-0, 94-P and 94-1).  GIP estimates are based on the total porosity, sorbed gas capacity, thickness of the strata and the reservoir pressure. For the ORB layer, the southwestern portion of map sections 94-1, 94-N and 94-0 have the greatest GIP potential (> 24 bcf/section) because of: 1) greater thickness; and 2) high porosity. High estimates for the ORB layer in 94-N and 94O are due to the higher reservoir pressures because of the greater depths. When comparing the GIP estimates for the Garbutt-Moosebar-Wilrich formations, there is a significant increase towards the northwest because of the thicker sequence within the Liard Basin (Fig. 5.16B). Both the reservoir thickness and pressure increase the GIP for the Garbutt-Moosebar-Wilrich Formations to over 300 bcf/section in 94-N.  157  5.4.9 Producibility Considerations  Matrix permeability, determined by mercury porosimetry, of the Lower Cretaceous shale ranges between 0.0005 and 0.3 md. Permeability decreases with increasing depth and the shallower samples have a greater range in permeability values (Fig. 5.19). This trend is similar to the relationship between porosity and depth as both permeability and porosity decrease with increasing diagenesis. Mineralogical (e.g. illite and quartz contents) and fabric differences (i.e. degree of anisotropy) may account for the large variation in permeability of shallow samples. The reason some shallow samples have low permeability is because they were at greater depths compared to present depths due to removed of overlying strata (e.g. samples located on the PRA). Samples across the P R A (Fig. 5.8) would have been at least 650 m deeper than present assuming the strata were uniform thickness across the P R A area.  Natural fractures and occurrence of coarser-grained facies within the shale would increase gas flow to the well. Natural fractures occur in the Buckinghorse Formation (Figs 5.20A and B) and are either open, partially mineralized or fully mineralized by calcite, quartz or pyrite. Some fractures show bitumen staining (Fig. 5.20A). Natural fractures can concentrate within shale sequences in areas where isolated sand bodies taper out (Cherven and Fisher, 1992; Cosgrove and Hillier, 2000). Differential compaction between lithologies produces forced-drape folds and natural fractures will concentrate within the shale sequence. From the cross-sections, the greatest number of sandstone  158  units that taper out in the Garbutt-Moosebar-Wilrich formations are found in map section 94-H and thus this area may contain a favourable concentration of natural fractures.  Facies changes from shale to coarser-grained beds occur in the Buckinghorse Formation (Fig. 5.13; Figs 5.20C and D). Thin fine-sandstone beds and lenses that contain ripples are interpreted as tempestites and are due to changes in depositional energy during storm events (Fig. 5.20D). Fining-upward packages of fine sandstone, siltstone to claystone that contain biotite crystals and bentonite and are interpreted as volcanic deposits (Fig. 5.20C).  5.5 EXPLORATION CONSIDERATIONS  The gas shale resource potential of Lower Cretaceous shale in northeastern British Columbia has been evaluated from the measurement of the sorbed gas, total gas and gasin-place estimates. The sorbed gas content is controlled by TOC and the total gas content is calculated from the sorbed gas content and total porosity. The gas-in-place estimates are controlled by the total gas content and the stratal thickness.  With the general trend of increasing play thickness with depth of burial (i.e. Liard Basin map sections 94-N and 94-0), there is a concomitant increase in the reservoir pressure and these factors increase the GIP even though TOC is relatively low. TOC, however small the quantity, is still an important component because it is the source of the methane.  159  With increasing depth of burial there is loss in porosity and permeability which reduces the free gas component and the producibility of the shale. Since shale reservoirs have low permeability, induced fracturing will be important and therefore the geological controls on the rock mechanics need to be considered.  5.6 CONCLUSIONS  • TOC distribution has an inverse relationship with stratal thickness due to mineral matter dilution because of high sedimentation rates. Low TOC contents occurs adjacent to the deformation front and TOC content increases towards the northeast (i.e. 94-P) • Highest TOC contents are found in condensed sections in 94-P where the ORB layer is the thinnest and flooding surfaces coalesce. Sedimentation was slow and ocean circulation was restricted by the topography during the Moosebar Sea transgression. • Keg River Palaeohigh within 94-1 was the source of quartz and terrestrial plant fragments during the deposition of the ORB layer in 94-P. The palaeohigh also acted as a barrier to sediments prograding from the south and further reduced the sedimentation rates within 94-P. • Greater maturity occurs along the deformation front, in particular, the Liard and Deep basins due to greater burial and/or high heat flow. Maturity lessens from dry gas window adjacent to the deformation front to oil-prone towards the northeast.  160  • Highest sorbed-gas capacities are found in 94-P and 94-1 because of the high TOC contents but lower maturity indicates less gas generation compared to areas adjacent to the deformation front. • High total-gas capacity and GIP estimates occur in 94-1 because of the high porosity and greater thickness of the ORB layer compared to rest of the study area. High GIP estimates occurring adjacent to the deformation front are due to higher reservoir pressures. • Methane capacity is greater i f reservoir temperatures are below 30°C and TOC content is high. The northeast part of the study area would have greater methane capacities than what is presented in this paper. • The Garbutt-Moosebar-Wilrich formations and equivalent strata have large GIP estimates within 94-N because of the greatest depth of burial, stratal thickness and reservoir pressures. • Matrix permeability decreases with depth. • Greatest potential for gas shale development is within 94-P because of the high TOC and sorbed gas contents or along the deformational front where higher reservoir pressures have created high total gas capacities.  161  Fig. 5.1. Study area in northeastern British Columbia and structures that have influenced sedimentation of the Lower Cretaceous strata; the Peace River Arch (Wright et al., 1994), Deep Basin (Masters, 1984), Keg River Palaeohigh (Smith, 1994) and Bovie Structure (Price, 1994). The eastern margin of the study area is the border between British Columbia and Alberta and the western margin is the deformation front.  162  Peace River Foothills Moberly Lake Dunvegan Fm  Sully F m  Northwestern Geophysical! logs Alberta Plains Dunvegan Fm.  Cruiser F m Goodrich Fm  Bougie m b  Upper Hosier F m  Viking" marker bed  "Viking" marker bed  10-22-83-21W6 Shaftesbury F m  GR (API)  6  150 IL (ohmms)  Paddy Mb  100  Lower Hosier F m Lower Boulder Creek  Cadotte Mb  Hulcross F m  Harmon M b  Gates Fm  Notikewin Mb Falher Mb  Moosebar Fm  Wilrich M b Bluesky F m  Fig. 5.2. Stratigraphic table of the Lower Cretaceous strata for northeastern British Columbia and northwestern Alberta. A geophysical-log example through the relevant formations is inset. Location of the Liard Basin, Sikanni Chief River and Moberly Lake sections are shown in Fig. 5.1.  163  Well control and index map for cross-sections and isopach maps 60-  59  58-  57-  -Fort St John  Hudson's H o p e ^  56  Key +  +  Wells for isopach maps  •  Non-analysed well ties  •  Town -124  &m 1  • ' Analysed Wells  -123  93-P -122  -121  Dawson Greek]  -120  Fig. 5.3. Index map for the three cross-sections and the well control for the analysed wells (full circles) and for the wells used for isopach maps (crosses). Cross-sections C - C , D - D ' , E - E ' and F-F' are found in Appendix A , B, C and D, respectively.  164  Structure map on the base of the  Fig. 5.4. The structural map on the base of the Buckinghorse Formation. Short dashed lines are the boundaries of the Peace River Arch (PRA) and the long dashed line is the margin of the Deep Basin (DB). Unbroken line is approximation of the Bovie Structure (BS). Crosses indicate well locations.  165  Fig. 5.5. Isopach map for the total thickness of the Buckinghorse Formation. Crosses indicate location of wells used for all isopach maps.  -124.8-124.4 -124 -123.6-123-2-122.B-122.4 -122 -121.B-121.2-120.6-120.4  -124.8 -12-14 -124 -123.6-123 2-1228 -122.4 -122 -121.6 -121.2-120.8-120.4  Fig. 5.6. Isopach maps of the organic-rich basal (ORB) layer (A) and the Moosebar and equivalent formations (B). Well control shown in Fig. 5.5.  167  I Sampled miwvol  Fig. 5.7. Stratigraphic cross-section A - A ' . Cross-section shows the Buckinghorse Formation and its equivalents. Refer to Fig. 5.3 for location of cross-sections. Location of P R A is identified by the erosion of the Sikanni and part of the Lepine formations.  168  Geophysical Key GC - Gamma Hay In API unft |scaleteOtoISO unless designated) 1 - Induction log Iteslstrvlty In OHMM5 |sc<Ho I). I to 100 unlets designated] (JHOS -- Bulk Density m Kg/m Iscale 2000 to 3000) DI = Some (scoie 500 to 100| J  | Oroanie-nch tfrole I Oiacnlc-leanei shale Sampled Mfeival  —  Flooalng Sutace Sandstone  Datum - FS 2  V  Fig. 5.8. Stratigraphic cross-section A ' - A " . A thinning of the strata highlighted by the coalescence of flooding surfaces occurs towards the north (cross-section A - A ' - A " ) .  169  220 km  Fig. 5.9. Stratigraphic cross-section B - B ' . The B ' end connects with A " and is the westward extension of A - A ' - A " cross-sections. The abrupt thickening in this crosssection is due to the syndepositional faulting of the Bovie Structure which defines the eastern margin of the Liard Basin (between wells B-59-I-04-O-11 and B-66-D-94-0-13).  170  Regional Distribution of TOC Content  Regional Maturity Trends  Regional Distribution of Kerogen Types  Distribution of O i l / G a s W i n d o w s  Fig. 5.10. The regional distribution for the TOC content (A), kerogen types (B), kerogen maturity by T  m a x  (C) and oil, wet gas and dry gas windows (D). A l l data are well averages  and black crosses indicate location of wells.  171  Kerogen Type By Sections  0  25  50  75  100  125  150  Oxygen Index.  Fig. 5.11. Modified van Krevelen diagram illustrating the kerogen types by their geographic location in map sections.  172  Regional Distribution of Illite Content (%)  Regional Distribution of Quartz Content (%)  Fig. 5.12. The regional distribution of the illite (A) and quartz (B) contents. Values are averaged per well and crosses in (B) are location of wells with shale mineralogy analysed.  173  N  360 kmA-77-K-Q94-P-07  8-O17-H-O94-I-09  D-57-L-094-H-O8  D-066-t-OM-G-OI  3-21-81-22-W6 +46 m  +90 m  - 179 m  IP  -332 m  +36 m  •1 i f a 188 m i i i i i i i c  F C M F S I  •••••nr-iv-v.ri-.--.y +27 m I I I I I I & & & & & & & & +77 m C M F S Sh I I I I I I I C P C M F Si  r> o  .  to  -  W to  Q.  HI  o  CO CO  Sh  i  o Q  <D  ' ' '  li^lpij&g  1 S h s  >..n ..*.>.!•  h  •x- ti, vj!v.--:r +32 m I I I I I C M F Si Sh  I  GO IT U  1  sr.  Kev Sfsifct SUsxme Sandstone  ?-^> g |  CongtorriwatB £o*^  BkjOjrtitrton - SSgftt; ft~ff"ttl Unticular Mode-ate; Worao J A J ? „ * j Boddng  Fragments  i£.J  Fractures  Branch  fx"|  j  j  Crass  Sfctotte  Fig. 5.13. Five graphic logs of cores from across the basin. Sections include part of the Gething/Bluesky formations and the basal section of the Buckinghorse Formation. Depths are from sea level.  174  Methane Sorption Capacity at Reservoir Pressure  Fig. 5.14. The distribution of methane sorption capacity on an average per well basis. Gas capacities are measured in cm /g, at hydrostatic pressure and at 30°C. Crosses show location of analysed wells.  175  Average Porosity per Well (%)  Total G a s at Reservoir Pressures  Fig. 5.15. Average porosity (%) per well (A) and the total gas capacity (cm /g) (B). 3  Crosses show location of analysed wells.  176  GIP for O R B Layer at Reservoir Pressures (bcf/section)  -124.4 -123.8 -123.2 -122.6 -122 -121.4 -120.8 -120.2  GIP for Garbutt-Moosebar-Wilrich Formations at Reservoir Pressures (bcf/section)  124.4 -123.8 -123.2 -122.6 -122 -121.4 -120.8 -120.2  Fig. 5.16. GIP estimates for the ORB layer (A) and the Garbutt-Moosebar-Wilrich formations and the equivalents (B).  177  Reservoir Temperature (degrees Celsius)  -124.4 -123.8 -123.2 -122.6 -122 -121.4 -120.8 -120.2 Fig. 5.17. Reservoir temperature from bottom-hole temperature from analysed wells.  Sample ID & T O C CO CO -  E o  4  O  A - 7 7 - K - 1 1 i s o - 17% D-65-D-1 iso - 8% D-75-E-6iso-1% B-17-H-2iso-3%  o  a  3  CO  O c o  I*  CO CD  c CO  £  CD  1 1  10  20  30  40  50  60  Analysis Temperature (°C) Fig. 5.18. The relationship between methane sorption capacity and temperature on four samples with varying TOC contents.  179  Fig. 5.19. The variation in matrix permeability of the Lower Cretaceous shale at different depths.  180  Fig. 5.20. Natural fracturing and facies changes are present within the Buckinghorse Formation. A vertical, straight, bitumen-filled fracture (A) core width is 4 inches, and calcite-filled fractures are commonly found within the more competent ironstone or siderite bands and lenses (B). Facies changes from shale to very fine-grained to finegrained sandstone occurs as volcanic ash deposits, Canadian Penny for scale (C), or as tempesites (D).  181  Table 5.1: Mineralogy of shale samples subdivided by their location with respect to the map sections Gypsum Kaolinite Quartz Calcite Dolomite Illite Pyrite Total Clay Chlorite 93-P Section 35 71 35 47 70 46 94-A Section 48 58 55 46 94-B Section 35 94-H Section 35 59 56 45 34 94-G Section 50 94-I Section 57 88 54 57 67 74 94-P Section 32 20 20 67  Albite  Siderite  1  0  1  0 1 6 1 2  0 0 0 0  0 0 0 0  1 0 1 1  0 0 1 0  0 0 0 6  0  1  0  0  5  43 41 43 54 65  0 0 0 0 0  0 0 0 0 0  0 0 0 0 0  0 0 1 1 1  22 0 0 0 0  6  49  0  0  0  1  0  3 0 9 0 0 0  4 4 3 9 3 5  39 12 36 40 32 25  1 0 1 2 0 0  0 0 0 0 0 0  0 0 0 0 0 0  0 0 0 1 0 0  0 0 0  0 0 3 0  20 15 9 38  66 79 75 33  2 1 1 0  0 0 0 0  1 0 0 0  0 0 0 0  0 7 0 10 9 3  30 58 27 20 55 38  15 0 0 0 0 0  5 6 7 18 7 5  49 28 63 46 28 51  0 0 1 2 0 0  0 0 0 0 0 0  0 0 0 0 0  0 0 0 0  32 36 47 28  0 0 0 0  16 22 8 18  51 41 42 48  0 1 1 0  0  28  0  7  59  0 5 0 0 0  34 50 56 39 25  0 0 0 0 0  2 4 0 5 9  0  45  0  0 2 0 10 7 12  53 82 51 37 58 57  0 0 10 2  11 5 1 27  0 0  0 0 0  Table 5.1 continued Total Clay Chlorite 94-P Section (continued) 0 24 0 38 0 59 0 33 0 46 0 59 0 59 0 36 0 14 8 73 0 37 3 68 37 0 0 35 0 29 94-0 Section 0 49 77 10 21 0 0 75  Illite  Gypsum  Kaolinite  Quartz  Pyrite  Calcite  Dolomite  Albite  Siderite  4 18 51 15 33 53 57 33 0 39 26 62 21 22 26  0 0 0 0 0 0 3 0 0 0 0 0 9 7 0  20 21 8 18 13 6 2 4 14 26 12 3 16 13 3  76 55 40 66 53 39 38 63 80 26 60 31 52 51 70  1 1 1 1 0 1 0 0 3 0 1 1 2 5 1  0 0 0 0 1 0 0 0 0 0 2 0 0 2 0  0 6 0 0 0 0 0 0 0 0 0 0 0 0 0  0 0 0 0 0 0 0 0 0 0 0 0 0 0 0  0  29 46 13 72  0 0 0 0  20 21 8 3  51 23 79 24  0 0 0 0  0 0 0 0  0 0 0 0  0 0 0 1  0 0 0 0 3  0 0 0 0 0 0 0  5.7 REFERENCES CITED  A S T M D1412-04, 2004. Test for equilibrium moisture of coal at 96 to 97% relative humidity and 30°C. Boggs, S. Jr. 1992. Petrology of Sedimentary Rocks. Macmillan Publishing Company, New York. 707 p. Cherven, V . B . , and Fisher, P.J. 1992. Non-tectonic structures caused by drape and differential compaction over lenticular sand bodies, southern Sacramento Basin. In: V . B . Cherven and W.F. Edmondson (eds) Structural Geology of the Sacramento Basin. Annual Meeting Pacific Section A A P G , Sacramento, California, April 27 May 2, 1992. The Pacific Section, American Association of Petroleum Geologists, Bakersfield, California, USA. Cosgrove, J.W., and Hillier, R.D. 2000. Forced-fold development within Tertiary sediments of the Alba Field, U K C S : evidence of differential compaction and postdepositional sandstone remobilization. In: Cosgrove, J.W., and Ameen, M.S. (eds). Forced folds and Fractures. Geological Society, London, Special Publications, vol. 169, 51-60. The Geological Society of London. Davies, G.R. 1997. The Upper Triassic Baldonnel and Pardonent formations, Western Canada Sedimentary Basin. Bulletin of Canadian Petroleum Geology, vol. 45 (4), p 643-674. Hage, C O . 1944. Geology adjacent to the Alaska Highway between Fort St John and Fort Nelson, British Columbia. Geological Survey of Canada, Department of Mines and Resources, Mines and Geology Branch. Paper 44-30, pp. 1-22. Hayes, B.J.R., Christopher, J.E., Rosenthal, L., Los, G., McKercher, B., Minken, D., Tremblay, Y . M . , and Fennell, J. 1994. Cretaceous Mannville Group of the western Canadian sedimentary basin. In: Mossop, G. and Shetsen, I. (compilers) Geological Atlas of the western Canada sedimentary basin, Chapter 19. Canadian Society of Petroleum Geologists and the Alberta Research Council. Calgary, Alberta, Canada. Hill, D.G. and Nelson, C R . 2000. Gas productive fractured shales: A n overview and update. Gastips, Summer, 2000. pp 4-13. Hinds, S.J. 2002. Stratigraphy, structure and tectonic history of the Pink Mountain Anticline, Trutch (94G) and Halfway River (94B) map areas, northeastern British Columbia. M.Sc. thesis, University of Calgary, Calgary, Alberta, 104p. Hinds, S.J. and Spratt, D.A. 2005. Stratigraphy, structure and tectonic history of the Pink Mountain Anticline, Trutch (94G) and Halfway River (94B) map areas,  184  northeastern British Columbia. Bulletin of Canadian Petroleum Geology, Vol. 53 (l),p.84-98. I U P A C , 1997. Compendium of Chemical Terminology, Electronic Version, http://goldbookk.iupac.org/M03853.html Jackson, P.C. 1984. Paleogeography of the Lower Cretaceous Mannville Group of western Canada. In: .A. Masters (ed), Elmworth - Case Study of a deep basin gas field. A A P G Memoir 38, Oklahoma U S A . pp. 79-114. Jowett, D.M.S. and Schroder-Adams, C.J., 2005. Paleoenvironments and regional stratigraphic framework of the Middle-Upper Albian Lepine Formation in the Liard Basin, Northern Canada. Bulletin of Canadian Petroleum Geology, vol. 53 (1), p. 25-50. Karst, R.H. 1981. Correlation of the lower Cretaceous stratigraphy of Northeastern British Columbia from foothills to plains. B.C. Ministry of Energy and Mines, pp 79-89. Laubach, S.E., Schultz-Ela, D.D., and Tyler, R. 2000. Differential Compaction of interbedded sandstone and coal. In: Cosgrove, J.W., and Ameen, M.S. (eds). Forced folds and Fractures. Geological Society, London, Special Publications, vol. 169, 5160. The Geological Society of London. Leckie, D.A. 1986. Rates, controls, and sand-body geometries of transgressive-regressive cycles: Cretaceous Moosebar and Gates Formations, British Colombia. A A P G Bulletin vol. 70, pp 516-535 Leckie, D.A., Kalkreuth, W.D., and Snowdon, L.R. 1988. Source rock potential and thermal maturity of Lower Cretaceous Strata: Monkman Pass area, British Columbia. A A P G Bulletin, vol. 72, pp 820-838. Leckie, D.A., Staniland, M.R. and Hayes, B.J. 1990. Regional maps of the Albian Peace River and lower Shaftesbury formations on the Peace River Arch, northwestern Alberta and northeastern British Columbia. Bulletin of Canadian Petroleum Geology, Vol. 38A, p 176-189. Leckie, D.A., Potocki, D.J. and Visser, K . 1991. The Lower Cretaceous Chinkeh Formation: a frontier - type play in the Liard Basin of western Canada. A A P G Vol. 75 (8), p. 1324-1352/ Leckie, D.A. and Smith, D.G. 1992. Regional setting, evolution and depositional cycles of the western Canadian foreland basin. In: R.W. Macqueen and D.A. Leckie (Editors), Foreland basins and fold belts. American Association of Petroleum Geologists Memoir 55. American Association of Petroleum Geologists, Oklahoma, U S A , pp. 9-46.  185  Leckie, D.A., and Potocki, D.J. 1998. Sedimentology and petrography of marine shelf sandstones of the Cretaceous, Scatter and Garbutt formations, Liard Basin, northern Canada. Bulletin of Canadian Petroleum Geology, vol. 46 (1), p. 30-50. Lu, X . C . , L i , F.C., Watson, A.T., 1995. Adsorption measurements in Devonian shales. Fuel 74, p. 599-603. McLean J.R. and Wall, J.H. 1981. The Early Cretaceous Moosebar Sea in Alberta. Bulletin of Canadian Petroleum Geologists, vol 29 (3), p. 334-377. Masters, J.A. 1984. Elmworth, Case Study of a Deep Basin Gas Field. A A P G Memoir 38, Oklahoma U S A . 316p. Montgomery, S.L., Jarvie, D . M . , Bowker, K . A . and Pollastro, R . M . 2005. Mississippian Barnett Shale, Fort Worth basin, north-central Texas: Gas-shale play with multitrillion cubic foot potential. A A P G Vol. 89 (2), p 155-175. Passey, Q.R., Creaney, S., Kulla, J.B., Moretti, F.J. and Stroud, J.D. 1990. A practical model for organic richness from porosity and resistivity logs. A A P G , Vol. 74 (11), pp 1777-1794. Pecharsky, V . K . and Zavalij, P.Y, 2003, Fundamentals of powder diffraction and structural characterization of minerals. Kluwer Academic Publishers, New York, 713 p. Peterson, P.K. and Schroder-Adams, C. 2001. Depositional environment and sequence architecture of the new Cretaceous gas bearing Bougie Sandstone Member, Northeastern British Columbia. CSPG, Rock the Foundation Convention, June 18-22, 2001. 2 pages. Price, R.A. 1994. Cordilleran tectonics and the evolution of the western Canadian sedimentary basin. In: Mossop, G. and Shetsen, I. (compilers) Geological Atlas of the western Canada sedimentary basin, Chapter 2. Canadian Society of Petroleum Geologists and the Alberta Research Council. Calgary, Alberta, Canada, pi3-39. Schmoker, J.W. 1981. Determination of organic-matter content of Appalachian Devonian shales from Gamma-ray logs. A A P G , Vol. 65, pp. 1285-1298. Schroder-Adams, C.J. and Pederson, P.K. 2003. Litho- and biofacies analyses of the Buckinghorse Formation: the Albian Western Interior Sea in northeastern British Columbia (Canada). Bulletin of Canadian Petroleum Geology, vol. 51 (3), p. 234252. Smith, D.G. 1994. Paleogeography evolution of western Canada foreland basin. In: Mossop, G. and Shetsen, I. (compilers) Geological Atlas of the western Canada  186  sedimentary basin, Chapter 17. Canadian Society of Petroleum Geologists and the Alberta Research Council. Calgary, Alberta, Canada. Stott, D.F. 1982. Lower Cretaceous Fort St John Group and Upper Cretaceous Dunvegan Formation of the foothills and plains of Alberta, British Columbia, District of Mackenzie and Yukon Territory. Geological Survey of Canada, Bulletin 328, 124 pages. Swanson, B.F., 1981, A simple correlation between permeabilities and mercury capillary pressures: Journal of Petroleum Technology, Paper SPE 8234, p 2498-2504. Taylor, D.R. and Walker, R.G. 1984. Depositional environments and palaeogeography in the Albian Moosebar Formation and adjacent fluvial Gladstone and Beaver Mines Formations, Alberta. Canadian Journal of Earth Sciences, vol. 21, pp681-714. Webb, A.C., Schroder-Adams, C.J. and Pederson, P.K. 2005. Regional subsurface correlations of Albian sequences north of the Peace River in N E British Columbia: northward extent of sandstones of the Falher and Notikewin members along the eastern flank of the foredeep. Bulletin of Canadian Petroleum Geology, vol. 53 (2), p. 165-188. Wignall, P.B. 1994. Black Shales. Clarendon Press, Oxford. 127 p. Wright, G.N., McMechan, M . E . and Potter, D.E.G. 1994. Structure and architecture of the Western Canadian Sedimentary Basin. In: Mossop, G. and Shetsen, I. (compilers) Geological Atlas of the western Canada sedimentary basin, Chapter 19. Canadian Society of Petroleum Geologists and the Alberta Research Council. Calgary, Alberta, Canada.  187  CHAPTER SIX  CONCLUSIONS AND RECOMMENDATIONS FOR FUTURE WORK  6.1 GENERAL CONCLUSIONS  TOC is the dominating geological control on the methane sorption capacity with a broad positive relationship. TOC dominates because gas shales are organic lean in comparison to coal and small changes in TOC significantly affect the methane capacity. For coals, rank is the dominating control and masks the effects of other geological controls, while TOC masks the effects within gas shales. The broad trend between TOC and methane capacity indicates other factors are contributing to the capacity and these include: 1) kerogen type; 2) organic maturation; 3) mineralogy; 4) moisture content; and 5) pore size distribution.  The effect kerogen types have on methane capacity is a function of their relationship with TOC. Methane capacity is higher in Types I and II because the strata have higher TOC compared to strata rich in Types II/III and III. When methane capacity is normalized to TOC, Types II/III and III have a higher methane capacity (on a per unit TOC volume basis) compared to Types I and II. Liptinite-rich coals are enriched in Types I and II kerogen and were found to have comparable or even greater methane capacity than the more common, vitrinite-rich coals (Type III). Gas storage in Types I and II rich  188  sediments differs from Type III rich sediments because methane is stored in solution as opposed to physical adsorption onto surfaces.  Methane capacity decreases with maturity in the shales which is the opposite trend observed within coalbed methane studies. The reason methane capacity is higher in low maturity samples is because of their greater amount of TOC compared to higher maturity samples. The relationship between methane capacity, TOC and maturity is due to the influence the evolution of the basin has on the sedimentation and subsidence rates. High maturity samples are found in close proximity to the deformation front which experienced high sedimentation and subsidence rates. Higher subsidence and sedimentation rates caused: 1) dilution of the TOC by an increase in mineral matter; and 2) greater depths of burial and loss of TOC through hydrocarbon generation.  Quartz and illite dominant the mineralogy of the Lower Cretaceous shales. Illite increases with maturity through the process of illitization of kaolinite and smectite. Illite does contribute to methane capacity but only on a dried basis. When samples are moistureequilibrated, the illite has mostly lost its ability to sorb methane. Illite contents are higher adjacent to the deformation front because of greater depth of burial and increased diagenesis that converts smectite and kaolinite to illite. Variation in the distribution of the illite content is due to changes in the depositional environments and provenance across the study area.  189  A complex relationship exists between moisture content and: 1) methane capacity; 2) TOC; and 3) illite content. Equilibrium moisture is established prior to methane capacity analysis and because there are no trends between the moisture content and methane capacity, the moisture is not occupying all sorption sites and there are still sites available to methane.  Surface area analysis of the shales reveal that the microporosity has a positive relationship with methane capacity and is the primary control on methane capacity. For a given pore volume, the surface area increases with decreasing pore diameter. Microporosity is primarily associated with the TOC and to a lesser extent the illite content. The pore size distribution is affected by the TOC, quartz and illite contents with microporosity increasing with TOC, mesoporosity with illite and the macroporosity with quartz content. Microporosity and mesoporosity both increase with maturity because of the increase in the illite content. The moisture content increases with both the microporosity and mesoporosity which suggests that moisture is associated with both the TOC and illite contents and this is why there is a complex relationship between moisture, TOC and clay contents.  Sorption capacity is the highest in the northeast of the study area (94-P) because samples have a higher TOC content compared to the rest of the study area. TOC is high in this area because less sediment accumulated increasing the TOC and loss of TOC through hydrocarbon generation was less than the higher maturity areas adjacent to the deformation front. Total gas contents are highest in 94-N, 94-H and 94-1 because these  190  areas have higher porosity and/or reservoir pressure. GIP estimates for the ORB layer are controlled by the stratal thickness, TOC, porosity and reservoir pressure, while GIP estimates for the Moosebar-Wilrich-Garbutt Formations are primary controlled by the stratal thickness and reservoir pressure.  6.2 SIGNIFICANCE OF WORK AND APPLICABILITY OF RESEARCH  This research project has identified and evaluated the most significant geological controls in gas shale capacity by utilizing the Lower Cretaceous shales in northeastern British Columbia as an example. The regional distribution of the methane capacity is influenced by the organic and inorganic sedimentology, subsidence rates, and depth of burial which all relate to the evolution of the basin. With an understanding of the varying influence of the geological controls and how these controls are affected by the evolution of the basin, a more focused exploration strategy can be developed. With many shale formations occurring in sedimentary basins around the world, this study provides insight as to which basins and formations to should be explore for potential gas shales.  Chapter Five provides the location of the greatest potential for gas-in-place estimates for both the ORB layer and the Garbutt-Moosebar-Wilrich and equivalent strata. This information can be readily applied to an exploration strategy by petroleum companies that are currently exploring the Lower Cretaceous shales of northeastern British Columbia.  191  6.3 FUTURE RESEARCH AND RECOMMENDATIONS  No complete cores (apart from the 180 m core documented in Chapter Three) were available to sample because past drilling projects focused on the units underlying the Buckinghorse Formation. This limited the project to a lateral evaluation of the shale resource within a narrow zone (i.e. tens of metres). As petroleum companies begin to target shale for coring, future projects could focus on adding the third dimension (vertical) and therefore have the ability to apply sequence stratigraphy to the gas shale exploration model. Bohacs (1998) shows that the most organic-rich shales are the basal transgressive shales and applying this model to the Lower Cretaceous shale of northeastern British Columbia could aid prediction of highly productive gas plays.  Further research is needed into the location of the water molecule with respect to the pore size distribution to gain an understanding of how the moisture content is affecting the methane capacity. Separation of the organic and inorganic fraction of a suite of these Lower Cretaceous shale samples should be analysed in terms of pore size distribution, moisture contents and methane sorption capacity as this will provide more information on the location of the water versus the methane molecule and the role illite plays in both the moisture and methane capacities.  A n understanding of enhancing gas deliverability through the evaluation of the controls on rock mechanics and matrix permeability of these shales is needed for the development of this resource. The main objective would be to assess what geological controls are  192  important to maximize fracture networks during well completion as this will greatly increase gas production. Similarly, there will be a need to identify what controls the matrix permeability since gas shales are tight reservoirs in comparison to conventional petroleum systems.  6.4 REFERENCES  Beamish, B.B. and Crosdale, P.J., 1995. The influence of maceral content on the sorption of gases by coal and the association with outbursting. Int. Symp. Cum Workshop on Management and Control of High Gas Emission and Outbursts, Wollongong, 20-24 March, 1995. Wollongong, Australia. Bohacs, K . M . , 1998. Contrasting expressions of depositional sequences in mudrocks from marine to non marine environs, in: Schieber, J., Zimmerle, W., Sethi, P. (eds.), Shales and Mudstone 1.1. E. Schweizerbart'she Verlagbuchhandlung (Nagele u. Obermiller), D-70176. Stuttgart, pp.301-349. Bustin, R . M . and Clarkson, C.R., 1998. Geological controls on coalbed methane reservoir capacity and gas content. Int. J. Coal Geol. 38, 3-26. Carroll, R.E. and Pashin, J.C., 2003. Relationship of sorption capacity to coal quality: CO2 sequestration potential of coalbed methane reservoirs in the Black Warrior Basin. International Coalbed Methane Symposium, proceedings, paper 0317. Tuscaloosa, Alabama, USA. Crosdale, P.J. and Beamish, B.B., Valix, M . , 1998. Coalbed methane sorption related to coal composition. Int. J. Coal Geol. 35, 147-158. Faiz, M . M . , Aziz, N.I., Hutton, A . C . and Jones, B.G., 1992. Porosity and gas sorption capacity of some eastern Australian coals in relation to coal rank and composition. Coalbed Methane Symposium, Townsville, 19-21 November, 1992. Townsville, Australia. Faiz, M . , Saghafi, A., Sherwood, N . , Wang, I. in press. The influence of petrographic properties and burial history on coal seam methane reservoir characterisation, Sydney Basin, Australia. Int. J. Coal Geol.  193  Hildenbrand, A., Krooss, B . M . , Busch, A . and Gashnitz, R., 2006. Evolution of methane sorption capacity of coal seams as a function of burial history - a case study from the Campine Basin, N E Belgium. International Journal Coal Geology 66,179203. Lamberson, M . N . and Bustin, R . M . , 1993. Coalbed Methane Characteristics of Gates formation Coals, Northeastern British Columbia: Effect of Maceral Composition. A A P G 77 (12), 2062-2072. Laxminarayana, C. and Crosdale, P. J., 1999. Role of coal type and rank on methane sorption characteristics of Bowen Basin, Australia coals. Int. J. Coal Geol. 40, 309-325. Mastalerz, M . , Gluskoter, H . and Rupp, J., 2004. Carbon dioxide and methane sorption in high volatile bituminous coals from Indiana, U S A . Int. J. Coal Geol. 60, 43-55.  194  A P P E N D I X A : Data table for 216 samples - analyses include methane sorption capacity, total gas capacity, porosity, equilibrium moisture content, and total organic carbon content, kerogen type and maturity, f Methane capacities are an arbitrary pressure of 6 MPa and volumes reported in cm /g. 3  Sample ID 14-20-77-23W6-2iso 14-20-77-3iso 14-20-77-4iso 14-20-77-5iso 3-21-81-22W6-2iso 3-21-81-3iso 3-21-81-4iso 4-21-83-17W6-2iso 4-21-83-3iso 4-21-83-4iso 4-21-83-5iso 6-29-8 l-15W6-2iso 6-29-81-3 iso 6-29-81-1 iso 6-30-80-13W6-lliso 6-30-80-12iso 6-30-80-13iso 6-30-80-14iso 7-30-80-14W6-2iso 7-30-80-3iso 7-30-80-4iso 7-30-80-5iso a-l-l-94-H-12-2iso a-1-1-3 iso a-23-g-94-I-3-2iso a-25-a-94-H-l-2iso a-25-f-94-H-16-2iso a-26-b-94-0-ll-2iso a-26-b-3iso a-26-b-4iso a-26-b-5iso a-26-b-6iso a-26-b-7iso a-30-h-94-I-9-2iso a-30-h-4iso a-32-a-94-H-5-2iso a-32-a-3iso a-32-a-4iso a-45-b-94-H-16-2iso a-45-b-3iso a-45-b-4iso a-5-d-94-H-9-2iso a-5-d-3iso a-65-k-94-P-7-2iso a-65-k-3iso a-65-k-6iso a-65-k-7iso a-77-d-94-0-ll-2iso  TOC wt% 1.96 1.35 1.44 1.49 1.63 1.61 1.70 1.54 1.61 1.88 1.20 1.55 1.15 1.37 2.34 1.92 2.19 2.21 1.83 1.05 1.14 1.02 1.91 1.59 1.91 2.82 2.07 1.40 1.43 1.45 1.51 1.47 1.36 7.18 2.30 1.37 1.56 1.81 2.03 1.54 1.76 1.89 1.61 10.49 9.43 3.26 5.70 0.81  Moisture % 3.36 2.70 3.38 2.52 4.03 3.55 3.10 3.53 3.70 3.69 3.29 4.40 4.75 3.72 6.52 4.72 5.12 5.17 2.63 3.06 3.24 3.57 3.57 3.77 3.63 3.57 5.63 7.19 3.85 4.45 4.17 4.77 4.26 4.48 7.62 3.10 4.37 2.97 6.30 4.88 5.41 6.41 3.22 5.32 7.12 3.82 3.90 4.05  Porosity % 3.41 5.49 5.36 4.13 4.56 3.80 3.66 6.44 4.58 6.03 5.38 5.50 7.93 7.62 11.78 9.15 4.12 11.88 2.62 4.42 4.59 5.57 3.01 3.00 4.80 10.54 12.18 6.33 3.61 2.78 4.22 3.84 2.66 6.89 10.10 2.89 2.16 4.66 16.68 3.62 10.08 6.44 4.12 2.63 4.45 11.28 6.40 1.96  Methane Sorption Capacity f 0.22 0.34 0.37 0.35 0.30 0.19 0.18 0.19 0.24 0.21 0.34 0.20 0.43 0.57 0.82 0.48 0.49 0.23 0.21 0.38 0.17 0.35 0.32 0.25 0.45 0.45 0.23 0.27 0.51 0.3 0.22 0.41 0.47 1.16 0.61 0.3 0.51 0.92 0.42 0.45 0.71 0.27 0.67 1.55 1.37 1.1 1.46 0.51  Maturity °C)  Kerogen Type *  Oil/Gas Windows  -  -  -  476  II/III  (Tmax5  -  -  449  Ill  -  -  440  II/III  -  -  439  Ill  -  -  427  Ill  -  -  441  Ill  -  -  458 459 441 435 439 444 446 446 445 446 447 428 434 459 459 460 452 438 439 439 441 424 428 433 429 438  I I II/III II/III II III II/III II/III II II/III II/III II II/III III II/III II/III II II/III II III II I I I I III  dry gas wet gas oil -  oil  -  wet gas -  wet gas wet gas wet gas wet gas oil oil wet gas wet gas wet gas wet gas wet gas wet gas oil oil dry gas wet gas wet gas wet gas wet gas oil oil oil immature oil oil oil wet gas  195  Sample ID a-77-d-3iso a-77-d-4iso a-77-d-5iso a-77-k-94-P-7-10iso a-77-k-lliso a-77-k-14iso a-77-k-16iso a-77-k-2iso a-77-k-3iso a-77-k-4iso a-77-k-5iso a-774c-6iso a-77-k-7iso a-77-k-8iso a-7-c-94-H-ll-2iso a-7-c-3iso a-88-j-94-H-4-2iso a-88-j-3iso a-88-j-4iso b-17-h-94-I-9-2iso b-17-h-3iso b-17-h-4iso b-17-h-5iso b-24-b-94-H-16-3iso b-2-f-94-H-16-2iso b-2-k-94-H-16-2iso b-30-c-94-H-10-3iso b-30-g-94-H-6-3iso b-40-g-94-H-16-2iso b-40-g-3iso b-40-g-4iso b-44-e-94-I-2-3iso b-48-a-94-H-16-3iso b-55-e-94-0-13lOiso b-55-e-lliso b-55-e-12iso b-55-e-13iso b-55-e-16iso b-55-e-17iso b-55-e-18iso b-55-e-19iso b-55-e-20iso b-55-e-2iso b-55-e-3iso b-55-e-4iso b-55-e-5iso b-55-e-6iso b-55-e-7iso b-55-e-9iso b-56-e-94-I-10-5iso b-59-i-94-0-ll-3iso b-59-i-4iso  Moisture % 4.98 3.73 4.01 5.84 6.97 1.50 4.33 4.71 4.19 7.83 3.26 4.68 4.66 5.38 3.29 2.62 4.32 4.22 3.35 3.16 4.02 4.82 6.94 6.25 4.41 5.36 2.96 3.85 5.48 4.65 7.12 3.50 5.62  Porosity % 8.64 1.74 3.60 6.29 7.15 22.16 17.84 2.99 2.16 4.46 6.16 7.29 8.55 8.01 7.04 1.87 1.01 1.55 5.21 4.28 4.71 10.40 8.22 8.48 2.50 11.22 4.01 1.78 9.19 8.72 5.92 8.44 8.23  Methane Sorption Capacity f 0.09 0.29 0.28 0.58 1.16 0.19 0.57 1.45 1.74 0.55 0.93 0.83 0.76 0.99 0.22 0.66 0.15 0.23 0.23 0.94 1.4 0.58 0.64 0.3 0.5 0.31 0.4 0.35 0.26 0.63 0.3 0.43 0.53  Maturity  TOC wt% 0.81 0.87 0.95 8.34 16.99 1.88 0.64 8.84 10.86 5.23 4.34 3.00 2.20 6.11 3.79 1.72 1.79 1.38 1.68 3.26 7.93 1.61 5.15 2.85 1.36 1.15 1.84 1.58 1.28 1.46 1.64 1.69 1.38  °C) 442 442 441 427 425 426 427 433 428 427 432 436 433 427 422 453 460 463 466 431 429 434 425 438 439 438 444 451 438 439 439 440 438  Kerogen Type * II/III II/III II/III II II/III II III I II I II II II II II II II/III II/III II II II II/III II II III III II II II/III II/III II II/III II/III  Oil/Gas Windows wet gas wet gas wet gas oil immature immature wet gas oil oil oil oil oil oil oil immature wet gas wet gas wet gas wet gas oil oil oil immature oil wet gas wet gas oil wet gas oil oil oil wet gas wet gas  1.53 1.50 1.50 1.07 1.69 1.68 1.66 1.64 1.34 0.56 1.03 0.58 0.53 0.95 1.21 1.31 10.30 1.75 2.13  2.55 2.93 2.49 2.70 2.37 2.52 3.97 3.03 2.71 2.34 2.99 4.49 2.51 2.60 3.87 5.48 4.27 6.36 6.54  3.18 1.12 4.08 3.41 3.04 1.29 4.40 1.91 5.66 4.78 2.31 4.96 4.53 10.05 2.78 2.73 5.08 5.18 2.27  0.17 0.32 0.2 0.28 0.04 0.44 0.3 0.33 0.34 0.12 0.38 0.55 0.1 0.27 0.16 0.16 1.27 0.22 0.23  444 446 442 445 446 448 443 446 440 439 438 434 440 443 441 443 441 443 436  II/III II II/III II/III II/III II II II/III III II/III III III III II/III II/III II/III I II/III II/III  wet gas oil wet gas wet gas wet gas oil oil wet gas wet gas oil wet gas wet gas wet gas wet gas wet gas wet gas oil wet gas wet gas  (TmaX5  196  Sample ID b-59-i-5iso b-59-i-6iso b-59-i-7iso b-66-d-94-0-15-2iso b-66-d-3iso b-66-d-4iso b-66-d-5iso b-66-d-6iso b-66-d-7iso b-66-d-8iso b-70-b-94-H-16-2iso b-76-d-94-I-2-2iso b-79-g-94-0-lllOiso b-79-g-2iso b-79-g-3iso b-79-g-4iso b-79-g-5iso b-79-g-6iso b-81-g-94-H-16-2iso b-84-i-94-H-4-2iso b-95-j-94-P-12-2iso b-95-j-3iso b-95-j-4iso b-95-j-5iso b-95-j-6iso b-95-j-7iso b-95-j-8iso c-15-e-94-H-16-2iso c-16-d-94-H-10-2iso c-26-a-94-P-ll-3iso c-26-a-4iso c-26-a-6iso c-26-a-8iso c-30-k-94-P-6-3iso c-30-k-4iso c-32-e-94-H-16-2iso c-32-i-94-H-9-2iso c-35-b-94-A-14-2iso c-35-b-3iso c-35-b-4iso c-42-g-94-I-3-2iso c-51-b-94-0-14-2iso c-51-b-5iso c-56-i-94-H-9-2iso c-62-b-94-H-ll-2iso c-62-b-3iso c-63-d-94-P-l-liso c-63-d-2iso c-74-f-94-H-16-2iso c-74-j-3iso c-74-j-4iso c-78-i-94-H-9-2iso  Moisture % 6.28 5.49 5.51 4.53 3.78 5.68 5.92 4.03 5.41 4.99 4.67 4.62  Porosity % 0.84 2.67 1.16 6.22 4.46 8.20 5.44 6.50 6.40 5.05 9.78 15.72  Methane Sorption Capacity f 0.64 0.57 0.9 0.19 0.19 0.31 0.18 0.19 0.12 0.25 0.25 0.3  Maturity  TOC wt% 4.80 3.88 3.46 1.35 1.34 1.39 1.27 1.22 1.31 1.15 1.26 1.70 2.93 1.81 1.15 1.20 1.23 1.07 1.35 1.58 4.42 0.78 6.05  4.74 3.84 2.70 2.65 3.81 3.62 6.20 4.01 7.11 6.52 7.34 2.19 8.95 8.59 8.95 5.12 2.57 5.24 6.71 6.55 6.19 7.22 4.02 3.55 4.85 2.35 2.23 2.81 6.65 5.26 3.54 4.04 6.93 3.27 10.97 5.34 3.39 4.37 3.83 6.71  3.61 1.14 1.70 2.70 3.80 8.40 5.68 11.17 1.78 10.76 9.38 10.23 7.45 10.48 5.41 6.40 5.91 1.11 4.42 4.35 9.15 2.82 2.20 11.57 9.06 4.03 5.10 9.80 9.72 2.61 6.32 12.54 1.65 3.26 7.97 7.95 11.04 1.61 1.69 5.93  0.28 0.36 0.5 0.53 0.1 0.28 0.19 0.35 0.67 0.38 1.33 1.06 0.21 0.07 0.27 0.16 0.57 0.79 1.18 0.34 0.41 0.94 0.7 0.41 0.42 0.43 0.41 0.24 0.28 0.25 0.32 0.55 0.49 0.37 0.78 0.78 0.48 0.22 0.18 0.32  -  2.37 1.30 5.32 1.57 1.58 6.84 4.51 1.42 2.95 10.31 4.33 1.40 2.25 1.74 1.77 0.89 1.36 1.49 1.38 2.37 4.82 1.86 5.05 4.00 1.47 1.64 1.35 1.15  Oil/Gas Windows oil oil oil wet gas wet gas  436 438 441  Kerogen Type * I II II/III II/III II/III II/III Ill II/III  440 445 444 446 439 439 458 422 430 432  Ill II/III II II/III III II/III II/III II II/III II  -  wet gas wet gas oil wet gas wet gas oil dry gas immature oil oil  (Tinax*  °C) 435 430 431 438 437  -  -  431 432 420 439 440 416 431 448 433 426 429 439 436 441 439 440 440 441 440 439 429 451 435 435 438 443 438 437  -  II/III II/III II/III II/III III II II II/III II II II II/III II/III II/III II/III II/III II/III II II II/III II II II II III II/III III III  -  wet gas -  wet gas wet gas  -  oil oil immature wet gas wet gas immature oil wet gas oil immature oil oil oil wet gas wet gas wet gas wet gas oil oil wet gas oil wet gas oil oil -  wet gas wet gas wet gas  Sample ID c-80-g-94-H-16-2iso c-80-g-3iso c-84-f-94-I-3-2iso c-89-g-94-B-16-2iso c-8-i-94-H-5-4iso d-10-c-94-H-7-2iso d-10-c-4iso d-13-k-94-H-7-2iso d-13-k-7iso d-20-h-94-I-9-3iso d-23-L-94-H-2-2iso d-24-L-94-H-2-4iso d-33-f-94-P-13-2iso d-33-f-3iso d-33-f-4iso d-33-f-5iso d-33-f-6iso d-33-f-7iso d-33-f-9iso d-33-j-94-H-7-3iso d-33-j-5iso d-38-k-94-H-9-4iso d-47-c-94-H-10-2iso d-51-f-94-H-16-3iso d-55-e-94-H-6-3iso d-55-f-94-P-6-2iso d-55-f-3iso d-55-f-4iso d-55-f-5iso d-55-f-6iso d-55-h-94-P-12-3iso d-55-h-3iso d-55-h-4iso d-55-h-5iso d-55-h-6iso d-57-L-94-H-8-2iso d-57-L-4iso d-65-d-94-P-7-6iso d-65-d-7iso d-65-d-10iso d-65-d-lliso d-65-d-liso d-65-d-5iso d-65-d-8iso d-66-i-94-G-l-3iso d-67-k-94-H-2-2iso d-68-c-94-H-7-2iso d-68-c-7iso d-71-g-94-I-l-2iso d-75-e-94-N-8-6iso d-75-e-9iso d-76-j-94-H-10-2iso d-77-f-94-H-3-3iso  TOC wt% 1.39 1.37 1.57 1.79 1.51 1.91 2.95 2.41 1.65 3.19 2.05 1.96 1.88 1.57 0.81 1.46 2.45 6.48 4.06 2.18 1.66 1.45 2.42 1.82 1.79 4.82 1.65 2.45 3.04 2.59  10.16 8.92  1.77 1.67 3.16 3.23 4.28 3.83 7.98 4.18 2.62 1.68 1.31 0.88 2.04 1.01  1.60 1.68  Moisture  Porosity  %  %  8.41 4.35 5.90 2.96 3.26 3.87 2.93 4.86 5.10 4.65 4.19 3.13 5.63 4.51 2.87 3.71 4.61 4.04 2.45 5.20 4.60 3.87 3.80 6.37 3.27 5.31 4.38 4.87 4.87 7.53 3.28 2.63 4.78 4.69 5.90 5.61 4.35 5.32 5.36 5.74 5.42 5.64 8.46 4.00 3.87 3.49 2.67 3.86 7.77 4.48 2.54 4.98 4.21  9.55 10.51 11.79 6.18 2.98 2.73 1.70 1.86 14.55 9.35 2.31 4.19 10.97 12.92 8.86 10.51 5.33 3.94 5.01 9.58 2.71 6.25 3.76 9.54 2.82 8.80 10.39 6.09 8.68 8.26 1.60 3.94 5.41 7.07 10.19 4.24 2.73 2.37 1.62 6.02 9.71 6.62 3.90 1.13 5.31 3.56 2.68 6.01 7.56 6.47 8.81 7.42 1.28  Methane Sorption Capacity f 0.22 0.45 0.1 0.43 0.32 0.42 0.48 0.6 0.29 0.9 0.54 0.44 0.2 0.62 0.21 0.42 0.64 0.96 0.65 0.19 0.24 0.4 0.47 0.31 0.44 0.8 0.6 0.77 0.91 0.36 0.56 1.85 1.25 0.61 0.64 0.28 0.61 1.42 0.43 0.68 0.77 1.23 1.42 0.57 0.48 0.27 0.68 0.24 0.34 0.27 0.41 0.36 0.58  Maturity (Tmaxj  °C) 438 438 440 467 457 441 440 441 442 434 441 443 425 435 435 434 424 418 421 439 439 438 441 455 456 427 435 433 430 435  Kerogen Type * II/III II/III II/III II II/III II/III III II II/III II/III II/III II/III III II/III II/III II/III II/III I I II/III II/III II/III II II II/III I II/III II II II  Oil/Gas Windows wet gas wet gas wet gas wet gas dry gas wet gas wet gas oil wet gas oil wet gas wet gas immature oil oil oil immature immature immature oil oil oil oil wet gas wet gas oil oil oil oil oil  -  -  -  430 431  II II  oil wet gas  -  -  -  440 440  II/III II/III  wet gas  -  -  428 435 433 420  II I I I  oil oil oil immature  -  -  -  468 441  II II/III  wet gas wet gas  -  -  -  -  439 425 466  Ill III III  wet gas immature dry gas  -  -  -  440 450  II II  oil wet gas  198  Sample ID d-77-f-4iso d-84-c-94-H-16-2iso d-92-f-94-H-9-2iso d-93-b-94-H-16-3iso d-94-I-94-B-8-2iso d-94-I-3iso d-94-I-4iso d-99-g-94-H-16-2iso d-99-i-94-H-9-2iso d-99-k-94-H-2-3iso  TOC wt% 1.67 1.47 2.00 2.32 1.92 1.96 1.70 1.57 1.95 1.57  Moisture  Porosity  %  %  2.34 5.08 3.90 6.66 3.73 3.80 2.61 5.49 6.17 3.88  9.69 11.80 12.35 13.13 4.46 4.04 1.51 4.58 7.67 4.78  Methane Sorption Capacity f 0.18 0.39 0.22 0.36 0.38 0.24 0.15 0.33 0.5 0.45  Maturity °C) 450 440 437 435  Kerogen Type * II II/III III II/III  -  -  443 437 437 441  Ill II II/III III  (Tmax»  Oil/Gas Windows wet gas wet gas wet gas oil  -  wet gas oil oil wet gas  199  Appendix B: Reservoir (hydrostatic) pressure, sorbed and total gas capacity, permeability and depth to samples. * permeability is measured from the porosimeter data and using equations by Swanson (1981). X Sample depth is total vertical depth and from the surface, f measured in cm /g at reservoir pressure. GIP = gas in place. 3  Sample ID 14-20-77-23W6-2iso 14-20-77-3iso 14-20-77-4iso 14-20-77-5iso 3-21-81-22W6-2iso 3-21-81-3iso 3-21-81-4iso 4-21-83-17W6-2iso 4-21-83-3iso 4-21-83-4iso 4-21-83-5iso 6-29-81-15W6-2iso 6-29-81-3iso 6-29-81-4iso 6-30-80-13W6-11iso 6-30-80-12iso 6-30-80-13iso 6-30-80-14iso 7-30-80-14W6-2iso 7-30-80-3iso 7-30-80-4iso 7-30-80-5iso a-1-l-94-H-12-2iso a-1-l-3iso a-23-g-94-l-3-2iso a-25-a-94-H-1-2iso a-25-f-94-H-16-2iso a-26-b-94-0-11-2iso a-26-b-3iso a-26-b-4iso a-26-b-5iso a-26-b-6iso a-26-b-7iso a-30-h-94-l-9-2iso a-30-h-4iso a-32-a-94-H-5-2iso a-32-a-3iso a-32-a-4iso a-45-b-94-H-16-2iso a-45-b-3iso a-45-b-4iso a-5-d-94-H-9-2iso a-5-d-3iso a-65-k-94-P-7-2iso a-65-k-3iso a-65-k-6iso a-65-k-7iso  Reservoir Pressure (MPa) 16.83 16.85 16.86 16.87 6.58 6.61 6.67 9.21 9.26 9.31 9.35 10.68 10.68 10.68 6.90 6.97 7.00 7.08 10.66 10.69 10.73 10.74 10.88 10.94 6.46 9.45 7.73 12.87 12.87 12.88 12.88 12.89 12.90 3.31 3.35 10.14 10.22 10.10 8.84 8.88 8.91 9.66 9.71 4.15 4.15 4.18 4.19  Permeability (Md)* 0.52  5.01  2.32  7.93  184.88 26.27 5.03 126.13  7.066 20.20  59.82 294.3 35.29  148.93 117.59  -  Sample Depth (m)t -1718.2 -1720 -1721 -1722.6 -671.5 -674.5 -681.1 -940 -945.4 -950.7 -954.7 -1090 -1090.5 -1090.8 -704.2 -711.6 -714.6 -722.9 -1088 -1091.4 -1095.5 -1096.9 -1110.4 -1117 -659.3 -964.7 -789.75 -1313.6 -1314.1 -1314.8 -1315.5 -1316.4 -1316.9 -338.2 -341.9 -1035.4 -1043.1 -1031.5 -902.3 -906.2 -909.9 -985.8 -991.8 -423.3 -423.7 -426.5 -427.4  Sorbed Gas Capacity t 0.3  0.74 0.31 0.3 0.19 0.18 0.21 0.26 0.32 0.47 0.22 0.51 0.77 0.87 0.61 0.45 0.25 0.17 0.54 0.3 0.57 0.67 0.42 0.36 0.58 0.28 0.42 0.9 0.45 0.29 0.62 0.72 0.74 0.39 0.52 0.81 1.49 0.63 0.62 0.98 0.34 0.89 1.14 1.02 0.64 1.08  GIP for GarbuttMoosebar F (bcf/sectio  Total Gas Capacity f (average/well)  GIP for Orb Layer (bcf/section)  -  -  -  6.20  9.9  87.6  -  -  -  2.96  11.6  34.5  -  -  -  4.42  12.5  50.9  -  -  -  7.79  22.2  103.7  -  -  -  7.36  12.2  29.0  -  -  -  5.35  11.3  49.7  -  -  -  3.24  3.4  35.7  -  -  -  3.04 9.75 8.87  1.9 11.1 10.2  9.6 62.2 54.7  -  -  -  5.77  20.2  20.2  -  -  -  2.98  3.4  3.4  -  -  -  3.77  3.4  26.3  -  -  -  8.91  3.0  25.6  -  -  -  4.66  11.8  12.6  -  -  -  3.38  4.0  4.2  -  -  -  200  Sample ID a-77-d-94-0-11-2iso a-77-d-3iso a-77-d-4iso a-77-d-5iso a-77-k-94-P-7-10iso a-77-k-11iso a-77-k-14iso a-77-k-16iso a-77-k-2iso a-77-k-3iso a-77-k-4iso a-77-k-5iso a-77-k-6iso a-77-k-7iso a-77-k-8iso a-7-c-94-H-11-2iso a-7-c-3iso a-88-j-94-H-4-2iso a-88-j-3iso a-88-j-4iso b-17-h-94-l-9-2iso b-17-h-3iso b-17-h-4iso b-17-h-5iso b-24-b-94-H-16-3iso b-2-f-94-H-16-2iso b-2-k-94-H-16-2iso b-30-c-94-H-10-3iso b-30-g-94-H-6-3iso b-40-g-94-H-16-2iso b-40-g-4iso b-44-e-94-l-2-3iso b-48-a-94-H-16-3iso b-55-e-94-O-13-10iso b-55-e-11iso b-55-e-12iso b-55-e-13iso b-55-e-16iso b-55-e-17iso b-55-e-18iso b-55-e-19iso b-55-e-20iso b-55-e-2iso b-55-e-3iso b-55-e-4iso b-55-e-5iso b-55-e-6iso b-55-e-7iso b-55-e-9iso b-56-e-94-l-10-5iso b-59-i-94-0-11-3iso b-59-i-4iso  Reservoir Pressure (MPa) 14.68 14.72 14.70 14.71 4.22 4.23 4.24 4.20 4.14 4.15 4.16 4.17 4.18 4.19 4.20 10.67 10.74 11.39 11.43 11.48 3.31 3.33 3.35 3.36 8.36 7.85 7.54 9.64 10.62 7.80 7.88 6.19 8.68 14.58 14.60 14.63 15.06 15.07 15.09 15.10 15.12 14.59 11.41 11.45 11.48 11.52 13.75 13.78 13.80 4.39 11.70 11.72  Permeability ( d)* M  31.82  94.84 37.57  47.53  31.35 32.14  38.36  49.7  -  Sample Depth (m)t -1499.2 -1502.4 -1500.8 -1501.7 -431 -431.8 -433.4 -429.3 -422.3 -423.5 -424.4 -425.4 -426.5 -427.5 -428.5 -1089.8 -1096.4 -1162.6 -1166.6 -1172.2 -338.4 -340.3 -341.9 -343 -854 -801.3 -770.2 -984.6 -1084.4 -796.3 -804.7 -631.9 -886.18 -1488.2 -1490.8 -1493.4 -1537.2 -1538.8 -1540.7 -1542.2 -1543.7 -1489.8 -1164.5 -1169.1 -1172.3 -1176 -1404.0 -1406.7 -1409.2 -448.0 -1194.2 -1197  Sorbed Gas Capacity t 1.07 0.21 0.47 0.56 0.55 1.02 0.13 0.43 1.07 1.86 0.46 0.75 0.65 0.56 0.75 0.49 0.97 0.4 0.34 1.36 0.56 0.91 0.37 0.42 0.33 0.6 0.37 0.51 0.55 0.3 0.37 0.43 0.4 0.2 0.78 0.38 0.47 0.03 0.77 0.52 0.55 0.67 0.29 0.52 1.0 0.13 0.51 0.4 0.29 1.01 0.3 0.32  Total Gas Capacity t (average/well)  GIP for Orb Layer (bcf/section)  GIP for GarbuttMoosebar Fms (bcf/section)  6.68  35.1  32.6  -  -  -  3.89  7.1  5.7  -  -  -  10.73  23.2  55.8  -  -  -  4.86 2.84  7.3 5.2  16.9 5.2  -  -  -  7.75 2.32 7.91 2.90 2.04 6.58  1.0 3.6 4.3 2.4  21.6 15.4 18.5 6.6  -  -  -  -  -  2.2  16.7  -  -  -  4.43 6.25  0.9 8.8  8.8 18.4  -  -  -  8.13  27.2  56.2  -  -  -  -  -  9.8 1.5  3.3 40.5  -  -  2.51  -  201  Sample ID b-59-i-5iso b-59-i-6iso b-59-i-7iso b-66-d-94-0-15-2iso b-66-d-3iso b-66-d-4iso b-66-d-5iso b-66-d-6iso b-66-d-7iso b-66-d-8iso b-70-b-94-H-16-2iso b-76-d-94-l-2-2iso b-79-g-94-O-11-10iso b-79-g-2iso b-79-g-3iso b-79-g-4iso b-79-g-5iso b-79-g-6iso b-81-g-94-H-16-2iso b-84-i-94-H-4-2iso b-95-j-94-P-12-2iso b-95-j-3iso b-95-j-4iso b-95-j-5iso b-95-j-6iso b-95-j-7iso b-95-j-8iSO  c-15-e-94-H-16-2iso c-16-d-94-H-10-2iso c-26-a-94-P-11-3iso c-26-a-4iso c-26-a-6iso c-26-a-8iso c-30-k-94-P-6-3iso c-30-k-4iso c-32-e-94-H-16-2iso c-32-i-94-H-9-2iso  Reservoir Pressure (MPa) 11.75 11.79 11.84 5.17 5.19 5.21 5.23 5.27 5.29 5.34 8.07 6.39 15.85 15.84  -  -  32.93  -  -  -  15.89 15.94 15.98 16.00 7.94 11.47  -  3.33 3.34 3.36 3.37  -  3.40 3.41 3.44 8.41 9.72 3.84 3.86 3.90 3.91 4.56 4.57 8.02 8.95  C-35-b-94-A-14-2iso c-35-b-3iso c-35-b-4iso c-42-g-94-l-3-2iso c-51-b-94-CM4-2iso c-51-b-5iso c-56-i-94-H-9-2iso c-62-b-94-H-11-2iso c-62-b-3iso c-63-d-94-P-1-1iso c-63-d-2iso  8.45 8.47 8.50 6.43 12.12 12.18 8.75  c-74-f-94-H-16-2iso  7.77 10.52 10.53 8.41  c-74-j-3iso c-74-j-4iso C-78-i-94-H-9-2iso  Permeability (Md)*  10.09 10.04 4.88 4.89  55.61 3.3 244.26 84.31  -  72.34  -  35.21  -  35.21  -  -  Sample Depth (m)J -1200.1 -1204.0 -1208.5 -527.8 -530.0 -532.0 -534.4 -538.0 -540.0 -545.7 -824.2 -652.2 -1618.5 -1617.6 -1622.2 -1627.6 -1631.2 -1634.1 -810.25 -1171.2 -340.2 -341.3 -342.6 -344.2  Sorbed Gas Capacity t 1.16 0.89 1.66 0.18 0.17 0.31 0.18 0.19 0.11 0.2  Total Gas Capacity t (average/well)  GIP for Orb Layer (bcf/section)  GIP for GarbuttMoosebar Fms (bcf/section)  -  -  -  3.69  1.5  28.7  -  -  -  -  -  -  -  4.12  4.9  28.7  0.31 0.29 0.34 0.66 0.58 1.06 0.12 0.44 0.25 0.56 0.37 0.21 0.86 0.73 0.17 0.13 0.19 0.21 0.68 0.55 0.76 0.22 0.32 0.85  7.53 10.08  3.6 3.5  20.1 57.2  -  -  -  -  11.46  13.9  115.1  -  -  -  -  -  3.91 8.97 2.07  2.1 4.3 2.4  7.0 14.2 2.5  -  -  -  -  -  -  -  -  -  -  5.23 4.76 1.89  2.1 3.7 2.7  11.7 10.1 2.5  -  -  -  -819.2 -913.3  0.58 0.49 0.52  1.54 7.60 8.27  1.1 2.1 7.2  1.1 17.8 31.2  -863.2 -864.8 -867.6 -656.2 -1237.1 -1244 -892.9 -1030.1 -1025.2 -498.4 -499.7  0.51 0.51 0.31 0.29 0.43 0.58 0.69 0.62 0.4 0.66 0.57  4.96  12.8  33.9  -  -  -  6.29  38.7  38.1  -  -  6.52 9.17  8.8 10.5 0.9  65.4 32.0 6.2  -  -  -793.7  0.43 0.39 0.26 0.39  -346.8 -348.2 -351.3 -858.3 -992.6 -392.0 -393.9 -397.7 -399.4 -465.9 -467.1  -1073.8 -1075.5 -858.6  -  3.15  -  3.60 6.72 1.49  -  -  -  -  1.0  7.0  2.3 0.3  15.5 8.6  -  -  -  5.27  0.7  17.7  202  Sample ID c-80-g-94-H-16-2iso c-80-g-3iso c-84-f-94-l-3-2iso c-89-g-94-B-16-2iso c-8-i-94-H-5-4iso d-10-c-94-H-7-2iso d-10-c-4iso d-13-k-94-H-7-2iso d-13-k-7iso d-20-h-94-l-9-3iso d-23-L-94-H-2-2iso d-24-L-94-H-2-4iso d-33-f-94-P-13-2iso d-33-f-3iso d-33-f-4iso d-33-f-5iso d-33-f-6iso d-33-f-7iso d-33-f-9iso d-33-j-94-H-7-3iso d-33-j-5iso d-38-k-94-H-9-4iso d-47-c-94-H-10-2iso d-51-f-94-H-16-3iso d-55-e-94-H-6-3iso d-55-f-94-P-6-2iso d-55-f-3iso d-55-f-4iso2 d-55-f-5iso d-55-f-6iso d-55-h-94-P-12-2iso d-55-h-3iso d-55-h-4iso d-55-h-5iso d-55-h-6iso d-57-L-94-H-8-2iso d-57-L-4iso d-65-d-94-P-7-6iso d-65-d-7iso d-65-d-10iso d-65-d-11iso d-65-d-1iso d-65-d-5iso d-65-d-8iso d-66-i-94-G-1-3iso d-67-k-94-H-2-2iso d-68-c-94-H-7-2iso d-68-c-7iso d-71-g-94-l-1-2iso d-75-e-94-N-8-6iso d-75-e-9iso d-76-j-94-H-10-2iso  Reservoir Pressure (MPa) 8.13 8.08 6.46 12.95 12.53 10.47 10.60 10.98 11.02 3.32 10.14 10.23 2.92 2.95 2.95 2.97 2.99 3.04 3.06 11.09 11.14 8.70 9.47 8.02 11.07 4.67 4.69 4.73 4.76 4.77 3.69 3.73 3.75 3.77 3.78 10.97 11.04 5.20 5.21 5.24 5.25 5.18 5.19 5.22 12.83 10.23 10.64 10.70 6.24 17.55 17.56 8.31  Permeability (Pd)*  61.59  20.14  0.88 57.21  22.21  10.86 142.85  -  Sample Depth (m)t -830.1 -824.7 -659.8 -1322.4 -1279.3 -1068.9 -1081.8 -1121.3 -1125 -339 -1034.8 -1044.9 -298.3 -300.7 -301.1 -303.5 -305.5 -309.9 -312.8 -1131.9 -1137.7 -888.5 -967.3 -818.7 -1130.0 -476.35 -478.45 -483.1 -485.55 -487.5 -377.2 -380.6 -382.7 -384.8 -386.4 -1120.2 -1127.6 -531.1 -531.9 -534.7 -535.8 -528.9 -529.9 -532.7 -1310.4 -1044.4 -1086.2 -1092.5 -637.3 -1791.8 -1792.7 -848.7  Sorbed Gas Capacity t 0.26 0.52 0.15 0.66 0.55 0.61 0.63 0.84 0.39 0.5 1.0 0.58 0.15 0.39 0.13 0.49 0.36 0.65 0.41 0.22 0.38 0.55 0.67 0.36 0.7 0.65 0.48 0.66 0.78 0.78 0.42 0.43 0.98 0.4 0.43 0.46 0.96 1.23 0.76 0.61 0.69 1.13 1.21 0.51 0.76 0.43 1.14 0.35 0.36 0.63 0.98 0.47  GIP for GarbuttMoosebar Fms (bcf/section)  Total Gas Capacity t (average/well) 9.91  GIP for Orb Layer (bcf/section) 3.9  -  -  -  7.87 7.12 3.11  29.0 22.6 0.9  36.4 23.1 5.5  22.0  -  -  -  2.22 9.42  0.8 2.5  10.0 23.2  -  -  -  2.97 2.97 4.61  3.7 4.1 1.3  3.7 30.2 55.0  -  -  -  2.41  2.6  2.8  -  -  -  6.72 5.35 3.99 7.16 3.86  4.2 1.8 0.8 2.0 3.3  18.1 14.7 9.2 17.6 30.4  -  -  8.70  10.2  10.1  -  -  -  2.43  2.5  2.7  -  -  -  4.90  0.7  15.1  - . -  -  -  -  3.05  2.9  2.8  -  -  -  7.04 3.66 6.21  1.5 0.8 3.6  118.9 32.7 21.0  -  -  -  5.62 14.49 14.53 6.41  5.0 31.0  5.0 356.1  -  -  3.2  10.5  203  Sample ID d-77-f-94-H-3-3iSO d-77-f-4iso d-84-c-94-H-16-2iso d-92-f-94-H-9-2iso d-93-b-94-H-16-3iso d-94-l-94-B-8-2iso d-94-l-3iso d-94-l-4iso d-99-g-94-H-16-2iso d-99-i-94-H-9-2iso d-99-k-94-H-2-3iso  Reservoir Pressure (MPa) 10.42 10.52 8.18 8.22 8.31 6.06 6.09 6.12 7.73 8.46 10.41  Permeability (ud)*  18.05  -  Sample Depth (m)J -1063.8 -1074 -835.4 -839.4 -848.0 -618.7 -621.9 -625.1 -788.7 -863.4 -1062.6  Sorbed Gas Capacity t 1.05 0.25 0.46 0.26 0.44 0.35 0.24 0.15 0.38 0.66 0.68  Total Gas Capacity f (average/well) 5.74  GIP for Orb Layer (bcf/section) 4.4  GIP for GarbuttMoosebar Fms (bcf/section) 31.7  -  -  -  9.58 9.76 10.65  2.6 3.3 2.1  25.8 27.1 30.7  -  -  -  1.95  4.6  20.4  -  -  3.26 6.27 4.81  0.7 5.8 7.9  -  7.5 20.1 27.8  204  Appendix C: Stratigraphic Cross-section C - C . Black boxes indicate the sampled intervals and FS 2 is the datum. 180 km  205  Appendix D: Stratigraphic Cross-section D - D ' . Black boxes indicate the sampled intervals and FS 2 is the datum. 140 k m -  D  D'  West  East  Formation Sikanni  Peace River Group Gates Moosebar  Geophysical Kev GR = G a m m a Ray in API unit (scale is 0 to 150 unless designated) IL = Induction Log - Resistivity In OHMMS (scale 0.1 to 100 unless designated) SP • Spontaneous Potential In mV (scale -35 to 35)  Geological Kev Organic-rich shale  Flooding  Surface  Organic-leaner shale or siltstone  206  Appendix E: Stratigraphic Cross-section E - E ' . Black boxes indicate the sampled intervals and FS 2 is the datum.  207  Appendix F: Stratigraphic Cross-section F-F'. Black boxes indicate the sampled intervals and FS 2 is the datum.  Pi  South  Sea Level  Formation 1 Sikanni  D-31-F-94-G-15  Geophysical Key GR = Gamma Ray In API unit (scale Is 0 to 150 unless designated) II - Induction Log - Resistivity In OHMMS (scale 0 to 50) DT = Sonic (scale 0 to 1000)  Geological Key Organic-rich shale Organic-leaner shale or siltstone  100 m  — | Flooding Surface ] Sandstone  208  

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