PETROLEUM GEOLOGY OF THE GUNNEDAH-BOWEN-SURAT BASINS, NORTHERN NEW SOUTH WALES

STRATIGRAPHY, ORGANIC PETROLOGY AND ORGANIC GEOCHEMISTRY

RUSHDY SAMAD OTHMAN

B.Sc. Geology M.Sc. Petroleum Geology

A thesis submitted in fulfillment of the requirements for the degree of Doctor of Philosophy

Faculty of Science University of New South Wales

July 2003

CERTIFICATE OF ORIGINALITY

I hereby declare that this submission is my own work and to the best of my knowledge it contains no materials previously published or written by another person, nor material which to a substantial extent has been accepted for the award of any other degree or diploma at UNSW or any other educational institution, except where due acknowledgement is made in the thesis. Any contribution made to the research by others, with whom I have worked at UNSW or elsewhere, is explicitly acknowledged in the thesis.

I also declare that the intellection content of this thesis is the product of my own work, except to the extent that assistance from others in the project’s design and conception or in style, presentation and linguistic expression is acknowledged.

(Signed)…………………………………………

ABSTRACT

The three-dimensional thermal maturity pattern has been investigated and the hydrocarbon generation potential assessed for the Permian and Triassic sequences of the southern Bowen and northern Gunnedah Basins and the lower part of the overlying Jurassic Cretaceous Surat Basin sequence in northern New South Wales. An oil-source rock correlation also has been investigated in the Gunnedah Basin. Vitrinite reflectance measurements were conducted on 256 samples from 28 boreholes. A total of 50 of these samples were subjected to Rock-Eval pyrolysis analysis, and 28 samples extracted for additional organic geochemical studies (GCMS). A re-evaluation of the stratigraphy in the southern Bowen Basin and a stratigraphic correlation between that area and the northern Gunnedah Basin was also included in the study.

An overpressured shaly interval has been identified as a marker bed within the lower parts of the Triassic Moolayember and Napperby Formations, in the Bowen and Gunnedah Basins respectively. Suppressed vitrinite reflectance in the Permian sequence was used as another marker for mapping the stratigraphic sequence in the southern Bowen Basin. The Permian sequence in the Bowen Basin thins to the south, and probably pinches out over the Moree High and also to the west. The coal-bearing Kianga Formation is present in the north and northeastern parts of the study area. A disconformity surface between Digby and Napperby Formations in the Gunnedah Basin is probably time-equivalent to deposition of the Clematis Group and Showgrounds Sandstone in the Bowen Basin. The Clematis Group is absent in the study area, and the Moolayember Formation considered equivalent to the Napperby Formation.

Although in many cases core samples were not available, handpicking of coal or shaly materials from cuttings samples where geophysical log signatures identify these materials helped in reducing contamination from caved debris. Histogram plots of reflectance also helped where the target and caved debris were of similar lithology. Vertical profiles of the vitrinite reflectance identified suppressed intervals in the study area due to marine influence (Back Creek Group and Maules Creek Formation) and liptinite rich source organic matter (Goonbri Formation). The suppression occurs due to the perhydrous character of the preserved organic matter. High reflectance values were noted within intrusion-affected intervals, and two types of igneous intrusion profiles were identified; these are simple and complex profiles. An isoreflectance map for the

i non-suppressed interval at the base of the Triassic sequence in the southern Bowen Basin shows that the organic matter is mature more towards the east close to the Goondiwindi Fault, and also towards the west where the Triassic sequence directly overlies the basement. High values also occur over the Gil Gil Ridge in the middle, to the south over the Moree High, and to the north where the sequence is thicker. The reflectance gradient in the suppressed intervals is higher than in the overlying non- suppressed sequences, especially when the rank has resulted from burial depth.

Tmax from Rock-Eval pyrolysis was found to be lower in the perhydrous intervals, and was high in mature and igneous intrusion-affected intervals. Based on the source potential parameters, the Permian Back Creek Group is a better source than the Kianga Formation, while the Goonbri Formation is better than the Maules Creek Formation. The Triassic Napperby Formation has a fair capacity to generate oil, and is considered a better source rock than the equivalent Moolayember Formation. The Jurassic Walloon Coal Measures is a better source than Evergreen Formation, and has the best source rock characteristics, but is immature. The Rock-Eval S1 value shows better correlation with extracted hydrocarbon compounds (saturated and aromatics) than the total extractable organic matter. This suggests that solvent extraction has a greater ability to extract NSO compounds than temperature distillation over the Rock-Eval S1 interval.

Terrestrial organic matter is the main source input for the sequences studied. This has been identified from organic petrology and from the n-alkane distributions and the relatively high C29 steranes and low sterane/hopane ratios. The absence of marine biomarker signatures in the Permian marine influenced sequence, could be attributed to their dilution by overwhelming amounts of non-marine organic matter. A mainly oxic to suboxic depositional environment is inferred from trace amounts of 25-NH, BNH and

TNH. This is further supported by relatively high pr/ph ratios. Although C29/C30 is generally regarded as an environmental indicator, high values were noted in intrusion- affected samples. The 22S and 20S ratios were inverted ‘reaches pseudo-equilibrium’ in such rapidly heated, high maturity samples. The ratio of C24 tetracyclic terpane to C21-

C26 tricyclic terpanes decreases, instead of increasing, within the Napperby Formation close to a major igneous intrusive body. The 22S ratio, which is faster in reaction than the other terpane and sterane maturity parameters, shows that the Permian sequence lies within the oil generation stage in the Bowen Basin, except for a Kianga Formation

ii sample. The Triassic sequence is marginally mature, and the Jurassic sequence is considered immature. In the Gunnedah Basin, the Permian sequence in Bellata-1 and Bohena-1, and the Triassic sequence in Coonarah-1A, lie within the oil generation range. In the intrusion-affected high maturity samples, the ratio is reaches pseudo- equilibrium. This and other terpane and sterane maturity parameters are not lowered (suppressed) in the perhydrous intervals. The ββ sterane ratio, however, is slowest in reaction to maturity, and variations in low maturity samples are mainly due to facies changes. Diasterane/sterane ratios, in the current study, increase with increasing TOC content up to 5% TOC, but decrease in rocks with higher TOC contents including coals. Highly mature samples, as expected, in both cases are anomalous with high ratios. Calculated vitrinite reflectance based on the method of Radke and Welte (1983), as well as MPI 1 and MPI 2, shows the best comparison to observed values. These aromatic maturity parameters are lowered within the reflectance-suppressed intervals.

Oil stains in the Jurassic Pilliga Sandstone in the Bellata-1 well have been identified as being indigenous and not due to contamination. The vitrinite reflectance calculated to the oil stain suggests that the source rock should be within a late mature zone. Such high maturity levels are only recognised within intrusion-affected intervals. A close similarity between the oil stain sample and the intruded interval of the Napperby Formation is evident from the thermal maturity and biomarker content. Hydrocarbon generation and expulsion from the lower part of the Napperby Formation as a result of igneous intrusion effects is suggested as the source of the oil in this particular occurrence.

Terpane and sterane maturity parameters increase with increasing burial depth in the intervals with suppressed (perhydrous) vitrinite reflectance. The generation maturity parameters also increase through intervals with perhydrous vitrinite, which suggests that hydrocarbons continue to be generated and the actual amount is increasing even though traditional rank ‘stress’ maturity parameters are lowered. Accordingly, the Permian sequences in the lower part of the Bowen Basin are at least within the peak oil generation zone, and probably within late oil generation in the north and northeast of the study area. To generate significant amounts of hydrocarbon, however, the thickness of the shaly and coaly intervals in the Permian sequence is probably a critical parameter. In the Gunnedah Basin, a significant amount of hydrocarbon generation is probably only possible as a result of igneous intrusions. iii ACKNOWLEDGEMENTS

This research study was carried out under an Australian Postgraduate Award (Industry) provided by the Australian Research Council and New South Wales Department of Mineral Resources. This award was greatly appreciated. Thanks are also expressed to the American Association of Petroleum Geologists for an AAPG Foundation Grant-in- Aid award to assist the study.

I am extremely grateful to my supervisor, Professor Colin Ward, for his keen supervision, continuous support and encouragement throughout my research study. His discussions and suggestions improved the outcomes of this study significantly, and his critical reading and corrections of the manuscript are really appreciated.

I would like to express my appreciation to Mr. David Alder and Dr Victor Tadros of the New South Wales Department of Mineral Resources, for allowing access to samples from Departmental drilling programs, and for considerable advice and assistance with the study. I am also grateful to Dr. Lila Gurba of UNSW and Dr. Mohinudeen Faiz of CSIRO, for advice on vitrinite reflectance measurement and other aspects of the work program, and to Mr Rad Flossman of UNSW for preparation of the polished sections.

I deeply appreciate the assistance of Dr. Chris Boreham, of Geoscience Australia, for co-operation with the Rock-Eval analysis program, as well as his comments and fruitful discussion on the results, and also for access to complementary data held by Geoscience Australia. Appreciation is also expressed to Mr. Ian Atkinson of the Isotopic and Organic Geochemistry Laboratories, Geoscience Australia, for assistance with the Rock-Eval analysis process.

My sincere appreciation is expressed to Dr. Khaled Arouri and Professor David McKirdy, of the University of Adelaide, for their co-operation with the GCMS analysis. I would also like to extend my deep appreciation to Dr. Arouri for his kind hospitality, support, valuable comments and critical reading the biomarker chapter. I gratefully acknowledge the assistance of Dr. Kenneth Peters, from the United States Geological Survey, for discussion and significant comments on the biomarkers chapter.

iv I extend my appreciation to Associate Professor Roger Read of the UNSW School of Chemical Sciences, for making available laboratory facilities for solvent extraction of the rock samples. I also appreciate the assistance of Dr. Neil Sherwood and Dr. Simon George of CSIRO, and Dr. P. K. Mukhopadhyay of Global Geo-energy Research Ltd. Canada, for fruitful discussions on different aspects of the work.

Finally, I am very grateful for all the help provided by the staff of the School of Biological Earth and Environmental Sciences at UNSW, and to my colleagues for their continued support and encouragement.

v CONTENTS

1. Chapter 1 INTRODUCTION...... 1 1.1. Reasons, aims and scope of the thesis...... 1 1.2. Location and geological setting ...... 5 1.2.1. Bowen Basin ...... 5 1.2.2. Gunnedah Basin ...... 7 1.2.3. Surat Basin ...... 8 1.3. Basin evolution and depositional history ...... 9 1.3.1. Early Permian extension phase ...... 10 1.3.2. Early-Mid Permian thermal relaxation phase ...... 12 1.3.3. Late Permian-Triassic foreland loading phase...... 13 1.3.4. Late Permian contraction ...... 15 1.3.5. Early Triassic contraction ...... 16 1.3.6. Middle-Late Triassic contraction ...... 17 1.3.7. Late Triassic- Early Jurassic magmatic event...... 18 1.3.8. Early Jurassic thermal relaxation phase ...... 19 1.3.9. Post-Early Cretaceous contraction ...... 20 1.4. Previous studies...... 21

2. Chapter 2 RESEARCH DATA AND METHODOLOGY ...... 24 2.1. Research data ...... 24 2.1.1. Well completion reports...... 24 2.1.2. Well log data ...... 24 2.1.3. Samples ...... 24 2.2. Methodology ...... 26 2.2.1. Well logs ...... 26 2.2.2. Rock samples ...... 27 2.2.2.1. Sample selection ...... 27 2.2.2.2. Sample evaluation ...... 27 2.2.2.2.1. Petrographic studies ...... 27 2.2.2.2.1.1. Polished section preparation ...... 27 2.2.2.2.1.2. Vitrinite reflectance measurements...... 29 2.2.2.2.2. Geochemical studies ...... 29 2.2.2.2.2.1. Sample preparation ...... 29 2.2.2.2.2.2. Analytical Studies ...... 30 2.2.2.2.2.2.1. Rock-Eval Pyrolysis and Total Organic Carbon...... 30 2.2.2.2.2.2.2. Soxhlet Extraction...... 30 2.2.2.2.2.2.3. Column Chromatography...... 31 2.2.2.2.2.2.4. Gas Chromatography-Mass Spectrometry (GCMS) ...... 31

3. Chapter 3 STRATIGRAPHY...... 32 3.1. Introduction...... 32 3.2. Previous studies...... 35 3.3. Bowen-Surat Basin stratigraphic framework in the study area...... 36 3.4. Basis of correlation ...... 36 3.4.1. Well completion reports...... 36 3.4.2. Marine influenced sequences ...... 37 3.4.3. Triassic overpressure interval ...... 37 3.4.3.1. Concept ...... 37

vi 3.4.3.2. Overpressure as marker bed in the study area...... 40 3.5. Stratigraphic correlations ...... 40 3.5.1. Bowen-Surat Basin ...... 40 3.5.2. Correlation of Bowen and Gunnedah Basins...... 42 3.6. Discussion and conclusions ...... 47

4. Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA....49 4.1. Introduction...... 49 4.2. Vitrinite reflectance as maturity parameter...... 49 4.2.1. Concept ...... 49 4.2.2. Applications, limitations and anomalies ...... 52 4.3. Sampling ...... 55 4.4. Cuttings contamination/alteration ...... 56 4.4.1. Caving debris ...... 56 4.4.2. Oxidised cuttings...... 57 4.5. Reflectance pattern in the study area ...... 64 4.5.1. Vitrinite reflectance profiles and anomalies ...... 64 4.5.1.1. Vitrinite reflectance suppression...... 64 4.5.1.2. Igneous intrusion effects ...... 74 4.5.1.3. Lithology effects ...... 78 4.5.1.4. Vitrinite reflectance retardation due to overpressure...... 79 4.5.2. Vitrinite reflectance gradient...... 81 4.5.3. Lateral reflectance trends ...... 88 4.6. Discussion and conclusions ...... 90

5. Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY ...... 94 5.1. Introduction...... 94 5.2. Identification ...... 95 5.2.1. Rock-Eval pyrolysis...... 95 5.2.1.1. Concept ...... 95 5.2.1.2. Applications ...... 96 5.2.2. n-Alkanes and acyclic isoprenoids...... 100 5.2.2.1. Identification ...... 100 5.2.2.2. Source indicators...... 100 5.2.2.2.1. n-Alkanes ...... 100 5.2.2.2.2. Isoprenoids ...... 103 5.2.2.3. Maturity indicators...... 105 5.3. Source rock identification in the study area...... 106 5.3.1. Rock-Eval pyrolysis data ...... 106 5.3.1.1. Permian sequences ...... 106 5.3.1.1.1. Bowen Basin ...... 106 5.3.1.1.1.1. Back Creek Group...... 106 5.3.1.1.1.2. Kianga Formation ...... 110 5.3.1.1.2. Gunnedah Basin ...... 112 5.3.1.1.2.1. Goonbri Formation...... 112 5.3.1.1.2.2. Maules Creek Formation...... 115 5.3.1.1.2.3. Watermark/Porcupine Formation...... 115 5.3.1.1.2.4. Black Jack Group ...... 117 5.3.1.2. Triassic sequences...... 120

vii 5.3.1.2.1. Bowen Basin ...... 120 5.3.1.2.1.1. Moolayember Formation...... 120 5.3.1.2.2. Gunnedah Basin ...... 122 5.3.1.2.2.1. Napperby Formation ...... 122 5.3.1.3. Jurassic sequences...... 125 5.3.1.3.1. Surat Basin (Bowen Basin area) ...... 125 5.3.1.3.1.1. Evergreen Formation...... 125 5.3.1.3.1.2. Walloon Coal Measures ...... 128 5.3.1.3.2. Surat Basin (Gunnedah Basin area) ...... 128 5.3.1.3.2.1. Purlawaugh Formation...... 128 5.3.2. n-Alkanes and acyclic isoprenoids patterns ...... 130 5.4. Rock-Eval S1 and EOM relationship...... 134 5.5. Free bitumen effect on the Rock-Eval S2 peak ...... 137 5.6. Rock-Eval Tmax and vitrinite reflectance relationship...... 138 5.7. Suppression and hydrocarbon generation ...... 140 5.8. Discussion and conclusions ...... 144

6. Chapter 6 BIOMARKERS...... 149 6.1. Introduction...... 149 6.2. Concept ...... 149 6.3. Identification ...... 150 6.3.1. Triterpanes...... 151 6.3.1.1. Identification ...... 151 6.3.1.1.1. Hopanes and moretanes...... 151 6.3.1.1.2. Homohopanes...... 151 6.3.1.1.3. Norhopanes ...... 155 6.3.1.1.4. Diahopanes and neohopanes ...... 155 6.3.1.1.5. Methylhopanes ...... 155 6.3.1.1.6. Tricyclic terpanes...... 156 6.3.1.1.7. Tetracyclic terpanes ...... 156 6.3.1.2. Terpanes as source and environmental indicators...... 156 6.3.1.2.1. C29 and C30 hopanes ...... 156 6.3.1.2.2. Homohopanes...... 158 6.3.1.2.3. 28,30-BNH and 25,28,30-TNH...... 158 6.3.1.2.4. 17α(H)-diahopane (C30*) and 18α(H)-30-norneohopane (C29Ts) ..159 6.3.1.2.5. Methylhopanes ...... 159 6.3.1.2.6. Tricyclic terpanes...... 160 6.3.1.2.7. Tetracyclic terpanes ...... 160 6.3.1.3. Terpanes as maturity indicators ...... 161 6.3.1.3.1. 22S or 22S/(22S+22R) Homohopane ratio ...... 161 6.3.1.3.2. Moretane/hopane ratio ...... 162 6.3.1.3.3. Ts/(Ts+Tm) ...... 163 6.3.1.3.4. C29Ts/C29 hopane ...... 163 6.3.1.3.5. Tricyclic terpanes...... 163 6.3.1.3.6. Tetracyclic terpanes ...... 164 6.3.2. Steranes ...... 164 6.3.2.1. Identification ...... 164 6.3.2.1.1. Regular steranes ...... 164 6.3.2.1.2. Diasteranes ...... 167 6.3.2.1.3. Methylsteranes ...... 167

viii 6.3.2.2. Steranes as source indicators...... 168 6.3.2.2.1. Steranes/17α(H)-hopanes ratio ...... 168 6.3.2.2.2. C27 : C28 : C29 regular steranes ...... 168 6.3.2.2.3. C27 : C28 : C29 diasteranes...... 169 6.3.2.2.4. Diasteranes/regular steranes...... 170 6.3.2.2.5. 4-Methylsteranes...... 170 6.3.2.3. Steranes as maturity indicators...... 171 6.3.2.3.1. 20S/(20S+20R) Epimer ratio ...... 172 6.3.2.3.2. ββ/(ββ+αα) Ratio ...... 173 6.3.3. Aromatic hydrocarbons...... 173 6.3.3.1. Identification ...... 173 6.3.3.2. Aromatic hydrocarbons as source and environmental indicators ...... 176 6.3.3.3. Aromatic hydrocarbon biomarkers as maturity indicators...... 178 6.4. Applications in the study area...... 182 6.4.1. Terpanes and steranes as source and environmental indicators...... 182 6.4.2. Terpanes and steranes as maturity indicators...... 196 6.4.2. Aromatic hydrocarbons as source and maturity indicators...... 211 6.6. Discussion and conclusions ...... 219

7. Chapter 7 OIL-SOURCE CORRELATION ...... 223 7.1. Introduction...... 223 7.2. Oil staining occurrences...... 223 7.3. Samples and analysis ...... 226 7.3.1. Samples ...... 226 7.3.2. Analytical techniques...... 227 7.4. Oil stain characterisation...... 227 7.4.1. Aromatic source parameters...... 227 7.4.2. Thermal maturity of the oil stain...... 227 7.4. Vitrinite reflectance profile in Bellata-1 ...... 233 7.5. Source rocks and hydrocarbon generation ...... 235 7.6. Oil-source rock correlation ...... 236 7.6.1. n-Aalkanes and isoprenoids ...... 236 7.6.2. Hopane and sterane distributions ...... 237 7.6.3. Tricyclic terpanes...... 242 7.7. Discussion and conclusions ...... 242

8. Chapter 8 CONCLUSIONS ...... 245 8.1. Basin stratigraphy ...... 245 8.2. Vitrinite reflectance pattern...... 247 8.2.1. Reflectance profiles………………………………………………………..247 8.2.2. Reflectance gradients………………………………………………………249 8.2.3. Lateral reflectance trends……………………………………………….….250 8.3. Source rock geochemistry...... 250 8.3.1. Rock-Eval pyrolysis……………………………………………………….250 8.3.1.1. Organic richness...... 250 8.3.1.2. Thermal maturity...... 251 8.3.1.3. Rock-Eval S1 and free bitumen relationship ...... 251 8.3.2. Hydrocarbon biomarkers……………………………………………….….252 8.3.2.1. n-Alkanes and isoprenoids ...... 252 8.3.2.2. Sterane and terpane distributions ...... 252

ix 8.3.2.2.1. Source and environmental indicator...... 252 8.3.2.2.2. Maturity indicator...... 253 8.3.2.3. Aromatic maturity parameters...... 254 8.4. Rank advance and maturity in suppressed intervals ...... 255 8.5. Oil-source correlation...... 256 8.6. Hydrocarbon generation...... 256 8.6.1. Bowen Basin...……………………………………………………………..256 8.6.2. Gunnedah Basin...…………………………………….……………………257

REFERENCES………………………………………………………………………..258

APPENDIX 1 Vitrinite reflectance data for samples studied….………..…………....294

APPENDIX 2 Geochemical parameters guidelines used in source rock evaluation....302

APPENDIX 3 Publications arising from this study….………..…………..……….....304

x ILLUSTRATIONS

FIGURES

Figure 1-1: Major structural subdivisions in the study area (modified from Othman and Ward, 2002)...... 2 Figure 1-2: Study area showing borehole locations (modified from Othman and Ward, 2002)...... 4

Figure 2-1: Analytical flow chart...... 28

Figure 3-1: Representative stratigraphic section for the southern Bowen and lower part of the overlying Surat Basin sequence in northern New South Wales (modified from Othman and Ward, 1999)...... 33 Figure 3-2: Northern Gunnedah-Surat Basin stratigraphy (after Othman and Ward, 2002)...... 34 Figure 3-3: New stratigraphic interpretation in Boomi-1, Bowen Basin, northern New South Wales...... 38 Figure 3-4: Normal and abnormal compaction zones in the lower part of the Moolayember Formation in Glencoe-1. (A) Porosity logs and Gamma Ray response, (B) Neutron-depth profile (modified from Othman and Ward, 1999)....41 Figure 3-5: Stratigraphic correlation in the southern Bowen Basin and lower part of the overlying Surat Basin, northern New South Wales...... 43 Figure 3-6: Cross-section of the southern Bowen and northern Gunnedah Basin successions in northern New South Wales (modified from Othman and Ward, 1999)...... 45

Figure 4-1: Histogram plots of reflectance distribution for two selected samples in Limebon-1 well showing two populations; one from target interval and one from less mature caved debris (modified from Othman and Ward, 2002)...... 58 Figure 4-2: Vitrinite reflectance profile for contamination (open circles) due to caving and target intervals (dark circles) for Limebon-1. W = Walloon Coal Measures; H = Hutton Sandstones; E = Evergreen Formation; P = Precipice Sandstone; M = Moolayember Formation; S = Showgrounds Sandstone; K = Kianga Formation; BC = Back Creek Group (modified from Othman and Ward, 2002)...... 59 Figure 4-3: Effect of oxidised sample (open circle) on reflectance gradient in Pearl-1 well. Reflectance gradient in (A) is 0.054% per 100 m and in (B) is 0.047% per 100 m. See Figure 4-2 for units identification (modified from Othman and Ward, 2002)...... 63 Figure 4-4: Reflectance profiles from McIntyre-1 and Goondiwindi-1. Anomalously low, suppressed, values can be seen in the Back Creek Group in both sections. V = Volcanics. See Figure 4-2 for identification of other units (modified from Othman and Ward, 2002)...... 66 Figure 4-5: Reflectance profile for Bellata-1 with two different horizontal scales to clarify suppression phenomenon. Samples below 900 m (except for contact metamorphosed sample) have suppressed reflectance. Samples at 829.60, 871.55 and 1104.16 m are highly affected by local igneous intrusion ( I ). Pi = Pilliga Sandstone; Pu = Purlawaugh Formation; N = Napperby Formation; D = Digby

xi Formation; Po = Porcupine Formation; MC = Maules Creek Formation; G = Goonbri Formation; B = Basement (modified from Othman and Ward, 2002). ....67 Figure 4-6: Reflectance profile for Wilga Park-1. High reflectance values due to igneous intrusions occur throughout the section, even though only one actual intrusion is encountered at 621.18 m. W/P = Watermark/Porcupine Formation. See Figure 4-5 for identification of other units (modified from Othman and Ward, 2002)...... 68 Figure 4-7: Reflectance profile for Coonarah-1A. High reflectance values occur throughout the section due to igneous intrusions. BJ = Black Jack Group; Wa = Watermark Formation; see Figure 4-5 for identification of other units (modified from Othman and Ward, 2002)...... 69 Figure 4-8: Reflectance profile for Bohena-1 with two different horizontal scales, entire Permian sequence shows relatively low reflectance except for local heat affected sample at depth 855.73 m. See Figures 4-5, 4-6 and 4-7 for units identification. ..70 Figure 4-9: ‘Simple profile’ localised increase in vitrinite reflectance around intrusive body in Mt Pleasant-1. Despite this effect, the Back Creek Group (BC) clearly has a lower reflectance than the upper part of the sequence. See Figures 4-2 and 4-5 for identification of other units (modified from Othman and Ward, 2002)...... 76 Figure 4-10: Reflectance profile in Boomi-1 showing possible lithology effect on a sample at depth 1595.22 m. See Figures 4-2 and 4-5 for units identification...... 80 Figure 4-11: Variation in reflectance gradient for selected boreholes through Triassic and Jurassic sequences in the northwestern part of the study area. R = Rewan Group; KV = Kuttung Volcanics. See Figures 4-2, 4-3 and 4-5 for identification of other units (modified from Othman and Ward, 2002)...... 83 Figure 4-12: Cross section for the boreholes in Figure 4-11. See Figures 4-2, 4-5 and 4- 11 for units identification (modified from Othman and Ward, 2002)...... 85 Figure 4-13: Lateral variation in reflectance gradient for the upper (normal) and lower (suppressed) parts of the sequence in the southern Bowen Basin (modified from Othman and Ward, 2002)...... 87 Figure 4-14: Isoreflectance map for a horizon at the contact of the Moolayember Formation with the Showgrounds Sandstone in the southern Bowen Basin (modified from Othman and Ward, 2002)...... 89

Figure 5-1: Structure of n-alkane and acyclic isoprenoids. Pristane is used as an example of the numbering system...... 101 Figure 5-2: Source potential rating based on (A) S2-TOC and (B) TOC-EOM plots for the Permian Back Creek Group, Bowen Basin...... 111 Figure 5-3: Source-rock richness plot for the Permian Back Creek Group, Bowen Basin...... 111 Figure 5-4: Kerogen type and estimation of maturity for the Permian Back Creek Group, Bowen Basin...... 111 Figure 5-5: Source potential rating based on (A) S2-TOC and (B) TOC-EOM plots for the Late Permian Kianga Formation, Bowen Basin...... 113 Figure 5-6: Source-rock richness plot for the Late Permian Kianga Formation, Bowen Basin...... 113 Figure 5-7: Kerogen type and estimation of maturity for the Late Permian Kianga Formation, Bowen Basin...... 113 Figure 5-8: Source potential rating based on (A) S2-TOC and (B) TOC-EOM plots for the Early Permian Goonbri Formation, Gunnedah Basin...... 114 Figure 5-9: Source-rock richness plot for the Early Permian Goonbri Formation, Gunnedah Basin...... 114

xii Figure 5-10: Kerogen type and estimation of maturity for the Early Permian Goonbri Formation, Gunnedah Basin...... 114 Figure 5-11: Source potential rating based on (A) S2-TOC and (B) TOC-EOM plots for the Early Permian Maules Creek Formation, Gunnedah Basin...... 116 Figure 5-12: Source-rock richness plot for the Early Permian Maules Creek Formation, Gunnedah Basin...... 116 Figure 5-13: Kerogen type and estimation of maturity for the Early Permian Maules Creek Formation, Gunnedah Basin...... 116 Figure 5-14: Source potential rating based on (A) S2-TOC and (B) TOC-EOM plots for the Permian Watermark/Porcupine Formation, Gunnedah Basin...... 118 Figure 5-15: Source-rock richness plot for the Permian Watermark/Porcupine Formation, Gunnedah Basin...... 118 Figure 5-16: Kerogen type for the Permian Watermark/Porcupine Formation, Gunnedah Basin...... 118 Figure 5-17: Source potential rating based on (A) S2-TOC and (B) TOC-EOM plots for the Late Permian Black Jack Group, Gunnedah Basin...... 119 Figure 5-18: Source-rock richness plot for the Late Permian Black Jack Group, Gunnedah Basin...... 119 Figure 5-19: Kerogen type and estimation of maturity for the Late Permian Black Jack Group, Gunnedah Basin...... 119 Figure 5-20: Source potential rating based on (A) S2-TOC and (B) TOC-EOM plots for the Middle Triassic Moolayember Formation, Bowen Basin...... 121 Figure 5-21: Source-rock richness plot for the Middle Triassic Moolayember Formation, Bowen Basin...... 121 Figure 5-22: Kerogen type and estimation of maturity for the Middle Triassic Moolayember Formation, Bowen Basin...... 121 Figure 5-23: Rock-Eval 6 pyrogram illustrating bimodal S2 peak possibly due to free NSO compounds in the Moolayember Formation (sample No. 7)...... 123 Figure 5-24: Source potential rating based on (A) S2-TOC and (B) TOC-EOM plots for the Middle Triassic Napperby Formation, Gunnedah Basin...... 124 Figure 5-25: Source-rock richness plot for the Middle Triassic Napperby Formation, Gunnedah Basin...... 124 Figure 5-26: Kerogen type and estimation of maturity for the Middle Triassic Napperby Formation (dark circles) and Jurassic Purlawaugh Formation (open circles), Gunnedah Basin...... 124 Figure 5-27: Rock-Eval 6 pyrogram illustrates S2 profile for Napperby Formation, sample No. 36...... 126 Figure 5-28: Source potential rating based on (A) S2-TOC and (B) TOC-EOM plots for the Early Jurassic Evergreen Formation, Bowen Basin...... 127 Figure 5-29: Source-rock richness plot for the Early Jurassic Evergreen Formation, Bowen Basin...... 127 Figure 5-30: Kerogen type and estimation of maturity for the Early Jurassic Evergreen Formation, Bowen Basin...... 127 Figure 5-31: Source potential rating based on (A) S2-TOC and (B) TOC-EOM plots for the Middle Jurassic Walloon Coal Measures, Bowen Basin...... 129 Figure 5-32: Source-rock richness plot for the Middle Jurassic Walloon Coal Measures, Bowen Basin...... 129 Figure 5-33: Kerogen type and estimation of maturity for the Middle Jurassic Walloon Coal Measures, Bowen Basin...... 129

xiii Figure 5-34: Mass chromatograms (m/z 85) showing alkane distributions in the selected Permian samples in the study area...... 131 Figure 5-35: Mass chromatograms (m/z 85) showing alkane distributions in the selected Triassic samples in the study area...... 132 Figure 5-36: Mass chromatograms (m/z 85) showing alkane distributions in the selected Jurassic samples in the study area...... 133 Figure 5-37: Rock-Eval S1 versus (A) EOM, (B) Hydrocarbons and (C) NSO compounds relationship for the studied samples...... 136 Figure 5-38: Measured vitrinite reflectance versus Tmax relationship for (A) all analysed o samples, and (B) Rv,max and Tmax values less than 1.5% and 450 C respectively. 139 Figure 5-39: Comparison between traditional rank and generation maturity parameters in Bellata-1, Gunnedah Basin. TOC and HI relation to depth show the quantity and quality of the organic matter. Stratigraphy showing major igneous intrusions within lower part of the Napperby Formation. Open circles represent samples influenced by igneous intrusions. Individual data points are joined by lines to facilitate comparison of different indicators used...... 142

Figure 6-1: Terpanes structures identified in this study...... 152 Figure 6-2: Hopanes gas chromatogram (for peak identification see Table 6-1)...... 154 Figure 6-3: Tricyclic terpanes gas chromatogram (see Table 6-2 for peak identification). Sample No. 49...... 157 Figure 6-4: Steranes, diasteranes and methylsteranes identified in this study...... 165 Figure 6-5: Steranes gas chromatogram (see Table 6-3 for peak identification)...... 166 Figure 6-6: Aromatic structures identified in this study...... 174 Figure 6-7: Composite mass chromatograms (m/z 156 + 170 + 178 + 192 + 206 + 219) showing the distributions of dimethylnaphthalene (DMN), trimethylnaphthalene (TMN), phenanthrene (P), methylphenanthrene (MP), dimethylphenanthrene (DMP) and retene. See Table 6-4 for peak identification...... 175 Figure 6-8: Selected hopane chromatograms (m/z 191)...... 188 Figure 6-9: Selected methylhopane chromatograms (m/z 205)...... 191 Figure 6-10: Selected sterane chromatograms (m/z 217)...... 192 Figure 6-11: Ternary plots of (A) C27-C29 regular steranes and (B) C27-C29 diasteranes showing C29 compound predominance, except in highly mature samples...... 194 Figure 6-12: TOC% versus diasterane/sterane ratio; positive correlation for samples with up to 5.0% TOC content and negative correlation with higher TOC% content. Intrusion affected postmature samples are anomalously separated...... 195 Figure 6-13: Selected methylsterane chromatograms (m/z 231)...... 197 Figure 6-14: Approximate correlation of various biomarker maturity parameters used in this study with stages of coalification and petroleum generation (modified from Tissot and Welte, 1984; Killops and Killops, 1993; Peters and Moldowan, 1993; Peters and Cassa, 1994)...... 198 Figure 6-15: Hopane and sterane maturity parameter plots in Bellata-1...... 202 Figure 6-16: Hopane and sterane maturity parameter plots in Goondiwindi-1...... 203 Figure 6-17: 22S versus Rv,max % relationship showing inversion of 22S ratios in intrusion effected highly mature samples...... 204 Figure 6-18: Relative abundance of tricyclic and tetracyclic terpanes in relation to hopanes with increasing maturity due to igneous intrusion in Napperby Formation, Bellata-1...... 207 Figure 6-19: Variations in tricyclic and tetracyclic terpanes with increasing thermal maturity due to igneous intrusion in Napperby Formation, Bellata-1...... 208

xiv Figure 6-20: Measured and calculated vitrinite reflectance plots for samples of Table 6- 9. Rv,max% versus Rc(rw)% shows closest similarity...... 214 o Figure 6- 21: Tmax ( C) versus measured and calculated vitrinite reflectance plots for samples of Table 6-9...... 215 Figure 6- 22: Variations of aromatic maturity parameters with depth for Bellata-1. MPI 2 marked as open circles...... 216 Figure 6- 23: Changes in the 1-, 2-, 3- and 9-MP abundance with increasing maturity close to igneous intrusions in the Napperby Formation, Bellata-1...... 218

Figure 7-1: Stratigraphy in Bellata-1, showing major igneous intrusions (see Table 7-1), the horizons sampled for oil staining (+) and potential source rocks (●), (modified from Othman et al., 2001)...... 224 Figure 7-2: Source affinity of the oil stain based on the aromatic hydrocarbon plots (modified from Othman et al., 2001)...... 231 Figure 7-3: Mass chromatograms (m/z 85) show the alkane distributions in the oil stain and selected potential source rocks in Bellata-1 (modified from Othman et al., 2001)...... 232 Figure 7-4: Calculated and measured vitrinite reflectance relationship in Bellata-1, open circle is the oil stain sample that clearly differs...... 234 Figure 7-5: Vitrinite reflectance profile in Bellata-1 (modified from Othman et al., 2001)...... 234 Figure 7-6: Mass chromatograms of triterpanes (m/z 191) and steranes (m/z 217) in the oil stain and potential source rocks in Bellata-1 (modified from Othman et al., 2001)...... 238 Figure 7-7: Sterane maturation – migration parameters for the oil stain and potential source rocks in Bellata-1 (modified from Othman et al., 2001)...... 240 Figure 7-8: Pristane/phytane vs. C29/C27 steranes plot for the oil stain and potential source rocks in Bellata-1 (modified from Othman et al., 2001)...... 240 Figure 7-9: Ternary plots for C27 – C29 (A) regular steranes, and (B) diasteranes for the oil stain and potential source rocks in Bellata-1 (modified from Othman et al., 2001)...... 241 Figure 7-10: Mass chromatograms of tricyclic terpanes (m/z 191) in the oil stain and potential source rocks in Bellata-1 (modified from Othman et al., 2001)...... 243

TABLES

Table 2-1: Sample details for boreholes studied...... 25

Table 4-1: Bottom hole temperature, present-day geothermal gradient and reflectance gradient in the boreholes studied (after Othman and Ward, 2002)...... 82

Table 5-1: Rock-Eval pyrolysis and vitrinite reflectance data for potential source rocks in the study area...... 107 Table 5-2: Bulk chemical composition for potential source rocks in the study area. ...109

Table 6-1: Identification of peaks in Figure 6-2...... 154 Table 6-2: Identification of peaks in Figure 6-3...... 157 Table 6-3: Identification of peaks in Figure 6-5...... 166 Table 6-4: Identification of peaks in Figure 6-7...... 175

xv Table 6-5: Terpanes and steranes used as source parameters in the study area. Refer to Table 6-6 for parameters identification...... 183 Table 6-6: Identification of the parameters used in table 6-5...... 186 Table 6-7: Terpanes and steranes as maturity parameters. For parameters identification see Table 6-8...... 199 Table 6-8: Identification of the parameters used in Table 6-7...... 200 Table 6-9: Aromatic parameters used in this study. For parameters identification see Table 6-10...... 212 Table 6-10: Identification of the parameters used in Table 6-9...... 213

Table 7-1: Thickness’ of igneous intrusions intersected in Bellata-1...... 225 Table 7-2: Geochemical data on the oil-stained Pilliga Sandstone and Permo-Triassic potential source rocks in Bellata-1 (modified from Othman et al., 2001). For parameters identification see Chapter 6...... 228 Table 7-3: Rock-Eval data on potential source rocks, Bellata-1 (modified from Othman et al., 2001)...... 230

PLATES

Plate 4-1: Features of macerals in samples studied...... 61 Plate 4-2: Features of liptinite macerals in the samples studied from the Goonbri Formation...... 72

xvi

xvii Chapter 1 INTRODUCTION

1. Chapter 1 INTRODUCTION

1.1. Reasons, aims and scope of the thesis

The Permo-Triassic Sydney, Gunnedah and Bowen Basins and the overlying Jurassic- Cretaceous Surat Basin (Figure 1-1) were formed adjacent to the New England Fold Belt in eastern Australia. The basins represent probably the most economically significant sedimentary system in the country, and represent one of the world’s major coal-producing terrains (Hammond, 1990). The basins have been associated with coal exploration and mining for over a century, and with hydrocarbon exploration and production, particularly in the Bowen and overlying Surat Basin succession in Queensland, for several decades.

The Bowen and the overlying Surat Basins were the site of the first commercial oil discovery in Australia (23.5 million barrels recoverable), at Moonie southeastern Queensland in 1961 (Thomas et al., 1982). The basins are still producing significant amounts of Australia’s oil and gas from mainly Jurassic and Triassic sequences, which were sourced from Permian and Triassic strata (e.g. Hawkins et al., 1992; Boreham, 1994, 1995; Arouri et al., 1998a, 1998b). These sequences continue into the New South Wales portion of the Bowen-Surat Basin, but as yet no major petroleum discoveries have been made in this sector. Further south in the Gunnedah-Surat Basin, the southern continuation of the Bowen-Surat Basin, several gas discoveries have been made (Morton, 1995) but no commercial production has been recorded. In the last few decades various studies have been published describing the hydrocarbon deposits and source rocks of Bowen-Surat Basin. Most of these studies have concentrated on that part of the basin north of the Queensland - New South Wales border. Exploration activity and research work are very limited in the New South Wales sector of these basins (the area studied) compared to the Queensland portion (Shaw, 2002).

This study was carried out under an Australian Postgraduate Award (Industry), in collaboration with the Coal and Petroleum Geology Branch of the New South Wales Department of Mineral Resources. The objectives of the study were to assess the hydrocarbon generation potential and to investigate in detail the three-dimensional

1 Chapter 1 INTRODUCTION

Figure 1-1: Major structural subdivisions in the study area (modified from Othman and Ward, 2002).

2 Chapter 1 INTRODUCTION pattern of thermal maturity in the strata of the Permian-Triassic southern Bowen and northern Gunnedah Basins and the overlying Jurassic-Cretaceous Surat Basin in northern New South Wales. The research has been based on 30 petroleum and stratigraphic boreholes that cover a total of more than 20 000 km2, extending over a region from the Queensland-New South Wales border to north of Boggabri (Figure 1-2).

To achieve the first objective of these studies, organic petrology, Rock-Eval pyrolysis, total organic carbon, and extract and biomarker analysis techniques were applied to selected samples from the Permian, Triassic and Jurassic sediments, to evaluate the potential source rocks in the area.

A second objective of the study was the use of extensive vitrinite reflectance measurements to evaluate in detail the maturation pattern of the region. This comprehensive study assisted in identifying variations in maturity both vertically (in borehole sections) and horizontally, including development of an isoreflectance map for the northern part of the study area over an interval between the Showgrounds Sandstone and the Moolayember Formation, both of Middle Triassic age. Correlation between the various maturation parameters was also established, and anomalies in maturation indicators due to igneous intrusions, marine influence, liptinite-rich organic matter and other possible factors were also investigated.

The boreholes in the study area were drilled over a period of several decades, and different names were applied in many cases to the same stratigraphic units encountered in different wells. Re-evaluation of the stratigraphy was therefore very significant in the first stage of the study. Well log data were used, in conjunction with vitrinite reflectance anomalies, to develop a consistent stratigraphic section for the southern Bowen-Surat Basin sequence in northern New South Wales. The proposed stratigraphy was correlated with the better-known Gunnedah-Surat Basin succession, the southern part of the research area, and used as a framework for the current study.

In addition, the techniques used in this study were used to help solve a long-standing problem relating to the uncertainty of the origin of an oil trace identified in the Jurassic Pilliga Sandstone from the Bellata-1 well in the Gunnedah-Surat Basin, and to relate this oil stain to its source rock and generation conditions. 3 Chapter 1 INTRODUCTION

Figure 1-2: Study area showing borehole locations (modified from Othman and Ward, 2002).

4 Chapter 1 INTRODUCTION

The outcomes of the study have contributed significantly to future petroleum exploration activities in the region, particularly since this is the first comprehensive petrographic and geochemical study in the area.

1.2. Location and geological setting

The Sydney, Gunnedah and Bowen Basins are interconnected sedimentary basins (Mallett et al., 1995), formed from one depositional basin system with prominent structural subdivisions. The basin extends for 1700 km along the eastern margin of Australia from central Queensland in the north to the edge of the continental shelf in southeast New South Wales (Tadros, 1988). The basin attains a maximum preserved onshore width of approximately 200 km (Kassan and Fielding, 1996). The overlying Surat Basin is an intracratonic sag containing Jurassic and Cretaceous sediments, extending across an area of 270 000 km2. The southern third of the Surat Basin extends well into northern New South Wales (Shaw, 2002).

1.2.1. Bowen Basin

The Bowen Basin represents the northernmost unit of the Bowen-Gunnedah-Sydney foreland basin system, located mainly in east central Queensland but extending south into northern New South Wales. The basin is elongated in shape, with a length of 900 km, extending from Collinsville in Queensland to Moree in New South Wales. The southern part of the basin is covered by the Surat Basin succession. Exon (1974, 1976) has intimated that the Taroom Trough, in the eastern part of the Bowen Basin, intertongues in the south with the Gunnedah Basin across the Narrabri Structural High. The basin crops out approximately between latitude 20o S and 25o S (Green et al., 1997). The present eastern margin of the Bowen Basin is the Moonie-Goondiwindi Thrust and its northern extension, the Burunga-Leichhardet Complex fault zone. To the west, the Permo-Triassic sequence of the Bowen Basin wedges out over the Walgett and Roma Shelves. A major angular unconformity is recognised with the overlying Jurassic- Cretaceous Surat Basin succession (Elliott, 1993). The basement rocks beneath the Bowen and Surat Basins are part of the Tasman Fold Belt System, which occupies the eastern third of the Australian continent (Murray, 1990).

5 Chapter 1 INTRODUCTION

The Bowen Basin comprises two major depocentres, the Denison Trough in the northwest and the Taroom Trough in the east, separated by the Collinsville Shelf in the north and the Comet Platform in the south. The Comet Platform is a high that maintained its topography throughout most of the basin’s depositional history (Ziolkowski and Taylor, 1985). The Denison Trough is a deep tectonic feature, approximately 320 km long and 65 km wide. The trough contains up to 4600 m of marine and non-marine Permian and Triassic strata (Paten et al., 1979). To the east, the Taroom Trough is the main part of the Bowen Basin beneath the Surat Basin succession. The trough is an elongate north south trending half graben, which plunges steadily to the north. The structure of the Taroom Trough represents an asymmetric depocentre forming the eastern part of the Bowen Basin, which extends to the south across the Queensland – New South Wales border to northern New South Wales. The deepest point in the trough is located at about latitude 25o S (O’Brien, 1984). Exon (1976) estimated that it contains around 10 000 m of sediment, and the same estimate is suggested by Totterdell et al. (1995). The basin shallows to the south so that, at about latitude 28o S, only approximately 600 m of sediment is present (O’Brien, 1984).

Totterdell and Krassay (1995) mentioned that the equivalent succession of the Bowen Basin in northern New South Wales is much thinner and less complete. The Gil Gil Ridge in New South Wales divides the Bowen Basin sequence into two elongated, mainly north south trending structural units (Figure 1-1). The Gil Gil Ridge probably continues, over the Moree High, to the Boggabri Ridge in the Gunnedah Basin.

The Permo-Triassic sequence of the Bowen Basin consists of terrestrial and shallow marine, largely clastic sediments, along with substantial economic deposits of bituminous coal. In New South Wales, the Permian sediments of the Bowen Basin are completely overlain by Mesozoic and Cenozoic sediments, and the sequence is only known from bore samples and cores (Jones, 1985). The Permian sequence in the New South Wales portion of the basin consists of the Kuttung Formation, Back Creek Group and Kianga Formation, while the Showgrounds Sandstone and Moolayember Formation, including the Snake Creek Mudstone Member, represent the Triassic sequence (Othman and Ward, 1999). However, the Lower Triassic Rewan Group is present only in the extreme north of the New South Wales Bowen Basin succession (Shaw, 1995; Totterdell and Krassay, 1995; Othman and Ward, 1999). 6 Chapter 1 INTRODUCTION

1.2.2. Gunnedah Basin

The Gunnedah Basin is located between the Bowen Basin in the north and the Sydney Basin in the south (Tadros, 1988). The basin is a structural trough with an elongated appearance, trending north-northwest in northern New South Wales (Figure 1-1). It contains rocks of Permian and Triassic age, and represents the major coal province in eastern Australia (Hamilton et al., 1988; Tadros, 1995a). The Late Palaeozoic New England Fold Belt bounds the basin in the east along the Hunter-Mooki Thrust. In the west, the boundary is depositional or erosional rather than structural; the Permo-Triassic sediments thin and lap on to the metamorphosed rocks of the Early Palaeozoic Lachlan Fold Belt, making a regional unconformity the boundary to the west. In the north, the boundary between the Gunnedah and Bowen Basins is along a transverse structural high north of Narrabri, and in the south the basin is bounded along the Mount Coricudgy Anticline, which separates the Gunnedah Basin from the Sydney Basin (Bembrick et al., 1973).

The Gunnedah Basin, as described by Korsch et al. (1993), consists of three sub-basins separated by two ridges. From west to east these have been referred to as the Gilgandra Trough, Rocky Glen Ridge, West Gunnedah Sub-basin, Boggabri Ridge and Maules Creek Sub-basin. However, Tadros (1988, 1993a) divided the basin to three sub-basins on the basis of the same Rocky Glen and Boggabri Ridges. From west to east these are the Gilgandra, Mullaley and Maules Creek Sub-basins, with additional transverse structural highs dividing the Gilgandra and Mullaley Sub-basins into further structural units. The Mullaley Sub-basin, the middle elongate structure, is sub-divided into four troughs separated by three structural highs and one ridge. From the Mount Coricudgy Anticline in the south (Figure 1-1), the structural subunits for the Mullaley Sub-basin are the Murrurundi Trough, the Bundella and Yarraman Highs, the Bando Trough, the Walla Walla Ridge, the Bohena Trough, the Narrabri High and the Bellata Trough.

The Moree High in the north separates these from the Bowen Basin. The Narrabri High probably represents the subsurface boundary between the Gunnedah and Bowen Basins. The northern part of the Gunnedah Basin, involved in this study, includes the Bohena and Bellata Troughs in the area north of Boggabri.

7 Chapter 1 INTRODUCTION

The Gunnedah Basin contains up to 1200 m of marine and non-marine Permian and Triassic sediments (Tadros, 1995a), which rest nonconformably upon Permian and possibly older basement (Russell and Middleton, 1981). The Permo-Triassic sequence of the Gunnedah Basin is unconformably overlain partially by the Jurassic-Cretaceous strata of the Surat Basin (Mullard, 1995). The Permian sequence is characterised by three major constructive depositional episodes representing deltaic and alluvial environments, separated by two significant marine transgressive events (Hamilton and Beckett, 1984). The Permian sequence in the study area consists of the Goonbri, Maules Creek, Porcupine, and Watermark Formations and the Black Jack Group; the Triassic sequence includes the Digby and Napperby Formations.

1.2.3. Surat Basin

The Jurassic-Cretaceous Surat Basin represents the eastern part of the Great Australian Basin. The Great Australian Basin is a composite structural basin that represents a relict group of major Jurassic-Cretaceous epicratonic sedimentary basins occupying about 1.7 million square kilometres of inland eastern Australia. The principal individual structural basins within this area are the Carpentaria, Eromanga, Surat, and Clarence-Moreton Basins. These basins are lithologically continuous in part, and separated by pre- Mesozoic basement ridges (Cramsie and Hawke, 1984).

The Auburn Arch and the New England Fold Belt in the east bound the Surat Basin; between these two highs it intertongues with the Clarence-Moreton Basin across the Kumbarella Ridge. To the west, the Surat Basin sequence intertongues with the Eromanga Basin across the Nebine Ridge and its broad southerly extension, the Cunnamulla Shelf. In the south the Central West (or Lachlan) Fold Belt bounds the Surat Basin, and in the north it has been eroded (Exon, 1974).

The Surat Basin is asymmetric, being wedge-shaped in cross section with the sedimentary section gradually thickening from the western margin to the axis of the Jurassic-Cretaceous trough, the Mimosa Syncline, and thinning more sharply farther east to the Kumbarella Ridge (Power and Devine, 1970). Thomas et al. (1982) suggested that the thickness of the Surat Basin sediments reaches up to 2500 m in the

8 Chapter 1 INTRODUCTION

Mimosa Syncline, which unconformably overlies the Permian and Triassic sediments of the Taroom Trough. However, the basin in New South Wales is a more shallow extension of the main basin sequence in Queensland. A reasonably complete and thick Jurassic-Cretaceous sequence occurs north of Moree, near the Queensland border (Cramsie and Hawke, 1984). The maximum thickness of the Surat Basin succession in this area, the Boomi Trough of Bourke et al. (1974), is about 1800 m. The reduction in Jurassic-Cretaceous sediment thickness southwards from Queensland to New South Wales is due to onlap of basal Early Jurassic units, overall thinning and in some cases pinching out of mid-Jurassic units, and in the southern areas erosion or non-deposition of the upper interval (Hawke and Bourke, 1984).

The stratigraphic sequence of the Surat Basin in New South Wales is divisible into four main intervals. The lowest is an Early to Middle Jurassic, predominantly fine-grained, terrestrial sequence on the eastern side. This is overlain by a widespread and relatively thick, dominantly fluvial sandstone sequence of Middle Jurassic to Neocomian age. A Neocomian to early Albian transgressive/marine/regressive, essentially fine-grained sequence, and finally in the deepest central area a further transgressive/regressive sequence of Albian age (Hawke and Bourke, 1984) complete the succession.

In addition to the Permian and Triassic succession, the present study is also focussed on the sequences from the lowermost part of the Surat Basin. This mainly includes the Evergreen Formation and the Walloon Coal Measures in the area north of the Moree High, and the Purlawaugh Formation, partially a Walloon Coal Measures equivalent, south of the high.

1.3. Basin evolution and depositional history

The stratigraphic sequences and depositional environments in the Bowen, Gunnedah and overlying Surat Basins are more fully discussed in Chapter 3. The Early Permian to Middle Triassic Bowen and Gunnedah Basins developed in response to a series of interplate and intraplate tectonic events located to the east of the basin system (Korsch, et al., 1998). The basins therefore have a similar subsidence history (Scheibner, 1993; Korsch and Totterdell, 1996), and were initiated as part of a single basin system in a back-arc tectonic setting (Korsch et al., 1993).

9 Chapter 1 INTRODUCTION

The Bowen, Gunnedah and Sydney Basins of eastern Australia are related in space and time. Several theories have been proposed to account for the formation of these basins. These theories have been discussed by Murray (1990), and include: cooling of mantle diapirs, rifting, back-arc spreading, extensional, transtensional, strike-slip, retro-arc foreland basin, fold-thrust belt foreland basin and fore-arc trough mechanisms. Scheibner (1993) discusses these theories further. Some of the models, however, apply to specific parts of the basins or to particular time intervals (Murray, 1990). The widely accepted view is that the basins developed entirely as foreland basins (Korsch et al., 1993), because they display many features consistent with a foreland basin setting (Tadros, 1995b), such as the regional structure and the rock types present along the eastern margin (Elliott, 1989). The present foreland basin configuration, however, only began to form after the mid-Permian period of deformation in the New England Fold Belt, when the Hunter-Mooki Fault System developed (Tadros, 1993c). In its early history, the basin was initiated in the Late Carboniferous or Early Permian by extensional tectonics (Scheibner, 1974; Elliot, 1993; Korsch and Totterdell, 1996; Korsch et al., 1998).

The depositional and tectonic history in eastern Australia, which is outlined here to provide a background for correlation, has been divided into several phases and deformations (e.g. Elliott, 1993; Hamilton et al., 1993; Tadros, 1993c; Totterdell et al., 1995; Korsch and Totterdell, 1995, 1996; Korsch et al., 1998). These are discussed as follows:

1.3.1. Early Permian extension phase

Evidence of this phase is best seen in the Denison Trough, on the western side of the Bowen Basin (Korsch and Totterdell, 1995). Clastic deposition was initiated in the Bowen Basin at the beginning of the Early Permian. In the Late Carboniferous or Early Permian the Bowen Basin was initiated as a result of back-arc extension associated with subduction along the continental-margin Camboon Volcanic Arc (Totterdell et al., 1995). At the same time in the eastern part of the Bowen Basin, in the Taroom Trough, there was an eruption of a thick volcanic pile and deposition of associated volcaniclastic

10 Chapter 1 INTRODUCTION sediments, probably also in an extensional environment (Murray, 1990). Mallett et al. (1995) suggested that the Taroom Trough, however, developed during the foreland basin phase of the basin’s tectonic history. These Early Permian volcanics are thought to be associated with a rifting event, based on interpretation of the Meandarra Gravity Ridge as a rift system associated with mafic volcanics (Murray, 1990). The upper part of a volcanic and sedimentary succession, the Kuttung Formation in the Undulla- Moonie area, which is also intersected in New South Wales boreholes, is time equivalent of the Camboon Volcanics (Totterdell et al., 1995). Korsch et al. (1992) suggested that, when extension was occurring in the northwest, the central part of the basin system was obliquely extensional and controlled by the north-south-bounding faults. The Early Permian phase in the Bowen Basin was followed by a mid-Permian thermal relaxation phase and a final Late Permian to Middle Triassic foreland basin stage (Murray, 1990).

The Gunnedah Basin, like the Bowen Basin, experienced an Early Permian extensional stage, followed by a mid-Permian thermal relaxation phase and a final Late Permian to Middle Triassic foreland basin phase (Scheibner, 1993). The basin fill, in the Early Permian, was localised in small rapidly subsiding troughs, separated by highlands and ridges consisting of silicic and mafic volcanics. Fine-grained lacustrine sediments, represented by the Goonbri Formation, accumulated in the most rapidly subsiding areas in the troughs (the Maules Creek Sub-basin, Bohena and Bando Troughs), whereas prograding volcanic-lithic alluvial fan and piedmont deposits accumulated on the flanks of the highs and ridges and on the trough margins. Alluvial sedimentation ultimately filled the lakes and covered the trough areas with thick sequences of fluvial sandstones and conglomerates of volcanic-lithic composition (Maules Creek Formation), while the highs and ridges were only partially covered by thin sediments (Tadros, 1993a). The Maules Creek Formation was sourced with a minor contribution from the Lachlan Orogen and locally from the Boggabri Volcanics (Thomson and Flood, 1984). The style of sedimentation in that period was typical of tectonically controlled volcanic rift sub- basins. Deposition in these sub-basins reflects subsidence of the underlying half- grabens, whereas the highs and ridges represent more stable basement structures and define the rift compartments (Tadros, 1993a, 1995b).

11 Chapter 1 INTRODUCTION

1.3.2. Early-Mid Permian thermal relaxation phase

The thermal relaxation in the Bowen Basin, which followed the extensional stage, resulted in deposition of marine sediments (Beeston et al., 1995). The marine transgression probably entered from the east over the subsiding and inactive volcanic arc (Fielding et al., 1990). During the early Permian, volcanism declined. Up to 3000 m of volcanoclastic sediments of the Back Creek Group were deposited under predominantly marine conditions, with a brief episode of deltaic sedimentation in the Taroom Trough. In their study on the Back Creek Group in the area extending from northern New South Wales to southern Queensland, Morton et al. (1993) identified four main depositional types in the Back Creek Group. These are alluvial fan/upper delta plain to fluvial, lower delta plain fluvial/marginal marine, lagoon/marsh to interdistributary/bay, and finally wholly marine sediments.

In the Gunnedah Basin, the thermal relaxation stage followed Early Permian tectonic extension. Relaxation occurred during the latest Early Permian to earliest Late Permian, and was soon succeeded by foreland tectonics that controlled basin development until the Middle Triassic. The relaxation stage is clearly indicated by changes in style of sedimentation from localised fluvial and lacustrine deposition, within several small trough areas controlled by tectonic subsidence of half-grabens (rift compartments) to basin wide marine deposition. The Porcupine – lower Watermark marine-shelf system, caused by regional subsidence and widespread marine incursion, represents this type of activity. The sediment was locally derived from the Boggabri Ridge, with some input of quartzose detritus from the Lachlan Orogen (Korsch et al., 1993). Sedimentation was initially dominated by shallow-marine conditions, but with continued inundation the marine shelf setting deepened (Tadros, 1995c). The maximum extent of the Late Permian marine transgression into the Gunnedah Basin is represented by deposition of the lower part of the Watermark Formation (Hamilton, 1991). This Late Permian regional subsidence is thought to have been caused by thermal relaxation of the lithosphere (Tadros, 1993a, 1995b).

12 Chapter 1 INTRODUCTION

1.3.3. Late Permian-Triassic foreland loading phase

In the Late Permian, uplift and westward thrusting of the New England Fold Belt (Hunter-Bowen Orogeny) transformed the Bowen-Gunnedah-Sydney Basin into a foreland basin, with the typical asymmetric shape. Compressional deformation of the basin commenced at this time. The increased Triassic, particularly Early Triassic, sedimentation rate in the Taroom Trough may have been due to the uplift and westward thrusting, supporting the transition to a foreland basin model (Murray, 1990). The onset of the foreland loading phase appears to be diachronous across the basin, being earlier in the east than in the west. Sediments deposited during the foreland loading phase thin dramatically from east to west across the Taroom Trough (Korsch et al., 1998). This may also apply further south in the study area, where sediment deposition during the foreland loading phase was thicker in the east than in the west.

A major regression during the Late Permian reversed the predominantly marine conditions and resulted in coal swamp sedimentation, forming the Blackwater Group on an extensive coastal plain. Up to 4000 m of Permian strata may be preserved in the southern Taroom Trough (Thomas et al., 1982; Hawkins et al., 1992). It was during this phase that extensive Late Permian coal measures were deposited over large areas of eastern Australia (Miyazaki and Korsch, 1993). However, the Kianga Formation, the Upper Permian equivalent of the Baralaba Coal Measures in the Taroom Trough and the Bandanna Formation of the Blackwater Group in the Denison Trough, is only present in the eastern and northern parts of the Bowen Basin in New South Wales (Othman and Ward, 1999). The presence of coal within this sequence in the study area indicates that the swamp conditions also extended to the southern part of the basin system.

In the Early Triassic, the coal swamps gave way to deposition of the mainly fine- grained terrestrial red-bed sequence of the Rewan Group. Along the southeastern margin of the Taroom Trough, laterally equivalent fanglomerates, the Cabawin Formation, were also deposited adjacent to upthrust landmass to the east (Thomas et al., 1982; Hawkins et al., 1992). The Rewan Group is separated unconformably from the underlying Blackwater Group on the basin margins, while in the basin centre the relationship is conformable (Fielding et al., 1990). Around the Early-Middle Triassic boundary, uplift in the craton to the west, and possibly also of the orogen to the east, 13 Chapter 1 INTRODUCTION brought a flood of quartzose sediment into the basin. Large, poorly confined alluvial channels thus deposited the Clematis Group (Fielding et al., 1990), which conformably overlies the early Triassic sequences except in localised areas. In the southern Bowen Basin, on the Roma Shelf, the Showgrounds Sandstone, the principal petroleum exploration target in Queensland, is probably a correlative of the upper part of the Clematis Group (Hawkins et al., 1992). The fluvial style of deposition was terminated by a transgression from the south, which affected the southern and western parts of the basin and resulted in accumulation of the fine-grained sediments of the lacustrine Snake Creek Mudstone Member of the lower Moolayember Formation. The Middle Triassic Moolayember Formation reflects a return to a dominantly alluvial environment of deposition across the basin, and represents the youngest preserved remnant of the Bowen Basin (Fielding et al., 1990).

The tectonic setting of the Gunnedah Basin changed in the mid-Permian, and the area also developed a foreland basin setting. Marine sedimentation changed to fluvio-deltaic deposition in the Late Permian (Tadros, 1993a), consistent with typical foreland basin deposition. The marine shelf conditions ended when a large delta system prograded southwesterly across the basin. Prodelta and delta front facies of this system are assigned to the upper part of the Watermark Formation. Regression continued and fluvial-dominated deltas deposited the lower part of the Black Jack Group (Hamilton et al., 1988). Renewed thrusting in the New England Fold Belt induced basin subsidence, and subsequent infilling from the east and north-east by volcanic-lithic detritus in a shallow marine setting deposited the Arkarula Sandstone (Hamilton, 1993). Hamilton (1985) subdivides the shallow marine system into a northern tidal shelf system and a southern wave-dominated delta system, based on contrasts in depositional style between the northern and southern parts of the Gunnedah Basin.

Late Permian plutonism and associated felsic volcanism in the New England Fold Belt region were concomitant with rapid subsidence of the foreland basin and a return to terrestrial sedimentation. As with the Bowen Basin in the north, marine conditions were terminated, and basin-wide swamps were established in which peat accumulated. This formed the Hoskissons Coal Member of the Black Jack Group (Tadros, 1995b). Rapid subsidence in the east changed the peat swamp in which Hoskissons Coal formed into a lake system, whereas active fluvial sedimentation terminated the swamps in the west 14 Chapter 1 INTRODUCTION

(Tadros, 1986). A rejuvenation of sediment supply in the New England Fold Belt followed and deposited a thick sequence of coarse volcano-lithic detritus, tuffs and tuffaceous sediments, with intercalated coals in the upper part of the Black Jack Group. Deposition took place in this stage as a major alluvial system (Hamilton et al., 1988).

The tectonic subsidence curves illustrated by Korsch et al. (1993) for the Triassic sediments suggest that subsidence was relatively rapid. Korsch et al. (1993) interpreted the rapid subsidence as being related to continued foreland loading, due to the continued development of a thrust belt farther to the east. In the Early Triassic, renewed tectonism in the New England Fold Belt resulted in widespread deposition of coarse alluvial clastics over the Gunnedah Basin. Deposition of this episode formed the Digby Formation (Hamilton, 1993), separated with a local angular unconformity from the underlying Black Jack Group sediments (Tadros, 1986, 1995b). The Digby Formation is divided into the Conglomerate Interval in the lower part and Sandy Interval in the upper part (Jian and Ward, 1993). The upper Sandy Interval displays excellent reservoir characteristics (Etheridge, 1987; Hamilton et al., 1993). The boundary between the Digby Formation and the overlying Napperby Formation is a disconformity surface (Wiles, 1996). Jian (1991) concluded that the surface represents a basin-wide palaeosol horizon. Renewed basin subsidence resulted in deposition of the Napperby Formation, with well-developed upward-coarsening sequences of laminated siltstone/claystone, interbedded sandstone/siltstone laminites and sandstone in the lower part of the sequence. This unit represents progradation of lacustrine deltas derived from the New England Fold Belt. The upper part consists of irregularly interbedded fluvial sandstone and siltstone sequences (Tadros, 1995b). The Napperby Formation records a gross regression cycle from lacustrine lake-basin to lacustrine delta system and ultimately to fluvial sedimentation, with the main sediment source being from the New England Fold Belt (Jian, 1991; Jian and Ward, 1993; Tadros, 1995b).

1.3.4. Late Permian contraction

The different parts of the basin system in eastern Australia each responded very differently to the Late Permian contraction event. The event prior to deposition of Early Triassic fluvial sediments is best observed in the Gunnedah Basin (Korsch and

15 Chapter 1 INTRODUCTION

Totterdell, 1996; Korsch et al., 1998), although even here the contraction was more significant in the north and northeast than other parts of the basin. No effects were recorded in the Bowen Basin, except at the basin margin. The Early Triassic Rewan Group in the centre of the basin is separated conformably from the Late Permian Blackwater Group, but on the basin margins the relation is unconformable. In addition, seismic lines in the Queensland portion of the Bowen Basin do not show any angular unconformity between the Triassic Rewan Group and the Permian succession (Korsch and Totterdell, 1996).

The end of Permian sedimentation in the Gunnedah Basin was followed by a period of compression and erosion prior to deposition of the Early Triassic Digby Formation. Compressive deformation, which initiated the foreland basin setting, intensified towards the end of the Permian and caused major uplift and tilting, particularly in the north and north-east of the Gunnedah Basin (Tadros, 1986). However, Hamilton (1991) related the uplift to a thrusting event in the New England Orogen. As a result, coal measure sedimentation was terminated, and a thick section of Permian sediment was eroded (Tadros et al., 1987; Tadros, 1994). In the Bellata area, the Digby Formation overlies the Porcupine Formation, due to uplift and erosion of the Black Jack Group, Watermark and most of the Porcupine Formations. In the Narrabri-2 borehole, the Upper Black Jack Group has been removed. The rapid subsidence in the southern Gunnedah Basin during the Late Permian was interrupted for only a short period, and probably a small portion of the upper Black Jack Group was eroded (Tadros, 1986). Palynological data indicate that the latest Permian to earliest Triassic is absent from the Gunnedah Basin, and the boundary between the Black Jack Group and the overlying Digby Formation is represented by an erosional unconformity (McMinn, 1993)

1.3.5. Early Triassic contraction

From the Late Permian to the Middle Triassic, in the foreland basin stage, compression and overthrusting took place along the Moonie-Goondiwindi Thrust trend (Hawkins et al., 1992). This event is best observed north of the Moree High. Prior to deposition of the Clematis Group a contraction event in the Early Triassic deformed the sediment pile (Elliott, 1993). New thrust faults were formed due to reactivation of earlier faults

16 Chapter 1 INTRODUCTION

(Korsch and Totterdell, 1995). The thrust faults displace the Permian Bandanna Formation and the overlying Early Triassic Rewan Formation, but do not penetrate into the overlying Clematis Group (Elliott, 1989). On the western margin of the Taroom Trough, broad regional uplift produced a low angle unconformity between the Rewan Group and the overlying Clematis Group. Evidence of Early Triassic contraction is also seen in the southern Taroom Trough, where the Showgrounds Sandstone unconformably overlies Rewan Group or Permian units. Here the hiatus was longer than in the north, and the lower Clematis Group was not deposited (Korsch et al., 1998). This is also applicable further to the south in New South Wales. However, the Showgrounds Sandstone overlies the Permian sequences or the basement, except in the northernmost area where the Rewan Group occurs (Othman and Ward, 1999). The uplift in the Gunnedah Basin was regional but not extensive, and resulted in disconformity and palaeosol development at the boundary with the overlying Napperby Formation (Jian, 1991; Wiles, 1996).

1.3.6. Middle-Late Triassic contraction

Thrusting along eastern margin of the southern Taroom Trough in the Bowen Basin continued during the Middle Triassic and persisted into the Late Triassic. At the close of the Late Triassic, compressional forces declined, movement on thrust faults bounding the southern Taroom Trough ended, and deposition ceased, followed by widespread erosion (Hawkins et al., 1992). The Middle-Late Triassic contractional event deformed the youngest Moolayember Formation and older rocks prior to start of deposition of the Surat Basin sediments in the Early Jurassic. This event was complex and produced significantly different geometries in different parts of the basin (Korsch et al., 1998). The break between the basins is a significant unconformity in terms of time, because it lasted for about 35 my (Korsch and Totterdell, 1995). Some parts of the basin were uplifted by up to 3000 m, and extensive erosion occurred (Elliott, 1989). Many of the normal faults associated with the half grabens were reversed at this time to become major reverse faults, and horizontal motion occurred along some of the faults (Elliott, 1989). Prior to the accumulation of the Surat Basin sediments in the Early Jurassic, the Bowen Basin structures were peneplaned, resulting in a generally smooth topography.

17 Chapter 1 INTRODUCTION

Renewed subsidence occurred during the Late Triassic over small areas, with regional subsidence commencing in the Early Jurassic (Elliott and Browen, 1988).

In the Gunnedah Basin, compression deformation culminated at the end of the Triassic with folding, wrench and thrust faulting associated with last major accretionary phase of the New England Fold Belt of eastern Australia (Hamilton et al., 1993). Etheridge (1987) has documented contractional faults, which cut the Permian and Triassic rocks in the Bellata area. Major erosion of the Triassic and Permian sediments occurred in the Gunnedah Basin. Using vitrinite reflectance data Hamilton et al. (1988) and Gurba (1998) concluded that up to 2000 m had been removed from the Triassic and Permian sediments in the south eastern Gunnedah Basin during the Late Triassic period of erosion. Uplift in the Late Triassic, however, was most pronounced along the Boggabri Ridge, and progressively older Gunnedah Basin sediments occur in subcrop and outcrop to the east (Hamilton et al., 1993).

1.3.7. Late Triassic- Early Jurassic magmatic event

The Bowen Basin succession in northern New South Wales is extensively intruded by undersaturated mafic igneous rocks, which in places appear to have formed topographic highs on to which the Surat Basin sediments onlap. Therefore, it is assumed that these rocks are of Late Triassic to Early Jurassic age, equivalent to the Garrawilla Volcanics further south in the Gunnedah Basin. The injection of heat associated with this Late Triassic to Early Jurassic magmatic event may have been partly responsible for the thermal subsidence that led to deposition of the Surat Basin succession (Totterdell and Krassay, 1995).

The Early to Middle Jurassic sediments of the Surat Basin sequence unconformably overlie Permian and Triassic sediments in the north and west of the Gunnedah Basin. There was a Late Triassic - Early Jurassic magmatic event between the deposition of sediments of the Gunnedah and Surat Basins. This produced basaltic and trachytic flows, sills and plugs, particularly in the western part of the basin, where they crop out extensively. Further east, volcanics below the Jurassic sediments, the Garrawilla

18 Chapter 1 INTRODUCTION

Volcanics, and sills intruding the Triassic and Permian sediments, have been encountered in many of the drill holes (Korsch et al., 1993).

1.3.8. Early Jurassic thermal relaxation phase

Following the Late Triassic unconformity, subsidence to produce the Early Jurassic to Early Cretaceous Surat Basin was probably driven by thermal relaxation due to cooling of the lithosphere (Korsch et al., 1993). Sedimentation in the Surat Basin was essentially cyclic, and Exon (1974) recognised five major cycles. Each cycle represents deposition in turn of braided stream, meandering stream, and finally swamp, lake and delta deposits. This was followed by transgression in the Early Cretaceous, which produced mainly shallow marine sedimentation (Hawkins et al., 1992).

In the first cycle, the Lower Jurassic Precipice Sandstone and Evergreen Formation were deposited (Exon, 1974). The Precipice Sandstone, principal reservoir in the Surat Basin, is mainly composed of medium to coarse grained braided stream sandstones. Deposition of the overlying Evergreen Formation followed, and the areal extent of the Surat Basin steadily increased. The Evergreen Formation consists of interbedded shale, siltstone and sandstone with minor coal. It is considered to have been deposited in a complex pattern of nearshore lacustrine and deltaic environments (Shaw, 1995). In Queensland, where the sequence is more fully deposited, some facies seem to be definite marine sediments (Exon, 1976). This initial cycle of upward fining Jurassic sedimentation was followed by a second fining upward cycle represented by the Early to Middle Jurassic Hutton Sandstone and the overlying Middle Jurassic Walloon Coal Measures. The Hutton Sandstone consists of medium to coarse-grained sandstones deposited in an essentially terrestrial, mainly fluviatile environment (Hawke and Bourke, 1984). The Walloon Coal Measures conformably overlies the Hutton Sandstone, and consists of carbonaceous shale, siltstone, sandstone and coal deposited in fluvio-lacustrine to lower delta plain conditions (Shaw, 1995). The third and forth major cycles of sedimentation in the southern Surat Basin are represented by the Middle Jurassic Pilliga Sandstone, which was deposited in a fluviatile environment (McMinn, 1993), and the Late Jurassic Orallo Formation respectively. The Early Cretaceous Mooga Sandstone, a thin but persistent sequence comprising fine-grained sandstone

19 Chapter 1 INTRODUCTION with interbedded siltstone and shale, is overlain by marine shales of the Bungil Formation. Together, these two units form the fifth cycle of deposition. Subsequent Early Cretaceous deposition consisted of marine sediments of the Rolling Downs Group (Shaw, 1995).

South of the Moree High, the Pilliga Sandstone conformably overlies the Purlawaugh Formation. The Purlawaugh Formation represents fluvial and lacustrine sediments, and is chronostratigraphically equivalent to the upper Evergreen Formation and lower Hutton Sandstone in Queensland. The formation is younger in the Bellata area, with the Upper Purlawaugh Formation shales being time-equivalent to the Walloon Coal Measures (Hamilton et al, 1988). Similar results were also previously obtained by Morgan (1984). The Purlawaugh Formation commonly comprises a basal sand up to 10 m thick, and an upper unit of interbedded siltstone, shale, thin coal and sandstone interpreted as floodplain, channel margin and meandering stream deposits. The basal sandstone, sealed by overlying shales, siltstones and coals, is an exploration target in the northern Gunnedah Basin (Hamilton et al., 1988).

1.3.9. Post-Early Cretaceous contraction

Deposition in the Cretaceous basins ceased in the Late Albian or Early Cenomanian (Elliott, 1993). Apatite fission track analysis (AFTA) of samples from several wells in the eastern Bowen and Surat Basins indicates that cooling occurred during the mid- Cretaceous (80-100 Ma), initiating erosion of overlying sediments (Raza et al., 1995). The erosion was induced by rapid uplift that Korsch et al. (1995) considered was associated with this contractional event.

The contraction resulted in reactivation of the Goondiwindi Fault at depth, and the development of folds in the Surat Basin sediments. This event also resulted in the development of thrust faults on the margins of some of the Late Triassic intrusions (Totterdell and Krassay, 1995). The early Late Cretaceous contraction also reactivated many of the earlier structures in the Bowen Basin and in the basement. Renewed thrusting on these faults led to the propagation of some of the faults into the Surat Basin succession. Nevertheless, deformation in the Surat Basin was principally by folding and

20 Chapter 1 INTRODUCTION uplift of the Surat succession above reactivated thrust faults at depth (Korsch et al., 1998). However, this reactivation was important because many of the structures in the Triassic of the Bowen Basin, and in the Surat Basin, that are now reservoirs for oil and gas were formed by this event (Korsch and Totterdell, 1995). The Surat Basin succession in the Gunnedah Basin area has been locally deformed, indicating that there has been a minor, post-depositional episode of contractional deformation (Korsch et al., 1993).

Following the early Late Cretaceous contraction, the Mid-Tertiary was a period of epeirogenic movement, which produced tilting to the southeast, accompained by widespread volcanic extrusion to the north and east to the Surat Basin (Hawkins et al, 1992).

1.4. Previous studies

Limited research have been carried out in the study area (Stewart and Alder, 1995a, 1995b; Shaw, 2002). Stewart and Alder (1995a) mentioned that, for example, the Late Permian Kianga Formation had not been sampled for source rock analysis and no information was available about its petroleum generating potential in New South Wales.

Organic petrographic techniques were employed by Morton et al. (1993) to study the hydrocarbon source potential of coals and dispersed organic matter (DOM) in the Permian Back Creek Group in an area extending from Mt Pleasant-1 and Gil Gil-1 in northern New South Wales to southern Queensland. They concluded that all the Back Creek Group sediments studied, which include four main depositional environments (see section 1.3.2), contain sufficient quantities of organic matter to be potential source rocks. They identified, however, wide variations in maceral quantity and type for the various depositional environments. The maturity in the Back Creek Group sequence in the area they studied was shown to be higher towards the north, and vitrinite reflectance reaches 1.12% in sediments located in southern Queensland. Based on isoreflectance lines drawn for a cross section, Morton et al. (1993) suggested that the lines generally follow stratigraphic horizons across the southern part of their study area, and transect formation boundaries in the north. They concluded that maturation in the south occurred before deformation, while in the north maturity increased due to deeper burial and

21 Chapter 1 INTRODUCTION subsidence. Sherwood et al. (1995) provided total organic carbon (TOC) data from nine boreholes in the New South Wales sector of the Bowen-Surat Basin, and noted that the most organic-rich facies are present in several sequences ranging from Permian to Cretaceous in age. Based on Rock-Eval pyrolysis analysis from five boreholes and petrographic data from the Permian sequence in two boreholes, Sherwood and co- workers (1995) indicated that sequences with considerable potential to generate liquid hydrocarbons are present in the area. They mentioned that the vitrinite reflectance in the New South Wales portion of the Bowen-Surat Basin ranges from immature to postmature (Rv = 0.30 – 5.03%), but considered values greater than about 0.85% to have resulted from igneous intrusion effects. In addition, they noted a spread of values in vitrinite reflectance versus depth profiles in some of the studied boreholes, and indicated further inconsistency among studied maturity parameters. They also suggested more extensive data verification and assessment, including testing of vitrinite reflectance suppression, as important aspects for future work. Russell and Morton (1995) conducted preliminary petroleum generation modeling for the Chester-1 well, and suggested a Bowen Basin source for any petroleum reservoired in the Surat Basin in northern New South Wales, because the Surat Basin succession itself is in the early stage of thermal maturity at best.

Based on vitrinite reflectance measurements from six boreholes, four of which were located within the current study area, Russell and Middleton (1981) concluded that the Permian and Triassic sequences in the Gunnedah Basin and the New South Wales sector of the Bowen Basins largely lie within the early to main oil generation zones.

Etheridge (1983) studied a borehole located further south of the current study area, and indicated that organically rich siltstone and claystone of the Watermark Formation and of the lower delta plain facies of the Black Jack Group are potential source rocks in the Gunnedah Basin. Based on regional data Etheridge (1987) suggested that the Permo- Triassic sequence in the northern part of the Gunnedah Basin is probably within the oil generation zone. Hamilton et al. (1988) assessed the source potential of the Gunnedah Basin from four boreholes, and suggested the floodplain, lacustrine and marine facies of the Triassic Purlawaugh and Napperby Formations, and the Permian Maules Creek and Goonbri Formations, to be the best potential source rocks. The Permian Arkarula Sandstone was also considered as having significant potential for oil generation. Based 22 Chapter 1 INTRODUCTION on maturity parameters, Hamilton et al. (1988) considered the Jurassic and Triassic sequences to be immature to marginally mature, and the Permian sequence to have reached early maturity. They also drew isoreflectance lines on a north-south cross section through the southern Bowen and Gunnedah Basins, and indicated that the Permian sequence in the Gunnedah Basin is less mature towards the north. Alder (1993) suggested that the vitrinite reflectance in the Gunnedah Basin ranges from 0.5 to 1.3%. Morton (1995), in addition, concluded that the entire Wilga Park-1 sequence in the Gunnedah Basin is mature to overmature for gas generation, and attributed the high maturity to a localised heating effect due to a nearby volcanic complex.

Detailed Permian coal rank studies in the Gunnedah Basin south of the current study area were carried out by Gurba (1998) and Gurba and Ward (1998). Isoreflectance maps show that maturation in the Permian coal seams increases from the east towards the west. Anomalously low vitrinite reflectance values (up to 0.2 per cent below expected levels) were recorded in the area, and attributed to marine influence on the Permian sequence. Two major intervals with lower vitrinite reflectance value were identified: one within the Maules Creek Formation and the other within the lower Black Jack Group in the upper part of coal bearing succession. In addition, Gurba (1998) and Gurba and Ward (1998) have recorded anomalously high vitrinite reflectance values in the basin due to the presence of pseudovitrinite, as well as to igneous intrusions and local heat effects (see also Gurba and Weber, 2001).

A few oil and numerous minor gas shows, including some significant gas accumulations, have been reported in the study area (e.g. Etheridge, 1987; Hamilton et al., 1988). Limited geochemical studies (e.g. Gould, 1986; McKirdy, 1986) have been carried out to investigate the source of identified oil shows in some boreholes (e.g. Bellata-1 and Moema-1). These investigations, however, were inconclusive (Hamilton et al., 1993).

Detailed literature reviews related to the techniques used in the study are given in each relevant chapter.

23 Chapter 2 RESEARCH DATA AND METHODOLOGY

2. Chapter 2 RESEARCH DATA AND METHODOLOGY

2.1. Research data

2.1.1. Well completion reports

The well completion reports for all of the exploration and stratigraphic wells in the study area were reviewed from records of the New South Wales Department of Mineral Resources. On the basis of their location, total depth and sequences penetrated, a total of 31 exploration and stratigraphic wells were chosen as the basis for the study (Figure 1- 2; Table 2-1).

A total of 21 of these wells are located in the New South Wales portion of the Bowen Basin. The remaining 10 wells are located further south, in the northern part of the Gunnedah Basin (Figure 1-2; Table 2-1).

2.1.2. Well log data

Wireline log data were available for the Bowen Basin wells chosen for the study, except for Moree-3. Although the logs had been run, the log data were absent in this case from the well completion report. The Coonarah-1 well in the Gunnedah Basin was abandoned due to technical reasons, and the well completion report for this well does not include any geophysical log data. The Coonarah-1A well, however, penetrated deeper intervals, and is only five metres away from Coonarah-1. For purposes of correlation the well log data are considered to be the same for both of these boreholes, especially the sequences penetrated, and the formation tops are taken at similar depths for both wells.

2.1.3. Samples

Cuttings and/or core samples of these wells were examined and sampled at the New South Wales Department of Mineral Resources Londonderry Core Library. About three hundred samples were selected for different petrological and geochemical studies.

24 Chapter 2 RESEARCH DATA AND METHODOLOGY

Table 2-1: Sample details for boreholes studied.

Drilling Total depth Drilling sidewall Recovered No. Borehole name Basin completed (m) samples cores cores (m) 1 Barb-1 B/S 1982 1704.13 cuttings 29 nc 2 Boomi-1 B/S 1963 1695.29 cuttings 12 17.98 3 Camurra-1 B/S 1980 882.40 cuttings nsc nc 4 Chester-1 B/S 1987 2138.00 cuttings 27 2.16 5 Edendale-1 B/S 1997 2237.00 cuttings nsc nc 6 Garah-1 B/S 1966 1600.80 cuttings nsc nc 7 Gil Gil-1 B/S 1965 1604.77 cuttings nsc 34.14 8 Glencoe-1 B/S 1984 1968.03 cuttings 22 nc 9 Goondiwindi-1 B/S 1964 222.60 cuttings 106 16.48 10 Kinnimo-1 B/S 1966 1583.43 cuttings nsc nc 11 Lantern-1 B/S 1982 2076.90 cuttings 26 nc 12 Limebon-1 B/S 1967 2010.15 cuttings 89 nc

13 McIntyre-1 B/S 1964 2535.63 cuttings 49 7.75 14 Moree-1 B/S 1972 1147.75 cuttings 11 nc 15 Moree-2 B/S 1973 1221.33 cuttings nsc nc

16 Moree-3 B/S 1977 1182.32 cuttings nsc nc 17 Mt Pleasant-1 B/S 1965 2266.18 cuttings 19 11.38 18 Pearl-1 B/S 1985 1575.81 cuttings 20 14.94

19 Quack-1 B/S 1985 1670.30 cuttings 19 12.50 20 Werrina-1 B/S 1969 1519.45 cuttings nsc 0.91 21 Werrina-2 B/S 1969 1566.67 cuttings nsc nc 22 Bellata-1 G/S 1987 1128.00 core nsc 1123.00 23 Bohena-1 G/S 1963 1650.49 cuttings 7 29.31 24 Coonarah1 G/S 1994 531.00 p/cored nsc 129.00 25 Coonarah-1A G/S 1994 650.00 p/cored nsc 229.00 26 Gorman-1 G/S 1982 604.10 p/cored nsc 459.93 27 Moema-1 G/S 1975 500.00 p/cored nsc 330.50 28 Narrabri-2 G/S 1984 651.15 p/cored nsc 552.25 29 Nyora-1 G/S 1987 811.37 cuttings 23 nc 30 Wee Waa-1 G/S 1963 824.78 cuttings nsc 13.79 31 Wilga Park-1 G/S 1986 795.83 cuttings 50 nc nsc = no sidewall core samples were cut nc = no core samples were cut p/cored = partially cored B/S = Bowen-Surat Basin G/S = Gunnedah-Surat Basin

25 Chapter 2 RESEARCH DATA AND METHODOLOGY

These samples were chosen from 28 boreholes (Table 2-1; Figure 1-2). Although not sampled, the Gorman-1, Moema-1 and Narrabri-2 wells were used for correlation purposes (see below). Samples were chosen from coal seams, shale and siltstone strata in the wells for source rock studies covering the Permian, Triassic and Jurassic rock units. A Jurassic Pilliga Sandstone sample from Bellata-1, which contained oil staining, was also sampled to investigate the source of the oil stain.

The exploration wells in the study area yielded mainly cuttings samples. Any available core samples were normally taken from intervals to test reservoir properties rather than for evaluation of source rock potential. The boreholes studied from the Bowen Basin basically contained drill cuttings. In the Gunnedah Basin, one of the chosen boreholes, Bellata-1, was fully cored. Coonarah-1A (and Coonarah-1), however, were partially cored. The cored interval in Coonarah-1A (and Coonarah-1) covered the Permian and Triassic sequences, and this was the only interval sampled for the present study. A total of 509 sidewall cores had also been recovered from 15 of the boreholes in the study area (Table 2-1), but samples of these were not available at the storage facility. Cores recovered from other boreholes are tabulated in Table 2-1. Appropriate samples for the study were also selected from these intervals.

2.2. Methodology

2.2.1. Well logs

The wireline logs provide the most complete and readily available data regarding the sections penetrated in the selected boreholes. Log data from all 30 wells were used to develop a comprehensive stratigraphic correlation for the Permian, Triassic and Jurassic beds in the study area. Porosity logs (sonic transit time or compensated neutron log) and gamma ray logs were used as the main basis for correlation. Wireline logs may also provide good information for separation of organic-rich from organic-lean sequences (e.g. Meyer and Nederlof, 1984; Passey et al., 1990). Accordingly, the well log data were also used as a preliminary tool to identify the organic-rich facies in the Permian and Mesozoic sequences.

26 Chapter 2 RESEARCH DATA AND METHODOLOGY

2.2.2. Rock samples

2.2.2.1. Sample selection

The usefulness of samples for the present study decreases in the following order: conventional whole core, sidewall core and drill cuttings. The core samples are most reliable in terms of depth and absence of possible contamination, and hence wherever possible priority was given to examining the core samples, rather than drill cuttings, for the different petrographical, geochemical and analytical studies. Cuttings and cores may be contaminated by particulates or fluid drilling additives, oil-based mud for example, and cuttings may additionally contain material “caved” from shallower depths in the section during drilling. Apart from this, samples stored for long periods were generally considered to be reliable representatives of the strata penetrated, provided they were clean and had been stored under conditions restricting the growth of fungus, other possible sources of contamination and oxidation.

2.2.2.2. Sample evaluation

Cores of coals and shaly rocks were sampled from the boreholes where they were available. The majority of the samples, however, were from cuttings, and therefore similar material was taken from the well cuttings, where available, for the main analysis program (Figure 2-1). The intervals sampled were chosen to select the same lithologies (coal and shaly material) as indicated by the relevant geophysical logs, with care taken to minimise contamination from overlying strata due to borehole caving. Vitrinite and other coal particles were selected from the cuttings of intervals where the well logs showed a coal seam to be present. Otherwise, priority was given to collecting shale and siltstone particles.

2.2.2.2.1. Petrographic studies

2.2.2.2.1.1. Polished section preparation

Polished sections were prepared in the School of Biological, Earth and Environmental Sciences at the University of New South Wales following the relevant Australian

27 Chapter 2 RESEARCH DATA AND METHODOLOGY

Rock Sample

Polished Section Powder (Vitrinite Reflectance Measurements) (200 mesh grain size)

Soxhlet Extraction Rock-Eval Pyrolysis

Bitumen Residue (Extractable Organic Matter, EOM)

Column Chromatography (CC)

Saturated Hydrocarbons Aromatic Hydrocarbons NSO Compounds

Gas Chromatography-Mass Spectrometry (GCMS)

Figure 2-1: Analytical flow chart.

28 Chapter 2 RESEARCH DATA AND METHODOLOGY

Standard (AS 2856.1–2000). The core samples were cut into small blocks perpendicular to the bedding planes. The cut blocks, and also the selected cuttings samples, were ground on a 220# diamond lap to remove all saw marks and to get a relatively flat surface, then impregnated with Araldite D/HY-951. The impregnation was used to help achieve the best possible surface for mounting. The fine grinding stage was carried out on a Logitech LP 30 using 600# silicon carbide and run for twenty minutes. The sections were then mounted on to glass slides using the same Araldite used for impregnation. Final polishing of the samples was performed on Kent Mk 3 polishing machines using various grinding media.

2.2.2.2.1.2. Vitrinite reflectance measurements

Some 256 polished sections were prepared from selected samples for petrographic studies, to identify the vitrinite reflectance pattern in the study area. The polished sections were examined in reflected light using a Ziess Axioskop system with oil immersion objectives, following the relevant Australian Standards (AS 2856.2–1998; AS 2856.3–2000). Measurements were made of the percentage of incident light reflected from the vitrinite (mainly telocollinite) particles in the samples, using a wavelength of 546 nm. Mean maximum vitrinite reflectance (Rv, max %) determinations were carried out, based on an average of at least 30 individual measurements for each sample studied.

2.2.2.2.2. Geochemical studies

2.2.2.2.2.1. Sample preparation

Preparation of rock samples for organic geochemical study followed the recommendations of Padley et al. (1991) and Peters and Cassa (1994). The core samples were wire-brushed to remove any drilling mud and scrape off any ink marks. Cuttings samples were washed thoroughly to remove mudcake using fresh water followed by purified organic-free water. In the process, the cuttings were wet-sieved with a 2 mm top sieve and a 180 µm bottom sieve, and then left to dry at room temperature. They were not washed with organic solvents, which would have removed partially soluble hydrocarbon components. Cuttings less than 2 mm and bigger than 180 µm in size were

29 Chapter 2 RESEARCH DATA AND METHODOLOGY used for the analysis (cf. Peters and Cassa, 1994). Any obvious contamination was hand picked and the cuttings double-checked under a binocular microscope. The prepared core samples, after being broken into pieces, and also the cuttings samples, were pulverized in a ring-grinder mill for 30 seconds. This period of time usually produces a 200-mesh grain size (Padley et al., 1991), which was used for geochemical analysis (Figure 2-1).

2.2.2.2.2.2. Analytical Studies

2.2.2.2.2.2.1. Rock-Eval Pyrolysis and Total Organic Carbon

Rock-Eval pyrolysis, including total organic carbon (TOC) determination, was undertaken for 50 core and cuttings samples to ascertain the source richness and kerogen type represented. Selection of these samples was based on the petrographic studies used for measuring vitrinite reflectance.

The Rock-Eval analyses were carried out at Geoscience Australia (formerly the Australian Geological Survey Organisation or AGSO) in Canberra. The analyses were carried out with a ‘‘Turbo’’ model Rock-Eval 6 pyrolyzer manufactured by VINCI Technologies. The basic operating principles of this apparatus are described by

Lafargue et al. (1998). In this version of the Rock-Eval equipment, N2 is used as the carrier gas, and programmed heating of both the pyrolysis and the oxidation ovens is conducted from 100oC to 850oC, instead of from 180oC to 600oC as used in previous versions (Lafargue et al., 1998).

2.2.2.2.2.2.2. Soxhlet Extraction

Based on the petrographic studies and Rock-Eval pyrolysis results, 27 core and cuttings source rock samples, and also the Jurassic Pilliga Sandstone sample with oil staining from Bellata-1, were extracted for further organic geochemical studies. Soxhlet extraction was performed following standard procedures (e.g. Padley et al., 1991). The powdered rock samples were extracted for 72 hours, using an azeotropic solvent mixture of dichloromethane (DCM) and methanol (93:7) in a Soxhlet apparatus.

30 Chapter 2 RESEARCH DATA AND METHODOLOGY

2.2.2.2.2.2.3. Column Chromatography

The extractable organic matter (EOM) was separated into its constituent fractions by silica/alumina column chromatography. A 10 x 40 mm column was filled with 40 ml of petroleum ether and packed to 4/5th with reactivated silica gel, following by four spatula loads of dry activated alumina. The sample was then added to the column and eluted with 80 ml of petroleum ether, followed by 80 ml (50:50) of petroleum ether:dichloromethane and finally by 80 ml (35:65) of dichloromethane:methanol, to elute the saturated hydrocarbons, aromatic hydrocarbons and non-hydrocarbon (NSO compounds) respectively (Padley et al., 1991). Further analyses were then carried out on the saturated and aromatic hydrocarbons.

2.2.2.2.2.2.4. Gas Chromatography-Mass Spectrometry (GCMS)

The saturated and aromatic hydrocarbon fractions were analysed by GCMS using a Hewlett Packard 6890 GC interfaced to a HP mass selective detector (MSD 5790), and controlled by Chemstation software. A HP-5MS (crosslinked 5% phenylmethylsiloxane; 30 m long x 0.25 mm i.d. x 0.25 µm film thickness) capillary column was used with helium as the carrier gas. Samples in dichloromethane (2 µl aliquot; 1 mg sample per 100 µl DCM) were injected (split) automatically using a HP 6890 automatic liquid sampler. The oven temperature was held at 70oC for 3 minutes, then raised to 100oC at 6oC/min, to 200oC at 4oC/min, and finally to 310oC at 6oC/min, after which it remained isothermal for 20 minutes.

Data were acquired in both full-scan (m/z 50-500) and selective-ion-monitoring (SIM) modes. For compound identification and integration, the following ions were monitored: m/z 85 (n-alkanes); m/z 177, m/z 191 and m/z 205 (norhopanes, hopanes, methylhopanes and tricyclic terpanes); m/z 217, m/z 231 and m/z 259 (steranes, methylsteranes and diasteranes). Aromatic compounds were identified by monitoring the following ions: m/z 156 (dimethylnaphthalenes); m/z 170 (trimethylnaphthalenes); m/z 178 (phenanthrene); m/z 192 (methylphenanthrenes); m/z 206 (dimethylphenanthrenes); m/z 219 (retene). For the calculation of the methylphenanthrene index (MPI: Radke and Welte, 1983), the phenanthrene peak area was multiplied by a response factor of 0.69.

31 Chapter 3 STRATIGRAPHY

3. Chapter 3 STRATIGRAPHY

3.1. Introduction

Over 1300 wells have been drilled in the Queensland portion of the Bowen-Surat Basin (Jones, 1985), and the stratigraphic succession of the area has been extensively studied (e.g. Totterdell et al., 1995; Bashari, 1996). Only 26 petroleum wells have been drilled in the New South Wales sector of the Bowen Basin, however (Shaw, 2002), with only limited stratigraphic studies. An extensive drilling program for coal exploration has been conducted in the adjoining Gunnedah Basin by the New South Wales Department of Mineral Resources (Tadros, 1993c), providing a comprehensive understanding of the area south of Narrabri. The area north of Narrabri, however, where the Gunnedah Basin passes into the southern part of the Bowen Basin, has been subject to much more limited geological studies. Both this transitional area and the southern Bowen Basin itself are included in the current study area (Figures 1-1 and 1-2).

The boreholes used in the study were drilled over a 40-year period. In the southern Bowen-Surat Basin in northern New South Wales, in particular, different names were applied in many cases to the same stratigraphic units. The Triassic sequence, for example, is called the Cabawin Formation for McIntyre-1, the Wandoan Sandstone for Boomi-1 and the Moolayember Formation for Edendale-1. Re-evaluation of the stratigraphy to a uniform sequence of names was a significant issue for this study, and also for future investigations.

This chapter attempts to integrate geophysical log data from the wells studied with vitrinite reflectance profiles (see Chapter 4) and lithologic indicators, in addition to other data available in completion reports (age determination studies, for example), to develop a consistent stratigraphic nomenclature for the southern Bowen-Surat Basin in northern New South Wales (Figure 3-1), and to correlate this with the stratigraphy of the better-known Gunnedah-Surat Basin succession (Figure 3-2). Stratigraphic correlations between the wells, based mainly on the geophysical logs, were drawn for an intersecting series of cross-sections. As a result of this study a stratigraphic correlation is proposed between the Permian and Early Mesozoic sediments of the northern

32 Chapter 3 STRATIGRAPHY

Figure 3-1: Representative stratigraphic section for the southern Bowen and lower part of the overlying Surat Basin sequence in northern New South Wales (modified from Othman and Ward, 1999).

33 Chapter 3 STRATIGRAPHY

Figure 3-2: Northern Gunnedah-Surat Basin stratigraphy (after Othman and Ward, 2002).

34 Chapter 3 STRATIGRAPHY

Gunnedah Basin and the southern Bowen Basin in New South Wales across the intervening Moree High.

3.2. Previous studies

The stratigraphy of the Queensland portion of the Bowen and Surat Basins is extensively described, for example by Power and Devine (1970), Exon (1974), Fielding et al. (1990), Brakel et al. (1992), Totterdell et al. (1995) and Green (1997). Other detailed studies have also been made of certain formations (e.g. Golin and Smyth, 1986; Yago and Fielding, 1996; Grech and Dyson, 1997). In the absence of any outcrop, stratigraphic control on the distribution and composition of the Bowen Basin sequences in northern New South Wales is based only on seismic coverage and well control, particularly on wells drilled in the Queensland section of the basin (Shaw, 1995). There are, however, some studies describing the stratigraphy in the New South Wales portion of the Bowen Basin (e.g. Shaw, 1995; Stewart and Alder, 1995a), with a detailed study also made for Back Creek Group (e.g. Morton et al, 1993). The Gunnedah Basin, on the other hand, has been studied more comprehensively than the southern part of the Bowen Basin (e.g. Hill, 1986; Etheridge, 1987; Hamilton et al., 1988; Tadros, 1993c, 1995b).

Studies on the Great Australian Basin in New South Wales were published in Hawke and Cramsie (1984), including a discussion of the Permian and Triassic sequence by Hawke and Bourke (1984). The latter researchers pointed out the difficulties in delineating accurately the boundary between the Triassic sediments, referred to as the Wandoan Formation, and the underlying Permian sediments from seismic surveys in the Moree area, also in distinguishing the Triassic sediments from the slate basement.

Morton et al. (1993) provide the only detailed published study of the Late Permian Back Creek Group, with a depositional model for the sequence constructed from subsurface information in an area extending from Gil Gil-1 and Mt Pleasant-1 in northern New South Wales into southern Queensland. Totterdell and Krassay (1995) studied the Bowen and Surat Basin successions in northern New South Wales, and suggested that it was not possible to map the extent and distribution of the fine-grained facies, the oldest sediment of the area, due to the poor quality of the seismic data. They reported further, a lack of tight palynological control and that the extensive distribution of igneous 35 Chapter 3 STRATIGRAPHY

intrusions have prevented correlation of these sediments on the log-based cross sections. Totterdell and Krassay (1995) also indicated that the Late Permian coal measures are only present in the northernmost part of the region, and that the Middle Triassic Napperby Formation in the Gunnedah Basin is time-equivalent to the Clematis Group in the Queensland Bowen Basin.

3.3. Bowen-Surat Basin stratigraphic framework in the study area

Shaw (1995) and Stewart and Alder (1995a) have outlined the principal stratigraphic units in the Bowen-Surat Basin in northern New South Wales. These unit names have been generally applied in the area, particularly for the recently drilled boreholes. Using geophysical logs, vitrinite reflectance data (Chapter 4) and other information provided in well completion reports, the units were re-evaluated for the boreholes studied for the present project based on the unit names used by Shaw (1995) and Stewart and Alder (1995a). Accordingly, a representative stratigraphic section has been proposed for the southern Bowen Basin and the lower part of the overlying Surat Basin in northern New South Wales, as shown in Figure 3-1.

3.4. Basis of correlation

3.4.1. Well completion reports

Palynological studies on selected samples, conducted for some boreholes and detailed in the relevant well completion reports, were used to assist in re-evaluating the previously identified contacts between the various geological units. In the Boomi-1 well, for example, the contact between the Triassic Wandoan Sandstone (as named in completion report) and the Jurassic Evergreen Formation was recognised at a depth of 1545.33 m. The depth of this contact has been changed as part of the present evaluation, based on the reported palynological study of a core sample from a depth of 1502.96 m. In this sample a Triassic age is indicated by the presence of abundant Alisporites (of the Pteruchus type), and absence of any characteristic Jurassic species (Boomi-1 WCR, 1963). This observation assisted in re-defining the boundary at a shallower depth. The

36 Chapter 3 STRATIGRAPHY

name of the Triassic sequence is changed to Moolayember Formation and, in addition, Showgrounds Sandstone identified at the base of the Triassic sequence based on the well log signatures (Figure 3-3).

3.4.2. Marine influenced sequences

The marine influenced Back Creek Group in the study area is characterised by a pronounced suppression of the vitrinite reflectance values (see Chapter 4). The vitrinite reflectance for the southern Bowen Basin succession increases steadily with depth through the Jurassic and Triassic strata, and where present into the uppermost Permian Kianga Formation. It decreases, however, and then continues to increase from a lower baseline but with a slightly higher gradient in the underlying strata of the Back Creek Group. This phenomenon was also recognised in the Gunnedah Basin by Gurba and Ward (1998) as well as in the present study. After elimination of low reflectance values due to reasons other than marine influence, contamination due to caving debris for example, or high values due to igneous intrusion and local heat effects (Chapter 4), the presence of reflectance suppression assisted in distinguishing the Permian Back Creek Group from the overlying Triassic sequence or, where present, the Permian Kianga Formation.

3.4.3. Triassic overpressure interval

Overpressure in subsurface sequences has been observed worldwide (Hunt, 1990), and studied by many researchers (e.g. Dickinson, 1953; Burts, 1969; Magara, 1968, 1975, 1978; Barker, 1972; Mudford and Best, 1989; Osborne et al., 1997).

3.4.3.1. Concept

The hydrostatic gradient is the pressure increase with depth of a liquid in contact with the surface, while the lithostatic gradient is the total pressure increase caused by rock grains plus water. Any departure from the commonplace hydrostatic pressure is an abnormal pressure, which includes overpressure and underpressure (Hunt, 1996).

37 Chapter 3 STRATIGRAPHY

ACZ = Abnormal Compaction Zone TD 1695m

Figure 3-3: New stratigraphic interpretation in Boomi-1, Bowen Basin, northern New South Wales.

38 Chapter 3 STRATIGRAPHY

The gravity load of overlying strata in a sedimentary sequence causes beds lower in the section to compact and lose porosity. Such a reduction in porosity is only possible if a commensurate portion of the (incompressible) pore fluid is allowed to escape. Layers in the section with low permeability may, however, impede the escape of the pore fluid from the beds beneath, confining it in the sediment and preventing or retarding the compaction process. Under such conditions, previously normal hydrostatic pressures in the pore fluid increase and the sediment becomes overpressured (Magara, 1978).

Waples and Couples (1998) viewed compaction as a sequence of steps, including; application of stress through sediment accumulation, response to the grain framework to the applied stress, transfer of stress to the pore fluids and a simultaneous increase in fluid pressure, and finally flow of fluid out of the rock. Osborne and Swarbrick (2001) regarded these steps, however, as a convenient way of considering the component parts of the compaction process, and concluded that the relative importance of these steps will vary based on subsidence rate, sediment permeability, mean stress and fluid flow in three dimensions.

Other mechanisms have also been proposed for generation of overpressure in sedimentary basins (e.g. Magara, 1978; Hunt 1996; Teige et al., 1999). Osborne and Swarbrick (1997) divided these mechanisms into three categories. These are 1) increase in compressive stress (reduction of pore volume) caused by disequilibrium compaction and tectonic compression, 2) change in fluid volume by temperature increase, diagenesis, hydrocarbon generation, and cracking to gas, and 3) fluid movement and processes related to density differences between fluids and gases.

In shale sequences that have been normally compacted, with associated escape of pore fluids, the porosity should decrease with increasing burial depth. In sequences that are abnormally compacted, however, the shale porosity would not be expected to decrease despite the increasing depth, and the porosity-depth profile may even show an increase in porosity with burial. Sonic transit time and neutron logs are widely used for porosity evaluation (Magara, 1978). Density logs also show this phenomenon, but density logs also respond to the effects of any heavy minerals present.

39 Chapter 3 STRATIGRAPHY

3.4.3.2. Overpressure as marker bed in the study area

Overpressure phenomena can be recognised from porosity logs, as illustrated in Figure 3-4a, for example, in the lower part of the Middle Triassic Moolayember and Napperby Formations in the Bowen and Gunnedah Basins respectively. As indicated by the porosity plot in Figure 3-4b, the porosity decreases with depth over an interval from 1800 m to 1815 m. Accordingly, the shale sequence in this interval is relatively well compacted, indicating an effective paleo-fluid drainage condition. The porosity increases, however, from 1815 m to 1853 m (Figure 3-4b), showing that this interval is abnormally compacted (overpressured). This phenomenon, as also shown in Figures 3-1 and 3-3, is widespread (with some variations in intensity) in the lower part of both the Moolayember and Napperby Formations in the Bowen and Gunnedah Basins respectively. This overpressured interval is not only observed in the area studied, but also in the boreholes further north and south, as indicated from the respective porosity logs.

The abnormal compaction (overpressure) zone in the lower part of the shaly sequence in both the Moolayember and Napperby Formations is therefore identified as a stratigraphic marker bed (Othman and Ward, 1999), which appears to represent a useful correlation horizon across the region. It is also significant as a local marker for correlation between boreholes in the southern Bowen succession.

3.5. Stratigraphic correlations

3.5.1. Bowen-Surat Basin

Based on the wireline log data, the interval with suppressed reflectance in the Permian, the overpressured marker bed in the Triassic, and other additional data from the well completion reports, the stratigraphy in the southern Bowen-Surat Basin succession has been re-evaluated, and a uniform nomenclature developed following the unit names outlined by Shaw (1995) and Stewart and Alder (1995a). A stratigraphic succession showing the stratigraphy has been presented in Figure 3-1, and the correlation and

40 Chapter 3 STRATIGRAPHY

A B

Comp. Neutron (%)

10 35 60 1780 1790 Normal compaction 1800 trend NCZ 1810

Moolayember 1820 Formation (m) Depth 1830 ACZ 1840

1850

Showgrounds 1860 Sandstone

NZC = Normal compaction zone ACZ = Abnormal compaction zone

Figure 3-4: Normal and abnormal compaction zones in the lower part of the Moolayember Formation in Glencoe-1. (A) Porosity logs and Gamma Ray response, (B) Neutron – depth profile (modified from Othman and Ward, 1999).

41 Chapter 3 STRATIGRAPHY

extent of these units between the boreholes in the northern part of the study area is shown in Figure 3-5.

In the northern part of the study area, as illustrated in the Figure 3-5, the Permian sequence is thicker towards the east and pinches out in the western part of the Bowen Basin, where the Triassic sequence overlaps the basement. An Upper Permian coal bearing sequence, the Kianga Formation, is developed in the extreme northern and eastern parts of the Bowen Basin in New South Wales, but this unit is thinner than the underlying Back Creek Group (Figure 3-5).

The Lower Triassic Rewan Group unconformably overlies the Kianga Formation. This unit is present only in the extreme north of the New South Wales portion of the Bowen Basin (Shaw, 1995; Totterdell and Krassay, 1995), and was only identified in Glencoe-1 in the present study. The Showgrounds Sandstone, distinguished from the Rewan Group by a lower gamma-ray count and a more quartzose composition (Bashari, 1996), is more widespread in the southern Bowen Basin, and occurs immediately beneath the abnormally compacted shale sequence in the lower part of the Moolayember Formation.

The Middle Triassic Moolayember Formation is well developed in the study area; the abnormally compacted lower part of the formation makes it a useful marker bed. In the boreholes shown in Figure 3-5, the Triassic sequence only disappears in the Werrina-2 well in the extreme east of the study area.

The Jurassic Precipice Sandstone is seen from Figure 3-5 to thin and pinch out towards the south and west, while the Evergreen Formation thins towards west but pinches out towards the south. The Hutton Sandstone and Walloon Coal Measures are thicker towards the north.

3.5.2. Correlation of Bowen and Gunnedah Basins

Totterdell and Krassay (1995) recognised four depositional supersequences in the Bowen and Surat Basins in northern New South Wales. The dominantly carbonaceous mudstone sections at the base of Lantern-1 and Macintyre-1, which represent the oldest sediments in the New South Wales portion of the Bowen Basin (Totterdell and Krassay, 42 Chapter 3 STRATIGRAPHY

Figure 3-5: Stratigraphic correlation in the southern Bowen Basin and lower part of the overlying Surat Basin, northern New South Wales.

43 Chapter 3 STRATIGRAPHY

1995), were considered to be equivalent to the lacustrine Goonbri Formation in the Gunnedah Basin in the south. The overlying succession, deposited in variety of fluvial settings and consisting of coarse clastic sediments, mudstone and coal, was suggested as being equivalent to the Maules Creek Formation in the Gunnedah Basin. These two intervals were considered as Supersequence 1 by Totterdell and Krassay (1995). Supersequence 2, which can be correlated with the interval from the Porcupine Formation to lower Black Jack Group, consists of shallow marine to deltaic sediments deposited in the Early Permian to early Late Permian. Morton et al. (1993) considered, however, all or part of the Porcupine and Watermark Formations and the lower Black Jack Group in the Gunnedah Basin to be age-equivalent to the Back Creek Group in the Bowen Basin of northern New South Wales.

The well-developed Back Creek Group in the eastern part of the Bowen Basin thins and probably pinches out over the Moree High (Figure 3-6). It also pinches out towards the west (Figure 3-5). The Kianga Formation, equivalent to the Bandana Formation of upper part of the Blackwater Group (Shaw, 1995; Korsch et al., 1998), considered by Totterdell and Krassay (1995) to be absent in the present study area, is identified in the eastern and northern parts of the region (Figures 3-5 and 3-6). The Kianga Formation, shows a more normal trend (regular increase) of vitrinite reflectance with depth (see Chapter 4). The Black Jack Group, Watermark Formation and part of the Porcupine Formation have been completely removed, probably due to uplift and erosion, in the area around Bellata and the Moree High. Although this makes exact correlation difficult, the Kianga Formation is probably equivalent to the upper part of the Black Jack Group, above the shallow marine Arkarula Sandstone succession, where the coals also have normal (unsuppressed) vitrinite reflectance characteristics (Gurba and Ward, 1998).

Uplift and erosion during the Early Triassic contraction in the New South Wales portion of the Bowen Basin was more significant than in other parts of the basin system. The Late Permian Kianga Formation is present in the eastern and northern parts, and the Rewan Group only in the northernmost part of the area close to the border with Queensland. This suggests that the New South Wales part of the Bowen Basin underwent regional uplift in the Early Triassic, resulting in erosion of most of the Late Permian section. Totterdell and Krassay (1995) reached a similar conclusion, but

44 Chapter 3 STRATIGRAPHY

Figure 3-6: Cross-section of the southern Bowen and northern Gunnedah Basin successions in northern New South Wales (modified from Othman and Ward, 1999).

45 Chapter 3 STRATIGRAPHY

considered a complete absence of the Kianga Formation equivalent in the New South Wales sector of the Bowen Basin. Around the early Middle Triassic, the Clematis Group was deposited conformably above the Early Triassic Rewan Group in the Queensland part of the Bowen Basin, while the New South Wales portion of the basin was probably still being uplifted.

If the Digby Formation in the Gunnedah Basin is considered as equivalent to the Rewan Group in the Bowen Basin (cf. Totterdell and Krassay, 1995), the hiatus that produced the disconformity surface in the Gunnedah Basin, between the Digby and Napperby Formations (Wiles, 1966; Jian, 1991), is probably equivalent in age to the deposition of Clematis Group and Showgrounds Sandstone in the Bowen Basin. The Clematis Group, however, is absent in the southern Bowen Basin in northern New South Wales, which suggests that the subsidence in this area resumed with deposition of the Showgrounds Sandstone sediments. This period was followed by basin-wide deposition of the Moolayember and Napperby Formations, starting with the shaley sequence identified in the current study as the overpressured zone. This conclusion is supported by Etheridge (1987), who suggested that the Napperby Formation in Bellata-1, at least above 866 m, is a stratigraphic correlative of the Snake Creek Mudstone Member, which is part of the overpressured interval, and that the overlying Triassic units are equivalent to the remainder of the Moolayember Formation. The abnormal compaction zones in both the lower Moolayember and Napperby Formations, and the nature of vitrinite reflectance profiles for the Triassic sequence, supports that these two intervals are equivalent (Othman and Ward, 1999). This conclusion is also supported by Etheridge (1987), who suggested that the Napperby Formation in the Gunnedah Basin in the vicinity of the Bellata-1 well is equivalent to the Moolayember Formation in the Bowen Basin to the north. Etheridge (1987) based this conclusion on data from palynological studies, and also mentioned that the correlation was corroborated by lithology and log similarities between Bellata-1 and boreholes north of the Moree area in the New South Wales sector of the Bowen Basin.

In the Surat Basin the Jurassic Walloon Coal Measures is equivalent to the upper part of Purlawaugh Formation further to the south (McMinn, 1993); it is continuous with that unit over the Moree High. Underlying units in the Surat Basin succession, including the Precipice Sandstone, Evergreen Formation and Hutton Sandstone, are also present

46 Chapter 3 STRATIGRAPHY

further north. These generally thin and pinch out towards the Moree High, suggesting an angular unconformity across that feature near the Cammura-1 well (Figure 1-2).

3.6. Discussion and conclusions

Stratigraphic correlations have been re-evaluated in the study area using well log signatures, vitrinite reflectance suppression characteristics, and age determination data provided in some well completion reports. This study is significant because the boreholes in the area were drilled over a 40-year period, and different names in many cases have been applied to the same geological units.

Based on porosity logs, an interval has been identified in the lower part of the Moolayember and Napperby Formations in the Bowen and Gunnedah Basins respectively with abnormal compaction (overpressure) characteristics. This interval is recognised as a useful marker bed in the area (Othman and Ward, 1999). This marker bed is also observed in porosity log signatures in the boreholes further north and south of the study area.

A representative stratigraphic column has therefore been proposed for the Bowen Basin and the lower part of the Surat Basin in northern New South Wales (Figure 3-1). This section has been used as a reference for correlation among boreholes studied in the southern part of the Bowen Basin. As indicated in the east-west fence diagram, the Permian sequence pinches out towards the east, where Triassic sediments overlap the basement except in Werrina-1 (Figure 3-5). The Back Creek Group pinches out towards the east and thins towards the south, while the Permian Kianga Formation is recognised only in the north and northeast parts of the New South Wales Bowen Basin. The Triassic Rewan Group is only present in Glencoe-1, and the Clematis Group is absent. The overlying Showgrounds Sandstone is relatively thin, but present in most of the studied boreholes in the southern Bowen Basin. This sequence underlies the overpressured interval. The Triassic Moolayember Formation is well developed in the southern Bowen Basin, and only disappears in the Werrina-1 well in the east where the Jurassic sequence overlaps the basement. The Evergreen Formation and Precipice Sandstone in northern New South Wales pinch out towards the south, while the Hutton Sandstone and Walloon Coal Measures thicken towards the north. 47 Chapter 3 STRATIGRAPHY

The Bowen Basin succession in the area has been correlated with the better-known Gunnedah Basin succession in the south. Part of the Permian sequence was removed in the Bellata Trough, which makes correlation between these areas difficult. The north- south cross section illustrates that the Permian sequence was also, probably, completely eroded between the Bowen and Gunnedah Basins at the Moree area. During the Triassic, while the Digby Formation in the Gunnedah Basin and Rewan Group in the Queensland sector of the Bowen Basin were being deposited, the New South Wales portion of the Bowen Basin experienced uplift and erosion. This event resulted in removal of most of the Kianga Formation, except in the eastern and northern parts, close to the New South Wales – Queensland border. The disconformity between the Digby and Napperby Formations is probably time-equivalent to deposition of the Clematis Group and Showgrounds Sandstone in the Bowen Basin. This event was followed by deposition of shaly sequences basin-wide, which are recognised as an overpressured interval in both the Bowen and Gunnedah Basins.

The Jurassic Purlawaugh Formation in the Gunnedah Basin is equivalent to the upper Evergreen Formation and lower Hutton Sandstone in the Queensland portion of the Bowen Basin. The Purlawaugh Formation, however, is younger in the Bellata area, and the upper part of this sequence is time-equivalent to the Walloon Coal Measures (McMinn, 1993).

48 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

4. Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

4.1. Introduction

This chapter investigates the three-dimensional pattern of thermal maturity in the study area based on vitrinite reflectance measurements. Several other maturity parameters are discussed in the following chapters. The study is based mainly on evaluation of vitrinite reflectance trends in vertical profiles against depth. To achieve the objectives of this chapter, comprehensive maximum vitrinite (telocollinite) reflectance data have been obtained for 256 polished sections from 28 petroleum exploration and stratigraphic wells. The samples were selected from the southern Bowen and northern Gunnedah Basins, and the lower part of the overlying Surat Basin successions (Appendix 1).

The vitrinite reflectance measurements obtained from the vertical profiles, after allowance for any anomalies due to depositional environment or igneous intrusion effects, were then used to evaluate vertical and lateral trends in thermal maturity across the basin area, and to relate those trends to the tectonic development of the basins.

4.2. Vitrinite reflectance as maturity parameter

4.2.1. Concept

Vitrinite is the term applied to a group of macerals/kerogens with certain definite, variable optical and chemical properties (Carr, 2000). Vitrinite designates a group of macerals whose colour is gray and whose reflectance is generally between that of the associated darker liptinites and lighter inertinites over the rank range in which the three respective maceral groups can be readily recognised (ICCP, 1998). Telocollinite is a maceral of the vitrinite group, subgroup telovitrinite, with a homogeneous, more-or-less structureless appearance. The reflectance value of telocollinite is widely used to determine the rank of coal and organic matter in sediments (ICCP, 1998).

49 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

Vitrinite is the maceral most often used for reflectance measurements, because its optical properties alter more uniformly during rank advance than do those of the other maceral groups (Dow, 1977). In addition, vitrinite is conventionally used for the rank assessment because of its wide distribution in coal and its favorable polishing qualities (Diessel, 1996). Reflectance measurements, however, must be made only on vitrinite group macerals, preferably only on telocollinite, since the reflectance of other macerals changes at different rates (Hunt, 1996).

Hunt (1996) notes that Marlies Teichmüller in her study of the Wealden Basin in 1958 first described the use of vitrinite reflectance as a technique for determining the maturation of organic matter in sedimentary rocks. Vitrinite reflectance was basically developed to measure coal rank, which is an indication of the degree of coalification (e.g. Diessel and Gammidge, 1998). The method has been widely extended to particles of disseminated organic matter (DOM) occurring in shales and other sedimentary rocks (Tissot and Welte, 1984). Vitrinite reflectance, today, is a widely used indicator of thermal stress, and is extensively used for assessment of thermal maturity in petroleum exploration studies (e.g. Dow, 1977; Tissot and Welte, 1984; Jones, 1987; Mukhopadhyay, 1994; Suggate, 1998; Copard et al., 2002). Vitrinite reflectance may be applied over a wider maturity range than any other indicator, and a skilled organic petrologist can make a large number of analyses in a relatively short time (Hunt, 1996).

The reflectance of vitrinite in coal and DOM increases during thermal maturation due to complex, irreversible aromatisation reactions (Peters and Cassa, 1994). Irreversible chemical reactions in which the rate rises exponentially with temperature are responsible for the changes in molecular structure. Consequently the reflectance associated with these maturation changes also increases exponentially with a linear rise in temperature (Hunt, 1996). According to Hilt’s Law, in a vertical sequence of strata the level of maturation is expected to increase steadily with depth (Stach et al., 1982; Taylor et al., 1998), and hence vitrinite reflectance should increase with depth in the strata encountered in an exploration well.

Rank is commonly assumed to be equivalent to organic matter maturity in petroleum geochemistry and exploration. Rank and maturity, however, can be considered different (e.g. Newman et al., 1997; Carr, 2000). Rank depends on the burial history of a coal or

50 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

rock, and important factors in rank evolution include temperature, pressure, time of burial, fluid flow and oxygen fugacity. Maturity is related, in general, to oil generation [thermal maturity describes the extent of heat-driven reactions, which convert sedimentary organic matter into petroleum (Peters and Moldowan, 1993)], and is more complex than rank, being dependent on both rank and the original chemical composition of the organic matter in question. Thus, samples that are of equal rank with a common burial history may have significantly different maturities (Newman et al., 1997). The same vitrinite reflectance values will not always reflect the same time-temperature histories, whereas different vitrinite reflectance values will not always indicate different organic maturity levels (Fang and Jianyu, 1992). In addition, vitrinite group macerals do not contribute significantly to oil generation compared to the liptinite macerals (Peters and Moldowan, 1993). Therefore, different source rocks with the same thermal history should have reached the same level of vitrinite reflectance, but not necessarily the same stage of evolution, in terms of oil or gas generation zones. Furthermore, different thermal histories, heating rates for example, may result in the same level of vitrinite reflectance but in different amounts and types of hydrocarbons generated (Tissot and Welte, 1984).

Even though vitrinite reflectance is related more to thermal stress experienced by the vitrinite than to petroleum generation (Peters and Moldowan, 1993), the correlation of reflectance with other maturation indicators and with oil and gas accumulations has resulted in an empirical definition of vitrinite reflectance values representing the limits of oil and gas generation (Hunt, 1996). Approximate vitrinite reflectance values have been assigned to identify thermal maturity stages for hydrocarbon generation (e.g. Tissot and Welte, 1984). Vitrinite reflectance, in addition, correlates well with other maturity parameters (see Chapters 5 and 6), and comparison between reflectance and other parameters is well established (cf. Peters, 1986; Peters and Moldowan, 1993; Peters and Cassa, 1994). Descriptions of levels of thermal maturity in this and other chapters follow Peters and Cassa (1994) (Appendix 2), who have provided detailed description of the key levels of thermal maturity. There are, however, no sharp boundaries of the oil zone, as oil represents a complex assemblage of a wide variety of components, which are generated at different rates. Furthermore, kerogen (including vitrinite) has no uniform structure (Tissot and Welte, 1984).

51 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

4.2.2. Applications, limitations and anomalies

Although there are limitations in using vitrinite reflectance as an organic matter thermal maturity parameter, they are probably less than those affecting other maturity parameters. Vitrinite reflectance is more precise and less subjective than the thermal alteration index (TAI) as a microscopic method (Peters and Moldowan, 1993), although Suggate (1998) has reported that vitrinite reflectance is by no means a precise parameter, Tissot and Welte (1984) consider vitrinite reflectance studies to be excellent for characterisation of the state of organic matter maturity.

Vitrinite reflectance profiles are used mainly to define generalised zones of oil and gas generation. However, they also can be used to interpret some of the sedimentary and tectonic history of the basin (Hunt, 1996). Some researchers (e.g. Dow, 1977; Katz et al., 1988) have identified and discussed significant offsets in vitrinite reflectance profiles, which have resulted from tectonic activities such as unconformities, faults and igneous intrusions. Other researchers have identified significant offsets in vitrinite reflectance profiles attributed to variations in depositional environment (e.g. Jones, 1987; George et al., 1994; Gurba and Ward, 1998; Othman and Ward, 2002), or maceral group composition (e.g. Hunt and Cook, 1980; Goodarzi et al., 1994; Othman and Ward, 2002). In the absence of any such offsets, vitrinite reflectance increases with depth of burial, although some scatter of individual values around the maturity profile often occur. Within some sedimentary sequences, the spread probably reflects the diversity of plant material from which the vitrinite is formed, and possibly a different diagenetic history (Tissot and Welte, 1984). Jones (1987) showed that, in a sedimentary succession, vitrinite reflectance may slightly differ for different sedimentary environments.

A significant limitation of using vitrinite reflectance, probably, is that vitrinite is derived from land plants and only can be used in rock samples that contain a sufficient amount of preserved terrestrial organic matter. Thus, vitrinite reflectance is limited to the post- Ordovician portion of the stratigraphic record (Katz et al., 1988). Abundant land plants, however, are not common in rocks older than Devonian in age (Peters and Cassa, 1994). Vitrinite reflectance can be used in rocks containing Type III kerogen (see Chapter 5 for kerogen types). Vitrinite, however, is only moderately abundant, or even scarce, in

52 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

rocks with Type II kerogen, and mostly absent in rocks with Type I kerogen (Tissot and Welte, 1984).

The cases where measured vitrinite reflectance values are lower (suppressed) or higher (enhanced) than the expected values at a given regional rank are defined as vitrinite reflectance anomalies (Fang and Jianyu, 1992). Thus, significant offsets in the vitrinite reflectance profiles may be recognised as anomalies. Vitrinite deposited in different redox conditions, and thus with different initial hydrogen contents and kinetics, may yield very different reflectance values at the same regional rank (Fang and Jianyu, 1992).

Anomalously high vitrinite reflectance values may result from local heat effects due to igneous intrusion (e.g. Dow, 1977). Significant offsets may occur in the reflectance profile where the sequence is affected by intrusions. Vitrinite reflectance above a sill typically increases to higher values than below the sill, indicating a better transfer of heat upward by advection than downward (Hunt, 1996). Occurrence of pseudovitrinite (e.g. Gurba and Ward, 1998) may produce relatively high reflectance values (Newman and Newman, 1982), and other high reflectance may also result from reworked materials (Tissot and Welte, 1984). Oxidation due to storage conditions may anomalously increase the vitrinite reflectance value. This type of alteration may be significant in the samples studies and needs to be identified (Othman and Ward, 2002).

Anomalously low vitrinite reflectance, sometimes described as reflectance suppression, in coal or DOM, may be caused by a number of factors, including the depositional environment and the type of the organic matter involved. Many authors (e.g. Hutton and Cook, 1980; Price and Barker, 1985; Raymond and Murchison, 1991; Wilkins et al., 1992; Kaiko and Tingate, 1996; Gurba and Ward, 1998) have recognised anomalously low, suppressed, vitrinite reflectance where lower than expected reflectance values are developed in the profile through a stratigraphic sequence. Although thermal maturity is the main control on vitrinite reflectance, it has also been shown that depositional factors may affect the reflectance value. The influence of marine conditions on the organic matter, in particular, may result in anomalously low vitrinite reflectance. Vitrinite reflectance has the advantage of not being metamorphic regressive, and records only the maximum temperature to which the enclosing rocks were exposed. However, it is also

53 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

greatly affected by organic facies (Fang and Jianyu, 1992). An abundance of associated liptinite macerals can give rise to vitrinite reflectance suppression (e.g. Stach et al., 1982; Thomas, 1982; Mukhopadhyay and Dow, 1994). Anomalously low, suppressed, vitrinite reflectance values may be used for stratigraphic and sedimentological investigations (Gurba and Ward, 1998). Deviation in the reflectance values from a normal maturation profile in a well can be an aid in identifying organic facies or sedimentation environment, and can also be used in stratigraphic correlations (e.g. Othman and Ward, 1999).

Peters and Moldowan (1993) have noted that vitrinite is present in many sedimentary rocks and is largely independent of rock composition. However, several authors (e.g. Goodarzi et al., 1988, 1993; Pearson and Murchison, 1990; Murchison et al., 1991) have suggested that lithology is another factor that may affect vitrinite reflectance. Khorasani and Michelsen (1994), in a study of Surat Basin and Norwegian samples, found systematic differences between the reflectance evolution of vitrinites in coals and intercalated shales. This phenomenon has also been observed in artificial maturation of immature vitrinites from coal, non-marine shales and marine shales. For any given temperature level in artificial maturation experiments, vitrinite in coal has the highest reflectance. The vitrinite in the interbedded non-marine shale has a reflectance lower than the corresponding vitrinite in coal, and both vitrinites in coal and in non-marine shale display higher reflectance than that in marine shale (Khorasani and Michelsen, 1994).

In the case of cuttings samples, contamination due to debris from caving intervals in overlying strata may result occasionally in low vitrinite reflectance values (Othman and Ward, 2002). Anomalies due to contamination are common for cuttings samples, and should be considered while interpreting organic matter maturity profiles based on such materials.

Lower reflectance may also result from overpressuring (e.g. McTavish, 1978; Price and Winger, 1992; Zou and Peng, 2001). As with suppression, retarded reflectance values are lower than those produced by low-reflecting non-retarded vitrinite (Carr, 2000). Vitrinite reflectance retardation can be defined as a thermochemical modification of the reaction rate responsible for compositional and structural changes that result in

54 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

increased vitrinite reflectance during burial. Overpressure appears to result in the retention of volatiles within the molecular structure, which prevents the molecular reorganisation necessary to produce higher reflectance values (Carr, 1999). Unlike suppression, retardation will influence the vitrinite reflectance only after sufficient burial has occurred to produce a pressure seal (Carr, 2000).

Identification of offsets that may arise in the vitrinite reflectance profiles, and the reason for any such phenomena, are important issues in organic matter maturation studies. Inaccurate maturation predictions result in incorrect source rock evaluation. The interpreter, furthermore, must be aware of both geological and non-geologic causes of apparent thermal history anomalies (Feazel and Aram, 1990).

4.3. Sampling

In the present study, vitrinite reflectance was measured for coal and for dispersed organic matter (DOM), mainly in shale and siltstone. The samples were chosen from intervals where these materials were available from the Permian, Triassic and Jurassic sequences encountered in exploration and stratigraphic wells throughout the study area. Samples were taken wherever possible from cores, but since only limited intervals of cored strata are available in the area, the reflectance data have been based mainly on material recovered from well cuttings. Fully cored boreholes were only available at two locations, the Bellata-1 and Coonarah-1 (and 1A) wells. Cores taken from other wells were mainly intended to evaluate hydrocarbon reservoir sequences; the materials cored usually contained little if any coaly material, and were of limited use for vitrinite reflectance studies.

The intervals sampled were selected from depths at which the presence of the relevant lithologies was indicated by geophysical logs. Care was taken to minimise inclusion of contaminants from overlying strata due to borehole caving. Vitrinite and other coal particles were handpicked from the cuttings over intervals where the well logs showed coal seams to be present. Otherwise, shale and siltstone intervals indicated by geophysical logs were sampled to evaluate the thermal maturity by measuring vitrinite reflectance from dispersed organic matter.

55 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

4.4. Cuttings contamination/alteration

Reliability of vitrinite reflectance measurements from single samples increases when the data are supported by independent maturity parameters, Tmax for example, and where vitrinite reflectance versus depth trends are established from multiple samples in a well. In situ vitrinite in some samples can be overwhelmed by, for example, caved debris. Selection of caved vitrinite particles in the target interval might result in anomalous values compared to the vitrinite reflectance trend established by other samples (Peters and Cassa, 1994).

Contamination due to caving debris in boreholes is a common problem with cuttings samples. In the study area, alteration due to storage conditions that resulted in oxidation of a few cuttings samples was also identified. Vitrinite reflectance measurements from caving debris and oxidised particles provide values different from those of the pristine target intervals. To provide results solely from the targets in question, the effect of any such non-indigenous particles was eliminated wherever possible.

4.4.1. Caving debris

Contamination of cuttings samples may arise due to caving of overlying strata around the drill hole. The process results in mixing of cuttings from shallower intervals with cuttings from the deeper intervals indicated by the drilling depth. The vitrinite reflectance measured on such samples may therefore represent a combination of both the value for the deeper (target) samples and the reflectance of any vitrinite in the caved debris, and thus does not always embrace material only from the interval intended. This significant problem mainly occurs in cuttings samples. In normally buried strata, vitrinite reflectance measurements for cuttings samples containing caved debris usually show lower reflectance than the actual value of the target interval. Depth profiles involving caved materials would be expected to show abnormally low mean vitrinite reflectance values, if the caved debris is not itself affected by local heat due to igneous intrusions.

The presence of low-reflecting vitrinite due to caving from beds higher in the sequence could be indicated from reflectance histograms for some of the individual samples 56 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

involved. The histograms for two such samples from the Jurassic Walloon Coal Measures and the Permian Kianga Formation from Limebon-1 at depths of 1222.25 m and 1712.98 m respectively, illustrates two vitrinite reflectance populations in each sample (Figure 4-1). Vitrinite with a reflectance value between 0.45 and 0.50% occurs as a separate population from the remaining vitrinite in each case; the reflectance measurements for the samples in question are 0.55-0.60% at depth 1222.25 m and 0.65- 0.75% at 1712.98 m (Figure 4-1).

Removal of the low-reflecting caved material from consideration shows a regular increase in reflectance with depth (dark circles, Figure 4-2) for the uncontaminated vitrinite component. The measured vitrinite (telocollinite) particles from caved debris have reflectance values around 0.48% in all studied polished sections in the Limebon-1 well. The vitrinite reflectance versus depth plotted for the lower-rank caved debris in the same borehole shows no change with depth (open circles, Figure 4-2). This suggests a single interval as the main source for the caved debris.

Hand picking of coal and vitrinite particles from intervals indicated by wireline log data as containing coal seams or shaley materials helped to reduce problems with such contamination in the present study. The contrast in reflectance between the lower- reflecting vitrinite from shallow depths and the material from the target horizon, identified from individual reflectance histograms (e.g. Figure 4-1), also helped to separate any contaminating caved particles from the remaining organic matter where the target interval and the caved debris have similar lithologies. Low reflectance values identified as representing caved materials were omitted from consideration in evaluating the results from samples where such contamination was identified by reflectance histogram data.

4.4.2. Oxidised cuttings

Oxidation may result from overvigorous drying (sample heating) at the well site. Oxidation effects, however, as a result of exposure during storage of the sample, which resulted in anomalously high vitrinite reflectance values, were noted for some vitrinite particles within the cuttings samples studied. Such anomalies were identified in Glencoe-1 (at depths of 1578.86 and 1661.16 m; Appendix-1) and in Pearl-1 (at a depth

57 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

Walloon Coal Measures Depth: 1222.25m

No. of measurements: 40

% 40

30

20

10

Measurement frequency 0

0 5 0 5 0 5 0 5 0 4 4 5 5 6 6 7 7 8 0. 0. 0. 0. 0. 0. 0. 0. 0. Rv,max %

Kianga Fm. Depth: 1712.98m No. of measurements: 40

% 40

30

20

10

Measurement frequency 0

0 .50 .55 6 .80 0.40 0.45 0 0 0. 0.65 0.70 0.75 0 Rv,max %

Figure 4-1: Histogram plots of reflectance distribution for two selected samples in Limebon-1 well showing two populations; one from target interval and one from less mature caved debris (modified from Othman and Ward, 2002).

58 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

Limebon-1 R (%) v,max 0.4 0.5 0.6 0.7 0.8 1000

W 1200 H E 1400 P

M

Depth (m) 1600 S K 1800 BC

2000 1.2

Figure 4-2: Vitrinite reflectance profile for contamination (open circles) due to caving and target intervals (dark circles) for Limebon-1. W = Walloon Coal Measures; H = Hutton Sandstones; E = Evergreen Formation; P = Precipice Sandstone; M = Moolayember Formation; S = Showgrounds Sandstone; K = Kianga Formation; BC = Back Creek Group (modified from Othman and Ward, 2002).

59 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

of 1369.29 m; Appendix-1). This problem, which usually causes anomalously high vitrinite reflectance values, was not encountered in the studied core samples. If the actual vitrinite reflectance of the target interval was high, in heat affected samples due to igneous intrusion for example, the oxidation effect would probably be negligible due to the initially high vitrinite reflectance value of the target sample. The polished surfaces of oxidised vitrinite particles have a noticeably higher reflectance than the remainder of the particles in the polished section. In some cases, the outlines of the vitrinite grains and areas around fractures within the particles were visibly brighter than the central parts (Plate 4-1; images a, b and c). Such grains are not from intervals that experienced local heat effects due to igneous intrusions, because in the latter case the particles would be entirely and homogeneously brighter, and show a higher reflectance consistent with the interval’s thermal maturity level. In addition, some of the igneous intrusion affected samples show vesiculation (Jones and Creany, 1977), due to escape of gas generated from the organic particles (Plate 4-1; images d, e and f). Care was taken to avoid such visibly oxidised vitrinite particles in the vitrinite reflectance measuring processes.

Measurement of reflectance in oxidised vitrinite particles, without recognising the oxidation effects, would give anomalously high reflectance values relative to those obtained from equivalent fresh material. As indicated in Figures 4-3a and 4-3b, inclusion of data from oxidised vitrinite may significantly affect the regression line representing reflectance increase with depth. In the Pearl-1 well, the reflectance gradient [identified as rate of increase in vitrinite reflectance with depth (e.g. Petmecky et al., 1999)] in Figure 4-3a is 0.054% per 100 m interval, while the gradient is 0.047% per 100 m after elimination of the oxidised sample at depth 1369.29 m with 0.64% vitrinite reflectance value from the Hutton Sandstone sequence (Figure 4-3b). This variation in reflectance gradient in a borehole is significant, and resulted in this case from only one oxidised sample.

Recognition of anomalously high vitrinite reflectance values in depth profiles, in cases where the high reflectance could not be attributed to igneous intrusions (see below), provided another basis for identifying oxidised materials. Where oxidation could be seen to have occurred with storage, the relevant data were eliminated from consideration in rank profiles and regional studies.

60 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

Plate 4-1: Features of macerals in samples studied.

All images were taken using white incident light and oil immersion objectives. See scale bar in images for magnification. a. Oxidation effect resulting in brighter outline for telocollinite (Tc) particle;

fusinite (F); pyrite (Py). Hutton Sandstone, 1578.86 m, 0.78% Rv,max, Glencoe-1, Bowen Basin. b. Brighter material around fractures inside telocollinite (Tc) particle due to

oxidation effects. Hutton Sandstone, 1578.86 m, 0.78% Rv,max, Glencoe-1, Bowen Basin. c. Oxidation effects altering entire lower particle of telocollinite (Tc), but with brighter material still visible around fractures and outlines. Upper particle less

affected. Hutton Sandstone, 1369.29 m, 0.64% Rv,max, Pearl-1, Bowen Basin. d. Gas escape traces (vesiculation) in telocollinite (Tc) due to igneous intrusion; clay minerals (Cm); quartz? (Q). Watermark/Porcupine Formation, 646.54 m,

1.86% Rv,max, Coonarah-1A, Gunnedah Basin. e. Vesiculation (~1-2 µm in diametere) in telocollinite (Tc) due to igneous intrusion; fusinite (F); inertodetrinite (Id). Watermark/Porcupine Formation,

639.11 m, 2.28% Rv,max, Wilgapark-1, Gunnedah Basin. f. As e, different field. Macrinite (M). g. Pyrite (Py) framboid in mineral matrix. Watermark/Porcupine Formation,

646.54 m, 1.86% Rv,max, Coonarah-1A, Gunnedah Basin. h. Pyrite (Py) framboid in fusinite (F). Maules Creek Formation, 939.93 m, 0.57%

Rv,max, Bellata-1, Gunnedah Basi

61 61 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

F

Tc Tc

Py

a 50 µm b 50 µm

Cm

Tc Q

Tc

Tc

25 µ c 50 µm d m

F

Tc F M Id Tc

Id

50 µm e F f 50 µm

Py

F 25 µm h 25 µm

62 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

Pearl-1 Pearl-1 A B Rv,max (%) Rv,max (%) 0.5 0.6 0.7 0.5 0.6 0.7 1200 1200 W W

1300 1300 H H

1400 1400 Depth (m) Depth (m) M M

1500 1500

S S

1600 1600

Figure 4-3: Effect of oxidised sample (open circle) on reflectance gradient in Pearl-1 well. Reflectance gradient in (A) is 0.054% per 100 m and in (B) is 0.047% per 100 m. See Figure 4-2 for units identification (modified from Othman and Ward, 2002).

63 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

4.5. Reflectance pattern in the study area

4.5.1. Vitrinite reflectance profiles and anomalies

Anomalous vitrinite reflectance values, in comparison to more normal values in the overlying or underlying intervals show significant offsets in reflectance profiles and were identified in the study area. The causes of such anomalies may include marine influence on the vitrinite during or shortly after deposition, as well as the presence of abundant liptinite macerals in close association with the vitrinite component. Significant offsets in reflectance profile may also arise due to additional heat flow from igneous intrusions. Less significant offsets, however, may be attributed to variation in lithology, overpressured intervals or to the presence, in some cases, of a pseudovitrinite component.

4.5.1.1. Vitrinite reflectance suppression

Anomalously low or suppressed vitrinite reflectance values due to marine influence in Permian coal seams of the Gunnedah Basin south of the study area have been described by Gurba (1998) and Gurba and Ward (1998). These occur in the upper part of the Early Permian Maules Creek Formation and in the lower part of the Late Permian Black Jack Group, mainly within the Arkarula shallow marine system. The same phenomenon has also been documented in the marine influenced Early Permian Greta seam of the Sydney Basin (George et al., 1994).

In the present study, suppressed vitrinite reflectance measurements were interpreted in coal and DOM samples from the Permian Back Creek Group sequence of the Bowen Basin. In the Gunnedah Basin, suppressed values were interpreted in the Goonbri, Maules Creek and Watermark/Porcupine Formations.

In the New South Wales portion of the Bowen Basin, reflectance profiles through boreholes show steady downward increases through the Jurassic and Triassic sediments, and where present the uppermost Permian Kianga Formation, but a sharp decrease at the top of the Permian Back Creek Group. The vitrinite reflectance then continues to increase at a slightly greater rate in the underlying Back Creek Group strata (Figures 4-2

64 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

and 4-4; Appendix-1). It is well documented that the Back Creek Group was deposited under predominantly marine conditions (e.g. Morton et al., 1993). Conformably, the vitrinite reflectance suppression in this sequence is attributed to this marine influence.

The reflectance versus depth profile for Bellata-1, in the Bellata Trough of the northern Gunnedah Basin, shows a steady increase with depth through the Jurassic and the upper part of the Triassic strata with vitrinite reflectance increasing from 0.42 to 0.63% over the 100 m depth interval from 566.73 to 665.77 m. Although interrupted by locally elevated values due to igneous intrusions near the base of the Triassic (781.80 – 871.55 m) and over a small interval near the base of the Permian sequences, the profile shows a lower than expected reflectance in the immediately underlying Early Permian Maules Creek and Goonbri Formations (Figure 4-5). The value at 939.93 m, for example, in the marine-influenced Maules Creek Formation is only 0.57% less than that in the Napperby Formation at 665.77 m, 274.16 m above. The Late Permian Black Jack Group, as well as the Watermark and most of the Porcupine Formations, have been removed from the sequence in this area (Figure 3-2; Chapter 3), due to an Early Triassic contraction event. The sedimentary sequence in the adjoining part of the Bohena Trough, in which most of the Permian sequence is preserved, is also significantly affected by local heat flow from igneous intrusions. Possible suppression of vitrinite reflectance within the Permian sequences in some of the borehole profiles cannot be identified because of intrusions (Figures 4-6 and 4-7), even though these sequences also contain partially marine sediments. In Bohena-1, although local heat has partially affected the sequence (Figure 4-8), a relatively low vitrinite reflectance is apparent for the analysed samples over the entire Permian sequence, except for the intrusion-affected sample. Relatively low, suppressed, reflectance values for Watermark/Porcupine Formation are also identified in Nyora-1 and Wee Waa-1 (Appendix-1).

As indicated by Gurba and Ward (1998), suppression of vitrinite reflectance in the Permian Maules Creek Formation and the lower part of the Black Jack Group in the Gunnedah Basin is mostly due to marine influence. This same factor may apply to the Watermark/Porcupine Formation, which also contains marine sediments (cf. Thomas et al., 1993). The marine influence on these sequences is consistent with abundance of framboidal pyrite in some of the samples studied (Plate 4-1; images g and h). Framboidal pyrite is identified as raspberry-like aggregates of tiny spherical particles of

65 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

McIntyre-1 Goondiwindi-1

Rv,max (%) Rv,max (%) 0.2 0.4 0.6 0.8 1 0.2 0.4 0.6 0.8 1 850 850 W 1050 1050 H 1250 1250 E P 1450 W 1450 M

S 1650 H 1650 K E Depth (m) 1850 Depth (m) 1850 BC P M 2050 2050 S K 2250 BC 2250 v 2450 2450

Figure 4-4: Reflectance profiles from McIntyre-1 and Goondiwindi-1. Anomalously low, suppressed, values can be seen in the Back Creek Group in both sections. V = Volcanics. See Figure 4-2 for identification of other units (modified from Othman and Ward, 2002).

66 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

Bellata-1 Bellata-1 Rv,max (%) Rv,max (%) 0123 0.3 0.6 0.9 500 500 Pi Pi 600 600 Pu Pu

700 700 N N 800 800 I I

900 900 Depth (m) DPo Depth (m) DPo MC MC 1000 1000

G G 1100 1100 B B 1200 1200

Figure 4-5: Reflectance profile for Bellata-1 with two different horizontal scales to clarify suppression phenomenon. Samples below 900 m (except for contact metamorphosed sample) have suppressed reflectance. Samples at 829.60, 871.55 and 1104.16 m are highly affected by local igneous intrusion ( I ). Pi = Pilliga Sandstone; Pu = Purlawaugh Formation; N = Napperby Formation; D = Digby Formation; Po = Porcupine Formation; MC = Maules Creek Formation; G = Goonbri Formation; B = Basement (modified from Othman and Ward, 2002).

67 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

Wilga Park-1 Rv,max (%) 0246

350

450 Pu

550

N

Depth (m) I 650 W/P MC 750 G

Figure 4-6: Reflectance profile for Wilga Park-1. High reflectance values due to igneous intrusions occur throughout the section, even though only one actual intrusion is encountered at 621.18 m. W/P = Watermark/ Porcupine Formation. See Figure 4-5 for identification of other units (modified from Othman and Ward, 2002).

68 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

Coonarah-1A Rv,max (%) 0123 350 Pu

N 450 I

D 550 Depth (m) BJ

Wa 650

Figure 4-7: Reflectance profile for Coonarah-1A. High reflectance values occur throughout the section due to igneous intrusions. BJ = Black Jack Group; Wa = Watermark Formation; see Figure 4-5 for identification of other units (modified from Othman and Ward, 2002).

69 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

Bohena-1 Bohena-1

R (%) R (%) v,max v,max 012 0.3 0.5 0.7 0.9 1.1

250 250

Pu Pu

450 450 N 1.43 N I I

650 BJ 650 BJ Depth (m) Depth (m) W/P W/P

850 850 1.32 MC MC

G G 1050 1050

Figure 4-8: Reflectance profile for Bohena-1 with two different horizontal scales, entire Permian sequence shows relatively low reflectance except for local heat affected sample at depth 855.73 m. See Figures 4-5, 4-6 and 4-7 for units identification.

70 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

pyrite; their presence in sediments has been attributed to the action of micro-organisms, or sometimes to colloidal deposition (Deer et al., 1967). Although pyrite may occur as a minor constituent of many sediments (e.g. Pettijohn, 1957; Selley 1976), Perry and Pedersen (1993) indicate that pyrite is a common authigenic mineral in recent marine and lacustrine sediments and sedimentary rocks. Smith and Batts (1974), and Pearson (1979) further recognised high pyrite content to be one of the most common characteristics of marine influenced coals. The presence of framboidal pyrite in the samples studied is considered to support marine incursion in deposition of these sequences. In such a case vitrinite reflectance suppression is more likely due to marine influence than to the adsorption of hydrocarbons into the vitrinite matrix (George et al., 1994). Perhydrous vitrinite is formed under anoxic conditions in marine sediments in which anaerobic degradation of the organic matter produces vitrinite with a high hydrogen content, which then suppresses the reflectance of the vitrinite (Diessel, 1990; Carr, 2000).

The vitrinite reflectance suppression encountered in the Goonbri Formation sequence is attributed to a high proportion of liptinite rich organic matter (Plate 4-2). Based on visual examination of the palynological assemblage, the type of organic matter in this formation is identified as liptinitic kerogen (Hamilton et al., 1988, 1993). Similar suppression of vitrinite reflectance due to associated high liptinite percentages is well documented by various workers, including Hutton and Cook (1980), Gentzis and Goodarzi (1994) and Goodarzi et al. (1994). Murchison et al. (1991) recorded that, particularly at lower rank levels, the reflectance of vitrinite in sediments is reduced, often significantly, when substantial quantities of liptinite macerals are present. With increase in total liptinite content a gradual reflectance decrease has also been documented in Cretaceous coals (Kalkreuth, 1982). The high proportion of liptinite in the coal or kerogen induces a lower reflectance value, which some researchers (e.g. Petersen and Vosgerau, 1999) attribute to bitumen expulsion from the liptinite into the huminite/vitrinite structure. The adsorbed bitumen reduces the rate of cross-linking and condensation of the aromatic framework, resulting in suppressed reflectance values (Diessel, 1990, 1992). However, as Price and Barker (1985) have reported previously, bitumen adsorption cannot be the main cause of suppression of vitrinite reflectance. Wenger and Barker (1987), in addition, found that extraction of hydrocarbons from black shales with suppressed reflectance did not change the reflectance after extraction.

71 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

Plate 4-2: Features of liptinite macerals in the samples studied from the Goonbri Formation.

All images were taken using fluorescent light and oil immersion objectives except b and g, which were taken using white incident light and oil immersion objectives. See scale bar in images for magnification. a. Fluorescent band interpreted as alginite (A). Goonbri Formation, 1104.95 m,

0.61% Rv,max, Bellata-1, Gunnedah Basin. b. As a, incident light. c. Sporinite (Sp); megaspore. Goonbri Formation, 1104.49 m, 0.66% Rv,max, Bellata-1, Gunnedah Basin. d. High concentration of sporinite (Sp), a megaspore is also present. Goonbri

Formation, 1112.68 m, 0.61% Rv,max, Bellata-1, Gunnedah Basin. e. Fluorescent liptinite, mainly sporinite. Goonbri Formation, 1019.22 m, 0.65%

Rv,max, Bellata-1, Gunnedah Basin. f. High concentration of cutinite (Cu). Liptodetrinite (Ld) is also observed.

Goonbri Formation, 1049.49 m, 0.66% Rv,max, Bellata-1, Gunnedah Basin. g. Unidentified liptinite in siltstone. Goonbri Formation, 1073.86 m, 0.73% Rv,max, Bellata-1, Gunnedah Basin. h. As in g, white incident light.

72 71 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

A A

a 50 µm b 50 µm

Sp

50 µm c

Cu

Ld e 50 µ m f 50 µm

g 50 µm h 50 µm

73 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

Mastalerz et al. (1993) studied variations in vitrinite chemistry with reference to the proportion of liptinite associated with vitrinite. The study showed that the C and O content decrease and the H content increases as liptinite content increases. On a molecular scale, the changes are expressed by an increase in aliphatic H and a decrease in aromatic H as liptinite content increases (Mastalerz et al., 1993).

Bitumen impregnation, together with the formation of perhydrous vitrinite and high liptinite concentration, are all plausible models to account for the occurrence of vitrinite reflectance suppression (Carr, 2000).

No significant decrease in vitrinite reflectance is noticed between the uppermost Permian, with vitrinite having ‘normal’ reflectance and the overlying Triassic sequence. In the Bowen Basin, the strata overlying the coal measures display a reflectance profile continuous with that of the Kianga Formation. This indicates that there was no major development of coalification in the Permian sequence during the interval represented by the angular unconformity between the Permian and Triassic successions, or that any differences associated with the unconformity was overprinted by later burial affects. However, the absolute difference in vitrinite reflectance across an unconformity decreases with time and with increasing burial depth (Katz et al., 1988). The Triassic sequence includes several coarsening upwards deltaic successions, interpreted by Jian and Ward (1993, 1996) as representing freshwater lake-fill fan-delta deposits rather than marine delta sequences. The absence of reflectance suppression in the Triassic sediments is consistent with a lack of marine influence for this part of the basin fill, and further supports the essentially terrestrial nature of the environment into which the fan- deltas prograded during deposition of the Napperby Formation.

4.5.1.2. Igneous intrusion effects

Contact metamorphism from igneous intrusions may affect the organic matter maturity in the surrounding strata (e.g. Dow, 1977; Beeston, 1978) and results in optical changes. The changes induced by thermal metamorphism, however, depend on the initial rank of the organic matter preserved in the sediment (Jones and Creany, 1977). Even though the extent of thermal alteration in a sedimentary sequence is reasonably similar and

74 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

proportional to dyke thickness, according to Bishop and Abbott (1995), variations in aureole thickness are recorded with regard to intrusion thickness. Carboniferous coal from cuttings samples, for example, shows aureole widths of approximately seven times the thickness of the intrusion (Jones and Creany, 1977). Studies in the Gunnedah Basin Permian coals (Gurba, 1998; Gurba and Weber, 2001) have shown that intrusion effects on vitrinite reflectance may extend over a maximum vertical distance of about twice the thickness of the intrusive body. Dow (1977) has previously suggested similar aureole widths. Bishop and Abbott (1995) observed in their study of Jurassic siltstone samples a relatively narrow lateral extent of enhanced vitrinite reflectance, and reported a maximum aureole width of 70% of the dyke thickness. Studies of Carboniferous coal and sediment by Raymond and Murchison (1988) indicate that the alkaline sills have had a minimal effect upon the organic matter even in sediments that are very close to the intrusions.

The width of the aureole in relation to the igneous intrusion thickness is dependent on the degree of compaction undergone by the sediment due to the overburden load, and consequently the volume of pore-water present at the time of emplacement (Raymond and Murchison, 1988). In such cases, host rock lithology also may be significant factor. Dow (1977), in addition, suggested that the actual extent of the metamorphic aureole depends on the temperature difference between the intrusion and the invaded rock, the depth at which the intrusion was emplaced, and the rate of cooling. The maturation profile in the vicinity of the intrusion is not a straight line, because the thermal gradient that caused it was continuously changing (Dow, 1977). The effects of igneous intrusion may often extend further above the intrusion than below (Figure 4-9) (Dow, 1977; Hunt, 1996). This could be attributed to preferential movement of hydrothermal solutions with convection and pressure (Othman and Ward, 2002).

Some of the boreholes in the study area have penetrated igneous intrusions, especially wells in the southern Bowen Basin close to the Moree High. Further south, in the northern Gunnedah Basin, igneous intrusions were also encountered in both the Bohena and Bellata Troughs. The intersected thicknesses of the individual intrusions are variable, ranging up to a maximum of 192 m for an intrusion in the Back Creek Group penetrated by the Lantern-1 well.

75 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

Mt Pleasant-1

Rv,max (%) 0.4 0.6 0.8 1 750

1000 H 2.0 1.3 I M 1250

K Depth (m) 1500

1750 BC

2000 1.3

Figure 4-9: ‘Simple profile’ localised increase in vitrinite reflectance around intrusive body in Mt Pleasant-1. Despite this effect, the Back Creek Group (BC) clearly has a lower reflectance than the upper part of the sequence. See Figures 4-2 and 4-5 for identification of other units (modified from Othman and Ward, 2002).

76 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

Two types of vitrinite reflectance profiles affected by igneous intrusions can be identified from the samples studied; these are simple and complex profiles (Othman and Ward, 2002). In the simple profile, with discrete, relatively thin intrusive bodies, the elevated reflectance values above and below the intrusion can be readily distinguished from the general downward increase in vitrinite reflectance with depth. Such a case can be observed within the Middle Triassic Moolayember Formation in the Mt Pleasant-1 well (Figure 4-9). Shifts in the reflectance profile due to marine influence can still be seen, and the vitrinite reflectance gradient may be calculated, despite the intrusions, in many such successions. In the complex profiles, despite there being only minor intruded intervals apparent, the entire sedimentary sequence appears to reflect a high local heat flow (e.g. Figures 4-6 and 4-7), obliterating the rank trends due to burial as well as any reflectance suppression effects. In such a case the vitrinite reflectance gradient, if recognisable, mainly reflects local heat effects due to the igneous intrusions.

The high heat flows associated with igneous intrusions in the area may give rise to local development of hydrocarbon generation. Bishop and Abbott (1995) note that detailed sampling of a Jurassic siltstone adjacent to a 0.9 m dyke reveals that the zone of maximum extractable organic matter (EOM mg/g rock), equivalent to the oil window, lies at a distance of between 25 and 50% of the dyke thickness from the contact. The position of this oil window, relative to the vitrinite reflectance profile, is comparable with that from burial maturation (Bishop and Abbott, 1995).

As indicated above, the lower part of the Middle Triassic Napperby Formation in Bellata-1 is also affected by igneous intrusions, in addition to a small interval in the Early Permian Goonbri Formation (Figure 4-5). Geochemical studies by Othman et al. (2001) have shown that oil stains in the overlying Jurassic Pilliga Sandstone were generated from relatively high-temperature metamorphism of the organic matter in this lower part of the Middle Triassic succession. Natural gas, in addition, was discovered in 1985 in the Wilga Park-1 well in the study area. Vitrinite reflectance in the samples studied from this borehole (Figure 4-6) ranges between 1.97 and 5.51% (Appendix-1). The Wilga Park-1 succession represents an example of a ‘complex’ profile for locally heated sequences due to igneous intrusion effects. The gas appears to have been generated as a result of local heat effects in conjunction with the more usual reflectance- depth profile. Traces of escaped gas and vesiculation patterns (cf. Jones and Creany,

77 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

1977) were observed in the organic matter particles of some samples studied in Wilga Park-1 well (Plate 4-1; images d, e and f).

4.5.1.3. Lithology effects

Leckie et al. (1988) have found higher reflectance values in thick coal seams compared to thin coal seams, and related this to a lower thermal conductivity and greater heat capacity of the thick seams. Héroux et al. (1979) previously suggested that, due to contrasts in thermal conductivity, vitrinite particles in coal generally have a slightly higher reflectance than vitrinite phytoclasts buried under equivalent conditions dispersed in associated mineral-rich non-coal lithologies. Khorasani and Michelsen (1994) reported that shales have lower vitrinite reflectance values than interbedded coals, but they attributed these variations to the differences in the chemistry of the vitrinite in the shales and coals respectively. This conclusion supports Goodarzi et al. (1993), who reported that differences in thermal conductivity cannot explain the differences in vitrinite reflectance within interbedded lithologies, which is dependent on the actual temperatures experienced by the rocks. Within a sedimentary column, the deepest sediment will at any time be hotter. Thermal conductivity affects the rate at which heat flows through the rocks and, consequently, the thermal gradients. Hence the effect of thermal conductivity on temperature is largely dependent on the thickness of the rock unit. It is generally accepted that even a 40% difference in thermal conductivity cannot account for any measurable differences in organic maturation (e.g. vitrinite reflectance) gradients between thinly interbedded successions or even between different lithologies (Goodarzi et al., 1993).

In the present study slightly lower reflectance values were recorded in a few DOM samples than from the adjacent coals. The overall effect on the resulting profiles in general does not seem to be significant, however, compared to other sources of anomalous reflectance values. One exception may be a case from the Permian sequence in Bohena-1 (Figure 4-8; Appendix-1) where a lithology effect may be apparent. A vitrinite reflectance value of 0.63% is recorded for a shale sample from a cored interval in the Goonbri Formation at 966.83 m. A cuttings sample of coal from the Maules Creek Formation at 896.11 m and a cuttings sample containing vitrinite and shale particles from the Goonbri Formation at 1002.79 m both show higher vitrinite

78 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

reflectance values of 0.72% and 0.74% respectively. A shale sample from 1595.22 m in a cored interval of Boomi-1 (Figure 4-10) has lower reflectance than the other cuttings samples studied, which contain mainly coaly materials. Such relatively low vitrinite reflectance values for shales in relation to the adjacent coaly samples are attributed to lithology variation.

4.5.1.4. Vitrinite reflectance retardation due to overpressure

A number of studies have indicated that overpressure may retard reflectance increase and maturation (e.g. Price and Wenger, 1992; Dalla et al., 1997), but some of the published investigations appear to be conflicting (e.g. Khorasani and Michelsen, 1994). Other workers (e.g. Philippi, 1965; Tissot and Welte, 1984) claim that pressure has no influence on maturation. Careful examination of the experimental conditions shows that both vitrinite reflectance and hydrocarbon generation are retarded by overpressure (Carr, 1999). Under overpressured conditions, the mean effective stress (mean stress minus pore pressure) is much lower and the pore pressure is usually higher than under hydrostatic pressure conditions. As a result, the progressive molecular ordering of the vitrinite, such as the aromatisation, is retarded, and the vitrinite reflectance is less readily increased according to Zou and Peng (2001).

A small interval in the lower part of the Middle Triassic sequence in the boreholes studied in the Gunnedah and Bowen Basins appears to have been abnormally compacted or overpressured (Othman and Ward, 1999). The overpressured zone is a thin interval, and was difficult to encompass in the sampling program. No cores were available, and cuttings from that interval, where they could be obtained, had low proportions of organic matter. The only cores were from Bellata-1 and Coonarah-1A, where in both wells the succession is intrusion affected. However, relatively low vitrinite reflectance values were observed in two samples of the overpressured Snake Creek Mudstone Member in Chester-1 (Appendix-1). The slightly lower values in this case cannot be a result of lithology effects, as the samples studied from the Middle Triassic sequences in this particular borehole are mainly shale, and it is also expected that these samples are not contaminated by caved debris. Hence the slightly lower vitrinite reflectance values in these two samples could be attributed to pressure effects.

79 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

Boomi-1

Rv,max (%) 0.4 0.6 0.8 1200

W 1300

1400 H

Depth (m) 1500 E

1600 M

S 1700 B

Figure 4-10: Reflectance profile in Boomi-1 showing possible lithology effect on a sample at depth 1595.22 m. See Figures 4-2 and 4-5 for units identification.

80 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

4.5.2. Vitrinite reflectance gradient

Present-day geothermal gradients in the boreholes studied, based on bottom hole temperatures, range from 1.84ºC per 100 m in McIntyre-1 to 5.51ºC per 100 m in Wilga Park-1 (Table 4-1). The reflectance gradient for the non suppressed sequences in the boreholes studied, based on vitrinite reflectance profiles excluding data from any localised heat-affected samples, ranges from 0.021% per 100 m in Limebon-1 to 0.087% per 100 m in Werrina-1. Reflectance gradient may be considered as a heat-flow indicator, during the time rank advance took place. If allowance is made for any intrusive effects, as in ‘simple’ intrusion-affected profiles, the reflectance-depth profiles and reflectance gradients in the sections studied provide useful information on the overall temperature history of the Permian and Mesozoic succession in different parts of the basin. The geothermal gradient and vitrinite reflectance gradient shows the importance of higher heat-flow at depth, causing generation of hydrocarbons.

Table 4-1 shows that the sequences studied experienced different heat-flow intensity during rank advance. This can be seen through the vitrinite reflectance gradients. The highest palaeo-heat flows are encountered in Coonara-1A (Rv,max = 0.53% to 2.74% over 119 m interval; Figure 4-7 and Appendix 1), and in Wilga Park-1 (Rv,max = 1.97% to 5.52% over 314 m interval; Figure 4-6 and Appendix 1), which both have ‘complex’ intrusion effect profiles and for which no gradient can be determined. Variations in present-day heat flow are also observed. Geothermal gradient is a good indicator of present day heat-flow in a particular borehole. The maximum present-day geothermal gradient is in Wilga Park-1 (5.51oC/100 m; Table 4-1) that reflects the highest current heat flow for the boreholes studied. In Coonarah-1A the heat-flow is significantly lower and the present-day geothermal gradient in this borehole is 2.62oC/100 m (Table 4-1). The bottom hole temperatures in these two boreholes are significantly different; 63.89oC in Wilga Park-1 at a depth of 795.83 m and 37oC in Coonarah-1A at a depth of 650 m (Table 4-1). The variations in bottom hole temperatures are attributed to intensity variations of the present-day heat-flow in different parts of the basin.

Figure 4-11 and Table 4-1 show that the sedimentary section in Glencoe-1 has a lower reflectance gradient than the section in Pearl-1, despite the fact that the relevant sediments in Glencoe-1 are currently more deeply buried. The reflectance gradients in

81 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

Table 4-1: Bottom hole temperature, present-day geothermal gradient and reflectance gradient in the boreholes studied (after Othman and Ward, 2002). Reflectance gradient% per Reflectance Bottom hole Geothermal 100 m (non- gradient% per 100 Total depth temperature gradient* suppressed m (suppressed o o No. Basin Borehole name (m) ( C) C/100 m interval) interval) 1 B/S Barb-1 1704.13 73.33 3.13 0.029 nd 2 G/S Bellata-1 1128 - nd 0.149 nd 3 G/S Bohena-1 1650.18 60.00 2.42 nd nd 4 B/S Boomi-1 1595.29 57.78 2.37 0.032 nd 5 B/S Camurra-1 882.39 47.78 3.15 nd nd 6 B/S Chester-1 2135.73 65.56 2.13 0.033 0.037 7 G/S Coonarah-1A 650.00 37.00 2.62 nd nd 8 B/S Edendale-1 2237.00 73.00 2.37 0.037 0.038 9 B/S Garah-1 1600.80 60.00 2.50 0.022 nd 10 B/S Gil Gil-1 1604.77 62.22 2.63 0.054 nd 11 B/S Glencoe-1 1958.03 62.22 2.16 0.027 nd 12 B/S Goondiwindi-1 2222.60 68.33 2.17 0.045 0.059 13 B/S Kinnimo-1 1538.43 60.00 2.60 0.023 nd 14 B/S Lantern-1 2076.90 60.00 1.93 0.023 nd 15 B/S Limebon-1 2010.15 66.67 2.32 0.020 nd 16 B/S McIntyre-1 2535.63 66.67 1.84 0.028 0.054 17 B/S Moree-1 1147.73 48.89 2.52 0.024 nd 18 B/S Moree-2 1221.33 55.56 2.91 0.080 nd 19 B/S Moree-3 - - - 0.115 nd 20 B/S Mt Pleasant-1 2266.18 66.67 2.06 0.024 0.026 21 G/S Nyora-1 811.37 44.50 3.02 nd nd 22 B/S Pearl-1 1575.81 58.33 2.43 0.047 nd 23 B/S Quack-1 1670.30 60.00 2.39 0.048 nd 24 G/S Wee Waa-1 824.78 45.00 3.03 nd nd 25 B/S Werrina-1 1519.45 54.44 2.27 0.087 nd 26 B/S Werrina-2 1566.74 56.67 2.34 0.055 nd 27 G/S Wilga Park-1 795.83 63.89 5.51 nd nd *Ambient surface temperature = 20oC B/S = Bowen/Surat Basin G/S = Gunnedah/Surat Basin nd = not determined

82 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

Werrina-1 Pearl-1 Glencoe-1 A B C Rv,max (%) Rv,max (%) Rv,max (%) 0.4 0.5 0.6 0.7 0.8 0.4 0.5 0.6 0.7 0.8 0.4 0.5 0.6 0.7 0.8 1150 1150 1150

W W

1350 H 1350 H 1350 E W B M S 1550 1550 1550 H

Depth (m) KV Depth (m) Depth (m) E

1750 1750 1750 M

S R 1950 1950 1950

Figure 4-11: Variation in reflectance gradient for selected boreholes through Triassic and Jurassic sequences in the northwestern part of the study area. R = Rewan Group; KV = Kuttung Volcanics. See Figures 4-2, 4-3 and 4-5 for identification of other units (modified from Othman and Ward, 2002).

83 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

these two boreholes are also lower than the gradient in Werrina-1 to the west. These differences might be attributed to the thickness of the underlying sedimentary sequence in different parts of the basin, which corresponds to the distance from basement, the presumed source of the heat. The Permian sequence, however, is thin or absent in these and other nearby boreholes. The Triassic sequence itself is absent from Werrina-1, and in that borehole the Jurassic sediments directly overlie the basement rocks (Figure 4- 12). Where the Permian sequence is present, the different boreholes may also show different reflectance gradients (Figure 4-4). The heat flow intensity coupled with burial in various parts of the basin apparently played the main role in determining organic matter thermal maturity.

It is well documented that organic matter maturation is mainly a result of time and temperature (e.g. Tissot and Welte, 1984; Taylor et al., 1998). The time factor may be eliminated, however, if comparison is based on the same geological sequence in different areas in the basin. The variation in organic maturation at such horizons can possibly be attributed to differences in burial depth or to variations in heat flow. Higher heat flow might be expected with ascending magmas or hydrothermal fluids associated with igneous processes, or with increasing proximity to radiogenic heat sources (e.g. potassium-bearing granites or acid volcanics) in the basement materials.

Even though the sedimentary succession currently is more buried in McIntyre-1 than in Goondiwindi-1, the geothermal gradient and reflectance gradient are both higher in Goondiwindi-1 (Table 4-1). The profile in McIntyre-1 (Figure 4-4) shows a reflectance gradient of 0.028% per 100 m in the upper part of the sequence, above the interval with suppressed vitrinite reflectance values (i.e. above a depth of 2206 m). The same but shallower section in Goondiwindi-1, however, shows a reflectance gradient of 0.045% per 100 m (Figure 4-4). The gradient in the section with anomalously low (suppressed) reflectance has a higher gradient in both wells. The reflectance gradient, again, is higher in Goondiwindi-1, 0.059% per 100 m, than in McIntyre-1, 0.054% per 100 m, (Figure 4-4; Table 4-1). The presence of similar levels of organic maturation at shallower depths in Goondiwindi-1 as for those of McIntyre-1 (Figure 4-4) may therefore be attributed to a local heat flow effect, particularly as the well is close to the Goondiwindi Thrust. More normal heat flows in McIntyre-1 produced similar reflectance at greater burial depth. Although the total depth in McIntyre-1 is 2535.63 m and in Goondiwindi-1 is

84 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

Werrina-1 Pearl-1 Glencoe-1

Figure 4-12: Cross section for the boreholes in Figure 4-11. See Figures 4-2, 4-5 and 4-11 for units identification (modified from Othman and Ward, 2002).

85 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

2222.60 m, the bottom hole temperature and the present-day geothermal gradient are both higher in Goondiwindi-1 than in McIntyre-1 (Table 4-1). This reflects the present- day heat flow, which is apparently still higher in the Goondiwindi Thrust area.

The vitrinite reflectance profile for Goondiwindi-1 has a high gradient, with the presence of slightly lower maturity intervals in the shallower Jurassic sequences than for McIntyre-1, while the McIntyre-1 profile has a lower vitrinite reflectance gradient with a more mature interval in the shallower Jurassic sequences (Figure 4-4). Such profiles suggest that organic matter maturity in Gondiwindi-1 is influenced from a higher heat flow, while in McIntyre-1 the maturity is more influenced by a greater burial depth.

Figure 4-13 shows the reflectance gradients for the wells between the Moree High and the New South Wales – Queensland border. The data represent the gradients after elimination of anomalies due to contamination and oxidation of well cuttings, and to the effects of any localised igneous intrusions. Reflectance gradients in the Permian Back Creek Group, where the vitrinite reflectance is anomalously low due to marine influence, are shown separately as the lower figure against the respective boreholes in the diagram. The gradients in the Early Permian marine interval are often somewhat higher than in the overlying Kianga Formation (where present) and the Mesozoic sequence. The Back Creek Group is not present in the west, and the overlying strata rest directly on the basement materials. Figure 4-13 also shows that the reflectance gradient in the New South Wales portion of the Bowen Basin, especially in the upper Permian and Mesozoic succession, increases generally towards the basin margin to the west. This is apparently related to depth to basement, as the increase takes place in conjunction with a thinning sedimentary succession. The Permian sequence pinches out to the west and the overlying sequences thin and progressively overlap the basement (Figure 4-12). The reflectance gradient also increases close to the Goondiwindi Thrust in the east, over the Gil Gil Ridge in the centre of the area, and towards the Moree High in the south (Figure 4-12). A similarly high reflectance gradient has been reported on the margins and ridges of the Bowen Basin portion further to the north in Queensland (Beeston, 1981).

Vitrinite macerals with different initial hydrogen contents have different reaction kinetics (Fang and Jianyu, 1992). Thus, it is expected that changes in the development

86 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

Figure 4-13: Lateral variation in reflectance gradient for the upper (normal) and lower (suppressed) parts of the sequence in the southern Bowen Basin (modified from Othman and Ward, 2002).

87 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

of the chemical structure of vitrinite would be reflected on the depth/reflectance relations (Suggate, 1998). Newman (1997) suggested that depositional and diagenetic influences on vitrinite compositions result in a variable hydrogen content, with a consequent variability in vitrinite reflectance. Consistently, higher reflectance gradients in the suppressed Back Creek Group sequence compared to non-suppressed intervals in McIntyre-1 (Table 4-1; Figure 4-13), for example, could be an expression of the different chemical composition of the vitrinite deposited under marine conditions.

Reflectance suppression effects are not apparent when the sequence experiences an intensive local heat flow due to igneous intrusions (Figures 4-6 and 4-7). This is attributed to rejuvenation of the entire vitrinite reflectance system due to the intense heat effect. Even though the reflectance gradient is higher in suppressed sequences, the variation in reflectance gradient between suppressed and non-suppressed intervals differs in different boreholes. Similar reflectance gradients occur in the suppressed and non-suppressed intervals of Chester-1 and Edendale-1, for example, but the gradients are different for the suppressed and non-suppressed intervals in McIntyre-1 and Limebon-1 (Figure 4-13; Table 4-1). This variation is possibly attributed to heat flow. Chester-1 and Edendale-1 are located on the Gil Gil Ridge, while equivalent maturation in McIntyre-1 and Limebon-1 possibly resulted from greater burial depths. Mt Pleasant- 1 is exceptional, because the non-suppressed interval is affected by igneous intrusion (Figure 4-9).

4.5.3. Lateral reflectance trends

Vitrinite reflectance was estimated from the individual borehole profiles for a horizon at the contact of the Moolayember Formation with the Showgrounds Sandstone. This contact was chosen as the datum for an isoreflectance map because it is widely distributed in the study area, no suppression of reflectance has been recorded above this level, and the contact is easy to recognise on wireline logs. The Showgrounds Sandstone is also a unit with good petroleum reservoir characteristics.

Although limited by the number of available boreholes, the reflectance at this level in the sequence (Figure 4-14) is in a good agreement with the vitrinite reflectance gradient distribution in the area and increases towards the west. It also increases over the Gil Gil

88 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

Figure 4-14: Isoreflectance map for a horizon at the contact of the Moolayember Formation with the Showgrounds Sandstone in the southern Bowen Basin (modified from Othman and Ward, 2002).

89 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

Ridge, close to the Goondiwindi Thrust in the east, and over the Moore High in the south. In addition, the values of the isoreflectance lines increase towards the north, over the Queensland – New South Wales border, where the Bowen and Surat Basins sequences are thicker.

The presence of higher reflectance values at stratigraphically equivalent horizons in areas above the basement ridges may be due to uplift of the ridges after the main period of rank advance. This phenomenon is consistent with a pre-deformation maturity pattern. Thinner stratigraphic sections over the ridges, combined with anticlinal folding in the basin-fill succession, suggest that the ridges were active as positive tectonic elements both during and after deposition. The presence of higher reflectance gradients on the ridges, discussed above, may also be an expression of higher heat flow from the shallower-buried basement materials.

Due to extensive intrusion effects and limited numbers of boreholes, it was not possible to extend the isoreflectance study across the Moree High and into the northern part of the Gunnedah Basin. The Gunnedah Basin has had a similar tectonic history to the Bowen Basin. The total amount of tectonic subsidence in the Gunnedah Basin, however, is lower than that in the Taroom Trough, the northern continuation of the Bowen Basin system in Queensland (Korsch et al., 1993). Although some high vitrinite reflectance values occur in the northern Gunnedah Basin (Appendix 1) or further to the south (Gurba, 1998), they are mainly a result of igneous intrusive activity in the area rather than greater burial depths.

4.6. Discussion and conclusions

Although subject to difficulties with sample contamination due to caving, some oxidation of organic material with storage, reliable data on vitrinite reflectance variations with depth can be obtained from non-cored wells, where only cuttings samples are available. Selection of material based on the lithologies indicated by down- hole geophysical logs at the target depth (e.g. hand-picking of vitrinite from intervals where coal is indicated) can help to reduce problems associated with contamination due to caving. Plotting of reflectance histograms can also be used to identify and eliminate

90 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

values due to contaminating organic matter from shallower borehole depths. High- reflecting oxidised vitrinite particles can be identified and avoided in the reflectance measurement process. Samples affected by oxidation that are not detected in this way, however, can be indicated from their anomalous positions on the reflectance-depth profile of the borehole in question.

Reflectance-depth profiles for the Permian Back Creek Group of the Bowen Basin commonly show anomalously low reflectance values due to marine influence, relative to the overlying Kianga Formation and Mesozoic sequence. Similar low reflectance values due to marine influence in the Gunnedah Basin are identified for the Maules Creek and Watermark/Porcupine Formations. Suppressed, low reflectance values are also recorded for the Goonbri Formation; these are attributed to the abundant liptinite maceral content. Suppression of vitrinite reflectance is not recorded where the sequences are locally heat affected due to igneous intrusions. Vitrinite reflectance ‘retardation’ is also a reduction in reflectance, but is produced by a different mechanism from those generally held responsible for suppression. Vitrinite chemistry has been proposed to explain anomalously low, suppressed, reflectance values (e.g. Newman and Newman, 1982; Price and Barker, 1985; Fang and Jianyu, 1992). Most workers agree that variation in the hydrogen content of vitrinite macerals is the main cause of the phenomenon, and that this variation is due to differences in vitrinite precursor material and depositional/early diagenetic effects (e.g. Ellacott et al., 1994). Slightly lower reflectance values for dispersed organic matter vitrinite related to vitrinite in coal seams may also be a result of the chemical composition of the vitrinite. However, lower thermal conductivity and greater heat capacity of coal seams may be an additional reason for slightly higher reflectance values than for the adjacent dispersed organic matter.

Continuity of the reflectance-depth profile above the Kianga Formation suggests that little significant removal of strata took place in this area during the breaks in sedimentation, despite the presence of angular unconformities at the base of the Triassic and the base of the Surat Basin succession. Absolute differences in vitrinite reflectance across an unconformity, however, decrease with time and with increasing burial depth.

91 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

Igneous intrusions have produced local intervals of anomalously high vitrinite reflectance in different parts of the studied sequences. Although burial depth and heat flux both play a part, increased heat flux is clearly more significant in intruded intervals. The extent of the intrusive effects is not always related to the intersected thickness of intrusive material. Two types of igneous effect are proposed in this study, these are simple and complex profiles. A relation between the width of the aureole and intrusion thickness may be recognised in the more simple profiles. As illustrated in Figure 4-9, an aureole width equivalent to twice the intrusion thickness is typically observed above the intrusion body, and a width about the same as the intrusion thickness typically occurs beneath the intrusion. In such cases reflectance suppression in the Permian sequence is still observed (Figure 4-9). The relation between the thickness of the intrusion and the width of heat-affected aureole is not clear for complex profiles, and the suppression phenomenon also is not evident (e.g. Figure 4-6). Intrusive effects are particularly extensive in the Bohena Trough of the Gunnedah Basin, where significant amounts of gas have been identified in Wilga Park area, and in the Bellata Trough, where a geochemical study (Othman et al., 2001) suggests that oil has been generated in response to the intrusion-generated high heat flow.

The reflectance gradient in the Early Permian Back Creek Group, after due allowance for igneous effects, is higher than in overlying Late Permian and Triassic successions. This may be due to differences in the vitrinite composition and the response of the suppressed vitrinite to rank advance, relative to the other vitrinite types. On the bases of data from McIntyre-1 and Goondiwindi-1 the variation in reflectance gradient between non-suppressed and suppressed intervals is lower where the section is influenced by higher heat flow as in Goondiwindi-1 (Figure 4-13). Present-day geothermal gradient is not necessarily related to the reflectance gradient because geothermal gradient depends on the present-day heat flow, while reflectance gradient depends on the highest heat flow that affected the sequence during the maturation process.

Reflectance gradients, especially in the upper part of the sequence, tend to be greater over the basement highs (Gil Gil Ridge; Goondiwindi Thrust), compared to the troughs that occupy the remainder of the basin. Reflectance gradients also increase from east to west. Both features may be due to higher radiogenic heat flow from the basement rocks, which would have been closer to the sediment succession in these areas during

92 Chapter 4 VITRINITE REFLECTANCE PATTERN IN THE STUDY AREA

the basin’s burial history. The presence of high reflectance gradients across the basement ridges, combined with post-depositional uplift on the highs relative to the troughs, has resulted in strata at equivalent stratigraphic levels (e.g. Showgrounds- Moolayember contact) having higher vitrinite reflectance levels on the ridge features, even where the strata are shallower. This is of significance in the generation of hydrocarbons.

Based on the vitrinite reflectance values (Appendix 1) the Jurassic sequences are mainly immature in the Bowen Basin, but in some areas fall partially within the peak mature stage. The Triassic sequences are mature, ranging between early and peak oil generation stages, and are locally postmature where affected by igneous intrusions. The Permian sequences have reached the peak mature stage, where they are not affected by igneous intrusions. The reflectance values for the Back Creek Group, however, appear to be suppressed and therefore indicate anomalously low thermal maturity. In the Gunnedah Basin, the Jurassic sequences studied are immature. The Triassic sequences are mainly mature, and locally postmature where affected by igneous intrusions. Even though the samples studied from the Permian sequences mainly have suppressed reflectance values, the sequences are mainly mature and locally postmature where affected by igneous intrusions. Generally, the Bowen Basin sequences reached higher rank levels compared with the Gunnedah Basin sequences largely due to burial depth. The Gunnedah Basin sequences, however, show higher vitrinite reflectance values, because this part of the study area was more affected by local heat due to igneous intrusions.

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5. Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

5.1. Introduction

Sedimentary rocks that are, may become, or have been able to generate petroleum are commonly called source rocks (Tissot and Welte, 1984). An effective source rock is an organic matter rich rock unit which under the influence of time and temperature has generated and expelled hydrocarbons, while a potential source rock is one that has not yet reached a sufficiently high maturation level for hydrocarbon generation in its natural setting (Rullkötter, 1987). An effective source rock may be active source rock which is currently generating and expelling petroleum, or an inactive source rock that has stopped generating petroleum because of (e.g.) cooling of the active source rock due to uplift and erosion (Hunt, 1996).

Although host lithology may also be involved (e.g. Wilkins and George, 2002) recognition of a petroleum source rock depends on the determination of its proportion of organic matter (organic matter quantity) which is usually expressed as total organic carbon (TOC). It also depends on the type (or quality) of the organic matter (kerogen) preserved in the petroleum source rock, and finally, the evolutionary stage of the kerogen (thermal maturity), or the extent of burial heating of the source rock (Tissot and Welte, 1984; Peters and Cassa, 1994) (Appendix 2).

In this chapter, bulk organic geochemistry data are presented and discussed for the proposed Permian, Triassic and Jurassic source rocks in the southern Bowen and northern Gunnedah Basins and the lower part of the overlying Surat Basin in northern

New South Wales. Total organic carbon, S2 and genetic potential from Rock-Eval pyrolysis, and extractable organic matter (EOM) and hydrocarbon yields from selected rock samples were used to identify the source-richness in terms of quantity and o generation potential. Plots of Tmax ( C) against Hydrogen Index (HI) and Hydrogen Index (HI) against Oxygen Index (OI) from Rock-Eval pyrolysis, in combination with n-alkane and isoprenoid distributions, were used to identify the kerogen type (quality)

94 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

o and depositional environment. Rock-Eval Tmax ( C), and alkane maturity parameters were used to evaluate the source rock maturity stage. In conjunction with the vitrinite reflectance pattern in the study area (see previous chapter) as a maturity tool, additional information on the depositional environment and maturity on the preserved organic matter in these source rocks was obtained from their saturated (terpane and sterane) and aromatic biomarker distributions. These data are discussed in the next chapter.

5.2. Identification

This chapter focuses on source rock identification in the study area based on the parameters and ratios obtained from Rock-Eval pyrolysis, and on the n- and acyclic alkanes from solvent extraction. This section discusses the identification and application of these parameters and ratios to source rock evaluation.

5.2.1. Rock-Eval pyrolysis

5.2.1.1. Concept

Pyrolysis is defined as the heating of organic matter in the absence of oxygen to yield organic compounds (Peters, 1986). Espitalié et al. (1977) published the first article on the development and application of a standard pyrolysis method for source rock characterisation and evaluation (cf. Hunt, 1996). Since 1977 several improved Rock- Eval analysers have been produced with new functions, e.g. Rock-Eval 6, to expand the application of the technique in petroleum geoscience.

In Rock-Eval pyrolysis pulverised rock samples are gradually heated under an inert atmosphere. This heating distills the free organic compounds (bitumen), then cracks pyrolytic products from the insoluble organic matter (kerogen) (Peters, 1986). The method is similar for the various Rock-Eval systems. The technique (Espitalié, 1986) involves programmed-temperature heating (25oC/minute on average) in an inert atmosphere (helium or nitrogen) of a small sample of rock (100 mg). The free hydrocarbons contained in the rock sample are released in the form of gas and oil

95 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

o (determined from peak S1) volatilised at up to 300 C. Afterwards, with continuously increasing temperature, the hydrocarbon compounds (peak S2) and the CO2 (peak S3) that are expelled during the cracking of the unextractable organic matter (kerogen) in the rock sample can be determined between 300o and 600oC. The temperature at the maximum rate of hydrocarbon generation of peak S2 is called Tmax, and is expressed in degrees Celsius. The parameters S1 and S2 are expressed in terms of mg HC/g rock, and

S3 as mg CO2/g rock (Espitalié, 1986). Furthermore, the total organic carbon (TOC) content of the rock sample also can be determined by oxidation in air, in a second oven, of the residual organic carbon after pyrolysis (peak S4) (Lafargue et al., 1998). The TOC is determined by adding the residual organic carbon (CO2 from peak S4) to the pyrolysed organic carbon, which in turn is measured from the hydrocarbon compounds issuing from pyrolysis (S1 and S2) (Espitalié, 1986).

Different parameters can be identified from the Rock-Eval pyrolysis measurements (S1,

S2 and S3). Hydrogen Index (HI) and Oxygen Index (OI) can be determined from S2 and

S3 respectively. The hydrogen index corresponds to the quantity of pyrolysable organic compounds, or hydrocarbons from S2, relative to the total organic carbon (TOC or Corg) in the sample, measured in mg hydrocarbon/g organic carbon (mg HC/g TOC). The oxygen index corresponds to the quantity of carbon dioxide from S3 relative to the TOC

(mg CO2/g TOC) (Peters, 1986). The Production Index (PI) or transformation ratio is another parameter, and can be defined as S1/(S1+S2), i.e. the proportion of free hydrocarbons in relation to the total amount of hydrocarbon compounds obtained by pyrolysis of the sample analysed (Espitalié, 1986). Tissot and Welte (1984) defined in addition the Genetic Potential, which is identified as total amount of petroleum that might be generated from the rock (S1+S2). This evaluation accounts for two aspects, the abundance and the type of the organic matter (Tissot and Welte, 1984).

5.2.1.2. Applications

Rock-Eval pyrolysis can be used to describe the petroleum-generative potential of prospective source rocks by providing information on the amount, type and thermal maturity of the organic matter preserved in the rock samples (Peters, 1986). Various authors during the last two decades have used pyrolysis methods to provide data on the

96 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

potential, maturity and type of organic matter in the source rocks in different sedimentary basins (Lafargue et al., 1998). Peters (1986), and Peters and Cassa (1994) described a guideline for using pyrolysis in evaluating petroleum source rocks for thermally immature source rocks. Critical interpretations, however, should be supported by additional geochemical analysis (Peters et al., 1983).

Total organic carbon (TOC, weight %) describes the quantity of organic carbon in a rock sample and includes both kerogen and bitumen (Peters and Cassa, 1994). Various methods can be used to determine amount of organic matter in a rock sample (Tissot and Welte, 1984). In this study, TOC was obtained from Rock-Eval pyrolysis. However TOC alone is not a clear indicator of petroleum potential. Graphite is essentially 100% carbon but it will not generate petroleum (Peters and Cassa, 1994). Consequently, a rock sample containing abundant graphite and no other OM will show a large TOC but essentially no pyrolysis response (Peters, 1986). TOC fraction and other pyrolysis parameters are used in combination to describe source rock potential (Peters, 1986).

A distinction between various types of sedimentary kerogen is essential for proper source rock appraisal, because different types of organic matter have different hydrocarbon potentials. These differences arise from variations in the chemical structure of the organic matter (Tissot and Welte, 1984). The HI versus OI plot can assist in identifying the three basic kerogen types (i.e. Type I “highly oil prone”, type II “oil prone” and type III “gas prone”) of Tissot et al. (1974). Type IV kerogen, which is dead carbon (generates little or no hydrocarbons during maturation), shows a very low (<50) hydrogen index. The HI versus OI plot generally is a reliable indicator of kerogen type. However, gas-prone coals and coaly rocks can give anomalously high HI values (Peters and Cassa, 1994), and do not generally respond to pyrolysis in the same way as dispersed type III organic matter (Peters, 1986). Typically, coals show HI values below about 300 mg/g TOC, with S2/S3 values greater than 5 (Peters, 1986). The S3 value, in addition, is generally not as reliable as other Rock-Eval parameters, partially because of interference of carbonate minerals or kerogen oxidation resulting from pulverising the sample. The HI versus Tmax plot, proposed by Espitalié et al. (1984), can be substituted for the HI versus OI plot when S3 results are suspected to be unreliable (Peters and Cassa, 1994). The type of hydrocarbon products (gas or oil) that will be generated from source rocks can also be obtained from the HI or the S2/S3 ratio (Peters, 1986). 97 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

Two Rock-Eval pyrolysis indices, PI and Tmax, are used in characterising the maturity of organic matter with respect to thermal evolution. In absence of migration the S1/(S1+S2) ratio is an evaluation of the transformation ratio, and the continuous increase of this ratio as a function of depth makes it a valuable maturation parameter (Tissot and Welte, 1984). The ratio gradually increases with depth for fine-grained rocks, as thermally labile components in the kerogen (S2) are converted to free hydrocarbons (S1) (Peters and Cassa, 1994). A PI value less than 0.1 indicates immature organic matter. The ratio reaches about 0.4 at the bottom of the oil window (beginning of the wet-gas zone) and increases to 1 when the hydrocarbon generative-potential capacity of the kerogen has been exhausted (Peters, 1986). Reservoir rocks show anomalously high PI values compared to adjacent fine-grained rocks (Peters and Cassa, 1994). In addition, for Tmax values between 390o and 435oC, and between 436o and 445oC, the PI values must be o o equal to or less than 0.1 and 0.3 respectively, and for Tmax between 445 and 460 C the PI value must be equal to or less than 0.4. Samples that do not meet these criteria are assumed to be contaminated by drilling additives or migrated oil (Peters and Cassa,

1994), that can also result in an increased S1 peak and consequently a high PI value (Clementz, 1979). However, the criteria must be applied with caution, because the relation between Tmax and PI may vary with kerogen type (Peters and Cassa, 1994). The value of Tmax is also broadly used as an organic matter maturity indicator, because its o value increases progressively with burial depth. Tmax values less than 435 C indicate immature organic matter, and values greater than 470oC represent the wet-gas zone.

However, Tmax values can also vary with different kerogen types.

There are some problems associated with Tmax. Even though its value may increase regularly with depth, variations can result due to unconformities, faults and other factors

(as discussed elsewhere in this section). Tmax values at the threshold of oil generation vary among petroleum source rocks because of differences in organic matter type

(Peters, 1986). Espitalié (1986) indicated that the Tmax range within the oil zone is wider o for Types II and III than for Type I organic matter. Tmax reaches about 442 C at the beginning of the oil formation stage for Type I kerogen and 445oC at the start of the wet-gas zone. A vitrinite reflectance range from 0.7 to 1.3% could be considered to indicate the same maturity interval. Oil formation can occur between 430o and 435oC

Tmax (Rv range from 0.4 to 0.5%) for Type II kerogen, and the transition to the 98 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

o condensate zone corresponds to a Tmax of 455 C (Rv = 1.3%). For Type III kerogen, o o hydrocarbon formation begins at a Tmax between about 430 and 435 C (Rv range 0.5 to o 0.6%), and the transition to the condensate zone occurs at 465 C Tmax which is equal to

Rv 1.3% (Espitalié, 1986).

Accumulation of heavy oil gives rise to inaccurate S2 values. Because the S2 peak may represent compounds coming either from the volatisation of heavy hydrocarbons or from cracking of other hydrocarbon compounds such as asphaltenes or resins, and not be solely due to hydrocarbon compounds derived from cracking of kerogen. In such cases, low Tmax values can be attributed to heavy oil accumulation due to the pyrolysis of resins and asphaltenes (Espitalié, 1986). Snowdon (1995), in his study of a shale sequence, reported that the Tmax might occasionally be suppressed relative to the surrounding rock units, and he attributed this phenomenon to either a bitumen contribution to the S2 peak or to the presence of sulfur-rich (and hence thermally labile) kerogen. Although Veld et al. (1997) found that Tmax can be elevated for perhydrous vitrinite, Norgate et al. (1997), in a study of middle Eocene bituminous coal, reported that perhydrous coals are characterised by depressed Tmax and elevated HI values. However, they concluded that the quantity of bitumen is not responsible for the lowering of Tmax, nor does the organic sulphur content always correlate with the depressed maturity characteristics. Newman et al. (1997) noted that Tmax values for mature coals are lowest in perhydrous samples, which also have relatively high S1+S2 yields. The perhydrous coals exhibit a marked suppression in the decline of S1+S2 yield until medium volatile bituminous rank, relative to less perhydrous coals with the same burial history. This phenomenon is attributed to the generation and expulsion of relatively greater amounts of hydrocarbon in the perhydrous coals (Newman et al.,

1997). On the other hand erroneously high Tmax values or lack of an S2 peak could be due to the presence of oxidised or reworked (more mature) organic matter (Peters, 1986). The mineral matrix may also retard the release of hydrocarbons due to adsorption of pyrolytic organic compounds (Espitalié et al., 1980). This retention will decrease the

S1 and S2 peaks, and increase the Tmax value (Espitalié, 1986). Further, Tmax value for samples with S2 less than 0.2 mg/g rock are often inaccurate and should be rejected (Peters, 1986).

99 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

In addition to the above mentioned problems, various technical (e.g. operating conditions) and non-technical (e.g. organic-lean samples) factors may affect Rock-Eval parameters (e.g. Espitalié et al., 1980; Espitalié, 1986; Peters, 1986; Peters and Cassa, 1994; Snowdon, 1995). Some of these problems, however, have been reduced and determination of other parameters improved in the Rock-Eval 6 technique (used in the present study) compared to previous Rock-Eval systems (Lafargue et al., 1998).

5.2.2. n-Alkanes and acyclic isoprenoids

5.2.2.1. Identification

The n-alkanes (or n-paraffins) have been used as biological markers (see Chapter 6) quite successfully for several decades, as a result of their abundance and ease of detection by gas chromatography (GC) alone (Philp, 1985) or by gas chromatography mass spectrometry (GCMS) on m/z 85 chromatograms. These compounds have a simple straight chain structure (Figure 5-1), with a general CnH2n+2 formula, and they are saturated hydrocarbons. In the gas chromatogram, the relative abundance for the individual compounds up to about n-C35 (Barker, 1985) appears as regularly spaced peaks, with pristane (i-C19) eluting immediately after n-C17 and phytane (i-C20) after the n-C18 compound.

5.2.2.2. Source indicators

5.2.2.2.1. n-Alkanes

Although various factors affect the n-alkane fingerprint, Large and Gize (1996) reported that the distribution is lithofacies controlled and reflects biological input. Hence the most common application of n-alkane fingerprints is to infer the source of the organic material in a sample (Philp, 1985).

Studies of hydrocarbons in algae and bacteria suggest that the C15 to C22 alkanes found in recent marine sediments originate largely from marine phytoplankton and possibly also from photosynthetic bacteria (Ebukanson and Kinghorn, 1986). Brooks et al.

100 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

n-alkane (n-C18)

16 17 18 19

2 4 6 8 10 12 14 1 3 5 7 9 11 13 15

pristane (C19) 2, 6, 10, 14-tetramethylpentadecan

phytane (C20) 2, 6, 10, 14-tetramethylhexadecan

Figure 5-1: Structure of n-alkane and acyclic isoprenoids. Pristane is used as an example of the numbering system.

101 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

(1992) attributed maximum abundance of C16 or C17 on the n-alkane fingerprint to a marine origin for the organic matter, and Tissot et al. (1978) in their study of the Green

River Formation, related a dominance of C17 alkane to the algae source. Eglinton and Hamilton (1967) and Murray and Boreham (1992) suggested that n-alkane compounds having between C12 to C22 carbon atoms in immature samples come from algae or bacteria, while longer chain n-alkanes are usually of terrestrial higher plant origin. Tissot et al. (1978), in addition, attributed the origin of high molecular weight alkanes with odd carbon numbers (C27, C29, C31) to the cuticular waxes of higher plants. High wax, long chain alkane content is thought to indicate a depositional environment where a marked terrigenous component has been incorporated into the sediment. The basis for this inference is the fact that higher plants, which would be expected to make significant contributions to land derived organic matter, biosynthesise n-alkanes of greater chain length (e.g. C31) than marine phytoplankton, with the dominant n-alkane of algae being a C17 compound (Didyk et al., 1978). It is generally believed that these long chain n- alkanes form by defunctionalisation of (loss of functional groups from) the major components of higher-plant cuticular waxes (Tegelaar et al., 1989).

Moldowan et al. (1985) reported that nonmarine oils display a tendency toward n-C31/n-

C19 ratios greater than 0.4. This parameter is selective for nonmarine oils but it is not definitive, since all types of marine and nonmarine oils can be found in the 0-0.4 n-

C31/n-C19 category (Moldowan et al., 1985).

The preference for odd or even carbon numbered paraffins can reflect the environment of source rock deposition (Moldowan et al., 1985). The profile of higher plant origin is characterised by higher concentrations of the odd than the even carbon numbers in the

C22 to C35 range (Meinschein, 1959, 1969; Eglinton, 1962). Powell and McKirdy (1973), in addition, indicated that a pronounced odd predominance in the wax range

(C25 to C35) indicates derivation from immature terrestrial plant material. Burns and Bein (1980) also suggested similar results. Tegelaar et al. (1989) further mentioned that long-chain n-alkanes, with a slight preference for an odd carbon number, are major constituents of high-wax crude oils. Bray and Evans (1961) identified a carbon preference index (CPI) to measure the ratio of odd to even n-alkane carbon molecules over the C24 to C34 range:

102 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

1 C25 + C27 + C29 + C31 + C33 C25 + C27 + C29 + C31 + C33 CPI = + 2 C + C + C + C + C C + C + C + C + C 24 26 28 30 32 26 28 30 32 34

The CPI is the expression of the odd-even predominance in the n-alkane spectrum

(Héroux et al., 1979). Philippi (1965) used a different ratio over the C28 to C30 range, and Vandenbroucke et al. (1976) used the range over the C24 to C30. Scalan and Smith (1970) introduced another coefficient, odd-even predominance (OEP), which is a sort of moving average showing the variation of the odd-even preference with increasing molecular weight. If Ci is the relative weight per cent of an n-alkane containing i carbons per molecule, then:

(-1)i+1 Ci + 6Ci+2 + Ci+4 OEP = 4Ci+1 + 4Ci+3

In practice, the OEP can be adjusted to include any specified range of carbon numbers (Peters and Moldowan, 1993). The CPI and OEP expressions give similar results. Values of more than one indicate a predominance of odd carbon numbered n-alkanes over their even counterparts, and are typical of land plant cuticular waxes. However, the values decrease with increasing organic matter evolution (Vandenbrouche et al., 1976). Burns and Bein (1980), in addition, suggested that the odd-over-even predominance at the higher molecular weight end is indicative of more immature land derived organic matter input. CPI and OEP values less than 1 intimate a predominance of even carbon- numbered homologues and characterise certain, but not all, algae and bacteria (Arouri, 1996). They have often been found in association with reducing, mainly carbonate depositional environments (Scalan and Smith, 1970). Dembicki et al. (1976) also mentioned that even-carbon number n-alkanes are preferentially produced in highly saline, carbonate environments, where aerobic and anaerobic bacteria have subsisted on the remains of blue-green algae.

5.2.2.2.2. Isoprenoids

Pristane (pr) and phytane (ph) are usually the most important acyclic isoprenoid hydrocarbons in terms of concentration (Powell and McKirdy, 1973), and frequently occur in sediments and oils (Chandra et al., 1994). Both are assumed to be diagenetic products of the phytyl side chain of chlorophyll (Brooks et al., 1969), although

103 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

alternative precursors have been suggested (Nissenbaum et al., 1972; Goossens et al., 1984; ten Haven et al., 1987; Li et al., 1995). In certain restricted environments, e.g. hypersaline, phytane can be derived from archaebacteria (Hughes et al., 1995), and very low pr/ph ratios are associated with lithofacies that were deposited in such hypersaline environments (Large and Gize, 1996).

The pristane to phytane ratio (pr/ph) is similar for petroleum that has resulted from material deposited under similar conditions (Alexander et al., 1981), and reflects further the oxicity of the environment of deposition (Powell and McKirdy, 1973; Didyk et al., 1978). Reducing conditions preferentially would lead to the formation of phytane (Ikan et al., 1975), and there is abundant evidence that the phytane carbon skeleton is extensively preserved under conditions where H2S is available (Rowland et al., 1993). Therefore, the pristane to phytane ratios of ancient sediments and oils reflect the palaeoenvironmental conditions of source-rock sedimentation (Didyk et al., 1978), and are considered as potential indicators of the redox conditions during sedimentation and diagenesis (Large and Gize, 1996). Tissot and Welte (1984) recorded that in very reducing environments, reduction of n-fatty acids, alcohols from waxes, and phytanic acid or phytol is prevalent over decarboxylation, resulting in the predominance of even- carbon-numbered n-alkane molecules over odd molecules (CPI<1) and a predominance of phytane over pristane. In less reducing environments, decarboxylation results in a majority of odd n-alkanes (CPI>1) and a predominance of pristane over phytane.

Rashid (1979) reported that the pr/ph ratio increases with increased terrestrial contribution of the organic matter source, and high ratios (>8) were recorded in a suite of vitrinite-rich high volatile bituminous coals (Radke et al., 1980; Casareo et al., 1996). Pr/ph ratios of less than 1 ascribed to anoxic depositional environments, whereas ratios greater than 1 are ascribed to oxic depositional environments (Didyk et al., 1978). Use of the pr/ph ratio as an indicator, however, is not recommended to describe palaeoenvironments at low maturity levels (Volkman and Maxwell, 1986). Within the oil-generative window high pr/ph ratios (>3) indicate terrestrial organic matter input under oxic conditions and low values (<0.6) typify anoxic, commonly hypersaline environments. In the range 0.8 to 2.5 it is not recommended that the ratio be used as an indicator of paleoenvironment without corroborating data (Peters and Moldowan, 1993). Casareo et al. (1996) reported high pr/ph ratio (>8) in suites of vitrinite rich high

104 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

volatile bituminous coals. Such a high ratio also reported previously by Radke et al. (1980) within similar coal rank. Empirical observations, however, have suggested that specific depositional environments and lithologies are associated with specific values for the pr/ph ratio (Hughes et al., 1995). Values less than 1 have been associated with marine carbonates, between 1 and 3 with marine shales, and larger than 3 with non- marine shales and coals (Koopmans et al., 1999). Despite the warning of Peters and Moldowan (1993), such usage is still common practice (Koopmans et al., 1999).

Lijmbach (1975) proved that the pr/n-C17 ratio is less than 0.5 in environments with abundant aerobic bacterial activity and more than 1 in low aerobic bacterial activity environments. Abdullah (1999), on the other hand, documented high pr/n-C17 and ph/n-

C18 values (1.5-1.6 and 1.2-1.6 respectively) in shallow marine shale, and lower values (0.4-1.1 and 0.4-0.9 respectively) in deep marine shale sediments.

5.2.2.3. Maturity indicators

In addition to the nature of the original organic matter, the stage of diagenesis of the system also affects the n-alkane distribution and the ratio of isoprenoid/n-alkane (Alexander et al., 1981). Increasing maturity results in a gradual shift from a heavy end bias of the chromatograms to a light end bias, an almost complete disappearance of odd carbon preference in the molecular range C27-C29, and a decrease of the pr/n-C17 and ph/n-C18 ratios (Leythaeuser and Welte, 1969; Albrecht et al., 1976; Durand and Espitalié, 1976; Radke et al., 1980; Milner, 1982).

Chromatograms demonstrate that increasing coalification is accompanied by decreasing average molecular weight distribution (Allan and Douglas, 1977). As thermal maturity approaches the main phase of oil generation, the CPI ratio modifies towards unity (e.g. Aizenshtat et al., 1998). Kerogen cracking favors the formation of pristane (e.g. Hughes et al., 1995), thus increasing the pr/ph ratio as thermal maturity increases (Brooks et al., 1969; Tissot et al., 1971; Albrecht et al., 1976; Rashid, 1979; ten Haven et al., 1987). The ratio increases mainly as the result of increase in the concentration of pristane rather than decrease in the phytane concentration (Hughes et al., 1995). Tang and Stauffer (1995) suggested that the pr/ph ratio, however, does not change with maturity with low mature oils before peak generation, but that the ratio will increase with

105 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

continuing maturation. The pr/n-C17 and ph/n-C18 ratios decrease with increasing maturity due to the preferential generation of n-alkanes (Horsfield and Rullkötter,

1994). Connan and Cassou (1980) considered, however, the pr/n-C17 ratio to be sensitive to thermal maturity for the same type of organic matter. ten Haven et al.

(1987) reported the development of high ph/n-C18 ratios (>>1) in immature oil and sediment extracts, while during maturation the ratio will eventually reach values below unity (Brooks et al., 1969; Tissot et al., 1971; Albrecht et al., 1976; Rashid, 1979; ten Haven et al., 1987).

5.3. Source rock identification in the study area

To commence source rock evaluation in the study area, a total of 50 samples were chosen for Rock-Eval analysis and 27 samples were selected for solvent extraction for further organic geochemical studies. Those samples expected to contain sufficient TOC, as predicted from lithology and organic petrology, and that showed variation in thermal maturity (based on the vitrinite reflectance measurements; Chapter 4) where selected. These samples were chosen from cored intervals wherever available, otherwise cuttings samples were selected. As indicated in Tables 5-1 and 5-2, a total of 21 proposed source rock samples were chosen from the Bowen Basin for Rock-Eval pyrolysis analysis; 7 samples among these were extracted for further organic geochemical studies. In the Gunnedah Basin, 18 samples were chosen for Rock-Eval analysis and 16 samples for extraction, while in the overlying Surat Basin, 11 samples were analysed by Rock-Eval pyrolysis and 4 samples extracted for further geochemical studies.

5.3.1. Rock-Eval pyrolysis data

5.3.1.1. Permian sequences

5.3.1.1.1. Bowen Basin

5.3.1.1.1.1. Back Creek Group

From the Permian Back Creek Group eight samples were chosen for Rock-Eval pyrolysis (Table 5-1); three samples from these were extracted (Tables 5-2). The Back

106 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

Table 5-1: Rock-Eval pyrolysis and vitrinite reflectance data for potential source rocks in the study area.

Sample Rv,max Tmax S1 S2 S3 TOC No. Basin Well Name Formation Lithology Depth (m) P I S2/S3 H I O I S1+S2 Type (%) (oC) (mg/g) (mg/g) (mg/g) (wt%) 1B/SBoomi-1 Moolayember Formation Core shale 1595.22 0.63 440 0.01 0.81 1.04 0.01 0.78 1.32 61 79 0.82 2 B/S Chester-1 Evergreen Formation Cutting 30% sst, 30% shale, 20% silt, 20% coal 1368.55 0.62 425 0.41 51.79 3.33 0.01 15.55 22.98 225 14 52.2 3 B/S Chester-1 Moolayember Formation Cutting 50% shale, 40% siltstone, 10% sst 1716.02 0.73 439 0.03 1.48 0.79 0.02 1.87 1.87 79 42 1.51

4 B/S Edendale-1 Moolayember Formation Cutting 40% siltstone, 35% coal, 25% sst 1569 0.68 434 0.35 32.33 1.92 0.01 16.84 18.05 179 11 32.68 5 B/S Edendale-1 Back Creek Group Cutting 100% coal 2190 0.64 431 10.80 223.58 3.63 0.05 61.59 81.97 273 4 234.38 6 B/S Gil Gil-1 Walloon Coal Measures Cutting 40% coal, 30% silt, 30% silt, 20% sst, 10% shale 999.74 0.52 425 0.21 38.03 5.22 0.01 7.29 14.99 254 35 38.24 7 B/S Gil Gil-1 Moolayember Formation Core coal 1307.97 1.3 556 0.58 7.87 2.42 0.07 3.25 32.93 24 7 8.45 8 B/S Gil Gil-1 Moolayember Formation Core shale 1381.35 0.73 436 0.01 1.89 0.43 0.01 4.40 1.65 115 26 1.9 9 B/S Goondiwindi-1 Walloon Coal Measures Cutting 90% coal, 5% shale, 5% sst 996.7 0.54 422 3.77 158.33 16.75 0.02 9.45 62.62 253 27 162.1

10 B/S Goondiwindi-1 Walloon Coal Measures Cutting 50% coal, 30% shale, 20% siltstone 1158.24 0.59 423 0.43 44.24 10.52 0.01 4.21 22.50 197 47 44.67 11 B/S Goondiwindi-1 Evergreen Formation Cutting 60% sst, 30% coal,10% siltstone 1264.92 0.56 424 0.64 25.83 10.55 0.02 2.45 22.63 114 47 26.47 12 B/S Goondiwindi-1 Evergreen Formation Cutting 60% shale, 30% siltstone, 10% coal 1356.36 0.72 424 0.13 27.44 8.51 0.00 3.22 18.37 149 46 27.57 13 B/S Goondiwindi-1 Moolayember Formation Core shale 1554.18 0.77 436 0.00 0.56 0.35 0.00 1.60 1.35 41 26 0.56 14 B/S Goondiwindi-1 Back Creek Group Cutting 100% coal 1886.71 0.6 425 5.15 161.49 12.06 0.03 13.39 75.16 215 16 166.64 4.69 15 B/S Goondiwindi-1 Back Creek Group Core shale 2117.44 0.73* 439 0.10 4.59 0.47 0.02 9.77 4.42 104 11 16 B/S McIntyre-1 Walloon Coal Measures Cutting 90% shale, 10% coal 1450.85 0.57 430 2.98 130.40 4.33 0.02 30.12 27.28 478 16 133.38 17 B/S McIntyre-1 Walloon Coal Measures Cutting 40% coal, 30% shale, 20% silt, 10% sst 1548.38 0.59 426 2.11 106.97 7.71 0.02 13.87 36.77 291 21 109.08 18 B/S McIntyre-1 Evergreen Formation Cutting 70% shale, 30% siltstone 1901.95 0.65 436 0.05 5.93 1.50 0.01 3.95 4.71 126 32 5.98 19 B/S McIntyre-1 Moolayember Formation Cutting 90% shale, 10% sst 1965.96 0.67 436 0.02 0.98 0.83 0.02 1.18 1.31 75 63 1 20 B/S McIntyre-1 Moolayember Formation Cutting 80% shale, 20% siltstone 2087.88 0.74 436 0.05 5.30 1.44 0.01 3.68 4.65 114 31 5.35 9.34 21 B/S McIntyre-1 Kianga Formation Cutting 70% coal, 30% ash 2139.7 0.75 431 0.12 9.22 1.87 0.01 4.93 8.68 106 22 22 B/S McIntyre-1 Kianga Formation Cutting 80% shale, 20% siltsone 2200.66 0.72 433 0.04 2.60 1.28 0.02 2.03 3.23 80 40 2.64 23 B/S McIntyre-1 Back Creek Group Cutting 60% shale, 40% siltsone 2286 0.67 438 0.04 3.90 1.45 0.01 2.69 4.09 95 35 3.94 24 B/S McIntyre-1 Back Creek Group Cutting 100% coal 2353.6 0.72 427 1.59 66.43 5.26 0.02 12.63 48.75 136 11 68.02 25 B/S McIntyre-1 Back Creek Group Cutting 70% shale, 30% siltstone 2441.45 0.75 443 0.04 1.23 0.79 0.03 1.56 3.88 32 20 1.27 B/S = Bowen/Surat Basin * Calculated vitrinite reflectance (Rc(rw); see Chapter 6)

107 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

Table 5-1: Rock-Eval pyrolysis and vitrinite reflectance data for potential source rocks in the study area continued.

Sample Rv,max Tmax S1 S2 S3 TOC No. Basin Well Name Formation Lithology Depth (m) P I S2/S3 H I O I S1 + S2 type (%) (oC) (mg/g) (mg/g) (mg/g) (wt%)

26 B/S Mt Pleasant-1 Kianga Formation Cutting 90% coal, 10% shale 1423.42 0.65 427 1.60 83.91 7.36 0.02 11.40 44.18 190 17 85.51 27 B/S Mt Pleasant-1 Kianga Formation Cutting 70% coal, 20% silt, 10% conglomerate 1511.81 0.67 428 1.07 65.44 6.62 0.02 9.89 35.54 184 19 66.51 28 B/S Mt Pleasant-1 Back Creek Group Cutting 70% coal, 20% conglomerate, 10% silt 1566.67 0.62 428 2.74 120.74 8.87 0.02 13.61 53.45 226 17 123.48 29 B/S Mt Pleasant-1 Back Creek Group Cutting 60% sst, 20% shale, 10% coal, 10% silt 1929.38 0.72 434 0.75 39.47 4.69 0.02 8.42 25.66 154 18 40.22 30 B/S Werrina-2 Walloon Coal Measures Cutting 90% coal, 10% shale 1237.49 0.56 427 1.30 94.22 13.30 0.01 7.08 44.05 214 30 95.52 31 B/S Werrina-2 Evergreen Formation Cutting 65% shale, 30% sst, 5% coal 1469.14 0.69 434 0.02 3.29 2.11 0.01 1.56 3.69 89 57 3.31 32 B/S Werrina-2 Moolayember Formation Cutting 70% shale, 15% siltstone, 15% sst 1539.24 0.72 434 0.01 1.94 1.56 0.01 1.24 2.52 77 62 1.95 33 G/S Bellata-1 Purlawaugh Formation Core siltstone 613.6 0.55 433 0.01 0.93 0.36 0.01 2.58 1.19 78 30 0.94 34 G/S Bellata-1 Napperby Formation Core claystone 642.4 0.6 428 0.44 96.87 9.12 0.00 10.62 56.70 171 16 97.31 35 G/S Bellata-1 Napperby Formation Core siltstone 805.18 0.98 435 0.01 0.92 1.24 0.01 0.74 1.49 62 83 0.93 36 G/S Bellata-1 Napperby Formation Core siltstone 829.6 2.21 348 0.30 5.13 0.46 0.06 11.15 1.89 271 24 5.43 37 G/S Bellata-1 Maules Creek Formation Core siltstone 929.6 0.67* 430 0.14 14.64 1.32 0.01 11.09 9.42 155 14 14.78 38 G/S Bellata-1 Maules Creek Formation Core coal 939.93 0.57 427 1.67 96.06 0.70 0.02 137.23 52.36 183 1 97.73 39 G/S Bellata-1 Goonbri Formation Core siltstone 1018.1 0.71* 428 0.55 26.76 1.02 0.02 26.24 10.76 249 9 27.31 40 G/S Bellata-1 Goonbri Formation Core coal 1054.74 0.66 427 2.91 175.00 8.79 0.02 19.91 82.75 211 11 177.91 41 G/S Bohena-1 Black Jack Group Core shale 660.85 0.62 433 0.05 5.86 0.52 0.01 11.27 5.12 114 10 5.91 42 G/S Bohena-1 Maules Creek Formation Core shale 855.73 1.32 432 0.72 18.72 2.22 0.04 8.43 28.38 66 8 19.44 43 G/S Bohena-1 Goonbri Formation Core shale 966.83 0.62 439 0.07 1.36 0.70 0.05 1.94 2.31 59 30 1.43 44 G/S Coonarah-1A Napperby Formation Core shale 421.96 0.52 443 0.09 6.10 1.15 0.01 5.30 3.24 188 35 6.19 45 G/S Coonarah-1A Napperby Formation Core shale 453.35 0.81 446 0.03 1.92 0.30 0.02 6.40 2.13 90 14 1.95 46 G/S Coonarah-1A Black Jack Group Core coal 522.6 1.8 538 0.64 22.04 1.83 0.03 12.04 88.30 25 2 22.68 47 G/S Coonarah-1A Black Jack Group Core coal 572.09 1.99 525 0.38 27.59 2.33 0.01 11.84 89.20 31 3 27.97 48 G/S Coonarah-1A Black Jack Group Core shale 604.74 1.79 nd 0.04 0.13 0.24 0.24 0.54 2.19 6 11 0.17 49 G/S Coonarah-1A Watermark/Porcupine Formation Core shale 613.24 1.62 nd 0.10 0.19 0.67 0.34 0.28 2.93 6 23 0.29 50 G/S Coonarah-1A Watermark/Porcupine Formation Core siltstone 635.35 1.8 553 0.05 0.21 0.12 0.19 1.75 1.39 15 9 0.26 B/S = Bowen/Surat Basin G/S = Gunnedah/Surat Basin nd = not determined * Calculated vitrinite reflectance (Rc(rw); see Chapter 6)

108 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

Table 5-2: Bulk chemical composition for potential source rocks in the study area. Sat Arom HC EOM HC EOM Sample Rv,max TOC Sat (mg/g Arom (mg/g (mg/g HC (mg/g EOM Pr/ Ph/ (mg/g (mg/g S1

No. Basin Well Name Formation Age type Lithology Depth (m) (%) (wt%) (ppm) TOC) (ppm) TOC) TOC) (ppm) TOC) (ppm) Pr/Ph n-C17 n-C18 CPI* rock) rock) (mg/g) 5 B/S Edendale-1 Back Creek Group Permian cutting 100% coal 2190 0.64 81.97 2763.57 3.37 10560.77 12.88 16.26 13324.34 70.68 57936.19 6.10 2.33 0.22 1.25 2.05 57.94 10.8 7 B/S Gil Gil-1 Moolayember Formation Triassic core coal 1307.97 1.30 32.93 160.35 0.49 994.18 3.02 3.51 1154.54 14.09 4639.53 3.54 0.40 0.09 1.32 1.15 4.64 0.58 9 B/S Goondiwindi-1 Walloon Coal Measures Jurassic cutting 90% coal, 5%shale, 5%sst. 996.7 0.54 62.62 2431.20 3.88 7050.49 11.26 15.14 9481.69 72.99 45706.63 3.75 3.15 0.26 2.67 0.52 45.71 3.77 11 B/S Goondiwindi-1 Evergreen Formation Jurassic cutting 60% sst, 30% coal,10% silt 1264.92 0.56 22.63 1045.11 4.62 1741.85 7.70 12.32 2786.97 89.67 20292.60 1.66 1.34 0.72 1.79 0.17 20.29 0.64 12 B/S Goondiwindi-1 Evergreen Formation Jurassic cutting 60% shale, 30% silt, 10% coal 1356.36 0.72 18.37 545.67 2.97 440.74 2.40 5.37 986.41 43.99 8080.17 2.51 1.61 0.49 2.21 0.88 8.08 0.13 13 B/S Goondiwindi-1 Moolayember Formation Triassic core shale 1554.18 0.77 1.35 24.01 1.78 26.41 1.96 3.73 50.42 22.41 302.51 2.80 1.00 0.14 2.11 0.05 0.30 0 14 B/S Goondiwindi-1 Back Creek Group Permian cutting 100% coal 1886.71 0.60 75.16 1220.82 1.62 4708.89 6.27 7.89 5929.72 64.97 48832.96 4.87 2.69 0.31 2.11 1.15 48.83 5.15 15 B/S Goondiwindi-1 Back Creek Group Permian core shale 2117.44 0.73 4.42 56.94 1.29 261.94 5.93 7.21 318.88 45.61 2015.80 2.44 2.04 0.29 2.54 0.32 2.02 0.1 22 B/S McIntyre-1 Kianga Formation Permian cutting 80% shale, 20% siltsone 2200.66 0.72 3.23 144.96 4.49 115.97 3.59 8.08 260.92 49.82 1609.03 1.51 1.43 0.37 2.00 0.25 1.61 0.04 26 B/S Mt Pleasant-1 Kianga Formation Permian cutting 90% coal, 10% shale 1423.42 0.65 44.18 578.47 1.31 3512.12 7.95 9.26 4090.59 35.07 15494.65 2.91 1.96 0.33 1.76 1.47 15.49 1.6 30 B/S Werrina-2 Walloon Coal Measures Jurassic cutting 90% coal, 10% shale 1237.49 0.56 44.05 2107.16 4.78 3389.78 7.70 12.48 5496.94 49.50 21804.55 4.96 2.05 0.20 1.85 0.93 21.80 1.3 34 G/S Bellata-1 Napperby Fm.Formation Triassic core claystone 642.4 0.60 56.70 576.19 1.02 1971.19 3.48 4.49 2547.38 32.41 18377.55 4.51 2.07 0.29 2.23 1.09 18.38 0.44 51 G/S Bellata-1 Napperby Formation Triassic core claystone 665.77 nd nd nd nd nd nd nd nd nd nd 5.68 1.15 0.15 2.45 nd nd nd 35 G/S Bellata-1 Napperby Formation Triassic core siltstone 805.18 0.98 1.49 54.86 3.68 35.50 2.38 6.06 90.37 29.89 445.37 1.04 0.61 0.34 1.40 0.09 0.45 0.01 36 G/S Bellata-1 Napperby Formation Triassic core siltstone 829.6 2.21 1.89 20.08 1.06 48.44 2.56 3.63 68.52 4.06 76.79 1.37 0.55 1.53 1.05 0.12 0.08 0.3 37 G/S Bellata-1 Maules Creek Formation Permian core siltstone 929.6 0.67* 9.42 527.28 5.60 895.15 9.50 15.10 1422.44 39.83 3752.29 4.17 1.03 0.14 2.46 0.40 3.75 0.14 38 G/S Bellata-1 Maules Creek Formation Permian core coal 939.93 0.57 52.36 816.59 1.56 3992.24 7.62 9.18 4808.83 34.48 18055.80 5.62 4.51 0.66 1.87 1.25 18.06 1.67 39 G/S Bellata-1 Goonbri Formation Permian core siltstone 1018.1 0.71* 10.76 708.29 6.58 1263.81 11.75 18.33 1972.10 45.95 4944.15 1.87 3.64 1.85 2.55 0.58 4.94 0.55 40 G/S Bellata-1 Goonbri Formation Permian core coal 1054.74 0.66 82.75 2480.42 3.00 6135.78 7.41 10.41 8616.20 48.12 39817.30 8.33 12.26 0.81 1.80 0.85 39.82 2.91 41 G/S Bohena-1 Black Jack Group Permian core shale 660.85 0.62 5.12 91.42 1.79 548.50 10.71 12.50 639.92 54.46 2788.20 2.11 1.24 0.22 1.74 0.40 2.79 0.05 44 G/S Coonarah-1A Napperby Formation Triassic core shale 421.96 0.52 3.24 171.17 5.28 256.75 7.92 13.21 427.92 57.27 1855.60 2.94 0.98 0.28 1.70 0.431.860.09 45 G/S Coonarah-1A Napperby Formation Triassic core shale 453.35 0.81 2.13 68.75 3.23 184.36 8.66 11.88 253.11 24.79 528.09 1.20 0.23 0.10 1.09 0.25 0.53 0.03 46 G/S Coonarah-1A Black Jack Group Permian core coal 522.6 1.80 88.30 135.10 0.15 2238.86 2.54 2.69 2373.97 5.27 4651.43 2.05 0.25 0.11 1.17 2.37 4.65 0.64 47 G/S Coonarah-1A Black Jack Group Permian core coal 572.09 1.99 89.20 108.64 0.12 1985.15 2.23 2.35 2093.79 4.61 4108.56 0.37 0.16 0.26 1.21 2.09 4.11 0.38 48 G/S Coonarah-1A Black Jack Group Permian core shale 604.74 1.79 2.19 16.31 0.74 61.17 2.79 3.54 77.48 21.23 464.85 0.42 0.24 0.38 1.14 0.08 0.46 0.04 49 G/S Coonarah-1A Watermark/Porcupine Formation Permian core shale 613.24 1.62 2.93 6.12 0.21 14.28 0.49 0.70 20.40 5.99 175.40 0.17 0.22 0.41 1.13 0.02 0.18 0.1 50 G/S Coonarah-1A Watermark/Porcupine Formation Permian core siltstone 635.35 1.80 1.39 12.27 0.88 69.55 5.00 5.89 81.82 26.05 362.07 0.12 0.11 0.21 1.15 0.08 0.36 0.05 EOM (ppm) = (wt EOM mg/wt sample extracted g) X 1000 EOM (mg/g TOC) = [(wt EOM mg/sample extracted g) X 100]/TOC; or EOM (mg/g TOC) = EOM ppm/(10 X TOC) HC (ppm) = [(wt sat mg + wt arom mg) X 1000 X wt EOM mg]/(wt EOM used mg X sample extracted g) HC mg/g TOC = HC ppm/(10 X TOC) B/S = Bowen/Surat Basin G/S = Gunnedah/Surat Basin nd = not determined *Calculated vitrinite reflectance (Rc(rw); see Chapter 6)

109 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

Creek Group, which was examined from four wells (Edendale-1, Goondiwindi-1, McIntyre-1 and Mt Pleasant-1), has a wide range of total organic carbon contents (3.88% to 81.97%; Table 5-1) and, as expected, the highest values were obtained from the coals. In terms of source rocks quality, the Back Creek Group has a very good to excellent TOC content, but poor (with some potential for gas) to good hydrocarbon genetic potential (S1+S2 = 1.27 to 234.38 kg hydrocarbon/tonne rock; Table 5-1; cf. Tissot and Welte, 1984) and fair to excellent hydrocarbon (saturated and aromatics) yields (600>HC ppm>2400, Table 5-2; cf. Peters and Cassa, 1994). The potential of hydrocarbon generation in a source rock also can be estimated from TOC (%) versus S2 (mg HC/g rock), and from extractable organic matter EOM (ppm) versus TOC (%) crossplots. The Back Creek Group has poor to excellent source rock potential based on these crossplots (Figures 5-2a and 5-2b). Another source rock richness rating is obtained from a TOC (%) versus total hydrocarbon content (ppm) crossplot (Figure 5-3), based on which the sequence seems to be a fair oil source at the best.

Organic matter types in the Back Creek Group are in a good agreement with the source potential figures. Although sample No. 25 contains Type IV kerogen (HI<50; Table 5-1; cf. Peters and Cassa, 1994), which is consistent with its low potentiality, other samples mainly contain Type II/III kerogen (Figure 5-4) which has ability to generate liquid as well as gaseous hydrocarbons at peak maturity (Peters and Cassa, 1994). Based on the o o Tmax values (425 C to 443 C; Figure 5-4 and Table 5-1), the sequence is within the immature to early mature stage. However, these Tmax values are suppressed due to the marine influence on the Back Creek Group sediments, and the actual values might be higher. In addition, the coals (e.g. samples No. 14 and 24) show even lower Tmax values compared to the adjacent Back Creek Group non-coal samples (Table 5-1), which might be attributed to relatively high free hydrocarbon content (Table 5-1).

5.3.1.1.1.2. Kianga Formation

Four samples from the Late Permian Kianga Formation were selected from the McIntyre-1 and Mt Pleasant-1 wells for Rock-Eval pyrolysis studies (Table 5-1), and from these, two samples were extracted (Tables 5-2). The Kianga Formation studied has 3.23% to 44.18% TOC content, and is classified accordingly as a very good to excellent source rock. The samples studied have moderate to good hydrocarbon genetic potential

110 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

(A) 1000 Poor Fair Good Very Excellent (B) Good 100 5 Excellent 5 (coals) 14 14 Gas source 28 Very 100 good 24 Good 29 10 Fair

n V ery Good 15 o Poor rb 10 a n o C b 15 Good ic r n a 23 a C rg ic Fair

TOC (%) n f O a o rg 2 1 % O 0 f 1 o S rock) HC/g (mg 25 Poor source n % 1 e 0 m 2 u n it e B m tu Poor i Very poor source B Oil staining or contamination 0.1 0.1 0.1 1 10 100 10 100 1000 10 000 100 000 TOC (%) EOM (ppm)

Figure 5-2: Source potential rating based on (A) S -TOC and (B) TOC-EOM 2 plots for the Permian Back Creek Group, Bowen Basin.

1000 I 900

750 900 % II 20 000 .5 600 = 0 v 5 R 450 10 000 800 14 300 5 Contaminated 28 14 or stained il 150 24 29 o Hydrogen Index (mg HC/gTOC) 700 15 23 d I 25 III o il o o 0 g 050100 y d 150 r o il e o o il Oxygen Index (mg CO2 /g TOC) 1000 V G ir o 600 a e F m o s d 15 n a s. 500 a G

100 400 Gas source Hydrocarbons (ppm) Hydrocarbons

Adequate(?)gas % 300 II 5 5 Hydrogen Index (mg HC/g TOC) HC/g (mg Index Hydrogen .3 1 = 28 v R 10 200 14 0.1 1 10 100 24 29 TOC (%) 15 100 23 Figure 5-3: Source-rock richness III 25 plot for the Permian Back Creek 0 Group, Bowen Basin. 380 430 480 530 580 o Tmax (C) Figure 5-4: Kerogen type and estimation of maturity for the Permian Back Creek Group, Bowen Basin.

111 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

(2.64 to 85.51 kg hydrocarbon/tonne rock; Table 5-1), and fair to excellent source rock potential on the basis of Figures 5-5a and 5-5b. It has poor to excellent hydrocarbon yield (Table 5-2), with some liquid hydrocarbon generation ability (Figure 5-6).

Based on the Tmax versus HI crossplot (Figure 5-7), the organic matter in the Kianga Formation is a mixture of kerogen Types II/III and Type III (gas is the main expelled product at peak maturity level for Type III kerogen; Peters and Cassa, 1994). The o organic matter in the sequence is mainly immature to marginally mature (Tmax = 427 to 433oC; Table 5-1).

5.3.1.1.2. Gunnedah Basin

5.3.1.1.2.1. Goonbri Formation

A carbonaceous siltstone and a coal sample were studied from the Early Permian Goonbri Formation in the Bellata-1 well, and a shale sample from the Bohena-1 well. The TOC content in the formation shows significant variation, and ranges between ‘very good to excellent’ (TOC = 2.31% to 82.75%; Table 5-1). The carbonaceous siltstone (#39) and the coal (#40) samples have a good hydrocarbon genetic potential

(S1+S2>6 kg hydrocarbon/tonne rock; Table 5-1; cf. Tissot and Welte, 1984), with excellent hydrocarbon yields (>2400 ppm; Table 5-2), and excellent source potential according to Figures 5-8a and 5-8b. The shale sample (#43) has poor hydrocarbon genetic (<2 kg hydrocarbon/tonne rock; Table 5-1) and source potential on the basis of

S2 (Figure 5-8a). This outcome is consistent with the low HI (59 mg HC/g TOC; Table 5-1) value of the sample. Based on the Bellata-1 samples, the Goonbri Formation could be a fair oil source as illustrated on the TOC% versus hydrocarbon (ppm) cross plot (Figure 5-9). This result is consistent with the relatively high HI for the Bellata-1 well samples (#39 and #40; Table 5-1).

Kerogen types in the Goonbri Formation range from Type II (oil is the main expelled product at peak maturity; Peters and Cassa, 1994) to Type III (Figure 5-10). The o Goonbri Formation is in the early mature stage in the Bohena-1 well (Tmax = 439 C), but o o immature in Bellata-1 (Tmax = 427 and 428 C; Table 5-1). However, the Tmax values in

112 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

(A) 1000 Poor Fair Good Very Excellent (B) Good 100 Excellent (coals)

Gas source Very 26 26 Excellent 100 good 27 Good

10 Fair

V ery n Good 22 o 10 Poor rb a n 21 C o Good b ic r n a a C g Fair

TOC (%) r ic

2 O n f a 22 o rg S S rock) HC/g (mg O 1 % f 0 o 1 Poor source n % 1 e 0 m 2 u n it e B m

Poor u it Very poor source B Oil staining or contamination 0.1 0.1 0.1 1 10 100 10 100 1000 10 000 100 000 TOC (%) EOM (ppm)

Figure 5-5: Source potential rating based on (A) S -TOC and (B) TOC-EOM 2 plots for the Late Permian Kianga Formation, Bowen Basin.

1000 I 900

750 900 % II 5 600 0. 10 000 v = R 450 800 Contaminated 26 300 or stained 26 il o

27 d 150 o Hydrogen Index (mgHC/g TOC) 21 il 700 o o I 22 g III ry d il 0 e o o l 1000 V o i 050100150 G ir o Oxygen Index (mg CO /g TOC) a e 2 F m o 600 s d n .a 22 s a 500 G

100 Gas source 400 (ppm) Hydrocarbons Adequate(?)gas % 300 II 5 Hydrogen Index (mg HC/g TOC) Index Hydrogen (mg HC/g .3 1 v = 10 R 200 26 0.1 1 10 100 27 TOC (%)

21 100 III 22 Figure 5-6: Source-rock richness 0 plot for the Late Permian Kianga 380 430 480 530 580 Formation, Bowen Basin. T (C)o max Figure 5-7: Kerogen type and estimation of maturity for the Late Permian Kianga Formation, Bowen Basin.

113 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

(A) 1000 Poor Fair Good Very Excellent (B) Good 100 40 Excellent (coals) 40 Gas source Very 100 good Good 39 10 39 Fair n V ery Good o 10 Poor rb a n o C b Good ic r n a a C rg c Fair i TOC (%) O n 2 f a o rg

S (mg HC/g rock) HC/g (mg S 1 % 0 f O 43 1 o Poor source n % 1 e 0 m 2 u n it e B m u Poor it Very poor source B Oil staining or contamination 0.1 0.1 0.1 1 10 100 10 100 1000 10 000 100 000 TOC (%) EOM (ppm)

Figure 5-8: Source potential rating based on (A) S -TOC and (B) TOC-EOM 2 plots for the Early Permian Goonbri Formation, Gunnedah Basin.

1000 I 900

750 900 % II 5 600 0. 10 000 v = 40 R 450 800 Contaminated or stained 300 il 39 o 40 d 150 o 39 Hydrogen Index (mg HC/g TOC) o il OC) 700 43 o I g III ry d il 0 e o o l 1000 V o i 050100150 G ir o a e Oxygen Index (mg CO2 /g TOC) C/g T F m o 600 s d n .a

H mg s a ( 500 G

ndex 100 Gas source 400 (ppm) Hydrocarbons ogen I Adequate(?)gas % 300 II 5 Hydr .3 1 39 = v 10 R 200 40 0.1 1 10 100 TOC (%)

100 43 Figure 5-9: Source-rock richness III plot for the Eearly Permian Goonbri 0 Formation, Gunnedah Basin. 380 430 480 530 580 T (C)o max Figure 5-10: Kerogen type and estimation of maturity for the Early Permian Goonbri Formation, Gunnedah Basin.

114 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

the Goonbri Formation might be suppressed, for the sequence is liptinite rich and possibly contains perhydrous organic matter (Chapter 4).

5.3.1.1.2.2. Maules Creek Formation

Based on three analysed samples from the Bellata-1 and Bohena-1 wells, the Early Permian Maules Creek Formation shows an ‘excellent’ TOC content (9.42% to 52.36%; Table 5-1) and good hydrocarbon genetic potential (Table 5-1). Samples No. 37 and 38 show, respectively, very good and excellent hydrocarbon yield ability (Table 5-2) and similar source potentiality (Figures 5-11a and 5-11b). The sequence has the capacity to be a fair oil source (Figure 5-12). Sample No. 42, however, shows a lower source potential (Figure 5-11a) than the other two samples with respect to the TOC content. This is attributed to the organic matter quality in this particular sample, which has a relatively low HI (66 mg HC/g TOC; Table 5-1).

The kerogen type in the Maules Creek Formation is a mixture of Types II/III and III o o organic matter (Figure 5-13). Based on the low Tmax values (427 to 432 C; Table 5-1) the formation is mainly immature to marginally mature. The Tmax value, however, probably suppressed similar to vitrinite reflectance values due to marine influence on the Maules Creek Formation sequence (Chapter 4).

5.3.1.1.2.3. Watermark/Porcupine Formation

A siltstone and a shale sample were analysed from the Permian Watermark/Porcupine o Formation in the Coonarah-1A well. The formation is postmature (Tmax > 470 C; Rv,max > 1.35%; Table 5-1) due to igneous intrusion and local heat effects. The high level of thermal maturity has significantly decreased the formation’s oil-proneness (Tables 5-1 and 5-2); it is expected that the original capacity to generate oil in such a sequence would have been higher, but previous generation and expulsion process have reduced the residual hydrocarbon potentiality. The total organic carbon content would also be reduced due to the high maturity level (Daly and Edman, 1987). However, in terms of TOC content, the Watermark/Porcupine Formation based on these two samples ranges from good to very good (1.39% and 2.93%; Table 5-1). The formation, as expected, shows poor hydrocarbon yields (81.82 and 20.4 ppm; Table 5-2), and poor hydrocarbon

115 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

(A) 1000 Poor Fair Good Very Excellent (B) Good 100 Excellent (coals) 38 Gas source Very 100 38 Excellent good Good

10 37 42 Fair 37 n V ery Good o 10 Poor rb a n o C b Good ic r n a a C rg ic Fair TOC (%) O n 2 f a o rg O S S rock) HC/g (mg 1 % 0 f 1 o Poor source n % 1 e 0 m 2 u n it e B m tu Poor i Very poor source B Oil staining or contamination 0.1 0.1 0.1 1 10 100 10 100 1000 10 000 100 000 TOC (%) EOM (ppm)

Figure 5-11: Source potential rating based on (A) S -TOC and (B) TOC-EOM 2 plots for the Early Permian Maules Creek Formation, Gunnedah Basin.

1000 I 900

750 900 % II .5 600 0 10 000 v = R 450 800 Contaminated 38 300 or stained il 83 o d 150 37 o TOC) HC/g (mg Index Hydrogen o il 700 g o 37 I 42 III ry d il 0 e o o V o il 050100150 1000 G ir o Oxygen Index (mg CO /g TOC) a e 2 F m o 600 s d n a s. a 500 G

100 Gas source 400 (ppm) Hydrocarbons Adequate(?)gas % 300 II 5 Hydrogen Index (mg HC/g TOC) HC/g (mg Index Hydrogen .3 1 v = 10 R 200 0.1 1 10 100 38 TOC (%) 37 100 III 42 Figure 5-12: Source-rock richness 0 plot for the Early Permian Maules 380 430 480 530 580 Creek Formation, Gunnedah Basin. T (C)o max Figure 5-13: Kerogen type and estimation of maturity for the Early Permian Maules Creek Formation, Gunnedah Basin.

116 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

genetic (0.29 and 0.26 kg HC/ton rock) and source potential (Figures 5-14a and 5-14b; Table 5-1). Based on the hydrocarbon versus TOC diagram, the formation might still have some potential for generating gaseous hydrocarbons (Figure 5-15). This, however, reflects the formation’s residual potentiality, after the intrusion process.

The low HI values in the samples (15 and 6 mg/g TOC; Table 5-1) are due to the high maturity level. However, this HI value (<50 mg/g TOC) is identical to that of Type IV kerogen (cf. Peters and Cassa, 1994; Figure 5-16). Although the Tmax was not determined for the shale sample (#49; Table 5-1), the Tmax value is regarded as being inaccurate when the S2 value is lower than 0.2 (Peters, 1986).

5.3.1.1.2.4. Black Jack Group

Four samples were analysed from the Late Permian Black Jack Group, three from Coonarah-1A and one from the Bohena-1 well. All the Coonarah-1A samples are postmature, while the Bohena-1 sample (#41) is marginally mature (Table 5-1). The Black Jack Group shows significant variation in TOC content (2.19% to 89.2%; Table 5-1) and ranges between very good to excellent. Sample No. 41 has a moderate hydrocarbon genetic potential (Table 5-1), and shows good (Figure 5-17a) and very good (Figure 5-17b), source potential with good hydrocarbon yield ability (Table 5-2). Based on this sample, at least a part of the sequence has a fair ability to generate oil (Figure 5-18). The residual low potentiality for hydrocarbon generation in the igneous affected postmature Coonarah-1A samples (Figure 5-17b and 5-18) is due to the high maturity level of the sequence. The high S2 content for samples No. 46 and 47 (Figures 5-17a; Table 5-1) and, accordingly, the high hydrocarbon genetic potential for these two postmature samples (Rv,max = 1.8 and 1.99% respectively; Table 5-1), probably is inaccurate (cf. Figure 5-18).

Based on sample No. 41, the Back Creek Group in the Bohena-1 well contains marginally mature Type II/III kerogen (Figure 5-19). The residual low HI values of the three postmature samples (Table 5-1) are attributed to the high level of thermal maturity. The Tmax value for sample No. 48 was not determined. However, the S2 quantity for this sample is less than 0.2 mg HC/g rock.

117 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

(A) 1000 Poor Fair Good Very Excellent (B) Good 100 Excellent (coals) Gas source Very 100 Excellent good Good

10 Fair

n V ery Good o 10 Poor rb a n 49 C o Good b ic r n a a C 50 g

Fair r ic TOC (%) O n 2 f a o rg O S (mg HC/g rock) HC/g (mg S 1 % 0 f 1 o Poor source n % 1 e 0 m 2 u n it e B m u Poor it Very poor source B Oil staining or 50 49 contamination 0.1 0.1 0.1 1 10 100 10 100 1000 10 000 100 000 TOC (%) EOM (ppm)

Figure 5-14: Source potential rating based on (A) S -TOC and (B) TOC-EOM 2 plots for the Permian Watermark/Porcupine Formation, Gunnedah Basin.

I 900

10 000 Contaminated C) 750 or stained O il o

T d

o il o o g ry d il II e o o C/g 1000 V o il 600 G ir o a e H F m o s d n .a mg s a 450 G

100 49

ndex ( Gas source

Hydrocarbons (ppm) 300 Adequate(?)gas 50 ogen I ydr 150 10 H 0.1 1 10 100 TOC (%) 50 III 49 0 Figure 5-15: Source-rock richness 0 50 100 150 plot for the Permian Watermark/

Oxygen Index (mg CO2 /g TOC) Porcupine Formation, Gunnedah Basin.

Figure 5-16: Kerogen type for the Permian Watermark/Porcupine Formation, Gunnedah Basin.

118 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

(A) 1000 Poor Fair Good Very Excellent (B) Good 100 47 46 Excellent (coals) Gas source Very 100 Excellent good Good 47 10 46 Fair

41 n V ery Good o 10 Poor rb a n 41 o C b Good ic r 48 n a a C rg c

Fair i TOC (%) O n 2 f a o rg O S S rock) HC/g (mg 1 % f 0 o 1 Poor source n % 1 e 0 m 2 u n it e B m tu Poor i Very poor source B Oil staining or contamination 48 0.1 0.1 0.1 1 10 100 10 100 1000 10 000 100 000 TOC (%) EOM (ppm)

Figure 5-17: Source potential rating based on (A) S -TOC and (B) TOC-EOM 2 plots for the Late Permian Black Jack Group, Gunnedah Basin.

1000 I 900

750 900 % II .5 600 0 10 000 v = R 450 800 Contaminated 300 or stained il o 46

d 150 41 Hydrogen Index (mg HC/g TOC) o il 700 o o 47 I 46 g 47 III y d il 48 r o o 0 e o il 050100150 1000 V ir o G a Oxygen Index (mg CO /g TOC) F e 2 m o 600 41 s d n a s. a 500 G 100 48 Gas source 400 (ppm) Hydrocarbons Adequate(?)gas % 300 II 5 Hydrogen Index (mg HC/g HC/g (mg TOC) Index Hydrogen .3 1 = v 10 R 200 0.1 1 10 100 TOC (%) 41 100 III 47 46 Figure 5-18: Source-rock richness 0 plot for the Late Permian Black 380 430 480 530 580 Jack Group, Gunnedah Basin. o T (C) max Figure 5-19: Kerogen type and estimation of maturity for the Late Permian Black Jack Group, Gunnedah Basin.

119 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

5.3.1.2. Triassic sequences

5.3.1.2.1. Bowen Basin

5.3.1.2.1.1. Moolayember Formation

Nine samples were selected from the Middle Triassic Moolayember Formation for the Rock-Eval pyrolysis study. Among these, two samples were extracted for further organic geochemical analysis. The Moolayember Formation samples were chosen from seven boreholes (Boomi-1, Chester-1, Edendale-1, Gil Gil-1, Goondiwindi-1, McIntyre- 1 and Werrina-2). The source potential of the formation ranges from good to excellent based on the total organic carbon content (1.31% to 32.93%; Table 5-1), but the hydrocarbon genetic potential ranges from poor to good (Table 5-1) and consequently shows poor to good hydrocarbon yield ability (Table 5-2). The majority of the analysed samples show that the formation has a poor source potential based on the S2 values (Figure 5-20a). From the two samples plotted on the TOC versus hydrocarbon diagram (Figure 5-21), the formation is considered to be mainly a gas source.

As illustrated in Figure 5-22, the Moolayember Formation contains mainly Type III kerogen at an early mature stage, except for sample No. 7 which is postmature (Figure 5-22; Table 5-1) due to local heat effects and igneous intrusion.

The residual oil potentiality for sample No. 7 is expected to be significantly reduced because of its maturity level. This prediction is consistent with the sample’s location within a gas source field based on the TOC% versus hydrocarbon (ppm) diagram (Figure 5-21). Even though the Moolayember Formation mainly has poor source potential (Figure 5-20a), this high mature sample locates within an excellent source potential field on the EOM (ppm) versus TOC% cross plot (Figure 5-20b). The high residual potentiality illustrated in Figure 5-20b is due to a relatively high EOM value. The high EOM in sample No. 7 is attributed to a high NSO compound content (cf. Figures 5-20b and 5-21), which probably resulted as a residual from the generated hydrocarbon’s primary migration and expulsion process (cf. Tissot and Welte, 1984). Accordingly, sample No. 7’s location within excellent source potential field in Figure 5- 20b is considered spurious and to have resulted from residual NSO compounds in the free extracted bitumen.

120 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

(A) 1000 Poor Fair Good Very Excellent (B) Good 100 Excellent (coals) Gas source Very 7 100 Excellent good Good 4 10 Fair

n V ery Good o 10 Poor b 7 n 20 bo Good ic Car n ar a C rg c

Fair i TOC (%) O 2 13 f an 8 32 o g S (mg HC/g rock) HC/g (mg S 1 % f Or 19 3 10 o Poor source n 1 e 1 m u n 20% e Bit 13 tum Poor Very poor source Bi Oil staining or contamination 0.1 0.1 0.1 1 10 100 10 100 1000 10 000 100 000 TOC (%) EOM (ppm)

Figure 5-20: Source potential rating based on (A) S2 -TOC and (B) TOC-EOM plots for the Middle Triassic Moolayember Formation, Bowen Basin.

1000 I 900 750 900 % II .5 600 0 10 000 v = R 450 800 Contaminated 300 or stained il o 4 d 150 8 20 19 o HydrogenIndex (mg HC/g TOC) il 3 32 o OC) 700 g o I 13 7 III ry d il 0 e o o l 7 1000 V o i 050100150 G ir o Oxygen Index (mg CO /g TOC) a e 2 F m 600 o HC/g T s d n .a

mg mg s a 500 G

nde 100 Gas source 400 Hydrocarbons (ppm) Hydrocarbons 13 ogen I Adequate(?)gas dr x ( % 300 II 5 Hy .3 1 = v 10 R 0.1 1 10 100 200 4 TOC (%) 8 20 32 100 3 Figure 5-21: Source-rock richness plot 19 III 1 7 13 for the Middle Triassic Moolayember 0 Formation, Bowen Basin. 380 430 480 530 580 o Tmax (C) Figure 5-22: Kerogen type and estimation of maturity for the Middle Triassic Moolayember Formation, Bowen Basin.

121 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

On the other hand, the sample illustrates good source rock potential (Figure 5-20a) and good genetic potential (Table 5-1). This high residual hydrocarbon generation potential capability is a result of the relatively high S2 value. In this case, the high S2 value probably is not formed solely from cracking of kerogen but also from free NSO compounds that were not distilled within the S1 peak’s temperature interval (cf. Barker,

1974; Clementz, 1979). The NSO compound’s distillation within S2 temperature o intervals of 300 to 650 C can be seen in Figure 5-23, where the NSO contribution to S2 bimodal peak is the major part of the lower maximum temperature. As a result, the S2 value in sample No. 7 is higher than the actual amount and considered spurious.

Consequently, parameters based on the S2 value in this case are inaccurate.

The Tmax is predicted to be lower than the actual value when the S2 peak is affected by free hydrocarbons (Espitalié, 1986). In the mature sample No. 7 the second S2 peak, which is formed from the residual kerogen is more capable of generating hydrocarbons than the NSO compounds distilled within the S2 temperature interval (Figure 5-23). o Thus, for this sample the Tmax (556 C, Table 5-1) was calculated from the second maximum temperature in the bimodal S2 peak. The Tmax value, however, is a calculated number being approximately 37oC lower than temperature (oC) on the pyrogram.

5.3.1.2.2. Gunnedah Basin

5.3.1.2.2.1. Napperby Formation

Five samples from the Middle Triassic Napperby Formation were analysed from the Bellata-1 and Coonarah-1A wells in the Gunnedah Basin. Part of the sequence in the Bellata-1 well is postmature due to igneous intrusions (Chapter 4). The Napperby Formation has a good to excellent TOC content (1.49% to 56.7%; Table 5-1), and shows poor to good hydrocarbon genetic potential (Table 5-1). Consequently it has poor to excellent source potential (Figures 5-24a and 5-24b) and poor to excellent hydrocarbon yield (Table 5-2), with a fair ability to generate oil, at best (Figure 5-25).

The Napperby Formation contains Type II/III and Type III kerogen (Figure 5-26), which is partially within the peak mature zone, and in places is postmature (Table 5-1), due to igneous intrusions and local heat effects.

122 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

100 90 Analysis : 19990601 (17/48) 80 70 60 50

Pyr. HC 40 30 20 10 0 100 200 300 400 500 600 700 800 Temperature (°C)

Figure 5-2: Rock-Eval 6 pyrogram illustrating bimodal S2 peak possibly due to free NSO compounds in the Moolayember Formation (sample No. 7).

123 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

(A) 1000 Poor Fai r G ood Very Ex c e l le nt (B) Go od 100 Exc el len t ( c o al s)

Ga s sou rce 34 Ver y 100 34 Excel lent goo d Go od

10 Fair

n V e ry Go od o 10 Poor rb 44 a n 44 C o 36 b Good ic r 45 n a a C g c Fai r r i TO C (%) 36 35 n 2 f O a 45 o rg

S (mg HC/g rock) HC/g (mg S 1 % 0 f O 1 o 35 Poor source n % 1 e 0 m 2 u n it e B m tu Poor i O il stain ing or Very poor source B c ont am ina t io n 0.1 0.1 0.1 1 10 100 10 100 1000 10 000 100 000 TOC (%) EOM (ppm)

Figure 5-24: Source potential rating based on (A) S2 -TOC and (B) TOC-EOM plots for the Middle Triassic Napperby Formation, Gunnedah Basin.

1000 900 I 750 90 0 % II 5 600 0. 10 000 v = R 450 80 0 Contaminated 300 or stained l oi 34

150 d

H ydrog Index en (mg HC/g TOC) o o il 70 0 I g o III y d l TOC) r i 0 e o o l 1000 V i 050100150 Go ir o a e C/ g Oxyg en Ind ex (mg CO2 /g T OC) F m o 600 s 44 d n .a s 45 a (mg 500 G 10 0 35 Inde 36 Gas sour ce 400 Hydrocarbons (ppm) ogen Adequate(?)gas dr x H % 300 5 Hy II .3 1 = v 10 R 0.1 1 10 100 200 44 34 TOC (%)

100 45 33 Figure 5-25: Source-rock richness III 35 plot for the Middle Triassic Napperby 0 380 430 480 530 580 Formation, Gunnedah Basin. o Tma x (C) Figure 5-26: Kerogen type and estimation of maturity for the Middle Triassic Napperby Formation (dark circles) and Jurassic Purlawaugh Formation (open circle), Gunnedah Basin.

124 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

Sample No.36 is considered postmature based on a vitrinite reflectance value equal to o 2.21%, but the Tmax is only 348 C (Table 5-1). This low value of Tmax is attributed to a high pyrobitumen [defined as thermally altered, solidified bitumen that is insoluble in common organic solvents (Peters and Moldowan, 1993)] content in the sample (Chris Boreham, 1999 personal communication). The pyrobitumen effect can be observed on o the S2 profile (Figure 5-27). The narrow peak created at around 390 C on the pyrogram is attributed to pyrobitumen distillation, while the second minor peak observed around o 540 C reflects the actual S2 that resulted from kerogen cracking. As discussed above, the presence of heavy ends of bitumen increases the quantity of S2 and decreases the

Tmax value (Barker, 1974; Clementz, 1979; Vandenbroucke et al., 1981). Thus, the high HI (271 mg HC/g TOC; Table 5-1), good source potential (Figure 5-24a) and moderate hydrocarbon genetic potential (S1+S2 = 5.43 kg hydrocarbon/tonne rock; Table 5-1) in this sample is considered unreliable. As illustrated in Figures 5-24b and 5-25, the sample is located within the gas source field, which reflects the residual source potentiality of the sample and it is consistent with its high level of thermal maturity. In addition, it verifies that this sample’s capability to generate liquid hydrocarbons is exhausted.

5.3.1.3. Jurassic sequences

5.3.1.3.1. Surat Basin (Bowen Basin area)

5.3.1.3.1.1. Evergreen Formation

Five samples were chosen from the Early Jurassic Evergreen Formation for Rock-Eval pyrolysis from the Chester-1, Goondiwindi-1, McIntyre-1 and Werrina-2 wells (Table 5-1). Among these samples two were extracted (Table 5-2). The formation is considered as a very good to excellent source rock based on the TOC content (3.69% to 22.98%; Table 5-1), and shows moderate to good hydrocarbon genetic (Table 5-1) and fair to excellent source potential (Figures 5-28a and 5-28b) with good to excellent hydrocarbon yield (Table 5-2). The Evergreen Formation has a fair ability to generate oil at the best (Figure 5-29).

125 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

100 90 Analysis : 9990611B (43/48) 80 70 60 50

Pyr. HC 40 30 20 10 0 100 200 300 400 500 600 700 800 Temperature (°C)

Figure 5-3: Rock-Eval 6 pyrogram illustrates S2 profile for Napperby Formation, sample No. 36.

126 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

(A) 1000 Poor Fair Good Very Excellent (B) Good 100 Excellent (coals) Gas source Very

Excellent 11 100 good 12 2 Good 11 10 12 Fair n V ery 10 Good Poor bo 18 n

Good bo ic Car n ar a C 31 c Fair

TOC (%)

2 f Org ani

S S rock) HC/g (mg 1 0% o f Org 1 o Poor source n 1 0% ume n 2 e Bit Poor Very poor source Bitum Oil staining or contamination

0.1 0.1 0.1 1 10 100 10 100 1000 10 000 100 000 TOC (%) EOM (ppm)

Figure 5-28: Source potential rating based on (A) S2 -TOC and (B) TOC-EOM plots for the Early Jurassic Evergreen Formation, Bowen Basin.

1000 I 900

750 900 % II 5 600 0. 10 000 v = R 450 800 Contaminated 300 or stained il 2 o 11

12 d 150 o Hydrogen Index (mg HC/g TOC) 18 o il 700 11 31 o I g III ry d il 12 0 e o o 1000 V o 050100150 G ir Oxygen Index (mg CO /g TOC) a 600 2 F

500 100 Gas source 400 (ppm) Hydrocarbons

Adequate(?)gas % 300 II 5 Hydrogen Index HC/g (mg TOC) Hydrogen .3 1 = v 10 2 R 200 0.1 1 10 100 12 TOC (%) 18 11 100 Figure 5-29: Source-rock richness plot III 31 for the Early Jurassic Evergreen 0 Formation, Bowen Basin. 380 430 480 530 580 o Tmax (C) Figure 5-30: Kerogen type and estimation of maturity for the Early Jurassic Evergreen Formation, Bowen Basin.

127 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

Based on the Tmax versus HI cross plot the Evergreen Formation contains Type II/III and Type III kerogen (Figure 5-30), which is partially within the early mature stage (up to o 436 C Tmax; Table 5-1).

5.3.1.3.1.2. Walloon Coal Measures

Six samples were chosen for Rock-Eval analyses from the Middle Jurassic Walloon Coal Measures from the Gil Gil-1, Goondiwindi-1, McIntyre-1 and Werrina-2 wells, including two samples that were extracted for further geochemical studies. The Walloon Coal Measures has an excellent TOC content (14.99% to 62.62%; Table 5-1) and good hydrocarbon genetic potential (Table 5-1), with good to excellent hydrocarbon yield ability (Table 5-2). Consequently, the sequence has excellent source potential (Figures 5-31a and 5-31b), with a fair ability to generate oil, as illustrated on the TOC versus hydrocarbon crossplot (Figure 5-32).

The Rock-Eval data suggest that the Walloon Coal Measures contains immature Type II kerogen (Figure 5-33; Table 5-1). The organic matter type is consistent with the sequence’s high potential to generate liquid hydrocarbons (Figures 5-31 and 5-32). The low maturity level is comparable with the vitrinite reflectance values (Table 5-1), and is attributed to a relatively shallow burial depth of the Walloon Coal Measures sequence in the study area with no local heat effects due to igneous intrusion.

5.3.1.3.2. Surat Basin (Gunnedah Basin area)

5.3.1.3.2.1. Purlawaugh Formation

A siltstone sample from the Jurassic Purlawaugh Formation was chosen for Rock-Eval pyrolysis from the Bellata-1 well. The sample has a good TOC content (1.19%; Table 5- 1), but poor hydrocarbon genetic potential (Table 5-1) and poor source potential (Figure 5-24a). The sample suggests that the Purlawaugh Formation contains marginally mature Type III kerogen (Figure 5-26; Table 5-1).

128 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

(A) 1000 Poor Fair Good Very Excellent (B) Good 100 Excellent (coals) 9

16 9 Gas source Very 30 Excellent 100 17 good 30 Good 6 10 10 Fair

n V ery Good o 10 Poor rb a n o C b Good ic r n a a C rg

Fair ic TOC (%) O n 2 f a o rg O S S rock) HC/g (mg 1 % f 0 o 1 Poor source n % 1 e 0 m 2 u n it e B m tu Poor i Very poor source B Oil staining or contamination 0.1 0.1 0.1 1 10 100 10 100 1000 10 000 100 000 TOC (%) EOM (ppm)

Figure 5-31: Source potential rating based on (A) S -TOC and (B) TOC-EOM 2 plots for the Middle Jurassic Walloon Coal Measures, Bowen Basin.

1000 I 900 750 900 II 5 % 600 0. = 10 000 9 v 16 R 450 800 Contaminated 30 17 300 or stained il 96 o 10 30 d 150 o Hydrogen Index (mg HC/g TOC) il 700 o o I g III ry d il 0 e o o l 1000 V o i 050100150 G ir o Oxygen Index (mg CO /g TOC) a e 2 F m o 600 s d n a s. a 500 G 16 100 Gas source 400 (ppm) Hydrocarbons Adequate(?)gas 17 % 300 II 5 Hydrogen Index (mg HC/g TOC) .3 1 9 = v 10 6 R 30 0.1 1 10 100 200 10 TOC (%)

100 Figure 5-32: Source-rock richness III plot for the Middle Jurassic Walloon 0 Coal Measures, Bowen Basin. 380 430 480 530 580 o Tmax (C)

Figure 5-33: Kerogen type and estimation of maturity for the Middle Jurassic Walloon Coal Measures, Bowen Basin.

129 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

5.3.2. n-Alkanes and acyclic isoprenoids patterns

The m/z 85 profile of the saturated hydrocarbon fraction is illustrated for selected Permian, Triassic and Jurassic source rock samples in Figures 5-34, 5-35 and 5-36. Various normal and isoprenoid alkane ratios for all extracted source rock samples are presented in Table 5-2.

The alkanes from the coal and non-coal samples in the sequences not affected by local heat due to igneous intrusions are characterised by a predominance odd-over-even carbon number preference (CPI = 1.25 to 2.67; Table 5-2) and relatively high pristane abundance (pr/ph = 1.51 to 8.33; Table 5-2). Furthermore, the n-alkane distributions in these samples maximise in the higher molecular weight range. These features collectively are consistent with immature higher plant-derived organic matter input deposited in a predominantly oxic environment. The high pr/ph ratio (8.33; Table 5-2) in coal sample No. 40 of the Goonbri Formation, for example, probably indicates a further increased terrestrial contribution for the source input (e.g. Rashid, 1979).

The locally heat affected sequences, due to igneous intrusion, contain more mature intervals (sample Nos. 7, 46 and 50 for example; Figure 5-34). The n-alkane distribution in these samples, maximising in the lower molecular weight range and declining smoothly towards higher n-alkane molecular weight, reflects maturity effects rather than variations in the source organic matter. The CPI values for these samples just above unity, and the lower pr/n-C17 ratios (Table 5-2) are attributed to the high level of thermal maturity. The relative decrease in CPI, pr/n-C17 and ph/n-C18 from the less mature sample No. 13 to the more mature sample No. 7 in the Moolayember Formation (Table 5-2) is attributed to increasing organic matter thermal maturity in the latter interval.

The n-alkane distribution for the lower part of the Napperby Formation in the Bellata-1 well (sample No. 36, Figure 5-35), which is influenced by local heat (Rv,max = 2.21%) from an igneous intrusion, is exceptional. The harsh heating effect of the intrusion is manifested in the alkane fingerprint for this sample. The n-alkanes were differentially expelled earlier from the source rock, resulting in their low abundance relative to other components that seem to be more tightly bound to the kerogen moiety (Othman et al., 2001). These compounds have previously been detected in Neoproterozoic sediments

130 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

23 25

27 Sample No. 14 Goondiwindi-1 29 Back Creek Group 1886.71 m CPI = 2.11 pr 18 pr/ph = 4.87 17 HI = 215 ph 31 o Tmax = 425 C

Rv,max = 0.60% 25 27

Sample No. 22 McIntyre-1 Kianga Fm. 2200.66 m CPI = 2.00 pr/ph = 1.51 HI = 80 18 T = 433oC max Rv,max = 0.72% 25

pr

Sample No. 40 27 Bellata-1 Goonbri Fm. 1054.74 m CPI = 1.80 pr/ph = 8.33 18 HI = 211 T = 427oC max Rv,max = 0.66% 25

29 Sample No. 37 Bellata-1 Maules Creek Fm. 929.60 m 18 CPI = 2.46 pr/ph = 4.17 17 HI = 155 o Tmax = 430 C

Rc(rw) = 0.67% 19

Sample No. 50 Coonarah-1A 25 Watermark/Porcupine Fm. 635.35 m CPI = 1.15 17 ph pr/ph = 0.12 HI = 15 pr T = 553oC max Rv,max = 1.80%

Figure 5-4: Mass chromatograms (m/z 85) showing alkane distributions in the selected Permian samples in the study area.

131 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

25

29

Sample No. 41 Bohena-1 Black Jack Group 660.85 m CPI = 1.74 pr/ph = 2.11 18 HI = 114 o Tmax = 433 C R = 0.62% v,max 18 17

Sample No. 46 Coonarah-1A Black Jack Group 522.60 m CPI = 1.17 pr pr/ph = 2.05 ph HI = 25 o Tmax = 538 C Rv,max = 1.8%

Figure 5-34: Mass chromatograms (m/z 85) showing alkane distributions in the selected Permian samples in the study area continued.

18

17

Sample No. 7 Gil Gil-1 Moolayember Fm. 1307.97 m pr CPI = 1.32 21 pr/ph = 3.54 ph HI = 24 29 o Tmax = 556 C R = 1.3% v,max 27

Sample No. 13 Goondiwindi-1 Moolayember Fm. 1554.18 m CPI = 2.11 pr/ph = 2.80 HI = 41 18 o Tmax = 436 C R = 0.77% v,max

Figure 5-5: Mass chromatograms (m/z 85) showing alkane distributions in the selected Triassic samples in the study area.

132 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

18

17 20 22 16 19 24 29 Sample No. 36 pr 21 31 Bellata-1 23 25 Napperby Fm. ph 829.60 m 33 CPI = 1.05 pr/ph = 1.37 HI = 271* 15 o Tmax = 348 C*

Rv,max = 2.21% *Not reliable (see text). 25 27

Sample No. 44 Coonarah-1A 18 Napperby Fm. 421.96 m CPI = 1.70 pr/ph = 2.94 HI = 188 o Tmax = 443 C Rv,max = 0.52%

Figure 5-35: Mass chromatograms (m/z 85) showing alkane distributions in the selected Triassic samples in the study area continued.

27

Sample No. 12 31 Goondiwindi-1 Evergreen Fm. 1356.36 m CPI = 2.21 pr/ph = 2.51 pr 18 HI = 149 o Tmax = 424 C

Rv,max = 0.72% 27

Sample No. 9 Goondiwindi-1 Walloon Coal Measures 996.70 m 29 CPI = 2.67 pr/ph = 3.75 HI = 253 o Tmax = 422 C 18 Rv,max = 0.54%

Figure 5-6: Mass chromatograms (m/z 85) showing alkane distributions in the selected Jurassic samples in the study area.

133 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

and tentatively identified as branched alkanes (Arouri et al., 2000; Greenwood et al.,

2001). The unusual combination of even-carbon-number predominance among the n-C17 to n-C25 alkanes and odd predominance in the n-C26+ range is difficult to explain (Othman et al., 2001).

Marine organic matter contribution to the Permian marine influenced sequences in the study area is not recognised in the n-alkane fingerprints. This could be attributed to the incorporation of varying amounts of nonmarine organic matter into the marine sediments (Tissot and Welte, 1984; Moldowan et al., 1985). In addition, the alkane content is usually much higher in continental than in marine organic matter; thus, where both types of material contribute, continental matter superimposes its pattern of n- alkane distribution, especially in the C25 to C33 range (Tissot and Welte, 1984).

5.4. Rock-Eval S1 and EOM relationship

Evaluation of petroleum source-rocks by pyrolysis is based on the concept that any free o hydrocarbons in rock samples (S1) are volatilised below 300 C, while hydrocarbons cracked from kerogen (S2) are released at higher temperatures. The pyrolysis of pure hydrocarbons with different mineral matrices shows that free hydrocarbons containing 16 or more carbon atoms may not be volatilised below 300oC, but at varying higher temperatures. However, all impregnated n-alkanes on calcium carbonate in the Rock- o Eval instrument, up to C32, were released over a temperature range between 257 and 274oC. The extent to which this occurs depends on the hydrocarbon volatility, the mineral matrix and the pyrolysis instrument design (Tarafa et al., 1983).

Even if S1 measures the amount of bitumen already generated in a rock sample, this value does not correspond directly to the solvent extracted bitumen because of procedure differences (Peters, 1986). The S1 peak represents organic compounds from

C1 to about C32, and is based primarily on separation by distillation at a temperature of up to about 400oC in the Rock-Eval and the flame ionisation detector (FID) response factor of each compound. Extractable bitumen represents the weight percentage of organic compounds removed by an organic solvent. This percentage varies with solvent polarity, extraction method, sample size, and extraction time. In addition, compounds

134 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

below C15 are lost while evaporating organic solvent during the free bitumen extraction procedure (Peters, 1986).

As illustrated in Figure 5-37a and Table 5-2, there is a strong relation between S1 (mg/g rock) and EOM (mg/g rock) for the samples studied. Highly mature samples, sample No. 35 for example, usually shows less residual potential for hydrocarbon generation, and the already generated hydrocarbons were probably expelled from the sequence.

Consequently such a sample shows a low S1 yield and a low EOM amount (Figure 5-

37a). Less mature samples, sample No. 5 for example, are characterised by high S1 and high EOM amounts (Figure 5-37a), for generated hydrocarbons in such a low mature samples are possibly not expelled yet. The exception is the postmature Napperby

Formation sample, No. 36, which has a low EOM value due to its maturity level (Rv,max

= 2.21%), along with a relatively high S1 (Figure 5-37a; Table 5-2). This might be attributed to pyrobitumen content in this sample (see below).

Figure 5-37a, in addition, demonstrates the capability of the various procedures in releasing different amounts of free bitumen from the rock sample. It is obvious that the amount released from solvent extraction, EOM (mg/g rock), is higher than the temperature-separated Rock-Eval S1 quantity (mg/g rock), as in samples No. 5 and 35 for example (Figure 5-37a). The relation of S1 (mg/g rock) to the hydrocarbons (mg/g rock) and S1 (mg/g rock) to the NSO (mg/g rock) compounds (Figures 5-37b and 5-37c;

Table 5-2), shows that the hydrocarbon constituents are more similar with S1.

Correspondingly, the differences between EOM and S1 is due to the organic solvents greater capability of extracting NSO compounds compared to the Rock-Eval pyrolysis temperature distillation release of the S1 peak. The exception is the postmature sample No. 36 of the Napperby Formation, which shows relatively low solvent extraction NSO compounds, in particular (Figure 5-37c). This is attributed to pyrobitumen content, which is solidified bitumen that is insoluble in common organic solvents (Peters and

Cassa, 1994). The free NSO compounds in this postmature sample (Rv,max = 2.21%), probably, mainly changed to the thermally altered pyrobitumens, while the S1 mainly reflects the hydrocarbons (Figure 5-37b; sample No. 36). In a general, Rock-Eval S1, as shown in Figure 5-37b, mainly represents the amount of the hydrocarbon constituents derived from the free bitumen in the analysed rock samples.

135 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

S1-EOM relationship S1-HC relationship S1-NSO relationship 1000 1000 1000 100 100 100 5 10 10 10 5 5 1 1 1 35 35 0.1 0.1 0.1 36 35 36 HC (mg/g rock) HC NSO (mg/g rock) EOM (mg/g rock) 0.01 0.01 0.01 36

0.001 0.001 0.001 0.001 0.01 0.1 1 10 100 1000 0.001 0.01 0.1 1 10 100 1000 0.001 0.01 0.1 1 10 100 1000 S1 (mg/g rock) S1 (mg/g rock) S1 (mg/g rock)

Figure 5-7: Rock-Eval S1 versus (A) EOM, (B) Hydrocarbons and (C) NSO compounds relationship for the studied samples.

136 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

5.5. Free bitumen effect on the Rock-Eval S2 peak

S1 and S2 are involved in petroleum exploration studies based on Rock-Eval pyrolysis applications. The non-distilled NSO compounds from free bitumen (Figure 5-37c) would be added to the S2 quantity, at the higher temperature levels used in the Rock-

Eval pyrolysis to produce hydrocarbons from kerogen (generating the S2 peak).

Furthermore, Barker (1974) attributed an extra S2 peak to hydrocarbons coming from the breakdown of a totally enclosed micro-reservoir, while Clementz (1979) showed that solid bitumen and EOM, the heavy end fraction of petroleum, appear in the S2 peak.

In general, this category of hydrocarbon compounds that are generated at the start of o o pyrolysis, at 300 to approximately 400 C, represent only a few percent of the total S2 amount, and affect neither the HI nor Tmax values (Espitalié, 1986). However, this depends on the amount of free bitumen that is involved in the S2 peak instead of S1; the problem is minor when the ratio of bitumen or oil to kerogen is small (Peters, 1986). If the amount is relatively high, as in sample No.36 (Figure 5-27) for example, any calculation of the parameters involving S1 or S2 measurements and the value of Tmax will be affected. The genetic potential (S1+S2) of Tissot and Welte (1984) also would be affected in such a case. If the complications caused by extra S2 amounts due to the accumulation of heavy oil is not recognised, the proposed source rock might be interpreted incorrectly as a prolific source for hydrocarbon generation based on their high HI values (Peters, 1986).

Chloroform extraction of heavy products prior to pyrolysis, in cases of impregnated source rocks, eliminates these product effect on the S2 peak and the various parameters therefore would be representative of the kerogen (Clementz, 1979). All the S1 compounds in such a case, however, would be removed. Extraction of suspect samples with an organic solvent prior to analysis is another option to eliminate heavy ends and oil-based additives, but the S1 will also be lost or reduced (Peters, 1986). Common organic solvents, however, would not eliminate the presence of pyrobitumen, such as that within postmature sample No. 36 for example. Such a problem can be identified from the pyrogram, which shows a bimodal S2 peak and a high HI value (Figure 5-27; Table 5-1).

137 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

Natural contamination is most severe where oil has migrated into coarse-grained or fractured organic-lean rocks. Pyrograms are useful indicators to distinguish such a problem. The pyrograms of contaminated or reservoir rocks commonly show an S1 peak greater than 2 (mg/g rock), an anomalously high PI and low Tmax, compared to adjacent samples, and a bimodal S2 peak (Peters, 1986).

5.6. Rock-Eval Tmax and vitrinite reflectance relationship

There is, in a general, a discernible relationship between Tmax and vitrinite reflectance among the analysed samples (Figures 5-38a and 5-38b). However, the postmature o sample No. 36 is anomalous (Figure 5-38a). The low Tmax value (348 C) for this sample in relation to its high Rv,max value (2.21%), is attributed to the pyrobitumen content that reduced the Tmax as discussed above.

Figure 5-38b provides a Tmax versus Rv,max plot for the samples with less than 1.5% o Rv,max and less than 450 C Tmax values. In addition to the perhydrous kerogen that lowers both the vitrinite reflectance and Tmax values, other parameters show different relations to these maturity indicators. Lithology variation (as discussed in section 4.5.1.3; Chapter 4), for example, effects vitrinite reflectance and results in slightly different values within intervals with similar burial depth and heat-flow histories, while

Tmax varies with kerogen type, reflecting the range in bond energies (Norgate et al.,

1997). Therefore, various parameters may influence the correlation of Tmax with vitrinite reflectance, and this explains the scattering of the samples on the Tmax versus vitrinite reflectance main path (Figure 5-38b). Similar variations in such relations has been noted previously (e.g. Teichmüller and Durand, 1983; Espitalié, 1986). Two samples, however, anomalously plot away from the main trend (Figure 5-38b); these are samples No. 35 and 42. The measured vitrinite reflectance for sample No. 35 is 0.98%. Accordingly, the sample would be considered to lie within the late mature zone, but the o sample is considered as being just marginally mature based on the 435 C Tmax value. It is also considered to lie within the late mature zone according to the calculated vitrinite reflectance based on the method of Radke and Welte (1983) (Rc(rw) = 0.94%; Table 6-9 Chapter 6), and is considered within the peak mature zone based on the method of

Boreham et al. (1988) (Rc(b)=0.85%; Table 6-9 Chapter 6) and that of Kvalheim et al.

(1987) (Rc(k)=0.87%; Table 6-9 Chapter 6). The slightly lower Tmax value of sample No. 138 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

Rv,max-Tmax relationship Rv,max-Tmax relationship R % v ,max R % 0123 00.511.5v ,max 300 420

350 425 36

400 430

C) C) 42 o o

( 450 ( 435

max max 35 T T

500 440

550 445

600 450

Figure 5-8: Measured vitrinite reflectance versus Tmax relationship for (A) all analysed samples, o and (B) Rv,max and Tmax values less than 1.5% and 450 C respectively.

139 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

35, compared to the measured and calculated vitrinite reflectance values, cannot be attributed to heavy oil accumulation, which could be added to the S2 peak and reduce the Tmax value. The S2 profile on the Rock-Eval 6 pyrogram illustrates a single peak.

However, the low Tmax value in this particular case might be attributed to a technical reason, the analysed sample weight for example (cf. Espitalié, 1986), and repeat Rock- Eval analysis is recommended.

Sample No. 42 is the other scattered point on Figure 3-38b. In the case of this sample, however, further comparison of various maturity indicators is not possible because an organic geochemical study based on solvent extraction was not carried out.

5.7. Suppression and hydrocarbon generation

This section discusses the relation between the suppression of thermal maturity parameters (i.e. Rv,max and Tmax) in relation to hydrocarbon generation. In fact, the inferred vitrinite reflectance calculated by various methods (see Chapter 6) also shows lower values than expected, similar to the measured vitrinite reflectance values, in marine influenced (e.g. Maules Creek Formation) and liptinite rich sequences (e.g. Goonbri Formation). Neil Sherwood (2002 personal communication) and P. K. Mukhopadhyay (2002 personal communication) have suggested that hydrocarbon generation increases with depth, even though a particular interval may be suppressed in terms of vitrinite reflectance.

Peters and Moldowan (1993) indicate that there are two types of thermal maturity parameters. These are thermal stress or traditional rank parameters, which are used to describe the effects of temperature/time, and generation or conversion parameters, used as indices of the stage of petroleum generation. At a given atomic H/C value different types of kerogen might generate equivalent amounts of oil, but the vitrinite reflectance in each case may differ. Rv,max and Tmax are thermal stress parameters; changes in these parameters depend primarily on time/temperature conditions, and can only be approximately related to the stage of petroleum generation for different rock/kerogen types. Generation parameters (e.g. bitumen/TOC ratio) are related to how much petroleum has actually been produced from the organic matter (Peters and Moldowan,

140 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

1993). Tissot et al. (1971) and Tissot and Welte (1984) have indicated that the extractable organic matter and generation of hydrocarbons both increase with increasing burial depth.

In the Bellata-1 well 22 samples were selected for vitrinite reflectance measurement (Figure 4-5, Chapter 4), nine samples were analysed by Rock-Eval pyrolysis (Table 5- 1), and eight samples selected among these for further geochemical studies (Table 5-2). As illustrated in Figure 5-39, a TOC versus depth profile, the sequence contains variable amounts of TOC. However, the upper part of the Napperby Formation (sample No. 34) and the Permian sequences are considered as excellent source rocks based on the TOC content. Although the sequences studied contain mainly terrigenous organic matter (section 5.3.2), they show variation in the organic matter quality. As indicated on the HI versus depth profile (Figure 5-39), the upper part of the Napperby Formation and the Permian sequences have better organic matter quality for hydrocarbon generation. The high HI value for the postmature sample (#36), however, is considered to be an inaccurate hydrocarbon generation potentiality indicator for this particular sample as discussed above. The Bellata-1 well is a good example for the comparison of hydrocarbon generation within suppressed sequences, because the maturity parameters

(Rv,max and Tmax), in addition to the suppressed sequences, embrace various maturity levels (immature to postmature). As illustrated in Figure 4-5 (Chapter 4), the Rv,max versus depth profile shows three different maturity trends (Othman et al., 2001):

1. A normal vitrinite reflectance trend, which is observed in the Jurassic and the upper part of the Middle Triassic sequences. 2. Anomalously high vitrinite reflectance values due to igneous intrusions. These are mainly recognised in the lower part of the Middle Triassic sequence (Figure 5-39), in addition to a small interval in the lower part of the Early Permian Goonbri Formation (Figure 4-5, Chapter 4). 3. Finally, suppressed vitrinite reflectance values over the entire Permian sequence, which is due to marine influence (Maules Creek Formation), and liptinite rich organic matter content (Goonbri Formation).

Similar trends can be observed on the Tmax versus depth profile (Figure 5-39). The anomalously low Tmax value for the postmature sample (#36), however, is attributed to 141 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

T -Depth profile TOC-Depth profile HI-Depth profile Rv-Depth profile max HC-Depth profile EOM-Depth profile in Bellata-1 in Bellata-1 in Bellata-1 in Bellata-1 in Bellata-1 in Bellata-1 EOM (mg/g TOC) o TOC(%) HI (mg HC/g TOC) R (%) Tmax ( C) HC (mg/g TOC) v,max 02550 50 175 300 0123325 375 425 475 01020 110100 600 Purlawaugh Fm.

700

Napperby Fm. 800

Digby Fm. Depth (m) Depth 900 Porcupine Fm.

Maules Creek Fm.

1000

Go on bri Fm.

1100

Figure 5-9: Comparison between traditional rank and generation maturity parameters in Bellata-1, Gunnedah Basin. TOC and HI relation to depth show the quantity and quality of the organic matter. Stratigraphy showing major igneous intrusions within lower part of the Napperby Formation. Open circles represent samples influenced by igneous intrusions. Individual data points are joined by lines to facilitate comparison of different indicators used. 142 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

the pyrobitumen content as discussed earlier. In contrast, only two trends can be identified on the hydrocarbon (HC mg/g TOC) versus depth and extractable organic matter (EOM mg/g TOC) versus depth profiles (Figure 5-39). Although there are variations that may be attributed to the organic matter quality, the HC mg/g TOC and the EOM mg/g TOC trends both increase with depth. An exception is the postmature sample (#36), in which the capability for hydrocarbon generation has been exhausted, and the generated hydrocarbons have expelled (Othman et al., 2001; Chapter 7).

It is concluded that the thermal stress parameters are suppressed within the Bellata-1 sequences containing perhydrous organic matter, due to marine influence or liptinite rich sequences, while the generation parameters increase with depth even within the vitrinite reflectance or Tmax suppressed sequences (Othman and Ward, 2003). Thus, the actual amount of hydrocarbons generated increases with increasing burial depth, even though the thermal stress maturity parameters are suppressed. It is significant to mention that maturity parameters based on hopane and sterane signatures (Chapter 6) are not obviously affected by perhydrous organic matter, in the vitrinite reflectance or

Tmax suppressed intervals.

The possibility that the generated hydrocarbons in the analysed samples are non- indigenous, and may be due to migration from a small igneous intrusion affected interval in the lower part of the Goonbri Formation (Figure 4-5, Chapter 4) is unlikely. This is because the calculated vitrinite reflectances for the Permian sequence, within the suppressed interval for the analysed samples, are generally similar to the measured vitrinite reflectance values (Othman et al., 2001; see Chapter 6). The n-alkane fingerprints (samples No. 37 and 40; Figures 5-34; Table 5-2), and the triterpane, sterane and tricyclic terpane chromatograms (Othman et al., 2001; Chapter 6) all indicate immature Permian sequences for the samples in question. These outcomes support that the hydrocarbons are locally generated and not migrated from higher maturity intervals, such as the igneous intruded part of the Goonbri Formation for example. In addition, the Goonbri and Maules Creek Formations contain coal, claystone and siltstone intervals (Hamilton et al., 1993), with a 2.18 m thick igneous intrusion located at a depth of 1103.70 m, and it is unlikely that hydrocarbons generated from the lower part of the Goonbri Formation from such a limited intrusion body, would have

143 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

migrated through a sequence containing coal, claystone and siltstone up to more than 170 m to reach and contaminate the analysed Permian samples.

5.8. Discussion and conclusions

Source rock data are described in this chapter, based on 50 samples subjected to Rock- Eval pyrolysis analysis and 27 samples subjected to solvent extraction and further organic geochemical studies. Although only n-alkanes and acyclic isoprenoids are studied in this section, steranes, hopanes and aromatic hydrocarbons are discussed in the following chapter to describe further the type, thermal maturity and depositional environment of the organic matter preserved in the sequences studied.

The amount of total organic carbon is one of the basic parameters in source rock evaluation, but it is not a sufficient indicator to describe the sequence’s potentiality in terms of hydrocarbon generation. Thus, in addition to the genetic potential and hydrocarbon yield ability, cross plots of TOC (%) versus S2 (mg HC/g rock), EOM (ppm) versus TOC (%), and TOC (%) versus hydrocarbons (ppm) were employed to describe source rock-richness. Organic matter types are classified with reference to the o main types of Tissot et al. (1974), based on Tmax ( C) versus HI (mg HC/g TOC), and HI o (mg HC/g TOC) versus OI (mg CO2/g TOC) cross plots. Rock-Eval Tmax ( C) was used to identify levels of organic matter thermal maturity. The PI shows a low degree of variation, and is not an effective maturity parameter in the samples studied. However,

Rock-Eval S1 value is noted to be small in coals and does not increase with increasing organic matter thermal maturity (Teichmüller and Durand, 1983). In mature coals, the low S1 values may be attributed to trapping of the generated hydrocarbons in closed pores, which prevent the hydrocarbon release at distillation temperatures consistent with the S1 peak (Littke and Leythaeuser, 1993).

Based on the Rock-Eval analysis data, the Permian Back Creek Group of the Bowen Basin sequence has a wide range of TOC values, and as expected in this and other sequences the highest TOC percentage were found in the coals. The amount of TOC in the Back Creek Group ranges from ‘very good to excellent’, with a majority of the analysed samples located within the excellent source rock field. At best, the sequence has good genetic potential, which is the highest level for describing a source rock 144 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

genetic potentiality (cf. Tissot and Welte, 1984), and is able to generate a fair amount of oil. The Back Creek Group contains mainly immature to early mature kerogen Type

II/III. The sequence is marine affected, and the Tmax values, like the vitrinite reflectance, are suppressed. Furthermore, the coals show even lower Tmax values compared to the adjacent non-coal samples. The Permian Kianga Formation, in terms of source rock evaluation, has a similar capability for hydrocarbon generation to the Back Creek Group, but contains immature to marginally mature Type II/III and Type III kerogen. However, the Back Creek Group sequence is more suitable for generating liquid hydrocarbons than the Kianga Formation (cf. Figures 5-3 and 5-6). Furthermore, the

Tmax values in the Kianga Formation are not suppressed.

Nine samples were analysed by Rock-Eval from the Middle Triassic Moolayember Formation in the Bowen Basin. The majority of the analysed samples indicates the sequence as ‘good’ in terms of TOC content, but mainly indicates poor source potential on the bases of S2 (Figure 5-20a). Based on two solvent extracted samples, the Moolayember Formation has a capability to generate gaseous hydrocarbons. Even though sample No. 7 has a high maturity level (Table 5-1), it has excellent source potentiality based on the EOM (ppm) versus TOC (%) cross plot (Figure 5-20b). However, it has mainly a gas capability, which is consistent with its maturity level, according to the TOC (%) versus hydrocarbons (ppm) cross plot (Figure 5-21). This difference in source rock potential evaluation is attributed to considerable heavy hydrocarbon content in this particular sample. The bimodal profile shown on the Rock-

Eval S2 pyrogram (Figure 5-23) possibly resulted from heavy hydrocarbons. The NSO compounds in sample No. 7 may be concentrated due to an expulsion of hydrocarbons. The Middle Triassic Moolayember Formation contains mainly Type III kerogen within the early mature zone, except for the intervals that are locally heated by igneous intrusions.

In the Gunnedah Basin, the Permian Goonbri Formation shows a significant variation in the amount of organic carbon, which categories the sequence as a ‘good to excellent source rock’. The analysed carbonaceous siltstone (#39) and coal (#40) samples have good genetic potential and are able to be a fair oil source. These parameters are consistent with the type of organic matter preserved in these two samples, which is mainly Type II kerogen. The shale sample (#43), however, has a poor source potential,

145 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

consistent with the low HI (59 mg HC/g TOC) value. The Goonbri Formation is immature in Bellata-1, but within the early mature stage in Bohena-1. The Permian Maules Creek Formation has a relatively good hydrocarbon generation capability, similar to the Goonbri Formation, but the average HI is higher in the latter sequence. In addition, the Maules Creek Formation is mainly immature to marginally mature.

However, these two Permian sequences have intervals with suppressed Tmax values. The Watermark/Porcupine Formation is highly heat affected due to igneous intrusions. Organic matter at such high maturity intervals has already lost its capability to generate oil, and it is expected that the produced hydrocarbons have already been expelled from the sequence. Furthermore, the total amount of organic carbon would also be expected to be reduced at such a high level of maturity. The residual source potential for the Watermark/Porcupine Formation, however, based on the analysed samples is poor, and the formation is located within the gas source field (Figure 5-15), which is consistent with the high maturity level of the formation. The Permian Black Jack Group, based on a marginally mature sample (#41), contains ‘excellent’ TOC with a moderate genetic potential. This sample is located within the ‘fair oil’ field (Figure 5-18), and contains Type II/III kerogen. Other postmature samples (#46, #47 and #48) are located within the gas source field (Figure 5-18), which is consistent with the maturity level of these samples. Sample Nos. 46 and 47, however, show high S2 (Figure 5-17a), but these are most likely inaccurate based on these samples maturity level (Table 5-1).

The Middle Triassic Napperby Formation in the Gunnedah Basin has a ‘good to excellent’ TOC content, and a poor to good genetic potential. The formation contains Type II/III and Type III kerogen, and is capable of generating gaseous as well as liquid hydrocarbons. The Napperby Formation is partially within the peak mature zone, and in places is postmature. Although sample No. 36 has a vitrinite reflectance equal to 2.21%, o it shows a Tmax value of only 348 C. The low value of Tmax is attributed to pyrobitumen o content, which forms a peak at a pyrolysis temperatures of less than 400 C in the S2 profile (Figure 5-27). The output of this peak is added to the actual S2 amount that is generated from kerogen cracking, which in turn has increased the S2 total value in this sample. Accordingly this postmature sample shows a relatively high hydrocarbon genetic potential (Table 5-2), which is considered inaccurate.

146 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

Samples were also selected from the Evergreen Formation and Walloon Coal Measures within the Surat Basin sequence overlying Bowen Basin succession. The Evergreen Formation has a ‘very good to excellent’ TOC content, with moderate to good genetic potential. The sequence contains Type II/III and Type III organic matter, which is partially within the early mature stage and able to generate gaseous and liquid hydrocarbons. The Walloon Coal Measures is a better hydrocarbon source rock than the Evergreen Formation and contains significant amounts of Type II kerogen. The organic matter in the Walloon Coal Measures, however, is immature in the study area. A siltstone sample from the Purlawaugh Formation in the Surat Basin, overlying the Gunnedah Basin, was analysed by Rock-Eval pyrolysis. The sample is classified as ‘good’ in terms of TOC content, but has a poor genetic potential which is consistent with the Type III kerogen present (Figure 5-26). Based on this sample the Purlawaugh Formation from the Bellata-1 well is marginally mature.

The sequences studied contain mainly terrigenous organic matter, as shown by the high molecular weight predominance in the n-alkane chromatograms, where CPI ratios are more than unity. They were deposited mainly in oxic environments, as identified from the relatively high pr/ph ratios. Exceptions are the mature samples, which show maxima in the low molecular weight n-alkanes and decline smoothly towards high molecular weights, and have CPI ratios just above the unity. In these samples in particular, this phenomenon reflects mainly organic matter maturity effects rather than variation in the input source material. Marine influence is not identified from the n-alkane distributions. This might be attributed to the high proportion of terrestrial material in the marine influenced environment.

Among the studied sequences, the Walloon Coal Measures has the best combination of features to generate liquid hydrocarbons. However, the sequence is considered only a potential source rock, because based on the analysed samples Tmax values, the Walloon Coal Measures is immature in the study area. Also based on the analysed samples, the Moolayember and Purlawaugh Formations, probably, have a lower capability to generate liquid hydrocarbons than the other sequences in the study area. The Tmax values for these units indicate that the sedimentary sequences in the study area reached the early mature zone (e.g. sample No. 25; Table 5-1). The sequence is within the peak mature zone (sample No. 45, Table 5-1), and in places postmature (e.g. sample No. 50;

147 Chapter 5 SOURCE ROCK EVALUATION – ROCK-EVAL AND EXTRACT GEOCHEMISTRY

Table 5-1), where the units are locally heated due to igneous intrusions. As with the vitrinite reflectance (Chapter 4), the Tmax values are suppressed within the sequences containing perhydrous organic matter due to marine influence (e.g. Maules Creek Formation), or with a high liptinite content (Goonbri Formation). However, it seems that generation maturity parameters (e.g. bitumen/TOC ratio) were not suppressed, and hydrocarbons continued to be produced in amounts increasing regularly with burial depth even within the vitrinite reflectance and Tmax suppressed intervals (Othman and Ward, 2003).

Rock-Eval S1 increases, as expected, with increasing extractable organic matter, because the S1 peak basically represents the free hydrocarbons in the source rock samples. However, various amounts of free bitumen may be released by different analytical procedures. As illustrated in Figure 5-37, a better correlation is apparent in the hydrocarbons versus S1 cross plot, which means that more NSO compounds may be extracted with organic solvents than by temperature distillation over the Rock-Eval S1 temperature interval. The free non-resolved bitumen in such cases would be added to the S2 peak. This may affect all parameters based on S1 or S2 quantity, and might lead to inaccurate source rock evaluation based on these parameters alone (sample No. 36 for example). This is mainly significant when a large amount of free bitumen included in the S2 peak. The problem, however, can be identified from the pyrogram (Figure 5-27). Because of such variations, applying more than one method is advisable, if possible, as different analyses may evaluate the same samples differently.

As expected there is a good relation between S2 amount and the amount of the total organic carbon in the analysed samples. A regular increase of the quantity of pyrolysis yield shown by S2 can be observed with increasing TOC content in samples with comparable organic matter quality, which are within an equivalent maturity level (e.g. Figure 5-5a). An abnormality to this can be observed for sample No. 25 for example, (Figure 5-2a), and can be attributed to the organic matter type (Figures 5-4), while in sample No. 48 (Figure 5-17a) it is due to organic matter thermal maturity level.

148 Chapter 6 BIOMARKERS

6. Chapter 6 BIOMARKERS

6.1. Introduction

In this chapter, selected source rock samples from Permian, Triassic and Jurassic sequences in the southern Bowen and Northern Gunnedah Basins and the overlying Surat Basin succession were further investigated based on molecular parameters of various sets of saturated and aromatic hydrocarbons.

The outcomes of this study assisted in further identification of the source input and in evaluation of thermal maturity in the sequences studied. They also included an evaluation of the changes in various saturated and aromatic maturity parameters in intervals with suppressed vitrinite reflectance and Tmax values in the Permian sequence. In addition, the outcomes assisted in investigation of the origin of oil traces identified in the Jurassic Pilliga Sandstone in the Bellata-1 well, and assisted further in relating this oil stain to its source rock. This study, however, is discussed separately in Chapter 7.

6.2. Concept

All living organisms are composed of the same basic chemical constituents: lipids, proteins and carbohydrates, as well as lignins in higher plants. However, there are very characteristic differences with respect to the relative abundances of these compounds and their detailed chemical structure in different organisms and their end products (Tissot and Welte, 1984). Organic geochemistry studies the distribution, composition, and fate of organic matter in the geosphere, both at bulk and molecular levels, combining aspects of geology, chemistry and biology (Rullkötter, 1987).

Biomarkers (biological markers or molecular fossils) are derived from biological precursor molecules in specific organisms that existed under certain environmental conditions. Thus, biomarkers are indicators of those prevailing conditions. They are complex organic compounds composed mainly of carbon, hydrogen, and other elements which are found in oil, bitumen, rocks, and sediments and show little or no change in structure from their parent organic molecules in living organisms (Peters and Moldowan, 1993). 149 Chapter 6 BIOMARKERS

Biomarkers exist because their carbon skeletons survive, in a recognisable form, the processes of diagenesis and thermal alteration associated with burial (Mackenzie, 1984). In general, the structure of a biomarker is specific to a particular organic matter input and its environmental/depositional conditions, and can be traced back to the natural precursors in algae, other plants or bacteria from which they are derived (Fenwick et al., 2000).

Biomarker distributions can be measured in both oils and source rock bitumens, thereby providing a powerful correlation tool, which can also be used to infer the characteristics of the petroleum source rock(s) when only oils are available. These include aspects of source rock lithology and age, as well as the extent of hydrocarbon biodegradation (Peters and Moldowan, 1993). Biomarkers can also provide crucial information on the nature of preserved organic matter in the source rock, and the environmental conditions during its deposition, burial diagenesis, and later catagenesis due to thermal maturation. However, these factors (i.e. source, maturity, depositional environment and the extent and timing of biodegradation) are largely interrelated and, must be considered collectively when interpreting biomarker distributions (Murray and Boreham, 1992). In other words, a single biomarker is less effective in defining organic matter type, source rock lithology or depositional environment than a number of biomarkers (Arouri, 1996). Biomarker and non-biomarker geochemical parameters are best combined to provide the most reliable geological interpretations (Peters and Moldowan, 1993).

6.3. Identification

This section deals with a selected assemblage of saturated and aromatic hydrocarbon biomarkers identified in this study of the southern Bowen, northern Gunnedah and the lower part of the overlying Surat Basins in northern New South Wales. Compounds were identified on the basis of their mass chromatograms and relative retention times, in comparison with standard samples and published literature. Relative abundances of the different compounds were measured from peak areas in the respective SIM (selective- ion-monitoring) mass chromatograms.

150 Chapter 6 BIOMARKERS

6.3.1. Triterpanes

6.3.1.1. Identification

The m/z 191 fragmentogram was used to measure hopanes and other terpanes such as tricyclics and tetracyclics, while methylhopanes were detected on the m/z 205 trace. Below are details of these biomarker compounds (Figures 6-1 and 6-2):

6.3.1.1.1. Hopanes and moretanes

The hopanes are cyclic alkanes consisting of four six-membered rings (A to D), one five-membered ring (E) and a side chain containing up to 8 carbon atoms. Hopanes are a class of the triterpane family, and the parent compound 17α(H),21β(H) hopane has 30 carbon atoms, three of which are in the side chain. It is possible for the hopanes to have certain hydrogen atoms either above (β) or below (α) the plane of the ring system, with positions 17 and 21 being the most important locations where epimerisation/isomerisation occurs. The hopanes are composed of three stereoisomeric series, namely 17α(H),21β(H)-hopanes, 17β(H),21β(H)-hopanes, and 17β(H),21α(H)- hopanes. Compounds in the 17β(H),21α(H)- series, which may be abbreviated as “βα” are called moretanes (Peters and Moldowan, 1993). The most stable compounds and therefore the ones found in mature sediments and oils are those with αβ configuration. Compounds with ββ arrangement are the least stable and are only found in very immature samples, and those with the βα configuration are of intermediate stability and are found as minor components in marginally mature oils and sediments (Murray and Boreham, 1992).

6.3.1.1.2. Homohopanes

These are ‘extended’ hopane compounds with more than 30 carbon atoms, the homo- prefix referring to additional methylene groups on the parent (C30 hopane) molecule

(e.g. C32 bishomohopane). Homohopanes show an extended side chain with an additional asymmetric centre at C-22, resulting in two peaks for each homologue (22S

151 Chapter 6 BIOMARKERS

Figure 6-1: Terpanes structures identified in this study.

152 Chapter 6 BIOMARKERS

Figure 6-1: Terpanes structures identified in this study continued.

153 Chapter 6 BIOMARKERS

m/z 191

7

10

17α(H)-homohopanes

12

13 1 8 14 2 5 6 15 16 11 3 9 17 18 19 20 4 21

Figure 6-2: Hopanes gas chromatogram (for peak identification see Table 6-1).

Table 6-1: Identification of peaks in Figure 6-2.

Peak No. Identification

1 18α(Η),21β(H)-22,29,30-trisnorneohopane, Ts, (C27) 2 17α(Η),21β(H)-22,29,30-trisnorhopane, Tm, (C27) 3 17α(Η),18α(H),21β(H)-25,28,30-trisnorhopane (C27) 4 17α(Η),18α(Η),21β(H)-29,30-bisnorhopane (C28) 5 17α(Η),18α(Η),21β(H)-28,30-bisnorhopane (± C29*) 6 17α(Η),21β(H)-25-norhopane (C29) 7 17α(H),21β(H)-30-norhopane (C29) 8 18α(H)-30-norneohopane (C29Ts) 9 17α(H)-diahopane (C30*) 10 17α(H),21β(H)-hopane (C30) 11 17β(H),21α(H)-moretane (C30) 12 22S 17α(H),21β(H)-30-homohopane (C31) 13 22R 17α(H),21β(H)-30-homohopane (C31) 14 22S 17α(H),21β(H)-30,31-bishomohopane (C32) 15 22R 17α(H),21β(H)-30,31-bishomohopane (C32) 16 22S 17α(H),21β(H)-30,31,32-trishomohopane (C33) 17 22R 17α(H),21β(H)-30,31,32-trishomohopane (C33) 18 22S 17α(H),21β(H)-30,31,32,33-tetrakishomohopane (C34) 19 22R 17α(H),21β(H)-30,31,32,33-tetrakishomohopane (C34) 20 22S 17α(H),21β(H)-30,31,32,33,34-pentakishomohopane (C35) 21 22R 17α(H),21β(H)-30,31,32,33,34-pentakishomohopane (C35)

154 Chapter 6 BIOMARKERS and 22R) on the mass chromatograms for these compounds (Peters and Moldowan, 1993).

6.3.1.1.3. Norhopanes

Norhopanes are hopanoid compounds containing less than 30 carbon atoms in the chain, with a prefix to show how many carbon atoms are missing. A numbering system is used to identify the missing carbon atoms positions; for example, 30-norhopane or 30-nor- 17α(H)-hopane has a methyl group missing from the C-30 position and 29,30- bisnorhopane (BNH) has methyl groups missing at both the 29 and 30 positions (e.g.

Murray and Boreham, 1992). The C28 28,30-BNH and 29,30-BNH; and C27 17α(H)- 22,29,30-trisnorhopane (Tm) and 25,28,30-trisnorhopane (TNH) are the most common norhopanes (Peters and Moldowan, 1993).

6.3.1.1.4. Diahopanes and neohopanes

These are rearranged hopanes, compounds in which a methyl group has undergone migration from one position on the ring system to another. In the case of the diahopanes, the migration is from the C-14 to the C-15 position, whereas for the neohopanes it is from the C-18 to the C-17 position (e.g. Murray and Boreham, 1992).

The 17α(H)-diahopanes are represented by a number of homologues in the C29-C34 range. The C27 18α(H)-22,29,30-trisnorneohopane (Ts) and its C29 analogue 18α(H)-30- norneohopane (C29Ts) are the most common neohopanes (Summons et al., 1988a, 1988b; Moldowan et al., 1991a).

6.3.1.1.5. Methylhopanes

The methylhopanes have an extra methyl group attached to the ring system as distinct from the side chain. The most common methylhopanes found in sediments and oils are the 2α- and 3β-methyl-17α(H),21β(H)-hopanes (Murray and Boreham, 1992; Summons and Jahnke, 1992).

155 Chapter 6 BIOMARKERS

6.3.1.1.6. Tricyclic terpanes

These terpanes commonly range from C19 to C29 with the C23 component often dominant (Figure 6-3). Homologous series up to C54, however, have also been identified (de Grande et al., 1993). The tricyclics with more than 25 carbon atoms exist as the S and R epimers, because they have side chains containing a chiral centre at C-22 (Kruge et al., 1990a, 1990b). These epimers often occur in approximately equal abundances

(Ekweozor and Strausz, 1983). Above C29 compound the tricyclic terpanes are often obscured by the hopanes (Farrimond et al., 1999), as both compound classes have m/z 191 as their base peak and may co-elute on some GC-MS instruments unless analysed in metastable-reaction-monitoring (MRM) mode or using GC-MS-MS.

6.3.1.1.7. Tetracyclic terpanes

Tetracyclic terpanes range from C24 to C27, with tentative evidence for homologues up to C35 (Aquino Neto et al., 1983), and can conveniently be identified on the m/z 191 trace (Figure 6-3). The C24 tetracyclic terpane shows the most widespread occurrence among all related homologues (Peters and Moldowan, 1993).

6.3.1.2. Terpanes as source and environmental indicators

The precursors of the most common triterpane biomarkers are believed to be triterpenoids in bacteria. Various microorganisms in different depositional environments yield a wide variety of triterpenoids. These compounds are therefore useful indicators of the depositional and diagenetic conditions of various environments, as well as their biota (Waples and Machihara, 1990, 1991).

6.3.1.2.1. C29 and C30 hopanes

The C29 and C30 17α(H)-hopanes are the two dominant triterpanes in most geological samples (Waples and Machihara, 1990). High concentrations of C29 17α(H)-hopane have been recorded in oils and extracts from organic-rich carbonate and evaporite source rocks (Connan et al., 1986; Clark and Philp, 1989; Picha, 1996; Klecker et al.,

2001). This phenomenon is attributed to additional input of the C29 homologue of the

156 Chapter 6 BIOMARKERS

m/z191

5 Ts

8 Tm

10 6 9 3 2 4 7 1

Figure 6- 3: Tricyclic terpanes gas chromatogram (see Table 6-2 for peak identification).

Table 6- 2: Identification of peaks in Figure 6-3.

Peak No. Compound name

1 C19 Tricyclic terpane 2 C20 Tricyclic terpane 3 C21 Tricyclic terpane 4 C22 Tricyclic terpane 5 C23 Tricyclic terpane 6 C24 Tricyclic terpane 7 C25 Tricyclic terpane 8 C24 Tetracyclic terpane 9 C26 Tricyclic terpane 10 C30 Tricyclic terpane

157 Chapter 6 BIOMARKERS

30-nor-17α(H)-hopane series (Subroto et al., 1991). Thus, high values (>1) for the

C29/C30 hopane ratio can be expected in these lithologies and their derived hydrocarbons. However, high 30-norhopane contents are not always associated with carbonates (Waples and Machihara, 1991); high ratios were recorded for Upper Carboniferous coals from Madagascar (Ramanampisoa et al., 1990), where they can only be attributed to enhanced input of land plants (see also Brooks, 1986). The predominance of C30 hopane over 30-norhopane (C29/C30 hopane<1), on the other hand, is a common feature of oils derived from clay-rich, shale source rocks (e.g. Gürgey, 1999).

6.3.1.2.2. Homohopanes

The most common distributions of 17α(H)-extended hopanes with a regular decrease in abundance from the C31 to C35 members usually represent clastic facies (Waples and Machihara, 1991) or a clay-rich character of the source rocks (Obermajer et al., 1999).

An abundant C35 homohopane component may be related to extensive bacterial activity in the depositional environment (Peters and Moldowan, 1993). Large amounts of the C35

17α(H)-extended hopanes, and hence high values of the C35-homohopane index [or simply homohopane index which is the C35/(C31 to C35) homohopanes ratio (Peters and Moldowan, 1993)], are commonly associated with marine carbonate or evaporite sediments (ten Haven et al., 1988; Clark and Philp, 1989). However, Peters and

Moldowan (1991) suggested that high C35-homohopane indices are typical of oils sourced from rocks deposited under anoxic marine conditions. The homohopane distributions are also affected by secondary processes; for example, the homohopane index decreases with increasing API gravity and thermal maturity of related oils from the Monterey Formation, offshore California (Peters and Moldowan, 1991).

6.3.1.2.3. 28,30-BNH and 25,28,30-TNH

The desmethylhopanes BNH and TNH occur as 17α,18α,21β(H)-, 17β,18α,21α(H)-, and 17β,18α,21β(H)-epimers. The 25,28,30-TNH is believed to be the degradation products of the 28,30-BNH compounds (Volkman et al., 1983a; Moldowan et al., 1984). No biological precursor for this group has yet been identified, and their origin is still

158 Chapter 6 BIOMARKERS unclear (Nytoft et al., 2000). BNH and TNH occur as free hydrocarbon compounds in the source rock bitumen that is released directly as oil without breaking down the kerogen (Moldowan et al., 1984; Nobel et al., 1985; Tannenbaum et al., 1986). The BNH/TNH ratio can be used to relate oils to their source rocks (Tannenbaum et al., 1986). High abundance of BNH and TNH in petroleum indicates that the source rock was deposited under anoxic conditions (Katz and Elrod, 1983). However, the absence of these compounds does not exclude anoxia (Peters and Moldowan, 1993).

6.3.1.2.4. 17α(H)-diahopane (C30*) and 18α(H)-30-norneohopane

(C29Ts)

The 17α(H)-diahopane was first noted in terrestrially sourced oils by Volkman et al. (1983b) and Philp and Gilbert (1986) as an unknown terpane, but has later been identified as diahopane C30* by Peters and Moldowan (1993). However, Telnaes et al. (1992) reported diahopanes and norneohopanes in lacustrine oil samples, and suggested that their distributions vary with the salinity of the depositional environment. The occurrence of C30* in oils may be related to bacterial hopanoid precursors that have undergone oxidation in the D-ring and rearrangement by clay-mediated acidic catalysis.

The greatest abundances of C30* have generally been found in terrestrial oils and their clayey source rocks that are rich in terrestrial organic matter deposited under oxic to suboxic conditions (Peters and Moldowan, 1993). The relative abundance of C30* and

C29Ts depends most strongly on the environment of deposition, where oils derived from shales deposited under oxic-suboxic conditions show higher C30*/C29Ts ratios than those derived from source rocks deposited under anoxic conditions. Increasing thermal maturity should increase the ratio of 17α(H)-diahopane to both 18α(H)-30- norneohopane or 17α(H)-hopane, due to the higher thermal stability of C30* (Peters and Moldowan, 1993).

6.3.1.2.5. Methylhopanes

The most noticeable series of methylhopanes are the 2α-methyl-17α(H),21β(H)- hopanes and 3β-methyl-17α(H),21β(H)-hopanes, with the latter isomers being less widely distributed than the former hopanoids (Summons and Jahnke, 1992).

159 Chapter 6 BIOMARKERS

Methylotrophic bacteria, common in calcareous lithologies (Bisseret et al., 1985), are the likely precursors for 3-methylhopanes whereas cyanobacteria are the likely precursors for the 2-methylhopanes (Summons et al., 1999; Farrimond et al., 2003).

6.3.1.2.6. Tricyclic terpanes

Tricyclic terpanes are found in most oils and bitumens (Aquino Neto et al., 1983; Farrimond et al., 1999). Various precursor biota have been suggested for these compounds. These include prokaryotic membrane lipids (Ourisson et al., 1982), specific (Tasmanites) algae (Volkman et al., 1989; Simoneit et al., 1993; Revill et al., 1994) and higher plants (Peters and Moldowan, 1993). The ubiquitous occurrence of tricyclic terpanes in sediments and oils of varying ages demonstrates that numerous sources must be involved (Farrimond et al., 1999). Aquino Neto et al. (1983) noted that the higher tricyclic terpane homologues (26 or more carbon atoms) were often in low abundance in carbonate samples compared with other lithologies, where they could be of the same order of magnitude as the other members of the series (C19-C25 homologues). Tricyclic terpanes ranging from C20 to at least C41 have been reported in mature lacustrine black shale in association with negligible amounts of hopanes and steranes (Kruge et al., 1990a, 1990b). Others (e.g. De Grande et al., 1993) have found wider ranges of tricyclic terpane series (C19 to C54) to be prominent in rock samples from saline lacustrine and marine carbonate settings. Although the ratio of tricyclic terpanes/17α(H)-hopanes is dependent primarily on source input and/or environmental factors, it increases with maturity. At high thermal maturity, these compounds are released from kerogen at higher rates compared to 17α(H)-hopanes due to their higher thermal stability (Peters et al., 1990).

6.3.1.2.7. Tetracyclic terpanes

Abundant C24 tetracyclic terpanes in oils and extracts appear to be a marker for evaporitic and carbonate sequences (Connan et al., 1986; Clark and Philp, 1989; Jones and Philp, 1990). However, relatively high concentrations of the C24 tetracyclic terpane characterised oils derived from terrigenous source material (Philp and Gilbert, 1986).

The C25 to C27 tetracyclic terpanes have also been reported in carbonate and evaporite

160 Chapter 6 BIOMARKERS sources (Aquino Neto et al., 1983; Connan et al., 1986), but they do not appear to be present in abundance in other types of sediments (Waples and Machihara, 1991).

6.3.1.3. Terpanes as maturity indicators

Inherited from their precursor (i.e. biological) molecules, immature forms of hopanes have the 17β(H),21β(H) configuration in the ring structure, with the chiral centre at C- 22 in the R configuration. With a slight increase in maturity, the ββ-hopanoid transforms into the βα isomer (moretane) in the early stages of catagenesis. With a further increase in maturity the more stable αβ-hopanes appear and become predominant in mature oils and sediments (Murray and Boreham, 1992).

6.3.1.3.1. 22S or 22S/(22S+22R) Homohopane ratio

Hopane epimerisation at the C-22 position is often applied for thermal maturity evaluation and highly specific for the immature to early stages of oil generation.

Chandra et al. (1994) correlated different maturity parameters and reported that C32 homohopane ratio shows a most distinct inflexion associated with a rapid increase up to the oil generation threshold, followed by very little change after the threshold. Typically

C31- or C32-homohopane homologues are used for calculation of the 22S/(22S+22R) ratio. During maturation, the ratio rises from 0 to about 0.6 (equilibrium occurs between 0.57 and 0.62; Seifert and Moldowan, 1986). The equilibrium stage is the end-point of the reaction in the oil generation zone (Brooks et al., 1992). Samples showing 22S/(22S+22R) ratios in the range 0.50 to 0.54 have barely entered the zone of oil generation, while ratios in the range 0.57 to 0.62 indicate that the main phase of oil generation has been reached or surpassed (Peters and Moldowan, 1993). However, this ratio is influenced by lithology, where immature evaporitic (ten Haven et al., 1986) and carbonate (Moldowan et al., 1992) rocks show mature hopane patterns.

Reversal of the 22S/(22S+22R) homohopane ratio was recorded in closed-system pyrolysis experiments (Lu et al., 1989; Abbott et al., 1990; Peters et al., 1990). This phenomenon has also been observed in sedimentary sequences rapidly heated due to igneous intrusions (Raymond and Murchison, 1992; Bishop and Abbott, 1993;

161 Chapter 6 BIOMARKERS

Farrimond et al., 1996). The ratio of 22S/(22S+22R) is mostly controlled by the kinetic balance of release/generation and loss, rather than direct chiral epimerisation in the saturated hydrocarbon fraction, although the latter cannot be ruled out as a contributor to an admixture of processes (Bishop and Abbott, 1993). Farrimond et al. (1996) concluded that changes in this ratio are not based upon a simple 22R to 22S conversion, but rather depend on the relative rates of generation and destruction of these epimers. Towards the onset of the oil window, the 22S abundance increases more sharply causing an increase in the parameter (Farrimond et al., 1996). Within the oil window, the 22R isomer is apparently destroyed more rapidly than the 22S; hence the continuous increase in the 22S/(22S+22R) ratio. At the later stages of the oil window, close to an igneous intrusion, the abundance of both S and R epimers is significantly reduced, probably with faster destruction of the S configuration, giving rise to the slight inversion in this parameter (Farrimond et al., 1996).

6.3.1.3.2. Moretane/hopane ratio

With increasing maturity, the proportion of moretanes is noticed to decrease relative to 17α(H)-hopanes (e.g. Mackenzie et al., 1980). The biological 17β(H),21β(H)- configuration (ββ) of hopanoids in organisms is unstable, and therefore it readily converts to βα-moretane following deposition, and later into a αβ-hopane configuration upon maturation. The moretanes are less stable than 17α(H)-hopanes (Waples and Machihara, 1990). Consequently, the ratio of 17β(H),21α(H)-moretanes to their corresponding 17α(H),21β(H)-hopanes decreases with increasing thermal maturity, from about 0.8 in immature sediments to about 0.15-0.05 in mature source rocks and oils (Mackenzie et al., 1980; Seifert and Moldowan, 1980). The C30 compounds are commonly used to quantify the moretane/hopane ratio (Peters and Moldowan, 1993), although C29 homologues can also be used (Seifert and Moldowan, 1980; Mackenzie et al., 1980). On their study of Carboniferous coals, ten Haven et al. (1992) concluded that the moretane/hopane ratio is controlled by their differing rates of destruction upon increasing maturation. Grantham (1986) found that oils from Tertiary sources often have higher ratios than older samples. However, organic matter input and the prevailing environment also affect the ratio. For example, Rullkötter and Marzi (1988) noted higher ratios in hypersaline settings.

162 Chapter 6 BIOMARKERS

6.3.1.3.3. Ts/(Ts+Tm) ratio

The Ts/(Ts+Tm) ratio (sometimes reported as Ts/Tm) is extensively applied in petroleum geochemistry as maturity parameter (Farrimond et al., 1996), although it is susceptible to source and facies variability in source rocks (Seifert and Moldowan,

1978; Moldowan et al., 1986; Rullkötter and Marzi, 1988). During catagenesis, the C27 17α(H)-22,29,30-trisnorhopane (Tm) possesses lower thermodynamic stability relative to that of C27 18α(H)-22,29,30-trisnorneohopane (Ts). Therefore, the ratio increases with organic maturity (Seifert and Moldowan, 1978), and it is most reliable as a maturity indicator in samples with identical organic matter (Peters and Moldowan, 1993). The ratio is particularly useful in the oil window, where it responds sensitively to maturity increments before approaching unity in zones of higher maturity (Murray and Boreham, 1992). Furthermore, the ratio appears to be sensitive to catalysed reactions (Peters and Moldowan, 1993). McKirdy et al. (1983) found that oils derived from carbonate source rocks have anomalously low Ts/(Ts+Tm) ratios compared to those generated from shales.

6.3.1.3.4. C29Ts/C29 hopane ratio

The thermal stability of 18α(H)-30-norneohopane (C29Ts) is greater than 17α(H)-30- norhopane (Kolaczkowska et al., 1990). Consequently, the C29Ts/C29 hopane ratio increases with maturity (Fowler and Brooks, 1990), and changes in this ratio are suggested to be solely related to thermal maturity variations (e.g. Riediger et al., 1990).

6.3.1.3.5. Tricyclic terpanes

Tricyclic terpanes have been applied successfully as molecular maturity parameters. With increasing thermal maturity the ratio of tricyclic terpanes to 17α(H)-hopanes increases for genetically related oils (Seifert and Moldowan, 1978). This is attributed to the greater rate of generation from kerogen of tricyclics compared to hopanes at higher levels of maturity (Aquino Neto et al., 1983) and/or due to the higher relative thermal stability of the tricyclic terpanes (van Grass, 1990). However, because the tricyclics and the hopanes are derived from different precursors in bacterial membranes (Ourisson et 163 Chapter 6 BIOMARKERS al., 1982) the ratio can vary considerably between petroleum from different organic facies (Peters and Moldowan, 1993).

The C23 tricyclic terpane decreases in abundance with increasing maturity relative to the

C21 and C24 homologues (Ekweozor and Strausz, 1983; Cassani et al., 1988). However, in their study on a sequence affected by igneous intrusion, Farrimond et al. (1999) indicated that the ratio of C23/C21 tricyclic terpanes increases through the oil window due to the greater rate of generation of the C23 component and the earlier thermal degradation of the C21 tricyclic terpane.

6.3.1.3.6. Tetracyclic terpanes

With increasing maturity the C24 tetracyclic terpane is released from kerogen and possibly asphaltenes or other polar fractions (Farrimond et al., 1999), resulting in an increase in its concentrations relative to the C23 tricyclic terpane, as is indicated from laboratory heating experiments on a crude oil (Aquino Neto et al., 1983).

6.3.2. Steranes

6.3.2.1. Identification

Steranes are a class of saturated tetracyclic-structured hydrocarbon biomarkers constructed from six isoprene subunits, totaling approximately 30 carbon atoms (Peters and Moldowan, 1993). Steranes usually consist of four rings (Figure 6-4), the D-ring of which contain five carbon atoms (Waples and Machihara, 1990). In the current study, sterane biomarkers were detected by SIM GC-MS using m/z 217 for steranes, m/z 231 for methylsteranes, and m/z 259 for diasteranes. These are summarised in Table 6-3 and shown in Figures 6-4 and 6-5. A brief discussion follows.

6.3.2.1.1. Regular steranes

Steranes are diagenetic alteration products of sterols that represent one of the main constituents of eucaryotes (McCaffrey et al., 1994), and are common in most higher plants and algae but absent or rare in procaryotic organisms (Volkman, 1986). Sterol

164 Chapter 6 BIOMARKERS

Figure 6-4: Steranes, diasteranes and methylsteranes identified in this study.

165 Chapter 6 BIOMARKERS

m/z 217

9 18 12 1 17 22 21 15 2 7 8 10 5 23 4 13 20 11 16 6 14 3 19

Figure 6-5: Steranes gas chromatogram (see Table 6-3 for peak identification).

Table 6-3: Identification of peaks in Figure 6-5.

Peak No. Compound name

1 20S 13β,17α-diacholestane (C27) 2 20R 13β,17α-diacholestane (C27) 3 20S 13α,17β-diacholestane (C27) 4 20R 13α,17β-diacholestane (C27) 5 20S 24-methyl-13β,17α-diacholestane (C28) 6 20R 24-methyl-13β,17α-diacholestane (C28) 7 20S 24-methyl-13α,17β-diacholestane (C28) 8 20S 14β,17α-cholestane (C27) 9 20S 24-ethyl-13β,17α-diacholestane (C29) + 20R 14β,17α-cholestane (C27) 10 20S 14β,17β-cholestane (C27) 11 20R 24-methyl-13α,17β-diacholestane (C28) 12 20R 14α,17α-cholestane (C27) 13 20R 24-ethyl-13β,17α-diacholestane (C29) 14 20S 24-ethyl-13α,17β-diacholestane (C29) 15 20S 24-methyl-14β,17α-cholestane (C28) 16 20R 24-ethyl-13α,17β-dicholestane (C29) 17 20R 24-methyl-14β,17β-cholestane (C28) 18 20S 24-methyl-14β,17β-cholestane (C28) 19 20R 24-methyl-14α,17α-cholestane (C28) 20 20S 24-ethyl-14α,17α-cholestane (C29) 21 20R 24-ethyl-14β,17β-cholestane (C29) 22 20S 24-ethyl-14β,17β-cholestane (C29) 23 20R 24-ethyl-14α,17α-cholestane (C29)

166 Chapter 6 BIOMARKERS precursors containing 27, 28, 29 and 30 carbon atoms have been identified that give rise to four different “regular” steranes during diagenesis. The term “regular” indicates that the carbon skeletons are the same as in the biological precursor (Waples and Machihara, 1990). Steranes with less carbon atoms are also reported, although less commonly (e.g. Wingert and Pomerantz, 1986; Peakman et al., 1989; Moldowan et al., 1991b; Requejo et al., 1997). The commonly reported sterane series that includes C27 (cholestane), C28

(24-methylcholestane) and C29 (24-ethylcholestane) has been recognised in the current study. The smaller homologues, C21, C22 and C26, as well as the C30 24-n- propylcholestane, can also be significant in oil and rock samples from certain environments (Peakman et al., 1989). Various stereoisomers exist for each class of steranes (Murray and Boreham, 1992), with the C-5, C-14, C-17 and C-20 positions being the most important locations for isomerisation. Stereoisomers of the regular steranes are 5α(H),14α(H),17α(H),20R (abbreviated αααR, or simply ααR); 5α(H),14α(H),17α(H),20S (αααS); αββR and αββS (Arouri, 1996).

6.3.2.1.2. Diasteranes

Diasteranes are “rearranged steranes”, also known as “isosteranes” (Murray and Boreham, 1992). The rearrangement involves migration of methyl groups from ring positions C-10 and C-13 (in sterane) to C-5 and C-14, thereby forming diasterane (Waples and Machihara, 1991; Peters and Moldowan, 1993) (Figure 5-4). All four isomers 13β,17α(H),20R abbreviated βαR; 13β,17α(H),20S (βαS); αβR; and αβS are commonly reported for the C27, C28 and C29 diasterane series (Arouri, 1996).

6.3.2.1.3. Methylsteranes

Methylation in steranes may occur in the A-ring at the C-2, C-3 or C-4 positions (Peters and Moldowan, 1993), with the 4-methylsteranes being the most commonly reported (Waples and Machihara, 1991). Two distinct families of 4-methylsteranes have been identified. These are dinosteranes and 4-methylcholestanes. Dinosteranes exist only as the various stereoisomers of the C30 homologue, and can be viewed as cholestane with three additional methyl groups at positions C-4, C-23 and C-24 (4α,23,24- trimethylcholestanes, Figure 5-4). On the other hand, the 4-methylcholestane can be considered as the three regular steranes (C27, C28 and C29) with an additional methyl

167 Chapter 6 BIOMARKERS group at the C-4 position only; thereby forming a homologous series with 28, 29 and 30 carbon atoms (e.g. C30 compound is 4α-methyl-24-ethylcholestane).

6.3.2.2. Steranes as source indicators

The steranes inherited directly from higher plants, animals and algae are the 20R epimers of the 5α(H),14α(H),17α(H) forms of the C27–C30 steranes. The relative proportions of each of these regular steranes can vary greatly from sample to sample, depending on the type of organic material contributing to the sediment (Waples and Machihara, 1991).

6.3.2.2.1. Steranes/17α(H)-hopanes ratio

The regular steranes/17α(H)-hopanes ratio reflects input of eukaryotic (mainly algae and higher plants) versus prokaryotic (bacteria) organisms to the source rock (Peters and Moldowan, 1993). The sterane/hopane ratio is relatively high in marine organic matter, with values generally approaching unity or even higher. In contrast, low steranes and sterane/hopane ratios are more indicative of terrigenous and/or microbially reworked organic matter (Tissot and Welte, 1984).

6.3.2.2.2. C27 : C28 : C29 regular steranes

The relative abundance of C27, C28 and C29 steranes has been found to be sensitive to organic matter type (e.g. Gürgey, 1999), and it is therefore a powerful oil-oil and oil- source correlation parameter (Seifert and Moldowan, 1978; Peters et al., 1989). Huang and Meinschein (1979) determined the significance of C27–C29 sterol distributions in providing organic source information. It has been indicated that C27 steranes are derived essentially from marine phytoplankton, whereas abundant C29 steranes indicate a strong contribution from higher plant organic matter. Consequently, predominance of C29/C27 steranes (>1) has commonly been reported in terrestrial plant-rich sediments (Czochanska et al., 1988), and the reverse has been observed in rocks containing marine algae. An abundance of C28 compounds may indicate a contribution by lacustrine algae

(Waples and Machihara, 1991). C27-C28-C29 sterane ternary plots have often been 168 Chapter 6 BIOMARKERS employed successfully for organic facies analysis based on the relative proportions of these sterane homologues. To establish these diagrams the 5α,14α,17α 20R isomer of the corresponding steranes can be used (Matsumoto et al., 1987; Arouri et al., 1998b), although Moldowan et al. (1985) used the sum of the 5α,14α,17α 20S and 20R and 5α,14β,17β 20S and 20R peaks obtained by GC-MS-MS analysis. However, caution should be applied when using such diagrams. Grantham (1986), for example, attributed the predominance of C29 steranes found in Precambrian-sourced oil in Oman to various algal sources, since land-plants did not exist in this period of geological time. Similarly, Rullkötter et al. (1986) concluded that such predominance in the Michigan Basin oils is not related to a strong influence of terrigenous organic matter. Furthermore, Brassel and

Eglinton (1983) found that marine organisms contain both C27 and C29 sterols, which could give rise to the related C27 and C29 steranes (Brooks et al., 1992). Volkman (1986, 1988) discovered that some marine sediments, including those deposited in pelagic environments far from terrigenous influence, do in fact show a predominance of C29 steranes.

The predominance of C28 steranes in oil samples is more source-specific. Dahl et al. (1994) related such predominance to the high abundance of oil-prone marine macerals in the associated kerogen. Grantham and Wakefield (1988) demonstrated that the

C28/C29 regular sterane ratio in marine environments is controlled by geological age, with younger samples systematically showing higher ratios. They discovered that the

C28/C29 regular sterane ratio is less than 0.5 for Early Paleozoic oils and greater than 0.7 in Late Jurassic to Miocene hydrocarbons. Peters and Moldowan (1993) attributed the increase in the C28 sterane to increased diversification of phytoplankton assemblages, including diatoms, coccolithophores and dinoflagellates, in the Jurassic and Cretaceous.

6.3.2.2.3. C27 : C28 : C29 diasteranes

Diasterane formation is generally favored in oxic environments (Peters and Moldowan, 1993), and its abundance increases with increasing maturity (Zumberge, 1987). Thus, the application of diasteranes as facies-indicator is complicated by their dependence on maturity as well as on depositional environment (Waples and Machihara, 1990).

Specificity of C27, C28 and C29-diasterane distributions is about the same as that of steranes. The C27-C28-C29 diasterane ternary plots can be used to support interpretations 169 Chapter 6 BIOMARKERS based on the analogous sterane ternary diagrams regarding genetic relationships between oils and source rock bitumens. The most important applications of diasterane plots are for heavily biodegraded oils, where steranes are altered but diasteranes remain intact, and for some highly mature oils and condensates that show low steranes but more abundant diasteranes (Peters and Moldowan, 1993).

6.3.2.2.4. Diasteranes/regular steranes

This ratio is influenced by lithology, maturity and biodegradation. The presence of diasteranes is generally attributed to clay-catalysed rearrangements of sterol and sterene precursors during diagenesis (Sieskind et al., 1979). Thus, high diasterane concentrations relative to regular steranes can be expected to occur in clay-rich source rocks and their hydrocarbon derivatives (e.g. Gürgey, 1999), and low ratios in oils indicate clay-poor, carbonate source rocks deposited under anoxic conditions (McKirdy et al., 1983). Clark and Philp (1989) found a plot of pr/ph ratios to diasterane/sterane ratios to be useful for delineating two oil groups and their source rocks. The diasteranes to regular steranes ratio is often used to distinguish between crude oils from carbonate and clastic facies (e.g. Czochansca et al., 1988; Mattavelli and Novelli, 1990). However, exceptions are recorded (Clark and Philp, 1989; Moldowan et al., 1992; Casareo et al., 1996; van Kaam-Peters et al., 1997). Casareo et al. (1996) linked the proportion of well- preserved tissues in a high-volatile bituminous coals and the positive abundance of steranes relative to diasteranes. van Kaam-Peters et al. (1998) indicated that the diasterane/sterane ratio correlates positively with the ratio of clay minerals to organic matter. It has also been found that the ratio increases with increasing maturation (Seifert and Moldowan, 1978) and biodegradation, for diasteranes are more resistant to biodegradation than steranes (Seifert and Moldowan, 1979; McKirdy et al., 1983; Cannon, 1984; Seifert et al., 1984). Goodwin et al. (1983) noted further the preferential removal of regular steranes compared to diasteranes under laboratory conditions of oil biodegradation.

6.3.2.2.5. 4-Methylsteranes

The 4-methyl sterol 4α,23,24R-trimethyl-5α-cholest-22E-en-3β-ol (dinosterol) is commonly used as an unambiguous biomarker for organic matter derived from 170 Chapter 6 BIOMARKERS dinoflagellates in sediments and seawater (Volkman et al., 1993). Thus, the presence in petroleum of the dinosteranes ―the geological derivative of dinosterol (Wolff et al., 1986; Summons et al., 1987)― is used as evidence for the presence of dinoflagellate organic matter in petroleum source rocks (Volkman et al., 1993). In addition, Thomas et al. (1993) proved that Dinophyceae are the major biological source of dinosteranes and some other 4-methylsteranes in marine sediments. However, marine unicellular prymnesiophyte algae of the genus Pavlova contain significant amounts of 4- methylsterols (Volkman et al., 1990), and certain bacteria (Methylococcus capsulatus) were proposed as an additional source (Bird et al., 1971). Diatoms have further been suggested as an alternative source of dinosterol/dinosterane in marine sediments, particularly those lacking obvious contributions of dinoflagellate organic matter (Volkman et al., 1993). Although, as discussed above, a direct biological contribution seems the most plausible source for dinosterol/dinosteranes, Difan et al. (1994) argue that some 4-methylsteranes may be a product of microbial activity during diagenesis.

Dinosteranes appear to be derived predominantly from marine dinoflagellates, and are therefore a useful biological marker for Mesozoic and Cainozoic marine organic matter (Summons et al., 1992) as these algae first became abundant during the Triassic (Summons et al., 1987; Goodwin et al., 1988). Conversely, the origin of 4α-methyl-24- ethylcholestanes, which are common in both marine and freshwater lacustrine samples, is still unclear (Peters and Moldowan, 1993), although their presence in the absence of dinosteranes is indicative of a lacustrine environment.

6.3.2.3. Steranes as maturity indicators

Sterane distributions in immature sediments are relatively simple. They are dominated by compounds with the R configuration at the C20, and hydrogen atoms at positions 5, 14 and 17 in the ααα configuration. With increasing maturity there is an increase in the relative abundance of the S diastereomers in the side chain, and of compounds with hydrogens in the αββ configuration in the ring system. These are the so-called “geological” counterparts of the original “biological” molecules. Both changes are used as maturity indicators as discussed below.

171 Chapter 6 BIOMARKERS

6.3.2.3.1. 20S/(20S+20R) ratio

With increasing thermal maturity the concentrations of (20R) 5α(H),14α(H),17α(H)-

C27, C28 and C29 steranes decrease relative to that of the corresponding 20S epimer (Mackenzie et al., 1980, 1982). This proportion has been expressed in a number of ways, including 20S/(20S+20R), %20S and 20S/20R (Waples and Machihara, 1990), and has been used to assess the thermal maturity for both sedimentary organic matter and crude oils (Mackenzie et al., 1980; Seifert and Moldowan, 1981). Maturity can be determined by following the change in the 20S/(20S+20R) ratio for any of the regular

C27, C28 or C29 steranes, but C29 is the least susceptible to overlapping peaks in the mass chromatogram (Waples and Machihara, 1990). The sterane isomerisation is highly specific for the immature to mature range (Peters and Moldowan, 1993) and is therefore widely used as thermal maturity indicator for sedimentary organic materials. The ratio of 20S/(20S+20R) rises from 0 with increasing maturity until an equilibrium is reached at 0.52–0.55 (Seifert and Moldowan, 1986) or at 0.5 (Gallegos and Moldowan, 1992). Within highly mature intervals (e.g. in the vicinity of igneous intrusions), a reversal of the 20S/(20S+20R) ratio was observed (Raymond and Murchison, 1992; Bishop and Abbott, 1993), a phenomenon also observed under laboratory conditions in hydrous pyrolysis studies (Lewan et al., 1986; Peters et al., 1990). This reversal can be ascribed to the greater loss of 20S compared to 20R (Bishop and Abbott, 1993).

Factors other than thermal maturity can affect sterane isomerisation ratio. Clayton and King (1987), for example, concluded that weathering has led to preferential loss of the

ααα 20S C29 sterane and the subsequent decrease in the 20S/(20S+20R) ratio. In contrast, biodegradation results in an increase of the ratio, apparently due to selective removal of the ααα 20R epimer by bacteria (McKirdy et al., 1983; Seifert et al., 1984). Immature samples in hypersaline environments may show a mature sterane appearance (ten Haven et al., 1985), probably due to the presence of specific steroid precursors in the original depositional environment (ten Haven et al., 1986). Zhusheng et al. (1988), based on laboratory simulations, studied fractionation effects on biomarkers and suggested that 20S-steranes elute from the source rock faster than 20R-steranes, resulting in higher 20S/(20S+20R) ratios in the expelled oil compared to that of the source rock.

172 Chapter 6 BIOMARKERS

6.3.2.3.2. ββ/(ββ+αα) ratio

The proportion of ββ/(ββ+αα) can simply be stated as %ββ. It expresses the intensity of isomerisation at the C-14 and C-17 positions, where the 14α(H),17α(H) sterane partially transforms upon maturation to 14β(H),17β(H) isomers in both the 20S and 20R forms (αα-20R, αα-20S, ββ-20R and ββ-20S), resulting in an increase in the

ββ/(ββ+αα) ratio from non-zero to about 0.7 with equilibrium for the C29 regular steranes occurring between 0.67 to 0.71 (Seifert and Moldowan, 1986). This diastereomer also exists for the C27 and C28 steranes, but are less frequently used due to the coelution of these homologues with other compounds on the m/z 217 chromatogram (Waples and Machihara, 1991). The ββ/(ββ+αα) ratio is very useful in maturity determinations for most oils and bitumens (Peters and Moldowan, 1993). However, in hypersaline environments the ratio could be higher than anticipated (ten Haven et al., 1986), and similar unusually high values can also be expected in samples from carbonate source rocks (McKirdy et al., 1983).

Seifert and Moldowan (1981) proposed a theoretical maturity curve on the basis that 14β(H), 17β(H)-steranes migrate faster than 14α(H), 17α(H)-steranes. By plotting the [5α,14β,17β(20R)] / [5α,14α,17α(20R)] ratio versus [5α,14α,17α(20S)] / [5α,14α,17α

(20R)] ratio for the C29 steranes, a petroleum maturity curve can be established. The distance from this curve yields a Biomarker Maturation Index (BMAI), and deviation from the BMAI-curve in favor of the [5α,14β,17β(20R)] / [5α,14α,17α(20R)]-axis may reflect changes due to migration. This plot is similar to that of the ββ/(ββ+αα) versus 20S/(20S+20R) ratios, which gives a straight-line rather than curved-line relationship (Peters and Moldowan, 1993).

6.3.3. Aromatic hydrocarbons

6.3.3.1. Identification

Aromatic hydrocarbon compounds identified for this study (Figures 6-6 and 6-7) were detected with GCMS of the total aromatic fraction by monitoring various molecular ion

173 Chapter 6 BIOMARKERS

Figure 6-6: Aromatic structures identified in this study.

174 Chapter 6 BIOMARKERS

6 13

5

9 10

7 8 11 12

3 4 1 2

m/z 156 m/z 170 m/z 178m/z 1 92m/z 2 06 m/z 219

Figure 6-7: Composite mass chromatograms (m/z 156 + 170 + 178 + 192 + 206 + 219) showing the distributions of dimethylnaphthalene (DMN), trimethylnaphthalene (TMN), phenanthrene (P), methylphenanthrene (MP), dimethylphenanthrene (DMP) and retene. See Table 6-4 for peak identification.

Table 6-4: Identification of peaks in Figure 6-7.

Peak No. Compound name 1 2,6-DMN 2 2,7-DMN 3 1,5-DMN 4 1,3,6-TMN 5 1,2,5-TMN 6 P 7 3-MP 8 2-MP 9 9-MP 10 1-MP 11 X-DMP 12 1,7-DMP 13 retene

175 Chapter 6 BIOMARKERS groups. Dimethylnaphthalenes (DMN) were measured on m/z 156 mass chromatogram, whereas trimethylnaphthalenes (TMN), phenanthrene (P), methylphenanthrenes (MP), dimethylphenanthrenes (DMP), and retene (7-isopropyl-1-methylphenanthrene) were measured respectively on m/z 170, m/z 178, m/z 192, m/z 206 and m/z 219 mass chromatograms (Figure 6-7, Table 6-4).

6.3.3.2. Aromatic hydrocarbons as source and environmental indicators

Although most aromatic compounds used as biomarkers do not occur as such in nature, their structures and characteristics are adequate to specify relationships with natural products. In turn, the nature of extant plants producing these natural products indicates the nature of the ancient plants that produced the precursors for the biomarkers (van Aarssen et al., 1996).

Alkyl naphthalenes and alkyl phenanthrenes are present in all oils and mature sediments, as they originate from both terrestrial and aquatic organic matter. However, the presence of certain isomers in abnormally high abundance hints at a contribution from specific types of organic matter (Murray and Boreham, 1992). Strachan et al. (1988) reported that the relative abundance of 1,2,5-TMN is much greater in low mature samples containing organic matter derived from higher plants than in samples without a higher plant input. It is therefore possible to link the 1,2,5-TMN found in sediments to specific natural product precursors found in higher plants. However, Norgate et al. (1999) reported that 1,2,5-TMN and retene often dominate in the lower rank coals, while more mature samples show an increase in the abundance of the phenanthrene isomers relative to trimethylnaphthalenes, associated with the loss of retene. Budzinski et al. (1995) suggested that the high abundance of 9-MP could be used as a marker for marine origin whereas 1-MP and 1,7-DMP appear as terrestrial indicators. However, 9- MP noted to occur in higher concentration in low mature Type III sourced oils (e.g. Budzinski et al., 1995). Murray and Boreham (1992) reported that retene is characteristic of conifers, and Alexander et al. (1987) suggested it to be an indicator of terrestrial organic matter; the ratio retene/9-MP has been applied as a higher land plant input indicator in a suite of Australian oils (Ellis et al., 1996).

176 Chapter 6 BIOMARKERS

The occurrence of certain higher plant biomarkers in crude oils and sediments also can be used as an indicator for the time of deposition, or the age of the petroleum source rocks (e.g. Alexander et al., 1988, 1992; Strachan et al., 1988). Suites of aromatic compounds that are indicative of plant resins, specifically from the Araucariaceae family (trees of the kauri pine group), have been identified in sediments of Jurassic age from the Eromanga Basin, but are absent (or in minimal abundances) in the underlying Permian-Carboniferous Cooper Basin (Alexander et al., 1988, 1992). Consequently, the relative abundance of 1-MP; 1,7-DMP; 1,2,5-TMN and retene as specific source indicators, expressed as ratios, has been shown to indicate that the contribution of Araucariacean (Agathis) flora remains essentially in the Jurassic sediments (Alexander et al., 1988, 1992). Since this family of conifers proliferated during Jurassic time, the relative abundance of these specific aromatics has been used as an age-specific marker for Jurassic and younger sediments and their inferred oils (Alexander et al., 1988, 1992; Boreham, 1994).

1,2,5-TMN may have formed from several natural product precursors found in higher plants. It subsequently reacts to give 1,3,6-TMN and other isomeric trimethylnaphthalenes, and hence the 1,2,5-TMN/1,3,6-TMN ratio is maturity dependant and decreases with increasing burial depth (Strachan et al., 1998). Alexander et al. (1988), however, identified Jurassic samples having a relatively high 1,2,5-TMN input within a moderate maturity zone, which may attributed to enhanced input of 1,2,5- TMN from Jurassic source material. Because the 1-MP and 9-MP isomers are similar in their thermodynamic stability (Radke et al., 1986), their relative abundance has been suggested as a purely source parameter, and the relative abundance of 1-MP has been calculated as a ratio to that of 9-MP (Alexander et al., 1988). As with 1,2,5-TMN, enhanced levels of 1-MP persist in sediments at moderate maturity; in this case, values greater than 1.0 for 1-MP/9-MP and 1.5 for 1,2,5-TMN/1,3,6-TMN have been taken to indicate an input from araucariacean flora and a Jurassic source affinity (Alexander et al., 1988). The value for 1-MP/9-MP was adjusted to 1.25 for the adjacent Bowen/Surat Basin sequence (Boreham, 1994, 1995). Using a cross-plot of log (1-MP/9-MP) versus log (1,2,5-TMN/1,3,6-TMN), Jurassic sediments and oils mainly plot in the upper right quadrant and those of Permian age in the lower left quadrant.

177 Chapter 6 BIOMARKERS

Two other aromatic biomarker ratios have further been devised to identify the age of source rocks and to better constrain oil-source correlations (Alexander et al., 1988). These are 1) the ratio of 1,7-DMP/X, where X is an unresolved mixture of 1,3-DMP, 2,10-DMP, 3,9-DMP and 3,10-DMP (Radke et al., 1986), and 2) the ratio of retene/9- MP. Values greater than 0.8 for the former, and greater than 0.3 (Alexander et al., 1988) or 0.4 (Boreham, 1995) for the latter, represent a Jurassic source affinity. On the cross- plot of these two parameters the Jurassic sediments again are predominantly located in the upper right quadrant and Permian samples in the lower left quadrant (see Chapter 7).

6.3.3.3. Aromatic hydrocarbon biomarkers as maturity indicators

For more than two decades, the distributions of aromatic hydrocarbon compounds in extracts of sedimentary organic matter and crude oils have been increasingly employed in thermal maturity evaluation (e.g. Radke et al., 1982a, 1982b, 1990; Radke and Welte, 1983; Alexander et al., 1984, 1985; Strachan et al., 1988; Budzinski et al., 1995; Wilhelms et al., 1998). Many of the aromatics are major hydrocarbon components, and occur in concentrations orders of magnitude higher than saturated hydrocarbon biomarkers, especially at higher maturities. As such, there is less likelihood of contamination by non-indigenous material such as drilling fluid oil (Murray and Boreham, 1992). The aromatic maturity parameters are formulated to reflect isomerisation and aromatisation reactions (Norgate et al., 1999). Generally, the α- substituted compounds are less stable than related isomers with β-substitution patterns (Figure 6-6, top). Consequently, upon maturation, the β/α ratios for specific groups of compounds often exhibit regular increase (Budzinski et al., 1995), although irregularities have been reported for some methylphenanthrene trends, particularly in the case of type II organic matter (Radke et al., 1986).

Based on the relative abundances of different isomers, various ratios and parameters have been suggested. The principle upon which the ratios are based is that the more thermodynamically stable isomers are favored at higher levels of thermal stress (Kruge, 2000). Probably one of the most widely used aromatic maturity parameters is the Methylphenanthrene Index (MPI) developed by Radke et al. (1982a). The parameter has been derived from the distribution of phenanthrene and four or three 178 Chapter 6 BIOMARKERS methylphenanthrene isomers (1-, 2-, 3-, and 9-MP) in type III organic matter, including coals (Radke and Welte, 1983):

MPI 1 = 1.5 (2-MP + 3-MP)/(P + 1-MP + 9-MP)………….……….(Radke et al., 1982a) MPI 2 = 3 (2-MP)/(P + 1-MP + 9-MP) ………………….………….(Radke et al., 1982a)

The development of MPI 1 was based on the assumption that the 2- and 3- methylphenanthrenes, the most stable isomers of the monomethylated phenanthrene (Wilhelms et al., 1998), are derived not only from 1- and 9-MP by rearrangement, but also from phenanthrene through methylation reactions. Thus, the mean of 2- and 3-MP concentrations has been related to the mean of the concentrations of these three potential precursor compounds (Radke et al., 1982a). The MPI 2 has been introduced as a possible substitute for MPI 1. The MPI 2, however, exhibits somewhat higher values than MPI 1, although they have a similar depth trend (Radke et al., 1982a; Radke, 1987). The difference reflects a slight predominance of 2- over 3-MP, which is common to the methylphenanthrene distribution (Radke et al., 1982b). The best correlation between the MPI 1 and measured vitrinite reflectance exists within the oil window, between 0.6–1.3% vitrinite reflectance (Radke et al., 1982a, 1982b), which corresponds to the MPI range 0.45–1.6 (Killops and Killops, 1993) This allows the calculation of mean vitrinite reflectance (Rc) from MPI 1 with a high degree of probability:

Rc(rw) = 0.6 MPI 1 + 0.4 (for Rm<1.35%)………..…..…………...(Radke and Welte, 1983)

Rc(rw) = - 0.6 MPI 1 + 2.3 (for Rm>1.35%)……………...…………(Radke and Welte, 1983)

The idea is that the MPI 1 value determined for an extract indicates the vitrinite reflectance value (Rc) of the corresponding source rock, unless the extract is not indigenous (Radke and Welte, 1983). The MPI is therefore a good tool when relating petroleum of unknown origin to its presumed source rocks, and is particularly useful for measuring the maturity of organic matter where vitrinite particles are rare, such as marls and limestone source rocks (Tissot and Welte, 1984). Boreham et al. (1988), in their study of Australian coal and terrestrial organic matter, suggested an extension of the relationship to a lower maturation level of 0.5% vitrinite reflectance, corresponds to 0.4

MPI 1, and suggested that Rc can be calculated as follows:

179 Chapter 6 BIOMARKERS

Rc(b) = 0.7 MPI 1 + 0.22 (for Rm < 1.7%)………………………... (Boreham et al., 1988)

Rc(b) = - 0.55 MPI 1 + 3.0 (for Rm > 1.7%)………………………... (Boreham et al., 1988)

Kvalheim et al. (1987) suggested that coal maturity correlates only with the distribution of the mono-methylphenanthrenes and not with the relative abundance of phenanthrene, and proposed a maturation indicator termed the methylphenanthrene distribution factor (MPDF):

MPDF = (2-MP + 3-MP)/(2-MP + 3-MP + 1-MP + 9-MP)……....(Kvalheim et al., 1987)

Rc(k) = - 0.166 + 2.2424 (MPDF)……………………………...…….(Kvalheim et al., 1987)

The MPDF is linearly related to vitrinite reflectance for coal with maturity within the oil window (Kvalheime et al., 1987). Boreham et al. (1988) argued that MPI 1 is the preferred index to determine calculated vitrinite reflectance (Rc).

Beyond the death line for oil at 1.35% vitrinite reflectance, a reversal occurs of increasing MPI 1 trend (Radke et al., 1982a). The decline of the MPI 1 curve is interpreted to reflect a change in the predominating reaction from methylation and rearrangement to demethylation at higher temperatures (Radke et al., 1982a; Boreham et al., 1988). Thus, it is difficult to distinguish immature from overly mature rock samples on the basis of their MPI 1 values alone. In addition, calibrations of MPI 1 against vitrinite reflectance measurements for a wider range of kerogen types were not successful (Radke, 1987), because aromatic isomer patterns can be affected by source organic matter (Radke et al., 1986; Budzinski et al., 1995). However, Boreham et al. (1988) reported that, in marine and in Proterozoic sediments containing no terrestrial organic matter, MPI 1 only becomes a valid maturity indicator beyond the onset of hydrocarbon generation at MPI 1 values above 0.7. Norgate et al. (1999) reported that, as with suppressed vitrinite reflectance values, MPI is similarly lowered in perhydrous samples. A similar observation has also been recorded by Othman et al. (2001) in a liptinite-rich and marine influenced sedimentary sequence (Chapter 4). This testifies to the positive relationship between measured and calculated vitrinite reflectance based on MPI, and further proves that perhydrous organic matter influences certain aromatic parameters.

180 Chapter 6 BIOMARKERS

Budzinski et al. (1995) noticed that increase in thermal maturity is reflected in the distribution of the methylphenanthrene isomers (1-, 2-, 3- and 9-MP) for type III organic matter , as summarised in the following equation:

MPI 3 = (%3-MP + %2-MP)/(%9-MP + %1-MP)…………….... (Budzinski et al., 1995)

MPI 3 increases with increasing maturity (Budzinski et al., 1995). Although this is the case for type III kerogen and its derived oils, type II aquatic-derived organic matter and related oils are dominated by 9-MP regardless of thermal maturity stage, which induces low MPI 3 values. Radke et al. (1986) previously observed similar results for type III organic matter, and also concluded that the methylphenanthrene distribution in rocks containing amorphous kerogen would not change regularly with maturity.

Wilhelms et al. (1998) proposed the ratio 3-MP/retene as another aromatic maturity parameter, based on a study of a thick shale sequence. The change in the ratio is related to an increase in the 3-MP concentrations associated with decrease in the retene abundance, and shows an exponential increase from the immature to the postmature range (ca 1.8% vitrinite reflectance). The parameter appears to work well in samples rich in terrestrial organic matter, but shows a somewhat slower increase in maturity in type II organic matter (Wilhelms et al., 1998).

Radke et al. (1982b) identified the dimethylnaphthalene ratio (DNR), based on specific dimethylnaphthalene isomers:

DNR = (2,6-DMN + 2,7-DMN)/(1,5-DMN)…………………….….(Radke et al., 1982b)

A corresponding rearrangement of 1,5-DMN, which is an isomer of the α,α-type (Figure 5-6), to yield α,β- and β,β-type isomers, would explain the increase of DNR with increasing maturity. The ratio responds positively to increasing coal rank, but shows a nonlinear trend with a marked increase in curvature around 0.9% vitrinite reflectance (Radke et al., 1982b). Other parameters proposed by various workers (e.g. Radke et al., 1982a, 1982b; Alexander et al., 1984, 1985; Garrigues et al., 1988; Wei and Songnian, 1990; Requejo et al., 1996), based on different aromatic isomers, were not measured in the current study. 181 Chapter 6 BIOMARKERS

6.4. Applications in the study area

6.4.1. Terpanes and steranes as source and environmental indicators

This section discusses the origin of the preserved organic matter and depositional environment for the sequences studied, based on terpane and sterane source-sensitive biomarker signatures (Tables 6-5 and 6-6; Figures 6-8 to 6-13).

The C29/C30 hopane ratios for all the samples analysed from the Permian, Triassic and

Jurassic successions are less than unity, except for sample No. 49 (C29/C30 hop = 1.12) from the Watermark/Porcupine Formation in the Coonarah-1A well at depth 613.42 m

(Table 6-5). Low C29/C30 hopane ratios are commonly associated with clay-rich (shale) source rocks (e.g. Gürgey, 1999), consistent with the current study. However, this is also the case for the coal samples analysed here, all with values < 1 for this ratio. Although commonly known as a source and environmental indicator (Connan et al.,

1986; Ramanampisoa et al., 1990), the C29/C30 hopane ratio does in fact increase consistently with maturity through the Napperby Formation in the Bellata-1 well (Table 6-5). Hence, it might be useful as a maturity parameter within a sequence where the organic facies is uniform. The high C29/C30 hopane ratio in sample No. 49, therefore, may be related to its high maturity level, as relatively high ratios are also observed in other highly mature samples (for example sample Nos. 7 and 48; Table 6-5). This is consistent with the findings of Boreham and Powell (1991), who found that this ratio increases with artificial maturation.

The homohopane distributions for all the analysed samples show a regular decrease in abundance towards higher molecular weights (Figure 6-8), resulting in low homohopane indices [C35/(C31-C35)-homohopane] which is consistent with the clay-bearing character (Waples and Machihara, 1991; Obermajer et al., 1999) of these samples (Table 6-5).

Trace amounts of 25-NH, BNH and TNH in the analysed samples (Figure 6-8; Table 6- 5) indicate oxic to suboxic conditions of the sedimentary environment, and further support the result based on the pr/ph ratio (see Chapter 5 section 5.3.2). The considerable abundances of C29Ts and diahopane (Figure 6-8) are additional evidence 182 Chapter 6 BIOMARKERS

Table 6-5: Terpanes and steranes used as source parameters in the study area. Refer to Table 6-6 for parameters identification.

4Regular steranes 1 2 3 No. Basin Well Name Formation Age Type Lithology Depth (m) C29/C30 Homohopane Index Ster/Hop C27%C28%C29% 5 B/S Edendale-1 Back Creek Group Permian cutting 100% coal 2190 0.95 0.03 0.30 3.44 17.57 79.00 7 B/S Gil Gil-1 Moolayember Formation Triassic core coal 1307.97 0.99 0.03 0.08 20.54 25.17 54.29 9 B/S Goondiwindi-1 Walloon Coal Measures Jurassic cutting 90% coal, 5% shale, 5% sst 996.7 0.48 0.02 0.10 7.57 22.17 70.26 11 B/S Goondiwindi-1 Evergreen Formation Jurassic cutting 60% sst, 30% coal, 10% siltstone 1264.92 0.43 0.01 0.21 7.97 27.62 64.41 12 B/S Goondiwindi-1 Evergreen Formation Jurassic cutting 60% shale, 30% siltstone,10% coal 1356.36 0.53 0.02 0.18 9.67 25.87 64.46 13 B/S Goondiwindi-1 Moolayember Formation Triassic core shale 1554.18 0.63 0.03 0.07 8.13 21.79 70.08 14 B/S Goondiwindi-1 Back Creek Group Permian cutting 100% coal 1886.71 0.57 0.05 0.11 3.71 16.79 79.49 15 B/S Goondiwindi-1 Back Creek Group Permian core shale 2117.44 0.54 0.03 0.26 4.63 14.60 80.78 22 B/S McIntyre-1 Kianga Formation Permian cutting 80% shale, 20% siltstone 2200.66 0.52 0.08 0.14 14.45 24.07 61.48 26 B/S Mt Pleasant-1 Kianga Formation Permian cutting 90% coal, 10% shale 1423.42 0.68 0.02 0.14 5.59 15.08 79.34 30 B/S Werrina-2 Walloon Coal Measures Jurassic cutting 90% coal, 10% shale 1237.49 0.64 0.01 0.08 4.84 21.54 73.62 34 G/S Bellata-1 Napperby Formation Triassic core claystone 642.4 0.54 0.02 0.08 7.19 36.45 56.37 51 G/S Bellata-1 Napperby Formation Triassic core claystone 665.77 0.63 0.01 0.13 7.24 22.33 70.44 35 G/S Bellata-1 Napperby Formation Triassic core siltstone 805.18 0.84 0.03 0.10 20.80 24.79 54.41 36 G/S Bellata-1 Napperby Formation Triassic core siltstone 829.6 0.99 0.08 0.25 43.09 20.62 36.29 37 G/S Bellata-1 Maules Creek Formation Permian core siltstone 929.6 0.43 0.03 0.15 5.41 18.32 76.27 38 G/S Bellata-1 Maules Creek Formation Permian core coal 939.93 0.65 0.03 0.28 10.94 21.38 67.68 39 G/S Bellata-1 Goonbri Formation Permian core sitstone 1018.1 0.62 0.03 0.26 25.23 11.44 63.33 40 G/S Bellata-1 Goonbri Formation Permian core coal 1054.74 0.62 0.02 0.23 3.24 17.76 79.00 41 B/S Bohena-1 Black Jack Group Permian core shale 660.85 0.69 0.05 0.17 10.75 21.29 67.96 44 G/S Coonarah-1A Napperby Formation Triassic core shale 421.96 0.56 0.04 0.24 22.68 15.74 61.57 45 G/S Coonarah-1A Napperby Formation Triassic core shale 453.35 0.69 0.04 0.06 18.24 18.35 63.40 46 G/S Coonarah-1A Black Jack Group Permian core coal 522.6 0.63 0.04 0.07 46.28 21.66 32.05 47 G/S Coonarah-1A Black Jack Group Permian core coal 572.09 0.89 0.09 0.11 34.53 27.68 37.80 48 G/S Coonarah-1A Black Jack Group Permian core shale 604.74 0.92 0.18 0.14 40.64 20.03 39.33 49 G/S Coonarah-1A Watermark/Porcupine Formation Permian core shale 613.42 1.12 0.09 0.17 42.32 20.30 37.38 50 G/S Coonarah-1A Watermark/Porcupine Formation Permian core siltstone 635.35 0.74 0.13 0.17 28.90 19.73 51.37

183 Chapter 6 BIOMARKERS

Table 6-5: Terpanes and steranes as source and maturity parameters in the study area. Refer to Table 6-6 for parameters identification continued. 6Diasteranes 5 7 8 9αββ ααα 10 11 12 13 14 No. C27R/C29RC27%C28%C29% Dia/Ster 20S/20R / 20R 25-NH/Hop 29,30-BNH/Hop 28,30-BNH/Hop 2+3MeH/Hop 2MeH/3MeH 5 0.04 4.35 20.34 75.31 0.25 0.87 0.81 0.01 0.04 0.02 0.18 5.91 7 0.38 32.83 31.64 35.53 0.50 0.39 0.62 0.01 0.33 0.05 0.06 2.31 9 0.11 10.85 23.23 65.92 0.26 0.17 0.84 0.01 0.39 0.03 0.06 1.29

11 0.12 7.49 24.95 67.56 0.64 0.29 1.18 0.01 0.27 0.08 0.08 2.70 12 0.15 8.88 27.89 63.23 0.37 0.28 0.84 0.03 0.38 0.05 0.17 3.44 13 0.12 20.69 21.43 57.88 0.15 0.25 0.46 0.00 0.23 0.02 0.11 0.75 14 0.05 5.20 21.39 73.41 0.34 0.39 0.59 0.01 0.10 0.02 0.15 5.75 15 0.06 5.77 12.44 81.78 0.37 0.58 0.74 0.01 0.06 0.01 0.08 5.34 22 0.24 17.63 30.06 52.30 0.32 0.29 0.76 0.03 0.24 0.13 0.07 1.35 26 0.07 6.09 18.76 75.16 0.30 0.54 0.77 0.01 0.05 0.03 0.16 7.79 30 0.07 6.87 23.48 69.65 0.22 0.35 0.63 0.01 0.12 0.01 0.15 6.10 34 0.13 8.26 39.72 52.02 0.27 0.25 0.79 0.01 0.35 0.03 0.18 3.14 51 0.10 6.74 26.41 66.86 0.29 0.20 0.60 0.02 0.39 0.05 0.12 3.47 35 0.38 23.16 34.15 42.68 0.19 0.31 0.49 0.02 0.16 0.04 0.12 3.43 36 1.19 26.33 35.24 38.42 0.42 0.92 1.78 0.05 0.02 0.07 0.15 3.33 37 0.07 5.71 25.27 69.03 0.42 0.30 0.69 0.01 0.10 0.01 0.12 10.40 38 0.16 8.12 21.40 70.49 0.54 0.42 0.98 0.12 0.16 0.07 0.29 10.53 39 0.40 26.35 12.45 61.20 0.41 0.23 0.34 0.03 0.14 0.06 0.12 3.52 40 0.04 5.88 22.62 71.50 0.28 0.42 0.50 0.04 0.06 0.03 0.24 10.53 41 0.16 9.60 20.95 69.45 0.52 0.80 1.13 0.04 0.07 0.07 0.07 2.68

44 0.37 23.45 18.44 58.10 0.36 0.44 0.47 0.02 0.05 0.00 0.12 5.28 45 0.29 20.92 18.53 60.54 0.27 1.02 0.76 0.01 0.02 0.01 0.09 8.44 46 1.44 37.13 33.92 28.95 0.47 1.02 2.21 0.03 0.02 0.00 0.08 5.53 47 0.91 39.15 25.27 35.58 0.36 1.02 2.43 0.02 0.01 0.02 0.24 8.72 48 1.03 38.17 28.33 33.50 0.50 0.90 1.88 0.04 0.03 0.06 0.24 8.29

49 1.13 37.36 31.23 31.41 0.40 0.98 2.31 0.03 0.02 0.03 0.29 7.90 50 0.56 31.41 28.52 40.08 0.42 0.57 0.89 0.01 0.13 0.02 0.10 3.23

184 Chapter 6 BIOMARKERS

Table 6-5: Terpanes and steranes as source and maturity parameters in the study area. Refer to Table 6-6 for parameters identification continued.

22 23 No. 15C dia/Hop 16C HH/C HH 17C /C st 18C /C st 19C dia/Ster 204Mest/C ster 212+3Mest/C ster 4αS/3βS Dino/3βS 30 35 33 27 29 28 29 29 29 29 5 0.03 0.49 0.12 0.18 0.24 0.10 0.49 1.63 1.99 7 0.06 0.06 0.54 0.52 0.36 0.19 0.40 1.13 3.48 9 0.03 0.10 0.20 0.32 0.26 0.22 1.06 1.47 2.68 11 0.02 0.10 0.23 0.36 0.69 0.31 1.16 0.59 2.78 12 0.05 0.16 0.27 0.39 0.39 0.25 0.79 0.66 3.77 13 0.03 0.12 0.17 0.36 0.13 0.27 0.57 0.60 3.84 14 0.03 0.28 0.14 0.23 0.35 0.13 0.56 0.21 0.97 15 0.04 0.08 0.17 0.17 0.40 0.14 0.49 0.19 0.90 22 0.05 0.16 0.32 0.42 0.29 0.40 0.72 0.93 4.80 26 0.03 0.25 0.16 0.20 0.30 0.14 0.45 0.13 0.67 30 0.03 0.31 0.13 0.33 0.23 0.16 0.73 0.27 1.27 34 0.04 0.15 0.25 0.61 0.26 0.28 1.04 0.47 2.78 51 0.07 0.29 0.19 0.35 0.30 0.13 0.90 0.19 2.24 35 0.05 0.39 0.40 0.48 0.15 0.31 0.30 0.73 5.53 36 0.16 0.35 1.08 0.66 0.44 0.42 0.28 3.72 10.40 37 0.03 0.35 0.20 0.25 0.42 0.16 0.54 0.54 2.49 38 0.08 0.54 0.35 0.34 0.65 0.21 0.79 0.45 1.54

39 0.06 0.40 0.50 0.19 0.42 0.07 0.27 0.51 2.19 40 0.03 0.31 0.13 0.24 0.28 0.05 0.58 0.03 0.42 41 0.02 0.24 0.34 0.28 0.58 0.13 0.39 0.18 0.94 44 0.03 0.20 0.49 0.26 0.36 0.33 0.45 0.75 2.56 45 0.03 0.26 0.34 0.29 0.27 0.37 0.45 0.48 1.59 46 0.06 0.19 1.15 0.62 0.38 0.72 0.90 1.95 5.95 47 0.11 0.37 0.74 0.50 0.29 0.72 0.91 1.11 2.61 48 0.06 0.46 0.80 0.52 0.39 0.45 0.48 2.04 3.19 49 0.10 0.79 0.92 0.52 0.31 0.50 0.83 1.49 2.25 50 0.02 0.28 0.65 0.44 0.35 0.23 0.49 0.61 1.97

185 Chapter 6 BIOMARKERS

Table 6-6: Identification of the parameters used in table 6-5. No. Parameter Ratio 1 C29/C30 = C29 / C30 αβ hopane = 17α(H),21β(H)-30-norhopane / 17α(H),21β(H)-hopane

2 Homohopane Index = C35 / (C31-C35) = 17α(H),21β(H)22(S+R) C35 homohopane / 17α(H),21β(H)22(S+R) C31-C35 homohopanes

3 Ster/Hop = Steranes / Hopanes = Sum C27-29 [5α,14α,17α(H)-20(S+R) + 5α,14β,17β(H)- 20(S+R)]steranes / [C27trisnorhopane (Ts+Tm) + C28bisnorhopanes (28,30-BNH + 29,30-BNH) + C29(30NH+moretane) + C30(hopane+moretane) + C31-34 (homohopanes + homomoretanes)]

4 Regular sterane = C27% : C28% : C29% = 5α,14α,17α(H)-cholestane 20R

5 C27R/C29R = 5α,14α,17α(H)-cholestane 20R / 5α,14α,17α(H)-24-ethylcholestane 20R

6 Diasterane = C27% : C28% : C29% = 5α,13β,17α(H)-dia-cholestane 20(S+R)

7 Dia/Ster = Diasteranes / Steranes = [total C27 to C29 13β(H),17α(H)(20S+20R) diasterane] / [total C27 to C29 5α(H),14β(H),17β(H) and 5α(H),14α(H),17α(H) (20S+20R) sterane]

8 20S /20R = 5α,14α,17α(H)-24-ethylcholestane 20S / 5α,14α,17α(H)-24-ethylcholestane 20R

9 αββ / ααα20R = 5α,14β,17β(H)-24-ethylcholestane 20R / 5α,14α,17α(H)-24-ethylcholestane 20R

10 25-NH / Hop = C29 17α(H),21β(H)-25-norhopane / C30 17α(H),21β(H)-hopane

11 29,30-BNH / Hop = 29,30-bisnorhopane / C30 17α(H),21β(H)-hopane

12 28,30-BNH / Hop = 28,30-bisnorhopane / C30 17α(H),21β(H)-hopane

186 Chapter 6 BIOMARKERS

Table 6-6: Identification of the parameters used in table 6-5 continued.

No. Parameter Ratio 13 2+3MeH / Hop = C31(2α+3β)-methylhopane / C30 17α(H),21β(H)-hopane

14 2MeH/ 3MeH = 2α-methylhopane /3β-methylhopane

15 C30 diah /Hop = C30 17α-diahopane / C30 17α(H),21β(H)-hopane

16 C35 HH / C33 HH = C35 / C33 homohopane

17 C27 / C29 st = [5α,14α,17α(H)-cholestane 20(S+R) + 5α,14β,17β(H)-cholestane 20(S+R)] / [5α,14α,17α(H)-24- ethylcholestane 20(S+R) + 5α,14β,17β(H)-24-ethylcholestane 20(S+R)]

18 C28 / C29 st = [5α,14α,17α(H)-24-methylcholestane 20(S+R) + 5α,14β,17β(H)-24-methylcholestane 20(S+R)] / [5α,14α,17α(H)-24-ethylcholestane 20(S+R) + 5α,14β,17β(H)-24-ethylcholestane 20(S+R)]

19 C29 dia / ster = 5α,13β,17α(H)-dia-24-ethylcholestane 20(S+R) / [5α,14α,17α(H)-24-ethylcholestane 20(S+R) + 5α,14β,17β(H)-24-ethylcholestane 20(S+R)]

20 4 Mest / C29 Ster = C30 4α-methylcholestane 20R / 5α,14α,17α(H)-24-ethylcholestane 20R

21 2+3 Mest / C29 Ster = (2α+3β)-methyl-5α,14α,17α(H)-24-ethylcholestane 20R / 5α,14α,17α(H)-24-ethylcholestane 20R

22 4αS / 3βS = 4α-methyl-5α,14α,17α(H)-24-ethylcholestane 20S / 3β-methyl-5α,14α,17α(H)-24-ethylcholestane 20S

23 Dino / 3βS = 4α,23R,24S-trimethyl-5α,14α,17α(H)-24-cholestane 20R / 3β-methyl-5α,14α,17α(H)-24- ethylcholestane 20S

187 30 Chapter 6 BIOMARKERS

31 Tm 29 βα

Sample No. 14 32 Goondiwindi-1 Back Creek Group 33 1886.71 m 34 R = 0.60% 35 v,max

Sample No. 22 29Ts McIntyre-1 Kianga Fm. 2200.66 m Ts Rv,max = 0.72%

Sample No. 40 Bellata-1 C*30 Goonbri Fm. 1054.74 m R= 0.66% v,max

Sample No. 37 Bellata-1 Maules Creek Fm. 929.60 m

R=c(rw) 0.67%

Sample No. 50 Coonarah-1A TNH Watermark/Porcupine Fm. 635.35 m CPI = 1.15 R= 1.80% v,max

Sample No. 41 BNH Bohena-1 NH Black Jack Group 660.85 m

Rv,max = 0.62%

Sample No. 46 Coonarah-1A Black Jack Group 522.60 m

R=v,max 1.8%

Permian rock samples

Figure 6-8: Selected hopane chromatograms (m/z 191).

188 Chapter 6 BIOMARKERS

29 30 βα Tm 31 32 33 Sample No. 7 Gil Gil-1 Moolayember Fm. 1307.97 m Ts R= 1.3% v,max

Sample No. 13 Goondiwindi-1 Moolayember Fm. 1554.18 m R = 0.77% v,max

29Ts Sample No. 36 TNH Bellata-1 34 35 Napperby Fm. 829.60 m

Rv,max = 2.21%

Sample No. 44 BNH Coonarah-1A NH Napperby Fm. 421.96 m R = 0.52% v,max

Triassic rock samples

30

Tm Sample No. 12 C*30 Goondiwindi-1 Evergreen Fm. 1356.36 m R = 0.72% v,max

Sample No. 9 Goondiwindi-1 Walloon Coal Measures 996.70 m

Rv,max = 0.54%

Jurassic rock samples

Figure 6-8: Selected hopane chromatograms (m/z 191) continued.

189 Chapter 6 BIOMARKERS for deposition of terrestrially derived organic matter in oxic to suboxic conditions. Bacterial reworking and subsequent input is evidenced by the presence of 2-α and 3-β methylhopanes in the samples studied (Figure 6-9).

As indicated in Table 6-5, all the samples have low sterane/hopane ratios, with a maximum value of 0.30 for the Maules Creek Formation coal sample from Edendale-1 at a depth of 2190 m (Table 6-5). Consistently, the samples are characterised by high relative abundances of C29 steranes (Figures 6-10 and 6-11a; Table 6-5), resulting in low

C27/C29 sterane ratios except for the igneous intrusion affected intervals, for example postmature sample Nos. 36 and 46 (Figures 6-11a; Table 6-5), where the high values are attributed to high thermal maturity. These outcomes support previous results (see also Chapter 5), and indicate that the terrestrial organic matter source is the main input for the source rock succession in the area studied.

The diasterane ternary plot (Figure 6-11b, Table 6-5) supports a terrestrial source input.

However, C29 diasteranes are relatively less abundant in intrusion-affected intervals, for example, sample No. 36. This phenomenon could be attributed to the high level of thermal maturity rather than preserved organic matter variations, even though high diasterane concentrations and high diasterane/sterane ratios are commonly used to indicate source rocks containing abundant clay (shale), while low diasterane abundance and low ratios indicate, clay-poor, carbonate source rocks deposited under anoxic conditions (McKirdy et al., 1983; Peters and Moldowan, 1993). Exceptions, however, are recorded (e.g. Clark and Philp, 1989; Moldowan et al., 1992; Casareo et al., 1996; van Kaam-Peters et al., 1997). For the samples studied, diasterane/sterane ratios are plotted versus TOC% from Rock-Eval pyrolysis (Figure 6-12). The plot illustrates a regular increase in the ratio among the samples with less than 5% TOC content, while the ratio decreases with higher TOC% contents (Figure 6-12). The intrusion affected postmature samples plot separately, showing high diasterane/sterane ratios (Figure 6-12; Table 6-5), consistent with its high thermal maturity level (Seifert and Moldowan, 1978). This diagram shows that in the samples studied the diasterane/sterane ratios are mainly controlled by the amount of TOC for a relatively low organic matter content (up to about 5% TOC), while the abundance of clay minerals relative to organic matter (cf. van Kaam-Peters et al., 1998) is probably, the main control on the diasterane/sterane ratios for rocks with higher TOC contents including coals. Further studies, however, are 190 Chapter 6 BIOMARKERS

C2Me30 α S+R C32 2α Me Sample No. 14 Sample No. 7 C2Me31 α Goondiwindi-1, Back Creek Group Gil Gil-1, Moolayember Fm. 1307.97 m, R = 1.3% 1886.71 m, Rv,max = 0.60% v,max 3Meβ Sample No. 22 Sample No. 13 McIntyre-1, Kianga Fm. Goondiwindi-1, Moolayember Fm. 1554.18 m, Rv,max = 0.77% 2200.66 m, Rv,max = 0.72%

Sample No. 40 Sample No. 36 C2Me30 α C2Meα Bellata-1, Goonbri Fm. Bellata-1, Napperby Fm. 31 1054.74 m, Rv,max = 0.66% 829.60 m, Rv,max = 2.21%

Sample No. 37 Sample No. 44 Bellata-1, Maules Creek Fm. Coonarah-1A, Napperby Fm. 421.96 m, Rv,max = 0.52% 929.60 m, Rc(rw) = 0.67%

Sample No. 50 S+R C 2α Me Coonarah-1A 32 Triassic rock samples Watermark/Porcupine Fm. 635.35 m, Rv,max = 1.80%

Sample No. 12 Sample No. 41 Goondiwindi-1, Evergreen Fm. Bohena-1, Black Jack Group 1356.36 m, Rv,max = 0.72% 660.85 m, Rv,max = 0.62% Sample No. 9 Goondiwindi-1 Sample No. 46 Walloon Coal Measures Coonarah-1A, Black Jack Group 996.70 m, Rv,max = 0.54% 522.60 m, Rv,max = 1.8%

Jurassic rock samples Permian rock samples

Figure 6-9: Selected methylhopane chromatograms (m/z 205).

191 Chapter 6 BIOMARKERS

Sample No. 14 Goondiwindi-1 Back Creek Group 1886.71 m R = 0.60% v,max

Sample No. 22 McIntyre-1 Kianga Fm. 2200.66 m Rv,max = 0.72%

Sample No. 40 Bellata-1 Goonbri Fm. 1054.74 m

Rv,max = 0.66%

29 βααβ+

Sample No. 37 Bellata-1 Maules Creek Fm. 929.60 m R= 0.67% c(rw)

Sample No. 50 Coonarah-1A Watermark/Porcupine Fm. 635.35 m CPI = 1.15 Rv,max = 1.80%

Sample No. 41 Bohena-1 Black Jack Group 660.85 m R = 0.62% v,max 27 27 ααββ+ βααβ+ 29 αα+ ββ 28 28 Sample No. 46 βααβ+ ααββ+ Coonarah-1A Black Jack Group 522.60 m R = 1.8% v,max

Permian rock samples

Figure 6-10: Selected sterane chromatograms (m/z 217). 192 Chapter 6 BIOMARKERS

29 + αα ββ 27 27 Sample No. 7 βα+ αβ αα+ ββ 28 28 Gil Gil-1 ααββ+ Moolayember Fm. βα+ αβ 1307.97 m Rv,max = 1.3%

Sample No. 13 Goondiwindi-1 Moolayember Fm. 1554.18 m R = 0.77% v,max

Sample No. 36 Bellata-1 Napperby Fm. 829.60 m

Rv,max = 2.21%

29 Sample No. 44 βααβ+ Coonarah-1A Napperby Fm. 421.96 m R = 0.52% v,max

Triassic rock samples

Sample No. 12 Goondiwindi-1 Evergreen Fm. 1356.36 m R = 0.72% v,max

Sample No. 9 Goondiwindi-1 Walloon Coal Measures 996.70 m R = 0.54% v,max

Jurassic rock samples

Figure 6-10: Selected sterane chromatograms (m/z 217) continued.

193 Chapter 6 BIOMARKERS

C28 ‹ Back Creek Group † Black Jack G roup  E v e r gr e e n F or m at i o n } Goonbri Formation „ Kianga Formation — Maules Creek Formation z Moolayember Formation { Napperby Formation ˜ Wa termark/Porcupine Fm. ’ Walloon Coal Measures

{

†  {z „  † z’{ {†˜ ˜ —† ’ { —}‹— Intrusion affected , { „‹ highly mature samples }

C27 C29

(A) C27 -C 29 Regular steranes

C28

{ † { { ˜ z „ † ˜ { † — ’ ’} Intrusion affected, z‹†— — highly mature samples {{ „ } ‹

C27 C29

(B) C-C27 29 Diasteranes

Figure 6-11: Ternary plots of (A) C27-C29 regular steranes and (B) C27-C29 diasteranes showing C29 compound predominance, except in highly mature samples. 194 Chapter 6 BIOMARKERS

TOC% - dia/ster relationship 0.7

11 0.6 Intrusion affected, 38 Intrusion affected, pos tmatur e s amples 41 pos tmatur e s amples 0.5 7 48 50 37 46 49 0.4 36 39 12 47 44 15 14 0.3 22 26 40 45 dia/ster ratio 34 9 5 0.2 30 35 13 0.1

0 0.1 1 10 100 1000

TOC%

Figure 6-12: TOC% versus diasterane/sterane ratio; positive correlation for samples with up to 5.0% TOC content and negative correlation with higher TOC% content. Intrusion affected postmature samples are anomalously separated.

195 Chapter 6 BIOMARKERS required to improve the interpretation or correlations of diasterane/sterane ratios with TOC% in source rock samples.

Weak dinosterane signatures in the analysed Triassic and Jurassic samples (Figure 6-13) could be attributed to their non-marine depositional environment. On the other hand, the lack of dinosteranes in the Permian samples can be attributed to the sediments age. Dinosteranes have mainly been documented in oils and sediments of post-Paleozoic age, due to the fact that their precursors, dinoflagellates, flourished during this period (e.g. Goodwin et al., 1986; Summons et al., 1987).

6.4.2. Terpanes and steranes as maturity indicators

Molecular maturity parameters (Figure 6-14) have been widely employed in the last two decades since the recognition of systematic changes in biomarker composition with increasing maturity (e.g. Seifert and Moldowan, 1978, 1980; Mackenzie et al., 1980). Most of these parameters are based on the relative abundances of two stereoisomers, and involve a relative increase of the more thermally stable (non-biological) isomer compared to the isomer with the original biologically-inherited stereochemistry. Originally, this process was widely assumed to comprise direct isomerisation or epimerisation of the free biomarkers in the bitumen. However, studies providing quantitative data have shown that the mechanisms behind the maturity parameters are more complicated (Farrimond et al., 1998). Some studies proved that relative rates of release (generation) of biomarkers from kerogen and possibly from asphaltenes or other polar fractions, and their thermal stability (cracking), are also important mechanisms that affect biomarker composition and abundance with increasing maturity (e.g. Lu et al., 1989; Abbott et al., 1990; Peters et al., 1990; Bishop and Abbott, 1993; Farrimond et al., 1996, 1998, 1999).

Several biomarker maturity parameters were calculated as shown in Tables 6-7 and 6-8, and in Figures 6-15 to 6-19. The 22S ratio [C31 homohopane 22S/(22S+22R)] for the Permian samples in the Gunnedah Basin ranges from 0.44 to 0.58, and 0.47 to 0.58 for the Triassic samples (Table 6-7). This indicates that only parts of the sequence have reached sufficient maturity to generate liquid hydrocarbons (22S = 0.55 – 0.58),

196 Chapter 6 BIOMARKERS

3Rβ Dinosterane isomers: Sample No. 14 2Rα 1 = 4α ,23S,24S-trimethylcholestane 20R Goondiwindi-1, Back Creek Group 2 = 4α ,23S,24R-trimethylcholestane 20R

1886.71 m, Rv,max = 0.60% 3 = 4α ,23R,24R-trimethylcholestane 20R 4 = 4α ,23R,24S-trimethylcholestane 20R 3(βββ ) 4Rα Sample No. 7 3Sβ 2(αββ ) 4Sα Gil Gil-1, Moolayember Fm. 1307.97 m, R = 1.3% v,max 1 4 Sample No. 22 2Sα 2 3 McIntyre-1, Kianga Fm.

2200.66 m, Rv,max = 0.72% Sample No. 13 Goondiwindi-1, Moolayember Fm. 1554.18 m, R = 0.77% v,max Sample No. 40 Bellata-1, Goonbri Fm. Sample No. 36 Bellata-1, Napperby Fm. 1054.74 m, Rv,max = 0.66% 829.60 m, R = 2.21% v,max Sample No. 37 Sample No. 44 Bellata-1, Maules Creek Fm. Coonarah-1A, Napperby Fm. 929.60 m, R = 0.67% 421.96 m, Rv,max = 0.52% c(rw) Triassic rock samples Sample No. 50 Coonarah-1A Watermark/Porcupine Fm. 635.35 m, Rv,max = 1.80% Sample No. 12 Goondiwindi-1, Evergreen Fm.

1356.36 m, Rv,max = 0.72% Sample No. 41 Bohena-1, Black Jack Group 660.85 m, Rv,max = 0.62%

Sample No. 9 Sample No. 46 Goondiwindi-1 Coonarah-1A, Black Jack Group Walloon Coal Measures 522.60 m, R = 1.8% v,max 996.70 m, Rv,max = 0.54% Permian rock samples Jurassic rock samples

Figure 6-13: Selected methylsterane chromatograms (m/z 231). 197 Chapter 6 BIOMARKERS

Figure 6-14: Approximate correlation of various biomarker maturity parameters used in this study with stages of coalification and petroleum generation (modified from Tissot and Welte, 1984; Killops and Killops, 1993; Peters and Moldowan, 1993; Peters and Cassa, 1994).

198 Chapter 6 BIOMARKERS

Table 6-7: Terpanes and steranes as maturity parameters. For parameters identification see Table 6-8.

24 26 32 33 No. 22S 25Mor/C Ts/(Ts+Tm) 27C Ts/C 28C -C TT/C 29C TT/C TT 30C Tetra/C 31C Tetr/C TT 20S ββ 29 29 29 21 26 30 23 24 24 30 24 21-26 5 0.59 0.46 0.05 0.04 0.01 0.22 0.04 3.62 0.46 0.30 7 0.49 0.88 0.11 0.10 0.82 0.40 0.37 0.45 0.28 0.31 9 0.38 1.21 0.03 0.08 0.03 0.51 0.02 0.77 0.14 0.42 11 0.38 1.11 0.10 0.16 0.14 1.38 0.04 0.26 0.22 0.48 12 0.36 1.11 0.06 0.13 0.07 0.98 0.03 0.43 0.22 0.39 13 0.52 1.07 0.03 0.03 0.04 0.66 0.03 0.76 0.20 0.27 14 0.58 0.88 0.03 0.05 0.02 0.20 0.03 1.69 0.28 0.30 15 0.57 0.73 0.05 0.08 0.02 0.40 0.03 1.25 0.37 0.32 22 0.39 1.01 0.08 0.19 0.09 1.16 0.03 0.32 0.22 0.37 26 0.58 0.65 0.02 0.04 0.03 0.41 0.03 1.21 0.35 0.33 30 0.56 0.84 0.03 0.04 0.02 0.18 0.04 1.50 0.26 0.32 34 0.47 1.25 0.02 0.03 0.02 0.20 0.03 1.29 0.20 0.39 51 0.47 1.17 0.03 0.03 0.05 0.22 0.04 0.84 0.17 0.33 35 0.51 0.77 0.07 0.09 0.14 0.81 0.05 0.39 0.24 0.27 36 0.54 0.17 0.48 0.23 0.92 1.84 0.20 0.22 0.48 0.48 37 0.55 0.81 0.07 0.11 0.01 0.17 0.02 1.84 0.23 0.35 38 0.54 0.75 0.04 0.10 0.03 0.40 0.04 1.17 0.30 0.41 39 0.54 0.76 0.12 0.11 0.09 0.94 0.02 0.28 0.19 0.22 40 0.58 0.84 0.03 0.06 0.03 0.26 0.04 1.12 0.29 0.26 41 0.58 0.61 0.05 0.08 0.04 0.62 0.05 1.29 0.44 0.39 44 0.58 0.64 0.15 0.20 0.04 0.44 0.03 0.67 0.31 0.24 45 0.58 0.49 0.11 0.09 0.07 1.01 0.05 0.68 0.51 0.27 46 0.44 0.45 0.44 0.23 0.50 1.49 0.09 0.18 0.50 0.52 47 0.48 0.22 0.49 0.26 0.23 1.60 0.07 0.28 0.50 0.55 48 0.55 0.27 0.50 0.27 1.50 1.23 0.17 0.12 0.47 0.50 49 0.55 0.12 0.57 0.27 1.09 2.52 0.30 0.28 0.49 0.54 50 0.53 0.57 0.21 0.15 0.55 1.64 0.11 0.19 0.36 0.36

199 Chapter 6 BIOMARKERS

Table 6-8: Identification of the parameters used in Table 6-7. No. Parameter Ratio

24 22S = 22S / (22S+22R) C31 homohopane = 17α,21β(H) 22S homohopane / 17α,21β(H)22(S+R)homohopane

25 Mor/C29 = C30 moretane / C29 hopane = 17β,21α(H)-hopane / 17α,21β(H)-30-norhopane

26 Ts/(Ts+Tm) = C27 18α(H)-22,29,30-trisnorneohopane / C27 18α(H)-22,29,30-trisnorneohopane + C27 17α(H)- 22,29,30-trisnorhopane

27 C29Ts/C29 = C29Ts / C29 hopane = 18α(H),21β(H)-30-norneohopane / 17α(H),21β(H)-30-norhopane

28 C21-C26TT/C30 = C21-C26Tricyclic terpanes / C30 hopane = [total C21 to C26 13β(Η),14α(Η)-cheilanthanes] / 17α(H),21β(H)- hopane

29 C23TT/C24TT = C23 tricyclic terpane / C24 tricyclic terpane = C2313β(Η),14α(Η)-cheilanthanes / C2413β(Η),14α(Η)- cheilanthanes

30 C24Tetra/C30 = C24tetracyclic terpane / 17α(H),21β(H)-hopane

31 C24Tetra/ C21-C26TT = C24tetracyclic terpane / [total C21 to C26 13β(Η),14α(Η)-cheilanthanes]

32 20S = 20S / (20S+20R)- C29 sterane = 5α,14β,17α(H)-24-ethylcholestane 20S / 5α,14α,17α(H)-24- ethylcholestane 20(S+R)

33 %ββ = %ββ / (ββ+αα)- C29 sterane = 5α,14β,17β(H)-24-ethylcholestane 20S(S+R) / [5α,14β,17β(H)-24- ethylcholestane 20(S+R) + 5α,14α,17α(H)-24-ethylcholestane 20(S+R)]

200 Chapter 6 BIOMARKERS although other parts are still immature to marginally mature (22S = 0.44 – 0.54). In the Permian Back Creek Group of the Bowen Basin, the hopane isomerisation ratio is 0.57 to 0.59, and 0.39 to 0.58 for the overlying Permian Kianga Formation (Table 6-7). The ratio for the Triassic samples ranges from 0.49 to 0.52, and 0.36 to 0.56 for the Jurassic samples. Table 6-7 demonstrates that, as expected, the ratio of the 22S increases with increasing depth. The Tmax and vitrinite reflectance suppressed Permian intervals (see Chapters 4 and 5) are not paralleled in the hopane isomerisation trend. This is most obvious in the Maules Creek and Goonbri Formations in Bellata-1 (Figure 6-15; Table 6-7) and the Back Creek Group in Goondiwindi-1 (Figure 6-16; Table 6-7). Similarly, the 22S-22R hopane reaction in the Back Creek Group in Edendale-1, at 2190 m depth, seems to have reached equilibrium (22S = 0.59), a testimony to its moderate level of maturity, although such a conclusion is not readily ascertainable based on vitrinite reflectance and Tmax alone due to these parameters’ suppression in this section (Rv,max = o 0.64% and Tmax = 432 C) due to marine influence (see Chapters 4 and 5).

Conversely, the trend of increasing hopane isomerisation demonstrates a reversal at high maturity in intrusion-affected intervals (Table 6-7). In the Gunnedah Basin, the Napperby Formation sample in the Bellata-1 well at depth 829.60 m (sample No. 36) is postmature (Rv,max = 2.21%), yet the value of only 0.54 for the 22S ratio is suggestive of a marginally mature sample (sample No. 36; Table 6-7 and Figure 6-15). The highly mature, intrusion-affected, Permian sequence in the Coonarah-1A well similarly shows low 22S ratios ranging from 0.44 to 0.55 (Table 6-7), while vitrinite reflectance for the same samples ranges between 1.62 and 1.99%. In the Bowen Basin, the only analysed highly mature sample, from the Moolayember Formation (Rv,max = 1.3%) in Gil Gil-1 at depth 1307.97 m (sample No. 7), again shows an immature signal according to the 0.49 value of the 22S ratio. The inversion of 22S ratio in rapidly heated sequences due to igneous intrusions has previously been recorded elsewhere (e.g. Bishop and Abbott 1993; Farrimond et al., 1996). This phenomenon, however, was not observed within sequences ‘normally’ matured due to burial depth (e.g. Farrimond et al., 1998), which indicates that the 22S ratio behaves differently to that in rapidly heated source rocks.

Figure 6-17 shows that the inversion of the 22S ratio for the sample suite analysed in this study occurs at around 1.1% measured vitrinite reflectance, corresponding to slightly higher than the 0.51 22S ratio. Bishop and Abbott (1993), however, noted that 201 Chapter 6 BIOMARKERS

- Depth 22S - Depth Mor/Hop - Depth Ts/Ts+Tm-Depth C29Ts/C29-Depth 20S - Depth ββ relationship relationship relationship relationship relationship relationship

Mor/Hop Ts/Ts+Tm 22S C29Ts/C29 20S ββ

0.4 0.5 0.6 00.751.500.250.50 0.15 0.3 00.30.600.30.6 600 Purlawaugh Fm. 34 51

700

Napperby Fm.

800 35 36 Igneous intrusion

Depth (m) Digby Fm. 900 Porcupine Fm. 37 siltstone 38 Coal Maules Creek Fm. 1000 39 siltstone

40 Coal Goonbri Fm. 1100

Figure 6-15: Hopane and sterane maturity parameter plots in Bellata-1. 202 Chapter 6 BIOMARKERS

Mor/Hop - Depth Ts/Ts+Tm - Depth - Depth 22S - Depth C29Ts/C29 - Depth 20S - Depth ββ relationship relationship relationship relationship relationship relationship

22S Mor/Hop Ts/Ts+Tm C Ts/C 20S 29 29 ββ 0.2 0.5 0.8 0.5 1 1.5 0 0.075 0.15 00.10.20 0.25 0.5 00.30.6 750

9 1050 Walloon Coal Measures

Hutton Sandstone 11 Evergreen Fm. 1350 12 precipice sandstone Moolayember Fm. 13 Showgrounds sandstone Depth (m) Depth 1650 Kianga Fm.

14 Back Creek Group 1950

15 2250

Figure 6-16: Hopane and sterane maturity parameter plots in Goondiwindi-1.

203 Chapter 6 BIOMARKERS

22S versus R % relationship v,max 22S 0.3 0.35 0.4 0.45 0.5 0.55 0.6 0.65

0.2

0.6

1.0 Proposed vitrinite reflectance limit for inversion of 22S ratio

% 1.4 v,max

R

1.8

2.2 Inverted 22S ratios in intrusion affected, postmature samples 2.6

Figure 6-17: 22S versus Rv,max % relationship showing inversion of 22S ratios in intrusion effected highly mature samples.

204 Chapter 6 BIOMARKERS the ratio reaches an end point of 0.53 at 1.15% measured vitrinite reflectance before inversion. Certainly, further investigation of a larger set of samples is needed to better refine this conclusion.

The moretane/hopane ratio (C29 compounds used to calculate the formula; Table 6-8) for the Permian sequence in the Gunnedah Basin ranges from 0.12 to 0.84, and in the Triassic sequence from 0.17 to 1.25. The ratio is at its lowest (0.17) close to the igneous intrusion paleo-heat source within the Napperby Formation in the Bellata-1 well (Figure 6-15). The ratio also decreases regularly within the Napperby Formation samples in the Coonarah-1A well, and shows low values within intrusion-affected postmature samples of the Permian sequence (Table 6-7). The deepest sample analysed from Coonarah-1A, at 635.35m (sample No. 50), interestingly indicates less maturity (illustrates higher moretane/hopane ratio) compared to the overlying Permian sequence. However, the abnormal increase in maturity in parts of this Permian sequence is due to igneous intrusions that evidently controlled the organic maturity, rather than normal burial. In the Bowen Basin the moretane/hopane ratio = 0.46 – 1.21, and generally decreases with depth within the Goondiwindi-1 well (Figure 6-16; Table 6-7). Similar to the 22S ratio, the moretane to hopane ratio in the Maules Creek and Goonbri Formations in Bellata-1, and more clearly in the Back Creek Group in Goondiwindi-1, seems to be not affected (suppressed) by the marine influence or liptinite rich intervals within the Permian sequence.

The Ts/(Ts+Tm) ratio ranges from 0.03 to 0.57 for the Permian samples of the Gunnedah Basin, and 0.02 to 0.48 for the Triassic samples (Table 6-7). The ratio clearly increases within the Napperby Formation in the Bellata-1 borehole, to a maximum in the vicinity of the intrusion body, and then also increases within the ‘suppressed zone’ of the Permian sequence (Figures 6-15). High ratios are shown within the intrusion affected, highly mature Permian sequence in the Coonarah-1A well. However, similar to the moretane/hopane ratio, the sample at depth 635.35 m (sample No. 50) appears less mature than overlying samples (Table 6-7). In the Bowen Basin samples, the Ts/(Ts+Tm) ratio in general is small (0.02 – 0.11). The Evergreen Formation in Goondiwindi-1 (Sample Nos. 11 and 12) shows relatively high ratios, Ts/(Ts+Tm) = 0.10 and 0.06 respectively (Figure 6-16 and Table 6-7). This has possibly not solely resulted from these samples’ maturity level (Rv,max = 0.56 and 0.72 respectively). The 205 Chapter 6 BIOMARKERS ratio is also susceptible to facies variability (Seifert and Moldowan, 1978). The relatively high Ts/(Ts+Tm) ratio (0.11) in the Moolayember Formation in Gil Gil-1

(sample No. 7; Table 6-7) is mainly attributed to the sample’s maturity level (Rv,max = 1.30%). This ratio also seems to be not affected by vitrinite reflectance suppressed intervals in the Permian sequence (Figures 6-15; Table 6-7).

In the Gunnedah Basin the C29Ts/C29 hopane ratio ranges from 0.05 to 0.27 for the Permian samples, and 0.03 to 0.23 for the Triassic samples. In the Bellata-1 well the ratio increases parallel to the Ts/(Ts+Tm), and maximises in the intrusion-effected interval of the lower part of the Napperby Formation and increases within the suppressed Permian interval. In the Bowen Basin the C29Ts/C29 hopane ratio ranges from 0.04 to 0.19 for the Permian samples, 0.03 to 0.10 for the Triassic, and 0.04 to 0.16 for the analysed Jurassic samples. Relatively high values (0.10) occur in the mature

Moolayember Formation (Rv,max = 1.30%), sample No. 7, in Gil Gil-1 (Table 6-7). The ratio in Goondiwindi-1 illustrates a similar profile to Ts/(Ts+Tm) and show relatively high values in the Evergreen Formation samples (Figure 6-16; Table 6-7).

The abundance and distribution of tricyclic and tetracyclic terpanes are influenced by the availability of their organic precursors and the environmental conditions in which they were deposited (as discussed in sections 6.3.1.2.6 and 6.3.1.2.7). Hence, maturity evaluation using these compounds are probably more reliable within similar environmental conditions, as in the Napperby Formation, for example, to avoid variations not related to thermal maturity. Although the maturity effect on various tricyclic and tetracyclic terpanes can be observed within the samples studied (Table 6- 7), they are more evident in the Napperby Formation in Bellata-1 (Figure 6-18). The thermal maturity in this particular sequence ranges from marginally mature to postmature (Rv,max = 0.6 – 2.21%), due to igneous intrusion effects. The ratio of tricyclic terpanes to C30 hopane increases with increasing thermal maturity (Figure 6-19). Although high ratios can be observed within highly mature samples (Table 6-7), the ratio increases obviously downhole within the Napperby Formation in Bellata-1, and most dramatically close to the igneous intrusion (Figure 6-19; Table 6-7). This is best observed for the C23 tricyclic terpane member with the highest C23/C24 tricyclic terpane ratios recorded for the highly mature Napperby Formation samples in Bellata-1 (Figures 6-18 and 6-19), as well as for much of the sequence at Coonarah-1A (Table 6-7). This 206 Chapter 6 BIOMARKERS

30

Tm

Sample No. 34 Bellata-1 Napperby Fm. 24 TT Ts 642.40 m 24 Tetra R=v,max 0.60%

30

Tm

Sample No. 35 Bellata-1 Napperby Fm. 23 TT Ts 805.18 m 24 TT 24 Tetra R=v,max 0.98%

30 29

31

32 33 34 35

Tm Ts 20 TT Sample No. 36 23 TT 24 Tetra Bellata-1 24 TT Napperby Fm. 26 TT 829.60 m 21 TT 25 TT 19 TT 22 TT R=v,max 2.21%

Figure 6-18: Relative abundance of tricyclic and tetracyclic terpanes in relation to hopanes with increasing maturity due to igneous intrusion in Napperby Formation, Bellata-1.

207 Chapter 6 BIOMARKERS

C21-C26TT/C30Hop - Depth C23TT/C24TT - Depth C24Tetra/C30Hop - Depth C24Tetra/C21-C26TT - Depth relationship in Napperby relationship in Napperby relationship in Napperby relationship in Napperby Formation, Bellata-1 Formation, Bellata-1 Formation, Bellata-1 Formation, Bellata-1

-C TT/C Hop C TT/C TT C21 26 30 23 24 C24Tetra/C30Hop C24Tetra/C21-C26TT 00.510120 0.1 0.2 0.3 00.511.5 600

650

700

750 Depth (m) Depth

800

850 Igneous intrusions

Figure 6-19: Variations in tricyclic and tetracyclic terpanes with increasing thermal maturity due to igneous intrusion in Napperby Formation, Bellata-1.

208 Chapter 6 BIOMARKERS phenomenon is similar to that reported by Farrimond et al. (1999), but differs from that in Cassani et al. (1988). Farrimond and co-workers attributed the disagreement between the responses in carbon number distribution to the drastically different heating rate in igneous intrusive intervals (as in Bellata-1 and Coonarah-1A), compared with organic matter maturity resulting from natural sediment burial.

A high C24 tetracyclic terpane to hopane ratio is observed in samples of high maturity (Table 6-7), and increases regularly within the Napperby Formation in Bellata-1 (Figure 6-18). However, the negative relationship between the behavior of tri- and tetracyclic terpanes upon maturation is exemplified in the C24 tetracyclic terpane versus C21-C26 tricyclic terpanes plot in Figure 6-19, which shows lower values in the more mature samples (see also Table 6-7). Similar results, in an igneous intruded sequence, were recorded within the oil window by Farrimond et al. (1999), who demonstrated that the

C24 tetracyclic terpane to the sum of the C20-C26 tricyclic terpanes ratio increases towards the oil window and then decreases within the oil window. They ascribed this to the greater rate of generation of the tetracyclic compounds compared with the tricyclics at earlier stages of maturation, followed by a faster thermal degradation of the former in the later parts of the oil window (Farrimond et al., 1999). It is also possible that the observed relationship is due to the fact that the C24 tetracyclic terpane is primarily an environmental indicator that responds significantly to maturity only at very high levels, unlike tricyclic terpanes that are more sensitive to maturity variations.

The C29 sterane 20S ratio (Table 6-7) in the Permian sequence of the Gunnedah Basin ranges from 0.19 to 0.44 in Bellata-1 and Bohena-1. The same ratio ranges between 0.36 and 0.50 within the overmature Permian samples in Coonarah-1A (Table 6-7). In the Triassic sequence, the ratio is between 0.17 and 0.51, including the overmature sample No. 36 (Rv,max = 2.21%) from the lower part of the Napperby Formation in Bellata-1 at depth 829.60 m. Interestingly, the 20S ratio in this latter sample is only 0.48. This ratio is in fact less than the equilibrium point (0.52 – 0.55), also for overmature samples in both the Permian and Triassic sequences. This can be attributed to the high level of thermal maturity that results in inversion of the C29 sterane 20S ratio

(Lewan et al., 1986). In the Bowen Basin, the C29 sterane 20S ratio ranges from 0.14 in the Jurassic to 0.46 in the Permian sequences (Table 6-7), indicating that the 20S-20R epimerisation reaction for the analysed samples has not reached equilibrium. However, 209 Chapter 6 BIOMARKERS the ratio in the highly mature Moolayember Formation sample No. 7 (Rv,max = 1.30%) in Gil Gil-1 is only 0.28, most likely due to its inversion in the vicinity of the igneous intrusion body. Figures 6-15 and 6-16 show that this ratio is not affected (suppressed) by the marine incursions and/or organic matter variations (liptinite content) that have suppressed vitrinite reflectance and Tmax in the Permian sequences (Chapters 4 and 5). However, it is worth mentioning that the Permian coal samples in Bellata-1 have higher ratios than the siltstone samples (Table 6-7; Figure 6-15). This variation could be a facies effect (Kenneth Peters, 2002 personal communication). The lower Ts/(Ts+Tm) and C29Ts/C29 ratios in the Permian coals than siltstone samples (Table 6-7; Figure 6- 15) may also be attributed to facies effect.

The ββ ratio for the Permian sequence in the Gunnedah Basin ranges from 0.22 to 0.55, and for the Triassic sequence between 0.24 and 0.48. The highest ratio, as expected, is recorded for the highly mature, intrusion-affected samples (Black Jack Group in Coonarah-1A for example, Table 6-7). In the Bowen Basin, the ββ ratio for the Permian sequence ranges between 0.30 and 0.37, for the Triassic from 0.27 to 0.31, and from 0.32 to 0.48 in the Jurassic samples (Table 6-7). The ββ profile in Goondiwindi-1 (Figure 6-16) shows higher ratios for the Jurassic samples and marginal variations in the Triassic and Permian samples. The ratio, however, mainly responds to the facies changes and not to maturation in the Goondiwindi-1 samples, and probably in Bellata-1 sequence also, except for the highly mature intrusion effected interval in the Triassic Napperby Formation. In fact, the ββ ratio is a slower reaction than 20S, while 22S is the faster among the studied parameters (Figure 6-15), and Ts/(Ts+Tm) and C29Ts/C29 ratios are also slow in their reaction to maturity changes (Kenneth Peters, 2002 personal communication).

The diasterane abundance relative to the regular steranes in the samples analysed increases with increasing maturity, most obviously in the intrusion-affected intervals, sample No. 36 for example (Figure 6-10; Table 6-5). The diasterane to sterane ratios for the studied samples, however, are affected by TOC content (Figure 6-12), as discussed previously in section 6.4.1.

210 Chapter 6 BIOMARKERS

6.4.3. Aromatic hydrocarbons as source and maturity indicators

Vitrinite reflectance was calculated (Rc) on the bitumen fractions, and the resulting data are shown in Table 6-9 (see also Table 6-10). The calculated vitrinite reflectance according to Radke and Welte (1983) are the most similar with measured vitrinite reflectance (Rv,max) for the samples studied, whereas equations proposed by Kvalheim et al. (1987) and Boreham et al. (1988) shown poorer correlations (Figure 6-20; Table 6- 9). This match is also illustrated when measured and calculated vitrinite reflectance values from various methods are plotted against Tmax (ºC) from Rock-Eval pyrolysis (Figure 6-21; Table 6-9).

Suppression is recorded in the measured vitrinite reflectance due to the inferred marine incursion and increased liptinite content within the Permian sequence (see Chapters 4 and 5). Lowered (suppressed) values also have been observed for the calculated vitrinite reflectance in perhydrous samples from the Buller Coalfield in New Zealand (Norgate et al., 1999). In the area studied, the Rc is suppressed similarly to the Rv,max in perhydrous coal and non-coal Permian samples (Table 6-9), for both marine influenced (Back Creek Group and Maules Creek Formation) and increased liptinite content (Goonbri Formation) intervals. The intrusion-affected, highly mature samples are distinguished by high Rc values (Table 6-9). This is most obvious for the lower part of the Napperby Formation in Bellata-1 (Figure 6-22) and the Permian sequence in Coonarah-1A (Table 6-9).

The methylphenanthrene indices MPI 1 and MPI 2 increase regularly with maturity, and, as expected, change in a similar way to the vitrinite reflectance data with somewhat higher MPI 2 values (Table 6-9, Figure 6-22), which is attributed to 2- over 3-MP slight predominance (Radke et al., 1982b). The reduced MPI value in the postmature (Rv,max = 2.21%) sample No. 36 (Figure 6-23) is due to inversion of the indices in such a highly mature interval (cf. Radke et al., 1982a). The MPI 3 (which is calculated from the methylphenanthrene isomers 1-, 2-, 3- and 9-MPs, as opposed to MPI 1 and 2 that additionally takes into account the phenanthrene) increases with maturity (Table 6-9), and demonstrates a similar trend to other aromatic maturity parameters shown in Figure 6-22 (see also Table 6-9).

211 Chapter 6 BIOMARKERS

Table 6-9: Aromatic parameters used in this study. For parameters identification see Table 6-10.

2 3 4 8 10 Sample Rc(rw) Rc(b) Rc(k) 3-MP/ Retene/ 1 5 6 7 9 No. Basin Borehole Fm. Age type Lithology Depth (m) Rv,max % % % % MPI 1 MPI 2 MPI 3 retene DNR-1 9-MP 5 B/S Edendale-1 Back Creek Group Permian cutting 100% coal 2190 0.64 0.74 0.62 0.69 0.57 0.66 0.61 0.36 2.13 1.53 7 B/S Gil Gil-1 Moolayember Formation Triassic core coal 1307.97 1.30 0.99 0.91 1.08 0.99 1.12 1.25 2.14 1.63 0.39 9 B/S Goondiwindi-1 Walloon Coal Measures Jurassic cutting 90% coal, 5%shale, 5% sst 966.7 0.54 0.65 0.51 0.48 0.42 0.56 0.41 0.05 nd 12.32 11 B/S Goondiwindi-1 Evergreen Formation Jurassic cutting 60% sst, 30% coal, 10% siltstone 1264.92 0.56 0.51 0.35 0.19 0.18 0.36 0.19 0.01 0.00 1.22 12 B/S Goondiwindi-1 Evergreen Formation Jurassic cutting 60% shale, 30% siltstone, 10% coal 1356.36 0.72 0.56 0.41 0.48 0.26 0.36 0.41 0.26 5.11 1.03 13 B/S Goondiwindi-1 Moolayember Formation Triassic core shale 1554.18 0.77 0.80 0.69 0.94 0.67 0.79 0.97 7.24 nd 0.09 14 B/S Goondiwindi-1 Back Creek Group Permian cutting 100% coal 1886.71 0.60 0.67 0.54 0.64 0.45 0.52 0.56 0.39 0.93 1.28 15 B/S Goondiwindi-1 Back Creek Group Permian core shale 2117.44 nd 0.73 0.60 0.75 0.55 0.62 0.69 1.33 0.42 0.39 22 B/S McIntyre-1 Kianga Formation Permian cutting 80% shale, 20% siltstone 2200.66 0.72 0.74 0.62 0.66 0.57 0.65 0.59 0.22 0.00 2.24 26 B/S Mt Pleasant-1 Kianga Formation Permian cutting 90% coal, 10% shale 1423.42 0.65 0.64 0.50 0.53 0.40 0.47 0.45 0.14 1.14 2.20 30 B/S Werrina-2 Walloon Coal Measures Jurassic cutting 90% coal, 10% shale 1237.49 0.56 0.63 0.49 0.39 0.39 0.48 0.33 0.09 0.12 7.87 34 G/S Bellata-1 Napperby Formation Triassic core claystone 642.4 0.60 0.72 0.60 0.54 0.54 0.57 0.46 1.87 0.00 0.15 51 G/S Bellata-1 Napperby Formation Triassic core claystone 665.77 0.63 0.74 0.62 0.82 0.57 0.59 0.78 1.67 1.11 0.41 35 G/S Bellata-1 Napperby Formation Triassic core siltstone 805.18 0.98 0.94 0.85 0.87 0.89 1.01 0.85 1.60 nd 0.41 36 G/S Bellata-1 Napperby Formation Triassic core siltstone 829.6 2.21 1.95 2.68 1.25 0.58 0.70 1.70 68.57 2.69 0.02 37 G/S Bellata-1 Maules Creek Formation Permian core siltstone 929.6 nd 0.67 0.53 0.70 0.45 0.52 0.62 1.32 1.02 0.34 38 G/S Bellata-1 Maules Creek Formation Permian core coal 939.93 0.57 0.69 0.56 0.85 0.48 0.42 0.82 1.62 3.76 0.41 39 G/S Bellata-1 Goonbri Formation Permian core siltstone 1018.1 nd 0.71 0.58 0.68 0.52 0.51 0.60 3.96 0.95 0.12 40 G/S Bellata-1 Goonbri Formation Permian core coal 1054.74 0.66 0.74 0.62 0.74 0.57 0.66 0.68 0.55 0.84 0.78 41 B/S Bohena-1 Black Jack Group Permian core shale 660.85 0.62 0.81 0.69 0.82 0.68 0.78 0.78 1.50 0.89 0.38 44 G/S Coonarah-1A Napperby Formation Triassic core shale 421.96 0.60 0.65 0.51 0.55 0.42 0.46 0.47 1.09 0.26 0.45 45 G/S Coonarah-1A Napperby Formation Triassic core shale 453.35 0.81 0.84 0.73 0.70 0.73 0.82 0.63 4.04 nd 0.11 46 G/S Coonarah-1A Black Jack Group Permian core coal 522.6 1.80 1.40 2.17 1.41 1.50 1.77 2.38 nd 6.64 0.00 47 G/S Coonarah-1A Black Jack Group Permian core coal 572.09 1.99 1.26 2.05 1.31 1.73 2.04 1.94 517.18 6.01 0.00 48 G/S Coonarah-1A Black Jack Group Permian core shale 604.74 1.79 1.42 2.19 1.36 1.47 1.74 2.14 85.02 1.82 0.02 49 G/S Coonarah-1A Watermark/Porcupine Formation Permian core shale 613.24 1.62 1.89 0.69 1.55 0.68 0.85 3.29 124.23 nd 0.02 50 G/S Coonarah-1A Watermark/Porcupine Formation Permian core siltstone 635.35 1.80 1.56 2.32 1.26 1.24 1.49 1.75 236.98 nd 0.01 B/S = Bowen/Surat Basin G/S = Gunnedah/Surat Basin nd = not determi 212 Chapter 6 BIOMARKERS

Table 6-10: Identification of the parameters used in Table 6-9.

No. Ratio Parameter

1 Rv,max = measured maximum vitrinite reflectance.

2 Rc(rw) = calculated vitrinite reflectance from Radke and Welte (1983), see text for details.

3 Rc(b) = calculated vitrinite reflectance from Boreham et al. (1988), see text for details

4 Rc(k) = calculated vitrinite reflectance from Kvalheim et al. (1987), see text for details

5 MPI 1 = 1.5 (2-MP + 3-MP)/(P + 1-MP + 9-MP), (Radke et al., 1982a). Phenanthrene (P) multiplied by a response factor of 0.69 to correct GCMC data to FID.

6 MPI 2 = 3 (2-MP)/(P + 1-MP + 9-MP), (Radke et al., 1982a). Phenanthrene (P) multiplied by a response factor of 0.69 to correct GCMC data to FID.

7 MPI 3 = (%3-MP + %2-MP)/(%9-MP + %1-MP).

8 3-MP/retene = 3-MP/retene

9 DNR-1 = (2,6-DMN + 2,7-DMN)/(1,5-DMN), (Radke et al., 1982b).

10 Retene/9-MP = Retene/9-MP

213 Chapter 6 BIOMARKERS

Rv,max% - Rc(rw)% re l a ti onshi p Rv,max% - R c(b)% re l a ti onshi p Rv,max% - Rc(k)% re l a ti onshi p

Rc(rw)% Rc(b)% Rc(k)% 012301230123 0 0 0

1 1 1

% % % v,max v,max v,max R R R 2 2 2

3 3 3

Figure 6-20: Measured and calculated vitrinite reflectance plots for samples of Table 6-9. Rv,max% versus Rc(r)% shows closest similarity.

214

Tmax-Rv,max relationship T -R relationship T -R relationship T -R relationship max c(rw) max c(b) max c(k) o (oC) (oC) o Tmax ( C) Tmax Tmax Tmax ( C) 300 400 500 600 300 400 500 600 300 400 500 600 300 400 500 600

0 0 0 0

1 1 1 1

% % %

% v,max c(b) c(k) c(rw)

R R R R 2 2 2 2

3 3 3 3

o Figure 6-21: Tmax ( C) versus measured and calculated vitrinite reflectance plots for samples of Table 6-9.

215 Chapter 6 BIOMARKERS

MPI 1 and 2-Depth MPI 3 - Depth 3-MP/retane - Rv,max%- Depth Rc(rw)%- Depth relationship Depth relationship relationship relationship relationship MPI 1 and MPI 2 3-MP/retene R % R % MPI 3 v,max c(rw) 01230123-0.5 0.5 1.5 0120.1 1 10 100 1000 600 Purlawaugh Fm. 34 51 700

Napperby Fm.

800 35 36 36 Igneous intrusion

Depth (m) Depth Digby Fm. 900 Porcupine Fm. 37 38 Maules Creek Fm.

1000 39

40 Goonbri Fm. 1100

Figure 6-22: Variations of aromatic maturity parameters with depth for Bellata-1. MPI 2 marked as open circles. 216 Chapter 6 BIOMARKERS

Radke et al. (1986) and Budzinski et al. (1995) observed an increase in the 2-MP and 3- MP abundance associated with a parallel decrease in the 9-MP and 1-MP amount with increasing thermal maturity in oils and extracts from Type III organic matter. This can be seen in the Napperby Formation samples (Rv,max = 0.60, 0.98 and 2.21% respectively) in the Bellata-1 well (Figure 6-23), which is also indicated by an increase in MPI 3 values (0.46, 0.85 and 1.70 respectively; Table 6-9).

The 3-MP/retene ratio in general increases with increasing thermal maturity (Table 6-9) and increases, similar to vitrinite reflectance, close to the igneous paleo-heat source in the Napperby Formation in Bellata-1 (Figure 6-22; Table 6-9). The ratio, however, increases markedly in postmature samples, as in the Permian sequence in Coonarah-1A, (Table 6-9) which is possibly due to a greater loss of retene in the more mature samples and partially to an increase in 3-MP with increasing maturity. Even though the 3- MP/retene ratio increases with increasing thermal maturity, exceptions are noted, for example sample No. 40 (Figure 6-22; Table 6-9). This exception might be attributed to facies changes in addition to maturity effects (cf. Wilhelms et al., 1998).

Within the vitrinite reflectance suppressed interval in Goondiwindi-1, the 3-MP/retene ratio increases and shows no special change with the marine influenced perhydrous samples (Table 6-9). However, this is not clear in Bellata-1 suppressed Permian sequence (Figure 6-22; Table 6-9). Further analysis, however, is required to establish a relation between 3-MP/retene ratio and vitrinite reflectance in perhydrous sequences.

The dimethylnaphthalene ratio (DNR) is non-linear with depth (Radke et al., 1982a). In the present study, it does not change systematically with increasing maturity, particularly within highly mature intervals, and shows a broad variation (DNR = 0.0 – 6.64; Table 6-9). George (1992) related such a large range of values in his study on intrusion affected intervals in Scotland to the low abundance and instability of 1,5- dimethylnaphthalene, which has an α,α-configuration.

Ellis et al. (1996) used the retene/9-MP ratio as land plant indicator in oil samples. Low ratios in the postmature Permian interval in Coonarah-1A, for example (Table 6-9), are attributed to the high level of thermal maturity rather than to organic matter variations, because retene is more dominant in the low maturity samples (Wilhelms et al., 1998). 217 Chapter 6 BIOMARKERS

9-MP 2-MP 3-MP Sample No. 34 Bellata-1 1-MP Napperby Fm. 642.40 m Rv,max = 0.60% MPI 3 = 0.46

Sample No. 35 Bellata-1 Napperby Fm. 805.18 m

Rv,max = 0.98% MPI 3 = 0.85

Sample No. 36 Bellata-1 Napperby Fm. 829.60 m

Rv,max = 2.21% MPI 3 = 1.70

Figure 6-23: Changes in the 1-, 2-, 3- and 9-MP abundance with increasing maturity close to igneous intrusions in the Napperby Formation, Bellata-1.

218 Chapter 6 BIOMARKERS

6.5. Discussion and conclusions

In this chapter selected source rock samples of Permian, Triassic and Jurassic age were further investigated using molecular parameters for a set of various saturated and aromatic hydrocarbons. Source input, depositional environment and thermal maturity were further evaluated, and various maturity parameters were examined in intervals of the Permian succession with suppressed Tmax and vitrinite reflectance values.

The regular decrease in abundance of homohopane distributions towards higher molecular weight, which lowered the homohopane indices, and the values of less than unity for the C29/C30 hopane ratios, except for sample No. 49, are consistent with the clay-bearing character of the samples analysed. Even though the latter ratio is commonly known as source and environmental indicator, the high maturity levels resulting from localised heat sources due to igneous intrusions seems to have affected this ratio in the samples studied. An increase is observed in the C29/C30 hopane ratios for the Napperby Formation in Bellata-1 close to such a paleo-heat source (Table 6-5). The values of more than unity (1.12) for the C29/C30 hopane ratio in the Watermark/ Porcupine Formation in Coonarah-1A, sample No. 49, and also the relatively high ratios in other high maturity samples, for example No. 7, 36 and 48 (Table 6-5), are possibly related to high thermal maturity levels in these samples rather than to lithology effects. Other samples, however, which were not subjected to such localised and rapid heating, for example those from Goondiwindi-1 (Table 6-5), are not characterised by such high

C29/C30 hopane ratios with increasing maturity due to burial alone.

Oxic to suboxic conditions of the sedimentary environment are indicated by trace amounts of 25-NH, BNH and TNH in the samples studied. High relative abundances of

C29 sterane and low sterane/hopane ratios (0.30) suggest that terrestrial organic matter was the main source input. The considerable abundance of C29Ts and diahopane also supports the deposition of the terrestrial organic matter under oxic to suboxic conditions. Ternary plots of steranes and diasteranes further indicate the terrestrial source nature of the preserved organic matter in the samples studied. However, the low abundance of C29 steranes and diasteranes in samples affected by igneous intrusions (Figure 6-11) is attributed to the high maturity level rather than to variations in the source organic matter. 219 Chapter 6 BIOMARKERS

It is generally recognised that high diasterane/sterane ratios commonly identify source rocks with an abundant clay content, and that low ratios occur in carbonate source rocks deposited under anoxic conditions. However, the current study shows a regular increase in this ratio with increasing TOC% (from Rock-Eval pyrolysis) for samples with up to 5% TOC, and a decrease in the ratio with higher TOC content, including coals. Only a few coal samples, sample No. 38 for example, occur as outliers on the plot (Figure 6- 12). Slight variations in organic matter input for coals, however, can lead to variable geochemical characteristics (Casareo et al., 1996). Due to their high level of thermal maturity, as expected, the samples affected by igneous intrusions plot separately, with higher diasterane/sterane ratios in both cases (Figure 6-12).

The marine influence on the Back Creek Group sequence in the New South Wales portion of the Bowen Basin (Othman and Ward, 1999, 2002; see Chapters 4 and 5) and in the Maules Creek Formation of the Gunnedah Basin (Gurba, 1998; Gurba and Ward, 1998, 1999; Othman and Ward, 1999, 2002; see Chapters 4 and 5) has been supported by the suppression of measured vitrinite reflectance. The same phenomenon was also noted in the Goonbri Formation, where it is attributed to the liptinite rich organic matter content of this particular sequence (Othman and Ward, 1999, 2002; see Chapters 4 and 5). The suppression phenomenon in these sequences has probably resulted from the perhydrous nature of the preserved organic matter as discussed in Chapter 4. The calculated vitrinite reflectance (as well as MPI 1 and MPI 2), which is based on the aromatic compounds, seems to have been lowered (suppressed) in a similar way to that of the measured vitrinite reflectance in the marine-influenced and liptinite rich, perhydrous, Permian sequences. Low calculated vitrinite reflectance values in marine sequence could be due to anomalously high 9-methylphenanthrene, which is abundant in marine origin organic matter (Budzinski et al., 1995). The absence of marine biomarker signatures among identified terpane and sterane compounds could be attributed to their dilution by overwhelming amounts of non-marine organic matter (e.g. Volkman et al., 1983b; Tissot and Welte, 1984; Moldowan et al., 1985), and their likely presence in only minute amounts, below the detection limit of the GC-MS. Although the terrestrial character decreases in the marine influenced Permian sequence in the area studied, the identified terpane and sterane compounds suggest that the source rock organic matter is still terrestrial in origin. However, further investigations, for example 220 Chapter 6 BIOMARKERS by GC-MS-MS to identify C30 steranes as a useful marker for marine environments (Moldowan, 1984; Peters et al., 1989), is required for better elucidation of the presence or absence of marine biomarkers.

Biomarker maturity parameters have been shown to change with increasing thermal maturity (Table 6-7). Two indicators (22S and 20S), however, showed a reversal in highly mature samples that have been more rapidly heated by igneous intrusions. Similar results have been previously documented in other sequences rapidly heated due to igneous intrusions (e.g. Raymond and Murchison, 1992; Bishop and Abbott 1993;

Farrimond et al., 1996). The ratio of C24 tetracyclic terpane to C21-C26 tricyclic terpanes behaved differently, and decreased regularly with increasing maturity towards the igneous intrusion in the Napperby Formation in Bellata-1, where the sediment is within the early mature to postmature stages based on a vitrinite reflectances of 0.6 to 2.21%. The high maturity igneous intruded intervals in the Permian sequence in Coonarah-1A, for example, are also characterised by low ratios of C24 tetracyclic terpane to C21-C26 tricyclic terpanes. This observation is similar to that reported by Farrimond et al. (1999), who indicated that the ratio increases toward the oil window and then decreases within the oil window and in postmature intervals close to igneous intrusions.

Among the terpane and sterane maturity parameters studied, the 22S ratio is the fastest in reaction (Kenneth Peters, 2002 personal communication). The samples studied from the Gunnedah Basin show that the Permian sequences in the Bellata-1 and Bohena-1 wells are within the oil generation stage based on 22S ratios of 0.54 to 0.58 (Table 6-7). The less than equilibrium values of the ratio in the Permian Coonarah-1A samples, and in the postmature Triassic Napperby Formation sample (No. 36) in Bellata-1, are due to inversion of the 22S ratios in the igneous intrusion affected high maturity intervals. The ratio for other Triassic samples in the Gunnedah Basin ranges between 0.47 and 0.58 (Table 6-7), and the sequence is considered to lie within the oil generation zone in Coonarah-1A and to be marginally mature at best in Bellata-1. In the Bowen Basin succession, based on the 22S ratios (Table 6-7), the Permian sequence is within oil generation zone, except for the Kianga Formation sample (No. 22) in McIntyre-1. The Triassic sequence is marginally mature except in the highly mature Moolayember Formation sample (No. 7) in G il Gil-1, which has a low value (0.49) due to inversion of the ratio, while the analysed Jurassic samples from the Bowen Basin are considered 221 Chapter 6 BIOMARKERS immature. Based on the 20S ratios (Table 6-7), only few samples, No. 45 for example, have reached the equilibrium point. The ratio is inverted, however, within the highly mature igneous intrusion affected intervals, sample No. 36 for example (Table 6-7).

Moretane/hopane ratios decrease, and Ts/(Ts+Tm), C29Ts/C29 and 20S ratios increase, with increasing maturity (Figure 6-15). The latter parameter shows higher values in Permian coals ( sample Nos. 38 and 40; Figure 6-15) than in the Permian siltstones

(sample Nos. 37 and 39; Figure 6-15), while Ts/(Ts+Tm) and C29Ts/C29 is lower in coal than in siltstone for the same samples. This variation is probably a result of facies effects. The ββ ratio responds more slowly to reaction than the other ratios, 22S and 20S ratios for example, with maturity increase, and variations in this parameter in low maturity intervals are affected by facies changes rather than maturity. Maturity parameters based on tricyclic and tetracyclic terpanes (Table 6-7) show consistent increase with depth within the Napperby Formation in Bellata-1 (Figure 6-19). Although these ratios show variations in other studied sequences, they are considered more reliable as maturity indicators when applied to genetically related extracts and oils (Seifert and Moldowan, 1978). Terpane and sterane maturity parameters are not lowered or ‘suppressed’ like Tmax and vitrinite reflectance in the Permian sequences of the area studied. This result indicates that a perhydrous character of the preserved organic matter due to marine influence or liptinite rich organic matter source input, seems not to effect the response of these parameters to maturity increase.

Calculated vitrinite reflectance from the bitumen fractions, based on Radke and Welte

(1983)’s method (Rc(rw)), as well as MPI 1 and MPI 2 generally agree with measured vitrinite reflectance (Rv,max) on the same samples (Table 6-9). These parameters increase with increasing maturity and are lowered in the suppressed (perhydrous) intervals. The MPI 1 and MPI 2, however, are inverted in some highly mature samples, as in the Napperby Formation in Bellata-1 (sample No. 36, Figure 6-22; Table 6-9). MPI 3 is also in a good agreement with observed vitrinite reflectance, although less than for MPI 1 and MPI 2.

Even though the 3MP/retene ratio illustrates a good comparison with vitrinite reflectance, further investigation is required to evaluate this ratio’s reaction within the reflectance suppressed intervals.

222 Chapter 7 OIL-SOURCE CORRELATION

7. Chapter 7 OIL-SOURCE CORRELATION

7.1. Introduction

A few oil shows have been discovered in wells of the study area, such as the Bohena-1 well in the Bohena Trough and the Bellata-1 well in the Bellata Trough (Figures 1-1 and 1-2, Chapter 1). Currently no significant or commercial petroleum accumulations have been identified, although numerous minor gas shows, including some significant gas accumulations, have been reported from coal exploration boreholes in the Gunnedah Basin (e.g. Morton, 1995).

Oil staining has been noted in cores of the Jurassic Pilliga Sandstone in the Bellata-1 well (Etheridge, 1987). The origin of the staining has always been somewhat controversial, and has been suggested by some authors to be anthropogenic in origin (see below). This chapter aims to shed further light on the origin of this oil staining, by using organic geochemical data for selected samples from the oil stain and for the Permian and Triassic strata identified as potential source rocks (Figure 7-1). Particular attention is paid to the likelihood of oil generation under the influence of localised thermal regimes induced by the emplacement of igneous intrusions within the Triassic sedimentary succession (Figure 7-1 and Table 7-1).

This chapter therefore represents a case study arising from the thesis, aimed at solving problems associated with the source of this oil by using the methods and data described in the previous chapters.

7.2. Oil staining occurrences

An oil show was reported from the Late Carboniferous to Early Permian Boggabri Volcanics in the Bohena-1 well (Figure 1-2, Chapter 1). A core cut within a sequence of interbedded marine mudstones and volcanics, over the interval from 1309.40 to 1312.64 m, was found to comprise 1 cm of mudstone underlain by tuffaceous conglomerate containing basalt pebbles. Dark-brown oil drops and gas bubbles bled from the core. Oil was smeared along fracture planes and also occupied vesicles within the basalt pebbles. The mudstone was sandwiched between two thick lava flows, and it was

223 Chapter 7 OIL-SOURCE CORRELATION

Figure 7-1: Stratigraphy in Bellata-1, showing major igneous intrusions (see Table 7-1), the horizons sampled for oil staining (+) and potential source rocks (●), (modified from Othman et al., 2001).

224 Chapter 7 OIL-SOURCE CORRELATION

Table 7-1: Thickness’ of igneous intrusions intersected in Bellata-1

Depth (m) Intrusion Thickness (m) 847.60 15.68 857.88 2.93 873.15 1.30 874.63 0.40 879.82 0.88 883.62 1.24 1107.70 2.18

assumed that the mudstone was the source for the oil show discovered in the Bohena-1 well (Hamilton et al., 1988).

In the fully-cored Bellata-1 well, approximately eight barrels (1270 litres) of diesel fuel (from the B.P. Depot, Moree, New South Wales) are reported to have been added when drilling had reached a depth of 470 m, in order to free a jammed drilling bit. Drilling did not resume until drilling mud had displaced the diesel fuel and the mud had been tested for contamination (Gould, 1986). Extensive oil staining was subsequently discovered in the Jurassic Pilliga Sandstone over the depth interval 480 to 599.67 m (Gould, 1986; Etheridge, 1987), along with a strong gas show in the underlying Purlawaugh Formation (Hamilton et al., 1988). The distribution of oil stained Pilliga Sandstone was evidenced by its appearance and a strong petroliferous odour (Gould, 1986). The hydrocarbon occurrences were preserved in porous and permeable sandstones that alternated with unstained intervals and tight sandstones and shales. In the depth interval from 480 to 576.45 m, above a 0.1 m shale band, the Pilliga Sandstone comprises alternating and variable high porosity-permeability oil-stained sandstones and finer grained, tight, oil- free sandstones. Between 576.5 m and 592 m high porosity-permeability oil-free sandstones are interbedded with either shale or tight oil-free sandstones. Below 592 m the Pilliga Sandstone consists of petroliferous porous-permeable sandstone (Gould, 1986).

225 Chapter 7 OIL-SOURCE CORRELATION

There has been considerable controversy as to the nature of the staining in the Jurassic sandstones in Bellata-1 well. Many parties believe that the oil stain is result of diesel contamination (e.g. McKirdy, 1986), but geochemical investigations of hydrocarbons extracted from the stained cores were generally inconclusive (Gould, 1986; Hamilton et al., 1993; Stewart and Alder, 1995b). These studies were based primarily on gas chromatographic comparison of the oil stain and diesel samples believed to resemble that used in the drilling program.

Subsequent re-examination of core from the basal Pilliga Sandstone in the neighboring Moema-1 well (located 20 km SE of Bellata-1; Figure 1-2, Chapter 1), drilled in 1975, also showed oil staining and fluorescence (Hamilton et al., 1988). Geochemical investigations were again inconclusive, and it is not known if this staining represents residual oil formed by natural processes or contamination by diesel used during drilling operations (Hamilton et al., 1993). It is important to note that the Triassic sequence in the Moema-1 well intersects a total thickness of more than 30 m of intrusive igneous rocks distributed over four separate intervals.

7.3. Samples and analysis

7.3.1. Samples

To achieve the objectives of this study, an oil-stained sandstone sample and a carbonaceous siltstone sample were selected from the Jurassic Pilliga Sandstone in the Bellata-1 core. Twenty potential source rock samples were also chosen to represent coal, shale and carbonaceous siltstone lithologies from the underlying Permo-Triassic sequence (Figure 7-1).

Previous studies had used most of the richly oil stained parts of the Pilliga Sandstone. However, although the chosen sample was not rich in its oil-stain content, there was sufficient oil present for organic geochemical studies.

226 Chapter 7 OIL-SOURCE CORRELATION

7.3.2. Analytical techniques

Polished sections for petrographic analysis were prepared from all 22 samples (Chapters 2 and 4). Mean maximum vitrinite (telocollinite) reflectance determinations were carried out using on average at least 30 individual measurements for each sample, except for the sandstone where only 12 measurements were taken due to the low organic matter content, as might be expected in sandstones. Nine of the samples, including the oil stained material, were selected for further organic geochemical analyses (Table 7-2). Potential source rock samples were screened by Rock-Eval pyrolysis (Chapters 2 and 5) to ascertain their source richness and kerogen type (Table 7-3). Bitumen was extracted using Soxhlet apparatus (Chapter 2). The extracts were then fractionated by silica/alumina column chromatography into saturated hydrocarbons, aromatic hydrocarbons and NSO compounds, and the saturated and aromatic hydrocarbon fractions were analysed further by GCMS (Chapters 2, 5 and 6).

7.4. Oil stain characterisation

7.4.1. Aromatic source parameters

The pre-Jurassic source affinity of the oil stain is evident based on its mono-, di-, and trimethylphenanthrene and retene distributions (Figure 7-2). However, no clear distinction as to whether it is of Triassic or Permian origin can be made using such plots, which were developed by Alexander et al. (1988) to distinguish between Jurassic and Permian oils in the Cooper and Eromanga Basins (see section 6.3.3.4, Chapter 6).

7.4.2. Thermal maturity of the oil stain

The gas chromatogram (m/z 85 profile) of saturated hydrocarbons (Figure 7-3) for the oil stain has a unimodal distribution, which is maximised in the lower molecular weight range and declines towards higher molecular weight n-alkanes. Such a profile may be evidence of a mature, terrestrial organic matter predominant source (Radke et al., 1980; Milner, 1982). As demonstrated in Table 7-2, the oil stain sample is identified with a slight n-alkane paraffin odd-over-even preference value (CPI = 1.32), and a low isoprenoid to n-alkane ratio (pr/n-C17 = 0.34). Biomarker maturity parameters of the saturated hydrocarbons (Table 7-2) show, in addition, that the 22S C31 homohopane

227 Chapter 7 OIL-SOURCE CORRELATION

Table 7-2: Geochemical data for an oil stain sample from the Pilliga Sandstone, and other Permo-Triassic potential source rocks in Bellata-1 (modified from Othman et al., 2001). For parameters identification see Chapter 6.

TOC EOM

No. Stratigraphic Units Depth (m) Age (wt%) (mg/gTOC) pr/ph pr/n-C17 CPI Rv,max (%) Rc(rw) (%) MPI-1 52 Pilliga Sandstone 566.73 Jurassic 0.16 109 0.75 0.34 1.32 0.42 1.29 1.48 34 Napperby Formation 642.4 Triassic 56.7 32 4.51 2.07 2.23 0.60 0.72 0.54 51 Napperby Formation 665.7 Triassic nd nd 5.68 1.15 2.45 0.63 0.74 0.57 35 Napperby Formation 805.18 Triassic 1.49 30 1.04 0.61 1.40 0.99 0.94 0.89 36 Napperby Formation 829.6 Triassic 1.89 4 1.37 0.55 1.05 2.21 1.95 0.58 37 Maules Creek Formation 929.6 Permian 9.42 40 4.17 1.03 2.46 nd 0.67 0.45

38 Maules Creek Formation 939.93 Permian 52.36 35 5.62 4.51 1.87 0.57 0.69 0.48 39 Goonbri Formation 1018.1 Permian 10.76 46 1.87 3.64 2.55 nd 0.71 0.52 40 Goonbri Formation 1054.74 Permian 82.75 48 8.33 12.26 1.80 0.67 0.74 0.57

228 Chapter 7 OIL-SOURCE CORRELATION

Table 7-3: Geochemical data for an oil stain sample from the Pilliga Sandstone, and other Permo-Triassic potential source rocks in Bellata-1 (modified from Othman et al., 2001). For parameters identification see Chapter 6 continued.

Regular steranes Diasteranes

No. MPI-2/MPI-1 20S αββ/ααα 22S βα/αβ Ts/(Ts+Tm) C29/C30 C29Ts/C29 C30*/C30 C27 C28 C29 C27 C28 C29

52 1.22 0.51 2.06 0.53 0.18 0.37 1.16 0.17 0.10 35 26 39 28 34 38

34 1.07 0.20 0.79 0.47 0.68 0.02 0.54 0.03 0.04 7 37 56 8 40 52

51 1.03 0.17 0.60 0.47 0.74 0.03 0.63 0.03 0.07 7 22 71 7 26 67 35 1.13 0.24 0.49 0.51 0.65 0.07 0.84 0.09 0.05 21 25 54 23 34 43 36 1.20 0.48 1.78 0.54 0.17 0.48 0.99 0.23 0.16 43 21 36 26 35 39 37 1.16 0.23 0.69 0.55 0.35 0.07 0.43 0.11 0.03 6 18 76 6 25 69 38 0.86 0.30 0.98 0.54 0.49 0.04 0.65 0.10 0.08 11 21 68 8 21 71 39 0.98 0.19 0.34 0.54 0.47 0.12 0.62 0.11 0.06 25 12 63 26 13 61 40 1.16 0.29 0.50 0.58 0.52 0.03 0.66 0.06 0.03 3 18 79 6 22 72

229 Chapter 7 OIL-SOURCE CORRELATION

Table 7-4: Rock-Eval data on potential source rocks, Bellata-1 (modified from Othman et al., 2001).

o No. Formation Depth (m) Rv,max%Tmax CS1+S2 mg/g TOC wt% HI OI Kerogen type 33 Purlawaugh Fm. 613.6 0.56 433 0.94 1.19 78 30 III 34 Napperby Fm. 642.4 0.60 428 97.31 56.70 171 16 II-III 35 Napperby Fm. 805.18 0.99 435 0.93 1.49 62 83 III 37 Maules Creek Fm. 929.6 0.67* 430 14.80 9.42 155 14 II-III

38 Maules Creek Fm. 939.93 0.57 427 97.73 52.36 183 1 II-III

39 Goonbri Fm. 1018.1 0.71* 428 27.78 10.76 249 9 II-III 40 Goonbri Fm. 1054.74 0.67 427 177.91 82.75 211 11 II-III *Calculated vitrinite reflectance (Rc(rw)); see Chapter 6

230 Chapter 7 OIL-SOURCE CORRELATION

Figure 7-2: Source affinity of the oil stain based on the aromatic hydrocarbon plots (modified from Othman et al., 2001).

231 Chapter 7 OIL-SOURCE CORRELATION

22

CPI=1.32 18 Pr/n-C17=0.34 Pilliga Sst. 566.73 m 17 Rc(rw)=1.29% Oil stain Rv,max=0.42% 25

CPI=2.23 Napperby Fm. 642.40 m Pr/n-C17=2.07 Pr Rock extract Rv,max=0.60% Triassic

25 CPI=2.45 Napperby Fm. 665.77 m Pr/n-C17=1.15 Pr Rock extract Rv,max=0.63% Triassic

25 29 CPI=1.40 Napperby Fm. 805.18 m 17 Pr/n-C17=0.61 Rock extract Rv,max=0.99% Triassic

18 20 17 19 22 24 27 CPI=1.05 21 23 25 31 Napperby Fm. 829.60 m 33 Pr/n-C17=0.55 Rock extract Rv,max=2.21% Triassic

25

CPI=2.46 29 Maules Creek Fm. 929.60 m Pr/n-C17=1.03 Pr Rock extract Rc(rw)=0.67% Permian

25

Pr CPI=1.87 Maules Creek Fm. 939.93 m Pr/n-C17=4.51 Rock extract Rv,max=0.57% Permian

25

CPI=2.55 Pr Goonbri Fm. 1018.10 m Pr/n-C17=3.64 Rock extract Rc(rw)=0.71% Permian

25 Pr CPI=1.80 Goonbri Fm. 1054.74 m Pr/n-C17=12.26 Rock extract Rv,max=0.67% Permian

Figure 7-3: Mass chromatograms (m/z 85) show the alkane distributions in the oil stain and selected potential source rocks in Bellata-1 (modified from Othman et al., 2001).

232 Chapter 7 OIL-SOURCE CORRELATION

ratio is 0.53, the moretane/hopane ratio is 0.18 and C29 sterane 20S ratio is 0.51. These are all features of mature oil, taking into consideration the possibility of a reversal in 22S and 20S values in rapidly-heated source rocks due to igneous intrusion effects (see Chapter 6) as in lower part of the Napperby Formation.

The MPI-based calculated vitrinite reflectance for the oil of the stain based on Radke and Welte (1983)’s method (Rc(rw)) is 1.29% (Table 7-2, Figure 7-4), suggesting expulsion from a source rock at a maturity level equivalent to the late oil window.

Similar data (Rc = 1.09% and 1.11%) were previously reported for oil stain samples from depths 480 m and 573.3 m, respectively (Gould, 1986). Comparison of the maturity of the oil stain (Rc(rw) = 1.29%) with that of the host rock (Rv,max = 0.42%) indicates that the oil is out-of-place (Figure 7-4); it was not sourced locally from the Jurassic sediments, but generated instead at a greater depth and maturity level. This is consistent with the source affinity of the oil stain as discussed above, and the high bitumen extractability (109 mg/g TOC) in the sandstone sample (Table 7-2).

7.4. Vitrinite reflectance profile in Bellata-1

The Rv,max-depth profile for the Bellata-1 well illustrates three intervals with different reflectance trends (Figure 7-5; see also section 5.7, Chapter 5). These include; normal trend interval, anomalously high Rv,max interval, and vitrinite reflectance suppressed. The normal trend is observed in the upper half of the sedimentary column, including the Jurassic and part of the Triassic sequence, and shows a gradient for vitrinite reflectance of 0.149% per 100 m. The second interval, with anomalously high Rv,max values due to igneous intrusions, is mainly recognised in the lower part of the Triassic Napperby Formation. Vitrinite reflectance over this interval reaches up to 2.43% at a depth of 871.55 m. A total of six intrusion bodies were intersected within the lower part of Napperby Formation with thicknesses ranging between 0.40 and 15.68 m (Table 7-1). A sample near the bottom of the Permian Goonbri Formation, at depth 1104.16 m, also shows the effect of local heating (Rv,max = 2.16%) due to a thin intrusive body (Figure 7- 5 and Table 7-1). Suppressed vitrinite reflectance interval is marked by anomalously low (suppressed) reflectance values over the entire Permian section. Suppressed vitrinite reflectance measurements for the Maules Creek Formation in the northern Gunnedah Basin have been attributed to marine influence (Othman and Ward, 2002; Chapter 4).

233 Chapter 7 OIL-SOURCE CORRELATION

2.5

2

1.5 %

c(rw)

R 1

0.5

0 0 0.5 1 1.5 2 2.5 Rv,max %

Figure 7-4: Calculated and measured vitrinite reflectance relationship in Bellata-1, open circle is the oil stain sample that clearly differs.

Rv,max (%)

0123 550 Pilliga Sst.

Purlawaugh Fm. 650

750 Napperby Fm.

850 Digby Fm. Depth (m) Porcupine Fm. 950 Maules Creek Fm.

1050 Go on bri Fm.

Basement 1150 Major igneous intrusions

Figure 7-5: Vitrinite reflectance profile in Bellata-1 (modified from Othman et al., 2001).

234 Chapter 7 OIL-SOURCE CORRELATION

Similar reasoning was given to explain the suppressed reflectance values of the Permian coals of the Maules Creek Formation further south (Gurba and Ward, 1998; Othman and Ward, 2002; Chapter 4). The underlying Goonbri Formation in Bellata-1 shows even lower reflectance values, apparently due to the presence of a liptinite-rich lacustrine organic facies (Othman and Ward, 2002; Chapter 4).

As shown in the Rv,max-depth profile for Bellata-1 (Figure 7-5), even the deepest parts of the sedimentary succession in the trough have not attained sufficient maturity to produce such highly mature oil, except where they are affected by igneous intrusions. This emphasises the likelihood that igneous intrusions in the basin have played an important role in heating certain parts of the sedimentary succession, leading to hydrocarbon generation. In considering the thermal maturity of the source rocks, the lowermost part of the Napperby Formation (between ~820 and 900 m), as well as the bottom of the Goonbri Formation, has achieved or passed the minimum requirement of

1.29% Rv,max to be considered as a potential source rock for the oil stain (Figure 7-5). It is also possible that the 1.29% Rc(rw) represents the average maturity of the oil, and that a larger range of maturity within the lower Napperby Formation was involved in hydrocarbon generation which culminated during the final stage of the conventional oil window.

7.5. Source rocks and hydrocarbon generation

Suppression of the vitrinite reflectance in the Permian section precludes accurate assessment of its actual maturity level. An offset of up to around 0.2% has been found elsewhere in the region, for the Goondiwindi-1 well for example, between suppressed and associated non-suppressed reflectance data (see also Gurba and Ward, 1998, 1999). Even adding such an increment to the suppressed reflectance values of the Permian sequence in Bellata-1, the entire section does not appear to be mature enough to have produced the highly mature oil (Rc(rw) = 1.29%) discovered in the basin.

Extrapolating the maturity trend of the overlying section may offer an alternative basis for assessing thermal maturity without the suppression effects. However, the maturation gradient in the Bellata well may be exaggerated due to heat derived from the intrusion in the lower part of the Triassic section. The maturation gradient would probably have

235 Chapter 7 OIL-SOURCE CORRELATION

been considerably lower if the section was not intruded. Nearby areas clearly have similar lower maturation gradients, unless they are also affected by intrusions (Othman and Ward, 2002).

The elevated reflectance associated with igneous intrusions, and the clear departure from solely burial-related trends, allow intruded sections to be readily identified. Although a vitrinite reflectance of 2.43% is recorded within the intruded zone in the lower part of the Napperby Formation, Rv,max drops to 0.99% at a depth 805.18 m, and to 0.84% at 781.8 m before returning to 0.63% at a depth of 665.77 m. As a result of heating due to post-Triassic emplacement of the igneous intrusives, the Napperby Formation below 819 m (~ 20% of its total thickness), and a narrow interval extending some 4 m above and below the 2.18 m-thick sill in the lower part of the Goonbri Formation (cf. Dow, 1977), have both passed rapidly through the oil window and are currently postmature (Figure 7-5). These intervals may represent spent source rocks from which hydrocarbons were expelled into nearby porous horizons. Other parts of the same formations further away from the paleoheat source are still within the oil window at present, where they can be expected to be actively generating hydrocarbons.

7.6. Oil-source rock correlation

7.6.1. n-Alkanes and isoprenoids

The m/z 85 profile of the saturated hydrocarbon fraction of the oil stain is shown in Figure 7-3, together with the corresponding traces for the underlying Triassic and Permian source rock extracts from Bellata-1. Various normal and isoprenoid alkane ratios are presented in Table 7-2. With a unimodal n-alkane distribution maximising at n-C22, the oil stain is clearly dissimilar to any of the potential source rock samples analysed in the study with respect to their overall alkane distributions. This could be attributed to fractionation effects associated with expulsion and primary migration of hydrocarbons (Mackenzie et al., 1983; Leythaeuser et al., 1984). Such a contrast between oil stain and potential source rocks may also be ascribed to the stains’ high level of thermal maturity (Rc(rw) = 1.29%), as evidenced by its low isoprenoid to n- alkane ratio (Pr/n-C17 = 0.34), and minimal predominance of odd-over-even carbon numbered n-alkanes (Figure 7-3, Table 7-2). On the other hand, alkanes from the coal

236 Chapter 7 OIL-SOURCE CORRELATION

and the carbonaceous mudstones and siltstones of the Napperby Formation, Maules Creek Formation and Goonbri Formation are all characterised by a pronounced odd- over-even carbon number preference (CPI = 1.80 – 2.55) and relatively high pristane abundances (Pr/Ph = 1.87 – 8.33). Collectively these features are consistent with immature, higher plant-derived organic matter, deposited in a predominantly oxic environment (Powell and McKirdy, 1973). Notable exceptions are the samples from the lower Napperby Formation most influenced by heat from the intrusion (i.e. those at 805.18 m and 829.60 m depth, about 26.74 and 2.32 m above the thickest intrusion, respectively), where lower CPI and Pr/n-C17 values are recorded (Table 7-2). These values approach those of the oil stain, suggesting a possible genetic relationship between these rocks and the oil stain. However, as expected, the sample analysed here (829.60 m) that was most affected by the intrusion is the most lean in extractable organic matter (EOM = 4 mg/g TOC, compared with 30 – 48 mg/g TOC in other, less affected, rock samples).

7.6.2. Hopane and sterane distributions

Figure 7-6 shows the triterpane (m/z 191) and sterane (m/z 217) distributions in the oil stain and representative Triassic (Napperby Formation) and Permian (Maules Creek and Goonbri Formations) rock extracts. Based on selected maturity and source-dependent biomarker parameters (Table 7-2), the intruded part of the Napperby Formation appears to be the best candidate for the oil source. In each of these two samples, steranes and terpanes have reached their thermodynamic equilibrium ratios (e.g. C29 sterane

20S/(20S+20R) = 0.51 – 0.48; C31 hopane 22S/(22S+22R) = 0.53 – 0.54); Ts/(Ts+Tm)

= 0.34 – 0.48; C30 βα/αβ hopane = 0.18 – 0.17: Table 7-2, Figure 7-6). The accepted equilibrium values for the sterane 20S to 20R and hopane 22S to 22R epimerisation reactions are 0.52-0.55 and 0.57-0.62 respectively (Seifert and Moldowan, 1986), slightly greater than those observed in the oil stain and its inferred source rock. This may be due to reversal of the trend in these parameters at the high maturity achieved by the samples in question (see Chapter 6). The high maturity of the samples is also evidenced by the predominance of the ββ sterane isomers (Table 7-2). The lower maturity of the other samples unaffected by intrusions, as inferred from the vitrinite reflectance data, is supported by the biomarker data (Table 7-2). This is better

237 Chapter 7 OIL-SOURCE CORRELATION

m/z 191 m/z 217 29 αα+ββ 27 28 βα+αβ αα+ββ 29 30

29T 31 556.73 m Tm 32 Pilliga Sst., Ts 33 34 35 Oil stain

30 29

Napperby Fm., 805.18 m Tm Rock extract Triassic

Napperby Fm., 829.60 m 29 30 Rock extract Tm Triassic Ts

29 30 βα+αβ 929.60 m Maules Creek Fm., Tm βα Rock extract βα βα Permian

30 Goonbri Fm., 1054.70 m Tm βα Rock extract βα Permian

Figure 7-6: Mass chromatograms of triterpanes (m/z 191) and steranes (m/z 217) in the oil stain and potential source rocks in Bellata-1 (modified from Othman et al., 2001).

238 Chapter 7 OIL-SOURCE CORRELATION

exemplified on the Biomarker Maturation Index (BMAI) versus Biomarker Migration Index (BMI) plot (Figure 7-7) of Seifert and Moldowan (1981), which shows a clear separation between the low-maturity Permo-Triassic source rocks and the highly mature oil stain. Again, the only similarity is with the lower part of the Napperby Formation affected by the intrusion.

The sterane fingerprints of the oil stain show sub-equal abundances of C27–C29 homologues as for the intruded Napperby Formation (Table 7-2, Figure 7-6). On the other hand, the coal and carbonaceous siltstones of the Permian Maules Creek and Goonbri Formations are clearly different from the oil stain in terms of their sterane and diasterane distributions. Both of the latter formations have ethylcholestane-dominant sterane distributions with prevalent αααR isomers, a characteristic of a predominantly land-plant-derived organic matter of low maturity. The high maturity of both the oil and the intruded part of the Napperby Formation have lowered both their pristane/phytane and C29/C27 regular sterane ratios (Figure 7-8). This and the enhanced concentrations in the oil stain of the rearranged hopanes 18α(H)-30-norneohopane (C29Ts/C29 hopane =

0.17) and diahopanes (C30*/C30 hopane = 0.10) are consistent with a shaley source rock deposited in an oxic to sub-oxic environment rich in terrestrially-derived organic matter (Table 7-2). Although this source affinity is common to the entire Permo-Triassic sequence, the best match appears to be with the intruded part of the Napperby Formation (Table 7-2, Figure 7-6). The high level of thermal maturity may enhance these compositional features.

A related parameter is the C29/C30 αβ hopane (Table 7-2), which may also have been preferentially increased in the oil upon the rapid heating of its source rock. Although primarily a source/environmental indicator (e.g. Brooks, 1986), this ratio found to be high in rapidly heated high mature intervals (see section 6.4.1, Chapter 6) and also found to increase significantly during artificial maturation (Boreham and Powell, 1991).

The positive ‘oil-source’ correlation between the oil stain and the Napperby Formation extracts is well displayed in the sterane and diasterane ternary plots (Figure 7-9). In Figure 7-9b, the oil stain plots proximal to some Napperby Formation samples, regardless of their lower maturity, although the diasterane distribution best matches that

239 Chapter 7 OIL-SOURCE CORRELATION

Figure 7-7: Sterane maturation – migration parameters for the oil stain and potential source rocks in Bellata-1 (modified from Othman et al., 2001).

Figure 7-8: Pristane/phytane vs. C29/C27 steranes plot for the oil stain and potential source rocks in Bellata-1 (modified from Othman et al., 2001).

240 Chapter 7 OIL-SOURCE CORRELATION

28

● Oil stain, Pilliga Sst.

O Napperby Fm. × Maules Creek Fm. + Goonbri Fm.

O

O O • ×O ×+ +

29 27

(A) C27 – C29 regular steranes

28

O OO O× ×+ +

27 29

(B) C27 – C29 diasteranes

Figure 7-9: Ternary plots for C27 – C29 (A) regular steranes, and (B) diasteranes for the oil stain and potential source rocks in Bellata-1 (modified from Othman et al., 2001).

241 Chapter 7 OIL-SOURCE CORRELATION

of the mature sample most affected by intrusive heating. This clearly demonstrates the importance of employing such relatively heat-resistant compounds in correlating highly mature oils and source rocks (Peters and Moldowan, 1993).

7.6.3. Tricyclic terpanes

Another particularly useful set of compounds well suited for correlation of such mature samples is the tricyclic terpanes (Figure 7-10). These compounds are highly resistant to thermal maturation compared to, for example, homohopanes (Aquino Neto et al., 1983). Various precursor biotas have been suggested for these compounds (section 6.3.1.3.5, Chapter 6). Regardless of their precise origin, inspection of the tricyclic distributions illustrated in Figure 7-10 reveals an excellent match between the oil stain and the intruded Napperby Formation sample.

7.7. Discussion and conclusions

Oil-stained cores from Bellata-1 and a “Caltex” diesel fuel sample were previously analysed by Gould (1986). McKirdy (1986) analysed another two oil-stained cores from the same well and a diesel sample from the same fuel depot (Moree, New South Wales) that supplied the diesel fuel used during drilling. Data used to support a diesel fuel origin included n-alkane distributions (McKirdy, 1986; Gould, 1986) and relationships of certain phenanthrene and methylphenanthrene isomer ratios, namely MPI-1 and MPI- 2 (Gould, 1986). Cyclic hydrocarbon biomarkers and other parameters, on the other hand, did not substantiate this conclusion. Gould (1986) used the strong petroliferous odour and the presence of staining in alternate porous/permeable sandstone layers, together with significant concentrations of NSO compounds in the oil stain, as evidence for a “basinal-sedimentary” origin. Polar fractions are a substantial component of crude oils but not of diesel fuel (Tissot and Welte, 1984). Moreover, the possibility that the NSO-rich oil encountered in the Pilliga Sandstone may be a product of the interaction of diesel with interbedded carbonaceous units seems unlikely. This is because the overlying sequence comprises mostly organically lean sandstone that is incapable of releasing large amounts of NSO compounds into the 1270 litres of diesel. In addition, as suggested by Gould (1986), to attribute a diesel fuel origin to the petroliferous component of the oil stained sandstones

242 Chapter 7 OIL-SOURCE CORRELATION

Pilliga Sst., 556.73 m Oil stain

24 Tetra

21 20 23 24 Napperby Fm., 805.18 m 19 Rock extract 26 25 Triassic 22

20 23

24 Tetra

24 25 26 Napperby Fm., 829.60 m 21 R ock extract 19 22 T riassic

24 Tetra

Maules Creek Fm., 929.60 m 24 Rock extract 19 20 Permian

Figure 7-10: Mass chromatograms of tricyclic terpanes (m/z 191) in the oil stain and potential source rocks in Bellata-1 (modified from Othman et al., 2001).

243 Chapter 7 OIL-SOURCE CORRELATION

requires a mechanism that allows the transport of diesel fuel from a well depth of 470 m through undrilled, impervious strata to a depth of 600 m, and which allows for selective contamination of the porous-permeable intervening sandstone succession.

The pre-Jurassic source affinity for the oil stain is evident based on aromatic source parameters. In addition, calculated vitrinite reflectance for the oil stain from the Jurassic Pilliga Sandstone is 1.29%, which is different from that measured for the host rock

(Rv,max = 0.42%); therefore a Jurassic source for the oil stain can be excluded (Othman et al., 2001).

The Permian and Triassic coal and carbonaceous lithofacies examined from Bellata-1 are considered to be hydrocarbon source rocks (Table 7-3; see also Chapter 5). However, the sequence is largely immature to marginally mature for hydrocarbon generation. Exceptions occur in the lower part of the Triassic Napperby Formation and a thin interval near the base of the Permian Goonbri Formation, where potential source rocks are mature to overmature due to localised heating by igneous intrusions. On the other hand, a close similarity is evident between this residual oil and the intruded part of the Triassic Napperby Formation, both in terms of their thermal maturity and biomarker contents. The basinal origin of the oil stain, and hydrocarbon generation and expulsion from the Napperby Formation as a result of rapid heating by igneous intrusions, are therefore suggested (Othman et al., 2000, 2001).

244 Chapter 8 CONCLUSIONS

8. Chapter 8 CONCLUSIONS

The objectives of the current study were to assess the hydrocarbon generation potential and to investigate the three-dimensional pattern of thermal maturity in the Permian- Triassic sequences of the southern Bowen and northern Gunnedah Basins and the lower part of the overlying Jurassic-Cretaceous Surat Basin in northern New South Wales. To achieve these objectives, vitrinite reflectance measurements were conducted on 256 samples. The samples were chosen from 28 boreholes, among which only Bellata-1 was fully cored, and Coonarah-1A (and Coonarah-1) partially cored. The limited number of core samples available from the other boreholes had been taken basically for studying reservoir characteristics, and were of limited use for source-rock evaluation. Although 509 sidewall cores had also been cut, these samples were not available in the NSW Department of Mineral Resources core library facilities.

Mean maximum reflectance was measured on telocollinite particles from coal, or from dispersed organic matter in shale or siltstone samples. These materials were chosen from core intervals wherever available, or from cuttings samples where the relevant geophysical logs indicated these lithologies. Care was taken to minimise contamination by caved debris from overlying strata, and handpicking samples to represent the lithology identified by log signatures was a useful method applied to minimise such contamination. A total of 50 of the samples were also subjected to Rock-Eval pyrolysis analysis, to identify the source richness and kerogen type for the preserved organic matter. From these, 27 samples in addition to a Pilliga Sandstone sample, were chosen for extraction and further organic geochemical analysis.

8.1. Basin stratigraphy

The boreholes studied had been drilled in the study area over several decades, and different names had been applied to the same stratigraphic units in different areas, particularly in the southern Bowen-Surat Basin in northern New South Wales. The stratigraphy of the area was therefore re-evaluated for the region as a whole, based on lithologic and geophysical logging data. An overpressured interval, based on porosity logs, was identified in the lower part of the Triassic Moolayember and Napperby

245 Chapter 8 CONCLUSIONS

Formations in the Bowen and Gunnedah Basins respectively. This zone is located above the Showgrounds Sandstone in the Bowen Basin and the Digby Formation in the Gunnedah Basin. This interval was found to be continuous throughout the study area, and was successfully used as a marker bed to assist the correlation. It was also observed, with some variations in intensity, in all other boreholes examined for this purpose located further to the north and south of the study area. The suppression of vitrinite reflectance in the Permian Back Creek Group, relative to other parts of the sequence, provided another useful parameter for correlation. The re-evaluation of the stratigraphy also benefited from previous palynological studies, the results of which were found in some of the well completion reports.

Based on information obtained from 31 boreholes (including the 28 sampled boreholes), a representative stratigraphic section has been proposed and a fence diagram drawn for the southern Bowen-Surat Basin succession. The stratigraphy in this area has been correlated with that in the northern Gunnedah-Surat Basin in the southern part of the area studied. The sections suggest that the Bowen-Surat Basin succession is thicker towards the north, and the Permian sequence pinches out towards the west and probably to the south over the Moree High. The Upper Permian Kianga Formation is present and thicker towards the east and north in the southern Bowen Basin, but pinches out towards the south and west.

The study also suggests that the Early Triassic contraction event in northeastern New South Wales was significant and affected the preserved sedimentary succession in the area. This event resulted in uplift and erosion of most of the Permian Porcupine Formation and all of the Watermark Formation, as well as all of the Black Jack Group succession in the vicinity of Bellata-1 in the northern Gunnedah Basin. The southern Bowen Basin also experienced significant uplift and erosion, for a longer period, which resulted in removing most of the Kianga Formation and part or all of the Back Creek Group in the south and west. When the Triassic Digby Formation was deposited in the Gunnedah Basin, the Rewan Group was deposited in the Bowen Basin north of the area studied. The contact between the Permian and Triassic sequences in the Bowen Basin is conformable except near the basin margins. The southern Bowen Basin, however, the main study area, still experienced uplift and erosion at this time, and as a result the Rewan and Clematis Groups are completely absent, except for a small area around

246 Chapter 8 CONCLUSIONS

Glencoe-1 where the Rewan Group is present. The hiatus and palaeosol developed between the Digby and Napperby Formations (Jian and Ward, 1993) is probably time- equivalent to the deposition of the Clematis Group and Showgrounds Sandstone further north in the Bowen Basin. Subsidence resumed in the southern Bowen Basin with deposition of the Showgrounds Sandstone, which widely extends throughout the study area. Following this event, a shaly sequence that is represented by the base of the Moolayember Formation in the Bowen Basin and the basal Napperby Formation in the Gunnedah Basin was deposited. These two sequences are considered equivalent; the lower shaly interval in both sequences has overpressure characteristics, but no reflectance suppression phenomena (Othman and Ward, 1999).

8.2. Vitrinite reflectance pattern

8.2.1. Reflectance profiles

In the absence of cores, handpicking the cuttings samples from the boreholes to represent the lithologies identified by wireline log signatures was found to be successful as a basis for vitrinite reflectance studies, reducing contamination by caved debris from shallower intervals. Plotting of reflectance histograms further assisted in eliminating caved materials when the lithology of the target interval and caved debris was similar. Contamination due to oxidation of the samples, as a result of storage conditions, was also identified in some organic matter samples. The oxidised particles were found to show higher vitrinite reflectance values, in some cases similar to those in intervals affected by igneous intrusions. Based on their petrographic characteristics, however, the oxidised particles could be separated from the localised heat-affected samples. The outlines and the areas around the fractures in the oxidised particles are brighter than the areas inside, while intrusion affected samples are uniformly bright and may show vesiculation characteristics, particularly in post mature samples.

Two major types of anomalies were identified from vertical vitrinite reflectance profiles. These are anomalously high vitrinite reflectance resulting from local heat effects and igneous intrusions, and anomalously low (suppressed) vitrinite reflectance resulting from the perhydrous character of the preserved organic matter. Two types of igneous intrusion affected profiles were identified in this study: these are simple and 247 Chapter 8 CONCLUSIONS

complex profiles. In the simple case; the igneous intrusion effect is localised and the vitrinite reflectance values increase with decreasing distance from intruded bodies. An example is the profile in Mt Pleasant-1. The heat-affected zone extends further above than below the intrusive body. In the complex case, despite the presence of only a small interval of intrusion in the drill hole, the entire sequence is affected by heat-flow from igneous intrusions, as in Wilgapark-1.

Vitrinite reflectance suppression is another significant type of anomaly within the Permian Back Creek Group in the Bowen Basin and the Maules Creek Formation in the Gunnedah Basin. The suppression phenomenon in these two intervals has apparently resulted from marine influence on vitrinite composition. The Goonbri Formation in the Gunnedah Basin also has suppressed reflectance, which is resulted to an abundance of associated liptinite-rich organic matter. The Porcupine/Watermark Formation and an interval within the Black Jack Group are also marine influenced. These sequences, however, are extensively affected by local heat-flows in the study area due to igneous intrusions, which have enhanced the maturation process and provided very high vitrinite reflectance values. Vitrinite particles dispersed in the shales and siltstones, show slightly lower reflectance values than vitrinite in the coals, in both the suppressed and non-suppressed intervals. The low (suppressed) vitrinite reflectance values in all cases are attributed to the presence of perhydrous vitrinite, although its formation may be attributed to various causes.

After due allowance for contamination and for anomalously high vitrinite reflectance values due to igneous effects, the comprehensive vitrinite reflectance measurements on which the study is based have permitted evaluation of vertical maturation profiles in the boreholes studied. They have also allowed production of an isoreflectance map for the contact between the Showgrounds Sandstone and the Moolayember Formation in the Bowen Basin. This contact was chosen because it is easy to identify from the wireline logs, it is located beneath the identified overpressured interval, and it is not affected by reflectance suppression phenomenon. In addition, the Showgrounds Sandstone is a reservoir target in the Bowen Basin. Production of such an isoreflectance map was not possible in the northern part of the Gunnedah Basin, in the southern part of the study area, due to the extensive igneous intrusion effects and also the limited number of boreholes drilled (Othman and Ward, 2002).

248 Chapter 8 CONCLUSIONS

8.2.2. Reflectance gradients

The vertical reflectance profiles in the Bowen Basin show a steady increase in reflectance down-sequence from the Jurassic, through the Triassic to the Permian Kianga Formation (where present). The reflectance decreases at the top of the Back Creek Group, and then increases with increasing burial depth with a somewhat higher reflectance gradient than in the non-suppressed upper intervals. In the Bellata-1 area in the Gunnedah Basin, two suppressed intervals were identified in the Permian succession. These are in the Maules Creek and Goonbri Formations, with even lower reflectance values in the Goonbri than in the Maules Creek interval.

The vertical reflectance profiles show that areas where the rank advance is affected by higher heat-flows have less difference in reflectance gradient between suppressed and non-suppressed intervals in comparison to profiles where rank advance resulted from mainly the burial depth. The variation in the reflectance gradient between suppressed and non-suppressed intervals is attributed to variations in the chemical composition of the vitrinite, with the different materials responding differently to the burial depth. Local heat effects due to intrusions, however, have enhanced the reflectance, allowing such low values to be increased and in some cases the suppressed character to disappear, as hydrocarbons are generated and the perhydrous nature is lost.

The present-day geothermal gradient and the vitrinite reflectance gradient are not necessarily related. Present-day geothermal gradient is a result of current heat-flow, while the reflectance gradient has resulted from the highest heat-flow and its duration during the rank advance process. The reflectance gradient for the non-suppressed intervals increases towards the margins of the Bowen Basin to the west and south, where the Permian sequence thins and/or the Triassic sequence overlaps the basement. The gradient is also higher towards the Moonie-Goondiwindi Fault and over the Gil Gil Ridge. These variations are mainly attributed to the heat-flow from the basement, which would particularly affect reflectances where the sedimentary succession is thinner. The high reflectance gradient in the Goondiwindi-1 well, however, which penetrated a relatively thick sequence, has resulted from the borehole’s location close to the thrust fault.

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8.2.3. Lateral reflectance trends

The isoreflectance map is in good agreement with the reflectance gradient values. The vitrinite reflectance increases towards the east, due to the higher heat-flow from the Moonie-Goondiwindi Fault, and towards the south, the west and over the Gil Gil Ridge, where the sequence is thinner and experienced higher heat-flow from shallower basement materials (Othman and Ward, 2000; 2002). The reflectance is also higher towards the north, where the sequence was more deeply buried. A pre-deformation influence on the maturity pattern is suggested in the study area, because of the presence of higher reflectance values at stratigraphically equivalent horizons in areas above the basement ridges. The effect of the higher heat-flow expected from the ridges, however, also contributed in rank advance after the deformation occurred.

8.3. Source rock geochemistry

8.3.1. Rock-Eval pyrolysis

8.3.1.1. Organic richness

The Permian Back Creek Group in the Bowen Basin generally contains abundant Type II/III kerogen with good genetic potential, and shows an ability to generate a fair amount of oil. The Kianga Formation has similar characteristics, but contains Type II/III and Type III kerogen, which reduces its capability for generating hydrocarbons compared to the Back Creek Group. In the Gunnedah Basin, the Goonbri and Maules Creek Formations are rich in organic matter, with an ability to generate fair amounts of hydrocarbons. The Maules Creek Formation, however, has on average, a lower HI than the Goonbri Formation. Therefore, the latter formation has better potential for hydrocarbon generation. Any such assessment based on the samples analysed from the Watermark/Porcupine Formation and Black Jack Group, however is difficult, because that sequence is heavily affected by igneous intrusions and the strata have probably already generated and may have expelled their hydrocarbons.

The Triassic sequence in both the Gunnedah and Bowen Basins has less TOC and a lower HI than the Permian sequence studied. The Napperby Formation, however, is

250 Chapter 8 CONCLUSIONS

characterised by a higher TOC content, and has better generation potential characteristics than the Moolayember Formation. It has the ability to be a fair oil source. The Jurassic Walloon Coal Measures is considered to be an excellent potential petroleum source based on the TOC content, which is mainly immature Type II kerogen. In fact, the Walloon Coal Measures has the best source potential, but is also the least mature rock unit among the sequences studied.

A consistent relation has been observed between the TOC% and the Rock-Eval S2 for samples with similar levels of maturity and similar kerogen types.

8.3.1.2. Thermal maturity

In a similar manner to the vitrinite reflectance anomalies, the Tmax value is also lowered (suppressed) in the Permian perhydrous intervals. This applies whether the suppression has resulted from marine influence or from a liptinite-rich organic matter content.

Anomalously high Tmax values occur in local heat-affected intervals due to igneous intrusions. A positive correlation exists between vitrinite reflectance and Tmax. The Tmax, value, however, is very low (348oC) in the postmature Napperby Formation sample

(Rv,max = 2.21%) at a depth of 829.60 m in Bellata-1. This low value is attributed to a significant pyrobitumen content, which produced a high peak at around 390oC as illustrated on the sample’s pyrogram. Based on the Tmax values, the studied sequences are within the early mature zone where the maturity has resulted from burial depth, and within the peak mature and in places the postmature zone where affected by igneous intrusions.

8.3.1.3. Rock-Eval S1 and free bitumen relationship

The Rock-Eval S1 peak represents free hydrocarbons already generated in a sample, and, as expected, illustrates a positive relationship to the proportion of extracted bitumen. The investigation for the current study shows that the S1 peak is better correlated with hydrocarbons (saturated and aromatics), while the extractable organic matter (EOM) is generally higher than S1 due to the capability of solvent extraction to extract more NSO compounds than thermal distillation over the Rock-Eval S1 temperature interval. This means that partially unreleased NSO compounds would be

251 Chapter 8 CONCLUSIONS

added to the S2 peak at higher Rock-Eval temperatures. This may result in significant inaccuracy in S2 value and in parameters based on both S1 and S2, particularly in cases where high amounts of unreleased NSO constituents as S1, would be added to the S2.

8.3.2. Hydrocarbon biomarkers

8.3.2.1. n-Alkanes and isoprenoids

An n-alkane distribution with high molecular weights predominant, and CPI values higher than unity, indicate mainly a terrestrial source input in the samples analysed. The high maturity samples, however, are exceptional, maximising in the low molecular weight n-alkanes and declining smoothly towards high molecular weights, with CPI values just above unity. These differences are attributed to the high maturity levels rather than to source input variation. The preserved organic matter was deposited mainly in oxic environments, as indicated by relatively high pr/ph ratios.

Any marine organic matter that possibly contributed to the organic input in the Permian marine influenced sequences was not identified on the n-alkane fingerprints. This might be attributed to overwhelming amounts of terrestrial organic matter deposited into the marine sediments. The alkane content is higher in continental organic matter than in marine, and where both types of material are present, the n-alkane distribution is dominated by that from continental organic matter, particularly in the C25 to C33 range (Tissot and Welte, 1984).

8.3.2.2. Sterane and terpane distributions

8.3.2.2.1. Source and environmental indicator

The homohopane distribution, with a decrease in abundance towards higher molecular weights and with a C29/C30 hopane ratio less than unity, is consistent with the clay- bearing character of the samples studied. Although the latter ratio is known as an environmental indicator, samples with high maturity due to igneous intrusion effects are characterised by high C29/C30 hopane ratios, and an increase is consistently noted within

252 Chapter 8 CONCLUSIONS

the lower part of the Napperby Formation in Bellata-1, close to the intruded interval.

This probably clarifies the more than unity C29/C30 hopane value for the high maturity sample (No. 49) from the Watermark/Porcupine Formation in Coonarah-1A.

Trace amounts of 25-NH, BNH and TNH indicate oxic to suboxic sedimentary environments for the studied sequences. In addition, the considerable abundance of

C29Ts and diahopane suggests terrestrial-source organic matter, deposited under oxic to suboxic conditions. A terrestrial source input is also indicated by the relatively high C29 sterane abundance and the low sterane/hopane ratios. The absence of a marine signature among the identified terpanes and steranes in the marine influenced intervals could be attributed to the mainly non-marine source of the organic matter input (Volkman et al., 1983b; Tissot and Welte, 1984; Moldowan et al., 1985).

8.3.2.2.2. Maturity indicators

Among the studied biomarker maturity parameters 22S and 20S show reversals in highly mature samples, rapidly heated due to igneous intrusions. The C24 tetracyclic terpane to C21-C26 tricyclic terpanes ratio decreases, instead of increasing, towards the lower part of the Napperby Formation, in an interval rapidly heated due to igneous intrusion. A similar observation on an intrusion-affected sequence has been noted previously by Farrimond et al. (1999).

The 22S ratio, which is fastest in reaction among other terpane and sterane maturity parameters, show that the Permian sequences in Bellata-1 and Bohena-1, and the Triassic sequence in Coonarah-1A, are within the oil generation stage, while the Triassic sequence is marginally mature at best in the Bellata-1 well. Intrusion affected intervals in the lower part of the Napperby Formation in Bellata-1, and in the Permian sequence in Coonarah-1A, are chracterised by less than the equilibrium 22S ratio as a result of inversion of the ratio. The Permian sequence in the Bowen Basin is within the oil generation zone, based on the 22S ratio. The exception is the Kianga Formation sample (No. 22) from McIntyre-1, which is considered immature. The Triassic sequence is marginally mature, except for the high maturity, intrusion-affected sample (No. 7) with an inverted 22S value. The Jurassic samples analysed form the Bowen Basin are

253 Chapter 8 CONCLUSIONS

considered immature. In the Bellata-1 well the 22S ratio increases consistently with increasing burial depth. Although the postmature sample (No. 36) is within the main path (Figure 6-15), in fact this value is inverted.

The ratio of moretane/hopane decreases with depth, with the lowest value observed in the highly mature intruded interval of the lower Napperby Formation. The ratios of

Ts/(Ts+Tm), C29Ts/C29 and 20S increase with increasing maturity, with abnormally high values within the rapidly heated Triassic interval. Although the 20S value in Bellata-1 is apparently higher in the postmature sample (No. 36) compared to the other samples analysed in the borehole (Figure 6-15), this value inverted because it is below the equilibrium point considering the 2.21% vitrinite reflectance. The ratio of ββ changes with depth, with highest values in the paleo-heat affected postmature sample in the Napperby Formation. This ratio, however, does not increase regularly with depth (Figure 6-15), because it is slowest among the studied maturity parameters to react to maturity changes. Therefore, the variations in ββ ratio within low maturity samples mainly reflect facies effects. These maturity parameters are not lowered (suppressed) within intervals having lower Tmax and suppressed vitrinite reflectance values in the Permian perhydrous sequences.

Even though the diasterane/sterane ratio is known to be sensitive to lithology, the ratio in the present study shows a good relation with TOC%. An increase in the ratio is observed with increasing TOC content up to around 5%, then the ratio decreases with increasing TOC including in the coal samples. In both cases the high maturity samples are separated anomalously, as expected, with high diasterane/sterane ratios.

8.3.2.3. Aromatic maturity parameters

The calculated vitrinite reflectance based on the method of Radke and Welte (1983), as well as MPI 1 and MPI 2, show the best comparison with the measured vitrinite reflectance of the aromatic maturity parameters. Even though it shows some variation (Figure 6-22 Chapter 6), the MPI 3 is also in a good agreement with the measured vitrinite reflectance values. These aromatic maturity parameters increase with increasing burial depth and within the paleo-heat affected intervals, and decrease within the

254 Chapter 8 CONCLUSIONS

Permian intervals containing perhydrous vitrinite. The ratio 3MP/retene increases with increasing maturity. Further investigation, however, is required into how this ratio reacts within suppressed intervals.

8.4. Rank advance and maturity in suppressed intervals

Vitrinite reflectance, which is lowered within perhydrous intervals, is a major maturity parameter used in source rock studies and basin modeling. Such lowering possibly leads to inaccurate hydrocarbon generation assessment. To answer a significant question regarding variations in hydrocarbon generation in a vertical profile within a vitrinite reflectance suppressed interval, the proportion of extractable organic matter (EOM mg/gm TOC) and its hydrocarbon constituent fractions (HC mg/g TOC) have been plotted against depth for the Bellata-1 well (Figure 5-39 Chapter 5). This fully-cored borehole was selected because the sequence penetrated shows a wide range of vitrinite reflectance (Rv,max = 0.42 – 2.43%), in addition, the Permian sequence is suppressed due to marine influence (Maules Creek Formation) and liptinite-rich organic matter input (Goonbri Formation).

The plots show that hydrocarbon generation generally increases with increasing burial depth, even within intervals having suppressed (perhydrous) vitrinite reflectance (including both the marine-influenced Maules Creek Formation and the liptinite-rich Goonbri Formation). This applies for the Permian coal and siltstone samples, with the siltstone samples showing even higher values than the coals, which probably resulted from lithology effects. The high-maturity samples in the lower part of the Napperby Formation that are affected by igneous intrusions, however, show low values (Othman and Ward, 2003). This is attributed to expulsion of the generated hydrocarbons from this interval (cf. Othman et al., 2001).

In conclusion, the actual amount of hydrocarbon generation increases with increasing burial depth, even though the Tmax or Rv,max values are lowered (suppressed) in the perhydrous intervals. This outcome does not necessarily mean that extrapolating the reflectance trend in a vertical profile would replace the actual (non-suppressed) vitrinite reflectance values within suppressed intervals in terms of hydrocarbon generation.

255 Chapter 8 CONCLUSIONS

Because suppression is a result of variations in organic matter chemical composition, which in turn results in different amounts of hydrocarbons generated.

8.5. Oil-source correlation

The techniques used in the study have assisted in investigating the origin of oil traces identified in the Jurassic Pilliga Sandstone in Bellata-1 as being indigenous, and not produced by anthropogenic contamination. They have also assisted in relating the oil to its source rock. Aromatic source parameters have indicated that the oil has a pre-

Jurassic source affinity. The calculated vitrinite reflectance (Rc(rw) = 1.29%) for the oil stain was different from the measured vitrinite reflectance of the host rock (Rv,max = 0.42%). This outcome suggests other sources for the oil stain and excluded the Jurassic sediments. A high level of maturity in the Bellata-1 sequence, with a reflectance close to 1.29%, is only possible within the intrusion-affected intervals, such as that identified in the lower part of the Napperby Formation and over a small interval in the Goonbri Formation. A close similarity between the oil stain and the intruded part of the Napperby Formation in terms of maturity and biomarker content suggests a basin origin of the oil stain. It is further proposed that the oil generation and expulsion took place from this interval as a result of rapid heating due to the igneous intrusions (Othman et al., 2000; 2001).

8.6. Hydrocarbon generation

8.6.1. Bowen Basin

Based on the isoreflectance map proposed for the lower contact of the Triassic Moolayember Formation (Figure 4-14 Chapter 4), and the increase in actual amounts of hydrocarbon generation within vitrinite reflectance suppressed intervals, the perhydrous Permian sequence in the lower part of the Bowen Basin in northern New South Wales is more mature than suggested by the observed rank indicators, vitrinite reflectance for example. Based on the isoreflectance map, the Permian sequence, in terms of maturity and hydrocarbon generation, is at least within the peak oil zone, and probably within the late oil zone in the northern and northeastern parts of the study area. Based on

256 Chapter 8 CONCLUSIONS

geophysical data, Alder et al. (1996) have noted the possibility of thickened sedimentary sections in the New South Wales portion of the Great Australian Basin. This may in turn result in more mature Permian and Triassic intervals.

Considering the actual maturity levels in the Permian sequence, which are higher than observed rank indicators, vitrinite reflectance for example, a lack of maturity, therefore, is probably not the basic reason for a lack of successful hydrocarbon discoveries in the southern Bowen Basin. The samples analysed from the Permian Back Creek Group generally contain abundant Type II/III kerogen, which is able to generate liquid as well as gaseous hydrocarbons at peak maturity. The Permian sequence, however, is not a thick shaly interval with coal seams, but also contains sandy intervals with reservoir characteristics (cf. Morton et al., 1993). In general, the critical question regarding hydrocarbon generation from the Permian sequence in the Bowen Basin is probably related to the thickness of the Permian sequence with suitable source rock properties. Although there are many other factors that may also need to be considered, the location of the boreholes drilled to date is probably still responsible for the lack of successful discoveries in the New South Wales portion of the Bowen Basin.

8.6.2. Gunnedah Basin

In the Gunnedah Basin, vitrinite reflectance in the Permian sequence is suppressed not only because of the marine influence but also is related to the presence of liptinite-rich organic matter. The Permian sequence contains coal seams. Organic matter with the ability to generate oil as well as gaseous hydrocarbons at peak maturity is therefore present in the Permian sequences. The level of maturity in the Gunnedah Basin, however, is the critical factor in generating significant amounts of hydrocarbons basin wide. It is important to note that the total amount of tectonic subsidence in the Gunnedah Basin is very small when compared with that in the Taroom Trough of the Bowen Basin, where the amount of tectonic subsidence is up to an order of magnitude greater (Korsch et al., 1993). The igneous intrusions in the basin are therefore probably the main factors associated with hydrocarbon generation. This has been proved in the Bellata-1 well (Othman et al., 2001), where an oil stain in the Pilliga Sandstone was related to a Napperby Formation source and was clearly generated due to igneous intrusions and local heat effects.

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293 APPENDIX 1

APPENDIX 1

Vitrinite reflectance data for samples studied

294 APPENDIX 1

Well: Barb-1; Bowen/Surat Basin Total depth: 1704.13 m Lithology1 SD2 No. Formation Depth (m) Age Source Rv, max % 1 Walloon Coal Measures 1115.57 Jurassic cuttings siltstone 0.58 0.03 2 Walloon Coal Measures 1164.34 Jurassic cuttings siltstone 0.59 0.03 3 Hutton Sandstone 1216.15 Jurassic cuttings siltstone 0.60 0.04 4 Moolayember Formation 1249.68 Triassic cuttings siltstone 0.61 0.03 5 Moolayember Formation 1319.78 Triassic cuttings siltstone 0.62 0.02 6 Moolayember Formation 1365.50 Triassic cuttings shale 0.63 0.03 7 Moolayember Formation 1408.18 Triassic cuttings siltstone 0.66 0.03 8 Moolayember Formation 1447.80 Triassic cuttings shale 0.67 0.04 9 Snake Creek Mudstone Member 1502.66 Triassic cuttings siltstone 0.69 0.04 10 Back Creek Group 1603.25 Permian cuttings siltstone 0.66 0.02 11 Back Creek Group 1645.92 Permian cuttings siltstone 0.69 0.03 12 Back Creek Group 1682.50 Permian cuttings siltstone 0.69 0.03 Well: Bellata-1, Gunnedah/Surat Basin Total depth: 1128 m

No. Formation Depth (m) Age Source Lithology Rv, max %SD 1 Pilliga Sandstone 566.73 Jurassic core sandstone 0.42 0.03 2 Pilliga Sandstone 585.75 Jurassic core siltstone 0.52 0.04 3 Purlawaugh Formation 613.60 Jurassic core siltstone 0.55 0.04 4 Napperby Formation 642.40 Triassic core claystone 0.60 0.03 5 Napperby Formation 665.77 Triassic core claystone 0.63 0.03 6 Napperby Formation 781.80 Triassic core siltstone 0.84 0.07 7 Napperby Formation 805.18 Triassic core siltstone 0.99 0.06 8 Napperby Formation 813.89 Triassic core siltstone 1.01 0.09 9 Napperby Formation 829.60 Triassic core siltstone 2.21 0.17 10 Napperby Formation 871.55 Triassic core siltstone 2.43 0.02 11 Maules Creek Formation 939.93 Permian core coal 0.57 0.02 12 Maules Creek Formation 959.20 Permian core coal 0.66 0.05 13 Maules Creek Formation 985.70 Permian core coal 0.67 0.02 14 Maules Creek Formation 987.55 Permian core coal 0.69 0.02 15 Maules Creek Formation 1005.90 Permian core siltstone 0.75 0.02 16 Goonbri Formation 1019.22 Permian core coal 0.65 0.02 17 Goonbri Formation 1049.49 Permian core coaly slst 0.66 0.03 18 Goonbri Formation 1054.74 Permian core coal 0.67 0.03 19 Goonbri Formation 1073.86 Permian core siltstone 0.73 0.03

20 Goonbri Formation 1104.16 Permian core coaly slst 2.16 0.04 21 Goonbri Formation 1104.95 Permian core coaly slst 0.61 0.03 22 Goonbri Formation 1112.68 Permian core coaly slst 0.61 0.02

Well: Bohena-1; Gunnedah/Surat Basin Total depth: 1650.49 m No. Formation Depth (m) Age Source Lithology Rv,max%SD 1 Purlawaugh Formation 341.38 Jurassic cuttings siltstone 0.54 0.03 2 Napperby Formation 408.43 Triassic cuttings siltstone 0.65 0.04 3 Napperby Formation 481.74 Triassic core shale 1.43 0.06 4 Black Jack Group 660.85 Permian core shale 0.62 0.06 5 Watermark/Porcupine 737.61 Permian cuttings shale 0.69 0.04 6 Watermark/Porcupine 774.19 Permian cuttings shale 0.70 0.04 7 Maules Creek Formation 835.15 Permian cuttings coal 0.68 0.03 8 Maules Creek Formation 855.73 Permian core shale 1.33 0.06

1 As indicated by well log

2 Standard deviation

295 APPENDIX 1

Well: Bohena-1 (continued) No. Formation Depth (m) Age Source Lithology Rv,max%SD 9 Maules Creek Formation 896.11 Permian cuttings coal 0.72 0.03 10 Goonbri Formation 966.83 Permian core shale 0.63 0.06

11 Goonbri Formation 1002.79 Permian cuttings shale 0.74 0.04

Well:Boomi - 1; Bowen/Surat Basin Total depth: 1695.29 m No. Formation Depth (m) Age Source Lithology Rv,max% SD 1 Walloon Coal Measures 1238.83 Jurassic core coal 0.56 0.02

2 Walloon Coal Measures 1328.93 Jurassic cuttings siltstone 0.61 0.41

3 Hutton Sandstone 1444.75 Jurassic cuttings shale 0.65 0.03 4 Evergreen Formation 1490.47 Jurassic cuttings shale 0.66 0.03 5 Moolayember Formation 1595.22 Triassic core shale 0.64 0.05 6 Moolayember Formation 1630.68 Triassic cuttings shale 0.69 0.03 7 Showgrounds Sandstone 1673.35 Triassic cuttings shale 0.70 0.03

Well: Camurra-1; Bowen/Surat Basin Total depth: 882.4 m No. Formation Depth (m) Age Source Lithology Rv,max%SD 1 Moolayember Formation 822.96 Triassic cuttings coal 0.62 0.04

Well: Chester-1; Bowen/Surat Basin Total depth: 2135.70 m No. Formation Depth (m) Age Source Lithology R %SD v,max 1 Walloon Coal Measures 1188.72 Jurassic cuttings coal 0.57 0.03 2 Walloon Coal Measures 1261.87 Jurassic cuttings shale 0.58 0.05 3 Evergreen Formation 1368.55 Jurassic cuttings shale 0.62 0.05 4 Moolayember Formation 1441.70 Triassic cuttings siltstone 0.65 0.04 5 Moolayember Formation 1472.18 Triassic cuttings siltstone 0.67 0.02 6 Moolayember Formation 1560.58 Triassic cuttings siltstone 0.70 0.05 7 Moolayember Formation 1621.54 Triassic cuttings siltstone 0.72 0.04 8 Moolayember Formation 1676.40 Triassic cuttings shale 0.73 0.03 9 Snake Creek Mudstone Member 1703.83 Triassic cuttings siltstone 0.73 0.03 10 Snake Creek Mudstone Member 1716.02 Triassic cuttings shale 0.73 0.04 11 Back Creek Group 1758.70 Permian cuttings coal 0.68 0.05

12 Back Creek Group 1798.32 Permian cuttings shale 0.70 0.03 13 Back Creek Group 1877.57 Permian cuttings shale 0.72 0.03

Well: Coonarah-1A, Gunnedah Basin Total depth: 650 m

No. Formation Depth (m) Age Source Lithology Rv,max%SD *1 Napperby Formation 393.35 Triassic core coal 0.53 0.01 2 Napperby Formation 421.96 Triassic core shale 0.60 0.02 3 Napperby Formation 438.51 Triassic core shale 0.79 0.04 4 Napperby Formation 442.23 Triassic core shale 0.88 0.05 5 Napperby Formation 449.18 Triassic core shale 0.83 0.06 6 Napperby Formation 453.35 Triassic core shale 0.87 0.04 7 Black Jack Group 512.36 Permian core carb. shale 2.74 0.05 8 Black Jack Group 522.60 Permian core coal 1.80 0.05 9 Black Jack Group 550.98 Permian core coal 1.69 0.01 10 Black Jack Group 572.09 Permian core coal 1.99 0.05 11 Black Jack Group 604.74 Permian core shale 1.91 0.05

296 APPENDIX 1

Well: Coonarah-1A (continued)

No. Formation Depth (m) Age Source Lithology Rv,max%SD 12 Watermark/Porcupine Formation 613.24 Permian core shale 1.72 0.07 13 Watermark/Porcupine Formation 635.35 Permian core siltstone 1.92 0.05 14 Watermark/Porcupine Formation 646.54 Permian core siltstone 1.87 0.06 * sample from Coonarah-1 well

Well: Edendale-1; Bowen Basin Total depth: 2237 m No. Formation Depth (m) Age Source Lithology Rv,max%SD 1 Walloon Coal Measures 1190 Jurassic cuttings coal 0.54 0.03 2 Walloon Coal Measures 1230 Jurassic cuttings coal 0.56 0.03

3 Walloon Coal Measures 1251 Jurassic cuttings coal 0.57 0.04 4 Walloon Coal Measures 1275 Jurassic cuttings coal 0.58 0.03 5 Evergreen Formation 1410 Jurassic cuttings claystone 0.58 0.04 6 Evergreen Formation 1452 Jurassic cuttings claystone 0.60 0.04 7 Moolayember Formation 1548 Triassic cuttings coal 0.68 0.05 8 Moolayember Formation 1569 Triassic cuttings siltstone 0.69 0.04 9 Moolayember Formation 1638 Triassic cuttings siltstone 0.70 0.05 10 Moolayember Formation 1680 Triassic cuttings siltstone 0.72 0.04 11 Moolayember Formation 1785 Triassic cuttings siltstone 0.74 0.03 12 Kianga Formation 1830 Permian cuttings siltstone 0.70 0.08 13 Kianga Formation 1869 Permian cuttings claystone 0.64 0.05 14 Back Creek Formation 1980 Permian cuttings siltstone 0.59 0.06 15 Back Creek Formation 2124 Permian cuttings coal 0.65 0.04 16 Back Creek Formation 2160 Permian cuttings coal 0.67 0.06 17 Back Creek Formation 2190 Permian cuttings coal 0.65 0.04

Well: Garah-1; Bowen Basin Total depth: 1600.80 m No. Formation Depth (m) Age Source Lithology Rv,max%SD 1 Walloon Coal Measures 1094.33 Jurassic cuttings siltstone 0.56 0.04 2 Walloon Coal Measures 1155.19 Jurassic cuttings coal 0.58 0.04 3 Hutton Sandstone 1231.39 Jurassic cuttings siltstone 0.59 0.03

4 Moolayember Formation 1277.11 Triassic cuttings shale 0.62 0.04 5 Moolayember Formation 1341.12 Triassic cuttings siltstone 0.61 0.04 6 Moolayember Formation 1408.18 Triassic cuttings siltstone 0.67 0.02 7 Moolayember Formation 1475.23 Triassic cuttings siltstone 0.66 0.04 8 Snake Creek Mudstone Member 1524.00 Triassic cuttings shale 0.67 0.04 9 Back Creek Group 1575.82 Permian cuttings shale 0.60 0.03

Well: Gil Gil-1; Bowen Basin Total depth: 1604.77 m No. Formation Depth (m) Age Source Lithology Rv,max%SD 1 Walloon Coal Measures 999.74 Jurassic cuttings coal 0.53 0.03 2 Moolayember Formation 1048.51 Triassic cuttings coal 0.76 0.05 3 Moolayember Formation 1094.23 Triassic cuttings coal 0.77 0.05 4 Moolayember Formation 1187.20 Triassic core shale 0.54 0.03 5 Moolayember Formation 1246.63 Triassic cuttings shale 0.63 0.02 6 Moolayember Formation 1307.97 Triassic core coal 1.30 0.04 7 Moolayember Formation 1381.35 Triassic core shale 0.73 0.06 8 Snake Creek Mudstone Member 1493.52 Triassic cuttings shale 0.70 0.04 9 Back Creek Group 1551.43 Permian cuttings coal 5.49 0.07

297 APPENDIX 1

Well:Glencoe-1, Bowen Basin Total depth: 1958.03 m No. Formation Depth (m) Age Source Lithology Rv,max%SD 1 Walloon Coal Measures 1377.70 Jurassic cuttings coal 0.59 0.02 2 Walloon Coal Measures 1469.14 Jurassic cuttings coal 0.64 0.03 3 Hutton Sandstone 1502.66 Jurassic cuttings siltstone 0.67 0.03 4 Hutton Sandstone 1578.86 Jurassic cuttings coal 0.78 0.03 5 Evergreen Formation 1661.16 Jurassic cuttings shale 0.77 0.05 6 Moolayember Formation 1740.41 Triassic cuttings siltstone 0.69 0.02 7 Moolayember Formation 1783.08 Triassic cuttings shale 0.70 0.03

Well: Goondiwindi-1, Bowen Basin Total depth: 2222.60 m No. Formation Depth (m) Age Source Lithology Rv,max%SD 1 Walloon Coal Measures 996.70 Jurassic cuttings coal 0.54 0.02 2 Walloon Coal Measures 1045.46 Jurassic cuttings shale 0.54 0.03 3 Walloon Coal Measures 1112.52 Jurassic cuttings coal 0.60 0.02 4 Walloon Coal Measures 1158.24 Jurassic cuttings coal 0.59 0.03 5 Evergreen Formation 1264.92 Jurassic cuttings coal 0.60 0.03

6 Evergreen Formation 1307.59 Jurassic cuttings shale 0.67 0.02 7 Evergreen Formation 1356.36 Jurassic cuttings shale 0.72 0.02 8 Moolayember Formation 1459.69 Triassic core shale 0.76 0.02 9 Moolayember Formation 1530.10 Triassic cuttings shale 0.74 0.02 10 Moolayember Formation 1554.18 Triassic core shale 0.77 0.03 11 Kianga Formation 1584.96 Permian cuttings shale 0.75 0.02 12 Back Creek Group 1776.98 Permian cuttings shale 0.58 0.02 13 Back Creek Group 1886.71 Permian cuttings coal 0.61 0.02 14 Back Creek Group 1941.58 Permian cuttings shale 0.61 0.03 15 Back Creek Group 1987.30 Permian cuttings shale 0.63 0.03 16 Back Creek Group 2017.78 Permian cuttings coal 0.70 0.03 17 Back Creek Group 2119.30 Permian core coal 0.73 0.02 18 Back Creek Group 2170.18 Permian cuttings coal 0.77 0.04 19 Back Creek Group 2209.80 Permian cuttings coal 0.80 0.03

Well: Kinnimo-1; Bowen Basin Total depth: 1583.43 m No. Formation Depth (m) Age Source Lithology Rv,max%SD 1 Walloon Coal Measures 1191.77 Jurassic cuttings siltstone 0.56 0.03 2 Walloon Coal Measures 1249.68 Jurassic cuttings siltstone 0.58 0.03 3 Hutton Sandstone 1325.88 Jurassic cuttings siltstone 0.61 0.02 4 Moolayember Formation 1402.08 Triassic cuttings shale 0.61 0.03 5 Moolayember Formation 1466.09 Triassic cuttings shale 0.62 0.04 6 Snake Creek Mudstone Member 1520.95 Triassic cuttings siltstone 0.64 0.05 7 Snake Creek Mudstone Member 1557.53 Triassic cuttings siltstone 0.65 0.04

Well: Lantern-1; Bowen Basin Total depth: 2076.90 m

No. Formation Depth (m) Age Source Lithology Rv,max%SD 1 Walloon Coal Measures 1121.66 Jurassic cuttings coal 0.54 0.04 2 Walloon Coal Measures 1197.56 Jurassic cuttings shale 0.55 0.05 3 Moolayember Formation 1252.73 Triassic cuttings shale 0.56 0.04 4 Moolayember Formation 1350.26 Triassic cuttings siltstone 0.59 0.04 5 Moolayember Formation 1411.22 Triassic cuttings siltstone 1.70 0.06

6 Moolayember Formation 1530.10 Triassic cuttings siltstone 0.63 0.05 7 Back Creek Group 1624.58 Permian cuttings siltstone 0.60 0.03 8 Back Creek Group 1688.59 Permian cuttings siltstone 1.69 0.07

298 APPENDIX 1

Well: Lantern-1 (continued) No. Formation Depth (m) Age Source Lithology Rv,max%SD 9 Back Creek Group 1725.17 Permian cuttings siltstone 1.93 0.09 10 Back Creek Group 1758.70 Permian cuttings shale 4.61 0.09

Well: Limebon-1, Bowen Basin Total depth: 2010.15 m

No. Formation Depth (m) Age Source Lithology Rv,max%SD 1 Walloon Coal Measures 1118.61 Jurassic cuttings coal 0.55 0.02 2 Walloon Coal Measures 1222.25 Jurassic cuttings siltstone 0.59 0.03 3 Hutton Sandstone 1283.21 Jurassic cuttings shale 0.60 0.05 4 Evergreen Formation 1328.93 Jurassic cuttings coal 0.63 0.03 5 Evergreen Formation 1374.65 Jurassic cuttings shale 0.63 0.04 6 Moolayember Formation 1463.04 Triassic cuttings siltstone 0.63 0.04 7 Moolayember Formation 1557.53 Triassic cuttings shale 0.65 0.04 8 Moolayember Formation 1633.73 Triassic cuttings shale 0.66 0.02 9 Snake Creek Mudstone Member 1679.45 Triassic cuttings shale 0.67 0.04 10 Kianga Formation 1712.98 Permian cuttings shale 0.69 0.04 11 Back Creek Group 1798.32 Permian cuttings shale 0.60 0.04 12 Back Creek Group 1880.62 Permian cuttings shale 0.64 0.03 13 Back Creek Group 1941.58 Permian cuttings shale 0.66 0.04 14 Back Creek Group 2002.54 Permian cuttings coal 1.29 0.04

Well: McIntyre-1, Bowen Basin Total depth: 2535.63 m No. Formation Depth (m) Age Source Lithology Rv,max%SD 1 Walloon Coal Measures 1450.85 Jurassic cuttings shale 0.57 0.03

2 Walloon Coal Measures 1548.38 Jurassic cuttings coal 0.60 0.03 3 Hutton Sandstone 1624.58 Jurassic cuttings shale 0.62 0.04 4 Hutton Sandstone 1722.12 Jurassic cuttings shale 0.65 0.03 5 Evergreen Formation 1810.51 Jurassic cuttings shale 0.70 0.03 6 Evergreen Formation 1901.95 Jurassic cuttings shale 0.65 0.02 7 Moolayember Formation 1965.96 Triassic cuttings shale 0.67 0.03 8 Moolayember Formation 2087.88 Triassic cuttings shale 0.74 0.03 9 Kianga Formation 2139.70 Permian cuttings coal 0.76 0.03 10 Kianga Formation 2151.89 Permian cuttings coal 0.77 0.03 11 Kianga Formation 2200.66 Permian cuttings shale 0.72 0.02 12 Back Creek Group 2225.04 Permian cuttings shale 0.65 0.03 13 Back Creek Group 2286.00 Permian cuttings shale 0.67 0.04 14 Back Creek Group 2313.43 Permian cuttings shale 0.68 0.03 15 Back Creek Group 2353.06 Permian cuttings coal 0.73 0.02 16 Back Creek Group 2441.45 Permian cuttings shale 0.75 0.04

Well: Moree-1; Bowen Basin Total depth: 1147.75 m No. Formation Depth (m) Age Source Lithology Rv,max%SD 1 Walloon Coal Measures 1054.61 Jurassic cuttings shale 0.54 0.03 2 Moolayember Formation 1072.90 Triassic cuttings coal 0.64 0.03 3 Moolayember Formation 1115.57 Triassic cuttings shale 0.64 0.03

Well: Moree-2; Bowen Basin Total depth: 1221.33 m

No. Formation Depth (m) Age Source Lithology Rv,max%SD 1 Walloon Coal Measures 1078.99 Jurassic cuttings shale 0.58 0.04 2 Walloon Coal Measures 1127.76 Jurassic cuttings siltstone 0.58 0.04

299 APPENDIX 1

Well: Moree-2 (continued) No. Formation Depth (m) Age Source Lithology Rv,max%SD 3 Moolayember Formation 1210.06 Triassic cuttings siltstone 0.61 0.04

Well: Moree-3; Bowen Basin Total depth: 1182.32 m

No. Formation Depth (m) Age Source Lithology Rv,max%SD 1 Walloon Coal Measures 1057.66 Jurassic cuttings coal 0.57 0.04 2 Walloon Coal Measures 1097.28 Jurassic cuttings shale 0.57 0.04 3 Moolayember Formation 1149.10 Triassic cuttings shale 0.66 0.03 4 Moolayember Formation 1173.48 Triassic cuttings coal 0.67 0.04

Well: Mt Pleasant-1; Bowen Basin Total depth: 2266.18 m No. Formation Depth (m) Age Source Lithology Rv,max%SD 1 Walloon Coal Measures 871.73 Jurassic cuttings siltstone 0.51 0.05 2 Walloon Coal Measures 914.40 Jurassic cuttings siltstone 0.54 0.03 3 Hutton Sandstone 957.07 Jurassic cuttings shale 0.55 0.03 4 Moolayember Formation 978.41 Triassic cuttings shale 0.60 0.03 5 Moolayember Formation 1021.08 Triassic cuttings coal 0.64 0.04 6 Moolayember Formation 1066.80 Triassic cuttings coal 2.06 0.07 7 Moolayember Formation 1143.00 Triassic cuttings shale 1.36 0.10 8 Moolayember Formation 1188.72 Triassic cuttings shale 0.64 0.03 9 Moolayember Formation 1240.54 Triassic cuttings shale 0.61 0.03 10 Moolayember Formation 1310.64 Triassic cuttings shale 0.61 0.04 11 Snake Creek Mudstone Member 1371.60 Triassic cuttings shale 0.63 0.03 12 Kianga Formation 1423.42 Permian cuttings coal 0.65 0.04

13 Kianga Formation 1469.14 Permian cuttings coal 0.68 0.04 14 Kianga Formation 1511.81 Permian cuttings coal 0.68 0.03 15 Back Creek Group 1566.67 Permian cuttings coal 0.62 0.03 16 Back Creek Group 1609.34 Permian cuttings coal 0.64 0.04 17 Back Creek Group 1655.06 Permian cuttings coal 0.65 0.03 18 Back Creek Group 1737.36 Permian cuttings coal 0.67 0.04 19 Back Creek Group 1810.51 Permian cuttings coal 0.68 0.04 20 Back Creek Group 1871.47 Permian cuttings coal 0.70 0.04 21 Back Creek Group 1929.38 Permian cuttings shale 0.73 0.05 22 Back Creek Group 1987.30 Permian cuttings coal 1.34 0.04 Well: Nyora-1; Gunnedah Basin Total depth: 811.37 m

No. Formation Depth (m) Age Source Lithology Rv,max%SD 1 Black Jack Group 582.17 Permian cuttings coal 0.71 0.03 2 Black Jack Group 609.60 Permian cuttings coal 0.73 0.04 3 Watermark/Porcupine Formation 749.81 Permian cuttings shale 0.70 0.04

Well: Pearl-1; Bowen Basin Total depth: 1575.81 m No. Formation Depth (m) Age Source Lithology Rv,max%SD 1 Walloon Coal Measures 1249.02 Jurassic cuttings siltstone 0.53 0.03 2 Walloon Coal Measures 1307.62 Jurassic cuttings siltstone 0.55 0.03 3 Hutton Sandstone 1369.30 Jurassic cuttings shale 0.64 0.05 4 Hutton Sandstone 1400.14 Jurassic cuttings coal 0.62 0.03 5 Moolayember Formation 1458.73 Triassic cuttings siltstone 0.62 0.03 6 Moolayember Formation 1501.91 Triassic cuttings siltstone 0.66 0.04 7 Snake Creek Mudstone Member 1557.42 Triassic cuttings shale 0.66 0.07

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Well: Quack-1; Bowen Basin Total depth: 1670.30 m

No. Formation Depth (m) Age Source Lithology Rv,max%SD 1 Walloon Coal Measures 1280.16 Jurassic cuttings siltstone 0.57 0.03 2 Walloon Coal Measures 1344.17 Jurassic cuttings claystone 0.63 0.05 3 Hutton Sandstone 1383.79 Jurassic cuttings siltstone 0.65 0.04 4 Hutton Sandstone 1453.90 Jurassic cuttings coal 0.68 0.03 5 Moolayember Formation 1514.86 Triassic cuttings siltstone 0.70 0.05 6 Moolayember Formation 1615.44 Triassic cuttings siltstone 0.72 0.05 7 Snake Creek Mudstone Member 1639.82 Triassic cuttings shale 0.74 0.05 8 Showgrounds Sandstone 1652.73 Triassic core shale 0.78 0.04

Well: Wee Waa-1; Gunnedah Basin Total depth: 824.78 m

No. Formation Depth (m) Age Source Lithology Rv,max%SD 1 Napperby Formation 544.68 Triassic core shale 0.65 0.04 2 Black Jack Group 609.60 Permian cuttings shale 0.71 0.03 3 Watermark/Porcupine Formation 685.80 Permian cuttings shale 0.72 0.02

Well: Werrina -1; Bowen Basin Total depth: 1519.45 m

No. Formation Depth (m) Age Source Lithology Rv,max%SD 1 Walloon Coal Measures 1219.20 Jurassic cuttings coal 0.55 0.03 2 Walloon Coal Measures 1289.30 Jurassic cuttings shale 0.58 0.04 3 Hutton Sandstone 1341.12 Jurassic cuttings shale 0.63 0.04 4 Evergreen Formation 1380.74 Jurassic cuttings shale 0.69 0.03

Well: Werrina - 2; Bowen Basin Total depth: 1566.67 m No. Formation Depth (m) Age Source Lithology Rv,max%SD 1 Walloon Coal Measures 1237.49 Jurassic cuttings coal 0.56 0.02 2 Walloon Coal Measures 1316.74 Jurassic cuttings shale 0.59 0.03 3 Hutton Sandstone 1389.89 Jurassic cuttings shale 0.64 0.02 4 Evergreen Formation 1469.14 Jurassic cuttings shale 0.69 0.03 5 Moolayember Formation 1539.24 Triassic cuttings shale 0.72 0.04

Well: Wilga Park-1; Gunnedah Basin Total depth: 795.83 m No. Formation Depth (m) Age Source Lithology Rv,max%SD 1 Black Jack Group 423.67 Permian cuttings coal 1.97 0.05 2 Black Jack Group 472.44 Permian cuttings coal 2.14 0.04 3 Watermark/Porcupine Formation 639.11 Permian core coal 2.29 0.04

4 Maulas Creek Formation 691.90 Permian cuttings coal 2.17 0.05 5 Maulas Creek Formation 716.28 Permian cuttings coal 4.31 0.07 6 Goonbri Formation 737.62 Permian cuttings coal 5.52 0.07

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APPENDIX 2

Geochemical parameters guidelines used in source rock evaluation

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Geochemical parameters describing the petroleum potential (quantity) of an immature source rock (modified from Peters and Cassa, 1994). Petroleum TOC Rock-Eval Pyrolysis Bitumen Hydrocarbons

Potential (wt %) S1 S2 (wt %) (ppm) (ppm) Poor 0 - 0.5 0 - 0.5 0 - 2.5 0 - 0.05 0 - 500 0 - 300

Fair 0.5 - 1 0.5 - 1 2.5 - 5 0.05 - 0.10 500 - 1000 300 - 600 Good 1 - 2 1 - 2 5 - 10 0.10 - 0.20 1000 - 2000 600 - 1200 Very Good 2 - 4 2 - 4 10 - 20 0.20 - 0.40 2000 - 4000 1200 - 2400 Excellent > 4 > 4 > 20 > 0.40 > 4000 >2400

Geochemical parameters describing kerogen type (quality) and

the character of expelled productsa (modified from Peters and

Cassa, 1994).

HI Main Expelled Product

Kerogen Type (mg HC/g TOC) S2/S3 Atomic H/C at Peak Maturity I > 600 > 15 > 1.5 Oil II 300 - 600 10 -15 1.2 - 1.5 Oil II/IIIb 200 - 300 5 - 10 1.0 - 1.2 Mixed oil and gas III 50 - 200 1 - 5 0.7 - 1.0 Gas IV < 50 <1 < 0.7 None a Based on thermally immature source rock. Ranges are approximate. bType II/III designated kerogens with compositions between Type II and III pathways that show intermediate HI.

Geochemical parameters describing level of thermal maturity (modified from Peters and Cassa, 1994).

Stage of Maturation Generation Thermal Bitumen/ Bitumen PI Maturity c o a b TOC mg/g rock S1/(S1+S2) for Oil Rv (%) Tmax ( C) TAI Immature 0.2 - 0.6 < 435 1.5 - 2.6 < 0.05 < 50 < 0.10 Mature Early 0.6 - 0.65 435 - 445 2.6 - 2.7 0.05 - 0.10 50 - 100 0.10 - 0.15 Peak 0.65 - 0.9 445 - 450 2.7 - 2.9 0.15 - 0.25 150 - 250 0.25 - 0.40 Late 0.9 - 1.35 450 - 470 2.9 - 3.3 – – > 0.40 Postmature > 1.35 > 470 > 3.3 – – – a See also Espitalié (1986). b Thermal alteration index. c Mature oil-prone source rock with type I or II kerogen commonly show bitumen/TOC ratios in the range 0.05-0.25. Caution should be applied when interpreting extract yield from coals, e.g., many gas-prone coals show high extract yield suggesting oil-prone character yield. Bitumen/TOC ratios over 0.25 can indicate contamination or migrated oil or can be artifacts caused by ratios of small, inaccurate numbers.

Source rock classification based on the genetic potential (S1+S2) (after Tissot and Welte, 1984):

- lower than 2 kg/tonne (2000 ppm): no oil source rock, some potential for gas, - from 2 to 6 kg/tonne (2000 to 6000 ppm): moderate source rock, - above 6 kg/tone (6000 ppm): good source rock.

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APPENDIX 3

Publications arising from this study

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Othman, R., 1999. Thermal history and hydrocarbon generation in the Surat/Bowen Basin, northern New South Wales, Australia. American Association of Petroleum Geologists Bulletin 83, 1892.

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Othman, R., Arouri, K., Ward, C.R., McKirdy, D., 2000. Generation of oil from Triassic lacustrine sediments by igneous intrusions, Gunnedah Basin, New South Wales. The Australian Organic Geochemistry Conference, Townsville, Book of Abstracts (not paginated).

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Othman, R., Arouri, K., Ward, C.R., McKirdy, D., 2001. Oil generation by igneous intrusions in the northern Gunnedah Basin, Australia. Organic Geochemistry 32, 1219 – 1232.

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Othman, R., Ward, C.R., 1999. Stratigraphic correlations in the southern Bowen and northern Gunnedah Basins, northern New South Wales. In: Diessel, C., Swift, E., Francis, S. (Eds.), Proceedings of 33rd Newcastle Symposium on Advances in the Study of the Sydney Basin. The University of Newcastle, pp. 23 – 30.

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Othman, R., Ward, C.R., 2000. Thermal maturation pattern in the southern Bowen and northern Gunnedah Basins and the overlying Surat Basin sequence, northern New South Wales. 15th Australian Geological Convention, University of Technology, Sydney, Book of Abstracts 59, 374.

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Othman R., Ward, C.R., 2002. Thermal maturation pattern in the southern Bowen, northern Gunnedah and Surat Basins, northern New South Wales, Australia. International Journal of Coal Geology 51, 145 – 167.

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Othman, R., Ward, C.R., 2003. Response of major geochemical thermal maturity parameters to suppression of vitrinite reflectance, Gunnedah-Surat Basins, New South Wales, Australia. 20th Annual Meeting of the Society for Organic Petrology, Washington D.C. Area, Book of Abstracts 20, 39.

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