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Investigation into the importance of geochemical and pore structural heterogeneities for shale gas reservoir… Ross, Daniel John Kerridge 2007

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INVESTIGATION INTO THE IMPORTANCE OF GEOCHEMICAL AND PORE STRUCTURAL HETEROGENEITIES FOR SHALE GAS RESERVOIR EVALUATION by DANIEL JOHN KERRIDGE ROSS B.Sc., (lions), The University of Aberdeen, 2002 M.Sc., The University of British Columbia, 2004 A THESIS SUBMITTED IN PARTIAL FULFILLMENT OF THE REQUIREMENTS FOR THE DEGREE OF DOCTOR OF PHILOSOPHY in THE FACULTY OF GRADUATE STUDIES (Geological Science) THE UNIVERSITY OF BRITISH COLUMBIA December 2007 © Daniel John Kerridge Ross, 2007 ABSTRACT An investigation of shale pore structure and compositional/geochemical heterogeneities has been undertaken to elucidate the controls upon gas capacities of potential shale gas reservoirs in northeastern British Columbia, western Canada. Methane sorption isotherms, pore structure and surface area data indicate a complex interrelationship of total organic carbon (TOC) content, mineral matter and thermal maturity affect gas sorption characteristics of Devonian—Mississippian (D—M) and Jurassic strata. Methane and carbon dioxide sorption capacities of D—M shales increase with TOC content, due to the microporous nature of the organic matter. Clay mineral phases are also capable of sorbing gas to their internal structure; hence D—M shales which are both TOC- and clay-rich have the largest micropore volumes and sorption capacities on a dry basis. Jurassic shales, which are invariably less thermally mature than D—M shales, do not have micropore volumes which correlate with TOC. The covariance of methane sorption capacity with TOC, independent of micropore volume, indicates a solute gas contribution (within matrix bituminite) to the total gas capacity. On a wt% TOC basis, D—M shales sorb more gas than Jurassic shales: a result of thernial-maturation induced, structural transformation of the D—M organic fraction. Organic-rich D—M strata are considered to be excellent candidates for gas shales in Western Canada. These strata have TOC contents ranging between 1-5.7 wt%, thermal maturities into the dry-gas region, and thicknesses in places of over 1000 m. Total gas capacity estimates range between 60 and 600 bcf/section where a substantial percentage of the gas capacity is free gas, due to high reservoir temperatures and pressures. ii Inorganic material influences modal pore size, total porosity and sorption characteristics of D—M shales. Carbonate-rich samples often have lower organic carbon contents (oxic deposition) and porosity, hence potentially lower sorbed and free-gas capacities. Highly mature Devonian shales are both silica and TOC-rich (up to 85% quartz and 5 wt% TOC) and as such, deemed excellent potential shale gas reservoirs because they are both brittle (fracable), and gas-charged. However, quartz-rich Devonian shales display tight-rock characteristics, with poorly developed fabric, small median pore diameters and low permeabilities. Hence potential `frac-zones' will require an increased density of hydraulic fracture networks for optimum gas production. iii TABLE OF CONTENTS ABSTRACT^ ii TABLE OF CONTENTS^ iv LIST OF FIGURES xi LIST OF TABLES^ xxiii LIST OF ABBREVIATIONS, ACCROYNMS AND CONVERSION FACTORS USED IN DISSERATION^ xxvi ACKNOWLEDGEMENTS xxxiii PROVERB^ xxxv CO-AUTHORSHIP STATEMENT^ xxxvi CHAPTER 1 — INTRODUCTION^ 1 1.1 INTRODUCTORY STATEMENTS^ 2 1.2 OVERVIEW OF GAS CAPACITY CONTROLS IN SHALES AND COALS ^ 4 1.3 SHALE GAS RESERVOIRS AND SEDIMENTOLOGY^ 8 1.4 THESIS OBJECTIVES^ 8 1.4.1 Black shale sedimentology and geochemistry^ 8 1.4.2 Controls on gas capacities ^ 9 1.4.3 Shale fabric, pore size distribution and petmeability ^ 9 1.4.4 Shale gas reservoir evaluation^ 9 1.4.6 Laboratory analyses of shale gas reservoirs^ 9 1.5 STRUCTURE OF THESIS^ 10 iv 1.6 REFERENCES^ 13 CHAPTER 2 — CONTROLS OF ORGANIC CONTENT, MAJOR ELEMENT AND TRACE METAL CONCENTRATIONS IN DEVONIAN-MISSISSIPPIAN STRATA, WESTERN CANADIAN SEDIMENTARY BASIN: IMPLICATIONS ON THE ROLE OF ANOXIA^ 18 2.1 INTRODUCTION^ 19 2.2 GEOLOGIC SETTING 22 2.3 SAMPLES AND METHODS^ 27 2.4 RESULTS AND DISCUSSION 28 2.4.1 Total organic carbon contents, TOC/TN ratios and Stotal^ 28 2.4.2 Major element characteristics^ 38 2.4.3 Excess silica concentrations 44 2.4.4 Trace metal characteristics ^ 45 2.4.4.1 Detrital proxying trace metals (including large ion lithophile TMs)^ 45 2.4.4.2 High field strength trace elements (low solubility in natural waters) 47 2.4.4.3 Bio-concentrated and anoxia-proxying elements^ 50 2.4.4.4 Bottom water redox — Mn concentrations 54 2.4.4.5 Chalcophile elements^ 55 2.4.4.6 Low crustal abundance elements (organo-metallic compounds)^ 56 2.4.4.7 Carbonate elements — Ca, Sr and Y^ 58 2.4 PALEOCEANOGRAPHIC CONDITIONS RESPONSIBLE FOR ORGANIC MATTER AND ELEMENT ACCUMULATIONS^ 58 2.5.1 Organic-rich black shales: Besa River and Muskwa formations^ 61 2.5.1.1 Anoxia^ 61 2.5.1.2 Productivity 61 2.5.1.3 Clastic influx/sediment supply^ 64 2.5.2 Organic-lean grey shales: Fort Simpson Formation^ 65 2.5.2.1 Anoxia and productivity ^ 65 2.5.3 Silty mudstones: Golata Formation^ 66 2.5.3.1 Anoxia and productivity 66 2.5.3.2 Sediment influx/clastic dilution^ 66 2.6 CONCLUSIONS^ 67 2.7 REFERENCES 70 CHAPTER 3 — PREDICTING GAS CAPACITIES OF SHALE GAS RESERVOIRS: IMPORTANCE OF SHALE/MUDROCK COMPOSITION AND PORE STRUCTURE HETEROGENEITY^ 87 3.1 INTRODUCTION^ 88 3.1.1 Shale pore structure 88 3.1.2 Coals as analogues^ 90 3.2 METHODS^ 91 3.2.1 Samples and preparation^ 91 3.2.2 Low pressure CO2 and N2 isotherms^ 93 3.2.3 High pressure Hg porosimetry 96 3.2.4 High pressure CH4 isotherms^ 96 3.2.5 Geochemical and imaging analyses 97 3.3 RESULTS^ 98 3.3.1 Shale composition and fabric^ 98 3.3.2 Low pressure CO2 analyses - shales 102 3.3.3 Low pressure N2 analyses - shales^ 102 3.3.4 Low pressure CO2 and N2 - inorganics 105 3.3.5 Total pore volume and Hg porosimetry^ 105 3.3.6 High pressure CH4 analyses^ 115 3.4 DISCUSSION: DEVELOPING A PORE STRUCTURAL MODEL^ 120 4.4.1 Sorption characteristics and organics: Jurassic strata^ 120 4.4.2 Sorption characteristics and organics: Devonian—Mississippian strata ^ 121 4.4.3 Sorption characteristics: effect of inorganics upon micropore structure ^ 124 4.4.4 Total pore volume^ 126 vi 3.5 CONCLUSIONS^ 128 3.6 REFERENCES 130 CHAPTER 4 — IMPACT OF SHALE LITHOLOGY AND DIAGENESIS UPON FABRIC, PORE SIZE DISTRIBUTION AND PERMEABILITY^ 140 4.1 INTRODUCTION^ 141 4.2 REGIONAL GEOLOGY 145 4.3 METHODOLOGY^ 147 4.3.1 Samples and preparation^ 147 4.3.2 Analyses^ 148 4.3.2.1 Organic content and mineralogy^ 148 4.3.2.2 Imaging methods^ 148 4.3.2.3 Mercury porosimetry 149 4.3.2.4 Permeability^ 149 4.4 RESULTS^ 152 4.4.1 Composition ^ 152 4.4.2 Image analyses 152 4.4.3 Mercury porosimetry^ 165 4.4.3.1 Porosity^ 165 4.4.3.2 Pore size distributions and capillary pressure curves^ 165 4.4.4 Permeability^ 169 4.5 DISCUSSION 171 4.5.1 Shale composition and physical properties^  171 4.5.2 Implications for Devonian shale gas reservoir evaluation, northern BC ^ 174 4.6 CONCLUSIONS^ 176 4.7 REFERENCES 178 vii CHAPTER 5 — CHARACTERIZING THE SHALE GAS RESOURCE POTENTIAL OF DEVONIAN-MISSISSIPPIAN STRATA IN THE WESTERN CANADIAN SEDIMENTARY BASIN: APPLICATION OF AN INTEGRATED FORMATION EVALAUTION^ 186 5.1 INTRODUCTION 187 5.2 SAMPLES AND METHODS^ 192 5.3 SEDIMENTOLOGY^ 197 5.3.1 Stratigraphy 197 5.3.2 Thickness^ 201 5.3.3 Structure 206 5.4 TOTAL ORGANIC CARBON/ROCK EVAL RESULTS^ 209 5.5 MINERALOGY^ 216 5.6 GAS CONTENTS 219 5.6.1 Adsorption capacities^ 220 5.6.2 Potential free gas capacities, total porosity and permeability^ 225 5.7 GEOCHEMICAL AND WIRELINE LOG EVALUATION^ 230 5.7.1 Organic contents, radioactive elements (U, Th and K) and gamma-ray logs^ 232 5.7.2 Shale/mudrock composition, bulk density and sonic log responses^ 232 5.7.3 Mapping TOC: combined gamma-ray and density log calibration^ 236 5.8 RESOURCE POTENTIAL^ 238 5.9 CONCLUSIONS^ 246 5.10 REFERENCES 248 viii CHAPTER 6 — IMPACT OF MASS BALANCE CALCULATIONS UPON ADSORPTION CAPACITIES IN MICROPOROUS SHALE GAS RESERVOIRS^ 258 6.1 INTRODUCTION^ 759 6.2 METHODS 264 6.2.1 Samples^ 264 6.2.2 High pressure adsorption analyses: experimental set-up and calculations 264 6.2.3 Considerations of volumetric calculations for gas adsorption^ 267 6.3 RESULTS^ 268 6.3.1 Section I: Helium effect^ 269 6.3.2 Section II: Helium calibrations and methane adsorption experiments: pore size effect^ 278 6.4 CONCLUSIONS 286 6.5 REFERENCES^ 289 CHAPTER 7 — CONCLUSIONS^ 294 7.1 INTRODUCTION^ 295 7.2 KEY FINDINGS 296 7.3 ECONOMIC PERSPECTIVE: SHALE GAS RESOURCE POTENTIAL OF DEVONIAN-MISSISSIPPIAN STRATA, WESTERN CANADIAN SEDIMENTARY BASIN^ 297 7.4 FUTURE RESEARCH POSSIBILITIES^ 298 7.5 REFERENCES^ 301 ix APPENDICES^ 303 APPENDIX DATA A: CORE DATA^ 304 APPENDIX DATA B: HIGH PRESSURE MERCURY PORE SIZE DISTRIBUTIONS^ 337 APPENDIX DATA C: ROCK EVAL PYROGRAMS^ 352 APPEDIX DATA D: ETHANE ISOTHERMS^ 368 LIST OF FIGURES CHAPTER 1 Figure 1-1^Effect of pore-size diameter on the free gas to sorbed gas ratio (modified from Beliveau, 1993). -Normal porosity" refers to conventional reservoir pore-size distributions. Also shown for reference are CH4 kinetic diameter (0.38 nm) and pore-size classification of the IUPAC (microporous materials)^ 7 CHAPTER 2 Figure 2-1 Map of northern British Columbia showing core locations and the major depo-centre of the Liard Basin (shaded area; see Section 2 for discussion). Provincial key: BC = British Columbia; YK = Yukon; NWT = Northwest Territories. The Liard Basin, which contains up to 5000 m of Palaeozoic and Mesozoic strata, is bounded by the Bovie Fault structure to the east and the Laramide deformation front to the west^ 23 Figure 2-2^Devonian stratigraphy in the Western Canadian Sedimentary Basin (modified from Gal and Jones, 2003)^ 24 Figure 2-3^Core photographs of Devonian-Mississippian strata (centimetre scale bars as shown). A) lower Besa River Foimation ; B) upper Besa River Formation; C) Muskwa Formation (upper left: pyrite-filled fractures; lower left: pyritized carbonaceous material; lower right: light grey interbeds of carbonate); D) light grey shales of the Fort Simpson Formation; E) silty mudrocks of the Golata Formation^ 25 Figure 2-4 Enrichment factors (EF), relative to average shale (Wedepohl, 1971), of analyzed elements in Devonian-Mississippian sediments: A) TOC, S total and major elements; B and C) minor trace elements deteimined by ICP- MS. Horizontal line drawn at EFaverage shale = 1 to highlight enrichment or depletion of elements^ 37 Figure 2-5 ^ Ternary diagram showing relative proportions of major shale/mudrock elements SiO2 (quartz), Al203 (clays) and Ca0 (carbonates). Average shale also shown (after Wedepohl, 1971)^ 39 xi Figure 2-6 ^ Relative concentrations of major elements (normalized to Al) of Devonian—Mississippian sediments. Note enrichment of Si/A1 in lower Besa River, Golata sediments and Muskwa sediments^ 40 Figure 2-7 Figure 2-8 Sulphur-Fe relationships for Devonian—Mississippian sediments. Good correlation between S and Fe2O3 underlines the importance of pyrite as the main storage phase of S (Muskwa and lower/upper Besa River). Poor correlation between Fe and Stotai for Fort Simpson and Golata sediments is a result of low S concentrations and the influence of Fe associated with other mineral phases^ 42 Correlation between TiO2 and Al203 suggesting Ti is primarily associated with clay phases. Note 'over enrichment' of Ti with respect to Al for Golata sediments implying an additional storage phase of Al (silt/sand-sized Ti-bearing minerals?)^ 43 Figure 2-9^Aluminosilicate associations of various elements (calculated as ppm). Plotted are values for: A) Rb; B) Cs; C) Ce; D) La; E) Be. Golata sediments show 'over enrichment' of Ce and La, similar to Ti, suggesting an association of these elements with coarser-grained detritus^ 46 Figure 2-10^Relationships between aluminosilicate phases and high field strength trace metals (all ppm). A) Zr; B) Hf; C) Nb; D) Ga; E) Ta; F) Th. Excess enrichments occur for Golata sediments (Nb, Ta and Th) suggesting affiliation with silt/sand-sized minerals^ 48 Figure 2-11^Plots of analog high field strength elements in Devonian—Mississippian sediments. Zirconium-Hf and Ta-Nb are not fractionated from one another during most geological processes^ 49 Figure 2-12 ^ Organic carbon concentrations verses Al-normalized metal concentrations (calculated as ppm per wt% Al). Plotted values are for: A) Mo/Al; B) Re/Al; C) V/Al; D) U/A1^ 51 Figure 2-13 Rhenium vs. Mo diagram for Devonian—Mississippian sediments. Lower Besa River, upper Besa River and Muskwa sediments show Re/Mo values of anoxic sedimentation. Enrichment of Mo in lower Besa River sediments suggests sporadic euxinic conditions. Both Fort Simpson and Golata sediments plot near the origin. Rhenium/Mo ratios used for identifying anoxic and dysoxic sedimentation from Crusius et al. (1996)^ 53 xii Figure 2-14 ^ Organic-element associations (calculated as ppm per wt% Al): A) Cu/Al; B) Ni/Al. Note enrichments of Cu in Fort Simpson sediments despite low TOC (and low S), indicating other sources (mineralogical?) contributing to Cu concentrations^ 57 Figure 2-15 Figure 2-16 A) Association between excess silica concentrations and low crustal abundance trace metals TI and Cd (-/Al, ppm) for Muskwa and lower Besa River sediments. B) Relationship between K20 and Tl in upper Besa River, Golata and Fort Simpson sediments, indicative of Tl-rich illite 59 Models of sedimentary influences on Devonian—Mississippian sediment geochemistry: A) lower Besa River; B) Muskwa; C) upper Besa River; D) Fort Simpson; E) Golata. See text for discussion 63 CHAPTER 3 Figure 3-1 Figure 3-2 Figure 3-3 Figure 3-4 Correlation between sorption capacities (cc/g) of moisture equilibrated and dry shales examined in this study (D—M = Devonian— Mississippian)^ 94 Major macerals of the shales examined in this study. (A) Granular micrinite of D—M shales in normal reflected light (Stach et al., 1982); (B) matrix bituminite of Jurassic shales after blue-light excitation (Stach et al., 1982; Teichmtiller, 1986). Scale bar = 50 µm^ 101 Scanning electron microscope images of shales examined in this study. A-C) Quartz-rich shales of the LBM member under various magnifications — note lack of fabric. D) Clay-rich UBS member sample — note planar microfabric of clay lamina^ 103 (A) Relationship between micropore volume and TOC for D—M shales. Note good correlation for Muskwa and Besa River samples and poor correlation for organic-lean Fort Simpson shales (r2 = 0.4, not shown). (B) Variation in micropore volume with TOC for Jurassic shales ^ 104 Figure 3-5 ^ Low pressure, low temperature (-196.15°C) N2 isotherms. (A) Organic-rich Muskwa and Besa River shales; (B) Organic-lean Fort Simpson shales; (C) Organic-rich Jurassic shales^ 106 Correlation between CO 2 micropore volume and N2 BET surface area for D—M shales (Fort Simpson r2 = 0.95; Besa River r 2 = 0.69; Muskwa r2 = 0.27)^ 107 Figure 3-6 Figure 3-7 Relationship between shale composition (quartz and clays), total porosity (0) and pore-size distribution for D—M shales. Major element geochemistry and total porosity are an average for the samples shown. High silica content shales (top) are tight with low total pore volume ^ As aluminosilicate fraction increases, porosity increases and modal pore size distribution shifts towards mesopores (microporosity associated with the organic fraction cannot be penetrated by Hg)^ 110 Figure 3-8^Mercury incremental intrusion vs. pore diameter for chert. Note comparable pore-size distributions to silica-rich LBM samples^ 111 Figure 3-9^Comparison of cumulative surface areas calculated using various techniques (low pressure CO2 and N2 sorption, high pressure Hg porosimetry). (A) D—M shales: most surface area is associated with pores <10 nm in diameter (SA = surface area). A significant proportion is in pores with pore throat diameters less than 2 nm. Inset show surface area associated with pores >3 nm diameter. (B) Jurassic shales: similar to D—M shales, most surface area is associated with pores <10 nm in diameter. Inset show surface area associated with pores >3 nm diameter^ 112-113 Figure 3-10^Moderate correlation between N2 BET surface area and total pore volume suggesting total porosity is influenced by the mesopore structure of D—M shales ^ 114 Figure 3-11^Correlation between TOC and methane sorption capacity of moisture- equilibrated D—M and Jurassic shales. Diagonal line highlights the ratio difference of methane sorption to TOC (Jurassic shales: r 2 = 0.38; Fort Simpson shales: r2 = 0.46; Muskwa and Besa River shales: r 2 = 0.8)^ 116 Figure 3-12^Three-dimensional plots relating TOC and micropore volume with sorption capacity. (A) D—M shales. Note importance of microporous organic material upon gas sorption capacities. (B) Jurassic shales^ 117-118 Figure 3-13^Sorption isotherms (at 30°C) for clay standards (dry-basis)^ 119 Figure 3-14^Linear correlation between pressure and methane sorption of a Jurassic shale sample, indicative of a solute gas (following Henrys Law)^ 122 xiv Figure 3-15 Variation of micropore volume with TOC and clay fraction (proxied by percent Al203) for D—M shales. Clay-rich Fort Simpson shales have micropore volumes which are not related to organic contents. Biosiliceous LBM samples show a strong correlation between TOC and micropore volume. Shales enriched in both clays and organics (UBS samples) have the largest micropore volumes, suggesting a micropore contribution from both the organic and clay fraction^ 125 CHAPTER 4 Figure 4-1 Figure 4-2 Figure 4-3 Schematic illustration of the two phase methane desorption from shales. Darcy flow through the fracture network, followed by matrix diffusion into the fractures^ 144 Major depositional influences during the Late Devonian, which included the Horn River and Liard Basins, Klua and Cardova embayments, and the Slave Point carbonate platform (modified from Ross and Bustin, in press)^ 146 Diagram illustrating the pulse-decay permeameter set-up for measuring permeabilities at various confining pressures. V u = upstream reservoir of gas; Vd = downstream reservoir of gas; V s = shale and pore volume; Pu = upstream pressure; pd = downstream pressure; p c = confining pressure; Ap = pressure decay^ 150 Figure 4-4 Figure 4-5 Ternary diagram of core A and B samples, and permeability sample sets C and D^ 156 Down-core profiles of lithologic variabilities (major mineral phases and TOC contents), and associated fabric differences, of core A (T/S = thin- section). A) clay-rich horizon (-60% illite); B) low TOC content (0.4 wt%) manly limestone (classified after Pettijohn, 1975) ; C-1) quartz- rich silty horizons; C-2) same sample as C-1, highlighting sharp horizontal contact between clay-rich layer and quartz-rich layer; D) organic-rich horizon with comparable concentrations of quartz, clays and carbonates; E) manly limestone with scatted organic matter (horizontally aligned organic flakes). Also shown is a vertical cemented fracture which is cross-cut by an open horizontal fracture (blue resin filled); F-1) recrystallized bio-fragments (possibly sponge spicules and brachiopod spines) and secondary calcite precipitation xv rims around bioclasts; F-2) compacted skeletal fragments (possibly compacted tests of foraminifera)^ 157-158 Figure 4-6 Figure 4-7 Figure 4-8 Figure 4-9 Down-core profiles of lithologic variabilities (major mineral phases and TOC contents), and associated fabric differences, of core B. A) organic-rich (-4 wt% TOC), quartz-rich (-98% quartz) shale with faint horizontal fabric; B) dolomitized shale; C) quartz-rich shale (-75% quartz) showing no fabric; D) Silty beds within quartz-rich shale; E) shale (-50% quartz) with horizontal lenses (carbonate); F-1) bioclastic zone in lower portion of core with compacted skeletal fragments (possibly compacted tests of foraminifera); F-2) carbonate precipitation rims (halos cement) around recrystallized bio-fragments; G) packed biomicrite^ 159-160 Image analysis of quartz-rich Devonian shales (scales as shown). A) Example of the faint crenulated fabric with possible lenticles of chalcedonic silica in shale matrix; B) rare coarser-grained quartz beds; C-1) compaction of kerogen stringers around a siliceous test (entactiniid radiolarian, Family Entactinaria; Carter pers. Comm.); C-2) figure C-1 in cross polarization, highlighting internal concentric lattice shells of siliceous test; D) cuspate-lobate external structure of a silica- filled cyst; E—F) SEM and BSEM (polished thin-section) images - note lack of distinct fabric in quartz-rich shales ^ 162 A—D) Image analysis of illite-rich/low quartz content Devonian shales (scale as shown). A) horizontal fabric due to preferential alignment of clay plates; B) SEM image highlighting clay mineral alignment; C) high magnification image of rare silty carbonate lenses (no visible porosity); D) BSEM image of a polished thin-section showing coarse, euhedral dolomite crystals with distinct zonation^ 163 Examples of microfractures (scale as shown). A) open fracture crosscutting quartz- and clay-rich laminae; B) BSEM image of near- horizontal fractures; C) calcite-filled vertical fracture, upon which smaller open fractures terminate (highlighted by arrows); D) parallel and near-vertical silica-cemented fractures^ 164 Figure 4-10 Macrofractures in Devonian core: A) mineralized pyrite fractures; B and C) calcite-cemented fractures; D) Partially mineralized calcite fracture with bitumen; E) mosaic-like calcite filled fracture with sulphides; F) horizontal hairline fractures with calcite cement; G) example of syn-depositional faulting (scale bar = 5 cm)^ 166 xvi Figure 4-11 ^ Relationship between key lithologic properties (TOC, quartz, clay and carbonate contents) and porosity. Sample key shown in TOC plot. Porosity shown on x axis^ 167 Figure 4-12 Figure 4-13 Log differential vs. pore size diameter: A) sample suite C; B) sample suite D Relationship between key lithologic properties (TOC, quartz, clay and carbonate contents) and porosity  168 Mercury saturation vs. pressure: A) sample suite C shows relatively close similarity in Hg intrusion trends; B) sample suite D shows differing saturation curves with clay-rich samples exhibiting high levels of Hg saturation at lower pressures compared to quartz-rich D1 ^ 170 Figure 4-14^Permeability vs. quartz content: A) sample suite C; B) sample suite D. Lower permeability of quartz-rich shales highlights tight-rock characteristics, similar to the results of high pressure Hg porosimetry^ 172 CHAPTER 5 Figure 5-1 ^ Stratigraphic section of Devonian—Mississippian in northern British Columbia, south-eastern Yukon and south-western Northwest Territories (modified from Gal and Jones, 2003). Darker grey shadings represent shaly strata. Note: Presq. = Presqu'ile^ 190 Figure 5-2^Map of study area map showing well-core locations. Also highlighted are the Laramide deformation front (western limit of study area) and Bovie Fault Zone (location from Wright et al., 1994). Study region also includes southern Yukon (YK) and Northwest Territories (NWT) for wireline log correlations. Grid pattern (e.g., 94-N) represents the National Topographic System (NTS) coordinates for British Columbia^ 191 Figure 5-3 Major paleogeographic, depositional facies and structural features which affected Devonian—Mississippian deposition including the Cardova and Klua reefal embayments. Also shown is the Trout Lake Fault zone (location from MacLean and Morrow, 2004) — see Structure text for discussion. Cross section lines for figures 5-5 and 5-8 are shown. Light grey regions represent carbonate-dominated facies. Dark grey regions represent basinal/argillaceous facies (Note: Yukon and xvii Northwest Territories use the grid-section-unit system of surveying, not NTS, hence map grids are different to British Columbia). Black squares show well locations for figures 5-4, 5-9 and 5-10^ 199 Figure 5-4^Well logs showing typical response through stratigraphic units. (A) Subdivision of the Besa River Formation into informal units for shale gas reservoir exploration (LBM = lower black mudrock member; MS = middle shale member; UBS = upper black shale member) with eastern lateral equivalents. (B) Wireline log response of the UBS member (Besa River) and the Mattson Formation. (C) Typical log response for Cardova embayment strata, which include the Muskwa Formation and argillaceous carbonates of the Evie Member and Otter Park Formation^ 200 Figure 5-5 Figure 5-6 Key for cross-sections (Figures 5-5 continued, 5-6 and 5-9). Log- stratigraphic cross-section. Cross section A-A' (Figure 5-3) of the Klua embayment showing the westward increase in thickness of basinal, argillaceous deposits of the Horn River and Muskwa formations. Datum = Banff Formation^ 202-203 Cross section B-B' (Figure 5-3) though the Cardova embayment (orientated E—W). Datum = Exshaw Formation. Logs shown: gamma- ray (profile on left); sonic, density and/or resistivity (right profile) ...204 Figure 5-7^Isopach maps for the Besa River Formation and sub-members, which are of interest for shale gas reservoir exploration. (A) Total Besa River (contour interval = 75 m). (B) Middle shale member (MS; contour interval = 50 m). (C) Lower black mudrock member LBM; contour interval = 30 m). (D) Upper black shale member (UBS; contour interval = 20 m). Isopach map of the entire Besa River Formation also shows the approximate transition zone from Besa River to Horn River/Woodbend /Winterburn sediments (dotted line). Solid line represents the edge Laramide thrusting and dashed line represents Bovie Fault^ 205 Figure 5-8 (A) Isopach map of the argillaceous/basinal deposits of the Horn River and Muskwa formations (contour interval = 25 m). Note thickening trends are primarily associated with the locations of Cardova and Klua carbonate embayments. (B) Isopach map of the Muskwa Formation only (contour interval = 20 m). (C) Isopach map of the Fort Simpson Formation, showing similar thickening trends as the Muskwa Formation towards the Liard Basin region (contour interval = 50 m). Thicknesses of Fort Simpson lateral equivalents in the Liard Basin are shown in Figure 5-7B (MS member)^ 207 xviii Figure 5-9 ^ Structure map to the top of the Muskwa Formation (and the LBM member lateral equivalent in the Liard Basin). Note significant change in burial depth across the Bovie Fault zone (contour interval^-250 m)^ 208 Figure 5-10 Figure 5-11 Cross-section C-C' (Figure 5-3) through the Bovie Fault zone highlighting erosion of the Mattson Formation across the Bovie Fault region^ 210 (A) TOC versus well-log response in down core profiles of the Besa River Formation. Note low measured TOC in the MS member (lateral equivalent of the Fort Simpson Formation). (B) Core profile of TOC contents versus well-log response in the UBS member (Besa River) and Mattson Formation^ 211 Figure 5-12^A to E: TOC core profile through Horn River, Muskwa and Fort Simpson formations^ 213-214 Figure 5-13 Figure 5-14 (A) Examples of adsorption isotherms for Muskwa Formation samples at various reservoir temperatures. Shaded grey zone represents approximate reservoir pressure based on hydrostatic pressure gradient. (B) Examples of adsorption isotherms of LBM member (Besa River) samples analyzed at 100°C. The saturation point of the isotherms (i.e. the point where the slope of the line is reduced) occurs at pressures typically less than 20 MPa. At the predicted reservoir pressures (grey box), the plateau of the isotherm is reached. (C) Effect of temperature on adsorption capacity for a UBS member sample. Significant reduction in adsorbed gas capacity occurs by increasing the temperature from 30 to 100°C^ 224 Potential free gas capacities assuming pore space is saturated with gas (zero water saturation). (A) UBS member. (B) and (C) LBM member samples. Adsorbed gas capacities shown are measured at 100°C. At high reservoir temperatures (>100°C), free gas capacity is a significant contributor to the total gas capacity for porosities in the range 0.5- 6.8%^ 227 Figure 5-15^(A) Relationship between porosity and permeability for Besa River, Muskwa and Fort Simpson samples. Correlation is poor although higher permeabilities are generally associated with more porous sediments (UBS member). (B) Log-linear relationship between porosity and peiineability of the LBM member and chert^ 229 xix Figure 5-16^Graph showing relationship between TOC and gamma-ray (measured in API) of Muskwa (wells A-94-G 94-P-08 and B-88-H 094-J-14) and Fort Simpson shales. Covariant trend is related to U-rich organic matter^ 231 Figure 5-17 Figure 5-18 Figure 5-19 Figure 5-20 Figure 5-21 (A) Sonic and density log response across the Muskwa Formation showing an increase in sonic transit time and decrease in bulk density related to organic enrichment. (B) Inverse correlation between quartz content and sonic transit time for LBM and UBS members and Muskwa samples. See text for discussion^ 233 Average sonic transit times for Horn River (including LBM member) and Muskwa formations across northern BC, southern YK and NWT (contour interval = 10 µs/m). There is a general decreasing trend of sonic transit time to the west, into the Liard Basin region likely due to enrichment of quartz (biogenic silica) 235 (A) Correlation between log- and laboratory-derived TOC. (B) Map of TOC concentrations for Horn River and Muskwa sediments (contour interval = 0.2 wt%). Total organic carbon enrichment in section 94-P is associated with a thin interval of Muskwa shale, as opposed to surrounding embayments, which contain organic-lean argillaceous carbonate deposits (e.g. Otter Park Formation). Elongate N—S organic enrichment in 94-0 may represent an elongate depocentre in this region^ 237 Bcf/section map (adsorption capacities) for Horn River and Muskwa formations (contour interval = 2 bcf/sec). Decrease into the Liard Basin region where reservoir temperatures exceed 100°C and adsorbed gas capacities are insignificant. Larger adsorption capacities east of the Bovie fault represent thicker sequences of basinal strata. Outline of the Fort Worth Basin, TX (Barnett Shale) also shown as polygon in lower right quarter of map for area comparison^ 240 Bcf/section map (adsorption capacities) for the Fort Simpson Formation (contour interval = 0.5) and the laterally equivalent UBS member (inset; contour interval = 0.2). Similar to Horn River and Muskwa formations, adsorbed gas capacities for Fort Simpson shales decrease into the Liard Basin region. Gas capacities for the UBS member follow thickness variability^ 241 Figure 5-22^Total gas capacity map (adsorbed plus free gas; bcf/section) for Horn River and Muskwa formations (contour interval = 20 bcf/sec)^ 243 xx Figure 5-23^Total gas capacity map (adsorbed plus free gas; bcf/section) for the Fort Simpson Formation (contour interval = 50 bcf/sec) and the UBS member (inset; contour interval = 50 bcf/sec) ^ 244 CHAPTER 6 Figure 6-1^Examples of calculated negative adsorption of Jurassic (A and B) and Devonian (C and D) shales)^ 261 Figure 6-2^Conceptual illustration of pore networks in shales and mudrocks ^ 262 Figure 6-3 ^ Helium void volume calibration of ZeoSorb 61 (pore diameter of 0.74 nm). Note that above 2 MPa, the pressure ratios between reference cell and sample cell are relatively consistent^ 270 Figure 6-4^Calibration examples of organic-rich mudrock samples showing relative increase in measured void volume at higher pressure expansions. Note scales are not uniform^ 271 Figure 6-5 ^ Helium void volume calibrations for major constituents of shale/mudrock samples (all on dry-basis). A) kaolinite; B) smectite; C) illite; D) quartz. Note the increasing void volume trend at higher cell expansions is not apparent for quartz^ 272 Figure 6-6^Void volume calibration examples of moisture equilibrated mudrock and clay samples with moisture contents shown in graphs. A—C) mudrock samples; D) smectite. Note for low EQ moisture samples, void volume calibration shows similar trend to dry samples indicating greater void space is still available at higher pressures. Samples with high EQ moisture contents (5378-1 and smectite) show no clear trend^ 273 Figure 6-7 ^ Helium isotherms with monotonous trends. A) Smectite; B) and C) mudrock samples. Occasionally isotherms have humps, perhaps a reflection of the slow diffusion into the microporosity^ 275 Figure 6-8 ^ Calculated helium isotherms of a shale sample with different void volume calibration time. With longer calibration time, the molecule accessibility/adsorption is similar to the actual adsorption experiment xx i hence lower excess helium capacity is calculated for the longer calibration time (i.e. 1000 seconds). The curves follow identical trends as only the void volume calibrations, and not the adsorption experiment, are varied with time^ 276 Figure 6-9 Figure 6-10 Methane adsorption isotherms of zeolites with known pore-size distribution A) ZeoSorb 61: 0.74 nm pore-size; B) ZeoSorb 43: 0.41 nm pore-size; C) ZeoSorb 33: 0.31 nm pore-size)^ 279 Methane adsorption isotherms of zeolites with known pore-size distribution A) ZeoSorb 61: 0.74 nm pore-size; B) ZeoSorb 43: 0.41 nm pore-size; C) ZeoSorb 33: 0.31 nm pore-size).^ 280 Figure 6-11^Mudrock sample with negative methane adsorption yet raw pressure data reveals gas diffusion and/or adsorption^ 283 Figure 6-12^Conceptual illustration of gas diffusion and sorption in the heterogeneous shale matrix. A) Low sorbing, organic-lean shale with some pores and pore throats penetrable only by helium (constricted pores; 1 and 2). Hence internal surface area can only be accessed by helium (3), and not methane (location of figure A-2 shown in figure A- 1). B) High sorbing, organic-rich shale which has pore throats through which both helium and methane can permeate (1 and 2). Following diffusion into the micropores, methane can sorb onto the internal surfaces (3)^ 284 Figure 6-13^Hypothetical example showing the reduction of porosity (or excess void space which is only accessible to helium) required to calculate positive adsorption using mass balance calculations on low-adsorbing shales^ 285 LIST OF TABLES CHAPTER 2 Table 2-1 Major oxides (as %) with total organic carbon (TOC; as wt%), inorganic carbon (IC; as wt%), sulphur (S; as %) and total nitrogen (TN; as %) of Devonian—Mississippian sediments. (Key: MU = Muskwa; LBR = lower Besa River; UBR = Upper Besa River; GA = Golata; FS = Fort Simpson). *See text for excess silica calculation — dashes represent sediments with no calculated excess silica. Total organic carbon and IC data from Chapter 5^ 29 Table 2-2^Major element concentrations (reported as %) 30 Table 2-3^Major elements normalized to Al (reported as %)^ 31 Table 2-4^Minor elements (reported as ppm). Note: ICPMS detection limit for Re is 0.002 ppm and Se is 1 ppm^ 32 Table 2-5 Table 2-6 elements normalized to Al (reported as ppm/% Al)^ 33 Average concentrations of al major elements and trace metals of Devonian—Mississippian sediments. Averages are also shown normalized to Al. (I)Average shale composition from Wedepohl (1971, 1991) used to determine enrichment factors (EF), except Re (from Crusius et al., 1996)^ 34 CHAPTER 3 Table 3-1 Composition, surface areas and sorption capacities of D—M shales. Total organic carbon (TOC) contents, equilibrium moisture contents (moisture), pore characteristics (total porosity, CO2 micropore volume and N2 BET surface area) and sorbed gas capacities (moisture equilibrated and dry-state) are provided. Also shown are the three major oxide groups Si02 , A1703 and CaO, representing quartz, clay and carbonate mineral phases respectively (* data from Chapter 2). Dashes show unavailable data^ 99 Table 3-2^Composition, surface areas and sorption capacities of Jurassic shales. Included are Tmax values (and vitrinite reflectance equivalent, % Ro) representing thermal maturation levels (*data from Ross and Bustin, 2007)^ 100 Table 3-3 ^ Results of pore structure (CO2 micropore volume and N2 BET surface area), moisture and sorbed gas capacities of clay mineral standards and chert^ 108 CHAPTER 4 Table 4-1 Table 4-2 Table 4-3 Lithologic composition of core A samples. TOC = total organic carbon content; 0 = total porosity^  153 Lithologic composition of core B samples (missing 0 measurements are shown as blanks)^ 154 Lithological composition and physical rock properties of permeability sample (k samples) suites C and D. k = permeability at 30 MPa effective confining pressure^ 155 CHAPTER 5 Table 5-1 ^ Sample locations, total carbon (TC), inorganic carbon (IC) and total organic carbon (TOC) for all Devonian-Mississippian units examined in this study (TVD = total vertical depth in metres)^ 193-196 Table 5-2 Rock Eval pyrolysis data for a representative suite of Devonian- Mississippian mudrocks and shales. S1 and S2 represent the amount of hydrocarbons volatilized at 300°C and evolved from kerogen at 300°C to 600°C respectively. The amount of CO) generated from 300°C to 390°C comprises the S3 value. Quality of organic carbon is assessed using Hydrogen (HI) and Oxygen (01) indices (HI=S2/TOCx100, OI=S3/TOCx100) which relates to the atomic H/C and 0/C ratios (Espitalie et al., 1977). S2 values below 0.2 are deemed unreliable. Total organic contents do not decrease with decreasing S2 values, hence low S2 values are the result of thermal maturation past the point of oil preservation. Anomalously low Tmax values (the temperature required to crack the remaining hydrocarbons) reflect the disappearance of the S2 peak^ 215 xxiv Table 5-3 ^ Mineralogical composition or Devonian—Mississippian shales and mudrocks. Note high quartz concentrations of LBM member sediments which, in part, are attributed to a biogenic source^ 217-218 Table 5-4 Adsorption capacities, predicted reservoir temperatures, equilibrium moisture contents and geochemical data of Devonian—Mississippian shales and mudrocks. Low adsorption capacities of Besa River and Mattson sediments are related to high reservoir temperatures (up to 150°C), whereas Muskwa shales have larger adsorbed gas capacities because reservoir temperatures are estimated to be lower (<80°C). Fort Simpson shales have low adsorption capacities which are related to low TOC and moderate-high reservoir temperatures (up to 92°C). Abbreviations: pounds per square inch absolute (PSIA); megapascals (MPa); standard cubic feet per ton (scf/t); centimetres cubed per gram (cm3/g)^ 221-223 Table 5-5 ^ Porosity and permeability for selected Devonian—Mississippian samples. Permeabilities calculated using the Swanson (1981) method^ 228 XXV LIST OF ABBREVIATIONS, ACRONYMS AND CONVERSION FACTORS USED IN DISSERTATION Abbreviations and acronyms API American Petroleum Institute ASTM American Society of Testing and Materials BCF Billion cubic feet BCF/section Billion cubic feet per section BET Brunauer-Emmett-Teller °C Degree Celsius CBM Coalbed methane CL Cathode luminescence CH4 Methane CNS Carbon-nitrogen-sulphur CM3/g Centimetres cubed per gram CO2 Carbon dioxide D Darcy D-R Dubinin-Radushkevich EOS Equation of state EOSc Earth and Ocean Sciences department (UBC) °F Degree Fahrenheit ft Feet GR Gamma-ray GSC Geological Survey of Canada xxvi HI Hydrogen index Hg Mercury k Permeability k11 Matrix permeability K Kelvin km Kilometre m Meters or meter Ma Million years ago mD Millidarcy, millidarcies (10 -6 D) mi Mile MPa Mega pascals M.Y. Million years N2 Nitrogen nD Nanodarcy, nanodarcies (10 -9 D) NE BC Northeastern British Columba (Canada) nm Nanometres (10 -9 m) OI Oxygen index ppm Parts per million PSIA Pounds per square inch absolute PSIG Pounds per square inch gage REE Rare earth element Ro Reflectance of vitrinite in oil scf/t Standard cubic feet pre tonne SEM Scanning electron microscopy sq. Square STP Standard temperature and pressure TCF Trillion cubic feet Tmax Thermal maturation level determined by Rock Eval pyrolysis TOC Total organic carbon Ds/m Microseconds per metre WCSB Western Canadian Sedimentary Basin wt. % Weight percent Unit Abbreviations FSS Fort Simpson Formation MU Muskwa Formation BRS Besa River Formation LBM member Lower Black Mudrock member (Besa River) MS member Middle shale member (Besa River) UBS Member Upper black shale member (Besa River) GA Golata Formation MASH Mattson Formation shales Provincial Abbreviations BC British Columbia AB Alberta NWT Northwest Territories SK Saskatchewan YK Yukon Elements Ag Silver Ba Barium Be Beryllium Bi Bismuth Cd Cadmium Ce Cerium Co Cobalt Cr Chromium Cs Caesium Cu Copper Ga Gallium Ge Germanium Hf Hafnium La Lanthanum Mn Manganese Mo Molybdenum Nb Niobium Ni Nickel Pb Lead Rb Rubidium Re Rhenium Se Selenium Sr Strontium Ta Tantalum Th Thorium TI Thallium U Uranium V Vanadium Y Yttrium Zn Zinc Zr Zirconium XXX Conversion factors To convert from^To^ Multiply by Length foot (ft)^kilometre (km)^0.000305 foot (ft) meter (m) 0.305 foot (ft) mile (mi) 0.000189 kilometre (km)^foot (ft)^ 3280 kilometre (km) mile (mi) 0.621 meter (m) foot (ft) 3.28 mile (mi)^foot (ft)^ 5280 mile (mi) kilometre (km) 1.61 Area sq. kilometre (km2 )^sq. mile (mi 2) ^ 0.386 sq. mile (mi 2)^sq. kilometre (km2) 2.59 Pressure MPa^ PSIA ^ 145.0377 PSIA MPa 0.0069 PSIA^ PSIG^ subtract 14.7 Sorption cm3/g^ scf/t^ 32.0369 scf/t cm3/g 0.03121 Temperature °C^ °F^ ((°Cx9)/5) + 32 °F °C ((°F-32)/9)*5 Geothermal Gradients degree Celsius per 100 meters^degree Fahrenheit per 100 feet^0.549 (°C/100 m) ^ (°F/100 ft) degree Fahrenheit per 100 feet^degree Celsius per 100 meters^1.82 (°F/100 ft) ^ (°C/100 m) ACKNOWLEDGEMENTS This thesis could not have been successfully completed without the patience and assistance of a number of people. First and foremost, I would like to thank Dr R. Marc Bustin for all his time, effort and mentoring during my PhD. He has read though my dissertation countless times, and his comments have made me a better writer and scientist. Marc has been a great inspiration to me throughout my MSc and PhD, and made my five years at UBC very memorable and enjoyable. I am sorely going to miss his Friday afternoon beers. Thanks also to my supervisory committee, Dr Stuart Sutherland and Dr Kurt Grimm for their advice and help. Special thanks to Dr Gareth Chalmers (yes, an Australian doctorate!) for his advice and chat over Tim Horton tea- runs. He was also a worthy advisory for killer darts.....although he could do with some more practice (as could SS). My time at EOSc was made enjoyable by many other people, especially the sedimentology group (Amanda, Laxmi, Murthy and Albert), and other graduate students too numerous to mention. I am also indebted to various Earth & Ocean Sciences staff including Maureen Soon for running CNS samples, and Alex Allen and Teresa Woodley for helping me out with a plethora of random questions in the main office. Access to core and core analysis was provided by the BC government - thanks to everyone at the BC core facility at Fort St John. Research and personal funding was provided by the Natural Sciences and Engineering Research Council of Canada (NSERC; Bustin) grant, EnCana, CBM Solutions and UBC graduate fellowships. Most importantly, I want to thank my family: mum, Robbie, Nat, Katrina, Keith and the not-so wee men (Aaron, Finlay and Angus) — I wish we were all closer geographically but your support and encouragement has always been there. Lastly, and by no means least, I want to give a big gihugious special thanks to my girlfriend Krista, who has shown endless love, patience and unwavering support during my Ph. D. It is to all of them I dedicate this thesis. xxxiv 'Set a stoot hert to a stey brae' XXXV STATEMENT OF CO-AUTHORSHIP Identification of research program The research of this thesis was developed upon original concepts of Dr R. Marc Bustin, as part of his unconventional gas exploration group. Jurassic and Devonian- Mississippian shales and mudrocks were chosen and sampled by Daniel J.K. Ross to elucidate the controls upon gas capacities in shale gas reservoirs. Data analyses High pressure methane adsorption and helium pycnometry apparatuses were designed and constructed by Dr R. Marc Bustin, at the department of Earth and Ocean Sciences (EOSc), University of British Columbia (UBC). Carbon-nitrogen-sulphur analyses were performed in the oceanography department (UBC) by Maureen Soon, as were major element analyses. High pressure mercury porosimetry and low pressure carbon dioxide and nitrogen adsorption analyses were conducted by Daniel J.K. Ross at EOSc. Permeability analyses were performed by Murthy Pathi, with the assistance of Drs Chikatamarla Laxminarayana and Amanda M.M. Bustin. Analytical troubleshooting was performed with the assistance of Drs R. Marc Bustin, Chikatamarla Laxminarayana and Gareth R.L. Chalmers. Rock Eval pyrolysis analyses were conducted at the Geological Survey of Canada (GSC) in Calgary, AB. Trace and rare earth element geochemistry was analyzed at ALS Chemex ® (Vancouver, BC). Polished thin-sections were prepared by Vancouver Petrographics Ltd® (Langley, BC). Data interpretation and manuscript preparation Interpretations of high pressure adsorption and pore structure data, permeability data, image analyses data, organic, major and trace element geochemistry data in this thesis were conducted by Daniel J.K. Ross. Daniel J.K. Ross is responsible for all manuscript content and the research papers produced. Conceptual, editorial and scientific guidance was provided by Dr. R. Marc Bustin. Editorial assistance was also provided by Dr. Gareth R.L. Chalmers. CHAPTER 1 INTRODUCTION 1 CHAPTER 1 Introduction 1.1 INTRODUCTORY STATEMENTS Natural gas from organic-rich shales is a viable economic energy resource, highlighted by the continuing successful development of shale gas reservoirs' in the United States (US). There are currently over 39,500 shale gas wells in the US producing 600 bcf/year, accounting for 8% of total gas production (Bustin, 2005; Warlick, 2006). The success of US shale gas exploration has provoked interest in potential reservoirs of the Western Canadian Sedimentary Basin (WCSB) which contains vast thicknesses of fine-grained, organic-rich siliclastic material. Shale strata range in age from Ordovician to Late Cretaceous (Allan and Creaney, 1991) with gas resource estimates of over 1000 trillion cubic feet (TCF; Bustin, 2005). To quantify shale gas resources and develop an efficient exploration program, the effects of shale physical properties upon gas content and transport need to be understood. However factors which influence total gas-in-place (TGIP) and reservoir processes remain unclear and favourable shale gas reservoir properties are poorly defined. Significant gas accumulations undoubtedly exist in WCSB shales, but their identification, exploration and exploitation have been inhibited by four factors: Includes gas produced from mudrock, siltstone and fine-grained sandstone strata 2 1) Insufficient/incomplete data sets on organic-rich facies which are deemed excellent source rocks but uneconomic reservoirs. Shales have not been the primary target for sub-surface exploration due to coring costs, therefore shale samples are scarce. Most published reservoir exploration data relates to source- rock analysis (Hunt, 1995), hydrocarbon seal efficiency (Bolton et al., 2000) or specific problems such as shale sensitivity to drilling fluids (van Oort et al., 1994). 2) Analytical difficulties due to the friable nature and tight-rock characteristics of shales. For these reasons, core analyses of shales for reservoir properties are not routinely done. 3) Gas storage mechanisms of shales are inadequately understood. Interpretations rely upon the findings of coal properties and coalbed methane (CBM) production. 4) There are no standard analytical protocols or procedures for shale gas reservoir characterization (e.g., American Society of Testing and Materials; ASTM). As a result, there is a degree of uncertainty comparing shale gas reservoir attributes. Coalbed methane reservoirs have provided insight to gas retention properties of shale gas reservoirs where gas is stored in the sorbed state. As for coals and other microporous materials, shale sorption2 data is modeled to the Langmuir isotherm 3 equation (Langmuir, 1918). The Type I isotherm is most commonly applied to organic matter (of shales and 2Sorption is a general term which includes surface adsorption, absorption and capillary condensation (Gregg and Sing, 1982). 3 Sorption isotherms represent the maximum storage capacity of gas in the sorbed state, as a function of pressure and temperature. 3 coals) with large internal/small external surface area4 and sorption is restricted to a few monolayers. Despite the general association of coals and shales as unconventional gas reservoirs, there are considerable geologic differences. These include (after Bustin, 2005): 1) the contribution of sorbed and free gas 5 to total gas capacity; 2) importance of pore-size distribution and total pore volume (% porosity); 3) total rock volume (lateral and vertical extent) and; 4) sensitivity of permeability (k) in CBM reservoirs due to the highly compressible organic matrix. Comparisons between shale gas and CBM reservoirs are complicated further by shale heterogeneity, a reflection of diverse sedimentological and oceanographic conditions during fine-grained sediment deposition. 1.2 OVERVIEW OF GAS CAPACITY CONTROLS IN SHALES AND COALS Both organic and clay contents are considered important controls on gas sorption in shales (Manger et al., 1991; Kuuskraa et al., 1992; Lu et al., 1995; Ramos, 2004; Ross, 2004; Chalmers and Bustin, 2007). Ross and Bustin (2007) showed a weak positive correlation between sorbed gas capacities and total organic carbon (TOC), arguing moisture, thermal maturity and mineral matter complicate the relationship between organics and sorption. Consequently there are difficulties isolating a dominant sorption control in shales (i.e. TOC). Nonetheless, TOC contents are important for two reasons: 1) the gas generative potential of organic-rich shales at appropriate levels of thermal Internal surface area is area which comprises the walls of all cracks, pores and cavities which are deeper than they are wide. External surface areas are all prominences/cracks which are wider than they are deeper (after Gregg and Sing, 1982). 'Free gas is defined as any gas which is not physically adhered to a surface, including gas in open/intergranular pores and fractures. 4 maturation (Hunt, 1995) and; 2) gas is concentrated in shale facies with extremely high TOC contents (Manger et al., 1991). Coal sorption characteristics and pore structure (of terrestrially-derived organic matter) are well documented in the literature due to investigations of coal gas outburst properties, CBM reservoirs and CO2 sequestration (Clarkson and Bustin, 1999; Xu et al., 2006; Faiz et al., 2007). On a mineral matter-free basis, the amount of methane sorbed increases with rank, vitrinite enrichment and decreases with higher inertinite content (Crosdale and Beamish, 1993; Lamberson and Bustin, 1993; Bustin, 1997; Clarkson and Bustin, 1999; Laxminarayana and Crosdale, 1999). Increasing CH 4 sorption with vitrinite content results from different pore-size distributions: vitrinite is predominantly microporous6 and inertinite is meso-macroporous (Lamberson and Bustin, 1993; Bustin and Clarkson, 1998). Inertinite-rich coals with high semi-fusinite contents can be microporous from the creation of smaller pores through charring (Clarkson and Bustin, 1996). Other important coal properties affecting gas sorption include ash content/mineral matter (Lamberson and Bustin, 1993; Laxminarayana and Crosdale, 1999), moisture (Joubert et al., 1974; Unsworth et al. 1989) and temperature (Bustin and Clarkson, 1998). There have been few systematic investigations of shale pore structure with respect to gas sorption. Chalmers and Bustin (2007) reported a positive correlation between TOC content, CO2 micropore volume (Dubinin-Radushkevich (D-R) equation; Gregg and Sing, 1982) and CH4 sorption attesting to the microporous nature of the organic matter. In a study of hydrocarbon gases on clays, coals and shales, Cheng and Huang (2004) 6 Porosity is classified according to diameter size using the International Union of Pure and Applied Chemistry (IUAPC) classification: micropores (<2 nm), mesopores (2-50 nm) and macropores (>50 nm) 5 found similar CH4 sorption capacities of clay minerals as a shaley coal (TOC = 24.7 wt.%) and oil shale (TOC = 20.2 wt.%), despite smaller surface areas of the coaly shale and oil-shale. To explain this, Cheng and Huang (2004) estimated the coverage area of the hydrocarbon component (based on hydrocarbon diameters), concluding a multi- layering may have occurred on the organics. Evaluating gas saturation of unconventional reservoirs also requires an understanding of the free gas component, stored within conventional matrix porosity and fracture porosity. The ratio of free gas to sorbed gas is dependent on pore-size distribution: as pore-diameter increases, the proportion of free gas to sorbed gas increases as less internal surface area is available onto which gas can sorb (Figure 1-1; Beliveau, 1993). Gas saturation often exceeds sorption capacity (Bustin, 2005, Montgomery et al., 2005) underlining the importance of free gas which can comprise over half the TGIP (e.g. Barnett Shale, Fort Worth Basin, TX; Montgomery et al., 2005). Discriminating free gas from sorbed gas is important for quantifying resource potential, reservoir modelling and production forecasting although differentiating the two gas components apart during production is problematic. Predicting well productivity (and well lifespan) also relies upon modeling gas flow rates from reservoir to well-bore. Gas transport through shale is controlled by matrix diffusion, the intensity/interconnectedness of fractures and coarser-grained pernieable facies — properties largely dependent on shale sedimentation and composition. As such, two reservoir components need to be understood to determine the full resource- and production potential of shale gas reservoirs: 1) storage mechanisms; and 2) release 6  100000 - 10000 - 1000 - 100 - 10- ^ 1 ^ 0.1 - 0.01 - 0.001 - 0.0001 - 0.00001 ^ •^ O "Normal porosity" ^•4^ Microporosity Mesoporosity^Macroporosity do 1^1^i^i b^b^b^bm m m m <Ix,^4.^C)^K.) Om O CH, diameter Pore diameter (meters) Figure 1-1. Effect of pore-size diameter on the free gas to sorbed gas ratio (modified from Beliveau, 1993). "Normal porosity" refers to conventional reservoir pore-size distributions. Also shown for reference are CH 4 kinetic diameter (0.38 nm) and pore-size classification of the IUPAC (microporous materials). mechanisms. Both processes will be examined in this thesis. 1.3 SHALE GAS RESERVOIRS AND SEDIMENTOLOGY On a basin scale, reservoir attributes are heterogeneous which presents considerable challenges isolating optimal production zones in thick sequences of shale strata. A clearer understanding of what can be enigmatic palaeoceanographic conditions of black shale formations is required to identify facies with appropriate organic contents, inorganic composition and thickness. Hence shale sedimentological and geochemical data needs to be incorporated into shale gas reservoir evaluation, identifying potential gas-charged zones and intervals with suitable reservoir access (i.e. permeability). In doing so, the environmental conditions affecting organic and element sequestration during black shale formation can be investigated. 1.4 THESIS OBJECTIVES In this study, Devonian-Mississippian (D—M; includes Besa River, Muskwa, Fort Simpson, Golata and Mattson formations) and Jurassic shales (Gordondale Member) are used to elucidate how heterogeneity in shale affects gas storage capacity. The following topics are addressed: 1.4.1 Black shale sedimentology and geochemistry •^What are the controls on organic-matter accumulation during D—M shale deposition? 8 • How do major and trace element concentrations reflect the geologic and oceanographic conditions of D—M sediments? 1.4.2 Controls on gas capacities • How do the organics, inorganics and thermal maturity effect pore characteristics of shales, including micro-, meso- and macropore sizes and total pore volumes? • How does pore structure influence gas sorption in organic-lean and organic-rich shales? How pertinent is this data with regards to reservoir modelling and predicting gas capacities? 1.4.3 Shale fabric, pore size distribution and permeability • How does mineralogy, fabric and pore-size distribution affect permeability at reservoir confining pressures? 1.4.4 Shale gas reservoir evaluation • What is the potential TGIP of D—M stratum in northern British Columbia, southeast Yukon and North West Territories? • Which regions provide the best opportunity to explore and produce natural gas economically? • Can digital log data be calibrated to laboratory data to enhance the reservoir exploration model? 1.4.5 Laboratory analyses of shale gas reservoirs • Are current laboratory procedures accurate for calculating high pressure CH4 in shale samples? 9 Devonian—Mississippian strata are deemed to have excellent shale gas potential in British Columbia (BC) and are the primary focus of this research. In northern BC, D—M shales have similar reservoir characteristics to the lower Barnett Shale — a prolific gas producer in the Fort Worth Basin (Texas). For example, both D—M strata and the Barnett Shale have favourable thermal maturities (into the dry gas window; Potter et al., 2003; Jarvie et al., 2007) allowing greater CH4 mobility through tight shale matrices (Zhao et al., 2007). The Newark East Field (Barnett Shale) is the largest gas producing field in Texas (Bach, 2004), ranks second in the US for annual gas production (EIA, 2005) and total mean undiscovered volumes of gas are estimated at 26.2 TCF (Pollastro, 2007). 1.5 STRUCTURE OF THESIS The results of my research are presented as a series of stand alone papers, divided into four main chapters, which address the questions outlined previously. Some overlap of subject matter occurs and although regrettable, is required due to the adoption of the current dissertation format. Chapters (either published, submitted for review or in preparation) are briefly discussed, explaining how each paper contributes to resolving the main shale gas reservoir issues. Chapter 2 investigates the paleoceanographic factors governing organic matter quantity and major/trace element distributions, with reference to Devonian—Mississippian strata in the WCSB (Besa River, Muskwa, Fort Simpson and Golata formations). By utilizing a diverse suite of major and trace elements (including rare earth elements), the validity of preservation vs. production models is assessed. Geochemical analyses also highlight the 10 concentration mechanisms of radioactive elements (U, Th and K) which are important for proxying TOC (Schmoker, 1981). Gamma-ray log models have proven to be a valuable and inexpensive means to quantify TOC content and help locate gas charged zones in shale gas reservoirs (Manger et al., 1991). Chapter 3 examines the influence of shale composition upon pore structure and high pressure CH4 sorption. Samples from Jurassic and D—M strata are used to determine the effects of organic content, organic type and thermal maturation on the ability for marine shales to sorb gas. Chapter 4 investigates the influence of shale/mudrock composition and diagenesis upon pore size distributions and permeability/gas transport properties. In doing so, the significance of effective confining pressure and fabric orientation on directional permeability is examined. Chapter 5 evaluates the shale gas reservoir characteristics of D—M strata in northern British Columbia (Liard Basin region), Yukon and Northwest Territories. Utilizing data gathered from chapters 2 and 3, total gas capacities are estimated and regions of exploration interest are delineated. Chapter 6 considers the analytical procedure for measuring high pressure CH 4 capacities of microporous shales. Recent research has shown negative calculated CH4 sorption isotherms for many types of shale (Ross, 2004), most commonly with organic- lean shales in which sorption is low (compared to TOC-rich shales). The calculation of 11 negative sorption highlights fundamental problems with the mass balance calculations used. 12 1.6 REFERENCES Allan, J., and S. Creaney. 1991. Oil families of the Western Canadian basin. Bulletin of Canadian Petroleum Geology, v. 39, p. 107-122. Beliveau, D. 1993. "Honey I shrunk the pores!" Journal of Canadian Petroleum Technology, v. 32, p. 15-17. Bolton, A.J., Maltman, A.J. and Fisher, Q. 2000. Anisotropic permeability and bimodal pore-size distributions of fine-grained marine sediments. Marine and Petroleum Geology, v. 17, p. 657-672. Brunauer, S., Emmet, P.H. and Teller, E. 1938. Adsorption of gases in multimolecular layers. Journal of the American Chemical Society, v. 60, p. 309. Bustin, R.M. 2007. Effect of coal composition and fabric on coalbed methane reservoir characteristics. European Coal Geology, 3 rd European Coal Conference, 1997, p. 69— 90. Bustin, R.M. 2005. Gas Shale Tapped For Big Play. AAPG Explorer, February. Bustin, R.M. and Clarkson, C.R. 1998. Geological controls on coalbed methane reservoir capacity and gas content. International Journal of Coal Geology, v. 38, p. 3— 26. 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, v. 70, p. 223-239. Cheng, A.L. and Huang, W.L. 2004. Selective adsorption of hydrocarbon gases on clays and organic matter. Organic Geochemistry, v. 35, p. 413-423. 13 Chun Lu, X., Li, F-C. and Watson, A.T. 1995. Adsorption measurements in Devonian shales. Fuel, v. 74, p. 599-603. Clarkson, C.R. and Bustin, R.M. 1996. Variation of micropore capacity and size distribution with composition in bituminous coal of the Western Canadian Sedimentary Basin. Fuel, v. 75, p. 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, v. 78, p. 1333-1344. Crosdale, P.J., Beamish, B.B. and Valix, M. 1998. Coalbed methane sorption related to coal composition. International Journal of Coal Geology, v. 35, p. 147-158. EIA (Energy Information Administration). 2005. Annual energy review 2004: U.S. Department of Energy, Energy Information Administration report DOE/EIA-0384 (2004), August 2005, p. 435: http://www.eia.doe.gov/oiaf/aer. Faiz, M.M., Saghafi, A., Barclay, S.A., Stalker, L., Sherwood, N.R. and Whitford, D.J. 2007. Evaluating geological sequestration of CO2 in bituminous coals: the southern Sydney Basin as a natural analogue. International Journal of Greenhouse Gas Control, v.1, p. 223-235. Gregg, S.J. and Sing, K.S.W. 1982. Adsorption surface area and porosity. New York, Academic press. Hunt, J.M. 1995. Petroleum Geology and Geochemistry. W.H. Freeman and Company, New York. Jarvie, D.M., Hill, R.J., Ruble, T.E. and Pollastro, R.M. 2007. Unconventional shale gas systems: The Mississippian Barnett Shale of north-central Texas as one model for 14 thermogenic shale-gas assessment. The American Association of Petroleum Geologists Bulletin, v. 91, p. 475-499. Joubert, J.I., Grein, C.T. and Bienstock, D. 1974. Effect of moisture on the methane capacity of American Coals. Fuel, v. 53, p. 186-191. Kuuskraa, V.A., Wicks, D.E., and Thurber, J.L. 1992. Geologic and Reservoir Mechanisms Controlling Gas Recovery From the Antrim Shale. Society of Petroleum Engineers, SPE24883, p. 209-224. Lamberson, M.N. & Bustin, R.M. 1993. Coalbed Methane Characteristics of Gates Formation Coals, Northeastern British Columbia: Effect of Maceral Composition. The American Association of Petroleum Geologists, v. 77, p. 2062-2076. Langmuir, I. 1918. The adsorption of gases on plane surfaces of glass, mica and platinum: Journal of the American Chemical Society, v. 40, p. 1403-1461. 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, v. 40, p. 309-325. Manger, K.C., Oliver, S.J.P., Curtis, J.B., and Scheper, R.J. 1991. Geologic Influences on the Location and Production of Antrim Shale Gas, Michigan Basin. Society of Petroleum Engineers, SPE 21854, p. 511-519. 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 multi-trillion cubic foot potential. The American Association of Petroleum Geologists Bulletin, v. 89, p. 155-175. 15 Pollastro, R.M. 2007. Total petroleum system assessment of undiscovered resources in the giant Barnett Shale continuous (unconventional) gas accumulation, Fort Worth Basin, Texas. The American Association of Petroleum Geologists Bulletin, v. 91, p. 551-578. Potter, J., F. Goodarzi, D.W. Morrow, B.C. Richards, and L.R. Snowdon. 2003. Organic petrology, thermal maturity and Rock-Eval/TOC data for upper Palaeozoic to Upper Cretaceous strata from wells near Liard River, northeast British Columbia. Geological Survey of Canada Open File Report 1751. Rach, N.M. 2004. Drilling expands in Texas' largest gas field. Oil and Gas Journal, v. 102, p. 45-50. Ramos, S. 2004. The effect of shale composition on the gas sorption potential of organic-rich mudrocks in the Western Canadian Sedimentary Basin. MSc thesis, unpublished, p. 140-141. Ross, D.J.K. 2004. Sedimentology, geochemistry and shale gas potential of the Early Jurassic Gordondale Member, northeastern British Columbia. MSc thesis, unpublished. Ross, D.J.K. and Bustin, R.M. 2007. Shale Gas Potential of the Lower Jurassic Gordondale Member, Northeastern British Columbia, Canada. Bulletin of Canadian Petroleum Geology, v. 55, p. 51-75. Schmoker, J.W. 1980. Determination of Organic-Matter Content of Appalachian Devonian Shales from Gamma Ray Logs. The American Association of Petroleum Geologists Bulletin, v. 64, p. 2156-2165. Unsworth, J.F., Fowler, C.S. and Jones, L.F. 1989. Moisture in coal: 2. Maceral effects on pore structure. Fuel, v. 68, p. 18 — 26. 16 Van Oort, E., Hale, A.H., Mody, F.K. and Roy, S. 1994. Critical parameters in modeling the chemical aspects of borehole stability in shales and in designing improved water-based shale drilling fluids. Proceedings of the SPE 69 th Annual Technical Conference and Exhibition, paper SPE 28309, New Orleans, LA, 25-28 th September, 2004. Xu, T., Tang, C.A., Yang, T.H., Zhu, W.C. and Liu, J. 2006. Numerical investigation of coal and gas outbursts in underground collieries. International Journal of Rock Mechanics and Mining Sciences, v. 43, p. 905-919. Warlick, D. 2006. Gas shale and CBM development in North America: Oil and Gas Financial Journal, v. 3, Issue 11, p. 1-5. Zhao, H., Givens, N.B. and Curtis, B. 2007. Thelma' maturity of the Barnett Shale deteiuiined from well-log analysis. The American Association of Petroleum Geologists Bulletin, v. 91, p. 535-549. 17 CHAPTER 2 CONTROLS OF ORGANIC CONTENT, MAJOR ELEMENT AND TRACE METAL CONCENTRATIONS IN DEVONIAN- MISSISSIPPIAN STRATA, WESTERN CANADIAN SEDIMENTARY BASIN: IMPLICATIONS ON THE ROLE OF ANOXIA 18 CHAPTER 2 Controls of organic content, major element and trace metal concentrations in Devonian—Mississippian strata, Western Canadian Sedimentary Basin: implications on the role of anoxia * 2.1 INTRODUCTION The genesis of organic-rich shales and mudrocks is a continuing matter of debate, stemming from the first use of recent sedimentary environments as analogues for ancient organic-rich strata (Pompeckj, 1901). Considerable research has focused on the role of bottom-water oxygen levels and its effect on organic matter concentrations. Retention of organic matter in marine sediments has been attributed to one of two models in most black shale studies: preservation of organic carbon through reducing conditions (Demaison and Moore, 1980; Tyson, 1987; Wignall and Newton, 2001; Meyers et al., 2006) and heightened productivity associated with upwelling systems (Parrish, 1982; Pederson and Calvert, 1990; Calvert and Pederson, 1992; Caplan and Bustin, 1998). Multiple factors can control organic carbon accumulations, arising from a complex interplay of various palaeoceanographic conditions that include: (1) a combination of both anoxia and productivity (Rimmer et al., 2004); (2) anoxia, sediment dilution and low A version of this chapter has been submitted for publication. Ross, D.J.K. and Bustin, R.M. Investigating the use of sedimentary geochemical proxies for paleoenvironments of thermally mature Devonian—Mississippian strata, Western Canadian Sedimentary Basin. Chemical Geology, in review. 19 to moderate productivity (Tyson, 1996; Tribovillard et al., 2001, Tyson, 2004; Cobelo- Garcia et al., 2004); (3) clay surface area and organic matter adsorption (Keil et al., 1994; Salmon et al., 2000; Mackin and Bustin, 2002); (4) efficient organic carbon flux to the sea-floor (Grimm et al., 1997); (5) biogenic activity (Borchers et al., 2005); (6) hydrothermal input (Lipinski et al., 2003); (7) diagenesis (Morford et al., 2005); (8) mass extinctions (Kato et al., 2002); (9) provenance/tectonic setting (Di Leo et al., 2002); and 10) climate (Meyers, 2006). Studies by Tyson and Pearson (1991), Schieber (1999), Murphy et al. (2000), Sageman et al. (2003) and Tyson (2007) argue organic matter accumulations using anoxic and productivity theories alone can be simplistic, and emphasize the importance of multi-disciplinary approaches to identify processes which are not necessarily mutually exclusive. Inorganic geochemistry has proven useful in explaining the diverse, often enigmatic depositional processes of black shales (for examples see Brumsack, 2006 and references therein). The geochemical signature provides important information on fine-grained sediment deposition and organic carbon accumulation, tracers for crustal evolution and insight as to the composition of exposed crust as sedimentary mass balance calculations are largely controlled by shale/mudrocks data (Taylor and McLennan, 1985). Elemental groups including Ti-group (Ti, Zr and Hf), Al-group (Al, Ga) and rare earth elements (REE; e.g. La, Y and Sc) remain in the ocean for shorter periods of time than typical ocean-mixing cycles (Taylor and McLennan, 1985). Hence quantification of these elements may provide robust evidence regarding the sediment source (Alvarez and Roser, 2007). 20 Under anoxic oceanographic conditions, the flux and transfer rates of trace metals (TM) are high, resulting in significant drawdown of TM concentrations in seawater (Morford and Emerson, 1999; Ganeshram et al., 1999; Nijenhuis et al., 1999; Morford et al., 2001; Boning et al., 2004; Borchers et al., 2005). Chemostratigraphic variations are a consequence of efficient organo-metallic complexation or precipitation of authigenic mineral phases (Morford and Emerson, 1999). As such, organic-rich sediments are often enriched in redox-sensitive and stable sulphide-forming metals (Warning and Brumsack, 2000; Arnaboldi and Meyers, 2003; Brumsack, 2006), being an important 'trap' for TM under reduced oxygenated conditions. Modern analogues to black shale formation are scarce however as permanent benthic anoxia only occurs in 0.3% of the total sea-floor (Bertine and Turekian, 1973). One of the few examples of anoxic/euxinic basins is the Black Sea (Lyons, 1997; Wilkin and Arthur, 2001; Wijsman et al., 2001) which accounts for almost two thirds of modem anoxic seafloor (Algeo, 2004). The Black Sea basin is typically quoted as exhibiting the conditions necessary for black shale formation (Arthur and Sageman, 1994) although it has been deemed an "extreme" analog for black shales (Tyson, 2005). Sediment transfer and sequestration of TM into sediments is also dependent on conditions of the overlying water column. Quantity and diversity of TM bears relation to sea-water concentrations (Algeo, 2004) sourced from aeolian and/or fluvial origins (Goldschmidt, 1954; Brumsack 2006). Due to the interrelated mechanisms through which trace elements are concentrated in fine-grained sediments (bio-concentration, detrital-terrigenous input and diagenetic enrichment; Brumsack, 2006), the source and mediation of trace metals are difficult to differentiate (Stow et al., 2001). Consequently, geochemical investigations of organic- 21 rich strata also require an understanding of major element (ME) distributions, used as proxies for background sedimentary influences (terrigenous/detrital input) highlighting TM enrichments or excess contents (Brumsack, 2006). In this study, organic and inorganic geochemical data for Devonian—Mississippian strata from the northwestern region of the Western Canadian Sedimentary Basin (WCSB; Figure 2-1) is presented. Organic-rich shales and mudstones from the Besa River and Muskwa formations, organic-lean shales of the Fort Simpson Formation and silty mudstones of the Golata Formation are investigated geochemically (Figures 2-2 and 2-3). Our purpose is to utilize a broad suite of ME and TM to provide insight to paleoceanographic conditions responsible for organic carbon accumulations of these important petroleum source rocks and shale gas reservoirs in the WCSB (Allan and Creaney, 1991; Ross and Bustin, in press). We also contribute a wide-range of TM (e.g. large ion lithophile TM, high field strength TM and low crustal abundance TM data) to the geochemical data set of black shales which are lacking in the current literature. 2.2 GEOLOGIC SETTING The Late Devonian strata in northern British Columbia (BC), south-eastern Yukon (YK) and south-western Northwest Territories (NWT) consists mainly of shales, mudstones and carbonates (Figure 2-3; Ziegler, 1967). Besa River shales and mudrocks in northern BC were defined by Kidd (1962, 1964) as thick black shale sequences lying between Mississippian cherry limestones and Devonian carbonates. Subsequent stratigraphic analyses argue that Besa River shales represent continuous deposition in a 22 Core locations ^ Lower Besa River • Upper Besa River 0 Muskwa A Fort Simpson X Golata Bovie Fault Eastern edge of main Laramide Thrusting Provincial border Figure 2-1. Map of northern British Columbia showing core locations and the major depo-centre of the Liard Basin (shaded area; see Section 2 for discussion). Provincial key: BC = British Columbia; YK = Yukon; NWT = Northwest Territories. The Liard Basin, which contains up to 5000 m of Palaeozoic and Mesozoic strata, is bounded by the Bovie Fault structure to the east and the Laramide deformation front to the west. 23 .C1- ... PERIOD EPOCH (...) 0 N 0 W __I <„ LL cn z 2 0.) :4— C 0 (....)U <2 c a) u) (u 1:303 c 0.., c 03 a ^ _ - -. 03 ---. Mattson 5 2 -(1'_, --I-Zrophet u)A" b,..,.. (,)a. cs tt$..s 4^ AIIIIIIIh.^co Uppe(..... X C CI3•—• C 0 a a) CD —J Trout River MuskwaI 1^ Kakiska Red Knife Besa River^ Jean Marie Memb r Fort^>,^Twin Falls Middle ^Simpson Hay River Otter Park A ,_(1)Iv "0 ...- Horn River^Presq.^Watt Mountain/Sulfur Point Lower^ Klua Keg River /^Nahinni Nahinni^Upper Chinchaga I Headless 71----;--17^/^11P41111111111111111111011 Manetoe . Funeral^/ Road^.^ ..- •^i• River^1 / ^, ^ I^I Landry 1^1 ^I ^I Lower Chinchaga >. CD W Mirage Point La Loche I^I ,^.1 Arnica Sombre Delorme Figure 2-2. Devonian stratigraphy in the Western Canadian Sedimentary Basin (modified from Gal and Jones, 2003). 24 Figure 2-3. Core photographs of Devonian—Mississippian strata (centimetre scale bars as shown). A) lower Besa River Formation ; B) upper Besa River Formation; C) Muskwa Formation (upper left pyrite-filled fractures; lower left: pyritized carbonaceous material; lower right: light grey interbeds of carbonate); D) light grey shales of the Fort Simpson Formation; E) silty mudrocks of the Golata Formation. 25 sediment-starved deep water setting, through a period between Givetian and Chesterian (Pelzer, 1966). Ross and Bustin (in review) subdivided the Besa River Formation into three informal units based on gamma-ray log variability: 1) a lower black mudrock member; 2) a middle shale member and; 3) an upper black shale member, of which the lower and upper Besa River members are sampled and examined in this study. Besa River strata are part of an anomalously thick upper Palaeozoic fill which defines the Liard Basin in northern BC, Northwest Territories and the Yukon (Figure 2-1; Gabrielse, 1967). The basin covers a total area of approximately 2.5 million hectares with up to 5000 m of Palaeozoic and Mesozoic strata (Walsh et al., 2005). The eastern boundary of the Liard Basin is delineated by the Bovie Fault system and to the west by the Laramide deformation front (Monahan, 2000). The Golata Formation overlies the upper black shale member of the Besa River Formation in parts of the basin, deposited during major late Visèan regression-transgressions (Richards et al., 1994). Eastern lateral equivalents of the lower Besa River member include highly radioactive shales of the Frasnian Muskwa Formation, interpreted to record an abrupt sea-level rise or transgression across the WCSB (Williams, 1983 and references therein; Weissenberger and Potma, 2001). Conformably overlying the Muskwa Formation are Fort Simpson shales which represent the lateral equivalents to the MS member (Besa River Formation). 26 2.3 SAMPLES AND METHODS Fifty-one samples were collected from various drill cores in northern BC (Figure 2-1). Powdered shale samples of Devonian—Mississippian strata were analyzed for total carbon (TC) and total nitrogen (TN) using a Carlo Erba® NA-1500 Analyzer. Inorganic carbon (IC) concentration values were generated from a CM5014 CO 2 coulometer with a precision of 2%. Fifteen to twenty-five milligrams of ground sample were weighed and reacted with HC1. Total organic carbon (TOC) values were determined by subtracting total inorganic carbon from total carbon values (TOC = TC-TIC). X-ray fluorescence spectrometry was used to determine the concentration of selected major elements (Al, Ca, Fe, K, Mg, Mn, Na, P, Si and Ti). Precision of results are ±3% for all major elements except Na which is ±7%. Measurements of trace elements (Ag, As, Ba, Be, Bi, Cd, Ce, Co, Cr, Cs, Cu, Ga, Ge, Hf, In, La, Li, Mo, Na, Nb, Ni, Pb, Rb, Re, Sb, Se, Sn, Sr, Ta, Te, Th, Ti, U, V, W, Y, Zn, Zr) and S total were carried out with an element inductively coupled plasma mass spectrometry (ICP-MS). Analytical precision is ±7% for trace elements except for Ag which is 18%. Prior to analysis, samples were prepared using a four acid (HF, HNO3, HC1O4, HC1) 'near total' digestion. The variability of ME and TM are examined as absolute concentrations and by normalization to Al since Al is limited to the detrital aluminosilicate component in near- shore environments (Calvert, 1976), enabling elemental concentrations from non- aluminosilicate sources (e.g. biogenic dilution of silica and carbonates) to be investigated. Element concentrations are compared to that of average shales (AS; 27 Wedepohl, 1971) and element enrichment factors (EFelement) were determined using the formula: EFelement = (eleMerit/A0sample I (eleMerit/ADaverage shale^(1) Elements are described as "enriched" when EFelement >3, and "depleted" when EFelement <0.5. If EFelement for all units range between 0.5 and 3, elements are discussed as relative differences within the Devonian—Mississippian sample suite (e.g. elements with low crustal abundance). A summary of the geochemical parameters of Devonian— Mississippian sediments is given in Tables 2.1-2.6, including average TOC and Stotal, ME and TE concentrations and EFs compared to AS (Table 2-6). 2.4 RESULTS AND DISCUSSION 2.4.1 Total organic contents, TOC/TN ratios and Stotal Total organic carbon (TOC) contents average 0.26 wt% for Fort Simpson sediments, 2.4 wt% for Muskwa sediments and 2.8 wt% for Golata sediments. The lower and upper Besa River sediments have TOC averaging 2.9 wt% and 3.2 wt% respectively. Muskwa, Besa River and Golata sediments are enriched with organic carbon relative to average shale (Figure 2-4), with EFs in the order of Muskwa (10.5) <upper Besa River (11.4) <Golata (16.8) <lower Besa River (21.7; Figure 2-4). 28 Major Oxides Sample name TOC IC 6,,,,,. TN TOC/TN A40, Ca0 FeO K,0 Mg0 NaP PP, SiOs TiCI, Excess S10 (wt%) Iwt%) (%) (%) M./ (%) rid (%) (%) (%) (%) f%) (%) (%) Muskwa MU1745-1 1.9 2.0 2.6 0.10 19.3 7.5 6.4 3.3 1.7 1.5 0.38 0.08 67.9 044 44.5 MU1745-2 1.9 18 3.6 0.10 19.3 14.4 5.8 5.0 3.6 1.8 0.39 0.48 58.4 0.67 13.6 MU1745-3 2.3 1.1 4.5 0.17 13.7 13.5 5.8 6.2 3.2 1.6 0.42 0.22 54.9 0.62 12.9 MU1745-4 28 2.1 4.3 0.15 13.1 13.4 5.0 5.5 3.4 1.4 0.19 0.49 57.6 0.74 16.1 MU414-1 3.7 0.07 1.4 829 12.9 9.9 0.55 2.7 1.9 0.90 0.52 0.08 73.5 0.42 42.7 MU414-2 3.6 0.02 1.8 0.26 14.2 11.0 0.33 2.8 2.3 0.96 0.45 0.10 50.5 0.46 16.4 MU414-3 2.5 0.95 4.4 0.22 11.4 13.9 1.3 7.1 2.8 1.4 0.76 0.31 60.9 0.67 17.8 MU414-4 1.4 2.5 1.7 0.20 6.9 14.2 8.8 4.1 3.0 2.6 084 0.10 52.8 0.58 8.5 MU714-1 3.3 0.13 1.7 0.15 21.8 1.7 47.9 1.9 0.25 1.2 0.26 0.03 7.9 0.08 2.7 MU714-2 2.8 0.07 1.7 0.13 21.4 6.1 0.27 2.2 1.4 0.55 0.39 0.06 69.8 0.22 50.9 MU714-3 1.6 4.7 3.4 0.10 15.5 72 16.4 4.2 1.6 5.6 0.52 0.10 36.6 0.44 14.3 MU1416-1 2.1 0.79 2.2 0.16 13.5 17.5 0.78 3.8 3.9 1.6 0.56 0.09 64.1 0.75 9.8 MU1416-3 2.1 0.39 2.2 0.16 12.9 16.2 1.7 4.1 3.7 2.0 0.57 0.10 61.3 0.77 11.1 MU1416-7 2.0 0.04 2.4 0.15 13.4 12.7 0.57 3.7 3.0 1.2 0.50 0.09 68.6 0.48 29.2 Lower Besa River LBR32S-1 2.0 0.25 2.3 0.10 20.7 5.7 0.77 3.74 1.3 0.73 0.19 0.05 82.4 0.25 64.8 L8R325-3 2.0 0.22 1.1 0.10 19.7 5.1 1.3 2.35 1.1 0.96 0.19 0.06 85.9 0.24 70.1 L8R325-5 2.1 0.06 1.7 0.11 19.1 9.6 0.30 2.53 2.2 0.67 0.20 0.08 78.9 0.43 49.1 LBR2563-1 4.8 0.35 1.2 0.13 38.0 5.9 1.2 1.58 1.5 0.72 0.05 0.09 80.7 0.28 62.4 L8R2563-3 4.4 0.44 1.7 0.16 26.8 6.3 1.2 280 1.6 0.61 0.06 0.08 80.2 0.27 60.7 LBR2563-5 2.8 0.14 1.7 0.11 25.4 6.6 0.53 1.97 1.7 0.68 0.06 0.08 82.4 0.28 61.8 1BR2563-7 2.5 0.21 1.4 0.21 12.0 7.8 0.80 2.15 2.1 0.93 0.01 0.10 79.4 0.37 55.0 Upper Besa River UBR-C15-1331-1 1.4 0.22 1.3 022 6.3 9.8 1.2 2.38 1.5 0.68 0.32 0.26 78.3 0.71 47.6 UBR-C15-1331-5 4.0 1.03 1.6 0.38 10.4 16.9 1.7 2.73 2.4 0.96 0.37 0.42 60.7 0.92 8.3 UBR-C15-1331-7 2.2 1.03 2.2 0.26 8.5 11.9 4.3 3.64 1.7 1.1 0.42 0.06 66.0 0.66 28.9 UBR1331-1 2.0 0.02 2.1 0.37 5.3 18.7 0.73 3.72 2.1 0.62 0.77 0.08 63.4 0.82 5.1 UBR13313 2.7 0.01 2.2 0.40 6.8 18.5 0.77 4.04 2.1 0.70 0.66 0.08 62.4 0.81 4.7 UBR1331-4 4.0 0.00 34 0.31 13.0 23.0 1.2 9.62 1.7 1.3 0.99 0.25 47.3 0.89 - UBR1331-8 5.7 0.38 4.5 0.26 22.0 19.0 2.1 13.82 1.2 1.7 0.77 0.81 43.3 0.74 - UBR1331-11 3.8 0.01 4.4 0.31 12.4 22.8 0.81 7.88 1.6 0.82 0.71 0.46 48.0 1.04 - Golata GA442-1 3.4 0.22 0.51 0.08 45.9 8.8 0.19 3.22 1.2 0.60 0.34 0.09 75.9 1.25 48.6 GA442-2 3.0 0.29 0.45 0.09 33.4 12.8 0.32 3.80 1.9 0.90 0.40 0.13 71.2 1.24 31.5 GA442-3 2.0 0.01 0.38 0.07 30.0 12.1 0.25 2.92 18 0.78 0.37 0.12 74.1 1.20 366 Fort Simpson FS129.1 0.19 0.23 0.03 0.08 2.5 15.9 2.1 6.92 2.5 2.1 0.90 0.18 62.6 0.91 13.0 FS129.5 0.20 0.32 0.05 0.09 2.2 20.1 1.0 9.90 3.1 2.7 060 0.18 55.9 0.92 - FS129-13 0.24 0.19 0.65 0.11 2.2 20.2 0.74 7.48 3.3 2.4 0.62 0.11 55.4 0.85 FS947-1 0.14 1.13 2.49 0.12 1.2 19.5 3.8 5.91 4.7 2.4 0.59 0.11 53.2 0.81 - F59473 0.00 3.26 1.23 0.09 0.0 12.9 17.0 4.47 2.9 2.8 0.60 0.08 404 0.58 0.3 FS1238-1 0.25 0.30 0.75 0.11 2.4 206 0.95 7.73 3.6 2.6 0.56 0.14 566 0.86 - FS1238-12 0.32 0.32 2.15 0.12 2.7 17.8 2.8 5.11 3.5 2.8 0.40 0.11 56.7 0.75 1.4 F51416-1 0.29 047 0.09 0.11 2.7 19.5 1.7 8.64 32 2.6 0.60 0.15 56.6 0.91 - FS1416-5 0.16 0.33 0.06 0.12 1.4 19.2 1.8 9.18 3.1 2.6 0.60 0.17 55.5 0.90 - FS1528.1 0.33 0.64 0.83 0.11 2.9 19.9 1.7 2.53 5.4 1.6 0.14 0.18 61.8 0.95 F55245-1 0.31 082 0.05 0.10 3.2 192 0.40 6.64 3.3 2.3 0.82 0.16 61.0 0.95 1.3 FS5245-3 0.23 0.11 0.02 0.08 2.9 18.4 0.45 7.52 3.1 2.3 0.81 0.17 61.0 0.98 3.8 FS7194-2 0.21 0.08 1.28 0.12 1.7 22.3 0.52 2.76 6.1 1.3 0.23 0.14 62.0 0.97 - FS7194-4 0.48 0.21 1.4 0.11 4.5 20.5 0.50 2.82 5.8 1.3 0.03 0.13 62.4 0.89 - FS12140-1 0.34 0.47 0.04 0.08 4.4 14.0 5.9 6.51 2.1 1.8 0.87 0.19 60.4 0.83 16.9 FS12140-6 0.31 0.15 0.04 0.10 3.2 19.8 0.54 7.59 3.3 2.4 0.68 0.17 59.1 0.98 - F813703-2 0.38 0.01 0.06 0.39 1.0 20.1 0.68 7.67 34 2.5 0.75 0.17 59.9 0.97 - FS13703-4 026 1.03 0.08 0.08 3.2 162 5.96 6/3 2.7 2.1 878 0.17 56.4 081 5.9 FS13703-6 0.30 0.10 0.06 0.10 38 19.6 0.68 7.47 3.3 2.4 0.70 0.17 59.2 0.95 - Table 2-1. Major oxides (as %) with total organic carbon (TOC; as wt%), inorganic carbon (IC; as wt%), sulphur (S; as %) and total nitrogen (TN; as %) of Devonian-Mississippian sediments. (Key: MU = Muskwa; LBR = lower Besa River; UBR = Upper Besa River; GA = Golata; FS = Fort Simpson). *See text for excess silica calculation - dashes represent sediments with no calculated excess silica. Total organic carbon and IC data from Chapter 5. 29 Major Elements Sample name Al Ca Fe K Mg Na Si Ti Muskwa MU1745-1 4.0 2.6 2.3 1.4 0.93 0.28 0.04 31.7 0.26 MU1745-2 7.6 2.3 3.5 3.0 1.1 0.29 0.21 27.3 0.40 MU1745-3 7.1 2.3 4.3 2.7 1.0 0.31 0.10 25.6 0.37 MU1745-4 7.1 2.0 3.9 2.8 0.8 0.14 0.21 26.9 0.44 MU414-1 5.2 0.2 1.9 1.6 0.54 0.38 0.04 34.4 0.25 MU414-2 5.8 0.1 1.9 1.9 0.58 0.34 0.04 23.6 0.28 MU414-3 7.3 0.5 5.0 2.3 0.86 0.56 0.14 28.4 0.40 MU414-4 7.5 3.5 2.9 2.5 1.6 0.70 0.04 24.7 0.35 MU714-1 0.9 19.2 1.3 0.21 0.7 0.19 0.01 3.7 0.05 MU714-2 3.2 0.1 1.5 1.2 0.33 0.29 0.02 32.6 0.13 MU714-3 3.8 6.6 2.9 1.3 3.4 0.38 0.04 17.1 0.26 MU1416-1 9.2 0.3 2.7 3.2 1.0 0.41 0.04 30.0 0.45 MU1416-3 8.5 0.7 2.8 3.1 1.2 0.42 0.04 28.7 0.46 MU1416-7 6.7 0.2 2.6 2.5 0.72 0.37 0.04 32.1 0.29 Lower Besa River LBR325-1 3.0 0.5 2.6 1.1 0.44 0.14 0.02 38.5 0.15 LBR325-3 2.7 1.0 1.6 1.0 0.6 0.14 0.03 40.1 0.14 LBR325-5 5.1 0.2 1.8 1.9 0.40 0.15 0.04 36.9 0.26 LBR2563-1 3.1 0.8 1.1 1.3 0.44 0.03 0.04 37.7 0.17 LBR2563-3 3.3 0.9 1.4 1.3 0.37 0.05 0.03 37.5 0.16 LBR2563-5 3.5 0.4 1.4 1.4 0.41 0.04 0.04 38.5 0.17 LBR2563-7 4.2 0.6 1.5 1.7 0.56 0.01 0.04 37.1 0.22 Upper Besa River UBR-C15-1331-1 5.2 0.9 1.7 1.3 0.41 0.24 0.11 36.6 0.43 UBR-C15-1331-5 8.9 1.2 1.9 2.0 0.58 0.28 0.18 28.4 0.55 UBR-C15-1331-7 6.3 3.1 2.5 1.4 0.68 0.31 0.03 30.9 0.40 UBR1331-1 9.9 0.5 2.6 1.7 0.38 0.57 0.04 29.6 0.49 UBR1331-3 9.8 0.6 2.8 1.8 0.42 0.49 0.03 29.2 0.49 UBR1331-4 12.2 0.8 6.7 1.4 0.80 0.73 0.11 22.1 0.53 UBR1331-8 10.1 1.5 9.7 1.0 1.0 0.57 0.36 20.2 0.44 UBR1331-11 12.1 0.6 5.5 1.3 0.49 0.53 0.20 22.4 0.63 Golata GA442-1 4.6 0.13 2.3 1.0 0.36 0.25 0.04 35.5 0.75 GA442-2 6.8 0.23 2.7 1.5 0.54 0.30 0.06 33.3 0.74 GA442-3 6.4 0.18 2.0 1.5 0.47 0.28 0.05 34.7 0.72 Fort Simpson FS129-1 8.5 1.5 4.7 1.9 1.2 0.68 0.07 29.2 0.48 FS129-5 9.8 0.7 6.5 2.3 1.4 0.49 0.07 26.1 0.49 FS129-13 10.1 0.5 5.2 2.6 1.4 0.53 0.05 25.9 0.48 FS947-1 10.3 1.5 4.1 3.9 1.5 0.44 0.05 24.9 0.49 FS947-3 9.7 2.4 3.8 3.6 1.7 0.34 0.05 24.4 0.47 FS1238-1 10.9 0.4 5.4 3.0 1.6 0.42 0.06 26.5 0.52 FS1238-12 9.4 1.1 3.6 2.9 1.7 0.30 0.05 26.5 0.45 FS1416-1 10.3 0.7 6.0 2.7 1.6 0.44 0.07 26.5 0.54 FS1416-5 10.2 0.7 6.4 2.6 1.5 0.45 0.08 26.0 0.54 FS1528-1 10.5 0.7 1.8 4.5 0.9 0.11 0.08 28.9 0.57 FS5245-1 10.2 0.2 4.6 2.7 1.4 0.61 0.07 28.5 0.57 FS5245-3 9.7 0.2 5.3 2.5 1.4 0.60 0.07 28.5 0.58 FS7194-2 11.8 0.2 1.9 5.1 0.8 0.17 0.06 29.0 0.58 FS7194-4 10.9 0.2 2.0 4.8 0.8 0.02 0.06 29.2 0.54 FS12140-1 7.4 2.4 4.6 1.8 1.1 0.65 0.08 28.2 0.50 FS12140-6 10.5 0.2 5.3 2.7 1.4 0.50 0.07 27.6 0.59 FS13703-2 10.0 0.5 5.1 2.5 1.4 0.60 0.07 28.0 0.53 FS13703-4 7.9 4.1 3.9 2.0 1.1 0.56 0.07 26.4 0.44 FS13703-6 9.5 0.5 5.2 2.4 1.3 0.58 0.07 27.7 0.51 Table 2-2. Major element concentrations (reported as %). 30 Major elements normalized to Al Sample name TOC/AI Ca/AI Fe/AI K/AI Mg/AI Na/AI P/AI Si/AI Ti/AI Muskwa MU1745-1 0.47 0.64 0.58 0.36 0.23 0.07 0.009 8.0 0.066 MU1745-2 0.25 0.30 0.46 0.39 0.14 0.04 0.028 3.6 0.053 MU1745-3 0.33 0.32 0.61 0.37 0.14 0.04 0.014 3.6 0.052 MU1745-4 0.28 0.29 0.55 0.40 0.12 0.02 0.030 3.8 0.063 MU414-1 0.70 0.04 0.36 0.31 0.10 0.07 0.007 6.5 0.047 MU414-2 0.63 0.02 0.33 0.33 0.10 0.06 0.008 4.1 0.048 MU414-3 0.34 0.07 0.68 0.32 0.12 0.08 0.019 3.9 0.054 MU414-4 0.19 0.47 0.38 0.33 0.21 0.09 0.006 3.3 0.046 MU714-1 0.42 1.73 0.77 0.35 0.88 0.10 0.012 4.5 0.069 MU714-2 0.01 0.15 0.40 0.38 0.14 0.04 0.005 2.4 0.047 MU714-3 0.02 0.25 0.39 0.37 0.18 0.04 0.005 2.5 0.048 MU1416-1 0.23 0.03 0.29 0.35 0.10 0.04 0.004 3.2 0.048 MU1416-3 0.24 0.08 0.33 0.36 0.14 0.05 0.005 3.4 0.054 MU1416-7 0.31 0.03 0.38 0.37 0.11 0.05 0.006 4.8 0.043 Lower Besa River 113R325-1 0.67 0.18 0.87 0.36 0.15 0.05 0.01 12.8 0.05 LBR325-3 0.75 0.36 0.61 0.35 0.22 0.05 0.01 14.9 0.05 LBR325-5 0.41 0.04 0.35 0.37 0.08 0.03 0.01 7.3 0.05 LBR2563-1 1.5 027 0.35 0.40 0.14 0.01 0.013 12.1 0.054 LBR2563-3 1.3 0.27 0.42 0.40 0.11 0.01 0.010 11.3 0.049 LBR2563-5 0.79 0.11 0.39 0.41 0.12 0.01 0.010 11.0 0.048 LBR2563-7 0.60 0.14 0.36 0.41 0.14 0.00 0.010 8.9 0.053 Upper Besa River UBR-C15-1331-1 0.27 0.17 0.32 0.24 0.08 0.05 0.022 7.0 0.082 UBR-C15-1331-5 0.44 0.14 0.21 0.22 0.06 0.03 0.020 3.2 0.062 UBR-C15-1331-7 0.35 0.48 0.40 0.22 0.11 0.05 0.004 4.9 0.063 UBR1331-1 0.20 0.05 0.26 0.18 0.04 0.06 0.004 3.0 0.049 UBR1331-3 0.27 0.06 0.29 0.18 0.04 0.05 0.003 3.0 0.050 UBR1331-4 0.33 0.07 0.55 0.12 0.07 0.06 0.009 1.8 0.044 UBR1331-8 0.56 0.15 0.96 0.10 0.10 0.06 0.035 2.0 0.044 UBR1331-11 0.32 0.05 0.46 0.11 0.04 0.04 0.016 1.9 0.052 Golata GA442-1 0.74 0.03 0.48 0.22 0.08 0.05 0.008 7.6 0.161 GA442-2 0.45 0.03 0.39 0.23 0.08 0.04 0.009 4.9 0.110 GA442-3 0.32 0.03 0.32 0.23 0.07 0.04 0.008 5.4 0.112 Fort Simpson FS129-1 0.02 0.17 0.56 0.23 0.14 0.08 0.009 3.5 0.06 FS129-5 0.02 0.07 0.66 0.24 0.14 0.05 0.007 2.5 0.05 FS129-13 0.02 0.05 0.52 0.25 0.14 0.05 0.005 2.4 0.05 FS947-1 0.00 0.15 0.40 0.38 0.14 0.04 0.005 2.4 0.05 FS947-3 0.86 0.03 0.47 0.37 0.10 0.09 0.008 10.1 0.042 FS1238-1 0.02 0.03 0.50 0.27 0.14 0.04 0.006 2.4 0.047 FS1238-12 0.03 0.12 0.38 0.31 0.18 0.03 0.005 2.8 0.048 FS1416-1 0.03 0.07 0.59 0.26 0.15 0.04 0.006 2.6 0.053 FS1416-5 0.02 0.07 0.63 0.25 0.15 0.04 0.007 2.6 0.053 FS1528-1 0.03 0.06 0.17 0.43 0.09 0.01 0.007 2.7 0.054 FS5245-1 0.03 0.02 0.46 0.27 0.14 0.06 0.007 2.8 0.056 FS5245-3 0.02 0.02 0.54 0.26 0.14 0.06 0.008 2.9 0.060 FS7194-2 0.02 0.02 0.16 0.43 0.07 0.01 0.005 2.5 0.049 FS7194-4 0.04 0.02 0.18 0.44 0.07 0.00 0.005 2.7 0.049 FS12140-1 0.05 0.32 . 0.62 0.24 0.15 0.09 0.011 3.8 0.067 FS12140-6 0.03 0.02 0.51 0.26 0.14 0.05 0.007 2.6 0.056 FS13703-2 0.03 0.05 0.51 0.25 0.14 0.06 0.007 2.6 0.053 FS13703-4 0.04 0.52 0.50 0.26 0.14 0.07 0.009 3.1 0.056 FS13703-6 0.03 0.05 0.54 0.25 0.14 0.06 0.008 2.7 0.054 Table 2-3. Major elements normalized to Al (reported as %). 31 Trace Elements Sample name Ag ppm Ba ppm Be ppm Bi ppm Cd ppm Ce ppm Co ppm Cr ppm Cs ppm Cu ppm Ga ppm Ge ppm Hf ppm La ppm Mn ppm Mo ppm Nb ppm Ni ppm Pb ppm Rb ppm Re ppm Se^Sr ppm ppm Ta ppm Th ppm TI ppm U ppm V ppm Y ppm Zn ppm Zr ppm Muskwa MU1745-1 0.35 290 1.5 0.24 1.24 40.5 14.7 78 4.41 59.5 9.4 0.08 0.90 21.8 156 19.6 5.9 83.4 28.2 72.5 0.016 4 103 0.44 6.1 2.36 6.7 161 12.2 106 30 MU1745-2 0.28 180 2.7 0.38 0.91 55.1 17.6 118 11.5 62.9 17.1 0.13 1.5 29.8 134 24.5 9.6 94.1 22.7 142 0.025 6 119 0.71 9.5 3.13 7.3 183 17.5 87 46.7 MU1745-3 0.49 180 2.8 0.39 2.36 63.8 23.8 118 9.31 84.1 16.0 0.15 1.4 34.5 141 49.3 8.8 157 27.2 132 0.032 9 124 0.64 8.6 4.46 15.4 260 22.7 223 45.6 M1J1745-4 0.45 160 2.7 0.43 3.97 59.3 24.4 120 10.7 98.4 16.8 0.15 1.6 31.1 86 39 10 130 30.1 133 0.049 9 114 0.74 10 4.13 13 239 20.4 252 51.7 MU414-1 0.48 250 2.1 0.16 1.32 55.9 11.6 77 6.21 70.6 12.5 0.11 1.2 35.4 65 63.9 14.2 179 14.8 94.1 0.084 8 120 0.99 6.1 3.62 24.8 634 24.9 167 53.4 MU414-2 0.59 330 3.6 0.25 3.14 65.7 15 99 947 76.2 18.4 0.15 1.3 41.1 77 96.8 9.7 216 17.3 142 0.15 12 139 0.65 8.5 4.52 33.3 1275 31.3 370 43.1 M1J414-3 0.78 100 2.9 0.44 2.67 87.1 35.8 94 7.71 96.8 17.7 0.16 1.6 45.1 132 46.8 10.2 159 38.9 127 0.067 7 158 0.67 10.1 9.22 16.2 197 26.4 276 58.3 MU414-4 0.15 710 2.3 0.21 0.44 60.6 13 86 8.13 52.8 18.1 0.12 1 34.4 297 4.67 8.6 59.2 14.6 137 0.009 3 229 0.61 7.8 1.12 3 129 13.5 76 31.8 MU714-1 0.11 510 0.93 0.03 0.22 14.6 3.3 24 1.16 13.7 2.7 0.07 0.30 11 733 15 1.3 29.6 6.5 19.4 0.014 4 433 0.09 1.3 0,59 5.1 118 24.4 21 8.5 MU714-2 0.26 120 1.3 0.13 0.56 16 9.4 54 3.43 46.2 7.7 0.08 0.60 5 32 42.1 3.2 99.9 12.5 58.9 0.038 4 114 0.23 2.6 3.3 14.7 129 13.2 81 18.4 MU714-3 0.04 40 1.5 0.11 0.61 32.7 9.7 68 3.15 18.8 9.6 0.09 0.90 11.6 353 3.43 6.2 32.2 7.6 67.5 <0.002 4 195 0.46 4.8 0.93 2.7 55 17 57 27.5 MU1416-1 0.16 490 2.9 0.26 0.61 664 17.2 97 11.9 38 21.7 0.12 2.1 36.2 159 27.1 10.6 104 19.4 181 0.026 6 101 0.77 10.4 3.9 10.3 228 21.3 136 66 MU1416-3 0.15 500 2.7 0.26 0.45 67.6 17.9 96 11.7 32.6 20.7 0.12 2 38.4 174 31.5 12 106 17.6 178 0.045 2 104 0.89 10.9 4.16 11.8 188 21.9 110 65.8 MU1416-7 0.38 90 2.5 0.22 0.9 49.1 15.3 102 8.35 66.4 15.9 0.13 1.3 25.9 66 64.3 6.7 133 19.4 125 0.061 5 96.8 0.47 6.7 4.55 20.1 218 21.8 120 43.3 Lower Besa River BRS325-1 0.17 120 1.3 0.08 0.38 26.3 7.6 66 2.48 37.5 7.7 0.09 0.60 13.2 104 20.5 3.6 57.7 9.4 51.2 0.011 4 67.1 0.25 3.3 1.32 5.7 108 11.4 38 17 BRS325-3 0.15 220 1.1 0.09 0.24 28.6 7.6 75 2.21 33.1 6.8 0.09 0.60 14.2 134 27.2 3.4 51.4 7.4 44.9 0.011 4 80.5 0.23 3.1 1.12 8.6 67 11.8 30 17.5 BRS325-5 0.28 80 2.1 0.16 0.32 45.2 14.8 62 4.54 53.5 12.6 0.11 1.0 22.5 67 32.4 6.3 75.2 14.3 88.2 0.017 5 85.4 0.44 5.8 1.91 8.2 152 16.2 34 31.9 LBR2563-1 0.23 340 1.7 0.12 3.44 26 7.6 90 3.76 45.9 9.0 0.09 0.60 18 56 91.5 4.7 140 9.7 61.9 0.042 5 60.6 0.33 3.9 2 13 487 14.8 242 21.2 LBR2563-3 0.28 200 1.8 0.15 2.31 28.6 8.5 82 3.99 57.1 9.9 0.11 0.60 19.4 46 129 5 163 12.8 66 0.039 9 68.5 0.34 4.1 3.32 17 390 18 224 21 LBR2563-5 0.18 190 1.8 0.13 3.78 30.2 8.8 87 4.18 38.4 10.3 0.09 0.60 19.9 55 87.2 5.5 140 9.3 69.5 0.025 6 53.1 0.39 4.4 3 10.8 443 18 412 211 1BR2563-7 0.17 150 1.8 0.12 1.65 23.7 7.2 69 368 32.2 9.1 0.09 0.60 16 44 77.4 4.3 117 10.8 61 0.022 6 49.9 0.31 3.4 2.58 10.4 335 14.1 177 18 Upper Besa River UBR-C15-1331-1 0.84 330 1.4 0.13 0.24 50.3 5.8 261 5.05 32.1 11.6 0.09 0.70 35.4 39 4.32 8.9 54.7 10.4 63.5 0.011 8 88.5 0.65 9.3 0.43 3.8 84 17.7 123 18.7 UBR-C15.1331-5 2.2 510 2.5 0.23 1.38 66.1 10 525 10.4 54.1 20.3 0.16 1.1 47.9 46 14.3 12.2 131 13.8 109 0.047 24 145 0.9 11.3 0.79 7.6 170 32.1 440 31.6 UBR-C15.1331-7 2.4 390 1.5 0.18 1.3 43.5 9.1 237 6.41 37.1 14.9 0.11 1.1 25.6 84 4.34 9.6 72.3 15.8 78.3 0.024 16 136 0.68 8.8 0.59 2.4 144 7.7 207 35.9 UBR1331-1 0.89 450 2.5 0.27 0.36 70 11.1 194 884 32.1 22.6 0.11 0.50 43.2 38 2.39 12.7 72.8 24.7 98.7 0.007 10 165 0.9 12 0.62 1.3 194 6.6 94 15.4 UBR1331-3 1.33 530 2.4 0.28 0.76 59.5 12.4 264 9.21 34.9 22.5 0.12 0.60 40.4 32 4.82 12.1 107 25.8 102 0.014 18 147 0.86 11.4 0.6 1.9 180 7.5 187 18.1 UBR1331-4 0.65 590 2.9 0.45 0.1 75.9 15 173 6.73 30.5 29.0 0.13 0.50 44.1 133 1.99 14.7 96 35.3 72.1 0.008 10 181 1.04 15 0.39 1.7 405 12.6 99 13.1 UBR1331-8 1.0 180 1.9 0.49 0.2 73.3 13.1 173 5.77 35.6 26.7 0.2 0.40 48.8 166 2.43 12.8 101 49.1 56.9 0.009 13 181 0.91 13.8 0.35 2.2 361 30.2 204 12.8 UBR1331.11 1.1 240 2.9 0.5 0.39 85.6 15 185 6.96 39.7 28.5 0.16 0.50 50.1 92 2.1 15.2 102 42.8 71.6 0.007 13 171 1.06 15.4 0.39 2.2 351 30.1 319 14.9 Goleta GA442.1 0.1 200 1.2 0.24 0.07 108 15.2 120 2.46 12.4 11.7 0.09 2.6 44.2 262 1.38 16.7 45 10.4 38.1 0.002 <1 81.3 1.24 13 0.18 2.6 96 14.8 85 76.7 GA442.2 0.09 240 2.0 0.29 0.04 109 15 120 3.89 11.2 14.8 0.11 2.4 45 297 0.71 16.3 54.2 11.4 55.2 0.002 1 92.1 1.2 13.7 0.24 2.5 133 17 56 72.7 GA442-3 0.08 210 1.9 0.28 0.04 106 13.9 114 3.63 10.8 14.2 0.08 2.6 43.3 178 0.69 15.9 47.5 10.6 52.8 0.002 2 85.7 1.18 13.6 0.22 2.6 126 16.1 62 78.6 Table 2-4. Minor elements (reported as ppm). Note: ICPMS detection limit for Re is 0.002 ppm and Se is 1 ppm. Trace Elements Sample name Ag ppm Ba ppm Be ppm Bi ppm Cd ppm Ce ppm Co ppm Cr ppm Cs ppm Cu ppm Ga ppm Ge ppm Hf ppm La ppm Mn ppm Mo ppm Nb ppm Ni ppm Pb ppm Rb ppm Re ppm Se ppm Sr ppm Ta ppm Th ppm TI ppm U ppm V ppm Y ppm Zn ppm Zr ppm Fort Simpson FS129-1 0.08 420 2.5 0.3 0.02 77.9 22.1 101 10.3 48.4 26.5 0.15 2.7 35.7 591 0.18 12.4 63.7 13.5 151 <0.002 <1 159 0.86 12 0.8 2.5 165 21.4 157 84.1 FS129-5 0.11 430 2.8 0.32 0.02 74.7 32.5 102 9.74 21.9 25.5 0.14 2.3 36.2 540 0.39 11.6 64 84.5 158 <0.002 2 148 0.83 11.4 0.85 2.4 166 15.9 114 70 FS129-13 0.08 530 2.5 0.3 0.02 64.3 27.1 110 9.79 35.1 27.2 0.12 2.2 29.2 377 1.35 12 69.9 64.7 146 <0.002 2 137 0.85 10.3 0.94 2.5 186 14.4 119 67 FS947-1 0.01 660 3.0 0.29 0.02 70.3 20.6 85 10.4 21.1 25.9 0.14 1.7 34.2 267 0.71 12.4 56.9 18 162 <0.002 2 153 0.91 10.6 0.88 1.8 130 14.3 56 51.5 FS947.3 0.01 830 1.9 0.19 0.04 60 16 59 6.61 11.6 16.8 0.11 1.4 31.8 630 0.23 8.7 39 12.3 129 <0.002 1 204 0.63 8.3 0.55 1.5 83 16.4 55 45 FS1238-1 0.09 740 2.8 0.31 0.06 64.7 32.2 117 10.3 42.3 27.5 0.13 1.9 28.4 435 0.69 12.3 76.3 23.1 140 0.002 1 129 0.87 9.6 1.09 2.2 208 14.7 142 59.3 FS1238-12 0.06 780 2.8 0.27 0.99 65.1 17.6 82 9.61 42.5 23.7 0.14 1.8 33.2 528 8.5 10.8 79.7 21 146 0.007 3 140 0.77 9.9 1.56 2.8 216 18.8 694 57.9 FS1416-1 0.01 520 2.5 0.31 0.02 61 17.7 114 9.12 56.5 25.8 0.12 1.8 28 804 0.38 13.3 63.9 12.2 126 <0.002 4 149 0.87 9.6 0.74 2 180 16.4 111 58 FS1416-5 0.03 500 2.3 0.27 0.02 75.4 16.6 106 9.45 58.3 24.6 0.15 1.9 34.5 794 0.33 11.7 60.8 11.7 139 <0.002 2 155 0.81 10.6 0.69 2.1 174 19 114 58.6 FS1528-1 0.02 920 2.8 0.33 0.12 81.8 18.4 101 13 28.4 25.3 0,13 1.8 41 219 0.65 12.8 30.8 7.5 181 <0.002 1 122 0.93 11.4 1.48 2.3 211 16.2 85 55.4 FS5245-1 0.05 540 2.3 0.27 0.02 76.4 19.8 106 9.5 79.6 24.8 0.11 3.5 35.7 316 0.23 12.8 64.2 14.8 145 <0.002 11 136 0.9 12.1 0.78 3.1 195 21.4 133 110 FS5245-3 0.04 480 2.2 0.3 0.02 77.2 20 108 9.05 97.4 23.3 0.14 3.4 36 396 0.23 12.2 61.2 8.7 136 <0.002 3 131 0.87 11.8 0.72 2.9 176 21.4 150 105 FS7194-2 0.02 650 2.9 0.31 0.1 78.5 28.4 99 12.6 24.1 27.1 0.15 2.1 40.1 66 0.58 12.4 67.5 34.5 204 <0.002 1 104 0.9 12 1.12 2.3 181 15.6 41 68 FS7194-4 0.02 1130 3.5 0.15 0.54 82.3 17.2 91 11.5 14.9 25.4 0.14 2 43 65 1.11 11.8 31.3 14.8 191 0.002 2 111 0.86 12 1.8 3 183 15.6 362 63.4 FS12140-1 0.05 360 1.5 0.32 0.02 65.8 16 87 6.1 26 17.8 0.13 2.9 29.3 1215 0.6 10.8 46.6 15.8 97.2 0.002 <1 167 0.77 10.2 0.51 2.5 129 29.7 108 87 FS12140-6 0.07 570 2.3 0.19 0.02 73 20.7 110 9.94 60.7 25.0 0.13 3.4 32.5 418 0.27 12.4 64.8 9.8 138 0.002 <1 165 0.88 11.4 0.83 3 202 20.9 166 103 FS13703-2 0.03 500 2.6 0.35 0.03 78.8 22.7 107 9.3 43.1 25.7 0.12 3.2 37.6 395 0.29 12.7 64.8 9.8 151 <0.002 3 181 0.88 12.4 0.78 3 192 21.2 140 103 F513703-4 0.06 400 2.1 0.27 0.02 67.6 18.8 94 7.41 24.9 21.0 0.13 2.8 30.6 1245 0.27 11.2 53.1 17.8 109 <0.002 3 239 0.78 10.2 0.67 2.5 145 25.3 119 90.8 FS13703-6 0.04 560 2.3 0.34 0.05 58.4 21.5 110 8.85 52.3 25.0 0.12 3 25.3 439 0.27 12.1 64.4 18.2 120 <0.002 3 177 0.87 9.9 0.81 2.8 197 18 181 94.6 Table 2-4 cont. Trace elements normalized to Al SAMPLE Ag ppm Ba ppm Be ppm Bi ppm Cd ppm Ce ppm Co ppm Cr ppm Cs ppm Cu ppm Ga ppm Ge ppm Hf ppm La ppm Mn ppm Mo ppm Nb ppm Ni ppm Pb ppm Rb ppm Re ppm Se ppm Sr ppm Ta ppm Th ppm TI ppm U ppm V ppm ppm Muskwa MU1745-1 0.09 70.9 0.36 0.06 0. 30 9.9 3.6 19.1 1.1 14.5 2.3 0.020 0.22 5.3 39.3 4.8 1.4 20.4 6.9 17.7 0.0039 1.0 25.1 0.11 1.5 0.58 13 39.4 3.0 MU1745-2 0.04 24.4 0.36 0.05 0.12 7.5 2.4 16.0 1.6 8.5 2.3 0.018 0.20 4.0 17.6 3.3 1.3 12.7 3.1 19.2 0.0034 031 16.1 0.10 1.3 0.42 13 24.8 2.4 MU1745-3 0.07 26.4 0.41 0.06 0.35 9.4 3.5 17.3 t4 12.3 2.3 0.022 0.21 5.1 19.8 7.2 1.3 22.9 4.0 19.3 0.0047 1.3 18.2 0.09 1.3 0.65 2.3 38.1 3.3 MU1745-4 0.07 23.3 0.40 0.06 0.58 8.6 3.6 17.5 1.6 14.3 2.4 0.022 0.23 4.5 12.2 5.7 1.5 18.9 4.4 19.3 0.0071 1.3 16.5 0.11 1.5 0.60 1.9 34.8 3.0 MU414-1 0.10 51.2 0.43 0.03 0.27 11.5 2.4 15.8 1.3 14.5 2.6 0.023 0.25 7.3 12.4 13.1 2.9 36.6 3.0 19.3 0.0172 1.6 24.5 0.20 1.3 0.74 5.1 129.9 5.1 MU414-2 0.08 47.5 0.51 0.04 0.45 9.5 2.2 14.2 1.4 11.0 2.6 0.022 0.19 5.9 13.3 13.9 1.4 31.1 2.5 20.4 0.0216 1.7 20.0 0.09 1.2 0.65 4.8 183.5 4.5 MU414-3 0.11 14.4 0.41 0.06 0.38 12.6 5.2 13.5 1.1 13.9 2.6 0.023 0.23 6.5 18.0 6.7 1.5 22.8 5.6 18.2 0.0097 1.0 22.8 0.10 1.5 1.33 2.3 28.4 3.8 MU4144 0.02 94.0 0.30 0.03 0.06 8.0 1.7 11.4 1.1 7.0 2.4 0.016 0.13 4.6 39.4 0.62 1.1 7.8 1.9 18.1 0.0012 0.40 30.3 0.08 1.0 0.15 0.40 17.1 1.8 MU714-1 0.10 455.0 0.83 0.03 0.20 13.0 2.9 21.4 1.0 12.2 2.4 0.063 0.27 9.8 827.5 13.4 1.2 26.4 5.8 17.3 0.0125 3.6 386.6 0.08 1.2 0.53 4.6 105.4 21.8 MU714-2 0.08 39.2 0.42 0.04 0.18 5.2 3.1 17.6 1.1 15.1 2.5 0.026 0.20 1.6 9.9 13.8 1.0 32.6 4.1 192 0.0124 1.3 37.3 0.08 035 1.1 4.8 42.2 4.3 MU714-3 0.01 9.8 0.37 0.03 0.15 8.0 2.4 16.6 0.77 4.6 2.3 0,022 0.22 2.8 92.8 0.84 1.5 7.9 1.9 16.5 0.0000 1.0 47.6 0.11 1.2 0.23 0.7 13.4 4.1 MU1416-1 0.02 56.2 0.34 0.03 0.07 7.6 2.0 11.1 1.4 4.4 2.5 0.014 0.24 4.2 17.2 3.1 1.2 11.9 2.2 20.8 0.0030 039 11.6 0.09 1.2 0.45 1.2 26.1 2.4 MU1416-3 0.02 59.7 0.33 0.03 0.05 8.1 2.1 11.5 1.4 3.9 2.5 0.014 0.24 4.6 20.4 3.8 1.4 12.7 2.1 21.2 0.0054 0.24 12.4 0.11 1.3 0.50 1.4 22.5 2.6 MU1416-7 0.06 146 0.40 034 0.15 83 2.5 16.6 14 10.8 2.6 0.021 021 42 9.8 10.5 1.1 21.5 32 202 0.0099 0.81 15.7 0.08 1.1 0.74 33 35.4 3.5 Lower Bess River BRS325-1 0.06 39.9 0.43 0.03 0.13 8.8 2.5 22.0 0.83 12.5 2.6 0.030 0.20 4.4 34.6 6.8 1.2 19.2 3.1 17.0 0.0037 1.3 22.3 0.08 1.1 0.44 1.9 35.9 3.8 BRS325-3 0.06 81.8 0.39 0.03 0.09 10.6 2.8 27.9 0.82 12.3 2.5 0.033 0.22 5.3 44.6 10.1 1.3 19.1 2.8 16.7 0.0041 1.5 29.9 0.09 1.2 0.42 3.2 24.9 4.4 BR5325-5 0.06 15.8 0.41 0.03 0.06 8.9 2.9 12.2 0.90 10.6 2.5 0.022 0.20 44 22.3 6.4 1.2 14.9 2.8 17.4 0.0034 1.0 16.9 0.09 1.1 0.38 13 30.0 3.2 LBR2563-1 0.07 101.5 0.51 0.04 1.03 7.8 2.3 26.9 1.1 13.7 2.7 0.027 0.18 5.4 18.0 27.3 1.4 41.6 2.9 18.5 0.0125 1.5 18.1 0.10 1.2 0.60 3.9 145.4 4.4 LBR2563-3 0.08 545 049 0.04 0. 63 7.8 2.3 22.3 1.1 156 2.7 0.030 0.16 5.3 13.8 35.1 1.4 44.3 3.5 18.0 0.0106 2.5 18.7 0.09 1.1 0.90 4.6 106.3 4.9 1BR2563-5 0.04 47.3 044 0.03 0.94 7.5 2.2 21.6 1.0 9.6 2.5 0.022 0.15 5.0 15.7 21.7 1.4 34.7 2.3 17.3 0.0062 1.5 13.2 0.10 1.1 0.75 2.7 110.2 4.5 1BR2563-7 0.05 44.5 0.53 0.04 0.49 7.0 2.1 20.5 1.1 9.6 2.7 0.027 0.18 4.7 10.6 23.0 1.3 34.6 3.2 18.1 0.0065 1.8 14.8 0.09 1.0 0.77 3.1 99.4 4.2 Upper Bess River UBR-C15-1331.1 0.18 71.4 0.30 0.03 0.05 10.9 1.3 56.5 1.1 6.9 2.5 0.019 0.15 7.7 7.5 0.94 1.9 11.8 2.3 13.7 0.0024 1.7 19.2 0.14 2.0 0.09 0.82 18.2 3.8 UBR-C15-1331-5 0.27 62.0 0.30 0.03 0.17 80 1.2 63.8 1.3 6.6 2.5 0.019 0.13 5.8 5.2 1.7 1.5 15.9 1.7 13.2 0.0057 2.9 17.6 0.11 1.4 0.10 0.92 20.7 3.9 UBR-C15-1331-7 0.38 61.8 0.24 0.03 0.21 6.9 1.4 37.6 1.0 5.9 2.4 0.017 0.17 4.1 13.3 069 1.5 11.5 2.5 12.4 0.0038 2.5 21.5 0.11 1.4 0.09 0.38 22.8 1.2 UBR1331-1 0.10 49.5 0.27 0.03 0.04 7.7 1.2 21.3 1.0 3.5 2.5 0.012 0.06 4.8 3.8 0.26 1.4 8.0 2.7 10.9 0.0008 1.1 18.1 0.10 1.3 0.07 0.14 21.3 0.7 UBR1331-3 0.15 61.7 0.28 0.03 0.09 6.9 1.4 30.7 1.1 4.1 2.6 0,014 0.07 4.7 3.3 0.56 1.4 12.4 3.0 11.8 0.0016 2.1 17.1 0.10 1.3 0.07 0.22 21.0 0.9 UBR1331-4 0.06 53.9 0.26 0.04 0.01 6.9 1.4 15.8 0.61 2.8 26 0.012 0.05 4.0 10.9 0.18 1.3 8.8 3.2 6.6 0.0007 0.91 16.5 0.09 1.4 0.04 0.16 37.0 1.2 UBR13314 0.10 18.1 0.19 aos 0.02 74 1.3 17.4 0.58 3.6 2.7 0.020 0.04 4.9 16.5 024 1.3 10.1 4.9 5.7 0.0009 1.3 18.2 0.09 1.4 0.04 0.22 36.2 3.0 UBR1331-11 0.10 21.4 0.26 0.04 0.03 7.6 1.3 16.5 0.62 3.5 2.5 0.014 0.04 4.5 7.6 0.19 1.4 9.1 3.8 6.4 0.0006 1.2 15.3 0.09 14 0.03 020 31.3 2.7 Golata GA442-1 0.02 48.1 0.28 0.06 0.02 25.8 3.7 28.8 0.59 3.0 2.8 0.022 0.63 10.6 56.4 0.33 4.0 10.8 2.5 9.2 0.0005 0.00 19.5 0.30 3.1 0.04 0.63 23.1 3.6 GA442-2 0.01 38.0 0.31 0.05 0.01 17.2 2.4 19.0 0.62 1.8 2.3 0.017 0.38 7.1 43.9 0.11 2.6 8.6 1.8 8.7 0.0003 0.16 14.6 0.19 22 0.04 0.40 21.1 2.7 GA442-3 0.01 37.6 0.34 0.05 0.01 18.9 2.5 20.4 0.65 1.9 2.5 0.014 0.47 7.8 27.9 0.12 2.8 8.5 1.9 9.5 0.0004 0.36 15.4 0.21 2.4 0.04 0.47 22.6 2.9 Table 2-5. Minor elements normalized to Al (reported as ppm//0 Al). Trace elements normalized to Al SAMPLE Ag ppm Ba ppm Be ppm Bi ppm Cd ppm Ce ppm Co ppm Cr ppm Cs ppm Cu ppm Ga ppm Ge ppm Hf ppm La ppm Mn ppm Mo ppm Nb ppm Ni ppm Pb ppm Rb ppm Re ppm Se ppm Sr ppm Ta ppm Th ppm TI ppm U ppm V ppm ppm Fort Simpson FS129-1 0.008 42.9 0.26 0.03 0.00 7.9 2.3 10.3 1.0 4.9 2.7 0.015 0.28 3.6 #DIV/01 0.02 1.3 6.5 1.4 154 0.0000 0.00 16.2 0.09 1.2 0.08 0.26 16.8 2.2 FS129-5 0.011 44.4 0.29 0.03 0.00 7.7 14 10.5 1.0 2.3 2.6 0.014 0.24 3.7 #DIV/0! 0.04 1.2 6.6 8.7 16.3 0.0000 0.21 15.3 0.09 1.2 0.09 0.25 17.1 t6 FS129-13 0.008 52.7 0.25 0.03 0.00 6.4 2.7 10.9 1.0 3.5 2.7 0.012 0.22 2.9 #DIV/0! 0.13 1.2 7.0 6.4 14.5 0.0000 0.20 13.6 0.08 1.0 0.09 0.25 18.5 1.4 FS947-1 0.000 66.3 0.30 0.03 0.00 7.1 2.1 8.5 1.0 2.1 2.6 0.014 0.17 3.4 #DIV/0! 0.07 1.2 57 1.8 16.2 0.0000 0.20 15.3 0.09 1.1 0.09 0.18 13.1 1.4 FS947-3 0.000 118.1 0.27 0.03 0.01 8.5 2.3 8.4 0.94 1.7 2.4 0.016 0.20 4.5 #DIV/0! 0.03 1.2 5.5 1.7 18.3 0.0000 0.14 29.0 0.09 1.2 0.08 0.21 11.8 2.3 FS1238-1 0.009 74.6 0.28 0.03 0.01 6.5 3.2 11.8 1.0 4.3 2.8 0.013 0.19 2.9 #DIV/0! 0.07 1.2 7.7 2.3 14.1 0.0002 0.10 110 0.09 1.0 0.11 0.22 21.0 1.5 FS1238-12 0.007 86.9 0.31 0.03 0.11 7.2 2.0 9.1 1.1 4.7 2.6 0.016 0.20 3.7 #DIV/O! 0.95 1.2 8.9 2.3 16.3 0.0008 0.33 15.5 0.09 1.1 0.17 0.31 24.1 2.1 FS1416.1 0.000 53.4 0.25 0.03 0.00 6.3 1.8 11.7 0.94 5.8 2.6 0.012 0.18 2.9 #DIV/0! 0.04 1.4 6.6 1.3 12.9 0.0000 0.41 15.3 0.09 1.0 0.08 0.21 18.5 1.7 FS1416-5 0.003 51.8 0.24 0.03 0.00 7.8 1.7 11.0 1.0 6.0 2.5 0.016 0.20 3.6 #DIV/0! 0.03 1.2 6.3 1.2 14.3 0.0000 0.21 16.0 0.08 1.1 0.07 0.22 18.0 2.0 FS1528-1 0.002 94.6 0.29 0.03 0.01 8.4 1.9 10.4 1.3 2.9 2.6 0.013 0.18 4.2 #DIV/0! 0.07 1.3 3.2 0.8 18.6 0.0000 0.10 12.5 0.10 1.2 0.15 0.24 21.7 1.7 FS5245-1 0.005 54.3 0.23 0.03 0.00 7.7 2.0 10.7 1.0 8.0 2.5 a D11 0.35 3.6 #DIV/O! 0.02 1.3 6.5 1.5 14.5 0.0000 1.11 117 0.09 1.2 0.08 0.31 19.6 2.2 FS5245-3 0.004 52.4 0.24 0.03 0.00 8.4 2.2 11.8 1.0 10.6 2.5 0.015 0.37 3.9 #DIV/0! 0.03 1.3 6.7 0.9 14.8 0.0000 0.33 14.3 0.09 1.3 0.08 0.32 19.2 2.3 FS7194-2 0.002 61.9 028 0.03 0.01 7.5 27 9.4 12 2.3 2.6 0.014 0.20 3.8 #DIV/0! 0.06 1.2 6.4 3.3 19.4 0.0000 0.10 9.9 0.09 1.1 0.11 0.22 17.2 1.5 F87194-4 0.002 111.9 0.34 0.01 0.05 8.1 1.7 9.0 1.1 1.5 2.5 0.014 0.20 4.3 #DIV/0! 0.11 1.2 3.1 1.5 18.9 0.0002 120 10.9 0.09 1.2 0.18 0.30 18.1 1.5 FS12140-1 0.007 48.6 0.21 0.04 0.00 8.9 2.2 11.7 0.82 3.5 2.4 0.018 0.39 4.0 #DIV/0! 0.08 1.5 6.3 2.1 13.1 0.0003 0.00 22.5 0.10 1.4 0.07 0.34 174 4.0 FS12140.6 0.007 57.9 0.23 0.02 0.00 7.4 2.1 11.2 1.0 6.2 2.5 0.013 0.35 3.3 #DIV/0! 0.03 1.3 6.6 1.0 14.0 0.0002 0.00 16.7 0.09 1.2 0.08 0.30 20.5 2.1 FS13703-2 0.003 50.2 0.26 0.04 0.00 7.9 2.3 10.7 0.93 4.3 2.6 0.012 0.32 3.8 #DIV/0! 0.03 1.3 6.5 1.0 15.1 0.0000 0.30 18.1 0.09 12 0.08 0.30 19.3 2.1 FS13703-4 0.008 50.6 0.26 0.03 0.00 8.6 24 11.9 0.94 12 2.7 0.016 0.35 3.9 #DIV/0! 0.03 1.4 6.7 2.3 13.8 0.0000 0.38 30.3 0.10 1.3 0.08 0.32 18.4 3.2 F513703-6 0.004 58.7 0.24 0.04 0.01 6.1 2.3 11.5 0.93 5.5 2.6 0.013 0.31 2.7 #DIV/0! 0.03 1.3 6.8 1.9 12.6 0.0000 0.31 18.5 0.09 1.0 0.08 0.29 20.6 1.9 Table 2-5 cont Oxide/Element Av. Shale {') abundance -/AI Muskwa n = 14 abundance -JAI EF Fort Simpson n = 24 abundance -/AI EF Lower Besa River n = 7 abundance -/AI EF Upper Besa River n = 8 abundance -/AI EF Goleta n = 3 abundance -/AI^EF v.= TOC (wt%) 0.20 am 2.4 0.31 10.5 0.26 0.08 2.7 2.9 0.65 21.7 3.2 0.34 11.4 2.8 0.50^16.8 S (%) 0.24 0.03 2.7 0.45 15.0 0.60 0.06 2.0 1.6 016 15.3 2.7 0.29 9.7 OA 0.08^2.7 A60, (%) 16.7 [1] 11.4 [1] - 18.7 [1] 6.7 [1] - 173 [1] - 11.2 111^- CaO (%) 2.2 0.13 7.3 0.32 2.4 2.6 0.09 0.72 0.88 0.19 1.5 1.6 0.14 1.1 0.3 0.03^0.23 Fe,O, (5) 2.8 0.17 40 0.47 23 6.5 0.47 26 23 0.48 2.9 6.0 0.43 26 3.3 0.40^24 KuO (35) 3.6 0.22 2.6 0.36 1.6 16 0.29 1.4 1.7 0.39 1.8 1.8 0.17 079 1.6 0.23^1.0 MgO (%) 2.6 0.16 1.7 0.19 1.2 2.3 0.13 0.84 0.76 0.13 0.87 1.0 0.07 0.44 0.8 0.08^0.50 NatO (%) 1.6 0.10 0.49 0.06 0.60 0.59 0.05 0.53 0.11 0.02 0.25 06 0.05 0.52 0.4 0.05 049 P20, sio, (%) (%) 0.16 58.9 0.01 3.53 0.17 56.1 0.01 4.1 1.2 1.2 0.15 57.7 001 3.2 0.74 0.90 0.08 81.4 0.01 11.2 1.0 3.2 0.3 58.7 0.01 3.3 1.5 0.95 0.1 73.8 0.01^0.86 6.0^1.7 TiO2 (35) 0.78 0.05 0.52 0.05 1.1 0.88 0.05 1.1 0.30 0.05 1.1 0.8 0.06 1.2 1.2 0.13^2.7 Ag ppm 0.07 0.008 0.33 0.06 7.8 0.05 0.00 060 0.22 0.06 7.4 1.3 0.17 21.3 0.09 0.02^2.2 Ba ppm 580 666 282.1 70.5 1.1 606.3 64.8 0.99 220.0 55.0 0.84 402.5 50.0 076 216.7 41.2^0.63 Be ppm 3 0.34 2.3 0.42 1.2 2.5 0.26 0.78 1.8 0.46 1.3 2.2 0.26 0.77 1.7 0.31^0.91 Bi ppm 0.1 0.011 0.25 0.04 3.7 0.28 0.03 2.7 0.13 0.03 3.0 0.32 0.04 11 0.27 0.05^4.5 Cd ppm 0.8 0.09 11 0.24 2.6 0.11 0.01 0.13 2.80 0.48 5.3 0.59 0.08 0.85 0.05 0.01^0.11 Ce ppm 95 10.7 52.5 9.1 0.84 71.2 7.6 0.71 27.1 8.3 0.78 65.5 7.8 0.73 107.2 20.6^1.9 Co ppm 19 2.15 16.3 2.8 1.3 21.4 2.3 1.1 8.03 2.5 1.1 11.4 1.3 0.62 14.7 2.8^1.3 Cr ppm 90 10.2 87.9 15.7 1.5 99.4 10.6 1.0 82.0 21.9 2.2 251.5 32.4 3.2 118.0 22.8^2.2 Cs ppm 5.5 0.62 76 12 20 9.6 1.0 1.6 3.90 0.98 1.6 7.4 0.90 1.5 3.3 0.62^1.0 Cu ppm 45 5.1 58.4 10.5 2.1 41.5 4.4 0.86 43.4 12.0 2.3 37.0 4.6 0.91 11.5 2.2^014 Ga ppm 19 2.1 14.6 2.5 1.1 24.4 2.6 1.2 9.6 2.6 1.2 22.0 2.5 1.2 13.6 2.6^1.2 Ge ppm 1.6 0.18 0.12 0.02 0.13 0.13 0.01 0.08 0.10 0.03 0.15 0.14 0.02 0.09 0.09 0.02^0.10 Hf ppm 2.8 0.32 1.3 0.22 0.68 2.41 0.26 0.82 0.60 0.18 0.58 0.68 0.09 028 2.5 0.49^1.5 La ppm 40 4.5 28.7 5.03 1.1 33.8 3.6 0.80 18.3 4.9 1.1 41.9 5.0 1.1 44.2 8.5^1.9 Mn ppm 850 96.2 186.1 82.1 0.85 512.6 55.6 0.58 50.3 22.8 0.24 78.8 8.5 009 245.7 42.7 044 Mo ppm 2.6 0.29 37.7 7.2 24.5 0.91 0.10 0.33 96.3 18.6 63.4 16 0.60 2.0 0.93 0.19^0.64 Nb ppm 18 2.0 8.4 1.4 0.70 11.9 1.3 0.62 4.9 1.3 0.64 12.3 1.5 0.72 16.3 3.1^1.5 Ni ppm 68 7.7 112.9 20.5 2.7 59.1 6.3 0.82 139.5 29.8 3.9 92.0 11.0 1.4 48.9 9.3^1.2 Pb ppm 20 2.3 19.8 3.6 1.6 21.7 2.3 1.0 10.7 2.9 1.3 27.2 3.0 1.3 10.8 2.1^0.91 Rb ppm 140 15.8 114.7 19.1 1.2 145.5 15.4 0.97 64.6 17.6 1.1 81.4 10.1 0.64 48.7 9.1^0.58 Re ppm 0.0005 0.00 0.05 0.008 133.3 0.003 a000l 1.4 am 0.007 111.9 0.02 0.002 315 0.002 0.00^6.4 Se ppm 0.6 0.07 5.93 12 17.7 2.8 024 3.6 6.50 1.6 23.2 14.0 1.7 25.3 1.5 0.17^2.5 Sr ppm 300 33.9 153.5 48.9 1.4 152.8 16.7 0.49 58.0 19.1 0.56 151.6 17.9 0.53 86.4 16.5^0.49 Ta ppm 2 0.23 0.60 0.10 0.45 0.84 0.09 0.40 0.34 0.09 0.40 068 0.10 0/6 1.2 0.23^1.0 Th ppm 12 1.4 7.4 12 0.91 10.8 1.2 0.85 4.0 1.1 0.82 12.1 1.4 1.1 13.4 2.6^1.9 TI ppm 1.4 0.16 3.6 0.62 3.9 0.93 0.10 0.62 2.7 061 3.8 0.52 0.07 0.42 0.21 0.04^0.25 U ppm 3.7 0.42 13.2 2.5 6.0 2.48 0.27 033 12.8 3.0 7.2 2.9 0.38 0.91 2.6 0.50^1.2 V ppm 130 14.7 286.7 52.9 3.6 174.7 18.5 1.3 413.8 78.9 5.4 236.1 26.1 1.8 118.3 22.2^1.5 Y ppm 41 4.6 20.6 4.7 1.0 18.8 2.0 0.44 16.2 4.2 0.90 18.1 2.2 0.47 16.0 3.0^0.66 Zn ppm 95 10.7 148.7 25.1 2.3 160.4 17.1 1.6 2618 45.5 4.2 209.1 25.4 2.4 67.7 13.5^1.3 Zr ppm 160 18.1 42.2 7.2 0.40 75.3 8.1 015 20.5 5.9 0.33 20.1 2.6 0.15 76.0 14.7^0.81 t.e.)^Table 2-6. Average concentrations of al major elements and trace metals of Devonian-Mississippian sediments. Averages are also shown normalized to Al. (1)Average shale composition from Wedepohl (1971, 1991) used to determine enrichment factors (EF), except Re (from Crusius et al., 1996). 100 10 0.1 001 ME ,ate E7,1 Fort Simpson 1111 Lower Bess River Upper Bess Rivet MIN Goleta 0.1 - 0.01 TOC^S^Ca^Fe^K^Mg^Na^P^Si^Ti Ag Ba Be Bi Cd Ce Co Cr Cs Cu Ga Ge Hf La Mn Mo 1000 100 - 2rn al 1' 10- .1. U. 100 10 0. 1 Nb Ni Pb Rb Re Se Sr lj Ta Th TI U V Y Zn Zr Figure 2-4. Enrichment factors (EF), relative to average shale (Wedepohl, 1971), of analyzed elements in Devonian—Mississippian sediments: A) TOC, Stota l and major elements; B and C) minor trace elements determined by ICP-MS. Horizontal line drawn at EFaverage shale = 1 to highlight enrichment or depletion of elements. 37 TOC/TN ratios range between 1 (Fort Simpson) and 49.8 (lower Besa River; Table 2- 1). On a weight percent TOC basis, lower Besa River, Muskwa and Golata sediments have lower TN concentrations, hence higher TOC/TN ratios compared to upper Besa River sediments. TOC/TN ratios of Fort Simpson sediments are <5, similar to modern organic-lean sediments (Meyers and Arnaboldi, 2005). Total sulphur (Stotai) concentrations vary between 0.02% (Fort Simpson) and 4.5% (upper Besa River and Muskwa shales). Sulphur EFs are highest in Besa River and Muskwa sediments (9.7-15.3) and lowest in Fort Simpson and Golata sediments (2-2.7). 2.4.2 Major element characteristics Marine shales and mudrocks can be regarded as an admixture of three end member oxides: Si02 (detrital quartz or biogenic silica), Al203 (clay fraction) and CaO (carbonate content). The ternary plot of these major elements indicates the majority of shales and mudrocks examined are variably enriched with Si02 relative to Al203 and CaO (Figure 2- 5). Some Muskwa sediments have high levels of carbonate dilution (>40% CaO) which is not necessarily associated with reduced TOC contents (e.g. sample MU714-1). High silica concentrations occur in the lower Besa River (average Si02 = 81.4%), Golata (average Si02 = 73.8%; Figure 2-6) and Muskwa sediments (up to 73.5% SiO2). Silica concentrations of Fort Simpson and upper Besa River sediments are closer to AS composition, typically in the range between 56% and 59% Si0 2 . The lower Besa River, Muskwa and Golata formations have average Al203 concentrations between 6.7-11.4%, 38 10 20 30Si0 2 Al203 Average shale 0 40^50^60^70^80^90^100^CaO O Muskwa ^ Lower Besa River • Upper Besa River — Goleta O Fort Simpson Figure 2-5. Ternary diagram showing relative proportions of major shale/mudrock elements Si02 (quartz), Al203 (clays) and CaO (carbonates). Average shale also shown (after Wedepohl, 1971). 39 Ca/Al Fe/AI K/AI Mg/AI Mn/AI Na/A1 P/AI Ti/A1 TOC/A1 —Cr— Muskwa —C— lower Besa River upper Besa River —0— Fort Simpson ^ Golata Ca/AI Fe/AI K/AI Mg/AI Mn/AI Na/AI P/AI Si/AI Ti/AI Figure 2-6. Relative concentrations of major elements (normalized to Al) of Devonian—Mississippian sediments. Note enrichment of Si/AI in lower Besa River, Golata sediments and Muskwa sediments. whilst upper Besa River and Fort Simpson sediments average 17.6% and 18.7% Al 203 respectively. No notable enrichments of K, P, and Mg occur (Figure 2-4). Lower Besa River and Muskwa sediments have relatively high K/Al ratios owing to higher illite content (Yarincik et al., 2000; Ross and Bustin, in review). Upper Besa River, Fort Simpson and Golata sediments have lower K/Al and Mg/Al ratios than Muskwa and lower Besa River sediments, indicative of clay minerals containing minor concentrations of Mg and K such as kaolinite. Magnesium in Muskwa sediments is also related to dolomite. Iron concentrations are close to AS with ERF e ranging between 2.3 and 2.9. The poor to moderate correlation between Fe and Al attests to the variable Fe-bearing phases. For Muskwa, lower and upper Besa River sediments, Fe is associated with pyrite as indicated by the good correlation between Stotal and Fe2O3 (Figure 2-7). Low Stotai sediments of the Golata and Fort Simpson formations show poor correlation between Stotal and Fe2O3 (Figure 2-7, inset). Sodium concentrations are low in all sediments compared to AS. For AS, the Na content reflects plagioclase feldspars which dominate over K-feldspars (10— 15% bulk composition; Wedepohl, 1971). Devonian—Mississippian sediments contain relatively little plagioclase. Titanium, a diagenetically stable constituent of fine-grained sediments, has EFs <1.2 except for Golata sediments which have EF T, of 2.7. The good correlation between TiO2 and Al203 suggests Ti occurs in clay lattices (r 2=0.88; Figure 2- 8). Higher Ti/Al ratios for Golata sediments are a result of detrital input due to the known association of Ti with terrestrial detritus and coarser grained sediments in high energy environments (Wedepohl, 1978; Calvert et al., 1996). 41 A0 0 0 A 0 Muskwa ^ Lower Besa River A Upper Besa River O O 2 - (5D 2 10 120^2^4^6^8 Fe203 (%) 0 0^ A — Golata o Fort Simpson 3.0 2.0 1.5 Co 1.0 0.0 0 0 0^2^4^6^8^10^12^14^16 Fe20 3 (%) Figure 2-7. Sulphur-Fe relationships for Devonian—Mississippian sediments. Good correlation between S and Fe20 3 underlines the importance of pyrite as the main storage phase of S (Muskwa and lower/upper Besa River). Poor correlation between Fe and Stow, for Fort Simpson and Golata sediments is a result of low S concentrations and the influence of Fe associated with other mineral phases. 0 0.4 - COco0 0.2 - 1.4 0 0 1.2 - o Muskwe o Lower Be. River A Upper Be. River Goleta O Fort Sti-rpson 0.6 - 0.8 - 1.0 - 0 0 0 A 00 0 0 0 8 0 A 0 A 0 0.0 O Cs1 0 0 ^ 5^10^15 ^ 20 ^ 25 Al203 (%) Figure 2-8. Correlation between TiO2 and Al 203 suggesting Ti is primarily associated with clay phases. Note over enrichment' of Ti with respect to Al for Golata sediments implying an additional storage phase of Al (silt/sand-sized Ti-bearing minerals?). 43 2.4.3 Excess silica concentrations Sediments of the lower Besa River, Muskwa and Golata formations are characterized by high Si/Al ratios. Excess silica contents, which are SiO2 levels above 'normal' detrital background, were calculated using the formula: Element,s = elementsample — [(element/A1)background x Alsample] ^ (2) A Si/Al ratio of 3.11 is used for AS (Wedepohl, 1971). As such, up to 70% of the SiO 2 in lower Besa River sediments and up to 50% SiO 2 in Muskwa and Golata sediments cannot be accounted for by the aluminosilicate phase. Silt-sand sized quartz may account for excess SiO2 in Golata sediments which are Ti-rich and are coarser-grained. Although a detrital source of the silica cannot be completely discounted for lower Besa River and Muskwa sediments, it is argued here that excess Si is due to biogenic sources because: 1) TOC contents are high (1.4-4.8 wt%) and; 2) Ti concentrations are close to AS values. Both of these attributes suggest coarse-grained clastic dilution was relatively low during deposition. High excess silica concentrations have been utilized to infer biogenically- sourced silica in Cretaceous and Jurassic organic-rich shales/mudrocks (Turgeon and Brumsack, 2006; Ross and Bustin, 2006). Biogenically-sourced silica for lower Besa River and Muskwa sediments is also evident by the recognition of siliceous sponge spicules, spongy chalcedonic quartz and radiolaria assemblages in equivalent strata in the WCSB (Pelzer, 1966; Stasiuk and Fowler, 2004). 44 2.4.4 Trace metal characteristics In this study, trace metals are grouped based on their geochemical behaviour with respect to: 1) processes governing the accumulation and preservation of organic matter (after Wedepohl, 1971, 1978, 1991) and; 2) element-element associations. Elements are grouped as: a) detrital proxying elements b) high field strength elements c) bio-concentrated and anoxia-proxying elements d) redox sensitive (Mn) and chalcophile elements e) low crustal abundance elements (organo-metallic compounds) f) carbonate elements. The sedimentological processes governing groups c), d) and e) are directly related and element 'overlap' will exist. 2.4.4.1 Detrital proxying trace metals (including large ion lithophile TMs) Enrichment factors of large ion lithophile trace elements (Rb, Ba, Pb and Cs) are close to 1, implying background sedimentation is relatively similar to AS. Alkali elements Rb and Cs follow K (Figures 2-9A and 2-9B) where Rb/K and Cs/K ratios are relatively uniform. Rb and Cs are attributed to detrital phases in marine sediments and typically vary as a function of biogenic dilution (Plank and Langmuir, 1998). Cerium, La and Be have concentrations close to AS, correlating with the aluminosilicate fraction as these 45 A 0 00 04: A  o Wawa o Lower Besa River • Upper Elas• Rner Goala 0 ^ o Fort Saapson 20 - 0 0 0 10 15 20 250 5 80 - 0^0^0e 0 pc,„ A E a 60 - d 40 - 0 0 Detrital-proxyinq elements 120 100 0^00 00 0 A^0 0^A C 0 1510 20 255 40 E a 30 R -J 20 10 0 0 60 50 ° -o A 0 ^ 0^ A 0 0 ^6 ^0 0 ^00 po g 00oo 0 A0 0 0 .^.0 0 0 A A 0 D Alkali element distribution 0° 00ei 0 0 0 2^3^4^5 K20 (%) 14 12 10 8a 6 4 2 - 0 0^1 2^3^4 K20 (%) 6 ^ 7 B 0 0 °o ^o O 5 ^ 6 ^ 7 Al 203 (%) ^ Al 203 (%) E co ocb ° co cc) P C0^4, SP° 0 0 `.10 0^0 • 490% 0^ 0 " 0 -0 0 A 0 5 ^ 10 ^ 15 ^ 20 ^ 25 Al20 3 (%) Figure 2-9. Aluminosilicate associations of various elements (calculated as ppm). Plotted are values for: A) Rb; B) Cs; C) Ce; D) La; E) Be. Golata sediments show over enrichment' of Ce and La, similar to Ti, suggesting an association of these elements with coarser-grained detritus. 4 3 E a a2 CO 0 0 46 250 200 ? 150 a -0 100 50 0 elements adsorb onto clay minerals (Figures 2-9C-9E; Eskenazy and Valceva, 2003). Similar to Ti concentrations, the Golata sediments are enriched in Ce and La compared to AS, suggesting an elemental association with coarser-grained detritus as well as Al203 (proxy for clay fraction). 2.4.4.2 High field strength trace elements (low solubility in natural waters) The distribution of high field strength elements (Zr, Hf, Nb, Ga, Ta and Th) are primarily controlled by the aluminosilicate fraction (Figures 2-10A-2-10F). Exceptions are Zr and Hf concentrations in upper Besa River sediments which do not correlate with Al203 (Figures 10A and 10B) and have concentrations below that of AS (EF z, = 0.15. EFHf= 0.28). Hafnium, Nb, Ta and Th, classified as immobile elements (including Ti; Plank and Langmuir, 1998), are enriched in Golata sediments relative to AS, underlining their importance within continental detritus (and lack of biogenic dilution; Plank and Langmuir, 1998). In spite of the coarse-grained sedimentation which affected Golata sediments, EFz, is below 1 (i.e. lower than AS) which is surprising due to the association of zircon with coarser-grained sediment (high Si/A1 and Ti/A1 ratios; Calvert et al., 1996). Niobium-Ta and Hf-Zr can be considered as element pairs, essentially analogous to each other (Figure 2-11) as they are not fractionated during most geological processes (Plank and Langmuir, 1998). Due to the low sea-water/crustal coefficients and lack of mobility (i.e. from weathering or diagenesis), enrichments of Nb and Hf are excellent indicators of detrital input during deposition. It is assumed these elements are 47 120 100 80 40 20 0 A T • , 0 0 0 4.0 ^ B 3.5 0 ^3.0 ^ 0 2.5 - 0. 0. 2.0 - ^1 1.5^ c°0 0 o ,, ° 0 .0 co^^ 0.5^^r^I^ ^ 0 0 .0 00 0 0^8 0 0 A O „ ^0 ^So C' O 0 ^C' 0^0 0 (9° ° ^ 0^A 0 cc, 20 250^5^10^15^20^25^0^5^10^15 Al20 3 (%) Al203 (%) 00 A edtq ° O ° 0A 0% A^000 0 .c2 8 6 - 4 - 2 - 0 ^ C^- 0 D35 30 25 fx 20 Co 15 10 5 CILP° ^ UD 18 16 14 12 10 8 - 6 - 4 - 2 0  F 0 o cp cfP° 00 0  ^ 0 se :,0 0 00. 0A 0 0 E 0. .c Hicih field strength trace elements 5^10^15^20^25^0^5^10^15^20^25 A l203 (%) Al203 (°/0) 0^5^10^15 ^ 20 ^ 25 ^ 0 ^ 5 ^ 1 0 ^ 15 ^ 20 ^ 25 Al203 (%) Al203 (%) Figure 2 -10. Relationships between aluminosilicate phases and high field strength trace metals (all ppm). A) Zr; B) Hf; C) Nb; D) Ga; E) Ta; F) Th. Excess enrichments occur for Goleta sediments (Nb, Ta and Th) suggesting affiliation with silt/sand-sized minerals. 48 O Muskwa ct Lower Besa River A Upper Besa River Golata o Fort Stmpson OD 0 0 0 0 18 ^ 16 - 14 - 12 - 10 - 8 - 6 4 - 2 - 0 4.0 3.5 3.0 2.5 a_ Q. 2.0 1.5 1.0 0.5 0.0 E a. .a Analog high field strength elements 0^20^40^60^80 ^ 100^120^0.0^0.2^0.4^0.6^0.8^1.0 ^ 1.2^1.4 Zr (ppm) Ta (ppm) Figure 2-11. Plots of analog high field strength elements in Devonian—Mississippian sediments. Zirconium-Hf and Ta-Nb are not fractionated from one another during most geological processes transported through structural bonding or adhesion to clay minerals (Taylor and McLennan, 1985). 2.4.4.3 Bio-concentrated and anoxia-proxying elements Enrichment factor values of oxyanions Re, Mo, V and U follow the order: lower Besa River and Muskwa >upper Besa River and Golata >Fort Simpson. Lower Besa River and Muskwa sediments are enriched with Mo (EF Mo = 25.5-63.4), Re (EF Re = 111.9-133.3), U (EFu = 6-7.2) and V (EFv = 3.6-5.4). Rhenium is also enriched in upper Besa River (EFRe = 34.5) and Golata sediments (EFRe = 6.4). For Muskwa and lower Besa River sediments, Al-normalized concentrations of these metals are associated with organic- enrichment (Figures 2-12A-2-12D). However, metal/Al ratios show no correlation with TOC for upper Besa River, Fort Simpson and Golata sediments. Rhenium is a valuable tool for determining redox conditions due to low detrital concentrations (0.5 ppb in continental crust; Crusius et al., 1996), and it is not related to Fe or Mn cycling (Crusius et al., 1996), behaving as a conservative element in oxic and anoxic conditions. Hence Re redox behaviour is simplistic and is useful for tracing authigenic accumulation (through diffusive flux into the sediment; Morford et al., 2001). It has been proposed that following diffusion across the sediment-water interface, Re is incorporated into sulphides (Colodner et al., 1993) which would account for Re distributions in sulphide-rich Muskwa and Besa River sediments. Molybdenum is a robust tracer of sediments deposited under anoxic conditions (Francois, 1988; Dean et al., 1997) as HS - shifts the Mo species from molybdate to 50 5 6 200 180 - 160 - ...., 140 - ECL 120 a 100 - 80 - -^60 - 40 - 20 - 0 0 2^3^4 TOC (wt%) 0.025 0.020 a. 0.015 fa. 0. 010 0.005 0.000  0 ^ 2^3^4 ^5 ^ 6 ^ 0 ^ 2^3^4 ^5^6 TOC (wt%) TOC (wt%) Figure 2-12. Organic carbon concentrations verses Al-normalized metal concentrations (calculated as ppm per wt% Al). Plotted values are for: A) Mo/Al; B) Re/Al; C) V/Al; D) U/Al. particle reactive thiomolybdate (Crusius et al., 1996; Helz et al., 1996; Brumsack, 2006). The change of element reactivity also enhances the ability of organic matter to scavenge Mo (Coveney et a1., 1991; Crusius et al., 1996) producing co-eval enrichments of organics, sulphides and Mo. As such, Mo has been used to proxy 'original' TOC of black shales (Wilde et al., 2004). Modern reducing sediments with free H2S in the water column (Black Sea, Saanich Inlet) contain 2-125 ppm Mo (Crusius et al., 1996) which are comparable concentrations to Muskwa and lower Besa River Sediments (3.4-129 ppm). Such levels are considerably higher than AS (2.6 ppm; Wedepohl, 1971) and black shales (10 ppm; Vine and Tourtelot, 1970). Low EFm c, in upper Besa River sediments, which are organic and sulphur-rich, may signify a lack of bio-element concentration in the water column and/or related to removal of sulphide by Fe (to precipitate pyrite) which can limit Mo enrichment (Meyers et al., 2004). As noted by Cruse and Lyons (2004), the sequestration of Mo in organic-rich sediments is poorly constrained and needs to be examined further. Re/Mo ratios are used to decipher anoxic from suboxic sedimentation (Crusius et al., 1996). High ratios (>15x10 -3) are indicative of suboxic conditions as there is a preferential enrichment of Re over Mo in low sulphide environments (Crusius et al., 1996). Conversely, anoxic/sulfidic bottom waters have lower ratios, closer to the modern sea-water value of 0.8x10 -3 . Lower Besa River sediments plot below the Re/Mo of sea- water (Figure 2-13) suggesting anoxic deposition with intermittent euxinic conditions. Organic-rich Muskwa and upper Besa River sediments plot in stable anoxic conditions, relatively close to the Re/Mo of seawater. The majority of Fort Simpson and all Golata 52 -3 Re/Mo = 15 x 10 0.16 0.14 0.12 0.10 0.08 0.06 0.04 0.02 0.00 0 Sea water ,D Musky. ^ Lowe' Be. River A Upper Besa River Golata O poll Strrepson Anoxic -3 Re/Mo = 0.8 x 10 Euxinic (?) Suboxic 0^20^40^60^80^100 120 140 Mo (ppm) Figure 2 -13. Rhenium vs. Mo diagram for Devonian—Mississippian sediments. Lower Besa River, upper Besa River and Muskwa sediments show Re/Mo values of anoxic sedimentation. Enrichment of Mo in lower Besa River sediments suggests sporadic euxinic conditions. Both Fort Simpson and Golata sediments plot near the origin. Rhenium/Mo ratios used for identifying anoxic and dysoxic sedimentation from Crusius et al. (1996). sediments have relatively low Re and Mo concentrations implying the water column was oxic to suboxic. Moderate correlation between U and V with TOC for silica-rich Muskwa and lower Besa River sediments underlines the importance of elemental bio-concentration by plankton through sorption processes (Bruland, 1983; Brumsack, 1986). Higher concentrations of V and U also suggest anoxic/sulfidic bottom water conditions. In oxygenated waters, V is weakly adsorbed to organic particles and as OM decays, V is easily lost to the water column (Lewan and Maynard, 1982; Breit and Vanty, 1991). However adsorption is greatly enhanced entering anoxic waters due to the reduction of V (V) to the vanadyl ion. Similar to V, U solubility is redox-dependant, reducing to the insoluble U lv from the soluble Uvl (Langmuir, 1978) hence organic-rich sediments are argued to be the largest sink for U dissolved in sea-water (Klinkhammer and Palmer, 1991). Uranium and V behaves conservatively in oxic waters (Bruland, 1983) and diffuse into reducing sediments to precipitate at depth (Breit and Vanty, 1991). Vanadium and U do not form stable sulphides but excess H2S may aid the incorporation of these elements into the sediments (Klinkhammer and Palmer, 1991). 2.4.4.4 Bottom water redox — Mn concentrations Manganese concentrations are low in Besa River sediments (EF mr, range between 0.09- 0.24) whereas EFm n for Muskwa, Fort Simpson and Golata sediments are closer to AS (0.44-0.85). Under the oxygen-restricted bottom waters which persisted during lower and upper Besa River deposition (as evident from high TOC and S total), Mn 54 concentrations are depleted relative to AS because any Mn delivered to the sediment underwent reductive dissolution and remobilized (Calvert and Pederson, 1993). Enrichments of Mn in Muskwa sediments relate to higher carbonate contents and low Al concentrations (e.g. samples MU714-1 and MU714-3), therefore Mn is not detritally sourced. Absolute Mn concentrations can exceed 700 ppm, significantly higher than Black Sea sediments (270-430 ppm; Brumsack, 2006) and close to AS values (850 ppm; Wedepohl, 1971). Manganese carbonate phases suggest subsurface anoxic sediments which are overlain by oxide-enriched surfaces in order to saturate pore-waters with Mn (Calvert and Pederson, 1996). Total organic carbon contents >3 wt% indicates that at times, dissolved oxygen was present during deposition of some of the organic-rich Muskwa sediments. 2.4.4.5 Chalcophile elements Enrichment factors of Ag, Zn and to a lesser extent Pb, are higher for Muskwa and lower and upper Besa River sediments with EF Ag=7.4-21.3, EFzb=2.3-6.7 and EFpb=1.3— 1.6. Low EFs in sulphur-poor units (Fort Simpson and Golata) show the importance of sulphide incorporation of these elements in organic-rich sediments. Silver concentrations can also be controlled by bio-silica input which would affect the relationship between Stotat contents and Ag (Boning et al., 2004). Copper and Ni concentrations are highest in lower Besa River and Muskwa sediments = 2.1-2.4; ERN, = 2.7-3.9) suggesting incorporative mechanisms similar to elements associated with organic-rich, siliceous sediments (e.g. V and U in lower Besa 55 River and Muskwa; Figures 2-14A and 2-14B). Enrichment of Cu and Ni has been related to their role as micronutrients (Martin and Knauer, 1973) as these elements are incorporated into organic matter and fluxed to the sea-floor. The relationship between organic carbon, Cu and Ni is affected by H 2S-ladened bottom waters as Cu and Ni are known to precipitate under sulfidic conditions (Jacobs and Emerson, 1985). Al- normalized values of Cu and Ni for upper Besa River, Fort Simpson and Golata sediments are close to AS. The variability of Cu and Ni independent of TOC and Stotal contents (upper Besa River) implies the availability of settling organic matter and sulfidic bottom waters are not necessarily prerequisites for the assimilation of Cu and Ni into sediments. 2.4.4.6 Low crustal abundance elements (organo-metallic compounds) Low crustal abundant elements Bi, Cd, Se and Tl have variable concentrations in the sample suite. Bismuth EFs are higher in all units compared to AS but no discernable trend in concentrations occur in the Devonian—Mississippian sample set. Bismuth is not necessarily indicative of unique sedimentological/depositional conditions and can be controlled by its availability in sea-water (Bertine et al., 1996). Selenium is enriched in Muskwa, lower and upper Besa River sediments (EF se=17.7, 23.2 and 25.3 respectively), relating to Stotal contents and H2S-associated precipitation. Enrichment factors of Tl and Cd are highest for Muskwa and lower Besa River (EFT' = 3.8-3.9; EF cd = 2.6-5.3) whereas upper Besa River, Fort Simpson and Golata sediments have concentrations below AS (EFs <0.85). Greater concentrations of Tl and Cd in Muskwa and lower Besa River sediments, which are also enriched with organically mediated elements such as U 56  18 16 14 12 10 8 6 4 2 0 A 0 ^ 1 ^ 2^3^4 ^ 5 ^ 6 ^ 1 ^ 2^3^4 ^ 5 TOC (wt%) TOC (wt%) Figure 2-14. Organic-element associations (calculated as ppm per wt% Al): A) Cu/Al; B) Ni/Al. Note enrichments of Cu in Fort Simpson sediments despite low TOC (and low S), indicating other sources (mineralogical?) contributing to Cu concentrations. and V, suggests bio-accumulatory concentration. Sequestration of Ti and Cd may have been enhanced by anoxic bottom waters as both elements behave conservatively in oxic waters (Flegal and Patterson, 1985) and can be enriched in reducing sediments (Brumsack, 1980; Rosenthal et al., 1995). Upper Besa River, Fort Simpson and Golata sediments have Ti concentrations which relate to both K and Rb (r2 between K20 and Ti = 0.72; Figure 2-15) due to the association of these elements with illite (Heinrichs et al., 1980). Ge/Al ratios are slightly higher in Muskwa and lower Besa River sediments (Figure 2- 4), reflecting the oceanic cycling of Ge with biogenic silica (Froelich et al., 1989). The depletion of Ge compared to AS in all Devonian—Mississippian sediments can be explained by low Ge/Si ratios of the seawater which can control Ge incorporation into siliceous sponge spicules (Davie et al., 1983; Ellwood et al., 2006). 2.4.4.7 Carbonate elements — Ca, Sr and Y Yttrium and Sr concentrations in Devonian—Mississippian sediments are either lower or comparable to that of AS. The moderate enrichment of Sr in Muskwa sediments reflects the higher carbonate concentrations as Sr substitutes for Ca in the calcite lattice. 2.5 PALEOCEANOGRAPHIC CONDITIONS RESPONSIBLE FOR ORGANIC MATTER AND ELEMENT ACCUMULATIONS This section summarizes the key geochemical features of Devonian—Mississippian sediments in order to develop a model for sediment-water conditions which can account 58 76 - 5 - 4—.,,,,.0 0 2 3 - 2 - 1 - 0  0 0 0 0 0 0 0 o Muskwa a Lower Besa River A Upper Besa River — Golata 0 Fort Simpson 0 0^0.2^0.4^0.6^0.8^1.0^1.2 ^ 1.4^1.6^1.8^2 0 TI (ppm) Figure 2-15. A) Association between excess silica concentrations and low crustal abundance trace metals TI and Cd (-/AI, ppm) for Muskwa and lower Besa River sediments. B) Relationship between K20 and TI in upper Besa River, Golata and Fort Simpson sediments, indicative of TI- rich illite. 59 for the observed distribution of TOC, ME and TE concentrations. For discussion purposes, sediments are divided into organic-rich black shales and mudrocks (Besa River and Muskwa), organic-lean grey shales (Fort Simpson) and silty mudstones (Golata). The effects of anoxia, productivity and elastic influx/sediment supply are examined. It is difficult to rule out the possibility of post-depositional mobility of metals, considering thermal maturities can exceed 4.5% Ro for Besa River sediments (Morrow et al., 1993). At that level of vitrinite reflectance, sediments are within the metagenesis to metamorphic grade of maturation (Mukhopadhyay, 1994). The association of organics and element mobility, notably trace elements, under metagenetic/metamorphic conditions is inadequately understood. Both Shaw (1954) and Ronov et al. (1977) found only minor changes of major and minor element concentrations up to siliminite grade metamorphism. In a more recent study, Haack et al. (1984) highlighted the depletion of trace metals (including Rb, Tl, Ba, Pb, Bi, Sr, Cd, Zn and Cu) of aluminous metapelites, with respect to element substitution in the main rock-forming silicates. Thermal maturation can result in a 40-60% reduction of organic carbon in fine grained sediments yet a loss of metals is not necessarily associated with this process (Raiswell and Berner, 1987). Abanda and Hannigan (2006) showed that the organic fraction contains up to 20% of the total trace element content in Ordovician shales, arguing the whole rock geochemical signature represents the diagenetic history as opposed to source area or depositional environment. Despite the likelihood that concentrations of some elements are reduced due to diagenesis/metamorphism, certain trace metals of Devonian— Mississippian sediments are enriched compared to AS (e.g. organo-metallic elements Re, 60 Se and U). Element remobilization during diagenesis normally results in the migration of trace metals (as a result of clay mineral transformations and reduction of Fe-Mn oxyhydroxides; Milodowski and Zalaskiewicz, 1991). Therefore we believe element EFs may be used to evaluate Devonian—Mississippian depositional environments. 2.5.1 Organic-rich black shales: Besa River and Muskwa formations 2.5.1.1 Anoxia Sulfidic bottom waters were relatively persistent during deposition of Muskwa, lower and upper Besa River sediments (Stotai ranging between 1.2 and 4.5%) and in part, explain TOC enrichments compared to AS. At times, water column conditions were euxinic during lower Besa River deposition as indicated by high Mo concentrations, low Re/Mo ratios and low Mn EFs. Under sulfidic conditions, Re, Se and Ag were effectively incorporated into the sulphide phases. Occasional oxygenation of the surface sediments is evident during Muskwa deposition by: 1) Mn enrichments in carbonate-rich sediments, indicative of an open marine environment and; 2) the depletion of anoxia-proxying elements in Mn-rich sediments (Ag, Re and Zn). Despite oxygenated conditions, TOC contents are not necessarily lower implying the rate of organic matter to the sea-floor controlled organic-accumulation. 2.5.1.2 Productivity Excess Si02 concentrations of lower Besa River and Muskwa sediments, coincident with high TOC and low Ti/Al ratios, suggest a biosilica-rich, bio-productive water 61 column was instrumental for the accumulation of organic matter and concentration of trace elements U, V, Ni, T1, Cd and Mo. A highly productive water column could have driven a productivity-anoxia feedback system, creating contemporaneous anoxic (to euxinic) and bio-productive environments (Ingall and Jahnke, 1997; Filippelli et al., 2003; Kidder and Worsly, 2004; Rimmer et al., 2004). Fine-grained sedimentary rocks rich in biosiliceous material are interpreted as deep and cold water in origin because most modern analogs are found in these conditions (Beauchamp and Desrochers, 1997). The Late Devonian depositional basin may have been connected to an ancient Arctic Ocean to the north (Stasiuk and Fowler, 2004), upwelling cold deep-water masses into the basin supplying biosiliceous material to the sea-floor. Trace elements U, V, Ni, Tl, Cd and Mo are typically invoked as redox-sensitive elements (Borchers et al., 2005; Brumsack, 2006), but low EFs in sulfidic upper Besa River sediment show sulphur-rich bottom waters were not the sole pre-requisite for element concentration. Uranium, V, Ni, Tl, Cd and Mo display micronutrient-like behaviour, akin to biosiliceous upwelling environments where a biologically active water column overlay anoxic bottom waters (Figures 2-16A and 2-16B; Martin et al., 1983). The strong coupling between organics and these elements can be attributed to element- scavenging by organic matter settling through the water column, in conjunction with benthic anoxia. An element pre-concentration in sea-water is required prior to deposition (Brumsack, 1986; Turgeon and Brumsack, 2006), similar to that described for diatom belts (Borchers et al., 2005). Since only 1% of the organic matter produced in the photic zone reaches the sea bottom (Muller and Suess, 1979), water column conditions and 62 Reductive dissolution • C Background' silicidastic sedimeritaion dose to AS Fe,0,, TiO,, K,0 ) Sulfide precipitation Enrichments of Re, Ag, Se and ZnPreservation of OM in sulfidic pore-watersTCC: 32 el% average E High siliddastic input ( AI,0,, Fe,0,, TiO,, KO ) Upper Besa River deposition: anoxic Fort Simpson deposition: oxic - dysoxic Golata deposition: oxic-dysoxic ices Biosiliceous material Organic matter •••• Clays 0 Coarse-grained detntus - - a. Movement/flux of material Bio-circulating water column Oit Organic matter A TM scavenging Oxyanion fixation Bosiliceous^U. V, Mo, Ni. 71, Cd, Cu ^ sedimentary environment^ .^----IA (high excess St0,) * • *^C^IIIMI 0' * .. C.' .■^MI^* C . ..^Low Ca0 0^* C * * Opwetling Mn • H,S Relatively tow siticidastic input (tow Alp,. FeO,,, T10,, K,O) Sediment starved ■^4 Intermittent euxinic conditions Mn^ 0, Water Sediment Preservation of OM in sultilic pore-waters TOO 2.9 wt% average Sulfide precipitation Enrichments of Re, Ag, Se and Zn Lack of bioaccumulation in water column V, Ni. TI, Cd, Mo, U, CU concentrations dose to AS Potential adsorption of organics onto days • Mod-high sedimentation rate and carbon flux • Low oxyanion fixation• Low CaO ■ Mn 0 Reductive dissolution Water e•mien H,S Upwelling Eliositiceous sedimentary environment^■ (mod to high excess Si0,) ■ ■ B Moderate silicidastic input ( AJ,0,, FeO., TO,, K,O dose to AS) Occasional CaO ennchment TM scavenging Oxyanion fixation U. V, Mo, Ni, TI, Cd, Cu Mn fixation Flux of organic matter I^■ Water Sediment Preservation of OM in sullictic pore-waters TOO 2.4 wt% average O J-CS Sulfide precipitation Enrichments of Re, Ag, Se and Zn Background' silicidastic sedimentaion dose to AS Fe,0,, TO,, K,0 ) Lack of bioaccumulation in water column V, Ni, -n, Cd, Mo, U, CU concentrations dose to AS Low OM flux Low oxyanion fixation Sediments enriched in Re and Se^• compared to AS^— — (sea-water concentrations?) 0,ennched bottom waters Water Sediment Non-sulfulic environment 70C; 0.3 wt% average Low CaO Lack of bioaccumulation in water column V, Ni, TI, Cd, Mo, U, CU concentrations dose to AS Efficient flux of OM to sea-floor ■ Coarser-grained detritus Enrichments of Nb, Th, Hf, La, Ti/ • Oxic bottom waters^r • • • °^° ^• k i.,*; • Water Sediment Lack of sutfidic pore-waters TOC: 2.8 wt% average ■ O, Lower Besa River deposition: anoxic - euxinic^ Mukswa deposition: primarily anoxic Figure 2-16. Models of sedimentary influences on Devonian—Mississippian sediment geochemistry: A) lower Besa River; B) Muskwa; C) upper Besa River; D) Fort Simpson; E) Golata. See text for discussion. 63 processes will to a large extent, dictate organic accumulations and organo-metallic associations. High export productivity is also inferred from elevated TOC/TN ratios (Twichell et al., 2002), most notably for lower Besa River sediments. Van Mooy et al. (2002) proposed that TOC/TN values reflect the degree of suboxic microbial degradation which preferentially utilize nitrogen-rich amino acids. Therefore organics circulating in the water column, under highly productive conditions, result in high TOC/TN ratios of the accumulated organic matter. Barium and phosphate are also used as paleoproxies for bio-productive/upwelling environments (Dymond et al., 1992; Glenn et al., 1994) but oxic to suboxic conditions are favourable for precipitation (Brumsack and Gieskes, 1983; Mimi, 1996). Besa River and Muskwa sediments are characterized by sulfate-depleted bottom waters, accounting for the absence of Ba and P2O 5 enrichment in these sediments. 2.5.1.3 Clastic influx/sediment supply Biogenic silica was an important contributor to lower Besa River and Muskwa sediments, making it difficult to interpret clastic influx based on simple Si/Al ratios. As such, other clastic influx proxies need to be examined (e.g. Al203, Ti/Al and K/Al; Wedepohl, 1971). Among the organic-rich sample suites, Al203 concentrations are higher in upper Besa River sediments, a reflection of significant siliciclastic influx. Clay-surface area may have provided physical protection to the organic matter through surface adsorption (Mackin and Bustin, 2002), enriching sediments with clays and organics (Figure 2-16C). 64 Relatively low concentrations of certain redox elements (U, V, Ni, Tl, Cd and Mo) in the organic-rich and sulphur-rich upper Besa River sediments can also be explained by sedimentation rates. Oxyanions tend to accumulate by diffusion at the sediment-water interface hence low sedimentation rates facilitate metal concentration as elements including U can have residence times of 1000-2000 years even in euxinic environments (Anderson, 1987). Higher EFRe in lower Besa River and Muskwa sediments, compared to upper Besa River sediments, may be due to the delivery of Re by organic detritus where slower sedimentation rates were optimal for adsorbing Re in conjunction with slow precipitation kinetics (Sunby et al., 2004). 2.5.2 Organic-lean grey shales: Fort Simpson Formation 2.5.2.1 Anoxia and productivity Organic-lean Fort Simpson shales are not enriched with any major or trace elements compared to AS except for Bi and Se. Relatively low TOC concentrations (0.26 wt% ay.) and Stotai contents (0.6% ay.) suggests Fort Simpson sediments were deposited under the presence of oxygen with neither a bio-productive water column nor high carbon flux (Figure 2-16D). The low supply of organic detritus to the sea floor is further emphasized by low TOC concentrations (<0.32 wt%) in Fort Simpson sediments with higher Stotal (samples FS947-1, FS1238-12 with >2% S 1total, • Data regarding Bi concentrations in fine-grained sediments is limited as sea-water concentrations are highly variable with depth (Bruland, 1983). Of the studies that are 65 available, Bi correlate with S (Heinrichs et al., 1980). However a Bi-S total association is not evident in Devonian—Mississippian sediments. The enrichments of Bi and Se may reflect sea-water concentrations during the Devonian—Mississippian as bio-accumulation or sulphide incorporation are not plausible explanations. Further investigations of Bi in modern marine setting are required. 2.5.3 Silty mudstones: Golata Formation 2.5.3.1 Anoxia and productivity Golata sediments, with TOC values averaging 2.8 wt%, have moderate—high EFs of TOC compared to AS. Total sulphur contents are low, as are concentrations of bio- productivity elements including Cd, Ge, and Tl. Re/Mo plots give no indication of oxygen depleted bottom waters. Therefore neither productivity nor preservation models can be applied to Golata sediments to explain organic carbon concentrations. 2.5.3.2 Sediment influx/clastic dilution Coarse-grained siliclastic dilution was significant during Golata sedimentation, as suggested by excess Si concentrations (attributable to detrital quartz), enrichment of Ti and detrital proxying trace metals Th, Zr (relative to sample set), Hf, La, Ce and Nb. Ti/A1 ratios have been shown to relate to the coarser-grained fraction of fine-grained sediments (e.g. Bertrand et al., 1996; Caplan and Bustin, 1996). It is suggested that the source of the quartz is eolian as heavy mineral fractions, of which Ti is representative, is 66 thought to be predominantly transported to marine sediments by wind (Boyle, 1983; Shimmield, 1992; Wehausen and Brumsack, 1999). Due to the insoluble nature of Th, Zr, Hf, La, Ce and Nb (Brookins, 1988), combined with their low sea-water/continental crust distribution (Taylor and McLennan, 1985) and diagenetic immobility, these elements are diagnostic of a distinct lithogeonous source terrain (Sugisaki et al., 1982). Enrichment factors are only slightly higher than AS (up to 2) suggesting terrigenous origin of the elements, close to AS composition. Rare earth element concentrations of Golata sediment may be additionally controlled by heavy minerals which may sequester and transport REE's from source terrain to basin deposition (e.g. Ti and La; Condie, 1991). The coarse-grained nature of the sediments and the concentrations of high-field strength elements suggest the flux of organic carbon to the sediment was important (i.e. carbon delivery flux and carbon burial efficiency; Tyson, 2001; Figure 2-16E). There would need to be a balance however, between delivery flux and carbon burial efficiency with sedimentation rate as high levels of siliciclastic dilution can have a detrimental effect on OM-preservation (e.g. <5 cm/ka; Tyson 2001). 2.6 CONCLUSIONS The compositionally diverse suite of Devonian—Mississippian shales and mudrocks provides an excellent insight to the sedimentological controls of a broad suite of major and trace elements. Through the application of geochemical proxies, it is evident that bio-accumulation played a key role in the concentration of Devonian—Mississippian 67 organic matter and certain trace elements. The following paleo-redox conclusions can be made: 1) Not all redox-sensitive elements are enriched in OM-rich, sulfidic sediments as shown by relatively low concentrations of U, Mo and V in upper Besa River sediments. This suggests that the conditions of the overlying water column (productivity) were also important for organic matter accumulation and trace metal sequestration during deposition of Muskwa and lower Besa River sediments. 2) More micronutrients were available during lower Besa River and Muskwa deposition, perhaps introduced by upwelling water creating a productive, biosiliceous sedimentary environment. A biogenic source to the silica is suggested by the excess Si02 in lower Besa River and Muskwa sediments. The sequestration of low crustal abundance elements Ti and Cd, along with Ni and Zn is related to biodetritus. 3) Bottom water conditions during Besa River (both lower and upper) and Muskwa deposition were oxygen depleted, which allowed the assimilation of Ag, Re, Se and Zn into the sediments as sulphides and permitted the export of Mn. Occasional oxygenation of Muskwa sediments is evident from Mn-enriched carbonate phases, yet TOC contents exceed 3 wt%. The co-occurrence of bottom-water oxygenation indicators and organic-enrichment suggests a high carbon flux to the sea floor (related to a biologically active overlying water column?). 68 4) Oxygenated conditions during Fort Simpson deposition precluded organic matter preservation, reflected geochemically by the lack of anoxic proxying elements. Siliciclastic dilution did not effect the accumulation of organic matter as suggested by comparable Al contents (and elements associated) with the conformably underlying Muskwa Formation and AS. 5) Sediments of the Golata Formation are indicative of high levels of both organic matter and coarse detritus influx. Bottom-water conditions were oxic and only detrital proxying/high strength field metals were concentrated into the sediments (e.g. Ce, Ta, Th, Ti, Zr). Our data show that bioproductivity, carbon flux and sedimentation rate, in addition to benthic anoxia, require consideration as controls on organic carbon accumulations. However the identification of a primary mechanism by which organic carbon is sequestered remains problematic due to the complex interrelationship of many oceanographic processes. 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Alberta Society of Petroleum Geology Map: Upper Devonian 345-359 m.y., p. 13. 86 CHAPTER 3 PREDICTING GAS CAPACITIES OF SHALE GAS RESERVOIRS: IMPORTANCE OF SHALE/MUDROCK COMPOSITION AND PORE STRUCTURE HETEROGENEITY 87 CHAPTER 3 Predicting gas capacities of shale gas reservoirs: importance of shale/mudrock composition and pore structure heterogeneity * 3.1 INTRODUCTION 3.1.1 Shale pore structure Understanding pore structure and sorption characteristics of organic-rich shales is important due to potentially significant gas contents of shale gas reservoirs (Montgomery et al., 2005; Bustin, 2005A; Pollastro, 2007; Ross and Bustin, 2007). In the Western Canadian Sedimentary Basin (WCSB) alone, shale gas resources are estimated to be >1000 trillion cubic feet (tcf; Bustin, 2005A). To reduce exploration risk and determine economic feasibility, knowledge of gas storage and transport mechanisms is required so producible resources can be quantified and long-term production behaviour be evaluated. However there is a lack of data in the literature which addresses the relationship between porosity, pore-size distribution and total gas capacity in shales. Resource evaluations are complicated by the structurally heterogeneous nature of fine-grained strata and their intricate pore networks, which are interdependent on many geologic factors including * A version of this chapter has been submitted for publication. Ross, D.J.K. and Bustin, R.M. Predicting gas capacities of shale gas reservoirs: importance of shale mudrock composition and pore structure. Marine and Petroleum Geology, in review. 88 total organic carbon (TOC) content, mineralogy, maturity and grain-size (Yang and Aplin, 1998; Dewhurst et al., 1999A; Dewhurst et al., 1999B; Ross, 2004; Ross and Bustin, 2007; Chalmers and Bustin, 2007A). In previous shale gas studies, sorbed CH4 capacities correlate with TOC (Manger et al., 1991; Lu et al., 1995; Ross and Bustin, 2007), although the reasoning for this relationship is unclear because the pore structure of liptinite macerals (marine organic matter) is poorly constrained. Chalmers and Bustin (2007A) reported an increase of CH4 sorption capacity with an increase in micropore volume for Cretaceous shales, akin to coalbed methane (CBM) reservoirs (Lamberson and Bustin, 1993; Crosdale et al., 1998; Clarkson and Bustin, 1999). Microporosity, which is positively correlated with TOC in shales (Chalmers and Bustin, 2007A), is a critical component of porous media (e.g. zeolites, activated carbons) due to large internal surface areas and greater sorption energies of sub 2 nm pores compared to larger pores of solids with similar composition (Dubinin, 1975). In an attempt to elucidate the complex pore structure of shales, researchers have utilized low pressure N2 sorption isotherms, He pycnometry and Hg porosimetry (Katsube and Williams, 1994; Yang and Aplin, 1998; Katsube et al., 1998; Eseme et al., 2006). Pore size distributions of shales and mudrocks are also reported under variable confining pressures to better understand hydraulic conductivity/permeability and sealing efficiency (i.e. cap rock). Sealing efficiency has been found to be dependent on clay mineral surface area (Yang and Aplin, 1998; Dewhurst et al., 1999A). Aluminosilicate phases can have nanometre scale pore structures (hence large surface area; Aylmore and Quirk, 1967; Lloyd and Conley, 1970; Aylmore, 1974; Fripiat et al., 1974; Gil et al., 89 1995; Altin et al., 1999; Aringhieri, 2004; Wang et al., 2004) and may provide sorption sites for CH4 in addition to the organic fraction (e.g. Manger et al, 1991; Lu et al., 1995, Cheng and Huang, 2004). 3.1.2 Coals as analogues Shale gas and CBM reservoirs are informally grouped as unconventional or non conventional because gas is trapped by sorption processes in low permeability strata (Law and Curtis, 2002). Geologic controls on CBM reservoir capacities are well documented. Important coal properties include maceral type (Lamberson and Bustin, 1993; Crosdale et al., 1998), ash content (Laxminarayana and Crosdale, 1999), rank (Clarkson and Bustin, 1999; Laxminarayana and Crosdale, 1999; Laxminarayana and Crosdale, 2002; Hildenbrand et al., 2006), moisture (Joubert et al., 1974; Unsworth et al. 1989; Levy et al., 1997) and temperature (Bustin and Clarkson, 1998; Azmi et al., 2006). Crosdale et al. (1998) argued maceral type and rank are critical factors controlling gas sorption because of their influence on pore structure and consequently the sorption process. Chalmers and Bustin (2007B) showed that high pressure solubilization of CH4 was responsible for large gas capacities of liptinite-rich coals (bituminite and gilsonite). Mastalerz et al. (2004) found no relationship between liptinite content in coal and gas sorption which we attribute to the low concentrations of marine organic matter in the coals they examined. 90 Although previous studies have provided useful insight to CH4 sorption in organic-rich strata, direct comparisons of sorption characteristics between coals and shales may be of limited use due to physio-chemical differences that include: 1) type of organic matter: coals are typically enriched in vitrinite/inertinite macerals as oppose to liptinite-rich shales 2) % organic matter 3) % mineral matter 4) porosity (total pore volume and pore-size distribution) The objective of this study is to determine the sorption characteristics of marine shales in relation to pore volume distribution. Results and discussions presented here will aid reservoir model estimates of total gas resources and provide insight to the release of CH4 from shale matrices to predict gas transport. In this chapter, the effects of various shale attributes (organic/inorganic composition, maturity) on pore structure and high pressure CH4 sorption are examined. 3.2 METHODS 3.2.1 Samples and preparation A suite of Jurassic and Devonian—Mississippian (D—M) shales from northern British Columbia, western Canada, were chosen for this study. These shales are currently being explored as shale gas reservoirs. Jurassic samples were taken from the organic-rich Gordondale Member (from Ross and Bustin, 2007). Devonian—Mississippian samples 91 are taken from the organic-rich Muskwa and Besa River formations and the organic-lean Fort Simpson Formation. The Besa Formation is subdivided into three informal units (Ross and Bustin, in review): 1) lower black mudrock (LBM) member; 2) middle shale member (MS) and; 3) upper black shale (UBS) member. The LBM and UBS members are examined in this study. Gordondale Member shales were included in this study due to high TOC and wide ranges of thermal maturity compared to D—M shales (Ross and Bustin, 2006; Ross and Bustin, 2007). Hence these sediments provide additional insight to the relationship between organic matter and shale micropore structure. The affect of mineralogy upon pore size distribution (Hg porosimetry) and total pore volume for Gordondale Member shales is discussed in Ross and Bustin (2007), and therefore not included in this chapter. To investigate the effect of inorganics upon shale pore structure, pure clay mineral standards of illite (IMt-2), kaolinite (KGa-lb) and chlorite (clinochlore, CCa-2), representative of the clay minerals of shales analyzed in this study) and Na-saturated montmorillonite (SWy-2) were obtained from the University of Missouri-Columbia Source Clay Minerals Repository. The pore structure of Devonian chert (northern British Columbia) was also analyzed to assess the impact of biogenic silica on pore structure since silica in Muskwa and LBM samples is argued to be biogenically-sourced (Ross and Bustin, in review). Samples of 150 g were crushed to <250 pm for high pressure CH 4 sorption analysis. A split of approximately 0.2 g was used for low pressure isotherm analysis (CO2 and N2 surface area measurements), and 18 g for high pressure Hg porosimetry. Crushed 92 samples were utilized for qualitative petrographic analysis. Due to the required degassing of samples prior to pore structure analyses (CO 2 and N2 low pressure sorption, Hg porosimetry), pore structure data is reported on a dry basis. Samples were oven dried for 24 hours at 110 °C. High pressure CH4 isotherms were conducted on dry and moisture equilibrated samples. Moisture equilibration of shale samples followed the American Society for Testing and Materials (ASTM) procedure (ASTM D1412-04, 2004). It may seem counter-intuitive to compare analyses for dry and moisture equilibrated samples as moisture acts as a dilutent to gas sorption (Yee et al., 1993) and its effects cannot easily be isolated. However the good correlation between CH4 sorption capacity under dry and moisture equilibrated states (Figure 3-1) suggests meaningful comparisons can be made. The controls on moisture contents and its effect on sorption capacity in shale gas reservoirs will be addressed in a future paper. 3.2.2 Low pressure CO2 and N2 isotherm analyses Low pressure CO2 and N2 isotherms are used to describe the pore space of organic-rich, microporous materials as average pore-size distributions are in the nanometre scale, into which gases can effectively penetrate (Gan et al., 1972; Lamberson and Bustin, 1993; Larsen, 1995; Clarkson and Bustin, 1996; Levy et al., 1997; Bustin and Clarkson, 1998; Clarkson and Bustin, 1999; Prinz and Littke, 2005; Chalmers and Bustin, 2007). Carbon dioxide and N2 sorption analyses were performed using a Micromeritics® ASAP 2010 surface area analyzer. Carbon dioxide sorption was calculated over a pressure range of 93 4.5 ♦ D-M ^ Jurassic — Linear (D-M ) — — Linear (Jurassic) 4- a) 3.5 - 3 -a •0— • 2.5 - a: a_ 2 - cocc 0) 1.5 - -a a) • 10 0.5 - 0 • ♦ R2 = 0.81^^ • • •R2 = 0.8 •••• .0" •••• • • 00' .00'^^ • • .0* • 0 .0* ..••• •••• 0 0^0.5^1.0^1.5^2.0 ^ 25 Sorbed gas capacity (moisture EQ; cc/g) Figure 3-1. Correlation between sorption capacities (cc/g) of moisture equilibrated and dry shales examined in this study (D—M = Devonian—Mississippian). 94 4x10 -4 to 3.2x10 -2 at 0°C and monolayer capacities were determined using the Dubinin- Radushkevich (D-R) equation (Gregg and Sing, 1982): log V = log Vo — S log e where V is the volume of sorbed gas at equilibrium pressure (cm3g, -I , s.t.p.), Vo is the total micropore volume (cm 3g, -1 , s.t.p.), S is a constant, P is pressure and P o is saturation vapour pressure. Micropore volumes were calculated using 17x10 -20 m2 for the cross sectional area of the CO2 molecule. Micropore volumes are reported as volume per 100 g (cc/100 g). Nitrogen surface areas were measured at -196.15°C and calculated using the BET (Brunauer-Emmett-Teller) method in the 0.06-0.2 relative pressure range, following the equation (Brunauer et al., 1938): 1/W((P0/P)-1) = 1/WmC+C-1/WmC(P/P0) (2) where W is the weight of the sorbed gas at relative pressure P/P o, Wm is the weight of the monolayer adsorbent (N2), C is the BET constant which relates to the sorption energy between adsorbent and adsorbate. (1) 95 3.2.3 High pressure Hg porosimetry Mercury intrusion data were collected on a Micromeritics® Autopore IV 9500 Series. Pressure of Hg was increased continuously from 0.013 to 430 MPa and pore size distributions were determined using the Washburn equation (Washburn, 1921): D = — 47 cos° P (3) where D is the pore diameter, y is the surface tension, 0 is the contact angle and P is the applied pressure. A contact angle of 130° (Gan et al., 1972) and surface tension of 485 dyn/cm (Gregg and Sing, 1982) were used. Total pore volumes were calculated from Hg intrusion data. 3.2.4 High pressure CH4 isotherm analysis High-pressure CH4 sorption isotherms at 30°C were collected using a volumetric Boyles Law apparatus. Sorbed gas capacities were calculated from the Peng-Robinson equation of state. The isotherm equation used to model CH 4 sorption is the Langmuir isotherm (Langmuir, 1918): P=  1^P+ V BV„, Vni (4) 96 where P is the equilibrium gas pressure, V is the volume of gas sorbed, V„, is the Langmuir monolayer volume and B is an empirical constant. According to the Langmuir sorption theory, a plot of P vs. PN produces a straight line and the reciprocal of the slope of the fitted-line relates to the CI-14 monolayer volume. 3.2.5 Geochemical and imaging analyses Fifteen to twenty-five milligrams of powdered D—M shale and Jurassic samples were analyzed for total carbon (TC) using a Carlo Erba® NA-1500 Analyzer (precision of ±2%). Inorganic carbon concentration (IC) values were generated from a CM5014 CO2 coulometer with a precision of 2%. Total organic carbon values were determined by subtracting total inorganic carbon from total carbon values (TOC = TC-IC). Major elements SiO2, Al203 and CaO were determined by X-ray fluorescence spectrometry, the precision of results are ±3% (Ross and Bustin, in review). These major oxides are representative of the main mineral phases: quartz, clays and carbonate. Aid-dried rock chip samples (2-3 mm) were gold coated and examined with a Philips XL-30 scanning electron microscope (SEM) with a Princeton® Gamma-Tech PRISM IG energy-dispersive spectrometer. 97 3.3 RESULTS 3.3.1 Shale composition and fabric Total organic carbon contents of D—M shales (Besa River, Muskwa and Fort Simpson formations) range between 0.9 and 4.9 wt% (Table 3-1). Jurassic Gordondale shales have a wider range of TOC than D—M shales, between 3 and 38 wt% (Table 3-2). The organic fraction is dominated by maceral assemblages of granular micrinite (Figure 3- 2A, D—M samples) and matrix bituminite (Figure 3-2B, Jurassic samples; Stach et al.,1982; Teichmiiller, 1986). Micrinite, of which bituminite is the progenitor (Stach et al., 1982), interpreted as the residual organic matter after oil generation and expulsion (Teichmiiller and Ottenjann, 1977). Muskwa and LBM member samples are enriched with either silica or carbonate (Table 3-1). High silica concentrations are attributable to quartz content which accounts for 58- 93% of the bulk mineralogy (Ross and Bustin, in review). Carbonate minerals are calcite and dolomite. Upper black shales of the Besa River Formation and Fort Simpson shales have a bi-modal composition between silica and aluminosilicates. The aluminosilicate fraction of the UBS member is dominated by illite and kaolinite, whereas Fort Simpson shales have equal concentrations of illite, kaolinite and chlorite (Chapter 5). The majority of Jurassic shales are aluminosilicate-lean, silica- and/or carbonate-rich (Table 3-2) with quartz and calcite occurring as the main mineral phases (Ross and Bustin, 2007). Scanning electron microscope observations of quartz-rich shales (e.g., LBM member) 98 Sample ID TOC* we/. Porosity* `Ye BET Pore structure/surface area data N2^ CO2 surface area^micropore volume m218 cc/100 g CO2 equivalent surface area m2ig Moisture wt% Sorbed gas capacity moisture EQ^dry cc/g @ 6 MPa^cc/g @ 6 MPa Inorganic composition data* Al203^S102^Ca0 %^%^% MU1416-1 2.1 4.4 19.5 0.8 28.9 3.2 0.9 2.1 17.5 64.1 0.8 MU1416-4 1.7 2.22 10.1 0.6 23.7 3.5 0.7 - 14.7 65.8 0.7 MU1416-7 2.1 2.2 9.1 0.8 29.2 3.5 1.2 2.2 12.7 68.6 0.6 MU1416-9 0.4 1.42 3.4 0.3 11.1 2.5 0.2 0.6 1.7 5.5 44.6 MU714-3 1.6 0.95 10.5 0.5 18 8 1.9 0.7 1.7 7.2 36.6 16.4 MU414-1 3.7 3.7 10.7 1.0 36.7 3.1 0.8 - 9.9 73.5 0.6 UBS-C15-1331-1 1.4 5.4 16.8 0.5 19.1 2.4 0.3 1.6 9.9 78.3 1.2 UBS-C15-1331-5 4.0 6.0 44.5 1.3 47.2 4.1 1.6 3.2 16.9 60.7 0.6 UBS1331-4 4.0 7.2 29.3 0.9 32.9 4.9 1.2 3.0 23.0 47.3 1.2 UBS1331-5 4.9 5.1 20.0 1.0 38.3 4.4 1.3 3.5 24.1 50.9 0.6 UBS1331-6 4.7 5.2 31.0 1.2 44.7 4.1 1.6 4.0 22.3 45.1 1.2 UBS1331-11 3.8 4.6 22.3 0.8 29.8 5.2 0.8 3.0 22.9 48.0 0.8 LBM325-1 2.0 1.2 10.3 0.5 17.6 1.6 0.6 - 5.7 82.4 0.8 LBM325-5 2.1 1.3 12.8 0.5 18.2 1.8 0.7 1.6 9.6 78.9 0.3 LBM325-7 0.9 0.35 5.5 0.3 9.5 1.5 0.3 - 3.0 30.0 19.4 LBM2563-1 4.8 1.6 16.3 1.0 37.6 1.4 1.6 - 5.9 80.7 1.2 LBM2563-3 4.4 2.1 12.4 0.8 29.7 1.8 1.2 2.6 6.3 80.2 1.2 LBM2563-5 2.8 0.8 13.9 0.6 21.9 2.3 0.8 - 6.6 82.4 0.5 LBM2563-7 2.5 1.1 12.3 0.7 25.6 1.9 0.9 1.8 7.9 79.4 0.8 FSS1416-1 0.3 2.6 13.6 0.5 18.0 4.8 0.2 1.4 19.5 56.6 1.7 FSS1416-5 0.2 2.94 15.0 0.5 18.6 3.3 0.1 1.4 19.2 55.5 1.8 FSS5245-1 0.3 4.3 20.5 0.6 22.3 3.1 0.1 0.6 19.2 61.0 0.4 FSS12140-6 0.3 3.9 24.7 0.8 29.5 2.8 0.4 1.7 19.8 59.1 0.5 FSS1238-1 0.3 2.43 10.4 0.4 15.9 2.5 0.1 1.1 20.6 56.6 1.0 FSS947-3 0.2 1.9 11.3 0.4 14.9 2.4 0.3 1.2 12.9 40.4 17.0 Table 3-1. Composition, surface areas and sorption capacities of D-M shales. Total organic carbon (TOC) contents, equilibrium moisture contents (moisture), pore characteristics (total porosity, CO 2 micropore volume and N2 BET surface area) and sorbed gas capacities (moisture equilibrated and dry-state) are provided. Also shown are the three major oxide groups Si0 2 , Al 20 3 and CaO, representing quartz, clay and carbonate mineral phases respectively (* data from Chapter 2). Dashes show unavailable data. Sample ID TOC* wt./0 Porosity* % BET Pore structure/surface area data N2^ CO2 surface area^micropore volume miig cc/100 g CO2 equivalent surface area m2ig Moisture* wt% Sorbed gas capacity moisture EQ^dry cc/g @ 6 MPa^cc/g 0 6 MPa Maturity data* Tmax °C Inorganic composition data* Si02^Al203^Ca0 04^%^04 N5378-11 1.6 - 9.3 0.6 21.9 - - - - N8354-11 26.6 0.0 0.5 19.4 - - - - - - - N8354-4 37.8 - 1.6 0.6 23.7 - - - 446 24.8 5.4 26.8 N376-1 1.4 0.5 0.6 0.2 6.2 0.7 0.1 0.4 494 18.8 3.2 24.5 N2557-2 3.1 2.6 1.8 0.2 8.4 2.3 0.1 442 65.0 4.0 6.7 N6080-1 4.3 2.8 2.8 0.5 18.5 8.5 0.3 0.4 462 54.9 15.2 1.2 N3773-2 5.0 0.5 6.3 0.8 28.8 1.8 1.2 2.1 608 63.9 5.8 8.6 N89-1 5.2 0.8 2.8 0.3 12.7 1.6 0.5 1.2 457 16.8 5.5 35.0 N230-1 7.1 2.2 1.5 0.3 11.4 2.5 0.6 1.3 447 42.7 11.3 14.3 N3793-1 9.0 - 1.7 1.1 40.3 2.8 2.0 3.6 607 47.3 8.5 13.8 N49-2 10.0 1.5 2.8 0.6 23.4 2.3 1.5 2.0 461 38.0 7.6 18.2 N91-1 10.2 4.2 2.3 0.4 15.3 0.6 1.0 1.3 467 62.9 1.0 11.5 N174-1 11.8 - 1.2 0.4 16.1 1.7 1.6 1.6 459 61.0 1.3 11.7 Table 3-2. Composition, surface areas and sorption capacities of Jurassic shales. Included are Tmax values (and vitrinite reflectance equivalent, % Ro) representing thermal maturation levels (*data from Ross and Bustin, 2007). Figure 3-2. Major macerals of the shales examined in this study. (A) Granular micrinite of D—M shales in normal reflected light (Stach et al., 1982); (B) matrix bituminite of Jurassic shales after blue-light excitation (Stach et al., 1982; Teichm011er, 1986). Scale bar = 50 pm. 101 show no distinct bedding or fabric (Figure 3-3A, B and C). Quartz grains are typically less than 5 gm in size. Clay-rich shales (e.g., UBS member) show a moderately orientated clay microfabric, with locally disrupted planar clay grain arrangement by coarser silt grains (Figure 3-3D). 3.3.2 Low pressure CO2 analyses - shales Low pressure D-R CO2 isotherms of Muskwa and Besa River shales yield micropore volumes which positively correlate with TOC (Figure 3-4A). Organic-lean Fort Simpson shales have micropore volumes between 0.4 to 0.79 cc/100 g but sorbed CO2 capacities are independent of TOC (Figure 3-4A), implying factors other than the organic fraction influence micropore structure. Jurassic shale micropore volumes range from 0.2 to 1 cc/100 g and show no consistent variation with organic content (r 2 = 0.06; Table 3-2, Figure 3-4B). 3.3.3 Low pressure N2 analyses — shales Low pressure N2 isotherms for Jurassic and D-M shales are Type II (Figure 3-5), following the classification of Brunauer et al. (1940). Type II isotherms are interpreted of being due to micropore filling at low pressures and multilayer sorption at higher pressures, which suggests some pores are mesoporous (Gil et al., 1995). 102 Figure 3-3. Scanning electron microscope images of shales examined in this study. A-C) Quartz-rich shales of o^ the LBM member under various magnifications — note lack of fabric. D) Clay-rich UBS member sample — notet.,.) planar microfabric of clay lamina. 0.0 0 2 3 4 5 6 1.4 I A t x = 0.91^R2 = 0.79 0 6 - 0. 2 0 4 -•_ O • 0.2 - • • • A • A ♦ Muskwa X Besa River ♦ Fort Simpson •—• Linear (Muskwa) — — Linear (Besa River) 1.2 C) O O ZS• 0.8 7, • 0.6 O 0_ 0.4 64 0.2 2 _ 1.0 - ^ 0 ^ ^ 0 ^ 1'2=0.06 0.0 0 ^5^10^15^20^25 ^ 30^35 ^ 40 TOC (wt%) Figure 3 -4. (A) Relationship between micropore volume and TOC for D—M shales. Note good correlation for Muskwa and Besa River samples and poor correlation for organic-lean Fort Simpson shales (r2 = 0.4, not shown). (B) Variation in micropore volume with TOC for Jurassic shales. 104 Nitrogen BET surface areas of Besa River and Fort Simpson shales increase with increasing CO2 micropore volumes, ranging between 5.5 and 44.5 m 2/g (Table 3-1; Figure 3-6). The relationship between BET surface area and micropore volume for Muskwa shales is inconclusive (r2 = 0.27). Nitrogen BET surface areas of Jurassic shales are invariably smaller than D—M shales, varying from 0.04-9.3 m 2/g (Table 3-2), and do not correlate with micropore volume (r 2 = 0.07). 3.3.4 Low pressure CO2 and N2 analyses — inorganics Micropore volume and surface area analyses for clay standards and chert are provided in Table 3-3. Carbon dioxide micropore volumes are larger for illite (0.79 cc/100 g) and montmorillonite (0.78 cc/100 g) than kaolinite (0.27 cc/100 g) and chlorite (0.13 cc/100 g). Nitrogen BET surface areas range from 4.8 m2/g (chlorite) to 29.4 m2/g (illite), correlating with micropore volume. Chert has a small CO 2 micropore volume (0.08 cc/ 100 g) and N2 BET surface area (0.35 m2/g). 3.3.5 Total pore volume and Hg porosimetry Cumulative pore volumes, in the diameter range of 3-360,000 nm, increase with increasing aluminosilicate content. Clay-rich UBS samples have average porosities of 5.6% whereas high silica (quartz), low clay content LBM samples have average porosities of 1% (Table 3-1). Average pore-size distributions skew towards smaller pores with increasing clay content and decreasing quartz content (Figure 3-7). Clay-rich 105 45 40 - - o- FSS5245-1 -a- FSS12140-6 FSS1238-1 a) E 15 10O 5 0 - o- MU414-1 -o- M U714-3 -a- LBM2563-3 - UBS-C15-1331-5 0^0.1^0.2^0.3^0.4^0.5^0.6^0.7^0.8^0.9 45 40 - I C I U) 35 .0 30- 3 25 - O 20 0 4'.'erom*-1••=6.1-7=69-66.1-r=1,17=6,1-1=a1=41=itEtFtF1,11"6156) • 20 - 0 • 15 -m E O • 1 0 ---N230-1 -13- N91-1 - N49-2 B 0^0.1^0.2^0.3^0.4^0.5^0.6^0.7 ^ 0.8 ^ 0.9 Relative Pressure (p/p °) Figure 3-5. Low pressure, low temperature (-196.15°C) N2 isotherms. (A) Organic-rich Muskwa and Besa River shales; (B) Organic-lean Fort Simpson shales; (C) Organic-rich Jurassic shales. 106 1.4 1.2 - ♦ D-M: Muskwa x D-M: Besa River ♦ D-M: Fort Simpson x x ♦ X ♦ X A w 0.6 - 8 0. O 0.4 - E C7 0.2 - 0 X^•• • X A • • • x 0^5^10^15^20^25^30^35 ^ 40 ^ 45 ^ 50 N2 BET surface area (m2/g) Figure 3-6. Correlation between CO2 micropore volume and N BET surface area for D—M shales (Fort Simpson r2 = 0.95; Besa River r2 = 0.69; Muskwa rL = 0.27). 107 Pore structure/surface area data N2^ CO2 BET surface area^micropore volume m 2/g cc/100 g CO2 equivalent surface area rn zig Moisture wt% Sorbed gas capacity moisture EQ^dry cc/g @ 6 MPa^cc/g @ 6 MPa Clay Minerals IIlite 30.0 0.8 29.4 5.9 0.4 2.9 Montmorillonite 24.7 0.8 28.3 19.0 0.3 2.1 Kaolinite 7.1 0.3 9.8 2.9 0.7 0.7 Chlorite 2.1 0.1 4.8 0.8 Cited 0.4 0.1 3.12 0 Table 3-3. Results of pore structure (CO 2 micropore volume and N2 BET surface area), moisture and sorbed gas capacities of clay mineral standards and chert. shales have unimodal pore diameters of 7-8 nm, in contrast to silica-rich shales and chert (Figure 3-8) which show a dominance of pores >10,000 nm. Assuming surface areas calculated by Hg injection are primarily a function of meso- macropores (>3 nm diameter; Webb and Orr, 1997), mesopores for N2 analyses (>2 nm; Unsworth et al., 1989; Rouquerol et al., 1994) and micropores for CO 2 analyses (<2 nm; Marsh, 1989), the contribution from various pore-sizes to cumulative specific surface area can be approximated. There is a small amount of surface area associated with pores >15 nm in D—M shales (Figure 3-9A). Between 24-26% of the total surface area occurs within pores >3 nm for clay-rich, high-porosity UBS samples compared to 2-12% for quartz-rich, low-porosity LBM samples. Carbon dioxide surface areas are >N 2 surface area for D—M shales. Jurassic shales have comparable Hg and N2 surface areas, and pores >3 nm account for up to 58% of the total surface area (Figure 3-9B). Carbon dioxide surface areas are significantly >N 2 surface areas, which may reflect the high solubility coefficient of CO2 in the matrix bituminite of Jurassic shales (Reucroft and Patel, 1983). Nitrogen BET surface areas of D—M shales correlate with total porosity (Figure 3-10) whereas the correlation between CO 2 micropore volume and total pore volume is poor (r2=0.2). No relationship between total porosity, BET surface area and micropore volume could be determined for Jurassic shales. 109 0002 Macropore Mesopores540z = 80.2 % A1,03 = 7.3 % TOC = 2.2 wt% Av 0= 1.1% - 0.0018 - 00016 5 - 0.0014 - 0.0012 5 3 - 0.001 -8 2u. - a000s 0 - 00006 0.0004 - 00002 0 0.0012 = 69.7 % 6120 3 = 7.8 % TOC = 2.8 wt% Av 0 = 2.9% - 0.001 a - 0.0008 00006 2 0 - 0.0004 a 3 - 0.0002 (a. 0 1.E+06 ^ 1.E+05 ^ 1.E+04 ^ 1.E+03 ^ 1 E+02 ^ 1.E+01 ^ 1.E+00 1.E+06 ^ 1.E+05 ^ 1 . E + 0 4 ^ 1.E+03 ^ 1.E+02 ^ 1.E+01 ^ 1.E+00 ^ 0.0045 - 0.004 - 0.0035 47 0.003 7 - 00025 - 0.002 O - 0.0015 7 3 - 0.001 to - 00005 ^ 0 1.E+001.E+06^1 E+05^1.E+04^1.E+03^1.E+02 ^ 1.E+01 5102 = 57.1 % Al 203 = 19.5 % TOC = 3.3 wt% Av0=6.6% Pore size diameter (nm) Figure 3-7. Relationship between shale composition (quartz and clays), total porosity (0) and pore-size distribution for D-M shales. Major element geochemistry and total porosity are an average for the samples shown. High silica content shales (top) are tight with low total pore volume. As aluminosilicate fraction increases, porosity increases and modal pore size distribution shifts towards mesopores (microporosity associated with the organic fraction cannot be penetrated by Hg). Decreasing SiO 2 Increasing Al 20, 110 0.00014 Macropores Mesopores - 0.00012 1.E+06 •^ 1.E+05^1.E+04^1.E+03^1.E+02 Pore size diameter (nm) F - 0.0001 CD "..g - 0.00008 5) 79, -0 r4. 0 FO) - 0.00006 0) 0 - 0.00004 3 r- - 0.00002 0 1.E+00 • •^• •yaw 1.E+01 Figure 3-8. Mercury incremental intrusion vs. pore diameter for chert. Note comparable pore- size distributions to silica-rich LBM samples. 111 ^Hg SAI^ ^I N 2 SA I^ ? - --ICO2 SA I-- A 50 45 - 40 - • 12 • 10- • g_ x X 1 I 0 - X i 4- it) x -t) - 2 - tr. 1/4144.0**„............40_,_,_,,,_. 0 1.E-01^1.E+00 1.E+01^1.E+02^1.E+03^1.E+04^1.E+05^1.E+06 0 • 9 0 t<i% porosity[—.6, 13 35 - NE 30 - co 43" 25 - a) t c.) co 20 - (6 15- 10 - 5 - X X 0 A 14 6% porosity( t :A AL Nic n Ei n n El 1:1^CI 1.E+00^1.E+01^1.E+02^1.E+03^1.E+04 Pore size diameter (nm) 0 1.E-01 A 1.E+05 1.E+06 Figure 3-9. Comparison of cumulative surface areas calculated using various techniques (low pressure CO 2 and N2 sorption, high pressure Hg porosimetry). (A) D–M shales: most surface area is associated with pores <10 nm in diameter (SA = surface area). A significant proportion is in pores with pore throat diameters less than 2 nm. Inset show surface area associated with pores >3 nm diameter. N B N, SA ?-4c- - - CO, SA I-- 1 .E+061.E-01^1.E+00 1.E+04^1.E+051 .E+01^1.E+02^1.E+03 30 x 25 - • ,A4titt,1111111f • 5 0 S1^IBMS final; a Pore size diameter (nm) F--{Hg SA Î Figure 3-9 cont. (B) Jurassic shales: similar to D—M shales, most surface area is associated with pores <10 nm in diameter. Inset show surface area associated with pores >3 nm diameter. a) 35 - 03 CD 30- 25- 20- Cl) I- LU 15 - CO i 1 1 0 - 0 ^ 1 ^ 2 ^ 3^4^5 ^ 6 ^ 7 ^ 8 Total porosity (%) Figure 3-10. Moderate correlation between N2 BET surface area and total pore volume suggesting total porosity is influenced by the mesopore structure of D—M shales. 114 3.3.6 High pressure CH4 analyses High pressure CH 4 sorption capacities of Jurassic and D—M shales correlate with TOC (moisture-equilibrated and dry samples), although the correlation is significantly weaker for Jurassic shales (Figure 3-11). Sorbed gas capacities under moisture equilibration conditions range from 0.1 cc/g for organic-lean shales to 2 cc/g for organic-rich shales. In the dry-state, sorbed gas capacities range from 0.4 cc/g to 4 cc/g. Devonian— Mississippian shales show a positive correlation between TOC, micropore volume and sorbed CH4 capacity (Figure 3-12A), highlighting the structured, microporous nature of the organic matter. A relationship between TOC, micropore volume and sorbed CH4 capacity for Jurassic shales is not evident (Figure 3-12B). Sorbed CH4 capacities of dry and moisture-equilibrated and illite, montmorillonite and kaolinite vary significantly. On a dry-basis, illite and montmorillonite have larger sorption capacities than kaolinite (Figure 3-13); a result of greater micropore volume and surface area (Table 3-3). However kaolinite sorbs more CH4 on a moisture equilibrated basis, a consequence of low moisture content (2.9 wt%) compared to illite (5.9%) and montmorillonite (19%). 115 ^2- 0 10 ^ 12 ^ 140 ^ 2 ^ 4 • D-M: Muskwa Formation x D-M: Besa River Formation ♦ D-M: Fort Simpson Formation ^ J: Gordondale Member 2.5 C) 0 • •♦ x • x ^ ^x 3X ♦ 4 ♦ • ^ ^• ^ ^ ♦X^ ♦ ♦ â ^k* 0 ^ X 1 ' 0 ^ ^ 6^8 TOC (wt%) 14 1.5— cv o. co 0 Figure 3 -11. Correlation between TOC and methane sorption capacity of moisture-equilibrated D—M and Jurassic shales. Diagonal line highlights the ratio difference of methane sorption to TOC (Jurassic shales: r2 = 0.38; Fort Simpson shales: r2 = 0.46; Muskwa and Besa River shales: r2 = 0.8). 116 1.8 1.6 a) • 1.4 1.2c.)co ad 1.0 c.) rt 0.8a) -0 0.6a) 0 0.4 co 0.2 0.0 1.2 1.0 ...cr^0.8 opor_^0.6 0.4 m/livo —e (cc/100 w 0.2 O Muskwa Formation • Besa River Formation • Fort Simpson Formation Figure 3-12. Three-dimensional plots relating TOC and micropore volume with sorption capacity. (A) D—M shales. Note importance of microporous organic material upon gas sorption capacities. 117 Figure 3-12 cont. (B) Jurassic shales. 118 0 • • 3.5 Illite 3 0 - Montmorillonite • • • • • 0 0.5 - ^ • • • • • • • • • • • • • • • • Kaolinite • 0.0 0 ^ 2 ^ 3^4^5 ^ 6 ^ 7 ^ 8 Pressure (MPa) Figure 3-13. Sorption isotherms (at 30°C) for clay standards (dry-basis). 119 3.4 DISCUSSION: DEVELOPING A PORE STRUCTURE MODEL Due to dissimilarities and heterogeneities of their pore structures, Jurassic and D—M strata are discussed separately. In the following sections, the effect of: 1) organic matter abundance and type and; 2) mineral matter, upon pore structure and total pore volume are discussed. 3.4.1 Sorption characteristics and organics: Jurassic strata Jurassic shales are organically-richer than D—M shales but do not show an increase of CO2 microporosity or N2 BET surface area with TOC. The ratio of micropore surface area to TOC is lower for Jurassic shales, averaging 4.2 compared to 8.6 for D—M shales. Thus despite the relative importance of organic carbon to sorption capacity (Figure 3-10), the influence of TOC upon micropore structure is not as apparent in Jurassic shales, perhaps reflecting the amorphous character of matrix bituminite which comprises a large percentage of the TOC. Significant quantities of CH4 are stored within organic-rich Jurassic shales, in spite of small micropore volumes, because CH4 may be solubilised within the matrix bituminite (analogous to solute methane within semi-solid bitumen; Svrcek and Mehrotra, 1982). For example, sample N174-1 sorbs over 300% more CH4 than N89-1, but N174-1 has only 20% more micropore volume (Table 3-2; Figure 3- 11 B). The difference in gas capacity is attributable to TOC, which is volumetrically more significant in N174-1 (11.8 wt%) than N89-1 (5.2 wt%), and provides an additional gas storage mechanism (as a solute in the bituminite) to the gas physically adsorbed onto micropore surfaces. 120 A solute gas component in Jurassic samples is indicated by the linear correlation between pressure and sorption capacity (Figure 3-14). Typically, high pressure sorption experiments of microporous materials result in Type I isotherms (as described by Brunauer et al. 1940) due to gas saturation at higher pressures from the completion of a monolayer. Type I isotherms are not indicative of some Jurassic samples as the gas storage process follows Henry's Law (Duffy et al, 1961), where the concentration of solute gas is directly proportional to the partial pressure of that gas above the solution. The inability of CO2 and N2 to go into solution (reflected by moderate CO2 micropore volumes and low N2 BET surface areas of some high TOC samples) is an artefact of the low-pressure analyses in contrast to the high pressure CH4 analyses. 3.4.2 Sorption characteristics and organics: Devonian—Mississippian strata Sorption capacities and micropore volumes of D—M shales increase with TOC, highlighting the greater sorption energy of smaller pores within the organic fraction (Burggraaf, 1999). Nitrogen BET surface areas are covariant with CO2 micropore volume suggesting high-sorbing samples are both micro- and mesoporous. Gan et al. (1972) argued N2 cannot access the finest micropores at low temperatures, and hence only measuring the external surface area and area contained within mesopores (see also Kopp et al., 2000; Monge et al., 2001). At -196°C, N2 lacks the required thermal energy to diffuse through the narrow constricted pore throats (Unsworth et al. 1989). Carbon dioxide, which is used at a higher temperature and thus has greater thermal energy, can force 121 0) 13 1.4 - 1.2 co CL 1.0 e cc co 0.8 0) Va) 0.6 - -2 0u) 0.4 - 0 ^ 1 ^ 2 ^ 3^4^5 ^ 6 ^ 7 ^ 8 Pressure (MPa) Figure 3-14. Linear correlation between pressure and methane sorption of a Jurassic shale sample, indicative of a solute gas (following Henrys Law). 122 through narrow passages (Larsen et al., 1995) and is believed to represent the 'truest' surface area, measuring ultra-microporosity (Walsh, 1987). The large micropore volumes and surface areas per wt% TOC of D—M shales compared to Jurassic shales are a result of thermal maturation. Jurassic strata in northern British Columbia have equivalent vitrinite reflectances (% Ro) typically <1.2 % Ro (Table 3-2) whilst D—M shales are more thermally mature, with vitrinite reflectance values (actual or equivalent) ranging between 1.6 and 4.5 % Ro (Morrow et al., 1993; Potter et al., 2000; Stasiuk and Fowler, 2002; Potter et al., 2003). At higher thermal maturity, diagenesis structurally transforms the organic fraction (described here as micrinite), creating more microporosity and/or decreasing the heterogeneity of the pore surfaces: processes related to larger sorbed gas capacities of high-rank coals (e.g. Levy et al., 1997; Bustin and Clarkson, 1998; Laxminarayana and Crosdale, 1999). With increasing rank, the macromolecular aromatic structures are stacked (up to 2-4 layers, known as crystallites; Lu et al., 2001) and zones of parallel orientated crystallites form. It is within the interlayer spacing of the crystallites that the microporosity exists (Oberlin et al., 1980; Marsh, 1987; Clarkson and Bustin, 1996; Lu et al., 2001; Prinz et al., 2004). During coalification, it is believed that the hydrocarbon components are cracked, opening up additional sorption sites to CH4 (Gan et al., 1972). Due to these processes, D—M shales sorb more gas per wt% TOC than Jurassic shales. Larger micropore volumes within the Jurassic suite of samples are associated with thermally mature shales (-3% Ro; N3773-2 and N3793-1), contributing an adsorbed gas component to the total sorption capacity. These results emphasize the 'over-printing' 123 effect of thermal maturity upon organic matter, pore-structure and gas sorption. No consistent variation exists between thermal maturation and microporosity as pore structure is affected by other compositional attributes (e.g. inorganic material). 3.4.3 Sorption characteristics: effect of inorganics upon micropore structure The influence of mineralogy upon shale pore-structure and surface area is evident in D- M shales. Organic-lean, aluminosilicate-rich Fort Simpson shales have micropore volumes which cannot be related to the organic fraction (Figure 3-4A). The micropore structure is controlled by the clay fraction (Figure 3-15): illite, chlorite and kaolinite (Ross and Bustin, in review), whereas micropore volumes of silica-rich, aluminosilicate- poor LBM samples (>75% SiO 2) are a function of TOC only (Figure 3-15). The biogenic silica (Chapter 2) has insignificant microporosity and hence sorption sites, as indicated by the small micropore volume and surface area, and no pore-sizes <100 nm diameter in chert. Clay-rich UBS samples, which have comparable organic contents and maturity to LBM samples, have the largest micropore volumes and BET surface areas, reflecting a contribution of organics and clays to the micropore structure (Figure 3-15). Consideration must also be given to the hydrophilic nature of clay minerals which reduces their adsorptive capacity (Table 3-3). Under moisture equilibrated conditions, moisture may render many microporous sorption sites unavailable to CH4 by filling pore throats or occupying sorption sites (Joubert et al., 1973; Joubert et al., 1974; Yalcin and 124 • Organic-lean, Al 203-rich (Fort Simpson) o Variably organic and Al203-rich (UBS; Besa River) • Silica-rich, Al203-poor (LBM; Besa River) Figure 3-15. Variation of micropore volume with TOC and clay fraction (proxied by percent Al203) for D—M shales. Clay-rich Fort Simpson shales have micropore volumes which are not related to organic contents. Biosiliceous LBM samples show a strong correlation between TOC and micropore volume. Shales enriched in both clays and organics (UBS samples) have the largest micropore volumes, suggesting a micropore contribution from both the organic and clay fraction. 125 Durucan, 1991; Bustin and Clarkson, 1998; Krooss et al., 2002; Hildenbrand et al., 2006; Ross and Bustin, 2007). In a study of gas sorption on clays, coals and shales, Cheng and Huang (2004) reported comparable CH4 capacities of pure kaolinite and montmorillonite standards to oil shale (TOC = 20.2 wt%). However surface areas measured using the N2 BET method were smaller for the oil-shale than clay minerals. In an attempt to relate the variation in sorption capacity with surface area, Cheng and Huang (2004) estimated the area coverage of CH4 concluding absorption in the organics may provide an additional retention mechanism. Devonian—Mississippian shales have microporosities, surface areas and sorbed gas capacities comparable with clay mineral standards, suggesting the influence of absorption is minimal. 3.4.4 Total pore volume Mercury porosimetry data indicates that mineralogy influences total pore volumes and pore size distributions. Quartz-rich, clay-poor D—M shales have pore-sizes skewed towards smaller pores and lower total pore volumes, most notably for LBM samples. The largest porosities were measured for clay-rich shales (UBS member). These findings are in contrast to other studies which describe porosity increasing with quartz content due to the presence of intergranular pores between coarser detrital grains (silt-sized quartz; SchlOmer and Krooss, 1997; Dewhurst et al., 1999B). However, silica in LBM and MU strata is mainly biogenic and not detrital (Ross and Bustin, in review), and the diagenesis of biogenic silica plays an important role in preserving or destroying the pore space and 126 fabric by secondary cementation (silica-dissolution and re-precipitation; Volpi et al., 2003). Image analyses reveal no distinct fabric or laminations in quartz-rich shales, even although deposition occurred under anoxic-euxinic conditions (Ross and Bustin, in review), which would preclude bioturbation (and subsequent destruction of shale fabric). Such dissolution and precipitation processes do not exclude gas sorption in quartz-rich shales as there are micropore surfaces within the organic matter upon which gas can sorb (sections 3.3.2 and 3.3.6). The total porosity is a function of meso- and macropores, not micropores, as evident by the good correlation between porosity (measured by Hg porosimetry) and N2 BET surface area. Micropores measured using low pressure CO2 analyses are not quantified due to the inability of Hg to penetrate restricted pore throats (Webb and Orr, 1997). A shift to smaller mean pore sizes and lower total porosity has been related to compaction-driven porosity reduction (Katsube and Best, 1992). In general, this does not account for the observations in this study due to comparable burial depths of the clay-rich and silica-rich shales (LBM and UBS samples at approximately 3800 m depth). Despite the irrelevance of the meso- and macropore structure and total porosity to gas sorption (controlled by microporosity), an understanding of these attributes is important to predicting total gas capacities. A significant proportion of the total gas content in shale gas reservoirs is free-gas; non-sorbed gas occupying open pores. During production, free gas co-mingles with sorbed gas, explaining the over-saturation of shale gas reservoirs (Bustin, 2005B; Montgomery et al., 2005). 127 3.5 CONCLUSIONS A variety of pore-structure analyses have been applied to a suite of organic-poor and organic-rich shales of different thermal maturation and mineralogy, to determine the fundamental controls on gas capacities in fine-grained marine strata. The following conclusions have been reached: 1) The organic fraction in shales is an important control on CH4 storage capacity, shown by positive correlations between TOC and sorbed gas. 2) For thermally immature Jurassic shales enriched with matrix bituminite, no relationship exists between TOC and D-R CO2 micropore volumes or N2 BET surface areas, indicating surface area alone is not the sole determiner of CH4 capacity. A component of solute CH4 within the internal structure of the matrix bituminite is an important gas storage mechanism in Jurassic shales. 3) Thermally mature shales have larger D-R CO 2 micropore volumes and N2 BET surface areas per wt% TOC. Hence the ratio of sorbed gas to TOC is greater in thermally mature strata (D—M) than immature strata. 4) The relationship between organics and sorption is affected by mineral matter. Clay minerals such as illite have micropore structures capable of sorbing gas. Mercury porosimetry analyses show that clay-rich shales have a significant percentage of mesoporosity (unimodal pore size distribution in the mesopore range). 128 5) Shale inorganics influence total pore volume which is an important parameter for evaluating total gas capacities due to storage potential of open pores for free-gas. Total porosity increases with aluminosilicates whereas high-silica content shales have lower total porosities. The results of this research highlight the pore structure complexity of shales and mudrocks. Due to multi-modal pore size distributions and surface area heterogeneities in the nanometre scale, there is difficulty predicting sorbed gas capacities of shales based on TOC contents and maturation levels alone. Shales contain a variety of organic and inorganic material with multifarious pore networks, which varies from one shale formation to another and within a formation itself. Hence the ability to establish a model of shale gas reservoir capacity is challenging and the prediction of CH4 capacities is problematic. Future research on gas sorption in shales will require a multi-faceted approach, addressing the effects of other reservoir parameters including moisture and temperature. Moisture is known to influence gas sorption in coals and shales (acting as a dilutent), but its relationship to the pore-structure in shales is unclear. 129 3.6 REFERENCES Altin, 0., Ozbelge, O. 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Mining Science and Technology, v. 13, p. 215-222. 138 Yang, Y. and Aplin, A.C. 1998. Influence of lithology and compaction on the pore size distribution and modelled permeability of some mudstones from the Norwegian margin. Marine and Petroleum Geology, v. 15, p. 163-175. Yee, D., Seidle, J.P. & Hanson, W.B. 1993. Chapter 9, Gas sorption on Coal Measurements and Gas Content. In: Law, B.E. and Rice, D.D. (eds), Hydrocarbons from Coal, American Association of Petroleum Geologists, AAPG Studies in Geology, p. 203-218. 139 CHAPTER 4 IMPACT OF SHALE LITHOLOGY AND DIAGENESIS UPON FABRIC, PORE SIZE DISTRIBUTION AND PERMEABILITY 140 CHAPTER 4 Impact of shale lithology and diagenesis upon fabric, pore size distribution and permeability 4.1 INTRODUCTION Shale gas reservoirs are complex, heterogeneous geologic systems that require innovative exploration strategies to produce natural gas economically. The commercial gas production from shales is dependent upon two main geologic factors: 1) total gas capacity (sorbed plus free gas) which is a function of matrix properties including total organic carbon (TOC) content, mineralogy, maturity, porosity (micro-macropores 8), moisture, fabric and texture (Zielinski and McIver, 1982; Soeder, 1988; Lu et al., 1994; Bustin, 2005; Montgomery et al., 2005; Ross and Bustin, 2007, Chalmers and Bustin, 2007; Ross and Bustin, in review) and; 2) producibility (or deliverability), governed by fracture density, size, aperture and orientation (Manger et al., 1991; Kuuskraa et al., 1992), coarser-grained facies (Thompson et al., 1984; Hill and Nelson, 2000) and matrix flow properties (Luffel et al., 1993). Shale matrix permeabilities (k„,) are in the millidarcy to nanodarcy range (Soeder, 1988; Luffel et al., 1993, Montgomery et al., 2005) Includes gas produced from mudrocks, siltstones and some fine-grained sandstones. 8 Using the International Union of Pure and Applied Chemistry (IUPAC), micropore have diameters <2 nm, mesopores between 2 and 50 nm and macropores have diameters >50 nm (Rouquerol et al., 1994). 141 which can be insufficient for economic gas production; hence fractures and/or coarser grained horizons are needed. As such, gas flow/diffusion through the shale matrix was not considered to limit gas deliverability to the well-bore. Shale matrices are however, important to gas storage (Chalmers and Bustin, 2007; Ross and Bustin, 2007; Ross and Bustin, in review). To maximise gas recovery in thick sequences of 'homogenous' black shale, shale gas explorationists seek natural fracture sets (Antrim and Lewis shales; Manger et al., 1991; Shirley, 2001; Curtis, 2002; Bustin, 2005) or delineate stratigraphic zones with suitable rock properties for effective hydraulic stimulation (e.g., Barnett Shale: brittle, quartz-rich facies or zones with healed natural fractures; Bowker, 2007; Gale et al., 2007). Recent unpublished experimental and numerical analyses indicate that with wide fracture spacing, gas flow/diffusion through the shale matrix can also be production-rate limiting (Bustin et al., 2007). Thus to predict reservoir performance, determine optimal fracture spacing and estimate long-term productivity, an understanding of k m with respect to shale composition and fabric is required, since these attributes ultimately control the interconnected pore space (pore-throat sizes) and gas transport properties (Kwon et al., 2004). Fluid flow through shales is a complex process because pore-sizes are often in the 0.3-12 nm range (Katsube and Best, 1992; Neuzil, 1994; Best and Katsube, 1995), which affects gas migration at the molecular scale (Soeder, 1988), During production, shale gas wells typically show a rapid initial decline (gas flows through fractures) followed by a long, slow decline as gas desorbs from the matrix into the fracture network (Soeder, 1988). It is the later of these processes (matrix diffusion) 142 which will dictate the life-span of the well; hence knowledge of k„, is an important component in computer simulation modelling for long term shale gas production (Luffel et al., 1993; Figure 4-1). Numerous studies have investigated shale microfabric (O'Brien and Slatt, 1990) and permeability for predictive modelling of cap-rock sealing efficiency to petroleum and water (Neuzil, 1994; SchlOmer and Krooss, 1997; Dewhurst et al., 1999; Yang and Aplin, 2007). Much of the development and variation of permeability has been attributed to various factors including burial depth and degree of deformation (BjØrlykke, 1998; Dewhurst et al., 1998; Kwon et al., 2001; Kwon et al., 2004), porosity and lithology (grain-size, clay content and pore-size distribution; Katsube et al., 1991; Aplin et al., 1995; SchlOmer and Krooss, 1997; Yang and Aplin, 1998; Dewhurst et al., 1998; Katsube et al., 1998; Dewhurst et al., 1999), bioturbation (Schulteiss and Gunn, 1985) and microfractures/microcracks (Bolton et al., 2000; Lash and Engelder, 2005). Shales also exhibit diverse fabrics which influence permeability. Preferred orientation of clays and organics create effective barriers to fluid migration due to anisotropic permeability (Sutton et al., 2004), whereby horizontal permeability exceeds the vertical permeability by ratios of 1 to 2.5 (Chandler et al., 1990; Clennell et al., 1998). The current laboratory study reported here, part of an on-going shale gas/gas transport research project at UBC, attempts to: 1) provide detailed description of sedimentological and diagenetic features of Late Devonian shales; and 2) correlate various shale attributes (organic content, mineralogy and pore-size distribution) with microfabric and 143 Desorption Figure 4-1. Schematic illustration of the two phases of methane desorption from shales. Darcy flow through the fracture network, followed by matrix diffusion into the fractures. 144 permeability of Devonian-aged shale gas reservoirs in the Western Canadian Sedimentary Basin (WCSB). In doing so, the effects of both shale pore structure and effective confining pressure (at 30 MPa) upon gas transmissibility are examined. Core, petrographic and SEM observations are utilized to assess fracture network (micro and macro), and evaluate their potential impact upon gas flow in Devonian shaly strata. 4.2 REGIONAL GEOLOGY Organic-rich Devonian shales located within the Liard and Horn River basins, and carbonate embayments of northern British Columbia (BC; including the Besa River, Muskwa, Klua and Otter Park formations, and the Evie Member; Grey and Kassube, 1963; Figure 4-2) contain diverse lithologies of siliceous mudstones, shales, micrites and argillaceous carbonates (Pelzer, 1966; Ross and Bustin, in press; Ross and Bustin, in review). Biogenic components are an important contributor to bulk rock composition, as evident from the presence of radiolarian capsules, lenticular chalcedonic quartz and calcispheres (Pelzer 1966; Stasiuk and Fowler, 2004). To the east of the Horn River Basin (east of 122°W), equivalent strata are dominated by shallow-water shelf carbonates of the Presqu'ile barrier complex (Keg River and Slave Point; Morrow et al., 2002). Late Devonian fine-grained siliciclastics attain thicknesses greater than 1500 m (Pelzer, 1966; Ross and Bustin, in press). Overlying the organic-rich, deep-basin strata are the organic- lean Fort Simpson shales, which reach thicknesses >1000 m (Ross and Bustin, in press). 145 Alberta British CoFemale 1 on I-^Northwest Territories CANADA 0 ^ Miles^ 75 0 Kilometers^120 61°N ( •^•^/ NWT Arrowhead I Salient 60°N 1 • 1 YK BC Cardova^I Embayment 59°N- \Ya'' Eastern edge of I^ ♦ Lararnicle thrusting ♦ • • . \koft‘ \<.‘ ea' Slave Point Platform 58°N -126°W Bo., Fault Zone•^ -124°W Study area -122°W^ -120°W Figure 4-2. Major depositional influences during the Late Devonian, which included the Horn River and Liard basins, Klua and Cardova embayments, and the Slave Point carbonate platform (modified from Ross and Bustin, in press). 146 The Liard and Horn River basins are separated by the Bovie Fault Structure, a product of two deformation phases: 1) Permo-Carboniferous crustal uplift and compression; and 2) thrusting associated with the Laramide Orogeny (MacLean and Morrow, 2004). Across the Bovie Fault, strata are vertically displaced by more than1200 m (Wright et al., 2004), resulting in significantly different reservoir depths of Devonian shales across northern BC (up to 4 km total vertical depth). The Liard Basin is bounded on the west by the eastern edge of Laramide thrusting. 4.3 METHODOLOGY 4.3.1 Samples and preparation Sixty-six shale samples were collected from Devonian core and sidewall samples in northern BC for thin sections to analyze fabric and bio-content. Most samples are from two cores, referred to here as core A and B. Seven samples representing the major lithological variations were analyzed for permeability and high pressure Hg porosimetry (described here as permeability sets C and D). Core samples were wrapped and immediately sealed upon retrieval to reduce the possibility of drying and shrinking. Each core selected for analysis was clamped in a press and horizontal core plugs were drilled from a 31/2 centimetres diameter orientated drill core. The coring bit was cooled with air to aid core plug removal from the core barrel. Plugs were then cut into three one-inch long cores to be used for permeability measurements and Hg porosimetry, polished thin sections (30 lam) and the remaining sample was crushed to 250 gm powder for organic carbon and mineralogical analysis. 147 4.3.2 Analyses 4.3.2.1 Organic content and mineralogy Total carbon (Ctotai) was measured using a Carlo Erba NA-1500 Analyzer following combustion at 1050°C with precision of 0.5% (Verardo et al., 1990). Inorganic carbon concentration (Ccarbonate) values were generated from a CM5014 CO2 coulometer with a precision of 2%. Fifteen to twenty-five milligrams of ground sample were weighed and reacted with HC1. Total organic carbon values were determined by Ctotai - Ccarbonate- Abundance of minerals were calculated semi-quantitatively using peak-area from x-ray diffraction (XRD) traces, corrected for Lorentz polarization (Pecharsky and Zavalij, 2003). 4.3.2.2 Imaging methods Impregnated polished thin sections (<30 µm), cut perpendicular to bedding, were examined using conventional transmitted polarized light microscopy prior to scanning electron microscopy (SEM) analysis. Rock chips were gold coated for SEM analysis whilst thin sections were carbon coated for back scatter electron microscopy (BSEM). Scanning electron microscopy and BSEM micrographs were acquired using a Philips XL-30 SEM with a Princeton® Gamma-Tech PRISM IG energy-dispersive spectrometer, which allowed identification of the chemical composition of mineral phases by their X- ray sprectra. 148 4.3.2.3 Mercury porosimetry Mercury intrusion data was collected on a Micromeritics® Autopore IV 9500 Series. Pressure of mercury was increased continuously from 0.013 to 430 MPa and pore size distributions were determined using the Washburn equation (Washburn, 1921): D — 4y cos 0 P ^(1) where D is the pore diameter, y is the surface tension, 0 is the contact angle and P is the applied pressure. A contact angle of 140° (Gan et al., 1972) and surface tension of 485 dyn/cm (Gregg and Sing, 1982) were used. Total pore volumes were calculated from Hg intrusion data. 4.3.2.4 Permeability Permeability was measured using the pulse-decay method following the methods and procedures by Jones (1997). The steady-state permeameter apparatus (Figure 4-3) consists of an upstream reservoir of gas (V,,), a cell (containing the shale sample with pore volume V s) which is held between two hydraulically activated pistons (capable of applying high confining-pressures, p c), and a downstream reservoir (Vd). A differential pressure transducer reads the pressure difference between the two reservoirs (Ap), whilst two transducers read the upstream (p u) and downstream reservoir pressure (Pd). 149 Valve 1^Valve 3 Ap VdV. Confining pressure Valve 4 C Figure 4-3. Diagram illustrating the pulse-decay permeameter set-up for measuring permeabilities at various confining pressures. Vu = upstream reservoir of gas; Vd = downstream reservoir of gas; Vs = shale and pore volume; pu = upstream pressure; pd = downstream pressure; pc = confining pressure; Ap = pressure decay. 150 Initially, valves 1, 2 and 3 are open, and the reservoirs and Hoek are filled with gas to high pressure to avoid gas slippage. Once pressure becomes uniform throughout the system, valves are closed. Next, helium gas is injected into Vu and the pressure is allowed to stabilize while reaching thermal equilibrium. Thereafter gas is injected into the sample and pressure decay (Ap) with time is monitored, and the permeability is calculated. Permeabilities were calculated (at 30 MPa effective confining pressure and a fixed pore pressure of 3.5 MPa) using the following equation: —14696m i ,ug Lfz Kg =^ ^ 1^1^(2)^Ap, (^ + ) " VI V2 where: Kg = effective permeability to gas, millidarcy (mD) m1= slope of linear equation mg = viscosity of gas, cP L = Length of cylindrical core plug, cm fZ = gas compressibility correction factor = mass flow correction factor A = cross sectional area of cylindrical core plug, cm2 pm= mean absolute pore pressure, psi V 1 and V2 =volume of up stream and down stream reservoirs respectively, cc 151 4.4 RESULTS 4.4.1 Composition Total organic carbon contents range between 0.4-6 wt% (Tables 4-1, 4-2 and 4-3). Ternary diagrams show relative proportions of quartz, clay and carbonate (in the form of fossil debris) of Devonian shales (Figure 4-4). Samples are enriched with either quartz (4.3-97.8%), illite (<1% to 63.8%), calcite (0-92.6%) or dolomite (0-45.5%), with lesser concentrations of kaolinite, pyrite, chlorite and albite. Organic contents generally increase with increasing quartz content, and decreasing carbonate content. Down-core mineralogical and TOC profiles, with textural heterogeneities, are shown in figures 4-5 and 4-6 (see following section for detailed fabric description). 4.4.2 Image analyses Quartz-rich samples 9 exhibit a faint fabric of discontinuous kerogen stringers (Figure 4- 7A) and rare quartz silt lamina (Figure 4-7B). Fabric is distorted by differential compaction of kerogen stringers around radiolarians (entactiniid radiolarian, Family Entactinaria; Carter pers. comm.), creating a wavy/crenulated fabric (Figure 4-7, C-1). The presence of siliceous tests (microcrystalline quartz masses) suggests a predominantly biogenic source to the silica. Tests range in size from 75-100 ii,M, and show internal concentric lattice shells (Figure 4-7, C-2). Petrographic analyses indicate that some quartz exists as silica-filled cysts (Tasmanites i°?), identified by spherical quartz grains 9 Quartz-rich permeability samples were examined using normal/cross polarized light and SEM in their initial states (prior to compaction during permeability testing). 10 Cysts of planktonic marine prasinophyte algae 152 Core A TOC 0 Quartz Illite Kaolinite Calcite Dolomite Pyrite Albite Chlorite Total clays Total carbonate Samples (wt%) (%) (%) (%) (°/0/ (°M (%) (%) (%) (%) (%) (%) Al 0.9 1.2 17.0 24.1 0.0 45.7 13.7 1.3 1.6 2.8 26.9 59.4 A2 2.1 2.2 25.6 48.0 8.9 20.5 3.6 1.6 2.4 0.0 56.9 24.1 A3 1.8 1.3 44.5 60.2 0.0 0.0 1.6 2.4 5.9 2.6 62.8 1.6 A4 2.5 0.8 47.1 37.5 2.0 2.0 15.3 1.4 1.6 4.5 43.9 17.2 A5 3.1 2.1 46.8 32.3 5.9 19.6 1.6 2.3 1.4 0.0 38.2 21.2 A6 1.5 1.1 45.4 43.3 1.9 2.6 5.3 1.5 1.9 0.0 45.2 7.8 A7 2.5 0.9 61.1 34.1 0.0 1.1 2.5 2.3 2.0 0.0 34.1 3.6 A8 0.4 1.1 9.2 12.2 0.0 75.3 3.0 1.1 1.8 0.0 12.2 78.3 A9 1.8 2.1 62.6 20.8 0.0 0.0 12.7 3.3 4.2 0.0 20.8 12.7 A10 5.0 1.2 48.5 37.7 0.0 5.5 9.3 4.4 2.9 0.0 37.7 14.8 All 0.4 0.7 45.5 28.7 0.0 6.4 21.8 2.9 0.5 0.3 29.0 28.2 Al2 5.6 2.0 31.6 48.6 0.0 14.3 9.2 5.2 0.7 0.3 48.9 23.4 A13 4.4 3.1 19.5 37.2 0.0 26.4 15.6 0.8 2.0 3.2 40.4 42.0 A14 0.3 1.6 24.8 41.2 0.0 32.4 4.0 1.5 3.5 0.1 41.3 36.4 A15 0.2 2.1 23.6 43.5 0.0 27.9 5.9 1.1 2.7 0.1 43.6 33.8 A16 0.5 2.1 21.4 38.2 0.0 33.9 7.6 0.4 2.9 0.1 38.3 41.5 A17 0.3 1.3 27.7 63.8 0.0 7.9 6.6 1.8 2.2 0.1 63.9 14.6 A18 0.3 2.9 27.7 53.2 0.0 9.6 9.8 0.9 4.7 0.1 53.3 19.3 A19 0.2 0.9 6.9 18.6 0.0 75.9 0.0 0.4 1.2 3.9 22.6 75.9 A20 3.1 2.0 69.8 21.7 0.0 5.0 9.1 1.7 0.2 0.0 21.7 14.1 A21 5.3 0.9 30.3 24.4 0.0 22.0 24.8 n/a 2.2 0.0 24.5 46.8 A22 3.1 1.8 39.3 19.9 0.0 30.3 10.2 2.7 0.4 0.2 20.1 40.4 A23 5.0 1.3 36.7 8.2 0.0 52.6 3.2 1.2 0.5 0.0 8.2 55.8 A24 3.6 2.0 36.6 14.6 0.0 44.5 0.0 1.4 0.7 1.9 16.5 44.5 Table 4.1. Lithologic composition of core A samples. TOC = total organic carbon content; 0 = total porosity. Core B TOC 0 Quartz Illite Kaolinite Calcite Dolomite Pyrite Albite Chlorite Total clays Total carbonate Samples (wt%) (%) (%) (%) (%) (%) ( %) (%) ( % ) ( % ) ( %) (%) B1 4.09 1.8 73.2 11.4 0.0 1.2 4.0 2.7 7.5 0.0 11.4 5.2 B2 3.86 2.3 97.8 2.2 0.0 0.0 0.0 0.0 0.0 0.0 2.2 0.0 B3 2.7 1.9 68.2 27.7 0.0 1.5 0.4 0.7 1.6 0.0 27.7 1.8 84 3.13 1.9 69.3 9.6 0.0 1.9 14.5 1.2 3.5 0.0 9.6 16.4 B5 3.68 1.2 93.2 2.8 0.0 1.9 0.0 1.3 0.8 0.0 2.8 1.9 B6 1.18 36.8 0.4 0.0 0.0 45.5 4.4 3.1 0.0 0.4 45.5 B7 1.78 1.0 46.4 8.0 0.0 8.8 30.8 1.4 4.7 0.0 8.0 39.6 B8 2.33 2.5 74.3 9.3 0.0 5.0 4.9 2.3 4.2 0.0 9.3 9.9 B9 3.02 1.4 54.2 27.9 0.0 0.7 4.2 9.6 2.2 0.0 27.9 4.9 B10 3.25 54.6 8.5 0.0 6.0 2.6 23.2 0.0 0.0 8.5 8.6 B11 3.94 2.0 67.2 17.0 0.0 9.1 0.5 2.6 4.5 0.0 17.0 9.6 B12 3.74 1.5 58.2 21.3 0.0 12.9 0.1 2.6 4.9 0.0 21.3 13.0 B13 5.88 1.9 77.2 13.4 0.0 5.2 4.2 0.0 0.0 0.0 13.4 9.4 B14 5.95 1.7 55.4 12.5 0.0 20.5 2.6 3.1 5.9 0.0 12.5 23.1 B15 3.2 1.7 59.5 20.0 0.0 4.4 6.5 1.7 7.8 0.0 20.0 11.0 B16 1.26 1.5 59.5 20.0 0.0 4.4 6.5 1.7 7.8 0.0 20.0 11.0 B17 1.98 1.6 50.9 25.2 0.0 0.8 10.0 4.0 9.1 0.0 25.2 10.9 B18 3.84 1.7 66.7 11.3 0.0 5.3 8.5 2.4 5.8 0.0 11.3 13.8 B19 0.61 2.1 5.3 0.0 0.0 92.6 0.3 0.5 1.4 0.0 0.0 92.8 B20 0.41 2.0 4.3 0.0 0.0 82.0 5.1 8.6 0.0 0.0 0.0 87.1 B21 3.22 2.4 45.3 20.8 0.0 17.4 6.6 2.6 7.3 0.0 20.8 24.0 B22 4.28 2.0 43.7 22.4 0.0 17.0 7.6 1.8 7.5 0.0 22.4 24.6 B23 4.09 1.7 40.9 4.6 0.0 44.9 5.3 1.0 3.4 0.0 4.6 50.2 B24 5.47 39.3 10.7 0.0 35.7 7.1 2.0 5.2 0.0 10.7 42.8 B25 1.88 1.8 29.1 4.0 0.0 63.6 0.8 1.4 1.9 0.0 4.0 64.4 Table 4.2. Lithologic composition of core B samples (missing 0 measurements are shown as blanks). k TOC 0 k Quartz Illite Kaolinite Calcite Dolomite Pyrite Albite Chlorite Total clays Total carbonate Samples (wt%) (%) and (%) %) (%) (%) (%) (%) (%) (%) (%) %) C1 4.1 2.3 0.0033 67.6 29.2 0.0 1.9 0.3 0.5 0.4 0.0 29.2 2.2 C2 4.8 3.1 0.0001 70.6 21.5 0.0 5.1 1.1 0.7 0.9 0.0 21.5 6.2 C3 5.9 2.3 0.0059 65.7 23.8 0.0 3.1 2.9 2.4 2.2 0.0 23.8 6.0 D1 3.1 3.0 0.0280 79.6 17.9 1.1 0.0 0.3 0.3 0.7 0.0 19.0 0.4 D7 1.0 2.2 0.6516 18.4 78.2 0.0 0.0 1.9 0.4 1.1 0.0 78.2 1.9 D8 2.7 2.7 0.8012 45.0 50.3 2.5 0.1 0.8 0.6 0.6 0.0 52.8 0.9 D9 3.4 2.6 0.8891 34.8 63.1 0.0 0.0 0.1 0.7 1.3 0.0 63.1 0.1 D13 4.2 2.2 0.4096 45.9 51.1 0.0 0.2 0.0 1.1 1.7 0.0 51.1 0.2 Table 4.3. Lithological composition and physical rock properties of permeability sample (k samples) suites C and D. k = permeability at 30 MPa effective confining pressure. ^ Core A samples A Core B samples Permeability samples: A 0 Permeability samples: B Quartz^0 40^50^60^70^80^90^100^Clays10 Carbonate Figure 4-4. Ternary diagram of core A and B samples, and permeability sample sets C and D. 156 Figure 4-5. Down-core profiles of lithologic variabilities (major mineral phases and TOC contents), and associated fabric differences, of core A (T/S = thin-section). A) clay-rich horizon (-60% illite); B) low TOC content (0.4 wt%) manly limestone (classified after Pettijohn, 1975) ; C- 1) quartz-rich silty horizons; C-2) same sample as C-1, highlighting sharp horizontal contact between clay-rich layer and quartz-rich layer; D) organic-rich horizon with comparable concentrations of quartz, clays and carbonates; E) manly limestone with scatted organic matter (horizontally aligned organic flakes). Also shown is a vertical cemented fracture which is cross- cut by an open horizontal fracture (blue resin filled); F-1) recrystallized bio-fragments (possibly sponge spicules and brachiopod spines) and secondary calcite precipitation rims around bioclasts; F-2) compacted skeletal fragments (possibly compacted tests of foraminifera). 157 Sc I till'1'1'1'1'1 1 1 1 1 1 1111 1 101111111111111'111111111^110111 ' 11 1 1 1' 1 1' 11 1 1 1 1 1 1 1 1 1 1 0 1 1 1 1 1 1'1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 11^1 1^1 "ill^I^1 1 1^1111111111 '1 yyt: 111,01,1110,11,1,1,11 1 1,1 1 1 : 1,Y,1 1 1 , 1 ; 1 , 1 10; 1 : 1 , 1 1 1 , 1 1 1 ,1: 1 1:0,1,1;1;i11: 1,:101 11,1 1 ili Thi,i,1,111 i,i;ili: 11,11 1 , 1 , 101^1 1^1 11:,111;i 1,1: :111 1,0,111,1 1,1; 0 0 0 0 0 C) a-0 F6- — O O 0C) Dhi 0 Co Figure 4-6. Down-core profiles of lithologic variabilities (major mineral phases and TOC contents), and associated fabric differences, of core B. A) organic-rich (-4 wt% TOC), quartz-rich (-98% quartz) shale with faint horizontal fabric; B) dolomitized shale; C) quartz-rich shale (-75% quartz) showing no fabric; D) Silty beds within quartz-rich shale; E) shale (-50% quartz) with horizontal lenses (carbonate); F-1) bioclastic zone in lower portion of core with compacted skeletal fragments (possibly compacted tests of foraminifera); F-2) carbonate precipitation rims ('halo' cement) around recrystallized bio-fragments; G) packed biomicrite. 159 O- 0̂ 0 - 0 C) •.< C/1 8 O O C) ErO a) O O O 0 0^C) co >10 -n rn co T/S 091 11^1 : 1 1  I I^I I 1 1 111^1 1 :^1^I : I li^111 1 1 111 1 1^1 1  1 1  1 1 1 1  I I  I I^lo I  I I I I  I li I li 1 1  1 1  1 1  1 11^I I 1 1 I I^I 1 1 1 1 1 1 1 1 1 1 1 1 1 1^I 1 1 1 1 1 1 1 1 1 1 1 1 I I I I 1 1^I I I I I I I^I I I I I WI '1 1 1^1 1^1 1^1 1 1 1^I I 1 1^1 1^1 0 1 6 1 1^'t^V I 11'1 1 11 1111 11 11 1 1 '^11111111111111111 1II II II I^I^I^I^HI^I i I^i I^1^I I^i^I ^I^I    ^11 1111^1111 1 1^ 1 111 1^Y II^Y it 1 1 1 1 1 1 1 1 II I ' f ill 1 1 1 1 1 1 1 1 1 1 1 1^1 1 ri l l^1 1 II 1 1^II 1 1^I d^I I^i r^'I I I^ 1 1111 I I IIII 1 1 1 1 oC) co with embayments and pointed projections (Figure 4-7D; Schieber, 1996). The silica is possibly sourced from radiolarians. Microstructural SEM analysis shows a slightly granular to massive quartz texture (Figure 4-7E), common of chalcedony (Keene, 1983). Back scattered images reveal a lack of pervasive fabric, as the quartz creates a dense, amorphous matrix with no obvious orientated particles, open porosity or grain on grain contacts (Figures 4-7F). Thin section observations of illite-rich samples show a strong preferential orientation of clays, with scattered quartz throughout (Figures 4-8A and 4-8B). The micro-fabric has discontinuous parallel laminations with rare lenses of coarsely crystalline carbonate, which show no intergranular porosity (possibly due to cementation; Figure 4-8C). Sharp contacts between illite-rich and quartz-rich horizons occur (Figure 4-5, C-2). At the SEM scale of observation, the groundmass has a heterogeneous grain-size and framework, with randomly dispersed pristine euhedral dolomite crystals, resulting in a lesser defined clay fabric (Figure 4-8D). Carbonate bioclastic material is concentrated into event beds, as compacted and disarticulated shell debris at the base of the cored sections (see figures 4-5 and 4-6). Carbonate also occurs as discrete beds of crystalline calcite (Figure 4-5B). Microfractures i I are present, but not necessarily associated with a specific type of laminae or bed, and can be: 1) horizontal: either parallel or sub-parallel to bedding, and are typically wider than 2 ftln; 2) cross cutting both organic-rich and silty layers (Figure 4-9A); 3) concentrated along the edges of coarser dolomite crystals (Figure 4-9B); and 4) Microfractures are defined here as any fracture that can only be determined with the aid of transmitted light microscopy, SEM and BSEM analyses. 161 Figure 4-7. Image analysis of quartz-rich Devonian shales (scales as shown). A) Example of the faint crenulated fabric with possible lenticles of chalcedonic silica in shale matrix; B) rare coarser- grained quartz beds; C-1) compaction of kerogen stringers around a siliceous test; C-2) figure C- 1 in cross polarization, highlighting internal concentric lattice shells of siliceous test (entactiniid radiolarian, Family Entactinaria; Carter pers. Comm.); D) cuspate-lobate external structure of asilica-filled cyst (possibly Tasmanites); E—F) SEM and BSEM (polished thin-section) images - note lack of distinct fabric in quartz-rich shales. 162 4:e Figure 4 -8. A—D) Image analysis of illite-rich/low quartz content Devonian shales (scale as shown). A) horizontal fabric due to preferential alignment of clay plates; B) SEM image highlighting clay mineral alignment; C) high magnification image of rare silty carbonate lenses (no visible porosity); D) BSEM image of a polished thin-section showing coarse, euhedral dolomite crystals with distinct zonation. e .. Figure 4-9. Examples of microfractures (scale as shown). A) open fracture crosscutting quartz- and clay-rich laminae; B) BSEM image of near-horizontal fractures; C) calcite-filled vertical fracture, upon which smaller open fractures terminate (highlighted by arrows); D) parallel and near-vertical silica-cemented fractures. near vertical cemented fractures (with carbonate- and silica cement; Figures 4-9C and 4- 9D), upon which open fractures terminate (Figure 4-9C). Rarely do fractures propagate through grains. The possibility of fracture enhancement during the coring and drying processes cannot be discounted as cemented microfractures were rarely observed. Pyrite and calcite mineralized natural macrofractures occur in Devonian shale core (Figure 4-10, A—F). Occasionally, bitumen and sulphides are found within the fractures (Figure 4-10, D and E). Fractures can have a sheared, mosaic-like network, or orientated parallel to bedding (Figure 4-10B to F). Syn-sedimentary faulting is also visible (Figure 4-10G). 4.4.3 Mercury Porosimetry 4.4.3.1 Porosity Total pore volumes range between 0.9 to 5.5%. No influence of lithological composition (both organic content and mineralogy) upon total porosity was discernable (Figure 4-11). 4.4.3.2 Pore size distributions and capillary pressure curves Figure 4-12 shows the log differential intrusion volume vs. diameter for sample suites C and D. Such plots are particularly useful because areas under the peaks provide information on the contribution of specific pore size diameters to the total pore volume (Webb and Orr, 1997). Samples Cl, C2 and C3 have intrusion curves which are almost 165 Figure 4-10. Macrofractures in Devonian core: A) mineralized pyrite fractures; B and C) calcite-cemented fractures; D) Partially mineralized calcite fracture with bitumen; E) mosaic-like calcite filled fracture with sulphides; F) horizontal hairline fractures with calcite cement; G) example of syn-depositional faulting (scale bar = 5 cm). 1.0 1.5 1.0 1.500 0.5 2.5 3.0 2.5 3.0 352.0 35 0.5 2.000 00 001.0 3.0 2.52.02.5 3.00.5352.0 1 51.01.50.5 35 100 100 90 - • 90 - 80 - 80 -O CI 0 70 - C 2 60 - C O 50 - CO 40 • • CI 0 0^ EP 03 0 •14-' 70 - ^ ^ 4. •EP 100 • A 90 - 80 0 70 - 5 60 - 5 0 50 40 - m 30 - • ^ 0^ • ^O O20 - 0 00 A • • • •ID CIO ♦^0^ ^ ♦ ^ 0^• •• A ♦ A o A ^^ A • A • 30 - to 30-CI ♦ EI‘ o^ •20 - 20 0 10 - • 10 -0 • •0 • •• • A AO I*^ •• •• AA A • •^ ^ A A • -A A • •^•0^ •^•• E •^8^o 10 0 7 0 ^ Core A samples • Core B samples Permeability samples: C °Permeability samples: ID A A • • • 0 • • ♦♦ ♦ AO •^A • • ♦ ^ 0 • ^ ^ ^^ ^ 0 0 0 CI• 0 • 6 CI Porosity (%) Figure 4-11. Relationship between key lithologic properties (TOC, quartz, clay and carbonate contents) and porosity. Sample key shown in TOC plot. Porosity shown on x axis. o C1 ■ C2 C3 - 4 A  - - A 0 ■ 0 A 0 eglktgggeo - • - • • D1 • 07 oD8 oD9 x D13 6 8 x x ■ • A 0 A^A8 ia^00^V • O B 0.016 0.014 1:1) 0.012 0.— 0.01 0 .— 0.008 73 0.006 Tis 0.004 0 —J 0.002 0 IA l 1000000 ^ 100000 ^ 10000 ^ 1000 ^ 100 ^ 10 ^ 1 0.025 0.02 E C 0 2 0.015 C 0.01 0.005 0 1000000 ^ 100000 10000^1000^100 10 ^ 1 Pore size diameter (nm) Figure 4-12. Log differential vs. pore size diameter: A) sample suite C; B) sample suite D. 168 coincident, with the only notable difference being the larger intrusion volume of C2 in the 100,000 nm scale pores (Figure 4-12A). Similar to C samples, D samples have relatively consistent pore size distributions, but significantly different log differential intrusion volumes (Figure 4-12B). Quartz-rich D1 has the largest Hg intrusion volume within sub 10 nm pores, followed by D8, D13, D7 and D9. Subtle differences are observed in the 100 to 400 nm pore sizes, where the intrusion volumes are in the order of D9 >D13>D7 >D8 >D1. In addition to Hg intrusion vs. pore size diameter plots, the capillary pressure data also provides information on fabric and pore structure. Of significant importance is the inflection point on Hg saturation (as a %) vs. pressure curves, which signifies the pressure at which Hg forms an interconnected filament through the sample (connecting the pore network; Figure 4-13). Although the pressure at which the inflection points occur are relatively similar (C samples —200 MPa, Figure 4-13A; D samples = —100 MPa, Figure 4-13B), the percent Hg saturation (at inflection) are significantly different between D samples (Figure 4-13B). Illite-rich D7 and D9 samples have between 60 to 75% Hg saturation at inflection, in contrast to quartz-rich D1 which has Hg saturation of only 24% (i.e., sample D1 has a higher threshold pressure before interconnection of the pore network). 4.4.4 Permeability Permeabilities of C samples are low, ranging between 0.0001 md to 0.0059 md at an effective confining pressure of 30 MPa, whereas D samples have permeabilities of 0.028 169 1000 o C1 ■ C2 A C3 OEreo • 100 0 o A • o A ■ 0 A ■ 0 A ■ 0 A ■ 0 A ■ 0 A ■ 0 A ■ 0 e■ 0 A ■ o p ■ 0 A ■ 0 A ■ 0 A ■ <A ■ 10 1 • ^0G^ 0^10^20 30^40^50^60^70^80^90^100 B 1000 100 - 0.1 - 10 - o D1 ■ D7 ♦ D8 x D9 o D13 0 0 0 0 0 ICC 0 ^ 0 • **A • itx 6, 9%*(i)„ .9' a ^ max O ♦ o^ ♦^cu x o ♦^0 X 0^ ♦ 0 X 0 ♦^0 X ^ 0^ ♦ 0 X 0 ♦^CO X 0^ ♦^011^X 0 ♦^0 • X 0^ ♦ 0 • X 0 ♦ 0 ■ X 0^ ♦ 0 •x 0 • 0 • X 0^ • 0 ■ X AO ■ X ID • X a x DM x 0.01 0 10^20^30^40^50^60^70 80 ^ 90 ^ 100 Mercury saturation (%) Figure 4-13. Mercury saturation vs. pressure: A) sample suite C shows relatively close similarity in Hg intrusion trends; B) sample suite D shows differing saturation curves with clay-rich samples exhibiting high levels of Hg saturation at lower pressures compared to quartz-rich 170 md to 0.889 md (Table 4-1). Permeability of C and D sample suites decrease logarithmically with increasing confining pressure. The most notable decrease occurs with D1, which has permeability varying by two orders of magnitude. Both sample suites show a negative correlation between quartz content and permeability (although there is scattering of the data below 50% quartz for sample set D; Figure 4-14A and 4- 14B), and no correlation between porosity and permeability exists. 4.5 DISCUSSION 4.5.1 Shale composition and physical properties The results in section 4.4 clearly show the affect of composition upon shale fabric, pore structure, capillary entry pressure and permeability. Quartz-rich samples exhibit tight- rock characteristics, with little or no fabric (possibly cemented?), and pore sizes which skew towards smaller pores. Consequently, measured permeabilities are lower in quartz- rich Devonian shales than shales with 'average' quartz contents (<60% quartz, —30-40% clays; Wedepohl, 1971), which typically have a distinct horizontal clay fabric, and a greater proportion of larger pores. Such findings appear counter-intuitive, since most quartz in shales occurs as silt-sized detrital quartz (Pettijohn, 1975), creating coarser intergranular porosity and higher permeabilities compared to fine-grained, clay-rich samples (Dewhurst et al., 1998). However consideration must be given to the source of quartz, which for Devonian samples, is mainly biogenic (see also Pelzer, 1966; Stasiuk and Fowler, 2004; Ross and Bustin, in review). Hence the tight micro-fabric of quartz- 171 71 • 70 - 69 - 68 - *C1 ■ C2 A C3 0 67 - 66 - A 65 90 80 - 70 - 60 - 50 - 40 - 30 - • ♦ D1 + D7 o D8 o D9 x D13 0 0 20 - 1.E-04 1.E-03 1. E-02 1.E-01 1.E+00 B 10 - 0 1.0E-02 1.0E-01 1.0E+00 Permeability (mD) Figure 4-14. Permeability vs. quartz content: A) sample suite C; B) sample suite D. Lower permeability of quartz-rich shales highlights tight-rock characteristics, similar to the results of high pressure Hg porosimetry. o- 42 tQ a 172 rich shales is inherited from its depositional and diagenetic history, resulting in poor correlations between porosity, permeability and quartz content. The absence of a laminated shale fabric has been attributed to the presence of oxygen- rich bottom waters during deposition (facilitating extensive bioturbation), but these types of conditions commonly result in organic-poor (<0.5 wt% TOC), grey coloured shales (Soeder, 1988; Wignall and Maynard, 1993; Sutton et al., 2004); features dissimilar of Devonian shales examined in this study. It is more likely that dissolution and re- precipitation of biogenic silica (through opal A, opal-CT to quartz) has affected and altered the original sediment fabric (Volpi et al., 2003). The transition of opal-CT to quartz typically occurs at temperatures between 55 to 110 °C (Pisciotto, 1981), with a sharp increase of amorphous silica solubility occurring at 100 °C (Krauskopf, 1959). Under these conditions, opaline debris would be re-deposited as chalcedonic quartz during post-deposition diagenesis. In contrast, clays (primarily illite) provide a supportive grain framework, creating an interconnected flow path (anisotropic permeability); this despite the compressible nature of fine-grained, clay-rich shales (Dewhurst et al., 1998). Thin-section, SEM and BSEM analyses provide qualitative information on shale fabric, but quantification of fabric elements with permeability is challenging as pore heterogeneities are at the molecular scale (Ross and Bustin, in press); a resolution beyond that of the techniques utilized here. Non-quantifiable pore structures may also help explain the significant differences in permeability between A and D sample sets. Although beyond the scope of this paper, another potentially important pore structure 173 variable is microporosity associated with the organic fraction (<2 nm diameter pores; Chalmers and Bustin, 2007, Ross and Bustin, in review), which cannot be quantified using high pressure Hg porosimetry (assesses only pores >3 nm diameter; Webb and On, 1997), but will undoubtedly affect gas diffusion through the shale matrix. 4.5.2 Implications for Devonian shale gas reservoir evaluation, northern BC Characterizing shale mineralogy is crucial for shale gas reservoir evaluation due to the lithology-dependent responses of induced fracturing. Akin to Barnett and Woodford shales, organic-rich (>3 wt% TOC), quartz-rich (>75% quartz) Devonian facies are excellent shale gas candidates due to their gas charged, brittle nature (causing fracture dilation; BjØrlykke, 1998; Nyg5.rd and Gutierrez, 2002; NyOrd et al., 2006), as opposed to clay-rich shales which respond poorly to fracture stimulation (e.g., Caney shale; Brown, 2006). However the research presented here suggests that, in addition to rock mechanical properties, matrix permeabilities are important variables. From east to west, towards the Liard basin, quartz content increases (Ross and Bustin, in press), and as such, Poisson's ratio 12 decreases and Young's modulus 13 increases. In deep basin regions, biogenic silica-rich shales have also experienced higher levels of diagenesis (i.e., west of the Bovie Fault), and generally have lower porosity (Ross and Bustin, in review). Hence it may be necessary to compromise between facies that can be most successfully completed and those of largest gas-in-place (GIP) across a sedimentary basin. Furthermore, there is significant vertical heterogeneity (Figures 4-5 and 4-6), 12 An elastic constant that is a measure of the compressibility of a rock perpendicular to an applied stress (i.e. the ratio of longitudinal to latitudinal strain). 1 3 An elastic constant representing the ratio of longitudinal stress to longitudinal strain. 174 impacting the mechanical stratigraphy and gas deliverability in strata that can exceed 1000 m thickness. To optimize reservoir production of Devonian shales in northern BC, two exploration possibilities need consideration: 1) increase the density of the hydraulic fracture network within quartz-rich strata. This strategy would enhance gas deliverability to the well-bore (shorter matrix diffusion time). 2) seek a balance between brittle/fracable (quartz-rich) rock properties, and a reservoir with larger matrix permeabilities (lower silica/bio-silica contents), although induced fracturing may not be as effective. The relationship between lithological composition and permeability is affected by microfractures, which were observed in thin-section and BSEM. Lack of mineralization suggests some microfractures may be an artefact of sample preparation, and not necessarily indicative of in-situ reservoir conditions. Statistically meaningful analyses of microfractures are complex, because factors including fracture-width, -length, - connectivity, -mineralization, and the amount of intergranular porosity are important variables, but challenging to quantify (Bustin, 1997). The effect of natural macro- fractures upon permeability appears minimal due to mineralization. As discussed by Soeder (1988), microfractures are likely the most significant gas-productive fractures, whereby small apertures at 'reasonable spacing distances' provide optimum permeability (i.e. balance between matrix permeability, fracture spacing, fracture width and fracture 175 porosity). Furthermore, smaller healed fractures may act as planes of weakness, and reactive during hydraulic fracture stimulation to increase permeability (Gale et al., 2007). The impact of artificial fractures upon permeability is in the experiments reported here due to the high confining pressure applied; although asperities may exist hence complete fracture closure is unlikely (Gutierrez et al., 2000). As such, extrapolating laboratory data to regional reservoir scales should be done with caution due to the significant scale effect. 4.6 CONCLUSIONS Permeability is influenced by small scale shale features which are a result of depositional setting and diagenesis. Quartz-rich Devonian shales display tight-rock characteristics, with poorly developed fabric, small median pore diameters and low permeabilities. These are features attributable to the biogenically-sourced silica, emphasising the importance of physio-chemical alteration of shales during diagenesis upon pore structure and permeability. Shales with lesser biogenic silica/greater illite content have a structured fabric due to clay parallel alignment, and the strong fabric aids gas flow even at high confining pressures. Permeability of shales examined here cannot be related to total porosity as any relationship is masked by lithology, which is the primary control upon fluid flow. The wider implications of this research relates to predictive modelling for shale gas reservoir evaluation. Pore size distribution and fabric heterogeneities need to be taken into consideration so shale permeability can be assessed, gas flow modelled and 176 deliverability be accurately determined. Without an appreciation of such small scale variabilities, the controls on reservoir quality and deliverability, and the identification of exploration sweet-spots, will remain enigmatic. Further research on this topic could assess the impact of TOC upon permeability, examining the preferential orientation of organic matter and fluid flow properties. The affect of TOC could not be constrained in this study due to comparable TOC contents between the samples examined. 177 4.7 REFERENCES Aplin, A.C., Yang, Y. and Hansen, S. 1995. Assessment of (3, the compression coefficient of mudstones and its relationship with detailed lithology. Marine and Petroleum Geology, v. 12, p. 955-963. Best, M.E. and Katusbe, T.J. 1995. Shale permeability and its significance in hydrocarbon production. The Leading Edge, v. 14, p. 65-170. BjØrlykke, K. Principal aspects of compaction and fluid flow in mudstones. In: A.C. Aplin, A.J. Fleet and J.H.S. 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In: Proceedings of the Unconventional Gas Recovery Symposium, May 16-18,1982, Pittsburgh, PA. 185 CHAPTER 5 CHARACTERIZING THE SHALE GAS RESOURCE POTENTIAL OF DEVONIAN-MISSISSIPPIAN STRATA IN THE WESTERN CANADIAN SEDIMENTARY BASIN: APPLICATION OF AN INTERGRATED FORMATION EVALUATION 186 CHAPTER 5 Characterizing the shale gas resource potential of Devonian—Mississippian strata in the Western Canadian Sedimentary Basin: application of an integrated formation evaluation * 5.1 INTRODUCTION Unconventional gas reservoirs (shale gas, coalbed methane and tight gas sands) are major petroleum exploration targets because of their gas storage properties and potential for large recoverable resource. With the continued growth in production from shale gas reservoirs in the United States (US), there has been a paradigm shift toward shale gas reservoir exploration in the Western Canadian Sedimentary Basin (WCSB). These low permeability (typically less than 1 md), marginal reservoirs in compositionally diverse stratigraphic intervals (e.g. Devonian, Jurassic and Cretaceous strata; Ramos, 2004; Ross, 2004; British Columbia Ministry of Energy and Mines, 2005; Chalmers and Bustin, 2007A; Ross and Bustin, 2007) potentially contain massive gas resources due to their organic-richness, porosity, thickness and lateral extent. Canadian shale gas resources are estimated to be >1,000 tcf gas in place (GIP; Bustin, 2005). * A version of this chapter has been accepted for publication. Ross, D.J.K. and Bustin, R.M. 2008. Characterizing the shale gas resource potential of Devonian—Mississippian strata in the Western Canadian Sedimentary Basin: application of an integrated formation evaluation. American Association of Petroleum Geologists Bulletin, v. 92, p. 1-30. 187 In the US, natural gas has been produced from shales and mudrocks since 1821. Gas shale production accounts for 8% of the total US gas production with over 39,500 actively producing gas wells (Warlick, 2006). Estimates of US shale gas in-place (GIP) ranges from 497 tcf to 783 tcf (Curtis, 2002). Such substantial gas resources have catalyzed interest in various organic-rich, fine-grained units with the most notable shale gas success being the Barnett Shale in the Fort Worth Basin, Texas (see Pollastro, 2003; Pollastro et al., 2003; Montgomery et al., 2005, Pollastro et al., 2007). Other shale gas resource plays in the United States include the Caney, Woodford, Fayetteville, Antrim, Ohio, New Albany and Lewis shales. Exploration and exploitation of shale gas plays in the US is primarily attributed to the depletion of US conventional gas resources; however tax credits (section 29), thick sequences of strata, thermal maturity, permeability (both natural fractures and fracable units) and pre-existing infrastructure are also significant contributors to its success. Shale gas plays, often referred to as technological plays (Cardott, 2006), benefit from the application and advancements in horizontal drilling, fracture design and stimulation, and 3-D seismic. As the exploration frontier of shale gas systems expands to new regions, reservoirs analogous to those from the United States are being sought to improve exploration strategies in Western Canada. With continued shale gas research in North America, it is apparent that heterogeneity of shales and mudrocks limits the application of reservoir analogues. Gas shale heterogeneity extends to the nanometre pore-size scale (Ross and Bustin, in review). Hence each shale gas reservoir requires unique treatment and systematic approaches before analogs can be directly applied. Parameters of importance 188 include organic matter type (oil- vs. gas- prone kerogen) and abundance, shale/mudrock vertical and lateral extent, depth of burial (affecting reservoir temperature, pressure and thermal maturity) and porosity (including pore-size distribution). Mineralogical composition is also a key variable to determine shale gas potential because it influences natural fracture genesis and designs for fracture stimulation (e.g. Manger et al., 1991). The most prospective shale gas exploration targets in western Canada are the organic- rich, Devonian—Mississippian black shale/mudrock formations which are widespread throughout Saskatchewan (SK), Alberta (AB), British Columbia (BC), Yukon (YK) and Northwest Territories (NWT; Fitzgerald and Braun, 1965; Pelzer, 1966; Lowey, 1990; Switzer et al., 1994; Smith and Bustin, 1998; Caplan and Bustin, 2001). Of particular exploration interest here are shales and mudstones of the Besa River, Horn River, Muskwa and Fort Simpson formations (BC Ministry of Energy and Mines, 2005; Figure 5-1). Our study area includes the northeastern region of BC, southern YK and southern NWT and bound by latitude 58°N and 62°N and by longitude 120°W and 125°W (to the Laramide deformation belt; Figure 5-2). These regions already have significant gas production from conventional fields along the Devonian Presqu'ile Barrier reef complex (e.g. Helmet Gas Field and Clarke Lake Gas Field; Morrow et al., 2002). The purpose of this chapter is to evaluate the shale gas reservoir properties of Devonian—Mississippian strata in the study area using a multi-disciplinary approach. Production and resource potential will be classified through understanding key geologic and production characteristics to delineate exploration 'sweet-spots'. It is not intended 189 Mattson 70c -0 C  FP- cda SYSTEM Series Stages^Liard Plateau^Trout Lake Area Cameron Hills Penn. .,.. ,. Serp .ii."'"'"Irmnill Prophet  Besa River (Exshaw/Banf))<4" 1 4, g-::.2A, --1 Ahirshunda ,, W wean _ Tourn. Pekisko Banff edloinella="14"11 mpiram. - c al— c > 0 a) TI5 .s' — co Kotcho Te cho —I Besa River (Fort Simpson) Besa River (Horn River and Muskwa ) Trout River Kak ska .lean Marie^embe C. lathWna Fort^)e Twin Falls Simpson Hay River  Otter Park^Slave Point Horn ti-') -(5 . River^Presq.^Watt Mountain/Sulfur Point upper ------Klua/Evie •Keg River L̂ower Nahanni^Upper Chinchaga Nahanni • • I ^ Headless I^• Manet09, !^N/ -----r i r • He^s xr-7 Figure 5-1. Stratigraphic section of Devonian—Mississippian in northern British Columbia, south- eastern Yukon and south-western Northwest Territories (modified from Gal and Jones, 2003). Darker grey shadings represent shaly strata. Note: Presq. = Presqu'ile. 190 Bovie Fault126 ° N120° Eastern edge of main Laramide thrusting Liard Basin: Besa River shales and mudrocks Muskwa Otter Park Fort Simpson Yukon '‘.^Northwest ' ......... ,^Territories Alberta British^\t, Columbia^*,,s \, 1 CANADA] ri Study area 0 0 30 60 90 Kilometres Miles 55 Muskwa A Fort Simpson Fort Simpson & Muskwa 0 Besa River and Mattson Figure 5-2. Map of study area map showing well-core locations. Also highlighted are the Laramide deformation front (western limit of study area) and Bovie Fault Zone (location from Wright et al., 1994). Study region also includes southern Yukon (YK) and Northwest Territories (NWT) for wireline log correlations. Grid pattern (e.g., 94-N) represents the National Topographic System (NTS) coordinates for British Columbia. 191 to provide significant detail on the fundamental controls on gas capacities in Devonian— Mississippian strata (e.g. pore structure and adsorption, moisture effect, thermal maturity effect) as these issues are addressed in chapter 3 (also Ross and Bustin, in review). 5.2 SAMPLES AND METHODS Devonian—Mississippian shale and mudrock samples were collected from sub-surface core (see Table 5-1 and Figure 5-2 for locations), which includes the Besa River, Muskwa, Fort Simpson and Mattson formations. Total carbon (Ctotal) was measured using a Carlo Erba® NA-1500 Analyzer following combustion at 1050°C (1922 °F) with precision of 0.5% for Ctotal. Inorganic carbon concentration (Ccarbonate) values were generated using a CM5014 CO 2 coulometer with a precision of 2%. Fifteen to twenty- five milligrams of ground sample were weighed and reacted with HCI. Total organic carbon values were determined by the difference between Ctotai and Ccarbonate. Semi- quantitative bulk mineralogy was determined by x-ray powder diffraction (XRD) using peak-area calculations and corrected for Lorentz polarization (Pecharsky and Zavalij, 2003). Thermal maturity analyses were performed using a Rock-Eval 6/TOC pyrolysis apparatus. Quantity of organic carbon can also be determined using Rock-Eval pyrolysis, but the Carlo Erba® analyses were preferred due to the higher combustion temperature. A higher analytical temperature in the Carlo Erba analyses allows more complete combustion of the organic fraction which is important in highly mature rocks, such as in 192 Formation Sample Name Well ID Depth TC IC TOC (TVD; m) (wt%) (wt%) (wt%) Besa River UBS member BRS/C15-1331-1 D-75-E 94-N-08 3667.56 1.63 0.22 1.41 BRS/C15-1331-2 D-75-E 94-N-08 3669.43 5.90 0.22 5.68 BRS/C15-1331-3 D-75-E 94-N-08 3672.06 4.51 1.14 3.37 BRS/C15-1331-4 D-75-E 94-N-08 3673.94 3.61 0.42 3.19 BRS/C15-1331-5 D-75-E 94-N-08 3676.93 4.20 0.23 3.97 BRS/C15-1331-6 D-75-E 94-N-08 3679.19 5.48 0.50 4.98 BRS/C15-1331-7 D-75-E 94-N-08 3680.69 3.25 1.03 2.22 BRS1331-1 D-75-E 94-N-08 3751.51 1.98 0.02 1.96 BRS1331-2 D-75-E 94-N-08 3752.26 2.60 0.07 2.53 BRS1331-3 D-75-E 94-N-08 3753.01 2.68 0.01 2.68 BRS1331-4 D-75-E 94-N-08 3868.8 4.01 0.00 4.01 BRS1331-5 D-75-E 94-N-08 3869.55 4.90 0.00 4.89 BRS1331-6 D-75-E 94-N-08 3870.3 4.94 0.21 4.72 BRS1331-7 D-75-E 94-N-08 3871.05 4.51 0.09 4.43 BRS1331-8 D-75-E 94-N-08 3871.8 6.05 0.38 5.67 BRS1331-9 D-75-E 94-N-08 3872.55 5.28 0.02 5.27 BRS1331-10 D-75-E 94-N-08 3873.3 4.12 0.04 4.08 BRS1331-11 D-75-E 94-N-08 3874.05 3.84 0.01 3.83 LBM member BRS325-1 d-064-K 094-N-16 3344.85 2.27 0.25 2.01 BRS325-2 d-064-K 094-N-16 3346.35 2.27 0.33 1.93 BRS325-3 d-064-K 094-N-16 3347.85 2.29 0.33 1.95 BRS325-4 d-064-K 094-N-16 3349.35 2.53 0.06 2.48 BRS325-5 d-064-K 094-N-16 3350.85 2.14 0.06 2.08 BRS325-6 d-064-K 094-N-16 3352.35 1.88 0.17 1.70 BRS325-7 d-064-K 094-N-16 3353.05 7.84 6.94 0.90 BRS2563-1 b-019-K 094-N-16 3756.21 5.18 0.35 4.83 BRS2563-2 b-019-K 094-N-16 3757.94 4.52 0.30 4.22 BRS2563-3 b-019-K 094-N-16 3758.69 4.81 0.44 4.37 BRS2563-4 b-019-K 094-N-16 3760.56 3.10 0.30 2.80 BRS2563-5 b-019-K 094-N-16 3762.06 2.91 0.14 2.77 BRS2563-6 b-019-K 094-N-16 3763.56 4.20 0.77 3.43 BRS2563-7 b-019-K 094-N-16 3759.81 2.71 0.21 2.50 Muskwa MU414-1 C-28-D 94-0-01 1937.9 3.74 0.07 3.67 MU414-2 C-28-D 94-0-01 1938.65 3.65 0.02 3.63 MU414-3 C-28-D 94-0-01 1939.4 3.46 0.95 2.51 MU414-4 C-28-D 94-0-01 1940.9 3.86 2.45 1.41 MU714-1 A-009-F 94-P-03 2010.9 3.40 0.13 3.26 MU714-2 A-009-F 94-P-03 2012.4 2.85 0.07 2.78 MU714-3 A-009-F 94-P-03 2013.9 6.28 4.70 1.58 MU1416-1 A-94-G 94-P-08 1539.24 2.93 0.79 2.14 Table 5-1. Sample locations, total carbon (TC), inorganic carbon (IC) and total organic carbon (TOC) for all Devonian-Mississippian units examined in this study (TVD = total vertical depth in metres). 193 Formation Sample Name Well ID Depth (TVD; m) TC (wt%) IC (wt%) TOC (wt%) Muskwa (cont.) MU1416-2 A-94-G 94-P-08 1541.3 2.71 0.56 2.15 MU1416-3 A-94-G 94-P-08 1542.6 2.48 0.39 2.08 MU1416-4 A-94-G 94-P-08 1545.6 1.84 0.12 1.72 M1J1416-5 A-94-G 94-P-08 1547.2 4.43 0.83 3.59 MU1416-6 A-94-G 94-P-08 1550 3.36 0.10 3.26 MU1416-7 A-94-G 94-P-08 1551.2 2.09 0.04 2.05 MU1416-8 A-94-G 94-P-08 1553.68 2.79 0.24 2.56 MU1416-9 A-94-G 94-P-08 1555 6.27 5.83 0.44 MU1745-1 B-88-H 094-J-14 1949.37 3.88 2.00 1.87 M1J1745-2 B-88-H 094-J-14 1951.62 3.65 1.77 1.88 Mattson MU1745-3 B-88-H 094-J-14 1950.12 3.49 1.14 2.35 MU1745-4 B-88-H 094-J-14 1952.67 4.06  2.09 1.97 MASH1331-1 D-75-E 94-N-08 3182.1 1.99 1.81 0.18 MASH1331-2 D-75-E 94-N-08 3326.04 0.79 0.01 0.77 MASH1331-4 D-75-E 94-N-08 3329.04 0.77 0.19 0.57 MASH1331-5 D-75-E 94-N-08 3332.79 0.87 0.32 0.55 MASH1331-6 D-75-E 94-N-08 3409.41 0.92 0.42 0.50 MASH1331-7 D-75-E 94-N-08 3412.01 0.81 0.24 0.56 MASH1331-8 D-75-E 94-N-08 3414.73 0.85 0.22 0.63 MASH1331-10 D-75-E 94-N-08 3491.1 1.13 0.17 0.96 MASH1331-11 D-75-E 94-N-08 3571.18 1.25 0.16 1.08 Fort Simpson MASH1331-12 D-75-E 94-N-08 3573.43 1.28 0.22 1.06 MASH1331-13 D-75-E 94-N-08 3576.81 1.22 0.01 1.21 FSS26-1 D-82-L 94-J-02 1818.85 1.14 0.93 0.21 FSS26-2 D-82-L 94-J-02 1920 0.91 0.70 0.21 FSS26-3 D-82-L 94-J-02 2188.8 0.62 0.41 0.21 FSS26-4 D-82-L 94-J-02 2190.3 0.66 0.41 0.25 FSS126-1 B-92-D 94-1-04 1939.4 0.70 0.45 0.25 FSS126-2 B-92-D 94-1-04 1940.9 0.39 0.01 0.38 FSS126-3 B-92-D 94-1-04 1942.4 2.37 2.03 0.34 FSS126-4 B-92-D 94-1-04 1943.9 1.67 1.44 0.23 FSS126-5 B-92-D 94-1-04 2090.9 0.61 0.31 0.30 FSS126-6 B-92-D 94-1-04 2092.4 0.63 0.35 0.28 FSS126-7 B-92-D 94-1-04 2093.9 0.39 0.11 0.28 FSS126-8 B-92-D 94-1-04 2095.4 0.65 0.36 0.29 FSS126-9 B-92-D 94-1-04 2203 0.85 0.52 0.32 FSS126-10 B-92-D 94-1-04 2204.5 0.35 0.10 0.25 FSS126-11 B-92-D 94-1-04 2206 1.01 0.66 0.35 FSS126-12 B-92-D 94-1-04 2207.5 0.86 0.63 0.23 FSS126-13 B-92-D 94-1-04 2320.6 3.09 2.85 0.24 Table 5-1 continued 194 Formation Sample Name Well ID Depth (TVD; m) TC (wt%) IC (wt%) TOC (wt%) Fort Simpson FSS126-14 B-92-D 94-1-04 2322.1 3.26 3.08 0.18 (cont.) FSS126-15 B-92-D 94-1-04 2323.6 5.64 5.57 0.08 FSS126-16 B-92-D 94-1-04 2325.1 4.54 4.28 0.26 FSS129-1 A-49-B 94-H-16 1899.39 0.42 0.23 0.19 FSS129-2 A-49-B 94-H-16 1900.89 0.44 0.24 0.20 FSS129-3 A-49-B 94-H-16 1902.39 0.48 0.28 0.20 FSS129-4 A-49-B 94-H-16 1903.89 0.42 0.22 0.20 FSS129-5 A-49-B 94-H-16 2003.3 0.52 0.32 0.20 FSS129-6 A-49-B 94-H-16 2004.8 1.47 1.28 0.18 FSS129-7 A-49-B 94-H-16 2006.3 0.62 0.43 0.19 FSS129-8 A-49-B 94-H-16 2007.8 0.78 0.60 0.18 FSS129-10 A-49-B 94-H-16 2143.6 0.69 0.53 0.16 FSS129-11 A-49-B 94-H-16 2145.1 0.73 0.61 0.12 FSS129-12 A-49-B 94-H-16 2146.6 0.63 0.48 0.15 FSS129-13 A-49-B 94-H-16 2254.8 0.42 0.19 0.24 FSS129-14 A-49-B 94-H-16 2256.3 0.32 0.08 0.24 FSS129-15 A-49-B 94-1-1-16 2257.8 0.68 0.52 0.16 FSS1238-1 C-60-E 94-1-11 1857.11 0.56 0.30 0.25 FSS1238-2 C-60-E 94-1-11 1858.63 0.73 0.42 0.32 FSS1238-3 C-60-E 94-1-11 1860.17 0.46 0.17 0.29 FSS1238-5 C-60-E 94-1-11 1863.23 0.88 0.50 0.37 FSS1238-6 C-60-E 94-1-11 1864.77 0.61 0.35 0.26 FSS1238-7 C-60-E 94-1-11 1866.3 0.64 0.39 0.25 FSS1238-9 C-60-E 94-1-11 1869.37 0.73 0.46 0.27 FSS1238-10 C-60-E 94-1-11 1872.4 1.03 0.41 0.62 FSS1238-11 C-60-E 94-1-11 1873.93 0.70 0.20 0.50 FSS1416-1 A-94-G 94-P-08 1475.95 0.76 0.47 0.29 FSS1416-2 A-94-G 94-P-08 1485.6 0.39 0.20 0.19 FSS1416-3 A-94-G 94-P-08 1486.4 0.40 0.21 0.19 FSS1416-4 A-94-G 94-P-08 1487.2 0.46 0.30 0.16 FSS1416-5 A-94-G 94-P-08 1488 0.50 0.33 0.16 FSS1542-1 C-15-J 94-1-06 1485.25 0.56 0.27 0.29 FSS1542-2 C-15-J 94-1-06 1486.75 0.44 0.01 0.43 FSS1542-3 C-15-J 94-1-06 1488.25 0.35 0.06 0.30 FSS5245-1 D-31-F 94-P-08 1049.9 0.33 0.02 0.31 FSS5245-2 D-31-F 94-P-08 1054 0.37 0.01 0.36 FSS5245-3 D-31-F 94-P-08 1060 0.34 0.11 0.23 FSS7194-1 C-32-K 94-1-14 1799 0.52 0.24 0.28 FSS7194-2 C-32-K 94-1-14 1802.4 0.28 0.08 0.21 FSS7194-3 C-32-K 94-1-14 1807.6 3.12 1.75 1.37 FSS7194-4 C-32-K 94-1-14 1809.6 0.70 0.21 0.48 FSS8288-1 B-98-B 94-P-08 1035.9 0.97 0.67 0.30 FSS8288-2 B-98-B 94-P-08 1036.65 0.38 0.01 0.37 FSS8288-3 B-98-B 94-P-08 1037.4 0.43 0.09 0.34 FSS8288-4 B-98-B 94-P-08 1038.15 0.52 0.14 0.38 Table 5-1 continued 195 Formation Sample Name Well ID Depth TC IC TOC (TVD; m) (wt%) (wt%) Lwt%)^- Fort Simpson FSS12140-1 C-82-F 94-P-02 1430 0.81 0.47 0.34 (cont.) FSS12140-2 C-82-F 94-P-02 1431.5 0.38 0.12 0.26 FSS12140-3 C-82-F 94-P-02 1433 0.41 0.10 0.31 FSS12140-4 C-82-F 94-P-02 1434.5 0.46 0.01 0.45 FSS12140-5 C-82-F 94-P-02 1436 0.40 0.07 0.32 FSS12140-6 C-82-F 94-P-02 1437.5 0.46 0.15 0.31 FSS13703-1 C-28-D 94-P-02 1426.6 0.40 0.02 0.37 FSS13703-2 C-28-D 94-P-02 1428.1 0.39 0.01 0.38 FSS13703-3 C-28-D 94-P-02 1429.6 0.43 0.08 0.34 FSS13703-4 C-28-D 94-P-02 1431.1 1.29 1.03 0.26 FSS13703-5 C-28-D 94-P-02 1432.6 0.37 0.07 0.30 FSS13703-6 C-28-D 94-P-02 1434.1 0.39 0.10 0.30 FSS13703-7 C-28-D 94-P-02 1435.6 0.43 0.08 0.35 FSS1238-12 C-60-E 94-1-11 1875.47 0.64 0.32 0.32 FSS1238-13 C-60-E 94-1-11 1877 1.72 0.64 1.08 FSS1238-14 C-60-E 94-1-11 1877.77 2.69 1.17 1.51 FSS1238-15 C-60-E 94-1-11 1878.53 1.17 0.10 1.07 FSS1238-17 C-60-E 94-1-11 1880.07 1.68 0.16 1.53 FSS143-1 B-90-G 94-J-14 1896.97 1.22 0.13 1.091 FSS143-2 B-90-G 94-J-14 1897.72 1.35 0.03 1.3162 FSS143-3 B-90-G 94-J-14 1898.47 1.15 0.14 1.009 FSS143-4 B-90-G 94-J-14 1899.22 1.69 0.30 1.398 FSS143-5 B-90-G 94-J-14 1899.97 1.09 0.44 0.6546 FSS143-6 B-90-G 94-J-14 1900.72 1.41 0.48 0.9293 FSS143-7 B-90-G 94-J-14 1901.47 1.00 0.28 0.7199 FSS143-8 B-90-G 94-J-14 1902.22 1.22 0.25 0.9616 FSS143-9 B-90-G 94-J-14 1902.97 0.98 0.05 0.9314 FSS143-10 B-90-G 94-J-14 1903.72 1.36 0.46 0.9044 FSS143-11 B-90-G 94-J-14 1904.47 0.93 0.03 0.9047 FSS1528-1 A-65-G 94-J-10 1976 0.97 0.64 0.332 FSS1528-2 A-65-G 94-J-10 1976.75 1.10 0.63 0.4681 FSS1528-3 A-65-G 94-J-10 1979 2.43 0.04 2.3815 FSS1528-5 A-65-G 94-J-10 1982 3.07 1.21 1.8599 FSS1528-6 A-65-G 94-J-10 1978.5 2.35 0.42 1.9312 FSS1279-1 B-49-G 94-P-07 1800 1.77 1.04 0.7247 FSS1279-2 B-49-G 94-P-07 1800.75 1.49 0.67 0.826 FSS1279-3 B-49-G 94-P-07 1801.5 1.14 0.38 0.7608 FSS1279-4 B-49-G 94-P-07 1802.25 1.53 0.31 1.221 FSS1279-6 B-49-G 94-P-07 1803.75 2.33 0.98 1.3555 FSS1279-8 B-49-G 94-P-07 1805.25 1.74 0.70 1.0344 FSS1279-9 B-49-G 94-P-07 1806 2.60 1.19 1.4146 Table 5-1 continued 196 this study. A volumetric, Boyles Law gas adsorption technique was used to measure high pressure methane isotherms. For each sample, pressure points were collected up to 9 MPa (1300 psia) and the adsorption data fitted to the Langmuir equation (Langmuir, 1918). Moisture equilibrated samples of approximately 150 g were crushed and homogenized to 250 p.m in a ring-mill for adsorption analysis. Moisture capacities were determined by water saturation at 30°C (ASTM D1412-04, 2004) which is recommended for moisture content under reservoir conditions. The method required equilibrating crushed shale samples over a saturated solution of potassium sulphate for more than 72 hours. Porosities were determined using a Micromeritics x Autopore IV 9500 Series. Using mercury capillary pressures, permeabilities were calculated following the Swanson (1981) method. Although there are limitations using the Swanson method (mercury as analysis fluid and effective stress of 1000 psi) it was used here for comparative purposes among units. 5.3 SEDIMENTOLOGY 5.3.1 Stratigraphy The Devonian—Mississippian strata in northern BC, south-eastern YK and south- western NWT consist mainly of shales, mudstones and carbonates (Ziegler, 1967). Prominent Late Devonian depositional features include the paleogeographic depressions and reefal-reentrants of the Cardova and Klua embayments (Bebout and Maiklem, 1973; 197 Phipps, 1982), Arrowhead Salient (Phipps, 1982; Morrow et al., 2002) and the Liard Basin (Gabrielse, 1967; Wright et al., 1994; Figure 5-3). In the Liard Basin region, west of the Bovie Fault, the mudstone-shale sequence of the Besa River Formation dominates the stratigraphic section (Figure 5-1), spanning the Devonian—Mississippian boundary and overlies strata of the Nahanni carbonate platform (Morrow et al., 1993), and Manetoe dolomite facies which replace limestones of the Nahanni (Morrow et al., 1986). The Liard Basin is a sub-basin of the WCSB (Gabrielse, 1967) and contains up to 5000 m (16,400 ft) of Palaeozoic and Mesozoic sedimentary fill (Walsh et al., 2005), covering an area of 25,000 km 2 (9600 mi2). For the purpose of this study, we have subdivided the Besa River Formation into three informal stratigraphic units for shale gas evaluation based on gamma-ray response: 1) a lower black mudrock member (LBM); 2) a middle shale member (MS) and; 3) an upper black shale member (UBS; Figure 5-4A). Golata Formation sediments deposited during major late Visean regression-transgressions (Richards et al., 1994) and the sandstone-dominated deltaic and deltaic-related slope deposits of the Mattson Formation overlie the UBS member of the Besa River Formation (Braman and Hills, 1977; Richards et al., 1994; Figure 5-4B). The eastern lateral equivalents of the LBM member include the Horn River and overlying Muskwa (MU) formations which range in age from Givetian to Frasnian (Williams, 1983 and references therein; Figure 5-4C). The eastward transition from Besa River sediments into the Horn River and Muskwa formations coincides approximately with the Bovie Fault Zone. Included within the Horn River Formation are shallow-water carbonate shelf successions of the Upper Keg River (skeletal lime- wackestones; 198 58°N -126°W 59°N 60°N 61°N 62°N I^I^1^I^I^I^I^I , ftMikes 75Khometres^120 111111111 II 11111II N II MI MNri INNII IIII nicamin ii Elmmil iiiiMMnoile. WIMFENIMErildell ^iiWI I 11111111111111 11MIN NOMMMOMEPOOMMOM 101011111111111111 al MMON INORLiiiiirtzlE POMOLONINOMIOOMMOMMOMMOM oximmonsumm;;-7.mou OlOOMMOON MOMTMAOMM7500POMMOOMMOOMMOREMOOMON OOM000000=1105110 I IN limo NUMMI El 111111.111Eminiummumuum. 000MOMMOOMOU20000 MMOMMOMMOOMMMO OMMOOMMOOMOU OO■■■MM■■NMO maluaaramamocammumacememealummum PM/OOMMUJI MOO 0......■ MO■MOOMOON■MONVOMO -g IMMOMESAMMOMONOOMPMEN MOOOMOMMOIOMOMMOOMMOOPOMOODIO Al MONO .mmummumniamommensompowom►lummul MO / M OLMONOOMOMMOMOMMUO IMM■■■■OM■MOOOMO 011 MOOOOMOMONION fir^1 MillOOW7777711 MOOMMOINOMMOMMIM MMUMMUMOSOSNENOMMON ONIMOMOMOMMUKNOM. MONUOMMOMMUNIMMOVIMMWOMM00 0 XIMMO num§ ' n 0 a OMMTAMOOM OMMKUMOP"mROMMOOOMMMO MOMMOONOMMM MEW 1111 ,Z;- ,!■■■■■OOOROMOOMMO NOMMONOCON ONIUMMENNO -,17,7,111mmummommumum OOMM■■MMONIONOMAI■ MMOMMIIMMOMOOMMOOMCOOMM20 mosilimanommummonan OMMOMMONOOMMOMMOOMMOOM iii■MOMMmOMMOONOOMMOMOPOOMMOMO MMONOONIMOOMOMMOMIONONO ■MMOO I 0 MOOMMOOOMOONOMON. mummummumai MMOMOMOSIMONOMOOMWV MOOOOMMOOMOOMIONOMMO OMONI IMMOMOOMOMMENMOMM MOMMONNOMMMONOMMOMM-^V VOMOMMOOMOMMOMOMOSMOMON MOMMON COMM MOMMOOMEVOMMOMO MONOMMOMINVOMOMOON -125°W -124°W -123°W -122°W^-121 °W^-120°VV Figure 5-3. Major paleogeographic, depositional facies and structural features which affected Devonian—Mississippian deposition including the Cardova and Klua reefal embayments. Also shown is the Trout Lake Fault zone (location from MacLean and Morrow, 2004) — see Structure text for discussion. Cross section lines for figures 5-5 and 5-8 are shown. Light grey regions represent carbonate-dominated facies. Dark grey regions represent basinal/argillaceous facies (Note: Yukon and Northwest Territories use the grid-section-unit system of surveying, not NTS, hence map grids are different to British Columbia). Black squares show well locations for figures 5-4, 5-9 and 5-10. 199 0 150 2000 RHOB (kg/m') 3000 WARN,^,^,^I ; T CI RundleGroup Perki5ko andShalocl. formabons IrtFT^1"wil Ilki:MI•"1111 ^ L VAN BIPM 4T"- i-li I rtri.atirl' C---_„„ ___.....___ ...in ".S. IR .1^11 Iail lien &III I , -7 7 ori=4-_, T I1111M::::--1172 III^IIII 11^t. 1^IL1 1111111111WANianuilii= -,En 1E -IMW/E----— _ Banff 1I T 11 r 7 1-•-• MI- 1111..L, EIMIIMMIalIVinime UEISMurkier Exellaw IN t " ME F...„ ,^II , 7 1 NOM ,- VvInterbum NS 1,- -•^t-4 bran NSMember Equivalents leg Fort Simpson Jeer Mane 111 1- r-1 L A 7rt-t^ri Il&ilth Red Knife, Keluelutt TH [ --'peamiNNE...-1111111111m i Mill surse,q, Muskwa 4 II- 1 -1 -*sall Otter Perk/ ML-,Hglilj U344 Member Slave Pc4ntiSulphur Potnt L I .1 t_ °C•VOMi^,^i ■Nr.11•Thiw___.- Memom— mlimw'ft--71i Keg 11 i^1^1 ^ IT^I 1E11 Mahan. River 10E DUNEDIN D- 075-E/094-N-08 Location : 200/d-075-E/094-N-08/00 GR (GAPI) ... Ili^DT (us/m)^QS 1^ILD (ohmm)^118.1,I^1^1 :...... -now ._:...m.n. - 11 ,^t :4 4. - t,.ILL II 7 1 '..--1^ ,....,_^_ 14+,^ ,^-1-1 I i^I ..t 11 - 1^I T 7, r 1,-^-, eiil .r1- ,t•-r^r ,..,...... - 7^i I^..-"--...71111111.1111 .,4-11111 ....... 11 IT •^. 1 i 4^I-1--.. . I--I-11^1^I Nre‘Mil •-• .....1^1^.. ...4^, _-• at ^'. ''-. ---..-- 1 4111UOMIN i -1 NM ..1.& 7^_,,E "-} 1...5s1 . • 1^t^i .1"^I^I 1.1 r ,.-'711111 111 I■1 ICtle:kr.N4 ,_i^J1^■L. 1_1 -11^t I^I T T r^1-I-1 I^I^I I^I^1 ,---1 lI ..4., VI^• I^I^I^I 1- I-I-4 f 'MIMI NIL - -i al, 1:1.- ill_ _1 , ^1^7^1F........ IIIIIIIIIIMMIIIL ...Re -LI 1 I^I^I rr •. f^i^i^i nn -1 • • •t: , "^-, --I I^I^I 1 1 L -S-f __i_ j^I 1^t^I^I 7^G- t- t. ;^,,,, ‘t...1/4.1..1. ,1'y.1, 1,- -I-4 .1 1 I L^'^- I^I^I^I7 - Ir I_t$t!, en/^.... eg•e• , :v: -In +^-4 I^i^ ..1. L r 1^I ii .1.^1- 1_1 -I, _I, PTF HELMET B- 071-J/094-P-10 Location : 200/b-071-J/094-P-10/00 500^DT (us/m)^100 1111116:1, ,^, . Rettikeite iii 1.1w IIIIIK".*'211• ..^.. . nirlimi... .a Jew /Aim 1 4-1 1 I IIIITAI , FM II ril I I7 Ell.W.;; IIII --,-...._i. J L IL, ILI _111, 1 ]^-....n. INE . n il 7 rI wrz-r- i r LIB^i , 1 L^. 1 J _I 1 1 Fort Simpson __-:-.....^.;w,. MNle-I rt-t VI VIII -3111 LI intill - 11111 hl all IIII 7 Ft^III WPA.- r ■ a Q !MINION, LI L^ ON. 1_1 L i Mvekwe 91&71z EMIC Otter Pa* iII^C— I 4. Ir Mut Slave Pool 1, IWIMII 1 Li^L^,^.- J I FAA I^_ Evil, Miliril:' Keg fibrinMINN 411111.i I i^- ,rI GR (GAPI)1100A 1200 1300 1400gO 1500 1600 1700 1800 1900 2000 GR (GA PI ^500 DT (usim) iQg 0 ^ 15 aos) RHOB (kg/m') 000 E .e 2900 3000 3100 3200 3300 3400 3500 3600 3700 3800 r 0 3200 3300 3400 3500 3600 3700 3800 3900 Lbird Basin Region Eastem Equivalents OUESTERRE BEAVER B- 019-K/094- Location : 2001b-019-J/094-N-16/00 A Figure 5-4. Well logs showing typical response through stratigraphic units. (A) Subdivision of the Besa River Formation into informal units for shale gas reservoir exploration (LBM = lower black mudrock member; MS = middle shale member; UBS = upper black shale member) with eastern lateral equivalents. (B) Wireline log response of the UBS member (Besa River) and the Mattson Formation. (C) Typical log response for Cardova embayment strata, which include the Muskwa Formation and argillaceous carbonates of the Evie Member and Otter Park Formation. Hriskevich, 1966), Sulphur Point (pelletal lime wackestones; Norris, 1965) and Slave Point (reefal limestones; Griffin, 1967). Underlying the Horn River Formation are crinoidal dolostones of the lower Keg River Member (Hriskevich, 1966). From east to west, strata within the Horn River Formation become increasingly argillaceous and were originally subdivided into three basinal deposits: the Evie, Otter Park and Muskwa (Figure 5-5; Grey and Kassube, 1963). Within the Cardova embayment, strata-fill also includes the bituminous shales of the Klua Formation, defined as "a tongue of Otter Park shale in the carbonate barrier" (Figure 5-6; Williams, 1983). Klua shales and basinal argillaceous carbonates (Evie and Otter Park) in the embayments were deposited during two large-scale transgression-regressions (Morrow et al., 2002). Highly radioactive Muskwa shales, which are now given formation status in the Woodbend Group, are interpreted to record an abrupt sea-level rise or transgression across the WCSB (Williams, 1983) and subsequently generated most hydrocarbons in Late Devonian reservoirs (Allan and Creaney, 1991). Conformably overlying the Muskwa Formation are Fort Simpson shales (FSS), which represent lateral equivalents of the MS member (Besa River Formation). Organic-rich mudrocks of the Exshaw Formation are equivalent to the UBS member of the Besa River Formation (Liard Basin). 5.3.2 Thickness Besa River thickness ranges from 675 m to over 1000 m in the Liard Basin region (2200-3280 ft; Figure 5-7A) with the middle shale member comprises up to 750 m (2460 ft) in the eastern part of the Liard Basin (Figure 5-7B). The LBM and UBS members are 201 Black, bituminous, organic-rich shale/mudrock Key Basinal, argillaceous carbonate Organic-lean shale Argillaceous carbonates Shallow water carbonates Interbedded sandstone, siltstone and shale Figure 5-5. Key for cross-sections (Figures 5-5 continued, 5-6 and 5-9). 202 C-015-I 094-0-06 C-094-1094-0-01 B-086-F 094-P-04^A-081-J 094-P-04 A' A 50Mlles0 0 Kilometres 80 D-073-H 094-P-04 A-029-G 094-P-04^ A-004-L 094-P-03 C-020-K 094-P-02 Datum: Banff Evie B-021-G 094-0-06 West East B-072-K 094-0 01 4^ Klua Embayment Figure 5-5 continued. Log-stratigraphic cross-section. Cross section A-A' (Figure Y-3) of the Klua embayment showing the westward increase in thickness of basinal, argillaceous deposits of the Horn River and Muskwa formations. Datum = Banff Formation. B' ^ B 0 Miles 50 West Cardova Embayment 0 Kilometres 80 East C-015-E 094-P-10 B-020-I 094-P-16  B-015-F 094-P-16 C-057-A 094-P-15 IBM IME 15 IME1151671111r1.1111 11111iSIIIIIII ----la.0.!IM^ jib'  —".......-Ia'. ^ ITIVE3Irli^ !'illat.31111!Titillf imaW MUM LITIIKz am '-;-• si..- --.= MINIM JIM^ i II OM, -111 IlvilliMit; All  BM MN IMO^IL1111111C4 MI^ 1111 IIIMILIMI MI MEE UM^111111111MFAMI IIIIMINMII^ ■113111111=11111Meseres rininaliev_ _..... ^....._...... -, yailimaiLi^mai■■ss.  ...p.m..1* maiNile.^ 10111111111111111101.11111 1111-11.14111111111111".NIIE MI ■iIIII■MIII^ imliTigaii.....miinujj ^filliMati Allriati^rimioniiros 14111-11iiiiirill LIMMON...._^111111111 II^ 18111111111111 IIIIIIIIIMMI 3 1.1111111=1.1111 011111111,11 tniIMINIVIII laiNgsguirtm ^,1111111,011":11MMIM311 ^ 1■04111111.AM it _110- _ .210^FA IIIIIM. AM KIMMINS ill NC IIIIsr -1111 111011111- 11illglIPiL dilIM^111 115 Zi^ ils.:411 MIMP-all ^ 10141M,:-7=. -411viE^ril____---- - .7.111112:77117: IN MEW as MIV IVIIIII IM al Intilill171011017-IIM 111115111.: MI 111121111111111^ 1.111MILE IIMMillev.- - 1111^ 1111611'11^Kivu -4.1^mom us^►im VMS 1111^wa- um nu MOAN mums- AMMINII- ill^MIEM 1MR 1111 ■ 11,111L1111^UM illik,-. "MN MU^Itilliltill^waisma. MMIMM /111111:10111r1111IIIIPor-itill^1111111Fil^MIMEO Mill MIIIMMIMM IIMillax NMIIKAPI,-.1111 IIIIIIIMMII 111101--tr. Mg^MIME 4111 IIIIMIIII MN MIMMIIIMM^ 111111111P- 111 MILIMIL IIIII 11/11M,M11^MIIMIRE,: 1111^1113111111:111 IIII maw a P 3111 MINIM MN^INJ11 1 i.1mp- 4.• ME _law wit now•Tsativempor RIIImr.' 15 ^111111WP.1111 111111rnallt11111M7 /III^ IIIIIIV AIII "LIRIM1w, 111111^ (111111111111 .:31.1111:11 1111/1111r4r IIIMINIMIll^ tiallian!!!!! "1-1166211-11,,A11%41111C.11111MisTaii :11€ tretrat--t....wilosiliur-iimMINIE-taliftiva^IIIIIMMIIIII..--,meuriaiitria kurnmicraalmum  —...i....... .....2M1111111111M.:1 tigtir" Figure 5-6. Cross section B-B' (Figure Y-3) though the Cardova embayment (orientated E—W). Datum = Exshaw Formation. Logs shown: gamma-ray (profile on left); sonic, density and/or resistivity (right profile). tad^ %Bann 11`4111r=111111 ..;a1111511^ W-41 11".11r•"' 1k1111111CAM = 11Q.IFIVOIINAM 1111111111KIIIM^ 111111MIYAMNI WNW AIMKimesiwuni  Datum: Exshaw OaIlt/iiiiIS ill. =rail^ We Mat raMMINUMIM VOMINMS. tli;611111111111711 Remo_rimam us alum 11!IIIMM1111 11111111011^1 ire 11101111M11 11111111111 •1141111111110 1111115....-241 11011PQ.- B-071-J 094-P-10 D-014-D 094-P-16 It 11111111111111•111= *All 7...,...alMollrawg it^Klua OillA11.111—It't^ifftliiiiiitiamilm.......... -.... .....-- , `Amman. 1Keg^ 1-11"—mi.7 6-.1 -riIIIIIIIMIE Ill River nikiiIILIMIL la III^111es^75 IL^---^12^111111■1111 IMMOMO ON MOON MUM ROOM OMMOIMINIM MO 1110 ammo MI IOU= 11=1 SINOISOOMMIO IO MOIMOOSINWRIMMO, ON MI IONIIIIICINNII II ION ONIONS IMO, MO OMOIROMIS MOINAN'II 1111111/1OF 1 I MI 94 -P 14T 94-K^94J 944 1i.  =. -- A__^1111111111101 94-K 94-1 94-P 58°N^ 58N —126°W -125°W —124°W —123°W —1221N —121°W —120°W^-426°W —125°W —1241N —123°W —122°W -421°lN —1201 4/ 62°N 0^Wft^75 Kdameters^12 ti 94-P 944 6rN —51 1 62°N 61 N 60°N 59°N 62°N 61°N 60°N 59 N 61 N 60°N 59 N 61°N 60°N 59°N N 94-F' 944( 944 I^I^I wes 0^mometm̂ 120 <Y BC 94-N similar in thickness, between 60 and 240 m (200-790 ft; Figures 5-7C and 5-7D). Pelzer (1966) suggested that the general west to east shale/mudrock thickening across the Liard Basin represents the clinothem of an undothem-clinothem-fondothem model, in which basin-filling was a series of prograding wedges (after Rich, 1951). The overlying Mattson strata vary dramatically in thickness across northern BC due to erosion from the eastern side of the Bovie Fault (see Structure section; Taylor and Scott, 1968). Basinal strata of the Cardova and Klua embayments (including the Horn River and Muskwa formations) range in thickness between 30 and 240 m (98-790 ft; Figure 5-8A). The Muskwa Formation reaches a maximum of 80 m (260 ft), increasing in thickness towards the Bovie Fault region (Figure 5-8B) whereas Fort Simpson shales attain thicknesses of over 1000 m (3280 ft; Figure 5-8C). 5.3.3 Structure The Liard basin is bounded on the east by the Bovie Fault Zone and on the west by the eastern edge of Laramide thrusting. Bovie Structure is interpreted to be the product of two phases of tectonic development: 1) initial crustal uplift and compression during the Permo-Carboniferous and 2) a second phase of convergence during the Laramide Orogeny (MacLean and Morrow, 2004). Strata displacement across the Bovie Fault Zone reaches a maximum of 1200 m (3940 ft) over a horizontal distance of 0.5 km (0.31 mi; Wright et al., 1994) and represents a significant change in reservoir depth of Late Devonian—Mississippian strata (Figure 5-9). Syn-depositional faulting led to the preservation of thick Mississippian strata (Mattson) in northern BC (e.g. 94-N, 94-0; 206 1 r ww^(„, O 58°N^ -126°W -125°W 1 -124°W -123°V -122°W -121°W -120°W 59°N 9.44( 153 59 N 60°N 61 N 62 N 58 MMOOMF71IIIIIIIWOMO MOW MINI it 1 NINON NOIONOIMMOINIL N I11141111111111 MOMMOIMICA IMMO MOM INIMMOOMO MIN IIIIMMINIIIMIPME EINUMMUMIROMO OMIBINMOINOMMENONOWONSICIONAMImoolomoor -1111111161INIOIMOS■OMMIL ' sissamen.ummounummummum 19111111111,' 4- 41MUIRMIIr-- \i)e^■ ° 1^,2.^.4 ',01f4 6 1 100, "iteek.1^.,^•^p 944( 04 'CI; milli limmEmlimmilmansmommumwrimemmimmoommoomoomoloommesoloosonI l'ilIl1111 I I 11111mom Imo= mum EUMMUMMONNEMONSNIONNOMMOM IMMOOMMEEMIIIIII IN■MMINOMMINIMIONIMI OMOOMOMMOIIMIONM■MOOMOOM INIMMOOOMMI 3111111111111,MN IMOMOOMMOMIONMO MAUI*0 0 . s S ^•^°0 0^. 944( a t f . v 62 N 61 N 60°N 59 N -126°W -125°W -124°W -123°W -122°W -121°W -120°W^-126°W -125°W -124°W -123°W -122°W -121°W -120°W ^. 11WW.11101211‘21.46513EINITIM■ MOOMMIORMISOMATIONWRI IMOMMIMORIMMENMEMBEI ■■NO■MOIMMANNIMINIUM INUMEINIMENIUMMI61°N  EIMINNISMINVETIMINIVE INOMMINIVEMBinsmum ouloomoomostoomot000mo■I■■MEINIMIUMOVIIMMIUMMINUILIM IOWEIMMINE0111.7113111EFIPLINI Figure 5-8. (A) Isopach map of the argillaceous/basinal deposits of the Horn River and Muskwa formations (contour interval = 25 m). Note thickening trends are primarily associated with the locations of Cardova and Klua carbonate embayments. (B) Isopach map of the Muskwa Formation only (contour interval = 20 m). (C) Isopach map of the Fort Simpson Formation, showing similar thickening trends as the Muskwa Formation towards the Liard Basin region (contour interval = 50 m). Thicknesses of Fort Simpson lateral equivalents in the Liard Basin are shown in Figure 5-7B (MS member). 62°N 60°N 207 58°N —126°W 60°N 59°N 61°N 62°N 0^Miles^75 g4 4^I^i Kiloma:l....:iliallfil REI CIRO 111111 IIIwpm" iii 11111111 -111101_ 6 ,_- MIMI 111:8111111 1123 1111 IrdilIMILIMINIII 111 11 1111 11111E111111111111 MINN MIEN .1411O1111111 MIMI NutYK rim:towel. BC 94-N60; • 9, 1 94-K ; 0iP1 94-J0 00 94-1 D —125°W —124°W —123°W —122°W^—121°W^—120°W Figure 5 -9. Structure map to the top of the Muskwa Formation (and the LBM member lateral equivalent in the Liard Basin). Note significant change in burial depth across the Bovie Fault zone (contour interval = -250 m). 208 Morrow et al., 2001), but these strata were eroded from the eastern side of the Bovie Fault zone prior to deposition of Triassic sediments (Figure 5-10; Taylor and Stott, 1968). Basement faults may also have controlled the position of the Cardova embayment which existed as a reef-rimmed basin through Slave Point time (Morrow et al., 2002). Another significant fault zone is the NE-trending Trout Lake Fault Zone, which changes the orientation of the Bovie Structure westward (see Figure 5-3; MacLean and Morrow, 2004). The Trout Lake Fault Zone, likely related to ancestral strike-slip or transfer faults of a crustal scale (Cecile et al., 1997; MacLean and Morrow, 2004), is interpreted as a component of the "Celibeta Structure" (Williams, 1977; MacLean and Morrow, 2001), a structural high that may have formed during the Early Cretaceous (Wright et al., 1994). 5.4 TOTAL ORGANIC CARBON/ROCK-EVAL RESULTS. Total organic carbon (TOC) contents of Besa River rocks range between 0.9 and 5.7 weight percent (wt%; Table 5-1). The LBM and UBS members have higher TOC compared to the MS member, which typically has <1 wt% TOC (Figure 5-11A). Interbedded shales of the overlying Mattson Formation, sampled from one well, yielded TOC <1.5 wt% (0.2-1.5 wt%; Figure 5-11B). Total organic carbon contents of Muskwa rocks ranges between 0.4 and 3.7 wt%. Similar to the Besa River Formation, carbonate- rich Muskwa shales have lower TOC (e.g. samples BRS325-7, MU1416-9 and MU714- 3). Fort Simpson shales are generally organic lean (<0.5 wt% TOC), except for strata 209 C-056-8 094-0-05 6-092-A 094-0-16 East C 8-091-8 094-0-10 West A-079-8 094-0-11 D-046-H 094-0-11 A-068-8 094-0-16 Sea-level Bovie Fault Zone Besa River Nahanni IMPUI lmt:t irma71 as a.r.al MIA MILIM VC= :31:2442all CU= madam sm6611111 -mammon =ma mi 0-061-A 094-0-15 0 Miles 75 120Kilometres Figure 5-10. Cross-section C-C' (Figure 5-3) through the Bovie Fault zone highlighting erosion of the Mattson Formation across the Bovie Fault region. AMOCO ET AL LA BICHE A- 067-D/0 Location : 200/a-067-D/094-0-13/00 GR (GAPI) •CO^DT (us/m)^100 2000^R HOB (kg/m3)^3000 =111211, Mir^.1914:111T177111; LI -  -11 11 ill• 1111 t^i I- L'_11 ,^.1 i 31 177! I^I^I - -MIIII 11 11 ElI^I - ILL 1 -; II I^ _ _II 1 - ,^,,- kii ^1111 ^, ^ ,^,.^i h9,-„. •,-,^1, ,ill Iu.,03^L Sr ei 1 T rlitl tq ' MEM r r.., i I III]^i .M.1A-^1^II 1 T i il I- 11 I- 1 r &L....4 tiirl t^T gin El ,r,- , -; k-, , 5,1 , , ,-, 111 1 r 7 r^..:4 Tn_...- f -1 ti 1111 r111 1 r- n I itml 1 ri 01111Wil Oil intiligillati '-r--. .;NTeaine lijnrirnlair::iiallINI•wie il!7 1111 . i -t^7 leAl r I-1 'I n 1^Ili - 1^rl 1111 `1^r -2 rl I111 r ri i - Iill rri^-1 t ri it.-71=2 ummurainuo FANNIN 1111 , t1 IIIIINIMNIIIIIINfildill 711 fill 1 T r ill^^I 1 11 r-j1^t''^-.1 Ea 3200 3300 3400 TOC (wt%) o^1^2^3^4 5^6 3500 3600 MS member 3700 LBM member 3800 10E DUNEDIN 0- 075-E/094-N-08 Location' 200/c1-075-E/094-N-08/00 GR (GAPI) 00^DT (us/m)^100 0^ILD (ohmm)^10'-' ME= :=-w---.'-=— C0a 0 0 c0 V 412 c033at g 0LI- 'il ?.. Ce I awl -4....-__=.^1-- r • _^- ,^_,_, 4^1 ,..,H, 1 1 1, • la--^.. – t_ __ t^I I r-r t„ i:r_ _ lr._ti I^I^l^t -ti -I - t_^_ :.....,_.1_, 1 'I -I '1 I^t^l F.--ott-, I^1^I I- I- •r1-I I^>t ...^t Ay -I^-4 .ti^1 - I^I - I^F 1..._ ,^-........,..--^.....a I^I^1 Î. r r r r- 111, -1.4--.1^-'i  -^.1 ' ,^H ij ^I tii^11 r 'I-^n 1111 - .1" 1-1 1 I^I1 I^I J _f T i ii _1 n- - -tt^1^I I^_I^J -1, ..), MIMI" F '-'-'-42* ,..^, 4rrr Y7 .=111 -1-11^,^1 1 ....". 4,..:^-4, MEM. - .17-t JJ...1 -.4 i^,^i Ill 1l I^".-^—11 0111tal I^I^I 4,..1.314in --I --1 -I I^t^d^d rrr ri.".....,„4- ling ,. ,-, zz. till -4 -I -i '-...111L 31 •- ^ 7 -I 4200 4300 4400 4500 4600 4700 4800 4900 5000 5100 TOC (wt%) o 1 2 3 4 5 6 UBS Member Figure 5-11. (A) TOC versus well-log response in down core profiles of the Besa River Formation. Note low measured TOC in the MS member (lateral equivalent of the Fort Simpson Formation). (B) Core profile of TOC contents versus well-log response in the UBS member (Besa River) and Mattson Formation. near the Muskwa contact, where TOC concentrations reach 2.4 wt% (Figures 5-12A to 5- 12E). Rock-Eval pyrolysis did not yield a distinct S2 peak (Table 5-2) due to maturation levels exceeding that of oil generation and preservation (i.e., into the dry- gas/thermogenic gas window). According to Peters (1986), an S2 value less than 0.2 is unreliable (as are organic carbon contents <0.5 wt%), hence the erroneous Tmax values. In the Liard Basin region, Devonian—Mississippian samples have mean vitrinite reflectance (Ro) values (measured or equivalent) between 1.6 and 4.5% (Morrow et al., 1993; Potter et al., 2000; Stasiuk and Fowler, 2002; Potter et al., 2003). During the Paleozoic, geothermal gradients may have reached 65°C/km (Morrow et al., 1993) which is significantly higher than the current geothermal gradients, 30 to 40°C/km (Majorowicz et al., 1988) suggesting a complex, multiphase thermal history. Despite the high levels of thermal maturity attained by these rocks (most notably the Besa River shales and mudrocks), TOC is relatively high, highlighting the good-excellent potential for natural gas. Pseudo-Van Krevelen plots are of limited use in determining organic matter type as the over-maturity of the kerogen restricts the discrimination of marine versus terrigenous organic matter because hydrogen indices and oxygen indices are near zero. 212 ECAOG TRAIL C- 002-H1094-0-10 Location : 200/c-002-H1094-0-10/00 DT (us/m) 500^100 E a 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 TOC (wt%) 0 1^2 3 4 5 6 Fort Simpson Muskwa & Horn River formations Keg River DT (usim)GR (GAPI) B 10E UNION SHEKILIE A- 094-G/094 Location : 200/a-094-G/094-P-08/00E a)a 1000 1100 1200 1300 TOC (wt%) 0^1^2^3 Fort Simpson Slave Point Muskwa 500^ 1000 150 1400 1500 1600 Figure 5-12. A to E: TOC core profile through Horn River, Muskwa and Fort Simpson formations. rd1 Welt Name : PC ANDERSON MILO Location , 200/d-089-131094-J-11/00 GR (GAP!) { 110M5!-° Iiiill El 115° 111111P1111 DT (usim) L i op OM MM. El I 111111111Kallilowirm MS  it MIIllitZt .1 L La 1111111111211111L 111TAN -^' Ell i^, OE 111 ME 11 111111 1 In '^- ta Will INIMMEIN MEOW -ik44,41,„1111111Iul LI ,Williki 311"."mitrwe' .. EME INEMINid' ;iii EN 'Ai =EOM FAIN MIMEO 111111=111 IMININEVIIIIMMINIM GR (GAP! ci 0^150 1900 Kakiska Jean Marie 3000 Well Name : ECAOG TRAIL B- 091-13/094-0-10 Location : 200t ,-091-13/094-0-10/00 Fort Simpson Muskwa & Horn River formations 2000 2100 2200 2300 2400 2500 2800 2700 2800 2900 E 19002000210022002300 24002500 2600 27002800 3000 3100 2900 E fi a1900 2000 210022002300 24002500 2600 27002800 TOC (wt%) 0^1^2 3^4^5 Well Name ECAOG TRAIL Location^b-002-H/094-0-10 R (GAP!) a 140^DT (osit)^41 R1108 (gm/cc) fill="-= ININNEVINI etii71 111121ffilil NINENr .4 INIENV1111 ENO 111ffitAlli 1111P-9 INNINIP_ININ INIC INEENINNIE it^ NEi IMINI41vein - gtheltit-,NINNE', NINNINDIEN NE n i* MEW ,,, NEM INN iii,,c III NNW ins ff.: sk. S' ill! k MK. IL izam 161111 m" 6- ILA 1111,17'!-' 11- 311^, 111 ..-..............-.-Terdw 11111r3;A.. - AinIlla I lit,^/ 1^, LI^1_1 TOC (Vet%) 0 1 2 3 4 Fort Simpson Muskwa & Horn River formations Figure 5-12 continued Sample Well location Depth Tmax S1 S2 S3 PI HI 01 TVD; m .e mg HC/g rock mg HC/g rock mg CO2/g rock S1/(S1+S2) mg HC/g TOC mg CO 2/9 TOC MASH 1331-11 D-75-E 94-N-08 3571.18 404 0.01 0.06 0.13 0.14 5 12 BRS-C15-1331-5 D-75-E 94-N-08 3676.93 609 0.04 0.13 0.47 0.23 2 8 BRS1331-1 D-75-E 94-N-08 3751.51 369 0.03 0.04 0.19 0.42 2 9 BRS1331-6 D-75-E 94-N-08 3870.3 611 0.04 0.07 0.51 0.36 1 9 BRS325-3 D-064-K 094-N-16 3347.85 416 0.03 0.10 0.19 0.23 4 8 BRS2563-5 B-019-K 094-N-16 3758.69 421 0.01 0.07 0.13 0.13 2 4 MU1745-1 B-88-H 094-J-14 1949.37 426 0.03 0.14 0.18 0.17 6 8 MU414-1 C-28-D 94-0-01 1937.9 609 0.04 0.07 0.34 0.36 1 6 MU714-2 A-009-F 94-P-03 2012.4 594 0.02 0.24 0.16 0.08 7 4 MU714-3 A-009-F 94-P-03 2013.9 400 0.01 0.21 0.26 0.05 9 11 MU1416-1 A-94-G 94-P-08 1550 601 0.01 0.17 0.24 0.06 7 9 Table 5-2. Rock Eval pyrolysis data for a representative suite of Devonian-Mississippian mudrocks and shales. S1 and S2 represent the amount of hydrocarbons volatilized at 300°C and evolved from kerogen at 300°C to 600°C respectively. The amount of CO 2 generated from 300°C to 390°C comprises the S3 value. Quality of organic carbon is assessed using Hydrogen (HI) and Oxygen (01) indices (HI=S2/TOCx100, 01=S3/TOCx100) which relates to the atomic H/C and 0/C ratios (Espitalie et al., 1977). S2 values below 0.2 are deemed unreliable. Total organic contents do not decrease with decreasing S2 values, hence low S2 values are the result of thermal maturation past the point of oil preservation. Anomalously low Tmax values (the temperature required to crack the remaining hydrocarbons) reflect the disappearance of the S2 peak. 5.5 MINERALOGY Bulk mineralogy of the LBM member is dominated by quartz, accounting for 58-93% of the bulk rocks (Table 5-3). Lower quartz contents are associated with high carbonate contents, such as sample BRS325-7 which contains 39% dolomite. Illite was the only clay mineral identified, accounting for 1-25% of the bulk mineralogy. Upper black shales (UBS) of the Besa River have a bimodal composition between quartz and clays with minor carbonate minerals. Quartz ranges between 11 and 73%, varying inversely with clay contents, which range between 26% and 88%. Similar to the LBM member, illite is the dominant clay mineral but kaolinite may also be present in significant quantities (up to 23%). Minor amounts of chlorite (<3%) are sometimes present. Muskwa rocks contain as much as 86% quartz and average 55%: clay content (mainly illite with some kaolinite) varies between 1% and 53%, with lower concentrations in calcareous samples (e.g. sample MU1416-9 which has 82% calcite, classifying it as a marly limestone; after Pettijohn, 1975). Pyrite in organic-rich sediments (LBM/UBS members and Muskwa) rarely exceeds 1%. Organic-lean Fort Simpson shales are clay- rich, with almost equal concentrations of illite, kaolinite and chlorite. Minor amounts of albite also occur (<2%). Due to the covariance of quartz and TOC, a possible biogenic source is suggested for the silica in the Devonian sediments although primary silica depositional textures are difficult to determine due to recrystallization. Pelzer (1966) and Stasiuk and Fowler (2004) noted silica as sponge spicules, radiolarian capsules and siliceous microfossils 216 Sample Quartz Albite Calcite Dolomite Pyrite Illite Kaolinite Chlorite Total Clays Total Carbonate Total Besa River LBM BRS2563-1 89.5 0.0 0.3 0.5 0.4 9.3 0.0 0.0 9.3 0.8 100.0 BRS2563-3 87.4 0.0 0.7 0.2 0.7 11.0 0.0 0.0 11.0 0.9 100.0 BRS2563-5 85.7 0.0 0.0 1.0 1.0 12.3 0.0 0.0 12.3 1.0 100.0 BRS2563-7 81.3 0.0 0.0 0.4 0.8 17.5 0.0 0.0 17.5 0.4 100.0 BRS325-1 90.5 0.0 0.0 0.5 0.6 8.4 0.0 0.0 8.4 0.5 100.0 BRS325-3 92.5 0.0 0.0 1.0 0.6 5.9 0.0 0.0 5.9 1.0 100.0 BRS325-5 74.2 0.0 0.2 0.2 0.6 24.8 0.0 0.0 24.8 0.4 100.0 BRS325-7 58.8 0.0 0.6 39.1 0.4 1.0 0.0 0.0 1.0 39.8 100.0 UBS BRS-c15-1331-1 73.2 0.0 0.0 0.5 0.3 26.0 0.0 0.0 26.0 0.5 100.0 BRS-c15-1331-2 58.5 0.0 0.0 0.6 0.5 40.5 0.0 0.0 40.5 0.6 100.0 BRS-c15-1331-3 66.6 0.2 1.7 0.0 0.4 31.1 0.0 0.0 31.1 1.7 100.0 BRS-c15-1331-5 43.8 0.0 0.0 0.3 0.3 55.5 0.0 0.0 55.5 0.3 100.0 BRS-c15-1331-7 62.1 0.0 1.4 1.2 0.5 34.8 0.0 0.0 34.8 2.6 100.0 BRS 1331-2 22.1 0.0 0.0 0.0 0.2 76.0 1.7 0.0 77.7 0.0 100.0 BRS1331-3 37.1 0.0 0.0 0.0 0.3 61.0 1.6 0.0 62.6 0.0 100.0 BRS1331-4 18.2 0.0 0.0 0.0 0.4 64.8 14.3 2.3 81.4 0.0 100.0 BRS1331-6 20.9 0.0 0.0 0.0 0.7 52.9 22.5 2.8 78.4 0.0 100.0 BRS1331-7 20.3 0.0 0.0 0.0 0.5 67.4 11.7 0.0 79.1 0.0 100.0 BRS1331-8 34.4 0.0 0.0 0.0 0.9 46.5 17.3 0.9 64.7 0.0 100.0 BRS1331-9 25.4 0.0 0.0 0.0 0.7 55.7 18.1 0.1 73.9 0.0 100.0 BRS1331-10 11.1 0.0 0.0 0.0 0.6 69.0 17.9 1.5 88.3 0.0 100.0 BRS1331-11 18.6 0.0 0.0 0.0 0.6 68.6 10.3 1.9 80.7 0.0 100.0 Muskwa M U1745-1 76.8 0.2 4.6 1.4 0.9 16.1 0.0 0.0 16.1 6.0 100.0 MU1745-2 51.5 0.0 1.9 0.6 0.6 45.2 0.0 0.0 45.2 2.6 100.0 MU1745-3 54.9 0.6 1.9 0.5 0.9 41.3 0.0 0.0 41.3 2.3 100.0 MU1745-4 56.3 0.1 2.0 0.0 0.8 40.7 0.0 0.0 40.7 2.0 100.0 MU414-1 72.5 0.7 0.0 0.0 0.6 26.2 0.0 0.0 26.2 0.0 100.0 Table 5-3. Mineralogical composition or Devonian-Mississippian shales and mudrocks. Note high quartz concentrations of LBM member sediments which, in part, are attributed to a biogenic source. Sample Quartz Albite Calcite Dolomite Pyrite Illite Kaolinite Chlorite Total Clays Total Carbonate Total Muskwa (cont.) MU414-2 67.3 1.1 0.4 0.0 0.4 29.6 1.0 0.0 30.7 0.4 100.0 MU414-3 53.9 1.3 0.3 0.3 1.3 40.6 2.2 0.0 42.8 0.6 100.0 MU414-4 50.5 1.2 2.3 1.2 0.4 42.1 2.3 0.0 44.5 3.4 100.0 MU714-1 16.5 0.0 82.7 0.0 0.7 0.0 0.0 0.0 0.0 82.7 100.0 MU714-2 85.8 0.0 0.0 1.8 2.2 10.1 0.0 0.0 10.1 1.8 100.0 MU714-3 61.9 0.7 10.3 10.8 1.5 14.7 0.0 0.0 14.7 21.1 100.0 MU1416-1 41.2 0.3 0.0 0.0 0.4 56.9 1.2 0.0 58.1 0.0 100.0 MU1416-2 54.4 0.1 0.5 0.5 0.8 42.4 1.3 0.0 43.7 0.9 100.0 MU1416-3 45.2 0.4 0.7 0.7 0.4 51.0 1.5 0.0 52.5 1.5 100.0 MU1416-4 53.0 0.0 0.0 0.0 0.4 46.6 0.0 0.0 46.6 0.0 100.0 MU1416-5 61.0 0.4 0.1 1.5 0.9 33.9 2.2 0.0 36.1 1.6 100.0 MU1416-6 67.3 0.1 0.0 0.0 0.7 30.9 1.0 0.0 31.9 0.0 100.0 MU1416-7 61.1 0.0 0.0 0.0 1.0 36.1 1.7 0.0 37.8 0.0 100.0 MU1416-8 67.5 0.0 0.0 0.0 0.4 32.0 0.0 1.0 32.0 0.0 100.0 MU1416-9 13.1 0.0 82.2 3.2 0.5 1.0 0.0 0.0 1.0 85.4 100.0 Fort Simpson FSS129-1 46.4 1.0 1.0 0.0 0.0 17.2 21.8 12.6 51.6 1.0 100.0 FSS129-5 29.7 1.0 0.0 0.0 0.0 25.0 29.8 14.5 69.3 0.0 100.0 FSS129-9 29.4 1.1 0.0 0.0 0.0 27.5 26.5 15.6 69.5 0.0 100.0 FSS129-13 29.4 1.0 0.0 0.0 0.0 28.3 24.3 17.0 69.6 0.0 100.0 FSS1238-1 28.0 0.8 0.0 0.0 0.0 28.8 25.3 17.1 71.2 0.0 100.0 FSS1238-2 29.5 0.8 0.0 0.0 0.0 23.9 28.8 17.0 69.7 0.0 100.0 FSS1238-7 34.0 0.0 0.0 0.0 0.0 29.8 21.7 14.5 66.0 0.0 100.0 FSS1238-11 28.6 0.2 0.0 0.0 0.3 61.0 8.8 1.2 70.9 0.0 100.0 FSS1416-1 32.1 0.9 0.3 0.0 0.0 24.7 27.4 14.5 66.7 0.3 100.0 FSS1416-5 33.7 0.7 0.2 0.0 0.0 19.9 31.9 13.6 65.4 0.2 100.0 FSS5245-1 33.3 1.3 0.0 0.0 0.0 20.4 27.1 17.8 65.4 0.0 100.0 FSS5245-3 36.1 2.0 0.0 0.0 0.0 19.8 28.4 13.8 61.9 0.0 100.0 FSS12140-1 52.6 1.0 2.0 1.0 0.0 14.5 17.0 11.9 43.4 3.0 100.0 FSS13703-2 30.0 1.0 0.0 0.0 0.0 23.3 27.6 18.1 69.0 0.0 100.0 FSS13703-4 27.4 1.4 3.6 0.4 0.0 21.7 24.8 20.6 67.1 4.1 100.0 FSS13703-6 31.4 1.5 0.0 0.0 0.0 19.1 31.5 16.5 67.1 0.0 100.0 Table 5-3 continued infilled by granular bitumen in adjacent strata. Ross and Bustin (in review) also argued a biogenic origin for the silica based on excess silica concentrations (silica not attributable to the detrital phase) and trace/rare earth elements, although at high thermal maturity levels it is difficult to isolate biogenic- from detrital-sourced silica (i.e., detrital quartz) using major oxide geochemistry calculations. 5.6 GAS CONTENTS A critical parameter for shale gas reservoir evaluation is determination of the potential gas capacity. Gas can be stored in three ways including: 1) adsorbed-state gas; 2) free gas (gas not physically adhered onto internal surfaces; and 3) solute gas (within water and/or bitumen). Both potential adsorbed and free gas capacities are considered here. Adsorbed gas contents may include solute gas, which cannot be differentiated under the experimental conditions. In-situ reservoir pressures were assumed to be hydrostatic (9.792 kPa/m; 0.43 psi/ft) and reservoir temperatures were estimated using a geothermal gradient of 4°C/100 m (2.2°F/100 ft; after Majorowicz et al., 2005). In this study, experiments were run at temperatures up to 100°C. Adsorbed gas capacities at temperatures >100°C (212°F; Besa River and Mattson) were calculated using the following equation: (1)^nsorbed = A ln(rtemp) + B 219 where nsorbed is the adsorbed gas capacity, A and B are constants (-0.8114 and 3.8659 respectively) and r temp is the reservoir temperature. Equation (1) was formulated from a plot of measured adsorption capacities at 30, 50, 75 and 100°C (86, 122, 167 and 212°F) using shale samples with TOC ranging between 2-4 wt%, which can then be extrapolated to temperatures >100°C (212°F; from Ross and Bustin, in review). 5.6.1 Adsorption capacities In the Liard Basin, adsorbed methane capacities of the quartz-rich LBM member, clay- rich UBS member and Mattson shales are <0.01 cm 3/g (0.32 scf/t) at reservoir depths of 3100-3800 m and temperatures between 127 and 155°C (261-311°F; Table 5-4). Muskwa shales to the east of the Bovie Fault Zone are buried to shallower depths at lower reservoir temperatures (<80°C or 176°F) and have maximum adsorbed gas capacities of 0.7 cm3/g (22 scf/t; Figure 5-13A). Carbonate-rich samples (e.g. MU1416- 9) tend to have lower adsorption capacities (<0.1 cm 3/g; 3.2 scf/t) whilst overlying Fort Simpson shales have adsorbed gas contents that rarely exceed 0.1 cm 3/g (3.2 scf/t). In most samples, adsorption capacities do not significantly change following Langmuir extrapolation to reservoir pressures (up to 35 MPa/5090 psia for Besa River samples) because the plateau of the isotherm occurs at relatively low pressures, often in the range 10-15 MPa (160-2190 psia; Figure 5-13B). The ability of Devonian—Mississippian shales and mudrocks to adsorb methane is controlled primarily by the amount of organic matter. The organic matter is 220 Sample # Well Location Depth (m) TOC (wt %) IC (wt %) Moisture (wt %) Predicted Reservoir Pressure' (PSIA)^(MPa) Predicted Reservoir Temperature' (oC) Adsorption Capacity (scf/t)^(cm3!g) Besa River LBM BRS325-1 2021d-064-K 094-N-16 3344.85 2.01 0.25 1.55 4766.15 32.76 133.79 <0.32 <0.01 BRS325-2 202/d-064-K 094-N-16 3346.35 1.93 0.33 1.69 4768.28 32.77 133.85 <0.32 <0.01 BRS325-3 202/d-064-K 094-N-16 3347.85 2.03 0.22 1.41 4770.42 32.79 133.91 <0.32 <0.01 BRS325-4 2021d-064-K 094-N-16 3349.35 2.48 0.06 2.03 4772.55 32.80 133.97 <0.32 <0.01 BRS325-5 202/d-064-K 094-N-16 3350.85 2.08 0.06 1.79 4774.68 32.82 134.03 <0.32 <0.01 BRS325-7 202/d-064-K 094-N-16 3353.05 0.90 6.94 1.48 4777.80 32.84 134.12 <0.32 <0.01 BRS2563-1 B-019-K 094-N-16 3756.21 4.83 0.35 1.35 5350.50 36.79 150.25 <0.32 <0.01 BRS2563-2 B-019-K 094-N-16 3757.54 4.22 0.30 2.27 5352.39 36.80 150.30 <0.32 <0.01 BRS2563-3 B-019-K 094-N-16 3758.69 4.37 0.44 1.82 5354.03 36.81 150.35 <0.32 <0.01 BRS2563-5 B-019-K 094-N-16 3762.06 2.77 0.14 2.34 5358.81 36.85 150.48 <0.32 <0.01 BRS2563-7 B-019-K 094-N-16 3759.81 2.50 0.21 1.87 5355.62 36.82 150.39 <0.32 <0.01 UBS BRS-C15-1331-1 D-75-E 94-N-08 3667.56 1.41 0.22 2.43 5224.57 35.92 146.70 <0.32 <0.01 BRS-C15-1331-3 D-75-E 94-N-08 3672.06 3.37 1.14 3.77 5230.96 35.96 146.88 <0.32 <0.01 BRS-C 15-1331-5 D-75-E 94-N-08 3676.93 3.97 0.23 4.07 5237.88 36.01 147.08 <0.32 <0.01 BRS-C1 5-1 33 1-7 D-75-E 94-N-08 3680.69 2.22 1.03 3.07 5243.22 36.05 147.23 <0.32 <0.01 BRS 1331-1 D-75-E 94-N-08 3751.51 1.96 0.02 5.14 5343.83 36.74 150.06 <0.32 <0.01 BRS1331-2 ID-75-E 94-N-08 3752.26 2.53 0.07 5.63 5344.89 36.75 150.09 <0.32 <0.01 BRS1331-3 D-75-E 94-N-08 3753.01 2.68 0.01 5.17 5345.96 36.76 150.12 <0.32 <0.01 BRS 1331-4 D-75-E 94-N-08 3868.80 4.01 0.00 4.91 5510.44 37.89 154.75 <0.32 <0.01 BRS1331-5 D-75-E94-N-08 3869.55 4.89 0.00 4.36 5511.51 37.90 154.78 <0.32 <0.01 BRS 1331-6 D-75-E 94-N-08 3870.30 4.72 0.21 4.14 5512.57 37.91 154.81 <0.32 <0.01 BRS1331-7 D-75-E 94-N-08 3871.05 4.43 0.09 5.37 5513.64 37.91 154.84 <0.32 <0.01 BRS1331-8 D-75-E 94-N-08 3871.80 5.67 0.38 5.05 5514.70 37.92 154.87 <0.32 <0.01 BRS1331-9 D-75-E94-N-08 3871.80 5.27 0.02 4.19 5514.70 37.92 154.87 <0.32 <0.01 BRS1331-10 D-75-E 94-N-08 3872.55 4.08 0.04 4.84 5515.77 37.93 154.90 <0.32 <0.01 BRS1331-11 D-75-E 94-N-08 3874.05 3.83 0.01 5.15 5517.90 37.94 154.96 <0.32 <0.01 Table 5-4. Adsorption capacities, predicted reservoir temperatures, equilibrium moisture contents and geochemical data of Devonian- Mississippian shales and mudrocks. Low adsorption capacities of Besa River and Mattson sediments are related to high reservoir temperatures (up to 150°C), whereas Muskwa shales have larger adsorbed gas capacities because reservoir temperatures are estimated to be lower (<80°C). Fort Simpson shales have low adsorption capacities which are related to low TOC and moderate-high reservoir temperatures (up to 92°C). Abbreviations: pounds per square inch absolute (PSIA); megapascals (MPa); standard cubic feet per ton (scf/t); centimetres cubed per gram (cm3/g). Sample # Well Location Depth (m) TOC (wt %) IC (wt %) Moisture (wt %) Predicted Reservoir Pressure• (PSIA)^(MPa) Predicted Reservoir Temperature* (oC) Adsorption Capacity (scf/t)^(cm'/9) Muskwa MU414-1 C-28-D 94-0-01 1937.90 3.67 0.07 3.12 2767.54 18.98 77.52 13.12 0.41 MU414-2 C-28-D 94-0-01 1938.65 3.63 0.02 3.35 2768.61 18.99 77.55 13.12 0.41 MU414-3 C-28-D 94-0-01 1939.40 2.51 0.95 3.49 2769.67 18.99 77.58 9.60 0.30 MU414-4 C-28-D 94-0-01 1940.90 1.41 2.45 3.45 2771.80 19.01 77.64 8.96 0.28 MU714-1 A-009-F 94-P-03 2010.90 3.26 0.13 2.30 2871.24 19.70 80.44 10.24 0.32 MU714-2 A-009-F 94-P-03 2012.40 2.78 0.07 2.56 2873.37 19.71 80.50 12.80 0.40 MU714-3 A-009-F 94-P-03 2013.90 1.58 4.70 1.89 2875.50 19.72 80.56 4.80 0.15 MU1416-1 A-94-G 94-P-08 1539.24 2.14 0.79 3.16 2201.23 15.08 61.57 17.28 0.54 MU1416-3 A-94-G 94-P-08 1542.60 2.08 0.39 3.76 2206.01 15.11 61.70 9.60 0.30 MU1416-4 A-94-G 94-P-08 1545.60 1.72 0.12 3.48 2210.27 15.14 61.82 12.80 0.40 MU1416-6 A-94-G 94-P-08 1550.00 3.26 0.10 3.30 2216.52 15.18 62.00 19.52 0.61 MU1416-7 A-94-G 94-P-08 1551.20 2.05 0.04 3.48 2218.22 15.19 62.05 21.76 0.68 MU1416-9 A-94-G 94-P-08 1555.00 0.44 5.83 2.49 2223.62 15.23 62.20 3.20 0.10 MU1745-1 B-88-H 094-J-14 1949.37 1.87 2.00 1.52 2783.84 19.09 77.97 4.42 0.14 MU1745-2 B-88-H 094-J-14 1951.62 1.88 1.77 1.73 2787.03 19.11 78.06 5.31 0.17 MU1745-3 B-88-H 094-J-14 1950.12 2.35 1.14 2.73 2784.90 19.10 78.00 4.48 0.14 MU1745-4 B-88-H 094-J-14 1952.67 1.97 2.09 2.30 2788.52 19.12 78.11 3.65 0.11 Mattson MASH1331-1 D-75-E 94-N-08 3182.10 0.18 0.01 3.18 4534.96 31.17 127.28 0.32 <0.01 MASH1331-7 D-75-E 94-N-08 3412.01 0.56 0.24 3.50 4861.56 33.42 136.48 0.32 <0.01 MASH1331-11 D-75-E 94-N-08 3571.18 1.08 0.16 4.93 5087.66 34.98 142.85 0.32 <0.01 Ft Simpson FSS126-1 B-92-D 94-1-04 1939.40 0.25 0.45 5.68 2769.67 18.99 77.58 <3.2 <0.1 FSS126-7 B-92-D 94-1-04 2093.90 0.28 0.11 5.12 2989.14 20.51 83.76 <3.2 <0.1 FSS126-10 B-92-D 94-1-04 2204.50 0.25 0.10 5.41 3146.25 21.59 88.18 <3.2 <0.1 FSS126-12 B-92-D 94-1-04 2207.50 0.23 0.63 4.29 3150.52 21.62 88.30 <3.2 <0.1 FSS126-13 B-92-D 94-1-04 2320.60 0.24 2.85 2.82 3311.18 22.73 92.82 <3.2 <0.1 FSS126-14 B-92-D 94-1-04 2322.10 0.18 3.08 2.79 3313.31 22.74 92.88 <3.2 <0.1 FSS1238-1 C-60-E 94-1-11 1857.11 0.25 0.30 2.47 2652.78 18.19 74.28 <3.2 <0.1 FSS1238-7 C-60-E 94-1-11 1866.30 0.25 0.39 2.50 2665.83 18.28 74.65 <3.2 <0.1 FSS1416-1 A-94-G 94-P-08 1475.95 0.29 0.47 4.83 2111.33 14.46 59.04 <3.2 <0.1 FSS1416-5 A-94-G 94-P-08 1488.00 0.16 0.34 3.29 2128.45 14.57 59.52 <3.2 <0.1 FSS5245-1 D-31-F 94-P-08 1049.90 0.31 0.02 3.09 1506.11 10.28 42.00 <3.2 <0.1 Table 5-4 continued Sample # Well Location Depth (m) TOC (wt %) IC (wt %) Moisture (wt %) Predicted Reservoir Pressure* (PSIA)^(MPa) Predicted Reservoir Temperature* (oC) Adsorption Capacity (scf/t)^(cm'/9) FSS5245-3 D-31-F 94-P-08 1060.00 0.23 0.11 3.50 1520.46 10.38 42.40 <3.2 <0.1 FSS12140-1 C-82-F 94-P-02 1430.00 0.34 0.47 4.81 2046.06 14.01 57.20 <3.2 <0.1 FSS12140-4 C-82-F 94-P-02 1434.50 0.45 0.01 4.45 2052.45 14.05 57.38 <3.2 <0.1 FSS12140-6 C-82-F 94-P-02 1437.50 0.31 0.15 2.78 2056.71 14.08 57.50 4.26 0.13 FSS13703-2 C-28-D 094-P-02 1428.10 0.38 0.01 4.29 2043.36 13.99 57.12 3.2 0.1 FSS13703-6 C-28-D 094-P-02 1434.10 0.30 0.10 4.30 2051.88 14.05 57.36 3.2 0.10 FSS143-1 B-90-G 94-J-14 1896.97 1.09 0.13 2.84 2709.40 18.58 75.88 <3.2 <0.1 FSS143-4 B-90-G 94-J-14 1899.22 1.40 0.19 2.63 2712.60 18.60 75.97 <3.2 <0.1 FSS143-12 B-90-G 94-J-14 1905.22 1.02 0.08 3.45 2721.12 18.66 76.21 <3.2 <0.1 FSS947-3 B-86-L 94-1-16 1762.90 0.15 3.26 2.40 2518.95 17.27 70.52 <3.2 <0.1 FSS1238-12 C-60-E 94-1-11 1875.47 0.32 0.32 3.25 2678.86 18.37 75.02 <3.2 <0.1 FSS1238-16 C-60-E 94-1-11 1879.30 0.80 3.81 2684.30 18.41 75.17 <3.2 <0.1 FSS1279-1 B-49-G 94-P-07 1800.00 0.72 1.04 2.93 2571.65 17.63 72.00 <3.2 <0.1 FSS1279-3 B-49-G 94-P-07 1801.50 0.76 0.38 2.91 2573.78 17.64 72.06 <3.2 <0.1 FSS1279-9 B-49-G 94-P-07 1806.00 1.41 1.19 3.80 2580.17 17.69 72.24 3.97 0.12 FSS1528-1 A-65-G 94-J-10 1976.00 0.33 0.64 3.18 2821.66 19.35 79.04 <3.2 <0.1 FSS1528-3 A-65-G 94-J-10 1979.00 2.38 0.05 2.46 2825.93 19.38 79.16 5.63 0.18 FSS1528-5 A-65-G 94-J-10 1982.00 1.86 1.21 1.97 2830.19 19.41 79.28 <3.2 <0.1 FSS7194-1 C-32-K 94-1-14 1799.00 0.28 0.24 5.07 2570.23 17.62 71.96 <3.2 <0.1 FSS7194-2 C-32-K 94-1-14 1802.40 0.21 0.08 4.55 2575.06 17.65 72.10 <3.2 <0.1 FSS7194-3 C-32-K 94-1-14 1807.60 1.37 1.75 3.44 2582.45 17.70 72.30 <3.2 <0.1 FSS7194-4 C-32-K 94-1-14 1809.60 0.48 0.21 3.48 2585.29 17.72 72.38 <3.2 <0.1 Table 5-4 continued 1 4 -6, 1 2 nE U tn; 0 8 0 eo Q • 06 3 04 -o 0.2 Predicted reservoir pressure zone (Assuming hydrostatic conditions)lAl Mt114113-7 60"C BRS1331-5 30 °C 2.5 - Predicted reservoir pressure zone (Assuming hydrostatic conditions) BRS1331-5 @ 100 °C5 0to 0^ 10^15^20^25^30^35^40 Predicted reservoir pressure zone (Assuming hydrostatic conditions) 0.9 - 0.8 cn E 10 ^ 15 ^ 20 ^ 25 ^ 30 ^ 35 ^ 40 10^15^20^25 ^ 30 ^ 35 ^ 40 Pressure (MPa) Figure 5-13. (A) Examples of adsorption isotherms for Muskwa Formation samples at various reservoir temperatures. Shaded grey zone represents approximate reservoir pressure based on hydrostatic pressure gradient. (B) Examples of adsorption isotherms of LBM member (Besa River) samples analyzed at 100°C. The saturation point of the isotherms (i.e. the point where the slope of the line is reduced) occurs at pressures typically less than 20 MPa. At the predicted reservoir pressures (grey box), the plateau of the isotherm is reached. (C) Effect of temperature on adsorption capacity for a UBS member sample. Significant reduction in adsorbed gas capacity occurs by increasing the temperature from 30 to 100°C. 224 microporous 14 , with a large internal surface area that increases with thermal maturity due to pore-structure transformation (Ross and Bustin, in review). Methane could be stored as a solute gas within the bituminite groundmass, which has been shown to store significant quantities of gas in other rocks (Chalmers and Bustin, 2007B; Ross and Bustin, in review). Clays may also contribute to adsorption capacities (Lu et al., 1995; Ross and Bustin, in review) because aluminosilicates such as illite have microporosity suitable to adsorb gas (Ross and Bustin, in review). However, any relationship between gas adsorption and micropores (associated with the organic or clay fraction) is affected by high temperatures, which reduce the ability of gas to adsorb because the physical adsorption process is exothermic (e.g. Besa River and Mattson formations in the Liard Basin; Figure 5-13C). Clays also affect moisture content where, for example, 5 wt% moisture can reduce the sorbed gas capacity by 60% (Ross and Bustin, 2007). Silica-rich mudrocks of the LBM member have lower moisture contents than clay-rich mudrocks due to the non-adsorptive nature of quartz to both water and gas (Ross and Bustin, in review). 5.6.2 Potential free gas capacities, total porosity and permeability Similar to tight-gas sand reservoirs, a significant proportion of the total gas in shale gas reservoirs is free gas, as suggested by gas contents above critical saturation (e.g. Kuuskraa et al., 1992; Montgomery et al., 2005, Bustin, 2006). Hence, quantifying total porosity is important but also requires estimates of free gas capacities. In this study, free 14 Following the International Union of Pure and Applied Chemistry (IUPAC) classification (Rouquerol et al., 1994), micropores have diameters <2 nanometres (nm), mesopores 2-50 nm and macropores >50 nm. 225 gas was estimated by assuming methane saturation of the open pores, i.e., Sw = 0. Rocks examined in this study were not freshly cored, and water saturations were unknown. Total porosities of Besa River shales and mudrocks vary as a function of lithology. The clay-rich UBS member has porosities ranging between 3.9 and 6.7%. A significant proportion of the porosity is attributable to the aluminosilicate fraction (Ross and Bustin, in review). For clay-rich samples, free gas may comprise up to 85% of the total gas capacity (Figure 5-14A). Quartz and carbonate-rich mudrocks of the LBM member have lower total porosities, between 0.6-2.1%, hence relatively lower potential free gas capacities (Figures 5-14B and 5-14C). Pressure solution and redistribution of silica and carbonate through diagenesis may have cemented pores within the fine-grained matrix (BjØrlykke, 1999) as a result of thermal maturation (Ro >4%). Nevertheless, free gas component is still potentially the most significant contributor to GIP in low porosity units due to low adsorption capacity at high temperatures. Shales of the Muskwa and Fort Simpson formations to the east of the Bovie Fault Zone have porosities ranging between 0.7 and 4.7% but the association between porosity and lithology is less pronounced than Besa River rocks. Similar to Besa River mudrock and shales however, high carbonate contents in Muskwa sediments have an adverse effect on total pore volume. Porosimetry indicates that permeabilities are <0.04 md and often in the nanodarcy range with no statistically significant correlation with porosity for the entire sample suite (Table 5-5, Figure 5-15A). Higher permeabilities are indicative of the UBS member with larger total pore volumes and in the range of 0.004-0.02 md. The only notable relationship between porosity and permeability is for siliceous LBM member sediments 226 14 12 10 I A I Sample: BRS1331-4 TOC: 4.0 wt% Porosity: 6.8 % Depth: 1668.8 m Reservoir Pnisssure: 38 MPa Predicted reservar pressure zone (Assuming hydrostatic conditions) 0 1Predicted reservoir pressure zone(Assuming hydrostat° conditions) 50 5 1 0 15 30 3520 25 40 FBI 5 4.5 E^3.5- to 2.5 5^10 Sample: BR52563-1 TOO:4.6 wt% Porosity: 1.4 % Depth:3766.21 or Reservoir Pressure: 38 MN 15^20^25^30^35^40 rote■rra free fr:^Li p 2^1.5 0 0.5 10^15^20 30^35^40 0 25 Semple: BR5325-3 TOC: 1.8 wt% Porosity. 0.6 % Depth: 3347.86 m Reservoir Pressure: 32 MPe Predicted reservoir pressure zone (Assuming hydrostatic conditions) o^2.0 <0^1.5 0 to 2^1.0o '17 / / 0.5 0.D 'Adsorbed gas capacity' Föl " 2.5 [Adsorbed gas capacity' Pressure (MPa) Figure 5-14. Potential free gas capacities assuming pore space is saturated with gas (zero water saturation). (A) UBS member. (B) and (C) LBM member samples. Adsorbed gas capacities shown are measured at 100°C. At high reservoir temperatures (>100°C), free gas capacity is a significant contributor to the total gas capacity for porosities in the range 0.5-6.8%. 227 Porosity Permeability (%) (md) 1.16 0.0054 0.58 0.0008 1.24 0.0083 0.35 0.0006 1.61 0.0218 2.14 0.0363 1.06 0.0048 5.4 0.0054 5.32 0.0044 6.35 0.0212 3.88 0.0024 6.8 0.0099 6.84 0.0114 5.06 0.0135 5.23 0.0193 4.6 0.0107 3.66 0.0080 2.9 0.0054 3.72 0.0032 3.1 0.0026 0.7 0.0012 1.8 0.0053 0.95 0.0031 4.26 0.0071 2.22 0.0051 1.42 0.0064 0.85 0.0008 2 0.0096 2.29 0.0047 1.6 0.0017 4.65 0.0002 1.9 0.0013 2.43 0.0030 2.62 0.0012 2.94 0.0024 4.33 0.0011 4.31 0.0043 3.94 0.0036 0.2 0.0002 Sample Besa River LBM BRS325-1 BRS325-3 BRS325-5 BRS325-7 BRS2563-1 BRS2563-3 BRS2563-7 UBS BRS-C15-1331-1 BRS-C15-1331-3 BRS-C15-1331-5 BRS1331-1 BRS1331-3 BRS1331-4 BRS1331-5 BRS1331-6 BRS1331-11 Muskwa MU414-1 MU414-2 MU414-3 MU414-4 MU714-1 MU714-2 MU714-3 MU1416-1 MU1416-4 MU1416-9 MU1745-1 MU1745-2 MU1745-3 MU1745-4 Fort Simpson FSS 143-1 FSS 947-3 FSS1238-1 FSS1416-1 FSS1416-5 FSS5245-1 FSS5245-3 FSS12140-6 Chert Table 5-5. Porosity and permeability for selected Devonian-Mississippian samples. Permeabilities calculated using the Swanson (1981) method. 228 2.5 ^ LBM member X Chert B 0 2- 0 0 0.5 - 0.01 Permeability (md) 0 0.0001 0.001 0.1 0.040 0.035 - 0.030 - E 0.025 - P 0.020 - coa) Cr) 0.015 - CL 0.010 - 0.005 - 0.000 ^ LBM member ♦ UBS member o MU ♦ FSS 0 c] 0 0 ^ p Do 0 0 • • • 0 • •• 0 0 0 cb • •• 0^o •• • •• 0 2 ^ 3^4^5 ^ 6 ^ 7 ^ 8 Porosity (%) Figure 5-15. (A) Relationship between porosity and permeability for Besa River, Muskwa and Fort Simpson samples. Correlation is poor although higher permeabilities are generally associated with more porous sediments (UBS member). (B) Log-linear relationship between porosity and permeability of the LBM member and chert. 229 which show a log—linear profile (Figure 5-15B) and similar to previous experimentally measured permeabilities of mudstones (see Neuzil, 1994; Schliimer and Krooss, 1997; Dewhurst et al., 1998). Also shown in figure 5-15B are porosity/permeability data for chert, which lies on the log-linear plot of LBM sediments, illustrating a logarithmic decrease in permeability with porosity in biosiliceous sediments. Permeability reported here is matrix permeability because fractures were not sampled. Core studies and thin- section analyses show that natural fractures are present in the LBM member and Muskwa shales; however, most natural fractures identified are mineralized with calcite cement or pyrite. Thus, the contribution of smaller fractures to reservoir storage is assumed minimal. 5.7 GEOCHEMICAL AND WIRELINE LOG EVALUATION Amount and distribution of TOC and inorganic composition are of significant value to characterize the natural-gas resource potential of Devonian—Mississippian strata and identify potential completion zones. Furthermore, calibration of core laboratory analyses to wireline logs is important so that the spatial variability of the shale gas reservoir can be documented because data is limited. The following section discusses geochemical heterogeneity of the Devonian—Mississippian strata with respect to petrophysical properties. 230 04.0 3.5 - 3.0 2.5 - 2.0 - 1.5 - 1.0 - 0.5 - 0.0  ♦ A-94-G 94-P-08 ^ C-60-E 94-1-11 ♦ B-49-G 94-P-07 x A-65-G 94-J-10 B-88-H 094-J-14 • • x • • • x xx • • • 0^20^40^60^80^100^120^140^160^180^200 Gamma ray (API) Figure 5-16. Graph showing relationship between TOC and gamma-ray (measured in API) of Muskwa (wells A-94-G 94-P-08 and B-88-H 094-J-14) and Fort Simpson shales. Covariant trend is related to U-rich organic matter. 231 5.7.1 Organic content, radioactive elements (U, Th and K) and gamma-ray logs Both the LBM member and Muskwa Formation show good correlation between TOC and uranium (U; Ross and Bustin, in review). High (2 to 20 ppm) U content and TOC correspond to intervals with high gamma-ray intensity. Organic-lean Fort Simpson shales have up to 80% less U than Muskwa shales and thus can be easily identified by a decrease in gamma-ray response (Figures 5-12 and 5-16). Despite the organic- and sulphur-rich and pyritic nature of the UBS member units and corresponding moderate- high gamma-ray intensity, U concentrations do not correlate with TOC (average U content = 2.8 ppm; Ross and Bustin, in review). Thus, gamma-ray log is probably measuring Th and lesser amounts of K, which are elements associated with clay minerals, more specifically illite (Ross and Bustin, in review). The inability of organic matter to adsorb U may be due to low levels of biogenic activity in the overlying water column and/or rapid sedimentation, which reduces the interaction time between organics and U (Ross and Bustin, in review). As such, gamma-ray derived TOC models would be misleading across the UBS member. 5.7.2 Shale/mudrock composition, bulk density and sonic log response Both density and sonic logs demonstrate the difference in organic content of the Muskwa Formation as compared to the overlying Fort Simpson shales (Figure 5-17A). Bulk density is lower and sonic transit time is higher in organic-rich strata because kerogen is of low density (approximately 1.4 cm 3/g) compared to quartz (2.65 cm3/g) and clay (approx. 2.77 cm3/g). The quartz-rich LBM member does not show sonic transit 232 100 90 - 80 70 - o A • UBS (Besa River Fm) LBM (Besa River Fm) A MS 60 50 - RI 4o- 30 - 20 - 10 - o A A A .• • • • IA1 Well Name : CNRL NORTHSTAR OSPREY C- 018-B/ Location : 200/a-018-B/094-H-02/00 o^GR (GAPI)^150 500^ or (us/m)^ 100 2000^RHOB (kg/m)^3000 , '^1 , 2800 2900 r i^' ,^, i^I , J^41 J^.:1 ■• i, -4, i^ -' ,^■ ■^T^I^■ .,   j I^I^■ ■^,i ' -:i ■^.1 ,^1_, , I^I J I I^I^, - I^.,^h^■ - PortSiMpSor I^■^■ I i-^'^, -^1 ' " L.,,, ,I^1, - 1^■ ,^1.;?.-- I '^'. ,^...,^,   t4us}(wa^; ';4.'"--7-- , I^f^I Oft■JrPirlo,^, i^I^4 - -1^i^t,.. I ^■ ^i ^ _1-^I o^GR (GAPI)^150 500^ DT (us/m)^ 10-0 2000^RHOB (kg/m3)^3000 150^200^250^300^350 ^ 400 ^ 450 Sonic transit time (ps/m) Figure 5-17. (A) Sonic and density log response across the Muskwa Formation showing an increase in sonic transit time and decrease in bulk density related to organic enrichment. (B) Inverse correlation between quartz content and sonic transit time for LBM and UBS members and Muskwa samples. See text for discussion. 233 times or bulk densities that reflect fluctuations in the amount of organic carbon. The high biogenic silica content (indicated by coeval enrichments of quartz and TOC), increases bulk density and decreases sonic transit time, irrespective of organic content (Figure 5- 17B). The moderate-to-good inverse relation between the sonic log response and quartz content is significant, considering the difficulties inherent with scaling laboratory data and field measurements. Density log response is inversely proportional to total porosity in the LBM member and suggest a diagenetic transformation of biogenic opal during the opal-A to Opal-CT transition (Volpi et al., 2003) resulting in a reduction in porosity. Similar changes in physical properties of rocks that have undergone silica diagenesis have been attributed to incipient opal transformation and cementation with opal-CT (e.g. Lonsdale, 1990; Nobes et al., 1992). Scanning Electron Microscopy (SEM) analysis shows no textural evidence of the silica diagenesis where recrystallization has destroyed original microfossils and left only faint traces of the original micro-laminated texture. Lateral changes in sonic transit times associated with increased silica content can be mapped from east to west across the study area (330 to 220 µs/m; Figure 5-18), indicating a basin-ward enrichment of quartz. In the Liard Basin region, mudrocks are characteristic of a biosiliceous, bio-productive depositional environment (Ross and Bustin, in review) and thus supporting a biogenic source of the silica. However, caution must be used when integrating sonic data (and bulk density) for silica distribution further east (east of 122 °W longitude) due to the influence of carbonate, which results in or produces low transit time readings (e.g., Issler, 1992). It is also apparent through the 234 Mdes^ 75 Kilometres 120  vv-r Thrusting V Eastern Edge I Laramide Thruslk of 94-K I Bovie Fault I 62°N 61°N 60°N BC 11111111111111 111111111111111111112111111111101111111EZMI 11111111111111111111111110.641111111MAINr^4 94-N 4 59°N A% 6 0 4-I 0) 58°N —126°W —125°W —124°W —123°W —122°W 1 —121°W —120°01 Figure 5-18. Average sonic transit times for Horn River (including LBM member) and Muskwa formations across northern BC, southern YK and NWT (contour interval = 10 his/m). There is a general decreasing trend of sonic transit time to the west, into the Liard Basin region likely due to enrichment of quartz (biogenic silica). 235 Besa River Fon^ation that the ratios between biogenic silica and aluminosilicate fraction affect sonic log and density log responses. The UBS sediments are enriched in clay minerals (with larger total porosities compared to quartz-rich sediments) with lower quartz contents, producing lower densities and higher sonic transit times (see sonic and density log responses in Figure 5-4A). 5.7.3 Mapping TOC: combined gamma-ray and density log calibration The increase in organic carbon content with an increase in gamma-ray log intensity and corresponding decrease in bulk density in Muskwa rocks requires TOC to be calibrated using a pseudo gamma-ray and formation density type model. The following equation has been formulated to determine TOC contents (modified from Schmoker 1980): (2) TOC — (GR baseline - GR. ) (Am) where GRbaseline is the gamma-ray intensity (API units) of strata with no organic carbon, GRunit is the gamma-ray intensity of the reservoir unit, m is the slope of the plot of gamma-ray intensity verses formation density, and A is a constant. The values used here are GRbaselme-15 API, m=-192 and A=0.3. Values of GRunit are typically in the range of 75 API to 150 API in the mapped area. A good correlation between laboratory- and log- derived TOC of Muskwa and Fort Simpson samples demonstrates that a pseudo gamma- ray/bulk density model is reliable for estimating TOC (Figure 5-19A). 236 61 N 60°N 59 N 0 0 0 5 1 0 1 5 2 0 2.5 3.0 3.5 40 -125°VV -124°VV^-123°W^-122°W -121°W^-1 20°VV 4 AeS K1 .1111=1MIMI Elm I1111 ILI,.111 1Immumuminium11111 PRIMO amno minfinem 1111111111111111111 111011MENII iIIININFA Y‹ 1.31 IIIIIIII►IPAIVOIUMAII BC 94N‘ 1 t ^M VIP 1 @ 19 ^ ^Ai^°,, ^•ErtEct: 94K irkc(;Irg `) 18°°F" 62 N 58°N -126 ° W Laboratory TOC (wt%) Figure 5-19. (A) Correlation between log- and laboratory-derived TOC. (B) Map of TOC concentrations for Horn River and Muskwa sediments (contour interval = 0.2 wt%). Total organic carbon enrichment in section 94-P is associated with a thin interval of Muskwa shale, as opposed to surrounding embayments, which contain organic-lean argillaceous carbonate deposits (e.g. Otter Park Formation). Elongate N—S organic enrichment in 94-0 may represent an elongate depocentre in this region. Weight percent TOC was determined for 386 wells across northern BC for Horn River and Muskwa sediments and mapped in Figure 5-19B. East of 122°W, average organic carbon concentrations are highest in thin horizons (<25 m), primarily between the Klua and Cardova embayments with over 3 wt% TOC. Average TOC contents are lower in the embayment regions (<1.6 wt%) due to organic-lean argillaceous carbonate of the Otter Park Formation and Evie Member and separates the organic-rich Muskwa and Klua formations. Between 122°W and the Bovie Fault Zone, organic enrichments occur in thicker stratal sequences (north of 59°N), up to 3 wt% TOC, which may indicate an elongate depocentre in a NNE-SSW orientation. As discussed by Schmoker (1980), estimation of TOC using equation 2 requires a consistent relationship between formation density and gamma-ray intensity. In the Liard Basin region of northern BC, TOC and density are proportional to each other due to biogenic silica diagenesis (high density organic- and quartz-rich mudrocks). Thus, TOC calculations are underestimated westward. Qualitative determination and distribution of TOC contents can be estimated in this region because of the consistent relationship between organic matter and gamma-ray intensity (U contents) of Givetian-Frasnian organic-rich strata of the LBM member and Muskwa sediments. 5.8 RESOURCE POTENTIAL Laboratory data combined with subsurface mapping indicates a significant shale gas resource in the Besa River, Horn River, Muskwa and Fort Simpson formations. 238 Devonian—Mississippian strata are within the dry gas region in northern BC, therefore potential production zones will not be restricted by the co-presence of oil and gas which can reduce effective permeability (e.g., Barnett Shale in western and northern regions of the Fort Worth Basin; Montgomery et al., 2005). In particular, the Horn River Formation sediments (including LBM member) and overlying Muskwa shales are prime shale gas exploration targets in the Liard Basin and in adjacent regions to the east, which cover an area of approximately 125,000 km 2 (48,300 mil ; see Figure 5-18 for areal extent comparison with the Fort Worth Basin, TX). Despite the organic-lean nature of Fort Simpson shales, shale gas resource estimates are also considered (including the lateral equivalent MS member of the Besa River Formation) because of thick sections greater than 1000 m (3280 ft). Adsorption capacities determined for Horn River and Muskwa strata in the area are estimated between 10-20 bcf/section (Figure 5-20), up to 9 bcf/section for the Fort Simpson Formation and 0.5-1.2 bcf/section for the UBS member (Figure 5-21). Total adsorption capacities for Muskwa and Fort Simpson shales decrease in the Liard Basin where burial depths are greater than 3500 m (11,480 ft) and reservoir temperatures are high (over 150°C/302°F). Pressures in the Liard Basin region exceed that of the isotherm-plateau (flat-part) and no additional gas adsorbs at these higher pressures (Figure 5-12). Total bcf/section for adsorption capacity of the UBS member is consistent with thickness. To the east of the Bovie Fault Zone, greater adsorption capacities correspond to greater thickness of shale/mudrock sections, such as the Klua and Cardova embayments. 239 62°N 61°N 60°N 59°N Miles 75 11111111111111111111111 IIINIIIMINEMMEJ 111111111111101111M1 MINIMMEMEK lASE111111111111111M1111 11111MMIRMINSIMINNI taria11111111111111111 11111116141111MINTROBNE 11111111■1111/11MINEME 11111111111111111111111MEA 1114 kl 11 1L\\ mw-vole 94-K Bovie Fault —125°W^—124°W 1 —123°W Kilometres 120 YK BC 94-N 58°N —126°W Eastern Edge of Laramide Thrusting —122°W —121°W —120°W Figure 5-20. Bcf/section map (adsorption capacities) for Horn River and Muskwa formations (contour interval = 2 bcf/sec). Decrease into the Liard Basin region where reservoir temperatures exceed 100°C and adsorbed gas capacities are insignificant. Larger adsorption capacities east of the Bovie fault represent thicker sequences of basinal strata. Outline of the Fort Worth Basin, TX (Barnett Shale) also shown as polygon in lower right quarter of map for area comparison 240 61 N 60 N 59 N 11114"IIII Mrk,^75o.^ NA-ornelr.^ 120 ill 11/0111111 YK ITAR1111111 .. fBC^1 94-N 40 4 ♦.. Eastern Edge of Lararnt6e Thrusing 94-K • • 94-J I go7. 7.7.4 1 58°N —126°W I^I^I —125°1N —124°W —123°W^—122°W 60°N 59°N MOOMMINagin I 1111111111111•113111111 1111111111111N110111111111■ 271111E111111111111111 1111111111111111:11111111111111 11111111111111111111111111110 rd1111111111111111111111111111/ 1101111111M1111,11110. 111111111131111111112111MLWAS 119wir Laramide Thrusting 58°N —126°W —125°W —124°W —123°W —122°W —121°W —120°W Figure 5-21. Bcf/section map (adsorption capacities) for the Fort Simpson Formation (contour interval = 0.5) and the laterally equivalent UBS member (inset; contour interval = 0.2). Similar to Horn River and Muskwa formations, adsorbed gas capacities for Fort Simpson shales decrease into the Liard Basin region. Gas capacities for the UBS member follow thickness variability. 241 However, these areas have interbedded argillaceous carbonate sections of the Otter Park Formation and Evie Member and are typically organic-lean compared to Horn River Basin sediments (west of the Arrowhead Salient and Slave Point edge) and Muskwa shales. Total gas capacities (adsorbed plus free gas) for the Horn River and Muskwa formations are in the range of 60 to 240 bcf/section (Figure 5-22) and 100-600 bcf/section for Fort Simpson shales and the UBS member (in the Liard Basin; Figure 5- 23). Here, free gas may be greater than 12 times the volume of the adsorbed gas phase in certain regions such as NTS: 94-P-4. Shales and mudrocks of the Horn River and Muskwa formations have a total resource potential estimated to be between of 144 to over 600 tcf GIP. High quartz content and organic carbon in Horn River and Muskwa shales and mudrocks to the west of the Slave Point edge may provide the most significant gas production from the Devonian—Mississippian strata. With high quartz and low clay contents, these intervals are more favourable for fracturing (such as quartz-rich intervals of the Lewis Shale, San Juan Basin; Bereskin et al., 2001), than clay-rich shales, such as the Caney shale (Brown, 2006). Similar compositional attributes have been discussed with respect to the producibility of the lower Barnett Shale interval in the Fort Worth Basin, Texas (Montgomery et al., 2005) where fracturing (either natural or induced) is essential for shale gas production because matrix permeabilities are extremely low, restricting deliverability of gas to the wellbore (Soeder, 1988). The non-dilative response of ductile rocks (i.e. inability to develop fracture permeability; Ingram and Urai, 1999), such as Fort Simpson shales and the UBS member, which have clay contents in the range 26-88%, will present production challenges. 242 58°N —126°W 59°N 60°N 61°N 62° 1^4 0^ Miles^ 75 1 4- 0 Kilometres^120 1^: °Iil IlkOEM .1111111iriEl IPA ' 1111111111 il11 11111.1111111 111111111111,1111VEM111111111 ME YK VA11 1111 MIL1111111 hi NV, BC 94-N Eastern Laramide 94-K Thrusting Edge If 01, ,,ii .,-) /9 0 ak. W-........—N6 11 11., 1  tisr, 40 w ig Bovie Fault (\i^.^. . —125°W —124°W —123°W —122°W —121 °W —120°W Figure 5-22. Total gas capacity map (adsorbed plus free gas; bcf/section) for Horn River and Muskwa formations (contour interval = 20 bcf/sec). 243 61 N 60°N 59°N 1^1^1^4—^1^1^1^1 o ^ Wes 7 1^lele,setres a li osellaY < I II ... BC 94-N tirikal 4 oo ...) Eastern Edge of Lararrede Thrusting 94-K ••••••• • 94-J 17,07,eFUt 58N —126°W i^I^r —125°W —124°W —123°W^—122' BC NQ I 1111111111101110111C-11 111111111111111111111111111 1111111M111111111111111111 21111111111111111111111111 111111111111111111111•111111111 11/111 115111111111111111111111 1111611111111111111111111111 111112110101111111111111/111111111 tt Eastern Edge Laramide Thrusting • 94-N 60°N 59°N 94-K Boyle Fault of^94-I0 Miles 75 0 0 QA^ ^Kilometres 120 58°N —126°W —125°W^—124°W I^I^I^ I^I^I —121°W^—120°W--123°W^—122°W Figure 5-23. Total gas capacity map (adsorbed plus free gas; bcf/section) for the Fort Simpson Formation (contour interval = 50 bcf/sec) and the UBS member (inset; contour interval = 50 bcf/sec). 244 Carbonate-rich facies (Klua and Cardova embayments) may also be problematic for completions and fracturing due to potential ineffective rock mechanical properties of shales/mudrocks enriched with carbonate minerals (high Poisson's ratio and low Young's modulus). For example, calcite-rich shale facies often serve as efficient barriers to fracture propagation, affecting the stimulation success of adjacent gas-charged black shale facies (e.g., middle grey facies of the Lower Antrim; Manger et al., 1991). Consideration must also be given to not only optimize production potential (through fracturing), but to maximize potential gas capacities which is largely controlled by the effective porosity and free-gas capacity. As such, a balance must be sought between quartz content and total porosity as silica-rich mudrocks and shales tend to have lower porosities compared to their clay-rich counterparts. For the Givetian-Frasnian organic-rich units discussed here, prospective areas for successful gas production are identified east of the Bovie Fault region, between 122°W and 123°W, covering an area of 6250 km 2 (2404 mi2), for the following reasons: 1) High estimated TOC 2) Adjacent to the carbonate platform (Slave Point Edge), where shale/mudrock thickness reach 200 m (656 ft) 3) The region may provide the optimum balance between quartz contents (fracturing ability) and total porosity (free gas capacities) 4) Present-day burial depths of -2000 m sub-sea level (6560 ft), hence exploration costs will be significantly lower than for adjacent strata on the west side of the Bovie Fault Zone (up to -4000 m sub-sea; 13,100 ft) 245 5.9 CONCLUSIONS Devonian—Mississippian strata in northern BC and southern YK and NWT have characteristics indicative of large continuous-type gas accumulations. Potential exploration areas have been identified here after mapping thickness, organic content, inorganic variability and gas capacities (adsorbed plus free gas) of these units. Integrating these parameters yields GIP estimates up to 600 bcf/section. Thick sequences of mature to overmature argillaceous strata in respect to gas generation occur in the Cardova and Klua embayments and basinal regions west of 122°W. Organic carbon enrichments (up to 3.2 wt%) are associated with thin Muskwa sequences south of the Arrowhead Salient (e.g., NTS: 94-P-06) and within Horn River strata west of the Slave Point Edge (94-0-08 to 94-0-15). Basinal deposits west of 122°W represent the most prospective shale gas exploration region. Less favourable areas are within the embayment with lower organic carbon content (averaging 1.4 wt%) and commonly interbedded with argillaceous carbonate units such as in the Otter Park Formation and Evie Member. High temperature, high pressure adsorption analyses indicate that gas contents are largely controlled by the free-gas component, notably in the western study area (west of the Slave Point edge), emphasizing the importance of total effective porosity as a control on total gas capacity. With higher reservoir temperatures, any influences on gas adsorption (e.g. organic matter, clays) become less important as adsorption capacities approach zero. Due to the low slope of the adsorption isotherm at high pressures and 246 temperatures, minor amounts of adsorbed gas will be produced until reservoir pressure is markedly depleted. Successful exploitation of Devonian—Mississippian shale gas reservoirs requires delineating gas-charged zones and intervals with favourable reservoir properties in shale/mudrock sequences greater than 1 km thick. Quartz-rich horizons of the Horn River Group (LBM member of the Besa River Formation) may be most effective gas- producing facies due to more favourable rock-mechanical properties of more brittle lithologies to fracture stimulation. However, the LBM member, enriched in biogenic silica, invariably shows lower total porosities than clay-rich rocks, such as the UBS member, and it may be necessary to compromise high GIP zones with zones that can be successfully produced. Core studies and thins-section analyses show mineralized fractures that may not provide effective conduits for gas flow. Further expansion of the Devonian—Mississippian shale gas play in the WCSB will require a better understanding of the causative factors of fracture formation, including the influence of lithology and the importance of pre-existing fractures. 247 5.10 REFERENCES Allan, J. and Creaney, S. 1991. Oil families of the Western Canadian basin. Bulletin of Canadian Petroleum Geology, v. 39, p. 107-122. 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F. 1981. A simple correlation between permeabilities and mercury capillary pressures. Journal of Petroleum Technology, December, p. 2498-2504. Switzer, S. B., Holland, W.G., Christie, D.S., Graf, G.C., Hedinger, A.S., McAuley, R.J., Wierzbicki, R.A. and Packard, J.J. 1994. Devonian Woodbend-Winterburn Strata of the Western Canadian Sedimentary Basin, in G. Mossop and I. Shetsen, eds., Geological Atlas of the Western Canadian Sedimentary Basin. Canadian Society of Petroleum Geologists and Alberta Research Council, Calgary, Alberta, p.165-195. 256 Taylor, G. C. and Stott, D.F. 1968. Maxhamish Lake, British Columbia (94-0): Geological Survey of Canada Paper 68-12, p. 23. Volpi, V., Camerlenghi, A., Hillenbrand, C.-D., Rebesco, M. and Ivaldi, R. 2003. Effects of biogenic silica on sediment compaction and slope stability on the Pacific margin of the Antarctic Peninsula. Basin Research, v. 15, p. 339-363. Walsh, W., Hersi, O.S. and Hayes, M. 2005. Liard Basin — Middle Devonian Exploration. 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Alberta Society of Petroleum Geologists, Upper Devonian 345-359 m.y., 13 p. 257 CHAPTER 6 IMPACT OF MASS BALANCE CALCULATIONS ON ADSORPTION CAPACITIES IN MICROPOROUS SHALE GAS RESERVOIRS 258 CHAPTER 6 Impact of mass balance calculations on adsorption capacities in microporous shale gas reservoirs * 6.1 INTRODUCTION Gas shales and coal beds are important unconventional gas reservoirs in which much of the gas is stored in the adsorbed state (Bustin, 2005). For shale gas and coalbed methane reservoir evaluation, adsorption isotherms (mainly methane) are used to determine the adsorbed gas capacity. Adsorbed gas capacities are then extrapolated to regional reservoir scales and hence even small errors in adsorption capacity can result in significant over or underestimation of predicted gas in place and severely impact the perceived economics of development. Adsorbed gas capacities are also compared with actual gas contents from the well-site to determine the degree of gas saturation. Saturated rocks will desorb gas upon initial pressure drawdown which generally is accomplished by water production. In under-saturated reservoirs the saturation level is important to the economics of the reservoirs since the degree of under-saturation dictates to what pressure the reservoir must be depleted to allow desorption to occur which is referred to as the critical desorption pressure (GRI, 1996). A version of this chapter has been accepted for publication. Ross, D.J.K. and Bustin, R.M. Impact of mass balance calculations on adsorption capacities in microporous shale gas reservoirs. Fuel, in press, corrected proof. 259 For both coals and shales, gases adsorb onto the internal surfaces of the matrix. Typically a Type I isotherm (Langmuir) fits and is used for microporous 15 materials whereby gas adsorption increases rapidly at relatively low pressures while adsorption sites are being filled (Brunauer et al., 1940). Thereafter, the isotherm plateaus as the system reaches gas saturation. However, our recent research has shown negative calculated methane adsorption isotherms for many shales (Figure 6-1; Ross, 2004) and negative ethane isotherms for some coals. The calculation of negative adsorption reveals fundamental problems with the mass balance calculations that are invariably used for calculating adsorption. Calculated negative adsorption is particular evident in high pressure adsorption experiments of organic poor gas shales in which adsorption is low (relative to organic rich shales and coals) and errors are easier to recognize. Due to the significant lateral and vertical extent of shale/mudrock strata, any mis-calculations will have significant implications on gas-in-place (GIP) estimations. Porous materials such as coals have been described as a network of slit-like pores which are interconnected by narrow capillary constrictions (Marsh, 1987). Therefore pore accessibility is affected by both the geometry of pore throats and the pore diameter (Figure 6-2). The diffusion of gases through pore throats to adsorption sites is also dependant on the kinetic diameter of the gas. For example Cui et al. (2004A) reported a higher micropore diffusivity of carbon dioxide than those of methane and nitrogen due to the smaller kinetic diameter of carbon dioxide. 15 Using the International Union of Applied and Pure Chemistry (IUAPC) pore classification (Rouquerol et al., 1994), micropores are pores <2 nm in diameter, mesopores 2-50 nm and macropores >50 nm. 260 Figure 6-1. Examples of calculated negative adsorption of Jurassic (A and B) and Devonian (C and D) shales. 0.6 0.4 0.2 0.0 -0.2 -0.4 -0.6 0.04r_ Co a 0.02 U -o^0 H -0.02 03 -0.04 at A TOC = 0.8 wt%Moisture = 10.9 wt% • ■ • , a. ■ ■^ • ■^■ C TOC = 1.6 we/.Moisture = 4.5 ■ ■ ■ • ■ ■ • ■ ■ 10 ■■ 7 82^3^4^5^6^7^8 Equilibrium cell pressure (MPa) 2^3^4^5^6 Equilibrium cell pressure (MPa) TOC = 0.2 wt% Moisture = 4.3 wt% ■ 9^10 0.30 0.25 0.20 0.15 0.10 0.05 0.00 -0.05 -0.10 0 D 1 F- 1 - C) t.) at O ns at .c B TOC = 2.2 wt%Moisture = 5.0 wt% • ■■ 0.40 0.35 - a_ (Ps, 0.30 - l9.) 0.25 42. 0.20 - H 0.15 - om f 0.10 - m 0.05 - 0.00 07 810 1 7 82^3^4^5^6 Equilibrium cell pressure (MPa) ■ ■ ■ ■^I, .^,■,■^■^.^.^. 2^3^4^5^6 Equilibrium cell pressure (MPa) 0.06 -0.06 -0.08 Sample container A Key Void Volume Sample 4 Interconnected pore network Tight/restricted pore throats (bottleneck pores)^Porosity that is accessible through restricted pore throats Isolated pores^ Open porosity Figure 6-2. Conceptual illustration of pore networks in shales and mudrocks 262 The pore structure of coals (related to the organic fraction) controls, to a large extent, the adsorption of gases whether it is multilayer adsorption in meso-macro pores (Gan et al., 1972), or the pore-volume filling of micropores due to enhanced adsorption energies Cui et al., 2004B). For shales, it has been also shown that the organic matter mainly controls gas adsorption (Ramos, 2004; Chalmers and Bustin, 2007; Ross and Bustin, 2007) despite lower organic matter contents. Shales and mudrocks also have microporosity associated with clay minerals. Clays such as illite, kaolinite and montmorillonite have a predominance of pores with an effective radius between 1 and 2 nm. Microporosity of kaolinite and illite is attributed solely to the size of the clay crystals whereas montmorillonite has different pore-size distributions depending on the exchangeable cation saturation as well as crystal size (Alymore and Quirk, 1967; Aringhieri, 2004). Negative adsorption results for methane have been reported on zeolites (Vermesse et al., 1996) but the data was not included in their results as they have 'no physical meaning'. From a suite of Pennsylvanian coals, Krooss et al. (2002) reported negative excess adsorption of carbon dioxide (between 8-10 MPa) which was partly attributed to the inadequacy of the Gibbs approach (as described later) for a strongly non-ideal gas at high pressures and low temperatures. To investigate the occurrence and the importance of negative adsorption of shale/mudrock units and coal, both the void volume calculation and adsorption experiment need to be examined. It is not the purpose of this paper to provide further insight into the theories of adsorption phenomenon which is widely addressed in the 263 literature (Polanyi, 1932; Dubinin and Astakhov, 1971; Rudzinksi and Everett, 1972; Steele, 1974; Dubinin, 1975; Sircar, 1985; Sing et al., 1985; Neimark and Ravikovitch, 1997; Malbrunot et al., 1997; Roquerol et al., 1999; Gumma and Talu, 2003; Cavenati et al., 2004; Li et al., 2004) but to rather investigate the failure of mass balance calculations to the determination of adsorption capacity of microporous unconventional reservoir rocks and shale gas reservoirs in particular. 6.2 METHODS 6.2.1 Samples Shale samples were selected from Jurassic and Devonian strata in northeastern British Columbia, Canada. Additionally, pure clay mineral standards of illite, smectite and kaolinite used in this study were purchased from the University of Missouri-Columbia Source Clay Minerals Repository. The inorganics (including quartz) were chosen on the basis that they are the primary constituents of shales and mudrocks. The weight of the samples was approximately 200 g and crushed to a particle size of 250 pm and analyzed in both the dry and moisture equilibrated state. Synthetic zeolites (named ZeoSorb ) 33, 43 and 61 were also analyzed as they have known pore-size diameters of 0.31, 0.41 and 0.74 nm respectively. The suites of zeolites are in extrudate and powder form and were manufactured by TRICAT Inc. 6.2.2 High pressure adsorption analysis: experimental setup and calculations Prior to the adsorption experiment, a series of helium expansions corrected for non- ideality from a known reference volume to a sample cell are performed to calculate the 264 void volume. In our experiments the expansions are carried out over 10 pressure steps ranging from 0.25 MPa to 5 MPa. The void volume is calculated from: ( 1 ) P2 — P3 P3 — P1 where with appropriate correction for non ideality, P1 is the initial sample cell pressure, P2 is the pressure in the reference cell after charging with helium and P3 is the pressure in the sample cell and reference cell after expansion. A volumetric Boyles Law gas adsorption apparatus was used to measure high pressure methane isotherms at 30.0°C. The following mass balance calculation was used in conjunction with the real-gas law to calculate pure gas adsorbed volume isotherms of samples with mass, m, (@STP conditions; T = 273.15 K, P = 0.101325 MPa) at each isotherm step: P \P (2) V =ads TSTD ref ref (Vvo id l x[V ref PSTDM s The sample void volume (Vvoid), which is the volume in the sample cell not occupied by solid sample (includes free space in the sample chamber and accessible porosity in the sample), corrected for the volume occupied by the adsorbate (Vs) by assuming a molar density of the adsorbate which is taken here as that at normal boiling which for methane, a value of 0.423 g/cm3 was used. If the adsorbate volume is neglected, the Gibbs 265 isotherm is obtained. The effect of the assumed density of adsorbate is not considered in this paper but accepting any reasonable values do not detract from the conclusions of this study. Gas compressibility factors for pure gas isotherms were determined using the Peng-Robinson equation of state (EOS; Peng and Robinson, 1976). From our analyses, changing the EOS does not change the outcome of negative shales and mudrocks we have examined. The adsorption data is fitted to the Langmuir equation (Langmuir, 1918): (3)^VE^ VL P„ PL Pg where VE is the volume of absorbed gas per unit volume of the reservoir in equilibrium at pressure Pg, VL is the Langmuir volume (based on monolayer adsorption), the maximum adsorption capacity of the absorbent, P g is the gas pressure, PL is the Langmuir pressure, the pressure at which total volume absorbed and VE, is equal to one half of the Langmuir volume, VL. Pressure points were collected up to 9 MPa using high-precision pressure transducers (precision of 0.05% of the full scale value). For both helium calibrations and methane adsorption analysis, the system is kept at a constant bath temperature at ± 0.01°C as minor fluctuations in temperature effect the pressure. Before helium and methane analyses, the system manifold and cells are leak tested with helium to check for isolated cell leaks and through-valve leaks. Typically the system is evacuated and pressured up to 9 MPa. Several minutes are allowed for thermal equilibration, and 266 pressure readings are taken every 15 minutes for a 1-2 hour period. In addition, the high pressure fittings are leak tested with SNOOP® . Moisture capacities were determined by water saturation at 30°C (ASTM, 2004) which is recommended for moisture content under reservoir conditions. The method consisted of equilibrating samples over a saturated solution of potassium sulfate for more than 72 hours in a vacuum dessicator. For dry basis analysis, all samples were oven dried for 24 hours at a temperature of 110°C. 6.2.3 Considerations of volumetric calculation for gas adsorption Using the Gibbs excess approach (Gibbs, 1961) the amount of gas adsorbed is determined experimentally by (Sircar, 1985): (4) nsorbed = ntotal - CgasVvoid where ntotal is the total amount of gas in the system and c gasV,„id is the gas occupying the void volume calculated from the molar concentration in the gas phase, c ps utilising an EOS of the gas at various pressure/temperature conditions. The void volume in these calculations includes free space within the sample bomb and porosity within the sample not occupied by sorbate. During the adsorption experiments the void volume progressively decreases as the sorbate occupies space which is considered in the mass balance calculations. The volume also decreases due to swelling of the organic matter during adsorption (Laxminarayana and Bustin, 2003), the amount of which is organic matter and gas dependent. Although swelling is important as it results in a decrease in 267 the void volume, the error introduced by not considering the swelling effects due to methane adsorption can not account for negative adsorption. The impact of swelling is considered in a future paper. To calculate the adsorbed gas component (or excess adsorption), precise measurement of the void volume (Vvo,d) is required. Helium expansions are used for void volume calculations as it is considered to give precise measurement of the void space, hence sample volume by difference (Mayor et al., 1990). Helium is used as a choice of volumetric fluid for two reasons: 1) it has a small kinetic diameter which enables penetration to the finest microporosity (Singh and Kakati, 2000); and 2) it is commonly assumed that helium has a low adsorption coefficient at room temperature and moderate pressure (up to 9 MPa). Such an assumption however has been questioned since solid atoms can attract He (Starzewski and Grillet, 1989; Rouquerol et al., 1999) with helium even adsorbing in inert solids such as silicates (Gumma and Talu, 2003). 6.3 RESULTS The results of the paper are divided into two sections. Section I focuses on the use of helium as an analytical gas for void volume calibrations in adsorption experiments of heterogeneous materials, and in doing so examines the effects of pressure, helium adsorption and time. Section II discusses the adsorption implications of section Ito mass balance calculations in heterogeneous microporous materials. In order to demonstrate the importance of the heterogeneous and microporous pore structure of organic matter and minerals in coals and shales we have also carried parallel experiments using 268 synthetic zeolites of known pore size distribution and these results are included in the follow sections. 6.3.1 Section I: Helium effect If the pore sizes are comparatively large, adsorption and sample compressibility negligible, void volumes (free space between particles and accessible sample porosity) measured at various pressures with helium should be constant assuming appropriate corrections are made for non-ideality of the gas. These assumptions appear to be valid, for the ZeoSorb 61 sample which has a uniform pore size of 0.74 nm and for which the void volume (ratio of (P2-P3) / (P3-P1)) calculated by helium expansion is constant with increasing experimental pressures (Figure 6-3). However, for dry shale samples and the mineral standards of kaolinite, smectite and illite (Figures 6-4, 6-5A—C), the calculated void volume overall increases with increasing pressure. No continuous increase in void volume with higher pressure expansions is evident for quartz (>3.5 MPa; Figure 6-5D). For moisture equilibrated samples (Figure 6-6) the trend to increasing void volume with pressure is less pronounced than their dry counter parts, or is non-existent (e.g. smectite). The apparent increase in void volume for the natural materials (Figures 6-4, 6-5 and 6- 6) may be a manifestation of helium adsorption at high pressure or helium being able to access finer pores at higher pressures. Helium adsorption has been reported in previous literature for zeolites (Vermesse et al., 1996), activated carbons (Neimark and Ravikovitch, 1997) and inert silicates (Gumma and Talu, 2003). Although some adsorption of helium cannot be ruled out in our study, the absence of an increase in calculated void volume with increase pressure for ZeoSorb 61 suggests that adsorption is 269 0.6935 0.6930 0.6925 - 0.6920 - 0.6915 0.6910 - 0.6905 - 0.6900 0.6895 0.6890 0 ■ ■ • ■ ■ • ■ • • 0.5^1^1.5^2^2.5^3^3.5 ^ 4 ^ 4.5 ^ 5 Equilibrium cell pressure (MPa) Figure 6-3. Helium void volume calibration of ZeoSorb 61 (pore diameter of 0.74 nm). Note that above 2 MPa, the pressure ratios between reference cell and sample cell are relatively consistent. 270 0.386 • 0.385 ••• • • ■0.384 - • • ■ 0.383 - 0.382 0.4770 0.4765 0.4760 0.4755 0.4750 - 0.4745 - 0.4740 0.4735 0  • ■ • • ■ ■ ■ ■ • 2^3^4 5 6 Equilibrium cell pressure (MPa) 0 ^ 2^3^4 ^ 5 ^ 6 Equilibrium cell pressure (MPa) Figure 6-4. Calibration examples of organic-rich mudrock samples showing relative increase in measured void volume at higher pressure expansions. Note scales are not uniform. 271 1\.) Figure 6-5. Helium void volume calibrations for major constituents of shale/mudrock samples (all on dry-basis). A) kaolinite; B)smectite; C) illite; D) quartz. Note the increasing void volume trend at higher cell expansions is not apparent for quartz. 0 1 4 5 0 1 2 3 4 5 0 1 4 5 0 1 2 3 4 5 0.674 ■ ■ ■ 0.565 ■ •▪ ■ ■ • • ■ ■ • ■ 0.427 0.426 O • 0.425 a. .Ja- &.:4 0.424 0.423 0.422 2^3 Equilibrium cell pressure (MPa) 2^3 Equilibrium cell pressure (MPa) Equilibrium cell pressure (MPa) Equilibrium cell pressure (MPa) 0.684 A 0.682 -- 0.68 - (I a_ 0.678 -c) a. a_ 0.676 - ■ ■ 0.672 0.58 B 0.575 - 0.57 - • ■ 0.56 0.68 0.66 - 0.64 - 0.62 0.6 - 0.58 - 0.56 - 0.54 0.52 C ■ ■ ■ ■ ■ • ■ ■ ■ ■ 0.5 0.4615 0.461 - 0.4605 - 0.46 - a - 0.4595 - M a. 0.459 - (.4 0.4585 - a. 0.458 - 0.4575 - 0.457 - B • •■ ■ ■ ■ ■■ Moisture = 3.4 0.4565 0.431 A 0 43 ■ ■0.429 a. • a ■ a. c4i 0.428 - • 0.427 Moisture = 1.6 wt% 0.426 0 ^ 2 ^ 3 ^ 4 ^ 5 ^ 0 ^ 2^3 ^ 4 Equilibrium cell pressure (MPa) Equilibrium cell pressure (MPa) 0.475 0.474 0.473 0.472 21; 0.471 a.^0.47 ▪ 0.469 - a -r Cs1  0.468 - 0.467 - 0.466 - 0.465 - 0.464  0.482 C D ■ ■ C7. a. a. 0.481 - ■ 0.48 - ■ ■ ■ ■ ■ ■ ■ Moisture = 10.9 0.479 Moisture = 24.1 wt% 0 ^ 2 ^ 3 ^ 4 ^ 5 ^ 0 ^ 2^3 ^ 4 Equilibrium cell pressure (MPa) Equilibrium cell pressure (MPa) Figure 6-6. Void volume calibration examples of moisture equilibrated mudrock and clay samples with moisture contents shown in graphs. A—C) mudrock samples; D) smectite. Note for low EQ moisture samples, void volume calibration shows similar trend to dry samples indicating greater void space is still available at higher pressures. Samples with high EQ moisture contents (5378-1 and smectite) show no clear trend. not significant. Additionally if adsorption of helium was responsible for the trend in void volume with pressure, we would anticipate that the calculated void volume would plateau at higher pressures, mimicking a Langmuir adsorption isotherm. The general slopes of the helium isotherm curves are rather continuous and relatively constant (Figure 6-7) suggesting that helium is not significantly being adsorbed as no saturation point is reached (hence labelled as excess helium capacity rather than helium adsorption (Hyun and Danner, 1982; Cavenati et al., 2004). The time-dependant diffusive nature (Mair et al., 1998) of helium is also suggested from calculated excess helium capacities for different calibration times (i.e. the time given between the shut-in of the cell and recording cell pressure). For example, there is a systematic decrease in the excess void volume (or using the Gibbs methods amount of He adsorbed) from a calibration time of 1000, 300 and 30 seconds (Figure 6-8). The results suggest that for shorter calibration times there is less time available for helium to diffuse and/or adsorb into the sample which produces a smaller void volume. Although we can not entirely separate the helium capillary effect from the helium adsorption effect for void space calculations, our experiments indicate that pore access at higher pressures is important. Hence the increasing trend in void volume with pressure is thus considered mainly a consequence of greater accessibility of helium to restricted pores at higher pressures (i.e. a capillary effect). Essentially a "squeezing" of molecules through pore openings and into micropores occurs (Predescu et al., 1996; Du and Wu, 2006). Diffusion of helium is confirmed by the slow and continuous decrease of equilibrium pressure as the He penetrated the interconnected network of pores. 274 Figure 6 -7. Helium isotherms with monotonous trends. A) Smectite; B) and C) mudrock samples. Occasionally isotherms have humps, perhaps a reflection of the slow diffusion into the microporosity. 0 2^3^4^5^6 Equilibrium cell pressure (MPa) 7 8 II: 0.07 0.06 0.05 U 0.04 ets°- c.) 0.03 0.02 .c a) 0.01 11.1 0.00 -0.01 0.00 co ^ 7 80 54 6 7 0.12 0.10 - 0.08 - 0.06 - 0.04 - 0.02 - 0.00 0 2^32^3^4^5^6 Equilibrium cell pressure (MPa) Equilibrium cell pressure (MPa) B ■ ■ ■ ■ 0.08 0.07 - 0.06 0.05 0.04 0.03 0.02 0.01 - A ■ ■ • ■ • ■ C • ■ • - • ■ • • ■ •■ • —0— 30 secs —A— 300 secs —II— 1000 secs 0 05 a. co -  0.04 cs) • 0.03P_ co • 0.02 Ez.— 7) 0.01 N a) c.)• 0 w -0.01 0 ^ 1 ^ 2^3^4^5^6 ^ 7 ^ 8 Equilibrium cell pressure (MPa) Figure 6-8. Calculated helium isotherms of a shale sample with different void volume calibration time. With longer calibration time, the molecule accessibility/adsorption is similar to the actual adsorption experiment hence lower excess helium capacity is calculated for the longer calibration time (i.e. 1000 seconds). The curves follow identical trends as only the void volume calibrations, and not the adsorption experiment, are varied with time. 276 Many of the helium isotherms have a 'step-like' profile (e.g. Figure 6-7C) which may reflect the gradual infilling of pores. The filling of microporosity (associated with the organic component?) can explain changes of the helium isotherm for the shale sample in Figure 6-7C which contains 11 wt% organic matter. The diffusion of helium into the microporosity is not controlled by the diffusion rate through the bulk sample (i.e. chemically assimilated in the matrix) as helium is not soluble over the time-scale of these experiments (unlike, for example, carbon dioxide; Larsen et al., 1995). As noted by Larsen et al. (1995), the diffusion of helium does raise an interesting point: is the ability of helium accessing pore space due to the small movement required of the samples molecular segments (and/or moisture) to allow its passage or is the micropore network continuous on the small-scale size of the helium atom? From the research here, no definitive conclusion can be made. Diffusion and adsorption of helium is also effected by the presence of moisture in shale and mudrock samples. The occupation of adsorption sites and pore-throats by water creates less space for the helium molecule to occupy and may restrict helium diffusion, as suggested by the less significant increase in void volume in moist samples. The absence of a trend in void volume for quartz is because it is not a microporous material. For the microporous ZeoSorb 61, the absence of a trend in void volume with pressure is because pore size is comparatively large and distribution is even and the sample dry such that helium saturation occurs at lower pressures than for shale samples which do not have the consistent internal structure of the zeolites. 277 If as our results suggest, there is a gas capillary effect at higher pressures with the natural microporous materials, then this change in void volume must be taken into consideration and accounted for in the mass balance calculation. With greater pore space (and hence void space) accessible to helium and thus presumably analyses gases at higher pressures, a unique void volume exists for each pressure step. To determine the excess adsorption for a particular pressure the corresponding pressure dependent void volume is required. If an average void volume is used for the entire isotherm, adsorption at low pressures will be overestimated and at high pressures underestimated. 6.3.2 Section II: Helium calibrations and methane adsorption experiments: pore size effect Isolating the effects of pore size and pore size distribution on the void volume calculations of gas shales or coals is difficult due to their heterogeneous character, variable moisture content and organic matter type and abundance. Hence in this section we first demonstrate the importance of helium vs. methane porosity on the adsorption calculations using synthetic zeolites of know pore size distribution. Methane adsorption isotherms were measured on zeolites 33, 43 and 61 at pressures up to 9 MPa utilizing helium to measure the void volume as routinely done in adsorption experiments of gas shales and coals. For both the 43 and 61 zeolites, methane isotherm data fit well to the Type I Langmuir model (Figures 6-9A and 6-9B). Conversely ZeoSorb 33 (0.31 nm pore-size) yields a calculated negative adsorption at every pressure step (Figure 6-9C). During the initial low pressure adsorption steps, sample cell pressure does not decrease indicating that adsorption is not taking place (Figure 6-10, example 1). 278 7 8 0 1 2^3^4^5^6 ^ 72^3^4^5^6 Equilibrium cell pressure (MPa) ^0.0 a^ ■ ■ 70 • •B •60- • 50- ■ •40 - ■ 30 - ■ 20 - ■ 10 - ■ 0 Equilibrium cell pressure (MPa) C 60 - 70 50 - 40 - 30 - 20 - 10 - 0 0 ■ ■ A • • ■ 1 ■ ■ • • • ■• ■ ■ ■ -2.0 - ■ • -12.0 0 ^ 1 ^ 2^3^4^5^6 ^ 7 ^ 8 Equilibrium cell pressure (MPa) Figure 6-9. Methane adsorption isotherms of zeolites with known pore-size distribution A) ZeoSorb 61: 0.74 nm pore-size; B) ZeoSorb 43: 0.41 nm pore-size; C) ZeoSorb 33: 0.31 nm pore-size). ■■ Example 3 0^1^2^3^4^5^6^7 Equilibrium cell pressure (MPa) 0.0 -2.0 - -4.0 - -6.0 - -8.0 - -10.0 - -12.0 0.246 Example 1 c). 2 02455 - 0.245 - 0.2445 - E 0.244 - .0 LW 0 2435 0243 0^0.01^0.02^0.03^0.04^0.05^0.06^0.07^0.08^0.09 0.9071 Example 2 - 0 907 0. 0.9069 g 0.9068 0 0.9067 e 0.9066 - o- w 0.9065 0.9064 ^ 0^0.01^0.02^0.03^0.04^0.05^0.06^0.07^0.08^0.09 0.01^0.02 0.03^0.04 0.05^0.06^0.07^0.08^0.09 7.376 7.374 7.372 7.37 - 7.368 - 7.366 - 7.364 - 7.362 - 7.36  - 7.358 - 7.356 Time (hours; minutes; seconds) Figure 6-10. Selected pressure steps of ZeoSorb 33 showing negative adsorption at all pressure steps. Example 1 shows no adsorption/diffusion of methane (no pressure decrease). However at further pressure intervals (e.g. Example 2 and 3), negative adsorption occurs despite cell pressure reductions. At higher pressure steps however, sample-cell pressures gradually decrease (Figure 6-10, examples 2 and 3), implying gas is either adsorbing and/or diffusing even though negative adsorption is calculated by mass balance. Two aspects of the high-pressure adsorption experiments need to be taken into consideration to explain the calculated negative adsorption for ZeoSorb 33: 1) the difference of kinetic diameters of the analytical gases - helium has a kinetic diameter of 0.26 nm whilst methane has a kinetic diameter of 0.38 nm (Vermesse et al., 1996); and 2) the equation used to calculate adsorbed gas capacities. If equal pore space was available to both helium and methane and no adsorption occurred (i.e. ntotai = Vvoid from equation (4)), then zero adsorption would be calculated. For ZeoSorb 43 and 61, positive adsorption is recorded as both helium and methane can penetrate all pores (pore size 0.41 and 0.74 nm) and methane can adsorb onto the high internal surface areas (i.e. ntotai >Vvoid). However negative adsorption of ZeoSorb 33 indicates Vvoid is larger than ntotai. This is a result of steric hindrance where helium can access pore space methane cannot, as the permeance of these gases is controlled by their kinetic diameters, molecular geometry, the pore dimensions and pore geometry of the samples. Methane with its larger kinetic diameter cannot penetrate the 0.31 nm pores, thus a larger void volume to helium exists than for methane. The larger void volume combined with extremely low levels of methane adsorption (as there are minimal amounts of adsorption sites available to methane due to the pore size) produces a calculated negative adsorption. The minute pressure drops in sample cell pressure for ZeoSorb 33 is a reflection of methane adsorbing onto the external surface area as all internal surface areas (i.e. 0.31 nm pores) 281 are inaccessible. Since the amount of adsorbed gas is minimal and the void volume is erroneously large, negative adsorption is calculated by mass balance. The sieving effect of gas molecules shown by ZeoSorb 33 helps explain why negative adsorption isotherms are calculated for low organic carbon content (TOC) shales (e.g. Figure 6-1). For TOC-lean shales, adsorbed gas capacities are low as there are minimal adsorption sites available to methane (minimal microporous organics). Similar to ZeoSorb 33, shales with negative adsorption show reductions in sample cell pressures (Figure 6-11) indicating gas is adsorbing during the experiment. However the magnitude of pressure-change due to adsorption is too small to compensate for the negative effects that are an artifact of the void volume to helium exceeding the void volume available to methane (vvold >ntotai)• Helium can penetrate more of the sample whether it is ultra-fine microporosity (Marsh, 1987) or restricted pore-throats which cannot be accessed by methane (Figure 6-12A). For organic-rich shales, there is ample porosity available and accessible to both helium and methane hence positive sorption is calculated (Figure 6- 12B). In Figure 6-13 we consider the adsorption isotherm on an organic lean, low methane adsorbing shale with a total helium porosity of 2.64% and organic carbon content of 1.65%. Utilizing the void volume to helium averaged over a series of helium expansions yields negative adsorption values at high pressures in spite of adsorption occurring as evident from pressure changes in the sample cell. If the porosity available to methane is not 2.64% (helium porosity) but 1.99% (for example), positive adsorption is calculated (ritotal >Vvold)• Assuming (in this example) that 0.65% porosity (2.64% minus 1.99%) is 282 0.20 0.15 0.10 0.05 0.00 -0.05 -0.10 -0.15 -0.20 0^1^2^3^4^5^6^7 Equilibrium cell pressure (MPa) 26785 ii m 3.678 a 3 6775 ok: 3.677 - - Il E 3.6765 - 3.676 - .3 0" U.1 3.6755 - 3.675 ^ Example 2 a ES II 6.492 6.4915 6.491 6.4905 6.49 02648 Example 1 0.2647 a. 0.2646 - 11' ti 0.2645 E ■= 02643 W 0.2642 - 0.2641 O 0.01^0.02^0.03^0.04^0.05^0.06^0.07^0.08^0.09 3.679 O 0.01^0.02^0.03^0.04^005^0.06^0.07^0.08^0.09 a 0.  0.2644 - 64945 6.494 Tv'O. 6.4935 2 6.493 Sa 6.4925 Example 3 O 0.01^002^0.03^0.04^0.05^0.06^0.07 ^ 0.08^0.09 lime (hours; minutes; seconds) Figure 6-11. Mudrock sample with negative methane adsorption yet raw pressure data reveals gas diffusion and/or adsorption. A4 I I S S I S 5 S S  0 Figure 6-12. Conceptual illustration of gas diffusion and sorption in the heterogeneous shale matrix. A) Low sorbing, organic-lean shale with some pores and pore throats penetrable only by helium (constricted pores; 1 and 2). Hence internal surface area can only be accessed by helium (3), and not methane (location of figure A-2 shown in figure A-1). B) High sorbing, organic-rich shale which has pore throats through which both helium and methane can permeate (1 and 2). Following diffusion into the micropores, methane can sorb onto the internal surfaces (3). 284 •• ■• • • I x x • ■ • • • ■ • 1.99% Porosity ■ 2.21% Porosity ♦ 2.42% Porosity x 2.64% Porosity ••• •■ • • ■ • • ■ • 0.25 0.2 0.15 0.1 1u) 0.05 0 2 -0.05 -0.1 0 ^1^2^3^4^5^6^7^8^9^10 Equilibrium cell pressure (MPa) Figure 6-13. Hypothetical example showing the reduction of porosity (or excess void space which is only accessible to helium) required to calculate positive adsorption using mass balance calculations on low-adsorbing shales. 285 available to helium but not methane has a marked effect on the isotherm shape and the calculated adsorptive capacity. The actual amount of porosity available to helium but not methane will vary from sample to sample due to heterogeneous pore-throat diameters, pore-size distributions and surface roughness and hence must be measured for each sample. ZeoSorb 33 with a 0.31 nm pore size is the most dramatic example of pore sieving since the pore size are uniformly larger than helium and smaller than methane whereas in naturally materials the pore size and pore distribution will vary markedly. The example selected here (Figure 6-13) is a low adsorbing shale and hence the errors resulting from inappropriate void volume are striking. Errors will also exist in more strongly adsorbing organic-rich shales (and coals) however the errors are masked unless the experiments are run to pressures high enough that adsorption is negligible. The amount of the error will be proportional to the pore-size and pore-size distribution of the sorbate (mainly the organic fraction) and the analysis gas. For example some of our laboratory experiments have shown that ethane adsorption experiments on some coals do produce calculated negative isotherms at moderate to higher pressures even though there is adsorption taking place as evident from the pressure changes in the sample cells. 6.4 CONCLUSIONS The data presented here documents the effect and errors that may result if helium is used as a void volume calibration gas for high pressure adsorption experiments in heterogeneous microporous materials. Experimental analysis reveals that both pressure and time affect the amount of helium which penetrates, and possibly adsorbs, into a sample: potentially more pore space is available to helium at greater pressures and 286 increased calibration time. If pore accessibility to various gases change with increasing pressure as suggested by our data, using an average void volume will results in calculated adsorbed gas volumes that are too high at low pressures and too low at high pressures, even if the volume is corrected for sorbate volume. Experiments with zeolites of known pore size highlights how the porous structure of the adsorbent contributes to adsorption which depends on the accessibility of the molecule to the adsorption sites and underlining the deficiencies of mass balance calculations. The accessibility to internal surface area is controlled by the diameter size of the pores, pore- throats and kinetic diameter of the gas molecule and needs to be taken into consideration where helium is used to measure the void volume. Experiments with the synthetic zeolite, ZeoSorb 33, which a pore diameter of 0.31 nm underlines the importance of pore size: negative adsorption is calculated by mass balance at all pressures because the helium can access the internal pore structure and methane cannot and thus the void volume to helium markedly exceeds that available to methane. Calculated negative adsorption of shale samples lean in total organic carbon content is a result of the void volume (free space plus sample pore space) available to helium exceeding that available to methane and hence the mass balance calculation is in error - negative adsorption is calculated even though adsorption occurs as evident from distinctive pressure drop in the sample cells. In organic-rich shales and coals, their larger adsorbed gas capacities mask errors due to inappropriate void volumes. However even with organic rich samples and positive adsorption, the adsorbed gas capacity is underestimated. 287 Mass balance techniques when used without due consideration for the pore size distribution are inappropriate for heterogeneous microporous materials such as shales, mudrocks and coals. For gas shales and coalbed methane deposits even relatively small errors is adsorption calculations may result in substantial errors when extrapolated to the reservoir scale. Future work on this topic will include expansion of the current data set by incorporating a broader suite of compositionally diverse, low-sorbing shales and mudrocks. To assess the effect of kinetic diameter hindrance in shales and mudrocks, gases of variable size will be utilized for volumetric adsorption calculations (e.g. ethane, krypton, and argon). Further investigation of negative adsorption for coals is also required as from our limited data-set, ethane adsorption experiments can produce negative isotherms. 288 6. 5 REFERENCES Alymore, L.A.G and Quirk, J.P. 1967. Micropores of Clay Mineral Systems. Journal of Soil Science, v. 18, p. 1-17. Aringhieri, R. 2004. Nanoporosity characteristics of some natural clay minerals and soils. Clays and Clay Minerals, v. 52, p. 700-704. ASTM D1412-04, 2004. Test for Equilibrium Moisture of Coal at 96 to 97% Relative Humidity and 30°C. Brunauer, S., Deming, L.S., Deming, W.S. & Teller, E. 1940. On a theory of van der Waals adsorption of gases. The Journal of the American Chemical Society, v. 62, p. 1723-1732. Bustin, R. M. Gas shales Tapped for Big Play. AAPG Explorer; February 2005 Cavenati, S., Grande, C.A. and Rodrigues, A.E. 2004. Adsorption Equilibrium of CH4, Carbon Dioxide, and Nitrogen on Zeolite 13X at High Pressures. Journal of Chemical Engineering Data, v. 49, p. 1095-1101. 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. International Journal of Coal Geology, v. 70, p. 223-239. Cui, X., Bustin, R.M. and Dipple, G. 2004A. Selective transport of CO 2 , CH4, and N2 in coals: insights from modeling of experimental gas adsorption data. Fuel, v. 83, p. 293- 303. Cui, Y., Kita, H. and Okamoto, K. 2004B. Preparation and gas separation performance of zeolite T membrane. Journal of Materials Chemistry, v. 14, p. 924-932. 289 Du, X. and Wu, E. 2006. Physiosorption of hydrogen in A, X and ZSM-5 types Zeolites at moderately high pressures. Chinese Journal of Chemical Physics, v. 19, p. 457-462. Dubinin, M.M. 1975. Progress in Surface and Membrane Science. Academic Press, New York. Dubinin, M.M. and Astakhov, V.V. 1971. Description of adsorption equilibria of vapors on zeolites over wide ranges of temperatures and pressure, in R.F. Gould, ed., Advances in Chemistry Series, American Chemical Society, Washington DC, v. 102, p. 69-85. Gan, H., Nandie, S.P. and Walker Jr, P.L. 1972. Nature of porosity in American Coals. Fuel, v. 51, p. 272-277. Gibbs, J.W. 1961. On the equilibrium of heterogeneous substances in J.W. Gibbs, ed., The Scientific Papers of J.W. Gibbs, New York NY: Dover Publications, v. 1, p. 55- 349. GRI (Gas Research Institute). 1996. A guide to coalbed methane reservoir engineering. Gas Research Institute, FRI-94/-397. Gumma, S. and Talu, 0. 2003. Gibbs dividing surface and helium adsorption. Adsorption, v. 9, p. 17-28. Hyun, S.H. and Danner, R.P. 1982. Equilibrium Adsorption of Ethane, Ethylene, Isobutane, Carbon Dioxide and Their Binary Mixtures on 13X Molecular Sieves. Journal of Chemical Engineering Data, v. 27, p. 196-200. Krooss, B.M., van Bergen, F., Gensterblum, Y., Siemons, N., Pagnier, H.J.M. and David, P. 2002. High pressure CH4 and carbon dioxide adsorption on dry and moisture equilibrated Pennsylvanian coals. International Journal of Coal Geology, v. 51, p. 69— 92. 290 Langmuir, I. 1918. The adsorption of gases on plane surfaces of glass, mica and platinum. The Journal of American Chemical Society, v. 40, p. 1403-1461. Larsen, J.W., Hall, P. and Wernett, P.C. 1995. Pore Structure of the Argonne Premium Coals. Energy and Fuels, v. 9, p. 324-330. Laxminarayana, C. and Bustin, R.M. 2003. Sequestration potential Acid gases in Western Canadian coal, Paper # 0360, The 2003 International Coalbed Methane Symposium held on 5-8th May 2003 at Tuscaloosa, Alabama, USA. Li, M., Gu, A.-Z., Lu, S.-S. and Wang, R.-S. 2004. Supercritical Methane Adsorption Equilibrium Data on Activated Carbon with Prediction by the Adsorption Potential Theory. Journal of Chemical Engineering Data, v. 49, p. 73-76. Mair, R.W., Cory, D.G., Peled, S., Tseng, C. –H., Patz, S. and Walsworth, L. 1998. Pulsed-Field-Gradient Measurements of Time-Dependent Gas Diffusion. Journal of Magnetic Resonance, v. 135, p. 478-486. Malbrunot, P., Vidal, D. and Vermesse, J. 1997. Adsorbent helium density measurement and its effect on adsorption isotherms at high pressure. Langmuir, v. 13, p. 539-544. Marsh, H. 1987. Adsorption methods to study microporosity in coals and carbons—a critique. Carbon, v. 25, p. 49-58. Mayor, M.J., Owen, L.B., Pratt, T.J. 1990. Measurement and evaluation of coal sorption isotherm data. 65 th Annual Technical Conference and Exhibition of the Society of Petroleum Engineers. Society of Petroleum Engineers, New Orleans, LA, p. 157-170, SPE 20728. Neimark, A.V. and Ravikovitch, P.I. 1997. Calibration of pore volume in adsorption experiments and theoretical models. Langmuir, v. 13, p. 5148-5160. 291 Polanyi, M. 1932. Theories of the adsorption of gases: A general survey and some additional remarks. Transactions of the Faraday Society, v.28, p. 316-321. Predescu, L., Tezel, F.H. and Chopra, S. 1996. Adsorption of nitrogen, methane, carbon monoxide, and their binary mixtures on aluminosilicate molecular sieves. Adsorption, v. 3, p. 7-25. Ramos, S. 2004. The effect of shale composition on the gas sorption potential of organic-rich mudrocks in the Western Canadian Sedimentary Basin. Unpublished MSc Thesis, University of British Columbia, Canada. Ross, D.J.K. and Bustin, R.M. 2007. Shale gas potential of the Lower Jurassic Gordondale Member, northeastern British Columbia, Canada. Bulletin of Canadian Petroleum Geology, v. 55, p. 51-75. Rouquerol, J., Avnir, D., Fairbridge, C.W., Everett, D.H., Haynes, J.H., Pernicone, N., Ramsay, J.D.F., Sing, K.S.W. and Unger, K. 1994. Recommendations for the characterization of porous solids, International Union of Pure and Applied Chemistry. Pure and Applied Chemistry, v. 68, p. 1739-1758. Roquerol, F., Roquerol, J. and Sing, K. 1999. Adsorption by powders and porous solids. Academic Press, London. Rudzinski, W. and Everett, D.H. 1972. Adsorption of gases on heterogeneous surfaces. Academic Press, San Diego, CA. Sing, K.S.W, Everett, D.H., Haul, R.A.W., Moscou, L., Pierottie, R.A., Roquerol, J. and Simieniewska, T. Reporting Physiosorption Data for Gas/Solid systems. Pure and Applied Chemistry, v. 57, p. 603-619. 292 Singh, K.P. and Kakati, M.C. 2000. Simple models for estimating helium densities of coals. Chemical Engineering Journal, v. 76, p. 67-71. Sircar, S. 1985. Excess properties and thermodynamics of multicomponent gas adsorption. Journal of the Chemical Society Faraday Transactions, v. 81, p. 1527- 1540. Starzewski, P. and Grillet, Y. 1989. Thermochemical studies of adsorption of He and CO2 on coals at ambient temperature. Fuel, v. 68, p. 375-379. Steele, W.A. 1974. The interaction of gases with solid surfaces. Pergamon Press, New York. Vermesse, J., Vidal, D. and Malbrunot, P. 1996. Gas Adsorption on Zeolites at High Pressure. Langmuir, v. 12, p. 4190-4196. 293 CHAPTER 7 CONCLUSIONS 294 CHAPTER 7 Conclusions 7.1 INTRODUCTION Elucidating the controls upon gas capacities in fine-grained strata and accurately determining reservoir potential requires knowledge of shale physical structure. Shale is a complex, heterogeneous rock which presents formidable analytical challenges. The intricate pore network of shales is difficult to assess because pore-throats can be smaller than 2 nm — a size that many experimental methods cannot characterize. At this scale, molecular sieving effects may exist which imparts significant errors on gas content calculations (Chapter 3). Shale gas reservoir evaluations rely upon scaling laboratory data to regional reservoir magnitudes, but failure to recognize the nano-scale heterogeneity will lead to erroneous economic assessments. The goal of this research was to characterise the diversity and heterogeneity of shales with respect to shale gas reservoir evaluation; from the inception of sediment deposition, through maturation and diagenesis. The interrelationship of these key geologic parameters affect pore structure hence gas-storage properties and producibility, and the ability to construct exploration and development models. Shales from Devonian- 295 Mississippian (D—M) strata (Besa River, Muskwa, Fort Simpson and Mattson formations) and Jurassic strata (Gordondale Member) were used in this study. 7.2 KEY FINDINGS Comparisons of D—M and Jurassic strata show that shale pore structure is a function of organic content, mineralogy and thermal maturation. Low pressure volumetric sorption experiments of iso-maturity D—M samples indicate greater micropore volumes of organic-rich shales than organic-lean shales, thus increasing methane sorption capacity with total organic carbon (TOC) content. The ratio of sorbed gas to TOC is also dependent on thermal maturity. At higher maturation levels, internal surface areas are larger (per wt% TOC), illustrating the effect of thermal maturity on pore-wall chemistry. As a consequence, over-mature D—M shales sorb more gas than Jurassic shales (within the wet gas/oil to dry gas region) on a wt% TOC basis. Micropore volumes of Jurassic strata within the oil-window tend to be low, despite TOC contents >30 wt%, due to the amorphous/structureless nature of matrix bituminite at these levels of thermal maturation. Isotherms of Jurassic shales are often linear, not Type I Langmuir, indicative of a solute gas component to the total gas storage capacity. Microporosity is associated with clay mineral phases, as evident by the largest micropore volumes (in this study) of organic-rich, clay-rich upper Besa River shales, and large internal surface areas of clay minerals. Mercury porosimetry results show that clay- rich shales have unimodal, mesopore-size distributions whereas quartz-rich (bio-silica), clay-poor and carbonate-rich mudrocks display tight-rock characteristics with mercury 296 unable to penetrate the meso- and micropores. Such findings emphasize the importance of shale sedimentology, depositional environment and diagenesis (Chapter 2) to total gas capacities and producibility. 7.3 ECOMOMIC PERSPECITVE: SHALE GAS RESOURCE POTENTIAL OF DEVONIAN—MISSISIPPIAN STRATA, WESTERN CANADIAN SEDIMENTARY BASIN Devonian—Mississippian strata in northern British Columbia have significant shale gas resource potential. Of interest are the Horn River (including the laterally equivalent lower Besa River mudrocks) and Muskwa formations which have potential gas capacities ranging between 100 and 240 bcf/section and >400 tcf gas in place (GIP). Reservoir characteristics making Horn River and Muskwa formations prospective exploration opportunities include: 1) high TOC contents, up to 5 wt% 2) total thicknesses >240 m and areal extent of 6250 km2 3) the formations lie within the thermogenic gas region, maximising the potential for gas generation and enhanced permeability (through the removal of pore-blocking oil phases) 4) strata are quartz-rich (up to 93%) and may be suitable for induced fracturing, increasing drainage area and aid gas flow to wellbore 5) shales are underlain by limestones which may provide suitable fracture propagation barriers 297 The multidisciplinary approach used in this study highlight shale gas reservoir features unique to Devonian—Mississippian strata in northern BC that require consideration. For example, despite the invariably brittle nature of quartz-rich shales, the predictable pore- size variation between siliceous D—M shales towards smaller pores (<2 nm) suggests lower free gas capacities of quartz-rich shales than porous clay-rich shales (e.g., upper Besa River). Therefore a balance is needed between producibility (or fracturing potential, which varies with quartz content) and total gas content (varying with total porosity). At the reservoir temperatures of D—M strata, sorbed gas capacities are low (<0.01 cc/g), due to the exothermic nature of gas sorption (Al-Muhtaseb and Ritter, 1999), underlining the potential importance of free gas to economic gas production. 7.4 FUTURE RESEARCH POSSIBILITIES Shales constitute a large proportion of sedimentary sequences, between 60-70% of basin-fill (Dewhurst et al., 1998), and represent potentially enormous gas resources which require examination. In order to predict gas capacities and gas production of these unconventional-type reservoirs, intricate shale gas models need to be developed which integrate the data discussed in this thesis. However, nano-scale heterogeneities of fine- grained, organic-rich strata inhibit the development of a reservoir exploration model that can be applied to shale gas systems worldwide since relationships between shale physical properties, gas contents and producibility established for one reservoir are not directly applicable to another. Systematic investigations of shales with different compositions and thermal maturities are required to expand the research presented here, which will: 1) help identify possible global relationships between total gas capacity and shale 298 composition, and; 2) develop our knowledge of favourable geologic attributes needed to produce gas economically from shales. A useful study would address the accurate scaling of laboratory data to in-situ reservoir conditions. As discussed in Chapter 3, the pore size distributions of shales are at a scale whereby the size of the analytical gas molecule influences measurements of sorption capacity and total porosity. These are parameters requiring precise determination in the laboratory, because extrapolation of incorrect gas contents to regional reservoir scales with only result in larger errors of GIP estimations. Further investigations of the use of gases with different kinetic diameters (He, CH4, CO2, and N2) in shales are required to resolve these errors. Another research area of practical significance is determining gas saturation levels of shales. To do so, canister desorption data (in conjunction with sorption isotherms; GRI, 1996) are needed from which gas recovery strategies can be devised. The degree of gas saturation is critical for reservoir modelling as this will dictate the pressure to which the reservoir needs to be lowered to for gas production. If it is indeed true that during thermal maturation, more CH4 is released than can be stored on internal surfaces (akin to coals; Rightmire, 1984), shales should be over-satumted 16 . However, reported under- saturation 17 of coals (Radovic et al., 1997; Bustin and Bustin, in press) suggests laboratory experiments have difficulties replicating geologic-time equilibration processes. Recent data has shown over-saturation of shales, implying that desorbed gas capacity is a product of both sorbed and free gas (i.e., co-mingled gas production; Bustin, 16 Refers to gas reservoirs which have canister desorption datum above the sorption isotherm 17 Refers to gas reservoirs which contain less gas than their measured sorption capacity 299 2005). More data is required to investigate the gas saturation levels of shale reservoirs at various pressures and temperatures, and with different gas compositions. Although this study has provided insight to the pore structure of shales with variable composition and maturity, pore-geometry and -connectivity models for shales are not well established. Pores can be a variety of shapes including slits, cylinders or spheres, and either isolated or connected within the matrix (Larson et al., 1995; Anderson et al., 1997). Supplementary examination of shale pore network could include I29Xe nuclear magnetic resonance (NMR) spectroscopy, which has been used to define pore sizes in zeolites (Demarquay and Fraissard, 1987), microporous carbons (Wernett et al., 1990) and coals (Tsiao and Botto, 1991). Conceptual illustrations of shale pore structure would also benefit from high resolution imaging, such as magnetic resonance imaging (MRI; Anderson et al., 1997). These types of analyses would contribute to our understanding of pore structures, and improve adsorption rate/matrix transport models. 300 7.5 REFERENCES Al-Muhtaseb, S.A. and Ritter, J.A. 1999. A statistical mechanical perspective on the temperature dependence of the isosteric heat of adsorption and adsorbed phase heat capacity. Journal of Physical Chemistry B, v. 103, p. 8104-8115. Anderson, S.A., Radovic, L.R. and Hatcher, P.G. 1997. Effects of surface chemistry on the porous structure of coal. Technical progress report, Fuel Science Program, Pennsylvania State University, 24 p. Bustin, R. M. 2005. Factors influencing the reservoir capacity of gas shales and coals (abs.): Key note address, Gussow Conference, Canadian Society of Petroleum Geologists, March 10,2005, Banff, Alberta p. 5. Bustin, A.M.M. and Bustin, R.M. Coal reservoir saturation — impact of temperature and pressure. The American Association of Petroleum Geologists Bulletin, in press. Demarquay, J. and Fraissard, J. 1987. 129Xe NMR of xenon adsorbed on zeolites. Relationship between chemical shift and the void space. Chemical Physical Letters, v. 136, p. 314-318. Dewhurst, D.N., Aplin, A.C., Sarda, J-P. and Yang, Y. 1998. Compaction-driven evolution of porosity and permeability in natural mudstones: an experimental study. Journal of Geophysical Research, v. 103, p. 651-661. GRI (Gas Research Institute), 1996. A guide to coalbed methane reservoir engineering: Chicago, Gas Research Institute, FRI-94/-397. Larsen, J.W., Hall, P. and Wernett, P.C. 1995. Pore structure of the Argonne Premium coals. Energy Fuels, v. 9, p. 324-330. 301 Radovic, L.R., Menon, V.C., Leon Y Leon, C.A., Kyotani, T., Danner, R.P., Anderson, S. and Hatcher, P.G. 1997. On the porous structure of coals: evidence for an interconnected but constricted micropore system and implications for coalbed methane recovery. Adsorption, v. 3, p. 221-232. Rightmire, C.T. 1984. Coalbed methane resource. In: C.T. Rightmire, G.E. Eddy and J.N. Kin (Eds.). The American Association of Petroleum Geologists, Tulsa, 1984, p. 1- 13. Tsiao, C. and Botto, R.E. 129Xe NMR investigation of coal micropores. Energy Fuels, v. 5, p. 87-92. Wernett, P.C., Larsen, J.W., Yamada, 0. and Yue, H.J. 1990. Determination of the average micropore diameter of an Illinois no. 6 coal by I29Xe NMR. Energy Fuels, v. 4, p. 412-413. 302 SHDIGNaddV WE APPENDIX DATA A CORE DATA 304 Well #:^2002/D-064-K 094-N-16^Formation: Besa River^Date:^Sheet #: Core # 21 Name: QUESTERRE HZ BEAVER^Core Interval: 3344 . 85 m - 3353 . 33 m^Logged By: 15 2 Texture Lithology sorting 1 Fractures , i ;^= F is -: Comments/Remarks UNIT: BESA RIVER. Mudstone - shale, very stlicic, hard, dense, setter towards base, blocky, rare fractures ISOTHERM SAMPLES BRS325-1 (3344.85 m) 8RS325-2 (3346.35 m) BRS325-3 (3347.85 m) BRS325-4 (3349 35 m) BRS325-5 (3350.85 m) BRS325-6 (3352.35 m) BR5325-7 (3353.05 m) BRS325-2 • _._-^...A---4^,.- .^-., v 44.;.^.3.SZ ' Ogit .' T 4.:??. •.: : Fy 4, rr.: Conglorn. Sand 'o -_ r.nZcorpo,0 c..)2LL> 3344 3346 3348 _ _- 3350 3352 3354 E11)) Pyrite filled fracture 111111111111111 9^A^A_^R^A 305 r Well #: 202/b-019-K 094-N-16^Formation' Besa River^Date:^Sheet #: Core # 1 & 2 Name: QUESTERRE BEAVER^Core Interval' 3756.06 m - 3763.64 m^Logged By: F2 cu 2 Texture Lithc409Y a Sorting t 3 i: '8^.4' Z o_ 5 Sand Fractures ii4 f, - f,.^xi,^c 3^9 ?= ' g ... Comments/Remarks UNIT: SHALE (7.6 m). Mudstone, black, siliceous, finely laminated, slickensides, disseminated pyrite, hairline horizontal and vertical fractures, partial and full cementation with calcite. ISOTHERM SAMPLES BRS2563-1 (3756.21 m) BRS2563-2 (3757.94 m) BRS2563-3 (3758.69 m) BRS2563-4 (3760.56 m) BRS2563-5 (3762.06 m) BRS2563-6 (3763.56 m) Perm, Sample BRS2563-7 (3759.81) TOC samples: 28 samples throughout core interval Conglom. rii 'iri ^^c coiuoir...4 c.i2iL L5 3756 3758 3760 3762 BRS2563-6 -.=■,-4,;•.^.. -,,, III --------- 3764 4^5^6^7 :',M^IIII^BRS2563-7 306 Well #:^D-075-E 094-N-08^Formation' Fantasque^Date:^Sheet #: Core # 8 Name:^10E DUNEDIN Core Interval: 3157.8 m - 3163.93 m^Logged By: :42' cii Texture Lithology Soiling *-Z 3 I ; n Fractures ca »^ c- E = 173  5 i `C E co S'. 1:‘ Comments/Remarks CORE 8: 3751.51 m - 3753.61 m UNIT: FANTASQUE. Silica mudstone/chert, black, dense, hard, abundant vertical and horizontal fractures, hairline, calcite lined and filled. ISOTHERM SAMPLES FAS1331-21 (3157.8 m) FAS1331- (3160.05 m) FAS1331-3 (3162.9 m) FAS1331-4 (3163.8 m) FAS1331-5 (3164.92 m) fr^ : ...111 ...:-K„,,- :4,^•.. ,..• ..,:,*%.3Z;:w ^'':,. ::,..t,[:., '^• /1111111[11111111•111,111 0^1^2^3_^4^5^6^7 Conglom. Sand rm L'..' 4 . re2 I.L...^c cer.Do_O (..)Zi.L> 3156 3158 3160 3162 3164 / .3 307 Well #:^D-075-E 094-N-08^Formation Mattson^Date:^Sheet # Core # 9 Name:^10E DUNEDIN Core Interval: 3181 . 8 m - 3184.55 m^Logged By: ,tf2 '6 2 Texture Lithofogy Sorting t^083^.._ I ; ci ‘1 Fractures I ^, ^c ^ .. -' t ^t ^ 1 1'^2 li'7:-. - Comments/Remarks CORE 9: 3181.8 m - 3184.55 m UNIT: MATTSON SHALE (075 m), Medium-light grey, marly texture, fissile, sl ightly carbonitic UNIT LIMESTONE (0.75m), Medium grey, microcrystalline, argillaceous, fractured with occasional coarse calcite fill.. ISOTHERM SAMPLES MASH1331-1 (3182,1 m) ,ii. '.,^,,iark C00910+71. Sand 'a .-..-: i-Acor.'91:Lc9 (32,,j 3181 3182 3183 3184 3185 1-Lril ^I 308 Well #:^D-075-E 094-N-08^Formation: Mattson^Date:Sheet #: Core # 10 Name:^10E DUNEDIN Core Interval: 3254.8 m - 3266.97 m^Logged By: <I.) 2 Texture La10109Y Sorting I • T2 "' a" g^3' Fractures g (.. E g  -a k Comments/Remarks CORE 10: 3254.8 m - 3266.97 m UNIT: SILTSTONE (12.1 m). Medium grey, finely laminated, dense, hard, calcareous, shaley in parts, mm-sized fractures (vertical, horizontal and oblique), calcite-filled, evidence for soft-sediment deformation. Lower 5 m: shaley with minor amounts of carboante, bioturbation, occasional shell debris with calcite replacement, mud ctasts as base of section, pyritic 'blebs'. Conglom. Sand ...,^..7-2 .— = co 2 s c o Up scLO , 0^u_ >  E , 1 c'^i5^°' i m 3254 3256 3258 3260 3262 3264 3266 —.—.- - — — --A^t -:.,^, -.,....^..^-^-..^._ 'fiiii^..„,10- , 3268 Samples: MASST1331-1 (3256.11 m) MASST1331-2 (3257.8 m) MASST1331-3 (3264.66 m) • 309 Well #:^D-075-E 094-N-08^Formation' Mattson^Date:^Sheet #' Core # 11 Name:^10E DUNEDIN Core Interval: 3324 - 54 m - 3336.15 m^Logged By: mu) 2 Texture Lithology Sorting "5-^- a o_ 3 If, "3 Fractures E co^r, m^g _._rif m g p_ g a. Comments/Remarks CORE It 3324.54 m - 3336.15 m UNIT: SILTSTONE (1.0 my Medium grey, interbedded shale stringers, non-calcareous, massive, dense, hard, scattered shell material replaced by calcite. UNIT: SHALE (2.6 m). Black, non-calcareous, fissile. fractured with no cementation, fractures are hairline and vertical, interbedded with silt at top contact, pyrite laminae, pyrite 'blebs', laminae up to 1 cm thickness UNIT SILTSTONE (3.75 my As above, occasional horizontal calcite veins, 3 - 4 mm in thickness UNIT: SHALE (1.25 m). As above, abundant hairline fractures, many with calcite cementation UNIT: SANDSTONE (3 m). Very fine greained, grading to silty shale, sandstone highly bioturbate. Samples: MASH1331-2 (3326.04 m) MASH1331-3 (3326.79 m) MASH1331-4 (3329.04 m) MASH1331-5 (3332.79 m), -......:.-i,:ir TOC samples:^ gat MASH1 331-4 C0091001 . Sand ..1, 1.-_ '4 -- . in2 >^c coon_o to. omit> 3324 3326 3328 3330 3332 3334 — ---•—•--_._._ ._.... ____ _ — — - _____ •---••^.-•----••^•-• •••• ••••• *.".'.*..•^ •• •• • • •• ••^ ••• • • •^•^• le trac t{ Sandstone - massive and bioturbated ,..., '!,'. -4111 Ji., 310 Well #:^D -075 -E 094 -N-08^Formation' Mattson^Date:^Sheet #: Core # 12 Name:^10E DUNEDIN Core Interval: 3409.01 m - 3420.3 m^Logged By: cn2 1 5 2 Texture Lithotogy sorting t 11 j ; , Fractures cs,^, ^c -•E^..^•!. ,^g ! I 1' 2 2C l M...° "o.. Comments/Remarks CORE 12: 3409.01 in - 3420.3 m UNIT: SHALE (7.5 m). Dark grey, many texture in parts, interlaminated with siltstorte, disseminated pyrite, highly fractured, majority hairline and vertical, occasional calcite-filled fractures, coarse crystalline, soft- sediment deformation, slickensides common. Conglom. Sand ,,.. 1 2 -Ir?1:1.- 1, C)-alp(o..(9 (_)11.`>. 3409 3411 3413 3415 3417 3419 -- — — — -- _—_ — — --- — — -^— _______ • •^•^•^•• •^•^• UNIT: SANDSTONE (1.5 m). Med-coarse grained, light - dark grey, occasional cross-bedding, interiaminated stialey stringers, contact with overlying shale marked by sst with angular carbonaceous fragments. ^MAST1331-1^- ^- Samples:^ . MASH1331-6 (3409.41 m)^ .^.,.. MASH1331-7 (3412.01 m) .^ , MASH1331-8 (3414.73 m) -- MASH1331-9 (3416.51 m) MAST1331-1 (3416.61 m) MAST1331-2 (3418.11 m)^III^•^_■ ^_ .^.^.^. .^.^. . ......... .^.^.^.^. 311 Well #: D-075-E 094 -N -08^Formation. Mattson ^Date:  Sheet #:  Core # 13 Name: 10E DUNEDIN 3488.48 m - 3496.48 m Core Interval .^Logged By:^ o 15 Texture Lrthology sorting 0 - 11^g' Sand22 Fractures Ia. ug 1 1' g S 7, a. Comments/Remarks CORE 13: 3488.48 m -349648 m UNIT SILTSTONE (2.8 m). Mechum-dark grey, occasional shale partings, slightly calcareous, fractured UNIT: SHALE (0.75 m). Black, bituminous, non-calcareous, fissile, vertical hairline fractures.  UNIT: SILTSTONE (6.0 m)^As above, with calcite-filled vertical fractures ,....^, Samples^ 1 MASH1331-10 (3491.1 m) ..^. MASST-3 (348961 m) MASST-4 (3494 48 m) 0 OPIr. ',-.^... Conglom. -a c-Am(Sci.(S ou_t 3488 3490 3492 3494 3496 - - - • --• — • -- • --t-- • '^V-- ^ .^. , ,••^:-_^• „ _^• N MASH1331-10 312 Well #:^D-075-E 094-N-08^Formation Mattson^Date:^Sheet # Core # 14 Name:^10E DUNEDIN Core Interval' 3568.18 m - 3577.88 m^Logged By: tg_ rl) 2 Texture Lithotogy Sorting •• rio_g ; t Fractures t, .. t^g 2 ^i^. r,- - Comments/Remarks CORE 14: 3568.18 m - 3577.88 m UNIT: SILTY-SHALE (9.7 rn). Medium-dark grey. shaley in parts, shale stringers, soft-sediment deformation, occasional vertical fractures with quartz cement, vertical hairline fractures. Samples: MASH1331-11 (3571.18 m)^.^t4 ::-,Y7 - MASH1331-12 (3573.43 m) MASH1331-13 (3576.81 m) MASST1331-5 (3568.38 m) MASST1331-6 (357643 m) --^• ^ •^. ..... Gongtorn Sand Ri 7.3 .-= i-5- w 2,0(o.( 0,,.> 3568 3570 3572 3574 3576 3578 _ _ — _ _^.^• Ns • NI^NI^IN ;^•^2^2^4^%^I^' ^MASST1331-5^ _^_ 313 Well #:^D-075-E 094-N-08^Formation' Besa River^Date:^Sheet #: Core # 15 Name:^10E DUNEDIN Core Interval: 3666.06 m - 3680.91 m^Logged By: Texture Lithology Sorting 3^ci. Ys'n„eL> Fractures) in,c E^fli F II..J^, ^ _..?o. Eco Comments/Remarks CORE 15: 3666.06 m - 3680.91 m UNIT SHALE (14.85 m). Carbonaceous, black, fissile to massive, slightly micromicaceous, pyritic, slickensides, rare scattered shell debris. Samples: BRS/C15-1331-1 (3667.56 m) BRS/C15-1331-2 (3669.43 m) BRS/C15-1331 -3 (3672.06 m) BRS/C15-1331-4 (3673.94 m) BRS/C15-1331-5 (3676.93 m) BRS/C15-1331-6 (3679.19 m) BRS/C15-1331-7 (3680.69 m) Pemi. Sample: BRS/C15-1331-8 (3667.94 m) Conglom. Sand _ -0- =Wm>^.a,“..,a_o u.,...)2,L, 3666 3668 3670 3672 3674 3676 3678 - — —__ _ _ - — f P..,...0 1.:!.;1v.,., ,Na.: zr. 3680 --- BRS/C15-1331-2 -- ■ ■ ■ III BRS/C15-1331-8^ WE^In 3682 314 Well #:^D-075-E 094-N-08^Formation. Besa River^Date:^Sheet #: Core # 16 10E DUNEDINName: Core Interval- 3751.51 m - 3753.61 m^Logged By: Texture Lithology Sorting t- 3 1-rn Fractures is, oi^'C.._ LII2 ! I I isi r'i — a. Comments/Remarks CORE 16 3751.51 m - 3753.61 m UNIT BESA RIVER^Shale, black, bituminous, non-calcareous, fissile ISOTHERM SAMPLES 5R1331-1 (3751 51 m) 8R1331-2 (3752 26 m) BR1331-3 (3753 01 m) TOC SAMPLES 11 samples taken every 20 cm Con8lam Sand >,,,,, 0 a_ 0 o 2 u_ >i.,. z_ -_ -0= a) n 3751.5 3753.5 I . _ 3867 3875 CORE 17: 3867.3 m - 3874.8 m UNIT: BESA RIVER. ISOTHERM SAMPLES BR1331-4 (3868.8 m) BR1331-5 (3869.55 m) BR1331-6 (3870.3 m) BR1331-7 (3871.05 m) BR1331-8 (3871.8 m) 8R1331-9 (3872 55 m) BR1331-10 (3873.3 m) BR1331-11 (3874.05 m) TOC SAMPLES 36 samples taken every 20 cm ,...,,, ^.At ‘ •^• 1 If ,_-_-_.• i^''' .^• .....^ ..^4 '''^Y:.^Ot Ar.'.:'i Aiir...2 . --^'' ‘v-.W. ,. .^.4 ^'4.. Ao: i 4 315 We ll #: A-009-F 094-P-03^Formation' Muskwa^Date:^Sheet #: Name: WEST NAT KOTCHO^Core Interval: 2010.9 m - 2022.7^Logged By: 2 Texture l-ithologY Sorting '. 3 UM . .^c Fractures . .is E^.. T1'^g a  E 1^, g E. E 5 o Comments/Remarks UNIT: MUDSTONE: (5.5 m). Black, massive, discrete pyrite concentrations, increasingly calcareous towards base. 1111 Cot19 10fil. Sand .t2 orr)t.i. > corps.° L)Zu_> 2011 ^-.11:4 ^....1 •-ii • a •-.-^• •Wri,„.^i Aii'Vrit? - = 2017 2018 . UNIT: SHALE (1.5 m). Med grey, fissile, calcareous ISOTHERM SAMPLES: MU714-1 (2010.9 m) MU714-2 (2012.4 m) MU714-3 (2013.9 m) 316 Well #:^C-028-D 094-0-01^Formation* Muskwa (Ft Simpson ?)^Date:^Sheet ^̂ * Name: PAN AM ET ALA-1 SNAKE RIVER^Core Interval'^1937.9 m - 1941.81 m^Logged By: co4,. .2 al Texture Lithology Sorting TD^g tg og_ >" —"a•tf-F6'1 Fractures ^ . ^g ^: ^ § gE, 5 i^. 2 1 V, ii° Comments/Remarks UNIT: SHALE. Black, fissile-massive, non-calacareous, pyritic Shale - Black, massive, calcareous ISOTHERM SAMPLES: MU414-1 (1937.9 m) MU414-2 (1938.65 m) MU414-3 (1939.4 m) MU414-4 (1940.9 m) TOC SAMPLES 17 samples taken every 20 cm Conglom. Sand ,,. fi = 1:1._ = (02..^cmcoo_c0 u_oiL> 1937 1942 L 317 Fort SODSon 0448, 031) 147^Z-Z, _ Shake: medium grey, non- calcareous, fissile. siderite bands, finely laminated -̂ - -A' — ;^. . -: -- - ,r, , ,...._ kW. h.....,...__̂ g.. .:=4.. ,^_ ,^' ffs.,Pwrrommimmumummummomp111111111-=11 killtr11111IF Fen, SimOSOn .^.,-.. tall MI cotpthtm)14852 -...---,..... ...F: -=a medium grey, non- Scahlac iaereo'^us, fissile, siderite finely laminated ‘ -,... ,-,:ry,II1111 1/111 1111 [II Muskwa DOI, tm1153a2^.^_, --- I S^, non-hate: black, fissile^ i' Ca icareous, interbects of . pyrite laminations, finely laminated throughout ..=--^- -- ---'^' II Pli wiltprii_aw LTIMSKWA img Min.•.,-^• 1554.4 645 eill GR GAPI ^ Slave Point ISOTHERM SAMPLES:^Muskwa^TOC SAMPLES: MU1416-1 (1539.24 m) Ft Simpson^MU1416-2 (1541.3 m)^Fort Simpson: 13 samples taken every 40 FSS1416-1 (1475.95 m)^MU1416-3 (1542.6 m)^cm FSS1416-2 (1485.6 m)^MU1416-4 (1545.6 m) FSS1416-3 (1486.4 m)^MU1416-5 (1547.2 m)^Muskwa: 45 samples taken every 40 cm FSS1416-4 (1487.2 m)^MU1416-6 (1550 m) FSS1416-5 (1488 m) MU1416-7 (1551.2 m) MU1416-8 (1553.68 m) MU1416-9 (1555 m) 318 LithologyTexture 1951 Samples :4'13^Gong loin.^Sand a 132 :-_,' ra ^ > . ^a.0._(.9 o 2 L.,.. > a) 2 Sorting^Fractures xx E E - "0 "2" Comments/Remarks UNIT: SHALE (0.1 m). Black, very siliceous, UNIT: LIMESTONE (0.35 m). Medium-light grey, macrocrystalline, argillaceous with shale partings, mm - cm scale. UNIT: SHALE (2.7 m). Dark grey, siliceous with trace pyrite, hairline vertical fractures, few thin limestone interbeds. UNIT: LIMESTONE (3.6 m). Medium-light grey, macrocrystalline, argillaceous, poorly preserved fossils, sulfur odor in fresh fractures, fractures with calcite filling, bedding deformation. MU1745-1 (1949.37 m) MU1745-2 (1951.63 m) MU1745-3 (1950.12 m) MU1745-4 (1952.67 m) 1952 1953 1954 1947 1948 1949 1950 Well #: 200-1)-088-H 094-J-14^Formation' Muskwa ^Date:^ Name: FRONTIER ET AL EVIE^ Core Interval' 1947.37 m - 1953.94 m ^Logged By: ^ Sheet # Core #11 . 319 D-082-L 094-J-02Well #^ Formation' Ft Simpson^Date:^Sheet #* Name' AL TAIR ET AL TENAKA^Core Interval' 3 cored intervals^Logged By: 112 V 2 Texture i. Lithology Sorting .g a = a06-6-to._> Fractures co.j.•1 6^..^P2^2co^-^4,^I^.6  - 8 2Z o,I .: -F Comments/Remarks CORE 1: 1818.2 m - 1819.3 m UNIT: FORT SIMPSON SHALE. Med grey, fissile-massive, calcareous in part, ISOTHERM SAMPLES FSS26-1 (1818.25 m) TOC SAMPLES 5 samples taken at 25 cm intervals COnglOM. Sand >,ti =a •- =rn2 >^c mL9o_o u.c.)2u_> 1818 1819 --,,, :--:-:-.-1-_--_-_- --_ .-_-_ _ _ 1920 1922 CORE 2: 1920 m - 1921.5 m UNIT: FORT SIMPSON SHALE. ISOTHERM SAMPLES FSS26-2 (1920 m) TOC SAMPLES 3 samples taken from section 2188.5 2191.5 CORE 3: 2188.8 m - 2191.5 m UNIT: FORT SIMPSON SHALE. ISOTHERM SAMPLES FSS26-3 (2188.8 m) F5526-4 (2190.3 m) TOC SAMPLES 12 samples taken at 25 cm intervals • --.7:-77 -:: :-.:-.7-: - =-:--=-=-:: 7- -- C-=-=-=-: :_ c---.7-.=-: I _i 320 Well #: C-082-F 094-P-02Ft SimpsonFormation'^ Date:^Sheet #: Name'^DEVON ARL HELMET^Core Interval: 1430 m - 1439.4 m^Logged By: 2- 6 Texture Lithology Sorting I^i lEg_ I _ Fractures .^_ E^1 '..ma d  5 2 E Comments/Remarks UNIT. FORT SIMPSON SHALE. Med grey, fissile, calcareous in part, calcareous bands appear whiter in core section ISOTHERM SAMPLES FSS1214O-1 (1430 m) FSS12140-2 (1431.5 m) FSS12140-3 (1433 m) FSS12140-4 (1434.5 m) FSS12140-5 (1436 m) FSS12140-6 (1437.5 m) TOC SAMPLES 18 samples taken throughout cored section ^ .-^.—^.. .'•^.^4, :"' :^• . '^''''• ...4a^'^.. w.^'' .^•', _ ...^. • 5.'^: Conglorn. Sand Z -*'i, rcocci_c c)2L,">" 1430 1440 ----- _____- 321 Well #: B-092-D 0944.-04Ft SimpsonFormation .^Date:^Sheet #. Name: IMPERIAL SIKANNI CHIEF^Core Interval: 5 core intervals^Logged By: 0,.1•0 Iii2 Texture Lithology Sorting t no87; Fractures` ^ L.+1;^'^f„ e g^i ! i i 8 g -F., -6 a. Comments/Remarks Cores 13 -15: Ft Simpson Shale. Med grey, massive in parts, generally fissile. 13 and 14 are non calcareous_ Core 15 increasingly calcareous towards base. CORE 13 1939.4 m - 1945.5 m Conglom. Sand ,-,0zrz =a- (7)&ccicSo,L.S u2ii., 1939.5 1949.5 _ ___ ISOTHERM SAMPLES:^ s.x .-,--,t,,,x ,..Ara- ..^..„„.^• F55126-1 (1939.4 m)^0.0r.:,.'71 Mic.i....%., • FSS126-2 (1940.99 m) FSS126-3 (1942.49 m)^Oa. FSS126-4 (1943.9 m) -. TOC SAMPLES^ ..^ ' ._ ... -^•^.^, 12 samples _ __ -_77^ _ 1 _ 2091 2097 ----- CORE 14 2090.9 m - 2096.25 m III _ _ _ _ – ISOTHERM SAMPLES: FSS126-5 (2090.9 m) FSS126-6 (2092.49 m) FSS126-7 (2093.99 m) FSS126-8 (2095.4 m) TOC SAMPLES 12 samples 2.-...7._ — 111 2203 2209 CORE 15 2203 m - 2209.1 mI 1111111111 ISOTHERM SAMPLES: FSS126-9 (2203 m) FSS126-10 (2204.5 m) FSS126-11 (2206 m) FSS126-12 (2207.5 m) TOC SAMPLES 12 samples  11 11 2320.5 2320.6 23 26.7 m. Marty shale, dense, calcareouss: SAM PLES: FSS126-13 (2320.6 m) FSS126-14 (2322.1 m) FSS126-15 (2323.6 m) FSS126-16 (2325.1 m) I 2326 5 TOC SAMPLES 12 sam. es 2366 CORE 17 2366 m - 2371 m. Limestone, med grey. Silty, argillaceous, ..... dense, blocky ,.,^, if mm 177.4:11:1:1 2372 322 .Well #:^A-049-B 094-H-16^Formation Ft Simpson^Date:^Sheet #: i^t^ry^lre n e va sName : BRC HTR ETAL RING^Core Interval: 4 co Logged By: Texture Litho1017Y Sorting t^q 3^*°- I -g:sig: Fractures iLi g rE vt'3'^m . i2m S .2 t 2=P;...st_ Comments/Remarks All cores Ft Simpson shale CORE 16 1899.39 m - 1904.85 m^ - ISOTHERM SAMPLES:^ , FSS129-1 (189939 m) i.j.r^.. ,-1' FSS129-2 (1900.89 m) FSS129-3 (1902.39 m) FSS129-4 (1903.89 m) -f TOC SAMPLES-7.'1 12 samples^ -...-w^ , Ale^.x -"tfOli,,^• .•". "-tv'*.41-^. • tfi^Conglom. Sand T I-,' :1 C - = an d a s^=coi_on_i.0 i.,.c.)2i,_> 1899.5 --_--- 4905.5 _-_-___ , 2003.5 2009.5 CORE 17 2003.3 m - 2009.4 m 7.7..7.-I--: ISOTHERM SAMPLES: FSS129-5 (2003.3 m) FSS129-6 (2004.8 m) FSS129-7 (2006.3 m) FSS129-8 (2007.8 m) TOC SAMPLES 12 samples ,,,,, -- -. 2142 CORE 18 2142.1 m -2148.2 m ISOTHERM SAMPLES: FSS129-9 (2142.1 m) FSS129-10 (2143.6 m) FSS129-11 (2145.1 m) FSS129-12 (2146.6 m) TOC SAMPLES 12 samples2150 2254.5 CORE 19 2254.8 m -2260.9 m ISOTHERM SAMPLES:^ •^ . - , FSS129-13 (2254.8 m)  ^FSS129-14 (2256.3 m)^ ,. FSS129-15 (2257.8 m) ^. FSS129-16 (2259.3 m) -,..-----, _-_"--- TOC SAMPLES 12 samples AleFT•! ^ ••^-,^.,. 6.' -di,,-^•^ro". 2262 323 We ll #: 8-090-G 094-J-14^Formation^Fort Simpson^Date:^Sheet #• Name: GULF STATES EVIE LAKE^Core Interval'^1896.97 m -1905.97 m^Logged By: in2 rl ) Texture Lithology Sorting 77;^'g 3^. . - = 7, Q  a, t§E.3' Fractures •,, 6^. c :T: g^-t-,^4, .^i co .9 , g a' 2 2° - .  2 2 Comments/Remarks UNIT: SHALE: dark grey-black, fissile, non-calcareous, scattered pyrite ISOTHERM SAMPLES: FSS143-1 (1896.97 m) FSS143-2 (1897.72 m) FSS143-3 (1898.47 m) FSS143-4 (1899.22 m) FSS143-5 (1899.97 m) FSS 143-6 (1900.72 m) FSS143-7 (1901.47 m) FSS143-8 (1902.22 m) FSS 143-9 (1902.97 m) FSS 143-10 (1903.72 m) FSS 143-11 (1904.47 m) FSS 143-12 (1905.22 m) TOC SAMPLES: 30 samples collected every 20 cm (starting at 1896.97 m) Conglom. Sand oi r. ,_ — u7) im (..)i a_ (9 um LL L'>-• 1897 1898 1899 1900 1901 1902 1903 1904 1905 1906 _____ I- - 7.-1-17.—: ft7-7. :7.:- -_—.1—=-2- -..-_--------,-____, .=7.=Z—:. _ _ __ 324 Well #:^B-086-L 094-1-16^Formation' Muskwa^Date:^Sheet #: Name*^ESSO NFA WALRUS^Core Interval . 1761.4 m - 1763.9^Logged By: _ 2 Texture^Lithology Sorting 8 3^a 1M Fractures ! ^.? -=^i 1 - I ,^; E i i g a E - f^Comments/Remarks  ^UNIT: SHALE. Medium grey, non-calcareous, fissile ISOTHERM SAMPLES: MS947-1 (1761.4 m) M5947-2 (1762.15 m) MS 947-3 (1762.9 m) MS947-4 (1763.65 m) TOC SAMPLES: 20 samples collected at 20 cm intervals (starting at 1761.4 m) .....:. qt..... ,.;,,;. .,,^. ConglOni. Sand co -8-z T, J3 at .(..c,_( 02,,;- 1761.5 1762.5 1763.5 1764.5 1_ _ [1 I 1101.11wil IIIIIIIIIIII ii I. I I 325 Well #:^O-060-E 094+11^Formation'^Ft Simpson^Date:^Sheet #• Name:^10E JUNIOR Core Interval'^1857.1 m - 1881 m^Logged By:^G. Chalmers ,(313 Texture Lithology Sorting ^= ^o 0 0 - "g ^ t,' 2 0_ > Fractures % ^.. it^E^.-- 2 _.^^ Comments/Remarks UNIT: FORT SIMPSON SHALE: dark grey, fissile, non-calcareous ISOTHERM SAMPLES: MS1238-1 (1857.11 m) MS1238-2 (1858.63 m) MS1238-3 (1860.17 m) MS1238-4 (1861.7 m) MS1238-5 (186323 m) MS 1238-6 (1864.77 m) MS 1238-7 (1866.3 m) MS1238-9 (1869.37 m) MS1238-10 (1872.4 m) MS1238-11 (1873.93 m) Conglom.^Sand   --•..6 ,_.^c^u_ — = mon_c9 c)2LL> to 1857 IIIIII 1881 UNIT FORT SIMPSON SHALE: Dark grey - black, fissile, non- calcareous ISOTHERM SAMPLES MS1238-12 (1875.47 m) MS1238-13 (1877 m) MS1238-14 (1877.77 m) MS1238-15 (1878.53 m) MS1238-16 (1879.3 m) MS1238-17 (1880.07 m) MS1238-18 (1879.7 m) _ 326 ■„<^ki-^mi-} -I^4.^5. ê, , ell Nem<^-Fi RRA CT AI^1 TOGO I, 03 I ..1. ffi Localion^2047 , d-071-F 09.1- P-flt 00 Red Knife Depth (m)^Shale: medium grey, marly;.•- --.. 1011^—^texture non-calcaroeus Base of shale marked by^ tV^, ":...... ...,,,^argillaceous limestone, , ,; soft-sediment deformation • «gqii"1/.1 37...=. Limestone: white-light ggrreeyy,camticaerbredeouds sedhlieh , med marty^ •••,. .... .__ ĝrey, ^ -A.-. Shale medium gre ^■•••• - ,...-- Limestone: white-light grey, interbedded with med .... ^grey calcareous shale, bioturbated, mottled 1019 \,__ OR (60)1_ 4,54 ,r.^DT ,,,th^t,,, fist tu3 I^3.004,:ALKL____________FI -105 q-^1 0 `" 100 91' RFIAii ..,I., ''''''' ---7-- -17-;-__- -T  — jEF(XI 44 ' .•• .••^■ ,. ^t III 2. 1111 - .... A......:_._ - ••^ocimi .1....,-. ....-....ige Jean Marie - Ft Simpson DePth (m)^Jew 10904 1040.75 aijimniellasceotone us7ed grey-dark brown, bioclastic, slightly 044 5^...... . Ilrfm—gai' '1-1-11El -r.,-------- Limestone: light greymassive, very  fossiliferous, microcrystalline, trace ^ ....^sparite, vuggy porosity, 1048 5 ^ ,  Limestone dark grey,i ^4(49_2 ^.=,, -- .i-.• •A..”- Ini ^ . .it -iiEl 11150C I^ orl 5 tmpson • le: med-dark grey,^ Contact between Jean Made and fine^laminated, Ft Simpson IIIE SWIM 111111 160( — OR (C^PI^1 sp1^DT u., WI.^R-11°E1 (kw n■ -; I^111111 ISOTHERM SAMPLES: Red Knife RKS5245-1^1011.5 RKS5245-2 1015.25 TOC - 5 samples Ft Simpson FSS5245-1^1049.9 FSS5245-2 1054 FSS5245-3^1060 II^ -) I; I^r ____^.^" 1060 , _,,,,,._,_,.. .,,,,,,. ^..........,^,..,,.. TOC - 10 samples every 30 cm 327 Shale: dark grey- black, fissile, non-calcareous, pyritic, carbonaceous, partial replacement of carbonaceous fragments with pyrite Muskwa Depth (m) 1978 4 Shale: black, scattered yrite, blocky dense r.tt l_ I(^CR MPH^ton _REDKNIFEL345ft JEAN MARX 1440 II^____ 7RTISEAP6foLLI5SIL— ,0^ILD Lohrnref^on 1400 -e_•-- t=-- ;- .— _.. --T—will^ --1 „,,,,._.=_____ __f_ _ _ I 59a, T !elk 1700 1814( 19t)(1 MUSKWA VW 2 • iea..^•-^ "Li . _,. GR (GAIA)_LSO ILD (ohmm)^SO Filename - Getitlectiog Well Name CHEVRON KOTCHO C- 032-Kb94-I- L^r0 -0 -K/094-2- 4100 ISOTHERM SAMPLES: MS7194-1 1799 MS7194-2 1802.4 MS7194-3 1807.6 MS7194-4 1809.6 TOC SAMPLES: 42 samples taken every 40 cm 328 We ll #: B-098-B 094-P-08^Formation' Jean Marie & Ft Simspon^Date:^Sheet # HOME CABRE PEGGOName:^ Core Interval: 1018 m 1043 m^Logged By: 2 Texture Lithology^Sorting Z-^0 3^0 - lEg" Sand Fractures) § f„,^? !,^.-i 2 se E a Comments/Remarks CORE 1. 1018 m - 1028.4 m JEAN MARIE UNIT: LIMESTONE. Light grey, biodastic (brachs), vuggy porosity with partial calcite cementation. * UNIT: SHALE. Dark grey. Fissile, non-calcareous UNIT: LIMESTONE. As above conglom, ia Z :.-..' ii  -- (nM . co0cLO oMu.> -I 1018 Ell irgiraINE trigialg leVatIVAI — ^#^ .. ,TJ 4 41,^4.. ^N. ,,^.. ^_ J. *Jean Made limestone/shale contact Egitighrh".!i... . Ai . . .. IT ........... ..56 Doan .11101 55.:76.. ........ ...^.N........ V k^'4,4 Jean Made shale 1 ... .... 1028 Bioclasts in Jean Made with slight  vuggy porosity•••••••... 1511E-1 a .^...e.o.m.-^.,, I^7r7fir:..ett.-1 1,4 ..., I^ .i41.4:,,,,, Jean Marie-Ft Simpson contact IMIIIIVA: .4Fami vim • 1.T. 1.Ylithir ....ria UNIT: SHALE. FT SIMPSON. Light-med grey, fissile, increasingly calcareous upwards ISOTHERM SAMPLES: l•^'^-^'''.....^. i Jean Marie JM8288-1 (1019.9 m) JM8288-2 (1020.65 m) Ft Simpson^ -.. F558288-1 (1035.9 m)^ .. FSS8288-2 (1036.65 m) - FSS8288-3 (1037.4 m) FSS8288-4 (1038.15 m) Ft Simpson shale 1035 329 We ll^C-028-D 094-P-02 ^Formation' Ft Simpson Date:  Sheet # : Name. ECAOG DYNAMIC TOOGA Core Interval: 1426.6 m - 1436.8 m Logged By t=") T> Texture Lithology -.:-.. :6- Sorting To .3 8 ,,'2 c_ > _ , Fractures E T,0,^45=^'='^= 3 n. Comments/Remarks UNIT: FORT SIMPSON SHALE. Med grey, fissile-massive, calcareous in part, calcareous bands appear whiter in core section ISOTHERM SAMPLES FSS13703-1 (1426.6 m) FSS13703-2 (1428.1 m) FSS13703-3 (1429.6 m) FSS13703-4 (1431.1 m) FSS13703-5 (1432.6 m) FSS13703-6 (1434.1 m) FSS13703-7 (1435.6 m) TOC SAMPLES 20 samples taken throughout cored section ^ \ ''.:;.^•^..i,l. • • v.ii. ....e, .^•,....^;.: • .4...51h, ...!41^• ..w.4^Va^•• -.will^•^411"nAlP "L •+401•1111111 3:' ._, --...+''''^,^•^":^.'''■-i_.-_:.,^- ..:-, ,s4 r,'"--4- • :40....* Ft Simpson varies between med-dark grey fissile and • massive shale I Conglom. Sand gi "-al ' ^. co2 Smoo_o U—0M,> 1426.6 --- --: .7_:::- -1:- "..-2.- .7, 1436.6 330 Well #:^B-055-E 094-0-13^Formation' Fantasque^Date:^Sheet #: Core #11 Name: IMPERIAL PAN AM LA BICHECore Interval: 2075.45 m - 2080.91 m^Logged By: w2 Texture I-00400Y = a Sorting to-^'g I g 'cg Fractures c =^,T,^g coI .m, g ioa E Comments/Remarks CORE 11: 2075.45 m - 2080.91 m UNIT: SILICA MUDSTONEJCHERT (5.46 m). Black, dense, hard, massive, tight, numerous smooth vertical fractures, slickensided fractures w