UBC Theses and Dissertations

UBC Theses Logo

UBC Theses and Dissertations

The effect of shale composition on the gas sorption potential of organic-rich mudrocks in the Western… Ramos, Sharleen 2004

Your browser doesn't seem to have a PDF viewer, please download the PDF to view this item.

Item Metadata

Download

Media
831-ubc_2004-0287.pdf [ 19.75MB ]
Metadata
JSON: 831-1.0052557.json
JSON-LD: 831-1.0052557-ld.json
RDF/XML (Pretty): 831-1.0052557-rdf.xml
RDF/JSON: 831-1.0052557-rdf.json
Turtle: 831-1.0052557-turtle.txt
N-Triples: 831-1.0052557-rdf-ntriples.txt
Original Record: 831-1.0052557-source.json
Full Text
831-1.0052557-fulltext.txt
Citation
831-1.0052557.ris

Full Text

THE EFFECT OF SHALE COMPOSITION O N THE GAS SORPTION POTENTIAL OF ORGANIC-RICH MUDROCKS IN THE WESTERN C A N A D I A N SEDIMENTARY BASIN By SHARLEEN RAMOS B.Sc. (Hons), The University of British Columbia, 2000 A THESIS SUBMITTED IN PARTIAL FILFILLMENT OF THE REQUIREMENTS FOR THE DEGREE OF MASTER OF SCIENCE in T H E FACULTY OF G R A D U A T E STUDIES Department of Earth and Ocean Sciences We accept this thesis as conforming to the required standard T H E UNIVERSITY OF BRITISH COLUMBIA February 2004 © Sharleen Ramos, 2004 Library Authorization In presenting this thesis in partial fulfillment of the requirements for an advanced degree at the University of British Columbia, I agree that the Library shall make it freely available for reference and study. I further agree that permission for extensive copying of this thesis for scholarly purposes may be granted by the head of my department or by his or her representatives. It is understood that copying or publication of this thesis for financial gain shall not be allowed without my written permission. tie of Thesis: 77/^ F.FfecT oF £«*LbT ComPo^iTiod <W Qf/oz/2oo¥ Name of Author (please print) Date (dd/mm/yyyy) Degree: b/]A^TTfl OF ZC(€h/Ctr Year: &QQLJ-Department of fftjZTH ftND QCcAflJ -$C/€7llC£S> The University of British Columbia Vancouver, BC Canada ABSTRACT The gas sorption capacity of six organic-rich mudstones found throughout the Phanerozoic in the Western Canadian Sedimentary Basin has been measured through 66 high-pressure methane sorption isotherms at 30°C. The shales vary in total organic carbon and maturity (Tmax). Variations of gas sorption potential with shale composition, organic matter abundance, kerogen types, composition, geochemistry, and maturity have been investigated. For the combined data set, the amount of total organic carbon is strongly related to methane sorption capacity (r2 = 0.78). Organic-rich shales show better correlation between total organic carbon and methane sorption capacity and higher sorption capacities than organic-lean shales. Low-TOC shales are influenced by mineralogical differences (more clay for sorption) and pore/moisture/maturity relationships. Gas sorption capacity increases with maturation because there is decreased competition of organic (eg. vitrinite) and rnineral matter (eg. clays) sites for sorption from moisture because of reduced moisture contents with depth. Increased microporosity of the organic matter is also associated with higher maturity shales as seen by the flattening of the isotherm curve. Methane sorption capacity and TOC abundance varies with organic matter type, nature, HI, kerogen isotopic composition and depositional environment. Difficulties exist when attempting to determine if methane sorption capacity varies with organic matter ii composition. However, it is noted that isolating samples of similar TOC and maturity, samples with more vitrinite (Type III) have more sorption capacity. The shales sampled in this study vary in inorganic and organic compositions, organic matter abundances, kerogen types, maturity, porosity, and permeability, which vary vertically and laterally throughout a shale sequence. Therefore, the spatial variability of these variables should be considered in exploration programs for natural gas from shale strata. Future work on gas shale targets includes detailed sequence stratigraphy, paleoenvironmental analysis, and structural analysis. Core, well log signatures (eg. gamma ray, density, sonic and resistivity), and sorption data can be correlated with total organic carbon and compositional variations (using mineralogy and kerogen isotopes) to identify varying composition and gas potential throughout a target. Kerogen can be isolated to measure differences in sorption of varying organic matter compositions. The porosity available to methane (free gas porosity) and pore structures also should be researched. iii TABLE OF CONTENTS ABSTRACT i i TABLE OF CONTENTS iv LIST OF TABLES ix LIST OF FIGURES xii ACKNOWLEDGEMENTS xvi i i CHAPTER 1 - INTRODUCTORY STATEMENTS 1.1 INTRODUCTION .1 1.2 PRODUCTIVE SHALES 3 1.3 NATURAL GAS IN SHALE 3 1.4 GAS SHALE POTENTIAL .4 1.5 INTENT OF STUDY 5 1.6 STRUCTURE OF THESIS .5 1.7 REFERENCES CITED 7 CHAPTER 2- SHALE G E O L O G Y IN THE WESTERN C A N A D I A N SEDIMENTARY BASIN: SOURCE ROCK ENVIRONMENTS A N D SORPTION POTENTIAL 2.1 ABSTRACT 8 2.2 INTRODUCTION 9 2.3 B A C K G R O U N D 12 2.3.1 Shale in the Western Canadian Sedimentary Basin 12 2.3.2 Sample Collection ...14 iv 2.3.3 Methods 15 2.4 RESULTS 17 2.4.1 Upper Devonian Duvernay Formation 17 2.4.1.1 Geological Setting and Stratigraphic Framework 17 2.4.1.2 Sample Distribution 19 2.4.1.3 Source Rock Characterization 21 2.4.1.4 Methane Sorption and Total Organic Carbon 25 2.4.1.5 Methane Sorption and Maturity 25 2.4.1.6 Metliane Sorption and Mineral Abundance 27 2.4.2 Late Devonian - Mississippian Exshaw Formation 27 2.4.2.1 Geological Setting and Stratigraphic Framework 27 2.4.2.2 Sample Distribution 30 2.4.2.3 Source Rock Characterization .30 2.4.2.4 Methane Sorption and Total Organic Carbon 34 2.4.2.5 Methane Sorption and Maturity 34 2.4.2.6 Methane Sorption and Mineral Abundance .34 2.4.3 Lower Jurassic "Nordegg" Member 36 2.4.3.1 Geological Setting and Stratigraphic Framework 36 2.4.3.2 Sample Distribution 38 2.4.3.3 Source Rock Characterization 41 2.4.3.4 Methane Sorption and Total Organic Carbon .43 2.4.3.5 Methane Sorption and Maturity 45 2.4.3.6 Methane Sorption and Mineral Abundance_ 45 2.4.4 Lower Cretaceous Colorado Group 46 2.4.4.1 Geological Setting and Stratigraphic Framework 46 2.4.4.2 Sample Distribution .48 2.4.4.3 Late Cenomanian to Middle Turonian Second White Specks Formation 49 2.4.4.4 Source Rock Characterization .51 2.4.4.5 Methane Sorption and Total Organic Carbon .53 2.4.4.6 Methane Sorption and Maturity 55 2.4.4.7 Methane Sorption and Mineral Abundance 55 2.4.4.8 Middle to Late Cenomanian Belle Fourche Formation 56 2.4.4.9 Source Rock Characterization 58 v 2.4.4.10 Methane Sorption and Total Organic Carbon 60 2.4.4.11 Methane Sorption and Maturity 60 2.4.4.12 Methane Sorption and Mineral Abundance •_ 62 2.5 COMPARISON OF SORPTION RESULTS 62 2.5.1 Total Organic Carbon 62 2.5.2 Maturation (Tmax) 63 2.5.3 Mineralogy. 65 2.6 DISCUSSION/IMPLICATIONS 67 2.7 CONCLUSION 7 1 2.8 REFERENCES 7 3 CHAPTER 3 - ORGANIC MATTER DESCRIPTIONS OF SELECTED SHALE FORMATIONS: COMPARISON OF ORGANIC MATTER COMPOSITIONS, ABUNDANCE, MATURITY, A N D SOURCING 3.1 ABSTRACT 7 9 3.2 INTRODUCTION 80 3.3 METHODS 8 3 3.3.1 Sample Collection 83 3.3.2 CNS Analysis 84 3.3.3 Petrographic Examination 85 3.3.4 Maturity (Tmax) 85 3.3.5 Organic Carbon Isotopes 85 3.3.6 X-Ray Diffraction 86 3.3.7 Sorption Isotherms 86 3.4 RESULTS 87 vi 3.4.1 Background P/ 3.4.2.2 Western Canadian Sedimentary Basin Samples .87 3.4.2.2 Classification ofMacerals in Source Rocks 87 3.4.2.3 Geochemical Parameters; ; 91 3.4.1.4 Organic Fades 91 3.4.2.5 Presentation of Data 94 3.4.2 Upper Devonian Duvernay Formation 94 3.4.2.2 Previous Work 96 3.4.2.2 Geochemistry 96 3.4.2.3 Organic Petrology. 98 3.4.2.4 Nature of Organic Matter .100 3.4.2.5 Organic matter and Sorption Capacity. 102 3.4.3 Upper Devonian - Lower Carboniferous Exshaw Formation 102 3.4.3.2 Previous Work .103 3.4.3.2 Geochemistry 103 3.4.3.3 Organic Petrology. .105 3.4.3.4 Nature of Organic Matter 107 3.4.3.5 Organic matter and Sorption Capacity 107 3.4.4 Lower Jurassic "Nordegg" Member 109 3.4.4.2 Previous Work 109 3.4.4.2 Geochemistry HO 3.4.4.3 Organic Petrology. 112 3.4.4.4 Nature of Organic Matter .115 3.4.4.5 Organic matter and Sorption capacity. 119 3.4.5 Lower Cretaceous Colorado Group 119 3.4.4.2 Previous Work 120 3.4.4.2 Second White Specks Formation 121 3.4.4.2.1 Geochemistry 121 3.4.4.2.2 Organic Petrology 121 3.4.4.2.3 Nature of Organic Matter 123 3.4.4.2.3 Organic Matter and Sorption Capacity 127 3.4.4.3 Belle Fourche Formation 127 3.4.4.3.1 Geochemistry .127 3.4.4.3.2 Organic Petrography 129 3.4.4.3.3 Nature of Organic Matter 131 3.4.4.3.4 Organic Matter and Sorption Capacity. 133 vii 3.6 DISCUSSION 133 3.6.1 Comparison of Shale Geochemical Properties 133 3.6.1.1 Organic Matter Deposition 135 3.6.1.2 Organic Matter Composition 138 3.6.1.3 Organic Fades and Source Potential 139 3.6.2 Comparison of Gas Potential 140 3.6.2.1 TOC Abundance and Methane Adsorption 140 3.6.2.2 Sorption Capacity and Organic Matter Composition 141 3.7 CONCLUSION 150 3.8 REFERENCES CITED 154 CHAPTER - 4. CONCLUSIONS 162 4.1 T H E EFFECTS UPON GAS SORPTION CAPACITY OF SHALE IN T H E WESTERN C A N A D I A N SEDIMENTARY BASIN 162 4.2 FUTURE WORK 164 4.3 REFERENCES CITED 166 APPENDIX A: GEOCHEMICAL D A T A 167 APPENDIX B: ORGANIC PETROLOGY D A T A 173 APPENDIX C: SORPTION D A T A 188 L I S T O F T A B L E S Table 2.1 Location, depth, organic carbon (TOC), Rock-Eval Pyrolysis parameters, geochemistry, moisture and ash data of samples from the Duvernay Formation, Western Canadian Sedimentary Basin. The samples are shown with increasing TOC within a maturity range _ 22 Table 2.2 Bulk Mineralogy for Duvernay Formation samples, as determined by X-Ray diffraction peak intensity analysis 22 Table 2.3 Calculated correlation coefficient values between chosen data shown in Table 2.1 and Table 2.2 26 Table 2.4 Location, depth, organic carbon (TOC), Rock-Eval Pyrolysis parameters, geochemistry, moisture and ash data of samples from the Exshaw Formation, Western Canadian Sedimentary Basin. The samples are shown with increasing TOC within a maturity range 31 Table 2.5 Bulk Mineralogy for Exshaw Formation samples, as determined by X-Ray diffraction peak intensity analysis 31 Table 2.6 Calculated correlation coefficient values between chosen data shown in Table 2.1 and Table 2.2 ; 35 Table 2.7 Location, depth, organic carbon (TOC), Rock-Eval Pyrolysis parameters, geochemistry, moisture and ash data of samples from the "Nordegg" Member, Western Canadian Sedimentary Basin. The samples are shown with increasing TOC within a maturity range 39 Table 2.8 Bulk Mineralogy for "Nordegg" Member samples, as determined by X-Ray diffraction peak intensity analysis 40 Table 2.9 Calculated correlation coefficient values between chosen data shown in Table 2.7 and Table 2.8 44 Table 2.10 Location, depth, organic carbon (TOC), Rock-Eval Pyrolysis parameters, geochemistry, moisture and ash data of samples from the Second White Specks Formation, Western Canadian Sedimentary Basin. The samples are shown with increasing TOC within a maturity range 50 Table 2.11 Bulk Mineralogy for Second White Specks Formation samples, as determined by X-Ray diffraction peak intensity analysis 50 Table 2.12 Calculated correlation coefficient values between chosen data shown in Table 2.10 and Table 2.11 54 ix Table 2.13 Location, depth, organic carbon (TOC), Rock-Eval Pyrolysis parameters, geochemistry, moisture and ash data of samples from the Belle Fourche Formation, Western Canadian Sedimentary Basin. The samples are shown with increasing TOC within a maturity range _ _ ; 57 Table 2.14 Bulk Mineralogy for Belle Fourche Formation samples, as determined by X-Ray diffraction peak intensity analysis 57 Table 2.15 Calculated correlation coefficient values between chosen data shown in Table 2.13 and Table 2.14 61 Table 3.1 Maceral classification for primary dispersed organic matter and bitumens (From Potter et al., 1998) 89 Table 3.2 Classification of coal macerals (After Potter et al., 1998) 90 Table 3.3 Comparison of nomenclature in the classification of unstructured organic matter (UOM) in immature or marginally mature oil source rocks (Taylor et al.,1998). 90 Table 3.4 Summary of gross chemical, pyrolysis (Rock-Eval), and microscopic criteria and characteristics of classical organic facies of Jones (1987). From Tyson (1995) 92 Table 3.5 Location, depth, organic carbon (TOC), Rock-Eval Pyrolysis parameters, geochemistry, moisture and ash data of samples from the Duvernay Formation, Western Canadian Sedimentary Basin. The samples are shown with increasing TOC within a maturity range 97 Table 3.6 Location, depth, organic carbon (TOC), Rock-Eval Pyrolysis parameters, geochemistry, moisture and ash data of samples from the Exshaw Formation, Western Canadian Sedimentary Basin. The samples are shown with increasing TOC within a maturity range 104 Table 3.7 Location, depth, organic carbon (TOC), Rock-Eval Pyrolysis parameters, geochemistry, moisture and ash data of samples from the "Nordegg" Formation, Western Canadian Sedimentary Basin. The samples are shown with increasing TOC within a maturity range I l l Table 3.8 Location, depth, organic carbon (TOC), Rock-Eval Pyrolysis parameters, geochemistry, moisture and ash data of samples from the Second White Specks Formation, Western Canadian Sedimentary Basin. The samples are shown with increasing TOC within a maturity range 122 Table 3.9 Location, depth, organic carbon (TOC), Rock-Eval Pyrolysis parameters, geochemistry, moisture and ash data of samples from the Belle Fourche Formation, Western Canadian Sedimentary Basin. The samples are shown with increasing TOC within a maturity range 128 x Table 3.10 Table summarizing physical and chemical properties of Western Canadian Basin Shale '. '. ". 1 3 4 LIST OF FIGURES Figure 2.1 a) The NW-SE trending Western Canadian Sedimentary Basin (between dark outline) that extends from the Northwest Territories to northern Manitoba (modified from Ricketts, 1989). West of the limit of Laramide deformation are five morphogeological belts. The study area is shown extending from the Peace River Area to southern Alberta; b) Schematic representation of stratigraphy in the Western Canadian Sedimentary Basin* (modified from Mossop and Shetsen, 1994). Each division is denoted with the dominant lithology to give an overall impression of deposition of the slice 13 Figure 2.2 Scatter plots showing TOC versus Tmax versus methane sorption capacity for: a) all samples; b) Duvernay samples; c) Exshaw samples; d) Nordegg samples; e) Belle Fourche samples; and f) Second White Specks samples 18 Figure 2.3 a) Late Devonian (part) stratigraphy in central plains of Alberta (from AGAT Laboratories, 1988). The stage boundaries are approximate; b) Location map of west-central Alberta showing the core locations of the Duvernay sample suite used in this study 20 Figure 2.4 Plot of weight percent organic carbon vs. weight percent total sulphur for Duvernay shales. The samples bellow the normal marine Une (slope = 0.4, zero intercept; Berner, 1984) 24 Figure 2.5 Plot of weight percent total nitrogen vs. weight percent of total organic carbon for Duvernay shales. The r 2 value is 0.78 mdicating a positive relation ship 24 Figure 2.6 High-Pressure methane adsorption isotherms for Duvernay shales of the Western Canadian Sedimentary Basin. In general, the adsorption capacity (as received) increases sorption TOC and maturation. Plot symbols increase in size with increasing maturation (Tmax) value 26 Figure 2.7 a) Subsurface and litho- and biostratigraphy of Alberta Devonian to Carboniferous strata (modified from Caplan and Bustin, 2001) established from previous studies such as Macqueen and Sandberg (1970), Richards and Higgins (1988), Richards (1989), Richards et al. (1991), Savoy (1992), Johnston and Meijer Drees (1993), and Meijer Drees and Johnston (1994); b) Location map of west-central Alberta showing the corelocations of the Exshaw sample suite used in this study 29 Figure 2.8 Plot of weight percent organic carbon vs. weight percent total sulphur for Exshaw shales. The samples bellow the normal marine line (slope = 0.4, zero intercept; Berner, 1984) 33 Figure 2.9 Plot of weight percent total nitrogen vs. weight percent of total organic carbon for Exshaw shales. The r2value is 0.75 indicating a positive relationship 33 xii Figure 2.10 High-Pressure methane adsorption isotherms for Exshaw shales of the Western Canadian Sedimentary Basin. In general, the adsorption capacity (as received) increases sorption TOC and maturation. Plot symbols increase in size with increasing maturation (Tmax) value 35 Figure 2.11 a) Stratigraphic chart Jurassic units from N.E. British Columbia to West Central Alberta (modified from Riediger et al., 1990); b) Location map of west-central Alberta showing the core locations of the "Nordegg" sample suite used in this study 37 Figure 2.12 Plot of weight percent organic carbon vs. weight percent total sulphur for Duvernay shales. The samples bellow the normal marine line (slope = 0.4, zero intercept; Berner, 1984) 42 Figure 2.13 Plot of weight percent total nitrogen vs. weight percent of total organic carbon for "Nordegg" shales. The r 2 value is 0.94 indicating a positive relation ship 42 Figure 2.14 High-Pressure methane adsorption isotherms for "Nordegg" shales of the Western Canadian Sedimentary Basin. In general, the adsorption capacity (as received) increases sorption TOC and maturation. Plot symbols increase in size with increasing maturation (Tmax) value 44 Figure 2.15 a) Regional Albian through middle Turonian stratigraphy for the central, southern, and northwestern plains of the Western Canadian Sedimentary Basin (after Bloch et al., 1993); b) Location map of west-central Alberta showing the core locations of the Colorado Group samples used in this study. Light grey: Belle Fourche Formation, Dark Grey: Second White Specks Formation ; 47 Figure 2.16 Plot of weight percent organic carbon vs. weight percent total sulphur for Second White Specks shales. Most samples plot above the normal marine line (slope = 0.4, zero intercept; Berner, 1984) ' 52 Figure 2.17 Plot of weight percent total nitrogen vs. weight percent of total organic carbon for Second White Specks shales 52 Figure 2.18 High-Pressure methane adsorption isotherms for Second White Specks shales of the Western Canadian Sedimentary Basin. In general, the adsorption capacity (as received) increases sorption TOC and maturation. Plot symbols increase in size with increasing maturation (Tmax) value 54 Figure 2.19 Plot of weight percent organic carbon vs. weight percent total sulphur for Belle Fourche shales. Most samples plot above the normal marine line (slope = 0.4, zero intercept; Berner, 1984) 59 Figure 2.20 Plot of weight percent total nitrogen vs. weight percent of total organic carbon for Belle Fourche shales 59 x i n Figure 2.21 High-Pressure methane adsorption isotherms for Belle Fourche shales of the Western Canadian Sedimentary Basin. In general, the adsorption capacity (as received) increases sorption TOC and maturation. Plot symbols increase in size with increasing maturation (Tmax) value 61 Figure 2.22 TOC versus methane sorption capacity for all shales. The size of the symbols increase with maturation 64 Figure 2.23 Tmax (°C) versus moisture content for all shales indicating a general trend of decreasing moisture with maturity. Variable moisture contents in each sample set are due to mineralogical differences 64 Figure 2.24 TOC + Ash + Moisture content for all samples. With increasing carbonate content, the x axis decreases in value, representing a loss of CaCOs during ashing 66 Figure 2.25 TOC + Ash + Moisture content for each shale 66 Figure 2.26 Ash content versus TOC content versus moisture content for all shales. In general, ash has an inverse relationship with TOC content (inherent). Some moisture is held in mineral matter (excluding carbonate) 68 Figure 2.27 Clay content versus moisture content for all shales. In general, moisture contents increase with the amount of clay 68 Figure 2.28 Clay versus TOC versus moisture content for all shales 69 Figure 2.29 Carbonate versus TOC versus moisture content for all shales 69 Figure 3.1 Pseudo van Krevelen diagram showing hydrogen and oxygen indices from Rock Eval pyrolysis and their evolutionary pathway from early diagenesis (right side of pathway) to metagenesis. Increasing burial is indicated by the direction of the arrows for each particular path. Kerogen types I, II, and III are defined by Espitalie et al., (1997). The samples for this study are plotted showing varying kerogen types, and maturities 92 Figure 3.2 HI versus Tmax diagram defining the Type of organic matter and maturation. For Type I there is a fast increase in Tmax at the 430 - 440°C range, and slower one for Type II (420 - 435°C range). Catagenesis is reflected by a decrease and disappearance of the HI. For Type III, the HI increases at low maturities and decreases around 440°C. This is due to a relative enrichment of aliphatic structures of the organic matter by the progressive elimination of oxygenated compounds (Espitalie et al., 1977). Catagenesis is characterized by a slow decrease in HI in the oil formation zone, at the same time a sharp rise in Tmax 93 Figure 3.3 Correlation of organic carbon and hydrogen index from <440°C shales where the TOC is approximately of the original value (Tissot and Welte, 1984). Organic fades are outlined using the values shown in Table 3.1 95 xiv Figure 3.4 Photomicrographs of dominant inorganic and kerogen components commonly found in the Duvernay shale. A l l photomicrographs were taken using reflected light and oil immersion objectives; a-e are taken under blue light. A) Amorphous dark brown bittiminite (b) occurring as lens-like streaks are dominant in this sample (DUV-53). Liptodetrinite (1) is sparse. B) Large well-preserved alginite is abundant in this sample (DUV-56), including a thick?-walled Tasmanites (t). Pyrite framboids (p) are found occurring within the walls of a thin alginite. Matrix bituminite (mb) is found associated with mineral matter (mm). C) Yellow fluorescing acritarch? (ac) showing spikey morphology. Matrix bituminite (dark brown) is intermixed with groundmass. D) This organic-rich (11.15 wt% TOC) sample contains more abundant liptinite, and liptodetrinite with wavy character. E) Matrix bituminite (mb) and mineral matter (mm) relationship. Thin alginite (a) is stringy. F) Same as E), but in reflected white light. Pyrite framboids (p) are common and fluoresce strongly 99 Figure 3.5 Organic matter plots for Duvernay samples within and below the oil window: a) TOC versus Hydrogen Index (HI) b) TOC versus 8C 1 3 ; c) 8C 1 3 versus methane sorption capacity 101 Figure 3.6 Photomicrographs of dominant inorganic and kerogen components commonly found in the Exshaw shale. A l l photomicrographs were taken using reflected light and oil immersion objectives; a-c are taken under blue light. A) Pyrite framboids (p) within a bright yellow-reflecting Thin-walled Leiosphaeridia (1) alginite. B) The matrix of Exshaw samples consist of a matrix moderately abundant with fluoramorphinite or lamalginite (1). Concentrated thin-walled Leiosphaeridia (1) alginite is present. Tasmanites-like (T) alginite is showing pore canals, viewed parallel to bedding. C) Brightly fluorescing Tasmanites (T) alginite and Prasinophyte alginite embedded in this dark matrix. Faint thin yellow lamalginite present in matrix. D) Same as in C, in white light reflection. Dark-brown streaks are lamalginite. Matrix contains minute vitrinite, semifusinite, and inertinite particles, usually elongate to matrix. E) An immature Exshaw sample (compare to F). The matrix is dominantly quartz-rich and layer interbedded with lamalginite. Embedded in this image is an mertinite (i). F) Sample EX-36, overmature with respect to the oil window, show an equigranular texture, and small grains. Abundant pyrite and tiny maceral particles are dispersed 106 Figure 3.7 Exshaw organic matter plots within and below the oil window: a) TOC versus Hydrogen Index (HI); b) TOC versus SO 3 ; c) SC 1 3 versus Hydrogen Index; d) Hydrogen Index versus methane sorption capacity; e) 5C 1 3 versus methane sorption capacity 108 Figure 3.8 Photomicrographs of dominant inorganic and kerogen components commonly found in the "Nordegg" shale. A l l photomicrographs were taken using reflected light and oil immersion objectives; a and c are taken under blue light and others are in white light. A) Amorphous dark brown bituminite (b) occurring as lens-like streaks are dominant in this sample (NOR-1). Rare liptodetrinite wisps fluoresces weak yellow because this sample is mature. B) Abundant dispersed organic matter (22.49 wt% TOC) in this sample is in the form of particulate mertmite/semifusinites (i) that bright reflect, small elongate or broken vitrinite (v), that reflect grey. Pyrite (p) xv framboids are comrnon. Bituminite (b) is very dense in the sample, reflecting a dark brown. C) Abundant thin-walled alginite occurring as bedding parallel bands and thin wispy particles. Matrix bituminite fluoresces a yellow green. D) Calcite rhombs are common in some of the "Nordegg" shales, and exhibits a 'speckly' habit. E) An overmature, low TOC sample (NOR-45) containing sporadic particulate organic matter and pyrite framboids (p). The character pore structure is also smaller than immature samples reflecting burial 113 Figure 3.9 Photomicrographs of rare components identified in the "Nordegg" shale under reflected light and oil immersion objectives. A, E and F are taken under blue light excitation and B-D are under white light excitation. A) Black in colour cenosphere (c) with brown vacuoles (v) under blue light. Green-yellow matrix bituminite (mb) groundmass contains moderately abundant alginite (a) stringers in yellow. B) Image A under white light. The cenosphere reflects brightly and the vacuoles are black. Angular sernifusinite (s) particle present. C) Grey-reflecting granular solid bitumen? common in mature samples. D) Vitrinite (geopetal?) occurring within calcareous foraminifera. E) and F) show dark yellow oil globules 114 Figure 3.10 Nordegg organic matter plots within and below the oil window: a) TOC versus Hydrogen Index (HI); b) TOC versus SO 3 ; c) S O 3 versus Hydrogen Index; d) 5C 1 3 versus methane sorption capacity; e) Hydrogen Index versus methane sorption capacity 117-118 Figure 3.11 Photomicrographs of dominant inorganic and kerogen components commonly found in the Second White Specks shale. A l l photomicrographs were taken using reflected light and oil immersion objectives; c-e are taken under blue light. A) Granular dark brown matrix. The organic matter is termed Hebamorphinite (H) and occurs as concentrated and dispersed forms. Degraded and shard-like inertodetrinite (i) and degraded vitrinite (v) are dispersed throughout the matrix. B) Hebamorphinite (H) is concentrated as a thick band in this mineral matter (mm) dominated matrix. Small vitrinite (v) is either elongate or roundish particles. C) Prasinophyte? alginite and liptodetrinite. The green-brown matrix is the amorphous organic and mineral matter matrix. D) Thin-walled alginite and wispy liptodetrinite. E) A mature sample with alginite (coccoidal?) indistinct and with decreased fluorescence intensity. F) Mineralized foraminifera 124 Figure 3.12 Second White Specks organic matter plots within and below the oil window: a) TOC versus 5C 1 3; b) 5C 1 3 versus methane sorption capacity (cc/ g) 126 Figure 3.13 Photomicrographs of dominant inorganic and kerogen components commonly found in the Belle Fourche shale. A l l photomicrographs were taken using reflected light and oil immersion objectives; b and d are taken under blue light. A) Quartz-rich matrix with concentrated, elongate, dark brown bituminite (b) and vitrinite (v). Framboidal pyrite (p) is common. B) Alginite is minor and sparse throughout the matrix and are small and indistinct to classify. Bituminite (b) is non-fluorescing. C) Dispersed bitiiminite (b), matrix bituminite, vitrinite (v) and pyrites.(p) 130 xvi Figure 3.14 Belle Fourche organic matter plots for samples within and below the oil window: a) TOC versus 5C 1 3 ; b) SC 1 3 versus methane sorption capacity 132 Figure 3.15 Generalized cross-section from continent to ocean for two major sedimentation stages of the Western Canadian Sedimentary Basin (Modified from Brooks, 1987). a) The Mid-Jurassic to Paleocene foreland basin succession contains the Second White Specks and Belle Fourche Formation deposited where reduced oxygen conditions occur. Organic Facies are plotted and the shales are C and BC Organic Facies. b) The Devonian to Jurassic platform stage contains the Nordegg, Exshaw, and Duvernay shales deposited in a large marine anoxic basin. Organic Facies are A and B 136 Figure 3.16 TOC versus methane sorption capacity for samples with similar maturities. A table below shows predictive sorption capacities from a linear equation if the samples have 2 or more points in the plot. The r 2 value is show for each set and shale (if present) 142-143 Figure 3.17 420°C and <420°C shales: a) TOC versus 5C 1 3 versus methane sorption capacity; b) TOC versus 5C 1 3 versus moisture content 145 Figure 3.18 <430°C shales: a) TOC versus 5C 1 3 versus methane sorption capacity; b) TOC versus 5C 1 3 versus moisture content :. .146 Figure 3.19 440°C shales: a) TOC versus 5C 1 3 versus methane sorption capacity; b) TOC versus SC 1 3 versus moisture content 148 Figure 3.20 450°C, 460°C, and >460°C shales: a) TOC versus SC 1 3 versus methane sorption capacity; b) TOC versus SC 1 3 versus moisture content 149 xvii AWKNOWLEDGEMENTS Financial support was provided by the Canadian Society of Petroleum Geologists (Graduate Regional Scholarship - West), The Society of Organic Petrology (Student Research Grant), and the American Association of Petroleum Geologists (Gustavus E. Archie Memorial Grant). Firstly I would like to thank R. Marc Bustin for his constant guidance, input, and sense of humor, especially during the countless edits. I would also like to thank my committee members, Dr. Kurt Grimm and Dr. Stuart Sutherland for their time and being receptive to questions. To Maureen Soon, Kathy Gordon, Dr. Les Lavkulich, Laxmi Laxminarayana, Raphael Wust, Maristela Bagatin Silva, Mati Raudsepp, Elizabetha Pani, Bryon Cranston, Ray Rod way, and Mike St. Pierre, I appreciate you technical help. A special thanks to Dr. Cindy Riediger for being accommodating with advice and access to some Nordegg samples. I am grateful to the staff at Alberta Energy and Utilities Board for allowing me to make odd requests for one core and lots of sample. The process was eased by the Sedimentology research group and other grads with advice, reviews, and coffee breaks. The lab coffee wouldn't have tasted any better. I thank Erin Workman for her hard work and being just as excited when the shales pass with porosity. I would like to express my gratitude to my family, Mom, Dad, and Cheryl. Your support, patience, and love throughout the years are paramount. To Raymond, thank you for sharing another milestone with me. xviii CHAPTER 1 - INTRODUCTORY STATEMENTS 1.1 INTRODUCTION Development of gas shale reservoirs in the Western Canadian Sedimentary Basin is becoming essential to sustain an increasing North American energy demand. There has been a resurgence of exploration for unconventional reservoirs such as gas shales and coalbed methane, as the rate of conventional gas production has declined. This decline in natural gas production is set in an economic background of increased demand for electrical power generation. This increased demand for natural gas and improved production technology is seeing greater interest in gas shales as a visible economic resource. Gas shales are unconventional, continuous-type natural gas reservoirs where accumulations are volumetrically important and generally lack well-defined oil/water or gas/water contacts (no obvious structural control) (USGS, 1995). The gas is trapped in complex and tight reservoirs that require stimulation adjacent coarser strata, and/or and extensive fracture system for sufficient volumes of gas to move from the matrix to the well bore for production. Obtaining an economic production rate for gas shale is an exploration risk, due to low matrix permeabilities which are on the order of 0.1 to 10 pd (De Witt, 1986) and porosities generally less than 10%. 1 A complex interplay of geologic and economic factors affects the successful production of shale gas. Geologic factors affecting the recovery of shale gas are: thickness, continuity, geometry, and distribution; fracture permeability; maturity, shale composition; depth of burial; gas saturation; and reservoir pressure and hydrologic conditions to name but a few. A l l these factors are in turn dictated by sedimentary environment, depositional processes, basin evolution, and structure. Therefore source rock characteristics influence reservoir characteristics for shale. Controls of shale characteristics and composition (particularly the organic fraction) upon the retention of gas have only briefly been investigated. The hydrocarbon gas of organic-rich source rocks is retained in the shale as most of the gas is held in shales by adsorption. Organic matter and to a lesser extent clay (illite) has high surface area, providing sites for gas sorption. This thesis investigates, through the use of the volumetric method of measuring gas sorption isotherms, the gas sorption capacities of various shales. The effects of organic matter contents and mineralogy, kerogen type, and degree of maturation upon gas sorption capacities are determined. Further, geochemistry is coupled with petrology to assess the organic matter composition in detail to compare kerogen types, organic matter composition, and character. Effects of organic matter composition on sorption capacity will be evaluated. 2 1.2 PRODUCTIVE SHALES Natural gas has been continually supplied from Devonian shale in the United States ever since the first fractured gas shale reservoir, the Appalachian Basin Fredonia fractured shale was drilled in 1821. The Appalachian Basin Ohio Shale, Michigan Basin Antrim Shale, and the Illinois Basin New Albany Shale are laterally pervasive and economically productive. For example, the Appalachian basin, extending from south western New York to eastern Kentucky and central Tennessee, covers an area of 414,398 km 2 (Hill and Nelson, 2000). Here, production comes mainly from the Big Sandy field of eastern Kentucky and West Virginia, producing around 8.5 X 101 0 m 3 . The Big Sandy gas field (upper Bituminous shale) has been produced commercially since 1921 (Hunter and Young, 1953). By the end of 1999, there were 21,000 gas shale wells producing approximately 120 Bcf annually in the Appalachian shales (Hill and Nelson, 2000). Gas resource estimates range from 206 Tcf to 2000 Tcf, and technically recoverable resource estimates ranging from 14.5 Tcf to 27.5 Tcf. These eastern Devonian shales are similar to shale formations found in the Western Canadian Sedimentary Basin in that they are volumetrically important hence it is significant to explore the possibility of Western Canadian shales being continually producing reservoirs. 1.3 N A T U R A L G A S I N S H A L E The gas in gas shales and coalbed methane are formed either by methanogenic bacteria or thermal cracking of organic matter. Gas shales and coals are the source and the 3 reservoir. The volume of gas stored in the sorbed state is dependent on the volume of rocks and organic matter. For a given volume and low pressures, the gas storage capacity of gas shales and coal can exceed that stored in conventional reservoirs. Gas shales and coal seams, like conventional reservoirs are heterogeneous due to their varying sedimentology and structural and reservoir properties and gas generation vary with degree of diagenesis. Understanding the geology, sedimentology, structure, and diagenesis are key to recognize and predict source and reservoir characteristics of gas shale and coal. 1.4 GAS SHALE POTENTIAL Evaluating the potential of a gas shale reservoir involves accounting for the unique storage properties of shales. Gas shale is a source, reservoir, and trap for methane and minor amounts of other gases. Unlike conventional gas resources, gas in shale is stored three ways: (1) adsorbed onto kerogen and clay, micro- (<2 nm) and mesopores (2 - 50 nm); (2) compressed in macropores (2 - 50 nm); and (3) compressed in fractures. For production, there is desorption of gas from the micropores as a response to the decrease in pressure, then slow diffusion and Darcy flow of gas through the matrix (10~9 to 10-12 md) and finally mass transfer by Darcy flow through the fractures (De Witt, 1986). Gas-in-place estimations for gas shales involve accounting for the adsorbed and pore space/free gas storage components. The adsorbed gas capacity is quantified through adsorption isotherms modelled that can be modelled by the Langmuir equation. They 4 are run at reservoir temperature. The free gas component is estimated by measuring the total porosity of the shale to gas from the difference between Hg (bulk density) and He (skeletal density/or more appropriately CH 4 ) . In many producing shales the free gas makes up to 40% of the gas-in-place. Yet because of the mode of occurrence of gas in shales, estimation of gas-in-place using free-gas capacities to forecast long-term production history is less predicable than for conventional methane resources. 1.5 INTENT OF STUDY There is a need to characterize the gas potential of organic rich shales in the Western Canadian Sedimentary Basin. This study investigates the gas storage capacity (sorption capacity) of organic rich mudrocks in Western Canada. The units studied include the Duvernay, Exshaw, Nordegg, Belle Fourche, and Second White Specks shale. These mudrocks are a potential source of natural gas because they are volumetrically important, occurring throughout much of the Phanerozoic succession. Since all strata vary geographically in organic matter abundance, kerogen type, and maturity, the gas shale potential wil l vary. 1.6 STRUCTURE OF THESIS Each of the chapters (chapters 2 and 3) of this thesis constitutes a stand-alone paper that is unpublished. In Chapter 2, source rock characteristics and geology of the selected 5 shale formations are described. The gas sorption potential in shales is assessed and related to the source rock characteristics and geology. Chapter 3 compares the geochemistry and petrology of the shales and relates the nature and composition of organic matter to the sorption capacity. Geochemical and mineralogical data are summarized in Appendix A. Detailed descriptions of the nature of the organic matter observed in the shale samples in white and blue light excitation is found in Appendix B. Appendix C contains methane sorption data. 6 1.7 REFERENCES CITED De Witt, W., Jr, 1986. Devonian Gas Bearing Shales in the Appalachian Basin. Geology of Tight Gas Reservoirs, pp. 1-8. Hil l , D.G., and Nelson, C.R., 2000. Gas Productive and Fractured Shales: A n Overview and Update. Gas Tips, pp. 4-13. Hunter, C D . , D.M. Young, 1953. Relationship of Natural Gas Occurrence and Production in Eastern Kentucky (Big Sandy Gas Field) to Joints and Fractures in Devonian Bituminous Shale. Bulletin of the American Association of Petroleum Geologists, 37: 282-299. U.S. Geological Survey Circular 1118, 1995. 1995 National Assessment of United States Oil and Gas Resources. Geological Survey, United States Government Printing Office, Washington D.C., 20 pp. 7 CHAPTER 2- ORGANIC-RICH SHALE IN T H E WESTERN C A N A D I A N SEDIMENTARY BASIN: GEOLOGY, SOURCE ROCK POTENTIAL, A N D SORPTION CAPACITY 2.1 ABSTRACT High-pressure methane sorption isotherms of six organic-rich mudstone found throughout the Phanerozoic in the Western Canadian Sedimentary Basin have been measured. Variations of gas sorption potential with organic matter abundance, kerogen types, composition and maturity have been investigated. For the combined data set, the amount of total organic carbon is strongly related to methane sorption capacity (r2 = 0.78), suggesting that organic matter abundance is important. The Duvernay, Exshaw, Nordegg, and Second White Specks samples range in TOC contents from 1 to 23 wt% and contain primarily marine, Type I and/or II organic matter and have sorption capacities up to 2 cc/g (66 scf/ton)1. The Belle Fourche samples range in TOC content from 1 to 4 wt% and primarily contain terrestrial, Type III organic matter and have sorption capacities up to 0.8 cc/g (25 scf/ton). The variation in sorption capacity with TOC content of the more organic-lean shales of this study (r2 = 0.44 for Belle Fourche and r 2 = 0.07 for Second White Specks) is not nearly as marked as observed with the more organic-rich shales (r2 = >0.74). The poor correlation between TOC and sorption capacity of organic-poor samples is due to mineralogical differences. Relatively more clay is available for sorption versus abundance of kerogens for the organic-poor = at 0°C +1 atm Imperial at 60°F + 1 atm 8 samples. The ash content is generally inversely correlated with TOC and sorption capacity for all samples. Moisture contents are positively correlated with ash contents when comparing similar maturity shales, indicating that mineral matter has an affinity for moisture. With increasing maturity, there is an increase in sorption capacity, however it must be noted that this correlation is drawn from a small data set. With higher maturity shales, there is increased, sorption capacity due to an increase in rnicroporosity. Also there is decreased competition from moisture for gas sorption sites because of decreased moisture contents with maturation. 2.2 INTRODUCTION Gas shales are defined as unconventional, continuous-type natural gas reservoirs (USGS, 1995) where accumulations are volumetrically important. The gas is trapped in complex and tight reservoirs that require stimulation for production. Obtaining an economic production rate is an exploration risk, due to low matrix permeabilities which are on the order of 0.1 to 10 pd (De Witt, 1986) and porosities generally less than 10%. An extensive fracture system and/or adjacent coarser strata are needed for sufficient volumes of gas to move from the matrix to the well bore for production. Development of appropriate hydraulic fracturing and improved economies of scale contributes to recent successes in gas production. Evaluating the potential of a gas shale reservoir involves accounting for the unique storage properties of shales. Gas shale is a source, reservoir, and trap primarily for 9 methane and minor amounts of other gases. Unlike conventional gas resources, gas in shale is stored three ways: (1) adsorbed onto kerogen and clay, micro- (<2 nm) and mesopores (2 - 50 nm); (2) compressed in macropores (2 - 50 nm); and (3) compressed in fractures. For production, there is desorption of gas from the micropores as a response to the decrease in pressure, then slow diffusion and Darcy flow of gas through the matrix (10-9 to 10-12 md) and finally mass transfer by Darcy flow through the fractures (De Witt, 1986). Gas-in-place estimations for gas shales involve accounting for the adsorbed and pore space/free gas storage components. The adsorbed gas capacity is quantified through adsorption isotherms modelled by the Langmuir equation. They are run at reservoir temperature. The free gas component is estimated by measuring the total porosity of the shale to gas from the difference between Hg (bulk density) and He or CHa (skeletal density). In many producing shales the free gas makes up to 40% of the gas-in-place. Yet because of the mode of occurrence of gas in shales, estimation of gas-in-place using free-gas capacities to forecast long-term production history is less predicable than for conventional methane resources. Devonian shale in the U.S. has long been recognized as a potential economic resource. The first production from naturally fractured Devonian black shale was drilled in 1821 near Fredonia, New York. Today, shales in several U.S. basins such as the Appalachian, Michigan, Antrim, San Juan, and Fort Worth produce significant volumes of natural gas. Currently, there are over 28,000 producing gas shale wells from the five major producing gas shale basins in the U.S., with a cumulative production to date of 380 10 Bcf/day (Hill and Nelson, 2000). Total annual U.S. dry natural gas from shale is 1.9 percent (0.38 Tcf), and the total U.S. proved natural gas shale reserves is 2.3 percent (3.9 Tcf). Gas-in-place resource estimates for the five main U.S. gas shale plays total 581 Tcf, and the recoverable resource estimates for these five plays range from 31 to 76 Tcf. A vast potential exists in the Western Canadian Sedimentary Basin because there is volumetrically important shale strata similar to the laterally continuous producing shale in the United States. Organic-rich mudrocks were deposited during much of the Phanerozoic succession of the WCSB. To date there has been little interest or development for shale gas in Canada. Although organic-rich shales in Western Canada have been well studied as source rocks, shale gas potential is unknown. Along with a need to characterize gas shale potential in Canada, no studies have focused on the relationship between shale sorption with composition or maturation. The objectives of our ongoing research are to determine the relationship of total organic carbon content, organic maturity, and kerogen type on the methane sorption characteristics. This paper characterizes the gas sorption potential of several important organic-rich source rocks in the WCSB. In this paper we describe and contrast the source rock characteristics, compositions, and sorption capacities of the Second White Specks Belle Fourche, Nordegg, Exshaw, and Duvernay strata. 11 2.3 B A C K G R O U N D 2.3.1 Shale in the Western Canadian Sedimentary Basin The Western Canadian Sedimentary Basin is a NW-SE trending basin, extending from the Northwest Territories to Northern Montana (Figure 2.1a). The WCSB is a wedge of mainly Phanerozoic sedimentary rocks that thicken westward from a zero edge on the Canadian Shield to in excess of 10,000 m in the Rocky Mountains. It overlies Precambrian crystalline rocks. Major structural elements affecting basin shape and maturation of strata are the Sweetgrass Arch in southeastern Alberta and the Peace River Arch in west-central Alberta. Both were deformed on along the western margin during the Laramide Orogeny, and, in part, post-orogenic uplift and erosion of sediment played a role forming the present form of the basin. The sedimentary section contains volumetrically important shale from the Late Ordovician to Late Cretaceous. Sedimentation in the WCSB can be divided into two distinct tectonic settings. Carbonate rocks deposited on the stable passive margin of North America dominate the Paleozoic to Jurassic miogeocline and platform stage (Figure 2.1b). The sediments form a wedge tapering from 6 km thick in the west to zero in Manitoba. The Nordegg, Exshaw, and Duvernay shales examined in this study are found in this succession. Younger clastic rocks formed during active margin orogenic evolution of the Canadian Cordillera dominate the overlying mid-Jurassic to Paleocene foreland basin succession (Figure 2.1b). The Colorado Group Second White Specks and Belle Fourche shales examined in this study were deposited in the foreland basin succession. 12 a) b) N O R T H W E S T T E R R I T O R E S \5 \ \ ALBERTA S A S K A T C H E W A N M*? Western Canada CANADIAN SHIELD Sedimentary Basin • , *Bariff „ , C A N A D A USA T" ' STUDY AREA I ; Cypress Hills Figure 2.1: a) The NW-SE trending Western Canadian Sedimentary-Basin (between dark outline) that extends from the Northwest Territories to northern Manitoba (modified from Ricketts, 1989). West of the limit of Laramide deformation are five morphogeological belts. The study area is shown extending from the Peace River Area to southern Alberta; b) Schematic representation of stratigraphy in the Western Canadian Sedimentary Basin* (modified from Mossop and Shetsen, 1994). Each division is denoted with the dominant lithology to give an overall impression of deposition of the slice. SANDSTONE SHALE, "BASINAL CARBONATES", SILTS \ CARBONATE, LIMESTONE, DOLOMITE REEF LIMESTONES AND SHALE I X X GRANITIC AND METAM ORPHIC British C o l u m b i a Tertiary Saskate hewan and Manitoba E d m o r t t d n : - . - . ' : : : : : : : : : : : D u M e g a n : C r e t a c e o u s • • • t • M * * Jurassic Triassic Permian Carboni ferous Devon ian Stoddarf M-Silurian Ordovic ian C a m b r i a n Mj i lS!;!S!i!ili!ili!i!iSi^ i!iSi!i!i!S!S!i!S!Hi!i Precambr icn : W e r o z p i c V'-x x x Jnl x x x x i X X X X Irjlpfkjk?: X X X X X X X X X X X X ) X X X X X X X X X X X X X X 1 ( X X x x x x x x x x x x x x x x x x •Important strata are marked as stratigraphic divisions or slices, whole periods, or on smaller economically important stratigraphic units. "Approximate boundary between the Paleozoic to mid-Jurassic miogeociine and platform stage and the mid-Jurassic to Paleocene foreland basin succession 2.3.2 Sample Collection Seventy homogeneous, mudstone/shale were collected based on total organic carbon and maturity data. Strata at different depths were chosen to represent the variability of each formation throughout the basin. Cores that penetrate the Second White Specks, Belle Fourche, Nordegg, Exshaw, and Duvernay were sampled at the Alberta Energy and Utilities Board Core Research Centre (Calgary). For each formation, the samples range in thermal maturity (Tmax value), and within each maturity range (eg. 430 -440°C, 440 - 450°C etc.) samples with a range of total organic carbon (TOC) contents were selected. Total organic carbon contents are up to 23% by weight and range in maturity from 410°C Tmax to >470°C Tmax. As commonly defined, the <430°C samples are immature, 430°C - 460°C samples are in the oil window, and >460°C samples are overmature (Tissot and Welte, 1984). The organic matter ranges in composition from kerogen Types I - III. Samples were rinsed of drilling mud and ground to a powder. Approximately 150 grams was used for sorption and representative splits were taken for carbon-nitrogen-sulphur (CNS) analysis, bulk X-Ray diffraction, 5 C 1 3 o r g analysis, Rock Eval (Tmax), ash and moisture content, and organic petrography. 14 2.3.3 Methods Total carbon and total sulphur percentages were determined for the samples by combustion/ gas chromatography. Total sulphur content was determined by a LECO CS-225 analyser on an aliquot of ground sample. A l l measurements were calibrated by comparison to pure sulfanilamide standard. The total organic carbon was measured after acid removal of carbonates by heated hydrochloric acid. A total of ~20 - 30 mg of ground sample was reacted with 2 N HC1 to liberate CO2. The amount of total organic carbon (TOC) was calculated as the difference between Total Carbon (TC) and Inorganic Carbon (IC). Inorganic carbon was determined through coulometry. The combined precision is ± 2%. The percentage of carbonate was calculated from the IC content using the following equation: C a C 0 3 (wt%) = IC (wt%) x 8.33. A l l of the C O 2 evolved was assumed to be from the dissolution of calcium carbonate. Several samples were run in duplicate to establish precision. The precisions determined on replicate subsamples were ± 1 % for total C, N , and S, and ± 2% for carbonate. The total N values determined from the CNS analysis are assumed to represent organic nitrogen. Samples were ground to a powder (~100 mg) for pyrolysis using a Rock Eval II instrument (Espitalie et al., 1977). The Tmax (maturity) value is obtained during the stage where the oven temperature is steadily increased to 600°C at a rate of 25°C/min and decomposition of kerogen occurs. 15 Random bulk X-Ray diffraction powder mounts were prepared as follows (Moore and Reynolds, 1997): a) the sample was ground with a mortar and pestle with ethyl alcohol; b) the sample was carefully packed onto a glass slide (not to orientate the sample); and c) the slide was heated under a hot lamp. X-ray powder diffraction on the Siemens D5000 X-Ray Power Diffractometer for the bulk mineralogy was run at 30° 24? to 70° 2<t> at the setting of 40 kV and 30 mA, at a step size of 0.04°, 2 sec/step. The calculation to obtain relative semiquantitative mineral percentages on peaks used was: weight % = (Intensity (counts per second))/sum of Intensity for all peaks used) * 100. The total organic carbon percent was included in the calculations. Carbon isotopes (5C13) were determined using a Finnigan Mat Delta S mass spectrometer on aliquots of powdered sample. Removal of carbonates was by adding hydrochloric acid. The reproducibility of the numbers is ± 0.2 per mil or better. A volumetric apparatus was used to collect high-pressure methane isotherms. To enable comparison, all samples were analysed at a temperature of 30°C. Equilibrium moist shales were prepared to better estimate in-situ conditions. The shales were crushed to a -60 mesh size and brought to equilibrium moisture according to ASTM procedure D3173-73 (Reapproved 1979). About 150 g of sample was prepared for sorption by equilibrating the samples to moisture at 30°C in a K2SO4 saturated brine under partial vacuum for at least 48 hours (Australian Standard AS 1038.17-1989).. The desiccator was evacuated with a water vapour venturi pump. The ash and moisture content of the shales were calculated by drying ~ 1 gram of sample at 105°C to obtain the equilibrium moisture content at 30°C and combusting the sample at 750°C to obtain the ash content. 16 The sorption data was modeled using the Langmuir equation (Langmuir, 1918): P / V = P/Vm + 1/aVm. P= pressure, V= volume of methane adsorbed, V m = monolayer volume, a= constant. 2.4 RESULTS Values for sorption capacities are reported normally to cc/g (cm 3/ g), at a temperature of 30°C and pressure of 5 MPa for comparative purposes. Figure 2.2 shows 3-D scatter plots of TOC versus Tmax, versus methane sorption capacity at 5 MPa for the whole data set (Figure 2.2a) and for each of the formations studied (Figure 2.2b-f). Variations of TOC and Tmax with sorption capacity and organic/inorganic compositions are discussed below. 2.4.1 Upper Devonian Duvernay Formation 2.4.1.1 Geological Setting and Stratigraphic Framework The Duvernay Formation, of the Upper Devonian Woodbend Group, is an organic-rich basinal carbonate facies that is considered to have sourced most of the conventional hydrocarbon accumulations found in the Upper Devonian reservoirs of central Alberta (Stoakes and Creaney, 1984; Allan and Creaney, 1991). It was deposited during the maximum transgressive stage of the Woodbend and is the basinal-time equivalent of Leduc reef growth during the Frasnian. 17 Figure 2.2: Scatter plots showing TOC versus Tmax versus methane sorption capacity for: a) all samples; b) Duvernay samples; c) Exshaw samples; d) Nordegg samples; e) Belle Fourche samples; and f) Second White Specks samples. 18 The Duvernay is conformably overlain by green shales of the Ireton Formation (Figure 2.3a). In the East Shale Basin, the Duvernay overlies stacked carbonate platforms of the Cooking Lake Formation with minor discontinuity. Northward and eastward, the strata passes into lithologies more typical of the overlying lower Ireton Formation (Switzer et al., 1994). In the West Shale Basin the Cooking Lake is absent and the Duvernay conformably overlies similar basinal shales of the Majeau Lake Member. The thickness of the Duvernay varies, depending upon proximity to reef facies. In the East Shale Basin, the Duvernay is over 90 m thick adjacent reef edges and thickens northward and eastward. In the West Shale Basin, it reaches a thickness of up to 125 m near the reef complexes and thins away to less than 30 m thick in the basin centre. The Duvernay is composed of a sequence of dark brown to black, bituminous, slightly argillaceous carbonates interbedded with gray-green, calcareous shales. Two interbedded lithofacies make up the Duvernay: (1) nodular - banded lime mudstones showing varying degrees of bioturbation; and (2) laminated lime mudstones containing fine carbonate material and organic-rich layers. Rich source intervals (up to 20 wt% organic matter) are confined to the dark laminated lime mudstones. The organic-rich interval ranges in thickness from 16 to 60 m in the Duhamel area (Andrichuk, 1961). 2.4.1.2 Sample Distribution Figure 2.3b shows the study area in west-central Alberta and well locations. The Duvernay occurs widely throughout Alberta, much of it is thermally immature, but a 19 a) STAGES (ma) SB 5 a -374 B L U E R I D G E ' 1 Z I Z ~ Z Z . ' . l „ CALMAg WOLF / "ZE|A\ [>SMO,L CK / . C Y N T H I M - J ^ " 1 / NISKU : : l j O f f i ! I C K . . . B I C ^ A Y / Q. O o: CD O U J C Q Q o o 5 GI\£TIAN Q-g CD > U J C O - J G R A M ! N ! A " C A M R O S E \ IRETON O Q DUVERNAY / g \ DUVERNAY \ ' U J \ 1 \ MAJEAU / I LAKE / _ _ , ^ i BASAL C O O K I N G LAKE \ C O O K I N G \ j LAKE \ / SWAN \ / HILLS y f WATERWAYS / REEF SLAVE PO!NT ...FORI.VERMILLION... R5 W 5 R25 R20 T55 T50 T45 T40 T35 / A L B E R T A ! \ \ U S A i ! WEST S H A L E BASIN IwJLUUi I I I I I EAST SHALE BASIN T60 T55 T50 T45 T40 T35 R25 R20 R5 R l R28 F I G U R E 2 . 3 : a ) L a t e D e v o n i a n ( p a r t ) s t r a t i g r a p h y i n c e n t r a l p l a i n s o f A l b e r t a ( f r o m A G A T L a b o r a t o r i e s , 1 9 8 8 ) . T h e s t a g e b o u n d a r i e s a r e a p p r o x i m a t e ; b ) L o c a t i o n m a p o f w e s t - c e n t r a l A l b e r t a s h o w i n g t h e c o r e l o c a t i o n s o f t h e D u v e r n a y s a m p l e s u i t e u s e d i n t h i s s t u d y . 20 broad arcuate band of the Duvernay is within the oil window. Maturity and depth increases to the southwest in the study area. Well locations, for the Duvernay sample set are listed in Table 2.1. The samples selected range from immature (417°C Tmax) to mature (450°C Tmax), and range in depth from 1157 m to 3013 m respectively. Total organic carbon content ranges from 2 to 11 wt%. 2.4.1.3 Source Rock characterization Typical Duvernay mudstones/calcareous mudstones are dark brown to black, hard, very finely laminated, and locally conchoidal fractured. The laminations consist of very fine carbonate and organic-rich layers. Framboidal pyrite is ubiquitous in the shale matrix. Mineralogically, the shales predominantly consist of quartz, calcite, dolomite, feldspar, pyrite, illite, kaolinite, and minor chlorite (Table 2.2). Organic matter within Duvernay samples consist primarily of Type II kerogen. Hydrogen index values are as high as 550 mg/g TOC in immature samples. Values from stable carbon isotope analysis reflect organic matter rich in marine kerogens (average -28.29%o) Microscopically, the Duvernay is dominated by low-reflecting, fluorescing to non-fluorescing amorphous organic matter. Inclusions of unicellular prasinophyte alginite, acanthomorphic acritarchs and liptodetrinite are common. Some samples have sporinite and coccoidal alginite macerals. 21 Table 2.1: Location, depth, organic carbon (TOC), Rock-Eval Pyrolysis parameters, geochemistry, moisture and ash data of samples from the Duvernay Formation, Western Canadian Sedimentary Basin. The samples are shown with increasing TOC within a maturity range. " " " P r o x i m a t e A n a l y s e s R o c k - E v a l p a r a m e t e r s • C N S d a t a . % . L a n g m u i r W e l l L o c a t i o n D e p t h (m) S a m p l e T O C (wt%) T m a x Cc) H I ( m g H C / g T O C ) T o t a l C % C a r b o n a t e % N % S l o l a i C / N m o i s t u r e a s h 6 C 1 3 o r g Methane Sorption (cc/g) @ 5MPa 1 6 - 2 8 - 5 7 - 2 1 W 4 1 1 5 7 . 4 8 D U V - 5 0 8.12 417 550 13.50 44 .76 0.41 1.39 19.60 6.78 69.24 -27.84 0.80 1 6 - 2 8 - 5 7 - 2 1 W 4 1156 .41 D U V - 4 9 8.91 4 1 7 5 5 0 13.63 38.45 0.45 1.71 19.70 7.81 71.03 -28.02 0.98 1 2 - 9 - 4 9 - 1 9 W 4 1404 .24 D U V - 5 3 2.71 427 4 6 6 9.51 57.43 0.12 0.05 22.39 1.49 71.48 -29.32 0.18 1 2 - 9 - 4 9 - 1 9 W 4 1 4 0 5 . 2 0 D U V - 5 1 5.02 4 2 7 4 6 6 10.69 47.19 0.24 0.53 21.36 0.97 71.85 -29.21 0.50 1 6 - 1 8 - 5 2 - 5 W 5 2 3 3 6 . 1 0 D U V - 5 7 2.24 431 5 4 6 4.71 20.65 0.11 1.05 20.28 3.41 89.44 -29.25 0.20 1 6 - 1 8 - 5 2 - 5 W 5 2 3 3 7 . 5 0 D U V - 5 5 4 .92 434 4 2 2 7.38 20.48 0.21 1.31 23.49 3.07 87.58 -28.86 0.59 1 6 - 1 8 - 5 2 - 5 W 5 2 3 3 5 . 7 0 D U V - 5 6 6.18 4 3 9 376 9.04 23.81 0.23 1.93 27 .02 3.28 83.20 -28.23 0.57 1 0 - 4 - 5 1 - 2 4 W 4 1 6 7 3 . 2 0 D U V - 5 9 11.15 431 501 11 .97 6.81 0.33 2.17 33.56 0.66 81.23 -27.69 1.10 1 4 - 2 9 - 4 8 - 6 W 5 2 7 2 1 . 4 0 D U V - 6 7 2.70 444 204 6.05 27.93 0.12 0.86 23.33 3.50 86.11 -27.17 0.16 0 1 - 2 8 - 3 6 - 3 W 5 3 0 1 3 . 4 0 D U V - 6 1 4 .62 4 5 0 1 4 6 10.60 49 .77 0.16 1.45 28 .92 0.31 77.21 -27.87 0.43 Table 2.2: Bulk Mineralogy for Duvernay Formation samples, as deternuned by X-Ray diffraction peak intensity analysis. W e l l L o c a t i o n D e p t h ( m ) S a m p l e T O C ( w t % ) T m a x C9 Q u a r t z 4 . 2 3 d C a l c i t e 3 . 0 3 d P y r i t e 2 . 7 1 d D o l o m i t e I l l i t e / M L C 2 . 8 9 d l O . O O d C h l o r i t e 1 4 . 0 0 d K a o l i n i t e 7 . 1 0 d K f e l d 3 . 7 9 d T o t a l C l a y 1 6 - 2 8 - 5 7 - 2 1 W 4 1 1 5 7 . 4 8 D U V - 5 0 8 .12 4 1 7 3 4 7 5 4 5 4 0 1 0 4 1 6 - 2 8 - 5 7 - 2 1 W 4 1 1 5 6 . 4 1 D U V - 4 9 8.91 4 1 7 3 1 4 7 3 5 2 0 1 4 3 1 2 - 9 - 4 9 - 1 9 W 4 1 4 0 4 . 2 4 D U V - 5 3 2.71 4 2 7 3 0 5 7 2 2 2 0 1 0 3 1 2 - 9 - 4 9 - 1 9 W 4 1 4 0 5 . 2 0 D U V - 5 1 5 .02 4 2 7 3 0 • 6 5 0 0 1 0 1 0 2 1 6 - 1 8 - 5 2 - 5 W 5 2 3 3 6 . 1 0 D U V - 5 7 2 .24 4 3 1 6 9 2 3 2 1 2 0 1 0 3 1 6 - 1 8 - 5 2 - 5 W 5 2 3 3 7 . 5 0 D U V - 5 5 4 . 9 2 4 3 4 61 2 6 3 1 2 0 2 0 4 1 6 - 1 8 - 5 2 - 5 W 5 2 3 3 5 . 7 0 D U V - 5 6 6 .18 4 3 9 5 0 3 0 4 5 2 0 2 0 4 1 0 - 4 - 5 1 - 2 4 W 4 1 6 7 3 . 2 0 D U V - 5 9 1 1 . 1 5 4 3 1 4 0 1 7 9 14 2 0 1 11 3 1 4 - 2 9 - 4 8 - 6 W 5 2 7 2 1 . 4 0 D U V - 6 7 2 .70 4 4 4 3 9 3 8 2 5 6 2 4 0 1 2 1 - 2 8 - 3 6 - 3 W 5 3 0 1 3 . 4 0 D U V - 6 1 4 . 6 2 4 5 0 4 4 0 0 4 8 3 0 0 4 3 There is a positive correlation between TOC and total sulphur content. A S /C chart plotted for the Duvernay samples (Figure 2.4) plots with slope less than 0.4 (normal marine oxic line) which is suggestive of freshwater oxic settings (Berner and Raiswell, 1984). The geochemical proxies above indicative of marine anoxic settings do not correlate with a freshwater interpretation. The lack of correlation may be due to that carbonate systems are usually Fe-lirnited; hence pyrite formation is inhibited (Berner, 1970,1984). Moreover, maturation loses organic carbon (Raiswell and Berner, 1987) and residual TOC content of ancient sediments is an unreliable indicator of original sulphate reducing activity (Tyson, 1995). The >430°C Tmax samples have a higher S / C ratio than the <430°C Tmax samples. A plot of C o r g to Ntota i (Figure 2.5) has a positive correlation of nitrogen with organic carbon (Table 2.4). The average C / N value is 23.96, where with a ratio greater than 15 represents sediments that have gone under extensive diagenesis and burial (Meyers, 1994). The Duvernay organic-rich lithofacies accumulated under anoxic, marine, low-energy, basinal conditions (Stoakes and Creaney, 1984). Euxinic conditions are suggested by the absence of fauna, preservation of organic material (Type II oil-prone kerogen), colour of the sediment, the presence of framboidal pyrite, and preservation of laminae. Bottom water anoxia (Chow et al., 1995), combined with slow sedimentation rates within this depositional basin is the main reason for preservation of abundant organic material in this rich source rock. The Duvernay accumulated in water depths between 65 and 100 m under low oxygen bottom water conditions and slow sedimentation rates, and the sea 23 5.00 | 4.00 -| % 3.00 I 2-00 \ % 1.00 H 0.00 O <430 • >430 A l l samples r = 0.84 0.00 2.00 4.00 6.00 TOC (wt%) 8.00 10.00 12.00 Figure 2.4: Plot of weight percent organic carbon vs. weight percent total sulphur for Duvernay shales. The samples plot below the normal marine line (slope = 0.4, zero intercept; Berner, 1970). 12.00 10.00 J 8.00 * 6.00 U o t—I 2.00 0.00 o o ^ - " " " ^ ^ o r 2 = 0.78 1 "i 0.00 0.10 0.20 0.30 Total Nitrogen (wt%) 0.40 0.50 Figure 2.5: Plot of weight percent total nitrogen vs. weight percent of total organic carbon for Duvernay shales. The r 2 value is 0.78. 24 became deep enough to allow for the development of a stratified water column over the entire basin. A detailed description of the deposition of the rich source intervals is in Stoakes and Creaney (1984). 2.4.14 Metliane Sorption and Total Organic Carbon The sorption capacity of the Duvernay sample suite ranges from 0.18 cc/g to 1.10 cc/g at 5 MPa (Figure 2.6). For each maturity range, there is an increase in sorption capacity with TOC (Table 2.1). There is a strong linear relationship between TOC and methane sorption capacity (r2 = 0.96), at a pressure of 5 MPa for all samples. In general, a two-fold increase in total organic carbon content represents a two-fold increase in sorption capacity. For example, at 5.02 wt%, methane sorption is 0.45 cc/g and in contrast at 8.12 wt% methane sorption is 0.80 cc/g. The increase in sorption capacity with maturity (same TOC) is indicated by an increase in symbol size for more mature samples in Figure 2.6 (eg. 5.02 wt% isotherm versus 4.62 wt% isotherm). 2.4.2.5 Methane Sorption and Maturity The relationship between sorption capacity and maturation is masked by the strong correlation that exists between sorption and TOC, and there is only one sample at 450°C Tmax (Figure 2.2b). There is a poor negative correlation of sorption with Tmax (r = -0.47; Table 2.3) given that this sample population happens to have lower TOC contents (r = -0.43) and higher ash contents (r = 0.58; Table 2.3) with higher Tmax values. There is a 25 11.15 wt% 8.91 wt% 8.12 wt% 6.18 wt% 4.92 wt% 5.02 wt% 4.62 wt% 2.24 wt% 2.71 wt% 2.70 wt% 3 4 5 P r e s s u r e ( M P a ) Figure 2.6 High-Pressure methane adsorption isotherms for Duvernay shales of the Western Canadian Sedimentary Basin. In general, the adsorption capacity (as received) increases with total organic carbon content. Plot symbols differ for specified maturity ranges, and symbols increase in size with increasing maturation (Tmax) value. Table 2.3 Calculated correlation coefficient values (r) between chosen data shown in Table 2.1 and Table 2.2. TOC Tmax Carbonate Sulphur Quartz lllite Clay Moisture TOC 1.00 Tmax -0.43 1.00 Carbonate -0.31 -0.17 1.00 Sulphur 0.75 0.06 -0.63 1.00 Quartz -0.34 0.37 -0.60 0.22 1.00 lllite -0.11 0.34 -0.12 0.06 -0.10 1.00 Clay -0.28 0.37 -0.20 -0.10 -0.02 0.94 1.00 1.00 Moisture 0.29 -0.62 0.01 0.24 -0.10 0.26 0.17 Sorption 0.98 -0.47 -0.32 0.75 -0.27 -0.17 -0.34 0.34 ash -0.35 0.58 -0.76 0.21 0.86 0.22 0.37 -0.23 26 poor correlation between Tmax and moisture (r2 = -0.39) and the immature samples have higher moisture contents (6.78% and 7.81%) than samples at higher maturity (0.09%). 2.4.1.6 Methane Sorption and Mineral Abundance Interpretation of the relationship between methane sorption and mineralogy for all Duvernay samples is difficult as the samples are from varying locations and depths. The Duvernay is a calcite, quartz, and TOC-rich rock with relatively low amounts of clay (Table 2.2). The ash content (77 - 95 wt%) is strongly correlated to quartz with an r 2 = 0.74. The ash content shows a positive relationship with moisture at each maturation level indicating that some mineral matter is contiibuting to the moisture content. The negative relationship between TOC/sorption with carbonate, quartz, ash, and clay contents are poor (Table 2.3). 2.4.2 Upper Devonian - Lower Carboniferous Exshaw Formation 2.4.2.2 Geological Setting and Stratigraphic Framework During the Devonian - Mississippian, significant organic-rich marine source rocks were deposited throughout much of North America (Allen and Creaney, 1991). In the Western Canadian Sedimentary Basin, mudrocks of the Exshaw and Bakken were deposited. Organic-rich muds accumulated in a marine shelf setting within an epicontinental sea (Richards, 1989). Deposition occurred during a transgressive episode as the mudrocks onlap palaeodepositional highs in southern and west-central Alberta. 27 The strata are stratigraphically equivalent to the Devonian gas shales of the United States. The Exshaw Formation lies in the Cratonic Platform in Alberta, is bounded on its western side by the Prophet Trough, and grades to the Bakken Formation at the Alberta-Saskatchewan border near the Sweetgrass Arch. It is found across much of Alberta subsurface, northeastern British Columbia and outcrops in the Front Ranges of the Canadian Cordillera. In western Alberta, the Exshaw Formation overlies marine carbonates of the Palliser Formation (Figure 2.7a). In eastern Alberta, the Exshaw Formation disconformably overlies carbonate ramp deposits of the Big Valley Formation (Wabamun Group). The Exshaw Formation is separated from the shale of the overlying Banff Formation by a sharp contact. The Exshaw Formation is thickest in southwestern Alberta (20 m). Eastward to the Alberta-Saskatchewan border, the strata gradually thins. The Exshaw is composed of two members: (1) a lower black shale member; and (2) an upper siltstone member (Macqueen and Sandberg, 1970). The two members are classified as lithofacies B l (black mudrock) and lithofacies B2 (grey-green laminated silty mudstone) respectively by Caplan (1997). The lower black source interval contains TOC contents up to 35 wt% TOC and is <20 m thick (Smith and Bustin, 2000). It varies in thickness from 0.01 m in south-central Alberta to greater than 12 m in northwestern and southeastern Alberta. 28 C o n o d o n t Z o n e s lower crenulata A b e r t a S t ra t i g raphy West East :Lover BANFF F m : sandberg! i dupllcata j sulcata U M praesulcata L U M expansa L U postera L U trachyteia L U M marginifera L b) W6 W5 • # A L B E R T A • V .-V \^  • \ \ \ \ < \..„ • USA F I G U R E 2 . 7 : a) S u b s u r f a c e a n d l i t h o - a n d b i o s t r a t i g r a p h y o f A l b e r t a D e v o n i a n t o C a r b o n i f e r o u s s t r a t a ( m o d i f i e d f r o m C a p l a n a n d B u s t i n , 2 0 0 1 ) e s t a b l i s h e d f r o m p r e v i o u s s t u d i e s s u c h as M a c q u e e n a n d S a n d b e r g ( 1 9 7 0 ) , R i c h a r d s a n d H i g g i n s ( 1 9 8 8 ) , R i c h a r d s ( 1 9 8 9 ) , R i c h a r d s e t a l . (1991) , S a v o y ( 1 9 9 2 ) , J o h n s t o n a n d M e i j e r D r e e s (1993) , a n d M e i j e r D r e e s a n d J o h n s t o n ( 1 9 9 4 ) ; b) L o c a t i o n m a p o f w e s t - c e n t r a l A l b e r t a s h o w i n g t h e c o r e l o c a t i o n s o f t h e E x s h a w s a m p l e s u i t e u s e d i n t h i s s t u d y . 29 2.4.2.2 Sample Distribution Well locations, TOC, Rock-Eval, geochemical, ash, and moisture data are listed in (Table 2.4) . The samples selected range from immature (420°C Tmax) to mature (460°C Tmax) and range in depth from 1782 m to 2789 m. Total organic carbon content ranges from 2 to 12 wt%. Well locations and study area are shown on Figure 2.7b. 2.4.2.3 Source Rock Characterization Exshaw shale is dark grey to black, hard, very finely laminated, and fissile. The shale is locally sheared and rare shelly horizons occur. The laminations consist of very fine silt, and organic-rich layers. Framboidal pyrite commonly occurs parallel to the lamination. The mineralogy consists of quartz, illite, K-feldspar, calcite, dolomite, and pyrite (Table 2.5) . Kerogen is Type 1/II, suggesting predominantly marine organic matter. Hydrogen indices are as high as 671 mg H C / g TOC in immature samples. The organic carbon isotope values range from -27.78%o to -28.41 % o , indicating that most samples are dominated with marine organic matter and contain minor terrestrial organic matter. Petrographically, the organic matter of the Exshaw is dominated by laminae of well-preserved alginite and abundant disseminated amorphous organic matter (red-brown fluorescing bituminite). Alginite is dorninated by thick-walled Tasmanites prasinophytes 30 Table 2.4: Location, depth, organic carbon (TOC), Rock-Eval Pyrolysis parameters, geochemistry, moisture and ash data of samples from the Exshaw Formation, Western Canadian Sedimentary Basin. The samples are shown with mcreasing TOC within a maturity range. R o c k - E v a l p a r a m e t e r s C N S d a t a P r o x i m a t e a n a l y s e s (wt%) L a n g m u i r W e l l L o c a t i o n D e p t h ( m ) S a m p l e T O C (wt%) T m a x H I ( m g H C / g (°C) T O C O I ( m g C 0 2 / g T O C ) % C a r b o n a t e % N % S t o t a i C / N m o i s t u r e a s h org M e t h a n e s o r p t i o n ( c c / g ) @ 5 M P a 1 0 - 1 7 - 8 0 - 2 4 W 5 1781 .92 E X - 2 9 3.36 420 4 0 7 8 1.15 0.18 2.41 18.60 2.32 85.80 -28.41 0.43 1 0 - 1 7 - 8 0 - 2 4 W 5 1782.28 E X - 3 0 6.11 4 2 2 596 8 9.46 0.21 2.56 29.69 0.89 91.89 -27.78 0.59 1 0 - 1 7 - 8 0 - 2 4 W 5 1783 .24 E X - 3 1 11 .85 423 671 6 14.04 0.50 1.49 23.55 1.26 88.78 -28 .30 1.37 1 6 - 3 0 - 7 7 - 2 5 W 5 2023 .35 E X - 2 6 8.91 4 3 2 621 6 1.17 0.34 1.46 26.47 0.69 78.83 -28.38 1.23 1 0 - 2 1 - 7 8 - 1 W 6 2084 .12 E X - 2 5 8.95 4 3 0 834 5 13.79 0.25 1.88 35.56 0.61 86.81 -28 .09 1.05 1 0 - 2 1 - 7 8 - 1 W 6 2084.48 E X - 2 8 9 .95 4 3 2 706 7 15.69 0.34 2.25 29.59 0.90 82.31 -28 .14 0.79 1 - 2 0 - 1 - 2 4 - W 4 2794 .00 E X - 3 7 1.62 449 44 0 2.80 0.08 1.34 21.38 0.30 80.41 -28 .34 0.25 1 - 2 0 - 1 - 2 4 - W 4 2789 .25 E X - 3 5 10 .62 4 5 5 39 0 2.53 0.59 4 .95 18.12 0.60 95.94 -27 .89 1.67 1 - 2 0 - 1 - 2 4 - W 4 2791 .00 E X - 3 6 7.94 4 6 0 76 8 5.89 0.41 4 .18 19.46 0.00 81.41 -28.00 0.99 Table 2.5: Bulk Mineralogy for Exshaw Formation samples, as deterirtined by X-Ray diffraction peak intensity analysis. W e l l L o c a t i o n D e p t h (m) S a m p l e T O C ( w t % ) T m a x C9 Q u a r t z 4 . 2 3 d C a l c i t e 3 . 0 3 d P y r i t e 2 . 7 1 d D o l o m i t e I l l i t e / M L C 2 . 8 9 d l O . O O d C h l o r i t e 1 4 . 0 0 d K a o l i n i t e 7 . 1 0 d K f e l d 3 . 7 9 d T o t a l C l a y 1 0 - 1 7 - 8 0 - 2 4 W 5 1 7 8 1 . 9 2 E X - 2 9 3 .36 4 2 0 81 1 5 2 6 0 0 0 6 1 0 - 1 7 - 8 0 - 2 4 W 5 1 7 8 2 . 2 8 E X - 3 0 6.11 4 2 2 8 3 5 2 3 1 0 0 0 1 1 0 - 1 7 - 8 0 - 2 4 W 5 1 7 8 3 . 2 4 E X - 3 1 1 1 . 8 5 4 2 3 59 20 1 2 3 0 0 2 3 1 6 - 3 0 - 7 7 - 2 5 W 5 2 0 2 3 . 3 5 E X - 2 6 8.91 4 3 2 8 6 0 2 0 2 0 0 2 2 1 0 - 2 1 - 7 8 - 1 W 6 2 0 8 4 . 1 2 E X - 2 5 8 .95 4 3 0 6 0 24 2 2 2 0 0 2 2 1 0 - 2 1 - 7 8 - 1 W 6 2 0 8 4 . 4 8 E X - 2 8 9 .95 4 3 2 56 26 3 2 3 0 0 2 3 1 - 2 0 - 1 - 2 4 - W 4 2 7 9 4 . 0 0 E X - 3 7 1 .62 4 4 9 9 5 1 1 1 0 0 0 0 0 1 - 2 0 - 1 - 2 4 - W 4 2 7 8 9 . 2 5 E X - 3 5 1 0 . 6 2 4 5 5 5 4 4 5 1 3 6 0 0 7 6 1 - 2 0 - 1 - 2 4 - W 4 2 7 9 1 . 0 0 E X - 3 6 7.94 4 6 0 6 5 4 4 7 5 0 0 6 5 and thin-walled Leiosphaeridia. Minor terrestrial organic matter occurs as angular inertodefrinite and vitrodetrinite maceral particles. Total sulphur content (ranges from 1.34 to 4.95 wt%) increases with TOC content (Table 2.4). In the S / C o r g plot of the Exshaw samples (Figure 2.8), the points follow and are slightly above the normal marine line (Berner, 1970). A few organic-rich samples plot below the normal marine line, where a possible explanation may be due to iron-limitation of pyrite formation that may occur when organic carbon accumulation rates are high. A cross plot of C o r g to Ntotai (Figure 2.9) has a positive correlation (Table 2.4). The ratio is low 19 - 30 (immature), and is similar to that of Caplan and Bustin (1996), where the numbers match those of the organic-rich layer (lithofacies-Bi). The average C / N value is 24.71. The black laminated Exshaw member (lithofacies Bi - of Caplan, 1997) reflects suspension deposition in low-energy, quiescent depositional environments (Caplan and Bustin, 2001), below the influence of storm wave-base (Caplan and Bustin, 1996). Evidence for anoxic conditions includes the absence of fauna, preservation of organic matter Type II, high TOC, the colour of the sediment, the presence of pyrite, the parallel-laminated fabric preserved (lack of biogenic reworking), and lack of trace fossils. 32 2 4 6 8 10 12 14 T O C (wt%) Figure 2.8: Plot of weight percent organic carbon vs. weight percent total sulphur for Exshaw shales. The samples plot along and below the normal marine line (slope = 0.4, zero intercept; Berner, 1970). 14.00 12.00 T 10.00 % 8.00 6.00 4.00 2.00 0.00 u o H o oo\ o o r 2 - 0.75 o o 1 1 0.00 0.10 0.20 0.30 0.40 0.50 0.60 Total Nitrogen (wt%) 0.70 Figure 2.9: Plot of weight percent total nitrogen vs. weight percent of total organic carbon for Exshaw shales. The r 2 value is 0.75. 33 2.4.2.4. Methane Sorption and Total Organic Carbon The sorption capacity of the Exshaw sample suite ranges from 0.25 cc/g to 1.67 cc/g (Table 2.6). There is a positive correlation between TOC and methane sorption capacity (r2 = 0.78; Figure 2.10), at a pressure of 5 MPa for all samples at each maturity range. In general, a two-fold increase in total organic carbon content represents a two-fold increase in sorption capacity. For example, at 3.36 wt%, methane sorption is 0.43 cc/g and in contrast at 11.85 wt% methane sorption is 1.37 cc/g. 2.4.2.5 Methane Sorption and Maturity A slight increase in sorption with maturity (r = 0.24; Table 2.6) is seen on the 3-D scatter plot in Figure 2.2c. For example, at a maturity of 420°C and TOC content of 11.85 wt%, sorption is 1.37 cc/g. A sample of maturity 450°C at a TOC of 10.62 wt% sorbs at 1.62 cc/g. Moreover, the immature samples have higher moisture contents that those at higher maturity levels (2.32% to 0.60%). 2.4.2.6 Methane Sorption and Mineral Abundance The Exshaw samples are predominantly siliceous, and have varying clay and calcite abundances (Table 2.5). Both sorption capacity and TOC are negatively correlated with ash contents (r2 = -0.64, and -0.94 respectively). The ash is dominantly composed of quartz (ash content and quartz percent r 2 = 0.85). TOC abundance is poorly related to carbonate and clay abundance (Table 2.6). Mineral matter contributes to the increased 34 3.0 Pressure (MPa) Figure 2.10: Exshaw Methane Isotherms showing the increase in sorption capacity with TOC at each maturity range. Plot symbols differ for specified maturity ranges, and symbols increase in size with increasing maturation (Tmax) value. Table 2.6: Calculated correlation coefficient values between chosen data shown in Table 2.1 and Table 2.2 . TOC Tmax Carbonate Sulphur Quartz ////fe Clay moisture TOC 1.00 Tmax -0.02 1.00 Carbonate 0.52 -0.37 1.00 Sulphur 0.26 0.47 -0.23 1.00 Quartz -0.82 -0.07 -0.61 -0.46 1.00 1 Mite 0.33 0.06 -0.23 0.69 -0.51 1.00 Clay 0.33 0.06 -0.23 0.69 -0.51 1.00 1.00 1.00 moisture 0.00 0.43 -0.64 0.82 -0.15 0.78 0.78 Sorption 0.88 0.24 0.12 0.45 -0.68 0.45 0.45 0.36 ash -0.97 0.07 -0.66 -0.27 0.92 -0.36 -0.36 0.04 35 moisture content because ash and moisture have a positive relationship within each maturation level. The combined data set shows that clay is positively associated with moisture contents (r = 0.78; Table 2.6). 2.4.3 Lower Jurassic "Nordegg" Formation 2.4.3.1 Geological Setting and Stratigraphic Framework The Lower Jurassic "Nordegg"* Member of the Fernie Formation was deposited on a shallow shelf that existed over much of the WCSB. This highly-oil prone marine source unit is a dark brown to black, variably phosphatic marlstone and calcareous mudstone that was deposited during the Pliensbachian (Poulton, et al., 1990), in west central and north central Alberta and adjacent parts of British Columbia. The Nordegg rests unconformably on successively older Triassic and underlying Paleozoic strata from west to east. The Toarcian Poker Chip shale overlies the Nordegg, and is removed by erosion in the eastern regions close to the subcrop edge (Figure 2.11a). Either Upper Fernie shales or sandstones and siltstones of the Lower Cretaceous Manville Group overlie the Nordegg where there is no Poker Chip shale. Pliensbachian and older Fernie Nordegg strata are up to 60 m thick and thin erosionally *Quotation marks are used for the "Nordegg" Member because there is uncertainty in stratigraphic equivalent between the subsurface "Nordegg" to the type section of the "Nordegg" Member in outcrop. 36 a) b) T90 T85 T80 T75 T70 T65 T60 T55 STAGES (ma) N.E. BRITISH C O L U M B I A | N.W. ALBERTA AALENIAN 182 PLIENS-BACHIAN S N E -MLRIAN HET1ANGIAN 208 STAGES POKER \ , CHIP SHALE S sittsone shate " B r o w l b e d s ' . J -POKERX _ CHIP fi? SHALE NORDEGG' WEST CENTRAL ALBERTA IroCKCRJjplOj •?• 9 D  •9,. * M RED ,r DEER j ' RIO R5 W6 R20 R15 RIO I i i I I ALBERTA USA T90 T85-T80 T75 T70 T65 T60 T55 RIO R5 R1R27 R25 R20 R15 RIO F I G U R E 2 . 1 1 : a ) S t r a t i g r a p h i c c h a r t J u r a s s i c u n i t s f r o m N . E . B r i t i s h C o l u m b i a t o W e s t C e n t r a l A l b e r t a ( m o d i f i e d f r o m R i e d i g e r e t a l . , 1 9 9 0 ) ; b ) L o c a t i o n m a p o f w e s t - c e n t r a l A l b e r t a s h o w i n g t h e c o r e l o c a t i o n s o f t h e " N o r d e g g " s a m p l e s u i t e u s e d i n t h i s s t u d y . and depositionally to the east. In the subsurface of west-central Alberta, the "Nordegg" member is 20 - 25 m thick (Riediger et al. 1990). Riediger (1991) subdivided the "Nordegg" into three informal members: (1) a Lower member of organic-rich carbonaceous marlstone (13 m thick); (2) a Middle Member of siltstone to very fine-grained sandstone (1 to 3 m thick); and (3) an Upper Member, basal carbonaceous marlstone passing upwards into carbonaceous, non-calcareous mudstone (9 m thick). The lower and upper member contain abundant (up to 28 % TOC) oil-prone (Type I/II) organic matter. 2.4.3.2 Sample Distribution Figure 2.11b shows the study area encompassing southwestern Alberta with the sample well locations. The Nordegg is marginally mature in the northeast of the study area to overmature near the eastern edge of the Foothills belt (Creaney and Allan, 1990; Riediger et al., 1990). Well locations, TOC, Rock-Eval, geochemical, ash and moisture data for the Nordegg sample suite are listed in Table 2.7. Some samples are a composite of smaller samples over a range of depths within a well. The samples selected range from immature (430°C) to overmature (>470°C) and range in depth from 1062.40 m to 2464.90 m. Total organic carbon content ranges from 2 wt% to 22 wt%. 38 Table 2.7: Location, depth, organic carbon (TOC), Rock-Eval Pyrolysis parameters, geochemistry, moisture and ash data of samples from the "Nordegg" Formation, Western Canadian Sedimentary Basin. The samples are shown with increasing TOC within a maturity range. R o c k - E v a l p a r a m e t e r s C N S d a t a P r o x i m a t e a n a l y s i s (wt%) L a n g m i u r W e l l L o c a t i o n D e p t h (m) S a m p l e T O C (wt%) T m a x C9 H I ( m g H C / g T O C ) T o t a l C % C a r b o n a t e % N % S t o t a | C / N m o i s t u r e a s h 5 C o r g M e t h a n e s o r p t i o n ( c c / g ) @ 5 M p a 1 6 - 2 7 - 8 8 - 7 W 6 1300 .30 N O R - 2 0 12 .70 428 788 12.71 0.08 0.37 9.81 34 .06 2.85 74.70 -28.99 1.27 1 1 - 1 9 - 8 5 - 3 W 6 1062 .40 N O R - 1 8 13 .34 429 762 14.55 10 .03 0.46 3.35 29 .07 3.06 75.96 -29.10 1.12 1 1 - 1 9 - 8 5 - 3 W 6 1064 .17 N O R - 1 9 22 .49 431 779 23.63 9.48 0.60 4 .30 37 .72 1.45 67.00 -29.31 1.95 1 3 - 1 2 - 6 1 - 1 2 W 5 1687 .80 -1695 .50 N O R - 3 9 2 .07 441 4 5 9 7.19 42 .65 0.07 0.95 31 .13 0.80 81.76 -28.40 0.07 2 - 1 3 - 7 1 - 2 2 W 5 1392.91 N O R - 2 3 7.99 4 3 7 560 13.98 49 .69 0.22 1.73 36 .72 0.70 74.68 -26.21 0.64 4 - 2 8 - 6 9 - 1 9 W 5 1461 .30 -1468 .70 N O R - 4 0 12.21 4 4 2 6 0 7 13 .77 12.94 0.41 2 .32 29 .75 1.04 76.97 -28.58 0.91 1 4 - 1 1 - 8 4 - 8 W 6 1130 .50 -1140 .80 N O R - 4 1 13 .42 4 4 0 696 15.03 13 .37 0.38 2.11 34.98 0.88 76.56 -28.68 0.90 2 - 1 3 - 7 1 - 2 2 W 5 1397.16 N O R - 2 4 14.11 441 682 14.89 6.50 0.41 3.14 34.29 1.43 79.32 -28.51 0.90 1 4 - 1 4 - 7 8 - 2 W 6 1070 .60 N O R - 2 1 15 .62 438 815 19.25 30.24 0.55 3.25 28.30 1.20 69.45 -28 .79 1.33 7 - 3 1 - 7 9 - 1 0 W 6 1548 .23 N O R - 3 5.28 4 4 7 214 11 .27 49 .63 0.17 1.08 31.51 1.48 74.00 -28 .36 0.50 7 - 3 1 - 7 9 - 1 0 W 6 1539 .67 N O R - 1 6 .82 4 5 2 264 8.30 12.28 0.24 3.05 28.26 2.33 86.86 -29 .63 0.62 1 0 - 6 - 6 0 - 2 0 W 5 2453 .70 -2463 .40 N O R - 4 3 4 .43 460 151 9.58 42 .89 0.20 1.58 22 .30 1.23 84.40 -27 .19 0.96 1 0 - 6 - 6 0 - 2 0 W 5 2448 .30 -2464 .90 N O R - 4 4 6 .27 460 122 10.20 32 .75 0.25 2.57 24.59 1.51 82.19 -28 .15 1.11 1 6 - 2 3 - 5 7 - 6 W 6 2377 .80 -2391 .80 N O R - 4 5 3.01 545 10 8.34 44 .44 0.12 1.00 25 .49 0.39 83.37 -28.27 0.52 1 6 - 2 3 - 5 7 - 6 W 6 2377 .10 -2391 .20 N O R - 4 6 5.34 554 9 9.80 37.18 0.21 2.00 25.01 0.73 81.82 -28 .67 1.31 Table 2.8: Bulk Mineralogy for "Nordegg"Member samples, as determined by X-Ray diffraction peak intensity analysis. W e l l L o c a t i o n D e p t h ( m ) S a m p l e T O C ( w t % ) T m a x _ro_ Q u a r t z 4 . 2 3 d C a l c i t e 3 . 0 3 d P y r i t e 2 . 7 1 d D o l o m i t e I l l i t e / M L C C h l o r i t e K a o l i n i t e K f e l d 2 . 8 9 d l O . O O d 1 4 . 0 0 d 7 . 1 0 d 3 . 7 9 d T o t a l C l a y 1 6 - 2 7 - 8 8 - 7 W 6 1 1 - 1 9 - 8 5 - 3 W 6 1 1 - 1 9 - 8 5 - 3 W 6 1 3 0 0 . 3 0 1 0 6 2 . 4 0 1 0 6 4 . 1 7 N O R - 2 0 N O R - 1 8 N O R - 1 9 1 2 . 7 0 1 3 . 3 4 2 2 . 4 9 4 2 8 4 2 9 4 3 1 1 3 - 1 2 - 6 1 - 1 2 W 5 2 - 1 3 - 7 1 - 2 2 W 5 4 - 2 8 - 6 9 - 1 9 W 5 1 4 - 1 1 - 8 4 - 8 W 6 2 - 1 3 - 7 1 - 2 2 W 5 1 4 - 1 4 - 7 8 - 2 W 6 1 6 8 7 . 8 0 - 1 6 9 5 . 5 0 1 3 9 2 . 9 1 1 4 6 1 . 3 0 - 1 4 6 8 . 7 0 1 1 3 0 . 5 0 - 1 1 4 0 . 8 0 1 3 9 7 . 1 6 1 0 7 0 . 6 0 N O R - 3 9 N O R - 2 3 N O R - 4 0 N O R - 4 1 N O R - 2 4 N O R - 2 1 2 . 0 7 7 . 9 9 1 2 . 2 1 1 3 . 4 2 1 4 . 1 1 1 5 . 6 2 4 4 1 4 3 7 4 4 2 4 4 0 4 4 1 4 3 8 7 - 3 1 - 7 9 - 1 0 W 6 7 - 3 1 - 7 9 - 1 0 W 6 1 5 4 8 . 2 3 1 5 3 9 . 6 7 N O R - 3 N O R - 1 5 . 2 8 6 . 8 2 4 4 7 4 5 2 1 0 - 6 - 6 0 - 2 0 W 5 1 0 - 6 - 6 0 - 2 0 W 5 2 4 5 3 . 7 0 - 2 4 6 3 . 4 0 2 4 4 8 . 3 0 - 2 4 6 4 . 9 0 N O R - 4 3 N O R - 4 4 4 . 4 3 6 . 2 7 4 6 0 4 6 0 1 6 - 2 3 - 5 7 - 6 W 6 1 6 - 2 3 - 5 7 - 6 W 6 2 3 7 7 . 8 0 - 2 3 9 1 . 8 0 2 3 7 7 . 1 0 - 2 3 9 1 . 2 0 N O R - 4 5 N O R - 4 6 3 .01 5 . 3 4 > 4 7 0 > 4 7 0 4 3 5 9 5 8 2 7 3 5 4 1 5 1 5 4 3 2 3 9 6 1 3 3 4 1 5 0 4 9 5 5 51 2 5 2 4 9 4 1 4 8 1 3 4 7 3 5 4 0 3 8 2 0 5 1 0 1 2 9 1 2 1 2 1 1 5 8 6 1 0 3 0 0 0 0 0 0 11 0 0 1 1 4 2 6 2 1 6 6 2 4^ O 2.4.3.3 Source Rock Characterization Typical Nordegg calcareous marlstones and mudstones are dark grey to black, hard, very finely laminated, thickly bedded, and some break conchoidally. The laminations are thin, organic-rich units and interbedded apatite-bearing horizons. Bulk shale mineralogy is mainly quartz, plagioclase, K-feldspar, calcite, dolomite, illite and NOR-20 contains abundant kaolinite (Table 2.8). The "Nordegg" Member is dominated by Type I/II marine kerogens. Immature sample have a hydrogen index of up to 815 mg H C / g TOC. The organic carbon isotope values range from -27.19%o to -29.63%o (Table 2.7), suggesting samples have a mix of marine and terrestrial or marine dominated organic matter. The petrographic composition is dominated by well-preserved alginite and abundant amorphous disseminated organic matter (bituminite), both interpreted as marine in origin. Inertinite, seirufusinite, and inertodetrinite are sporadic in the matrix. Vifrinite and sporinite are scattered throughout the matrix and are rare. The S/C plot of the Nordegg shows a positive increase in sulfur with TOC (Figure 2.12). Pyrite formation was limited by Fe availability, as suggested by the lower than expected values because the sediments are carbonate-rich (Berner, 1970; Berner, 1984). Riediger and Bloch (1995) found that the Fe (mainly pyrite) varies with carbonate content. When Fe falls below 3%, excess sulfides are incorporated into kerogen. 41 Figure 2.12: Plot of weight percent organic carbon vs. weight percent total sulphur for "Nordegg" shales. Most samples plot along and below the normal marine line (slope = 0.4, zero intercept; Berner, 1970). 25.00 o.oo H 1 ' ' 1 1 1 1 0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 Total Nitrogen (wt%) Figure 2.13: Plot of weight percent total nitrogen vs. weight percent of total organic carbon for "Nordegg" shales. The r 2 value is 0.94. 42 A cross plot of Corg to Ntotal (Figure 2.13) has a positive correlation (r2 = 0.94) (Table 2.4). The average C / N ratio is 30.21. The "Nordegg" Member organic-rich facies accumulated in anoxic water, as evidenced by the high sulphur content, lack of bioturbation, the colour of the sediment, and preservation of organic material. The mterlarnination of organic-rich (anoxic conditions) and apatite bearing beds (dysaerobic conditions) indicate there was periodic fluctuation in the concentration of oxygen in bottom waters above the sediment-water interface (Belayouni and Trichet, 1983; Belayouni and Trichet, 1984). These alternations are best-developed in shallow sedimentary basins (Belayouni and Trichet, 1984; Belayouni et al., 1990). The depositional model proposed by Riediger (1991) is restricted circulation in a silled basin, as there was little clay input as terrane obduction was occurring to the west in Jurassic time. Biomarker signatures and lithotypes indicate an anoxic, possibly hypersaline, carbonate depositional environment (Riediger, 1991). 2.4.3.4 Methane Sorption and Total Organic Carbon For all maturity ranges, there is an increase in sorption capacity with TOC (Table 2.7). Methane sorption capacity ranges from 0.07 cc/g to 1.95 cc/g at 5 MPa. Figure 2.14 shows the Nordegg methane isotherms. The r 2 value of TOC versus methane sorption at 5 MPa for all samples is 0.74. For example, at the 4 3 0 ° - 4 4 0 ° range and pressure of 5 MPa, the sorption capacity at 7.99 wt% TOC is 0.64 cc/g, and at 22.49 wt%, the sorption capacity is 1.95 cc/g. 43 F i g u r e 2 .14: N o r d e g g M e t h a n e I s o t h e r m s s h o w i n g the i n c r e a s e i n s o r p t i o n c a p a c i t y w i t h T O C at e a c h m a t u r i t y r a n g e . P l o t s y m b o l s d i f f e r f o r s p e c i f i e d m a t u r i t y r a n g e s , a n d s y m b o l s i n c r e a s e i n s i z e w i t h i n c r e a s i n g m a t u r a t i o n ( T m a x ) v a l u e . Table 2.9: Calculated correlation coefficient values between chosen data shown in Table 2.7 and Table 2.8 roc Tmax Carbonate Sulphur Quartz ////fe Clay moisture TOC 1.00 Tmax -0.70 1.00 Carbonate -0.72 0.55 1.00 Sulphur 0.51 -0.53 -0.69 1.00 1.00 Quartz 0.42 -0.05 -0.63 0.22 1 Mite 0.23 -0.28 -0.72 0.55 0.50 1.00 Clay 0.22 -0.39 -0.64 0.90 0.20 0.74 1.00 1.00 moisture 0.25 -0.48 -0.48 0.91 0.09 0.50 0.92 Sorption 0.76 -0.24 -0.50 0.52 0.37 0.16 0.22 0.27 ash -0.77 0.71 0.23 -0.35 0.03 0.23 -0.01 -0.22 1.00 -0.55 1.00 44 2.4.3.5 Methane Sorption and Maturity The TOC versus methane sorption r 2 value for all samples (0.78) is better correlated when plotting similar maturities. The r 2 value for samples of 430° and 440° Tmax is 0.96 and 0.98 respectively. The overmature samples have higher sorption capacities than other samples, as seen by the slope in Figure 2.2d. At a TOC content of ~5 wt%, sorption capacities increase from 0.50 cc/g to 1.31 cc/g with the maturities 440°C to >470°C. The correlation coefficient value of Tmax versus sorption (r = -0.24; Table 2.9) does show a poor inverse correlation but only because the TOC strongly decreases with Tmax (r = -0.70; Table 2.9). Moisture content decreases with maturation (r = 0.48; Table 2.9). 2.4.3.6 Methane Sorption and Mineral Abundance The Nordegg samples are calcite and/or quartz-rich, with relatively low clay contents (Table 2.9). The ash content is variable and ranges between 67 to 87 wt%. There are no correlations between ash content and mineral matter compositions because some samples are high in carbonate. Calcium carbonate breaks down during the ashing technique and releases CO3. The ash contents are moderately inversely correlated with TOC (r2 = 0.69). For all maturity levels, samples containing more carbonate (marlstones) have less TOC quartz, and clay (Table 2.9). The clay content has a strong correlation with moisture content (r2 = 0.85), and a carbonate content has a poor negative correlation (r = -0.48) with moisture. Sample NOR-20 has a lower TOC content and similar moisture content with NOR-18 yet has a higher capacity for methane because of higher clay contents (Table 2.9). 45 2.4.4 Lower Cretaceous Colorado Group 2.4.4.1 Geological Setting and Stratigraphic Framework ' During the Albian to Santonian, a major marine transgression occurred in a large epeiric sea over western North America (William and Stelck, 1975; Kauffmann, 1977). An eastward tapering wedge of marine shales and intercalcalated sandstones of the Lower Cretaceous Colorado Group were deposited. The four major regressive pulses are the Peace River-Viking, Dunvegan, Cardium-Bad Heart, and Milk River Formations. The sea was oriented north-south between the rising Cordillera to the west and the Canadian Shield to the east. To the south, the sea covered the American midwest and southwest. Concomitant was regional tectonic downflexing of the craton as a result of crustal thickening along the western margin during the Columbian orogeny (Lambeck et al., 1987), and eustatic changes in sea level. The Colorado Group unconformably overlies the Mannville Group in central and southern Alberta. The strata are conformably to disconformably overlain by the Milk River, Lea Park or equivalent formations. In the southern foothills it is partially equivalent to the Alberta Group. The Alberta Group unconformably overlies the Crowsnest Volcanics and Blairmore Group and is unconformably overlain by the Belly River Formation. In the central-northern foothills it is equivalent to the Fort St. John, Dunvegan, and Alberta Groups (Figure 2.15a). 46 PERIOD SERIES | STAGE CENTRAL AND SOUTHERN PLAINS NORTHWEST PLAINS U n n a m e d SMOKY GR C O UPPE TURONI/ OUP UPPE S E C O N D W H I T E S P E C K S F M . SMOKY GR KASKAPAU FM. o LAN 0 B E L L E F O U R C H E F M D U N V E G A N F M . CRETACE CENOMAN DO ZD >-CRETACE ER CENOMAN ORA NBR F I S H S C A L E S F M T. JOHN GRO FTESBU R F I S H S C A L E S M B R . CRETACE LOW O W E S T G A T E F M T. JOHN GRO SHA LOW z <, CQ <! O V I K I N G F M . T. JOHN GRO PEACE RIVER J O U F O U F M . CO 1— o: B A S A L C O L O R A D O M E M B E R O FM. W6R25 R20 R15 RIO l l . i i l » l » f a l . » ; b l a f a l i c b i 5 l » i l » l » l i » l a U I » k l » l » l i . l . R5 T60 T55 T50 T45 T40 W5 R20 R15 RIO laslislssJsslssl^lsffilsslsal^lsal^l*£ls£I^.IK»lssls SlEETf ALBERTA USA R5 W4 J© B T60 T55 T50 T45 T40 T35 T30 T25 T20 T15 T10 T5 R1R30 R25 R20 R15 RIO R5 R1R30 FIGURE 2.15: a) Regional Albian through middle Turonian stratigraphy for the central, southern, and northwestern plains of the Western Canadian Sedimentary Basin (after Bloch et al., 1993); b) Location map of west-central Alberta showing the core locations of the Colorado Group samples used in this study. Light grey: Belle Fourche Formation, Dark Grey: Second White Specks Formation. 47 The strata are the thickest and most regionally extensive succession of Cretaceous rocks in the Western Canadian Sedimentary Basin. The strata changes in thickness from about 700 m in southwestern Alberta to 200 m in the Manitoba Escarpment. In northwestern Alberta, overlying the Peace River Arch, the Colorado Group is 1500 m thick. The lower Colorado Group shales (lower Albian to Turonian) comprises a wedge of dominantly mudstone and claystone. The formations are the Late Albian Westgate, the Early Cenomanian Fish Scales, the Middle to Late Cenomanian Belle Fourche, and the latest Cenomanian to Middle Turonian Second White Specks (Figure 2.15a). The four formations are defined by their geochemical, mineralogical, biofacies, and sedimentological characteristics (Bloch et al., 1993). For this study, the Second White Specks and Belle Fourche Formations are evaluated and described in detail below. 2.4.4.2 Sample Distribution ~\ Figure 2.15b shows the well locations of the Second White Specks and Belle Fourche samples used in this study. The lower Colorado Group shales are immature east of ~ 114° longitude and are mature adjacent to and beneath the Fold and Thrust Belt along the western margin of the WCSB. Tables 2.10 and 2.13 show the sample information and data collected for the two sample suites. The samples collected from the Second White Specks shales range from 2 to 4 wt%. The Belle Fourche shales range in TOC content from 1 to 4 wt %. 48 2.4.4.3 Late Cenomanian to Middle Turonian Second White Specks Formation The Second White Specks Formation was deposited when sea level was a maximum in the Western Interior Seaway during the Late Cenomanian to Middle Turonian (Kauffman 1977,1984; Haq et a l , 1988; Caldwell et al., 1993; Kauffman et al., 1993). The increased water depths fostered marine anoxic conditions and migration of Tethyan planktic foraminifers and coccoliths to the northern portion of the seaway. The strata are a transgressive, condensed section. It is correlative with the Greenhorn Formation in the United States and the Favel Formation in Manitoba. The basal contact of the Second White Specks Formation with Belle Fourche Formation varies from conformable to disconformable. The Cardium Formation overlies the Second White Specks. The stratum ranges in thickness from 25 m in the Saskatchewan-Manitoba border to over 90 m thick in the Peace River Arch and northwestern Alberta. It is commonly 20 m thick on average. The Second White Specks grades from calcareous mudstone to siltstone in eastern and southern Alberta. To the northwest of Alberta, it grades to a calcareous siltstone. The "white specks" are small aggregates of coccoliths (<1 mm) of lensoid calcareous bodies that are found scattered throughout the interval. The strata are distinguished on logs by the occurrence of carbonate and increase in resistivity and gamma radiation from underlying Belle Fourche and by a decrease in resistivity and density from overlying 49 Table 210- Location, depth, organic carbon (TOC), Rock-Eval Pyrolysis parameters, geochemistry, moisture and ash data of samples from the Second White Specks Formation, Western Canadian Sedimentary Basin. The samples are shown with increasing TOC within a maturity range. Rock-Eval parameters CNS analysis Proximate analysis (wt%) Langmiur Well Location Depth (m) Sample TOC (wt%) Tmax (°Q HI (mg HC/g TOC) Total C % Carbonate %N % Stotai C / N moisture ash 5C" o r g Methane sorbed (CC/R) @ 5 MPa 06-34-30-08W4 693.00 SWS-68 4.08 422 258 4.17 0.72 0.24 1.62 16.98 2.62 89.26 -26.62 0.10 10-36-11-29W4 2638.00 SWS-75 3.29 431 292 5.36 17.23 0.18 2.16 18.24 1.06 89.39 -25.68 0.34 04-13-54-18W5 04-13-54-18W5 04-13-54-18W5 04-13-54-18W5 2100.89 2098.90 2104.00 2102.42 SWS-80 SWS-76 SWS-77 SWS-81 1.88 2.07 2.11 2.32 442 442 441 441 195 195 296 296 2.47 2.69 2.93 3.34 5.19 5.17 6.86 8.45 0.18 0.19 0.19 0.19 1.84 2.14 2.24 2.25 10.24 11.08 11.31 12.19 1.41 0.94 1.50 0.95 93.19 93.26 92.84 92.90 -24.68 -28.31 -24.95 -25.05 0.11 0.48 0.29 0.19 14-29-13-29W4 14-29-13-29W4 14-29-13-29W4 2756.66 2759.17 2760.22 SWS-13 SWS-78 SWS-72 2.71 3.48 4.39 453 445 445 88 136 95 1.54 7.01 7.95 21.86 29.36 29.67 0.15 0.16 0.19 2.12 1.94 1.49 17.78 21.33 23.66 0.67 0.67 0.67 88.53 87.84 85.35 -26.27 -25.78 -25.76 0.48 0.37 0.53 Table 2.11: Bulk Mineralogy for Second White Specks Formation samples, as determined by X-Ray diffraction peak intensity analyst W e l l L o c a t i o n D e p t h ( m ) S a m p l e T O C ( w t % ) T m a x ( °C) Q u a r t z 4 . 2 3 d C a l c i t e 3 . 0 3 d P y r i t e 2 . 7 1 d D o l o m i t e I l l i t e / M L C 2 . 8 9 d l O . O O d C h l o r i t e 1 4 . 0 0 d K a o l i n i t e 7 . 1 0 d K f e l d 3 . 7 9 d T o t a l C l a y 0 6 - 3 4 - 3 0 - 0 8 W 4 6 9 3 . 0 0 S W S - 6 8 4 .08 4 2 2 0 0 3 1 4 0 0 0 4 1 0 - 3 6 - 1 1 - 2 9 W 4 2 6 3 8 . 0 0 S W S - 7 5 3 .29 4 3 1 6 3 2 1 4 5 2 0 1 0 3 0 4 - 1 3 - 5 4 - 1 8 W 5 2 1 0 0 . 8 9 S W S - 8 0 1.88 4 4 1 7 8 2 4 4 4 1 3 0 9 0 4 - 1 3 - 5 4 - 1 8 W 5 2 0 9 8 . 9 0 S W S - 7 6 2 .07 4 4 1 8 0 3 5 4 3 1 3 0 0 0 6 0 4 - 1 3 - 5 4 - 1 8 W 5 2 1 0 4 . 0 0 S W S - 7 7 2.11 4 4 1 7 5 6 5 5 4 1 2 7 0 4 - 1 3 - 5 4 - 1 8 W 5 2 1 0 2 . 4 2 S W S - 8 1 2 .32 4 4 1 7 2 8 6 4 4 0 3 7 1 4 - 2 9 - 1 3 - 2 9 W 4 2 7 5 9 . 1 7 S W S - 7 8 3 .48 4 5 0 54 3 2 5 4 2 0 1 0 3 1 4 - 2 9 - 1 3 - 2 9 W 4 2 7 6 0 . 2 2 S W S - 7 2 4 . 3 9 4 5 0 5 2 3 4 3 3 2 0 0 0 3 o less or non-calcareous shales. Organic-rich Second White Specks shales (condensed sections) can have TOC contents of up to 12 wt%. 2.4.4.4 Source Rock Characterization Typical mudstones of the Second White Specks are dark grey, laminated, pyritiferous, and calcareous with rare current structures. The mineralogical composition is quartz, dolomite, pyrite, K-feldspar, kaolinite, illite/ smectite mixed layer clays and trace amount of detrital mica and chlorite (Table 2.11). The kerogen composition is characterized as Type II organic matter. Hydrogen indices are up to 300 mg H C / g TOC in immature samples. The organic carbon isotope values range from -24.68%o to -26.62%o indicating a mix of terrestrial and marine organic matter. Petrographically, the Second White Specks is dominated by brown fluorescing bituminite that is elongate and parallel to bedding. Alginite is Tasmanites-type, Leiosphere-type and possible Boytrococcus. There is minor liptodetrinite, mertinite, alginite, and vitrinite. Sulfur contents range from 1.49 to 2.25 wt% and in general, sulphur contents increase with TOC. The immature samples are above the normal marine line signifying euxinic conditions (Raiswell and Berner, 1985) in the S/C plot (Figure 2.16). 51 2 3 TOC (wt%) Figure 2.16: Plot of weight percent organic carbon vs. weight percent total sulphur for Second White Specks shales. Most samples plot above the normal marine line (slope = 0.4, zero intercept) (Berner, 1970). U O 5.00 4.00 3.00 2.00 1.00 0.00 o o / r2 = 0.09 0.00 0.05 0.10 0.15 0.20 Total Nitrogen (wt%) 0.25 0.30 Figure 2.17: Plot of weight percent total nitrogen vs. weight percent of total organic carbon for Second White Specks shales. 52 Figure 2.17 shows the C / N plot for the Second White Specks samples. The correlation between total nitrogen and total organic carbon is poor (r2 = 0.09). The average C / N value is 15.87, which is lower than the previous shales with higher organic carbon contents. TOC contents of up to 12 wt% (condensed sections), Type II organic matter, and pelagic organisms suggest widespread bottom water anoxia (Bloch et al., 1999). Hydrogen indices are up to 450 mg H C / g TOC where immature (Allan and Creaney, 1988). Samples in this study are not >5 wt% (likely between condensed sections) but are still effective source zones, hydrogen indices range up to 300 mg H C / g TOC. The Second White Specks dark grey laminated mudstone represents deposition during dominantly marine anoxic conditions corresponding to a global anoxic event and maximum sea-level rise (Kauffman, 1977). High TOC values in the Second White Speckled Shale may be due to a global productivity increase at the Cenomanian-Turonian stage boundary. Deposition was likely below storm wave-base as sedimentary structures do not indicate significant wave influence. 2.4.4.5 Methane Sorption and Total Organic Carbon Figure 2.18 shows the Second White specks sample suite isotherms at each maturity range. The sorption capacity ranges from 0.10 - 0.53 cc/g at 5 MPa. These organic-lean samples show a very low correlation with sorption (r2 = 0.07). 53 Figure 2.18: Second White Specks Methane Isotherms showing the increase in sorption capacity with TOC at each maturity range. Plot symbols differ for specified maturity ranges, and symbols increase in size with increasing maturation (Tmax) value. Table 2.12: Calculated correlation coefficient values between chosen data shown in Table 2.10 and Table 2.11 . TOC Tmax Carbonate Sulphur Quartz lllite Clay moisture TOC 1.00 Tmax -0.10 1.00 Carbonate 0.56 0.67 1.00 Sulphur -0.73 -0.01 -0.29 1.00 Quartz -0.77 0.56 0.04 0.63 1.00 lllite -0.58 -0.37 -0.83 0.24 0.08 1.00 Clay -0.91 -0.02 -0.71 0.47 0.58 0.83 1.00 moisture 0.26 -0.85 -0.63 -0.36 -0.79 0.43 -0.01 1.00 Sorption 0.26 0.57 0.66 -0.05 0.29 -0.80 -0.48 -0.65 ash -0.94 -0.20 -0.79 0.70 0.54 0.75 0.92 0.05 54 2.4.4.6 Methane Sorption and Maturity Sorption shows a poor positive correlation with maturation for all samples (Table 2.12, Figure 2.2f). For example, at a maturity of 422°C and TOC content of 4.08 wt%, the sorption capacity is 0.10 cc/g. A sample at a maturity of 450°C with a TOC content of 4.39 wt%, the sorption capacity is 0.53 cc/g. Moisture contents have a strong inverse correlation with Tmax (r2 = -0.72), and moisture shows a poor inverse correlation with sorption (r = -0.65; Table 2.12). One immature sample at 420°C has moisture content at 10.88 wt% signifying that this low maturity sample has a high affinity for moisture. 2.4.4.7 Methane Sorption and Mineral Abundance The Second White Specks samples are quartz and clay-rich with low TOC contents. Clay contents and quartz decreases with TOC (Table 2.12). The relationship between TOC with quartz and clay contents is inversely related (r = -0.77, r = -0.91). The relationship between TOC versus methane sorption capacity is poor (r2 = 0.07). Sorption capacity is inversely related with moisture contents (r = -0.65; Table 2.12). The correlation between moisture contents (r2 = 0.70, minus immature sample) and clay contents (r2 = 0.65, minus immature sample) with ash content is good mdicating that mineral matter and clay has an affinity for moisture. Carbonate contents does not hold moisture (moisture and carbonate r 2= -0.94). 55 2.4.4.8 Middle to Late Cenomanian Belle Fourche During the Middle to Late Cenomanian, the Belle Fourche was deposited while sea-level dropped and there was a significant influx of sediment into the basin. A seaway connecting Boreal and Tethyan water masses was established but the waters were dominantly of Boreal affinity (cold and low-salinity waters; Eicher and Diner, 1985). Bottom water oxygen levels changed from anoxic at Fish Scales time to dysoxic at Belle Fourche time, allowing for a few foraminiferal species to colonize the substrate. The organic matter changes from Type II to Type III and TOC abundance is generally less than 2 wt%. The Belle Fourche Formation conformably overlies the Fish Scales Formation. Encased within strata equivalent to the Belle Fourche Formation in northwestern Alberta, is the Dunvegan Formation which is a southeastward-prograding silty/sandy deltaic complex deposited during relative lowstand (Figure 2.16a). The Belle Fourche is 20 m at the Manitoba-Saskatchewan border. It thickens westward to >150 m in the subsurface of the central plains of Alberta. Non-calcareous to slightly calcareous mudstone to siltstone comprises the Belle Fourche Formation. It represents an overall coarsening-upwards sequence to a thin uppermost siltstone to fine sandstone layer. The shales are bioturbated with variable amounts of bioclastic material. High TOC contents occur (>2 wt%) in transitional fades to the overlying Second White Speck Formation (Bloch et al., 1993). 56 Table 2.13: Location, depth, organic carbon (TOC), Rock-Eval Pyrolysis parameters, geochemistry, moisture and ash data of samples from the Belle Fourche Formation, Western Canadian Sedimentary Basin. The samples are shown with increasing TOC within a maturity range. R o c k - E v a l p a r a m e t e r s C N S a n a l y s i s P r o x i m a t e a n a l y s i s (w t%) L a n g m u i r W e l l L o c a t i o n D e p t h (m) S a m p l e T O C (wt%) T m a x H I ( m g H C / g (°C) T O C ) T o t a l C % C a r b o n a t e % N % S l o t a i C / N m o i s t u r e a s h O C O R G M e t h a n e s o r p t i o n ( c c / g ) @ 5 M P a 8 - 2 5 - 1 2 - 2 4 W 4 8 - 2 5 - 1 2 - 2 4 W 4 1340 .70 1340 .00 B E L L E - 1 4 0 B E L L E - 1 3 9 1.44 2 .07 4 2 5 4 2 5 2 9 0 290 2.49 2 .09 1.93 0.13 0.15 0.15 2 .32 2.30 14.93 13.44 1.44 1.61 92 .42 92 .87 -26.55 -26.25 0.33 0.47 0 6 - 0 7 - 1 2 - 2 8 W 4 0 6 - 0 7 - 1 2 - 2 8 W 4 2594 .20 2594 .00 B E L L E - 1 3 4 B E L L E - 1 3 3 1.50 3.21 4 3 9 4 3 9 1 2 0 120 1.67 3.92 1.41 5.92 0.17 0.17 2 .32 3.22 8.80 19.00 1.16 0.79 94.58 92 .16 -25.67 -24.93 0.31 0.42 0 9 - 0 9 - 5 6 - 1 9 W 5 0 9 - 0 9 - 5 6 - 1 9 W 5 2268 .63 2268 .00 B E L L E - 1 3 2 B E L L E - 1 3 1 3.96 4.11 4 4 6 4 4 6 2 6 6 266 4 .93 5.18 8.04 8.88 0.24 0.24 2.76 2.93 16.44 17.33 1.29 1.15 90 .20 90.38 -23.74 -24.00 0.35 0.72 1 4 - 2 9 - 1 3 - 2 9 W 4 2769 .28 B E L L E - 1 3 6 1.29 4 5 0 39 1.49 1.65 0.16 2.48 8.28 0.87 95.01 -25.79 0.35 Table 2.14: Bulk Mineralogy for Belle Fourche Formation samples, as determined by X-Ray diffraction peak intensity analysis. D e p t h ( m ) S a m p l e T O C T m a x Q u a r t z C a l c i t e P y r i t e D o l o m i t e l l l i t e / M L C h l o r i t e K a o l i n i t e K f e l d T o t a l W e l l L o c a t i o n ( w t % ) (°c) 4 . 2 3 d 3 . 0 3 d 2 . 7 1 d 2 . 8 9 d C l O . O O d 1 4 . 0 0 d 7 . 1 0 d 3 . 7 9 d C l a y 8 - 2 5 - 5 5 - 2 5 W 4 1 3 4 0 . 7 0 B E L L E - 1 4 0 1.44 4 2 5 7 7 0 4 0 8 0 4 0 8 8 - 2 5 - 5 5 - 2 5 W 4 1 3 4 0 . 0 0 B E L L E - 1 3 9 2 . 0 7 4 2 5 7 6 0 5 0 9 0 5 0 9 0 6 - 0 7 - 1 2 - 2 8 W 4 2 5 9 4 . 2 0 B E L L E - 1 3 4 1.50 4 3 9 7 7 0 5 0 9 0 5 0 9 0 6 - 0 7 - 1 2 - 2 8 W 4 2 5 9 4 . 0 0 B E L L E - 1 3 3 3 .21 4 3 9 7 3 0 5 7 7 0 5 7 7 0 9 - 0 9 - 5 6 - 1 9 W 5 2 2 6 8 . 6 3 B E L L E - 1 3 2 3 .96 4 4 6 6 6 9 7 3 6 9 7 3 6 0 9 - 0 9 - 5 6 - 1 9 W 5 2 2 6 8 . 0 0 B E L L E - 1 3 1 4 .11 4 4 6 6 9 8 6 4 6 8 6 4 6 1 4 - 2 9 - 1 3 - 2 9 W 4 2 7 6 9 . 2 8 B E L L E - 1 3 6 1.29 4 5 0 8 0 0 4 2 6 0 4 2 6 1 4 - 2 9 - 1 3 - 2 9 W 4 2 7 5 6 . 6 6 B E L L E - 1 3 7 2 .71 4 5 0 6 0 2 3 4 4 4 23 4 4 4 2.4.4.9 Source Rock Characterization Belle Fourche mudstones are dark grey to black, hard, very finely laminated, thickly bedded, and some break conchoidally. The laminations consist of mudstone and siltstone. Mineralogy is quartz, feldspar, pyrite, kaolinite, illite/smectite mixed layer clays, calcite and dolomite (Table 2.14). Bentonites are common in this unit. Siderite, pyrite and detrital mica are common accessory minerals. The organic matter is dominantly Type III kerogen. The 5 O 3 0 r g values signify abundant terrigenous organic matter with varying marine organic matter contents (-24.00%o to -26.55%o). Hydrogen Index values from Rock-Eval are 290 mg H C / g TOC in immature samples. The sulfur content is 2 - 3 wt% (Table 2.13). The S/C plot (Figure 2.19) of the Belle Fourche plots above the normal marine line with a y-intercept indicating a euxinic environment (Raiswell and Berner, 1985). Constant sulfur content (pyrite) is limited by the amount of reactive organic matter (Dean and Arthur, 1989). A C / N plot (Figure 2.20) shows positive correlation r 2 = 0.78 between total nitrogen and total organic carbon. The average C / N value is 13.36. Bioturbated beds with variable amounts of bioclastic material in the Belle Fourche indicate at least locally a dysoxic environment. The northwestern part of the basin was 58 Figure 2.19: Plot of weight percent organic carbon vs. weight percent total sulphur for Belle Fourche shales. Most samples plot above the normal marine line (slope = 0.4, zero intercept) (Berner, 1970). U O 5.00 4.00 H 3.00 2.00 1.00 0.00 - o o r 2 = 0.78 o 0.10 0.12 0.14 0.16 0.18 0.20 0.22 0.24 0.26 Total Nitrogen (wt%) Figure 2.20: Plot of weight percent total nitrogen vs. weight percent of total organic carbon for Belle Fourche shales. 59 influenced by the progradation of sediments of the Dunvegan Formation. A slight improvement of benthic conditions from Fish Scales to Belle Fourche deposition occurred, allowing a few opportunistic agglutinated forarruniferal species to colonize the substrate (Bloch et al., 1993). Organic matter changed from Type II to Type III organic matter. Numerical modeling of paleoceanic circulation in the Western Interior Seaway suggests that circulation was generally storm dominated with currents affecting the seafloor down to 200 m (Ericksen and Slingerland, 1990). 2.4.4.10 Methane Sorption and Total Organic Carbon The sorption capacity ranges from 0.06 to 0.72 cc/g at 5 MPa (Table 2.13). Figure 2.21 shows the Belle Fourche methane isotherms at each maturity range. These low TOC samples show a poor correlation with sorption capacities (r2 = 0.44) at 5 MPa. 2.4.4.11 Methane Sorption and Maturity A 3-D scatter plot of TOC versus maturity versus sorption shows no correlation between sorption and maturity (Figure 2.2e, Table 2.15). The samples collected show similar TOC abundances across all maturity levels. With maturation, the clay contents and moisture contents decrease (r = -0.85 and -0.60 respectively). One immature sample at 420°C Tmax has a moisture content of 9.26 wt%. 60 4.11 wt% 2.71 wt% 2.07 wt% 3.21 wt% 1.29 wt% 3.96 wt% 1.44 wt% 1.50 wt% 1.36 wt% 3 4 5 Pressure (MPa) Figure 2.21: Belle Fourche Methane Isotherms showing the increase in sorption capacity with TOC at each maturity range. Plot symbols differ for specified maturity ranges, and symbols increase in size with increasing maturation (Tmax) value. Table 2.15: Calculated correlation coefficient values between chosen data shown in Table 2.13 and Table 2.14 ; moisture Sorption ash TOC Tmax Carbonate Sulphur Quartz lllite Clay TOC 1.00 Tmax 0.38 1.00 Carbonate 0.49 0.59 1.00 Sulphur 0.65 0.19 -0.09 1.00 Quartz -0.70 -0.49 -0.93 -0.03 1.00 lllite -0.52 -0.76 -0.87 -0.14 0.77 1.00 Clay -0.58 -0.85 -0.86 -0.25 0.77 0.96 1.00 moisture -0.19 -0.60 -0.48 -0.28 0.33 0.52 0.58 Sorption 0.63 0.21 0.37 0.33 -0.43 -0.44 -0.39 ash -0.73 -0.30 -0.86 -0.09 0.95 0.73 0.67 1.00 0.16 0.25 1.00 -0.50 1.00 61 2.4.4.12 Methane Sorption and Mineral Abundance The Belle Fourche is quartz and clay-rich shale with relatively low TOC contents. Hence the high surface areas of the clays are sites for sorption. A probable reason why the sorption capacities are lower for the mature samples at same TOC than the immature samples is because of higher clay contents than the mature samples (Figure 2.12). 2.5 C O M P A R I S O N OF SORPTION RESULTS This study suggests that a combination of factors contributes to the sorption capacity. Below the effects of TOC abundance, maturation and rnineralogy upon the sorbed gas capacity are discussed. 2.5.1 Total Organic Carbon The relationship between TOC and methane sorption at a constant pressure (5 MPa) show a strong and positive relationship (r2 = 0.78; Figure 2.2) for all samples collected for this study. Organic matter has the highest surface areas and the dorriinant control in determiriing sorption capacity is the abundance of organic carbon. The Duvernay, Nordegg, Exshaw, and Second White Specks samples range in TOC contents from 1 to 23 wt% and contain primarily algal or amorphous, Type I or II organic matter and have sorption capacities up to 1.95 cc/g (66.4 scf/ton). The Belle 62 Fourche samples range in TOC content from 1 to 4 wt% and primarily contain terrestrial, Type III organic matter and have sorption capacities up to 0.72 cc/g (24.7 scf/ton). 2.5.2 Maturation (Tmax) Results of the linear regression between TOC and sorption are better correlated by constraining data within a maturity level to show the effects of maturation. Figure 2.22 shows TOC versus methane sorption for all samples at varying maturities at a constant pressure of 5 MPa, and the symbols with higher maturities plotted with increasing size. The steeper slope of the higher maturity shales reveal that the more mature samples have higher sorption capacities (note that the overmature shales come from the "Nordegg" samples). There is a general decrease in moisture contents with Tmax values (Figure 2.23). Moisture is expelled from the clay structure during diagenesis. These observations of decreasing moisture content with maturation follow results from coal studies. Inherent moisture represents water sorbed or dissolved in the coal microstructure and is characterized by subnormal vapour pressures (Ode, 1963; Krumin, 1963) owing to the intermolecular attractive forces. Inherent moisture constitutes an integral component of coals of all ranks and is one of the principal components of low rank coals and low maturity shales. Water shares the same sort of interrelationship with the coal and shale structure as with methane which it "competes" for the accessibility to the coal structure. When moisture is removed, the structure collapses and shrinks, and all of its physical and chemical properties change (Allardice and Evans, 1978). At low rank, the molecular 63 2.50 2.00 6 0 • DUVERNAY R2 = 0.97 • NORDEGG R2 = 0.58 • EXSHAW R2 = 0.78 » BELLE R2 = 0.00 • SECOND R2 = 0.96 Al l samples R2 = 0.78 o a a, o 5 1.50 1.00 0.50 9M • « 0.00 0.00 5.00 10.00 15.00 TOC (wt%) 20.00 25.00 Figure 2.22: TOC versus methane sorption capacity for all shales. The size of the symbols increase with maturation. 400 450 500 550 600 Tmax (°C) Figure 2.23: Tmax (°C) versus moisture content for all shales indicating a general trend of decreasing moisture with maturity. Variable moisture contents in each sample set are due to mineralogical differences. 64 component is dominated by water, at medium rank by oil, and at high rank by methane and water, but there is always a diverse mixture of species present (Levine, 1993). In addition, with burial, pore sizes decrease and microporosity increases. The effects of microporosity are observed on the Langmuir isotherm curves for mature and overmature samples (eg Nordegg - Figure 2.7 and Second White Specks - Figure 2.10). Microporosity is associated with a sharp knee (steep initial portion) and a horizontal plateau that may be taken as the micropore volume (Gregg and Sing, 1982). 2.5.3 Mineralogy The ash content is used as a general proxy for mineral matter content but the value of ash content decreases in shales with more carbonate. Since TOC + moisture + ash content = -100%, a plot of TOC + moisture + ash contents versus carbonate content (Figure 2.24) shows that shales with more carbonate have lower ash contents because CO3 is released during the ashing process (r2 = 0.81). The ash contents of the Nordegg and Duvernay are high in carbonate (Figure 2.25). Samples that add up to more than 100% (over -5% Figure 2.24) have very high moisture contents and may be within error of the procedure. Most of the shales (except Nordegg) have good correlation between quartz contents from XRD data (Tables 2.3, 2.6, 2.9, 2.12, and 2.15) and measured ash contents. For all strata, an overall inverse correlation occurs between ash yield and TOC content signifying that mineral matter has a dilutent effect on sorption capacity. 65 70.00 60.00 70.00 80.00 90.00 100.00 110.00 120.00 TOC + Ash + Moisture content (wt%) Figure 2.24: TOC + Ash + Moisture content for all samples. With increasing carbonate content, the x axis decreases in value, representing a loss of C a C 0 3 during ashing. 35.00 55.00 75.00 95.00 115.00 TOC + Ash + Moisture content (wt%) Figure 2.25: TOC + Ash + Moisture content for each shale. 66 The ash contents also show a positive correlation with equilibrium moisture contents at each maturity level for all samples (Figure 2.26), suggesting that some mineral matter contributes to moisture content. TOC increases with moisture content (Figure 2.26), but the correlation is related a decrease of TOC with maturation while moisture decreases with maturity, causing the positive correlation. Moisture may be held in organic matter phyteral porosity, but that relationship is unknown. No relationship exists between moisture and carbonate, therefore the moisture is not held in carbonate mineral matter (Figure 2.29). The correlation between clay contents and moisture contents are poor or good (Figure 2.27 and 2.28) depending on the shale samples. Although the presence of clays provides sites for sorption, the clays hold moisture which competes for the sorption sites of clays. The effect is pronounced at lower maturities because of higher moisture contents. 2.6 DISCUSSION/IMPLICATIONS The sample set collected in the Paleozoic to Jurassic rm^geosyncline and platform succession of the WCSB contain organic matter abundances >10 wt%. The best source rock potential belongs to strata having the most TOC which generally contains dispersed organic matter rich in algal and amorphous, Type I and II kerogens. These shales show proxies indicative of anoxic environments such as black colour, lamination, and high pyrite content. Deposition occurred within large anoxic basins with little or no clastic detritus and 67 Figure 2.26: Ash content versus TOC content versus moisture content for all shales. In general, ash has an inverse relationship with TOC content (inherent). Some moisture is held in mineral matter (excluding carbonate). o Duvernay R2 = 0.03 • Nordegg R2 = 0.84 A Exshaw R2 = 0.62 <> Belle Fourche R2 = 0.28 O Second White Specks R2 = 0.01 >uvernay trend minus point, 0.27 0 . 0 0 5 . 0 0 1 0 . 0 0 1 5 . 0 0 2 0 . 0 0 Clay content (wt%) 2 5 . 0 0 3 0 . 0 0 Figure 2.27: Clay content versus moisture content for all shales. In general, moisture contents increase with the amount of clay. 68 Figure 2.29: Carbonate versus TOC versus moisture content for all shales. 69 terrigenous organic input. In general the organic-rich, carbonate-rich, clay-poor Duvernay and Nordegg shales have relatively low clay contents compared to the amount of organic carbon and mineral matter. Their matrix is dominated by carbonate/quartz and organic matter. Therefore the sorption capacity of the Duvernay and Nordegg samples is dependant on TOC and maturation rather than the clay abundance. The organic-rich Exshaw samples are comparatively more quartz and clay rich than the Duvernay and Nordegg. The ash content, mostly quartz, follows a negative linear relationship with TOC and sorption. A more siliciclastic depositional system during the mid-Jurassic to Paleocene foreland basin succession allowed for more input and organic matter dilution. The shales with low TOC still can contain adsorbed gas. The Belle Fourche and Second White Specks shales have relatively high quartz and clay contents compared to the total organic matter content. The correlation between TOC and with organic content is lacking due to clay minerals (especially illite) responsible for sorption. The beds are affected by moisture/clay/maturation relationships explicating the poor TOC and sorption r 2 values. Although the source rocks from the foreland basin succession have low hydrocarbon generating potential, they represent an enormous volume of low-quality source beds. Together with interbedded sandstones throughout the succession, the strata would function as highly effective carrier beds during migration (Figure 2.1b). The organic-rich shales would need extensive fracturing and/or stimulation for effective production. 70 2.7 CONCLUSION The data collected thus far has allowed preliminary observations for understanding the controls on methane retention in mudrocks. The shale sample sets have varying organic matter abundances, kerogen types, compositions, maturity, and potential, hence show variable sorption capacities. The variation in methane adsorptive capacity is due to a complex interplay of factors including total organic carbon content, kerogen type, geometry, thickness, macro/microscopic composition, chemistry, physical properties, mineralogy, porosity, permeability. A l l are part attributable to sedimentary environment and the burial history and tectonics. Methane sorption capacity is quahtatively related to organic matter contents where the amount of organic carbon present is related to the source rock type and potential. The most abundant organic matter is found in shale containing Type I or II kerogens. The expulsion of water of mature strata (small data set) results in a marked increase in sorbed gas contents. Shales with abundant clays show affinity to sorption, if moisture does not compete with methane for sites. The effect is greatest with lower maturities where the moisture holding capacity is greatest. Little or no sorption is from mineral matter and the correlation of ash content with moisture content signifies that that the mineral matter retains moisture. It is likely that this preliminary study will assist future work in more detailed stratigraphic and spatial gas shale analyses. Gas shales need to be approached by a reservoir engineering viewpoint, where optimal conditions for economic production are 71 desired. For example, important are strata with permeable interbeds or coarsening upwards sequences. Fracturing is either compositional or structural, where the latter tends to occur with black organic-rich shales than grey organic-lean shales. Desirable locations can be refined by combining the use of well logs with TOC, density, and mineralogical data. The data from this research shows that high organic matter and mature shales have the best sorption potential however they may not be the best target from a production standpoint. Even though the organic-lean samples in this study have low sorption capacities, the strata interbeds with coarser strata providing pathways for ease of gas flow. Part of routine exploration program to assess a gas shale deposit properly would involve the assessment of methane producibility. Generally, an adequate fracture system (structural or compositional weaknesses) and/or coarsening upward sequences are desired for production. Future work needs to assess the stratigraphy, depositional models, and structure in detail. 72 2.8 REFERENCES AGAT Laboratories, 1988. Table of formations of Alberta. A G A T Laboratories, Calgary. Allan, J. and Creaney, S. 1988. Sequence stratigraphic control of source rocks: Viking-Belly River System (Abstract). In: D.P. James and D.A. Leckie (Editors), Sequences, Stratigraphy, Sedimentology; Surface and Subsurface. Canadian Society of Petroleum Geologists, Memoir 15: 575 pp. Allan, J., and Creaney, S., 1991. Oil Families of the Western Canada Basin. Bulletin of Canadian Petroleum Geology, 39:107-122. Allardice, D.J., and Evans, D.G., 1978. Moisture in coal. In: C. Karr (Editor), Analytical methods for coal and coal products, Volume 1. Academic Press, New York, pp. 247-262. American Society of Testing Materials (ASTM), D-3173-73 (Reapproved 1979). Standard Test Method for Moisture in the Analysis Sample of Coal and Coke. American Society of Testing Materials, Philadelphia, Pennsylvania, pp. 387 - 391. Andrichuk, J.M., 1961. Stratigraphic evidence for tectonic and current control of Upper Devonian reef sedimentation Duhamel area, Alberta, Canada. American Association of Petroleum Geologists Bulletin, 42: 612-632. Australian Standard AS 1038.17-1989,1989. Methods for the analysis and testing of coal and coke part 17: deterrnining the moisture-holding capacity (equilibrium moisture) of higher rank coal. Standards Association of Australia, North Sydney, 8 pp. Belayouni, H . , and Trichet, J., 1983. PreHminary data on the origin and diagenesis of the organic matter in the phosphate basin of Gafsa (Tunisia). In: M . Bjoroy (Editor), Advances in Organic Geochemistry, 1981. Wiley, Chichester, U.K., pp. 328-335. Belayouni, H. , and Trichet, J., 1984. Hydrocarbons in phosphatized and non-phosphatized sediments from the phosphate basin of Gafsa. Organic Geochemistry, 6: 741-754. Belayouni, H , Slansky, M . , and Trichet, J., 1990. A study of the organic matter in Tunisian phosphate series: relevance to phosphorite genesis in the Gafsa Basin (Tunisia). Organic Geochemistry, 15: 47-72. Berner, R.A., 1970. Sedimentary Pyrite Formation. American Journal of Science, 268: 1-23. Berner, R.A., 1984. Sedimentary pyrite formation: A n update. Geochimica et Cosmochimica Acta, 48: 605-615. 73 Berner, R.A., and Raiswell, R., 1984. C /S method for distinguishing freshwater from marine sedimentary rocks. Geology, 12: 855-862. Bloch, J., Schroder-Adams, C , Leckie, D.A., Mclntyre, D.J., Craig, J., and Staniland, M . , 1993. Revised stratigraphy of the lower Cretaceous Colorado Group (Albian to Turonian), Western Canada. Canadian Society of Petroleum Geologists Bulletin, 42: 325 pp. Bloch, J.D., Schroder-Adams, C.J., Lecke, D.A., Craig, J., and Mclntyre, D.J., 1999. Sedimentology, Micropaleontology, Geochemistry, and Hydrocarbon Potential of Shale from the Cretaceous Lower Colorado Group in Western Canada. Geological Survey of Canada BuUetin, 531. CaldweU, W.G.E., Diner, R., Eicher, D.L., Fowler, S.P., North, B.R., Stelck, C.R., and con Holdt Wilhelm, I., 1993. Foraminiferal Biostratigraphy of Cretaceous Marine Cyclothems. In: W.G.E. Calwell, and E.G. Kauffman (Editors), Evolution of the Western Interior Basin. Geological Association of Canada, Special Paper 39, pp. 477-520. Caplan, M.L., 1997. Factors Influencing the Formation of Organic-Rich Sedimentary Facies: Example for the Devonian-Carboniferous Exshaw Formation, Alberta, Canada. 1997. Vancouver, British Columbia, Canada, University of British Columbia. 1997 Caplan, M.L., and Bustin, R.M., 1996. Factors governing organic matter accumulation and preservation in a marine petroleum source rock from the Upper Devonian to Lower Carboniferous Exshaw Formation, Alberta. Bulletin of Canadian Petroleum Geology, 44(3): 474-494. Caplan, M.L., and Bustin, R.M., 2001. Palaeoenvironmental and palaeoceanographic controls on black, laminated mudrock deposition: example from Devonian-Carboniferous strata, Alberta, Canada. Sedimentary Geology, 145: 45-72. Chow, N . , Wendte, J. and Stasiuk, L.D., 1995. Productivity versus preservation controls on two organic rich carbonate facies in the Devonian of Alberta: sedimentological and organic petrological evidence. Bulletin of Canadian Petroleum Geology, 43: 433-460. Creaney, S., and Allan, J., 1990. Hydrocarbon generation and migration in the Western Canada Sedimentary Basin, In: J. Brooks (Editor), Classic Petroleum Provences. Geological Society of London, Special Publication, 50:189-202. Dean, W.E., and Arthur, M.A. , 1989. Iron-sulfur-carbon relationships in organic-carbon-rich sequences I: Cretaceous Western Interior Seaway. American Journal of Science, 289: 708-743. De Witt, W. Jr, 1986. Devonian Gas Bearing Shales in the Appalachian Basin. Geology of Tight Gas Reservoirs, pp.1-8. 74 Drees, N.C.M. , and Johnston, D.L, 1994. Type Section and Conodont Biostratigraphy of the Upper Devonian Palliser Formation, Southwestern Alberta. Bulletin of Canadian Petroleum Geology, 42 (1): 55-62. Eicher, D.L., and Diner, R., 1985. Forarmnifera as indicators of water mass in the Cretaceous Greenhorn Sea, Western Interior. In: L . M . Pratt, E.G. Kauffmann, and F.B. Zelt (Editors), Fine-grained deposits of Cyclic Sedimentary Processes. Society of Economic Paleontologists and Mineralogists, 1985 midyear meeting, Golden, CO, Field Trip Guidebook 9, pp. 60-71. Ericksen, M . C , and Slingerland, R., 1990. Numerical simulations of tidal and wind-driven circulation in the Cretaceous Interior Seaway of North-America. Geological Society of America Bulletin, 102(11): 1499-1516. Espitalie, J., J.L. Laporte, M . Madec, F. Marquis, P. Leplat, J. Paulet, and A. Boutefeu, 1977. Methode rapide de caracterisation des roches meres de leur potentiel petrolier et de leur degre d'evolution. Revue de rinstitute Francais du Petrole, 32: 23- 42. Gregg, S.J. and K. S. W. Sing, 1982. Adsorption, surface area and porosity, 2 n d Edition. Academic Press, London. Haq, B.U., Hardenbol, J., and Vail, P.R., 1988. Mesozoic and Cenozoic chronostratigraphy and cycles of sea level change. In: C.K., Wilgus, B.S. Hastings, H . Posamentier, J. Can Wagoner, C.A. Ross, and C.G. St. C. Kendall (Editors), Sea Level Changes: A n Integrated Approach. Society of Economic Paleontologists and Mineralogists, Special Publication 42, pp. 71-108. Hil l , David, 2001, Multi-Basin Comparison of Gas Productive Naturally Fractured Shale Plays; A A P G Annual Meeting 2001: A n Energy Odyssey. Hi l l , David G., and Nelson, Charles R., 2000. Gas Productive and Fractured Shales: An Overview and Update;". Gas Tips, pp. 4-13. Johnston, D.L, and Drees, N.C.M. , 1993. Upper Devonian Conodonts in West Central Alberta and Adjacent British-Columbia. Bulletin of Canadian Petroleum Geology, 41(2): 139-149. Kauffman, E.G., 1977. Geological and biological overview. Western Interior Cretaceous Basin. Mountain Geologist, 14: 75-99. Kauffman, E.G., 1984. Paleogeography and evolutionary response dynamic in the Cretaceous Western Interior Seaway of North America. In: G.E.G, Westerman (Editor), Jurassic-Cretaceous Biochronology and Paleogeography of North America. Geological Association of Canada, Special Paper 27, pp. 273-306. 75 Kauffman, E.G., Villamil, T., and Johnson, C.C., 1993. Cretaceous Sequence Stratigraphy of the Northern South-American Passive Margin - Implications for tectonic Evolution. A A P G Bulletin, 77(2): 329-329. Krumin, P.O., 1963. The determination of forms of moisture in coal. Ohio State Engineering Experimental Station Bulletin, 195, 78 pp. Lambeck, K., Cloetingh, S., and McQueen, H. , 1987. Intraplate stress and apparent changes in sea level: the basins of northeastern Europe. In: G.D. Mossop and I. Shetsen (Editors), Sedimentary Basins and Basm-Forming Mechanisms. Canadian Society of Petroleum Geologists and Alberta Research Council, Calgary, Ch. 23. Langmuir, I., 1918. The adsorption of gases on plane surfaces of glass, mica, and platinum. The Journal of American Chemical Society, 40:1461-1403. Levine, J.R., 1993. Coalification: the evolution of coal as source rock and reservoir rock for oil and gas. In: B.E. Law, and D.D. Rice (Editors), Hydrocarbons from coal. A A P G Studies in Geology # 38, pp. 39-77. Macqueen, R.W., and Sandberg, C.A., 1970. Stratigraphy, age, and interregional correlation of the Exshaw Formation, Alberta Rocky mountains. Bulletin of Canadian Petroleum Geology, 18: 32-66. Meyers, P.A., 1994. Preservation of Elemental and Isotopic Source Identification of Sedimentary Organic-Matter. Chemical Geology, 114(3-4): 289-302. Moore, Duane M . , and Reynolds, R .C, 1997. X-Ray Diffraction and the Identification and Analysis of Clay Minerals, 2nd Edition, Oxford University Press, Oxford, 378 pp. Mossop, G. and Shetsen, I., 1994. Geological Atlas of the Western Canada Sedimentary Basin. Canadian Society of Petroleum Geologists and Alberta Research Council, Calgary, 504 pp. Ode, W.H., 1963. Coal analysis and mineral matter. In: H.H. Lowry (Editor), Chemistry of coal utilization, Supplementary volume. John Wiley, New York, pp. 202-231. Poulton, T.P., Tittemore, J., and Dolby, G., 1990. Jurassic strata, northwestern (and westcentral) Alberta and northeastern British Columbia. Bulletin of Canadian Petroleum Geology, 38A: 159-175. Raiswell, R., and Berner, R.A., 1985. Pyrite Formation in Euxinic and Semi-Euxinic Sediments. American Journal of Science, 285(8): 710-724. Raiswell, R., and Berner, R.A., 1987. Organic carbon losses during burial and thermal maturation of normal marine shales; Geology, 15: 853-856. 76 Richards, B.C., 1989. Upper Kaskaskia Sequence: uppermost Devonian and Lower Carboniferous, Chapter 9. In: B.D. Ricketts (Editor), Western Canada Sedimentary Basin, a Case History. Canadian Society of Petroleum Geologists, pp. 165-201. Richards, B. C. and Higgins, A . C , 1988. Devonian-Carboniferous boundary beds of the Palliser and Exshaw formations at Jura Creek, Rocky Mountains, southwestern Alberta. In: N.J. McMillan, A.F. Embry, and D.J. Glass (Editors), Devonian of the World. Canadian Society of Petroleum Geologists, Memoir 14, pp. 397-410. Richards, B. C , Henderson, C.A., Higgins, A . C , Johnston, D.L, Mamet, B.L., and Meijer Drees, N.C., 1991. The Upper Devonian (Famennian) and Lower Carboniferous (Tournaisian) at Jura Creek, southwestern Alberta. In: P.L. Smith (Editor), A Field Guide to the Paleontology of Southwestern Canada. Paleontology Division, Geological Association of Canada, A Field Guide book, pp. 34-81. Ricketts, B.D., 1989. Chapter 1: Introduction. In: B.D. Ricketts (Editor), Western Canadian Sedimentary Basin, A Case History. Canadian Society of Petroleum Geology, Calgary, pp. 1-8. Riediger, CL., 1991. Lower Mesozoic Hydrocarbon Source Rocks, Western Canada Sedimenatary Basin. 1991. Waterloo, Waterloo, Ontario, Canada. 1991. Riediger, CL, M G Fowler, L R Snowdon, F Goodarzi, P W Brooks, 1990. Source rock analysis of the Lower Jurassic "Nordegg Member" and oil-source rock correlations, northwestern Alberta and northeastern British Columbia. Bulletin of Canadian Petroleum Geology, 38A: 236-249. Riediger, C.L., and Bloch, J.D., 1995. Depositional and Diagenetic Controls on Source-Rock Characteristics on the Lower Jurassic "Nordegg Member", Western Canada. Journal of Sedimentary Research, A65(l): 112-126. Savoy, L.E., 1992. Environmental Record of Devonian-Mississippian Carbonate and Low- Oxygen Facies Transitions, Southernmost Canadian - Rocky Mountains and Northwesternmost Montana. Geological Society of America Bulletin, 104(11): 1412-1432. Smith, M.G., and Bustin, R.M., 2000. Late Devonian and Early Mississippian Bakken and Exshaw Black Shale Source Rocks, Western Canadian Sedimentary Basin: A Sequence Stratigraphic Interpretation. A A P G Bulletin, 84(7): 940-960. 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 Canada Sedimentary Basin. In: C D . Mossop and I. Shetson (Editors), Geological Atlas of the Western Canada Sedimentary Basin, Canadian Society of Petroleum Geologists and Alberta Research Council, Calgary, Alberta, Chapter 12 Stokes, F.A., and Creaney, S., 1984. Sedimentology of a carbonate source rock: Duvernay Formation of central Alberta. In: L. Eliuk (Editor), Carbonates in Subsurface and 77 outcrop. Proceedings of the 1984 Canadian Society of Petroleum Geologists Core Conference, Calgary, pp. 132-147. Tissot, B.P., and Welte, D.H., 1984. Petroleum, Formation and Occurrence. Springer, Berlin. Tyson, R.V., 1995. Sedimentary organic matter: organic facies and palynofacies. Chapman & Hall, London, New York. U.S. Geological Survey Circular 1118,1995, "1995 National Assessment of United States Oil and Gas Resources," Geological Survey, United States Government Printing Office, Washington D.C., 20 pp. Williams, G.D., and Stelck C.R., 1975. Speculations on the Cretaceous palaeogeography of North America. In: W.G.E. Caldwell (Editor), The Cretaceous System in the Western Interior of North America. Geological Association of Canada, Special Paper 13, pp. 1-20. 78 CHAPTER 3 - ORGANIC COMPOSITION A N D NATURE OF ORGANIC-RICH SHALES F R O M T H E WESTERN CANADIAN SEDIMENTARY BASIN A N D RELATIONSHIPS T O M E T H A N E SORPTION CAPACITIES 3.1 ABSTRACT Geochemical data (TOC, HI, and carbon isotopes) and organic petrology for six organic-rich mudstones from the Western Canadian Sedimentary Basin were coupled to interpret organic facies and nature of organic matter. High-pressure methane isotherms at 30°C were run to assess the gas potential. The relationships between gas sorption capacity with the abundance, nature, composition, type, and facies of the organic matter within these rocks have been assessed. In general, there is a positive correlation between TOC and HI values indicating better hydrocarbon generating potential for the oil-generative shales. The Duvernay, Exshaw, and Nordegg shales are high-TOC, high hydrogen index (HI) shales, and are Type I or II kerogens indicative of oil generative organic facies A (saline, anoxic). The organic matter is dominated by algal and amorphous (yellow, brown and red fluorescing bituminite) kerogens. The alginite is well-preserved. The Second White Specks and Belle Fourche shales are low in TOC, have low hydrogen index and are Type II or III kerogens indicative of oil and gas generative organic facies B-C (deltaic and variable marine, anoxic). The organic matter in the Second White Specks is predominantly brown, non-fluorescing bii^minite, with minor alginite particles (well and poorly preserved). The Belle Fourche contains mostly vitiinite. Variations in organic carbon isotopic 79 composition ratios are not only related to terrestrial (<25.00%o)/marine (>27.00%o) ratios but are to be related to alginite (~28.00%o)/bimminite (>29.00%o) ratios. Positive correlation exists between TOC content and methane sorption capacity for high-TOC shales versus low-TOC shales because low-TOC shales have low TOC range and are affected by pore/clay/moisture/maturation relationships. Methane sorption capacity varies with organic matter type, nature, HI, kerogen isotopic composition and depositional environment are due to inherent correlations with TOC abundance. The gas capacity of shales increases with Type 1/ II kerogens because of TOC abundance, but isolating rank and other factors, sorption increases with Type III kerogen. The shale samples with more vitrinite (specifically Belle Fourche) have higher sorption capacities than samples with equivalent TOC contents and maturities, especially the Type II kerogen samples. Moisture contents are negatively correlated with methane sorption capacities and are positively correlated with vitrinites at low maturities. Significant development of micropores at higher ranks expels moisture and increases sorption capacities. 3.2 I N T R O D U C T I O N Most knowledge on the factors which influence methane sorption capacities and recovery from organic-rich mudrocks are inferred from studies of coal. Previous studies have attributed variable gas contents to coal composition and rank (eg. Kim, 1977; 8 0 Meissner, 1984; Ayers and Kelso, 1989; Yee et al., 1991; Levine, 1992,1993; Schraufnagel and Schafer, 1996; Levy et al., 1997; Bustin and Clarkson, 1998; Crosdale et al., 1998; Laxminarayana and Crosdale, 1999, 2002). Compositional variations can be expressed in terms of many physical and chemical properties such as ultimate analysis, proximate analysis, maceral content, and mineral matter composition. Coal rank plays an important role in determining gas storage capacity because it directly influences porosity and pore size distribution (Lamberson and Bustin, 1993). Gas sorption by coal is also related moisture content, mineral matter content, temperature, depth, stress, degree and type of secondary mineralization, and fracture development. The maceral composition of coal directly influences gas storage capacity through porosity and pore size distribution. Porosity is greatest in inertinite, intermediate in vitrinite, and least in liptinite (Harris and Yust, 1976). Previous studies on the effect of coal composition on methane adsorption have yielded varied results. Ettinger et al. (1966) reported that fusinite has a greater sorption capacity than vitrinite whereas most studies found that vitrinite has greater sorption capacity (Lamberson and Bustin, 1993; Crosdale and Beamish, 1993; Bustin, 1997). Vitrinite adsorbs a greater volume of gas because it contains a higher proportion of micropores (Clarkson and Bustin, 1996). The effect of shale organic matter composition upon methane adsorption has not been studied in detail. The nature and composition of organic matter from organic-rich mudrocks are commonly assessed by coupling organic geochemical and petrographical methods to characterize and identify organic constituents and degree of maturity (Tissot and Welte, 81 1984). Kerogen types, organic facies, and depositional conditions are interpreted and used to ascertain the hydrocarbon generating potential of organic-rich source rocks. The hydrocarbon gas that an organic-rich source rock generates is retained in part in the shale as sorbed gas. The potential of shale strata as a gas resource can be evaluated through measuring gas adsorption isotherms modelled by the Langmuir equation (Langmuir, 1918). Shale organic matter composition and thermal maturity data can be coupled with adsorption isotherms to determine their relationships. Isotherms measured on shale (eg Ramos and Bustin, 2002) show that adsorption capacity is largely dependent on maturation and total organic carbon content. Higher sorption capacities are from materials with higher organic carbon contents because of the high surface area of organic material. Higher sorption with maturity is related to decreasing pore structure, moisture, and increasing microporosity due to burial. No attempt has been made to date to establish a relationship between the geochemistry and petrographic nature of the original and residual organic matter from which the gas may be produced with the reservoir (sorption) capacity of organic-rich shales. This study is an attempt to relate methane gas storage capacity with geochemical and petrological data on a set of organic-rich shales from the Western Canadian Sedimentary Basin. Rock-Eval parameters such as hydrogen index (HI) and Tmax (thermal maturity), and total organic carbon (TOC) content (Leco method), is coupled with organic petrology to describe the nature of the organic matter. The contribution of the type and nature of organic matter with sorption capacities wil l be discussed. A n attempt to 82 compare and contrast various gas shale reservoirs has implications for future economic interest. 3.3 METHODS 3.3.1 Sample Collection A total of 66 rock samples analysed in this study were collected from a variety of formations throughout the Phanerozoic in the Western Canadian Sedimentary Basin. The shales vary in mineralogical composition, TOC content, kerogen type, source, and thermal maturity. The stratigraphic units investigated include: Second White Specks Formation; Belle Fourche Formation; "Nordegg" Member; Exshaw Formation; and Duvernay Formation. Very finely laminated, organic-rich mudstone/shale was sampled from cores that penetrate the six formations at the Alberta Energy and Utilities Board Core Research Centre (Calgary). Samples from different cores were chosen to represent the variability of each formation throughout the basin, and were also collected based on total organic carbon and maturity data. For each formation, the samples range in thermal maturity (Tmax value), and within each maturity range samples with a range of total organic carbon (TOC) contents were selected. Total organic carbon contents are up to 28% by weight and range in maturity from immature (410°C Tmax) to overmature (554°C Tmax). 83 Samples were rinsed of drilling mud and ground to a powder about -60 mesh size with a ring grinder. Approximately 150 grams was used for sorption and representative splits were taken for CNS analysis, organic petrography, 5C 1 3 analysis, Rock Eval (Tmax), X-ray diffraction, sorption, and ash and moisture content. 3.3.2 CNS Analysis Total carbon and total sulphur percentages were determined for the samples by combustion/ gas chromatography. Total sulphur content was determined by a LECO CS-225 analyser on an aliquot of ground sample. A l l measurements were calibrated by comparison to pure sulfanilamide standard. The total organic carbon was measured after acid removal of carbonates by heated hydrochloric acid. A total of -20 - 30 mg of ground sample was reacted with 2 N HC1 to liberate CO2. The amount of total organic carbon (TOC) was calculated as the difference between TC and IC (determined from coulometry). The combined precision is ± 2%. The percentage of carbonate was calculated from the IC content using the following equation: CaC03 (wt%) = IC (wt%) x 8.33. A l l of the CO2 evolved was assumed from the dissolution of calcium carbonate. Several samples were run in duplicate for precision. The precisions determined on replicate subsamples were ± 1% for total C, N , and S, and ± 2% for carbonate. The total N values determined from the CNS analysis are assumed to represent organic nitrogen. 84 3.3.3 Petrographic Examination The organic matter is characterized visually by organic petrography in reflected light (white light excitation) and fluorescence with a mercury arc lamp and a blue filter for excitation. Bulk ground samples were prepared by mixing the crushed samples in cold setting epoxy and polished as described in Bustin et al. (1983). Analysis of ground samples with petrography permits the identification of kerogen components and distribution. The maceral classification for primary dispersed organic matter and bitumen was from Potter et al. (1998). 3.3.4 Maturity (Tmax) Approximately 100 mg of each sample were ground to a finer powder for pyrolysis using a Rock-Eval II instrument (Espitalie et al. 1977) to obtain Tmax (maturity). Tmax is temperature of maximum hydrocarbon yield during generation of the S2 peak. 3.3.5 Organic Carbon Isotopes Carbon isotopes (5C13) were determined using a Finnigan Mat Delta S mass spectrometer on aliquots of powdered sample. Removal of carbonates was by adding hydrochloric acid. The reproducibility of the numbers are ± 0.2 per mil or better. 85 3.3.6 X-Ray Diffraction The mineralogy of the bulk samples was determined by X-Ray diffractometry. Samples were run on a Siemens D5000 X-Ray Power Diffractometer were run at 3° 2<J> to 70° 20 at the setting of 40 kV and 30 ma, at a step size of 0.04°, 2 sec/step. Mineral abundance was determined semi-quantitatively by dividing the intensity count values of each identified mineral by the total sum of the intensity counts times 100 (TOC from Leco analysis is included in the sum). 3.3.7 Sorption Isotherms A volumetric apparatus was used to collect high-pressure methane isotherms at a temperature of 30°C. The Langmuir isotherms are modeled using the Langmuir equation (Langmuir, 1918). Equilibrium moist shales are used to better estimate in-situ conditions. The shales were crushed to a -60 mesh size and brought to equilibrium moisture according to ASTM procedure D3173-73 (Reapproved 1979)'. About 150 g of sample was prepared for sorption by equilibrating the samples to moisture at 30°C in a K2SO4 saturated brine under partial vacuum for at least 48 hours. The desiccator is evacuated with a water vapour venturi pump. The ash and moisture content of the shales were calculated by drying ~ 1 gram of sample at 105°C to obtain the equilibrium moisture content at 30°C and combusting the sample at 750°C to obtain the ash content. 86 3.4 RESULTS 3.4.1 Background 3.4.1.1 Western Canadian Sedimentary Basin Samples The organic-rich shales collected for this study are collected throughout the Phanerozoic of the Western Canadian Sedimentary Basin (WCSB), and reflect a wide variety of depositional environments. The WCSB can be divided into two distinct tectonic settings. Carbonate rocks deposited on the stable adjacent passive margin of North America dominate the Paleozoic to Jurassic miogeocline and platform stage. The sediments formed a wedge tapering from 6 km thick in the west to zero in Manitoba. The Nordegg, Exshaw, and Duvernay shales examined in this study are found in this succession. Younger clastic rocks formed during active margin orogenic evolution of the Canadian Cordillera dominate the overlying mid-Jurassic to Paleocene foreland basin succession. The Colorado Group Second White Specks and Belle Fourche, and Dunvegan shales examined in this study were deposited in the foreland basin succession. 3.4.1.2 Classification ofMacerals in source rocks Depending on the depositional environment and sources, organic matter in shale is dominantly derived from varied types of marine and lacustrine algae with some debris of land plants. The classification schemes used in this study are the maceral 87 classification for primary dispersed organic matter and bitumens (Table 3.1) and coal maceral classification (Table 3.2) from Potter et al. (1988). Table 3.1 includes secondary features and organic fossils. Detailed descriptions of the nature of the organic matter found in the shale samples in white and blue light excitation is found in Appendix B. Previous organic petrological studies on organic-rich shales show that different types of alginite and amorphous (unstructured) bimminite are the most common macerals (Teichmuller and Ottenjann, 1977; Hutton, 1987). Many oil shales have biturrvinite predorrunating over alginite as the major contributor to the total organic matter content of shale. Different nomenclature for the classification of unstructured organic matter (UOM) or bituminite (Table 3.3) has been used. Three types of the maceral biturrtinite were classified by Teichmuller and Ottenjann, (1977) and are summarized here in Table 3.3. The origin, nature, characteristics of the different biturrtinite types and other dispersed organic matter is described in detail in Appendix B. Bituminite is amorphous organic material formed by the decomposition of algae, bacteria and faunal plankton (Teichmuller, 1989). Biturrtinite either occurs as a maceral (small or large lenses or layers) or as blending with the matrix groundmass, called 'matiix-bituminite' (Creaney, 1980). Macerals of Uptinite, vitiinite, and mertinite are embedded in the matrix. Other shales contain organic matter either chiefly from terrestrial sources or contain rrdnor terrestrial matter such as huminite/vitrinite and mertinite. 88 Table 3.1: Maceral classification for primary dispersed organic matter and bitumens (From Potter et al., 1998). DOM (CSCOP Atlas) M A C E R A L GROUP (after ICCP) MACERAL M A C E R A L VARIETY Herbaceous Amorphous Alginite Huminite/ Vitrinite Inertinite Liptinite See Table 3.2 See Table 3.2 sporinite cutinite resinite suberinite fluorinite chlorophyllinite amorphinite, bituminite alginite acritarchs Phyllovitrinite Hebamorphinite2 Fluoramorphinite2 matrix bituminite3 Botryococcus Pila-Rheinshia Tasmanites Leiosphaeridia filamentous Gloeocapsomorpha dinoflagellates Organic fossils Zooclast scolecodont graptolite chitinozoan foraminifera conchostracan Bitumen Bitumen esudatinite primary bitumen migrabitumen pyrobitumen 2after Senftle et al. (1987) %fter Creaney (1980) 89 LIGNITES AND SUBBUTUMINOUS COALS BITUMINOUS COALS A N D ANTHI *ACITES Maceral Group Maceral Subgroup Maceral Maceral Maceral Subgroup Maceral Group w H p-H 2 humotelinite textinite telinite telovitrinite w H p—1 2 H M > ulminite collotelinite humodetrinite attrinite vitrodetrinite detrovitrinite densinite collodetrinite humocollinite corpohuminite corpogelinite gelovitrinite gelinite gelinite LIPTINITE sporinite sporinite LIPTINITE LIPTINITE cutinite cutinite LIPTINITE LIPTINITE resinite resinite LIPTINITE LIPTINITE alginite alginite LIPTINITE LIPTINITE liptodetrinite liptodetrinite LIPTINITE LIPTINITE suberinite LIPTINITE LIPTINITE chlorophyllinite LIPTINITE LIPTINITE exudatinite LIPTINITE LIPTINITE bituminite LIPTINITE fluorinite m w H p—H t—1 H P< W 2 t—i micrinite micrinite w H p-H 2 p H H P i W 2 macreinite macreinite semimacrinite semimacrinite fusinite fusinite semuhisinite semifusinite secretinite secretinite funginite funginite inertodetrinite inertodetrinite 2vitrinite classification, after ICCP (1994) sinertinite classification, after ICCP (1963,1971,1975,1997) Table 3.3: Comparison of nomenclature in the classification of unstructured organic matter (UOM) in immature or marginally mature oil source rocks (Taylor et al.,1998) Taylor et al. (1998) Brightly fluorescing U O M Brown fluorescing U O M Red fluorescing U O M Non-fluorescing U O M Teichmuller and Qttenjann (1977) Bituminite I Bituminite II Bituminite III Senftle et al. (1987) Fluoramorphinite Fluoramorphinite Fluoramorphinite Herbamorphinite 90 3.4.1.3 Geochemical Parameters A Pseudo Van Krevelen plot, HI vs. O l plot (Figure 3.1) comparable to the H / C vs. O / C Van Krevelen diagram (Espitalie et al., 1977) is used to classify kerogen types. The evolution of kerogen composition with depth is marked by the arrow along each kerogen path. The organic matter of the samples collected in this study ranges in composition from kerogen Types I - III, as defined by Espitalie et al. (1977). The present distribution of organic matter is influenced by a generally south-westward increase in thermal maturation in the sediments. Figure 3.2 shows a HI-Tmax plot showing kerogen types and maturation. Below the plot are the ranges of Tmax above, within, and below with respect to the oil window, characteristic for each kerogen type. For this study, the <430°C samples are immature, 430°C - 460°C samples are in the oil window, and >460°C samples are overmature. 3.4.1.4 Organic Facies Interpretation of the distribution of organic matter on a basinal (Hue, 1988) and sequence scale (Leckie et al., 1990; Chow et al., 1995) is described and interpreted in terms of organic facies (Jones, 1987). Organic facies are defined by combining bulk geochemical and microscopic data (Table 3.4). They are used to predict the occurrence and quality of hydrocarbon source rocks as a function of paleoenvironment (Tyson, 1995). In general, marine or lacustrine derived amorphous and algal kerogen has high 91 1000 900 800 • 700 O e O) O x O) E 600 i 500 400 -300 -200 100 0 • DUVERNAY • NORDEGG AEXSHAW •BELLE x s w s Genera l i zed oil zone -Type 400 420 440 460 480 500 520 540 560 580 600 Tmax (°C)) IMM OIL GAS Type I IMM OIL GAS Type II IMM OIL GAS Type II Figure 3.2: HI versus Tmax diagram defining the Type of organic matter and maturation. For Type I there is a fast increase in Tmax at the 430 -440CC range, and slower one for Type II (420 - 435°C range). Catagenesis is reflected by a decrease and disappearance of the HI. For Type III, the HI increases at low maturities and decreases around 440°C. This is due to a relative enrichment of aliphatic structures of the organic matter by the progressive elimination of oxygenated compounds (Espitalie et al., 1977). Catagenesis is characterized by a slow decrease in HI in the oil formation zone, at the same time a sharprise in Tmax. Maturity with respect to the oil window for each kerogen type is below the plot. For this study, the o i l window is from 430 - 460"C. 92 0 50 100 150 Ol (mg HC/g TOC) Figure 3.1 Pseudo van Krevelen diagram showing hydrogen and oxygen indices from Rock Eval pyrolysis and their evolutionary pathway from early diagenesis (right side of pathway) to metagenesis. Increasing burial is indicated by the direction of the arrows for each particular path. Kerogen types I, II, and III are defined by Espitalie et al. (1997). The samples for this study are plotted showing varying kerogen types, and maturities. 93 hydrogen index values and tends to be associated with oil production. In contrast, terrestrially derived woody kerogen has low hydrogen index values and tends to be associated with gas. Figure 3.3 shows a TOC versus HI diagram, summarizing the organic facies of the samples in this study. 3.4.1.5 Presentation of Data The petrography, geochemistry, thermal maturation, and depositional environment for each formation wil l be described and coupled with sorption data (Tables 3.5 - 3.9). The relative abundances of alginite (A), bituminite (B), and terrestrial (T) organic matter are summarized in the data tables. Values for sorption capacities are reported as cc/g (cm 3/ g) at a constant pressure of 5 MPa, for comparative purposes. 3.4.2 Upper Devonian Duvernay Formation The Duvernay Formation, of the Upper Devonian Woodbend Group, is an organic-rich basinal carbonate facies considered to have sourced most of the conventional hydrocarbon accumulations found in the Upper Devonian reservoirs of central Alberta (Stoakes and Creaney, 1984; Allan and Creaney, 1991). It was deposited during the maximum transgressive stage of the Woodbend and is the basinal-time equivalent of Leduc reef growth during the Frasnian. The most organic-rich laminae correspond to the deep water, most condensed basinal succession with the farthest backstepped reef margins. 94 Table 3.4: Summary of gross chemical, pyrolysis (Rock Eval), and microscopic criteria and characteristics of classical organic facies of Jones (1987). From Tyson (1995). Organic Facies Atomic H/Cat %R„ = 0.5 Pyrolysis Yield' HI Ol Products Dominant Organic Matter Sedimentary Structure Depositional Environment A >1.4 700-1000+ 10-40 Oil Algal amorphous Finely laminated Anoxic (saline) lacustrine; rare marine B 1.2-1.4 350-700 20-60 Oil Algal, amorphous; Laminated, well bedded Anoxic; marine B-C 1.0-1.2 200-350 40-80 Oil-gas Mixed marine, Terrestrial Poorly bedded Variable; deltaic C 0.7-1.0 50-200 50-150 Gas Terrestrial, Poorly partially degraded bedded; organic matter bioturbated Midly oxic; shelf/slope; coals D 0.4-0.7 <50 20-200 Dry Gas Highly oxidized; reworked Massive; bioturbated Highly oxic anywhere 'Derived from Rock-Eval pyrolysis data. HI = CO, generated/ gTOC %R„ = % vitrinite reflectance Hydrogen Index = mg hydrocarbons generated/ g TOC; Ol - mg 25.00 20.00 J 15.00 -\ £ 10.00 H 5.00 0.00 Anoxic, lacustrine, / rare marine A Anoxic, marine Variable, / deltaic B-C I B • • • D U V E R N A Y B N O R D E G G E X S H A W • B E L L E X S W S 200 400 600 800 1000 Hydrogen Index (mg hc/g TOC) Figure 3.3: Correlation of organic carbon and hydrogen index from <440°C shales where the TOC is approximately of the original value (Tissot and Welte, 1984). Organic facies are outlined using the values shown in Table 3.1. 95 Typical Duvernay mudstones/calcareous mudstones are dark brown to black, hard, very finely laminated, and some samples have conchoidal fractures. The laminations consist of very fine carbonate and organic-rich layers. 3.4.2.1 Previous Work Stoakes and Creaney (1984) determined the TOC, organic matter quality, and source rock maturity on a number of cored intervals of the Duvernay Formation. Organic petrographic analyses have been coupled with Rock-Eval pyrolysis data to obtain information on the organic source and maturity of numerous samples (Requejo, et al., 1992; Requejo, 1994; L i et al., 1997). Organic-rich source rocks of the Duvernay Formation are found to be comprised of either unstructured oil-prone Type I kerogens (Stoakes and Creaney, 1984) and marine, Type II organic material (others) in quantities of up to 17 wt% TOC. The average is generally 5 to 10%. 3.4.2.2 Geochemistry The results of Rock-Eval pyrolysis and TOC data show that the Duvernay sample suite ranges in TOC from 2.70 to 11.15 wt% TOC, and range in maturity from 417°C to 450°C Tmax (Table 3.5). The TOC content and HI values (average ~500 mg H C / g TOC) for Duvernay samples below and within the oil window are characteristic of organic matter containing primarily Type II organic matter (Figures 3.1 and 3.2). The samples >440°C Tmax have HI values of ~200 mg H C / g TOC. The two samples >440°C were collected from core on the southwest portion of the study area. Maturity progressively increases 96 Table 3.5: Location, depth, organic carbon (TOC), Rock-Eval Pyrolysis parameters, geochemistry, moisture and ash data, petrography, and methane sorption data of samples from the Duvernay Formation, Western Canadian Sedimentary Basin. The samples are shown with increasing TOC within a maturity range. Rock-Eval parameters C N S data Proximate Analyses (wt%) Langmuir Wel l Location Depth (m) Sample T O C (wt%) Tmax (°Q HI (mg O l (mg H C / g TOC) C 0 2 / g TOC) %Carbonate %N %S t o t a i C / N moisture ash 5 C 1 3 ore Petrography Methane Sorption (cc/g) @ 5MPa 16-28-57-21W4 1157.48 DUV-50 8.12 417 550 32 44.76 0.41 1.39 19.60 6.78 69.24 -27.84 A>B 0.80 16-28-57-21W4 1156.41 DUV-49 8.91 417 550 32 38.45 0.45 1.71 19.70 7.81 71.03 -28.02 A>B 0.98 12-9-49-19W4 1404.24 DUV-53 2.71 427 466 31 57.43 0.12 0.05 22.39 1.49 71.48 -29.32 B>A 0.18 12-9-49-19W4 1405.20 DUV-51 5.02 427 466 31 47.19 0.24 0.53 21.36 0.97 71.85 -29.21 B>A 0.50 16-18-52-5W5 2336.10 DUV-57 2.24 431 546 32 20.65 0.11 1.05 20.28 3.41 - 89.44 -29.25 B>A 0.20 16-18-52-5W5 2337.50 DUV-55 4.92 434 422 35 20.48 0.21 1.31 23.49 3.07 87.58 -28.86 A=B 0.59 16-18-52-5W5 2335.70 DUV-56 6.18 439 376 11 23.81 0.23 1.93 27.02 3.28 83.20 -28.23 A>B 0.57 10-4-51-24W4 1673.20 DUV-59 11.15 431 501 11 6.81 0.33 2.17 33.56 0.66 81.23 -27.69 A>B 1.10 14-29-48-6W5 2721.40 DUV-67 2.70 444 204 15 27.93 0.12 0.86 23.33 3.50 86.11 -27.17 0.16 01-28-36-3W5 3013.40 DUV-61 4.62 450 146 20 49.77 0.16 1.45 28.92 0.31 77.21 -27.87 0.43 A = alginite B= bituminite towards the deep, western part of the WCSB adjacent to the overthrust belt (Creaney and Allan, 1990). 3.4.2.3 Organic Petrology Microscopically, the Duvernay shales are dominated by low-reflecting, fluorescing to non-fluorescing amorphous bituminite (Figure 3.4). Common are inclusions of alginite, possible acritarchs, and liptodetrinites. Some samples contain, sporinite and coccoidal alginite macerals. Abundant mineral matter is in the form of calcite, pyrite, observed in white light excitation. In detail, samples are dominated by brown amorphous bihiminite (bitAxminite I; Teichmuller and Ottenjann, 1977) that commonly occurs as bedding parallel thick lenses or bands (Figure 3.4A and E), and well-preserved yellow-fluorescing alginite in blue light excitation. Matrix bituminite is intermixed with the groundmass (Figure 3.4B, C, and D). Common alginite dispersed organic matter present are unicellular prasinophyte alginite, acanthomorphic acritarchs? (Figure 3.4C), and liptodetrinite-sized macerals (Figure 3.4A) that may be wispy lamalginite. Some samples contain Tasmanites (Figure 3.4B), unusual dinoflagellate, and coccoidal alginite. In white light the cloudy white matrix is dominated by varying amounts of dominantly large calcite and quartz grains and pyrite framboids (Figure 3.4B and F). Changes to the character organic matter are observed with a passing through the hydrocarbon generation window. Immature samples contain more amorphous material, 98 Figure 3.4: Photomicrographs of dominant inorganic and kerogen components commonly found in the Duvernay shale. All photomicrographs were taken using reflected light and oil immersion objectives; a-e are taken under blue light. A) Amorphous dark brown bituminite (b) occurring as lens-like streaks are dominant in this sample (DUV-53). Liptodetrinite (1) is sparse. B) Large well-preserved alginite is abundant in this sample (DUV-56), including a thick?-walled Tasmanites (t). Pyrite framboids (p) are found occurring within the walls of a thin alginite. Matrix bituminite (mb) is found associated with mineral matter (mm). C) Yellow fluorescing acritarch? (ac) showing spikey morphology. Matrix bituminite (dark brown) is intermixed with groundmass. D) This organic-rich (11.15 wt% TOC) sample contains more abundant liptinite, and liptodetrinite with wavy character. E) Matrix bituminite (mb) and mineral matter (mm) relationship. Thin alginite (a) is stringy. F) Same as E), but in reflected white light. Pyrite framboids (p) are common and fluoresce strongly. qq that diminishes gradually with increasing maturity and are replaced by solid bitumen in more mature samples. The amorphous matter changes colour from orange brown to grey to granular from immature to mature. Kerogen fluorescence also decreases with maturity. Minor secondary exsudatinite occurs within fractures of the rock or bedding parallel in samples at or above the oil window. 3.4.2.4 Nature of Organic Matter The kerogen isotopic composition values range from -27.17%o to -29.32%o which is indicative of largely marine organic matter. The samples containing more bituminite have a lighter isotopic signature (~ -29.00%o, Figure 3.4A) than samples with relatively more alginite (~ -28.00%o, Figure 3.4B). There is no relationship between the compositions of organic matter, represented by SC.13, with hydrogen index values (Figure 3.5a). The kerogen from the Duvernay samples are Type II, marine organic matter and is characterized by moderately high HI and low O l values (Figure 3.1). The TOC content, HI values of ~500 mg H C / g TOC, and the dominantly amorphous and alginite kerogens, suggest the Duvernay samples are of oil-generating, organic facies B (Table 3.4, Figure 3.3). Evidence suggests that euxinic conditions existed in water depths on the order of 100 m in the East Shale Basin (Stoakes, 1980). Deposition was in anoxic, marine, deep-water, low-energy, basinal conditions. The main reasons for preservation of abundant organic material in this rich source rock are anoxic conditions, combined with slow sedimentation rates within this depositional basin. 100 a) 600 U 550 M 500 U.450 g> 400 S 350 -300 • o o - • o o • • 1 1 O <430 Tmax • 430-440 Tmax i 0.00 2.00 4.00 6.00 8.00 TOC (wt%) 10.00 12.00 b) -27.00 CO u 0. -27.50 -28.00 -28.50 -29.00 -29.50 30 i 2.00 i i 4.00 6.00 i 8.00 10.00 12 - R2 = 0.87 • -• • < 440 Tmax 00 TOC (wt%) Figure 3.5: Organic matter plots for Duvernay samples within and below the oil window: a) TOC versus Hydrogen Index (HI) b) TOC versus 5C 1 3 ; c) 5C 1 3 versus methane sorption capacity. 101 The samples with the highest organic carbon abundance contain more alginite than bituminite. There is a strong positive correlation between TOC and kerogen isotopes at <440°C (r2 = 0.87 Figure 3.5b). A few organic lean samples have abundant bituminite and show sparse well-preserved alginite and poorly preserved alginite/liptodetrinite. The two more mature samples show decreased fluorescence of alginite and more solid bitumen. . . 3.4.2.5 Organic Matter and Sorption Capacity- . Sorption capacity has a strong positive correlation with TOC (r2 = 0.97), therefore organic matter content masks any effects with maturity. Therefore the relationship between kerogen isotopes and sorption capacity (r2 =0.82; Figure 3.5c) is inherent. Samples with more organic matter contain relatively more alginite than bihiminite. 3.4.3 Upper Devonian - Lower Carboniferous Exshaw Formation During the Devonian - Mississippian, significant organic-rich marine source rocks were deposited throughout much of the Western Basin, including the Exshaw Formation. These strata are stratigraphically equivalent to the Devonian gas shales of the United States. These organic rich muds accumulated in a marine shelf setting while an epicontinental sea covered the basin. The Exshaw Formation lies in the Cratonic Platform in Alberta, is bounded on its western side by the Prophet Trough, and borders the Bakken Formation at the Alberta-Saskatchewan border near the Sweetgrass Arch. It 102 is found across much of Alberta subsurface, northeastern British Columbia and outcrops in the Front Ranges of the Canadian Cordillera. Typical Exshaw shale is dark grey to black, hard, very finely laminated (locally pyritic), fissile or platy. The laminations consist of very fine silt, and Organic-rich layers. 3.4.3.1 Previous Work The geochemistry of the Exshaw Formation has been documented by many authors, including Leenheer, (1984) Price et al. (1984) Creaney and Stokes, (1987) and Creaney and Allan (1990). More recently, Caplan and Bustin, (2001) did organic geochemical profiles for HI and TOC. Caplan and Bustin, (1996) looked at pyrolysis and organic petrology. From hydrogen indices, organic matter is predorninantly marine, Type II kerogen. 3.4.3.2 Geochemistry Geochemical data run on the Exshaw samples selected for this study show varying organic carbon, Tmax, and HI values (Table 3.6). The samples range in TOC content from 1.62 to 11.85 wt% and Tmax from 420°C to 455°C. The HI vs. O l plot (Figure 3.1) suggests Type I and II organic matter. One sample has an HI value of 834 mg H C / g TOC. The mature samples show a sharp decrease in HI values (Figure 3.2) because of 103 Table 3.6: Location, depth, organic carbon (TOC), Rock-Eval Pyrolysis parameters, geochemistry, moisture and ash data, petrography, and methane sorption capacity of samples from the Exshaw Formation, Western Canadian Sedimentary Basin. The samples are shown with increasing TOC within a maturity range. Rock-Eval parameters CNS data analyses (wt%) Langmuir Well Location Depth (m) Sample TOC (wt%) Tmax C9 HI (mg Ol (mg HC/g TOC C02/gTOC) %Carbonate %N %Stotal C / N moisture ash 6C13 org Petrography Methane sorption (cc/g) @ 5MPa 10-17-80-24W5 1781.92 EX-29 3.36 420 407 8 1.15 0.18 2.41 18.60 2.32 85.80 -28.41 A=B 0.43 10-17-80-24W5 1782.28 EX-30 6.11 422 596 8 9.46 0.21 2.56 29.69 0.89 91.89 -27.78 A>B 0.59 10-17-80-24W5 1783.24 EX-31 11.85 423 671 6 14.04 0.50 1.49 23.55 1.26 88.78 -28.30 A=B 1.37 16-30-77-25W5 2023.35 EX-26 8.91 432 621 6 1.17 0.34 1.46 26.47 0.69 78.83 -28.38 A=B 1.23 10-21-78-1W6 2084.12 EX-25 8.95 430 834 5 13.79 0.25 1.88 35.56 0.61 86.81 -28.09 A=B 1.05 10-21-78-1W6 2084.48 EX-28 9.95 432 706 7 15.69 0.34 2.25 29.59 0.90 82.31 -28.14 0.79 1-20-1-24-W4 2794.00 EX-37 1.62 449 44 0 2.80 0.08 1.34 21.38 0.30 80.41 -28.34 0.25 1-20-1-24-W4 2789.25 EX-35 10.62 455 39 0 2.53 0.59 4.95 18.12 0.60 95.94 -27.89 1.67 1-20-1-24-W4 2791.00 EX-36 7.94 460 76 8 5.89 0.41 4.18 19.46 0.00 81.41 -28.00 0.99 A = alginite B= bituminite o 4>. the maturity trend of the Exshaw exhibits a southwesterly maturity increase and stratigraphic deepening. 3.4.3.3 Organic Petrology The matrix of the Exshaw shale is predominantly silty, and the organic matter comprises mostly well-preserved alginite and weakly fluorescing matrix-bound bitximinite (Figure 3.6). The bitiirriinite is possibly fluoramorphinite (Seriftie, 1988) variety showing a sieve-like matrix (Table 3.1). Rare are sermfusinite, vitrinite and inertinite macerals. Pyrite is common and is seen bedded or occurring within Tasmanites alginite cysts. Well preserved Tasmanites prasinophytes of marine algal origin are the dominant macerals (Figure 3.6B, C). Thick-walled Tasmanites prasinophytes are found in northern Alberta, and thin-walled Tasmanites and delicate Leiospheres in southern Alberta (Caplan, 1997). Bitiirriinite is diffuse red-brown fluorescing organic matter associated with the clay matrix (Figure 3.6B, C). Laminae of minor amounts of angular mertodetiinite and vitiodetrinite macerals indicate a minor supply of terrestrially derived organic matter (Figure 3.6D, E and F). Reworked vitiodetiinite and mertodetiinite macerals are scattered. With maturation, the fluorescence intensity of alginite decreases. The matrix is too dark in most mature samples to identify components. 105 Figure 3.6: Photomicrographs of dominant inorganic and kerogen components commonly found in the Exshaw shale. A l l photomicrographs were taken using reflected light and oil immersion objectives; a-c are taken under blue light. A) Pyrite framboids (p) within a bright yellow-reflecting Thin-walled Leiosphaeridia (I) alginite. B) The matrix of Exshaw samples consist of a matrix moderately abundant with fluoramorphinite or lamalginite (1). Concentrated thin-walled Leiosphaeridia (I) alginite is present. Tasmanites-like CT) alginite is showing pore canals, viewed parallel to bedding. C) Brightly fluorescing Tasmanites CT) alginite and Prasinophyte alginite embedded in this dark matrix. Faint thin yellow lamalginite present in matrix. D) Same as in C, in white light reflection. Dark-brown streaks are lamalginite. Matrix contains minute vitrinite, semifusinite, and inertinite particles, usually elongate to matrix. E) A n immature Exshaw sample (compare to F). The matrix is dominantly quartz-rich and layer interbedded with lamalginite. Embedded in this image is an inertinite (i). F) Sample EX-36, overmature with respect to the oil window, show an equigranular texture, and small grains. Abundant pyrite and tiny maceral particles are dispersed. 106 3.4.3.4 Nature of Organic Matter The carbon isotope value ranges from 27.78%o - 28.41 %o. The average 8C 1 3 value is -28.15%o indicating dominantly marine derived liptinite and minor terrigenous material. The immature and mature samples with respect to the oil window have HI values indicative of B to A organic facies and Type II to Type I kerogen types respectively (Figure 3.3). Carbonate-poor sequences containing organic facies A usually contain discrete algae (Hutton, Kantlser, and Cook, 1980). Suspension deposition occurred in an anoxic, quiescent environment (Caplan and Bustin, 1998), below storm wave base (Caplan and Bustin, 1996). There is a weak positive correlation between TOC and HI for samples below 450°C Tmax (r2 = 0.55; Figure 3.7a). Hydrogen indexes positively increase (r2 = 0.74) with lighter isotopic composition (Figure 3.7c). The samples with the higher organic carbon have more well-preserved alginite. The samples with lower TOC have overall less particulate organic matter and some indistinct alginite. A plot of TOC versus 5C 1 3 (Figure 3.7b) shows general increase of TOC with lighter carbon isotopic composition. 3.4.3.5 Organic Matter and Sorption Capacity Since TOC and sorption capacity has a strong positive correlation (r2 = 0.78). Correlation between organic matter type and sorption is differentiated when the low TOC, low HI 107 a) 900 -OC) 800 -s- 700 -HC/ 600 -bo B. 5 0 0 -X 4 0 0 -3 0 0 -R2 = 0.55 o <450 Tmax 0.00 2.00 4.00 6.00 8.00 TOC (wt%) 10.00 12.00 14.00 b) c) 4 e) f) TOC (Wt%) 900 R2 - 0.12 800 700 o 600 500 All points minus -27 sample 400 R2 = 0.74 300 200 | o < 450 Tmax] 100 1 1 , 1 e-5.50 -28.40 -28.30 -28.20 -28.10 -28.00 -27.90 -27.80 -27.70 dO 3 1.60 1.40 1.20 : 1.00 ' 0.80 0.60 i 0.40 0.20 0.00 300 o < 450 Tmax 400 500 600 700 800 900 HI(mgHC/gTOQ R = 0.77 • <440 Tmax -28.50 -28.40 1.60 1.40 1.20 1.00 0.80 >0.60 0.40 0.20 — i 1 1 1 1 r—(we--28.30 -28.20 -28.10 -28.00 -27.90 -27.80 -27.70 dC13 Figure 3.7: Exshaw organic matter plots within and below the oil window: a) TOC versus Hydrogen Index (HI); b) TOC versus SC 1 3 ; c) 5C 1 3 versus Hydrogen Index; d) Hydrogen Index versus methane sorption capacity; e) 5C 1 3 versus methane sorption capacity. 1 0 8 sample is taken out. A slight increase in sorption capacity is seen from samples with lighter isotopic value (r2 = 0.77; Figure 3.7e) and hydrogen indices (r2 =0.35; Figure 3.7d), because more well-preserved alginite is observed in higher TOC samples (Type I shales). The organic matter composition of the Exshaw shales is fairly constant albeit a small data set. 3.4.4 Lower Jurassic "Nordegg" Member The "Nordegg"* Member of the Fernie Formation, is an organic-rich shale occurring in the subsurface of northwestern Alberta and northeastern British Columbia, and also outcrops (some uncertainty) in the central Alberta Foothills and Rocky Mountain Foothills. The "Nordegg" was probably deposited during the Pleinsbachian (Poulton et al., 1990) in a shallow shelf over much of the WCSB. The unit is dominantly comprised of calcareous marlstones and mudstones that are dark brown to black, hard, and variably phosphatic. The laminations are thin, organic-rich units and interbedded apatite-bearing horizons. 3.4.4.1 Previous Work Previous organic geochemical and petrographical analysis verify that the Nordegg is a good source rock, containing Type I/II organic matter, and TOC contents can reach up The "Nordegg" Member is reported with quotations as there is uncertainty with stratigraphic correlation with other Jurassic Units in the WCSB (Poulton et al, 1990; Riediger et al, 1990a). 109 to 28 wt% for immature samples (Stasiuk et al., 1988; Fowler et al., 1989; Creaney and Allan, 1990; Riediger et al., 1990a,b; Riediger, 1991). Riediger et al. (1990) and Riediger, (1991) have done detailed geochemical and petrographical work on the Nordegg Member in west-central Alberta and British Columbia. 3.4.4.2 Geochemistry Table 3.7 shows the results of Rock-Eval pyrolysis analyses and total organic carbon (TOC) results for the "Nordegg" sample set. TOC contents range from 1 to 23 wt%, and the range of Tmax values is 430°C to 554°C. A n HI versus O l plot indicates Type I and II organic matter (Figure 3.1). In this sample collection, the immature samples (>10 wt%) have higher organic matter than mature samples (<10 wt%). Hydrogen index values of >600 mg H C / g TOC in samples that range in Tmax from 430°C to 450°C suggests oil prone Type I organic matter. A few samples within the oil window with HI values less than 600 mg H C / g TOC indicate oil and gas prone Type II organic matter. With maturity, the HI values are less than 300 mg H C / g TOC, and are less than 10 mg H C / g TOC in overmature samples (Figure 3.2). The overmature samples reflect deeper burial of the "Nordegg" strata from the northeast to the southwest, paralleling the edge of the disturbed belt. 110 Table 3.7: Location, depth, organic carbon (TOC), Rock-Eval Pyrolysis parameters, geochemistry, moisture and ash data, petrography, and methane sorption capacity data of samples from the "Nordegg" Formation, Western Canadian Sedimentary Basin. The samples are shown with increasing TOC within a maturity range. R o c k - E v a l parameters C N S data . Langmiu r w i n ^ T-, i w \ c i T O C T m a x H I ( m g O I ( m g c ° 2 / g „ , „ , L „ , . , o / c ^ / V T ^ u s ^ i 3 Methane sorpt ion W e l l Locat ion D e p t h (m) Samp le M % ) ( „ Q ^ C C ) 6 %Carbonate % N % S l o a l C / N moisture ash 5 C ' 3 0 r g Petrography ( c c / j , ) @ 5 M p a 16-27-88-7W6 1300.30 N O R - 2 0 12.70 428 788 23 0.08 0.37 9.81 34.06 2.85 74.70 -28.99 B>A>T 1.27 11-19-85-3W6 1062.40 N O R - 1 8 13.34 429 762 34 10.03 0.46 3.35 29.07 3.06 75.96 -29.10 B>A>T 1.12 11-19-85-3W6 1064.17 N O R - 1 9 22.49 431 779 25 9.48 0.60 4.30 37.72 1.45 67.00 -29.31 B>A>T 1.95 13- 12-61-12W5 1687.80-1695.50 N O R - 3 9 2.07 441 459 25 42.65 0.07 0.95 31.13 0.80 81.76 -28.40 A>B>T 0.07 2-13-71-22W5 1392.91 N O R - 2 3 7.99 437 560 12 49.69 0.22 1.73 36.72 0.70 74.68 -26.21 T>A>B 0.64 4-28-69-19W5 1461.30-1468.70 N O R - 4 0 12.21 442 607 15 12.94 0.41 2.32 29.75 1.04 76.97 -28.58 A>B>T 0.91 14- 11-84-8W6 1130.50-1140.80 N O R - 4 1 13.42 440 696 11 13.37 0.38 2.11 34.98 0.88 76.56 -28.68 A>B>T 0.90 2-13-71-22W5 1397.16 N O R - 2 4 14.11 441 682 11 6.50 0.41 3.14 34.29 1.43 79.32 -28.51 A>B>T 0.90 14-14-78-2W6 1070.60 N O R - 2 1 15.62 438 815 20 30.24 0.55 3.25 28.30 1.20 69.45 -28.79 B=A>T 1.33 7-31-79-10W6 1548.23 N O R - 3 5.28 447 214 5 49.63 0.17 1.08 31.51 1.48 74.00 -28.36 0.50 7-31-79-10W6 1539.67 N O R - 1 6.82 452 264 3 12.28 0.24 3.05 28.26 2.33 86.86 -29.63 0.62 10-6-60-20W5 2453.70-2463.40 N O R - 4 3 4.43 460 151 22 42.89 0.20 1.58 22.30 1.23 84.40 -27.19 0.96 10-6-60-20W5 2448.30-2464.90 N O R - 4 4 6.27 460 122 15 32.75 0.25 2.57 24.59 1.51 82.19 -28.15 1.11 16-23-57-6W6 2377.80-2391.80 N O R - 4 5 3.01 545 10 11 44.44 0.12 1.00 25.49 0.39 83.37 -28.27 0.52 16-23-57-6W6 2377.10-2391.20 N O R - 4 6 5.34 554 9 6 37.18 0.21 2.00 25.01 0.73 81.82 -28.67 1.31 A = a lg in i te B = b i t u m i n i t e T=ter res t r ia l 3.4.4.3 Organic Petrology Visual exarrvination reveals an organic-mineral groundmass, dark brown in white-light excitation and fluoresces green-brown in blue-light excitation (Figure 3.8B, C). Embedded in the groundmass are macerals of mertinite, liptinite, and vitrinite. There are varying amount of calcite (Figure 3.8D), quartz and pyrite framboids. Two types of amorphous material are identified in the Nordegg. The first type is bituminite, occurring as either as brown fluorescing mineral organic groundmass (Figure 3.9A) or brown fluorescing fluoramorphinite (Senftle et al., 1987)/bituminite type I (Teichmuller and Ottenjann, 1977), concentrated as layers or lenses (Figure 3.8A). The second type of amorphous material is characterized by small (< 3um) whole and broken dark brown (low maturities) coccoliths set in a bituminous groundmass. The coccoliths occur as lenses and laminae within the matrix (100's pm in length and 20 to > 50 pm in width). The mertinite is abundant and sporadic as thin and angular inertodetrinite and broken and/or altered sernifusinite (Figure 3.8B). Sometimes the semifusinite are cenospheres, showing exsudatinite-filled vacuoles (Figure 3.9A, B). The most abundant form of liptinite occurs as yellow fluorescing thin alginite (<10 - 20 pm in diameter), found either as thin long stringers or as liptodetrinite particles (Figure 3.8C). The alginates are parallel to bedding, sporadic, and sometimes concentrated. Moderately abundant liptinitic macerals are thick-walled unicellular Tasmanites alginite (compressed cysts), and thin-walled Leiosphaeridia. Vitrinite is small rounded and angular particles, sometimes with oxidized rims. Sporinite is rare, and fluoresces red. 112 Figure 3.8: Photomicrographs of dominant inorganic and kerogen components commonly found in the "Nordegg" shale. All photomicrographs were taken using reflected light and oil immersion objectives; a and c are taken under blue light and others are in white light. A) Amorphous dark brown bituminite (b) occurring as lens-like streaks are dominant in this sample (NOR-1). Rare liptodetrinite wisps fluoresces weak yellow because this sample is mature. B) Abundant dispersed organic matter (22.49 wt% TOC) in this sample is in the form of particulate inertinite/semifusinites (i) that bright reflect, small elongate or broken vitrinite (v), that reflect grey. Pyrite (p) framboids are common. Bituminite (b) is very dense in the sample, reflecting a dark brown. C) Abundant thin-walled alginite occurring as bedding parallel bands and thin wispy particles. Matrix bituminite flouresces a yellow green. D) Calcite rhombs are common in some of the "Nordegg" shales, and exhibits a 'speckly' habit. E) An overmature, low TOC sample (NOR-45) containing sporadic particulate organic matter and pyrite framboids (p). The character pore structure is also smaller than immature samples reflecting burial. 113 Figure 3.9: Photomicrographs of rare components identified in the "Nordegg" shale under reflected light and oil immersion objectives. A, E and F are taken under blue light excitation and B-D are under white light excitation. A) Black in colour cenosphere (c) with brown vacuoles (v) under blue light. Green-yellow matrix bituminite (mb) groundmass contains moderately abundant alginite (a) stringers in yellow. B) Image A under white light. The cenosphere reflects brightly and the vacuoles are black. Angular semifusinite (s) particle present. C) Grey-reflecting granular solid bitumen? common in mature samples. D) Vitrinite (geopetal?) occurring within calcareous foraminifera. E) and F) show dark yellow oil globules. 114 Solid bitumen is found in mertinite 'porosity' (cell lumens). There are rare foraminifera (Figure 3.9D). With increasing thermal maturity, the bituminous groundmass looses reflectance intensity and changes to a grey reflectance. Secondary fracture filling and yellow fluorescing, exsudatinite is found in several samples. Non-fluorescing secondary solid bitumen (Figure 3.9C) and oil infills diagenetic minerals that fluoresce are rare (Figure 3.9E, F). With overmature samples, the matrix is more granular and has smaller pores (Figure 3.8E). With increasing maturity, the dark grey-brown coccoliths stand out from the light grey groundmass. 3.4.4.4 Nature of organic matter The kerogen isotopic composition values range from -26.21 %o to -29.63%o (average is -28.47%o) mdicating that some samples contain a mix of terrigenous (isotopically heavier) and marine organic matter (isotopically lighter). The variations in carbon isotopic composition appear to be related not only to terrestrial to marine ratios, the value appears to be related to alginite and bituminite ratios. Samples that contain dominantly well-preserved alginite (Figure 3.8C) have carbon isotopic compositions of -27.00%o to -29.00%o. In comparison, samples with abundant bacterially degraded bitAiminite occurring as thick lenses (Figure 3.8A), have a carbon isotopic composition of >-29.00%o. Samples with TOC values of 12 - 23 wt%) are predominantly Type I (HI is > 600 mg H C / g TOC), oil generative, organic facies A (Table 3.4, Figure 3.3; Jones, 1987). The 115 organic matter found in Type I samples is largely made up of dense lenses of bituminite with moderate to minor wispy alginite and Uptodetrinite, and sparse semifusinite and vitrinite particles. The HI values are high and the isotopic values (~-29.00%o) reflect the maceral bituminite. The samples within the oil window (TOC ranges from 2 -16 wt%), are predominantly Type II (HI is 450 - 700 mg H C / g TOC), oil generative, Organic Facies B (Table 3.4, Figure 3.3). The organic matter found in most Type II samples contains well-preserved alginite over bituminite or terrestrial dispersed organic matter, and moderate HI values reflect this. Hydrocarbon generation is chiefly oil. Based on biomarker signatures, lithology, and tectonic evidence that terrane obduction was occurring to the west during early Jurassic time (Riediger, 1991) the Nordegg was deposited in anoxic carbonate environment in a silled basin with restricted circulation. The TOC and HI show a positive relationship (r2 = 0.67 for samples <450°C; Figure 3.10a). The samples with the highest organic carbon percentages are generally characterized by a large abundance of either bituminite or alginite and moderately abundant to rare terrestrial material. The 430°C Tmax samples collected have more TOC and contain more bituminite and are Type I organic matter. Figure 3.10a shows that 430°C samples have the highest HI values. With higher TOC contents, the samples show a lighter isotopic signature (Figure 3.10b) and a high hydrogen index (Figure 3.10c). The character of the organic matter in one organic lean sample at 2.07 wt% TOC is that the dispersed organic matter is more sporadic and either as small discrete particles or 116 900 U 800 ^700 x 600 " g=500 S 400 300 0.00 A l l points R2 = 0.67 R z = 0.01 5.00 I T = 0.87 O 430 Tmax • 440 Tmax 10.00 15.00 TOC (wt%) 20.00 25.00 -26 00 --26 50°--27 00 -^27 50 -U T328 00 --28 50 --29 00 --29 50 -i • i i • -30 5.00 -40 .00 15.00 20.00 25 \ A 1 1 points minus -26 sample R 2 = 0.15 R2 = 0.61 • < V — - -^-Z^f^ 00 TOC (wt%) O 430 Tmax • 440Tmax U o to u X so o O 440 Tmax • 430 Tmax y = -52.578x - 845.94 -900-800 700 A l l 440 Tmax points minus -26 sample R2 = 0.81 500 400 -300--29.50 -29.00 -28.50 -28.00 -27.50 -27.00 -26.50 -26.00 dC13 117 nS in O H I-I o 02 QJ O < 450 R z = 0.82 -29.50 -29.00 -28.50 dC13 -28.00 2.50 si 2.00 1.50 1.00 0.50 0.00 u Ol «s O) O <450 o OO 1.20 o o R2 = 0.54 — i 1 1 1— 200 400 600 800 Hydrogen Index (mg H C / g TOC) -em--27.50 1000 Figure 3.10: Nordegg organic matter plots within and below the oil window: a) TOC versus Hydrogen Index (HI); b) TOC versus SC 1 3 ; c) S O 3 versus Hydrogen Index; d) 5C 1 3 versus methane sorption capacity; e) Hydrogen Index versus methane sorption capacity. 118 smaller well-preserved organic matter. The more mature samples have lower TOC than immature samples, and have abundant sparse non-preserved organic matter or particles. Many alginite fluoresce orange. With maturation, the vitrinite and semifusinite show the same grey reflectance in white light and the bituminite has changed into grey granular micrinite. 3.4.4.5 Organic Matter and Sorption Capacity The squared correlation coefficient between sorption capacity and TOC for all samples is 0.58 and the <450°C samples is the value is 0.92. Samples higher in organic carbon have a lighter carbon isotope value and contain organic matter that is rich in bituminite than samples lower in organic carbon. These samples are Type I organic matter (>600 mg H C / g TOC). Thus the samples with light values of kerogen isotopes (r2 = 0.28, all samples and r 2 = 0.82 <450°C samples; Figure 3.10d), and high Hydrogen Index values (r2 = 0.54; Figure 3.10e) have higher sorption capacities. In comparison, the 440°C samples have more alginite and slightly heavy isotopic value, and have lower TOC samples that the 430°C samples. Samples with a TOC content of -13 wt%, the 430°C samples have more sorption capacity than the 440°C samples (>1.00 cc/g versus -0.90 cc/g). 3 . 4 . 5 Lower Cretaceous Colorado Group The Colorado Group was deposited when global sea level was high during the Albian to Santonian, with specific sea-level maxima in the Late Albian, Early Turonian and Middle 119 Santonian (Caldwell, 1984; Haq et al., 1987). Regional tectonic downflexing of the era ton occurred as a result of crustal thickening along the western margin during the Columbian orogeny (Porter et al., 1982; Lambeck et al., 1987), and eustatic changes in sea level. An eastward tapering wedge of transgressive marine mudstone and claystone with intercalcalated sandstones of the Lower Cretaceous Colorado Group was deposited in the large epeiric sea oriented north-south in the Western Canadian Sedimentary Basin (William and Stelck, 1975; Kaufmann, 1977). The formations are the Late Albian Westgate, the Early Cenomanian Fish Scales, the Middle to Late Cenomanian Belle Fourche, and the latest Cenomanian to Middle Turonian Second White Specks. The four major regressive pulses are the Peace River-Viking, Dunvegan, Cardium-Bad Heart, and Milk River Formations. For this study, the Second White Specks and Belle Fourche Formations are evaluated and described in detail below. 3.4.4.1 Previous Work The four formations are defined by their geochemical, mineralogical, biofacies, and sedimentological characteristics (Bloch et al., 1993). For this study, the Second White Specks and Belle Fourche Formations are evaluated and described in detail below. Several authors looked at the organic petrology of the Colorado group (Creaney, 1980; Stasiuk and Goodarzi, 1988; Leckie et al. 1990; McCloskey, 1992). McCloskey (1992) described the organic matter in these rocks, explained their lateral variations, and evaluated factors affecting deposition and preservation. 120 3.4.4.2 Second White Specks Formation 3.4.4.2.1 Geochemistry Geochemical, CNS, proximate analysis, organic matter composition, and methane sorption data are shown in Table 3.8. The Second White Specks Formation contains marine, Type II organic matter (Figure 3.1) with TOC up to 12 wt% (condensed sections). TOC ranges from 2 - 4 wt%. Maturity ranges from 420 - 450°C. Hydrogen indices are ~300mg H C / g TOC, and can reach up to 450 mg H C / g TOC (Allan and Creaney, 1988). Hydrogen indices are fairly uniform and range from 100 to 300 mg H C / g TOC over the range of maturities (Figure 3.2). 3.4.4.2.2 Organic Petrology The groundmass of the Second White Specks shale is grainy and dominantly quartz, and clays, with varying calcite. The organic matter is mostly bituminite, which shows no fluorescence in blue light excitation, and is either grey and grainy or translucent brown in white. Particulate organic matter is alginite, inertinite, and vitrinite, which show degradation. The grainy matrix, termed hebamorphinite (Senftle et al. 1987) or unstructured bihiminite Type III (Teichmiiller and Ottenjann, 1977; Table 3.3) is a granular, grey-brown reflecting, dominantly non-fluorescing matrix. The bituminite is either dispersed (Figure 3.11 A) or concentrated (Figure 3.11B). Some unstructured organic matter is a 121 Table 3.8: Location, depth, organic carbon (TOC), Rock-Eval Pyrolysis parameters, geochemistry, moisture and ash data, petrography, and methane sorption capacity data of samples from the Second White Specks Formation, Western Canadian Sedimentary Basin. The samples are shown with increasing TOC within a maturity range. Rock-Eval parameters C N S analysis Proximate analysis (wt%) Langmiur Well Location Depth (m) Sample T O C (wt%) Tmax (°Q H I ( m g H C / g T O C ) O l mg C 0 2 / g T O C %Carbonate %N C / N moisture ash 6 C " o r g Petrography Methane sorbed ( c c / g ) @ 5 M P a 06-34-30-08W4 693.00 SWS-68 4.08 422 258 23 0.72 0.24 1.62 16.98 2.62 89.26 -26.62 B>T=A 0.10 10-36-11-29W4 2638.00 SWS-75 3.29 431 292 11 17.23 0.18 2.16 18.24 1.06 89.39 -25.68 B>T>A 0.34 04-13-54-18W5 2100.89 SWS-80 1.88 442 195 12 5.19 0.18 1.84 10.24 1.41 93.19 -24.68 B>T=A 0.11 04-13-54-18W5 2098.90 SWS-76 2.07 442 195 12 5.17 0.19 2.14 11.08 0.94 93.26 -28.31 B>A>T 0.48 04-13-54-18W5 2104.00 SWS-77 2.11 441 296 10 6.86 0.19 2.24 11.31 1.50 92.84 -24.95 B>T>A 0.29 04-13-54-18W5 2102.42 SWS-81 2.32 441 296 10 8.45 0.19 2.25 12.19 0.95 92.90 -25.05 B>T=A 0.19 14-29-13-29W4 2756.66 SWS-13 2.71 453 88 34 21.86 0.15 2.12 17.78 0.67 88.53 -26.27 B>T>A 0.48 14-29-13-29W4 2759.17 SWS-78 3.48 445 136 24 29.36 0.16 1.94 21.33 0.67 87.84 -25.78 B>T>A 0.37 14-29-13-29W4 2760.7? SWS-72 4.39 445 132 24 29.67 0.19 1.49 23.66 0.67 85.35 -25.76 B>T>A 0.53 A = a l g i n i t e B = b i t u m i n i t e T= te r res t r ia l light brown in white light and is elongate and parallel to bedding, and sometimes contains inclusions of yellow fluorescing liptodetrinite. Liptodetrinite is common as wispy and particulate lamalginite and other alginite (Figure 3.11C, D). Well-preserved alginite present is Tasmanites-type, Leiosphere-type, possible Boytrococcus and prasinophytes. Terrestrial organic matter is commonly degraded (Figure 3.11A). The mertinite is small and angular. Well-scattered vitrinite is pitted, 'shard'-like, and sometimes has oxidation rims. Cutinite and sporinite are rare. Mineralized foraminifera are abundant in carbonate-rich samples (Figure 3.11F). Pyrite framboids are common. With maturation the alginite becomes indistinct and loses fluorescence intensity (Figure 3.HE). The concentrated bituminite may be micrinite. Rare exsudatinite or fluorescing oil-bearing inclusions are observed, mertinite and vitrinites are indistinct, showing the same grey reflectance at a mature stage. 3.4.4.2.3 Nature of Organic Matter Kerogen isotopic values range from -24.68%o to -28.31 % o . The samples with a heavier isotopic signature contain relatively more terrestrial organic matter. For example, samples SWS-80 and 81 contain concentrated blocky bituminite that is not bound to the matrix. The abundance of non-fluorescing unstructured organic matter is possibly a precipitate of humic acids derived from terrigenous organic matter (Littke, 1993). Vitrinite is common as degraded elongate stringers parallel to bedding or as blocky fragments. Minor alginite is indistinct but is round (coccoidal alginite?). Sample SWS-76, has an isotopic value of -28.31 %o and predominantly contains non-fluorescing, 123 Figu re 3.10: P h o t o m i c r o g r a p h s of d o m i n a n t i no rgan ic a n d ke rogen c o m p o n e n t s c o m m o n l y f o u n d i n the S e c o n d W h i t e Specks shale. A l l p h o t o m i c r o g r a p h s w e r e taken u s i n g reflected l i g h t a n d o i l i m m e r s i o n objectives; c-e are taken u n d e r b lue l igh t . A ) G r a n u l a r da rk b r o w n mat r ix . T h e o rgan ic mat ter is t e rmed H e b a m o r p h i n i t e (H) a n d occurs as concentra ted a n d d i s p e r s e d forms. D e g r a d e d a n d sha rd - l i ke iner tode t r in i te (i) a n d deg raded v i t r i n i t e (v) are d i spe r sed t h r o u g h o u t the ma t r ix . B) H e b a m o r p h i n i t e (H) is concent ra ted as a t h i ck b a n d i n this m i n e r a l matter (mm) d o m i n a t e d ma t r ix . S m a l l v i t r i n i t e (v) is either elongate o r r o u n d i s h par t ic les . C ) P ras inophy te? a lg ini te a n d l ip tode t r in i te . T h e g r e e n - b r o w n mat r ix is the a m o r p h o u s o rgan ic a n d m i n e r a l matter mat r ix . D ) T h i n - w a l l e d a lg in i te a n d w i s p y l ip tode t r in i te . E) A mature s a m p l e w i t h a lg in i te (coccoidal?) ind i s t inc t a n d w i t h decreased f luorescence in tens i ty . F) M i n e r a l i z e d foramini fe ra . 124 translucent brown reflecting biturrtinite parallel to bedding, with alginite particles. In blue fluorescence the colour of the matrix is a dark brown. The TOC and HI values (~ 300 mg HC/TOC) correspond to kerogen Type II and organic facies B-C (Table 3.4, Figure 3.3). The low HI values (<600 mg HC/TOC) in this shale, and common for Cenomanian to Turonian shales (Dean and Arthur, 1989), is from the degradation of primary marine biomass (non-fluorescing biturninite) instead of a mixing of H-rich marine with H-poor terrigenous organic matter (Taylor et al., 1988). The presence of non-fluorescing organic matter, and degraded organic material, with low HI values indicate that these samples are of moderate hydrocarbon generation. Most samples are within the oil window (Figure 3.2). The samples with the highest organic carbon (-4.00 wt%) versus samples with lower organic carbon (-2.00 wt%) show no difference in maceral types seen in petrography except for an increase in overall organic matter abundance (small data set and TOC range). The OM-rich samples have more of bituminite, alginite, and terrestrial macerals. A relationship between TOC and carbon isotopes is seen when an isotopically light sample is taken out of the regression (Figure 3.12a). The r 2 equals 0.98 showing that with increasing TOC, the samples show a lighter isotopic signature. 125 -24.50 -25.000. -25.50 00 -26.00 1 CO 0-26.50 i -27.00 -27.50 -28.00 -28.50 1.00 O 2.00 o 3.00 4.00 5.00 FT = 0.04 A l l points minus • 28 sample R2 = 0.98 O < 450 Tmax TOC (wt%) •o ra u £ o D H tH o fi s ra 01 too ra p-i o <450 - e r e o --28.50 -28.00 -27.50 -27.00 -26.50 -26.00 -25.50 -25.00 -24.50 dC13 Figure 3.12: Second White Specks organic matter plots within and below the oil window: a) TOC versus SC 1 3 ; b) S O 3 versus methane sorption capacity (cc/g). 126 3.4.4.2.4 Organic Matter and Sorption Capacity There is no relationship between sorption capacity and TOC for all samples (r 2 = 0.07). With increasing organic carbon contents, the carbon isotopic value is slightly negative (r = 0.35; Figure 3.12b) indicating that these samples have slightly more alginite, and sorption capacity slightly increases (r2 = 0.35). One sample with a -28.00%o signature at with a TOC content of ~ 2 wt% does not fit in the regression in Figure 3.12a and has the highest sorption capacity compared to similar samples. 3.4.4.3 Belle Fourche Formation 3.4.4.3.1 Geochemistry The Belle Fourche Formation samples contains a mix of marine, Type II organic matter and terrigenous, Type III organic matter (Figure 3.1). TOC abundances that have <2 wt% TOC contain organic matter dominantly of Type III (terrestrial). Shales with >2 wt% TOC usually contain more Type II (marine) organic matter. The Type II shales occur near transition to the overlying Second White Specks Formation (Bloch et al., 1993). In this study, total organic carbon contents are up to 4 wt%. Hydrogen indices reach up to 300 mg H C / g TOC for immature samples (Table 3.9). Hydrogen indices drop down to 40 mg H C / g TOC in one 450°C sample. The sample ranges in maturity from 425 - 450°C (Figure 3.2). 127 Table 3.9: Location, depth, organic carbon (TOC), Rock-Eval Pyrolysis parameters, geochemistry, moisture and ash data, petrography, and methane sorption capacity data of samples from the Belle Fourche Formation, Western Canadian Sedimentary Basin. The samples are shown with increasing TOC within a maturity range. Rock-Eval parameters CNS analysis analysis (wt%) Langmuir Well Location Depth (m) Sample TOC (wt%) Tmax HI (mg HC/g OI(mgC0 2/g CC) TOC) TOC) %Carbonate %N C / N moisture ash 5C 1 3 Petrography Methane sorption (cc/g)@5MPa 8-25-12-24W4 8-25-12-24W4 1340.70 1340.00 BELLE-140 BELLE-139 1.44 2.07 425 425 290 290 16 16 1.93 0.13 0.15 0.15 2.32 2.30 14.93 13.44 1.44 1.61 92.42 92.87 -26.55 -26.25 V=B>A V>B>A 0.33 0.47 06-07-12-28W4 06-07-12-28W4 2594.20 2594.00 BELLE-134 BELLE-133 1.50 3.21 439 439 120 120 14 14 1.41 5.92 0.17 0.17 2.32 3.22 8.80 19.00 1.16 0.79 94.58 92.16 -25.67 -24.93 V>B>A V>B>A 0.31 0.42 09-09-56-19W5 09-09-56-19W5 2268.63 2268.00 BELLE-132 BELLE-131 3.96 4.11 446 446 266 266 14 14 8.04 8.88 0.24 0.24 2.76 2.93 16.44 17.33 1.29 1.15 90.20 90.38 -23.74 -24.00 V>B>A 0.35 0.72 14-29-13-29W4 2769.28 BELLE-136 1.29 450 39 16 1.65 0.16 2.48 8.28 0.87 95.01 -25.79 V>B>A 0.35 A = a lg in i te B = b i t u m i n i t e T=ter rest r ia l 3.4A.3.2 Organic Petrography The Belle Fourche Formation samples are a dominantly inorganic groundmass (silty) with low organic carbon. Observed are abundant vitrinite and small amounts of bituminite and minute alginite. Vitrinite is the dominant maceral contributing the TOC content (Figure 3.13A). The vitrinites (high relief) are commonly elongate to bedding and show degraded and oxidation features. Edges of blocky vitrinites appear fused with the matrix, and the edges are dark showing oxidation. Vitiodefrinite is also common. Pyrite is embedded within a large vitrinite particle. Bituminite is minor, and occurs as dark brown reflecting diffuse matrix-type (Figure 3.13C), non-fluorescing bituminite type III (Teichmuller and Ottenjann, 1977). Some concentrated blocky biliirninite are present in a few samples (Figure 3.13A). Alginite is minor and small and is of a variety of types. Possible types present may be prasinophytes, Leiosphaeridia, coccoidal alginite (Pila), and lamalginite (Figure 3.13B). With increasing maturity, the fluorescence intensity of alginite decreases. Alginite may have disappeared due to volatilization and some have transformed into opaque residues. Vitrinite shows degradation. 129 Figure 3.13: Photomicrographs of dominant inorganic and kerogen components commonly found in the Belle Fourche shale. All photomicrographs were taken using reflected light and oil immersion objectives; b and d are taken under blue light. A) Quartz-rich matrix with concentrated, elongate dark brown bituminite (b) and vitrinite (v). Framboidal pyrite (p) is common. B) Alginite is minor and sparse throughout the matrix and are small and indistinct to classify. Bituminite (b) is non-fluorescing. C) Dispersed bituminite (b), matrix bituminite, vitrinite (v) and pyrite (p). 130 3.4.4.3.3 Nature of Organic Matter The carbon isotope values for Belle Fourche samples range from -23.74%o to -26.55%o. The samples with carbon isotopic values of around -24.00% are dominated by terrigenous derived vitrinite. Samples with values ~26.00%o contains more alginite, but vitrinite is the most abundant. Samples with <2.00 wt% TOC have lighter carbon isotopic signature than samples with >2.00 wt% TOC (Figure 3.14a). The TOC and HI values in combination with the petrography indicate organic facies B-C for the Belle Fourche samples (Table 3.4 and Figure 3.3). Samples with higher HI values samples contain slightly more marine organic matter and lighter isotope values than samples with lower HI values and relatively more vitrinite and a corresponding heavier isotopic signature. The samples with higher HI also plot as Type II organic matter versus the lower HI samples plotting within Type III kerogen pathways (Figure 3.1). A weak positive correlation with TOC and HI exists as there is a mix of Types II and III organic matter as seen with other Cretaceous shales in the Western Interior (Gautier, 1985; Davis, 1987; Dean and Arthur, 1989). In general, Belle Fourche Formation proximal facies are more deeply buried and mature than distal facies. Belle Fourche Formation samples with a greater abundance of organic carbon and higher HI values are from the central and eastern parts of the basin, where sedimentation rates were lower and open marine conditions existed. Low TOC (<2 wt%) and HI (<200 mg H C / g TOC) values are characteristic of more proximal depositional environments of the Western Interior (Dean and Arthur, 1989; Bloch and Krouse, 1992; McCloskey and Bustin, 1992). Some loss of organic carbon and a reduction in HI values also may result from the 131 u T3 -23.50 -24 -24.50 -25.00 -25.50 -26.00 -26.50 -27.00 ocP-PO 1.00 5.00 R = 0.88 O < 450 Tmax TOC (wt%) o •a a, S H O in ai C brj -0:80--0:00--27.00 -26.50 -26.00 -25.50 -25.00 dC13 -24.50 -24.00 -23.50 Figure 3.14: Belle Fourche organic matter plots for samples within and below the oil window: a) TOC versus 8C 1 3 ; b) 5C 1 3 versus methane sorption capacity. 132 increased maturity of the more proximal sediments. TOC abundance is not variable and the petrographic composition of all the samples is similar. The higher TOC Belle Fourche samples contain more vitrinite particles. 3.4.4.3.4 Organic Matter and Sorption Capacity TOC and sorption capacity has a weak positive relationship (r2 = 0.44). TOC and carbon isotopes are positively related (r2 = 0.88), where the high TOC samples contain heavier isotopic kerogens (Figure 3.14a). Therefore sorption is higher for samples containing a heavier 5C 1 3 signature; the correlation is very weak (r2 = 0.19; Figure 3.14b) because TOC and sorption has a weak correlation. 3.6 DISCUSSION 3.6.1 Comparison of Shale Geochemical Properties The samples have different inorganic/ organic compositions, organic matter types, and abundance (Table 3.10). The deposition, evolution, nature, and geochemistry are compared below. 133 T a b l e 3.10: T a b l e s u m m a r i z i n g p h y s i c a l a n d c h e m i c a l p r o p e r t i e s o f W e s t e r n C a n a d i a n B a s i n S h a l e AGE FORMATION SHALE TYPE KEROGEN TYPE HI (mg HC/g TOC 5C'3 r/j Dominant OM TOC (Wt%) SORPTION CAPACITY (cc/g) TOC vs. sorptior r2 Upper Devonian Duvernay TOC-rich carbonate-rich, clay poor, mst, est II 550 -28.29 Bituminite/ Alginite 2-11 0.59 - 1.23 0.96 Late Devonian-Early Mississippian Exshaw TOC-rich, carbonate-poor, clay rich, ms l/ll 600 -28.47 Matrix bituminite, well-preserved alginite 2 - 2 8 0.20-1.10 0.74 i Lower Jurassic "Nordegg" Member, (Fernie Formation) TOC-rich, carbonate-rich, clay poor, mst, est l/ll 700 -28.15 Bituminite/ alginite, inertinite, minor vitrinite 2 - 1 0 0.64- 1.95 0.78 Lower Cretaceous Second White Specks TOC-rich, clay poor rich ms II 300 -25.05--28.31 Bituminite, vitrinite, minor alginite 1 -4 0.42 0.07 Lower Cretaceous Belle Fourche TOC-poor, clay poor rich ms ll/lll 300 -25.85 Vitrinite, minor bituminite, alginite 1 -4 0.34 0.44 3.6.1.1 Organic matter deposition The varying organic matter abundances and compositions of the organic-rich shales are controlled by depositional environment and changes through time with the evolution of the basin. In general, sedimentation in the Western Canadian Sedimentary Basin can be divided into two distinct tectonic settings. During the Paleozoic to Jurassic miogeocline and platform stage, carbonate rocks were deposited on the stable adjacent passive margin of North America. The sediments formed a wedge tapering from 6 km thick in the west to zero in Manitoba. Marine phytoplankton, zooplankton, and bacteria were major contributors to organic matter since the Cambrian to the Jurassic, (Tissot and Welte, 1984). The organic-rich (>5 wt%) Nordegg, Exshaw, and Duvernay shales examined in this study are found in this succession (Figure 3.15b). The organic matter is Type I and/or II kerogen and is composed of bituminite and/ or alginite. The Nordegg contains more terrestrial-derived organic matter vitrinite and inertinite than the older shales but the terrestrial organic matter does not contribute much to the TOC content. In the mid-Jurassic to Paleocene, clastic rocks formed a foreland basin succession during active margin orogenic evolution of the Canadian Cordillera. The organic-lean (<5 wt%) Colorado Group Second White Specks and Belle Fourche shales examined in this study were deposited in the foreland basin succession during the Cretaceous (Figure 3.15a). Clastic dilution may be an important factor in lowering the TOC content of the sediments (Gautier, 1985) during deposition of these shales when oxygen was deficient 135 MID-JURASSIC-PALEOCENE FORELAND BASIN Vascular plants with high level of evolution DEVONIAN TO JURASSIC: PLATFORM, MIOGEOCLINE Vascular plants present lower level of evolution LAGOONAL, M ^ Figure 3.15: Generalized cross-section from continent to ocean for two major sedimentation stages of the Western Canadian Sedimentary Basin (Modified from Stasiuk, 1999). a) The Mid-Jurassic to Paleocene foreland basin succession contains the Second White Specks and Belle Fourche Formation deposited where reduced oxygen conditions occur. Organic Facies are plotted and the shales are C and BC Organic Facies. b) The Devonian to Jurassic platform stage contains the Nordegg, Exshaw, and Duvernay shales deposited in a large marine anoxic basin. Organic Facies are A and B. 136 in the basin. Deposition of terrestrial organic matter began confributing in the Devonian and was dominant during the Cretaceous to Recent (Tissot and Welte, 1984). A mix of terrestrial or marine organic matter comprises the organic matter content. The Second White Specks contains Type II organic matter, dominated by a mix of bituminite and vitrinite, with minor alginite. The Belle Fourche Formation contains organic matter of Type II/III kerogens, and vitrinite is the predominant maceral. The evolution of the Western Canadian Sedimentary Basin shales reflects what is occurring globally. Through the Phanerozoic, the evolution of life provided sediments with more organic matter from the land (Tissot and Welte, 1984), and the qualitative diversity and abundance of petroleum source rocks increased. However marine environments favourable for deposition of facies enriched by sapropelic (Type II) organic matter (black shales) gradually eliminated and environments favourable for Type III organic matter flourished and are abundant in the Tertiary (Klemme and Ulmishek, 1991). The changes are due to: (1) decreased aerial extent of Type II organic matter deposition; (2) a change from low latitudes (carbonate and evaporate seals) favourable for Type II deposition, preservation, and effectiveness*, to high latitudes favourable for Type III deposition; (3) deposition of source rock in platforms open to oceans during the early and Middle Paleozoic to deltas and half sags by the Oligocene-Miocene; and (4) biological evolution of different groups of producers and consumers evolved and resulted in the decreased variety of conditions suitable for the preservation of Type II organic matter. More extensive discussion is found in Klemm and Ulmishek *the amounts of discovered original conventionally recoverable reserves of oil and gas generated by these rocks (Klemme and Ulmishek, 1991) 137 (1991). Thus several factors controlled the aerial distribution of source rocks, their geochemical type, and their effectiveness including geologic age, paleolatitude of deposition, structural forms where deposition occurred, and evolution of biota (Klemme and Ulmishek, 1991). 3.6.2.2 Organic Matter Composition Variations in carbon isotopic composition ratios are both related to terrestrial/marine organic matter ratios and to algmite/bituminite organic matter ratios (Goodnight et al., 2002). Shales such as the Duvernay, Exshaw, and Nordegg, contain organic matter-rich in algal matter (largely alginite and bituminite) and show organic carbon isotopic values ranging from approximately -27.00%o to -30.00%o (average ~-28.00%o). Samples with 5C 1 3 values of <-29.00%o contain abundant bituminite. Samples containing more alginite than bituminite have carbon isotopic values of -27.00%o to <-29.00%o. The higher TOC content samples of the Duvernay and Nordegg are bituminite-rich. The Exshaw contains mostly alginite. Second White Specks and Belle Fourche shales contain organic matter rich with a mix of terrestrial and marine organic matter, and have isotopic values from -24.00%o to -27.00%o (average ~-25.00%o). Organic matter within the Second White Specks is dominantly amorphous bituminite that occurs as matrix-bound organic matter. The heavy isotopic kerogen composition reflects the presence of terrestrial vitrinite, matrix bituminite terrestrially derived (type III organic matter), with various algal matter. The Belle 138 Fourche samples contain mostly degraded vitrinites and varying maceral and matrix bituminite. TOC increases more vitrinite and isotopic values (~ -25.00%o). 3.6.1.3 Organic Facies and Source Potential The source potential of shales and carbonates depends on the organic facies rather than the mineral matrix (Jones and Demaison, 1982). Gross chemical, pyrolysis, microscopic criteria and characteristics of classical organic facies are summarized in Table 3.4. A TOC versus HI plot (Figure 3.3) shows a positive correlation between TOC and HI and organic facies zones are approximated. Samples plotted have not undergone extensive diagenesis, as evidenced by Tmax values <440°C and therefore approximates original values (Tissot and Welte, 1984). The positive correlation between HI and TOC shows higher accumulation of algal and bituminous organic matter, versus shales with low hydrogen content containing fragments of terrestrial organic matter. For the more organic-rich shales (>5 wt%), the Nordegg (Carbonate-rich) and Exshaw (quartz-rich) samples plot as organic facies A and B and the Duvernay (carbonate-rich) is organic facies B (Figure 3.16). Organic facies A and B are oil-prone source rocks which are laminated and bedded, have moderate to high TOC, contain high quality O M , and were deposited in highly anoxic environments. Organic matter (maceral) such as prasinophytes alginite was deposited in deep waters. The anoxic environment may be pre-existing or created by the high input of O M (Demaison and Moore, 1980). Kerogens present are high hydrocarbon generating algal and amorphous (algal/bacterial origin) kerogen. The differences between the shales are minor. The Exshaw and Duvernay 139 contain minor terrestrial input. The Exshaw and Duvernay contain more discrete algae (eg. Tasmanites). The Nordegg is mostly bihiminite and lamalginite. Organic-lean shales (<5 wt%) of the Second White Specks (TOC reaches up to 12 wt%) and Belle Fourche and plot as organic facies B-C (Figure 3.16). The rocks are poorly bedded and were formed in variable, deltaic environments. Products are oil and gas and kerogen present comprises a mix of algal (degraded) marine material and terrestrial organic matter. Organic matter of the algal and amorphous type has greater potential to generate hydrocarbons than the ones in shallow, near shore, or on land masses surrounding seas and lakes (Zielinski and Mclver, 1982). 3.6.2 Comparison of Gas Potential 3.6.2.1 TOC Abundance, Maturity, and Methane Sorption For all shales sorption capacity generally increases with increasing TOC and maturation (Ramos and Bustin, 2002). The increase with sorption capacity with TOC is because TOC has high surface area for sorption. The increase with sorption capacity with maturation is related to the decrease in pore size, moisture contents, and an increase in microporosity. 140 3.6.2.2 Sorption Capacity and Organic Matter Composition The sorption capacity is indirectly related to organic matter type, nature, and depositional environment through direct correlations with TOC. High sorption capacity of shales with high TOC contents in turn contain Type I and II kerogens, have high HI values, light kerogen isotopes, and contain bituminite or alginite-rich organic matter. Low sorption capacities from TOC-low shales (Type II and III kerogens) have low HI values, heavy kerogen isotopes, and contain is a mix of terrestrial and marine organic matter. The relationship between sorption capacity and the dispersed organic matter composition is difficult to isolate. Not all shale is present at each maturity level, TOC contents do not overlap, and mineralogy varies. Isolating similar Tmax values, the r 2 between TOC and methane sorption capacity improves. For all shales, the r 2 = 0.78, and the r 2 for <430°C is 0.74, 430°C is 0.94, 440°C is 0.85, 450°C is 0.80, and 460°C and >460°C is 0.99 (Figure 3.16). The immature and mature samples have some samples >10 wt% TOC. The overmature samples have <10wt% TOC. The linear regression is good for samples with >5 wt% TOC for all Tmax levels (Figure 3.16). The <5 wt% TOC samples is more variable because the low TOC samples have lower correlation. There is minor overlap in values to compare sorption capacities. Comparisons can be made for <5 wt% TOC samples. 141 WCSB Shales <430 @ 5 Mpa -35 1-50 o g 0.50 y - 0.08x + 0.13 m = f\7d AIT SAMPI.FS •5 s 0.00 1.00 3.00 5.00 7.00 TOC(wt%) 9.00 11.00 Tmax<430 TOC 2 4 10 30 100 r2 ALL 0.29 0.45 0.93 2.54 8.14 0.78 DUV 0.18 0.39 1.03 3.17 10.64 0.95 EX 0.21 0.44 1.13 3.43 11.49 0.97 BELLE 0.46 0.91 2.28 6.83 22.77 1 W C S B Sha les 430 @ 5 M p a bo 3.00 2.50 •2- i 73 2.00 j S 1.50 5 1-00 I 0.50 0.00 y = 0.09x + 0.10 R2 = 0.94 ALL SAMPLES • B E L L E o S W S • E X A D U V X N O R 1.00 3.00 5.00 7.00 9.00 11.00 13.00 15.00 T O C ( w t % ) 17.00 19.00 21.00 23.00 Tmax 430 TOC 2 4 10 30 100 r2 ALL 0.27 0.44 0.96 2.68 8.72 0.94 BELLE 0.34 0.47 0.87 2.21 6.88 1 DUV 0.19 0.37 0.93 2.79 9.30 0.97 NOR 0.22 0.40 0.92 2.65 8.73 0.97 1.60 • 1.40 1.20 -1.00 0.80 0.60 0.40 0.20 0.00 W C S B Sha les 440 @ 5 M p a y = 0.07x + 0.10 R2 = 0.8484 ALL SAMPLES • N O R A B E L L E X D U V • S W S 1.00 3.00 5.00 7.00 9.00 T O C ( w t % ) 11.00 13.00 15.00 TOC 2 4 10 30 100 r2 ALL 0.23 0.37 0.77 2.13 6.87 0.85 NOR 0.13 0.28 0.74 2.26 7.57 0.92 WCSB Shales 450® 5 Mpa 1.00 0.80 u u T3 OJ -a u 0.40 -| c | 0.20 0.00 • BELLE o D U V o E X A NOR svvs 1.00 2.00 3.00 4.00 5.00 TOC(wt%) 6.00 7.00 ;.oo Tmax 450 T O C 2 4 10 30 100 r2 A L L 0.29 0.47 1.00 2.77 8.96 0.8 BELLE 0.36 0.68 1.65 4.87 16.15 0.56 N O R 0.26 0.40 0.85 2.35 7.58 1 svvs 0.11 0.46 1.51 5.00 17.23 1 EX 0.30 0.52 1.21 3.50 11.51 1 WCSB Shales >470 @ 5 Mpa 3.00 T 3 0J u o . . in bJO OJ 50 00 50 00 50 -| 00 y = 0.12x + 0.45 R2 = 0.99 ALL SAMPLES 6 7 TOC(wt%) x NOR >470 o 460NOR • 460 EX 10 11 Tmax 460 T O C 2 4 10 30 100 r2 A L L 0.65 0.89 1.58 3.91 12.06 0.99 N O R 0.77 0.93 1.41 3.02 8.66 1 Tmax >470 T O C A L L 2 0.19 4 0.86 10 2.87 30 9.60 100 33.12 r2 1 Figure 3.16: TOC versus methane sorption capacity for samples with similar maturities. A table below shows predictive sorption capacities from a linear equation if the samples have 2 or more points in the plot. The r 2 value is show for each set and shale (if present). 143 For samples <430°C (Figure 3.16) the r 2 between TOC and sorption capacity is 0.74. The ~2 wt% TOC Belle Fourche samples have higher sorption capacities than the 2 - 8 wt% TOC Duvernay, Exshaw, and Second White Specks samples (Figure 3.17a). The moisture capacity for the immature samples ranges up to 12 wt%. More moisture is held in the Belle Fourche and Second White Specks shales (Figure 3.17b). The moisture content is either held in the mineral matter or in organic matter. The Belle Fourche and Second White Specks contains more terrestrial organic matter (vifrinite), seen by the heavy carbon isotopic value, than the other shales. Vitrinite may be holding moisture as moisture contents increase with 5C 1 3 . For samples with 430°C Tmax, the r 2 value for TOC and sorption capacity is 0.94. The only overlap occurs at < 5wt% TOC (Figure 3.16). The Belle Fourche has higher sorption than the Duvernay and Second White Specks samples (Figure 3.18b). The moisture contents for the 430°C samples on average is 5 wt% while one Nordegg sample has 17 wt% moisture content. That Nordegg sample has more clay and a relatively low isotopic composition (inertinite and vitrinite than alginite and bituminite). The slight increase in sorption capacity for the Belle Fourche shales (Figure 3.18a) either means that clay or vitrinite is responsible for better sorption capacities. For samples at 440°C Tmax, the TOC versus methane sorption capacity r 2 value is 0.85 (Figure 3.16). Overlap occurs with Belle Fourche, Second White Specks and Duvernay and Nordegg (Figure 3.16). The Fourche and Second White Specks have higher sorption capacities and slightly higher moisture contents than the Duvernay and Nordegg 144 • DUVERNAY A EXSHAW O BELLE FOURCHE + SECOND WHITE S P E C K S DUVERNAY < 420°C Tmax b) Figure 3.17: 420°C and <420°C shales: a) TOC versus d C 1 3 versus methane sorption capacity; b) TOC versus d C 1 3 versus moisture content. 145 • DUVERNAY • NORDEGG A EXSHAW O BELLE FOURCHE + SECOND WHITE SPECKS Figure 3.18: 430°C shales: a) TOC versus d C 1 3 versus methane sorption capacity; b) TOC versus d C 1 3 versus moisture content. 146 (Figure 3.19). The moisture contents vary from 2 to 5 wt%. The vitrinite contents are high for the heavy 5C 1 3 samples. For samples at 450°C Tmax (Figure 3.20), the TOC versus methane sorption capacity r 2 value is 0.80. The Exshaw and Belle Fourche shales have slightly higher sorption capacities than Second White Specks, Duvernay, and Nordegg samples (Figure 3.16). Moisture contents are on average 3 wt% and one Exshaw has 8 wt% because of high clay contents. There are a few samples >460°C to make any compositional correlations. The sorption capacities increase with maturation. The gas capacity of gas shales increases with kerogen type (Type I, II kerogens) but isolating rank and other factors, increases with Type III kerogens. Studies from coal show that vitrinites retain more moisture due to open porous structure compared to mertinites (Levine, 1993). Inertinites contain more macroporosity (30 nm - 10 microm) and less microporosity (<2 nm) than equivalent vitrinites. Vitrinite has more hydrophilic functional groups to retain moisture when compared with mertinite (Taylor et al., 1998). The hydrophilic functional groups decrease with increasing rank due to changes in surface chemistry. Unsworth et a l , (1988) show that the total porosity and inherent moisture in coals (at 30°C) are determined primarily by rank effects. For the shales, moisture contents are negatively correlated with methane sorption capacities and are positively correlated with vitrinites at low ranks. With increasing rank, vitrinites develop more micropores creating more adsorption sites and less moisture is retained in 147 • NORDEGG A EXSHAW o BELLE FOURCHE + SECOND WHITE SPECKS Figure 3.19: 440°C shales: a) TOC versus dC 1 3 versus methane sorption capacity; b) TOC versus d C 1 3 versus moisture content. 148 • DUVERNAY EXSHAW • NORDEGG Q BELLE FOURCHE + SECOND WHITE SPECKS 1 NORDEGG 460°C EXSHAW 460°C • NORDEGG >460°C Figure 3.20: 450°C, 460°C, and >460°C shales: a) TOC versus dC 1 3 versus methane sorption capacity; b) TOC versus dC 1 3 versus moisture content. 149 spite of significant development of micropores at higher ranks. It is unclear what fraction of the moisture content is retained in clay/ mineral/ ash content or vitrinite and other organic matter. The shale samples with more vitrinite show high sorption capacities (Belle Fourche and Second White Specks) than samples with equivalent TOC contents, especially the Type II kerogen samples. It is unknown what the influence of alginite and bituminite is to the pore structure and changes with maturity. The Nordegg and Duvernay are calcareous-rich and alginite and bituminite-rich and generally contain less moisture because there is relatively less mineral matter (ash contents) and clay. 3.7 CONCLUSION Several conclusions on the relationships between organic matter and sorption capacity on a variety of organic-rich (>2 wt% TOC) shale were reached from this study. The shale are separated into two general groups, <5 wt% TOC (TOC-rich) and >5 wt% TOC (TOC-lean), and differ in depositional/tectonic environments, geochemistry, and methane sorption potential. Tectonic changes of the Western Canadian Sedimentary Basin formed shales in different sedimentary depositional environments that changed throughout the evolution of the basin. The geochemical type and effectiveness of the rocks were controlled by age, paleolatitude, structural and biological evolution. Throughout the evolution of the basin through the Phanerozoic, organic matter and the diversity and abundance of source rocks increased with time. Marine environments favourable for deposition of facies 150 enriched by Type II marine organic matter (miogeocline/platform stage) declined and environments favourable for Type III terrestrial organic matter (foreland basin) deposition increased. TOC-rich shales of the Duvernay, Exshaw, and Nordegg were deposited in the Devonian to Jurassic platform succession of the WCSB. Type I kerogens (Exshaw, and Nordegg samples) having high TOC and HI values (>600 mg H C / g TOC), contain dense lenses of bituminite (bright yellow fluorescing lamalginite and red or brown fluorescing) with moderate to minor alginite. Carbon isotopic values are ~<-29.00%o. The samples are classified as oil generative, organic facies A. Type II kerogens (Duvernay, Exshaw, and Nordegg samples) characterized by high TOC content moderate HI values (450 -700 mg HC/g) contain dominantly alginite and amorphous kerogens (red or brown fluorescing). Carbon isotopic values are ~28.00%o. The samples are classified as oil generative, organic facies B. TOC-lean shales of the Second White Specks (TOC's up to 12 wt%) and Belle Fourche shales were deposited in the Mid-Jurassic to Paleocene foreland basin succession of the WCSB. The samples with higher HI also plot as Type II organic matter versus the lower HI samples plotting within Type III kerogen pathways (Figure 3.1). Type II kerogens (Second White Specks and Belle Fourche) having low TOC and HI values (~ 300 mg HC/TOC) contains organic matter of a mix of marine macerals and terrestrial macerals with non-fluorescing bituminite. Type III kerogens (Belle Fourche) characterized with low TOC and HI values (~ 300 mg HC/TOC) contains mostly vitrinite. Carbon isotopic 151 values are ~25.00%o. Both low-TOC shales are classified as oil and gas generative organic facies B-C. Varying methane sorption capacity with organic matter type, nature, HI, kerogen isotopic composition and depositional environment are due to inherent correlations with TOC abundance. Positive correlation exists between TOC content and methane sorption capacity for high-TOC (kerogen Type I and II) shales versus low-TOC shales (kerogen Type II and III) because the low-TOC shales have more influence from pore/moisture/maturity relationships. Determining relationships between methane sorption capacity and organic matter composition is difficult for shale versus coal because TOC contents do not exceed 30 wt%, and many are very low in TOC content (2 wt%). Different organic matter abundances, compositions and maturities also make compositions difficult to isolate. Isolating rank and other factors such as mineral matter contents, the gas capacity increases with shales containing more vifrinite (kerogen Type III). Vitrinite holds more moisture at lower maturities and microporosity increases with maturity. Future work entails isolating organic matter (different kerogen types) by for example density centrifugation or kerogen isolation, and running sorption capacities and/or surface area on the extracts. More detailed work on specific formations is important as organic matter composition changes vertically and horizontally (eg. Creaney and Passey, 1993; Schiebler, 2001). Therefore, sorption capacities vary spatially. Zones of high TOC 152 identified vertically and horizontally can be used in adjunct with well logs for gas-in-place calculations. The pore structure and porosity can be measured using mercury porosimetry to correlate with the effects of maturity, shale type, and organic matter composition. 153 3.8 REFERENCES CITED Allan, J. and Creaney, S. 1988. Sequence stratigraphic control of source rocks: Viking-Belly River System (Abstract). In: D.P. James and D.A. Leckie (Editors), Sequences, Stratigraphy, Sedimentology; Surface and Subsurface. Canadian Society of Petroleum Geologists, Memoir 15, pp. 575. Allan, J., and Creaney, S., 1991. Oil Families of the Western Canada Basin. Bulletin of Canadian Petroleum Geology, 39:107-122. American Society of Testing Materials (ASTM), D-3173-73 (Reapproved 1979). Standard Test Method for Moisture in the Analysis Sample of Coal and Coke. American Society of Testing Materials, Philadelphia, Pennsylvania, pp. 387 - 391. Ayers, W.B., and Kelso, B.S., 1989. Knowledge of methane potential for coalbed resources grows, but needs more study. Oil and Gas Journal, 87: 64-67. Bloch, J., and Krouse, H.R., 1992, Sulfide diagenesis and sedimentation in the Albian Harmon Member (Peace River Formation), western Canada; Clay and Clay Minerals, v. 40: 682-699. Bloch, J., Schroder-Adams, C , Leckie, D.A., Mclntyre, D.J., Craig, J., and Staniland, M . , 1993. Revised stratigraphy of the lower Cretaceous Colorado Group (Albian to Turonian), Western Canada. Canadian Society of Petroleum Geologists Bulletin, 42: 325 PP- ; Bustin, R.M., 1997. Effect of coal composition and fabric on coalbed methane reservoir characteristics. European Coal Geology, 3 r d European Coal Conference, Publication, pp. 69-90. Bustin, R.M., and Clarkson, C.R., 1998. Geological controls on coalbed methane reservoir capacity and gas content. In: P.C. Lyons (Editor), Special Issue: Appalachian coalbed methane. International Journal of Coal Geology, 38: 3-26. Bustin, R.M., Cameron, A.R., Grieve, D.A., Kalkreuth, W.D., 1983. Coal Petrology Its Principles, Methods, and Applications. Geological Association of Canada, Short Course Notes, Volume 3. Victoria, 1983. Caldwell, W.G.E., 1984. Early Cretaceous transgressions and regressions in the southern Interior Plains. In: D.F. Stott and D.J. Glass (Editors), The Mesozoic of Middle North America. Canadian Society of Petroleum Geologists Memoir 9:173-203. Caplan, M.L., 1997. Factors Influencing the Formation of Organic-Rich Sedimentary Facies: Example for the Devonian-Carboniferous Exshaw Formation, Alberta, Canada. 1997. University of British Columbia,Vancouver, British Columbia, Canada. 1997 154 Caplan, M.L., and Bustin, R.M., 1996. Factors governing organic matter accumulation and preservation in a marine petroleum source rock from the Upper Devonian to Lower Carboniferous Exshaw Formation, Alberta. Bulletin of Canadian Petroleum Geology, 44(3): 474-494. Caplan, M.L., and Bustin, R.M., 1998. Sedimentology and sequence stratigraphy of Devonian-Carboniferous strata, southern Alberta. Bulletin of Canadian Petroleum Geology, 46(4): 487-514. Caplan, M.L., and Bustin, R.M., 2001. Palaeoenvironmental and palaeoceanographic controls on black, laminated mudrock deposition: example from Devonian-Carboniferous strata, Alberta, Canada. Sedimentary Geology, 145: 45-72. Chow, N . , Wendte, J. and Stasiuk, L.D., 1995. Productivity versus preservation controls on two organic rich carbonate facies in the Devonian of Alberta: sedimentological and organic petrological evidence. Bulletin of Canadian Petroleum Geology, 43: 433-460. Clarkson, C.R., and Bustin, R.M., 1996. Variation in micropore capacity and size distribution with composition in bituminous coal of the Western Canadian Sedimentary Basin. Fuel, 75:1483-1498. Creaney, S., 1980. The Organic Petrology or the Upper Cretaceous Boundary Creek Formation, Beaufort-Mackenzie Basin. Bulletin of Canadian Petroleum Geology, 28:112-129. Creany, S., and Stoakes, F.A., 1987. The Exshaw Formation laminites in the Peace River Arch area: pattern of maturation and migration with exploration implications for the Wabamin Group. Abstract and talk presented at the 2 n d Internationsal Symposium on the Devonian System, Calgary, 1987 Creaney, S., and Allan, J., 1990. Hydrocarbon generation and migration in the Western Canada Sedimentary Basin, In: J. Brooks (Editor), Classic Petroleum Provences. Geological Society of London, Special Publication, 50:189-202. Creaney, S., and Passey, Quinn, R., 1993. Recurring Patterns of Total Organic Carbon and Source Rock Quality within a Sequence Stratigraphic Framework. American Association of Petroleum Geologists BuUetin, 77(3): 386-401. Crosdale, P.J., and Beamish, B., 1993. Maceral effects on methane sorption by coal. In: J.W. Beamish (Editor), New Developments in Coal Geology, A Symposium. Brisbane, pp. 95-98. Crosdale, P.J., Beamish, B. Basil, Valix, Majorie, 1998. Coal methane sorption related to coal composition. International Journal of Coal Geology, 35: 147-158. Davis, H.R., 1987. Deposition of the Lower Cretaceous Mowry Shale. PhD Thesis, 1987. University Wisconsin-Madison, USA. 1987 155 Dean, W.E., and Arthur, M.A. , 1989. Iron-sulfur-carbon relationships in organic-carbon-rich sequences I: Cretaceous Western Interior Seaway. American Journal of Science, 289: 708-743. Demaison, G.J., and Moore, G.T., 1980. Anoxic Environments and Oil Source Bed Genesis. A A P G Bulletin, 64(8): 1179-1209. Espitalie, J., J.L. Laporte, M . Madec, F. Marquis, P. Leplat, J. Paulet, and A. Boutefeu, 1977. Methode rapide de caracterisation des roches meres de leur potentiel petrolier et de leur degre d'evolution. Revue de rinstitute Francais du Petrole, 32: 23- 42. Ettinger, I., Eremin, B., Zimakov, Yavovskaya, M. , 1966. Natural factors influencing coal sorption properties: I. Petrography and the sorption properties of coals. Fuel, 45: 267-275. Fowler, M.G., Brooks, P.W., and Macqueen, R.W., 1989. A comparison between the biomarker geochemistry of some samples from the Lower Jurassic "Nordegg" Member and western Canada Basin oil sands and heavy oils. In: Current Research, Part D., Geological Survey of Canada, Paper, 89-1D, pp. 19-24 Gautier, D.L., 1985. Interpretation of early diagenesis in ancient marine sediments: relationship of organic matter and mineral diagenesis. SEPM Short Course 17, pp. 6-72. Goodnight, Shane A., Rimmer, Susan M . , Creling, John C , Hugget, William W., and Atudorei Viorel, 2002. Carbon isotope variability in kerogen from Devonian-Mississipian marine black shales. 2002 Denver Annual Meeting (October 27-30, 2002) GSA. Haq, B.U., Hardenbol, J., and Vail, P.R. 1987. Chronology of fluctuating sea levels since the Triassic. Science, 235:1156-1166. Harris L.A., and Yust, C.S., 1976, Transmission electron microscope observations of porosity in coal. Fuel, 55: 233-236. Hue, A.Y., 1988. Aspects of depositional processes of organic matter in sedimentary basins. Organic Geochemistry, 13: 263 - 272. Hutton, A . C , 1987. Petrographic classification of oil shales. International Journal of Coal Geology, 8: 203-231. Hutton, A.C. Kantsler, A.J., Cook, A.C. and McKirdy, D.M., 1980. Organic matter in oil shales. A.P.E.A. Journal, 20(l):44-67. International Committee for Coal Petrology, 1963. Handbook of Coal Petrology, 1 s t Edition. Centre Nationale de la Recherche Scientifique, Paris. International ConrLmittee for Coal Petrology, 1971. Handbook of Coal Petrology, 2 n d Edition. Centre Nationale de la Recherche Scientifique, Paris. 156 International Comrnittee for Coal Petrology, 1975. Handbook of Coal Petrology, supplement to 2 n d Edition. Centre Nationale de la Recherche Scientifique, Paris. International Committee for Coal Petrology, 1994. Vitrinite classification, ICCP System 1994. International Committee for Coal and Organic Petrology, Aachen, Germany 1994. International Committee for Coal Petrology, 1997. Inertinite classification, ICCP System 1997. International Committee for Coal and Organic Petrology, Wellington, New Zealand, 1997. Jones, R.W., 1987. Organic Facies. In: J. Brooks (Editor), Advances in Petroleum Geochemistry, Volume 2. Academic Press, London, pp. 1-90. Jones J.W., and Demaison, G.J., 1982. Organic facies - stratigraphic concept and exploration tool. In: A . Saldivar-Sali (Editor), Proceedings of the Second ASCOPE Conference and Exhibition, Manila, pp. 51-68. Kauffman, E.G., 1977. Geological and biological overview. Western Interior Cretaceous Basin. Mountain Geologist, 14: 75-99. Kim, A.G., 1977. Estimating methane content of bituminous coalbeds from adsorption data. U.S. Bureau of Mines Report of Investigations, 8245 pp. Klemme, D.H., and Ulmishek, G.F., 1991. Effective Petroleum Source Rocks of the World: Stratigraphic Distribution and Controlling Depositional Factors. The American Association of Petroleum Geologists Bulletin, 75(12): 1809-1851. Lambeck, K., Cloetingh, S., and McQueen, H , 1987. Intraplate stress and apparent changes in sea level: the basins of northeastern Europe. In: G.D. Mossop and I. Shetsen (Editors), Sedimentary Basins and Basm-Forrning Mechanisms. Canadian Society of Petroleum Geologists and Alberta Research Council, Calgary, Ch. 23. Lamberson, Michelle N . , and Bustin, R. Marc, 1993. Coalbed Methane Characteristics of Gates Formation Coals, Northeastern British Columbia: Effect of Maceral Composition. American Association of Petroleum Geologists Bulletin, 77(12): 2062-2076. Langmuir, I., 1918. The adsorption of gases on plane surfaces of glass, mica, and platinum. The Journal of American Chemical Society, 40:1461-1403. Laxminarayana, C , and Crosdale, 1999. Role of coal type and rank on methane sorption characteristics of Bowen Basin, Australia coals. International Journal of Coal Geology, 40: 309 - 325. Laxminarayana, C , and Crosdale, 2002. Controls on methane sorption capacities of Indian coals. A A P G Bulletin, 86(2): 201-212. Leckie, D.A., Singh, C , Goodarzi, F., and Wall, J.H., 1990. Organic-rich radioactive marine shale: a case study of a shallow-water condensed section, Cretaceous Shaftesbury 157 Formation, Alberta, Canada. Journal of Sedimentary Petrology, 60:101 - 117. Leenheer, M.J., 1984. Mississippian Bakken and equivalent formations as source rocks in the Western Canadian Basin. Organic Geochemistry, 6: 521 - 532. Levine, J.R., 1992. Influence of coal composition on coal seam reservoir quality: a review. Coalbed Methane Symposium, Townsville, Australia, 1992:1 to XXVIII. Levine, J.R., 1993. Coalification: the evolution of coal as source rock and reservoir rock for oil and gas. In: B.E. Law, and D.D. Rice (Editors), Hydrocarbons from coal. A A P G Studies in Geology # 38, pp. 39-77. Levy, J.H., and Day, S.J., and Killingly, J.S., 1997. Methane capacities of Bowen Basin coals related to coal properties. Fuel, 76: 813-819. Li , Maowen, Yao, Huanxin, Stasiuk, L.D., Fowler, M.G., and Larter, S.R., 1997. Effect of maturity and petroleum expulsion on pyrrolic nitrogen compound yields and distributions in Duvernay Formation petroleum source rocks in central Alberta, Canada. Organic Geochemistry, 26(11-12): 731-744. Littke, R., 1993. Deposition, diagenesis and weathering of organic matter-rich sediments. Lecture Notes in Earth Sciences, 47: 218 pp. McCloskey, WG., 1992. Sedimentary Organic Matter in the Colorado Group. 1992. Vancouver, University of British Columbia. 1992. McCloskey, W.G., and Bustin, R.M., 1992. Controls on distribution of organic matter in Cretaceous black shales, Colorado Group, Western Canada (Abstract). 29 t h In. Geol. Congr., Volume 1, 238 p. Meissner, F.F., 1984. Cretaceous and lower Tertiary coal as sources for gas accumulations in the Rocky Mountains area. In: J. Woodward, F.F. Meissener, and J.L. Clayton (Editors), Source rocks of the Rocky Mountain region, Volume 1984 Guidebook. Rocky Mountain Association of Geologists, pp. 401-431. Porter, J.W., 1992. Oil and gas reserves of the Western Canada Foreland Basin. In: R.W. Macqueen and D.A. Leckie (Editors), Foreland Basins and Fold Belts. American Association of Petroleum Geologists, Memoir 55, pp. 125-158. Potter, J., Stasiuk, L.D., Cameron, A.R., 1998. A Petrographic Atlas of Canadian Coal Macerals and Dispersed Organic Matter. Canadian Society for Coal Science and Organic Petrology, Geological Survey of Canada (Calgary), Canment Energy Technology Centre Poulton, T.P., Tittemore, J., and Dolby, G., 1990. Jurassic strata, northwestern (and westcentral) Alberta and northeastern British Columbia. Bulletin of Canadian Petroleum Geology, 38A: 159-175. 158 Price, L . C , Ging, T., Daws, T., Love, A., Pawlewicz, M . , and Anders, D., 1984. Organic metamorphism in the Mississippian-Devonian Bakken shale, North Dakota portion of the Williston Basin. In: F.F. Meissner and J.L Clayton (Editors), Hydrocarbon Source Rocks of the Greater Rocky Mountain Region, J. Woodward, Denver: Rocky Mountain Association of Geologists, pp. 82 - 134. Ramos, S., and Bustin, R.M., 2002. Western Canadian Gas Shales: Relationship Between Gas Sorption Capacity and Organic Matter Abundance, Type, and Maturity. Canadian Society of Coal and Organic Petrology/TSOP Abstracts with Programs, September 4, 2002. Requejo, A.G., 1994. Maturation of petroleum source rocks - II. Quantitative changes in extractable hydrocarbon content and composition associated with hydrocarbon generation. Organic Geochemistry, 21(1): 91-105. Requejo, A.G., Gray, N.R., Freund, H , Thomann H , C.F., and Hsu, C.S., 1992. Maturation of petroleum source rocks -' I. Changes in kerogen structure and composition associated with hydrocarbon generation. Energy and Fuels, 6: 203-214. Riediger, C.L., 1991. Lower Mesozoic Hydrocarbon Source Rocks, Western Canada Sedimenatary Basin. 1991. Waterloo, Waterloo, Ontariro, Canada. 1991. Riediger, C.L., Brooks, P.W., Fowler, M.G., and Snowdon, L.R. 1990a. Lower and Middle Triassic source rocks, thermal maturation, and oil-source correlation in the Peace River Embayment area, Alberta and British Columbia. Bulletin of Canadian Petroleum Geology, 38A: 218-235. Riediger, CL, M G Fowler, L R Snowdon, F Goodarzi, P W Brooks, 1990b. Source rock analysis of the Lower Jurassic "Nordegg Member" and oil-source rock correlations, northwestern Alberta and northeastern British Columbia. Bulletin of Canadian Petroleum Geology, 38A: 236-249. Schraufnagel, R.A., and Schafer, P.S., 1996. The success of coalbed methane. In: J.L. Sulsberry, P.S. Schafer, and R.A. Schraufnagel (Editors), A Guide to Methane Reservoir Engineering Gas Research Institute (GRI Reference Number GRI-94/0397). Chicago, Illinois, pp. 1.1-1.10. Schieber, J., 2001. A role for organic petrology in integrated studies of mudrocks: examples from Devonian black shales of the eastern US. International Journal of Coal Geology, 47(3-4): 171-187. Senftle, J.T., J.H. Brown, and S.R. Larter, 1987. Refinement of organic petrographic methods for kerogen characterization. International Journal of Coal Geology, 7:105-117. Senftle, J.T., Landis, C.R., and McLaughlin, R., 1996. Refinement of organic petrographic methods for kerogen characterization. International Journal of Coal Geology, 7:105-117. 159 Stasiuk, L.D., 1999. Microscopic Studies of Sedimentary Organic Matter: Key to Understanding Organic-Rich Strata, with Paleozoic Examples from Western Canada Basin. Geoscience Canada, 26(4): 149-172. Stasiuk, L.D., Osadetz, K.G., and Goodarzi, F., 1988. Preliminary source rock evaluation of the Nordegg Member (Lower Jurassic), Alberta. In: Current Research Part D, Geological Survey or Canada Paper, 88-1D, pp. 51-56. Stasiuk, L.D., and Goodarzi, F., 1988. Organic Petrology of Second White Speckled Shale, Saskatchewan, Canada - A possible link between Bituminite and Biogenic Gas?. Bulletin of Canadian Petroleum Geology, 36(4): 397-406. Stoakes, F.A. 1980. Nature and control of shale basin fill and its effect on reef growth and termination: Upper Devonian Duvernay and Ireton formations of Alberta, Canada. Bulletin of Canadian Petroleum Geology, 28: 345-410. Stokes, F.A., and Creaney, S., 1984. Sedimentology of a carbonate source rock: Duvernay Formation of central Alberta. In: L. Eliuk (Editor), Carbonates in Subsurface and outcrop. Proceedings of the 1984 Canadian Society of Petroleum Geologists Core Conference, Calgary, pp. 132-147. Taylor, G.H., Teichmuller, M . , Davis, A., Diessel, C.F.K., Littke, R., Robert, P., 1998. Organic Petrology. Gebruder Borntraeger, Berlin-Stuttgart, 704 p. Teichmuller, M . , 1989. The genesis of coal from the viewpoint of coal petrology. International Journal of Coal Geology, 12:1-87. « Teichmuller, M . , and Ottenjann, K., 1977. Art and Diagenese von Liptiniten und lipoiden Stoffen in einem Erdolmuttergestein auf Grand fluoroeszenzmikroskopischer Untersuchungen. Erdol u. Kohle, 30: 387-398. Tissot, B.P., and Welte, D.H., 1984. Petroleum, Formation and Occurrence. Springer, Berlin. Tyson, R.V., 1995, Sedimentary organic matter: organic facies and palynofacies, London, New York, Chapman & Hall. Unsworth, J.F., Fowler, C.S., and Jones, L.F., 1989. Moisture in coal: 2. Maceral effects on pore structure. Fuel, 68(l):18-26. Williams, G.D., and Stelck C.R., 1975. Speculations on the Cretaceous palaeogeography of North America. In: W.G.E. Caldwell (Editor), The Cretaceous System in the Western Interior of North America. Geological Association of Canada, Special Paper 13, pp. 1-20. Yee, D., Seidle, J.P., and Hanson, W.B., 1993. Gas sorption on coal and measurement of gas content in hydrocarbons from coal. In: B.E. Law and D.D. Rice (Editors), Hydrocarbons from coal. A A P G Studies in Geology # 38, p. 203-218. 160 Zielinski, Ronald E., and Mclver, Richard D., 1982. Synthesis of Organic Geochemical Data from the Eastern Gas Shales. SPE/DOE #10793. 161 CHAPTER 4 - CONLUDING REMARKS 4.1 THE EFFECTS UPON GAS SORPTION CAPACITY OF SHALE IN THE WESTERN CANADIAN SEDIMENTARY BASIN Ultimate controls on the variation in methane adsorptive capacity in the Western Canadian Sedimentary Basin shale is due to a complex interplay of factors including total organic carbon content, kerogen type, source rock effectiveness, geometry, thickness, composition, chemistry, physical properties, mineralogy, porosity, and permeability. A l l are part attributable to sedimentary environment, burial history and tectonics, which were controlled by age, paleolatitude, structural and biological evolution. Sedimentary depositional and organic matter evolution and deposition varied throughout the evolution of the basin. Tectonic changes of the Western Canadian Sedimentary Basin formed organic-rich (>2 wt% TOC) shales in two different sedimentation stages. During the Devonian to Jurassic miogeocline/platform stage, TOC-rich shales were deposited and formed in anoxic, marine environments favourable for deposition black shales enriched by Type I and II organic matter. During the Mid-Jurassic to Paleocene, TOC-lean shales were deposited in the foreland basin succession. Environments favourable for Type II and Type III containing a mix of marine and terrestrial deposition increased at the time. Several primary factors such as geologic age, paleolatitude of the depositional areas, structural forms of deposition, and the evolution 162 of biota controlled the areal distribution of source rocks, their geochemical type, and their effectiveness (Klemme and Ulmishek, 1991). The shale sample sets vary in inorganic and organic compositions, organic matter abundances, kerogen types, and maturity which varies spatially throughout a shale sequence. Therefore the variability should be considered in exploration programs for natural gas from shale strata. This thesis has demonstrated that shale gas capacity is affected by TOC and mineral content. Specifically, gas capacity of mudrocks increases with TOC content, maturation, and clay content. Methane sorption capacity is qualitatively related to organic matter contents where the amount of organic carbon present is related to the source rock type and potential. The most abundant organic matter is found in shale containing Type I or II kerogen. Conversely, gas capacity decreases with mineral matter (ash content, quartz, and carbonate), and moisture content. Positive correlation exists between TOC content and methane sorption capacity for high-TOC shales versus low-TOC shales because the low-TOC shales have more influence from pore/moisture/maturity relationships. The expulsion of water and blockage of sites due to compaction of mature strata (small data set) results in a marked increase in sorbed gas contents. Shales with abundant clays show affinity to sorption, if moisture does not compete with methane for sites where the effect is greatest. Varying methane sorption capacity with organic matter type, nature, HI, kerogen isotopic composition and depositional environment are due to inherent correlations with 163 TOC abundance. Isolating rank and other factors such as mineral matter contents, the gas capacity increases with shales containing more vitrinite (kerogen Type III). Vitrinite holds more moisture at lower maturities and microporosity increases with depth. 4.2 F U T U R E W O R K The data from this research shows that high organic matter and mature shales have the best sorption potential however they may not be the best target from a production standpoint. Even though the organic-lean samples in this study have low sorption capacities, the strata interbeds with coarser strata (thin siltstone stringers as small reservoirs) and/ or fractures providing pathways for hydrocarbon mobility. Moreover, organic-lean, Type III kerogen shales with terrestrial vitrinite have slightly more sorption capacities than similar TOC, Type 1/II kerogen shales. It is likely that this preliminary study will assist future work in more detailed stratigraphic and spatial gas shale analyses. Gas shales need to be approached by a reservoir engineering viewpoint, where optimal conditions for economic production are desired (eg. permeable interbeds or coarsening upwards sequences). TOC and source rock quality needs to be evaluated more within a sequence stratigraphic framework. More detailed work on organic matter compositional changes spatially, as estimates zones of interest may be targeted and gas-in-place calculations can be refined. Moreover TOC, density, and mineralogical data can be coupled with TOC estimates from well logs. 164 The effect of kerogen composition needs to be researched by isolating organic matter from shales of varying kerogen type. The effects of maceral/kerogen content of shale upon pore volumes and size distributions requires investigation in order to completely understand the determinants of gas content and producibility. 165 4.3 REFERENCES CITED Klerrvme, D.H., and Ulmishek, G.F., 1991. Effective Petroleum Source Rocks of the World: Stratigraphic Distribution and Controlling Depositional Factors. The American Association of Petroleum Geologists Bulletin, 75(12): 1809-1851. 1 6 6 A P P E N D I X A : S A M P L E D A T A D E V O N I A N T O JURRASIC, >5 wt % T O C SHALES: G E O C H E M I S T R Y S A M P L E C O L L E C T I O N G E O C H E M I C A L D A T A O R G A N I C GEOCHEMISTRY ORGANIC Well Location Depth (m) Tmax (oC) SAMPLE TOC %N Total C Carbonate Sulphur C/N C/S S/C 13 C Petrography HI Ol FACIES 16-28-57-21W4 1157.48 417 DUV-50 8.12 0.41 13.50 44.76 1.39 19.60 5.85 0.17 -27.84 A>B 550 32 B 16-28-57-21W4 1156.41 417 DOV-49 8.91 0.45 13.63 38.45 1.71 19.70 5.21 0.19 -28.02 A>B 550 32 B 12-9-49-19W4 1404.24 427 DUV-53 2.71 0.12 9.51 57.43 0.05 22.39 49.23 0.02 -29.32 B>A 466 31 B 12-9-49-19W4 1405.20 427 DUV-51 5.02 0.24 10.69 47.19 0.53 21.36 9.42 0.11 -29.21 B>A • 466 31 B 16-18-52-5W5 2336.10 431 DUV-57 2.24 0.11 4.71 20.65 1.05 20.28 2.14 0.47 -29.25 B>A 546 32 B 16-18-52-5W5 2337.50 434 DUV-55 4.92 0.21 7.38 20.48 1.31 23.49 3.76 0.27 -28.86 A=B 422 35 B 16-18-52-5W5 2335.70 439 DUV-56 6.18 0.23 9.04 23.81 1.93 27.02 3.21 0.31 -28.23 A>B 376 11 B 10-4-51-24W4 1673.20 431 DUV-59 11.15 0.33 11.97 6.81 2.17 33.56 5.14 0.19 -27.69 A>B 501 11 B 14-29-48-6W5 2721.40 444 DUV-67 2.70 0.12 6.05 27.93 0.86 23.33 3.15 0.32 -27.17 204 15 1-28-36-3W5 3013.40 450 DUV-61 4.62 0.16 10.60 49.77 1.45 28.92 3.20 0.31 -27.87 146 20 16-27-88-7W6 1300.30 428 NOR-20 12.70 0.37 12.71 0.08 9.81 34.06 1.29 0.77 -28.99 B>A>T 788 23 A 11-19-85-3W6 1062.40 429 NOR-18 13.34 0.46 14.55 10.03 3.35 29.07 3.98 0.25 -29.10 B>A>T 762 34 A 11-19-85-3W6 1064.17 431 NOR-19 22.49 0.60 23.63 9.48 4.30 37.72 5.23 0.19 -29.31 B>A>T 779 25 A 13-12-61-12W5 1687.8-1695.5 441 NOR-39 2.07 0.07 7.19 42.65 0.95 31.13 2.17 0.46 -28.40 A>B>T 459 25 B 2-13-71-22W5 1392.91 437 NOR-23 7.99 0.22 13.98 49.69 1.73 36.72 4.62 0.22 -26.21 T>A>B 560 12 B 4-28-69-19W5 1461.3-1468.7 442 NOR-40 12.21 0.41 13.77 12.94 2.32 29.75 5.27 0.19 -28.58 A>B>T 607 15 B 14-11-84-8W6 1130.5-1140.8 440 NOR-41 13.42 0.38 15.03 13.37 2.11 34.98 6.36 0.16 -28.68 A>B>T 696 11 B 2-13-71-22W5 1397.16 441 NOR-24 14.11 0.41 14.89 6.50 3.14 34.29 4.49 0.22 -28.51 A>B>T 682 11 • B 14-14-78-2W6 1070.60 438 NOR-21 15.62 0.55 19.25 30.24 3.25 28.30 4.81 0.21 -28.79 B=A>T 815 20 A 7-31-79-10W6 1548.23 447 NOR-3 5.28 0.17 11.27 49.63 1.08 31.51 4.90 0.20 -28.36 214 5. 7-31-79-10W6 1539.67 452 NOR-1 6.82 0.24 8.30 12.28 3.05 28.26 2.24 0.45 -29.63 264 3 10-6-60-20W5 2453.7-2463.4 460 NOR-43 4.43 0.20 9.58 42.89 1.58 22.30 2.80 0.36 -27.19 151 22 10-6-60-20W5 2448.3-2464.9 460 NOR-44 6.27 0.25 10.20 32.75 2.57 24.59 2.44 0.41 -28.15 122 15 16-23-57-6W6 2377.8-2391.8 545 NOR-45 3.01 0.12 8.34 44.44 1.00 25.49 3.01 0.33 -28.27 10 11 16-23-57-6W6 2377.1-2391.2 554 NOR-46 5.34 0.21 9.80 37.18 2.00 25.01 2.67 0.38 -28.67 9 6 lilllliHlilPllli!^ 10-17-80-24W5M 1781.92 420 EX-29 3.36 0.18 3.49 1.15 2.41 18.60 1.39 0.72 -28.41 A=B 407 8 B 10-17-80-24W5M 1782.28 422 EX-30 6.11 0.21 7.25 9.46 2.56 29.69 239 0.42 -27.78 A>B 596 8 B 10-17-80-24W5M 1783.24 423 EX-31 11.85 0.50 13.54 14.04 1.49 23.55 7.97 0.13 -28.30 A=B 671 6 B 16-30-77-25W5M 2023.35 432 EX-26 8.91 0.34 9.00 1.17 1.46 26.47 6.12 0.16 -28.38 A=B 621 6 B 10-21-78-1W6M 2084.12 430 EX-25 8.95 0.25 10.61 13.79 1.88 35.56 4.76 0.21 -28.09 A=B 834 5 A 10-21-78-1W6M 2084.48 432 EX-28 9.95 0.34 11.84 15.69 2.25 29.59 4.42 0.23 -28.14 - 706 7 A 1-20-1-24-W4 2794.00 449 EX-37 1.62 0.08 1.96 2.80 1.34 21.38 1.21 0.83 -28.34 44 0 1-20-1-24-W4 2789.25 455 EX-35 10.62 0.59 10.93 2.53 4.95 18.12 2.15 0.47 -27.89 39 0 1-20-1-24-W4 2791.00 460 EX-36 7.94 0.41 8.65 5.89 4.18 19.46 1.90 0.53 -28.00 76 8 M I D - J U R A S S I C T O P A L E O C E N E , <5 wt % T O C S H A L E S : G E O C H E M I S T R Y S A M P L E C O L L E C T I O N G E O C H E M I C A L D A T A O R G A N I C GEOCHEMISTRY ORGANIC Well Location Depth (m) Tmax (oC) SAMPLE TOC %N Total C Carbonate Sulphur C/N C/S S/C 13 C Petrography HI Ol FACIES 8-25-55-25W4 1340.70 425 BELLE-140 1.44 0.15 2.49 1.93 2.32 14.93 0.62 1.61 -26.54777 V=B>A 290 16 B-C 8-25-55-25W4 1340.00 425 BELLE-139 2.07 0.15 2.09 0.13 2.30 13.44 0.90 1.11 -26.24819 V>B>A 290 16 B-C 06-07-12-28W4 2594.20 439 BELLE-134 1.50 0.17 1.67 1.41 2.32 8.80 0.65 1.54 -25.66876 V>B>A 120 14 C 06-07-12-28W4 2594.00 439 BELLE-133 3.21 0.17 3.92 5.92 3.22 19.00 1.00 1.00 -24.92794 V>B>A 120 14 C 09-09-56-19W5 2268.63 446 BELLE-132 3.96 0.24 4.93 8.04 2.76 16.44 1.44 0.70 -23.74383 266 14 B-C 09-09-56-19W5 2268.00 446 BELLE-131 4.11 0.24 5.18 8.88 2.93 17.33 1.40 0.71 -23.99807 V>B>A 266 14 B-C 14-29-13-29W4 2769.28 450 BELLE-136 1.29 0.16 1.49 1.65 2.48 8.28 0.52 1.91 -25.7943 V>B>A 39 16 14-29-13-29W4 2769.94 450 BELLE-135 1.36 0.16 1.54 1.52 2.47 8.69 0.55 1.82 -25.67842 V>B>A 06-34-30-08W4 693.00 422 SWS-68 4.08 0.24 4.17 0.72 1.62 16.98 2.51 0.40 -26.62154 B>T=A 258 23 B-C 10-36-11-29W4 2638.00 431 SWS-75 3.29 0.18 5.36 17.23 2.16 18.24 1.52 0.66 -25.67712 B>T>A 292 11 B-C 04-13-54-18W5 2100.89 441 SWS-80 1.88 0.18 2.47 5.19 1.84 10.24 1.02 0.98 -24.68222 B>T=A 195 12 D 04-13-54-18W5 2098.90 441 SWS-76 2.07 0.19 2.69 5.17 2.14 11.08 0.97 1.03 -28.31327 B>A>T 195 ' 12 D 04-13-54-18W5 2104.00 ' 441 SWS-77 2.11 0.19 2.93 6.86 2.24 11.31 0.94 1.07 -24.95104 B>T>A 296 10 B-C 04-13-54-18W5 2102.42 441 SWS-81 2.32 0.19 3.34 8.45 2.25 12.19 1.03 0.97 -25.04776 B>T=A 296 10 D 14-29-13-29W4 2759.17 450 SWS-78 3.48 0.16 7.01 29.36 1.94 21.33 1.80 0.56 -25.77729 B>T>A 88 34 D 14-29-13-29W4 2760.22 450 SWS-72 4.39 0.19 7.95 29.67 1.49 23.66 2.95 0.34 -25.75749 B>T>A 136 24 C 14-29-13-29W4 2756.66 450 SWS-87 2.71 0.15 5.34 21.86 212 17.78 1.28 0.78 -26.2675 B>T>A 132 24 OO D E V O N I A N T O JURRASIC, >5 wt % T O C SHALES: SORPTION S A M P L E C O L L E C T I O N HIGH-PRESSURE M E T H A N E P R O X I M A T E Saturated Monolayer Langmuir Pressure Helium Tmax (oC) SAMPLE TOC 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 Volume (cc/g @ STP): (MPa): density (cc/g) Ash Moisture 417 DUV-50 8.12 0.25 0.43 0.58 0.70 0.80 0.89 0.96 1.02 1.85 6.50 2.35 69.24 6.78 417 DUV-49 8.91 0.33 0.56 0.74 0.87 0.98 1.07 1.15 1.21 1.97 5.00 2.27 71.03 7.81 427 DUV-53 2.71 0.10 0.14 0.16 0.17 0.18 0.19 0.19 0.20 0.23 1.26 2.53 71.48 1.49 427 DUV-51 5.02 0.18 0.30 0.39 0.45 0.50 0.54 0.57 0.60 0.88 3.81 2.42 71.85 0.97 431 DUV-57 2.24 0.08 0.13 0.16 0.18 0.20 0.22 0.23 0.24 0.34 3.34 . 2.48 89.44 3.41 434 DUV-55 4.92 0.16 0.30 0.41 0.51 0.59 0.67 0.73 0.79 1.70 9.33 2.54 87.58 3.07 439 DUV-56 6.18 0.14 0.27 0.38 0.48 0.57 0.65 0.73 0.79 2.26 14.77 251 83.20 3.28 431 DUV-59 11.15 0.33 0.58 0.79 0.96 1.10 1.22 1.33 1.42 2.72 7.36 2.37 81.23 0.66 444 DUV-67 2.70 0.06 0.10 0.13 0.15 0.16 0.17 0.18 0.19 0.26 3.13 2.65 86.11 3.50 450 DUV-61 4.62 0.15 0.25 0.33 0.38 0.43 0.46 0.50 0.52 0.81 4.43 2.58 77.21 0.31 428 NOR-20 12.70 0.37 0.66 0.90 1.10 1.27 1.41 1.54 1.64 3.26 7.86 1.95 74.70 17.31 429 NOR-18 13.34 0.37 0.64 0.84 1.00 1.12 1.23 1.31 1.39 2.28 5.12 202 75.96 6.53 431 NOR-19 22.49 0.55 1.00 1.37 1.68 1.95 2.18 2.39 2.57 5.41 8.87 - 1.98 67.00 2.82 441 NOR-39 207 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.12 2.67 81.76 1.24 437 NOR-23 7.99 0.23 0.39 0.50 0.58 0.64 0.69 0.73 0.77 1.14 3.88 2.39 74.68 , 2.82 442 NOR^O 12.21 0.44 0.65 0.77 0.85 0.91 0.96 0.99 1.01 0.99 1.54 226 76.97 1.07 440 NOR- i l 13.42 0.23 0.43 0.61 0.76 0.90 1.03 1.14 1.24 3.33 13.45 231 76.56 1.46 441 NOR-24 14.11 0.46 0.66 0.78 0.85 0.90 0.94 0.97 0.99 1.19 1.58 2.17 79.32 1.69 438 NOR-21 15.62 0.35 0.65 0.91 1.14 1.33 1.51 1.67 1.81 4.47 11.75 2.14 69.45 2.62 447 NOR-3 5.28 0.16 0.28 0.37 0.44 0.50 0.55 0.59 0.63 1.08 5.82 2.48 74.00 0.65 452 NOR-1 6.82 0.26 0.41 0.50 0.57 0.62 0.65 0.68 0.70 0.93 2.56 2.42 86.86 2.29 460 NOR-43 4.43 0.42 0.65 0.79 0.89 0.96 1.02 1.06 1.10 1.43 2.42 2.47 84.40 2.12 460 NOR^4 6.27 0.48 0.74 0.91 1.03 1.11 1.17 1.23 1.27 1.65 2.45 2.51 82.19 1.54 545 NOR-45 3.01 0.31 0.41 0.47 0.50 0.52 0.54 0.55 0.56 0.64 1.07 2.63 83.37 254 554 NOR-46 5.34 0.92 1.13 1.22 1.27 1.31 1.33 1.35 1.36 1.46 0.59 2.56 81.82 0.63 420 EX-29 3.36 0.18 0.28 0.35 0.39 0.43 0.45 0.47 0.49 0.64 2.48 2.36 91.89 8.73 422 EX-30 6.11 0.15 0.29 0.40 0.50 0.59 0.67 0.74 0.80 2.01 11.99 • ' 2.54 88.78 2.61 423 EX-31 11.85 0.57 0.90 1.11 1.26 1.37 1.46 1.52 1.58 2.11 2.70 . 2.19 78.83 229 432 EX-26 8.91 0.43 0.72 0.94 1.10 1.23 1.33 1.41 1.48 2.28 4.29 2.31 86.81 3.42 430 EX-25 8.95 0.33 0.58 0.77 0.92 1.05 1.16 1.25 1.32 2.33 6.06 2.35 82.31 1.91 432 EX-28 9.95 0.26 0.44 0.59 0.70 0.79 0.87 0.93 0.98 1.65 5.42 2.42 80.41 0.30 449 EX-37 1.62 0.07 0.13 0.18 0.22 0.25 0.28 0.31 0.33 0.67 8.18 2.64 95.94 2.62 455 EX-35 10.62 0.53 0.92 1.22 1.47 1.67 1.83 1.97 2.09 3.65 5.93 2.38 81.41 13.63 460 EX-36 7.94 0.42 0.66 0.81 0.91 0.99 1.05 1.09 1.13 1.49 2.52 . 2.40 7.40 ON MID-JURASSIC TO PALEOCENE, <5 wt % TOC SHALES: SORPTION SAMPLE COLLECTION HIGH-PRESSURE METHANE PROXIMATE Saturated Monolayer Langmuir Pressure Helium Tmax (oC) SAMPLE T O C 1.00 2.00 3.00 • 4.00 5.00 6.00 7.00 8.00 Volume (cc/g @ STP): (MPa): density (cc/g) Ash Moisture 425 BELLE-140 1.44 0.11 0.18 0.24 0.29 0.33 0.36 0.39 0.41 0.69 5.52 2.55 92.42 3.62 425 BELLE-139 2.07 0.16 0.27 0.35 0.42 0.47 0.51 0.55 0.58 0.95 5.09 2.53 92.87 9.26 439 BELLE-134 1.50 0.09 0.16 0.22 0.27 0.31 0.34 0.37 0.40 0.77 7.49 2.57 94.58 3.60 439 BELLE-133 3.21 0.13 0.23 0.31 0.37 0.42 0.46 0.50 0.53 0.92 5.91 2.58 92.16 2.26 446 BELLE-132 3.96 0.16 0.24 0.29 0.33 0.35 0.37 0.39 0.40 0.51 2.22 2.59 90.20 3.48 446 BELLE-131 4.11 0.20 0.37 0.51 0.62 0.72 0.81 0.89 0.96 2.07 9.30 2.60 90.38 4.02 450 BELLE-136 1.29 0.12 0.20 0.26 0.31 0.35 0.38 0.41 0.43 0.70 4.94 2.64 95.01 3.59 450 BELLE-135 1.36 0.03 0.04 0.05 0.06 0.06 0.06 0.07 0.07 0.09 2.40 . 2.72 94.00 1.39 • 422 SWS-68 4.08 0.04 0.06 0.08 0.09 0.10 0.10 0.11 0.12 0.17 0.17 2.39 89.26 10.88 431 SWS-75 3.29 0.11 0.19 0.25 0.30 0.34 0.38 0.41 0.43 0.77 6.11 . 2.63 89.39 3.48 441 SWS-80 1.88 0.07 0.08 0.09 0.10 0.11 0.13 0.14 0.15 1.27 18.20 2.59 93.19 4.40 441 SWS-76 2.07 0.14 0.25 0.34 0.41 0.48 0.53 0.58 0.62 1.23 1.23 2.58 93.26 3.62 441 SWS-77 2.11 0.09 0.15 0.21 0.25 0.29 0.32 0.34 0.36 0.68 6.86 2.60 92.84 3.15 441 SWS-81 2.32 0.08 0.13 0.15 0.17 0.19 0.20 0.20 0.21 0.27 2.28 2.53 92.90 3.58 450 SWS-78 3.48 0.22 0.29 0.33 0.35 0.37 0.38 0.39 0.39 0.44 1.01 2.59 87.84 2.21 450 SWS-72 4.39 0.25 0.37 0.45 0.50 0.53 0.56 0.58 0.59 0.74 2.00 Z50 85.35 2.21 450 SWS-87 2.71 0.14 0.25 0.34 0.41 0.48 0.53 0.58 0.62 1.41 8.77 2.59 88.53 2.35 —J o DEVONIAN TO JURRASIC, >5 wt % TOC SHALES: COMPOSITION | SAMPLE COLLECTION X-RAY DIFFRACTION PEAKS Illite/Mica Dolomite Chlorite Kaolinite Tmax (oC) SAMPLE T O C Quartz (d=4.23) Calcite (d=3.03) Pyrite (d=2.71) (d=10.00) (d=2.89) (d=14.00) (d=7.10) Kfeld (d=3.79) Clay 417 DUV-50 8.12 34 75 4 4 5 0 1 0 4 417 DUV-49 8.91 31 47 3 2 5 0 1 4 3 427 DUV-53 2.71 30 57 2 2 2 0 1 0 3 427 DUV-51 5.02 30 65 0 1 0 0 1 0 2 431 DUV-57 2.24 69 23 2 2 1 0 1 0 3 434 DUV-55 4.92 61 26 3 2 1 0 2 0 4 439 DUV-56 6.18 50 30 4 2 5 0 2 0 4 431 DUV-59 11.15 40 17 9 2 14 0 1 11 3 444 DUV-67 2.70 39 38 2 6 5 2 4 0 12 450 DUV-61 4.62 44 0 0 3 48 " 0 0 4 3 428 NOR-20 12.70 43 0 20 5 0 11 5 16 429 NOR-18 13.34 59 7 5 6 12 0 0 5 6 431 NOR-19 22.49 58 5 1 2 9 0 0 2 2 441 NOR-39 2.07 27 55 2 1 12 0 0 1 1 437 NOR-23 7.99 35 51 2 1 12 0 0 1 1 442 NOR-40 12.21 41 25 3 3 11 0 0 4 3 440 NOR-41 13.42 51 24 3 1 5 0 0 2 1 441 NOR-24 14.11 54 9 4 5 8 0 0 6 5 438 NOR-21 15.62 32 41 2 1 6 0 0 2 1 447 NOR-3 5.28 39 48 3 1 4 0 0 0 1 452 NOR-1 6.82 61 13 9 5 6 0 0 0 5 460 NOR-43 4.43 33 47 3 3 10 0 0 0 3 460 NOR^4 6.27 41 35 4 3 3 0 0 0 3 545 NOR-45 3.01 50 40 3 1 3 0 0 0 1 554 NOR-46 5.34 49 38 3 1 4 0 0 0 1 420 EX-29 3.36 81 1 5 6 2 0 0 0 6 422 EX-30 6.11 83 5 2 1 3 0 0 0 1 423 EX-31 11.85 59 20 1 3 2 0 0 2 3 432 EX-26 8.91 86 0 2 2 0 0 0 . 2 2 430 EX-25 8.95 60 24 2 2 2 0 0 2 2 432 EX-28 9.95 56 26 3 3 2 0 0 2 3 449 EX-37 1.62 95 1 1 0 1 0 0 0 0 455 EX-35 10.62 54 4 5 6 13 0 0 7 6 460 EX-36 7.94 65 4 4 5 7 0 0 6 5 DEVONIAN TO JURRASIC, >5 wt % TOC SHALES: COMPOSITION SAMPLE COLLECTION X-RAY DIFFRACTION PEAKS Tmax (oC) SAMPLE TOC Illite/Mica Dolomite Chlorite Kaolinite Quartz (d=4.23) Calcite (d-3.03) Pyrite (d=2.71) (d=10.00) (d=2.89) (d=14.00) (d=7.10) Kfeld (d=3.79) Clay 425.00 BELLE-140 1.44 425.00 BELLE-139 2.07 77 ' 0 4 8 0 2 7 0 1/ 76 0 5 9 0 2 6 0 17 439.00 BELLE-134 1.50 439.00 BELLE-133 3.21 7 7 - 0 5 9 0 1 5 0 16 73 0 5 7 7 1 3 .. 0 446.00 BELLE-132 3.96 446.00 BELLE-131 4.11 • 66 9 7 6 3 0 4 0 69 8 6 6 4 1 4 0 11 450.00 BELLE-136 1.29 450.00 BELLE-135 1.36 / i n rtn CWQ_Aft A CIS 80 0 4 6 2 1 4 0 12 60 23 4 4 4 0 3 0 7 I H I '— 3~ : 4 ' 1 ' ' 0 0 0 4 1 4Y ' '" • DW>DO t.uo 431.00 SWS-75 3.29 441.00 SWS-80 1.88 441.00 SWS-76 2.07 441.00 SWS-77 2.11 441.00 SWS-81 2.32 63 21 4 2 5 0 1 0 3 7 G 2 4 4 4 1 3 0 9 80 3 5 3 4 1 3 0 6 75 6 5 4 5 1 2 0 7 72 8 6 4 4 0 3 . 0 7 450.00 SWS-78 3.48 450.00 SWS-72 4.39 450.00 SWS-87 2.71 54 32 5 2 4 0 1 0 ^ 52 34 3 2 3 0 0 0 3 52 34 3 2 3 0 0 0 . 3 APPENDIX B: O R G A N I C PETROGRAPHY B A C K G R O U N D : TERMINOLOGY A N D DESCRIPTION Organic matter identified in this thesis is defined and described below. Descriptions are from Stach (1982), Bustin et al. (1983), Stasiuk (1992), and Taylor et al. (1998). A) N O N - D E G R A D E D O R G A N I C MATTER (see Table 3.1 and 3.2) LIPTINITE GROUP (Alginite) Group derived from lipid-rich components of higher plants and algae (eg. spores, pollen, leaf cuticles, plant resins and essential oils, planktonic and benthic algae). High H and low reflectance. Alginite: hydrogen rich maceral of liptinite with precursors are cyanophyte and chlorophyte algae. Morphology ranges from unicellular (Prasinophytes) through colonial to filamentous. Telalginite: informal term of alginite with internal structure in fluorescent light eg. Boytrococcus, Tasmanites. Boytrococcus: algal colonies, occurs as a fossil in boghead coals. Two varieties exist. Vila is massive-fan-like structure which represents a section through a hemisphere with diverging radii. Greenish to brown fluorescence, crenulated outer margins of the bodies open cell cavities can be seen where protoplasm formerly present. The middle is a chrysanthemum-like pattern. Corresponds to a Recent alga, Boytrococcus braunii Kiitzing that lives in freshwater lakes and lagoons. Reinschia has the form of a hollow sphere in horizontal view. In vertical view, they are compressed so the original cavity appears as a line. Cell walls are opened outward, and in shape of toothed rim. Occurs in torbanite. Tasmanites: algal cysts derived from unicellular green algae of the phytoplankton. Compressed to form a flat disc. Leiosphaeridia: thin-walled smooth or slightly ornamented spherical microalgae. Filamentous: algae thin in diameter; resembling a thread Coccoidal: Round colonial bodies, (eg. Derived from Boytrococcus, G. prisca alginite or Gloecapsomorpha prisca). 173 Gloeocapsomorpha:massive algal mat or stromatolitic texture. A coccoidal alginite that is planar, larrdnated, filamentous in texture. Dinoflagellates: chiefly marine protozoa having two flagella; a chief constituent of plankton. Generally single-celled organisms. Usually between 20 and 150 pm long, Acritarchs: a microscopic, organic-walled, commonly spiny, unicellular, marine organism of unknown biological affinity (algal?) ranging in age from Precambrian to Holocene. ; t Lamalginite: derived from small unicellular or thin-walled colonial planktonic or benthic algae showing lamellar form perpendicular to bedding with little botanical structure. Processes of minute spines may rarely be present indicating possible affinity to acritarchs or dinoflagellates Liptodetrinite: fine detrital nature and fine particle size cannot be grouped with other liptinite. Fragments and fine degradation remains of sporinite, cutinite, resinite, alginite, and suberinite LIPTINITE (Herbaceous) Sporinite: derived from pollen and spores. Individual bodies with distinct cell walls. Shows high relief Cutinite: derived from cuticles. Shows serrated edges and high relief. LIPTINITE (Amorphous) See B) Non-fluorescing organic matter INERTINITE (Herbaceous) Inertinite: maceral characterized by high reflectance and oxygen content relative to vitrinite and liptinite; inert during coking process Micrinite: maceral of mertinite group. Formation may be related to petroleum from H -rich liptinite macerals. Fusinite: derived from woody tissue. Shows high reflectance, white to yellowish colour, open cell lurnina, thin cell walls, and bogen structure Semifusinite: derived from woody tissue, reflectance between vitiinite and fusinite, smaller cell lurnina, often closed often cloudy appearance Sclerotinite: fungal mycelia, fungal spores. Survives in unfavourable environments (draught, water logging, toxic conditions). 174 Inertodetrinite: fragments of other mertinite macerals normally <30 micrometres. VITRINITE (Herbaceous) Vitrinite: maceral group derived from humic or woody material (h'gnin) of plants. Medium reflectance. ORGANIC FOSSILS: Microforaminifera: Calcareous, unicellular marine organisms. BITUMEN: Exsudatinite: coal maceral equivalent to migrabitumen formed by thermal alteration of H-rich macerals Migrabitumen: secondary maceral from kerogen during diagenesis and catagenesis. Fills formed cavities of coats the veins. B) NON-FLUORESCING O R G A N I C MATTER Bituminite: amorphous, unstructured, hydrogen-rich maceral. Likely produced during penecontemporaneous and early diagenetic degradation and microbial alteration of lipid-rich organic matter (Teichmuller and Ottenjann, 1977; Teichmuller and Wolf, 1977; Robl et al., 1987) such as cyanobacterial mats (Glickson and Taylor, 1986) and algae, and composed of the degradation products of the degrading microbes. Bimminite varies in size, internal structure, fluorescence intensity and composition. Most consists of small or large lenses and layers, with length >100 microns, or most seem to blend with groundmass (matrix bituminite- mtimate with clays). Types shown with decreasing fluorescence intensity (Sentfle et al., 1987): 1) Brightly yellow or orange fluorescing (fluoramorphinite): -eg. Nordlinger Ries and Messel shales -High HI -Made of or transitioned into lamalginite -lamalginite and unstructured O M same fluorescence intensity -Derived from lipidic biomass of algae (Gutjahr, 1983) 2) Brown-flourescing (piturninite I, fluoramorphinite): -eg. Toarcian Posidonia (Teichmuller and Ottenjann, 1977) and Jordanian oil shales. -Potential not directly known, disappears alginite maturation (Littke et al., 1988) - Intensity less than alginite - residual product after maturation is micrinite (Teichmuller 1982a) 175 3) Red fluorescing (bitaminite II, fluoramorphinite): -Cretaceous Albanian oil shales and Cenomanian-Turonian black shales — -High to intermediate HI values -derived from lipidic biomass and converted by anaerobic processes or faecal pellet origin. 4) Non- fluorescing (bimrrunite III, hebamorphinite): -Pennsylvanian black shales. -Low to intermediate HI values. -possibly a precipitate of humic acids derived from terrigenous organic matter (Littke, 1993). DUVERNAY SAMPLES DUV-50, 16-28-57-21W4 TOC 8.12 wt %, Tmax 417 44.76 % carbonate, 1.39Stotai, -27.84 S O 3 HI 550 Alginite > Bituminite Blue light: Matrix is fluoresces yellow-green from calcite. Sporadic, bright yellow and weakly yellow fluorescing liptodetrinite are throughout the matrix, not aligned. Parallel to bedding, are wavy bands of non-fluorescing brown biUiminite (minor occurrence). White light: Cloudy white carbonate — rich matrix contains rare bituminite stringers, and small vitrinite wisps and particles. Pyrite sporadic and commonly associated wihin bituminite bands. DUV-49, 16-28-57-21W4 TOC 8.91 wt %, Tmax 417 38.45 % carbonate, 1.71 Stotai, -28.02 5 0 3 HI 550 Alginite > Biturninite Blue light: Matrix is fluoresces yellow-green from calcite. Discrete tiny orange and yellow reflecting liptodetrinite are rare. Rare Tasmanites. Weakly fluorescing exsudatinite fill is seen. White light: Mineral grains reflect dull white with very dark brown organic-mineral matrix surrounding the grains. Pyrite scattered. DUV-53, 12-9-49-19W4 TOC 2.71 wt %, Tmax 427 57.43 % carbonate, 0.05 Stotai, -29.32 8 G 3 HI 466 Bimminite > Alginite Blue light: Thick brown wavy lenses of bituminite occur between green-yellow fluorescing mineral matter. Sporadic is small bright yellow fluorescing elongate and blocky liptodetrinite. There is abundant very thin wavy lamalginite, orange 176 reflecting. Pyrite commonly occurs in alginite. Acritarchs present that weakly reflect yellow. White light: Large carbonate/quartz and brown matrix shows dark brown elongate bituminite stringers and some dark grey degraded ones. Rounded and blocky.small vitrinite particles are rare. DUV-51, 12-9-49-19W4 T O C 5.02 wt %, Tmax 427 47.19 % carbonate, 0.53 S t otai, -29.21 S O 3 HI 466 Bituminite > Alginite Blue light: Same as DUV-53. Rare exsudatinite is seen occurring between cracks. Hardly any liptodetrinite seen in blue light excitation. White light: Dark brown matrix bitunrunite occurring as parallel lenses. DUV-57, 16-18-52-5W5 T O C 2.24 wt %, Tmax 431 20.65 % carbonate, 1.05S t otai, -29.25 5C« HI 546 Bituminite > Alginite Blue light: Very small yellow and orange fluorescing alginite sparse throughout the fluorescing yellow-green and brown matrix. Not much alginite stringers present. See pyrite occurring within Tasmanites alginite. Acritarch present. White light: Mmeral-dominated matrix showing cloudy reflection. Abundant are dark grey and brown biturninite? Stringers (solid bitumen?). Minor in abundance are vitrodefrinite particles with oxidation rims (high relief). DUV-55, 16-18-52-5W5 T O C 4.92 wt %, Tmax 434 20.48 % carbonate, 1.31 S t otai, -28.86 S C " HI 422 Alginite = Bituminite Blue light: Dark yellow brown matrix with sporadic dark brown lenses of bituminite, thinner than samples above. Rare orange sporinite bits and yellow liptodetrinite. White light: Dark silty/calcite-rich matrix with thin bituminite lenses. Pyrite framboids are scattered. DUV-56, 16-18-52-5W5 T O C 6.18 wt %, Tmax 439 23.81 % carbonate, 1.93Stotai, -28.23 5C« HI 376 Alginite > Bituminite Blue light: Very small (Type C) alginite and liptodetrinite are sparse throughout dark brown - yellowish matrix. Rare sporinite and thick walled Tasmanites are discrete. Pyrite is found occurring within alginite. Rare round spikey acritarchs present. White light: Cloudy dark brown matrix, contains vitriruTe/bituminite particles?, as stringers, they look degraded. Matrix contains light brown, non structured bimrninite, not elongate. 177 DUV-59, 10-4-51-24W4 TOC 11.15 wt %, Tmax 431 6.81 % carbonate, 2.17S t o tai, -27.69 8 C " HI 501 Alginite > Bituminite Blue light: Dark brown matrix contains wispy lamalginite that weakly reflect yellow in clue light excitation. Sparse are brightly reflecting liptodetrinite, some are aligned to bedding. Big long and round Tasmanites are discrete. White light: Dark brown thin streaks are the lamalginite bands. Rare are grey-reflecting vitrinite/bituminite elongate particles. DUV-61, 01-28-36-W5 TOC 4.62 wt %, Tmax 450 49.77 % carbonate, 1.45Stotai, -27.87 8C 1 3 HI 146 Blue light: Very dark matrix. Mineral (calcite) fluoresces a bright-dull yellow, as blocks and rhombs. Sparsely scattered are stringy and particulate lamalginite. White light: Matrix is dark and pyrite rich. EXSHAW SAMPLES EX-29, 10-17-80-24W5 TOC 3.36 wt %, Tmax 420 1.15 % carbonate, 2.41 S to tai, -28.41 5C« HI 407 Alginite = Bituminite Blue light: Moderately abundant brightly yellow reflecting alginite, occurring either as discrete long string-like laminations or dense bands, commonly parallel to bedding. Pyrite commonly occurs within alginite. White light: Lamalginite (brightly reflecting in blue light) is seen as light brown streaks in white-light excitation. Darker brown biturninite wavy larriinae are sparse throughout. Moderately abundant is small elongate bitiirriinite in the dorninantly silty matrix. Rarely observed are small blocky vitrinite particles, and shardy mertinite. EX-30, 10-17-80-24W5 TOC 6.11 wt %, Tmax 422 9.46 % carbonate, 2.56Stotai, -27.78 8C« HI 596 Alginite > Bitiirriinite Blue light: Similar to EX-29. Matrix dark. Huge Tasmanities. Rare Pila B.? White light: Matrix dark with moderately abundant aligned bituminite. Pyrite rich. Not many maceral particles. EX-31, 10-17-80-24W5 TOC 11.85 wt %, Tmax 423 14.04 % carbonate, 1.49Stotai, -28.30 5 C " HI 671 Alginite = Bituminite 178 Blue light: Greenish yellow reflecting background in blue light. Abundant brightly fluorescing yellow Tasmanites and or liptodetrinite. Common are wispy and long lamalginite sometimes orange and a dull yellow reflectance (alginite more broken). Light brown non-structured bituminite occurs as thin wavy lenses, scattered throughout. White light: Calcite grains (white and cloudy) more abundant than two samples above. The matrix is has darker brown streaks of organic matter (elongate matrix bituminite), more than samples above. EX-26, 16-30-77-25W5 T O C 8.91 wt %, Tmax 432 1.17 % carbonate, 1.46Stotai, -28.38 8C« HI 621 Alginite = Bituminite Blue light: Organic matter is abundantly long thin alginite that weakly fluoresces yellow and orange, and occurs as either discrete particles or lenses. Brightly fluorescing Tasmanites are discrete and some contain pyrite. Orange fluorescing sporinite is rare. White light: Matrix is grainy, containing rare small inertinite, semifusinite and vitrinite particles (shardy, elongate, and blocky). EX-25, 10-21-78-1W6 T O C 8.95 wt %, Tmax 430 13.79 % carbonate, 1.88Stotai, -28.09 8 C " HI 834 Blue light: Similar to above. Pila B. present. White light: More calcite grains in between dark brown laminated organic-mineral matrix. Pyrite commonly bedded. Rare sparse small inertinite, semifusinite, and vitrinite particles. EX-28, 10-21-78-1W6 T O C 9.95 wt %, Tmax 432 15.69 % carbonate, 2.25S t otai, -28.14 S C " HI 706 Blue light: Blue light excitation shows a dark matrix with moderately abundant thin liptodetiinite. Tasmanites are minor. Pila B. present. White light: Bituminite very thin and streaky across. There are sparsely scattered small inertinite, semifusinite, and vitrinite bits. EX-36, 1-20-1-24W4 T O C 7.94 wt %, Tmax 460 5.89 % carbonate, 4.18 S t o tai, -28.00 5C 1 3 HI 76 Blue light: Very dark. White light: Equigranular grey texture. Very sparse thin maceral particles. Very thin streaky bituminite is sparse. 179 N O R D E G G SAMPLES NOR-20, 16-27-88-7W6 T O C 12.70 wt%, Tmax 428 0.08 % carbonate, 9.81 S t o t a i , -28.99 5C« HI 788 Bituminite > Alginite > Terrestrial Blue light: Matrix bituminite weakly fluoresces brown with small discrete parallel alginite stringers and sparsely scattered liptodetrinite particles that fluoresce yellow. Rare low yellow fluorescing small roundish alginate. White light: Matrix fluoresces brown-dark brown and contains abundant bits of broken mertinite and semifusinite and scattered small vitrinite particles. Large vitrinite particles and big large shardy semifusinite occur sporadically. Cenospheres (due to rapid burning) with vacuoles are rare. Small, framboidal, euhedral pyrite is sporadic throughout the matrix. NOR-19, 11-19-85-3W6 T O C 22.49 wt%, Tmax 431 9.48 % carbonate, 4.30Stotai, -29.315C" HI 779 Bituminite > Alginite > Terrestrial Blue light: Matrix consists of a dense abundance of brown fluorescing bituminite occurring as thin oriented lenses. Thin stringy yellow reflecting alginite (less structured) moderately abundant throughout matrix, and is wavy/parallel to bedding. White light: Broken mertinite, semifusinite and vitrinite dominate the matrix. The macerals are commonly altered with zoning and are partially rounded and or blocky. mertinite (shardy) of faunal origin is sparse. Smaller vitrinite/ vitrodetrinite are found parallel to bedding. Inclusions of framboidal pyrite occur within vitrinite particles. NOR-18, 11-19-85-3W6 T O C 13.34 wt%, Tmax 429 10.03 % carbonate, 3.35S,otai, -29.10 6C« HI 762 Bituminite > Alginite > Terrestrial Blue light: Matrix consists of weakly fluorescing yellow-brown bituminite with moderately abundant parallel alginite stringers. Yellow fluorescing liptodetrinite particles are scattered throughout the matrix. Tasmanites are scattered throughout and some have pyrite occurring within the structure. White light: Similar to NOR-20, except with more carbonate. NOR-23 2-13-71-22W5 T O C 7.99 wt%, Tmax 437 50 % carbonate, 1.73 Stotai, -26.21 5C13, HI 560 Terrestrial> Alginite> Bimminite Blue light: Matrix fluoresces brown with carbonate grains. Yellow fluorescing alginite stringers are common, and thin-walled and thick-walled liptodetrinites are sporadic; some oriented with matrix. 180 White light: A calcite-rich matrix with sporadic framboidal and euhedral pyrite. Bright white semifusinite is abundant and sporadic; some are elongate wispy bodies parallel to bedding. Dary grey vitrinite is more discrete, smaller particles and rare particles, commonly degraded. Rare carbonate shells. NOR-21, 14-14-78-2W6 TOC 15.62 wt%, Tmax 438 30.24 % carbonate, 3.25 Stotai, -28.79 8 C " H I 815 Bituminite = Alginite > Terrestrial Blue light: Under fluorescent light the matrix is darker. Abundant small, wispy, liptodetrinite and small alginite occur throughout the matrix. Some thick-walled yellow reflecting alginite occurs as thick bands and layers. Some carbonate fluoresce a weak yellow. Rare Bottyococcus alginite. White light: Matrix dominated by more abundant and larger carbonate crystals. Particles of elongate vitrinite, rectangular vitrinite and broken angular semifusinite are moderately abundant. NOR-39, 13-12-61-12W5 TOC 2.07 wt%, Tmax 441 42.69 % carbonate, 0.95 Stotai, -28.406C" H I 450 Alginite > Bimminite > Terrestrial Blue light: The sample is low in organic matter as seen by a very low abundance of yellow fluorescing lamalginite, except for sporadic large unstructured liptodetrinite. Bedding is mdistinct, and there is minor bituminite present. White light: Matrix material exhibits strong reflectance (light grey) and contains larger and abundant mineral matter, specifically calcite. Minute particles of inertodetrinite and/or vitrinite are sporadic and rninor. Both reflect similar grey intensities. NOR-22, 6-29-85-11W6 TOC 22.49 wt%, Tmax 431 30.68 % carbonate, 1.38 Stotai, -28.64 8C« H I 496 Alginite > Bitummite > Terrestrial Blue light: Abundant in the brown fluorescing matrix are weakly yellow fluorescing thin lamalginite and smaller but elongate weakly orange reflecting sporinite?. Most alginite aligns to the bedding. Weakly yellow fluorescing exsudatinite is rare. Bimminite is rare and not as large lenses. White light: Moderated sized mineral particles occur throughout the matrix. Tiny vitrodetrinite and inertodetrinite shards and elongate particles are dispersed throughout. There is rare foraminifer with vitrodetrinite inside a calcite infill (geopetal?). Large degraded vitrinite showing oxidized rim. NOR-40, 4-28-69-19W5 TOC 12.21 wt%, Tmax 442 12.94% carbonate, 2.32 Stotai, -28.58 8C« H I 600 Alginite > Bituminite > Terrestrial 181 Blue light: Dark brown matrix contains fine wispy liptodetrinite fluorescing yellow-orange. The bituminite does not form into long lenses, but intermixed with matrix. White light: The silty matrix (cloudy grey reflectance) contains sporadic fragmental bits of inertinite, semifusinite, and vitrinite that are elongate, blocky, broken, or shardy. Vitrinite commonly shows oxidation rims. Pyrite framboids scattered throughout the matrix. NOR-41, 14-11-84-8W6 T O C 13.42 wt%, Tmax 440 13.37 % carbonate, 2.11 Stotai, -28.68 5 C « HI 600 Alginite > Bibiminite > Terrestrial Blue light: The matrix is a very dark brown. White light: The light brown silty matrix contains rare macerals. Moderately abundant are large grey- reflecting material either vitrinite, coccoidal or solid bitumen. NOR-24, 2-13-71-22W5 T O C 14.11 wt%, Tmax 441 6.50 % carbonate, 3.14S;o ta), -28.518Q3 HI 682 Alginite > Bituminite > Terrestrial Blue light: Scattered and aligned throughout the matrix is weakly and brightly fluorescing yellow small wispy liptodetrinite. The mineral matrix fluoresces mdicating bituminous substances on clay minerals. Bituminite is faint and not as aligned or as big lenses but more intermixed with matrix. White light: The dark brown grainy mineral matrix contains abundant pyrite scattered throughout the matrix. Rare are discrete small vitrinite, semifusinite, and mertinite particles that are broken, elongate, or blocky in shape. NOR-1, 7-31-79-10W6 T O C 6.82 wt%, Tmax 452 12.28 % carbonate, 3.05 Stotai, -29.63 5 C " HI 264 Bimminite > Alginite > Terrestrial Blue light: Very dark brown matrix is dominated by large lenticicular weakly brown fluorescing bimmLnite that is bedding parallel. Thin, wispy liptodetrinite, and yellow-orange Type C (round) alginite is moderately abundant. Moderately abundant calcite rhombs fluoresce a dull yellow. White light: Large mineral particles occur throughout the matrix. There is a rare abundance of particles vitrinite, serriifusinite, and mertinite. Frequent are grey-reflecting, granular coccoid? NOR-43, 10-6-60-20W5 T O C 4.43 wt%, Tmax 460 42.89 % carbonate, 1.58 Stotai, -27.19 5 C " HI 150 Blue light: Under blue light the specimen is very dark. Abundant are wispy liptodetrinite and round Type C alginite. Mineral fluorescence from calcite. 182 White light: Calcite rich, background inundated with bright and grey reflecting particles. NOR-44, 10-6-60-20W5 T O C 6.27 wt%, Tmax >460 32.75 % carbonate, 2.57 Stotai, -28.15 S C " HI 120 Blue light: Matrix banded with yellow fluorescing and dark brown fluorescing matrix. Calcite fluorescence throughout. Type C alginite? White light: Very dark brown matrix that is carbonate rich with abundant pyrite. Minor minor bits of vitrinite or mertinite that grey fluoresce. NOR-45, 16-23-57-6W6 T O C 3.01 wt%, Tmax >470 44.44 % carbonate, 1.00 Stotai, -28.27 8C« HI 5 Blue light: Matrix comprised of very small yellow fluorescing and orange fluorescing round/square particles. White light: A grainy grey matrix that is carbonate rich. Minor very fine bits of vitrinite and mertinite scattered throughout. SECOND WHITE SPECKS SAMPLES SWS-68, 06-34-30-08W4 T O C 4.08 wt %, Tmax 422 0.72 % carbonate, 1.62 Stotai, -26.62 5 C 3 HI 258 Blue light: Minor alginite is found as small subtle or barely recognizable Tasmam'fes-like, Leiospheridia-like, coccoidal alginite (more round), elongate or wispy alginite (some possibly small Prasinophytes), and liptodetrinite. Well-formed alginite fluoresces bright yellow and more subtle alginite is fluoresces more weak yellow. White light: Matrix is grainy and white, containing dark brown concentrated matrix-bituminite and disperse matrix bituminite (both Hebamorphinite). There is minor non-fluorescing organic matter that is light brown in white light and is a streaky form. Scattered pyrite framboids are sparse. Present are small inertinite, and vitrinite particles. SWS-75, 10-36-11-29W4 T O C 3.29 wt %, Tmax 431 17.23 % carbonate, 2.16Stotai, -25.68 6C« HI 292 Blue light: Wispy long alginite and thin liptodetrinite common. Thin-walled Leiosphaeridia are rare. The matrix is dark brown with is non-fluorescing bituminite. White light: Silty (whiteish) and dark brown grainy matrix contains bituminite (more diffuse-type) and inclusions of large and small degraded vitrinites (with oxidation rims). Some bituminite is found as concentrated bands and blocky 183 fragments. Framboidal pyrite is numerous. Sporadic is mertinite, and vitrinite bits. SWS-80, 04-13-54-18W5 T O C 1.88 wt %, Tmax 441 5.19 % carbonate, 1.84 Stotai, -24.68 S O 3 HIO Blue light: More abundant sporadic rninute round particles than samples above than wispy alginite. Quartz grains observed. Light brown alginite elongate. White light: The dark brown grainy matrix contains round, blocky, and concentrated biturrvinite (hebamorphinite). Minute and particulate vitiinite lined with bedding and some are elongate. SWS-76, 04-13-54-18W5 T O C 2.07 wt %, Tmax 441 5.17 % carbonate, 2.14Stotai, -28.31 S O 3 HIO Blue light: Algnite present as above samples. Matrix in blue light fluoresces brown, not greenish because of more abundant elongate non-fluorescing bitiirriinite, sometimes with inclusions of vitrinite bits. Rare cutinite? White light: White grainy matrix contains bits of degraded vitrinite. Abundant are the non-fluorescing bituminite elongate with bedding. Some of the bituminite is present as dark grey grainy large particles. SWS-77, 04-13-54-18W5 T O C 2.11 wt %, Tmax 441 6.86 % carbonate, 2.24Stotai, -24.95 5 Q 3 HI 296 Blue light: More greenish matrix. Not much bedding structure is seen, some dark biturninite seen. Lots of rninute round alginite bits sporadic. Rare exsudatinite. White light: Matrix bituminite is grey and brown concentrated grainy material. Some bituminite clear brown in white light, non-fluorescing in blue. Degraded vitrinite (some long) and inertinite. Lots of pyrite present. SWS-81, 04-13-54-18W5 T O C 2.32wt %, Tmax 441 8.45 % carbonate, 2.25 Stotai, -25.05 5C 1 3 HIO Blue light: Barely recognizable alginite is particulate and thin. Bituminite is non-fluorescing and dark. White light: Grainy matrix contains mostly concentrated type biturriinite as large blocky particles (elongate less common); micrinite derived from biturninite and bacteria? Clear brown bituminite present (elongate). Vitrinite particles are small and dispersed. SWS87, 14-29-13-29W4 T O C 2.71 wt %, Tmax 450 21.86 % carbonate, 2.12Stotai, -26.2750 3 HI? B>T>A Blue light: not many organic bits, but diffuse mid-sized blobs 184 White light: Blocky, lenses, hebamorphinite, vitrinite and mertinite. SWS-78, 14-29-13-29W4 T O C 3.48 wt %, Tmax 450 29.36 % carbonate, 1.94 Stotai, -25.78 5 C " HIO Blue light: Dark 'Tiger'-like background. More orange coloured alginite bits that are round. Elongate bits of alginite. Blocky exsudatinite?. White light: Large carbonate grains are numerous. Lots of foraminifea. Grainy green brown lenses and bands of bituminite/micrinite interbedded with vitrinite stringers. Rare faunal mertinite bits. Abundant pyrite, commonly concentrated as bands. SWS-72, 14-29-13-29W4 T O C 4.39 wt %, Tmax 450 29.67 % carbonate, 1.49 Stotai, -25.76 S C " HI 95 Blue light: Very dark matrix. Same as above. See orange net-like alginite?. White light: Dark matrix contains foraminifera, large mertinites, and vitrinite particles. Dark material is matrix bimminite and sometimes blocky type. Black/ grey micrinite common, BELLE FOURCHE SAMPLES BELLE 140, 8-25-55-25W4 T O C 1.44 wt %, Tmax 425 1.93 % carbonate, 2.32 Stotai, -26.55 8C« HI 290 Blue light: A variety of yellow fluorescing alginite are observed to be randomly scattered. Possible alginite are thin, wispy, Leiosphere-type, Pila-type, and Prasinophytes-type. White light: Grainy quartz-rich matrix contains elongate brown/ grey bituminite, and concentrated blocky bituminite. Vitrinites are large and blocky. Vitiodetrinites are abundant. Pyrite framboids present. BELLE 139, 8-25-55-25W4 T O C 2.07 wt %, Tmax 425 0.13 % carbonate, 2.30 Stotai, -26.25 8 C " HI 290 Blue light: Hardly any alginite present. Yellow fluorescing long, wispy types. White light: Vitrinite is small or elongate. Bimnrrinite present is minor, as matrix and as minor streaks. BELLE 134, 06-07-12-28W4 T O C 1.50wt %, Tmax 439 1.41 % carbonate, 2.32Stotai, -25.67 6 C " HI 120 Blue light: Minor bits of subtle alginite. White light: Dominantly degraded, oxidized vitrinites. Bits of clear brown bituminite present. Framboidal pyrite is common. 185 BELLE 133, 06-07-12-28W4 T O C 3.21 wt %, Tmax 439 5.92 % carbonate, 3.22 Stotai, -24.93 SC 1 3 HI 120 . Blue light: Rare bits of alginite. White light: Quartz-rich matrix dominated by veiny and elongate that is parallel to bedding. More matrix biturrvinite than previous sample. BELLE 131, 09-09-56-19W5 T O C 4.11 wt %, Tmax 446 8.88 % carbonate, 2.93 S t o t ai, -24.00 S O 3 HI 266 Blue light: "Tiger" appearance. Degraded alginite are small and thin. White light:. Grainy dark matrix contains dark black biturrvinite with long vitrinites BELLE 136, 14-29-13-29W4 T O C 1.29 wt %, Tmax 450 1.65 % carbonate, 2.48 S t o t ai, -25.79 S O 3 HI 39 Blue light: Bits of alginite as above samples. White light: Degraded vitrinites throughout matrix. Some granular bitiirriinite. BELLE 135, 14-29-13-29W4 T O C 1.52wt %, Tmax 450 1.65 % carbonate, 2.48Stotai, -25.68 5 0 3 HI Blue light: Same as above. White light: Same as above. See pyrite inclusions within vitrinite. REFERENCES Bustin, R.M., Cameron, A.R., Grieve, D.A., Kalkreuth, W.D., 1983. Coal Petrology Its Principles, Methods, and Applications. Geological Association of Canada, Short Course Notes, Volume 3. Victoria, 1983. Glikson, M . , and Taylor, G.H., 1986. Cyanobacterial mats: major contributors to the organic matter in Toolebuc Formation oil shales. In D.L Gravestock, P.S. Moore, and G.M. Pitt, (Editors), Contributions to the geology and hydrocarbon potential of the Eromanga basin: Geological Society of Australia Special Publication 12, p. 273-286. Gutjahr, C.C.M., 1983. Introduction to incident-light microscopy of oil and gas source rocks. Geologie en Mijnbouw, 62: 417-425. Littke, R., 1993. Deposition, diagenesis and weathering of organic matter-rich sediments. Lecture Notes in Earth Sciences, 47: 218 pp. Robl, T.L., Taulbee, D.N., Barron, L.S., and Jones, W.C., 1987. Petiologic chemistry of a Devonian Type II kerogen. Energy Fuels, 1: 507-513. 186 Senftle, J.T., Brown, J.H., and Larter, S.R., 1987. Refinement of organic petrographic methods for kerogen characterization. International Journal of Coal Geology, 7:105-117. Stach, E., Mackowsky, M.-Th., Teichmuller, M . , Taylor, G.H., Chandra, D., and Teichmuller, R., 1982. Stach's textbook of coal petrology, 3 r d Edition. Berlin & Stuttgart, Gebruder Borntraeger, 535 pp. Stasiuk, L., 1992. Organic Petrology and petroleum formation in Paleozoic rocks of Northern Williston Basin, Canada. 1992. University of Regina, Regina, Saskatchewan, Canada. 1992. Taylor, G.H., Teichmuller, M . , Davis, A., Diessel, C.F.K., Littke, R., Robert, P., 1998. Organic Petrology. Gebruder Borntraeger, Berlin-Stuttgart, 704 pp. Teichmuller, M . , 1982. The importance of coal petrology in prospecting for oil and natural gas. In E. Stach and others (Editors), Stach's textbook of coal petrology, 3 r d edition. Berlin, Gebruder Borntraeger, pp. 399-412. Teichmuller, M . , and Ottenjann, K., 1977. Art and Diagenese von Liptiniten und lipoiden Stoffen in einem Erdolmuttergestein auf Grand fluoroeszenzmikroskopischer Untersuchungen. Erdol u. Kohle, 30: 387-398. Teichmuller, M . , and Wolf, M . , 1977. Application of fluorescence microscopy in coal petrology and oil exploration. Journal of Microscopy, 109(1): 49-73. 187 APPENDIX C: SORPTION DATA DUVLHNAY I Isotherm Proximate Analysis (wt%) Well Location Depth (m) Tmax (oC) Sample TOC (wt%) Pressure (Mpa) Gas (CC/R) Ash Moisture 16-28-57-21W4 1157.48 417 DUV-50 8.12 0.00 0.00 69.24 6.78 0.28 0.09 0.64 0.18 1.16 0.30 1.73 0.36 2.58 0.46 3.53 0.59 4.49 0.71 5.46 0.84 6.43 0.95 7.40 1.06 16-28-57-21W4 1156.41 417 D U V M 9 8.91 0.00 0.00 71.03 7.81 0.30 0.13 0.66 0.26 1.18 0.39 1.75 0.47 2.62 0.63 3.56 0.75 4.53 0.87 5.51 1.02 6.48 1.14 7.46 1.26 12-9J19-19W4 1404.24 427 DUV-53 2.71 0.00 0.00 71.48 1.49 0.38 0.06 0.75 0.09 1.35 0.12 1.95 0.12 2.85 0.15 3.74 0.19 4.85 0.19 5.81 0.19 6.84 0.17 7.71 0.22 12-9-49-19W4 1405.20 427 DUV-51 5.02 0.00 0.00 71.85 0.97 . 0.34 0.08 0.70 0.16 1.30 0.23 1.85 0.28 2.80 0.34 3.67 0.42 4.59 0.46 5.55 0.50 6.52 0.55 7.50 0.65 16-18-52-5W5 2336.10 431 DUV-57 2.24 0.00 0.00 89.44 3.41 0.28 0.02 0.64 0.07 1.16 0.09 1.74 0.11 2.60 0.14 3.56 0.16 4.51 0.18 5.49 0.22 6.45 0.20 7.42 0.26 16-18-52-5 W5 2337.50 434 DUV-55 4.92 0.37 0.07 87.58 3.07 0.72 0.14 1.25 0.20 1.83 0.25 2.68 0.34 3.62 0.44 4.59 0.54 5.55 0.64 6.54 0.77 7.56 0.77 188 Isotherm Proximate Analysis (wt%) Well Location Depth (m) Tmax (oC) Sample TOC (wt%) Pressure (Mpa) Gas (cc/g) Ash Moisture 16-18-52-5W5 2335.70 439 DUV-56 6.18 0.00 0.00 83.20 3.28 0.34 0.06 0.70 0.11 1.27 0.18 1.91 0.23 2.76 0.34 3.67 0.44 4.70 0.53 5.73 0.62 6.61 0.70 7.55 0.81 10-4-51-24W4 1673.20 431 DUV-59 11.15 0.00 0.00 81.23 0.66 0.35 0.13 0.70 0.24 1.20 0.38 1.79 0.52 2.67 0.70 3.63 0.87 4.57 1.02 5.55 1.14 6.52 1.30 7.45 1.41 14-29-48-6W5 2721.40 444 DUV-67 2.70 0.00 0.00 86.11 3.50 0.40 0.01 0.73 0.04 1.26 0.05 1.88 0.07 2.72 0.12 3.71 0.16 4.69 0.16 5.63 0.16 6.58 0.17 7.57 0.18 1-28-36-3W5 3013.40 450 DUV-61 4.62 0.00 0.00 77.21 0.31 0.32 0.06 0.61 0.12 1.20 0.16 1.75 0.21 2.64 0.29 3.65 0.36 4.63 0.40 5.57 0.44 6.57 0.47 7.53 0.54 NO < [ » ( . ( , • 1 Isotherm Proximate Analysis (wt%) Well Location Depth (m) Tmax (oC) Sample TOCl«tt%) Pressure (Mpa) Gas (cc/g) Ash Moisture 16-27-88-7W6 1300.30 NOR-20 12.69672873 428.00 0.00 0.00 17.31 74.70 0.26 0.17 0.50 0.23 0.86 0.31 1.32 0.42 1.82 0.54 2.67 0.72 3.95 1.00 5.36 1.23 6.79 1.52 8.55 1.91 16-27-88-7W6 1300.30 428 NOR-20 12.70 0.00 0.00 74.70 17.31 0.35 0.12 0.72 0.18 1.23 0.26 1.81 0.35 2.67 0.45 3.63 0.52 4.61 0.60 5.59 0.63 6.53 0.73 7.51 0.81 189 Isotherm Proximate Analysis (wt%) Well Location Depth (m) Tmax (oC) Sample TOC (wr%) Pressure (Mpa) Gas (cc/g) Ash Moisture 11-19-85-3W6 106240 429 NOR48 1334 0 0 0 O 0 0 75.96 6.53 0.31 0.15 0.62 0.28 1.04 0.40 1.46 0.47 1.88 0.56 2.78 0.76 3.64 0.89 4.95 108 6.34 1.24 7.74 148 11-19-85-3W6 106417 431 NOR-19 2249 O O EOO 6700 0.25 0.15 0.68 0.39 0.91 0.54 1.42 0.74 1.87 0.91 2.66 1.20 3.69 1.53 5.01 193 6.57 2.31 7.83 2.61 13-12-61-12W5 1687.8-1695.5 441 NOR-39 2.07 0.00 0.00 81./6 0.25 0.03 0.50 0.06 0.86 0.06 1.38 0.06 1.89 0.09 2.70 0.12 3.97 0.07 5.37 0.07 6.81 0.06 2-13-71-22W5 1392.91 437 NOR-23 7.99 0.00 0.00 74.68 2.82 0.35 0.12 0.72 0.18 1.23 0.26 1.81 0.35 2.67 0.45 3.63 0.52 4.61 0.60 5.59 0.63 6.53 0.73 7.51 0.81 n nn 7A Q7 1 07 4-28-69-19W5 1461.3-1468.7 442 NOR-40 0.20 0.10 0.50 0.18 0.93 0.27 1.35 0.35 1.85 0.45 2.76 0.55 4.00 0.76 5.55 0.87 14-11-84-8W6 1130.5-1140.8 0.00 0.00 76.56 0.29 0.06 0.66 0.17 1.19 0.28 1.77 0.39 2.65 0.56 3.61 0.70 4.58 0.84 5.57 0.98 6.55 1.08 7.54 1.20 190 Isotherm Proximate Analysis (wt%) Well Location Depth (m) Tmax (oQ Sample TOC (wt%) Pressure (Mpa) Gas (cc/R) Ash Moisture 2-13-71-22W5 1397.16 441 NOR-24 14.11 0.00 0.00 79.32 1.69 0.22 0.19 0.45 0.29 0.83 0.44 1.33 0.52 1.83 0.53 2.73 0.68 3.68 0.83 4.68 0.93 5.63 0.93 6.59 0.97 14-14-78-2W6 1070.60 438 NOR-21 15.62' 0.00 0.00 69.45 2.62 0.29 0.11 0.65 0.25 1.20 0.41 1.78 0.57 2.67 0.81 3.60 1.04 4.57 1.24 5.61 1.42 6.52 1.61 7.48 1.78 7-31-79-10W6 1548.23 447 NOR-3 5.28 0.00 0.00 74.00 0.65 0.23 0.03 0.48 0.09 0.88 0.16 1.36 0.24 1.81 0.28 2.68 0.36 3.63 0.41 4.58 0.48 5.54 0.51 6.53 0.56 7-31-79-10W6 1539.67 452 NOR-1 6.82 0.00 0.00 86.86 2.29 0.17 0.06 0.41 0.14 0.85 0.23 1.34 0.30 1.86 0.38 2.67 0.46 3.64 0.54 4.61 0.61 5.61 0.64 6.56 0.67 10-6-60-20W5 2453.7-2463.4 460 NOR-43 4.43 0.00 0.00 84.40 2.12 0.18 0.16 0.41 0.23 0.83 0.35 1.31 0.46 1.81 0.56 2.69 0.69 3.64 0.81 4.96 0.93 6.36 1.09 7.83 1.12 10-6-60-20W5 2448.3-2464.9 460 NOR-44 6.27 0.00 0.00 82.19 1.54 0.17 0.17 0.41 0.28 0.85 0.40 1.32 0.52 1.83 0.64 2.67 0.80 3.61 0.93 4.93 1.09 6.37 1.26 7.81 1.28 Isotherm Proximate Analysis (wt%) Well Location Depth (m) Tmax (oC) Sample TOC (wt%L Pressure (Mpa) Gas (CC/R) Ash Moisture 16-23-57-6 W6 2377.8-2391.8 545 NOR-45 3.01 0.00 0.00 83.37 2.54 0.31 0.17 0.68 0.26 1.22 0.32 1.80 0.39 2.69 0.47 3.65 0.49 4.64 0.50 5.60 0.53 6.58 0.53 7.56 0.59 16-23-57-6W6 2377.1-2391.2 554 NOR t^6 5.34 0.00 0.00 81.82 0.63 0.11 0.25 0.33 0.54 0.79 0.84 1.32 0.96 1.82 1.06 2.64 1.23 3.60 1.32 4.97 1.26 6.39 1.33 7.85 1.38 1" l \ M I \V\ Isotherm Proximate Analysis (wt%) Well Location Depth (m) Tmax (oQ Sample TOC (wt%) Pressure (Mpa) Gas (CC/R) Ash Moisture 10-17-80-24W5M 1781.92 420 EX-29 3.36 0.00 0.00 91.89 8.73 0.32 0.07 0.70 0.14 1.24 0.22 1.78 0.26 2.69 0.34 3.60 0.38 4.63 0.40 5.60 0.43 6.67 0.45 7.55 0.51 10-17-80-24W5M 1782.28 422 EX-30 6.11 0.00 0.00 88.78 2.61 0.28 0.05 0.67 0.11 1.19 0.18 1.76 0.26 2.62 0.37 3.57 0.45 4.54 0.54 5.51 0.61 6.49 0.70 7.46 0.81 10-17-80-24W5M 1783.24 423 EX-31 11.85 0.00 0.00 78.83 2.29 0.30 0.19 0.65 0.35 1.25 0.58 1.77 0.90 2.62 1.18 3.70 1.26 4.68 1.63 5.71 1.62 6.61 1.33 7.51 1.45 16-30-77-25W5M 2023.35 432 EX-26 8.91 0.00 0.00 86.81 3.42 0.24 0.12 0.49 0.21 0.85 0.44 1.30 0.58 1.78 0.72 2.65 0.85 3.96 1.02 5.39 1.18 6.91 1.35 8.61 1.64 192 Isotherm Proximate Analysis (wt%) Well Location Depth (mL Tmax (oQ Sample TOC K / . | Pressure (Mpa) Gas (cc/g) Ash Moisture 10-21-78-1W6M 2084.12 430 EX-25 8.95 0.00 0.00 82.31 1.91 0.27 0.11 0.44 0.18 0.84 0.30 1.34 0.40 1.82 0.49 2.73 0.65 4.00 0.85 5.39 1.12 7.05 1.27 8.72 1.42 10-21-78-1W6M 2084.48 432 EX-28 9.95 0.00 0.00 80.41 0.30 0.19 0.05 0.44 0.14 0.87 0.25 1.33 0.34 1.84 0.44 2.69 0.55 4.00 0.69 5.63 0.75 6.94 0.96 8.65 1.04 1-20-1-24-W4 2794.00 449 EX-37 1.62 0.00 0.00 95.94 2.62 0.27 0.02 0.67 0.06 1.20 0.08 1.76 0.13 2.65 0.14 ' 3.61 0.17 4.58 0.24 5.55 0.29 6.52 0.36 7.51 0.29 1-20-1-24-W4 2789.25 455 EX-35 10.62 0.00 0.00 81.41 13.63 0.57 0.33 0.77 0.45 1.29 0.65 1.88 0.89 2.71 1.12 3.67 1.32 4.59 1.54 5.54 1.72 6.47 1.92 7.44 2.12 1-20-1-24-W4 2791.00 460 EX-36 7.94 0.00 0.00 7.40 0.63 0.29 0.82 0.38 1.32 0.50 1.94 0.65 2.72 0.77 3.74 0.89 4.68 0.98 5.72 0.98 6.53 1.07 7.47 1.14 HEIl l -IOUUIIl Well Location Depth (m) Isotherm Tmax(oC) Sample TOC (wt%) Pressure (Mpa) Gas (cc/g) Proximate Analysis (wt%) Ash Moisture 8-25-55-25W4 BELLE-140 0.00 0.32 0.67 1.20 1.77 2.67 3.62 4.60 5.57 6.55 7.51 0.00 0.04 0.08 0.12 0.16 0.22 0.27 0.29 0.33 0.39 0.43 92.42 193 Isotherm Proximate Analysis (wt%) Well Location Depth (m) Tmax (oC) " " ' " 8-25-55-25W4 1340.00 425 BELLE-139 2.07 0.00 0.00 92.87 9.26 0.35 0.06 0.71 0.13 1.24 0.20 1.80 0.26 2.71 0.33 3.66 0.37 4.68 0.40 5.63 0.47 6.60 0.56 7.58 0.63 06-07-12-28W4 2594.20 439 BELLE-134 1.50 0.00 0.00 94.58 0.30 0.05 0.67 0.06 1.21 0.11 1.77 0.12 2.66 0.18 3.61 0.23 4.57 0.29 5.56 0.34 6.53 0.38 7.51 0.39 06-07-12-28 W4 2594.00 439 BELLE-133 321 O00 O00 921(5 226" 0.37 0.06 0.72 0.10 1.24 0.15 1.82 0.20 2.70 0.27 3.63 0.35 4.74 0.42 5.72 0.44 6.56 0.48 7.47 0.53 09-09-56-19W5 2268.63 446 BELLE-132 3.96 0.00 0.00 90.20 3.48 0.36 0.06 0.71 0.12 1.25 0.15 1.82 0.19 2.69 0.25 3.64 0.30 4.60 0.34 5.60 0.38 6.57 6.39 7.56 0.39 09-09-56-19W5 2268.00 446 BELLE-131 O l O00 O00 9038 WT 0.31 0.08 0.68 0.15 1.23 0.23 1.81 0.31 2.69 0.43 3.62 0.57 4.61 0.68 5.58 0.78 6.56 0.88 7.54 0.95 14-29-13-29W4 2769.28 450 - BELLE-136 129 O00 O00 9501 359~~ 0.32 0.04 068 . 0.09 1.19 " 0.15 1.77 , 0.18 2.64 0.24 3.61 0.29 4.63 0.34 5.61 0.39 6.54 0.38 7.50 0.41 194 Isotherm Proximate Analysis (wt%) Well Location Depth (m) Tmax (oC) Sample TOC (wt%) Pressure (Mpa) Gas (cc/g) Ash Moisture 14-29-13-29W4 2769.94 450 BELLE-135 1.36 0.00 0.00 94.00 1.39 0.31 0.01 0.69 0.02 1.25 0.03 1.79 0.04 2.69 0.04 3.64 0.07 4.64 0.06 5.60 0.08 6.58 0.06 7.56 0.06 | .SirOMDWIIIll.SPl.CkS Isotherm Proximate Analysis (wt%) Well Location Depth (m) Tmax (oC) Sample TOC (wt%) Pressure (Mpa) G as (cc/g) Ash Moisture 06-34-30-08W4 693.00 422 SWS-68 4.08 0.00 0.00 89.26 10.88 0.32 0.00 0.69 0.03 1.34 0.03 1.95 0.05 2.71 0.08 3.68 0.10 4.66 0.10 5.62 0.10 6.59 0.10 7.51 0.11 10-36-11-29W4 2638.00 431 SWS-75 3.29 0.00 0.00 89.39 3.48 0.31 0.05 0.68 0.08 1.21 0.12 1.79 0.15 2.64 0.21 3.61 0.27 4.58 0.32 5.54 0.36 6.54 0.40 7.52 0.45 04-13-54-18 W5 2100.89 441 SWS-80 1.88 0.00 0.00 93.19 4.40 0.32 0.03 0.68 0.04 1.20 0.07 1.79 0.11 2.67 0.16 3.63 0.21 4.60 0.26 5.58 0.30 6.56 0.33 7.55 0.37 04-13-54-18W5 2098.90 441 SWS-76 2.07 0.00 0.00 93.26 3.62 0.32 0.05 0.69 0.11 1.22 0.16 1.77 0.21 2.64 0.29 3.60 0.37 4.56 0.45 5.59 0.52 6.57 0.56 7.51 0.61 04-13-54-18W5 2104.00 441 SWS-77 2.11 0.00 0.00 92.84 3.15 0.37 0.04 0.74 0.07 1.26 0.10 1.86 0.14 2.70 0.19 3.68 0.23 4.69 0.27 5.61 0.31 6.57 0.34 7.53 0.36 195 Isotherm Proximate Analysis (wt%) Well Location Depth (m) Tmax (oC) Sample TOC (wt%) Pressure (Mpa) Gas (CC/R) Ash Moisture 04-13-54-18W5 2102.42 441 SWS-81 2.32 0.00 0.00 92.90 3.58 0.32 0.05 0.68 0.08 1.22 0.10 1.78 0.11 2.67 0.12 3.62 0.13 4.60 0.17 5.59 0.19 6.56 0.20 7.54 0.23 14-29-13-29W4 2759.17 450 SWS-78 3.48 0.00 0.00 87.84 2.21 0.35 0.12 0.70 0.16 1.25 0.21 1.84 0.27 2.72 0.35 3.66 0.39 4.65 0.39 5.68 0.38 6.64 0.36 7.59 0.38 14-29-13-29W4 2760.22 450 SWS-72 4.39 0.00 0.00 85.35 2.21 0.35 0.10 0.69 0.22 1.24 0.29 1.82 0.37 2.69 0.41 3.67 0.47 4.65 0.49 5.61 0.55 6.58 0.58 7.56 0.60 14-29-13-29W4 2756.66 450 SWS-87 2.71 0.00 0.00 88.53 2.35 0.36 0.07 0.71 0.13 1.25 0.17 1.82 0.22 2.69 0.31 3.64 0.38 4.60 0.46 5.60 0.55 6.57 0.64 7.56 0.69 196 

Cite

Citation Scheme:

        

Citations by CSL (citeproc-js)

Usage Statistics

Share

Embed

Customize your widget with the following options, then copy and paste the code below into the HTML of your page to embed this item in your website.
                        
                            <div id="ubcOpenCollectionsWidgetDisplay">
                            <script id="ubcOpenCollectionsWidget"
                            src="{[{embed.src}]}"
                            data-item="{[{embed.item}]}"
                            data-collection="{[{embed.collection}]}"
                            data-metadata="{[{embed.showMetadata}]}"
                            data-width="{[{embed.width}]}"
                            async >
                            </script>
                            </div>
                        
                    
IIIF logo Our image viewer uses the IIIF 2.0 standard. To load this item in other compatible viewers, use this url:
http://iiif.library.ubc.ca/presentation/dsp.831.1-0052557/manifest

Comment

Related Items